Document ID: EPA-HQ-OAR-2002-0058-0649
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-08-13T04:00Z

1
May
26,
2004
MEMORANDUM
Subject:
Response
to
Public
Comments
on
Proposed
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
NESHAP
(
Revised)

From:
Jim
Eddinger,
ESD
Combustion
Group
To:
Robert
Wayland,
ESD
Combustion
Group
On
January
13,
2003,
the
U.
S.
Environmental
Protection
Agency
(
EPA)
proposed
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
Industrial/
Commercial/
Institutional
Boilers
and
Process
Heaters.
The
proposed
rule
fulfills
the
requirements
of
the
Clean
Air
Act
(
CAA),
which
requires
EPA
to
regulate
emissions
of
hazardous
air
pollutants
(
HAP)
listed
in
section
112(
b)
of
the
CAA.

This
document
contains
summaries
of
the
public
comments
that
EPA
received
on
the
Industrial,
Commercial,
Institutional
Boilers
and
Process
Heaters
proposal
to
establish
NESHAP
for
Industrial/
Commercial/
Institutional
Boilers
and
Process
Heaters.
In
this
document,
EPA
responds
to
the
public
comments.
This
summary
of
public
comments
and
EPA
responses
serves
as
the
basis
for
revisions
made
to
the
Industrial/
Commercial/
Institutional
Boilers
and
Process
Heaters
between
proposal
and
promulgation.

The
EPA
received
191
comment
letters
for
the
Industrial,
Commercial,
Institutional
Boilers
and
Process
Heaters
proposed
rule
before
the
comment
period
closed
on
March
14,
2003.
These
comments
are
contained
in
Docket
ID
No.
OAR­
2002­
0058
(
formerly
Docket
No.
A­
96­
47).
Eight
comments
were
received
shortly
after
the
March
14,
2003
deadline.
These
comments
are
contained
in
the
same
docket.
The
commenter,
affiliation,
and
item
number
in
Docket
ID
No.
OAR­
2002­
0058
are
listed
in
Table
1.

The
March
25,
2004
version
was
revised
to
correct
inconsistencies
with
the
final
rule
discovered
after
the
final
rule
was
signed.
The
corrections
(
indicated
by
redline/
strikeout)
are
on
pages
23,
41,
45,
57,
64,
128,
139,
and
155.
2
Table
1.
List
of
Commenters
on
the
Proposed
NESHAP
for
Industrial,
Commercial,
and
Institutional
Boiler
and
Process
Heaters
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
295
jeanpublic@
yahoo.
com
A­
96­
47,
IV­
D­
17
296
S.
Kaderly
Nebraska
Department
of
Environmental
Quality
Lincoln,
NE
A­
96­
47,
IV­
D­
07
297
R.
C.
Abrams
Kimberly­
Clark
Corporation
Everett
Mill,
Everett,
WA
A­
96­
47,
IV­
D­
18
320
C.
Cary
Biomass
Combustion
Systems,
Inc.
Princeton,
MA
331
R.
W.
Gore
Alabama
Department
of
Environmental
Management
Montgomery,
AL
A­
96­
47,
IV­
D­
08
332
J.
F.
Stahl
Los
Angeles
County
Sanitation
Districts
Los
Angeles,
CA
A­
96­
47,
IV­
D­
20
333
J.
Wallen
Hambro
Forest
Products,
Inc.
Crescent
City,
CA
334
G.
Banks
335
J.
Olashuk
National
Steel
Corporation
Mishawaka,
IN
A­
96­
47,
IV­
D­
21
336
J.
Olashuk
National
Steel
Corporation
Mishawaka,
IN
A­
96­
47,
IV­
D­
12
337
H.
G.
Moore
International
Carbon
Black
Association
Alpharetta,
GA
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
3
A­
96­
47,
IV­
D­
11
338
J.
T.
Clapacs
Indiana
University
Bloomington,
IN
A­
96­
47,
IV­
D­
10
339
H.
Abrams
R.
J.
Reynolds
Tobacco
Co.
Winston­
Salem,
N.
C.

A­
96­
47,
IV­
D­
14
340
J.
T.
Higgins
New
York
Department
of
Environmental
Conservation
Albany,
NY
A­
96­
47,
IV­
D­
09
341
L.
Eagan
STAPPA/
ALAPCO
Washington,
D.
C.

A­
96­
47,
IV­
D­
15
342
D.
Young
Menasha
Utilities
Menasha,
WI
A­
96­
47,
IV­
D­
16
343
E.
M.
Adamo
Air
Products
and
Chemicals
Allentown,
PA
A­
96­
47,
IV­
D­
01
344
P.
Mayberry
INDA
Association
of
the
NonWoven
Fabrics
Industry
Falls
Church,
VA
A­
96­
47,
IV­
D­
24
345
Randy
Putnam
Aurora,
CO
A­
96­
47,
IV­
D­
13
346
G.
A.
Wilkins
Marathon
Ashland
Petroleum
LLC
Findlay,
OH
A­
96­
47,
IV­
D­
25
347
L.
Knee
Bowels
Rice,
McDavid
Graff
&
Love
PLLC
Charleston,
WV
A­
96­
47,
IV­
D­
04
348
J.
Jackson
Cumberland
Lumber
&
Mfg.
Co.,
Inc.
McMinnville,
TN
A­
96­
47,
IV­
D­
05
349
L.
Eagan
State
of
Wisconsin
Department
of
Natural
Resources
Madison,
Wisconsin
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
4
A­
96­
47,
IV­
D­
06
350
J.
Paul
Regional
Air
Pollution
Control
Association
Dayton,
Ohio
A­
96­
47,
IV­
D­
03
351
T.
Pugh
American
Public
Power
Association
Washington,
DC
A­
96­
47,
IV­
D­
02
352
J.
Bardi
American
Society
for
Testing
and
Materials
(
ASTM)
W.
Conshohocken,
PA
A­
96­
47,
IV­
D­
57
353
A.
R.
Heighway
Eli
Lilly
and
Company
Indianapolis,
IN
A­
96­
47,
IV­
D­
56
354
N.
J.
House
BAE
Systems
Ordnance
Systems
Inc.
Holston
Army
Ammunition
Plant
Kingsport,
TN
A­
96­
47,
IV­
D­
36
356
J.
Allen
Rochester
Gas
and
Electric
Corporation
Rochester,
NY
A­
96­
47,
IV­
D­
35
357
D.
Reiter
U.
S.
Enrichment
Corporation's
Paducah
Gaseous
Diffusion
Plant,
Paducah,
KY
A­
96­
47,
IV­
D­
37
358
D.
S.
Hedrick
Associated
Electric
Cooperative,
Inc.
Springfield,
MO
359
S.
Frey
Wisconsin
Public
Power
Inc.
Sun
Prairie,
WI
360
C.
P.
Feerick
Exxon
Mobil
361
J.
L.
Nitzschke
Deere
&
Company
Moline,
IL
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
5
362
J.
L.
Nitzschke
Deere
&
Company
Moline,
IL
363
R.
Merriman
Peru
Utilities
Peru,
IN
A­
96­
47,
IV­
D­
123
364
Attachments
to
OAR­
2002­
0058­
0366
A­
96­
47,
IV­
D­
102
365
D.
Kolaz
Illinois
Environmental
Protection
Agency
Springfield,
IL
A­
96­
47,
IV­
D­
123
366
T.
G.
Hunt
American
Forest
&
Paper
Association,
Inc.
Washington,
DC
A­
96­
47,
IV­
D­
102
367
D.
Kolaz
Illinois
Environmental
Protection
Agency
Springfield,
IL
A­
96­
47,
IV­
D­
123
368
Attachments
to
OAR­
2002­
0058­
0366
369
D.
R.
Schregardus
Department
of
the
Navy
Washington,
DC
370
P.
A.
Reinhardt
University
of
North
Carolina
at
Chapel
Hill
Chapel
Hill,
NC
371
M.
C.
Frank
Boeing
Company
Arlington,
VA
372
M.
R.
Weber
CMS
Generation
Co.
Dearborn,
MI
373
D.
G.
Koster
Holland
Board
of
Public
Works
Holland,
MI
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
6
374
D.
M.
Chari
Rohm
and
Haas
Company
Philadelphia,
PA
375
C.
Clapsaddle
MSI/
Mechanical
Systems
Inc.
Raleigh,
NC
376
J.
Shefchek
Alliant
Energy
Madison,
WI
377
T.
LaFond
Battery
Council
International
Washington,
DC
378
R.
G.
Rao
Indiana
Municipal
Power
Agency
Carmel,
IN
A­
96­
47,
IV­
D­
34
379
J.
P.
Witkowski
South
Carolina
Chamber
of
Commerce
Columbia,
SC
380
L.
Beal
Interstate
Natural
Gas
Association
of
America
Washington,
DC
381
H.
P.
Quinn,
Jr.
National
Mining
Association
Washington,
DC
382
J.
C.
deRuyter
DuPont
Engineering
Wilmington,
DE
383
R.
Kaufmann
and
L.
Otwell
Georgia­
Pacific
Corp.
Atlanta,
GA
384
S.
Davis
Pinnacle
West
Capital
Corporation
Phoenix,
AZ
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
7
385
S.
Davis
Pinnacle
West
Capital
Corporation
Phoenix,
AZ
386
S.
Davis
Pinnacle
West
Capital
Corporation
Phoenix,
AZ
A­
96­
47,
IV­
D­
122
387
R.
Brear
Domtar
Industries
Inc.
Ashdown,
AR
388
Attachments
to
OAR­
2002­
0058­
0389
A­
96­
47,
IV­
D­
60
389
J.
Summers
Textile
and
Carpet
Industry
MACT
Coalition
Atlanta,
GA
390
N.
Burwell
Lansing
Board
of
Water
and
Light
Lansing,
MI
391
Attachments
to
OAR­
2002­
0058­
0389
0392
Attachments
to
OAR­
2002­
0058­
0389
A­
96­
47,
IV­
D­
108
393
Debra
J.
Jezouit
Counsel
to
the
Class
of
'
85
Regulatory
Response
Group
Washington,
DC
A­
96­
47,
IV­
D­
62
394
Springs
Industries
A­
96­
47,
IV­
D­
121
395
P.
Maciejewski
General
Motors
Corporation
Troy,
MI
396
D.
F.
Hunter
ConocoPhillips
Houston,
TX
397
W.
O'Sullivan
New
Jersey
Department
of
Environmental
Protection
Trenton,
NJ
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
8
398
M.
F.
Nitchals
Willmar
Municipal
Utilities
Willmar,
MN
A­
96­
47,
IV­
D­
61
399
J.
M.
Geers
Cinergy
Corp.
Cincinnati,
OH
400
R.
D.
Langford
Celanese
Americas
Corporation
Narrows,
VA
A­
96­
47,
IV­
D­
59
401
D.
C.
Reeves
American
&
Efird,
Inc.
Mt.
Holly,
NC
402
K.
Evans
Phelps
Dodge
Corporation
______,
__

403
S.
E.
Woock
Weyerhaeuser
New
Bern,
NC
404
T.
S.
Van
Til
Primary
Power
International
Ithaca,
MI
405
J.
Wittenborn
Counsel
to
Specialty
Steel
Industry
of
North
America
Washington,
DC
A­
96­
47,
IV­
D­
26
406
J.
A.
Fanjul
Atlantic
Sugar
Association,
Inc.
Belle
Glade,
FL
A­
96­
47,
IV­
D­
93
407
W.
A.
Raiola
United
States
Sugar
Corporation
Clewiston,
FL
A­
96­
47,
IV­
D­
104
408
J.
Alvarez
Sugar
Cane
Growers
Cooperative
of
Florida
Belle
Glade,
FL
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
9
409
W.
D.
Herrin
Southern
Company
Birmingham,
AL
410
R.
Karp
American
Petroleum
Institute
Washington,
DC
411
Attachment
to
OAR­
2002­
0058­
0410
A­
96­
47,
IV­
D­
72
412
M.
Johnston
Michigan
Manufacturers
Association
Lansing,
MI
413
G.
Calvo
Utility
Air
Regulatory
Group
Washington,
DC
414
M.
W.
Stroben
Duke
Energy
Charlotte,
NC
A­
96­
47,
IV­
D­
58
415
M.
Murray
National
Wildlife
Federation
Ann
Arbor,
MI
A­
96­
47,
IV­
D­
120
416
T.
R.
Weeks
San
Diego
County
Air
Pollution
Control
Board
San
Diego,
CA
417
D.
A.
McWilliams
Counsel
to
American
Municipal
Power­
Ohio,
Inc.
Columbus,
OH
418
D.
A.
McWilliams
Counsel
to
Blast
Furnace
Operator
Group
Cleveland,
OH
419
E.
H.
McMeekin
PPG
Industries,
Inc.
Allison
Park,
PA
A­
96­
47,
IV­
D­
40
420
T.
Woods
Downingtown,
PA
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
10
A­
96­
47,
IV­
D­
41
421
N.
Kothari
Manitowoc
Public
Utilities
Manitowoc,
WI
A­
96­
47,
IV­
D­
42
422
J.
Hunter
City
of
Shelby
Shelby,
OH
A­
96­
47,
IV­
D­
43
423
M.
Green
Central
Electric
Power
Cooperative
Chamois,
MO
A­
96­
47,
IV­
D­
44
424
C.
Hornback
Association
of
Metropolitan
Sewerage
Agencies
Washington,
DC
A­
96­
47,
IV­
D­
45
425
J.
Shumaker
International
Paper
Memphis,
TN
A­
96­
47,
IV­
D­
46
426
P.
T.
Cavanaugh
ChevronTexaco
Washington,
DC
A­
96­
47,
IV­
D­
50
427
B.
C.
Thomas
Alyeska­
Pipeline
Valdez,
AK
A­
96­
47,
IV­
D­
47
428
M.
Y.
Kinter
The
Graphic
Arts
Coalition
Fairfax,
VA
A­
96­
47,
IV­
D­
51
429
R.
McMahon
City
of
Painesville
Painesville,
OH
A­
96­
47,
IV­
D­
52
430
R.
Rawson
American
Boiler
Manufacturers
Association
Arlington,
VA
A­
96­
47,
IV­
D­
53
431
D.
C.
Ailor
American
Coke
and
Coal
Chemicals
Institute
Washington,
DC
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
11
A­
96­
47,
IV­
D­
54
432
J.
M.
Meriwether
New
Hope
Power
Partnership
South
Bay,
FL
(
cover
letter
to
433)

A­
96­
47,
IV­
D­
54
433
J.
M.
Meriwether
New
Hope
Power
Partnership
(
NHPP)
South
Bay,
FL
A­
96­
47,
IV­
D­
112
434
M.
Vignovic
Weirton
Steel
Corporation
Weirton,
WV
435
D.
G.
Pauken
Muscatine
Power
and
Water
(
MPW)
Muscatine,
IO
A­
96­
47,
IV­
D­
111
436
M.
Cooke
Counsel
to
Florida
Citrus
Processors
Association
Tampa,
FL
437
S.
Felton
AK
Steel
Middletown,
OH
438
Arch
Coal,
Inc.
St.
Louis,
MO
A­
96­
47,
IV­
D­
116
439
M.
C.
Malott
Delphi
Automotive
Systems,
LLC
Troy,
MI
440
R.
Fellows
Transprint
USA
Harrisonburg,
VA
441
J.
Idzorek
NRG
Energy,
Inc.
Minneapolis,
MN
A­
96­
47,
IV­
D­
118
442
K.
Finemore
New
Hampshire
Department
of
Environmental
Services
Concord,
NH
443
D.
J.
Krouskop
MeadWestvaco
MD
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
12
A­
96­
47,
IV­
D­
115
444
J.
Jackson
Boise
Cascade
Corporation
Boise,
ID
445
J.
W.
Shipp
Tennessee
Valley
Authority
Chattanooga,
TN
446
T.
P.
Walmsley
Fibrowatt
LLC
Yardley,
PA
447
T.
J.
Norberg
Rubber
Manufacturers
Association
Washington,
DC
A­
96­
47,
IV­
D­
96
448
J.
Walke
Natural
Resources
Defense
Council
Washington,
DC
A­
96­
47,
IV­
D­
119
449
Council
of
Industrial
Boiler
Owners
450
M.
A.
Peters
Counsel
to
American
Airlines
Inc.,
OK
A­
96­
47,
IV­
D­
113
451
EarthJustice
Washington,
DC
A­
96­
47,
IV­
D­
106
452
G.
Gesell
American
Ref­
Fuel
Company
Montvale,
NJ
A­
96­
47,
IV­
D­
49
453
Attachment
to
OAR­
2002­
0058­
0454
A­
96­
47,
IV­
D­
49
454
G.
Narum
Simpson
Tacoma
Kraft
Company,
LLC
Tacoma,
WA
A­
96­
47,
IV­
D­
49
455
Attachment
to
OAR­
2002­
0058­
0454
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
13
456
M.
Round
Northeast
States
for
Coordinated
Air
Use
Management
Boston,
MA
457
Attachment
to
OAR­
2002­
0058­
0456
458
Attachment
to
OAR­
2002­
0058­
0456
459
Attachment
to
OAR­
2002­
0058­
0456
460
Attachment
to
OAR­
2002­
0058­
0456
461
Attachment
to
OAR­
2002­
0058­
0456
462
Attachment
to
OAR­
2002­
0058­
0456
463
Attachment
to
OAR­
2002­
0058­
0456
464
Attachment
to
OAR­
2002­
0058­
0456
465
Attachment
to
OAR­
2002­
0058­
0456
466
Attachment
to
OAR­
2002­
0058­
0456
467
Attachment
to
OAR­
2002­
0058­
0456
A­
96­
47,
IV­
D­
92
468
B.
Sorensen
Packaging
Corporation
of
America
Lake
Forest,
IL
A­
96­
47,
IV­
D­
94,
IV­
D­
95
469
M.
R.
Perry
City
of
Hamilton
Hamilton,
Ohio
A­
96­
47,
IV­
D­
91
470
D.
R.
Steiner
City
of
Orrville
Orrville,
Ohio
A­
96­
47,
IV­
D­
90
471
G.
Freewalt
City
of
St.
Mary's
St.
Mary's,
Ohio
A­
96­
47,
IV­
D­
89
472
S.
Rentfrow
Crisp
County
Power
Commission
Cordele,
GA
A­
96­
47,
IV­
D­
88
473
J.
D.
Bassett
Vaughn­
Bassett
Furniture
Galax,
VA
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
14
A­
96­
47,
IV­
D­
87
474
D.
P.
Maddox
Stanley
Furniture
Company
Stanleytown,
VA
A­
96­
47,
IV­
D­
32
475
M.
Hohman
US
Steel
Corporation
Clairton,
PA
A­
96­
47,
IV­
D­
86
476
P.
A.
Lacey
American
Gas
Association
Washington,
DC
A­
96­
47,
IV­
D­
85
477
C.
Jones
Ohio
Environmental
Protection
Agency
Columbus,
OH
A­
96­
47,
IV­
D­
84
478
E.
Clark
Synthetic
Organic
Chemical
Manufacturers
Association
Washington,
DC
A­
96­
47,
IV­
D­
83
479
N.
Dee
National
Petrochemical
&
Refiners
Association
Washington,
DC
A­
96­
47,
IV­
D­
82
480
T.
Shonkwiler
Duncan,
Weinberg,
Genzer
and
Pembroke
Washington,
DC
A­
96­
47,
IV­
D­
81
481
R.
P.
Hornrighausen
City
of
Dover
Dover,
OH
A­
96­
47,
IV­
D­
80
482
D.
R.
Adams
Wisconsin
Electric
Power
Company
Milwaukee,
WI
A­
96­
47,
IV­
D­
33
483
O.
M.
Dominguez
National
Aeronautics
and
Space
Administration
Washington,
DC
A­
96­
47,
IV­
D­
38
484
J.
J.
Lyphout
University
of
Notre
Dame
Notre
Dame,
IN
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
15
A­
96­
47,
IV­
D­
79
485
M.
Martinez
Merck
&
Co.,
Inc.
Whitehouse
Station,
NJ
A­
96­
47,
IV­
D­
78
486
R.
J.
Barkanic
PPL
Services
Corp.
Allentown,
PA
A­
96­
47,
IV­
D­
77
487
W.
C.
Herz
The
Fertilizer
Institute
Washington,
DC
A­
96­
47,
IV­
D­
29
488
J.
R.
Strenkowski
Counsel
to
Association
of
Battery
Recyclers
Inc.
Washington,
DC
A­
96­
47,
IV­
D­
76
489
R.
P.
Streiter
The
Aluminum
Association,
Inc.
Washington,
DC
A­
96­
47,
IV­
D­
75
490
G.
J.
Dana
Alliance
of
Automobile
Manufacturers
Washington,
DC
A­
96­
47,
IV­
D­
74
491
R.
W.
Schenker
General
Electric
Company
Fairfield,
CT
A­
96­
47,
IV­
D­
73
492
J.
J.
Mayhew
American
Chemistry
Council
Arlington,
VA
493
Attachment
to
OAR­
2002­
0058­
0448
494
Attachment
to
OAR­
2002­
0058­
0448
495
Attachment
to
OAR­
2002­
0058­
0448
496
Attachment
to
OAR­
2002­
0058­
0448
A­
96­
47,
IV­
D­
39
497
B.
Perdue
American
Furniture
Manufacturers
Association
High
Point,
NC
A­
96­
47,
IV­
D­
109
498
J.
W.
Snyder
The
Corn
Refiners
Association,
Inc.
Washington,
DC
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
16
A­
96­
47,
IV­
D­
117
499
P.
F.
Faggert
Dominion
Glen
Allen,
VA
A­
96­
47,
IV­
D­
114
500
J.
Carson
Ispat
Inland,
Inc.,
East
Chicago,
IN
501
D.
A.
Buff
The
Florida
Sugar
Industry
Gainesville,
FL
A­
96­
47,
IV­
D­
55
502
E.
Bulgin
The
Amalgamated
Sugar
Company,
LLC
Nampa,
ID
A­
96­
47,
IV­
D­
23
503
W.
S.
Kubiak
US
Steel
Corporation
Pittsburgh,
PA
A­
96­
47,
IV­
D­
27
504
W.
S.
Unruh
US
Steel
Corporation
Fairfield,
AL
A­
96­
47,
IV­
D­
68
505
J.
Alexander
US
Steel
Corporation
Gary,
IN
A­
96­
47,
IV­
D­
67
506
J.
F.
Stevens
City
of
Vero
Beach
Vero
Beach,
FL
A­
96­
47,
IV­
D­
66
507
M.
E.
Ludecker
Wood
Mode,
Inc.
Kreamer,
PA
A­
96­
47,
IV­
D­
65
508
C.
R.
Titus
Kitchen
Cabinet
Manufacturers
Association
Reston,
VA
A­
96­
47,
IV­
D­
30
509
W.
E.
Schwandt
Moorehead
Public
Service
Moorhead,
MN
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
17
A­
96­
47,
IV­
D­
64
510
P.
A.
Bennett
Molded
Fiber
Glass
Companies
Ashtabula,
OH
A­
96­
47,
IV­
D­
132
511
W.
B.
Vaughan
Vaughan
Furniture
Company
Galax,
VA
A­
96­
47,
IV­
D­
135
512
A.
Johnston
Clean
Air
Task
Force
Boston,
MA
A­
96­
47,
IV­
D­
133
513
J.
R.
Groves
Century
Furniture
Industries
Hickory,
NC
A­
96­
47,
IV­
D­
134
514
P.
W.
Craymer
Bernhardt
Furniture
Co.
Lenoir,
NC
A­
96­
47,
IV­
D­
22
515
R.
Hahn
Jones­
Hamilton
Co.
Walbridge,
OH
A­
96­
47,
IV­
D­
99
517
G.
L.
Kiser
La­
Z­
Boy,
Inc.
Monroe,
MI
A­
96­
47,
IV­
D­
100
518
J.
H.
Beall
Fairfield
Chair
Company
Lenoir,
NC
A­
96­
47,
IV­
D­
101
519
D.
L.
Chapman
Goodyear
Tire
&
Rubber
Company
Akron,
OH
A­
96­
47,
IV­
D­
103
520
A.
Lawrence
Department
of
Energy
(
DOE)
Washington,
DC
A­
96­
47,
IV­
D­
97
521
W.
Kjonaas
Purdue
University
West
Lafayette,
IN
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
18
A­
96­
47,
IV­
D­
98
522
R.
M.
Ridgway
Coalition
of
University
Coal­
fired
Boiler
Owners
West
Lafayette,
IN
A­
96­
47,
IV­
D­
72
523
M.
Johnston
Michigan
Manufacturers
Association
Lansing,
MI
A­
96­
47,
IV­
D­
107
524
S.
H.
Bruntz
Alcoa
Power
Generating
Plant
­
Warrick
Power
Plant
Newburgh,
IN
A­
96­
47,
IV­
D­
28
525
T.
Mangum
Drexel
Heritage
High
Point,
NC
A­
96­
47,
IV­
D­
124
526
H.
Martin
Pennsylvania
House,
Inc.
Lewisburg,
PA
A­
96­
47,
IV­
D­
125
527
D.
C.
Foerter
Institute
of
Clean
Air
Companies,
Inc.
Washington,
DC
A­
96­
47,
IV­
D­
126
528
M.
Carey
Ohio
Coal
Association
Columbus,
OH
A­
96­
47,
IV­
D­
127
529
R.
C.
Methier
Georgia
Dept.
of
Natural
Resources
Atlanta,
GA
A­
96­
47,
IV­
D­
128
530
M.
R.
Benoit
Cement
Kiln
Recycling
Coalition
Washington,
DC
A­
96­
47,
IV­
D­
129
531
S.
M.
Kincaid
Kincaid
Furniture
Company,
Inc.
Hudson,
NC
A­
96­
47,
IV­
D­
130
532
J.
M.
Daniel
Virginia
Department
of
Environmental
Quality
Richmond,
CA
Docket
No.
Docket
ID
No.
OAR­
2002­
0058
Commenter,
Address,
Title
or
Description
19
A­
96­
47,
IV­
D­
131
533
R.
Purdue
Citizens
Thermal
Energy
Indianapolis,
IN
A­
96­
47,
IV­
D­
63
534
W.
J.
Haley
Miami
University
Oxford,
OH
A­
96­
47,
IV­
D­
136
535
P.
McPherson
Michigan
State
University
East
Lansing,
MI
A­
96­
47,
IV­
D­
48
536
T.
Pugh
American
Public
Power
Association
Washington,
DC
A­
96­
47,
IV­
D­
105
537
W.
M.
Barfield
South
Carolina
Pulp
&
Paper
Association
Bennettsville,
SC
A­
96­
47,
IV­
D­
71
538
D.
J.
Harvey
Louisiana
Pacific
Corporation
Portland,
OR
539
T.
J.
O'Toole
U.
S.
Steel
­
Mon
Valley
Works
Dravosburg,
PA
540
S.
E.
Woock
Weyerhaeuser
New
Bern,
NC
541
W.
OSullivan
New
Jersey
Department
of
Environmental
Protection
Trenton,
NJ
542
Ohio
Department
of
Development
_____,
OH
20
The
summary
of
public
comments
and
responses
is
organized
as
follows:

3.0
Definitions
4.0
Applicability
4.1
General
4.2
Exemptions
4.3
Lower
size
cutoff
4.4
Major
source
4.5
Delisting
5.0
Format
of
the
Standard
5.1
Surrogates
(
general)
5.2
Surrogates
(
HCl)
5.3
Surrogates
(
CO)
5.4
Miscellaneous
6.0
Compliance
Schedule
6.1
General
6.2
Compliance
Schedule
for
New
Units
6.3
Compliance
Schedule
for
Existing
Units
6.4
Performance
Testing
6.5
Miscellaneous
7.0
Subcategorization
7.1
General
7.2
Additional
Subcategories
7.3
Size
Threshold
7.4
Fuels
8.0
MACT
Floor
9.0
Options
Beyond
the
MACT
Floor
9.1
General
9.2
Carbon
Injection
9.3
Fuel
Switching
10.0
Work
Practices
Standards
11.0
Compliance
11.1
General
11.2
Monitoring
11.3
Operating
Limits
21
11.4
Performance
Testing
12.0
Recordkeeping
and
Reporting
13.0
Impacts
13.1
Control
Costs
13.2
Cost
of
Monitoring
13.3
Methodology
13.4
Cost
to
Municipal
Power
Generators
13.5
Economic
Impacts
13.6
Cost
of
Regulation
13.7
Miscellaneous
14.0
Interaction
with
Other
Rules
14.1
General
14.2
Section
129
14.3
Section
112
14.4
NESHAP
for
Electric
Utility
Steam
Generating
Units
15.0
Emission
Averaging
16.0
Administrative
Requirements
16.1
Executive
Order
12866
16.2
Paperwork
Reduction
Act
16.3
Small
Business
Regulatory
Enforcement
Fairness
Act
16.4
Unfunded
Mandates
Reform
Act
16.5
Executive
Order
13211
17.0
Miscellaneous
17.1
General
Provisions
17.2
Editorial
Corrections
17.3
Miscellaneous
22
3.0
Definitions
Comment:
One
commenter
(
343)
requested
that
EPA
clarify
the
definition
for
"
reconstructed
affected
source."
The
commenter
recommended
that
EPA
add
wording
to
clarify
that
if
a
facility
reconstructed
boilers
or
process
heaters
while
an
area
source,
that
these
units
would
also
be
classified
as
existing
affected
sources
in
the
event
that
the
facility's
status
later
changes
to
a
major
source
of
HAP.
Response:
The
final
rule
clarifies
the
requirements
for
area
sources
that
become
major
sources.
In
§
63.7495(
c)(
2)
of
the
final
rule,
EPA
allows
an
existing
boiler
or
process
heater
located
at
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP
to
comply
with
the
subpart
within
3
years
of
the
facility
becoming
a
major
source.
The
reconstructed
source
is
defined
in
63.7490(
c)
as
"
A
boiler
or
process
heater
is
reconstructed
if
you
meet
the
reconstruction
criteria
as
defined
in
§
63.2
of
subpart
A
of
this
part,
you
commence
reconstruction
after
January
13,
2003,
and
you
meet
the
applicability
criteria
at
the
time
you
commence
reconstruction."
The
applicability
criteria
includes
the
provision
that
an
affected
source
is
located
at
a
major
source
of
HAP
emissions.
Therefore,
if
you
reconstruct
a
boiler
or
process
heater
at
an
area
source,
then
the
source
would
not
meet
the
definition
of
a
reconstructed
source
for
the
purposes
of
this
subpart
since
it
did
not
meet
the
applicability
criteria
at
the
time
you
commenced
reconstruction
(
i.
e.,
it
was
not
located
at
a
major
source
of
HAP
emissions).
In
this
case,
the
boiler
or
process
heater
would
be
considered
an
existing
source
in
the
event
a
facility
later
becomes
a
major
source
of
HAP
emissions
since
it
did
not
meet
the
definition
of
reconstructed
source
under
this
subpart.

Comment:
One
commenter
(
491)
stated
that
Subpart
DDDDD
inconsistently
uses
the
terms
"
source"
and
"
affected
source."
The
commenter
stated
that
the
rule
applies
to
an
"
affected
source,"
a
term
defined
in
§
63.2
of
the
General
Provisions.
The
commenter
stated
that
the
term
"
source"
is
not
defined
and
therefore
has
an
uncertain
meaning.
The
commenter
stated
that
the
rule
should
avoid
use
of
the
term
"
source"
and
be
consistent
and
accurate
in
the
appropriate
use
of
the
term
"
affected
source."
Response:
In
the
final
rule,
we
clarified
the
definition
of
affected
sources
for
the
purposes
of
this
subpart.
For
existing
sources,
the
affected
source
is
the
collection
of
affected
boilers
and
the
collection
of
affected
process
heaters.
For
new
sources,
each
boiler
and
process
heater
is
considered
an
affected
source.
We
also
modified
the
language
in
the
final
rule
to
be
more
consistent
with
terminology
and
adopted
the
term
"
boiler
or
process
heater"
when
discussing
individual
units.

Comment:
Several
commenters
(
346,
360,
364,
382,
392,
387,
388,
399,
400,
410,
419,
449,
479,
490,
492,
498,
523,
524,
533)
suggested
that
EPA
revise
the
proposed
definition
of
affected
source
to
be
consistent
with
the
definition
of
affected
source
in
the
General
Provisions.
The
commenters
added
that
the
affected
source
would
then
be
the
collection
of
industrial,
commercial,
or
institutional
boilers
and
process
heaters
located
at
a
major
source
of
HAP
emissions.
The
definition
in
the
rule
is
much
more
narrow
than
that
in
the
General
Provisions,
even
though
the
General
Provisions
states
that
each
standard
will
redefine
"
affected
source"
based
on
published
justification
as
to
why
the
definition
would
result
in
significant
administration,
practical
or
implementation
problems.
The
commenters
argued
that
EPA
failed
to
provide
23
justification
for
the
proposed
definition
of
affected
source,
which
is
narrower
than
the
definition
of
affected
source
in
the
General
Provisions.
Response:
We
agree
with
the
commenters
and
in
the
final
rule
have
incorporated
the
broader
definition
of
affected
source
from
the
revised
General
Provisions.
The
General
Provisions
define
the
affected
source
as
"
the
collection
of
equipment,
activities,
or
both
within
a
single
contiguous
area
and
under
common
control
that
is
included
in
a
section
112
©
(
c)
source
category
or
subcategory..."
Therefore,
the
definition
of
existing
affected
source
in
the
final
rule
is
the
collection
of
existing
industrial,
commercial,
or
institutional
boilers
and
process
heaters
within
a
subcategory
located
at
a
major
source
of
HAP
emissions.
For
new
sources,
the
definition
of
affected
source
in
the
final
rule
is
each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
located
at
a
major
source
of
HAP
emissions.

Comment:
One
commenter
(
491)
stated
that
two
or
more
boilers
with
a
common
fuel
feed
system,
common
baghouse
and/
or
common
stack
should
be
considered
a
single
affected
source.
The
commenter
stated
that
requiring
separation
of
boiler
coal
feed
and
combustion
emission
streams
just
for
the
purpose
of
complying
with
a
rule
written
with
the
perspective
of
a
single
boiler
or
process
heater
is
onerous
and
unreasonable.
The
commenter
suggested
changing
the
definition
of
boiler
in
§
63.7575
to
read,
"
Boiler
means
an
enclosed
device
using
controlled
flame
combustion
and
having
the
primary
purpose
of
recovering
thermal
energy
in
the
form
of
steam
or
hot
water.
More
than
one
enclosed
device
using
controlled
flame
combustion
and
having
the
primary
purpose
of
recovering
thermal
energy
in
the
form
of
steam
or
hot
water,
and
sharing
the
same
fuel
feed
system,
control
equipment,
and/
or
emissions
stack
are
considered
to
be
a
boiler
if
designated
as
such
in
the
Notification
of
Compliance
Status.
Waste
heat
boilers
are
excluded
from
this
definition."
In
addition,
the
commenter
stated
that
the
information
required
to
be
included
in
the
Notification
of
Compliance
Status
pursuant
to
§
63.7545
needs
to
be
expanded
as
follows:
(
f)
If
you
designate
two
or
more
enclosed
devices
using
controlled
flame
combustion
and
having
the
primary
purpose
of
recovering
thermal
energy
in
the
form
of
steam
or
hot
water,
that
share
the
same
fuel
feed
system,
control
equipment
and/
or
emissions
stack,
to
be
a
boiler,
you
must
define
those
devices
comprising
the
boiler
in
the
Notification
of
Compliance
Status
report.
Response:
In
the
final
rule,
we
revised
the
definition
of
existing
affected
source
to
be
the
collection
of
existing
industrial,
commercial,
or
institutional
boilers
and
process
heaters
within
a
subcategory
located
at
a
major
source
of
HAP
emissions.
We
believe
this
change
will
resolve
the
commenter's
concerns.
Furthermore,
we
modified
the
fuel
monitoring
provisions
of
the
rule
from
requiring
daily
fuel
monitoring
to
requiring
monthly
fuel
monitoring.
This
should
provide
relief
for
facilities
that
have
units
that
share
various
components.

Comment:
The
commenter
(
492)
suggested
the
term
"
deviation"
should
be
changed
to
"
excursion"
to
avoid
confusion
with
Title
V
operating
permit
requirements
and
for
consistency
with
other
NESHAP
(
e.
g.,
HON).
Response:
We
disagree
with
the
commenter's
suggestion.
We
recognize
that
the
term
excursion
was
used
in
the
HON
and
other
MACT
rules.
However,
EPA's
current
policy
is
to
use
the
term
deviation
to
describe
variances
from
the
regulation.
Anything
not
meeting
the
requirements
from
the
standard
is
considered
a
deviation
from
the
standard.
We
would
like
to
clarify
that
deviations
are
only
considered
violations
if
the
regulatory
authority
determines
them
to
be
violations
of
the
standard.
24
Comment:
Two
commenters
(
447,
519)
expressed
concern
over
the
EPA
proposed
definition
of
distillate
oil.
The
commenter
explained
that
the
proposed
rule
defines
distillate
oil
as
fuel
oil
number
1
or
2
as
defined
by
American
Society
for
Testing
and
Materials
(
ASTM)
with
a
nitrogen
content
of
0.05
or
less.
The
commenters
noted
that
the
proposed
rule
references
ASTM
standard
D396­
78,
which
was
the
1978
version.
The
commenters
requested
that
EPA
modify
that
reference
to
the
most
recent
ASTM
standard
D396­
02a.
Secondly,
the
commenters
noted
that
neither
the
specification
nor
the
EPA
includes
a
test
method
for
determining
nitrogen
content.
The
commenters
also
questioned
EPA's
rationale
in
establishing
a
nitrogen
content
limit
because
EPA
has
not
given
any
indication
that
nitrogen
content
is
related
to
HAP
emissions.
The
commenters
believe
that
it
is
not
appropriate
to
regulate
distillate
oils
that
have
a
nitrogen
content
higher
than
0.05
percent
as
a
residual
fuel
oil.
The
commenters
requested
that
EPA
delete
any
reference
to
nitrogen
content
in
the
distillate
fuel
oil
definition.
The
commenter
also
stated
that
some
fuel
suppliers
have
been
reluctant
to
certify
that
the
oil
they
are
supplying
meets
a
certain
ASTM
specification.
The
commenters
requested
that
EPA
revise
the
proposed
rule
to
allow
for
alternative
means
of
demonstration
that
a
boiler
is
consuming
only
non­
residual,
or
distillate
oil.
One
commenter
(
529)
questioned
the
definitions
of
"
distillate
oil"
and
"
residual
oil",
asking
for
the
purpose
of
using
nitrogen
content
to
determine
fuel
oil
categories.
One
commenter
(
478)
requested
that
EPA
revise
the
definition
of
residual
oil
to
not
include
number
2
oil.
Response:
In
the
final
rule,
we
removed
the
nitrogen
specifications
that
were
contained
in
the
proposed
definitions
of
distillate
and
residual
oil.
We
agree
with
the
commenters
that
fuel
oil
should
not
be
differentiated
in
this
standard
based
on
nitrogen
content
because
such
delineations
are
not
appropriate
for
a
standard
regulating
hazardous
air
pollutants.
We
also
updated
the
ASTM
standard
reference
for
oil
type
determination.
We
believe
that
the
proposed
requirements
for
demonstrating
whether
you
are
not
burning
any
residual
oil
is
appropriate
and
did
not
change
that
requirement
in
the
final
rule.
While
fuel
suppliers
may
not
certify
whether
their
oil
meets
an
ASTM
standard,
suppliers
typically
categorize
by
ASTM
oil
numbers
or
by
common
names
(
e.
g.,
residual
oil,
distillate
oil,
kerosene,
diesel).

Comment:
One
commenter
(
491)
stated
that
the
inclusion
of
"
spray
dryer"
in
the
definition
of
dry
scrubber
is
not
necessary
and
adds
confusion
regarding
the
activity
that
is
being
defined.
The
commenter
stated
that
in
chemical
manufacturing
operations,
a
spray
dryer
typically
refers
to
a
unit
operation
other
than
scrubbing
or
emissions
control.
The
commenter
suggested
the
definition
be
clarified
by
either
removing
"
spray
dryer"
or
replacing
it
with
another
descriptive
term
as
shown
below:
Dry
scrubber
means
an
add­
on
air
pollution
control
system
that
injects
dry
alkaline
sorbent
(
dry
injection)
or
sprays
an
alkaline
sorbent
(
spray
injection)
to
react
with
and
neutralize
acid
gas
in
the
exhaust
stream,
forming
a
dry
powder
material.
Response:
We
retain
the
term
"
spray
dryer"
in
the
definition
of
dry
scrubber
because
in
some
cases
it
does
refer
to
a
type
of
emission
control
device.
Since
there
are
no
regulatory
impacts
of
keeping
this
term
in
the
definition
and
the
context
in
which
it
is
discussed
clearly
categorizes
it
as
an
emission
control
device,
we
do
not
believe
that
removing
the
term
is
justified.

Comment:
One
commenter
(
370)
requested
clarification
of
the
definition
of
dry
scrubber,
which
does
not
clearly
include
dry
sorbent
injection
in
circulating
fluidized­
bed
boilers
as
a
dry
scrubber.
The
commenter
requested
circulating
fluidized­
bed
boiler
units
with
limestone
and
caustic
sorbent
injection
to
be
considered
control
for
inorganic
acid
gases.
If
the
EPA
does
not
intend
to
include
circulating
fluidized­
bed
boilers
with
sorbent
injection,
then
the
commenter
25
requested
modification
of
the
definition
or
modification
of
the
rule.
Response:
In
the
final
rule
we
included
sorbent
injection
systems
in
fluidized
bed
boilers
in
the
definition
of
dry
scrubbers.
Since
this
type
of
control
may
be
used
to
achieve
compliance
with
the
emission
limits
in
this
NESHAP,
including
sorbent
injection
systems
will
result
in
the
sorbent
injection
rate
being
considered
an
operating
limit
for
the
purposes
of
ongoing
compliance
demonstrations.

Comment:
One
commenter
(
358)
contended
that
EPA
has
redefined
a
utility
boiler
incorrectly
by
applying
heat
input
to
generator
output.
Response:
The
definition
of
electric
utility
steam
generating
unit
in
the
proposal
and
in
the
final
rule
is
consistent
with
the
definition
in
section
112
of
the
CAA
and
in
other
EPA
regulations.
Since
the
definition
is
consistent
with
the
CAA
section
that
mandates
the
NESHAP
program,
we
retain
it
in
the
final
rule.

Comment:
One
commenter
(
529)
questioned
the
definition
of
"
biomass
fuel,"
asking
if
wood
residue
and
wood
products
include
wood
that
contains
some
type
of
binder.
Response:
In
the
final
rule,
we
clarify
that
biomass
fuel
includes
unadulterated
wood
products.
Plywood,
particle
board,
oriented
strand
board,
and
other
types
of
wood
products
bound
by
glues
and
resins
are
included
in
this
definition.
If
the
wood
residue
or
wood
product
contains
only
binders
and
is
not
painted,
pigment­
stained,
or
pressure
treated
with
compounds
such
as
chromate
copper
arsenate,
pentachlorophenol,
and
creosote,
then
it
is
considered
to
be
biomass.

Comment:
One
commenter
(
491)
requested
that
EPA
clarify
the
definitions
of
fuels
to
indicate
that
solid,
liquid,
and
gaseous
fuels
are
fuels
and
are
not
chemical
feedstocks
or
something
else.
The
commenter
suggested
the
following
clarifications:
I.
Solid
fuel
means
fuel
in
solid
form
and
includes,
but
is
not
limited
to,
coal,
wood,
biomass,
tires,
plastics,
and
other
non­
fossil
solid
materials.

II.
Gaseous
fuel
means
fuel
in
gaseous
form
and
includes,
but
is
not
limited
to,
natural
gas,
synthetic
natural
gas,
process
gas,
refinery
gas,
gasified
coal,
biogas,
and
landfill
gas,
but
does
not
include
process
vent
streams
burned
to
achieve
emission
control.

III.
Liquid
fuel
means
fuel
in
liquid
form
and
includes,
but
is
not
limited
to,
distillate
oil,
residual
oil,
waste
oil,
and
process
liquids.

Response:
We
do
not
agree
with
the
commenter's
suggestion
and
retain
the
proposed
definition
for
solid,
liquid,
and
gaseous
fuels
in
the
final
rule.
We
intended
for
the
terms
solid,
liquid,
and
gaseous
fuels
to
mean
anything
that
is
burned
in
a
boiler
or
process
heater.
For
example,
if
we
incorporated
the
commenter's
suggestion,
a
boiler
that
burns
solid
chemical
feedstock
and
natural
gas
would
be
considered
a
gaseous
fuel­
fired
units,
and
would
not
have
any
emission
limits.
Since
the
solid
chemical
feedstock
may
contain
regulated
pollutants,
by
retaining
the
proposed
definition
of
solid
fuel,
we
at
least
require
them
to
conduct
a
fuel
analysis
to
determine
if
the
pollutant
content
is
lower
than
any
applicable
emission
limit
for
solid
fuel­
fired
units.
26
Comment:
Two
commenters
(
490,
491)
stated
that
the
definition
of
"
gaseous
fuel"
needs
to
be
modified
to
clarify
that
synthetic
natural
gas,
gasified
coal,
and
landfill
gas
are
gaseous
fuels
so
that
boilers
that
fire
these
fuels
will
be
considered
to
be
in
one
of
the
gaseous
fuel
subcategories
and
not
subject
to
emission
limits.
One
commenter
(
490)
stated
that
these
fuels
are
gaseous
and
act
like
gaseous
fuels
in
boilers.
The
commenter
suggested
revising
§
63.7575
as
follows:
Gaseous
fuel
means
fuel
in
gaseous
form
and
includes,
but
is
not
limited
to
natural
gas,
synthetic
natural
gas,
process
gas,
refinery
gas,
gasified
coal,
biogas,
and
landfill
gas,
but
does
not
include
process
vent
streams
burned
to
achieve
emission
control.
The
other
commenter
(
491)
suggested
that
§
63.7575
be
changed
as
follows:
Coal
means
synthetic
fuels,
other
than
synthetic
natural
gas
and
gasified
coal,
derived
from
coal
for
the
purpose
of
creating
useful
heat
including,
but
not
limited
to,
solvent­
refined
coal,
coal­
oil
mixtures,
and
coal­
water
mixtures,
are
included
in
this
definition
for
the
purpose
of
this
subpart.
Two
commenters
(
335,336)
suggested
that
the
definition
of
gaseous
fuels
should
be
revised
by
adding
coke
oven
gas
(
COG)
and
blast
furnace
gas
(
BFG)
to
the
list
of
included
gases
to
avoid
confusion.
Response:
We
agree
with
the
commenters'
suggestion
for
the
definition
of
gaseous
fuels
and
have
modified
the
final
rule
to
include
these
other
gas
types
into
the
definition
of
gaseous
fuel.
With
regard
to
blast
oven
gas,
we
have
exempted
units
from
this
standard
if
they
burn
more
than
90
percent
blast
furnace
gas
on
an
annual
basis.
Based
on
information
provided
by
commenters,
EPA
agrees
that
blast
furnace
gas
does
not
contain
organic
compounds
and
is
comprised
mostly
of
CO.

Comment:
One
commenter
(
491)
urged
EPA
to
provide
that
a
process
vent
stream,
which
is
routed
to
a
boiler
that
serves
as
an
emission
control
device,
is
not
considered
to
be
fuel
for
purposes
of
the
boilers
NESHAP.
In
addition,
the
commenter
suggested
that
the
gaseous
fuel
definition
be
changed
to
read,
"
Gaseous
fuel
includes,
but
is
not
limited
to,
natural
gas,
process
gas,
refinery
gas,
and
biogas,
but
does
not
include
process
vent
streams
burned
to
achieve
emission
control."
Response:
We
disagree
with
commenters'
suggestion
for
the
definition
of
gaseous
fuels.
As
we
explained
in
the
previous
comment,
we
intended
to
consider
any
gas
burned
in
a
boiler
or
process
heater
as
a
fuel,
with
the
exception
of
blast
furnace
case.
We
do
not
believe
that
this
is
an
issue,
since
existing
gaseous
fuel­
fired
units
do
not
have
any
emission
limits,
and
new
gaseous
fuel­
fired
units
only
have
a
carbon
monoxide
work
practice
standard.

Comment:
One
commenter
(
529)
stated
that
because
the
term
"
other
gases"
is
not
defined
in
§
63.7575,
it
is
assumed
that
the
defined
term
"
gaseous
fuel"
is
consistent
with
the
term
"
other
gases."
However,
boilers
and
process
heaters
in
one
of
the
liquid
fuel
subcategories
burning
fossil
fuels
and
other
gases
are
not
required
to
conduct
a
performance
test.
The
commenter
believed
that
allowing
unspecified
process
gases
to
be
combusted
without
determining
compliance
with
standards
provides
no
assurance
of
compliance.
Response:
In
the
rule,
the
use
of
the
term
other
gases
was
intended
to
mean
gaseous
fuels
as
defined
in
§
63.7575.
However,
in
developing
the
MACT
floor
for
the
boilers
and
process
heaters
subject
to
this
NESHAP,
there
was
no
floor
level
of
control.
Therefore,
no
emission
limits
were
applied
to
gaseous
fuel­
fired
units.

Comment:
Several
commenters
(
374,
388,
416,
449,
478,
491,
492,
498,
524,
533)
requested
that
EPA
revise
the
definition
of
hot
water
heaters
to
include
liquid
fuel­
fired
hot
water
27
heaters
and
to
adopt
the
higher
pressure
and
temperature
standards
for
hot
water
heaters
published
by
the
American
Society
of
Mechanical
Engineers
(
i.
e.,
160
p.
s.
i.
and
250
degrees
Fahrenheit).
Response:
In
the
final
rule,
we
included
liquid
fuel­
fired
water
heaters
under
the
definition
of
hot
water
heaters.
However,
we
have
retained
the
proposed
temperature
and
pressure
limitations
for
hot
water
heaters.

Comment:
Several
commenters
(
347,
353,
360,
364,
374,
379,
382,
387,
388,
396,
399,
400,
410,
439,
447,
449,
479,
482,
483,
485,
487,
490,
491,
492,
498,
519,
523,
524,
533)
requested
that
EPA
revise
the
definition
of
gaseous
fuel­
fired
units
to
allow
a
minimum
annual
capacity
utilization
(
hours
of
operation
per
year)
on
fuel
oil,
below
which
the
affected
unit
would
be
classified
as
a
gaseous
fuel
unit.
The
commenters
explained
that
liquid
fuel
is
used
for
a
backup
during
periods
of
gas
curtailment,
gas
supply
emergencies,
and
other
gas
supply
issues.
Several
commenters
stated
that
the
rule
should
specifically
redefine
gaseous
fuel
units
to
include
units
that
have
an
annual
capacity
utilization
on
fuel
oil
of
less
than
or
equal
to
10
percent
(
876
hours
per
year).
One
commenter
(
487)
also
requested
that
this
exemption
include
periodic
testing
to
ensure
available
and
reliable
fuel
switching
when
needed.
One
commenter
(
483)
cited
Model
Unit
Development
Memorandum,
Docket
A­
96­
47
item
II­
B­
6,
because
EPA
concluded
that
units
burning
natural
gas
and
Number
2
fuel
oil
would
burn
Number
2
fuel
oil
only
as
a
backup
fuel
due
to
its
costs
and
EPA
assigned
these
units
to
the
gas
category.
The
commenter
explained
that
incorrect
assignment
of
these
types
of
units
into
the
liquid
fuel
subcategory
would
lead
to
unnecessary
reporting
and
recordkeeping.
One
commenter
(
439)
argued
that
imposing
the
particulate
matter
and
hydrogen
chloride
limitations
at
all
times
for
units
that
may
burn
liquid
fuel
less
than
one
time
annually
is
impractical
and
could
result
in
higher
emissions
due
to
compliance
testing
that
may
take
place
more
often
than
the
alternative
fuel
is
actually
used.
One
commenter
(
410)
noted
that
a
number
of
California
air
pollution
control
districts
provide
for
relaxation
of
emission
limitations
in
recognition
of
natural
gas
curtailment.
Response:
We
agree
with
the
commenters
that
an
allowance
needs
to
be
made
to
deal
with
periods
of
gas
curtailment
and
gas
supply
emergencies.
We
recognize
that
such
situations
do
not
constitute
normal
operation,
but
are
the
result
of
extreme
situations
that
are
not
controlled
by
the
unit
operator.
Therefore,
the
final
rule
allows
gaseous
fuel­
fired
boilers
and
process
heaters
to
burn
liquid
fuel
only
during
periods
of
gas
curtailment
or
gas
supply
emergencies.
We
added
a
definition
of
"
period
of
gas
curtailment
or
supply
interruption"
and
the
final
definitions
of
liquid
fuel
subcategory
excludes
units
that
burn
liquid
fuel
during
periods
of
gas
curtailment
or
gas
supply
emergencies.
We
do
not
provide
an
allowance
for
units
to
test
liquid
fuel
delivery
systems
as
sources
should
maintain
those
systems
during
normal
maintenance
activities.

Comment:
One
commenter
(
519)
requested
that
EPA
modify
the
definition
for
new
liquid
fuel­
fired
units
so
that
units
that
fire
residual
oil
less
than
10
percent
of
the
unit's
capacity
utilization
would
be
subject
to
only
the
limited
use
standards.
Response:
We
do
not
believe
any
change
is
necessary
for
the
final
rule.
The
proposed
and
final
rule
states
that
"
Limited
use
liquid
fuel
subcategory
includes
any
boiler
or
process
heater
that....
has
a
federally
enforceable
annual
average
capacity
factor
of
equal
to
or
less
than
10
percent."
We
consider
the
definition
to
clearly
identify
units
that
are
a
part
of
the
limited
use
subcategory.
We
also
disagree
with
redefining
liquid
subcategories
based
on
residual
oil
use
only.
While
distillate
oil
and
other
liquids
fired
in
boilers
and
process
heaters
are
exempt
from
many
of
28
the
rule
requirements,
these
fuels
are
still
liquids
and
units
burning
them
alone
or
in
combination
with
a
gaseous
fuel
should
be
considered
when
determining
subcategories.

Comment:
Several
commenters
(
364,
382,
387,
388,
399,
440,
449,
473,
474,
479,
492,
497,
498,
511,
513,
514,
517,
518,
524,
525,
526,
531,
533
)
supported
the
inclusion
of
firetube
boilers
in
the
small
solid
fuel
subcategory
definition.
In
addition,
many
other
commenters
(
343,
345,
382,
388,
440,
449,
479,
492,
498,
524,
533)
requested
that
EPA
add
fire­
tube
boilers
to
the
definition
of
small
liquid­
or
gas­
fueled
units.
Response:
We
agree
with
the
commenters'
request
to
add
firetube
boilers
to
the
definition
of
small
liquid
fuel
and
gaseous
fuel
subcategories
and
have
incorporated
these
changes
in
the
final
rule.

Comment:
One
commenter
(
490)
stated
that
according
to
§
63.7575,
"
process
heater
means
an
enclosed
device
using
controlled
flame,
and
the
unit's
primary
purpose
is
to
transfer
heat
indirectly
to
a
process
stream
(
liquid,
gas,
or
solid)
or
to
a
heat
transfer
material
for
use
in
a
process
unit
instead
of
generating
steam.
Process
heaters
are
devices
in
which
the
combustion
gases
do
not
directly
come
into
contact
with
process
materials."
The
commenter
interpreted
that
units
used
for
providing
space
heating
are
not
process
heaters.
The
commenter
requested
confirmation
that
this
interpretation
was
correct.
The
commenter
stated
that
if
EPA
should
disagree
with
this
interpretation,
or
for
some
reason
decide
to
cover
these
space
heaters
in
the
rule,
the
Agency's
cost
analysis
must
be
significantly
revised
upward
due
to
the
huge
capital
and
recordkeeping
costs
that
would
be
imposed.
Two
commenters
(
371,
428)
recommended
that
the
process
heater
definition
be
revised
to
exclude
make­
up
air,
room
air,
space,
or
comfort
heaters,
as
well
as
heating
devices
for
preparation
of
food.
One
commenter
(
428)
recommended
that
the
process
heater
definition
be
revised
to
include
an
explicit
definition
of
a
process
unit.
The
commenter
stated
that
without
the
definition
of
a
process
unit,
there
exists
a
very
strong
possibility
that
the
regulation
might
be
incorrectly
applied
to
sources
such
as
space
and
comfort
heaters.
One
commenter
(
491)
stated
that
the
definition
of
"
process
heater"
is
sufficiently
broad
that
one
might
interpret
that
indirect
fired
furnaces,
autoclaves,
dryers,
etc.
are
process
heaters.
The
commenter
suggested
revising
§
65.7575
as
follows:
"
Process
heater
means
an
enclosed
device
using
controlled
flame,
and
the
unit's
primary
purpose
is
to
transfer
heat
indirectly
to
a
process
stream
(
liquid,
gas,
or
solid)
by
way
of
a
heat
transfer
material
instead
of
generating
steam.
Process
heaters
are
devices
in
which
the
combustion
gases
do
not
come
in
contact
with
process
materials.
Indirect
fired
process
units
such
as
furnaces,
autoclaves,
dryers,
etc.
are
not
process
heaters."
Response:
We
agree
that
comfort
heaters
and
other
types
of
units
discussed
by
the
commenters
should
not
be
subject
to
this
NESHAP.
It
was
not
EPA's
intention
to
regulate
such
systems
in
this
standard.
The
majority
of
these
systems
are
gas­
fired
and
are
very
small.
Therefore,
in
the
final
rule
we
specifically
excluded
comfort
heaters,
space
heaters,
units
used
for
food
preparation
for
on­
site
consumption,
and
autoclaves
from
the
definition
of
process
heaters.

Comment:
One
commenter
(
488)
stated
that
the
definition
of
process
heater
would
include
any
enclosed
device
using
a
controlled
flame
where
the
unit's
primary
purpose
is
to
transfer
heat
indirectly
to
a
process
material,
instead
of
generating
steam.
The
commenter
stated
that
this
definition
could
be
interpreted
to
suggest
that
the
boiler
NESHAP
applies
to
refining
kettles
at
secondary
lead
smelters,
which
are
already
subject
to
the
Secondary
Lead
MACT.
The
29
commenter
suggested
changing
the
language
in
§
63.7490(
b)(
9)
to
read
"
A
refining
kettle
that
is
an
affected
source
under
40
CFR
part
63,
subpart
X."
Response:
We
do
not
intend
for
the
boilers
NESHAP
to
affect
units
that
are
already
regulated
by
another
NESHAP.
We
clarified
the
applicability
section
of
the
final
rule
to
ensure
that
this
does
not
happen.
Furthermore,
§
63.7490
(
b)(
9)
specifically
excludes
refining
kettles
covered
by
40
CFR
part
63,
subpart
X.
We
believe
this
to
be
sufficient
and
do
not
believe
any
further
explanation/
changes
are
necessary
for
this
specific
piece
of
equipment.

Comment:
One
commenter
(
410)
noted
that
the
definition
of
process
heater
in
§
63.7485(
a)
is
not
identical
to
the
one
in
the
definitions
section
of
the
rule
and
requested
that
the
definition
include
heat
transfer
fluids.
Response:
We
have
removed
the
boiler
and
process
heater
definitions
from
§
63.7485(
a)
and
only
provide
definitions
for
boilers
and
process
heaters
in
§
63.7575.
30
4.0
APPLICABILITY
4.1
General
Comment:
One
commenter
(
427)
suggested
a
model
to
discretely
define
high­
risk
urban
areas
at
significantly
lower
costs
than
are
in
the
proposed
rule.
The
commenter
also
suggested
limiting
the
rule's
applicability
to
solid
fuel
fired
sources.
The
commenter
added
that
a
facility
would
then
be
required
to
install
whatever
control
device
is
necessary
to
comply
and
develop
a
site­
specific
operation
and
maintenance
plan
that
details
how
the
source
will
be
monitored
and
the
device
maintained.
The
commenter
continued
that
sources
would
perform
an
initial
test
to
validate
monitoring
parameters,
and
compliance
with
the
operation
and
maintenance
plan
would
constitute
compliance
with
the
MACT
standard.
The
commenter
added
that
control
device
performance
summaries
and
excess
emission
reports
could
be
summarized
and
submitted
on
an
annual
basis.
Response:
We
disagree
with
the
commenter.
The
CAA
does
not
allow
us
to
focus
emission
standards
on
only
high­
risk
urban
areas
in
the
NESHAP
program.
Additionally,
we
do
not
believe
there
is
any
legal
justification
for
regulating
only
solid
fuel­
fired
units.
The
source
category
list
does
not
differentiate
boilers
by
fuel,
but
refers
to
all
industrial
boilers
and
all
institutional
and
commercial
boilers.
We
believe
that
the
final
rule
meets
the
requirements
of
the
CAA,
but
also
limits
the
burden
on
subcategories
where
the
MACT
floor
analysis
indicates
no
emission
reduction
was
determined.
These
subcategories
include
gas
and
liquid
fuel­
fired
units.
Under
the
residual
risk
program
outlined
in
section
112(
f)
of
the
CAA,
we
will
review
emissions
from
this
subcategory
and
promulgate
additional
standards
if
necessary
to
provide
an
ample
margin
of
safety
to
protect
public
health.
With
regard
to
compliance,
you
may
use
whatever
control
device
or
strategy
you
choose
to
meet
the
emission
limits
of
this
rule.
You
are
not
required
to
use
the
MACT
floor
level
of
control,
but
you
are
required
to
meet
the
emission
limits
that
were
based
on
the
MACT
floor
level
of
control.
We
also
allow
you
to
petition
the
Administrator
for
approval
of
an
alternative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63
if
you
want
to
develop
a
site­
specific
monitoring
plan
that
is
different
from
those
contained
in
the
final
rule.

Comment:
One
commenter
(
491)
stated
that
boilers
and
process
heaters
located
at
area
sources
of
HAP
do
not
significantly
impact
air
quality.
The
commenter
supports
limiting
the
boilers
NESHAP
applicability
to
a
boiler
or
process
heater
that
is
located
at
a
major
source
of
HAP.
However,
another
commenter
(
397)
noted
that
similar
sources
affected
by
the
boilers
NESHAP
also
exist
at
area
sources
and
would
not
be
regulated
by
this
NESHAP.
The
commenter
expressed
concern
that
the
health
risks
from
units
located
at
nonmajor
sources
would
be
the
same
as
those
located
at
major
sources,
yet
would
go
unregulated.
Response:
Per
the
requirements
in
section
112(
d)
of
the
CAA,
the
boilers
NESHAP
regulates
only
units
located
at
major
sources.
We
realize
that
similar
sources
affected
by
this
rule
also
exist
at
area
sources
and
are
not
regulated
under
this
rule.
However,
EPA
is
also
studying
emissions
from
boilers
and
process
heaters
located
at
area
sources.
We
will
use
the
results
of
this
study
to
make
a
decision
on
whether
to
regulate
units
located
at
area
sources.
We
anticipate
completing
this
study
and
determining
if
boilers
and
process
heaters
located
at
area
sources
should
be
regulated
in
the
near
future.

Comment:
One
commenter
(
491)
stated
that
the
boilers
NESHAP
attempts
to
establish
31
rule
applicability
in
§
63.7485
and
§
63.7490.
The
commenter
stated
that
this
complicates
the
understanding
of
applicability
because
it
defines
terms
in
the
applicability
sections
that
already
have
defined
meanings
arising
from
the
definitions
established
in
§
63.7575
and
§
63.2.
The
commenter
stated
that
terms
appearing
in
applicable
rule
definition
sections
should
not
be
redefined
in
another
section
of
the
rule.
The
commenter
stated
that
redefining
terms
in
§
63.7485
creates
confusion
and
adds
unnecessary
narrative.
The
commenter
suggested
that
EPA
clarify
§
63.7485
as
follows:
"
You
are
subject
to
this
subpart
if
you
own
or
operate
an
industrial,
commercial,
or
institutional
boiler
or
process
heater,
as
defined
in
§
63.7575,
that
is
located
at,
or
is
part
of
,
a
major
source,
as
defined
in
§
63.2,
except
as
specifically
exempted
in
§
63.7490."
In
addition,
the
commenter
stated
that
the
above
change
would
require
that
§
63.7490(
b)
be
revised
as
follows:
"
The
affected
source
is
each
industrial,
commercial,
or
institutional
boiler
or
process
heater,
as
defined
in
§
63.7575,
that
is
not
one
of
the
types
of
combustion
units
listed
in
§
63.7490(
b)
(
1)
through
(
10)."
Response:
We
agree
with
the
commenters
that
the
applicability
section
and
definitions
in
the
proposed
rule
overlap
and
may
not
be
consistent
with
each
other.
In
the
final
rule,
we
removed
definitions
from
the
applicability
section
and
present
them
in
only
the
definitions
section
of
the
final
rule
or
refer
you
to
the
definitions
contained
in
the
General
Provisions
(
subpart
A
of
part
63).

Comment:
One
commenter
(
485)
noted
that
§
63.7495(
c)(
1)
is
redundant
with
(
a)(
1)
and
(
2),
is
unnecessary,
and
should
be
removed.
The
commenter
also
requested
that
§
63.7495(
c)(
2)
be
included
into
§
63.7495(
b).
Response:
We
disagree
with
the
commenter
and
made
only
minor
changes
to
this
section
in
the
final
rule.
The
provisions
contained
in
§
63.7495(
c)
address
compliance
schedules
for
facilities
that
are
area
sources
at
the
time
the
final
rule
is
promulgated,
but
become
major
sources
at
a
later
date.
The
provisions
in
§
63.7495(
a)
and
(
b)
outline
the
compliance
schedule
for
sources
at
facilities
that
are
major
sources
at
the
time
the
final
rule
is
published.

Comment:
One
commenter
(
369)
requested
that
EPA
clarify
that
sources
reconstructed
before
January
13,
2003
are
subject
to
the
proposed
rule's
existing
affected
source
requirements
and
not
subject
to
the
proposed
rule's
reconstructed
affected
source
requirements.
The
commenter
pointed
out
that
the
rule's
applicability
to
reconstructed
affected
sources
would
not
be
limited
to
those
reconstructed
after
the
proposed
rule's
publication
date
based
on
the
proposed
rule.
The
commenter
believes
this
would
unreasonably
limit
the
number
of
affected
sources
that
would
qualify
as
an
existing
affected
source.
Response:
In
the
final
rule,
we
clarify
that
sources
that
commence
reconstruction
before
January
13,
2003
would
be
considered
existing
sources
under
this
NESHAP.
In
the
proposal,
we
inadvertently
did
not
include
a
trigger
date
for
reconstructed
sources.

Comment:
Two
commenters
(
374,
400)
requested
that
EPA
clarify
that
if
units
that
commence
construction
or
reconstruction
before
January
13,
2003
and
become
subject
to
this
standard
after
promulgation
due
to
a
change
in
operation
(
e.
g.,
no
longer
burn
hazardous
waste)
would
fall
under
the
existing
source
category
and
not
be
classified
as
a
new
source.
One
commenter
(
374)
proposed
rule
language
to
address
this
clarification.
Response:
In
the
final
rule,
§
63.7490(
d)
and
(
e)
state
that
you
are
a
new
or
reconstructed
source
if
you
commence
construction
or
reconstruction
after
January
13,
2003
AND
you
meet
the
32
applicability
criteria
at
the
time
you
commenced
construction
or
reconstruction.
Furthermore,
§
63.7490(
f)
states
that
a
source
is
existing
if
it
does
not
meet
the
definition
of
new
or
reconstructed.
Based
on
these
revisions,
it
is
clear
that
any
source
that
commences
construction
or
reconstruction
on
or
before
January
13,
2003
is
considered
an
existing
source.
Also,
since
the
source
the
commenter
alluded
to
was
considered
a
hazardous
waste
boiler
at
the
time
of
construction
or
reconstruction,
it
would
be
considered
an
existing
source
because
the
definitions
of
new
and
reconstructed
units
contained
in
§
63.7490(
d)
and
(
e)
state
that
you
must
meet
the
applicability
requirements
of
this
NESHAP
at
the
time
you
commenced
construction
or
reconstruction.
As
the
source
was
subject
to
the
hazardous
waste
NESHAP
at
the
time
it
commenced
construction
or
reconstruction,
and
did
not
meet
the
applicability
requirements
of
this
NESHAP
at
that
time,
any
change
in
operation
that
would
result
in
that
source
becoming
subject
to
this
NESHAP
as
an
existing
source.

Comment:
One
commenter
(
492)
suggested
that
EPA
clarify
for
the
boilers
NESHAP
that
retrofitting
and
control
costs
to
comply
with
the
boilers
NESHAP
are
not
considered
reconstruction
costs.
The
commenter
proposed
that
the
boilers
NESHAP
include
language
similar
to
that
found
in
the
Hazardous
Waste
Combustor
NESHAP
(
40
CFR
63.1206(
a)(
2)).
Response:
We
agree
with
the
commenter
that
retrofits
and
control
equipment
costs
incurred
in
complying
with
the
boilers
NESHAP
should
not
be
considered
reconstruction
costs.
This
consideration
is
consistent
with
previous
EPA
regulatory
decisions.

Comment:
One
commenter
(
410)
requested
EPA
clarify
that
the
components
to
be
considered
in
judging
whether
reconstruction
has
occurred
should
include
the
entirety
of
the
boiler
or
process
heater,
and
that
reconstruction
must
involve
replacement
of
boiler
or
heater
components
amounting
to
50
percent
or
more
of
the
cost
of
the
entire
comparable
new
boiler
or
heater.
The
commenter
provided
a
list
of
equipment
components
that
are
part
of
boilers
and
process
heaters.
Response:
In
the
general
provisions
to
40
CFR
part
63,
reconstruction
is
defined
as:
"
Reconstruction,
unless
otherwise
defined
in
a
relevant
standard,
means
the
replacement
of
components
of
an
affected
or
a
previously
nonaffected
source
to
such
an
extent
that:
(
1)
The
fixed
capital
cost
of
the
new
components
exceeds
50
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
a
comparable
new
source;
and
(
2)
It
is
technologically
and
economically
feasible
for
the
reconstructed
source
to
meet
the
relevant
standard(
s)
established
by
the
Administrator
(
or
a
State)
pursuant
to
section
112
of
the
[
Clean
Air]
Act.
Upon
reconstruction,
an
affected
source,
or
a
stationary
source
that
becomes
an
affected
source,
is
subject
to
relevant
standards
for
new
sources,
including
compliance
dates,
irrespective
of
any
change
in
emissions
of
hazardous
air
pollutants
from
that
source."
Based
on
this
definition
and
the
definition
of
affected
source
in
the
final
rule,
you
would
have
to
spend
50
percent
or
more
of
the
cost
of
the
collection
of
all
your
affected
existing
boilers
or
the
collection
of
all
your
existing
process
heaters
to
trigger
reconstruction.
Given
the
broad
definition
of
existing
affected
source
in
the
final
rule,
we
do
not
specifically
identify
components
that
are
considered
in
judging
whether
reconstruction
has
occurred.
We
have
clarified
in
other
responses
to
comments
that
retrofits
and
control
equipment
costs
incurred
in
complying
with
the
boilers
NESHAP
should
not
be
considered
reconstruction
costs.
33
4.2
Exemptions
Comment:
One
commenter
(
491)
stated
that
natural
gas
used
to
maintain
coal
boiler
igniter/
pilot
flame
controls
should
be
excluded
from
the
regulation.
The
commenter
stated
that
requirements
to
account
for
such
small
uses
of
gas
(
e.
g.,
in
various
recordkeeping,
reporting,
compliance
determinations,
and
calculations
in
§
63.7530(
c))
is
onerous
and
has
a
negligible
impact
on
environmental
protection.
The
commenter
suggested
that
EPA
simplify
recordkeeping,
reporting,
and
compliance
determination
by
excluding
accounting
for
de
minimis
fuel
burned
for
igniter/
pilot
flame
controls
from
the
rule.

Response:
We
do
not
specifically
exclude
fuel
used
to
maintain
pilots
or
for
flame
control.
In
the
final
rule,
we
most
liquid
and
gaseous
fuel­
fired
units
are
not
subject
to
fuel
monitoring
requirements.
We
also
reduced
fuel
monitoring
frequency
to
once
a
month
for
sources
that
are
required
to
monitor
fuel
use.
Given
these
changes,
we
believe
that
the
fuel
monitoring
burden
is
not
significant.
Furthermore,
the
amount
of
fuel
used
for
these
purposes
may
not
be
the
same
from
source
to
source
and
some
sources
may
also
use
these
fuels
as
a
significant
source
of
heat
input.

Comment:
Several
commenters
(
402,
410,
479,
490)
requested
that
EPA
exempt
units
that
are
used
to
achieve
emission
reductions
or
are
required
for
emission
control.
Several
commenters
(
410,
479,
490)
requested
an
exemption
for
incinerators,
thermal
oxidizers,
and
flares
that
are
required
or
selected
to
comply
with
pollution
regulations.
They
also
requested
exemption
for
flares
installed
for
safe
disposal
of
flammable
gases
released
from
a
process
unit
due
to
abnormal
process
conditions.
One
commenter
(
402)
noted
that
pre­
heaters
for
sulfuric
acid
plants
used
for
emission
control
at
copper
smelting
plants
may
be
subject
to
the
proposed
NESHAP,
but
compliance
with
the
emission
standards
and
work
practice
requirements
may
interfere
with
the
effectiveness
of
the
acid
plant
as
a
pollution
control
device
under
the
Copper
Smelting
NESHAP.

Response:
The
final
rule
clarifies
that
equipment
that
are
included
as
part
of
the
affected
source
in
another
NESHAP
are
not
subject
to
the
boilers
NESHAP.
However,
we
do
not
exempt
boilers
and
process
heaters
that
are
used
as
control
devices
unless
they
are
specifically
considered
part
of
another
NESHAP's
definition
of
affected
source.
Incinerators,
thermal
oxidizers,
and
flares
do
not
generally
fall
under
the
definition
of
a
boiler
or
process
heater
and
would
not
be
subject
to
this
rule.
However,
if
one
of
these
types
of
units
are
subject
to
this
rule,
they
typically
burn
gaseous
and
liquid
fuels
and
existing
sources
firing
gaseous
and
liquid
fuels
do
not
have
any
significant
requirements
under
this
NESHAP.

Comment:
One
commenter
(
491)
supported
the
exclusion
of
waste
heat
boilers.
Several
commenters
(
360,
382,
388,
394,
449,
492,
498,
524,
533)
recommended
EPA
exempt
commercial
and
industrial
solid
waste
incinerators
(
CISWI
units)
with
energy
recovery
from
the
definition
of
affected
source.
The
commenters
cited
preamble
language
in
the
proposed
rule
that
indicates
that
CISWI
units
with
energy
recovery
will
not
be
regulated
by
the
boilers
NESHAP.
The
commenters
noted
that
the
proposed
regulatory
language
is
not
clear
and
should
be
revised
to
specifically
exclude
these
units.
Several
commenters
(
410,
436,
479)
requested
that
EPA
revise
the
definition
of
boilers
and
waste
heat
boilers
to
exclude
waste
heat
recovery
devices
and
waste
heat
evaporators.
Two
commenters
(
410,
479)
requested
that
EPA
exempt
waste
heat
boilers
34
that
have
supplemental
firing
as
long
as
the
primary
heat
input
is
from
waste
heat.
One
commenter
(
529)
recommended
the
phrase,
"
Waste
heat
boilers
are
excluded"
be
moved
from
§
63.7485(
a)
to
§
63.7490.

Response:
The
final
rule
excludes
waste
heat
boilers
and
waste
heat
boilers
with
supplemental
firing,
as
long
as
the
supplemental
firing
does
not
provide
more
than
50
percent
of
the
waste
heat
boiler's
heat
input.
If
your
waste
heat
boiler
does
receive
50
percent
of
its
total
heat
input
from
supplemental
firing,
it
may
be
subject
to
the
boilers
NESHAP
unless
it
is
subject
to
another
NESHAP.
The
final
rule
directly
addresses
sources
that
have
been
specifically
listed
as
an
affected
source
under
another
NESHAP
but
not
making
them
subject
to
this
standard.

Comment:
One
commenter
(
476)
supported
EPA's
exclusion
of
residential
natural
gasfired
hot
water
heaters
from
the
proposed
boilers
NESHAP.
One
commenter
(
479)
requested
that
EPA
exempt
liquid
fuel­
fired
hot
water
heaters
from
the
final
boilers
NESHAP.

Response:
We
agree
with
the
commenters
regarding
not
requiring
liquid
fuel­
fired
hot
water
heaters
and
liquid
fuel­
fired
hot
water
heaters
to
be
subject
to
this
rule,
as
long
as
they
meet
the
size,
temperature,
and
pressure
criteria
outlined
in
the
definition
section
of
the
final
NESHAP.

Comment:
Two
commenters
(
410,
497)
requested
that
EPA
exempt
any
boilers
used
to
make
steam
or
heated
water
solely
or
primarily
for
comfort
heating.

Response:
We
specifically
make
comfort
heaters
not
subject
to
the
final
rule.
However,
we
do
not
provide
a
blanket
exemption
for
boilers
used
to
make
steam
or
heated
water
for
comfort
heat.
If
your
boiler
meets
the
definition
of
a
hot
water
heater,
then
it
would
not
be
subject
to
this
rule.
However,
if
the
size,
temperature,
and
pressure
specifications
of
your
boiler
exceed
the
criteria
specified
for
hot
water
heaters,
then
your
boiler
would
be
subject
to
this
NESHAP.

Comment:
Several
commenter
(
343,
413,
491,
499)
requested
that
EPA
specifically
exclude
duct
burners
from
the
final
NESHAP.
One
commenter
(
499)
requested
the
rule
clarify
that
"
duct
burners"
for
heat
recovery
steam
generators
are
not
affected
sources
for
purposes
of
the
MACT
for
small
boilers
and
process
heaters.
One
commenter
(
413)
expressed
concern
that
duct
burners
on
combined
cycle
units
would
be
affected
under
the
proposed
rule.

Response:
In
the
final
rule
we
do
not
make
waste
heat
boilers
(
or
heat
recovery
steam
generators)
subject
to
this
rule
as
long
as
their
supplemental
firing
(
including
duct
burners)
does
not
provide
more
than
50
percent
of
the
heat
input
to
the
waste
heat
boiler.
If
your
duct
burner
provides
more
than
50
percent
of
the
total
heat
input
to
your
heat
recovery
steam
generator,
then
it
would
be
subject
to
this
NESHAP.

Comment:
Several
commenters
(
156,
335,
336,
371,
374,
376,
382,
388,
394,
434,
437,
449,
450,
487,
491,
498,
520,
524,
533)
recommended
that
the
final
boilers
NESHAP
exempt
units
that
have
no
emission
limits
or
work
practice
standards
from
all
monitoring,
recordkeeping,
and
reporting
requirements
of
the
boilers
NESHAP
and
the
General
Provisions.
One
commenter
(
489)
expressed
confusion
over
the
applicability
of
notification,
reporting
and
recordkeeping
35
provisions
to
units
without
emission
limits
or
work
practice
standards
and
requested
clarification
in
the
final
rule
on
the
requirements
for
affected
sources
that
have
no
emission
limits.
However,
several
commenters
(
343,
437,
491,
520)
specifically
requested
that
EPA
not
exempt
these
units
from
the
startup,
shutdown,
and
malfunction
plan
requirements
of
the
NESHAP.
Two
commenters
(
376,
489)
supported
the
proposed
provisions
stating
that
existing
gas­
fired
sources
do
not
have
emissions
limits
and
do
not
need
to
follow
work
practice
standards
to
maintain
compliance.
Several
commenters
(
374,
382,
388,
394,
449,
487,
498,
524,
533)
noted
that
other
MACT
standards
provide
this
exemption
and
that
the
level
of
burden
is
not
justified.
The
commenters
suggested
that
if
EPA
does
decide
to
impose
some
level
of
reporting
for
these
units
that
it
be
limited
to
no
more
than
an
initial
notification.

Response:
We
agree
that
sources
that
do
not
have
any
emission
limits
or
work
practice
standards
should
not
have
to
comply
with
monitoring,
recordkeeping,
and
most
reporting
requirements,
including
startup,
shutdown
and
malfunction
plans.
The
final
rule
limits
the
monitoring,
recordkeeping,
and
reporting
requirements
for
sources
that
have
no
emission
limits
or
work
practice
standards
to
initial
notifications
for
larger
sources,
and
no
requirements
whatsoever
for
smaller
sources.
We
are
also
not
requiring
startup,
shutdown,
and
malfunction
plans
for
sources
that
do
not
have
any
emission
limits
or
work
practice
standards.
This
is
appropriate
because
no
reports
other
than
the
initial
notification
would
apply
to
these
units.
We
do
not
believe
the
SSM
plan
to
be
necessary
or
required
for
these
units
because
§
63.6(
e)(
3)
of
subpart
A
of
this
part
requires
an
affected
source
to
develop
an
SSM
plan
for
control
equipment
used
to
comply
with
the
relevant
standard.
The
proposed
rule
was
not
intended
to
require
monitoring,
recordkeeping,
and
reporting
(
including
startup,
shutdown,
and
malfunction
plans),
other
than
the
initial
notification
for
sources
not
subject
to
an
emission
limit.
We
have
clarified
this
decision
in
the
final
rule.
We
have
also
determined
that
existing
small
units,
which
are
not
subject
to
emission
limits
or
work
practices
in
this
standard,
and
which
are
also
not
subject
to
such
requirements
in
any
other
Federal
regulation,
should
also
not
have
to
provide
an
initial
notification.
These
small
sources
are
generally
gas­
fired
and
since
they
have
minimal
emissions,
they
are
usually
considered
as
insignificant
emission
units
by
State
permitting
agencies.

Comment:
Several
commenters
(
360,
364,
379,
382,
387,
388,
394,
399,
406,
407,
408,
430,
439,
449,
479,
487,
492,
498,
501,
524,
533)
requested
that
EPA
specifically
exclude
portable/
transportable
units
from
the
final
rule.
The
commenters
stated
that
facilities
periodically
use
these
units
to
supply
or
supplement
other
site
steam
supplies
when
there
is
a
mechanical
problem
that
takes
a
unit
out
of
service
or
during
planned
outages.
The
commenters
added
that
because
they
are
used
on
a
limited
basis,
portable
units
are
not
fully
integrated
with
site
control
systems
and
most
portable/
transportable
units
are
owned
by
a
rental
company
and
may
not
be
operated
by
the
facility
owner
or
operator.
One
commenter
(
479)
that
these
types
of
units
typically
fire
only
natural
gas
or
distillate
oil.
Several
commenters
(
382,
406,
407,
408,
492,
501)
also
suggested
revised
rule
language
that
would
exclude
rental
or
temporary
boilers,
as
long
as
the
units
do
not
remain
at
one
location
for
more
than
12
consecutive
months.

Response:
We
agree
with
the
commenters
that
temporary/
portable
units
are
used
only
on
a
limited
basis
and
are
not
integrated
into
a
facilities
control
system.
In
the
final
rule,
we
make
gaseous
and
liquid
fuel­
fired
temporary
boilers
not
subject
to
the
requirements
of
this
NESHAP.
Units
in
the
existing
gaseous
or
liquid
subcategories
are
not
subject
to
emission
limits
or
work
practice
standards.
Consequently,
we
have
decided
to
make
temporary/
portable
units
not
subject
36
to
the
final
rule.
We
have
added
a
definition
for
temporary
boiler
to
mean
any
gaseous
or
liquid
fuel­
fired
boiler
that
is
designed,
and
is
capable
of,
being
carried
or
moved
from
one
location
to
another.
A
temporary
boiler
that
remains
at
a
location
for
more
than
180
consecutive
days
is
no
longer
considered
to
be
a
temporary
boiler.
Any
temporary
boiler
that
replaces
a
temporary
boiler
at
a
location
and
is
intended
to
perform
the
same
or
similar
function
will
be
included
in
calculating
the
consecutive
time
period.
We
chose
the
180
day
time
frame
because
that
is
the
length
of
time
a
new
source
has
after
startup
to
conduct
the
initial
performance
test.

Comment:
Several
commenters
(
336,
339,
345,
356,
361,
362,
377,
395,
405,
427,
439,
489,
490,
523,
529)
recommended
exempting
gaseous
fuel­
fired
units
from
the
final
rule.
Two
commenters
(
477,
510)
requested
that
EPA
exempt
the
small
gaseous
fuel­
fired
category.
The
commenters
noted
that
these
units
do
not
have
any
emission
limits
and
that
making
them
undergo
the
various
recordkeeping
and
reporting
requirements
would
be
an
unnecessary
waste
of
resources.
Several
commenters
(
336,
339,
361,
362,
427,
529)
requested
that
EPA
exempt
all
existing
liquid
fuel­
fired
units.
The
commenters
questioned
why
EPA
would
still
subject
these
units
to
the
NESHAP
when
they
have
no
emission
limits
or
work
practice
standards.
Two
commenters
(
405,
529)
suggested
that
all
distillate
oil­
fired
units
be
exempted.
One
commenter
(
336)
requested
that
EPA
exempt
existing
small
solid
fuel­
fired
units
from
the
NESHAP.
Many
of
the
commenters
stated
these
units
are
inherently
low
in
HAP
emissions
and
the
EPA
cannot
quantify
any
environmental
benefits
from
subjecting
them
to
this
NESHAP.
One
commenter
(
523)
noted
that
since
EPA
did
not
set
emission
limits
for
these
units,
it
indicates
that
they
are
not
significant
sources
of
HAP.
In
addition,
the
commenters
stated
that
it
will
eliminate
the
large
costs
associated
with
recordkeeping
and
reporting
and
the
requirement
to
install
carbon
monoxide
monitors
for
new
units.
Commenters
also
claimed
it
would
significantly
reduce
the
burdens
placed
on
permitting
agencies
to
maintain
permits
for
these
facilities.
One
commenter
(
489)
argued
that
including
these
sources
in
the
rule
has
no
environmental
benefits
and
is
in
contravention
of
the
purpose
of
the
Paperwork
Reduction
Act
of
1995.
One
commenter
(
490)
stated
that
this
solution
would
create
an
incentive
for
facilities
to
use
this
clean­
burning
fuel
when
it
is
possible
to
do
so.

Response:
We
are
required
by
the
Act
to
regulate
sources
on
the
source
category
list.
The
list
includes
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Consequently,
all
such
units,
regardless
of
size,
are
required
by
the
Act
to
be
regulated.
At
proposal,
and
in
the
final
rule,
we
did
separate
sources
into
small,
large
and
limited
use
subcategories
for
the
reasons
described
in
the
proposal
preamble
and
preamble
to
the
final
rule.
As
such,
we
determined
that
there
were
no
MACT
floors
for
existing
small
subcategories
and
limited
use
and
large
gaseous
and
liquid
fuel
subcategories.
We
revised
the
final
rule
to
require
existing
units
that
do
not
have
emission
limits
or
work
practice
requirements
to
submit
only
an
initial
notification.
For
some
smaller
units
with
no
emission
limits
or
work
practice
standards,
there
are
no
requirements.
New
gaseous
and
liquid
fuel­
fired
units
that
have
a
capacity
of
10
MMBtu/
hr
to
100
MMBtu/
hr
must
conduct
an
annual
test
to
maintain
CO
limits
and
must
keep
records
of
the
annual
test.
Units
larger
than
100
MMBtu/
hr
must
install
and
operate
CO
CEMS.
We
consider
these
to
be
minimal
requirements
that
will
facilitate
good
combustion
practices,
and
will
not
burden
owners
or
operators
of
these
units.
New
liquid
and
solid
fuel
fired
units
will
be
required
to
meet
new
source
emission
limits
based
on
the
results
of
EPA's
MACT
floor
analysis
for
new
units.
Since
these
emission
limits
were
developed
in
accordance
with
the
procedures
outlined
in
section
112(
d),
we
37
must
require
these
sources
to
meet
at
least
the
MACT
floor
level
of
control.
To
minimize
the
burden
on
affected
sources,
we
revised
the
final
rule
to
streamline
the
monitoring
requirements
of
this
NESHAP.

Comment:
One
commenter
(
502)
requested
that
EPA
exempt
boilers
and
process
heaters
at
sugar
beet
facilities
from
the
final
boilers
NESHAP.
The
commenter
stated
that
the
application
of
hydrogen
chloride
and
acetaldehyde
HAP
potential­
to­
emit
analysis
to
seasonal
facilities
greatly
exaggerates
HAP
levels,
categorizing
them
as
major
sources
and
will
result
in
high
costs
with
minimal
environmental
benefit.
The
facilities
cannot
be
moved
or
closed
without
creating
an
economic
disaster
for
sugar
beet
growers.
The
commenter
pointed
out
that
there
are
no
MACT
standards
for
sugar
beet
factories.
The
commenter
pointed
out
that
as
a
seasonal
food
processor,
the
commenter's
facility
generates
small
amounts
of
HAP
as
a
by­
product
of
combustion
or
food
processing,
but
it
makes
no
sense
to
impose
MACT
standards
on
boilers
for
HAP
released
through
vents
or
boilers
that
are
not
regulated
through
a
permit.
Both
hydrogen
chloride
and
acetaldehyde
are
subject
to
no
emission
limits
or
regulatory
requirements.

Response:
The
only
boilers
and
process
heaters
that
will
be
affected
by
this
NESHAP
are
those
that
are
located
at
a
major
source.
If
you
are
a
major
source,
then
your
facility
must
have
a
Title
V
Operating
Permit.
We
are
required
to
regulate
all
boilers
and
process
heaters
located
at
major
sources
according
to
the
provisions
of
section
112
of
the
CAA
and
cannot
exclude
some
sources
due
to
cost.
While
no
MACT
standard
for
sugar
beet
factories
may
exist,
boilers
and
process
heaters
are
a
listed
source
category
under
section
112
and
must
be
regulated
by
a
NESHAP
program
if
they
are
located
at
a
major
source
of
HAP
emissions.

Comment:
One
commenter
(
446)
explained
that
their
facility
burns
poultry
litter
and
requested
that
EPA
not
regulate
those
types
of
units
under
this
MACT
standard
because
they
are
not
"
similar"
types
of
sources
and
should
be
regulated
under
another
category.
The
commenter
further
noted
that
tracking
fuel
suppliers
and
specifying
fuel
content
is
not
workable
for
these
types
of
units.

Response:
We
recognize
the
that
the
commenter
burns
a
unique
fuel.
However,
we
consider
units
burning
poultry
litter
to
be
part
of
the
solid
fuel­
fired
subcategory
and
subject
to
the
requirements
of
the
rule.
We
revised
the
fuel
sampling,
monitoring,
and
recordkeeping
requirements
so
the
final
rule
accommodates
more
sources
that
burn
fuel
from
many
different
suppliers.
We
also
provide
a
compliance
option
that
is
based
on
fuel
analysis.
We
believe
that
these
changes
will
resolve
the
commenter's
concerns
regarding
fuel
monitoring
may
provide
compliance
relief
if
the
fuel
sampling
strategy
for
compliance
demonstration
can
be
used.

Comment:
One
commenter
(
445)
explained
that
some
limited
use
boilers
are
simply
used
for
the
startup
of
larger,
electrical
utility
boilers
and
that
the
cost
of
the
equipment
and
maintaining
the
equipment
needed
to
comply
with
the
requirements
for
new,
limited
use
gaseous
or
liquid
fuel­
fired
boilers
does
not
seem
reasonable.
Therefore,
the
commenter
requested
that
EPA
exempt
gaseous
and
distillate
fuel­
fired
boilers
used
only
for
the
purpose
of
startup
of
electrical
utility
steam
generators.

Response:
We
do
not
provide
a
specific
exemption
for
boilers
used
to
startup
electrical
38
utility
steam
generators.
Existing
gaseous
and
liquid
fuel­
fired
units
do
not
have
any
emission
limits
or
work
practice
standards,
and
at
most
are
required
to
submit
an
initial
notification.
Therefore,
we
do
not
believe
that
there
is
a
compliance
burden
for
units
used
to
startup
larger
electrical
utility
boilers.
For
new
gaseous
fuel­
fired
units,
there
are
no
emission
limits,
and
for
limited­
use
units
and
units
smaller
than
100
MMBtu/
hr
that
have
an
applicable
work
practice
standards,
the
final
rule
requires
only
that
you
conduct
an
annual
emission
test
for
carbon
monoxide.
You
are
not
required
to
install
a
CEMS
for
carbon
monoxide.
Distillate
oil­
fired
units
that
fall
under
the
new
or
new
limited
use
categories
do
have
emission
limits,
but
the
only
requirement
for
demonstrating
compliance
is
to
keep
records
that
you
are
not
burning
any
residual
oil.
For
new
distillate
oil­
fired
units
less
than
100
MMBtu/
hr
and
for
new
limited
use
distillate
oil
fired
units
with
an
applicable
carbon
monoxide
work
practice
standard,
you
are
not
required
to
install
a
CEMS
for
carbon
monoxide.
You
only
have
to
conduct
an
annual
performance
test.
New
units
larger
than
100
MMBtu/
hr
must
install
a
CEMS
for
carbon
monoxide.
Given
the
revisions
since
proposal
that
provide
additional
flexibility
and
reduce
the
compliance
burden
for
many
affected
sources,
we
do
not
believe
that
the
cost
of
compliance
are
significant
for
these
types
of
units.

Comment:
One
commenter
(
382)
requested
that
EPA
treat
units
that
fire
fuels
meeting
the
comparable
fuels
limits
similarly
to
distillate
oil­
fired
units
and
receive
an
exemption
from
the
particulate
matter
and
hydrogen
chloride
emission
limits.
Two
other
commenters
(
485,
492)
suggested
that
EPA
exempt
units
burning
fuels
comparable
to
distillate
oil
under
40
CFR
261.38
(
and
not
residual
oils).
One
commenter
(
485)
argued
that
imposing
the
liquid
non­
fossil
and
residual
oil
requirements
on
comparable
fuels
would
discourage
their
use,
increase
the
use
of
fossil
fuels,
and
increase
the
emissions
of
greenhouse
gases.

Response:
The
EPA
disagrees
with
the
commenters
request.
The
comparable
fuels
requirements
in
40
CFR
261.38
distinguishes
between
materials
that
are
considered
hazardous
solid
waste
and
fuels.
Based
on
the
latest
CISWI
regulations
all
materials
burned
in
boilers
and
process
heaters
are
fuels.
We
believe
it
is
inappropriate
and
unnecessary
to
incorporate
a
comparable
fuels
allowance
for
distillate
oil
in
the
final
rule.
We
would
also
note
that
the
rule
considers
a
fuel
to
be
distillate
oil
if
it
meets
the
ASTM
requirements
for
distillate
oil.

Comment:
Several
commenters
(
406,
407,
408,
501)
requested
that
EPA
exempt
bagasse
fuel
from
the
boilers
NESHAP.
The
commenters
noted
that
bagasse
is
a
clean
fuel
by
nature,
air
dispersion
modeling
demonstrates
no
risk
to
the
public
from
bagasse
combustion,
existing
controls
are
adequate
to
control
emissions
below
the
proposed
standards,
and
the
rule
would
cause
significant
impacts
with
no
benefit
to
the
environment.
The
commenters
provided
emission,
dispersion
modeling,
and
fuel
analysis
data
from
bagasse
fuel­
fired
sources.
Another
commenter
(
446)
argued
that
since
renewable
biomass
sources
only
cycle
mercury,
rather
than
introducing
new
mercury,
these
types
of
sources
should
be
considered
de
minimis
sources
of
mercury
and
not
regulated.

Response:
We
recognize
that
some
biomass
fuels
have
lower
emissions
of
regulated
HAP
than
other
solid
fuels.
However,
we
maintain
that
biomass
should
still
be
regulated
by
this
NESHAP
because
it
emits
some
metals
and
inorganic
HAP.
Therefore,
we
do
not
exempt
biomass
from
this
NESHAP.
In
the
final
rule,
we
provide
an
option
to
demonstrate
compliance
39
with
the
emission
limits
of
this
NESHAP
through
fuel
sampling.
If
the
results
of
your
fuel
sampling
(
in
units
of
pounds
of
pollutant
to
the
heat
content
of
the
fuel
in
MMBtu)
show
regulated
pollutant
levels
less
than
your
applicable
emission
limits,
then
you
are
in
compliance
with
this
NESHAP
and
only
monitor
monthly
fuel
use
and
to
conduct
additional
fuel
sampling
on
that
same
fuel
type
once
every
five
years.
We
provide
this
option
for
sources
that
burn
fuel
that
inherently
have
low
HAP
content
to
minimize
the
compliance
burden.

Comment:
One
commenter
(
500)
stated
that
new
blast
furnace
gas
(
BFG)
fired
units
that
meet
the
definition
of
a
process
heater
should
be
exempt
from
the
400
ppm
CO
standard.
The
commenter
stated
that
the
low
heating
value
to
volume
ratio
of
BFG,
its
moisture
variability,
flame
characteristics,
variances
in
its
generation
rate,
and
Wobbie
index
due
to
normal
blast
furnace
process
adjustments
make
complying
with
this
standard
virtually
impossible.
In
addition,
the
commenter
stated
that
BFG
fired
process
heaters
and
boilers
have
always
been
considered
"
clean"
fuel
units
and
should
therefore
be
exempted
from
the
boilers
NESHAP
unless
EPA
studies
show
otherwise.

Response:
We
recognize
the
unique
properties
of
blast
furnace
gas
having
high
CO
emissions,
agree
that
these
sources
could
not
meet
the
CO
limit,
and
have
determined
that
monitoring
CO
would
not
indicate
that
the
unit
was
operating
under
good
combustion
practices
or
reducing
organic
HAP.
As
a
result,
we
make
units
that
receive
90
percent
or
more
of
their
total
heat
input
from
blast
furnace
gas
not
subject
to
this
rule.

Comment:
Two
commenters
(
358,
423)
contended
that
EPA
should
exempt
small
utility
boilers
less
than
25
megawatts
from
the
rule.
The
commenters
asserted
that
when
the
CAA
established
a
threshold
capacity
for
utility
boilers,
it
intended
to
limit
EPA's
regulation
of
small
utility
boilers,
therefore,
categorically
exempting
them.
The
commenters
expressed
concern
that
EPA
used
this
"
regulatory
limiting"
exclusion
to
include
small
utility
boilers
in
the
proposed
rule.
One
commenter
(
358)
requested
that
EPA
clarify
its
intent
to
regulate
fossil
fuel­
fired
utility
boilers
within
this
regulation
and
EPA
should
address
any
concerns
the
regulated
entities
may
have
over
its
narrow
definition
of
utility
boilers.
The
commenter
supported
a
fossil
fuel­
fired
boilers
NESHAP
that
would
evaluate
the
appropriateness
of
controls,
the
types
of
specific
controls
unique
to
the
utility
industry,
and
the
specific
HAP
of
concern,
as
determined
by
the
Utility
Boiler
MACT
Workgroup.

Response:
The
CAA
requires
us
to
study
HAP
emissions
from
fossil
fuel­
fired
utility
boilers
and
we
are
in
the
process
of
evaluating
these
emissions.
The
results
of
that
study
will
determine
if
utility
boilers
will
be
regulated
under
the
NESHAP
program.
The
CAA
defines
a
utility
boiler
as
"
any
fossil
fuel­
fired
combustion
unit
of
more
than
25
megawatts
that
serves
a
generator
that
produces
electricity
for
sale.
A
unit
that
cogenerates
steam
and
electricity
and
supplies
more
than
one­
third
of
it
potential
electric
output
capacity
and
more
than
25
megawatts
electrical
output
to
any
utility
power
distribution
system
for
sale..."
If
your
boiler
does
not
fall
under
the
above
definition
of
a
utility
boiler
and
your
boiler
is
located
at
a
major
source,
then
you
are
subject
to
this
NESHAP.

Comment:
Several
commenters
(
345,
427,
428)
recommended
regulating
only
solid
fuel­
40
fired
units.
One
commenter
(
345)
stated
that
by
eliminating
all
categories
except
solid
fuel
would
cause
the
emission
reductions
to
be
reduced
by
less
than
1
percent,
while
the
costs
would
be
reduced
by
$
39
million
per
year
(
annualized)
and
$
166
million
capital.

Response:
The
CAA
requires
us
to
regulate
sources
on
the
source
category
list.
The
source
category
list
includes
all
industrial,
commercial
and
institutional
boilers
located
at
major
sources,
not
just
solid
fuel­
fired
units.
Therefore,
we
are
legally
obligated
to
include
liquids
and
gaseous
fuel
fired
units
in
the
boilers
NESHAP.
Additionally,
we
cannot
use
cost
as
a
deciding
factor
in
developing
the
MACT
floor.
Also,
our
MACT
floor
analysis
shows
that
new
liquid
units
should
meet
an
emission
limit
and
all
new
units
should
meet
a
CO
work
practice.
Since
the
MACT
floor
level
of
control
for
existing
gaseous
and
liquid
fuel­
fired
units
was
no
control,
we
make
these
units
not
subject
to
most
of
the
requirements
of
this
NESHAP.
For
units
that
do
not
have
emission
limits
under
this
NESHAP,
we
require
them
to
do
nothing
more
than
submit
a
notification
of
their
existence
(
initial
notification),
and
some
have
no
requirements
at
all.
All
existing
units
less
than
10
MMBtu/
hr
have
no
requirements
at
all
under
this
NESHAP,
and
an
initial
notification
is
the
only
requirement
for
existing
large
and
limited
use
gaseous
and
liquid
fuel­
fired
units
and
for
new
small
gaseous
and
liquid
fuel­
fired
units.
We
believe
that
these
final
requirements
minimize
the
impact
of
the
final
NESHAP
for
thousands
of
non­
solid
fuel­
fired
units.

Comment:
One
commenter
(
416)
suggested
for
combined­
cycle
turbine
power
plants,
the
exemption
in
§
63.7490(
b)(
3)
should
be
clarified
as
to
whether
25
megawatts
applies
only
to
the
steam
generation
portion
of
the
power
plant
or
the
power
plant
as
a
whole.

Response:
As
is
consistent
with
Subpart
Db,
the
25
MW
requirement
refers
only
to
the
steam
generation
portion
of
the
power
plant.

Comment:
Several
commenters
(
360,
377,
382,
491)
supported
EPA's
proposed
list
of
excluded
sources
in
§
63.7490(
b).
Several
commenters
(
337,
360,
402,
410,
418,
431,
437,
475,
479,
489,
490,
503,
504,
505)
requested
specific
exemptions
from
the
boilers
NESHAP
because
they
were
concerned
that
some
equipment
may
become
subject
to
more
than
one
NESHAP.
The
specific
equipment
requested
for
exemptions
included:
process
heaters
at
magnet
wire
facilities
(
Surface
Coating
of
Miscellaneous
Metal
Parts
and
Products
NESHAP);
boilers
and
process
heaters
at
carbon
black
facilities
(
Generic
NESHAP);
boilers
and
process
heaters
associated
with
a
catalytic
cracking,
catalytic
reforming,
or
sulfur
recovery
units
(
Refinery
MACT
II);
asphalt
oxidizers
subject
to
40
CFR
part
63,
subpart
LLLLL;
direct­
fired
cure
ovens,
spray
booth
air
tempering
systems,
and
because
these
are
integral
components
of
any
surface
coating
operation
(
Auto/
Light­
Duty
Truck,
Plastic
Parts,
and
Miscellaneous
Metal
Parts
NESHAP);
units
subject
to
40
CFR
part
63,
subparts
HH
and
HHH;
blast
furnace
stoves;
coke
oven
batteries;
and
annealing
furnaces.
One
commenter
(
524)
expressed
concern
over
EPA's
attempt
to
specifically
list
sources
exempted
from
this
rule
because
they
are
subject
to
another
MACT
standard.
Two
commenters
(
524,
489)
suggested
that
EPA
delete
that
exclusion
list
and
replace
it
with
a
generic
exemption
that
exempts
units
that
are
already,
or
will
be,
subject
to
another
NESHAP.
Another
commenter
(
343)
requested
that
EPA
clarify
the
exclusion
for
boilers
burning
hazardous
waste
in
§
63.7490(
4)
to
help
sources
determine
applicability.
In
addition,
the
commenter
stated
additional
wording
should
be
provided
to
clarify
that
boilers
required
to
have
a
permit
under
40
CFR
part
41
266,
subpart
H,
"
Hazardous
Waste
Burned
in
Boilers
and
Industrial
Furnaces,"
are
excluded
from
this
NESHAP.
One
commenter
(
428)
requested
that
an
exemption
specifically
addressing
press
and
other
related
types
of
dryers
be
included
in
the
rule
under
§
63.7490(
b).
One
commenter
(
346)
requested
that
EPA
specifically
list
combustion
sources
(
e.
g.,
incinerators
and
flares)
that
are
not
subject
to
this
NESHAP
and
those
that
were
listed
in
the
proposal
preamble.
Other
commenters
(
360,
377)
expressed
concern
over
the
language
in
§
63.7490(
b)(
9)
because
they
thought
that
the
term
"
covered
by"
was
ambiguous
and
suggested
more
direct
language
to
ensure
the
exclusion
such
as
"
an
affected
source
under."
Another
commenter
(
369)
requested
that
§
63.7490
be
revised
to
identify
affected
sources
that
are
not
subject
to
any
requirements.

Response:
In
the
final
rule,
we
provide
a
generically
makegeneral
exemption
from
this
rule
for
sources
that
are
specifically
listed
as
an
affected
source
in
another
standard
under
40
CFR
part
63
not
subject
to
this
rule.
In
addition
we
provide
a
specific
list
of
sources
that
are
not
subject
to
this
rule.
We
believe
that
this
should
address
the
commenters'
concern
over
overlapping
applicability.
We
have
also
excluded
boilers
that
are
required
to
have
a
permit
under
section
3005
of
the
Solid
Waste
Disposal
Act
or
40
CFR
part
26663,
subpart
HEEE
(
e.
g.,
"
Hhazardous
Wwaste
Burned
in
Bboilers
and
Industrial
Furnaces)."

Comment:
One
commenter
(
376)
strongly
believes
that
biomass
fired
units
should
not
be
regulated
under
this
MACT
standard.
The
commenter
noted
that
EPA
lacked
adequate
data
for
biomass
sources
in
setting
the
standard
and
that
this
regulation
would
place
significant
economic
burdens
on
biomass
fuel­
fired
sources,
thus
discouraging
biomass
as
a
renewable
energy
source.

Response:
We
disagree
with
the
commenter
and
do
not
exempt
biomass
fuel­
fired
units
from
the
boilers
NESHAP.
We
are
charged
with
regulating
industrial,
commercial,
and
institutional
boilers
and
process
heaters
and
many
industrial
boilers
use
biomass
as
a
fuel.
Consequently,
we
must
regulate
these
units
under
this
rule.
Since
proposal,
we
revised
the
boilers
NESHAP
to
relieve
the
compliance
burden
for
many
sources.
For
example,
we
provide
an
option
to
demonstrate
compliance
with
the
emission
limits
through
fuel
analysis.
If
the
results
of
fuel
analysis
(
in
pounds
of
regulated
pollutant
contained
in
a
fuel
divided
by
the
heat
content
of
the
fuel
in
Btu
per
pound)
show
that
a
fuel
type
meets
the
emission
limit,
then
a
source
would
not
have
to
conduct
performance
testing
and
monitor
pollution
control
device
operation
to
demonstrate
compliance.
We
believe
that
this
compliance
option
will
provide
significant
relief
to
biomass
fuel­
fired
sources.
We
also
disagree
with
the
commenter's
assertion
that
insufficient
data
are
available
to
set
standards
for
these
sources.
A
questionnaire
sent
during
the
ICCR
process
focused
data
gathering
activities
on
non­
fossil
fuel
fired
units.
The
majority
of
these
units
are
biomass
fired.
Additionally,
we
gathered
emission
test
reports
from
biomass
boilers.
In
the
proposed
rule,
we
requested
that
any
further
test
information
be
submitted.
However,
no
additional
test
information
on
biomass
units
was
provided
by
commenters.
We
concluded
that
the
majority,
if
not
all,
the
test
reports
for
biomass
fired
units
that
were
available
were
gathered
for
the
rule.
We
believe
that
we
have
sufficient
information
on
facilities,
capacities,
emissions
and
controls
from
the
questionnaires
and
test
reports
to
develop
standards.

4.3
Lower
size
cutoff
Comment:
Numerous
commenters
(
332,
339,
343,
347,
361,
362,
364,
374,
376,
379,
42
382,
383,
387,
388,
391,
392,
394,
395,
399,
401,
410,
416,
424,
428,
434,
439,
440,
447,
449,
473,
474,
478,
479,
483,
489,
491,
492,
497,
498,
507,
508,
511,
513,
514,
517,
518,
519,
524,
525,
526,
529,
531,
533)
requested
that
EPA
establish
a
lower
size
cutoff
in
the
final
boilers
NESHAP.
Several
commenters
argued
that
the
benefits
from
requiring
smaller
units
to
install
controls
would
be
minimal
given
the
overall
monitoring,
recordkeeping,
and
reporting
burden.
Several
commenters
(
473,
474,
497,
508,
511,
513,
514,
517,
518,
525,
526,
531)
provided
data
showing
a
cost­
benefit
for
a
small
boiler
of
$
250,000
per
ton
of
metallic
HAP
removal.
The
commenters
noted
that
cost
increases
for
smaller
units
because
those
units
must
use
the
same
control
as
much
higher
capacity
units
and
provided
cost
data
for
a
small
unit.
The
commenters
explained
that
EPA
previously
exempted
units
smaller
than
30
MMBtu/
hr
in
the
Industrial
Boilers
NSPS
because
EPA
determined
that
it
would
be
an
unreasonable
cost
burden
for
smaller
units
to
comply
with
the
NSPS.
Several
commenters
(
347,
395,
410,
447,
479,
519)
also
requested
lower
size
cutoffs
to
make
this
regulation
similar
to
others
established
by
EPA
(
e.
g,
NSPS,
NOx
SIP
Call).

Several
commenters
(
388,
394,
449,
492,
498,
524,
533)
noted
recent
court
decisions
in
which
the
court
has
decided
that
a
de
minimis
exemption
is
appropriate
since
the
regulation
of
small
sources
would
"
yield
a
gain
of
trivial
or
no
value"
yet
would
impose
significant
regulatory
burden.
Some
commenters
(
439,
489)
argued
that
many
of
these
smaller
units
are
too
small
to
typically
require
New
Source
Review
permits,
Minor
Source
Registration
or
inclusion
on
Title
V
Permits.

One
commenter
(
507)
explained
that
the
proposed
rule
would
affect
only
those
facilities
that
have
invested
in
more
efficient
water­
tube
boilers
and
that
the
exemption
for
fire­
tube
boilers
puts
owners
of
water­
tube
boilers
at
a
competitive
disadvantage.
The
commenter
also
noted
that
the
practical
effect
of
the
proposed
regulation
would
extend
the
economically
viable
life
of
the
less
efficient
fire­
tube
boilers.
One
commenter
(
478)
noted
that
this
would
significantly
alleviate
the
impact
on
small
businesses
and
focus
the
rule
on
significant
sources
of
HAP.

One
commenter
(
529)
pointed
out
that
smaller
sources
pose
low
risk,
are
easily
identified,
and
may
be
revisited
during
the
residual
risk
analysis
in
8
years.
A
wide
range
of
lower
size
cutoffs
were
suggested,
including:
All
units:
400,000Btu/
hr;
1MMBtu/
hr;
5MMBtu/
hr;
10MMBtu/
hr;
50MMBtu/
hr;
100MMBtu/
hr.
Gas:
15MMBtu/
hr;
100MMBtu/
hr;
250MMBtu/
hr;
330MMBtu/
hr.
Liquid:
10MMBtu/
hr
new
liquid;
60MMBtu/
hr
residual
oil;
90MMBtu/
hr
for
distillate
oil;
100MMBtu/
hr;
30MMBtu/
hr
for
residual
oil;
100
MMBtu/
hr
distillate
oil.
Solid:
100MMBtu/
hr
for
hydrogen
chloride
control
on
solid
fuel­
fired
units;
50
MMBtu/
hr
for
PM,
metals,
mercury,
and
CO
control
on
solid
fuel­
fired
units.
However,
one
commenter
(
448)
said
that
EPA
should
not
develop
de
minimis
exemptions.
The
commenter
noted
that
de
minimis
exemptions
do
not
spare
EPA's
resources
for
use
on
other
purposes
and
are
not
justified
by
reductions
in
industry
burden
or
inconvenience.
The
commenter
noted
that
EPA
did
not
establish
any
administrative
record
justifying
the
de
minimis
exemption.

Response:
We
have
reviewed
the
commenters
arguments
and
all
the
data
provided
in
the
comment
letters.
We
do
not
feel
there
is
justification
for
developing
a
lower
size
cut­
off
or
de
minimis
level.
We
would
also
note
the
designation
of
large
and
small
subcategories
was
not
based
solely
on
size
of
the
unit.
Large
and
small
subcategories
were
developed
because
small
units
less
than
10
MMBtu/
hr
heat
input
typically
use
a
combustor
design
that
is
not
common
in
larger
units.
Large
boilers
generally
use
the
watertube
combustor
design.
The
design
of
the
boiler
or
process
heater
will
influence
the
completeness
of
the
combustion
process
which
will
influence
the
43
formation
of
organic
HAP
emissions.
Additionally,
the
vast
majority
of
small
units
use
natural
gas
as
fuel.
The
EPA
chose
to
develop
large
and
small
subcategories
to
account
for
these
differences
and
their
affect
on
the
type
of
emissions.
The
cut­
off
between
the
large
and
small
subcategories
of
10
MMBtu/
hr
was
based
on
typical
sizes
for
fire
tube
units,
and
also
when
considering
cut­
offs
in
State
and
Federal
rules.
Lastly,
we
would
like
to
note
that
the
final
rule
does
not
impose
any
requirements
for
existing
units
in
any
of
the
small
subcategories.

Comment:
Several
commenters
(
376,
406,
407,
408,
497,
501)
recommended
that
EPA
exempt
boilers
and
process
heaters
from
the
boilers
NESHAP
that
are
not
major
sources
of
HAP
individually
or
are
considered
insignificant
sources
under
approved
Title
V
programs.
One
commenter
(
400)
contended
that
sources
that
are
subject
to
the
proposed
boilers
NESHAP
generally
are
not
major
sources
and
should
not
be
subject
to
the
regulation
as
such.
One
commenter
(
523)
questioned
how
EPA
concluded
that
a
10
MMBtu/
hr
gas­
fired
boiler
would
meet
the
definition
of
a
"
major
source"
of
HAP
under
section
112
such
that
it
warranted
listing
or
regulation
under
section
112.
Two
commenters
(
478,
502)
objected
to
the
fact
that
the
proposed
rule
would
regulate
boilers
and
process
heaters
that
are
not
themselves
a
major
source
of
HAP,
but
which
are
collocated
at
facilities
with
other
HAP
sources.
One
commenter
(
502)
explained
that
HAP
produced
from
other
processes
at
a
facility
will
trigger
the
major
source
definition
and
result
in
MACT
technology
being
imposed
on
boilers
that
do
not
create
the
major
source
applicability.
Several
commenters
(
406,
407,
408,
501)
requested
EPA
clearly
state
that
units
that
are
non­
major
alone,
although
located
at
a
major
source
of
HAP,
are
not
subject
to
the
rule,
other
than
notification
requirements
in
40
CFR
part
63,
subpart
A.
One
commenter
(
478)
requested
that
EPA
establish
a
minimum
threshold
of
2,000
lb/
yr
of
actual
HAP
emissions.
Several
commenters
(
473,
474,
497,
508,
511,
513,
514,
517,
518,
525,
526,
531)
noted
that
other
MACT
standards
(
i.
e.,
Wool
Fiberglass
Manufacturing,
Natural
Gas
Transmission
and
Storage,
Pharmaceutical
Production,
and
Amino/
Phenolic
Resins)
contain
exemptions
for
sources
that
emit
less
than
10
tons
per
year
of
HAP.

Response:
The
CAA
requires
that
standards
be
developed
for
emission
sources
located
at
a
major
source.
A
major
source
is
defined
in
the
CAA
as
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
10
tons
per
year
or
more
of
any
HAP
or
25
tons
per
year
or
more
of
any
combination
of
HAP.
Also,
boilers
and
process
heaters
are
listed
source
section
112
of
the
CAA
that
must
be
regulated
by
a
NESHAP
program.
Therefore,
we
must
develop
standards
for
boilers
and
process
heaters
located
at
any
major
source,
even
if
the
source
is
only
major
because
of
emission
points
not
related
to
boilers
and
process
heaters.
Due
to
these
reasons,
even
if
a
boiler
or
process
heater
is
not
a
major
source
in
an
of
itself,
it
still
must
be
regulated
under
the
boilers
NESHAP.
We
are
also
not
going
to
provide
a
minimum
threshold
of
HAP
emissions
that
would
trigger
applicability.
Since
proposal,
we
have
made
several
changes
that
will
reduce
the
burden
of
this
NESHAP
on
sources
and
have
eliminated
many
requirements
for
gaseous
and
liquid
fuel­
fired
sources.
Therefore,
we
do
not
believe
an
emission
threshold
that
triggers
applicability
is
warranted.

4.4
Major
source
Comment:
One
commenter
(
492)
requested
that
when
an
area
source
becomes
a
major
44
source,
each
boiler
or
process
heater
unit
that
exists
prior
to
the
date
the
area
source
becomes
a
major
source
should
be
required
to
meet
existing
source
MACT
even
if
it
was
constructed
after
January
13,
2003.
The
commenter
explained
that
the
new
source
definition
in
§
63.7490(
c)
defines
new
sources
as
meeting
"...
the
applicability
criteria
at
the
time
you
commenced
construction."
Therefore,
if
an
area
source
contains
boilers
and/
or
process
heaters
becomes
a
major
source
due
to
reasons
not
related
to
the
boilers
and/
or
process
heaters,
then
these
units
do
not
meet
the
applicability
requirements
of
new
sources.
The
commenter
requested
that
EPA
explicitly
explain
this
result
in
the
final
rule,
and
provides
a
recommended
revision
to
§
63.7490(
c)
to
address
this
issue.
The
commenter
also
argued
that
sources
that
become
subject
to
the
boilers
NESHAP
after
the
promulgation
date
due
to
changes
in
their
applicability
status
are
existing
sources
if
they
were
in
existence
prior
to
January
13,
2003
and
should
have
up
to
3
years
to
comply.
The
commenter
noted
as
examples
that
hazardous
waste
combustors
or
commercial
and
industrial
solid
waste
incinerators
could
become
subject
to
the
boilers
NESHAP
if
they
stopped
burning
wastes
and
used
clean
fuels
instead.
The
commenter
requested
that
the
final
NESHAP
clarify
that
these
units,
if
in
existence
prior
to
January
13,
2003,
should
be
considered
"
existing"
sources.

Response:
In
the
final
rule,
§
63.7490(
d)
and
(
e)
state
that
you
have
a
new
or
reconstructed
source
if
you
commence
construction
or
reconstruction
after
January
13,
2003
AND
you
meet
the
applicability
criteria
at
the
time
you
commenced
construction
or
reconstruction.
Furthermore,
§
63.7490(
f)
states
that
a
source
is
existing
if
it
does
not
meet
the
definition
of
new
or
reconstructed.
If
a
boiler
or
process
heater
located
at
an
area
source
commences
construction
or
reconstruction
after
January
13,
2003,
and
that
construction
or
reconstruction
does
not
itself
make
the
area
source
a
major
source,
then
the
boiler
or
process
heater
would
be
considered
an
existing
source
if
the
area
source
later
becomes
a
major
source.
This
is
due
to
the
fact
that
the
boiler
or
process
heater
did
not
meet
the
applicability
criteria
of
this
NESHAP
at
the
time
it
commenced
construction
or
reconstruction
because
it
was
located
at
an
area
source,
and
units
located
at
area
sources
are
not
subject
to
this
NESHAP.
The
final
rule
clarifies
the
requirements
for
area
sources
that
become
major
sources.
In
§
63.7495(
c)(
2)
of
the
final
rule,
an
existing
boiler
or
process
heater
located
at
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP
comply
with
the
subpart
within
3
years
of
the
facility
becoming
a
major
source.

Comment:
Two
commenters
(
396,
410)
requested
clarification
on
the
date
by
which
a
source
must
be
below
the
major
source
potential
to
emit
threshold
in
order
to
not
be
subject
to
the
boilers
NESHAP.
Two
commenters
(
396,
410)
requested
that
EPA
allow
an
affected
source
to
switch
to
area
source
status
by
reducing
its
potential
to
emit
at
any
time
up
until
the
compliance
date,
rather
than
the
promulgation
date,
to
avoid
being
subject
to
the
boilers
NESHAP
and
referenced
previous
EPA
guidance
and
policy
for
this
clarification,
including
a
memorandum
from
John
Seitz
dated
May
16,
1995.
One
commenter
(
396)
explained
that
this
deadline
would
give
small
emitters
time
to
limit
their
potential
emissions
rather
than
comply
with
the
boilers
NESHAP.
The
commenter
added
that
it
would
also
be
appropriate
for
sources
that
are
above
the
major
source
threshold
at
rule
promulgation
to
become
area
sources
if
they
reduce
emissions
or
take
limits
and
requested
that
EPA
provide
guidance
and
specify
any
recordkeeping
and
reporting
requirements
that
would
be
applicable.
Two
commenters
(
391,
392)
expressed
their
belief
that
the
"
once
in,
always
in"
approach
to
the
NESHAP
program
is
contrary
to
the
45
goals
of
pollution
prevention,
emission
minimization,
and
the
Administrative
Procedures
Act.

Response:
We
agree
with
the
commenters
that
basedUnder
EPA's
policy
on
the
John
Seitz
memorandum,
determining
potential­
to­
emit,
if
a
major
source
can
switches
to
an
area
source
any
time
before
the
first
compliance
date,
but
not
the
promulgation
date.
However,
units
located
at
major
sources
at
the
promulgation
date
are
still
of
this
NESHAP,
any
existing
boilers
and
process
heaters
would
not
be
an
affected
source.
The
first
compliance
date
is
the
first
date
that
an
affected
source
must
comply
with
an
emission
limitation
or
other
substantive
requirement
of
the
rule
(
excluding
notifications).
Affected
sources
are
required
to
submit
an
initial
notification
and
any
other
notifications
that
are
required
during
the
period
that
the
source
is
still
major
for
this
rule.
The
policy
affects
new
sources
differently.
After
the
promulgation
date
of
this
rule,
a
boiler
or
process
heater
that
is
constructed
or
reconstructed
at
a
major
source
will
remain
subject
to
this
NESHAP,
even
if
the
facility
becomes
an
area
source
at
a
later
date.
To
avoid
applicability,
the
facility
would
have
to
become
an
area
source
prior
to
start­
up
of
the
new/
reconstructed
boiler
or
process
heater.
A
boiler
or
process
heater
that
is
constructed
or
reconstructed
between
proposal
and
promulgation
of
this
rule
would
need
to
become
an
area
source
prior
to
promulgation
to
avoid
applicability.

Furthermore,
EPA
has
also
proposed
amendments
to
the
General
Provisions
of
part
63
(
see
68
FR
26249)
to
provide
guidance
for
facilities
with
sources
regulated
under
the
NESHAP
program
to
use
pollution
prevention
techniques
to
lower
HAP
emissions
and,
by
meeting
the
guidelines
of
this
proposal,
receive
regulatory
relief
from
applicable
NESHAPs.
This
regulatory
relief
would
come
through
reduced
monitoring,
recordkeeping,
and
reporting
requirements.
These
propose
amendments
would
allow
this
relief
to
take
place
after
the
compliance
date
of
NESHAP.

4.5
Delisting
Comment:
Several
commenters
(
345,
349,
413,
427,
499)
expressed
support
for
delisting
some
subcategories
under
this
NESHAP.
One
commenter
(
413)
supported
delisting
subcategories
based
on
CAA
section
112(
c)(
9)
of
the
CAA
and
viewed
it
as
a
mechanism
to
limit
costs
and
impacts
of
rules
to
those
facilities
that
actually
need
to
be
regulated
to
protect
public
health.
The
commenter
added
that
once
EPA
receives
a
petition
to
delist
a
subcategory,
it
should
evaluate
the
petition
to
determine
if
each
facility
meets
the
criteria
in
section
112(
c).
The
commenter
continued
that
once
EPA
delists
a
subcategory,
it
should
establish
a
procedure
to
evaluate
petitions
from
other
units
that
would
like
to
be
included
in
the
delisted
subcategory.
Another
commenter
(
345)
recommended
that
EPA
establish
automatic
subcategory
delisting
criteria
where
a
facility
that
meets
the
criteria
can
apply
for
automatic
delisting.
The
commenter
stated
that
such
criteria
should
be
based
on
fuel
type
and
usage
as
well
as
control
efficiency,
if
any
were
used.
In
addition,
the
commenter
stated
that
delisting
those
subcategories
for
which
no
reduction
is
predicted
is
the
most
cost
effective
solution,
with
no
impact
on
emissions.
One
commenter
(
427)
contended
that
the
proposed
MACT
should
be
withdrawn
and
boilers
and
process
heaters
delisted
or
the
rule
should
be
limited
in
scope
to
those
sources
where
the
social
benefits
resulting
from
HAP
emission
reductions
can
be
demonstrated
(
e.
g.,
solid
fuel­
fired
units
in
large
urban
areas).
One
commenter
(
499)
stated
that
EPA
should
consider
delisting
small
industrial/
commercial/
institutional
boilers
and
process
heaters
as
a
source
category
under
section
112(
c)(
9)
of
the
CAA
and
40
CFR
part
63,
subpart
C.
The
commenter
stated
that
recent
studies
46
indicate
that
HAP
emissions
from
virtually
all
small
boilers
in
the
U.
S.
represent
a
cancer
risk
of
well
below
1
in
1
million
and
that
the
non­
cancer
risks
are
well
below
levels
EPA
considers
to
protect
public
health
with
an
adequate
margin
of
safety.
In
addition,
the
commenter
stated
there
are
a
number
of
economic
benefits
of
delisting
small
boilers
and
process
heaters
under
the
NESHAP
program.
One
commenter
(
349)
agreed
with
the
concept
of
delisting
subcategories
before
the
MACT
compliance
date
and
explained
that
delisting
after
the
compliance
date
can
be
problematic
when
sources
do
not
comply
with
the
current
rule
in
the
anticipation
that
they
may
be
delisted.
Several
commenters
(
376,
413,
477,
336,
482,
536)
requested
that
EPA
exempt
limited
use
boilers
from
the
NESHAP.
Two
commenters
(
413,
482)
noted
that
it
is
not
cost­
effective
to
control
HAP
emissions
for
these
units,
and
because
these
boilers
emit
low
levels
of
HAP
and
do
not
threaten
air
quality.
The
commenter
referenced
the
utility
air
regulatory
group's
comments
and
cost
analysis.
One
commenter
(
413)
provided
an
analysis
of
the
costs
and
emission
reductions
associated
with
the
complying
with
the
limited
use
standards.

Two
commenters
(
448,
512)
opposed
any
plan
to
delist
subcategories
under
the
boilers
NESHAP.
One
commenter
(
448)
said
that
section
112(
c)(
9)(
B)
does
not
give
EPA
authority
to
delist
subcategories,
including
sources
of
carcinogens,
from
MACT
standards.
The
commenter
noted
that
the
authority
only
applies
to
categories
(
not
subcategories)
when
all
sources
in
the
category
meet
the
standard.
The
commenter
stated
that
EPA
can
not
establish
a
separate
de
minimis
subcategory
to
delist
sources
and
noted
that
section
112(
c)(
9)(
B)
precludes
development
of
de
minimis
exemptions
that
exceed
its
narrow
authority.
Another
commenter
(
512)
cautioned
EPA
from
considering
subcategories
for
the
sole
purpose
of
delisting
them
as
"
low­
risk"
under
the
authority
of
section
112(
c)(
9)(
B).
The
commenter
argued
that
this
approach
is
unlawful.
The
commenter
explained
that
EPA
cannot
subcategorize
to
enable
a
source
category
to
avoid
the
language,
intent,
or
deadlines
of
the
CAA.
To
delist
a
source
category,
EPA
must
first
find
that
no
source
in
the
category
will
emit
such
HAP
at
a
level
that
would
cause
a
one
in
one
million
lifetime
risk
of
cancer.
The
commenter
argued
that
EPA's
proposed
delisting
of
a
subcategory
is
inappropriate
here
because
EPA
has
not
made
such
a
finding
in
this
proposal.

Response:
The
final
rule
does
not
delist
any
subcategories.
We
do
not
consider
it
appropriate
for
this
standard
to
de­
list
any
subcategories.
However,
we
do
recognize
that
some
sources
may
have
very
low
emissions
of
HAP
and
may
pose
a
minimal
health
risk.
Consequently,
we
have
included
in
the
final
rule
an
alternative
that
allows
sources
that
demonstrate
emissions
below
a
health
threshold
for
some
pollutants
to
not
be
subject
to
the
emission
limit
requirements.
Detailed
discussions
of
the
risk
alternative
is
found
in
section
18
of
this
document.
47
5.0
Format
of
the
Standard
Comment:
Two
commenters
(
390,
413)
supported
emission
limits
based
on
heat
input
rather
than
on
unit
output.
One
commenter
(
413)
added
that
output
based
limits
would
become
overly
complex
without
providing
commensurate
health
benefits.
The
commenters
explained
that
limits
based
on
heat
input
would
simplify
many
of
the
complex
details
that
would
have
to
be
addressed
with
an
energy­
output
based
limit.
Commenters
cited
complex
details
such
as
cogeneration
of
steam
where
common
systems
serve
more
than
one
boiler
and
the
complexity
of
the
instrumentation
needed
to
monitor
the
systems.

Response:
We
agree
with
the
commenters
and
have
not
included
output­
based
emission
limits
in
the
final
rule.
Given
the
diversity
of
end
uses
for
the
boilers
and
process
heaters
regulated
by
this
NESHAP,
it
would
be
impossible
to
develop
an
output­
based
standard
that
could
apply.
Furthermore,
we
do
not
have
enough
data
that
show
emission
rates
in
terms
of
unit
output
to
develop
such
a
standard.

Comment:
Several
commenters
supported
percent
reduction
in
combination
with
other
means
of
compliance
such
as
emission
limits,
concentration
limits,
pounds
per
heat
input,
and
pounds
of
emissions
per
energy
output.
One
commenter
(
390)
asserted
that
the
MACT
standard
should
be
flexible
and
should
give
the
option
of
demonstrating
compliance
with
either
a
percent
reduction
or
an
emission
rate
limit.
One
commenter
(
409)
supported
allowing
a
percent
reduction
approach
as
an
alternative
means
of
compliance
because
it
would
provide
additional
flexibility
to
the
standard,
alleviate
concerns
that
one
specific
compliance
measure
is
not
sufficient
to
address
variability,
and
reduce
the
necessity
for
sources
to
demonstrate
compliance
on
a
continuous
basis.
Another
commenter
(
413)
agreed
that
allowing
compliance
with
either
percentage
reduction
or
emission
limits
would
provide
additional
flexibility
to
a
facility,
stating
that
the
option
would
allow
units
an
efficient
way
of
coping
with
the
variability
of
their
fuel
supplies.
Commenter
(
409)
added
that
the
percent
reduction
option
would
be
consistent
with
the
Hazardous
Waste
Combustion
MACT
standards.
Three
commenters
(
376,
445,
446)
requested
that
EPA
provide
emission
limits
as
a
percent
reduction
and
in
pounds
per
heat
input.

