80290
Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
51
and
52
[
FRL
 
7414
 
6;
Docket
A
 
2002
 
4]

RIN
2060
 
AK28
Prevention
of
Significant
Deterioration
(
PSD)
and
Non­
attainment
New
Source
Review
(
NSR):
Routine
Maintenance,
Repair
and
Replacement
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.

SUMMARY:
The
EPA
is
proposing
revisions
to
the
regulations
governing
the
NSR
programs
mandated
by
parts
C
and
D
of
title
I
of
the
Clean
Air
Act
(
CAA).
These
proposed
changes
reflect
the
EPA's
consideration
of
the
President's
National
Energy
Policy
(
NEP),
EPA's
Report
to
the
President
on
the
impact
of
NSR
pursuant
to
the
NEP,
and
EPA's
recommended
changes
to
NSR
based
on
the
Report
findings
and
discussions
with
various
stakeholders
including
representatives
from
industry,
State
and
local
governments,
and
environmental
groups.
The
proposed
changes
provide
a
future
category
of
activities
that
would
be
considered
to
be
routine
maintenance,
repair
and
replacement
(
RMRR)
under
the
NSR
program.
The
changes
are
intended
to
provide
greater
regulatory
certainty
without
sacrificing
the
current
level
of
environmental
protection
and
benefit
derived
from
the
program.
We
believe
that
these
changes
will
facilitate
the
safe,
efficient,
and
reliable
operation
of
affected
facilities.

DATES:
Comments.
Comments
must
be
received
on
or
before
March
3,
2003.
Public
Hearing.
If
anyone
contacts
us
requesting
to
speak
at
a
public
hearing
by
January
21,
2003,
we
will
hold
a
public
hearing
approximately
30
days
after
publication
in
the
Federal
Register.

ADDRESSES:
Comments.
Comments
may
be
submitted
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
Follow
the
detailed
instructions
as
provided
in
section
I.
C.
of
the
SUPPLEMENTARY
INFORMATION
section.
Public
Hearing.
The
public
hearing,
if
requested,
will
be
held
at
the
EPA's
facilities
at
109
TW
Alexander
Drive,
Research
Triangle
Park,
NC
27709
or
at
an
alternate
facility
nearby.
The
EPA
will
not
hold
a
hearing
if
one
is
not
requested.
Please
check
EPA's
web
page
at
http://
www.
epa.
gov/
ttn/
nsr/
whatsnew.
html
on
January
21,
2003
for
the
announcement
of
whether
the
hearing
will
be
held.

FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Dave
Svendsgaard,
Information
Transfer
and
Program
Integration
Division
(
C339
 
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711,
telephone
(
919)
541
 
2380,
or
electronic
mail
at
svendsgaard.
dave@
epa.
gov.

SUPPLEMENTARY
INFORMATION:

I.
General
Information
A.
What
Are
the
Regulated
Entities?

Entities
potentially
affected
by
this
proposed
action
include
sources
in
all
industry
groups.
The
majority
of
sources
potentially
affected
are
expected
to
be
in
the
following
groups.

Industry
group
SECa
NAICSb
Electric
Services
.....................................................
491
221111,
221112,
221113,
221119,
221121,
221122
Petroleum
Refining
.................................................
291
32411
Chemical
Processes
...............................................
281
325181,
32512,
325131,
325182,
211112,
325998,
331311,
325188
Natural
Gas
Transport
............................................
492
48621,
22121
Pulp
and
Paper
Mills
..............................................
261
32211,
322121,
322122,
32213
Paper
Mills
..............................................................
262
322121,
322122
Automobile
Manufacturing
......................................
371
336111,
336112,
336712,
336211,
336992,
336322,
336312,
33633,
33634,
33635,
336399,
336212,
336213
Pharmaceuticals
.....................................................
283
325411,
325412,
325413,
325414
a
Standard
Industrial
Classification
b
North
American
Industry
Classification
System.
Entities
potentially
affected
by
this
proposed
action
also
would
include
State,
local,
and
tribal
governments
that
are
delegated
authority
to
implement
these
regulations.

B.
How
Can
I
Get
Copies
of
This
Document
and
Other
Related
Information?

1.
Docket.
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
A
 
2002
 
04.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
EPA
Docket
Center,
(
Air
Docket),
U.
S.
Environmental
Protection
Agency,
1301
Constitution
Ave.,
NW.,
Room:
B108,
Mail
Code:
6102T,
Washington,
DC,
20004.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
 
1742.
A
reasonable
fee
may
be
charged
for
copying.
2.
Electronic
Access.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
``
Federal
Register''
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
appropriate
docket
identification
number.
Certain
types
of
information
will
not
be
placed
in
the
EPA
Dockets.
Information
claimed
as
CBI
and
other
information
whose
disclosure
is
restricted
by
statute,
which
is
not
included
in
the
official
public
docket,
will
not
be
available
for
public
viewing
in
EPA's
electronic
public
docket.
EPA's
policy
is
that
copyrighted
material
will
not
be
placed
in
EPA's
electronic
public
docket
but
will
be
available
only
in
printed,
paper
form
in
the
official
public
docket.
To
the
extent
feasible,
publicly
available
docket
materials
will
be
made
available
in
EPA's
electronic
public
docket.
When
a
document
is
selected
from
the
index
list
in
EPA
Dockets,
the
system
will
identify
whether
the
document
is
available
for
viewing
in
EPA's
electronic
public
docket.
Although
not
all
docket
materials
may
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Federal
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
in
section
I.
B.
1.
EPA
intends
to
work
towards
providing
electronic
access
to
all
of
the
publicly
available
docket
materials
through
EPA's
electronic
public
docket.
For
public
commenters,
it
is
important
to
note
that
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
EPA's
electronic
public
docket
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EPA's
electronic
public
docket.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Public
comments
submitted
on
computer
disks
that
are
mailed
or
delivered
to
the
docket
will
be
transferred
to
EPA's
electronic
public
docket.
Public
comments
that
are
mailed
or
delivered
to
the
Docket
will
be
scanned
and
placed
in
EPA's
electronic
public
docket.
Where
practical,
physical
objects
will
be
photographed,
and
the
photograph
will
be
placed
in
EPA's
electronic
public
docket
along
with
a
brief
description
written
by
the
docket
staff.
For
additional
information
about
EPA's
electronic
public
docket
visit
EPA
Dockets
online
or
see
67
FR
38102,
May
31,
2002.

