JCAR350225-08

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TITLE

35: ENVIRONMENTAL

PROTECTION

SUBTITLE

B: AIR

POLLUTION

CHAPTER

POLLUTION

CONTROL

BOARD

SUBCHAPTER

c: EMISSION

STANDARDS

AND LIMITATIONS

FOR STATIONARY

SOURCES

011

Op,,

CONTROL

OF EMISSIONS

FROM LARGE

COMBUSTION

SOURCES

1Con’$JNOIs

SUBPART

A: GENERAL

PROVISIONS

Section

225.100

Severability

225.120

Abbreviations

and Acronyms

225.130

Definitions

225.140

Incorporations

by Reference

225.150

Commence

Commercial

Operation

SUBPART

CONTROL OF MERCURY

EMISSIONS

FROM COAL-FIRED

ELECTRIC

GENERATING UNITS

Section

225.200

Purpose

225 .202

Measurement Methods

225.205

Applicability

225.210

Compliance

Requirements

225 .220

Clean Air Act

Permit Program

(CAAPP) Permit

Requirements

225.230

Emission

Standards for EGUs

at Existing Sources

225 .232

Averaging

Demonstrations for

Existing Sources

225.233

Multi-Pollutant

Standard

(MPS)

225.234

Temporary

Technology-Based

Standard for EGUs

at Existing Sources

225.23

Units

Scheduled

for Permanent

Shut Down

225 .237

Emission Standards

for New

Sources with EGUs

225.23

Temporary Technology-Based

Standard for New Sources

with EGUs

225.239

Periodic Emissions

Testing Alternative

Requirements

225.240

General

Monitoring

and

Reporting

Requirements

225.250

Initial Certification

and Recertification

Procedures

for Emissions

Monitoring

225 .260

Out of

Control Periods and Data

Availability

for Emission Monitors

225 .261

Additional

Requirements

to Provide

Heat

Input Data

225.263

Monitoring

of Gross Electrical

Output

225 .265

Coal

Analysis for Input

Mercury Levels

225.270

Notifications

225.290

Recordkeeping

and Reporting

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225.291

Combined

Pollutant Standard: Purpose

225.292

Applicability of the Combined Pollutant Standard

225.293

Combined Pollutant

Standard:

Notice of Intent

225.294

Combined

Pollutant Standard: Control Technology Requirements and Emissions

Standards for Mercury

49 225.295

Combined-Pollutant Standard: Emissions Standards for

and SO

Treatment

of Mercury

Allowances

225.296

Combined

Pollutant

Standard: Control Technology Requirements for

NON,

and

Emissions

225.297

Combined Pollutant

Standard: Permanent Shut-Downs

225.298

Combined Pollutant Standard: Requirements for

and

Allowances

225.299

Combined Pollutant

Standard:

Clean

Air

Act

Requirements

SUBPART C: CLEAN AIR ACT INTERSTATE

RULE (CAR) SO

2 TRADING PROGRAM

Section

225.300

Purpose

225.305

Applicability

225.3 10

Compliance Requirements

225.315

Appeal

Procedures

225.320

Permit

Requirements

225.325

Trading Program

SUBPART D: CAR

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

225.43 0

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

JCAR350225-081 8507r01

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: CAR

OZONE SEASON TRADING PROGRAM

Section

225.500

Purpose

225.505

Applicability

225.5 10

Compliance Requirements

225.515

Appeal Procedures

225.520

Permit Requirements

225.525

Ozone

Season Trading

Budget

100

225.530

Timing for Ozone Season Allocations

101

225.535

Methodology for Calculating

Ozone Season Allocations

102

225.540

Ozone Season Allocations

103

225.545

New

Unit Set-Aside

(NUSA)

104

225.550

Monitoring, Recordkeeping and Reporting Requirements

for Gross Electrical

105

Output

and Useful Thermal

Energy

106

225.555

Clean Air Set-Aside (CASA)

107

225.560

Energy Efficiency and Conservation, Renewable Energy,

and Clean Technology

108

Projects

109

225.565

Clean Air

Set-Aside

(CASA) Allowances

110

225.570

Clean

Air Set-Aside (CASA)

Applications

111

225.5 75

Agency Action on Clean Air Set-Aside (CASA)

Applications

112

113

SUBPART F: COMBINED

POLLUTANT STANDARDS

114

115

225.600

Purpose (Repealed)

116

225.605

Applicability

(Repealed)

117

225.6 10

Notice of Intent (Repealed)

118

225.615

Control

Technology

Requirements and Emissions Standards for

Mercury

119

(Repealed)

120

225.620

Emissions Standards

for

and

(Repealed)

121

225.625

Control Technology Requirements for

NOR,

2,and PM Emissions (Repealed)

122

225.630

Permanent Shut-Downs (Repealed)

123

225.63 5

Requirements for CAR

SO CAR

NOR,

and CAIR

Ozone Season

124

Allowances (Repealed)

125

225.640

Clean Air Act Requirements

(Repealed)

126

127

225.APPENDIX A

Specified EGUs

for

Purposes of the CPS Subpart F (Midwest Generation’s

128

Coal-Fired Boilers as

of July 1,

2006)

129

225.APPENDIX B

Continuous Emission Monitoring Systems

for Mercury

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130

131

AUTHORITY: Implementing and authorized

by Section

of the

Environmental

Protection

Act

132

[415 ILCS 5/27].

133

134

SOURCE: Adopted in R06-25 at 31111.

Reg.

129,

effective December 21, 2006; amended

135

R06-26 at 31111. Reg.

12864,

effective August 31, 2007; amended

inRO9-10 at 33111. Reg.

136

, effective

137

138

SUBPART A: GENERAL

PROVISIONS

139

140

Section 225.120 Abbreviations and Acronyms

141

142

Unless otherwise specified within this Part, the abbreviations

used in

this Part

must be the

same

143

as those found

35 Ill. Adm. Code 211. The following

abbreviations and acronyms

are used in

144

this

Part:

145

Act

Environmental

Protection Act [415 ILCS 5]

ACT

activated carbon injection

AETB

Air Emission Testing Body

Agency

Illinois Environmental

Protection Agency

Btu

British thermal unit

CAA

Clean Air Act (42

USC

7401

et seq.)

CAAPP

Clean Air Act Permit Program

CA1R

Clean Air Interstate Rule

CASA

Clean Air Set-Aside

CEMS

continuous emission monitoring

system

carbon dioxide

CPS

Combined Pollutant Standard

CGO

converted

gross electrical output

CRM

certified

reference materials

CUTE

converted

useful thermal energy

DAHS

data acquisition and handling system

dscm

dry standard cubic meters

EGU

electric generating unit

ESP

electrostatic precipitator

FGD

flue gas desulfurization

feet per minute

gross

electrical

output

GWh

gigawatt hour

heat input

mercury

hour

ISO

International

Organization

for Standardization

JCAR350225-08

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kilogram

pound

MPS

Multi-Pollutant Standard

MSDS

Material Safety Data Sheet

megawatt

MWe

megawatt electrical

MWh

megawatt hour

NAAQS

National

Ambient Air Quality

Standards

NIST

National Institute

Standards

and

Technology

nitrogen oxides

NTRM

NIST Traceable Reference Material

NUSA

New

Unit Set-Aside

ORIS

Office of Regulatory Information Systems

oxygen

2.5

particles less than 2.5 micrometers in diameter

quality assurance

quality certification

RATA

relative accuracy

test audit

RGFM

reference gas flow meter

sulfur dioxide

SNCR

selective noncatalytic reduction

TTBS

Temporary Technology

Based Standard

TCGO

total converted useful thermal energy

UTE

useful thermal energy

USEPA

United States Environmental Protection Agency

year

146

147

(Source:

Amended

at 33

Ill.

Reg.

effective

148

149

Section 225.130

Definitions

150

151

The

following definitions apply for the purposes of this

Part.

Unless

otherwise defined

in this

152

Section or a different meaning

for

a term is clear from its context, the terms used in this Part

153

have the

meanings specified in 35 Ill. Adm. Code 211.

154

155

“Agency” means the Illinois Environmental

Protection Agency. [415 ILCS

156

5/3.105]

157

158

“Averaging demonstration”

means, with regard to Subpart B of this Part, a

159

demonstration of compliance that is based

on the combined performance of

EGUs

160

at two or more sources.

161

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162

“Base Emission

Rate?!

means, for a group of EGUs subject to emission

standards

163

for

and

pursuant

to Section 225.233, the average emission rate of

164

from the EGUs, in pounds per million Btu heat input,

for calendar years 2003

165

through

2005

(or, for seasonal

NOR,

the 2003 through 2005 ozone seasons),

166

determined

from

the

data collected and quality assured by the USEPA, pursuant

167

to the 40 CFR 72 and

federal

Acid Rain

and

Budget Trading Programs,

168

for the emissions and heat input of that group of

EGUs.

169

170

“Board” means the Illinois Pollution Control

Board. [415 ILCS 5/3.130]

171

172

“Boiler” means an enclosed

fossil or other fuel-fired combustion device used

173

produce heat and to transfer heat to recirculating water, steam, or other

medium.

174

175

“Bottoming-cycle cogeneration unit” means a cogeneration unit in which the

176

energy input to the unit is first used to produce useful thermal

energy and at least

177

some

the reject heat

from

the useful thermal energy application or process

178

then used for electricity production.

179

180

“CAJR authorized account representative”

means,

for the purpose of general

181

accounts, a responsible natural person who is authorized, in accordance

with 40

182

CFR 96, subparts BB, FF, BBB, FFF, BBBB, and FFFF to transfer and

otherwise

183

dispose of CAR

NON,

SO and

Ozone Season allowances, as applicable,

184

held

in the CAR

NOR,

SO2,

and

Ozone Season general account, and for

the

185

purpose of a CAR

compliance account, a CAR

2compliance account,

186

a CAR

Ozone Season compliance account, the CAR designated

187

representative of the source.

188

189

“CAR

designated representative”

means, for a CAR

source, a CAR

190

source, and a CAR

Ozone Season source and each

CAIR

unit, CAR

191

unit

and

CAR

Ozone Season unit at the source, the natural person

who

192

is authorized by the owners and operators of the source and

all such units at the

193

source, in accordance with 40

CFR 96, subparts BB, FF, BBB, FFF, BBBB,

and

194

FFFF as applicable, to represent and legally bind each owner and

operator in

195

matters pertaining to the CAR

Annual Trading Program, CAR

Trading

196

Program, and CAR

Ozone Season Trading Program,

as applicable. For any

197

unit

that

subject to one or

of the following programs: CAR

Annual

198

Trading Program, CAR

Ozone Season Trading

199

Program, or the

federal

Acid Rain Program, the designated

representative for the

200

unit

must be the

same natural

person for all programs applicable to the unit.

201

202

“Coal” means any solid fuel classified

as anthracite, bituminous, subbituminous,

203

or lignite by the

American

Society for Testing and

Materials (ASTM) Standard

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204

Specification for Classification

of Coals by Rank D388-77, 90,

91,

95, 98a,

205

(Reapproved 2004).

206

207

“Coal-derived fuel” means any

fuel (whether in a solid, liquid or gaseous

state)

208

produced by the mechanical, thermal,

or chemical processing of coal.

209

210

“Coal-fired” means:

211

212

For purposes of SubpartSubparts

and F, or

for

purposes

of allocating

213

allowances

under Sections 225.435, 225.445, 225.535, and 225.545,

214

combusting any amount of coal

coal-derived fuel,

alone or in

215

combination with

any amount of any other fuel, during a specified

year;

216

217

Except as provided above,

combusting any amount of coal or coal-derived

218

fuel, alone or in combination with any amount of any other fuel.

219

220

“Cogeneration

unit”

means, for the purposes of Subparts

D, and E,

a stationary,

221

fossil fuel-fired boiler or a stationary,

fossil

fuel-fired combustion turbine of

222

which both of the following conditions are true:

223

224

It uses equipment to

produce electricity and useful thermal energy for

225

industrial, commercial, heating,

cooling

purposes through the sequential

226

use

of energy; and

227

228

produces either

of the following during the 12-month period

beginning

229

on the date the unit first produces electricity

and during any subsequent

230

calendar year after that in which the unit first produces electricity:

231

232

For a topping-cycle cogeneration unit, both of the following:

233

234

Useful thermal energy not less than five percent

of total

235

energy output; and

236

237

Useful power that, when added

to one-half of useful

238

thermal energy produced, is not less than 42.5 percent

239

total energy input, if useful

thermal

energy produced

is 15

240

percent or more of total energy output,

or not less than 45

241

percent of total energy input if useful thermal energy

242

produced is

less

than

15 percent of total energy output;

243

244

For a bottoming-cycle cogeneration unit,

useful

power not less

245

than 45 percent of total energy input.

246

JCAR350225-08

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247

“Combined

cycle

system” means a system comprised

one or

more combustion

248

turbines, heat recovery steam generators,

and steam turbines configured to

249

improve

overall efficiency of electricity generation

steam

production.

250

251

“Combustion turbine” means:

252

253

An enclosed device comprising a compressor, a combustor,

and a turbine

254

and in which

the flue gas resulting from the combustion of fuel in the

255

combustor passes through

the

turbine,

rotating the turbine; and

256

257

If the enclosed device described

in the above paragraph of this definition

258

combined

cycle, any associated duct burner, heat recovery steam

259

generator and steam turbine.

260

261

“Commence commercial operation” means, for the purposes

of SubpartSubparts

262

and F of this Part, with regard

to an EGU that serves a generator, to have begun

263

produce steam, gas, or other heated medium used to generate electricity

for sale

264

use, including test generation.

Such

date must remain the unit’s date of

265

commencement of operation even if the EGU

is subsequently modified,

266

reconstructed or repowered. For the purposes of Subparts

D and E,

267

“commence commercial

operation” is as defined in Section 225.150.

268

269

“Commence construction” means, for

the purposes of Section 225.460(f),

270

225.470,

225.560(f), and 225.570, that the owner

owner’s

designee has

271

obtained all

necessary

preconstruction approvals (e.g., zoning) or permits

and

272

either has:

273

274

Begun,

caused to

begin, a continuous program of actual on-site

275

construction of the source, to be completed within a

reasonable time; or

276

277

Entered into binding agreements or contractual obligations,

which cannot

278

be cancelled or modified without

substantial loss to the owner or operator,

279

undertake

a program of actual construction of the source to

280

completed within a reasonable time.

281

282

For purposes of this definition:

283

284

“Construction”

shall

be determined as any physical change

285

change in

the method of operation, including but not limited

286

fabrication, erection, installation,

demolition, or modification

287

projects eligible for CASA allowances,

as set forth in Sections

288

225.460

and 225.560.

289

JCAR350225-08 1 8507r01

290

“A

reasonable time”

shall be

determined

considering

but not

291

limited

the

following factors: the nature and

size of the project,

292

the

extent of design

engineering,

the amount of off-site

293

preparation,

whether equipment can

fabricated

or can be

294

purchased,

when the project begins (considering

both the seasonal

295

nature

of the construction activity and the existence of other

296

projects

competing

for

construction labor at the same time, the

297

place

of the environmental permit in the sequence

of corporate and

298

overall governmental

approval), and the nature of the project

299

sponsor (e.g., private, public, regulated).

300

301

“Commence

operation”,

for purposes of Subparts

C, D and E, means:

302

303

To have begun

any mechanical, chemical, or electronic

process,

including,

304

for

the purpose of a unit, start-up

of a unit’s combustion chamber, except

305

provided in 40

CFR 96.105, 96.205, or 96.305, as incorporated

306

reference in Section 225.140.

307

308

For a unit that undergoes

a physical change (other than replacement

of the

309

unit

by a unit at the same source) after the date

the unit commences

310

operation as

set forth in the first paragraph of this

definition,

such date will

311

remain the date

of commencement of operation of the unit, which

will

312

continue to be treated

as the same unit.

313

314

For a unit that

is replaced by a unit at the same

source (e.g., repowered),

315

after the date the

unit commences operation as set forth in

the first

316

paragraph of this definition, such date

will remain the replaced unit’s

date

317

of commencement

of operation, and the replacement

unit will be treated as

318

a separate unit with a separate date

for commencement of operation

as set

319

forth in this definition

as appropriate.

320

321

“Common stack” means a single

flue through which emissions from two

322

units are

exhausted.

323

324

“Compliance

account”

means:

325

326

For the purposes of Subparts

and

E, a CAR

Allowance Tracking

327

System

account,

established by USEPA for a

CAIR

source or CAR

328

Ozone Season

source pursuant to 40 CFR

96, subparts FF and FFFF

329

in which any CAR

allowance or CAR

Ozone

Season

330

allowance allocations for the

CAR

units or CAR

Ozone

331

Season units at the source are initially recorded

and in which are held

any

332

CAR

or CAR

Ozone Season allowances

available

for use for

JCAR350225-081 8507r01

333

control period in order to meet the source’s

CAR

CAIR

334

Ozone Season emissions limitations

in accordance with Sections 225 .410

335

and 225.5 10, and 40 CFR 96.154

and 96.354, as incorporated by reference

336

in Section

225.140.

CAIR

allowances may

not

be used for

337

compliance with

the

CAIR

Ozone Season Trading Program and

338

CAR

Ozone Season allowances

may not be used for compliance

339

with the CAR

Annual Trading Program;

340

341

For the purposes

Subpart

C, a “compliance account” means a CAR

342

2 compliance account, established

by the

USEPA for a

CAR SO

343

source pursuant to 40 CFR

96, subpart FFF, in which any

units

at the

344

source

are initially recorded and in which are held any

allowances

345

available for use for a control

period in order to meet the source’s CAIR

346

emissions

limitations in accordance with Section 225.3 10 and 40

CFR

347

96.254, as incorporated by reference in

Section

225.140.

348

349

“Control period” means:

350

351

For the CAIR

and

Annual

Trading Programs

in Subparts

C and

352

D, the period beginning January 1 of a calendar year, except

as provided

353

in Sections 225.3

10(d)(3) and 225.410(d)(3), and ending on

December31

354

of the same year,

inclusive; or

355

356

For the CAIR

Ozone Season Trading

Program in Subpart E, the

357

period

beginning May 1 of a calendar year, except as provided

in Section

358

225.5

10(d)(3), and

ending on September 30 of the same year, inclusive.

359

360

“Designated representative”

means, for the purposes of Subpart B of this

Part, the

361

natural person as defined in 40 CFR 60.4 102, and is

the same natural person

362

the

person who is the designated

representative for the CAR trading and

Acid

363

Rain programs.

364

365

“Electric generating

unit” or “EGU” means a fossil fuel-fired stationary

boiler,

366

combustion turbine or combined cycle

system that serves a generator that has

367

nameplate

capacity

greater than

25 MWe and produces electricity for

sale.

368

369

“Flue” means a conduit or duct through which

gases or other matter is exhausted

370

to the

atmosphere.

371

372

“Fossil fuel” means natural

gas, petroleum, coal, or any form of solid, liquid,

373

gaseous fuel derived from such material.

374

375

“Fossil fuel-fired” means

the combusting of any amount of fossil fuel,

alone or in

JCAR350225-08

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376

combination with

any other fuel in any calendar year.

377

378

uGenerator

means a device that produces electricity.

379

380

“Gross

electrical output”

means the total electrical output from an EGU before

381

making any deductions for energy

output

used in any way related to the

382

production of energy. For an EGU generating

only electricity, the gross electrical

383

output is

the output

from the turbine/generator set.

384

385

“Heat input” means, for the purposes of Subparts

and E, a specified period

386

time, the product (in mmBtu/hr)

of the gross calorific value of the fuel (in

387

Btu!lb) divided by 1,000,000 BtulmmBtu and multiplied

by the

fuel

feed rate into

388

a combustion device (in lb of fuelltime),

as measured, recorded and reported to

389

USEPA by

the CAR

designated representative and determined

USEPA

390

accordance with 40 CFR 96, subpart

HH,

HHH, or

HHHH, if applicable, and

391

excluding the heat derived

from preheated combustion air, recirculated flue

gases,

392

or exhaust from other sources.

393

394

“Higher heating value” or “HHV”

means the total heat liberated per mass of fuel

395

burned (Btu/lb), when fuel and dry air at standard conditions

undergo complete

396

combustion and all resultant

products

are brought to their standard states

397

standard conditions.

398

399

“Input mercury” means the mass of mercury that is

contained in the coal

400

combusted

within

an EGU.

401

402

“Integrated gasification combined cycle” or “IGCC”

means a coal-fired electric

403

utility steam generating

unit that

burns a synthetic gas derived from coal

404

combined-cycle gas turbine. No coal is directly

burned in the unit during

405

operation.

406

407

“Long-term cold storage” means

the complete shutdown of a unit intended

to last

408

for an extended period of time

(at

least two calendar years) where

notice for long-

409

term cold storage is provided under 40

CFR 75.6

1(a)(7).

410

411

“Nameplate capacity” means,

starting from the initial installation of a generator,

412

the maximum electrical generating output (in

MWe) that the generator is capable

413

of producing on a steady-state basis and during continuous

operation (when not

414

restricted

seasonal

or other deratings) as of such installation as

specified by the

415

manufacturer of the

generator or, starting from the completion of any

subsequent

416

physical change in the generator resulting in

an increase in the maximum

417

electrical generating output (in MWe) that the generator

is capable of producing

418

on a steady-state

basis

and during continuous operation (when

not restricted by

JCAR350225-081 8507r01

419

seasonal or other

deratings), such increased maximum

amount as of completion

420

specified by the person conducting

the physical change.

421

422

“NIST traceable elemental

mercury standards”

means

either:

423

424

Compressed gas

cylinders having known concentrations

425

elemental mercury, which have

been prepared according to the

426

“EPA

Traceability Protocol for Assay and Certification

of Gaseous

427

Calibration Standards”;

428

429

Calibration gases having

known concentrations of elemental

430

mercury,

produced by a generator that

fully

meets the performance

431

requirements of the

“EPA Traceability Protocol for

Qualification

432

and Certification

of Elemental Mercury Gas Generators.”

433

434

“NIST traceable source of oxidized

mercury” means a

generator

that

capable

435

providing known concentrations of vapor

phase mercuric chloride (HgCI

and

436

that fully meets the performance

requirements

of the “EPA Traceability

Protocol

437

for

Qualification

and Certification of

Oxidized Mercury Gas Generators.”

438

439

“Oil-fired

unit” means a

unit combusting fuel oil for more than

15.0 percent of

the

440

annual heat

input in a specified

year and not qualifying as coal-fired.

441

442

“Output-based emission standard” means,

for the purposes of Subpart B of

this

443

Part, a maximum allowable rate of emissions of mercury

per unit of gross

444

electrical output

from an EGU.

445

446

“Potential electrical output capacity”

means 33 percent of a unit’s

maximum design

447

heat input, expressed in mmBtulhr divided

3.4

13 mmBtulMWh, and multiplied

448

by 8,760

hr/yr.

449

450

“Project sponsor” means a person

or an entity, including but not limited

to the

451

owner or

operator

of an EGU or a not-for-profit group,

that provides the majority

452

of funding for an energy efficiency and

conservation, renewable energy,

or clean

453

technology project

as listed in Sections 225 .460 and 225.560,

unless another

454

person or entity is designated

by a written agreement as the project

sponsor for

the

455

purpose of applying for

allowances or

Ozone Season allowances

from

456

the CASA.

457

458

“Rated-energy efficiency” means

the percentage of thermal energy

input

that is

459

recovered as useable energy in the form

of gross electrical output, useful

thermal

460

energy, or both that is used for heating, cooling, industrial

processes, or other

461

beneficial

uses as

follows:

JCAR350225-08

1 8507r01

462

463

For

electric generators, rated-energy

efficiency

is calculated

one

464

kilowatt

hour

(3,413

Btu) of electricity divided

by the unit’s

design heat

465

rate

using the higher heating

value

of the

fuel, and expressed

as a

466

percentage.

467

468

For combined

heat and power projects,

rated-energy

efficiency is

469

calculated using

the following

formula:

470

REE

= ((GO

+ UTE)/HI)

100

471

472

Where:

473

REE

= Rated-energy

efficiency, expressed

as percentage.

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.

= Heat

input, based

upon the higher heating

value of fuel,

Btulhr.

474

475

“Repowered”

means, for the purposes

an EGU,

replacement of a

coal-fired

476

boiler with one

of the following

coal-fired technologies

at the same

source as

the

477

coal-fired boiler:

478

479

Atmospheric

or pressurized

fluidized

bed

combustion;

480

481

Integrated

gasification

combined cycle;

482

483

Magnetohydrodynamics;

484

485

Direct

and indirect

coal-fired turbines;

486

487

Integrated

gasification

fuel cells; or

488

489

determined

the USEPA in consultation

with

the

United States

490

Department of

Energy, a derivative

of one or more

of the technologies

491

under this definition

and

any other

coal-fired technology

capable

492

controlling multiple

combustion

emissions

simultaneously

with

improved

493

boiler or

generation efficiency

and with

significantly

greater waste

494

reduction relative

to the performance

of technology

in widespread

495

commercial

use

as of

January 1, 2005.

496

JCAR350225-081 8507r01

497

“Rolling 12-month basis” means,

for the purposes of SubpartSubparts B and

F of

498

this Part, a

determination

made on a monthly basis

from the relevant data for a

499

particular calendar

month

and

the

preceding 11 calendar months (total of 12

500

months of data), with two exceptions.

For determinations involving one EGU,

501

calendar months in which the EGU does not operate

(zero EGU operating hours)

502

must not be

included

in the determination, and must

be replaced by a

preceding

503

month

or months in which

the EGU does operate, so that the determination is

still

504

based on 12 months of data. For

determinations

involving two or more EGUs,

505

calendar

months

in which none of the EGUs covered

by the determination

506

operates (zero EGU operating

hours) must not be included in the determination,

507

and must be replaced by preceding months in which

at least one of the EGUs

508

covered by the determination does

operate, so that the determination is still based

509

on 12 months

data.

510

511

“Total

energy output”

means, with respect to a cogeneration unit, the sum of

512

useful power and useful thermal energy produced

by the cogeneration unit.

513

514

“Useful thermal energy” means, for the

purpose of a cogeneration unit, the

515

thermal energy that is made available to an industrial or commercial process,

516

excluding any heat contained

in condensate return or makeup water:

517

518

Used in a heating application (e.g., space

heating or domestic hot water

519

heating); or

520

521

Used in a space cooling

application (e.g., thermal energy used by an

522

absorption chiller).

523

524

(Source:

Amended at 33 Ill. Reg.

effective

525

526

Section

225.140 Incorporations by Reference

527

528

The following

materials are incorporated

reference. These incorporations

do not include any

529

later amendments

or editions.

530

531

Appendix A, Subpart A, and Performance

Specifications 2 and 3 of Appendix

532

of 40 CFR 60, 60.17, 60.45a, 60.49a(k)(1) and

(p),

60.50a(h), and

60.4170

533

through

60.4176

(2005).

534

535

})

40 CFR 72.2

(2005).

536

537

th)

40 CFR

75.4,

75.11

through

75.14, 75.16 through 75.19,

75.30,

75.34

through

538

75.37,

75.40

through 75.48,

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

through

75.57(c)(2)(vi),

539

75.60 through 75.67, 75.71,

75.74(c), Sections 2.1.1.5, 2.1.1.2, 7.7, and 7.8

JCAR350225-08 1 8507r01

540

Appendix A to

CFR 75, Appendix

C to

CFR 75, Section 3.3.5 of Appendix

541

F to

40 CFR 75 (2006)40

CFR

75 (2006).

542

543

de)

40 CFR78

(2006).

544

545

e4)

40 CFR 96, CAR

Trading Program, subparts AAA (excluding 40

CFR

546

96.204 and 96.206), BBB,

FFF, GGG, and HHH (2006).

547

548

fe)

40 CFR

96,

CAR

Annual Trading Program, subparts AA (excluding

549

CFR 96.104, 96.105(b)(2), and 96.106), BB,

FF,

GG,

and HH (2006).

550

551

g4)

40 CFR 96, CAR

Ozone Season Trading

Program, subparts AAAA

552

(excluding 40 CFR 96.304,

96.305(b)(2),

and 96.306), BBBB, FFFF,

GGGG,

and

553

HHHH (2006).

554

555

hg)

ASTM.

The following

methods from the American Society for Testing

and

556

Materials, 100 Barr Harbor Drive,

P.O. Box C700, West Conshohocken PA

557

19428-2959,

(610) 832-9585:

558

559

ASTM D388-77 (approved February 25,

1977), D388-90 (approved

560

March 30, 1990), D388-91a (approved April

15, 1991), D388-95

561

(approved

January 15, 1995), D388-98a (approved September

10, 1998),

562

or D388-99 (approved

September

10, 1999, reapproved in 2004),

563

Classification of Coals

Rank.

564

565

ASTM D3173-03,

Standard

Test Method for Moisture in the

Analysis

566

Sample of Coal and Coke (Approved

April 10, 2003).

567

568

ASTM D3684-01, Standard Test

Method for Total Mercury in Coal

by the

569

Oxygen

Bomb CombustionlAtomic Absorption Method

(Approved

570

October 10, 2001).

571

572

ASTM D4840-99, Standard Guide for Sampling

Chain-of-Custody

573

Procedures (Reapproved 2004).

574

575

54)

ASTM D5865-04,

Standard

Test Method for Gross Calorific

Value

576

Coal and Coke (Approved April

2004).

577

578

65)

ASTM

D6414-01,

Standard

Test Method for Total Mercury

in Coal

and

579

Coal

Combustion Residues by Acid Extraction or Wet

OxidationlCold

580

Vapor Atomic

Absorption (Approved October 10, 2001).

581

JCAR350225-08 1 8507r01

582

76)

ASTM D6784-02, Standard

Test Method for Elemental, Oxidized,

583

Particle-Bound and Total Mercury in Flue

Gas Generated from Coal-Fired

584

Stationary

Sources (Ontario Hydro Method) (Approved April

10,

2002).

585

586

)

ASTM D691 1-03. Standard Guide

for Packaging and Shipping

587

Environmental Samples for Laboratory

Analysis.

588

589

ASTM D7036-04, Standard Practice

for Competence of Air Emission

590

Testing Bodies.

591

592

ih)

Federal Energy Management Program, M&V Guidelines:

Measurement and

593

Verification for Federal Energy Projects,

Department of Energy, Office

594

Energy Efficiency and Renewable Energy, Version 2.2,

DOE/GO-102000-0960

595

(September 2000).

596

597

(Source: Amended at 33 Iii. Reg.

effective

598

599

SUBPART B: CONTROL OF MERCURY

EMISSIONS

600

FROM COAL-FIRED ELECTRIC GENERATING

UNITS

601

602

Section 225.202 Measurement Methods

603

604

Measurement of mercury must be according to the following:

605

606

Continuous emission monitoring

pursuant

to Appendix B to this Part or an

607

alternative emissions monitoring system, alternative reference

method

for

608

measuring emissions,

or other alternative to the emissions monitoring and

609

measurement requirements of Sections 225.240

through

225.290, if such

610

alternative is submitted

to the Agency in writing and approved in writing

the

611

Manager of the Bureau of Air’s Compliance Section.40

CFR 75 (2005).

612

613

ASTM D3173-03, Standard Test Method for Moisture

in the Analysis Sample

614

Coal and Coke (Approved April

10, 2003), incorporated by reference in Section

615

225.140.

616

617

ASTM D3684-01, Standard Test Method for

Total Mercury in Coal by the

618

Oxygen Bomb CombustionlAtomic Absorption Method (Approved

October 10,

619

2001), incorporated

reference in

Section 225.140.

620

621

ASTM D5865-04, Standard Test Method for

Gross Calorific Value of Coal and

622

Coke

(Approved

April 1, 2004), incorporated

reference

in Section 225.140.

623

JCAR350225-081

8507r01

624

ASTM

D6414-01,

Standard Test

Method for Total Mercury in

Coal and Coal

625

Combustion Residues

Acid Extraction

or Wet Oxidation/Cold Vapor Atomic

626

Absorption

(Approved October 10, 2001), incorporated

by reference in Section

627

225.140.

628

629

ASTM D6784-02, Standard Test Method for

Elemental, Oxidized, Particle-Bound

630

and

Total Mercury

in Flue Gas Generated from Coal-Fired

Stationary Sources

631

(Ontario Hydro Method) (Approved

April

10, 2002), incorporated

reference

632

Section 225.140.

633

634

Emissions testing pursuant to Appendix

A of

CFR 60.

635

636

(Source: Amended at 33 Iii. Reg.

effective

637

638

Section 225.210 Compliance Requirements

639

640

Permit Requirements.

641

The

owner or operator

each

source with one or more EGUs subject to

this

642

Subpart B at the source must apply for a

CAAPP permit that addresses the

643

applicable

requirements

of this Subpart B.

644

645

Monitoring and Testing Requirements.

646

647

The owner or operator of each source and

each EGU at the source must

64.8

comply with

either the monitoring requirements of Sections 225.240

649

through 225 .290

this

Subpart B, the periodic emissions testing

650

requirements of Section 225.23

of this

Subpart B, or an alternative

651

emissions monitoring

system, alternative reference method for

measuring

652

emissions, or other alternative to the emissions

monitoring and

653

measurement requirements

of Sections 225.240 through 225.290, if

such

654

alternative

is submitted to the Agency in writing

and approved in writing

655

by the Manager of the Bureau

of Air’s Compliance Section.

656

657

The compliance of each EGU with

the mercury requirements of Sections

658

225.230 and 225.237

of this Subpart B must be determined

by the

659

emissions measurements

recorded

and reported in accordance with

either

660

Sections

225.240

through 225.290

this

Subpart

B, Section 225.239

661

this Subpart B,

or an alternative emissions monitoring

system, alternative

662

reference method

for measuring emissions, or other alternative

to the

663

emissions monitoring

and measurement requirements of Sections 225.240

664

through

225.290,

if such alternative

is submitted to the Agency in writing

665

and approved

in writing

the Manager of

the Bureau of Air’s

666

Compliance Section.

JCAR350225-08 1 8507r01

667

668

Mercury Emission Reduction Requirements

669

The owner or

operator

of any EGU subject to this Subpart B must comply with

670

applicable requirements for control

mercury

emissions of Section 225.230 or

671

Section 225.237 of this Subpart B.

672

673

Recordkeeping

and

Reporting Requirements

674

Unless otherwise provided, the owner or operator

of a source with one or more

675

EGUs at the source must keep on site at the source each of the documents

listed in

676

subsections

(d)(1) through

(d)(3) of this Section for a period of five years from the

677

date the document is created. This period may be extended, in writing

by the

678

Agency,

for cause, at any time prior

the end

of five years.

679

680

All emissions monitoring information gathered in

accordance with

681

Sections

225.240

through 225.290 and all periodic emissions testing

682

information gathered in accordance with Section 225.239.

683

684

Copies of all reports, compliance certifications, and

other submissions and

685

all records made or required or documents necessary to demonstrate

686

compliance with

the requirements of this Subpart B.

687

688

Copies of all documents used to complete a permit application

and any

689

other submission under this Subpart B.

690

691

Liability.

692

693

The owner or operator of each source with one or more EGUs must

meet

694

the requirements of this Subpart B.

695

696

Any provision of this Subpart B that applies

to a

source

must

also

apply

697

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

698

each EGU at the source.

699

700

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

701

the

owner

or operator

of such EGU.

702

703

Effect on Other Authorities. No provision of this Subpart B may be construed

704

exempting or

excluding the

owner or

operator of a source or EGU from

705

compliance with any other provision

of an

approved

State Implementation Plan,

706

permit, the Act, or the CAA.

707

708

(Source: Amended at 33 Ill. Reg.

effective

709

JCAR350225-081 8507r01

710

Section 225.220 Clean Air

Act Permit Program (CAAPP) Permit Requirements

711

712

Application

Requirements.

713

714

Each source with one or

more EGUs subject to the requirements of this

715

Subpart B is required to submit

CAAPP

permit application that

716

addresses all applicable requirements of this Subpart

applicable

to each

717

EGU at the

source.

718

719

For any EGU that commenced commercial operation:

720

721

before December 31, 2008, the owner or operator

such

722

EGUs must submit an initial permit application

or application for

723

CAAPP

permit modification that meets the requirements of this

724

Section on or before December 31, 2008.

725

726

after December 31, 2008, the owner or operator

any

such

EGU

727

must submit

an initial CAAPP permit application or application

for

728

CAAPP modification that meets the requirements

of this Section

729

not later than 180 days before initial startup of the EGU, unless

the

730

construction

permit issued for the EGU addresses the requirements

731

of this Subpart

732

733

Contents of Permit Applications.

734

In addition to other information required for a complete application for CAAPP

735

permit or CAAPP permit modification,

the application must include the following

736

information:

737

738

The ORIS (Office of Regulatory Information Systems)

or facility code

739

assigned to the source

by the

U.S.

Department of Energy, Energy

740

Information Administration, if applicable.

741

742

Identification

of each EGU at the source.

743

744

The

intended

approach

to the monitoring requirements of Sections

745

225 .240 through 225.290 of

this Subpart B, or, in the alternative, the

746

applicant may include its intended approach to the

testing requirement

747

Section 225 .239

of this Subpart B.

748

749

The intended approach

the

mercury emission reduction requirements

750

Section 225.230 or 225.237 of this Subpart B,

applicable.

751

752

Permit

Contents.

JCAR350225-081 8507r01

753

754

Each CAAPP permit issued

the Agency for a source

with one or more

755

EGUs subject

to the requirements of this Subpart B must contain federally

756

enforceable conditions addressing all applicable

requirements of this

757

Subpart B, which conditions must be a complete

and segregable portion of

758

the source’s entire CAAPP permit.

759

760

In addition to conditions related

to the applicable requirements of this

761

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

762

specified under

subsection

(b) of this Section.

763

764

(Source:

Amended at 33 Ill. Reg.

effective

765

766

Section 225.230 Emission Standards for EGUs at Existing Sources

767

768

Emission Standards.

769

770

Except as provided in Sections 225.230(b)

and

(d),

225 .232

through

771

225.234,

225.239, and 225.29 1 through 225.299 of this Subpart

772

beginningBeginning

July

1, 2009, the owner or operator of a source with

773

one or more EGUs

subject to this Subpart B that commenced commercial

774

operation on or before December 31, 2008, must

comply with one of the

775

following standards for each EGU on a rolling 12-month basis:

776

777

emission standard of 0.0080 lb mercury/GWh gross electrical

778

output; or

779

780

A minimum 90-percent reduction

of input mercury.

781

782

For an EGU complying with subsection (a)(1)(A)

of this Section, the

783

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

period,

784

as monitored in accordance with this Subpart

and calculated

as follows,

785

must not

exceed

the applicable emission standard:

786

787

ER=E

÷O1

788

789

Where:

790

ER = Actual mercury emissions rate of the EGU for the particular

12-

month rolling period, expressed in lbIGWh.

= Actual mercury emissions

of the EGU, in ibs, in an individual

month in the 12-month rolling period, as determined

JCAR350225-08

1 8507r01

accordance with

the emissions monitoring provisions

this

Subpart B.

= Gross electrical output of the EGU, in

GWh, in

an individual

month

the 12-month

rolling period, as determined in

accordance with Section 225.263

of this Subpart B.

791

792

For an EGU

complying with subsection

(a)(1)(B)

this Section,

the

793

actual control efficiency for

mercury emissions achieved by the EGU

for

794

each

12-month

rolling period, as monitored

in accordance with this

795

Subpart B

and calculated as follows, must meet or exceed the applicable

796

efficiency requirement:

797

798

CE=100x{1—(>ZE1

÷I1

)}

799

800

Where:

801

= Actual control efficiency for mercury emissions

of the EGU for

the

particular

12-month

rolling period, expressed as a percent.

Actual mercury emissions

of the EGU, in ibs, in an individual

month in the 12-month rolling

period, as determined in

accordance with the emissions monitoring provisions

of this

Subpart B.

= Amount

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

individual month in the 12-month

rolling period, as determined

accordance with Section 225.265 of this Subpart B.

802

803

Alternative

Emission

Standards for Single EGUs.

804

805

an alternative

to compliance with the emission standards in

subsection

806

(a) of this Section, the owner or operator

of the EGU may comply with

the

807

emission standards

of this Subpart B by demonstrating that the actual

808

emissions

of mercury from the EGU are less

than the allowable emissions

809

of mercury from the EGU

on a rolling 12-month basis.

810

811

For

the purpose

of demonstrating compliance with the alternative

emission

812

standards of this subsection

(b), for each rolling 12-month period, the

813

actual emissions of mercury from

the EGU,

as monitored in accordance

814

with

this

Subpart B, must not exceed the allowable

emissions

of mercury

815

from the

EGU, as further provided

the following formulas:

816

817

818

JCAR350225-08 1 8507r01

819

820

821

822

823

Where:

824

= Actual mercury emissions

of the EGU for the particular

12-month rolling period.

= Allowable mercury emissions

of the EGU for the particular

12-month

rolling period.

= Actual mercury emissions of the

EGU

an individual

month

in the 12-month rolling period.

= 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

)

or the electrical

output

from

the EGU

as selected by the owner or

operator

the

EGU for

that

given

month.

= 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) of the input mercury to the

EGU.

= Allowable

mercury

emissions of the EGU in a particular

month based on the electrical output from the EGU,

calculated

as the product of the output based mercury limit,

i.e., 0.0080 lb/GWh, and the electrical output

from the

EGU,

in GWh.

825

826

If the owner or operator

of an EGU does not conduct the necessary

827

sampling,

analysis,

and recordkeeping, in accordance with Section

828

225 .265 of this Subpart B, to determine

the mercury input to the EGU, the

829

allowable emissions

of the EGU must be calculated based on the electrical

830

output of the EGU.

831

832

two or more EGUs are served

by common

stack4s

and the owner or operator

833

conducts monitoring for mercury emissions in the common

stacks, as provided

834

for by

Sections 1.14 through

1.18 of Appendix B to this Part4O CFR 75, subpart

835

such that the mercury emissions

of each EGU are not determined separately,

836

compliance of the EGUs with the applicable

emission standards of this Subpart B

837

must be determined as if the EGUs were a single EGU.

838

839

Alternative Emission Standards

for Multiple EGUs.

840

JCAR350225-08 1 8507r01

841

As an alternative to compliance with the emission standards of subsection

842

(a) of this Section, the owner

or operator of a source

with

multiple EGUs

843

may comply with the emission standards of this Subpart B

844

demonstrating

that the actual emissions of mercury from all EGUs

at the

845

source are

less

than the allowable

emissions of mercury from all EGUs

846

the source on a rolling 12-month basis.

847

848

For the

purposes of the alternative emission standard of subsection

(d)(1)

849

of this Section, for each rolling 12-month

period, the

actual

emissions of

850

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

with

851

this Subpart B, must not exceed the

sum of the

allowable

emissions of

852

mercury

from all the EGUs at the source, as further provided by the

853

following formulas:

854

855

ESAS

856

857

858

859

860

861

Where:

862

= Sum

of the actual mercury emissions of the EGUs at the source.

Sum of the allowable mercury emissions of the EGUs

at the source.

= Actual

mercury emissions of an individual EGU at the source,

determined in accordance with subsection (b)(2)

of this Section.

= Allowable mercury

emissions of an individual EGU at the

source, as

determined in accordance with subsection (b)(2) of

this Section.

= Number

EGUs covered

by the demonstration.

863

864

If an owner or operator of a source

with two or more EGUs that is relying

865

on this subsection (d) to demonstrate compliance fails to meet the

866

requirements

of this

subsection

(d) in a given 12-month rolling period,

all

867

EGUs at such source covered

the

compliance

demonstration

are

868

considered out of compliance with the applicable emission standards

869

this Subpart B for the entire last month of that period.

870

871

(Source:

Amended at 33 Iii. Reg.

effective

872

873

Section 225.233

Multi-Pollutant

Standards (MPS)

JCAR350225-081

8507r01

874

875

General.

876

877

As an alternative

to compliance with the emissions standards

of Section

878

225.230(a),

the owner

eligible

EGUs

may elect for those

EGUs

879

demonstrate compliance pursuant to

this Section, which establishes

880

control requirements

and standards for emissions

and

as well

881

as for emissions

of mercury.

882

883

For the purpose

of this Section, the following requirements

apply:

884

885

eligible

EGU is an EGU that is located in Illinois

and which

886

commenced commercial operation

on or before December 31,

887

2004; and

888

889

Ownership of an

eligible EGU is determined based on direct

890

ownership,

by the holding of a majority interest

in a company

that

891

owns the EGU

or EGUs, or by the common ownership

of the

892

company that owns the EGU, whether

through a parent-subsidiary

893

relationship,

as a sister corporation, or as

an affiliated corporation

894

with the same

parent corporation, provided that

the owner has the

895

right or authority

to submit a CAAPP application on behalf

of the

896

EGU.

897

898

The owner of one

more EGUs electing to demonstrate

compliance with

899

this Subpart B pursuant to this

Section must submit an application

for a

900

CAAPP permit modification to the Agency,

as provided in Section

901

225.220, that includes

the

information

specified in subsection

(b) of this

902

Section and which clearly states the owner’s

election to demonstrate

903

compliance pursuant

this

Section 225.233.

904

905

If the owner of one or

more EGUs elects to demonstrate

906

compliance

with this Subpart pursuant

this

Section,

then all

907

EGUs it owns in Illinois

as of July 1, 2006, as defined in

908

subsection

(a)(2)(B) of this Section, must

be thereafter subject

909

the standards and control

requirements of this Section,

except as

910

provided in subsection (a)(3)(B).

Such EGUs must be referred

911

as a

Multi-Pollutant

Standard (MPS)

Group.

912

913

Notwithstanding the

foregoing, the owner may exclude

from an

914

MPS Group any EGU scheduled

for permanent shutdown that

the

915

owner

so designates in its CAAPP application

required

to be

916

submitted

pursuant to subsection (a)(3)

this

Section,

with

JCAR350225-081 8507r01

917

compliance for such units

to be

achieved

by means of Section

918

225.235.

919

920

When

an EGU is subject to the requirements

of this Section, the

921

requirements

apply to all owners or operators of the EGU,

and to the

922

designated representative

for the EGU.

923

924

Notice

of Intent.

925

The owner of one

more EGUs that intends to comply with this

Subpart B by

926

means of this Section must notify the Agency

of its intention by December 31,

927

2007.

The following

information must accompany the notification:

928

929

The identification

each

EGU that will be complying with this

Subpart B

930

by means of the multi-pollutant standards contained

in this Section, with

931

evidence that the owner has identified

all EGUs that it owned in Illinois

932

of July

2006

and which commenced commercial

operation

on or before

933

December 31, 2004;

934

935

If an EGU identified in

subsection (b)(1) of this Section is also

owned or

936

operated by a person different than

the

owner

submitting the notice

937

intent, a demonstration that the submitter has

the right to commit the

EGU

938

or authorization

from the responsible official for the

EGU accepting the

939

application;

940

941

The Base Emission Rates for the EGUs,

with copies of supporting data

942

and

calculations;

943

944

A summary of the current control devices installed

and operating on each

945

EGU and identification

of the additional control devices that will

likely

946

needed for

the each EGU to comply with emission

control requirements

947

this Section, including identification

of each EGU in the MPS group

that

948

will be addressed

by subsection (c)(1)(B) of this Section,

with information

949

showing that the eligibility criteria for

this

subsection (b) are satisfied;

and

950

951

Identification of each EGU that

is scheduled for permanent shut down,

952

provided

by Section 225 .235, which will not

be part of the MPS Group

953

and which will not

be demonstrating compliance with this

Subpart B

954

pursuant to this Section.

955

956

Control

Technology

Requirements

for Emissions of

Mercury.

957

958

Requirements for EGUs in an

MPS

Group.

959

JCAR350225-08

1 8507r01

960

For each EGU in an

MPS

Group other

than

EGU that is

961

addressed

by subsection (c)(1)(B) of this Section for the period

962

beginning July

2009

(or

December 31, 2009 for an EGU for

963

which an

scrubber

fabric filter is being

installed

to be in

964

operation by December 31, 2009), and ending

December

31,

965

2014

(or

such earlier date that the EGU is subject to the mercury

966

emission standard in

subsection (d)(1) of this Section), the owner

967

or operator of the EGU must install, to the extent

not already

968

installed,

and properly operate and maintain one of the following

969

emission control devices:

970

971

A Halogenated Activated Carbon Injection

System,

972

complying with the sorbent injection requirements of

973

subsection (c)(2) of this Section, except as may

974

otherwise

provided by subsection (c)(4) of this Section,

and

975

followed by a Cold-Side Electrostatic Precipitator

or Fabric

976

Filter;

977

978

ii)

If the boiler fires bituminous coal, a Selective Catalytic

979

Reduction

(SCR)

System

and

an SO

2 Scrubber.

980

981

An owner of an EGU in an MPS Group has two options

under this

982

subsection (c). For an MPS Group that contains EGUs smaller

983

than

90 gross MW in capacity, the owner may designate any

such

984

EGUs to be not subject

subsection

(c)(1)(A) of this Section.

Or,

985

for an MPS Group that contains EGUs with gross

MW capacity of

986

less than

115 MW, the owner may designate any such EGUs

to be

987

not subject to subsection (c)(1)(A) of this Section,

provided that

988

the

aggregate

gross MW capacity of the designated EGUs does

not

989

exceed 4% of the total gross MW capacity

the

MPS

Group. For

990

any EGU

subject to one of these two options, unless the EGU is

991

subject to the emission standards in subsection (d)(2)

this

992

Section, beginning

January

2013,

and

continuing until such

993

date that the owner or operator of the EGU commits to

comply

994

with the mercury emission standard

in subsection (d)(2) of this

995

Section, the owner or operator of the EGU must install

and

996

properly operate and maintain a Halogenated Activated Carbon

997

Injection

System

that

complies

with

the sorbent injection

998

requirements of subsection (c)(2) of this

Section, except as may

999

otherwise provided by subsection (c)(4) of this Section,

and

1000

followed by either a Cold-Side Electrostatic Precipitator

or Fabric

1001

Filter.

The use of a properly installed, operated, and maintained

1002

Halogenated Activated Carbon Injection

System that meets the

JCAR350225-081 8507r01

1003

sorbent injection requirements

subsection (c)(2)

of this Section

1004

is defined

as the “principal control technique.”

1005

1006

For each

EGU for which injection of halogenated activated

carbon

1007

required

by subsection (c)(1) of this Section, the owner or operator

of the

1008

EGU must inject halogenated activated

carbon in an optimum manner,

1009

which,

except as provided in subsection

(c)(4) of this Section, is defined

1010

all of the

following:

1011

1012

The use of an injection system

designed for

effective

absorption

1013

mercury,

considering the configuration of the EGU and its

1014

ductwork;

1015

1016

The injection

of halogenated activated carbon manufactured

1017

Alstom, Norit, or Sorbent Technologies,

or Calgon Carbon’s

1018

FLUEPAC

MC Plus, or the injection of any other halogenated

1019

activated carbon or sorbent that

the owner or operator of the EGU

1020

has

demonstrated to have similar or better effectiveness

for control

1021

of mercury emissions; and

1022

1023

The

injection of sorbent at the following minimum rates,

1024

applicable:

1025

1026

For an EGU firing

subbituminous coal, 5.0 lbs per million

1027

actual cubic feet or, for any

cyclone-fired EGU that will

1028

install

a scrubber and baghouse

December

31, 2012,

and

1029

which already meets

an emission rate of 0.020 lbs

1030

mercury/GWh gross electrical output or at least

75 percent

1031

reduction of input

mercury,

2.5 lbs per million actual

cubic

1032

feet;

1033

1034

ii)

For an

EGU firing bituminous coal, 10.0 lbs per million

1035

actual cubic feet for any

cyclone-fired EGU that will install

1036

a scrubber and

baghouse by December

31,

2012, and

which

1037

already meets an emission

rate of 0.020 lb mercury/GWh

1038

gross electrical output or at least

percent reduction

1039

input mercury,

5.0 lbs per million actual cubic feet;

1040

1041

iii)

For an EGU firing a blend

of subbituminous and

1042

bituminous

coal, a rate that is the weighted average

of the

1043

above

rates,

based on the blend of coal being fired;

1044

JCAR350225-081 8507r01

1045

iv)

A rate or

rates set lower

the Agency, in writing,

than

the

1046

rate specified

in any

subsections

(c)(2)(C)(i),

1047

(c)(2)(C)(ii),

or (c)(2)(C)(iii)

of this Section on

unit-

1048

specific

basis,

provided

that the owner or

operator of the

1049

EGU

has demonstrated

that such

rate

or rates are needed

1050

that carbon injection

will not increase particulate

matter

1051

emissions

or opacity

so as to threaten

noncompliance

with

1052

applicable requirements

for particulate

matter or opacity.

1053

1054

For the

purposes

subsection (c)(2)(C)

of this Section, the

flue

1055

gas

flow rate must be

determined for the point

of sorbent

injection;

1056

provided

that this

flow rate

may be assumed

to be identical to

the

1057

stack

flow rate if the gas

temperatures at the

point

injection

and

1058

the stack

are normally within

100°F, or

the flue gas flow rate

may

1059

otherwise

be calculated

from the stack flow

rate, corrected

for the

1060

difference

in gas temperatures.

1061

1062

The owner or

operator of an EGU

that seeks

operate an EGU with

1063

activated carbon

injection rate

or rates that are set on

a unit-specific

basis

1064

pursuant to subsection

(c)(2)(C)(iv)

of this Section

must submit an

1065

application

to the Agency proposing

such rate

or rates, and must

meet

the

1066

requirements

of subsections

(c)(3)(A) and (c)(3)(B)

of this Section,

subject

1067

the limitations

of subsections

(c)(3)(C) and

(c)(3)(D)

of this Section:

1068

1069

The application

must be submitted

as an application

for a new

1070

revised federally

enforceable

operating

permit

for the EGU, and

1071

must include

a summary of

relevant mercury emission

data for

the

1072

EGU, the

unit-specific injection

rate or rates

that are proposed,

and

1073

detailed

information to support

the proposed injection

rate

rates;

1074

and

1075

1076

This

application

must be submitted

later

than the date that

1077

activated carbon

must first

be injected. For example,

the owner

1078

operator of

an EGU that must inject

activated

carbon pursuant to

1079

subsection (c)(1)(A)

of this

subsection must apply

for unit-specific

1080

injection

rate or rates

July 1,

2009.

Thereafter,

the owner or

1081

operator

of the EGU may supplement

its application;

and

1082

1083

Any

decision of the Agency

denying a permit

or granting a

permit

1084

with

conditions that set

a lower injection

rate or rates may

1085

appealed

to the Board

pursuant to Section

39 of the Act;

and

1086

JCAR350225-081 8507r01

1087

The owner or operator

of an EGU may operate at the injection rate

1088

or rates proposed in its application until a final decision is made

1089

the application, including

a final decision on any appeal to the

1090

Board.

1091

1092

During any

evaluation of the effectiveness of a listed sorbent, an

1093

alternative sorbent, or other technique

to control mercury emissions, the

1094

owner or operator of an EGU need

not

comply with the requirements

1095

subsection

(c)(2) of this Section for any system needed to carry out the

1096

evaluation, as further provided as

follows:

1097

1098

The owner or operator

of the EGU must conduct the

evaluation

1099

accordance

with a formal evaluation program submitted to the

1100

Agency at least 30 days prior

commencement of the evaluation;

1101

1102

The duration and scope of the evaluation may not exceed the

1103

duration

and

scope

reasonably needed to complete the desired

1104

evaluation of the alternative control technique, as initially

1105

addressed

by the owner or operator in a support document

1106

submitted with the evaluation

program;

1107

1108

The owner or operator of the EGU must submit a report to the

1109

Agency no later than 30 days after the conclusion of the evaluation

1110

that describes

the

evaluation

conducted and which provides the

1111

results of the evaluation; and

1112

1113

If the evaluation

of the alternative control technique shows less

1114

effective control of mercury emissions

from the EGU

than

was

1115

achieved with

the principal control technique, the owner or

1116

operator of the EGU must resume use

the principal control

1117

technique. If the evaluation

of the alternative control technique

1118

shows comparable effectiveness to the principal control technique,

1119

the owner or operator of the

EGU

may either continue to use the

1120

alternative

control

technique in a manner that is at least as effective

1121

as the principal control

technique,

or it may resume use of the

1122

principal control technique. If the evaluation

of the

alternative

1123

control

technique shows more effective control of mercury

1124

emissions than the control

technique, the owner or operator of the

1125

EGU must continue to use

the alternative control technique in a

1126

manner

that is more effective than the principal control

technique,

1127

long

as it continues to be subject to this subsection (c).

1128

JCAR350225-08 1 8507r01

1129

In addition to complying

with

the applicable recordkeeping and

1130

monitoring requirements

in Sections 225.240

through

225.290,

the

owner

1131

or operator of an EGU

that elects to comply with this Subpart B

by means

1132

this Section

must also

comply with the following additional

1133

requirements:

1134

1135

For the first

36 months that injection of sorbent is required,

it must

1136

maintain records

of the usage of sorbent, the exhaust gas flow

rate

1137

from

the EGU, and the sorbent feed rate, in pounds

per million

1138

actual cubic feet

of exhaust gas at the injection point, on a weekly

1139

average;

1140

1141

After

the first 36 months that injection of sorbent is required,

1142

must monitor activated

sorbent feed rate to the EGU, flue gas

1143

temperature

at the point of sorbent injection, and exhaust

gas flow

1144

rate from the EGU, automatically

recording

this data and the

1145

sorbent

carbon feed rate, in pounds per million actual cubic

feet

1146

exhaust gas at the injection point,

on an hourly average; and

1147

1148

If a blend

of bituminous and subbituminous coal is fired in

the

1149

EGU, it must keep

records of the amount of each type of coal

1150

burned and the required injection rate

for injection of activated

1151

carbon, on a weekly basis.

1152

1153

As an alternative

to the CEMS monitoring, recordkeeping, and reporting

1154

requirements in Sections 225.240 through 225.290,

the owner or operator

1155

of an

EGU may elect to comply with the emissions testing, monitoring,

1156

recordkeeping, and reporting requirements

in Section

225.239(c),

(d),

(e),

1157

(f)(1) and

(2), (h)(2),

(i)(3)

and

(4),

and

(j)(1).

1158

1159

7é)

In addition

complying

with the applicable reporting requirements

1160

Sections 225.240 through 225.290, the owner

or operator of an EGU

that

1161

elects to comply

with this Subpart B by means of this Section must

also

1162

submit quarterly reports for the recordkeeping

and monitoring conducted

1163

pursuant to subsection

(c)(5) of this Section.

1164

1165

Emission Standards for Mercury.

1166

1167

For each EGU in an

MPS

Group

that is not addressed by subsection

1168

(c)(1)(B) of this Section, beginning

January 1, 2015 (or such earlier

date

1169

when

the owner or operator of the EGU notifies

the Agency that it will

1170

comply

with

these

standards)

and continuing thereafter, the

owner or

JCAR350225-0818507r01

1171

operator

of the EGU must comply

with

one of the following standards

1172

a rolling 12-month

basis:

1173

1174

An emission standard of

0.0080 lb mercury/GWh gross electrical

1175

output;

1176

1177

A minimum 90-percent reduction

of input mercury.

1178

1179

For each EGU

in an MPS Group that has been addressed under subsection

1180

(c)(1)(B) of this Section, beginning

on the date when the owner or

1181

operator of

the EGU notifies the Agency that it will comply with these

1182

standards and continuing thereafter,

the

owner

or operator of the EGU

1183

must comply with

one of the following standards on a rolling 12-month

1184

basis:

1185

1186

An emission standard of 0.0080 lb mercury/GWh

gross

electrical

1187

output; or

1188

1189

A minimum

90-percent reduction of input mercury.

1190

1191

Compliance with the mercury emission standard or

reduction requirement

1192

of this subsection (d) must be calculated in accordance with Section

1193

225.230(a)

or (d).

1194

1195

Until June 30, 2012, as an alternative

to demonstrating compliance with

1196

the emissions standards in this subsection

(d),

the owner or operator

of an

1197

EGU may elect to comply with

the emissions testing requirements in

1198

Section

225.239(c),

(d),

(e),

(f)(1)

and

(2),

(h)(2),

(i)(3)

and

(4),

and

(j)(1)

1199

of this Subpart.

1200

1201

Emission Standards for

and

1202

1203

Emission Standards.

1204

1205

Beginning in calendar

year

2012

and continuing in each calendar

1206

thereafter, for the EGUs in each MPS Group, the owner

and

1207

operator of the

EGUs must comply with an overall

annual

1208

emission rate of no more

than 0.11 lb/million Btu or an emission

1209

rate equivalent to 52 percent of the Base

Annual Rate of

1210

emissions, whichever is more stringent.

1211

1212

Beginning in the 2012

ozone season and continuing in each

ozone

1213

season thereafter, for the EGUs

in each MPS Group, the owner and

JCAR350225-08 1 8507r01

1214

operator of the EGUs must

comply with an overall

seasonal

1215

emission rate

of no more than 0.11 lb/million Btu or an

emission

1216

rate equivalent to

percent

of the Base Seasonal Rate of

1217

emissions, whichever is more stringent.

1218

1219

Emission Standards.

1220

1221

Beginning in calendar year 2013 and continuing in

calendar year

1222

2014, for the

EGUs in each MPS Group, the owner and operator

1223

the EGUs must comply with

an overall SO

2 annual emission

rate

1224

0.33

lb/million

Btu

or a rate equivalent to 44 percent of

the Base

1225

Rate of

emissions, whichever

is more stringent.

1226

1227

Beginning in calendar year 2015 and continuing in

each calendar

1228

year thereafter,

for the EGUs in each MPS Grouping, the owner

1229

and

operator of the EGUs must comply with an overall

annual

1230

emission rate for

2 of 0.25 lbs/million Btu or a rate equivalent

1231

percent of the Base Rate of

emissions, whichever

is more

1232

stringent.

1233

1234

Compliance with the

and

emission standards

must be

1235

demonstrated

in accordance with Sections 225.310, 225.410,

and 225.510.

1236

The owner or

operator of EGUs must complete the demonstration

1237

compliance before

March

1 of the following year for annual standards

and

1238

before November 1 for seasonal standards,

by which date a compliance

1239

report must be submitted to the Agency.

1240

1241

Requirements for

and

Allowances.

1242

1243

The owner or operator of EGUs in an MPS Group must not

sell or trade

1244

any person or otherwise

exchange

with or give to any person

1245

allowances allocated

to the EGUs in the MPS Group for vintage

years

1246

2012 and beyond that would otherwise

available

for sale, trade, or

1247

exchange

as a result

of actions taken to comply with the standards

1248

subsection (e) of this Section.

Such

allowances

that are not retired for

1249

compliance must be surrendered to the Agency on an annual

basis,

1250

beginning in calendar

year

2013. This provision does not apply

to the use,

1251

sale, exchange, gift, or

trade

of allowances

among the EGUs in an

MPS

1252

Group.

1253

1254

The owners or

operators of EGUs in an MPS Group must not

sell or trade

1255

to any person or otherwise exchange

with or give to any person

1256

allowances allocated to the

EGUs in

the

MPS Group for vintage years

JCAR350225-08

1 8507r01

1257

2013 and

beyond that

would otherwise be

available

for

sale or trade as a

1258

result

of actions taken

to comply with

the standards in subsection

(e) of

1259

this Section.

Such

allowances

that

are not

retired for compliance,

1260

otherwise

surrendered

pursuant to a consent

decree

which

the State

1261

Illinois is a party, must

be surrendered

to the Agency on

an annual basis,

1262

beginning

in calendar

year

2014.

This provision does

not apply to the

use,

1263

sale, exchange,

gift, or trade of allowances

among

the EGUs in an MPS

1264

Group.

1265

1266

The provisions

of this subsection

(f) do not restrict

or inhibit the

sale or

1267

trading of allowances

that

become available from

one or more EGUs

in a

1268

MPS Group

as a result of holding

allowances

that represent over-

1269

compliance

with the

SO standard in subsection

(e) of this Section,

1270

once such a standard

becomes

effective, whether such

over-compliance

1271

results from

control equipment, fuel

changes, changes

in the method

1272

operation, unit shut

downs,

other reasons.

1273

1274

For purposes of

this

subsection

(f),

and

allowances

mean

1275

allowances

necessary

for compliance

with Subpart

W of Section 217

(NOX

1276

Trading Program

for Electrical

Generating Units)Sections

225.310,

1277

225.4 10, or

225.5

10,

CFR

72, Subparts or subparts

A through

IA and

1278

AAAA

of 40 CFR

96,

or any future federal

emissions

trading

1279

programs

that include Illinois

sources.

This Section does not

prohibit

the

1280

owner

or operator of

EGUs in an MPS

Group

from purchasing

1281

otherwise

obtaining

allowances from other

sources

allowed

by law for

1282

purposes of complying

with

federal

or state requirements,

except

1283

specifically set forth

in this Section.

1284

1285

Before March 1,

2010, and continuing

each year thereafter,

the owner

1286

operator of EGUs

in an MPS Group

must submit a report

to the

Agency

1287

that

demonstrates

compliance

with the

requirements

of this subsection

(f)

1288

for the previous calendar

year, and

which includes identification

of any

1289

allowances

that

have

been surrendered

to the

USEPA

or to the Agency

and

1290

any allowances that were

sold, gifted,

used,

exchanged,

or traded

because

1291

they

became

available

due to over-compliance.

All

allowances that are

1292

required to be surrendered

must

surrendered

August

31,

unless

1293

USEPA has not yet

deducted the allowances

from the

previous year.

1294

final

report

must

be submitted to the

Agency

August 31 of each year,

1295

verifying that

the actions described

in the initial report

have taken

place

1296

or, if such actions

have

not

taken place, an explanation

of all changes

that

1297

have occurred

and the reasons

for

such

changes.

If USEPA has not

1298

deducted

the

allowances

from the previous

year by August 31,

the final

JCAR350225-08 1 8507r01

1299

report must be due, and all

allowances required to be surrendered must

1300

surrendered,

within 30 days after such deduction

occurs.

1301

1302

Notwithstanding 35 Ill. Adm.

Code

201 .146(hhh), until an EGU has complied

1303

with the applicable emission standards

subsections

(d) and (e) of this Section

1304

for 12

months, the

owner

operator of the EGU

must obtain

a construction

1305

permit

for any new or modified

air pollution control equipment that it proposes

1306

construct for control of emissions

of mercury,

NOR,

1307

1308

(Source: Amended at 33 Ill. Reg.

effective

1309

1310

Section

225.234 Temporary Technology-Based

Standard for EGUs at Existing Sources

1311

1312

General.

1313

1314

At a source with EGUs that

commenced commercial operation on or

1315

before December

31, 2008, for an EGU that meets the eligibility

criteria in

1316

subsection (b) of this Section,

the

owner or operator of the EGU may

1317

temporarily comply with the requirements

this Section

through June

30,

1318

2015, as an alternative

to compliance with the mercury emission

standards

1319

in Section 225.230,

as provided in subsections (c), (d), and (e) of this

1320

Section.

1321

1322

An EGU that is complying with the emission control requirements

of this

1323

Subpart B

by operating pursuant to this Section may not be included

in a

1324

compliance demonstration involving

other EGUs during the period that

1325

operating pursuant to this Section.

1326

1327

The owner or operator of an EGU that is complying with this

Subpart B

1328

means of the temporary

alternative emission standards of this Section

1329

not

excused

from any of the applicable monitoring, recordkeeping,

and

1330

reporting requirements

set

forth in

Sections

225 .240

through 225.290.

1331

1332

Until June 30, 2012,

an alternative

to the CEMS monitoring,

1333

recordkeeping,

and reporting requirements in Sections 225 .240

through

1334

225.290, the owner

operator

of an EGU may elect to comply with

the

1335

emissions

testing,

monitoring, recordkeeping, and reporting

requirements

1336

in Section

225 .239(c),

(d),

(e),

(f)(1)

and

(2), (h)(2),

(i)(3) and (4),

and

1337

(j)(1).

1338

1339

Eligibility.

1340

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

the following criteria

1341

must be met

for the EGU:

JCAR350225-081 8507r01

1342

1343

The

EGU is equipped and operated with the

air

pollution control

1344

equipment

or systems that include injection of halogenated activated

1345

carbon and either a cold-side

electrostatic precipitator or a fabric filter.

1346

1347

The owner

or operator of the EGU is injecting halogenated activated

1348

carbon in an

optimum manner for control of mercury emissions, which

1349

must include injection of Aistrom,

Norit, Sorbent

Technologies, Calgon

1350

Carbon’s

FLUEPAC MC Plus, or other halogenated activated carbon

that

1351

the owner or operator

of the EGU has demonstrated to have similar or

1352

better effectiveness for control of mercury emissions, at least at the

1353

following rates set forth in

subsections (b)(2)(A) through (b)(2)(D) of this

1354

Section,

unless other provisions for injection of halogenated activated

1355

carbon are established in a federally

enforceable

operating permit issued

1356

for the EGU,

using an injection system designed for effective absorption

1357

of mercury, considering the configuration

the EGU and its ductwork.

1358

For the purposes

of this subsection (b)(2), the flue gas flow rate must

1359

determined for the point of sorbent injection

(provided,

however,

that this

1360

flow

rate may be assumed to be identical to the stack flow rate if the

gas

1361

temperatures

at the point of injection and the stack are normally within

1362

100° F) or may otherwise be calculated

from the stack flow rate, corrected

1363

for the difference in gas temperatures.

1364

1365

For an EGU firing subbituminous coal, 5.0 lbs per million actual

1366

cubic feet.

1367

1368

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

1369

cubic feet.

1370

1371

For an EGU firing a blend of subbituminous

and

bituminous

coal,

1372

rate that

is the weighted average of the above rates, based on

the

1373

blend of coal being fired.

1374

1375

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

the

1376

rate specified

above to the extent that the owner or operator of

the

1377

EGU demonstrates that such rate

or rates are needed so that carbon

1378

injection would not increase particulate matter emissions or

1379

opacity

so as to threaten compliance with applicable regulatory

1380

requirements for particulate matter

or opacity.

1381

1382

The total capacity of the EGUs that operate pursuant to this Section

does

1383

not

exceed the applicable of the following values:

1384

JCAR350225-081

8507r01

1385

For

the

owner or operator

of more than

one existing source

with

1386

EGUs,

25 percent

of the total rated capacity,

MW,

of all

the

1387

EGUs at the existing

sources that it

owns or operates, other

than

1388

any

EGUs operating

pursuant

Section

225.235

this Subpart B.

1389

1390

For the owner

or operator of only

a single existing source

with

1391

EGUs (i.e., City,

Water, Light

& Power, City of

Springfield, ID

1392

167120AA0;

Kincaid Generating

Station,

ID 021814AAB;

and

1393

Southern Illinois

Power Cooperative/Marion

Generating

Station,

1394

ID 199856AAC),

25 percent

of the total rated

capacity, in MW,

1395

the all the

EGUs

at the existing

sources, other than

any

EGUs

1396

operating

pursuant to Section 225.235.

1397

1398

Compliance

Requirements.

1399

1400

Emission

Control

Requirements.

1401

The owner or operator

of an EGU

that is operating pursuant

to this

Section

1402

must continue to

maintain and operate

the EGU

to comply

with the criteria

1403

for eligibility for

operation pursuant

to this Section, except

during an

1404

evaluation of the

current

sorbent,

alternative

sorbents

or other

techniques

1405

to control mercury

emissions, as

provided by subsection

(e) of this

1406

Section.

1407

1408

Monitoring

and

Recordkeeping

Requirements.

1409

In addition

to complying

with all applicable

monitoring and

recordkeeping

1410

reporting requirements

in Sections 225 .240

through 225.290

or Section

1411

225.239(c),

(d),

(e), (f)(1)

and

(2), (h)(2),

and

i(3)

and

(4),

the

owner

1412

operator of an EGU operating

pursuant

this

Section must

also:

1413

1414

Through December

31, 2012, it must

maintain

records

of the usage

1415

of activated

carbon, the exhaust

gas flow rate from the

EGU,

and

1416

the activated

carbon

feed rate, in pounds

per

million

actual cubic

1417

feet of exhaust

gas at the injection

point, on a weekly

average.

1418

1419

Beginning

January 1, 2013, it must

monitor activated

carbon

feed

1420

rate to the EGU,

flue gas temperature

the point

of sorbent

1421

injection,

and exhaust gas flow

rate from the EGU, automatically

1422

recording this

data and the

activated carbon feed

rate, in pounds

1423

per million

actual

cubic

feet

of exhaust gas at

the injection point,

1424

on an

hourly average.

1425

1426

If a blend

of bituminous

and subbituminous

coal is fired in the

1427

EGU,

it must maintain

records of the

amount of each type

coal

JCAR350225-081 8507r01

1428

burned and the required

injection

rate for injection of halogenated

1429

activated carbon, on a weekly basis.

1430

1431

Notification and Reporting Requirements.

1432

In addition to complying with all applicable

reporting requirements in

1433

Sections 225.240

through 225.290 or Section 225.239(f)(1), (f)(2),

and

1434

(j)(1), the owner or

operator of an EGU operating pursuant to this Section

1435

must also submit the following notifications

and reports to the Agency:

1436

1437

Written notification

prior to the month in which any of the

1438

following events will occur:

1439

1440

The EGU will no longer be eligible to operate under

this

1441

Section due to a change

in operation;

1442

1443

ii)

The type of coal fired in

the EGU will change; the mercury

1444

emission

standard

with which the owner or operator is

1445

attempting to comply

for the EGU will change; or

1446

1447

iii)

Operation

under this Section will be terminated.

1448

1449

Quarterly reports for the recordkeeping

and monitoring or

1450

emissions testing conducted pursuant to subsection (c)(2)

of this

1451

Section.

1452

1453

Annual reports detailing activities

conducted for the EGU to

1454

further improve control of mercury emissions, including the

1455

measures taken during the past

year

and activities planned for the

1456

current year.

1457

1458

Applications

Operate

under the Technology-Based Standard

1459

1460

Application Deadlines.

1461

1462

The owner

or operator of an EGU that is seeking to operate the

1463

EGU pursuant to this Section must

submit an application to the

1464

Agency

no later than three months prior to the date on which

1465

compliance with

Section 225.230 of this Subpart B would

1466

otherwise have to be demonstrated.

For example, the owner or

1467

operator of an EGU that is applying

to operate the EGU pursuant

1468

to this Section on June 30, 2010, when compliance with

applicable

1469

mercury emission

standards must be first demonstrated,

must apply

1470

March 31, 2010 to

operate under this Section.

JCAR350225-08 1 8507r01

1471

1472

Unless the Agency

finds that the EGU is not eligible to operate

1473

pursuant to this Section or that

the application for operation

1474

pursuant

this

Section

does not meet the requirements

1475

subsection (d)(2)

of this Section, the owner or operator of the

EGU

1476

is authorized to operate

the

EGU pursuant to this Section

1477

beginning 60 days after receipt

of the application by the Agency.