Response:
We
do
not
include
a
percent
reduction
option
for
emission
limits
in
the
final
rule.
As
discussed
in
the
preamble
to
the
proposal
(
see
68
FR
1671),
this
decision
was
based
on
the
fact
that
we
did
not
have
sufficient
data
to
determine
the
percent
reduction
of
the
floor
level
of
control.
We
explained
at
proposal
that
we
had
insufficient
data
to
propose
a
percent
reduction
option
and
requested
additional
data
to
evaluate
a
percent
reduction
option.
We
did
not
receive
adequate
data
to
develop
a
percent
reduction
option,
therefore,
we
have
not
included
one
in
the
final
rule.

Comment:
Some
commenters
(
442,
512)
disagreed
with
percent
reduction
as
an
option.
One
commenter
(
442)
believes
that
percent
reduction
based
standards
are
more
difficult
to
comply
with
than
heat­
input
based
standards.
To
demonstrate
compliance,
inlet
and
outlet
concentrations
are
required,
increasing
the
costs
and
difficulty
of
proving
compliance.
The
commenter
(
442)
also
believes
it
would
be
better
to
establish
emission
limits
based
on
the
pounds
of
emissions
per
energy
output,
thus
encouraging
energy
efficiency.
The
commenter
(
512)
noted
48
that
a
percent
reduction
requirement
would
limit
the
flexibility
of
the
rule
by
requiring
the
use
of
a
control
device.
However,
the
commenter
recommended
that
EPA
set
output­
based
emission
limits
to
encourage
and
reward
efficiency.
One
commenter
(
499)
stated
there
is
no
reason
why
the
"
stack
limit"
approach
and
the
"
percent
reduction"
must
be
presented
as
an
"
either­
or"
approach.
The
commenter
stated
that
allowing
an
alternative
means
of
compliance
can
only
improve
the
flexibility
of
the
rule.
One
commenter
(
340)
recommended
outlet
concentration
limits,
rather
than
a
percent
reduction
requirement.
The
commenter
found
this
much
simpler
to
monitor,
keep
records,
report,
and
make
compliance
determinations,
and
was
therefore
cheaper
than
percent
reduction
requirements.

Response:
In
the
final
rule,
we
retained
emission
limits
in
the
pound
per
million
Btu
format.
We
maintain
that
this
the
most
effective
and
least
burdensome
format
for
the
emission
limits
of
this
NESHAP.
As
discussed
in
the
proposal
preamble,
we
did
not
have
enough
data
to
establish
a
percent
reduction
option.
Furthermore,
we
have
also
have
not
implemented
an
output
based
standard
for
the
pollutants
regulated
by
this
NESHAP.
We
believe
that
attempting
to
establish
an
output
based
standard
would
not
be
appropriate
given
the
diverse
nature
of
application
for
the
sources
regulated
by
this
NESHAP.

5.1
Surrogates
(
general)

Comment:
Many
commenters
(
451,
512)
disagreed
with
EPA's
use
of
surrogates
for
HAP.
Two
commenters
(
512,
451)
stated
that
EPA
must
set
emission
standards
for
all
HAP
emitted
by
this
category.
One
commenter
(
451)
claimed
that
the
proposed
standards
are
unlawful
because
EPA
must
establish
standards
for
each
HAP
emitted
from
the
source
category
regulated.
One
commenter
(
512)
explained
that
the
use
of
surrogates
is
acceptable
if
the
surrogates
(
1)
reflect
the
actual
emissions
of
the
represented
pollutants;
(
2)
the
emission
limit
set
for
the
surrogate
is
consistent
with
the
emission
limit
calculated
for
the
represented
pollutants;
and
(
3)
have
substantially
the
same
properties
as
the
represented
pollutants
and
is
controlled
by
the
same
mechanism.
Based
on
these
criteria,
the
commenter
argued
that
EPA's
selection
of
surrogates
is
inadequate.
The
commenter
also
provided
more
technical
discussion
of
specific
pollutant
properties
to
support
their
argument.
The
commenter
requested
that
if
EPA
chooses
to
promulgate
standards
using
the
surrogate
pollutants,
sources
should
be
required
to
measure
all
pollutants
represented
by
the
surrogate.

One
commenter
(
423)
contented
that
the
selection
of
pollutants
and
emission
limits
in
the
proposed
rule
is
inconsistent
with
rules
currently
in
place
for
large
electric
steam
generating
units.
The
commenter
added
that
the
proposed
rule
would
impose
more
restrictions
on
HAP
from
small
utility
boilers
and
more
controls
than
would
be
required
for
larger
units
not
covered
by
the
rule.
The
commenter
stated
that
the
only
HAP
currently
under
consideration
for
emission
limits
on
large
utility
boilers
is
mercury.

Response:
As
discussed
in
the
proposal
preamble,
we
feel
the
use
of
surrogates
for
the
HAP
regulated
is
appropriate.
Because
of
the
large
number
of
HAP
potentially
present,
the
disparity
in
the
quality
and
quantity
of
the
emissions
information
available,
particularly
for
different
fuel
types,
we
chose
to
group
HAP
into
four
categories:
mercury,
non­
mercury
metallic
HAP,
inorganic
HAP,
and
organic
HAP.
In
general,
the
pollutants
within
each
group
have
similar
characteristics
and
can
be
controlled
with
the
same
techniques.
We
then
chose
compounds
that
could
be
used
as
surrogates
for
all
the
compounds
in
each
pollutant
category.
We
have
used
49
surrogates
in
previous
NESHAPs
as
a
technique
to
reduce
the
performance
testing
costs
and
believe
that
the
use
of
surrogates
is
appropriate
in
this
NESHAP.

For
inorganic
HAP,
we
chose
to
use
HCl
as
a
surrogate.
The
emissions
test
information
available
to
us
indicated
that
the
primary
inorganic
HAP
emitted
from
boilers
and
process
heaters
is
HCl.
Much
smaller
amounts
of
hydrogen
fluoride
and
chlorine
are
emitted.
Control
technologies
that
would
reduce
HCl
would
also
control
other
inorganic
HAP.
Additionally,
we
had
limited
emissions
information
for
other
inorganic
HAP.
By
focusing
on
HCl,
we
have
achieved
control
of
the
largest
emitted
and
most
widely
emitted
HAP,
and
control
of
HCl
would
also
constitute
control
of
other
inorganic
HAP.

For
non­
mercury
metallic
HAP,
we
chose
to
use
PM
as
a
surrogate.
Most,
if
not
all,
nonmercury
metallic
HAP
emitted
from
combustion
sources
will
appear
on
the
flue
gas
fly­
ash.
Therefore,
the
same
control
technology
that
would
be
used
to
control
fly­
ash
PM
will
control
non­
mercury
metallic
HAP.
A
review
of
data
in
the
emission
database
for
PM
control
devices
having
both
inlet
and
outlet
emissions
results
shows
control
efficiencies
for
each
non­
mercury
metallic
HAP
similar
to
PM.
Particulate
matter
was
also
chosen
instead
of
a
specific
metallic
HAP
because
all
fuels
do
not
emit
the
same
type
and
amount
of
metallic
HAP,
but
most
generally
emit
PM
that
includes
some
amount
and
combination
of
metallic
HAP.
We
maintain
that
particulate
matter
reflects
the
emissions
of
non­
mercury
metallic
HAP
as
these
compounds
usually
comprise
a
percentage
of
the
emitted
particulate
matter.
Since
the
NESHAP
program
is
a
technology­
based
standard,
the
technologies
that
have
been
developed
and
implemented
to
control
particulate
matter,
also
control
non­
mercury
metallic
HAP.
Furthermore,
since
nonmercury
metallic
HAP
is
a
component
of
particulate
matter,
we
continue
to
believe
that
we
can
use
particulate
matter
as
a
surrogate
for
the
purposes
of
this
rule.

While
we
did
use
PM
as
a
surrogate
for
non­
mercury
metallic
HAP,
we
also
provided
an
alternative
total
selected
metals
emission
limit
based
on
the
sum
of
the
emissions
of
the
eight
most
common
and
largest
emitted
metallic
HAP
compounds
from
boilers
and
process
heaters.
Again,
a
total
selected
metals
number
was
used
instead
of
limits
for
each
individual
metallic
HAP
because
sufficient
information
was
not
available
for
each
metallic
HAP
for
every
fuel
type.
However,
a
total
metals
number
could
be
calculated
for
every
fuel
type.

We
realize
that
mercury
emissions
can
exist
in
different
forms
depending
on
combustion
conditions
and
concentrations
of
other
compounds.
That
is
why
we
have
mercury
as
a
separate
pollutant
category
in
the
final
rule
and
do
not
provide
for
a
surrogate.

For
organic
HAP,
we
chose
to
use
CO
as
a
surrogate
to
represent
the
variety
of
organic
compounds
emitted
from
the
various
fuels
burned.
Both
organic
HAP
and
CO
emissions
are
the
result
of
incomplete
combustion
of
the
fuel.
Because
CO
is
a
good
indicator
of
incomplete
combustion,
there
is
a
direct
correlation
between
CO
emissions
and
minimizing
organic
HAP
emissions.
The
extent
to
which
CO
and
HAP
emissions
are
related
can
also
depend
on
sitespecific
operating
conditions
for
each
boiler
or
process
heater.
This
site­
specific
nature
may
result
in
various
degrees
of
correlation
between
CO
and
organic
HAP
emissions,
but
it
is
proven
that
reductions
in
CO
emissions
result
in
a
reduction
of
organic
HAP
emissions.
The
control
methods
for
both
CO
and
organic
HAP
are
the
same,
i.
e.,
complete
combustion.
This
result
would
not
have
been
different
if
MACT
floor
analyses
were
conducted
for
specific
organic
HAP
or
for
a
surrogate
compound
such
as
CO.
For
boilers
and
process
heaters,
we
have
determined
that
CO
is
a
reasonable
indicator
of
incomplete
combustion.
Also,
we
did
not
set
emission
limits
for
each
50
specific
organic
HAP
because
we
lacked
sufficient
information
for
many
of
the
organic
HAP
for
all
the
fuels
combusted.
We
acknowledge
that
there
are
many
factors
that
affect
the
formation
of
dioxin,
but
we
also
recognize
that
dioxin
can
be
formed
in
both
the
combustion
unit
and
downstream
in
the
associated
PM
control
device.
We
believe
that
minimizing
organic
HAP
emissions
can
limit
the
formation
of
dioxin
in
the
combustion
unit.
We
reviewed
all
the
good
combustion
practice
(
GCP)
information
available
in
the
boiler
population
database
and
determined
that
no
floor
level
of
control
exists,
except
for
limiting
CO
emissions,
such
that
GCP
could
be
incorporated
into
the
standard.
One
control
technique,
controlling
inlet
temperature
to
the
PM
control
device,
that
has
demonstrated
controlling
downstream
formation
of
dioxins
in
other
source
categories
(
e.
g.,
municipal
waste
combustors)
was
analyzed
for
industrial
boilers.
In
all
cases,
no
increase
in
dioxins
emissions
were
indicated
across
the
PM
control
device
even
at
high
inlet
temperatures.
However,
we
requested
comment
on
controls
that
would
achieve
reductions
of
organic
HAP,
including
any
additional
data
that
might
be
available.
The
EPA
did
not
receive
any
additional
supporting
information
or
data.
Additionally,
more
stringent
options
beyond
the
floor
level
of
control
were
evaluated,
but
were
determined
to
be
too
costly
and
emission
reductions
associated
with
the
options
could
not
be
evaluated
because
no
information
was
available
that
indicated
a
relationship
between
the
GCP's
and
emission
reduction
of
organics
(
including
dioxin).

Comment:
Several
commenters
(
479,
364,
387,
399,
479,
536)
supported
EPA's
approach
to
using
surrogates
for
all
emitted
HAP
and
the
four
HAP
categories.
Two
commenters
(
353,
492)
supported
EPA's
proposal
to
use
surrogates
as
a
method
to
determine
compliance
with
this
NESHAP
and
discussed
EPA's
legal
authority
to
regulate
HAP
through
the
use
of
surrogates.
Commenter
(
479)
noted
that
EPA
has
the
authority
to
use
this
approach
as
upheld
in
the
National
Lime
case.
However,
the
commenters
(
364,
399,
387)
noted
that
particulate
matter
will
not
always
be
an
ideal
surrogate
for
metals
given
the
different
levels
of
metals
in
various
fuels
and
agreed
with
EPA
in
providing
an
alternative
metals
limit.
Other
commenters
(
364,
399,
387,
403,
425,
443,
444,
397)
supported
EPA's
inclusion
of
the
total
selected
metals
limit
as
an
alternative
to
the
particulate
matter
limit.
One
(
444)
commenter
believes
that
the
alternative
will
provide
significant
benefit
for
solid
fuel­
fired
units
that
burn
predominantly
wood
or
biomass.
One
commenter
(
376)
supported
EPA's
allowance
for
solid
fuel­
fired
units
to
meet
either
a
particulate
matter
or
total
selected
metals
emission
limit.

Response:
We
agree
with
the
commenters
and
maintain
that
the
use
of
surrogates
is
appropriate
for
this
NESHAP
and
retained
them
in
the
final
rule.
We
also
retained
the
total
selected
metals
alternative
to
the
particulate
matter
surrogate
for
sources
due
to
the
various
levels
of
metals
in
different
fuels.

Comment:
One
commenter
(
381,
451)
stated
that
particulate
matter
is
not
a
valid
surrogate
for
total
metal
HAP
since
it
is
not
a
valid
surrogate
for
volatile
metal
HAP
such
as
cadmium
and
lead.
Also,
the
commenter
said
that
particulate
matter
is
not
a
valid
surrogate
since
factors
other
than
particulate
matter
affect
emissions
of
metal
HAP.
One
commenter
(
381)
noted
that
EPA's
Criteria
Document
indicates
metal
content
of
particulate
matter
can
vary
widely
depending
on
the
type
of
source,
metals
content
of
fuels,
control
technology
used,
and
other
factors.
The
commenter
concluded
that
the
particulate
matter
standard
would
not
reflect
the
51
metal
emission
levels
actually
achieved.
The
commenter
added
that
EPA
may
not
use
a
surrogate
where
it
results
in
regulations
that
do
not
include
standards
for
each
HAP
or
do
not
reflect
the
emission
levels
achieved
by
the
best
performers.
The
commenter
referred
to
the
National
Lime
court
decision.
One
commenter
(
536)
contended
that
setting
a
MACT
standard
for
mercury
is
complicated
because
there
are
three
forms
of
mercury
possible,
and
the
level
of
control
varies
widely
depending
on
the
relative
concentration
of
each
form
and
the
installed
control
equipment,
as
well
as
the
physical
circumstances
at
the
facility.

Response:
In
the
preamble
to
the
proposed
rule,
we
stated
that
we
chose
particulate
matter
as
a
surrogate
for
non­
mercury
metallic
HAP
because
most,
if
not
all,
non­
mercury
metallic
HAP
emitted
from
combustion
sources
will
appear
on
the
flue
gas
fly
ash.
Therefore,
the
same
control
technologies
that
would
be
used
to
control
particulate
matter
would
control
nonmercury
metallic
HAP.
We
acknowledged
that
not
all
metallic
HAP
would
be
represented
by
particulate
matter,
but
maintain
that
most
would.
Therefore,
we
continue
to
use
particulate
matter
as
a
surrogate
for
non­
mercury
metallic
HAP
in
the
final
rule.

We
maintain
that
particulate
matter
reflects
the
emissions
of
non­
mercury
metallic
HAP
as
these
compounds
usually
comprise
a
percentage
of
the
emitted
particulate
matter.
Since
the
NESHAP
program
is
a
technology­
based
standard,
the
technologies
that
have
been
developed
and
implemented
to
control
particulate
matter,
also
control
non­
mercury
metallic
HAP.
Furthermore,
since
non­
mercury
metallic
HAP
is
a
component
of
particulate
matter,
we
continue
to
believe
that
we
can
use
particulate
matter
as
a
surrogate
for
the
purposes
of
this
rule.
We
also
provide
the
option
of
measuring
total
selected
metals,
which
includes
cadmium
and
lead,
instead
of
particulate
matter
when
you
conduct
performance
testing
or
fuel
analyses
to
determine
compliance.
We
include
this
option
because
we
acknowledge
that
the
metals
content
of
fuels
vary
and
some
fuels
may
contain
very
little
metals,
but
sources
burning
these
fuels
would
have
particulate
matter
emissions
higher
than
the
emission
limit
and
would
require
control
to
meet
the
emission
limit.

We
realize
that
mercury
emissions
can
exist
in
different
forms
depending
on
combustion
conditions
and
concentrations
of
other
compounds.
That
is
why
we
have
mercury
as
a
separate
pollutant
category
in
the
final
rule
and
do
not
provide
for
a
surrogate.
Regardless
of
the
form
in
which
mercury
exists
when
it
leaves
the
stack,
you
are
required
to
meet
the
emission
limits
for
mercury.
You
are
free
to
meet
the
mercury
emission
limit
through
the
use
of
add­
on
control
devices
or
through
fuel
switching.

Comment:
One
commenter
(
451)
contended
that
EPA
did
not
explain
why
its
only
choice
is
either
to
set
individual
standards
for
each
metal
HAP
or
to
use
particulate
matter
as
a
surrogate
for
all
of
them.
The
commenter
noted
that
in
previous
rulemakings
EPA
has
grouped
metals
with
similar
characteristics
together.
The
commenter
(
451)
stated
that
one
of
EPA's
rationale
for
using
particulate
matter
as
a
surrogate
for
HAP
metals
is
that
it
would
reduce
costs.
The
commenter
(
451)
contended
that
cost
concerns
do
not
allow
the
EPA
to
use
an
inadequate
surrogate.

Response:
In
the
preamble
to
the
proposed
NESHAP,
we
explained
that
we
chose
to
use
surrogates
to
minimize
the
cost
of
compliance
of
this
rule
due
to
the
many
different
types
of
pollutants
emitted
from
these
sources.
We
separated
the
HAP
emitted
from
boilers
and
process
heaters
based
on
the
physical
and
chemical
characteristics
of
the
pollutant
and
based
on
the
methods
used
to
control
the
different
types
of
pollutants.
For
the
non­
mercury
metallic
HAP
52
group,
we
determined
that
particulate
matter
was
an
appropriate
surrogate
because
most
nonmercury
metallic
HAP
emitted
from
combustion
sources
will
appear
on
the
flue
gas
fly
ash.
Therefore,
the
same
control
techniques
that
would
be
used
to
control
the
fly­
ash
particulate
matter
would
control
non­
mercury
metallic
HAP.
We
cannot
use
cost
as
a
factor
in
setting
the
MACT
floor;
however,
we
are
able
to
consider
cost
in
the
methods
that
we
require
to
demonstrate
compliance
with
this
NESHAP.
We
have
worked
to
minimize
the
compliance
burden
and
costs
in
many
areas
related
to
compliance
activities
of
this
NESHAP
and
maintain
that
those
approached
are
valid.

5.2
Surrogates
(
HCl)

Comment:
Several
commenters
(
338,
521,
535,
484,
522,
370)
disagreed
with
the
use
of
hydrogen
chloride
as
a
surrogate
for
other
inorganic
acid
gases.
Some
commenters
(
338,
521,
535,
484)
claimed
hydrogen
chloride
is
not
a
significant
health
hazard
on
its
own
and
did
not
see
a
reason
to
impose
installation
of
costly
prohibitive
pollution
control
technologies
for
criteria
pollutants,
which
EPA
states
are
only
surrogate
indicators
to
other
inorganic
compounds.
The
commenters
stated
if
EPA
is
concerned
about
other
inorganic
non­
HAP
compounds,
then
these
emissions
should
be
regulated
by
other
means,
not
through
the
use
of
a
program
targeted
at
HAP
emission
reductions.
One
commenter
(
522)
opposed
installation
of
costly
controls
for
hydrogen
chloride
that
are
intended
to
control
inorganic
non­
HAP
compounds.
The
commenter
asserted
that
inorganic
non­
HAP
should
be
regulated
by
other
means
and
not
the
MACT
program.
One
commenter
(
370)
believes
that
sulfur
dioxide
would
be
preferable
as
a
surrogate
for
inorganic
acid
gases
verses
hydrogen
chloride
from
existing
coal­
fired
boilers
already
subject
to
40
CFR
part
60,
subpart
Db.
The
existence
of
sulfur
dioxide
CEMS
would
continuously
document
conformance
with
desired
control
level
without
the
necessity
of
annual
hydrogen
chloride
performance
tests
and
issued
associated
with
variable
fuel
chlorine
contents.

Response:
We
are
required
under
section
112
of
the
CAA
to
regulate
HAP
emissions
from
each
listed
source
category.
Currently,
hydrogen
chloride
is
a
listed
HAP
under
§
112,
therefore,
if
this
HAP
is
emitted
from
boilers
and
process
heaters,
we
must
regulate
its
emissions
from
these
sources.
Our
data
indicate
that
hydrogen
chloride
is
the
inorganic
HAP
that
is
present
in
the
largest
amount
from
boilers
and
process
heaters.
The
data
also
indicate
that
other
inorganic
HAP
compounds
are
emitted
from
boilers
and
process
heaters
in
much
smaller
quantities.
We
determined
that
the
control
technologies
that
are
effective
at
controlling
hydrogen
chloride
are
also
effective
at
controlling
other
inorganic
HAP.
This
is
why
we
regulate
hydrogen
chloride
under
this
NESHAP
and
use
it
as
a
surrogate
for
all
inorganic
HAP
compounds
regulated
by
this
NESHAP.
We
disagree
with
the
commenters'
suggestion
that
hydrogen
chloride
be
regulated
under
another
standard
and
have
kept
hydrogen
chloride
emission
limits
in
the
final
rule.

Comment:
One
commenter
(
370)
assumed
that
§
63.7500(
a)(
2)
of
the
proposed
boilers
NESHAP
would
allow
a
Subpart
Db
source
to
propose
alternative
limits
and
monitoring
parameters
based
on
sulfur
dioxide
as
a
surrogate
for
hydrogen
chloride
and
the
other
inorganic
acid
gases.
Acceptance
of
a
proposed
alternative
program
would
require
approval
by
the
implementing
agency,
that
in
most
cases
would
be
the
State
Air
Pollution
Control
Agency.
The
commenter
expressed
concern
with
State
agencies'
receptiveness
to
alternative
operating
limits
or
monitoring
programs
unless
specification
of
these
alternatives
is
given
from
EPA.
The
commenter
53
requested
that
EPA
identify
the
existing
40
CFR
part
60,
subpart
Db
90
percent
sulfur
dioxide
control
and
CEMS
requirements
as
appropriate
surrogates
for
all
the
inorganic
acids
including
hydrogen
chloride.

Response:
We
do
not
explicitly
state
that
the
sulfur
dioxide
limits
and
CEMS
monitoring
requirements
required
by
subpart
Db
will
qualify
as
an
appropriate
alternative
surrogate
for
inorganic
HAP
regulated
by
this
NESHAP.
We
did
not
study
the
relation
between
sulfur
dioxide
emissions
and
the
HAPs
regulated
by
this
NESHAP.
If
you
want
to
use
sulfur
dioxide
as
a
surrogate
for
hydrogen
chloride
and
inorganic
HAP
and
your
sulfur
dioxide
CEMS
as
a
continuous
compliance
tool,
you
will
need
to
submit
a
petition
to
the
Administrator
for
an
alternative
monitoring
plan
under
§
63.8(
f)
of
subpart
A.
To
be
considered
for
approval,
your
alternative
monitoring
plan
must
meet
the
elements
of
§
63.8(
f)
of
subpart
A
for
demonstrating
compliance
with
the
hydrogen
chloride
emission
limits
and
continuous
compliance
requirements
of
this
NESHAP.

5.3
Surrogates
(
CO)

Comment:
One
commenter
(
345)
agreed
that
using
CO
as
a
surrogate
for
organic
HAP
makes
it
easier
to
monitor
emissions
and
presumably
the
performance
of
the
unit,
but
questioned
whether
there
is
any
data
confirming
a
correlation
between
CO
and
HAP
emissions.
However,
another
commenter
(
451)
stated
that
CO
is
not
a
valid
surrogate
for
dioxins,
since
dioxin
formation
is
a
function
of
several
variables
(
not
just
good
combustion).

Response:
We
chose
CO
as
a
surrogate
for
organic
HAP
because
CO
is
a
good
indicator
of
incomplete
combustion
and
there
is
direct
correlation
between
CO
emissions
and
the
formation
of
organic
HAP
emissions.
The
extent
to
which
CO
and
HAP
emissions
are
related
can
also
depend
on
site­
specific
operating
conditions
for
each
boiler
or
process
heater.
This
site­
specific
nature
may
result
in
various
degrees
of
correlation
between
CO
and
organic
HAP
emissions,
but
it
is
proven
that
reductions
in
CO
emissions
result
in
a
reduction
of
organic
HAP
emissions.
We
agree
with
the
commenter
that
CO
was
also
chosen
as
a
surrogate
for
organic
HAP
due
to
the
readily
available
CO
monitoring
equipment.
CO
can
be
monitored
with
proven
CEMS
or
through
annual
performance
testing
by
EPA
methods.
With
respect
to
dioxin
emissions,
we
agree
that
there
are
many
factors
that
effect
the
formation
of
dioxin
emissions.
However,
the
greater
the
availability
of
hydrocarbon
compounds,
the
higher
the
probability
of
dioxin
formation
if
chlorine
compounds
are
present.
If
more
complete
combustion
in
a
combustion
unit
is
achieved,
the
fewer
hydrocarbon
compounds
exist,
and
the
formation
of
dioxin
should
be
reduced.
We
acknowledge
that
there
are
many
factors
that
affect
the
formation
of
dioxin,
but
we
also
recognize
that
dioxin
can
be
formed
in
both
the
combustion
unit
and
downstream
in
the
associated
PM
control
device.
We
believe
that
minimizing
organic
HAP
emissions
can
limit
the
formation
of
dioxin
in
the
combustion
unit.
We
reviewed
all
the
good
combustion
practice
(
GCP)
information
available
in
the
boiler
population
database
and
determined
that
no
floor
level
of
control
exists,
except
for
limiting
CO
emissions,
such
that
GCP
could
be
incorporated
into
the
standard.
One
control
technique,
controlling
inlet
temperature
to
the
PM
control
device,
that
has
demonstrated
controlling
downstream
formation
of
dioxins
in
other
source
categories
(
e.
g.,
municipal
waste
combustors)
was
analyzed
for
industrial
boilers.
In
all
cases,
no
increase
in
dioxins
emissions
were
indicated
across
the
PM
control
device
even
at
high
inlet
temperatures.
However,
we
requested
comment
on
controls
that
would
achieve
reductions
of
organic
HAP,
including
any
54
additional
data
that
might
be
available.
The
EPA
did
not
receive
any
additional
supporting
information
or
data.
Additionally,
more
stringent
options
beyond
the
floor
level
of
control
were
evaluated,
but
were
determined
to
be
too
costly
and
emission
reductions
associated
with
the
options
could
not
be
evaluated
because
no
information
was
available
that
indicated
a
relationship
between
the
GCP's
and
emission
reduction
of
organics
(
including
dioxin).

5.4
Miscellaneous
Comment:
One
commenter
(
357)
stated
that
acid
gas
emissions
should
not
be
regulated
under
the
boilers
NESHAP.
The
commenter
stated
that
industrial
boilers
are
regulated
under
section
112
of
Title
III
of
the
CAA
and
Congress
regulated
acid
gas
emissions
under
Title
IV
of
the
CAA.
The
commenter
stated
that
at
the
very
least,
small
and
medium
sized
boilers
should
be
excluded
from
the
acid
gas
standards
in
the
rule.

Response:
We
recognize
that
the
term
"
acid
gas"
was
used
frequently
and
inappropriately
in
the
proposal.
The
term
was
not
meant
to
refer
to
acid
gas
emissions
under
Title
IV
of
the
Clean
Air
Act,
such
as
sulfur
dioxide,
but
rather
to
HAP
compounds
that
form
acidic
compounds
in
the
presence
of
water,
such
as
hydrogen
chloride,
hydrogen
bromide,
and
hydrogen
fluoride.
The
final
rule
has
been
revised
to
use
the
more
appropriate
term
"
inorganic
HAP"
rather
than
acid
gas.

Comment:
One
commenter
(
395)
objected
to
the
attempt
to
use
performance
testing
to
establish
case­
by­
case
MACT
standards.
The
commenter
claimed
this
requirement
would
establish
excessively
stringent
limitations
and
improperly
tie
parametric
monitoring
to
compliance
demonstrations.
The
commenter
stated
that
parametric
levels
are
not
direct
dictates
of
a
limited
parameter
necessary
to
maintain
compliance.

Response:
We
do
not
agree
with
the
commenter's
assessment
of
this
NESHAP.
It
is
not
establishing
case­
by­
case
standards.
Compliance
with
this
NESHAP
is
based
on
the
results
of
performance
testing
or
fuel
sampling
and
how
they
compare
with
the
emission
limits
applicable
to
each
source.
During
the
performance
testing
or
fuel
sampling,
operating
limits
are
established.
These
operating
limits
are
operating
parameters
that
sources
typically
monitor.
Once
these
operating
limits
are
established,
they
are
used
to
ensure
that
a
source
is
operating
in
a
manner
similar
to
that
during
the
performance
testing
or
fuel
sampling.
This
approach
to
determining
continuous
compliance
is
consistent
with
previous
NESHAPs
and
other
standards.
We
have
made
several
changes
since
proposal
that
reduce
the
compliance
burden
and
have
changed
the
opacity
based
operating
limit
to
a
fixed
limit,
as
opposed
to
a
limit
based
on
performance
testing.
Furthermore,
we
have
provided
a
10
percent
operating
range
to
operating
limits
established
during
performance
testing
to
address
variability
issues
that
occur
during
normal
operation.
55
6.0
Compliance
Schedule
6.1
General
Comment:
One
commenter
(
400)
requested
that
EPA
allow
existing
units
that
become
subject
to
the
boilers
NESHAP
after
the
compliance
date
be
allowed
3
years
to
achieve
compliance,
because
they
cease
to
burn
hazardous
waste.
The
commenter
added
that
these
sources,
already
in
existence
and
operation,
would
be
faced
with
new
regulatory
requirements
that
could
involve
design,
procurement,
and
installation
of
new
control
equipment,
installation
or
modification
of
data
collection
and
recordkeeping
systems,
and
additional
training.

Response:
We
agree
with
the
commenter
that
if
an
existing
hazardous
waste
boiler
ceases
to
burn
hazardous
waste
they
would
be
allowed
3
years
to
achieve
compliance
with
the
Boiler
NESHAP.
This
situation
is
similar
to
the
case
of
an
existing
area
source
that
becomes
a
major
source.
The
rule
states
that
any
existing
area
source
that
becomes
major
must
be
in
compliance
with
the
final
rule
within
3
years
after
the
facility
becomes
major.

6.2
Compliance
Schedule
for
New
Units
Comment:
Several
commenters
(
347,
427,
500)
expressed
concern
over
the
requirement
for
new
units
to
be
in
compliance
with
the
NESHAP
upon
startup.
Two
commenters
(
347,
427)
explained
that
it
would
be
difficult
for
new
boilers
that
startup
near
the
promulgation
date
of
the
NESHAP
to
know
what
regulatory
requirements
would
apply
since
the
promulgated
rule
could
change
from
the
proposed
rule.
One
commenter
(
500)
stated
that
new
units
commencing
operation
after
January
13,
2003
should
be
given
the
same
time
period
for
compliance
as
existing
units.
The
commenter
stated
that
the
rule
is
not
only
forcing
the
new
units
to
meet
tighter
standards,
but
is
also
requiring
compliance
up
to
3
years
sooner
than
existing
units.
The
commenter
stated
that
any
regulated
unit
starting
operation
after
January
13,
2003
should
be
given
3
years
after
rule
promulgation
to
comply
with
the
provisions
of
the
NESHAP,
similar
to
existing
units.
One
commenter
(
427)
added
that
sources
that
started
up
before
the
final
publication
date
of
the
rule
should
be
treated
as
existing
sources.
Another
commenter
(
347)
suggested
that
the
rule
have
an
effective
date
90
days
after
the
final
boiler
NESHAP
is
published
in
the
Federal
Register.

Response:
We
do
not
believe
any
change
in
the
rule
is
necessary.
The
CAA
directs
us
to
require
sources
that
commenced
construction
after
proposal
to
comply
with
new
source
requirements.
We
are
not
allowed
to
deviate
from
this
requirement.
We
recognize
that
the
initial
compliance,
continuous
compliance,
and
recordkeeping
and
reporting
requirements
have
changed
since
proposal.
However,
we
do
not
consider
the
final
rule
applicability
or
emission
limits
to
be
significantly
different
than
the
proposed
rule.
In
the
final
rule,
§
63.7510(
e)
outlines
an
alternative
compliance
schedule
for
sources
that
commenced
construction
or
reconstruction
between
the
proposal
and
promulgation
date
of
this
rule.
It
states
that
if
you
choose
to
comply
with
the
proposed
NESHAP
upon
startup,
you
have
3
years
to
comply
with
the
final
NESHAP
requirements
for
new
sources.

6.3
Compliance
Schedule
for
Existing
Units
56
Comment:
Several
commenters
(
338,
339,
364,
379,
381,
387,
388,
390,
391,
392,
399,
400,
413,
417,
443,
449,
480,
484,
498,
522,
524,
533)
argued
that
the
proposed
3­
year
compliance
deadline
is
too
short.
Many
commenters
explained
that
the
time
lines
associated
with
permitting,
capital
appropriation,
project
bid,
and
construction
activities
are
significant
and
that
the
3­
year
deadline
would
not
provide
adequate
time
for
the
estimated
3,730
existing
units
at
affected
sources
to
be
retrofitted
as
necessary
to
meet
the
new
MACT
standards.
The
commenters
stated
that
design,
procurement,
installation,
and
shakedown
of
these
projects
will
easily
consume
3
years,
if
not
substantially
more.
Commenters
(
381,
480,
484)
also
added
that
these
thousands
of
facilities
(
including
facilities
subject
to
the
Utility
MACT)
will
be
competing
nationwide
for
limited
resources
and
materials
from
engineering
consultants,
equipment
vendors,
construction
contractors,
financial
institutions,
and
other
critical
suppliers.
These
commenters
worried
that
some
operators
may
be
unable
to
obtain
the
required
equipment
and
assistance
needed
to
retrofit
their
units
within
the
3
years.
Two
commenters
(
480,
522)
contended
that
the
3­
year
compliance
schedule
is
too
short
for
municipalities,
universities,
and
colleges
because
funding
must
go
through
lengthy
appropriations
process
and
must
frequently
be
approved
by
State
and
Local
governments.
One
commenter
(
480)
concluded
that
if
municipal
utilities
are
forced
to
comply
within
3
years,
there
may
be
significant
outages
and
significant
adverse
effects
on
the
supply
and
distribution
of
energy.
One
commenter
(
417)
noted
that
EPA
effectively
requires
that
all
initial
compliance
demonstrations
be
completed
and
the
notification
of
compliance
status
submitted
prior
to
the
date
3
years
after
the
effective
date
of
the
standard.

Several
commenters
(
339,
364,
381,
387,
388,
399,
400,
413,
443
449,
498,
524,
533)
urged
EPA
to
use
its
authority
under
section
112(
i)(
3)(
B)
to
provide
an
additional
1
year
in
the
compliance
schedule.
Another
commenter
(
484)
noted
that
§
63.6(
i)(
1)­(
14)
provides
EPA
with
flexibility
to
grant
compliance
date
extensions
if
additional
time
is
necessary
for
installation
of
controls.
One
commenter
(
381)
asked
for
one
additional
year.
Three
commenters
(
484,
338,
522)
requested
that
EPA
provide
a
minimum
extension
of
an
additional
2
years
(
for
a
total
of
5
years
beyond
promulgation).
Several
commenters
(
342,
359,
480)
requested
that
EPA
allow
5
or
more
years
to
achieve
compliance.
Two
commenters
(
359,
480)
requested
that
the
compliance
schedule
be
no
shorter
than
the
compliance
schedule
for
large
utility
boilers,
which
has
not
been
finalized
at
this
time.

Response:
The
EPA
disagrees
with
the
commenters
that
the
3­
year
compliance
deadline
is
too
short
considering
the
number
of
sources
that
will
be
competing
for
the
resources
and
materials
from
engineering
consultants,
equipment
vendors,
construction
contractors,
financial
institutions,
and
other
critical
suppliers.
The
EPA
recognizes
the
possibility
that
these
same
consultants,
vendors,
etc.,
may
also
be
used
to
comply
with
the
utility
MACT
standard.
However,
we
know
that
many
sources
will
not
need
to
install
controls.
As
a
result,
since
not
everyone
will
need
more
than
3
years
to
actually
install
controls,
the
final
rule
does
not
allow
an
extra
year
for
existing
sources
to
comply
with
the
final
rule.
Section
112(
i)(
3)(
B)
allows
EPA,
on
a
case­
by­
case
basis
to
grant
an
extension
permitting
an
existing
source
up
to
one
additional
year
to
comply
with
standards
if
such
additional
period
is
necessary
for
the
installation
of
controls.
The
EPA
feels
that
this
provision
is
sufficient
for
those
sources
where
the
3­
year
deadline
would
not
provide
adequate
time
to
retrofit
as
necessary
to
comply
with
the
requirements
of
the
standard.

Comment:
One
commenter
(
396)
requested
clarification
on
the
substantive
regulatory
57
requirement
dates
for
each
type
of
boiler
or
process
heater.
The
commenter
interpreted
the
proposal
to
have
no
substantive
regulatory
requirement
for
gas
and
liquid
fired
units,
and
therefore,
3
years
would
be
allowed
from
promulgation
of
the
rule.
The
commenter
interpreted
the
rule
to
also
allow
3
years
for
solid
fuel­
fired
units
to
comply.
The
commenter
requested
that
EPA
specify
the
potential­
to­
emit
timing
issues
on
the
EPA
Web
site
as
soon
as
possible
so
that
sources
can
become
compliant
on
the
date.

Response:
In
the
final
rule,
the
compliance
schedule
is
3
years
after
promulgation
of
the
boilers
NESHAP.
Furthermore,
we
specifically
included
the
minimal
requirements
for
sources
(
e.
g.,
existing
gaseous
and
liquid
fuel­
fired
units)
that
do
not
have
emission
limits
or
work
practice
standards
under
the
boilers
NESHAP.
Since
these
units
do
not
have
any
emission
limits
or
substantive
compliance
requirements,
we
maintain
that
there
is
no
specific
date
for
substantive
regulatory
requirements.

6.4
Performance
Testing
Comment:
Several
commenters
(
339,
343,
353,
374,
379,
382,
388,
400,
449,
478,
479,
491,
492,
498,
524,
533,
417)
disagreed
with
EPA's
requirement
that
existing
affected
sources
must
conduct
performance
tests,
set
operating
limits,
and
conduct
monitoring
equipment
performance
evaluations
by
the
compliance
date,
and
that
EPA
did
not
follow
the
General
Provisions
allowance
for
180
days
after
the
compliance
date
to
conduct
performance
testing.
The
commenters
requested
that
existing
sources
be
allowed
180
days
after
the
compliance
date
to
complete
performance
testing,
set
operating
limits,
and
conduct
monitoring
equipment
performance
evaluations.
Many
commenters
noted
that
the
EPA's
settlement
agreement
on
the
General
Provisions
should
be
honored,
and
questioned
why
EPA
deviated
from
the
General
Provisions
without
any
justification.
Two
commenters
(
353,
492)
explained
that
the
additional
time
is
needed
to
complete
retrofits
and
shakedown
the
new
equipment
and
to
schedule
the
performance
testing.
Furthermore,
two
commenters
(
374,
492)
requested
that
EPA
also
revise
the
proposed
deadlines
for
completing
the
initial
compliance
demonstration
and
submission
of
the
notification
of
compliance
status
to
be
consistent
with
those
of
the
General
Provisions.

Response:
We
revised
the
final
rule
to
be
consistent
with
the
General
Provisions
schedules.
Affected
sources
now
have
180
days
after
the
compliance
date
to
conduct
an
initial
compliance
demonstration.
Furthermore,
the
compliance
date
is
3
years
after
boilers
NESHAP
promulgation.
We
believe
this
gives
existing
sources
enough
time
to
comply
with
the
provisions
of
the
boilers
NESHAP.

6.5
Miscellaneous
Comment:
One
commenter
(
376)
requested
that
EPA
provide
a
variance
option
in
the
final
rule
specific
to
electric
utilities,
that
would
extend
the
compliance
deadline
upon
demonstration
of
good­
faith
efforts
to
meet
the
boilers
NESHAP
requirements
in
instances
where
rule
conditions
would
cause
unacceptable
impacts
to
energy
supply
and
reliability.

Response:
We
disagree
with
the
commenter's
suggestion
and
do
not
provide
a
variance
for
sources
that
may
be
electric
utilities.
In
tThe
final
rule,
we
extend
the
provides
a
compliance
schedule
fromof
3
to
4
years.
We
believe
this
will
allow
sufficient
time
for
sources
to
meet
the
regulatory
requirements.
Furthermore,
the
final
rule
specifically
exempts
electrical
utility
steam
58
generating
units
defined
as:
a
fossil
fuel­
fired
combustion
unit
of
more
than
25
megawatts
that
serves
a
generator
that
produces
electricity
for
sale.
A
unit
that
cogenerates
steam
and
electricity
and
supplies
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
megawatts
electrical
output
to
any
utility
power
distribution
system
for
sale
is
considered
an
electric
utility
steam
generating
unit.
Since
this
is
the
definition
in
section
112
for
electrical
utility
steam
generating
units,
those
units
would
be
covered
by
the
utility
MACT.
We
do
not
believe
that
sources
would
be
subject
to
both
standards
and,
therefore,
do
not
believe
that
a
variance
is
necessary.

Comment:
One
commenter
(
446)
requested
that
EPA
clarify
that
if
a
facility
that
has
undergone
a
section
§
112(
g)
case­
by­
case
MACT
determination,
then
it
would
have
8
years
to
comply
with
the
boilers
NESHAP
after
it
commences
operation.

Response:
In
the
final
rule,
we
do
not
explicitly
state
that
a
source
which
as
undergone
and
has
received
a
final
and
legally
effective
case­
by­
case
MACT
determination
under
section
112(
g)
has
8
years
to
comply
with
the
boilers
NESHAP
after
it
becomes
subject
to
this
NESHAP.
With
regard
to
sources
that
have
received
a
case­
by­
case
MACT
determination,
§
63.44(
b)(
2)
states
that
"
If
no
compliance
date
has
been
established
in
the
promulgated
section
112(
d)
or
112(
h)
standard
or
section
112(
j)
determination,
for
those
sources
that
have
obtained
a
final
and
legally
effective
MACT
determination
under
this
subpart,
then
the
permitting
authority
shall
establish
a
compliance
date
in
the
permit
that
assures
that
the
owner
or
operator
shall
comply
with
the
promulgated
standard
or
determination
as
expeditiously
as
practicable,
but
not
longer
than
8
years
after
such
standard
is
promulgated
or
a
section
112(
j)
determination
is
made."
Since
the
requirements
of
case­
by­
case
MACT
determinations
may
vary,
we
do
not
provide
a
blanket
8­
year
compliance
schedule.
We
retain
the
position
outlined
in
§
63.44(
b)(
2)
that
your
permitting
authority
will
establish
a
compliance
date
that
is
no
longer
than
8
years
after
this
NESHAP
is
promulgated.
59
7.0
SUBCATEGORIZATION
7.1
General
Comment:
Several
commenters
(
364,
381,
382,
387,
388,
393,
399,
406,
407,
408,
413,
444,
445,
447,
449,
452,
492,
498,
499,
501,
519,
523,
524,
530,
533,
536)
supported
EPA's
proposed
subcategories
of
boilers
and
process
heaters
based
on
fuel
state.
One
commenter
(
381)
agreed
that
the
design
and
construction
of
large
and
small
units
involve
further
technological
differences
that
affect
nature,
composition
and
controllability
of
HAP
emissions
and
believed
the
EPA
has
followed
the
section
112
of
the
Clean
Air
Act
(
CAA)
properly.
Many
commenters
(
388,
406,
407,
408,
449,
479,
492,
498,
501,
524,
533)
noted
that
legislative
history,
case
law,
and
section
112
supports
EPA's
proposal
to
distinguish
among
the
units
in
the
source
category.
One
commenter
(
479)
stated
that
EPA
has
the
authority
to
subcategorize
by
fuel
type
and
noted
that
the
emission
control
achieved
by
one
subcategory
should
not
have
an
effect
on
the
MACT
floor
determination
on
any
other
subcategories.

Response:
The
EPA
thanks
the
commenters
for
their
support.

Comment:
Several
commenters
(
413,
482,
499,
536)
requested
that
EPA
increase
the
maximum
annual
capacity
factor
for
limited
use
units.
One
commenter
(
482)
requested
that
EPA
expand
the
limited
use
source
category
from
a
10
percent
annual
capacity
factor
to
a
30
percent
annual
capacity
factor.
Two
commenters
(
413,
536)
requested
EPA
modify
the
subcategory
for
limited
use
boilers
by
increasing
the
maximum
annual
capacity
factor
from
10
to
25
percent.
Another
commenter
(
499)
suggested
that
EPA
expand
the
limited
use
category
maximum
capacity
factor
from
10
to
20
percent.
The
commenter
contended
that
according
to
EPA
numbers,
the
cost
effectiveness
of
the
limited
use
solid
fuel
subcategory
at
a
10
percent
capacity
level
is
$
3,808,592
per
ton
of
HAP
removed.
The
commenter
stated
that
increasing
this
capacity
factor
to
20
percent
would
cut
the
cost
effectiveness
by
about
half
to
$
1,904,250
per
ton
of
HAP
removed.
One
commenter
(
413)
stated
that
some
boilers
operate
at
capacity
factors
greater
than
ten
percent
yet
they
still
function
as
an
emergency,
backup,
or
start
up
boiler.
One
commenter
(
482)
added
that
a
limited
use
unit
should
be
based
on
the
average
capacity
during
the
previous
three
calendar
years
and
noted
that
such
a
change
would
decrease
the
cost
of
control
for
limited
use
boilers
by
one­
third.

Response:
The
EPA
sees
no
justification
for
changing
the
limited
use
capacity
factor.
We
would
note
that
EPA
is
not
allowed
to
consider
cost
when
developing
subcategories
or
the
MACT
floor.
Cost
may
be
factored
when
considering
options
beyond
the
MACT
floor
level
of
control.
The
subcategories
at
proposal
and
in
the
final
rule
are
based
on
differences
in
fuel
states,
combustor
types,
and
use
of
boilers
and
process
heaters.
As
discussed
in
the
proposal
preamble,
the
EPA's
boiler
database
indicates
that
these
infrequently
operated
units
typically
operate
10
percent
of
the
year
or
less.
In
the
proposed
rule,
we
requested
that
commenters
provide
additional
information
to
be
considered
in
developing
the
MACT
floor.
The
EPA
has
not
obtained
any
additional
information
from
commenters
that
could
be
used
to
revise
the
proposal
numbers.

Comment:
Two
commenters
(
448,
512)
stated
that
EPA
does
not
have
the
authority
to
60
develop
subcategories
for
the
purpose
of
reducing
compliance
costs
or
weakening
the
standard.
The
commenters
also
noted
that
costs
should
not
be
considered
in
subcategorizing
and
establishing
the
MACT
floor.
One
commenter
(
512)
explained
that
EPA
has
failed
to
present
a
persuasive
rationale
for
the
establishment
of
new
or
different
subcategories,
such
as
a
wood­
fired
unit
subcategory
and
noted
that
EPA
cannot
subcategorize
based
on
fuel
type,
cost,
level
of
emission
reductions,
control
technology
applicability
or
effectiveness,
achievability
of
emission
reductions,
or
health
risks.
The
commenter
argued
that
EPA
cannot
subcategorize
to
reduce
cost
because
that
would
change
section
112
standards
into
a
cost­
benefit
program,
which
is
not
legally
defensible.
The
commenter
noted
that
the
D.
C.
Circuit
court
recently
held
that,
when
confronted
with
the
cost
argument,
costs
are
not
relevant
when
determining
MACT
floors.

Response:
If
the
commenters
are
referring
to
the
request
for
comment
regarding
further
subcategorizations
than
what
was
proposed,
the
EPA
agrees
that
there
is
no
justification
for
any
further
subcategories.
The
final
rule
maintains
the
subcategories
presented
in
the
proposed
rule.
If
the
commenters
are
referring
to
subcategories
presented
in
the
proposed
rule,
Section
112(
d)(
1)
of
the
CAA
states
"
the
Administrator
may
distinguish
among
classes,
types,
and
sizes
of
sources
within
a
category
or
subcategory"
in
establishing
emission
standards.
Thus,
we
have
discretion
in
determining
appropriate
subcategories
based
on
classes,
types,
and
sizes
of
sources.
We
used
this
discretion
in
developing
subcategories
for
the
industrial,
commercial,
and
institutional
boilers
and
process
heaters
source
category.
Through
subcategorization,
we
are
able
to
define
subsets
of
similar
emission
sources
within
a
source
category
if
differences
in
emissions
characteristics,
processes,
APCD
viability,
or
opportunities
for
pollution
prevention
exist
within
the
source
category.
We
first
subcategorized
boilers
and
process
heaters
based
on
the
physical
state
of
the
fuel
(
solid,
liquid,
or
gaseous),
which
will
affect
the
type
of
pollutants
emitted
and
controls
applicable,
and
the
design
and
operation
of
the
boiler,
which
influences
the
formation
of
organic
HAP
emissions.
We
then
further
subcategorized
boilers
and
process
heaters
based
on
size.
Our
distinctions
are
based
on
technological
differences
in
the
equipment.
For
example,
small
units
are
package
units
typically
having
capacities
less
than
10
million
Btu
per
hour
heat
input
and
use
a
combustor
design
which
is
not
common
in
large
units.
A
review
of
the
information
gathered
on
boilers
also
shows
that
a
number
of
units
operate
as
backup,
emergency,
or
peaking
units
that
operate
infrequently.
The
boiler
database
indicates
that
these
infrequently
operated
units
typically
operate
10
percent
of
the
year
or
less.
These
limited
use
boilers,
when
called
upon
to
operate,
must
respond
without
failure
and
without
lengthy
periods
of
startup.
Since
their
use
and
operation
are
different
compared
to
typical
industrial,
commercial,
and
institutional
boilers,
we
decided
that
such
limited
use
units
should
have
their
own
subcategory.

The
EPA
contends
that
neither
the
subcategories
or
MACT
floor
analysis
was
conducted
considering
costs,
either
in
the
proposed
rule
or
in
the
final
rule.

Comment:
One
commenter
(
529)
questioned
the
basic
subcategorization
of
the
proposed
boilers
NESHAP.
The
commenter
pointed
out
that
co­
firing
multiple
fuels
shows
the
variability
of
emissions
resulting
from
such
an
operational
method.
Co­
firing
allows
a
source
to
practice
"
fuel­
switching"
to
achieve
marginal
compliance
with
the
emission
limit
over
the
6­
month
assessment
period.

Response:
The
EPA
contends
that
the
subcategories
developed
in
the
proposed
rule
and
maintained
in
the
final
rule
are
the
most
appropriate
for
this
source
category.
The
subcategories
61
differentiate
units
by
parameters
that
influence
the
type
of
pollutants
emitted
and
comport
to
the
requirements
of
the
CAA.
The
EPA
recognizes
many
boilers
co­
fire
multiple
fuels,
but
contends
that
general
fuel
subcategories
of
solids,
liquids,
and
gaseous
fuels
are
more
appropriate
than
identifying
a
multitude
of
fuel
specific
subcategories
(
e.
g.,
coal,
wood,
etc).
The
EPA's
interpretation
of
the
CAA
does
not
allow
it
to
subcategorize
units
based
on
the
type
of
fuel
burned.
In
addition,
multiple
fuel
subcategories
would
lead
to
extremely
complicated
analyses
and
compliance
requirements
to
account
for
co­
firing.
Such
subcategories
would
also
require
us
to
develop
more
stringent
compliance
requirements
to
ensure
the
standards
are
being
met
and
would
reduce
the
flexibility
EPA
could
provide
to
comply
with
the
standard.
Also,
EPA
does
not
set
specific
controls
that
can
be
used
to
meet
requirements.
An
owner
or
operator
can
meet
the
emission
limits
using
any
control
technology
or
fuel
switching
available.
The
EPA
considers
it
entirely
appropriate
for
units
to
meet
emission
requirements
by
switching
to
less
polluting
fuels.

Comment:
One
commenter
(
369)
stated
that
the
proposed
boilers
NESHAP
is
unclear
as
to
which
requirements
apply
to
a
dual­
fuel
affected
source
permitted
to
burn
backup
fuel
with
emissions
greater
than
its
primary
fuel.
The
commenter
asks
that
in
the
final
rule,
EPA
clarify
which
requirements
apply
to
a
dual­
fuel
affected
source
when
firing
the
cleaner
burning
of
the
two
fuels.

Response:
The
final
rule,
like
the
proposed
rule,
clearly
defines
which
subcategories
are
applicable
to
each
boiler.
Units
burning
any
amount
of
solid
fuel,
as
the
primary
fuel,
or
co­
fired
fuel,
or
back­
up
fuel,
are
subject
to
the
requirements
of
the
solid
fuel
subcategory.
Units
burning
only
gaseous
fuels
are
subject
to
the
requirements
of
the
gaseous
fuel
subcategory.
For
the
final
rule,
EPA
has
decided
to
allow
sources
in
the
gaseous
fuel
subcategories
that
burn
liquid
fuels
during
periods
of
gas
curtailment
or
gas
supply
emergencies
to
remain
in
the
gaseous
fuel
subcategories
rather
than
liquid
fuel
subcategories.
This
decision
was
made
to
reflect
that
in
some
circumstances
that
are
beyond
the
owners
or
operators
control,
gas
supplies
may
not
be
available.
We
decided
that
for
these
short
periods,
it
could
be
confusing
and
burdensome
for
the
source
and
State
regulators
to
meet
requirements
for
the
liquid
fuel
subcategories
when
they
will
go
back
to
firing
gaseous
fuel
after
the
emergency
is
over.
All
other
units
firing
liquid
fuel
or
liquid
and
gaseous
fuel
are
subject
to
the
requirements
of
the
liquid
fuel
subcategory.

Comment:
Two
commenters
(
490,
523)
suggested
that
voluntary
fuel
switching
be
a
compliance
option
for
existing
sources.
The
commenters
recommended
that
if
the
owner
or
operator
of
a
solid
fuel
unit
switches
to
liquid
and/
or
gaseous
fuel,
it
should
be
allowed
to
elect
the
standard
under
which
the
unit
will
be
regulated.
The
commenters
proposed
two
options:
(
1)
The
unit
will
be
subject
to
the
standard
for
existing
liquid
or
gaseous
fuel
units,
or
(
2)
the
standard
for
existing
solid
fuel
units
will
continue
to
apply.
In
that
context,
the
owner
or
operator
may
elect
to
average
emissions
over
the
solid­
fuel
units
under
a
bubbling
compliance
demonstration
alternative.
The
commenters
stated
that
if
EPA
should
disapprove
of
such
an
election,
the
rule
should
state
that
there
will
be
presumptive
compliance
for
solid
fuel
units
that
switch
to
liquid
or
gaseous
fuels.
In
addition,
the
commenters
stated
that
such
units
that
comply
through
switching
gas
or
oil
should
have
no
applicable
requirements
other
than
recordkeeping
to
demonstrate
that
only
gas
and
oil
burned
in
the
unit
after
the
compliance
deadline
for
the
solidfuel
unit
limits.
Other
commenters
(
374,
523)
requested
that
EPA
clarify
that
if
units
already
62
subject
to
this
standard
as
an
existing
source
change
subcategories
due
to
a
change
in
operation
would
remain
classified
as
an
existing
source.
One
commenter
(
523)
stated
that
existing
units
that
change
fuels
should
be
able
to
comply
with
the
standards
for
existing
units
rather
than
new
units.
The
commenter
stated
that
fuel­
switching
would
enable
more
cost
effective
compliance
with
the
standard,
especially
for
units
switching
to
a
less­
polluting
fuel
like
natural
gas
or
solid
fuels
that
contain
fewer
HAP
metals.
The
commenter
stated
that
the
rule
should
clearly
state
that
fuel
switching
would
not
trigger
entry
into
a
new
subcategory.

Response:
We
reviewed
the
proposal
preamble
and
rule
and
determined
that
further
clarification
of
fuel
switching
requirements
are
needed.
For
the
final
rule,
we
decided
to
allow
sources
that
are
originally
in
one
subcategory
(
based
on
fuel
state)
that
change
the
fuel
burned
to
be
in
another
subcategory
(
i.
e.,
to
voluntarily
fuel
switch)
after
the
effective
date,
to
still
be
subject
to
the
requirements
of
the
original
subcategory
they
were
a
part
of.
For
example,
a
source
that
switches
from
firing
coal
to
gas
after
the
effective
date
of
the
rule
is
still
subject
to
the
solid
fuel
requirements
of
the
regulation
(
e.
g.,
emission
limits,
work
practices,
monitoring,
and
recordkeeping
and
reporting,
etc.).
Because
sources
may
switch
to
different
fuels
(
e.
g.,
when
gas
prices
are
high,
they
may
use
liquid
fuel)
it
would
be
confusing
and
also
a
compliance
concern
to
keep
track
of
and
ensure
that
the
appropriate
standards
are
being
met.
We
believe
that
requiring
sources
to
meet
the
standards
of
the
original
fuel
subcategory
clarifies
compliance
requirements
for
sources
and
allows
regulators
to
ensure
that
sources
are
not
gaming
the
regulation.

Comment:
One
commenter
(
512)
opposed
the
limited
use
subcategory
because
the
resulting
MACT
floor
was
a
"
no
emission
reduction"
determination.
The
commenter
argued
that
this
did
not
meet
the
requirements
of
the
CAA.

Response:
The
EPA
disagrees
with
the
commenter's
assertion,
and
contends
that
the
proposed
and
final
rule
comply
with
the
requirements
of
the
CAA.
As
discussed
in
the
proposal
preamble,
the
decision
to
create
a
separate
subcategory
for
limited
use
units
was
based
on
a
review
that
showed
that
a
number
of
units
operate
as
backup,
emergency,
or
peaking
units
that
operate
infrequently.
These
limited
use
boilers,
when
called
upon
to
operate,
must
respond
without
failure
and
without
lengthy
startup
periods.
The
EPA
continues
to
consider
these
units
as
having
uses
and
operation
that
are
different
compared
to
other
industrial,
commercial,
and
institutional
units.
The
EPA
contends
that
this
differentiation
from
other
boilers
comports
to
the
requirement
for
subcategory
development
in
section
112(
c)
and
(
d).
For
the
liquid
and
gaseous
limited
use
subcategories,
the
resulting
MACT
floor
analysis
did
result
in
a
"
no
emission
reduction"
determination.
However,
EPA
contends
that
this
result
is
no
different
than
the
MACT
floor
determinations
for
the
small
solid,
liquid,
and
gaseous
fuel
subcategories,
which
also
resulted
in
a
"
no
emission
reduction"
determination.
We
also
believe
that
EPA
has
ample
legal
authority
to
set
the
MACT
floor
at
"
no
emissions
reductions".
This
is
because
the
statute
requires
EPA
to
set
standards
that
are
duplicable
by
others.
In
National
Lime,
the
court
threw
out
EPA's
determination
of
a
no
control
floor
because
it
was
based
only
on
a
control
technology
approach.
The
court
stated
that
EPA
must
look
at
what
the
best
performers
achieve,
regardless
of
how
they
achieve
it.
Therefore,
our
determination
that
the
MACT
floor
for
certain
subcategories
or
HAP
is
"
no
emissions
reduction"
is
lawful
because
we
determined
that
the
best­
performing
sources
were
not
achieving
emissions
reduction
through
the
use
of
an
emission
control
system
and
there
were
no
other
appropriate
methods
by
which
boilers
and
process
heaters
could
reduce
HAP
emissions.
Furthermore,
setting
emissions
standards
on
the
basis
of
actual
emissions
data
alone
63
where
facilities
have
no
way
of
controlling
their
HAP
emissions
would
contravene
the
plain
statutory
language
as
well
as
Congressional
intent
that
affected
sources
not
be
forced
to
shut
down.

7.2
Additional
Subcategories
Comment:
Several
commenters
(
358,
373,
378,
398,
413,
416,
417,
421,
422,
423,
429,
435,
469,
470,
471,
472,
480,
481,
506,
509,
528,
536)
requested
that
EPA
establish
a
separate
subcategory
for
municipal
utilities.
Several
commenters
(
358,
413,
416,
417,
423)
suggested
that
this
subcategory
cover
units
less
than
25
megawatts.
The
commenters
noted
that
these
units
face
different
issues
that
industrial
units
and
some
control
equipment
may
not
be
feasible.
One
commenter
(
416)
insisted
that
for
combined­
cycle
turbines
producing
less
that
for
units
with
25
megawatts
of
electrical
power
with
duct
burners,
the
identified
control
equipment
for
the
MACT
floor
for
new
liquid­
fired
units
(
electrostatic
precipitators,
fabric
filters,
and
packed
bed
scrubbers)
may
not
be
feasible.
One
commenter
(
417)
cited
the
following
reasons
for
creating
a
subcategory
for
small
electrical
utility
steam
generating
units:
1)
EPA
has
authority
from
the
CAA
to
establish
such
a
subcategory
of
sources
to
be
regulated
under
section
112
and
is
meant
to
address
control
costs
and
feasibility;
2)
past
EPA
practice
supports
subcategorization
in
this
instance,
3)
differences
between
municipal
utility
boilers
and
non­
utility
boilers
justify
subcategorization,
and
4)
EPA
cannot
properly
account
for
cost
and
energy
concerns
mandated
in
the
MACT
standard
setting
process
without
subcategorization
for
municipal
utility
boilers.
One
commenter
(
358)
suggested
including
three
additional
subcategories
specific
to
the
utility
sector:
(
1)
large
solid
fuel­
fired
utility
boilers
(>
10MMBtu/
hr
heat
input),
(
2)
small
solid
fuel­
fired
utility
boilers
(>
1
MMBtu/
hr
to
<
or
=
10
MMBtu/
hr
of
heat
input,
and
(
3)
other
utility
boilers
burning
liquid
or
gaseous
fuels.
One
commenter
(
423)
suggested
subcategorizing
small
utility
boilers
by
fuel
type,
because
there
are
differences
between
solid
and
liquid/
gaseous
fuels
and
their
combustion
products.
One
commenter
(
480)
stated
that
a
separate
subcategory
for
municipal
utilities
could
effectively
implement
the
purposes
of
UMRA.
The
commenter
added
that
the
unique
physical
attributes
of
municipally­
owned
utilities,
as
well
as
their
significant
and
direct
impact
on
municipal
tax
base
support
a
separate
subcategorization.
The
commenter
also
stated
that
municipally
owned
utilities
are
typically
located
in
physically
constrained
urban
areas
where
installation
of
controls
is
frequently
physically
impossible.

One
commenter
(
536)
supported
developing
a
subcategory
for
small
public
power
systems
to
minimize
losses
of
revenue
to
the
city,
unemployment,
and
higher
electricity
rates.
The
commenter
added
that
this
change
in
combination
with
the
option
to
become
unaffected
based
on
risk
would
mitigate
adverse
economic
burdens
to
local
government.
One
commenter
(
528)
expressed
concern
that
the
proposed
regulation
would
have
a
detrimental
effect
on
the
continued
viability
of
municipal
electric
generation.

Response:
The
EPA
sees
no
technical
or
legal
justification
for
creating
a
separate
subcategory
for
municipal
utilities.
Boilers
at
municipal
utilities
fire
the
same
type
of
fuels,
have
the
same
type
of
combustor
designs,
and
can
use
the
same
type
of
controls
as
other
units
in
the
large
subcategory.
Consequently,
the
subcategories
that
are
in
the
final
rule
are
the
same
as
at
proposal.
We
would
also
like
to
clarify
that
subcategories
were
developed
based
on
combustor
design
and
not
on
industrial
sector.
Also,
had
we
gone
beyond­
the­
floor,
we
would
have
considered
cost
in
the
final
determination.
Since
we
did
not
go
beyond­
the­
floor
level
of
control,
64
cost
did
not
play
a
role
in
the
analysis.

Comment:
One
commenter
(
418)
requested
that
EPA
establish
a
separate
subcategory
for
blast
furnace
gas­
fired
units.
The
commenter
noted
that
this
subcategorization
would
eliminate
the
CO
work
practice
standards
for
those
types
of
sources.

Response:
The
EPA
did
not
establish
a
separate
subcategory
for
blast
furnace
gas­
fired
units
because
there
is
no
justification
for
differentiating
these
units
from
other
gas­
fired
units.
However,
EPA
recognizes
the
unique
properties
of
blast
furnace
gas
having
high
CO
emissions.
The
EPA
agrees
that
these
sources
could
not
meet
the
CO
limit,
and
monitoring
CO
would
not
indicate
that
the
unit
was
operating
under
good
combustion
practices
or
reducing
organic
HAP.
As
a
result,
in
the
final
rule,
EPA
exempts
blast
furnace
gas
fired
units,
as
outlined
in
§
63.7941,
from
the
CO
limit.
However,
the
final
rule
requires
that
these
units
monitor
oxygen
content
to
demonstrate
proper
combustion
operation.

7.3
Size
Threshold
Comment:
Commenters
(
396,
401,
497)
urged
EPA
to
increase
the
size
range
for
small
units.
The
commenters
argued
that
the
current
threshold
between
small
and
large
units
is
too
low
because
the
units
at
the
lower
end
of
the
large
subcategory
emit
low
quantities
of
HAP,
but
would
be
required
to
meet
strict
emission
standards
and
install
CO
monitor
(
for
new
units).
One
commenter
(
401)
noted
that
a
CO
monitor
will
not
reduce
HAP
emissions
so
there
is
no
benefit
that
can
be
assigned.
The
commenter
considered
this
a
waste
of
resources.
The
commenter
pointed
out
that
the
HAP
emission
factors
for
a
100
MMBtu/
hr
uncontrolled
gas
boiler
unit
operating
at
100
percent
capacity
factor
will
emit
total
HAP
emissions
of
0.3
ton
per
year,
which
is
1.2
percent
of
the
major
source
trigger
level
of
25
ton
per
year
for
all
HAP.
One
commenter
(
396)
added
that
a
more
appropriate
limit
would
be
100
MMBtu/
hr.
Another
commenter
(
497)
asserted
that
their
analysis
of
the
EPA
database
indicates
that
a
50
MMBtu/
hr
minimum
applicability
size
for
large
units
encompasses
predominantly
firetube
boilers
and
is
therefore
more
appropriate
than
the
proposed
10
MMBtu/
hr
minimum.

Response:
The
final
rule
clarifies
that
CO
standards
are
work
practices
and
not
emission
limits.
Also,
the
final
rule
does
not
require
CO
CEMS
for
units
less
than
100
MMBtu/
hr,
but
allows
annual
testing
or
monitoring
of
oxygen
levelfor
CO
to
ensure
compliance.
The
EPA
believes
these
clarifications
will
alleviate
some
of
the
commenter's
concerns.
The
designation
of
large
and
small
subcategories
was
not
based
solely
on
size
of
the
unit.
Large
and
small
subcategories
were
developed
because
small
units
less
than
10
MMBtu/
hr
heat
input
typically
use
a
combustor
design
that
is
not
common
in
larger
units.
Large
boilers
generally
use
the
watertube
combustor
design.
The
design
of
the
boiler
or
process
heater
will
influence
the
completeness
of
the
combustion
process
which
will
influence
the
formation
of
organic
HAP
emissions.
Additionally,
the
vast
majority
of
small
units
use
natural
gas
as
fuel.
The
EPA
chose
to
develop
large
and
small
subcategories
to
account
for
these
differences
and
their
affect
on
the
type
of
emissions.
The
cut­
off
between
the
large
and
small
subcategories
of
10
MMBtu/
hr
was
based
on
typical
sizes
for
firetube
units,
and
also
when
considering
cut­
offs
in
State
and
Federal
rules.
Additionally,
EPA's
interpretation
of
the
CAA
does
not
allow
subcategorization
based
on
the
magnitude
of
emissions
or
existing
controls.
Subcategories
can
be
developed
based
on
65
parameters
that
affect
the
type
of
pollutants
emitted
and
applicable
controls.
The
EPA
sees
no
legal
justification
further
changing
the
size
range
designations
for
large
and
small
units.

Comment:
Two
commenters
(
431,
503)
explained
that
units
that
are
rated
at
greater
than
10
MMBtu/
hr
rarely
operate
at
or
above
that
threshold.
The
commenters
noted
that
these
units
would
be
regulated
as
large
units
under
the
proposed
rule,
although
they
exhibit
emission
characteristics
substantially
similar
to
small
units.
The
commenters
suggested
utilizing
the
actual
annual
average
firing
rate
for
the
unit
to
determine
whether
it
is
a
large
or
small
unit.

Response:
The
EPA
disagrees
with
the
commenter's
suggestion.
Although
some
units
rated
at
greater
than
10
MMBtu/
hr
might
operate
their
boiler
at
less
than
capacity,
they
have
the
potential
to
operate
above
the
10
MMBtu/
hr
subcategory
cut­
off.

Comment:
One
commenter
(
357)
contended
that
hours
of
operation
should
not
be
a
factor
in
establishing
the
MACT
floor.

Response:
Hours
of
operation
were
not
considered
in
developing
the
MACT
floor.
The
MACT
floor
was
based
on
the
best­
controlled
sources
in
each
subcategory.
As
discussed
in
the
proposal
preamble,
the
decision
to
create
a
separate
subcategory
for
limited
use
units
was
based
on
a
review
that
showed
that
a
number
of
units
operate
as
backup,
emergency,
or
peaking
units
that
operate
infrequently.
In
order
to
define
the
subcategory
to
include
these
units,
the
EPA
reviewed
the
data
available
to
them.
The
information
available
to
EPA
indicated
these
units
typically
operate
10
percent
of
the
year
or
less.

Comment:
One
commenter
(
345)
recommended
that
the
large
and
small
gas­
fired
subcategory
be
combined
into
a
single
category
or
increase
the
cut­
off
between
them.
In
addition,
the
commenter
stated
that
the
limited­
use
gas­
fired
subcategory
could
be
combined
with
the
small
gas
fired
category.
The
commenter
stated
this
would
not
have
any
impact
on
emissions.

Response:
We
disagree
with
the
commenter's
suggestions.
At
proposal
and
in
the
final
rule,
separate
subcategories
were
developed
for
large
and
small
units
based
on
the
combustor
type.
Separate
subcategories
were
developed
for
limited
use
units
based
on
their
difference
in
use
and
operation.
While
combining
the
gaseous
subcategories
may
not
have
an
impact
on
the
rule
because
none
of
the
existing
gaseous
subcategories
have
emission
limits
or
work
practice
requirements,
we
decided
not
to
combine
them
in
order
to
maintain
consistency
with
the
liquid
and
solid
fuel
subcategories
and
because
of
the
differences
between
small,
large,
and
limited
use
units.

Comment:
One
commenter
(
357)
suggested
that
EPA
add
a
category
for
medium
sized
boilers
between
10
and
100
MMBtu/
hr.
The
commenter
stated
it
is
not
reasonable
to
lump
the
medium
boilers
into
the
large
boiler
category
because
the
CAA
requires
MACT
standards
to
be
evaluated
based
on
similar
sources
in
the
source
category.
In
addition,
the
commenter
stated
that
large
boilers
have
been
legally
mandated
to
have
reduced
emissions
(
i.
e.,
more
stringent
pollution
control
devices)
compared
to
medium
size
boilers.
The
commenter
contented
that
the
two
are
not
similar
sources
even
though
they
are
in
the
same
source
category
(
industrial
boilers).
The
66
commenter
added
that
there
are
differences
in
fuel
handling
systems,
pollution
controls,
and
emissions
monitoring
equipment.
The
commenter
stated
that
based
on
the
CAA,
separate
MACT
standards
must
be
developed
for
medium
sized
industrial
boilers.
The
commenter
(
357)
suggested
that
boiler
subcategories
be
included
in
the
final
rule
based
on
AP­
42
boiler
classifications,
capacity,
and
on
past
practices.
The
commenter
added
that
the
proposed
rule
argues
for
a
"
one
size
fits
all"
large
boiler
category
because
of
equipment
similarity,
yet
on
the
other
hand,
EPA
has
long
held
there
are
emission
differences
for
boilers
depending
on
fuel
type,
firing
configuration,
and
feed
method.

Response:
The
EPA
does
not
see
justification
for
creating
a
separate
subcategory
for
medium
sized
units.
The
designation
of
large
and
small
subcategories
was
not
based
solely
on
size
of
the
unit.
Large
and
small
subcategories
were
developed
because
small
units
less
than
10
MMBtu/
hr
heat
input
typically
use
a
combustor
design
that
is
not
common
in
larger
units.
Large
boilers
generally
use
the
watertube
combustor
design.
The
design
of
the
boiler
or
process
heater
will
influence
the
completeness
of
the
combustion
process
which
will
influence
the
formation
of
organic
HAP
emissions.
The
EPA
chose
to
develop
large
and
small
subcategories
to
account
for
these
differences
and
their
affect
on
the
type
of
emissions.
The
proposed
size
break
between
the
large
and
small
subcategories
of
10
MMBtu/
hr
was
based
on
typical
sizes
for
firetube
and
cast
iron
units
and
considering
cut­
offs
in
State
and
Federal
permitting
requirements
and
rules.
The
EPA
does
not
view
medium
sized
boilers
as
being
different
than
larger
boilers.
Combustor
designs,
applicable
air
pollution
control
devices,
fuels
used,
and
operation
are
similar
for
large
and
medium.
While
actual
pollution
controls
used
and
monitoring
equipment
may
be
different,
the
CAA
does
not
allow
EPA
to
subcategorize
on
these
parameters.

Section
112(
d)(
1)
of
the
CAA
allows
EPA
to
distinguish
among
classes,
types,
and
size
in
establishing
MACT
standards.
As
indicated
above,
at
proposal,
the
size
break
selected
between
large
and
small
units
of
10
MMBtu/
hr
was
based
on
typical
sizes
for
fire
tube
units
and
also
considering
cut­
offs
in
State
and
Federal
permitting
requirements
and
emission
rules.
Based
on
comments,
we
have
examined
information
in
the
docket
regarding
the
population
and
characteristics
of
industrial,
commercial,
and
institutional
boilers.
It
is
correct
that
boilers
below
10
MMBtu/
hr
are
generally
not
required
to
be
permitted
and
are
either
firetube
or
cast
iron
boilers.
Based
on
review
of
the
thousands
of
responses
received
on
a
information
collection
request
(
ICR)
conducted
during
the
rulemaking,
it
is
obvious
and
appropriate
that
the
distinction
between
small
and
large
units
needs
to
include
size.
It
is
apparent
from
the
ICR
responses
that
facilities
know
the
size
of
their
units
but
do
not
generally
know
the
exact
type
of
the
units.
Many
responses
indicated
that
the
boiler
was
both
firetube
and
watertube.
Many
more
responses
did
not
list
the
boiler
type
at
all.
Therefore,
the
inclusion
of
size
in
the
definition
of
small
and
large
subcategories
is
appropriate.

Based
on
review
of
the
1979
EPA
document
on
boiler
population
and
the
information
collection
request
(
ICR)
survey
database,
the
appropriate
size
break
between
small
and
large
type
units
is
10
MMBtu/
hr.
In
the
EPA
document,
99
percent
of
the
boilers
listed
as
being
below
10
MMbtu/
hr
are
either
firetube
or
cast
iron.
Since
these
trends
are
from
a
25
year
old
report,
we
analyzed
our
ICR
survey
database
which
confirmed
these
findings.

Comment:
One
commenter
(
529)
questioned
the
limited
use
subcategory,
pointing
out
that
large
units
operating
only
10
percent
of
the
time
can
produce
hourly
emissions
comparable
to
67
units
operating
all
the
time.
Large
units
that
operated
10
percent
of
firing
capacity
produce
higher
amounts
of
organic
HAP
as
products
of
incomplete
combustion
and
therefore
present
an
even
greater
threat
to
human
health
for
every
MMBtu
of
heat
input.

Response:
The
CAA
does
not
allow
EPA
to
subcategorize
based
on
magnitude
of
emissions
or
prevalence
of
controls
for
one
sector
of
the
population
over
another.
Section
112(
d)(
1)
allows
EPA
to
subcategorize
only
on
the
basis
of
sizes,
types,
and
classes.
The
limited
use
subcategory
was
not
developed
based
on
size
or
magnitude
of
emissions
released.
It
was
developed
to
represent
a
specific
type
of
boiler,
those
used
as
backup,
emergency,
or
peaking
units
that
operate
infrequently.
These
limited
use
boilers,
when
called
upon
to
operate,
must
respond
without
failure
and
without
lengthy
startup
periods.
The
EPA
continues
to
consider
these
units
as
having
uses
and
operation
that
are
different
compared
to
industrial,
commercial,
and
institutional
units.
Consequently,
the
final
rule
contains
a
separate
subcategory
for
them.
We
would
also
note
that
we
could
not
identify
any
control
technologies
that
would
reduce
organic
HAP
emissions.
Therefore,
while
larger
units
may
emit
more
than
smaller
units,
we
have
not
identified
any
appropriate
technology
or
method
that
could
be
used
to
reduce
organic
HAP
emissions.

Comment:
One
commenter
(
484)
suggested
that
EPA
should
establish
large
unit
subcategories
such
that
they
are
similar
to
other
EPA
regulations
(
e.
g.,
NSPS).
Two
commenters
(
490,
523)
stated
that
the
definition
of
large
and
small
units
is
inconsistent
with
EPA's
own
New
Source
Performance
Standard.
The
commenters
stated
that
this
rule
should
be
similarly
divided.
Three
commenters
(
339,
343,
428)
requested
that
EPA
modify
the
subcategories
such
that
larger
units
are
greater
than
100
MMBtu/
hr
and
small
units
are
10
to
100
MMBtu/
hr.
Two
commenters
(
490,
523)
stated
that
the
suggested
approach
would
be
consistent
with
the
mandate
of
section
112(
c)(
1)
which
states
"
To
the
extent
practicable,
the
categories
and
subcategories
listed
under
this
subsection
shall
be
consistent
with
the
list
of
source
categories
established
pursuant
to
section
111
and
Part
C."
One
commenter
(
343)
recommended
that
limited
use
units
be
categorized
as
>
100MMBtu/
hr.
The
commenters
pointed
to
the
Industrial
Boiler
NSPS
(
Subpart
Dc)
for
useful
guidelines
in
establishing
appropriate
thresholds.

Response:
The
designation
of
large
and
small
subcategories
was
not
based
solely
on
size
of
the
unit.
Large
and
small
subcategories
were
developed
because
small
units
less
than
10
MMBtu/
hr
heat
input
typically
use
a
combustor
design
that
is
not
common
in
larger
units.
Large
boilers
are
generally
using
the
watertube
combustor
design.
The
design
of
the
boiler
or
process
heater
will
influence
the
completeness
of
the
combustion
process,
which,
in
turn,
will
influence
the
formation
of
organic
HAP
emissions.
Additionally,
the
vast
majority
of
small
units
use
natural
gas
as
fuel.
The
EPA
chose
to
develop
large
and
small
subcategories
to
account
for
these
differences
and
their
affect
on
the
type
of
emissions.
The
cut­
off
between
the
large
and
small
subcategories
of
10
MMBtu/
hr
was
based
on
typical
sizes
for
firetube
units,
and
also
when
considering
cutoffs
in
State
and
Federal
rules.
Additionally,
EPA's
interpretation
of
the
CAA
does
not
allow
subcategorization
based
on
the
magnitude
of
emissions
or
existing
controls.
Subcategories
can
be
developed
based
on
parameters
that
affect
the
type
of
pollutants
emitted
and
applicable
controls.
The
EPA
sees
no
legal
justification
further
changing
the
size
range
designations
for
large
and
small
units.
68
7.4
Fuels
Comment:
Two
commenters
(
393,
441)
questioned
EPA's
decision
to
include
biomass
in
the
same
subcategory
with
all
solid
fuel­
fired
boilers
and
process
heaters.
The
commenters
argued
that
since
biomass
is
a
renewable
fuel,
and
has
lower
fuel­
related
pollutants,
EPA
risks
discouraging
its
use
by
not
placing
biomass
units
into
a
separate
subcategory.
However,
other
commenters
(
364,
399,
387)
argued
that
EPA
should
not
create
a
separate
subcategory
for
biomass
fuel­
fired
boilers.
The
commenters
explained
that,
in
most
cases,
facilities
have
insufficient
residual
biomass
to
represent
the
sole
boiler
fuel
source
and
this
additional
subcategorization
could
add
substantial
complexity
to
the
rule
since
the
amount
of
biomass
burned
in
a
unit
can
vary.

Response:
The
EPA
disagrees
with
further
subcategorizing
solid
fuel
units.
As
discussed
in
the
proposal
preamble,
solid
fuel­
fired
units
generally
emit
PM,
metals,
and
inorganic
HAP,
and
similar
control
technologies
(
fabric
filters,
ESPs,
scrubbers)
may
be
used
for
all
solid
fuel
units
to
control
these
pollutants.
Additionally,
as
one
commenter
noted,
in
most
boilers
biomass
is
not
the
sole
fuel
burned.
Often
it
is
co­
fired
with
coal,
or
other
solid
fuels.
The
EPA
concluded
that
it
would
be
difficult
to
establish
subcategories
for
specific
fuels
and
even
more
difficult
for
facilities
that
burn
multiple
fuels
in
a
boiler
to
comply
with
such
standards.
To
do
so
would
require
us
to
consider
all
the
possible
fuels
that
may
be
burned
in
boilers
and
process
heaters,
and
all
their
potential
fuel
combinations.

Comment:
Three
commenters
(
390,
393,
438)
suggested
that
EPA
develop
subcategories
for
different
types
of
coals.
The
commenters
stated
that
EPA's
variability
analyses
did
not
adequately
account
for
the
impacts
that
fuel
characteristics
can
have
on
mercury
emissions,
particularly
the
chlorine
content
of
different
coals.
One
commenter
(
438)
explained
that
the
variation
in
pollutant
concentration
across
the
different
coal
types
warrants
further
subcategorization.
One
commenter
(
390)
contended
that
EPA
must
structure
the
boilers
NESHAP
to
refrain
from
forcing
utilities
from
switching
from
one
coal
rank
to
another,
such
as
sub­
bituminous
to
bituminous.
The
commenter
added
that
process
differences
related
to
temperature
can
affect
emission
characteristics,
further
justifying
subcategorization.

One
commenter
(
376)
recommended
that
EPA
reconsider
the
mercury
standard
by
further
subcategorizing
by
fuel
type
and
boiler
design.

Response:
The
EPA
disagrees
with
the
commenters
suggestion
to
further
subcategorize
solid
fuel
units
based
on
the
type
of
coal
burned.
The
EPA
recognizes
the
variation
in
emissions
between
different
coal
types,
as
well
as
difference
within
each
coal
type,
and
differences
between
coal
and
other
solid
fuels.
However,
the
EPA
also
does
not
see
any
justification
for
any
further
subcategorization.
Although
there
may
be
variation
in
the
amount
of
pollutants
emitted,
the
type
of
pollutants
emitted
will
be
similar
between
all
solid
fuel
units
(
particulate
matter,
metallic
HAP,
and
inorganic
HAP).
As
a
result,
similar
control
technologies
may
be
used.
The
EPA
would
like
to
clarify
that
because
of
the
general
nature
of
the
fuel
subcategories
(
solid,
liquid,
gas),
boilers
in
the
solid
fuel
subcategory
can
burn
any
solid
fuel
as
long
as
they
are
able
to
meet
the
emission
limits
for
the
subcategory.
The
EPA
also
considers
that
variability
has
been
incorporated
into
the
MACT
floor
analysis
because
the
emission
limits
developed
for
the
MACT
floor
level
of
control
incorporate
boilers
using
various
fuels,
various
combustor
types,
and
variations
of
the
same
control
device.
69
70
8.0
MACT
FLOOR
Comment:
One
commenter
(
297)
questioned
EPA's
logic
for
stating
that
a
scrubber
is
the
floor
technology
for
hydrogen
chloride
(
HCl)
control
when
this
is
an
older
level
of
technology
that
may
have
particulate
matter
emissions
higher
than
the
floor
level
of
control.

Two
commenters
(
490,
519)
questioned
EPA's
determination
that
the
floor
technology
for
existing
solid
fuel­
fired
units
is
a
fabric
filter
in
combination
with
a
scrubber.
One
commenter
(
490)
stated
that
some
boilers
have
baghouses,
but
many
have
other
types
of
control
equipment.
The
commenter
stated
that
it
appears
that
EPA
has
predetermined
that
baghouses
are
the
only
acceptable
control
system
for
particulate
HAP.
The
commenter
stated
that
this
could
require
facilities
to
rip
out
existing
control
equipment
and
make
a
costly
replacement.
The
commenter
stated
that
if
EPA
had
not
predetermined
the
outcome,
it
is
quite
possible
that
existing
equipment
could
continue
to
be
used
to
meet
emission
levels
based
on
what
facilities
actually
emit.
In
addition,
the
commenter
stated
that
EPA
must
reevaluate
the
floor
determination
for
both
HCl
and
particulate
without
prejudgement
regarding
the
control
devices
that
must
be
installed.
The
commenter
stated
that
EPA
appears
to
have
disregarded
the
emissions
data
collected
for
solid
fuel
units,
and
instead
is
relying
on
certain
control
technology
(
e.
g.,
scrubbers
in
combination
with
baghouses)
as
a
pre­
ordained
floor.
The
commenter
stated
that
very
few
coal­
fired
boilers
in
this
industry
(
or
in
other
industrial
applications
for
that
matter)
have
scrubbers
and
those
that
do
use
wet
scrubbers
for
SO2
control,
not
HCl.
In
addition,
the
commenter
stated
that
wet
scrubbers
use
chemicals
that
are
best
suited
for
SO2
control
and
those
same
chemicals
may
not
be
sufficient
to
control
HCl
to
the
levels
proposed.
One
commenter
(
519)
argued
that
EPA
did
not
properly
establish
the
floor
for
solid
fuel­
fired
units.
The
commenter
explained
that
there
was
no
evidence
that
12
percent
of
the
population
of
solid
fuel­
fired
units
are
equipped
with
both
fabric
filters
and
wet
scrubber
systems.

Response:
The
MACT
floor
analysis
was
conducted
for
each
pollutant
category
separately.
The
final
MACT
floor
for
a
subcategory
would
be
the
combination
of
control
requirements
for
each
pollutant
category.
Therefore,
separate
MACT
floor
analyses
were
done
for
PM
and
HCl.
These
procedures
have
been
followed
in
previous
MACT
standards.
In
the
proposal
and
in
the
final
rule
for
every
subcategory
that
has
an
HCl
limit,
a
PM/
metals
limit
was
also
developed.
The
database
that
EPA
has
assembled
shows
that
at
least
one
source
in
the
applicable
subcategories
has
a
fabric
filter/
scrubber
combination.

The
EPA
would
also
like
to
clarify
that
the
MACT
floor
analysis
is
based
on
the
best
controlled
12
percent
of
sources
in
a
subcategory.
A
detailed
discussion
of
the
MACT
floor
methodology
is
presented
in
the
memorandum
"
MACT
Floor
Analysis
for
New
and
Existing
Sources
in
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
Source
Categories".
EPA's
determination
of
the
most
efficient
control
techniques
for
each
pollutant
category
is
based
on
emission
information
gathered
for
the
boilers
NESHAP,
previous
EPA
studies,
and
information
provided
by
stakeholders
in
the
ICCR
process.
If
the
majority
of
sources
in
the
top
12
percent
use
scrubbers
to
control
inorganic
HAP,
then
scrubbing
will
be
the
floor
technology.
Because
HCl
is
readily
absorbed
into
water
and
caustic,
which
is
the
primary
scrubber
medium
in
sulfur
dioxide
scrubbers,
EPA
does
not
believe
that
any
lower
removal
performance
for
HCl
removal
will
occur.
We
would
also
like
to
clarify
that
the
proposed
rule
and
final
rule
do
not
require
a
specific
control
technology
to
meet
the
standards.
An
owner/
operator
71
can
choose
any
control
technique
as
long
as
they
can
meet
the
emission
limit
requirements
of
the
rule.

Comment:
Several
commenter
(
364,
383,
387,
399)
suggested
EPA
reevaluate
the
feasibility
of
fabric
filters
for
certain
combination
and
solid
fuel­
fired
boilers.
The
commenters
explained
that
the
pulp
and
paper
industry
frequently
employs
boilers
burning
a
combination
of
fuels
that
may
combust
a
variable
mixture
of
fossil,
biomass,
and/
or
residual
fuels.
This
variety
of
fuels
results
in
a
dynamic
combustion
process
with
constantly
varying
combustion
conditions.
The
commenters
explained
that
these
boilers
run
at
higher
excess
air
levels
than
comparable
boilers
firing
only
one
or
two
fuels.
The
higher
excess
air
levels
are
frequently
reflected
in
higher
levels
of
fixed
carbon
in
the
flyash,
which
represents
a
particular
fire
and
explosion
hazard
for
fabric
filters
that
retain
significant
"
cake"
on
the
fabric
surface.
The
commenters
concluded
that
for
this
reason,
fabric
filters
are
generally
regarded
as
technically
infeasible
for
these
types
of
boilers.
The
commenters
noted
that
EPA's
database
shows
few,
if
any,
examples
of
filters
installed
on
boilers
of
this
type,
firing
two
or
more
solid
fuels.

Response:
The
EPA
would
like
to
clarify
that
the
proposed
rule
and
final
rule
do
not
require
a
specific
control
technology
to
meet
the
standards.
An
owner/
operator
can
choose
any
control
technique
as
long
as
they
can
meet
the
emission
limit
requirements
of
the
rule.
The
MACT
floor
analysis
is
based
on
identifying
technologies
that
achieved
the
best
control
of
the
regulated
pollutants
in
the
population
database.
After
the
control
level
used
by
the
best
performing
12
percent
of
sources
in
a
subcategory
was
identified,
the
emissions
database
was
used
to
determine
an
emission
limit
corresponding
to
the
performance
achieved
by
the
MACT
floor
control
technology.
The
final
rule
also
allows
units
to
comply
with
the
standards
by
conducting
a
fuel
analysis
to
demonstrate
that
emissions
of
pollutants
would
be
below
the
emission
limits
in
the
standard.
EPA
contends
that
there
is
sufficient
flexibility
for
owners/
operators
to
comply
with
the
standards.

Comment:
One
commenter
(
340)
requested
that
area
sources
that
have
been
controlled
so
they
are
minor
facilities
(
synthetic
minors)
should
be
included
in
the
database.
The
commenter
stated
that
if
a
facility
applied
controls
to
limit
HAP
emissions
to
below
major
facility
thresholds,
they
have
applied
controls
worthy
of
consideration
as
a
MACT
technology.
The
commenter
agrees
that
area
sources
that
are
naturally
minor
facilities
should
not
be
considered
in
the
database.

Response:
The
EPA
agrees
with
the
commenter
that
facilities
that
apply
controls
to
limit
HAP
emissions
below
major
facility
thresholds
should
be
considered
in
the
MACT
floor
analysis.
However,
EPA's
database
does
not
indicate
which
boilers
would
be
these
synthetic
minors
and
which
would
be
naturally
minor
facilities.
Therefore,
the
commenter's
suggestion,
while
appropriate,
cannot
be
conducted.
The
EPA
would
also
like
to
clarify
that
boilers
assigned
to
area
source
were
identified
initially
by
reviewing
their
SIC
and
SCC
codes,
and
using
best
engineering
judgement.
The
potential
to
emit
HAP
from
each
boiler
assigned
to
the
area
source
category
was
calculated
using
emission
factors
developed
from
EPA's
boiler
emission
test
database
and
the
boiler
heat
input
capacity.
Those
boilers
calculated
to
have
a
potential
to
emit
greater
or
equal
to
the
10
tons
per
year
of
any
HAP/
25
tons
per
year
combined
HAP
(
10/
25)
major
source
definition
were
re­
assigned
to
the
major
source
category.
Control
technologies
72
present
at
each
boiler
were
not
considered
in
the
area
source
determination.

Comment:
Some
commenters
(
357,
358,
361,
362)
objected
to
the
inclusion
of
utility
boilers
in
the
database
used
to
determine
the
MACT
floor.
One
commenter
(
357)
stated
the
large
solid
fuel
subcategory
MACT
floor
determination
is
flawed
because
data
was
used
from
sources
outside
of
the
source
category.
The
commenter
stated
the
CAA
requires
MACT
standards
to
be
based
on
the
best
performing
12
percent
of
existing
sources,
yet
at
68
FR
1675
of
the
proposal
preamble,
EPA
states
that
it
used
data
from
utility
boilers
to
determine
the
mercury
MACT
floor.
In
addition,
the
commenter
stated
if
less
than
12
percent
of
existing
sources
in
the
large
solid
fuel
source
category
do
not
control
mercury
emissions
or
control
levels
are
not
defined,
then
the
MACT
floor
should
be
no
control
for
these
existing
sources.
Two
commenters
(
361,
362)
argued
that
the
mercury
emission
standard
may
be
impossible
for
sources
subject
to
the
boilers
NESHAP
to
meet
because
the
MACT
floor
level
of
control
(
fabric
filters)
may
not
perform
the
same
on
non­
utility
units,
but
the
standard
is
based
on
data
from
utility
units
using
fabric
filters.
One
commenter
(
358)
contended
that
reevaluation
of
MACT
floors
based
on
subcategorizing
utility
boilers
separately
would
result
in
a
MACT
floor
for
the
proposed
HAP
ranging
from
no
control
to
cold­
side
ESPs.
However,
one
commenter
(
340)
requested
utility
boilers
less
than
100
megawatt
not
be
removed
from
the
database
because
the
control
technologies
utilized
by
these
small
utility
boilers
are
readily
adoptable
by
industrial
boilers.

Response:
The
EPA
has
interpreted
the
comments
regarding
using
utility
boiler
information
to
refer
to
the
statements
in
68
FR
1675
"
Based
on
test
information
on
utility
boilers,
we
have
concluded...
Although
EPA
used
information
from
utility
boilers
to
conclude
that
fabric
filters...."
The
EPA
would
like
to
clarify
that
these
statements
refer
to
an
assessment
of
control
technologies
for
reducing
various
HAP
(
see
the
memorandum
"
Control
Technology
Assessment
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters"
for
further
details).
The
EPA
contends
that
it
can
use
any
available
information
from
similar
sources,
such
as
another
combustion
device
using
fabric
filters,
to
assess
the
effectiveness
of
any
control
technology.
The
EPA
also
considers
it
appropriate
because
some
technologies
used
on
boilers
and
process
heaters
were
not
previously
evaluated
for
mercury
control
effectiveness,
while
they
were
in
other
similar
source
categories.

The
MACT
floor
analysis
for
mercury
is
based
on
a
two
step
process.
First,
the
percentage
of
units
with
control
technologies
that
were
identified
that
could
achieve
mercury
emission
reductions
was
determined
using
the
boiler
population
databases.
If
the
control
technology
analysis
indicated
that
at
least
12
percent
of
sources
in
the
subcategory
used
a
control
device
that
could
achieve
mercury
emission
reductions,
then
the
control
technology
present
at
the
median
(
6th
percentile)
was
identified
as
the
MACT
floor
control
technology.
Second,
the
emission
limit
associated
with
the
MACT
floor
control
technology
was
calculated
using
emissions
information
for
units
in
the
subcategory,
or
similar
source.
A
detailed
explanation
of
the
MACT
floor
methodology
is
presented
in
the
memorandum
"
MACT
Floor
Analysis
for
New
and
Existing
Sources
in
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
Source
Categories".
In
neither
the
analysis
of
the
MACT
floor
control
technology,
nor
the
emission
limit
associated
with
the
control
technology,
was
information
from
utility
boilers
used.
The
mercury
and
hydrogen
chloride
fuel
content
of
coal
from
the
utility
industry
was
used
in
developing
the
variability
factors
for
new
solid
fuel­
fired
units.
This
was
done
because
mercury
and
hydrogen
chloride
emissions
are
dependent
on
the
quantity
of
chlorine
or
mercury
in
the
fuel
burned.
Coal
73
available
to
utilities
and
industrial
boilers
and
process
heaters
is
expected
to
be
similar,
and
coal
is
the
solid
fuel
that
is
routinely
used
in
such
units
that
generally
has
the
greatest
degree
of
HAP
variability.

The
EPA
would
also
like
to
note
that
only
fossil
fuel­
fired
steam
generating
units
that
sell
more
than
25
megawatt
to
the
grid
are
considered
utility
boilers
in
the
Clean
Air
Act
(
CAA),
and
are
covered
by
the
utility
boiler
MACT.
All
non­
fossil
fuel
fired
steam
generating
units
and
steam
generating
units
that
sell
less
than
25
megawatt
to
the
grid
are
included
in
this
MACT
standard.
As
such,
information
from
these
sources
can
be
included
in
the
MACT
floor
analysis.
The
commenter
is
referred
to
Appendix
C
of
the
MACT
floor
memorandum
for
a
detailed
list
of
all
emissions
information
used
in
the
analysis.

Comment:
One
commenter
(
529)
expressed
concern
that
test
data
supporting
the
MACT
floor
includes
both
controlled
and
uncontrolled
emissions
from
the
same
sources.
The
commenter
pointed
out
that
the
uncontrolled
test
data
serves
only
to
increase
the
population
of
test
data
to
allow
an
increased
number
of
sources
in
the
top
12
percent
and
lower
the
calculated
MACT
floor.
The
commenter
also
noted
that
a
substantial
number
of
performance
tests
in
the
MACT
floor
database
show
"
zero"
emissions.
The
commenter
believes
this
information
to
be
erroneous,
or
should
be
included
in
the
MACT
floor.
The
commenter
(
529)
pointed
out
that
the
number
of
performance
test
reports
in
the
MACT
floor
database
is
inconsistent
with
the
number
given
in
the
October
2002
MACT
Floor
Analysis.
The
commenter
also
mentioned
that
the
information
referenced
from
the
utility­
related
information
request
is
not
consolidated
with
the
other
boiler/
process
heater
data
so
that
this
information
could
be
reviewed
with
the
other
MACT
floor
database.

Response:
The
EPA
believes
the
commenter
is
mistaken
in
their
assertion.
The
MACT
floor
analysis
is
based
on
a
two
step
process.
First,
the
percentage
of
units
with
control
technologies
that
were
identified
that
could
achieve
emission
reductions
of
each
pollutant
category
was
determined
using
the
boiler
population
databases.
If
the
control
technology
analysis
indicated
that
at
least
12
percent
of
sources
in
the
subcategory
used
a
control
device
that
could
achieve
emission
reductions,
then
the
control
technology
present
at
the
median
(
6th
percentile)
was
identified
as
the
MACT
floor
control
technology.
Second,
the
emission
limit
associated
with
the
MACT
floor
control
technology
was
calculated
using
emissions
information
for
units
in
the
subcategory,
or
similar
source.
The
MACT
floor
emission
limits
were
only
based
on
units
in
the
emissions
database
that
utilized
the
MACT
floor
control
technology.
Uncontrolled
emissions
information
was
not
used
to
calculate
MACT
floor
emission
limits.
Therefore,
the
emissions
data
used
in
the
MACT
floor
emission
limit
analysis
does
not
match
the
total
number
of
emissions
tests
in
the
MACT
floor
emissions
database
because
it
is
only
a
subset
of
that
database.

The
EPA
would
also
like
to
clarify
that
emission
test
information
from
utility
boilers
was
not
used
in
establishing
the
MACT
floor
emission
limits.
The
commenter
is
referred
to
Appendix
C
of
the
MACT
floor
memorandum
for
a
detailed
list
of
all
the
emissions
information
used
in
the
analysis.
Regarding
the
comment
about
zero
emissions
information,
the
EPA
believes
the
commenter
is
referring
to
test
results
where
the
there
are
no
emissions
information
provided
in
the
database.
(
The
emissions
database
does
not
contain
average
emission
factors
with
values
of
0.)
This
result
is
due
to
emissions
being
below
the
detection
limit,
insufficient
numbers
of
test
runs,
or
missing
data
that
would
not
allow
the
use
of
the
emissions
information.
This
information
was
not
74
used
in
the
MACT
floor
emission
level
analysis.

Comment:
One
commenter
(
357)
stated
that
the
MACT
floor
determinations
are
flawed
because
not
all
available
data
were
included.
The
commenter
claimed
that
states
without
an
electronic
database
were
not
included
in
the
MACT
floor
determinations.
In
addition,
the
commenter
stated
that
this
has
the
potential
to
bias
MACT
floor
determinations
toward
States
with
electronic
databases.
The
commenter
believes
that
the
States
with
electronic
databases
could
have
more
stringent
pollution
control
requirements
resulting
in
a
bias
towards
a
certain
pollution
control
technology.

Response:
The
EPA
attempted
to
obtain
the
most
complete
information
available.
In
the
ICCR
process,
EPA
developed
and
submitted
a
questionnaire
for
non­
fossil
fuel
fired
units.
Information
on
fossil
fuel
units
was
obtained
from
AIRS/
OTAQ,
which
is
a
national
database,
and
from
as
many
States
as
possible.
Only
a
few
States
submitted
data.
In
the
preamble
to
the
proposed
rule,
EPA
requested
additional
information.
However,
no
additional
information
on
the
population
of
units
was
provided
in
the
comments.
The
CAA
allows
EPA
to
conduct
analysis
based
on
available
information,
as
was
done
at
proposal
and
in
the
final
rule.
The
EPA
does
not
have
any
information
that
would
lead
to
the
conclusions
that
States
with
electronic
databases
have
more
stringent
standards.
Also,
the
EPA
believes
that
most,
if
not
all
States,
keep
records
electronically.

Comment:
One
commenter
(
530)
supported
EPA's
decision
in
the
boilers
NESHAP
not
to
use
the
"
inherent
and
unavoidable"
variations
in
fuels
in
a
way
that
could
improperly
bias
the
selection
of
the
"
best
controlled"
and
"
best
performing"
sources.
The
commenter
stated
that
the
HAP
content
of
fuels
simply
is
not
a
measure
of
performance
and
therefore
cannot
be
an
indicator
of
the
"
best
controlled"
or
"
best
performing"
sources.

Response:
Wherever
possible,
the
MACT
floor
emission
limits
were
based
on
emission
information.
If
emissions
information
was
not
available
we
looked
at
the
fuel
pollutant
content
as
a
substitute.
For
all
the
solid
fuel
subcategories,
emissions
information
was
available
for
sources
within
the
subcategory
or
from
a
similar
source,
i.
e.,
another
solid
subcategory.
For
the
new
source
liquid
emission
limits,
the
MACT
floor
emission
limit
for
HCl
is
based
on
the
fuel
pollutant
content
because
there
was
no
available
emissions
test
data
for
HCl
from
liquid
fuel­
fired
boilers.
The
EPA
contends
this
approach
is
entirely
appropriate
because
for
some
pollutants,
such
as
HCl
and
metallic
HAP,
emissions
are
related
to
the
amount
of
pollutants
in
the
fuel
and
are
not
affected
by
combustion
mechanisms.

Comment:
Several
commenters
(
338,
388,
447,
449,
484,
498,
519,
521,
524,
530,
533)
requested
that
EPA
account
for
variability
in
fuel
composition
as
MACT
floors
are
established
and
to
provide
adequate
allowances
for
inherent
fuel
supply
variability.
Some
commenters
(
338,
484,
521,
522)
argued
that
there
is
no
flexibility
in
the
rule
to
account
for
this
variability
and
noted
that
coal
composition
can
vary
by
location
and
also
within
an
individual
seam.
One
commenter
(
522)
explained
that
under
the
initial
testing,
coal
with
a
lower
pollutant
content
might
be
used
and
the
source
would
not
have
to
control
emissions,
but
coal
from
the
same
seam
might
yield
higher
pollutant
content
later
and
the
source
might
not
have
sufficient
time
to
install
controls
75
to
meet
the
MACT
compliance
deadline.
The
commenter
added
that
universities
and
colleges
are
also
limited
in
fuel
suppliers
because
procurement
policies
of
public
institutions
prohibit
exclusionary
contracts
with
fuel
vendors.
One
commenter
(
413)
contended
that
the
MACT
floor
analysis
should
incorporate
variability
in
fuel
being
burned,
the
unit's
operating
condition,
and
sampling
and
analytical
errors.
One
commenter
(
410)
contended
that
EPA's
calculation
of
variability
was
statistically
unsound.
The
commenter
recommended
that
EPA
estimate
statistically
the
variance
in
the
distribution
of
control
technology
efficiency
rather
than
calculate
a
variability
factor.
The
commenter
added
that
EPA
could
then
calculate
the
emission
limitation
that
would
yield
an
acceptable
number
of
expected
exceedences
of
the
limitation.

Responses:
As
described
in
the
memorandum
"
Revised
MACT
Floor
Analysis
for
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heater
National
Emission
Standards
for
Hazardous
Air
Pollutants
Based
on
Public
Comments"
in
the
docket,
the
calculation
of
numerical
emission
limits
was
a
two­
step
analysis.
The
first
step
involved
calculating
a
numerical
average
of
the
appropriate
subset
of
emission
test
data.
The
second
step
involved
generating
and
applying
an
appropriate
variability
factor
to
account
for
unavoidable
variations
in
emissions
due
to
uncontrollable
variations
in
fuel
characteristics
and
ordinary
operational
variability.
Accounting
for
variability
is
appropriate
in
order
to
generate
a
more
accurate
estimation
of
the
actual,
long
term,
performance
of
a
source
(
e.
g.,
the
source
occupying
the
median
point
in
the
top
12%).
An
emission
test
provides
a
momentary
snapshot,
not
an
estimation
of
continuous
performance.
In
order
to
translate
the
former
into
the
latter,
we
must
account
for
that
ordinary
and
unavoidable
variability
that
the
source
is
like
to
experience
over
time.
This
give
us
a
more
reasonable
estimate
of
the
actual
level
of
emissions
control
that
the
unit
is
achieving.
The
EPA
contends
that
by
considering
the
variability
of
emissions
information,
we
have
indirectly
incorporated
variability
in
fuel,
operating
conditions,
and
sampling
and
analytical
conditions
because
these
parameters
vary
from
emission
tests
conducted
from
one
unit
to
another,
and
even
within
each
test
set
of
three
measurements
at
a
single
unit.
The
most
elementary
measure
of
variation
is
range.
Range
is
defined
as
the
difference
between
the
largest
and
smallest
values.
This
is
the
variability
methodology
used
in
the
proposed
rule.
That
is,
for
each
unit
with
multiple
emissions
tests
conducted
over
time,
the
variability
was
calculated
by
dividing
the
highest
three­
run
test
result
by
the
lowest
three­
run
test
result.
The
overall
variability
was
calculated
by
averaging
all
the
individual
unit
variability
factors.
This
overall
variability
factor
was
multiplied
by
the
overall
average
emission
level
to
derive
a
MACT
floor
limit
representative
of
the
average
emission
limitation
achieved
by
the
top
12
percent
of
units.
We
believe
that
this
approach
adequately
accounts
for
inherent
fuel
supply
variability.
Based
on
comments,
EPA
did
conduct
a
more
robust
statistical
analysis
(
t­
test)
of
the
mercury
emissions
data
used
in
the
MACT
floor
analysis
to
identify
the
97.5th
percent
confidence
limit.
This
analysis
provided
similar
results
to
the
variability
analysis
conducted
in
the
proposed
rule.
Consequently,
EPA
decided
not
to
change
its
variability
methodology.
A
detailed
discussion
of
the
statistical
analysis
conducted
is
provided
in
the
memorandum
"
Statistical
Analysis
of
Mercury
Test
Data
Variability
in
Response
to
Public
Comments
on
Determination
of
the
MACT
Floor
for
Mercury
Emissions"
in
the
docket.

Comment:
One
commenter
(
529)
pointed
out
that
the
variability
factor
used
to
make
the
calculated
MACT
floor
less
stringent
is
not
allowed
by
section
112
of
the
CAA.
The
commenter
mentioned
that
the
variability
factors
are
not
consistent,
as
one
factor
considers
the
fuel
variability
and
the
other
factor
considers
the
test
data
variability.
76
Response:
Section
112(
d)(
2)
of
the
CAA
requires
that
emissions
standards
promulgated
shall
require
the
maximum
degree
of
reduction
in
emissions
that
the
Administrator,
taking
into
consideration
the
costs
of
achieving
such
emission
reduction,
determines
is
achievable
for
new
and
existing
sources
in
the
subcategory
to
which
such
emission
standards
applies.
Accounting
for
variability
is
appropriate
in
order
to
generate
a
more
accurate
estimation
of
the
actual,
long
term,
performance
of
a
source
(
e.
g.,
the
source
occupying
the
median
point
in
the
top
12%).
An
emission
test
provides
a
momentary
snapshot,
not
an
estimation
of
continuous
performance.
In
order
to
translate
the
former
into
the
latter,
we
must
account
for
that
ordinary
and
unavoidable
variability
that
the
source
is
like
to
experience
over
time.
This
give
us
a
more
reasonable
estimate
of
the
actual
level
of
emissions
control
that
the
unit
is
achieving.
As
such,
due
to
variations
in
fuel
burned,
and
ordinary
operational
variability
any
emission
limit
set
from
a
point
source
measurement
alone
may
not
be
indicative
of
normal
emissions
or
operations
of
the
unit.
Attempting
to
base
a
standard
(
either
a
floor
standard,
or
a
beyond­
the­
floor
standard)
solely
on
point
measurements
would
lead
to
unachievable
standards
for
all
sources.
Limits
set
by
EPA
must
be
achieved
at
all
times,
and
it
is
important
that
the
MACT
floor
limit
adequately
account
for
the
normal
and
unavoidable
variability
in
the
process
and
in
the
operation
of
the
control
device.

Variability
was
assessed
two
ways.
For
existing
subcategories,
variability
in
emissions
information
was
used
to
develop
variability
factors
for
all
subcategories
where
emissions
information
was
available.
Variability
in
fuel
content
was
used
only
in
situations
regarding
determining
the
achievable
MACT
floor
level
for
new
sources
from
the
emission
test
result
on
the
best
controlled
similar
source.
We
believe
this
approach
is
appropriate
since
the
main
uncertainty
associated
with
the
emission
test
result
from
the
best
controlled
similar
source
is
fuel
variability.
Corresponding
fuel
analysis
results
was
not
available
for
the
emissions
test
results
from
the
best
controlled
similar
source.
Whereas,
the
average
emission
level
of
the
best
12
percent
of
the
units
has,
besides
fuel
variability,
the
uncertainty
associated
with
operational
and
design
variability
of
the
various
control
devices
installed
on
units
that
represent
the
best
12
percent
of
the
units.
For
example,
available
fuel
analysis
information
shows
that
mercury
content
of
coal
varies
by
a
factor
of
12.54.
Dividing
the
highest
mercury
emission
test
result
by
the
lowest
mercury
test
results
from
coal­
fired
units
included
in
units
that
represent
the
best
12
percent
results
in
a
variability
factor
of
20.
Therefore,
we
concluded
that
fuel
availability
was
inherently
considered
in
the
MACT
floor
analysis
approach
used
for
existing
subcategories.

Comment:
Several
commenters
(
413,
492,
499,
519)
argued
that
the
database
used
to
establish
the
MACT
floor
for
mercury
from
solid
fuel­
fired
units
is
too
limited.
One
commenter
(
499)
stated
that
the
0.000007
lb
mercury/
MMBtu
limit
for
existing
solid
fuel
boilers
and
process
heaters
is
based
on
emissions
data
from
only
seven
industrial
boilers
and
process
heaters
equipped
with
fabric
filters.
The
commenter
stated
that
according
to
EPA's
Economic
Analysis
of
Air
Pollution
Regulations:
Boilers
and
Process
Heaters,
there
are
approximately
5,600
existing
and
new
units
operating
in
the
U.
S.
today
that
will
be
affected
by
this
rule.
The
commenter
stated
that
seven
out
of
5,600
is
an
inadequate
sample
to
represent
the
universe
of
small
boilers/
process
heaters
in
the
United
States.
In
addition,
the
commenter
stated
that
given
the
cost
that
this
rule
will
have
on
the
U.
S.
economy,
EPA
must
collect
more
information
before
proceeding
with
this
rulemaking.
One
commenter
(
413)
stated
that
EPA's
new
source
MACT
floor
for
mercury
and
HCl
would
be
improved
by
using
a
more
robust
coal
database.
The
commenter
suggested
using
the
Part
II
of
the
utility
ICR
of
coal­
fired
electric
utility
steam
generating
units
to
obtain
additional
77
mercury
fuel
information.
One
commenter
(
492)
stated
that
new
test
data
for
conventional
design
boilers
with
fabric
filter
control
should
be
included
in
the
emission
database
and
used
for
determining
the
MACT
floor
for
mercury.
The
commenter
noted
that
conventional
stoker
and
pulverized
coal
boilers
with
fabric
filters
are
not
represented
in
the
emission
data
in
docket
item
II­
B­
14.
The
commenter
also
explained
that
another
commenter
to
this
rule
(
CIBO)
has
noted
that
some
additional
test
data
on
these
types
of
units
are
available.
One
commenter
(
415)
was
confused
by
the
apparent
lack
of
data
on
emissions
and
pollution
control
configurations
in
use
in
the
ICI
boiler
and
process
heater
sectors,
given
the
amount
of
time
EPA
has
had
to
develop
the
rule.
The
commenter
contended
that
more
aggressive
data
collection
may
have
yielded
more
information
on
factors
impacting
emissions.
The
commenter
concluded
that
such
information
would
allow
the
EPA
to
identify
the
range
of
control
options
available
to
meet
the
MACT
emission
limit.
One
commenter
(
519)
noted
that
there
was
no
information
regarding
the
fuel
characteristics
of
the
units
used
to
determine
the
MACT
floor.

Response:
As
discussed
in
the
proposal
preamble,
the
MACT
floor
analysis
for
mercury
was
based
on
a
two
step
process.
First
the
percentage
of
units
with
control
technologies
that
could
achieve
mercury
emissions
reductions
was
determined
using
the
boiler
population
databases.
If
the
control
technology
analysis
indicated
that
at
least
12
percent
of
sources
in
the
subcategory
used
a
control
device
that
could
achieve
mercury
emissions
reductions,
then
the
control
technology
present
at
the
median
(
6th
percentile)
was
identified
as
the
MACT
floor
control
technology.
The
MACT
floor
level
of
control
for
mercury
was
identified
as
a
fabric
filter.
The
control
effectiveness
of
fabric
filters
was
based
on
emissions
information
for
utility
boilers
that
indicated
that
mercury
emissions
reductions
were
being
achieved
with
this
technology.
In
this
case,
we
could
use
control
efficiency
information
from
another
similar
source
category
to
supplement
the
information
available
in
this
source
category
because
of
the
similarity
in
fuel
burned,
combustor
type,
and
control
methodology
and
operation.
We
maintain
that
fabric
filters
are
still
the
appropriate
level
of
control
for
the
MACT
floor.

Second,
the
emission
limit
associated
with
the
MACT
floor
control
technology
was
calculated
using
emissions
information
for
units
in
the
subcategory,
whenever
possible.
For
most
of
the
subcategories
developed,
emissions
information
was
adequate.
Only
for
the
emission
limit
for
new
source
liquids
and
the
variability
factor
for
new
source
solids
was
fuel
pollutant
content
incorporated
into
the
MACT
floor
analyses.
The
mercury
fuel
content
of
coal
from
the
utility
industry
was
used
in
developing
the
variability
factors
for
new
solid
fired
units.
This
was
done
because
mercury
emissions
are
dependent
on
the
quantity
of
mercury
in
the
fuel
burned.
Coal
available
to
utilities
and
industrial
boilers
and
process
heaters
is
expected
to
be
similar,
and
coal
is
the
solid
fuel
that
is
routinely
used
in
such
units
that
has
generally
the
greatest
degree
of
HAP
variability.
We
maintain
that
the
utility
database
used
at
proposal
to
develop
the
variability
factor
for
new
sources
was
adequate
in
establishing
the
MACT
floor
emission
limit.

The
EPA
recognizes
that
the
mercury
emissions
database
for
industrial
boilers
is
limited.
However,
EPA
is
directed
by
the
CAA
to
develop
standards
for
sources
using
whatever
data
is
available.
Prior
to
proposal
and
during
the
Industrial
Combustion
Coordinated
Rulemaking
(
ICCR)
process,
EPA
conducted
a
thorough
search
for
HAP
emission
test
reports.
This
search
was
supported
by
industry,
trade
groups,
and
States.
For
criteria
pollutants,
such
as
PM,
substantial
emission
information
was
available
and
gathered.
For
mercury
and
other
HAP,
this
was
not
the
case.
Industrial
boilers
have
not
generally
been
required
to
test
for
HAP
emissions.
In
the
proposed
rule,
EPA
requested
commenters
to
provide
additional
emissions
information.
78
However,
only
one
source
provided
any
additional
mercury
emissions
data.
This
information
(
test
results
from
three
additional
coal­
fired
industrial
boilers)
was
used
to
revise
the
mercury
emission
limit
for
existing
sources.
We
also
reviewed
the
mercury
emission
database
used
to
develop
the
MACT
floor
emission
limit
for
existing
sources.
After
review,
we
determined
that
a
revision
to
the
variability
factor
was
appropriate.
The
additional
data
and
the
revised
variability
factor
was
used
to
re­
calculate
the
mercury
emission
limit
to
be
0.000009
lb/
MMBtu
(
from
0.000007
lb/
MMBtu
at
proposal).
A
detailed
discussion
of
the
revised
MACT
floor
analysis
conducted
is
provided
in
the
memorandum
"
Revised
MACT
Floor
Analysis
for
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants
Based
on
Public
Comments"
in
the
docket.

Variability
of
the
emissions
data
were
incorporated
into
the
final
emission
limits.
The
EPA
contends
that
by
considering
the
variability
of
emissions
information,
we
have
indirectly
incorporated
variability
in
fuel,
operating
conditions,
and
sampling
and
analytical
conditions
because
these
parameters
vary
from
emission
tests
conducted
from
one
unit
to
another,
and
even
within
one
unit.
The
EPA
does
not
consider
it
appropriate
or
feasible
to
incorporate
variability
from
a
multitude
of
parameters
because
such
information
is
not
available
and
cannot
be
correlated
to
the
emissions
information
in
the
emissions
test
database.
For
the
final
rule,
EPA
did
conduct
a
statistical
analysis
of
the
data
to
identify
the
97.5th
percent
confidence
interval.
This
analysis
provided
similar
results
to
the
variability
analysis
conducted
in
the
proposed
rule.
Consequently,
EPA
decided
not
to
change
its
variability
methodology.
A
detailed
discussion
of
the
statistical
analysis
conducted
is
provided
in
the
memorandum
"
Statistical
Analysis
of
Mercury
Test
Data
Variability
in
Response
to
Public
Comments
on
Determination
of
the
MACT
Floor
for
Mercury
Emissions"
in
the
docket.

Comment:
One
commenter
(
393)
supported
EPA's
decision
not
to
impose
emission
limitations
on
new
gaseous
fuel­
fired
units.
Several
commenters
(
360,
382,
479,
393,
410,
413,
486,
492,
536)
supported
EPA's
finding
that
the
MACT
floor
level
of
control
for
existing
gas
and
liquid
fuel­
fired
units
is
no
control.
Two
commenters
(
393,
486)
explained
that
they
supported
EPA's
determination
because
few
existing
units
in
these
subcategories
operate
with
emission
control
technologies
to
reduce
HAP
emissions,
thus
the
commenters
stated
it
was
appropriate
to
set
the
MACT
floor
at
no
emission
reductions.
One
commenter
(
410)
supported
EPA's
conclusion
that
control
technology
is
the
primary
factor
to
be
considered
in
boiler
MACT
floor
determinations
because
it
is
the
most
feasible
method
by
which
operators
of
boilers
can
reduce
HAP
emissions.
Other
commenters
(
410,
479)
contended
that
EPA
has
legal
authority
to
set
the
MACT
floor
as
"
no
emissions
control"
for
particular
HAP
categories,
and
provided
additional
justification
for
this
decision.
One
commenter
(
492)
urged
that
EPA,
in
setting
a
"
no
control"
emission
standard,
would
not
cause
a
delay
in
compliance.
The
commenter
noted
that
recent
court
decisions
may
cast
doubt
on
whether
EPA
may
establish
a
"
no
control"
emission
limitation.
However,
the
commenter
believes
that
EPA
may
establish
a
"
no
control"
emission
limitation
if
its
analysis
determines
that
sources
are
not
taking
any
action
that
either
controls
emissions
or
is
duplicable
by
other
sources.

One
commenter
(
448)
said
that
EPA's
proposed
"
no
control"
as
the
MACT
some
subcategories
is
unlawful.
The
commenter
noted
that
EPA
has
a
clear
statutory
obligation
to
set
emission
standards
for
each
listed
HAP
(
the
commenter
cited
legal
briefs).
One
commenter
(
512)
argued
that
EPA's
determination
that
"
no
control"
is
the
MACT
floor
for
some
subcategories
is
79
unacceptable.
The
commenter
specifically
challenged
EPA's
determination
of
the
MACT
floor
for
organic
pollutants.
The
commenter
explained
that
EPA
should
rank
the
units
for
which
emissions
data
is
available
according
to
the
best
performing
units,
not
based
on
the
add­
on
control
level
of
6
percent
of
the
total
population.
The
commenter
noted
that
the
U.
S.
Court
of
Appeals
for
the
D.
C.
Circuit
had
squarely
held,
in
the
National
Lime
case,
that
EPA
was
not
allowed
to
make
a
"
no
control"
determination
for
a
pollutant
emitted
by
a
listed
category
of
sources.

Response:
We
believe
that
EPA
has
ample
legal
authority
to
set
the
MACT
floor
at
"
no
emissions
reductions".
This
is
because
the
statute
requires
EPA
to
set
standards
that
are
duplicable
by
others.
In
National
Lime,
the
court
threw
out
EPA's
determination
of
a
no
control
floor
because
it
was
based
only
on
a
control
technology
approach.
The
court
stated
that
EPA
must
look
at
what
the
best
performers
achieve,
regardless
of
how
they
achieve
it.
Therefore,
our
determination
that
the
MACT
floor
for
certain
subcategories
or
HAP
is
"
no
emissions
reduction"
is
lawful
because
we
determined
that
the
best­
performing
sources
were
not
achieving
emissions
reduction
through
the
use
of
an
emission
control
system
and
there
were
no
other
appropriate
methods
by
which
boilers
and
process
heaters
could
reduce
HAP
emissions.
Furthermore,
setting
emissions
standards
on
the
basis
of
actual
emissions
data
alone
where
facilities
have
no
way
of
controlling
their
HAP
emissions
would
contravene
the
plain
statutory
language
as
well
as
Congressional
intent
that
affected
sources
not
be
forced
to
shut
down.

Comment:
One
commenter
(
397)
expressed
concern
that
the
proposed
emission
limits
for
solid
fuel­
fired
units
would
exempt
many
units
from
control
of
acid
gas
HAP
and
would
require
less
than
50
percent
control
from
most
units
and
requested
that
EPA
lower
the
HCl
emission
limit
to
0.02
lb/
MMBtu.
One
commenter
(
295)
suggested
cutting
the
present
emission
standards
by
50
percent
from
boilers
and
process
heaters.

Response:
The
EPA
does
not
believe
there
is
technical
justification
for
requiring
different
emission
limits.
The
HCl
emission
limit
for
solid
fuel­
fired
units
was
calculated
using
the
MACT
floor
methodology
presented
in
the
memorandum
"
MACT
Floor
Analysis
for
New
and
Existing
Sources
in
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
Source
Categories".
The
EPA's
analysis
showed
a
packed
bed
scrubber
as
being
more
stringent
than
the
floor
level
of
control
for
existing
sources.
While
cost
cannot
be
incorporated
into
the
MACT
floor
analysis,
it
is
a
component
in
any
analysis
of
beyond­
the­
floor
options.
The
EPA
calculated
that
the
additional
annualized
cost
to
comply
with
the
emission
limit
associated
with
the
packed
bed
scrubber
level
of
control
would
be
$
900
million
and
the
emission
reduction
would
increase
by
20,000
tons
of
HCl.
The
results
indicated
that
while
additional
emission
reductions
may
be
realized,
the
costs
would
be
too
high
to
consider
it
as
MACT.

Comment:
One
commenter
(
338)
stated
that
the
rule
should
allow
for
the
inherent
degradation
in
performance
throughout
the
normal
life
of
pollution
control
equipment.
The
commenter
added
that
normal
life
expectancy
of
consumables
in
process
control
will
cause
degradation
in
emission
rates.

Response:
The
EPA
disagrees
with
the
commenter.
Emission
standards
are
not
developed
to
allow
increase
as
equipment
degrades.
This
would
contravene
the
purpose
of
any
environmental
standard
to
reduce
pollution.
Facilities
must
maintain
their
equipment
to
ensure
80
that
continuous
compliance
is
achieved.
The
EPA
believes
that
proper
maintenance
of
equipment
is
necessary
for
sources
to
meet
the
compliance
requirements
of
the
rule.

Comment:
One
commenter
(
451)
contended
that
floors
need
not
be
achievable
for
all
units
in
a
subcategory
through
the
application
of
end­
of­
stack
technology
because
the
CAA
only
requires
that
MACT
floors
reflect
the
emission
levels
actually
achieved
by
the
relevant
best
sources.
The
commenter
added
that
even
if
some
sources
could
not
meet
the
floor
through
end
of
stack
controls,
the
EPA
would
still
be
required
to
set
the
MACT
floor
from
the
best
performing
sources,
and
the
sources
in
question
would
have
to
shut
down
or
switch
fuels.

Response:
We
disagree
with
the
commenter.
We
contend
that
the
MACT
floor
needs
to
be
achievable
by
all
sources.
As
such
we
only
considered
universally
applicable
control
techniques.

Comment:
One
commenter
(
497)
contended
that
the
MACT
floor
is
not
representative
of
the
more
than
500
boilers
operated
by
the
furniture
industry.
The
commenter
added
that
the
458
boilers
comprising
the
EPA's
MACT
floor
include
only
30
boilers
burning
some
quantity
of
wood
as
fuel,
and
only
8
of
the
30
burn
some
quantity
of
kiln­
dried
wood
as
fuel.
The
commenter
noted
that
EPA
databases
do
not
quantify
the
percentage
of
total
fuel
comprised
by
wood
resulting
in
a
boiler
burning
1
percent
wood
and
99
percent
commercial
waste
listed
as
burning
wood
and
burning
commercial
waste.

Response:
As
discussed
in
the
proposal
preamble,
EPA
developed
nine
subcategories
based
on
fuel
state,
operation/
use,
and
size/
combustor
type.
Boilers
used
in
the
furniture
industry
burn
solid
fuel
and
are
grouped
with
the
solid
fuel­
fired
boiler
subcategories.
The
MACT
floor
for
each
subcategory
is
based
on
the
emissions
data
from
the
boilers
in
the
subcategory
with
the
control
technologies
that
were
determined
to
best
control
mercury,
metallic
HAP,
PM,
and
inorganic
HAP.
This
analysis
is
discussed
in
the
memorandum
"
MACT
Floor
Analysis
for
New
and
Existing
Sources
in
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
Source
Categories".
Because
units
burning
any
amount
of
solid
fuel
are
grouped
together,
the
possibility
exists
that
units
from
the
furniture
manufacturing
industry,
which
may
not
have
as
effective
control
devices
as
units
in
other
industries,
are
not
a
part
of
the
best­
controlled
units
used
to
develop
the
MACT
floor
emission
limits.
The
only
option
to
develop
MACT
floors
that
would
specifically
include
information
from
the
furniture
industry
is
to
develop
a
separate
subcategory
for
the
furniture
industry.
However,
the
EPA
has
determined
that
there
no
justification
for
creating
additional
subcategories
for
the
final
rule.

Comment:
One
commenter
(
497)
used
EPA's
MACT
floor
methodology
and
determined
that
the
MACT
floor
for
a
<
50
MMBtu/
hr
size
category
is
75
percent
PM
control,
which
is
more
easily
achieved
by
existing
cyclone
and
multiclone
collectors.

Response:
The
EPA
would
like
to
note
that
there
is
no
subcategory
that
is
comprised
of
units
<
50
MMBtu/
hr.
The
small
unit
subcategory
consists
of
units
less
than
10
MMBtu/
hr.
The
EPA
determined
there
was
no
justification
for
changing
the
subcategories
presented
in
the
proposed
rule.
Therefore,
while
the
commenters
analysis
may
be
correct,
(
EPA
has
not
verified
it),
it
is
not
relevant
to
the
final
rule.
81
Comment:
Commenters
(
410,
479)
agreed
with
EPA
that
good
combustion
practices
are
not
an
appropriate
basis
for
establishing
a
MACT
Floor.
The
commenter
(
479)
noted
that
work
practices
that
might
reduce
HAP
emissions
are
widely
variable
across
a
very
diverse
universe
of
boilers
and
process
heaters.
Furthermore,
data
on
the
use
of
good
combustion
practices
a
their
impact
on
HAP
emissions
is
very
limited.
In
response
to
EPA
request
for
comment
on
whether
there
are
any
uniform
good
combustion
practices
that
would
be
appropriate
for
minimizing
organic
HAP
emissions,
one
commenter
(
413)
noted
that
there
were
no
uniform
practices
because
the
characteristics
of
individual
boilers
differ
dramatically.
The
commenter
(
413)
supported
not
including
good
combustion
practices
in
the
MACT
floor
for
new
or
existing
units.
Another
commenter
(
442)
agreed
that
there
is
a
lack
of
information
and
of
a
uniform
approach
for
assuring
combustion
efficiency,
due
to
the
vast
diversity
of
units.
The
commenter
pointed
out
that
procedures
to
minimize
one
pollutant
could
increase
another.
The
commenter
requested
that
EPA
prepare
a
new
separate
summary
report
documenting
types
of
work
practices
that
constitute
Good
Combustion
Practices.

Response:
The
EPA
thanks
the
commenters
for
their
input.
At
proposal,
EPA
had
requested
commenters
provide
additional
information
on
good
combustion
practices.
However,
no
information
on
the
effectiveness
of
good
combustion
practices
at
reducing
specific
pollutants
was
received.
Since
no
additional
information
was
obtained,
the
final
rule
maintains
that
good
combustion
practices
are
not
an
appropriate
basis
for
establishing
a
MACT
floor.