C.
How
and
to
Whom
Do
I
Submit
Comments?
You
may
submit
comments
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
comment.
Please
ensure
that
your
comments
are
submitted
within
the
specified
comment
period.
Comments
received
after
the
close
of
the
comment
period
will
be
marked
``
late.''
EPA
is
not
required
to
consider
these
late
comments.
If
you
wish
to
submit
CBI
or
information
that
is
otherwise
protected
by
statute,
please
follow
the
instructions
in
section
I.
D.
Do
not
use
EPA
Dockets
or
e­
mail
to
submit
CBI
or
information
protected
by
statute.
1.
Electronically.
If
you
submit
an
electronic
comment
as
prescribed
below,
EPA
recommends
that
you
include
your
name,
mailing
address,
and
an
e­
mail
address
or
other
contact
information
in
the
body
of
your
comment.
Also
include
this
contact
information
on
the
outside
of
any
disk
or
CD
ROM
you
submit,
and
in
any
cover
letter
accompanying
the
disk
or
CD
ROM.
This
ensures
that
you
can
be
identified
as
the
submitter
of
the
comment
and
allows
EPA
to
contact
you
in
case
EPA
cannot
read
your
comment
due
to
technical
difficulties
or
needs
further
information
on
the
substance
of
your
comment.
EPA's
policy
is
that
EPA
will
not
edit
your
comment,
and
any
identifying
or
contact
information
provided
in
the
body
of
a
comment
will
be
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket,
and
made
available
in
EPA's
electronic
public
docket.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.
a.
EPA
Dockets.
Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket,
and
follow
the
online
instructions
for
submitting
comments.
To
access
EPA's
electronic
public
docket
from
the
EPA
Internet
Home
Page,
select
``
Information
Sources,''
``
Dockets,''
and
``
EPA
Dockets.''
Once
in
the
system,
select
``
search,''
and
then
key
in
Docket
ID
No.
A
 
2002
 
04.
The
system
is
an
``
anonymous
access''
system,
which
means
EPA
will
not
know
your
identity,
e­
mail
address,
or
other
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
b.
E­
mail.
Comments
may
be
sent
by
electronic
mail
(
e­
mail)
to
a­
and­
rdocket
epamail.
epa.
gov,
Attention
Docket
ID
No.
A
 
2002
 
04.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
email
system
is
not
an
``
anonymous
access''
system.
If
you
send
an
e­
mail
comment
directly
to
the
Docket
without
going
through
EPA's
electronic
public
docket,
EPA's
e­
mail
system
automatically
captures
your
e­
mail
address.
E­
mail
addresses
that
are
automatically
captured
by
EPA's
e­
mail
system
are
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket,
and
made
available
in
EPA's
electronic
public
docket.
c.
Disk
or
CD
ROM.
You
may
submit
comments
on
a
disk
or
CD
ROM
that
you
mail
to
the
mailing
address
identified
in
section
I.
C.
2.
These
electronic
submissions
will
be
accepted
in
WordPerfect
or
ASCII
file
format.
Avoid
the
use
of
special
characters
and
any
form
of
encryption.
2.
By
Mail.
Send
two
copies
of
your
comments
to:
U.
S.
Environmental
Protection
Agency,
EPA
West
(
Air
Docket),
1200
Pennsylvania
Ave.,
NW,
Room:
B108,
Mail
code:
6102T,
Washington,
DC,
20460,
Attention
Docket
ID
No.
A
 
2002
 
04.
3.
By
Hand
Delivery
or
Courier.
Deliver
your
comments
to:
EPA
Docket
Center,
(
Air
Docket),
U.
S.
Environmental
Protection
Agency,
1301
Constitution
Ave.,
NW.,
Room:
B108,
Mail
Code:
6102T,
Washington,
DC,
20004.,
Attention
Docket
ID
No.
A
 
2002
 
04.
Such
deliveries
are
only
accepted
during
the
Docket's
normal
hours
of
operation
as
identified
in
section
I.
B.
1.
4.
By
Facsimile.
Fax
your
comments
to
the
EPA
Docket
Center
at
(
202)
566
 
1741,
Attention
Docket
ID.
No.
A
 
2002
 
04.

D.
How
Should
I
Submit
CBI
to
the
Agency?

Do
not
submit
information
that
you
consider
to
be
CBI
electronically
through
EPA's
electronic
public
docket
or
by
e­
mail.
Send
or
deliver
information
identified
as
CBI
only
to
the
following
address:
Mr.
David
Svendsgaard,
c/
o
OAQPS
Document
Control
Officer
(
C339
 
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711,
Attention
Docket
ID
No.
A
 
2002
 
04.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
CBI.
(
If
you
submit
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
as
CBI
and
then
identify
electronically
within
the
disk
or
CD
ROM
the
specific
information
that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
Part
2.
In
addition
to
one
complete
version
of
the
comment
that
includes
any
information
claimed
as
CBI,
a
copy
of
the
comment
that
does
not
contain
the
information
claimed
as
CBI
must
be
submitted
for
inclusion
in
the
public
docket
and
EPA's
electronic
public
docket.
If
you
submit
the
copy
that
does
not
contain
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
clearly
that
it
does
not
contain
CBI.
Information
not
marked
as
CBI
will
be
included
in
the
public
docket
and
EPA's
electronic
public
docket
without
prior
notice.
If
you
have
any
questions
about
CBI
or
the
procedures
for
claiming
CBI,
please
consult
the
person
identified
in
the
FOR
FURTHER
INFORMATION
CONTACT
section.

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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
E.
What
Should
I
Consider
as
I
Prepare
my
Comments
for
EPA?

You
may
find
the
following
suggestions
helpful
for
preparing
your
comments.
 
Explain
your
views
as
clearly
as
possible.
 
Describe
any
assumptions
that
you
used.
 
Provide
any
technical
information
and/
or
data
you
used
that
support
your
views.
 
If
you
estimate
potential
burden
or
costs,
explain
how
you
arrived
at
your
estimate.
 
Provide
specific
examples
to
illustrate
your
concerns.
 
Offer
alternatives.
 
Make
sure
to
submit
your
comments
by
the
comment
period
deadline
identified.
 
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
response.
It
would
also
be
helpful
if
you
provided
the
name,
date,
and
Federal
Register
citation
related
to
your
comments.

F.
How
Can
I
Find
Information
About
a
Possible
Public
Hearing?

Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Pamela
J.
Smith,
Integrated
Implementation
Group,
Information
Transfer
and
Program
Integration
Division
(
C339
 
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711,
telephone
number
(
919)
541
 
0641,
at
least
2
days
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
should
also
contact
Ms.
Smith
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
these
proposed
emission
standards.

G.
Where
Can
I
Obtain
Additional
Information?

In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
this
proposed
rule
is
also
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature
by
the
EPA
Administrator,
a
copy
of
the
proposed
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
 
5384.
H.
How
is
This
Preamble
Organized?
The
information
presented
in
this
preamble
is
organized
as
follows:

I.
General
Information
A.
What
are
the
regulated
entities?
B.
How
can
I
get
copies
of
this
document
and
other
related
information?
C.
How
and
to
whom
do
I
submit
comments?
D.
How
should
I
submit
CBI
to
the
Agency?
E.
What
should
I
consider
as
I
prepare
my
comments
for
EPA?
F.
How
can
I
find
information
about
a
possible
public
hearing?
G.
Where
can
I
obtain
additional
information?
H.
How
is
this
preamble
organized?
II.
Purpose
III.
Background
A.
How
does
the
process
of
using
the
RMRR
exclusion
currently
work?
B.
Why
is
the
specification
of
categories
of
RMRR
activities
appropriate?
C.
Process
Used
to
Develop
This
Rule
IV.
Overview
of
Recommended
Approaches
for
RMRR
A.
Annual
Maintenance,
Repair
and
Replacement
Allowance
B.
Equipment
Replacement
Provision
V.
Legal
Basis
for
Recommended
Approaches
VI.
Discussion
of
Issues
Under
Annual
Maintenance,
Repair
and
Replacement
Allowance
Approach
A.
Appropriate
Time
Period
for
a
Maintenance,
Repair
and
Replacement
Allowance
B.
Cost
Basis
C.
Basis
for
Annual
Allowance
 