1478

1479

The owner or

operator of an EGU operating pursuant to this

1480

Section must reapply to operate pursuant

to this Section:

1481

1482

If it operated the EGU pursuant to

this

Section 225.234

1483

during the

period of June 2010 through December 2012

and

1484

it seeks to operate the EGU pursuant to this Section

1485

225.234 during

the

period from January

2013

through

June

1486

2015.

1487

1488

ii)

If it is planning a physical change to or a change

in the

1489

method

of operation of the EGU, control equipment or

1490

practices for injection

activated

carbon that is expected

1491

to reduce the level of control of mercury emissions.

1492

1493

Contents of Application.

1494

An application to operate

an EGU pursuant to this Section 225 .234

must

1495

be submitted as an application for a new or revised federally

enforceable

1496

operating

permit

for the EGU, and it must include the following

1497

documents and information:

1498

1499

A formal request

to operate pursuant to

this

Section

showing

that

1500

the EGU is eligible to operate pursuant to this Section and

1501

describing the reason

for the request, the measures that have

been

1502

taken

for control

of mercury emissions, and factors preventing

1503

more effective control

mercury emissions

from

the

EGU.

1504

1505

The applicable mercury emission standard

in Section

225

.230(a)

1506

with

which the owner or operator of the EGU is attempting

1507

comply and

a summary of relevant mercury emission data for

the

1508

EGU.

1509

1510

a unit-specific

rate or rates for carbon injection are proposed

1511

pursuant

to subsection (b)(2) of this Section, detailed information

1512

to support the

proposed injection rates.

1513

JCAR350225-08 1 8507r01

1514

An action plan

describing the measures that will be taken while

1515

operating

under

this Section to

improve control of mercury

1516

emissions.

This plan must address measures such as evaluation

1517

alternative forms or

sources of activated carbon, changes

the

1518

injection system, changes to

operation of the unit that affect the

1519

effectiveness

of mercury absorption and

collection, changes to the

1520

particulate

matter control device to improve performance,

and

1521

changes to other emission

control devices. For each measure

1522

contained

in the plan, the plan must

provide a detailed description

1523

of the specific

actions that are planned, the reason that the measure

1524

being pursued and the range

of improvement in control of

1525

mercury that

expected,

and the factors that affect the timing

for

1526

carrying

out the measure, together with the current

schedule

for the

1527

measure.

1528

1529

Evaluation of Alternative Control Techniques

for Mercury Emissions.

1530

1531

During an evaluation of the effectiveness

of the current sorbent,

1532

alternative

sorbent, or other technique to control mercury

emissions, the

1533

owner or operator

of an EGU operating pursuant to this Section need

not

1534

comply with the eligibility

criteria

for operation pursuant to this Section

1535

needed to carry out an evaluation of the

practicality and effectiveness

1536

such

technique, subject to the following limitations:

1537

1538

The owner or

operator of the EGU must conduct the evaluation

1539

accordance with a formal evaluation

program

that it has submitted

1540

to the Agency

at least 30 days prior to beginning the evaluation.

1541

1542

The duration

and scope of the formal evaluation program

must not

1543

exceed the duration and

scope reasonably needed to complete

the

1544

desired evaluation

of the alternative control technique, as

initially

1545

addressed by the owner or owner

in a support document that it

has

1546

submitted with

the formal evaluation program pursuant to

1547

subsection (e)(1)(A) of this Section.

1548

1549

Notwithstanding 35 Ill. Adm.

Code 201.146(hhh), the owner

1550

operator

of the EGU must obtain a construction

permit for any new

1551

or modified

air pollution control equipment to be constructed

1552

part of the evaluation

of the alternative control technique.

1553

1554

The

owner

or operator of the EGU

must

submit

a report to the

1555

Agency, no

later than 90 days after the conclusion

of the formal

JCAR350225-081

8507r01

1556

evaluation program describing the evaluation

that

was

conducted,

1557

and

providing

the results

of the formal evaluation program.

1558

1559

If the

evaluation of the alternative control technique shows less

effective

1560

control

of mercury

emissions

from the EGU than achieved with the

prior

1561

control technique, the owner or

operator of the EGU must resume use

1562

the prior control technique. If the evaluation

of the

alternative

control

1563

technique

shows comparable control effectiveness, the owner or

operator

1564

of the EGU may either continue

to use the alternative control technique

1565

an optimum manner or resume use of the prior control technique.

If the

1566

evaluation of

the

alternative

control

technique shows more effective

1567

control of mercury emissions, the owner or operator

the EGU

must

1568

continue to use the alternative

control technique in an optimum manner,

1569

it continues to operate pursuant to this Section.

1570

1571

(Source:

Amended at

33 Ill. Reg.

effective

1572

1573

Section 225.235 Units

Scheduled

for Permanent Shut Down

1574

1575

The emission standards of Section 225.230(a) are

not

applicable

to an EGU that

1576

will be permanently shut down as described in this Section:

1577

1578

The owner or

operator of an EGU that relies on this Section must

1579

complete the following actions

before June 30, 2009:

1580

1581

Have

notified the Agency that it is planning to permanently

shut

1582

down the EGU

by the applicable date specified in subsection

(a)(3)

1583

or (4)

of this Section. This notification must include a

description

1584

of the actions

that have already been taken to allow the shut down

1585

the

EGU and a description of the future actions that must

1586

accomplished to complete

the shut down of the EGU, with the

1587

anticipated

schedule for those actions and the anticipated date

1588

permanent shut down of the unit.

1589

1590

Have applied for a construction

permit or be actively pursuing

1591

federally

enforceable agreement that requires the EGU

to be

1592

permanently

shut

down

in accordance with this Section.

1593

1594

Have applied for revisions to the operating permits for

the EGU

1595

include

provisions that terminate the authorization to operate

the

1596

unit in accordance

with this Section.

1597

JCAR35022508

8507r01

1598

The

owner or operator

of an EGU

that

relies

on this

Section must,

before

1599

June 30, 2010,

complete the following

actions:

1600

1601

Have

obtained a construction

permit

entered into a federally

1602

enforceable

agreement

as described

in subsection (a)(1)(B)

of this

1603

Section;

1604

1605

Have obtained revised

operating

permits in accordance

with

1606

subsection

(a)(1)(C)

of this Section.

1607

1608

The plan

for

permanent

shut down of the EGU

must provide

for the

EGU

1609

to be

permanently shut down

no later

than the applicable

date

specified

1610

below:

1611

1612

If the owner

operator of the EGU

is not constructing

a new EGU

1613

or other generating

unit to specifically

replace the existing

EGU,

1614

by December31,

2010.

1615

1616

If the

owner or

operator of the EGU

is constructing

a new EGU

1617

other generating

unit to specifically

replace

the existing

EGU, by

1618

December3l,2011.

1619

1620

The owner

operator of the EGU

must

permanently

shut down the

EGU

1621

by the date

specified in subsection

(a)(3) of this

Section, unless the

owner

1622

or operator submits

a demonstration

to the Agency

before the specified

1623

date showing

that circumstances

beyond its

reasonable control (such

1624

protracted delays

in construction

activity, unanticipated

outage

of another

1625

EGU, or

protracted shakedown

of a replacement

unit) have occurred

that

1626

interfere with

the

plan for

permanent shut down

of the EGU,

in which

case

1627

the Agency

may

accept the demonstration

as substantiated and extend

the

1628

date for shut

down

of the

EGU as follows:

1629

1630

If the

owner

or operator

of the EGU is not

constructing

a new EGU

1631

other generating unit

to specifically

replace

the existing

EGU,

1632

for up

to one

year,

i.e., permanent shut

down of the

EGU

to occur

1633

byno

later than December31,

2011;

1634

1635

the owner

operator of the EGU

is constructing

a new EGU

1636

other generating unit

specifically

replace the existing

EGU, for

1637

up to 18 months,

i.e., permanent

shutdown of the

EGU to occur

1638

no later

than

June 30, 2013; provided,

however,

that afler

1639

December

31, 2012, the existing

EGU must only

operate as a

back-

1CAR350225-081

8507r01

1640

unit to address periods when

the

new

generating

units are not

1641

service.

1642

1643

Notwithstanding

Sections 225 .230 and 225.232, any

EGU

that

is not required to

1644

comply with Section 225.230

pursuant

to this Section must not be included

when

1645

detennining whether any other

EGUs at the source or other sources are in

1646

compliance with Section 225.230.

1647

1648

If an EGU, for which the owner

or operator of the source has relied upon this

1649

Section in lieu of complying with Section 225.230(a)

is not permanently shut

1650

down as required

this Section,

the EGU must be considered to be a new

EGU

1651

subject to the emission standards in Section 225 .237(a) beginning

in the month

1652

after the EGU was required to

be permanently shut down, in addition to any

other

1653

penalties that may

be imposed for failure to permanently shut down the

EGU in

1654

accordance with this Section.

1655

1656

çj

An EGU that has completed the requirements

of subsection (a) of this Section

1657

exempt from

the

monitoring and testing requirements in Sections 225 .239

and

1658

225.240.

1659

1660

An EGU that is scheduled for permanent shut down pursuant to Section

1661

225.294(b) is exempt

from the monitoring and testing requirements in

Sections

1662

225.239 and 225 .240.

1663

1664

(Source: Amended at 33 Ill. Reg.

effective

1665

1666

Section

225.237 Emission Standards for New Sources

with EGUs

1667

1668

Standards.

1669

1670

Except as provided in Sections 225.238

and 225.239, theThe owner or

1671

operator of

a source with one or more EGUs, but that previously

had not

1672

had any EGUs that commenced

commercial operation before January

1673

2009, must

comply

with one of the following emission standards

for each

1674

EGU on a rolling 12-month basis:

1675

1676

An emission

standard of 0.0080 lb mercury/GWh gross electrical

1677

output; or

1678

1679

minimum 90 percent reduction

input mercury.

1680

1681

For this purpose, compliance

may be demonstrated using the equations

1682

Section 225.230(a)(2), (a)(3), or (b)(2).

JCAR350225-08

1 8507r01

1683

1684

The

initial 12-month

rolling period

for which compliance with the emission

1685

standards of

subsection (a)(1) of this Section must

demonstrated

for a new

1686

EGU will commence

the

date that the initial performance testing

commences

1687

under

CFR 60.8test for the

mercury emission standard under 40 CFR 60.45a

1688

also commences. The CEMS required

by this Subpart B for mercury emissions

1689

from the

EGU must be certified prior to this date. Thereafier,

compliance must

1690

demonstrated on

rolling 12-month

basis based on calendar months.

1691

1692

(Source: Amended at

33 III. Reg.

effective

1693

1694

Section 225.238 Temporary

Technology-Based Standard for New Sources with

EGUs

1695

1696

General.

1697

1698

At a source with

EGUs that previously had not had any EGUs that

1699

commenced commercial operation before January

1, 2009, for an EGU

1700

that meets the eligibility

criteria in subsection (b) of this Section,

as an

1701

alternative to compliance with the

mercury emission standards in Section

1702

225.237,

the owner or operator of the EGU may

temporarily comply with

1703

the requirements

of this Section, through December 31, 2018, as

further

1704

provided in subsections

(c), (d), and (e) of this Section.

1705

1706

An EGU that is complying with the

emission control requirements of

this

1707

Subpart B by operating pursuant to this Section

may not

be included in

1708

compliance demonstration

involving other EGUs at the source during

the

1709

period that the temporary technology-based

standard is in effect.

1710

1711

The owner or operator of an EGU that

is complying with this Subpart

1712

pursuant to this Section

is not excused from applicable monitoring,

1713

recordkeeping, and reporting requirements

of Sections

225.240

through

1714

225.290.

1715

1716

Until June 30, 2012, as an alternative

to the CEMS monitoring,

1717

recordkeeping,

and reporting requirements in Sections 225 .240

through

1718

225.290, the owner or

operator of an EGU may elect

comply with

the

1719

emissions testing, monitoring, recordkeeping,

and reporting requirements

1720

Section

225 .239(c),

(d), (e),

(f)(1) and (2), (h)(2),

(i)(3)

and

(4),

and

1721

(j)(1).

1722

1723

Eligibility.

1724

To be eligible to operate an EGU pursuant

to this Section, the following criteria

1725

must

be met

for

the

EGU:

JCAR350225-08 1 8507r01

1726

1727

The EGU is subject to Best Available Control Technology (BACT)

for

1728

emissions

sulfur

dioxide,

nitrogen oxides, and particulate matter,

and

1729

the EGU is equipped and operated with the air pollution

control equipment

1730

or systems specified below, as applicable to the category

EGU:

1731

1732

For

coal-fired boilers, injection of sorbent or other mercury control

1733

technique (e.g., reagent) approved

the Agency.

1734

1735

For an

EGU

firing

fuel gas produced by coal gasification,

1736

processing of the raw fuel gas prior to combustion for removal

1737

mercury with

a system using a sorbent or other mercury control

1738

technique approved by the Agency.

1739

1740

For

an EGU for which injection of a sorbent or other mercury control

1741

technique is required pursuant to subsection (b)(1) of this Section,

the

1742

owner or

operator of the EGU is injecting sorbent or other mercury control

1743

technique in an optimum manner for control of mercury emissions,

which

1744

must include injection of Aistrom, Norit, Sorbent Technologies, Calgon

1745

CarbontsFLUEPAC

MC Plus, or other sorbent or other mercury control

1746

technique that the owner or

operator of the EGU

demonstrates

to have

1747

similar or better effectiveness for control of mercury emissions,

at least at

1748

the rate set forth in the appropriate of subsections (b)(2)(A) through

1749

(b)(2)(C) of this Section, unless other provisions for injection of sorbent

1750

other mercury control

technique are established in a federally enforceable

1751

operating permit issued for the EGU, with an injection system

designed

1752

for effective absorption of mercury. For the purposes of this subsection

1753

(b)(2), the flue gas flow rate must

determined

for the point of sorbent

1754

injection or other mercury control technique (provided, however, that

this

1755

flow rate may be assumed to be identical

the stack flow rate

if the gas

1756

temperatures

at the point of injection and the stack are normally within

1757

100° F), or the flow rate may otherwise be calculated from the

stack flow

1758

rate, corrected for the

difference

in gas temperatures.

1759

1760

For an EGU

firing subbituminous coal, 5.0 pounds per million

1761

actual cubic feet.

1762

1763

For an EGU

firing bituminous coal, 10.0 pounds per million

actual

1764

cubic feet.

1765

1766

For

an EGU firing a blend

subbituminous and bituminous

coal,

1767

rate

that is the weighted average of the above rates, based

on the

1768

blend of coal

being fired.

JCAR350225-081

8507r01

1769

1770

A rate or rates set

unit-specific

basis that are lower than

the

1771

rate

specified in subsections (b)(2)(A), (B),

and (C) of this Section,

1772

to the extent that

the owner or operator of the

EGU demonstrates

1773

that such rate or

rates are needed so that sorbent injection

or other

1774

mercury control technique

would

not

increase

particulate

matter

1775

emissions

or opacity so as

threaten compliance

with

applicable

1776

regulatory requirements

for particulate matter or opacity

cause

1777

safety issue.

1778

1779

Compliance Requirements.

1780

1781

Emission Control Requirements.

1782

The owner or

operator of an EGU that is operating pursuant to

this Section

1783

must continue to maintain and operate the

EGU to comply with the criteria

1784

for eligibility for

operation under this Section, except during

an evaluation

1785

of the current sorbent, alternative sorbents,

or other techniques to control

1786

mercury emissions,

as provided by subsection (e) of this Section.

1787

1788

Monitoring and Recordkeeping Requirements.

1789

In addition

to complying with all applicable monitoring and

1790

requirements in Sections 225.240 through

225.290

1791

or Section 225.239(c),

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

and

(2), (h)(2),

and (i)(3) and (4),

the

1792

owner or operator of a new EGU

operating pursuant to this Section

must

1793

also:

1794

1795

Monitor sorbent feed rate

to the EGU, flue gas temperature at

the

1796

point

of sorbent injection or other mercury control

technique, and

1797

exhaust gas flow rate from

the EGU,

automatically recording

this

1798

data

and the sorbent feed rate, in pounds per million

actual cubic

1799

feet of exhaust gas at the injection

point, on an hourly average.

1800

1801

If a blend of bituminous and subbituminous

coal is fired in the

1802

EGU, maintain

records of the amount of each type of coal

burned

1803

and the required injection rate for

injection of sorbent, on a weekly

1804

basis.

1805

1806

If a mercury control technique

other than sorbent injection is

1807

approved by the Agency, monitor appropriate

parameter for that

1808

control

technique as specified by the Agency.

1809

1810

Notification and Reporting Requirements.

JCAR350225-081 8507r01

1811

addition to complying with all applicable

reporting requirements

1812

Sections 225.240

through

225.290 or Section 225.239(f)(1) and (2)

and

1813

(j)(1),

the owner

operator

of an EGU operating pursuant to this

Section

1814

must

also submit the following notifications and

reports to the Agency:

1815

1816

Written notification

prior

to the month in which any of the

1817

following events will occur:

the

EGU will no longer be eligible

1818

operate under this Section due to a change in operation;

the type

1819

coal fired

in the EGU will change; the mercury emission

standard

1820

with which the owner or operator

attempting

to comply for

the

1821

EGU

will change; or operation under this Section will be

1822

terminated.

1823

1824

Quarterly reports for the recordkeeping and

monitoring or

1825

emissions testing

conducted

pursuant to subsection (c)(2) of

this

1826

Section.

1827

1828

Annual reports detailing activities conducted

for

the

EGU to

1829

further improve

control of mercury emissions, including the

1830

measures taken during the past

year and activities planned for

the

1831

current year.

1832

1833

Applications to Operate

under the Technology-Based Standard.

1834

1835

Application Deadlines.

1836

1837

The owner

or operator of an EGU that is seeking to operate

the

1838

EGU pursuant to this Section must

submit

an application to the

1839

Agency no

later than three months prior to the date that

1840

compliance with Section 225.237 would otherwise have

to be

1841

demonstrated.

1842

1843

Unless the Agency finds that

the EGU is not eligible to operate

1844

pursuant

to this Section or that the application for operation

under

1845

this Section does not

meet

the requirements of subsection (d)(2)

1846

this Section, the owner or operator

of the EGU is authorized to

1847

operate the

EGU

pursuant to this Section beginning

days

after

1848

receipt of the application

by the Agency.

1849

1850

The owner or operator of an EGU operating

pursuant to this

1851

Section must

reapply to operate pursuant to this Section if it

1852

planning a

physical change to or a change in the method of

1853

operation of the EGU, control

equipment,

or practices for injection

JCAR350225-08

1 8507r01

1854

of sorbent

or other mercury control technique that

is expected

1855

reduce the level

of control of mercury emissions.

1856

1857

Contents of

Application.

1858

An application to

operate pursuant to this Section must be submitted

as an

1859

application for a new or revised

federally enforceable operating permit

for

1860

the new

EGU, and it must include the following

information:

1861

1862

A formal request

to operate pursuant to this Section showing

that

1863

the

EGU is eligible to operate pursuant to this

Section and

1864

describing

the reason for the request, the measures that have

been

1865

taken

for control of mercury emissions, and factors

preventing

1866

more effective

control

of mercury emissions from the EGU.

1867

1868

The applicable mercury

emission standard in Section 225.237

with

1869

which

the owner or operator of the EGU is attempting

to comply

1870

and a summary of relevant

mercury

emission data for the EGU.

1871

1872

If a unit-specific

rate

or rates for sorbent or other mercury control

1873

technique injection are proposed pursuant

to subsection (b)(2)

1874

this

Section, detailed information to support the proposed

injection

1875

rates.

1876

1877

An action plan

describing

the measures that will be taken while

1878

operating pursuant to this Section

improve

control

of mercury

1879

emissions.

This plan must address measures such as evaluation

1880

alternative forms

or sources of sorbent or other mercury control

1881

technique, changes to the injection system, changes

to operation

1882

the unit that affect

the

effectiveness of mercury absorption and

1883

collection,

and changes to other emission control devices.

For

1884

each measure contained in

the plan, the plan must provide a

1885

detailed

description of the specific actions that are planned,

the

1886

reason that the measure is being

pursued

and the range of

1887

improvement

in control of mercury that is expected, and

the factors

1888

that affect the timing for carrying

out the measure, with the current

1889

schedule

for the measure.

1890

1891

Evaluation of Alternative Control Techniques

for Mercury Emissions.

1892

1893

During an evaluation

of the effectiveness of the current

sorbent,

1894

alternative sorbent,

or other technique to control mercury emissions,

the

1895

owner or operator of an

EGU operating pursuant to this Section does

not

1896

need

to comply with the eligibility criteria for

operation pursuant to

this

JCAR350225-081

8507r01

1897

Section

as needed to carry out an

evaluation of the practicality and

1898

effectiveness

of such technique, further subject

the

following

1899

limitations:

1900

1901

The owner or operator of the

EGU must conduct the evaluation

1902

accordance

with a formal evaluation

program

that it has submitted

1903

the

Agency at least 30 days prior to beginning the evaluation.

1904

1905

The

duration and scope of the

formal evaluation program must

not

1906

exceed the

duration and scope reasonably needed to complete

the

1907

desired evaluation of the alternative

control technique, as initially

1908

addressed

by the owner or operator in a support document

that it

1909

has submitted with the formal

evaluation program pursuant to

1910

subsection (e)(1)(A)

of this Section.

1911

1912

Notwithstanding 35 Ill.

Adm. Code 201.146(hhh), the owner

1913

operator of the EGU must obtain a construction

permit for any

new

1914

or modified air pollution

control equipment to be constructed

1915

part of the evaluation of the alternative

control technique.

1916

1917

The owner

or operator of the EGU must submit a report to

the

1918

Agency no later than

90 days after the conclusion of the formal

1919

evaluation program describing

the evaluation that was conducted

1920

and providing the results of the formal evaluation

program.

1921

1922

If the evaluation of the alternative

control technique shows less effective

1923

control of mercury emissions from the EGU

than

was achieved

with the

1924

prior control technique,

the owner or operator

of the EGU must resume

1925

use of the prior control technique. If the evaluation

of the alternative

1926

control technique shows

comparable effectiveness, the owner or

operator

1927

of the EGU may either continue to use the alternative control

technique

1928

an optimum manner or resume use

of the prior control technique. If

the

1929

evaluation of

the alternative control technique shows more effective

1930

control of mercury emissions, the

owner or operator of the EGU must

1931

continue to

use the alternative control technique in an optimum

manner,

1932

it continues to operate pursuant

to this Section.

1933

1934

(Source: Amended at 33

Ill.

Reg.

effective

1935

1936

Section

225.239 Periodic Emissions Testing Alternative

Requirements

1937

1938

General.

1939

JCAR350225-081 8507r01

1940

As an alternative to demonstrating

compliance

with

the emissions

1941

standards of Sections

225.230(a) or 225.237(a), the owner

operator

1942

an EGU may elect

to demonstrate compliance pursuant to the emission

1943

standards in subsection

(b)

of this

Section

and

the

use of quarterly

1944

emissions testing

as an alternative to the use of

CEMS:

1945

1946

)

The owner or

operator

of an EGU that elects to demonstrate compliance

1947

pursuant to this Section must comply with the testing,

recordkeeping,

and

1948

reporting requirements

of this Section in addition to other applicable

1949

recordkeeping and reporting

requirements

this

Subpart:

1950

1951

The alternative method

of compliance provided under this subsection

may

1952

only be

used until June 30, 2012, after which a CEMS certified in

1953

accordance with Section 225.250

this

Subpart

must be used.

1954

1955

If an owner or operator of an EGU demonstrating compliance

pursuant

1956

Section 225.230

225.237

discontinues use of CEMS before collecting

1957

full 12 months of CEMS

data

and elects

to demonstrate compliance

1958

pursuant to this Section, the data collected prior to that point must

1959

averaged to

determine compliance for such period. In such case, for

1960

purposes of calculating

an emission standard or mercury control efficiency

1961

using the equations in Section 225.230(a)

(b),

the

t?12?I

in the equations

1962

will be replaced by a variable equal to the number of full

and

partial

1963

months for which the owner or operator collected CEMS data.

1964

1965

})

Emission Limits.

1966

1967

Existing Units: Beginning July

2009,

the owner or operator of a source

1968

with one or more EGUs

subject

to this Subpart B that commenced

1969

commercial operation on or before

June 30,

2009,

must comply with

one

1970

of the following standards for each EGU, as determined through

quarterly

1971

emissions testing according to subsections (c),

(d), (e),

and

(f)

of this

1972

Section:

1973

1974

)

emission standard of 0.0080 lb

mercury/GWh

gross electrical

1975

output:

1976

1977

)

minimum

90-percent reduction of input mercury.

1978

1979

)

New Units: Beginning within the first 2,160

hours after the

1980

commencement of commercial operations, the owner or

operator of a

1981

source with one or more EGUs subject to this Subpart B that commenced

1982

commercial

operation after

June

30, 2009, must comply with one of

the

JCAR350225-081

8507r01

1983

following

standards

for each EGU,

determined through quarterly

1984

emissions testing

in accordance with subsections (c),

(d),

(e), and

(f)

1985

this Section:

1986

1987

An emission

standard of 0.0080 lb

mercury/GWh

gross electrical

1988

output; or

1989

1990

minimum

90-percent reduction of input mercury.

1991

1992

c).

Initial Emissions Testing Requirements for New Units. The owner or

operator

1993

an EGU that commenced

commercial operation after June 30, 2009, and that is

1994

complying by means of this Section must conduct an initial performance

test in

1995

accordance with the requirements

of subsections

(d)

and

(e)

of this Section within

1996

the

first 2,160 hours

after the commencement of commercial operations.

1997

1998

)

Emissions Testing

Requirements

1999

2000

Subsequent to the initial performance test, emissions tests must

2001

performed on a quarterly

calendar basis in accordance with the

2002

requirements of subsections (d), (e), and (f) of this Section;

2003

2004

Notwithstanding

the provisions in subsection

(d)(1),

owners or operators

2005

of EGUs demonstrating

compliance under

Section

225.233

or Sections

2006

225.29 1 through 225.299

must

perform

emissions testing on a semi-annual

2007

calendar basis, where the

periods

consist

of the months of January

through

2008

June

and July through December, in accordance with the requirements

2009

subsections

(d), (e),

and

(f)(1)

and (2)

of this Section;

2010

2011

Emissions tests which demonstrate

compliance with this Subpart must

2012

performed at least 45 days apart. However, if an emissions test fails

2013

demonstrate

compliance

with

this Subpart or the emissions

test

is being

2014

performed

subsequent

to a significant change in the operations of an

EGU

2015

under subsection

(h)(2)

of this Section, the owner or operator

of an EGU

2016

may

perform

additional emissions tests using the same test

protocol

2017

previously submitted in the same period, with less than 45

days in between

2018

emissions

tests;

2019

2020

A minimum of three and a maximum of nine emissions

test

runs, lasting

2021

least one hour each, shall be conducted and averaged to determine

2022

compliance.

All test runs performed will be reported.

2023

2024

If the EGU shares a common

stack

with

one or more other EGUs, the

2025

owner or operator of the EGU will conduct emissions

testing

in the duct to

JCAR350225-081 8507r01

the common stack

from each unit, unless the owner or operator

of the

EGU considers the combined emissions

measured

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 to

the CEMS

monitoring provisions

Section 225.240

of this Subpart, the owner

operator must comply with the emissions

monitoring

deadlines in Section

225.240(b)(4)

of 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

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 of subsection

(b)(1)(B)

or (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 at 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

subsection (b)(1’)(A) or (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 in writing by the Manager

the Bureau

of Air’s Compliance

Section.

Notification Requirements

The owner or operator of an EGU must submit

testing

protocol as

described

in USEPA’s Emission Measurement Center’s Guideline

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

2051

2052

2053

2054

2055

2056

2057

2058

2059

2060

2061

2062

2063

2064

2065

2066

2067

2068

JCAR350225-08

1 8507r01

2069

Document

#42 to the

Agency

at least

45 days prior to a

scheduled

2070

emissions

test,

except

as provided in Section

225.239(h)(2)

and

(h)(3).

2071

Upon written request

directed

to the

Manager of the Bureau

of Air’s

2072

Compliance Section,

the Agency

may, in its sole discretion,

waive

the 45-

2073

day

requirement.

Such waiver shall

only be effective

if it

provided

2074

writing and

signed by the Manager

of the Bureau

Air’s Compliance

2075

Section,

or his

or her designee;

2076

2077

)

Notification

of a scheduled

emissions

test must

be submitted to

the

2078

Agency

in writing,

directed

to the Manager

of the Bureau of Air’s

2079

Compliance

Section, at least

30 days prior to the

expected date

of the

2080

emissions

test.

Upon

written

request directed

to the Manager of the

Bureau

2081

of Air’s

Compliance Section,

the

Agency may,

in its sole discretion,

2082

waive

the

30-day notification

requirement. Such

waiver

shall

only

2083

effective if it

is provided

in writing and signed

by the Manager of the

2084

Bureau

of Air’s Compliance Section,

or his or her designee.

Notification

2085

the actual date

and expected

time

of testing must

be submitted in writing,

2086

directed

to the Manager of the

Bureau

Air’s

Compliance Section,

2087

least five

working days prior

to the actual date

of the

test:

2088

2089

For

an EGU that has elected

to demonstrate

compliance

by use

of the

2090

emission standards of

subsection

(b)

of this

Section,

if an

emissions

test

2091

performed under

the requirements of this

Section fails to demonstrate

2092

compliance with

the limits of subsection

(b)

of this Section,

the

owner

2093

operator

of an EGU

may perform

a new emissions test

using the same

test

2094

protocol previously

submitted in the

same period,

by notifying the

2095

Manager

of the Bureau of Air’s

Compliance Section

or his or her

designee

2096

of the actual

date and

expected time

of testing at

least five working days

2097

prior

the

actual date of the test.

The Agency may,

in its sole discretion,

2098

waive this five-day

notification requirement.

Such

waiver shall only

2099

effective if it is

provided in writing

and signed by the

Manager

the

2100

Bureau of Air’s

Compliance Section,

or his or her

designee;

2101

2102

In addition to

the testing protocol

required

subsection

(f)(1)

of this

2103

Section, the owner

or operator

of an EGU that has elected

to demonstrate

2104

compliance by

use of the emission

standards

subsection

(b)

of this

2105

Section

must submit a Continuous

Parameter Monitoring

Plan

the

2106

Agency at least

days prior

to a scheduled emissions

test.

Upon

written

2107

request directed

the

Manager

the

Bureau

of Air’s Compliance

2108

Section,

the

Agency may,

its

sole discretion,

waive the 45-day

2109

requirement. Such waiver

shall only be effective

if it

provided

in writing

2110

and

signed by the

Manager of the Bureau

of Air’s Compliance

Section, or

2111

his or her designee.

The Continuous

Parameter Monitoring

Plan must

JCAR350225-08

8507r01

2112

detail how the EGU will

continue to operate within the parameters

2113

enumerated in the testing protocol

and how those parameters will ensure

2114

compliance with the

applicable mercury limit. For example, the

2115

Continuous Parameter

Monitoring Plan must include coal sampling

2116

described in Section 225.239(e)(3)

of this Subpart and must ensure that

2117

EGU that performs an emissions test

using

blend

of coals continues to

2118

operate using that

same blend of coal. If the Agency disapproves

the

2119

Continuous Parameter Monitoring

Plan, the owner or

operator

of the

EGU

2120

has 30 days from the date of receipt

of the

disapproval

submit

2121

detailed information

in accordance with the Agency’s

request.

2122

2123

Compliance Determination

2124

2125

Each quarterly emissions

test

shall determine compliance with this

2126

Subpart for that quarter, where the quarterly periods consist of

the months

2127

of January through March,

April through June, July through September,

2128

and October through

December:

2129

2130

If emissions testing conducted pursuant to this

Section

fails to demonstrate

2131

compliance,

the owner or operator of the EGU will be deemed

to have

2132

been out of compliance

with this Subpart beginning on the day after

the

2133

most recent emissions

test

that demonstrated compliance or the last

day of

2134

certified

CEMS data demonstrating compliance

on a rolling 12-month

2135

basis,

and the EGU will remain out of compliance until

a subsequent

2136

emissions

test successfully demonstrates compliance with the limits

of this

2137

Section.

2138

2139

)

Operation Requirements

2140

2141

The owner or

operator

of an EGU that has elected to demonstrate

2142

compliance

by use of the emission standards of subsection

(b)

of this

2143

Section must continue

to operate the EGU commensurate with the

2144

Continuous

Parameter Monitoring Plan until another Continuous

2145

Parameter Monitoring Plan is developed

and submitted to the Agency

2146

conjunction

with

the next compliance demonstration, in accordance

with

2147

subsection

(f)(4)

of this Section.

2148

2149

)

If the

owner

or operator makes a significant change to the

operations of

2150

EGU

subject

to this Section, such as changing from bituminous

2151

subbituminous coal,

the

owner

or operator must submit a testing protocol

2152

to the Agency and perform an emissions

test within

seven

operating

days

2153

of the significant change. In addition, the owner

operator

of an EGU

2154

that

has elected

to demonstrate compliance by use of the emission

JCAR350225-0818507r01

2155

standards of subsection

(b)

this

Section must submit

Continuous

2156

Parameter

Monitoring

Plan within

seven

operating

days of the significant

2157

change.

2158

2159

)

If a

blend

of bituminous and

subbituminous

coal is fired in the EGU,

the

2160

owner or

operator of the

EGU must ensure

that

the EGU continues

2161

operate

using the

same

blend that was used

during the

most

recent

2162

successful

emissions test.

the

blend

of coal changes, the owner

2163

operator of the EGU

must re-test in accordance

with

subsections

(d),

(e),

2164

(f),

and (g) of this

Section

within 30 days

of the change in coal

blend,

2165

notwithstanding

the

requirement of

subsection

(d)(3)

this Section that

2166

there

must be 45

days between emissions

tests.

2167

2168

recordkeeping

2169

2170

The

owner or operator of

an EGU

and

its designated representative

must

2171

comply

with

all applicable

recordkeeping

and reporting requirements

2172

this

Section.

2173

2174

)

Continuous

Parameter

Monitoring. The

owner or operator of

EGU

2175

must maintain

records to substantiate

that the EGU is operating

2176

compliance with

the parameters listed

in the Continuous

Parameter

2177

Monitoring

Plan, detailing the parameters

that

impact

mercury reduction

2178

and

including

the following records

to the

emissions

of mercury:

2179

2180

For an EGU for which

the owner or

operator

is complying

with

2181

this Subpart B

pursuant

to Section 225.239(b)(1)(B)

2182

225.239(b)(2)(B),

records of the daily

mercury content of

coal

2183

used

(lbs/trillion Btu)

and the daily and

quarterly input

mercury

2184

(ibs).

2185

2186

For an EGU for which

the owner

operator

of an EGU

complying

2187

with

this Subpart

B pursuant to Section

225.239(b)(1)(A)

2188

225.239b)(2)(A),

records

of the daily

and quarterly oss

2189

electrical

output

(MWh)

on an hourly basis.:

2190

2191

The

owner or

operator

an EGU using activated

carbon

injection

must

2192

also

comply

with the

following requirements:

2193

2194

Maintain records

the

usage

of sorbent, the exhaust

gas flow

rate

2195

from the

EGU, and the sorbent

feed rate, in

pounds per million

2196

actual

cubic

feet of exhaust

gas at

the

mi ection

point,

on a weekly

2197

average

JCAR350225-08 1 8507r01

2198

2199

)

If a blend of bituminous

and subbituminous

coal is fired

the

2200

EGU, keep

records

the

amount

of each type of coal

burned

and

2201

the required

injection

rate for injection

of activated

carbon, on a

2202

weekly basis.

2203

2204

The owner or operator

of an

EGU

must retain all records

required by

this

2205

Section

at the

source

unless otherwise

provided in the

CAAPP permit

2206

issued for the source

and

must

make

a copy of any

record available

to the

2207

Agency

promptly

upon request.

2208

2209

)

The owner or

operator

of an EGU

demonstrating

compliance

pursuant

2210

this Section must

monitor

and

report the heat input

rate at the unit level.

2211

2212

The owner or operator

of an EGU

demonstrating compliance

pursuant

2213

this

Section

must

perform

and report

coal sampling in accordance

with

2214

subsection 225.23

9(e)(3).

2215

2216

Reporting

Requirements

2217

2218

owner

or operator of an EGU

shall submit

the

Agency a Final

2219

Source Test

Report

for each

periodic emissions

test within 45

days afler

2220

the test

is completed.

The

Final Source Test

Report will be directed

to the

2221

Manager

of the Bureau

of Air’s Compliance

Section, or his or

her

2222

designee, and include

at a minimum:

2223

2224

)

A summary of

results;

2225

2226

A description

test methods,

including

a description

sampling

2227

points, sampling

train,

analysis

equipment,

and

test schedule,

and a

2228

detailed description

of test

conditions, including:

2229

2230

j).

Process

information, including

but not limited

to modes

2231

operation,

process rate,

and fuel or raw material

2232

consumption;

2233

2234

li)

Control

equipment

information

(i.e., equipment

condition

2235

and

operating parameters

during testing);

2236

2237

iiil

A discussion of

any preparatory actions

taken

(i.e.,

2238

inspections,

maintenance,

and repair);

and

2239

JCAR350225-081

8507r01

2240

Data and

calculations, including copies

of all raw data

2241

sheets

and records of laboratory

analyses, sample

2242

calculations,

and data on equipment calibration.

2243

2244

)

The owner or operator of

source

with one or more EGUs demonstrating

2245

compliance

with

Subpart B in accordance

with

this Section must submit

2246

the Agency a Quarterly

Certification of Compliance within 45

days

2247

following the end of each

calendar quarter. Quarterly certifications

2248

compliance

must

certify

whether compliance

existed for each EGTJ for

the

2249

calendar quarter covered

by the certification. If the EGU failed

to comply

2250

during the quarter covered

the certification,

the owner or operator must

2251

provide the reasons

the EGU or EGUs failed to comply and a full

2252

description of the noncompliance

(i.e.,

tested emissions

rate, coal sample

2253

data,

etc.).

In addition, for

each EGU, the owner or operator must provide

2254

the

following

appropriate data to the Agency as set

forth

this Section.

2255

2256

A list

of all emissions tests performed within

the

calendar

quarter

2257

covered

by the Certification and submitted to the Agency for

each

2258

EGU, including the dates on which

such tests were performed.

2259

2260

)

Any

deviations or exceptions each month and discussion of

the

2261

reasons for such deviations

or exceptions.

2262

2263

All

Quarterly

Certifications of Compliance

required to be

2264

submitted must include the following certification

responsible

2265

official:

2266

2267

I certify

under penalty of law that this document and all

2268

attachments were prepared under my direction

or supervision in

2269

accordance

with a system designed to assure that qualified

2270

personnel properly gather and evaluate the information

submitted.

2271

Based on my inquiry of the

person or persons directly responsible

2272

for

gathering the information, the information submitted

is, to the

2273

best of my knowledge and

belief, true, accurate, and complete.

2274

am aware that there are significant

penalties

for

submitting false

2275

information, including

the possibility of fine and imprisonment

for

2276

knowing

violations.

2277

2278

Deviation Reports.

For each EGU, the owner or operator must promptly

2279

notify

the Agency of deviations

from any of the requirements of this

2280

Subpart B. At a minimum, these notifications

must include a description

2281

of such deviations within 30 days after discovery

of the deviations, and

JCAR35O225O8

1 8507r01

2282

discussion of the possible cause

of such deviations, any corrective

actions,

2283

and

any

preventative

measures taken.

2284

2285

(Source: Added at 33 Ill. Reg.

effective

2286

2287

Section 225.240 General Monitoring and

Reporting Requirements

2288

2289

The owner or operator of an EGU must comply with the

monitoring, recordkeeping, and

2290

reporting requirements

provided in

this Section, Sections 225.250

through 225.290 of this

2291

Subpart B, and Sections 1.14 through 1.18 of Appendix

B to this PartSubpart I of 40

CFR 75

2292

(sections 75.80

through

75.84),

incorporated

by reference in Section 225.140.

If the EGU

2293

utilizes a common stack with units that are not EGUs and

the owner or operator

the

EGU does

2294

not

conduct

emissions monitoring

the

duct

to the common stack from

each EGU, the owner

2295

operator of the EGU must conduct emissions monitoring

in accordance with Section 1.1 6(b)(2)

2296

Appendix B to this Part 40 CFR 75.82(b)(2)

and this Section, including monitoring

in the duct

2297

to the common stack from each unit that is not an EGU, unless

the owner or operator of the

EGU

2298

counts

the combined emissions measured at the

common stack as the mass emissions

of mercury

2299

for the EGUs for recordkeeping and compliance purposes.

2300

2301

Requirements for installation,

certification, and data accounting. The

owner or

2302

operator of each EGU must:

2303

2304

Install all monitoring systems required pursuant

to this Section and

2305

Sections 225.250

through 225.290 for monitoring

mercury mass emissions

2306

(including

all systems required

to monitor mercury concentration,

stack

2307

gas moisture content, stack gas flow rate,

and

concentration,

2308

applicable, in accordance

with Sections 1.15 and 1.16

of Appendix B

2309

this Part4O CFR 75.81 and 75.82).

2310

2311

Successfully complete all certification

tests required pursuant to

Section

2312

225.250 and meet all

other requirements of this Section,

Sections 225.250

2313

through

225.290,

and Sections 1.14 through

1.18 of Appendix B to

this

2314

Part subpart I of 40 CFR

75 applicable to the monitoring

systems required

2315

under subsection (a)(1) of this Section.

2316

2317

Record, report, and assure the

quality of the data from the monitoring

2318

systems

required

under

subsection (a)( 1) of this

Section.

2319

2320

If the owner or operator elects

to use the low mass emissions excepted

2321

monitoring methodology for

an EGU that emits no more than 464

ounces

2322

(29 pounds) of mercury per year pursuant

to Section

1.15(b)

of Appendix

2323

B to this

Part4O

CFR 75.8 1(b), it must perform emissions

testing in

2324

accordance

with Section

1.15(c)

of Appendix B to this Part 40

CFR

JCAR350225-08

1 8507r01

2325

75.81(c) to demonstrate

that the

EGU is eligible

to use this excepted

2326

emissions

monitoring

methodology,

as well as

comply with all other

2327

applicable requirements

of Section

1.15(b) through

(f)

of Appendix

B to

2328

this Part4O CFR

75.81(b)

through (f). Also, the

owner or

operator

must

2329

submit

a copy of any information

required

to be submitted to the

USEPA

2330

pursuant

to these provisions

to the

Agency.

The initial emissions

testing

2331

to demonstrate

eligibility

of an EGU for the

low

mass emissions

excepted

2332

methodology

must

conducted

by the

applicable of

the

following

dates:

2333

2334

If the

EGU

has commenced commercial

operation

before July 1,

2335

2008,

at least

jpjyJanuary

2009,

45 days

prior to relying

2336

on the

low

mass emissions excepted

methodology,

whichever

date

2337

is later.

2338

2339

If the EGU has

commenced commercial

operation

on or after

July

2340

1, 2008, at least 45

days prior to

the applicable date

specified

2341

pursuant to subsection

(b)(2) of this

Section or 45

days prior

2342

relying

the low mass emissions

excepted methodology,

2343

whichever date

is later.

2344

2345

Emissions

Monitoring

Deadlines. The owner

or operator must

meet the emissions

2346

monitoring

system certification

and other

emissions monitoring

requirements

2347

subsections (a)(1) and

(a)(2)

this Section

on or before

the applicable of the

2348

following dates.

The

owner or operator

must record,

report,

and quality-assure

2349

the data from

the emissions monitoring

systems required

under

subsection

(a)(1)

2350

of this Section

on and after

the

applicable of the following

dates:

2351

2352

For the

owner

or operator

of an EGU that commences

commercial

2353

operation

before July 1, 2008,

jyJanuary

1, 2009.

2354

2355

For

the owner or operator

of an EGU that

commences commercial

2356

operation

on or after

July

1, 2008, by 90 unit

operating days or

180

2357

calendar

days, whichever

occurs first, after the

date on which

the EGU

2358

commences

commercial

operation.

2359

2360

For the

owner

or operator

of an EGU for which

construction

of a new

2361

stack

or flue or installation

of add-on mercury

emission controls,

flue

2362

gas desulfurization system,

a selective catalytic

reduction

system, a fabric

2363

filter,

a compact

hybrid particulate collector

system

is completed after

2364

the applicable

deadline

pursuant to

subsection (b)(1) or

(b)(2)

of this

2365

Section, by

unit

operating

days or 180 calendar days,

whichever

occurs

2366

first, after the

date on which emissions

first exit

to the atmosphere through

2367

the

new

stack

or flue, add-on

mercury emission

controls, flue gas

2368

2369

2370

2371

2372

2373

2374

2375

2376

2377

2378

2379

2380

2381

2382

2383

2384

2385

2386

2387

2388

2389

2390

2391

2392

2393

2394

2395

2396

2397

2398

2399

2400

2401

2402

2403

2404

2405

2406

2407

2408

2409

JCAR350225-081 8507r01

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 to demonstrate

compliance pursuant to the emissions

testing requirements in Section

225.239,

by the first day of the calendar quarter following

the last

emissions

test

demonstrating

compliance with

Section 225.239.

Reporting Data.

Except as provided in subsection (c)(2)

this

Section,

the owner or

operator of 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 each such monitoring

system,

the maximum

- fl-n-nm-n-n

fltp

determi,

record, and report

-‘ia1

(or,

the minimum

notential)

values

for mercury concentration, the

stack gas flow rate, the stack gas moisture

content,

d any other parameters required to deteine mercury

mass

emissions in accordance with 40

CFR 75.80(g).

The owner or operator of an EGU that

does not meet the applicable

emissions monitoring

date set forth in subsection

(b)(3) of this Section

for

any emissions monitoring system required pursuant to subsection

(a)(1)

this Section must begin

periodic emissions testing in accordance with

Section

225.239, for each such monitoring

system, deteine, record,

and

report

substitute

data using the applicable missing data procedures

as set

forth in 40 CFR 75.80(f), in lieu

of the maximum potential (or, as

appropriate,

minimum potential) values for a parameter, if the

owner or

operator demonstrates that there

is continuity between the data streams

for

1,nf

-nnrnmptpm

pfyp nr1 nftr

f1p

ntrnrHn

installation

pursuant

subsection(b)(3) of this Section.

Prohibitions.

No owner or operator of an

EGU

may

use any alternative emissions

monitoring system, alternative reference method for

measuring emissions,

other alternative

to the emissions monitoring and measurement

requirements

of this Section

and Sections 225.250 through 225.290,

unless

such alternative is submitted

the

Agency in writing and approved in

writing by the Manager of the Bureau

Air’s Compliance

Section, or his

or her

designeepromulgated

the USEPA and approved

writing

by the

JCAR350225-0818507r01

2410

Agency, or the

use of such alternative is approved

in writing by the

2411

Anc’v

and USEPA.

2412

2413

owner or operator

of an EGU may operate its

EGU so as to discharge,

2414

or allow to be discharged,

mercury emissions to the atmosphere

without

2415

accounting for all such emissions

in accordance with the applicable

2416

provisions

of this Section, Sections 225.250

through 225.290, and

2417

Sections 1.14

through

1.18 of Appendix B to this Part, unless

2418

demonstrating compliance

pursuant

to Section 225.239, as

2419

applicablesubpart

I of 40 CFR 75.

2420

2421

No owner or operator of an EGU may disrupt the

CEMS,

any portion

2422

thereof,

or any other approved

emission monitoring method, and thereby

2423

avoid monitoring

and recording mercury mass emissions discharged

into

2424

the atmosphere, except for periods

recertification

or periods when

2425

calibration,

quality assurance testing, or maintenance is performed

2426

accordance with the applicable provisions

of this Section, Sections

2427

225.250 through

225.290, and Sections 1.14 through 1.18

of Appendix B

2428

to this Partsubpart I of 40

CFR ‘75.

2429

2430

No owner or operator of an EGU may retire or permanently

discontinue

2431

use of the

CEMS or any component thereof, or any other approved

2432

monitoring system

pursuant to this Subpart B, except under any one

of the

2433

following circumstances:

2434

2435

The

owner or operator is monitoring emissions from the

EGU with

2436

another certified monitoring

system that has been approved, in

2437

accordance

with the applicable provisions of this

Section, Sections

2438

225.250 through 225.290

of this Subpart B, and Sections 1.14

2439

through

1.18 of Appendix B to this Partsubpart I

CFR 75,

2440

the Agency for use at that

EGU

and that provides emission data

for

2441

the

same

pollutant or parameter as the retired or discontinued

2442

monitoring system; or

2443

2444

The owner or operator or designated

representative submits

2445

notification

of the date of certification

testing

of a replacement

2446

monitoring

system for the retired or discontinued monitoring

2447

system in accordance with Section 225.250(a)(3)(A).

2448

2449

The

owner or operator is demonstrating compliance

pursuant

to the

2450

applicable

subsections

of Section 225.239.

2451

2452

Long-term Cold Storage.

JCAR350225-081 8507r01

2453

The owner or operator of an EGU that is in

long-term cold storage is subject to

2454

the provisions

CFR

75.4

and

CFR 75.64, incorporated

reference

2455

Section 225.140, relating to monitoring, recordkeeping,

and reporting for units

2456

long-term cold storage.

2457

2458

(Source:

Amended at 33 Ill. Reg.

effective

2459

2460

Section 225.250 Initial

Certification

and Recertification Procedures for Emissions

2461

Monitoring

2462

2463

The

owner or operator

of an EGU must comply with the following initial

2464

certification and recertification procedures

for

CEMS (i.e., a CEMS or an

2465

excepted monitoring system

(sorbent trap monitoring system) pursuant to

Section

2466

1.3 of Appendix B to this Part4O CFR 75.15, incorporated

by reference in Section

2467

225.140) required

Section 225.240(a)(1).

The owner or operator of an

EGU

2468

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

use, the low-mass-

2469

emissions excepted methodology pursuant

to Section 1.15(b) of Appendix B

2470

this

Part4O

CFR 75.8 1(b), incorporated

reference in Section 225.140,

must

2471

comply

with

the procedures

set forth in subsection (c) of this Section.

2472

2473

Requirements for Initial Certification. The

owner or operator of an EGU

2474

must ensure that, for each CEMS required

Section 225.240(a)(1)

2475

(including the automated data acquisition and handling system),

the

owner

2476

or operator successfully

completes all of the initial certification testing

2477

required pursuant to Section 1.4

of Appendix B to this Part4O CFR

2478

75.80(d), incorporated by reference in Section 225.140,

the

applicable

2479

deadline in Section 225.240(b).

In addition, whenever the owner or

2480

operator of an EGU installs a monitoring

system to meet the requirements

2481

this Subpart B in a

location where no such monitoring system was

2482

previously installed, the owner or operator

must successfully complete

the

2483

initial certification requirements

of Section 1.4 of Appendix B to this

2484

Part4O

CFR 75.80(d).

2485

2486

Requirements for Recertification. Whenever the owner or

operator of

2487

EGU

makes a replacement,

modification, or change in any certified

2488

CEMS,

or an excepted monitoring system

(sorbent

trap

monitoring

2489

system)

pursuant to

Section 1.3 of Appendix B to this Part4O CFR

75.15,

2490

and required by Section 225 .240(a)(1),

that may significantly affect

the

2491

ability of the system to accurately

measure

or record mercury mass

2492

emissions or heat

input rate or to meet the quality-assurance

and quality

2493

control requirements

of Section 1.5 of Appendix B to this Part 40

CFR

2494

75.21 or Exhibit B to Appendix

B to this PartAppendix B to 40

CFR 75,

2495

each incorporated by reference

in Section

225.140,

the

owner or operator

JCAR350225-08

1 8507r01

2496

of an EGU must recertify the

monitoring system in accordance

with

2497

Section

1.4(b) of Appendix B to this Part4O

CFR

75.20(b),

incorporated

2498

by reference in Section 225.140.

Furthermore, whenever the

owner or

2499

operator

of an EGU makes a replacement,

modification,

or change

to the

2500

flue gas

handling system or the EGU’s operation

that may significantly

2501

change the

stack flow or concentration profile, the

owner

or operator must

2502

recertify each CEMS, and

each excepted monitoring system

(sorbent trap

2503

monitoring system) pursuant to Section

1.3 to Appendix B to this Part4O

2504

CFR

75.15, whose accuracy is potentially affected

by the change, all in

2505

accordance with Section 1.4(b)

Appendix B to this Part4O

CFR

2506

75.20(b).

Examples of changes to a CEMS that

require recertification

2507

include, but are not limited to,

replacement of the analyzer, complete

2508

replacement

of an existing CEMS, or change in location

or orientation

2509

the sampling probe or site.

2510

2511

Approval Process for Initial Certification

and Recertification. Subsections

2512

(a)(3)(A) through

(a)(3)(D) of this Section apply to both initial

2513

certification and recertification of

a CEMS required by Section

2514

225.240(a)(1).

For recertifications, the words “certification

and “initial

2515

certification” are to

be read as the word “recertification”, the word

2516

“certified” is to be read as the word

“recertified”, and the procedures

set

2517

forth

in Section

1.4(b)(5)

of Appendix

B to this Part 40 CFR 75.20(b)(5)

2518

are

to be followed in lieu of the procedures set

forth in subsection

2519

(a)(3)(E)

of this Section.

2520

2521

Notification of Certification.

The

owner

or operator must submit

2522

written

notice

of the dates of certification testing

to the Agency

2523

directed to the Manager

of the Bureau of Air’s Compliance

2524

Section,

USEPA Region 5, and the Administrator

of the USEPA

2525

written notice of the dates

of certification testing, in accordance

2526

with

Section

225

.270.

2527

2528

Certification Application.

The owner or operator must

submit

2529

the

Agency a certification application

for each monitoring

system.

2530

A complete

certification application must include

the information

2531

specified in 40 CFR 75.63,

incorporated by reference in Section

2532

225.140.

2533

2534

Provisional Certification

Date. The provisional certification

date

2535

for a monitoring system

must be determined in accordance

with

2536

Section

1.4(a)(3)

of Appendix

B to

this Part4O

CFR 75.20(a)(3),

2537

incorporated

by reference in Section 225.140.

provisionally

2538

certified monitoring

system maybe used pursuant

this

Subpart

JCAR350225-08 1 8507r01

2539

for a period not to exceed 120

days after receipt by the Agency

2540

the complete

certification

application for the monitoring

system

2541

pursuant to subsection

(a)(3)(B) of this Section. Data

measured

2542

and recorded by the provisionally

certified monitoring system, in

2543

accordance

with

the requirements of Appendix

B to this Part4O

2544

CFR 75, will

be considered valid quality-assured data

(retroactive

2545

to the date and time

provisional

certification), provided

that the

2546

Agency does not invalidate the provisional

certification

issuing

2547

a notice of disapproval

within 120 days after the date

of receipt

2548

the Agency of the complete certification

application.

2549

2550

Certification Application Approval

Process. The Agency

must

2551

issue a written notice

of approval or disapproval of

the certification

2552

application

to the owner or operator within

120 days after receipt

2553

of the complete certification

application required by subsection

2554

(a)(3)(B)

of this Section. Tn the event the Agency

does not issue

2555

written notice of approval or

disapproval within the 120-day

2556

period,

each

monitoring system that meets

the applicable

2557

performance requirements

of Appendix B to this Part 40

CFR 75

2558

and which is included in the certification

application will

2559

deemed certified for use pursuant

this

Subpart

2560

2561

Approval

Notice. If the certification application

2562

complete and

shows that each

monitoring system

meets

the

2563

applicable performance

requirements of Appendix B

this

2564

Part4O

CFR 75, then the Agency

must issue a written

notice

2565

of approval

the

certification application within 120

days

2566

after receipt.

2567

2568

ii)

Incomplete

Application

Notice.

If the certification

2569

application is not complete,

then

the Agency must

issue a

2570

written

notice of incompleteness that

sets a reasonable

date

2571

by which the owner

or operator must submit the additional

2572

information

required to complete the certification

2573

application. If the owner

or operator does not comply

with

2574

the

notice of incompleteness

by the specified date, the

2575

Agency may

issue a notice of disapproval

pursuant to

2576

subsection (a)(3)(D)(iii)

of this Section. The 120-day

2577

review period will not begin

before

receipt of a complete

2578

certification

application.

2579

2580

iii)

Disapproval

Notice. If the certification application

shows

2581

that any monitoring

system does not meet the performance

JCAR350225-08

1 8507r01

2582

requirements

of Appendix B to this

Part4O CFR

75, or if

2583

the certification

application is incomplete and

the

2584

requirement

for disapproval pursuant

to subsection

2585

(a)(3)(D)(ii)

of this Section is met, the

Agency must issue

2586

written notice

of disapproval of the certification

2587

application.

Upon issuance of such notice of

disapproval,

2588

the

provisional certification is invalidated,

and the data

2589

measured

and recorded by each uncertified

monitoring

2590

system will not

be considered valid quality-assured

data

2591

beginning

with

the date and hour

of provisional

2592

certification (as

defined pursuant to Section 1

.4(a)(3) of

2593

Appendix

B to this Part4O CFR 75.20(a)(3)).

The owner

2594

operator must follow

the procedures for loss of

certification

2595

set forth

in subsection (a)(3)(E) of this

Section for each

2596

monitoring system that

is disapproved for initial

2597

certification.

iv)

Audit

Decertification.

The Agency

may

issue a notice

disapproval of

the certification status of a monitor

accordance with Section 225 .260(b).

Procedures for

Loss of Certification. If the

Agency issues a

notice

of disapproval

a certification

application

pursuant

to subsection

(a)(3)(D)(iii) of this Section

or a notice of disapproval

certification

status pursuant to subsection

(a)(3)(D)(iv) of this

Section, the

owner or operator

must fulfill

the following

requirements:

The owner or operator

must substitute the following

values

for

each disapproved monitoring

system and for each

hour

of EGU operation during

the period of invalid data

specified

pursuant to

CFR 75.20(a(4)(iii)

or 75.21(e),

continuing until the applicable

date and hour specified

pursuant

CFR 75.20(a(5)(i), each

incorporated

reference in Section 225.140.

For a disapproved

mercury

pollutant

concentration monitor

and disapproved flow

monitor, respectively,

the maximum potential

concentration

of mercury and the maximum

potential

flow rate,

defined in sections 2.1.7.1

and

2.1.4.1

of appendix A

to 40

CFR

75, incorporated by reference

in Section 225.140.

For

a disapproved

moisture monitoring system and

disapproved

diluent gas monitoring

system, respectively, the

minimum

potential moisture percentage

and either the maximum

2598

2599

2600

2601

2602

2603

2604

2605

2606

2607

2608

2609

2610

2611

2612

2613

2614

2615

2616

2617

2618

2619

2620

2621

2622

2623

2624

JCAR350225-08 1 8507r01

2625

potential

concentration

or the minimum potential

2626

concentration

(as applicable), as defined in sections 2.1.5,

2627

2.1.3.1, and 2.1.3.2

of appendix Ato 40 CFR 75,

2628

incorporated by reference in Section 225.140.

For a

2629

disapproved

excepted monitoring system (sorbent trap

2630

monitoring

system) pursuant to 40 CFR 75.15 and

2631

disapproved flow monitor,

respectively, the maximum

2632

potential concentration of mercury

and

maximum

potential

2633

flow

rate, as defined in sections 2.1.7.1 and 2.1.4.1 of

2634

appendix A to 40 CFR 75,

incorporated by reference in

2635

Section 225.140.

2636

2637

ii4)

The

owner or operator must submit a notification of

2638

certification retest dates and a new certification

application

2639

in accordance with subsections

(a)(3)(A) and (B) of this

2640

Section.

2641

2642

iii4)

The owner or operator must repeat all certification

tests or

2643

other requirements

that were failed by the monitoring

2644

system, as indicated in the

Agency’s

notice of disapproval,

2645

no later than 30 unit operating

days after the date of

2646

issuance of the notice of disapproval.

2647

2648

Exemption.

2649

2650

If an

emissions

monitoring system has been previously certified

2651

accordance with Appendix B

this

Part

CFR 75 and the applicable

2652

quality assurance and quality control requirements

of Section 1.5 and

2653

Exhibit B to Appendix B to this

Part

CFR 75.21 and appendix B

to 40

2654

CFR 75

are

fully met, the monitoring system will

exempt

from the

2655

initial certification requirements of this

Section.

2656

2657

The recertification provisions of this

Section apply to an emissions

2658

monitoring

system required by Section 225.240(a)(1) exempt

from initial

2659

certification requirements pursuant to

subsection (a)(1) of this Section.

2660

2661

Initial

certification

and recertification

procedures for EGUs using the mercury

low

2662

mass emissions excepted

methodology pursuant

to Section

1.15(b)

of Appendix

2663

to this Part4O

CFR

75.8 1(b). The owner or operator that

has elected to use the

2664

mercury-low-mass-emissions-excepted

methodology

for a

qualified EGU

2665

pursuant to

Section 1.15(b)

to Appendix B to this Part 40 CFR 75.81(b)

must

2666

meet the applicable certification and

recertification requirements in Section

JCAR350225-081

8507r01

2667

1.15(c) through

(f)

to Appendix B to this Part4O

CFR

75.81(c)

through

2668

incorporated by reference in Section 225.140.

2669

2670

Certification Applications.

The owner or operator

EGU

must

submit an

2671

application to the Agency

within

days after completing all initial certification

2672

or recertification tests required pursuant

to this Section, including the information

2673

required pursuant to 40 CFR 75.63, incorporated

reference

in Section 225.140.

2674

2675

(Source: Amended at 33 Ill. Reg.

effective

2676

2677

Section

225.260 Out of Control Periods and

Data

Availability for Emission Monitors

2678

2679

Out of control periods must be determined

in accordance with Section 1.7 of

2680

Appendix

2681

2682

ha)

Monitor data

availability

must

be determined on a calendar quarter basis in

2683

accordance with Section 1.8 of Appendix BWhenever

any emissions monitoring

2684

system fails to meet the quality assurance and quality control requirements

2685

data validation requirements

CFR 75, incorporated by reference in Section

2686

225.140, data must be substituted using the applicable

missing data procedures

2687

subparts D and I of 40 CFR 75, each incorporated

reference in

Section 225.140

2688

following initial certification of the required

flow monitor, or mercury

2689

concentration or moisture

monitoring system(s) at a particular unit or stack

2690

location.

Compliance with the

percent reduction standard in Section

2691

225.230(a)(1)(B)

225.237(a)(1)(B)

or the emissions

concentration standard

2692

Section

225.23

0(a)(1)(A)

or 225

.237(a)(1)(A)

can only be demonstrated if

the

2693

monitor data availability

is equal to or greater than 75 percent; that is, quality

2694

assured

data must be recorded by a certified primary monitor, a certified

2695

redundant or non-redundant

backup monitor, or reference method for that unit

2696

least 75 percent of the time the unit is in operation.

2697

2698

cb)

Audit Decertification. Whenever both an audit of an emissions monitoring

2699

system and a review of the initial certification

or recertification application reveal

2700

that any

emissions

monitoring system should not have been certified or

recertified

2701

because it did not meet a particular performance

specification

or other

2702

requirement pursuant to Section 225.250 or the applicable provisions

of Appendix

2703

B to

this Part4O CFR

75, both at the time of the initial certification or

2704

recertification application submission and

at the time of the audit, the Agency

2705

must issue a notice of disapproval of the certification

status of such monitoring

2706

system. For the purposes of this subsection (cb), an audit must

either

a field

2707

audit

or an audit of

any information submitted to the Agency. By issuing the

2708

notice of disapproval, the Agency revokes

prospectively the certification status

2709

the emissions monitoring system. The data

measured and recorded by the

JCAR350225-081

8507r01

2710

monitoring system must not

considered

valid quality-assured data from the

2711

date of issuance

of the notification of the revoked certification

status until the date

2712

and time that the owner or

operator completes subsequently approved initial

2713

certification

or recertification tests for the

monitoring system. The owner or

2714

operator must follow

the applicable initial certification

or recertification

2715

procedures in Section

225

.250

for each disapproved

monitoring

system.

2716

2717

(Source:

Amended at 33 Ill. Reg.

effective

2718

2719

Section

225.261

Additional Requirements

to Provide Heat Input Data

2720

2721

The owner or operator of an EGU that monitors

and reports mercury mass emissions using

2722

mercury

concentration monitoring

system and a flow monitoring system must also

monitor and

2723

report the heat input rate at the EGU level using the procedures

set forth in Appendix B to this

2724

Part4O CFR 75, incorporated

reference

Section 225.140.

2725

2726

(Source: Amended at 33 Iii.

Reg.

effective

2727

2728

Section

225.265 Coal Analysis

for Input Mercury Levels

2729

2730

The owner or operator of an EGU

complying with this Subpart B by means

2731

Section 225.230(a)(12),-ef using input

mercury

levels

(Ii)

and complying

2732

means of Section 225.230(b) or (d) or Section 225.232, electing

to comply with

2733

the

emissions testing,

monitoring, and recordkeeping requirements

under

Section

2734

225.239, or demonstrating compliance

under Section 225.233 or Sections

225.291

2735

through 225.299 must fulfill the following

requirements:

2736

2737

Perforni daily sampling

of the coal combusted in the EGU for mercury

2738

content.

The owner or operator of such EGU must collect

a minimum

2739

one 2-lb grab sample per day

of operation from the belt feeders anywhere

2740

between the crusher

house or breaker building and the boiler.

The sample

2741

must be taken in a manner that provides

a representative mercury content

2742

for the coal burned

on that day. EGUs complying

means of

Section

2743

225.233 or Sections 225.291 through 225.299

of this Subpart must

2744

perform such coal

sampling at least once per month; EGUs complying

2745

means of the emissions testing,

monitoring,

and recordkeeping

2746

requirements under Section 225.239 must perform

such coal sampling

2747

according to the schedule

provided in Section 225.239(e)(3) of

this

2748

Subpart; all other EGUs subject

to this requirement must perform

such

2749

coal sampling on a

daily

basis.

2750

2751

Analyze the

grab coal sample for the following:

2752

JCAR350225-08

1 8507r01

2753

Determine

the heat content using ASTM D5865-04

or an

2754

equivalent method

approved in writing by the Agency.

2755

2756

Determine

the moisture content using ASTM

D3173-03 or an

2757

equivalent

method approved in writing by the Agency.

2758

2759

Measure the mercury content

using ASTM

D6414-01,

ASTM

2760

D3684-01,

or an equivalent method approved in writing

by the

2761

Agency.

2762

2763

The owner

operator

of multiple EGUs at the same source using the

2764

same crusher house or breaker building may take

one

sample

per crusher

2765

house or breaker building,

rather than one per EGU.

2766

2767

The owner or operator of an

EGU must use the data analyzed pursuant

2768

subsection

(b) of this Section to determine the mercury content in terms

2769

lbs/trillion Btu.

2770

2771

The

owner or operator of

an EGU that must conduct sampling and analysis

of coal

2772

pursuant to subsection (a) of this Section

must

begin

such activity by the

2773

following date:

2774

2775

the

EGU is in daily service, at least 30 days before the start of the

month

2776

for which such activity

will be required.

2777

2778

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

2779

operation.

2780

2781

(Source:

Amended at

Ill.

Reg.

effective

2782

2783

Section 225.270

Notifications

2784

2785

The

owner or

operator of a source with one

more EGUs

must submit written notice to the

2786

Agency

according to the provisions in 40 CFR 75.61, incorporated

reference in Section

2787

225.140 (as a

segment of 40 CFR 75), for each

EGU or group of EGUs monitored at a common

2788

stack and each

non-EGU monitored pursuant to Section 1.16(b)(2)(B) of Appendix

B to this

2789

Part4O CFR

75.82b)(2)(ii), incorporated

by reference in Section 225.140.

2790

2791

(Source:

Amended at 33 Ill. Reg.

effective

2792

2793

Section

225.290

Recordkeeping and

Reporting

2794

2795

General Provisions.

JCAR350225-08 1 8507r01

2796

2797

The owner or

operator of an EGU and its designated representative

must

2798

comply with all applicable

recordkeeping and reporting requirements

2799

this Section and with all applicable

recordkeeping and reporting

2800

requirements

of Section 1.18 to Appendix

to this Part4O CFR

75.84,

2801

incorporated

by reference in Section 225.140.

2802

2803

The owner or operator of an EGU must maintain

records for each month

2804

identifying

the

emission standard in Section 225 .230(a) or 225 .237(a)

2805

this Section with which

it is complying or that is applicable for the EGU

2806

and

the following

records related to the emissions of mercury

that

the

2807

EGU is allowed to emit:

2808

2809

For an EGU for which the owner or operator

is complying with

2810

this Subpart

B by means of Section 225.230(a)(i2)ç or

2811

225

.237(a)(1)(B) or using input mercury levels to determine

the

2812

allowable emissions

of the EGU, records of the daily mercury

2813

content of coal used (lbs/trillion

Btu)

and the daily

and monthly

2814

input

mercury (ibs), which must be kept in the file pursuant

2815

Section 1.18(a) of

Appendix B to this

Part4O

CFR 75.84(a).

2816

2817

For an EGU for which the owner or operator of an

EGU complying

2818

with this Subpart B by means of Section 225.23 0(a)(1)

2819

225 .237(a)(1)(A)

or using electrical output to determine the

2820

allowable emissions

of the EGU, records of the daily and monthly

2821

gross electrical output (GWh), which must

be kept in the file

2822

required pursuant

to Section 1.18(a) of Appendix B to this

Part4O

2823

CFR 75.84(a).

2824

2825

The owner or operator of an EGU must maintain

records of the following

2826

data for each EGU:

2827

2828

Monthly emissions

of mercury from the EGU.

2829

2830

For an

EGU

for which

the owner or operator is complying

2831

means of Section 225.230(b) or

(d) of

this

Subpart B, records

2832

the

monthly

allowable emissions of mercury from the

EGU.

2833

2834

The owner or operator of an EGU

that

is participating in an Averaging

2835

Demonstration pursuant to Section 225.232

of this Subpart B must

2836

maintain records identifying all sources and EGUs covered

by the

2837

Demonstration for each

month and, within 60 days after the end

of each

2838

calendar month, calculate and

record the actual and allowable mercury

JCAR350225-08 1 8507r01

2839

emissions of the EGU

for the month and the applicable 12-month rolling

2840

period.

2841

2842

The owner or operator

EGU must maintain the following records

2843

related to quality assurance activities

conducted for emissions monitoring

2844

systems:

2845

2846

The results

quarterly

assessments

conducted pursuant to

2847

Sectionsection 2.2 of Exhibit B

Appendix

B to this Partappendix

2848

B of 40

CFR 75, incorporated by reference in Section 225.140;

and

2849

2850

Daily/weekly

system integrity checks pursuant to Sectionseet4en

2851

2.6

of Exhibit B to Appendix B to

this

Partappendix

B of

CFR

2852

75, incorporated

reference

in Section

225.140.

2853

2854

The owner or operator of an

EGU must maintain an electronic copy

of all

2855

electronic

submittals

to the USEPA pursuant to Section 1.18(f)

2856

Appendix B to this Part4O

CFR 75.84(f), incorporated by reference in

2857

Section

225.140.

2858

2859

The owner or operator

of an EGU must retain all records required

by this

2860

Section

at the source unless

otherwise provided in the CAAPP permit

2861

issued for the source and must make

a copy of any record available to

the

2862

Agency upon request.

2863

2864

Quarterly Reports. The owner or

operator of a source with one or more EGUs

2865

must submit quarterly reports to the Agency as follows:

2866

2867

These reports must include the following information

for operation of

the

2868

EGUs during the quarter:

2869

2870

The total operating

hours

of each EGU and the mercury

CEMS, as

2871

also

reported in accordance with Appendix B to this Part4O

CFR

2872

75, incorporated

reference

in Section

225.140.

2873

2874

A discussion

of any significant changes in the measures used

2875

control emissions of mercury from

the

EGUs or the coal supply

2876

the

EGUs, including changes in the source

of coal.

2877

2878

Summary information

on the perfonnance of the mercury

CEMS.

2879

When the mercury CEMS

was not inoperative, repaired, or

2880

adjusted, except for routine zero and

span checks, this must be

2881

stated

the report.

JCAR350225-08 1 8507r01

2882

2883

If the

CEMS downtime was more than

5.0

percent

of the total

2884

operating time

for the EGU: the date and time identifying each

2885

period

during which the

CEMS was inoperative, except for routine

2886

zero and

span checks; the nature

of CEMS repairs or adjustments

2887

and a summary

of quality assurance data consistent with Appendix

2888

B to this Part4O

CFR 75, i.e., the dates and results of the Linearity

2889

Tests

and any RATAs during the

quarter; a listing of any days

2890

when

a required

daily calibration

was not performed; and

the date

2891

and duration

of any periods when the CEMS was out-of-control

2892

addressed

by Section 225 .260.

2893

2894

Recertification

testing that has been performed for any

CEMS and

2895

the

status of the results.

2896

2897

The

owner

or operator must submit each quarterly

report to the Agency

2898

within 45 days following

the end of the calendar quarter covered

by the

2899

report.

2900

2901

Compliance Certification. The

owner or operator of a source with one or more

2902

EGUs must submit to the Agency a compliance

certification

in support of each

2903

quarterly report

based

on reasonable inquiry of those

persons with primary

2904

responsibility for ensuring

that all of the EGUs’ emissions are correctly

and fully

2905

monitored. The certification

must

state:

2906

2907

That the monitoring data submitted were recorded

in accordance with

the

2908

applicable requirements

of this Section, Sections 225.240 through 225

.270

2909

and Section 225.290 of this Subpart B,

and Appendix B to this Part4O

2910

CFR 75, including

the quality assurance procedures and specifications;

2911

and

2912

2913

For an EGU with add-on mercury emission

controls, a flue gas

2914

desulfurization system,

a selective catalytic reduction system, or

2915

compact

hybrid

particulate collector system and

for

all hours where

2916

mercury data is missing thatare

substituted

in accordance with 40

CFR

2917

75.34(a)(1):

2918

2919

That:

2920

2921

The mercury add-on emission controls,

flue gas desulfurization

2922

system,

selective catalytic reduction

system, or compact hybrid

2923

particulate collector

system was operating

within the range of

2924

parameters listed

in the quality assurance/quality control

program

JCAR350225-081 8507r01

2925

pursuant to Exhibit B to

Appendix B to this Partappendix B to 40

2926

CFR75;or

2927

2928

i4)

With regard to a flue gas

desulfurization system or a selective

2929

catalytic

reduction system,

quality-assured SO

2 emission data

2930

recorded in accordance

with Appendix

B to

this Part 40

CFR 75

2931

document that the flue

gas desulfurization system was operating

2932

properly, or quality-assured

emission data recorded in

2933

accordance with

Appendix B

this Part 40

CFR

document that

2934

the selective catalytic reduction

system was operating properly,

2935

applicable;

and

2936

2937

The substitute

data

values do not

vstematically

underestimate

2938

mercury emissions.