Comment:
One
commenter
(
410)
contended
that
the
California
standards,
which
the
CO
requirements
are
based
on,
do
not
require
CO
CEMS,
but
require
initial
compliance
testing
and
periodic
subsequent
performance
testing.
The
commenter
added
that
the
California
standards
exempt
some
limited
use
units
and
provide
for
less
stringent
requirements
for
units
affected
by
natural
gas
curtailment.
As
such,
the
commenter
stated
that
EPA's
CO
standard
exceeds
the
California
CO
regulations.
The
commenter
added
that
if
EPA
intends
to
go
beyond
the
floor,
then
it
must
consider
cost
and
emission
reductions.
The
commenter
provided
additional
data
and
analyses
detailing
the
cost
and
emission
reduction
impacts
of
the
proposed
CO
requirements.
The
commenter
contended
that
EPA
underestimated
the
number
of
new
and
reconstructed
units
and
underestimated
the
costs
to
these
units
of
meeting
the
proposed
standards.
The
commenter
added
that
EPA
costed
out
an
inexpensive
portable
CO
monitor
that
would
not
meet
the
continuous
monitoring
requirements
of
the
rule.
The
commenter
concluded
that
based
on
their
analysis,
the
CO
requirements
are
cost
ineffective.
Commenters
(
380,
476)
opposed
the
continuous
emissions
monitoring
for
CO
for
gas­
fired
boilers.
The
commenter
added
that
EPA
wrongly
considered
monitoring
as
part
of
the
MACT
floor
analysis
for
new
gas­
fired
boilers.
The
commenters
explained
that
the
state
regulations
EPA
used
as
the
basis
for
the
requirements
do
not
require
CO
CEMS.
The
commenter
also
added
that
the
CAA
does
not
support
including
monitoring
as
a
floor
requirement.
One
commenter
(
393)
suggested
boiler
and
process
heaters
be
allowed
the
option
of
complying
with
the
proposed
CO
limit
or
establishing
good
combustion
practices.
The
commenter
stated
the
EPA
failed
to
justify
the
MACT
floor
of
organic
HAP
for
new
large
and
limited
use
units
as
the
determination
of
a
CO
limit
of
400
ppm.
The
commenter
claimed
EPA
failed
to
explain
how
this
met
the
"
best
controlled
similar
source"
requirement
of
section
112(
d)(
3)
of
CAA
Response:
The
commenters
are
correct
that
the
California
CO
regulations
do
not
require
CO
CEMS.
The
regulations
do
provide
sources
with
the
option
of
conducting
annual
testing
or
82
installing
CO
CEMS
to
demonstrate
compliance
with
the
CO
emission
limit.
Because
the
regulations
that
were
the
basis
of
the
MACT
floor
do
not
provide
specifics
on
which
boilers
should
conduct
annual
testing
and
which
should
use
CO
CEMS,
we
reviewed
the
cost
information
provided
by
the
commenters
to
make
this
determination.
In
considering
the
additional
cost
information
and
reviewing
the
cost
information
used
in
the
proposed
rule,
the
EPA
decided
that
changes
to
the
CO
compliance
requirements
were
warranted.
The
final
rule
requires
that
new
units
with
heat
input
capacities
less
than
100
MMBtu/
hr
conduct
initial
and
annual
performance
tests
for
CO
emissions.
New
units
with
heat
input
capacities
greater
or
equal
to
100
MMBtu/
hr
are
still
required
to
install,
operate,
and
maintain
a
CO
CEM.

Regardless
of
whether
the
California
regulations
do
or
do
not
require
CO
CEMS,
we
would
have
reviewed
the
need
for
continuous
monitoring
and
operating
limits
in
order
to
ensure
the
most
accurate
indication
of
proper
operation
of
the
control
system.
The
purpose
of
all
of
the
minimum
operating
parameter
limits
in
the
standard
is
to
ensure
continuous
compliance
by
ensuring
that
the
air
pollution
control
equipment
is
operating
as
they
were
during
the
latest
performance
test
demonstrating
compliance
with
the
emission
limits.
The
operating
parameters
are
established
as
"
minimum"
to
provide
enforceable
boundaries
in
their
operation.
Operating
outside
the
bounds
of
the
minimum
parameters
may
lead
to
increased
air
emissions.

The
EPA
would
also
like
to
clarify
that
operation
above
the
CO
limit
constitutes
a
deviation
of
the
work
practice
standard.
However,
the
determination
of
what
deviations
constitute
violations
of
the
standard
is
up
to
the
discretion
of
the
entity
responsible
for
enforcement
of
the
standards.

Comment:
One
commenter
(
512)
requested
that
EPA
re­
calculate
the
MACT
floor
for
organic
HAP
emissions
based
on
emission
data
and
source
performance,
not
on
whether
add­
on
controls
are
in
place.
Once
a
numerical
floor
is
calculated,
EPA
should
evaluate
whether
good
combustion
practices
are
sufficient
to
ensure
that
the
floor
level
is
met.

Response:
As
explained
in
the
proposal
preamble,
the
EPA
considered
calculating
the
MACT
floor
based
on
emissions
data
and
source
performance.
However,
there
were
several
problems
associated
with
establishing
MACT
floor
emission
limits
in
this
manner.
The
commenters
are
referred
to
68
FR
1672,
January
13,
2003.
The
EPA's
interpretation
of
the
CAA
requires
that
standards
be
set
that
are
achievable
by
sources.
This
interpretation
predicates
that
an
emission
control
technique
must
be
available
to
meet
the
standard.
As
discussed
in
the
proposal
preamble,
the
EPA
could
not
identify
any
add­
on
technologies
that
could
be
used
to
reduce
organic
HAP
emissions.
The
EPA
also
notes
that
it
does
not
have
information
on
the
effectiveness
of
good
combustion
practices
on
reducing
emissions.
This
information
was
also
requested
in
the
proposal
preamble.
However,
no
additional
information
was
provided
by
commenters.
Therefore,
EPA
could
not
reassess
its
decision
regarding
good
combustion
practices
for
the
final
rule.

Comment:
One
commenter
(
497)
contended
that
EPA
has
not
identified
a
technology
to
meet
the
proposed
HAP
limit
for
CO
for
new
sources.
The
commenter
added
that
an
atmospheric
fluid
bed
combustor
burning
wood
can
meet
the
proposed
level,
but
may
exceed
the
limit
when
burning
coal
as
a
back­
up
fuel.
83
Response:
We
would
like
to
clarify
that
the
CO
limits
in
the
proposed
and
final
rule
are
work
practice
standards
and
not
emission
limits.
We
also
note
that
the
work
practice
CO
limits
are
only
applicable
to
new
sources,
and
the
standard
requires
that
the
CO
limit
be
achieved
on
a
30­
day
rolling
average,
instead
of
daily.
It
is
EPA's
contention
that
new
boilers
and
process
heaters
should
be
able
to
meet
the
CO
limit
because
they
are
better
designed
and
more
efficient
than
existing
units.

Comment:
Several
commenters
(
364,
383,
387,
388,
399,
413,
419,
449,
492,
498,
524,
533)
requested
that
EPA
revisit
the
determination
of
the
mercury
emission
test
data
variability
factor.
Some
commenters
(
449,
524,
533,
388,
498)
questioned
whether
EPA's
method
for
generating
the
"
variability
factor"
is
adequate
to
ensure
that
the
mercury
limitation
is
achievable.
The
commenters
believe
that
it
is
improper
for
EPA
to
estimate
the
variability
in
mercury
emissions
based
upon
data
only
from
those
sources
that
utilize
the
MACT
floor
technology.
The
commenters
argued
that
EPA
should
consider
the
fuel
mercury
variability
from
all
coal
supplies
utilized
by
ICI
boilers
and
process
heaters.
The
commenters
added
that
the
court
instruction
in
Cement
Kiln
ruling
would
make
it
improper
for
the
EPA
to
estimate
variability
in
mercury
emissions
based
upon
data
from
only
those
sources
that
use
the
MACT
technology,
and
EPA
must
consider
the
fuel
mercury
content
of
all
coal
supplies
used
by
ICI
boilers
regardless
of
the
unit's
control
technology.
The
commenters
concluded
that
from
this
database,
EPA
must
develop
a
standard
that
the
coal
with
the
worst­
case
mercury
and
chlorine
content
can
achieve.
The
commenters
added
the
emission
limitation
for
mercury
will
only
be
achievable
if
it
is
based
solely
on
the
fuel
with
the
worst
case
composition
and
any
statistical
methodology
that
considers
data
from
burning
fuels
of
better
quality
will
influence
the
calculation,
dilute
the
standard
and
dictate
that
available
fuels
with
the
worst
case
composition
will
not
be
capable
of
achieving
the
standard.

Commenters
(
364,
399,
387)
contended
that
the
mercury
standard
must
take
into
account
the
variability
in
coal
and
its
impact
on
the
ability
of
sources
to
remove
mercury
from
flue
gas.
Commenters
discussed
the
chemistry
of
mercury
and
the
wide
variability
of
mercury
in
coal.
Several
commenters
(
449,
524,
533,
388,
498)
provided
data
and
discussion
on
the
variability
of
mercury
in
coal,
the
effect
of
other
components
in
coal
that
effect
the
state
of
mercury,
and
the
effects
of
those
parameters
on
removal
efficiencies.

One
commenter
(
413)
asserted
that
there
is
no
factual
basis
for
EPA's
assumption
that
emission
tests
for
the
best
performing
units
adequately
reflect
the
full
range
of
fuel
variability
those
units
experience
over
the
long
term.
The
commenter
added
that
fuel
variability
alone
would
be
a
factor
significantly
higher
than
EPA's
calculated
values.
The
commenter
also
stated
that
the
variability
factor
for
existing
solids
is
suspect
because
it
was
produced
by
removing
an
outlier
point
and
the
reason
for
the
removal
was
not
documented.
Additionally,
the
commenter
stated
the
same
outlier
results
were
incorporated
into
the
calculation
for
the
new
source
MACT
floor
for
mercury
emissions.
The
commenter
added
that
EPA's
variability
factor
was
flawed
because
it
assumes
that
any
pair
of
emission
tests
at
a
given
facility
brackets
the
long­
term
performance
of
the
facility.

Several
commenters
(
364,
383,
387,
388,
399,
413,
419,
449,
492,
498,
524,
533)
argued
that
the
current
variability
factor
of
2.49
that
EPA
used
to
develop
the
emission
limit
for
mercury
does
not
reflect
the
universe
of
fuel,
fuel
characteristics,
and
control
technology
variability.
One
commenter
(
381)
stated
the
EPA's
MACT
floor
determinations
should
include
84
adjustments
to
account
for
operational
and
fuel
variability.
Based
on
Sierra
Club
v.
EPA
the
EPA
is
required
to
include
adjustments
to
account
for
significant
operational
and
fuel
variability.
Control
requirements
for
mercury
emissions
should
be
revised
to
take
into
account
the
variability
of
coal
composition
since
mercury
emissions
depend
in
large
part
on
the
chlorine
content
of
coal.
One
commenter
(
382)
suggested
that
EPA
reconsider
the
following
points:
1)
The
inherent
variability
of
mercury
and
chlorine
in
different
types
of
coal,
as
well
as
within
a
single
mine;
2)
the
inherent
expanded
variability
in
fuel
quality
when
the
range
of
fuels
are
considered;
3)
the
minimal
impact
of
coal
cleaning
on
mercury
level
and
variability;
4)
the
extremely
diverse
fuel
mix
used
by
the
affected
population
and
the
failure
of
EPA
to
adequately
provide
a
fuel
dependent
variability
factor;
5)
recently
obtained
mercury
emission
test
data
from
coal
boilers
equipped
with
fabric
filters;
6)
lack
of
justification
in
selecting
the
emission
rate
for
one
boiler's
test
variability;
7)
the
diversity
of
boiler
and
process
heater
designs;
and
8)
deleting
emission
data
from
one
source
when
establishing
the
MACT
floor
with
no
supporting
information
to
indicate
that
the
particular
source
is
not
actually
one
of
the
best
controlled
12
percent
in
the
source
category.

Response:
As
discussed
in
the
proposal
preamble,
the
MACT
floor
analysis
for
mercury
was
based
on
a
two
step
process.
First
the
percentage
of
units
with
control
technologies
that
could
achieve
mercury
emissions
reductions
was
determined
using
the
boiler
population
databases.
If
the
control
technology
analysis
indicated
that
at
least
12
percent
of
sources
in
the
subcategory
used
a
control
device
that
could
achieve
mercury
emissions
reductions,
then
the
control
technology
present
at
the
median
(
6th
percentile)
was
identified
as
the
MACT
floor
control
technology.
The
MACT
floor
level
of
control
for
mercury
was
identified
as
a
fabric
filter.
The
control
effectiveness
of
fabric
filters
was
based
on
emissions
information
for
utility
boilers
that
indicated
that
mercury
emissions
reductions
were
being
achieved
with
this
technology.
In
this
case,
we
could
use
control
efficiency
information
from
another
similar
source
category
to
supplement
the
information
available
in
this
source
category
because
of
the
similarity
in
fuel
burned,
combustor
type,
and
control
methodology
and
operation.
We
maintain
that
fabric
filters
are
still
the
appropriate
level
of
control
for
the
MACT
floor.

Second,
the
emission
limit
associated
with
the
MACT
floor
control
technology
was
calculated
using
emissions
information
for
units
in
the
subcategory,
whenever
possible.
For
most
of
the
subcategories
developed,
emissions
information
was
adequate.
Only
for
the
emission
limit
for
new
source
liquids
and
the
variability
factor
for
new
source
solids
was
fuel
pollutant
content
incorporated
into
the
MACT
floor
analyses.
The
mercury
fuel
content
of
coal
from
the
utility
industry
was
used
in
developing
the
variability
factors
for
new
solid
fired
units.
This
was
done
because
mercury
emissions
are
dependent
on
the
quantity
of
mercury
in
the
fuel
burned.
Coal
available
to
utilities
and
industrial
boilers
and
process
heaters
is
expected
to
be
similar,
and
coal
is
the
solid
fuel
that
is
routinely
used
in
such
units
that
has
generally
the
greatest
degree
of
HAP
variability.
We
maintain
that
the
utility
database
used
at
proposal
to
develop
the
variability
factor
for
new
sources
was
adequate
in
establishing
the
MACT
floor
emission
limit.

The
EPA
recognizes
that
the
mercury
emissions
database
for
industrial
boilers
is
limited.
However,
EPA
is
directed
by
the
CAA
to
develop
standards
for
sources
using
whatever
data
is
available.
Prior
to
proposal
and
during
the
Industrial
Combustion
Coordinated
Rulemaking
(
ICCR)
process,
EPA
conducted
a
thorough
search
for
HAP
emission
test
reports.
This
search
was
supported
by
industry,
trade
groups,
and
States.
For
criteria
pollutants,
such
as
PM,
substantial
emission
information
was
available
and
gathered.
For
mercury
and
other
HAP,
this
was
not
the
case.
Industrial
boilers
have
not
generally
been
required
to
test
for
HAP
emissions.
85
In
the
proposed
rule,
EPA
requested
commenters
to
provide
additional
emissions
information.
However,
only
one
source
provided
any
additional
mercury
emissions
data.
This
information
(
test
results
from
three
additional
coal­
fired
industrial
boilers)
was
used
to
revise
the
mercury
emission
limit
for
existing
sources.
We
also
reviewed
the
mercury
emission
database
used
to
develop
the
MACT
floor
emission
limit
for
existing
sources.
After
review,
we
determined
that
a
revision
to
the
variability
factor
was
appropriate.
The
additional
data
and
the
revised
variability
factor
was
used
to
re­
calculate
the
mercury
emission
limit
to
be
0.000009
lb/
MMBtu
(
from
0.000007
lb/
MMBtu
at
proposal).
A
detailed
discussion
of
the
revised
MACT
floor
analysis
conducted
is
provided
in
the
memorandum
"
Revised
MACT
Floor
Analysis
for
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants
Based
on
Public
Comments"
in
the
docket.

Variability
of
the
emissions
data
were
incorporated
into
the
final
emission
limits.
The
EPA
contends
that
by
considering
the
variability
of
emissions
information,
we
have
indirectly
incorporated
variability
in
fuel,
operating
conditions,
and
sampling
and
analytical
conditions
because
these
parameters
vary
from
emission
tests
conducted
from
one
unit
to
another,
and
even
within
one
unit.
The
EPA
does
not
consider
it
appropriate
or
feasible
to
incorporate
variability
from
a
multitude
of
parameters
because
such
information
is
not
available
and
cannot
be
correlated
to
the
emissions
information
in
the
emissions
test
database.
For
the
final
rule,
EPA
did
conduct
a
statistical
analysis
of
the
data
to
identify
the
97.5th
percent
confidence
interval.
This
analysis
provided
similar
results
to
the
variability
analysis
conducted
in
the
proposed
rule.
Consequently,
EPA
decided
not
to
change
its
variability
methodology.
A
detailed
discussion
of
the
statistical
analysis
conducted
is
provided
in
the
memorandum
"
Statistical
Analysis
of
Mercury
Test
Data
Variability
in
Response
to
Public
Comments
on
Determination
of
the
MACT
Floor
for
Mercury
Emissions"
in
the
docket.

Comment:
Several
commenters
(
364,
383,
387,
388,
399,
406,
407,
408,
449,
498,
501,
524,
533)
recommended
that
EPA
reconsider
the
mercury
limit
for
new,
solid
fuel­
fired
sources.
The
commenters
generally
supported
EPA's
approach
to
determining
a
new
source
mercury
emission
limit
based
on
a
MACT
floor
technology
of
fabric
filter
control,
but
expressed
concern
that
the
inherent
variability
of
mercury
content
in
fuels
has
not
been
captured
in
the
variability
factor
developed
by
EPA.
This
could
result
in
units
that
have
fabric
filter
control
not
being
able
to
achieve
the
proposed
mercury
limit,
even
though
they
use
the
maximum
achievable
control
technology
as
determined
by
EPA.

Many
commenters
(
364,
387,
399)
requested
that
EPA
revisit
the
basis
of
the
mercury
emission
variability
factor
by
including
data
in
the
analysis
that
was
not
included
previously
and
by
expanding
the
fuel
dependant
variability
factor
to
include
the
full
range
of
diverse
fuel
types.
Since
the
unused
data
set
documents
the
mercury
emission
level
of
a
unit
that
employs
the
floor
level
of
control,
and
it
would
be
difficult
to
disentangle
the
effects
of
multiple
control
technologies,
the
commenters
believe
that
the
use
of
all
available
data
is
necessary
to
establish
a
MACT
floor.
By
adding
in
this
additional
data
set
and
applying
the
variability
factor
of
2.49,
the
commenters
(
364,
387,
399)
calculated
the
resulting
MACT
floor
emission
level
would
be
9.8
lb/
trillion
Btu,
rounded
to10
lb/
trillion
Btu.
Some
commenters
(
449,
524,
533,
388,
498)
argued
that
there
are
problems
with
the
methodology
and
interpretation
of
"
best
controlled
similar
source"
that
EPA
used.
Specifically,
the
commenters
requested
that
EPA
include
the
petroleum
coke
mercury
data
point
in
the
calculation
of
the
fuel
dependent
variability
factor
and
that
EPA
should
expand
the
86
fuel
dependent
variability
factor
to
include
the
full
range
of
diverse
fuel
types
used
by
ICI
boilers
and
process
heaters,
specifically
considering
that
the
best
controlled
similar
source
that
EPA
designated
was
firing
urban
wood
waste
and
biomass.
The
commenters
noted
that
by
addressing
these
recommendations,
the
new
solid
fuel­
fired
MACT
floor
would
increase
to
8
lb/
trillion
Btu.

One
commenter
(
492)
noted
that
the
best
controlled
similar
source
that
the
fuel
dependent
variability
factor
was
based
on
was
fired
with
wood
and
biomass
that
has
undetected
fuel
mercury
levels.
The
commenter
observed
that
not
all
sources
will
have
this
mixture
of
fuels
available,
and
that
the
variability
factor
established
using
this
data
may
not
be
suitable
to
units
firing
certain
types
of
coal
or
coke.

Response:
As
discussed
in
the
proposal
preamble,
the
MACT
floor
analysis
for
mercury
was
based
on
a
two
step
process.
First
the
percentage
of
units
with
control
technologies
that
could
achieve
mercury
emissions
reductions
was
determined
using
the
boiler
population
databases.
If
the
control
technology
analysis
indicated
that
at
least
12
percent
of
sources
in
the
subcategory
used
a
control
device
that
could
achieve
mercury
emissions
reductions,
then
the
control
technology
present
at
the
median
(
6th
percentile)
was
identified
as
the
MACT
floor
control
technology.
The
MACT
floor
level
of
control
for
mercury
was
identified
as
a
fabric
filter.
The
control
effectiveness
of
fabric
filters
was
based
on
emissions
information
for
utility
boilers
that
indicated
that
mercury
emissions
reductions
were
being
achieved
with
this
technology.
In
this
case,
we
could
use
control
efficiency
information
from
another
similar
source
category
to
supplement
the
information
available
in
this
source
category
because
of
the
similarity
in
fuel
burned,
combustor
type,
and
control
methodology
and
operation.
We
maintain
that
fabric
filters
are
still
the
appropriate
level
of
control
for
the
MACT
floor.

Second,
the
emission
limit
associated
with
the
MACT
floor
control
technology
was
calculated
using
emissions
information
for
units
in
the
subcategory,
whenever
possible.
For
most
of
the
subcategories
developed,
emissions
information
was
adequate.
Only
for
the
emission
limit
for
new
source
liquids
and
the
variability
factor
for
new
source
solids
was
fuel
pollutant
content
incorporated
into
the
MACT
floor
analyses.
The
mercury
fuel
content
of
coal
from
the
utility
industry
was
used
in
developing
the
variability
factors
for
new
solid
fired
units.
This
was
done
because
mercury
emissions
are
dependent
on
the
quantity
of
mercury
in
the
fuel
burned.
Coal
available
to
utilities
and
industrial
boilers
and
process
heaters
is
expected
to
be
similar,
and
coal
is
the
solid
fuel
that
is
routinely
used
in
such
units
that
has
generally
the
greatest
degree
of
HAP
variability.
We
maintain
that
the
utility
database
used
at
proposal
to
develop
the
variability
factor
for
new
sources
was
adequate
in
establishing
the
MACT
floor
emission
limit.

The
EPA
recognizes
that
the
mercury
emissions
database
for
industrial
boilers
is
limited.
However,
EPA
is
directed
by
the
CAA
to
develop
standards
for
sources
using
whatever
data
is
available.
Prior
to
proposal
and
during
the
Industrial
Combustion
Coordinated
Rulemaking
(
ICCR)
process,
EPA
conducted
a
thorough
search
for
HAP
emission
test
reports.
This
search
was
supported
by
industry,
trade
groups,
and
States.
For
criteria
pollutants,
such
as
PM,
substantial
emission
information
was
available
and
gathered.
For
mercury
and
other
HAP,
this
was
not
the
case.
Industrial
boilers
have
not
generally
been
required
to
test
for
HAP
emissions.
In
the
proposed
rule,
EPA
requested
commenters
to
provide
additional
emissions
information.
However,
only
one
source
provided
any
additional
mercury
emissions
data.
This
information
(
test
results
from
three
additional
coal­
fired
industrial
boilers)
was
used
to
revise
the
mercury
emission
limit
for
existing
sources.
87
A
variability
factor
for
mercury
was
derived
from
the
mercury
content
of
coal
by
dividing
the
highest
observed
HAP
concentration
by
the
lowest
observed
HAP
concentration
from
the
utility
coal
analysis.
This
was
done
because
coal
available
to
utilities
and
industrial
boilers
is
expected
to
be
similar,
and
coal
is
the
solid
fuel
that
is
routinely
used
in
such
units
that
has
generally
the
greatest
degree
of
HAP
variability.
Given
the
limited
information
available,
we
believe
that
variability
calculated
using
this
methodology
is
reasonable.

Comment:
Several
commenters
(
364,
383,
387,
388,
399,
406,
407,
408,
419,
449,
492,
498,
501,
524,
533)
suggested
that
EPA
raise
the
mercury
emission
limit
for
existing
solid
fuelfired
units.
The
commenters
expressed
concern
over
the
lack
of
a
demonstrated,
reliable
technology
that
could
achieve
the
standard
without
great
expense
to
the
existing
sources.
The
commenters
noted
that
fabric
filter
technology
has
not
been
proven
at
some
sources
and
has
drawbacks
such
as
plugging
with
a
high
moisture
fuel
and
fire
hazards
due
to
carryover
of
hot
particles.
Some
commenters
(
406,
407,
408,
501)
requested
that
EPA
raise
the
mercury
emission
limit
for
existing
sources
to
15
lb/
trillion
Btu.

Several
commenters
(
364,
383,
387,
388,
399,
449,
492,
498,
524,
533)
requested
that
EPA
reevaluate
the
MACT
floor
for
mercury
from
solid
fuel­
fired
boilers
using
all
available
data.
The
commenters
noted
that
EPA
used
only
six
of
seven
data
sets
in
determining
the
MACT
floor
and
the
unused
data
set
is
from
a
coal­
fired
boiler
with
fabric
filter
control,
which
is
the
floor
level
of
control
as
determined
by
EPA.
Several
commenters
(
388,
449,
492,
498,
524,
533)
urged
EPA
to
use
all
the
data
in
its
mercury
emissions
data
set
in
Appendix
C­
4
to
determine
the
mercury
emission
limitation
for
existing
units.
The
commenters
stated
that
the
use
of
only
12/
14th
of
the
solid­
fuel
fired
mercury
data
is
inconsistent
with
EPA's
floor
methodology,
and
that
the
remainder
of
the
solid­
fuel
fired
data
(
i.
e.,
CAPCO
data
set)
is
warranted.

Several
commenters
(
364,
387,
399)
argued
that
EPA's
approach
might
be
a
reasonable
approach
if
the
data
set
were
representative
of
the
population
of
boilers,
but
the
only
coal­
fired
boiler
data
used
in
determining
the
MACT
floor
were
from
fluidized
bed
boilers
and
the
commenters
noted
that
fluidized
bed
boilers
are
inherently
lower
emitting
sources,
which
would
bias
the
overall
mercury
emission
data
set
lower.
The
commenters
also
pointed
out
that
in
addition
to
not
using
all
of
the
available
data,
several
of
the
units
used
to
establish
the
MACT
floor
have
other
air
pollution
controls
(
spray
dryers,
limestone
injection)
in
addition
to
fabric
filters.
Since
these
additional
controls
are
known
to
remove
mercury,
the
commenters
contended
that
the
resulting
MACT
floor
calculation
would
be
biased
low
because
of
these
additional
air
pollution
controls
that
are
beyond
the
floor
level
of
control.

One
commenter
(
529)
discussed
the
MACT
floor
calculated
in
the
October
2002
MACT
Floor
Analysis,
which
clearly
shows
that
individual
test
runs
from
the
same
source
were
used
to
calculate
the
MACT
floor.
The
commenter
pointed
out
that
section
112(
d)
of
the
CAA
requires
the
existing
source
MACT
floor
be
calculated
using
the
"
best
performing
12
percent
of
existing
sources"
not
the
best
performing
12
percent
of
source
tests
from
existing
sources.

Response:
As
discussed
in
the
proposal
preamble,
the
MACT
floor
analysis
for
mercury
was
based
on
a
two
step
process.
First
the
percentage
of
units
with
control
technologies
that
were
identified
that
could
achieve
mercury
emission
reductions
was
determined
using
the
boiler
population
databases.
If
the
control
technology
analysis
indicated
that
at
least
12
percent
of
88
sources
in
the
subcategory
used
a
control
device
that
could
achieve
mercury
emission
reductions,
then
the
control
technology
present
at
the
median
(
6th
percentile)
was
identified
as
the
MACT
floor
control
technology.
The
MACT
floor
level
of
control
for
mercury
was
identified
as
a
fabric
filter.
The
control
effectiveness
of
fabric
filters
was
based
on
emissions
information
for
utility
boilers
that
indicated
that
mercury
emissions
reduction
were
being
achieved
with
this
technology.
In
this
case,
we
could
use
control
efficiency
information
from
another
similar
source
category
to
supplement
the
information
available
in
this
source
category
because
of
the
similarity
in
fuel
burned,
combustor
type,
and
control
methodology
and
operation.
We
maintain
that
fabric
filters
are
still
the
appropriate
level
of
control
for
the
MACT
floor.

Second,
the
emission
limit
associated
with
the
MACT
floor
control
technology
was
calculated
using
emissions
information
for
units
in
the
subcategory,
whenever
possible.
For
most
of
the
subcategories
developed,
emissions
information
was
adequate.
Only
for
the
emission
limit
for
new
source
liquids
and
the
variability
factor
for
new
source
solids
was
fuel
pollutant
content
incorporated
into
the
MACT
floor
analyses.
The
mercury
fuel
content
of
coal
from
the
utility
industry
was
used
in
developing
the
variability
factors
for
new
solid
fired
units.
This
was
done
because
mercury
emissions
depend
on
the
quantity
of
mercury
in
the
fuel
burned.
Coal
available
to
utilities
and
industrial
boilers
and
process
heaters
are
expected
to
be
similar,
and
coal
is
the
solid
fuel
that
is
routinely
used
in
such
units
that
has
generally
the
greatest
degree
of
HAP
variability.
We
maintain
that
the
utility
database
used
at
proposal
to
develop
the
variability
factor
for
new
sources
was
adequate
in
establishing
the
MACT
floor
emission
limit.

The
EPA
recognizes
that
the
mercury
emissions
database
for
industrial
boilers
is
limited.
However,
EPA
is
directed
by
the
CAA
to
develop
standards
for
sources
using
whatever
data
is
available.
Prior
to
proposal
and
during
the
ICCR
process,
EPA
conducted
a
thorough
search
for
HAP
emission
test
reports.
This
search
was
supported
by
industry,
trade
groups,
and
States.
For
criteria
pollutants,
such
as
PM,
substantial
emission
information
was
available
and
gathered.
For
mercury
and
other
HAP,
this
was
not
the
case.
Industrial
boilers
have
not
generally
been
required
to
test
for
HAP
emissions.
In
the
proposed
rule,
EPA
requested
commenters
to
provide
additional
emissions
information.
However,
only
one
source
provided
any
additional
mercury
emissions
data.
This
information
(
test
results
from
three
additional
coal­
fired
industrial
boilers)
was
used
to
revise
the
mercury
emission
limit
for
existing
sources.
We
also
reviewed
the
mercury
emission
database
used
to
develop
the
MACT
floor
emission
limit
for
existing
sources.
After
review,
we
determined
that
a
revision
to
the
variability
factor
was
appropriate.
The
additional
data
and
the
revised
variability
factor
was
used
to
re­
calculate
the
mercury
emission
limit
to
be
0.000009
lb/
MMBtu
(
from
0.000007
lb/
MMBtu
at
proposal).

Comment:
One
commenter
(
492)
presented
the
following
from
the
MACT
Floor
Analysis
(
Docket
item
II­
B­
14):
"
The
MACT
floor
emission
level
for
mercury
is
based
on
emissions
test
information
from
units
using
fabric
filters.
Approximately
14
percent
of
the
boilers
in
the
population
database
used
scrubbers.
The
emissions
database
contains
mercury
information
on
7
different
boilers
using
scrubbers."
The
commenter
noted
that
"
scrubber"
in
the
second
and
third
sentences
should
read
"
fabric
filters."

Response:
The
EPA
thanks
the
commenter
and
will
make
the
corrections
identified.
89
Comment:
Two
commenters
(
396,
410)
questioned
EPA's
determination
of
emission
limits
for
new
liquid
fuel­
fired
units.
One
commenter
(
410)
contended
that
for
new
liquid
fuelfired
units,
EPA's
PM
and
HCl
emission
limits
are
based
on
the
average
performance
of
the
bestcontrolled
existing
unit
as
a
not
to
be
exceeded
new
source
emission
limit.
The
commenter
explained
that
by
establishing
the
new
source
emission
limitation
at
the
average
performance
level
achieved
by
the
best­
controlled
existing
source,
EPA
will
require
a
new
source
to
achieve
average
performance
much
better
than
the
average
performance
of
the
best­
controlled
existing
source
in
order
to
not
violate
the
emission
standard.
The
commenter
concluded
that
this
was
a
beyond­
thefloor
requirement
and
a
beyond­
the­
floor
requirement
for
liquid
fired
units
is
not
warranted.
Two
commenters
(
396,
410)
suggested
that
EPA
should
employ
a
more
careful
statistical
approach
to
reflect
variability,
and
must
reflect
all
the
factors
(
e.
g.,
fuel
burned,
operating
conditions,
performance
of
control
technology)
that
give
rise
to
variation
in
emissions
performance
and
set
a
standard
at
an
achievable
level
rather
than
an
average
level.
Otherwise,
even
the
best
performing
source
would
be
out
of
compliance
half
of
the
time.
One
commenter
(
410)
added
that
EPA
attempted
to
reflect
variability
only
in
fuel
burned
in
its
variability
factor,
and
this
calculation
was
not
sufficiently
statistically
based.
The
commenters
provided
examples
of
their
interpretation
of
EPA's
calculations
and
limitations.
The
commenter
recommended
that
EPA
establish
a
fuel
related
variability
factor
for
liquid
fired
units
that
reflects
a
chlorine
content
at
least
two
standard
deviations
above
the
mean
chlorine
content
of
residual
oil.

One
commenter
(
415)
stated
that
the
EPA
must
develop
a
mercury
emission
limit
for
liquid
fuel
boilers
and
process
heaters.
The
commenter
suggested
that
EPA
should
identify
the
existing
data
on
mercury
emissions
from
this
sector
and
establish
a
MACT
floor
for
mercury
emissions
from
liquid
fuel­
fired
boilers
and
process
heaters
using
that
data.

Response:
As
discussed
in
the
MACT
floor
memorandum,
there
was
no
available
emissions
test
data
for
Hcl
from
the
liquid
fuel­
fired
boilers.
Therefore,
the
available
fuel
analysis
chlorine
data
for
residual
oil
and
distillate
oil
was
identified
for
the
purposes
of
determin
a
hydrogen
chloride
emission
limit
for
new
sources
in
the
liquid
subcategory.
The
MACT
floor
emission
limit
calculations
for
Hcl
were
done
using
the
highest
residual
data
point.
Assuming
that
all
the
chlorine
in
the
fuel
would
be
emitted
as
Hcl,
the
chlorine
content
value
was
converted
to
an
uncontrolled
emission
factor.
Based
on
previous
EPA
work,
we
used
a
control
device
efficiency
of
95%
for
wet
scrubbers
(
although
many
can
achieve
as
high
as
99%
reduction)
to
control
Hcl.
We
contend
that
variability
was
adequately
incorporated
into
the
new
source
emission
limit
because
the
highest
fuel
content
point
and
an
achievable
removal
efficiency
was
used
in
the
calculation.
We
would
also
add
that
the
MACT
floor
analysis
indicated
that
there
was
not
MACT
floor
level
of
control
to
reduce
mercury
emissions
for
new
liquid
fired
units.

Comment:
One
commenter
(
413)
asserted
that
selecting
best
control
technology
for
MACT
floors
does
not
work
for
mercury
because
combustion
yields
three
forms
of
mercury
(
elemental,
gaseous
ionic,
and
particulate)
and
the
level
of
mercury
control
achieved
by
a
control
technology
depends
on
the
relative
concentrations
of
each
of
the
three
forms.
As
an
example,
the
commenter
used
a
scrubber
that
removes
gaseous
ionic
mercury,
but
does
not
remove
elemental
mercury.
The
commenter
added
that
control
efficiency
for
fabric
filters
is
greatly
affected
by
coal
chemistry
and
plant
operating
conditions.
The
commenter
explained
that
if
coal
has
a
very
low
chloride
level,
most
of
the
mercury
formed
will
be
in
the
elemental
state
and
a
fabric
filter
will
be
ineffective
in
capturing
it.
The
commenter
also
noted
that
if
a
boiler
is
operated
such
that
very
90
low
levels
of
carbon
exist
in
the
flue
gas,
then
the
ability
of
a
fabric
filter
to
capture
mercury
is
greatly
reduced.
One
commenter
(
442)
cautioned
that
the
effectiveness
of
fabric
filters
for
controlling
mercury
emissions
depends
on
the
design
of
the
whole
air
pollution
control
system.
Some
acid
gas
scrubbers
can
decrease
mercury
collection
efficiencies
of
ESPs
and
fabric
filters
by
converting
mercury
to
non­
particulate
matter
which
passes
through
the
fabric
filter.

Response:
The
EPA
recognizes
that
there
are
different
forms
of
mercury
and
not
all
forms
will
be
controlled
equally
with
every
control
technology.
However,
the
emissions
database
does
not
speciate
mercury
emissions,
so
only
total
mercury
emissions
were
considered
in
the
analysis.
Fabric
filters
were
determined
to
be
the
basis
for
the
MACT
floor
emission
limit
based
on
information
in
the
utility
boiler
standards
that
indicated
fabric
filters
can
achieve
greater
mercury
emissions
reduction
than
other
existing
add­
on
technologies.
Because
the
test
reports
did
not
speciate
mercury,
it
is
possible
that
the
mercury
emissions
information
may
incorporate
fabric
filters
that
achieve
a
range
of
control
for
the
various
mercury
forms.

The
EPA
would
like
to
clarify
that
sources
are
not
required
to
install
fabric
filters
to
meet
the
standard.
The
rule
allows
sources
to
use
any
control
technology,
including
fuel
switching,
to
meet
the
mercury
emission
limits.

Comment:
One
commenter
(
415)
said
that
the
proposed
emission
limits
for
mercury
must
be
significantly
strengthened
to
reflect
the
removal
performance
of
the
best­
performing
units
and
to
protect
public
health
and
the
environment.
The
commenter
noted
that
fabric
filters
are
capable
of
mercury
capture
efficiencies
ranging
from
72
to
90
percent.
The
commenter
expressed
concern
that
the
mercury
emission
limit
could
be
a
no
control
standard
for
mercury
because
the
limit
is
sufficiently
high
enough
that
most
boilers
would
not
be
required
to
use
additional
controls.
One
commenter
(
448)
said
that
the
proposed
emission
levels
for
mercury
do
not
meet
the
requirements
of
MACT
development
under
section
112(
d).
The
commenter
stated
that
EPA
appeared
to
have
ignored
performance
data
of
existing
control
devices,
such
as
enhanced
fabric
filters
downstream
of
an
activated
carbon
injection
device.
The
commenter
added
that
information
from
the
electric
utility
MACT
information
collection
request
and
subsequent
field
test
data
was
also
not
considered.
The
commenter
asserted
that
information
from
the
utility
standard
on
mercury
controls
would
have
provided
a
better
indication
of
control
than
the
single
emission
point
not
achieving
mercury
reductions
in
configuration
similar
to
those
used
in
municipal
waste
combustors.

Response:
We
considered
mercury
control
information
developed
in
the
utility
boiler
standard
for
the
Boiler
MACT
standard.
The
utility
boiler
information
indicated
a
much
lower
control
effectiveness
for
mercury
than
the
commenter
had
indicated.
We
requested
additional
information
in
the
proposal
preamble.
However,
none
was
provided
by
the
commenters.
Additionally,
we
do
not
have
specific
information
about
types
of
control
devices.
For
example,
we
know
a
boiler
is
equipped
with
a
fabric
filter
but
we
do
not
have
information
to
the
specific
type
of
fabric
filter.
We
did
review
carbon
injection
as
an
above
the
floor
technology
(
see
chapter
9)
but
determined
that
it
was
not
appropriate
for
the
final
rule.

Comment:
One
commenter
(
512)
argued
that
the
floor
for
new
solid
fuel­
fired
sources
should
include
carbon
injection
for
mercury
control.
The
commenter
explained
that
EPA
cannot
91
set
new
source
floors
based
solely
on
control
technologies.
The
commenter
noted
that
EPA
set
the
new
source
floor
based
on
engineering
assumptions
about
the
control
efficiency
of
certain
control
technologies
(
i.
e.,
the
best
controlled)
but
did
not
select
the
lowest
emitting
(
i.
e.,
the
best
performing)
sources.
If
EPA
correctly
used
this
methodology,
the
commenter
argued
that
it
should
have
selected
carbon
injection
as
the
floor
for
new
units
because
one
unit
uses
this
technology
and
EPA
has
noted
that
carbon
injection
is
capable
of
achieving
high
mercury
reductions
in
other
categories
(
e.
g.,
incinerators)
and
it
is
expected
to
be
the
control
technology
of
choice
for
reducing
mercury
from
coal­
fired
utility
boilers.
The
commenter
noted
that
not
all
boilers
and
process
heaters
using
fabric
filters
have
the
lowest
emissions,
yet
EPA
selected
this
technology
for
the
basis
of
the
MACT
floor
based
on
knowledge
that
it
could
perform
to
high
levels.
Therefore,
it
does
not
matter
that
the
unit
using
carbon
injection
is
not
the
lowest­
emitting
source;
the
fact
that
one
source
is
using
the
best
technology
for
mercury
control
should
lead
EPA
to
select
carbon
injection
as
the
MACT
floor
for
new
sources.
One
commenter
(
390)
contended
that
the
MACT
floor
for
new
units
reflects
the
mercury
control
benefits
of
systems
installed
under
the
NSPS
and
not
on
what
the
EPA
speculates
may
become
available
in
the
future.

Response:
As
discussed
in
the
proposal
preamble,
we
identified
one
existing
industrial
boiler
that
was
using
carbon
injection.
However,
the
emissions
data
that
we
obtained
from
the
boiler
indicated
that
this
unit
was
not
achieving
mercury
emission
reduction.
This
result
led
us
to
conclude
that
it
was
not
the
new
source
floor
level
of
control.
We
considered
carbon
injection
as
a
beyond­
the­
floor
option,
but
decided
that
while
this
control
technique
has
been
used
in
other
source
categories,
there
is
no
demonstrated
evidence
that
it
would
work
for
industrial
boilers
and
process
heaters
because
the
type
of
mercury
emitted
and
properties
of
the
emission
streams
are
sufficiently
different
for
boilers
and
process
heaters
and
other
source
categories.
For
fabric
filters,
we
had
some
emissions
information
for
utility
boilers
that
indicated
that
mercury
emissions
reduction
were
being
achieved
with
this
technology.
In
this
case,
we
could
confidently
use
control
efficiency
information
from
another
similar
source
category
to
supplement
the
information
available
in
this
source
category.
Unlike
fabric
filters,
the
available
emissions
information
indicated
that
carbon
injection
was
not
effective
for
industrial
boilers
and
process
heaters.

Comment:
One
commenter
(
492)
stated
that
EPA
must
demonstrate
that
a
source
(
or
sources,
in
the
case
of
the
existing
source
standard)
is
actually
achieving
the
standard
established.
The
commenter
noted
that
EPA
recognized
that
certain
fuels,
while
providing
decreased
emissions
for
some
HAP,
may
contribute
to
higher
emissions
in
other
types
of
HAP
(
i.
e.,
gaseous
fuels
may
have
low
PM
and
metal
emissions,
but
may
have
higher
organic
HAP
emissions
than
solid
fuels).
The
commenter
was
concerned
that
EPA,
in
establishing
emission
limits
or
when
conducting
the
floor
evaluation,
has
not
considered
whether
the
best
performing
sources
can
achieve
the
emissions
limitations
in
the
aggregate.
The
commenter
noted
that
section
112(
d)
of
the
CAA
requires
EPA
to
establish
standards
that
are
duplicable
by
others.
Some
of
the
best
units
may
be
achieving
low
emissions
based
on
methods
that
are
not
available
to
other
units
within
the
source
category
or
subcategory.
The
commenter
believes
that
this
requires
the
EPA
to
the
following:
(
1)
discover
how
these
sources
actually
are
"
controlling"
emissions,
and
(
2)
set
standards
that
are
achievable
through
application
of
various
measures,
techniques,
methods
or
processes.

The
commenter
(
492)
stated
that
the
floor
methodology
must
provide
a
reasonable
92
estimate
of
what
the
best
performers
achieve,
regardless
of
which
method
EPA
uses.
The
commenter
noted
recent
court
decisions
that
criticize
EPA
for
not
determining
a
reasonable
estimate
of
the
best
performers
based
on
all
of
the
factors
that
affected
emissions
for
a
particular
rule.

Response:
We
disagree
with
the
commenter.
The
emission
test
database
and
population
database
show
that
there
is
at
least
one
source
with
the
MACT
floor
control
technologies
required
in
the
proposed
and
final
rule.
Additionally,
we
received
4
test
reports
after
proposal
(
which
are
now
in
the
docket)
from
emission
tests
conducted
at
a
boiler
in
Michigan
State
University.
The
reports
also
show
that
the
source
utilizes
the
MACT
floor
levels
of
control
identified
in
the
rule.

Comment:
One
commenter
(
451)
contended
that
EPA
may
not
use
control
technology
as
the
basis
for
the
MACT
floor
since
other
factors
(
e.
g.,
type
of
fuel
combusted)
affect
HAP
emission
levels.
The
commenter
stated
that
the
MACT
floor
should
reflect
the
emission
levels
actually
achieved
by
the
"
best­
performing"
sources,
regardless
of
how
the
emission
levels
are
achieved
(
e.
g.,
through
add­
on
controls,
cleaner
fuels).
One
commenter
(
415)
said
that
the
approach
used
by
EPA
in
establishing
the
MACT
floor
for
the
boilers
NESHAP
is
not
consistent
with
recent
legal
decisions
(
Cement
Kiln
Recycling
Coalition
v.
EPA,
255
F.
3d
855,
865
(
D.
C.
Cir.
2001).
The
commenter
stated
that
the
MACT
floor
should
be
based
on
actual
emissions
of
the
relevant
best­
performing
sources,
rather
than
specific
technologies
in
use.
The
commenter
added
that
in
some
cases
lower
emissions
may
be
achieved
by
a
combination
of
lower
emission
fuels,
operational
parameters,
or
other
means
separate
from
or
in
addition
to
end­
of­
stack
controls.

Response:
First,
we
believe
the
MACT
floor
methodology
we
use
is
consistent
with
D.
C.
Circuit's
holding
in
the
National
Lime
case.
The
D.
C.
Circuit
held
that
by
focusing
only
on
technology
EPA
ignored
the
directive
in
section
112(
d)(
2)
to
consider
pollution­
reducing
measures
including
process
changes
and
substitution
of
materials.

The
EPA
agrees
with
the
commenter
that
all
factors
which
might
control
HAP
emissions
must
be
considered
in
making
a
floor
determination
for
each
subcategory.
However,
EPA
disagrees
that
it
must
express
the
floor
as
a
quantitative
emission
level
in
those
instances
where
the
source
on
which
the
floor
determination
is
based
has
not
adopted
or
implemented
any
measure
that
would
reduce
emissions.

A
detailed
discussion
of
the
MACT
floor
methodology
is
presented
in
the
memorandum
"
MACT
Floor
Analysis
for
New
and
Existing
Sources
in
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
Source
Categories"
in
the
docket.
In
summary,
we
considered
several
approaches
to
identifying
MACT
floor
for
existing
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Based
on
recent
court
decisions,
in
most
cases
the
most
acceptable
approach
for
determining
the
MACT
floor
is
likely
to
involve
primarily
the
consideration
of
available
emissions
test
data.
However,
after
review
of
the
available
HAP
emission
test
data,
we
determined
that
it
was
inappropriate
to
use
this
MACT
floor
approach
to
establish
emission
limits
for
boilers
and
process
heaters.
The
main
problem
with
using
only
the
HAP
emissions
data
is
that,
based
on
the
test
data
alone,
uncontrolled
units
(
or
units
with
low
efficiency
add­
on
controls)
were
frequently
identified
as
being
among
the
best
performing
12
percent
of
sources
in
a
subcategory,
while
many
units
with
high
efficiency
controls
were
not.
93
However,
these
uncontrolled
or
poorly
controlled
units
are
not
truly
among
the
best
controlled
units
in
the
category.
Rather,
the
emissions
from
these
units
are
relatively
low
because
of
particular
characteristics
of
the
fuel
that
they
burn,
that
can
not
reasonably
be
replicated
by
other
units
in
the
category
or
subcategory.
A
review
of
fuel
analyses
indicate
that
the
concentration
of
HAP
(
metals,
HCl,
mercury)
vary
greatly,
not
only
between
fuel
types,
but
also
within
each
fuel
type.
Therefore,
a
unit
without
any
add­
on
controls,
but
burning
a
fuel
containing
lower
amounts
of
HAP,
can
have
emission
levels
that
are
lower
than
the
emissions
from
a
unit
with
the
best
available
add­
on
controls.
If
only
the
available
HAP
emissions
data
are
used,
the
resulting
MACT
floor
levels
would,
in
most
cases,
be
unachievable
for
many,
if
not
most,
existing
units,
even
those
that
employ
the
most
effective
available
emission
control
technology.
Another
problem
with
using
only
emissions
data
is
that
there
is
very
limited
or
no
HAP
emissions
information
available
to
the
Agency
for
the
subcategories.
This
is
consistent
with
the
fact
that
units
in
these
source
categories
have
not
historically
been
required
to
test
for
HAP
emissions.

We
also
considered
using
HAP
emission
limits
contained
in
State
regulations
and
permits
as
a
surrogate
for
actual
emission
data
in
order
to
identify
the
emissions
levels
from
the
best
performing
units
in
the
category
for
purposes
of
establishing
MACT
standards.
However,
we
found
no
State
regulations
or
State
permits
which
specifically
limit
HAP
emissions
from
these
sources.

Consequently,
we
concluded
that
the
most
appropriate
approach
for
determining
MACT
floors
for
boilers
and
process
heaters
is
to
look
at
the
control
options
used
by
the
units
within
each
subcategory
in
order
to
identify
the
best
performing
units.
Information
was
available
regarding
the
emission
control
options
employed
by
the
population
of
boilers
identified
by
the
EPA.
We
considered
several
possible
control
controls
(
i.
e.,
factors
that
influence
emissions),
including
fuel
substitution,
process
changes
and
work
practices,
and
add­
on
control
technologies.
We
first
considered
whether
fuel
switching
would
be
an
appropriate
control
option
for
sources
in
each
subcategory.
We
considered
the
feasibility
of
both
fuel
switching
to
other
fuels
used
in
the
subcategory
and
to
fuels
from
other
subcategories
were
considered.
This
consideration
included
determining
whether
switching
fuels
would
achieve
lower
HAP
emissions.
A
second
consideration
was
whether
fuel
switching
could
be
technically
achieved
by
boilers
and
process
heaters
in
the
subcategory
considering
the
existing
design
of
boilers
and
process
heaters.
We
also
considered
the
availability
of
various
types
of
fuel.
After
considering
these
factors,
we
determined
that
fuel
switching
was
not
an
appropriate
control
technology
for
purposes
of
determining
the
MACT
floor
level
of
control
for
any
subcategory.
This
decision
was
based
on
the
overall
effect
of
fuel
switching
on
HAP
emissions,
technical
and
design
considerations,
and
concerns
about
fuel
availability.

We
also
concluded
that
process
changes
or
work
practices
were
not
appropriate
criteria
for
identifying
the
MACT
floor
level
of
control
for
units
in
the
boilers
and
process
heaters
category.
The
HAP
emissions
from
boilers
and
process
heaters
are
either
fuel
dependent
(
i.
e.,
mercury,
metals,
and
inorganic
HAP)
or
combustion
related
(
i.
e.,
organic
HAP).
Fuel
dependent
HAP
are
typically
controlled
by
removing
them
from
the
flue
gas
after
combustion.
Therefore,
they
are
not
affected
by
the
operation
of
the
boiler
or
process
heater.
Consequently,
process
changes
would
be
ineffective
in
reducing
these
fuel­
related
HAP
emissions.

On
the
other
hand,
organic
HAP
can
be
formed
from
incomplete
combustion
of
the
fuel.
Good
combustion
practice
(
GCP),
in
terms
of
boilers
and
process
heaters,
could
be
defined
as
the
system
design
and
work
practices
expected
to
minimize
organic
HAP
emissions.
While
few
94
sources
in
EPA's
database
specifically
reported
using
good
combustion
practices,
the
data
that
we
have
suggests
that
boilers
and
process
heaters
within
each
subcategory
might
use
any
of
a
wide
variety
of
different
work
practices,
depending
on
the
characteristics
of
the
individual
unit.
The
lack
of
information,
and
lack
of
a
uniform
approach
to
assuring
combustion
efficiency,
is
not
surprising
given
the
extreme
diversity
of
boilers
and
process
heaters,
and
given
the
fact
that
no
applicable
Federal
standards,
and
most
applicable
State
standards,
do
not
include
work
practice
requirements
for
boilers
and
process
heaters.
Even
those
States
that
do
have
such
requirements
do
not
require
the
same
work
practices.
For
example,
CO
emissions
are
generally
a
good
indicator
of
incomplete
combustion,
and,
therefore,
low
CO
emissions
might
reflect
good
combustion
practices.
(
As
discussed
in
the
proposal,
CO
is
considered
a
surrogate
for
organic
HAP
emissions.)
Therefore,
we
considered
whether
existing
CO
emission
limits
might
be
used
to
establish
good
combustion
practice
standards
for
boilers
and
process
heaters.
We
reviewed
State
regulations
applicable
to
boilers
and
process
heaters,
and
then
for
each
subcategory
we
matched
the
applicability
of
State
CO
emission
limits
with
information
on
the
locations
and
characteristics
of
the
boilers
and
process
heaters
in
the
population
database.
Ultimately,
we
found
that
very
few
units
(
less
than
6
percent)
in
any
subcategory
were
subject
to
CO
emission
limits.
We
concluded
that
this
information
did
not
allow
EPA
to
identify
a
level
of
performance
that
was
representative
of
good
combustion
across
the
various
units
in
any
subcategory.
Therefore,
we
did
not
establish
a
CO
emission
limit,
as
a
surrogate
for
organic
HAP
emissions,
as
a
part
of
the
MACT
floor
for
existing
units.
However,
we
have
considered
the
appropriateness
of
such
requirements
in
the
context
of
evaluation
possible
beyond­
the­
floor
options.

In
general,
boilers
and
process
heaters
are
designed
for
good
combustion.
Facilities
have
an
economic
incentive
to
ensure
that
fuel
is
not
wasted,
and
the
combustion
device
operates
properly
and
is
appropriately
maintained.
In
fact,
existing
boilers
and
process
heaters
are
used
typically
as
high
efficiency
control
devices
to
control
(
reduce)
emission
streams
containing
organic
HAP
compounds
from
various
process
operations.
Therefore,
EPA's
inability
to
establish
a
combustion
practice
requirement
as
part
of
the
MACT
floor
for
existing
sources
in
this
category
should
not
reduce
the
incentive
for
owners
and
operators
to
run
their
boilers
and
process
heaters
at
top
efficiency.

As
a
result
of
the
evaluation
of
the
feasibility
of
establishing
emission
limits
based
on
control
techniques
such
as
fuel
switching
and
good
combustion
practices,
we
concluded
that
addon
control
technology
should
be
the
primary
factor
for
purposes
of
identifying
the
best
controlled
units
within
each
subcategory
of
boilers
and
process
heaters.
We
identified
the
types
of
air
pollution
control
techniques
currently
used.
We
ranked
those
controls
according
to
their
effectiveness
in
removing
the
different
HAP
categories
of
pollutants;
including
metallic
HAP
and
PM,
inorganic
HAP
such
as
acid
gases,
mercury,
and
organic
HAP.
We
then
listed
all
the
boilers
and
process
heaters
in
the
population
database
in
order
of
decreasing
control
device
effectiveness
within
each
subcategory
for
each
pollutant
type.
Then
we
identified
the
top
12
percent
of
units
within
each
category
based
on
this
ranking,
and
determined
what
kind
of
emission
control
technology,
or
combination
of
technologies,
the
units
in
the
top
12
percent
employed.
Finally,
we
looked
at
the
emissions
test
data
from
boilers
and
process
heaters
that
used
the
same
control
technology,
or
technologies,
as
the
units
in
the
top
12
percent
to
estimate
the
average
emissions
limitation
achieved
by
the
these
units.

This
approach
reasonably
ensures
that
the
emission
limit
selected
as
the
MACT
floor
adequately
represents
the
average
level
of
control
actually
achieved
by
units
in
the
top
12
percent.
95
The
analysis
of
the
measured
emissions
from
units
representative
of
the
top
12
percent
is
reasonably
designed
to
provide
a
meaningful
estimate
of
the
average
performance,
or
central
tendency,
of
the
best
controlled
12
percent
of
units
in
a
given
subcategory.
For
existing
subcategories
where
less
than
12
percent
of
units
in
the
subcategory
use
any
type
of
control
technology,
we
looked
to
see
if
we
could
estimate
the
central
tendency
of
the
best
controlled
units
by
looking
at
the
unit
occupying
the
median
point
in
the
top
12
percent
(
the
unit
at
the
94th
percentile).
If
the
median
unit
of
the
top
12
percent
is
using
some
control
technology,
we
might
use
the
measured
emission
performance
of
that
individual
unit
as
the
basis
for
estimating
an
appropriate
average
level
of
control
of
the
top
12
percent.
For
subcategories
were
less
than
6
percent
of
the
units
in
a
HAP
grouping
used
controls
or
limited
emissions,
the
median
unit
for
that
HAP
grouping
reflects
no
emissions
reduction.
Therefore,
in
these
circumstances,
EPA
believes
that
it
has
appropriately
established
the
MACT
floor
emission
levels
for
these
sources
as
no
emission
reduction.

Comment:
One
commenter
(
512)
argued
that
EPA's
approach
to
setting
MACT
floors
for
existing
sources
is
fundamentally
flawed.
The
commenter
explained
that
none
of
the
floors
set
by
EPA
reflect
the
actual
emissions
of
the
best
performing
sources
but
were
based
on
the
assumed
control
efficiency
of
add­
on
controls.
The
commenter
noted
that
EPA
admitted
that
many
factors
influence
emissions,
not
just
control
equipment,
and
that
the
available
data
show
that
some
sources
are
performing
better
than
the
floor.
The
commenter
also
noted
that
Congress
required
EPA
to
set
MACT
emission
standards
based
on
the
performance
of
"
sources,"
not
simply
the
"
technology
system"
and
cautioned
that
EPA
should
not
rely
on
data
from
sources
that
are
not
among
the
top
12
percent
when
determining
standards
or
variability.
The
commenter
added
that
if
EPA
is
concerned
that
the
existing
sources
may
not
be
able
to
meet
MACT
emission
standards
under
all
relevant
conditions,
it
should
develop
a
targeted
variability
factor
that
is
based
on
performance
fluctuations
of
the
top
12
percent
sources
and
which
accounts
for
factors
other
than
MACT
technology
that
influence
source
performance.
The
commenter
contended
that
under
no
circumstance
should
EPA
rely
on
the
data
from
sources
that
are
not
among
the
top
12
percent
when
determining
performance
standards
or
variability.

Three
commenters
(
343,
479,
492)
supported
EPA's
approach
to
establishing
the
MACT
floors
for
boilers
and
process
heaters.
Two
commenters
(
479,
492)
specifically
supported
the
method
of
using
both
control
technologies
and
emissions
data
to
establish
MACT
floors.
One
commenter
(
343)
agreed
with
EPA
that
using
HAP
emissions
data
alone
is
not
appropriate
since
uncontrolled
units
may
have
lower
emissions
than
controlled
units
due
to
fuel
characteristics
and
that
HAP
emissions
from
boilers
and
process
heaters
are
primarily
dependent
upon
the
composition
of
the
fuel.
In
addition,
the
commenter
stated
EPA's
approach
of
developing
subcategories
based
on
fuel
used,
unit
size,
and
evaluating
control
options
used
by
the
units
within
each
subcategory
to
determine
the
MACT
floor
is
most
appropriate.
One
commenter
(
492)
expressed
that,
for
a
source
category
as
large
and
diverse
as
this
one,
add­
on
technology
is
the
most
viable
way
of
accounting
for
variability.
Two
commenters
(
479,
492)
noted
that
the
approach
that
EPA
used
to
determine
the
MACT
floor
in
this
proposal
is
not
countramanded
by
the
holding
in
the
Cement
Kiln
ruling.
The
commenters
explained
that
EPA
used
the
emission
data
from
the
best
performing
12
percent
of
the
sources
as
opposed
to
the
worst
source
using
the
MACT
control.

Response:
As
discussed
in
the
proposal
preamble,
the
MACT
floor
analysis
was
based
on
96
a
two
step
process.
First
the
percentage
of
units
with
control
technologies
that
could
achieve
mercury
emissions
reductions
was
determined
using
the
boiler
population
databases.
We
identified
the
types
of
air
pollution
control
techniques
currently
used.
We
ranked
those
controls
according
to
their
effectiveness
in
removing
the
different
HAP
categories
of
pollutants;
including
metallic
HAP
and
PM,
inorganic
HAP
such
as
acid
gases,
mercury,
and
organic
HAP.
We
then
listed
all
the
boilers
and
process
heaters
in
the
population
database
in
order
of
decreasing
control
device
effectiveness
within
each
subcategory
for
each
pollutant
type.
Then
we
identified
the
top
12
percent
of
units
within
each
category
based
on
this
ranking,
and
determined
what
kind
of
emission
control
technology,
or
combination
of
technologies,
the
units
in
the
top
12
percent
employed.
Second,
we
looked
at
the
emissions
test
data
from
boilers
and
process
heaters
that
used
the
same
control
technology,
or
technologies,
as
the
units
in
the
top
12
percent
to
estimate
the
average
emissions
limitation
achieved
by
the
these
units.

This
approach
reasonably
ensures
that
the
emission
limit
selected
as
the
MACT
floor
adequately
represents
the
average
level
of
control
actually
achieved
by
units
in
the
top
12
percent.
The
analysis
of
the
measured
emissions
from
units
representative
of
the
top
12
percent
is
reasonably
designed
to
provide
a
meaningful
estimate
of
the
average
performance,
or
central
tendency,
of
the
best
controlled
12
percent
of
units
in
a
given
subcategory.
For
existing
subcategories
where
less
than
12
percent
of
units
in
the
subcategory
use
any
type
of
control
technology,
we
looked
to
see
if
we
could
estimate
the
central
tendency
of
the
best
controlled
units
by
looking
at
the
unit
occupying
the
median
point
in
the
top
12
percent
(
the
unit
at
the
94th
percentile).
If
the
median
unit
of
the
top
12
percent
is
using
some
control
technology,
we
might
use
the
measured
emission
performance
of
that
individual
unit
as
the
basis
for
estimating
an
appropriate
average
level
of
control
of
the
top
12
percent.

Comment:
Several
commenters
(
348,
388,
401,
449,
492,
498,
524,
533
)
opposed
the
use
of
emissions
data
from
large
units
to
establish
the
MACT
floor
for
small
and
limited
use
units.
One
commenter
(
401)
stated
that
it
was
not
appropriate
to
assume
that
emissions
rates
achievable
by
large
units
are
achievable
by
small
units,
even
the
best
controlled
units.
Several
commenters
(
388,
449,
498,
524,
533)
argued
that
the
use
of
large
unit
data
in
MACT
determinations
for
other
subcategories
would
defeat
the
purpose
of
the
subcategorization
and
violate
the
requirements
of
section
112
because
the
use
of
this
data
does
not
represent
sources
in
the
relevant
category
or
subcategory.
Furthermore,
the
commenters
noted
that
most
existing
State
and
Federal
regulations
do
not
regulate
units
less
than
10
MMBtu/
hr
due
to
their
low
emissions
and
extension
of
emission
data
from
larger
sources
ignores
that
lack
of
regulation.
One
commenter
(
348)
questioned
the
use
of
the
MACT
floor
database
for
smaller
units
because
it
does
not
contain
data
from
smaller
units.

Response:
The
EPA
disagrees
with
the
commenters
and
maintains
that
it
has
conducted
the
MACT
floor
analysis
appropriately.
First,
EPA
calculated
the
control
technology
used
by
the
best
controlled
12
percent
of
sources
in
the
subcategory.
For
example,
only
units
in
the
population
database
less
than
10
MMBtu/
hr
(
and
not
in
the
limited
use
subcategory)
were
used
to
determine
the
MACT
floor
control
technology
for
units
in
the
small
subcategories.
Second,
EPA
used
information
in
the
emissions
test
database
to
calculate
the
emission
level
associated
with
the
MACT
floor
control
technology.
The
emissions
test
database
did
not
contain
test
data
for
limited
use
or
small
boilers
and
process
heaters.
The
EPA's
interpretation
of
section
___
of
the
CAA
allows
EPA
to
use
information
from
similar
sources
to
set
the
MACT
floor
when
no
information
97
from
the
subcategory
is
available.
Although
the
units
in
the
small
and
limited
use
subcategories
are
different
enough
to
warrant
their
own
subcategory
(
i.
e.,
different
purposes
and
operation),
emissions
of
the
specific
types
of
HAP
for
which
limits
are
being
proposed
are
expected
to
be
related
more
to
the
type
of
fuel
burned
and
the
type
of
control
used,
than
to
unit
operation.
Consequently,
EPA
determined
that
emissions
information
from
large
fuel
fired
units
could
be
mused
to
establish
MACT
floor
levels
for
the
small
and
limited
use
subcategories
because
the
fuels
and
controls
are
similar.
The
proposal
preamble
requested
additional
information
from
commenters
to
refine/
revise
the
approach
if
necessary.
No
commenters
provided
emissions
information
for
limited
use
or
small
subcategory
boilers
or
process
heaters.

Comment:
Several
commenters
(
374,
382,
388,
449,
492,
498,
524,
533)
believe
that
new
distillate
oil
fuel­
fired
boilers
and
process
heaters
should
be
exempt
from
PM
and
HCl
emission
limit
requirements
in
addition
to
other
rule
requirements.
Several
commenters
(
382,
388,
449,
498,
524,
533)
noted
that
EPA
has
generally
treated
distillate
oil
on
par
with
natural
gas
relative
to
emission
requirements
and
that
no
basis
for
imposing
these
emission
limits
exists.
Commenters
explained
that
EPA
already
recognizes
the
lower
emissions
of
these
units
since
it
does
not
require
emission
testing.
However,
commenters
noted
that
units
will
be
required
to
demonstrate
compliance
with
the
emission
limits
in
their
operating
permit
even
if
EPA
does
not
require
testing
in
the
boilers
NESHAP.
The
commenters
(
382,
388,
449,
492,
498,
524,
533)
contended
that
a
regulatory
rationale
does
not
exist
for
concluding
PM
and
HCl
emissions
are
controlled
in
liquid
fuel­
fired
units
other
than
those
firing
residual
oils.
Since
there
are
no
units
within
the
emissions
database
that
are
firing
distillate
oil
or
diesel
oil
that
are
equipped
with
any
PM
or
HCl
controls
or
emissions
test
data
for
these
pollutants,
commenters
(
492,
382)
argued
that
EPA
apparently
has
arbitrarily
imposed
emission
limits
that
are
based
on
firing
residual
oil
on
units
fired
with
distillate
oil.
The
commenter
(
492)
also
noted
that
emissions
from
distillate
oil­
fired
units
are
inherent
with
the
units
and
the
fuel.
Hydrogen
chloride
emissions
are
a
function
of
the
fuel
chloride
content,
which
is
not
a
detailed
requirement
in
ASTM
oil
specifications.
Furthermore,
the
commenter
argued
that
emissions
limitations
serve
no
regulatory
purpose
if
there
is
no
mechanism
for
control.
The
commenter
concluded
by
pointing
out
that
PM
and
HCl
emissions
from
distillate
oil­
fired
units
are
very
low
and
are
not
controllable
by
the
source,
so
that
they
could
legitimately
be
considered
de
minimis.
Several
commenters
(
374,
382,
388,
449,
498,
524,
533)
suggested
that
these
units
should
only
have
to
comply
with
the
initial
notification
requirements
in
the
general
provisions
(
40
CFR
part
63,
subpart
A).

Response:
Units
firing
distillate
fuel
are
still
included
in
the
liquid
subcategory.
As
such
they
are
subject
to
the
emission
limits
that
are
applicable
to
liquid
fuel
fired
units.
However,
we
do
recognize
that
emissions
from
firing
distillate
oil
are
lower
than
from
firing
residual
oil,
and
reflect
this
in
the
rule.
Units
firing
only
distillate
oil
are
only
required
to
submit
a
signed
statement
that
they
fire
distillate
oil,
and
are
not
subject
to
testing
or
monitoring
requirements.
98
9.0
OPTIONS
BEYOND
THE
MACT
FLOOR
9.1
General
Comment:
Several
commenters
(
376,
393,
491,
536)
supported
the
EPA's
proposal
not
to
require
beyond­
the­
floor
MACT
standards
for
any
subcategories.
One
commenter
(
393)
urged
EPA
to
set
the
MACT
standards
equal
to
the
MACT
floors
for
each
subcategory.
One
commenter
(
491)
supported
EPA's
decision
to
set
the
emissions
limitations
at
the
MACT
floor
and
not
establish
emission
standards
beyond
the
floor.
The
commenter
stated
that
the
standard
can
be
achieved
by
most
existing
sources
in
the
source
category
in
a
cost
effective
manner
and
the
standard
will
provide
a
sufficient
level
of
emission
controls
to
adequately
protect
the
public
and
the
environment.
One
commenter
(
390)
urged
the
EPA
to
carefully
assess
the
costs
and
actual
availability
of
any
beyond­
the­
floor
control
technologies
not
commercially
available.
The
commenter
added
that
any
further
control
beyond­
the­
floor,
based
on
the
EPA
Utility
and
Mercury
Study,
will
have
little
incremental
effect
on
public
health
while
proving
very
costly.

Two
commenters
(
512,
527)
argued
that
EPA
could
achieve
more
emission
reductions
from
this
source
category
through
this
standard.
One
commenter
(
527)
stated
that
EPA
concluded
that
most
beyond­
the­
floor
options
for
existing
units
would
further
reduce
emissions
but
the
cost
would
be
too
high
to
consider
it
a
feasible
beyond
the
floor
option.
The
commenter
stated
that
the
impact
of
this
rationale
is
the
missed
opportunity
to
remove
hundreds
of
tons
of
hazardous
air
pollutants
(
HAP)
emitted
directly
into
the
air
each
year
by
the
affected
sources
in
this
industry.
The
commenter
stated
that
this
not
a
question
as
to
the
availability
of
control
and
measurement
options,
but
rather,
EPA's
gauge
of
what
if
any
cost
is
deemed
acceptable.
One
commenter
(
512)
argued
that
EPA's
database
indicates
substantially
lower
emissions
are
achievable
for
this
source
category
and
that
further
reductions
should
be
evaluated
as
part
of
a
beyond­
the­
floor
analysis.

Response:
For
the
final
rule,
EPA
maintains
that
options
beyond
the
MACT
floor
are
not
appropriate
for
the
standard.
The
EPA
is
required
by
the
Clean
Air
Act
(
CAA)
to
set
the
standard
at
a
minimum
on
the
best
controlled
12
percent
of
sources
(
for
existing
units)
or
best
controlled
source
(
for
new
units).
The
CAA
also
requires
EPA
to
consider
costs
and
non­
air
quality
impacts
and
energy
requirements
when
considering
more
stringent
requirements
than
the
MACT
floor.
EPA
did
consider
the
cost
and
emission
impacts
of
a
variety
of
regulatory
options
more
stringent
than
the
MACT
floor
for
each
subcategory.
The
EPA
recognizes
that
for
some
subcategories,
more
stringent
controls
than
the
MACT
floor
can
be
applied
and
achieve
additional
emission
reductions.
However,
EPA
also
determined
that
the
cost
impacts
of
such
controls
were
very
high.
Considering
both
the
costs
and
emission
reductions,
EPA
determined
that
it
would
be
infeasible
to
require
any
options
more
stringent
than
the
floor
level.

9.2
Carbon
Injection
Comment:
Several
commenters
(
364,
376,
387,
388,
393,
399,
406,
407,
408,
413,
446,
447,
449,
452,
492,
498,
501,
519,
524,
533)
supported
EPA's
decision
not
to
require
activated
carbon
injection
as
an
"
above
the
floor"
technology.
Some
commenters
(
364,
387,
388,
393,
399,
413,
449,
492,
498,
524,
533,
536)
explained
that
consideration
of
the
use
of
activated
carbon
99
injection
has
issues
including:
1)
insufficient
data
on
the
effectiveness
of
carbon
injection
for
this
source
category;
2)
the
reductions
indicated
from
data
outside
of
this
source
category
vary
greatly
with
boiler
type
and
fuel
source;
3)
contamination
of
fly
ash
such
that
it
cannot
be
beneficially
reused
for
various
byproducts;
4)
catastrophic
foaming
in
plants
with
wet
flue
gas
desulfurization;
and
5)
its
use
is
prohibitively
expensive
when
compared
to
what
EPA
considers
reasonable
for
beyond
the
floor
costs.
Other
commenters
(
393,
406,
407,
408,
413,
447,
501,
519)
noted
that
activated
carbon
injection
has
not
yet
been
proven
as
a
commercially
viable
option
for
mercury
control.

Some
commenters
(
415,
451,
527
)
expressed
concern
that
EPA
did
not
propose
to
require
activated
carbon
injection.
One
commenter
(
451)
contended
that
EPA
neglected
to
consider
the
high
emission
reduction
levels
that
can
be
achieved
through
carbon
injection.
As
a
result,
the
commenter
argued
that
EPA
neglected
to
consider
that
it
may
be
possible
for
coal
burning
units
to
match
the
mercury
emissions
performance
of
wood
fired
units.
Another
commenter
(
415)
argued
that
the
single
emission
test
of
the
industrial
boiler
using
activated
carbon
was
not
representative.
Two
commenters
(
415,
527)
argued
that
EPA
should
consider
the
well­
documented
success
of
activated
carbon
injection
for
the
control
of
mercury
from
other
combustion
sources
including
incinerators,
waste­
to­
energy
facilities,
and
electric
power
facilities.
One
commenter
(
527)
stated
that
the
approach
to
control
mercury
in
this
rule
appears
to
ignore
the
wealth
of
data
and
information
that
is
currently
available
to
control
mercury
from
similar
flue
gas
streams.
The
commenter
stated
that
despite
fuel
and
process
differences
and
therefore
potential
differences
in
the
control
options
that
might
be
selected,
there
are
often
substantial
similarities
between
the
different
industries
in
the
design,
operation,
and
flue
gas
stream
characteristics,
and
therefore
the
general
availability
of
similar
control
options.

Response:
For
the
final
rule,
EPA
maintains
that
options
beyond
the
MACT
floor
are
not
appropriate
for
the
standard.
The
EPA
is
required
by
the
CAA
to
set
the
standard
at
a
minimum
on
the
best
controlled
12
percent
of
sources
(
for
existing
units)
or
best
controlled
source
(
for
new
units).
The
CAA
also
requires
EPA
to
consider
costs
and
non­
air
quality
impacts
and
energy
requirements
when
considering
more
stringent
requirements
than
the
MACT
floor.
As
documented
in
the
memorandum
"
Methodology
for
Estimating
Costs
and
Emissions
Impacts
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants"
in
the
docket,
EPA
did
consider
the
cost
and
emission
impacts
of
a
variety
of
regulatory
options
more
stringent
than
the
MACT
floor
for
each
subcategory.
The
EPA
recognizes
that
for
some
subcategories,
more
stringent
controls
than
the
MACT
floor
can
be
applied
and
achieve
additional
emission
reductions.
However,
EPA
also
determined
that
the
cost
impacts
of
such
controls
were
very
high.
Considering
both
the
costs
and
emission
reductions,
EPA
determined
that
it
would
be
infeasible
to
require
any
options
more
stringent
than
the
floor
level.

For
the
final
rule,
EPA
maintains
that
carbon
injection
should
not
be
required
as
an
above
the
floor
technology.
As
discussed
in
the
proposal
preamble,
we
identified
one
existing
industrial
boiler
that
was
using
carbon
injection.
The
emissions
data
that
we
obtained
from
the
boiler
indicated
that
this
carbon
injection
unit
was
not
achieving
mercury
emissions
reductions.
This
result
led
us
to
conclude
that
it
was
not
the
new
source
floor
level
of
control.
However,
there
may
have
been
other
reasons
for
the
ineffectiveness
of
this
system
(
e.
g.,
low
inlet
mercury
levels,
insufficient
carbon
injection
rate,
ESP
instead
of
fabric
filter
for
PM
control).
Therefore,
we
considered
carbon
injection
as
a
beyond­
the­
floor
option,
but
decided
that
while
this
control
100
technique
has
been
used
in
other
source
categories,
there
is
no
demonstrated
evidence
that
it
would
work
for
industrial
boilers
and
process
heaters
because
the
type
of
mercury
emitted
and
properties
of
the
emission
streams
are
sufficiently
different
for
boilers
and
process
heaters
and
other
source
categories.
For
fabric
filters,
we
had
some
emissions
information
for
utility
boilers
that
indicated
that
mercury
emissions
reductions
were
being
achieved
with
this
technology.
In
this
case,
we
could
confidently
use
control
efficiency
information
from
another
similar
source
category
to
supplement
the
information
available
in
this
source
category.
Unlike
fabric
filters,
the
available
emissions
information
indicated
that
carbon
injection
was
not
effective
for
industrial
boilers
and
process
heaters.

9.3
Fuel
Switching
Comment:
Several
commenters
(
364,
381,
382,
387,
388,
391,
392,
399,
403,
410,
413,
444,
447,
449,
479,
492,
498,
519,
524,
533,
536)
supported
EPA's
conclusion
that
fuel
switching
is
not
a
viable
regulatory
option
for
setting
the
MACT
floor
or
considering
beyond­
thefloor
options.
In
support
of
EPA's
conclusion,
some
commenters
(
364,
381,
399,
387,
479)
provided
the
following
arguments
against
fuel
switching:
1)
Fuel
switching
is
neither
technologically
viable
nor
environmentally
beneficial;
2)
fuel
switching
would
contradict
the
National
Energy
Policy
goal
of
enhancing
fuel
diversity;
3)
fuel
switching
would
force
a
shift
away
from
bioenergy;
4)
fuel
switching
would
not
provide
the
additional
minimization
of
greenhouse
gas
emissions
that
the
use
of
biomass
would
provide;
5)
the
CAA
does
not
require
EPA
to
consider
fuel
switching
as
part
of
a
MACT
floor
analysis;
6)
the
inclusion
of
fuel
switching
as
a
MACT
floor
option
under
section
112(
d)(
3)
would
eliminate
EPA's
subcategorization
authority
as
well
as
EPA's
established
authority
to
vary
emission
standards
based
on
the
pollutant
content
of
the
fuel
burned;
and
7)
the
MACT
program
is
not
an
appropriate
vehicle
to
force
a
wholesale
change
in
energy
sources
that
fuel
switching
to
natural
gas
would
entail.
One
commenter
(
492)
explained
that
fuel
switching
is
not
a
technology
that
is
feasible
for
all
sources
within
the
category,
therefore,
it
is
not
"
duplicable."

One
commenter
(
415)
stated
that
the
EPA
should
provide
more
quantitative
information
on
the
potential
for
fuel
switching
to
reduce
HAP
emissions.
The
commenter
suggested
that,
with
regard
to
the
overall
reduction
of
HAP
associated
with
fuel
switching,
it
was
not
clear
if
the
EPA
had
sufficient
data
to
make
a
quantitative
determination
of
this
issue.
Regarding
EPA's
assertion
that
the
availability
of
natural
gas
supply
and
distribution
infrastructure
would
preclude
more
significant
use
of
fuel
switching,
the
commenter
also
requested
a
more
quantitative
assessment.

Response:
The
EPA
maintains
that
fuel
switching
is
not
a
viable
option
for
the
promulgated
rule,
based
on
the
rationale
presented
in
the
proposal
preamble.
Regarding
fuel
switching
emission
reductions/
increases,
the
memorandum
"
 
"
details
the
fuel
switching
impacts
analysis.
The
memorandum
presents
emission
impacts
for
pollutants,
including
organics,
inorganics,
and
metallic
HAPs.
This
analysis
was
based
on
all
the
emissions
information
gathered
by
EPA,
consisting
of
emission
test
reports
for
gas
fired
units
and
solid
fuel
units.
In
the
proposal,
EPA
requested
commenters
to
provide
additional
information.
However,
no
additional
emissions
information
was
provided.
Regarding
natural
gas
supply
and
infrastructure
comments,
commenters
are
referred
to
the
fuel
switching
memorandum.
The
EPA
did
not
have
extensive
information
on
natural
gas
supply
or
infrastructure.
The
EPA
did
have
sufficient
information
on
pipelines
and
use
of
natural
gas
at
each
boiler
and
other
combustion
units
to
estimate
whether
a
significant
number
of
sources
would
need
to
make
changes
to
their
combustion
unit.
The
fuel
101
switching
analysis
also
shows
that
the
major
annualized
cost
of
fuel
switching
to
natural
gas
is
not
the
capital
cost
of
equipment/
infrastructure,
but
the
high
cost
of
natural
gas
relative
to
other
fuels.
This
cost
differential
results
in
the
infeasibility
of
fuel
switching
to
natural
gas.
102
10.0
WORK
PRACTICES
STANDARDS
Comment:
One
commenter
(
445)
requested
that
EPA
consider
establishing
a
longer
averaging
period
for
the
CO
work
practice
standard
and
exempt
periods
of
startup,
shutdown,
and
malfunction
for
limited
use
boilers.
The
commenter
noted
that
the
infrequent
and
limited
use
of
these
boilers
makes
CO
emissions
highly
variable
and
would
result
in
difficulty
in
meeting
the
CO
work
practice
standard.
Four
commenters
(
364,
399,
387,
403)
supported
EPA's
conclusion
that
a
one­
day
averaging
period
for
CO
is
appropriate.
Other
commenters
(
401,
478)
suggested
that
if
EPA
decides
to
keep
CO
continuous
emissions
monitoring
system
requirements,
then
EPA
should
provide
a
30­
day
rolling
average
for
the
CO
standard
in
order
to
take
into
account
the
existence
of
fuel
and
operational
variability.

Response:
In
the
final
rule
we
modified
the
averaging
period
for
solid
fuel­
fired
sources
that
have
a
work
practice
standard
for
CO
and
are
required
to
monitor
CO
using
CEMS
(
i.
e.,
units
with
a
capacity
of
100
MMBtu/
hr
or
more).
We
changed
the
averaging
period
from
a
24­
hour
period
to
a
30­
day
rolling
average.
This
change
accounts
for
the
variability
in
fuel
characteristics
(
e.
g.,
moisture,
Btu
content,
mixture)
that
occur
for
solid
fuel­
fired
boilers
and
process
heaters.
With
regard
to
limited
use
units,
we
removed
the
requirement
for
those
units
to
install
and
operate
CO
CEMS
if
they
have
an
applicable
work
practice
standard.
Limited
use
units
with
an
applicable
CO
work
practice
standard
will
only
have
to
conduct
a
performance
test
for
CO
emissions.
This
change
was
made
due
to
the
limited
use
of
such
units
and
the
time
needed
to
conduct
annual
CO
CEMS
certifications.

Comment:
Several
commenters
(
418,
431,
475,
503,
504,
505)
claimed
that
the
potential
for
HAP
emissions
from
blast
furnace
gas
or
coke
oven
gas
is
significantly
less
than
that
associated
with
the
combustion
of
natural
gas
due
to
a
much
smaller
concentration
of
complex
hydrocarbon
compounds.
The
commenters
believe
that
sources
burning
these
byproduct
gases
should
not
be
required
to
meet
a
CO
limit
of
400
ppm
or
install
a
CO
continuous
emissions
monitor
because
CO
is
not
a
reliable
indicator
that
HAP
emissions
are
elevated.
In
addition,
units
burning
high
CO
concentrated
gases
may
not
be
able
to
meet
the
400
ppm
emission
limit.
The
commenters
claimed
that
this
would
discourage
the
use
of
byproduct
fuels
and
result
in
increased
HAP
emissions
since
the
gases
would
be
burned
elsewhere,
and
natural
gas
burned
in
their
place.
One
commenter
(
418)
recommended
that
blast
furnace
gas­
fueled
units
be
exempted
from
all
work
practice
standards
because
this
type
of
fuel
does
not
contain
the
constituents
that
generate
HAP
during
combustion.
The
other
commenters
(
431,
475,
503,
504,
505)
suggested
encouraging
the
beneficial
use
of
byproduct
fuels
by
exempting
them
from
the
MACT
requirements
or
allow
units
using
byproduct
fuels
to
be
regulated
according
to
the
amount
of
purchased
fossil
fuels
it
utilizes.

Response:
We
have
reviewed
the
information
submitted
by
the
commenters
and
agree
that
blast
furnace
gas
contains
minimal
or
even
no
hydrocarbons.
In
the
final
rule,
we
exempted
blast
furnace
gas­
fired
units
from
all
provisions
of
the
boilers
NESHAP.
However,
these
units,
as
defined
by
the
boilers
NESHAP,
are
boilers
and
process
heaters
that
receive
90
percent
or
more
of
their
total
heat
input
(
based
on
an
annual
average)
from
blast
furnace
gas.
If
your
boiler
or
process
heater
receives
less
than
90
percent
of
it
total
heat
input
from
blast
furnace
gas,
then
the
CO
work
practice
standards
could
apply
to
your
unit
if
it
meets
the
definition
of
new
source
and
is
larger
than
10
MMBtu/
hr
103
Comment:
Several
commenters
(
360,
364,
382,
388,
399,
387,
403,
406,
407,
408,
410,
426,
449,
479,
492,
498,
501,
524,
533)
requested
that
EPA
implement
the
CO
work
practice
standard
as
a
trigger
for
corrective
action
and
not
as
an
emission
limit
as
proposed.
Several
commenters
(
406,
407,
408,
501)
noted
that
a
corrective
action
trigger
would
be
appropriate
because
CO
is
not
a
HAP,
but
a
surrogate
to
control
related
HAP
emissions
in
a
general
sense
as
opposed
to
a
quantitative
or
predictive
sense.
One
commenter
(
360)
contended
that
there
was
little
proof
that
a
400
ppm
CO
limit
would
limit
organic
HAP
emissions.
One
commenter
(
410)
agreed
that
CO
emissions
from
boilers
or
heaters
provide
a
reasonable
rough
indicator
of
whether
good
combustion
practices
are
being
followed
and
preferred
monitoring
CO
over
monitoring
organic
HAP
directly.
The
commenter
added
that
based
on
the
PERF
study,
CO
is
a
weak
indicator
of
organic
HAP
in
concentrations
between
10
and
1000
ppm,
but
good
beyond
1000
ppm.
The
commenter
concluded
that
based
on
the
PERF
study,
exceedence
of
the
400
ppm
limit
should
not
be
considered
a
violation
but
should
require
the
owner
to
take
corrective
action
within
a
reasonable
time
frame.
Two
commenters
(
426,
492)
added
the
CO
level
being
a
corrective
action
trigger
will
provide
incentive
to
maintain
good
operating
practices
without
creating
violations
for
conditions
that
may
not
be
related
to
increased
HAP
emissions.
One
commenter
(
426)
listed
several
planned
activities
that
could
cause
CO
emissions
to
exceed
400
ppm.
The
commenter
also
listed
some
unforeseen
activities
that
could
cause
an
increase
in
CO
emissions.
The
commenter
added
that
because
of
the
complexity
of
refinery
operations,
it
would
be
difficult
and
time­
consuming
to
identify
and
document
every
conceivable
situation
that
would
require
units
to
be
run
at
a
reduced
rate
in
a
startup,
shutdown
and
malfunction
plan.

Response:
In
the
final
rule,
we
have
clarified
that
an
exceedence
of
the
CO
limit
constitutes
a
deviation
of
the
work
practice
standard.
An
observed
exceedence
of
a
monitoring
parameter
is
not
an
automatic
violation.
You
are
required
to
report
any
deviation
from
an
applicable
emission
limitation
(
including
operating
limit).
We
will
review
the
information
in
your
report
along
with
other
available
information
to
determine
if
the
deviation
constitutes
a
violation.
The
determination
of
what
emission
or
operating
limit
deviation
constitutes
violations
of
the
standard
is
up
to
the
discretion
of
the
entity
responsible
for
enforcement
of
the
standard.
Since
proposal,
we
revised
the
rule
to
provide
more
flexibility
with
regard
to
complying
with
the
work
practice
standard
for
CO.
For
solid
fuel­
fired
units,
we
changed
the
oxygen
correction
factor
from
3
to
7
percent
to
more
accurately
reflect
oxygen
levels
in
solid
fuel­
fired
units.
We
also
lengthened
the
averaging
period
for
solid
fuel­
fired
units
that
are
required
to
use
CO
CEMS
from
a
24­
hour
average
to
a
30­
day
rolling
average.
Furthermore,
we
added
a
provision
that
excluded
CO
emission
data
when
a
boiler
or
process
heater
is
operating
at
or
below
50
percent
of
the
rated
capacity.
We
believe
that
these
changes
should
address
some
of
the
commenters'
concern.

Comment:
One
commenter
(
427)
contended
that
§
63.7500(
c)
regarding
requesting
alternative
work
practices
is
poorly
written
and
does
not
convey
the
requirement
clearly.
The
commenter
suggested
alternative
wording.

Response:
This
alternative
is
only
applicable
if,
in
the
Administrator's
judgment,
an
owner
or
operator
of
an
affected
source
has
established
that
an
alternative
means
of
emission
limitation
will
achieve
a
reduction
in
emissions
of
a
hazardous
air
pollutant
from
an
affected
source
at
least
equivalent
to
the
reduction
in
emissions
of
that
pollutant
from
that
source
achieved
under
any
design,
equipment,
work
practice,
or
operational
emission
standard,
or
combination
thereof,
established
under
this
part
pursuant
to
section
112(
h).
For
a
source
to
be
allowed
to
establish
an
104
alternative
work
practice
standard,
the
Administrator
must
determine
one
of
the
following:
a)
HAP
cannot
be
emitted
through
a
conveyance
designed
and
constructed
to
emit
or
capture
such
pollutants,
or
that
any
requirement
for,
or
use
of,
such
a
conveyance
would
be
inconsistent
with
any
Federal,
State,
or
local
law,
or
b)
the
application
of
measurement
methodology
to
a
particular
class
of
sources
is
not
practicable
due
to
technological
and
economic
limitations.
We
are
not
going
to
modify
this
section
for
two
reasons:
1)
We
do
not
believe
that
many
sources
affected
by
this
NESHAP
would
be
in
a
situation
where
this
alternative
would
be
allowed,
and
2)
the
section
refers
to
§
63.6(
g)
which
clearly
spells
out
the
reasons
and
requirements
for
petitioning
for
an
alternative
work
practice
standard.

Comment:
Several
commenters
(
364,
399,
387
383)
requested
that
EPA
reevaluate
the
CO
work
practice
standard.
The
commenters
argued
that
the
current
CO
standard
may
result
in
unintended
consequences
such
as
a
reduction
in
the
use
of
biomass
fuel.
One
commenter
(
364)
provided
an
example
wherein
a
boiler
affected
by
a
CO
limitation
could
not
meet
the
limitation
while
burning
its
standard
blend
of
fuels.
To
meet
the
standard,
the
source
cut
back
the
combustion
of
biomass
resulting
in
an
increase
of
sulfur
dioxide
emissions
due
to
the
additional
fossil
fuels
required.
One
commenter
(
320)
contended
that
the
CO
standard
of
400
ppm
would
be
impossible
to
attain
with
biomass
fuels.
The
commenter
contended
that
there
are
severe
negative
economic
impacts
and
minimal
reduction
in
HAP
emissions
resulting
from
the
CO
standard.

Response:
Since
proposal,
we
revised
the
CO
work
practice
standards
to
address
solid
fuel­
fired
sources
more
appropriately.
We
increased
the
oxygen
correction
factor
for
new
solid
fuel­
fired
sources
from
3
to
7
percent
to
be
more
representative
of
the
oxygen
levels
present
in
solid
fuel­
fired
units.
We
increased
the
averaging
period
for
solid
fuel­
fired
sources
has
been
increased
from
24
hours
to
a
30­
day
rolling
average
to
account
for
normal
variations
in
fuel
quality
that
may
affect
CO
emissions.
Finally,
we
modified
the
recordkeeping
requirements
that
relate
to
CO
emissions
and
do
not
require
you
to
collect
or
include
CO
emission
data
for
periods
where
your
boiler
or
process
heater
is
operating
at
loads
less
than
50
percent
of
total
capacity.
We
believe
that
these
changes
should
address
the
commenters
concern
and
should
not
discourage
the
beneficial
use
of
renewable
energy
sources
such
as
biomass.

Comment:
One
commenter
(
424)
stated
that
EPA
underestimated
the
cost
of
installing
and
operating
CO
continuous
emissions
monitoring
systems
and
recommended
that
EPA
exempt
new
gaseous
fuel­
fired
boilers
from
any
NESHAP
requirements.
One
commenter
(
490)
argued
that
the
CO
monitoring
requirements
for
gaseous
fuel­
fired
units
would
be
expensive
and
result
in
no
environmental
benefits.

Response:
We
do
not
exempt
all
new
gaseous
fuel­
fired
boilers
and
process
heaters
from
any
NESHAP
requirements.
New
gaseous
fuel­
fired
sources
that
have
a
heat
input
capacity
of
10
MMBtu/
hr
or
more
will
have
an
applicable
CO
work
practice
standard.
However,
in
the
final
rule,
we
no
longer
require
new
boilers
and
process
heaters
that
have
a
heat
input
capacity
less
than
100
MMBtu/
hr
to
install
a
CO
CEMS
if
they
have
an
applicable
CO
work
practice
standard.
Units
with
a
heat
input
capacity
less
than
100
MMBtu/
hr
will
only
have
to
conduct
annual
performance
testing
for
CO.
This
change
significantly
reduces
the
cost
of
compliance
for
new
sources.
105
Comment:
Several
commenters
(
364,
374,
382,
383,
387,
388,
399,
403,
449,
492,
498,
524,
533)
suggested
modifying
the
400
ppm
standard
so
that
it
does
not
apply
during
periods
of
very
low
load
operation.
One
commenter
(
492)
noted
that
real
time
variation
of
CO
measurements
from
varying
operating
load
conditions
must
be
considered
in
establishing
an
achievable
CO
work
practice
standard.
The
commenter
added
that
cycling
load
and
intermittent
low
load
conditions
may
often
result
in
spikes
and
fluctuations
in
CO
emissions,
and
the
imposition
of
a
CO
limit
under
very
low
load
conditions
may
be
inappropriate.
Several
commenters
(
364,
382,
387,
388,
399,
403,
449,
498,
524,
533
)
suggested
providing
an
exemption
to
the
CO
standard
when
units
are
operating
at
loads
less
than
50
percent.
One
commenter
(
364)
also
noted
that
EPA's
analysis
did
not
include
startup,
shutdown,
malfunction,
and
high
boiler
turndown
events
into
the
variability
analysis
and
also
pointed
out
that
other
existing
State
CO
limitations
include
exemptions
during
turndown
periods.

Response:
We
agree
with
the
commenters
that
cycling
load
and
intermittent
low
load
conditions
may
result
in
fluctuations
in
CO
emissions
that
sources
cannot
control.
Therefore,
in
the
final
rule,
we
modified
the
recordkeeping
provisions
such
that
you
are
not
required
to
collect
or
use
CO
emission
data
in
determining
compliance
when
your
boiler
or
process
heater
is
operating
a
loads
less
than
50
percent
of
the
rated
capacity.
Furthermore,
we
also
modified
the
final
rule
to
extend
the
averaging
period
for
CO
emissions
from
24
hours
to
a
30­
day
rolling
average.
We
believe
that
this
change
will
continue
to
provide
the
desired
reduction
in
organic
HAP
emissions
while
accounting
for
normal
unit
operation
that
may
affect
CO
emissions.

Comment:
Several
commenters
(
364,
382,
383,
387,
388,
399,
401,
404,
406,
407,
408,
430,
449,
498,
524,
533)
requested
that
EPA
increase
the
oxygen
correction
factor
applied
to
the
CO
work
practice
standard
for
solid
fuel­
fired
units,
especially
biomass
fuel­
fired
units.
The
commenters
requested
that
EPA
increase
the
oxygen
correction
factor
from
3
to
7
percent
for
solid
fuel­
fired
units.
Several
commenters
(
449,
524,
533,
388,
498)
stated
that
many
solid
fuelfired
units
typically
operate
with
excess
oxygen
levels
in
the
7
percent
range
and
that
higher
excess
air
levels
are
needed
to
compensate
for
the
more
difficult
mixing
of
air
and
fuel.
The
commenters
also
noted
that
high
moisture
fuel
with
inherent
moisture
variations
coupled
with
load
variations,
make
the
400
ppmv
corrected
to
3
percent
oxygen
CO
limit
unattainable.
Several
commenters
(
406,
407,
408,
501)
provided
CO
data
from
four
modern
biomass­
fired
boilers
that
underwent
PSD
and
BACT
that
showed
that
these
boilers
would
not
comply
with
the
proposed
CO
standards.
Other
commenters
(
388,
406,
407,
408,
449,
498,
501,
524,
533)
also
listed
other
EPA
regulations
that
have
incorporated
an
oxygen
correction
factor
of
7
percent.
Several
commenters
(
374,
382,
388,
449,
492,
498,
524,
533)
suggested
that
the
3
percent
correction
factor
remain
for
gas
and
oil­
fired
units.
One
commenter
(
340)
stated
the
CO
concentration
in
Table
8
needed
to
be
referenced
to
an
oxygen
concentration
of
3
percent
is
the
usual
standard
for
boilers.

Response:
We
agree
that
the
application
of
a
3
percent
oxygen
correction
factor
for
solid
fuel­
fired
boilers
and
process
heaters
may
not
be
appropriate.
Due
to
the
nature
of
burning
solid
fuels
completely,
additional
oxygen
is
needed
in
the
flame
zone
to
ensure
complete
combustion.
Therefore,
in
the
final
rule,
we
increased
the
oxygen
correction
factor
from
3
to
7
percent
for
solid
fuel­
fired
units.
Furthermore,
we
increased
the
averaging
time
for
solid
fuel­
fired
sources
from
24
hours
to
a
30­
day
rolling
average
to
account
for
fuel
variations
such
as
moisture.
We
believe
that
these
changes
should
address
the
commenters'
concern
over
the
CO
work
practice
standard
application
to
solid
fuel­
fired
boilers
and
process
heaters.
106
Comment:
Several
commenters
(
346,
374,
382,
388,
410,
449,
479,
492,
498,
524,
533)
recommended
that
CO
continuous
emissions
monitoring
systems
be
required
only
for
units
greater
than
250
MMBtu/
hr.
Several
commenters
(
360,
492)
supported
an
initial
compliance
test
followed
by
periodic
testing
for
units
less
than
250
MMBtu/
hr.
Two
commenters
(
410,
490)
suggested
requiring
initial
compliance
tests
using
a
portable
CO
process
monitor
for
units
greater
than
100
MMBtu/
hr
and
less
than
250
MMBtu/
hr.
The
commenters
also
suggested
that
EPA
exempt
units
smaller
than
100
MMBtu/
hr
from
the
CO
work
practice
standard.
One
commenter
(
490)
suggested
for
units
greater
than
100
and
up
to
250
MMBtu/
hour,
the
operator
would
be
required
to
complete
an
initial
stack
test
and
thereafter
complete
annual
inspections
and
unit
adjustments,
and
subsequent
stack
tests
would
be
required
if
the
unit
burners
are
replaced.
The
commenter
also
added
that
for
units
greater
than
250
MMBtu/
hour,
the
operator
would
be
required
to
complete
an
initial
stack
test
and
annual
tuning
of
the
burners,
and
retesting
of
the
unit
would
be
conducted
every
5
years
or
when
burners
are
replaced.
Several
commenters
(
332,
371,
424,
479)
requested
that
EPA
only
require
CO
continuous
emissions
monitoring
systems
on
units
larger
than
40
MMBtu/
hr
and
allow
smaller
units
to
conduct
annual
CO
emission
tests.
One
commenter
(
371)
claimed
the
proposed
rule
is
inconsistent
with
the
current
South
Coast
Air
Quality
Management
District
requirements,
which
allow
annual
source
testing
of
units
that
are
less
than
40
MMBtu/
hr
in
lieu
of
continuous
emissions
monitoring
systems.

Response:
In
the
final
rule,
we
require
boilers
and
process
heaters
that
have
a
heat
input
capacity
of
100
MMBtu/
hr
or
more
to
install
a
CO
CEMS
only
if
they
have
an
applicable
CO
work
practice
standard.
For
sources
smaller
than
100
MMBtu/
hr,
annual
performance
testing
for
CO
is
required
to
demonstrate
compliance
with
the
applicable
work
practice
standard.
We
made
this
change
in
the
boilers
NESHAP
to
minimize
compliance
costs
for
smaller
sources
that
would
result
from
the
installation
of
a
CEMS.
With
a
size
cutoff
of
100
MMBtu/
hr,
we
are
assured
that
all
units
with
a
heat
input
capacity
of
100
MMBtu/
hr
or
greater
will
already
have
a
CEMS
for
other
pollutants
required
by
NSPS
subpart
Dc
and
the
addition
of
a
CO
analyzer
to
an
existing
CEMS
would
not
be
as
onerous
as
installing
a
CEMS
for
the
purpose
of
monitoring
only
CO.

Comment:
Two
commenters
(
369,
491)
recommended
that
EPA
exclude
from
CO
monitoring
requirements
natural
gas
and
distillate
oil
fired
boilers
and
process
heaters
with
less
than
50
MMBtu/
hr
heat
input.
One
commenter
(
491)
argued
that
calculations
based
on
AP­
42
emission
factors
indicated
that
CO
emissions
from
natural
gas
and
distillate
oil
fired
boilers
and
process
heaters
are
significantly
less
than
the
work
practice
standard
of
400
ppm
of
CO.
Therefore,
the
commenter
stated
that
there
is
no
point
in
installing
a
CO
continuous
emissions
monitoring
system
and
monitoring
CO
if
the
emissions
are
expected
to
always
be
well
below
the
proposed
work
practice
limit.
In
addition,
the
commenter
stated
that
EPA
could
promulgate
a
boiler
tune­
up
requirement
as
a
work
practice
standard
to
assure
that
boilers
and
process
heaters
are
properly
maintained.
The
commenter
cited
New
York
State's
tune­
up
regulation
(
6NYCRR
Part
227­
2.4(
d)).
Another
commenter
(
479)
requested
EPA
exempt
small
and
new
reconstructed
gas
and
liquid
fuel­
fired
units
that
have
minimal
emissions.
One
commenter
(
500)
stated
that
CO
continuous
emissions
monitoring
systems
are
not
necessary
for
new
gaseous­
fired
units.
The
commenter
stated
that
facilities
already
closely
maintain
burners
for
economic
reasons.
The
commenter
stated
that
periodic
CO
performance
testing
provides
an
adequate
measure
of
the
combustion
performance
of
a
gaseous­
fired
burner,
without
the
need
for
costly
continuous
emissions
monitoring
systems
and
their
respective
monitoring
plans.
107
Response:
In
the
final
rule,
we
modified
the
CO
monitoring
requirements
for
boilers
and
process
heaters
that
have
a
heat
input
capacity
less
than
100
MMBtu/
hr.
Units
with
rated
heat
input
capacities
less
than
100
MMBtu/
hr
are
not
required
to
install
a
CO
CEMS,
but
will
only
have
to
conduct
annual
performance
testing
for
CO.
We
maintain
that
this
change
to
the
monitoring
requirements
will
reduce
the
cost
of
compliance
for
smaller
sources
but
still
maintains
assurance
that
these
sources
are
meeting
the
CO
work
practice
standards.

With
regard
to
the
commenter's
request
to
exempt
small
and
new
reconstructed
gaseous
and
liquid
fuel­
fired
units,
the
proposed
and
final
rule
does
not
contain
any
compliance
requirements
for
small
gaseous­
fuel
fired
sources,
new
or
existing.
For
new
small
liquid
fuel­
fired
sources,
emission
limits
exist,
but
the
monitoring,
recordkeeping,
and
reporting
requirements
have
been
minimized
for
sources
that
burn
only
fossil
fuels
and
do
not
burn
any
residual
oil.

Comment:
One
commenter
(
439)
suggested
that
EPA
consider
the
cost
effectiveness
of
requiring
continuous
emissions
monitor
on
units
less
than
100
MMBtu/
hr
in
relation
to
the
potential
reduction
in
HAP
emissions
given
the
required
work
practice
standard.
The
commenter
stated
that
EPA
should
provide
information
on
actual
HAP
emissions
from
improperly
operated
units
and
potential
HAP
reductions
resulting
from
work
practice
standards.
The
commenter
believes
EPA
should
quantify
actual
HAP
emissions
from
"
improperly
operated"
units
less
than
100
MMBtu/
hr
and
compare
these
HAP
emissions
to
the
costs
of
implementing
the
proposed
work
practice
standards
for
units
with
the
same
heat
input
capacity.
The
commenter
suggested
that
EPA
should
revise
the
requirements
and
remove
work
practice
standards
for
new
gaseous
fuel
units
less
than
100
MMBtu/
hr
heat
input.

Response:
In
the
final
rule,
we
removed
the
requirement
for
sources
less
than
100
MMBtu/
hr
to
install
and
operate
CO
CEMS
if
they
have
an
applicable
CO
work
practice
standard.
These
sources
will
only
have
to
conduct
annual
performance
testing
to
demonstrate
compliance
with
the
CO
work
practice
standard.
We
believe
that
this
change
is
an
effective
way
to
minimize
the
compliance
cost
for
many
sources.

With
regard
to
quantifying
HAP
reductions
resulting
from
the
application
of
the
work
practice
standards,
obtaining
quantitative
impacts
on
HAP
emission
reductions
is
difficult
due
to
the
site­
specific
nature
of
boiler
and
process
heater
operation
and
organic
HAP
emission
levels,
though
experience
with
boiler
and
process
heater
operation
demonstrates
that
organic
HAP
emissions
are
minimized
through
efficient
combustion
(
e.
g.,
low
CO
emission
levels).
For
example,
if
a
boiler
or
process
heater
is
typically
operating
in
an
efficient
manner
and
the
owner/
operator
of
such
a
unit
maintains
the
source
in
a
good
manner,
the
application
of
a
CO
work
practice
standard
may
not
result
in
significant
reductions
of
organic
HAP.
However,
if
a
boiler
or
process
heater
is
not
operated
in
an
efficient
manner,
organic
HAP
reductions
would
be
more
significant.
Therefore,
arriving
at
organic
HAP
reductions
is
not
as
straightforward
as
determining
the
reduction
in
hydrogen
chloride
emissions
from
installing
a
scrubber
or
from
switching
fuel
types.
For
these
reasons,
we
do
not
provide
emission
impacts
resulting
from
the
application
of
work
practice
standards.

Comment:
One
commenter
(
340)
requested
the
EPA
include
a
combustion
optimization
requirement
for
existing,
new,
and
reconstructed
units.
There
have
been
papers
presented
at
the
Electric
Power
Research
Institute/
EPA
Megasymposiums
which
discuss
the
effectiveness
of
tuning
boilers
using
software
packages
that
manage
boiler
combustion.
Decreases
of
nitrogen
108
compound
emissions,
less
loss
on
ignition
to
fly
ash,
and
increases
in
efficiency
were
demonstrated.
This
indicates
economic
incentives
to
ensure
that
fuel
is
not
wasted,
and
the
combustion
device
operates
properly
and
is
appropriately
maintained.
The
commenter
requested
that
EPA
include
a
combustion
optimization
requirement
for
existing,
new,
and
reconstructed
units.
The
combustion
optimization
should
use
control
and
automatic
boiler
tuning
algorithms
to
automatically
track
time­
varying
physical
and
operational
changes
to
the
boiler
in
order
to
optimize
boiler
efficiency
and
loss
on
ignition
through
closed­
loop
mangagement
of
the
air/
fuel
and
temperature
distributions
within
the
boiler
while
maintaining
the
NOx
emission
rate
in
compliance
with
other
applicable
requirements.
Another
commenter
(
376)
requested
that
EPA
allow
the
use
of
Good
Combustion
Practices
demonstrated
through
combustion
optimization
in
lieu
of
the
CO
work
practice
standard.
The
commenter
expressed
concern
that
the
CO
work
practice
standard
could
have
adverse
impacts
such
as
increased
nitrogen
compound
emissions.

Response:
As
we
discussed
in
the
preamble
to
the
proposal,
we
did
review
good
combustion
practice
references
and
application
of
good
combustion
practices.
However,
we
noted
that
there
was
a
lack
of
information,
and
a
lack
of
uniform
approach
to
assuring
combustion
efficiency.
We
noted
that
these
finding
were
not
surprising
given
the
extreme
diversity
of
boilers
and
process
heaters,
and
given
the
fact
that
no
applicable
Federal
standards,
and
most
applicable
State
standards,
do
not
include
work
practice
requirements
for
boilers
and
process
heaters.
Even
those
States
that
do
have
such
requirements
do
not
require
the
same
work
practices.
Since
we
were
unable
to
determine
any
uniform
requirements
or
set
of
work
practices
that
would
meaningfully
reflect
the
use
of
good
combustion
practices,
or
that
could
be
meaningfully
implemented
across
any
subcategory
of
boilers
and
process
heaters,
we
have
not
included
any
specific
good
combustion
practice
requirements
in
the
final
rule.
We
do
consider
monitoring
and
maintaining
CO
emission
levels
to
be
associated
with
minimizing
emissions
of
organic
HAP.
Therefore,
controlling
CO
emissions
can
be
a
mechanism
for
ensuring
combustion
efficiency
and
may
be
viewed
as
a
type
of
good
combustion
practice.
That
is
why
we
included
the
CO
work
practice
standards
in
the
final
rule
and
did
not
include
any
specific
good
combustion
practices.

Comment:
One
commenter
(
382)
supported
the
use
of
CO
limits
as
the
only
new
source
work
practice
standard.
Three
commenters
(
382,
447,
519)
noted
that
there
are
no
"
common"
good
combustion
practices
that
could
assure
a
certain
level
of
HAP
emission
control
across
the
diverse
population
of
boilers
and
process
heaters.
One
commenter
(
492)
agreed
with
EPA's
finding
that
CO
monitoring
is
the
only
applicable
new
source
work
practice
standard
requirement.
According
to
the
commenter,
the
diversity
of
industrial
and
commercial
boilers
and
process
heaters
does
not
allow
for
"
common"
combustion
practice
requirements
that
could
assure
a
certain
level
of
HAP
emissions,
and
EPA
correctly
determined
that
none
are
suitable
as
a
basis
for
the
MACT
floor.
One
commenter
(
415)
suggested
that
EPA
should
incorporate
good
combustion
practice
recommendations
into
the
proposed
rule.
The
commenter
noted
that
it
is
inappropriate
for
EPA
to
make
the
blanket
assumption
that
all
existing
boilers
and
process
heaters
already
are
operating
at
optimum
efficiency
when
data
suggest
otherwise.
The
commenter
stated
that
EPA
should
not
assume
that
economic
concerns
are
sufficient
to
ensure
that
boilers
at
all
facilities
are
already
operating
at
peak
efficiency.
The
commenter
referenced
work
done
by
the
Delta
Institute
on
benefits
and
emission
reductions
from
good
combustion
practices.

Response:
As
we
explained
in
the
preamble
to
the
proposal,
we
were
unable
to
identify
any
uniform
requirements
or
set
of
work
practices
that
would
meaningfully
reflect
the
use
of
good
combustion
practices,
or
that
could
be
meaningfully
implemented
across
any
subcategory
of
109
boilers
and
process
heaters.
That
is
why
we
did
not
promulgate
any
good
combustion
practices
in
this
NESHAP.
With
regard
to
the
commenter's
statement
that
we
made
a
blanket
assumption
that
all
boilers
and
process
heaters
are
operating
at
optimum
efficiency,
we
maintain
that
all
boilers
and
process
heaters
are
designed
for
good
combustion
and
facilities
have
an
economic
incentive
to
ensure
fuel
is
not
wasted
by
maintaining
good
combustion.
However,
we
do
not
believe
that
all
facilities
operate
their
units
at
optimum
efficiency.
That
is
why
we
promulgated
a
CO
work
practice
standard
as
a
mechanism
for
ensuring
combustion
efficiency,
which
may
be
viewed
as
a
type
of
good
combustion
practice.

Comment:
One
commenter
(
343)
agreed
with
EPA
that
CO
is
a
good
indicator
of
incomplete
combustion
and
that
minimizing
CO
emissions
should
result
in
minimizing
organic
HAP
emissions.
However,
two
commenters
(
343,
434)
recommended
that
minimizing
CO
emissions
can
be
accomplished
more
cost­
effectively
by
ensuring
that
there
is
sufficient
excess
air
for
complete
combustion,
rather
than
by
installing
a
CO
continuous
emissions
monitor.
One
commenter
(
434)
recommended
that
excess
air
monitors
be
permitted
to
control
such
sources.
Another
commenter
(
343)
suggested
the
following
alternatives:
1)
Perform
a
stack
test
to
demonstrate
initial
compliance
with
the
400
ppmvd
at
3
percent
oxygen,
CO
emissions
limitation.
To
demonstrate
continuous
compliance,
verify
once
per
month
that
the
burner
oxygen
setpoint
from
the
initial
compliance
test
has
not
changed.
In
the
event
that
changes
are
made
to
the
operation
of
the
boiler/
process
heater
that
could
reasonably
be
expected
to
impact
CO
emissions,
a
test
with
a
portable
analyzer
for
CO
is
required
to
ensure
that
CO
emissions
are
still
below
the
400
ppmvd;
2)
Use
an
annual
tuning
procedure
that
establishes
the
minimum
oxygen
level
resulting
in
400
ppmv
CO
and
then
set
the
burner
oxygen
controls
to
operate
above
this
level
with
an
allowable
margin.
Burner
setpoints
are
verified
once
per
month
to
ensure
that
the
settings
established
during
the
tuneup
have
not
changed.
The
commenter
referenced
procedures
used
by
the
Massachusetts
Nitrogen
Compound
Reasonably
Available
Control
Technology
regulations.

Response:
We
chose
to
use
CO
CEMS
as
the
monitoring
parameter
for
the
CO
work
practice
standard
because
CO
CEMS
are
proven
technologies
for
measuring
CO
emissions.
In
the
case
of
some
other
pollutants
regulated
by
the
boilers
NESHAP
(
e.
g.,
hydrogen
chloride,
mercury,
etc.),
CEMS
are
not
widely
proven
and
are
cost­
prohibitive.
Therefore,
for
several
regulated
pollutants
in
this
NESHAP
we
use
parametric
monitoring
systems
when
direct
measurement
is
not
practical.
In
the
final
rule,
we
require
sources
that
have
an
applicable
CO
work
practice
standard
to
install
a
CO
CEMS
if
the
unit
has
a
heat
input
capacity
of
100
MMBtu/
hr
or
greater.
We
have
decided
to
stay
with
CO
CEMS
for
those
units
because
they
would
already
have
to
install
a
CEMS
system
under
the
NSPS
requirements
and
the
addition
of
a
CO
analyzer
would
be
an
incremental
cost.
For
units
with
a
heat
input
capacity
less
than
100
MMBtu/
hr,
we
require
annual
CO
performance
testing.
If
you
would
like
to
use
another
method
to
monitor
CO
emissions
from
your
boiler
or
process
heater,
you
can
petition
the
Administrator
for
approval
of
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.
110
11.0
COMPLIANCE
11.1
General
Comment:
Several
commenters
(
364,
382,
387,
399,
449,
492,524)
insisted
that
EPA
provide
flexibility
for
emission
limits,
testing,
and
operating
parameters
to
account
for
the
many
diverse
equipment
arrangements
used
by
boilers
and
process
heaters.
One
commenter
(
382)
argued
that
the
proposal
was
based
on
the
assumption
of
a
single
unit
being
associated
with
its
own
control
system
and
that
in
practice
there
are
many
arrangements
that
are
more
complex.
The
commenters
provided
several
examples
of
alternate
arrangements
and
requested
that
EPA
specifically
address
arrangements
such
as,
but
not
limited
to
the
following:
1)
allowing
the
use
of
a
single
opacity
monitor
or
bag
leak
detection
system
downstream
of
a
common
emissions
control
device;
2)
allowing
the
use
of
existing
emission
monitoring
and
testing
locations
whether
it
serves
single
or
multiple
units;
3)
emission
testing
that
allows
for
multiple
units
being
served
by
a
single
control
device;
4)
establishment
of
control
ranges
for
operating
parameters
that
could
vary
significantly
depending
on
the
number
and
firing
rate
of
individual
units
operating;
5)
emission
testing
that
can
simultaneously
cover
all
of
the
units
served
by
a
common
control
device
rather
than
testing
each
unit
individually;
and
6)
flexibility
to
test
emissions
from
common
control
devices
whether
or
not
full
load
capability
is
available
at
the
time.
The
commenters
requested
that
EPA
provide
sources
an
opportunity
to
propose
alternative
approaches
for
compliance
demonstrations
to
their
permitting
authorities
should
specific
arrangements
not
be
addressed
in
the
rule.
One
commenter
(
492)
suggested
that
this
flexibility
may
best
be
served
by
enabling
the
"
bubbling"
compliance
concept
described
in
the
proposal.

Response:
We
are
aware
that
a
diverse
population
of
boiler
and
process
heater
arrangements
exist.
However,
to
address
in
this
rule
all
the
different
types
of
arrangements
that
exist
would
be
too
cumbersome
and
we
believe
that
we
would
still
not
be
able
to
incorporate
all
the
existing
and
future
arrangements
that
will
be
employed
by
boilers
and
process
heaters.
Therefore,
in
the
final
boilersNESHAP
we
have
modified
the
proposed
requirements
to
provide
more
flexibility
by
including
such
elements
as
the
following:
1)
fixed
opacity
limits
similar
to
those
provided
in
the
industrial
boilersNSPS;
2)
emission
averaging
provisions
for
solid
fuel­
fired
units;
3)
less
restrictive
fuel
sampling
requirements
that
are
based
on
fuel
type
(
i.
e.,
subbituminous
coal,
bark,
railroad
ties,
tires)
and
not
triggered
by
changes
in
fuel
suppliers
or
fuel
location;
4)
providing
operating
ranges
around
the
operating
limits;
and
5)
providing
a
compliance
method
based
on
fuel
analysis.
If
you
still
require
an
alternative
monitoring
strategy
for
your
source,
you
can
petition
the
Administrator
for
approval
of
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Two
commenters
(
521,
535)
stated
that
a
circulating
fluidized
bed
(
CFB)
boiler
using
limestone
injection
controls
inorganic
acid
gases
effectively
and
reliably.
Therefore,
the
commenter
requested
that
EPA
allow
sources
having
CFB
boilers
to
take
pollution
control
credit,
similar
to
the
credit
offered
to
sources
having
scrubbers
and
other
add­
on
controls.

Response:
We
acknowledge
that
CFB
boilers
that
inject
limestone
and
other
types
of
sorbents
achieve
effected
acid
gas
control.
Therefore,
we
have
added
CFB
boilers
with
limestone
or
sorbent
injection
to
the
dry
scrubber
definition.
In
the
final
boilers
NESHAP,
CFB
boilers
that
inject
limestone
or
other
types
of
sorbent
will
be
required
to
establish
a
sorbent
injection
rate
during
performance
testing
for
hydrogen
chloride
and
must
monitor
sorbent
injection
as
an
111
operating
limit.

Comment:
One
commenter
(
491)
requested
that
EPA
state
in
§
§
63.7530(
b)
and
§
63.7540(
a)(
2)
that
new
or
reconstructed
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil
are
presumed
to
be
in
compliance
with
the
applicable
requirements
and
that
no
gap
filling
periodic
monitoring
is
required
for
these
units
under
Title
V.
The
commenter
stated
that
this
statement
is
needed
to
assure
that
state
regulators
do
not
feel
that
they
have
to
require
gap
filling
monitoring
for
these
units.
One
commenter
(
487)
requested
that
EPA
clarify
the
final
rule
so
that
gaseous
and
liquid
fuel­
fired
units
are
not
required
to
comply
with
the
monitoring
and
data
collection
requirements
proposed
in
§
§
63.7535
and
63.7540,
and
the
monitoring
and
inspection,
operation,
and
maintenance
requirements
of
§
63.7525.

Response:
In
the
final
boilers
NESHAP,
we
have
clearly
stated
that
liquid
fuel­
fired
units
that
only
burn
fossil
fuels
and
do
not
burn
any
residual
oil
demonstrate
compliance
by
certifying
that
they
do
not
burn
any
residual
oil.
We
do
not
believe
an
additional
statement
addressing
Title
V
is
necessary
since
we
have
clearly
outlined
the
compliance
requirements
for
these
types
of
units.
We
also
have
clearly
stated
in
§
§
63.7535
and
63.7540
the
specific
requirements
for
these
types
of
units
and
believe
that
no
additional
clarification
is
needed
in
those
sections.
Furthermore,
since
these
units
are
not
required
to
have
continuous
monitoring
systems
(
CMS),
we
also
believe
that
no
additional
clarification
is
needed
in
§
63.7525.

Comment:
Two
commenters
(
354,
417)
do
not
believe
that
the
proposed
monitoring,
recordkeeping,
notification,
analytical
and
stack
performance
testing
requirements
in
the
proposed
rule
are
justified.
One
commenter
(
354)
argued
that
EPA
has
not
presented
evidence
that
any
of
these
additional
requirements
will
achieve
emission
reductions,
but
will
be
costly
and
burdensome
for
affected
entities.
The
commenter
recommended
that
all
requirements
that
are
not
directly
related
to
quantifiable
emission
reductions
be
removed
from
the
final
rule.

Response:
We
disagree
with
the
commenter
because
continuous
monitoring
requirements
are
necessary
to
ensure
ongoing
compliance
with
the
emission
limits.
We
require
performance
testing
to
demonstrate
compliance
with
the
emission
limits
and
use
operating
parameters
to
ensure
that
the
source
is
operating
in
a
manner
similar
to
the
way
it
was
operating
during
the
successful
performance
testing.
Parametric
monitoring
is
a
tool
to
minimize
the
cost
that
would
be
associated
with
installing
continuous
emission
monitoring
systems
for
the
regulated
pollutants
or
conducting
more
frequent
performance
testing.
However,
we
need
the
monitoring,
recordkeeping,
notification,
analytical
and
stack
performance
testing
requirements
to
provide
evidence
of
compliance
with
this
NESHAP.
We
have
worked
to
minimize
the
burden
of
the
boilers
NESHAP
while
remaining
confident
that
compliance
with
the
standard
is
being
sustained.

Comment:
One
commenter
(
347,
376)
requested
that
EPA
allow
sources
flexibility
to
use
any
technology
to
comply
with
the
applicable
emission
limitations.
One
commenter
(
347)
requested
that
EPA
clarify
whether
new
sources
have
to
install
the
MACT
floor
level
of
control
or
if
the
only
requirement
is
demonstration
of
compliance
with
the
emission
limits.

Response:
The
NESHAP
program
is
a
technology­
based
regulatory
program
that
sets
emission
limits
based
on
the
best
performing
units
in
a
category.
However,
existing
and
new
112
sources
are
not
required
to
use
the
specific
control
technologies
that
were
used
to
establish
the
emission
limits.
You
may
use
any
technology
or
pollution
prevention
strategy
to
comply
with
the
applicable
emission
limits.

Comment:
One
commenter
(
372)
requested
that
EPA
exempt
"
low­
risk"
sources
from
most
of
the
ongoing
compliance
demonstration
requirements.
The
commenter
defined
low­
risk
facilities
as
those
that
demonstrate
compliance
with
the
emission
limits
by
as
substantial
margin,
such
as
less
than
50
percent
of
the
emission
limit.
This
margin
would
be
enough
to
provide
assurance
of
ongoing
compliance
over
the
range
of
fuel
variability
and
normal
operating
conditions.
Using
existing
opacity
limits
and
requiring
chlorine
content
testing
for
new
fuel
types,
the
commenter
believes
that
this
would
provide
a
reasonable
alternative
to
the
proposed
rule
requirements.

Response:
We
are
not
providing
an
exemption
for
source
that
demonstrate
compliance
with
the
emission
limits
by
a
substantial
margin.
Since
proposal,
we
have
minimized
the
ongoing
compliance
requirements
of
the
boilers
NESHAP
in
order
to
reduce
the
burden
on
sources,
by
modifying
the
fuel
sampling
requirements,
opacity
limits,
and
the
definition
of
operating
limits.
We
are
also
allowing
facilities
to
conduct
performance
testing
once
every
three
years
if
they
demonstrate
compliance
with
the
emission
limits
for
three
consecutive
years.
Therefore,
we
believe
that
we
have
provided
a
significant
amount
of
flexibility
for
sources
without
compromising
the
measures
needed
to
ensure
ongoing
compliance
with
the
emission
limits.

Comment:
One
commenter
(
529)
questioned
the
instructions
in
§
63.7530(
c)
for
conducting
performance
tests.
The
instructions
indicate
that
no
controls
are
required,
even
if
a
control
device
is
installed
and
has
been
identified
as
part
of
the
MACT
floor.
The
commenter
stated
that
allowing
a
facility
to
not
take
credit
for
the
control
device
minimizes
the
reduction
of
emissions
to
a
level
that
barely
passes
the
emission
standard
and
provides
a
disincentive
for
new
technology.
Also,
§
63.7530(
c)
allows
the
regulated
facility
to
use
fuel
switching
to
achieve
the
emission
limits.
The
commenter
stated
that
this
practice
does
not
protect
human
health
and
asks
that
either
the
compliance
period
be
assessed
more
frequently
or
the
short
term
firing
ratio
be
enforceable.

Response:
The
NESHAP
program
establishes
emission
limits
based
on
the
best
performing
sources
in
a
category.
Some
facilities
may
be
able
to
meet
the
emission
limits
through
the
types
of
fuel
that
they
burn
or
through
fuel
switching.
In
these
cases,
we
allow
fuel
analysis
as
the
method
to
demonstrate
compliance
because
emissions
of
the
regulated
pollutants
under
this
NESHAP
(
metals,
mercury,
hydrogen
chloride)
can
be
determined
through
fuel
analysis
since
they
are
neither
formed
nor
created
during
the
combustion
process.
Therefore,
if
the
ratio
of
fuel
pollutant
content
to
fuel
heat
value
is
lower
than
the
emission
limit,
we
are
confident
that
the
source
is
meeting
the
emission
limit.
Since
the
NESHAP
program
does
not
require
installation
of
the
specific
control
technologies
used
to
establish
the
MACT,
only
demonstration
that
the
emission
limits
established
by
the
MACT
control
technologies
are
being
met,
it
is
acceptable
under
this
program
for
a
facility
to
demonstrate
compliance
with
the
emission
limits
without
the
use
of
addon
controls
or
through
fuel
switching.
Residual
health
risks
from
these
sources
after
the
NESHAP
emission
limits
have
been
implemented
will
be
addressed
in
eight
years
under
the
112(
f)
residual
risk
program.
113
Comment:
One
commenter
(
354)
suggested
EPA
consider
requiring
mine
permitting
authorities
to
impose
restrictions
on
issuance
of
mining
permits
for
coal
seams
deemed
to
have
unacceptable
levels
of
HAP.

Response:
We
are
required
to
develop
and
implement
a
NESHAP
for
boilers
and
process
heaters
since
they
are
a
listed
source
category
under
section
112
of
the
CAA.
Coal
mines
are
not
a
specifically
listed
source
under
this
program.
Therefore,
we
cannot
regulate
coal
mines
directly
under
the
NESHAP
program.
For
some
facilities,
their
economics
allows
them
to
purchase
coal
with
pollutant
contents
higher
than
the
emission
limits
and
use
control
to
achieve
compliance.
This
is
an
acceptable
option
under
this
NESHAP.
As
part
of
their
fuel
purchasing
contracts,
sources
also
have
the
option
of
requiring
coal
mines
to
only
ship
coal
that
contain
pollutants
at
concentrations
less
than
the
emission
limits
of
this
NESHAP.

Comment:
One
commenter
(
491)
stated
that
§
§
63.7540(
a)(
4),
(
6),
and
(
8)
include
provisions
for
conducting
new
performance
tests
in
the
event
a
new
type
of
fuel,
a
fuel
from
a
new
supplier,
or
a
new
mixture
of
fuel
is
burned
and
the
calculated
values
exceeded
the
established
values.
However,
it
is
not
clear
what
time
period
is
allowed
for
conducting
the
tests.
The
commenter
suggested
that
EPA
clarify
the
applicable
time
period.
The
commenter
requested
that
EPA
allow
the
source
180
days
in
which
to
perform
this
new
performance
test.
The
commenter
stated
that
this
time
is
necessary
for
the
owner
or
operator
to
schedule
and
conduct
the
performance
test
and
to
perform
multiple
tests
if
needed
to
establish
worst­
case
fuel
conditions.
The
commenter
stated
that
noncompliance
should
not
result
if
the
new
performance
test
indicates
that
the
applicable
emission
limitations
have
not
been
exceeded.

Response:
We
agree
that
some
time
allowance
is
needed
for
which
a
source
must
conduct
a
new
performance
test
if
it
burns
a
new
fuel
that
has
a
pollutant
content
higher
than
the
fuel
that
they
have
previously
burned
and
the
source
cannot
demonstrate
compliance
with
the
emission
limits
through
fuel
analysis.
However,
we
believe
that
180
days
it
too
long.
We
agree
that
switching
the
type
of
fuel
requires
planning,
but
we
believe
that
60
days
is
adequate
time
to
conduct
a
performance
test
in
such
situations.
If
a
source
is
planning
to
switch
its
fuel,
then
they
should
have
time
to
prepare
for
a
performance
test.
We
have
also
modified
the
fuel
monitoring
provisions
such
that
sources
are
required
to
conduct
fuel
analyses
only
if
a
new
fuel
type
(
i.
e.,
bituminous
coal,
tires,
biomass)
is
burned.
This
should
minimize
performance
testing
that
is
triggered
by
natural
variation
with
a
fuel
type.
If
a
new
performance
test
is
required
due
to
the
use
of
a
new
fuel
type,
then
the
source
must
demonstrate
compliance
with
the
applicable
emission
limits
and
establish
new
applicable
operating
limits.

11.2
MONITORING
Comment:
One
commenter
(
417)
stated
that
the
proposed
rule's
approach
to
monitoring
is
unduly
burdensome
and
overly
restrictive
and
suggested
that
affected
units
be
given
the
flexibility
to
develop
a
source
specific
monitoring
program
that
builds
on
current
monitoring
practices
and
is
consistent
with
existing
rule
and
permit
requirements.
The
commenter
also
suggested
that
operators
have
the
flexibility
to
propose
a
monitoring
plan
for
ESP
performance
indicators
rather
than
conforming
to
a
single
monitoring
requirement.