Stationary
Source
vs
Process
Unit
D.
Basis
for
Annual
Maintenance,
Repair
and
Replacement
Allowance
Percentage
E.
How
to
Calculate
Costs
F.
Applicability
Safeguards
G.
Timing
of
Determination
VII.
Discussion
of
Issues
under
the
Equipment
Replacement
Approach
A.
Replacement
of
Existing
Equipment
with
Identical
or
Functionally
Equivalent
Equipment
B.
Defining
``
Process
Unit''
for
Evaluating
Equipment
Replacement
Cost
Percentage
C.
Miscellaneous
Issues
D.
Quantitative
Analysis
VIII.
Other
Options
Considered
A.
Capacity­
Based
Option
B.
Age­
Based
Option
IX.
Administrative
Requirements
for
this
Proposed
Rulemaking
A.
Executive
Order
12866
 
Regulatory
Planning
and
Review
B.
Executive
Order
13132
 
Federalism
C.
Executive
Order
13175
 
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045
 
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Paperwork
Reduction
Act
F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
G.
Unfunded
Mandates
Reform
Act
of
1995
H.
National
Technology
Transfer
and
Advancement
Act
of
1995
I.
Executive
Order
13211
 
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
X.
Statutory
Authority
II.
Purpose
We
are
proposing
a
change
to
the
NSR
program
to
provide
specific
categories
of
activities
that
EPA
will
consider
RMRR
in
the
future.
We
are
seeking
comment
on
all
aspects
of
our
proposed
approaches
to
specifying
categories
of
RMRR
activities
under
the
NSR
program,
and
on
other
options
considered.
These
approaches
would
be
voluntary,
in
that
owners
or
operators
could
opt
to
continue
using
the
current
procedures
for
determining
what
activities
constitute
RMRR
at
their
facilities.
This
proposal
seeks
public
comments
in
accordance
with
section
307(
d)
of
the
CAA
and
should
not
be
used
or
cited
in
any
litigation
as
the
final
position
of
the
Agency.

III.
Background
A.
How
Does
the
Process
of
Using
the
RMRR
Exclusion
Currently
Work?

Under
the
changes
promulgated
today
to
40
CFR
parts
51
and
52,
``
major
modification''
is
defined
as
any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
would
result
in:
(
1)
A
significant
emissions
increase
of
a
regulated
NSR
pollutant;
and
(
2)
a
significant
net
emissions
increase
of
that
pollutant
from
the
major
stationary
source.
Owners/
operators
of
major
stationary
sources
are
required
to
obtain
a
major
NSR
permit
prior
to
beginning
actual
construction
of
a
modification
that
meets
this
definition.
The
regulations
exclude
certain
activities
from
the
definition
of
``
major
modification.''
One
such
exclusion
is
for
RMRR
activities.
The
regulations
do
not
define
this
term.
(
See
40
CFR
51.165(
a)(
1)(
v)(
C)(
1),
51.166(
b)(
2)(
iii)(
a),
52.21(
b)(
2)(
iii)(
a)
and
52.24(
f)(
5)(
iii)(
a).)
Under
our
current
approach,
the
RMRR
exclusion
is
applied
on
a
caseby
case
basis.
In
interpreting
this
exclusion,
we
have
followed
certain
criteria.
The
preamble
to
the
1992
``
WEPCO
Rule''
(
57
FR
32314)
and
applicability
determinations
made
to
date
describe
our
current
approach
to
assessing
what
activities
constitute
RMRR.
These
applicability
determinations
are
available
electronically
from
the
Region
7
NSR
Policy
and
Guidance
Database
(
http/://
www.
epa.
gov/
Region7/
programs/
artd/
air/
nsr/
nsrpg.
htm).
To
summarize
these
documents,
to
determine
whether
proposed
work
at
a
facility
is
routine,
EPA
makes
a
case­
by­

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/
Vol.
67,
No.
251
/
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December
31,
2002
/
Proposed
Rules
1
Reliable,
Affordable,
and
Environmentally
Sound
Energy
for
America's
Future,
Report
of
the
National
Energy
Policy
Development
Group,
May
17,
2001.
case
determination
by
weighing
the
nature,
extent,
purpose,
frequency,
and
the
cost
of
the
work
as
well
as
other
relevant
factors
to
arrive
at
a
common
sense
finding.
WEPCO
at
910.
None
of
these
factors,
in
and
of
itself,
is
conclusive.
Instead,
a
reviewing
authority
should
take
account
of
how
each
of
these
factors
might
apply
in
a
particular
circumstance
to
arrive
at
a
conclusion
considering
the
project
as
a
whole.
If
an
owner
or
operator
is
uncertain
whether
he
or
she
is
applying
the
NSR
regulations
correctly,
we
encourage
the
owner
or
operator
to
consult
the
appropriate
reviewing
authority
for
assistance.

B.
Why
Is
Specification
of
Categories
of
RMRR
Activities
Appropriate?
There
has
been
some
debate
over
the
years
as
to
the
case­
by­
case
approach
and
the
types
of
activities
that
qualify
as
RMRR
under
our
current
case­
by­
case
approach.
The
case­
specific
approach
works
well
in
many
respects.
For
example,
it
is
a
flexible
tool
that
accommodates
the
broad
range
of
industries
and
the
diversity
of
activities
that
are
potentially
subject
to
the
NSR
program.
However,
the
case­
by­
case
approach
has
certain
drawbacks.
Unless
an
owner
or
operator
seeks
an
applicability
determination
from
his
or
her
reviewing
authority
or
from
EPA,
it
can
be
difficult
for
the
owner
or
operator
to
know
with
certainty
whether
a
particular
activity
constitutes
RMRR.
Applicability
determinations
can
be
costly
and
time
consuming
for
reviewing
authorities
and
industry
alike.
If
a
source
proceeds
without
a
determination
and
is
later
proven
to
have
made
an
incorrect
determination,
that
source
faces
potentially
serious
enforcement
consequences.
Moreover,
under
the
current
case­
by­
case
approach,
State
and
local
reviewing
authorities
must
devote
scarce
resources
to
making
complex
determinations
and
consult
with
other
agencies
to
ensure
that
any
determinations
are
consistent
with
determinations
made
for
similar
circumstances
in
other
jurisdictions
and/
or
that
EPA
or
other
reviewing
authorities
would
concur
with
the
conclusion.
On
the
other
hand,
if
a
source
foregoes
or
defers
activities
that
are
important
to
maintaining
its
plant
when
the
activities
in
question
are
in
fact
within
scope
of
the
exclusion,
that
can
have
adverse
consequences
for
the
source's
reliability,
efficiency,
and
safety.
Finally,
the
source
may
install
less
efficient
or
less
modern
equipment
in
order
to
be
more
certain
that
it
is
within
the
regulatory
bounds,
or
it
may
agree
to
limit
its
hours
of
operation
or
capacity.
Any
of
these
approaches
will
make
the
source
less
productive
than
it
would
be
otherwise.
In
fact,
we
concluded
in
our
recent
report
to
the
President
on
the
impacts
of
NSR
on
the
energy
sector
that
there
have
been
cases
in
which
uncertainty
about
the
exclusion
for
RMRR
resulted
in
delay
or
cancellation
of
activities
that
would
have
maintained
and
improved
the
reliability,
efficiency,
and
safety
of
existing
energy
capacity.
Such
discouragement
results
in
lost
capacity
and
lost
opportunities
to
improve
energy
efficiency
and
reduce
air
pollution.
We
believe
that
these
problems
would
be
significantly
reduced
by
adding
to
our
current
RMRR
provision
specific
categories
of
activities
that
will
be
considered
to
be
RMRR
in
the
future.
Such
categories
would
remove
disincentives
to
undertaking
RMRR
activities
and
provide
more
certainty
both
to
source
owners
and
operators
who
could
better
plan
activities
at
their
facilities,
and
to
reviewing
authorities
who
could
better
focus
resources
on
activities
outside
these
RMRR
categories.
Accordingly,
the
establishment
of
categories
of
activities
as
RMRR
is
consistent
with
the
central
purpose
of
the
CAA,
``
to
protect
and
enhance
the
quality
of
the
Nation's
air
resources
so
as
to
promote
the
public
health
and
welfare
and
the
productive
capacity
of
its
population.''
CAA
section
101.
It
should
be
noted
that
there
may
be
some
activities
which,
while
fitting
within
the
ambit
of
the
RMRR
exclusion
could,
if
implemented,
violate
other
applicable
CAA
requirements.
As
has
always
been
the
case,
compliance
with
NSR
requirements
is
not
a
license
to
violate
any
of
the
other
applicable
CAA
requirements
such
as
title
V
permitting
requirements.