2939

2940

Annual Certification of Compliance.

2941

2942

The owner or operator of a

source with one or more EGUs subject to

this

2943

Subpart B must submit to the Agency an Annual Certification

2944

Compliance

with

this Subpart B no later than May 1 of each year

and must

2945

address compliance

for the previous calendar year. Such certification

2946

must be submitted to the Agency,

Air Compliance and Enforcement

2947

Section, and the Air Regional Field Office.

2948

2949

Annual Certifications

of Compliance must indicate whether compliance

2950

existed for each EGU for each

month in the year covered by the

2951

Certification and it must certify to that effect. In addition,

for each

EGU,

2952

the

owner or operator

must provide the following appropriate data as

set

2953

forth in subsections (d)(2)(A) through (d)(2)(E)

this Section,

together

2954

with

the data set forth

in subsection (d)(2)(F) of this Section:

2955

2956

If complying with this

Subpart

B by means of Section

2957

225 .230(a)(1

)(A) or 225.23 7(a)(1 )(A):

2958

2959

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

2960

rolling

period

ending in the year covered by the

2961

Certification;

2962

2963

ii)

Actual emissions, in ibs, and gross electrical output,

2964

GWh, for each 12-month rolling period ending in the

year

2965

covered

the Certification;

and

2966

JCAR350225-081 8507r01

2967

iii)

Actual emissions,

in ibs, and gross electrical output, in

2968

GWh, for each month in the

year covered by

the

2969

Certification and

in the previous year.

2970

2971

If complying

with

this Subpart

B by means of Section

2972

225

.230(a)(1

)(B)

225

.237(a)(1 )(B):

2973

2974

Actual control efficiency

for emissions for each 12-month

2975

rolling

period ending in the year covered

the

2976

Certification, expressed

as a percent;

2977

2978

ii)

Actual emissions, in

lbs,

and mercury content in the fuel

2979

fired

in such EGU, in ibs, for each 12-month rolling

period

2980

ending in the year covered

by the Certification; and

2981

2982

iii)

Actual emissions, in ibs, and

mercury content in the fuel

2983

fired in

such EGU, in ibs, for each month in the year

2984

covered by the Certification

and in the previous year.

2985

2986

If complying with this

Subpart

B by means of Section 225.23

0(b):

2987

2988

Actual emissions and allowable

emissions

for each 12-

2989

month rolling period ending in the year covered

by the

2990

Certification;

and

2991

2992

ii)

Actual emissions and allowable

emissions, and which

2993

standard

of compliance the owner or operator was

utilizing

2994

for each month in the

year covered by the Certification

and

2995

in the

previous year.

2996

2997

If complying with

this Subpart B by means of Section 225.230(d):

2998

2999

Actual emissions

and allowable emissions for all

EGUs at

3000

the source for each 12-month rolling

period

ending in the

3001

year covered

by the Certification; and

3002

3003

ii)

Actual

emissions and allowable emissions,

and which

3004

standard

compliance

the

owner or operator was

utilizing

3005

for each month in the

year covered by the Certification

and

3006

in the previous year.

3007

3008

If complying with

this Subpart B

means of Section 225

.232:

3009

JCAR350225-0818507r01

3010

Actual emissions and allowable

emissions for

all

EGUs at

3011

the source

in an Averaging Demonstration for each 12-

3012

month rolling period

ending in

the

year covered by the

3013

Certification; and

3014

3015

ii)

Actual emissions

and allowable emissions, with the

3016

standard of compliance

the

owner

or operator was utilizing

3017

for each EGU at the source in an Averaging Demonstration

3018

for each

month for all EGUs at the source in an Averaging

3019

Demonstration in the year covered

by the

Certification

and

3020

in the

previous year.

3021

3022

Any deviations, data

substitutions, or exceptions each month and

3023

discussion of the reasons for such deviations, data substitutions,

3024

exceptions.

3025

3026

All Annual Certifications of

Compliance required to be submitted must

3027

include

the following certification by a responsible official:

3028

3029

I certify under penalty of law that

this

document and

all attachments were

3030

prepared under my direction or supervision in accordance with a

system

3031

designed

to assure that qualified personnel properly gather and evaluate

3032

the

information submitted.

Based on my inquiry of the person or persons

3033

directly responsible for gathering

the information, the information

3034

submitted is, to the best of my knowledge and belief, true,

accurate, and

3035

complete. I am aware that there are significant penalties for submitting

3036

false information, including

the possibility of fine and imprisonment

for

3037

knowing violations.

3038

3039

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

3040

Certification of Compliance

to address calendar year 2009 or the calendar

3041

year in

which

the EGU commences commercial operation, whichever

3042

later. Notwithstanding subsection (d)(2)

this

Section, in the Annual

3043

Certifications

of Compliance that are required to be submitted

by May

3044

2010, and

May 1, 2011,

address

calendar years

2009

and 2010,

3045

respectively, the owner or operator is not required to provide 12-month

3046

rolling data for

any period that ends before June 30, 2010.

3047

3048

Deviation Reports. For each EGU, the owner or operator

must

promptly

notify

3049

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

3050

these notifications must

include a description of such deviations within

30 days

3051

after discovery of the deviations,

and a

discussion

of the possible cause of such

3052

deviations, any corrective actions, and any preventative

measures taken.

JCAR350225-08

1 8507r01

3053

3054

Quality

Assurance RATA

Reports.

The

owner or operator

EGU must

3055

submit

to the Agency,

Air Compliance

and Enforcement

Section, the quality

3056

assurance

RATA report

for each EGU

or group

EGUs monitored at a

common

3057

stack and each non-EGU

pursuant

to Section 1.16(b)(2)(B)

of Appendix

B to this

3058

Part4O

CFR

75.82(b)(2)(ii),

incorporated

by reference

in Section 225.140,

within

3059

45 days after

completing a quality

assurance

RATA.

3060

3061

(Source:

Amended

at 33 Ill. Reg.

effective

3062

3063

Section

225.291

Combined Pollutant

Standard:

Purpose

3064

3065

The

purpose of Sections

225.29

1 through 225.299

(hereinafter

referred

to as the Combined

3066

Pollutant

Standard

(CPS”))

allow

alternate means of compliance

with

the emissions

3067

standards

for mercury

Section

225.230(a)

for

specified EGUs

through

permanent

shut-down,

3068

installation

of ACT, and the application

of pollution

control technology

for

NON,

PM, and

3069

emissions

that

also reduce

mercury

emissions as

co-benefit

and to establish permanent

3070

emissions

standards for those

specified

EGUs.

Unless otherwise

provided

for

in the CPS,

3071

owners

and operators of those

specified

EGUs

are not excused

from

compliance

with

other

3072

applicable

requirements

of Subparts B,

and E.

3073

3074

(Source: Added

at 33 Ill. Reg.

effective

3075

3076

Section

225.292

Applicability

of the Combined

Pollutant

Standard

3077

3078

As an alternative to

compliance

with

the emissions standards

of Section

3079

225.23

0(a),

the

owner or operator

of specified EGUs

in the CPS located

at Fisk,

3080

Crawford, Joliet, Powerton,

Waukegan,

and Will

County power plants

may

elect

3081

for all of those

EGUs as a group

to demonstrate compliance

pursuant

the

CPS,

3082

which establishes control

requirements

and emissions

standards

for

NO.fI,

3083

SQ2,

and mercury.

For this purpose,

ownership of

a specified EGU is

determined

3084

based on direct ownership,

by holding

a majority interest

a company

that

owns

3085

the EGU or EGUs,

or by the common

ownership

the company that owns

the

3086

EGU, whether through

a parent-subsidiary

relationship,

as a sister

corporation,

3087

as an affiliated

corporation with

the

same parent corporation,

provided that

the

3088

owner or operator has

the right or

authority to submit

a CAAPP application

3089

behalf of the EGU.

3090

3091

specified EGU

coal-fired

EGU listed in Appendix

A, irrespective

any

3092

subsequent

changes in

ownership

of the EGU

or power plant,

the operator, unit

3093

designation,

or name of unit.

3094

JCAR35O225O8l 8507r01

3095

The owner or

operator

of each of the specified EGUs electing

demonstrate

3096

compliance with Section 225.230(a) pursuant

to the CPS must submit an

3097

application for

a CAAPP permit modification

the Agency,

provided

for in

3098

Section 225.220, that includes

the information specified in Section 225.293

that

3099

clearly states the owner’s or operator’s

election to demonstrate compliance with

3100

Section 225.230(a) pursuant to the CPS.

3101

3102

If an owner or operator

one

or more specified EGUs elects to demonstrate

3103

compliance with Section 225.230(a)

pursuant to the CPS, then all specified EGUs

3104

owned or

operated

in Illinois by the owner or operator as of December

31,

2006,

3105

as defined in subsection (a) of this

Section,

are thereafter subject to the standards

3106

and control

requirements

of the CPS. Such EGUs are referred to as a Combined

3107

Pollutant Standard (CPS) group.

3108

3109

If an EGU is subject to the requirements

this

Section, then the requirements

3110

apply to all owners and operators

of the EGU, and to the CAIR designated

3111

representative for the EGU.

3112

3113

(Source: Added at 33 Ill. Reg.

effective

3114

3115

Section 225.293

Combined Pollutant

Standard: Notice of Intent

3116

3117

The

owner or

operator of one or more specified

EGUs that intends to comply with Section

3118

225.230(a) by

means of the CPS must notify the Agency

of its intention on or before December

3119

31, 2007.

The following information must accompany the notification:

3120

3121

The identification of each EGU that

will be complying with Section 225.23(

3122

pursuant to the CPS,

with evidence

that the owner or operator has identified

all

3123

specified EGUs that it owned or

operated in Illinois as of December 31, 2006,

and

3124

which commenced commercial operation on or before December 31, 2004;

3125

3126

If an EGU

identified

subsection

(a)

of this Section is also owned or operated

3127

a person different than the owner or operator submitting

the notice of intent, a

3128

demonstration that the submitter

has the right to commit the EGU or authorization

3129

from the responsible official for the EGU submitting

the

application;

and

3130

3131

summary of the current control

devices installed and operating on each EGU

3132

and

identification of the additional control devices

that

will

likely

be needed for

3133

each EGU to comply with emission control requirements of the

CPS.

3134

3135

(Source:

Added at

Ill. Reg.,_____

effective

3136

JCAR350225-08

8507r01

3137

Section 225.294 Combined Pollutant Standard:

Control Technology Requirements and

3138

Emissions

Standards

for Mercury

3139

3140

Control Technology Requirements

for Mercury.

3141

3142

For

each

EGU in a CPS group other than an EGU

that

addressed by

3143

subsection

(b)

of this Section, the owner or operator of the

EGU must

3144

install, if not already installed,

and properly operate and maintain, by the

3145

dates

set

forth in subsection (a)(2)

this Section,

ACT equipment

3146

complying with

subsections (g),

(h),

(i),

(I),

and

(k)

of this Section,

3147

applicable.

3148

3149

)

the

following dates, for the EGUs listed in subsections (a)(2)(A)

and

3150

(B), which include hot and

cold side ESPs, the owner or operator must

3151

install, if not

already

installed, and begin operating ACT equipment

or the

3152

Agency must be given written

notice that the EGU will be shut down on

3153

before the

following dates:

3154

3155

Fisk 19, Crawford 7, Crawford

Waukegan

7, and Waukegan 8

3156

on or

before July 1,

2008:

and

3157

3158

Powerton 5, Powerton

6, Will County 3, Will County 4, Joliet

3159

Joliet 7, and Joliet

on or before July 1,2009.

3160

3161

Notwithstanding subsection

(a) of this Section, the following EGUs are not

3162

required to install ACI equipment

because

they will be permanently shut down,

3163

addressed by Section 225.297, by the date specified:

3164

3165

EGUs that are required to permanently shut down:

3166

3167

On or before December 31, 2007, Waukegan

and

3168

3169

)

On or

before December 31, 2010, Will County 1 and Will

County

3170

3171

3172

Any other specified EGU

that is permanently shut down by December

31,

3173

2010.

3174

3175

Beginning on January

2015,

and continuing thereafter, and measured on

3176

rolling 12-month basis

(the

initial

period is January 1, 2015, through December

3177

31, 2015, and, then, for every 12-month period thereafter),

each specified EGU,

3178

except

Will

County 3, shall achieve one of the following

emissions standards:

3179

JCAR350225-08 1 8507r01

3180

emissions

standard of

0.0080 lbs mercury/GWh gross electrical

output:

3181

3182

3183

)

minimum 90 percent reduction

of input mercury.

3184

3185

Beginning on January 1, 2016,

and continuing thereafter, Will

County 3 shall

3186

achieve

the

mercury emissions

standards

of subsection (c) of this Section

3187

measured

on a rolling 12-month basis (the initial

period is January 1, 2016,

3188

through December 31, 2016,

and, then, for every 12-month

period thereafter).

3189

3190

Compliance with

Emission Standards

3191

3192

At any time

prior to the dates required for

compliance in subsections (c)

3193

and

(d)

of this Section, the owner

or operator

of a specified EGU. upon

3194

notice to the Agency,

may elect to comply with the emissions

standards

3195

subsection

on either:

3196

3197

a rolling 12-month basis,

or:

3198

3199

semi-annual

calendar

basis pursuant to the emissions testing

3200

requirements in Section 225.239(c),

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

and (2),

(h)(2),

3201

and

(i)(3)

and

(4)

of this

Subpart until June 30, 2012.

3202

3203

Once an EGU

subject

to the mercury emissions standards

of subsection

3204

(c)

of this Section, it

shall

not be subject to the requirements of

3205

subsections

(g),

(h), (i),

(i)

and (k)

of this Section.

3206

3207

Compliance with the mercury emissions

standards or reduction requirement

3208

this

Section must be calculated

in accordance with Section 225.230(a)

(b).

3209

3210

For

each EGU for which injection

of halogenated activated carbon is required

3211

subsection

(a)(1)

of this Section, the owner

or operator of the EGU must inject

3212

halogenated activated carbon

in an optimum manner, which, except

as provided in

3213

subsection (h) of this Section, is defined as all

of the following:

3214

3215

The use of an injection

system for effective absorption of mercury,

3216

considering the configuration

the EGU

and its

ductwork:

3217

3218

The injection of halogenated

activated

carbon manufactured

Aistom,

3219

Norit, or Sorbent Technologies,

or Calgon Carbon’s FLUEPAC MC

Plus,

3220

or the

injection

of any other halogenated activated

carbon

or sorbent that

3221

the owner or

operator of the EGU has demonstrated

to have similar or

3222

better effectiveness for

control of mercury

emissions:

and

JCAR350225-08

1 8507r01

3223

3224

The

injection

sorbent at the following minimum rates, as applicable:

3225

3226

For an

EGU firing subbituminous coal,

5.0 lbs per million actual

3227

cubic feet

or, for any cyclone-fired EGU that will install

a scrubber

3228

and baghouse

by December 31, 2012, and which already

meets an

3229

emission

rate

of 0.020

lb mercury/GWh gross electrical output

3230

at least

75 percent reduction of input mercury, 2.5

lbs per million

3231

actual cubic

feet;

3232

3233

For an

EGU firing bituminous coal, 10.0 lbs per million

actual

3234

cubic feet or, for any cyclone-fired

EGU

that will install a scrubber

3235

and baghouse

by December 31, 2012, and which already meets

3236

emission

rate of 0.020 lb mercury/GWh

gross electrical output or

3237

at least 75

percent reduction of input mercury, 5.0 lbs per million

3238

actual

cubic feet;

3239

3240

For

an EGU firing a blend of subbituminous

and

bituminous

coal,

3241

a rate that

is the weighted average of the rates

specified

3242

subsections (g)(3)(A)

and

(B),

based on the blend of coal being

3243

fired;

3244

3245

A rate

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

the rate

3246

specified

any of subsection (g)(3)(A),

(B),

(C)

of this

Section

3247

on a unit-specific basis,

provided

that the owner or operator

of the

3248

EGU has demonstrated that such rate

or rates are needed so that

3249

carbon injection

will

not increase particulate matter emissions

3250

opacity so as to threaten noncompliance

with

applicable

3251

requirements for

particulate matter or opacity.

3252

3253

For purposes of subsection

(g)(3) of this Section, the flue gas flow rate

3254

must be determined

for the point sorbent injection;

provided that this flow

3255

rate maybe assumed

to be identical to the stack flow rate if the gas

3256

temperatures

at the point of

injection

and the stack

are normally within

3257

100°F, or the flue gas

flow rate may otherwise be calculated from the

stack

3258

flow

rate,

corrected for the difference in

gas temperatures.

3259

3260

The owner or operator of an

EGU that seeks to operate an EGU with an activated

3261

carbon injection rate or rates that are set on

a unit-specific basis pursuant to

3262

subsection (g)(3)(D) of this Section must submit

an application to the Agency

3263

proposing

such rate

or rates, and must meet the

requirements

of subsections (h)(1)

3264

and

(h)(2)

of this Section,

subject to the limitations of subsections (h)(3) and

3265

(4)

of this Section:

JCAR350225-08 1 8507r01

3266

3267

)

The application

must be submitted as an application for a new

revised

3268

federally enforceable operation

permit for the EGU, and it must include

3269

summary of relevant mercury emissions

data for the EGU, the unit-

3270

specific injection

rate or rates that are proposed,

and

detailed information

3271

support

the proposed

injection

rate or rates; and

3272

3273

This application must be submitted no later

than

the date

that activated

3274

carbon

must first be

injected.

For example, the owner or operator

of an

3275

EGU that must inject activated carbon

pursuant to subsection

(a)(1)

of this

3276

Section

must

apply for unit-specific injection rate or rates

July

2008.

3277

Thereafier, the owner or

operator

may supplement

its

application; and

3278

3279

)

Any decision of the Agency denying

a permit or

granting

a permit with

3280

conditions that set

lower

injection

rate or rates may be appealed to

the

3281

Board pursuant to Section 39 of the Act; and

3282

3283

The owner or operator of an EGU may operate

the injection

rate or rates

3284

proposed in its application until a final decision is made on the application

3285

including a final decision on

any appeal to the Board.

3286

3287

During any evaluation of the effectiveness of a listed sorbent, alternative

sorbent,

3288

or other technique to control mercury emissions, the owner or operator of

an EGU

3289

need not comply with the requirements of subsection

(g)

of this Section for

any

3290

system needed to carry out the evaluation,

as further

provided

as follows:

3291

3292

The

owner

or operator of the EGU must conduct the evaluation in

3293

accordance with a formal evaluation

program

submitted

to the Agency at

3294

least

30 days prior to commencement of the

evaluation;

3295

3296

The duration

and scope of the evaluation may not exceed the duration

and

3297

scope

reasonably needed to complete the desired evaluation

of the

3298

alternative control techniques,

as initially addressed by the owner or

3299

operator in a support document submitted with the evaluation

program;

3300

3301

3302

The owner or operator of the EGU must submit a report to the Agency

3303

later than

30 days after the conclusion of the evaluation that describes

the

3304

evaluation conducted and which

provides

the results of the

evaluation;

and

3305

3306

If the evaluation of alternative control techniques shows less effective

3307

control

of mercury

emissions from the EGU than was achieved with

the

3308

principal control techniques,

the

owner

or operator of the EGU must

JCAR350225-081

8507r01

3309

resume use

of the principal control

techniques.

the evaluation

of the

3310

alternative

control

technique shows

comparable effectiveness to the

3311

principal

control technique, the owner or operator

of the EGU may either

3312

continue to use

the alternative control technique in a manner that

is at least

3313

effective

as the principal

control technique or it may resume use

of the

3314

principal

control

technique. If the evaluation

of the alternative control

3315

technique

shows more effective control of mercury emissions

than the

3316

control technique,

the owner or operator of the EGU must continue

to use

3317

the alternative control technique in

manner

that is more effective than

3318

the principal

control technique, so long as it continues to

be subject to this

3319

Section.

3320

3321

In addition to complying with the applicable

recordkeeping and monitoring

3322

requirements in Sections 225.240

through

225.290,

the owner or operator

of an

3323

EGU that elects

to comply with Section 225.230(a)

by means of the CPS must

3324

also comply with the following

additional

requirements:

3325

3326

For the first

36 months that

injection

of sorbent is required, it must

3327

maintain records of the usage

sorbent,

the exhaust gas flow rate from

3328

the EGU,

and the

sorbent feed rate, in pounds per million

actual cubic feet

3329

of exhaust

gas at the

injection

point, on a weekly average;

3330

3331

)

After the first 36 months that

injection

of sorbent is required, it must

3332

monitor activated sorbent feed rate

the

EGU, flue gas temperature

at the

3333

point of sorbent injection, and exhaust gas flow rate

from the EGU,

3334

automatically recording

this data and the sorbent carbon feed rate, in

3335

pounds per million actual cubic

feet of

exhaust

gas at the

injection

point,

3336

an hourly average;

and

3337

3338

)

If a blend of

bituminous and subbituminous coal is fired in the EGU,

3339

must keep records of the amount

each

type of coal burned and the

3340

required injection rate

for

injection

of activated carbon on a weekly

basis.

3341

3342

In addition to complying with

the applicable reporting requirements in Sections

3343

225.240 through

225.290,

the owner or operator of an EGU

that elects to comply

3344

with Section 225.23

0(a)

by means of the CPS must also submit quarterly

reports

3345

for the recordkeeping and monitoring

conducted pursuant to subsection

ii)

this

3346

Section.

3347

3348

As an alternative to the

CEMS monitoring, recordkeeping, and reporting

3349

requirements in Sections 225.240

through

225.290,

the owner or operator

of an

3350

EGU may elect to comply with the emissions testing,

monitoring, recordkeeping,

JCAR350225-08

1 8507r01

3351

and reporting requirements in Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2),

3352

(i)(3) and (4),

and

(fl(1).

3353

3354

(Source:

Added at 33 Iii. Reg.

effective

3355

3356

Section

225.295 Combined-Pollutant Standard: Emissions

Standards for

NOX

and

3357

Trcatment of Mcrcury Allowances

3358

3359

Any

mercury allowances allocated

the Agency

by the USEPA must be treated as follows:

3360

3361

such allowances

may be

allocated

to any owner or operator of an EGU or

3362

other sources of mercury emissions into the atmosphere or discharges

into the

3363

waters of the State.

3364

3365

The Agency must hold all allowances allocated

by the USEPA to the State. At

3366

the

end of each calendar year, the Agency must instruct the USEPA to retire

3367

permanently all such allowances.

3368

3369

Emissions Standards for

and

Reporting Requirements.

3370

3371

Beginning with calendar year 2012 and continuing in each calendar

year

3372

thereafter, the CPS group, which includes all specified EGUs that have

not

3373

been permanently shut down by December 31 before the applicable

3374

calendar year, must

comply with

a CPS group average annual

3375

emissions rate of no more than

0.11

lbs/mmBtu.

3376

3377

Beginning with ozone season

control period

2012

and continuing in each

3378

ozone season control period

(May

1 through September

30)

thereafter,

the

3379

CPS

group, which includes

all specified EGUs that have not been

3380

permanently shut down by December 31 before the applicable ozone

3381

season, must comply with a

CPS group

average

ozone season

3382

emissions rate of no more than 0.11 lbs/mmBtu.

3383

3384

The

owner or operator of the specified EGUs in the CPS group must

file,

3385

not later than one year after

startup of any selective SNCR on such EGU,

3386

report with the Agency describing the

emissions reductions that

the

3387

SNCR has

been

able to

achieve.

3388

3389

Emissions Standards for

Beginning

calendar year 2013

and continuing in

3390

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

3391

CPS group average

annual

SO emissions rate listed as follows:

3392

3393

lbs/nimBtu

JCAR350225-08 1 8507r01

3394

3395

2013

0.44

3396

2014

0.41

3397

2015

028

3398

2016

0.195

3399

2017

0.15

3400

2018

0.13

3401

2019

0.11

3402

3403

Compliance with the

and

2 emissions standards must be demonstrated

3404

accordance

with

Sections 225.310, 225.410, and 225.5 10. The owner

or operator

3405

of the specified EGUs must complete

the demonstration of compliance

pursuant

3406

to Section

225 .298(c)

before March 1 of the following year for annual

standards

3407

and

before November 30 of the particular

year

for ozone

season

control periods

3408

(May

1 through September

30)

standards, by which date a compliance report

must

3409

submitted to the Agency.

3410

3411

The CPS group average annual

emission rate,

annual

emission rate

and

3412

ozone season

emission rates shall be determined as follows:

3413

3414

3415

ERavb = 2

(SO

orNOtons)/

(HI

3416

i=1

i=l

3417

3418

Where:

3419

ER = average

annual or ozone season emission rate in

lbs/mmBbtu of all EGUs in the CPS group.

HI,

= heat input

for the

annual

or ozone control period of each

EGU, in mmBtu.

= actual annual

tons of each

EGU in the CPS group.

NQi

= actual annual or ozone season

tons of each EGU

the CPS group.

= number

of EGUs that are in the CPS group

each EGU

in the CPS group.

3420

3421

(Source:

Amended at

Ill. Reg.

effective

3422

3423

Section

225.296 Combined Pollutant Standard: Control Technology

Reiuirements

for

3424

QQ2,

and PM

Emissions

3425

3426

Control Technology Requirements

for

and SO

3427

JCAR350225-081 8507r01

3428

or before December 31, 2013, the owner

operator must either

3429

permanently

shut

down

or install and have operational FGD equipment

3430

Waukegan

3431

3432

)

On or before

December 31, 2014, the owner or operator must either

3433

permanently

shut

down or

install and

have

operational FGD equipment

3434

Waukegan

3435

3436

)

On or before

December 31,

2015,

the

owner or operator must either

3437

permanently

shut down or install and have operational

FGD

equipment

3438

Fisk 19;

3439

3440

If Crawford

will

be operated after December 31, 2018, and not

3441

permanently

shut down by this date, the owner or operator must:

3442

3443

)

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

3444

SNCR or equipment capable

delivering essentially

equivalent

3445

reductions on Crawford

and

3446

3447

On or before December 31, 2018, install

and

have operational

FGD

3448

equipment on Crawford

3449

3450

)

If Crawford

will

be operated afier December 31, 2017 and not

3451

permanently shut down

by this date, the owner or operator must:

3452

3453

)

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

3454

SNCR or

equipment capable of delivering essentially equivalent

3455

emissions reductions on Crawford

and

3456

3457

On or before December 31, 2017, install and have operational

FGD

3458

equipment on Crawford

3459

3460

Other Control Technology Requirements for

2.Owners or operators of

3461

specified EGUs must either permanently shut down or install FGD equipment

3462

each

specified EGU

(except

Joliet

5),

or before December 31, 2018, unless

3463

earlier date is specified in subsection

(a)

of this Section.

3464

3465

Control Technology Requirements for

PM. The owner or operator of the two

3466

specified EGUs listed in this subsection that

are equipped with a hot-side ESP

3467

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

3468

designed fabric

filter,

permanently shut down the EGU

the dates specified.

3469

Hot-side ESP means an ESP

on a coal-fired boiler that is installed before the

3470

boiler?s

air-preheater where the operating

temperature is typically at least 5 50°F,

JCAR350225-08

1 8507r01

3471

as distinguished from a cold-side

ESP

that is installed

after

the

air

pre-heater

3472

where

the

operating

temperature is typically no more than 350°F.

3473

3474

Waukegan 7 on or before December 31, 2013; and

3475

3476

)

Will

County

3 on or before December 31,

2015.

3477

3478

Beginning on December 31, 2008, and annually thereafter up to and including

3479

December 31,

2015,

the owner or operator of the Fisk power plant must submit in

3480

writing to the Agency a report

on any

technology

equipment

designed

to affect

3481

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

3482

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

operator to install

3483

any equipment

described

in the report.

3484

3485

Notwithstanding

35 Ill. Adm. Code

20l.146(hhh),

until an EGU has complied

3486

with the applicable requirements of subsections

225.296(a),

(b),

and

(c),

the

3487

owner or

operator

of the EGU must

obtain

a construction permit for any new or

3488

modified air pollution control equipment that it proposes to construct for

control

3489

of emissions of mercury,

NOR,

PM, or

3490

3491

(Source:

Added at 33 Ill. Reg.

effective

3492

3493

Section

225.297 Combined Pollutant Standard: Permanent Shut-Downs

3494

3495

The

owner or operator

of the following EGUs must permanently shut down the

3496

EGU by

the dates specified:

3497

3498

Waukegan

before December 31, 2007; and

3499

3500

)

Will County 1

and

Will County 2 on or before December 31, 2010.

3501

3502

later thasi 8 months before the date that a specified EGU will be permanently

3503

shut down, the

owner

or operator must submit a report to the Agency that includes

3504

description of the actions that have already been taken to allow the shutdown

3505

the EGU

and

a description of the future actions that must be accomplished to

3506

complete

the shutdown

the EGU, with the anticipated schedule

for those

3507

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

3508

3509

ç).

No later

than six months before

a specified

EGU

will be permanently shut down,

3510

the

owner or operator shall apply

for

revisions to the operating permits for

the

3511

EGU to include provisions that terminate the authorization to operate the

unit

3512

that date.

3513

JCAR350225-08

1 8507r01

3514

If after applying

for

obtaining

a construction

permit

to install

required control

3515

equipment,

the

owner or

operator

decides to permanently

shut-down

Specified

3516

EGU

rather

than install

the

required

control

technology, the owner

or operator

3517

must

immediately

notify

the Agency in writing

and thereafter

submit the

3518

information

required

by subsections

(b)

and

3519

3520

Failure to permanently

shut

down

specified

EGU

the required date shall

3521

considered

separate

violations of the

applicable emissions

standards

and

control

3522

technology requirements

of the CPS

for

NON,

PM,

SO,,

and mercury.

3523

3524

(Source:

Added at

33 Ill. Reg.

effective

3525

3526

Section

225.298 Combined

Pollutant

Standard: Requirements

for

and SO

3527

Allowances

3528

3529

The

following

requirements

apply to

the owner, the operator,

and the

designated

3530

representative with

respect

to SO

and

allowances:

3531

3532

The owner,

operator, and

designated representative

of specified EGUs

in a

3533

CPS group

is permitted

sell,

trade,

transfer

SO,

and

emissions

3534

allowances

of any vintage

owned, allocated

to, or earned by

the specified

3535

EGUs

(the

“CPS

allowances”)

to its affiliated

Homer City,

Pennsylvania,

3536

generating

station

for as long as the Homer

City Station needs

the

CPS

3537

allowances

for

compliance.

3538

3539

)

When and if

the Homer City Station

no longer requires

all

of the CPS

3540

allowances,

the owner, operator,

or designated representative

specified

3541

EGUs in a CPS

group may sell

any and all remaining

CPS allowances,

3542

without restriction,

to any person

or entity located

anywhere,

except

that

3543

the owner or

operator may not directly

sell, trade,

transfer CPS

3544

allowances to

a unit

located

Ohio,

Indiana, Illinois,

Wisconsin,

3545

Michigan, Kentucky,

Missouri, Iowa,

Minnesota, or

Texas.

3546

3547

In no event shall

this subsection

(a)

require or be interpreted

to require

any

3548

restriction whatsoever

the

sale, trade, or exchange

of the CPS

3549

allowances by

persons or entities who

have acquired

the CPS allowances

3550

from the

owner, operator, or designated

representative

of specified

EGUs

3551

maCPS

group.

3552

3553

The owner,

operator,

and designated

representative

of EGUs in a specified

CPS

3554

group

prohibited from purchasing

or using

and

allowances for

the

3555

purposes

meeting the

SO, and

emissions

standards set forth

in Section

3556

225.295.

JCAR350225-08

1 8507r01

ç).

Before March 1, 2010, and

continuing each year thereafler, 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

allowances that

have been

used for compliance with

any

trading

programs, and any

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 in 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

Iii.

Reg.

effective•

Section

225.299 Combined Pollutant

Standard: Clean Air Act Requirements

The

emissions

rates

set forth in

the CPS shall be deemed to be best available retrofit

technology (

BART”) under the Visibility

Protection

provisions of the CAA (42

USC 7491),

reasonably available control technology (BRACT”) and reasonably available

control measures

(

RACM”) for

achieving

fine

particulate

matter

(“PM”)

requirements under NAAOS

in effect

on August 31,

2007, as required

by the CAA (42

USC

7502).

The Agency may use the

SO, and

emissions

reductions required under

the CPS in

developing

attainment demonstrations

and

demonstrating

reasonable further progress

for PM and 8 hour ozone standards, as required

under

the CAA. Furthermore, in developing rules, regulations,

or State Implementation Plans

designed to comply

with PM and

8 hour ozone

NAAOS,

the Agency, taking into

account all

emission

reduction efforts and other appropriate

factors, will use best efforts to seek

and

emissions rates

from

other EGUs that are equal to or less than the rates

applicable to the

CPS

group and

will seek

and NO reductions

from other sources before seeking additional

emissions reductions

from any

EGU in the CPS group.

(Source:

Added at

Iii.

Reg.

effective

SUBPART F:

COMBiNED POLLUTANT STANDARDS

Section 225.600

Purpose (Repealed)

The puose of

this Subpart F is to allow an alternate means

of compliance with the emissions

standards

for mercury

Section 225.23

0(a)

for specified EGUs

through permanent shut down,

installation of ACT,

and the application

of pollution control technology for

NON,

PM, and

emissions that also

reduce mercury

emissions as a co benefit and to establish permanent

emissions

standards for those specified

EGUs. Unless

othevise

provided for in this Subpart

3557

3558

3559

3560

3561

3562

3563

3564

3565

3566

3567

3568

3569

3570

3571

3572

3573

3574

3575

3576

3577

3578

3579

3580

3581

3582

3583

3584

3585

3586

3587

3588

3589

3590

3591

3592

3593

3594

3595

3596

3597

3598

(

)JF

OCN

(ID

(‘I

lCD

I—

lCD

)LS

Ci):

)

-F

3-.

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(

‘3

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3-’

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)

r-C

(

-C

)

•

-3

3--.

3-F

-F.

‘It

(

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1-.

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3-.

‘-3

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C_F

F-

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3-4

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JCAR350225-08 1 8507r01

4082

Section 225.APPENDIX A Specified

EGUs

for Purposes

of the CPSSubpart F (Midwest

4083

Generation’s

Coal-Fired Boilers as of July 1, 2006)

4084

Plant

Permit

Number

Crawford

031 600AIN

Boiler

Permit designation

Unit

7 Boiler BLR1

Unit 8 Boiler BLR2

çSubpar-tF

Designation

Crawford

Crawford 8

Unit 19 Boiler BLR19

Unit 7 Boiler BLR71

Unit 7 Boiler BLR72

Unit 8 Boiler BLR81

Unit 8 Boiler BLR82

Unit 6 Boiler BLR5

Powerton

179801AAA

Unit 5 Boiler BLR5 1

Unit

Boiler BLR52

Unit 6 Boiler BLR61

Unit 6 Boiler BLR62

Powerton

Waukegan

097190AAC

Unit 6 Boiler BLR17

Unit

Boiler BLR7

Unit 8 Boiler BLR8

Waukegan

4085

Will

County

19781 OAAK

Unit 1 Boiler BLR1

Unit 2 Boiler BLR2

Unit

Boiler BLR3

Unit 4 Boiler BLR4

Will County

Will

County 2

Will County

Will

County 4

Fisk

031600AM1

Joliet

197809AA0

Fisk

Joliet

Joliet 7

Joliet

Joliet 8

Joliet

4086

(Source:

Amended at 33 Ill. Reg.

effective

JCAR350225-081

8507r01

4087

Section 225.APPENDIX B Continuous Emission

Monitoring Systems for Mercury

4088

4089

Section 1.1 Applicability

4090

4091

The provisions of this Appendix apply to sources subject to

35 Iii. Adm. Code

225

mercury

(Hg)

4092

mass emission reduction program.

4093

4094

Section 1.2 General Operating Requirements

4095

4096

Primary

Equipment Performance

Requirements. The owner or

operator

must

4097

ensure that each continuous mercury emission

monitoring system required by this

4098

Appendix meets the equipment,

installation and performance specifications

4099

Exhibit

this Appendix and is maintained according

to the quality assurance

4100

and quality control procedures in Exhibit B

to this Appendix.

4101

4102

Heat Input Rate Measurement Requirement.

The owner or operator must

4103

determine and record

the heat input rate, in units of mmBtu/hr,

each

affected

4104

unit for every hour or

part

of an hour

any fuel is combusted following the

4105

procedures in Exhibit

to this Appendix.

4106

4107

Primary Equipment Hourly

Operating Requirements. The owner or operator

must

4108

ensure that all continuous mercury emission

monitoring

systems required by

this

4109

Appendix are in operation and monitoring unit emissions

at all times that the

4110

affected unit combusts any fuel except during periods

calibration,

quality

4111

assurance, or preventive

maintenance, performed pursuant to Section 1.5

of this

4112

Appendix and Exhibit B to this Appendix,

periods

of repair, periods of backups

4113

data from the data acquisition and handling system,

recertification

performed

4114

pursuant to Section 1.4 of this

Appendix.

4115

4116

The owner or operator

must ensure that each continuous emission

4117

monitoring

system is capable of completing

minimum

of one cycle of

4118

operation (sampling, analyzing

and data recording) for each successive

15-

4119

minute interval.

The owner or operator must reduce all volumetric

flow,

4120

çQ2concentration,

concentration

and mercury concentration data

4121

collected

the

monitors to hourly averages. Hourly averages

must be

4122

computed using at least

one data point in each 15 minute quadrant

of an

4123

hour,

where

the unit combusted fuel

during that quadrant of an hour.

4124

Notwithstanding

this requirement, an hourly average may be

computed

4125

from at least two

data points separated

a minimum of 15 minutes

4126

(where the unit operates

for more

than one quadrant of an

hour)

if data

are

4127

unavailable as a result of the performance

of calibration, quality assurance,

4128

preventive

maintenance activities pursuant

to Section 1.5 of this

4129

Appendix and Exhibit

B to this Appendix, or backups of data

from the

JCAR350225-08 1 8507r01

4130

data acquisition

and handling

system,

recertification,

pursuant

4131

Section 1.4 of this

Appendix. The owner or operator

must use all

valid

4132

measurements or data

points collected during an hour to calculate

the

4133

hourly averages. All data

points collected during an hour must be, to

the

4134

extent

practicable, evenly

spaced over the hour.

4135

4136

)

Failure

emissions

concentration

monitor, mercury

4137

concentration monitor, flow monitor

or a

moisture

monitor to acquire

the

4138

minimum

number of data points for calculation of an hourly

average in

4139

subsection

(c)(1)

this

Section must

result in the failure to obtain

a valid

4140

hour of data and the loss of such component data for

the

entire

hour. For

4141

moisture monitoring

system consisting of one or more oxygen analyzers

4142

capable of measuring

on a wet-basis and a dry-basis,

an hourly average

4143

percent moisture value is

valid only if the

minimum

number of data

points

4144

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

4145

4146

Optional Backup Monitor Requirements. If the owner or operator chooses

to use

4147

two or more continuous mercury emission

monitoring

systems, each of which

4148

capable of monitoring the same stack or duct at a specific affected

unit, or group

4149

of units using a

common

stack, then the owner or operator must designate

one

4150

monitoring system

the

primary monitoring system, and must record this

4151

information in the monitoring

plan,

provided

for in

Section

1.10 of this

4152

Appendix. The owner or operator must designate the other monitoring

systems

4153

backup

monitoring systems in the monitoring plan. The backup monitoring

4154

systems

must be designated as redundant backup monitoring

systems,

non-

4155

redundant backup monitoring

systems, or

reference

method

backup systems,

4156

described in Section

1.4(d)

of this Appendix. When the certified primary

4157

monitoring

system is

operating and not out-of-control as defined in Section

1.7 of

4158

this Appendix, only data from the certified primary monitoring

system must be

4159

reported

valid, quality-assured

data. Thus, data from the backup monitoring

4160

system may be reported as valid, quality-assured data only when the

backup is

4161

operating and not out-of-control

as defined in

Section

1.7 of this Appendix

(or

4162

the applicable reference method in appendix A of 40 CFR

60,

incorporated

4163

reference in Section 225.140)

and when the certified primary monitoring system

4164

is not operating (or is operating but

out-of-control).

A particular monitor

may

4165

designated

both as a certified

primary monitor for one unit and as a certified

4166

redundant backup monitor for another unit.

4167

4168

Minimum

Measurement

Capability Requirement. The owner or operator must

4169

ensure

that

each continuous

emission monitoring system is capable of accurately

4170

measuring,

recording and reporting

data, and must

not incur

an exceedance of

the

4171

full scale range, except as provided in Section 2.1.2.3 of Exhibit

A to this

4172

Appendix.

JCAR350225-081

8507r01

4173

4174

Minimum

Recording

and Recordkeeping

Requirements.

The

owner or

operator

4175

must record and the

designated representative

must report

the hourly, daily,

4176

quarterly

and

annual

information collected

under the requirements

as specified

4177

subpart

of 40

CFR 75, incorporated

reference in

Section 225.140,

and

4178

Section

1.11 through

1.13 of

this

Appendix.

4179

4180

Section 1.3 Special Provisions

for

Measuring

Mercury

Mass Emissions Using

the

Excepted

4181

Sorbent Trap Monitoring

Methodology

4182

4183

For

an affected coal-fired

unit under

Iii. Adm. Code

225,

if the owner or

operator

elects

to use

4184

sorbent trap monitoring

systems

(as

defined

in Section 225.130)

to quantify mass

emissions,

the

4185

guidelines

in subsections (a)

through

(1)

of this Section must

be followed for this excepted

4186

monitoring

methodology:

4187

4188

For

each sorbent

trap monitoring

system

(whether

primary or redundant

backup),

4189

the

use of paired

sorbent traps, as

described in Exhibit

D to this Appendix,

4190

required;

4191

4192

Each sorbent

trap must have

a main section, a

backup section and

a third section

4193

allow spiking with a calibration

gas of known

mercury concentration,

4194

described

Exhibit

D to this Appendix;

4195

4196

A certified flow monitoring

system

is required;

4197

4198

Correction

for stack gas moisture

content is required, and

in some cases,

4199

certified

monitoring

system is required

(see

Section 1.15(a)(4));

4200

4201

Each sorbent trap

monitoring

system must be installed

and operated in

accordance

4202

with Exhibit

D to this Appendix.

The automated

data

acquisition and

handling

4203

system must ensure

that the sampling

rate

is proportional

to the stack gas

4204

volumetric

flow rate.

4205

4206

the beginning and

end of each

sample collection period,

and at least

once

4207

each unit operating

hour during the collection

period,

the gas flow meter

reading

4208

must be recorded.

4209

4210

After each

sample collection

period,

the

mass

of mercury adsorbed in

each

4211

sorbent

trap (in all three

sections)

must be determined

according

to the applicable

4212

procedures

in Exhibit D

to this Appendix.

4213

4214

The

hourly mercury mass

emissions for

each collection period

are determined

4215

using the results of the

analyses

in conjunction

with contemporaneous

hourly

data

JCAR350225-081

8507r01

4216

recorded by a certified stack

flow monitor, corrected for the stack

gas moisture

4217

content.

For

each

pair of sorbent traps analyzed,

the

average

of the 2 mercury

4218

concentrations must

be used for reporting purposes under Section

1.18(f)

of this

4219

Appendix. Notwithstanding this

requirement, if, due to circumstances

beyond the

4220

control

of the owner or operator,

one of the paired traps is accidentally lost,

4221

damaged

broken

and cannot be analyzed,

the

results

of the analysis of the

other

4222

trap may be used for

reporting purposes, provided that the other

trap has met all

4223

the applicable quality-assurance

requirements

of this Part.

4224

4225

All unit operating

hours for which valid mercury concentration

data are obtained

4226

with the primary sorbent trap monitoring

system

(as

verified using the quality

4227

assurance procedures

in Exhibit D to this Appendix) must be reported in

the

4228

electronic quarterly report under Section 1.18(f)

of this Appendix. For hours

4229

which data from the primary

monitoring system are

invalid,

the owner or

operator

4230

may, in accordance with Section 1.4(d) of this Appendix,

report valid mercury

4231

concentration data from:

a certified redundant backup CEMS or sorbent trap

4232

monitoring

system a certified non-redundant backup

CEMS or sorbent trap

4233

monitoring

system:

an applicable reference method under Section 1.6

of this

4234

Appendix.

4235

4236

Initial certification requirements

and additional quality-assurance requirements

4237

for the sorbent trap monitoring

systems are found in Section 1

.4(c)(7),

Section

4238

6.5.6 of Exhibit A to this Appendix,

in Sections 1.3 and 2.3 of Exhibit B to this

4239

Appendix, and in Exhibit D to this Appendix.

4240

4241

ç)

During each RATA

of a sorbent trap monitoring system, the type of sorbent

4242

material used by the traps must

be the

same

for

daily operation of the

4243

monitoring

system.

A new pair of traps must be used for each RATA run.

4244

However, the size of the traps used

for the

RATA

may be smaller than the traps

4245

used for

daily operation

of the system.

4246

4247

Whenever the type of

sorbent material used by the traps is changed, the owner

4248

operator must conduct a diagnostic RATA of the modified

sorbent trap

4249

monitoring system within

720 unit or stack operating hours after the date and

hour

4250

when the new sorbent material is first used. If the

diagnostic RATA is passed,

4251

data from

the modified

system may be reported as quality-assured, back

to the

4252

date and hour when the new

sorbent material was first used. If the RATA is

4253

failed, all data from the modified system must be invalidated,

back

to the date

and

4254

hour when the new sorbent material was first used, and data

from the system

must

4255

remain

invalid

until

a subsequent RATA is passed. If the required RATA

is not

4256

completed within 720 unit or

stack operating hours, but is passed on the first

4257

attempt,

data from the modified system

must

be invalidated beginning with the

4258

first

operating hour after the 720 unit or stack operating

hour

window

expires,

and

JCAR350225-0818507r01

4259

data

from the

system

must

remain invalid

until the date

aid

hour of completion

4260

the

successful

RATA.

4261

4262

Section

1.4 Initial

Certification

and

Recertification

Procedures

4263

4264

Initial Certification

Approval

Process.

The

owner or

operator

must

ensure

that

4265

each

continuous

mercury

emission

monitoring

system

required by

this Appendix

4266

meets

the

initial

certification

requirements

of this Section.

fri addition,

whenever

4267

the

owner

or operator

installs

continuous

mercury

emission

monitoring

system

4268

in order

to meet

the

requirements

of Section

1.3

of this

Appendix

and 40

CFR

4269

sections

75.11 through

75.14

and 75.16

through

75.18,

incorporated

reference

4270

in Section

225.140,

where

continuous

emission

monitoring

system was

4271

previously

installed,

initial

certification

is required.

4272

4273

Notification

of initial

certification

test dates.

The

owner

or operator

4274

designated

representative

must submit

a written

notice

of the dates

4275

initial certification

testing

at the

unit as specified

40 CFR

75.6 1(a)(1),

4276

incorporated

reference

in Section

225.140.

4277

4278

Certification

application.

The

owner

operator

must

apply for

4279

certification

each

continuous

mercury

emission monitoring

system.

4280

The owner

operator

must

submit the

certification

application

4281

accordance

with

CFR

75.60, incorporated

reference

Section

4282

225.140,

and

each complete

certification

application

must

include

the

4283

infonnation

specified

CFR

75.63,

incorporated

reference

4284

Section

225.140.

4285

4286

)

Provisional

approval

certification

(or

recertification)

applications.

Upon

4287

the

successful

completion

of the

required

certification

(or

recertification)

4288

procedures

of this Section,

each continuous

mercury

emission

monitoring

4289

system

must

be deemed

provisionally

certified

(or

recertified)

for

use for a

4290

period

not

to exceed

120

days following

receipt

the Agency

of the

4291

complete certification

(or

recertification)

application

under

subsection

4292

(a)(4)

this

Section.

Data

measured

and recorded

a provisionally

4293

certified

(or

recertified)

continuous

emission

monitoring

system,

operated

4294

accordance

with

the

requirements

of Exhibit

B to

this

Appendix,

will

4295

considered

valid

quality-assured

data

(retroactive

the

date and time

4296

provisional

certification

or recertification),

provided

that

the Agency

does

4297

not invalidate

the

provisional

certification

(or

recertification)

issuing

4298

notice

disapproval

within 120

days

of receipt

the

Agency

of the

4299

complete

certification

(or recertification)

application.

Note

that

when the

4300

conditional

data

validation

procedures

of subsection

(b)(3)

of this Section

4301

are

used for the

initial

certification

(or

recertification)

of a continuous

JCAR350225-081 8507r01

4302

emissions monitoring

system, the date and time of provisional certification

4303

(or recertification)

the CEMS

may be

earlier

than the date and time

4304

completion

of the required certification (or recertification) tests.

4305

4306

Certification (or recertification)

application formal approval process.

The

4307

Agency will issue a notice of approval

disapproval

of the certification

4308

(or

recertification)

application to the owner or operator within 120

days

4309

after receipt

of the complete certification

(or recertification)

application.

4310

the event the Agency does not issue

such a

notice within 120

days after

4311

receipt, each

continuous emission monitoring system that meets

the

4312

performance requirements

this

Part and

included in the certification

4313

(or

recertification)

application will be deemed certified (or recertified)

for

4314

use under 35 Ill. Adm. Code 225.

4315

4316

Approval notice. If the certification (or recertification)

application

4317

is complete

and shows that each continuous emission monitoring

4318

system meets the performance requirements

this

Part, then the

4319

Agency

will issue a notice of approval of the certification

(or

4320

recertification) application

within

120

days after receipt.

4321

4322

Incomplete application notice. A certification (or recertification)

4323

application

will

be considered complete when all of the applicable

4324

information

required to be submitted in 40 CFR 75.63,

4325

incorporated

reference

in Section

225.140,

has been received

4326

the Agency. If the certification

(or

recertification)

application is

4327

not

complete,

then the Agency will issue a notice of

4328

incompleteness that provides

a reasonable timeframe for the

4329

designated representative to submit the additional information

4330

required

to complete

the certification

(or

recertification)

4331

application. If the designated representative has not

complied with

4332

the notice of incompleteness

by a

specified

due date, then the

4333

Agency may issue a notice of disapproval specified under

4334

subsection

(a)(4)(C)

of this Section. The 120day

review period

4335

will

not

begin prior to receipt of a complete application.

4336

4337

Disapproval notice. If the certification

(or

recertification)

4338

application

shows that any continuous emission monitoring

system

4339

does not meet the performance requirements

of this Part, or if

the

4340

certification

(or recertification)

application

is incomplete and the

4341

requirement for disapproval under subsection (a)(4)(B)

of this

4342

Section

has been met, the Agency must issue a written notice

4343

disapproval

of the certification

(or recertification)

application

4344

within 120 days after receipt.

issuing

the notice of disapproval,

JCAR350225-08 1 8507r01

4345

the provisional

certification

(or recertification)

is invalidated

by the

4346

Agency,

and the data measured and recorded

each uncertified

4347

continuous emission

or opacity monitoring system must not

4348

considered valid

quality-assured data as follows: from the hour of

4349

the

probationary calibration error test that began the initial

4350

certification

(or

recertification) test period (if the conditional

data

4351

validation procedures

of subsection (b)(3) of this Section were

4352

used to retrospectively validate

data);

or from the date and time of

4353

completion of the invalid certification or recertification

tests

(if

the

4354

conditional data

validation procedures of subsection (b)(3) of this

4355

Section

were not used). The owner or operator must follow

the

4356

procedures for loss

initial

certification in subsection

(a)(5)

4357

this Section for each continuous emission or opacity monitoring

4358

system

that is disapproved for

initial certification. For each

4359

disapproved

recertification, the owner or operator must follow

the

4360

procedures of subsection

(b)(5)

this Section.

4361

4362

)

Procedures for loss of certification.

When

the Agency issues a notice of

4363

disapproval

of a certification application or a notice of disapproval

4364

certification

status

(as

specified in subsection (a)(4) of this

Section),

then:

4365

4366

)

Until such time, date and hour as the continuous

mercury emission

4367

monitoring system can be adjusted, repaired or replaced

and

4368

certification tests successfully completed

(or,

if the conditional

4369

data validation

procedures in subsections

(b)(3)(B)

through

(I)

4370

this Section are used, until a probationary

calibration error test is

4371

passed following corrective actions in accordance with

subsection

4372

(b)(3)(B) of this Section),

the

owner

or operator must perform

4373

emissions testing pursuant to Section 225 .239.

4374

4375

The designated representative must submit a notification of

4376

certification retest dates

specified in

Section

225.250(a)(3)(A)

4377

and a new certification application according to the procedures

4378

Section

225.250(a)(3)(B):

and

4379

4380

The owner or operator

must repeat all certification tests or other

4381

requirements that were failed by the continuous

mercury emission

4382

monitoring

system, as indicated in the Agency’s notice of

4383

disapproval,

later

than 30 unit operating days after the date

4384

issuance of the notice of disapproval.

4385

4386

Recertification

Approval Process. Whenever the owner or operator makes

4387

replacement, modification

or change in a certified continuous mercury emission

JCAR350225-08 1

8507r01

4388

monitoring

system

that may significantly

affect the ability of the system

4389

accurately measure

or record the gas volumetric flow rate,

mercury concentration,

4390

percent moisture, or to meet the

requirements of Section 1.5

this

Appendix

4391

Exhibit

B to this Appendix, the owner

or operator must recertify the continuous

4392

mercury emission

monitoring

system, according

the

procedures in this

4393

subsection. Examples

of changes that require recertification

include: replacement

4394

of the analyzer; change

in location or orientation of the sampling probe

or site;

4395

and complete replacement of an existing

continuous

mercury emission monitoring

4396

system. The owner

or operator

must also recertify the continuous

emission

4397

monitoring

systems

for

unit

that has recommenced commercial operation

4398

following

a period of long-term cold storage

defined

in Section

225.130.

Any

4399

change to a flow monitor or

gas monitoring system for which a RATA is

not

4400

necessary will not

be considered a recertification event.

In addition, changing

the

4401

polynomial coefficients or K factors

of a flow monitor will require a 3-load

4402

RATA, but is not considered

to be a recertification event; however,

records

of the

4403

polynomial coefficients or K factors

currently in use must be maintained on-site

4404

format suitable

for inspection. Changing the coefficient or

K factors of a

4405

moisture monitoring system will

require a RATA, but is not considered

to be a

4406

recertification

event;

however, records of the coefficient

or K factors currently

4407

use

the moisture monitoring

system must be maintained on-site in

a format

4408

suitable

for inspection. In

such cases, any other tests that are necessary

to ensure

4409

continued

proper operation of

the monitoring system (e.g., 3-load flow RATAs

4410

following changes to flow monitor polynomial coefficients,

linearity checks,

4411

calibration error tests, DAHS verifications, etc.) must be

performed as diagnostic

4412

tests,

rather than

recertification

tests. The data validation procedures

4413

subsection

(b)(3)

of this Section

must be applied to RATAs associated with

4414

changes to flow or moisture monitor coefficients, and to linearity

checks,

7-day

4415

calibration error tests and

cycle time tests when these are required as

diagnostic

4416

tests. When the data

validation

procedures

of subsection

(b)(3)

of this Section

are

4417

applied in this manner,

replace

the word “recertification” with the word

4418

“diagnostic”.

4419

4420

Tests required. For all recertification testing, the owner

or operator must

4421

complete all initial certification

tests in subsection

(c)

of this Section

that

4422

are applicable to the monitoring system, except

otherwise

approved

4423

the Agency. For diagnostic

testing after changing the flow rate

monitor

4424

polynomial coefficients, the owner

or operator must complete a 3-level

4425

RATA. For

diagnostic

testing after changing the K

factor

or mathematical

4426

algorithm

of a moisture

monitoring

system, the owner or

operator must

4427

complete

a RATA.

4428

4429

)

Notification of recertification test dates. The

owner, operator or designated

4430

representative must

submit notice of testing dates for

recertification under

JCAR350225-081

8507r01

4431

this subsection

as specified

in 40 CFR 75.61(a)(l)(ii),

incorporated

4432

reference

in Section 225.140,

unless

all

of the tests in subsection

4433

Section

are

required

for recertification, in which

case

the

owner

4434

operator

must provide

notice in accordance

with the notice provisions

for

4435

initial certification testing

in 40

CFR

75.61(a)(l)(i),

incorporated

4436

reference

in Section

225.140.

4437

4438

Recertification

test period requirements

and data validation.

The data

4439

validation

provisions

in subsections

(b)(3)(A)

through

(I)

of this Section

4440

will apply to

all mercury CEMS

recertifications and

diagnostic testing.

4441

The provisions

in subsections

(b)(3)(B) through

(I)

of this Section may

4442

also be applied

to initial certifications

(see

Sections

6.2(a), 6.3.1(a),

4443

6.3.2(a),

6.4(a)

and

6.5(f)

of Exhibit

A to this Appendix)

and may be

used

4444

to supplement

the linearity check

and RATA data validation

procedures

4445

Sections 2.2.3(b)

and

2.3.2(b)

of Exhibit

B to

this Appendix.

4446

4447

The

owner or operator must

report emission

data using a reference

4448

method

or another monitoring

system that has

been certified or

4449

approved

for use under this

Part,

in the

period extending from

the

4450

hour

of the replacement,

modification

or change

made

4451

monitoring system

that triggers the need

to perform recertification

4452

testing,

until

either: the hour of successful

completion of

all of

the

4453

required recertification

tests;

the hour in which a probationary

4454

calibration error

test (according

to subsection (b)(3)(B)

of this

4455

Section)

is performed and passed,

following all necessary

repairs,

4456

adjustments

or reprogramming

of the monitoring

system. The

first

4457

hour of quality-assured

data for

the recertified

monitoring system

4458

must

either be

the hour after

all recertification tests

have been

4459

completed

or, if conditional

data validation

is used, the first

4460

quality-assured

hour must

be determined in accordance

with

4461

subsections

(b)(3)(B)

through

(I)

of this Section.

Notwithstanding

4462

these

requirements,

if the replacement,

modification

or change

4463

requiring

recertification of the

CEMS

is such

that the historical

4464

data stream is

no longer representative

(e.g., where

the mercury

4465

concentration

and stack flow rate

change

significantly

after

4466

installation

of a wet

scrubber),

the owner or operator

must estimate

4467

the

mercury

emissions over

that time period

and notify the Agency

4468

within

15 days after the replacement,

modification

or change

4469

requiring

recertification

of the CEMS.

4470

4471

Once

the modification

or change to

the CEMS has been completed

4472

and all of the associated

repairs,

component replacements,

4473

adjustments, linearization

and reprogramming

the CEMS have

JCAR350225-08 1 8507r01

4474

been

completed, a

probationary calibration error test is required

4475

establish the beginning point

of the

recertification test period.

4476

this instance, the

first successful calibration error test of the

4477

monitoring system

following completion of all necessary repairs,

4478

component replacements,

adjustments,

linearization

and

4479

reprogramming

must be the probationary calibration error

test. The

4480

probationary

calibration

error test must be passed before any

of the

4481

required recertification

tests are commenced.

4482

4483

Beginning

with

the hour of commencement of a recertification

test

4484

period, emission

data

recorded

the mercury

CEMS

are

4485

considered

to be conditionally valid, contingent upon the results

4486

the

subsequent recertification tests.

4487

4488

L’)

Each required recertification test must be completed no later

than

4489

the following

number of unit operating hours

(or

unit operating

4490

days) after the probationary calibration error test that initiates

the

4491

test

period:

4492

4493

For a linearity check and/or cycle time test, 168

4494

consecutive unit operating hours, as defined in 40 CFR

4495

72.2,

incorporated by reference in Section 225.140, or,

for

4496

CEMS

installed on common stacks or bypass stacks, 168

4497

consecutive

stack

operating hours,

as defined in

CFR

4498

72.2;

4499

4500

For

RATA

(whether

normal-load or

multiple-load), 720

4501

consecutive unit operating hours, as defined in 40 CFR

4502

72.2, incorporated

reference in

Section

225.140,

or, for

4503

CEMS installed on common stacks or bypass stacks, 720

4504

consecutive

stack operating hours,

as defined in 40 CFR

4505

72.2;

and

4506

4507

jjjj

For a 7-day calibration error test, 21 consecutive unit

4508

operating

days,

as defined in 40 CFR 72.2,

incorporated

4509

reference in Section 225.140.

4510

4511

All recertification tests must be performed hands-off.

4512

adjustments

to the calibration of the mercury CEMS,

other than the

4513

routine calibration

adjustments

following daily calibration error

4514

tests

as described in Section

2.1.3

of Exhibit B to this Appendix,

4515

are permitted

during

the recertification

test period. Routine daily

4516

calibration error tests must be

performed

throughout the

j•

•CD

C)C)

•

0C)C)

C)c

—

0•0

—.

CD0

•CDC)

—

•

—

)

Cl)

C)CD”

—.—.

CDC)OOCD

—

0CD

—.

-CD

—

-i

—

•

CDC”

C,)C,DCD

CDCD-

—•O

-+.-

0•

—.

JCAR350225-08

1 8507r01

4560

(or stack)

operating hours. The

new recertification

test

4561

sequence must

not

be commenced

until

all necessary

4562

maintenance

activities, adjustments,

linearization

and

4563

reprogramming

of the CEMS

have been completed;

4564

4565

jj)

a linearity check,

RATA or cycle

time test is failed or

4566

aborted due to a problem

with the mercury

CEMS, all

4567

conditionally

valid

emission

data recorded

the

CEMS

4568

are invalidated, from

the hour of

commencement of the

4569

recertification

test period to the hour

in which the

test is

4570

failed or aborted,

except for the

case

in which a multiple-

4571

load

flow

RATA

passed

at one or

more load levels,

failed

4572

at a subsequent load

level, and the

problem that caused

the

4573

RATA

failure

is corrected without re-linearizing

the

4574

instrument. In that

case, data

invalidation

will be

4575

prospective,

from

the hour of failure

of the RATA until

the

4576

commencement of

the new recertification

test period.

Data

4577

from

the CEMS

remain invalid until

the hour in which

4578

new recertification

test period is

commenced, following

4579

corrective action,

and a probationary

calibration

error

test is

4580

passed, at

which time the conditionally

valid

status

4581

emission

data from the CEMS

begins again;

4582

4583

jjj

If a 7-day

calibration

error test is failed within

the

4584

recertification

test period,

previously-recorded

4585

conditionally

valid

emission data from the

mercury

CEMS

4586

are

not invalidated.

The conditionally

valid data status

4587

unaffected, unless the

calibration error on

the day

of the

4588

failed

7-day calibration

error test exceeds

twice the

4589

performance specification

in Section 3 of

Exhibit

A to

this

4590

Appendix,

as described

in subsection

(b)(3)(G)(iv)

this

4591

Section.

4592

4593

jy)

If a daily calibration

error test is failed during

4594

recertification

test period

(i.e.,

the results

of the test exceed

4595

twice the performance

specification in Section

3 of Exhibit

4596

to this

Appendix),

the CEMS is out-of-control

of the

4597

hour in which the calibration

error

test is failed. Emission

4598

data from the CEMS

will

invalidated

prospectively

from

4599

the hour of

the failed calibration

error test until

the hour of

4600

completion

of a subsequent

successful calibration

error

test

4601

following

corrective action,

at which time the

conditionally

4602

valid status

of data from

the

monitoring

system

resumes.

JCAR350225-08 1 8507r01

4603

Failure

to perform a required daily calibration error test

4604

during a recertification test

period

will also cause data

from

4605

the CEMS to be invalidated prospectively, from the hour in

4606

which the calibration

error test was due until the hour of

4607

completion of a subsequent

successful

calibration

error

test.

4608

Whenever a calibration error test is failed or missed during

4609

recertification

test period, no further recertification tests

4610

must be performed

until the required

subsequent

calibration

4611

error test has been

passed,

re-establishing the conditionally

4612

valid

status

of data from the monitoring

system.

If a

4613

calibration error test failure occurs while

linearity check

4614

or RATA is still in progress, the linearity check or RATA

4615

must be re-started.

4616

4617

Trial

gas

injections

and trial RATA runs are permissible

4618

during the recertification

test

period,

prior to commencing a

4619

linearity check or RATA, for the purpose of optimizing the

4620

performance

of the

CEMS.

The

results of such gas

4621

injections

and trial runs will not affect the status of

4622

previously-recorded conditionally valid data or result in

4623

termination

of the recertification test period, provided that

4624

they meet the following

specifications

and conditions: for

4625

gas injections, the stable, ending monitor response

is within

4626

5 percent or within 5 ppm of the tag value of the

4627

reference

gas; for RATA trial runs, the average reference

4628

method reading and the

average CEMS

reading

for the run

4629

differ by no more than

10%

of the average reference

4630

method value or ± 15 ppm, or + 1.5% H

20or ± 0.02

4631

lb/mmBtu from the average reference method value,

4632

applicable;

no adjustments to the calibration of the CEMS

4633

are made following the trial injections or runs, other than

4634

the adjustments permitted

under

Section 2.1.3

of Exhibit B

4635

to this Appendix and the CEMS is not repaired, re

4636

linearized or

repro-ammed

(e.g., changing flow monitor

4637

polynomial coefficients,

linearity

constants or K-factors)

4638

after the

trial injections

or runs.

4639

4640

If the results of any trial gas injections or RATA runs

are

4641

outside the limits in subsection

(b)(3)(G)(v)

of this Section

4642

or if

the

CEMS

is repaired,

re-linearized or reprogrammed

4643

after the trial injections or runs,

the

trial injections

or runs

4644

will be counted as a failed linearity check or RATA

4645

attempt.

If this occurs, follow the procedures pertaining

JCAR350225-081

8507r01

4646

failed

and

aborted

recertification

tests in

subsections

4647

(b)(3)(G)(i)

and

(ii)

of this

Section.

4648

4649

If any required

recertification

test

is not completed

within

its

4650

allotted time

period,

data validation

must be

done

follows.

For

4651

late linearity

test, RATA

cycle

time test

that

passed

the

4652

first

attempt,

data

from the

monitoring

system

will

invalidated

4653

from

the hour

expiration

of the

recertification

test

period until

4654

the hour

completion

of the

late test.

For a

late

7-day calibration

4655

error

test, whether

or not

it is passed

on the

first attempt,

data

from

4656

the

monitoring

system

will

also be invalidated

from

the hour

4657

expiration

of the

recertification

test

period

until the

hour of

4658

completion

of the

late test.

For a late

linearity

test, RATA

cycle

4659

time

test that is

failed

the first

attempt

or aborted

on the first

4660

attempt

due to

problem with

the monitor,

all conditionally

valid

4661

data

from the

monitoring

system

will be

considered

invalid back

4662

the hour

of the first

probationary

calibration

error test

that initiated

4663

the

recertification

test

period.

Data

from

the

monitoring

system

4664

will

remain

invalid

until the

hour of

successful

completion

the

4665

late

recertification

test and

any

additional

recertification

4666

diagnostic

tests

that are

required as

result

of changes

made

to the

4667

monitoring

system

to correct

problems

that caused

failure

of the

4668

late recertification

test.

4669

4670

If any required

recertification

test of a

monitoring

system

has

not

4671

been completed

the

end

of a

calendar quarter

and if

data

4672

contained

in the

quarterly

report

are

conditionally

valid

pending

4673

the

results

of tests

to be completed

in a

subsequent

quarter,

the

4674

owner

or operator

must indicate

this by

means

of a suitable

4675

conditionally

valid

data flag

the

electronic

quarterly

report,

and

4676

notification

within

the quarterly

report

pursuant

to Section

4677

225

.290(b)(1’)(E),

for

that quarter.

The owner

or operator

must

4678

resubmit

the report

for that quarter

if the

required

recertification

4679

test

subsequently

failed.

any

required

recertification

test is

not

4680

completed

the

end

of a particular

calendar

quarter but

4681

completed

no later

than

days

after

the

end

of that quarter

(i.e.,

4682

prior

to the

deadline

for submitting

the

quarterly

report

under 40

4683

CFR

75.64,

incorporated

reference

in Section

225.140),

the

test

4684

data

and results

may be submitted

with

the

earlier quarterly

report

4685

even

though

the

test dates

are from

the

next calendar

quarter.

4686

such instances,

the recertification

tests are passed

in accordance

4687

with the

provisions

of subsection

(b)(3)

this Section,

4688

conditionally

valid data

may be

reported as

quality-assured,

in lieu

JCAR350225-08 1 8507r01

4689

of reporting a conditional data

flag. In addition, if the owner or

4690

operator uses a conditionally

valid data flag in any of the four

4691

quarterly reports for a given

year, the owner or operator must

4692

indicate

the final status of the conditionally

valid

data

(i.e.,

4693

resolved

unresolved)

in the annual compliance certification

4694

report required under 40

CFR 72.90 for that year. The Agency may

4695

invalidate

any conditionally valid

data that

remains unresolved at

4696

the end

of a particular calendar year.

4697

4698

Recertification application. The designated

representative must apply for

4699

recertification of

each continuous mercury emission monitoring system.

4700

The

owner

or operator must submit the recertification

application in

4701

accordance with 40 CFR

75.60, incorporated by reference in Section

4702

225.140, and

each complete recertification application

must

include

the

4703

information specified in 40 CFR

75.63, incorporated by reference in

4704

Section 225.140.

4705

4706

)

Approval

or disapproval of request for recertification.

The

procedures

for

4707

provisional certification

in subsection (a)(3) of this Section apply to

4708

recertification applications. The Agency will

issue a notice of approval,

4709

disapproval

or incompleteness according to the procedures

in subsection

4710

(a)(4) of

this

Section. Data from the monitoring system remain invalid

4711

until all required recertification

tests

have

been

passed

or until a

4712

subsequent probationary calibration

error test is passed, beginning a

new

4713

recertification test period. The owner or operator

must repeat all

4714

recertification

tests or other requirements, as indicated in the Agency’s

4715

notice of disapproval, no

later than 30 unit operating days after the date

4716

issuance of the notice of disapproval. The designated representative

must

4717

submit a notification of the

recertification retest dates, as specified in 40

4718

CFR

75.61(a)(1)(ii),

incorporated

reference in Section 225.140,

and

4719

must submit a new recertification

application according to the procedures

4720

in subsection

(b)(4) of this Section.

4721

4722

Initial

Certification

and Recertification Procedures. Prior to the applicable

4723

deadline in 35 Ill. Adm. Code 225 .240(b), the

owner or operator must conduct

4724

initial

certification

tests and in accordance with 40 CFR

75.63,

incorporated

4725

reference in Section 225.140,

the designated representative must submit an

4726

application to demonstrate that the continuous

emission monitoring

system

and

4727

components of the system meet the specifications in Exhibit

A to this Appendix.

4728

The

owner

operator must compare reference method values

with output from

4729

the

automated

data

acquisition

and handling system that is part of the continuous

4730

mercury emission monitoring system

being tested. Except as otherwise specified

4731

in subsections

(b)(1),

(d) and (e) of this Section,

and in Sections 6.3.1 and 6.3.2

JCAR350225-08 1 8507r01

4732

Exhibit A to this Appendix, the owner

or operator must perform the following

4733

tests

for

initial

certification

or recertification of continuous emission

monitoring

4734

systems or components according

to the requirements of Exhibit B to this

4735

Appendix:

4736

4737

For each mercury concentration monitoring system:

4738

4739

A 7-day calibration error test;

4740

4741

)

A linearity check,

for

mercury monitors, perform this check with

4742

elemental mercury stmdards;

4743

4744

A relative accuracy test audit must be done on a ig!scm

basis;

4745

4746

A bias

test;

4747

4748

A cycle time

test;

4749

4750

For

mercury monitors a 3-level

system

integrity check,

using a

4751

NIST-traceable

source of oxidized mercury, as described in

4752

Section 6.2 of Exhibit

A to this Appendix. This test is not required

4753

for

a mercury monitor that does not

have a

converter.

4754

4755

For each

flow

monitor:

4756

4757

A 7-day calibration error

test;

4758

4759

Relative accuracy

test

audits, as follows:

4760

4761

single-load

(or

single-level)

RATA at the normal load

(or

4762

level),

as defined in Section

6.5.2.1(d)

of Exhibit

A to this

4763

Appendix,

for a flow

monitor

installed

on a peaking unit

4764

bypass stack, or for a flow monitor exempted from

4765

multiple-level RATA testing under

Section 6.5.2(e) of

4766

Exhibit

A to this Appendix;

4767

4768

For all other flow monitors, a RATA at each

of the three

4769

load levels

(or

operating

levels)

corresponding to the

three

4770

flue

gas velocities described in Section

6.5.2(a)

of Exhibit

4771

A to this

Appendix;

4772

4773

A bias test for the single-load

(or

single-level) flow RATA

4774

described

in subsection

(c)(2)(B)(i)

of this Section; and

JCAR350225-0818507r01

4775

4776

)

A bias test (or bias

tests) for the 3-level flow

RATA

described

4777

subsection (c)(2)(B)(ii)

of this Section, at the following load or

4778

operational

levels:

4779

4780

At each

load level designated as normal under Section

4781

6.5.2.1(d)

Exhibit

A to this Appendix, for units that

4782

produce electrical or thermal

output, or

4783

4784

)

At the operational level

identified as normal in Section

4785

6.5.2.1(d)

of Exhibit A to this Appendix, for units

that do

4786

not produce electrical or

thermal output.

4787

4788

)

For each diluent

gas monitor used only to monitor

heat input rate:

4789

4790

)

7-day calibration error test;

4791

4792

)

linearity

check;

4793

4794

A relative accuracy test audit, where,

for an

monitor used

4795

determine

CO7

concentration, the

2reference method must

4796

used

for the RATA; and

4797

4798

j.)

A cycle-time

test.

4799

4800

For each

continuous moisture monitoring system consisting

of wet- and

4801

dry-basis

analyzers:

4802

4803

)

7-day

calibration

error test of each

analyzer;

4804

4805

])

A cycle time

test of each

analyzer;

4806

4807

A linearity test

each

analyzer; and

4808

4809

A RATA directly

comparing the percent moisture measured

by the

4810

monitoring system to a reference

method.

4811

4812

For each continuous moisture

sensor: A RATA directly comparing

the

4813

percent moisture measured

the monitor

sensor to a reference method.

4814

4815

)

For

continuous

moisture monitoring

system

consisting

of a temperature

4816

sensor and a data

acquisition and handling

system

(DAHS)

software

4817

component programmed with

moisture

lookup

table: A demonstration

JCAR350225-0818507r01

4818

that the correct moisture

value for each hour is being

taken from the

4819

moisture lookup tables and applied

to the emission calculations. At a

4820

minimum,

the demonstration must

be made at

three

different

temperatures

4821

covering

the normal

range

of stack temperatures from low to

high.