Response:
We
revised
the
monitoring
provisions
to
minimize
the
burden
of
the
boilers
114
NESHAP
on
affected
sources.
However,
we
must
have
continuous
monitoring
provisions
to
ensure
ongoing
compliance
with
the
NESHAP
and
cannot
completely
eliminate
them.
We
have
worked
to
use
parameters
already
monitored
by
most
sources
as
the
basis
for
ongoing
operating
limits.
We
chose
this
approach
to
minimize
the
monitoring
burden.
However,
we
are
unable
to
address
all
the
configurations
that
exist.
If
you
believe
your
source
needs
a
more
site­
specific
monitoring
plan,
you
can
petition
the
Administrator
for
an
alterative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Several
commenters
(
297,
364,
387,
399,
491,
492)
argued
that
units
that
operate
fabric
filters
should
be
able
to
use
either
a
continuous
opacity
monitoring
systems
(
COMS)
or
a
bag
leak
detection
system
to
monitor
compliance
and
that
a
requirement
to
use
both
systems
would
be
duplicative,
expensive,
and
not
necessary.
Some
commenters
(
382,
419,
478,
529)
recommended
that
EPA
allow
facilities
that
operate
fabric
filters
the
option
to
use
pressure
drop
monitors.
One
commenter
(
297)
expressed
concern
over
the
requirement
to
establish
an
opacity
limit
based
on
the
measured
opacity
during
the
performance
test.
The
commenter
explained
that
it
is
not
reasonable
to
have
such
a
requirement
because
the
commenter
typically
operates
the
boiler
near
0
percent
opacity.
The
commenter
argued
that
it
is
not
reasonable
to
establish
the
emission
limit
at
near
0
percent.
Another
commenter
(
419)
noted
that
COMS
are
known
to
have
difficulty
measuring
less
than
10%
opacity.
The
commenter's
historical
opacity
levels
are
between
0
and
5%
and
commenter
does
not
want
to
be
forced
into
purchasing
an
expensive
COMS
system
that
is
less
accurate
then
their
current
pressure
drop
monitoring
practice.
Several
commenters
(
364,
382,
387,
388,
399,
449,
491,
492,
498,
524,
533)
recommended
that
EPA
clarify
in
the
final
rule
that
new
or
existing
units
with
bag
leak
detectors
on
fabric
filters
are
not
required
to
monitor
opacity
nor
would
they
be
subject
to
any
opacity
limits.
The
commenters
noted
that
there
are
conflicting
statements
within
the
proposed
preamble
and
rule
that
indicate
that
bag
leak
detection
systems
and
opacity
monitoring
systems
may
both
be
required.
One
commenter
(
491)
stated
that
bag
leak
detection
systems
should
be
used
in
all
cases.
In
addition,
the
commenter
stated
that
the
installation
and
operation
of
a
continuous
monitoring
system
for
those
boilers
and
process
heaters
that
are
equipped
with
a
fabric
filter
serves
no
useful
purpose.
One
commenter
(
492)
suggested
that
a
bag
leak
detection
system
be
considered
an
operating
parameter
and
a
clarification
that
the
General
Provisions
requirement
of
submittal
of
continuous
opacity
monitoring
system
data
does
not
apply
to
fabric
filter
equipped
units.

Response:
In
the
final
NESHAP,
we
clarified
that
sources
using
fabric
filter
control
have
the
option
of
using
either
opacity
monitoring
systems
or
bag
leak
detection
systems
to
demonstrate
continuous
compliance.

Comment:
One
commenter
(
413)
requested
EPA
explain
how
sources
are
to
chose
the
alarm
sensitivity
for
bag
leak
detectors
and
whether
the
level
can
be
adjusted
over
time.
The
commenter
added
that
if
EPA
intends
the
alarm
level
to
be
based
on
performance
testing,
EPA
has
not
explained
how
that
would
be
accomplished.
The
commenter
concluded
that
EPA
has
not
demonstrated
that
the
5
percent
alarm
rate
limit
is
reasonable
or
that
technology
is
sufficiently
reliable
to
be
used
as
a
compliance
method.

Response:
As
outlined
in
the
final
NESHAP,
we
supplied
guidance
on
fabric
filter
operating
in
a
document
entitled
"
Fabric
Filter
Bag
Leak
Detection
Guidance."
This
document
is
available
at
www.
epa.
gov/
ttnemc01/
cam/
tribo.
pdf.
We
believe
that
the
5
percent
alarm
rate
is
a
115
reasonable
allowance
for
sources
due
to
variation
in
operation
and
fabric
filter
failure
that
can
occur
during
normal
operation
and
have
also
require
sources
to
develop
a
startup,
shutdown,
and
malfunction
plan
that
will
outline
corrective
actions
when
a
fabric
filter
alarm
is
triggered.

Comment:
Some
commenters
(
478,
491,
529)
expressed
concern
over
the
proposed
requirement
for
positive
pressure
fabric
filters
to
have
bag
leak
detection
systems
located
on
each
cell,
but
only
one
bag
leak
detection
system
is
required
for
negative
pressure
systems.
The
commenters
stated
that
they
understand
this
requirement
when
each
compartment
or
cell
exhaust
directly
to
the
atmosphere,
however,
many
fabric
filters
exhaust
through
a
stack.
Therefore,
the
commenters
stated
that
a
single
bag
leak
detector
will
be
sufficient
downstream
of
a
positive
pressure
fabric
filter
when
all
compartments
or
cells
are
ducted
to
a
common
stack
before
being
exhausted
to
the
atmosphere.
One
commenter
(
478)
argued
that
as
long
as
a
unit
can
be
monitored
in
accordance
with
§
63.7505(
cdc)(
1)(
i),
a
single
instrument
should
be
sufficient
to
demonstrate
compliance
for
positive
pressure
fabric
filter
systems.
One
commenter
(
529)
reviewed
the
Fabric
Filter
Bag
Leak
Detection
Guidance
referenced
in
§
63.7525(
f)
as
providing
specifications
and
recommendations
for
bag
leak
detection
systems.
However,
the
commenter
reported
that
this
document
specifically
states
that
it
"
does
not
impose
regulatory
requirements."
The
commenter
recommended
that
the
requirements
be
pulled
from
the
Guidance
and
inserted
into
the
MACT
or
that
the
guidance
document
be
required
to
establish
bag
leak
detection
system
installation,
operation
and
maintenance
criteria.

Response:
We
agree
with
the
commenters.
In
the
final
rule,
we
require
only
one
bag
leak
detector
on
the
outlet
positive
pressure
fabric
filters,
as
long
as
they
are
ducted
into
a
common
stack.
If
the
individual
fabric
filter
cells
do
not
duct
into
a
common
stack,
then
bag
leak
detectors
will
be
required
for
each
cell.
The
guidance
document
offers
one
way
to
specify
an
acceptable
fabric
filter
bag
leak
detection
system.
You
also
have
the
option
to
petition
the
Administrator
for
an
alternative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
One
commenter
(
393)
believes
the
proposed
requirement
to
use
of
a
bag
leak
detection
system
will
not
demonstrate
non­
compliance
with
emission
limits.
The
commenter
noted
that
EPA
can
prove
that
the
activation
of
a
bag
leak
detection
alarm
is
an
indication
that
the
source
is
exceeding
the
emission
limits
of
the
boilers
NESHAP.
Another
commenter
(
413)
questioned
EPA's
proposal
to
use
opacity
and
ESP
voltage
and
power
measurements
as
enforceable
operating
limits
because
EPA
has
not
provided
a
direct
correlation
between
opacity
and
PM
or
mercury
to
justify
an
enforceable
limit.

Response:
The
use
of
bag
leak
detectors
and
ESP
voltage/
current
monitoring
is
employed
to
determine
the
operational
status
of
the
various
control
devices.
The
use
of
operating
limits
is
not
based
on
a
direct
correlation
with
emission
levels,
operating
limits
are
used
to
ensure
that
pollution
control
systems
are
operating
similarly
to
their
operation
during
the
performance
test
that
demonstrated
compliance
with
the
emission
limits.
Since
demonstrated
and
cost­
effective
CEMS
for
particulate
matter,
mercury,
or
total
selected
metals
are
not
widely
used,
we
use
parameters
that
facilities
already
monitor
to
determine
control
device
performance.
As
we
do
not
have
a
direct
correlation
between
the
operational
parameters
of
these
control
devices
and
emission
levels,
the
final
rule
provides
a
10
percent
operating
range
around
the
parameters
established
during
the
performance
testing
to
account
for
normal
variations
in
operation
of
the
source
and
pollution
control
device.
116
Comment:
One
commenter
(
529)
explained
that
§
63.7540(
a)(
9)
allows
an
alarm
on
the
bag
leak
detection
system
to
not
be
counted
"
if
inspection
of
the
fabric
filter
demonstrates
that
no
corrective
action
is
required."
The
commenter
believes
this
wording
implies
that
the
baghouse
should
be
shut
down
for
inspection.
This
procedure
should
be
covered
in
the
Site
Specific
Monitoring
Plan
required
in
§
63.7505(
cd)
and
suggested
that
EPA
modify
that
language
to
read
"
if
inspection
of
the
fabric
filter
in
accordance
with
the
Site
Specific
Monitoring
Plan
demonstrates
that
no
corrective
action
is
required."

Response:
We
agree
with
the
commenter
that
a
fabric
filter
should
not
have
to
be
shut
down
for
inspection
if
an
alarm
is
triggered
and
revised
the
final
NESHAP
according
to
the
commenter's
suggestion.

Comment:
Several
commenters
(
364,
399,
387,
519)
requested
the
EPA
remove
or
qualify
the
requirement
that
facilities
use
manufacturer's
originally
installed
control
device
operating
parameter
monitoring
equipment.
The
commenter
noted
that
facilities
typically
replace
original
equipment
for
various
reasons
and,
therefore,
this
requirement
may
not
be
appropriate.

Response:
We
agree
with
the
commenter
and
removed
from
the
final
rule
the
requirement
to
use
the
manufacturer's
originally
installed
monitoring
requirement.
However,
you
must
have
equivalent
monitoring
equipment
in
place
if
you
use
that
monitoring
parameter
to
demonstrate
continuous
compliance.

Comment:
Several
commenters
(
364,
399,
387,
468,
491)
requested
that
EPA
revise
the
language
in
§
63.7530(
c)(
6)(
ii)
and
in
Tables
7.
A
and
7.
B
to
require
monitoring
only
for
the
parameters
that
impact
the
specific
pollutant
for
which
the
control
is
installed.
For
example,
if
a
source
uses
a
scrubber
to
control
particulate
matter,
and
hydrogen
chloride
is
controlled
by
limiting
fuel
chlorine
content,
the
source
should
not
be
required
to
monitor
pH
of
the
scrubber.
Or,
conversely,
if
a
scrubber
controls
hydrogen
chloride
with
a
scrubber
but
not
particulate
matter,
then
scrubber
liquid
flow
rate
and
pH
would
be
appropriate
monitoring
parameters
and
pressure
drop
would
not.

Response:
We
agree
with
the
commenters.
In
the
final
rule,
we
completely
revised
the
tables
at
the
end
of
the
rule
to
make
the
compliance
requirements
more
simple
to
understand
and
apply
in
practice.
For
example,
if
a
wet
scrubber
is
used
to
control
particulate
matter
and
is
not
credited
for
hydrogen
chloride
removal,
then
the
source
would
not
be
required
to
monitor
pH.
Also,
if
a
source
is
not
taking
credit
for
fabric
filter
control
or
if
the
fabric
filter
control
is
not
applicable
to
the
pollutant
in
question
(
i.
e.,
hydrogen
chloride),
then
the
source
is
not
required
to
monitor
bag
leak
detection
alarms.

Comment:
Several
commenters
(
364,
399,
387,
444)
requested
that
EPA
allow
certain
types
of
solid
fuel­
fired
boilers
equipped
with
dry
control
devices
to
choose
which
operational
parameter
(
e.
g.,
ESP
voltage,
fabric
filter
leak
detection)
would
be
used
as
a
sole
compliance
monitoring
method.

Response:
For
sources
with
dry
control
devices,
you
must
either
monitor
fuel
pollutant
content,
opacity,
or
fabric
filter
leak
detection
alarms
to
demonstrate
compliance.
We
do
not
allow
the
monitoring
of
ESP
parameters
as
a
sole
method
of
compliance
for
sources
with
dry
117
controls.
We
believe
that
the
use
of
opacity
and
leak
detection
monitoring
devices
are
more
effective
for
determining
the
ongoing
operation
of
a
source
and
its
pollution
control
device
than
ESP
parameters.
However,
when
a
wet
control
device
is
employed
with
an
ESP,
we
require
the
monitoring
of
ESP
parameters
as
opacity
monitoring
systems
may
not
be
an
effective
monitoring
device
in
wet
exhaust
conditions.

Comment:
One
commenter
(
529)
recommended
that
the
word
"
secondary"
be
included
in
all
references
to
voltage,
current,
and
power
to
clearly
specify
that
all
operating
limits
are
established
for
the
secondary
side
of
the
transformer/
rectifier
set.
The
commenter
explained
that
operating
limits
need
to
be
established
that
allow
an
operating
range
for
ESPs,
or
require
a
multipoint
testing
and
monitoring
of
firing
conditions
to
describe
the
ESP
operating
limit.
This
is
necessary
because
as
a
firing
rate
for
a
boiler
decreases,
the
pollutant
emissions
decrease
and
the
power
required
to
charge
the
particle
in
the
ESP
decreases
significantly.
One
commenter
(
413)
provided
a
detailed
explanation
that
ESP
power
input
is
not
directly
related
to
particulate
removal
performance.
One
commenter
(
364,
399,
387)
requested
that
EPA
allow
the
use
of
monitoring
alternatives
including
the
monitoring
of
voltage
applied
to
an
ESP
instead
of
secondary
current
and
secondary
voltage.
One
commenter
(
357)
stated
that
the
setting
of
operating
limits
is
unworkable
as
stated
in
the
rule
regarding
ESP
readings
for
solid
fuels.
The
commenter
stated
that
it
is
not
reasonable
to
set
ESP
limits
based
on
the
performance
testing
because
ash
content
affects
ESP
current
load.
The
commenter
stated
that
a
particular
solid
fuel
such
as
coal
may
have
the
same
selected
metals
content
per
Btu,
but
a
different
ash
content.
In
addition,
the
commenter
stated
the
ESP
can
draw
more
current
while
maintaining
the
same
removal
efficiency
with
higher
ash
loading.
The
commenter
suggested
another
option
for
setting
ESP
operating
limits
is
to
determine
ESP
efficiency
and
along
with
fuel
analysis
determine
an
operating
limit.

Response:
The
final
NESHAP
provides
you
with
the
option
of
monitoring
voltage
and
secondary
current
or
total
power
input
to
the
ESP.
We
also
provided
a
10
percent
operating
range
to
the
operating
limit
established
during
the
performance
testing
to
allow
for
normal
process
variation.
If
you
believe
that
you
need
another
approach
to
monitoring
your
ESP,
you
can
petition
the
Administrator
for
an
alternative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
One
commenter
(
515)
expressed
concern
that
the
requirement
to
monitor
scrubber
pH
is
not
an
appropriate
operational
parameter
for
a
wet
scrubber
that
controls
hydrogen
chloride.
The
commenter
explained
that
hydrogen
chloride
is
very
water
soluble
in
water
and
that
at
low
concentrations,
the
pH
of
the
scrubber
liquid
will
be
quite
acidic.
The
commenter
requested
that
EPA
require
monitoring
of
scrubber
liquid
hydrogen
chloride
content
and
for
facilities
to
maintain
the
hydrogen
chloride
content
at
or
below
10
percent
to
determine
compliance.
The
commenter
noted
that
this
could
be
done
by
periodically
titrating
collected
samples
with
1N
caustic.
The
commenter
also
provided
hydrogen
chloride
vapor
pressure
and
concentration
curves
to
support
their
argument.

Response:
We
disagree
with
the
commenter
and
continue
to
require
sources
with
wet
scrubber
control
of
hydrogen
chloride
(
and
other
inorganic
HAP)
to
monitor
scrubber
effluent
pH.
We
believe
that
establishing
a
pH
operating
limit
based
on
the
results
of
a
performance
test
that
demonstrates
compliance
with
the
hydrogen
chloride
emission
limit
will
ensure
that
the
wet
scrubber
is
operating
similarly
to
its
operation
during
the
performance
test
that
demonstrated
118
compliance
with
the
hydrogen
chloride
emission
limit.
Furthermore,
the
monitoring
of
pH
is
a
common
monitoring
parameter
for
wet
scrubbing
systems
and
minimizes
additional
compliance
expenses.

Comment:
Several
commenters
(
364,
399,
387)
requested
that
EPA
change
the
requirement
for
wet
scrubbers
to
set
operating
limits
based
on
the
highest
pressure
drop
and
liquid
flow
rate
values
measured
during
the
initial
performance
tests
to
one
based
on
the
lowest
measurements.

Response:
We
agree
with
the
commenters
and
changed
the
language
in
the
final
NESHAP.
The
proposal
language
was
in
error
and
in
the
final
NESHAP
we
require
that
the
operating
limit
to
be
set
at
the
minimum
pressure
drop
and
liquid
flow
rate
that
demonstrates
compliance
with
the
emission
limits.

Comment:
One
commenter
(
519)
argued
that
the
proposed
monitoring
parameters
for
ESPs
are
not
indicative
of
performance
of
ESPs
equipped
with
microprocessor­
based
control
systems.
The
commenter
explained
that
these
types
of
ESPs
adjust
power
usage
based
on
unit
load
and
the
proposed
monitoring
parameters
are
inappropriate
and
unreasonable.
The
commenter
suggested
that
ESPs
equipped
with
microprocessor
control
have
the
following
requirements:
1)
monitor
primary
voltage
to
assure
that
voltage
remains
above
the
minimum
level
required
to
assure
creation
of
a
corona
(
which
is
a
site­
specific
variable
depending
on
ESP
geometry);
and
2)
maintain
a
log
of
all
instances
when
the
ESP
control
system
trips
off
or
alarms,
including
the
date,
duration,
and
cause
of
the
incident.
The
commenter
also
provided
a
paper
explaining
ESP
operation
and
suggested
monitoring
methodologies.

Response:
We
acknowledge
that
sources
may
have
different
types
of
control
device
operating
systems
but
realize
that
it
would
be
impossible
to
capture
all
the
different
systems
in
a
single
rule.
If
you
believe
that
you
can
develop
a
better
monitoring
plan
for
your
source,
you
may
petition
the
Administrator
for
an
alternative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Several
commenters
(
364,
399,
387,
444)
requested
that
EPA
establish
a
larger
universe
of
scrubber
designs
and
appropriate
monitoring
parameters.
The
commenters
argued
that
additional
scrubber
types
exist
than
those
in
the
proposed
rule
and
that
the
proposed
monitoring
parameters
may
not
be
appropriate
for
these
other
types
of
scrubbers.
One
commenter
(
364,
399,
387)
offered
to
work
with
EPA
to
develop
a
larger
matrix
of
scrubbers
and
associated
monitoring
parameters.

Response:
As
we
discussed
in
other
responses,
it
would
be
almost
impossible
to
capture
all
the
different
types
of
control
devices
in
operation
and
to
predict
what
types
of
future
controls
will
be
employed.
Therefore,
we
provided
operating
limits
for
the
majority
of
the
control
devices
in
operation.
If
your
source
has
a
different
type
of
control
device
than
one
listed
in
the
rule,
you
can
petition
the
Administrator
for
an
alternative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Several
commenters
(
374,
388,
403,
444,
445,
449,
478,
498,
523,
524,
533)
requested
that
EPA
extend
the
averaging
periods
for
operating
limits
based
on
fuel
sampling
for
119
pollutant
concentrations.
The
commenters
argued
that
coal
quality
is
inherently
variable
across
suppliers,
but
also
within
a
single
supplier.
By
providing
a
time­
weighted
average
limit,
the
affected
source
would
not
have
rejected
individual
shipments
due
to
variations
that
result
in
fuel
pollutant
concentrations
above
the
established
limit,
but
could
offset
over
the
averaging
period
to
compensate
for
the
off­
specification
shipment
of
fuel.
The
commenters
explained
that
such
a
short
averaging
time
would
not
be
practical
given
the
multitude
of
fuel
suppliers
that
a
facility
might
have
and
is
also
not
consistent
with
the
limit
for
fuel
combinations
tested
during
the
performance
test.
One
commenter
(
374)
explained
that
longer
averaging
times
are
appropriate
because
1)
fuel
pollutant
content
is
variable;
2)
these
emission
limits
are
designed
to
address
chronic
exposure
and
not
acute
risks;
3)
it
provides
compliance
flexibility;
and
4)
it
provides
the
same
overall
emission
reductions.
One
commenter
(
523)
stated
that
daily
tracking
of
fuel
usage
is
unnecessary
and
likely
an
inaccurate
means
of
tracking
usage
since
the
gauges
used
to
track
fuel
usage
are
generally
not
designed
to
precisely
track
daily
usage.
Some
commenters
(
403,
444,
523)
requested
changing
the
averaging
period
to
monthly.
One
commenter
(
478)
requested
that
facilities
only
be
required
to
track
fuel
usage
on
an
as­
occurring
basis,
such
as
whenever
a
fuel,
source,
or
supplier
changes.

Response:
In
the
final
boiler
NESHAP,
we
modified
the
fuel
sampling
requirements.
In
the
revised
provisions,
you
must
conduct
initial
fuel
pollutant
analysis
for
each
"
type"
of
fuel
burned
and
then
conduct
further
analyses
for
each
fuel
type
once
every
5
years.
For
the
purposes
of
this
NESHAP,
a
fuel
type
is
defined
as
each
specific
category
of
fuels
burned
by
a
source
(
e.
g.,
bituminous
coal,
subbituminous
coal,
tires,
residual
oil,
biomass,
railroad
ties,
etc.).
For
example,
if
a
you
burn
only
bituminous
coal
and
bark,
then
you
would
have
to
conduct
an
initial
fuel
sample
for
each
fuel,
and
then
one
every
five
years
as
long
as
those
are
the
only
two
types
of
fuel
burned.
Even
if
you
receive
those
same
fuel
types
from
a
different
source
or
suppliers,
you
would
not
have
to
re­
sample
the
fuel
as
long
as
it
is
the
same
type
of
fuel
that
you
have
already
sampled
and
have
been
burning.
If
you
start
to
burn
another
type
of
fuel
such
as
tires,
then
a
sample
of
the
tire
fuel
must
be
analyzed
initially
and
then
every
five
years
as
long
as
the
source
burns
that
type
of
fuel.
This
should
alleviate
the
commenters'
concern
over
having
to
conduct
fuel
sampling
for
fuel
shipments
from
different
sources
or
suppliers.
Also,
we
modified
the
fuel
use
recordkeeping
requirements
to
be
on
a
monthly
basis
and
not
on
a
daily
basis.

Comment:
Several
commenters
(
364,
399,
387)
requested
that
EPA
establish
longer
averaging
times
for
the
continuous
parameter
monitoring
provisions
of
the
boilers
NESHAP.
The
commenters
argued
that
the
proposed
3­
hour
block
average
does
not
allow
enough
time
for
control
equipment
to
respond
to
systematic
adjustments
in
the
manufacturing
process
and
requested
a
minimum
6­
hour
block
averaging
period.

Response:
We
are
not
going
to
extend
the
averaging
periods
for
continuous
monitoring
systems
beyond
3
hours.
In
the
final
NESHAP,
we
added
flexibility
through
the
following
provisions:
1)
provided
a
fixed
opacity
limit
based
on
6­
minute
averages
for
existing
sources
and
3­
hour
block
averages
for
new
sources;
2)
initial
and
every
five
year
fuel
sampling
requirements;
and
3)
a
10
percent
range
for
operating
limits
established
during
performance
testing.
Given
these
changes
in
the
final
rule,
we
are
not
going
to
provide
longer
operating
limit
averaging
periods.

Comment:
One
commenter
(
497)
recommended
a
longer
averaging
period
for
the
proposed
CO
emission
limit,
such
as
an
8­
hour
averaging
period.
120
Response:
In
the
NESHAP,
we
have
made
the
averaging
period
for
CO
to
be
a
rolling
30­
day
average.
We
have
provided
this
averaging
period
to
address
normal
fluctuations
in
fuel
supply
an
operating
conditions.
This
should
address
the
commenter's
concern
over
CO
averaging
period.

Comment:
One
commenter
(
529)
questioned
the
"
6­
month
period"
on
which
operating
limits
for
bag
leak
detection
systems
are
assessed.
The
commenter
stated
that
it
is
unclear
whether
this
period
is
a
single
semiannual
period
or
if
the
period
is
a
rolling
6­
month
period
where
compliance
is
demonstrated
every
month.

Response:
Consistent
with
other
NESHAPs,
the
6­
month
period
is
a
block
period
and
not
a
rolling
period.

Comment:
Several
commenters
(
360,
361,
388,
449,
491,
492,
498,
524,
533)
requested
that
EPA
remove
§
63.7525(
e)(
3)
in
the
proposed
rule,
which
requires
monthly
inspections
of
electronic
equipment
and
connections.
The
commenters
argued
that
these
requirements
add
no
value,
inappropriately
increase
interaction
with
electrical
equipment
adding
increased
safety
concerns,
and
any
system
issues
would
already
be
detected
by
other
means.
Furthermore,
the
commenters
noted
that
these
requirements
are
not
included
in
PS­
1
for
opacity
monitors
nor
are
they
included
in
the
guidance
document
for
leak
detection
systems.
One
commenter
(
362)
expressed
concern
that
the
requirements
for
continuous
monitoring
systems
would
necessitate
a
monthly
shutdown
of
the
affected
source
to
satisfy
the
inspection
requirement.
The
commenter
stated
this
would
be
extremely
burdensome
for
units
that
are
required
to
operate
without
interruption
throughout
the
entire
year,
and
will
likely
result
in
excess
emissions
due
to
shutdown/
startup
activities.
Some
commenters
(
360,
492)
added
that
EPA
has
indicated
that
these
QA/
QC
requirements
would
be
withdrawn
from
other
MACT
standards
and
QA/
QC
requirements
for
continuous
parameter
monitors
would
be
addressed
through
a
generic
rulemaking.

Response:
We
modified
the
language
related
to
developing
site
specific
monitoring
plans
and
associated
QA/
QC
requirements.
Your
site­
specific
monitoring
plan
no
longer
requires
you
to
conduct
monthly
internal
inspections
and
no
longer
require
monthly
inspections.
You
must
develop
ongoing
quality
assurance
procedures
according
to
the
requirements
in
§
63.8(
d)
of
subpart
A
of
part
63.

Comment:
One
commenter
(
536)
suggested
not
requiring
continuous
emission
monitoring
of
carbon
monoxide,
hydrogen
chloride,
mercury,
or
any
other
pollutant
except
for
opacity.
One
commenter
(
397)
supported
the
use
of
opacity
monitors
for
solid
fuel­
fired
units.

Response:
We
do
not
require
CEMS
for
any
pollutants
other
than
opacity,
and
in
some
cases,
and
carbon
monoxide.
For
carbon
monoxide
CEMS,
we
limited
their
requirement
to
units
larger
than
100
MMBtu/
hr;
smaller
units
with
applicable
work
practice
standards
for
carbon
monoxide
only
must
conduct
annual
compliance
tests.
We
do
not
believe
the
CO
CEMS
requirement
for
sources
larger
than
100
MMBtu/
hr
is
burdensome
as
those
units
would
already
be
required
to
have
a
CEMS
system
under
the
NSPS
requirements.

Comment:
Several
commenters
(
357,
444,
491,
523)
stated
that
continuous
operation
of
121
monitoring
equipment
"
at
all
times"
should
be
better
defined
by
providing
a
minimum
data
availability
percentage.
Two
commenters
(
444,
523)
noted
that
the
boilers
NESHAP
allows
baghouses
a
5
percent
allowance
for
operating
in
alarm
conditions,
but
there
are
no
such
equivalent
condition
for
other
continuous
monitoring
systems.
The
commenters
suggested
that
EPA
provide
at
least
a
5
percent
downtime
allowance
per
six­
month
period.
One
commenter
(
491)
noted
that
§
63.7525(
c)(
3)
states
that
any
period
for
which
the
monitoring
system
is
out­
ofcontrol
and
data
are
not
available
for
required
calculations
constitutes
a
deviation
from
the
monitoring
requirements.
The
commenter
stated
that
a
deviation
from
the
monitoring
requirements
should
not
be
a
violation
if
the
monitoring
equipment
has
been
properly
maintained
and
the
malfunction
is
not
reasonably
preventable.
The
commenter
requests
that
§
63.7525(
c)(
3)
include
this
statement,
"
A
deviation
caused
by
a
monitoring
malfunction
is
not
a
violation."

Response:
We
are
not
going
to
provide
specific
continuous
monitoring
system
downtime
allowances.
Monitor
downtime
does
occur
due
to
calibration
and
QA/
QC
procedures,
and
from
occasional
malfunctions.
In
these
situations,
your
site­
specific
monitoring
plan
required
by
§
63.7505(
cdc)
will
address
how
you
will
deal
with
these
issues
and
you
will
be
expected
to
bring
the
monitoring
system
back
into
operation
in
an
expeditious
manner.

Comment:
One
commenter
(
405)
believes
that
since
many
facilities
are
regulated
by
one
or
more
programs
and
an
additional
layer
of
requirement
will
not
effect
emissions,
EPA
should
delete
any
requirements
for
the
use
of
CO
monitors
on
gaseous
and
oil
fired
units
or
limit
its
application
to
units
larger
than
100
MMBtu/
hr.
The
commenter
also
argued
that
it
is
inappropriate
to
require
the
installation
of
individual
CO
monitors
for
small
burners.
The
commenter
stated
that
if
EPA
retains
the
CO
monitoring
requirement,
it
should
clarify
its
application
to
process
heater
units
with
multiple
burners
and
stacks.
Individual
burners
typically
are
rated
under
10MMBtu/
hr
and
vent
to
individual
stacks,
however,
the
process
unit
in
aggregate
may
be
larger
than
10
MMBtu/
hr.

Response:
We
limited
the
application
of
CO
CEMS
to
units
larger
than
100
MMBtu/
hr.
For
a
unit
with
multiple
smaller
burners
with
individual
stacks,
a
CO
CEMS
on
each
stack
would
not
be
required
if
the
burners
ducted
to
each
stack
are
less
than
100
MMBtu/
hr.

Comment:
One
commenter
(
403,
433)
recommended
the
use
of
generic
biomass
fuel
characterizations
by
class
or
categories
instead
of
repeated
fuel
and
emission
testing.
The
commenters
explained
that
these
classes
would
be
based
on
similar
easily
identifiable
fuel
characteristics
such
as
source
and
potential
contamination,
and
on
similar
chloride,
metals,
and
mercury
concentrations.
The
commenter
added
that
facilities
would
be
required
to
certify
that
they
are
burning
only
clean
fuels
or
specific
fuel
mixes
such
that
the
stoichiometric
emissions
are
below
the
regulated
values.
Two
commenters
(
372,
404)
requested
that
EPA
consider
an
exemption
or
exclusion
from
compliance
requirements
for
wood/
biomass
fired
units.
The
commenters
expressed
concern
over
the
monitoring,
recordkeeping,
and
reporting
requirements
for
those
units.
One
commenter
(
433)
stated
that
burning
differing
proportions
of
biomass
and
fossil
fuel
should
not
constitute
a
`
new
mixture'
under
the
proposed
rule.

Response:
We
do
not
provide
an
exemption
from
fuel
sampling
for
biomass
fuel.
However,
we
made
two
changes
since
proposal
that
should
address
the
commenters'
concern.
First,
we
modified
the
fuel
sampling
requirement
to
be
initially
and
then
once
every
five
years
for
each
fuel
type.
You
are
not
required
to
conduct
fuel
analyses
if
a
similar
fuel
type
(
i.
e.,
biomass,
122
bituminous
coal,
etc.)
comes
from
a
different
supplier.
Once
you
have
conducted
the
fuel
analysis
for
each
type
of
fuel
that
you
burn,
you
will
only
be
required
to
record
the
monthly
amounts
of
each
fuel
type
that
you
burn.
You
will
be
required
to
conduct
fuel
sampling
for
each
type
of
fuel
every
five
years
thereafter.
Also,
we
adopted
a
generic
biomass
characterization
and
provided
a
definition
for
biomass
for
the
purposes
of
this
rule.
Therefore,
the
different
types
of
unadulterated
material
that
are
included
in
the
biomass
definition
are
considered
to
be
one
type
of
fuel
and
you
are
only
required
to
conduct
fuel
sampling
for
biomass
once
every
five
years.
We
believe
that
this
significantly
reduces
the
monitoring,
recordkeeping,
and
reporting
requirements
of
the
rule
for
units
that
burn
biomass.
You
will
still
be
required
to
demonstrate
compliance
through
fuel
analysis
or
through
performance
testing
if
the
fuel
analysis
shows
pollutant
content
higher
than
the
emission
limits
of
the
boilers
NESHAP.

Comment:
Several
commenters
(
361,
362,
364,
387,
399,
403,
444,
478,
491,
492,
536)
requested
that
EPA
allow
demonstration
of
compliance
with
the
hydrogen
chloride,
metals,
and
mercury
emission
limits
based
on
stoichiometric
calculation
of
emissions
or
fuel
analysis
and
mass
balance
calculations
at
facilities
without
control
other
than
a
wet
scrubber
or
dry
scrubber
or
those
not
taking
credit
for
control.
The
commenters
argue
that
this
would
reduce
the
cost
of
stack
testing
and
ongoing
compliance
could
be
assured
by
tracking
fuel
usage.
One
commenter
(
362)
did
agree
that
if
the
facility
could
not
demonstrate
compliance
in
this
way,
then
a
new
performance
test
should
be
conducted
to
show
compliance
with
the
emission
limitation.
The
commenter
added
that
is
was
wasteful
to
require
stack
tests
that
cost
$
5,000
to
$
6,000
each,
when
compliance
can
be
demonstrated
on
other
ways.
The
commenter
(
362)
suggested
a
new
equation
to
utilize
if
EPA
allows
this
option.
Two
commenters'
(
492,
536)
suggested
approach
was
to
allow
ongoing
fuel
analysis
as
a
continuing
compliance
demonstration
technique.
This
approach
would
involve
the
following:
1)
establish
a
fuel
input
limit
for
pollutants
(
e.
g.,
x
lb
Cl/
MMBtu)
based
on
the
compliance
test
as
described
in
the
proposal,
2)
periodically
sample
and
analyze
each
fuel
for
pollutant
concentration
and
heat
value,
3)
monitor
daily
usage
of
each
fuel,
4)
calculate
average
daily
pollutant
input
rate
for
all
wastes
fed,
and
5)
demonstrate
that
the
average
daily
pollutant
input
rate
is
equal
to
or
less
than
the
fuel
input
limit.

Response:
In
the
final
NESHAP,
we
provide
the
option
to
either
demonstrate
compliance
through
fuel
analysis
or
through
performance
testing.
The
fuel
analysis
option
is
for
sources
that
can
demonstrate
that
the
fuel
pollutant
content
is
less
than
the
applicable
emission
limit
(
e.
g.,
the
fuel
analysis
results
show
that
the
ratio
of
pollutant
content
to
heat
content
is
less
than
the
respective
emission
limit
in
the
final
NESHAP).
However,
if
you
cannot
demonstrate
compliance
with
the
emission
limits
through
fuel
analysis,
then
you
will
be
required
to
conduct
performance
testing.
We
agree
that
this
will
reduce
the
compliance
costs
for
sources
and
will
still
demonstrate
compliance
with
the
emission
limits.

Comment:
One
commenter
(
536)
suggested
using
published
emission
factors
such
as
AP­
42
or
FIRE
for
hydrogen
chloride
and
particulate
matter
in
lieu
of
any
annual
testing
or
monitoring
for
these
pollutants.
The
commenter
(
357)
stated
that
allowing
sources
the
option
to
use
"
A"
rated
AP­
42
emission
factors
instead
of
performance
testing
is
consistent
with
past
permitting
history
and
provides
an
adequate
means
of
protecting
human
health
and
the
environment.

Response:
We
do
not
allow
sources
to
use
published
emission
factors,
such
as
those
in
123
AP­
42
or
FIRE,
to
demonstrate
compliance
with
this
NESHAP.
Published
emission
factors
are
average
values
and
do
not
provide
specific
emission
information
about
a
particular
source.
The
range
of
data
used
to
develop
an
emission
factor
may
not
all
fall
under
the
emission
limits
in
the
final
NESHAP.
Therefore,
an
emission
factor
for
a
specific
source
may
demonstrate
compliance
with
the
emission
limits
of
this
NESHAP,
but
the
source
could
be
actually
out
of
compliance
with
the
emission
limit
given
the
variation
between
sources.
Also,
performance
testing
is
used
to
establish
operating
parameters
that
are
monitored
to
ensure
ongoing
compliance
with
this
NESHAP.
We
made
several
changes
since
proposal
to
minimize
the
burden
of
this
rule
on
affected
sources
and
believe
that
these
changes
will
result
in
reduced
burden
for
sources,
but
the
use
of
site­
specific
performance
testing
and
fuel
analysis
is
key
to
determining
the
compliance
of
each
source
an
establishing
a
method
to
determine
ongoing
compliance.

Comment:
Several
commenters
(
364,
374,
387,
383,
388,
399,
403,
404,
425,
441,
443,
444,
449,
468,
498,
524,
533)
argued
that
the
proposed
fuel
monitoring
requirements
are
unworkable
biomass
and
multi­
fuel
boilers.
The
commenters
noted
that
some
facilities
may
receive
fuel
shipments
from
up
to
100
different
suppliers
and
that
the
requirement
to
sample
each
time
a
fuel
comes
from
a
new
supplier,
and
the
possibility
for
frequent
performance
testing,
could
become
very
burdensome.
Some
commenters
suggested
using
fuel
purchase
specifications
to
demonstrate
compliance
by
comparing
the
fuel
specifications
to
the
maximum
fuel
pollutant
concentration
established
during
the
performance
testing.
The
commenters
requested
that
EPA
consider
fuel
testing
exemptions
for
inherently
clean
fuels,
breaking
down
biomass
into
several
"
types"
and
then
conduct
quarterly
composite
samples
for
fuel
pollutant
concentration,
and
modifying
the
fuel
testing
requirements
to
account
for
complex
fuel
mixtures.

Response:
In
the
final
NESHAP
we
simplified
the
fuel
sampling
and
analysis
requirements.
You
must
conduct
fuel
sampling
and
analysis
for
each
type
of
fuel
initially
and
then
once
every
five
years.
You
are
not
required
to
conduct
fuel
sampling
for
fuel
shipments
from
different
suppliers
as
long
as
they
supply
the
same
type
of
fuel.
Since
you
will
only
have
to
do
initial
and
five­
year
fuel
sampling,
this
significantly
reduces
the
burden
for
sources
that
receive
the
same
type
of
fuel
from
many
different
suppliers.
Furthermore,
we
designated
that
all
unadulterated
biomass
is
a
single
type
of
fuel.
We
do
not
allow
you
to
use
fuel
purchase
specifications
to
demonstrate
compliance,
you
will
have
to
conduct
fuel
sampling
and
analysis
according
to
the
requirements
in
the
final
rule.

Comment:
One
commenter
(
512)
argued
that
the
proposed
compliance
demonstrations
for
mercury
do
not
ensure
that
the
emission
limit
will
be
met.
The
commenter
explained
that
keeping
track
of
how
a
scrubber
or
precipitator
is
operating
does
not
mean
that
mercury
emissions
are
being
reduced.
The
commenter
requested
that
EPA
require
sources
to
frequently
sample
fuel
for
mercury
content
along
with
measuring
the
inlet
and
outlet
of
the
control
device
to
determine
mercury
reduction
in
order
to
ensure
compliance
on
a
continuous
basis.

Response:
We
disagree
with
the
commenter
and
believe
that
the
compliance
provisions
in
this
NESHAP
will
ensure
that
the
emission
limits
will
be
met.
Performance
tests
demonstrate
if
a
facility
is
meeting
the
emission
limits
and
give
a
clear
determination
of
compliance
with
the
emission
limits.
During
the
performance
testing,
a
source
must
establish
operating
limits
for
the
type
of
control
device
that
is
used.
These
operating
limits
are
required
to
ensure
that
the
source
is
operating
similarly
to
its
operation
during
the
performance
test
that
demonstrated
compliance
124
with
the
emission
limits.
Sources
must
also
sample
and
analyze
the
fuel(
s)
being
burned
during
the
performance
test.
After
the
performance
testing,
the
source
must
monitor
fuel
type
and
use
and
conduct
additional
fuel
sampling
and
analysis
if
a
new
type
of
fuel
is
burned.
If
this
new
fuel
type
has
a
higher
pollutant
content
than
the
type
of
fuels
burned
during
the
last
performance
test,
the
source
will
be
required
to
conduct
additional
performance
testing
within
60
days
of
burning
the
new
fuel
type
to
demonstrate
compliance
with
the
emission
limits.
Given
these
requirements,
we
believe
that
the
final
NESHAP
ensures
compliance
with
the
emission
limits
while
minimizing
the
burden
to
demonstrate
compliance.

Comment:
Several
commenters
(
406,
407,
408,
501)
believes
that
the
burning
of
differing
proportions
of
fuel
should
not
constitute
a
"
new
mixture"
under
the
NESHAP.
The
commenters
noted
that
if
such
an
understanding
is
not
included
in
the
final
rule,
then
the
implementation
could
become
unmanageable.
The
commenters
considered
all
bagasse
produced
from
sugarcane
grown
in
the
same
geographic
region
to
be
the
"
same"
fuel,
and
not
subject
to
the
fuel
switching
provisions
of
the
rule.
One
commenter
(
492)
contended
that
the
requirement
to
conduct
a
new
performance
test
every
time
there
is
a
minor
change
in
fuels
is
unreasonable.
In
particular,
the
commenter
argued
that
fuels
are
often
switched
based
on
economics,
with
the
supplier
being
selected
on
the
best
price
bid.
In
such
situations
the
units
are
burning
like
fuels,
but
the
proposed
requirements
of
§
63.7540
would
make
the
owner
recalculate
the
emission
level,
which
may
require
testing.
The
commenter
believed
that
this
is
burdensome
and
that
the
costs
to
possible
test
and
to
recalculate
emission
levels
each
time
a
fuel
supplier
is
changed
are
not
accounted
for
in
the
economic
burden
estimate.
The
commenter
suggested
that
the
following
language
replace
the
proposed
language
in
§
63.7540:
"
If
you
plan
to
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier,
or
a
new
mixture
of
fuels,
and
the
characteristics
of
the
new
fuel(
s)
are
such
that
the
emissions
limitations
of
Table
1
may
not
be
met,
you
must
perform
a
new
performance
test."

Response:
In
the
final
NESHAP,
we
made
several
changes
to
the
fuel
sampling
and
analysis
requirements
that
should
address
the
commenters'
concerns.
We
provided
fuel
type
designations
in
the
final
NESHAP
such
that
if
you
burn
the
same
fuel
type
(
i.
e.,
biomass,
bituminous
coal,
tires,
etc.,)
you
conduct
fuel
sampling
initially
and
then
once
every
five
years.
This
eliminates
the
requirement
to
conduct
different
fuel
analyses
for
fuel
received
from
different
suppliers.
With
regard
to
burning
different
mixtures
of
fuels,
if
you
demonstrate
compliance
through
fuel
analysis,
you
can
burn
any
mixture
of
fuel
types,
as
long
as
the
pollutant
content
of
the
fuel
mixture
remains
below
your
applicable
emission
limit.
If
you
demonstrate
compliance
through
performance
testing,
you
can
burn
any
mixture
of
fuel
types
as
long
as
the
pollutant
content
of
the
fuel
mixture
remains
below
that
of
the
fuel
mixture
that
you
burned
during
your
last
performance
test.
This
requires
you
to
carefully
plan
your
performance
test
fuel
mixture
so
that
it
has
the
highest
fuel
pollutant
content
that
you
plan
to
burn.
If
you
decide
to
burn
a
new
type
of
fuel
or
fuel
mixture
that
has
a
higher
pollutant
content
than
the
fuel
mixture
burned
during
your
last
performance
test,
you
will
be
required
to
conduct
a
new
performance
test
within
60
days
of
burning
the
new
fuel
mixture.

Comment:
One
commenter
(
491)
stated
that
the
proposed
rule
does
not
specify
allowable
methods
for
determining
chlorine,
mercury,
and
total
selected
metals
content
of
the
fuel.
The
commenter
suggested
that
EPA
clarify
its
expectation
for
allowable
methods
so
operators
can
determine
the
fuel
chlorine
content
and
the
mercury
content
pursuant
to
rule
requirements.
The
commenter
stated
that
similar
circumstances
exist
in
the
rule
for
determination
of
total
selected
125
metals.
In
addition,
the
commenter
stated
that
if
method
selection
is
expected
to
be
made
by
the
operator
and
merely
included
in
the
site­
specific
test
plan
pursuant
to
§
63.7520(
a),
then
EPA
should
clarify
that
expectation.

Response:
In
the
final
rule,
we
specify
the
appropriate
methods
for
determining
the
chlorine,
mercury,
and
total
selected
metals
content
of
the
fuel.
If
you
would
like
to
use
different
fuel
analysis
methods,
you
can
petition
the
Administrator
for
an
alterative
testing
plan
under
§
63.7(
e)(
2)(
ii)
and
(
f)
of
subpart
A
of
part
63.

Comment:
Two
commenters
(
297,
372)
expressed
concern
over
the
proposed
requirement
to
recalculate
the
maximum
pollutant
input
each
time
you
burn
a
new
fuel,
fuel
from
a
new
mixture,
or
from
a
new
supplier.
The
commenters
explained
that
their
fuel
supply
comes
from
many
different
suppliers
and
trying
to
isolate
individual
fuel
shipments
would
not
be
practical.
One
commenter
(
372)
requested
that
after
a
source
has
determined
the
worst
case
fuel
blend,
there
should
be
no
requirement
to
sample
fuel
or
retest
as
long
as
the
maximum
blend
percentage
of
any
fuel
did
not
exceed
the
percentage
fired
during
the
performance
test.
In
addition,
the
commenter
also
requested
that
any
fuel
type
that
was
evaluated
and
determined
not
to
be
part
of
the
worst
case
fuel
blend,
could
be
burned
in
any
amount
during
the
year
without
fuel
analysis
or
retesting.
The
commenter
also
added
that
the
requirement
to
test
fuel
from
every
supplier
will
be
too
costly.
The
commenter
also
suggested
requiring
quarterly
composite
fuel
sampling
instead
of
daily
fuel
analysis.

Response:
In
the
final
NESHAP,
we
modified
the
fuel
sampling
and
analysis
requirements
monitoring
requirements.
You
only
conduct
fuel
sampling
initially
and
then
once
every
five
years
for
each
type
of
fuel
burned.
This
eliminates
the
requirement
to
conduct
fuel
sampling
for
each
type
of
fuel
from
different
suppliers.
With
regard
to
the
fuel
mixture
burned
during
the
performance
test,
if
you
choose
to
demonstrate
compliance
through
performance
testing,
you
should
evaluate
your
fuel
use
and
plan
the
performance
test
such
that
the
mixture
burned
has
the
highest
content
of
pollutants
expected
to
be
burned
during
normal
operation.
After
that
performance
test,
you
are
allowed
to
burn
any
mixture
of
fuel
types
that
have
been
sampled,
as
long
as
the
total
fuel
pollutant
input
is
less
than
that
during
the
last
performance
test.
We
are
still
requiring
you
to
conduct
performance
tests
if
you
burn
a
new
mixture
of
fuel
that
contains
a
higher
regulated
HAP
content
that
the
one
burned
during
the
last
performance
test.
You
are
allowed
to
burn
any
mixture
of
fuels
as
long
as
you
can
demonstrate
that
the
input
of
regulated
HAP
in
the
fuel
stream
is
not
greater
than
that
during
the
last
performance
test.
If
you
demonstrate
compliance
through
fuel
analysis,
you
must
also
conduct
fuel
analyses
for
each
fuel
type
that
you
burn
initially,
and
then
once
every
five
years.
In
this
situation,
all
you
have
to
do
in
demonstrate
that
the
pollutant
content
of
any
fuel
mixture
that
you
burn
is
less
than
your
applicable
emission
limit.

Comment:
One
commenter
(
413)
expressed
concern
about
the
frequency
that
fuel
testing
would
need
to
be
performed
because
sources
purchase
fuel
from
a
variety
of
suppliers
and
many
suppliers
provide
fuel
from
a
variety
of
sources.
The
commenter
suggested
periodic
fuel
testing
as
an
alternative
compliance
option
for
units
with
variable
fuel
supplies.

Response:
In
the
final
NESHAP,
we
revised
the
fuel
sampling
results
to
reduce
fuel
sampling.
You
will
only
have
to
conduct
fuel
sampling
initially
and
once
every
five
years
for
each
fuel
type
burned
by
the
source,
regardless
of
whether
it
comes
from
a
different
source
or
supplier.
126
The
should
eliminate
the
commenter's
concern
over
having
to
conduct
fuel
sampling
for
the
same
type
of
fuel
from
different
suppliers.

Comment:
The
commenter
(
523)
stated
that
tracking
natural
gas
usage
should
not
be
required
for
existing
gas­
fired
units.
The
commenter
stated
that
the
requirement
to
burn
only
natural
gas
could
be
introduced
into
the
Title
V
permits
for
these
sources,
if
they
desire.
The
commenter
stated
that
if
the
existing
gas­
fired
unit
was
converted
to
solid
fuel,
the
source
would
need
to
secure
an
installation
permit
and
the
appropriate
MACT
requirements
would
be
incorporated
into
that
permit.

Response:
All
existing
sources
that
burn
gas
and/
or
oil
only
are
specifically
exempted
from
any
fuel
monitoring
provisions.
New
sources
that
burn
gas
only
do
not
have
to
monitor
fuel
use.
If
you
have
an
existing
or
new
source
that
co­
fires
gas
with
solid
fuels,
you
must
monitor
all
fuel
use
on
a
monthly
basis.

Comment:
One
commenter
(
536)
requested
that
EPA
minimize
monitoring
burdens
on
smaller
systems.
The
commenter
contended
that
smaller
systems
are
being
asked
to
monitor
too
frequently
for
their
budgetary
manpower
and
pose
a
significant
time
and
financial
burden.

Response:
We
agree
with
the
commenter
and
have
taken
some
steps
to
minimize
the
monitoring
burden
on
smaller
sources.
For
example,
we
removed
the
requirement
for
new
sources
with
heat
input
capacities
less
than
100
MMBtu/
hr
that
have
a
work
practice
standard
for
CO
to
install
a
CEMS
for
CO.
Instead,
these
sources
will
have
to
conduct
annual
CO
stack
tests.
This
results
in
a
significant
reduction
in
monitoring
equipment
and
manpower
costs.
We
have
also
included
the
option
to
demonstrate
compliance
through
fuel
analysis
if
the
results
of
the
fuel
analysis
show
that
the
fuel
pollutant
content
is
less
that
the
applicable
emission
limit.

Comment:
Several
commenters
(
364,
399,
387)
argued
that
some
smaller
boiler
stacks
are
poor
structural
candidates
for
retrofitting
continuous
opacity
monitoring
systems
(
COMS).
In
some
cases,
the
commenters
noted
that
to
install
a
COMS,
facilities
may
have
to
completely
replace
the
stack.

Response:
In
the
final
NESHAP
we
have
provided
additional
options
for
demonstrating
compliance,
such
a
fuel
analysis
in
order
to
minimize
the
compliance
burden.
We
realize
that
some
sources
will
have
some
additional
retrofitting
costs
to
install
COMS.
If
a
source
believes
that
the
installation
of
a
COMS
may
be
too
burdensome,
you
can
petition
the
Administrator
for
an
alternative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
One
commenter
(
491)
stated
that
it
is
not
clear
what
the
requirement
"
to
conduct
all
monitoring
in
continuous
operation
at
all
times
that
the
unit
is
operating"
means.
The
commenter
suggested
that
§
63.7525(
c)(
2)
be
clarified
as
follows:
§
63.7525(
c)(
2)
Except
for,
monitoring
malfunctions,
associated
repairs
and
required
quality
assurance
or
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments),
you
must
operate
all
CPMS
at
all
times
that
the
affected
source
is
operating.
A
CPMS
is
not
required
to
be
operated
when
the
affected
source
is
not
operating.
A
monitoring
malfunction
is
any
sudden,
infrequent,
not
reasonably
preventable
failure
of
the
monitoring
system
to
provide
valid
data.
Monitoring
failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
127
malfunctions.

Response:
We
understand
the
commenter's
concern
and
incorporated
their
suggested
language
changes
into
the
final
NESHAP.

Comment:
One
commenter
(
491)
requested
that
EPA
clarify
that
§
63.7505(
cd)
applies
to
continuous
monitoring
systems.

Response:
In
the
final
NESHAP,
we
added
language
to
§
63.7505(
cd)
that
clarify
that
this
section
applies
to
sources
that
demonstrate
compliance
via
performance
testing,
which
are
required
to
use
continuous
monitoring
systems
to
demonstrate
continuous
compliance
with
the
provisions
of
this
NESHAP..

Comment:
One
commenter
(
375)
contended
that
the
EPA's
assertion
that
CEMS
for
particulate
matter
have
not
been
demonstrated
in
the
United
States
for
the
purpose
of
determining
compliance
was
inaccurate.
The
commenter
believes
that
EPA
has
demonstrated
that
particulate
matter
CEMS
can
be
used
from
determining
compliance
with
a
particulate
matter
emission
limit.
The
Office
of
Enforcement
and
Compliance
Assurance
has
required
the
use
of
particulate
matter
CEMS
in
serval
enforcement
actions.
The
particulate
matter
CEMS
installed
as
part
of
the
Tampa
Electric
enforcement
action
has
been
operating
for
over
one
year
and
has
met
the
proposed
performance
specifications.
The
commenter
requested
that
CEMS
be
allowed
as
an
option
to
determine
compliance
with
the
particulate
emission
limits
in
the
NESHAP.
The
commenter
stated
for
those
facilities
that
install
wet
scrubbers
to
control
sulfur
dioxide,
the
use
of
upstream
particulate
removal
device
operating
parameters
will
not
be
sufficient
to
determine
compliance
with
the
particulate
matter
standard
at
the
stack.
The
commenter
suggested
the
proposed
rule
should
require
particulate
matter
CEMS
for
wet
stack
installations
or
the
proposal
of
a
different
mode
of
compliance
assurance.

Response:
We
do
not
explicitly
provide
an
option
in
the
final
boilers
NESHAP
for
the
use
of
particulate
CEMS.
However,
you
can
petition
the
Administrator
for
an
alterative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63.
You
must
provide
the
necessary
site
specific
monitoring
plan
for
your
particulate
matter
CEMS,
including
appropriate
QA/
QC
plans
for
the
CEMS.
If
you
are
approved
to
use
particulate
matter
CEMS
to
determine
compliance
with
an
applicable
particulate
matter
emission
limit,
exceedances
of
the
emission
limit
will
be
considered
a
violation
of
standard
and
you
will
not
be
given
the
operating
range
allowances
provided
for
parametric
monitoring
systems
since
the
particulate
matter
CEMS
provides
real­
time
determination
of
compliance
with
the
emission
limits.

Comment:
One
commenter
(
364,
399,
387)
questioned
whether
only
whole
numbers
be
used
in
recording
instantaneous
values
and
computing
various
averages
of
opacity.
The
commenter
also
asked
if
a
3­
hour
block
average
that
exceeds
the
highest
1­
hour
block
average
recorded
during
the
performance
test
by
0.1
percent
be
considered
an
exceedance.
The
commenter
contended
that
if
this
is
the
case,
then
exceedances
will
occur
on
a
continuous
basis.

Response:
In
the
final
NESHAP,
we
adopted
a
fixed
opacity
limit
for
new
and
existing
sources.
These
fixed
opacity
limits
do
not
include
decimal
places,
therefore,
you
must
determine
compliance
by
using
whole
numbers
for
your
opacity
data.
For
example,
the
existing
source
opacity
limit
for
solid
fuel­
fired
units
is
20
percent.
Since
the
limit
is
not
20.0
percent,
as
long
as
128
your
6­
minute
average
is
20.4
percent
or
less,
you
will
be
in
compliance.

Comment:
Several
commenters
(
364,
375,
387,
388,
399,
449,
498,
524,
533)
requested
that
EPA
allow
existing
common
stack
opacity
monitoring
systems
be
grandfathered
from
the
requirements
of
§
63.8(
b)(
2)
and
(
b)(
3)
that
would
require
monitors
on
individual
effluents
before
they
combine.
The
commenters
believe
that
this
could
be
a
costly
requirement
for
some
affected
sources
with
no
demonstrable
environmental
benefit.
The
commenters
also
noted
that
in
some
cases,
these
"
individual"
opacity
monitoring
systems
would
not
satisfy
the
location
requirements
under
PS­
1
and,
as
such,
could
not
be
used
to
demonstrate
compliance
with
applicable
regulations
under
a
State
rule
or
an
NSPS.

Response:
The
final
rule
does
not
provide
a
specific
"
grandfather"
clause
for
existing
monitoring
systems.
However,
since
the
final
rule
has
adopted
a
fixed
opacity
operating
limit,
the
use
of
a
common
stack
opacity
monitor
would
not
pose
a
compliance
issue
under
this
standard.
If
you
fall
under
this
situation,
you
should
apply
to
the
Administrator
for
an
alternative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63
to
demonstrate
compliance
with
a
common
stack
opacity
monitoring
system.

Comment:
One
commenter
(
445)
requested
that
EPA
allow
the
use
of
existing
continuous
opacity
monitoring
systems
and
non­
mercury
CEMS
as
an
alternative
to
the
operating
limits
for
mercury.
The
commenter
explained
that
these
existing
programs
provide
assurances
of
unit
operations
and
that
no
other
requirements
are
warranted.

Response:
Under
the
final
boilers
NESHAP,
sources
have
the
option
of
using
opacity
monitors
(
or
bag
leak
detection
devices
for
units
with
fabric
filters),
or
fuel
analysis
as
an
option
to
demonstrate
compliance
with
the
mercury
emission
limits.
If
you
wish
to
use
another
monitoring
strategy
for
demonstrating
compliance
with
the
mercury
emission
limits,
you
can
petition
the
Administrator
for
an
alterative
monitoring
plan
under
§
63.8(
f)
of
subpart
A
of
part
63.

11.3
OPERATING
LIMITS
Comment:
Several
commenters
(
355,
359,
374,
384,
393,
409,
410,
413,
417,
478,
482,
484,
521,
522,
523,
535)
opposed
the
use
of
operating
limits
for
demonstrating
compliance
with
the
boilers
NESHAP.
Other
commenters
argued
that
the
establishment
of,
and
ongoing
compliance
with,
site­
specific
limitations
present
difficult
challenges
due
to
fuel
variability,
institutional
procurement
practices,
and
equipment
useful
life
and
will
create
needless
and
overly
stringent
limits
that
cannot
be
consistently
maintained.
Several
commenters
(
359,
409,
413,
482)
opposed
using
operating
limits
as
a
means
of
demonstrating
continuous
compliance
with
emission
limitations
because
they
reduce
operational
flexibility,
eliminate
control
device
margins,
and
provide
incentives
for
sources
to
conduct
performance
tests
at
less
than
optimal
conditions.
Several
commenters
(
374,
410,
417,
523)
stated
that
the
use
of
operating
limits
was
inappropriate
because
it
effectively
sets
a
new
NESHAP
emission
limit
as
the
emissions
are
actually
emitted
during
the
performance
test.
Some
commenters
(
375,
393,
413)
objected
to
the
use
of
operating
limits
because
EPA
has
not
proven
a
direct
correlation
between
those
operating
limits
and
actual
emission
levels.
129
Response:
We
believe
that
continuous
monitoring
is
needed
to
ensure
ongoing
compliance
with
this
rule.
In
order
to
minimize
costs,
we
look
for
parameters
that
are
already
monitored
to
use
for
compliance
demonstration.
We
require
performance
tests
to
demonstrate
compliance
with
emission
limits,
then
use
operating
limits
to
ensure
the
source
is
operating
similarly
to
how
it
was
operating
when
it
completed
a
successful
performance
test.
Operating
limits
are
not
direct
measures
of
emissions,
but
provide
measure
of
fuel
characteristics
and
control
device
performance.
In
addition,
we
modified
and
simplified
opacity
limits,
fuel
sampling/
testing
requirements,
and
are
allowing
emission
averaging.
You
are
also
able
to
petition
the
Administrator
for
approval
of
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Several
commenters
(
364,
370,
374,
382,
383,
387,
388,
391,
392,
399,
401,
404,
406,
407,
408,
449,
452,
491,
492,
498,
501,
521,
524,
533)
requested
that
EPA
follow
previous
opacity
limit
approaches
found
in
boilers
new
source
performance
standards
(
NSPS)
(
40
CFR
part
60,
subpart
Db
and
Dc)
where
20
percent
opacity
is
the
limit
and
one
excursion
to
27
percent
is
allowed
per
day
for
soot
blowing.
The
commenters
stated
that
such
a
limit
may
not
be
achievable
on
an
ongoing
basis
because
boiler
and
particulate
collection
equipment
performance
varies
over
time
due
to
equipment
condition,
fuel
variations,
operating
variations,
and
other
uncontrollable
parameters.
One
commenter
(
404)
requested
that
EPA
consider
a
fixed
opacity
limit
similar
to
the
boilers
NSPS
Subpart
Db
and
suggested
a
14
percent
opacity
limit
that
was
calculated
by
taking
the
particulate
matter
emission
ratio
(
NSPS
and
MACT)
and
applying
it
to
the
20
percent
opacity
limit
in
the
NSPS.
One
commenter
(
374)
suggested
that
EPA
promulgate
a
requirement
for
corrective
action
when
opacity
levels
exceed
20
percent
for
10
consecutive
6­
minute
periods
and
have
an
overall
limit
of
27
percent.
Several
commenters
(
357,
388,
449,
492,
498,
524,
533)
listed
several
issues
that
need
to
be
resolve
before
implementation
if
EPA
decides
to
stay
with
the
proposed
opacity
monitoring
requirement:
1)
How
should
a
one­
hour
block
average
be
calculated
for
performance
test
runs
that
last
longer
than
one
hour?
2)
Should
only
whole
numbers
be
used
for
establishing
limits
and
determining
compliance?
3)
How
will
the
opacity
monitoring
requirements
work
for
units
with
more
than
one
stack?
4)
How
will
the
opacity
monitoring
requirements
work
for
units
that
share
a
common
control
device?
5)
Define
increases
in
opacity
and
opacity
operating
limits
in
5
percent
increments
consistent
with
EPA
Method
9
and
historic
regulatory
enforcement
activities
Response:
We
agree
with
the
commenters
that
an
opacity
operating
limit
based
on
performance
testing
results
may
not
be
appropriate,
and
that
a
fixed
opacity
limit
similar
to
the
NSPS
requirements
would
be
a
better
solution.
Therefore,
in
the
final
NESHAP,
we
incorporated
the
industrial
boilers
NSPS
opacity
provisions
(
20
percent,
one
6­
minute
27
percent
period
per
day)
for
existing
sources
that
may
have
an
applicable
opacity
operating
limit.
If
you
have
a
new
source
that
has
applicable
opacity
operating
limit,
you
will
be
required
to
meet
a
10
percent
opacity
limit
based
on
a
3­
hour13­
hour
block
average.

Comment:
Three
commenters
(
355,
370,
417)
argued
that
limiting
the
fuel
pollutant
content
to
the
level
occurring
during
the
performance
test
is
overly
restrictive
and
limits
flexibility.
One
commenter
(
355)
stated
that
it
is
unreasonable
to
establish
any
type
of
limit
based
on
the
particular
coal
being
combusted
at
the
time
of
a
compliance
test,
because
the
composition
and
characteristics
of
coal
can
vary
widely
from
the
same
mine
and
seam.
Another
commenter
(
417)
pointed
out
that
if
a
facility
uses
a
low
chlorine
fuel,
even
if
the
performance
test
results
are
well
130
below
the
hydrogen
chloride
emission
limit,
the
chlorine
content
during
the
performance
test
becomes
the
new
limit.
Then
a
facility
is
locked
into
an
artificially
restrictive
operating
limit
by
requirements
that
they
recalculate
the
maximum
chlorine
input
from
any
new
fuel
and
conduct
a
new
performance
test.
This
penalizes
facilities
that
use
fuels
with
low
pollutant
content.

Response:
We
agree
with
the
commenters
that
the
proposed
fuel
pollutant
content
operating
limit
may
not
address
normal
fuel
pollutant
variation.
In
the
final
boilers
NESHAP,
we
modified
the
performance
testing
and
fuel
sampling
requirements
to
address
fuel
pollutant
content
variation,
to
minimize
the
compliance
burden,
and
to
simplify
the
requirements.
You
must
conduct
your
performance
test
with
the
fuel
type
or
mixture
of
fuel
types
that
have
the
highest
content
of
pollutants
regulated
by
this
NESHAP.
As
long
as
you
burn
the
same
fuel
types
or
mixture
of
fuel
types
that
have
been
sampled
and
have
a
pollutant
content
lower
than
the
type
or
mixture
of
types
burned
during
the
last
performance
test,
you
meet
the
fuel
content
operating
limit
requirements
of
this
NESHAP.
Therefore,
the
final
NESHAP
bases
compliance
on
fuel
type
and
should
eliminate
the
commenter's
concern
over
locking
into
an
artificially
restrictive
operating
limit.

Comment:
One
commenter
(
395)
recommended
that
the
agency
revise
the
regulation
to
allow
sources
to
operate
control
equipment
within
the
ranges
identified
by
the
equipment
manufacturers.
These
ranges
will
ensure
that
the
equipment
is
operated
appropriately
and,
thus,
effectively
controlling
the
emissions
of
the
associated
source.

Response:
We
do
not
provide
this
option
in
the
final
boilers
NESHAP.
Control
devices
may
operate
differently
in
practice
than
what
the
manufacturer
recommends.
Therefore,
we
are
requiring
sources
to
set
site­
specific
operating
ranges
based
on
performance
testing
results.

Comment:
One
commenter
(
395)
stated
it
was
inappropriate
to
establish
a
single
set
of
operating
parameters
for
most
control
devices
serving
production
operations.
Control
systems
would
be
influenced
by
numerous
parameters
including
ambient
temperature
and
humidity,
process
variations,
pollutant
concentrations,
airflow,
etc.
The
commenter
stated
that
an
operating
parameter
observed
at
one
point
in
time
may
not
be
repeatable,
or
appropriate,
at
a
later
time
even
though
the
system
continuously
maintains
proper
efficiency.

Response:
The
final
NESHAP
contains
more
flexibility
for
operating
limits
than
the
proposal.
We
included
fixed
opacity
limits,
fuel
sampling
requirements
based
on
fuel
type,
and
operating
limit
ranges.
To
incorporate
all
the
operating
factors
and
ambient
conditions
into
the
requirements
of
this
rule
would
be
too
onerous.
If
you
expect
that
the
additional
flexibility
in
the
final
NESHAP
is
not
enough
for
your
source,
you
may
petition
the
Administrator
for
approval
of
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Several
commenters
(
297,
340,
348,
354,
355,
357,
370,
374,
382,
387,
382,
383,
388,
393,
399,
401,
403,
417,
425,
427,
441,
443,
444,
449,
468,
492,
498,
521,
524,
533)
objected
to
the
provision
in
the
proposed
NESHAP
that
would
establish
an
opacity
"
operating
limit"
based
on
the
initial
performance
test.
Some
commenters
contended
that
EPA
has
provided
no
data
or
references
demonstrating
a
relationship
between
opacity
and
particulate,
total
metals,
or
mercury
emissions.
Other
commenters
argued
that
the
proposed
opacity
limit
approach
for
dry
control
devices
is
unworkable
due
to
the
inherent
inability
of
continuous
opacity
monitoring
131
system
(
COMS)
to
accurately
measure
opacity
at
levels
less
than
10
percent.
Some
commenters
argued
that
the
performance
and
opacity
achieved
during
the
initial
test
may
not
be
representative
of
the
unit's
performance.
Other
commenters
explained
that
equipment
condition,
fuel
and
operating
variations,
and
other
uncontrollable
parameters
may
result
in
varying
emissions
and
emissions
control
equipment
efficiencies
over
time.
The
commenters
also
noted
that
the
"
worst
case
fuel"
use
during
initial
performance
test
assumes
"
a
degree
of
perfection
in
fuel
selection
that
is
hardly
achievable
in
actual
practice."
The
commenters
explained
that
"
worst
case
fuels"
with
respect
to
all
pollutants
must
be
considered
during
the
performance
test,
not
just
for
particulate
matter.
Lastly,
the
commenters
argued
that
burning
"
worst
case
fuels"
during
the
initial
performance
test
may
not
result
in
the
worst
case
opacity
levels,
given
that
in­
stack
opacities
depend
on
variables
beyond
the
realm
of
fuel
composition
(
e.
g.,
particle
size
distribution,
flue
gas
properties,
stack
diameters,
etc.).
One
commenter
(
468)
noted
that
the
proposed
operating
limit
a)
does
not
take
into
consideration
any
margin
of
compliance;
b)
ignores
the
reality
of
operating
dynamics
and
other
seasonal
and
diurnal
changes
that
influence
opacity;
c)
raises
the
prospect
that
a
source
could
exceed
the
operating
limit,
but
remain
below
the
underlying
standard;
and
d)
conflicts
with
established
standards
that
acknowledge
the
fundamental
variation
associated
with
opacity
measurement
technology.

Response:
We
agree
with
the
commenters
that
an
opacity
limit
based
on
performance
testing
may
not
be
appropriate
given
the
normal
variation
that
occurs
in
boiler
and
process
heater
operation.
In
the
final
boilers
NESHAP,
we
adopted
a
fixed
opacity
limit
not
set
by
the
performance
test.
For
existing
sources,
it
is
similar
to
the
opacity
limits
in
the
boilers
NSPS
(
40
CFR
part
60,
subpart
Dc).
For
new
sources,
it
is
a
limit
of
10
percent
opacity
based
on
a
3­
hour13­
hour
block
average.
We
believe
that
modifying
the
opacity
limit
to
a
fixed
standard,
this
should
address
the
commenters'
concern
over
normal
process
variation
and
the
relationship
between
"
worst
case"
fuels
and
resulting
opacity
levels.
However,
you
will
still
be
required
to
burn
the
fuel
type
or
mixture
of
fuel
types
that
contain
the
highest
content
of
pollutants
regulated
by
this
NESHAP
when
conducting
performance
tests.

Comment:
One
commenter
(
492)
argued
that
the
procedures
for
establishing
operating
parameters
during
the
initial
performance
test
must
be
prorated
to
the
emission
limitations
to
meet
the
requirements
of
the
Clean
Air
Act
and
to
protect
the
environment.
Since
the
source
cannot
exceed
the
standard
during
the
performance
test,
the
operating
limitations
will
result
in
an
"
above
the
floor"
control
level,
which
is
not
warranted
by
EPA's
MACT
floor
analysis.
As
a
result,
the
commenter
contended
that
sources
either
have
to
run
a
worst
case
fuel
at
the
initial
performance
test
or
accept
above
the
floor
level
of
control,
which
would
be
both
costly
and
detrimental
to
the
environment.
The
commenter
argued
that
the
correct
approach
is
to
allow
the
source
to
set
operating
conditions
to
the
level
that
generates
the
emissions
level
established
in
the
rule.

Response:
We
are
not
allow
facilities
to
prorate
operating
limits.
Without
conducting
performance
testing
over
the
range
of
operating
conditions,
the
correlation
between
operating
levels
and
emission
levels
are
not
available.
In
the
final
NESHAP
we
provided
additional
flexibility
for
you
to
comply
with
the
operating
limit
provisions
(
e.
g.,
fixed
opacity
limits,
operating
limit
ranges,
fuel
sampling
based
on
fuel
type
instead
of
shipment,
supplier,
or
source),
and
believe
that
these
changes
address
the
commenter's
concern.

Comment:
Several
commenters
(
364,
399,
387)
noted
that
many
boilers
that
share
a
132
common
particulate
matter
control
device,
and
conducting
a
performance
test
while
each
boiler
is
burning
its
worst­
case
fuels
will
be
difficult
to
accomplish
and
may
give
non­
representative
opacity
levels
during
the
performance
test.
The
commenter
stated
that
it
is
illogical
to
establish
a
future
opacity
operating
limit
based
on
this
type
of
short­
term
performance
testing.

Response:
The
final
NESHAP
contains
a
fixed
opacity
limit
for
both
new
and
existing
sources.
Therefore,
if
boilers
share
a
common
control
device,
they
will
all
have
to
meet
the
same
opacity
limit.
The
eliminates
the
concern
over
establishing
opacity
operating
limits
during
performance
testing.
Furthermore,
we
modified
the
fuel
sampling
requirements
to
be
based
on
fuel
type
and
not
on
shipment,
supplier,
and
source.
This
change
should
help
you
determine
the
fuel
type
of
fuel
mixture
that
has
the
highest
pollutant
content
for
your
performance
testing.

Comment:
Several
commenters
(
364,
372,
374,
382,
387,
388,
399,
401,
406,
407,
408,
410,
417,
443,
449,
452,
479,
491,
492,
498,
501,
523,
524,
533)
argued
that
operating
limits
(
e.
g.,
parametric
monitoring
ranges,
opacity)
should
not
create
the
same
enforcement
implications
as
emission
limits.
Some
commenters
requested
that
EPA
use
the
operating
limits
established
during
the
initial
performance
tests
as
a
trigger
for
corrective
actions
that
would
be
spelled
out
in
the
startup,
shutdown,
and
malfunction
plan.
Under
this
approach,
the
commenters
explained
that
facilities
would
be
required
to
respond
expeditiously,
and
would
face
enforcement
exposure
if
they
failed
to
do
so.
Therefore,
the
commenters
suggested
that
EPA
change
the
term
"
operating
limits"
to
"
action
levels"
or
"
indicator
parameters."
Other
commenters
(
382,
491,
492)
contended
that
EPA,
by
setting
another
set
of
limitations,
has
extended
the
regulations
beyond
the
MACT
floor,
even
though
the
preamble
states
that
EPA
decided
not
to
go
beyond
the
MACT
floor
level
of
control.
Some
commenters
(
374,
382,
388,
417,
449,
452,
479,
498,
524,
533)
argued
that
EPA
cannot
enforce
operating
limits
as
permit
limits
because
there
is
no
direct
correlation
between
an
exceedance
of
an
operating
limit
and
the
emission
limitations.
One
commenter
(
417)
requested
that
the
ambiguity
regarding
compliance
enforcement
of
operating
limits
be
clarified
in
the
final
regulation
to
provide
uniform
enforcement
across
multiple
types
of
affected
units.
Some
commenters
(
374,
388,
401,
449,
492,
498,
524,
533)
noted
that
other
MACT
provide
for
a
limited
number
of
exceedances
before
a
violation
occurs
and
suggested
that
following
criteria
for
establishing
violations:
1)
Failure
to
initiate
correction
actions
specified
in
the
Operation,
Maintenance,
and
Malfunction
(
OMM)
plan
within
1
hour
of
becoming
aware
of
a
limit
deviation;
and
2)
The
occurrence
of
more
than
six
exceedances
for
a
given
operating
parameter
value
associated
with
monitoring
a
specific
process
or
control
device
in
any
calendar
half­
year
monitoring
period.
The
commenters
urged
the
EPA
to
adopt
this
language
in
the
final
boilers
NESHAP.
One
commenter
(
372)
suggested
that
EPA
adjust
the
opacity
operating
limits
such
that
if
a
facility
exceeds
their
existing
opacity
limit
less
than
3
percent
of
the
time,
then
they
would
demonstrate
compliance
with
the
particulate
matter,
selected
metals,
and
mercury
limits.

Response:
Since
proposal,
we
made
some
changes
that
should
address
the
commenters'
concern.
In
the
final
NESHAP,
we
provided
an
extended
range
of
10
percent
for
operating
limits
established
during
performance
testing.
We
provided
this
range
to
account
for
normal
variation
that
occurs
at
boilers
and
process
heaters.
We
also
changed
the
opacity
limit
requirement
to
incorporate
fixed
opacity
limits
which
are
not
based
on
performance
testing
results.
We
are
not
going
to
provide
any
exceedance
allowances
in
the
final
rule.
The
determination
of
whether
an
exceedance
of
an
operating
limit
is
a
violation
of
the
standard
will
be
made
by
the
Administrator
(
your
local
permitting
authority
if
your
state
or
local
program
is
delegated
authority
to
administer
the
NESHAP
program).
That
determination
would
be
made
based
on
the
nature
of
the
133
exceedance,
your
adherence
to
your
SSM
plan
during
the
exceedance,
and
your
history
of
compliance.

Comment:
Several
commenters
(
359,
413,
482,
484,
523,
535,
536)
stated
that
affected
sources
should
only
be
required
to
demonstrate
compliance
through
performance
testing
with
applicable
emission
limitations
for
each
type
of
unit.

Response:
To
ensure
ongoing
compliance,
we
need
some
sort
of
continuous
monitoring
provisions.
While
performance
testing
gives
an
accurate
measure
of
compliance
for
discrete
periods,
it
is
generally
too
expensive
to
be
conducted
on
an
ongoing
basis.
In
effort
to
minimize
costs,
we
look
for
operating
parameters
that
are
already
being
measured
by
sources
that
can
provide
an
indication
of
source
and
control
device
operation.
This
approach
to
monitoring
continuous
compliance
is
not
unprecedented
and
we
retained
the
approach
in
the
final
rule.
The
purpose
for
operating
limits
is
to
ensure
that
the
boiler
or
process
heater
is
operating
in
a
manner
similar
to
its
operation
during
the
performance
test
that
demonstrated
compliance
with
the
emission
limits
of
this
NESHAP.

Comment:
Several
commenters
(
376,
413,
482,)
urged
EPA
to
employ
concepts
in
the
compliance
assurance
monitoring
(
CAM)
rule
that
allows
for
establishment
of
more
rational
and
reasonable
operational
parameter
levels.
The
commenter
added
that
sources
would
then
be
required
to
monitor
those
parameters
and
respond
to
changes
that
indicate
problems
with
the
controls
that
could
jeopardize
compliance.

Response:
We
have
worked
to
minimize
the
compliance
costs
associated
with
this
NESHAP
and
in
the
final
NESHAP,
we
made
several
changes
to
achieve
this
goal.
We
used
guidance
from
the
CAM
rule
to
establish
methods
for
setting
operating
limits.
However,
the
CAM
rule
was
designed
to
provide
a
reasonable
assurance
of
compliance,
which
is
a
lower
standard
of
compliance
than
the
NESHAP
program,
which
requires
continuous
compliance.
Therefore,
we
did
not
directly
incorporate
concepts
of
the
CAM
rule
into
the
final
NESHAP.
You
are
also
able
to
petition
the
Administrator
for
approval
of
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Several
commenters
(
340,
364,
387,
399,
484)
questioned
how
3­
hour
block
averages
for
operating
limits
would
be
calculated
when
the
three
performance
test
runs
exceed
three
hours
in
duration.
One
commenter
(
340)
recommended
using
the
terms
"
three
test
runs"
and
the
"
three­
run
performance
test"
in
the
text
to
establish
operating
limits.

Response:
In
the
final
rule,
your
operating
limits
will
be
based
on
the
lowest
or
highest
average
parameter
level
measured
during
the
three­
run
performance
testing.
For
example,
if
you
are
determining
the
minimum
sorbent
injection
rate
(
e.
g.,
your
sorbent
injection
rate
operating
limit),
it
would
be
90
percent
of
the
lowest
average
sorbent
injection
rate
measured
during
the
three­
run
performance
test
as
determined
by
Table
7
of
the
final
rule.
The
modification
of
determining
your
operating
limits
should
address
the
commenter's
concern.
Furthermore,
we
have
modified
the
language
in
the
rule
to
use
the
term
"
test
run
average"
and
do
not
based
it
on
a
1­
hour
average.

Comment:
Several
commenters
(
361,
362,
364,
387,
399,
439,
444)
expressed
concern
134
over
the
requirement
to
set
operating
limits
based
on
the
results
of
three
1­
hour
performance
tests.
The
commenters
pointed
out
that
this
method
represents
only
three
out
of
a
possible
8,760
hours
per
year,
these
results
would
not
represent
normal
operating
fluctuations
and
that
maintaining
compliance
with
these
operating
limits
may
be
difficult.
The
commenter
believes
that
EPA
should
allow
for
typical
operational
and
process
variations
that
cause
a
process
to
operate
both
above
and
below
average
values
when
determining
operating
limits.
Two
commenters
(
361,
362)
suggested
that
a
more
statistically
valid
method
should
be
used
for
establishing
site­
specific
operating
parameters.
Several
commenters
(
364,
399,
387)
suggested
that
EPA
allow
facilities
the
flexibility
to
set
continuous
parameter
monitoring
ranges
based
on
normal
operating
variability
and
proposed
changes
to
the
regulatory
text
to
address
these
concerns.

Response:
We
provided
more
flexibility
in
the
final
rule
for
regarding
operating
limits
(
i.
e.,
fixed
opacity
limits
not
based
on
performance
testing
results,
a
10
percent
operating
range
for
operating
limits
established
by
performance
testing,
option
for
compliance
demonstration
through
fuel
analysis,
simplified
fuel
sampling
requirements
based
on
fuel
type
with
no
sampling
triggers
based
on
fuel
supplier
or
source
changes).
We
believe
that
these
changes
allow
for
operational
and
process
variations
that
may
not
be
observed
during
performance
testing.
However,
if
you
wish
to
establish
a
different
monitoring
strategy
based
on
statistical
or
some
other
methods,
you
can
petition
the
Administrator
for
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Several
commenters
(
338,
364,
374,
382,
387,
388,
395,
399,
403,
413,
417
444,
449,
484,
491,
492,
498,
521,
522,
524,
533,
535)
requested
that
EPA
allow
facilities
to
prorate
fuel
pollutant
content
operating
limits
established
during
performance
tests
by
the
ratio
of
the
performance
test
results
to
the
applicable
emission
limits,
then
maintain
fuel
pollutant
content
levels
below
the
extrapolated
value.
Some
commenters
noted
that
allowing
facilities
to
prorate
operating
limits
would
help
those
that
use
multiple
fuel
suppliers
by:
1)
providing
needed
operational
flexibility;
2)
avoiding
repeated
testing;
and
3)
eliminating
the
difficult
requirement
to
conduct
performance
testing
at
"
worst
case"
conditions.
One
commenter
(
491)
stated
that
a
new
performance
test
could
then
be
required
if
the
fuel
chlorine,
mercury,
and/
or
total
selected
metals
content
exceeded
the
prorated
values
established
during
the
performance
test.
Several
commenters
(
338,
374,
417,
484,
521,
522,
535)
recommended
that
facilities
be
able
to
demonstrate
compliance
through
fuel
purchase
specifications
or
certifications.
Some
commenters
(
374,
492)
also
requested
that
EPA
provide
allowances
for
facilities
to
use
other
compliance
strategies
that
would
be
more
appropriate
for
specific
sites,
with
prior
EPA
approval.
One
commenter
(
413)
referenced
the
CAM
protocols
and
a
protocol
developed
by
Electric
Power
Research
Institute
(
EPRI)
as
a
background
Some
commenters
(
364,
399,
387,
403)
provided
equations
that
prorate
the
allowable
fuel
input
by
the
ratio
of
the
stack
testing
results
to
the
emission
limit
for
each
pollutant.

Response:
Since
proposal,
we
changed
the
fuel
monitoring
and
sampling
requirements.
In
the
final
NESHAP,
we
base
the
fuel
sampling
requirements
on
fuel
type
(
e.
g.,
bituminous
coal,
anthracite,
tires,
biomass,
residual
oil)
and
no
longer
require
you
to
sample
fuel
shipments
received
from
different
suppliers
or
sources
as
long
as
the
fuel
is
the
same
type.
Therefore,
we
do
not
allow
facilities
to
prorate
fuel
pollutant
content
limits.
We
also
modified
the
fuel
sampling
provisions
such
that
you
are
required
only
to
conduct
fuel
sampling
for
each
type
of
fuel
initially,
and
then
once
every
five
years.
We
believe
that
this
should
address
the
commenters'
concern
regarding
sources
that
receive
fuel
from
many
different
suppliers.
We
are
still
requiring
you
to
135
conduct
performance
testing
with
the
fuel
type
or
mixtures
of
fuels
that
contain
the
highest
amount
of
regulated
pollutants.
Given
the
change
in
fuel
sampling
requirements
to
the
fuel
type
basis,
the
determination
of
the
types
of
fuels
that
have
the
highest
pollutant
content
should
be
less
onerous.
After
your
performance
testing,
as
long
as
you
burn
the
types
of
fuels
previously
sampled
and
do
not
burn
new
types
of
fuels
or
mixtures
of
fuels
with
higher
regulated
pollutant
contents,
you
are
not
required
to
conduct
any
additional
fuel
sampling
or
performance
testing
outside
of
the
normal
testing
schedule
contained
in
this
NESHAP.
We
also
provided
an
option
for
you
to
demonstrate
compliance
through
fuel
sampling
when
the
fuel
analysis
results
show
fuel
pollutant
content
(
on
a
pounds
per
million
Btu
(
lb/
MMBtu)
of
heat
content
basis)
is
less
than
your
applicable
emission
limit.

Comment:
Several
commenters
(
406,
407,
408,
501)
contended
that
in
regards
to
the
operating
parameters,
sources
should
have
the
option
of
performing
additional
test
runs
over
a
range
of
operating
parameters
if
desired.
The
commenters
also
suggested
that
sources
be
allowed
to
exceed
the
emission
limit
during
such
testing
without
it
being
a
violation,
so
that
the
minimum
or
maximum
parameter
operating
level
can
be
correctly
established.
The
commenters
added
that
once
an
operating
parameter
is
established,
the
source
should
be
required
to
maintain
the
parameter
level
within
20
percent
of
the
performance
test
baseline
average
value.
The
commenters
also
added
that
sources
should
be
allowed
to
set
operating
parameter
levels
as
a
function
of
boiler
load.
One
commenter
(
384)
believes
EPA
should
allow
sources
to
propose
their
own
strategy
on
how
to
demonstrate
compliance.

Response:
In
the
final
NESHAP,
we
do
not
provide
an
option
for
sources
to
conduct
performance
testing
over
a
range
of
operating
parameters
or
loads
because
it
would
be
difficult
to
structure
performance
testing
requirements
that
would
incorporate
different
operating
loads
and
conditions
that
would
benefit
sources
on
a
site­
specific
basis.
However,
if
you
want
to
establish
operating
limits
based
on
operating
loads
and/
or
conditions,
you
can
petition
the
Administrator
for
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.
In
the
final
NESHAP,
we
added
additional
flexibility
in
the
operating
limit
requirements
to
account
for
normal
variation
in
source
operation.
We
provided
fixed
opacity
limits
that
are
not
based
on
performance
testing
results
and
added
a
10
percent
operating
range
around
operating
limits
that
are
established
during
performance
testing.
We
are
also
not
providing
a
waiver
for
emission
exceedances
experienced
during
performance
testing.

Comment:
One
commenter
(
445)
requested
that
EPA
allow
sources
to
define
a
range
(
as
a
percentage)
for
blended
fuels
to
demonstrate
compliance
with
the
MACT
standard.
The
commenter
explained
that
blended
fuels
behave
like
one
of
the
regional
coals
within
the
blend.

Response:
We
revised
the
fuel
sampling
and
monitoring
requirements
in
the
final
NESHAP
to
be
based
on
fuel
type
and
removed
the
requirement
to
conduct
fuel
sampling
for
the
same
fuel
types
that
come
from
different
suppliers
or
sources.
If
you
demonstrate
compliance
through
performance
testing,
you
must
plan
to
burn
the
fuel
type
or
mixture
of
fuel
types
that
contain
the
highest
content
of
regulated
pollutants.
After
that
performance
test,
you
can
burn
any
range
of
fuel
types
and
mixtures,
as
long
as
the
results
of
the
fuel
sampling
for
each
fuel
type
or
mixture
show
that
the
total
regulated
pollutant
content
is
less
than
that
burned
during
the
last
performance
test.
These
changes
should
provide
flexibility
for
sources
that
burn
a
mixture
of
fuels.
136
Comment:
One
commenter
(
499)
stated
that
the
fuel
based
operating
limit
procedures
for
chloride,
metals,
and
mercury
in
§
63.7530
are
flawed
because
they
rely
too
heavily
on
the
performance
during
a
stack
test,
with
no
consideration
for
a
margin
of
safety.
The
commenter
explained
that
this
operating
limit
approach
could
inadvertently
encourage
sources
to
fire
a
fuel
that
has
the
maximum
chloride,
metals,
and
mercury
content
during
the
performance
test
since,
provided
the
source
meets
the
emission
limit,
there
is
no
incentive
to
strive
for
a
margin
of
safety
to
over
comply
in
order
to
ensure
100
percent
compliance.
The
commenter
stated
that
this
approach
is
a
disincentive
to
promoting
greater
emissions
reductions
and
should
be
changed.
In
addition,
the
commenter
stated
that
sources
who
over­
comply
should
be
afforded
some
reward
in
terms
of
regulatory
relief
rather
than
penalized
with
more
restrictive
limits.

Response:
We
require
performance
testing
for
sources
that
cannot
demonstrate
compliance
with
the
emission
limits
of
this
NESHAP
through
fuel
sampling.
The
requirement
is
necessary
to
ensure
that
the
emission
limits
are
being
achieved.
Then,
we
use
operating
limits
established
during
the
performance
testing
to
ensure
that
the
source
is
operating
in
manner
similar
to
that
during
the
performance
testing.
We
still
require
that
you
burn
the
fuel
type
of
mixture
of
fuels
that
contain
the
greatest
amount
of
regulated
pollutants
during
performance
testing.
This
assures
us
that
you
are
able
to
meet
the
applicable
emission
limits
burning
the
fuel
type
of
mixture
that
contains
the
greatest
content
of
regulated
pollutants.
It
also
provides
you
with
flexibility
to
burn
any
fuel
type
or
mixture
that
contains
a
lesser
amount
of
regulated
pollutants
without
having
to
conduct
additional
performance
testing.
Given
these
changes,
we
are
not
providing
any
other
relief
for
sources
that
over­
comply
because
we
believe
that
the
changes
made
since
proposal
reduce
the
burden
of
compliance
and
provide
additional
flexibility.
Furthermore,
the
goal
of
the
NESHAP
program
is
to
provide
a
uniform
application
of
the
maximum
achievable
control
technology
determined
for
this
source
category
and
for
all
sources
within
the
source
category
to
meet
the
MACT
based
emission
limits.

11.4
PERFORMANCE
TESTING
Comment:
One
commenter
(
358)
supported
expanding
compliance
demonstration
options
to
include
engineering
calculations
and
other
emission
estimates
to
be
considered
"
as
good"
as
actual
site­
specific
test
data.
The
commenter
contended
that
the
proposed
rule
did
not
adequately
address
cost
associated
with
stack
compliance
testing
and
the
burden
to
conduct
testing
for
sources
that
emit
relatively
small
quantities
of
HAP.

Response:
If
you
are
required
to
demonstrate
compliance
through
performance
testing,
we
are
not
going
to
allow
compliance
to
be
demonstrated
by
engineering
calculations
or
other
emission
estimates.
We
are
aware
of
the
costs
of
performance
testing
and
have
attempted
to
minimize
the
cost
of
testing
through
the
following
provisions:
1)
allowance
for
testing
once
every
three
years
for
sources
that
have
passed
performance
tests
for
three
consecutive
years;
and
2)
allowance
for
demonstrating
compliance
through
fuel
analysis
for
units
that
are
not
taking
credit
for
pollution
control
devices
or
for
units
that
do
not
require
pollution
control
devices
to
demonstrate
compliance.
For
units
that
require
control
devices
to
meet
the
emission
limits,
we
require
performance
testing
because
this
is
the
only
method
to
accurately
determine
the
effectiveness
of
those
control
devices.
The
final
rule
does
allow
for
sources
to
demonstrate
compliance
through
fuel
analysis
in
cases
where
the
analysis
shows
that
the
pollutant
137
concentration
in
the
fuel
is
less
than
the
applicable
emission
limit.
We
also
do
not
require
performance
testing
for
any
existing
gas
or
liquid
fuel­
fired
units,
existing
small
solid
fuel­
fired
units,
new
gas
fuel­
fired
units,
and
new
liquid
fuel­
fired
units
that
do
not
burn
residual
oil.

Comment:
One
commenter
(
413)
asserted
that
for
sources
wanting
to
base
their
operating
parameter
levels
on
actual
test
data,
EPA
should
provide
a
waiver
for
excess
emissions
during
performance
testing
to
establish
operating
parameter
levels.
The
commenter
explained
that
in
the
proposal,
EPA
wanted
sources
to
test
at
worst
case
conditions,
which
might
require
a
"
de­
tuning"
of
control
devices
for
sources
that
have
purchased
additional
capacity
for
their
control
device.
The
commenter
added
that
this
would
present
a
conflict
for
sources
whose
highest
emissions
might
occur
under
conditions
that
are
consistent
with
the
unit's
basic
design,
but
which
the
unit
might
not
normally
choose
to
operate.

Response:
We
are
not
providing
a
waiver
for
excess
emissions
during
performance
testing.
The
requirement
for
conducting
performance
testing
is
to
use
the
fuels,
or
mixture
of
fuels,
that
contain
the
highest
amount
of
pollutants
regulated
by
the
boilers
NESHAP.
We
did
not
intend
to
imply
that
you
"
de­
tune"
your
control
device
during
the
performance
testing.
The
purpose
of
the
requirement
to
burn
the
fuel
or
mixture
of
fuels
with
the
highest
pollutant
content
is
to
provide
an
assurance
that
you
will
be
able
to
meet
the
emission
limits
of
the
NESHAP
even
when
burning
the
fuel(
s)
with
the
highest
pollutant
content.
To
address
concerns
over
compliance
flexibility,
the
final
rule
provides
several
different
approaches
to
compliance
that
were
not
in
the
proposed
rule
such
as:
1)
fixed
opacity
limits;
2)
operating
ranges
for
operating
limits;
3)
demonstrating
compliance
through
fuel
analysis;
and
4)
emissions
averaging
across
multiple
solid
fuel­
fired
boilers
at
a
single
facility.

Comment:
Two
commenters
(
345,
487)
requested
that
EPA
clarify
that
gaseous
fuel­
fired
units
are
not
required
to
demonstrate
initial
compliance
with
the
emission
limitations
and
work
practice
requirements.
The
commenters
explained
that
the
proposal
is
clear
that
liquid
fuel­
fired
units
are
not
required
to
conduct
this
demonstration,
but
does
not
specifically
state
that
gaseous
fuel­
fired
units
are
exempt
from
this
demonstration.
Another
commenter
(
478)
requested
that
EPA
not
require
emission
testing
for
existing
residual
oil
fired
units
since
they
have
no
emission
standards,
or
at
least
not
require
performance
tests
for
units
burning
distillate
oil.

Response:
In
the
final
boilers
NESHAP,
we
clarify
that
all
existing
gaseous
and
liquid
fuelfired
units
are
not
required
to
demonstrate
initial
compliance
with
the
emission
limits
or
work
practice
standards.
Existing
gas
and
liquid
fuel­
fired
units
smaller
than
10
MMBtu/
hr
are
exempt
from
all
requirements
under
the
final
boilers
NESHAP,
and
existing
small
gas
and
liquid
fuel­
fired
units
greater
than
10
MMBtu/
hr
only
have
to
submit
initial
notifications.
For
new
liquid
fuel­
fired
boilers
that
do
not
burn
residual
oil,
the
final
rule
clarifies
that
no
performance
testing
is
required
to
demonstrate
compliance
with
the
emission
limits.
However,
if
your
new
liquid
fuel
fired
unit
burns
residual
oil,
you
will
be
required
to
demonstrate
compliance
through
fuel
analysis
or
performance
testing.
If
your
new
gas
or
liquid
fuel­
fired
unit
is
larger
than
10
MMBtu/
hr,
then
you
will
be
required
to
demonstrate
compliance
with
the
CO
work
practice
standard.
In
this
case,
if
your
unit
is
less
than
100
MMBtu/
hr,
you
can
conduct
annual
performance
testing
for
CO.
However,
if
your
new
gas
or
liquid
fuel­
fired
unit
is
larger
than
100
MMBtu/
hr,
then
you
will
be
required
to
install
and
operate
a
CO
CEMS
to
demonstrate
compliance
with
the
CO
work
practice
standard.
138
Comment:
One
commenter
(
376)
requested
that
EPA
allow
one
year
after
the
compliance
deadline
for
facilities
to
conduct
the
initial
performance
test.

Response:
We
do
not
allow
one
year
after
compliance
to
conduct
initial
performance
testing.
In
the
final
boilers
NESHAP,
we
included
the
General
Provisions
allowance
that
provides
180
days
after
the
compliance
deadline
to
conduct
performance.
This
timeline
is
consistent
with
other
NESHAP
and
NSPS
programs
and
we
believe
that
this
is
sufficient
time
for
sources
to
conduct
initial
performance
testing.

Comment:
Several
commenters
(
388,
400,
449,
492,
498,
524,
533)
requested
that
EPA
clarify
that
a
compliance
test
conducted
within
60
days
of
the
initial
due
date
or
subsequent
annual
due
dates
meets
the
provisions
for
testing.
The
commenters
also
recommended
that
EPA
allow
units
not
operating
within
the
timeframe
of
a
required
performance
test
to
conduct
such
testing
within
60
days
of
commencing
or
recommencing
operations.
The
commenters
argued
that
it
is
nonsensical
to
require
units
that
do
not
operate
on
a
regular
basis
to
have
to
commence
operation
for
the
sole
purpose
of
performance
testing.
One
commenter
(
413)
requested
EPA
consider
including
a
"
grace
period"
for
periodic
testing
similar
to
the
period
provided
for
performance
of
relative
accuracy
test
audits
under
the
Acid
Rain
Program.
The
commenter
explained
that
the
grace
period
allows
a
source
time
to
complete
testing
after
coming
back
on­
line
from
an
unexpected
event,
such
as
a
outage.
The
commenter
added
that
such
a
grace
period
does
not
extend
the
deadline
for
future
testing.
The
commenter
added
that
the
grace
period
would
eliminate
the
need
for
submission
of
source
specific
petitions
to
seek
minor
extensions
of
testing.

Response:
We
to
not
provide
a
"
grace
period"
for
conducting
performance
testing.
The
final
boilers
NESHAP
has
extended
the
compliance
date
from
three
to
four
years
after
publication
of
the
final
rule
and
includes
the
General
Provision
allowance
of
180
days
after
the
compliance
date
to
conduct
the
initial
performance
testing.
This
provides
sources
with
3
years
and
180
days
after
the
effective
date
of
this
NESHAP
to
conduct
their
initial
performance
testing.
Therefore,
we
believe
that
facilities
have
adequate
time
to
prepare
for
the
initial
performance
testing
requirements.
Furthermore,
for
the
annual
performance
testing
requirement,
we
require
that
sources
conduct
their
performance
testing
between
10
and
12
months
after
the
previous
performance
testing.
We
also
allow
sources
to
conduct
testing
once
every
three
years
if
they
conduct
three
consecutive
performance
tests
that
demonstrate
compliance.
We
believe
that
this
provides
sufficient
flexibility
for
sources
to
conduct
performance
testing.

Comment:
One
commenter
(
332,
424)
requested
that
EPA
allow
sources
to
use
handheld
monitors
on
a
routine
basis
according
to
EPA
approved
calibration
and
testing
protocols
instead
of
periodic
source
testing.
One
commenter
(
332)
noted
that
the
use
of
reasonably
accurate
and
cost
effective
instrumentation
would
do
more
to
improve
the
environment
than
expensive
and
precise,
yet
infrequent
source
tests.

Response:
We
do
not
allow
the
use
of
handheld
monitors
in
lieu
of
performance
testing.
The
only
pollutant
regulated
by
the
boilers
NESHAP
that
could
be
tested
using
a
handheld
monitor
is
carbon
monoxide,
and
for
carbon
monoxide
we
modified
the
final
rule
to
require
CEMS
only
for
larger
sources
that
have
a
heat
input
of
100
MMBtu/
hr
or
more.
Sources
with
heat
input
less
than
100
MMBtu/
hr
that
have
a
carbon
monoxide
work
practice
standard
are
only
required
to
conduct
annual
performance
testing.
139
Comment:
Several
commenters
(
388,
449,
491,
492,
498,
524,
533)
requested
that
EPA
allow
performance
testing
on
a
single
unit
and
allow
the
results
of
that
testing
to
represent
units
that
are
similar.
The
commenters
noted
that
another
EPA
MACT
standard
includes
such
a
provision.
The
commenters
also
noted
that
similar
units:
1)
use
the
same
fuel;
2)
are
operated
in
the
same
manner;
3)
are
of
the
same
design;
and
4)
are
tested
at
the
highest
load
expected
at
any
of
the
represented
units.

Response:
In
the
final
boilers
NESHAP,
we
provide
additional
compliance
flexibility
compared
to
the
proposed
NESHAP.
However,
we
do
not
allow
the
performance
testing
on
a
single
unit
represent
units
that
are
similar.
The
performance
of
individual
units
can
vary
and
therefore
we
do
not
feel
that
using
representative
performance
tests
would
ensure
compliance
with
the
emission
limits.

Comment:
One
commenter
(
523)
stated
that
this
rule
need
not
impose
stack
testing
requirements
because
Title
V
permits
cover
such
provisions.
The
commenter
believes
that
mandating
stack
testing
in
the
rule
could
conflict
with
existing
Title
V
permits.
In
addition,
the
commenter
stated
that
the
monitoring
requirements
in
this
proposed
rule
are
extremely
costly,
burdensome,
and
unnecessary.

Response:
We
have
worked
to
minimize
the
testing
and
monitoring
requirements
of
this
rule
while
retaining
the
ability
to
ensure
compliance
with
the
emission
limits
and
work
practice
requirements.
Sources
may
conduct
performance
testing
once
every
three
years
if
they
conduct
successful
performance
testing
for
three
consecutive
years.
We
are
also
allowing
sources
to
conduct
only
fuel
sampling
if
they
can
demonstrate
compliance
with
the
hydrogen
chloride,
mercury,
or
total
selected
metals
emission
limits
through
fuel
analysis.
However,
stack
testing
is
the
only
method
for
demonstrating
compliance
with
the
emission
limits
for
units
that
cannot
demonstrate
compliance
through
fuel
analysis.

Comment:
Several
commenters
(
354,
357,
395,
404,
417,
441,
444,
452,
478,
491,
521,
535)
objected
to
the
requirement
to
conduct
performance
testing
at
"
worst
case"
conditions.
The
commenters
found
this
requirement
to
be
unrealistic
because
stack
testing
must
be
scheduled
well
in
advance
and
worst­
case
conditions
depend
on
fuel,
load,
and
many
other
variables,
making
it
impossible
to
assure
that
the
testing
will
occur
during
"
worst­
case"
conditions.
Two
commenters
(
521,
535)
contended
there
can
be
no
guarantee
that
mineral
properties
for
a
fuel
source
at
the
time
of
the
baseline
test
can
be
guaranteed
beyond
the
content
identified
during
purchase
contract
negotiations
with
a
fuel
supplier.
One
commenter
(
417)
recommended
that
testing
be
required
under
normal
operating
conditions.
Two
commenters
(
357,
441)
suggested
that
EPA
define
what
"
worst
case"
conditions
are
because
sources
do
not
have
the
experience
to
determine
"
worstcase
representative
process
conditions.

Response:
Since
proposal,
we
modified
the
performance
testing
requirements
regarding
the
conditions
at
which
you
must
conduct
the
testing.
During
performance
testing,
you
are
required
to
burn
the
type
of
fuel
or
mixture
of
fuel
types
that
have
the
highest
concentration
of
regulated
HAP.
This
is
what
is
considered
"
worst
case"
for
the
purpose
of
performance
testing.
Since
this
performance
testing
requirement
is
based
on
the
fuel
type,
and
not
on
any
other
variables,
the
determination
of
the
fuel
type
or
fuel
mixture
that
contains
the
highest
level
of
regulated
pollutants
is
reasonable.
After
the
initial
performance
testing,
you
must
conduct
an
analysis
of
the
fuel
types
that
you
burn
in
your
unit
initially
and
then
once
every
five
years.
The
140
fuel
analysis
applies
to
each
type
of
fuel
and
you
are
not
required
to
conduct
additional
analyses
if
you
receive
a
fuel
type
from
a
different
supplier.
Given
the
revised
fuel
sampling
requirements
(
e.
g.,
based
on
fuel
type
and
not
on
supplier,
etc),
developing
the
fuel
blend
during
the
performance
testing
should
address
the
commenters'
concern..

Comment:
Several
commenters
(
364,
387,
388,
399,
449,
468,
492,
498,
524,
533)
requested
that
EPA
clarify
that
particulate
matter
testing
to
determine
compliance
is
based
on
the
"
front­
half"
catch
and
that
any
"
back­
half"
condensable
particulate
matter
is
excluded
from
the
compliance
determination.
The
commenters
believed
that
the
data
EPA
used
to
set
the
MACT
floor
is
based
on
"
front­
half"
testing
data
and
that
compliance
determinations
should
be
based
on
the
same
methodology.
Furthermore,
since
the
metals
for
which
PM
is
serving
as
a
surrogate
for
are
of
the
non­
condensible
type
that
the
front­
half
collects.

Response:
For
the
purposes
of
this
NESHAP,
only
the
"
front­
half",
or
filterable
catch
of
an
EPA
Method
5
sampling
train
should
be
used
to
demonstrate
compliance
with
any
applicable
particulate
matter
emission
limit.

Comment:
Several
commenters
(
354,
355,
357,
374,
382,
388,
400,
427,
447,
449,
484,
491,
492,
498,
519,
524,
533)
objected
to
the
requirement
for
annual
performance
tests
because
they
believe
that
it
is
overly
burdensome
given
the
ongoing
compliance
demonstrations
required
by
the
boilers
NESHAP.
Several
commenters
(
357,
382,
388,
400,
444,
449,
478,
492,
498,
524,
533)
suggested
that
initial
performance
testing
should
be
required
with
subsequent
performance
testing
occurring
every
3
to
5
years.
Some
commenters
stated
that
5­
year
test
intervals
are
consistent
with
Title
V
permits
and
have
been
allowed
in
other
MACT
standards
(
e.
g.,
Hazardous
Waste
Combustors).
One
commenter
(
484)
suggested
that
if
a
source
fails
a
performance
test,
then
the
source
should
be
required
to
perform
two
consecutive
successful
annual
performance
tests
prior
to
returning
to
a
three­
year
cycle.
One
commenter
(
478)
urged
EPA
to
extend
the
reduced
testing
provision
from
three
years
to
five
years
for
facilities
that
have
conducted
three
consecutive
tests
that
demonstrate
compliance
with
this
NESHAP.
One
commenter
(
404)
recommended
that
EPA
allow
facilities
to
immediately
use
the
three­
year
testing
schedule
if
they
have
three
valid
stack
tests
indicating
compliance
in
the
past
several
years.
Another
commenter
(
491)
suggested
that
provisions
be
included
in
the
rule
to
allow
operators
of
"
clean
units"
to
be
eligible
for
reduced
performance
testing
frequency.
As
an
example,
the
commenter
stated
that
a
boiler
or
process
heater
with
emissions
no
greater
than
80
percent
of
the
compliance
level
should
be
required
to
test
only
every
three
years.
In
addition,
the
commenter
stated
that
units
with
even
"
cleaner"
performance
should
be
granted
required
test
frequencies
of
every
five
years.
The
commenter
urged
EPA
to
revise
Subpart
DDDDD
to
include
reduced
performance
testing
frequency
for
"
clean
units,"
with
EPA
reserving
the
authority
to
require
testing
at
any
time
if
due
cause
exists
to
indicate
emissions
are
no
longer
"
clean."

Response:
We
have
worked
to
minimize
the
testing
and
monitoring
requirements
of
the
final
rule
while
retaining
the
ability
to
ensure
compliance
with
the
emission
limits
and
work
practice
requirements.
Sources
may
conduct
performance
testing
once
every
three
years
if
they
conduct
successful
performance
testing
for
three
consecutive
years.
We
are
also
allowing
sources
to
demonstrate
compliance
with
the
hydrogen
chloride,
mercury,
and
total
selected
metals
emission
limits
through
fuel
testing
if
they
do
not
need
emission
control
devices
to
achieve
the
standard.
However,
stack
testing
is
the
only
method
for
demonstrating
compliance
with
the
141
emission
limits
for
units
that
cannot
demonstrate
compliance
through
fuel
testing.

Comment:
One
commenter
(
491)
stated
that
sampling
of
coal
burned
during
a
three­
hour
performance
test
is
not
practicable
with
some
coal
feed
system
designs.
The
commenter
requested
that
EPA
clarify
that
testing
samples
obtained
by
following
procedures
established
to
obtain
a
representative
sample
of
coal
as­
bunkered
for
burning
during
the
performance
test
is
acceptable
for
the
measurements
required
in
§
63.7530(
c).

Response:
In
the
final
boilers
NESHAP,
you
must
sample
and
analyze
the
fuel
types
that
you
burn
initially
and
then
once
every
five
years
for
each
type
(
e.
g.,
bituminous
coal,
tires,
biomass,
etc.)
of
fuel
burned
in
a
boiler
or
process
heater.
Therefore,
we
believe
that
this
addresses
the
commenter's
concern
regarding
sampling
frequency.
You
would
have
to
conduct
additional
fuel
analyses
only
if
you
burn
a
new
type
of
fuel.
We
have
provided
a
specific
procedure
for
you
to
follow
as
you
conduct
fuel
sampling,
including
the
development
of
a
sitespecific
fuel
analysis
plan,
in
§
63.7521.

Comment:
Several
commenters
(
364,
382,
387,
388,
399,
413,
444,
449,
468,
492,
498,
521,
522,
524,
533,
535)
objected
to
the
requirement
for
larger
solid
fuel­
fired
units
(>
250
MMBtu/
hr)
to
use
the
ASTM
method
for
determining
mercury
emissions
and
requested
that
EPA
remove
this
requirement.
The
commenters
argued
that
the
ASTM
method
is
more
expensive,
is
not
an
EPA
reference
method,
uses
a
considerably
more
complex
sampling
train
and
analytical
methods,
and
that
there
are
minimal
differences
between
the
results
of
the
two
test
methods.
Some
commenters
argued
that
EPA
has
not
provided
information
on
or
explained
the
logic
for
requiring
different
test
methods
depending
on
heat
input
capacity.
Furthermore,
the
commenters
explained
that
the
data
used
to
set
the
MACT
floor
were
conducted
using
EPA
Method
29.
The
commenters
contended
that
performance
testing
for
mercury
should
allow
use
of
either
Method
29
or
Draft
ASTM
Z65907
for
any
size
source
at
the
discretion
of
the
affected
source.

Response:
In
the
final
NEHSAP,
we
removed
requirement
for
units
>
250
MMBtu/
hr
to
use
the
ASTM
method
for
mercury
performance
testing.
All
sources
have
the
option
of
using
either
EPA
Method
29
or
ASTM
Method
D6784­
02
for
conducting
performance
tests
for
mercury.

Comment:
Several
commenters
(
382,
388,
449,
498,
524,
533)
requested
that
EPA
allow
affected
units
with
dry
controls
the
option
to
utilize
either
Method
26
or
26A
for
the
determination
of
hydrogen
chloride
emissions.
The
commenters
explained
that
as
an
isokinetic
test
method,
Method
26A
may
be
performed
in
the
"
back­
half"
of
a
Method
5
sampling
train
and
the
use
of
this
method
could
provide
some
savings
for
testing
costs.

Response:
In
the
final
boilers
NESHAP,
the
performance
testing
requirements
allow
you
to
use
either
EPA
Method
26
or
26A
for
the
determination
of
hydrogen
chloride
emissions.

Comment:
Commenters
(
364,
399,
387)
recommended
that
EPA
amend
EPA
Method
19
applicability
to
clarify
that
it
can
apply
to
the
calculation
of
hydrogen
chloride,
selected
metals,
and
mercury
emissions.
The
commenter
noted
that
currently,
Method
19
states
that
it
should
be
used
for
the
determination
of
particulate
matter,
sulfur
dioxide,
and
oxides
of
nitrogen
emissions.
If
the
applicability
of
Method
19
to
these
other
pollutants
is
not
amended,
the
commenter
is
142
concerned
that
implementation
problems
could
result.

Response:
We
are
not
going
to
modify
Method
19
in
this
rulemaking
because
it
is
outside
of
the
scope
of
this
rulemaking.
We
realize
that
the
equations
provided
in
Method
19
were
developed
for
pollutants
other
than
those
regulated
in
this
NESHAP,
but
those
equations
can
be
used
for
the
pollutants
regulated
by
this
NESHAP.
We
clarify
in
the
final
NESHAP
which
equations
from
Method
19
you
should
use
in
order
to
avoid
confusion.

Comment:
Several
commenters
(
357,
364,
399,
387,
403,
406,
407,
408,
501)
requested
that
EPA
promulgate
an
alternative
procedure
for
calculating
heat
input.
Some
commenters
noted
that
the
use
of
EPA
Method
19
is
difficult
to
apply
where
multiple
fuels
are
burned
and
some
of
those
fuels
may
have
variable
moisture
content
and
the
published
F­
factors
may
not
apply,
or
may
significantly
differ
from
the
actual
F­
factors.
The
commenters
recommended
that
EPA
allow
sources
to
use
the
thermal
efficiency
method
to
determine
heat
input.

Response:
We
consider
the
use
of
thermal
efficiency
a
viable
option
to
determine
heat
input.
However,
we
do
not
specifically
outline
a
method
in
the
boilers
NESHAP
to
evaluate
heat
efficiency
or
monitor
heat
input.
If
you
want
to
use
boiler
or
process
heater
efficiency
to
determine
heat
input,
you
must
petition
the
Administrator
for
approval
of
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.
Typically,
boilers
monitor
steam
flow.
Through
the
use
of
boiler
efficiency
measurements
and
calculations,
you
can
determine
the
heat
input
of
a
boiler.
If
you
own
or
operate
a
boiler
and
want
to
use
boiler
efficiency,
you
must
use
a
current
ASTM
method
for
determining
heat
input
in
your
alternative
monitoring
plan.
Process
heaters
may
have
different
outputs
to
relate
to
heat
input.
If
you
can
demonstrate
the
relation
of
process
output
to
heat
input,
we
consider
that
a
viable
method
to
determine
heat
input.
For
boilers
and
process
heaters,
your
alternative
monitoring
plan
must
include
the
requirement
to
determine
unit
efficiency
before
or
during
the
initial
performance
test
and
to
determine
unit
efficiency
with
every
subsequent
performance
test
to
make
sure
that
any
changes
in
unit
efficiency
are
reflected
in
each
performance
test
result.

Comment:
One
commenter
(
491)
stated
that
the
proposed
boilers
NESHAP
does
not
specify
allow
methods
for
determining
the
heating
value
of
fuel.
The
commenter
suggested
that
EPA
clarify
its
expectations
for
allowable
methods
so
operators
can
determine
the
fuel
heating
value
pursuant
to
rule
requirements.
In
addition,
the
commenter
stated
that
if
method
selection
is
expected
to
be
made
by
the
operator
and
merely
included
in
the
site­
specific
test
plan
pursuant
to
§
63.7520(
a),
then
EPA
should
clarify
that
expectation.

Response:
In
the
final
NESHAP,
we
outline
methods
to
be
used
for
determining
fuel
heating
value
in
Table
6.
However,
if
you
want
to
use
another
method,
you
can
petition
the
Administrator
for
the
use
of
an
alterative
testing
plan
under
§
63.7(
e)(
2)(
ii)
and
(
f)
of
subpart
A
of
part
63.

Comment:
One
commenter
(
413)
requested
EPA
to
allow
the
use
of
Method
101­
A
to
measure
mercury
emissions.
The
commenter
noted
that
Method
29
specifically
notes
that
mercury
can
be
measured,
alternatively,
using
EPA
method
101­
A.

Response:
In
the
final
NESHAP,
we
allow
either
EPA
Method
29
or
the
ASTM
Method
D6784­
02,
to
measure
mercury
emissions.
As
EPA
Method
29
specifically
allows
for
the
use
of
143
EPA
Method
101­
A,
you
could
use
that
method
to
demonstrate
compliance
with
the
mercury
emission
limits
of
this
NESHAP.
However,
neither
EPA
Method
29
nor
Method
101­
A
has
been
revised
to
reflect
the
best
laboratory
techniques
for
preserving
and
recovering
mercury
from
the
permanganate
impingers.
If
you
believe
this
might
be
an
issue
for
you,
the
ASTM
Method
D6784­
02
may
be
a
better
choice.

Comment:
One
commenter
(
529)
recommended
that
§
63.7515(
d)
be
changed
to
read
"...
you
must
demonstrate
compliance
and
thereafter
conduct
annual
stack
tests..."
This
change
requires
a
facility
to
demonstrate
compliance
before
entering
an
annual
performance
test
schedule.

Response:
We
do
not
believe
that
this
change
is
necessary.
The
final
NESHAP
has
changed
since
proposal
to
clarify
the
performance
testing
schedule
requirements
and
affected
source
should
readily
understand
that
they
are
required
to
conduct
initial
and
annual
performance
testing.
144
12.0
Recordkeeping
and
Reporting
Comment:
One
commenter
(
484)
stated
that
EPA's
proposal
supercedes
critical
language
that
facilities
rely
upon
to
realize
their
general
duty
to
minimize
emissions
during
startup,
shutdown,
and
malfunction
conditions.
In
addition,
the
commenter
asserted
that
uninhibited,
ongoing
source
adjustments
to
startup,
shutdown,
and
malfunction
plans
provide
the
internal
control
necessary
to
meet
this
general
duty.

Response:
The
startup,
shutdown,
and
malfunction
(
SSM)
plan
requirements
contained
in
the
General
Provisions
to
part
63
apply
to
all
sources
subject
to
a
NESHAP
unless
specifically
exempted
for
a
specific
source
category.
We
are
not
exempting
sources
from
the
SSM
requirements,
unless
they
have
no
emission
limits
or
work
practice
standards
under
the
final
rule.
The
SSM
plan
requirements
are
not
intended
to
supercede
existing
plans
to
minimize
emissions
during
periods
of
SSM,
but
are
required
in
order
to
make
facilities
document
how
their
sources
undergo
SSM,
how
sources
minimize
emissions
during
SSM,
and
to
provide
a
procedure
that
sources
must
follow
during
periods
of
SSM.
You
can
incorporate
existing
SSM
plans
into
the
SSM
plan
required
by
the
final
rule.
Refer
to
§
63.6
of
subpart
A
of
this
part
for
more
information
regarding
SSM
plan
requirements.

Comment:
One
commenter
(
427)
requested
that
the
requirement
for
semiannual
compliance
reports
in
§
63.7550(
a)
be
modified
to
allow
the
flexibility
for
annual
compliance
reports
in
order
to
make
the
rule
consistent
with
other
MACT
standards
with
which
the
commenter
is
required
to
comply.

Response:
We
did
not
modify
the
reporting
schedule
in
the
final
rule.
However,
the
General
Provisions
(
40
CFR
part
63,
subpart
A)
allows
you
to
petition
the
Administrator
for
a
different
reporting
schedule.
Furthermore,
§
63.7550(
b)(
5)
allows
for
an
alternative
reporting
schedule
if
your
permitting
authority
has
already
established
different
reporting
dates
for
your
semiannual
report
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
71.6(
a)(
3)(
iii)(
A).

Comment:
One
commenter
(
427)
contended
that
§
63.7505
(
General
Compliance
Requirements)
must
be
clarified
to
state
that
it
applies
only
if
§
63.7500
(
Emission
Limits)
applies.
The
commenter
stated
that
§
63.7500
should
contain
the
explicit
statement
that
it
applies
only
to
those
sources
not
explicitly
exempted
under
§
63.7490
(
Applicability).

Response:
In
the
final
rule,
we
specifically
note
in
§
63.75056
the
minimal
requirements
for
sources
that
do
not
have
any
emission
limits
or
work
practice
standards
under
§
63.7500.
We
believe
that
§
63.7490
clearly
lists
which
sources
are
not
subject
to
the
final
rule
(
including
the
emission
limits
and
work
practice
standards
contained
in
§
63.7500).
We
do
not
provide
an
additional
statement
in
§
63.7500
that
states
that
the
emission
limits
and
work
practice
standards
apply
only
to
source
not
specifically
exempted
under
§
63.7490.

Comment:
One
commenter
(
529)
suggested
that
§
63.7535(
a)
be
revised
to
require
monitoring
and
data
collection
in
accordance
with
§
63.7535
and
the
Site
Specific
Monitoring
Plan
required
by
§
63.7505(
cd).

Response:
We
agree
with
the
commenter's
suggestion
and
revised
the
final
rule
145
accordingly.

Comment:
One
commenter
(
491)
suggested
that
§
63.7550(
b)(
1)
be
revised
as
follows:

§
63.7550(
b)(
1)
The
first
compliance
report
must
cover
the
period
beginning
on
the
compliance
date
that
is
specified
for
you
affected
source
in
§
63.7495
and
ending
on
June
30
or
December
31,
whichever
date
is
the
first
date
that
occurs
at
least
180
days
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.7495.

Response:
We
agree
with
the
commenter's
suggestion
and
in
the
final
rule
we
have
included
the
change
recommended
by
the
commenter.

Comment:
One
commenter
(
346)
recommended
that
the
Quality
Assurance
Procedures
in
Appendix
F
to
Part
60
be
provided
as
an
acceptable
alternative
to
the
site
specific
monitoring
plan
because
some
State
permits
require
this
documentation.

Response:
The
site­
specific
monitoring
plan
requirements
in
§
63.7505
apply
for
all
continuous
monitoring
systems
used
to
comply
with
this
NESHAP.
Since
the
quality
assurance
procedures
in
Appendix
F
to
Part
60
apply
only
to
continuous
emission
monitoring
systems
and
only
some
new
and
reconstructed
sources
will
be
required
to
install
and
operate
these
systems,
these
quality
assurance
procedures
do
not
address
the
other
types
of
continuous
monitoring
systems
that
are
based
on
operating
parameters.
You
can
include
the
quality
assurance
procedures
in
Appendix
F
to
Part
60
in
the
quality
assurance
section
of
your
site­
specific
monitoring
plan
if
you
are
required
to
install
and
operate
a
CEMS
to
comply
with
this
NESHAP.

Comment:
One
commenter
(
484)
recommended
that
EPA
utilize
its
authority
under
40
CFR
Part
70
to
eliminate
duplicative
state
reporting
requirements.
The
commenter
stated
that
the
reporting
requirement
in
§
63.10(
d)(
5)(
i)
of
the
boilers
NESHAP
regarding
malfunction
reporting
is
duplicative
and
should
be
deleted
from
the
standard.

Response:
We
do
not
have
authority
under
this
rulemaking
to
eliminate
duplicative
state
reporting
requirements.
The
malfunction
reporting
required
under
§
63.10(
d)(
5)(
i)
is
a
semiannual
occurrence
for
a
source
that
experience
startups,
shutdowns,
or
malfunctions
and
must
respond
to
those
occurrences
according
to
their
SSM
plan.
If
that
requirement
overlaps
with
another
requirement
in
your
Title
V
Operating
Permit,
you
should
work
with
your
permitting
authority
to
streamline
your
reporting
requirements.

Comment:
Several
commenters
(
383,
413,
490,
499)
maintained
that
the
recordkeeping
and
reporting
requirements
are
burdensome,
costly,
and
require
unnecessary
data.
One
commenter
(
413)
provided
examples
of
unnecessary
information.
The
commenter
added
that
much
of
the
information
required
cannot
be
collected
automatically
but
must
be
manually
gathered.
Two
commenters
(
484,
535)
stated
that
required
submission
of
SSM
plans
and
associated
revisions
is
administratively
burdensome
and
redundant.
One
commenter
(
383)
would
like
EPA
to
streamline
these
requirements
and
offered
to
work
with
EPA
to
do
so.

Response:
Since
proposal,
we
have
streamlined
many
of
the
monitoring
requirements,
which
will
result
in
much
less
reporting
and
recordkeeping.
These
changes
especially
reduce
the
amount
of
manually
gathered
data
associated
with
the
fuel
sampling
provisions
of
the
final
rule.
146
We
have
worked
to
minimize
the
compliance
burden
of
the
final
rule,
and
maintain
that
the
recordkeeping
and
reporting
requirements
that
we
have
retained
are
necessary
to
ensure
continuous
compliance
with
the
provisions
of
this
NESHAP
Comment:
One
commenter
(
424)
requested
that
EPA
clarify
if
permitting
requirements
under
the
boilers
NESHAP
will
be
in
addition
to
semiannual
reporting
under
Title
V,
such
as
deviation
information.
One
commenter
(
490)
stated
that
these
requirements
impose
burdens
over
and
above
what
is
required
by
states
under
State
Implementation
Plans
and
Title
V
monitoring
requirements.
The
commenter
urged
EPA
to
reconsider
the
monitoring,
recordkeeping,
and
reporting
requirements
associated
with
this
rule
and
make
them
compatible
with
existing
Title
V
requirements
for
the
same
emission
units.

Response:
Making
the
monitoring,
recordkeeping,
and
reporting
requirements
of
this
rule
compatible
with
existing
Title
V
requirements
is
not
feasible.
Many
states
have
accepted
delegation
of
the
Title
V
program
from
EPA
and
their
requirements
vary
from
state
to
state.
Therefore,
we
cannot
make
the
requirements
of
this
rule
fully
compatible
with
existing
Title
V
requirements.
In
the
final
rule,
we
have
streamlined
many
of
the
monitoring
requirements,
which
will
also
result
in
decreased
recordkeeping
and
reporting
burdens.
Furthermore,
many
of
the
monitoring
requirements
in
the
final
rule
are
parameters
that
sources
would
already
be
monitoring,
so
we
do
not
expect
this
NESHAP
will
impose
burdens
over
and
above
what
may
already
be
required.
If
you
already
have
a
monitoring
program
that
you
believe
would
satisfy
the
monitoring
elements
of
this
NESHAP,
you
can
petition
the
Administrator
for
approval
of
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
One
commenter
(
491)
stated
there
was
no
reasonable
basis
to
require
determining
and
reporting
the
average
daily
hours
of
operation
by
each
source,
or
affected
source,
for
each
calendar
month
within
the
semiannual
reporting
period.
The
commenter
suggested
simplifying
§
63.7550(
c)(
8)
to
read,
"
The
hours
of
operation
by
each
affected
source
for
each
calendar
month
within
the
semiannual
reporting
period."
One
commenter
(
428)
stated
that
given
the
very
large
potential
increase
in
the
recordkeeping
burden
for
small
sources
that
are
not
contributors
to
HAP
emissions
and
the
lack
of
a
rationale
for
collecting
such
information
even
for
larger
sources,
the
requirement
to
keep
records
of
daily
hours
of
operation
by
each
source
(
§
63.7555(
d)(
2))
should
be
stricken
for
the
regulation
Response:
In
the
final
rule,
we
modified
the
recordkeeping
and
reporting
provisions
to
require
only
that
monthly
fuel
use
be
recorded
and
reported.
Furthermore,
the
only
sources
that
now
have
to
monitor
hours
of
operation
are
limited
use
sources,
and
they
are
required
to
record
and
report
hours
of
operation
on
a
monthly
basis.

Comment:
One
commenter
(
413)
expressed
concern
regarding
how
control
device
parameter
deviations
during
startup,
shutdown,
and
malfunction
will
be
treated
by
the
EPA
and
what
time
limit
the
Administrator
will
follow
in
making
determinations.
The
commenter
added
that
a
source
would
not
know
whether
it
was
in
compliance
or
not
if
something
happens
during
a
startup
or
a
malfunction
that
is
not
covered
by
the
plan.

Response:
During
periods
of
startup,
shutdown,
and
malfunction,
you
are
required
to
follow
the
procedures
that
you
have
outlined
in
your
SSM
plan
according
to
§
63.6
of
subpart
A
147
of
part
63.
In
this
§
63.6,
we
explain
how
parameter
deviations
would
be
treated.
It
states:
"
At
all
times,
including
periods
of
startup,
shutdown,
and
malfunction,
the
owner
or
operator
must
operate
and
maintain
any
affected
source,
including
associated
air
pollution
control
equipment
and
monitoring
equipment,
in
a
manner
consistent
with
safety
and
good
air
pollution
control
practices
for
minimizing
emissions.
During
a
period
of
startup,
shutdown,
or
malfunction,
this
general
duty
to
minimize
emissions
requires
that
the
owner
or
operator
reduce
emissions
from
the
affected
source
to
the
greatest
extent
that
is
consistent
with
safety
and
good
air
pollution
control
practices.
The
general
duty
to
minimize
emissions
during
a
period
of
startup,
shutdown,
or
malfunction
does
not
require
the
owner
or
operator
to
achieve
emission
levels
that
would
be
required
by
the
applicable
standard
at
other
times
if
this
is
not
consistent
with
safety
and
good
air
pollution
control
practices,
nor
does
it
require
the
owner
or
operator
to
make
any
further
efforts
to
reduce
emissions
if
levels
required
by
the
applicable
standard
have
been
achieved.
Determination
of
whether
such
operation
and
maintenance
procedures
are
being
used
will
be
based
on
information
available
to
the
Administrator,
which
may
include,
but
is
not
limited
to,
monitoring
results,
review
of
operation
and
maintenance
procedures
(
including
the
startup,
shutdown,
and
malfunction
plan
required
in
paragraph
(
e)(
3)
of
this
section),
review
of
operation
and
maintenance
records,
and
inspection
of
the
source."
Furthermore,
it
states
that:
"
Malfunctions
must
be
corrected
as
soon
as
practicable
after
their
occurrence
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan
required
in
paragraph
(
e)(
3)
of
this
section.
To
the
extent
that
an
unexpected
event
arises
during
a
startup,
shutdown,
or
malfunction,
an
owner
or
operator
must
comply
by
minimizing
emissions
during
such
a
startup,
shutdown,
and
malfunction
event
consistent
with
safety
and
good
air
pollution
control
practices."
This
means
that
the
Administrator
will
review
any
deviations
that
occur
during
a
SSM
event
and
respond
based
on
your
adherence
to
your
SSM
plan
and
your
history
of
SSM
events.