C.
Process
Used
To
Develop
This
Rule
In
the
1992
``
WEPCO
Rule''
preamble,
we
indicated
that
we
planned
to
issue
guidance
on
the
subject
of
RMRR.
In
1994,
as
part
of
our
meetings
with
the
Clean
Air
Act
Advisory
Committee,
we
developed,
for
discussion
purposes
only,
a
document
on
how
RMRR
could
be
defined.
We
received
a
substantial
volume
of
comments
on
this
document.
We
subsequently
decided
not
to
include
a
definition
of
RMRR
in
our
1996
NSR
proposed
rulemaking.
In
2001,
the
President's
NEP
Report
1
directed
EPA
in
consultation
with
the
Department
of
Energy
(
DOE)
and
other
federal
agencies
to
review
the
impact
of
NSR
on
investment
in
new
utility
and
refinery
generation
capacity,
energy
efficiency
and
environmental
protection.
The
release
of
the
report
in
May
2001
triggered
a
review
of
the
impacts
of
NSR
rules.
EPA's
Report
to
the
President
underscored
the
desirability
of
specifying
certain
categories
of
activities
that
qualify
as
RMRR.
In
parallel
with
this
review,
we
renewed
our
exploration
of
recommendations
for
improving
the
NSR
program.
Recommended
improvements
suggested
during
this
time
represented
a
continuation
of
discussions
on
NSR
issues
that
had
taken
place
during
the
1990'
s,
as
well
as
new
ideas.
The
process
of
discussing
possible
improvements
to
the
NSR
program
included
significant
interagency
consultation,
including
meetings
with
representatives
from
the
DOE,
the
Department
of
the
Interior,
and
the
Office
of
Management
and
Budget.
Building
on
what
we
heard,
we
held
conference
calls
with
various
stakeholders
during
October
2001
(
including
representatives
from
industry,
State
and
local
governments,
and
environmental
groups)
to
discuss
new
ideas
that
were
raised.
During
many
of
these
meetings,
we
discussed
ideas
for
how
to
define
RMRR
in
order
to
create
more
certainty
for
the
industry
and
reviewing
authorities.
Today's
proposed
rule
is
an
outgrowth
of
ideas
discussed
in
those
meetings.

IV.
Overview
of
Recommended
Approaches
for
RMRR
Ever
since
EPA's
promulgation
of
its
original
Prevention
of
Significant
Deterioration
(
PSD)
regulations
in
1980,
EPA
has
defined
``
modification''
in
its
NSR
regulations
to
include
commonsense
exclusions
from
the
``
physical
or
operational
change''
component
of
the
definition,
including
an
exclusion
for
RMRR.
Today,
we
are
proposing
two
categories
of
activities
that
will
in
the
future
be
considered
RMRR
activities:
activities
within
an
annual
maintenance,
repair
and
replacement
allowance
and
replacements
that
meet
our
equipment
replacement
provision
criteria.
Under
the
proposal,
when
an
activity
falls
within
either
of
these
categories,
it
would
be
considered
RMRR
and
a
source's
owners
or
operators
would
know
that
the
activity
was
excluded
from
NSR
without
regard
to
other
considerations.
When
an
activity
did
not
fall
within
one
of
these
categories,
then
it
still
could
qualify
as
routine
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Vol.
67,
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251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
2
A
fiscal
year
period
would
have
to
be
12
consecutive
months.
maintenance,
repair,
and
replacement
under
the
case­
by­
case
test.

A.
Annual
Maintenance,
Repair
and
Replacement
Allowance
First,
we
are
proposing
to
add
new
language
to
the
RMRR
exclusion
at
40
CFR
51.165
(
a)(
1)(
v)(
C)(
1),
40
CFR
51.166
(
b)(
2)(
iii)(
a),
40
CFR
part
51,
Appendix
S
(
A)(
5)(
iii)(
a),
40
CFR
52.21(
b)(
2)(
iii)(
a),
and
40
CFR
52.24
(
f)(
5)(
iii)(
a).
This
proposal
would
allow
certain
activities
engaged
in
to
promote
the
safe,
reliable
and
efficient
operation
of
a
facility­
that
is,
those
that
involve
relatively
small
capital
expenditures
compared
with
the
replacement
cost
of
the
facility
 