4822

4823

For each sorbent trap monitoring

system, perform a RATA, on a jig!dscrn

4824

basis, and a bias test.

4825

4826

)

For the automated data acquisition

and handling system, tests designed

4827

verify the proper computation of hourly averages for

pollutant

4828

concentrations, flow rate, pollutant

emission rates and pollutant mass

4829

emissions.

4830

4831

)

The owner

or operator must provide

adequate

facilities for initial

4832

certification or recertification testing

that

include:

4833

4834

)

Sampling

ports

adequate for

test methods applicable to such

4835

facility,

such that:

4836

4837

Volumetric

flow rate, pollutant

concentration and pollutant

4838

emission rates can be accurately determined

by applicable

4839

test

methods and procedures; and

4840

4841

jj)

A stack or

duct free of cyclonic flow during performance

4842

tests is available, as demonstrated

by applicable test

4843

methods and procedures.

4844

4845

)

Basic facilities

(e.g., electricity)

for sampling and testing

4846

quipment.

4847

4848

ci)

Initial Certification and Recertification

and Quality Assurance Procedures for

4849

Optional Backup Continuous Emission Monitoring

Systems.

4850

4851

Redundant

backups. The owner or operator of an

optional

redundant

4852

backup CEMS must comply with all

the requirements for initial

4853

certification and recertification according to the procedures

specified in

4854

subsections

(a), (b)

and

4855

operate the redundant

backup CEMS during all periods of unit operation,

4856

except for periods of calibration, quality

assurance,

maintenance

or repair.

4857

The owner or operator must perform upon the redundant backup

CEMS all

4858

quality

assurance

and quality control procedures specified in Exhibit

B to

4859

this Appendix, except

that the daily assessments in Section 2.1 of Exhibit

4860

B to this Appendix are

optional for

days

on which the redundant backup

JCAR350225-08

1 8507r01

4861

CEMS is not

used to report emission data under this Part. For any

day

4862

which

a redundant backup CEMS is

used to report emission data, the

4863

system must

meet all of the applicable daily assessment criteria in

Exhibit

4864

B to this Appendix.

4865

4866

)

Non-redundant backups. The owner or operator

of an optional non-

4867

redundant

backup CEMS or like-kind replacement analyzer must

comply

4868

with all of the

following requirements for initial certification, quality

4869

assurance, recertification and data reporting:

4870

4871

Except as provided in subsection (d)(2)(E)

of this Section, for a

4872

regular

non-redundant backup CEMS

(i.e.,

a non-redundant

backup

4873

CEMS that has its own separate probe,

sample

interface and

4874

analyzer), or

a non-redundant backup flow monitor, all of the

tests

4875

in subsection

(c)

of this Section are required for initial

certification

4876

of the system, except

for the 7-day calibration error test.

4877

4878

For

like-kind

replacement non-redundant

backup

analyzer

(i.e.,

4879

non-redundant backup analyzer

that uses the same probe and

4880

sample interface as a primary monitoring system), no initial

4881

certification

of the analyzer is required.

4882

4883

Each non-redundant backup

CEMS or like-kind replacement

4884

analyzer must comply with the

daily and quarterly quality

4885

assurance and quality control requirements in Exhibit B

to this

4886

Appendix for each

day and quarter that the non-redundant backup

4887

CEMS or like-kind

replacement

analyzer

is used to report data, and

4888

must meet the additional linearity and calibration error test

4889

requirements specified in this

subsection. The owner or operator

4890

must ensure

that each non-redundant backup CEMS or like-kind

4891

replacement analyzer passes a linearity check

(for

mercury

4892

concentration and

diluent gas monitors) or a calibration error

test

4893

(for

flow

monitors)

prior to each use for recording

and reporting

4894

emissions.

When

non-redundant

backup CEMS or like-kind

4895

replacement analyzer is brought into service, prior

to conducting

4896

the linearity

test, a probationary calibration error test

(as

described

4897

in subsection (b)(3)(B) of

this

Section),

which will begin a period

4898

of conditionally valid data, may be performed

in order to allow the

4899

validation of data retrospectively as follows. Conditionally

valid

4900

data from the

CEMS or like-kind replacement analyzer are

4901

validated back

the

hour of completion of the probationary

4902

calibration error test if the following conditions

are met: if no

4903

adjustments

are made to the CEMS

like-kind replacement

JCAR350225-081 8507r01

4904

analyzer

other

than

the allowable

calibration

adjustments

specified

4905

in Section 2.1.3 of Exhibit

B to this

Appendix between

the

4906

probationary calibration

error

test

and the successful

completion

4907

the

linearity test;

and if the linearity

test

passed

within

168 unit

4908

(or stack)

operating hours of the

probationary calibration

error test.

4909

However, if the

linearity

test

is performed within

168

unit or

stack

4910

operating

hours but is either

failed or aborted

due to a problem

4911

with the

CEMS or like-kind

replacement

analyzer,

then all of

the

4912

conditionally

valid

data

are invalidated back

to the hour

the

4913

probationary

calibration error

test, and data

from the non-

4914

redundant

backup

CEMS

or from the primary

monitoring

system

4915

of which

the like-kind replacement

analyzer,

is a part remain

4916

invalid until

the hour

completion of a successful

linearity

test.

4917

Notwithstanding

this requirement,

the conditionally

valid

data

4918

status may

be re-established

after a failed or

aborted linearity

4919

check,

if corrective action

is taken and a calibration

error test

4920

subsequently

passed.

However,

in no case will

the use of

4921

conditional

data validation

extend for more

than 168 unit or stack

4922

operating

hours

beyond

the date and time of

the original

4923

probationary

calibration

error test when

the analyzer was brought

4924

into

service.

4925

4926

For

each

parameter

monitored (i.e.,QQ

Hg or

flow

rate) at

4927

each unit or

stack,

a regular non-redundant

backup CEMS

may not

4928

be used to

report

data

at that

affected unit

or common

stack for

4929

more than

720 hours in any one

calendar year

(in

accordance

with

4930

40 CFR

75.74(c), incorporated

by reference

in Section

225.140),

4931

unless the

CEMS

passes a RATA

that unit

or stack. For each

4932

parameter monitored

at each

unit or stack, the use

of a like-kind

4933

replacement

non-redundant

backup

analyzer

(or

analyzers) is

4934

restricted to 720

cumulative

hours per calendar year,

unless

the

4935

owner

operator redesignates

the like-kind replacement

analyzers

4936

as components

regular

non-redundant

backup

CEMS and

each

4937

redesignated

CEMS passes a RATA

at that unit

or stack.

4938

4939

For each

regular non-redundant

backup

CEMS,

no more than

eight

4940

successive

calendar quarters

must elapse following

the quarter

4941

which the

last

RATA

the CEMS was done

at a particular

unit

4942

stack,

without performing

a subsequent

RATA. Otherwise, the

4943

CEMS

may not be used

to report

data

from that unit or stack

until

4944

the

hour

of completion

of a passing RATA

at that

location.

4945

JCAR350225-0818507r01

4946

)

Each regular

non-redundant

backup

CEMS

must be

represented

4947

the monitoring

plan required

under

Section

1.10 of this

Appendix

4948

as a separate

monitoring

system,

with unique

system

and

4949

component

identification

numbers.

When

like-kind

replacement

4950

non-redundant

backup

analyzers

are

used,

the

owner

or operator

4951

must

represent

each

like-kind

replacement

analyzer

used during

4952

particular

calendar

quarter

in the monitoring

plan

required

under

4953

Section

1.10

of this Appendix

as a

component

of a primary

4954

monitoring

system.

The

owner

or operator

must

also assign

4955

unique

component

identification

number

each

like-kind

4956

replacement

analyzer,

beginning

with the

letters

“LK” (e.g.,

LK1,

4957

LK2,

etc.)

and

must specify

the manufacturer,

model

and

serial

4958

number of

the

like-kind replacement

analyzer.

This

information

4959

may

be added,

deleted

or updated

as necessary,

from

quarter

4960

quarter. The

owner

or operator

must

also report

data from

the like-

4961

kind

replacement

analyzer

using the

system

identification

number

4962

the

primary

monitoring

system and

the assied

component

4963

identification

number of

the like-kind

replacement

analyzer.

For

4964

the purposes

the electronic

quarterly

report required

under

4965

CFR

75.64,

incorporated

reference

in Section

225.140,

the

4966

owner or operator

may

manually

enter the

appropriate

component

4967

identification

numbers

of any

like-kind

replacement

analyzers

used

4968

for data

reporting

during the

quarter.

4969

4970

)

When

reporting

data from a

certified regular

non-redundant

backup

4971

CEMS,

use

method

of determination

code

(MODC)

of”02”.

4972

When

reporting

data from

like-kind

replacement

non-redundant

4973

backup

analyzer,

use a MODC

(see Table

under

Section

4974

1.11

of this

Appendix).

For

the

purposes

the electronic

quarterly

4975

report

required

under

CFR 75.64,

incorporated

by reference

4976

Section

225.140,

the owner

operator

may

manually

enter

the

4977

required

MODC

of” 17”

for a like-kind

replacement

analyzer.

4978

4979

ifi

For

non-redundant

backup

mercury

CEMS

and sorbent

trap

4980

monitoring

systems,

and for

like-kind

replacement

mercury

4981

analyzers,

the

following provisions

apply in

addition

to, or.

4982

some

cases,

lieu

of, the

general

requirements

subsections

4983

(d)(2)(A)

through

(H) of

this Section:

4984

4985

When

a certified

sorbent

trap

monitoring

system

is brought

4986

into

service

as a regular

non-redundant

backup monitoring

4987

system,

the system

must

be operated

according

to the

JCAR350225-081

8507r01

4988

procedures in Section

1.3 of

this

Appendix and Exhibit D

4989

to this Appendix;

4990

4991

When a regular non-redundant backup mercury

CEMS or a

4992

like-kind replacement mercury analyzer is brought into

4993

service,

a linearity check with elemental mercury standards,

4994

as described

in subsection

(c)(1)(B)

of this Section and

4995

Section 6.2 of Exhibit A to this Appendix, and a

single-

4996

point system integrity check, as described in Section 2.6

4997

Exhibit

B to

this Appendix,

must be performed.

4998

Alternatively, a 3-level system integrity check, as described

4999

in subsection (c)(1)(E)

this Section

and subsection

(g)

5000

Section 6.2 in Exhibit A to this Appendix, may be

5001

performed in lieu of these two tests.

5002

5003

liii

The weekly single-point

system

integrity checks described

5004

Section

2.6

of Exhibit B to this Appendix are required

5005

long as a non-redundant backup mercury CEMS

like-

5006

kind replacement mercury analyzer remains in service,

5007

unless

the

daily calibrations

of the mercury analyzer are

5008

done using a NIST-traceable source

other

approved

5009

source of oxidized mercury.

5010

5011

Reference method backups. A monitoring system that is operated as

5012

reference method backup

system pursuant to the reference method

5013

requirements

of Methods 2, 3A, 30A and 30B in appendix A of 40

CFR

5014

60, incorporated by reference in Section

225.140,

need

not perform

and

5015

pass the certification tests required

subsection (c)

this

Section

prior

5016

to its use pursuant to this subsection.

5017

5018

Certification/Recertification Procedures for Either Peaking Unit or By-pass

5019

Stack/Duct

Continuous Emission Monitoring Systems. The owner or operator

5020

either

a peaking

unit or

by-pass stack/duct continuous emission monitoring

5021

system must comply with all the

requirements

for certification or recertification

5022

according to the

procedures

specified in subsections

(a),

(b) and

(c)

of this

5023

Section,

except

as follows: the owner or operator need only perform

one Nine-run

5024

relative accuracy test audit for certification or recertification of a flow monitor

5025

installed on the by-pass stack/duct or on the stack/duct used only by affected

5026

peaking

units. The relative accuracy

test

audit

must be performed during normal

5027

operation of the peaking units or the by-pass stack/duct.

5028

5029

Certification/Recertification Procedures for Alternative Monitoring

Systems.

The

5030

designated representative representing

the owner or operator of each alternative

JCAR350225-081

8507r01

5031

monitoring

system

approved

by the Agency as equivalent

to or better

than a

5032

continuous emission

monitoring

system according

the

criteria in

subpart E of

5033

CFR 75, incorporated

reference

in Section 225.140,

must

apply for

5034

certification

to the Agency prior

to use of the

system under Subpart

B of

this

Part,

5035

and must apply

for recertification

to the Agency following

a replacement,

5036

modification,

or change according

to the procedures

subsection

5037

Section.

The owner or operator

of an alternative

monitoring system

must comply

5038

with the notification

and

application requirements

for certification

5039

recertification

according

to the procedures

specified in

subsections

(a)

and

(b)

5040

this

Section.

5041

5042

Section

1.5

Quality

Assurance

and Quality Control

Reiuirements

5043

5044

Continuous

Emission

Monitoring

Systems.

The owner or operator

of an affected

5045

unit must

operate, calibrate

and maintain

each continuous mercury

emission

5046

monitoring

system

used

to report mercury emission

data as

follows:

5047

5048

The

owner

or operator

must operate,

calibrate and maintain

each primary

5049

and redundant

backup continuous

emission monitoring

system according

5050

to the quality assurance

and quality

control procedures

in Exhibit

B to this

5051

Appendix.

5052

5053

)

The owner or

operator must

ensure that each

non-redundant

backup

5054

CEMS meets

the quality

assurance requirements

of Section

1.4(d) of

this

5055

Appendix

for each day

and quarter that

the system is used

to report data.

5056

5057

)

The

owner or

operator

must perform quality

assurance

upon

a reference

5058

method backup monitoring

system

according to the requirements

5059

Method

2 or

in appendix A of 40 CFR

60, incorporated

by reference

5060

Section 225.140 (supplemented,

necessary, by guidance

from

the

5061

Administrator

the Agency), or one of

the mercury reference

methods

5062

Section

1.6

of this Appendix,

as applicable,

instead of the

procedures

5063

specified

in Exhibit

B of this Appendix.

5064

5065

}

Calibration

Gases. The owner

or operator must

ensure that all calibration

gases

5066

used to

quality assure the operation

the

instrumentation required

this

5067

Appendix must

meet

the

definition in 40 CFR

72.2,

incorporated

reference

5068

Section

225.140.

5069

5070

Section

1.6

Reference

Test

Methods

5071

5072

The owner or operator

must use the

following methods,

which

are found

5073

appendix A-4 to

40 CFR

60,

incorporated by reference

Section

225.140,

JCAR350225-08

1 8507r01

5074

have

been

published

by ASTM, to conduct

the

following

tests: monitoring system

5075

tests

for certification or

recertification

of continuous mercury

emission

5076

monitoring systems;

the

emission tests required

under

Section

1.15(c)

and (d)

5077

this

Appendix;

and required quality assurance

and

quality control tests:

5078

5079

Methods

1 or 1A are

the

reference

methods

for selection of sampling

site

5080

and

sample

traverses.

5081

5082

Method

its allowable

alternatives,

as provided in appendix

A to 40

5083

CFR 60, incorporated

by reference

in Section 225.140,

except for Methods

5084

and 2E, are the

reference methods

for determination of volumetric

5085

flow.

5086

5087

)

Methods

3, 3A or 3B

are the reference methods

for the determination

5088

the

dry

molecular weight

07 and CO2

concentrations in the emissions.

5089

5090

Method

(either

the standard

procedure

described in Section

8.1 of the

5091

method or the moisture

approximation

procedure

described

in Section 8.2

5092

of the

method)

must

be used to correct

pollutant concentrations

from a dry

5093

basis to a wet basis (or

from

a wet

basis to a dry basis) and

must be used

5094

when relative accuracy

test

audits of

continuous moisture

monitoring

5095

systems are

conducted. For the purpose

determining

the stack gas

5096

molecular weight,

however,

the

alternative wet bulb-dry

bulb technique

5097

for approximating

the

stack

gas moisture content

described

in Section

2.2

5098

of Method

4 may be used in lieu

of the procedures

in Sections 8.1

and

8.2

5099

of the

method.

5100

5101

ASTM

D6784-02, Standard

Test

Method

for Elemental, Oxidized,

5102

Particle-Bound

and

Total

Mercury in Flue

Gas Generated from

Coal-Fired

5103

Stationary

Sources

(Ontario

Hydro

Method)

(incorporated

reference

5104

under Section

225.140)

is the reference method

for determining mercury

5105

concentration.

5106

5107

Alternatively,

Method

29 in appendix A-8

CFR

60,

5108

incorporated

reference

in Section

225.140, may be used,

with

5109

these caveats: The

procedures

for

preparation of mercury

standards

5110

and

sample

analysis

in Sections 13.4.1.1

through 13.4.1.3

ASTM

5111

D6784-02 (incorporated

by reference

under Section 225.140)

must

5112

followed instead

the

procedures

in Sections

7.5.33 and 11.1.3

5113

of Method

29 in appendix

A-8 to

CFR 60,

and the

OAJOC

5114

procedures

in Section 13.4.2

of ASTM D6784-02

(incorporated

5115

reference

under

Section

225.140)

must be performed

instead

of the

5116

procedures

Section

9.2.3 of Method 29

in appendix A-8 to

•

,•

••

‘

•

••,

-‘

•

••

•

••

——

—

——

————

—

Cfl

-<H

—

CDD°

z•_

-“

-t

()

CDCDbNQCID

:°-

CCCD

_C)p-+

CDC)P-CD

pQ00

—.

atJ

CDCDCD

T1pC)

—

‘•J

CDC2

CD1JJC

O”

—.

L’JC)

C)CD-”-CD

C/)

L’J

•

CdD

—

-t

CDO

CC/)

(_)

-t

•

pC-

QCD

CD”OCD

CDC

CCDCD

•

CC)

C’)

•

EC4CD

CC)JODCD

—

ci)CNCDOPC

Cf)

(

—

p()CD

HOCCD

C’)OCD

_•P

-i

CI)

‘

JCAR350225-081

8507r01

5160

emission

testing

required

under

Section

1.15(c)

and

(d)

this

5161

Appendix,

locate

the reference

method

test points

according

5162

Section 8.1

Method 30A,

and

if mercury

stratification

testing

5163

part of the

test

protocol,

the

procedures

in Sections

8.1.3

5164

through

8.1.3.5

of Method

30A.

5165

5166

j.)

The owner

or operator

may

use

any

of the

following

methods,

which

are

found

5167

appendix

CFR

60,

incorporated

reference

in Section

225.140,

or have

5168

been

published

ASTM,

as a

reference method

backup

monitoring

system

5169

provide

quality-assured

monitor

data:

5170

5171

Method 3A

for

determining

CO2concentration;

5172

5173

)

Method

or its

allowable

alternatives,

provided

in appendix

A to 40

5174

CFR

60, incorporated

reference

in Section

225.140,

except

for

Methods

5175

and

2E,

for

determining

volumetric

flow. The

sample points

for

5176

reference

methods

must

be located

according

to the

provisions

of Section

5177

6.5.4

of Exhibit

A to this

Appendix.

5178

5179

)

ASTM D6784-02,

Standard

Test

Method for

Elemental,

Oxidized,

5180

Particle-Bound

and

Total

Mercury

in Flue

Gas

Generated

from Coal-Fired

5181

Stationary

Sources

(Ontario

Hydro

Method)

(incorporated

by reference

5182

under Section

225.140)

for determining

mercury

concentration;

5183

5184

Method

29 in appendix

A-8

CFR

60,

incorporated

reference

5185

Section

225.140,

for

determining

mercury

concentration;

5186

5187

)

Method

30A

for

determining

mercury

concentration;

and

5188

5189

)

Method

30B

for

determining

mercury

concentration.

5190

5191

Instrumental

EPA Reference

Method

3A in

appendices

A-2

and A-4

of 40

CFR

5192

60,

incorporated

reference

in Section

225.140,

must

conducted

using

5193

calibration

gases as defined

in Section

5 of Exhibit

this

Appendix.

5194

Otherwise,

performance

tests must

be conducted

and data

reduced

in accordance

5195

with the test

methods

and

procedures

this Part

unless

the

Agency:

5196

5197

Specifies

or approves,

specific cases,

the

use

of a

reference

method

with

5198

minor

changes

methodology;

5199

5200

)

Approves the

use

of an

equivalent

method;

5201

JCAR350225-08

1 8507r01

5202

Approves shorter sampling

times and smaller

sample

volumes

when

5203

necessitated

by process variables

other factors.

5204

5205

Section

1.7

Out-of-Control Periods and System

Bias Testing

5206

5207

If an out-of-control

period occurs to a monitor or continuous

emission

monitoring

5208

system,

the owner

or operator must take corrective action and repeat

the tests

5209

applicable

to the out-of-control parameter

as described in Exhibit B to this

5210

Appendix.

5211

5212

For daily calibration error tests,

an out-of-control period occurs when the

5213

calibration error

of a pollutant concentration monitor exceeds the

5214

applicable specification in Section 2.1.4

Exhibit

B to this Appendix.

5215

5216

)

For quarterly

linearity checks, an out-of-control period

occurs when the

5217

error in linearity at any

of three gas concentrations

(low,

mid-range

and

5218

high) exceeds

the applicable specification in Exhibit A

this

Appendix.

5219

5220

For relative accuracy test audits,

an out-of-control period occurs when

the

5221

relative

accuracy

exceeds the applicable specification in Exhibit

A to this

5222

Appendix.

5223

5224

)

When a monitor or continuous emission

monitoring system is out-of-control,

any

5225

data

recorded by the monitor or monitoring

system are not quality-assured and

5226

must not be used in calculating monitor data availabilities pursuant

to Section

1.8

5227

this Appendix.

5228

5229

When

a monitor

or continuous emission monitoring

system

is out-of-control,

the

5230

owner or operator must take one of the following

actions until

the monitor or

5231

monitoring

system has successfully met the relevant criteria in Exhibits

A and B

5232

of this Appendix as demonstrated

subsequent tests:

5233

5234

Use a certified backup monitoring

system

or a reference

method

for

5235

measuring and recording

emissions from the affected

units:

5236

5237

)

Adjust

the gas discharge paths from the affected units with emissions

5238

normally observed

the

out-of-control monitor or monitoring system

5239

that all exhaust gases are monitored

a certified

monitor or monitoring

5240

system meeting the requirements of Exhibits A and B to this

Appendix.

5241

5242

When the bias test indicates that

a flow monitor, a diluent monitoring system,

5243

mercury concentration monitoring system

or a

sorbent

trap monitoring

system

5244

biased

low

(i.e.,

the arithmetic mean of the differences between

the reference

JCAR350225-081

8507r01

5245

method

value

and the monitor

or monitoring

system

measurements

relative

5246

accuracy

test audit

exceed

the

bias statistic

in Section

Exhibit

A to

this

5247

Appendix),

the

owner or

operator must

adjust

the

monitor

or continuous

emission

5248

monitoring

system to eliminate

the

cause

of bias

such that

passes the

bias

test.

5249

5250

Section

1.8

Determination

of Monitor

Data

Availability

5251

5252

Following

initial certification

the

required

flow

monitoring

systems,

5253

Hg concentration

moisture

monitoring

systems

particular

unit or stack

5254

location

(i.e.,

the date

and

time

at which

quality-assured

data

begins

to be

5255

recorded

CEMSs

at that

location),

the owner

operator

must

begin

5256

calculating

the percent

monitor

data availability

described

subsection

(a)(1)

5257

of this

Section,

means

the

automated

data acquisition

and handling

system,

5258

and

the

percent monitor

data

availability

for each

monitored

parameter.

5259

5260

Following

initial

certification,

the

owner or

operator

must use

Equation

5261

calculate, hourly,

percent

monitor

data availability

for

each calendar

5262

quarter.

5263

5264

Total unit operating

hours

for which

quality-assured

data

Percent

was

5265

recorded

for the calendar

quarter

monitor

data = X

100 (Eq.8)

5266

Availability

Total

unit

operating

hours

for

the

calendar

quarter

5267

5268

When

calculating

percent monitor

data

availability

using Equation

the

5269

owner

or operator

must

include

all unit

operating

hours,

and

all monitor

5270

operating

hours

for which

quality-assured

data

were

recorded

by a

5271

certified primary

monitor;

a certified

redundant

or non-redundant

backup

5272

monitor

or a reference

method

for that

unit.

5273

5274

Section

1.9

Determination

Sorbent Trap

Monitorin2

Systems

Data

Availability

5275

5276

If a

primary

sorbent

trap

monitoring

system

has not been

certified

the

5277

applicable

compliance

date

specified

under

Subpart

B of

this

Part,

and if quality-

5278

assured mercury

concentration

data

from a

certified

backup

mercury

monitoring

5279

system,

reference

method

approved

alternative

monitoring

system

are

5280

unavailable,

the owner

operator

must perform

quarterly

emissions

testing

5281

accordance

with Section

225.239

until such time

the primary

sorbent

trap

5282

monitoring

system

has

been certified.

5283

5284

For

certified sorbent

trap

system,

a missing

data

period

will occur

the

5285

following

circumstances,

unless

quality-assured

mercury

concentration

data

from

5286

certified backup

mercury

CEMS,

sorbent

trap system,

reference

method

5287

approved

alternative

monitoring

system

are available:

JCAR350225-08

1 8507r01

5288

5289

A gas sample

not

extracted

from

the

stack

during

unit

operation

(e.g.,

5290

during

monitoring

system malfunction

when the

system

undergoes

5291

maintenance);

5292

5293

The results

of the

mercury

analysis

for

the

paired

sorbent

traps

are

missing

5294

or invalid

(as

detennined

using

the

quality

assurance

procedures

in Exhibit

5295

to this Appendix).

The

missing

data

period

begins

with the

hour in

5296

which

the paired

sorbent

traps

for which

the

mercury

analysis

is missing

5297

invalid were

put into

service. The

missing data

period

ends at the

first

5298

hour

in which

valid

mercury

concentration

data are

obtained

with

another

5299

pair

of sorbent

traps (i.e.,

the hour

at which this

pair

of traps

was placed

5300

service),

with

certified

backup mercury

CEMS,

reference

method

5301

approved

alternative

monitoring

system.

5302

5303

Following

initial certification

the

sorbent

trap monitoring

system,

begin

5304

reporting

the

percent monitor

data

availability

in accordance

with

Section 1.8

5305

this Appendix.

5306

5307

Section

1.10

Monitoring

Plan

5308

5309

The

owner

or operator

of an

affected

unit

must prepare

and

maintain

mercury

5310

emissions

monitoring

plan.

5311

5312

12)

Whenever

the

owner or operator

makes

a replacement,

modification

or change

5313

the

certified

CEMS, including

change

in the

automated

data

acquisition

and

5314

handling

system

the flue

gas handling

system, that

affects

information

5315

reported

in the

monitoring

plan

(e.g.,

a change

to a serial

number

for

a component

5316

of a

monitoring

system),

then

the owner

operator

must

update the

monitoring

5317

plan, by

the

applicable

deadline specified

40 CFR 75.62,

incorporated

5318

reference

in Section

225.140,

elsewhere

in this

Appendix.

5319

5320

Contents

of Monitoring

Plan

for

Specific

Situations.

The

following additional

5321

information

must

be included

the

monitoring

plan for

the

specific

situations

5322

described.

For

each monitoring

system

recertification,

maintenance

or other

5323

event,

the

designated

representative

must include

the following

additional

5324

information

electronic

format

in the

monitoring

plan:

5325

5326

Component/system

identification

code;

5327

5328

)

Event

code

for

required

test;

5329

5330

)

Event begin

date

and

hour;

JCAR350225-08 1 8507r01

5331

5332

Conditionally

valid data period begin date and hour

(if

applicable)

5333

5334

)

Date

and hour that last test is successfully completed; and

5335

5336

Indicator of whether conditionally valid

data

were

reported at the end of

5337

the quarter.

5338

5339

Contents of the Mercury Monitoring Plan. The requirements

of subsection

(d)

5340

this

Section must be met on and after July 1, 2009. Each monitoring plan

must

5341

contain the information

in subsection

(d)(1)

of this Section in electronic format

5342

and the information in subsection

(d)(2)

of this Section in hardcopy format.

5343

Electronic storage of all monitoring plan information,

including

the hardcopy

5344

portions,

is permissible

provided

that a paper copy of the information can be

5345

furnished upon

request

for audit purposes.

5346

5347

Electronic

5348

5349

The facility

ORISPL

number

developed by the Department of

5350

Energy and used in the National Allowance Data Base (or

5351

equivalent

facility

ID number assigned

USEPA, if the facility

5352

does

not have an ORISPL

number).

Also provide the following

5353

information

for each

unit

and

(as

applicable) for each common

5354

stack and/or

pipe,

and each multiple

stack and/or pipe involved in

5355

the monitoring plan:

5356

5357

A representation of the exhaust

configuration

for the units

5358

the monitoring plan. Provide the ID number of each

unit

5359

and assign

unique ID number

to each common stack,

5360

common pipe, multiple stack and/or

multiple

pipe

5361

associated with the units represented

in the monitoring

5362

plan. For common and multiple stacks and/or pipes,

5363

provide the activation date and

deactivation date

(if

5364

applicable) of each stack andlor pipe;

5365

5366

ii)

Identification of the monitoring

system

locations (e.g.,

5367

the unit-level,

on the common stack, at each

multiple

stack,

5368

etc.).

Provide an indicator

(flag) if the monitoring location

5369

is at a bypass stack or in the ductwork (breeching);

5370

5371

jjj

The

stack exit height

(ft)

above ground level and ground

5372

level elevation

above sea level, and the inside cross

5373

sectional area

(ft

at the flue

exit and at the flow

JCAR350225-08

1 8507r01

5374

monitoring

location

(for

units with

flow monitors

only).

5375

Also use

appropriate

codes

indicate

the

materials

5376

construction

and the shapes

the

stack

or duct

cross-

5377

sections at

the flue exit

and

(if

applicable)

the

flow

5378

monitor

location;

5379

5380

The

types

of fuels fired

each

unit. Indicate

the start

and

5381

(if

applicable)

end

date of combustion

for

each type

of fuel,

5382

and

whether

the

fuel is the

primary,

secondary,

emergency

5383

startup

fuel;

5384

5385

The

types

of emission

controls

that are

used to reduce

5386

mercury

emissions

from each

unit.

Also provide

the

5387

installation

date, optimization

date

and retirement

date

(if

5388

applicable)

of the emission

controls,

and indicate

whether

5389

the controls

are an

original

installation;

and

5390

5391

yjj

Maximum

hourly

heat input

capacity

each unit.

5392

5393

)

For

each monitored

parameter

(i.e.,

mercury concentration,

diluent

5394

concentration

or flow)

at each monitoring

location,

specify

the

5395

monitoring

methodology

for the

parameter.

If the

unmonitored

5396

bypass stack

approach

is used

for a

particular

parameter,

indicate

5397

this by

means of

an appropriate

code.

Provide

the activation

5398

date/hour,

and

deactivation

date/hour

(if

applicable)

for each

5399

monitoring

methodology.

5400

5401

)

For each

required

continuous

emission

monitoring

system and

each

5402

sorbent

trap

monitoring

system

(as

defined

in Section

225.130),

5403

identify

and describe

the major

monitoring

components

in the

5404

monitoring

system

(e.g.,

gas analyzer,

flow

monitor,

moisture

5405

sensor,

DAHS software,

etc.).

Other

important

components

the

5406

system

(e.g.,

sample

probe,

PLC,

data

logger,

etc.)

may

also

5407

represented

in the

monitoring

plan,

necessary.

Provide

the

5408

following

specific

information

about

each

component

and

5409

monitoring

system:

5410

5411

For

each

required monitoring

system,

assign

a unique,

5412

character

alphanumeric

identification

code

to the system;

5413

indicate

the parameter

monitored

by the

system;

designate

5414

the

system

a primary,

redundant

backup,

non-redundant

5415

backup,

data

backup or

reference

method

backup

system,

5416

provided

in Section

1.2(d)

of this

Appendix:

and

indicate

JCAR350225-08 1 8507r01

5417

the system activation

date/hour and deactivation date/hour

5418

(as applicable).

5419

5420

For

each component

of each

monitoring

system represented

5421

in the

monitoring plan, assign a unique,

3-character

5422

alphanumeric

identification code to the component;

5423

indicate the manufacturer,

model and serial number;

5424

designate the component type;

for gas analyzers, indicate

5425

the

moisture basis of measurement; indicate the

method of

5426

sample acquisition

or operation, (e.g., extractive

pollutant

5427

concentration

monitor or thermal flow monitor);

and

5428

indicate the component

activation

date/hour and

5429

deactivation

date/hour

(as applicable).

5430

5431

)

Explicit formulas,

using the component and

system

identification

5432

codes

for the primary monitoring system,

and containing all

5433

constants and factors

required to

derive

the

required emission

rates,

5434

heat input rates, etc. from the hourly

data recorded by the

5435

monitoring

systems. Formulas using the system and component

5436

codes for backup monitoring

systems are required only if different

5437

formulas for the same parameter

are used for the primary and

5438

backup monitoring systems (e.g., if the

primary system measures

5439

pollutant

concentration

on a different moisture

basis

from

the

5440

backup

system). Provide the equation number or other

appropriate

5441

code for each emissions

formula

(e.g., use code F-i if Equation

F-i

5442

Exhibit

to this Appendix is used

to calculate

mass

5443

emissions).

Also

identify each emissions formula with

a unique

5444

three character alphanumeric

code. The formula effective start

5445

date/hour

and

inactivation

date/hour

(as

applicable)

must

5446

included for each formula.

5447

5448

For

each parameter monitored with CEMS,

provide the following

5449

information:

5450

5451

Measurement

scale;

5452

5453

Maximum potential value

(and

method

calculation);

5454

5455

jjj

Maximum expected

value

(if

applicable) and method

5456

calculation;

5457

5458

Span values and full-scale measurement ranges;

5459

JCAR350225-081 8507r01

5460

Daily calibration

units

of measure:

5461

5462

Effective

date/hour, and

(if

applicable) inactivation

5463

date/hour

of each

span

value:

5464

5465

yj)

The default high range

value

(if applicable)

and the

5466

maximum

allowable

low-range value

for this

option.

5467

5468

)

If the monitoring system

excepted methodology

provides

for

the

5469

use of

a constant, assumed

or default value

for a parameter

under

5470

specific

circumstances,

then include the following

information

for

5471

each

such value for

each

parameter:

5472

5473

Identification

of the

parameter:

5474

5475

Default, maximum,

minimum,

constant value, and

units

5476

measure for

the

value:

5477

5478

iii)

Purpose of the

value:

5479

5480

jy)

Indicator of

use, i.e., during

controlled hours,

uncontrolled

5481

hours or all

operating

hours:

5482

5483

Type

fuel:

5484

5485

Source

of the

value:

5486

5487

yjj)

Value

effective

date and

hour:

5488

5489

yjji

Date

and hour

value is no longer effective

(if

applicable):

5490

and

5491

5492

)

Unless otherwise

specified

in Section 6.5.2.1 of

Exhibit

A to

this

5493

Appendix,

for each unit

or common stack on

which hardware

5494

CEMS are installed:

5495

5496

Maximum hourly gross

load

(in

MW, rounded to the

5497

nearest

MW, or

steam

load in

1000 lb/hr

(i.e., klb/hr),

5498

rounded

the nearest klb/hr, or

thermal

output

5499

mmBtu/hr, rounded

to the nearest

mmBtulhr),

for

units

that

5500

produce electrical

or thermal

output:

5501

5502

II)

The

upper and lower boundaries

the

range of operation

JCAR350225-0818507r01

5503

(as defined

Section 6.5.2.1

Exhibit

A to this

5504

Appendix),

expressed

in megawatts,

thousands

lb/hr

5505

steam,

mrnBtu/hr

of thermal

output

ft/sec

(as

5506

applicable);

5507

5508

jjfl

Except

for

peaking units,

identify

the most frequently

and

5509

second most

frequently

used load

(or

operating)

levels

(i.e.,

5510

low,

mid

high)

in accordance

with

Section

6.5.2.1

5511

Exhibit

to this Appendix,

expressed

in megawatts,

5512

thousands

of lb/hr

of steam,

mmBtu/hr

of thermal

output

5513

fl/sec

(as

applicable);

5514

5515

indicator

of whether

the

second

most

frequently

used

5516

load

(or

operating)

level

designated

as normal

Section

5517

6.5.2.1

ExhibitAto

this Appendix;

5518

5519

The date

of the data

analysis used

to determine

the normal

5520

load

(or

operating)

levels and

the

two most

frequently-used

5521

load

(or

operating)

levels

(as applicable);

and

5522

5523

Activation

and

deactivation

dates

and hours,

when

the

5524

maximum

hourly

gross load,

boundaries

of the range

5525

operation,

normal

load (or

operating)

levels or two

most

5526

frequently-used

load (or

operating)

levels change

and

are

5527

updated.

5528

5529

For

each unit for

which

CEMS

are

not

installed,

the

maximum

5530

hourly

gross load

(in

MW, rounded

the

nearest

MW, or steam

5531

load

in klb/hr,

rounded

to the

nearest

klb/hr

or steam

load in

5532

mmBtu/hr,

rounded

to the nearest

mmBtu/hr);

5533

5534

For each

unit

with

a flow monitor

installed

on a rectangular

stack

5535

duct,

if a

wall effects

adjustment

factor

(WAY) is

determined

5536

and applied

to the

hourly

flow

rate data:

5537

5538

Stack or duct

width

at the test

location,

ft;

5539

5540

jj)

Stack

duct

depth

at the test location,

ft;

5541

5542

liii

Wall

effects adjustment

factor

(WAF).

the

nearest

5543

0.0001;

5544

5545

Method

determining

the

WAY;

JCAR350225-081

8507r01

5546

5547

WAF effective date

and hour;

5548

5549

yj)

WAF no longer

effective

date and

hour

(if

applicable):

5550

5551

yjj)

WAF determination

date:

5552

5553

yjji

Number

WAF

test runs;

5554

5555

Number

of Method 1 traverse

points in the

WAF test;

5556

5557

)

Number

of test ports in

the WAF

test;

and

5558

5559

Number

of Method 1 traverse

points in the reference

flow

5560

RATA.

5561

5562

)

Hardcopy

5563

5564

Information,

including

(as

applicable):

Identification

of the test

5565

strategy; protocol

for the relative

accuracy test

audit; other relevant

5566

test information;

calibration

gas levels

(percent

span)

for the

5567

calibration

error test

and

linearity check and

span; and

5568

apportionment

strategies under

Sections

1.2

and 1.3 of this

5569

Appendix.

5570

5571

)

Description

of site locations

for each

monitoring component

in the

5572

continuous emission

monitoring

systems, including schematic

5573

diagrams

and engineering

drawings

specified in 40

CFR

5574

75.53(e)(2)(iv)

and

(v),

incorporated

by reference in

Section

5575

225.140

and any

other documentation

that demonstrates

each

5576

monitor location meets

the appropriate

siting

criteria.

5577

5578

data flow diagram

denoting the complete

information

handling

5579

path

from output signals

of CEMS

components to final reports.

5580

5581

For

units monitored

by a continuous

emission monitoring

system,

5582

schematic diagram

identifying

entire gas handling system

from

5583

boiler

to stack

for all affected units,

using

identification

numbers

5584

for units, monitoring

systems and

components

and stacks

5585

corresponding

to the

identification

numbers provided

5586

subsections

(d)(1)(A) and

The schematic

5587

diagram

must depict stack

height

and the

height of any monitor

5588

locations.

Comprehensive

and/or

separate schematic

diagrams

JCAR350225-08

1 8507r01

5589

must be used to

describe groups of units using a

common stack.

5590

5591

)

For units monitored

by a continuous emission monitoring

system,

5592

stack and duct engineering

diagrams showing the dimensions

and

5593

location

of fans, turning vanes, air

preheaters, monitor

5594

components,

probes, reference method

sampling ports and other

5595

equipment

that affects the monitoring system location,

5596

performance or quality

control checks.

5597

5598

Section 1.11 General Recordkeepin2 Provisions

5599

5600

The

owner or operator must meet all of

the applicable recordkeeping

requirements

of Section

5601

225.290 and of this Section.

5602

5603

)

Recordkeeping Requirements

for Affected Sources. The owner

or operator of any

5604

affected source

subject

to the requirements

of this Appendix must maintain

for

5605

each

affected unit

file

of all measurements, data, reports and

other information

5606

required by Subpart B of this Part

at the source in a form suitable for inspection

5607

for at least 3 years from the date of each record. The

file must contain the

5608

following information:

5609

5610

The data and information

required

in subsections (b) through

(h)

of this

5611

Section, beginning with the earlier of the

date of provisional certification

5612

or July 1,

2009;

5613

5614

The supporting data

and information used to calculate values required

5615

subsections

(b)

through

(g)

of this Section, excluding

the subhourly data

5616

points

used to compute

hourly averages under Section

1.2(c)

this

5617

Appendix, beginning with the earlier of the

date of provisional

5618

certification or July

1, 2009;

5619

5620

The data and information

required in Section 1.12 of this Appendix

for

5621

specific situations,

beginning with the earlier of the

date of provisional

5622

certification or July 1, 2009;

5623

5624

The certification test

data and information required in Section 1.13

of this

5625

Appendix for tests required under Section 1.4

of this Appendix, beginning

5626

with

the

date of

the first certification test performed,

the quality assurance

5627

and

quality

control

data

and information required in Section

1.13 of this

5628

Appendix for tests,

and the quality assurance/quality control plan

required

5629

under Section 1.5 of this

Appendix

and

Exhibit B to this Appendix,

5630

beginning

with

the date of provisional

certification;

5631

JCAR350225-08 1 8507r01

5632

The current

monitoring plan as

specified in Section 1.10 of this Appendix,

5633

beginning with

the

initial

submission required by

CFR

75.62,

5634

incorporated

by reference in

Section

225.140:

and

5635

5636

)

The quality control plan

as described in Section 1

Exhibit

B to this

5637

Appendix, beginning with

the date of provisional certification.

5638

5639

)

Operating Parameter

Record

Provisions. The owner or operator

must record for

5640

each hour the following information

on unit operating time, heat input rate

and

5641

load, separately

for each affected unit and also

for

each

group of units utilizing

5642

common stack and a common monitoring

system:

5643

5644

Date andhour;

5645

5646

Unit operating time

(rounded

up to the nearest fraction of an hour

(in

5647

equal

increments

that

can range from one hundredth to one

quarter of an

5648

hour, at the option of the owner or

operator)):

5649

5650

Hourly gross unit load (rounded

to nearest

MWge)

5651

5652

Steam load

1000

lbs/hr at stated temperatures

and pressures, rounded

5653

the nearest 1000

lbs/hr.

5654

5655

Operating load range corresponding

to hourly gross load of 1 to

10, except

5656

for

units using a common stack, which

may use up to 20 load ranges

for

5657

stack or fuel flow,

as specified in the monitoring plan:

5658

5659

)

Hourly heat input

rate

(mmBtulhr,

rounded

to the nearest

tenth):

5660

5661

Identification

code for formula used for heat

input as provided in Section

5662

1.10 of this Appendix: and

5663

5664

For Mercury CEMS units only, F-factor

for heat input calculation and

5665

indication of whether

the diluent cap was used for heat input

calculations

5666

for

the hour.

5667

5668

Diluent Record Provisions. The

owner or operator of a unit using

a flow monitor

5669

and an

diluent monitor to determine heat

input, in accordance with Equation

5670

17 or

F-18

Exhibit

C to this Appendix,

or a unit that accounts for heat input

5671

using a flow monitor and

a CO

2diluent monitor

(which

is used only for heat input

5672

determination and is not used

as a CO

2pollutant concentration monitor)

must

5673

keep the following records for the

CO2

diluent monitor:

5674

JCAR350225-081 8507r01

5675

Component-system identification

code as provided in Section 1.10

of this

5676

Appendix;

5677

5678

Date and hour;

5679

5680

)

Hourly

average diluent gas

(Q2

concentration

(in

percent, rounded

5681

to the nearest tenth);

5682

5683

4).

Percent monitor data availability for the diluent monitor

(recorded

to the

5684

nearest tenth

of a percent) calculated pursuant to Section 1.8 of this

5685

Appendix;

and

5686

5687

Method of determination code for diluent gas

(02

concentration

5688

data using Codes 1-55 in Table 4a

of this Section.

5689

5690

Missing Data Records. The owner

operator

must record the causes of any

5691

missing data

periods

and the actions taken by the owner or operator to correct

5692

such causes.

5693

5694

Mercury Emission

Record

Provisions

(CEMS’).

The owner or operator must

5695

record for each hour the

information required by this subsection for each affected

5696

unit using mercury CEMS in combination

with

flow rate, and (in certain cases)

5697

moisture, and diluent gas monitors, to determine mercury

concentration and (if

5698

applicable)

unit

heat input under Subpart B of this Part.

5699

5700

For mercury concentration

during unit operation, as measured and

5701

reported from each certified primary monitor, certified

back-up monitor or

5702

other approved

method of emissions determination:

5703

5704

Component-system identification code as provided in Section

1.10

5705

of this Appendix;

5706

5707

Date and

hour;

5708

5709

Hourly mercury concentration

(jig/scm,

rounded to the

nearest

5710

tenth).

For

a particular pair of sorbent traps, this will be the flow-

5711

proportional average concentration for

the data collection period;

5712

5713

j).

Method

of determination for hourly mercury concentration

using

5714

Codes

1-55 in Table

of this Section; and

5715

5716

1).

The percent monitor data availability

(to

the nearest tenth of a

5717

percent) calculated pursuant to Section 1.8 of this Appendix.

JCAR350225-081

8507r01

5718

5719

For flue

gas

moisture

content during

unit

operation

(if

required),

5720

measured

and reported

from

each

certified

primary

monitor,

certified

5721

back-up

monitor

or other

approved method

emissions

determination

5722

(except

where

a default

moisture

value

approved

under 40

CFR 75.66,

5723

incorporated

reference

in Section

225.140):

5724

5725

)

Component-system

identification

code

provided

in Section

1.10

5726

this Appendix;

5727

5728

Date

and hour;

5729

5730

Hourly

average

moisture content

of flue

gas (percent,

rounded

5731

the

nearest

tenth).

the continuous

moisture

monitoring

system

5732

consists

wet-and

dry-basis

oxygen analyzers,

also

record

both

5733

the

wet- and

dry-basis

oxygen

hourly

averages

(in

percent

5734

rounded

to the

nearest

tenth);

5735

5736

Percent

monitor

data availability

(recorded

to the

nearest tenth

of a

5737

percent)

for the

moisture

monitoring

system

calculated

pursuant

5738

Section

1.8

of this

Appendix;

and

5739

5740

)

Method

determination

for hourly

average

moisture percentage

5741

using

Codes 1-55

Table 4a of

this Section.

5742

5743

For

diluent gas

(Q2

C0)

concentration

during

unit

operation

(if

5744

required),

measured

and

reported

from

each

certified

primary

monitor,

5745

certified

back-up

monitor

or other

approved

method

of emissions

5746

determination:

5747

5748

Component-system identification

code

provided

in Section

1.10

5749

of this

Appendix;

5750

5751

)

Date

and hour;

5752

5753

Hourly

average

diluent

gas

(02

concentration

(in

percent,

5754

rounded

to the

nearest

tenth);

5755

5756

Method

of determination

code for diluent

gas

(02

5757

concentration

data

using

Codes 1-55

Table 4a

of this

Section;

5758

5759

5760

The

percent

monitor

data availability

(to

the

nearest tenth

of a

JCAR350225-08

1 8507r01

5761

percent)

for the

monitoring

system (if

separate

O2or

5762

cQ2

monitoring system

is used

for heat input detennination)

5763

calculated

pursuant

to Section

1.8

this Appendix.

5764

5765

4,)

For stack gas volumetric

flow

rate

during unit operation,

as measured and

5766

reported from each

certified primary

monitor,

certified

back-up monitor

5767

other approved

method of emissions

determination, record

the information

5768

required under 40

CFR

75.5

7(c)(2)(i)

through

(vi),

incorporated by

5769

reference in

Section 225.140.

5770

5771

For mercury

mass emissions

during

unit

operation,

as measured and

5772

reported

from the certified primary

monitoring systems,

certified

5773

redundant or

non-redundant

back-up monitoring

systems, or other

5774

approved methods

emissions

determination:

5775

5776

)

Date and

hour;

5777

5778

Hourly mercury

mass

emissions

(ounces, rounded

to three decimal

5779

places);

5780

5781

Identification

code

for emissions formula

used to derive hourly

5782

mercury

mass

emissions

from mercury

concentration, flow

rate

5783

and moisture data,

as provided

in Section

1.10

of this

Appendix.

5784

5785

Mercury

Emission

Record

Provisions

(Sorbent

Trap

Systems).

The

owner

5786

operator

must record

for

each

hour the information

required

this subsection,

5787

for

each affected unit using

sorbent

trap monitoring

systems in

combination with

5788

flow rate,

moisture,

and

(in

certain

cases)

diluent gas monitors,

to determine

5789

mercury

mass emissions

and (if required) unit

heat input under

this Part.

5790

5791

For mercury concentration

during unit

operation, as measured

and

5792

reported from each

certified primary

monitor, certified back-up

monitor

5793

other approved method

of emissions determination:

5794

5795

)

Component-system

identification

code as provided in

Section 1.10

5796

of this

Appendix;

5797

5798

Date

and hour;

5799

5800

Hourly

mercury

concentration

(ig/dscm,

rounded to the nearest

5801

tenth).

For

a particular

pair of sorbent

traps, this will be the

flow-

5802

proportional average

concentration

for the data collection

period;

5803

JCAR350225-081

8507r01

5804

)

Method

determination

for

hourly average

mercury

concentration

5805

using

Codes 1-55

in Table

4a of this Section;

and

5806

5807

Percent

monitor

data availability

(recorded

to the

nearest tenth

of a

5808

percent)

calculated

pursuant

to Section

1.8 of this

Appendix;

5809

5810

For flue

gas moisture

content

during unit

operation,

measured

and

5811

reported

from each

certified primary

monitor,

certified

back-up

monitor or

5812

other approved

method

of emissions

determination

(except

where

a default

5813

moisture

value

approved

under

CFR 75.66,

incorporated

reference

5814

in Section

225.140),

record the

information

required under

subsections

5815

(e)(2)(A)

through

(E)

this Section;

5816

5817

For

diluent gas

(02

C0)

concentration

during unit

operation

(if

5818

required

for heat

input

determination),

record

the

information

required

5819

under

subsections

(e)(3)(A)

through

(E) of

this Section.

5820

5821

For

stack

gas volumetric

flow

rate during

unit operation,

as measured

and

5822

reported

from each

certified

primary monitor,

certified

back-up

monitor

5823

other

approved

method

of emissions

determination,

record

the information

5824

required

under

CFR

75.57(c)(2)(i)

through

(vi),

incorporated

5825

reference

Section

225.140.

5826

5827

For mercury

mass emissions

during

unit operation,

as measured

and

5828

reported

from the

certified

primary

monitoring

systems,

certified

5829

redundant

non-redundant

back-up

monitoring

systems

or other

5830

approved

methods

emissions

determination,

record the

information

5831

required

under

subsection

(e)(5)

of this

Section.

5832

5833

Record

the average

flow

rate of stack

gas

through

each

sorbent trap

(in

5834

appropriate

units, e.g.,

liters/mm,

cc/mi

dscmlmin).

5835

5836

Record the

gas flow

meter

reading

(in

dscm,

rounded

the nearest

5837

hundredth)

the beginning

and

end of the collection

period

and at

least

5838

once in each

unit operating

hour

during the

collection

period.

5839

5840

)

Calculate

and record

the ratio

of the bias-adjusted

stack

gas flow

rate to

5841

the sample

flow rate,

described

in Section

11.2

of Exhibit

D to

this

5842

Appendix.

5843

5844

Table

4a. — Codes

for

Method

of Emissions

and

Flow Determination

Code

5845

Hourly

emissions/flow

measurement

or estimation

method

5846

JCAR350225-0818507r01

Certified primary

emission/flow

monitoring

system.

Certified backup

emission/flow

monitoring

system.

Approved alternative

monitoring

system.

Reference

method.

Like-kind replacement

non-redundant

backup

analyzer.

Hourly Hg

concentration

determined from analysis

of a

single

trap multiplied

by a factor of 1.111

when one of the

paired

traps is invalidated

damaged

(See

Appendix K,

Section

8).

Hourly

Hg concentration

determined

from the trap resulting

in the

higher

Hg concentration

when

the

relative

deviation

criterion

for the

paired traps is not met

(See Appendix K,

Section

8).

Fuel

specific default value

(or

prorated

default value) used

for the

hour.

Other

quality assured methodologies

approved

through

petition.

These

hours

are included in missing

data lookback

and

are treated as unavailable

hours

for percent monitor

availability

calculations.

Other

substitute

data approved through

petition. These

hours are not included

in missing

data lookback and are

treated as unavailable

hours

for percent monitor

availability

calculations.

5847

5848

5849

Section

1.12

General Recordkeeping

Provisions

for Specific

Situations

5850

5851

The owner or

operator must meet all

of the applicable

recordkeeping requirements

of this

5852

Section.

accordance

with 40 CFR

75.34,

incorporated

by reference in

Section

225.140,

the

5853

owner or operator

of an affected unit

with

add-on

emission controls must

record the applicable

5854

information

in this

Section for each hour

of missing

mercury

concentration

data. Except

5855

otherwise

provided

CFR 75.34(d),

incorporated

reference

Section 225.140, for

units

5856

with

add-on mercury

emission controls,

the

owner or

operator must record:

5857

5858

Parametric

data that demonstrate,

for

each

hour of missing

mercury

emission

data,

5859

the proper operation

of the add-on

emission controls, as

described in the

quality

5860

assurance/quality

control

program for

the unit. The

parametric data must

5861

maintained on site and

must

be submitted,

upon request,

the Agency.

5862

Alternatively, for

units equipped

with flue gas desulfurization

(FGD)

systems,

the

5863

owner or operator

may use quality-assured

data

from a certified

monitor

5864

demonstrate proper

operation

of the emission controls

during periods

of missing

5865

mercury data;

5866

JCAR350225-081

8507r01

5867

)

flag indicating, for each

hour of missing

mercury emission

data,

either

that the

5868

add-on

emission

controls

are operating

properly,

as evidenced

by all

parameters

5869

jffig

within the ranges

specified in the

quality assurance/quality

control

program,

5870

or that the add-on emission

controls

are not operating properly.

5871

5872

Section

1.13

Certification,

Quality

Assurance

and Quality

Control

Record

Provisions

5873

5874

The owner or

operator must

meet all of the applicable

recordkeeping

requirements

this

5875

Section.

5876

5877

Continuous Emission

Monitoring

Systems.

The owner or operator

must record

the

5878

applicable

information in

this Section for each

certified monitor

or certified

5879

monitoring system

(including

certified backup

monitors)

measuring

and recording

5880

emissions

flow from an affected

unit.

5881

5882

1).

For

each flow monitor, mercury

monitor

or diluent gas monitor

(including

5883

wet- and

dry-basis

monitors used to determine

percent

moisture),

the

5884

owner

or operator must record

the following

for all daily and

7-day

5885

calibration

error

tests,

all daily system

integrity checks and

all off-line

5886

calibration

demonstrations,

including any

follow-up

tests after corrective

5887

action:

5888

5889

Component-system

identification

code

(on and after January

5890

2009,

only the component

identification

code is

required);

5891

5892

Instrument

span and

span

scale;

5893

5894

Date

and hour;

5895

5896

Reference

value

(i.e.,

calibration gas

concentration

or reference

5897

signal

value,

in ppm

or other appropriate

units);

5898

5899

)

Observed

value

(monitor

response

during

calibration,

in ppm

5900

other

appropriate units);

5901

5902

Percent

calibration

error

(rounded

the nearest tenth

of a percent)

5903

(flag

if using alternative

performance

specification for

low

emitters

5904

differential

pressure

flow monitors);

5905

5906

Reference signal

calibration

gas

level:

5907

5908

For

7-day

calibration error

tests, a test number

and reason for

test;

5909

JCAR350225-081 8507r01

5910

For 7-day calibration

tests for certification or

recertification,

5911

certification from the cylinder gas vendor or CEMS vendor that

5912

calibration

gas, as defined in 40 CFR 72.2, incorporated by

5913

reference in Section 225.140,

and Exhibit A to this

Appendix, was

5914

used to conduct calibration error testing;

5915

5916

Description

of any

adjustments,

corrective actions or maintenance

5917

prior to a passed test or following

failed test; and

5918

5919

)

Indication

whether

the unit is off-line or on-line.

5920

5921

For each flow monitor, the

owner or operator must record

the following

5922

for all daily interference checks, including any follow-up tests after

5923

corrective action.

5924

5925

Component-system identification code

(after January

1, 2009,

only

5926

the

component identification code is required);

5927

5928

)

Date and hour;

5929

5930

)

Code indicating whether

monitor

passes or

fails the interference

5931

check; and

5932

5933

)

Description of any

adjustments,

corrective actions or maintenance

5934

prior

to a passed test or following a failed test.

5935

5936

For each mercury concentration monitor or diluent gas monitor (including

5937

wet- and

dry-basis

monitors

used to

determine percent moisture),

the

5938

owner or operator must record the following for the initial and all

5939

subsequent linearity checks

and

3-level

system integrity

checks

(mercury

5940

monitors with converters only), including any follow-up tests after

5941

corrective

action:

5942

5943

Component-system identification code

(on

and after July

1, 2009,

5944

only the

component identification code is required);

5945

5946

)

Instrument span and span scale

(only

span scale is

required

on and

5947

after

July 1, 2009);

5948

5949

)

Calibration gas level;

5950

5951

Date and time

(hour

and

minute)

of each gas injection at each

5952

calibration

gas level;

JCAR350225-08

8507r01

5953

5954

)

Reference

value

(i.e.,

reference

gas concentration

for

each gas

5955

injection

at each calibration

gas

level, in

ppm

or other

appropriate

5956

units);

5957

5958

Observed

value

(monitor

response

to each

reference

gas injection

5959

at each

calibration

gas level,

in ppm

or other appropriate

units);

5960

5961

)

Mean of

reference

values

and

mean

measured

values at

each

5962

calibration

gas

level;

5963

5964

Linearity

error

each

of the reference

gas

concentrations

(rounded

5965

nearest

tenth

of a percent)

(flag

if using

alternative

perfoance

5966

specification);

5967

5968

Test

number

and

reason

for test (flag

aborted test);

and

5969

5970

Description

of any

adjustments,

corrective

action

or maintenance

5971

prior to a

passed

test or following

failed test.

5972

5973

For each

differential

pressure

type

flow

monitor,

the owner

or operator

5974

must

record items

subsections

(a)(4)(A)

through

(E)

of this Section,

for

5975

all quarterly

leak

checks,

including

any

follow-up

tests after corrective

5976

action.

For

each

flow

monitor,

the owner

or operator

must

record items

5977

subsections

(a)(4)(F)

and (G)

of this

Section for

all

flow-to-load

ratio

and

5978

gross heat

rate tests:

5979

5980

)

Component-system

identification

code

(on

and after

July

1, 2009,

5981

only

the system

identification

code

required).

5982

5983

)

Date

and hour.

5984

5985

Reason

for

test.

5986

5987

Code

indicating

whether monitor

passes

or fails the

quarterly

leak

5988

check.

5989

5990

Description

of any

adjustments,

corrective

actions

or maintenance

5991

prior

to a

passed

test or

following

a failed test.

5992

5993

)

Test data

from the

flow-to-load

ratio

gross

heat rate (GHR)

5994

evaluation,

including:

5995

JCAR350225-081

8507r01

5996

Monitoring

system identification

cocj

5997

5998

Calendar

year

and quarter;

5999

6000

jjj)

Indication

whether

the test

is a

flow-to-load

ratio

6001

gross

heat

rate evaluation;

6002

6003

jy)

Indication

of whether

bias

adjusted

flow rates

were

used:

6004

6005

Average

absolute

percent difference

between

reference

6006

ratio

(or GHR)

and

hourly

ratios

(or

GHR

values):

6007

6008

yj)

Test

result;

6009

6010

yj)

Number

of hours

used in final

quarterly

average;

6011

6012

yjji

Number

of hours

exempted

for

use of a

different fuel

type;

6013

6014

Number

of hours

exempted

for

load ramping

up or

down;

6015

6016

Number

of hours

exempted

for

scrubber

bypass;

6017

6018

çj)

Number

of hours

exempted

for

hours

preceding

a normal-

6019

load flow

RATA;

6020

6021

Number

hours

exempted for

hours

preceding

6022

successful

diagnostic

test,

following

a documented

monitor

6023

repair

major

component

replacement;

6024

6025

çjji

Number

of hours

excluded for

flue

gases discharging

6026

simultaneously

thorough

main

stack and

a bypass stack;

6027

and

6028

6029

4y)

Test

number.

6030

6031

)

Reference

data

for

the

flow-to-load

ratio

gross heat

rate

6032

evaluation,

including

(as

applicable):

6033

6034

Reference

flow

RATA end

date and

time;

6035

6036

jj)

Test

number of

the reference

RATA;

6037

6038

jjj

Reference

RATA

load

and load

level;

JCAR350225-081

8507r01

6039

6040

Average reference

method flow

rate during reference

flow

6041

RATA;

6042

6043

Reference

flow/load ratio;

6044

6045

Average

reference

method diluent gas concentration

during

6046

flow

RATA and diluent

gas units of

measure;

6047

6048

yjj

Fuel

specific

Fd-or

Fe-factor

during flow

RATA and F

6049

factor

units

of measure;

6050

6051

yjji

Reference

gross heat

rate

value;

6052

6053

Monitoring

system

identification code;

6054

6055

Average

hourly

heat

input rate during RATA;

6056

6057

çj)

Average

gross unit

load;

6058

6059

Operating load level;

and

6060

6061

jji

An indicator

(flag) if separate reference

ratios are

6062

calculated

for each multiple

stack.

6063

6064

)

For each flow monitor,

each

diluent gas

(02

monitor

used to

6065

determine

heat

input,

each moisture monitoring

system, mercury

6066

concentration monitoring

system, each sorbent

trap

monitoring

system

and

6067

each

approved alternative

monitoring

system, the owner or operator

must

6068

record the following

information for the initial

and

all subsequent

relative

6069

accuracy

test audits:

6070

6071

)

Reference methods

used.

6072

6073

Individual test run

data

from the

relative

accuracy test

audit for

the

6074

flow

monitor,

emissions concentration

monitor-diluent

6075

continuous

emission

monitoring

system, diluent gas

(02

6076

monitor used

to determine

heat

input, moisture monitoring

system,

6077

mercury

concentration monitoring

system, sorbent

trap monitoring

6078

system

or approved alternative

monitoring

system, including:

6079

6080

Date,

hour

and minute of beginning

of test run;

6081

JCAR350225-08

1 8507r01

6082

Date,

hour and minute of end of test

run;

6083

6084

lii)

Monitoring system identification code;

6085

6086

jy)

Test number

and

reason

for test;

6087

6088

Operating level

(low,

mid, high or

normal, as appropriate)

6089

and number

of operating levels comprising test;

6090

6091

Normal

load

(or

operating

level)

indicator

for flow RATAs

6092

(except

for peaking units);

6093

6094

yjj)

Units

of measure;

6095

6096

yjji

Run number;

6097

6098

Run value from CEMS being tested,

in the appropriate

6099

units of measure;

6100

6101

Run value

from reference method, in

the appropriate units

6102

of measure;

6103

6104

Flag value

(0,

1 or

9, as appropriate) indicating whether

run

6105

has been used in calculating relative

accuracy and bias

6106

values

or whether the test was aborted

prior to completion;

6107

6108

çjj)

Average gross unit load, expressed

as a total gross unit

6109

load,

rounded

to the nearest MWe, or as steam

load,

6110

rounded to the nearest

1000 lb/hr. except for units that

6111

not produce

electrical or thermal output; and

6112

6113

jji

Flag to indicate

whether an alternative performance

6114

specification has been used.

6115

6116

Calculations

and tabulated results, as follows:

6117

6118

Arithmetic mean

the

monitoring system measurement

6119

values

of the reference method

values, and of their

6120

differences,

specified

Equation

A—7 in Exhibit A to

6121

this Appendix;

6122

6123

Ii.1

Standard deviation, as

specified in Equation A—8 in Exhibit

6124

A to

this Appendix;

JCAR350225-08

1 8507r01

6125

6126

jjj)

Confidence coefficient,

as specified in Equation

A—9 in

6127

Exhibit

A to this Appendix;

6128

6129

Statistical t value

used in

calculations;

6130

6131

)

Relative

accuracy test results,

as specified

in Equation

A—

6132

10 in Exhibit

A to this Appendix. For multi-level

flow

6133

monitor tests the relative

accuracy

test results must

6134

recorded

at each load

(or

operating) level

tested.

Each

load

6135

(or

operating) level

must be expressed as a total gross

unit

6136

load, rounded

to the nearest MWe, or

as steam load,

6137

rounded to the nearest

1000 lb/hr. or as otherwise specified

6138

by the Agency,

for units that do not produce electrical

6139

thermal output;

6140

6141

Bias

test results as specified in Section 7.4.4

Exhibit

A to

6142

this Appendix;

and

6143

6144

Description

of any

adjustment,

corrective action or

maintenance

6145

prior to a passed

test or following a failed or aborted

test.

6146

6147

For

flow monitors, the equation

used to linearize the flow

monitor

6148

and the

numerical values of the

polynomial coefficients or K

6149

factors of that

equation.

6150

6151

For

moisture monitoring systems, the

coefficient or K factor

6152

other mathematical

algorithm used to adjust the monitoring

system

6153

with respect

to the reference method.

6154

6155

For each mercury

concentration monitor, and

each CO2or

monitor

6156

used to determine heat input, the

owner or operator must record

the

6157

following information

for the cycle time test:

6158

6159

Component-system

identification code

(on

and after July 1, 2009,

6160

only the component

identification code is required);

6161

6162

Date:

6163

6164

)

Start and end times;

6165

6166

Upscale

and downscale cycle

times for each component;

6167

JCAR350225-08 1 8507r01

6168

Stable start monitor

value:

6169

6170

Stable end monitor

value:

6171

6172

Reference

value

calibration

gases:

6173

6174

Calibration gas

level:

6175

6176

Total cycle

time:

6177

6178

Reason for

test:

and

6179

6180

Test number.

6181

6182

In addition to the information in subsection (a)(5) of this Section, the

6183

owner or operator

must record, for each

relative

accuracy test audit,

6184

supporting information sufficient to substantiate compliance with all

6185

applicable

Sections and Appendices in this Part. Unless otherwise

6186

specified

in this Part or in an applicable test method,

the

information

6187

subsections (a)(7)(A) through (H) of this Section may be recorded either

6188

in hard copy format, electronic format or a combination of the two, and

6189

the

owner or

operator must maintain this information in a format suitable

6190

for inspection and audit purposes. This RATA

supporting

information

6191

must include, but must not be limited

to,

the following data elements:

6192

6193

For each

RATA using Reference Method 2 (or its allowable

6194

alternatives)

in appendix A to 40 CFR

60,

incorporated

6195

reference in Section 225.140, to determine volumetric flow rate:

6196

6197

Information indicating whether or not the location meets

6198

requirements of Method 1 in appendix

to 40

CFR 60,

6199

incorporated

by reference in Section

225.140:

and

6200

6201

Information

indicating whether

or not the equipment passed

6202

the

required

leak checks.

6203

6204

For each run of each RATA

using Reference Method 2

(or

its

6205

allowable alternatives in appendix A

40 CFR

60,

incorporated

6206

by reference in Section

225.140)

to determine volumetric flow

6207

rate, record

the following data elements

(as

applicable to the

6208

measurement

method

used):

6209

6210

Operating

level

(low,

mid, high or normal, as

appropriate):

JCAR350225-08

8507r01

6211

6212

jj)

Number

of reference

method

traverse

points;

6213

6214

Average

stack

gas temperature

(°F);

6215

6216

jyj

Barometric

pressure

at test

port

(inches

mercury);

6217

6218

Stack

static

pressure

(inches

of H

Q)j

6219

6220

yj)

Absolute

stack

gas

pressure

(inches

mercury);

6221

6222

jj)

Percent

and

O7in

the

stack

gas,

dry basis;

6223

6224

yjji

çQ2

and

reference

method

used;

6225

6226

jç)

Moisture

content

stack

gas

(percent

6227

6228

)

Molecular

weight

stack

gas,

dry-basis

(lb/lb-mole);

6229

6230

çj)

Molecular

weight

stack

gas, wet-basis

(lb/lb-mole);

6231

6232

jj)

Stack

diameter

(or

equivalent

diameter)

at the test

port

(fi);

6233

6234

jji

Average

square

root

velocity

head

of stack

gas (inches

6235

jO)fortherun;

6236

6237

çjy)

Stack

or duct

cross-sectional

area at

test port

(fl

);

6238

6239

çy)

Average

velocity

(ft/sec);

6240

6241

çyj)

Average

stack

flow rate,

adjusted,

applicable,

for

wall

6242

effects

(scfh,

wet-basis);

6243

6244

çyjjJ

Flow

rate reference

method

used;

6245

6246

xviii)

Average

velocity,

adjusted

for

wall

effects;

6247

6248

çj)

Calculated

(site-specific)

wall

effects

adjustment

factor

6249

determined

during

the run,

and,

different,

the

wall

effects

6250

adjustment

factor

used in

the

calculations;

and

6251

6252

Default

wall

effects

adjustment

factor

used.

6253

JCAR350225-08 1 8507r01

6254

)

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

6255

Method 2 (or its allowable alternatives

appendix A

CFR

6256

60, incorporated by reference in Section 225.140) to determine

6257

volumetric

flow rate, record the following data elements (as

6258

applicable

to the measurement method

used):

6259

6260

Reference method probe type;

6261

6262

Pressure measurement device

type;

6263

6264

IJj

Traverse point ID;

6265

6266

Probe or pitot tube calibration coefficient;

6267

6268

Date of latest probe or pitot tube calibration;

6269

6270

Average velocity differential pressure at traverse point

6271

(inches

or the average of the square roots of the

6272

velocity differential pressures

the traverse

point

((inches

6273

H,O)”

);

6274

6275

yjj

stack temperature at the traverse point (°F);

6276

6277

yjji

Composite (wall

effects) traverse point identifier;

6278

6279

ç)

Number of

points

included in composite traverse point;

6280

6281

Yaw angle of flow at traverse point (degrees);

6282

6283

Pitch angle of flow at traverse point (degrees);

6284

6285

2c1i1

Calculated

velocity

traverse

point both accounting and

6286

not accounting for wall effects

(ft/see):

and

6287

6288

jji

Probe identification number.

6289

6290

For each RATA using Method

3A in appendix A to

CFR 60,

6291

incorporated by reference in Section 225.140, to determine

6292

concentration:

6293

6294

Pollutant

or diluent gas being measured;

6295

6296

jjj

Span of reference method analyzer;

JCAR350225-081 8507r01

6297

6298

jj)

Type of reference method system (e.g.,

extractive or

6299

dilution

type);

6300

6301

jy)

Reference method dilution factor (dilution

type systems

6302

only);

6303

6304

Reference

gas

concentrations (zero,

mid and high gas

6305

levels)

used for

the 3-point

pre-test

analyzer

calibration

6306

error test

(or,

for dilution type reference method

systems,

6307

for the 3-point pre-test system calibration

error test) and

for

6308

any subsequent

recalibrations;

6309

6310

yj)

Analyzer

responses to the zero-,

mid-

and high-level

6311

calibration

gases during the 3-point pre-test analyzer

(or

6312

system) calibration error test

and during any subsequent

6313

recalibrations;

6314

6315

yjfl

Analyzer

calibration

error at each gas level

(zero,

mid

and

6316

high) for the

3-point

pre-test analyzer

(or

system)

6317

calibration error

test

and for any subsequent

recalibrations

6318

(percent of span value);

6319

6320

yjji

Upscale gas concentration

(mid

or high gas

level)

used

for

6321

each pre-run

post-run system bias check or

(for

dilution

6322

type reference method

systems)

for each pre-run or

post-

6323

run

system calibration error check;

6324

6325

Analyzer

response

to the calibration

gas for each pre-run

6326

post-run system bias

(or

system calibration error) check;

6327

6328

The arithmetic average

of the analyzer responses

the

6329

zero-level

gas, for each pair of pre- and

post-run system

6330

bias

(or

system calibration error)

checks;

6331

6332

çj)

The arithmetic average

of the analyzer responses

to the

6333

upscale calibration gas for each pair

of pre- and post-run

6334

system

bias

(or

system calibration error) checks;

6335

6336

li)

The results of each

pre-run and each post-run

system

bias

6337

(or

system calibration

error)

check using the zero-level

gas

6338

(percentage

of span value);

6339

JCAR350225-08

1 8507r01

6340

jji

The results

of each pre-run and

each post-run system

bias

6341

(or

system

calibration

error) check using

the upscale

6342

calibration

gas (percentage of span

value);

6343

6344

Calibration

drift and zero drift of

analyzer during

each

6345

RATA

run (percentage of span

value);

6346

6347

çy)

Moisture

basis

the

reference

method analysis:

6348

6349

çyj

Moisture content of

stack gas, in percent,

during each test

6350

run

(if

needed to convert

to moisture basis

of CEMS being

6351

tested);

6352

6353

yjj)

Unadjusted

(raw) average pollutant

or diluent

gas

6354

concentration

for each run:

6355

6356

xviii)

Average

pollutant or diluent

gas concentration

for each

run,

6357

corrected

for calibration

bias

(or

calibration

error)

and, if

6358

applicable,

corrected for

moisture:

6359

6360

The

F-factor used

to convert reference

method

data to

units

6361

of lb/mmBtu

(if

applicable);

6362

6363

ç)

Dates of the

latest analyzer interference

tests;

6364

6365

pçj)

Results

the

latest

analyzer

interference

tests:

and

6366

6367

çjj)

For

each calibration gas

cylinder used during

each RATA,

6368

record

the cylinder gas vendor,

cylinder number,

expiration

6369

date,

pollutants in the cylinder

and certified gas

6370

concentrations.