Comment:
One
commenter
(
491)
stated
that
deviation
reporting
is
required
pursuant
to
§
63.7550.
The
commenter
stated
it
is
unclear
why
additional
deviation
reporting
is
required
pursuant
to
§
63.7545(
e)(
1)(
vii)
when
submitting
a
Notification
of
Compliance
Status
report.
In
addition,
the
commenter
stated
that
the
time
period
for
which
deviations
need
to
be
reported
is
not
specified.
The
commenter
stated
that
the
initial
Notification
of
Compliance
Status
is
due
before
the
close
of
business
on
the
60th
calendar
day
following
the
completion
of
the
performance
test
and/
or
other
initial
compliance
demonstrations
according
to
§
63.10(
d)(
2).
The
commenter
stated
there
is
no
basis
for
requiring
duplicative
deviation
reporting
when
submitting
a
Notification
of
Compliance
Status
report
and
recommended
deleting
§
63.7545(
e)(
1)(
vii).
Response:
The
deviation
reporting
required
by
§
63.7545(
e)(
19)
is
an
element
of
your
Notification
of
Compliance
Status
report
that
you
must
submit
after
your
initial
compliance
demonstration,
or
any
subsequent
performance
test
or
compliance
demonstration.
This
report
is
required
only
under
these
circumstances
and
the
deviation
portion
addresses
any
deviation
from
an
applicable
emission
limit
or
work
practice
standard
that
may
have
occurred
during
your
performance
test
or
compliance
demonstration.
The
deviation
reporting
requirement
under
§
63.7550(
d)
is
an
element
of
your
compliance
report
that
must
be
submitted
semiannually.
This
report
requires
you
to
report
any
deviation
from
an
emission
limit,
operating
limit,
and
work
practice
standard
that
might
have
occurred
during
the
previous
six­
month
period.
These
reports
serve
different
functions
and
we
did
not
delete
either
of
the
deviation
reporting
requirements
in
the
final
rule.
You
must
submit
your
semiannual
compliance
report
by
July
31
and
January
31
each
year
according
to
§
63.7550(
b)(
4),
unless
you
have
an
alternative
semiannual
reporting
period
in
your
Title
V
Operating
Permit.
148
Comment:
One
commenter
(
523)
stated
that
the
rule
requires
that
if
there
are
no
deviations
during
a
compliance
period,
then
an
affirmative
statement
must
be
submitted
in
the
semiannual
report.
The
commenter
stated
that
the
renewable
operating
permit
program
requires
sources
to
use
state­
generated
forms
for
semiannual
reports
and
these
forms
do
not
provide
for
making
such
a
statement
specific
to
individual
NESHAPs.
The
commenter
stated
that
the
forms
require
that
the
company
certify
compliance
except
for
the
deviations
reported.
The
commenter
stated
that
there
is
no
reason
for
the
boilers
NESHAP
to
require
anything
separate
or
different
from
that
already
required
by
the
renewable
operating
permit.
Response:
The
compliance
reporting
requirements
of
this
NESHAP
do
not
prescribe
a
specific
format
for
the
semiannual
report.
As
previously
discussed,
many
states
operate
a
delegated
Title
V
Operating
Permit
program
and
the
requirements
of
those
programs
can
vary
from
state
to
state.
Therefore,
it
would
be
difficult,
if
not
impossible,
to
capture
all
the
different
state­
specific
reporting
requirements
in
this
NESHAP.
The
final
rule
outlines
the
elements
that
must
be
contained
in
a
semiannual
compliance
report.
You
should
work
with
your
permitting
authority
to
integrate
those
required
elements
into
your
standard
semiannual
report.

Comment:
Several
commenters
(
379,
388,
449,
491,
492,
524,
533)
recommended
that
deviation
reports
should
not
be
required
for
routine
startup
and
shutdown
events
that
are
consistent
with
the
SSM
plan.
Two
commenters
(
491,
492)
proceeded
to
explain
that
startups
and
shutdowns
are
routine
operations
for
boilers
and
process
heaters,
and
are
addressed
in
the
SSM
plan.
The
commenters
argued
that
there
is
no
need
to
submit
additional
data
other
than
to
note
that
there
was
a
startup
or
shutdown
and
that
the
event
was
consistent
with
the
SSM
plan.
Several
commenters
(
364,
399,
387,
403)
requested
that
EPA
should
not
require
reporting
of
SSM
events
that
do
not
result
in
an
exceedance
of
the
emission
limits.
The
commenters
argued
that
the
proposed
language
of
the
boilers
NESHAP
would
require
facilities
to
report
every
SSM
event,
regardless
of
whether
an
emission
limit
or
operating
requirement
was
violated.
The
commenters
suggested
changes
to
the
definition
of
SSM
that
would
address
their
concerns.
One
commenter
(
491)
stated
that
reporting
the
date
and
time
that
each
deviation
started
and
stopped,
and
that
the
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
should
be
sufficient.
Response:
You
must
submit
a
deviation
report
any
time
you
have
a
deviation
from
the
emission
limits,
operating
limits,
or
work
practice
standards
required
by
this
NESHAP.
Deviations
that
occur
during
SSM
events
are
not
automatically
a
violation
of
the
standard.
Your
deviation
report
will
be
reviewed
to
see
if
you
followed
your
SSM
plan.
Furthermore,
your
history
of
SSM
events
and
your
response
to
those
events
are
also
considered
in
the
evaluation
of
deviations
that
occur
during
SSM
events.
If
no
deviations
occurred
during
an
SSM
event,
you
are
required
only
to
report
that
you
had
an
SSM
event.
We
did
not
change
the
reporting
requirements
related
to
SSM
events
as
these
requirements
have
been
addressed
in
previous
revisions
to
the
General
Provisions
to
part
63
and
represent
EPA's
policy
regarding
these
events.

Comment:
Two
commenters
(
413,
499)
stated
that
the
rule
fails
to
propose
a
standard
reporting
format
or
an
opportunity
for
electronic
reporting.
One
commenter
(
499)
claimed
that
much
of
the
required
data
will
have
to
be
hand­
gathered
and
hand­
entered
into
an
electronic
format.
In
addition,
the
rule
does
not
indicate
where
or
to
whom
this
data
should
be
sent.
Response:
We
did
not
develop
a
standard
reporting
format
for
this
NESHAP
because
you
typically
report
the
required
elements
to
your
local
permitting
authority.
In
many
cases,
your
149
permitting
authority
has
accepted
delegation
of
this
NESHAP
and
Title
V
Operating
Permit
programs.
Once
delegated,
the
permitting
authority
can
develop
whatever
reporting
format
requirements
they
wish
as
long
as
they
meet
the
minimum
requirements
established
by
EPA.
Since
these
reporting
requirements
may
vary,
we
believe
that
developing
a
standard
reporting
format
in
this
NESHAP
is
not
appropriate.
In
the
final
rule,
we
have
streamlined
many
of
the
monitoring
requirements,
which
will
result
in
a
substantial
decrease
in
recordkeeping
and
reporting
activities,
especially
those
requirements
that
cannot
be
automatically
recorded.
All
required
reports
should
be
submitted
to
your
local
permitting
authority
according
to
your
Title
V
Operating
Permit.

Comment:
Several
commenters
(
388,
449,
491,
492,
498,
524,
533)
requested
that
EPA
not
require
readily
available
electronic
records
to
be
stored
onsite.
One
commenter
(
492)
noted
that
significant
changes
in
technology
have
encouraged
many
companies
to
opt
for
electronic
information
storage
on
computers
and
servers.
In
many
cases,
the
server
may
not
be
located
on
the
actual
site,
but
the
data
is
still
readily
available.
Therefore,
the
commenter
recommended
that
§
63.7560(
c)
be
revised
to
recognize
the
trend
to
electronic
record
keeping.
One
commenter
(
491)
suggested
changes
to
§
63.7560(
c)
to
require
on­
site
records
to
be
kept
for
only
the
first
2
years,
and
allow
off­
site
storage
for
the
last
3
years.
Response:
We
did
not
modify
the
records
retention
requirements
of
this
NESHAP.
These
requirements
are
consistent
with
other
NESHAPs
and
EPA
policy.
The
requirement
to
have
records
stored
on­
site
is
to
facilitate
timely
review
of
these
records
by
EPA
or
your
permitting
authority.
Even
readily
available
electronic
data
stored
off
site
can
be
unretrievable
if
your
server
is
down
or
if
there
is
a
problem
with
your
Internet
connection.
For
these
reasons,
we
will
still
require
that
you
keep
records
on
site
for
a
period
of
at
least
2
years.

Comment:
Several
commenters
(
343,
346,
360,
396,
427,
434,
492)
recommended
that
EPA
clarify
that
existing
units
in
all
of
the
gaseous
and
liquid
fuel
subcategories
(
large/
small/
limited
use)
and
new
units
in
the
small
gaseous
fuel
subcategory
be
excluded
from
recordkeeping
and
reporting
requirements,
including
requirements
of
the
General
Provisions.
The
commenters
opposed
the
requirement
to
develop
and
implement
SSM
plans
and
to
submit
semiannual
compliance
reports
because
these
subcategories
are
not
subject
to
any
emission
limitations,
operating
limitations,
or
work
practice
standards
and
the
requirements
are
costly.
In
addition,
the
commenters
requested
that
the
initial
notifications
not
be
required
for
these
units.
One
commenter
(
345)
stated
that
gas­
fired
or
small
and
limited
use
subcategories
should
not
have
any
requirements
other
than
an
annual
certification
that
no
other
fuel
was
used.
One
commenter
(
490)
requested
EPA
confirm
that
since
no
standard
is
established
for
existing
gas­
fired
units,
there
would
be
no
recordkeeping
and
reporting
requirements.
In
addition,
the
commenter
stated
that
the
language
of
§
63.7550
and
the
text
in
Table
9
must
be
clarified
so
that
compliance
reports
and
SSM
reports
are
not
required
for
units
which
are
not
subject
to
any
standard.
One
commenter
(
396)
added
that
if
EPA
intends
to
still
require
reports
for
subcategories
with
no
limits
or
work
standards,
then
they
should
explain
their
rationale.
Several
commenters
(
369,
410,
426,
447,
479,
491,
519)
requested
that
EPA
exempt
units
that
are
not
subject
to
any
emission
limitations,
work
practice
standards,
or
operating
limitations
from
recordkeeping
and
reporting
requirements,
including
SSM
plans
and
semiannual
compliance
reports.
One
commenter
(
355)
suggested
that
all
requirements
in
the
proposed
rule
that
are
not
directly
related
to
quantifiable
emission
reductions
be
removed
from
the
rule
(
i.
e.,
notification,
monitoring,
reporting,
fuel
analyses,
and
recordkeeping
requirements).
One
commenter
(
491)
stated
that
Title
V
permits
150
should
not
be
required
for
units
with
no
substantive
requirements.
The
commenter
recommended
that
these
units
be
excluded
from
the
various
procedure
requirements
such
as
initial
notifications
in
the
boilers
NESHAP
or
exempt
them
from
Title
V
and
other
air
pollution
permit
requirements,
if
they
would
otherwise
be
exempt
under
state
or
local
regulations.
Response:
In
the
final
rule,
we
specifically
exempt
sources
with
no
emission
limits
or
work
practice
standards
from
most
requirements
of
this
NESHAP
and
the
General
Provisions
to
part
63,
including
the
SSM
plan
requirements.
For
large
sources
(
i.
e.,
sources
with
heat
input
capacities
of
10
MMBtu/
hr
or
greater)
we
require
only
that
you
submit
an
initial
notification.
See
§
63.75056(
e)
and
(
f)
of
the
final
rule
for
the
requirements
for
sources
with
no
emission
limits
or
work
practice
standards.

Comment:
One
commenter
(
491)
suggested
that
EPA
remove
the
requirement
in
§
63.7520
to
prepare
a
site
specific
test
plan
for
those
facilities
that
do
not
have
to
perform
any
testing.
Response:
The
final
rule
does
not
require
you
to
prepare
a
site­
specific
test
plan
if
you
do
not
have
to
perform
any
emission
testing.
If
you
demonstrate
compliance
through
fuel
sampling
and
analysis,
you
will
have
to
develop
a
site­
specific
fuel
sampling
plan.

Comment:
One
commenter
(
380,
476)
requested
clarification
of
whether
daily
fuel
use
records
are
required
for
gas­
fired
boilers.
The
commenter
contended
that
the
preamble
and
the
regulatory
text
have
differing
views.
The
commenter
added
that
since
gas­
fired
boilers
are
subject
to
only
the
CO
work
practice,
it
is
unnecessary
to
maintain
records
for
fuel
use.
One
commenter
(
427)
questioned
why
it
is
necessary
for
gas
and
liquid
fired
sources
that
switch
suppliers
to
submit
notifications
of
fuel
changes
if
they
are
not
required
to
be
controlled.
One
commenter
(
417)
believes
the
provisions
requiring
operators
to
keep
daily
records
of
fuel
use
and
operating
hours
are
onerous
and
unnecessary.
If
a
facility
does
not
have
any
indication
of
compliance
problems,
these
recordkeeping
obligations
should
be
substantially
reduced
to
require
only
information
about
atypical
operating
hours
and
new
fuels
that
threaten
an
emission
limit.
The
commenter
(
417)
believes
that
operators
should
only
have
to
provide
statements
if
fuel
chlorine,
mercury
or
total
selected
metals
will
exceed
a
prorated
value
equal
to
the
applicable
emission
standard.
Several
commenters
(
406,
407,
408,
501)
contended
that
the
proposed
rule
would
place
unduly
burdensome
monitoring
and
recordkeeping
requirements
on
owners
of
biomassfueled
boilers.
The
commenters
added
that
a
strict
reading
of
the
proposal
could
require
an
almost
continuous
process
of
fuel
analysis,
with
extremely
burdensome
recordkeeping
consequences.
The
commenters
added
that
the
reporting
requirements
for
the
semiannual
compliance
reports
are
excessive.
The
commenters
requested
that
EPA
reduce
the
requirements
to
a
semiannual
statement
of
compliance,
using
current
state
forms
already
developed
for
this
purpose
and
that
only
require
deviations
from
compliance
to
be
included.
Response:
The
final
rule
does
not
require
existing
liquid
and
gaseous
fuel­
fired
units
to
keep
records
of
fuel
use.
New
gaseous
fuel­
fired
units
that
do
not
have
any
emission
limits
or
work
practice
standards
and
new
liquid
fuel­
fired
units
that
do
not
burn
any
residual
oil
do
not
have
to
monitor
fuel
use.
For
all
other
sources
that
have
to
monitor
fuel
use,
we
have
modified
the
fuel
monitoring
requirements
to
be
based
on
monthly
fuel
use,
and
no
longer
require
daily
fuel
use
monitoring.
We
have
also
modified
the
fuel
sampling
requirements
to
be
based
on
fuel
type
and
not
on
fuel
shipment,
supplier,
and
location.
Therefore,
if
you
have
to
conduct
fuel
sampling,
you
will
only
be
required
to
conduct
an
initial
sample,
and
then
once
every
five
years
for
each
fuel
type
that
you
burn.
Additional
fuel
sampling
would
be
triggered
only
if
you
burned
a
new
type
of
151
fuel.
We
maintain
that
the
changes
to
the
fuel
monitoring
and
sampling
requirements
in
the
final
rule
will
significantly
reduce
the
recordkeeping
and
reporting
burden
of
the
final
rule.

Comment:
One
commenter
(
491)
stated
that
§
63.7555(
d)
does
not
contain
a
clearly
relevant
applicable
requirement
for
such
affected
sources
unless
they
were
deemed
to
be
electing
to
comply
with
an
emission
limit
based
on
fuel
analysis.
Therefore,
the
commenter
suggested
that
the
section
be
modified
to
read:
§
63.7555(
d)
You
must
also
keep
the
records
in
paragraphs
(
d)(
1)
through
(
5)
of
this
section,
as
applicable.
(
1)
If
you
operate
an
affected
source
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil,
or
you
elect
to
comply
with
an
emission
limit
for
an
affected
source
based
on
fuel
analysis,
you
must
keep
records
of
daily
fuel
use
by
that
affected
source,
including
the
type(
s)
of
fuel,
amount(
s)
used,
the
supplier(
s),
and
original
source
location(
s).
(
2)
You
must
keep
records
of
daily
hours
of
operation
by
each
affected
source.
Response:
In
the
final
rule,
we
modified
this
section
to
clarify
that
all
units
subject
to
an
emission
limit
must
keep
records
of
fuel
use.
This
requirement
has
changed
from
daily
fuel
use
to
monthly
fuel
use
in
the
final
rule.
Also,
we
require
only
that
you
keep
records
of
operating
hours,
on
a
per­
month
basis,
if
you
have
a
limited­
use
source.
As
stated
in
an
earlier
section
of
the
final
rule,
if
you
have
a
liquid
fuel­
fired
unit
and
you
do
not
burn
any
residual
oil,
you
are
not
required
to
monitor
fuel
use.
We
also
made
several
changes
to
the
fuel
sampling
and
analysis
requirements
that
significantly
reduce
the
recordkeeping
burden
of
this
NESHAP.

Comment:
One
commenter
(
357)
contended
that
the
recordkeeping
requirements
should
be
based
on
fuel
analysis
and
not
supplier.
The
commenter
added
that
as
along
as
levels
established
during
performance
testing
are
not
exceeded,
the
fuel
source
does
not
matter.
Response:
In
the
final
rule,
we
modified
the
fuel
monitoring
requirements
to
be
based
on
fuel
type,
and
removed
the
requirements
to
conduct
additional
fuel
analyses
when
you
receive
fuel
from
a
new
supplier,
as
long
as
it
is
the
same
type
of
fuel
that
you
have
previously
analyzed.
This
change
should
significantly
reduce
the
monitoring,
recordkeeping,
and
reporting
burden
of
the
final
rule.

Comment:
Two
commenters
(
388,
449,
492,
498,
524,
533)
stated
that
only
one
statement
should
have
to
be
provided
for
each
fuel
in
the
event
that
several
similar
units
are
fired
with
the
same
fuel.
One
of
the
commenters
(
492)
suggested
allowing
one
statement
to
be
submitted
along
with
the
supporting
calculations.
The
commenter
did
not
see
any
need
in
requiring
repeated
statements
and
calculations
for
each
unit.
Furthermore,
the
commenter
noted
that
if
a
source
is
required
to
burn
fuel
with
certain
specifications,
then
the
owner
or
operator
should
not
have
to
submit
these
statements.
Response:
We
do
not
allow
one
statement
to
be
provided
for
similar
units
burning
the
same
type
of
fuel.
We
do
not
believe
that
this
is
a
requirement
that
needs
to
be
changed.
The
monitoring,
recordkeeping,
and
reporting
requirement
of
this
NESHAP,
and
typically
of
permits,
require
information
to
be
submitted
based
on
each
unit.
The
calculations
used
for
the
fuel
type
could
be
used
for
all
units
burning
the
fuel,
therefore,
this
is
not
an
onerous
requirement.

Comment:
Several
commenters
(
374,
388,
449,
492,
498,
523,
524,
533)
suggested
that
initial
notifications
should
not
be
required
for
affected
sources
that
have
submitted
112(
j)
Part
1
152
applications.
One
commenter
(
523)
stated
that
at
a
minimum,
initial
notifications
should
be
required
only
from
sources
subject
to
a
work
practice
or
an
emission
limitation
and
not
simply
because
a
source
is
subject
to
a
monitoring,
recordkeeping,
or
reporting
requirement.
One
commenter
(
492)
contended
that
requiring
these
sources
to
submit
similar
initial
notifications
required
under
§
63.7545(
b)
and
(
c)
is
redundant
and
burdensome.
Response:
Most
sources
are
not
required
to
submit
an
initial
notification
under
this
NESHAP.
We
do
not
believe
that
this
is
a
burdensome
requirement.
We
are
not
requiring
small
existing
sources
to
submit
an
Initial
Notification
because
they
do
not
have
any
emission
limits
or
work
practice
standards
and
believe
that
this
will
eliminate
several
thousand
sources
from
having
to
submit
a
notification.
All
new
sources
that
are
subject
to
this
NESHAP,
whether
they
have
emission
limits
and
work
practice
standards
or
not,
will
have
to
submit
an
Initial
Notification.

Comment:
One
commenter
(
523)
stated
that
the
requirement
to
submit
semiannual
reports
30
days
after
the
end
of
the
reporting
period
conflicts
with
state
reporting
requirements.
The
commenter
stated
that
semiannual
reports
should
be
submitted
as
required
by
the
renewable
operating
permit
(
ROP).
Response:
As
outlined
in
§
63.7550(
b)(
5),
if
you
have
an
alternative
reporting
schedule
for
semiannual
reporting
outlined
in
your
Title
V
operating
permit,
then
you
can
submit
the
semiannual
report
required
by
this
NESHAP
on
those
dates.
However,
these
alternative
reporting
dates
must
be
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A).

Comment:
One
commenter
(
529)
mentioned
that
the
site­
specific
monitoring
plan
is
required
to
be
submitted
for
approval
as
stated
in
§
63.7505(
cd)(
1),
but
does
not
have
a
stated
submission
date.
The
commenter
assumes
the
plan
should
be
submitted
in
accordance
with
the
submission
schedule
for
the
site
specific
performance
evaluation
plan
shown
in
§
63.8(
e),
but
would
like
clarification.
Response:
In
the
final
rule,
we
clarify
a
submittal
date
for
your
site­
specific
monitoring
plans
of
60
days
before
your
initial
compliance
demonstration.
This
is
the
least
amount
of
time
before
your
initial
compliance
demonstration
that
you
can
submit
your
monitoring
plans.
We
suggest
that
you
submit
your
monitoring
plans
more
than
60
days
before
your
initial
compliance
demonstration,
especially
if
you
are
petitioning
the
Administrator
for
an
alternative
monitoring
plan,
to
allow
time
for
you
and
your
permitting
authority
to
resolve
andy
issues
that
may
exist.

Comment:
One
commenter
(
523)
stated
that
the
rule
requires
sources
to
implement
a
written
SSM
plan
according
to
the
requirements
of
the
NESHAP
general
provisions.
The
commenter
believes
that
instead
of
referencing
the
general
provisions,
specific
SSM
requirements
should
be
adopted
in
this
rule.
The
commenter
stated
that
the
general
provisions
are
intended
to
be
"
gap­
fillers,"
i.
e.,
requirements
which
apply
unless
the
specific
rule
states
otherwise.
The
commenter
stated
that
since
the
SSM
general
provisions
appear
to
be
in
flux
due
to
litigation
over
the
general
provisions,
the
commenter
suggested
specifying
the
provisions
in
this
rule
and
not
having
40
CFR
63.6(
e)
apply.
The
commenter
stated
that
this
approach
will
also
avoid
conflicts
between
the
state
rules
for
SSM
plans,
Title
V
requirements,
and
the
NESHAP.
The
commenter
stated
that
the
SSM
requirements
only
need
to
state
that
such
a
plan
be
prepared,
implemented,
written,
and
amended
as
necessary
to
address
SSM
issues.
In
addition,
the
commenter
stated
that
there
should
not
be
any
requirement
to
submit
the
plans
to
the
state
agency
for
approval,
instead
simply
a
requirement
that
the
plan
be
"
approvable"
in
the
sense
that
it
meets
the
state
requirements
and
those
currently
listed
under
§
63.6.
153
Response:
We
do
not
incorporate
the
SSM
plan
requirements
of
the
general
provisions
into
this
rule.
The
final
rule
continues
to
reference
the
SSM
plan
requirements
in
the
general
provisions.
The
general
provisions
exist
not
as
a
"
gap­
filler,"
but
as
a
way
to
provide
consistency
for
compliance
activities
that
must
occur
for
all
sources
subject
to
a
NESHAP.

Comment:
One
commenter
(
523)
suggested
that
since
all
of
the
sources
affected
by
this
NESHAP
are
subject
to
the
Title
V
permit
program
and
since
that
program
already
includes
a
compliance
certification
requirement,
as
well
as
a
requirement
for
reporting
at
least
semiannually,
the
additional
monitoring
requirements
included
in
this
rule
should
be
modified
so
that
sources
can
do
all
required
reporting
and
recordkeeping
through
their
Title
V
permit
program.
The
commenter
asserted
that
this
is
especially
necessary
for
sources
that
are
not
subject
to
any
emission
limitations
under
the
proposed
rule.
One
commenter
(
358)
supported
all
compliance
reporting
and
recordkeeping
be
provided
to
the
Administrator
as
part
of
the
facility's
Title
V
operating
permit.
The
commenter
suggested
requiring
compliance
reports
to
be
submitted
to
the
reporting
agency
no
less
often
than
annually,
as
part
of
the
Annual
Compliance
Certification
Statement.
Response:
We
disagree
with
the
commenter
and
have
retained
the
recordkeeping
and
reporting
elements
in
the
final
rule.
Several
changes
have
been
made
since
proposal
that
have
reduced
the
compliance
burden
of
the
final
rule.
However,
we
believe
that
we
must
include
recordkeeping
and
reporting
requirements
in
this
rule
and
not
simply
let
the
Title
V
Operating
Permit
program
develop
those
requirements.
By
including
recordkeeping
and
reporting
requirements
in
this
rule,
this
will
result
in
consistent
requirements
for
all
sources
affected
by
this
rule.
If
it
were
left
up
to
Title
V
mechanisms,
sources
could
have
a
wide
range
of
recordkeeping
and
reporting
requirements
and
we
do
not
believe
that
this
would
be
appropriate.
Furthermore,
keeping
recordkeeping
and
reporting
requirements
in
the
final
rule
assure
us
that
all
affected
sources
will
collect
the
right
types
and
amount
of
data
to
ensure
continuous
compliance
with
this
NESHAP.

Comment:
Several
commenters
(
364,
374,
381,
382,
387,
391,
392,
399,
400,
401,
403,
449,
452,
478,
479,
492)
agreed
with
the
EPA
approach
that
deviations
during
periods
of
startup,
shutdown,
or
malfunction
should
not
automatically
constitute
violations
of
the
MACT
standards.
The
commenters
urged
the
EPA
to
retain
it
in
the
final
boilers
NESHAP.
One
commenter
(
491)
supported
the
position
in
§
63.7540(
d)
that
deviations
that
occur
during
periods
of
startup,
shutdown
or
malfunctions
are
not
violations
if
it
can
be
demonstrated
to
the
Administrator's
satisfaction
that
the
source
was
being
operated
in
accordance
with
the
SSM
plan.
The
commenter
stated
that
it
may
not
be
possible
to
comply
with
limitations
during
these
times.
In
addition,
the
commenter
stated
that
the
owner
or
operator
should
be
required
to
take
expeditious
action
in
the
event
of
a
malfunction
and
that
non­
compliance
should
not
result
if
the
malfunction
is
corrected
in
a
timely
manner.
Another
commenter
(
448)
said
that
the
EPA's
compliance
loophole
for
startup,
shutdown,
and
malfunction
events
is
unlawful,
arbitrary,
and
capricious
since
the
proposed
standards
do
not
require
compliance
with
emission
standards
during
those
events.
The
commenter
also
questioned
how
the
proposed
provision
for
determining
if
a
facility
was
operating
in
compliance
with
its
SSM
plan
and
OMM
plan
would
operate
in
enforcement
suits
brought
by
citizens
rather
than
the
Administrator.
Response:
We
maintain
that
sources
should
have
special
provisions
for
periods
of
startup,
shutdown,
and
malfunction
as
these
are
normal
occurrences
for
boilers
and
process
heaters,
but
they
are
also
associated
with
transient
behavior
of
the
source
which
can
lead
to
fluctuations
in
154
emission
levels.
Sources
have
to
consider
personnel
and
equipment
safety
considerations
during
these
periods
and
these
considerations
also
effect
a
source's
ability
to
minimize
emissions
and
respond
to
such
periods.
Therefore,
we
require
sources
to
develop
SSM
plans
to
document
how
they
will
operate
their
source
during
these
periods
in
order
to
minimize
emission
levels.
We
defer
to
the
Administrator
the
decision
on
whether
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
violations
of
the
standard
because
historical
and
case­
dependent
factors
must
be
reviewed
before
such
a
decision
is
made.
To
evaluate
a
deviation
that
occurs
during
a
period
of
startup,
shutdown,
or
malfunction,
the
Administrator
must
consider
whether
the
source
followed
their
SSM
plan,
were
there
any
other
actions
the
source
could
have
taken
to
minimize
emissions,
does
the
source
have
a
history
of
malfunctions
that
could
be
attributed
to
poor
maintenance,
and
other
case­
specific
factors.
We
believe
that
this
is
the
most
appropriate
method
to
evaluate
deviations
during
periods
of
startup,
shutdown,
or
malfunction.

Comment:
One
commenter
(
491)
stated
that
§
63.7550(
e)(
6)
imposes
vague
and
unnecessary
requirements.
The
commenter
suggested
that
§
63.7550(
e)(
6)
be
revised
as
follows:
§
63.7550(
e)(
6)
A
breakdown
of
the
total
duration
of
the
deviations
during
the
reporting
period
into
those
that
are
due
to
startup,
shutdown,
malfunction,
and
other
causes.
Response:
We
maintain
that
these
requirements
are
not
vague
and
unnecessary.
In
the
final
rule,
we
do
not
state
that
deviations
that
occur
during
periods
of
startup,
shutdown,
or
malfunction
are
not
automatically
violations
of
the
standard.
This
determination
would
be
made
by
the
Administrator.
However,
for
the
Administrator
to
make
such
a
decision,
an
historical
perspective
of
a
source's
startup,
shutdown,
and
malfunction
events
are
necessary.
Therefore,
we
require
a
more
detailed
breakdown
of
the
reasons
for
the
occurrence
of
deviations
and
are
not
groupiing
control
equipment
problems,
process
problems
into
a
single
malfunction
category.

Comment:
Several
commenters
(
406,
407,
408,
413,
501)
requested
that
EPA
require
a
30­
day
notice
for
performance
testing
instead
of
the
60­
day
notification
in
the
proposal.
Several
commenters
(
406,
407,
408,
501)
contended
that
a
60­
day
notification
for
performance
tests
should
only
apply
to
the
initial
performance
tests.
The
commenters
added
that
most
states
have
a
much
shorter
notification
requirement.
The
commenters
added
that
it
is
difficult
to
plan
testing
60
days
in
advance
when
a
facility
has
multiple
boilers.
Response:
In
the
final
rule,
we
have
changed
the
reporting
requirements
since
proposal
to
require
that
you
submit
a
notification
from
30
to
60
days
before
you
conduct
your
compliance
demonstration.
The
compliance
demonstration
is
either
your
performance
testing
or
your
fuel
sampling,
depending
on
how
you
demonstrate
compliance
with
this
NESHAP.

Comment:
One
commenter
(
491)
claimed
that
the
statement
regarding
periods
of
startup,
shutdown,
and
malfunction
in
§
63.7540(
b)
is
problematic
and
seems
inconsistent
with
the
provisions
of
§
63.7505(
a)
which
provides
"
you
must
be
in
compliance
with
the
emission
limitations
(
including
operating
limits)
and
the
work
practice
standards
in
this
subpart
at
all
times,
except
during
periods
of
startup,
shutdown,
and
malfunction."
The
commenter
stated
that
it
is
not
clear
what
emission
limit
or
operating
limit
would
not
be
met
that
must
be
reported
under
§
63.7540(
b)
since
the
emission
limits
and
operating
limits
in
Table
7.
A
and
7.
B
apply
to
periods
other
than
periods
of
startup,
shutdown,
and
malfunction.
The
commenter
suggested
clarifying
§
63.7540(
b)
as
follows:
§
63.7540(
b)
You
must
report
each
instance
in
which
you
did
not
meet
each
emission
limit
and
each
operating
limit
in
Tables
7.
A
and
7.
B
to
this
subpart
that
apply
to
you,
and
you
must
report
155
each
instance
during
a
startup,
shutdown
or
malfunction
when
emissions
exceeded
the
level
of
a
relevant
emissions
limit
or
work
practice
standard,
or
you
did
not
meet
a
parameter
value
for
an
operating
limit
in
Table
7.
B.
You
must
also
report
each
instance
in
which
you
did
not
meet
the
work
practice
requirements
in
Table
8
to
this
subpart
that
apply
to
you.
These
instances
are
deviations
from
the
emission
limitations
and
work
practice
standards
in
this
subpart.
These
deviations
must
be
reported
according
to
the
requirements
in
§
63.7550.
Response:
In
the
final
rule,
we
revised
§
63.7540(
b)
to
make
it
more
clear
and
consistent
with
our
stance
on
periods
of
startup,
shutdown,
and
malfunction.
In
this
section,
the
final
rule
separates
your
reporting
requirements
for
deviations
based
on
whether
or
not
a
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction.

Comment:
One
commenter
(
491)
stated
that
the
requirement
in
§
63.7540(
d)
that
a
source
must
demonstrate
that
it
is
operated
in
accordance
with
its
startup,
shutdown,
and
malfunction
plan
during
every
event
is
burdensome
and
the
demonstration
to
the
"
Administrator's
Satisfaction"
statement
is
vague.
The
commenter
suggested
that
§
63.7540(
d)
be
revised
to
as
follows:
(
d)
Consistent
with
§
63.6(
e)
and
§
63.7(
e),
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
not
violations
if,
upon
request
of
the
Administrator,
you
demonstrate
that
you
were
operating
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
Response:
We
did
not
revise
§
63.7540(
d)
as
suggested
by
the
commenter.
We
do
not
believe
that
the
requirement
is
overly
burdensome
and
will
require
you
to
demonstrate
that
you
were
operating
in
accordance
with
your
SSM
plan.
The
Administrator
will
require
this
information
anyway
if
you
experienced
a
deviation
during
a
period
of
startup,
shutdown,
or
malfunction
to
determine
if
the
deviation
is
a
violation
of
the
standard
or
not.
To
include
the
commenter's
suggested
language
would
retard
the
process
of
the
Administrator's
decision
by
adding
another
step
in
the
data
gathering
process
that
would
automatically
occur
under
the
proposed
and
final
rule.
156
13.0
Impacts
13.1
Control
Costs
Comment:
Several
commenters
(
338,484,
522,
521,
363)
stated
that
EPA
has
understated
the
cost
to
install
controls
on
existing
units
because
of
site­
specific
physical
constraints.
Commenters
(
338,
484,
522)
claimed
that
due
to
footprint
boundaries,
some
retrofits
are
only
possible
through
vertical
construction
schemes,
which
can
cost
up
to
four
times
more
than
horizontal
construction
schemes.
One
commenter
(
522)
explained
that
universities
and
colleges
are
space
limited
and
any
additional
controls
would
have
to
be
integrated
vertically
as
opposed
to
horizontally,
thereby
significantly
increasing
costs.
Another
commenter
(
521)
stated
that
some
boilers'
fans,
duct
work,
and
positioning
were
not
originally
designed
to
handle
a
baghouse.
Therefore,
many
parts
will
need
to
be
modified
to
accommodate
a
baghouse
as
part
of
boiler
NESHAP
compliance.
The
commenter
stated
that
based
upon
estimates
from
equipment
suppliers,
the
cost
for
a
baghouse
could
be
$
3.5
million,
almost
ten
times
EPA's
estimate.
One
commenter
(
363)
contended
that
installing
flue
gas
scrubbers
would
be
a
problem
because
there
would
not
be
enough
room
on
site.
The
commenter
(
363)
added
that
purchasing
the
scrubbers
would
increase
the
electricity
rates
and
their
customers
would
not
be
able
to
absorb
the
costs.
The
commenter
concluded
that
the
units
would
be
taken
out
of
service,
thereby
denying
customers
an
economical
and
reliable
source
of
electricity.
Response:
Costs
and
emission
impacts
estimated
for
the
boiler
MACT
standard
are
intended
to
represent
national
impacts.
Consequently,
costs
for
a
specific
facility
may
be
lower
or
higher
than
what
was
estimated
for
a
specific
model
unit.
But
on
a
national
basis,
we
believe
that
our
estimates
are
reasonable.
We
would
also
note
that
the
cost
algorithms
include
a
cost
factor
for
retrofitting
existing
boilers,
that
do
incorporate
duct
length
and
some
spacial
concerns.
Additionally,
facility
or
boiler
specific
information
on
construction
schemes
were
not
available
to
develop
cost
impacts.
Therefore,
they
could
not
be
incorporated
into
the
cost
estimates.

13.1
Control
Costs
Comment:
Commenters
(
364,
399,
387)
suggested
that
EPA
reevaluate
the
cost
analysis
for
coal
and
wood­
fired
boilers.
For
coal­
fired
boilers,
the
commenter
believes
that
venturi
scrubbers
alone
are
not
likely
to
achieve
the
particulate
emission
limits
and
requested
that
EPA
reevaluate
the
cost
analysis
using
ESPs
or
fabric
filters
as
the
control
technology
for
meeting
the
particulate
matter
or
alternative
limits.
Furthermore,
the
commenter
believes
that
fabric
filters
will
be
required
on
many
existing
coal­
fired
boilers
to
meet
the
mercury
emission
limit.
For
woodfired
boilers,
the
commenter
also
questioned
the
effectiveness
of
venturi
scrubbers
to
meet
the
proposed
emission
limit
and
requested
that
EPA
reevaluate
the
cost
analysis
using
ESPs
as
the
control
technology.
Response:
For
the
cost
analysis,
we
evaluated
several
different
control
technologies
to
meet
emission
limits.
The
technologies
considered
the
least
cost
option
in
controlling
emissions
from
the
four
pollutant
classes
regulated
in
the
MACT
standard
were
used
to
represent
the
costs
of
the
rule.
Based
on
control
effectiveness
information
provided
for
the
proposal,
we
determined
that
newer
venturi
scrubbers
can
achieve
PM
emission
reductions
from
the
baseline
level
to
meet
the
MACT
standard.
In
most
of
these
cases,
the
PM
reduction
required
is
small
because
the
baseline
level
is
already
close
to
the
MACT
emission
limits.
The
impacts
memorandum
developed
at
proposal
provides
costs
for
all
the
various
control
technologies
that
were
looked
at
as
control
options
for
a
model
unit.
157
13.2
Cost
of
Monitoring
Comment:
Commenters
(
339,
347)
opposed
the
requirement
for
CO
CEMS
on
new
and
reconstructed
liquid
and
gaseous
fuel­
fired
units.
One
commenter
(
339)
noted
that
sources
already
have
an
economic
and
operational
incentive
to
maintain
good
combustion
practices
without
expensive
monitoring.
The
commenter
(
339)
also
explained
that
EPA
had
determined
that
as
capital
cost
of
$
88,000
and
$
33,000
in
operating
costs
for
HCl
monitors
was
unreasonable,
however,
the
costs
for
CO
monitoring
systems
would
be
equivalent,
yet
EPA
did
not
deem
them
to
be
unreasonable.
One
commenter
(
347)
contended
that
CO
CEMS
are
too
costly
and
there
are
more
cost
effective
methods
to
ensure
good
combustion
practices.
The
commenter
(
347)
suggested
that
annual
tuning
of
the
burner
be
required
instead,
especially
for
units
smaller
than
10
MMBtu/
hr.
Another
commenter
(
343)
opposed
the
requirements
for
a
CO
CEMS
for
units
burning
gaseous
or
liquid
fuels
with
a
heat
input
capacity
greater
than
10
MMBtu/
hr.
The
commenter
(
343)
stated
the
costs
to
implement
CEMS
are
very
high
compared
to
other
alternatives.
In
addition,
the
commenter
(
343)
stated
that
EPA's
CEMS
Cost
Model
Version
3.0
estimates
total
costs
to
implement
a
base­
case
extractive
CO
CEMS
on
a
new
unit
would
be
$
129,500,
with
annual
costs
of
$
39,100.
Commenters
(
360,
424,
332)
contended
that
EPA
significantly
underestimated
the
typical
cost
of
new
sources
to
comply
with
the
requirement
to
install
a
CO
CEMS.
The
commenter
(
360)
concluded
that
the
high
costs
to
install
CO
CEMS
and
the
low
emissions
reduction
would
make
their
use
cost­
ineffective,
and
cannot
be
justified
based
on
either
existing
regulations
or
a
cost­
effectiveness
basis.
(
4)
The
commenter
(
332)
explained
that
the
cost
EPA
assumed
for
complying
with
the
CO
work
practice
standard
is
insufficient
to
even
purchase
a
CO
analyzer,
much
less
the
system
into
which
it
must
be
operated.
The
commenter
noted
that
the
cost
per
CO
CEMS
would
be
$
164,500
in
capital
with
an
annual
cost
of
$
32,896.
Another
commenter
(
499)
stated
that
the
costs
for
CO
CEMS
can
be
as
much
as
$
150,000
to
install
and
operate.
The
commenter
stated
that
this
cost
can
approach
or
exceed
the
fixed
capital
costs
to
install
many
small
boilers
and
process
heaters.
Another
commenter
(
371)
claimed
the
cost
of
purchase
and
install
CEMS
would
be
approximately
$
120,000
per
unit,
with
approximately
$
20,000
­
$
30,000
in
annual
maintenance
costs.
In
contrast,
the
cost
of
source
testing
of
units
is
approximately
$
1,500
annually
per
unit.
Given
the
high
cost
of
CO
CEMS,
commenter
(
332)
requested
that
EPA
reconsider
applying
a
CO
work
practice
standard
to
gaseous
fuel­
fired
units.
One
commenter
(
380)
contended
that
EPA
underestimated
the
cost
of
CO
CEMS
because
it
based
its
costs
on
CO/
O
2
process
monitors
in
a
study
of
medical
waste
incinerators.
The
commenter
added
that
these
process
monitors
are
not
typical
of
CO
CEMS
and
have
not
been
demonstrated
to
provide
continuous
monitoring
of
CO.
The
commenter
referenced
work
done
by
the
Gas
Research
Institute
on
CO
monitors.
The
commenter
concluded
that
the
actual
cost
of
CO
CEMS
would
be
three
times
higher.
The
commenter
cited
information
presented
in
the
"
Cost
Algorithms"
Memorandum.
Response:
We
have
revised
the
CO
requirements
in
the
final
rule.
The
regulations
that
formed
the
basis
of
the
CO
requirements
in
the
proposed
rule
do
provide
sources
with
the
option
of
conducting
annual
testing
or
installing
CO
CEMS
to
demonstrate
compliance
with
the
CO
emission
limit.
Because
the
regulations
that
were
the
basis
of
the
MACT
floor
do
not
provide
specifics
on
which
boilers
should
conduct
annual
testing
and
which
should
use
CO
CEMS,
we
reviewed
the
cost
information
provided
by
the
commenters
to
make
this
determination.
In
considering
the
additional
cost
information
and
reviewing
the
cost
information
used
in
the
proposed
rule,
the
EPA
decided
that
changes
to
the
CO
compliance
requirements
were
warranted.
158
The
final
rule
requires
that
new
units
with
heat
input
capacities
less
than
100
MMBtu/
hr
conduct
initial
and
annual
performance
tests
for
CO
emissions.
New
units
with
heat
input
capacities
greater
or
equal
to
100
MMBtu/
hr
are
still
required
to
install,
operate,
and
maintain
a
CO
CEM.
Additionally,
units
in
the
limited
use
subcategories
must
conduct
performance
tests
and
are
not
required
to
operate
CO
CEMS
because
of
the
small
length
of
time
these
units
are
in
operation.

Comment:
One
commenter
(
395)
stated
the
proposed
procedures
for
changing
operating
limits
do
not
provide
an
acceptable
solution.
Multiple
tests
would
be
necessary
to
establish
the
minimum
operating
parameters
required
to
maintain
compliance
with
the
provisions,
resulting
in
excessive
costs
and
repeated
delays
associated
with
the
required
notifications,
testing,
and
approvals.
Response:
We
have
made
several
changes
to
the
proposed
rule
that
will
reduce
burden
and
cost
of
compliance
while
maintaining
the
stringency
of
the
standard.
However,
we
believe
that
multiple
tests
may
be
necessary
in
some
cases
in
order
to
ensure
that
the
proper
operating
parameters
can
be
established.

Comment:
One
commenter
(
348)
argued
that
the
requirement
to
install
a
COMS
would
be
extremely
costly
because
extensive
modifications
would
have
to
be
completed
to
support
the
monitor.
Response:
We
recognize
that
in
some
cases
costs
for
COMS
may
be
high.
This
cost
was
incorporated
into
the
impacts
analysis.
We
would
note
that
sources
that
use
fabric
filters
are
not
required
to
use
COMS.
Additionally,
sources
can
petition
the
Administrator
for
alternative
monitoring
plans.

13.3
Methodology
Comment:
One
commenter
(
536)
claimed
that
EPA
failed
to
adequately
characterize
the
impacts
on
public
power
producers
because
EPA
did
not
create
separate
model
plants
for
public
power.
The
commenter
contended
that
EPA's
impacts
analysis
depends
upon
the
accuracy
of
model
plants
to
predict
the
costs
of
compliance.
However,
the
commenter
added
that
to
adequately
characterize
impacts
on
public
power
produces,
EPA
would
need
to
create
separate
model
plants
for
public
power.
The
commenter
(
536)
contended
that
EPA
used
a
standard
nationwide
model
to
assess
the
effects
of
compliance
on
the
electric
industry
as
a
whole.
The
commenter
continued
that
the
model
then
estimated
government
effects
by
determining
the
likely
compliance
costs
to
firms
and
extrapolating
what
pass­
through
costs
will
be
shouldered
by
State
and
local
governments.
The
commenter
contended
that
this
estimate
cannot
be
credibly
done
without
evaluating
the
costs
of
compliance
to
public
power
producers.
The
commenter
(
536)
added
that
EPA
must
consider
factors
that
make
public
power
systems
unique
in
the
analysis,
including
contractual,
physical
and
political
constraints
and
potential
loss
of
high
paying
jobs
in
small
communities.
In
addition,
the
commenter
contended
that
EPA
failed
to
recognize
that
public
power
produces
provide
other
services
to
the
locality
that
would
be
harmed
by
the
proposed
rule.
The
commenter
added
that
some
of
the
services
include
direct
payments
to
local
governments,
free
or
reduced
electric
services,
and
services
to
local
communities
that
are
generally
lower
than
prices
charged
by
investor
owned
utilit1ies.
Other
commenters
(
449,
524,
533,
388,
498)
claimed
that
EPA's
"
macro­
economic"
analysis
failed
to
adequately
address
the
impacts
on
small
coal
or
wood­
burning
facilities.
The
commenters
noted
that
EPA's
MACT
support
document
that
addresses
the
economic
analysis
of
159
the
proposed
boilers
NESHAP
is
a
"
macro­
economic"
impact
type
of
analysis
and
may
not
be
effective
at
analyzing
the
cost
to
small
businesses.
The
commenters
explained
that
the
analysis
does
not
address
the
less­
than­
50
person
coal
or
wood
burning
facility
that
will
have
to
make
upfront
investments
for
control
devices,
monitoring
systems,
and
other
items
required
to
comply
with
the
boilers
NESHAP.
Response:
The
economic
impact
model
used
by
EPA
is
a
national
model
that
is
primarily
designed
to
examine
impacts
to
producers
and
consumers
through
estimation
of
price
and
output
changes
to
affected
products
on
a
nationwide
basis.
In
doing
so,
the
model
presumes
competitive
behavior
among
entities
and
some
ability
of
entities
to
pass
along
some
share
of
their
compliance
costs
to
consumers.
This
is
generally
a
suitable
presumption
for
the
industries
contained
in
the
model
and
affected
by
this
proposed
rule.
For
industries
and
entities
where
there
may
be
deviation
from
this
presumption,
it
may
be
that
the
accuracy
of
the
model
becomes
more
problematic.
It
should
be
noted
that,
for
the
purposes
of
estimating
small
entity
analyses,
EPA
also
estimated
annual
costs
as
a
percentage
of
revenues
for
affected
small
entities.
The
results
of
this
screening
analysis
are
shown
in
the
economic
impact
analysis
report,
and
the
results
of
this
screening
analysis
are
combined
with
the
results
of
the
economic
impact
analysis
to
ascertain
the
small
entity
impact
results.
Given
these
impacts,
we
were
able
to
conclude
that
the
small
entity
impact
results
were
insufficient
to
be
a
significant
impact
on
a
substantial
number
of
small
entities
(
or
SISNOSE).
While
it
is
EPA's
position
that
our
economic
impact
model
is
still
accurate
in
estimating
the
impacts
of
this
rule
upon
affected
producers
and
consumers,
we
understand
that
municipal
utilities
may
be
a
more
difficult
type
of
entity
to
model
in
this
fashion.
EPA
thanks
the
commenters
for
providing
their
statements
of
potential
effects
of
the
rule
to
small
communities.

Comment:
Several
commenters
disagreed
with
the
methodology
EPA
used
to
determine
the
cost
and
compliance
burden
on
affected
facilities.
One
commenter
(
536)
noted
that
EPA
used
the
Cost­
to­
Sales
ratio
(
CSR)
method
to
determine
what
constitutes
a
"
significant"
effect
on
a
given
facility.
The
commenter
contended
that
the
CSR
method
cannot
provide
a
meaningful
estimate
of
economic
effect
because
it
compares
annualized
compliance
costs
against
annual
gross
sales
for
each
facility.
The
commenter
contended
that
gross
sales
is
a
meaningless
measure
of
economic
viability,
particularly
for
public
power
producers
since
they
do
not
operate
on
a
forprofit
basis.
The
commenter
stated
that
an
effective
analysis
of
the
economic
impact
of
compliance
must
examine
compliance
costs
against
some
form
of
net
revenue
in
net
present
value
terms.
The
commenter
added
that
for
public
power
producers,
the
net
payments
to
the
general
fund
of
the
parent
entity
provides
an
appropriate
measure
with
which
to
calculate
net
effects.
One
commenter
(
428)
stated
the
annualized
compliance
cost,
which
EPA
claims
to
be
zero
for
existing
liquid
and
gaseous
units
(
Table
3
of
the
preamble),
has
failed
to
include
the
expense
associated
with
semiannual
compliance
reports,
recording
daily
fuel
usage,
recording
hours
of
operation,
and
the
development
and
documentation
of
adherence
to
the
startup,
shutdown,
and
malfunction
plan.
One
commenter
(
427)
opposed
using
reductions
of
PM
and
SO
2
to
justify
a
MACT
standard.
The
commenter
contended
that
EPA
should
detail
the
social
benefits
of
reduction
of
HAP
emissions
instead
of
looking
at
PM
and
SO
2.
Response:
EPA
has
used
a
comparison
of
annualized
compliance
costs
to
annual
gross
sales
as
a
indicator
of
potential
economic
impacts
to
small
entities
for
small
entity
analysis
purposes
for
a
number
of
years.
While
it
is
not
the
only
possible
indicator
of
impacts
of
a
regulation
on
small
entities,
it
is
one
that
is
useful
given
the
usual
availability
of
financial
data
on
160
affected
firms.
Profits
or
net
payments
to
general
funds
of
the
parent
entity
are
data
not
normally
available
for
firms,
and
profit
data
is
often
different
from
what
is
preferred
for
an
analysis
since
it
is
often
not
true
economic
profit
(
due
to
tax
and
other
accounting
considerations).
EPA
will
explore
using
net
payment
data
in
comparison
to
the
compliance
costs
for
affected
small
public
power
producers
in
its
analysis
for
the
final
rule.
EPA
presents
monetized
benefits
of
the
PM
and
SO2
emission
reductions
as
part
of
providing
as
full
a
comparison
of
benefits
and
costs
of
this
proposal
as
possible.
Since
this
proposal
is
a
major
rule
under
the
definitions
provided
in
Executive
Order
12866,
EPA
must
follow
its
requirements.
A
Regulatory
Impact
Analysis
(
RIA)
is
called
for
by
that
Executive
Order,
and
a
full
comparison
of
benefits
and
costs
is
required.
For
this
rule,
the
PM
and
SO2
emission
reductions
are
substantial,
and
credible
methodologies
exist
to
provided
monetized
benefit
estimates
to
compare
to
the
compliance
costs.
These
benefit
estimates
do
not
justify
the
rule,
since
the
MACT
floor
option
proposed
is
unrelated
to
the
costs
and
impacts
associated
with
it.
We
are
currently
unable
to
provide
monetized
benefits
of
the
substantial
HAP
emission
reductions
associated
with
this
proposed
rule,
a
statement
we
make
in
the
RIA.

13.4
Cost
to
Municipal
Power
Generators
Comment:
Commenters
stated
that
the
proposed
rule
would
have
significant
impacts
on
municipal
electrical
power
generators
and
that
EPA
underestimated
those
impacts.
Commenters
claimed
that
EPA
failed
to
recognize
the
unique
characteristics
of
these
small
municipal
generators
and
therefore
inadequately
assessed
the
economic
impacts.
Several
commenters
(
373,
378,
398,
421,
422,
429,
435,
469,
470,
471,
472,
481,
506,
509)
contended
that
the
proposed
rule
endangers
the
continued
viability
of
municipal
electric
generation
by
imposing
enormous
capital
and
operating
costs
on
small
municipal
generators
which,
given
existing
legal
and
functional
constraints,
are
not
feasible
or
achievable.
The
commenters
added
that
if
the
rule
is
not
changed,
many
municipal
generators
will
shut
down
resulting
in
customers
and
coal
companies
losing
important
benefits
and
protections.
One
commenter
(
536)
contended
that
EPA
failed
to
recognize
the
basic
differences
between
the
public
power
sector
as
both
government
and
small
business
entity.
The
commenter
also
added
that
EPA
failed
to
recognize
that
public
power
is
not
a
traditional
business.
The
commenter
added
that
public
power
producers
operate
under
constraints
that
cause
them
to
act
to
maximize
the
utility
of
entities
other
than
themselves.
The
commenter
stated
that
they
have
contractual
obligations
to
the
local
governments
that
keep
them
from
acting
strictly
to
maximize
company
profits.
The
commenter
continued
that
public
power
utilities
are
also
faced
with
pressures
imposed
on
any
local
government
entity
because
they
are
governed
by
their
consumerowners
through
locally
elected
or
appointed
officials.
The
commenter
(
536)
also
contended
that
EPA
failed
to
recognize
that
municipal
generating
units
provide
services
for
the
public
good,
including
increasing
system
reliability
through
distributed
sources,
protecting
municipal
electric
system
residents
against
wholesale
prices
and
spikes,
providing
power
for
public
services,
and
relieving
transmission
congestion
and
providing
reactive
power
to
the
transmission
grid.
The
commenter
explained
that
unlike
real
power,
the
reactive
component
of
power
cannot
be
transmitted
over
long
distances
and
must
be
locally
provided.
The
commenter
added
that
without
local
generation,
parts
of
the
regional
grid
system
are
weakened
and
become
susceptible
to
voltage
collapse.
The
commenter
also
added
that
public
power
communities
are
legally
obligated
to
serve
local
residents
and
cannot
readily
expand
their
customer
base
without
increasing
their
geographic
and
political
borders,
which
can
only
be
161
altered
by
state,
city
or
county
ordinances
or
state
constitutions.
Response:
The
economic
impact
model
used
by
EPA
is
a
national
model
that
is
primarily
designed
to
examine
impacts
to
producers
and
consumers
through
estimation
of
price
and
output
changes
to
affected
products
on
a
nationwide
basis.
In
doing
so,
the
model
presumes
competitive
behavior
among
entities
and
some
ability
of
entities
to
pass
along
some
share
of
their
compliance
costs
to
consumers.
This
is
generally
a
suitable
presumption
for
the
industries
contained
in
the
model
and
affected
by
this
proposed
rule.
For
industries
and
entities
where
there
may
be
deviation
from
this
presumption,
it
may
be
that
the
accuracy
of
the
model
becomes
more
problematic.
Given
the
small
changes
in
price
and
output
of
products
affected
by
this
proposed
rule,
it
is
EPA's
position
that
municipal
utilities
and
public
power
generation
will
not
be
affected
significantly.
However,
while
it
is
EPA's
position
that
our
economic
impact
model
is
still
accurate
in
estimating
the
impacts
of
this
rule
upon
affected
producers
and
consumers,
we
understand
that
municipal
utilities
may
be
a
more
difficult
type
of
entity
to
model
in
this
fashion.
EPA
thanks
the
commenters
for
providing
their
statements
of
potential
effects
of
the
rule
to
small
communities.

Comment:
One
commenter
(
417)
stated
that
EPA's
analysis
failed
to
adequately
account
for
the
different
sets
of
constraints
under
which
public
power
providers
and
their
local
communities
must
operate
and
as
a
result,
designed
a
rule
that
causes
significant
localized
economic
harm
to
public
power
producers.
The
commenter
argued
that
EPA
incorrectly
assumed
that
impacts
on
municipal
generators
are
similar
to
those
on
other
utilities.
The
commenter
went
on
to
explain
that
the
proposed
rule
will
increase
the
cost
of
municipal
power
to
local
consumers
by
approximately
7
percent,
at
least
100
times
more
than
estimated
by
EPA.
The
commenter
believes
that
EPA
neglected
to
conduct
critical
parts
of
the
economic
analysis
required
by
a
number
of
statutes
and
Executive
Orders,
including
the
Unfunded
Mandates
Reform
Act
of
1995,
the
Regulatory
Flexibility
Act
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
and
Executive
Order
12866.
The
commenter
offered
to
provide
data
to
support
its
claim.
Response:
The
preliminary
analysis
that
the
commenter
uses
to
provide
foundation
to
its
claim
that
the
cost
of
municipal
power
to
local
consumers
will
increase
by
7
percent
is
not
part
of
its
submittal.
It
is
therefore
not
possible
for
EPA
to
understand
or
ascertain
the
basis
for
this
claim.

EPA
disagrees
with
the
commenter's
assertions
that
it
neglected
parts
or
the
whole
of
requirements
of
UMRA,
SBREFA,
and
E.
O.
12866.
EPA's
analyses
in
compliance
with
these
statues
and
Executive
Order
fufill
the
statutory
requirements
and
also
the
OMB
guidelines
issued
for
compliance
with
E.
O.
12866.
All
of
these
analyses
also
reflect
the
proposed
rule,
which
is
the
least
burdensome
alternative
that
EPA
could
issue
while
remaining
consistent
with
the
requirements
of
the
Clean
Air
Act.

While
it
is
EPA's
position
that
our
economic
impact
model
is
accurate
in
estimating
the
impacts
of
this
rule
upon
affected
producers
and
consumers,
we
understand
that
municipal
utilities
may
be
a
more
difficult
type
of
entity
to
model
in
this
fashion.
EPA
thanks
the
commenters
for
providing
their
statements
of
potential
effects
of
the
rule
to
small
communities.

Comment:
Several
commenters
contended
that
the
substantial
costs
to
municipal
power
generators
will
result
in
increased
electricity
rates
to
customers.
One
commenter
(
480)
contended
162
that
to
meet
the
requirements
of
the
proposed
rule,
municipal
utilities
will
be
forced
to
increase
electric
rates
to
their
customers.
The
commenter
contended
that
the
costs
of
the
rule
will
adversely
affect
municipalities
because
they
rely
on
low
electric
rates
from
the
utility
to
attract
business.
The
commenter
added
that
the
costs
to
comply
will
affect
the
ability
to
provide
essential
services
and
the
bond
ratings
of
cities.
One
commenter
(
536)
contended
that
the
proposed
rule
will
result
in
dramatically
higher
costs
per
kilowatt
hour
for
electricity,
tax
increases,
potential
loss
of
public
services,
and
the
transfer
costs
of
high­
wage
jobs
out
of
the
locality.
The
commenter
added
that
if
the
public
utility's
generation
source
ceases
to
function,
it
is
likely
that
the
community
will
see
a
substantial
increase
in
electric
rates
if
it
must
purchase
power
from
investor
utilities.
The
commenter
asserted
that
EPA
did
not
look
at
these
indirect
community
impacts.
One
commenter
(
423)
contended
that
for
small
electric
utility
boilers,
the
costs
will
be
many
magnitudes
greater
on
a
per
megawatt
basis
than
for
industrial
units.
The
commenter
added
that
the
full
cost
implementation
of
the
ruling,
when
spread
across
a
few
megawatts
produced,
will
drive
the
cost
of
power
from
these
units
to
exorbitant
levels.
One
commenter
(
342)
contended
that
there
would
be
a
significant
economic
impact
on
their
industry
because
they
are
small,
municipally
owned
business
and
use
their
electric
generation
during
time
peak
demand
or
during
high
market
conditions.
The
commenter
added
that
the
rule­
making
could
cause
a
shutdown,
causing
a
loss
of
revenue
of
$
1.3
million
annual
for
capacity
credits
from
their
electric
supplier.
Also,
the
commenter
contended
that
this
shutdown
would
cause
them
to
lose
26
percent
of
their
workforce,
the
city
would
see
a
reduction
of
payment
in
lieu
of
taxes,
and
they
would
bear
the
cost
of
replacement
energy.
The
commenter
concluded
that
the
rule
would
have
a
`
very
detrimental'
impact
on
their
utility
and
community.
Response:
EPA
estimated
a
increase
in
electricity
rates
of
only
0.05
percent
related
to
the
implementation
of
this
rule.
While
this
is
an
estimate
made
at
the
national
level,
it
is
EPA's
position
that
any
increase
in
electricity
rates
should
be
minimal
as
a
result
of
this
rule
to
local
producers
such
as
municipal
utilities.
Also,
the
economic
impact
analysis
does
examine
the
effect
to
consumers
from
increases
in
product
prices,
and
the
small
decrease
in
product
demand
by
consumers
is
evidence
that
the
indirect
community
impacts
are
small
as
well.
This
should
be
true
for
small
boiler
owners
as
well
as
larger
ones.

Comment:
One
commenter
(
417)
stated
that
the
proposed
rule's
use
of
site­
specific
operating
limits
imposes
arbitrary
and
inconsistent
requirements
that
will
detrimentally
affect
all
municipal
utilities.
The
commenter
suggested
that
the
existing
source
emission
limits
applied
to
municipal
utilities
should
be
revised
to
reflect
the
control
technology
achieved
in
practice
by
the
top
12
percent
of
the
municipal
utility
subcategory.
Response:
As
discussed
in
earlier
sections,
EPA
does
see
justification
for
developing
a
subcategory
specifically
for
municipal
utilities.
Additionally,
a
review
of
boilers
with
controls
located
at
municipal
utilities
indicates
that
establishing
such
a
subcategory
would
result
in
similar
control
requirements
that
are
already
required
in
the
rule.
We
would
also
note
that
we
have
provided
several
compliance
alternatives
that
will
provides
sources
with
the
flexibility
to
comply
with
the
standard
while
maintaining
the
stringency
of
the
standard.
These
alternatives
include
emissions
averaging,
meeting
fuel
content
limits,
and
risk
off
ramps.

13.5
Economic
Impacts
Comment:
Commenters
(
391,
392)
explained
that
the
textile
industry
cannot
pass
the
163
costs
of
the
boilers
NESHAP
compliance
to
customers
and
still
compete
with
imported
products
produced
in
high­
emission
facilities.
Many
textile
mills
would
be
forced
to
go
out
of
business.
Response:
EPA's
economic
impact
analysis
shows
that
there
will
be
minimal
decreases
in
demand
by
textile
consumers
as
a
result
of
implementing
this
rule.
The
reduction
in
demand
will
be
no
more
than
0.02
percent
according
the
modeling
done
for
this
analysis.
This
is
due
to
the
low
estimated
increase
in
textile
output
price
(
0.03
percent).
While
the
textile
industry
is
under
pressure
due
to
competition
from
imported
products,
the
decrease
in
output
demand
resulting
from
this
rule's
requirements
appears
quite
small.
Thus,
EPA
believes
textile
mills
are
unlikely
to
be
forced
out
of
business
as
a
result
of
implementing
this
proposed
rule.

Comment:
Once
commenter
(
333)
requested
that
a
complete,
thorough
and
current
economic
impact
report
be
compiled
to
determine
just
how
many
companies
will
be
shut
down
due
to
the
added
financial
burden
of
complying
with
the
MACT
rules.
Response:
It
is
EPA's
position
that
very
few,
if
any,
companies
will
have
to
close
as
a
result
of
incurring
the
costs
associated
with
the
proposed
rule.
The
economic
impact
analysis
for
this
proposed
rule
shows
that
only
4
percent
of
affected
firms
are
expected
to
have
annual
compliance
costs
of
more
than
3
percent
of
sales,
a
benchmark
often
used
by
EPA
in
its
economic
analyses
as
a
sign
of
potentially
high
impacts
to
affected
entities.
These
estimates
do
not
take
into
account
the
ability
of
entities
to
pass
through
costs
to
their
customers
or
to
obtain
electricity
rate
increases.
The
price
increase
to
affected
products,
including
electricity,
should
mitigate
the
impact
of
this
proposal
upon
affected
producers.

13.5
Economic
Impacts
(
Non­
air
impacts)
Comment:
One
commenter
(
446)
noted
that
if
wet
scrubbers
were
required
for
HCl
control
then
additional
add­
on
water
management
would
be
required
and
facilities
could
not
achieve
"
zero
water
discharge."
The
commenter
added
that
the
use
of
wet
scrubbing
could
also
have
detrimental
impacts
on
the
ability
to
market
ash
byproduct
from
their
industry
and
they
would
no
longer
be
able
to
market
it
as
high­
value
fertilizer.
Response:
The
final
rule
does
not
require
wet
scrubbers
to
be
used
for
Hcl
control.
A
source
may
use
any
method
to
control
emissions
to
meet
the
rule
limits.
Additionally,
we
have
provided
several
compliance
alternatives
that
will
provides
sources
with
the
flexibility
to
comply
with
the
standard
while
maintaining
the
stringency
of
the
standard.
These
alternatives
include
emissions
averaging,
meeting
fuel
content
limits,
and
risk
off
ramps.

Comment:
Commenters
(
349,
377,
523)
expressed
concern
about
the
burden
placed
on
permitting
authorities
for
the
compliance
options
that
involve
monitoring,
modeling
or
risk
screening.
One
commenter
(
377)
believes
that
requiring
every
major
source
to
submit
information
on
every
collocated
gaseous
fuel­
fired
and
process
heater
that
is
exempt
from
emission
limits
is
likely
to
overwhelm
state
and
local
permitting
authorities.
Another
commenter
(
349)
believes
that
since
permitting
authorities
would
need
to
do
the
work,
State
and
local
resources
would
be
directed
toward
presumably
insignificant
sources,
thus
detracting
from
efforts
to
monitor
and
regulate
significant
sources.
One
commenter
(
523)
agreed
that
this
rule
will
impose
substantial
economic
and
administrative
burdens
not
only
on
industry,
but
also
on
the
agencies
charged
with
enforcing
this
rule.
One
commenter
(
440)
stated
that
additional
requirements
on
natural
gas/
propane
fired
164
boilers
will
be
an
administrative
burden
with
no
benefit
to
the
environment.
The
commenter
claimed
nothing
would
be
gained
by
subjecting
small,
gaseous
fired
boilers
to
the
proposed
standard.
The
commenter
stated
a
Title
V
permit
contains
all
applicable
requirements
for
such
sources.
Response:
The
final
rule
has
been
revised
to
allow
units
in
small
subcategories
to
not
to
submit
any
reports
or
keep
records,
and
units
in
the
liquid
and
gaseous
subcategories
to
have
minimal
recordkeeping
and
reporting
requirements.
We
believe
these
changes
will
significantly
reduce
the
burden
on
state
and
local
resources
and
on
sources
subject
to
the
rule.

13.6
Cost
of
Regulation
Comment:
Several
commenters
(
502,
364,
399,
387,
425,
444)
believe
that
EPA
has
grossly
understated
the
capital
and
annualized
cost
of
the
proposed
boilers
NESHAP.
Commenters
(
364,
399,
387)
offered
several
different
approaches
to
estimate
these
costs.
Another
commenter
(
425)
believes
that
the
estimated
costs
for
monitoring,
recordkeeping,
and
reporting
were
unrealistically
low
and
those
costs
should
not
be
hidden.
One
commenter
(
502)
explained
that
the
conversion
necessary
to
comply
with
the
proposed
boiler
NESHAP
would
require
significant
expenses
in
the
range
of
millions
of
dollars
for
each
boiler
and
would
also
impose
process
changes
that
would
require
re­
permitting
and
may
not
even
be
possible.
The
application
of
the
MACT
to
industrial
boilers
and
process
heaters
may
result
in
the
closing
of
the
commenter's
facilities,
which
have
been
in
operation
since
1916.
The
commenter
believes
that
subjecting
sugar
beet
processing
facilities
such
as
the
commenter's
to
the
proposed
MACT
will
provide
little
or
no
environmental
benefit
and
impose
significant
costs
on
farmers.
The
commenter
stated
that
these
farmers
have
no
other
facility
to
process
their
crops,
and
would
pay
an
enormous
cost
as
a
result
of
the
regulations.
Response:
We
disagree
with
the
commenters.
Cost
estimates
were
based
on
algorithms
and
inputs
developed
in
previous
EPA
studies
and
updated
for
this
standard.
They
are
the
best
information
that
EPA
has
to
estimate
cost
impacts.
The
final
rule
incorporates
several
compliance
alternatives
that
will
provides
sources
with
the
flexibility
to
comply
with
the
standard
while
maintaining
the
stringency
of
the
standard.
These
alternatives
include
emissions
averaging,
meeting
fuel
content
limits,
and
risk
off
ramps.
We
have
also
reduced
the
recordkeeping
and
reporting
burden
of
the
rule
since
proposal.
These
changes
since
proposal
will
reduce
the
cost
of
compliance
and
should
resolve
the
commenters
concerns.

Comment:
One
commenter
(
523)
stated
that
as
drafted,
the
proposed
boilers
NESHAP
will
result
in
nominal
reductions
of
HAP,
yet
it
will
impose
extraordinary
costs.
The
commenter
suggested
that
EPA
utilize
the
options
available
under
the
authority
of
the
CAA
to
reduce
the
impact
and
costs
of
this
rulemaking.
The
commenter
stated
some
of
the
available
options
are
to
delist
source
categories
or
not
regulate
de
minimis
emissions
or
de
minimis
sources
of
emissions.
Response:
The
EPA
disagrees
with
the
commenter.
The
final
rule
provides
significant
reduction
in
HAP
emissions.
While
the
total
costs
of
the
rule
are
large,
the
costs
when
allocated
to
a
per
boiler
basis
are
relatively
small.
Additionally,
changes
to
the
rule
since
proposal
have
reduced
total
annualized
costs
by
approximately
100­
200
million
dollars
on
a
national
basis.

Comment:
Several
commenters
(
473,
474,
497,
508,
511,
513,
514,
517,
518,
525,
526,
531,
348)
expressed
concern
that
the
boilers
NESHAP
will
force
units
to
switch
from
solid
fuels
to
alternative
fuels
such
as
natural
gas
or
fuel
oil
in
order
to
meet
compliance.
The
commenters
165
noted
the
increased
cost
from
fuel
switching
and
claimed
that
the
available
renewable
fuel
used
by
furniture
manufacturers
will
have
to
be
sent
to
a
landfill,
further
increasing
the
cost
of
the
boilers
NESHAP.
One
commenter
(
348)
noted
that
it
would
be
economically
impossible
to
switch
to
an
alternative
fuel
source
to
comply
with
the
proposed
NESHAP
and
questioned
whether
EPA
had
considered
the
economic
hardship
this
would
place
on
the
furniture
industry.
One
commenter
(
497)
agreed
that
industrial
boilers
that
burn
wood
will
incur
substantial
costs
to
comply
with
the
proposed
boilers
NESHAP
standard.
The
commenter
(
497)
could
not
identify
a
single
boiler
that
meets
the
proposed
existing
source
limit
for
PM
from
the
furniture
industry.
The
commenter
added
that
none
of
the
units
are
meeting
the
alternative
metals
limit
either.
Response:
We
do
not
believe
that
the
final
rule
will
force
sources
to
switch
fuels.
The
final
rule
incorporates
several
compliance
alternatives
that
will
provides
sources
with
the
flexibility
to
comply
with
the
standard
while
maintaining
the
stringency
of
the
standard.
These
alternatives
include
emissions
averaging,
meeting
fuel
content
limits,
and
risk
off
ramps.
Regarding
units
in
the
furniture
industry
not
meeting
the
promulgated
emission
limits,
we
contend
that
there
was
no
justification
for
separating
boilers
located
in
this
industry
into
their
own
subcategory.
Consequently,
they
were
grouped
into
the
solid
fuel
fired
subcategories
and
are
subject
to
the
same
emission
limits
as
those
units.

Comment:
One
commenter
(
358)
contented
that
EPA
has
not
adequately
addressed
the
impact
to
the
energy
supply
in
light
of
the
President's
Energy
Policy
initiatives.
The
commenter
contended
that
many
small
electrical
generating
utility
boilers
will
be
forced
to
close
and
that
their
closure
would
necessitate
the
procurement
of
new
generation
assets
at
a
much
higher
cost.
Response:
It
is
EPA's
position
that
it
is
unlikely
that
many
small
electrical
generating
utility
boilers
will
be
forced
to
close.
The
small
impacts
on
price
and
output
of
electricity
estimated
in
the
economic
impact
analysis
of
this
proposed
rule
suggest
that
any
closure
of
such
boilers
will
be
very
few,
if
any.
This
analysis
accounts
for
the
pass
through
of
costs
to
electricity
consumers
as
well
as
the
direct
impact
to
electrical
generators.
166
14.0
Interaction
With
Other
Rules
14.1
General
Comment:
One
commenter
(
370)
stated
the
implementation
of
the
proposed
boilers
NESHAP
hydrogen
chloride
emission
limit
and
monitoring
requirements
on
the
units
already
subject
to
more
stringent
inorganic
acid
gas
sulfur
dioxide
control
and
monitoring
program
is
redundant
and
unwarranted.
Response:
Under
the
NESHAP
program,
EPA
is
required
to
develop,
implement,
and
enforce
emission
standards
for
HAPs
from
prescribed
source
categories,
including
industrial/
commercial/
institutional
boilers
and
process
heaters.
We
have
worked
to
minimize
the
burden
of
the
NESHAP
on
the
affected
population,
and
one
method
has
been
through
the
use
of
surrogates.
In
this
NESHAP,
we
use
hydrogen
chloride
as
a
surrogate
for
all
inorganic
HAP
emitted
from
boilers
and
process
heaters.
We
realize
that
some
sources
may
already
have
sulfur
dioxide
emission
limits
through
the
NSPS
or
some
other
program,
but
we
are
unable
to
remove
the
hydrogen
chloride
emission
limit
for
that
reason.
Furthermore,
many
units
subject
to
this
NESHAP
do
not
have
sulfur
dioxide
emission
limits.
If
you
have
a
sulfur
dioxide
emission
limit
that
results
in
hydrogen
chloride
emission
levels
below
the
emission
limits
in
this
NESHAP,
then
you
would
already
be
in
compliance
with
this
NESHAP.
If
you
already
have
a
monitoring
program
for
sulfur
dioxide
and
you
can
demonstrate
that
it
could
be
used
to
demonstrate
continuous
compliance
with
the
hydrogen
chloride
emission
limit,
you
can
petition
the
Administrator
for
an
alternative
monitoring
plan
under
section
§
63.8(
f)
of
subpart
A
of
part
63.

Comment:
Two
commenters
(
360,
410)
suggested
EPA
clarify
that
the
Department
of
Interior
has
jurisdiction
in
the
central
and
western
Gulf
of
Mexico
and
the
rule
does
not
apply
to
sources
located
in
these
areas.
The
commenter
cited
42
U.
S.
C.
section
7627
as
the
authority
by
which
the
Department
of
the
Interior
has
exclusive
authority
to
regulate
air
emissions
in
these
areas.
Response:
We
agree
with
the
commenters
and
clarify
that
the
Department
of
Interior
has
jurisdiction
in
the
central
and
western
Gulf
of
Mexico
and
this
NESHAP
does
not
apply
to
sources
located
in
these
areas.

14.2
Section
129
Comment:
One
commenter
(
451)
stated
the
EPA's
failure
to
promulgate
standards
for
units
combusting
solid
waste
under
section
129
of
the
Clean
Air
Act
is
unlawful
and
its
failure
to
explain
its
decision
is
arbitrary
and
capricious.
The
commenter
(
451)
stated
that
the
proposed
standards
should
not
apply
to
solid
waste
combustion
units
(
as
defined
under
section
129).
Two
commenters
(
451,
512)
argued
that
regulations
for
solid
waste
combustion
units
should
be
promulgated
under
section
129.
The
commenter
(
451)
also
argued
that
if
EPA
is
relying
on
arguments
that
were
advance
in
the
CISWI
rulemaking,
the
agency
is
relying
on
an
unlawful
interpretation
of
the
statute.
The
commenter
discussed
their
interpretation
of
the
statute
including:
(
1)
CAA
requires
EPA
to
establish
standards
for
each
category
of
solid
waste
incineration,
(
2)
Congress
rejected
a
broad
exemption
from
section
129
for
units
that
combust
solid
waste
for
energy
recovery,
(
3)
CAA
defines
solid
waste
broadly
and
encompasses
waste
that
is
burned
for
energy
recovery,
and
(
4)
subsequent
attempts
by
EPA
to
narrow
the
definition
would
be
irrelevant
because
section
129(
g)(
6)
refers
to
the
EPA
definition
of
solid
waste
under
the
Solid
Waste
Disposal
Act
167
(
SWDA)
that
existed
at
the
time
Congress
enacted
section
129
(
i.
e.,
in
1990).
One
commenter
(
451)
said
that
EPA
had
not
conducted
the
notice
and
comment
rulemaking
that
it
committed
to
in
granting
the
petition
for
agency
reconsideration
and
the
voluntary
remand
with
respect
to
the
definitions
of
"
commercial
and
industrial
waste"
and
"
commercial
and
industrial
solid
waste
incineration
unit."
The
commenter
continued
that
if
EPA
concluded
that
such
units
must
be
regulated
under
section
129
after
having
already
decided
to
regulate
them
under
section
112,
EPA
would
have
to
redo
the
rulemaking
completely
to
comply
with
section
129.
One
commenter
(
451)
stated
that
EPA
must
re­
evaluate
the
MACT
floor
development
since
EPA
must
regulate
solid
waste
combustion
units
separately
from
units
that
do
not
combust
any
solid
waste.
The
commenter
added
that
EPA
must
promulgate
standards
for
all
units
that
combust
any
solid
waste,
regardless
of
size
and
promulgate
emission
standards
for
each
of
the
pollutants
enumerated
in
section
129(
a)(
4).
Response:
The
EPA
has
recently
published
a
notice
soliciting
comments
on
the
definition
of
solid
waste
and
solid
waste
combustion
units
as
provided
in
the
commercial
and
industrial
solid
waste
incineration
(
CISWI)
rule
(
69
FR
7390).
Under
the
CISWI
rule
a
material
burned
at
a
commercial
or
industrial
facility
in
a
combustion
unit
with
heat
recovery
is
not
considered
a
commercial
and
industrial
waste,
nor
is
the
combustion
unit
considered
a
commercial
and
industrial
solid
waste
incineration
unit
for
the
purposes
of
the
CISWI
rule.
Such
units
are
covered
by
the
final
boiler
MACT
standards.
A
detailed
discussion
of
EPA's
rationale
for
these
definitions
are
found
in
the
CISWI
rule
notice.
EPA
is
also
required
to
promulgate
standards
for
industrial,
commercial,
and
institutional
boilers
and
process
heaters
by
the
end
of
February
2004.
Changes
made
to
the
CISWI
rule
in
the
promulgated
rule
that
affect
boilers
and
process
heaters
will
be
dealt
with
after
the
promulgation
of
the
boiler
MACT
standards.

14.3
Section
112
Comment:
Two
commenters
(
376,
532)
requested
that
EPA
expedite
promulgation
to
avoid
overlap
with
the
section
112(
j)
"
hammer"
deadline.
One
commenter
(
376)
urged
EPA
to
promulgate
this
MACT
standard
in
a
timely
manner
to
minimize
the
burden
on
affected
sources
that
would
have
to
submit
Part
II
case­
by­
case
MACT
applications
under
112(
j).
Another
commenter
(
532)
stressed
the
importance
of
promulgating
the
standard
on
time
to
prevent
requiring
states
to
implement
the
section
112(
j)
program.
Another
commenter
(
448)
said
that
EPA
may
not
implement
any
section
112(
d)(
4)
applicability
cutoffs
through
any
post­
rulemaking
mechanism.
The
commenter
noted
that
section
112(
j)
of
the
CAA
contains
the
exclusive
mechanism
for
the
individualized
standard­
setting
process.
Response:
We
plan
to
promulgate
this
NESHAP
before
the
112(
j)
"
hammer"
deadline
in
order
to
avoid
overlap.

Comment:
One
commenter
(
410)
requested
that
EPA
incorporate
the
provisions
of
section
112(
n)(
4)
of
the
Clean
Air
Act
in
the
final
boilers
NESHAP
and
add
and
revise
certain
definitions
unless
it
determines
that
boilers
and
process
heaters
at
oil
and
natural
gas
production
facilities
are
not
subject
to
the
this
rule.
The
commenter
added
that
40
CFR
part
63,
subpart
HH
contains
special
provisions
to
determine
potential
to
emit
for
oil
and
gas
production
facilities
and
EPA
should
add
potential
to
emit
definition
that
references
the
40
CFR
part
63,
subpart
HH
potential
to
emit
provisions.
Response:
Under
the
"
Am
I
Subject
to
this
Subpart"
section
of
the
rule,
§
63.7485,
we
clearly
indicate
that
the
major
source
determination
is
different
for
boilers
and
process
heaters
168
located
at
oil
and
natural
gas
production
facilities.
The
final
rule
also
clarifies
that
equipment
that
are
included
as
part
of
the
affected
source
in
another
NESHAP
standard
are
exempt
from
this
rule.
However,
if
a
boiler
or
process
heater
located
at
an
oil
and
natural
gas
production
facility
is
not
specifically
subject
to
another
NESHAP
standard,
then
it
would
be
subject
to
this
NESHAP
if
the
facility
is
a
major
source
according
to
40
CFR
63
Subpart
HH.

14.4
NESHAP
for
Electric
Utility
Steam
Generating
Units
Comment:
One
commenter
(
536)
requested
that
EPA
harmonize
the
compliance
times
between
the
Industrial
Boiler
MACT
and
the
NESHAP
for
coal­
and
oil­
fired
electric
utility
steam
generating
units
(
utility
NESHAP)
and
that
EPA
allow
an
additional
three
years
to
bring
all
units
into
compliance
with
the
industrial
boiler
NESHAP.
The
commenter
contended
that
sources
subject
to
a
less
stringent
standard
would
have
an
advantage.
The
commenter
added
that
under
the
current
compliance
schedule,
the
public
power
sector's
smaller
systems
would
have
to
place
mercury
and
metals
controls
on
their
systems
years
before
their
competitor
larger
utilities.
The
commenter
also
contended
that
public
power
systems
should
have
the
opportunity
for
a
special
variance,
by
class,
or
subcategory
for
an
additional
two
years
for
compliance
if
that
public
power
system
has
planned
to
build
a
new
generating
unit
that
is
cleaner.
Another
commenter
(
376)
recommended
that
EPA
include
a
variance
provision
in
the
final
rule
that
recognizes
multi­
emission
reduction
programs
undertaken
by
utilities
that
would
be
regulated
under
this
NESHAP.
Furthermore,
the
commenter
recommended
that
any
units
less
than
25
megawatts
that
opted
into
the
Clear
Skies
program
(
or
a
similar
program)
would
be
fully
exempt
from
the
provisions
of
this
NESHAP.
Otherwise,
the
commenter
(
376)
recommended
that
fossil
fuel­
fired
units
with
capacities
less
than
25
megawatts
be
given
an
option
to
comply
with
either
the
boiler
and
process
heater
MACT
or
the
utility
NESHAP.
Response:
We
are
unable
to
harmonize
this
NESHAP
with
the
utility
boiler
NESHAP.
The
utility
boiler
NESHAP
is
still
under
development
and
this
NESHAP
has
a
court­
ordered
promulgation
deadline
of
February
28,
2004.
We
are
also
not
providing
any
variances
for
any
multi­
emission
reduction
programs
as
those
types
of
programs
are
separate
from
the
112
NESHAP
program.
If
requirements
for
this
NESHAP
and
any
subsequent
multi­
pollutant
program
are
similar
or
duplicative,
you
need
to
work
with
your
permitting
authority
to
streamline
your
compliance
requirements.

Comment:
One
commenter
(
393)
requested
that
utility
boilers
have
the
option
to
comply
with
the
proposed
boilers
NESHAP
or
with
the
coal­
and­
oil­
fired
utility
NESHAP
since
many
boilers
located
at
electric
generating
plants
will
be
subject
to
the
coal­
and­
oil­
fired
utility
NESHAP.
Requiring
compliance
with
both
NESHAPs
would
be
burdensome,
particularly
if
different
emission
limit
averaging
times,
monitoring
requirements,
recordkeeping
requirements
and
reporting
requirements
are
established
in
each.
Regulatory
inconsistencies
between
the
two
NESHAP
could
prevent
electric
generating
plants
from
choosing
the
most
technically
feasible
and
cost
effective
control
options
to
simultaneously
meet
the
MACT
standards
under
both
NESHAP.

Response:
In
the
"
Are
any
boilers
or
process
heaters
exempt
from
this
subpart?"
section
of
the
final
rule,
we
specifically
exempt
utility
boilers
as
defined
by
112
of
the
Clean
Air
Act
Amendments
and
units
that
are
specifically
subject
to
another
NESHAP.
Therefore,
we
are
not
providing
an
option
for
compliance
with
this
NESHAP
or
the
utility
boiler
NESHAP.
If
your
unit
is
subject
to
another
NESHAP
you
must
comply
with
that
NESHAP,
otherwise,
if
you
meet
the
169
applicability
requirements
of
this
NESHAP
and
are
not
subject
to
another
NESHAP,
you
must
comply
with
this
NESHAP.
170
15.0
EMISSIONS
AVERAGING
Comment:
Many
commenters
(
391,
392,
406,
407,
408,
501,
382,
400,
447,
519,
419,
479,
484,
482,
376,
449,
524,
533,
388,
498,
364,
399,
387,
383,
403,
425,
443,
444)
supported
the
bubbling
compliance
alternative
and
recommended
that
it
should
be
included
in
the
final
rule.
Several
commenters
(
482,
419,
376,
449,
524,
533,
388,
498,
364,
383)
claimed
it
was
cost
effective
and
provided
better
environmental
control
(
376,
449,
524,
533,
388,
498,
364,
383).
Several
commenters
(
479,
449,
524,
533,
388,
498)
cited
precedent
in
prior
rulemakings.
Three
commenters
(
379,
381,
492)
believe
that
an
alternate
compliance
approach
involving
the
"
bubbling"
of
sources
at
a
facility
would
offer
flexibility
and
result
in
equivalent
or
superior
environmental
benefits
at
less
cost.
One
commenter
(
381)
stated
that
this
would
create
environmental
benefit
of
allowing
control
options
that
maximize
energy
efficiency,
thus
reducing
power
demands
and
the
impacts
of
energy
production.
One
commenter
(
417)
supported
the
use
of
bubbling
to
improve
the
cost
effectiveness
of
the
implementation
of
MACT
controls.
The
commenter
(
417)
believes
that
bubbling
allows
facilities
with
multiple
boilers
or
process
heaters
the
flexibility
to
over­
control
units
where
the
most
cost­
effective
reductions
can
be
achieved.
Several
commenters
(
379,
381,
492)
believe
"
bubbling"
should
be
permitted
for
any
pollutant
for
which
a
mass
based
emission
standard
has
been
set
and
(
commenter
379)
cited
40
CFR
part
63,
subpart
MM
 
Pulping
Chemical
Recovery
Combustion
MACT
as
an
example.
Another
commenter
(
484)
cited
other
MACT
standards,
which
allow
affected
sources
to
aggregate
unit
emissions
to
achieve
overall
reductions.
The
commenter
(
357)
stated
that
the
bubble
should
include
a
mass
(
tons/
year)
based
emission
limit
for
boilers
in
the
same
category.
Other
commenters
(
382,
400)
requested
that
EPA
provide
the
maximum
degree
of
flexibility
under
the
bubbling
compliance
alternative.
Specifically,
the
commenters
recommended
that
sources
be
allowed
to
choose
between
a
bubbling
compliance
alternative
that
is
based
on
actual
emissions
or
one
based
on
established
emission
limits.
They
noted
that
an
actual
emission
basis
might
be
used
by
sources
that
have
changing
capacity
factors.
Commenters
(
417,
492,
382,
400,
443)
recommended
that
EPA
adopt
bubbling
that
allows
for
the
voluntary
use
of
cleaner
fuels.
Under
this
approach,
if
a
facility
owner
were
to
voluntarily
modify
one
of
its
several
coal­
fired
boilers
to
burn
natural
gas,
emissions
from
this
modified
boiler
would
remain
within
the
bubble
to
determine
compliance
with
the
MACT
standards
for
the
facility's
existing
solid
fuel
fired
units.
One
commenter
(
379)
stated
that
the
included
sources
should
be
a
broad
grouping
and
should
specifically
include
solid
fuel
fired
units
that
are
converted
to
lower
emission
fuels.
One
commenter
(
443)
noted
that,
for
some
facilities,
fuel
switching
might
be
a
cost­
effective
means
of
achieving
the
targeted
emission
limits.
Several
commenters
(
449,
524,
533,
388,
498)
recommended
a
method
to
calculate
a
bubble
limit
by
summing
the
unit­
specific
alternate
limits
by
the
respective
heat
input
capacities
of
the
units
to
which
they
apply.
The
sum
of
this
should
be
equal
or
less
than
the
sum
of
the
nonbubbling
unit­
specific
standards
in
the
rule
multiplied
by
the
unit's
respective
heat­
input
capacity.
The
commenters
also
suggested
an
alternative
bubbling
provision
and
method
to
apply
to
units
that
may
only
operate
part
of
the
time.
The
commenters
noted
that
40
CFR
part
60,
subpart
MM
restricts
bubbling
to
units
that
operate
more
than
6,300
hours
per
year,
but
requested
that
EPA
lower
that
threshold
to
5,000
hours
per
year.
For
units
that
operate
less
than
5,000
hours
per
year,
the
commenters
explained
that
additional
recordkeeping
and
reporting
would
be
required
and
proposed
a
method
to
account
for
those
types
of
units.
One
commenter
(
393)
urged
EPA
to
allow
sources
using
the
bubbling
compliance
alternative
to
use
a
longer
averaging
time.
171
Specifically,
the
commenter
stated
that
the
EPA
should
allow
annual
averaging,
consistent
with
the
NOx
averaging
plan
requirements
specified
in
the
Acid
Rain
Program
at
40
CFR
Part
76.11
to
ensure
that
short­
term
operational
fluctuations
do
not
create
compliance
issues
at
a
source.
This
would
allow
sources
to
include
both
new
units
and
units
in
different
subcategories
within
the
"
bubble."
One
commenter
(
340)
stated
EPA
failed
to
discuss
averaging
time
for
the
compliance
determination
and
the
type
of
additional
monitoring,
record
keeping,
and
reporting
requirements.
Commenters
(
492,
447,
406,
407,
408,
501)
suggested
that
EPA
adopt
an
expanded
compliance
alternative
that
allows
for
bubbling
across
subcategories
for
new
and
existing
units.
One
commenter
(
400)
provided
an
example
of
a
facility
that
replaces
an
older
boiler
with
a
new,
more
efficient,
boiler
that
burns
a
cleaner
fuel.
The
commenters
requested
that
EPA
allow
new
units
to
participate
in
the
bubble
if
they
replace
higher
emitting
units.
Commenters
(
499,
536,
482,
413)
supported
bubbling
and
suggested
that
the
rule
could
be
made
even
more
flexible
by
allowing
compliance
to
be
demonstrated
across
the
entire
facility,
rather
than
on
a
unit­
by­
unit
basis.
The
commenter
(
499)
stated
that
the
approach
adopted
by
Congress
and
EPA
to
evaluate
the
public
health
and
welfare
concerns
related
to
the
emissions
of
hazardous
air
pollutants
is
to
examine
cumulative
emissions
from
the
entire
facility,
not
just
individual
sources.
One
commenter
(
499)
stated
that
since
the
sources
are
evaluated
for
total
emissions
from
the
facility,
it
is
entirely
consistent
that
the
regulated
community
have
the
flexibility
to
adopt
innovative
"
facilityaveraging
compliance
programs
that
embrace
"
bubbling"
within
the
limits
of
the
definition
of
the
term
"
major
source."
One
commenter
(
413)
added
that
facility­
wide
or
unit­
specific
standards
result
in
the
same
amount
of
HAP
being
emitted
by
the
facility
and
from
a
public
health
perspective
there
is
no
difference
between
the
approaches.
The
commenter
(
413)
concluded
that
a
facility­
wide
limit
provides
greater
operational
flexibility.
Other
commenters
(
449,
524,
533,
388,
498,
400,
447,
519)
417)
stated
that
EPA
should
allow
cross­
category
bubbling,
as
in
the
MACT
standards
for
chemical
recovery
combustion
sources
at
pulp
and
paper
mills
(
40
CFR
part
63,
subpart
MM).
This
would
allow
the
most
flexible,
cost­
effective
method
for
meeting
the
proposed
rule's
standards.
The
commenter
(
417)
also
suggested
that
EPA
should
allow
regional
bubbling
among
municipal
utilities
in
a
common
geographical
area,
even
if
they
do
not
share
a
common
ownership
or
operation.
The
commenter
(
417)
also
suggested
that
EPA
should
adopt
the
bubbling
that
allows
maximum
choice
in
meeting
the
overall
MACT
standard.
The
commenter
believes
that
source
owners
should
be
able
to
choose
among
a
number
of
different
compliance
options
to
achieve
the
environmental
benefit
at
the
lowest
cost.
Including
bubbling
as
an
option
in
the
final
rule
would
help
achieve
that
objective.
Another
commenter
(
536)
supported
bubbling
across
the
community
to
allow
utility
boiler,
industrial
boiler
and
commercial
boiler
operators
to
"
bubble"
in
order
to
reduce
mercury
and
other
metals
in
a
cost­
effective
manner.
However,
one
commenter
(
340)
supported
bubbling
only
if
the
bubble
is
limited
to
a
single
facility
instead
of
multiple
facilities.
One
commenter
(
393)
strongly
supported
offering
a
bubbling
compliance
alternative,
but
questioned
why
this
alternative
should
be
limited
to
existing
boilers
and
process
heaters
within
the
same
subcategory.
Two
commenters
(
512,
529)
do
not
support
the
creation
of
a
bubbling
compliance
option
under
this
NESHAP
because
the
commenter
believes
that
it
would
not
fit
within
the
CAA
mandate
and
is
inconsistent
with
the
purpose
of
section
112.
The
commenter
argued
that
if
a
source
can
reduce
its
HAP
emissions
below
the
required
level
of
the
MACT
standards,
then
further
reduction
should
be
included
in
EPA's
evaluations
of
the
maximum
degree
of
reduction
available
and
be
used
in
a
beyond
the
floor
determination.
The
commenter
noted
that
the
air
toxics
program
has
not
managed
to
prevent
toxic
air
pollution
from
remaining
on
the
most
significant
health
and
environmental
problems
in
the
U.
S.
and
urged
EPA
to
require
compliance
172
on
a
unit
by
unit
basis
and
not
pursue
the
bubbling
compliance
option.
One
commenter
(
529)
pointed
out
that
add­
on
control
devices
cannot
be
used
for
bubbling
emission
units
because
the
operating
limit
for
each
control
device
is
determined
based
on
equipment
tests,
and
fuel
tests
are
applicable
only
to
the
tested
equipment.
Using
bubbling
compliance,
a
facility
could
burn
a
fuel
surpassing
the
chlorine
emission
limit,
but
average
the
results
with
those
of
other
fuels
and
still
show
compliance.
The
commenter
believes
that
compliance
determination
and
public
health
could
be
sacrificed
by
a
bubbling
option.
Response:
The
final
rule
includes
an
emissions
averaging
compliance
alternative
because
we
believe
that
emissions
averaging
represents
an
equivalent,
more
flexible,
and
less
costly
alternative
to
controlling
certain
emission
points
to
MACT
levels.
We
have
concluded
that
a
limited
form
of
averaging
could
be
implemented
and
not
lessen
the
stringency
of
the
standard.
We
agree
with
the
commenters
that
some
type
of
emissions
averaging
would
provide
flexibility
in
compliance,
cost
and
energy
savings
to
owners
and
operators.
We
also
recognize
that
we
must
ensure
that
any
emissions
averaging
option
can
be
implemented
and
enforced,
will
be
clear
to
sources,
and
most
importantly,
will
achieve
no
less
emissions
reductions
than
unit
by
unit
implementation
of
the
MACT
requirements.
The
final
rule
is
not
the
first
NESHAP
to
include
provisions
permitting
emission
averaging.
The
legal
basis
and
rationale
for
emissions
averaging
were
provided
in
the
preamble
to
the
final
Hazardous
Organic
NESHAP
(
59
FR
19425,
April
22,
1994).
In
general,
EPA
has
concluded
that
it
is
permissible
to
establish
within
a
NESHAP
a
unified
compliance
regimen
that
permits
averaging
across
affected
units
subject
to
the
standard
under
certain
conditions.
Averaging
across
affected
units
is
permitted
only
if
it
can
be
demonstrated
that
the
total
quantity
of
any
particular
HAP
that
may
be
emitted
by
that
portion
of
a
contiguous
major
source
that
is
subject
to
the
NESHAP
will
not
be
greater
under
the
averaging
mechanism
than
it
would
be
if
each
individual
affected
unit
complied
separately
with
the
applicable
standard.
Under
this
rigorous
test,
the
practical
outcome
of
averaging
is
equivalent
in
every
respect
to
compliance
by
the
discrete
units,
and
the
statutory
policy
embodied
in
the
MACT
floor
provisions
is,
therefore,
fully
effectuated.
The
EPA
has
generally
imposed
certain
limits
on
the
scope
and
nature
of
emissions
averaging
programs.
These
limits
include:
(
1)
no
averaging
between
different
types
of
pollutants,
(
2)
no
averaging
between
sources
that
are
not
part
of
the
same
major
source,
(
3)
no
averaging
between
sources
within
the
same
major
source
that
are
not
subject
to
the
same
NESHAP,
and
(
4)
no
averaging
between
existing
sources
and
new
sources.
The
final
rule
fully
satisfies
each
of
these
criteria.
Accordingly,
EPA
has
concluded
that
the
averaging
of
emissions
across
affected
units
permitted
by
the
final
rule
is
consistent
with
the
CAA.
In
addition,
EPA
notes
that
the
provision
in
the
final
rule
that
requires
each
facility
that
intends
to
utilize
emission
averaging
to
submit
an
emission
averaging
plan
provides
additional
assurance
that
the
necessary
criteria
will
be
followed.
In
this
emission
averaging
plan,
the
facility
must
include
the
identification
of
(
1)
all
units
in
the
averaging
group,
(
2)
the
control
technology
installed,
(
3)
the
process
parameter
that
will
be
monitored,
(
4)
the
specific
control
technology
or
pollution
prevention
measure
to
be
used,
(
5)
the
test
plan
for
the
measurement
of
particulate
matter
(
or
selected
total
metals),
hydrogen
chloride,
or
mercury
emissions,
and
(
6)
the
operating
parameters
to
be
monitored
for
each
control
device.
Upon
receipt,
the
regulatory
authority
will
not
approve
an
emission
averaging
plan
containing
averaging
between
emissions
of
different
types
of
pollutants
or
between
sources
in
different
subcategories.
The
final
rule
excludes
new
affected
sources
from
the
emissions
averaging
provision.
New
sources
have
historically
been
held
to
a
stricter
standard
than
existing
sources
because
it
is
most
173
cost
effective
to
integrate
state­
of­
the­
art
controls
into
equipment
design
and
to
install
the
technology
during
construction
of
new
sources.
One
reason
we
allow
emissions
averaging
is
to
give
existing
sources
flexibility
to
achieve
compliance
at
diverse
points
with
varying
degrees
of
add­
on
control
already
in
place
in
the
most
cost­
effective
and
technically
reasonable
fashion.
This
concern
does
not
apply
to
new
sources
which
can
be
designed
and
constructed
with
compliance
in
mind.
Only
existing
large
solid
fuel
units,
as
defined
in
the
final
rule,
can
be
included
in
the
emissions
averaging
compliance
alternative.
Of
the
nine
subcategories
established
for
existing
sources,
existing
large
solid
fuel
units
is
the
only
subcategory
for
which
multiple
HAP
emissions
limits
apply.
For
the
existing
small
solid
fuel
subcategory
and
the
six
existing
gaseous
and
liquid
fuel
subcategories,
no
HAP
emissions
limits
are
included
in
the
final
rule
and,
thus,
it
would
not
be
appropriate
to
allow
these
units
to
average
emissions.
As
for
the
existing
limited
use
solid
fuel
subcategory,
since
these
units,
as
defined
in
the
final
rule,
operated
on
a
limited
basis
(
capacity
factor
of
less
than
10
percent)
and
are
subject
only
to
a
less
stringent
PM
emissions
limit
(
as
a
surrogate
for
non­
mercury
metals),
we
believe
it
would
be
inappropriate
to
allow
these
units
to
average
emissions.
As
for
comments
regarding
the
inclusion
of
new
units
in
the
emissions
averaging,
as
stated
previously,
no
averaging
can
be
permitted
between
existing
sources
and
new
sources
since
new
sources
have
historically
been
held
to
a
stricter
standard
than
existing
sources.
With
concern
about
the
equivalency
of
emissions
reductions
from
averaging
and
non­
averaging
in
mind,
the
Administrator
is
also
imposing
under
the
emission
averaging
provision
caps
on
the
current
emissions
from
each
of
the
sources
in
the
averaging
group.
The
emissions
for
each
unit
in
the
averaging
group
would
be
capped
at
the
emission
level
being
achieved
on
the
effective
date
of
the
final
rule.
These
caps
would
ensure
that
emissions
do
not
increase
above
the
emission
levels
that
sources
currently
are
designed,
operated,
and
maintained
to
achieve.
In
the
absence
of
performance
tests,
in
documenting
these
caps,
these
sources
will
documented
the
type,
design,
and
operating
specification
of
control
devices
installed
on
the
effective
date
of
the
final
rule
to
ensure
that
existing
controls
are
not
removed
or
lessen.
By
including
this
provision
in
the
final
rule,
the
Administrator
has
taken
yet
another
step
to
assist
in
ensuring
that
emission
averaging
results
in
environmental
benefits
equivalent
or
better
over
what
would
have
happened
without
emission
averaging.
We
believe
the
inclusion
of
emissions
averaging
into
rules
and
the
decision
on
how
to
design
an
emission
averaging
approach
for
a
particular
source
category
must
be
evaluated
for
each
source
category.
174
16.0
Administrative
Requirements
16.1
Executive
Order
12866
Comment:
One
commenter
(
536)
contended
that
EPA
failed
to
complete
requirements
of
Executive
Order
12866
to
provide
special
consideration
for
government
entities
when
examining
the
impacts
of
compliance
on
equity
concerns.
The
commenter
added
that
EPA
is
directed
to
minimize
those
burdens
that
uniquely
or
significantly
affect
such
government
entities,
whenever
possible.
The
commenter
provided
examples
of
the
impact
of
Unfunded
Mandates
on
a
local
power
system.
Response:
Under
Executive
Order
12866,
EPA
must
determine
whether
a
regulatory
action
is
"
significant"
and
therefore,
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB).
As
discussed
in
the
preamble
to
the
proposed
and
final
rule,
EPA
determined
that
the
boilers
NESHAP
is
a
"
significant"
regulatory
action
and
the
rule
was
reviewed
by
OMB.
We
responded
to
concerns
raised
by
OMB
and
the
final
rule
reflects
those
concerns.
Therefore,
we
disagree
with
the
commenters
and
assert
that
we
completed
the
requirements
of
E.
O.
12866.
For
a
discussion
of
how
EPA
minimized
the
impacts
on
government
entities,
see
sections
16.3
and
16.4
of
this
document.

16.2
Paperwork
Reduction
Act
Comment:
One
commenter
(
371)
claimed
that
small
combustion
units,
curing
ovens,
forming
ovens,
degreaser
tank
heaters,
autoclaves,
and
similar
heaters
would
be
all
be
burdened
with
unnecessary
paperwork,
including
notification,
recordkeeping,
and
reporting
requirements.
Specifically,
these
units
would
be
subject
to
operation
and
maintenance
requirements
and
startup,
shutdown,
and
malfunction
planning
and
reporting.
Most
of
these
units
are
operated
intermittently
and/
or
for
short
periods
of
time
as
needed
and
may
start
up
and
shut
down
several
times
a
day.
The
commenter
estimated
that
tracking
would
require
approximately
1400
labor
hours
the
first
year,
and
approximately
800
hours
per
year
thereafter.
The
commenter
noted
that
under
the
Paperwork
Reduction
Act,
all
federal
agencies
were
expected
to
reduce
their
reporting
burden
by
40
percent
between
1995
and
2000.
The
commenter
claimed
that
during
that
time,
EPA's
reporting
burden
increased.
Response:
The
EPA
expects
that
most
of
the
units
cited
by
the
commenters
are
less
than
10
MMBtu,
and
most
likely,
are
gas­
fired.
In
the
final
rule,
these
units
have
minimal
requirements.
Although
all
units
affected
by
the
final
rule
must
submit
an
initial
notification,
units
that
do
not
have
emission
limits
or
work
practice
standards
are
not
required
to
prepare
an
SSM
plan.
We
documented
the
paperwork
burden
for
all
affected
facilities
in
the
Standard
Form
83­
I
Supporting
Statement
for
ICR
No.
2028.01
(
www.
epa.
gov/
icr).

16.3
Small
Business
Regulatory
Enforcement
Fairness
Act
Comment:
One
commenter
(
536)
contended
that
EPA
failed
to
comply
with
the
Small
Business
Regulatory
Enforcement
Act
of
1996
in
identification
of
small
business
alternatives
recognizing
that
public
power
systems
are
clearly
different
from
the
rest
of
the
boilers
in
the
proposed
rulemaking.
The
commenter
contended
that
EPA
overlooked
municipal
utilities
when
they
certified
that
the
proposed
rule
would
not
have
a
significant
impact
on
a
substantial
number
of
small
entities.
Response:
The
EPA
complied
with
the
analytical
requirements
with
SBREFA.
Our
small
entity
analysis
calculated
impacts
to
small
municipal
utility
boilers
that
will
be
affected
by
the
final
rule.
We
considered
the
Small
Business
Administration
(
SBA)
small
business
size
standard
175
appropriate
to
this
type
of
entity
(
owned
by
a
community
with
50,000
or
less
population)
in
designing
and
preparing
our
analysis.
A
detailed
discussion
of
the
economic
impact
analysis
for
the
proposed
rule
appears
in
the
Boilers
NESHAP.

16.4
Unfunded
Mandates
Reform
Act
Comment:
One
commenter
(
480)
contended
that
EPA
has
failed
to
provide
adequate
outreach
efforts
for
municipal
governments
or
adequate
opportunity
for
their
input
in
the
early
phase
of
the
rulemaking.
The
commenter
asserted
this
failure
violates
the
letter
and
spirit
of
UMRA.
The
commenter
was
unable
to
find
evidence
of
any
pre­
proposal
input
with
the
government
entities
directly
affected
by
the
rule.
The
commenter
also
disagreed
with
EPA's
assertion
that
State
and
local
air
pollution
control
entities
are
not
affected
by
the
proposed
rule.
The
commenter
objected
to
the
limited
and
late
input
for
government
entities
considering
the
time
lines
for
this
and
other
rules,
including
the
ICCR,
being
in
development
for
over
8
years.
Response:
The
EPA
did
provide
outreach
to
municipal
governments
as
part
of
the
Industrial
Combustion
Coordinated
Rulemaking
(
ICCR)
process.
This
outreach,
which
took
place
over
a
period
of
several
years
prior
to
proposal,
was
part
of
a
larger
effort
to
obtain
public
input
for
this
rulemaking
and
two
others
(
stationary
combustion
turbines,
reciprocating
stationary
internal
combustion
engines).
The
outreach
to
municipalities,
among
other
factors,
led
EPA
to
develop
the
subcategory
for
limited
use
units
that
became
part
of
the
final.
Thus,
EPA
disagrees
with
the
commenter's
assertions.

Comment:
Several
commenters
(
373,
378,
398,
421,
422,
429,
435,
469,
470,
471,
472,
481,
506,
509)
emphasized
their
concern
that
EPA
failed
to
identify
and
propose
regulatory
alternatives
for
smaller
businesses
and
those
local
governments
with
extensive
economic
impacts
from
Unfunded
Mandates.
The
commenters
asserted
that
EPA
has
an
obligation
to
recognize
the
unique
circumstances
including
small
business
impacts,
Unfunded
Mandates
impacts
to
local
governments,
and
energy
reliability
concerns
consistent
with
the
president's
Executive
Order
on
energy.
Other
commenters
(
536,
480)
contended
that
EPA
failed
to
meet
its
UMRA
obligations
to
consider
and
adopt
the
least
costly
and
least
burdensome
alternative
for
municipal
utilities.
Response:
The
EPA
proposed
the
MACT
floor
level
of
control
for
this
rule.
We
believe
that
this
is
the
least
stringent,
and
thus,
least
burdensome
alternative
that
is
consistent
with
the
requirements
of
the
Clean
Air
Act.
We
believe
this
is
true
for
small
entities
as
well
as
large
entities
based
on
the
results
of
our
analysis.
The
MACT
floor
level
of
control,
as
discussed
the
preamble
to
the
proposed
and
final
rule,
is
based
on
existing
technology
as
defined
in
the
Clean
Air
Act,
and
not
on
cost
and
economic
impacts.
In
developing
the
rule,
we
considered
our
obligations
under
UMRA
and
by
establishing
the
MACT
floor
level
of
control,
the
final
rule
is
the
least
stringent
alternative
and
the
least
burdensome
to
local
governments
and
municipal
utilities,
while
still
consistent
with
the
requirements
of
the
Clean
Air
Act.
The
EPA
will
submit
an
Unfunded
Mandates
Reform
Act
report
in
order
to
provide
impacts
to
small
governments
and
municipal
utilities
separate
from
the
economic
impact
analysis.
Therefore,
these
impacts
are
more
clear
than
at
proposal.
Note
that
these
impacts
are
estimated
in
the
larger
economic
impact
analysis
currently
in
the
public
docket.
Finally,
we
considered
the
effect
on
energy
reliability
resulting
from
implementation
of
the
boilers
NESHAP
in
the
energy
impact
analysis
 
an
analysis
done
in
compliance
with
Executive
Order
13211
(
Statement
of
Energy
Effects).
We
determined
that
energy
reliability
at
municipal
utilities
would
not
be
adversely
affected
as
part
of
the
energy
impact
analysis,
which
is
a
part
of
the
larger
economic
impact
analysis.
176
Comment:
One
commenter
(
480)
questioned
whether
EPA's
cost/
benefits
analysis
accurately
reflects
the
impact
of
the
proposed
rule
on
municipally
owned
utilities.
The
commenter
disputed
EPA's
estimation
that
only
ten
small
firms
will
have
compliance
costs
over
3
percent
of
their
sales.
The
commenter
provided
cost
and
revenue
projections
showing
their
costs
to
comply
with
the
proposed
rule
are
40
percent
of
its
annual
operating
revenues.
The
commenter
requested
EPA
to
reflect
this
impact
in
the
analysis
for
the
final
rule,
and
to
provide
flexibility
in
the
regulatory
alternative
selected
for
municipal
utilities.
The
commenter
was
unable
to
locate
an
analysis
of
available
federal
funding
in
the
proposed
rule
which
is
required
by
UMRA.
The
commenter
was
also
unable
to
locate
any
support
for
EPA's
conclusion
that
there
will
not
be
any
disproportionate
budgetary
effects
of
the
proposed
rule
on
any
particular
areas
of
the
county,
State,
or
local
governments,
types
of
communities,
or
particular
industry.
The
commenter
contended
that
such
analysis
should
address
the
unique
impacts
of
the
proposed
rule
on
energy
supply
in
communities
with
municipally
owned
utilities.
The
commenter
contended
that
while
the
rule
may
not
affect
national
energy
supply,
it
will
have
a
significant
impact
on
local
energy
supply.
One
commenter
(
534)
stated
that
the
standards
established
by
EPA
for
rules
proposed
under
the
Clean
Air
Act
require
that
cost
be
a
consideration,
particularly
with
regard
to
the
Unfunded
Mandates
Reform
Act
of
1995.
The
commenter
stated
that
the
proposed
rule
would
force
sources
to
comply
with
unfunded
regulatory
mandates
by
retrofitting
existing
systems
within
the
limits
of
known,
reliable
technology.
In
addition,
the
commenter
stated
that
EPA
has
understated
the
cost
to
retrofit
existing
units.
Response:
We
identified
entities
affected
by
the
boilers
NESHAP
based
on
the
data
available
in
the
ICCR
inventory.
We
also
collected
cost
data
as
part
of
the
economic
impact
analysis.
Using
information
from
the
two
data
sets,
we
established
cost
to
revenue
ratios
to
estimate
small
entity
impacts.
Note
that
the
costs
used
in
calculating
these
ratios
are
annual
compliance
costs,
not
capital
compliance
costs.
Both
EPA
and
SBA
guidance
specify
annual
compliance
costs
that
in
developing
such
estimates.
The
commenter
appears
to
use
the
capital
costs
of
compliance
to
prepare
its
comparison
of
costs
to
revenues,
which
leads
to
an
inconsistent
and
incorrect
comparison.
We
responded
to
municipalities'
requests
for
considerations
of
their
circumstances
by
developing
the
subcategory
for
limited
use
units
that
became
part
of
the
proposed
rule.
Thus,
EPA
provided
flexibility
to
municipalities
to
help
them
comply
with
the
rule.
We
expect
the
requirements
for
limited
use
boilers
and
process
heaters
to
mitigate
effects
upon
local
energy
supply
that
may
occur
as
a
result
of
compliance
with
the
rule,
if
such
effects
occur.
The
commenter
supplies
no
data
to
support
its
assertion
of
significant
effects
on
local
energy
supply.
Regarding
cost
to
retrofit
existing
units,
we
calculated
control
costs
using
the
most
up­
todate
information
and
cost
algorithms
available
to
EPA.
Details
of
the
costs
can
be
found
in
the
economic
impacts
analysis
in
the
Boilers
NESHAP
docket.
We
recognize
that
the
costs
for
some
facilities
may
be
higher
and
others
may
be
lower,
but
believe
the
costs
reflect
an
accurate
assessment
of
the
national
impacts
of
the
final
regulation.

Comment:
Commenters
(
480,
536)
contended
that
EPA
failed
to
develop
a
small
government
agency
plan
required
under
section
203
of
UMRA.
One
commenter
(
536)
contended
that
because
EPA
did
not
accurately
assess
the
effects
of
the
rule
on
small
governments,
it
concluded
that
a
Small
Government
Agency
Plan
was
not
necessary.
Another
commenter
(
480)
asserted
that
the
proposed
rule
concluded
without
explanation
that
it
will
not
significantly
or
uniquely
affect
small
governments,
therefore,
a
plan
was
not
developed.
However,
the
commenter
contended
that
this
decision
is
in
contrast
to
EPA
also
deciding
that
there
would
be
a
177
significant
impact
on
public
and
private
entities.
The
commenter
contended
that
the
costs
for
municipal
utilities
alone
may
exceed
$
100
million.
The
commenter
added
that
EPA
failed
to
make
an
adequate
analysis
of
these
costs
and
determine
the
true
impact
of
the
rule
under
section
203.
The
commenter
also
added
that
section
203
was
intended
to
provide
unique
protections
to
small
governments,
which
have
significantly
smaller
budgets
than
most
entities
covered
by
the
rule.
The
cost
for
municipal
utilities
is
significant
and
unique
and
dictate
that
a
small
government
agency
plan
should
have
been
developed.
Commenter
(
536)
added
that
by
neither
preparing
the
plan
or
consulting
with
in­
scope
governments,
EPA
has
stripped
the
affected
communities
of
their
statutory
protections.
Response:
We
disagree
with
the
commenter's
assertion
that
costs
for
municipal
utilities
alone
for
complying
with
this
proposal
may
exceed
$
100
million.
We
believe
the
limited
use
category
established
as
part
of
the
proposed
rule
will
serve
to
reduce
the
potential
impact
to
these
entities.
In
addition,
we
believe
the
analysis
of
impacts
to
small
governments
is
adequate,
and
that
it
fully
complied
with
the
provisions
of
UMRA.
We
will,
however,
prepare
an
Unfunded
Mandates
Reform
Act
analysis
to
clarify
the
expected
impacts
of
the
boilers
NESHAP
upon
municipalities.

16.5
Executive
Order
13211
Comment:
One
commenter
(
536)
contended
that
EPA
failed
to
consider
energy
impacts
to
the
national
grid
and
regional
energy
networks
as
required
under
Executive
Order
13211.
The
commenter
added
that
EPA
did
not
consider
how
the
elimination
of
local
coal­
fired
municipal
generating
units
could
affect
the
availability
of
reactive
power
in
sections
of
the
grid
that
depend
upon
local
generation
to
ensure
the
stable
and
reliable
transmission
of
electricity.
Response:
We
do
not
believe
the
elimination
of
local
coal­
fired
municipal
generating
units
is
likely
to
occur
as
a
result
of
rule
implementation.
The
commenter
does
not
provide
any
evidence
to
indicate
that
this
will
occur
in
its
submittal.
Also,
the
estimated
small
increase
in
electricity
prices
and
reduction
in
electricity
output
is
evidence
that
the
national
power
grid
is
not
likely
to
be
adversely
impacted
by
the
final
boilers
NESHAP.
The
same
conclusion
applies
to
regional
energy
networks.

.
178
17.0
Miscellaneous
17.1
General
Provisions
Comment:
One
commenter
(
529)
requested
adding
the
text
"
You
must
conduct
all
performance
tests
according
to
the
requirements
in
this
subpart
and
§
§
63.7(
c),
(
d),
(
f),
and
(
h)"
to
the
first
sentence
of
§
63.7520(
a).
Response:
We
have
included
the
suggested
text
to
the
final
rule.

Comment:
One
commenter
(
491)
stated
that
EPA
should
indicate
whether
industrial
boilers
and
process
heaters
are
subject
to
the
provisions
of
§
§
63.7(
e)(
4),
63.8(
c)(
5),
and
63.8(
c)(
6).
The
commenter
(
491)
stated
that
in
Table
10
to
subpart
DDDDD,
EPA
indicates
that
§
63.6(
h)(
5)
(
dealing
with
visible
emissions/
opacity
tests)
is
not
applicable
to
industrial
boilers
and
process
heaters.
Therefore,
the
commenter
suggested
that
EPA
indicate
in
Table
10
that
§
63.9(
f),
§
63.9(
h)(
1)
through
(
6),
and
§
63.10(
d)(
3)
are
not
applicable
to
industrial
boilers
and
process
heaters
to
be
consistent
with
its
proposed
determination
that
§
63.6(
h)(
5)
does
not
apply
to
the
boilers
NESHAP.
Response:
We
have
included
the
sections
that
the
commenter
has
requested
clarification
in
the
final
rule
General
Provision
applicability
table,
Table
10.

Comment:
One
commenter
(
491)
stated
that
the
inclusion
of
provision
§
63.10(
b)(
2)(
xiii)
is
inconsistent
with
EPA's
determination
for
§
63.8(
f)(
6)
and
should
not
be
applicable
to
industrial
boilers
and
process
heaters.
Response:
We
agree
with
the
commenter's
assertion
and
have
made
§
63.8(
f)(
6)
not
applicable
to
industrial
boilers
and
process
heaters
Comment:
One
commenter
(
491)
stated
that
§
63.6(
h)(
7)(
i)
and
(
iii)
of
the
General
Provisions
requires
the
owner
or
operator
to
submit
continuous
opacity
monitoring
system
data
with
other
performance
test
data
and
to
reduce
continuous
opacity
monitoring
system
data
to
6­
minute
averages.
The
commenter
stated
that
this
requirement
makes
no
sense
if
a
boiler
is
equipped
with
a
fabric
filter.
The
commenter
stated
that
both
the
initial
and
continuous
compliance
demonstration
requirements
in
the
boilers
NESHAP
for
boilers
equipped
with
fabric
filters
rely
on
the
installation
and
operation
of
a
properly
calibrated
bag
leak
detection
system.
The
commenter
stated
there
are
no
requirements
for
opacity
data
in
either
the
initial
or
continuous
compliance
demonstrations.
The
commenter
stated
that
there
is
no
point
installing
and
operating
a
continuous
opacity
monitoring
system
or
reporting
the
data
with
the
other
performance
test
data
or
reducing
the
data
to
6­
minute
averages
since
the
boilers
NESHAP
makes
no
use
of
this
data.
The
commenter
requested
that
EPA
clarify
that
§
63.6(
h)(
7)(
i)
and
(
iii)
do
not
apply
to
boilers
equipped
with
fabric
filters.
Response:
In
the
final
rule,
we
have
provided
the
option
for
units
that
operate
with
fabric
filter
control
to
use
either
a
bag
leak
detection
system
or
an
opacity
monitoring
system
(
if
they
do
not
have
additional
wet
controls).
Since
this
is
clearly
addressed
in
the
rule,
we
do
not
believe
there
is
any
reason
to
change
the
applicability
of
this
General
Provision
section
to
affected
sources
under
this
NESHAP.
If
they
use
a
COMS
to
demonstrate
compliance
they
will
have
to
follow
this
requirement,
and
if
they
use
a
bag
leak
detection
system,
they
will
not
have
to
follow
this
requirement.
179
Comment:
One
commenter
(
491)
stated
that
Table
10
to
subpart
DDDDD
fails
to
mention
amendments
to
Subpart
A
that
were
promulgated
on
April
5,
2002
at
67
FR
16603.
The
commenter
requested
that
Table
10
be
corrected
to
address
the
amendments.
Response:
Table
10
to
subpart
DDDDD
in
the
final
rule
accounts
for
recent
revisions
to
the
General
Provisions.
Citations
in
the
final
Table
10
refer
to
the
most
current
General
Provisions,
thus
it
is
not
necessary
to
note
which
amendments
are
incorporated.

Comment:
One
commenter
(
491)
stated
that
§
63.7(
a)(
2)
and
§
63.7(
a)(
2)(
ix)
of
the
General
Provisions
provide
180
days
after
the
compliance
date
or
180
days
after
startup
of
the
source
to
demonstrate
compliance
for
existing
or
new
industrial
boilers
or
process
heaters
in
a
number
of
different
situations.
The
commenter
stated
that
EPA
failed
to
address
the
applicability
of
§
63.7(
a)(
2),
as
amended
April
5,
2002,
and
determined
that
the
provisions
of
§
63.7(
a)(
2)
should
not
apply.
One
commenter
(
529)
suggested
that
if
amendments
to
Subpart
A
and
B
(
67
FR
72875)
are
promulgated,
§
63.7505(
ded)
should
be
reworded
to
require
submission
of
the
SSM
plan
in
accordance
with
the
final
amendments
to
Subpart
A
to
Part
63.
Response:
In
the
final
rule,
we
allow
sources
180
days
after
startup
or
the
applicable
compliance
date
to
conduct
a
performance
test
and
believe
that
this
addresses
the
commenter's
concern.
With
regard
to
the
SSM
provisions,
in
the
final
rule
we
still
reference
§
63.6(
e)(
3)
in
the
General
Provisions
for
requirements
for
a
SSM
plan.
Therefore,
the
reference
implies
that
the
most
current
version
of
the
SSM
requirements
in
§
63.6(
e)(
3)
be
followed.

17.2
Editorial
Corrections
Comment:
One
commenter
(
529)
pointed
out
that
although
§
63.7520
(
g)
and
(
h)
refer
to
test
methods
promulgated
in
"
this
part"
(
i.
e.,
part
63),
those
methods
are
actually
promulgated
in
part
60.
One
commenter
(
491)
stated
that
compliance
cannot
be
determined
when
test
methods
are
not
properly
cited.
The
commenter
stated
that
they
believe
EPA
means
for
the
test
methods
specified
in
§
63.7520(
g)
and
(
h)
to
be
the
methods
in
40
CFR
part
60,
appendix
A
and
not
in
appendix
A
in
40
CFR
part
63.
Response:
We
revised
the
final
rule
to
refer
to
part
60,
rather
than
part
63.

Comment:
One
commenter
(
529)
mentioned
that
the
monitoring
requirements
for
liquid
scrubbers
are
missing
from
§
63.7525,
where
they
are
shown
for
other
MACT
floor
controls.
Response:
In
§
63.7525,
we
outline
the
monitoring
requirements
by
the
type
of
monitoring
device
(
e.
g.,
pressure,
flow,
pH,
etc.)
and
not
by
the
type
of
emission
control
device.
Since
the
monitoring
requirements
for
a
liquid
scrubber
are
flow,
pressure,
and
pH
(
for
hydrogen
chloride),
the
monitoring
requirements
for
liquid
scrubbers
are
addressed.

Comment:
One
commenter
(
491)
suggested
that
§
63.7540(
a)
should
be
clarified
as
follows:
§
63.7540(
a)
You
must
demonstrate
continuous
compliance
with
each
emission
limit,
operating
limit,
and
work
practice
standard
in
Tables
1
through
3
to
this
subpart
that
applies
to
you
by
following
the
methods
specified
in
...
Response:
We
have
clarified
the
language
in
§
63.7540(
a)
to
be
more
specific
and
believe
that
this
will
address
the
commenter's
concern.
180
Comment:
One
commenter
(
529)
requested
correction
of
the
applicability
of
§
§
63.6(
h)(
4)
through
(
6),
which
are
referred
to
in
§
63.7545(
a),
but
shown
as
not
applicable
in
Table
10
to
subpart
DDDDD.
Response:
We
have
removed
the
reference
to
Section
§
63.6(
h)(
4)
through
(
5)
in
§
63.7545(
a)
as
it
regarding
notification
of
opacity
or
visual
emission
observations.
Since
this
rule
relies
on
continuous
compliance
(
e.
g.,
COMS,
fabric
filter
leak
detection
systems,
etc),
this
notification
is
not
applicable.
We
have
also
noted
this
in
Table
10.

Comment:
One
commenter
(
529)
pointed
out
that
reporting
requirements
are
scattered
throughout
the
proposed
boilers
NESHAP.
The
commenter
asked
that
the
requirements
for
test
reports
and
SSM
immediate
reports
be
added
to
both
§
63.7550
and
Table
9
of
subpart
DDDDD.
Response:
In
the
final
rule,
§
63.7550
contains
reporting
requirements
and
Table
9
summarized
the
reporting
requirements,
including
the
SSM
immediate
reports
required
in
by
§
63.10(
d)(
5).

Comment:
One
commenter
(
491)
stated
that
the
terms
used
in
§
§
63.7570(
c)(
3)
through
(
c)(
5)
should
be
consistent
with
the
usage
in
the
referenced
citations.
The
commenter
stated
that
§
63.90
defines
"
major
change
to
test
method,"
"
major
change
to
monitoring,"
"
major
change
to
record
keeping/
reporting,"
and
§
§
63.7(
f),
63.8(
f),
and
63.10(
f)
refer,
respectively,
the
use
of
an
"
alternative
test
method,"
to
"
use
of
an
alternative
monitoring
method,"
and
to
waiver
of
record
keeping
or
reporting
requirements.
The
commenter
requested
that
EPA
clarify
the
rule
and
provided
language
to
address
their
issue.
Response:
The
final
rule
incorporates
the
consistent
terminology
as
found
in
§
63.90.

Comment:
One
commenter
(
369)
suggested
that
Tables
1
through
7
to
subpart
DDDDD
be
revised
to
either
clarify
which
requirements
are
applicable
to
affected
sources
that
have
control
combinations
that
fall
into
more
than
one
scenario
described
in
the
column
entitled
"
that
is
controlled
with..."
or
redefine
the
control
combination
scenarios
so
that
they
are
mutually
exclusive.
The
commenter
also
suggested
that
EPA
make
sure
that
applicable
requirements
broaden
combination
scenarios
(
e.
g.,
other
than
wet
or
dry
scrubbers,
fabric
filters
alone
or
in
combination
with...)
are
comprehensive.
Response:
Since
proposal,
we
have
significantly
revised
the
Tables
for
subpart
DDDDD
to
be
more
user­
friendly
and
to
address
control
devices
on
a
singular
basis,
instead
of
providing
a
few
combination
scenarios.
We
believe
that
these
changes
address
the
commenter's
concern.

Comment:
One
commenter
(
369)
suggested
that
Tables
1
through
9
to
subpart
DDDDD
be
revised
to
clearly
show
which
units
are
not
subject
to
the
requirements
in
that
table.
The
commenter
remarked
that
the
tables
are
not
designed
to
allow
someone
to
quickly
determine
all
of
the
requirements
that
apply
to
a
specific
boiler
or
process
heater.
One
commenter
(
369)
suggested
that
40
CFR
63
subpart
DDDDD
Table
4A,
and
Table
4E,
column
1,
rows
1
and
2
be
revised
to
clarify
that
existing
boilers
and
process
heaters
in
the
small
solid
fuel
subcategory
are
not
subject
to
the
performance
testing
requirements.
The
commenter
proposed
revised
language
changes.
Response:
The
final
boilers
NESHAP
clarifies
that
some
boilers
and
process
heaters
have
fewer
requirements
than
others.
We
added
a
new
question
heading
at
§
63.7506
to
identify
units
that
are
subject
to
the
emission
limits
and
applicable
work
practice,
but
do
not
demonstrate
181
compliance
through
performance
testing.

Comment:
One
commenter
(
369)
requested
that
Table
1
to
subpart
DDDDD
be
revised
to
include
the
applicable
carbon
monoxide
emission
limits,
which
are
described
later
in
Table
3
to
subpart
DDDDD.
Response:
At
proposal,
Table
1
was
intended
to
only
list
emission
limits
for
regulated
pollutants.
Table
3
was
intended
to
list
work
practice
standards.
The
CO
emission
standards
are
work
practice
standards
and
not
emission
limits.
We
recognized
that
many
commenters
were
confused
about
the
requirements
for
CO,
particularly
monitoring
and
exceedance
requirements.
The
CO
requirements
of
the
final
rule
have
been
clarified.
See
§
63.7510
regarding
work
practices
for
further
discussions
of
the
CO
work
practice.
For
the
final
rule,
EPA
simplified
the
tables
and
Table
1
contains
both
the
work
practice
standards
and
emission
limits.

Comment:
One
commenter
(
491)
suggested
the
following
table
changes:
The
work
practice
standard
in
both
rows
of
the
second
column
of
Table
3
should
be
changed
as
follows,
"***
the
procedures
in
§
63.7525(
a)
and
maintain
carbon
monoxide
emissions
***".
In
Table
9,
the
requirements
"
Semiannually
according
to
the
requirements
in
§
63.7550(
b)"
should
be
repeated
for
1.
b,
1.
c,
and
1.
d
instead
of
stating
"
See
item
1.
a
of
this
table."
Response:
The
final
rule
combines
the
emission
limits
and
work
practice
standards
in
Table
1
of
subpart
DDDDD.
As
a
result,
initial
and
continuous
compliance
appear
in
sections
§
§
63.7510
and
63.7540,
respectively.
In
addition,
we
revised
Table
9
to
clearly
require
items
1.
b,
1.
c,
and
1.
d
semiannually
according
to
the
requirements
in
§
63.7550(
b).