to
be
excluded
from
NSR
provided
that
total
costs
did
not
exceed
the
annual
maintenance,
repair
and
replacement
allowance.
The
annual
maintenance,
repair
and
replacement
allowance
and
the
rules
for
calculation
and
summation
of
activities
under
the
allowance
would
be
defined
in
new
provisions
at
40
CFR
51.165(
a)(
1)(
xxxxii),
40
CFR
51.166(
b)(
53),
40
CFR
52.21(
b)(
55),
and
40
CFR
52.24(
f)(
25).
Under
our
proposed
approach,
a
calendar
year
maintenance,
repair
and
replacement
allowance
would
be
established
for
each
stationary
source.
The
owner
or
operator
may
elect
to
use
a
fiscal
year
period
instead
of
a
calendar
year
if
financial
records
are
typically
kept
for
a
period
other
than
calendar
year
at
a
facility.
2
Although
the
proposal
contemplates
a
one­
year
allowance,
in
recognition
of
the
fact
that
maintenance
cycles
in
many
industries
extend
for
more
than
1
year,
we
also
seek
comment
on
whether
a
stationary
source
should
have
the
option
of
a
multi­
year
allowance,
such
as
over
5
years.
Under
our
1­
year
allowance
proposal,
an
owner
or
operator
would
sum
the
costs
of
the
relevant
activities
performed
at
the
stationary
source
during
the
fiscal
or
calendar
year
(
from
the
least
expensive
to
the
most
expensive)
to
get
a
yearly
cost.
For
activities
taking
more
than
1
year
to
complete,
costs
associated
with
those
activities
would
be
included
in
the
cost
calculations
for
the
year
that
the
costs
were
incurred
(
using
an
accounting
method
consistent
with
that
used
for
other
purposes
by
the
stationary
source).
If
the
total
costs
for
all
activities
undertaken
for
these
purposes
came
within
the
annual
maintenance,
repair
and
replacement
allowance,
these
activities
would
all
be
considered
RMRR
activities.
Other
than
documentation
of
the
results
of
this
assessment,
the
owner
or
operator
would
not
have
to
do
anything
further
with
respect
to
those
activities
for
purposes
of
major
NSR.
Where
total
yearly
costs
for
all
activities
undertaken
for
these
purposes
at
a
source
exceed
the
annual
maintenance,
repair
and
replacement
allowance,
the
activities
would
be
reviewed
as
follows.
 
The
owner
or
operator
would
subtract
activities
from
the
total
yearly
cost,
starting
with
the
most
expensive
activity,
until
the
remainder
is
less
than
or
equal
to
the
annual
maintenance,
repair
and
replacement
allowance.
 
The
owner
or
operator
would
evaluate
on
a
case­
by­
case
basis
in
accordance
with
EPA's
case­
by­
case
test
any
activities
that
did
not
come
within
the
allowance
and
that
are
not
otherwise
excluded,
in
order
to
determine
whether
they
are
RMRR.
If
uncertain
about
a
particular
activity
the
owner
or
operator
could
seek
an
applicability
determination.
 
If
an
owner
or
operator
concluded
that
any
such
activity
was
not
RMRR,
he
or
she
would
then
have
to
determine
whether
it
constitutes
a
``
major
modification''
that
requires
an
NSR
permit.
The
annual
maintenance,
repair
and
replacement
allowance
would
be
equal
to
the
product
of
the
replacement
cost
of
the
source
and
a
specified
maintenance,
repair
and
replacement
percentage.
(
See
§
§
51.165(
a)(
1)(
xxxxii),
51.166(
b)(
53),
52.21(
b)(
55)
and
52.24(
f)(
25)
of
proposed
rules.)
EPA
intends
to
set
this
percentage
on
an
industry­
specific
basis.
There
are
several
ways
in
which
the
percentage
could
be
established.
One
way
is
to
set
the
threshold
so
as
to
cover
the
RMRR
capital
and
non­
capital
costs
that
an
owner
or
operator
incurs
to
maintain,
facilitate,
restore,
or
improve
the
safety,
reliability,
availability,
or
efficiency
of
the
source.
We
are
also
requesting
comment
on
other
approaches.
For
example,
we
could
apply
a
discount
factor
to
the
typical
costs
in
order
to
account
for
variability
within
an
industry.
We
also
ask
for
comment
on
how
to
determine
typical
costs
for
particular
industries.
We
are
considering
using
the
Internal
Revenue
Service
``
Annual
Asset
Guideline
Repair
Allowance
Percentages''
(
AAGRAP),
which
we
use
for
an
exclusion
under
the
New
Source
Performance
Standard
(
NSPS)
program
for
increases
in
production.
We
also
could
rely
on
industry
specific
data
for
choosing
an
appropriate
threshold,
such
as
the
North
American
Electric
Reliability
Council
Generating
Availability
Data
System
(
NERC/
GADS)
database
or
standard
industry
reference
manuals.
The
replacement
cost
used
in
the
calculation
described
above
would
be
an
estimate
of
the
total
capital
investment
necessary
to
replace
the
stationary
source.
The
accounting
procedures
used
to
document
eligibility
under
this
rule
should
conform
to
the
accounting
procedures
used
for
other
purposes
at
a
facility.
Where
several
accounting
procedures
are
used
at
a
facility
(
e.
g.,
methods
for
tax
accounting
and
for
setting
rates
often
are
different),
the
most
appropriate
procedures
should
be
used
for
the
purpose
of
determining
costs
pursuant
to
this
regulation.
EPA
also
seeks
to
standardize
practices
for
estimating
this
investment,
along
the
lines
described
in
the
EPA
Air
Pollution
Control
Cost
Manual,
excluding
the
costs
for
installing
and
maintaining
pollution
control
equipment.
See
section
V.
E.
of
this
document
for
further
information
on
our
recommended
approach
to
calculating
costs.
The
control
cost
manual
is
available
electronically
via
the
internet
at
http://
www.
epa.
gov/
ttn/
catc/
dir1/
c_
allchs.
pdf.
We
acknowledge
that
this
manual
is
geared
toward
cost
calculations
for
add­
on
control
equipment
but
believe
the
basic
concepts
can
be
applied
to
process
equipment
as
well.
These
concepts
are
taken
from
work
done
by
the
American
Association
of
Cost
Engineers
to
define
the
components
of
cost
calculations
for
all
types
of
processes,
not
just
emission
control
equipment.
We
seek
comment
on
whether
this
manual
or
other
reference
documents
or
tools
provide
the
best
approach
for
standardizing
estimation
of
these
costs,
whether
different
methods
should
be
provided,
and
whether
provision
should
be
made
in
the
form
of
a
requirement
or
an
assurance
that
if
a
method
is
used,
we
will
accept
it.
Our
recommended
approach
will
contain
safeguards
to
help
ensure
that
activities
that
should
be
considered
a
physical
change
or
change
in
the
method
of
operation
under
the
regulations
are
ineligible
for
exclusion
from
NSR
under
the
annual
maintenance,
repair
and
replacement
allowance.
We
are
proposing
to
exclude
the
following
from
use
of
the
annual
allowance.
 
The
construction
of
a
new
``
process
unit,''
which
is
a
collection
of
structures
and/
or
equipment
that
uses
material
inputs
to
produce
or
store
a
completed
product.
See
discussion
below
at
section
VII
for
further
information
regarding
process
units.
 