6371

6372

)

For each test run

of each moisture determination

using

Method 4 in

6373

appendix A to 40

CFR 60, incorporated

by reference

in Section

6374

225.140,

(or

its

allowable

alternatives),

whether the determination

6375

is made to

support a gas RATA,

to support a flow RATA

6376

quality assure

the

data from

continuous

moisture

monitoring

6377

system, record

the following data

elements

(as

applicable

to the

6378

moisture

measurement method

used):

6379

6380

Test number;

6381

6382

Run number:

JCAR350225-08

1 8507r01

6383

6384

The beginning

date, hour and minute of the run;

6385

6386

The ending date, hour and minute

the

run;

6387

6388

Unit operating

level

(low,

mid,

high or normal, as

6389

appropriate);

6390

6391

yj)

Moisture

measurement method;

6392

6393

yjfl

Volume

of 02

H collected in the impingers (ml);

6394

6395

yjji

Mass

of 02

H collected in the silica gel (g);

6396

6397

jç)

Dry gas meter

calibration

factor;

6398

6399

)

Average dry

gas meter temperature

(°F);

6400

6401

çj

Barometric

pressure (inches of

mercury);

6402

6403

jj)

Differential pressure across the orifice

meter

(inches

6404

6405

6406

jji

Initial

and final dry gas meter readings

(ft

);

6407

6408

çjy)

Total

sample gas volume, corrected to standard

conditions

6409

(dscf);

and

6410

6411

çy)

Percentage

of moisture in the stack gas

(percent

6412

6413

The raw data and

calculated results for any stratification tests

6414

performed

in accordance with Sections 6.5.5.1 through

6.5.5.3 of

6415

Exhibit A to this Appendix.

6416

6417

For each RATA run

using the Ontario Hydro Method to determine

6418

mercury concentration:

6419

6420

Percent

2and

O2in

the stack gas, dry-basis;

6421

6422

Moisture content of the stack gas

(percent

Q)j

6423

6424

jjjj.

Average

stack temperature

(°F);

6425

JCAR350225-081 8507r01

6426

Dry

gas volume metered

(dscm):

6427

6428

Percent

isokinetic;

6429

6430

Particle-bound

mercury

collected

the filter,

blank and

6431

probe rinse

(igm);

6432

6433

yiIl

Oxidized

mercury collected by the

KC1 impingers

(igm);

6434

6435

yjji

Elemental

mercury collected

the IINO

impinger

6436

and

the

KMnO

impingers

(igm);

6437

6438

jç)

Total

mercury,

including particle-bound

mercury (igm);

6439

and

6440

6441

)

Total mercury,

excluding

particle-bound

mercury

()

6442

6443

All appropriate data

elements

for Methods

30A

and

30B.

6444

6445

For a unit with a flow

monitor installed

on a rectangular stack

6446

duct, if a site-specific

default

or measured

wall effects

adjustment

6447

factor (WAF)

is used to correct

the stack

gas volumetric

flow rate

6448

data

to account for

velocity

decay

near

the stack or duct wall,

the

6449

owner

or operator

must keep records

of the following

for each

flow

6450

RATA

performed with EPA

Method 2 in appendices

A—i and A—2

6451

to 40 CFR 60, incorporated

by reference in

Section 225.140,

6452

subsequent to the

WAF determination:

6453

6454

Monitoring

system

ID;

6455

6456

Test

number:

6457

6458

jJj)

Operating

level:

6459

6460

RATA end date and

time:

6461

6462

Number of

Method 1

traverse

points;

and

6463

6464

yj)

Wall effects

adjustment factor

(WAF),

to the nearest

6465

0.0001.

6466

JCAR350225-08

8507r01

6467

For

each

RATA run

using Method

29 in

appendix

A—8

CFR

6468

60, incorporated

by reference

in Section

225.140,

to determine

6469

mercury

concentration:

6470

6471

Percent

2and 2

the stack

gas,

dry-basis;

6472

6473

jj)

Moisture

content

of the

stack

gas (percent

6474

6475

jjj)

Average

stack

gas temperature

(°F);

6476

6477

Dry

gas

volume

metered

(dscm);

6478

6479

Percent

isokinetic;

6480

6481

yj)

Particulate

mercury

collected

in the front

half of the

6482

sampling

train,

corrected for

the

front-half

blank value

6483

Qigm);

and

6484

6485

yji)

Total

vapor phase

mercury

collected

the back half

the

6486

sampling

train,

corrected for

the back-half

blank

value

6487

fllgm).

6488

6489

)

For

each certified

continuous

emission

monitoring

system, excepted

6490

monitoring

system or

alternative

monitoring

system,

the date

and

6491

description

of each

event

that requires

certification,

recertification

6492

certain diagnostic

testing

of the system

and

the date

and type

of each

test

6493

performed.

If the conditional

data

validation

procedures

of Section

6494

.4(b)(3)

of this

Appendix

are to

be used to

validate

and

report data

prior

6495

to the completion

the

required

certification,

recertification

or diagnostic

6496

testing,

the

date and

hour

of the probationary

calibration

error

test

must

6497

reported

to mark the

beginning

of conditional

data

validation.

6498

6499

Hardcopy

relative

accuracy

test

reports,

certification

reports,

6500

recertification

reports

semiannual

or animal

reports

for gas

or flow

rate

6501

CEMS, mercury

CEMS

or sorbent

trap monitoring

systems

are required

6502

requested

under

CFR

75.60(b)(6)

or 75.63,

incorporated

by reference

6503

Section 225.140,

the

reports must

include,

at a

minimum,

the following

6504

elements

as applicable

the

types of tests

performed:

6505

6506

Summarized

test

results.

6507

6508

)

DAHS

printouts

of the CEMS

data

generated

during the

calibration

6509

error,

linearity,

cycle

time

and

relative accuracy

tests.

JCAR350225-081

8507r01

6510

6511

)

For pollutant

concentration

monitor or diluent

monitor relative

6512

accuracy

tests at normal operating

load:

6513

6514

The raw reference

method

data

from each run, i.e., the

data

6515

under subsection

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

of this Section (usually

6516

the

form of

computerized

printout,

showing

a series

6517

one-minute

readings

and the

run average);

6518

6519

The

raw

data and results for

all

required

pre-test,

post-test,

6520

pre-run and

post-run

quality

assurance checks

(i.e.,

6521

calibration

gas

injections)

the reference method

6522

analyzers,

i.e., the data under subsections

(a)(7)(D)(v)

6523

through (xiv)

of this Section;

6524

6525

jjj)

The raw data

and results for

any moisture measurements

6526

made during

the relative accuracy

testing, i.e.,

the data

6527

under subsections

(a)(7)(E)(i)

through

(xv)

of this

Section;

6528

and

6529

6530

Tabulated,

final, corrected

reference method

run

data

(i.e.,

6531

the actual

values

used

in the relative accuracy

calculations),

6532

along

with the equations

used

convert

the raw data to

the

6533

final values and example

calculations

to demonstrate how

6534

the

test data were

reduced.

6535

6536

For

relative accuracy

tests

for flow monitors:

6537

6538

The raw flow rate

reference method

data, from Reference

6539

Method 2

(or

its allowable

alternatives)

under appendix

6540

to 40 CFR 60,

incorporated

reference

in Section

6541

225.140, including

auxiliary moisture

data

(often

in the

6542

form of handwritten

data

sheets),

i.e.,

the

data under

6543

subsections (a)(7)(B)(i)

through

(xx),

subsections

6544

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

through

(xiii),

and, if applicable,

subsections

6545

(a)(7)(E)(i)

through (xv) of this

Section;

and

6546

6547

The tabulated,

final volumetric flow

rate values

used in the

6548

relative

accuracy calculations

(determined

from the flow

6549

rate reference

method data

and other necessary

6550

measurements,

such

as moisture, stack temperature

and

6551

pressure),

along with the

equations used

to convert the raw

JCAR350225-081

8507r01

6552

data to the

final

values

and example

calculations

6553

demonstrate

how the test

data

were reduced.

6554

6555

Calibration

gas

certificates

for

the gases

used in the

linearity,

6556

calibration

error

and cycle time

tests

and

for

the calibration

gases

6557

used to

quality

assure the

gas monitor

reference

method

data

6558

during

the relative

accuracy

test audit.

6559

6560

)

Laboratory

calibrations

of the source

sampling

equipment.

For

6561

sorbent trap

monitoring

systems,

the

laboratory

analyses of

all

6562

sorbent

traps and

information

documenting

the results

all leak

6563

checks and

other

applicable

quality

control

procedures.

6564

6565

)

A copy of

the

test protocol

used

for

the

CEMS

certifications

6566

recertifications,

including

narrative

that

explains

any testing

6567

abnormalities,

problematic

sampling,

and

analytical

conditions

that

6568

required

a change

to the

test protocol,

andlor solutions

to technical

6569

problems

encountered

during

the testing

program.

6570

6571

)

Diagrams

illustrating

test locations

and

sample

point

locations

(to

6572

verify that

locations

are

consistent

with information

in the

6573

monitoring

plan).

Include

a discussion

of any

special

traversing

6574

measurement

scheme.

The discussion

must

also

confirm

that

6575

sample

points satisfy

applicable

acceptance

criteria.

6576

6577

Names

of key

personnel

involved

in the

test

program,

including

6578

test team

members,

plant

contacts, agency

representatives

and test

6579

observers

site.

6580

6581

IQ)

Whenever

reference

methods

are

used as

backup

monitoring

systems

6582

pursuant to

Section

1.4(d)(3)

of this

Appendix,

the

owner or

operator

must

6583

record the

following

information:

6584

6585

)

For

each test

run

using Reference

Method

2 (or its

allowable

6586

alternatives

appendix A

to 40 CFR

60,

incorporated

reference

6587

Section

225.140)

determine

volumetric

flow

rate,

record

the

6588

following

data

elements

(as

applicable

the measurement

method

6589

used):

6590

6591

Unit

stack identification

number;

6592

6593

iii

Reference

method

system

and component

identification

6594

numbers;

JCAR350225-0818507r01

6595

6596

jjj)

Run

date and hour;

6597

6598

The

data in

subsection

(a)(7)(B)

of this

Section,

except

for

6599

subsections

(a)(7)(B)(i),

(vi), (viii),

(xii) and

(xvii)

through

6600

(xx);

and

6601

6602

The data in

subsection

(a)(7)(C),

except on a run

basis.

6603

6604

)

For each reference

method test run

using Method 6C,

7E or 3A in

6605

appendix

to 40

CFR

60,

incorporated

by reference

in Section

6606

225.140,

to determine

N0,

CO2

concentration:

6607

6608

Unit or stack identification

number;

6609

6610

li)

The reference

method

system

and component identification

6611

numbers;

6612

6613

jjj

Run number;

6614

6615

jy)

Run start

date and hour;

6616

6617

Run

end date and hour;

6618

6619

yj)

The

data in subsections

(a)(7)(D)(ii)

through

(ix)

and (xii)

6620

through (xv);

and

(vii)

Stack gas

density adjustment

factor

6621

(if

applicable).

6622

6623

)

For

each hour of each

reference method

test run using Method

6C,

6624

7E or

3A in appendix

A to 40 CFR 60,

incorporated

by reference

6625

Section 225.140, to

determine

SO,

N0,

2.or

6626

concentration:

6627

6628

Unit or stack

identification number;

6629

6630

jj)

The reference

method

system and

component

identification

6631

numbers;

6632

6633

jjj)

Run

number;

6634

6635

jy)

Run date

and hour;

6636

6637

Pollutant

or diluent

gas being measured;

JCAR350225-081 8507r01

6638

6639

Unadjusted (raw) average pollutant

diluent

gas

6640

concentration

for the hour; and

6641

6642

XIi)

Average pollutant

or diluent gas

concentration

for the hour,

6643

adjusted

as appropriate for moisture, calibration

bias (or

6644

calibration

error)

and stack gas density.

6645

6646

II)

For each other quality-assurance test or other quality assurance

activity,

6647

the

owner or operator

must record the following

(as

applicable):

6648

6649

)

Component/system

identification

code;

6650

6651

Parameter;

6652

6653

Test or activity completion date

and hour;

6654

6655

Test or activity

description;

6656

6657

Test result;

6658

6659

Reason for test; and

6660

6661

Test code.

6662

6663

For each

request

for a quality assurance

test

extension

or exemption,

for

6664

any loss of exempt status, and for each single-load flow RATA claim

6665

pursuant to Section 2.3.1.3(c)(3)

of Exhibit B to this Appendix, the

owner

6666

operator must record the following (as applicable):

6667

6668

For a RATA deadline extension or exemption request:

6669

6670

Monitoring system identification code;

6671

6672

jj)

Date

of last RATA;

6673

6674

jjj

RATA

expiration

date without extension;

6675

6676

RATA

expiration date with extension;

6677

6678

Type of RATA extension

of exemption claimed or lost;

6679

JCAR350225-08 1 8507r01

6680

Year

to date hours of usage of fuel other than very

low

6681

sulfur fuel;

6682

6683

Year to date

hours of non-redundant back-up CEMS usage

6684

at the unit/stack;

and

6685

6686

yjji

Quarter

and year.

6687

6688

)

For a linearity test or

flow-to-load ratio test quarterly exemption:

6689

6690

Component-system

identification

code;

6691

6692

jj)

Type of

test:

6693

6694

jj)

Basis for

exemption:

6695

6696

Quarter

and year; and

6697

6698

Span scale.

6699

6700

)

For a fuel flowmeter accuracy test extension:

6701

6702

Component-system identification

code;

6703

6704

Date of last accuracy test;

6705

6706

Iji)

Accuracy

test

expiration

date

without extension;

6707

6708

jy)

Accuracy test expiration

date

with

extension;

6709

6710

Type of

extension:

and

6711

6712

yj)

Quarter

and year.

6713

6714

)

For a single-load

(or

single-level) flow RATA claim:

6715

6716

Monitoring

system identification code;

6717

6718

ji)

Ending date of last annual flow RATA;

6719

6720

jjj

The relative frequency (percentage) of unit or stack

6721

operation

at each load

(or operating)

level

(low,

mid

and

JCAR350225-0818507r01

6722

high) since the

previous annual flow RATA, to the nearest

6723

0.1 percent;

6724

6725

End date of the historical

load

(or

operating

level)

data

6726

collection

period; and

6727

6728

Indication

the

load

(or

operating) level

(low,

mid or

6729

high) claimed for the single-load

flow RATA.

6730

6731

For the sorbent

traps

used in sorbent

trap monitoring systems to quantify

6732

mercury concentration

under Sections 1.14 through 1.18 of this Appendix

6733

(including sorbent traps used for relative

accuracy

testing), the owner or

6734

operator

must keep

records of the following:

6735

6736

The ID number

of the monitoring system in which each sorbent

6737

trap

was

used to collect mercury;

6738

6739

The unique identification number of

each sorbent trap;

6740

6741

)

The beginning and ending

dates and hours of the data collection

6742

period for each sorbent trap;

6743

6744

The average

mercury concentration

(in

igm1dscm) for the

data

6745

collection

period;

6746

6747

)

Information

documenting the results of the required

leak checks;

6748

6749

)

The analysis of the mercury collected

by each sorbent trap; and

6750

6751

Information documenting the results

of the other applicable quality

6752

control procedures

in Section 1.3 of this Appendix and in Exhibits

6753

B and D to this Appendix.

6754

6755

Except as

otherwise provided

in Section

1.12(a)

of this Appendix,

for units with

6756

add-on mercury emission controls,

the owner or operator must keep the following

6757

records on-site in the quality assurance/quality

control plan required by Section

6758

of Exhibit B to

this Appendix:

6759

6760

A list of operating parameters

for the add-on emission controls, including

6761

parameters

in Section 1.12 of this Appendix,

appropriate

to the particular

6762

installation

of add-on emission controls; and

6763

JCAR350225-08 1 8507r01

6764

The range of each operating parameter

in the list that indicates the add-on

6765

emission

controls are properly operating.

6766

6767

ç).

Excepted Monitoring for Mercury Low

Mass Emission Units under Section

6768

1.15(b)

of this Appendix. For qualifng coal-fired units using

the

alternative

low

6769

mass emission methodology under Section

1.15(b),

the owner or operator

must

6770

record

the data elements

described

in Section 1.13

(a)(7)(G),

Section 1.1 3(a)(7)(H)

6771

or Section 1.1 3(a)(7)(J) of this Appendix,

applicable, for

each run

of each

6772

mercury emission test and re-test required under Section 1.15(c)(1) or Section

6773

1.15(d)(4)(C)

of this

Appendix.

6774

6775

DM15

Verification. For

each

DAHS

(missing data and

formula)

verification that

6776

is required for initial certification, recertification or for certain diagnostic testing

6777

of a

monitoring system, record the date and

hour that the DAHS verification is

6778

successfully completed.

(This

requirement only applies to units that report

6779

monitoring plan data in accordance with Section

1.10(d)

of this

Appendix.)

6780

6781

Section

1.14 General Provisions

6782

6783

Applicability.

The

owner or operator of a unit must comply with the requirements

6784

this Appendix

the extent

that compliance is required by this Part. For

6785

purposes of this Appendix, the term “affected

unit” means any coal-fired unit

(as

6786

defined in 40 CFR 72.2,

incorporated

reference) that is subject to this

Part. The

6787

term “non-affected unit” means any unit that is not subject to such a program,

the

6788

term “permitting authority” means the Agency, and the term “designated

6789

representative” means

the

responsible

party under

this Part.

6790

6791

Compliance

Dates.

The owner or operator of an affected unit must meet the

6792

compliance

deadlines

established

Subpart B of this Part.

6793

6794

Prohibitions.

6795

6796

No owner or operator of an affected unit or a non-affected unit under

6797

Section 1.16(b)(2)(B)

this Appendix

will

use

any alternative monitoring

6798

system,

alternative reference method or any other alternative for the

6799

required

continuous

emission monitoring system without having obtained

6800

prior written approval in accordance with subsection

(f)

of this

Section.

6801

6802

)

No owner or operator of an affected unit or a non-affected unit under

6803

Section 1.16(b)(2)(B)

of this Appendix will operate the unit so as to

6804

discharge, or allow to be discharged, emissions

of mercury to the

6805

atmosphere without accounting for all such emissions in accordance

with

6806

the applicable provisions of this Appendix.

JCAR350225-081

8507r01

6807

6808

)

owner

or operator of an affected unit

or a non-affected unit under

6809

Section 1.16(b)(2)(B)

of this Appendix will disrupt

the continuous

6810

emission monitoring system,

any

portion of the system, or any other

6811

approved

emission monitoring method,

and thereby

avoid

monitoring and

6812

recording

mercury mass emissions discharged

into the atmosphere, except

6813

for periods

recertification

or periods when calibration,

quality assurance

6814

testing or maintenance is performed

in accordance with the provisions

6815

this

Appendix applicable to monitoring

systems under Section 1.15 of this

6816

Appendix.

6817

6818

No owner or operator

of an affected unit or a non-affected unit

under

6819

Section 1.1

6(b)(2)(B)

will retire or permanently

discontinue use of the

6820

continuous emission monitoring

system, any component of the system,

6821

any other approved

emission monitoring system under

this Appendix,

6822

except under any one of the following

circumstances:

6823

6824

During the period

that the unit is covered by a retired unit

6825

exemption

that

is in effect under

this Part; or

6826

6827

)

The owner

or operator is monitoring mercury mass emissions

from

6828

the affected unit with another

certified monitoring system

6829

approved, in accordance with

the provisions of Section 250 of

this

6830

Part; or

6831

6832

)

The designated representative

submits notification of the date

6833

certification testing of a replacement

monitoring

system in

6834

accordance with

Section

240(d)

of this Part.

6835

6836

)

Quality Assurance and Quality Control

Requirements. For units that use

6837

continuous emission monitoring systems to account for

mercury mass emissions,

6838

the owner or operator must meet the

applicable quality assurance and quality

6839

control requirements in

Section 1.5 and Exhibit B to this Appendix

for the flow

6840

monitoring systems, mercury concentration

monitoring systems, moisture

6841

monitoring systems

and diluent monitors

required

under

Section

1.15 of this

6842

Appendix. Units using sorbent trap

monitoring systems must meet the

applicable

6843

quality assurance requirements in Section 1.3

of this Appendix, Exhibit D to

this

6844

Appendix, and Sections

1.3 and 2.3 of Exhibit B to this

Appendix.

6845

6846

Reporting Data Prior to Initial

Certification. If, by the

applicable

compliance

date

6847

under this Part, the owner or

operator

an affected unit has not successfully

6848

completed

all

required certification tests for

any monitoring systems, he or she

6849

must

determine, record,

and report data prior to initial certification

in accordance

JCAR350225-081 8507r01

6850

with Section 239 of this Part.

6851

6852

Petitions.

6853

6854

The

designated

representative

of an affected unit that is also subject

to the

6855

Acid Rain Program may

submit a petition to the Agency requesting an

6856

alternative to any requirement

of Sections 1.14 through 1.18 of this

6857

Appendix. Such a petition must meet the requirements

CFR 75.66,

6858

incorporated

reference

in Section 225.140, and any additional

6859

requirements established

Subpart B of this Part. Use of an alternative to

6860

any requirement

Sections

1.14 through 1.18 of this Appendix is in

6861

accordance with Sections 1.14 through

1.18 of this Appendix and with

6862

Subpart B

of this

Part

only

to the extent that the petition is approved

6863

writing by the Agency.

6864

6865

Notwithstanding subsection

(f)(1)

of this Section, petitions

requesting an

6866

alternative to

requirement

concerning any additional CEMS required

6867

solely to meet the common stack provisions of Section

1.16 of this

6868

Appendix must

be submitted to the Agency and will be governed

6869

subsection (f)(3) of this

Section. Such a petition must meet the

6870

requirements of 40 CFR 75.66, incorporated

by reference in Section

6871

225.140, and any additional requirements established

by Subpart B of this

6872

Part.

6873

6874

)

The designated representative

of an affected unit that is not

subject

the

6875

Acid Rain Program may submit a petition to the Agency

requesting an

6876

alternative

to any requirement of Sections 1.14 through 1.18 of this

6877

Appendix. Such a petition must

meet

the requirements

of 40 CFR 75.66,

6878

incorporated

by reference in Section 225.140, and any additional

6879

requirements established

by Subpart

B of this

Part.

Use of an alternative

6880

any

requirement

of Sections 1.14 through 1.18 of this Appendix is in

6881

accordance with Sections 1.14 through 1.18 of this Appendix

only to the

6882

extent that it is approved

in writing by the Agency.

6883

6884

Section

1.15

Monitoring of Mercury

Mass Emissions and Heat

Input

at the Unit Level

6885

6886

The owner or

operator of the

affected

coal-fired unit must:

6887

6888

Meet

the general operating requirements

in Section

1.2

of this Appendix for the

6889

following continuous emission monitors (except

provided

in accordance with

6890

subpart E of 40 CFR 75, incorporated

reference in Section 225.140):

6891

6892

A mercury concentration

monitoring

system

(consisting

of a mercury

JCAR350225-08

1 8507r01

6893

pollutant concentration

monitor

and an automated DAHS,

which provides

6894

a permanent,

continuous record of

mercury emissions

in units of

6895

micrograms

per standard cubic

meter

(jig/scm))

a sorbent trap

6896

monitoring

system to measure

the mass concentration

of total vapor phase

6897

mercury

in the flue gas, including

the elemental

and oxidized forms

6898

mercury,

in micrograms per

standard cubic meter

(pg/scm);

6899

6900

)

A flow

monitoring system;

6901

6902

A continuous

moisture

monitoring system

(if

correction of mercury

6903

concentration for moisture

is required),

described

CFR

75.11(b),

6904

incorporated

reference

in Section

225.140.

Alternatively,

the owner

6905

operator may use the

appropriate fuel-specific

default moisture

value

6906

provided

in 40 CFR 75.11,

incorporated

by reference in Section

225.140,

6907

or a site-specific moisture

value approved

by petition under 40

CFR 75.66,

6908

incorporated

by reference

in Section 225.140;

and

6909

6910

If heat

input is

required

to be reported

under

this Part, the owner

6911

operator must meet the

general operating requirements

for

flow

6912

monitoring

system

and an

CO2

monitoring

system

to measure

heat

6913

input rate.

6914

6915

For an affected unit

that

emits 464 ounces

(29 lb) of

mercury

per

year or less,

use

6916

the following excepted

monitoring methodology.

To implement

this methodology

6917

for a qualifying

unit,

the

owner

operator must meet

the general operating

6918

requirements in

Section

1.2 of this

Appendix

for the

continuous emission

6919

monitors described

in subsections

(a)(2)

and (a)(4) of this

Section,

and

perform

6920

mercury

emission

testing

for

initial certification and

on-going quality-assurance,

6921

as described

in subsections (c) through

(e) of this Section.

6922

6923

To determine

whether an affected

unit is eligible to use

the monitoring provisions

6924

subsections

(b)

of this Section:

6925

6926

The owner

or operator must

perform mercury

emission testing within

6927

months

before the compliance

date in Section 1.14(b)

of this

Appendix to

6928

determine

the mercury

concentration

(i.e.,

total vapor phase mercury)

6929

the

effluent.

6930

6931

)

The testing

must

be performed

using one of the mercury

reference

6932

methods listed

in Section

1.6(a)(5)

of this Appendix,

and must

6933

consist of

a minimum

of 3 runs at the normal

unit operating load,

6934

while

combusting

coal. The

coal combusted during

the testing

6935

must

be representative

of the coal that will be

combusted

at the

JCAR350225-081 8507r01

6936

start

of the mercury

mass emissions

reduction program

(preferably

6937

from the same sources

of supply).

6938

6939

)

The minimum

time per run must be

hour if

Method 30A is used.

6940

If either Method 29

in appendix A-8 to 40 CFR

60,

incorporated

6941

by reference, ASTM D6784-02

(the

Ontario

Hydro

method)

6942

(incorporated

by reference under

Section

225.140)

or Method

30B

6943

is used, paired

samples are required for each test run

and the runs

6944

must be long enough

to ensure that sufficient mercury is collected

6945

to analyze.

When Method 29 in

appendix A-8 to 40 CFR 60,

6946

incorporated

reference,

or the Ontario Hydro method is

used,

6947

the test

results

must be based on the vapor

phase mercury collected

6948

in the back-half

the

sampling trains (i.e., the non-filterable

6949

impinger

catches).

For each Method 29 in appendix

A-8 to 40 CFR

6950

60, incorporated

reference,

Method 30B or Ontario Hydro

6951

method test

run, the paired trains must meet the relative

deviation

6952

(RD)

requirement specified

in Section

1.6(a)(5)

of this Appendix

6953

or Method

30B, as applicable. If the RD specification

is met, the

6954

results of the two

samples must be averaged arithmetically.

6955

6956

)

the

unit is equipped with flue gas desulfurization

or add-on

6957

mercury

emission controls, the controls must be operating

6958

normally

during the testing, and, for the purpose of establishing

6959

proper operation

of the controls, the owner or operator must record

6960

parametric data or

concentration

data in accordance with

6961

Section

1.12(a)

of this Appendix.

6962

6963

If two or more of units of the same type qualify

as a group of

6964

identical units in

accordance with 40 CFR 75.19(c)(1)(iv)(B),

6965

incorporated by reference in Section 225.140, the owner

6966

operator may test

a subset of these units in lieu of testing each

unit

6967

individually.

If this option is selected, the number of

units required

6968

to be tested must

determined

from Table LM-4 in 40 CFR

6969

75.19,

incorporated by reference in Section 225.140.

For the

6970

purposes of the required

retests under subsection (d)(4) of this

6971

Section, it is strongly recommended that

(to

the

extent

practicable)

6972

the same subset

of the units not be tested in two successive

retests,

6973

and that every

effort be made to ensure that each unit in the group

6974

of identical units is tested in

timely

manner.

6975

6976

6977

6978

Based on the results

of the

emission

testing, Equation 1 of this

1CAR350225-08

8507r01

6979

Section must be used

to provide a conservative estimate of the

6980

annual

mercury mass emissions from

the unit:

6981

6982

E=NXKXCHgXQmax

(Equation

6983

6984

Where:

6985

= Estimated annual mercury

mass emissions from the

affected unit,

(ounces/year)

= Units conversion constant,

9.978 x

100

oz-scm/Iig

scf

= Either 8,760

(the

number

of hours in a year) or the

maximum

number of operating hours per year

(if

less

than 8,760) allowed by the unit’s Federally-

enforceable operating

permit.

The highest mercury concentration (

ug/scm)

from

any

the test

runs or 0.50 ,ug/scm, whichever

greater

Maximum potential flow rate, determined according

—

to Section 2.1.2.1

of Exhibit A to this Appendix,

(scfh)

6986

6987

Equation

1 of this Section assumes that the unit operates

at its

6988

maximum

potential flow rate, either year-round or for the

6989

maximum number

of hours

allowed

by the operating permit (if

unit

6990

operation

is restricted to less than

8,760 hours per

year).

If the

6991

permit restricts

the annual unit heat input but not the number

6992

annual unit operating hours, the owner

or operator may divide the

6993

allowable annual

heat input

(mmBtu)

by the design rated heat

input

6994

capacity

of the unit (mmBtu/hr) to determine

the value of “N” in

6995

Equation 1. Also, note

that if the highest mercury concentration

6996

measured

in any test run is less than 0.50 ftg/scm, a default

value

6997

of 0.50 pg/scm must be

used

the calculations.

6998

6999

If the estimated annual

mercury mass emissions from subsection (c)(2)

7000

this Section

are

464 ounces per year or less,

then the unit is eligible to

use

7001

the monitoring provisions

in subsection

(b)

of this Section, and

continuous

7002

monitoring of the mercury

concentration

is not required

(except

7003

otherwise provided in subsections

(e)

and

(f)

of this Section).

7004

7005

If the

owner

operator

of an eligible unit under subsection

(c)(3)

of this Section

7006

elects

not to continuously monitor

mercury concentration, then the following

7007

requirements must be met:

JCAR350225-081

8507r01

7008

7009

The results

of the mercury emission

testing

performed under subsection

7010

Section must be submitted as

certification

application to the

7011

permitting authority,

no later than 45

days

after the testing

is completed.

7012

The calculations demonstrating

that the unit emits 464 ounces (or less)

per

7013

year

of mercury must also be provided,

and the default mercury

7014

concentration

that will be used for reporting

under

Section

1.18 of this

7015

Appendix must be specified

in both the electronic and hard copy

portions

7016

of the monitoring plan for the unit.

The methodology is considered to

7017

provisionally

certified as of the date and hour

completion

of the

7018

mercury emission testing.

7019

7020

Following initial certification, the

same default mercury concentration

7021

value

that was used

to estimate the unit’s annual mercury mass

emissions

7022

under

subsection (c) of this Section must

be reported for each unit

7023

operating hour, except as

otherwise provided in subsection (d)(4)(D)

7024

(d)(6)

of this Section. The default mercury concentration

value must

7025

updated

as appropriate

according to subsection

(d)(5)

of this Section.

7026

7027

)

The hourly

mercury mass emissions must be calculated according

7028

Section 4.1.3 in Exhibit

to this Appendix.

7029

7030

The mercury emission testing

described in subsection

(c)

of this Section

7031

must be repeated periodically, for the

purposes of quality-assurance,

7032

follows:

7033

7034

If the results of the certification

testing under subsection

(c)

of this

7035

Section show

that the unit emits 144 ounces

lb)

of mercury

per

7036

year or less, the first retest

is required by the end of the fourth

7037

operating

quarter

(as

defined in 40 CFR 72.2, incorporated

7038

reference) following the calendar

quarter

of the certification

7039

testing; or

7040

7041

)

If the results

of the certification testing under subsection

(c)

of this

7042

Section show that the unit emits

more than 144 ounces of mercury

7043

per year,

but less than or equal to 464 ounces per year,

the first

7044

retest is required

by the end of the second

operating

quarter

(as

7045

defined in 40 CFR 72.2, incorporated

by reference) following

the

7046

calendar

quarter

of the certification testing;

and

7047

7048

)

Thereafter, retesting

must

required

either semiannually

7049

annually

(i.e.,

the

end of the second or fourth

operating

7050

quarter following the quarter

of the

test),

depending

JCAR350225-08

1 8507r01

7051

the

results

of the

test.

determine

whether

the next

7052

retest

is due

within two

or four

operating

quarters,

substitute

7053

the

highest mercury

concentration

from the

current

test or

0.50

7054

jig/scm

(whichever

is greater)

into

the

equation

in subsection

(c)(2)

7055

of this Section.

the

estimated

annual

mercury

mass

emissions

7056

exceeds

144

ounces,

the next

test is due

within

two

operating

7057

quarters.

If the

estimated

annual

mercury

mass

emissions

is 144

7058

ounces

or less,

the

next test is

due within

four

operating

7059

quarters.

7060

7061

An additional

retest

is required

when there

is a

change

in the

coal

7062

rank

of the primary

fuel

(e.g.,

when

the

primary

fuel

is switched

7063

from bituminous

coal to

lignite).

Use ASTM

D388-99

7064

(incorporated

reference

under

Section

225.140) to

determine

the

7065

coal

rank.

The four

principal

coal ranks

are

anthracitic,

bituminous,

7066

subbituminous

and

lignitic. The

ranks of

anthracite

coal refuse

7067

(cuim)

and

bituminous

coal refuse

(gob)

must

be anthracitic

and

7068

bituminous,

respectively.

The

retest must

be performed

within

720

7069

unit operating

hours

of the change.

7070

7071

)

The

default mercury

concentration

used for reporting

under

Section

1.18

7072

of this Appendix

must

updated

after

each

required retest.

This

includes

7073

retests that

are required

prior

the compliance

date in Section

1.14(b) of

7074

this Appendix.

The

updated

value

must

either be

the highest

mercury

7075

concentration

measured

in any

of the

test runs or

0.50

jig/scm, whichever

7076

is greater.

The

updated

value

must be applied

beginning

with

the first

unit

7077

operating

hour

in which mercury

emissions

data

are

required

to be

7078

reported

after

completion

the retest,

except

provided

subsection

7079

(d)(4)(D)

of this

Section, where

the need

to retest

triggered

by a change

7080

the

coal

rank

of the

primary

fuel. In that

case,

apply

the updated

default

7081

mercury

concentration

beginning

with

the first unit

operating

hour

7082

which

mercury

emissions

are

required

be reported

after the

date

and

7083

hour

of the fuel

switch.

7084

7085

If the

unit is equipped

with

a flue gas

desulfurization

system or

add-on

7086

mercury

controls,

the

owner

or operator

must

record

the information

7087

required

under

Section 1.12

of this Appendix

for

each unit

operating hour,

7088

document proper

operation

of the

emission

controls.

7089

7090

For

units with

common

stack

and

multiple

stack exhaust

configurations,

the

use

7091

the

monitoring

methodology

described

subsections

(b)

through

(d)

of this

7092

Section

is restricted

as follows:

7093

JCAR350225-08 1 8507r01

7094

The methodology may not

be used for reporting mercury mass emissions

7095

at a

common stack unless all of the units using the common

stack are

7096

affected

units

and

the

units’ combined potential to emit does not exceed

7097

464

ounces of mercury per year

times

the number of units sharing the

7098

stack, in accordance with subsections (c) and

(d)

of this Section. If the test

7099

results

demonstrate that the units sharing the common stack

qualify as low

7100

mass emitters, the default

mercury concentration used for reporting

7101

mercury mass emissions at the common

stack must either be the highest

7102

value obtained in any test run or 0.50 hg/scm, whichever

is greater.

7103

7104

)

The initial emission testing required under subsection

(c)

of this

7105

Section maybe performed

at the common stack if the following

7106

conditions are met. Otherwise, testing of the individual

units (or a

7107

subset of the units, if identical,

as described in subsection (c)(l)(D)

7108

of this

Section)

is required:

7109

7110

The testing must be done at a combined load corresponding

7111

to the designated

normal load level

(low,

mid or

high)

for

7112

the units sharing the common stack in accordance

with

7113

Section

6.5.2.1

of Exhibit Ato this Appendix;

7114

7115

All of the units that

share the stack must be operating in

7116

normal, stable manner and

typical load levels

during

the

7117

emission testing. The coal combusted in each

unit during

7118

the testing

must be representative of the coal that will

7119

combusted in that unit

at the start of the mercury mass

7120

emission reduction program (preferably from

the

same

7121

sources

of supply);

7122

7123

jjj

If flue gas

desulfurization andlor add-on mercury emission

7124

controls are used to reduce the level of the emissions

7125

exiting from the

common stack, these emission controls

7126

must be operating normally during the emission

testing

7127

and, for the purpose

of establishing proper operation

of the

7128

controls, the owner or

operator

must record parametric

data

7129

concentration

data

in accordance with Section

7130

1.12(a) of this Appendix;

7131

7132

When

calculating E, the estimated maximum

potential

7133

annual mercury

mass emissions

from the stack, substitute

7134

the maximum potential

flow rate through the common

stack

7135

(as

defined in the monitoring plan)

and the highest

7136

concentration

from any test run

(or

0.50

pig/scm,

if greater)

JCAR350225-081

8507r01

7137

into Equation

7138

7139

The calculated

value

of E

must

divided

by the number

7140

units

sharing the stack.

If the result, when

rounded

to the

7141

nearest

ounce, does

not exceed 464 ounces,

the

units

7142

qualify

to use the

low

mass

emission

methodology;

and

7143

7144

If the units qualify

to use the methodology,

the

default

7145

mercury

concentration

used for reporting

at the common

7146

stack must be the

highest value

obtained in any test

run or

7147

0.50 pg/scm,

whichever

is greater;

7148

7149

The retests

required

under

subsection

(d)(4)

of this Section may

7150

also

be done at the common

stack. If this testing

option

chosen,

7151

the testing

must

done

at a combined

load corresponding to

the

7152

designated

normal load

level

(low,

mid or

high)

for the

units

7153

sharing

the common stack,

in accordance

with Section 6.5.2.1

7154

Exhibit

A to this Appendix.

Provided

that the

required

load

level is

7155

attained

and that

all

of the units sharing

the stack are fed from

the

7156

same

on-site coal supply

during normal

operation, it is not

7157

necessary for all of

the units sharing the

stack

to be in

operation

7158

during

a retest.

However, if two or more

of the units that

share the

7159

stack are fed

from

different on-site

coal supplies (e.g.,

one

unit

7160

bums low-sulfur

coal for compliance

and the other

combusts

7161

higher-sulfur

coal),

then either:

7162

7163

Perform

the

retest

with all units in normal

operation;

7164

7165

this is not

possible,

due to circumstances

beyond

the

7166

control of the owner

or operator (e.g.,

a forced unit outage),

7167

perform

the retest

with the available

units operating and

7168

assess the test results

as follows. Use the

mercury

7169

concentration

obtained

the retest for

reporting purposes

7170

under this Part if the

concentration is greater

than or equal

7171

the value

obtained

the

most recent

test. If the retested

7172

value is lower than

the mercury concentration

from the

7173

test, continue

using the higher

value from

the

7174

previous test for reporting

purposes

and use that same

7175

higher mercury

concentration value

in Equation 1

7176

determine

the due date for the next

retest,

as described

7177

subsection

(e)(1)(C)

of this Section.

7178

7179

If testing is done

at the

common

stack, the due date

for

the next

JCAR350225-08

1 8507r01

7180

scheduled retest must be determined

follows:

7181

7182

Substitute the

maximum potential flow rate for the common

7183

stack

(as defined in the monitoring plan)

and the highest

7184

mercury

concentration from any test run (or 0.50

,ug/scm, if

7185

greater) into

Equation 1 and

7186

7187

jj)

If the value of E obtained from Equation

1, rounded to the

7188

nearest

ounce,

is greater than 144 times the number

of units

7189

sharing the common stack,

but less than or equal to 464

7190

times the

number of units sharing the stack, the next

retest

7191

is due in two

operating quarters

7192

7193

jjj)

If the value of E obtained from Equation

rounded

to the

7194

nearest ounce, is

less than or equal to

144

times the number

7195

units sharing the common stack, the next retest

is due in

7196

four

operating

quarters.

7197

7198

)

For units with multiple

stack or duct configurations, mercury emission

7199

testing must be performed separately

on each stack or duct, and the

sum of

7200

the estimated annual mercury mass emissions from

the

stacks or ducts

7201

must not exceed 464

ounces of mercury per year. For reporting

purposes,

7202

the default mercury

concentration used for each stack or duct must

either

7203

be the highest value obtained

in any test run for that stack or 0.50

jig/scm,

7204

whichever

is greater.

7205

7206

For units with a main

stack and bypass stack configuration, mercury

7207

emission

testing

must be performed only

on the main stack. For reporting

7208

purposes, the default mercury

concentration used for the main stack

must

7209

either be

the

highest value obtained in any

test run for that stack or 0.50

7210

jig/scm,

whichever is greater.

Whenever the main stack is bypassed,

the

7211

maximum potential

mercury concentration,

as defined in Section

2.1.3

7212

Exhibit A to this Appendix, must

be reported.

7213

7214

At the end of each calendar year,

if the cumulative annual mercury mass

7215

emissions from

affected unit have exceeded 464

ounces, then the owner must

7216

install, certify, operate and

maintain a mercury concentration monitoring

system

7217

or a sorbent trap monitoring system

no later than 180

days

after the end of

the

7218

calendar year in which the annual mercury

mass emissions exceeded 464

ounces.

7219

For common

stack

and multiple stack configurations,

installation

and certification

7220

a mercury concentration

or sorbent trap monitoring system on each

stack

7221

(except

for

bypass

stacks)

is likewise

required within 180 days after the

end of the

7222

calendar year, if:

JCAR350225-081 8507r01

7223

7224

The

annual mercury mass emissions at the common stack have

exceeded

7225

464

ounces times

the number of affected units using the common stack;

7226

7227

The

sum of the annual mercury

mass

emissions from

all of the multiple

7228

stacks or

ducts has exceeded 464 ounces; or

7229

7230

)

The sum of the annual

mercury mass

emissions

from the main and bypass

7231

stacks has exceeded 464 ounces.

7232

7233

For an affected unit that is using a mercury concentration

CEMS

a sorbent trap

7234

system under Section 1.15(a)

of this Appendix to continuously monitor the

7235

mercury mass emissions, the owner or operator may switch to the

methodology in

7236

Section

1.15(b)

of this Appendix,

provided that the applicable conditions in

7237

subsections

(c)

through

(f)

of this Section are met.

7238

7239

Section 1.16

Monitorin2

Mercury

Mass Emissions and Heat Input at Common and

7240

Multiple Stacks

7241

7242

Unit

Utilizing

Common Stack with Other Affected Units. When an affected

unit

7243

utilizes a common stack with

one or more affected units, but no non-affected

7244

units, the owner or operator must

either:

7245

7246

Install, certify, operate and maintain the monitoring

systems described in

7247

Section 1.15(a)

of this Appendix at the common stack record the

7248

combined mercury mass emissions

for the units exhausting to the common

7249

stack. Alternatively, if, in accordance with Section 1.15(e)

of this

7250

Appendix,

each of

the units using the common stack is demonstrated

7251

emit less than

464

ounces of mercury per year, the owner

or operator may

7252

install, certify, operate

and maintain the monitoring systems and perform

7253

the mercury emission testing described under Section

1.15(b)

of this

7254

Appendix. If reporting

the

unit

heat input rate is required, determine

the

7255

hourly

unit

heat input rates either by:

7256

7257

Apportioning

the common stack heat input rate

to the

individual

7258

units according

to the procedures in 40 CFR

75.16(e)(3),

7259

incorporated by reference in

Section

225.140;

7260

7261

Installing,

certifying, operating

and maintaining

flow

monitoring

7262

system

and diluent

monitor in the duct to the common stack

from

7263

each unit; or

7264

7265

Install,

certify,

operate and maintain the monitoring systems

and

(if

JCAR350225-081

8507r01

7266

applicable) perform the

mercury

emission

testing

described

in Section

7267

1.15(a)

Section

1.15(b) of this Appendix

in the duct

the

common

7268

stack from each unit.

7269

7270

J2)

Unit Utilizing Common

Stack

with Nonaffected Units.

When

one

7271

affected

units

utilizes a common

stack with one or more

nonaffected

units,

the

7272

owner or operator

must either:

7273

7274

Install, certify,

operate and maintain

the monitoring

systems and

(if

7275

applicable) perform

the mercury emission

testing

described in Section

7276

1.15(a)

Section

1.15(b)

this

Appendix in the duct

the

common

7277

stack from each

affected unit; or

7278

7279

Install,

certify,

operate and

maintain the monitoring

systems described

7280

Section

1.15(a)

of this Appendix

in the common

stack; and

7281

7282

Install,

certify,

operate

and maintain the

monitoring systems

and

(if

7283

applicable)

perform the

mercury emission

testing described in

7284

Section

1.15(a)

(b)

of this Appendix in the

duct to the

common

7285

stack

from each non-affected

unit. The

designated representative

7286

must submit

a petition to the Agency

allow

a method of

7287

calculating and

reporting

the

mercury mass emissions

from the

7288

affected units as

the difference

between mercury mass

emissions

7289

measured

in the

common stack and

mercury mass

emissions

7290

measured in the ducts

of the non-affected

units, not to

reported

7291

an hourly value less

than

zero. The

Agency may approve

such

7292

method

whenever

the designated representative

demonstrates,

7293

the

satisfaction of the

Agency, that

the method ensures that

the

7294

mercury

mass emissions

from the affected

units

are not

7295

underestimated;

7296

7297

Count

the

combined emissions

measured

at the common

stack

7298

the mercury mass

emissions for the affected

units,

for

7299

recordkeeping

and

compliance purposes,

in accordance with

7300

subsection

(a)

of this

Section; or

7301

7302

Submit

petition

to the Agency to allow

use of a method for

7303

apportioning

mercury

mass emissions measured

in the

common

7304

stack

to each of the units using

the common

stack

and for reporting

7305

the mercury

mass emissions.

The Agency may

approve such a

7306

method

whenever

the designated

representative

demonstrates, to

7307

the satisfaction

of the Agency,

that

the method ensures

that the

7308

mercury mass

emissions from the affected

units

are not

JCAR350225-081

8507r01

7309

underestimated.

7310

7311

If the monitoring

option in

subsection

(b)(2)

of this Section is selected,

7312

and

if heat input

is required

to be reported under

this

Part, the

owner or

7313

operator

must

either:

7314

7315

Apportion the

common

stack

heat input rate to the

individual units

7316

according

to the procedures in

40 CFR 75.16(e)(3),

incorporated

7317

by reference

in Section 225.140;

7318

7319

Install a

flow monitoring system

and a diluent gas

(02

7320

monitoring

system in the

duct

leading from

each affected unit

7321

the common

stack, and measure

the heat input rate

in each duct,

7322

according

to Section 2.2 of Exhibit

to this

Appendix.

7323

7324

Unit With

a Main

Stack

and a Bypass Stack. Whenever

any portion

of the flue

7325

gases from

an affected unit can

routed

through

a bypass stack

to avoid the

7326

mercury monitoring

systems

installed on the main

stack, the

owner and operator

7327

must either:

7328

7329

Install,

certify,

operate and maintain

the monitoring

systems described

7330

Section 1.15(a)

of this Appendix

on both the main

stack and the

bypass

7331

stack and calculate

mercury

mass emissions for

the unit

the

sum of the

7332

mercury

mass emissions

measured at the two

stacks;

7333

7334

Install,

certify,

operate

and maintain the monitoring

systems

described

7335

Section

1.15(a)

of this

Appendix at the

main stack and measure

mercury

7336

mass

emissions at the

bypass stack using the

appropriate

reference

7337

methods

in Section

1.6(b)

of this Appendix.

Calculate mercury

mass

7338

emissions

for the unit

as the sum of the emissions

recorded

by the installed

7339

monitoring

systems on

the main stack

and the emissions measured

the

7340

reference

method

monitoring

systems:

7341

7342

Install, certify,

operate

and maintain the monitoring

systems

and

(if

7343

applicable)

perform the mercury

emission

testing

described

in Section

7344

1.15(a)

(b)

of this

Appendix only on

the main stack. If

this option is

7345

chosen,

it is not necessary

to designate

the

exhaust configuration

as a

7346

multiple stack configuration

the

monitoring plan required

under

Section

7347

1.10 of

this

Appendix,

since only

the main stack is

monitored; or

7348

7349

If the monitoring

option

in subsection

(c)(1) or (2)

of this Section

7350

selected, and

if heat input

is required to be reported

under

this

Part, the

7351

owner or

operator

must:

JCAR350225-08

1 8507r01

7352

7353

Use the

installed flow

and

diluent

monitors to

determine

the hourly

7354

heat input

rate at

each

stack (mmBtu/hr),

according

Section

2.2

7355

of Exhibit

to this

Appendix;

and

7356

7357

)

Calculate

the

hourly

heat input

at each

stack

(in mmBtu)

7358

multiplying

the

measured

stack

heat input

rate

the

7359

corresponding

stack operating

time;

and

7360

7361

Determine

the

hourly unit

heat input

summing

the

hourly

stack

7362

heat

input

values.

7363

7364

Unit

With

Multiple

Stack or

Duct

Configuration.

When

the flue

gases

from

7365

affected

unit

discharge

the

atmosphere

through more

than

one stack,

or when

7366

the

flue

gases from

an affected

unit

utilize

two or more

ducts

feeding

into

single

7367

stack

and

the owner

or operator

chooses

to monitor

in the

ducts rather

than

the

7368

stack,

the owner

or operator

must

either:

7369

7370

Install,

certify,

operate

and

maintain the

monitoring

systems

and

(if

7371

applicable)

perform

the mercury

emission

testing described

7372

Section

1.15(a)

(b)

this Appendix

each of

the multiple

7373

stacks and

determine

mercury mass

emissions from

the affected

7374

unit

as the

sum of

the

mercury

mass

emissions

recorded

for each

7375

stack.

If another

unit

also

exhausts

flue gases

into one

of the

7376

monitored

stacks,

the

owner or

operator

must

comply

with the

7377

applicable

requirements

subsections

(a)

and

(b)

of this

Section,

7378

in order

properly

determine

the mercury

mass

emissions

from

7379

the

units

using

that

stack;

7380

7381

)

Install,

certify, operate

and

maintain the

monitoring

systems

and (if

7382

applicable)

perform

the

mercury

emission

testing described

7383

Section

1.15(a) or

(b) of this

Appendix

each

of the

ducts

that

7384

feed

into the stack,

and determine

mercury

mass emissions

from

7385

the affected

unit

using

the sum

of the

mercury

mass emissions

7386

measured

at each

duct,

except

that where

another unit

also

7387

exhausts

flue

gases

to one or

more of the

stacks,

the owner

7388

operator

must

also comply

with

the

applicable

requirements

7389

subsections

(a)

and

(b)

of this

Section

determine

and record

7390

mercury mass

emissions

from

the units

using that

stack;

7391

7392

If the monitoring

option

in subsection

(d)(1)

(2) of this

Section

7393

is selected,

and if

heat

input is

required to

reported under

this

7394

Part, the

owner

operator

must:

JCAR350225-08 1 8507r01

7395

7396

Use the installed

flow and

diluent monitors

to determine

7397

the

hourly heat input rate at each stack or duct (mmBtu/hr),

7398

according to

Section 2.2 of Exhibit C to this Appendix;

and

7399

7400

])

Calculate the hourly heat input at each stack or

duct (in

7401

mmBtu)

by multiplying the measured stack

(or

duct)

heat

7402

input rate

the

corresponding stack (or duct) operating

7403

time;

and

7404

7405

Determine the hourly unit heat input

summing

the

7406

hourly stack

(or

duct) heat input values.

7407

7408

Section 1.17

Calculation of mercury mass emissions

and heat input rate

7409

7410

The

owner or operator must calculate mercury

mass emissions and heat input rate in accordance

7411

with the procedures in Sections

4.1

through

4.3

of Exhibit F to this Appendix.

7412

7413

Section 1.18 Recordkeepiug and reporting

7414

7415

General recordkeeping

provisions.

The owner or operator of any affected unit

7416

must maintain for each affected

unit

and each non-affected unit under Section

7417

1.1

6(b)(2)(B)

of this Appendix a file of all measurements,

data, reports, and other

7418

information required by this part at the source in a form suitable

for

inspection

for

7419

at least 3 years from the date of each record. Except for the certification

data

7420

required in Section 1.1 1(a)(4)

of this Appendix and the initial submission of

the

7421

monitoring plan required in Section

1.11(a)(5)

of this Appendix,

the data must

7422

collected beginning

with

the earlier of the date of provisional certification

or the

7423

compliance deadline in Section

1.14(b)

of this Appendix.

The certification data

7424

required

in Section

1.1 1(a)(4) of this Appendix must be collected beginning

with

7425

the date of the first certification test performed. The file must contain

the

7426

following information:

7427

7428

The information required

Sections

1.11 (a)(2),

(a)(4), (a)(5), (a)(6),

(b),

7429

applicable), (d), and

(e)

(f)

of this Appendix (as applicable);

7430

7431

The information

required

in Section 1.12

of this Appendix, for units with

7432

flue gas

desulfurization

systems or add-on mercury emission

controls;

7433

7434

For affected

units

using

mercury CEMS or sorbent

trap

monitoring

7435

systems, for each hour when the unit is

operating, record the mercury

mass

7436

emissions, calculated in accordance with Section 4

of Exhibit

to this

7437

Appendix.

JCAR350225-081 8507r01

7438

7439

Heat

input and

mercury

methodologies for the hour; and

7440

7441

)

Formulas from the monitoring

plan for total mercury mass emissions and

7442

heat input

rate

(if

applicable);

7443

7444

Certification, quality assurance

and quality control record provisions. The owner

7445

or operator of any affected unit must record

the

applicable

information

in Section

7446

1.13 of this Appendix

for each affected unit or group of units monitored

at a

7447

common stack and each non-affected

unit under Section

1.16(b)(2)(B)

of this

7448

Appendix.

7449

7450

Monitoring plan recordkeeping

provisions.

7451

7452

General provisions.

The owner or operator of an affected unit must

7453

prepare and maintain a monitoring plan

for each

affected

unit or group of

7454

units monitored at

a common stack and each non-affected unit under

7455

Section

1.16(b)(2)(B)

of this Appendix.

The monitoring plan must contain

7456

sufficient

information on the continuous monitoring systems and

the use

7457

of data derived from these

systems

to demonstrate that all the unit’s

7458

mercury emissions are monitored

and reported.

7459

7460

)

Updates. Whenever the owner or operator makes

replacement,

7461

modification, or

change in a certified continuous monitoring

system or

7462

alternative monitoring

system under 40 CFR 75, subpart E, incorporated

7463

by reference in Section 225.140, including

a change in the automated

data

7464

acquisition and handling system or in the flue gas handling

system, that

7465

affects information reported

in the monitoring plan (e.g., a change to

7466

serial number for a component of a monitoring system), then the

owner or

7467

operator must

update

the monitoring

plan.

7468

7469

Contents of the monitoring plan.

Each monitoring plan must contain the

7470

information in Section

1.10(d)(1)

of this Appendix in electronic format

7471

and the information in Section 1.1 0(d)(2)

in hardcopy format.

7472

7473

General reporting provisions.

7474

7475

The designated representative

for an affected unit must comply

with all

7476

reporting

reciuirements

this Section and with any additional

7477

requirements set forth in 35 Ill.

Adm. Code 225.

7478

7479

)

The

designated

representative for an affected unit

must

submit the

7480

following for each

affected unit or group of units monitored

at a common

JCAR350225-081

8507r01

7481

stack

and each

non-affected

unit under

Section

1.1

6(b)(2)(B)

this

7482

Appendix:

7483

7484

Monitoring

plans

in accordance

with subsection

(e)

of this

Section;

7485

and

7486

7487

)

Quarterly

reports

in accordance

with

subsection

(f)

of this

Section.

7488

7489

Other

petitions

and communications.

The

designated

representative

for

7490

affected

unit

must

submit petitions,

correspondence,

application

fonns,

7491

and

petition-related

test results

in accordance

with

the

provisions

7492

Section

1.14(f)

of this

Appendix.

7493

7494

Quality

assurance

RATA

reports.

If requested

the Agency,

the

7495

designated

representative

of an affected

unit

must submit

the quality

7496

assurance

RATA

report

for each

affected

unit or

group

of units monitored

7497

at a

common stack

and

each non-affected

unit under

Section 1.1

6(b)(2)(B)

7498

of this

Appendix

by the

later

of 45 days

after

completing

a quality

7499

assurance

RATA

according

to Section

2.3

Exhibit

B to this Appendix

7500

15 days after

receiving

the

request.

The

designated

representative

must

7501

report

the hardcopy

information

required

by Section

1.1

3(a)(9)

of this

7502

Appendix

the

Agency.

7503

7504

)

Notifications.

The designated

representative

for

affected

unit must

7505

submit

written notice

the Agency

according

to the

provisions

CFR

7506

75.61,

incorporated

reference

in Section

225.140,

for

each

affected

unit

7507

or group

of units

monitored

at a common

stack and

each

non-affected

unit

7508

under

Section

1.16(b)(2)(B)

this Appendix.

7509

7510

Monitoring

plan

reporting.

7511

7512

Electronic

submission.

The designated

representative

for

affected

unit

7513

must submit

to the

Agency

and USEPA,

an alternate

Agency designee

7514

if one

specified,

complete,

electronic,

up-to-date

monitoring

plan file

7515

in a format

specified

the

Agency

for each

affected unit

or group

7516

units

monitored

at a

common stack

and each

non-affected

unit under

7517

Section

1.16(b)(2)(B)

this

Appendix,

follows:

later than

21 days

7518

prior

to the

commencement

initial certification

testing;

at the

time

7519

certification

recertification

application

submission;

and whenever

7520

update of

the electronic

monitoring

plan

is required,

either

under Section

7521

1.10

this Appendix

elsewhere

in this

Appendix.

7522

7523

Hardcopy

submission.

The

designated

representative

of an

affected

unit

JCAR350225-0818507r01

7524

must submit all of the hardcopy information required

under Section

1.10

7525

this Appendix,

for each

affected

unit or group

of units monitored at a

7526

common stack and each non-affected unit under Section

1.1 6(b)(2)(B)

7527

this Appendix, to the Agency prior to initial

certification. Thereafter,

the

7528

designated representative

must

submit hardcopy

information only if that

7529

portion

of the monitoring

plan is

revised. The

designated representative

7530

must submit the

required

hardcopy information as

follows: no later

than

7531

21 days prior to the commencement of initial

certification

testing; with

7532

any certification or

recertification application, if a hardcopy monitoring

7533

plan change is associated with the recertification event;

and within

30 days

7534

after any other

event

with

which

a hardcopy

monitoring plan change is

7535

associated, pursuant to Section

1.10(b)

of this

Appendix. Electronic

7536

submittal

of all monitoring

plan information, including hardcopy portions,

7537

is permissible provided that a paper copy of the

hardcopy portions can

7538

furnished

upon

request.

7539

7540

Quarterly

reports.

7541

7542

Electronic submission. Electronic

quarterly reports must be submitted,

7543

beginning with the calendar quarter containing the

compliance

date

7544

Section

1.14(b)

of this Appendix, unless otherwise

specified in

Ill.

7545

Adm.

Code 225. The designated

representative

for

an affected unit

must

7546

report the data and information in this

subsection (f)(1) and the applicable

7547

compliance certification

information in subsection

(f)(2)

of this Section

7548

the

Agency and USEPA, or an alternate Agency designee if one is

7549

specified, quarterly in a format specified by the

Agency, except

7550

otherwise provided in

CFR 75.64(a),

incorporated by reference in

7551

Section 225.140, for units in long-term cold storage. Each

electronic

7552

report must be submitted to the

Agency within 45 days following the end

7553

each calendar

quarter.

Except as otherwise provided

in 40

CFR

7554

75.64(a)(4) and

(a)(5),

incorporated

reference in Section 225.140, each

7555

electronic report must include the date of report

generation and the

7556

following

information for each affected unit or group of units monitored

7557

a common stack:

7558

7559

The

facility

information in 40 CFR 75.64(a)(3), incorporated by

7560

reference in Section 225.140; and

7561

7562

The information and

hourly

data

required

in subections (a) and

(b)

7563

of this Section, except for:

7564

7565

Descriptions of

adjustments,

corrective action, and

7566

maintenance;

JCAR350225-081 8507r01

7567

7568

jj)

Information which

incompatible

with

electronic

reporting

7569

(e.g., field

data

sheets,

lab

analyses,

quality

control

plan);

7570

7571

jj)

For units

with

flue gas

desulfurization systems

with

add-

7572

on mercury

emission

controls,

the parametric

information

7573

in Section

1.12

of this

Appendix;

7574

7575

jy)

Information

required

by Section

1.11(d)

this

Appendix

7576

concerning

the

causes

of any

missing

data

periods

and

the

7577

actions

taken

to cure

those

causes;

7578

7579

Hardcopy

monitoring

plan

information

required

Section

7580

1.10

of this

Appendix

and hardcopy

test data

and results

7581

required

Section

1.13 of

this

Appendix;

7582

7583

yj)

Records

flow

polynomial

equations

and

numerical

7584

values

required

by Section

1.13(a)(5)(E)

this

Appendix;

7585

7586

yjj)

Stratification

test results

required

part of

the

RATA

7587

supplementary records

under

Section

1.13(a)(7)

this

7588

Appendix;

7589

7590

yjji

Data and

results

of RATAs

that

are aborted

invalidated

7591

due to

problems

with

the

reference

method

operational

7592

problems

with

the unit

and data

and

results

liney

7593

checks

that

are

aborted

invalidated

due to

operational

7594

problems

with

the

unit;

7595

7596

jy)

Supplementary RATA

information

required

under

Section

7597

1.1 3(a)(7)

this Appendix,

except

that:

the

applicable

data

7598

elements

under

Section

1.13(a)(7)(B)(i)

through

(xx)

of this

7599

Appendix

and

under

Section

1.13

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

through

(xiii)

7600

of this

Appendix

must

reported

for

flow

RATAs

7601

circular

or rectangular stacks

(or

ducts)

in which

angular

7602

compensation for yaw

and/or

pitch

angles

used

(i.e.,

7603

Method

2G in

appendices

A-i and

A-2

40 CFR

60,

7604

incorporated

reference

in Section

225.140),

with

7605

without

wall

effects

adjustments;

the

applicable

data

7606

elements

under

Section

1.13(a)(7)(B)(i)

through

(xx)

this

7607

Appendix

and

under

Section

1.1

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

through

(xiii)

7608

this Appendix

must

reported

for any

flow

RATA

run

7609

at a circular

stack

in which

Method

2 in

appendices

A-i

JCAR350225-08

8507r01

7610

and A-2 to 40 CFR

60,

incorporated

reference in

Section

7611

225.140, is

used and a wall effects

adjustment

factor

7612

determined by direct measurement;

the data

under

Section

7613

1.13(a)(7)(B)(xx)

of this Appendix must be reported

for all

7614

flow RATAs

at circular stacks in which Method 2 in

7615

appendices

A-i and A-2 to 40 CFR 60, incorporated by

7616

reference in Section 225.140,

is used and a default wall

7617

effects

adjustment

factor is applied; and the data under

7618

Section 1.1

3(a)(7)(I)(i)

through (vi) must be reported for

all

7619

flow RATAs at rectangular

stacks or

ducts in which

7620

Method 2

in appendices A-i and A-2 to 40 CFR 60,

7621

incorporated

reference in

Section

225.140,

used and a

7622

wall effects

adjustment

factor

is applied.

7623

7624

)

For units using

sorbent trap monitoring systems, the hourly

7625

gas flow meter readings taken between the initial and

final

7626

meter readings

for the data collection period; and

7627

7628

Ounces

mercury

emitted during quarter and cumulative ounces

7629

of mercury emitted in the year-to-date (rounded

the

nearest

7630

thousandth);

and

7631

7632

Unit or

stack operating hours for quarter, cumulative unit or

stack

7633

operating hours

for year-to-date;

and

7634

7635

)

Reporting period heat input (if applicable) and cumulative,

year-to-

7636

date heat input.

7637

7638

)

Compliance certification.

7639

7640

The designated

representative must certify that the monitoring

plan

7641

information in each quarterly electronic report (i.e., component

and

7642

system identification

codes, formulas,

etc.)

represent current

7643

operating conditions for the affected units.

7644

7645

The designated

representative

must submit and

sign

a compliance

7646

certification in support of each quarterly emissions monitoring

7647

report

based on

reasonable

inquiry of those persons with primary

7648

responsibility for ensuring

that all of the unit’s emissions are

7649

correctly and

fully

monitored.

The certification

must state that:

7650

7651

The monitoring data submitted were recorded in

7652

accordance with

the applicable requirements of this

JCAR350225-08

1 8507r01

7653

Appendix,

including

the

quality assurance

procedures

and

7654

specifications;

and

7655

7656

j.fl

With regard

to a unit with an

FGD

system

with

add-on

7657

mercury emission

controls,

that for all hours where

7658

mercury data

is missing

in accordance with Section

1.13(b)

7659

of this

Appendix,

the

add-on emission controls

were

7660

operating

within the range

of parameters listed

the

7661

quality-assurance

plan

for the unit

(or

that

quality-assured

7662

CEMS data were available

document

proper

7663

operation

of the emission

controls).

7664

7665

)

Additional reporting

requirements.

The designated representative

must

7666

also

comply with

all of the quarterly reporting

requirements

in 40

CFR

7667

75.64(d),

(f),

and

(g),

incorporated

by reference in Section

225.140.

7668

JCAR350225-081

8507r01

7669

Exhibit A to

Appendix

B — Specifications and Test Procedures

7670

7671

1. Installation and Measurement Location

7672

7673

1.1 Gas and Mercury Monitors

7674

7675

Following the procedures in Section 8.1.1 of Performance Specification 2

in Appendix B to

7676

CFR 60, incorporated by reference in Section 225.140, install the pollutant concentration

7677

monitor or

monitoring

system

location

where the pollutant concentration and emission rate

7678

measurements are directly representative of the total emissions from

the affected

unit. Select

7679

representative

measurement

point or path for the monitor probes (or for the path from the

7680

transmitter to the

receiver)

such that the

concentration monitoring system, mercury

7681

concentration

monitoring

system,

sorbent

trap monitoring system will pass the relative

7682

accuracy test (see Section 6 of this Exhibit).

7683

7684

It is

recommended that monitor measurements be made at locations where the exhaust gas

7685

temperature is above

the dew-point temperature.

If the cause of

failure

to meet the relative

7686

accuracy tests

is determined to be the measurement location, relocate the monitor probes.

7687

7688

1.1.1 Point Monitors

7689

7690

Locate the

measurement point (1) within the centroidal area of the stack or duct cross section,

7691

(2)

no less

than 1.0 meter from the stack or duct wall.

7692

7693

1.2 Flow

Monitors

7694

7695

Install

the flow monitor in a location that provides representative volumetric flow over all

7696

operating

conditions. Such a location is one that provides an average velocity of the

flue gas flow

7697

over the

stack

or duct cross section and is representative of the pollutant concentration monitor

7698

location. Where

the moisture content of the flue gas affects volumetric flow measurements,

use

7699

the

procedures in both Reference Methods 1 and

of appendix A to 40 CFR 60, incorporated

7700

reference in

Section 225.140, to establish a proper location for the flow monitor. The Illinois

7701

EPA

recommends

(but

does

not

require) performing

a flow profile study following the

7702

procedures in

40 CFR 60, appendix A, Method 1, Sections 11.5 or 11.4, incorporated

7703

reference

in Section

225.140,

for

each

of the three operating or load levels indicated in Section

7704

6.5.2.1 of this

Exhibit to determine the acceptability of the potential flow monitor location

and to

7705

determine

the number and location of flow sampling points required to obtain a

representative

7706

flow

value. The procedure in

40 CFR

60, appendix A, Test Method 1, Section 11.5, incorporated

7707

reference in Section

225.140, may be used even

if the flow measurement location is greater

7708

than

or equal to

2 equivalent stack or duct diameters downstream or greater than

or equal to

7709

duct

diameter upstream from a flow disturbance. If a flow profile study shows that cyclonic

(or

7710

swirling)

or stratified flow conditions exist at the potential flow monitor location that are likely

7711

prevent the

monitor from meeting the

performance specifications of this part, then the Agency

JCAR350225-08

1 8507r01

7712

recommends

either (1) selecting

another

location where there is

no cyclonic

(or

swirling) or

7713

stratified flow condition, or (2) eliminating the

cyclonic

(or

swirling) or stratified flow condition

7714

by straightening the flow, e.g., by installing straightening vanes.

The Agency also recommends

7715

selecting

flow

monitor locations

to minimize

the effects of condensation, coating, erosion,

7716

other

conditions that

could adversely affect

flow

monitor performance.

7717

7718

1.2.1 Acceptability of Monitor

Location

7719

7720

The installation

of a

flow monitor is acceptable

if either (1) the location satisfies the minimum

7721

siting criteria of Method 1 in appendix A to 40 CFR 60, incorporated

reference

in Section

7722

225.140

(i.e.,

the

location is greater than or equal

to eight stack or duct diameters downstream

7723

and two diameters upstream from a flow

disturbance;

or, if necessary,

two stack

duct

7724

diameters downstream and one-half stack or

duct diameter upstream from a flow disturbance),

7725

(2) the results of a flow profile study, if performed, are acceptable (i.e., there are no cyclonic

(or

7726

swirling) or stratified flow

conditions),

and the

flow

monitor

also satisfies the performance

7727

specifications of this part. If

the flow

monitor is installed in a location that does not satisfy

these

7728

physical criteria, but nevertheless the monitor achieves

the performance specifications of this

7729

part, then the location is acceptable, notwithstanding the requirements of this Section.

7730

7731

1.2.2 Alternative Monitoring

Location

7732

7733

Whenever the owner or operator successfully demonstrates that modifications to the exhaust

duct

7734

or stack (such as

installation of straightening

vanes, modifications of ductwork, and the like)

are

7735

necessary for the

flow monitor to meet the

performance specifications, the Agency may approve

7736

an interim

alternative flow monitoring methodology and an

extension to the required certification

7737

date

for the flow monitor.

7738

7739

Where no

location exists that satisfies the physical siting criteria in Section 1.2.1,

where the

7740

results of flow

profile studies performed

at two or more

alternative

flow monitor locations

are

7741

unacceptable, or where installation of a flow monitor in either the stack or the

ducts is

7742

demonstrated to

be technically infeasible, the

owner or operator may petition the Agency

for an

7743

alternative method for monitoring flow.

7744

7745

Equipment Specifications

7746

7747

2.1

Instrument Span and Range

7748

7749

implementing

Sections 2.1.1 through 2.1.2

of this Exhibit, set the measurement range for

each

7750 parameter (COQ

or flow

rate)

high enough

to prevent

full-scale

exceedances

from occurring,

7751

yet low

enough to ensure good measurement accuracy and to maintain a

high signal-to-noise

7752

ratio. To

meet these

objectives,

select the range such that the majority of the readings

obtained

7753

during typical

unit operation are kept,

to the extent practicable, between 20.0 and

80.0

percent

7754

the

full-scale

range of the instrument.

JCAR350225-081 8507r01

7755

7756

2.1.1

CO2

and

Monitors

7757

7758

For an

monitor (including

monitors

used to measure CO2 emissions or percentage

7759

moisture), select a span value between 15.0 and 25.0 percent

02.

For a CO2monitor installed on

7760

a boiler, select a span value between 14.0 and 20.0 percent

2.For a CO2

monitor installed

on a

7761

combustion turbine, an

alternative

span value between 6.0 and 14.0 percent

CO1

may be used.

7762

alternative

CQ2

span value below

6.0 percent may be used if an appropriate technical

7763

justification is included in the

hardcopy

monitoring plan. An alternative

span

value below

7764

15.0 percent

may be

used

an appropriate technical justification is included in the

7765

monitoring plan (e.gQ

2concentrations above a certain level create

an unsafe

operating

7766

condition).

Select

the

full-scale

range of the instrument to be consistent with Section 2.1 of this

7767

Exhibit and to be greater than or equal to the span value. Select the calibration

gas

concentrations

7768

for the

daily calibration error tests

and

linearity

checks in accordance with Section 5.1 of this

7769

Exhibit, as percentages of the span value. For

monitors with span values

21.0 percent

7770

purified

instrument

air containing 20.9 percent

may

be used

as the high-level calibration

7771

material. If a dual-range or autoranging diluent analyzer is installed, the analyzer may

7772

represented in the

monitoring plan as a single

component, using a special component type code

7773

specified

the USEPA to satisfy the requirements of 40 CFR 75.53(e)(1)(iv)(D), incorporated

7774

reference in Section

225.140.

7775

7776

2.1.2

Flow Monitors

7777

7778

Select the

full-scale range of the flow monitor so that it is consistent with Section 2.1

of this

7779

Exhibit and can accurately measure all potential volumetric flow rates at the flow monitor

7780

installation site.

7781

7782

2.1.2.1 Maximum

Potential Velocity and Flow Rate

7783

7784

For

this purpose,

determine

the

span value

of the flow monitor using the following procedure.

7785

Calculate

the maximum potential velocity

(MPV)

using Equation A-3a or A-3b

determine

the

7786

MPV

(wet basis)

from

velocity traverse testing

using Reference Method 2

(or

its allowable

7787

alternatives)

in appendix A to

CFR 60,

incorporated

reference in Section 225.140. If

using

7788

test

values, use

the

highest average velocity

(determined

from the Method 2 traverses) measured

7789

at or near

the maximum unit operating load

(or,

for units that

not produce electrical

or thermal

7790

output,

at the normal process

operating

conditions corresponding to the maximum stack gas

flow

7791

rate).

Express

the MPV in units of wet standard

feet

per minute

(fm).

For the purpose of

7792

providing

substitute data during periods of missing flow rate data in accordance with 40

CFR

7793

75.31

and 75.33 and as required elsewhere in this part, calculate the maximum potential stack

7794

gas

flow rate

(MPF) in

units

of standard

cubic feet per hour

(scfh),

as the product of the MPV

(in

7795

units

of wet,

standard fpm) times 60, times the cross-sectional

area of the stack or duct (in

7796

the

flow

monitor location.

7797

JCAR350225-081 8507r01

7798

(‘FdH

209

100

7799

MPV

= I

(Equation

A-3a)

20•9

— %02d

,A\100

— %H2

7800

7801

7802

MPV

100

(Equation A-3b)

J%CO

d,A\l00—%H2

7803

7804

Where:

7805

MPV

maximum potential velocity

(fpm, standard wet

basis).

= dry-basis

F factor

(dscf/mmBtu)

from Table 1, Section 3.3.5 of

Appendix F, 40 CFR 75.

= carbon-based

F factor

(scfCO

/mmBtu)

from Table 1, Section

3.3.5

of Appendix F, 40 CFR 75.

maximum heat

input

(mmBtu/minute)

for all units, combined,

exhausting to the stack or duct where the flow monitor is located.

= inside cross sectional area

)

(ft

of the flue at the flow monitor

location.

= maximum oxygen concentration, percent dry basis, under

normal

operating conditions.

%CO

= minimum

carbon dioxide concentration, percent dry basis, under

normal operating

conditions.

= maximum percent

flue gas

moisture

content

under normal operating

conditions.