Comment:
One
commenter
(
529)
asked
that
the
emission
standards
be
cited
in
both
metric
and
English
units
in
Table
1
of
Subpart
DDDDD.
Response:
We
have
not
cited
emission
standards
in
both
metric
and
English
units.
We
have
retained
the
English
unit
approach
in
the
final
rule
to
avoid
duplication
of
emission
limits.

Comment:
One
commenter
(
529)
pointed
out
that
the
equations
used
to
calculate
fuel
input
operating
limits
are
inconsistent
with
the
standards
in
Table
1.
The
operating
limit
is
calculated
in
lb/
BTU
and
the
emission
limits
are
in
lb/
MMBtu.
Response:
In
the
final
rule,
we
have
modified
the
equations
for
calculating
fuel
input
operating
limits
to
be
consistent
with
the
emission
limits
in
Table
1,
in
units
of
lb/
MMBtu.

Comment:
The
commenter
(
492)
recommended
the
following
editorial
revisions:
In
Table
1
of
the
preamble,
Emission
Limits
and
Work
Practice
Standards
for
Boilers
and
Process
Heaters,
on
page
1666,
an
error
exists
on
control
of
liquid
fuel,
small
units.
The
0.0009
limit
should
apply
to
Hydrogen
Chloride
and
not
Total
Selected
metals.
Response:
We
agree
with
the
commenter
and
made
the
correction
in
the
preamble
to
the
final
rule.

Comment:
One
commenter
(
369)
requested
that
column
2
of
proposed
40
CFR
63
subpart
DDDDD
Tables
4.
A
through
4.
E,
5.
B
and
5.
D
be
revised
by
changing
"
Any
type
of
device"
to
"
No
control
or
any
type
of
control
device"
where
the
corresponding
requirements
should
also
apply
to
uncontrolled
affected
sources.
Response:
We
have
significantly
revised
the
tables
to
subpart
DDDDD
since
proposal
to
provide
more
clarification
of
the
compliance
responsibilities
for
source
with
no
control
or
control
182
devices
not
listed
in
the
tables.
We
believe
that
the
promulgated
changes
should
address
the
commenter's
concern.

Comment:
One
commenter
(
369)
suggested
that
row
1
column
1
of
40
CFR
63
subpart
DDDDD
Tables
4.
A,
5.
A,
and
7.
A
be
revised
if
solid
fuel
affected
sources
that
choose
to
comply
with
the
total
selected
metals
limit
instead
of
the
particulate
matter
limit
are
not
supposed
to
be
subject
to
the
initial
PM
performance
test,
the
initial
PM
compliance
requirements
for
PM,
or
the
continuous
monitoring
requirements
that
vary
depending
on
the
control
device
used
(
opacity,
pH,
etc.),
respectively.
Response:
Since
proposal,
we
have
significantly
modified
the
tables
for
subpart
DDDDD
and
believe
that
the
promulgated
changes
will
address
the
commenter's
concern.

Comment:
One
commenter
(
369)
requested
that
row
3
column
1
of
proposed
40
CFR
63
subpart
DDDDD
Table
4.
E
be
revised
if
solid
fuel
affected
sources
rated
greater
than
250
MMBtu/
hr
heat
input
that
choose
to
comply
with
the
total
selected
metals
limit
instead
of
the
particular
matter
limit
are
not
supposed
to
be
subject
to
both
the
initial
total
selected
metal
performance
test
using
Method
29
(
required
by
proposed
Table
4.
A,
row
2
and
results
include
mercury)
and
the
initial
mercury
performance
test
using
Draft
ASTM
Z65907.
Response:
In
the
final
rule,
we
do
not
require
units
larger
than
250
MMBtu/
hr
to
use
the
ASTM
method
for
mercury
performance
tests.
Since
all
sources
have
the
choice
of
using
either
EPA
Method
29
or
the
ASTM
method,
this
addresses
the
commenter's
concern.

Comment:
One
commenter
(
362)
found
data
in
Tables
5.
A
and
5.
E
(
initial
compliance)
and
Table
7.
A
(
continuous
compliance)
to
be
inconsistent.
The
commenter
noted
the
EPA
did
not
give
an
option
allowing
facilities
to
demonstrate
continuous
compliance
with
the
emission
limitations
mercury
emissions
without
controls
or
an
add­
on
control
for
which
a
facility
does
not
wish
to
take
credit
for
reductions.
If
the
initial
compliance
is
demonstrated
on
the
basis
of
mercury
emissions
and
calculation
by
Equation
2
instead
of
performance
stack
test,
then
there
is
no
"
performance
test".
The
commenter
recommended
the
EPA
change
the
wording
in
table
7.
A,
item
3
and
6,
and
give
the
option
of
demonstrating
compliance
on
the
basis
of
mercury
emissions
and
calculation
by
Equation
2,
then
same
manner
as
demonstrating
initial
compliance
in
Table
5.
A
items
3
and
6.
Response:
The
final
rule
was
revised
to
clearly
indicate
that
source
can
demonstrate
compliance
through
fuel
sampling
or
performance
testing.
Furthermore,
the
significant
revisions
to
the
tables
in
final
rule
should
provide
greater
clarity
with
regard
to
compliance
requirements.

Comment:
One
commenter
(
413)
noted
there
were
several
errors
in
Table
5.
A.
The
commenter
contended
that
the
values
presented
in
the
third
and
fourth
pages
of
the
table
appear
to
be
emission
limits
for
the
limited
use
solid
fuel
category
instead
of
the
large
solid
fuel
category.
Additionally,
the
commenter
stated
that
the
PM
standard
on
68
FR
1736­
37
is
0.21
per
MMBtu
heat
input
whereas
the
PM
standard
in
Table
1
for
limited
use
solid
boilers
is
0.2.
The
commenter
also
questioned
in
Table
5.
A,
page
1736,
whether
the
(
e)­(
h)
controls
really
supposed
to
be
(
a)­
(
d)
for
limited
use
boilers.
Response:
We
revised
the
tables
of
the
final
boilers
NESHAP
to
simplify
the
presentation
of
requirements.
We
expect
the
new
table
format
will
eliminate
the
type
of
errors
pointed
out
by
the
commenter.
183
Comment:
One
commenter
noted
several
typographical
errors
in
Table
10
of
subpart
DDDDD.
Under
the
entry
for
§
63.10(
a),
"
vx"
be
"
vs."
In
Table
10,
under
the
entry
for
§
§
63.7(
a)(
2)(
i)­(
vii),
these
citations
are
reserved
sections.
In
Table
10,
entry
for
§
63.8(
c)(
1)(
ii),
the
citation
pertains
to
spare
parts
rather
than
reporting
requirements
SSM
when
action
is
not
described
in
the
SSM
plan.
In
Table
10,
entry
for
§
63.8(
c)(
1)(
iii),
the
citation
pertains
to
SSM
plans
for
CEMS
rather
than
compliance
with
operation
maintenance
requirements.
In
Table
10,
entry
for
§
63.10(
c)(
1)­(
6),
(
9)­(
15),
the
citations
for
(
c)(
2),
(
3),
(
4)
and
(
9)
are
reserved
sections.
Response:
We
revised
Table
10
of
subpart
DDDDD
in
the
final
boilers
NESHAP
to
correct
the
discrepancies
pointed
out
by
the
commenter.

Comment:
One
commenter
(
491)
suggested
that
in
Table
10
of
subpart
DDDDD,
the
fourth
column
heading
"
Explanation"
be
changed
to
"
Applicable
to
Subpart
DDDDD."
Another
commenter
(
434)
stated
that
Table
10
of
subpart
DDDDD
is
confusing.
The
commenter
suggested
that
the
heading
"
Explanation"
be
changed
to
"
Applicable"
so
that
the
Yes/
No
answers
in
that
column
make
more
sense.
Response:
In
the
final
rule
we
have
changed
the
fourth
column
heading
to
"
Applicable"
to
avoid
any
confusion.

Comment:
One
commenter
(
347)
believes
the
presentation
of
the
rule
is
unclear
and
recommends
that
the
requirements
of
the
proposed
boiler
MACT
be
set
forth
in
the
preamble,
not
in
the
rule
text.
Response:
Since
proposal,
we
have
made
many
revisions
to
provide
greater
clarification
of
the
rule
requirements.
As
the
preamble
is
not
codified
in
the
Code
of
Federal
Regulations
(
CFR),
we
cannot
put
the
requirements
of
the
NESHAP
in
the
preamble,
they
must
remain
in
the
regulation
itself.

Comment:
One
commenter
(
491)
stated
that
deleting
the
comma
after
"
including
any
operating
limit"
in
the
last
sentence
helps
clarify
the
requirement
in
§
63.7550(
f).
Response:
We
revised
§
63.7550(
f)
to
clarify
that
if
the
compliance
report
includes
all
required
information
concerning
deviations
from
any
emission
limit,
operating
limit,
or
work
practice
requirement
in
this
subpart,
submission
of
the
compliance
report
satisfies
any
obligation
to
report
the
same
deviations
in
the
semiannual
monitoring
report.
However,
submission
of
a
compliance
report
does
not
otherwise
affect
any
obligation
the
affected
source
may
have
to
report
deviations
from
permit
requirements
to
the
permit
authority.

Comment:
One
commenter
(
491)
requested
that
EPA
explain
and
clarify
what
it
means
by
the
phrase
"
and
the
supplier(
s)
and
original
source
location(
s)"
in
§
63.7555(
d)(
1).
Response:
In
the
final
rule,
we
address
fuel
monitoring
and
sampling
by
fuel
type.
Therefore,
discussion
of
fuel
supplier
or
location
has
been
removed.

Comment:
One
commenter
(
352)
noted
that
following
standards
referenced
have
been
updated:
D388­
77
is
now
D
388­
99;
D396­
78
is
now
D
396­
02a;
D1835­
82
is
now
D
1835­
98.
Also,
z65907
is
now
ASTM
standard
D
6784­
02.
The
commenter
requested
that
EPA
reference
the
latest
version
of
these
methods
in
the
rule
along
with
the
rationale
for
the
changes.
Response:
We
have
worked
to
make
sure
all
ASTM
methods
have
been
updated
in
the
final
rule
and
believe
that
the
most
current
methods
are
the
proper
ones
to
use.
However,
as
those
methods
will
continue
to
be
updated
after
this
rule
has
been
promulgated,
you
must
receive
184
permission
from
your
permitting
authority
to
use
any
updated
methods
because
we
are
not
going
to
provide
technical
corrections
to
this
NESHAP
each
time
an
ASTM
method
is
updated.

17.3
Miscellaneous
Comment:
One
commenter
(
424)
requested
that
EPA
provide
emission
information
on
hexavalent
chromium
emissions
from
boilers
if
it
is
available.
Response:
We
do
not
present
hexavalent
chromium
emissions
from
boilers
under
this
NESHAP
as
we
do
not
believe
that
we
have
sufficient
data
to
provide
an
accurate
estimate
of
those
emissions.
185
RISK­
BASED
COMPLIANCE
PROVISIONS
18.1
PROGRAM
ISSUES:
GENERAL
COMMENTS
18.1.1
Health­
based
approaches
Comment:
Commenter
IV­
D­
75
supported
EPA's
incorporation
of
risk­
based
concepts
into
the
MACT
Program.
The
commenter
believes
that
providing
risk­
based
applicability
criteria
for
sources
whose
HAP
emissions
do
not
pose
a
significant
risk
is
appropriate.
The
commenter
added
that
risk­
based
alternatives
will
function
as
indirect
emission
limits
that
must
be
maintained
by
the
facilities
to
assure
that
the
criteria
are
met,
and,
thus,
such
alternatives
for
low­
risk
facilities
are
supportable
by
EPA's
authority
under
§
§
112(
d)(
4)
and
112(
c)(
9)
of
the
CAA
and
EPA's
inherent
de
minimis
authority.
Commenter
IV­
D­
75
stated
that
low­
emitting
facilities
within
the
Surface
Coating
of
Automobiles
and
Light­
Duty
Trucks
(
SCALDT)
source
category
are
particularly
suited
to
subcategorization
and
delisting
on
the
basis
of
risk.
Many
of
the
sources
are
well­
controlled
and
can
easily
be
distinguished
from
other
facilities.
Commenter
IV­
D­
34
believes
that
there
is
clear
legal
authority
in
the
CAA
to
construct
NESHAP
based
on
risk,
and
such
an
approach
is
very
appropriate
in
the
case
of
the
Industrial
Boiler
MACT.
The
commenter
also
noted
that
the
regulatory
framework
exists
within
their
State
to
implement
such
an
approach.
Commenters
IV­
D­
166
and
IV­
D­
83
supported
the
use
of
risk­
based
applicability
criteria
to
remove
sources
that
do
not
pose
significant
risk.
Commenter
IV­
D­
78
believes
that
there
are
ways
to
structure
the
rule
to
focus
on
facilities
that
pose
significant
risks
and
avoid
imposition
of
high
costs
on
facilities
that
pose
little
risk.
An
appropriate
approach
would
be
to
allow
individual
facilities
to
conduct
a
risk
assessment
to
show
that
it
poses
insignificant
risks
to
the
public.
Commenter
IV­
D­
19
supported
the
concept
that
sources
which
present
no
or
only
minimal
risk
should
not
be
burdened
with
the
requirements
of
MACT.
The
commenter
stated
that
EPA
should
structure
the
source
category
applicabilities
such
that
a
source
with
minimal
or
no
risk
may
be
excluded
from
regulation
under
a
MACT
standard.
However,
commenter
IV­
D­
19
does
not
believe
that
it
is
appropriate
for
State
and
local
programs
to
determine
which
facilities
should
be
exempted
from
MACT.
Commenter
IV­
D­
146
believes
that
the
MACT
standards
should
provide
for
operational
flexibility
and
minimize
costs
while
assuring
achievement
of
specified
emissions
reductions.
The
commenter
supported
the
use
of
risk­
based
compliance
options
as
have
been
proposed
in
other
MACT
standards.
The
commenter
thought
it
would
be
appropriate
in
some
circumstances
to
consider
risk
in
setting
MACT
standards.
Commenter
IV­
D­
175
believes
that
a
risk­
based
approach
to
MACT
applicability
constitutes
sound
public
policy.
The
commenter
supported
EPA's
recognition
that
regulatory
priority
should
be
given
to
sources
that
have
been
demonstrated,
by
the
weight
of
credible
scientific
evidence,
to
pose
the
greatest
threat
to
human
health
and
the
environment.
The
commenter
noted
that
EPA
has
embraced
risk­
based
decision
making
in
other
regulatory
contexts,
and
encourages
EPA
to
extend
such
an
approach
to
the
MACT
promulgation
process.
The
commenter
believes
that
risk­
based
decision
making
can
be
as
protective
of
human
health
and
the
environment
as
other
regulatory
approaches,
and
offers
the
additional
benefits
of
costeffectiveness
and
administrative
efficiency.
186
Commenter
IV­
D­
130
agreed
with
EPA
that
under
certain
circumstances
it
makes
more
environmental
and
economic
sense
to
proceed
with
a
risk
evaluation
prior
to
the
installation
of
costly
controls.
The
commenter
believes
in
achieving
the
goal
of
maximum
environmental
benefit
in
a
sensible
and
logical
manner
which
may
mean
something
other
than
command
and
control.
Risk­
based
exemptions
would
give
individual
facilities
another
option
to
demonstrate
the
actual
risk,
as
opposed
to
assumed
risk.
Commenter
IV­
D­
72
stated
that
§
112
explicitly
provides
for
a
risk­
based
approach
to
regulating
HAP.
Failure
to
implement
a
risk­
based
approach
would
require
facilities
to
expend
tremendous
resources
to
control
emissions
that
"
may
not
result
in
exposures
which
could
pose
an
excess
individual
lifetime
cancer
risk
greater
than
one
in
one
million
or
which
exceed
thresholds
determined
to
provide
an
ample
margin
of
safety
for
protecting
public
health
and
the
environment
from
the
effects
of
hazardous
air
pollutants."
From
a
public
policy
perspective,
a
health
riskbased
approach
to
implementing
§
112
is
appropriate
so
as
to
focus
the
EPA's
limited
resources
on
industries
and
emissions
that
pose
unacceptable
risks
to
public
health.
Commenter
IV­
D­
72
stated
that
the
level
of
discretion
provided
to
EPA
by
Congress
under
the
CAA
is
consistent
with
allowing
EPA
to
utilize
any
approach
necessary
to
arrive
at
useful,
meaningful,
and
productive
regulations
which
are
protective
of
public
health.
Nothing
in
the
CAA
requires
EPA
to
regulate
sources
which
are
not
posing
an
unacceptable
risk
to
the
public
health
or
environment.
Commenter
IV­
D­
72
added
that
gas­
fired
boilers
and
process
heaters
present
a
perfect
opportunity
for
EPA
to
exercise
its
authority
under
either
§
112(
d)(
4)
to
utilize
a
risk­
based
standard
or
§
112(
c)(
9)(
B)
to
delist
gas­
fired
units.
The
two
(
out
of
six)
subcategories
of
gasfired
units
for
which
EPA
proposed
emissions
limits
emit
such
a
low
level
of
HAP
that
EPA
had
to
use
CO
to
approximate
the
extent
to
which
organic
HAP
might
be
emitted.
In
addition,
most
of
the
existing
sources
already
are
in
compliance
with
the
CO
limit.
Commenter
IV­
D­
61
agreed
with
and
adopted
the
rationales
of
the
referenced
AF&
PA
white
papers,
and
believes
that
EPA
has
the
legal
and
statutory
authority
to
implement
a
riskbased
approach
in
the
final
rule
pursuant
to
CAA
§
112(
d)(
4)
and
the
EPA's
inherent
de
minimis
authority.
Commenters
IV­
D­
104,
IV­
D­
26,
and
IV­
D­
150
supported
the
adoption
of
a
risk­
based
option
for
complying
with,
or
being
exempt
from,
the
Boiler
MACT
rule
and
believe
that
such
an
approach
is
within
EPA's
established
authority
under
CAA
§
112.
The
commenters
believe
that
such
an
option
would
allow
a
more
rational,
cost­
effective,
environmentally
sound
rule
that
complies
with
the
health­
protective
purposes
of
the
CAA.
Commenters
IV­
D­
73
and
IV­
D­
166
stated
that
allowing
the
use
of
the
§
112(
d)(
4)
provision
within
the
source
category
could
provide
substantial
cost­
effectiveness
benefits
while,
at
the
same
time,
providing
protection
to
human
health
and
the
environment.
However,
the
commenters
believe
that
EPA
must
clarify
in
the
final
rule
exactly
how
the
provisions
will
be
implemented.
Commenter
IV­
D­
37
supported
the
use
of
CAA
§
112(
d)(
4).
The
commenter
believes
§
112(
d)(
4)
may
be
used
to
relieve
the
regulatory
burden
on
small
utility
boilers
and
other
specific
subcategories
of
potentially
affected
sources.
Commenters
IV­
D­
166
and
IV­
D­
73
stated
that
based
on
the
size
and
complexity
of
the
boiler
and
process
heater
source
category,
it
is
doubtful
that
EPA
could
effectively
use
the
riskbased
provisions
of
§
112(
c)(
9)
to
delist
a
subset
of
the
source
category.
Commenter
IV­
D­
184
supported
EPA
using
the
risk­
based
provisions
of
§
§
112(
d)(
4)
and
112(
c)(
9)
to
target
the
regulatory
process
so
that
facilities
focus
on
achieving
meaningful
187
reductions
in
emissions
from
air
toxics
in
a
cost­
effective
manner.
The
commenter
recommended
that
EPA
use
prioritization
techniques,
applicability
criteria,
and
risk
based
standards
to
focus
regulations
on
sources
that
pose
significant
risks.
Sections
112(
d)(
4)
and
112(
c)(
9)
of
the
CAA
embody
this
principle.
The
commenter
believes
that
focusing
on
achieving
reductions
from
sources
of
unacceptable
risk
is
consistent
with
Congressional
intent
and
makes
good
sense
from
a
science
policy
standpoint.
Commenter
IV­
D­
35
believes
the
final
rule
should
offer
sources
the
option
of
complying
with
a
risk
alternative
such
that
the
requirements
of
the
rule
do
not
apply
to
any
source
that
demonstrates
(
based
on
a
tiered
approach
that
includes
EPA­
approved
modeling
of
the
affected
source's
emissions)
that
the
anticipated
HAP
exposures
do
not
exceed
the
specified
hazard
index
(
HI)
limit.
The
commenter
agreed
that
§
112
of
the
CAA
provides
for
a
threshold
pollutant
cutoff
whereby
sources
emitting
less
than
the
threshold,
with
an
ample
safety
margin,
to
demonstrate
compliance
by
showing
HAP
emissions
are
below
the
threshold
pollutant
limit.
The
commenter
stated
that
this
CAA
provision
should
be
implemented
in
the
final
rule.
Commenter
IV­
D­
35
provided
an
example
where
a
solid
fuel
source
may
have
pollution
control
equipment
that
greatly
reduces
mercury
emissions
but
is
still
not
consistently
below
the
0.000007
lbs/
MMBtu
proposed
limit.
In
the
example,
the
source
would
be
required
to
install,
operate,
and
maintain
additional
pollution
control
equipment
because
mercury
emissions
exceed
the
proposed
limit
by
0.375
pounds
per
year
(
lbs/
year)
or
0.001
pounds
per
day
(
lb/
day).
The
commenter
asserted
that
the
threshold
pollutant
cutoff
limit
should
apply
to
all
pollutants
in
the
MACT
rule.
Commenter
IV­
D­
35
stated
that
as
discussed
in
the
proposal,
low­
risk
facilities
should
be
delisted
from
the
final
rule
if
they
are
in
the
appropriate
subcategory.
The
commenter
believes
that
establishment
of
low­
risk
subcategories
is
still
protective
of
human
health
while
minimizing
impacts
on
the
regulated
community.
Commenter
IV­
D­
35
stated
that
the
compliance
options
EPA
offers
in
the
final
rule
do
not
have
to
be
mutually
exclusive.
Compliance
options
should
include
a
bubbling
compliance
alternative
emission
limit,
the
establishment
of
pollutant
thresholds,
and
delisting.
The
commenter
noted
that
multiple
compliance
options
offer
sources
greater
flexibility
while
still
achieving
the
final
goal.
Commenter
IV­
D­
108
supported
approaches
to
regulation
that
focus
on
exposures
posing
significant
risks
to
human
health
and
the
environment,
and
removing
low
risk
facilities
from
regulation.
Specifically,
the
commenter
supported
the
hybrid
approach
that
is
described
in
the
Proposal
 
a
combination
of
applicability
thresholds
and
subcategorization
and
delisting.
The
commenter
noted
that
under
this
approach,
a
subcategory
would
be
made
of
those
boilers
and
process
heaters
that
do
not
pose
significant
risks
and,
subsequently,
that
subcategory
would
be
delisted.
Commenter
IV­
D­
73
commented
on
all
issues
with
the
risk­
based
off­
ramp
discussed
in
the
preamble,
but
suggested
that
EPA
concentrate
on
promulgating
a
risk­
based
emission
standard
for
HCl
for
several
reasons:
(
1)
HCl
is
a
threshold
HAP
that
generally
presents
little
risk
to
the
public
or
environment
when
emitted
from
boilers/
process
heaters.
The
commenter
cited
the
Chlorine
Production
and
Pulp
and
Paper
NESHAP.
(
2)
Modeling
submitted
by
the
commenter
shows
that
many
facilities
could
benefit
from
a
risk­
based
HCl
standard
and
that
it
would
be
protective
of
human
health
and
the
environment.
(
3)
Use
of
§
112(
d)(
4)
in
the
simple
case
of
a
threshold
HAP
would
not
be
controversial.
(
4)
Implementation
issues
with
other
approaches
discussed
in
the
preamble
could
be
time­
consuming
and
EPA
is
under
a
promulgation
deadline.
The
implementation
steps
for
a
risk­
based
HCl
limit
are
relatively
straightforward
(
determine
ample
margin
of
safety
threshold
for
HCl
(
and
HF),
establishing
an
emission
limit
based
on
look­
188
up
tables,
and
allowing
source
to
comply).
(
5)
Developing
risk­
based
standards
for
other
HAPsurrogate
pollutants
(
e.
g.,
CO,
PM)
raises
difficult
issues,
whereas
HCl
and
HF
are
clearly
covered
with
§
112(
d)(
4).
A
risk­
based
standard
for
HCl
is
easily
segregated
from
the
standards
for
other
HAP.
Commenter
IV­
D­
123
believes
that
a
risk­
based
compliance
option
under
§
112(
d)(
4)
is
particularly
appropriate
for
HCl
emissions.
Such
an
approach
would
reduce
the
economic
impact
of
MACT
on
the
wood
products
industry
and
maximize
environmental
benefits
by
targeting
only
the
HCl
emissions
from
boilers
that
present
a
risk
to
human
health
and
the
environment.
The
commenter
noted
that
available
data
suggest
that
many
industrial
boilers
(
especially
wood­
fired
boilers)
do
not
emit
HCl
in
an
amount
that
would
exceed
applicable
health
benchmarks.
The
commenter
believes
the
potential
costs
savings
range
from
$
295
to
$
772
million
(
see
pp.
24­
25
of
IV­
D­
123
for
the
commenters
derivation
of
these
cost
estimates).
The
commenter
supports
EPA's
acknowledgment
that,
absent
risk­
based
mechanisms,
the
proposed
Boiler
MACT
would
require
some
facilities
to
incur
significant
costs
to
further
control
emissions
that
do
not
pose
an
excess
individual
lifetime
cancer
risk
greater
than
10­
6.
Commenter
IV­
D­
115
stated
that
they
expect
most
of
their
wood
panel
plant
solid
fuel
boilers
to
be
able
to
meet
the
HCl
standard
without
installing
a
scrubber
(
because
they
do
not
burn
coal
or
store
logs
in
salt
water).
However,
they
have
one
facility
that
may
need
a
scrubber,
and
this
facility
could
benefit
from
the
risk­
based
compliance
option
for
HCl.
Commenter
IV­
D­
159
strongly
supported
the
approach
that
if
a
facility
can
demonstrate
that
their
emissions
of
HCl
will
not
result
in
air
concentrations
above
the
inhalation
reference
concentration
(
RfC)
for
HCl,
then
EPA
should
exempt
the
HCl
controls,
even
if
the
category
is
otherwise
subject
to
MACT.
The
commenter
believes
that
this
approach
will
relieve
a
significant
burden
for
facilities
that
can
demonstrate
that
their
emissions
of
HCl
will
not
result
in
air
concentrations
above
the
inhalation
RfC
for
HCl.
Commenter
IV­
D­
159
supported
EPA's
proposed
approach
to
applicability
cutoffs
from
HCl
controls
under
CAA
§
112(
d)(
4).
Commenter
IV­
D­
45
supported
the
inclusion
of
applicability
cutoffs
for
low
risk
sources
of
threshold
pollutants
such
as
HCl.
The
commenter
supported
this
approach
as
good
policy
for
reaching
the
stated
goals
of
the
statute
by
directly
evaluating
whether
a
source
is
adequately
protective
of
human
health
and
the
environment
for
a
given
pollutant.
The
commenter
submitted
that
this
type
of
approach
is
clearly
beneficial
for
pulp
and
paper
mill
sites
where
previous
stack
testing
and
modeling
have
demonstrated
that
current
emission
levels
are
protective.
The
commenter
provided
HCl
modeling
results
from
two
coal/
petroleum
coke
plus
paper
rejects
fired
cyclone
boilers,
a
wood
residual
fired
boiler
plus
two
recovery
furnaces
(
not
in
this
source
category)
that
showed
a
maximum
ambient
annual
HCl
concentration
of
0.29
micrograms
per
cubic
meter
(

g/
m3).
The
commenter
noted
that
this
facility
is
a
high
emitter
of
HCl
in
the
pulp
and
paper
industry
according
to
Toxic
Release
Inventory
(
TRI),
yet
the
modeling
results
indicated
that
concentrations
are
orders
of
magnitude
below
the
HCl
health
benchmark
of
20

g/
m3.
Commenter
IV­
D­
186
supported
the
use
of
§
112(
c)(
9)
to
delist
a
subcategory
and
views
it
as
an
excellent
mechanism
to
limit
the
costs
and
impacts
of
the
rule
to
those
facilities
that
actually
need
to
be
regulated
to
protect
public
health.
Once
EPA
delists
a
subcategory,
it
should
establish
a
procedure
to
evaluate
petitions
from
other
units
that
would
like
to
be
included
in
the
delisted
subcategory.
Commenter
IV­
D­
10
encouraged
EPA
to
pursue
subcategory
delisting
proposed
in
preamble
section
IV.
E.
4.
Commenter
IV­
D­
117
stated
that
EPA
should
consider
delisting
stationary
combustion
turbines
as
a
source
category
under
§
112(
c)(
9)
of
the
CAA
and
40
CFR
63
subpart
C.
189
Commenter
IV­
D­
117
stated
that
recent
studies
indicate
that
HAP
emissions
from
all
small
boilers
in
the
United
States
represent
a
cancer
risk
of
well
below
one
in
one
million
and
the
non­
cancer
risks
are
well
below
levels
EPA
considers
to
protect
public
health
with
an
adequate
margin
of
safety.
The
commenter
added
that
there
are
a
number
of
benefits
of
delisting
boilers
and
process
heaters,
including
that
delisting
would
free
up
agency
resources
for
more
pressing
MACT
issues.
Response:
The
EPA
has
determined
that
it
can
establish
applicable
health­
based
emission
standards
for
HCl
and
Mn
for
affected
sources
in
this
category
pursuant
to
its
authority
under
§
112(
d)(
4)
of
the
CAA.
As
a
result,
EPA
has
included
such
standards
in
the
final
rule
as
alternative
compliance
requirements
for
large
solid
fuel­
fired
boilers
and
process
heaters.
Under
this
approach,
affected
sources
can
choose
to
comply
with
either
the
MACT­
based
emission
limits
or
the
health­
based
emission
limits.
Sources
which
choose
to
comply
with
the
health­
based
emission
limit(
s)
will
remain
subject
to
those
limits,
but
will
need
to
comply
with
testing,
monitoring
and
reporting
requirements
commensurate
with
the
compliance
option
they
have
chosen.
The
EPA
believes
that
such
health­
based
standards
are
consistent
with
both
the
commenters'
support
for
an
approach
that
minimizes
the
impact
on
low­
risk
facilities
and
EPA's
statutory
mandate
under
§
112.
Section
112(
d)(
4)
authorizes
EPA
to
consider
established
health
thresholds,
with
an
ample
margin
of
safety,
when
promulgating
emission
standards
under
§
112.
HCl
and
Mn
are
two
pollutants
for
which
health
thresholds
have
been
established.
Issues
concerning
our
legal
authority
to
establish
health­
based
emission
standards
under
CAA
§
112(
d)(
4)
are
discussed
in
more
detail
in
section
18.2.
The
criteria
defining
how
affected
sources
demonstrate
that
they
meet
the
threshold
emissions
levels
for
the
health­
based
compliance
alternative(
s)
is
included
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
(
the
final
rule).
The
criteria
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
were
developed
for
and
apply
only
to
the
Boiler
and
process
heater
source
category
and
are
not
applicable
to
other
source
categories.
The
final
rule
provides
two
ways
that
an
affected
source
may
demonstrate
compliance
with
the
health­
based
emission
limits.
The
first
option
is
through
the
use
of
look­
up
tables
which
allow
facilities
to
determine,
using
a
limited
number
of
site­
specific
input
parameters,
whether
emissions
from
the
affected
source
might
cause
a
hazard
index
(
HI)
limit
for
non­
carcinogens
to
be
exceeded.
The
second
option
is
a
tiered
site­
specific
modeling
approach,
which
allows
those
affected
sources
that
do
not
match
the
site­
specific
input
parameters
on
which
the
look­
up
tables
are
based
to
demonstrate
compliance
with
the
health­
based
emission
limits
by
modeling
using
site­
specific
information.
The
affected
source
will
have
to
demonstrate
that
it
meets
the
criteria
established
by
the
final
rule
and
then
assume
Federally
enforceable
limitations,
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63,
that
ensure
their
specified
HAP
emissions
do
not
subsequently
increase
to
exceed
levels
reflected
in
their
eligibility
demonstrations.
We
are
not
using
§
112(
c)(
9)
for
the
boiler
and
process
heater
source
category,
and
there
is
no
delisting
of
categories
or
subcategories,
as
would
be
consistent
with
§
112(
c)(
9).
We
also
are
not
relying
on
de
minimis
authority;
additional
discussion
of
de
minimis
authority
is
addressed
in
section
18.3.
Bubbling
and
emissions
averaging,
as
mentioned
by
one
commenter,
are
discussed
in
another
section.
For
discussion
of
who
will
review
eligibility
demonstrations
for
the
health­
based
compliance
alternatives,
see
section
18.9.
One
commenter
also
made
reference
to
the
SCALDT
rule;
we
are
not
incorporating
a
risk­
based
option
into
the
SCALDT
rule.
One
commenter
also
mentioned
Stationary
Combustion
Turbines.
We
are
not
including
risk­
based
approaches
in
the
final
combustion
turbines
rule
190
(
which
was
signed
by
the
Administrator
in
August
2003).
However,
we
are
considering
a
petition
to
delist
certain
subcategories
of
combustion
turbines.
Once
a
final
determination
has
been
made
concerning
the
delisting
petition,
we
will
promptly
make
any
conforming
amendments
to
the
Stationary
Combustion
Turbines
NESHAP
which
are
warranted.

Comment:
Commenters
IV­
D­
123,
IV­
D­
122,
IV­
D­
62,
IV­
D­
60,
and
IV­
D­
119
stated
that
a
§
112(
d)(
4)
risk­
based
emission
limitation
could
be
implemented
in
two
ways:
(
1)
by
allowing
sources
whose
emissions
result
in
exposures
that
are
below
the
applicable
health
benchmark
for
a
given
HAP
to
forgo
installation
of
controls;
or
(
2)
by
allowing
sources,
as
an
alternative
to
MACT
controls,
to
control
their
emissions
of
a
given
HAP
down
to
a
level
that
maintains
exposures
below
the
applicable
benchmark.
Commenter
IV­
D­
174
stated
that
a
riskbased
compliance
option
could
be
implemented
by
allowing
sources
to
control
their
HCl
emissions
down
to
a
level
that
maintains
exposures
below
the
health
benchmark
as
an
alternative
to
MACT
controls.
The
commenters
stated
that
EPA
should
include
a
compliance
option
for
HCl
that
would
allow
facilities
to
forgo
MACT
control
if
they
can
show
that
at
the
point
of
greatest
offsite
impact
(
some
of
the
commenters
indicated
at
the
fenceline
or
nearest
receptor)
HCl
concentrations
are
not
expected
to
exceed
the
Integrated
Risk
Information
System
(
IRIS)
RfC
for
HCl.
For
the
Tier
I
screening
model,
HCl
concentrations
at
"
the
point
of
greatest
off­
property
impact"
could
not
exceed
the
benchmark,
while
for
refined
modeling
HCl
concentrations
at
"
the
receptor
of
greatest
off­
property
impact"
could
not
exceed
the
benchmark.
Site­
specific
enforceable
permit
limitation
would
ensure
the
emissions
remain
at
low
risk
levels.
If
the
source
installs
controls,
the
same
initial
compliance
demonstration
and
continuous
compliance
monitoring
used
for
MACT
could
be
done.
If
controls
are
not
required,
then
periodic
monitoring
of
performance
indicators
(
e.
g.,
fuel
quality,
fuel
throughput)
could
be
required.
Commenter
IV­
D­
61
stated
that
sources
wishing
to
take
advantage
of
the
risk­
based
compliance
option
would
take
a
federally­
enforceable
permit
limit
that
would
guarantee
that
their
emissions
remain
below
the
risk­
based
emission
standard.
This
would
constitute
an
"
emission
limitation"
­
within
the
statutory
definition
of
the
term
­
and
it
would
allow
sources
to
forego
the
installation
of
incinerators
where
they
are
not
warranted
by
public
health
and
environmental
considerations.
Response:
The
health­
based
compliance
alternatives
for
HCl
and
Mn
included
in
the
final
rule
for
one
subcategory
(
large
solid­
fuel
fired
boilers
and
process
heaters)
are
intended
to
avoid
imposing
unnecessary
controls
for
emissions
that
pose
little
risk
to
human
health
or
the
environment.
Affected
sources
will
have
to
select
controls
or
other
methods
of
limiting
risk
associated
with
HCl
and
Mn,
and
then
demonstrate,
using
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
and
other
analytical
tools,
such
as
the
"
Air
Toxics
Risk
Assessment
Reference
Library,
Volume
2,
Site­
Specific
Risk
Assessment
Technical
Resource
Document"
(
Air
Toxics
Risk
Assessment
Reference
Library),
if
appropriate
in
a
source's
case,
that
their
emissions
do
not
exceed
the
health­
based
emission
limits.
The
affected
source
will
have
to
demonstrate
that
it
meets
the
criteria
established
by
the
final
rule
and
then
assume
Federally
enforceable
limitations,
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63,
that
ensure
their
specified
HAP
emissions
do
not
subsequently
increase
to
exceed
levels
reflected
in
their
demonstration.

Comment:
Multiple
commenters
opposed
risk­
based
approaches
(
IV­
D­
113,
IV­
D­
09,
IV­
D­
148,
IV­
D­
96,
IV­
D­
06,
IV­
D­
154,
and
IV­
D­
118).
Commenters
IV­
D­
09
and
IV­
D­
118
noted
that
the
proposal
to
include
risk­
based
exemptions
is
critically
flawed
and
opposes
adoption
of
the
risk­
based
exemptions
into
MACT.
191
Commenter
IV­
D­
148
stated
that
the
inclusion
of
case­
by­
case
risk­
based
exemptions
into
the
first
phase
of
the
MACT
program
will
negate
the
legislative
mandate
and
jeopardize
the
effectiveness
of
the
national
air
toxics
program
to
adequately
protect
public
health
and
the
environment
and
to
establish
a
level
playing
field.
Therefore,
the
commenter
strongly
disagrees
with
inclusion
of
risk­
based
exemptions
in
the
MACT
standard
process.
The
commenter
was
very
concerned
that
EPA
referenced
a
fundamentally
flawed
interpretation
of
§
112(
d)(
4)
written
by
an
industry
(
AF&
PA)
subject
to
regulation.
Of
particular
concern
was
AF&
PA's
unprecedented
proposal
to
include
"
de
minimis
exemptions"
and
"
cost"
in
the
MACT
standard
process.
Commenter
IV­
D­
96
stated
that
in
AF&
PA's
supplemental
comments
on
the
Brick
and
Structural
Clay
Products
(
BSCP)
MACT,
AF&
PA
attempted
to
rebut
NRDC's
position
regarding
the
risk­
based
approaches.
But
AF&
PA's
vague
and
tortured
explanation
of
how
emissions
limits
for
individual
facilities
would
be
established
actually
supports
NRDC's
position.
MACT
standards
must
be
set
by
EPA
and
must
be
clear,
known,
and
enforceable.
The
source­
specific
standard­
setting
process
desired
by
AF&
PA
would
give
extensive
discretion
to
private
entities
and
States
to
establish
Federal
MACT
standards
and
exemptions,
and
no
precedent
for
this
type
of
approach
was
provided
by
AF&
PA
or
EPA
(
and
none
exists).
Commenter
IV­
D­
154
is
extremely
concerned
about
the
policy
and
technical
implications
of
the
risk­
based
exemption
proposal.
Because
of
the
flaws
with
the
proposal,
the
commenter
is
opposed
to
the
adoption
of
the
risk­
based
exemptions
to
MACT.
Commenter
IV­
D­
05
stated
the
belief
that
the
use
of
risk­
based
concepts
to
evade
MACT
applicability
is
contrary
to
the
intent
of
the
CAA
and
is
based
on
a
flawed
interpretation
of
§
112(
d)(
4)
of
the
CAA.
The
commenter
added
that
the
CAA
requires
a
technology­
based
floor
level
of
control
and
does
not
provide
exclusions
for
risk
or
secondary
impacts
from
applying
the
MACT
floor.
Commenter
IV­
D­
05
stated
that
from
a
practical
standpoint,
the
approaches
(
to
risk­
based
exemptions)
in
the
preamble
are
not
appropriate.
Commenter
IV­
D­
17
is
opposed
to
risk­
based
exemptions
discussed
in
the
preamble
and
recommends
that
EPA
expeditiously
propose
and
promulgate
the
rule
without
such
exemptions.
Commenter
IV­
D­
14
is
opposed
to
the
risk­
based
exemptions
and
called
upon
EPA
to
promulgate
the
remaining
technology­
based
MACT
standards
without
the
risk­
based
exemptions.
Commenter
IV­
D­
141
believes
that
the
risk­
based
exemption
approaches
described
in
the
proposal
preamble
are
not
appropriate
or
workable.
The
commenter
understood
that
the
MACT
standards
were
to
be
technology
based
and
to
have
considered
the
best
level
of
controls
on
existing
boilers.
The
commenter
noted
that
they
operate
two
small
(
10.5
MMBtu/
hr)
firetube
natural
gas/
propane
fired
boilers
that
would
be
covered
by
the
proposed
rule.
A
brief
review
by
the
commenter
indicated
that
there
were
no
controls
for
HAP
on
any
boilers
of
the
type
at
the
commenter's
facility
anywhere
in
the
United
States.
Therefore,
Commenter
IV­
D­
141
firmly
believes
that
this
type
of
boiler
should
be
fully
exempted
from
the
proposed
rules.
The
commenter
pointed
out
that
the
CAA
makes
a
provision
for
considering
risk
once
the
MACT
standards
are
in
place.
The
commenter
believes
it
would
not
be
appropriate
to
consider
risk
until
after
the
MACT
standards
have
been
fully
promulgated.
(
It
should
be
noted
that
the
commenter
provided
information
regarding
the
insignificant
risk
associated
with
boilers
of
the
size
and
type
used
at
the
commenter's
facility.)
The
commenter
also
noted
that
the
complexity
of
risk
analysis
would
make
its
inclusion
in
the
proposed
rules
very
time
consuming
and
extremely
difficult
to
implement.
Commenter
IV­
D­
96
stated
that
in
separate
rulemakings
and
lawsuits,
EPA
has
adopted
legal
positions
and
policies
that
refute
and
contradict
the
very
risk­
based
and
cost­
based
approaches
contained
in
the
proposals.
In
these
other
arena,
EPA
has
properly
rejected
risk
192
assessment
to
alter
the
establishment
of
MACT
standards.
EPA
also
has
properly
rejected
cost
in
determining
MACT
floors
and
in
denying
a
basis
for
avoiding
the
MACT
floor.
The
commenter
attached
passages
from
several
EPA
briefs:
Brief
for
Respondent
Environmental
Protection
Agency,
Sierra
Club
v.
EPA;
Brief
for
Respondent
Environmental
Protection
Agency,
Cement
Kiln
Recycling
Coalition
v.
EPA,
No.
99­
1457
and
consolidated
cases,
D.
C.
Cir.)
(
Jan.
18,
2001)
(
Attachment
1);
Brief
for
Respondent
Environmental
Protection
Agency,
National
Lime
Ass'n
v.
EPA,
233
F.
3D
625
(
D.
C.
Cir.
2000)
(
July
14,
2000)
(
Attachment
3).
Commenter
IV­
D­
154
stated
that
the
preamble
discussion
of
the
risk­
based
approaches
is
not
sufficient
to
allow
for
complete
public
comment
and,
therefore,
it
would
not
be
appropriate
for
EPA
to
go
directly
to
a
final
rule
(
without
reproposal)
with
any
of
the
approaches
outlined
in
the
proposal.
The
commenter
recommended
that
the
risk­
based
exemption
proposal
be
dropped
because
it
is
unacceptable.
Commenter
IV­
D­
10
agreed
in
principle
with
EPA's
proposed
plan
to
utilize
applicability
thresholds
and
risk
assessment
as
an
alternative
to
the
proposed
MACT
limits
and
applauds
EPA's
effort
to
establish
an
alternative
compliance
method
using
risk
assessment.
However,
the
commenter
felt
that
the
methods
being
considered
as
part
of
the
rule
are
far
too
complex
to
warrant
detailed
comments
at
this
time.
Consequently,
the
commenter
requested
that
EPA
draft
language
for
the
final
Boiler
MACT
that
allows
utilization
of
this
option
without
specifics.
The
commenter
suggested
that
EPA
should
then
proceed
with
development
of
additional
rulemaking
for
review
and
comment
that
would
provide
the
specifics
and
a
structured
approach
for
requirements
a
source
would
need
to
satisfy
to
perform
a
successful
risk
assessment.
Commenter
IV­
D­
135
summarized
Administrative
Procedure
Act
issues.
The
commenter
submitted
that
in
many
sections,
EPA's
proposal
lacks
sufficient
detail
so
as
to
deprive
the
public
of
notice
and
opportunity
to
comment.
For
example,
the
various
delisting
and
applicability
cutoff
proposals
were
so
lacking
in
detail
that
anything
could
be
a
"
logical
outgrowth"
of
the
proposal.
The
commenter
asserted
that
section
IV.
E
of
the
EPA's
proposal
failed
to
provide
an
in
depth,
reasoned
analysis
of
its
action.
[
Motor
Vehicles
Mfrs.
Ass'n
v.
State
Farm
Mut.
Auto
Ins.
Co.,
463
U.
S.
29,
43
(
1983)(
requiring
an
agency
to
"
articulate
a
satisfactory
explanation
for
its
action."]
The
commenter
asserted
that
EPA
must
review
and
re­
propose
insufficiently
detailed
proposals
prior
to
going
to
final
rulemaking.
Commenter
IV­
D­
14
stated
that
the
use
of
sub­
categorization
and
source
category
deletions
under
§
112(
c)
have
been
implemented
several
times
since
the
MACT
program
began.
The
commenters
have
been
unable
to
comment
on
the
technical
merit
of
the
risk
analysis
employed
by
the
EPA.
Until
the
residual
risk
analysis
procedures
have
been
implemented
via
the
§
112(
f)
process,
risk
analysis
should
not
been
used
in
making
MACT
determinations
pursuant
to
§
112(
d)(
4)
and,
could
never
be
used
to
establish
a
MACT
floor.
Commenter
IV­
D­
135
argued
that
EPA's
discussion
of
the
threshold
applicability
approach
lacked
the
specificity
to
allow
reasoned
comment
or
analysis
of
the
proposal
and
enumerates
several
issues
related
to
the
proposal
that
EPA
did
not
discuss
or
consider.
The
commenter
concluded
that
EPA's
discussion
of
a
threshold
applicability
approach
lacked
crucial
elements
of
a
valid
rulemaking.
Response:
We
are
not
identifying
and
deleting
a
subcategory
of
sources
in
this
source
category
pursuant
to
the
authority
of
CAA
§
112(
c)(
9).
We
also
are
not
relying
on
de
minimus
authority.
Legal
issues
associated
with
the
health­
based
provisions
are
addressed
in
sections
18.2
and
18.4.
In
addition,
de
minimis
authority
is
discussed
in
section
18.3.
As
discussed
above,
we
are,
however,
including
in
the
final
rule
alternative
health­
based
emission
standards
for
HCl
and
Mn
based
on
our
authority
under
CAA
§
112(
d)(
4).
193
Section
112(
d)(
4)
authorizes
EPA
to
consider
health
thresholds,
with
an
ample
margin
of
safety,
in
establishing
emission
standards.
The
analysis
necessary
to
do
this
can
generally
be
characterized
as
a
risk
analysis.
Thus,
we
disagree
with
the
commenter
that
we
must
wait
for
implementation
of
§
112(
f)
before
utilizing
risk
analysis.

Comment:
Multiple
commenters
(
IV­
D­
06,
IV­
D­
09,
IV­
D­
154,
IV­
D­
102,
IV­
D­
118,
and
IV­
D­
14)
believe
that
the
preambles
of
individual
rule
proposals
were
an
inappropriate
forum
for
introducing
significant
changes
in
the
way
that
MACT
standards
are
established.
Precedentsetting
change
of
the
magnitude
that
EPA
has
raised
should
be
discussed
openly
and
carefully
with
all
affected
parties
instead
of
being
buried
in
the
preambles
of
individual
standards.
Commenter
IV­
D­
05
stated
the
concern
that
other
parties
may
miss
commenting
on
the
risk­
based
exemptions
because
they
are
contained
within
six
separate
proposals.
The
commenter
added
that
to
give
the
issue
full
consideration,
the
risk
provisions
should
not
be
adopted
within
any
of
the
final
rules
but
should
be
addressed
in
one
place,
such
as
in
revisions
to
the
general
provisions
of
40
CFR
63
subpart
A.
Commenter
IV­
D­
148
stated
that
for
many
years,
they
have
coordinated
with
OAQPS
on
development
of
MACT
standards
for
the
national
air
toxics
program,
and
there
has
been
no
indication
of
any
kind
regarding
inclusion
of
risk­
based
exemptions
in
the
first
phase
of
the
MACT
program.
The
commenter
thought
it
was
unprecedented
and
alarming
that
EPA
is
proposing
such
a
radical
change
at
the
end
of
Phase
1
of
the
MACT
standard
process.
Commenter
IV­
D­
148
believes
that
allowing
risk­
based
exemptions
requires
changes
to
existing
law
and
that
such
a
debate
should
take
place
within
the
democratic
legislative
process
and
not
in
the
MACT
standard
process.
Response:
The
discussion
of
health­
based
compliance
alternatives
was
included
in
individual
proposals
for
several
reasons.
We
recognize
that
such
provisions
are
only
appropriate
for
certain
HAP,
and
our
decision­
making
process
required
source
category­
specific
input
from
stakeholders.
The
10­
year
MACT
standards,
which
are
now
being
completed,
are
the
last
group
of
MACT
standards
currently
planned
for
development,
and
for
any
risk
provisions
to
be
useful,
the
provisions
must
be
finalized
in
a
timely
manner
The
health­
based
provisions
are
not
available
for
any
other
standards
that
have
already
been
implemented,
and
any
decisions
regarding
risk
must,
therefore,
be
applied
on
a
source
category
specific
basis.

Comment:
Commenter
IV­
D­
96
stated
that
the
dockets
for
the
MACT
proposals
that
contain
the
risk
approaches
make
it
clear
that
the
White
House
Office
of
Management
and
Budget
(
OMB)
and
industry
were
the
driving
forces
behind
the
appearance
of
these
unlawful
approaches
in
EPA's
proposals.
The
commenter
cited
internal
emails
between
the
White
House
OMB
and
EPA
that
reveal
OMB
officials
exerting
pressure
on
EPA
to
"
take
ownership"
of
the
deregulatory
approaches
developed
by
the
AF&
PA
and
Latham
and
Watkins
(
Boilers
Docket
A­
96­
47,
item
IIF
24).
The
commenter
noted
that
comparison
of
the
BSCP
and
Plywood
and
Composite
Wood
Products
(
PCWP)
MACT
proposal
language
makes
clear
that
EPA
capitulated
to
OMB
pressure
to
remove
references
to
the
risk­
based
exemptions
in
PCWP
preamble
section
IV.
G
being
"
industry's
suggested
approaches."
The
commenter
cited
preamble
edits
from
OMB
that
the
commenter
believes
reveals
an
OMB
agenda
to
dictate
EPA
adoption
of
industry's
risk­
based
approaches,
and
to
signal
these
plans
in
the
rulemaking
proposals,
even
before
public
comment
has
been
taken.
(
We
will
evaluate
all
comments
before
determining
which
of
the
two
alternatives
will
be
included
in
the
final
rule.
See
Boilers
Docket
A­
96­
47,
item
II­
F­
24).
The
commenter
also
noted
that
OMB
urged
support
of
a
dangerous
and
technically
unfounded
HI
of
10,
and
that
194
EPA
appropriately
rejected
proposing
HI
of
10
because
EPA
had
no
technical
rationale
to
support
this
HI
option.
The
commenter
condemned
the
industry­
driven
agenda
(
that
would
allow
higher
levels
of
toxic,
cancer­
causing
air
pollution)
that
is
being
promoted
by
the
White
House
OMB.
Commenter
IV­
D­
123
stated
that
accusations
by
NRDC
that
EPA
has
succumbed
to
industry
lobbying
and
internal
pressures
are
entirely
unfounded.
Eighty
source
categories
have
already
been
addressed
with
MACT
standards.
The
remaining
source
categories
are
lower
priority
and
include
a
large
number
of
facilities
that
pose
negligible
risk
to
public
health
and
environment.
The
EPA
purposefully
saved
those
categories
for
last
in
accordance
with
Congress's
explicit,
risk­
based
priority
setting
mandate
expressed
in
§
112(
e)(
2).
EPA
has
now
reached
the
point
where
regulation
by
MACT
would
result
in
more
environmental
harm
than
good.
Response:
The
commenter
is
correct
in
stating
that
industry
representatives
and
OMB
support
the
inclusion
of
health­
based
approaches
in
the
final
rule
as
a
method
of
reducing
costs.
We
are
required
by
Executive
Order
12866
to
submit
to
OMB
for
review
all
proposed
and
final
rulemaking
packages
that
would
have
an
annual
effect
on
the
economy
of
$
100
million
or
more.
The
comments
we
received
from
OMB
reflect
their
position
that
low­
risk
facilities
do
not
warrant
regulation.
However,
the
commenter
is
incorrect
in
implying
that
we
have
not
exercised
our
independent
judgement
in
addressing
these
issues.
Our
rationale
for
adopting
the
health­
based
approach
in
the
final
rule
is
that
such
an
approach
is
fully
authorized
under
the
CAA.

18.1.2
Effects
on
MACT
program
Comment:
Commenters
IV­
D­
06,
IV­
D­
09,
IV­
D­
154,
IV­
D­
102,
IV­
D­
148,
IV­
D­
17,
IV­
D­
14,
and
IV­
D­
118
stated
that
the
proposal
to
include
risk­
based
exemptions
is
contrary
to
the
1990
CAAA
which
calls
for
MACT
standards
based
on
technology
rather
than
risk
as
a
first
step.
Congress
incorporated
the
residual
risk
program
under
§
112(
f)
to
follow
the
MACT
standards
(
not
to
replace
them).
The
need
for
the
technology­
based
approach
has
been
recently
reinforced
by
the
results
of
the
National
Air
Toxics
Assessment
(
NATA),
which
indicates
that
exposure
to
air
toxics
is
very
high
throughout
the
country
in
urban
and
remote
areas.
Commenters
IV­
D­
154,
IV­
D­
09,
IV­
D­
102,
IV­
D­
118,
and
IV­
D­
85
added
that
risk­
based
approaches
will
be
used
separately
to
augment
and
improve
technology­
based
standards
that
do
not
adequately
provide
protection
to
the
public.
Commenter
IV­
D­
148
believes
that
§
112(
b)(
4)
of
the
CAA
and
the
regulatory
precedent
established
in
over
80
MACT
standards
rejects
the
inclusion
of
risk
in
the
first
phase
of
the
MACT
standards
process.
Commenter
IV­
D­
06
added
that
§
112(
f)
of
the
CAA
was
developed
to
address
residual
risks
remaining
after
implementation
of
technology­
based
MACT
standards
and
was
intended
to
provide
additional
protection,
not
replace
technology
controls.
Commenter
IV­
D­
148
added
that
they
have
been
unable
to
substantiate
the
basis
for
EPA's
support
of
the
regulatory
relief
sought
by
industry
through
riskbased
exemptions.
In
fact,
the
use
of
risk
assessment
at
this
stage
of
the
MACT
program
is
directly
opposed
to
title
III
of
the
CAA.
Commenter
IV­
D­
148
attached
an
EPA
fact
sheet
and
testimony
by
two
individuals
that
supports
this
position.
Commenter
IV­
D­
85
recognized
the
merits
of
focusing
on
the
highest
risk
facilities,
but
believes
the
risk­
based
exemption
approach
would
not
survive
any
legal
challenges
as
they
appear
to
be
contrary
to
the
intent
of
the
CAAA
of
1990.
Response:
We
disagree
that
inclusion
of
health­
based
compliance
alternatives,
in
the
form
of
emission
standards
based
on
the
authority
of
§
112(
d)(
4),
in
the
final
rule
is
contrary
to
the
195
1990
CAAA.
The
Boiler
MACT
is
a
technology­
based
standard
developed
using
the
procedures
dictated
by
§
112
of
the
CAA.
The
only
difference
in
the
Boiler
MACT
and
other
MACT
is
that
we
used
our
discretion
under
§
112(
d)(
4)
to
base
appropriate
parts
of
the
Boiler
MACT
on
established
health
thresholds,
with
an
ample
margin
of
safety.
We
believe
that
the
Boiler
and
process
heater
source
category
is
particularly
well­
suited
for
a
health­
based
compliance
alternative,
established
pursuant
to
the
criteria
set
forth
in
§
112(
d)(
4).
In
addition
to
the
fact
that
there
are
established
health
thresholds
for
HCl
and
Mn,
EPA
has
determined
that
some
of
the
facilities
in
this
source
category
do
not
emit
these
pollutants
in
amounts
that
pose
a
significant
risk
to
the
surrounding
population.
Those
sources
that
can
demonstrate
that
the
emissions
of
HClequivalents
and
Mn
meet
the
threshold
emission
levels
will
be
in
compliance
with
the
MACT.
The
criteria
are
based
on
health­
protective
estimates
of
risk
and
the
threshold
emission
levels
will
provide
ample
protection
of
human
health
and
the
environment.
Inclusion
of
health­
based
compliance
alternatives
in
the
final
rule
does
not
alter
the
MACT
program.
Rather,
it
merely
represents
EPA
availing
itself,
in
appropriate
circumstances,
of
the
authority
Congress
granted
it
in
§
112(
d)(
4)
of
the
CAA.
We
recognize
that
such
provisions
are
only
appropriate
for
certain
HAP,
and
our
decision­
making
process
required
source
categoryspecific
input
from
stakeholders.
The
10­
year
MACT
standards,
which
are
now
being
completed,
are
the
last
group
of
MACT
standards
currently
planned
for
development,
and
for
any
risk
provisions
to
be
useful,
the
provisions
must
be
finalized
in
a
timely
manner
Although
NATA
may
show
measurable
concentrations
of
toxic
air
pollution
across
the
country,
these
data
do
not
suggest
that
EPA
should
not
establish
health­
based
emission
standards
pursuant
to
its
authority
under
§
112(
d)(
4)
when
it
determines
that
it
is
appropriate
to
do
so.
The
alternative
health­
based
emission
standards
included
in
the
final
rule
will
ensure
that
affected
sources
which
choose
to
comply
with
those
standards
do
not
emit
HCl
and/
or
Mn
at
levels
that
are
harmful
to
public
health.
A
discussion
of
background
concentrations
is
provided
in
section
18.6.

Comment:
Commenters
IV­
D­
09,
IV­
D­
14,
IV­
D­
154,
IV­
D­
102,
IV­
D­
148,
and
IV­
D­
118
stated
that
the
risk­
based
exemption
proposal
removes
the
"
level­
playing
field"
that
would
result
from
the
proper
implementation
of
technology­
based
MACT
standards.
Establishing
a
baseline
level
of
control
is
essential
to
prevent
industry
from
moving
to
areas
of
the
country
that
have
the
least
stringent
air
toxics
programs,
which
was
one
of
the
primary
goals
of
developing
a
uniform
national
air
toxics
program
under
§
112
of
the
1990
CAA
amendments.
The
risk­
based
approaches
would
jeopardize
future
reductions
of
HAP
in
a
uniform
and
consistent
manner
across
the
nation.
Commenters
IV­
D­
09
and
IV­
D­
118
stated
that
the
NATA
data
show
that
virtually
no
area
of
the
country
has
escaped
measurable
concentrations
of
toxic
air
pollution.
The
NATA
information
indicates
that
exposure
to
air
toxics
is
high
in
both
densely
populated
and
remote
rural
areas.
Commenter
IV­
D­
123
provided
the
following,
in
response
to
NRDC
comments
regarding
the
proposals
potential
removal
of
a
level
playing
field;
(
1)
As
a
policy
matter,
NRDC's
argument
would
be
that
EPA
should
impose
unnecessary
and
potentially
environmentally
damaging
controls
for
the
sole
purpose
of
equalizing
control
costs
across
sources.
Such
a
result
is
at
odds
with
stated
purpose
of
CAA.
(
2)
As
factual
matter,
NRDC's
claim
that
risk­
based
approach
would
favor
facilities
located
away
from
population
centers
is
incorrect.
As
contemplated,
the
risk­
based
196
approaches
to
the
NESHAP
would
be
key
to
the
comparison
of
health
benchmarks
with
potential
maximum
exposure,
regardless
of
whether
actual
receptors
are
present
at
the
exposure
location.
Presence
or
absence
of
human
populations
would
have
no
effect
on
whether
facilities
would
qualify.
Response:
We
agree
that
one
of
the
goals
of
developing
a
uniform
national
air
toxics
program
under
§
112
of
the
1990
CAAA
was
to
establish
a
level
playing
field.
We
do
not
believe
that
providing
health­
based
compliance
alternatives
for
sources
that
can
meet
them
in
the
final
rule
will
do
anything
to
create
an
unlevel
playing
field
for
sources
subject
to
this
rule.
The
final
rule
and
its
criteria
for
demonstrating
eligibility
for
the
health­
based
compliance
alternatives
apply
uniformly
to
boilers
and
process
heaters
across
the
nation
in
the
large
solid
fuel­
fired
subcategory.
The
final
rule
establishes
two
baseline
levels
of
emissions
reduction
for
HCl
and
Mn,
one
based
on
a
traditional
MACT
analysis
and
the
other
based
on
EPA's
evaluation
of
the
health
threat
posed
by
emissions
of
these
two
pollutants.
All
boilers
and
process
heaters
in
the
applicable
subcategory
must
meet
one
of
these
baseline
levels,
and
all
boilers
and
process
heaters
in
the
applicable
subcategory
have
the
same
opportunity
to
demonstrate
that
they
can
meet
the
alternative
healthbased
emission
standards.
The
criteria
for
demonstrating
eligibility
for
the
alternative
healthbased
emission
standards
are
not
dependent
on
local
air
toxics
programs.
Therefore,
concerns
regarding
facilities
moving
to
areas
of
the
country
with
less­
stringent
air
toxics
programs
should
be
alleviated.
Although
NATA
may
show
measurable
concentrations
of
toxic
air
pollution
across
the
country,
these
data
do
not
suggest
that
EPA
should
not
establish
health­
based
emission
standards
pursuant
to
its
authority
under
§
112(
d)(
4)
when
it
determines
that
it
is
appropriate
to
do
so.
The
alternative
health­
based
emission
standards
included
in
the
final
rule
will
ensure
that
affected
sources
which
choose
to
comply
with
those
standards
do
not
emit
HCl
and/
or
Mn
at
levels
that
are
harmful
to
public
health.

Comment:
Commenters
IV­
D­
06,
IV­
D­
09,
IV­
D­
14,
IV­
D­
154,
IV­
D­
102,
IV­
D­
118,
and
IV­
D­
17
stated
that
the
proposal
to
allow
risk­
based
exemptions
would
divert
back
to
the
time­
consuming
NESHAP
development
process
that
existed
prior
to
the
CAAA.
Under
this
process,
which
began
with
a
risk
assessment
step,
only
eight
NESHAP
were
promulgated
during
a
20­
year
period.
If
the
proposed
approaches
are
inserted
into
upcoming
standards,
the
commenters
fear
the
MACT
program
(
which
is
already
far
behind
schedule)
would
be
further
delayed.
Commenter
IV­
D­
168
supported
EPA
efforts
to
determine
alternative
MACT
setting
methodologies
but
strongly
recommended
that
these
be
pursued
separately
from
this
rulemaking.
This
will
provide
for
timely
issuance
of
final
Reciprocating
Internal
Combustion
Engine
(
RICE)
and
Boiler/
Process
Heater
MACT
standards
relative
to
the
settlement
deadline.
Commenters
IV­
D­
09
and
IV­
D­
118
stated
that
it
is
evident
that
the
proposed
approach
to
risk­
based
exemptions
would
require
extensive
debate
and
review
in
order
to
launch,
which
will
further
delay
promulgation
of
the
remaining
MACT
standards.
Commenters
IV­
D­
09
and
IV­
D­
118
stated
that
delays
could
be
exacerbated
by
litigation
following
legal
challenges
to
the
rules,
and
such
delays
would
trigger
the
MACT
hammer,
which
would
unnecessarily
burden
the
State
and
local
agencies
and
the
industries.
The
commenters
concluded
that,
obviously,
further
delay
is
unacceptable.
Commenter
IV­
D­
130
did
not
want
to
be
in
a
position
of
implementing
the
§
112(
j)
program
and
urged
EPA
to
not
delay
the
issuance
of
any
MACT
standard.
197
Commenters
IV­
D­
17
and
IV­
D­
118
stated
that
the
proposed
approaches
will
jeopardize
expeditious
promulgation
of
remaining
MACT
standards.
The
commenters
noted
that
according
to
a
recently
proposed
EPA
rule
regarding
§
112(
j),
the
regulated
community
and
State
and
local
agencies
would
have
to
proceed
with
Part
2
permit
applications,
followed
by
case­
by­
case
MACT,
if
EPA
misses
the
newly
agreed­
upon
MACT
deadlines
by
as
little
as
two
months.
This
would
be
time
consuming,
costly,
and
burdensome
for
both
regulators
and
the
regulated
community.
Commenter
IV­
D­
148
noted
that
the
Inspector
General
recently
found
that
EPA
is
nearly
two
years
behind
in
fulfilling
its
statutory
responsibilities
for
implementing
Phase
1
MACT
standards.
This
delay
potentially
harms
the
public
and
environment.
The
inclusion
of
risk­
based
exemptions
in
10­
year
MACT
standards
will
only
further
delay
this
process.
Commenter
IV­
D­
154
stated
that
the
risk
assessment
exemption
could
significantly
delay
compliance
with
MACT
for
sources
trying
unsuccessfully
to
opt
out
using
the
exemption.
Commenter
IV­
D­
96
stated
that
the
EPA's
proposal
would
cripple
the
MACT
program
which
is
already
in
disarray.
The
risk­
based
approach
could
delay
the
HAP
emissions
reductions
required
by
§
112.
EPA's
MACT
program
is
already
delayed
and
the
incorporation
of
improper
risk
assessment
into
the
technology­
based
standard
process
will
only
exacerbate
the
delay.
The
EPA
lacks
adequate
emissions
and
exposure
data,
source
characterization
data,
and
health
and
ecological
effects
information
to
conduct
this
process
anyway.
The
commenter
attached
portions
of
a
report
from
EPA's
Office
of
Inspector
General
that
lists
describes
EPA's
challenges
related
to
the
air
toxics
program.
The
commenter
believes
that
the
air
toxics
program
is
flawed
and
is
failing
to
protect
public
health
and
the
environment,
and
therefore,
it
is
irresponsible
for
EPA
to
pursue
a
deregulatory
agenda
that
will
further
weaken
the
effectiveness
of
EPA's
air
toxics
program.
Commenter
IV­
D­
96
noted
that
EPA
acknowledged
the
complexity
and
delays
associated
with
the
proposed
risk­
based
approaches
in
deciding
not
to
adopt
the
approaches
in
the
BSCP
rulemaking.
Response:
We
disagree
that
allowing
health­
based
compliance
alternatives
in
the
final
rule
will
alter
the
MACT
program
or
affect
the
schedule
for
promulgation
of
the
remaining
MACT
standards,
especially
this
Boiler
MACT
rule.
In
fact,
it
has
not
caused
such
a
delay
for
this
rule.
We
do
not
anticipate
any
further
delays
in
completing
the
remaining
MACT
standards.
The
setting
of
alternative
health­
based
emission
standards
in
the
final
rule
affects
only
the
boiler
and
process
heater
source
category,
and
not
any
other
MACT
standards.
We
believe
that
the
approach
taken
in
the
final
rule
is
particularly
well­
suited
to
HCl
and
Mn,
which
are
the
only
pollutants
for
which
health­
based
compliance
alternatives
are
included.
For
some
facilities,
the
pollutants
are
currently
emitted
in
amounts
that
do
not
expose
anyone
in
the
surrounding
population
to
concentrations
above
the
established
health
threshold.
As
a
result,
emissions
of
HCl
and/
or
Mn
at
these
facilities
do
not
pose
a
significant
risk
to
the
surrounding
population.
Only
those
affected
sources
that
demonstrate
that
their
emissions
are
below
the
health­
based
emission
standard(
s)
are
eligible
for
the
compliance
alternatives.
The
criteria
are
based
on
health­
protective
estimates
of
risk
and
will
provide
ample
protection
of
human
health
and
the
environment.
Including
health­
based
compliance
alternatives
for
the
boiler
and
process
heater
source
category
does
not
mean
that
we
will
automatically
provide
such
alternatives
for
other
industries.
Rather,
as
has
been
the
case
throughout
the
MACT
rule
development
process,
we
will
undertake
in
each
individual
rule
to
determine
whether
it
is
appropriate
to
exercise
its
discretion
to
use
its
authority
under
§
112(
d)(
4)
in
developing
applicable
emission
standards.
Furthermore,
we
have
198
no
intentions
of
re­
opening
previously
promulgated
NESHAP
in
light
of
decisions
made
specific
to
the
boilers
and
process
heaters
source
category.
The
Boilers
NESHAP
is
being
promulgated
by
the
February
2004
court­
ordered
deadline.
Any
delays
in
implementation
of
the
Boilers
NESHAP
caused
by
legal
challenges,
which
could
and
often
do
occur
for
any
MACT
standard
we
promulgate
without
a
health­
based
approach,
are
beyond
our
control.

18.2
LEGAL
ISSUES:
SECTION
112(
d)(
4)
AUTHORITY
18.2.1
Section
112(
d)(
4)
Authority
to
Exempt
Sources
Comment:
Multiple
commenters
(
IV­
D­
40,
IV­
D­
61,
IV­
D­
72,
IV­
D­
73,
IV­
D­
75,
IVD
122,
IV­
D­
123,
IV­
D­
166,
IV­
D­
172,
IV­
D­
173,
IV­
D­
175,
IV­
D­
183,
and
IV­
D­
186)
believe
that
§
112(
d)(
4)
provides
EPA
with
authority
to
exclude
sources
that
emit
threshold
pollutants
from
regulation.
The
commenters
indicated
that
§
112(
d)(
4)
allows
for
discretion
in
developing
MACT
standards
for
HAP
with
health
thresholds.
This
is
consistent
with
the
plain
language
of
the
statute,
which
states
that:
"
With
respect
to
pollutants
for
which
a
health
threshold
has
been
established,
the
Administrator
may
consider
such
threshold
level,
with
an
ample
margin
of
safety,
when
establishing
emission
standards
under
this
subsection."
The
commenters
stated
that
the
use
of
§
112(
d)(
4)
authority
also
is
supported
by
CAA's
legislative
history,
which
emphasizes
that
Congress
included
§
112(
d)(
4)
in
the
CAA
to
prevent
unnecessary
regulation
of
source
categories.
Multiple
commenters
(
I­
D­
61,
IV­
D­
122,
IV­
D­
123,
IV­
D­
172,
IV­
D­
175,
and
IV­
D­
186)
referenced
Sen
Rep.
101­
228,
at
176
(
1989),
reprinted
in
1990
U.
S.
C.
C.
A.
N.
3385,
3560:
"[
W]
here
some
sources
do
emit
more
than
the
threshold
amount,
the
Administrator
is
authorized
by
section
112(
d)(
4)
to
use
the
no
observable
effects
level
or
NOEL
(
again
with
an
ample
margin
of
safety)
as
the
emission
limitation
in
lieu
of
more
stringent
"
best
technology"
requirements.
Following
this
scenario,
only
those
sources
in
the
category
which
present
a
risk
to
public
health
(
those
emitting
in
amounts
greater
than
the
safety
threshold)
would
be
required
to
install
controls,
even
though
the
general
policy
is
"
maximum
achievable
technology
everywhere."
Again,
there
is
a
means
to
avoid
regulatory
costs
which
would
be
without
public
health
benefit.
Several
commenters
(
IV­
D­
73,
IV­
D­
166,
and
IV­
D­
175)
cited
a
Senate
report
(
S.
Rep.
No.
228,
101st
Congress
Sess.
171
(
1990))
that
makes
clear
the
intent
of
112(
d)(
4)
as
follows:
"
to
avoid
expenditures
by
regulated
entities
which
serve
no
public
health
or
environmental
benefit,
the
Administrator
is
given
discretionary
authority
to
consider
the
evidence
for
a
health
threshold
higher
than
MACT
at
the
time
the
standard
is
under
review
....
Employing
a
health
threshold
or
safety
level
rather
than
the
MACT
criteria
to
set
standards
shall
not
result
in
adverse
environmental
effects
which
would
otherwise
be
reduced
or
eliminated."
Commenter
IV­
D­
175
added
that
under
this
risk­
based
approach,
EPA
must
select
controls
which
"
provide
the
greatest
protection
to
human
health
(
unless
the
incremental
health
protection
is
negligible
and
there
are
very
significant
environmental
values
that
would
be
afforded
protection
by
some
other
configuration)."
Id.
at
168
(
commenter
emphasis
added).
Commenter
IV­
D­
72
pointed
out
that
Congress
does
not
differentiate
between
technology­
based
"
emission
standards"
set
under
§
112(
d)(
3)
versus
"
health
threshold"
based
199
"
emission
standards"
set
under
§
112(
d)(
4).
Instead,
the
statute
explicitly
treats
emission
standards
promulgated
under
§
§
112(
d)(
3)
and
112(
d)(
4)
as
equivalent
by
not
distinguishing
between
those
emission
standards
under
the
residual
risk
provisions
of
§
112(
f).
The
commenter
stated
that,
in
short,
by
using
the
phrase
"
standards
developed
pursuant
to
subsection
(
d),"
Congress
was
indicating
that
EPA
could
develop
technology­
based
emission
standards
under
§
112(
d)(
3)
OR
health­
based
emission
standards
under
112(
d)(
4).
According
to
the
commenter
there
is
no
indication
under
§
112(
f)
that
emission
standards
must
first
be
technology­
based
and
only
secondarily
health­
or
risk­
based.
Moreover,
by
specifically
referring
to
provision
"
in
effect
before
the
date
of
enactment
of
the
CAAA
of
1990"
and
citing
the
Benzene
NESHAP
(
promulgated
under
the
pre­
1990
§
112),
Congress
appears
to
be
explicitly
approving
the
risk
methodology
set
forth
in
the
D.
C.
Circuit's
Vinyl
Chloride
decision
and
followed
by
EPA
in
the
Benzene
NESHAP.
Commenter
IV­
D­
72
stated
that
this
explicit
approval
provides
definition
of
how
Congress
intended
"
risk,"
and
by
extrapolation,
health­
based
standards,
is
to
be
addressed
under
the
1990
CAA.
Commenter
IV­
D­
75
added
that
EPA
is
permitted
to
establish
alternative
standards
as
long
as
it
ensures
that
ambient
concentrations
are
less
than
the
health
thresholds
plus
a
margin
of
safety
and
the
emissions
do
not
cause
adverse
environmental
effects.
Multiple
commenters
(
IVD
123,
IV­
D­
122,
IV­
D­
07,
IV­
D­
75,
and
IV­
D­
61)
pointed
out
that
EPA
has
exercised
such
authority
and
cited
the
Pulp
and
Paper
MACT.
In
addition,
in
the
Pulp
and
Paper
MACT,
EPA
identified
circumstances
in
which
they
would
decline
to
exercise
112(
d)(
4)
authority
 
where
significant
or
widespread
environmental
harm
would
occur
as
a
result
of
emissions
from
the
category
and
the
estimated
health
thresholds
are
subject
to
substantial
scientific
uncertainty.
The
commenters
stated
that
EPA
determined
that
these
considerations
were
not
relevant
to
emissions
from
the
pulp
and
paper
source
category,
and
the
commenters
believe
that
the
same
is
true
for
their
source
categories
and
that
the
same
treatment
is
warranted
for
many
facilities
within
the
source
categories.
The
commenters
noted
that
facilities
that
cannot
meet
the
risk
criteria
would
remain
subject
to
the
MACT
requirements.
With
regard
to
comments
by
NRDC
that
EPA
may
not
grant
individual
sources
exemptions
from
MACT
standards
because
EPA
must
promulgate
a
MACT­
based
emission
standard
for
the
entire
group
of
sources,
commenter
IV­
D­
123
stated
the
following.
Contrary
to
NRDC's
and
Earthjustice's
comments,
the
risk­
based
approaches
are
squarely
in
line
with
the
plain
meaning
of
§
112(
d)(
4).
The
commenter
pointed
out
that
the
Senate
report
cited
(
Sen
Rep.
No.
228,
101st
Congress,
1st
Sess
175­
6
(
1990))
clearly
indicates
that
Congress
contemplated
that
sources
within
the
same
category
or
subcategory
would
be
subject
to
varied
regulatory
requirements,
depending
on
the
risk
they
pose
to
public
health.
Nothing
in
the
statutory
definition
of
"
emission
standard"
suggests
that
the
term
is
limited
to
a
requirement
for
the
installation
of
control
technology.
The
commenter
believed
the
risk
based
compliance
options
would
meet
this
requirement
because
they
would
apply
to
an
entire
source
category
or
subcategory.
The
commenter
suggested
EPA
could
create
a
subcategory
for
low­
risk
sources
and
tailor
an
emission
standard
to
this
subcategory,
or
apply
to
all
sources
in
the
category
a
NESHAP
containing
multiple
compliance
options,
one
or
more
being
risk­
based.
Finally,
commenter
IV­
D­
23
stated
that
Earthjustice's
comment
that
EPA's
authority
under
§
112(
d)(
4)
is
limited
to
pollutants
and
does
not
empower
EPA
to
exempt
facilities
from
compliance
with
emission
standards
should
be
rejected
for
two
reasons;
1)
§
112(
d)(
4)
pertains
to
development
of
emission
standards
that
apply
to
facilities,
not
to
pollutants,
and
2)
§
112(
d)(
4)
grants
authority
to
develop
standards
that
may
be
less
stringent
than
the
MACT
floor,
which
itself
is
based
on
performance
of
facilities,
not
200
pollutants.
Therefore,
any
exemption
authority
granted
by
§
112(
d)(
4)
must
apply
to
facilities.
Several
commenters
(
IV­
D­
07,
IV­
D­
10,
IV­
D­
61,
IV­
D­
101,
IV­
D­
117,
IV­
D­
123,
IVD
146,
IV­
D­
172,
IV­
D­
179,
and
IV­
D­
186)
believed
that
a
risk­
based
compliance
option
under
§
112(
d)(
4)
is
particularly
appropriate
for
HCl
emissions.
The
commenters
supported
use
of
112(
d)(
4)
for
those
units
that
can
demonstrate
that
they
pose
a
low
risk
to
the
public.
Commenters
IV­
D­
117,
IV­
D­
146,
IV­
D­
172,
and
IV­
D­
179
stated
that
EPA
should
provide
an
exemption
from
HCl
controls
in
cases
where
it
is
demonstrated
that
HCl
emissions
will
not
result
in
air
concentrations
above
the
inhalation
RfC
for
HCl.
Commenters
IV­
D­
186
and
IVD
117
noted
that
public
exposure
to
HCl
should
be
well
below
the
RfC
for
HCl.
Commenter
IVD
117
noted
that
no
unit
risk
estimate
for
HCl
was
mentioned
in
the
proposal,
and
therefore,
use
of
§
112(
d)(
4)
is
justified.
Commenter
IV­
D­
07
believed
that
an
approach
allowing
emissions
limit
exceptions
if
a
de
minimus
health
risk
exists
is
valid
and
asked
that
EPA
consider
allowing
it
for
HCl
emissions
from
wood
waste
boilers.
The
commenter
noted
that
EPA's
112(
d)(
4)
determination
in
the
Pulp
and
Paper
rule
was
based
on
an
Inhalation
RfC
for
HCl
"
defined
as
an
estimate
(
with
an
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
daily
inhalation
exposure
that,
over
a
lifetime,
would
not
likely
result
in
the
occurrence
of
noncancer
health
effects
in
humans."
The
RfC
for
HCl
is
20
micrograms/
cubic
meter.
Based
on
emissions
from
recovery
furnaces
up
to
1,016
tons/
year,
EPA
stated
that
"
at
the
95%
confidence
interval,
the
maximum
concentration
predicted
to
which
people
are
estimated
to
be
exposed
is
0.3

g/
m3,
60
times
less
than
the
inhalation
reference
concentration."
The
commenter
requested
that
EPA
examine
the
rationale
behind
the
1998
decision
not
to
regulate
HCl,
and
supports
EPA's
applicability
cutoff
approach
which
would
allow
any
source
which
can
demonstrate
that
HCl
inhalation
RfC
is
not
exceeded
be
exempted
from
the
proposed
rule.
Commenter
IV­
D­
117
stated
that
EPA
should
use
its
discretion
under
§
112(
d)(
4)
to
recognize
that
there
is
no
need
to
set
emission
limits
for
HCl
because
the
risks
are
well
below
the
RfC.
The
commenter
stated
that
EPA
should
adopt
an
applicability
cutoff
from
HCl
controls
based
on
EPA's
§
112(
d)(
4)
authority
to
exempt
individual
facilities
from
HCl
controls
provided
that
the
facilities
can
demonstrate
that
their
HCl
emissions
do
not
result
in
concentrations
above
the
RfC.
The
commenter
noted
that
no
unit
risk
estimate
for
HCl
was
mentioned
in
the
proposal,
and
therefore,
use
of
§
112(
d)(
4)
is
justified.
Commenters
IV­
D­
62,
IV­
D­
119,
and
IV­
D­
160
submitted
that
EPA
has
concluded
that
HCl
is
a
threshold
pollutant
with
a
well­
defined
health
threshold
and
properly
has
invoked
the
Agency's
§
112(
d)(
4)
authority
in
choosing
not
to
regulate
HCl
emissions
in
prior
NESHAPs.
The
commenters
cited
a
NESHAP
finalized
in
2001,
in
which
the
Agency
exempted
from
regulation
HCl
emissions
from
chemical
recovery
combustion
sources
at
pulp
mills.
In
this
case,
EPA
noted
it
"
has
the
discretion
under
§
112(
d)(
4)
to
develop
risk­
based
standards
for
some
categories
emitting
threshold
pollutants,
which
may
be
less
stringent
than
the
corresponding
`
floor'­
based
MACT
standard
would
be."
The
Agency
found
that
no
further
control
of
HCl
is
necessary
because
"
HCl
levels
emitted
from
recovery
furnaces
are
below
the
threshold
value
within
an
ample
margin
of
safety."
The
commenters
added
that
EPA
similarly
has
proposed
not
to
regulate
HCl
emissions
from
the
Chlorine
Production
source
category.
Commenter
IV­
D­
61
stated
that
EPA
invoked
§
112(
d)(
4)
authority
in
choosing
not
to
impose
control
requirements
on
HCl
emissions
from
chemical
recovery
furnaces
at
pulp
mills
(
40
CFR
part
63,
subpart
MM).
See
63
Fed.
Reg.
18754,
18765
(
April
15,
1998).
Commenters
IV­
D­
122
and
IV­
D­
123
noted
that
in
the
pulp
and
paper
chemical
recovery
furnaces
rule,
EPA
201
was
able
to
make
a
source
category
determination
that
every
source
in
the
category
met
the
criteria
under
§
112(
d)(
4)
for
HCl.
The
commenters
believed
the
large
number
and
variety
of
sources,
coupled
with
the
diverse
use
of
fuels,
in
the
Boiler
MACT
precludes
EPA
from
taking
the
source
category­
wide
approach
that
it
used
in
the
pulp
and
paper
rule.
Commenter
IV­
D­
122
agreed
with
establishing
a
risk­
based
compliance
mechanism
for
HCl.
The
commenter
believed
EPA
has
legal
authority
and
that
such
an
approach
would
reduce
the
economic
impact
of
MACT
on
the
wood
products
industry
and
maximize
environmental
benefits
by
targeting
only
the
HCl
emissions
from
boilers
that
present
a
risk
to
human
health
and
the
environment.
Sources
taking
a
risk­
based
exemption
for
HCl
would
still
have
to
comply
with
limits
for
metals,
mercury
,
and
organics.
The
commenter
noted
that
federally
enforceable
permit
limits
could
ensure
that
emissions
remain
at
low­
risk
levels,
and
that
the
risk­
based
approaches
could
be
structured
in
a
manner
that
does
not
adversely
impact
State
resources.
Commenter
IV­
D­
180
stated
that
EPA
should
exercise
its
considerable
legal
authority
under
the
CAA,
as
detailed
in
the
comments
of
AF&
PA,
to
develop
a
regulatory
approach
to
HCl
(
from
boilers)
that
both
significantly
reduces
the
economic
impact
of
the
rule
on
the
forest
products
industry
and
maximizes
environmental
benefits.
The
commenter
suggested
that
where
facilities
are
able
to
demonstrate
that
emissions
of
HCl
are
below
levels
of
concern,
they
would
take
federally
enforcable
permit
limits
to
ensure
that
emissions
do
not
increase.
Those
facilities,
however,
would
not
be
required
to
install
unnecessary
controls.
Commenter
IV­
D­
174
stated
that
the
case
for
exempting
boilers
and
process
heaters
that
fire
solid
fuels
other
than
coal
(
and
a
number
of
coal­
fired
units)
is
at
least
as
strong
as
the
case
for
exempting
pulp
and
paper
industry
combustion
sources
under
§
112(
d)(
4).
The
commenter
urged
EPA
to
use
its
§
112(
d)(
4)
authority
to
avoid
forcing
many
facilities
to
install
costly,
energy
ineffecient
control
equipment
that
will
serve
no
useful
purpose
in
terms
of
reducing
risks
to
human
health
and
the
environment.
Commenters
IV­
D­
73
and
IV­
D­
166
suggested
that
EPA
develop
risk­
based
emission
standards,
particularly
for
emissions
of
HCl.
Under
§
112(
d)(
4),
Congress
authorized
EPA
to
consider
risk­
based
endpoints
when
setting
NESHAP
for
threshold
HAP.
HCl
is
a
threshold
HAP
and
one
that
generally
presents
little
risk
to
the
public
or
the
environment
when
emitted
from
boilers
and
process
heaters,
as
shown
by
modeling
conducted
by
the
commenter.
Commenter
IV­
D­
49
approved
of
a
risk­
based
compliance
approach
under
CAA
§
112(
d)(
4)
as
particularly
appropriate
for
emissions
of
HCl.
The
commenter
observed
that
EPA
had
previously
invoked
its
CAA
§
112(
d)(
4)
authority
to
address
low­
risk
sources
of
HCl,
and
felt
that
the
boiler
source
category
was
a
particularly
appropriate
candidate
for
a
risk­
based
approach.
The
commenter
noted
that
the
BSCP
MACT,
as
signed
by
the
Administrator,
did
not
include
the
risk­
based
approach,
and
urged
EPA
to
fully
consider
the
concept
of
risk­
based
approaches
in
the
boiler
MACT
and
other
MACT
rules
and
to
provide
such
an
approach
in
the
final
boiler
rule.
The
commenter
believed
that
the
risk­
based
approach
would
provide
an
optimal
means
to
meet
EPA's
goals
for
the
MACT
program
without
unintended
consequences
to
the
environment,
the
community,
and
the
source
that
accompany
a
default
emissions
standard.
Commenter
IV­
D­
49
provided
several
benefits
of
a
risk­
based
approach.
The
commenter
submitted
that
a
risk­
based
approach
would
provide
a
means
to
address
communities
desires
to
avoid
the
perception
of
pollution
associated
with
a
visible
steam
plume,
ensure
that
HCl
emissions
are
below
established
health
thresholds,
and
achieve
the
goals
of
the
MACT
rule
in
a
considerably
less
costly
manner.
Commenter
IV­
D­
49
provided
a
case
example
of
how
the
risk­
based
approach
would
be
202
appropriate
on
a
site­
specific
basis,
and
could
provide
the
community,
environment,
and
regulated
source
a
better
outcome
than
would
be
achieved
if
the
approach
were
not
provided
in
the
final
rule.
The
commenter
operates
a
boiler
in
Tacoma,
Washington
that
is
used
to
provide
process
steam
by
combusting
wood
by­
products.
Under
the
proposed
regulation,
the
boiler
would
be
subject
to
the
HCl
emissions
standard
proposed
in
Table
1
to
Subpart
DDDDD.
To
assure
compliance
with
the
proposed
HCl
standard,
the
commenter
might
have
to
install
additional
costly
control
equipment
that
would
create
a
visible
steam
plume
(
re­
adding
a
plume
to
the
Tacoma
skyline
and
waterfront
that
was
eliminated
over
a
decade
ago
with
strong
community
support),
and
would
add
500,000
gallons
per
day
to
the
mill's
water
consumption.
The
commenter
related
that
the
boiler
began
operation
in
1991,
replacing
an
older
boiler
with
significantly
higher
PM
emissions.
The
installation
of
the
boiler
and
electrostatic
precipitator
(
ESP)
resulted
in
the
biggest
single
improvement
in
Tacoma's
air
quality
in
over
a
decade
and
was
fundamental
in
Tacoma
achieving
the
National
Ambient
Air
Quality
Standards
(
NAAQS)
for
PM10.
Commenter
IV­
D­
143
strongly
supported
adoption
of
a
risk­
based
compliance
mechanism
for
HCl
under
EPA's
§
112(
d)(
4)
authority.
The
commenter
noted
that
facilities
that
are
able
to
demonstrate
their
emissions
do
not
present
a
risk
to
human
health
or
the
environment
should
not
be
required
to
install
costly
controls
as
would
otherwise
be
required
under
the
MACT
standards.
The
commenter
felt
that
the
final
rule
should
include
provisions
for
facilities
to
use
an
approved
EPA
method
such
as
dispersion
modeling
to
demonstrate
that
ambient
concentrations
of
HCl
are
below
a
risk­
based
emission
standard
and
therefore
be
exempted
from
the
emission
control
and
monitoring
requirements
under
the
MACT
standards.
Commenter
IV­
D­
173
strongly
supported
the
proposed
applicability
cutoffs
for
HCl
under
EPA's
112
(
d)(
4)
authority
since
the
available
data
suggest
that
a
significant
proportion
of
industrial
boilers
and
process
heaters
do
not
emit
HCl
in
an
amount
that
would
result
in
exceedance
of
applicable
health
benchmarks.
The
commenter
believed
that
incorporating
this
option
into
the
final
rule
would
provide
significant
cost
savings
by
foregoing
the
requirement
for
add­
on
controls
on
boilers
and
process
heaters
whose
emissions
do
not
result
in
HCl
concentrations
the
exceed
health
benchmarks.
Commenter
IV­
D­
14
disagreed
that
§
112(
d)(
4)
can
be
interpreted
to
allow
exemption
of
individual
pollutants
(
i.
e.,
HCl).
Commenter
IV­
D­
135
contended
that
alternative
scenarios
concerning
HCl
cutoffs
constitute
impermissible
attempts
to
circumvent
the
control
requirements
for
HCl.
Under
another
applicability
cutoff
scenario,
the
Agency
suggested
that
any
threshold
HAP
eligible
for
exemption
under
CAA
§
112(
d)(
4)
that
are
controlled
by
control
devices
different
from
those
controlling
non­
threshold
HAP
would
still
be
able
to
use
the
applicability
cutoff.
This
scenario
represented
an
illegal
attempt
to
circumvent
the
control
requirements
for
HCl
altogether,
and
ignored
the
case
law
holding
that
standard
setting
under
§
112(
d)
is
not
limited
to
consideration
of
particular
control
technologies.
[
See
Cement
Kiln
Recycling
Coalition
v.
EPA,
255
F.
3D
855
(
D.
C.
Cir.
2001)].
Many
of
the
nonthreshold
pollutants
are
metals
that
would
be
controlled
by
particulate
matter
controls.
Other
nonthreshold
HAPs
are
organic
emissions
for
which
the
Agency
proposed
a
"
no
control"
MACT
floor.
HCl,
on
the
other
hand,
would
need
to
be
controlled
by
a
scrubber.
If
finalized,
this
exemption
would
potentially
allow
59
percent
of
the
emissions
from
this
source
category
to
go
uncontrolled
(
assuming
that
the
Agency
could
successfully
contrive
an
exposure
modeling
approach
that
would
result
in
exposures
less
than
the
RfC).
The
commenter
believed
that
exempting
HCl
emissions
from
control
is
unacceptable,
particularly
since
EPA
proposed
HCl
as
a
surrogate
measure
for
all
the
inorganic
HAP
emitted
by
this
source
category.
Hence,
an
203
exemption
that
excluded
HCl
emission
points
from
control
requirements
would
also
exclude
emissions
of
all
the
other
inorganic
HAP
that
would
likely
include
hydrogen
cyanide
and
hydrogen
fluoride.
Multiple
commenters
(
IV­
D­
05,
IV­
D­
14,
IV­
D­
96,
IV­
D­
113,
IV­
D­
135,
and
IV­
D­
148)
stated
that
the
plain
meaning
of
§
112(
d)(
4)
does
not
allow
EPA
to
make
MACT
standard
exemptions
for
individual
sources.
Commenters
IV­
D­
05
and
IV­
D­
148
believe
that
§
112(
d)(
4)
applies
to
categories
of
sources.
Commenters
IV­
D­
96
and
IV­
D­
135
noted
that
§
112(
d)(
4)
states
that
"
with
respect
to
pollutants
for
which
a
health
threshold
has
been
established,
the
Administrator
may
consider
such
threshold
level,
with
ample
margin
of
safety,
when
establishing
emission
standards
under
this
subsection."
Commenter
IV­
D­
96
stated
that
the
plain
language
of
the
CAA
specifies
that
EPA
cannot
refuse
to
set
emission
standards
for
listed
sources.
The
commenter
contended
that
it
is
unlawful
to
refuse
to
set
an
emission
standard
for
a
group
of
sources
that
are
part
of
a
listed
source
category.
The
EPA
must
establish
emission
standards
that
apply
to
a
whole
listed
source
category.
Section
112(
d)(
4)
only
gives
EPA
authority
to
"
consider"
an
established
health
threshold
in
establishing
emission
standards.
The
commenter
believed
that
the
section
does
not
give
EPA
the
ability
to
waive
standards
altogether
because
the
provision
is
only
available
"
when
establishing
emission
standards
under
this
subsection."
The
U.
S.
Court
of
Appeals
for
the
D.
C.
Curcuit
has
squarely
held
that
EPA
was
not
allowed
to
make
a
"
no
control"
determination
for
a
pollutant
emitted
by
a
listed
source
category
(
National
Lime
Ass'n
v.
EPA,
233
F.
3D
625,
633­
34
(
D.
C.
Cir
2000)).
Commenter
IV­
D­
96
also
stated
that
subsection
112(
d)
directs
the
Administrator
to
establish
emission
standards
"
for
each
category
or
subcategory"
of
sources,
not
for
each
individual
source.
In
setting
a
schedule
for
developing
112(
d)
regulations,
subsection
112(
e)
makes
clear
that
the
deadlines
are
for
the
establishment
of
emission
standards
"
for
categories
and
subcategories
of
sources,"
not
for
individual
sources.
The
commenter
continued
that
while
subsection
112(
j)
authorizes
a
permitting
authority
to
establish
HAP
emission
limitations
specific
to
a
single
source,
the
authorization
applies
only
if
the
Administrator
has
not
yet
promulgated
emission
standards
for
the
category
to
which
the
source
belongs.
The
commenter
believed
therefore,
that
the
effect
of
the
phrase,
"
when
establishing
emission
standards
under
this
section,"
is
to
limit
subsection
112(
d)(
4)'
s
authorization
to
instances
in
which
the
Administrator
is
establishing
an
emission
standard
for
an
entire
category
or
a
subcategory
of
sources.
Commenter
IV­
D­
96
added
that
the
only
time
§
112
mentions
individualized
standard
setting
is
under
the
"
MACT
hammer"
provisions
in
§
112(
j).
The
specific
language
used
by
Congress
in
§
112(
j)
shows
that
had
Congress
wished
to
create
authority
to
establish
individualized
exemptions,
it
would
have
included
similarly
precise
language
in
subsection
112(
d)(
4).
Commenter
IV­
D­
96
stated
further
that
§
112(
d)(
4)
authorizes
the
Administrator
alone
to
consider
health
thresholds,
and
only
when
she
is
establishing
emission
standards
for
an
entire
category
or
subcategory
of
sources,
and
therefore,
EPA
cannot
rely
on
112(
d)(
4)
to
allow
permitting
authorities
to
approve
"
applicability
cutoffs"
that
are
less
stringent
than
MACT.
Commenter
IV­
D­
135
asserted
that
the
establishment
of
applicability
cutoffs
for
threshold
and
nonthreshold
pollutants
based
on
§
112(
d)(
4)
of
the
CAA
is
contrary
to
law.
The
commenter
claimed
the
CAA
does
not
authorize
EPA
to
finalize
any
of
the
three
applicability
cutoff
scenarios
described
in
the
proposal
preamble
as
alternatives
to
a
MACT
standard
from
the
source
category.
Commenter
IV­
D­
135
claimed
that
when
a
source
category
is
listed,
the
Agency
must
establish
204
emission
standards
that
apply
to
the
whole
category
and
cites
the
language
of
sections
112(
c)(
1)
and
(
d)(
1).
The
commenter
asserted
the
statutory
language
clearly
mandates
that
EPA
set
emissions
standards
for
HAPs
from
all
categories
and
subcategories,
even
for
those
pollutants
with
established
health
thresholds.
Commenter
IV­
D­
135
pointed
out
that
because
of
the
plain
statutory
language,
the
U.
S.
Court
of
Appeals
for
the
D.
C.
Circuit
has
squarely
held
that
EPA
was
not
allowed
to
make
a
"
no
control"
determination
for
a
pollutant
emitted
by
a
listed
category
of
sources
[
National
Lime
Ass'n
v.
EPA,
233
F.
3D
625,
633­
34
(
D.
C.
Cir.
2000)].
The
commenter
asserted
that
given
the
weight
of
legal
authority
requiring
EPA
to
establish
emissions
standards
for
HAPs
from
all
sources,
the
agency
cannot
finalize
the
applicability
cut­
off
approach
without
first
providing
some
legal
rationale
for
its
reinterpretation
of
§
112(
d)(
4).
Commenter
IV­
D­
14
believed
that
EPA
has
misinterpreted
the
provision
in
112(
d)(
4).
Section
112(
d)(
4)
does
not
state
that
EPA
can
use
applicability
thresholds
"
in
lieu
of"
the
§
112(
d)(
3)
MACT
floor
requirements.
The
commenter
interpreted
§
112(
d)(
4)
to
state
that
health
based
thresholds
can
be
considered
when
establishing
the
degree
of
the
MACT
floor
requirements,
but
it
should
not
be
used
to
supplant
the
requirements
established
pursuant
to
§
112(
d)(
3).
Commenters
IV­
D­
96,
IV­
D­
113,
and
IV­
D­
135
stated
that
the
legislative
history
of
§
112(
d)(
4)
clearly
rejects
EPA's
proposed
facility­
by­
facility
MACT
exemptions.
The
commenters
noted
that
Congress
considered
and
rejected
the
applicability
cutoffs
upon
which
EPA
now
solicits
comment.
The
House
version
of
the
1990
Amendments
allowed
States
to
issue
permits
that
exempted
a
source
from
compliance
with
MACT
rules
if
the
source
presented
sufficient
evidence
to
demonstrate
negligible
risk.
The
Senate
version
of
the
1990
Amendments
contained
no
such
provision.
The
commenters
pointed
out
that
in
conference,
Congress
considered
both
the
House
and
Senate
versions
and
rejected
the
House
bill's
exemption
for
specific
facilities
in
favor
of
the
Senate
bill's
language.
Commenter
IV­
D­
96
also
noted
that
the
conference
report
on
the
1990
CAAA
states,
"[
i]
t
is
the
conferees'
intent
that
EPA
not
use
the
permit
hammer
approach
(
case­
by­
case)
to
avoid
or
delay
meeting
MACT
requirements."
Thus,
Congress
expressed
desire
for
a
category­
based
approach
to
MACT
standard
setting
rather
than
a
time­
consuming
and
delay­
inducing
facility­
byfacility
approach.
Commenter
IV­
D­
96
also
pointed
out
that
in
describing
§
112,
Senator
Durenberger
explained
on
the
floor
that
managers
were
unhappy
with
EPA's
practice
under
§
111
"
of
establishing
cutoffs
that
result
in
excluding
some
sources
within
a
category
or
subcategory
from
the
emission
limitations
or
control
measures
otherwise
required."
Thus,
Senator
Durenberger
clearly
recognized
that
individualized
exemptions
from
a
MACT
standard
could
create
an
uneven
playing
field
for
the
industry.
The
commenter
believed
that
reading
§
112(
d)(
4)
as
EPA
suggests
leads
to
uneven
and
unfair
treatment
of
very
similar
sources
and
contradicts
Congress's
wish
that
facilities
be
regulated
on
a
categorical
basis
rather
than
on
an
individual
basis.
Commenter
IV­
D­
96
further
stated
that
the
legislative
history
for
the
CAA
shows
that
§
112(
d)(
4)
cannot
be
a
basis
for
non­
applicability.
Both
Houses
of
Congress
put
forward
riskbased
exemptions
from
HAP
standards
but
chose
not
to
adopt
them.
The
commenter
pointed
out
that
emission
standards
under
§
112
apply
to
"
major
sources"
which
emit
in
excess
of
10
tpy
of
a
given
HAP.
A
prior
version
of
the
bill
would
have
allowed
EPA
to
decline
to
regulate
higherpolluting
sources
if
they
emitted
threshold
pollutants.
The
fact
that
this
provision
did
not
become
law
indicated
to
the
commenter
that
the
current
CAA
does
not
permit
EPA
to
avoid
regulating
facilities
by
pointing
to
evidence
of
a
health
threshold.
The
Senate
bill
would
have
allowed
EPA
205
to
set
a
size
cutoff
higher
than
10
tpy
for
categories
of
sources
emitting
threshold
pollutants
(
See
S.
1630,
101st
Cong.,
1st
Sess.,
§
301
(
amending
section
112(
c)(
5)).
A
Senate
report
explaining
the
provision
said
"
under
section
112(
c)(
5)
the
Administrator
may
set
a
lower
boundary
for
the
category
of
major
sources
which
is
higher
than
10
tons
per
year
(
but
which
provides
an
ample
margin
of
safety
to
protect
public
health).
If
there
are
no
sources
emitting
the
pollutant
in
that
amount
in
a
particular
category,
then
no
regulation
under
section
112(
d)
need
be
promulgated."
(
S.
Rep.
101­
228,
101st
Cong.,
1st
Sess.
at
176
(
1989))
The
commenter
also
noted
that
during
the
1990
CAAA
debate,
the
House
bill
would
have
allowed
individual
facilities
to
escape
MACT
if
a
risk
analysis
showed
that
the
source
posed
a
negligible
hazard.
However,
this
proposal
was
not
in
the
Senate
bill,
and
the
conference
rejected
the
idea
for
the
final
legislation.
(
See
1
Legislative
History
at
866
(
Statement
from
Senator
Durenberger)
("
The
authority
for
such
exemptions
was
not
present
in
the
Senate
bill,
and
the
House
receded
to
the
Senate
on
this
point.
The
provision
was
deleted
in
conference.").
Commenter
IV­
D­
135
submitted
that
Congress
did
not
require
EPA
to
consider
the
evidence
of
a
health
threshold
in
setting
standards
under
§
112.
The
legislative
history
states
the
following:
The
Administrator
is
not
required
to
take
the
evidence
of
a
health
threshold
into
account;
that
would
jeopardize
the
standard­
setting
schedule
imposed
under
this
section
with
the
kind
of
lengthy
study
and
debate
that
has
crippled
the
current
program.
But
where
health
thresholds
are
well­
established,...
and
the
pollutant
presents
no
risk
of
other
adverse
health
effects,
including
cancer,
for
which
no
threshold
can
be
established,
the
Administrator
may
use
the
threshold
with
an
ample
margin
of
safety
(
and
not
considering
cost)
to
set
emissions
limitations
for
sources
in
the
category
or
subcategory.
[
S.
Rep.
101­
228
at
171].
Commenter
IV­
D­
96
also
noted
AF&
PA's
argument
in
its
supplemental
comments
on
the
BSCP
rulemaking
(
see
Docket
A­
99­
30,
Item
IV­
G­
5)
that
risk­
based
exemptions
are
lawful
because
the
CAA
directs
EPA
to
consider
health
risk
in
establishing
the
order
of
source
categories
to
regulate
and
to
perform
residual
risk
evaluations.
The
commenter
stated
that
Congress
knew
how
to
authorize
risk­
based
decisionmaking
when
that
is
what
it
wanted
to
do
(
e.
g.,
establishing
order
of
source
categories
for
regulation
and,
consideration
of
residual
risk).
The
commenter
concluded
that
had
Congress
wanted
to
authorize
or
direct
EPA
to
exempt
facilities
from
the
MACT
requirement
on
the
basis
of
case­
by­
case
risk
assessments,
it
would
have
done
so.
Commenter
IV­
D­
96
added
that
EPA
has
itself
insisted
in
briefs
filed
in
federal
courts
that
the
CAA
does
not
permit
EPA
to
temper
MACT
requirements
on
the
basis
of
risk
assessments.
For
instance,
EPA
has
declared
that
"
risk
reduction
is
not
a
factor
to
be
considered
in
developing
standards
under
section
112(
d),"
and
that
"[
t]
he
legislative
history
confirms
that
risk
assessments
cannot
be
used
to
lessen
the
stringency
of
MACT
standards."
[
EPA
Brief
as
Respondent
in
Cement
Kiln
Recycling
Coalition
v.
Browner,
D.
C.
Circuit
Case
No.
99­
1457,
January
18,
2001,
at
99
(
Attachment
1
to
IV­
D­
96).
EPA
Brief
as
Respondent
in
Copper
MACT
Case,
March
6,
2003,
at
36­
36
(
Attachment
2
to
IV­
D­
96).]
Commenter
IV­
D­
96
disagreed
with
AF&
PA's
argument
that
legislative
history
supports
individual
exemptions
from
MACT
standards.
The
commenter
repeated
the
Senate
Report
passage
quoted
in
AF&
PA's
white
paper:
"
The
Administrator
is
authorized
by
Section
112(
d)(
4)
to
use
the
no
observable
effects
level
(
NOEL)
(
again
with
an
ample
margin
of
safety)
as
the
emission
limitation
in
lieu
of
more
stringent
best
technology
requirements.
Following
this
206
scenario,
only
those
sources
in
the
category
which
present
a
risk
to
public
health
(
those
emitting
in
amounts
greater
than
the
safety
threshold)
would
be
required
to
install
controls,
even
though
the
general
policy
is
"
maximum
achievable
technology"
everywhere."
Commenter
IV­
D­
96
stated
that
this
passage
does
nothing
more
than
grant
EPA
the
authority
to
set
a
category­
wide
emission
standard
more
or
less
stringent
than
MACT
based
on
health
risk.
The
statement
also
clarifies
that
facilities
able
to
meet
an
emission
standard
(
whether
MACT­
or
threshold­
based)
without
installing
controls
need
not
install
controls.
Commenter
IV­
D­
96
stated
that
each
of
the
three
scenarios
proposed
by
EPA
(
exempt
low
risk
facilities
emitting
only
threshold
pollutants;
allow
112(
d)(
4)
for
threshold
and
non­
threshold
pollutants;
and
exempt
emission
points
at
a
facility
that
emit
only
threshold
pollutants)
are
unlawful.
The
third
scenario
is
unlawful
because
there
is
no
statutory
provision
within
the
CAA
that
could
be
read
to
authorize
emission
point­
by­
point
exemption.
Response:
We
believe
that
we
have
properly
exercised
the
authority
granted
to
us
pursuant
to
§
112(
d)(
4)
of
the
CAA
in
establishing
health­
based
emission
standards
for
HCl
and
Mn
which
are
applicable
to
the
large
solid
fuel­
fired
subcategories.
We
believe
that
§
112(
d)(
4)
authorizes
us
to
by­
pass
the
mandate
in
§
112(
d)(
3)
in
appropriate
circumstances.
Those
circumstances
are
present
in
the
large
solid
fuel­
fired
Boiler
subcategories.
Section
112(
d)(
4)
provides
us
with
authority,
at
our
discretion,
to
develop
health­
based
emission
standards
for
HAP's
"
for
which
a
health
threshold
has
been
established",
provided
that
the
standard
reflects
the
health
threshold
"
with
an
ample
margin
of
safety."
(
The
full
text
of
the
§
112(
d)(
4):
"[
w]
ith
respect
to
pollutants
for
which
a
health
threshold
has
been
established,
the
Administrator
may
consider
such
threshold
level,
within
an
ample
margin
of
safety,
when
establishing
emission
standards
under
this
subsection.")
We
presumptively
apply
§
112(
d)(
4)
only
to
HAP's
that
are
not
carcinogens
because
Congress
clearly
intended
that
carcinogens
be
considered
nonthreshold
pollutants.
(
Staff
of
the
Senate
Committee
on
Environment
and
Public
Works,
A
Legislative
History
of
the
Clean
Air
Act
Amendments
of
1990,
Vol.
1
at
876,
statement
of
Senator
Durenberger
during
Senate
Debate
of
October
27,
1990:
"
With
respect
to
the
pollutants
for
which
a
safe
threshold
can
be
set,
the
authority
to
set
a
standard
less
stringent
than
maximum
achievable
control
technology
is
contained
in
subsection
(
d)(
4).
With
respect
to
carcinogens
and
other
non­
threshold
pollutants,
no
such
authority
exists
in
subsection
(
d)
or
in
any
other
provision
of
the
Act.")
The
legislative
history
further
indicates
that
if
we
invoke
this
provision,
we
must
assure
that
any
emission
standard
results
in
ambient
concentrations
less
than
the
health
threshold,
with
an
ample
margin
of
safety,
and
that
the
standards
must
also
be
sufficient
to
protect
against
adverse
environmental
effects
(
S.
Rep.
No.
228,
101st
Cong.
at
171).
(
Section
112(
a)(
7)
of
the
CAA
defines
the
term
"
adverse
environmental
effect"
as
"
any
significant
and
widespread
adverse
effect,
which
may
reasonably
be
anticipated,
to
wildlife,
aquatic
life,
or
other
natural
resources,
including
adverse
impacts
on
populations
of
endangered
or
threatened
species
or
significant
degradation
of
environmental
quality
over
broad
areas.)
Costs
are
not
to
be
considered
in
establishing
a
standard
pursuant
to
§
112(
d)(
4)
(
Ibid.).
Both
the
plain
language
of
§
112(
d)(
4)
and
the
legislative
history
cited
above
indicate
that
we
have
the
discretion
under
§
112(
d)(
4)
to
develop
health­
based
standards
for
some
source
categories
emitting
threshold
pollutants,
and
that
those
standards
may
be
less
stringent
than
the
corresponding
"
floor"­
based
MACT
standard
would
be.
We
do
not
believe
that
our
use
of
such
standards
is
limited
to
situations
where
every
affected
source
in
the
category
or
subcategory
can
comply
with
them.
As
is
the
case
with
technology­
based
standards,
a
particular
affected
source's
207
ability
to
comply
with
a
health­
based
standard
will
depend
on
it's
individual
circumstances,
as
will
what
it
must
do
to
achieve
compliance.
In
developing
health­
based
emission
standards
under
§
112(
d)(
4),
we
seek
to
assure
that
those
standards
ensure
that
the
concentration
of
the
particular
HAP
to
which
an
individual
exposed
at
the
upper
end
of
the
exposure
distribution
is
exposed
does
not
exceed
the
health
threshold.
The
upper
end
of
the
exposure
distribution
is
calculated
using
the
"
high
end
exposure
estimate,"
defined
as
"
a
plausible
estimate
of
individual
exposure
for
those
persons
at
the
upper
end
of
the
exposure
distribution,
conceptually
above
the
90th
percentile,
but
not
higher
than
the
individual
in
the
population
who
has
the
highest
exposure"
(
EPA
Exposure
Assessment
Guidelines,
57
FR
22888,
May
29,
1992).
We
believe
that
assuring
protection
to
persons
at
the
upper
end
of
the
exposure
distribution
is
consistent
with
the
"
ample
margin
of
safety"
requirement
in
§
112(
d)(
4).
Regarding
the
comment
that
an
exemption
that
excluded
HCl
emission
points
from
control
requirements
would
also
exclude
emissions
of
all
other
inorganic
HAP
that
would
likely
include
hydrogen
cyanide
and
hydrogen
fluoride,
affected
facilities
attempting
to
utilize
the
health­
based
alternative
compliance
option
for
HCl
will
be
required
to
evaluate
emissions
of
HAP
in
addition
to
HCl.
We
conducted
an
assessment
of
boiler
emissions
and
determined
that,
of
the
acid
gas
HAP
controlled
by
scrubbing
technology,
Cl
2
is
responsible
for
the
great
majority
of
risk
and
HCl
is
responsible
for
the
next
largest
portion
of
the
total
risk.
The
contributions
of
other
HAP,
including
hydrogen
fluoride,
to
the
total
risk
were
negligible.
Therefore,
affected
facilities
attempting
to
utilize
the
health­
based
alternative
compliance
option
for
HCl,
either
by
conducting
a
look­
up
table
analysis
or
by
conducting
a
site­
specific
risk
assessment,
must
include
emission
rates
of
Cl
2
and
HCl
from
their
boilers.
We
do
not
expect
hydrogen
cyanide
emissions
from
boilers
covered
under
the
final
rule.
We
emphasize
that
use
of
§
112(
d)(
4)
authority
is
wholly
discretionary.
As
the
legislative
history
described
above
indicates,
cases
may
arise
in
which
other
considerations
dictate
that
the
Agency
should
not
invoke
this
authority
to
establish
less
stringent
standards,
despite
the
existence
of
a
health
effects
threshold
that
is
not
jeopardized.
For
instance,
we
do
not
anticipate
that
we
would
set
less
stringent
standards
where
the
estimated
health
threshold
for
a
contaminant
is
subject
to
large
uncertainty.
Thus,
in
considering
appropriate
uses
of
our
discretionary
authority
under
§
112(
d)(
4),
we
consider
other
factors
in
addition
to
health
thresholds,
including
uncertainty
and
potential
"
adverse
environmental
effects,"
as
that
phrase
is
defined
in
§
112(
a)(
7).
We
agree
that
§
112(
d)(
4)
is
appropriate
for
establishing
emission
standards
for
HCl
and
Mn
applicable
to
the
large
solid
fuel­
fired
Boiler
subcategories,
and
therefore
we
have
established
such
standards
as
health­
based
compliance
alternatives
for
affected
sources
in
those
subcategories.
Affected
sources
in
the
large
solid
fuel­
fired
Boiler
subcategories
which
believe
that
they
can
demonstrate
compliance
with
one
or
both
of
the
health­
based
emission
standards
may
choose
to
comply
with
those
standards
in
lieu
of
the
otherwise
applicable
MACT­
based
standard.

18.2.2
Health­
based
approaches
as
emission
standards
Comment:
Commenters
IV­
D­
61,
IV­
D­
122,
and
IV­
D­
123
stated
that
the
risk­
based
approaches
can
be
implemented
as
an
"
emission
standard"
within
the
statutory
definition
of
the
term.
The
commenters
stated
that
the
risk­
based
approaches
being
considered
by
EPA
can,
and
should,
be
implemented
as
compliance
options,
rather
than
outright
exemptions
from
MACT
standard
applicability.
This
approach
fits
with
the
statutory
definition
of
"
emission
standard"
and
208
"
emission
limitation"
as
used
in
§
112.
Nothing
in
the
definition
equates
"
emission
standard"
with
the
requirement
to
install
control
technology.
If
the
risk­
based
approach
is
implemented
as
a
compliance
option,
then
the
"
emission
standard"
set
by
EPA
would
be
the
emission
rate
that
corresponds
with
the
concentration
of
HAP
at
the
property
line
that
is
below
the
health
benchmark
for
threshold
HAPs,
and
below
the
one
in
a
million
risk
level
for
non­
threshold
carcinogens.
Commenters
IV­
D­
61,
IV­
D­
122,
and
IV­
D­
123
stated
that
EPA's
implementation
of
the
risk­
based
approach
as
a
compliance
option
clearly
would
meet
the
statutory
definitions
of
"
emission
limitation"
and
"
emission
standard"
(
defined
identically
by
CAA
§
302(
k))
by
placing
federally­
enforceable
limitations
on
facility
HAP
emissions.
That
this
cap
would
be
based
on
correlations
with
risk­
based
property
line
concentrations
does
nothing
to
detract
from
this
conclusion.
Commenters
IV­
D­
122
and
IV­
D­
123
added
that
the
risk
based
approaches
are
not
an
attempt
to
"
refuse
to
set
an
emission
standard."
The
commenters
asserted
that
an
emission
standard
is
not
a
requirement
to
install
control
technology
­
but
rather
a
term
defined
in
the
CAA
as
a
limitation
on
the
quantity,
rate,
or
concentration
of
emissions
of
air
pollutants.
EPA's
implementation
of
risk­
based
approaches
as
compliance
options
would
meet
the
statutory
definition
of
emission
limitations.
The
commenters
stated
that
NRDC
acknowledges
that
facilities
able
to
meet
an
emission
standard
(
whether
MACT­
based
or
threshold­
based)
without
installing
controls
should
not
install
controls.
Commenter
IV­
D­
75
stated
that
risk­
based
alternatives
are
not
exemptions
but
will
function
as
indirect
emission
limits
that
must
be
maintained
by
the
facilities
to
assure
that
the
criteria
are
met,
and,
thus,
such
alternatives
for
low­
risk
facilities
are
supportable
by
EPA's
authority
under
§
112(
d)(
4)
and
112(
c)(
9)
of
the
CAA
and
EPA's
inherent
de
minimis
authority.
Commenter
IV­
D­
96
disagreed
that
risk­
based
approaches
can
function
as
emission
standards.
The
commenter
pointed
out
that
AF&
PA
asserts
for
the
first
time
in
its
supplemental
comments
on
the
BSCP
rule
(
see
Docket
A­
99­
30,
Item
IV­
G­
5)
that
the
risk­
based
approaches
it
advocates
are
"
compliance
options,
rather
than
outright
exemptions
from
the
MACT
standard."
This
creative
packaging
fails
to
hide
the
unlawful
shape
of
AF&
PA's
suggested
approaches.
Section
112(
d)(
2)
mandates
MACT
emission
standards
for
each
HAP
source
category
and
subcategory.
Neither
AF&
PA
nor
EPA
has
offered
any
evidence
that
could
support
the
notion
that
a
source
whose
emissions
are
below
a
"
risk­
based
emission
standard"
is
achieving
MACT
for
the
source's
category.
Subsection
112(
d)(
4)
permits
EPA
to
consider
an
established
health
threshold
for
a
particular
HAP
when
setting
an
emission
standard
for
that
HAP
in
a
particular
source
category.
But
nothing
in
either
subsections
112(
d)(
2)
or
(
d)(
4)
even
implies
the
authority
to
promulgate,
for
a
single
HAP,
different
emission
standards
for
different
facilities
within
the
same
source
subcategory.
Response:
As
is
explained
in
the
previous
response
in
this
section,
we
believe
that
we
have
properly
exercised
the
authority
granted
to
us
pursuant
to
§
112(
d)(
4)
of
the
CAA
in
establishing
health­
based
emission
standards
for
HCl
and
Mn
which
are
applicable
to
the
large
solid
fuel­
fired
subcategories.
We
believe
that
§
112(
d)(
4)
authorizes
us
to
by­
pass
the
mandate
in
§
112(
d)(
3)
in
appropriate
circumstances.
Those
circumstances
are
present
in
the
large
solid
fuelfired
Boiler
subcategories.

18.2.3
Section
112(
d)(
4)
Authority
for
Carcinogens
and
Non­
Carcinogens
209
Comment:
Many
commenters
(
IV­
D­
72,
IV­
D­
75,
IV­
D­
108,
IV­
D­
172,
and
IV­
D­
175)
supported
the
use
of
§
112(
d)(
4)
applicability
cutoffs
for
both
threshold
and
non­
threshold
pollutants.
Comenter
IV­
D­
172
stated
that
nothing
in
§
112(
d)(
4)
limits
it
to
non­
carcinogens,
and
EPA
should
consider
112(
d)(
4)
whenever
it
sets
emission
standards
for
HAP
regardless
of
health
endpoint.
Commenter
IV­
D­
172
added
that
advances
in
risk
assessment
science
indicate
that
some
carcinogens
may
be
threshold
pollutants.
Commenters
IV­
D­
72,
IV­
D­
75,
IV­
D­
108,
and
IV­
D­
172
believe
that
a
health
threshold
of
one
in
one
million
cancer
risk
is
appropriate
for
non­
threshold
pollutants.
Commenter
IV­
D­
108
added
that
a
HI
would
need
to
be
calculated
to
include
all
pollutants
emitted
by
a
boiler
or
process
heater
for
that
unit
to
be
added
to
the
subcategory
that
would
be
delisted.
Commenter
IV­
D­
03
agreed
with
Hunton
&
Willams
(
on
behalf
of
the
UARG,
IV­
D­
186)
that
the
EPA
failed
to
utilize
its
authority
to
establish
a
health
threshold
for
setting
MACT
standards
for
carcinogens
and
non­
carcinogens.
Commenter
IV­
D­
10
stated
that
EPA
should
use
the
latest
science
with
regard
to
thresholds
for
compounds
that
EPA
has
traditionally
viewed
as
non­
threshold.
Commenter
IV­
D­
75
stated
that
the
language
in
112(
d)(
4)
does
not
limit
EPA's
ability
to
set
emission
standards
to
only
threshold
pollutants
but
states
that
"[
w]
ith
respect
to
pollutants
for
which
a
health
threshold
has
been
established,
the
Administrator
may
consider
such
threshold..."
Rather,
EPA
may
issue
standards
for
any
pollutant
for
which
a
threshold
may
be
established.
For
non­
threshold
carcinogens,
EPA
could
use
112(
d)(
4)
authority
and
could
establish
a
"
threshold"
risk
of
one
in
one
million.
Such
a
de
facto
threshold
is
supported
by
the
use
of
one
in
one
million
as
the
presumptive
acceptable
risk
for
both
the
delisting
process
in
§
112(
c)(
9)
and
in
the
residual
risk
program
under
§
112(
f).
The
commenter
added
that
the
D.
C.
Circuit
court
noted
in
NRDC
v.
EPA
(
the
vinyl
chloride
decision)
that
safe
does
not
always
mean
risk
free
and
that
a
risk
of
cancer
between
one
in
ten
thousand
and
one
in
one
million
can
be
an
acceptable
risk.
Congress
specifically
incorporated
the
vinyl
chloride
decision
into
the
1990
CAAA.
Commenters
IV­
D­
122
and
IV­
D­
123
stated
that
§
112
(
d)(
4)
may
be
properly
applied
to
carcinogenic
HAPs
that
EPA
determines
have
a
threshold
of
safe
exposure.
The
CAA
places
no
limitation
on
EPA's
authority.
For
some
pollutants
a
MACT
emissions
limitation
may
be
far
more
stringent
than
is
necessary
to
protect
public
health,
whereas,
EPA
may
set
an
emission
limitation
under
§
112(
d)(
4)
where
it
is
possible
to
establish
a
level
of
exposure
that
is
safe.
EPA
has
welldeveloped
methodologies
and
extensive
experience
in
setting
"
safe"
levels
of
exposure.
Congress
recognized
that
not
all
HAP
should
be
regulated
at
the
stringency
of
the
MACT
floor
which
is
consistent
with
the
intent
to
avoid
expenditures
which
secure
no
public
health
or
environmental
benefit.
Section
112(
d)(
4)
authority
exists
with
respect
to
pollutants
for
which
a
health
threshold
has
been
established
and
therefore
can
be
applied
to
carcinogens
as
well
as
noncarinogens.
Although,
legislative
history
generally
distinguishes
between
threshold
pollutants
and
carcinogens,
EPA
should
not
view
those
as
overriding
the
clear
statutory
language.
Agency
policy
and
science
has
evolved
over
the
last
12
years
to
allow
for
a
carcinogen
to
have
threshold
of
action.
Nothing
in
statue
exists
to
preclude
EPA's
regulatory
programs
from
keeping
pace
with
the
state
of
the
art
in
scientific
understanding.
Commenters
IV­
D­
122
and
IV­
D­
123
also
stated
that
application
of
§
112(
d)(
4)
authority
to
threshold
carcinogens
would
not
conflict
with
other
provisions
of
the
CAA.
Sections
112
(
c)(
9)(
B)(
i)
and
112(
f)(
2)(
A)
specify
cancer
risk
of
one
in
a
million
as
the
level
below
which
sources
need
not
be
regulated
with
further
controls.
In
the
context
of
implementing
risk­
based
210
approaches
in
the
MACT
program,
the
commenters
submitted
that
EPA
can
and
should
use
a
de
minimis,
one
in
a
million
risk
level
as
the
health
benchmark.
Commenters
IV­
D­
122
and
IV­
D­
123
believed
EPA
can
use
a
risk­
based
approach
for
non­
threshold
pollutants,
including
metals.
Commenter
IV­
D­
123
included
additional
discussion
in
their
Attachment
A.
Several
commenters
(
IV­
D­
05,
IV­
D­
96,
IV­
D­
113,
IV­
D­
135,
IV­
D­
148,
and
IV­
D­
154)
stated
that
§
112(
d)(
4)
does
not
apply
for
source
categories
that
emit
carcinogens.
Several
commenters
(
IV­
D­
96,
IV­
D­
113,
IV­
D­
135,
and
IV­
D­
154)
stated
that
legislative
history
makes
it
clear
the
§
112(
d)(
4)
is
only
to
be
used
when
a
there
is
a
wellestablished
health
threshold.
Commenter
IV­
D­
113
cited
legislative
history
that
makes
it
clear
that
Congress
did
not
intend
EPA
to
establish
and
carcinogens
as
"
threshold"
pollutants
under
§
112(
d)(
4).
Commenter
IV­
D­
154
stated
that
the
concept
of
cancer
exposure
below
a
threshold
is
untried,
and
Congress
clearly
intended
that
carcinogens
be
considered
non­
threshold
pollutants.
Commenter
IV­
D­
96
stated
that,
even
if
permissible,
deregulation
under
§
112(
d)(
4)
is
rarely
available
and
noted
that
EPA
may
only
use
the
authority
for
pollutants
with
a
wellestablished
health
threshold.
The
commenter
pointed
out
that
§
112(
d)(
4)
only
allows
EPA
to
substitute
a
health
threshold
for
a
MACT
standard
when
the
threshold
"
has
been
established."
The
term
"
has
been"
means
that
the
accepted
threshold
is
already
in
existence.
The
commenter
stated
that
Congress
did
not
intend
for
EPA
to
use
this
provision
to
spend
time
to
determine
if
a
threshold
exists.
The
term
"
established"
shows
Congress's
intent
that
EPA
have
a
high
degree
of
scientific
certainty
before
using
its
§
112(
d)(
4)
authority.
Legislative
history
supports
this
interpretation
(
See
S.
Rep.
101­
228
at
171).
According
to
the
commenter,
Congress
also
specified
that
EPA
must
have
direct
evidence
of
no
effects
(
i.
e.,
use
of
NOEL)
before
invoking
§
112(
d)(
4).
The
EPA
must
be
sure
that
there
are
no
effects
from
exposure
at
the
level
chosen
for
the
emission
standard.
Commenter
IV­
D­
96
stated
further
that
EPA
may
not
use
the
authority
for
carcinogens
and
other
non­
threshold
pollutants.
The
§
112(
d)(
4)
provision
is
unavailable
for
non­
threshold
pollutants.
All
carcinogens
must
be
treated
as
non­
threshold
pollutants.
The
commenter
submitted
that
it
is
clear
throughout
the
history
of
the
CAAA
that
Congress
legislated
with
an
understanding
that
carcinogens
do
not
have
a
safe
threshold.
In
recognition
of
Congressional
intent,
EPA
traditionally
has
interpreted
§
§
112(
d)(
4)
to
exclude
consideration
of
carcinogens.
The
commenter
quoted
the
proposed
pulp
and
paper
NESHAP
(
63
FR
18754,18765,
proposed
April
15,
1998):
EPA
has
not
applied
§
112(
d)(
4)
to
carcinogens
because
Congress
clearly
intended
them
to
be
non­
threshold
pollutants.
Commenter
IV­
D­
135
asserted
that
the
establishment
of
applicability
cutoffs
for
threshold
and
nonthreshold
pollutants,
as
EPA
proposed,
is
technically
unsound
and
contrary
to
good
public
policy.
Congress
has
clearly
stated
that
carcinogens
are
not
threshold
pollutants.
The
commenter
added
that
regardless
of
whether
EPA
believes
that
there
have
been
advances
in
risk
assessment
science
that
might
allow
the
agency
to
better
evaluate
dose­
response
relationships,
an
attempt
to
do
so
here
would
be
EPA
impermissibly
subverting
the
judgement
of
Congress.
Commenter
IVD
135
also
asserted
that,
even
assuming,
arguendo,
that
EPA
had
the
authority
to
establish
cutoffs
for
threshold
pollutants,
this
authority
could
not
apply
to
nonthreshold
pollutants.
The
commenter
claimed
it
is
clear
that
Congress
legislated
an
understanding
that
there
is
no
safe
threshold
for
carcinogens
[
see
for
example
S.
Rep
101­
228
at
175]
and
provides
supporting
language
from
Senator
Durenberger.
The
commenter
concluded
that
attempting
to
determine
a
threshold
for
carcinogens
would
contravene
Congressional
intent.
[
68
Fed.
Reg.
at
1689/
1].
211
Commenter
IV­
D­
96
stated
that
allowing
carcinogens
to
escape
regulation
under
§
112(
d)(
4)
would
conflict
with
other
portions
of
the
CAA.
The
commenter
believed
EPA's
interpretation
would
give
it
authority
to
ignore
source
that
emits
a
threshold
carcinogen
(
if
such
a
thing
exists)
and
pose
greater
than
one
in
a
million
risk.
The
commenter
submitted
that
this
conflicts
with
the
plain
language
of
the
more­
specific
delisting
provision
§
112(
c)(
9)(
B)(
i),
which
only
allows
a
category
that
emits
a
carcinogen
to
be
delisted
if
risk
can
be
shown
to
be
less
than
one
in
a
million
for
any
source
in
the
category.
It
also
conflicts
with
the
residual
risk
assessment
provision
in
112(
f)(
2)(
A)
which
requires
EPA
to
promulgate
residual
risk
standards
if
the
cancer
risk
remains
above
one
in
a
million
after
MACT
is
applied.
Response:
We
agree
that
unless
scientific
evidence
indicates
otherwise,
carcinogens
should
be
treated
as
non­
threshold
pollutants.
As
is
explained
in
response
18.2.1,
§
112(
d)(
4)
provides
us
with
authority,
at
our
discretion,
to
develop
health­
based
standards
for
HAP's
"
for
which
a
health
threshold
has
been
established,"
provided
that
the
standard
reflects
the
health
threshold
"
with
an
ample
margin
of
safety."
Consequently,
the
boiler
rule
includes
health­
based
alternative
compliance
options
only
for
the
threshold
pollutants
HCl
and
Mn.