The
replacement
of
an
entire
process
unit
 
Any
change
that
would
result
in
an
increase
in
the
source's
maximum
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/
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31,
2002
/
Proposed
Rules
3
Of
course,
as
noted
earlier,
the
traditional
caseby
case
approach
to
administering
the
RMRR
exclusion
will
continue
to
apply
to
activities
that
do
not
qualify
under
the
annual
maintenance,
repair
and
replacement
allowance
approach
described
above,
but
for
the
reasons
noted
earlier,
we
believe
that
approach
would
be
improved
on
by
the
identification
of
activities
that
may
be
found
to
Continued
achievable
hourly
emissions
rate
of
any
regulated
NSR
pollutant,
or
in
the
emission
of
any
regulated
NSR
pollutant
not
previously
emitted
by
the
stationary
source.
If
an
owner
or
operator
uses
the
annual
maintenance,
repair
and
replacement
allowance
to
determine
that
certain
activities
at
a
stationary
source
are
RMRR,
all
relevant
activities
performed
at
that
source
must
be
included
in
the
annual
cost
calculations
unless
the
owner
or
operator
elects
to
obtain
a
major
NSR
permit
for
the
activity.
In
other
words,
an
owner
or
operator
may
not
select
which
activities
to
review
case­
by­
case
and
which
to
include
in
the
cost
calculations
when
using
the
annual
maintenance,
repair
and
replacement
allowance
to
determine
RMRR
activities.
This
is
because,
assuming
the
threshold
is
set
to
approximate
the
total
amount
that
an
owner
or
operator
would
typically
be
expected
to
spend
on
RMRR
activities
(
or
a
discounted
portion
of
this
value
selected
to
account
for
variability
within
an
industry),
the
fact
that
a
given
activity's
cost
comes
within
the
allowance
can
only
reasonably
assure
that
it
is
RMRR
if
all
other
relevant
activities
also
are
included.
If
the
owner
or
operator
could
pick
and
choose
among
activities
that
he
or
she
wished
to
include
in
the
allowance,
such
an
approach
might
allow
the
owner
or
operator
to
include
large,
atypical
activities
that
do
not
constitute
RMRR
within
the
allowance,
while
applying
the
case­
by­
case
test
to
smaller
activities
that
quite
clearly
constitute
RMRR
under
that
test.
The
rule
that
all
relevant
activities
must
be
included
in
the
calculation
and
that
lowest
cost
activities
would
be
counted
first
should
provide
sufficient
protection
against
this
risk.
Owners
or
operators
electing
to
use
the
annual
maintenance,
repair
and
replacement
allowance
to
determine
RMRR
activities
will
be
required
to
submit
an
annual
report
to
the
appropriate
reviewing
authority
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
The
report
will
provide
a
summary
of
the
estimated
replacement
value
of
the
stationary
source,
the
annual
maintenance,
repair
and
replacement
allowance
for
the
stationary
source,
a
brief
description
of
all
maintenance,
repair
and
replacement
activities
undertaken
at
the
stationary
source,
and
the
costs
associated
with
those
activities.
If
the
costs
of
activities
in
question
exceed
the
annual
maintenance,
repair
and
replacement
allowance
for
a
stationary
source,
the
report
must
identify
the
activities
included
within
the
allowance
and
the
activities
that
fell
outside
the
allowance.
The
procedures
set
out
in
40
CFR
part
2
are
available
for
confidential
and
business­
sensitive
information
submitted
as
part
of
this
report.
The
following
provides
an
example
of
how
the
process
would
work.
Assume
the
source's
annual
maintenance,
repair
and
replacement
allowance
equals
$
2,000,000.
During
a
given
year,
the
owner
or
operator
spends
$
1,000,000
on
running
maintenance
activities,
and
implements
five
other
discrete
maintenance
activities
at
the
source
with
costs
as
follows
in
Table
1
(
none
of
these
activities
involves
the
construction
of
a
new
process
unit,
replacement
of
an
existing
process
unit,
or
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
a
regulated
NSR
pollutant
or
in
the
emission
of
any
regulated
NSR
pollutant
not
previously
emitted
by
the
stationary
source).

TABLE
1.
 
EXAMPLE
SUMMARY
OF
ACTIVITIES
COMMENCED
DURING
YEAR
Change
Month
Cost
Activity
1
.................................................................................
January
...................................................................................
$
200,000
Activity
2
.................................................................................
March
......................................................................................
600,000
Activity
3
.................................................................................
April
........................................................................................
360,000
Activity
4
.................................................................................
July
.........................................................................................
150,000
Activity
5
.................................................................................
November
...............................................................................
250,000
The
sum
of
costs
incurred
during
the
year
is
$
2,560,000,
$
560,000
above
the
annual
maintenance,
repair
and
replacement
allowance.
The
most
expensive
activity
commencing
during
the
year
was
the
$
600,000
activity
commencing
in
March.
The
source
must
evaluate
on
a
case­
by­
case
basis
whether
this
activity
is
RMRR.
When
the
cost
of
Activity
2
is
subtracted
from
the
total
annual
cost,
the
remainder
is
$
1,960,000,
less
than
the
annual
maintenance,
repair
and
replacement
allowance.
The
remaining
activities
(
Activities
1,
3,
4,
and
5)
are
considered
to
be
RMRR.
We
note
that
this
example
is
framed
as
if
the
owner
or
operator
would
make
these
calculations
for
the
first
time
at
the
end
of
the
year.
In
reality,
however,
an
owner
or
operator
who
is
considering
relying
on
the
maintenance,
repair
and
replacement
allowance
as
the
basis
for
his
or
her
conclusion
that
a
particular
activity
is
RMRR
is
likely
to
make
these
calculations
before
beginning
construction
on
any
activity.
This
is
because
the
owner
or
operator
would
know
that
he
or
she
will
only
be
able
to
rely
on
the
allowance
if
the
costs
of
the
activity
in
question,
when
added
with
the
costs
of
other
activities
to
assure
the
safe,
efficient,
and
reliable
operation
of
the
plant
that
the
owner
or
operator
is
planning
for
the
year,
will
in
fact
be
within
the
allowance.