7806

7807

2.1.2.2

Span

Values and Range

7808

7809

Determine the span and

range of the

flow monitor as follows. Convert the MPV, as determined

7810

Section 2.1

.2.1 of this Exhibit, to the same measurement units

flow rate

that are used for

7811

daily

calibration

error tests

(e.g.,

scth,

kscfh, kacfm, or differential pressure

(inches

of water)).

7812

Next, determine the

“calibration span value”

by multiplying the MPV

(converted

to equivalent

7813

daily

calibration

error

units)

by a factor no less than 1.00 and no greater than 1.25, and

rounding

7814

up the

result

at least tvo

significant

figures. For calibration span values in inches of water,

7815

retain

at least two

decimal places. Select

appropriate reference signals for the daily calibration

7816

error tests as

percentages of the calibration

span

value,

as specified in Section

2.2.2.1

of this

7817

Exhibit. Finally,

calculate the “flow rate span value” (in scth) as

the product of

the

MPF, as

7818

determined in

Section 2.1.2.1 of

this

Exhibit, times the same factor

(between

1.00

and 1.25)

that

7819

was used

to calculate the

calibration

span value. Round off the flow rate span value to the

nearest

JCAR350225-081 8507r01

7820

1000 scth. Select the full-scale

range

of the flow monitor so that

it is greater

than

or equal to the

7821

span value and is consistent with Section 2.1

of this

Exhibit.

Include in the monitoring plan for

7822

the

unit: calculations

of the MPV, MPF, calibration span value,

flow

rate span

value,

and full-

7823

scale range

(expressed

both in scth

and, if different, in the measurement

units of

calibration).

7824

7825

2.1.2.3

Adjustment

Span

and Range

7826

7827

For

each affected unit or common

stack, the owner or operator must make

periodic

evaluation

7828

of the MPV, span, and range values for each flow

rate monitor (at a minimum, an annual

7829

evaluation

required)

and must make any necessary span and range

adjustments with

7830

corresponding monitoring

plan

updates,

as described in subsections

(a)

through (c) of this

7831

Section

2.1.2.3.

Span and range

adjustments

may be

required,

for example,

as a result of changes

7832

in the fuel supply, changes in the stack or ductwork

configuration, changes in the manner

7833

operation of the

unit, or installation

or removal of emission controls. In implementing

the

7834

provisions in subsections (a) and

(b)

of this Section 2.1.2.3,

note that flow rate data recorded

7835

during short-term,

non-representative

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

type of

7836

fuel) must be excluded from consideration. The owner

or operator must keep the results of the

7837

most recent span and range

evaluation

on-site, in a format suitable for inspection. Make

each

7838

required span or range adjustment no later

than

days after the end of the quarter in which

the

7839

need to adjust the span or range is identified.

7840

7841

the fuel

supply,

stack or ductwork configuration, operating parameters,

or other

7842

conditions change

such that the maximum potential flow rate changes

7843

significantly, adjust the

span and range to assure the continued accuracy of

the

7844

flow

monitor. A

flsignificantH

change in the

MPV means that the guidelines

7845

Section

2.1

of this Exhibit can no longer bernet, as determined

either

7846

periodic evaluation

the owner

or operator or from the results of an audit

by the

7847

Agency. The owner or operator should evaluate

whether any planned changes

7848

operation of the unit may

affect the flow of the unit or stack and should plan

any

7849

necessary span and range changes needed to

account for these

changes,

so that

7850

they are made in as timely

a manner as practicable to coordinate with the

7851

operational

changes. Calculate the adjusted calibration span and flow rate

span

7852

values using the procedures in Section 2.1.2.2

of this Exhibit.

7853

7854

Whenever the full-scale range

exceeded

during

a quarter, provided that the

7855

exceedance is not caused by a monitor out-of-control

period, report

200.0

percent

7856

the current full-scale

range as the hourly flow rate for each hour of the

full

7857

scale exceedance. If the range is exceeded,

make appropriate adjustments to

the

7858

flow rate span and range to prevent future

full-scale exceedances. Calculate

the

7859

new calibration span value by converting the new flow

rate span value from units

7860

scth to

units

of daily

calibration.

A calibration error test

must be

performed

and

7861

passed to validate data

on the new range.

7862

JCAR350225-08

1 8507r01

7863

Whenever

changes are made

to the

MPV,

full-scale range,

or span value

of the

7864

flow monitor, as described

in subsections

(a) and

(b) of

this

Section, record and

7865

report

(as applicable)

the new full-scale

range setting, calculations

of the

flow rate

7866

span value, calibration

span value,

and MPV in an updated

monitoring

plan

for

7867

the unit. The monitoring

plan

update

must

be made

in the quarter in which

the

7868

changes become

effective. Record

and

report

the

adjusted

calibration

span and

7869

reference values

as parts of the

records for the calibration

error test required

7870

Exhibit B to

this Appendix.

Whenever

the calibration

span value is

adjusted,

use

7871

reference

values for the calibration

error test

that meet the

requirements

of Section

7872

2.2.2.1 of this

Exhibit,

based

on the most recent

adjusted calibration

span

value.

7873

Perform

a calibration error test

according to

Section

2.1

.1 of Exhibit

B to this

7874

Appendix whenever

making

a change to the flow

monitor span or range,

unless

7875

the range

change also triggers

a recertification under

Section

1.4

of this Appendix.

7876

7877

2.1.3 Mercury

Monitors

7878

7879

Determine the appropriate

span and range values

for each mercury

pollutant concentration

7880

monitor, so that

all expected

mercury concentrations

can be determined

accurately.

7881

7882

2.1.3.1

Maximum

Potential Concentration

7883

7884

The maximum

potential

concentration

depends

upon

the

type of coal combusted

in the unit.

For

7885

the

initial

MPC

determination, there

are three options:

7886

7887

Use

one

of the following

default values:

igJscm

for bituminous

coal; 10

7888

1g/scm

for sub-bituminous

coal; 16 jig/scm

for lignite, and 1 pig/scm

for

7889

waste

coal, i.e., anthracite

cuim or bituminous

gob. If different

coals are

7890

blended,

use the highest

MPC for any fuel

in the blend; or

7891

7892

)

You may

base the

MPC

on the results of site-specific

emission testing

7893

using

one of the mercury

reference methods in

Section

1.6 of

this

7894

Appendix,

if the unit

does not

have

add-on

mercury emission controls

or a

7895

flue

gas desulfurization system,

or if

you

test upstream

these

control

7896

devices.

A minimum

of 3 test runs are required

at the normal operating

7897

load.

Use

the

highest total

mercury concentration

obtained

any of the

7898

tests as the

MPC:

7899

7900

You may base the MPC

on 720 or more hours

historical

CEMS data

7901

data

from a

sorbent

trap monitoring system,

if the unit

does

not

have

add

7902

mercury emission

controls or a

flue gas desulfurization

system

(or

7903

the CEMS or sorbent

trap

system

is located

upstream

of these control

7904

devices)

and

if the mercury

CEMS or sorbent trap

system has been tested

7905

for relative

accuracy

against one

of the

mercury

reference

methods

JCAR350225-081 8507r01

7906

Section 1.6 of this Appendix and

has met a

relative

accuracy specification

7907

20.0%

less.

7908

7909

2.1.3.2

Maximum Expected Concentration

7910

7911

For units with FGD

systems

that

significantly

reduce

mercury emissions (including fluidized

bed

7912

units that use limestone

injection)

and for units equipped

with add-on mercury emission controls

7913

(e.g., carbon

injection),

determine the maximum expected mercury concentration

(MEC)

during

7914

normal, stable operation of the unit

and emission controls. To calculate the MEC, substitute

the

7915

MPC value from Section 2.1.3.1 of this Exhibit into Equation A-2

in Section 2.1.1.2 of appendix

7916

40 CFR

75,

incorporated

by reference in Section 225.140. For units with add-on

mercury

7917

emission controls, base the percent removal efficiency on

design engineering calculations. For

7918

units

with FGD systems, use the

best available estimate of the mercury removal efficiency

of the

7919

FGD system.

7920

7921

2.1.3.3 Span and Range Values

7922

7923

For each mercury monitor, determine a high

span

value,

by rounding the MPC

7924

value from Section 2.1.3.1

of this Exhibit upward to the next highest

multiple

7925

10 jig/scm.

7926

7927

]

For an affected unit equipped with an FGD system

or a

unit

with add-on mercury

7928

emission controls, if the MEC value from Section 2.1.3.2 of this Exhibit

is less

7929

than

20 percent

of the high span value from subsection

(a)

of this Section,

and if

7930

the high span value is 20

jig/scm or greater, define a second, low span value

of 10

7931

jig/scm.

7932

7933

only a high span value is

required,

set the

full-scale range of the mercury

7934

analyzer

to be greater than or equal to the span value.

7935

7936

ç)

If two

span values

are required, you may either:

7937

7938

Use

two

separate

(high and

low)

measurement scales, setting the range

7939

each scale to be greater than or equal

to the high or low span value, as

7940

appropriate;

7941

7942

)

Quality-assure two segments of a single measurement scale.

7943

7944

2.1.3.4 Adjustment

of Span and Range

7945

7946

For each

affected unit

or common stack, the owner or operator

must make a periodic evaluation

7947

of the MPC,

MEC, span, and range values for each mercury monitor (at

minimum,

an annual

7948

evaluation is

required) and

must

make any

necessary span and range adjustments, with

JCAR350225-081 8507r01

7949

corresponding monitoring

plan

updates.

Span and range

adjustments

may be required, for

7950

example, as a result of changes in the fuel supply, changes

the manner

of operation of the unit,

7951

installation or removal

emission

controls. In implementing the provisions in subsections

(a)

7952

and

(b)

of this Section, data recorded

during

short-term,

non-representative process operating

7953

conditions (e.g., a trial burn of a different type of fuel)

must be

excluded

from consideration.

The

7954

owner or operator must keep the results of the most recent span and range evaluation

on-site, in

7955

format

suitable

for inspection.

Make each required span or range

adjustment

no later than 45

7956

days

after the end of the quarter in which

the need to

adjust

the span or range is identified, except

7957

that up to 90 days after the end of that quarter may

taken

implement

a span

adjustment

7958

the calibration gas

concentrations

currently being

used for calibration error tests,

system

integrity

7959

checks, and linearity checks are unsuitable for use with the

new

span

value and new calibration

7960

materials must be

ordered.

7961

7962

The guidelines of Section 2.1

of this Exhibit do not apply to mercury monitoring

7963

systems.

7964

7965

)

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

caused

7966

by a

monitor out-of-control

period, proceed as follows:

7967

7968

For monitors with a single measurement scale, report that the

system was

7969

out

range and

invalid data was obtained until the readings come

back

7970

on-scale and, if appropriate,

make

adjustments

to the MPC, span, and

7971

range to prevent future full-scale exceedances;

7972

7973

For units with two separate measurement scales, if the low range

7974

exceeded, no further

action

is required, provided that the high range

7975

available and is not out-of-control or out-of-service

for any reason.

7976

However, if the

high range is not able to provide quality assured data

7977

the time of the low range exceedance or

at any

time

during

the

7978

continuation of

the exceedance, report that the system was out-of-control

7979

until the readings return to the low range or until the high range

is able

7980

provide quality assured

data

(unless

the

reason that the high-scale range

7981

not able to provide quality assured data is because the high-scale

range

has

7982

been exceeded; if the

high-scale range is exceeded follow the procedures

7983

in subsection

(b)(1)

of this

Section).

7984

7985

Whenever changes are made to the

MPC,

MEC, full-scale range, or span value

7986

the mercury monitor, record and report (as applicable)

the

new full-scale

range

7987

setting,

the

new MPC

or MEC and calculations of the adjusted span value

in an

7988

updated

monitoring plan. The

monitoring plan update must be made in the

quarter

7989

which the changes become effective.

In addition, record and report the adjusted

7990

span as part of the records for the

daily

calibration

error test and linearity check

7991

specified by

Exhibit

B to this Appendix. Whenever the span value is adjusted,

use

JCAR350225-081 8507r01

7992

calibration gas concentrations that meet the requirements of Section 5.1 of this

7993

Exhibit, based on the adjusted span value.

When a span adjustment is

7994

significant

that the

calibration

gas

concentrations

currently

being used for

7995

calibration error tests, system integrity checks and linearity checks are unsuitable

7996

for use with the new span value, then a

diagnostic linearity

3-level

system

7997

integrity check using the new calibration gas

concentrations

must

be performed

7998

and passed. Use the data validation

procedures in Section 1

.4(b)(3)

of this

7999

Appendix,

beginning with

the hour in which the span is changed.

8000

8001

2.2

Design for Quality

Control Testing

8002

8003

2.2.1 Pollutant Concentration

andQ

Monitors

8004

8005

Design and equip

each pollutant concentration and

CO2

monitor

with a

8006

calibration gas injection port that allows a

check of the entire measurement

8007

system when

calibration

gases are introduced. For extractive and

dilution

type

8008

monitors, all monitoring components exposed

to the sample gas, (e.g., sample

8009

lines,

filters, scrubbers,

conditioners, and as much of the probe as practicable) are

8010

included in

the measurement system. For in-situ type

monitors, the calibration

8011

must

check against the injected gas for the

performance of all active electronic

8012

and

optical components (e.g.,

transmitter, receiver,

analyzer).

8013

8014

])

Design and

equip

each

pollutant concentration or

monitor to allow

8015

daily

determinations of calibration error (positive or

negative) at the zero- and

8016

mid-

or high-level concentrations

specified

Section 5.2 of this Exhibit.

8017

8018

2.2.2 Flow Monitors

8019

8020

Design all

flow monitors to

meet the applicable performance

specifications.

8021

8022

2.2.2.1 Calibration Error Test

8023

8024

Design and

equip each

flow monitor to allow for a daily calibration

error

test consisting of at

8025

least

two reference

values: Zero to

20 percent of span or an equivalent reference

value

(e.g.,

8026

pressure

pulse or electronic

signal) and 50 to 70 percent of span.

Flow monitor response, both

8027

before

and afler any

adjustment, must be capable of

being recorded

the data acquisition and

8028

handling system.

Design each

flow monitor to allow a daily calibration error test

of the entire

8029

flow

monitoring system, from

and including the probe tip

(or

equivalent)

through

and including

8030

the

data

acquisition

and handling system, or the flow

monitoring system from and including the

8031

transducer

through

and including

the

data

acquisition and handling system.

8032

8033

2.2.2.2 Interference Check

8034

JCAR350225-08 1 8507r01

8035

Design and equip each

flow

monitor with a means to ensure that the moisture

8036

expected to occur at

the

monitoring location

does not

interfere with

the proper

8037

functioning of the flow monitoring system. Design and equip each

flow

monitor

8038

with

means to detect,

on at least a daily basis, pluggage of each sample line

and

8039

sensing port, and malfunction

of each resistance temperature

detector

(RTD),

8040

transceiver or equivalent.

8041

8042

])

Design

and

equip

each differential pressure flow monitor to provide an automatic,

8043

periodic back purging (simultaneously

on both

sides

of the

probe)

or equivalent

8044

method of sufficient force and frequency to keep the probe and lines sufficiently

8045

free of obstructions on at least

daily

basis to

prevent velocity sensing

8046

interference, and a means for detecting leaks in the system on at least a quarterly

8047

basis

(manual

check is acceptable).

8048

8049

Design and equip each thermal flow monitor with a means to ensure on

least

8050

daily

basis

that the

probe remains sufficiently clean to

prevent velocity

sensing

8051

interference.

8052

8053

ci)

Design

and equip each ultrasonic flow monitor

with a means to

ensure

on at least

8054

a daily basis that the transceivers remain sufficiently clean (e.g., back purging

8055

system) to prevent velocity sensing interference.

8056

8057

2.2.3

Mercury Monitors

8058

8059

Design and

equip each mercury monitor to

permit

the introduction of known concentrations

8060

elemental mercury and HgC1

2separately, at a point

immediately

preceding the sample extraction

8061

filtration system, such

that the entire measurement system

can be

checked.

the mercury

8062

monitor does

not have a

converter,

the

HgCl2

injection

capability

is not required.

8063

8064

3. Performance Specifications

8065

8066

3.1 Calibration Error

8067

8068

The

calibration error

performance specifications in this Section apply only to

8069

day

calibration error tests under Sections 6.3.1

and

6.3.2 of this Exhibit

and to the

8070

offline calibration demonstration described in Section 2.1 .1.2 of Exhibit B to

this

8071

Appendix. The calibration

error limits for daily operation of the continuous

8072

monitoring

systems

required under this part are

found

in Section 2.1.4(a)

8073

Exhibit B to this Appendix.

8074

8075

The

calibration error

of a mercury concentration monitor must not deviate from

8076

the

reference value of either the zero

or upscale calibration gas by more than

5.0

8077

percent of the span value, as calculated using Equation A-S

this Exhibit.

JCAR350225-08 1 8507r01

8078

Alternatively,

if the span value is

fig/scm,

the

calibration

error test results

are

8079

also acceptable if the absolute

value of the difference between the monitor

8080

response value and the reference

value, R-A in

Equation

A-5 of this Exhibit,

8081

1.0

rig/scm.

8082

8083

100

(Equation A-5)

8084

8085

Where:

8086

CE =

Calibration error as

a percentage of

the

span of the instrument.

Reference

value of 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.

Span of the instrument, as specified in Section 2

this

Exhibit.

8087

8088

8089

3.2

Linearity

Check

8090

8091

For

CO2

monitors (including

monitors

used to measure CO2 emissions or

percent

8092

moisture):

8093

8094

The error in linearity for each calibration gas concentration (low-, mid-,

and high-

8095

levels)

must not exceed

or deviate from the reference value

more than 5.0

8096

percent as calculated using Equation A-4

of this

Exhibit

8097

8098

The absolute

value

of the difference between the average of the monitor

response

8099

values and the average of the reference values,

R-A in Equation A-4 of this

8100

Exhibit, must

be less

than or equal to 0.5 percent

CO2

02,

whichever is less

8101

restrictive.

8102

8103

ç)

For

the linearity check and the 3-level system integrity

check of a mercury

8104

monitor, which are required,

respectively,

under Section 1

.4(c)(

)(B)

and

8105

(c)(1)(E) of this Appendix, the measurement

error must not exceed 10.0 percent

8106

of the reference

value

at any of the three gas levels. To calculate the measurement

8107

error at

each level, take

the absolute value of the difference between the reference

8108

value and mean CEM response,

divide the result by the reference value, and

then

8109

multiply by 100. Alternatively, the results at any

gas level are acceptable if the

8110

absolute value of the difference between the average

monitor response and the

8111

average reference

value,

i.e., R-A in Equation A-4 of this Exhibit, does

not exceed

8112

0.8

.igJm

The principal

and alternative performance specifications in this

8113

Section also apply to the single-level

system

integrity

check described in Section

JCAR350225-08 1 8507r01

8114

2.6 of Exhibit

B to this Appendix.

8115

8116

LE=

xlOO

(EguationA-4)

8117

8118

Where:

8119

LE = Percentage linearity error, based upon the reference

value.

= Reference value of low-, mid-, or high-level calibration

gas

introduced

into the monitoring system.

Average of the monitoring

system

responses.

8120

8121

3.3 Relative Accuracy

8122

8123

3.3.1

Relative

Accuracy for

CO2

and

Monitors

8124

8125

The

relative accuracy for CO

2and

monitors must not exceed 10.0 percent. The relative

8126

accuracy test results

are also acceptable

if the difference between the mean value of the

2or

8127

monitor

measurements and the corresponding reference

method measurement mean value,

8128

calculated using

equation

A-7 of this Exhibit, does not exceed

1.0

percent

CO2or

02.

8129

8130

(Equation A-7)

8131

8132

Where:

8133

= Number

of data points.

The difference between a reference method value

and the

corresponding

continuous

emission monitoring system value

CEM

at a given point in time i.

8134

8135

3.3.2

Relative Accuracy for Flow Monitors

8136

8137

The relative accuracy of flow monitors must not exceed

10.0 percent at any load

8138

(or operating)

level

at which a RATA is performed

(i.e.,

the low-, mid-,

or high-

8139

level,

defined in Section 6.5.2.1

of this Exhibit).

8140

8141

For affected units where the average of the flow reference

method measurements

8142

of gas velocity

a particular load (or operating) level of the relative accuracy

test

8143

audit is less

than or equal

to 10.0 fps, the difference between the mean value

8144

the

flow monitor velocity measurements

and the reference method mean value

8145

fps at that

level

must not exceed

2.0

fps,

wherever

the 10.0 percent

relative

JCAR350225-08 1 8507r01

8146

accuracy specification is not achieved.

8147

8148

3.3.3 Relative Accuracy for

Moisture Monitoring Systems

8149

8150

The relative accuracy

moisture monitoring

system

must

not exceed 10.0 percent.

The

8151

relative accuracy test results are also acceptable

if the difference between the mean

value of the

8152

reference method measurements

(in

percent 0)2

and the corresponding mean value of the

8153

moisture monitoring system measurements (in percent

0),

calculated

using Equation A-7

8154

this Exhibit does not

exceed ± 1.5

percent H

8155

8156

3.3.4 Relative

Accuracy for Mercury Monitoring Systems

8157

8158

The relative accuracy

of a mercury

concentration monitoring

system

or a sorbent trap

monitoring

8159

system must not exceed 20.0 percent. Alternatively,

for affected units

where

the average of

the

8160

reference method

measurements

mercury concentration during the relative accuracy

test audit

8161

is less than 5.0 jig/scm, the test results are

acceptable

if the difference between

the mean value

8162

the monitor

measurements and the

reference method mean value does not exceed 1.0

jig/scm, in

8163

cases

where the relative accuracy specification

20.0

percent is not achieved.

8164

8165

3.4 Bias

8166

8167

3.4.1 Flow Monitors

8168

8169

Flow monitors must not be biased low as determined by the test procedure in

Section 7.4 of this

8170

Exhibit. The bias

specification

applies to all flow monitors including those measuring

an average

8171

gas velocity of 10.0

fps or less.

8172

8173

3.4.2

Mercury Monitoring Systems

8174

8175

Mercury

concentration monitoring

systems and sorbent trap monitoring systems must not

8176

biased

low as determined by the test procedure in Section 7.4 of this Exhibit.

8177

8178

3.5 Cycle Time

8179

8180

The

cycle time for mercury concentration monitors, oxygen monitors used to determine

percent

8181

moisture, and any

other monitoring

component

of a continuous emission monitoring

system that

8182

is required to

perform

a cycle time test must not exceed 15 minutes.

8183

8184

4. Data Acquisition and Handling Systems

8185

8186

Automated

data

acquisition and handling systems must read

and record the full range ofpollutant

8187

concentrations and volumetric flow from zero through span and

provide a continuous, permanent

8188

record

of all measurements and required information as an ASCII flat file capable of

JCAR350225-08

8507r01

8189

transmission both

direct computer-to-computer

electronic transfer via modem and EPA-

8190

provided software and by an IBM-compatible personal computer

diskette. These systems also

8191

must

have the capability of interpreting

and converting the individual output signals from

a flow

8192

monitor, a

CO2

monitor, an

monitor,

a moisture monitoring system, a mercury concentration

8193

monitoring system, and a sorbent trap monitoring system,

produce

a continuous readout of

8194

pollutant emission rates or pollutant mass emissions (as applicable)

the appropriate

units

(çg

8195

lb/hr.

lb/mmBtu, ounces/hr,

tons/hr).

These

systems also must have the capability of interpreting

8196

and converting the individual output

signals from a flow monitor to produce a continuous

8197

readout of pollutant mass emission rates in the units of

the

standard.

Where CO2emissions are

8198

measured

with

continuous

emission monitoring system, the data acquisition and handling

8199

system must also

produce

a readout of

CO2

mass emissions

in tons.

8200

8201

Data acquisition and handling systems must also compute

and

record

monitor

calibration error,

8202 any bias

adjustments to mercury pollutant

concentration data, flow rate data, or mercury emission

8203

rate data.

8204

8205

5. Calibration Gas

8206

8207

5.1 Reference Gases

8208

8209

For the purposes of

this Appendix,

calibration gases include the following:

8210

8211

5.1.1 Standard Reference

Materials

(SRM)

8212

8213

These calibration gases may be obtained from the National Institute of Standards and

8214

Technology (NIST)

at the following

address:

Quince

Orchard

and Cloppers Road, Gaithersburg,

8215

20899-0001.

8216

8217

5.1.2 SRM-Equivalent Compressed

Gas

Primary Reference

Material

(PRM)

8218

8219

Contact the

Gas Metrology Team, Analytical

Chemistry

Division, Chemical

Science and

8220

Technology

Laboratory

of NIST, at

the address in Section 5.1.1, for a list of vendors and

8221

cylinder

gases.

8222

8223

5.1.3

NIST Traceable Reference Materials

8224

8225

Contact the Gas

Metrology Team, Analytical

Chemistry

Division,

Chemical Science and

8226

Technology

Laboratory of NIST, at the address in Section 5.1.1,

for

a list of vendors and

8227

cylinder gases that meet the definition for a NIST Traceable Reference Material (NTRM)

8228

provided in 40 CFR

72.2, incorporated

by reference in Section 225.140.

8229

8230

5.1.4

EPA Protocol

Gases

8231

JCAR350225-08 1 8507r01

8232

An EPA

Protocol

Gas is a calibration

gas

mixture prepared and analyzed

8233

according to Section 2 of the “EPA Traceability

Protocol

for Assay and

8234

Certification

Gaseous

Calibration

Standards”,

September 1997, EPA-600/R-

8235

97/121

such revised procedure

approved

the Administrator

(EPA

8236

Traceability Protocol).

8237

8238

An EPA Protocol Gas must have a specialty gas

producer-certified uncertainty

8239

(95

percent

confidence interval) that must not be greater than 2.0 percent of the

8240

certified concentration

(tag value)

of the gas mixture. The uncertainty must be

8241

calculated using the

statistical

procedures

(or

equivalent statistical techniques)

8242

that

are listed in Section 2.1.8 of the EPA Traceability Protocol.

8243

8244

copy ofEPA-600/R-97/121 is available from the

National Technical

8245

Information

Service, 5285 Port

Royal

Road, Springfield VA, 703-605-6585 or

8246

http ://www.ntis. gov, and from http ://www. epa.

gov/ttnlemc/news.html or http

://

8247

www.epa.

gov/appcdwww/tsb/index.html.

8248

8249

5.1.5

Research

Gas

Mixtures

8250

8251

Research gas

mixtures must be vendor-certified to be within 2.0

percent of the concentration

8252

specified on

the

cylinder

label (tag

value),

using the

uncertainty calculation procedure in Section

8253

2.1.8 of the

“EPA Traceability

Protocol

for

Assay and Certification of Gaseous Calibration

8254

Standards”,

September 1997,

EPA-600/R-97/121. Inquiries about the RGM program should

8255

directed

to: National

Institute

of Standards and Technology, Analytical

Chemistry Division,

8256

Chemical Science

and

Technology Laboratory, B-324 Chemistry,

Gaithersburg MD 20899.

8257

8258

5.1.6 Zero Air Material

8259

8260

Zero air

material is defined

in 40 CFR 72.2, incorporated by reference in Section

225.140.

8261

8262

5.1.7

NIST/EPA-Approved Certified Reference Materials

8263

8264

Existing

certified reference

materials

(CRMs)

that

are still within

their certification

period may

8265

used as

calibration gas.

8266

8267

5.1.8 Gas Manufacturer’s

Intermediate Standards

8268

8269

Gas

manufacturer’s

intermediate standards is defined in 40 CFR

72.2, incorporated

by reference

8270

in Section

225.140.

8271

8272

5.1.9 Mercury Standards

8273

8274

For 7-day

calibration

error

tests

of mercury concentration monitors

and

for daily calibration error

JCAR350225-08 1 8507r01

8275

tests of mercury monitors, either NIST-traceable elemental

mercury

standards (as defined in

8276

Section

225.130)

or a NIST-traceable

source of oxidized mercury (as

defined

in Section

8277

225.130)

maybe used. For linearity checks, NIST-traceable

elemental mercury standards must

8278

be used. For 3-level and single-point system integrity checks under

Section

l.4(c)(l)(E)

of this

8279

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

8280

to this

Appendix, a NIST-traceable

source of oxidized mercury must

be used.

Alternatively,

8281

other NIST-traceable standards may be used

for the required checks, subject to the approval

8282

the Agency.

Notwithstanding

these requirements, mercury calibration

standards that are not

8283

NIST-traceable may

be used for

the tests described in this Section until December 31, 2009.

8284

However, on and after January 1, 2010, only

NIST-traceable calibration standards must be

used

8285

for these tests.

8286

8287

5.2 Concentrations

8288

8289

Four

concentration levels

are required

as follows.

8290

8291

5.2.1 Zero-level

Concentration

8292

8293

0.0 to 20.0 percent of span, including span for high-scale or both low- and high-scale

for

CO2

8294

and

monitors, as

appropriate.

8295

8296

5.2.2 Low-level Concentration

8297

8298

20.0 to 30.0 percent of span,

including

span for high-scale or both low- and high-scale

for

CO2

8299

and

monitors, as

appropriate.

8300

8301

5.2.3

Mid-level Concentration

8302

8303

50.0

60.0

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

and

high-scale for

CO2

8304

and

monitors, as

appropriate.

8305

8306

5.2.4 High-level Concentration

8307

8308

80.0 to 100.0

percent of span, including span for high-scale

or both low-and high-scale for

CO2

8309

andQ2

monitors, as appropriate.

8310

8311

6. Certification Tests and Procedures

8312

8313

6.1

General Requirements

8314

8315

6.1.1 Pretest Preparation

8316

8317

Install the components of the

continuous

emission monitoring system (i.e., pollutant

JCAR350225-08 1 8507r01

8318

concentration monitors,

monitor, and

flow monitor) as specified in Sections 1, 2,

and

8319

3 of this

Exhibit,

and prepare each system component and the combined system

for operation in

8320

accordance

with

the manufacturer’s written instructions.

Operate

the units during each period

8321

when measurements are made. Units may be tested

on non-consecutive days. To the extent

8322

practicable, test the DAHS software prior to testing the monitoring

hardware.

8323

8324

6.1.2

Requirements for Air Emission Testing Bodies

8325

8326

On and after January 1, 2009, any Air Emission Testing

Body

(AETB)

conducting

8327

relative accuracy test

audits

of CEMS and sorbent trap monitoring systems

under

8328

Part 225, Subpart B, must conform to the requirements

ASTM

D7036-04

8329

(incorporated

reference

in Section 225.140). This Section is not applicable

8330

daily operation, daily calibration error checks,

daily

flow

interference

checks,

8331

quarterly linearity checks

routine

maintenance

of CEMS.

8332

8333

The AETB must provide to the

affected sources certification that the AETB

8334

operates in conformance with, and that data submitted to the Agency has

been

8335

collected in accordance

with, the requirements of ASTM D7036-04

(incorporated

8336

by reference in Section

225.140).

This certification may be provided

in the form

8337

ofi

8338

8339

A certificate

accreditation

of relevant scope issued by a recognized,

8340

national accreditation

body;

8341

8342

A letter of certification signed

a member of the senior management

8343

staff

the

AETB.

8344

8345

The AETB must either provide a Qualified Individual on-site to conduct

or must

8346

oversee all relative accuracy testing carried out

the AETB

as required in

8347

ASTM

D7036-04

(incorporated by reference in Section

225.140).

The

Oualified

8348

Individual must

provide

the

affected sources with copies

of the qualification

8349

credentials relevant

to the scope of the testing conducted.

8350

8351

6.2 Linearity

Check (General Procedures)

8352

8353

Check

the linearity of each CO

2.Hg, and

monitor while the unit, or group of units

for a

8354

common stack, is

combusting fuel at conditions

of typical stack temperature and pressure;

it is

8355

not necessary

for the unit to be generating electricity during this test. For

units with two

8356

measurement

ranges

(high

and

low)

for a particular parameter, perform a linearity

check on

both

8357

the

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

perform

linearity

8358

checks, using the

procedures in this Section,

on the

ranges

and at the frequency specified in

8359

Section

2.2.1

of Exhibit B to this Appendix. Challenge each monitor

with calibration gas, as

8360

defined in

Section 5.1 of this Exhibit, at the low-, mid-, and high-range

concentrations specified

JCAR350225-08 1 8507r01

8361

Section

5.2 of this

Exhibit. Introduce the

calibration gas at the gas injection port, as specified

8362

in Section 2.2.1

this Exhibit. Operate each monitor at its normal operating temperature

and

8363

conditions. For

extractive

and dilution

te monitors, pass the calibration gas through all filters,

8364

scrubbers, conditioners, and other monitor components

used

during normal sampling and

8365

through as much

the sampling probe as is practical. For in-situ

monitors, perform

8366

calibration checking all active electronic and optical components, including the transmitter,

8367

receiver, and analyzer.

Challenge

the monitor three times with each reference gas (see example

8368

data sheet in Figure

1). Do not use the same

gas

twice in

succession. To the extent

practicable,

8369

the

duration of each linearity test, from the hour of the first injection

the hour of the

last

8370

injection,

must not

exceed

24 unit

operating hours. Record the monitor response from the data

8371

acquisition and handling system. For each concentration, use the average of the responses

8372

determine the error in

linearity using

Equation A-4 in this Exhibit. Linearity checks are

8373

acceptable

for monitor or monitoring system certification, recertification, or quality assurance

8374

none of the test

results

exceed the applicable

performance

specifications

in Section

3.2

of this

8375

Exhibit. The status of emission data from a CEMS prior to and during a

linearity

test

period

must

8376

be determined as

follows:

8377

8378

For the

initial certification

of a CEMS, data from the monitoring system are

8379

considered invalid until all certification tests, including the linearity test,

have

8380

been

successfully

completed, unless the conditional data validation procedures

8381

Section 1.4(b)(3) of this Appendix are used. When the procedures in Section

8382

1 .4(b)(3)

of this Appendix

are

followed, the words

‘initia1 certification’ apply

8383

instead of 11

recertification”, and complete all of the initial certification

tests by

8384

January 1, 2009, rather than within the time periods specified in Section

8385

1.4(b)(3)(D)

of this Appendix for the individual tests.

8386

8387

For the routine quality assurance linearity checks required

Section 2.2.1

8388

Exhibit B to this Appendix, use the data validation procedures in Section 2.2.3

8389

Exhibit B to this Appendix.

8390

8391

When a linearity test is required as a diagnostic test or for recertification,

use the

8392

data

validation procedures

in Section

1.4

(b)(3)

of this Appendix.

8393

8394

For

linearity tests of non-redundant backup monitoring

systems, use the data

8395

validation procedures in Section 1

.4(d)(2)(C)

of this Appendix.

8396

8397

For

linearity tests performed during a grace period

and after the

expiration

of a

8398

grace period, use the data validation procedures in Sections 2.2.3 and 2.2.4,

8399

respectively,

of Exhibit B to this Appendix.

8400

8401

For

all other linearity checks,

use

the data validation

procedures in Section 2.2.3

8402

of Exhibit B to this Appendix.

8403

JCAR350225-08 1 8507r01

8404

For mercury monitors,

the

guidelines

in Section 2.2.3 of this Exhibit in

8405

addition

to the applicable procedures in

Section 6.2 when performing the

system

8406

integrity checks

described in Section 1.4(c)(1)(E)

and in Sections 2.1.1, 2.2.1,

and

8407

2.6 of Exhibit B to this Appendix.

8408

8409

For

mercury

concentration monitors,

moisture

is added to the calibration

gas

8410

during the required

linearity checks or system

integrity checks, the moisture

8411

content of the calibration

gas must be accounted for. Under

these circumstances,

8412

the

dry

basis concentration of the calibration

gas must be used to calculate

the

8413

linearity error or

measurement error

(as

applicable).

8414

8415

6.3 7-Day Calibration Error

Test

8416

8417

6.3.1 Gas Monitor

7-day Calibration Error Test

8418

8419

Measure the calibration error of each mercury

concentration monitor

and each

CO2or

8420

monitor while the unit

combusting fuel

(but

not necessarily

generating

electricity)

once

each

8421

day for

consecutive operating days

according to the following procedures.

For mercury

8422

monitors, you may perform this test using either

elemental mercury standards or a

NIST

8423

traceable source of

oxidized

mercury. Also for mercury monitors,

if moisture is added to the

8424

calibration gas,

the added moisture

must

be accounted for and the dry-basis

concentration

of the

8425

calibration gas must be used to calculate

the calibration error.

(In

the event

that unit outages

8426

occur after the commencement of the test,

the 7 consecutive unit operating

days need not be

8427

consecutive calendar days.) Units using dual

span monitors must perform the calibration

error

8428

test on both high- and low-scales of the pollutant concentration

monitor. The calibration error

8429

test procedures

in this Section and in

Section 6.3.2 of this Exhibit must also

be used to

perform

8430

the

daily

assessments

and additional calibration

error tests required under Sections 2.1.1

and

8431

2.1.3 of Exhibit B to

this Appendix.

Do not make manual or automatic

adjustments

to the

8432

monitor settings until after taking measurements

at both zero and high concentration levels

for

8433

that day during the 7-day test. If automatic adjustments are made following

both

injections,

8434

conduct the calibration error test such that the magnitude

of the

adjustments

can be

determined

8435

and recorded.

Record and report test

results

for each

day

using the unadjusted

concentration

8436

measured in the calibration error test prior to making any

manual or automatic adjustments

(i.e.,

8437

resetting the

calibration).

The calibration

error tests should be approximately

24 hours apart,

8438

(unless the

7-day

test is performed over non-consecutive

days). Perform calibration error

tests

8439

both the zero-level

concentration and

high-level concentration,

as specified in Section 5.2

of this

8440

Exhibit.

Alternatively, a mid-level concentration

gas

(50.0

to 60.0

percent

of the span

value)

may

8441

be used

in lieu of the high-level gas, provided that the

mid-level gas is more representative

the

8442

actual stack gas concentrations. Use only calibration gas,

as specified in Section 5.1 of this

8443

Exhibit. Introduce

the

calibration

gas at the gas

injection

port,

specified

in Section 2.2.1

of this

8444

Exhibit. Operate

each monitor in its normal

sampling mode. For extractive

and dilution type

8445

monitors, pass

the calibration gas through all

filters, scrubbers, conditioners,

and other monitor

8446

components used during normal sampling and through

as much of the sampling probe

as is

JCAR350225-081

8507r01

8447

practical. For

in-situ type monitors,

perform calibration, checking all active electronic

and

8448

optical components, including the transmitter, receiver,

and analyzer. Challenge the pollutant

8449

concentration monitors

and

2or

monitors once with

each

calibration

gas. Record the

8450

monitor

response from the data

acquisition and handling

system.

Using Equation A-5

this

8451

Exhibit, determine the calibration error

at each concentration once each day

(at

approximately

8452

24-hour

intervals)

for 7 consecutive days according

to the procedures given in this Section. The

8453

results of a 7-day calibration error test are acceptable for monitor or

monitoring system

8454

certification,

recertification or

diagnostic testing if none of these daily calibration error test

8455

results

exceed the applicable performance specifications

in Section 3.1 of this Exhibit. The status

8456

of emission data from a

gas

monitor prior to and during a 7-day calibration

error test period must

8457

determined as follows:

8458

8459

For initial certification, data from the

monitor are considered invalid until all

8460

certification tests,

including the 7-day calibration error test, have been

8461

successfully completed, unless the conditional

data

validation procedures in

8462

Section 1.4(b)(3)

of this Appendix are used. When the procedures in Section

8463

1.4(b)(3)

of this Appendix are followed, the words

“initial certification” apply

8464

instead

of “recertification”,

and complete all of the initial certification tests

8465

January

1, 2009, rather than within the

time

periods specified in Section

8466

.4(b)(3)(D)

of this Appendix for the individual tests.

8467

8468

When a

7-day calibration

error test is required as a diagnostic test or for

8469

recertification, use the

data

validation

procedures in Section 1

.4(b)(3)

of this

8470

Appendix.

8471

8472

6.3.2

Flow Monitor 7-day Calibration Error Test

8473

8474

Flow monitors

installed on peaking units

(as

defined in 40 CFR 72.2, incorporated

by reference

8475

Section 225.140)

are exempted from the

7-day calibration error test requirements of this

part.

8476

In all other

cases, perform the 7-day calibration error test of a flow monitor, when required

for

8477

certification,

recertification or

diagnostic

testing, according

to the following procedures.

8478

Introduce

the reference signal

corresponding

to the values specified in Section 2.2.2.1

of this

8479

Exhibit to the

probe tip

(or equivalent),

or to the transducer.

During the 7-day certification test

8480

period,

conduct the calibration error test while the unit is operating once each unit operating

day

8481

(as

close to

24-hour intervals as practicable). In the event

that unit

outages occur after the

8482

commencement

of the test, the 7 consecutive operating days need not be

7 consecutive calendar

8483

days.

Record the

flow monitor responses

by means of the data acquisition and handling

system.

8484

Calculate

the

calibration error using Equation

A-6 of

this Exhibit.

Do not perform any corrective

8485

maintenance,

repair, or replacement upon the flow monitor during

the 7-day test period other

8486

than that

required in the quality assurance/quality control plan required

Exhibit B

to this

8487

Appendix.

Do not

make adjustments

between the zero and high reference level measurements

8488

any

day

during

the 7-day test. If the flow

monitor operates within the calibration error

8489

performance

specification

(i.e., less than or equal

3.0 percent

error each day and requiring no

JCAR350225-081 8507r01

8490

corrective

maintenance, repair, or replacement during the 7-day test period), the flow monitor

8491

passes

the calibration error test.

Record all maintenance activities

and the

magnitude of any

8492

adjustments. Record

output readings from the data acquisition and handling system before and

8493

after all

adjustments. Record and report all

calibration

error test results using

the unadjusted

flow

8494

rate

measured in the calibration

error test

prior to resetting

the

calibration. Record all

8495

adjustments made during the

7-day period at the time the

adjustment

is made, and

report

them

8496

the certification or

recertification application. The status of emissions data from a flow monitor

8497

prior to and

during a 7-day calibration error test period must be determined as follows:

8498

8499

For

initial certification, data from the monitor are considered invalid until all

8500

certification tests,

including the

7-day

calibration error test, have been

8501

successfully completed,

unless the conditional data validation procedures in

8502

Section

1.4(b)(3)

of this

Appendix are used. When the procedures in Section

8503

1 .4(b)(3)

of this Appendix are followed, the words “initial

certification”

apply

8504

instead of

“recertification”, and complete all of the initial certification tests by

8505

January 1, 2009, rather than within the time periods specified in

Section

8506

.4(b)(3)(D)

this Appendix for the individual tests.

8507

8508

When a 7-day calibration error test is

required

a diagnostic test or for

8509

recertification,

use the data validation procedures in Section 1 .4(b)(3).

8510

8511

CE=

xlOO

(EquationA-6)

8512

8513

Where:

8514

Calibration error as a percentage

of span.

= Low or high level reference value specified in Section

2.2.2.1

of this

Exhibit.

A = Actual flow

monitor response to the reference value.

= Flow monitor

calibration span value as determined under Section

2.1.2.2 of this Exhibit.

8515

8516

6.3.3

8517

8518

For gas or

flow

monitors installed on peaking units, the exemption

from performing

the 7-day

8519

calibration error

test

applies as long as the unit

continues

meet the definition of a peaking

unit

8520

40 CFR

72.2, incorporated by

reference

Section 225.140. However, if at the end of a

8521

particular

calendar year or

ozone season, it is determined that peaking unit status has been lost,

8522

the owner

operator must perform a diagnostic 7-day calibration error test of

each

monitor

8523

installed on the

unit,

no later than December 31 of

the following calendar year.

JCAR350225-08

1 8507r01

8524

8525

6.4 Cycle Time Test

8526

8527

Perform cycle time tests for each pollutant concentration

monitor and continuous emission

8528

monitoring system while the unit is operating, according

the

following procedures. Use a zero-

8529

level

and

high-level calibration

gas

(as

defined in Section 5.2

of this

Exhibit)

alternately. For

8530

mercury monitors, the calibration gas

used for this test may either be the elemental or

oxidized

8531

form of mercury. To determine the downscale cycle

time,

measure the concentration of the

flue

8532

gas emissions until

the

response stabilizes. Record the stable emissions

value.

Inject

a zero-level

8533

concentration calibration gas into the

probe tip

(or injection

port leading to the calibration

cell,

8534

for in-situ systems with no

probe).

Record the time of the zero

gas

injection,

using the data

8535

acquisition and handling

system

(DAHS).

Next, allow the

monitor to measure the concentration

8536

of the zero gas until the response stabilizes. Record the stable ending

calibration gas reading.

8537

Determine the downscale cycle time as the time it

takes for 95.0 percent of the step change

to be

8538

achieved between

the stable stack

emissions value

and the stable ending zero

gas reading. Then

8539

repeat the procedure, starting with stable stack emissions

and injecting the high-level gas, to

8540

determine the

upscale cycle time,

which is the time it takes for 95.0 percent

of the step change to

8541

achieved between the stable stack emissions value

and the stable

ending

high-level

gas

8542

reading. Use the following criteria to assess when a stable reading

of stack emissions or

8543

calibration gas

concentration has

been attained. A stable

value

is equivalent to

reading with

8544

change of less

than

2.0 percent of the

span

value

for 2 minutes, or a reading with a change

of less

8545

than 6.0

percent from the measured average concentration over

6 minutes. Alternatively, the

8546

reading is considered stable if it changes by no more than

0.5 ppm, 0.5 ig/m

(for

mercury) for

8547

two

minutes.

(Owners

or operators of systems that do not record

data in 1-minute or 3-minute

8548

intervals may petition

the Agency

for alternative stabilization criteria). For monitors

8549

monitoring

systems that

perform

a series of operations

(such

as purge, sample, and analyze),

8550

time

the

injections of the calibration gases so they will produce the

longest possible cycle time.

8551

Refer to Figures 6a

and 6b in this Exhibit

for example calculations of upscale and downscale

8552

cycle times. Report the slower of the two cycle times (upscale or

downscale)

as the cycle time

8553

for the analyzer.

On and after January

2009,

record the cycle time for each component

8554

analyzer separately. For time-shared systems, perform the cycle time

tests at each of the probe

8555

locations that

will be

polled

within

the same 15-minute

period during monitoring system

8556

operations. To

determine

the cycle time for time-shared systems, at each

monitoring location,

8557

report the sum

of the cycle time observed at

that monitoring location plus the sum of the time

8558

required for all purge

cycles

(as

determined by the continuous emission

monitoring system

8559

manufacturer)

each of the probe locations

of the time-shared systems. For monitors with

dual

8560

ranges, report

the test results for each range separately. Cycle

time test results are acceptable

for

8561

monitor or monitoring system certification, recertification or diagnostic

testing

if none of the

8562

cycle

times exceed 15

minutes. The

status of emissions data from a monitor

prior to and during

8563

cycle time test

period must be determined

as follows:

8564

8565

For initial certification, data from the monitor

are considered invalid until all

8566

certification

tests, including the cycle time test, have been

successfully completed,

JCAR350225-08

1 8507r01

8567

unless

the conditional

data validation

procedures

Section 1

.4(b)(3)

this

8568

Appendix are used.

When the procedures

in Section 1.4(b)(3)

of this

Appendix

8569

are

followed,

the

words “initial certification”

apply

instead of “recertification”,

8570

and complete

all of

the

initial certification

tests

by January 1, 2009,

rather than

8571

within the time

periods specified

in Section 1.4(b)(3)(D)

of this

Appendix for the

8572

individual tests.

8573

8574

When a cycle

time test

required

as a diagnostic

test or for

recertification, use

8575

the data

validation procedures

Section

.4(b)(3)

of this Appendix.

8576

8577

6.5

Relative Accuracy and

Bias

Tests

(General

Procedures)

8578

8579

Perform the required relative

accuracy test audits

(RATAs)

as follows for each

flow

monitor,

8580

each

diluent monitor

used to

calculate heat input,

each

mercury

concentration

8581

monitoring system, each

sorbent trap monitoring

system,

and each moisture monitoring

system.

8582

8583

Except

as otherwise

provided

in this

subsection,

perform each RATA

while

the

8584

unit

(or units,

if more

than

one unit exhausts into

the

flue) is

combusting the

fuel

8585

that is

normal primary or backup

fuel for

that unit

(for

some units,

more than

8586

one

type of fuel may be

considered normal,

e.g., a unit that

combusts gas or

oil on

8587

seasonal

basis).

For

units that co-fire fuels

as the predominant

mode of

8588

operation,

perform the

RATAs while

co-firing. For mercury

monitoring

systems,

8589

perform the RATAs

while

the

unit

is combusting coal.

When relative

accuracy

8590

test audits are performed

on CEMS

installed on bypass

stacks/ducts,

use the fuel

8591

normally combusted

by the unit (or

units, if more

than

one unit exhausts

into

the

8592

flue)

when emissions

exhaust

through the bypass stack/ducts.

8593

8594

Perform

each RATA at the load

(or

operating)

levels specified in

Section

6.5.1

8595

6.5.2

of this

Exhibit or in Section

2.3.1.3

of Exhibit

B to this Appendix,

8596

applicable.

8597

8598

For

monitoring

systems

with

dual ranges, perform

the relative

accuracy

test

the

8599

range normally

used for measuring

emissions.

For units with add-on

mercury

8600

controls

that operate

continuously

rather

than seasonally,

or for

units that need

8601

dual range to

record high concentration

“spikes”

during startup conditions,

the

8602

low

range

is considered normal.

However,

for

some dual span units

(e.g.,

for

units

8603

that use fuel

switching or

for

which the emission

controls

are

operated

8604

seasonally),

provided that

both monitor ranges

are connected to

common probe

8605

and

sample interface, either

of the

two

measurement ranges

may be considered

8606

normal; in such

cases,

perform the RATA

the range

that is in use at the

time of

8607

the

scheduled test. If the

low

and

high

measurement

ranges

are connected

8608

separate sample probes

and

interfaces,

RATA testing

both

ranges

is required.

8609

JCAR350225-08 1 8507r01

8610

)

Record monitor or monitoring system

output from the data acquisition and

8611

handling system.

8612

8613

Complete each single-load relative accuracy test

audit within a period of 168

8614

consecutive unit operating hours, as defined in 40

CFR

72.2, incorporated

8615

reference

Section

225.140

(or,

for CEMS installed on common stacks or

bypass

8616

stacks,

168 consecutive stack

operating hours, as defined in 40 CFR 72.2,

8617

incorporated by reference in Section 225.140).

Notwithstanding this requirement,

8618

to 336

consecutive

unit

or stack operating hours may

taken

complete

the

8619

RATA of a mercury monitoring

system, when ASTM 6784-02 (incorporated

8620

reference in Section

225.140)

or Method 29 in appendix A-8

40 CFR

60,

8621

incorporated

reference in Section 225.140,

is used as the reference method. For

8622

2-level and 3-level flow monitor RATAs, complete all of the RATAs at all

levels,

8623

to the extent practicable, within a period

168 consecutive

unit

(or

stack)

8624

operating hours; however, if this is not possible, up to 720 consecutive unit

(or

8625

stack)

operating hours may be taken to complete

a multiple-load flow RATA.

8626

8627

The status of emission data from the CEMS prior

to and during the RATA test

8628

period must be determined as follows:

8629

8630

For the initial certification

of a CEMS, data from the monitoring system

8631

are considered invalid until all certification

tests, including the RATA,

8632

have been successfully

completed,

unless the conditional

data validation

8633

procedures in Section 1

.4(b’)(3)

of this Appendix are used. When

the

8634

procedures

in Section 1 .4(b)(3) of this Appendix are followed, the words

8635

“initial certification”

apply

instead of”recertification”,

and complete all

8636

the initial certification tests

January

1, 2009, rather than within

the time

8637

periods

specified

Section 1.4(b)(3)(D) of this Appendix for the

8638

individual tests.

8639

8640

For the routine quality assurance RATAs required

Section 2.3.1

8641

Exhibit B to this Appendix, use the data validation

procedures in Section

8642

2.3.2

Exhibit

B to this Appendix.

8643

8644

For

recertification

RATAs, use the data validation procedures in

Section

8645

.4(b)(3).

8646

8647

For quality assurance RATAs of non-redundant backup monitoring

8648

systems,

use

the data validation procedures in Section 1 .4(d)(2)(D)

and

(B)

8649

this Appendix.

8650

8651

For RATAs performed during and afier the expiration

of a

grace

period,

8652

use the

data

validation

procedures in Sections 2.3.2 and 2.3.3,

JCAR350225-08 1 8507r01

8653

respectively,

of Exhibit B

to this

Appendix.

8654

8655

)

For all

other RATAs,

use the data validation procedures in Section 2.3.2

8656

Exhibit B to this Appendix.

8657

8658

For each flow monitor, each

diluent

monitor used to

determine

heat

8659

input,

each

moisture

monitoring

system, each mercury concentration monitoring

8660

system, and each sorbent trap monitoring

system, calculate the

relative

accuracy,

8661

in accordance with Section 7.3 of this Exhibit,

as applicable.

8662

8663

6.5.1 Gas and Mercury Monitoring System RATAs

(Special Considerations)

8664

8665

Perform the required relative accuracy test audits

for each CO or

diluent

8666

monitor used to determine heat input,

each

mercury concentration monitoring

8667

system, and each sorbent trap monitoring system at the normal load level or

8668

normal operating level for the unit (or

combined units, if common stack), as

8669

defined in Section 6.5.2.1 of this Exhibit. If two load levels or operating levels

8670

have

been designated as normal,

the RATAs may be done at either load level.

8671

8672

For the initial certification of a gas or mercury monitoring system and for

8673

recertifications in which,

addition to a RATA, one or more other tests are

8674

required

(i.e.,

linearity

test, cycle

time test, or 7-day calibration error test), the

8675

Agency recommends that the RATA not

commenced until the other required

8676

tests of the CEMS have been passed.

8677

8678

6.5.2 Flow Monitor

RATAs (Special Considerations)

8679

8680

Except as otherwise

provided

in subsection

(b)

(e)

of this Section, perform

8681

relative accuracy test audits for the initial certification

of each flow monitor at

8682

three different exhaust gas velocities

(low,

mid, and

high),

corresponding to

three

8683

different load levels or operating levels within the range of operation,

as defined

8684

in Section

6.5.2.1

this Exhibit.

For a common stack/duct, the three different

8685

exhaust gas velocities may be obtained from frequently used unit/load

8686

operating

level combinations

for the units exhausting to the common stack. Select

8687

the

three exhaust gas velocities such that the audit points at adjacent load

8688

operating levels

(i.e.,

low and mid or mid and

high),

in megawatts

(or

8689

thousands of lb/hr of steam

production

or in fl/sec. as applicable), are separated

8690

no less than 25.0 percent of the range of operation,

as defined

Section

8691

6.5.2.1 of this Exhibit.

8692

8693

For

flow monitors on bypass

stacks/ducts and peaking units, the flow monitor

8694

relative accuracy test audits for initial certification

and recertification must be

8695

single-load tests, performed at the normal load,

defined in Section

6.5.2.1(d)

JCAR350225-081

8507r01

8696

this Exhibit.

8697

8698

Flow monitor

recertification

RATAs must be

done

at three

load levels

(or

three

8699

operating

levels), unless

otherwise specified

in subsection

(b)

or (e) of this

8700

Section

unless

otherwise

specified

or approved by the Agency.

8701

8702

ç)

The

semiannual

and annual quality assurance

flow

monitor RATAs required

8703

under Exhibit B to this

Appendix

must be done at the load

levels

(or

operating

8704

levels)

specified

in Section

2.3.1.3

Exhibit

B to

this Appendix.

8705

8706

For flow monitors

installed on units

that do not produce

electrical or thermal

8707

output, the flow RATAs

for initial

certification

recertification

may

be done

8708

fewer than

three

operating levels, if:

8709

8710

The owner

or operator provides

a technical

justification

in the hardcopy

8711

portion of the

monitoring

plan for the unit required

under 40

CFR

8712

75.53(e)(2),

incorporated by reference

Section

225.140,

demonstrating

8713

that the unit

operates

at only

one level or two levels

during normal

8714

operation

(excluding

unit startup

and shutdown).

Appropriate

8715

documentation

and data must

be provided

to support the claim

of single-

8716

level or

two-level

operation

and

8717

8718

)

The justification provided

in subsection

(e)(l)

of this Section

deemed

8719

be acceptable by

the permitting

authority.

8720

8721

6.5.2.1

Range of Operation

and Normal

Load

(or

Operating)

Levels

8722

8723

The

owner or operator

must determine

the upper and lower

boundaries of

the

8724

orange of operation”

as follows for

each

unit (or combination

of units,

for

8725

common

stack configurations):

8726

8727

For affected units

that produce

electrical output (in

megawatts) or

thermal

8728

output

(in

lb/hr

of steam production

mmBtu/hr),

the lower boundary

8729

the range of

operation of a unit

must

be the minimum

safe, stable

loads for

8730

any of the units

discharging through

the stack. Alternatively,

for

group

8731

of frequently

operated units that

serve a common

stack, the sum

of the

8732

minimum safe,

stable

loads

for

the individual units

may

be used

as the

8733

lower boundary

of the range

of operation. The

upper boundary

of the

8734

range

of operation of a unit

must

the

maximum sustainable

load. The

8735

“maximum

sustainable

load” is the higher of

either:

the

nameplate or rated

8736

capacity

of the unit, less

any physical or

regulatory limitations

or other

8737

deratings; or the highest

sustainable

load, based on at least

four

quarters

8738

representative

historical

operating

data. For common

stacks, the

maximum

JCAR350225-08 1 8507r01

8739

sustainable load is

the sum of all

the maximum sustainable loads of the

8740

individual units discharging through the stack,

unless this load is

8741

unattainable in

practice, in which

case

use the highest sustainable

8742

combined load for

the units that discharge through the stack.

Based

on at

8743

least

four quarters of representative historical

operating

data.

The load

8744

values for the units must be expressed either in

units of megawatts of

8745

thousands of lb/hr of

steam load

mmBtu/hr of thermal output; or

8746

8747

)

For affected units that do not produce

electrical or thermal output, the

8748

lower boundary of

the range

operation must be the minimum expected

8749

flue

gas

velocity

(in ft/sec) during normal, stable

operation of the unit.

The

8750

upper boundary of

the range of operation must be the maximum potential

8751

flue gas velocity

(in ft/see)

as defined in Section

2.1.2.1 of this Exhibit.

8752

The minimum

expected and maximum potential

velocities

may be derived

8753

from the results of reference method

testing

using Equation A-3a

8754

A-3b

(as

applicable) in Section 2.1.2.1 of this Exhibit. If

Equation A-3a

8755

A-3b is used to determine the

minimum expected velocity, replace the

8756

word

“maximum” with the word “minimum” in the definitions of “MPV,”

8757

i,”

“%O”,

and “%H

o” and replace the word

“minimum” with the

8758

word “maximum” in the definition of “COj”.

Alternatively, 0.0 ft/sec may

8759

be used as the

lower boundary of the range of operation.

8760

8761

The operating

levels for relative accuracy test audits will,

except

for peaking

8762

units, be

defined as follows: the “low” operating level

will be the first 30.0

8763

percent

of the range of operation; the “mid”

operating level will be the middle

8764

portion

(>30.0

percent,

but

60.0

percent) of the range of

operation;

and the

8765

“high”

operating level will be the upper end

60.0 percent)

of the range of

8766

operation. For example, if the

upper

and

lower boundaries of the range of

8767

operation are

100 and 1100 megawatts, respectively, then

the low, mid, and

high

8768

operating levels would be 100 to

400 megawatts, 400 to 700 megawatts, and 700

8769

1100

megawatts, respectively.

8770

8771

ç)

Units

that do

not produce electrical or thermal output

are exempted from the

8772

requirements of

this subsection

(c).

The owner or operator must identify, for each

8773

affected

unit or common stack, the “normal” load

level

or levels

(low,

mid or

8774

high),

based on the operating

history

of the

units. To identify the normal load

8775

levels, the owner

or operator must, at a minimum, determine the

relative number

8776

operating hours at each of the three load levels, low,

mid and high over the

past

8777

four

representative operating quarters. The owner

or operator must determine,

8778

the

nearest 0.1 percent, the

percentage

the time that each load level

(low,

mid,

8779

high) has been used

during that

time period. A summary of the data used for this

8780

determination and

the

calculated results must be kept on-site in a

format suitable

8781

for

inspection. For new units or newly affected units,

the data analysis in this

JCAR350225-08

1 8507r01

8782

subsection may be based

fewer

than

four

quarters

of data if fewer than four

8783

representative

quarters of historical load data

are available. Or,

if no historical

8784

load data are available,

the

owner or operator

may designate the normal load

8785

based on the expected or projected

manner

of operating the

unit. However, in

8786

either case, once four quarters of representative

data become available,

the

8787

historical

load analysis must be repeated.

8788

8789

ci)

Determination of normal load

(or

operating level)

8790

8791

Based on the analysis

of the historical load data

described in subsection

(c)

8792

of this Section, the owner

or operator must, for units that produce

8793

electrical or thermal

output, designate the most

frequently used load level

8794

as the normal load level for the

unit

(or

combination of units, for common

8795

stacks).

The owner or

operator may also designate the

second

most

8796

frequently used load level as

additional

normal load level for the

unit or

8797

stack. If the manner

of operation of the unit changes significantly,

such

8798

that the designated normal loads or the

two

most frequently used load

8799

levels change, the

owner or

operator

must repeat

the historical

load

8800

analysis and must redesignate

the normal loads and the two most

8801

frequently used load levels, as appropriate.

A minimum of two

8802

representative

quarters of historical load data

are required to document

8803

that a change in the

manner of unit operation has occurred.

Update the

8804

electronic monitoring

plan

whenever

the normal load levels and

the two

8805

most frequently used load levels

are redesignated.

8806

8807

)

For units that

do not produce electrical or thermal

output, the normal

8808

operating levels must

be determined using sound engineering

judgment,

8809

based

on knowledge of the unit and operating

experience with

the

8810

industrial process.

8811

8812

ç)

The owner or operator must report the

upper and lower boundaries of the range

8813

operation for each

unit

(or

combination of units, for common

stacks),

in units

8814

megawatts or thousands of lb/hr or mniBtu/hr

of steam production or fl/sec

(as

8815

applicable), in the electronic

monitoring plan required under

Section 1.10 of this

8816

Appendix.

8817

8818

6.5.2.2 Multi-Load

(or

Multi-Level) Flow RATA Results

8819

8820

For each

multi-load

(or multi-level)

flow RATA, calculate

the flow monitor relative accuracy

8821

each

operating

level.

If a

flow monitor

relative accuracy test is failed

or aborted due to a problem

8822

with

the

monitor on any level of a 2-level

(or

3-level) relative accuracy test

audit, the RATA

8823

must

repeated at that load

(or

operating)

level.

However, the entire 2-level (or 3-level)

relative

8824

accuracy

test audit does not

have

to be repeated

unless

the

flow monitor polynomial coefficients

JCAR350225-081

8507r01

8825

or K-factors

are changed,

which

case a 3-level RATA is required

(or,

a 2-level RATA,

for

8826

units demonstrated to operate at only two levels, under Section

6.5.2(e)

of this Exhibit).

8827

8828

6.5.3

Calculations

8829

8830

Using the data from the relative accuracy test audits, calculate

relative accuracy and bias in

8831

accordance

with

the procedures and equations specified in Section

7 of this

Exhibit.

8832

8833

6.5.4 Reference Method Measurement

Location

8834

8835

Select

location for reference method measurements

that

(1)

accessible; (2) in the same

8836

proximity as the monitor or monitoring system location; and

(3)

meets the requirements

8837

Performance Specification 3 in appendix B of 40 CFR

60,

incorporated

by reference in Section

8838

225.140, for CO

2or

monitors,

or Method 1 (or

1A)

in appendix A of 40 CFR 60, incorporated

8839

reference

in Section 225.140, for volumetric flow, except as

otherwise indicated in this

8840

Section or as approved by

the Agency.

8841

8842

6.5.5 Reference Method Traverse Point Selection

8843

8844

Select

traverse points that ensure acquisition of representative samples

pollutant

and diluent

8845

concentrations, moisture content, temperature, and flue gas flow rate over the flue cross

Section.

8846

achieve this, the reference method

traverse

points must meet the requirements of Section

8847

8.1.3 of Performance

Specification 2 (“PS

No.

2”)

in appendix B to 40 CFR 60, incorporated

8848

reference in Section

225.140

(for

moisture monitoring

system

RATAs),

Performance

8849

Specification 3

in appendix B to 40 CFR 60, incorporated

reference

Section 225.140

(for

8850

and C0

monitor

RATAs),

Method 1

(or 1A) (for

volumetric

flow rate monitor RATAs),

8851

Method 3

(for

molecular

weight),

and Method 4

(for

moisture determination) in appendix

A to

8852

40 CFR 60,

incorporated

by reference in Section 225.140. The following alternative

reference

8853

method traverse point

locations are permitted for

moisture and gas monitor RATAs:

8854

8855

For

moisture determinations where

the moisture data are used only to determine

8856

stack gas molecular weight, a single reference method point, located at least

1.0

8857

meter from the stack wall, may be

used.

For

moisture

monitoring system RATAs

8858

and for gas monitor

RATAs

in which moisture data are used to correct

pollutant

8859

diluent concentrations from a dry

basis to a wet basis (or

vice-versa),

single-

8860

point moisture sampling may only be used if the 12-point stratification

test

8861

described

in Section

6.5.5.1

of this Exhibit is performed prior to the RATA

for at

8862

least

one pollutant or diluent gas,

and

if the

test is passed according to the

8863

acceptance criteria in Section

6.5.5.3(b)

of this Exhibit.

8864

8865

]

For gas monitoring

system

RATAs, the owner or operator may use any of the

8866

following

options:

8867

JCAR350225-081 8507r01

8868

At any location (including locations where

stratification is expected), use a

8869

minimum of six

traverse points along a diameter, in the direction of

any

8870

expected stratification. The

points must be located in accordance with

8871

Method 1 in appendix A to 40 CFR 60, incorporated

reference

8872

Section

225.140.

8873

8874

)

At locations where Section

8.1.3 of PS No. 2 allows the use of a short

8875

reference method measurement line

(with

three

points located

0.4,

1.2,

8876

and

2.0 meters

from the stack wall), the owner or operator may use

8877

alternative 3-point measurement line,

locating the three points at 4.4, 14.6,

8878

and

29.6

percent of the way across the stack, in accordance with Method

8879

appendix A to 40 CFR

60,

incorporated

by reference in Section

8880

225.140.

8881

8882

)

At locations

where stratification is likely to occur (e.g., following a wet

8883

scrubber or when dissimilar gas streams are

combined),

the short

8884

measurement line

from Section 8.1.3 of PS No.

(or the alternative line

8885

described in subsection

(b)(2)

of this Section) may

used in lieu

of the

8886

prescribed

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

8887

that the 12-point stratification

test

described

in Section 6.5.5.1 of this

8888

Exhibit is performed and passed one time

at the location (according to the

8889

acceptance criteria of Section

6.5.5.3(a)

of this

Exhibit)

and provided

that

8890

either the 12-point stratification test or the alternative (abbreviated)

8891

stratification

test in Section 6.5.5.2 of this Exhibit is performed and

passed

8892

prior to each

subsequent RATA at the location (according to the

8893

acceptance criteria of Section 6.5.5.3(a) of this Exhibit).

8894

8895

A single reference method measurement

point, located no

less

than 1.0

8896

meter from the stack wall and situated along one of the measurement

lines

8897

used for the stratification

test,

may be

used at any

sampling location

if the

8898

12-point

stratification test described in Section 6.5.5.1 of this Exhibit

8899

performed and passed prior to each RATA

the location (according

to the

8900

acceptance criteria

of Section 6.5.5.3(b) of this Exhibit).

8901

8902

çj

For

mercury monitoring

systems, use the same basic approach for traverse

point

8903

selection that is used for the other

gas

monitoring

system RATAs, except that the

8904

stratification test provisions in Sections 8.1.3

through

8.1.3.5 of Method

3 OA must

8905

apply, rather

than

the provisions

of Sections 6.5.5.1 through 6.5.5.3 of this

8906

Exhibit.

8907

8908

6.5.5.1 Stratification Test

8909

8910

With the units

operating under

steady-state conditions at the normal load level

(or

JCAR350225-081 8507r01

8911

normal operating level),

defined

in Section 6.5.2.1 of this Exhibit, use a

8912

traversing

gas sampling probe to measure diluent

(CO2

02)

concentrations

8913

minimum of 12 points, located

according to Method 1 in appendix A to 40

CFR

8914

60, incorporated by reference in Section 225.140.

8915

8916

Use

Method

3A in appendix A to 40 CFR 60, incorporated

reference in

8917

Section 225.140, to make

the measurements. Data from the reference method

8918

analyzers must be quality assured

performing

analyzer calibration error and

8919

system

bias

checks before the series of measurements and

conducting

system

8920

bias and

calibration drift checks

after

the measurements, in accordance with the

8921

procedures of Method 3A.

8922

8923

Measure for a minimum of 2 minutes at each traverse point. To the extent

8924

practicable, complete the traverse within

2-hour period.

8925

8926

)

If the load has remained constant

(±

3.0

percent)

during

the traverse and if the

8927

reference method analyzers

have

passed all of the required quality assurance

8928

checks, proceed with the data analysis.

8929

8930

ç)

Calculate

the average

CO2

(or 02)

concentrations at each of the individual

8931

traverse

points.

Then, calculate

the

arithmetic

average

(or

02)

concentrations

8932

for all traverse points.

8933

8934

6.5.5.2 Alternative

(Abbreviated) Stratification Test

8935

8936

With the units operating under steady-state

conditions at the normal load level

(or

8937

normal operating

level),

as defined in Section 6.5.2.1 of this Exhibit,

use a

8938

traversing gas sampling

probe

to measure the diluent

(CO2

02)

concentrations

8939

at three points. The points must be located according

the specifications

for the

8940

long

measurement line in Section

8.1.3 of PS No. 2 (i.e., locate the points 16.7

8941

percent, 50.0

percent,

and 83.3 percent of the way across the

stack).

Alternatively,

8942

the

concentration measurements may be

made

at six traverse points along a

8943

diameter. The

six points

must be located in accordance with Method 1 in

8944

appendix A to 40 CFR 60, incorporated

by reference in Section 225.140.

8945

8946

Use

Method 3A in appendix A

CFR 60, incorporated by reference in

8947

Section 225.140, to make the measurements.

Data from the reference method

8948

analyzers must be

quality

assured

by performing analyzer calibration error

and

8949

system

bias checks before

the series of measurements and

conducting

system

8950

bias

and

calibration drift checks

after the measurements, in accordance with

the

8951

procedures

of Method 3A.

8952

8953

Measure

for a

minimum

of 2 minutes at each traverse point. To the extent

JCAR350225-081 8507r01

8954

practicable, complete

the traverse within

a 1-hour period.

8955

8956

If the load has

remained

constant

(±

3.0

percent)

during the traverse and if the

8957

reference method analyzers

have

passed all of the required

quality assurance

8958

checks, proceed with the data

analysis.

8959

8960

Calculate the

average

CO2

(or

02)

concentrations

at each of the individual

8961

traverse points. Then,

calculate the arithmetic average

CO2

(or

02)

concentrations

8962

for all traverse points.

8963

8964

6.5.5.3 Stratification

Test Results and Acceptance Criteria

8965

8966

For each diluent gas, the

short reference method measurement line described

8967

Section

8.1.3 of PS No. 2 maybe used in lieu of the long

measurement line

8968

prescribed in Section 8.1.3

of PS No.

if the results of a stratification test,

8969

conducted in accordance

with Section 6.5.5.1 or 6.5.5.2

this Exhibit

(as

8970

appropriate see Section

6.5.5(b)(3)

of this Exhibit), show that the concentration

8971

each

individual

traverse

point

differs by no more

than

10.0 percent from the

8972

arithmetic average concentration

for all traverse points. The results are also

8973

acceptable if the concentration

each individual

traverse

point differs by no

8974

than

Sppm or

0.5 percent

CO2

(or

02)

from

the arithmetic average

8975

concentration

for all traverse

points.

8976

8977

For

each diluent gas,

a single reference method measurement point, located

8978

least 1.0 meter from the stack wall

and situated along one of the measurement

8979

lines used for the stratification test, may be used for

that diluent gas if the results

8980

of a

stratification test,

conducted in accordance with Section 6.5.5.1 of

this

8981

Exhibit, show that the concentration at each

individual traverse point differs

by no

8982

than

5.0

percent from the arithmetic average concentration for

all traverse

8983

points. The results are also acceptable if the

concentration at each individual

8984

traverse point differs

by no more than

3 ppm or

0.3 percent

CO2

(or

from

8985

the arithmetic average concentration for all traverse

points.

8986

8987

The owner or operator must keep the results of

all stratification tests on-site, in

8988

format suitable for inspection,

as part of the supplementary RATA records

8989

required under Section 1.1

3(a)(7)

of this Appendix.

8990

8991

6.5.6 Sampling Strategy

8992

8993

Conduct the reference method tests

they

will yield results representative

of the

8994

pollutant concentration,

emission rate, moisture, temperature,

and flue gas flow

8995

rate

from the unit

and can be correlated with the pollutant concentration

monitor,

8996

monitor,

flow

monitor, and mercury CEMS measurements. The

JCAR350225-081 8507r01

8997

minimum acceptable

time

for a gas monitoring

system

RATA run or for a

8998

moisture monitoring system RATA run is 21 minutes.

For each run of a gas

8999

monitoring

system

RATA, all necessary

pollutant concentration measurements,

9000

diluent concentration measurements, and moisture measurements

(if

applicable)

9001

must, to the extent practicable, be made within a

60-minute

period.

For

flow

9002

monitor RATAs, the minimum time per run must be 5

minutes. Flow rate

9003

reference method measurements may

be made either sequentially from port to

9004

port

simultaneously at two or more sample ports. The

velocity

measurement

9005

probe may be moved from traverse point to

traverse

point

either manually or

9006

automatically. If, during a

flow RATA, significant pulsations in the reference

9007

method readings are observed, be sure to allow enough

measurement time at

each

9008

traverse point to

obtain

accurate average reading when a manual readout

9009

method is used (e.g., a “sight-weighted”

average

from a

manometer).

Also, allow

9010

sufficient

measurement time to ensure that stable temperature readings are

9011

obtained at each traverse point, particularly at

the first measurement point at each

9012

sample

port, when a probe is moved sequentially from port-to-port.

A minimum

9013

of one set of auxiliary measurements for

stack gas molecular weight

9014

determination (i.e., diluent gas data and moisture data) is required for every clock

9015

hour

of a flow RATA or for every three test runs

(whichever is less restrictive).