18.2.4
Carcinogens
as
Threshold
Pollutants
Comment:
Commenter
IV­
D­
72
believes,
as
supported
by
draft
EPA
guidelines
for
carcinogen
risk
assessment,
that
some
carcinogens
are
threshold
pollutants,
and
EPA
should
recognize
the
inherent
"
legal
threshold"
for
carcinogens
that
Congress
put
into
the
CAA,
i.
e.,
"
lifetime
excess
cancer
risks
to
the
individual
most
exposed
to
emissions
from
a
source
in
the
category
or
subcategory
to
less
than
one
in
one
million."
The
commenter
noted
that
EPA's
assertions
that
Congress
may
have
intended
the
concept
of
a
"
threshold"
compound
to
automatically
mean
"
non­
carcinogen,"
is
effectively
destroyed
by
the
clear
and
literal
language
of
subsection
112(
f)(
2)(
A),
i.
e.,
that
the
provisions
for
carcinogens
under
§
112(
f)
are
not
limited
to
technology­
based
NESHAP
standards
promulgated
under
§
112(
d)(
3),
but
instead
merely
address
"
standards
promulgated
pursuant
to
subsection
(
d)."
Had
Congress
intended
§
112(
d)(
4)
to
apply
only
to
non­
carcinogens,
then
it
would
not
have
included
the
provisions
of
§
112(
d)(
4)
when
addressing
constraints
on
emissions
of
carcinogens
under
§
112(
f)(
2)(
A).
Commenter
IV­
D­
72
stated
that
there
is
no
mystery
as
to
what
constitutes
an
acceptable
level
of
risk,
a
question
which
EPA
seems
to
ponder
in
the
recently
proposed
rulemakings.
Congress
answered
the
question
when
it
cited
the
Benzene
NESHAP,
stating
in
§
112(
f)(
2):
"(
A)...
If
standards
promulgated
pursuant
to
subsection
(
d)
and
applicable
to
a
category
or
subcategory
of
sources
emitting
a
pollutant
(
or
pollutants)
classified
as
a
known,
probable,
or
possible
human
carcinogen
do
not
reduce
lifetime
excess
cancer
risks
to
the
individual
most
exposed
to
emissions
from
a
source
in
the
category
or
subcategory
to
less
than
one
in
one
million,
the
Administrator
shall
promulgate
[
residual
risk]
standards
under
this
subsection
for
such
source
category.
(
B)
Nothing
in
subparagraph
(
A)
or
in
any
other
provision
of
this
section
shall
be
construed
as
affecting,
or
applying
to
the
Administrator's
interpretation
of
this
section,
as
in
effect
before
the
date
of
enactment
of
the
Clean
Air
Act
Amendments
of
1990
and
set
forth
in
the
Federal
Register
of
September
14,
1989
(
54
Federal
Register
38044)."
Subsection
112(
f)(
2)(
B)
explicitly
defers
to
the
holding
in
the
pre­
eminent
Vinyl
Chloride
case
and
thus
sets
the
standards
for
evaluating
acceptable
health
limits
for
HAP.
Response:
As
explained
in
response
to
comment
18.2.1,
we
presumptively
apply
§
112(
d)(
4)
only
to
HAP's
that
are
not
carcinogens
because
in
the
absence
of
scientific
evidence
212
to
the
contrary
it
has
been
our
policy
to
consider
carcinogens
as
nonthreshold
pollutants.
The
legislative
history
indicates
that
if
we
invoke
this
provision,
we
must
assure
that
any
emission
standard
results
in
ambient
concentrations
less
than
the
health
threshold,
with
an
ample
margin
of
safety,
and
that
the
standards
must
also
be
sufficient
to
protect
against
adverse
environmental
effects
(
S.
Rep.
No.
228,
101st
Cong.
at
171).
(
Section
112(
a)(
7)
of
the
CAA
defines
the
term
"
adverse
environmental
effect"
as
"
any
significant
and
widespread
adverse
effect,
which
may
reasonably
be
anticipated,
to
wildlife,
aquatic
life,
or
other
natural
resources,
including
adverse
impacts
on
populations
of
endangered
or
threatened
species
or
significant
degradation
of
environmental
quality
over
broad
areas.)
Costs
are
not
to
be
considered
in
establishing
a
standard
pursuant
to
§
112(
d)(
4)
(
Ibid.).

18.2.5
Section
112(
d)(
4)
Authority
for
Emission
Points
That
Emit
Both
Threshold
and
Non­
Threshold
Pollutants
Comment:
Commenters
IV­
D­
73
and
IV­
D­
166
believe
that
EPA
could
implement
a
§
112(
d)(
4)
emissions
limitation
under
both
the
first
and
third
scenarios
discussed
in
the
preamble
(
scenario
1:
exempt
low
risk
facilities
emitting
only
threshold
pollutants,
scenario
3:
exempt
emission
points
at
facilities
that
emit
only
threshold
pollutants).
However,
the
commenters
believe
that
the
use
of
a
§
112(
d)(
4)
emissions
limit
as
described
under
the
third
scenario
in
the
preamble
would
provide
the
maximum
benefit
of
the
§
112(
d)(
4)
provision.
Under
this
scenario,
facilities
that
emit
both
threshold
and
nonthreshold
pollutants
could
achieve
exemption
from
MACT
controls
for
threshold
HAP
emission
points
based
on
their
ability
to
meet
the
associated
health
threshold
for
those
HAP.
Another
possible
use
of
the
§
112(
d)(
4)
emissions
limitation
that
EPA
discussed
would
apply
to
both
threshold
and
nonthreshold
pollutants.
Commenter
IV­
D­
40
believes
the
threshold
approach
to
establishing
emission
standards
would
be
ideal
for
facilities
that
only
emit
threshold
HAPs,
but
that
it
could
also
be
applied
to
facilities
that
can
accurately
monitor
and
differentiate
the
emissions
of
threshold
and
nonthreshold
HAPs,
which
would
allow
a
facility
to
estimate
the
impact
of
exposure
to
threshold
and
non­
threshold
HAPs
separately.
Response:
As
is
explained
in
response
18.2.1,
we
have
chosen
to
use
the
authority
of
§
112(
d)(
4)
to
provide
an
alternative
to
the
HCl
regulatory
requirements
of
the
final
rule
for
affected
facilities
in
the
large
solid­
fuel
fired
boilers
and
process
heaters
subcategory
that
demonstrate
their
subpart
DDDDD
unit
HCl
and
Cl
2
emissions
result
in
a
maximum
HI
of
1.0
outside
the
facility
area.
Different
controls
are
needed
to
reduce
acid
gas
emissions
than
are
used
to
reduce
PM
(
HAP
metal)
emissions
from
boilers
and
process
heaters.
The
acid
gases
emitted
from
boilers,
i.
e.,
HCl,
Cl
2,
and
HF,
are
threshold
pollutants.
Similarly,
an
affected
facility
in
the
large
solid
fuel­
fired
boilers
and
process
heaters
subcategory
that
demonstrates
that
their
subpart
DDDDD
unit
Mn
emissions
result
in
a
maximum
hazard
quotient
(
HQ)
of
1.0
outside
the
facility
area
has
the
option
of
complying
with
the
emission
standard
for
TSM
minus
Mn.
As
is
the
case
with
the
acid
gases,
Mn
is
a
threshold
pollutant.

18.3
LEGAL
ISSUES:
DE
MINIMIS
AUTHORITY
Comment:
Numerous
commenters
(
IV­
D­
61,
IV­
D­
72,
IV­
D­
73,
IV­
D­
75,
IV­
D­
123,
IV­
D­
166,
and
IV­
D­
175)
stated
that
EPA
has
inherent
authority
to
promulgate
risk­
based
213
exemptions
and
cited
several
caselaw
examples
of
appellate
courts
upholding
EPA's
application
of
its
de
minimis
authority.
Commenter
IV­
D­
61
stated
that
a
risk­
based
compliance
option
for
both
threshold
and
non­
threshold
HAPs
is
well
within
EPA's
authority
under
the
CAA
and
the
de
minimis
doctrine
articulated
by
appellate
courts.
The
commenter
stated
that
appellate
caselaw
makes
clear
that
EPA
may
lawfully
exempt
de
minimis
sources
of
risk
from
MACT­
level
controls
because
the
legislative
mandate
of
CAA
§
112
is
not
"
extraordinarily
rigid"
and
the
exemption
is
consistent
with
the
CAA's
health­
protective
purpose.
CAA
§
§
112(
c)(
9)
and
112(
f)(
2)
clearly
indicate
that
Congress
considered
a
cancer
risk
below
one
in
a
million
to
be
de
minimis
and
therefore
insufficient
to
justify
regulation
under
CAA
§
112.
Under
this
approach,
EPA
would
specify
an
emission
standard
as
a
de
minimis
level
of
cancer
risk,
and
sources
would
have
the
option
to
comply
with
the
NESHAP
by
demonstrating
that
their
emissions
result
in
exposures
below
this
risk
level.
Commenters
IV­
D­
61
and
IV­
D­
123
argued
that
EPA's
de
minimis
authority
properly
is
evaluated
vis­
à­
vis
the
statutory
design.
Appellate
caselaw
establishes
EPA's
authority
to
exempt
de
minimis
sources
as
long
as
the
legislative
mandate
is
not
"
extraordinarily
rigid"
and
the
exemption
is
consistent
with
the
legislative
purpose
­
in
this
case,
the
"
health
protective
purpose
of
the
statute."
Commenters
IV­
D­
72
and
IV­
D­
61
cited
Alabama
Power
Co.
v.
Costle,
636
F.
2D
323
(
D.
C.
Cir.
1979)
where
the
court
explained
that
categorical
exemptions
from
the
requirements
of
a
statute
may
be
permissible:
[
A]
s
an
exercise
of
agency
power,
inherent
in
most
statutory
schemes,
to
overlook
circumstances
that
in
context
may
fairly
be
considered
de
minimis.
It
is
commonplace,
of
course,
that
the
law
does
not
concern
itself
with
trifling
matters,
and
this
principle
has
often
found
application
in
the
administrative
context.
Courts
should
be
reluctant
to
apply
the
literal
terms
of
a
statute
to
mandate
pointless
expenditure
of
effort.
636
F.
2D
at
360.
The
commenters
also
cited
the
more
recent
D.
C.
Circuit
decision
that:
As
long
as
the
Congress
has
not
been
extraordinarily
rigid
in
drafting
the
statute,
however,
there
is
likely
a
basis
for
an
implication
of
de
minimis
authority
to
provide
an
exemption
when
the
burdens
of
regulation
yield
a
gain
of
trivial
or
no
value.
Environmental
Def.
Fund
v.
EPA,
82
F.
3D
451,
466
(
D.
C.
Cir.
1996)
Commenter
IV­
D­
61
stated
that
EPA's
frequent
exercise
of
its
de
minimis
authority
has
withstood
judicial
challenge.
The
Agency's
application
of
this
authority,
as
well
as
its
treatment
by
reviewing
courts,
uniformly
has
turned
on
the
degree
of
risk
at
issue,
not
on
the
mass
of
emissions
to
be
regulated.
The
commenter
stated
that
appellate
courts
consistently
have
upheld
EPA's
application
of
its
de
minimis
authority
in
a
line
of
cases
that,
according
to
the
D.
C.
Circuit,
have
established
"
virtually
a
presumption
in
its
favor."
Public
Citizen
v.
Young,
831
F.
2D
at
1113.
These
decisions
include
the
following:
­
EDF
v.
EPA,
82
F.
3D
451,
466,
469
(
D.
C.
Cir.
1996)
{
This
case
deals
with
EPA's
transportation
conformity
regulations
promulgated
under
CAA
§
176}
­
Public
Citizen,
831
F.
2D
at
1112
­
Ohio
v.
EPA,
997
F.
2D
1520
(
D.
C.
Cir.
1993)
{
This
case
deals
with
de
minimis
exemptions
from
CERCLA
requirements
on
the
basis
of
no
appreciable
health
risk}
­
Alabama
Power
Co.,
636
F.
2D
at
360
­
Ober
v.
Whitman,
243
F.
3D
1190
(
9th
Cir.
2001)
{
This
case
deals
with
exemption
of
de
minimis
sources
of
PM
10
under
a
Federal
214
Implementation
Plan
[
FIP]}
­
Industrial
Union
Dept.,
AFL­
CIO
v.
American
Petroleum
Inst.,
448
U.
S.
607,
663­
64
(
1980).
See
IV­
D­
123
Attachment
A
for
quotes
from
these
court
decisions.
Commenters
IV­
D­
61
and
IV­
D­
123
stated
that
the
D.
C.
Circuit
has
invalidated
EPA's
de
minimis
authority
only
where
it
was
applied
under
statutory
designs
that
are
"
extraordinarily
rigid."
In
Public
Citizen,
the
D.
C.
Circuit
refused
to
allow
a
de
minimis
exception
to
the
"
Delaney
Clause"
in
the
Pure
Food
and
Drug
Act,
which
provided
that
a
color
additive
will
be
deemed
unsafe
if
it
is
found
to
induce
cancer
in
man
or
animal.
831
F.
2D
at
1108.
In
distinguishing
its
own
precedent,
the
D.
C.
Circuit
later
noted
that
"[
t]
he
Public
Citizen
court
relied
heavily
on
the
almost
inescapable
terms
of
the
Delaney
Clause
and
the
substantial
legislative
history
supporting
an
absolutist
application
of
the
language."
Ohio,
997
F.
2D
at
1534
(
emphasis
added,
quotations
omitted).
As
discussed
below,
CAA
§
112
contains
no
such
absolutist
language
so
as
to
preclude
EPA's
application
of
its
de
minimis
authority.
Commenters
IV­
D­
61
and
IV­
D­
123
stated
that
the
statutory
design
and
legislative
purpose
expressed
in
CAA
§
112
fully
justify
emission
standards
based
on
de
minimis
levels
of
cancer
risk.
The
roots
of
de
minimis
authority
exist
in
the
language
of
CAA
§
112,
and
CAA
§
112
itself
provides
clear
indication
of
congressional
intent
as
to
what
constitutes
a
de
minimis
cancer
risk
for
purposes
of
MACT.
Congress
expressly
included
de
minimis
provisions
in
the
title
III
program.
Despite
its
initial
emphasis
on
MACT­
based
control
technology,
the
overall
structure
of
CAA
§
112
is
overwhelmingly
risk­
based.
This
emphasis
on
risk
renders
de
minimis
considerations
especially
appropriate.
Unlike,
e.
g.,
the
Delaney
Clause,
CAA
§
112'
s
mandates
are
not
absolute.
For
example,
CAA
§
112(
c)(
9)(
B)(
i)
authorizes
source
category
delisting
if
the
category
(
or
subcategory)
creates
less
than
a
10­
6
cancer
risk;
CAA
§
112(
c)(
9)(
B)(
ii)
allows
delisting
if
non­
carcinogenic
HAP
emissions
do
not
exceed
levels
adequate
to
protect
public
health
with
an
ample
margin
of
safety.
Congress
included
de
minimis
principles
in
§
112(
g)(
1).
In
addition,
Congress
included
other
provisions
in
CAA
§
112
that
demonstrate
that
the
statutory
design
is
not
"
extraordinarily
rigid."
See,
e.
g.,
CAA
§
§
112(
a)(
2)
and
(
c)(
3);
112(
a)(
7);
112(
c)(
7);
112(
f)(
2)(
C);
112(
d)(
5)
and
(
f)(
5);
and
112(
i)(
5)(
E).
Commenter
IV­
D­
61
stated
that
CAA
§
112
provides
clear
indication
of
Congressional
intent
as
to
the
degree
of
risk
that
properly
is
to
be
considered
de
minimis.
A
cancer
risk
of
one
in
a
million
is
the
touchstone
for
further
review
under
the
"
residual"
risk
provision
of
CAA
§
112(
f).
(
The
residual
risk
provisions
thus
call
for
additional
controls
if
and
only
if
the
remaining
risk
from
affected
sources
exceeds
one
in
a
million,
but
do
not
call
for
a
reduction
of
risk
to
the
maximum
exposed
individual
[
MEI]
below
this
level.
Rather,
the
provisions
generally
call
for
reduction
of
MEI
risk
to
a
level
no
higher
than
1
in
10,000,
although
in
some
cases,
risks
greater
than
1
in
10,000
may
be
allowable.)
Similarly,
a
one
in
a
million
cancer
risk
is
the
threshold
below
which
EPA
is
authorized
under
CAA
§
112(
c)(
9)(
B)
to
remove
entire
source
categories
from
the
purview
of
MACT
regulation.
Where
Congress
has
authorized
the
wholesale
removal
of
entire
source
categories
on
the
basis
of
a
cancer
risk
below
one
in
a
million,
EPA
is
certainly
warranted
in
exercising
its
de
minimis
authority
to
provide
a
significantly
more
limited
emission
standard
premised
on
the
same
level
of
risk.
Commenters
IV­
D­
61
and
IV­
D­
123
contended
that
use
of
the
phrase
"
de
minimis"
in
CAA
§
112(
g)(
1)
does
not
limit
EPA's
exercise
of
its
de
minimis
authority
in
the
MACT
context.
Although
the
phrase
"
de
minimis"
is
only
used
in
CAA
§
112(
g)(
1),
there
is
no
legal
or
policy
215
basis
for
assuming
that
Congress
intended
to
preclude
EPA's
exercise
of
its
de
minimis
authority
in
every
other
regulatory
context
affecting
HAPs.
Federal
agencies,
including
EPA,
are
presumed
to
have
de
minimis
authority
regardless
of
whether
such
authority
is
expressly
granted
by
statute.
Appellate
caselaw
recognizes
that
federal
agencies
have
an
inherent
authority
to
exempt
de
minimis
sources
of
risk
from
even
highly
prescriptive
statutory
requirements,
so
long
as
the
legislative
mandate
is
not
"
extraordinarily
rigid"
(
EDF,
82
F.
3D
at
466)
and
the
exemption
is
consistent
with
the
legislative
purpose
(
here,
the
health­
protective
purpose
of
the
CAA).
The
commenters
argued
that
CAA
§
112
is
not
"
extraordinarily
rigid"
and
that
Congress
had
ample
opportunity
to
make
§
112
"
extraordinarily
rigid"
when
it
developed
the
1990
CAAA.
The
commenters
stated
that
EPA's
exercise
of
its
de
minimis
authority
under
CAA
§
112
is
consistent
with
traditional
canons
of
statutory
interpretation.
The
argument
that
the
isolated
use
of
the
term
"
de
minimis"
in
CAA
§
112(
g)(
1)
somehow
precludes
the
exercise
of
EPA's
de
minimis
authority
in
setting
the
MACT
floor
does
not
withstand
scrutiny
under
principles
of
statutory
interpretation
for
three
reasons:
(
1)
the
use
of
a
term
in
one
statutory
provision
is,
at
most,
a
weak
indicator
of
congressional
intent
to
foreclose
the
term's
application
in
other
statutory
provisions
(
See,
e.
g.,
Mourning
v.
Family
Publications
Serv.,
Inc.,
411
U.
S.
356
(
1973)
and
also
United
States
v.
Vonn,
535
U.
S.
55
(
2002)
summarized
on
pp.
58­
59
of
IV­
D­
61);
(
2)
the
preclusive
effect
of
the
isolated
use
of
a
term
is
even
more
attenuated
where,
as
here,
the
provision
in
which
the
term
appears
has
little
in
common
with
the
provision
in
which
its
absence
would
be
interpreted
(
see
City
of
Columbus
v.
Ours
Garage
&
Wrecker
Serv.,
536
U.
S.
424
(
2002));
and
(
3)
any
purported
preclusive
effect
is
weakened
further
in
the
context
of
agency
rulemaking,
such
as
the
process
of
MACT
standard
setting.
Commenter
IV­
D­
123
attached
a
white
paper
in
the
context
of
the
boiler
MACT
(
see
attachment
A
of
IV­
D­
123).
Arguments
presented
in
the
white
paper
that
are
not
discussed
elsewhere
in
this
document
are
summarized
below
for
the
white
paper
submitted
with
IV­
D­
123.
Commenter
IV­
D­
123
stated
that
the
Congressional
intent
expressed
in
the
CAA
§
112(
d)(
3)(
A)
MACT
floor
language
did
not
preclude
consideration
of
non­
HAP
environmental
impacts.
The
CAA's
structure,
appellate
case
law,
and
Agency
practice
suggest
that
EPA
should
take
a
broad
view
of
the
terms
"
best
performing"
and
"
emission
limitations"
considering
the
non­
HAP
disbenefits
of
controls.
This
interpretation
is
supported
because:
(
a)
EPA
and
the
D.
C.
Circuit
have
previously
interpreted
the
phrase
"
best
performing"
as
encompassing
non­
HAP
environmental
impacts
(
see
66
FR
3180,
3187
(
January
12,
2001),
NESHAP
for
Chemical
Recovery
Combustion
Sources
at
Kraft,
Soda,
Sulfite,
and
Stand­
Alone
Semichemical
Pulp
Mills);
(
b)
the
CAA
calls
for
excluding
from
the
MACT
floor
calculation
sources
that
have
complied
with
recent
emission
standards
(
lowest
achievable
emission
rate
[
LAER]
standards)
directed
toward
criteria
pollutants
rather
than
HAPs;
and
(
c)
the
MACT
floor
language
in
not
limited
to
an
evaluation
of
HAP
emissions,
but
rather
contains
the
more
general
term
"
emissions
limitation"
whereas
surrounding
language
refers
specifically
to
HAP
emissions.
The
commenter
argued
that
when
Congress
uses
different
terms
in
the
same
section
of
a
statute
that
Congress
intends
different
meanings
(
see
e.
g.,
American
Petroleum
Instit.
v.
EPA,
198
F3d
275
(
D.
C.
Cir.
2000)).
The
commenter
believes
these
three
points
support
their
conclusion
that
§
112
is
not
"
extraordinarily
rigid."
The
commenter
also
contended
that
EPA
has
de
minimis
authority
under
§
112
that
is
consistent
with
the
health
protective
purpose
of
the
statute,
as
expressed
by
the
provisions
health­
216
based
regulatory
thresholds.
CAA
§
112
differentiates
between
threshold
HAPs
(
for
which
a
health
benchmark
can
be
established)
and
non­
threshold
HAPs.
Providing
de
minimis
exemptions
below
the
regulatory
thresholds
contained
in
the
CAA
for
both
types
of
HAPs
is
justified
under
D.
C.
Circuit
precedent
because
it
"
squares
with
the
health­
protective
purpose
of
the
statute."
(
Ohio,
997
F2d
at
1535).
Commenter
IV­
D­
123
stated
that
irrespective
of
§
112(
d)(
4),
EPA
has
ample
de
minimis
authority
to
implement
risk
based
approaches
for
non­
threshold
carcinogens.
The
commenter
argued
that
NRDC's
characterization
of
the
nature
and
extent
of
EPAs
de
minimis
authority
is
contradicted
by
the
unanimous
weight
of
appellate
caselaw.
Appellate
caselaw
establishes
that
EPA
has
inherent
authority
to
make
determinations
affecting
de
minimis
sources
of
risk
even
under
highly
prescriptive
statutory
requirements,
so
long
as
the
legislative
mandate
is
not
"
extraordinarily
rigid"
and
the
exemption
is
consistent
with
legislative
intent.
Sections
112(
c)(
9)
and
(
f)(
2)
are
properly
construed
not
as
sources
of
de
minimis
authority,
but
as
indications
of
the
level
of
cancer
risk
Congress
considered
to
be
de
minimis.
NRDC's
claim
that
EPA
has
rejected
its
de
minimis
authority
in
the
context
of
§
112
is
contradicted
by
the
relevant
rulemaking
record
and
by
EPA's
general
practice.
The
instance
cited
by
NRDC,
where
EPA
declined
to
exercise
its
de
minimis
authority
was
a
substantially
different
scenario.
In
the
cited
rulemaking,
EPA
declined
to
apply
the
de
minimis
doctrine
to
change
the
MACT
floor
determination,
noting
that
the
doctrine
may
not
be
invoked
to
alter
the
MACT
floor
on
the
basis
of
a
cost­
benefit
analysis.
The
de
minimis
doctrine
in
this
case
is
not
being
advanced
as
a
basis
for
EPA
to
alter
its
MACT
floor
determination.
Nor
is
it
being
advanced
on
the
basis
of
a
cost­
benefit
analysis,
but
rather
on
the
basis
of
the
acknowledged
minimal
risks
that
the
rules
would
regulate.
The
legislative
history
cited
by
NRDC
does
to
limit
EPA's
de
minimis
authority
under
§
112.
Sen.
Durenberger's
statements
are
best
viewed
as
one
legislator's
opinion
as
to
what
a
piece
of
legislation
should
mean,
rather
than
a
definitive
explanation
of
Congressional
intent.
The
supreme
court
has
held
that
"
the
remarks
of
a
single
legislator,
even
the
sponsor,
are
not
controlling
in
analyzing
legislative
history."
Sen
Durenberger's
statement
was
a
discussion
of
the
express
authority
granted
by
the
residual
risk
provisions
of
§
112(
f),
not
of
EPA's
implicit
de
minimis
authority,
and
as
a
result,
should
have
no
bearing
on
EPA's
de
minimis
authority,
even
if
given
weight.
Commenter
IV­
D­
61
cited
EPA's
brief
in
National
Lime
Association
v.
EPA,
233
F.
3D
625
(
D.
C.
Cir.
2000)
and
noted
that
the
D.
C.
Circuit
held
that
EPA
reasonably
declined
to
provide
a
de
minimis
exemption
on
the
basis
of
cost
for
the
Portland
Cement
NESHAP,
but
the
court
did
not
limit
EPA's
de
minimis
authority
under
CAA
§
112
in
any
other
way.
Commenter
IV­
D­
72
stated
that
EPA
has
wrongfully
attempted
to
deny
its
de
minimis
authority
based
on
the
National
Lime
Association
v.
EPA
court
case.
233
F.
3D
625
(
D.
C.
Cir.
2000)
In
that
case,
the
court
found,
in
part,
that
the
CAA
does
not
provide
for
exemptions
from
emission
standards
based
upon
either
cost
concerns
or
a
source
emitting
a
de
minimis
quantity
of
HAP
when
a
MACT
floor
exists
for
the
source
category.
The
court
did
not
address
the
issue
of
EPA's
authority
to
provide
for
exemptions
based
upon
either
de
minimis
emissions
or
de
minimis
effect
upon
human
health
and
the
environment.
The
commenter
stated
that
they
are
not
arguing
for
cost­
based
exemptions;
rather
they
believe
that
EPA
can
structure
the
MACT
rules
in
such
a
way
that
de
minimis
levels
of
emissions
or
de
minimis
levels
of
risks
to
public
health
are
not
subject
to
the
technology­
based
standards
developed
under
§
112(
d)(
3).
Commenter
IV­
D­
72
stated
that
case
law
(
National
Lime)
prohibits
EPA
from
exempting
a
source
category
based
on
a
de
minimis
quantity
if
MACT
floor
exists,
but
does
not
prohibit
EPA
from
exempting
based
on
a
de
minimis
effect,
even
if
there
is
a
floor.
217
Commenter
IV­
D­
72
further
indicated
that
unless
a
statute
is
"
extraordinarily
rigid,"
relevant
case
law
(
Alabama
Power)
allows
using
de
minimis
concepts
in
regulatory
programs
when
the
statute
would
otherwise
yield
a
"
gain
of
trivial
or
no
value"
or
if
the
statute
would
require
"
absurd
or
futile
results"
in
terms
of
risk
to
human
health
and
the
environment.
The
commenter
agreed
with
AF&
PA
white
papers,
which
show
that
de
minimis
applicability
exemptions
based
on
risk
and
the
risk­
based
delisting
of
sources
are
prime
examples
of
EPA's
authority
to
consider
de
minimis
and
to
determine
whether
a
NESHAP
results
in
a
"
gain
of
trivial
or
no
value"
or
leads
to
"
absurd
or
futile
results."
Commenter
IV­
D­
72
stated
that
the
statute
provides
both
implicit
and
explicit
de
minimis
authority,
and
added
that
this
position
is
supported
by
the
statute
itself
in
that
sections
112(
c)(
9)(
B),
112(
d)(
4),
and
112(
f)(
2)(
A)
all
discuss
the
objectives
of
the
§
112(
d)
standards
in
terms
of
the
effect
of
the
pollutants
on
human
health
and
the
environment.
None
of
these
provisions
require
that
HAP
be
regulated
simply
for
the
sake
of
regulation,
but,
rather,
provide
guidance
as
to
what
constitutes
"
acceptable"
emissions
based
on
the
health
impact
of
those
emissions.
The
commenter
stated
that
§
112(
d)(
4)
provides
that
MACT
standards
set
under
§
112(
d)(
3)
need
not
be
any
more
stringent
than
necessary
to
protect
public
health
with
an
ample
margin
of
safety.
Hence,
there
is
no
requirement
to
control
HAP
simply
for
the
purpose
of
controlling
HAP.
Commenter
IV­
D­
72
stated
that
the
case
law
supports
EPA's
de
minimis
authority.
The
Vinyl
Chloride
case
outlined
EPA's
authority
for
determining
what
constitutes
a
de
minimis
or
"
safe"
level
of
exposure
to
a
HAP,
particularly
with
respect
to
carcinogens.
Among
the
courts
findings
were:
the
Administrator
must
make
an
initial
determination
of
what
is
"
safe;"
and,
the
Administrator's
decision
does
not
require
a
finding
that
"
safe"
means
"
risk­
free"
or
a
finding
that
the
determination
is
free
from
uncertainty.
Furthermore,
in
§
112,
Congress
provides
clear
guidance
to
EPA
regarding
what
it
considers
an
"
ample
margin
of
safety"
for
compounds
that
may
be
carcinogens.
Specifically,
a
"
safe"
level
is
that
which
poses
a
risk
of
excess
cancer
to
the
most
exposed
individual
to
less
than
one
in
one
million.
The
EPA
is
empowered
to
promulgate
a
de
minimis
exemption
from
a
NESHAP
based
upon
the
Administrator's
determination
of
an
acceptable
level
of
exposure
to
a
HAP
that
protects
human
health
and
the
environment
with
an
ample
margin
of
safety.
Commenter
IV­
D­
72
agreed
with
AF&
PA
that
EPA
makes
de
minimis
applicability
determinations
(
e.
g.,
HON
for
equipment
leaks,
and
a
recently
issued
direct
final
rule
to
exempt
"
Noncommercial
incineration
of
dead
animals,
the
onsite
incineration
of
resident
animals..."
67
FR
55129,
August
28,
2002).
EPA
issued
a
direct
final
rule
to
exempt
"
non­
commercial
incineration
of
dead
animals,
the
on­
site
incineration
of
resident
animals
for
which
no
consideration
is
received
or
commercial
profit
is
realized,
as
authorized
in
section
269.020.6,
RSMo
2000."
The
MDNR
submitted
information
that
emissions
from
these
sources
is
minimal
and
that
the
exemption
should
not
have
an
adverse
impact
on
ambient
air
quality.
No
existing
incinerators
in
this
source
category
are
subject
to
the
operating
permit
program,
due
to
their
de
minimis
size.
This
is
clearly
an
exemption
based
on
de
minimis
authority.
Commenter
IV­
D­
72
stated
the
case
that
EPA
should
allow
no
exemptions
when
all
of
the
emission
reductions
benefit
health
and
the
environment;
should
allow
for
exemptions
when
the
all
of
the
effects
are
de
minimis;
and
should
do
a
combination
of
the
two
for
cases
where
some
of
the
reductions
yield
benefits,
but
part
of
the
reductions
do
not.
EPA
should
regulate
only
those
sources
that
would
provide
benefit.
Commenter
IV­
D­
75
stated
that
§
112
also
provides
EPA
with
the
authority
to
exclude
218
sources
through
its
de
minimis
authority.
The
commenter
stated
that
relevant
case
law
(
see
EDF
v.
EPA,
82F.
3D
451,
466
(
D.
C.
Cir.
1996))
gives
EPA
the
authority
to
incorporate
de
mimimis
concepts
into
regulatory
programs
as
long
as
the
governing
statute
is
not
"
extraordinarily
rigid."
Section
112
has
several
references
to
risk,
distinguishing
among
sources,
and
alternative
approaches
to
§
112(
d)(
3)
MACT
standards.
Section
112
cannot
be
viewed
as
"
extraordinarily
rigid."
The
commenter
also
believes
it
is
appropriate
based
on
the
decision
by
the
D.
C.
Circuit
in
Alabama
Power
v.
Costle,
636
F.
2nd
323
(
D.
C.
Cir
1979),
for
EPA
to
establish
exemptions
from
what
"
in
context
may
fairly
be
considered
de
minimis."
636
F2.
nd,
323,
360.
Commenters
IV­
D­
73
and
IV­
D­
166
believe
that
EPA
could
accomplish
the
same
outcome
as
a
§
112(
d)(
4)
emissions
limitation
if
it
applied
an
emissions
limitation
on
nonthreshold
pollutants
using
its
inherent
de
minimis
authority
instead
of
a
limit
based
on
§
112(
d)(
4).
Commenter
IV­
D­
175
asserted
that
EPA
has
the
authority
to
promulgate
risk­
based
standards
for
non­
threshold
pollutants.
The
commenter
stated
that
the
courts
have
long
recognized
that
EPA
has
the
inherent
authority
to
promulgate
de
minimis
exemptions
under
most
circumstances,
even
where
the
statute
does
not
expressly
authorize
such
an
exemption
and
cites
the
following
examples:
In
Envt'l
Defense
Fund
v.
EPA,
82
F.
3D
451,
466
(
D.
C.
Cir.
1996),
the
court
held
that
"[
a]
s
long
as
the
Congress
has
not
been
`
extraordinarily
rigid'
in
drafting
the
statute...
`
there
is
likely
a
basis
for
an
implication
of
de
minimis
authority
to
provide
[
an]
exemption
when
the
burdens
of
regulation
yield
a
gain
of
trivial
or
no
value.'
"
Id.
at
466(
citations
omitted)(
commenter
emphasis
added).
The
court
found
"
nothing
in
the
[
CAA]
to
preclude
the
EPA's
identification
of
categories
of
[
exempt
activities]
that
would
produce
either
no
or
a
trivial
level
of
emissions[.]"
Id.
at
466­
7.
According
to
the
commenter,
although
the
EDF
ruling
was
in
the
context
of
the
Clean
Air
Act
transportation
conformity
regulations,
the
court's
reasoning
applies
equally
to
any
other
Clean
Air
Act
program,
including
the
MACT
program.

In
another
case,
the
court
held
that
categorical
exemptions
from
a
statutory
requirement
constitute
"
an
exercise
of
agency
power,
inherent
in
most
statutory
schemes,
to
overlook
circumstances
that
in
context
may
fairly
be
considered
de
minimis."
Alabama
Power
Co.
v.
Costle,
636
F.
2D
323,
360
(
D.
C.
Cir.
1979).
The
commenter
noted
that
the
court
reasoned
that
the
ability
to
create
a
deminimis
exemption
"
is
not
an
ability
to
depart
from
the
statute,
but
rather
a
tool
to
be
used
in
implementing
the
legislative
design."
Id.

Similarly,
in
Ober
v.
Whitman,
243
F.
3D
1190
(
9th
Cir.
2001),
the
Ninth
Circuit
upheld
EPA's
exemption
of
de
minimis
sources
of
PM­
10
from
control
requirements
under
a
federal
implementation
plan.

Finally,
the
D.
C.
Circuit
upheld
EPA's
adoption
of
de
minimis
exemptions
under
Comprehensive
Environmental
Response,
Compensation,
and
Liability
Act
(
CERCLA,)
even
where
the
plain
language
of
the
statute
did
not
authorize
such
exemptions,
reasoning
that
"[
t]
he
literal
meaning
of
the
statute
need
not
be
followed
where
the
precise
terms
lead
to
...
futile
results,
or
where
failure
to
follow
a
de
minimis
exception
is
contrary
to
the
primary
legislative
goal....
EPA's
interpretation
...
squares
with
the
health
protective
purpose
of
the
statute."
Ohio
v.
EPA,
997
F.
2D
1520,
1535
(
D.
C.
Cir.
1993).
Commenter
IV­
D­
175
contended
that
these
cases
clearly
establish
EPA's
inherent
authority
to
219
promulgate
de
minimis
exemptions
under
regulatory
schemes,
even
where
the
statute
itself
does
not
specifically
authorize
such
exemptions.
The
commenter
also
pointed
out
that
EPA
has
included
de
minimis,
concentration­
based
thresholds
in
a
number
of
NESHAPs
(
e.
g.,
40
CFR
part
63,
subparts
F,
G,
H,
U,
CC,
GG,
TT,
GGG,
etc.),
without
reference
to
explicit
statutory
authority,
and
without
ensuing
legal
challenges.
Similarly,
Commenter
IV­
D­
72
referred
to
AF&
PA's
white
paper
on
concentration­
based
de
minimis
exemptions
(
the
white
paper
not
discussed
in
the
preamble)
and
stated
that
they
believe
EPA
has
broad
de
minimis
authority
under
the
CAA
for
purposes
of
determining
applicability
of
standards.
The
commenter
stated
that
EPA
has
general
authority
to
exempt
de
minimis
emissions
based
on
concentration
and
risk.
Emissions
could
be
de
minimis
based
on
either
the
quantity
and/
or
ambient
impact
of
the
emissions
or
by
establishing
a
risk­
based
approach
to
establishing
de
minimis
emissions.
On
the
other
hand,
two
commenters
(
IV­
D­
14
and
IV­
D­
96)
opposed
risk­
based
approaches
under
de
minimis
authority.
Commenters
IV­
D­
96
and
IV­
D­
14
argued
that
EPA
does
not
have
de
minimis
authority
for
risk­
based
exemptions.
Commenter
IV­
D­
96
stated
that
the
de
minimis
theories
proposed
by
AF&
PA
in
EPA's
docket
violate
the
CAA.
EPA
may
not
rely
on
its
narrow
de
minimis
exemption
authority
to
escape
the
highly
prescriptive
provisions
in
section
112.
Commenter
IV­
D­
96
noted
that
de
minimis
authority
does
not
exist
to
create
MACT
exemptions
on
a
facility­
by­
facility
or
category­
wide
basis.
According
to
the
commenter,
subsection
(
d)(
4)
is
clearly
limited
to
threshold
pollutants,
but
AF&
PA
suggests
that
EPA
has
de
minimis
exemption
authority
for
non­
threshold
pollutants
under
112(
f)(
2)(
A).
The
commenter
stated
that
this
is
not
the
purpose
of
112(
f)(
2)(
A),
rather,
§
112(
f)(
2)(
A)
demands
that
EPA
reduce
significant
residual
risks
remaining
after
a
MACT
standard
is
applied.
The
section
applies
to
risks
from
carcinogens
in
order
to
provide
a
safety
net
if
the
MACT
standard
set
under
§
112(
d)
does
not
sufficiently
reduce
cancer
risk.
Commenter
IV­
D­
96
stated
that
EPA
rejected
the
idea
that
de
minimis
exceptions
are
available
in
the
way
that
AF&
PA
suggests
in
the
response
to
comments
for
the
Proposed
NESHAP
for
Chemical
Recovery
Combustion
Sources
at
Kraft,
Soda,
Sulfite,
and
Stand­
Alone
Semichemical
Pulp
Mills
(
p.
23,
attached
to
the
comment).
Allowing
facilities
to
conduct
a
risk
assessment
in
an
attempt
to
prove
that
they
are
de
minimis
sources
of
carcinogens
is
to
convert
MACT's
technology­
based
standard
setting
approach
back
into
a
health­
based
standard
setting
process
­
a
result
explicitly
rejected
by
Congress.
The
commenter
stated
that
invoking
§
112(
f)(
2)(
A)
as
a
de
minimis
granting
authority
for
individual
assessment
of
non­
threshold
pollutants
converts
a
back­
end
safety
net
into
a
front­
end
excuse
for
not
establishing
a
technology­
based
standard.
The
commenter
referenced
a
floor
statement
made
by
Senator
Durenberger
that
emphasizes
the
fact
that
no
de
minimis
regulatory
authority
exists
for
nonthreshold
pollutants
(
Legislative
History
at
876).
Courts
have
held
that
EPA
may
not
create
individual
de
minimis
exemptions
in
the
absence
of
clear
statutory
authority
to
do
so
(
Alabama
Power
Co.
v.
Costle,
636
F.
2D
(
D.
C.
Cir.
1979)).
Commenter
IV­
D­
96
stated
that
no
logical
reading
of
section112(
f)(
2)(
A)
or
the
CAA's
legislative
history
would
lead
a
reasonable
person
to
believe
that
Congress
granted
EPA
authority
to
reduce
or
avoid
a
MACT
standard
because
it
was
too
protective
of
cancer
risks.
Commenter
IV­
D­
96
also
asserted
that
EPA
lacks
de
minimis
authority
to
delist
subcategories
based
on
risk
According
to
the
commenter,
the
CAA's
text
and
purpose
prohibit
the
establishment
of
a
separate
de
minimis
subcategory
to
delist
sources.
Section
112(
c)(
9)(
B)'
s
220
text
precludes
development
of
a
de
minimis
exemption
that
exceeds
the
section's
narrow
authority.
The
commenter
stated
that
this
provision
is
highly
prescriptive
in
addressing
the
role
of
risk
assessment
in
avoiding
MACT.
The
Administrator
may
delist
a
category
only
if
no
source
emits
more
than
a
specified
amount
of
HAP.
Congress
did
not
intend
to
include
de
minimis
authority
in
§
112(
c)(
9)(
B).
Commenter
IV­
D­
96
stated
that
a
de
minimis
exception
in
§
112(
c)(
9)(
B)
would
not
further
the
CAA's
purpose
of
decreasing
HAP
emissions.
Commenter
IV­
D­
96
charged
that
AF&
PA
developed
a
series
of
"
white
papers"
exploring
multiple
iterations
of
de
minimis
theories
that
ended
up
serving
as
an
industry
"
how
to"
manual
for
the
illegal
exemptions
and
deregulation
promoted
by
the
White
House
OMB
and
reflected
by
EPA
in
section
IV.
G
of
its
proposal.
EPA
has
repeatedly
and
explicitly
recognized,
however,
that
a
de
minimis
theory
is
not
available
to
authorize
the
exemption
of
any
source
from
a
MACT
limitation
that
has
been
promulgated
for
the
category
to
which
that
source
belongs.
See,
e.
g.,
EPA's
Brief
as
Respondent
in
Cement
Kiln
Recycling
Coalition
v.
Browner,
U.
S.
Court
of
Appeals
for
the
D.
C.
Circuit,
Case
No.
99­
1457,
January
18,
2001,
at
53
(
Attachment
1
to
IV­
D­
96)
("
EPA
rightly
concluded
that
`[
s]
ection
112
of
the
Act
does
not
provide
for
exceptions
from
emission
standards
based
on
de
minimis
principles
where
a
MACT
floor
exists.'
RTC
at
211
(
JA
1542).").
EPA
may
not
rely
on
its
narrow
de
minimis
exemption
authority
to
escape
the
highly
prescriptive
provisions
in
§
112.
Commenter
IV­
D­
96
stated
that
first,
the
basic
legal
purpose
justifying
invocation
of
the
de
minimis
doctrine
­
"
spar[
ing]
agency
resources
for
more
important
matters"
­­
is
not
relevant
here.
See
Public
Citizen
v.
Young,
831
F.
2D
1108,
1112
(
D.
C.
Cir.
1987).
EPA
can
and
must
issue
MACT
standards
to
regulate
every
HAP
emitted
by
the
source
category,
and
the
agency
resources
devoted
to
this
task
will
not
be
reduced
by
relying
upon
AF&
PA's
unfounded
de
minimis
theories.
The
commenter
noted
that
EPA's
own
proposal
discusses
the
complex
issues
associated
with
establishing
these
various
de
minimis
exemptions,
and
EPA
acknowledges
in
the
final
BSCP
MACT
standard
that
creation
of
these
exemptions
is
complex
and
time­
consuming.
Agency
resources
would
be
consumed
to
a
far
greater
degree
attempting
to
develop
these
approaches
than
not.
Commenter
IV­
D­
96
added
that
these
conclusions
are
doubly
true
with
respect
to
the
resources
of
state
and
local
permitting
authorities,
as
explained
by
these
officials
in
comments
on
the
BSCP
MACT
proposal
and
other
proposals
(
including
this
one)
in
which
EPA
has
proposed
saddling
them
with
time­
consuming,
complex
risk
assessments
and
cumbersome
determinations
in
service
of
industry's
deregulatory
agenda.
Commenter
IV­
D­
96
stated
that
second,
any
purported
inconvenience
to
industry
from
complying
with
MACT
is
not
a
justification
for
invoking
the
de
minimis
doctrine
so
as
to
escape
clear
statutory
provisions.
It
is
hardly
an
"
absurd
or
futile"
result
to
require
facilities
to
control
their
cancer­
causing
emissions
and
other
HAPs
with
MACT­
level
controls,
since
this
is
the
plain
purpose
of
§
112'
s
technology­
based
system
of
regulation.
Alabama
Power
v.
Costle,
636
F.
2D
323,
360,
n.
89
(
D.
C.
Cir.
1979).
Commenter
IV­
D­
96
stated
moreover,
that
requiring
these
HAPs
to
be
controlled
with
MACT
emissions
standards
clearly
"
provide[
s]
benefits,
in
the
sense
of
furthering
the
regulatory
objectives"
of
the
Act's
HAP
program.
Alabama
Power,
636
F.
2D
at
361.
At
any
rate,
EPA
has
not
revealed
any
administrative
record
justifying
a
de
minimis
exemption,
to
demonstrate
in
any
way
that
compliance
with
MACT
would
"
yield
a
gain
of
trivial
or
no
value."
Id.
Commenter
IV­
D­
96
stated
further
that
Congress
defined
the
terms,
"
modification"
and
"
major
source,"
such
to
ensure
that
the
severe
proscription
in
subsection
112(
g)(
2)
would
not
apply
where
only
de
minimis
HAP
emissions
resulted
from
the
construction
of
a
new
source
or
221
the
modification
of
an
existing
one.
The
commenter
noted
that
in
its
white
paper,
AF&
PA
asserts
that
EPA's
"
presumptive
de
minimis
authority"
empowers
the
agency
to
promulgate
a
rule
instituting
the
concentration­
based
applicability
threshold.
Commenter
IV­
D­
96
submitted
that
this
assertion
is
specious.
First
of
all,
to
the
extent
Congress
has
authorized
any
de
minimis
exclusion
from
the
MACT
requirement,
the
exclusion
is
for
de
minimis
amounts
of
a
HAP
emitted.
A
limit
on
the
concentration
of
a
HAP
in
a
source's
exhaust
stream
imposes
no
limit
whatsoever
on
the
amount
of
the
HAP
that
is
emitted
from
that
source.
The
commenter
stated
that
furthermore,
Congress
already
set
forth
in
the
text
of
§
112
the
extent
of
the
allowance
that
it
wished
to
make
for
de
minimis
amounts
of
HAP
emissions.
Commenter
IV­
D­
96
claimed
that
the
rule
that
AF&
PA
promotes
would
purport
to
exempt
from
the
MACT
requirement
changes
that
cause
HAP
emissions
increases
in
excess
of
any
de
minimis
thresholds
that
Congress
has
set,
or
that
EPA
has
instituted
pursuant
to
the
limited
discretion
afforded
the
agency
by
subsection
112(
a)(
5).
AF&
PA's
misplaced
invocation
of
the
de
minimis
doctrine
fails
to
hide
the
conflict
between
its
proposed
exemption
and
the
dictates
of
the
CAA.
Commenter
IV­
D­
96
stated
that
the
third
exemption
suggested
by
AF&
PA
and
proposed
by
EPA,
a
so­
called
"
concentration­
based
applicability
threshold,"
is
unlawful.
Subsection
112(
g)(
2)
of
the
CAA
declares
that
no
person
may
construct,
reconstruct,
or
modify
"
a
major
source
of
hazardous
air
pollutants"
unless
the
permitting
authority
"
determines
that
the
maximum
achievable
control
technology
emission
limitation
under
this
section
for
existing
sources
will
be
met."
As
long
as
the
source
meets
the
"
major
source"
threshold
and
the
proposed
modification
would
cause
more
than
a
de
minimis
increase
in
HAP
emissions,
the
CAA
requires
a
MACT
determination.
The
CAA
does
not
contain
any
provision
authorizing
EPA
to
waive
this
requirement
where
the
post­
change
HAP
concentration
in
the
source's
exhaust
stream
will
not
exceed
a
certain
level,
or
where
the
source
owner
commits
to
adopt
just
enough
HAP
control
to
bring
the
concentration
down
to
that
level.
After
all,
whether
a
source's
exhaust
stream
meets
a
certain
HAP
concentration
limit
has
no
bearing
on
whether
the
source
meets
the
MACT
emission
limitation.
As
EPA
itself
acknowledges
in
the
preamble
of
its
final
BSCP
NESHAP:
"
Exhaust
gas
concentrations
have
no
effect
on
mass
emission
rates,
provided
the
concentrations
are
above
the
test
method
detection
limit.
The
mass
emission
rate
(
e.
g.,
pounds
of
pollutant
emitted
per
hour)
for
a
source
is
unchanged
regardless
of
how
much
dilution
air
is
introduced."
Because
it
purports
to
replace
the
MACT
emission
limitation
with
a
requirement
that
places
no
limit
on
the
mass
emission
rate,
the
rule
that
the
AF&
PA
wants
EPA
to
promulgate
stands
in
direct
conflict
with
the
clear
language
of
the
CAA.
Regarding
the
use
of
a
concentration­
based
applicability
threshold,
commenter
IV­
D­
14
stated
that
this
is
not
what
Congress
intended
in
the
CAAA
of
1990.
Congress
mandated
that
the
MACT
floor
be
established
as
initial
level
of
control.
Response:
We
disagree
with
the
commenters
who
claimed
that
the
low
risk
approaches,
especially
the
concentration­
based
exemption,
can
be
justified
by
de
minimis
principles.
Our
de
minimis
authority
exists
to
help
avoid
excessive
regulation
of
tiny
amounts
of
pollutants,
where
regulation
would
yield
a
result
contrary
to
a
primary
legislative
goal.
It
is
unavailable
"
where
the
regulatory
function
does
provide
benefits,
in
the
sense
of
furthering
the
regulatory
objectives,
but
the
EPA
concludes
that
the
acknowledged
benefits
are
exceeded
by
the
costs."
EDF
v.
EPA,
82
F.
3d
451,
466
(
D.
C.
Cir.
1996);
Public
Citizen
v.
Young,
831
F.
2d
1108,
1112­
13
(
D.
C.
Cir.
1987);
Alabama
Power
v.
EPA,
636
F.
2d
323,
360­
61
&
n.
89
(
D.
C.
Cir.
1979).
Accordingly,
a
de
minimis
exemption
to
§
112(
d)(
3)
is
unavailable
in
this
final
rule,
because
it
would
frustrate
a
primary
legislative
goal
by
preventing
application
of
the
MACT
floor
to
tons
of
HAP
emissions
222
from
boiler
and
process
heater
affected
sources.
The
U.
S.
Court
of
Appeals
for
the
District
of
Columbia
Circuit
has
already
addressed
the
de
minimis
concept
in
the
MACT
context,
in
National
Lime
Ass'n
v.
EPA,
233
F.
3d
625,
640
(
D.
C.
Cir.
2000)
("
National
Lime"),
in
which
the
court
rejected
the
industry
petitioner's
claim
that
in
light
of
both
the
high
costs
and
low
quantities
of
HAP
at
issue
in
that
case,
EPA
should
read
a
de
minimis
exception
into
the
requirement
that
it
regulate
all
HAP
emitted
by
major
sources.
In
that
case,
the
Court
found
that
"
EPA
reasonably
rejected
this
argument
on
the
ground
that
the
statute
`
does
not
provide
for
exceptions
from
emissions
standards
based
on
de
minimis
principles
where
a
MACT
floor
exists.'"
(
See
National
Lime
at
640.)
We
recently
re­
affirmed
our
position
on
the
unavailability
of
de
minimis
exemptions
from
the
MACT
floor
in
the
final
rule
regulating
organic
liquids
distribution.
(
See
69
FR
5038,
5048­
49
(
February
3,
2004).)
We
see
no
reason
to
revisit
this
fundamental
issue.
Section
112
of
the
CAA
is
replete
with
careful
definitions
of
mass­
or
effect­
based
limitation
on
regulation,
indicating
that
Congress
has
already
defined
what
amounts
of
HAP
emissions
are
too
small
to
warrant
MACT
standards
or
other
controls
under
§
112.
The
requirement
to
adopt
MACT
emission
limitations,
for
example,
applies
without
exception
to
"
each
category
or
subcategory
of
major
sources
.
.
.
of
[
HAP]."
(
see
CAA
§
112(
d)(
1).)
For
sources
below
the
major
source
threshold,
however,
we
have
discretion
to
require
"
generally
available
control
technologies
or
management
practices."
(
see
CAA
§
112(
d)(
5).)
Congress
has
thus
itself
defined
which
sources'
emissions
are
small
enough
not
to
warrant
mandatory
MACT
standards.
Congress
likewise
defined
several
MACT
exceptions
applicable
where
emissions
have
de
minimis
health
effects.
Section
112(
d)(
4)
of
the
CAA
allows
us
to
establish
standards
less
stringent
than
MACT
for
HAP
with
an
established
health
threshold,
so
long
as
we
set
a
standard
below
the
health
threshold
with
"
an
ample
margin
of
safety."
Section
112(
b)(
3)(
C)
of
the
CAA
directs
us
to
de­
list
HAP
 
precluding
§
112(
d)
MACT
standards
 
if
we
determine
that
"
there
is
adequate
data
on
the
health
and
environmental
effects
of
the
substance
to
determine
that
emissions,
ambient
concentrations,
bioaccumulation
or
deposition
of
the
substance
may
not
reasonably
be
anticipated
to
cause
any
adverse
effects
to
the
[
sic]
human
health
or
adverse
environmental
effects."
Section
112(
c)(
9)(
B)(
i)
of
the
CAA
(
discussed
further
below)
lets
us
delete
source
categories
and
subcategories
from
the
category
list
 
the
consequence
again
being
no
MACT
control
 
if
we
determine
that,
for
emissions
of
carcinogenic
HAP,
"
no
source
in
the
category
.
.
.
emits
such
[
HAP]
in
quantities
which
may
cause
a
lifetime
risk
of
cancer
greater
than
one
in
one
million
to
the
individual
in
the
population
who
is
most
exposed
to
emissions
of
such
pollutant
from
the
source."
For
noncarcinogens,
we
may
delete
source
categories
and
subcategories
if
we
determine
that
"
emissions
from
no
source
in
the
category
or
subcategory
.
.
.
exceed
a
level
which
is
adequate
to
protect
public
health
with
an
ample
margin
of
safety
and
no
adverse
environmental
effect
will
result
from
emissions
from
any
source."
(
See
CAA
§
112(
c)(
9)(
B)(
ii).)
Moreover,
in
defining
which
source
modifications
trigger
additional
regulatory
standards,
CAA
§
112(
g)(
1)(
A)
mentions
a
"
greater
than
de
minimis
increase
in
actual
emission
of
a
[
HAP]."
This
shows
that
Congress
knew
how
to
use
the
de
minimis
concept
when
it
considered
it
appropriate
in
§
112,
and
the
fact
that
Congress
did
not
use
it
in
§
112(
d)(
3)
supports
EPA's
 
and
the
D.
C.
Circuit's
 
conclusion
that
it
is
unavailable
to
support
an
exception
to
a
MACT
floor
that
is
not
otherwise
authorized
under
§
112.
We
do
not
find
persuasive
the
proposition
that
the
overall
purpose
of
§
112
is
protecting
human
health
and
the
environment,
and
that,
therefore,
as
long
as
this
general
purpose
is
met,
we
may
fashion
de
minimis
exceptions
from
MACT
beyond
those
allowed
under
§
112.
First,
this
223
position
appears
to
assume
that
the
issue
is
to
be
drawn
on
a
clean
slate,
while
the
D.
C.
Circuit
has
affirmed
our
view
that
§
112(
d)(
3)
provides
no
discretion
to
use
a
de
minimis
rationale
to
avoid
MACT.
Second,
the
commenter
appears
to
give
prominence
to
an
over­
arching
statutory
goal
over
the
specific
language
of
the
statutory
provisions
themselves,
in
assessing
whether
those
provisions
are
"
extraordinarily
rigid"
regarding
EPA's
otherwise­
inherent
de
minimis
authority;
the
logical
extension
of
such
an
approach
would
be
to
find
that
no
single
provision
in
the
CAA
could
restrict
our
de
minimis
authority,
in
light
of
the
CAA's
over­
arching
purpose
"
to
promote
the
public
health
and
welfare."
(
see
CAA
§
101(
b)(
1).)
Third,
the
commenter
does
not
present
any
persuasive
statutory
arguments
to
overcome
those
that
we
presented
to
the
court
 
and
which
the
court
affirmed
 
in
National
Lime.
Fourth,
we
are
unable
to
discern
the
basis
for
the
commenter's
suggestion
that
we
have
in
fact
been
relying
on
de
minimis
authority
in
the
MACT
program
for
several
years
in
establishing
applicability
thresholds,
and
we
are
not
aware
of
any
instance
in
which
we
have
explicitly
justified
an
exception
from
an
applicable
MACT
floor
based
on
a
de
minimis
rationale
that
would
be,
like
the
commenter's
requested
exemption,
in
contravention
of
the
Court's
ruling
in
National
Lime.
Fifth,
notwithstanding
any
asserted
overall
risk­
based
goal
of
§
112,
§
112(
d)(
2)
repeatedly
directs
EPA
to
"
eliminate
emissions,"
where
feasible,
and
§
112(
d)(
6)
imposes
an
ongoing
obligation
for
EPA
to
review
and
revise
standards
as
necessary
to
account
for
developments
in
technology,
and
neither
of
these
specific
goals
is
restricted
to
situations
where
health
targets
have
not
yet
been
reached.
Finally,
to
the
extent
the
commenters
believe
such
a
de
minimis
exemption
is
justified
by
the
wish
to
reduce
the
costs
of
the
final
rule,
we
are
not
free
to
grant
a
de
minimis
exemption
to
account
for
costs:
Congress
already
took
cost
into
account
in
§
112(
d),
relying
on
prior
business
judgments
by
the
best
performing
sources
to
substitute
for
the
judgment
of
the
rest
of
the
Industrial/
Commercial/
Institutional
Boilers
and
Process
Heaters
source
category,
therefore
denying
us
the
leeway
to
consider
costs
as
a
factor
to
modify
the
MACT
floor.
Only
in
considering
more
stringent
"
beyond
floor"
standards
may
we
consider
costs
in
the
MACT
context.
Therefore,
we
do
not
believe
it
is
appropriate
or
necessary
to
revisit
our
and
the
D.
C.
Circuit's
prior
conclusions
regarding
the
availability
of
the
de
minimis
principle
in
the
final
rule.

18.4
LEGAL
ISSUES:
SECTION
112(
c)(
9)
AUTHORITY
18.4.1
Section
112(
c)(
9)
Authority
for
Delisting
Source
Categories
or
Subcategories
Comment:
Several
commenters
(
IV­
D­
72,
IV­
D­
73,
IV­
D­
75,
IV­
D­
123)
supported
the
use
of
§
112(
c)(
9)
authority
to
delist
categories
or
subcategories.
Commenter
IV­
D­
72
stated
that
EPA
has
broad
discretion
to
tailor
source
categories
as
appropriate
to
best
reflect
the
source
category.
Specifically,
§
112(
c)(
9)
provides
that
EPA
establish
categories
and
subcategories
of
sources,
as
appropriate,
pursuant
to
CAA
§
112(
c)(
1),
in
order
to
facilitate
the
development
of
MACT
standards
consistent
with
§
112
of
the
CAA.
The
commenter
further
pointed
out
that
§
112(
c)(
9)(
B)
allows
EPA
to
delete
a
category
(
or
subcategory)
from
the
list
of
major
sources
for
which
MACT
standards
are
to
be
developed
when
the
following
can
be
demonstrated:
(
1)
in
the
case
of
carcinogenic
pollutants,
that
"...
no
source
in
the
category...
emits
(
carcinogenic)
air
pollutants
in
quantities
which
may
cause
a
lifetime
risk
of
cancer
greater
than
1
in
1
million
to
the
individual
in
the
population
who
is
most
exposed
to
emissions
of
such
pollutants
from
the
source...";
(
2)
in
the
case
of
pollutants
that
cause
adverse
non­
cancer
health
effects,
that
"...
emissions
from
no
source
in
the
category
or
subcategory...
exceed
a
level
which
is
adequate
to
224
protect
public
health
with
an
ample
margin
of
safety...";
and
(
3)
in
the
case
of
pollutants
that
cause
adverse
environmental
effects,
that
"
no
adverse
environmental
effect
will
result
from
emissions
from
any
source..."
Commenter
IV­
D­
72
stated
that
this
level
of
discretion
clearly
grants
EPA
the
authority
to
establish
subcategor[
ies]
of
facilities
within
the
larger
source
category
that
would
meet
the
risk­
based
criteria
for
delisting.
Such
criteria
would
likely
include
HI
limits
for
threshold
pollutants
and
a
cancer
risk
level
of
10­
6
for
non­
threshold
pollutants.
Commenter
IV­
D­
75
noted
that
EPA
stated
in
its
initial
list
of
source
categories
that
Congress
appeared
to
use
the
terms
category
and
subcategory
interchangeably,
and
that
either
a
category
or
subcategory,
therefore,
can
be
delisted.
Furthermore,
§
112(
c)(
9)(
B)
indicates
that
the
Administrator
can
delist
both
categories
and
subcategories.
The
commenter
pointed
out
that
the
subsection
regarding
carcinogenic
HAP
states
that
a
category
of
sources
can
be
delisted
after
a
determination
that
"
no
source
in
the
category"
emit
pollutants
in
an
amount
that
poses
a
lifetime
cancer
risk
greater
than
one
in
one
million.
The
criteria
for
non­
carcinogens
allows
for
delisting
"
when
no
source
in
the
category
or
subcategory"
exceeds
an
emissions
level
adequate
to
protect
public
health.
Commenter
IV­
D­
73
added
that
nothing
in
the
statute
or
history
of
EPA's
interpretation
of
§
112(
c)
precludes
subcategorization
based
on
risk,
and,
in
addition,
EPA
has
stated
that
emission
characteristics
are
factors
to
be
considered
when
defining
categories.
Commenter
IV­
D­
75
stated
that
§
§
112(
c)(
1)
and
112(
c)(
9)
provide
EPA
the
authority
to
create
and
delist
low
risk
source
categories.
The
commenter
stated
that
while
§
112(
c)(
9)
is
clear
in
limiting
the
delisting
to
categories
and
subcategories
in
which
all
sources
meet
the
applicable
tests,
the
CAA
provides
the
Administrator
with
significant
flexibility
to
create
categories
and
subcategories
as
needed
to
implement
§
112.
Specifically,
§
112(
c)(
1)
states
that
"
Nothing
in
the
preceding
sentence
limits
the
Administrator's
authority
to
establish
subcategories
under
this
section,
as
appropriate."
The
commenter
stated
that
there
is
nothing
in
the
statute
that
limits
the
criteria
the
Administrator
can
use
in
establishing
categories
and
subcategories.
The
commenter
also
pointed
out
that
application
of
the
statutory
authority
to
exclude
sources
from
regulation
under
§
112(
d)(
3)
is
supported
by
relevant
case
law.
In
the
Vinyl
Chloride
decision
(
NRDC
v.
EPA,
824
F.
2D
1126
(
D.
C.
Cir.
1987)),
the
court
noted
that
what
is
considered
a
"
safe"
level
is
always
"
marked
by
scientific
uncertainty."
The
court
established
a
range
of
acceptable
level
of
risk
in
establishing
limits
under
prior
language
in
§
112.
The
commenter
suggested
that
the
establishment
of
an
acceptable
level
of
risk
could
be
used
to
create
a
low­
risk
subcategory
that
could
be
delisted.
The
commenter
also
noted
that
technological
or
operational
differences
among
sources
may
also
be
appropriate
of
the
differences
help
to
discriminate
between
low­
risk
and
highrisk
sources.
Finally,
the
commenter
added
that
effective
use
of
§
112(
c)(
1)
authority
to
create
risk
based
subcategories
would
significantly
improve
the
cost­
effectiveness
of
the
§
112
program
without
undermining
its
role
in
protecting
public
health
and
the
environment.
Commenter
IV­
D­
73
stated
that
in
the
preambles,
EPA
expresses
uncertainty
over
whether
it
has
the
authority
to
subcategorize
source
categories
based
on
risk.
The
commenter
believed
that
EPA
has
ample
authority,
based
on
§
§
112(
c)(
1)
and
112(
d)(
1),
to
subcategorize
based
on
risk.
Section
112(
c)(
1)
states:
"
Nothing
in
the
preceding
sentence
[
relating
to
following
the
NSPS
program
categories
and
subcategories]
limits
the
Administrator's
authority
to
establish
subcategories
under
this
section
as
appropriate."
Thus,
the
commenter
noted,
Congress
allowed
EPA
discretion
to
subcategorize
previously
created
categories,
regardless
of
the
criteria
that
EPA
used
to
create
the
category
in
the
first
place,
and
to
do
so
at
any
time.
Commenter
IV­
D­
73
also
pointed
out
that
§
112(
d)(
1)
provides
that
EPA
"
may
distinguish
among
classes,
types
and
sizes
of
sources"
when
establishing
MACT
standards.
According
to
the
commenter,
the
broad
terms
225
"
classes,"
"
types,"
and
"
sizes"
indicate
that
Congress
intended
that
EPA
have
broad
discretion
in
establishing
subcategories
and
do
not
preclude
EPA
from
subcategorizing
based
on
risk,
since
low­
risk
sources
could
be
considered
a
"
class"
or
"
type"
of
source.
The
commenter
added
that
the
only
case
to
clarify
this
statutory
language
recognized
the
broad
discretion
it
confers
on
EPA
to
create
subcategories
with
different
emission
standards.
Sierra
Club
v.
Costle,
657
F.
2D
298
(
D.
C.
Cir.
1981).
The
Court
noted,
"[
t]
he
required
finding
that
must
underlie
a
variable
standard
is
much
broader
than
a
mere
determination
that
uniformity
is
not
achievable."
Id.
at
321.
On
this
basis,
the
Court
expressly
upheld
EPA's
subcategorization
of
coal­
fired
power
plants
based
on
the
sulfur
content
of
fuel.
More
generally,
the
commenter
stated
that
the
Sierra
Club
decision
confirms
EPA's
discretion
to
set
differentiated
emissions
standards
for
subcategories
of
sources,
even
in
instances
where
the
strictest
standard
may
be
achievable
by
all
sources.
Commenter
IV­
D­
123
stated
that
EPA
has
ample
legal
authority
to
subcategorize
and
delist
low
risk
sources
and
that
EPA
has
ample
legal
authority
to
subcategorize
on
the
basis
of
risk.
The
commenter
submitted
that
NRDC's
and
Earthjustice's
contrasting
of
the
terms
"
category"
and
"
subcategory"
offers
a
distinction
that
in
no
way
limits
EPA's
authority
to
delist
low
risk
sources.
The
commenter
believed
the
idea
that
EPA
cannot
create
subcategories
based
on
risk
is
contradicted
by
the
statutory
language,
which
expressly
states
that
the
categories
and
subcategories
EPA
creates
under
§
112
need
not
match
those
created
under
§
111.
Further,
prior
EPA
statements
do
nothing
to
detract
from
the
Agency's
broad
discretion
to
establish
categories
and
subcategories.
Commenter
IV­
D­
123
stated
that
the
subcategorization
factors
previously
discussed
by
the
Agency
justify
subcategorization
based
on
risk.
The
commenter
stated
further
that
the
authority
cited
by
NRDC
does
not
establish
that
EPA's
discretion
to
alter
subcategorization
is
limited
in
anyway,
and
even
if
it
were,
EPA
is
not
bound
by
any
prior
position.
The
arguments
that
EPA
may
not
delist
subcategories
for
carcinogens
(
or
sources
emitting
carcinogens)
rest
on
a
formalistic
distinction
that
EPA
previously
has
rejected
as
meaningless,
and
that,
at
any
rate,
can
be
remedied
with
a
simple
recasting
of
a
subcategory
as
a
category.
The
commenter
asserted
that
doing
so
is
undisputedly
within
EPA's
authority.
Numerous
commenters
(
IV­
D­
05,
IV­
D­
55,
IV­
D­
96,
IV­
D­
113,
IV­
D­
127,
and
IV­
D­
135)
stated
that
§
112(
c)(
9)
should
not
be
used
to
subcategorize
based
on
risk.
Commenter
IV­
D­
113
stated
that
subcategory
delisting
under
§
112(
c)(
9)(
B)
is
flatly
unlawful.
The
commenter
pointed
out
that
§
112(
c)(
9)(
B)
provides
that
EPA
"
may
delete
any
source
category"
from
the
§
112(
c)
list
upon
making
certain
determinations.
The
commenter
submitted
that
Congress
was
well
aware
of
the
difference
between
a
"
category"
and
a
"
subcategory"
when
it
enacted
§
112(
c).
When
Congress
wished
to
refer
to
both
subcategories
and
subcategories,
it
did
so
expressly.
Commenter
IV­
D­
113
stated
that
by
referring
only
to
"
category,"
Congress
made
plain
that
§
112(
c)(
9)(
B)
does
not
allow
EPA
to
delist
a
"
subcategory"
for
any
reason.
Commenter
IV­
D­
96
stated
that
EPA's
subcategorization
theories
are
unlawful.
The
commenter
presented
the
following
arguments
supporting
the
opinion
that
§
112(
c)(
9)
does
not
authorize
EPA
to
separate
identical
pollution
sources
into
subcategories
that
are
regulated
differently
to
weed
out
low
risk
facilities
or
reduce
the
scope/
cost
of
the
standard.
EPA
may
not
subcategorize
based
on
risk.
Commenter
IV­
D­
96
stated
that
subcategories
based
solely
on
risk
do
not
bear
a
reasonable
relationship
to
Congress'
technology­
based
approach
or
the
statutory
structure
and
purposes
of
§
112,
and
are
not
authorized
by
the
CAA.
Categories
and
subcategories
are
required
to
be
consistent
with
the
categories
of
stationary
sources
in
§
111.
The
commenter
was
not
aware
of
any
instance
in
which
EPA
has
established
categories
or
subcategories
based
on
risk.
The
commenter
stated
that
EPA
routinely
defines
226
subcategories
based
on
equipment
characteristics
(
e.
g.,
technical
differences
in
emissions
characteristics,
processes,
control
device
applicability,
or
opportunities
for
pollution
prevention).
The
commenter
pointed
out
that
EPA
has
not
offered
any
explanation
for
why
reinterpreting
the
statute
to
ignore
nearly
12
years
of
settled
practices
and
expectations
under
the
MACT
program
is
reasonable,
not
why
reducing
the
applicability
of
HAP
emission
standards
serves
Congress's
goals
in
enacting
the
1990
CAAA.
EPA
may
not
subcategorize
to
reduce
costs.
Commenter
IV­
D­
96
noted
that
EPA's
discussion
of
the
risk­
based
exemptions
is
contained
in
a
preamble
section
entitled,
"
Can
We
Achieve
the
Goals
of
the
Proposed
Rule
in
a
Less
Costly
Manner."
This
strongly
suggested
to
the
commenter
that
EPA's
motivation
for
considering
these
risk­
based
approaches,
including
the
§
112(
c)(
9)
approach,
is
consideration
of
cost.
Commenter
IV­
D­
96
stated
that
EPA
itself
has
rejected
the
notion
that
cost
should
influence
MACT
determination,
and
this
prior,
consistently
applied
interpretation
better
serves
the
purposes
of
§
112.
The
commenter
pointed
out
that
in
the
"
Summary
of
Public
Comments
and
responses
on
the
Proposed
NESHAP
for
Chemical
Recovery
Combustion
Sources
at
Kraft,
Soda,
Sulfite,
and
Stand­
Alone
Semichemical
Pulp
Mills"
(
attached
to
the
comment),
the
Agency
addressed
concerns
about
high
costs
and
low
emissions
reductions
by
saying
"
invoking
a
de
minimis
concept
for
MACT
floors
would
frustrate
a
primary
legislative
goal
­
disregard
of
costs
in
determining
the
MACT
floor."
When
this
decision
was
challenged
in
court,
EPA
replied
that
"
sources
already
took
costs
into
account
in
taking
measures
to
limit
HAP
emissions,
and
Congress
built
their
cost
judgements
into
the
statute
by
mandating
that
all
others
in
the
industry
achieve
the
same
limitations.
Thus,
further
consideration
of
cost
factors
by
EPA
is
both
unnecessary
and
impermissible."
(
The
commenter
attached
portions
of
the
Brief
for
Respondent
Environmental
Protection
Agency,
National
Lime
Ass'n
v.
EPA,
233
F.
3D
625
(
D.
C.
Cir.
2000),
at
47
(
July
14,
2000).)
The
commenter
stated
that
the
D.
C.
Court
agreed
with
EPA
on
this
point.
Subcategorizing
to
set
a
no
control
MACT
floor
is
the
same
as
refusing
to
set
a
MACT
standard
because
the
benefits
would
be
negligible,
which
is
unlawful.
EPA
may
not
delist
a
subcategory
of
carcinogens.
Commenter
IV­
D­
96
pointed
out
that
§
112(
c)(
9)(
B)(
i)
does
not
authorize
EPA
to
delist
subcategories.
Section
112(
c)(
9)(
B)
contains
two
subsections.
Subsection
(
i)
refers
only
to
categories,
and
subsection
(
ii)
refers
to
both
categories
and
subcategories.
The
commenter
believed
that
the
absence
of
the
term
"
subcategories"
in
§
112(
c)(
9)(
B)(
i)
indicates
a
Congressional
choice
not
to
permit
the
Administrator
to
delist
subcategories
of
sources
under
§
112(
c)(
9)(
B).
The
commenter
stated
that
this
is
consistent
with
Congress's
decision
to
require
a
higher
standard
to
delist
categories
that
emit
carcinogens.
The
commenter
added
that
the
§
112(
c)(
9)(
B)(
ii)
requirement
of
less
than
one
in
a
million
lifetime
cancer
risk
for
the
most
exposed
individual
is
a
higher
and
more
specific
standard
than
the
standard
for
other
HAP.
Commenter
IV­
D­
113
stated
that
even
if
EPA
could
delist
a
subcategory,
it
could
not
do
so
based
on
risk.
The
commenter
observed
that
§
112(
c)
states
that
"[
t]
o
the
extent
practicable,
categories
and
subcategories
listed
under
this
subsection
shall
be
consistent
with
the
list
of
source
categories
established
pursuant
to
section
111
and
part
C,"
and
the
commenter
stated
that
subcategories
based
on
risk
would
not
be
consistent
with
either
the
§
111
list
or
part
C.
The
commenter
added
that
EPA
has
interpreted
the
statement
regarding
subcategorizing
by
"
classes,
types,
and
sizes"
in
§
112(
d)
to
mean
that
subcategories
must
share
physical
characteristics
relevant
to
the
degree
of
pollution
control
that
can
be
achieved.
Because
risk
is
not
such
a
characteristic,
EPA
may
not
subcategorize
based
on
risk.
The
commenter
also
added
that
risk­
227
based
subcategories
would
be
at
odds
with
Congress's
purpose
in
enacting
§
112,
i.
e.,
requiring
technology­
based
standards
with
a
performance­
based
floor,
which
was
intended
to
overcome
the
difficulties
EPA
encountered
in
completing
health­
based
standards.
In
addition,
the
commenter
stated
that
EPA
has
not
provided
a
reason
for
departing
from
its
current
interpretation
of
the
guidelines
for
establishing
subcategories
other
than
to
avoid
setting
emission
standards.
Thus,
subcategorization
based
on
risk,
including
under
the
pretense
of
subcategorization
by
technology
(
which
EPA
admits
to
considering),
would
be
unlawful.
Commenter
IV­
D­
113
stated
that
EPA
did
not
propose
any
subcategories
for
delisting,
and
if
EPA
wanted
to
delist
a
subcategory,
they
would
have
to
propose
the
delisting
and
allow
the
public
to
comment.
The
commenter
added
that
instead
of
creating
further
delays
with
such
a
process,
EPA
should
consider
that
its
standards
are
already
late
and
should
focus
its
resources
on
completing
the
overdue
standards
instead
of
providing
unlawful
exemptions
for
industry
groups
that
wish
to
avoid
cleaning
up
their
hazardous
air
pollution.
Commenter
IV­
D­
135
noted
that
EPA
requested
comment
on
establishing
a
subcategory
of
facilities
within
the
larger
industrial
boiler
and
process
heater
source
category
that
would
meet
the
risk­
based
criteria
for
delisting
under
§
112(
c)(
9)(
B).
The
commenter
further
noted
that
§
112(
c)(
9)(
B)(
i)
authorizes
the
Administrator
to
delist
a
source
category
even
if
a
source
in
the
source
category
emits
carcinogenic
HAPs.
However,
the
Administrator
must
first
find
that
no
source
in
the
category
will
emit
such
HAPs
at
levels
that
would
cause
a
one
in
one
million
lifetime
risk
of
cancer.
[
42
U.
S.
C.
Section
7412(
c)(
9)(
B)(
i).]
The
commenter
asserted
that
clearly
EPA's
proposed
delisting
of
a
subcategory
is
inappropriate
here
because
EPA
has
not
made
the
finding
in
this
proposal
that
no
boiler
or
process
heater
source
in
the
source
category
could
emit
greater
than
this
amount
for
all
of
the
carcinogens
regulated
by
this
rulemaking.
Commenter
IV­
D­
05
stated
that
the
only
option
that
appears
consistent
with
the
CAA,
does
not
create
excessive
work
for
State
and
local
agencies,
and
may
be
able
to
be
based
on
science,
is
the
subcategorization
and
delisting
approach.
However,
the
commenter
added
that
the
subcategories
should
be
based
on
equipment
or
fuel
use,
not
risk.
The
commenter
added
that
a
subcategory
based
on
site­
specific
risk
creates
a
circular
definition
and
does
not
make
sense.
The
commenter
also
stated
that
subcategory
de­
listing
should
occur
before
the
compliance
date
so
that
facilities
don't
put
off
compliance
in
the
hope
or
anticipation
of
de­
listing.
Commenter
IV­
D­
96
stated
that
EPA
requested
comment
on
the
establishment
of
PCWP
subcategories
ostensibly
based
on
physical
and
operational
characteristics,
but
in
reality
based
on
risk.
The
commenter
responded
that
This
indirect
approach
is
just
a
variation
on
the
approach
(
direct
reliance
on
risk)
that
EPA
itself
notes
would
disrupt
and
weaken
establishment
of
MACT
floors,
and
is
accordingly
unlawful.
The
commenter
stated
that
even
if
these
approaches
were
lawful,
to
the
extent
that
EPA's
proposal
could
be
read
to
suggest
that
facilities
could
be
allowed
to
become
part
of
the
allegedly
low­
risk
subcategory
in
the
future
without
additional
EPA
rulemaking,
this
too
would
be
unlawful.
According
to
the
commenter,
§
112(
c)(
9)
provides
the
EPA
Administrator
alone
the
authority
to
make
delisting
determinations,
and
such
authority
may
not
be
delegated
to
other
government
authorities
or
private
parties.
The
commenter
stated
that
EPA's
proposal
suggests
an
approach
entirely
backward
from
the
statute,
i.
e.,
allowing
sources
to
demonstrate
after­
the­
fact
that
it
belongs
in
a
subcategory
that
has
been
delisted
under
subsection
112(
c)(
9),
when
the
statute
requires
that
EPA
determine
that
no
source
in
the
category
emits
cancer­
causing
HAPs
above
specified
levels,
or
that
no
source
in
the
category
or
subcategory
emit
non­
carcinogenic
HAPs
above
specified
levels,
by
the
time
the
agency
establishes
the
standard.
Commenter
IV­
D­
96
noted
that
EPA
provides
no
explanation
of
how
the
suggested
approaches
228
would
be
lawful
or
workable.
Commenter
IV­
D­
55
requested
that
EPA
focus
on
the
different
circumstances
applicable
to
seasonal
agricultural
operations
to
exempt
facilities.
The
commenter
claimed
that
emissions
of
HAPs
such
as
HCl
and
acetaldehyde
on
a
seasonal
basis
do
not
create
any
risk
to
health
or
safety.
The
commenter
noted
that
in
the
past
EPA
has
treated
acetaldehyde
as
a
non­
threshold
pollutant,
but
that
in
reassessing
the
carcinogenic
dose­
response
relationship
for
acetaldehyde,
EPA
is
considering
reclassifying
acetaldehyde
as
a
threshold
carcinogen
subject
to
risk
exceptions.
The
commenter
believed
that
EPA
should
create
a
risk­
based
exemption
for
seasonal
agricultural
facilities
which
trigger
HAP
thresholds
through
natural
production
of
food
products.
The
commenter
asserted
that
the
absence
of
any
serious
risk
of
cancer
or
carcinogenic
affects
from
HCl,
a
surrogate
for
non­
HAPs
emissions,
indicated
that
sugar
beet
processing
is
a
subcategory
ideally
suited
for
delisting.
Commenter
IV­
D­
127
noted
that
the
MACT
floor
analysis
did
not
define
a
required
control
for
any
small
boiler
and
submitted
that
the
size
and
type
of
unit
are
clearly
distinguishable
and
the
risk
offered
by
these
units
is
exceptionally
small.
The
commenter
asserted
that
due
to
the
low
risk
offered
by
small
equipment,
the
easy
identification
of
the
equipment,
and
the
consistent
low­
risk
character
of
the
emissions,
small
equipment
firing
any
fuel
should
be
subcategorized
and
delisted
from
the
MACT
source
category.
Commenter
IV­
D­
127
believed
that
boilers
and
process
heaters,
of
all
sizes,
firing
gaseous
fossil
fuels
and
distillate
fuel
oil
represented
a
low
risk
class
of
boilers
and
process
heaters.
The
commenter
stated
that
due
to
the
low
risk
offered
by
equipment
firing
these
fuels,
the
easy
identification
and
characterization
of
the
fuels,
and
the
consistency
of
the
character
of
the
emissions,
equipment
firing
gaseous
fossil
fuel
and
distillate
fuel
oil
should
be
subcategorized
and
delisted
from
the
MACT
source
category.
Response:
As
is
explained
in
response
18.2.1,
we
have
chosen
to
exercise
the
authority
granted
to
us
pursuant
to
§
112(
d)(
4)
of
the
CAA
in
establishing
health­
based
emission
standards
for
HCl
and
Mn
which
are
applicable
to
the
large
solid
fuel­
fired
subcategories.
For
a
discussion
of
our
use
of
§
112(
c)(
9)
authority
to
define
a
risk­
based
subcategory
and
delist
the
subcategory
refer
to
the
PCWP
NESHAP
final
preamble.
(
See
Docket
ID
No.
OAR­
2003­
0048.)

18.4.2
The
Impact
on
MACT
floors
of
a
Low­
Risk
Subcategory
Comment:
Commenter
IV­
D­
05
stated
that
the
preamble
discussion
of
a
low­
risk
subcategory
on
the
MACT
floors
for
the
entire
category
sounds
like
another
valid
reason
not
to
mix
the
risk­
based
and
technology­
based
standards
development.
The
commenter
added
that
EPA
does
not
address
how
the
"
once
in,
always
in"
policy
would
apply.
Commenter
IV­
D­
96
stated
that
EPA
itself
provides
an
additional
compelling
reason
why
the
suggested
§
112(
c)(
9)
sub­
categorization
approach
is
unlawful
and
arbitrary,
i.
e.,
its
effect
on
establishment
of
MACT
floors.
According
to
the
commenter,
this
flaw
is
so
obvious,
inherent
and
contrary
to
the
MACT
floor
provisions
of
§
112
and
its
legislative
history,
that
it
proves
the
undoing
of
the
suggested
§
112(
c)(
9)
exemption.
The
commenter
believed
that
EPA
cannot
simultaneously
exercise
its
source
category
delisting
authority
consistent
with
§
112(
c)(
9),
establish
appropriate
MACT
floors
under
§
112(
d),
and
establish
sub­
category
exemptions
in
the
manner
suggested
by
EPA,
because
the
latter
approach
contravenes
both
§
112(
c)(
9)
and
the
§
112(
d)
floor­
setting
process.
Commenter
IV­
D­
96
stated
further
that
EPA
may
not
subcategorize
based
upon
risk,
or
229
delist
a
subcategory
of
carcinogens
because
there
is
nothing
in
the
CAA
authorizing
EPA
to
do
either
with
respect
to
individual
facilities
or
subcategories
after
a
MACT
standard
has
been
established.
Section
112'
s
major
source
thresholds
and
statutory
deadlines
make
clear
that
sources
meeting
MACT
by
the
time
EPA
is
required
to
issue
MACT
standards
must
install
MACT
controls
and
may
not
subsequently
throw
them
off
or
be
relieved
from
meeting
the
MACT­
level
standards.
The
commenter
asserts
that
while
the
§
112(
f)
residual
risk
process
allows
EPA
to
establish
more
stringent
emissions
standards,
there
is
nothing
in
the
CAA
that
suggests
EPA
possesses
authority
to
relax
promulgated
MACT
standards.
Commenter
IV­
D­
113
stated
that
even
if
EPA
could
subcategorize
based
on
risk,
it
would
be
unlawful
for
EPA
to
refuse
to
consider
low­
risk
facilities
in
the
floor
calculations
since
§
112
does
not
provide
any
exceptions
to
its
mandate
to
base
floors
on
the
emission
levels
achieved
by
the
relevant
best­
performing
sources.
Commenter
IV­
D­
135
stated
that
EPA
recognized
that
a
concern
with
the
approach
of
delisting
a
subcategory
of
facilities
under
§
112(
c)(
9)(
B)
is
the
effect
it
would
have
on
the
MACT
floors.
If
many
of
the
facilities
in
the
low­
risk
categories
are
well
controlled
or
have
low
emissions,
removing
them
from
the
category
could
make
the
MACT
floor
less
stringent
for
the
remaining
facilities.
The
commenter
observed
that
this
was
inconsistent
with
the
CAA
mandate
that
the
MACT
floors
reflect
the
emissions
limitation
achieved
by
the
best
performing
sources.
Commenter
IV­
D­
73
supported
the
concept
described
in
the
preambles
regarding
the
establishment
of
the
MACT
floor
based
on
the
controls
for
the
entire
source
category.
The
commenter
agreed
that
considering
controls
for
low­
risk
subcategories
could
maintain
the
appropriate
stringency
of
the
MACT
floor.
Once
the
floor
is
established,
facilities
could
demonstrate
their
inclusion
in
the
low­
risk
category
that
is
subsequently
listed.
Response:
We
have
chosen
not
to
use
§
112(
c)(
9)
authority
to
delist
a
subcategory
and
there
are
no
additional
subcategories
and
no
delisting
of
subcategories,
as
would
be
consistent
with
§
112(
c)(
9).
We
are
not
attempting
to
establish
or
rely
upon
de
minimis
authority.
Instead
we
are
using
§
112(
d)(
4)
authority
to
establish
health­
based
compliance
alternatives
for
affected
facilities
in
the
large
solid
fuel­
fired
boilers
and
process
heaters
subcategory
that
demonstrate
eligibility
under
the
procedures
prescribed
in
Appendix
A
to
the
final
rule.
For
affected
facilities
that
demonstrate
eligibility
for
the
health­
based
compliance
alternatives
for
HCl
and/
or
Mn,
the
parameters
used
to
demonstrate
eligibility
will
be
incorporated
into
title
V
permits
as
federally
enforceable
permit
terms
and
the
affected
sources
will
remain
subject
to
the
monitoring,
reporting,
and
recordkeeping
requirements
of
the
final
rule.
Additionally,
affected
sources
that
demonstrate
eligibility
for
the
Mn
compliance
alternative
will
be
required
to
comply
with
the
PM
limit
or
the
TSM
limit
based
on
seven
metals
(
excluding
Mn)
instead
of
eight.
Therefore,
the
affected
sources
remain
in
the
MACT
database
and
the
boiler
and
process
heater
MACT
floors
are
not
affected.

18.5
RISK
ASSESSMENT
FRAMEWORK
ISSUES:
POLLUTANT­
SPECIFIC
BENCHMARKS
18.5.1
Boiler
and
process
heater
risk
low
Comment:
Commenter
IV­
D­
179
expressed
concern
about
the
imposition
of
very
stringent
standards
for
HCl
emissions
from
solid
fuel­
fired
boilers.
The
commenter
completed
air
dispersion
modeling
of
the
HCl
emission
that
could
be
present
at
their
Rock
Hill
plant
that
operates
five
coal­
fired
boilers.
Three
of
the
units
have
a
heat
input
capacity
of
176
MMBtu/
hr
230
and
the
other
two
have
a
heat
input
capacity
of
222
MMBtu/
hr.
The
boilers
are
equipped
with
ESPs
for
particulate
control
but
are
not
currently
controlled
for
HCl
emissions.
As
input
to
the
dispersion
model,
commenter
IV­
D­
179
estimated
the
maximum
emissions
likely
to
be
expected.
First,
the
commenter
calculated
the
maximum
HCl
emission
factor
based
on
the
highest
chlorine
content
in
coal
delivered
to
the
plant
over
a
five
year
period
and
assuming
it
would
be
totally
converted
to
HCl
emissions.
Second,
the
commenter
also
developed
a
worstcase
emission
factor
from
stack
testing
of
similar
boilers
at
the
commenter's
plant
in
Narrows,
Virginia
which
obtain
coal
from
a
different
source.
The
resulting
worst­
case
emission
factor
estimates
were
0.17
and
0.23
lb/
MMBtu
HCl,
respectively.
Each
of
these
emission
factors
was
applied
to
the
maximum
rated
capacities
of
the
five
coal­
fired
boilers
at
the
Rock
Hill
site
to
estimate
maximum
emissions
of
HCl
for
each
emission
point.
The
commenter
modeled
these
resulting
emission
rates
using
the
Industrial
Source
Complex
Short
Term
Model,
Version
3
(
ISCST3)
dispersion
model.
Modeling
was
performed
in
accordance
with
approved
procedures
documented
in
EPA's
"
Guideline
on
Air
Quality
Models".
The
maximum
predicted
annual
concentration
was
0.95

g/
m3
HCl.
The
HQ
calculated
from
the
RfC
(
20

g/
m3)
is
0.05.
Therefore,
there
is
not
a
concern
for
long
term
health
effects
from
the
maximum
exposure
to
HCl
that
can
be
expected
from
the
Rock
Hill
plant.
Similarly,
the
maximum
predicted
short
term
exposures
(
24­,
12­,
8­,
and
1­
hour
concentrations)
were
well
below
any
short
term
exposure
guidelines
for
HCl.
Commenter
IV­
D­
179
asserted
that
this
study
shows
that
the
concentrations
of
HCl
near
the
Rock
Hill
facility
are
well
below
any
thresholds
of
concern.
Yet,
the
proposed
rule
would
require
the
installation
of
very
expensive
scrubbing
technology
even
when
the
HAP
removed
does
not
pose
a
health
threat
to
the
surrounding
community.
The
commenter
estimated
that
installation
of
scrubbing
technology
at
the
Rock
Hill
facility
will
cost
three
to
five
million
dollars
and
is
not
justified
given
the
total
lack
of
environmental
risk
to
human
health.
Response:
As
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63,
the
final
rule
will
include
a
provision
allowing
affected
sources
to
make
a
health­
based
demonstration
for
emissions
of
HCl
for
those
boilers
and
process
heaters
in
the
large
solid
fuel­
fired
subcategory.
Affected
sources
that
can
demonstrate
eligibility
for
this
compliance
alternative
by
either
a
look­
up
table
analysis
or
site­
specific
modeling
will
not
be
required
to
install
additional
scrubbing
technology.
These
boilers
and
process
heaters
would
still
be
required
to
meet
the
PM
limit
or
the
alternative
TSM
emission
limits.

Comment:
Nine
commenters
(
IV­
D­
28,
IV­
D­
39,
IV­
D­
99,
IV­
D­
100,
IV­
D­
124,
IV­
D­
129,
IV­
D­
132,
IV­
D­
133,
and
IV­
D­
134)
submitted
that
boilers
sized
50
MMBtu
or
smaller
should
be
exempt
from
regulation
because
those
boilers
do
not
emit
any
pollutant
that
would
threaten
public
health
as
defined
by
CAA,
§
112(
f).
The
commenters
cited
CAA
§
112(
f)(
2)
which
requires
standards
applicable
to
a
source
or
source
category
that
emit[
s]
a
pollutant
classified
as
a
known
or
possible
human
carcinogen
do
not
reduce
the
"
lifetime
excess
cancer
risk
to
the
individual
most
exposed
to
emissions
from
a
source
in
the
category
or
subcategory
to
less
than
one
in
one
million."
The
commenters
noted
that
commenter
IV­
D­
39
authorized
a
study
of
metallic
HAP
emissions
from
typical
furniture
industry
wood
and
coal­
fired
boilers.
The
emissions
estimates
in
this
study
were
based
on
EPA
emission
factors
from
AP­
42
and
resulted
in
emissions
exceeding
EPA's
alternative
cumulative
metals
exemption
level.
However,
Mn
was
responsible
for
91.8
percent
of
the
emissions
from
wood
residue
and
was
the
only
constituent
over
the
metals
exemption
threshold.
The
commenters
pointed
out
that
according
to
EPA,
Mn
is
231
a
category
D
pollutant
that
is
mainly
an
irritant
in
large
quantities
and
is
not
classifiable
as
to
carcinogenicity
in
humans.
The
commenters
stated
that
commenter
IV­
D­
39
is
in
the
process
of
finalizing
a
study
to
confirm
that
small
boilers
in
the
furniture
industry
do
not
emit
enough
HAP
to
create
a
health­
based
risk.
The
commenters
asserted
that
not
only
are
small
boilers
not
a
health
risk,
but
they
do
not
emit
any
carcinogens
that
can
be
measured
above
trace
amounts
while
combusting
wood
fuel.
Response:
Manganese
is
a
threshold
pollutant
and
has
not
been
suspected
of
causing
cancer.
Therefore,
cancer
risk
estimates
are
not
applicable
to
Mn.
As
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63,
the
final
rule
will
include
a
provision
allowing
affected
sources
with
boilers
and
process
heaters
in
the
large
solid
fuel­
fired
subcategory
to
make
a
healthbased
demonstration
for
Mn
emissions.
Affected
sources
that
can
demonstrate
eligibility
for
this
compliance
alternative
by
either
a
look­
up
table
analysis
or
site­
specific
modeling
will
not
be
required
to
include
Mn
in
their
metals
limit
(
TSM)
under
the
Boilers
MACT
but
can
comply
with
a
TSM
limit
based
on
seven
metals
(
excluding
Mn)
rather
than
eight.

Comment:
Commenters
IV­
D­
26,
IV­
D­
104,
and
IV­
D­
150
presented
the
results
of
a
detailed
modeling
analysis
of
TSM,
Hg,
and
HCl
emissions
conducted
for
four
sugar
mills.
Standard
EPA
models
and
protocols
were
followed
in
the
analysis.
Maximum
annual
impacts
at
the
property
line
for
each
mill
were
determined
based
on
the
existing
mill
operations
and
stack
parameters.
The
maximum
total
impacts
due
to
each
mill
for
TSM,
Hg,
and
HCl
were
then
compared
to
the
RfC
for
each
HAP,
as
well
as
the
unit
risk
factor
(
for
carcinogens),
as
shown
in
Table
4
of
the
preamble
to
the
proposed
rule.
The
commenters
presented
two
sets
of
results,
one
based
on
fuel
analysis
and
not
reflecting
any
reduction
in
emissions
due
to
the
inherent
removal
mechanisms
(
the
fly
ash
resulting
from
bagasse
fuel
burning
is
highly
alkaline,
resulting
in
significant
absorption
of
acid
gases)
or
to
existing
control
devices
(
one
boiler
utilizes
an
ESP)
and
the
second
based
on
emissions
determined
from
stack
testing.
The
total
impact
of
TSM,
Hg,
and
HCl
emissions
based
solely
on
fuel
analysis,
is
well
below
a
HI
of
1.0,
but
results
in
a
risk
of
six
in
one
million
for
carcinogens
(
eight
metals,
including
arsenic,
beryllium,
cadmium,
chromium
(
VI),
lead,
Mn,
nickle,
and
selenium).
The
total
impact
of
TSM,
Hg,
and
HCl
emissions
based
on
stack
test
results
accounting
for
the
effects
of
existing
control
devices
on
sugar
mill
boilers
show
a
reduction
in
excess
cancer
risk
to
less
than
one
in
one
million.
Commenters
IV­
D­
104
and
IV­
D­
26
submitted
that
the
purpose
of
this
analysis
is
to
demonstrate
that
bagasse
fuel
by
its
very
nature
is
a
clean
fuel,
is
consistent
in
quality,
and
emissions
of
TSM,
Hg,
or
HCl
from
bagasse
fuel
burning
pose
no
risk
to
the
public;
therefore,
bagasse
fuel
does
not
warrant
regulation
in
regards
to
PM/
TSM,
Hg,
or
HCl.
The
commenters
requested
that
bagasse
be
specifically
exempted
from
the
PM/
TSM,
Hg,
and
HCl
limits
of
the
MACT
rule.
If
this
exemption
is
not
granted,
the
commenters
supported
the
option
of
fuel
analysis
to
demonstrate
compliance,
but
believe
that
the
continuous
compliance
demonstration
requirements
and
other
requirements
related
to
fuel
testing
must
be
reduced
considerably
to
be
manageable.
Response:
As
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63,
the
final
rule
will
include
a
provision
allowing
affected
sources
to
make
a
health­
based
demonstration
for
Mn
and/
or
HCl
emissions.
Affected
sources
that
can
demonstrate
eligibility
for
the
Mn
compliance
alternative
by
either
a
look­
up
table
analysis
or
site­
specific
modeling
will
not
be
required
to
include
Mn
in
their
metals
limit
(
TSM)
under
the
Boilers
MACT
but
can
comply
with
a
TSM
limit
based
on
seven
metals
(
excluding
Mn)
rather
than
eight.
Affected
sources
that
can
demonstrate
eligibility
for
the
HCl
compliance
alternative
by
either
look­
up
table
analysis
or
site­
232
specific
modeling
will
not
be
required
to
install
additional
scrubbing
technology.
These
are
the
only
health­
based
compliance
alternatives
included
in
the
final
rule.
No
specific
exemption
for
bagasse
fuel
has
been
included
in
the
health­
based
compliance
alternatives.
All
affected
sources
with
boilers
and
process
heaters
in
the
applicable
large
solid
fuel­
fired
subcategory
have
an
opportunity
to
demonstrate
that
they
can
meet
the
health­
based
compliance
alternatives
for
HCl
and/
or
Mn.
Fuel
analysis
requirements
related
to
continuous
compliance
demonstration
are
addressed
elsewhere
in
this
document.
When
an
affected
source
is
demonstrating
eligibility
for
the
health­
based
compliance
alternatives,
fuel
sampling
and
analysis
are
not
included
as
options
for
quantifying
HCl
and/
or
Mn
emissions
levels
from
boilers
and
process
heaters
at
the
affected
source.
Affected
sources
must
conduct
emissions
testing
for
HCl,
Cl
2,
and/
or
Mn
emissions
levels.

18.5.2
Dose­
response
values
Comment:
Commenter
IV­
D­
96
stated
that
§
112(
d)(
4)
is
particularly
ill­
suited
to
the
PCWP
and
Boiler
source
categories.
The
commenter
stated
that
even
if
EPA
had
authority
to
create
individualized
MACT
exemptions
based
on
health
thresholds,
it
could
not
do
so
if
there
is
insufficient
evidence
on
the
pollutants
emitted
to
establish
a
NOEL.
Section
112(
d)(
4)
does
not
apply
for
chemicals
that
do
not
have
a
well­
defined
threshold
based
on
reliable
science.
Available
evidence
does
not
establish
a
no­
effect
threshold
for
HF.
Commenter
IV­
D­
96
stated
that
IRIS
and
NATA
do
not
contain
HF.
EPA
acknowledges
data
suggesting
that
those
with
occupational
exposure
to
fluoride
have
greater
than
normal
incidences
of
cancer
(
www.
epa.
gov/
ttn/
atw/
hlthef/
hydrogen.
html).
Registry
of
Toxic
Effects
of
Chemical
Substances
(
RTECS)
suggests
that
HF
has
a
mutagenic
effect
in
animals.
EPA
does
not
have
enough
evidence
to
classify
HF
as
a
threshold
pollutant
or
to
conclude
that
HF
is
not
a
carcinogen.
One
limited
study
(
Derryberry
et
al,
1963)
contains
a
NOEL
for
HF
but
does
not
account
for
children's
exposure.
There
is
no
determined
no­
effect
level
for
children,
infants,
and
fetuses.
Available
evidence
does
not
establish
a
no­
effect
threshold
for
HCl.
Commenter
IV­
D­
96
stated
that
IRIS
states
that
HCl
"
has
not
undergone
a
complete
evaluation
and
determination"
for
cancerous
effects.
Elsewhere
EPA
concludes
that
no
information
exists
on
HCl
carcinogenicity
in
humans
(
www.
epa.
gov/
ttn/
atw/
hlthef/
hydrochl.
html).
RTECS
explains
that
HCl
has
not
reported
tumorigenic
effect,
but
could
have
a
mutagenic
effect
in
animals.
EPA
cannot
conclude
that
HCl
does
not
cause
cancer.
Rat
studies
failed
to
identify
a
NOEL
for
HCl.
Therefore,
the
commenter
expressed
concern
that
chronic
exposure
to
low
levels
of
HCl
could
compromise
health,
especially
in
sensitive
subpopulations.
Available
evidence
does
not
establish
a
no­
effect
threshold
for
manganese
compounds.
Commenter
IV­
D­
96
stated
that
Mn
compounds
are
on
the
list
of
33
urban
air
toxics.
Regulatory
assessments
of
Mn's
toxicological
properties
prevent
EPA
from
treating
the
chemical
as
a
threshold
pollutant.
The
IRIS
profile
for
Mn
only
has
lowest
observed
adverse
effect
levels
(
LOAEL)
for
several
critical
effects
of
inhalation
exposure
to
the
substance.
California
EPA
(
CalEPA)
Office
of
Environmental
Health
Hazard
Assessment's
(
OEHHA)
chronic
toxicity
summary
states
that
there
is
no
observed
adverse
effect
level
(
NOAEL)
for
the
critical
effect
(
impairment
of
neurobehavioral
function).
Available
evidence
does
not
establish
a
no­
effect
threshold
for
arsenic.
Commenter
IV­
D­
96
stated
that
the
preamble
acknowledges
that
arsenic
is
a
human
carcinogen.
EPA's
IRIS
database
indicates
that
there
is
no
data
for
establishing
a
RfC
for
arsenic
exposure
by
inhalation
or
233
other
pathways.
In
addition,
CalEPA
OEHHA
reports
no
inhalation
NOAEL
for
exposure
to
arsenic.
Available
evidence
does
not
establish
a
no­
effect
threshold
for
cadmium.
Commenter
IVD
96
stated
that
the
preamble
acknowledges
that
cadmium
is
a
probable
human
carcinogen.
EPA's
IRIS
database
indicates
that
there
is
no
data
for
establishing
a
RfC
for
cadmium
exposure
by
inhalation
or
other
pathways.
Available
evidence
does
not
establish
a
no­
effect
threshold
for
chromium.
Commenter
IVD
96
stated
that
the
preamble
acknowledges
that
chromium
IV
is
a
human
carcinogen.
EPA's
IRIS
database
does
not
state
that
thresholds
exist
for
all
negative
health
effects
associated
with
chromium
III
or
chromium
IV
exposure
by
inhalation
or
other
pathways.
In
addition,
CalEPA
OEHHA
reports
no
inhalation
NOAEL
for
exposure
to
chromium.
Available
evidence
does
not
establish
a
no­
effect
threshold
for
lead.
Commenter
IV­
D­
96
stated
that
the
preamble
acknowledges
that
lead
is
a
probable
human
carcinogen.
EPA's
IRIS
database
indicates
that
there
is
no
data
for
establishing
a
RfC
for
lead
exposure
by
inhalation
or
other
pathways.
Available
evidence
does
not
establish
a
no­
effect
threshold
for
mercury.
Commenter
IVD
96
stated
that
the
preamble
acknowledges
that
mercury
is
a
possible
human
carcinogen.
EPA's
IRIS
database
indicates
that
there
is
no
data
for
establishing
a
RfC
for
exposure
to
mercuric
chloride,
and
the
database
does
not
state
that
thresholds
exist
for
all
negative
health
effects
caused
by
exposure
to
elemental
mercury.
In
addition,
CalEPA
OEHHA
reports
no
NOAEL
for
exposure
to
mercury.
Available
evidence
does
not
establish
a
no­
effect
threshold
for
nickel.
Commenter
IV­
D­
96
stated
that
the
preamble
acknowledges
that
nickel
refinery
subsulfide
as
a
human
carcinogen
and
nickel
carbonyl
as
a
probably
human
carcinogen.
EPA's
IRIS
database
indicates
that
there
is
no
data
for
establishing
a
RfC
for
exposure
to
any
of
the
four
nickel
substances
that
it
lists.
In
addition,
CalEPA
OEHHA
reports
no
NOAEL
for
exposure
to
nickel
oxide.
Response:
As
stated
previously,
we
are
pursuing
establishment
of
a
threshold
emission
rate
for
the
boilers
and
process
heaters
source
category
under
§
112(
d)(
4)
for
specific
threshold
pollutants
emitted
from
affected
sources.
We
agree
that
§
112(
d)(
4)
applies
to
threshold
pollutants.
In
the
absence
of
specific
scientific
evidence
to
the
contrary,
it
has
been
our
policy
to
classify
non­
carcinogenic
effects
as
threshold
effects.
RfC
development
is
the
default
approach
for
threshold
(
or
nonlinear)
effects.
The
methodology
employed
by
EPA,
which
is
consistent
with
that
used
by
other
sources
we
consult,
recognizes
that
while
a
NOAEL
is
preferable
to
a
LOAEL
for
use
as
the
point
of
departure
(
POD)
to
which
uncertainty
factors
are
applied
to
derive
a
RfC,
a
LOAEL
may
also
be
used
(
or
a
benchmark
concentration
derived
from
benchmark
modeling).
1
Use
of
the
LOAEL
or
other
POD
does
not
change
the
underlying
presumption
of
a
nonlinear
(
or
threshold)
dose­
response
relationship.
For
air
toxics
risk
assessments,
we
identify
pertinent
toxicity
or
dose­
response
values
using
a
default
hierarchy
of
sources,
with
IRIS
being
the
preferred
source,
to
assist
us
in
identifying
the
most
scientifically
appropriate
benchmarks
for
our
analyses
and
decisions.
The
IRIS
process
contains
internal
and
external
peer
review
steps
and
represents
EPA
consensus
values.
When
adequate
toxicity
information
is
not
available
in
IRIS,
we
consult
other
sources
in
a
default
hierarchy
that
recognizes
the
desirability
of
these
qualities
in
ensuring
that
we
have
consistent
and
scientifically
sound
assessments.
Furthermore,
where
the
IRIS
assessment
substantially
lags
the
current
scientific
knowledge,
we
are
committed
to
consider
alternate
credible
and
readily
available
assessments.
RfCs
or
similar
values
from
other
sources
are
available
for
all
of
the
HAP
listed
by
the
commenter,
and
we
currently
rely
on
these
values
for
234
assessments
of
non­
cancer
risks.
Comments
pertaining
to
the
final
PCWP
NESHAP
are
addressed
in
the
promulgation
preamble
for
that
rule.
(
See
Docket
ID
No.
OAR­
2003­
0048.)

Comment:
Commenter
IV­
D­
135
stated
that
HCl
applicability
cutoffs
are
not
permissible.
In
the
IRIS
database,
EPA
stated
that
HCl
"
has
not
undergone
a
complete
evaluation
and
determination"
for
cancerous
effects.
EPA
also
stated
that
"
no
information"
exists
on
HCl
carcinogenicity
in
humans.
In
addition,
EPA
set
the
RfC
at
0.02
milligrams
per
cubic
meter
(
mg/
m3)
based
on
rat
studies
demonstrating
adverse
effect.
These
studies
failed
to
establish
a
NOEL.
Response:
While
the
EPA
has
not
developed
a
formal
evaluation
of
the
potential
for
HCl
carcinogenicity
(
e.
g.,
for
IRIS),
the
evaluation
by
the
International
Agency
for
Research
on
Cancer
stated
that
there
was
inadequate
evidence
for
carcinogenicity
in
humans
or
experimental
animals
and
thus
concluded
that
HCl
is
not
classifiable
as
to
its
carcinogenicity
to
humans
(
Group
3
in
their
categorization
method).
Therefore,
for
the
purposes
of
the
final
rule,
we
have
evaluated
HCl
only
with
regard
to
non­
cancer
effects.
In
the
absence
of
specific
scientific
evidence
to
the
contrary,
it
has
been
our
policy
to
classify
non­
carcinogenic
effects
as
threshold
effects.
RfC
development
is
the
default
approach
for
threshold
(
or
nonlinear)
effects.
The
methodology
employed
by
EPA,
which
is
consistent
with
that
used
by
other
sources
we
consult,
recognizes
that
while
a
NOAEL
is
preferable
to
a
LOAEL
for
use
as
the
POD
in
deriving
a
RfC,
a
LOAEL
may
also
be
used
(
or
a
benchmark
concentration
derived
from
benchmark
modeling).
1
Use
of
the
LOAEL
rather
than
a
NOAEL
does
not
change
the
underlying
presumption
of
a
nonlinear
(
or
threshold)
dose­
response
relationship.
A
NOEL
is
not
recommended
for
use
in
developing
a
RfC.

Comment:
Commenter
IV­
D­
05
stated
that
EPA
should
consider
formaldehyde
and
acetaldehyde
as
carcinogens
unless
a
reassessment
classifies
them
as
threshold
pollutants.
Commenter
IV­
D­
148
stated
that
the
proposals
inappropriately
use
draft
guidelines
and
toxicity
profiles
that
have
not
been
subject
to
public
review
and/
or
are
not
publicly
available.
The
commenter
was
particularly
concerned
with
the
reference
to
the
use
of
non­
linear
carcinogenic
risk
values
and
toxicity
profiles
(
for
HAP)
that
have
not
been
finalized
and
are
not
available
for
review
by
the
public.
Response:
We
agree
that
we
should
use
the
best
available
sources
of
health
effects
information
for
risk
or
hazard
determinations.
As
we
have
stated
previously,
we
will
not
be
relying
exclusively
on
IRIS
values,
but
will
be
considering
all
credible
and
readily
available
assessments.
2
For
air
toxics
risk
assessments,
we
identify
pertinent
toxicity
or
dose­
response
values
using
a
default
hierarchy
of
sources,
with
IRIS
being
the
preferred
source,
to
assist
us
in
identifying
the
most
scientifically
appropriate
dose­
response
values
for
our
analyses
and
decisions.
The
IRIS
process
contains
internal
and
external
peer
review
steps
and
represents
EPA
consensus
values.
When
adequate
toxicity
information
is
not
available
in
IRIS,
we
consult
other
sources
in
a
default
hierarchy
that
recognizes
the
desirability
of
these
qualities
to
ensure
that
we
have
consistent
and
scientifically
sound
assessments.
Furthermore,
where
the
IRIS
assessment
substantially
lags
the
current
scientific
knowledge,
we
are
committed
to
consider
alternative
credible
and
readily
available
assessments.
For
our
use,
these
alternatives
need
to
be
grounded
in
publicly
available,
peer­
reviewed
information.
We
are
not
using
information
that
does
not
meet
these
requirements.
We
agree
with
the
commenter's
statement
that
formaldehyde
and
acetaldehyde
are
considered
probable
human
carcinogens.
However,
both
of
these
HAP
can
also
235
cause
non­
carcinogenic
(
threshold)
effects.
For
the
final
rule,
we
are
applying
§
l12(
d)(
4)
only
to
HAP
that
can
result
in
threshold
effects.
Affected
sources
conducting
risk
assessments
should
refer
to
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
and
other
analytic
tools
such
as
the
"
Air
Toxics
Risk
Assessment
Reference
Library"
(
if
appropriate
for
the
specific
source)
for
guidance
on
choosing
appropriate
dose­
response
values.

Comment:
Commenter
IV­
D­
14
agreed
with
EPA's
choice
to
derive
their
data
from
IRIS,
CalEPA
and
Agency
for
Toxic
Substances
and
Disease
Registry
(
ATSDR)
for
its
documentation
for
establishing
risk
based
threshold
and
non­
threshold
values.
The
commenter
added
that
almost
all
HAP
are
being
reviewed
and
reevaluated
on
a
regular
basis,
and
it
would
be
inappropriate
to
single
out
formaldehyde
and
acetaldehyde
at
this
time.
EPA
can
only
rely
on
what
is
currently
published
and
underwent
either
peer
review
or
agency
review.
The
issue
of
changing
health­
based
guideline
values
will
always
be
a
concern
once
health­
based
regulations
are
promulgated.
Response:
We
agree
with
the
commenter
that
the
issue
of
changing
health­
based
guideline
values
is
a
general
challenge
in
setting
health­
based
regulations.
However,
we
are
committed
to
setting
such
regulations
that
reflect
current
scientific
understanding,
to
the
extent
feasible.
Where
we
identify
pollutant
assessments
that
substantially
lag
current
understanding,
we
have
committed
to
consider
alternative
credible,
current,
and
readily
available
assessments,
developed
using
a
process
that
includes
external
peer­
review
and,
where
appropriate,
organization
consensus.
Affected
sources
conducting
risk
assessments
should
refer
to
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
and
other
analytic
tools
such
as
the
"
Air
Toxics
Risk
Assessment
Reference
Library"
(
if
appropriate
for
the
specific
source)
for
guidance
on
choosing
appropriate
dose­
response
values.

Comment:
Commenter
IV­
D­
40
asserted
that
the
proposal
in
the
preamble
that
would
permit
the
provision
of
CAA
§
112(
d)(
4)
to
"
be
applied
to
both
threshold
and
nonthreshold
pollutants
using
the
one
in
a
million
cancer
risk
level
for
decision
making
for
nonthreshold
pollutants"
was
not
acceptable.
The
commenter
noted
that
separate
calculations
are
made
of
cancer
risks
and
noncancer
HQ
and
stated
that
decisions
to
remediate
a
site
contaminated
with
threshold
pollutants
or
to
establish
threshold
level
based
emission
standards
should
not
be
based
on
cancer
risk
estimates.
The
commenter
believes
that
if
a
remedial
decision
were
based
on
the
cancer
risk
alone,
no
action
could
be
taken
at
a
site,
e.
g.,
with
a
HI
for
exposure
via
the
soil
ingestion
pathway
that
is
greater
than
one.
The
commenter
submitted
that
as
a
conservative
measure,
a
comparison
of
concentrations
of
threshold
HAP
emitted
from
boilers
and
process
heaters
to
risk­
based
concentrations
could
be
made,
and
suggested
the
EPA
Region
3
Risk­
Based
Concentration
table
would
be
a
good
reference
for
this
comparison.
Regarding
the
application
of
`
an
ample
margin
of
safety'
to
the
threshold
levels,
the
commenter
requested
that
further
description
of
the
safety
margin
be
provided
to
ensure
a
reviewer
that
the
procedure
will
adequately
protect
human
health.
Response:
For
the
final
rule,
we
are
applying
§
l12(
d)(
4)
only
to
threshold
pollutants.
In
the
modeling,
we
compare
predicted
exposure
concentrations
for
specified
HAP
to
appropriate
dose­
response
values.
As
stated
above,
we
identify
pertinent
toxicity
or
dose­
response
values
using
a
default
hierarchy
of
sources,
with
IRIS
being
the
preferred
source,
to
assist
us
in
identifying
the
most
scientifically
sound
dose­
response
values
for
our
analyses
and
decisions.
The
IRIS
process
includes
internal
and
external
peer
review
steps
and
represents
EPA
consensus
values.
When
adequate
toxicity
information
is
not
available
in
IRIS,
we
consult
other
sources
in
a
236
default
hierarchy
that
recognizes
the
desirability
of
these
qualities
in
ensuring
that
we
have
consistent
and
scientifically
sound
assessments.
For
the
final
rule,
we
are
considering
an
HI
(
HCl
and
Cl
2)
or
an
HQ
(
Mn)
of
1.0
to
provide
an
ample
margin
of
safety
for
protecting
public
health
under
CAA
section
112(
d)(
4).
Safety
factors
are
included
in
the
dose­
response
values
used
to
calculate
the
HI
to
account
for
scientific
uncertainties,
and
their
inclusion
helps
ensure
that
using
a
HI
limit
of
1.0
provides
an
ample
margin
of
safety.
The
TOSHI
approach
required
for
HCl
and
Cl
2
assumes
additivity
in
mixtures
of
chemicals
that
target
the
same
organ
system
(
i.
e.,
respiratory
system).
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
HCl
will
calculate
an
HI
for
HCl
and
Cl
2
as
described
in
Appendix
A
to
subpart
DDDDD.
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
Mn
will
calculate
an
HQ
for
Mn
as
described
in
Appendix
A
to
subpart
DDDDD.

Comment:
Commenters
IV­
D­
122
and
IV­
D­
123
believe
that
the
IRIS
RfC
for
HCl
is
conservative
and
provides
an
ample
margin
of
safety.
In
both
cases
where
the
EPA
declined
to
regulate
HCl
emissions
as
part
of
a
NESHAP,
EPA
concluded
that
HCl
is
a
threshold
pollutant
and
used
the
RfC
as
the
primary
benchmark
for
risk
assessment.
Response:
We
agree
with
the
commenter's
statement
that
HCl
is
a
threshold
pollutant
and
that
the
IRIS
RfC
for
HCl
is
appropriate
for
use
in
this
analysis.

Comment:
Commenters
IV­
D­
26,
IV­
D­
104,
and
IV­
D­
150
asserted
that
a
§
112(
d)(
4)
risk­
based
exemption
is
warranted
for
Mn,
citing
EPA
precedent
that
two
criteria
must
be
met:
(
1)
the
pollutant
must
be
health­
based
and
not
subject
to
large
uncertainty;
and
(
2)
the
pollutant
does
not
create
significant
or
widespread
environmental
effects.
The
commenters
claimed
that
Mn
meets
both
of
these
criteria.
The
commenters
stated
that
EPA's
Office
of
Research
and
Development
has
established
an
inhalation
RfC
for
Mn,
which
is
retrievable
from
the
EPA's
IRIS.
The
IRIS
monograph
for
Mn
identifies
impairment
of
nuero­
behavioral
function,
a
threshold
effect,
as
the
health
endpoint
of
concern,
and
establishes
an
RfC
of
0.00005
mg/
m3
(
0.05

g/
m3)
for
this
endpoint
by
applying
a
conservative
adjustment
factor
of
1000
to
the
identified
threshold
for
this
health
effect.
Regarding
the
creation
of
significant
or
widespread
environmental
effects,
the
commenters
claimed
that
Mn
is
ubiquitous
in
the
environment
and
is
an
essential
element
for
humans,
animals,
and
plants.
According
to
the
commenters,
acute
exposures
to
Mn
are
very
rare,
and
toxicity
from
inhaled
Mn
particles
has
been
reported
only
under
extreme
occupational
exposures
(
such
as
mining).
Chronic
(
i.
e,
2­
3
years
and
longer)
Mn
exposure
at
levels
significantly
higher
than
the
RfC
(
i.
e.,
from
0.14
to
30
mg/
m3)
is
reported
to
cause
manganism,
a
form
of
central
nervous
system
toxicity.
This
exposure
range
is
approximately
2,800
to
600,000
times
greater
than
the
RfC.
The
commenters
also
stated
that
there
are
no
known
human
reproductive
or
teratogenetic
effects
of
Mn
exposure.
Additionally,
the
commenters
noted
that
data
indicate
that
air
concentrations
of
Mn
have
been
decreasing
over
the
past
30
years.
The
commenters
stated
that
there
is
little
likelihood
of
chronic
or
widespread
exposure
to
Mn
at
concentrations
above
the
noadverse
effect
threshold,
given
the
above
factors
and
the
fact
that
Mn
emissions
from
combustion
sources
subject
to
this
rulemaking
are
quite
low,
and
concentrations
of
Mn
in
exhaust
gases
are
very
low
due
to
the
typically
high
volume
of
the
exhaust
gases.
In
addition,
ambient
concentrations
of
Mn
around
sugar
mills
are
expected
to
be
very
low
due
to
stack
height
effects,
topography,
meteorology,
and
other
site­
specific
factors.
Response:
We
agree
that
a
health­
based
compliance
alternative
is
appropriate
for
Mn,
237
which
is
a
threshold
pollutant,
under
CAA
§
112(
d)(
4)
in
cases
where
affected
sources
are
able
to
demonstrate
that
their
emissions
of
Mn
pose
little
or
no
threat
to
human
health.
We
agree
that
the
IRIS
RfC
for
Mn
is
appropriate
for
use
in
this
analysis,
and
for
the
final
rule,
we
are
basing
the
health­
based
compliance
alternative
on
the
RfC
value,
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
For
air
toxics
risk
assessments,
we
identify
pertinent
toxicity
or
dose­
response
values
using
a
default
hierarchy
of
sources,
with
IRIS
being
the
preferred
source,
to
assist
us
in
identifying
the
most
scientifically
appropriate
benchmarks
for
our
analyses
and
decisions.
The
IRIS
process
contains
internal
and
external
peer
review
steps
and
represents
EPA
consensus
values.
The
critical
effect
for
the
Mn
RfC,
representing
the
most
sensitive
toxicological
endpoint,
is
impairment
of
neurobehavioral
function.
With
regard
to
human
health
hazard
associated
with
acute
exposures,
we
have
performed
an
acute
assessment
of
Mn
emissions
from
boiler
and
process
heater
affected
sources.
Our
results
suggest
that
acute
emissions
of
Mn
from
boilers
and
process
heaters
are
unlikely
to
adversely
affect
human
health.
Therefore,
affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
Mn
are
not
required
to
perform
an
acute
assessment.
To
identify
HAP
with
potential
to
cause
multimedia
and/
or
environmental
effects,
we
have
identified
HAP
with
significant
potential
to
persist
in
the
environment
and
to
bioaccumulate.
This
list
does
not
include
Mn.
Therefore,
we
do
not
believe
that
emissions
of
Mn
from
affected
sources
will
pose
a
significant
risk
to
the
environment,
and
affected
sources
attempting
to
comply
with
the
health­
based
alternatives
for
Mn
are
not
required
to
perform
an
ecological
assessment.

Comment:
Commenters
IV­
D­
122
and
IV­
D­
123
stated
that
comparison
of
modeled
exposures
to
the
RfC
or
similarly
derived
health
benchmark
is
highly
protective
and
meets
the
CAA's
"
ample
margin
of
safety"
requirement.
The
EPA's
mandate
under
the
statute's
"
ample
margin
of
safety"
language
is
to
provide
a
reasonable
amount
of
protection
in
light
of
scientific
uncertainties.
The
CAA
does
not
define
"
ample
margin
of
safety"
explicitly.
However,
in
the
Vinyl
Chloride
case
the
D.
C.
Circuit
Court
of
Appeals
articulated
the
purpose
of
the
ample
margin
of
safety
determination
as
obtaining
a
"
reasonable
degree
of
protection"
in
light
of
scientific
uncertainties
and
information
gaps.
Natural
Res.
Def.
Council
v.
EPA,
824
F.
2D
1146,
1152­
53
(
D.
C.
Cir.
1987).
The
commenters
stated
that
in
regulatory
practice,
the
ample
margin
of
safety
analysis
consists
of
a
consideration
of
the
NOEL
for
a
pollutant
and
the
subsequent
application
of
factors
to
account
for
scientific
uncertainty
surrounding
that
safe
level
of
exposure.
This
is
the
approach
called
for
by
the
Senate
Report
accompanying
the
1990
CAA
Amendments:
For
some
pollutants
a
MACT
emissions
limitation
may
be
far
more
stringent
than
is
necessary
to
protect
public
health
and
the
environment.
For
some
of
the
hazardous
air
pollutants
listed
under
subsection
(
b)
it
is
possible
to
establish
a
"
no
observable
effects
level"
(
NOEL)
below
which
human
exposure
is
presumably
"
safe."
This
NOEL
or
health­
effects
threshold
may
be
higher
than
the
level
of
emissions
which
can
be
achieved
with
the
application
of
maximum
achievable
control
technology
.
.
.
[
W]
here
health
thresholds
are
well
established,
for
instance
in
the
case
of
ammonia,
and
the
pollutant
presents
no
risk
of
other
adverse
health
effects,
the
Administrator
may
use
the
threshold
with
an
ample
margin
of
safety
(
and
not
considering
cost)
to
set
emissions
limitations
for
sources
in
the
category
or
subcategory.
S.
Rep.
No.
228,
101st
Cong.
Sess.
171
(
1990).
The
legislative
history
of
CAA
§
112(
d)(
4)
thus
demonstrates
that
Congress
intended
the
adequate
margin
of
safety
determination
to
rest
on
a
finding
of
a
level
of
exposure
below
which
adverse
effects
are
not
seen
in
toxicological
studies
(
i.
e.,
the
NOEL),
reduced
by
multiplicative
238
factor(
s)
to
provide
a
reasonable
degree
of
protection
in
light
of
scientific
uncertainties.
This
is
exactly
what
is
done
in
deriving
an
RfC
or
similar
inhalation
health
benchmark.
Commenters
IV­
D­
61,
IV­
D­
122,
and
IV­
D­
123
stated
that
EPA's
derivation
of
the
RfC
contains
multiple
layers
of
conservatism
to
account
for
scientific
uncertainty.
The
commenters
believe
that
RfCs
and
similar
inhalation
health
benchmarks
already
incorporate
sufficient
uncertainty
factors
to
fulfill
or
exceed
the
ample
margin
of
safety
mandate
of
CAA
§
§
112(
d)(
4)
and
(
c)(
9).
The
commenters
noted
that
the
RfC
is
defined
as
the
concentration
of
a
pollutant
in
air
which
a
person
­
including
sensitive
individuals
­
can
breathe
24
hours
a
day
every
day
for
70
years
without
experiencing
an
adverse
health
effect.
The
RfC
is
calculated
by
taking
the
most
conservative
animal
data
and
employing
a
number
of
uncertainty
factors
which
assume
that
humans
generally
are
an
order
of
magnitude
more
sensitive
to
the
effect
than
animals,
that
some
humans
are
an
order
of
magnitude
more
sensitive
than
others,
and
that
the
dose
level
at
which
no
effect
will
be
seen
in
a
study
is
an
order
of
magnitude
lower
than
the
lowest
dose
level
at
which
an
effect
was
seen.
Safety
factors
may
also
be
added
where
a
study
was
of
shorter
than
lifetime
duration,
or
to
account
for
an
"
inadequate"
database.
The
range
of
aggregated
safety
factors
usually
is
between
300
and
3,000.
Commenters
IV­
D­
26,
IV­
D­
104,
and
IV­
D­
150
noted
that
individual
facility
exposure
modeling
would
be
required
to
demonstrate
that
the
health
benchmark
is
not
exceeded
and
believe
that
the
combination
of
conservative
air
dispersion
modeling
techniques
and
a
conservative
human
health
benchmark
ensure
that,
where
a
source
meets
the
requirement
for
a
risk­
based
compliance
option,
human
health
will
be
protected
with
an
ample
margin
of
safety.
Commenters
IV­
D­
26,
IV­
D­
104,
and
IV­
D­
150
stated
that
a
HI
of
1
or
higher
is
appropriate
due
to
a
variety
of
factors,
including
the
extensive
conservatism
built
into
both
the
derivation
of
the
RfCs
and
the
exposure
modeling,
and
the
limited
exposures
to
these
HAP
through
pathways.
The
commenters
noted
that
the
range
of
aggregated
safety
factors
built
into
the
RfC
usually
is
between
300
and
3,000,
resulting
in
the
RfC
being
an
extremely
conservative
number.
Commenters
IV­
D­
60,
IV­
D­
62,
and
IV­
D­
119
submitted
that
a
HI
of
1
is
appropriate
for
HCl
since
EPA's
derivation
of
the
RfC
in
general
contains
multiple
layers
of
conservatism
that
fulfills,
and
in
many
cases
exceeds,
the
ample
margin
of
safety
mandate
of
§
112(
d)(
4).
The
commenters
pointed
out
that
EPA's
RfC
for
HCl
is
20

g/
m3,
whereas
EPA
notes
in
its
IRIS
entry
for
HCl
that
an
expert
panel
identified
a
range
of
300
to
3000

g/
m3
as
a
reasonable
estimate
of
the
no­
effect
level
in
humans.
The
HCl
health
benchmark
of
20

g/
m3
incorporates
uncertainty
factors
of
300.
The
commenters
believe
that
given
that
EPA's
RfC
is
an
order
of
magnitude
lower
than
these
experts'
lowest
estimate
of
a
no­
effect
level
in
humans,
the
HCl
RfC
properly
is
viewed
as
a
highly
conservative
(
i.
e.,
health
protective)
value
and
does
not
warrant
a
further
reduction
through
a
regulatory
mechanism
that
would
allocate
only
a
portion
of
the
HI
to
major
sources.
Commenter
IV­
D­
73
stated
that
uncertainty
is
already
considered
in
the
establishment
of
RfC
from
which
the
HI
is
derived.
The
commenter
stated
that
the
uncertainty
factors
used
in
the
NATA
are
large,
and
because
of
the
considerable
uncertainty
adjustments
that
are
already
applied,
it
is
highly
unlikely
that
an
ample
margin
of
safety
would
ever
have
to
include
more
uncertainties
than
are
already
incorporated
in
the
RfCs.
In
some
cases,
the
uncertainty
corrections
are
too
conservative.
Commenter
IV­
D­
186
stated
that
EPA
should
use
RfC
and
reference
doses
(
RfDs)
as
the
threshold
for
deciding
whether
a
MACT
standard
for
a
specific
pollutant
is
warranted.
The
RfCs
239
and
RfDs
are
set
conservatively
by
first
determining
a
NOEL
and
then
reducing
that
level
by
an
uncertainty
factor.
This
method
of
setting
RfCs
and
RfDs
assures
that
public
health
is
protected
by
"
an
ample
margin
of
safety."
Commenter
IV­
D­
186
added
that
EPA
should
use
§
112(
d)(
4)
in
the
boiler
and
process
heater
MACT
to
limit
the
number
of
affected
sources
subject
to
limits
for
threshold
pollutants
like
HCl.
Public
exposure
to
HCl
from
most
industrial
boilers
should
be
well
below
the
RfC
for
HCl.
Response:
The
final
rule
will
utilize
CAA
§
112
(
d)(
4)
rather
than
§
112
(
c)(
9).
We
agree
that
the
CAA
does
not
define
"
ample
margin
of
safety"
explicitly.
The
CAA
does,
however,
in
§
112(
f),
explicitly
recognize
our
Federal
Register
notice
of
September
14,
1989,
which
described
our
interpretation
of
"
ample
margin
of
safety"
in
the
case
of
linear
carcinogens,
and
our
approach
to
implementing
that
interpretation.
While
the
first
step
involves
determination
of
an
"
acceptable
risk"
and
includes
a
presumptive
limit
on
maximum
individual
risk,
the
second
step
describes
the
setting
of
the
risk­
based
standard
at
a
level
that
provides
"
an
ample
margin
of
safety,"
in
consideration
of
a
number
of
factors.
In
considering
the
extrapolation
of
the
ample
margin
of
safety
objective
described
for
linear
cancer
risk
to
the
management
of
risk
for
nonlinear
effects,
EPA
considers
exposures
relative
to
the
RfC
or
comparable
values
for
all
of
the
emitted
HAP
with
specific
attention
to
those
affecting
a
similar
physiological
target
organ
or
system.
Allowable
emission
limits
under
this
health­
based
compliance
alternative
are
derived
with
consideration
of
RfC
values,
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
In
assessing
risk
or
hazard
of
nonlinear
effects,
we
use
the
RfC
or
comparable
value.
This
value
represents
an
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
to
the
human
population
(
including
sensitive
subgroups)
that
is
likely
to
be
without
an
appreciable
risk
of
deleterious
non­
cancer
effects
during
a
lifetime.
The
RfCs
and
comparable
values
are
derived
from
assessments
of
pertinent
toxicological
information
to
identify
the
lowest
POD
(
in
human
equivalent
terms)
from
the
experimental
data
that
is
also
representative
of
the
threshold
region
(
the
region
where
toxicity
is
apparent
from
the
available
data)
for
the
array
of
toxicity
data
for
that
chemical.
The
objective
is
to
select
a
prominent
toxic
effect
that
is
pertinent
to
the
chemical's
key
mechanism
or
mode
of
action.
This
approach
is
based,
in
part,
on
the
assumption
that
if
the
critical
toxic
effect
is
prevented,
then
all
toxic
effects
are
prevented.
The
RfC
is
derived
from
the
POD
(
in
terms
of
human
equivalent
exposure)
for
the
critical
effect
by
consistent
application
of
uncertainty
factors,
which
are
to
account
for
recognized
uncertainties
in
the
extrapolations
from
the
experimental
data
conditions
to
an
estimate
appropriate
to
the
assumed
human
scenario.
1
Affected
sources
can
demonstrate
compliance
with
the
health­
based
alternative
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
Affected
sources
are
not
restricted
to
a
particular
modeling
approach.
Rather,
they
may
choose
to
perform
a
relatively
refined
modeling
analysis
which
will
require
more
effort
but
will
produce
results
that
are
less
uncertain
and
less
conservative
(
i.
e.,
less
likely
to
overestimate
risk)
than
a
screening
level
assessment.