B.
Equipment
Replacement
Provision
In
addition
to
our
proposed
annual
maintenance,
repair
and
replacement
allowance,
today
we
are
also
soliciting
comment
on
an
additional
approach
to
be
used
in
the
future
for
those
replacement
activities
that
should
qualify
without
regard
to
other
considerations
as
RMRR.
Specifically,
we
are
soliciting
comment
on
whether
replacing
existing
equipment
with
equipment
that
serves
the
same
function
and
that
does
not
alter
the
basic
design
parameters
of
a
unit
should
also
qualify
without
regard
for
other
considerations
for
RMRR
treatment
provided
the
cost
of
the
replacement
equipment
does
not
exceed
a
certain
percentage
of
the
cost
of
the
process
unit
to
which
the
equipment
belongs.
While
we
believe
the
annual
maintenance,
repair
and
replacement
provisions
described
above
will
significantly
improve
implementation
of
the
RMRR
exclusion,
we
recognize
that
the
allowance
may
apply
only
to
a
subset
of
the
activities
that
appropriately
fall
within
the
exclusion
and
that
are
susceptible
of
being
identified
as
categorically
constituting
RMRR.
3
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31DEP2.
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
constitute
RMRR
without
requiring
case­
by­
case
consideration
of
this
type.
Accordingly,
today
we
are
soliciting
comment
on
an
additional
approach
to
be
used
in
the
future
for
determining
that
certain
replacement
activities
whose
costs
fall
below
a
specified
threshold
qualify
as
RMRR
without
regard
for
other
considerations.
Under
this
approach,
EPA
would
establish
a
percentage
of
the
replacement
value
of
a
process
unit
as
a
threshold
for
applying
the
equipment
replacement
provision.
If
the
replacement
component
is
functionally
equivalent
to
the
replaced
component,
does
not
change
the
basic
design
parameters
of
the
process
unit,
and
does
not
exceed
the
cost
threshold,
it
would
constitute
RMRR.
This
approach
should
enable
the
owner
or
operator
to
streamline
the
RMRR
analysis
and
make
this
determination
more
readily
and
should
further
alleviate
some
of
the
problems
noted
above.
We
are
soliciting
comment
on
whether
this
approach
would
serve
to
streamline
the
RMRR
determination
process
for
activities
that
involve
the
replacement
of
existing
equipment
with
identical
new
equipment
and
the
replacement
of
existing
equipment
with
functionally
equivalent
equipment.
We
are
also
soliciting
comment
on
whether
this
approach
should
be
adopted
along
with
the
annual
maintenance,
repair
and
replacement
allowance
described
above,
or
whether
this
approach
is
preferred
over
the
other
such
that
we
should
only
offer
the
equipment
replacement
provision
in
the
final
rule.
We
also
solicit
comment
on
what
provisions
might
be
needed
to
clarify
and
facilitate
implementation
of
a
combined
approach.
For
example,
should
the
costs
of
activities
that
qualify
as
an
excluded
equipment
replacement
count
toward
the
annual
maintenance,
repair
and
replacement
allowance?
And,
if
so,
how
should
they
be
counted?
We
are
also
soliciting
comment
on
whether
any
other
category
of
activity
undertaken
for
these
purposes
should
be
excludable
by
the
owner
or
operator
from
the
annual
maintenance,
repair
and
replacement
allowance.
For
example,
activities
undertaken
to
address
unanticipated
forced
outages
or
catastrophic
events
such
as
fires
or
explosions
may
be
the
kind
of
unforeseeable
expenditure
that
an
owner
or
operator
should
not
have
to
include
because
it
is
not
possible
to
plan
for
it.
Also,
the
absence
of
an
exclusion
for
such
activities
might
be
a
disincentive
for
maintaining
and
ensuring
safe
operation.
If
excluded
from
the
maintenance,
repair
and
replacement
allowance,
these
activities
could
still
qualify
for
RMRR
status
under
the
equipment
replacement
provision
of
this
rule
if
they
meet
the
criteria
for
that
allowance
or
under
the
case­
by­
case
analysis.
Finally,
we
are
soliciting
comment
on
other
approaches
that
might
be
effective
in
streamlining
the
RMRR
determination
process.

V.
Legal
Basis
for
Recommended
Approaches
The
modification
provisions
of
the
NSR
program
in
parts
C
and
D
of
title
I
of
the
CAA
are
based
on
the
broad
definition
of
modification
in
section
111(
a)(
4)
of
the
CAA.
The
term
``
modification''
means
``
any
physical
change
in,
or
change
in
the
method
of
operation
of,
a
stationary
source
which
increases
the
amount
of
any
air
pollutant
emitted
by
such
source
or
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted.''
That
definition
contemplates
that
you
will
first
determine
whether
a
physical
or
operational
change
will
occur.
If
so,
then
you
proceed
to
determine
whether
the
physical
or
operational
change
will
result
in
an
emissions
increase
over
baseline
levels.
The
expression
``
any
physical
change
*
*
*
or
change
in
the
method
of
operation''
in
section
111(
a)(
4)
of
the
CAA
is
not
defined.
We
have
recognized
that
Congress
did
not
intend
to
make
every
activity
at
a
source
subject
to
the
major
NSR
program.
As
a
result,
we
have
previously
adopted
nine
exclusions
from
what
may
constitute
a
``
physical
or
operational
change.''
One
of
these
is
an
exclusion
for
routine
maintenance,
repair,
and
replacement.
Today's
rulemaking
proposes
two
provisions
that
will
improve
and
help
carry
out
the
purposes
of
this
exclusion.