9016

Alternatively,

moisture

measurements

for

molecular weight determination may

9017

performed before and

after a series of flow RATA runs at a particular load level

9018

(low,

mid, or

high), provided that the time interval between the two moisture

9019

measurements does not exceed three hours. If this option is

selected, the results

9020

the two

moisture determinations must be averaged

arithmetically

and applied

9021

all

RATA runs in the series. Successive

flow RATA runs may be performed

9022

without waiting

in-between runs. If an 20

-diluent monitor is used as a CO

9023

continuous

emission monitoring system, perform a CO2system

RATA (i.e.,

9024

measure

rather than

02,

with the reference

method).

For moisture

9025

monitoring

systems, an appropriate coefficient, “K” factor

or other suitable

9026

mathematical algorithm

may

be developed prior to the RATA, to

adjust

the

9027

monitoring

system readings with respect to the reference

method. If such a

9028

coefficient,

K-factor or algorithm is developed, it must be applied to the CEMS

9029

readings

during

the RATA and

(if

the RATA is passed), to

the subsequent

CEMS

9030

data, by means of

the automated data acquisition and handling system. The owner

9031

operator must keep records of the current coefficient, K

factor

or algorithm,

9032

specified in Section 1

.13(a)(5)(F)

this Appendix. Whenever the coefficient, K

9033

factor or

algorithm is changed, a RATA of the moisture monitoring system is

9034

required. For the RATA of a mercury CEMS using the Ontario

Hydro Method,

9035

for

the RATA of a sorbent

trap

system

(irrespective

the reference method

9036

used),

the time per

run must be long enough to collect a sufficient mass of

9037

mercury to

analyze. For the RATA of a sorbent

trap

monitoring system, the type

9038

sorbent material used by the traps must be the same as for daily operation of

9039

the

monitoring system;

however,

the size of the traps used

for the RATA maybe

JCAR350225-08

1 8507r01

9040

smaller

than the traps used for daily

operation of the system. Spike

the third

9041

section of each sorbent trap

with elemental mercury,

described

in Section 7.1.2

9042

of Exhibit D to this Appendix. Install

a new pair of sorbent traps

prior to each test

9043

run.

For each run, the sorbent trap

data must be validated according

to the quality

9044

assurance criteria in

Section 8 of Exhibit

to this Appendix.

9045

9046

)

To properly correlate individual

mercury CEMS data

(in

lb/mmBtu)

and

9047

volumetric flow

rate data with the

reference method data, annotate the

beginning

9048

and end of each reference

method test run (including

the

exact

time of

day)

the

9049

individual chart recorders

or other pennanent recording devices.

9050

9051

6.5.7 Correlation of Reference Method

and Continuous Emission Monitoring

System

9052

9053

Confirm that the

monitor

or monitoring system and reference

method test results are

9054

consistent

moisture,

pressure, temperature,

and diluent concentration basis

(e.g.,

since the flow

9055

monitor measures

flow rate

on a wet basis, Method 2

test results must also be on a wet basis).

9056

Compare

flow-monitor and reference

method

results on a scfh basis. Also, consider

the response

9057

times of the pollutant concentration monitor, the

continuous emission monitoring

system, and the

9058

flow monitoring

system to ensure

comparison of simultaneous measurements.

9059

9060

For each

relative accuracy test audit run, compare

the measurements obtained from

the monitor

9061

or continuous emission monitoring system

(in

ppm, percent CO

2.lb/mmBtu, or other units)

9062

against the

corresponding reference

method

values. Tabulate the

paired data in a table such

as the

9063

one shown in

Figure 2.

9064

9065

6.5.8

Number of Reference

Method Tests

9066

9067

Perform a

minimum of nine sets of paired monitor

(or

monitoring

system) and

reference method

9068

test data for every

required

(i.e.,

certification, recertification, diagnostic,

semiannual,

or annual)

9069

relative

accuracy

test audit. For 2-level and

3-level relative accuracy test audits

of flow monitors,

9070

perform a minimum of

nine

sets at each of the operating levels.

9071

9072

6.5.9 Reference Methods

9073

9074

The

following

methods are from

appendix A to 40 CFR

60,

incorporated

by reference in Section

9075

225.140, or

have been published by ASTM,

and

are

the reference methods for

performing

9076

relative

accuracy test

audits

under this part: Method 1

or 1A in appendix A-i to 40 CFR

60 for

9077

siting;

Method 2 in

appendices A-i

and A-2 to 40 CFR

or its allowable

alternatives

9078

appendix A to

40 CFR 60

(except

for

Methods 2B and 2E in appendix

A-l to 40 CFR

60)

for

9079

stack gas

velocity and volumetric flow rate; Methods

3, 3A or 3B in appendix A-2

CFR

9080

for

and

CQ;

Method

in appendix A-3 to 40 CFR

60 for moisture; and for mercury,

either

9081

ASTM

D6784-02

(the

Ontario

Hydro

Method) (incorporated

by reference under Section

9082

225.140),

Method

29 in appendix A-8

CFR 60, Method

30A,

Method 30B.

JCAR350225-08 1 8507r01

9083

9084

7. Calculations

9085

9086

7.1 Linearity Check

9087

9088

Analyze

the

linearity

data for pollutant concentration monitors as follows. Calculate the

9089

percentage error in linearity based

upon the

reference value

at the

low-level,

mid-level,

and high-

9090

level concentrations specified in Section 6.2 of this Exhibit. Perform this calculation

once during

9091

the certification test. Use the following equation to calculate the error in linearity for each

9092

reference

value.

9093

9094

100

(Equation

A-4)

9095

9096

Where:

9097

= Percentage linearity error, based upon the reference value.

= Reference value

low-, mid-,

or high-level

calibration

gas

introduced

into

the monitoring system.

= Average of the monitoring

system

responses.

9098

9099

7.2

Calibration Error

9100

9101

7.2.1 Pollutant Concentration and Diluent Monitors

9102

9103

For

each reference value,

calculate the percentage calibration

error based upon instrument span

9104

for daily

calibration error tests using the following equation:

9105

jR-A

9106

CE=

xlOO

(EquationA-5)

9107

9108

Where:

9109

Calibration error as a percentage of the span of the instrument.

= Reference value of zero or upscale

(high-level

or mid-level, as

applicable)

calibration gas introduced into the monitoring system.

= Actual monitoring system response to the calibration gas.

= Span of the instrument, as

specified

Section 2 of this Exhibit.

9110

9111

7.2.2 Flow

Monitor Calibration Error

9112

1CAR350225-08 1 8507r01

9113

For

each reference value, calculate

the percentage calibration

error based upon span using

the

9114

following equation:

9115

9116

CE=

xlOO

(EquationA-6)

9117

9118

Where:

9119

= Calibration

error as a percentage

of span.

Low or high level

reference value specified in Section 2.2.2.1

of this Exhibit.

= Actual flow monitor

response to the reference value.

= Flow monitor calibration

span value as determined under Section 2.1.2.2

this Exhibit.

9120

9121

7.3

Relative Accuracy for

Monitors,

Mercury

Monitoring Systems,

and

Flow Monitors

9122

9123

Analyze

the

relative accuracy

test audit data

from the reference

method

tests for

CO2

9124

monitors

used

only

for heat input rate

determination, mercury monitoring systems

used to

9125

determine mercury mass emissions under

Sections 1.14 through 1.18 of Appendix B,

and flow

9126

monitors using the following procedures. Summarize

the results on a data sheet. An example

9127

shown in Figure 2. Calculate the mean of the monitor

or monitoring system measurement values.

9128

Calculate the mean of

the reference

method values. Using data from

the automated data

9129

acquisition and

handling system, calculate

the arithmetic differences between

the reference

9130

method

and monitor measurement data sets.

Then calculate the arithmetic mean of the

9131

difference, the

standard deviation,

the confidence coefficient, and

the monitor or monitoring

9132

system relative

accuracy using the following

procedures and equations.

9133

9134

7.3.1 Arithmetic Mean

9135

9136

Calculate the

arithmetic mean of the differences,

d, of a data set as follows.

9137

9138

d=d1 (EquationA-7)

9139

9140

Where:

9141

Number of data points.

= The difference between

a reference method value and

the corresponding

continuous

emission

monitoring

system value (RM-

CEMI)

a given point in

time i.

9142

ucju

•

Ccoo

•

4444

C.LM4

LQ-

lCD

iii

IF’

C-.

c,)

D”CD

•

C-)

(ID

LJ’

CCOoC—

CHU

——

—

————

—

I—

•

I-

•

CC4

LI.)

t’Jt’Jt’J

JJJ

CCCCCCCC

NCNC)

NC4C

C-)

-t

C/)

—

C,)

Cl)

-‘CD

-t

—.

-t

)

(I)

It)

-C)

)

CCD

j•)

C/DC)

-t

CDQ

—

—i

LI.)

cl)

1CAR350225-081

8507r01

2.262

2.086

2.021

2.228

2.080

2.000

2.201

2.074

>60

1.960

9161

9162

7.3.4

Relative Accuracy

9163

9164

Calculate the

relative

accuracy

of a data set using

the

following equation.

9165

9166

RA—

xlOO

(Equation A-b)

9167

9168

Where:

9169

= Arithmetic

mean of the reference method

values.

= The absolute

value of the mean difference

between the reference method

values and the

corresponding continuous emission monitoring

system

values.

The absolute value of the confidence

coefficient.

9170

9171

7.4 Bias Test

9172

9173

Test

the following

relative

accuracy test audit data sets for

bias: flow

monitors, mercury

9174

concentration

monitoring

systems,

and sorbent trap monitoring systems,

using the procedures

9175

outlined

in Sections 7.4.1 through 7.4.4 of this Exhibit.

For multiple-load flow RATAs,

perform

9176

bias test at each load

level designated

as normal under Section 6.5.2.1

of this Exhibit.

9177

9178

7.4.1 Arithmetic Mean

9179

9180

Calculate the

arithmetic mean of the difference,

“d”, of the data set using Equation

A-7 of this

9181

Exhibit. To

calculate bias for a flow monitor,

I?dH

is, for

each

paired data point, the difference

9182

between the

flow rate values

(in

scth)

obtained from the reference method

and the monitor. To

9183

calculate bias

for a mercury monitoring system when

using the Ontario Hydro Method

9184

Method 29 in

appendix A-8 to 40

CFR 60, incorporated

reference

in Section 225.140, “d”

is,

9185

for

each data

point, the difference between

the average mercury concentration value

(in ig/m

9186

from the

paired Ontario Hydro or Method 29

in appendix A-8 to 40 CFR 60 sampling

trains and

9187

the

concentration measured by the monitoring system.

For sorb ent trap monitoring systems,

use

9188

the

average

mercury concentration

measured by the

paired

traps

in the calculation of

“d”.

9189

9190

7.4.2

Standard

Deviation

9191

JCAR350225-08 1 8507r01

9192

Calculate the standard

deviation,

Sd,

of the data set using Equation A-8.

9193

9194

7.4.3 Confidence Coefficient

9195

9196

Calculate the

confidence coefficient,

cc, of the data set using Equation A-9.

9197

9198

7.4.4 Bias Test

9199

9200

If, for the relative

accuracy

test

audit data set being tested, the mean

difference, d, is less than

9201

equal to

the absolute value of the confidence coefficient, cc, the monitor or monitoring system

9202

has passed

the bias test. If the mean difference, d, is greater than the absolute value of the

9203

confidence coefficient,

cc, the monitor

monitoring

system has

failed to meet the bias test

9204

requirement.

9205

9206

7.5 Reference Flow-to-Load Ratio or Gross Heat Rate

9207

9208

Except

as provided

in Section 7.6 of this Exhibit,

the owner or operator must

9209

determine R, the reference value of the ratio of flow rate to unit load, each time

9210

that a passing flow RATA is performed at a load level designated as normal in

9211

Section 6.5.2.1 of this Exhibit. The owner or operator

must report the current

9212

value of

the electronic

quarterly report required under 40 CFR 75.64,

9213

incorporated

reference

Section 225.140, and must also report the completion

9214

date of the associated RATA. If two load levels have been designated as normal

9215

under Section 6.5.2.1 of this Exhibit, the owner or operator must

determine

9216

separate

Rvalue

for each of the

normal

load

levels. The

reference flow-to-load

9217

ratio

must be calculated as follows:

9218

ref

-5

9219

Rref___X1O

(EquationA-13)

avg

9220

9221

Where:

9222

= Reference value of the flow-to-load

ratio, from the most recent

normal-load flow RATA, scfhlmegawatts, scthll000 lb/hr of steam,

scthl

(mmBtu/hr

of steam output).

= Average stack gas volumetric flow rate measured by

the

reference

method during the

normal-load

RATA,

scth.

= Average unit

load

during the normal-load flow RATA, megawatts,

1000

lb/hr of steam, or mmBtu/hr of thermal output.

9223

9224

Equation A-13, for a common stack, determine L

summing, for each

JCAR350225-08 1 8507r01

9225

RATA run, the operating loads

of all units discharging through the common

stack,

9226

and

then taking

the arithmetic average

the

summed

loads. For a

unit that

9227

discharges its emissions

through

multiple

stacks, either determine a single value

9228

pfQ

for the unit or a separate value

for each stack. In the former case,

9229

calculate

by summing, for each

RATA run, the

volumetric

flow rates through

9230

the

individual

stacks and then taking the arithmetic average of the

summed RATA

9231

run flow rates. In the

latter case, calculate the value of

for each stack

9232

taking the arithmetic average, for

all RATA runs, of the flow rates through

the

9233

stack. For

unit with

a multiple stack discharge configuration consisting

of a

9234

main stack and a bypass

stack (e.g., a unit with a wet

scrubber),

determine

9235

separately

for each stack at the time

of the normal load flow RATA. Round

9236

off the value of R

to two decimal places.

9237

9238

In addition to determining Ror

as an alternative to determine R, a reference

9239

value of the

gross heat rate (GHR) may be determined. In order to use

this option,

9240

quality assured diluent

gas

(Q2

02)

must be available for each hour of the

9241

most recent normal-load

flow RATA. The reference value of the GHR

must be

9242

determined as follows:

9243

HeatInput)

9244

(GHR)reJ

avg

xl000

(Equation

A-13a)

avg

9245

9246

Where:

9247

(GHR

= Reference value of the gross heat rate

at the time of the

most recent normal-load flow RATA, Btu/kwh,

Btu/lb

steam load,

Btu heat input/mmBtu steam output.

(HeatInput) = Average hourly

heat input during the normal-load flow

RATA, as determined using the applicable

equation

Exhibit

to this Appendix,

mmBtu/hr. For multiple stack

configurations, if the reference GHR value is determined

separately for each stack, use

the

hourly

heat input

measured

at each stack. If the reference GHR is

determined

at the unit level,

sum

the hourly

heat inputs measured at

the

individual stacks.

= Average unit load during the normal-load

flow RATA,

megawatts, 1000 lb/hr of steam, or mmBtu/hr

thermal

output.

9248

9249

In the calculation of

(HeatInput),

use

the average

volumetric

flow rate

9250

measured by the reference method during the RATA,

and

use

the

average diluent

9251

gas concentration

measured during the flow RATA

(i.e.,

the arithmetic

average of

JCAR350225-08

1 8507r01

9252

the diluent gas concentrations

for all clock hours in which

a RATA

run was

9253

performed).

9254

9255

7.6 Flow-to-Load Test Exemptions

9256

9257

For

complex

stack configurations (e.g., when

the effluent from a unit is divided

9258

and discharges

through multiple stacks in such

manner

that the

flow

rate in the

9259

individual

stacks cannot be

correlated with unit

load),

the owner or operator

may

9260

petition

the USEPA under 40 CFR 75.66,

incorporated by reference in Section

9261

225.140, for an

exemption from the requirements

Section

7.7

Appendix A to

9262

CFR Part 75 and Section 2.2.5

of Exhibit B to Appendix B. The petition must

9263

include sufficient information

and data to demonstrate that

flow-to-load

or gross

9264

heat

rate evaluation is infeasible for the

complex stack configuration.

9265

9266

Units that

do not produce electrical output

(in

megawatts)

or thermal output (in

9267

of steam per

hour)

are exempted

from the flow-to-load ratio test requirements

9268

Section

7.5 of this Exhibit and Section 2.2.5 of

Exhibit

Appendix

9269

Figure 1. Linearity Error

Dietermination

Percent

Date and

Reference

Monitor

reference

time

value

Difference

value

Low-level:

Mid-level:

High-level:

JCAR350225-081

8507r01

9270

9271

Figure 2. Relative Accuracy

Determination

(Pollutant

Concentration

Monitors)

SQ2

(ppm

FFNc1)

cQ2

(Pollutant)

(ppm

[FNc1)

Run

and

time

[FNa1

FFNb]

Diff

time

[FNaJ

FFNb1

Diff

Arthmetic

Mean Difference

(Eci.

A-7).

Confidence

Coeffecient

(Eq. A-9).

Relative

Accuracy

(Eq.

A-b).

JCAR35O225O81

8507r01

FFNa1

means “reference

method data”.

FFNb1

M means “monitor data”.

FFNc1

Make sure

the

and M data are on

consistent

basis, either wet or dry.

9272

9273

Figure 3. Relative Accuracy Determination

(Flow Monitors)

Flow rate (Low)

Flow rate

(Normal)

Flow rate (High)

(scf/hr)

[FNa]

(scflhr)

[FNa]

(scf/hr)

[FNa]

Date

time

Diff time RM

M Diff

Arthinetic

Mean Difference

(Eq. A-7).

Confidence

Coeffecient (Eq. A-9).

Relative Accuracy

(Eq. A-b).

[FNa1

Make sure the RM and M

data are on a consistent basis, either wet or dry.

JCAR350225-081 8507r01

9274

9275

Figure 4. Relative Accuracy Determination

(NO/Dilent

Combined

System)

Reference

method data

system

(lb/mrnBtu)

Run

Date

N and time

NQXQ

[FNa]

Q2/Q2%

Difference

Arthmetic Mean Difference

(Eq.

A-7).

Confidence Coeffecient

(Eq.

A-9).

Relative Accuracy

(Eq.

A-

10).

{FNa1

Specify

units:

ppm, lb/dscf,

mgjdscm.

9276

9277

Figure

5. Cycle Time

Date of test

JCAR350225-08 1 8507r01

Component/system

ID#:

Analyzer type

Serial Number

High level gas

concentration:

ppml%

(circle one)

Zero level gas

concentration:

ppm/%

(circle one)

Analyzer span setting:

ppm/% (circle one)

Upscale:

Stable

starting monitor value:

ppml%

(circle

one)

Stable

ending monitor reading:

ppm/%

(circle one)

Elapsed

time:

Seconds

Downscale:

Stable starting

monitor value:

ppi%

(circle one)

Stable

ending monitor reading:

ppml%

(circle

one)

Elapsed time:

seconds

Component

cycle time =

seconds

System

cycle time

seconds

9278

9279

To detennine

the upscale cycle time

(Figure

6a),

measure the flue gas

emissions

until

9280

the response

stabilizes. Record the stabilized value

(see

Section

6.4

this Exhibit

for the

9281

stability

criteria).

9282

9283

Inject a high-level

calibration

gas

into the port leading to the calibration

cell

or thimble

9284

(Point

B).

Allow the analyzer to stabilize. Record the stabilized

value.

9285

9286

Determine

the

step change. The step change is equal to the

difference between the

9287

final

stable calibration gas value (Point

and the

stabilized stack emissions value

(Point

9288

9289

9290

D. Take 95%

of the step change value and add the result to the

stabilized stack emissions

9291

value

(Point A). Determine the time at

which

95%

of the

step

change occurred

(Point

C).

9292

9293

E. Calculate

the upscale cycle time by

subtracting the time at which the calibration gas

9294

was

injected (Point B)

from the time at which 95% of the step change

occurred

(Point

C).

9295

this

example,

upscale cycle time

= (11-5)

6 minutes.

9296

9297

F. To

determine the downscale cycle

time (Figure

6b)

repeat the procedures above,

9298

except

that

a zero gas is

injected when the flue gas emissions have stabilized, and 95% of

9299

the

step

change

concentration is subtracted from the stabilized stack

emissions value.

9300

9301

G. Compare

the upscale and downscale

cycle

time

values. The longer of these two times

9302

is the cycle time for the analyzer.

9303

JCAR350225-081 8507r01

Develop and implement

quality

assurance/quality control (QA/QC) program

for the continuous

emission monitoring systems and

their components. At a minimum, include in each

QA/QC

program a written plan that describes in detail (or that

refers

to separate documents containing)

complete, step-by-step

procedures and operations for each

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., soflware coefficients and

troubleshooting diagrams) available

for

review

during an audit. Electronic storage

of the

information in the

OAIQC

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

mnnitcrn a

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

reference

Section

225.140, and Sections 1.10 through 1.13

of Appendix B, as applicable.

1.1.3 Maintenance

Records

Keep a

record of all testing, maintenance, or repair activities

performed on any monitoring

system or

component in

location

and

format

suitable for inspection. A maintenance log

may

used for

this purpose. The following records should be

maintained: date, time, and description

any

testing,

adjustment, repair,

replacement,

or preventive maintenance action performed

on any

monitoring

system and records of any corrective

actions associated with a monitor’s outage

period. Additionally, any

adjustment

that recharacterizes a system’s

ability to record and report

emissions

data

must be recorded (e.g.,

changing 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 adjustments must be kept.

Exhibit B to

Appendix

B — Quality Assurance and Quality

Control Procedures

1. Quality Assurance/Quality

Control Program

9304

9305

9306

9307

9308

9309

9310

9311

9312

9313

9314

9315

9316

9317

9318

9319

9320

9321

9322

9323

9324

9325

9326

9327

9328

9329

9330

9331

9332

9333

9334

9335

9336

9337

9338

9339

9340

9341

9342

9343

9344

9345

9346

1.1.4

JCAR350225-081

8507r01

The requirements in Section 6.1.2 of Exhibit A to this

Appendix must be met by 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 1.1 5(c) and

1.15

(d)(4)

Appendix

1.2 Specific Requirements for Continuous Emissions

Monitoring

Systems

1.2.1 Calibration Error Test and Linearity

Check Procedures

Keep a written record of the procedures used

for

daily

calibration error tests and linearity

checks

(e.g.,

how gases are to be

injected, adjustments

of flow rates and pressure, introduction

reference values, length of time for

ection

calibration

gases, steps for obtaining calibration

error or error in linearity,

determination

of interferences, and when calibration adjustments

should be

made).

Identify any calibration error test and

linearity check procedures specific to

the

continuous emission

monitoring

system that

vary

from the procedures in Exhibit A to this

Appendix.

1.2.2 Calibration and

Linearity

Adjustments

Explain how each component of the continuous emission monitoring system will

adjusted

provide correct responses to calibration gases, reference values, andlor indications

interference both

initially and after repairs

or corrective action. Identify equations, conversion

factors and

other factors affecting calibration

of each continuous emission monitoring system.

9372

1.2.3 Relative

Accuracy Test Audit Procedures

9373

Keep a

written record of procedures and details peculiar to the installed

continuous

emission

monitoring

systems that are to be used

for

relative

accuracy test

audits, such as sampling and

analysis

methods.

1.2.4

Parametric Monitoring for Units With Add-on Emission Controls

The

owner or operator shall keep a

written

(or electronic)

record including a list

of operating

parameters

for the add-on mercury emission

controls, as applicable, and the range of each

operating

parameter that indicates the add-on emission controls are operating

properly.

The

owner

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

9347

9348

9349

9350

9351

9352

9353

9354

9355

9356

9357

9358

9359

9360

9361

9362

9363

9364

9365

9366

9367

9368

9369

9370

9371

9374

9375

9376

9377

9378

9379

9380

9381

9382

9383

9384

9385

9386

9387

9388

9389

JCAR350225-081 8507r01

9390

Include procedures for inscribing or otherwise permanently marking

unique

identification

9391

number

on each

sorbent

trap for tracking

purposes. Keep records of the ID of the monitoring

9392

system

in which each sorbent trap is used and the

dates

and

hours of each mercury collection

9393

period.

9394

9395

1.3.2 Monitoring

System Integrity and Data

Quality

9396

9397

Explain the procedures used to perform the leak checks when sorbent traps are placed in service

9398

and removed from service. Also

explain

the other

procedures used to ensure system integrity

9399

and data

quality, including, but not limited to, gas flow meter calibrations, verification

9400

moisture removal, and ensuring

air-tight

pump operation. In addition, the

plan must include

9401

the data

acceptance and quality control criteria in Section 8 of Exhibit

D to this Appendix. All

9402

reference meters used to

calibrate

the gas flow meters (e.g., wet test

meters)

must be periodically

9403

recalibrated. Annual, or more frequent, recalibration is recommended. If

NIST-traceable

9404

calibration device is used as a

reference

flow meter, the

plan must include a protocol for

9405

ongoing

maintenance and periodic recalibration to maintain the accuracy and NIST-traceability

9406

of the calibrator.

9407

9408

1.3.3 Mercury Analysis

9409

9410

Explain the

chain of custody

employed

in packing, transporting,

and

analyzing

the sorbent traps

9411

(see

Sections

7.2.8 and 7.2.9 in Exhibit D to this

Appendix.).

Keep records of all mercury

9412

analyses.

The

analyses must be performed in accordance with the procedures described in

9413

Section 10

of Exhibit D to this Appendix.

9414

9415

1.3.4 Laboratory Certification

9416

9417

The QA Plan

must include documentation that

the

laboratory

performing the

analyses

on the

9418

carbon

sorbent

traps is certified by the International Organization for Standardization (ISO)

9419

have a proficiency

that meets the requirements of

ISO

17025. Alternatively,

if the laboratory

9420

performs

the spike recovery study described in Section 10.3 of Exhibit D to this Appendix

and

9421

repeats that

procedure annually. ISO certification is not required.

9422

9423

1.3.5 Data Collection Period

9424

9425

State,

and provide

the rationale for, the minimum

acceptable data collection period (e.g., one

9426

day,

one

week,

etc.)

for the size of the sorbent trap selected for the monitoring. Include in

the

9427

discussion

such factors as the

mercury

concentration in the stack gas, the capacity of the sorbent

9428

trap,

and

the minimum mass of

mercury

required

for the analysis.

9429

9430

1.3.6

Relative

Accuracy Test Audit Procedures

9431

9432

Keep

records of the

procedures

and

details

peculiar to the sorbent trap monitoring

systems

that

JCAR350225-08

1 8507r01

9433

are

to be

followed

for

relative accuracy

test

audits,

such

as sampling and analysis

methods.

9434

9435

Frequency of Testing

9436

9437

A summary chart showing each quality assurance test

and the frequency at which each test

9438

required is located at the end of this Exhibit in Figure 1.

9439

9440

2.1 Daily Assessments

9441

9442

Perform the following daily

assessments

to quality-assure the

hourly

data recorded

the

9443

monitoring

systems during each period of unit operation,

or, for a bypass stack or duct, each

9444

period in which emissions pass

through

the bypass stack or duct. These

requirements

are

9445

effective as of the date when the monitor or continuous emission

monitoring system completes

9446

certification testing.

9447

9448

2.1 .1

Calibration Error Test

9449

9450

Except as provided

in Section 2.1.1.2

of this Exhibit, perform the daily calibration error test

9451

each gas

monitoring system (including moisture monitoring

systems consisting of wet- and

dry-

9452

basis

analyzers)

according to the procedures in Section 6.3.1 of Exhibit A to this

Appendix,

9453

and

perform the daily

calibration

error test of each flow monitoring system according

to the

9454

procedure in Section

6.3.2

Exhibit

A to this Appendix. When two measurement ranges

(low

9455

and high) are

required for a particular parameter, perform

sufficient

calibration error tests

9456

each range to

validate the data recorded on that range, according

to the

criteria

in Section 2.1.5

9457

this Exhibit.

9458

9459

For units with

add-on emission controls and dual-span or

auto-ranging monitors, and other

units

9460

that

use

the

maximum expected concentration to determine calibration gas values, perform

the

9461

daily calibration

error tests on each scale that

has been used since the previous calibration error

9462

test.

For example, if the pollutant concentration has not exceeded the low-scale value

(based

9463

the maximum

expected

concentration)

since the previous

calibration

error test, the calibration

9464

error

test

may be performed

on the

low-scale only. If,

however,

the concentration has exceeded

9465

the low-scale

span

value for one hour or longer since the previous calibration

error test, perform

9466

the

calibration error test on

both the low-

and high-scales.

9467

9468

2.1

.1.1 On-line Daily Calibration Error Tests

9469

9470

Except as

provided in Section 2.1.1.2 of this Exhibit, all daily

calibration error tests must be

9471

performed

while the unit is in operation at normal, stable conditions (i.e., ‘on-line”).

9472

9473

2.1.1.2 0ff-line

Daily Calibration Error Tests

9474

JCAR350225-081 8507r01

9475

Daily

calibrations may be performed while the unit is not operating

(i.e., “off-line”)

and

may be

9476

used to

validate

data for a

monitoring

system

that meets the following conditions:

9477

9478

1.)

An initial demonstration test of the monitoring system is successfully completed

9479

and the

results

are reported in the

quarterly

report

required

under

CFR

75.64,

9480

incorporated

by reference in

Section 225.140. The initial demonstration test,

9481

hereafter called the “off-line calibration demonstration”, consists of an off-line

9482

calibration error test followed by an on-line calibration error test. Both the off-line

9483

and on-line

portions

of the

off-line calibration demonstration

must

meet the

9484

calibration error

performance

specification in Section 3.1 of Exhibit A to

9485

Appendix B. Upon completion of the

off-line portion

of the

demonstration,

the

9486

zero and

upscale

monitor responses may be adjusted, but

only

toward the true

9487

values

the calibration

gases or

reference

signals

used

perform the test

and

9488

only in accordance with the routine calibration

adjustment

procedures specified in

9489

the

quality control program required under Section 1 of this Exhibit. Once these

9490

adjustments are made, no further

adjustments

may be made to the monitoring

9491

system

until after completion of the on-line portion of the off-line calibration

9492

demonstration. Within 26 clock hours after the completion hour of the off-line

9493

portion of the demonstration, the

monitoring

system must

successfully complete

9494

the

first

attempted calibration error test, i.e., the on-line portion of the

9495

demonstration.

9496

9497

)

For each monitoring system that has passed the off-line calibration

demonstration,

9498

off-line

calibration

error tests may be used on a

limited basis

validate data,

9499

accordance with subsection

(2)

in Section 2.1.5.1 of this Exhibit.

9500

9501

2.1.2

Daily Flow Interference Check

9502

9503

Perform the

daily flow monitor

interference

checks specified

in Section 2.2.2.2 of Exhibit

A to

9504

this

Appendix while

the unit is in operation at normal, stable conditions.

9505

9506

2.1.3

Additional Calibration Error Tests and Calibration

Adjustments

9507

9508

addition to the daily calibration error tests required under Section 2.1.1 of this

9509

Exhibit, a

calibration error

test of a

monitor

must be

performed in accordance

9510

with

Section

2.1.1 of this Exhibit, as follows: whenever a daily calibration error

9511

test is failed; whenever a monitoring system is returned to service following repair

9512

corrective maintenance

that could affect the monitor’s

ability

accurately

9513

measure

and record emissions data; or after making certain calibration

9514

adjustments, as described in this Section.

Except

in the case of the routine

9515

calibration adjustments described in this Section, data from the monitor are

9516

considered invalid until the required additional calibration error test has been

9517

successfully

completed.

JCAR350225-081 8507r01

9518

9519

Routine

calibration

adjustments

of a monitor are permitted after

any successful

9520

calibration error

test. These

routine

adjustments must be made so as to bring

the

9521

monitor readings as close as

practicable

to the known tag values of the calibration

9522

gases or to the actual value of the flow monitor reference signals.

An additional

9523

calibration error test is required following routine calibration adjustments

where

9524

the

monitor’s calibration

has

been

physically

adjusted

(e.g., by turning a

9525

potentiometer) to verify that the adjustments

have been made properly. An

9526

additional calibration error test is not required, however, if the routine calibration

9527

adjustments are made

means

of a mathematical algorithm programmed into

the

9528

data acquisition and handling system. It is recommended that routine

calibration

9529

adjustments be made,

at a

minimum,

whenever the daily calibration error exceeds

9530

the limits of the applicable perfonnance specification in Exhibit A to this

9531

Appendix for the pollutant concentration monitor,

CO2or

monitor, or flow

9532

monitor.

9533

9534

Additional

(non-routine)

calibration

adjustments

of a monitor are

permitted

prior

9535

(but not

during) linearity

checks and

RATAs and at other times, provided that

9536

an appropriate technical justification is included in the quality control

program

9537

required under

Section 1 of this Exhibit. The allowable non-routine adjustments

9538

are

follows. The owner or

operator may physically

adjust

the calibration

of a

9539

monitor

(e.g.,

by means of a potentiometer), provided

that

the post-adjustment

9540

zero and upscale responses of the monitor are within the performance

9541

specifications of the instrument given in Section 3.1 of Exhibit A to this

9542

Appendix. An additional

calibration error test is required following such

9543

adjustments to verify that the monitor is

operating within the performance

9544

specifications at both the zero and

upscale

calibration levels.

9545

9546

2.1.4

Data Validation

9547

9548

An out-of-control period occurs when the calibration error of a

CO2

monitor

9549

(includingQ monitors used to measure

CO2 emissions or percent

moisture)

9550

exceeds 1.0

percent

2or

02,

or when the calibration error of a flow

monitor or

9551

moisture sensor exceeds

6.0

percent

of the span value, which is twice the

9552

applicable specification of Exhibit A to this Appendix. Notwithstanding,

9553

differential pressure-type flow

monitor for which the calibration error exceeds

6.0

9554

percent of the span

value

will not be considered out-of-control

—

9555

absolute value of the difference

between the monitor response and the reference

9556

value in Equation A-6 of Exhibit A

to this Appendix, is < 0.02 inches of water.

9557

For a mercury monitor, an out-of-control

period

occurs

when

the calibration error

9558

exceeds 5.0% of the span value. Notwithstanding,

the

mercury monitor

will not

9559

considered out-of-control

—

in Equation A-6 does not exceed 1.0

fig/scm.

JCAR350225-081

8507r01

9560

The

out-of-control

period begins

upon failure of the calibration

error test and ends

9561

upon completion of a successful

calibration

error test. Note, that if a failed

9562

calibration, corrective action, and successful calibration

error test occur within

the

9563

same

hour,

emission

data for that hour recorded by the monitor

after the

9564

successful calibration error

test may be used for reporting purposes, provided

that

9565

two or more valid readings

are

obtained

required

by Section 1.2 of this

9566

Appendix. Emission data must not be reported from

an out-of-control monitor.

9567

9568

An out-of-control

period

also occurs whenever interference of a flow monitor

9569

identified. The out-of-control

period

begins with the hour

of completion of the

9570

failed interference check

and ends

with

the hour of completion of an interference

9571

check that is passed.

9572

9573

2.1.5

Quality Assurance of Data With Respect to Daily Assessments

9574

9575

When a monitoring

system

passes

a daily assessment (i.e.,

daily

calibration error test

or daily

9576

flow

interference check), data from that monitoring

system

are

prospectively validated for 26

9577

clock hours

(i.e.,

hours plus a 2-hour grace

period)

beginning with the hour in which

the test

9578

is passed,

unless another assessment

(i.e.,

a daily calibration error test, an interference check

of a

9579

flow

monitor, a quarterly linearity check, a quarterly leak

check, or

a relative accuracy test audit)

9580

is failed within the 26-hour period.

9581

9582

2.1.5.1 Data

Invalidation with Respect to Daily Assessments

9583

9584

The following

specific rules apply to the invalidation

of data

with

respect to daily assessments:

9585

9586

Data from

a monitoring system are invalid, beginning with the first

hour

9587

following the expiration of a 26-hour

data validation period or beginning

9588

with the

first hour following the expiration of an 8-hour start-up

grace

9589

period (as provided under Section 2.1.5.2

of this

Exhibit),

if the required

9590

subsequent daily assessment

has not been conducted.

9591

9592

)

For a monitor that

has passed the off-line calibration demonstration,

9593

combination of on-line and off-line calibration error tests

may be used to

9594

validate data from

the monitor, as follows. For a particular unit

(or

stack)

9595

operating hour, data from a monitor

may be validated using a successful

9596

off-line

calibration

error

test if:

9597

9598

An on-line calibration

error test has been passed within the

9599

previous 26 unit

(or stack)

operating hours; and

9600

9601

)

the 26

clock hour data validation window for the off-line

9602

calibration

error

test has not expired. If either of these conditions

JCAR350225-08

1 8507r01

9603

not met, then the data from

the

monitor are invalid with respect

9604

the daily calibration error test requirement. Data from the

monitor

9605

must

remain

invalid until

the appropriate on-line or off-line

9606

calibration error test is successfully completed

so that both

9607

conditions in subsections (a) and

(b)

are met.

9608

9609

For units with

two

measurement

ranges

(low

and high) for a particular

9610

parameter, when separate analyzers are used for the low and high

ranges,

9611

failed or expired calibration on one of the ranges does not affect the

9612

quality-assured data status on the

other range. For a dual-range analyzer

9613

(i.e.,

a single analyzer with two measurement scales), a failed calibration

9614

error test on either the low or high

scale results in an out-of-control period

9615

for the monitor. Data from the monitor remain invalid until corrective

9616

actions are taken and “hands-off’ calibration error tests have

been passed

9617

both

ranges.

However, if the most recent calibration error test on

the

9618

high scale was passed but has

expired,

while the low scale is up-to-date

9619

its calibration error

test

requirements

(or

vice-versa),

the expired

9620

calibration error test does not affect the quality-assured

status of the data

9621

recorded on the other scale.

9622

9623

2.1.5.2

Daily

Assessment

Start-Up Grace Period

9624

9625

For

the purpose of quality assuring data with respect to a daily assessment (i.e., a daily

9626

calibration error test or a flow

interference

check), a start-up grace period may apply when

a unit

9627

begins to operate

after a period of non-operation.

The start-up grace period for a daily calibration

9628

error test is

independent of the start-up grace period for

daily

flow

interference

check. To

9629

qualify

for a start-up grace period for a daily assessment, there are two requirements:

9630

9631

The unit must

have

resumed operation after being in outage for 1 or

9632

hours

(i.e.,

the unit must be in

a start-up

condition)

as evidenced by a

9633

change in unit operating time from zero in one clock hour to an

operating

9634

time greater than zero in the next

clock

hour.

9635

9636

For the monitoring system to be used

validate data

during

the grace

9637

period,

the

daily assessment

of the same kind must have been

9638

passed

on-line

within 26 clock

hours prior to the last hour in which the

9639

unit operated before the outage. fri addition, the monitoring

system must

9640

in-control with

respect to quarterly and semi-annual or annual

9641

assessments.

9642

9643

both of

the

above

conditions are met, then a start-up grace period

of up to 8 clock hours

9644

applies,

beginning with the first hour of unit operation following the outage. During the

start-up

9645

grace

period,

data generated

the monitoring

system are considered quality-assured. For

each

JCAR350225-08 1 8507r01

9646

monitoring system, a start-up grace period

for a calibration error test or flow interference check

9647

ends when

either:

(1)

daily

assessment of the same kind

(i.e.,

calibration

error test or flow

9648

interference check) is performed

(2)

8 clock hours have elapsed (starting with the first

hour of

9649

unit operation following the outage), whichever

occurs first.

9650

9651

2.1.6 Data Recording

9652

9653

Record and tabulate all calibration error test

data according to month, day, clock-hour, and

9654

magnitude in either ppm, percent volume, or scth. Program monitors that automatically

adjust

9655

data to

the corrected calibration

values (e.g., microprocessor

control)

to record either:

(1)

the

9656

unadjusted concentration or flow rate measured in the calibration error

test

prior to resetting the

9657

calibration, or (2) the magnitude

of any

adjustment.

Record

the following applicable flow

9658

monitor interference check data: (1) sample line/sensing port pluggage, and (2)

malfunction of

9659

each

RTD, transceiver, or equivalent.

9660

9661

2.2 Quarterly

Assessments

9662

9663

For each

primary and redundant backup monitor

or monitoring system, perform the following

9664

quarterly assessments. This requirement applies as of the calendar quarter

following

the calendar

9665

quarter

in which the

monitor

or continuous emission monitoring system is provisionally

certified.

9666

9667

2.2.1

Linearity Check

9668

9669

Unless a

particular monitor

(or

monitoring

range)

is exempted under this

subsection or under

9670

Section 6.2 of Exhibit A to this Appendix, perform a

linearity

check, in accordance with

the

9671

procedures in

Section 6.2 of Exhibit A to

this Appendix, for each primary and redundant backup,

9672

mercury,

pollutant concentration monitor and each primary and redundant

backup CO2or

9673

monitor (including

monitors

used

to measure

emissions or to continuously monitor

9674

moisture)

least once during each

operating quarter,

defined in 40

CFR

72.2,

9675

incorporated by

reference

Section 225.140.

For mercury monitors, perform the linearity

9676

checks using

elemental mercury standards. Alternatively, you may perform 3-level

system

9677

integrity checks at

the same three calibration

gas levels

(i.e.,

low,

mid, and

high),

using a

NIST

9678

traceable

source of oxidized mercury. If you choose this

option,

the performance

specification in

9679

Section

3.2(c)

Exhibit A to this Part must

be met at each gas level. For units using both

a low

9680

and high

span value, a linearity check is required

only

on the ranges used

to record and report

9681

emission data during the

operating quarter.

Conduct the linearity checks no less than

30 days

9682

apart, to the

extent practicable. The data validation

procedures

in Section

2.2.3(e)

of this Exhibit

9683

must be

followed.

9684

9685

2.2.2

Leak Check

9686

9687

For

differential

pressure flow monitors, perform

leak

check

of all sample lines (a manual check

9688

acceptable) at least once during each

operating quarter.

For this test, the unit does not have

JCAR350225-081

8507r01

9689

to be in

operation. Conduct

the leak

checks no less than

30 days

apart, to the

extent practicable.

9690

leak check is

failed, follow the applicable

data

validation

procedures in

Section 2.2.3(g)

9691

this

Exhibit.

9692

9693

2.2.3

Data

Validation

9694

9695

A linearity

check must not be commenced

the

monitoring system

is operating

9696

out-of-control with

respect to

any of the daily or semiannual

quality

assurance

9697

assessments

required

Sections 2.1 and 2.3

of this Exhibit or with

respect

to the

9698

additional

calibration error test

requirements

in Section 2.1.3 of

this Exhibit.

9699

9700

Each

required

linearity

check

must

be done

according

to subsection

(b)(l),

(b)(2)

9701

or (b)(3) of

this Section:

9702

9703

The

linearity check may

be done “cold”,

i.e., with no corrective

9704

maintenance,

repair,

calibration adjustments,

re-linearization

9705

reprogramming

of the

monitor prior to

the test.

9706

9707

The

linearity check

may be done after

performing only the routine

or non-

9708

routine calibration adjustments

described

in Section 2.1.3

of this Exhibit

9709

at the various calibration

gas

levels (zero,

low,

mid

or high), but no

other

9710

corrective maintenance,

repair, re-linearization

or reprogramming of

the

9711

monitor. Trial

gas

injection

runs

may be

performed

after

the calibration

9712

adjustments

and

additional

adjustments

within

the allowable limits

9713

Section

2.1.3 of this Exhibit

may

be made

prior to the

linearity

check,

9714

necessary,

to optimize the

performance

of the monitor. The trial

gas

9715

injections

need

not

reported, provided that

they

meet the

specification

9716

for

trial gas

injections

Section

1.4(b)(3)(G)(v)

of this Appendix.

9717

However,

if, for

any

trial

injection,

the specification

in Section

9718

1.4(b)(3)(G)(v)

is not met,

the trial

injection

must be counted

as an

aborted

9719

linearity

check.

9720

9721

The

linearity

check

may

be done after repair,

corrective maintenance

9722

reprogramming

of the monitor.

In this case,

the monitor must

9723

considered

out-of-control

from the hour in

which the repair, corrective

9724

maintenance

or reprogramming

commenced

until the

linearity

check

has

9725

been

passed.

Alternatively,

the data validation

procedures

and associated

9726

timelines

in Sections

1.4(b)(3)(B)

through

(I)

of this Appendix

maybe

9727

followed upon completion

of the necessary

repair, corrective

maintenance,

9728

or reprogramming.

If the procedures

in Section

1.4(b)(3)

are used, the

9729

words

“quality

assurance”

apply instead

of the word

“recertification”.

9730

9731

Once a linearity check

has

been commenced,

the test must

be done hands-off.

JCAR350225-081 8507r01

9732

That is, no adjustments of the

monitor

are permitted during the linearity test

9733

period, other than the routine calibration adjustments

following daily calibration

9734

error tests, as

described in Section

2.1.3

of this Exhibit. If a routine daily

9735

calibration error test is performed and passed just prior to a linearity test

(or

9736

during a linearity test period) and a mathematical correction

factor is

9737

automatically applied by the DAHS, the

correction factor

must

be applied

all

9738

subsequent

data recorded

by the

monitor, including the

linearity

test

data.

9739

9740

ç)

If a daily calibration error test is failed during a linearity test

period,

prior

9741

completing

the test, the linearity test must be

repeated.

Data

from the monitor are

9742

invalidated prospectively from the hour of the failed

calibration error

test

until the

9743

hour of

completion of

subsequent successful calibration error test. The linearity

9744

test must not be conunenced until the monitor has

successfully completed a

9745

calibration error test.

9746

9747

out-of-control

period occurs when a linearity test is failed

(i.e.,

when the error

9748

linearity at any of the three

concentrations in the quarterly

linearity

check (or

9749

any of

the six concentrations, when both ranges of a single analyzer with a dual

9750

range are tested) exceeds the applicable specification in

Section 3.2 of Exhibit

9751

to this Appendix) or when a linearity test

is aborted due to a problem with the

9752

monitor or

monitoring

system.

The out-of-control period begins with the hour of

9753

the failed

or aborted linearity check and ends with the hour of completion of a

9754

satisfactory linearity check following

corrective

action and/or

monitor

repair,

9755

unless

the option in subsection (b)(3) of this

Section

to use the data

validation

9756

procedures and associated timelines in

Section

1.4(b)(3)(B)

through

(I)

of this

9757

Appendix

has been selected, in which case the beginning and end of the out-of-

9758

control period must be determined in accordance with

Sections 1.4(b)(3)(G)(i)

9759

and

(ii).

For a dual-range

analyzer, “hands-off’ linearity checks must be passed

9760

both

measurement

scales to end the out-of-control period.

9761

9762

more than four successive calendar quarters must elapse

after the

quarter in

9763

which a

linearity check of a monitor or monitoring system

(or

range of a monitor

9764

monitoring system) was last performed

without

a subsequent linearity test

9765

having been

conducted. If a linearity test has not been completed by the end of the

9766

fourth calendar quarter since the last linearity test, then the

linearity test must

9767

completed

within a 168 unit

operating hour or stack operating hour “grace period”

9768

(as

provided in Section 2.2.4 of this Exhibit) following the end of the fourth

9769

successive elapsed calendar quarter, or data from the CEMS

(or

range) will

9770

become invalid.

9771

9772

out-of-control period also occurs when a flow monitor

sample

line leak is

9773

detected.

The out-of-control period begins with the hour of the failed

leak

check

9774

and

ends

with the hour of a satisfactory leak check following

corrective action.

1CAR350225-08

1 8507r01

9775

9776

)

For each monitoring system, report the

results of all completed and partial

9777

linearity

tests

that

affect

data validation (i.e.,

all

completed, passed linearity

9778

checks; all

completed,

failed linearity checks; and all

linearity

checks aborted

due

9779

to a problem with the monitor, including

trial gas

injections

counted as failed

test

9780

attempts under subsection (b)(2) of this

Section or under Section 1 .4(b)(3)(G)(vi)

9781

of Appendix

B),

in the quarterly report required under 40 CFR 75.64,

9782

incorporated

reference

in Section 225.140. Note that linearity attempts

that are

9783

aborted or invalidated due

problems

with

the reference calibration gases or

due

9784

to operational problems

with the affected units need not be reported.

Such partial

9785

tests do not affect the validation

status of emission data recorded by the monitor.

9786

record

all linearity

tests, trial gas

injections

and test attempts (whether

9787

reported or not) must be kept on-site as

part of the official test log for each

9788

monitoring system.

9789

9790

2.2.4

Linearity

and Leak Check Grace Period

9791

9792

When a required linearity

test or flow monitor leak check has not been

completed

9793

the end of the

operating

quarter in which it is due or if, due to infrequent

9794

operation of a unit or infrequent use of a required

high

range

of a monitor or

9795

monitoring system, four successive calendar quarters have elapsed

after

the

9796

quarter in which a linearity

check of a monitor or monitoring

system

(or

range)

9797

was

last performed without

a subsequent linearity test having been done, the

9798

owner or operator has a grace period

of 168 consecutive unit operating hours,

9799

defined in

CFR 72.2, incorporated

reference

in Section

225.140

(or,

for

9800

monitors installed

on common stacks or bypass stacks, 168 consecutive

stack

9801

operating hours, as defined in 40

CFR

72.2)

in which to perform a linearity

test or

9802

leak

check

of that monitor or monitoring system

(or

range). The grace

period

9803

begins with the first unit or stack

operating hour following the calendar quarter

9804

which the linearity test was due. Data validation during

linearity

or leak check

9805

grace period must be done in accordance

with the applicable provisions in

Section

9806

2.2.3 of this Exhibit.

9807

9808

If, at

the end

the 168

unit

(or

stack) operating hour grace

period,

the

required

9809

linearity testor leak check has not been

completed, data from the monitoring

9810

system

(or

range) will be invalid, beginning with the first

unit operating hour

9811

following the expiration

of the

grace

period. Data from the monitoring system

(or

9812

range) remain

invalid

until the hour

of completion of a subsequent successful

9813

hands-off linearity test or leak check of the

monitor or monitoring system

(or

9814

range). Note that

when

a linearity test or a leak check is conducted within

a grace

9815

period for the purpose of

satisfying the linearity test or leak check requirement

9816

from a previous

operating

quarter, the results of that

linearity

test or leak

9817

check

may only be used to meet the linearity

check or leak check requirement

JCAR350225-08 1

8507r01

9818

the previous quarter,

not

the quarter in which the missed linearity test

leak

9819

check is completed.

9820

9821

2.2.5 Flow-to-Load

Ratio or Gross Heat Rate Evaluation

9822

9823

Applicability and methodology. Unless

exempted

from the flow-to-load ratio test

9824

under Section 7.8 to Appendix A to 40 CFR

, the owner

operator

must, for

9825

each flow rate monitoring

system installed on each unit, common stack or

9826

multiple stack, evaluate the flow-to-load

ratio quarterly, i.e., for each

9827

operating

quarter

(as

defined in 40 CFR 72.2, incorporated

reference

in Section

9828

225.140). At the end

each

operating quarter, the owner or operator must

9829

use Equation B-i to calculate the flow-to-load ratio for every hour during

the

9830

quarter in which: the unit

(or

combination

of units, for a common stack) operated

9831

within

10.0 percent

of L, the average load during the most recent normal-load

9832

flow RATA and a quality assured hourly

average flow rate was obtained with a

9833

certified flow rate

monitor. Alternatively, for the reasons stated in subsections

9834

(c)(1)

through (6) of this Section, the owner or operator

may

exclude

from the

9835

data

analysis

certain hours

within

10.0

percent

of Land may calculate L,

9836

values for only the remaining hours.

9837

9838

=-iO

(EquationB-i)

9839

9840

Where:

9841

= Hourly value

of the flow-to-load ratio, scfhlmegawatts, scffi/1000

lb/hr

of steam, or

scflul(mmBtu/hr

thermal output).

= Hourly stack gas volumetric flow rate, as measured

by the

flow

rate

monitor, scfh.

= Hourly

unit load,

megawatts, 1000 lb/hr of steam, or mmBtulhr

thermal

output must be within

10.0 percent of

L during

the

most

recent normal-load

flow RATA.

9842

9843

.11

Equation

B-i, the

owner or operator may use either bias-adjusted flow

9844

rates or

unadjusted

flow rates, provided that all

of the ratios are calculated

9845

the same way. For a common stack,

will be the sum of the hourly

9846

operating

loads of

all units that discharge through the stack. For a unit

that

9847

discharges its emissions through

multiple stacks or that monitors its

9848

emissions in multiple breechings,

will

be either the combined hourly

9849

volumetric

flow

rate for all of the stacks or ducts

(if

the test is done on a

9850

unit

basis) or the

hourly flow rate through each stack individually (if

the

9851

test

performed

separately

for each

stack).

For a unit with a multiple

JCAR350225-08 1

8507r01

9852

stack

discharge configuration consisting

of a main stack

and

a bypass

9853

stack, each of which has a certified flow monitor (e.g., a unit with a wet

9854

scrubber), calculate the

hourly flow-to-load ratios separately for each

9855

stack. Round off each value of

two decimal places.

9856

9857

)

Alternatively, the owner or operator may calculate the hourly gross heat

9858

rates

(GHR)

lieu of the

hourly

flow-to-load

ratios. The hourly GHR

9859

must be determined

only

for those hours in which quality assured

flow rate

9860

data and diluent gas

(CO

02)

concentration data are both available

9861

from a certified monitor or

monitoring system or

reference

method. If this

9862

option is selected, calculate each hourly GHR value as follows:

9863

9864

(GHR)h

= (Heatlnput)h

1000

(Equation B-la)

9865

9866

Where:

9867

(GHR)h

= Hourly value of the gross heat rate, Btu/kwh, Btullb steam

load, or

1000 mmBtu heat input/mmBtu thermal output.

(Heatlnput)h

= Hourly heat input, as determined from the quality assured

flow

rate and diluent data, using the applicable equation in

Exhibit

C to this Appendix, mmBtu/hr.

Hourly

unit

load, megawatts, 1000 lb/hr of steam, or

mmBtu/hr thermal output; must be within

10.0 percent

L during the most recent normal-load flow RATA.

9868

9869

In Equation B-la, the owner or

operator

may either use bias-adjusted

flow

9870

rates

unadjusted

flow

rates

in the calculation of

(Heatlnput)h,

provided

9871

that all of the heat input values are determined in the same manner.

9872

9873

The owner or operator must evaluate the calculated hourly flow-to-load

9874

ratios

(or gross heat

rates)

as follows.

separate data

analysis

must be

9875

performed for each primary and each redundant backup flow rate monitor

9876

used to

record and report

data during the quarter. Each analysis must be

9877

based on a minimum of 168 acceptable recorded hourly average flow

rates

9878

(i.e.,

at loads within + 10 percent of

L).

When two RATA load levels

9879

are designated as normal, the

analysis

must be performed at the higher

9880

load

level, unless there are fewer than 168 acceptable data points available

9881

at that load level, in which case the analysis must be performed at the

9882

lower

load level. If, for

particular

flow monitor,

fewer

than

168

9883

acceptable hourly flow-to-load ratios

(or

GHR

values) are available

at any

9884

of the load levels designated as normal, a flow-to-load

(or

GHR)

JCAR350225-08

8507r01

9885

evaluation is not required for that monitor for that calendar quarter.

9886

9887

For each flow monitor,

use

Equation B-2 in

this

Exhibit to calculate

9888

the absolute percentage difference between each hourly

value and R

9889

the

reference value

of the flow-to-load ratio, as detennined in accordance

9890

with Section

7.7 to Appendix A to 40 CFR 75. Note that Rmust always

9891

be based upon the

most

recent normal-load RATA, even if that RATA

was

9892

performed in the calendar quarter being evaluated.

9893

R -R,

9894

= rf

xlOO

(EquationB-2)

Rrei

9895

9896

Where:

9897

= Absolute percentage difference between the hourly average flow-to-

load

ratio

and the reference value of the

flow-to-load ratio

normal

load.

= The hourly average flow-to-load ratio, for each flow rate recorded

at a

load level within ± 10.0

percent

of L,.

= 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 75.

9898

9899

Equation B-2 must be used in a consistent manner. That is, use Rand

9900

if the flow-to-load ratio is being evaluated, and use

(GHR)ref

and (GHR)h

9901

the gross

heat

rate is being evaluated.

Finally,

calculate Efj

9902

arithmetic average of all of the hourly

values. The owner or operator

9903

must

report

the

results

each quarterly flow-to-load

(or

gross

heat rate)

9904

evaluation, as determined from Equation B-2, in the electronic quarterly

9905

report required under 40 CFR 75.64.

9906

9907

Acceptable results. The results of a quarterly flow-to-load

(or

gross

heat rate)

9908

evaluation are acceptable, and no further action is required, if the calculated value

9909

of Ef is less

than or equal to:

(1)

15.0 percent, if L for the most recent normal-

9910

load

flow RATA is 60 megawatts (or 500 klb/hr of steam) and if

unadjusted

9911

flow rates were used in the calculations; or

(2)

10.0

percent, if L for the most

9912

recent normal-load

flow RATA

60 megawatts (or 500 klb/hr

of steam) and

9913

bias-adjusted flow rates were used in the calculations; or

(3)

20.0

percent,

9914

for the most recent normal-load flow RATA is <60 megawatts

(or

< 500

9915

klb/hr of

steam)

and if unadjusted flow rates were used in the calculations; or (4)

9916

15.0 percent, if L

for

the most recent normal-load

flow

RATA is <60

9917

megawatts (or

< 500

klb/hr of steam) and if bias-adjusted

flow

rates were

used in

JCAR350225-081 8507r01

9918

the

calculations.

If Ef

above these

limits, the

owner or operator must

either:

9919

implement Option

1 in Section

2.2.5.1

of this Exhibit;

or perform

a RATA in

9920

accordance

with

Option

in Section

2.2.5.2

this Exhibit; or re-examine

the

9921

hourly

data used for the flow-to-load

or GHR

analysis

and recalculate

Ef, after

9922

excluding all

non-representative

hourly flow

rates. If Ef is

above

these limits, the

9923

owner

or operator

must

either: implement

Option

1 in Section 2.2.5.1

of this

9924

Exhibit:

perform a

RATA in accordance

with Option 2 in Section

2.2.5.2

of this

9925

Exhibit:

(if

applicable)

re-examine

the hourly data used

for the flow-to-load

9926

GHR

analysis

and

recalculate Ef, after

excluding all non-representative

hourly

9927

flow rates, as provided

in subsection

(c)

of this Section.

9928

9929

Recalculation of Ef.

the owner

or operator did not exclude

any hours within

9930

percent

of L

from the original data

analysis and

chooses

to recalculate

9931

the flow rates for the

following hours

are considered non-representative

and

may

9932

excluded from

the data analysis:

9933

9934

Any hour in

which the type of

fuel combusted was

different

from

the fuel

9935

burned during

the most recent

normal-load RATA.

For purposes of this

9936

determination,

the type of fuel

is different

the fuel is in a different

state

9937

of matter (i.e.,

solid,

liquid,

or gas) than is the fuel

burned during

the

9938

RATA or

if the fuel is

different classification

of coal

(e.g.,

bituminous

9939

versus

sub-bituminous).

Also,

for units

that co-fire different

types of

fuels,

9940

if the reference RATA

was done

while

co-firing, then hours

in which

9941

single fuel was combusted

may

excluded

from

the

data

analysis

9942

different fuel

hours

(and

vice-versa

for co-fired hours, if

the reference

9943

RATA was done

while

combusting

only

one type of

fuel):

9944

9945

)

For a unit that is

equipped

with

scrubber and

which always

9946

discharges its

flue gases to the atmosphere

through

a single stack, any

9947

hour in which the

1 scrubber

was bypassed;

9948

9949

Any hour in which

“ramping”

occurred, i.e., the hourly

load differed

9950

more than

15.0 percent from the

load

during

the

preceding

hour or

the

9951

subsequent hour;

9952

9953

For

unit with a

multiple

stack

discharge configuration

consisting

of a

9954

main stack and

a bypass stack,

any hour in which

the flue gases were

9955

discharged

through

both

stacks:

9956

9957

If a normal-load

flow

RATA was performed

and passed during the

quarter

9958

being

analyzed, any hour

prior to completion

of that RATA;

and

9959

9960

)

If a

problem

with

the accuracy of the flow

monitor was

discovered

during

JCAR350225-081

8507r01

9961

the

quarter and was corrected

(as evidenced by

passing the

abbreviated

9962

flow-to-load

test in Section 2.2.5.3

this Exhibit),

any

hour prior to

9963

completion of

the

abbreviated

flow-to-load

test.

9964

9965

After identifying

and excluding all

non-representative

hourly

data in

9966

accordance with

subsections

(c)(1)

through

(6)

of this

Section,

the

owner

9967

or operator may

analyze the remaining

data a

second

time. At least 168

9968

representative hourly

ratios or GHR values

must be

available to

perform

9969

the analysis: otherwise,

the

flow-to-load

(or GHR)

analysis is not required

9970

for

that monitor for

that calendar quarter.

9971

9972

If, after

re-analyzing

the data, Ef meets

the

applicable

limit in subsection

9973

(b)(1),

(b)(2), (b)(3),

or (b)(4)

this

Section,

further action is

required.

9974

If,

however,

Ef is

still above the

applicable limit, data

from the

monitor

9975

will be declared out-of-control,

beginning

with

the

first

unit operating

9976

hour

following the

quarter in which Ef

exceeded the

applicable

limit.

9977

Alternatively, if a probationary

calibration

error

test

is performed and

9978

passed

according

Section

1.4(b)(3)(B)

of this Appendix,

data

from the

9979

monitor may be declared

conditionally

valid following

the quarter in

9980

which

Ef exceeded the

applicable limit.

The

owner

or operator must then

9981

either implement

Option

1 in Section

2.2.5.1 of this Exhibit

or Option 2 in

9982

Section

2.2.5.2

this Exhibit.

9983

9984

2.2.5.1 Option

9985

9986

Within

unit

operating

days of the end

of the calendar

quarter for which

the Ef value is

above

9987

the

applicable

limit,

investigate and troubleshoot

the

applicable flow monitors.

Evaluate

the

9988

results of each

investigation

as follows:

9989

9990

If the

investigation

fails to

uncover a problem

with

the

flow monitor, a RATA

9991

must be

performed in accordance

with

Option 2 in Section

2.2.5.2 of

this

Exhibit.

9992

9993

If a

problem

with the flow

monitor is

identified through the

investigation

9994

(including

the need to

re-linearize the monitor

changing

the polynomial

9995

coefficients

or K

factors),

data from the

monitor are considered

invalid back

the

9996

first unit

operating hour after

the

end of the

calendar

quarter

for which Ef was

9997

above the

applicable

limit.

If the option to use

conditional

data validation was

9998

selected under

Section

2.2.5(c)(8)

of this

Exhibit, all

conditionally

valid data

will

9999

be invalidated,

back to the first unit

operating

hour after the

end of the calendar

10000

quarter

for

which

Ef was above

the applicable limit.

Corrective

actions must be

10001

taken. All corrective

actions (e.g.,

non-routine

maintenance, repairs,

major

10002

component

replacements,

re-linearization

the monitor,

etc.)

must be

10003

documented

the operation

and

maintenance records

for the monitor.

The owner

JCAR350225-08 1 8507r01

10004

operator then

must either complete

the abbreviated flow-to-load test in Section

10005

2.2.5.3 of this Exhibit,

or, if the corrective action taken has required

10006

relinearization of the flow monitor,

must perform a 3-load RATA. The

10007

conditional data

validation procedures

Section

1.4(b)(3)of

this

Appendix may

10008

be applied to the 3-load

RATA.

10009

10010

2.2.5.2

Option

10011

10012

Perform

a single-load RATA

(at

a load

designated as normal under Section 6.5.2.1 of Exhibit

10013

to this Appendix) of each flow monitor for which

Ef is outside of the applicable limit. If the

10014

RATA is

passed hands-off, in accordance

with Section

2.3.2(c)

of this Exhibit, no further

action

10015

is required and the out-of-control period for the monitor

ends at the date and hour of

completion

10016

of a

successful RATA, unless the option

to use conditional data validation was selected

under

10017

Section

2.2.5(c)(8)

this

Exhibit.

In that case, all conditionally

valid data from the monitor are

10018

considered to be quality-assured, back

to the first unit operating hour following the end

of the

10019

calendar quarter

for which

the Ef value was above the applicable

limit. If the

RATA

is failed,

all

10020

data

from the monitor will be invalidated,

back

to the first

imit

operating hour following the

end

10021

of the calendar quarter for which the Ef value was above the

applicable limit. Data from the

10022

monitor remain

invalid

until the required

RATA has been passed. Alternatively, following

10023

failed

RATA and corrective actions, the conditional

data validation procedures of Section

10024

1 .4(b)(3)

of this Appendix may be used until the RATA

has been passed. If the corrective

actions

10025

taken following the

failed

RATA included

adjustment

of the

polynomial coefficients or K factors

10026

the flow

monitor,

3-level

RATA is required, except as otherwise specified in Section

2.3.1.3

10027

of this Exhibit.

10028

10029

2.2.5.3 Abbreviated Flow-to-Load

Test

10030

10031

The following abbreviated flow-to-load test

may be performed after any

10032

documented repair,

component replacement, or other corrective maintenance

10033

flow monitor (except for changes affecting

the linearity of the flow monitor,

such

10034

adjusting

the flow

monitor coefficients or K

factors)

to demonstrate

that the

10035

repair, replacement, or other maintenance has

not significantly affected the

10036

monitor’s ability to accurately

measure the stack gas volumetric flow rate.

Data

10037

from the monitoring system are considered invalid

from the hour of

10038

commencement of the repair,

replacement, or maintenance until either

the hour in

10039

which the abbreviated flow-to-load

test

passed, or the hour in which a

10040

probationary calibration error test is passed following

completion of the repair,

10041

replacement, or maintenance

and any associated adjustments to the monitor.

If the

10042

latter option is selected, the abbreviated

flow-to-load

test must be completed

10043

within 168 unit operating hours of the probationary

calibration error test

(or,

for

10044

peaking units, within 30 unit operating days, if

that is less

restrictive).

Data

from

10045

the monitor

are

considered to be conditionally valid

(as

defined

in 40

CFR 72.2,

10046

incorporated

reference in

Section

225.140),

beginning with the hour

of the

JCAR350225-08 1 8507r01

10047

probationary calibration error

test.

10048

10049

)

Operate

the units in

such a way as to reproduce, as closely as

practicable,

the

10050

exact conditions at the time

the

most recent normal-load

flow

RATA. To

10051

achieve this, it is recommended that the

load

be held constant to within

+ 10.0

10052

percent

of the

average

load during the RATA and that the diluent gas

(CQ2

02)

10053

concentration be

maintained within

0.5 percent

CO2

of the average diluent

10054

concentration during the RATA.

For

common stacks, to the

extent

practicable, use

10055

the same combination of units and load levels that were used during the RATA.

10056

When the

process

parameters

have

been set, record a minimum of six and a

10057

maximum of 12 consecutive hourly average flow rates, using the flow monitors

10058

for which Ef

was

outside the applicable limit. For peaking units, a minimum of

10059

three and a maximum of 12 consecutive hourly average flow rates are required.

10060

Also

record the corresponding hourly

load

values

and, if applicable, the hourly

10061

diluent gas concentrations. Calculate the flow-to-load ratio

(or GHR)

for each

10062

hour in

the test hour period,

using Equation

B-i or B-ia.

Determine

for each

10063

hourly flow- to-load ratio

(or GHR).

using Equation B-2 of this Exhibit and then

10064

calculate Ef,

the arithmetic

average of the Eh values.

10065

10066

ç)

The results of the abbreviated flow-to-load test will be considered acceptable,

and

10067

further

action is

required if the value of

does not exceed the applicable limit

10068

specified

in Section 2.2.5

of this Exhibit. All conditionally

valid

data recorded

10069

the flow

monitor will be considered quality assured, beginning with the

hour of

10070

the

probationary calibration error test that preceded the abbreviated flow-to-load

10071

test

(if

applicable). However, if Ef is outside the applicable limit, all conditionally

10072

valid data recorded by the flow monitor

(if

applicable) will be considered invalid

10073

back to

the hour of the probationary calibration error test that preceded the

10074

abbreviated flow-to-load test, and a single-load RATA is required in accordance

10075

with

Section

2.2.5.2 of this Exhibit. If the flow monitor must

re-linearized,

10076

however, a 3-load RATA is required.

10077

10078

2.3

Semiannual and Annual Assessments

10079

10080

For each

primary and redundant backup monitoring system, perform relative accuracy

10081

assessments either

semiannually or annually, as specified in Section 2.3.1.1 or 2.3.1.2 of this

10082

Exhibit for the

type

of test and the performance achieved. This requirement applies as of the

10083

calendar

quarter following

the calendar quarter in

which the monitoring system is provisionally

10084

certified.

summary chart showing the frequency with which a relative accuracy test

audit must

10085

performed,

depending on the accuracy achieved, is located at the end of this Exhibit in Figure

10086

10087

10088

2.3.1 Relative Accuracy Test

Audit

(RATA)

10089

JCAR350225-081 8507r01

10090

2.3.1.1 Standard RATA Frequencies

10091

10092

Except for mercury monitoring systems,

and as otherwise

specified

Section

10093

2.3.1.2 of this Exhibit, perform relative accuracy test audits semiannually, i.e.,

10094

once every two

successive

operating quarters

(as

defined in 40 CFR 72.2,

10095

incorporated by reference in

Section

225.140)

for each primary and redundant

10096

backup

flow monitor,

CO2

diluent

monitor used to

determine heat input,

10097

moisture monitoring system. For each primary and redundant backup mercury

10098

concentration monitoring system and each sorbent trap monitoring system,

10099

RATAs must be performed

annually,

i.e.,

once

every four successive

10100

operating quarters

(as

defined in

CFR 72.2). A calendar quarter that does not

10101

qualify as a

operating quarter must

excluded in determining the deadline

10102

for the next RATA. No more than eight successive calendar quarters must elapse

10103

after the quarter in which a RATA was last performed without a subsequent

10104

RATA

having been

conducted.

a RATA has not been

completed

by the end of

10105

the eighth calendar quarter since the quarter of the last RATA, then the RATA

10106

must be

completed within

720 unit

(or stack)

operating

hour grace

period

(as

10107

provided

in Section 2.3.3 of this

Exhibit)

following the end of the eighth

10108

successive elapsed calendar quarter, or data from the CEMS will become invalid.

10109

10110

})

The relative accuracy test audit frequency of a CEMS may be reduced, as

10111

specified in Section 2.3.1.2 of this Exhibit, for primary or redundant backup

10112

monitoring systems which qualify for less frequent testing. Perform all required

10113

RATAs in accordance with the applicable procedures and provisions in Sections

10114

6.5

through 6.5.2.2 of Exhibit

A to

this

Appendix and

Sections 2.3.1.3

and 2.3.1.4

10115

this Exhibit.

10116

10117

2.3.1.2 Reduced RATA Frequencies

10118

10119

Relative accuracy

test

audits of primary and redundant

backup

CO2

diluent monitors

used

10120

to determine

heat input, moisture monitoring systems, flow monitors may be performed annually

10121

(i.e.,

once every

four

successive

operating quarters, rather than once every two successive

10122

operating

quarters)

if any of the following conditions are met for the specific monitoring

10123

system involved:

10124

10125

The

relative accuracy during the audit of

diluent monitor

used to

10126

determine heat input is 7.5

percent:

10127

10128

The

relative accuracy during the audit

of a

flow

monitor is

7.5

percent at each

10129

operating level tested:

10130

10131

For low flow

0.0

fs),

as measured by the reference method during the RATA

10132

stacks/ducts, when

the

flow

monitor

fails to achieve a relative accuracy 7.5

JCAR350225-08 1 8507r01

10133

percent

during the audit, but the monitor

mean

value, calculated using Equation

10134

A-7 in Exhibit A

to this Appendix

and converted

back

an equivalent velocity in

10135

standard feet

per second

(fps),

is within

1.5

fps of the reference method mean

10136

value, converted to an equivalent velocity in fps;

10137

10138

çj)

For a

monitor, when

the

mean difference

between

the reference method

10139

values from the

RATA and the corresponding monitor values is within

0.7

10140

percent CO2

oQ; and

10141

10142

When the

relative accuracy of a continuous moisture monitoring system is 7.5

10143

percent or when the mean difference between the

reference method values from

10144

the RATA and

the corresponding monitoring system values is within

1.0

10145

percent H

10146

10147

2.3.1.3

RATA Load

(or

Operating) Levels and

Additional RATA Requirements

10148

10149

For

diluent monitors used to

determine heat input, mercury

10150

concentration

monitoring systems, sorbent trap monitoring systems, moisture

10151

monitoring

systems,

the

required semiannual or annual RATA

tests must be

done

10152

at the load level (or operating

level)

designated

normal under Section 6.5.2.1(d)

10153

of Exhibit A to

this Appendix. If two load levels

(or

operating

levels)

are

10154

designated as

normal, the required RATAs may be done at either load

level

(or

10155

operating

level).

10156

10157

}

For flow monitors installed and bypass stacks,

and for flow monitors that qualify

10158

to perform only

single-level RATAs under Section 6.5.2(e) of Exhibit A to this

10159

Appendix, all required semiannual or annual relative accuracy

test audits must

10160

single-load

(or

single-level) audits at

the normal load

(or

operating

level),

10161

defined

in Section

6.5.2.1(d)

of Exhibit A to this

Appendix.

10162

10163

For all

other flow monitors, the RATAs must be performed as

follows:

10164

10165

An annual 2-load

(or

2-level) flow

RATA

must be

done at the two most

10166

frequently used load

levels

(or

operating levels), as determined under

10167

Section

6.5.2.1(d)

of Exhibit A to this

Appendix, or (if applicable) at

the

10168

operating levels determined

under Section

6.5.2(e)

of Exhibit A to this

10169

Appendix. Alternatively, a 3-load

(or

3-level) flow RATA at the low, mid,

10170

and high load levels

(or

operating

levels),

as defined

under Section

10171

6.5.2.1(b)

of Exhibit A to this Appendix,

may

performed in lieu

of the

10172

2-load

(or

2-level) annual

RATA.

10173

10174

)

If the

flow monitor is on

semiannual RATA frequency, 2-load

(or

10175

level)

flow RATAs and single-load

(or

single-level) flow RATAs at

the

JCAR350225-08

8507r01

10176

normal load level (or normal operating level) maybe performed

10177

alternately.

10178

10179

)

A single-load (or single-level) annual flow RATA may be performed

10180

lieu of the

2-load

(or

2-level)

RATA if the results of an historical load data

10181

analysis show

that in the time period extending from the ending date of the

10182

last annual flow RATA to a date that

is no

more than 21

days prior to the

10183

date of the current annual flow RATA, the unit

(or

combination of units,

10184

for a common

stack)

has operated at a single load level

(or

operating level)

10185

(low,

mid, or

high),

for 85.0 percent of the time. Alternatively, a flow

10186

monitor may qualify for a single-load (or single-level) RATA if the 85.0

10187

percent criterion is met in the time period extending from the beginning

10188

the

quarter in which

the last annual flow RATA was performed through

10189

the end of the calendar quarter preceding the quarter of current annual

10190

flow RATA.