Comment:
Commenters
IV­
D­
122
and
IV­
D­
123
stated
that
the
combination
of
conservative
air
dispersion
modeling
techniques
and
a
conservative
human
health
benchmark
ensure
that,
where
a
source
meets
the
requirements
for
a
risk­
based
compliance
option,
human
health
will
be
protected
with
an
ample
margin
of
safety.
Commenters
IV­
D­
122
and
IV­
D­
123
pointed
out
that,
for
most
individuals
in
the
general
population,
actual
exposures
likely
are
one
or
more
orders
of
magnitude
below
the
maximum
exposures
predicted
by
the
tiered
modeling
240
approach.
EPA's
tiered
modeling
methodology
is
designed
to
identify
the
highest
annual
property
line
or
off­
site
concentrations
that
might
occur
around
each
facility
(
as
opposed
to
actual
population
exposure).
The
tiered
approach
models
exposures
of
a
"
maximally
exposed
individual"
and
incorporates
a
number
of
conservative
assumptions.
Actual
average
concentrations
are
likely
to
be
much
lower.
Even
if
the
modeled
concentrations
were
reflective
of
continuous
average
concentrations,
it
is
highly
unlikely
that
any
individual
would
actually
be
exposed
to
such
concentrations
for
a
lifetime.
Indeed,
the
Presidential/
Congressional
Commission
on
Risk
Assessment
and
Risk
Management
concluded
that
the
conservatism
inherent
in
use
of
the
MEI
"
was
often
so
unrealistic
that
its
use
impaired
the
scientific
credibility
of
health
risk
assessment."
Response:
Affected
sources
performing
site­
specific
modeling
are
referred
to
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
This
appendix
refers
to
the
EPA
"
Air
Toxics
Risk
Assessment
Reference
Library,"
which
describes
possible
approaches
to
conducting
site­
specific
modeling.
We
discussed
a
tiered
analytical
approach
in
the
preamble
to
the
proposed
rule,
beginning
with
relatively
simple
look­
up
tables
and
followed
by
increasingly
more
site­
specific
but
more
resource
intensive
tiers
of
analysis,
with
each
tier
being
more
refined.
In
the
final
rule,
we
are
adopting
a
somewhat
different
approach
for
meeting
the
requirements
of
CAA
§
112(
d)(
4).
The
basis
for
this
approach
stems
from
the
general
air
toxics
assessment
approach
presented
in
the
Residual
Risk
Report
to
Congress,
which
was
developed
with
full
consideration
of
EPA
risk
assessment
policy,
guidance,
and
methodology.
2
The
approach
for
demonstrating
eligibility
is
discussed
in
section
18.8.
Affected
sources
can
demonstrate
eligibility
for
the
health­
based
emission
limits
by
using
site­
specific
emissions
test
data
and
look­
up
tables
that
were
developed
using
health­
protective
input
parameters.
These
look­
up
tables
are
included
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
Affected
sources
that
cannot
demonstrate
eligibility
based
on
the
health­
protective
screening
assessment
(
i.
e.,
look­
up
tables)
may
used
more
refined
sitespecific
risk
assessments
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
and
in
other
analytical
tools
such
as
the
"
Air
Toxics
Risk
Assessment
Reference
Library,"
(
which
may
be
appropriate
for
specific
sources).
A
more
refined
analysis
requires
more
effort,
but
produces
results
that
are
less
uncertain
and
less
conservative
(
i.
e.,
less
likely
to
overestimate
risk).
2
18.5.3
HAP
to
be
included
Comment:
Multiple
commenters
(
IV­
D­
26,
IV­
D­
60,
IV­
D­
62,
IV­
D­
73,
IV­
D­
104,
IVD
119,
IV­
D­
122,
IV­
D­
123,
IV­
D­
150,
and
IV­
D­
166)
presented
modeling
examples
and
discussed
HAP
to
include
in
modeling.
Commenters
IV­
D­
122
and
IV­
D­
123
stated
that
many
coal­
fired
boilers
would
need
to
install
a
scrubber
to
meet
the
proposed
HCl
limit,
and
HF
would
also
be
controlled
by
the
scrubber.
The
commenters
stated
that,
based
on
modeling
performed
by
the
CIBO,
risk
from
HF
is
small
compared
to
that
for
HCl.
The
commenters
contended
that
HF
emissions
are
not
likely
to
drive
risk
for
industrial
boilers.
Risk
modeling
indicating
that
HCl
levels
are
below
the
health
benchmark
would
also
indicate
that
HF
is
below
the
benchmark.
Commenters
IV­
D­
60,
IV­
D­
62,
IV­
D­
73,
and
IV­
D­
119
presented
the
results
of
dispersion
modeling
conducted
at
two
sources
in
order
to
establish
whether
typical
solid
fuel
fired
sources
could
meet
the
RfC
provided
by
EPA
in
Table
4
(
68
Fed.
Reg.
1690).
Since
EPA
indicates
that
it
is
using
HCl
as
a
surrogate
for
other
acid
gas
HAP,
the
test
case
modeling
also
included
dispersion
modeling
for
HF
in
order
to
characterize
its
highest
concentration
versus
HCl
241
relative
to
the
respective
RfCs.
Dispersion
modeling
was
conducted
using
the
ISCST3.
All
modeling
was
done
in
accordance
with
approved
procedures
codified
in
40
CFR
51,
Appendix
W.
For
each
source,
the
models
were
run
using
two
stack
HCl
concentrations:
(
1)
the
proposed
rule
limit
of
0.09
lb/
MMBtu
and
(
2)
the
highest
conceivable
coal
chloride
content
for
the
facility
with
minimal
capture
in
the
fabric
filter
installed
for
PM
control.
The
commenters
presented
the
modeling
results
for
each
of
the
two
sources.
For
each
source,
the
commenters
claimed
that
the
HCl
modeling
results
indicate
that
there
is
an
insignificant
impact
due
to
emissions
of
HCl
from
those
coal­
fired
boilers
in
a
rural
setting,
and
that
a
requirement
to
install
HCl
emissions
controls
on
those
boilers
would
provide
insignificant
benefit
at
a
very
high
cost.
Similar
results
were
found
for
the
HF
modeling
at
each
source.
The
commenters,
and
commenter
IV­
D­
166,
asserted
that
based
on
the
analysis
of
modeling
these
specific
sources,
it
is
apparent
that
there
are
likely
many
solid
fuel
fired
affected
sources
that
could
take
advantage
of
a
flexible
modeling
option
to
prove
insignificant
impact
and
meet
MACT
intent
without
installation
of
expensive
control
technology.
The
commenters
stated
that
the
results
also
demonstrate
that
the
inherently
lower
fluorine
content
in
coals
results
in
much
lower
HQ
for
HF
emissions
than
seen
for
HCl
emissions,
indicating
an
even
higher
margin
of
safety
for
HF.
Therefore,
the
applicability
and
modeling
criteria
for
HCl
as
a
surrogate
for
acid
gas
HAP
are
adequate
without
requiring
additional
applicability
and/
or
modeling
criteria
for
other
acid
gas
HAP.
Commenters
IV­
D­
73
and
IV­
D­
166
added
that
it
is
apparent
from
the
modeling
exercise
that
a
solid
fuel­
fired
source
located
in
complex
terrain
may
not
be
able
to
demonstrate
an
HQ
on
an
annual
basis
of
less
than
1.0
relative
to
the
RfC.
Therefore,
there
will
be
inherent
limitations
to
the
ability
of
affected
sources
to
use
this
type
of
applicability
exemption
criteria.
Commenter
IV­
D­
73
also
described
risk
modeling
done
for
a
facility
that
includes
three
hazardous
waste
incinerators
and
seven
coal­
fired
boilers.
The
HCl
and
Cl
2
emissions
rates
were
based
on
worst­
case
testing
involving
chlorine
spikes.
Aggregate
modeling
results
for
the
incinerators/
boilers
showed
an
HQ
of
0.00897
for
total
HCl
and
chlorine
(
approximately
one
tenth
of
the
reference
air
concentration).
The
commenter
believes
other
boilers
would
also
show
low
risk
associated
with
HCl
and
Cl
2,
and
therefore,
it
would
be
inappropriate
to
impose
HCl
limits
on
boilers.
Commenters
IV­
D­
73
and
IV­
D­
166
stated
that
EPA
should
clarify
that
sources
wishing
to
use
the
§
112(
d)(
4)
emissions
limit
must
only
demonstrate
compliance
with
risk­
based
thresholds
for
those
HAP
from
Table
4
(
68
FR
1690)
that
are
emitted
from
the
source.
EPA
states
in
the
preamble
that
nine
HAP
account
for
68
percent
of
total
HAP
emissions
from
the
source
category,
and
HAP
emissions
vary
significantly
from
source
to
source
depending
on
fuel
use
and
combustion
device
configuration.
Therefore,
the
commenters
believe
that
those
HAP
identified
in
Table
4
are
the
only
HAP
that
could
potentially
be
emitted
in
significant
quantities
from
a
source
within
the
category,
and
for
purposes
of
demonstrating
compliance
with
a
riskbased
standard,
only
those
pollutants
should
be
considered.
The
commenters
added,
for
example,
that
a
boiler
MACT
facility
that
emits
HF,
HCl,
mercury,
chromium,
formaldehyde,
and
lead
would
demonstrate
risk­
based
compliance
with
§
112
(
d)(
4)
emissions
limitations
for
threshold
pollutants
(
HF,
HCl,
and
mercury)
and/
or
compliance
with
de
minimis
emissions
limitations
for
non­
threshold
pollutants
(
chromium,
formaldehyde,
and
lead).
Commenters
IV­
D­
26,
IV­
D­
104,
and
IV­
D­
150
also
believe
the
tiered
approach
should
be
extended
to
individual
HAP.
For
example,
if
a
facility
could
demonstrate
that
the
impact
of
its
TSM,
Hg,
or
HCl
emissions
were
individually
below
a
given
fraction
of
the
RfC
(
e.
g.,
242
20
percent),
or
that
the
HI
for
TSM,
Hg
or
HCl
were
below
a
given
fraction
of
1
(
e.
g.,
0.2),
then
the
facility
would
be
exempt
from
the
emission
limits
and
control
requirements
of
the
rule
as
they
apply
to
TSM,
Hg,
or
HCl.
The
commenters
pointed
out
that
it
makes
little
sense
to
require
controls
and
other
requirements
on
identified
categories
of
HAP
(
i.
e.,
TSM,
Hg,
or
HCl)
when
emissions
of
such
HAP
pose
no
threat
to
the
public
and
do
not
contribute
significantly
to
the
overall
HI
for
the
facility.
Therefore,
the
commenters
supported
an
approach
that
would
allow
individual
HAP
or
groups
of
HAP
(
such
as
TSM)
to
be
exempted
from
regulation
if
they
pose
no
risk
to
the
public.
Response:
Health­
based
compliance
alternatives
are
included
in
the
final
rule
only
for
HCl
and
Mn.
When
developing
MACT,
the
focus
was
on
the
most
prevalent
HAP
because
the
rule
was
technology­
based.
However,
health­
based
decisions
must
take
HAP
toxicity
into
account
as
well
as
emissions.
Our
rationale
for
selecting
HCl
as
a
surrogate
for
emissions
of
other
acid
gases
and
inorganic
HAP
for
MACT
purposes
is
provided
in
the
preamble
to
the
proposed
rule
(
68
FR
1660;
January
13,
2003.)
Affected
sources
can
demonstrate
compliance
with
the
health­
based
alternative
for
HCl
using
a
look­
up
table
analysis
or
site­
specific
modeling
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
Affected
sources
conducting
site­
specific
modeling
may
use
an
approach
of
their
choice
provided
that
approach
is
transparent,
scientifically
valid,
and
has
undergone
peer­
review.
We
have
required
measurement
of
Cl
2
emissions
from
emission
points
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
because
our
own
modeling
found
that
not
all
affected
sources
are
eligible
for
the
compliance
alternative
and
that
risk
is
driven
primarily
by
chronic
Cl
2
emissions.
Our
analysis
demonstrated
that
other
respiratory
toxicants
and
acid
gases
emitted
by
boilers
and
process
heaters
do
not
contribute
significantly
to
the
HI.
Affected
sources
can
demonstrate
compliance
with
the
health­
based
alternative
for
Mn
using
a
look­
up
table
analysis
or
site­
specific
modeling
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
We
acknowledge
that
terrain
characteristics
can
affect
the
outcome
of
a
risk
assessment.
However,
a
combination
of
factors,
only
one
of
which
is
terrain
characteristics,
will
determine
whether
an
affected
source
is
able
to
utilize
the
health­
based
compliance
alternative
in
the
final
rule.
3
18.6
RISK
ASSESSMENT
ANALYSES
18.6.1
Background
and
multipathway
exposure
Comment:
Multiple
commenters
(
IV­
D­
26,
IV­
D­
60,
IV­
D­
61,
IV­
D­
62,
IV­
D­
73,
IVD
75,
IV­
D­
104,
IV­
D­
119,
IV­
D­
122,
IV­
D­
123,
IV­
D­
150,
IV­
D­
184)
opposed
use
of
background
concentration
and
multipathway
exposure
modeling.
Commenters
IV­
D­
61,
IV­
D­
122,
and
IV­
D­
123
stated
that
consideration
of
background
and
multipathway
exposures
is
not
required
by
law
and
is
not
necessary
for
sound
policy.
The
commenters
explained
that
the
exclusive
focus
on
the
emissions
from
a
source
in
making
regulatory
decisions
under
CAA
§
112
is
evident
in
all
of
the
statutory
provisions
on
which
EPA
would
rely
to
implement
the
risk­
based
mechanisms
(
i.
e.,
§
112(
d)(
4),
112(
c)(
9)(
B),
or
EPA's
de
minimis
authority).
As
a
result,
EPA
has
no
legal
obligation
to
consider
background
or
multi­
pathway
exposures.
Moreover,
the
statutory
focus
on
the
MACT­
regulated
source
further
means
that
there
is
no
legal
obligation
to
model
risks
from
the
entire
facility,
but
rather
only
the
243
MACT­
regulated
portion
of
the
facility.
Commenters
IV­
D­
123
and
IV­
D­
122
referenced
House
Rep.
No.
101­
490,
Part
1,
at
327
and
stated
that
the
CAA's
legislative
history
does
not
support
a
requirement
to
consider
other
exposures.
Commenters
IV­
D­
123,
IV­
D­
61,
and
IV­
D­
122
also
noted
that
EPA
has
existing
regulatory
programs
(
e.
g.,
for
mobile
and
area
sources
[
Urban
Air
Toxics
Strategy])
in
place
to
address
HAP
emissions
from
other
sources.
Commenters
IV­
D­
60,
IV­
D­
61,
IV­
D­
62,
IV­
D­
119,
IV­
D­
122,
and
IV­
D­
123
noted
that
EPA
has
chosen
not
to
regulate
HCl
emissions
under
§
112(
d)(
4)
authority
in
NESHAP
for
chemical
recovery
combustion
sources
at
pulp
mills
[
63
FR
18754,
18765
(
April
15,
1998)]
and
for
the
chlorine
production
source
category
[
67
FR
44713
(
July
3,
2002)].
In
both
instances,
EPA's
exposure
assessment
focused
on
exposures
attributable
to
the
MACT
affected
sources
alone,
without
consideration
of
background
and
multipathway
HCl
exposures.
The
commenters
supported
this
approach.
Based
on
the
results
of
EPA's
Cumulative
Exposure
Project,
the
commenters
stated
that
compared
to
the
RfC,
background
concentrations
of
HCl
are
negligible
components
of
inhalation
exposure.
Commenters
IV­
D­
122
and
IV­
D­
123
stated
that
§
112(
d)(
4)
does
not
require
the
complete
absence
of
a
hazard
and
that
all
substances
have
adverse
effects
on
health
and
the
environment
at
sufficiently
high
doses
­
hence
the
fundamental
tenet
of
toxicology
that
"
the
dose
makes
the
poison."
Accordingly,
§
112(
d)(
4)
incorporates
the
concept
of
exposure,
and
the
Senate
Report
made
clear
that
the
provision
was
applicable
in
instances
where
"
it
is
possible
to
establish
a
`
no
observable
effects
level'
(
NOEL)
below
which
human
exposure
is
presumably
"
safe."
In
addition,
delisting
criteria
and
the
so­
called
"
trigger"
component
of
the
residual
risk
provision
focus
exclusively
on
emission
and
whether
the
risk
posed
by
any
source
in
the
category,
by
itself,
exceeds
one
in
a
million
cancer
risk.
Commenters
IV­
D­
122
and
IV­
D­
123
opposed
the
use
of
available
data
on
background
concentrations
and
facility­
specific
measurement
of
background
concentrations
to
determine
the
extent
of
exposures
from
other
sources.
The
CAA
and
sound
public
policy
warrant
a
focus
exclusively
on
the
emissions
from
the
source
category
at
hand
when
evaluating
the
applicability
of
a
risk­
based
compliance
option.
Because
an
HI
of
1.0
(
or
higher)
is
amply
protective
of
public
health
and
is
warranted
under
EPA's
statutory
mandate,
the
consideration
of
background
concentration
is
not
appropriate.
Commenters
IV­
D­
122
and
IV­
D­
123
disagreed
that
EPA
should
consider
multipathway
exposures
of
HCl.
The
commenters
stated
that
HCl
is
neither
persistent
or
bioaccumulative.
In
solution,
HCl
readily
dissociates
to
H+
and
Cl­.
The
commenters
stated
that
there
is
no
indication
that
ingestion
of
HCl
(
from
food,
water,
or
soil)
causes
risk
to
human
health.
The
commenters
stated
that
dietary
and
drinking
water
exposure
to
HCl
is
insignificant.
According
to
commenters
IV­
D­
60,
IV­
D­
61,
IV­
D­
62,
and
IV­
D­
119,
multipathway
exposures
to
HCl
are
negligible
and
need
not
be
considered.
The
commenters
asserted
that
there
is
no
indication
that
ingestion
exposure
to
HCl
causes
any
risk
to
human
health
(
the
IRIS
database
contains
no
oral
reference
dose
for
HCl).
Commenter
IV­
D­
75
stated
that
the
CAA
does
not
give
EPA
the
authority
to
consider
background
concentrations;
MACT
standards
must
be
based
only
on
emissions
from
the
regulated
source
and
not
existing
background
levels.
The
commenter
stated
that
§
112
can
be
distinguished
from
other
statutory
provisions
where
EPA
has
been
given
authority
to
consider
background
sources,
both
in
the
CAA
and
in
other
environmental
legislation.
Where
Congress
intended
EPA
to
consider
background
sources,
the
authority
is
clearly
granted.
The
commenter
provided
several
CAA
examples
where
authority
to
consider
background
concentrations
was
explicitly
244
granted,
including
regulations
to
meet
NAAQS;
§
112(
k),
relating
to
urban
air
toxics
from
area
sources;
and
§
169A,
relating
to
visibility
pollution.
The
commenter
also
provided
examples
of
other
environmental
legislation
where
Congress
explicitly
granted
authority
to
consider
background
concentrations.
The
commenter
concluded
that
where
intended,
Congress
granted
such
authority
explicitly
in
the
language
of
the
statutes,
and
in
any
rulemaking
to
develop
a
riskbased
alternative
limit
for
the
SCALDT
source
category,
the
consideration
of
background
concentrations
is
inappropriate
and
is
not
specifically
required
by
§
112(
d)
of
the
CAA.
Commenter
IV­
D­
73
stated
that
making
an
allowance
for
other
exposures
under
§
112
is
not
necessary
to
protect
public
health.
The
commenter
added
that
consideration
of
exposures
from
other
sources
places
a
disproportionate
burden
on
major
sources.
Legislative
history
does
not
support
the
consideration
of
exposures
from
other
source
types
when
setting
risk­
based
criteria.
The
commenter
stated
that
multi­
pathway
risk
assessment
should
be
required
only
for
those
HAP
that
have
the
potential
for
causing
significant
multi­
pathway
exposure.
Commenters
IV­
D­
26,
IV­
D­
104,
and
IV­
D­
150
supported
the
position
that
the
appropriate
HI
limit
is
1,
or
higher.
That
is,
whether
facilities
qualify
for
risk­
based
compliance
options
should
depend
on
a
comparison
of
HAP
exposures,
attributable
to
their
emissions
alone,
to
the
RfC
or
equivalent
health
benchmark.
The
commenters
believe
that
including
background
sources
in
determining
the
HI
is
not
appropriate.
Commenter
IV­
D­
184
stated
that
EPA
should
use
realistic
exposure
assumptions
the
characterize
risk
accurately;
specifically,
the
focus
should
be
on
inhalation
unless
there
is
HAPspecific
or
site­
specific
reason
to
expand
the
analysis
to
include
other
pathways
of
concern.
Response:
Commenters
discussed
the
use
of
§
112(
d)(
4)
and
§
112(
c)(
9)
of
the
CAA
for
the
Boiler
rule
health­
based
compliance
alternative.
This
rule
is
relying
not
on
CAA
§
112(
c)(
9),
but
on
§
112(
d)(
4),
which
requires
us
to
evaluate
ecological
and
multimedia
human
exposures
when
determining
the
applicability
of
§
112(
d)(
4).
To
identify
potential
multipathway
and/
or
ecological
concerns,
we
have
identified
HAP
with
significant
potential
to
persist
in
the
environment
and
to
bioaccumulate.
However,
this
list
does
not
include
Mn,
HCl,
or
Cl
2
which
are
the
only
HAP
relevant
for
the
health­
based
compliance
alternative
under
the
final
rule.
Therefore,
facilities
attempting
to
comply
with
the
health­
based
alternative
in
the
final
rule
are
not
required
to
perform
a
multipathway
analysis.
We
are
not
considering
background
emissions
in
the
health­
based
compliance
alternatives
for
HCl
and/
or
Mn.
Rather,
as
we
indicated
in
the
Residual
Risk
Report
to
Congress,
we
intend
to
assess
facility­
wide
emissions
of
HAP
in
future
residual
risk
actions
under
§
112(
f)(
2),
as
appropriate
and
to
the
extent
it
is
reasonable
and
appropriate
to
do
so.
See
also,
54
Fed.
Reg.
at
38,059
(
Sept.
14,
1989)
(
benzene
NESHAP).
Affected
sources
attempting
to
utilize
this
health­
based
compliance
alternative
for
HCl
must
measure
emissions
of
HCl
and
Cl
2
and
compare
the
HI
to
1.0,
as
described
in
Appendix
A
to
subpart
DDDDD.
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
Mn
must
measure
emissions
of
Mn
and
compare
the
HQ
to
1.0,
as
described
in
Appendix
A
to
subpart
DDDDD.
One
commenter
also
made
reference
to
the
SCALDT
rule;
we
are
not
incorporating
a
risk­
based
option
into
the
SCALDT
rule.

Comment:
Multiple
commenters
(
IV­
D­
05,
IV­
D­
14,
IV­
D­
40,
IV­
D­
96,
IV­
D­
113,
IVD
135)
supported
multipathway
exposure
modeling.
Commenter
IV­
D­
05
provided
the
example
of
mercury,
a
persistent,
bioaccumulative,
and
245
toxic
(
PBT),
from
coal
combustion.
The
commenter
stated
that
it
would
be
inappropriate
to
exclude
PBT
sources
from
MACT
without
consideration
of
non­
inhalation
pathway
exposures
and
environmental
impacts.
The
commenter
recommended
that
as
a
precaution,
PBT
sources
should
not
be
granted
exemptions
from
MACT,
which
provides
a
level
playing
field.
Commenter
IV­
D­
14
stated
that
analyses
like
the
concentration­
based
applicability
threshold
approach
do
not
address
non­
inhalation
exposures
or
adverse
effects
on
the
environment.
Commenter
IV­
D­
14
stated
that
allowing
individual
facilities
to
monitor
the
HAP
backgrounds
for
use
in
their
own
analysis
would
require
oversight
and
evaluation
by
State
and
local
agencies
to
insure
proper
site
selections
and
analytical
methods
and
would
be
costly
to
administer
and,
therefore,
not
acceptable.
Commenter
IV­
D­
96
stated
that
EPA
must
consider
all
ways
that
a
HAP
could
harm
public
health
or
the
environment.
With
regard
to
EPA's
request
for
comment
on
the
"
appropriateness
and
necessity"
of
accounting
for
non­
inhalation
exposures,
the
commenter
stated
that
§
112(
d)(
4)
refers
to
pollutants
"
for
which
a
health
threshold
has
been
established."
As
this
language
and
the
legislative
history
make
clear,
it
refers
to
pollutants
that
have
no
adverse
health
or
environmental
effects.
See
5
Legislative
History
at
8511.
Thus,
§
112(
d)(
4)
necessarily
requires
EPA
to
consider
all
possible
ways
that
a
pollutant
could
affect
human
health
or
the
environment.
As
EPA
has
recognized
repeatedly
in
the
past,
many
of
the
pollutants
emitted
by
the
source
category
are
re­
deposited
from
the
atmosphere,
and
then
contaminate
soil
and
water
for
long
periods
of
time.
Moreover
they
bioaccumulate
in
wildlife
and
food
sources,
poisoning
people
and
animals
alike.
See,
e.
g.,
64
Fed.
Reg.
52828,
53014
(
September
30,
1999);
64
Fed.
Reg.
31898,
31908­
31909
(
June
14,
1999);
63
Fed.
Reg.
14182,
14193
(
March
28,
1998);
61
Fed.
Reg.
17358,
17478
(
April
19,
1996)
(
due
to
bioaccumulation,
mercury
levels
may
be
10,000,000
times
higher
in
fish
than
in
water
those
fish
inhabit).
To
evaluate
whether
a
pollutant
is
a
threshold
pollutant
and
what
its
health
threshold
and
ample
margin
of
safety
must
be,
therefore,
EPA
must
consider
all
the
potential
health
and
environmental
effects
of
deposition,
persistence
and
bioaccumulation
of
that
pollutant.
EPA
would
contravene
§
112(
d)(
4)
by
considering
only
health
effects
caused
by
inhalation.
Commenter
IV­
D­
113
stated
that
EPA
appears
to
assume
that
it
only
needs
to
consider
inhalation
risks,
but
the
EPA
does
not
demonstrate
or
even
claim
that
people
are
exposed
only
by
inhalation
to
HAP
from
the
source
category.
Without
such
a
demonstration,
it
is
reasonable
to
conclude
that
other
pathways
may
result
in
exposures,
and,
therefore,
other
pathways
must
be
considered.
Commenter
IV­
D­
135
stated
that
all
exposure
pathways
must
be
considered.
Section
112(
d)(
4)
necessarily
requires
EPA
to
consider
all
possible
ways
that
a
pollutant
could
affect
human
health.
To
evaluate
whether
a
pollutant
is
a
threshold
pollutant
and
what
its
threshold
may
be,
EPA
must
consider
all
potential
health
effects,
including
non­
inhalation
pathways
such
as
ingestion
and
indirect
contamination
of
food
by
pollutants
such
as
mercury
and
dioxin.
Commenter
IV­
D­
40
noted
that
metals
and
HF
account
for
approximately
4
percent
and
5
percent,
respectively,
of
the
HAP
emissions
from
boilers
and
process
heaters
and
stated
that
exposure
to
these
HAP
can
result
in
noncancer
health
effects
ranging
from
skin
irritation
to
central
nervous
system
damage.
The
commenter
pointed
out
that
in
addition,
exposure
to
a
subset
of
these
HAP
(
i.
e.,
arsenic,
cadmium,
hexavalent
chromium,
and
nickle)
can
result
in
cancer.
The
commenter
submitted
that
EPA
is
proposing
to
base
the
NESHAP
on
the
direct
inhalation
pathway,
which
assumes
that
all
of
the
HAP
emissions
are
available
for
inhalation
and
246
that
no
other
routes
of
exposure
are
applicable.
The
commenter
has
found
that
EPA
currently
does
not
have
an
Fv
value
for
HF,
but
that
since
it
is
described
as
a
colorless
gas,
assumed
it
is
entirely
in
the
gaseous
state
and
available
only
through
the
direct
inhalation
pathway.
Conversely,
the
commenter
stated
that
all
of
the
metal
HAP
emitted
by
boilers
and
process
heaters,
with
the
exception
of
mercury,
were
entirely
in
the
particulate
state
when
emitted.
The
metals
are
available
for
direct
inhalation,
but
will
undergo
deposition
over
time.
The
commenter
stated
that
once
deposition
has
occurred,
the
chemical
is
available
for
uptake
through
indirect
exposure
pathways,
and
uses
the
incidental
ingestion
of
soil
pathway
as
an
example.
The
commenter
also
stated
that
incidental
soil
ingestion
rates
vary
among
age
groups,
with
young
children
ingesting
more
than
adults.
The
commenter
asserted
that
the
potential
risks
to
public
health
from
boiler
and
process
heater
emissions
should
be
explicitly
addressed
and
consideration
should
be
given
to
both
direct
and
indirect
exposure
pathways.
The
commenter
also
requested
that
impacts
from
deposition
of
the
HAP
emissions
be
adequately
addressed
to
ensure
the
proper
protection
of
human
health.
Response:
We
agree
that
exposures
via
all
relevant
routes
need
to
be
considered
for
pollutants
identified
as
PBT.
To
identify
HAP
with
potential
to
cause
multimedia
and/
or
environmental
effects,
we
have
identified
HAP
with
significant
potential
to
persist
in
the
environment
and
to
bioaccumulate.
This
list
does
not
include
HCl,
Cl
2,
or
Mn,
which
are
the
only
HAP
relevant
for
the
health­
based
compliance
alternative
in
the
final
rule.
Therefore,
affected
sources
attempting
to
comply
with
the
health­
based
alternatives
for
these
HAP
are
not
required
to
perform
a
multimedia
assessment.
Additionally,
a
screening
level
analysis
conducted
by
the
EPA
indicates
that
acute
impacts
of
these
HAP
from
boiler
and
process
heater
facilities
are
highly
unlikely.
For
these
reasons,
we
do
not
anticipate
that
emissions
of
HCl,
Cl
2,
or
Mn
from
boiler
and
process
heat
facilities
will
pose
a
significant
risk
to
the
environment,
and
affected
sources
attempting
to
comply
with
the
health­
based
alternatives
for
these
HAP
are
not
required
to
perform
an
ecological
assessment.
MACT
limits
for
Hg
are
not
affected
by
the
health­
based
compliance
alternative.
Affected
sources
able
to
demonstrate
that
they
are
low
risk
for
HCl
and
Cl
2
or
for
Mn
would
still
be
subject
to
a
PM
limit;
however,
they
would
be
subject
to
a
TSM
limit
based
on
seven
HAP
metals
(
excluding
Mn)
rather
than
the
TSM
limit
based
on
eight
metals.

Comment:
Commenter
IV­
D­
148
stated
that
EPA
has
not
discussed
the
need
to
assess
cumulative
risks,
aggregate
exposures,
and
health
impacts
associated
with
exposure
to
chemical
mixtures
emitted
from
facilities
within
the
source
categories.
The
commenter
referred
EPA
to
the
extensive
progress
that
has
been
made
in
more
completely
addressing
risks
from
exposure
to
air
pollution
and
integrated
decisionmaking
in
such
areas
as
children's
risk
issues,
cumulative
exposure
("
Framework
for
Cumulative
Risk
Assessment"
(
EPA/
630/
P­
02/
001A,
April
23,
2002),
and
chemical
mixtures
(
EPA/
630/
R­
00/
002).
The
commenter
requested
that
the
recent
advancements
be
incorporated
into
the
risk
assessment
methods
and
overall
cost
estimates
associated
with
risk­
based
exemptions
in
the
proposed
rules.
Commenter
IV­
D­
96
stated
that
(
if
§
112(
d)(
4)
may
properly
be
read
to
create
an
individualized
exemption
to
an
otherwise
applicable
MACT
standard)
EPA's
methodologies
for
determining
the
contribution
of
other
sources
to
the
overall
hazard
are
deeply
flawed.
The
EPA's
proposed
alternative
methodologies
for
determining
the
contribution
of
other
sources
to
cumulative
risk
are
untenable.
The
first
and
second
approaches
(
HI
of
1
and
HI
of
0.2)
would
allow
exemptions
based
on
blanket
assumptions
about
exposure,
but
EPA
provides
no
basis
for
making
any
assumption.
The
third
option
suggests
relying
on
existing
estimates
of
background
247
levels
of
certain
HAP,
but
these
information
sources
are
neither
designed
nor
adequately
precise
to
be
used
as
the
basis
of
regulatory
applicability
determinations.
The
EPA
itself
cautions
about
NATA
that
the
emission
estimates
"
cannot
be
used
to
identify
exposures
and
risks
for
specific
individuals,
or
even
to
identify
exposures
and
risks
in
small
geographic
regions
such
as
a
specific
census
tract."
(
U.
S.
EPA,
Limitations
in
the
1996
National­
Scale
Air
Toxics
Assessment).
NATA
does
no
estimate
exposure
to
a
number
of
HAP
(
e.
g.,
HF,
HCl).
The
ATSDR
profiles
offer
generalized
assessments,
but
are
not
specific
enough
to
establish
as
baseline
for
a
given
facility.
Commenter
IV­
D­
14
stated
that
the
use
of
NATA
to
determine
background
concentrations
is
unacceptable.
EPA
has
clearly
stated
at
a
number
of
public
meetings
that
NATA
is
not
to
be
used
to
make
regulatory
decisions.
Response:
Our
recommended
approach
for
assessing
risks
from
exposure
to
a
mixture
of
pollutants
is
to
utilize
a
dose­
response
assessment
developed
for
that
mixture.
3,
4
There
are
few
mixtures
(
e.
g.,
coke
oven
emissions),
however,
for
which
such
assessments
are
available.
When
mixture­
specific
dose­
response
assessments
are
not
available,
a
component­
by­
component
approach
is
recommended.
The
method
for
component
data
depends
on
a
judgement
of
toxicologic
similarity
among
components.
The
specific
term
"
toxicologic
similarity"
represents
a
general
knowledge
about
the
action
of
a
chemical
or
a
mixture
and
can
be
expressed
in
broad
terms
such
as
at
the
target
organ
level
in
the
body.
In
our
"
Air
Toxics
Risk
Assessment
Reference
Library,"
assumptions
about
toxicologic
similarity
are
made
in
order
to
choose
among
risk
assessment
methods.
In
general,
for
the
term
"
toxicologic
similarity,"
we
assume
a
similar
mode
of
action
across
mixtures
or
mixture
components
and,
in
some
cases,
this
requirement
may
be
relaxed
to
require
that
these
chemicals
act
only
on
the
same
target
organ.
3
The
primary
method
for
component­
based
risk
assessment
of
toxicologically
similar
chemicals
is
the
HI,
which
is
derived
from
dose
addition.
In
our
guidance,
dose
addition
is
interpreted
as
simple
similar
action,
where
the
component
chemicals
act
as
if
they
are
dilutions
or
concentrations
of
each
other
differing
only
in
relative
toxicity.
Dose
additivity
may
not
hold
for
all
toxic
effects.
Furthermore,
the
relative
toxic
potency
between
chemicals
may
differ
from
different
types
of
toxicity
or
toxicity
by
different
routes.
To
reflect
these
differences,
the
HI
is
then
usually
developed
for
each
exposure
route
of
interest,
and
for
a
single
target
organ
or
organ
system.
A
mixture
may
then
be
assessed
by
several
HI,
each
representing
one
route
and
one
toxic
effect
or
target
organ.
3
While
it
may
be
preferable
to
focus
on
the
addition
of
HAP
HQ
that
involve
the
same
mechanism
or
mode
of
action,
that
level
of
information
is
not
generally
available.
Pending
the
availability
of
such
data
for
the
HAP
components
of
the
mixture
being
assessed,
the
method
employed
is
to
aggregate
HAP
HQ
by
target
organ
to
generate
a
target
organ
specific
hazard
index
(
TOSHI).
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
HCl
will
calculate
an
HI
for
HCl
and
Cl
2
as
described
in
Appendix
A
to
subpart
DDDDD.
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
Mn
will
calculate
an
HQ
for
Mn
as
described
in
Appendix
A
to
subpart
DDDDD.
We
agree
that
it
is
inappropriate
to
use
the
NATA
national
scale
assessment
for
determining
local
background
concentrations
of
particular
HAP.
We
are
not
considering
background
emissions
in
the
health­
based
compliance
alternatives
for
HCl
and/
or
Mn.
Rather,
as
we
indicated
in
the
Residual
Risk
Report
to
Congress,
we
intend
to
assess
facility­
wide
emissions
of
HAP
in
future
residual
risk
actions
under
§
112(
f)(
2),
as
appropriate
and
to
the
extent
it
is
reasonable
and
appropriate
to
do
so.
See
also,
54
Fed.
Reg.
at
38,059
(
Sept.
14,
1989)
(
benzene
NESHAP).
248
Comment:
Commenter
IV­
D­
135
stated
that
EPA's
HI
proposal
is
unworkable.
It
is
inappropriate
to
exclude
sources
from
regulation
on
the
basis
of
a
calculated
HI
for
the
following
reasons:
(
a)
emissions,
ambient
concentrations
and
risks
vary
over
time
and
cannot
be
captured
by
a
single
analysis
to
predict
exposure,
(
b)
modeling
exercises
always
involve
simplifying
assumptions
that
may
or
may
not
accurately
reflect
the
level
of
pollution
that
people
are
exposed
to,
(
c)
relying
only
on
published
health
thresholds
does
not
account
for
exposures
and
risks
from
compounds
that
have
not
been
evaluated
or
for
which
the
data
are
inconclusive,
(
d)
evaluating
exposure
on
the
basis
of
ambient
exposure
does
not
account
for
all
pathways
of
exposure,
and
(
e)
variations
in
background
exposures
would
be
unaccounted
for,
thus
underestimating
the
level
of
pollution
that
people
are
exposed
to.
Response:
Affected
facilities
attempting
to
comply
with
the
health­
based
alternatives
will
be
required
to
assess
their
emissions
under
worst­
case
conditions
as
described
in
Appendix
A
to
subpart
DDDDD.
If
facilities
undergo
any
alterations
that
may
affect
their
HAP
emissions
as
described
in
Appendix
A,
they
are
required
to
re­
certify
their
low
risk
status.
We
discussed
a
tiered
analytical
approach
in
the
preamble
to
the
proposed
rule,
beginning
with
relatively
simple
look­
up
tables
and
followed
by
increasingly
more
site­
specific
but
more
resource
intensive
tiers
of
analysis,
with
each
tier
being
more
refined
and
less
conservative.
In
the
final
rule,
we
are
adopting
a
somewhat
different
approach
for
meeting
the
requirements
of
CAA
§
112(
d)(
4).
The
basis
for
this
approach
stems
from
the
general
air
toxics
assessment
approach
presented
in
the
Residual
Risk
Report
to
Congress,
which
was
developed
with
full
consideration
of
EPA
risk
assessment
policy,
guidance,
and
methodology.
2
The
approach
for
demonstrating
eligibility
is
discussed
in
section
18.8.
For
air
toxics
risk
assessments,
we
identify
pertinent
toxicity
or
dose­
response
values
using
a
default
hierarchy
of
sources,
with
IRIS
being
the
preferred
source,
to
assist
us
in
identifying
the
most
scientifically
appropriate
dose­
response
values
for
our
analyses
and
decisions.
The
IRIS
process
contains
internal
and
external
peer
review
steps
and
represents
EPA
consensus
values.
When
adequate
toxicity
information
is
not
available
in
IRIS,
we
consult
other
sources
in
a
default
hierarchy
that
recognizes
the
desirability
of
these
qualities
in
ensuring
that
we
have
consistent
and
scientifically
sound
assessments.
Further,
where
the
IRIS
assessment
substantially
lags
the
current
scientific
knowledge,
we
consider
alternate
credible
and
readily
available
assessments.
For
our
use,
these
alternatives
need
to
be
grounded
in
publicly
available,
peer
reviewed
information.
We
are
not
using
information
that
does
not
meet
these
requirements.
Health­
based
compliance
alternatives
are
available
for
HCl
and
for
Mn
in
the
final
rule.
EPA
has
identified
those
HAP
with
greatest
potential
to
cause
multimedia
and/
or
environmental
impacts.
This
list
does
not
include
Mn,
HCl,
or
Cl
2.
Therefore,
affected
sources
attempting
to
comply
with
the
health­
based
alternatives
in
the
final
rule
are
not
required
to
perform
a
multipathway
analysis.
We
are
not
considering
background
emissions
in
the
health­
based
compliance
alternatives
for
HCl
and/
or
Mn.
Rather,
as
we
indicated
in
the
Residual
Risk
Report
to
Congress,
we
intend
to
assess
facility­
wide
emissions
of
HAP
in
future
residual
risk
actions
under
§
112(
f)(
2),
as
appropriate
and
to
the
extent
it
is
reasonable
and
appropriate
to
do
so.
See
also,
54
Fed.
Reg.
at
38,059
(
Sept.
14,
1989)
(
benzene
NESHAP).

Comment:
Commenter
IV­
D­
154
stated
that
the
proposal
is
critically
flawed
because
riskbased
exemptions
ignore
the
cumulative
risk
that
comes
from
exposure
to
multiple
air
toxics
sources
(
e.
g.,
hundreds
of
combustion
engines
and
boilers
within
a
city)
and
do
not
protect
public
249
health.
Although
many
individual
sources
may
pose
a
risk
below
a
designated
threshold,
the
accumulation
of
these
pollutants
can
be
hazardous.
Addressing
this
problem
will
require
a
general
reduction
in
air
toxics
emissions
across
large
and
small
sources,
not
just
those
sources
for
which
a
high
local
risk
can
be
demonstrated.
The
commenter
stated
that
NATA
indicates
that
air
toxics
exposures
are
already
high
throughout
the
country.
Commenter
IV­
D­
154
stated
that
there
are
five
HAP
emitted
from
boilers/
process
heaters
that
are
predicted
to
be
at
concentrations
that
pose
greater
than
10­
6
risk
across
New
Jersey,
and
at
least
four
other
pollutants
have
county
averages
greater
than
10­
6.
Much
of
this
risk
comes
from
area
sources.
Response:
We
are
not
considering
background
emissions
in
the
health­
based
compliance
alternatives
for
HCl
and/
or
Mn.
Rather,
as
we
indicated
in
the
Residual
Risk
Report
to
Congress,
we
intend
to
assess
facility­
wide
emissions
of
HAP
in
future
residual
risk
actions
under
§
112(
f)(
2),
as
appropriate
and
to
the
extent
it
is
reasonable
and
appropriate
to
do
so.
See
also,
54
Fed.
Reg.
at
38,059
(
Sept.
14,
1989)
(
benzene
NESHAP).
The
only
HAP
relevant
for
the
health­
based
compliance
alternatives
for
boiler
and
process
heater
facilities
are
HCl,
Cl
2,
and
Mn.
These
HAP
pose
noncancer
risks
to
human
health.
Affected
sources
able
to
demonstrate
that
they
meet
the
health­
based
compliance
alternatives
will
still
be
required
to
install
controls
for
other
pollutants
covered
under
the
final
rule.

Comment:
Commenter
IV­
D­
40
offered
comments
on
each
option
proposed
by
EPA
to
establish
a
HI
limit.
The
commenter
asserted
that
the
first,
second,
and
third
options
should
be
removed
from
consideration.
The
commenter
stated
that
the
first
option
(
HI
of
1)
assumes
no
other
exposures
to
threshold
HAP
from
emissions
from
nearby
sources
or
from
uptake
via
other
exposure
pathways.
The
commenter
believes
the
second
option
(
a
default
percentage
such
as
HI
of
0.2)
has
a
high
level
of
uncertainty
because
it
does
not
take
into
account
site
characteristics,
such
as
the
predominant
wind
speed
and
direction,
topography,
climate
and
other
related
parameters
affecting
the
dispersion
of
emissions.
The
commenter
pointed
out
that
the
third
option
(
using
data
available
through
EPA
or
other
scientific
sources
to
establish
background
concentrations)
has
two
major
limitations:
(
1)
use
of
historically
collected
data
to
estimate
current
background
conditions,
which
may
be
different
because
of,
for
example,
the
construction
of
new
sources,
the
development
of
new
monitoring
devices,
or
a
change
in
atmospheric
conditions,
and
(
2)
the
likely
use
of
regional
background
concentration
data,
which
may
or
may
not
accurately
reflect
the
local
air
concentrations.
The
commenter
believes
that
the
final
option
(
permit
facilities
to
estimate
their
own
specific
background
concentrations
and
apply
a
default
percentage
based
on
their
findings
to
ensure
their
emissions
would
not
result
in
an
HI
of
greater
than
one)
was
clearly
the
best
approach
for
establishing
a
facility's
HI
limit.
The
commenter
believes
that
this
option
would
result
in
accurate
site­
specific
estimations
of
background
concentrations
and
an
accurate
estimation
of
a
facility's
default
percentage.
Response:
We
are
not
considering
background
emissions
in
the
health­
based
compliance
alternatives
for
HCl
and/
or
Mn.
Rather,
as
we
indicated
in
the
Residual
Risk
Report
to
Congress,
we
intend
to
assess
facility­
wide
emissions
of
HAP
in
future
residual
risk
actions
under
§
112(
f)(
2),
as
appropriate
and
to
the
extent
it
is
reasonable
and
appropriate
to
do
so.
See
also,
54
Fed.
Reg.
at
38,059
(
Sept.
14,
1989)
(
benzene
NESHAP).
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
HCl
must
measure
emissions
of
HCl
and
Cl
2
and
compare
the
HI
to
1.0,
as
described
in
Appendix
A
to
250
subpart
DDDDD.
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
Mn
must
measure
emissions
of
Mn
and
compare
the
HQ
to
1.0,
as
described
in
Appendix
A
to
subpart
DDDDD.

18.6.2
Hazard
index
Comment:
Several
commenters
(
IV­
D­
73,
IV­
D­
75,
IV­
D­
122,
and
IV­
D­
123)
stated
that
HQ
for
chemical
mixes
should
not
be
summed
to
determine
the
HI
unless
the
primary
effects
are
on
the
same
organ
by
the
same
mechanism;
otherwise
the
risk
will
be
overestimated.
Commenters
IV­
D­
122
and
IV­
D­
123
stated
that,
according
to
the
National
Research
Council
and
the
Presidential/
Congressional
Commission
on
Risk
Assessment
and
Risk
Management,
additivity
at
low
doses
is
more
likely
to
overestimate
than
to
underestimate
total
risk.
(
Complex
Mixtures
(
NRC
1988),
1997
Presidential/
Congressional
Commission
on
Risk
Assessment
and
Risk
Management
in
Regulatory
Decision­
Making).
Response:
Our
recommended
approach
for
assessing
risks
from
exposure
to
a
mixture
of
pollutants
is
to
utilize
a
dose­
response
assessment
developed
for
that
mixture.
3
There
are
few
mixtures
(
e.
g.,
coke
oven
emissions),
however,
for
which
such
assessments
are
available.
When
mixture
specific
dose­
response
assessments
are
not
available,
a
component­
by­
component
approach
is
recommended.
The
method
for
component
data
depends
on
a
judgement
of
toxicologic
similarity
among
components.
The
specific
term
toxicologic
similarity
represents
a
general
knowledge
about
the
action
of
a
chemical
or
a
mixture
and
can
be
expressed
in
broad
terms
such
as
at
the
target
organ
level
in
the
body.
In
our
guidance,
assumptions
about
toxicologic
similarity
are
made
in
order
to
choose
among
risk
assessment
methods.
In
general,
we
assume
a
similar
mode
of
action
across
mixtures
or
mixture
components
and,
in
some
cases,
this
requirement
may
be
relaxed
to
require
that
these
chemicals
act
only
on
the
same
target
organ.
3
The
primary
method
for
component­
based
risk
assessment
of
toxicologically
similar
chemicals
is
the
HI,
which
is
derived
from
dose
addition.
In
our
guidance,
dose
addition
is
interpreted
as
simple
similar
action,
where
the
component
chemicals
act
as
if
they
are
dilutions
or
concentrations
of
each
other
differing
only
in
relative
toxicity.
Dose
additivity
may
not
hold
for
all
toxic
effects.
Further,
the
relative
toxic
potency
between
chemicals
may
differ
from
different
types
of
toxicity
or
toxicity
by
different
routes.
To
reflect
these
differences,
the
HI
is
then
usually
developed
for
each
exposure
route
of
interest,
and
for
a
single
specific
toxic
effect
of
toxicity
to
a
single
target
organ.
A
mixture
may
then
be
assessed
by
several
HI,
each
representing
one
route
and
one
toxic
effect
or
target
organ.
3
While
it
may
be
preferable
to
focus
on
the
addition
of
HAP
HQ
that
involve
the
same
mechanism
or
mode
of
action,
that
level
of
information
is
not
generally
available.
Pending
the
availability
of
such
data
for
the
HAP
components
of
the
mixture
being
assessed,
the
method
employed
is
to
aggregate
HAP
HQ
by
target
organ
to
generate
a
TOSHI.
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
HCl
will
calculate
an
HI
for
HCl
and
Cl
2.
Respiratory
toxicity
is
the
critical
effect
for
both
of
these
pollutants.
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
Mn
will
calculate
an
HQ
because
Mn
is
the
only
HAP
considered
for
this
option.

Comment:
Commenter
IV­
D­
61
stated
that
a
HI
of
1
provides
for
the
statutory
mandate
of
an
ample
margin
of
safety.
A
default
HI
of
1
is
appropriate
due
to
a
variety
of
factors,
including
the
statutory
mandate
to
focus
on
emissions
from
title
III
facilities
alone,
the
extensive
251
layers
of
conservatism
built
into
both
the
derivation
of
the
RfC
and
the
pertinent
exposure
modeling,
and
the
limited
exposures
to
these
HAP
through
other
pathways.
With
regard
to
threshold
HAP,
EPA
must
protect
human
health
with
an
"
ample
margin
of
safety,"
a
term
which
is
not
explicitly
defined
in
the
CAA.
The
D.
C.
Circuit
Court
of
Appeals
articulated
the
purpose
of
the
ample
margin
of
safety
determination
as
obtaining
a
"
reasonable
degree
of
protection"
in
light
of
scientific
uncertainties
and
information
gaps.
NRDC
v.
EPA,
824
F.
2D
1126,
1152­
53
(
D.
C.
Cir.
1987).
The
court's
interpretation
was
incorporated
verbatim
in
the
1990
CAAA,
and
the
Supreme
Court
has
consistently
held
that
"
when
administrative
and
judicial
interpretations
have
settled
the
meaning
of
an
existing
statutory
provision,
repetition
of
the
same
language
in
a
new
statute
indicates,
as
a
general
matter,
the
intent
to
incorporate
its
administrative
and
judicial
interpretations
as
well."
Bragdon
v.
Abbott,
524
U.
S.
634,
645
(
1998).
The
commenter
cited
several
reasons
why
the
existing
RfCs
and
similar
inhalation
health
benchmarks
already
incorporate
sufficient
uncertainty
factors
to
fulfill
or
exceed
the
ample
margin
of
safety
requirements,
and
believes
that
because
the
benchmarks
are
abundantly
protective,
an
HI
of
1
(
or
more)
should
serve
as
the
benchmark
for
risk­
based
compliance
options
in
the
Boiler
MACT.
Commenters
IV­
D­
122
and
IV­
D­
123
stated
that
the
Final
Report
of
the
Presidential/
Congressional
Commission
on
Risk
Assessment
and
Risk
Management
supports
that
HI
of
1
provides
an
ample
margin
of
safety.
This
Commission
was
mandated
by
the
1990
CAA
Amendments
to
provide
guidance
to
the
EPA
for
the
implementation
of
the
risk
aspects
of
these
Amendments.
Specifically,
the
Commission
recommended
that
EPA
should,
on
the
basis
of
screening
assessments
of
source
categories,
do
further
risk
assessment
and
analysis
of
categories
where
the
noncancer
HI
exceeds
10.0.
The
Commission
also
recommended
that,
where
more
detailed
risk
assessments
yield
noncancer
hazard
indices
less
than
1.0,
no
further
action
should
be
required.
Commenter
IV­
D­
73
stated
that
all
risk­
related
provisions
of
§
112
should
be
guided
by
the
purpose
of
the
ample
margin
of
safety
determination
­
namely,
to
account
for
uncertainty
in
the
underlying
health
value.
A
HI
equal
to
or
greater
than
1
should
account
for
uncertainty
and
provide
an
ample
margin
[
of]
safety.
Commenters
IV­
D­
73
and
IV­
D­
166
stated
that
The
Report
of
the
Commission
on
Risk
Assessment
and
Risk
Management
provides
further
guidance
and
supports
the
commenters'
contention
that
a
HI
equal
to
or
greater
than
1
should
provide
an
ample
margin
of
safety
for
a
threshold
HAP.
Commenter
IV­
D­
49
submitted
that
a
HI
of
1
using
the
RfC
(
or
similarly
derived
health
benchmark)
is
the
appropriate
risk­
based
benchmark
for
threshold
HAP.
The
commenter
noted
that
EPA's
mandate
under
the
CAA's
"
ample
margin
of
safety"
language
is
to
provide
a
reasonable
amount
of
protection
in
light
of
scientific
uncertainties
and
believes
that
the
RfC
contains
multiple
layers
of
conservatism
to
account
for
scientific
uncertainty
and
is
amply
protective
of
human
health.
The
commenter
stated
that
source
demonstrations
should
be
based
on
EPA­
approved
modeling
techniques,
which
provide
further
layers
of
conservatism.
Commenter
IV­
D­
78
suggested
that
HI
of
1
be
used
to
determine
i[
f]
a
source
should
be
exempt
from
MACT.
The
HI
of
1
is
defensible
because
the
RfCs
used
to
determine
the
HI
are
conservative.
The
RfCs
contain
uncertainty
factors
and
assume
lifetime
exposure
to
the
pollutant,
although
no
person
would
spend
a
lifetime
at
maximum
exposure.
Commenters
IV­
D­
75
stated
that
an
HI
of
10
or
less
should
be
considered
presumptively
safe,
considering
the
inherent
safety
factors
in
HI.
Commenter
IV­
D­
75
agreed
with
other
industry
commenters
that
an
HQ
of
one
should
be
considered
an
acceptable
level
and
sources
252
should
not
be
required
to
go
below
that
amount
to
an
arbitrary
level
such
as
0.2.
Commenter
IV­
D­
05
stated
that
the
HI
is
useful
in
evaluating
site­
specific
impacts,
but
choosing
a
generic
HI
(
some
multiple
of
1)
for
application
to
a
wide
range
of
sites
is
inappropriate.
The
commenter
added
that
selection
of
an
arbitrary
multiple
of
1
is
not
science,
does
not
conform
with
CAA
§
112(
d)(
4)
and
does
not
protect
public
health.
The
commenter
added
that
using
background
concentrations
from
NATA
and
a
HI
of
1
is
inappropriate
because
NATA
information
includes
warnings
that
the
information
is
useful
for
large­
scale
planning
purposes
and
not
for
local
area
assessment.
Commenter
IV­
D­
05
stated
that
the
selection
of
a
0.2
HI
as
a
rough
screening
tool
seems
reasonable,
although
it
is
unsupported
by
any
analysis.
The
commenter
added
that
if
a
default
HI
is
used,
EPA
should
include
a
provision
that
would
disallow
the
use
to
exclude
a
facility
from
MACT,
now
or
in
the
future,
if
better
background
information
is
available
that
suggests
that
the
default
does
not
protect
public
health.
The
commenter,
however,
believes
that
the
interpretation
that
includes
the
use
of
such
a
default
to
allow
exemptions
for
individual
sources
is
not
supported
by
the
CAA,
and
the
expansion
of
the
interpretation
to
include
non­
threshold
pollutants
is
in
direct
conflict
with
§
112(
d)(
4)
of
the
CAA.
Commenter
IV­
D­
14
evaluated
the
four
potential
options
that
EPA
proposed
to
ensure
that
a
risk
analysis
under
§
112(
d)(
4)
considers
the
total
ambient
air
concentrations
of
all
the
HAP
to
which
the
public
is
exposed.
Option
1,
which
requires
that
the
HI
for
all
pollutants
be
no
greater
than
1,
does
not
consider
additional
sources
or
background
and
is
unacceptable.
Option
3,
which
uses
existing
data
such
as
the
NATA
to
determine
background
and
requires
that
the
HI
be
no
greater
than
1,
is
also
unacceptable.
EPA
has
clearly
stated
at
public
meetings
that
the
NATA
is
not
to
be
used
to
make
regulatory
decisions.
The
NATA
relies
on
data
submitted
to
EPA
voluntarily
and
has
been
reported
to
consistently
underestimate
measured
concentrations.
Until
EPA
requires
that
HAP
inventories
be
submitted
as
proposed
in
the
Consolidated
Emissions
Reporting
Rule
(
CERR),
and
the
NATA
conducts
refined
modeling
around
stationary
sources,
the
NATA
should
not
be
considered
for
estimating
background
concentrations.
Option
4,
which
allows
individual
facilities
to
monitoring
the
HAP
backgrounds
for
use
in
their
own
analysis,
will
require
oversight
and
evaluation
by
the
States
to
ensure
proper
site
selections
and
analytical
methods
and
should
not
be
considered.
The
commenters
believe
Option
2,
which
requires
that
the
HI
be
no
greater
than
0.2,
would
be
the
only
viable
option
at
this
time
using
a
conservative
risk
screening
analysis.
However,
the
commenters
did
not
endorse
using
any
of
the
proposed
threshold
limit
applicability
methods
to
exempt
process
sources
from
NESHAP
requirements.
With
regard
to
the
HI
options,
commenter
IV­
D­
10
believes
the
first
option
(
HI
of
1)
should
be
allowed
for
facilities
located
in
rural
areas,
while
using
HI
of
0.2
may
be
appropriate
when
multiple
facilities
are
present.
The
commenter
submitted
that
the
determination
of
the
base
case
percentage
should
be
based
on
a
refined
typical
(
not
arbitrary)
scenario,
and
subject
to
modification
for
specific
cases
by
showing
how
they
differ
from
the
base
case.
Commenter
IV­
D­
10
would
like
to
see
more
details
on
the
third
and
fourth
options.
Response:
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
HCl
must
measure
emissions
of
HCl
and
Cl
2
and
compare
the
HI
to
1.0,
as
described
in
Appendix
A
to
subpart
DDDDD.
Affected
sources
attempting
to
utilize
the
health­
based
compliance
alternative
for
Mn
must
measure
emissions
of
Mn
and
compare
the
HQ
to
1.0,
as
described
in
Appendix
A
to
subpart
DDDDD.
We
consider
that
a
HI
(
or
HQ)
limit
of
1.0
provides
an
ample
margin
of
safety
for
protecting
public
health
under
CAA
§
112(
d)(
4)
for
these
health­
based
compliance
alternatives.
253
The
RfCs
that
are
used
to
calculate
the
HI
(
or
HQ)
are
developed
to
protect
sensitive
subgroups
and
to
account
for
scientific
uncertainties,
ensuring
that
the
use
of
a
HI
limit
of
1.0
provides
an
ample
margin
of
safety.
The
TOSHI
approach
required
for
HCl
and
Cl
2
assumes
additivity
in
mixtures
of
chemicals
that
target
the
same
organ
system.
We
conclude
that
a
HI
(
or
HQ)
limit
of
1.0
is
appropriate
for
the
§
112(
d)(
4)
demonstrations
for
the
boiler
and
process
heater
source
category
that
are
described
in
the
final
rule.
In
future
risk­
based
actions
for
this
and
other
source
categories
(
e.
g.,
residual
risk
rulemakings
under
CAA
§
112(
f)),
we
may
identify
factors
on
a
case­
by­
case
basis
that
would
lead
us
to
conclude
that
HI
limits
other
than
1.0
would
be
more
appropriate
for
those
other
actions.
The
look­
up
tables
included
in
Appendix
A
to
subpart
DDDDD
of
40
CFR
part
63
were
developed
based
on
a
HI
of
1.0
for
HCl
and
Cl
2
and
a
HQ
of
1.0
for
Mn.
For
site­
specific
chronic
inhalation
risk
assessments,
affected
sources
are
required
to
ensure
that
their
HI
(
HCl
and
Cl
2)
or
HQ
(
Mn)
are
less
than
or
equal
to
a
value
of
1.0.
Several
commenters
presumed
the
use
of
CAA
§
112(
c)(
9)
for
the
rule
as
proposed.
However,
we
are
using
CAA
§
112(
d)(
4)
and
not
§
112(
c)(
9).
We
are
not
considering
background
emissions
in
the
health­
based
compliance
alternatives
for
HCl
and/
or
Mn.
Rather,
as
we
indicated
in
the
Residual
Risk
Report
to
Congress,
we
intend
to
assess
facility­
wide
emissions
of
HAP
in
future
residual
risk
actions
under
§
112(
f)(
2),
as
appropriate
and
to
the
extent
it
is
reasonable
and
appropriate
to
do
so.
See
also,
54
Fed.
Reg.
at
38,059
(
Sept.
14,
1989)
(
benzene
NESHAP).

Comment:
Commenter
IV­
D­
73
stated
that
adoption
of
the
Drinking
Water
Program's
concept
of
a
HI
of
0.2
is
not
supportable.
The
commenter
added
that,
at
a
minimum,
before
EPA
could
import
the
drinking
water
policy
into
air
programs,
the
agency
would
need
to
evaluate
the
available
scientific
data
 
for
the
HAP
of
concern
in
each
individual
rulemaking
 
to
determine
whether
the
data
justify
a
conclusion
that
80
percent
of
the
exposures
to
those
pollutants
come
from
sources
outside
the
source
category.
Response:
Affected
sources
attempting
to
comply
with
the
health
based
alternatives
in
the
final
rule
will
compare
their
HI
(
HCl
and
Cl
2)
and/
or
HQ
(
Mn)
values
to
1.0.

Comment:
Commenter
IV­
D­
154
stated
that
in
the
case
of
RICE
and
boilers/
process
heaters,
which
emit
acrolein,
there
appears
to
be
no
reasonable
limit
(
that
would
allow
sufficient
protection
between
the
contribution
of
a
potentially
affected
source
and
the
existing
background
concentrations
of
non­
carcinogens)
since
exposure
to
acrolein
is
predicted
to
be
high
almost
everywhere
in
the
country
(
based
on
NATA).
Uniformly
applied
NESHAP
are
necessary
to
move
this
country
toward
lower
exposures
to
irritants
like
acrolein.
Response:
The
EPA
performed
an
assessment
of
respiratory
HAP,
CNS
HAP,
and
other
acid
gas
HAP
emitted
from
industrial
boilers
and
process
heaters
and
determined
that
only
HCl,
Cl
2,
and
Mn
contribute
significantly
to
risk.
Therefore,
these
are
the
only
HAP
relevant
for
the
health­
based
compliance
alternatives
in
the
final
rule.
Measurement
of
acrolein
emissions
are
not
included.

18.6.3
Short­
term
health
effects
Comment:
Commenter
IV­
D­
14
stated
that
the
proposal
did
not
[
address]
threshold
limitation
guideline
values
for
short­
term
exposure.
Commenter
IV­
D­
14
stated
that
HCl
has
a
254
short­
term
guideline
value
established
by
CalEPA.
Commenter
IV­
D­
14
stated
that
HCl
is
capable
of
eliciting
strong
upper
respiratory
responses
and
short
term
evaluation
should
be
part
of
any
health
risk
assessment
undertaken.
Response:
We
agree
with
the
need
to
consider
acute
effects.
The
EPA
conducted
a
screening
assessment
and
determined
that
acute
exposures
to
HCl,
as
well
as
other
respiratory
and
acid
gas
HAP,
emitted
from
boilers
and
process
heaters
are
unlikely
to
adversely
affect
human
health.
Therefore,
affected
sources
attempting
to
comply
with
the
health­
based
option
for
HCl
will
not
be
required
to
conduct
an
acute
assessment.

18.7
RISK
ASSESSMENT
FRAMEWORK
ISSUES:
ESTIMATING
RISKS
TO
ECOLOGICAL
RECEPTORS
Comment:
Commenters
IV­
D­
60,
IV­
D­
61,
IV­
D­
62,
IV­
D­
119,
IV­
D­
122,
and
IV­
D­
123
submitted
that
the
RfC
for
HCl
is
protective
of
environmental
effects.
The
commenters
noted
that
in
both
of
EPA's
prior
risk­
based
determinations
not
to
regulate
HCl
(
pulp
and
paper
chemical
recovery
combustion
MACT
and
chlorine
production
MACT),
EPA
concluded
that
a
human
health­
based
applicability
cutoff
would
also
protect
other
environmental
values.
The
commenters
believe
EPA
has
no
reason
to
reach
a
different
conclusion
in
the
Boiler
MACT
context.
Commenters
IV­
D­
26,
IV­
D­
104,
and
IV­
D­
150
stated
that
scientific
literature
suggests
that
there
are
not
likely
to
be
any
significant
and
widespread
adverse
environmental
effects
to
wildlife,
aquatic
life,
and
other
natural
resources
attributable
to
Mn.
Commenters
IV­
D­
17
and
IV­
D­
118
stated
that
the
proposal
does
not
address
ecological
risk
that
may
result
from
uncontrolled
HAP
emissions,
especially
in
those
areas
with
sensitive
habitats
but
few
people
nearby
to
be
exposed.
Commenter
IV­
D­
148
stated
that
EPA
provided
inadequate
discussion
of
how
environmental
risks
will
be
evaluated.
The
commenter
added
that
the
CAA
requires
that
EPA
consider
the
environment
as
well
as
public
health,
and
at
a
minimum,
a
facility
would
be
required
to
conduct
an
assessment
based
on
EPA's
Guidelines
for
Ecosystem
Assessment
(
1998).
The
commenter
referred
EPA
to
Appendix
A
of
"
Generic
Assessment
for
Endpoints
for
Ecological
Risk
Assessment"
for
a
detailed
discussion
on
the
legal
basis
from
"
such
statutes
as
the
CAA...
that
require
EPA
to
consider
and
protect
organism­
level
attributes
or
various
taxa
including
fish,
birds,
and
plants
and
more
generally,
animals,
wildlife,
aquatic
life,
and
living
things."
Response:
An
ecological
assessment
is
normally
required
under
§
112(
d)(
4),
(
c)(
9),
and
(
f)(
2)
of
the
CAA
regarding
the
presence
or
absence
of
"
adverse
environmental
effects"
as
that
term
is
defined
in
CAA
§
112(
a)(
7).
To
identify
potential
multimedia
and/
or
environmental
concerns,
the
EPA
has
identified
HAP
with
significant
potential
to
persist
in
the
environment
and
to
bioaccumulate.
However,
this
list
does
not
include
HCl,
Cl
2,
or
Mn
which
are
the
only
HAP
relevant
for
the
health­
based
compliance
alternatives
under
the
final
rule.
Additionally,
a
screening
level
analysis
conducted
by
the
EPA
indicates
that
acute
impacts
of
these
HAP
from
boiler
facilities
are
highly
unlikely.
For
these
reasons
we
do
not
believe
that
emissions
of
HCl,
Cl
2
or
Mn
from
boiler
facilities
will
pose
a
significant
risk
to
the
environment,
and
facilities
attempting
to
comply
with
the
risk­
based
alternatives
for
these
HAP
are
not
required
to
perform
an
ecological
assessment.
255
18.8
RISK
ASSESSMENT
FRAMEWORK
ISSUES:
TIERED
APPROACH
AND
RISK
ASSESSMENT
GUIDANCE
18.8.1
Tiered
approach
Comment:
Multiple
commenters
(
IV­
D­
05,
IV­
D­
10,
IV­
D­
14,
IV­
D­
24,
IV­
D­
26,
IVD
61,
IV­
D­
72,
IV­
D­
73,
IV­
D­
75,
IV­
D­
104,
IV­
D­
146,
IV­
D­
150,
IV­
D­
166,
and
IV­
D­
186)
commented
on
the
tiered
modeling
approach.
Several
commenters
(
IV­
D­
10,
IV­
D­
26,
IV­
D­
72,
IV­
D­
73,
IV­
D­
75,
IV­
D­
104,
IV­
D­
146,
IV­
D­
150,
IV­
D­
166,
and
IV­
D­
186)
support
EPA's
proposed
tiered
modeling
approach,
which
begins
with
simple
"
look­
up
tables"
and
progresses
to
more
refined
facility­
specific
risk
assessments.
Commenter
IV­
D­
05
stated
that
the
State
of
Wisconsin
uses
a
tiered
approach
that
first
allows
sources
to
demonstrate
compliance
if
their
potential
emissions,
stack
height,
and
exhaust
direction
are
within
the
ranges
provided
in
conservative
look­
up
tables.
The
second
tier
allows
affected
sources
to
provide
site­
specific
modeling
to
demonstrate
compliance
with
ambient
air
standards
at
the
property
line.
In
general,
the
tiered
approach
has
worked
well
in
Wisconsin.
Commenter
IV­
D­
75
added
that
EPA
should
be
flexible
in
accepting
evolving
improvements
in
exposure
assessment
and
risk
modeling,
and
should
take
into
account
the
inherent
strengths
and
weaknesses
of
the
types
of
modeling
used.
Commenters
IV­
D­
73
and
IV­
D­
166
stated
that
an
initial
simplified
tier
of
risk
assessment,
such
as
look­
up
table,
nomograph,
or
equivalent,
should
be
embedded
in
individual
rulemakings.
The
commenters
added
that
a
guidance
document
should
address
two
additional
tiers
of
assessment:
a
conservative
screening
approach,
and
a
flexible
refined
approach.
Commenter
IV­
D­
73
stated
that
a
risk
assessment
guidance
document
should
not
attempt
to
address
policy
and
regulatory
decisions.
Rather,
regulatory
goals
and
policies
should
be
put
forth
within
individual
notice
and
rulemakings.
Appropriate
risk
assessment
endpoints
of
concern
will
also
be
established
within
these
rulemakings.
Commenter
IV­
D­
73
stated
that
rulemakings
that
use
source­
conducted
risk
assessment
should
appropriately
focus
the
initial
scope
of
the
assessment
on
the
HAP,
sources,
and
other
parameters
of
concern
through
applicability
criteria
specified
with
the
individual
rulemakings.
Commenter
IV­
D­
73
added
that
refined
risk
assessments
(
3rd
tier)
should
allow
for
more
accurate
estimates
of
maximum
individual
risk,
and
could
accomplish
this
through:
(
1)
modeling
ambient
exposures
to
an
actual
human
receptor
location;
(
2)
use
of
exposure
factors
or
models;
(
3)
use
of
realistic
exposure
assumptions
based
on
site­
specific
data
(
residential
tenure,
etc.);
and,
(
4)
use
of
probabilistic
analysis
of
uncertainty
and
variability.
Commenter
IV­
D­
61
believes
that
a
stepped
risk­
based
compliance
option
would
be
most
effective
and
efficient
in
achieving
the
goals
of
the
Boiler
MACT.
As
an
initial
threshold
matter,
the
commenter
believes
that
sources
operating
within
certain
fueling
limitations
should
be
exempted
from
the
requirements
of
the
final
rule.
HAP
content
in
fuel
is
one
of
the
most
significant
determinants
to
HAP
emissions,
and,
as
a
result,
sources
that
only
operate
on
low
HAP
fuel
would
never
be
expected
to
exceed
any
of
the
MACT
limits
in
the
proposed
rule.
To
demonstrate
compliance,
sources
would
pick
their
worst­
case
fuel
and
demonstrate
that
uncontrolled
emissions
from
that
fuel
(
assuming
all
HAP
in
the
fuel
is
emitted)
do
not
exceed
the
limits.
The
second
step,
for
affected
sources
that
do
not
qualify
based
on
fuel,
a
simple
screening
model,
such
as
EPA's
Screen
III,
could
be
used
to
demonstrate
that
HAP
emissions
are
below
the
health
benchmark.
Additional
steps
could
require
the
use
of
more
sophisticated
models.
256
Commenter
IV­
D­
24
suggested
that
EPA
should
establish
automatic
subcategory
delisting
criteria
where
a
facility
that
meets
the
criteria
can
apply
for
automatic
delisting.
The
commenter
further
suggested
that
such
criteria
would
be
based
on
fuel
type
and
usage
as
well
as
control
efficiency,
if
any
were
used.
On
the
other
hand,
Commenter
IV­
D­
14
stated
that
if
EPA
decides
to
pursue
an
up
front
risk
analysis
approach,
it
should
not
be
a
tiered
approach.
The
development
of
generic
risk
screening
approach
under
the
§
112(
d)(
4)
framework
will
need
to
be
conservative,
and
the
use
of
a
(
non­
tiered)
conservative
approach
would
represent
the
least
cost
to
the
regulated
community
and
would
be
the
least
time
consuming
for
States
reviewing
the
facility's
application.
Response:
We
discussed
a
tiered
analytical
approach
in
the
preamble
to
the
proposed
rule,
beginning
with
relatively
simple
look­
up
tables
and
followed
by
increasingly
more
site­
specific
but
more
resource
intensive
tiers
of
analysis,
with
each
tier
being
more
refined
and
less
conservative.
In
the
final
rule,
we
are
adopting
a
somewhat
different
approach
for
meeting
the
requirements
of
CAA
§
112(
d)(
4).
The
basis
for
this
approach
stems
from
the
general
air
toxics
assessment
approach
presented
in
the
Residual
Risk
Report
to
Congress,
which
was
developed
with
full
consideration
of
EPA
risk
assessment
policy,
guidance,
and
methodology.
2
Affected
sources
can
demonstrate
eligibility
for
the
health­
based
emission
limits
by
using
site­
specific
emissions
test
data
and
look­
up
tables
that
were
developed
using
health­
protective
input
parameters.
These
look­
up
tables
are
included
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
Affected
sources
that
cannot
demonstrate
eligibility
based
on
the
health­
protective
screening
assessment
(
i.
e.,
look­
up
tables)
may
use
more
refined
site­
specific
risk
assessments
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
and
in
other
analytical
tools
such
as
the
"
Air
Toxics
Risk
Assessment
Reference
Library,"
(
which
may
be
appropriate
for
specific
sources).
A
more
refined
analysis
requires
more
effort,
but
produces
results
that
are
less
uncertain
and
less
conservative
(
i.
e.,
less
likely
to
overestimate
risk).
2
For
site­
specific
modeling,
we
will
consider
assessments
that,
in
conjunction
with
the
criteria
specified
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63,
use
risk
methodology
and
modeling
techniques
other
than
that
described
in
the
EPA's
"
Air
Toxics
Risk
Assessment
Reference
Library"
provided
they
have
undergone
scientific
peer­
review
pertinent
to
their
use
in
the
submitted
assessment.
For
more
information
on
how
site­
specific
modeling
can
be
performed,
affected
sources
are
referred
to
the
EPA
"
Air
Toxics
Risk
Assessment
Reference
Library,"
which
describes
possible
approaches
for
conducting
the
site­
specific
modeling.
No
automatic
delisting
criteria
have
been
included
in
the
final
rule,
as
suggested
by
one
commenter.
No
specific
exemption
based
on
fuel
type
has
been
included
as
part
of
the
healthbased
compliance
alternatives.
All
affected
sources
with
boilers
and
process
heaters
in
the
applicable
large
solid
fuel­
fired
subcategory
have
an
opportunity
to
demonstrate
that
they
can
meet
the
health­
based
compliance
alternatives
for
HCl
and
Mn.
Fuel
analysis
requirements
related
to
continuous
compliance
demonstration
are
addressed
elsewhere
in
this
document.
The
§
112(
d)(
4)
authority
used
to
provide
the
health­
based
compliance
alternatives
for
the
HCl
emission
limit
and
Mn
(
TSM)
emission
limit
is
discussed
in
section
18.2.

Comment:
Commenters
IV­
D­
122
and
IV­
D­
123
described
EPA's
proposed
tiered
modeling
approach
and
noted
that,
while
most
sources
would
use
this
modeling
approach,
they
believe
facilities
should
be
allowed
to
use
any
EPA­
approved
modeling
technique
to
demonstrate
that
its
emissions
are
below
the
applicable
health
benchmark.
Commenters
IV­
D­
122
and
IV­
D­
257
123
believe
that
Tier
I
(
screening
level
analyses
or
look­
up
tables)
will
be
sufficient
to
make
the
low
risk
finding
for
HCl.
Response:
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
describes
the
process
by
which
affected
sources
can
demonstrate
that
boilers
and
process
heaters
meet
the
health­
based
compliance
alternatives.
Affected
sources
may
demonstrate
that
boilers
and
process
heaters
in
the
large
solid
fuel­
fired
subcategory
meet
the
health­
based
compliance
alternatives
using
either
(
1)
the
"
look­
up
table"
analysis
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
or
(
2)
site­
specific
modeling
(
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
and
other
analytical
tools,
which
may
be
appropriate
for
a
specific
source,
such
as
EPA's
"
Air
Toxics
Risk
Assessment
Reference
Library").
Affected
sources
electing
to
conduct
site­
specific
modeling
can
use
any
scientifically
defensible,
transparent,
and
peer­
reviewed
methodology
they
choose
in
conjunction
with
the
criteria
specified
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
An
example
of
how
site­
specific
modeling
can
be
performed
is
described
in
the
EPA
"
Air
Toxics
Risk
Assessment
Reference
Library."

18.8.2
Risk
assessment
guidance
Comment:
Commenter
IV­
D­
148
stated
that
EPA's
proposal
for
risk­
based
exemptions
effectively
misinterprets
not
only
the
CAA
but
also
the
guidelines
and
science
policies
established
by
EPA
to
ensure
adequate
protection
of
public
health
and
the
environment.
EPA
proposes
a
disorganized
and
cursory
approach
to
implement
risk­
based
exemptions,
which
falls
far
below
the
quality
of
risk
analysis
typically
required
by
EPA
across
other
EPA
programs.
The
proposal
does
not
adhere
to
EPA's
established
guidelines
for
characterizing
human
health
and
ecological
risks.
The
proposal
does
not
incorporate
risk
assessment
guidelines
for
conducting
multi­
pathway
risk
assessments.
The
proposal
does
not
reference
EPA
guidelines
for
cumulative
risk
assessment
that
specifically
require
consideration
of
non­
inhalation
pathways.
The
goals
of
EPA's
March
1995
Risk
Characterization
Policy
of
transparency,
clarity,
consistency,
and
reasonableness
in
EPA
risk
assessments
apply
to
risk
assessment
practices
across
the
EPA.
The
inconsistencies
between
EPA's
proposal
to
provide
risk­
based
exemptions
in
the
MACT
standard
process
and
risk
assessment
guidelines
undermine
many
regulatory
programs
throughout
the
EPA.
(
The
commenter
listed
numerous
programs).
Commenter
IV­
D­
148
also
stated
that
the
critical
deficiency
in
the
[
risk­
based]
scheme
reflects
a
fundamental
misunderstanding
of
the
use
of
public
health
and
ecological
risk
assessments
in
the
regulatory
process.
The
commenter
added
that
the
hallmark
of
the
federal
risk
assessment
guidelines
is
a
series
of
policy
memos
that
require
EPA
programs
to
conduct
risk
assessments
consistently
across
all
federal
environmental
programs.
The
approaches
outlined
by
AF&
PA's
white
papers
neglect
to
include
risk
characterization,
which
provides
needed
and
appropriate
information
to
decision
makers.
The
approaches
also
do
not
incorporate
the
critical
recommendation
of
the
Commission
of
Risk
Assessment
and
Risk
Management
to
establish
a
framework
for
stakeholder­
based
risk
management
decision
making.
These
omissions
in
the
proposals
will
prevent
regulatory
agencies
from
demonstrating
to
the
public
that
public
health
and
the
environment
are
adequately
protected.
However,
commenter
IV­
D­
123
stated
that
the
proposal
is
consistent
with
EPA
risk
assessment
guidelines
and
policies
and
they
believe
that
NESCAUM's
technical
objections
are
without
merit.
Specifically
the
commenter
stated
that:
(
1)
The
proposal
is
not
inconsistent
with
EPA's
risk
assessment
guidelines
and
policies;
and
(
2)
The
contemplated
risk­
based
applicability
258
criteria
are
not
in
conflict
with
the
classification
of
carcinogens
and
non­
carcinogens.
Response:
We
discussed
a
tiered
analytical
approach
in
the
preamble
to
the
proposed
rule,
beginning
with
relatively
simple
look­
up
tables
and
followed
by
increasingly
more
site­
specific
but
more
resource
intensive
tiers
of
analysis,
with
each
tier
being
more
refined.
In
the
final
rule,
we
are
adopting
a
somewhat
different
approach
for
meeting
the
requirements
of
CAA
§
112(
d)(
4).
The
basis
for
this
approach
stems
from
the
general
air
toxics
assessment
approach
presented
in
the
Residual
Risk
Report
to
Congress,
which
was
developed
with
full
consideration
of
EPA
risk
assessment
policy,
guidance,
and
methodology.
2
Affected
sources
can
comply
with
a
health­
based
alternative
for
Mn
and/
or
HCl.
EPA
has
identified
those
HAP
with
greatest
potential
to
cause
multimedia
or
environmental
impacts.
However,
this
list
does
not
include
HCl,
Cl
2,
or
Mn
which
are
the
only
HAP
relevant
for
the
health­
based
compliance
alternatives
under
the
final
rule.
Therefore,
affected
sources
attempting
to
comply
with
the
health­
based
alternative
in
the
final
rule
are
not
required
to
perform
a
multipathway
analysis.
Additionally,
a
screening
level
analysis
conducted
by
the
EPA
indicates
that
acute
impacts
of
these
HAP
from
boiler
facilities
are
highly
unlikely.
For
these
reasons
we
do
not
believe
that
emissions
of
HCl,
Cl
2
or
Mn
from
boiler
and
process
heater
facilities
will
pose
a
significant
risk
to
the
environment,
and
affected
sources
attempting
to
comply
with
the
risk­
based
alternatives
are
not
required
to
perform
an
ecological
assessment.
Because
Mn,
HCl
and
Cl
2
are
threshold
non­
carcinogenic
pollutants,
affected
sources
will
only
be
required
to
assess
non­
carcinogenic
endpoints
in
their
modeling.

Comment:
Commenter
IV­
D­
184
stated
that
EPA
should
incorporate
peer­
reviewed
and
validated
scientific
methods
and
use
high
quality
data
to
assess
risk.
It
is
critical
that
any
riskbased
air
toxics
regulation
be
based
on
up­
to­
date
science,
including
the
use
of
accurate
and
current
emissions
data,
health
effects
information,
modeling
techniques,
and
risk
assessment
methodologies.
Response:
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
describes
the
process
by
which
affected
sources
can
demonstrate
that
boilers
and
process
heaters
meet
the
health­
based
compliance
alternatives.
Affected
sources
can
demonstrate
eligibility
for
the
health­
based
emission
limits
by
using
site­
specific
emissions
test
data
and
look­
up
tables
that
were
developed
using
health­
protective
input
parameters.
These
look­
up
tables
are
included
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
Affected
sources
that
cannot
demonstrate
eligibility
based
on
the
health­
protective
screening
assessment
(
i.
e.,
look­
up
tables)
may
use
more
refined
sitespecific
risk
assessments
as
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
and
in
other
analytical
tools
such
as
the
"
Air
Toxics
Risk
Assessment
Reference
Library,"
(
which
may
be
appropriate
for
specific
sources).
Affected
sources
will
be
required
to
conduct
emission
testing
for
HCl,
Cl
2,
and
Mn
from
the
boiler
and
process
heater
source
category.

Comment:
Commenters
IV­
D­
73
and
IV­
D­
166
stated
that
any
risk­
based
approaches
should
be
consistent
with
the
policies
in
development
for
the
residual
risk
rules.
Commenters
IVD
166
and
IV­
D­
73
stated
that
EPA
should
specify
many
of
the
procedures
for
facility­
specific
risk
assessments
in
guidelines
rather
than
in
the
rules,
because
procedures
set
in
rules
could
be
seen
as
precedent
setting
and
could
impact
the
residual
risk
program.
For
example,
the
commenters
believe
that
EPA
should
specify
the
threshold
levels
by
which
a
source
would
be
excluded
from
a
rule,
as
well
as
any
Tier
1
look­
up
tables,
in
each
individual
rule.
In
contrast,
the
specifics
for
how
sources
should
carry
out
Tier
2
and
Tier
3
risk
assessments
should
be
left
259
flexible
in
guidelines
now
under
development
by
EPA
for
the
residual
risk
program.
Commenters
IV­
D­
09,
IV­
D­
118,
and
IV­
D­
154
stated
that
the
tools
needed
to
identify
sources
eligible
for
the
risk­
based
exemption
would
be
the
same
tools
necessary
for
a
§
112(
f)
residual
risk
assessment.
It
is
the
commenters'
understanding
that
these
tools
are
not
yet
ready
for
general
use.
Commenter
IV­
D­
148
stated
that
the
cancer
risk
guidelines
are
currently
undergoing
public
review.
Commenter
IV­
D­
14
has
serious
reservations
with
EPA's
apparent
attempt
to
conduct
an
ad­
hoc
risk
analysis
for
specific
source
categories
by
seeking
comments
on
the
specific
elements
to
be
included
in
the
risk
analysis
and
do
not
believe
these
rulemakings
are
an
adequate
forum
to
develop
this
risk
analysis
process.
The
commenters
believe
that
any
risk
analysis
conducted
by
the
EPA
must
adhere
to
the
risk
assessment
principles
outlined
in
the
Residual
Risk
Report
to
Congress.
Response:
We
agree
that
the
tools
needed
to
identify
sources
eligible
for
health­
based
compliance
alternatives
are
the
same
tools
necessary
for
a
§
112(
f)
residual
risk
assessment;
as
stated
in
the
Residual
Risk
Report
to
Congress,
we
intend
to
rely
on
the
general
methodology
and
process
illustrated
by
the
framework
presented
in
that
report
in
our
risk
assessment
activities
throughout
the
air
toxics
program.
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
describes
the
process
by
which
affected
sources
can
demonstrate
that
boilers
and
process
heaters
meet
the
health­
based
compliance
alternatives.
Affected
sources
may
demonstrate
that
boilers
and
process
heaters
in
the
large
solid
fuel­
fired
subcategory
meet
the
health­
based
compliance
alternative
using
either
(
1)
the
"
look­
up
table"
analysis
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
or
(
2)
site­
specific
modeling
(
described
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63
and
other
analytical
tools,
which
may
be
appropriate
for
a
specific
source,
such
as
EPA's
"
Air
Toxics
Risk
Assessment
Reference
Library").
Affected
sources
electing
to
conduct
sitespecific
modeling
can
use
any
scientifically
defensible,
transparent,
and
peer­
reviewed
methodology
they
choose
in
conjunction
with
the
criteria
specified
in
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63.
An
example
of
how
site­
specific
modeling
can
be
performed
is
described
in
the
EPA
"
Air
Toxics
Risk
Assessment
Reference
Library."
The
"
Air
Toxics
Risk
Assessment
Guidance
Library"
is
the
same
document
that
could
be
used,
where
appropriate,
for
facility­
specific
residual
risk
assessments
required
under
CAA
§
112(
f).
This
document
has
been
peer­
reviewed
and
was
developed
according
to
the
principles,
tools
and
methods
outlined
in
the
Residual
Risk
Report
to
Congress.
However,
it
may
not
be
appropriate
for
all
sources,
and
for
that
reason,
sources
and
EPA
may
consider
alternative
analytical
tools.
The
comment
that
the
new
cancer
guidelines
are
still
under
review
is
correct
but
as
stated
in
the
November
29,
2001
Federal
Register
notice
(
66
FR
59593),
these
1999
draft
guidelines
are
to
be
considered
the
interim
guidance.
5
18.8.3
Model
regulatory
text
Comment:
Commenter
IV­
D­
123
provided
model
regulatory
text
that
could
be
used
to
incorporate
an
HCl
risk­
based
compliance
option
into
the
final
rule
(
see
Attachment
D
to
IV­
D­
123).
The
commenter
believes
that
their
suggested
regulatory
text
will
allow
for
implementation
of
a
risk­
based
compliance
option
that
minimizes
administrative
burdens
on
States
and
industry,
ensures
protection
of
human
health
and
the
environment,
provides
for
continuous
compliance,
is
260
transparent
to
regulators,
industry
and
the
interested
public,
and
is
readily
enforceable.
Response:
We
acknowledge
receipt
of
the
model
regulatory
text
submitted
by
the
commenter.
However,
we
have
developed
our
own
regulatory
text
in
the
final
rule
(
Appendix
A
of
subpart
DDDDD
of
40
CFR
part
63)
to
specify
how
affected
sources
must
demonstrate
that
they
meet
the
health­
based
compliance
alternatives
for
HCl
and
Mn.

18.9
PROGRAM
ISSUES:
STATE
RESOURCES
Comment:
Commenters
IV­
D­
09,
IV­
D­
14,
IV­
D­
17,
IV­
D­
85,
IV­
D­
102,
IV­
D­
118,
IV­
D­
130,
and
IV­
D­
154
contended
that
the
proposal
will
place
a
very
intensive
resource
demand
on
State
and
local
agencies
to
review
source's
risk
assessments.
State/
local
agencies
may
not
have
expertise
in
risk
assessment
methodology
or
the
resources
needed
to
verify
information
(
e.
g.,
emissions
data
and
stack
parameters)
submitted
with
each
risk
assessment.
Commenter
IV­
D­
130
stated
that
they
do
not
have
the
resources
to
conduct
extensive
risk
analyses
and
requested
assistance
from
EPA
in
any
way
needed
if
this
option
is
to
work.
Commenter
IV­
D­
14
stated
that
if
EPA
intends
to
have
the
affected
industries
conduct
the
analysis,
then
EPA
must
consider
the
cost
incurred
by
States
which
may
lack
the
necessary
expertise
to
evaluate
and
review
these
analyses.
The
current
proposal
is
silent
on
these
implementation
and
cost
issues.
Commenters,
IV­
D­
17,
IV­
D­
102,
and
IV­
D­
154
stated
that
because
the
procedures
for
preparing
these
risk
assessments
on
a
large
scale
basis
and
for
assessing
the
potential
adverse
effects
of
the
pollutants
emitted
(
e.
g.,
taking
into
account
existing
background
and
looking
for
a
threshold
level
for
carcinogens)
are
untried
and
will
require
extensive
debate
and
review
to
launch,
even
more
time
and
resources
will
be
needed.
Commenter
IV­
D­
154
expressed
concern
about
exempting
a
facility
based
on
limited
emission
data
if
EPA
established
a
subcategory
listing
low­
risk
sources.
Commenter
IV­
D­
148
pointed
out
that
the
proposal
only
considers
cost
for
the
regulated
source
category,
and
not
for
regulatory
agencies.
The
EPA
did
not
consider
the
costs
and
resources
associated
with:
(
1)
the
public
process
required
in
reviewing/
approving
the
proposed
approaches
and,
if
approved,
making
substantial
changes
to
existing
regulations;
(
2)
the
development
of
methods
and
guidance
for
human
health
and
ecological
risk
assessments
of
affected
sources;
(
3)
the
review
by
already
budgetarily
constrained
State
agencies
of
the
assessments
and
assurance
of
adequate
public
participation
in
the
process;
and
(
4)
the
collection/
verification
of
source­
specific
data
needed
for
conducting
risk
assessments.
Commenter
IV­
D­
148
added
that
the
proposals
do
not
address
the
critical
need
for
qualified
assessors
to
evaluate
the
scientific
and
technical
basis
for
exempting
facilities
from
regulation
on
a
case­
by­
case
basis,
and
estimated
that
if
1
additional
full­
time
employee
(
FTE)
were
required
per
State
to
review
risk­
based
exemptions,
the
costs
would
be
an
additional
$
7.5
million
annually.
Commenter
IV­
D­
05
stated
that
they
are
concerned
about
the
potential
cost
and
workload
that
risk
provisions
would
place
on
permitting
authorities.
The
commenter
added
that
the
permitting
authorities
would
need
to
either
perform
or
verify
the
risk
analyses,
and
that
diverting
State
and
local
resources
to
focus
on
presumably
insignificant
sources
would
detract
from
efforts
associated
with
significant
sources.
The
commenter
pointed
out
some
of
the
specific
items
that
would
add
burden
to
the
State
and
local
agencies,
including
data
verification
for
background
concentrations
and
ongoing
assurance
that
low­
risk
facilities
remain
low
risk.
Because
EPA
understands
the
difficulty
with
risk
assessments,
commenter
IV­
D­
06
found
it
perplexing
that
EPA
believes
such
analyses
at
the
State
and
local
levels
would
be
an
efficient
way
to
protect
public
health.
261
By
contrast,
other
commenters
(
IV­
D­
123
and
IV­
D­
180)
believe
that
a
risk­
based
program
can
be
structured
and
implemented
in
a
manner
that
does
not
adversely
impact
limited
State
resources.
Commenter
IV­
D­
148
believes
that
EPA
should
work
closely
with
States
and
industry
to
implement
the
risk­
based
approach
in
a
non­
burdensome
manner.
Commenter
IV­
D­
123
stated
that
the
risk­
based
approaches,
like
other
MACT
standards,
would
simply
be
incorporated
into
each
State's
existing
title
V
program.
Because
the
title
V
framework
already
exists,
the
addition
of
a
risk­
based
MACT
standard
would
not
require
States
to
overhaul
existing
permitting
programs.
Commenter
IV­
D­
123
added
that
the
risk­
based
approach
would
not
increase
the
number
of
sources
regulated
by
each
State.
The
commenter
believes
that
the
final
MACT
rule
itself
should
set
forth
the
applicability
criteria
­
including
the
threshold
levels
of
exposure
­
that
sources
must
meet
to
qualify
for
a
risk­
based
determination.
Each
source
would
have
the
burden
of
demonstrating
that
its
exposures
are
below
this
limit,
and
therefore
the
States
would
not
be
required
to
develop
their
own
risk
assessment
guidance
or
to
conduct
source­
specific
risk
assessments.
Commenter
IV­
D­
123
stated
that
the
risk
assessment
guidance
to
be
issued
by
EPA
within
the
next
several
months
will
streamline
the
risk­
based
approach
and
further
reduce
any
burden
on
the
States.
Commenters
IV­
D­
123
and
IV­
D­
180
supported
having
States
charge
reasonable
increased
fees
(
as
a
component
of
annual
operating
permit
fees
or
other
fees)
to
cover
any
significant
additional
workload
demands
associated
with
reviewing
moredetailed
Tier
2/
3
modeling.
Response:
The
health­
based
compliance
alternatives
for
HCl
and
Mn
which
we
have
adopted
in
the
Boiler
NESHAP
do
not
rely
solely
on
site­
specific
risk
assessments
and,
therefore,
should
not
impose
significant
resource
burdens
on
States.
Further,
the
required
compliance
demonstration
methodology
is
structured
in
such
a
way
as
to
avoid
the
need
for
States
to
have
significant
expertise
in
risk
assessment
methodology.
We
have
considered
the
commenters'
concerns
in
developing
the
criteria
defining
eligibility
for
these
compliance
alternatives,
and
we
believe
that
the
approach
that
is
included
in
the
final
rule
provides
clear,
flexible
requirements
and
enforceable
compliance
parameters.
The
final
rule
provides
two
ways
that
an
affected
facility
may
demonstrate
eligibility
for
complying
with
the
alternative
health­
based
emission
standard.
First,
look­
up
tables,
which
are
included
as
Tables
2
(
HCl)
and
3
(
Mn)
in
Appendix
A
of
subpart
DDDDD,
allow
affected
facilities
to
determine,
using
a
limited
number
of
site­
specific
input
parameters,
whether
emissions
from
their
affected
sources
might
cause
a
HI
(
or
HQ)
limit
to
be
exceeded.
If
an
affected
facility
cannot
demonstrate
eligibility
using
a
look­
up
table,
a
modeling
approach
can
be
followed.
Appendix
A
to
the
final
rule
presents
the
criteria
for
performing
this
modeling.
Regarding
commenters'
concerns
with
looking
for
a
threshold
level
for
carcinogens,
the
compliance
alternatives
only
apply
to
HCl
and
Mn,
which
are
not
carcinogens.
Also,
regarding
the
concern
expressed
by
one
commenter
about
exempting
a
facility
based
on
limited
emission
data
if
EPA
established
a
subcategory
listing
low­
risk
sources,
we
have
not
used
§
112(
c)(
9)
authority
to
establish
a
low­
risk
subcategory
for
the
boilers
and
process
heaters
source
category.
With
respect
to
guidance
for
performing
site­
specific
modeling,
all
of
the
procedures
for
performing
such
modeling
are
available
in
peer­
reviewed
scientific
literature,
and
therefore,
no
additional
guidance
needs
to
be
developed.
Only
a
portion
of
the
major
facilities
in
the
large
solid
fuel­
fired
boilers
and
process
heaters
subcategory
will
submit
eligibility
demonstrations
for
the
compliance
alternatives.
Of
this
portion
of
major
sources,
we
believe
that
most
will
be
able
to
demonstrate
eligibility
based
on
simple
analyses
(
e.
g.,
using
the
look­
up
tables
provided
in
Appendix
A).
However,
it
is
likely
that
262
some
affected
facilities
will
require
more
detailed
modeling.
The
criteria
for
demonstrating
eligibility
for
the
compliance
alternatives
are
clearly
spelled
out
in
the
final
rule.
Because
these
requirements
are
clearly
spelled
out
and
because
any
standards
or
requirements
created
under
§
112
are
considered
applicable
requirements
under
part
70,
compliance
alternatives
would
be
incorporated
into
title
V
programs,
and
States
would
not
have
to
overhaul
existing
permitting
programs.
Finally,
with
respect
to
the
burden
associated
with
ongoing
assurance
that
affected
facilities
which
opt
to
do
so
continue
to
comply
with
the
health­
based
compliance
alternatives,
the
burden
to
States
will
be
minimal.
Rather
than
developing
detailed
recordkeeping
and
reporting
requirements
for
facilities
that
initially
qualify
for
the
health­
based
compliance
alternatives,
we
are
requiring
periodic
review
of
the
compliance
demonstration
and
certification
that
the
affected
source
still
qualifies
for
the
alternatives
every
five
years
to
ensure
continuing
compliance.
Additionally,
before
changing
key
parameters
that
may
impact
an
affected
source's
ability
to
continue
to
meet
one
or
both
of
the
health­
based
compliance
alternatives,
the
affected
source
is
required
to
evaluate
its
ability
to
continue
to
comply
with
the
health­
based
compliance
alternative(
s)
and
submit
documentation
to
the
permitting
authority
supporting
continued
eligibility
for
the
compliance
alternative.
Finally,
in
accordance
with
the
provisions
of
title
V
of
the
Clean
Air
Act
and
part
70
of
40
CFR
(
collectively
"
title
V"),
the
owner
or
operator
of
any
affected
source
opting
to
comply
with
the
health­
based
compliance
alternatives
will
be
required
to
certify
compliance
with
those
standards
on
an
annual
basis.
We
believe
that
the
promulgation
of
specific
health­
based
compliance
alternatives
and
a
uniform
methodology
for
demonstrating
compliance
with
those
alternatives
alleviates
any
concern
regarding
the
public
process
required
in
reviewing/
approving
the
proposed
approaches
and
making
substantial
changes
to
existing
regulations.
It
also
addresses
concerns
regarding
the
costs
and
resources
associated
with
assuring
adequate
public
participation
in
the
process
of
reviewing
site­
specific
risk
analyses.
To
ensure
that
affected
sources
which
choose
to
comply
with
the
health­
based
compliance
alternatives
continue
to
comply
with
those
options
after
the
initial
compliance
demonstration,
specified
assessment
parameters
(
e.
g.,
HCl­
equivalent
and/
or
manganese
emission
rate,
boiler
heat
output,
etc.)
must
be
included
in
their
title
V
permit
as
enforceable
requirements.
Draft
permits
and
permit
applications
must
be
made
available
from
the
State
or
local
agency
responsible
for
issuing
the
permit,
or
in
the
case
where
EPA
is
issuing
the
permit,
from
the
EPA
regional
office.
Members
of
the
public
may
request
that
the
state
or
local
agency
include
them
on
their
public
notice
mailing
list,
thus
providing
the
public
the
opportunity
to
review
the
appropriateness
of
these
requirements.
Every
proposed
title
V
permit
has
a
30­
day
public
comment
period
and
a
45­
day
EPA
review
period.
If
EPA
does
not
object
to
the
permit,
any
member
of
the
public
may
petition
EPA
to
object
to
the
permit
within
60
days
of
the
end
of
the
EPA
review
period.

Comment:
Commenter
IV­
D­
14
stated
that
if
EPA
intends
to
have
the
affected
industries
conduct
the
analysis,
then
EPA
must
consider
the
additional
cost
incurred
by
smaller
sources
to
do
the
analysis.
Commenter
IV­
D­
24
pointed
out
that
since
delisting
based
on
risk
will
require
collection
and
submission
of
data
and
air
quality
modeling,
small
sources,
which
are
likely
to
have
small
risk,
will
probably
not
be
able
to
afford
the
cost
of
requesting
delisting
unless
EPA
establishes
automatic
subcategory
delisting
criteria.
Response:
As
mentioned
previously,
there
are
two
ways
that
an
affected
source
in
the
263
large
solid
fuel­
fired
boilers
and
process
heaters
subcategory
may
demonstrate
eligibility
for
the
health­
based
compliance
alternatives
of
the
final
rule:
(
1)
look­
up
tables,
and
(
2)
a
site­
specific
modeling
approach.
The
look­
up
tables
include
Table
2
of
Appendix
A
to
the
final
rule
to
determine
if
an
affected
source
is
eligible
for
the
alternative
compliance
option
for
the
HCl
emission
limit
and
Table
3
of
Appendix
A
to
determine
if
an
affected
source
is
eligible
for
excluding
Mn
from
the
TSM
emission
limit.
The
look­
up
tables
allow
an
affected
source
to
determine,
using
a
limited
number
of
site­
specific
input
parameters
(
i.
e.,
stack
parameters,
distance
to
fence
line,
and
emission
rates),
whether
they
are
eligible
for
one
of
the
health­
based
compliance
alternatives.
Attempting
to
demonstrate
eligibility
for
one
of
the
health­
based
compliance
alternatives
is
completely
voluntary.
An
affected
source
that
is
not
eligible
for
one
of
the
health­
based
compliance
alternatives
based
on
look­
up
tables
is
not
required
to
pursue
a
modeling
approach
(
which
can
be
increasingly
complex
and
expensive
as
it
becomes
more
refined).
Each
affected
source
must
weigh
the
costs
of
making
an
eligibility
demonstration
with
the
costs
of
MACT
compliance.
We
believe
that,
in
general,
the
costs
associated
with
demonstrating
eligibility
for
the
health­
based
compliance
alternatives
will
be
lower
than
the
costs
associated
with
complying
with
MACT
for
many
affected
sources,
including
smaller
facilities
and
other
facilities
that
have
not
already
otherwise
installed
pollution
controls.
Successfully
demonstrating
eligibility
for
the
health­
based
compliance
alternative(
s)
will
result
in
cost­
savings
for
smaller
affected
sources
because
these
facilities
will
not
have
to
expend
the
costs,
i.
e.,
the
costs
of
installing
or
upgrading,
operating,
and
maintaining
the
add­
on
emission
controls
needed
to
comply
with
the
MACT
emission
limits
.
The
cost
and
economic
analyses
developed
as
part
of
the
MACT
rulemaking
were
based
on
the
costs
to
install,
maintain,
and
operate
controls
and
to
comply
with
the
MACT
requirements.
The
costs
associated
with
voluntarily
conducting
risk
analyses
were
not
estimated.
Therefore,
our
estimates
of
costs
associated
with
the
final
rule
are
conservative,
because
the
control
costs
that
would
be
incurred
to
comply
with
the
HCl
emission
limit
are
significantly
higher
than
the
costs
of
conducting
the
risk
analyses
that
in
some
cases
would
be
required
to
qualify
for
the
health­
based
compliance
alternative
for
the
HCl
emission
limit.
Similarly,
the
control
costs
of
complying
with
the
MACT
PM
or
TSM
emission
limits
are
higher
than
the
costs
of
conducting
the
risk
analyses
that
for
some
affected
facilities
would
be
required
to
demonstrate
eligibility
to
comply
with
the
health­
based
alternative
excluding
Mn
from
the
TSM
emission
limit.

18.10
PROGRAM
ISSUES:
TITLE
V
AS
IMPLEMENTATION
MECHANISM
Comment:
Commenter
IV­
D­
148
stated
that
risk­
based
exemptions
are
such
an
implausible
interpretation
of
the
CAA
that
states
do
not
even
have
the
authority
to
grant
them
under
their
title
V
permit
programs.
Therefore,
the
commenter
is
not
aware
of
any
approach
to
ensure
that
emissions
remain
below
specified
levels.
MACT
standard
applicability
is
the
gatekeeper
for
being
subject
to
a
title
V
operating
permit.
Once
a
source
is
exempt
from
a
MACT
standard,
it
would
be
exempt
from
the
monitoring,
reporting
and
recordkeeping
requirements
needed
to
demonstrate
compliance.
Similarly,
commenter
IV­
D­
135
noted
that
EPA
requested
comment
on
how
to
implement
applicability
cutoffs
without
specifying
what
methods
are
being
considered.
For
example,
EPA
did
not
discuss
or
consider
the
fact
that
States
currently
do
not
have
authority
to
provide
for
riskbased
exemptions
for
sources
subject
to
MACT
standards
through
the
title
V
permit
program.
264
Commenter
IV­
D­
96
stated
that
implementing
the
§
112(
d)(
4)
exemption
interpretation
through
title
V
would
be
unlawful
and
unworkable.
Congress
knew
how
to
authorize
States
to
establish
case­
by­
case
emission
standards
using
a
post­
rulemaking
title
V
permit
as
an
implementing
mechanism
because
it
did
so
in
112(
j).
Congress
did
not
do
so
in
[
section]
112(
d)(
4),
and
EPA
lacks
authority
to
delegate
[
section]
112(
d)(
4)
powers
to
States.
EPA
may
not
implement
any
112(
d)(
4)
applicability
cutoff
through
any
post­
rulemaking
mechanism
such
as
a
title
V
permit.
With
the
exception
of
carefully
delineated
compliance
monitoring,
reporting,
and
certification
provisions
in
the
statute,
title
V
permits
may
not
create
applicable
requirements
or
exemptions
from
applicable
requirements.
Even
if
this
approach
was
legal,
passing
familiarity
with
the
title
V
program,
the
resource
challenges
faced
by
States,
and
the
widespread
delays
in
issuing
title
V
permits
makes
it
clear
that
this
approach
is
unworkable.
Commenter
IV­
D­
96
noted
that
State
permit
engineers
and
officials
that
prepare
and
issue
title
V
permits
generally
are
not
experts
in
risk
assessment
or
air
dispersion
modeling.
States
and
the
public
would
be
confronted
with
more
self­
serving
facility
arguments
and
data
than
could
be
adequately
scrutinized,
which
could
cause
important
health
and
risk
determinations
to
be
rubber
stamped,
or
cause
the
permit
process
to
grind
to
a
halt.
Most
State
title
V
permit
programs
are
already
behind
the
statute's
permit
issuance
deadlines,
and
implementation
of
EPA's
risk­
based
approach
would
exacerbate
this
unlawful
situation
further.
Several
commenters
supported
implementing
the
risk­
based
approaches
in
the
Industrial/
Commercial/
Institutional
Boilers
and
Process
Heaters
rule
through
the
States'
existing
title
V
programs.
Commenter
IV­
D­
75
suggested
that
States
which
qualify
and
choose
to
do
so
should
be
delegated
the
authority
to
implement
risk­
based
alternatives.
The
commenter
added
this
would
allow
States
to
coordinate
between
the
MACT
alternatives
and
State
air
toxics
requirements.
Commenter
IV­
D­
123
stated
that
implementation
of
the
§
112(
d)(
4)
risk­
based
approach
through
title
V
would
be
lawful
and
workable.
According
to
the
commenter,
no
facility­
specific
post­
rulemaking
mechanisms,
nor
expansion
of
the
scope
of
title
V
permit
process,
would
be
necessary,
just
the
incorporation
of
the
NESHAP's
risk­
based
compliance
option,
which
would
contain
the
criteria
for
showing
what
the
source
would
have
to
meet
to
qualify
for
the
risk­
based
approach.
The
commenter
believed
that
the
objections
from
other
commenters
to
the
risk­
based
criteria
were
invalid,
arguing
that
their
objections
were
in
tension
with
the
conclusions
of
a
CAAAC
Workgroup
on
State/
Local/
Tribal
air
toxics
issues
and
that
their
comments
provided
no
basis
for
concluding
that
States
lack
the
legal
authority
to
implement
risk­
based
approach.
Commenter
IV­
D­
05
stated
that
title
V
permits
seem
to
be
the
obvious
implementation
tool,
and
that
title
V
permits
could
provide
enforceable
limitations,
appropriate
recordkeeping
requirements,
and
periodic
review
upon
renewal.
The
commenter
added
that
since
the
rule
would
apply
only
to
major
sources,
title
V
permits
already
are
required
and
would
not
be
an
added
burden;
title
V
could
also
be
used
to
implement
applicability
cutoffs,
but
that
the
workload
involved
with
the
options
requiring
modeling,
ambient
monitoring,
or
other
means
to
establish
background
concentrations
would
be
a
hindrance
to
any
implementation
mechanism.
In
addition,
the
commenter
stated
that
with
respect
to
potential
risk­
based
provisions,
monitoring
is
more
useful
for
demonstrating
non­
compliance
than
compliance
because
the
regulation
would
apply
to
potential
emissions
under
any
weather
conditions,
whereas
monitoring
reflects
current
weather
and
emission
conditions.
Response:
With
regard
to
title
V
permits
creating
applicable
requirements
or
exemptions
from
applicable
requirements,
the
requirements
for
qualifying
for
the
health­
based
compliance
265
alternatives
are
clearly
spelled
out
in
Appendix
A
to
Subpart
DDDDD,
and
any
standards
or
requirements
created
under
§
112
are
considered
applicable
requirements
under
part
70.
Unless
an
affected
source
meets
these
conditions,
it
will
remain
subject
to
the
HCl
and
Mn
regulatory
requirements
in
the
final
rule.
Therefore,
the
parameters
used
to
demonstrate
eligibility
for
the
health­
based
compliance
alternatives
would
be
incorporated
into
title
V
permits
as
federally
enforceable
permit
terms
and
States
would
not
have
to
overhaul
existing
permitting
programs.
We
note
that
our
rules
implementing
title
V
of
the
CAA
specifically
provide
for
situations
such
as
this.
For
example,
in
its
provisions
governing
what
types
of
permit
revisions
may
proceed
through
the
abbreviated
"
minor
permit
modification"
process,
our
rules
state
that
such
procedures
may
not
be
used
"
to
establish
or
change
a
permit
term
or
condition
for
which
there
is
no
corresponding
underlying
applicable
requirement
and
that
the
source
has
assumed
to
avoid
an
applicable
requirement
to
which
the
source
would
otherwise
be
subject."
40
C.
F.
R.
70.7(
e)(
2)(
i)(
A)(
4);
71.7(
e)(
1)(
i)(
A)(
4).
We
believe
that
permit
terms
reflecting
an
affected
source's
eligibility
clearly
represent
such
terms,
and
are
therefore
allowed
under
title
V.
Also,
such
terms
would
be
required
to
be
added
or
revised
through
the
more
formal
"
significant
modification"
procedures
of
40
C.
F.
R.
70.7(
e)(
4)
and
71.7(
e)(
3).
Affected
sources
will
initially
demonstrate
that
they
qualify
for
a
health­
based
compliance
alternative
using
either
the
look­
up
tables
provided
in
Appendix
A
to
the
final
rule
or
site­
specific
modeling
following
the
methodology
and
criteria
in
Appendix
A
to
the
final
rule.
They
will
keep
records
of
the
information
used
in
developing
the
eligibility
demonstration.
Affected
sources
will
not
be
required
to
perform
detailed
risk
analyses
for
public
review,
although
the
public
will
have
an
opportunity
to
comment
on
draft
permit
terms
and
conditions
that
reflect
eligibility
demonstrations,
and
to
judicially
challenge
final
EPA
approvals
of
eligibility
demonstrations
under
CAA
§
307(
b)(
1).
We
acknowledge
the
resource
challenges
faced
by
States,
however,
we
believe
that
most
affected
sources
qualifying
for
the
low­
risk
provisions
will
be
able
to
do
so
through
use
of
the
look­
up
tables.
The
only
facility
data
needed
to
use
the
look­
up
tables
are
stack
parameters,
HClequivalent
or
Mn
emission
rates,
and
fence
line
distances.
Other
than
the
HCl­
equivalent
emission
rates,
these
data
are
routinely
included
in
title
V
permit
applications
and
none
of
the
data
should
require
review
by
experts
in
risk
assessment
or
air
dispersion
modeling.
For
affected
sources
that
do
site­
specific
modeling,
all
of
the
procedures
for
performing
such
modeling
are
available
in
peer­
reviewed
scientific
literature.
As
far
as
the
title
V
permit
programs
being
behind
the
statute's
permit
issuance
deadlines,
the
incorporation
of
the
NESHAP
requirements
is
a
necessary
step
that
will
require
some
resources,
and
inclusion
of
the
health­
based
compliance
alternatives
should
be
a
straightforward
part
of
the
process
and
should
not
cause
significant
delay.

18.11
PROGRAM
ISSUES:
EFFECTS
ON
OTHER
SOURCE
CATEGORIES
Comment:
Commenter
IV­
D­
175
noted
that
in
the
MACT
Proposal,
EPA
proposes
three
separate
approaches
to
focus
on
sources
that
pose
the
greatest
adverse
health
and
environmental
impacts:
(
1)
an
applicability
cutoff
for
threshold
pollutants;
(
2)
subcategorization
and
delisting;
and
(
3)
the
use
of
a
concentration­
based
applicability
threshold.
The
commenter
believes
each
of
these
approaches
may
be
appropriate
in
different
contexts,
and
encourages
EPA
to
continue
to
consider
these
approaches
in
forthcoming
MACT
promulgations.
Response:
The
inclusion
of
health­
based
compliance
alternatives
in
the
final
rule
affects
266
only
the
boiler
and
process
heater
source
category
and
not
other
source
categories.

Comment:
Commenter
IV­
D­
72
stated
that
delisting
low
risk
subcategories
is
consistent
with
the
CAA
and
good
public
policy.
The
commenter
pointed
out
that
the
Taconite
Iron
Ore
Processing
source
category
presents
an
ideal
scenario
for
technologically­
defined
low
risk
subcategory
delisting.
For
example,
it
would
be
appropriate
to
divide
the
source
category
into
two
source
categories:
one
for
the
thermal
operations
and
one
for
the
material
handling
operations.
Based
on
preliminary
evaluations,
emissions
from
the
material
handling
operations
present
such
a
low
ambient
impact
that
they
easily
meet
criteria
set
forth
in
§
112(
c)(
9).
Commenter
IV­
D­
72
stated
for
purpose
of
the
Taconite
Iron
Ore
Processing
source
categories,
maintaining
the
MACT
floors
as
established
(
with
some
minor
corrections)
would
be
appropriate.
Response:
The
inclusion
of
health­
based
compliance
alternatives
in
the
final
rule
affects
only
the
boiler
and
process
heater
source
category
and
not
other
source
categories.

18.12
OTHER
ISSUES
18.12.1
Commenters
referencing
other
commenters
Comment:
Commenter
IV­
D­
148
endorsed
the
comments
submitted
by
STAPPA/
ALAPCO.
Response:
We
acknowledge
the
commenter's
support
of
the
comments
submitted
by
the
STAPPA/
ALAPCO.
Our
responses
to
the
specific
comments
submitted
by
the
STAPPA/
ALAPCO
are
provided
elsewhere
in
this
document.

Comment:
Commenters
IV­
D­
166
and
IV­
D­
179
supported
the
comments
provided
by
the
American
Chemistry
Council
(
IV­
D­
73)
and
the
CIBO
(
IV­
D­
119).
Commenter
IV­
D­
107
submitted
comments
identical
to
those
of
CIBO
(
IV­
D­
119).
Response:
We
acknowledge
the
commenters'
support
of
the
comments
submitted
by
the
American
Chemistry
Council
and
CIBO.
Our
responses
to
the
specific
comments
submitted
by
the
American
Chemistry
Council
and
CIBO
are
provided
elsewhere
in
this
document.

Comment:
Commenter
IV­
D­
45
strongly
endorsed
comments
submitted
by
the
AF&
PA
(
IV­
D­
123).
Response:
We
acknowledge
the
commenter's
support
of
the
comments
submitted
by
AF&
PA.
Our
responses
to
the
specific
comments
submitted
by
AF&
PA
are
provided
elsewhere
in
this
document.

Comment:
Commenter
IV­
D­
101
incorporated
the
comments
of
the
Rubber
Manufacturers
Association
(
IV­
D­
146)
by
reference.
Response:
We
acknowledge
the
commenter's
support
of
the
comments
submitted
by
the
Rubber
Manufacturers
Association.
Our
responses
to
the
specific
comments
submitted
by
the
Rubber
Manufacturers
Association
are
provided
elsewhere
in
this
document.

18.12.2
Attachments
to
certain
comments
Comment:
Commenter
IV­
D­
123
attached
(
see
Attachment
B
of
IV­
D­
123)
for
267
consideration
their
"
Response
to
Specific
Objections
to
the
Risk­
Based
Approaches
Raised
Previously
in
the
Context
of
EPA's
Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Brick
and
Structural
Clay
Products
Manufacturing
and
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Clay
Ceramics
Manufacturing."
Commenter
IV­
D­
122
cited
AF&
PA's
responses
to
objections
raised
by
NESCAUM,
NRDC,
and
Earthjustice.
Response:
The
comments
included
in
the
attachment
to
comment
IV­
D­
23
have
been
summarized
elsewhere
in
this
document,
and
our
responses
to
these
comments
are
provided
elsewhere.
We
acknowledge
the
support
of
commenter
IV­
D­
122
for
the
comments
submitted
by
AF&
PA.
We
acknowledge
comments
regarding
comments
submitted
by
others.
However,
we
have
responded
to
those
specific
comments
submitted
by
others
rather
than
agreeing
or
disagreeing
with
one
commenter's
assessment
of
another's
comments.

Comment:
Commenter
IV­
D­
148
included
multiple
attachments,
including
the
following:
Attachment
1­­
Congressional
Record,
E2383,
November
11,
1999
Attachment
2­­
EPA
Science
Policy
Council,
Policy
on
Evaluating
Health
Risks
to
Children
Attachment
3­­
EPA
Science
Policy
Council,
Memorandum
on
EPA
Risk
Characterization
Program,
March
21,
1995
Attachment
4­­
EPA
Science
Policy
Council,
Elements
to
Consider
When
Drafting
EPA
Risk
Characterizations,
March
1995
Attachment
5­­
EPA
Science
Policy
Council,
Policy
for
Risk
Characterization,
February
1995
Attachment
6­­
EPA
Science
Policy
Council,
Policy
for
Risk
Characterization,
March
1995
Attachment
7­­
EPA
Science
Policy
Council,
Memorandum
on
New
EPA
Policy
on
Evaluating
Health
Risks
to
Children,
October
20,
1995
Attachment
8
 
Fact
Sheet,
Report
to
Congress
on
Residual
Risk
Attachment
9
 
Statement
of
John
D.
Graham,
Ph.
D.,
Director,
Center
for
Risk
Analysis,
Harvard
School
of
Public
Health,
October
14,
1999
Attachment
10
 
Statement
of
Lee
P.
Hughes,
Vice
President,
Corporate
Environmental
Control,
Bayer
Corporation,
on
behalf
of
the
American
Chemistry
Council,
before
the
Senate
Environment
and
Public
Works
Committee
on
Clean
Air
Act
Residual
Risk,
October
3,
2000.
Response:
We
acknowledge
submittal
of
the
attachments
referenced
by
commenter
IV­
D­
148.

18.12.3
Miscellaneous
Comment:
Commenter
IV­
D­
96
noted
that
a
September
30,
2002
email
from
Amy
Vasu,
EPA,
to
Jim
Eddinger
and
Sims
Roy,
EPA,
mentions
20
e­
mails
to
Bryon
Allen,
OMB,
and
2
e­
mails
to
Alex
Cristofaro,
EPA,
from
Ms.
Vasu.
EPA
Docket
A­
96­
47
(
boilers
docket),
Document
II­
F­
24.
The
commenter
believes
the
docket
is
incomplete
because
they
were
unable
to
identify
that
number
of
e­
mails
from
Ms.
Vasu
to
Mr.
Allen
in
the
referenced
dockets
and
because
they
were
unable
to
locate
any
e­
mails
between
OMB
and
Mr.
Christofaro
in
the
docket
for
A­
96­
47.
The
commenter
urged
EPA
to
ensure
that
all
required
documents
are
included
in
the
administrative
dockets
for
all
of
the
relevant
proposals.
The
public's
right
to
comment
has
already
been
jeopardized
by
the
failure
to
include
all
relevant
and
required
documents
in
these
dockets.
Response:
We
disagree
that
the
public's
right
to
comment
has
been
compromised.
We
268
requested
public
comments
on
the
proposed
Boiler
NESHAP,
and
not
on
correspondence
between
EPA
and
OMB
that
occurred
prior
to
proposal
of
the
NESHAP.
In
terms
of
Document
No.
II­
F­
24
of
the
docket
for
the
Industrial
Boiler
NESHAP,
it
contains
all
the
relevant
(
to
the
Industrial
Boiler
MACT
rulemaking)
e­
mails.
The
cover
e­
mail
was
referring
to
the
entire
OMB
correspondence
for
both
Boiler
and
RICE
rulemakings.
The
emails
relevant
to
the
RICE
rulemaking
were
not
included
in
the
item
entered
into
the
Industrial
Boiler
docket.

Comment:
Commenter
IV­
D­
148
expressed
concern
with
the
April
30,
2002
memorandum,
"
Method
for
Approximate
("
Top­
Down")
Estimate
of
Aggregate
Cancer
Risk
Associated
With
Two
Maximum
Achievable
Control
Technology
(
MACT)
Source
Categories:
RICE
and
Industrial/
Commercial/
Institutional
Boilers."
The
commenter
stated
that
the
analysis
had
no
scientific,
technical,
or
policy
basis
and
apparently
had
not
been
peer
reviewed.
The
commenter
objected
to
the
document
and
suggests
that
EPA
remove
it
from
the
docket,
and
delete
all
references
to
it.
Response:
The
document
that
the
commenter
refers
to
was
used
in
the
development
of
the
proposal
for
the
Boilers
MACT,
and
therefore,
it
remains
in
the
project
docket.
The
document
explains
the
approach
we
used
prior
to
proposal
to
estimate
cancer
risk
associated
with
the
boiler
and
process
heater
source
category.
Peer
review
is
not
required
for
documentation
placed
in
NESHAP
dockets,
as
the
public
has
an
opportunity
to
comment
on
the
proposed
rulemaking
and
the
supporting
information
and
analyses,
just
as
the
commenter
has
done.
We
acknowledge
the
commenter's
objection
to
the
document.

Comment:
Commenter
IV­
D­
113
argued
that
EPA
must
regulate
all
units
that
combust
any
solid
waste
under
§
129
rather
than
§
112.
Because
§
129
does
not
permit
EPA
to
establish
risk­
based
exemptions,
it
would
be
unlawful
for
EPA
to
do
so
for
boilers
and
process
heaters
that
combust
any
solid
waste.
Response:
The
health­
based
compliance
alternatives
apply
to
large
solid­
fuel
fired
boilers
and
process
heaters
regulated
under
the
final
rule
developed
pursuant
to
§
112
(
and
not
§
129).
The
health­
based
compliance
alternatives
do
not
apply
for
solid
waste
combustors
regulated
under
§
129.

Comment:
Commenter
IV­
D­
118
stated
that
the
proposed
risk­
based
approach
would
not
be
necessary
if
EPA
were
to
include
a
minimum
boiler/
process
heater
size
cutoff.
This
size
cutoff
could
be
established
using
standard
EPA
refined
air
pollution
modeling
procedures
in
conjunction
with
the
most
stringent
federal
or
State
ambient
air
limits
for
HAP
to
model
the
air
impacts
associated
with
uncontrolled
HAP
emissions
from
the
"
model"
boiler/
process
heater.
A
similar
process
was
used
by
the
Industrial
Combustion
Coordinated
Rulemaking
Federal
Advisory
Committee
Act
(
ICCR
FACA)
process
when
selecting
the
HAP
of
interest
for
boilers/
process
heaters.
The
size­
based
applicability
limits
should
be
adequate
for
addressing
both
the
size
of
the
HAP
source
and
the
cost­
effectiveness
of
the
requirements.
Response:
As
discussed
elsewhere
in
this
document,
we
are
not
including
a
lower
size
cutoff.

Comment:
Commenter
IV­
D­
135
was
furthermore
concerned
that
EPA's
HCl
concept,
if
finalized,
would
allow
sources
whose
HCl
emissions
would
be
excluded
from
the
§
112(
d)
standards,
to
claim
to
be
area
sources.
The
commmenter
observed
that
HCl
is
probably
the
269
1.
U.
S.
Environmental
Protection
Agency.
1994.
Methods
for
Derivation
of
Inhalation
Reference
Concentrations
and
Application
of
Inhalation
Dosimetry.
Office
of
Research
and
Development.
EPA/
600/
8­
90/
066F.

2.
U.
S.
Environmental
Protection
Agency.
1999.
Residual
Risk
Report
to
Congress.
Office
of
Air
Quality
Planning
and
Standards,
Research
Triangle
Park,
NC
27711.
March
1999.
EPA­
453/
R­
99­
001;
available
at
http://
www.
epa.
aov/
ttn/
oarpa/
t3/
meta/
m8690.
html.

3.
U.
S.
Environmental
Protection
Agency.
2000.
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures.
Office
of
Research
and
Development.
EPA/
630/
R­
00/
002.

4.
U.
S.
Environmental
Protection
Agency.
1986.
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures.
Risk
Assessment
Forum,
Washington,
DC.
EPA/
630/
R­
98/
002;
available
at
http://
cfpub.
epa.
gov/
ncea/
raf/
recordisplay.
cfm?
deid=
20533.

5.
U.
S.
EPA.
1999.
Guidelines
for
Carcinogen
Risk
Assessment.
NCEA­
F­
0644.
Risk
Assessment
Forum,
Washington,
DC.
pollutant
emitted
in
quantities
greater
than
10
tons
and
would
result
initially
in
the
source
being
classified
a
major
source
under
§
112(
a)(
1).
A
subsequent
claim
by
a
facility
that
is
an
area
source
(
because
its
HCl
emissions
are
exempted)
would
exclude
the
facility
from
all
MACT
standard
requirements.
The
commenter
asserted
that
this
potential
outcome
is
clearly
contrary
to
the
intent
of
the
CAA.
Response:
Major
sources
of
HAP
are
those
stationary
sources
or
groups
of
stationary
sources
that
are
located
within
a
contiguous
area
under
common
control
that
emit
or
have
the
potential
to
emit,
considering
controls,
9.07
Mg/
yr
(
10
tpy10
tpy)
or
more
of
any
one
HAP
or
22.68
Mg/
yr
(
25
tpy)
or
more
of
any
combination
of
HAP.
Area
sources
are
those
stationary
sources
or
groups
of
stationary
sources
that
are
not
major
sources.
(
See
CAA
§
§
112(
a)(
1)
and
112(
a)(
2),
and
40
CFR
§
63.2).
Major/
area
source
determinations
are
based
on
the
total
HAP
emissions
from
the
facility,
regardless
of
the
emission
limits
that
the
source
is
required
to
meet.
This
is
true
regardless
of
whether
the
emission
limits
required
for
the
source
are
MACT
emission
limits
or
a
health­
based
alternative.
Thus,
just
because
a
source
may
meet
health­
based
compliance
alternative
for
HCl
does
not
mean
that
the
HCl
emissions
from
the
facility
will
not
be
considered
in
the
sources
major/
area
source
determination.
If
sources
emit
more
than
10
tpy
of
HCl,
then
they
would
be
considered
a
major
source,
regardless
of
whether
they
meet
the
healthbased
compliance
alternative
for
HCl
or
the
MACT
emission
limit
for
HCl.

References