10191

10192

A 3-load (or 3-level) RATA, at the low-,

mid-, and high-load

levels

(or

10193

operating levels), as determined under Section 6.5.2.1 of Exhibit A to

this

10194

Appendix,

must be performed at least once every twenty consecutive

10195

calendar quarters, except for flow monitors

that are exempted from 3-load

10196

(or 3-level)

RATA testing under Section 6.5.2(b) or 6.5.2(e)

Exhibit

10197

to this Appendix.

10198

10199

)

A 3-load

(or

3-level)

RATA

is required whenever a flow monitor is re

10200

linearized, i.e., when its polynomial

coefficients or K factors are changed,

10201

except for flow monitors that are exempted from 3-load (or 3-level)

10202

RATA testing

under

Section

6.5.2(b)

or 6.5.2(e) of Exhibit A to this

10203

Appendix. For monitors so exempted under Section 6.5.2(b),

a single-load

10204

flow RATA is required. For monitors so exempted under Section 6.5.2(e),

10205

either a single-level RATA or a 2-level RATA is required, depending

10206

the number of

operating

levels documented in the monitoring plan for

the

10207

unit.

10208

10209

)

For all multi-level flow audits, the audit points at adjacent load levels

or at

10210

adjacent

operating levels

(e.g., mid and high) must be separated by no less

10211

than 25.0 percent of the “range of operation,” as defined

in Section 6.5.2.1

10212

of Exhibit A to this Appendix.

10213

10214

ci)

A RATA of a

moisture monitoring system must

be performed whenever the

10215

coefficient, K factor or mathematical algorithm determined under Section

6.5.6 of

10216

Exhibit A to this Appendix is changed.

10217

10218

2.3.1.4 Number

RATA

Attempts

JCAR350225-08 1 8507r01

10219

10220

The

owner or operator may

perform

as many

RATA

attempts as are

necessary

achieve the

10221

desired

relative accuracy test

audit frequencies. However, the data validation procedures in

10222

Section 2.3.2 of this

Exhibit must be followed.

10223

10224

2.3.2

Data

Validation

10225

10226

RATA must not commence if the monitoring system is operating out-of-control

10227

with respect to any of the daily and quarterly quality

assurance assessments

10228

required by

Sections 2.1 and 2.2 of this Exhibit or with respect to the additional

10229

calibration error test requirements in Section

2.1.3

this Exhibit.

10230

10231

Each required RATA must be done according to

subsection

(b)(1’), (b)(2)

(b)(3)

10232

of this

Section:

10233

10234

The

RATA may be done “cold”, i.e., with no corrective

maintenance,

10235

repair,

calibration

adjustments,

re-linearization or reprogramming of the

10236

monitoring

system

prior to the test.

10237

10238

The RATA maybe done after

performing

only

the routine or non-routine

10239

calibration adjustments described in Section 2.1.3 of this Exhibit at the

10240

zero

and/or

upscale

calibration gas levels, but no other

corrective

10241

maintenance, repair, re-linearization or reprogramming of

the monitoring

10242

system. Trial RATA runs may be

performed after the calibration

10243

adjustments

and additional

adjustments within

the allowable limits in

10244

Section

2.1.3 of this Exhibit maybe made prior to the RATA, as

10245

necessary, to

optimize

the performance of

the

CEMS.

The trial RATA

10246

runs need not

be reported, provided that they meet the specification for

10247

trial RATA runs in Section

1.4(b)(3)(G)(v)

of this

Appendix. However,

if,

10248

for any trial run, the

specification in Section

(b)(3)(G)(v)

of this Appendix

10249

is not met, the trial run must be counted as

aborted

RATA attempt.

10250

10251

The RATA may be done after repair,

corrective maintenance, re

10252

linearization

reprogramming of the monitoring system. In this case, the

10253

monitoring system will be considered

out-of-control

from the hour in

10254

which the repair,

corrective maintenance, re-linearization or

10255

reprogramniing is commenced until the RATA has been passed.

10256

Alternatively, the data validation procedures

and associated timelines

10257

Sections

1.4(b)(3)(B)

through

(I)

this Appendix

maybe

followed

upon

10258

completion of the

necessary repair, corrective maintenance, re

10259

linearization or reprogramming. If the procedures in Section 1.4(b)(3) of

10260

this

Appendix are used, the words “quality assurance” apply

instead

of the

10261

word “recertification”.

JCAR350225-081

8507r01

10262

10263

Once a RATA is commenced, the test

must be done hands-off. No

adjustment

10264

the monitor’s calibration is permitted during

the

RATA

test period, other than the

10265

routine

calibration

adjustments following daily calibration error tests, as described

10266

in Section 2.1.3

this Exhibit.

If a routine daily calibration error test is

10267

performed and passed just prior to

RATA

(or

during a RATA test period) and

10268

mathematical correction factor is automatically applied

by the DAHS, the

10269

correction factor must be applied to all subsequent data recorded by the monitor,

10270

including the RATA test data. For 2-level

and 3- level flow monitor audits, no

10271

linearization or reprogramming of the monitor is permitted in between load

levels.

10272

10273

For single-load

(or

single-level) RATAs, if a daily calibration error test is failed

10274

during

a RATA test period, prior to

completing the test, the RATA must be

10275

repeated. Data from the monitor are invalidated prospectively from the hour

of the

10276

failed calibration error test until the hour

completion

of a subsequent successful

10277

calibration error test. The subsequent RATA must not be commenced until the

10278

monitor has

successfully passed

a calibration error

test

in accordance with Section

10279

2.1.3 of this

Exhibit.

Notwithstanding these requirements, when ASTM D6784-02

10280

(incorporated

reference under

Section

225.140)

or Method 29 in appendix

A-8

10281

40 CFR 60, incorporated

reference in Section 225.140,

used

as the

10282

reference method for the RATA of a mercury CEMS, if

calibration error

test of

10283

the CEMS is failed during a RATA test period, any test runs completed prior

10284

the failed

calibration error

test need not

be repeated; however, the RATA may

not

10285

continue until a subsequent calibration

error test of the mercury CEMS has been

10286

passed. For multiple-load

(or

multiple-level) flow

RATAs, each load level (or

10287

operating

level)

is treated as a separate RATA

(i.e.,

when a calibration error

test is

10288

failed

prior

completing the

RATA at a particular load level (or operating level),

10289

only the RATA at that load level

(or

operating level) must be repeated;

the results

10290

of any

previously-passed RATAs

at the other load levels (or operating levels)

are

10291

unaffected, unless re-linearization of the monitor is required

correct

the

10292

problem that caused the calibration

failure, in which case a subsequent 3-load

(or

10293

3-level)

RATA is required), except as otherwise provided in Section 2.3.1.3(c)(5)

10294

this Exhibit.

10295

10296

For

RATA performed using

the option in subsection

(b)(1)

or (b)(2) of this

10297

Section, if the RATA is failed

(that

is, if the relative

accuracy

exceeds

the

10298

applicable

specification

in Section 3.3 of Exhibit A to this

Appendix)

or if

the

10299

RATA is aborted prior to completion

due to a problem with the CEMS, then

the

10300

CEMS is out-of-control and all emission

data

from

the CEMS are

invalidated

10301

prospectively from the hour in which the RATA is failed

aborted.

Data

from

10302

the CEMS

remain invalid

until the hour of completion of

subsequent RATA

that

10303

meets the

applicable

specification

in Section 3.3 of Exhibit A to this Appendix.

10304

the option in subsection

(b)(3) of this

Section

to use the data validation

JCAR350225-08 1 8507r01

10305

procedures

and

associated

timelines

Sections

1 .4(b)(3)(B) through(b)(3)(I)

10306

this

Appendix

has been selected,

the beginning and

end of the

out-of-control

10307

period must

determined

accordance

with

Section 1 .4(b)(3)(G)(i)

and

(ii)

10308

this Appendix.

Note that when

a RATA is aborted

for a reason other than

10309

monitoring

system malfunction

(see

subsection (g) of this

Section),

this

does

not

10310

trigger

out-of-control

period for the

monitoring system.

10311

10312

For

a 2-level

3-level flow RATA,

if, at any load level

(or

operating

level),

10313

RATA

failed or aborted

due to a

problem

with the flow

monitor, the RATA

10314

that

load level

(or

operating

level)

must

be repeated. The flow

monitor is

10315

considered

out-of-control

and data from the

monitor are

invalidated from the

hour

10316

which the test is

failed

or aborted and

remain invalid until

the passing of a

10317

RATA

the failed

load level

(or operating

level),

unless

the option in subsection

10318

(b)(3)

of this Section

to use the

data

validation

procedures

and associated

10319

timelines

in Section

1.4(b)(3)(B)

through

(b)(3)(I)

this

Appendix has been

10320

selected,

which

case the beginning

and end of the out-of-control

period

must be

10321

determined in accordance

with Section

1.4(b)(3)(G)(i)

and (ii) of this Appendix.

10322

Flow

RATA(s)

that

were previously passed

at the other load

levels

(or

operating

10323

levelss)

not have

to be repeated unless

the flow monitor

must be re-linearized

10324

following

the failed or aborted

test. If the flow

monitor is re-linearized,

10325

subsequent

3-load

(or

3-level)

RATA is

required,

except

as otherwise

provided in

10326

Section

2.3.1.3(c)(5)

of this

Exhibit.

10327

10328

For each

monitoring

system,

report

the results of all completed

and

partial

10329

RATAs

that

affect

data

validation

(i.e.,

all

completed,

passed

RATAs

all

10330

completed, failed RATAs

and all

RATAs aborted due

to a problem with the

10331

CEMS,

including

trial RATA runs counted

as failed test attempts

under

10332

subsection (b)(2) of

this Section or under

Section

1.4(b)(3)(G)(vi))

in the

10333

quarterly

report

rejuired under 40 CFR

75.64, incorporated

reference

10334

Section

225.140. Note

that RATA attempts

that

are aborted

or invalidated due

10335

problems

with

the

reference method or

due

to operational problems

with

the

10336

affected units need not

be reported.

Such runs do not affect

the validation status

10337

emission

data

recorded

the CEMS.

However, a

record

all RATAs,

trial

10338

RATA runs and RATA

attempts

(whether

reported

or not)

must be kept on-site

10339

part

of the

official

test log for each monitoring

system.

10340

10341

Each

time that a

hands-off RATA of

mercury concentration

monitoring system,

10342

sorbent

trap

monitoring

system, or a flow

monitor is passed,

perform

bias

test

10343

in accordance

with

Section

7.4.4 of Exhibit A

this Appendix.

10344

10345

Failure of the

bias

test

does not result

in the monitoring

system being

out-of

10346

control.

10347

JCAR350225-081 8507r01

10348

2.3.3 RATA Grace

Period

10349

10350

The owner or operator has

a grace

period

of 720 consecutive unit operating

hours,

10351

as defined in 40 CFR 72.2, incorporated

by reference in Section 225.140

(or,

for

10352

CEMS installed on common stacks or bypass stacks,

720 consecutive stack

10353

operating

hours,

as defined in 40 CFR

72.2),

in which

complete

the required

10354

RATA for a

particular

CEMS whenever:

10355

10356

required

RATA has not been performed

by the end of the

operating

10357

quarter in which it

is due; or

10358

10359

A required 3-load

flow RATA has not been performed

the end of

the

10360

calendar

quarter in which it is due.

10361

10362

The

grace

period

will begin with the first unit

(or stack)

operating hour following

10363

the calendar quarter in which the required RATA

was due. Data

validation

during

10364

RATA grace

period must be done in accordance with the applicable provisions

10365

in Section 2.3.2 of this Exhibit.

10366

10367

If, at

the end of the 720

unit

(or

stack)

operating hour grace period, the RATA

has

10368

not been completed, data

from the

monitoring

system will be invalid, beginning

10369

with the first unit operating hour following

the expiration of the grace period.

10370

Data from the CEMS remain invalid until the hour

of completion of a subsequent

10371

hands-off RATA. The deadline for the next test will

either two

operating

10372

quarters

(if

semiannual RATA frequency is

obtained)

or four

operating

10373

quarters

(if

an annual RATA frequency is

obtained) after the quarter in which

the

10374

RATA is completed, not to exceed eight calendar

quarters.

10375

10376

When a RATA is done during a grace period in order

to satisfy a RATA

10377

requirement from

quarter, the deadline for the next RATA must

10378

determined as follows:

10379

10380

If the

grace

period RATA qualifies for a reduced, (i.e., annual),

RATA

10381

frequency the deadline

for

the

RATA will be set at three

10382

operating quarters after the

quarter

in which the grace period

test

10383

completed.

10384

10385

)

If the grace period RATA qualifies for the

standard, (i.e., semiannual),

10386

RATA

frequency the deadline

for the next RATA will be set

at two

10387

operating quarters

after the quarter in which the grace period test is

10388

completed.

10389

10390

Notwithstanding

these requirements, no more than eight successive

JCAR350225-081 8507r01

10391

calendar quarters must

elapse

after the quarter in which the grace period

10392

test is completed, without a subsequent RATA having been conducted.

10393

10394

2.4

Recertification, Quality Assurance, and RATA Frequency

(Special

Considerations)

10395

10396

When a significant change is made to a monitoring system

such

that

10397

recertification of the monitoring system is required in accordance with Section

10398

1.4(b)

of this Appendix, a recertification test (or tests) must be perfonned to

10399

ensure that the CEMS continues to generate valid data. In

all

recertifications, a

10400

RATA

will

be one

the required tests; for some recertifications, other tests

will

10401

also be required. A recertification test may be used to satisfy the quality assurance

10402

test

requirement of this Exhibit. For example, if, for a particular change made

to a

10403

CEMS, one of the required recertification tests is a linearity

check

and the

10404

linearity check is successful, then, unless another recertification event occurs in

10405

that same

operating quarter, it would not be necessary to

perform an

10406

additional linearity test of the CEMS in that

quarter

to meet the quality assurance

10407

requirement of Section

2.2.1

of this

Exhibit.

For this

reason, EPA recommends

10408

that

owners

or operators coordinate

component

replacements,

system

upgrades,

10409

and other events that may require recertification, to the extent practicable, with

10410

the periodic

quality

assurance testing required by

this Exhibit. When a quality

10411

assurance

test is done for the dual purpose

recertification and routine quality

10412

assurance, the applicable data validation procedures in Section

1.4(b)(3)

must be

10413

followed.

10414

10415

)

Except as provided in

Section 2.3.3

of this Exhibit,

whenever a passing RATA

10416

a gas

monitor is performed, or a passing 2-load

(or 2-level)

RATA or a passing

104 17

load

(or

3-level) RATA of a flow monitor is performed (irrespective of whether

10418

the RATA is

done to satisfy

a recertification

requirement or to meet the quality

10419

assurance requirements of this Exhibit, or

both),

the RATA frequency

(semi-

10420

annual or

annual)

must be

established based

upon the date and time of completion

10421

of the RATA and the relative accuracy percentage obtained. For 2-load

(or

10422

level)

and

3-load

(or

3-level) flow RATAs, use the highest percentage relative

10423

accuracy at any of the loads

(or levels)

to determine the

RATA

frequency. The

10424

results of a

single-load

(or single-level)

flow RATA may be used to establish the

10425

RATA frequency when the single-load

(or

single-level)

flow RATA

10426

specifically

required under

Section

2.3.1.3(b) of this Exhibit or when the single-

10427

load

(or

single-level) RATA is allowed under Section 2.3.1.3(c) of this Exhibit for

10428

a unit that has operated at one load level

(or

operating

level)

for

85.0

percent of

10429

the time since the

last

annual flow RATA. No other

single-load (or single-level)

10430

flow RATA may

be used

to establish

an annual RATA frequency; however,

10431

load

or 3-load (or a 2-level

3-level) flow RATA may be performed at any time

10432

or in

place

of any required single-load

(or single-level)

RATA, in order to

10433

establish an annual RATA frequency.

JCAR350225-08 1 8507r01

10434

10435

2.5 Other Audits

10436

10437

Affected units

may

be subject to

relative accuracy test

audits at any time. If a monitor or

10438

continuous

emission monitoring

system

fails the relative accuracy

test

during the

audit,

the

10439

monitor

or continuous emission monitoring

system

will be considered to be out-of-control

10440

beginning with the date and time of completion of the audit, and continuing until a successful

10441

audit test is

completed following corrective action.

10442

10443

2.6

System Integrity Checks for Mercury Monitors

10444

10445

For

each mercury concentration monitoring system (except for a mercury monitor that does not

10446

have a

converter),

perform a single-point

system

integrity check weekly, i.e., at least once

every

10447

168 unit or stack

operating hours,

using a

NIST-traceable

source of oxidized mercury. Perform

10448

this check

using

a mid- or high-level gas concentration, as defined in Section 5.2 of Exhibit

A to

10449

this

Appendix. The

performance

specifications

subsection

(3)

of Section

3.2

of Exhibit A to

10450

this

Appendix must

be met, otherwise the monitoring

system

is considered out-of-control,

from

10451

the hour

of the failed check until a subsequent system integrity check is passed. If a required

10452

system integrity

check is not performed and passed within 168 unit or stack operating

hours of

10453

last

successful check, the monitoring system will also be considered out of control, beginning

10454

with the

169th unit or stack operating hour after the last successful check, and continuing until

10455

subsequent system integrity check is passed. This weekly check is not required if the daily

10456

calibration assessments

in Section 2.1.1 of this Exhibit are performed using

a NIST-traceable

10457

source

of oxidized

mercury.

10458

10459

[Note: The

following TABLE/FORM is too wide to be displayed on one screen. You must print

10460

it for a

meaningful

review

its contents. The table has been divided into multiple

pieces with

10461

each piece

containing information to help you assemble a printout of the table. The information

10462

for each

piece

includes: (1)

three line message preceding the tabular

data showing by line

and

10463

character

the

position of the upper left-hand corner of the piece and the position of the piece

10464

within

the entire

table; and

(2)

a numeric scale following the tabular data displaying the

character

10465

positions.]

10466

10467

Figure 1 for

Exhibit B of Appendix B Part 75. — Qaulity Assurance Test Requirements

Basic

test frequency requirements

FFN*]

Daily

Quarterly

Semiannual

[FN*]

Weekly

[FN*1

FFN*1

Annual

Calibration

Error

Test

Pt.)

JCAR350225-08

8507r01

Interference

Check

(flow)

Flow-to-Load

Ratio

Leak Check

(DP

flow

monitors)

Linearity

Check or System

Integrity Check

[FN**]

pt.)

Single-point System

Integrity

Check

FFN**1

RATA

(SO

NOXQ

[FN11

RATA

(All Hg monitoring

systems)

RATA

(flow)

[FN1J

[FN21

10468

10469

[FN*1

“Daily”

means operating days, only.

“Weekly”

means

once every 168 unit or stack

10470

operating hours.

“Quarterly”

means once every QA operating

quarter.

“Semiannual”

means

10471

once every two

operating quarters. “Annual” means once every four

operating

10472

quarters.

FFN**1

The system integrity check applies

only

to Hg monitors with converters.

10473

The

single-point weekly system integrity check is not required if

daily calibrations

are

10474

performed

using a NIST-traceable

source

oxidized

Hg.

The 3-point quarterly system

10475

integrity check is not

required if a linearity check is

performed.

10476

10477

[FN11

Conduct RATA

annually

(i.e.,

once every four QA operating quarters), if monitor

10478

meets

accuracy requirements to qualify for less frequent testing.

FFN21

For flow monitors

10479

installed on peaking units,

bypass stacks, or units that qualify for

single-level

RATA

testing

10480

under

Section

6.5.2(e)

of this

part,

conduct all RATAs at a

single, normal load

(or

operating

10481

level).

For other

flow monitors, conduct annual RATAs at two load levels (or operating

10482

levels).

Alternating

single-load

and

2-load

(or

single-level

and

2-level)

RATAs may

be done

10483

if a

monitor is on a

semiannual frequency. A single-load

(or

single-level) RATA may be

10484

done in lieu

of a 2-load

(or

2-level) RATA if, since the last

annual flow RATA, the

unit has

10485

operated at one load

level

(or

operating

level)

for

85.0 percent of the time. A 3-level

10486

RATA is required

at least once every five calendar years and

whenever

a flow monitor is re

10487

linearized,

except for flow monitors exempted from 3-level RATA testing

under

Section

10488

6.5.2(b)

6.5.2(e)

of Exhibit A to this Appendix.

10489

10490

10491

Figure

2 for Exhibit B of

Appendix

— Relative

Accuracy Test

Frequency Incentive

System

10492

JCAR350225-081 8507r01

RATA

Semiannual

[FNW1

(percent)

Annual FFNW1

SQ2

orNOx

[FNY1

7.5% <RA lO.0% or* 15.0 ppm

RA 7.5% or± 12.0

ppm

[FNX1

FFNX1.

-diluent

7.5%

<RA

10.0% or ± 0.030

7.5% or ± 0.025

lb/mmBtu FFNX1

lb/mmBtu =G5X.

NOx-diluent

7.5% <RA

10.0% or

± 0.020

7.5%

± 0. 015

lb/mmBtu

FFNX]

lb/mmBtu [FNX].

Flow

7.5% <RA 10.0% or± 2.0

fps

RA 7.5% or± 1.5

fps

[FNX]

[FNX1.

or02

7.5%<RA 10.0%or± 1.0

7.5%or±0.7%

cQLQ2

FFNX1

cQLQ2

FFNX1.

HgFFNX1

N/A

RA<20.0%or±l.0

<<mu>>g/scm

FFNX1.

Moisture

7.5%<RA

10.0%or± 02

1.5%H RA

7.5%or± 1.0%H

[FNX1

FFNX].

10493

10494

[FNW]

The deadline for the next RATA

is the end of the second (if semiannual)

or fourth

(if

10495

annual)

successive

operating quarter

following the quarter in which the CEMS

was last

10496

tested. Exclude calendar quarters with fewer than 168 unit

operating hours

(or,

for comi-non

10497

stacks

and bypass stacks, exclude quarters

with fewer than 168 stack operating

hours)

10498

determining the RATA deadline. For

monitors,

operating quarters in which

only

10499

very

low sulfur fuel as defined in 40

CFR 72.2, incorporated by reference

in Section

10500

225.140, is combusted may also be excluded. However, the exclusion

of calendar

quarters

10501

limited as follows: the deadline for the next

RATA will be no more than

calendar

quarters

10502

afler the

quarter in which a RATA

was last

performed.

FFNX]

The difference between

10503

monitor_and_reference method mean values

applies to moisture monitors,

CO2.and

10504

monitors,

low emitters

of SO

NON,

or H, or and low flow,

only. The specifications for

10505

monitors also apply to sorbent trap monitoring

systems.

[FWY1

NOx

concentration

10506

monitoring system used to determine

mass emissions

under 40 CFR 75.71,

10507

incorporated

reference in Section

225.140.

JCAR350225-081 8507r01

10508

10509

Exhibit

C to Appendix

B--Conversion Procedures

10510

10511

Applicability

10512

10513

Use

the

procedures in this

Exhibit

to convert measured

data from a

monitor or continuous

10514

emission monitoring

system

into the appropriate

units of the standard.

10515

10516

Procedures for Heat

Input

10517

10518

Use the

following

procedures to compute

heat input

rate

to an affected

unit

(in

mmBtu/hr or

10519

mmBtu/day):

10520

10521

2.1

10522

10523

Calculate and

record heat input

rate

to an affected unit

on an hourly basis.

The owner or operator

10524

may

choose to

use the

provisions

specified

CFR

75.16(e),

incorporated

reference

10525

Section 225.140,

conjunction

with the

procedures

provided

in Sections

2.4 through 2.4.2

10526

apportion

heat

input among each unit

using

the common

stack or common pipe

header.

10527

10528

2.2

10529

10530

For an affected

unit that

has a flow monitor

(or

approved

alternate

monitoring system under

10531

subpart E of

40 CFR 75, incorporated

by reference

in Section

225.140,

for measuring volumetric

10532

flow

rate)

and

a diluent gas

(02

CO)

monitor, use

the

recorded

data

from

these monitors

and

10533

one of

the following

equations

to calculate hourly

heat input rate

(in mmBtu/hr).

10534

10535

2.2.1

10536

10537

When

measurements

of CO2

concentration

are on a wet

basis,

use the

following equation:

10538

1%CO

10539

HI=Q

—

100

(EquationF-15)

10540

10541

Where:

10542

Hourly

heat input rate during

unit operation, mmBtulhr.

Hourly average volumetric

flow rate during

unit

operation,

wet

basis, seth.

= Carbon-based F-factor,

listed

in Section

3.3.5 of appendix

40 CFR 75

for

each

fuel, scf/mmBtu.

%çQ

Hourly concentration

of 2

CO during

unit operation, percent

JCAR350225-081

8507r01

CO2

wet

basis.

10543

10544

10545

2.2.2

10546

10547

When

measurements

of CO2 concentration

are on

dry basis,

use

the

following

equation:

10548

10549

= Qhr

(100 — %H2

%C02d

(Equation

F-

16)

100F

]

100

10550

10551

Where:

10552

ffl

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

of appendix

F to 40

CFR 75 for each fuel,

scf/mniBtu.

%CO

Hourly

concentration

during unit

operation, percent

wet

basis.

Moisture content of

gas in the stack, percent.

10553

10554

2.2.3

10555

10556

When measurements

concentration

are on a wet basis,

use

the following

equation:

10557

10558

= Q__[(20.9/100X100/H

O)%O

(Equation

F-17)

10559

10560

Where:

10561

Hourly

heat input rate during

unit operation,

mmBtu/hr.

= Hourly

average volumetric

flow rate

during

unit operation, wet

basis,

scth.

Carbon-based

F-factor, listed

in Section 3.3.5 of

appendix F to 40 CFR

for each

fuel, scf/mmBtu.

Hourly

concentration

during unit operation,

percent

wet basis.

= Hourly average

stack

moisture

content,

percent

by volume.

10562

10563

2.2.4

10564

10565

When

measurements of

concentration are

on a

dry

basis,

use the following

equation:

JCAR350225-081

8507r01

10566

10567

= Qw[(b00l20)1[(20.902u]

(Equation

F-18)

10568

10569

Where:

10570

ffl

Hourly

heat

input rate

during unit

operation, mmBtu/hr.

Hourly

average

volumetric flow

during unit operation,

wet basis,

scfh.

Dry basis F-factor, listed

in Section

3.3.5 of appendix F

to 40

CFR

75 for

each

fuel,

dscf/mmBtu.

= Moisture

content

of the

stack

gas, percent.

Hourly concentration

during

unit operation, percent

Ocy

basis.

10571

10572

10573

10574

Heat Input

Summation

(for

Heat Input

Detennined Using

a Flow Monitor

and Diluent

Monitor)

10575

10576

2.3.1

10577

10578

Calculate total

quarterly heat

input

for a unit

or common stack using

a flow monitor

and diluent

10579

monitor to

calculate heat input,

using

the

following

equation:

10580

10581

HIq = HI

(Equation

F-18a)

hour—I

10582

10583

Where:

10584

HIq

= Total heat

input for

the quarter, mmBtu.

Hourly heat input

rate during unit

operation, using

Equation F-15, F

16, F-17, orF-18,

mmBtu/hr.

Hourly operating

time

for the unit

or common

stack, hour or fraction

an hour

(in

equal

increments

that can range from

one

hundredth

one quarter

of an hour,

the option of the owner

or operator).

10585

10586

2.3.2

10587

10588

Calculate

total

cumulative

heat input for

a unit or common

stack using

flow

monitor and

10589

diluent

monitor

calculate heat input,

using

the following

equation:

10590

JCAR350225-08 1 8507r01

HI =

the — current — quarter

HIq

q=1

10591

10592

10593

10594

10595

10596

10597

10598

10599

10600

10601

10602

10603

10604

10605

10606

10607

10608

10609

10610

(Equation F-i 8b

Where:

= Total heat input

for the quarter, mmBtu.

HIq

Total

heat

input

for the quarter, 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:

(Equation

F-2 1

Where:

= Heat input rate

for a unit, mmBtu/hr.

= Heat

input

rate

the

common stack or pipe, mmBtu/hr.

= Gross electrical output,

MWe.

= Unit operating time, hour or fraction

of an hour (in equal

increments that can range from one

hundredth

one quarter of

an hour, at the option of the owner

or operator).

tCS

= Common stack or common pipe

operating time, hour or

fraction of an hour

(in

equal

increments that

can range from

one

hundredth

one quarter of an hour, at the option

the

owner or

operator).

Total number

units

using

the

common stack or pipe.

= Designation of a particular unit.

2.4.2

JCAR350225-08 1

8507r01

10611

10612

Where applicable,

the

owner

operator of

an affected unit that

determines the

heat input rate

10613

the unit

level

apportioning

the heat input

rate monitored at

a common stack or common

pipe

10614

using

steam

load must apportion

the heat

input

rate

using

the following

equation:

10615

10616

(Equation

F-21b)

10617

10618

Where:

10619

= 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/hi,

or mmBtu/hr.

= Unit

operating time,

hour or fraction of an

hour (in equal

increments

that

can range

from one

hundredth

one quarter

an hour,

at the

option

of the owner or

operator).

= Common

stack or common

pipe operating time,

hour or

fraction of

an hour

(in

equal increments

that

can range from

one

hundredth

one quarter of an

hour, at

the

option of the

owner or operator).

= Total

number of units using

the common

stack or pipe.

= Designation

of a particular

unit.

10620

10621

2.5

Heat Input

Rate Summation

for Units with Multiple

Stacks or

Pipes

10622

10623

The

owner or

operator

of an

affected unit that

determines the heat

input rate at

the unit level

10624

summing

the

heat

input rates

monitored at

multiple stacks or

multiple pipes must

sum the heat

10625

input

rates

using the following

equation:

10626

—

HIt

10627

—

(Equation

F-21c)

tunit

10628

10629

Where:

10630

Heat

input

rate for

a unit, mmBtu/hr.

JCAR350225-08 1 8507r01

= Heat input rate

for the individual stack, duct, or

pipe,

mmBtulhr.

Unit operating

time, hour or fraction

of the hour (in equal

increments

that can range from one hundredth to one quarter

of an hour, at the option

of the owner or operator).

= Operating time for the individual

stack or pipe, hour or

fraction

of the hour

(in

equal increments

that

can range from

one

hundredth

one quarter of an hour, at the option

of the

owner or operator).

= Designation

for a particular

stack, duct, or pipe.

10631

10632

3. Procedure for Converting

Volumetric Flow to STP

10633

10634

Use the following

equation

to convert volumetric flow

at actual temperature and pressure to

10635

standard

temperature

and pressure.

10636

10637

FSTP = FActual (TSfd

TStack

XStack /Sd)

(Equation

F-22)

10638

10639

Where:

10640

= Flue gas volumetric

flow rate at standard temperature

and

pressure, scth.

Ectuai

Flue gas volumetric flow

rate at actual

temperature

and

pressure, acth.

Tst

= Standard

temperature 528 degreesR.

ISCk

= Flue

gas temperature at flow monitor location,

degreesR,

where degreesR = 460

degreesF.

SCk

= The absolute

flue gas pressure = barometric pressure

at the

flow monitor location

flue

gas static pressure, inches of

mercury.

The absolute flue gas pressure

= barometric pressure at the

flow monitor location

flue gas static pressure, inches

mercury.

10641

10642

4. Procedures

for

Mercury

Mass Emissions.

10643

10644

4.1

10645

10646

Use

the procedures

in this Section

to calculate the hourly mercury

mass emissions

(in

ounces)

10647

each

monitored

location

for the affected

unit or group of units that discharge

through a common

10648

stack.

JCAR350225-08 1 8507r01

10649

10650

4.1.1

10651

10652

determine the hourly mercury mass emissions when

using a

mercury concentration

10653

monitoring system that measures on a wet basis and a flow monitor, use the following equation:

10654

10655

Mh —KChQhth

(Equation F-28)

10656

10657

Where:

10658

Mercury mass emissions

for

the hour rounded off to

three

decimal places

(ounces).

K = Units conversion constant, 9.978 x 1

0b0

oz-scm/ig-scf.

Hourly mercury concentration, wet basis,

adjusted

for bias if the bias-test

procedures in Exhibit A

this Appendix show that

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

necessary,

(scifi).

Unit or stack operating time, as defined in 40 CFR 72.2,

(hr.).

10659

10660

4.1.2

10661

10662

To determine

the hourly mercury mass emissions when using a mercury concentration

10663

monitoring system that

measures on

dry

basis or a sorbent trap monitoring system and a flow

10664

monitor, use the

following

equation:

10665

10666

Mh = KChQhth

(1—

(Equation F-29)

10667

10668

Where:

10669

= mercury mass

emissions

for the hour rounded off to three decimal places

(ounces).

= Units

conversion

constant, 9.978 x

10b0

oz-scm/<<mu>>g-scf.

Hourly mercury

concentration,

dry basis,

adjusted

for bias if the bias-test

procedures

in Exhibit A to

this

Appendix

show that a bias-adjustment

factor is necessary, (jig/dscm). For sorbent

trap

systems,

single value

(i.e.,

a flow-proportional average concentration for the data collection

period) is

applied

to each hour in the data collection period for a particular

pair

of traps.

JCAR350225-08 1 8507r01

= Hourly stack

gas volumetric

flow

rate,

adjusted

for bias, where the bias-

test

procedures

in Exhibit

A to this Appendix shows

bias-adjustment

factor is necessary,

(seth).

Moisture fraction

the stack

gas expressed as a decimal (equal to

100)

= Unit or stack operating

time as defined in 40 CFR 72.2, (hr.).

10670

10671

4.1.3

10672

10673

For

units

that are demonstrated

under Section 1.15(d) of this

Appendix to emit less than 464

10674

ounces of mercury per year, and for which

the owner or operator elects not to continuously

10675

monitor the mercury concentration,

calculate the hourly mercury

mass emissions using Equation

10676

F-28 in Section 4.1 .1 of this Exhibit, except

that

“Ch”

will be the applicable default mercury

10677

concentration from Section 1.15(c),

(d),

or (e) of this Appendix, expressed

in jig/scm. Correction

10678

for the stack gas moisture content is not required when

this methodology is used.

10679

10680

4.2

10681

10682

Use the following equation to calculate

quarterly and year-to-date mercury mass

emissions in

10683

ounces:

10684

10685

Mtime

period

(Equation F-30)

10686

10687

Where:

10688

Mtime period

= Mercury mass

emissions

for the given time

period, i.e., quarter or

year-

to-date rounded

to the nearest

thousandth.

(ounces).

Mercury mass emissions for the

hour rounded to three decimal

places

(ounces).

The number of hours

in the given time period (quarter or

year-to-date).

10689

10690

4.3 If heat input rate monitoring is required,

the applicable procedures

for heat input

10691

apportionment and summation in Sections 2.3, 2.4

and

2.5

of this Exhibit.

10692

10693

5. Moisture Determination

From Wet and Dry

Readings

10694

10695

If a

correction for the stack gas moisture content

is required in any of the emissions or

heat

input

10696

calculations

described in this Exhibit,

and if the hourly moisture

content is determined from

wet-

10697

and

dry-basis

readings, use Equation

F-3 1 to calculate the percent

moisture, unless a “Kr’

10698

factor

or other mathematical algorithm is

developed as described in Section

6.5.6(a)

of Exhibit A

JCAR350225-081

8507r01

10699

to this

Appendix:

10700

10701

= (02d—02W)

100

(Equation

F-31)

10702

10703

Where:

10704

ll2O

Hourly

average stack

gas moisture content,

percentH20

= Dry-basis

hourly average

oxygen

concentration,

percent

Wet-basis hourly average

oxygen concentration,

percent

10705

10706

Exhibit

to Appendix

— Quality

Assurance

and

Operating

Procedures for Sorbent

Trap

10707

Monitoring

Systems

10708

10709

1.0 Scope

and Application

10710

10711

This Exhibit

specifies sampling,

and analytical,

and

quality-assurance

criteria

and procedures

for

10712

the

performance-based

monitoring of vapor-phase

mercury (Hg)

emissions in

combustion flue

10713

gas

streams,

using a

sorbent

trap monitoring system

(as

defined

in Section

225.130).

The

10714

principle employed

continuous

sampling using

in-stack

sorbent

media

coupled

with

analysis

10715

the

integrated

samples. The

performance-based

approach of this Exhibit

allows for

use

of various

10716

suitable

sampling

and

analytical

technologies while

maintaining

specified and documented

10717

level of data

quality

through performance

criteria. Persons

using this

Exhibit

should have a

10718

thorough

working

knowledge of Methods

1, 2, 3,

and 5

in appendices A-i

through A-3 to 40

10719

CFR 60,

incorporated

reference in Section

225.140,

well as the

determinative technique

10720

selected for

analysis.

10721

10722

1.1 Analytes

10723

10724

The

analyte

measured by

these procedures

and

specifications

is total

vapor-phase

mercury in the

10725

flue gas,

which

represents

the sum of elemental

mercury

(Hg°, CAS Number

7439-97-6)

and

10726

oxidized forms

of mercury,

in mass concentration

units of micrograms

per

dry standard cubic

10727

meter

(pg/dscm).

10728

10729

1.2

Applicability

10730

10731

These

performance

criteria

and procedures

are applicable to monitoring

of vapor-phase

mercury

10732

emissions

under

relatively

low-dust conditions

(i.e.,

sampling in the

stack

after all

pollution

10733

control

devices),

from coal-fired

electric utility steam

generators

which are subject to Sections

10734

1.14

through 1.18

of Appendix B.

Individual

sample

collection

times

can range

from

30 minutes

10735

to several

days

duration,

depending

on the mercury

concentration in the

stack. The monitoring

10736

system

must

achieve the

performance

criteria

specified

Section 8 of

this Exhibit and the

10737

sorbent

media

capture

ability

must not

be exceeded.

The

sampling rate must

be maintained at a

1CAR350225-081

8507r01

10738

constant proportion

to the total stack flow

rate to ensure

representativeness

of the sample

10739

collected. Failure

to achieve certain

performance

criteria will

result in

invalid mercury

emissions

10740

monitoring

data.

10741

10742

2.0

Principle

10743

10744

Known

volumes

flue gas

are

extracted from

a stack

duct through paired,

in-stack, pre

10745

spiked

sorbent

media

traps

at an appropriate

nominal flow rate.

Collection

mercury

on the

10746

sorbent media in the stack

mitigates

potential

loss

of mercury

during

transport

through

10747

probe/sample

line. Paired

train

sampling

is required to

determine measurement

precision

and

10748

verify acceptability of

the measured emissions

data.

10749

10750

The sorbent traps are

recovered from the sampling

system,

prepared for analysis,

as needed,

and

10751

analyzed by

any suitable determinative

technique

that can meet

the performance

criteria. A

10752

section of each sorbent

trap is spiked with Hg°

prior

to sampling.

This section

is analyzed

10753

separately

and the recovery

value is

used

to correct the individual

mercury sample

for

10754

measurement bias.

10755

10756

3.0 Clean

Handling and Contamination

10757

10758

To avoid mercury

contamination

the

samples,

special

attention should

be paid to cleanliness

10759

during transport,

field handling,

sampling, recovery,

and laboratory analysis,

well

during

10760

preparation

the sorbent cartridges.

Collection

and

analysis

of blank

samples (field,

trip, lab)

10761

useful

verifying the absence

of contaminant

mercury.

10762

10763

4.0 Safety

10764

10765

4.1

Site hazards

10766

10767

Site

hazards must be thoroughly

considered

in advance

applying these

10768

procedures/specifications

in the field;

advance

coordination with

the site is critical

understand

10769

the

conditions and

applicable

safety

policies.

At a minimum, portions

of the sampling

system

10770

will be hot,

requiring appropriate

gloves,

long sleeves, and caution

in handling this

equipment.

10771

10772

4.2 Laboratory

safety policies

10773

10774

Laboratory

safety

policies

should

place to minimize risk

of chemical exposure

and to

10775

properly

handle waste

disposal. Personnel

must

wear appropriate

laboratory attire

according

10776

Chemical

Hygiene

Plan established by

the laboratory.

10777

10778

4.3

Toxicity or carcinogenicity

10779

10780

The

toxicity

or carcinogenicity

of any reagents

used must be considered.

Depending

upon

the

JCAR350225-0818507r01

10781

sampling and

analytical technologies

selected,

this

measurement may

involve hazardous

10782

materials,

operations, and equipment

and this

Exhibit does not address

all of the safety

problems

10783

associated with

implementing

this approach.

is the responsibility of

the

user

establish

10784

appropriate

safety and health practices

and determine

the applicable

regulatory limitations

prior

10785

performance.

Any chemical should

be regarded as a

potential health

hazard and exposure

10786

these

compounds

should be

minimized.

Chemists

should

refer to the Material

Safety

Data

Sheet

10787

(MSDS)

for each

chemical used.

10788

10789

4.4

Wastes

10790

10791

Any

wastes

generated

by this procedure must

disposed

of according to a hazardous

materials

10792

management

plan that

details and tracks

various waste streams

and

disposal

procedures.

10793

10794

5.0 Equipment

and Supplies

10795

10796

The

following list is

presented as an example

of key equipment

and supplies

likely required to

10797

perform

vapor-phase

mercury monitoring using

sorbent

trap monitoring system.

10798

recognized

that

additional

equipment

and

supplies may be needed.

Collection

of paired samples

10799

required.

Also

required

are a certified stack

gas

volumetric

flow monitor that

meets the

10800

requirements

of Section

1.2

to this

Appendix

and an

acceptable

means of

correcting for the

stack

10801

gas

moisture

content, i.e.,

either

using data

from a certified continuous

moisture

monitoring

10802

system or

using an

approved

default moisture

value

(see

CFR

75.11(b),

incorporated

10803

reference in Section

225.140).

10804

10805

5.1 Sorbent

Trap Monitoring

System

10806

10807

typical

sorbent

trap monitoring system

is shown in

Figure K-i. The monitoring

system must

10808

include the

following

components:

10809

10810

5.1.1 Sorbent Traps

10811

10812

The

sorbent

media used

collect

mercury must be configured

in a trap

with three distinct and

10813

identical

segments

or sections, connected

in series,

that

are amenable to separate

analyses.

10814

Section

1 is

designated

for

primary

capture of gaseous mercury.

Section

2 is designated as

10815

backup

section

for

determination of vapor-phase

mercury

breakthrough. Section

3 is designated

10816

for

OAIOC

purposes

where

this

section

must be spiked with

a known amount

gaseous

Hg°

10817

prior to

sampling and

later analyzed to

determine recovery efficiency.

The

sorbent media may

10818

any

collection

material

(e.g.,

carbon,

chemically-treated

filter, etc.)

capable

quantitatively

10819

capturing and

recovering

for subsequent

analysis, all gaseous

forms of mercury for

the intended

10820

application.

Selection of the

sorbent media

must

be based on the

material’s ability

to achieve

the

10821

performance

criteria

contained

in Section 8 of this

Exhibit as well as

the sorbent’s

vapor-phase

10822

mercury

capture

efficiency for

the emissions matrix

and the expected

sampling duration

at the

10823

test

site. The

sorbent media must be

obtained

from

source that can demonstrate

the quality

JCAR350225-08

8507r01

10824

assurance and control necessary to ensure consistent

reliability. The paired sorbent traps are

10825

supported on a probe

(or

probes) and inserted directly

into the flue

gas

stream.

10826

10827

5.1.2 Sampling

Probe

Assembly

10828

10829

Each probe assembly must have a leak-free Exhibit to

the sorbent

traps.

Each sorbent trap must

10830

be mounted at the

entrance

of or

within

the probe such that the gas sampled enters the

trap

10831

directly. Each probe/sorbent trap assembly must

be heated to a temperature sufficient to prevent

10832

liquid condensation in the sorbent traps. Auxiliary heating

required

only where the stack

10833

temperature is too

low to prevent condensation.

Use a calibrated thermocouple to monitor

the

10834

stack

temperature. A single probe capable of operating

the paired

sorbent

traps may be used.

10835

Alternatively,

individual probe/sorbent

trap assemblies may be used, provided that the individual

10836

sorbent traps are co-located to ensure representative

mercury

monitoring

and are sufficiently

10837

separated to

prevent aerodynamic interference.

10838

10839

5.1.3 Moisture

Removal Device

10840

10841

A robust moisture

removal device or

system, suitable for continuous duty

(such

as a Peltier

10842

cooler),

must be used to remove water vapor from the

gas stream prior to entering the gas flow

10843

meter.

10844

10845

5.1.4

Vacuum Pump

10846

10847

Use a

leak-tight, vacuum pump capable of operating within

the

candidate

system’s flow range.

10848

10849

5.1.5 Gas Flow Meter

10850

10851

A gas

flow meter (such as a

dry

gas meter, thermal mass flow meter, or other suitable

10852

measurement

device)

must be used to determine the

total sample volume on a dry basis, in

units

10853

standard cubic meters. The meter must be sufficiently accurate to measure the total

sample

10854

volume to

within 2 percent and must be calibrated at selected

flow

rates across the range of

10855

sample flow rates at

which the sorbent

trap monitoring system typically operates. The

gas flow

10856

meter must

be equipped with any necessary auxiliary measurement devices

(e.g., temperature

10857

sensors, pressure

measurement

devices)

needed to correct the sample volume to standard

10858

conditions.

10859

10860

5.1.6

Sample

Flow

Rate

Meter and Controller

10861

10862

Use a flow

rate indicator and controller for maintaining necessary sampling

flow

rates.

10863

10864

5.1.7

Temperature Sensor

10865

10866

Same as Section

6.1.1.7 of Method 5 in appendix A-3 to 40

CFR 60, incorporated by reference

JCAR350225-08 1 8507r01

10867

Section 225.140.

10868

10869

5.1.8

Barometer

10870

10871

Same as

Section 6.1.2 of Method 5 in appendix A-3 to 40 CFR 60, incorporated by reference in

10872

Section 225.140.

10873

10874

5.1.9 Data Logger (Optional)

10875

10876

Device for recording

associated

and necessary ancillary information (e.g., temperatures,

10877

pressures,

flow, time,

etc.).

10878

10879

5.2

Gaseous

Hg° Sorbent Trap Spiking System

10880

10881

A known

mass of gaseous Hg° must be spiked onto section 3 of each

sorbent trap prior

10882

sampling. Any

approach

capable

of quantitatively delivering known masses of Hg° onto sorbent

10883

traps is

acceptable. Several

technologies

or devices are available to meet this

objective. Their

10884

practicality is a function

of mercury mass spike levels. For low levels, NIST-certified or NIST

10885

traceable gas

generators or tanks may be suitable, but will likely require long preparation times.

10886

A more

practical,

alternative system,

capable of delivering almost any mass

required, makes

use

10887

NIST-certified or

NIST-traceable mercury

salt

solutions (e.g., Hg(N03)2). With this

system,

10888

aliquot of known

volume and concentration is added to a reaction vessel containing a

10889

reducing agent (e.g.,

stannous

chloride);

the mercury salt solution is reduced to Hg° and purged

10890

onto section 3 of

the sorbent trap using an impinger sparging system.

10891

10892

5.3 Sample Analysis Equipment

10893

10894

Any

analytical system capable

of quantitatively

recovering and

quantifying total gaseous

10895

mercury from

sorbent media is acceptable provided that the analysis can meet the perfonnance

10896

criteria in

Section 8 of this

procedure.

Candidate

recovery techniques include leaching,

digestion,

10897

and

thermal

desorption.

Candidate analytical techniques include ultraviolet atomic fluorescence

10898

(UV

AF);

ultraviolet atomic

absorption

(UV AA),

with and without gold trapping; and in-situ

10899

ray

fluorescence

(XRF) analysis.

10900

10901

6.0 Reagents and Standards

10902

10903

Only

NIST-certified

or NIST-traceable calibration gas standards and reagents must be used for

10904

the

tests

and

procedures

required

under this Exhibit.

10905

10906

7.0

Sample

Collection and Transport

10907

10908

7.1 Pre-Test Procedures

10909

JCAR350225-08

1 8507r01

10910

7.1.1 Selection of Sampling

Site

10911

10912

Sampling

site information

should

be obtained in accordance

with Method

1 in

appendix

A-i

10913

40 CFR 60,

incorporated

reference

in Section 225.140.

Identify a

monitoring

location

10914

representative

source mercury emissions.

Locations

shown to be free of

stratification through

10915

measurement

traverses

for

gases such as SO

and NOmay

be one such approach.

An estimation

10916

of the

expected stack

mercury concentration

is required to establish

a target

sample flow rate,

10917

total gas

sample

volume,

and the mass of Hg°

be spiked onto

section 3 of each

sorbent trap.

10918

10919

7.1.2

Pre-sampling

Spiking of Sorbent

Traps

10920

10921

Based

the estimated

mercury concentration

in the stack, the target

sample

rate

and the target

10922

sampling

duration, calculate

the

expected

mass loading for section

1 of each sorbent

trap

(for an

10923

example

calculation,

see

Section 11.1 of this

Exhibit).

The

pre-sampling spike

to be added to

10924

section 3 of

each sorbent trap

must be within

50 percent of

the expected

section

1 mass

10925

Spike

section

3 of each sorbent trap

at this level, as

described in Section

5.2 of this

10926

Exhibit.

For each sorbent

trap,

keep an

official record of the mass

of Hg° added to

section 3.

This

10927

record

must

include,

a minimum, the ID number

of the trap, the

date and time

of the spike, the

10928

name of the

analyst performing

the

procedure,

the mass of Hg°

added to section 3 of

the trap

10929

(jig), and the

supporting

calculations. This record

must

be maintained

in a

format

suitable for

10930

inspection

and

audit

and

must

be made available

to the regulatory

agencies upon request.

10931

10932

7.1.3 Pre-test Leak

Check

10933

10934

Perform

leak check

with the

sorbent

traps in place. Draw

a vacuum in each

sample train.

10935

Adjust the

vacuum in

the sample train to

mercury. Using the

gas

flow meter,

determine leak rate.

10936

The

leakage

rate

must

not exceed

percent

of the target

sampling rate. Once the

leak check

10937

passes this

criterion,

carefully

release the

vacuum

in the sample

train then

seal the sorbent trap

10938

inlet

until

the probe

ready for insertion into

the

stack

duct.

10939

10940

7.1.4

Determination

Flue

Gas

Characteristics

10941

10942

Determine

measure

the flue

gas

measurement environment

characteristics

(gas

temperature,

10943

static

pressure, gas

velocity, stack moisture,

etc.)

in order to determine

ancillary

requirements

10944

such as

probe

heating

requirements

(if

any),

initial sample

rate, proportional sampling

10945

conditions,

moisture

management,

etc.

10946

10947

7.2

Sample

Collection

10948

10949

7.2.1

10950

10951

Remove

the plug

from the end of each

sorbent trap and store

each

plug

in a clean sorbent

trap

10952

storage

container.

Remove the

stack

duct port

cap

and insert the

probes.

Secure the probes and

JCAR350225-081 8507r01

10953

ensure

that

leakage occurs between

the

duct

and environment.

10954

10955

7.2.2

10956

10957

Record initial data including the

sorbent trap

ID, start time,

starting

dry gas

meter readings,

10958

initial

temperatures,

set-points,

and any other appropriate information.

10959

10960

7.2.3

Flow Rate Control

10961

10962

Set the initial sample

flow rate at the target value from Section 7.1.1 of this Exhibit. Record the

10963

initial

gas

flow meter reading, stack

temperature

(if

needed to convert to standard conditions),

10964

meter temperatures

(if

needed),

etc. Then, for every operating hour during the sampling period,

10965

record the date and time,

the

sample

flow rate,

the gas

flow meter reading, the stack temperature

10966

(if

needed), the flow

meter temperatures

(if

needed), temperatures of heated

equipment such

10967

the vacuum lines and

the probes

(if heated), and the sampling system vacuum readings. Also,

10968

record the

stack gas flow rate, as measured by the certified

flow

monitor,

and the ratio of the

10969

stack gas flow rate to

the sample flow rate. Adjust the sampling flow rate to maintain

10970

proportional

sampling, i.e., keep the ratio of the stack gas flow rate to sample

flow rate

constant,

10971

to within

25 percent of the

reference

ratio from the

first hour of the data collection period

(see

10972

Section

11 of this

Exhibit).

The sample flow rate through a sorbent trap monitoring system

10973

during any hour

(or

portion of an

hour)

in which the unit is not operating must be

zero.

10974

10975

7.2.4

Stack Gas Moisture

Determination

10976

10977

Determine stack gas

moisture using a continuous moisture monitoring system, as described in 40

10978

CFR

75.11(b),

incorporated by reference in Section

225.140.

Alternatively, the

owner or

10979

operator may use

the appropriate fuel-specific

moisture default value provided in 40 CFR

75.11,

10980

incorporated by

reference

in Section 225.140, or a site-specific moisture default value approved

10981

the Agency.

10982

10983

7.2.5

Essential Operating

Data

10984

10985

Obtain and

record any

essential

operating data for the

facility during the test period, e.g., the

10986

barometric pressure

for correcting the sample volume measured by a dry gas meter to standard

10987

conditions. At

the

end of the data collection period,

record the final gas flow meter reading and

10988

the

final values of all

other essential parameters.

10989

10990

7.2.6 Post Test Leak

Check

10991

10992

When

sampling is

completed, turn off the sample pump, remove the probe/sorbent trap from the

10993

port

and carefully

re-plug the end of each sorbent trap. Perform a leak check with the sorbent

10994

traps

in place, at

the maximum vacuum reached during the sampling period.

Use the same

10995

general

approach described in

Section

7.1.3 of this

Exhibit. Record

the

leakage

rate and vacuum.

JCAR350225-08

8507r01

10996

The leakage rate

must

not exceed

4 percent of the average

sampling rate for the data

collection

10997

period. Following the leak check, carefully

release the vacuum in the sample train.

10998

10999

7.2.7 Sample Recovery

11000

11001

Recover each sampled sorbent trap

removing

it from the probe, sealing

both ends. Wipe

any

11002

deposited

material from the outside of the sorbent trap.

Place the sorbent trap into an appropriate

11003

sample storage container and

store/preserve in appropriate

manner.

11004

11005

7.2.8

Sample Preservation, Storage,

and

Transport

11006

11007

While the performance criteria of this approach provide

for verification of appropriate

sample

11008

handling, it is still important that the user consider,

determine, and plan for suitable

sample

11009

preservation,

storage, transport,

and holding times for these

measurements. Therefore,

11010

procedures in ASTM D6911-03 “Standard Guide

for

Packaging and Shipping Environmental

11011

Samples

for

Laboratory

Analysis”

(incorporated

reference

under

Section

225.140)

must

11012

followed for all samples.

11013

11014

7.2.9

Sample Custody

11015

11016

Proper

procedures

and documentation for sample chain

of custody are critical to ensuring

data

11017

integrity. The chain

of custody

procedures in ASTM D4840-99

(reapproved

2004)

“Standard

11018

Guide for

Sample Chain-of-Custody

Procedures” (incorporated

reference

under

Section

11019

225.140)

must be followed for all samples

(including

field samples and blanks).

11020

11021

8.0 Quality Assurance and

Quality Control

11022

11023

Table K-i summarizes the

QAIQC

performance criteria

that are used to validate the mercury

11024

emissions data

from sorb ent trap monitoring

systems, including the relative

accuracy

test audit

11025

(RATA) requirement

(see

Section

1.4(c)(7),

Section

6.5.6 of Exhibit A to this Appendix,

and

11026

Section 2.3

of Exhibit B to this Appendix).

Except as provided in Section 1.3(h)

of this

11027

Appendix and as

otherwise indicated

in Table K-i, failure

achieve

these performance criteria

11028

will result

in invalidation of mercury emissions

data.

11029

11030

11031

Table

K-i. Quality

Assurance/Quality

Control

Criteria for Sorbent Trap Monitoring

Systems

OAIQC

test or

Acceptance

criteria

Frequency

Consequences if

not

specification

met

Pre-test leak check

4% of target

Prior

to sampling

Sampling

must

not

sampling

rate

commence until

the

leak

check is passed.

IC/)

IIC/)

lCD

‘

I’I

)

-÷

lCD

IC)

Id)

I—

lCD

IC)

I-”

I-t

‘‘

‘

IC)

‘

‘ii’

f’

‘

IPILt

IQl+)

E[1

I1P

‘

I—

Id,)

‘

‘•

‘0

‘

lCD

II0

I-

r-I-l

I’

IClo

lI0lLtI0

IPloIO

II0lC

L-”

IEI

I”

OIdJ

‘

-t

l-I

lICD

‘t

lCD

‘‘

‘

Iij

IT1

‘°

I’

ItTi

.Io

—

l-t

IIC

iiI

lCD

1°

lCD

IH°

IIp

Cl)

IoIi

o’l

I-lo

IIZ

I-III

IPIIp-

lCD

IC’

Ir-

-t

I-+

I-

I—:

I-

ll-t

lCD

i-t

I-+

IIo

Cl)

ullP

ICDI

-t

JCAR350225-08

1 8507r01

Analysis

independent

calibration standard

Within ± 10%

of true

value

Following daily

calibration,

prior to

analyzing

field

samples

Recalibrate

and repeat

independent standard

analysis

until

successful.

Spike recovery from

Section 3 of sorbent

75-125% of spike

amount

Every

sample

[FN**]

See Note,

below.

RATA

RA 20.0%orMean

difference

0<<mu>>g/dscm

for low emitters

For initial certification

and annually

thereafter

Data from

the

system

are invalidated

until a

RATA is

passed.

Gas flow meter

calibration

Calibration factor

(Y)

within

± 5% of

average value from

the

most

recent

point calibration

At three settings prior

to initial use and at

least quarterly

at one

setting thereafter. For

mass flow meters,

initial calibration

with

Recalibrate the meter

at three orifice

settings to determine

new value

stack gas is required

Temperature sensor

calibration

Absolute

temperature

measured

sensor

within± 1.5%ofa

reference sensor

Prior to initial use and

at least quarterly

thereafter

Recalibrate. Sensor

may not be used

until

specification is met.

11032

Barometer

calibration

Absolute pressure

measured by

instrument within

10 mm Hg of reading

with

a mercury

barometer

Prior

to initial use and

at least quarterly

thereafter

Recalibrate.

Instrument

may not

used until

specification

is met.

[FN**1

Note: If both traps fail to meet the acceptance criteria, the data from the pair

of traps are

invalidated.

However, if

only

one of the paired

traps

fails to meet this particular acceptance

criterion

and the other sample meets all of the applicable

criteria, the results of the valid

trap

may be

used

for reporting under this part, provided that the measured

concentration

multiplied by a

factor

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 be used. 9.0

Calibration

and Standardization.

11033

11034

11035

11036

11037

11038

11039

11040

11041

JCAR350225-081

8507r01

11042

9.1

11043

11044

Only NIST-certified

and NIST-traceable calibration

standards

(i.e.,

calibration

gases, solutions,

11045

etc.) must be used for the spiking and

analytical

procedures in this Exhibit.

11046

11047

9.2

Gas Flow Meter Calibration

11048

11049

9.2.1 Preliminaries

11050

11051

The manufacturer

or supplier of the gas flow meter should perform all necessary

set-up, testing,

11052

programming, etc., and should provide the end user with any necessary instructions, to ensure

11053

that the meter will

give an accurate readout of dry

gas

volume in standard

cubic meters for the

11054

particular field application.

11055

11056

9.2.2

Initial Calibration

11057

11058

Prior to its initial use, a

calibration

of the flow meter must be performed. The initial calibration

11059

may be done by

the manufacturer, by the equipment supplier, or

the end user. If

the flow

11060

meter is

volumetric in nature (e.g., a dry gas

meter),

the manufacturer, equipment supplier,

11061

end user may perform a

direct volumetric calibration

using any gas. For a mass flow meter, the

11062

manufacturer,

equipment supplier, or end user may calibrate the meter using

a bottled gas

11063

mixture containing

0.5%

2.7

0.5%

02,

and

balance

or these same gases in

11064

proportions

representative of the expected stack gas composition. Mass flow meters

may

11065

also be

initially

calibrated on-site, using actual stack gas.

11066

11067

9.2.2.1

Initial Calibration Procedures

11068

11069

Determine an average

calibration factor

(Y)

for the gas flow meter, by calibrating it at three

11070

sample flow

rate settings covering the range of sample flow rates at which the sorbent trap

11071

monitoring system

typically operates.

You may either follow the procedures in Section 10.3.1

11072

Method 5 in

appendix A-3 to 40 CFR 60, incorporated by reference in Section 225.140, or

the

11073

procedures in Section

16 of Method 5 in appendix

A-3 to

40 CFR

60.

If a dry

gas meter is being

11074

calibrated,

use at least five

revolutions

of the meter at each flow rate.

11075

11076

9.2.2.2 Alternative Initial Calibration Procedures

11077

11078

Alternatively, you

may

perform

the initial calibration

the gas flow meter using a reference

gas

11079

flow

meter (RGFM). The RGFM may either be:

(1)

A wet test meter calibrated according to

11080

Section

10.3.1 of Method 5 in

appendix

A-3 to 40 CFR 60, incorporated by reference in Section

11081

225.140;

(2) a gas

flow metering device

calibrated

at multiple

flow

rates

using the procedures in

11082

Section

16 of

Method 5 in appendix A-3

40 CFR

60;

or (3) a NIST-traceable calibration

11083

device

capable

of measuring volumetric flow to an accuracy of 1

percent.

To calibrate

the gas

11084

flow

meter using the RGFM,

proceed

as follows: While the sorbent trap monitoring system

JCAR350225-08 1 8507r01

11085

sampling the actual stack gas or a

compressed

gas

mixture that

simulates

the stack gas

11086

composition

(as applicable),

connect

the RGFM to the discharge of the system.

Care

should

11087

taken

minimize

the

dead volume between the sample flow

meter being tested and the RGFM.

11088

Concurrently measure dry gas volume with the RGFM and the flow

meter being calibrated the

11089

for a minimum of 10 minutes at each of three flow rates covering the typical range

of operation

11090

of the sorbent trap

monitoring

system. For each 10-minute

(or

longer) data collection period,

11091

record the

total

sample volume, in units of dry standard cubic meters

(dscm),

measured

by the

11092

RGFM and the gas flow meter being tested.

11093

11094

9.2.2.3 Initial Calibration

Factor

11095

11096

Calculate

an individual calibration factor Yi at each tested flow

rate from Section 9.2.2.1 or

11097

9.2.2.2 of this Exhibit (as applicable), by taking the ratio of the reference

sample

volume

to the

11098

sample volume recorded by the gas flow meter. Average the three Yi values,

to determine Y,

the

11099

calibration factor for the flow

meter. Each

of the three individual values of Yi must be within ±

11100

0.02

Except

as otherwise provided in Sections 9.2.2.4 and 9.2.2.5

this

Exhibit, use the

11101

average Y value from

the

three level calibration

adjust

all subsequent gas volume

11102

measurements made with the gas flow meter.

11103

11104

9.2.2.4 Initial On-Site Calibration

Check

11105

11106

For a mass

flow meter that was initially calibrated using a compressed

gas mixture, an on-site

11107

calibration check must be performed before using the flow meter to provide data for

this

part.

11108

While sampling stack gas, check the calibration of the flow meter at one intermediate flow

rate

11109

typical of normal

operation of the monitoring

system. Follow the basic procedures in Section

11110

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

11111

calibration factor at the tested flow rate, differs by more than 5

percent

from the value

of Y

11112

obtained in the

initial calibration of the meter, repeat

the full 3-level calibration of the meter

11113

using

stack gas to determine a new

value

of Y, and apply the new Y value to all subsequent

gas

11114

volume

measurements made with the gas flow meter.

11115

11116

9.2.2.5 Ongoing Quality Assurance

11117

11118

Recalibrate the gas flow meter quarterly at one intermediate flow

rate setting representative

11119

normal

operation

of the

monitoring

system. Follow the basic procedures in Section 9.2.2.1

11120

9.2.2.2 of this

Exhibit. If a quarterly recalibration

shows that the value of Yi, the calibration

11121

factor at

the tested flow rate, differs from the current value of

Y by

more than

5 percent, repeat

11122

the

full 3-level

calibration

the meter

to determine a new value of Y, and apply the new

11123

value

to all

subsequent

gas

volume measurements

made with the gas flow meter.

11124

11125

9.3 Thermocouples and Other Temperature Sensors

11126

11127

Use

the

procedures

and

criteria

in Section

10.3 of Method 2 in appendix A-i to 40 CFR

60,

JCAR350225-081 8507r01

11128

incorporated by reference

in Section 225.140,

to calibrate in-stack temperature sensors and

11129

thermocouples. Dial thermometers must be calibrated against mercury-in-glass

thermometers.

11130

Calibrations must be performed prior to initial use and at least quarterly thereafter. At each

11131

calibration

point, the

absolute temperature measured

by the temperature sensor must agree

11132

within

1.5 percent of the temperature measured with the reference sensor,

otherwise the sensor

11133

may not cOntinue to be used.

11134

11135

9.4 Barometer

11136

11137

Calibrate against a mercury barometer. Calibration must be performed prior to initial use and

11138

least quarterly thereafter. At each calibration point, the absolute pressure measured

by the

11139

barometer must agree to

within

mm mercury of the pressure measured by the mercury

11140

barometer, otherwise the barometer may not continue to be used.

11141

11142

9.5 Other Sensors and Gauges

11143

11144

Calibrate all other sensors and gauges according to the procedures specified

the instrument

11145

manufacturers.

11146

11147

9.6

Analytical System Calibration

11148

11149

See Section 10.1 of this

Exhibit.

11150

11151

10.0 Analytical Procedures

11152

11153

The analysis of the mercury

samples

may be conducted using any instrument or technology

11154

capable of

quantifying total mercury from the sorbent media and meeting

the performance

11155

criteria

in Section 8 of this Exhibit.

11156

11157

10.1 Analyzer System Calibration

11158

11159

Perform

a multipoint

calibration

of the analyzer at three or more upscale points over the desired

11160

quantitative

range

(multiple

calibration ranges must be calibrated, if necessary). The

field

11161

samples analyzed must fall

within a

calibrated,

quantitative

range and meet the necessary

11162

performance

criteria. For samples that are suitable for aliquotting, a series

dilutions

may be

11163

needed to

ensure that the samples fall within a calibrated range. However, for sorbent media

11164

samples that are

consumed during analysis

(e.g., thermal desorption techniques), extra care

must

11165

taken to

ensure that the analytical system is appropriately calibrated

prior to sample analysis.

11166

The

calibration curve ranges should be determined based on the anticipated level

of mercury

11167

mass on

the sorbent media.

Knowledge

of estimated stack mercury concentrations and total

11168

sample volume may be

required

prior

to analysis. The calibration

curve

for use with the various

11169

analytical

techniques (e.g., UV AA, TJV

AF, and

XRF)

can be

generated

by directly introducing

11170

standard

solutions into the analyzer or by spiking

the

standards onto the sorbent

media and then

JCAR350225-08 1 8507r01

11171

introducing into

the analyzer after

preparing the

sorbent/standard

according

to the

particular

11172

analytical

technique.

For each

calibration curve, the

value

of the

square

of the linear

correlation

11173

coefficient, i.e.,

must be

0.99, and the analyzer

response

must be within

percent

11174

reference

value at each upscale

calibration

point.

Calibrations must

be performed

on the day

11175

the

analysis,

before analyzing

any

of the

samples.

Following

calibration, an independently

11176

prepared standard

(not

from same calibration

stock solution)

must be analyzed.

The

measured

11177

value

the independently

prepared standard

must be within

10 percent

of the expected value.

11178

11179

10.2

Sample Preparation

11180

11181

Carefully separate

the three sections of

each sorbent trap.

Combine for analysis

all materials

11182

associated

with each section,

i.e.,

any

supporting substrate

that the

sample

gas passes through

11183

prior to entering a

media

section (e.g.,

glass

wool,

polyurethane

foam,

etc.)

must be analyzed

11184

with that segment.

11185

11186

10.3

Spike

Recovery

Study

11187

11188

Before

analyzing any

field samples,

the laboratory must

demonstrate the ability

to recover and

11189

quantify mercury

from the sorbent media

performing

the following spike

recovery study

for

11190

sorbent media

traps

spiked

with elemental

mercury.

11191

11192

Using

the procedures

described in

Sections

5.2

and 11.1 of this Exhibit,

spike

the

third

section

11193

nine sorbent

traps with gaseous

Hg°, i.e.,

three

traps at each of three

different mass loadings,

11194

representing

the range of masses

anticipated in the

field samples.

This

will

yield

3 x

3 sample

11195

matrix. Prepare and

analyze

the third section

of each spiked

trap, using the techniques

that

will

11196

be used to

prepare and analyze

the field

samples. The average

recovery

for

each spike

11197

concentration must be

between 85 and 115

percent.

If multiple

types of sorbent

media

are to

11198

analyzed, a

separate spike

recovery

study

is required for each

sorbent material.

multiple

ranges

11199

are

calibrated, a separate

spike recovery study

required

for each range.

11200

11201

10.4 Field

Sample

Analysis

11202

11203

Analyze

the sorbent trap

samples following

the

same procedures

that were used

for conducting

11204

the spike

recovery study. The

three sections

of each sorbent trap

must

be analyzed

separately

11205

(i.e.,

section 1, then section

2, then section

3).

Quantify

the

total mass of mercury

for

each

11206

section based

on analytical

system

response

and the calibration

curve from

Section 10.1 of

this

11207

Exhibit.

Determine

the

spike recovery

from sorbent trap

section 3. The

spike

recovery

must

11208

no less

than 75 percent

and no greater than

125

percent.

To report the final

mercury mass

for

11209

each trap, add

together

the mercury

masses collected in

trap sections 1

and 2.

11210

11211

11.0

Calculations

and Data Analysis

11212

11213

11.1

Calculation of

Pre-Samnling

Snikina

Level

JCAR350225-081

8507r01

11214

11215

11216

11217

11218

11219

11220

11221

11222

11223

11224

11225

11226

11227

11228

11229

11230

11231

11232

11233

11234

11235

11236

11237

11238

11239

11240

11241

Determine

sorbent

trap

section

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 be collected

in section

1 of

the trap. The

pre-sampling

spike

must

within

percent

this mass.

Example

calculation:

For an estimated

stack

mercury

concentration

of 5

ig/m

a target

sample

rate

of 0.30

L/min,

and

a sample

duration of

5 days:

(0.30

L/min)

(1440

minlday)

days)

(10

/liter) (5tg/m

)

10.8

pre-sampling

spike

of 10.8

.ig

50 percent

is, therefore,

appropriate.

11.2

Calculations

for

Flow-Proportional

Sampling

For the

first hour

the

data collection

period,

detennine

the reference

ratio

of the stack

volumetric

flow

rate to

the

sample

flow rate,

follows:

Rref

ref

(Equation

K-i)

Frei

Where:

Reference

ratio

of hourly

stack

gas

flow

rate

hourly

sample

flow

rate

Average stack

gas

volumetric

flow

rate

for

first

hour of

collection

period

Average

sample

flow rate

for first hour

of the

collection

period, in appropriate

units

(e.g.,

liters/mm,

cc/mm, dscm/min)

= Power

often

multiplier,

keep

the

value

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

the data collection

period,

calculate

ratio of

the stack

gas

flow rate

to the

sample

flow rate

using

the

equation K-2:

1 =

(Equation

K-2)

Where:

Ratio of hourly

stack

gas flow rate

hourly

sample flow

rate

= Average

stack

gas

volumetric

flow

rate

for the hour

JCAR350225-081 8507r01

= Average sample

flow rate for the hour, in appropriate

units

(e.g.,

liters/mm,

cc/mm, dscm/min)

Power often multiplier, to keep the value

between

1 and 100. The

appropriate

value

will

depend on the selected units

of measure for the

sample flow rate

and the range of expected stack gas flow rates.

11242

11243

11244

Maintain the value of

within

+ 25

percent of Rthroughout the data collection

period.

11245

11246

11.3 Calculation of

Spike

Recovery

11247

11248

Calculate the

percent recovery

of each section 3 spike, as follows:

11249

11250

%R=ix100

(EguationK-3)

11251

11252

Where:

11253

Percentage recovery of the pre-sampling

spike

Mass of mercury recovered

from section 3 of the sorbent trap, fig)

Percentage recovery

of the pre-sampling spike

11254

11255

11.4 Calculation of Breakthrough

11256

11257

Calculate

the percent breakthrough to the second

section

of the sorbent trap, as follows:

11258

11259

Where:

11260

11261

%B=--x100

(EguationK-4)

11262

11263

Where:

11264

= Percent breakthrough

Mass

of mercury

recovered from section 2 of the

sorbent trap, (jig)

1 = Mass of mercury recovered from section

1 of the sorbent trap,

fig)

11265

11266

11.5 Calculation

of Mercury Concentration

11267

11268

Calculate

the mercury concentration for each sorbent trap,

using the following

equation:

11269

JCAR350225-08

1 8507r01

11270

=—

(EguationK-5)

11271

11272

Where:

11273

Concentration of mercury for the collection period, igm1dscm)

= Total mass of mercury recovered from sections 1 and

of the sorbent trap,

= Total volume of dry gas metered during the collection period,

(dscm).

For

the

purposes of this Exhibit, standard temperature and pressure are defined

as 20

°C

and 760 mm mercury, respectively.

11274

11275

11.6 Calculation of Paired Trap Agreement

11276

11277

Calculate the relative deviation

(RD)

between the mercury concentrations

measured

with the

11278

paired sorbent

traps:

11279

jC -C

11280

RD=

xlOO

fEguationK-6)

Ca +Cb

11281

11282

Where:

11283

RD = Relative

deviation

between the mercury concentrations from traps

??atl

and

btt

(percent)

= Concentration of mercury for the collection period, for sorbent trap

tat

(jigm/dscm)

Concentration of

mercury

for the

collection

period,

for sorbent trap

b”

fligmldscm)

11284

11285

11.7 Calculation of Mercury

Mass

Emissions

11286

11287

calculate

mercury mass emissions, follow the procedures in Section 4.1.2 of Exhibit

11288

this

Appendix. Use the average of the two mercury concentrations from the paired traps

11289

the

calculations, except as

provided

in Section 2.2.3(h) of Exhibit B to this Appendix or in

11290

Table

K-i.

11291

11292

12.0 Method Performance

11293

11294

These

monitoring

criteria and procedures

have been applied to coal-fired utility

boilers

11295

(including units with

post-combustion emission controls), having vapor-phase mercury

11296

concentrations

ranging from 0.03 ig/dscm to 100 ig/dscm.

JCAR350225-08 1 8507r01

11297

11298

(Source:

Added at 33 Iii. Reg.

effective