VI.
Discussion
of
Issues
Under
Annual
Maintenance,
Repair
and
Replacement
Allowance
Approach
The
following
provides
a
discussion
of
the
key
issues
we
considered
in
developing
our
preferred
approaches
to
addressing
RMRR
under
the
NSR
program.
We
are
requesting
comment
on
all
alternatives
considered
and
any
other
viable
alternatives.
We
are
also
interested
in
the
impact
the
use
of
a
cost­
based
approach
such
as
the
annual
maintenance,
repair
and
replacement
allowance
will
have
on
reviewing
authorities,
such
as
the
need
for
staff
knowledgeable
in
cost
estimation,
and
are
requesting
comment
on
this
issue.
A.
Appropriate
Time
Period
for
a
Maintenance,
Repair
and
Replacement
Allowance
In
developing
a
maintenance,
repair
and
replacement
allowance,
we
considered
setting
an
allowance
based
on
either
a
calendar
or
fiscal
year
or
a
multi­
year
limit.
We
believe
that
a
limit
applied
over
a
specified
period
of
time
is
more
appropriate
than
an
activitybased
limit.
We
are
proposing
an
annual
limit,
but
we
also
believe
that
a
multiyear
limit
is
worthy
of
serious
consideration
as
a
possible
option
that
could
be
chosen
by
owners
or
operators
with
multi­
year
maintenance
cycles.
Under
NSR,
to
determine
applicability,
the
owner
or
operator
of
a
major
source
must
determine
whether
an
activity
performed
at
a
source
is
a
physical
change
or
change
in
the
method
of
operation
that
results
in
a
significant
emissions
increase
and
a
significant
net
emissions
increase.
NSR
may
apply
to
a
single
physical
change
or
operational
change
at
a
single
process
unit,
to
several
physical
or
operational
changes
at
a
single
process
unit,
or
to
multiple
changes
across
multiple
process
units,
each
of
which
changes
can
vary
widely
in
scope
and
cost.
Developing
a
maintenance,
repair
and
replacement
allowance
on
an
activity
basis
would
be
consistent
with
this
framework.
However,
the
variability
in
the
scope
of
such
activities
makes
it
difficult
to
establish
an
appropriate
cost
allowance
for
individual
activities
based
on
data
currently
available
to
us.
On
the
other
hand,
the
majority
of
information
that
is
currently
available
to
us
does
provide
a
reasonable
basis
for
developing
facility­
wide,
annual
maintenance,
repair
and
replacement
cost
estimates.
In
addition
to
the
difficulty
in
establishing
an
activity
cost
limit,
maintenance
budgets
are
typically
set
on
an
annual
basis
rather
than
an
activity
basis,
making
an
annual
allowance
more
consistent
with
industry
financial
practices.
In
choosing
between
an
annual
versus
a
multi­
year
limit,
there
are
considerations
pointing
in
both
directions.
The
most
important
argument
in
favor
of
a
multi­
year
option
is
that
in
a
number
of
industries,
maintenance
cycles
extend
over
multiple
years.
For
example,
petroleum
refineries
conduct
regularly
scheduled
maintenance,
referred
to
as
a
``
turnaround,''
in
cycles
that
can
be
as
long
as
8
years
depending
on
the
type
of
units
and
equipment
involved
and
the
particulars
of
the
unit's
operations.
During
a
turnaround,
all
or
part
of
the
refinery
is
shut
down,
and
the
owner
or
operator
undertakes
numerous
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Proposed
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maintenance,
repair
and/
or
replacement
activities
during
the
shutdown.
Similarly,
the
power
generation
sector
performs
regularly
scheduled
maintenance,
inspections,
and
repair
on
varying
cycles,
which,
depending
on
the
equipment
involved,
can
range
from
12
months
to
a
number
of
years.
Like
refineries,
power
generation
facilities
must
conduct
much
of
the
inspection,
maintenance,
repair
and
replacement
work
when
the
units
are
shut
down,
and
to
minimize
the
frequency
of
scheduled
outages,
the
owner
or
operator
will
undertake
numerous
activities
during
a
given
shutdown
to
minimize
maintenance
costs,
minimize
the
need
for
replacement
power,
and
maximize
the
availability
of
the
units.
As
a
result,
for
industries
of
this
type,
the
cost
of
maintenance
will
vary
significantly
from
year
to
year
and
may
be
distributed
across
several
years.
An
annual
allowance
for
industries
of
this
type
may
be
unworkable
if
the
allowance
is
set
at
the
average
of
their
maintenance
costs
during
their
maintenance
cycle.
But
setting
the
level
higher
than
the
average
runs
the
risk
of
sweeping
in
non­
routine
activity.
In
addition,
an
annual
allowance
might
lead
owners
or
operators
in
such
industries
to
engage
in
more
outages
than
is
efficient
in
order
to
make
sure
that
they
were
not
losing
a
portion
of
their
allowance.
This
could
increase
energy
costs
and
reduce
energy
availability
to
consumers.
If
a
multi­
year
allowance
were
used,
the
same
principles
of
summing
the
costs
of
activities
from
least
to
most
costly
and
excluding
the
most
costly
activities
from
the
allowance
and
instead
subjecting
them
to
case­
by­
case
scrutiny
would
continue
to
apply.
This
approach
also
may
have
its
difficulties.
For
example,
as
the
cycle
gets
longer,
it
is
harder
for
owners
or
operators
to
project
their
costs
for
safeguarding
the
safety,
reliability
and
efficiency
of
their
plants
farther
into
the
future.
This,
in
turn,
may
contribute
to
a
rule
that
is
more
difficult
to
implement
and
enforce.
If,
through
the
after
the
fact
case­
by­
case
review,
it
is
determined
that
certain
activities
should
have
been
subject
to
the
NSR
program,
all
parties
may
be
placed
in
the
difficult
situation
of
implementing
a
preconstruction
review
program
for
an
activity
that
was
begun
or
completed
significantly
prior
to
the
applicability
determination.
This
difficulty
may
arise
to
some
extent
even
with
a
1­
year
allowance
period.
But
extending
the
period
beyond
1
year
increases
both
the
possibility
for
this
occurrence
and
the
potential
difficulties
of
an
after­
the­
fact
applicability
determination
for
older
activities.
Thus,
while
using
a
single
year
as
the
time
period
will
reduce
the
flexibility
for
some
owners
or
operators,
we
believe
it
will
help
to
reduce
the
likelihood
that
an
after­
the­
fact
NSR
review
will
be
required.
For
these
reasons,
we
are
proposing
the
annual
maintenance,
repair
and
replacement
allowance
approach,
but
will
also
be
giving
serious
consideration
to
the
multi­
year
approach
of
up
to
5
years.
We
are
requesting
comments
on
the
approaches
discussed
above.
We
are
also
proposing
that
the
time
period
for
the
annual
maintenance,
repair
and
replacement
allowance
should
be
a
calendar
or
fiscal
year.
If
the
owner
or
operator
of
a
major
stationary
source
uses
a
fiscal
year
that
differs
from
a
calendar
year
for
accounting
purposes,
the
proposed
rule
would
allow
the
stationary
source
to
elect
to
use
that
fiscal
year
for
purposes
of
applying
the
annual
maintenance,
repair
and
replacement
allowance.
As
proposed,
once
the
choice
is
made,
the
choice
is
permanent.
(
See
§
51.165(
a)(
1)(
xxxxii)(
A)(
1),
§
51.166(
b)(
53)(
i)(
a),
§
52.21(
b)(
55)(
i)(
a),
and
§
52.24(
f)(
25)(
i)(
a)
of
proposed
rules.)
We
specifically
ask
for
comment
on
this
aspect
of
the
proposal.

B.
Cost
Basis
Under
our
proposal,
the
replacement
cost
of
a
source
would
be
multiplied
by
the
maintenance
percentage
established
by
rule
to
determine
the
annual
maintenance,
repair
and
replacement
allowance.
(
See
§
51.165(
a)(
1)(
xxxxii),
§
51.166(
b)(
53),
§
52.21(
b)(
55),
and
§
52.24(
f)(
25)
of
proposed
rules.)
In
developing
the
proposal,
we
also
considered
using
an
invested
cost
basis
adjusted
for
inflation.
There
can
be
advantages
to
using
invested
cost.
The
most
obvious
advantage
is
that
knowledge
of
cost
estimation
is
not
necessary,
because
actual
cost
data
would
be
used.
However,
complete
invested
cost
information
may
no
longer
exist
for
older
stationary
sources,
or
it
may
not
have
been
provided
to
the
buyer
when
a
source
was
purchased.
As
a
result,
we
would
still
need
to
provide
for
an
alternative
for
situations
where
invested
cost
data
were
not
available.
In
addition,
even
when
adjusted
for
inflation,
there
could
be
inequities
between
facilities
if
an
invested
cost
basis
was
used.
Adjustment
for
inflation
between
sources
will
not
likely
take
into
account
variations
in
site­
specific
costs
such
as
land,
labor,
and
materials,
among
others.
Use
of
replacement
cost,
which
takes
into
account
site­
specific
factors
to
a
greater
degree,
will
put
all
regulated
entities
on
a
more
equitable
footing.
Moreover,
most
decisions
regarding
maintenance,
repair
and
replacement
are
more
likely
to
take
into
consideration
the
cost
of
replacement
rather
than
the
original
invested
cost.
We
are
proposing
to
use
source
replacement
cost;
however,
we
are
requesting
comment
on
other
potentially
appropriate
bases
for
source
cost,
including
invested
cost,
invested
cost
adjusted
for
inflation
or
any
other
viable
methodology.

C.
Basis
for
Annual
Allowance
 
Stationary
Source
vs
Process
Unit
We
are
considering
two
approaches
for
administering
the
annual
maintenance,
repair
and
replacement
allowance
 
the
allowance
could
be
established
at
either
an
entire
stationary
source
(
source)
or
at
the
process
unit
level.
A
comprehensive
discussion
of
the
term
``
process
unit,''
along
with
a
proposed
definition,
is
set
forth
in
section
VII,
below.
If
we
opt
for
the
``
process
unit''
approach,
we
would
use
the
definition
and
concepts
proposed
in
section
VII.
We
are
proposing
the
stationary
source
approach
but
seeking
comment
on
both.
If
the
annual
maintenance,
repair
and
replacement
allowance
is
established
for
the
entire
stationary
source,
the
owner
or
operator
would
only
have
to
track
compliance
with
a
single
annual
maintenance,
repair
and
replacement
allowance
and
would
have
greater
flexibility
in
decision
making
with
respect
to
maintenance,
repair
and
replacement
activities.
It
is
our
understanding
that
accounting
of
maintenance
activities
is
most
often
performed
at
the
facility
level
and,
consequently,
managing
the
RMRR
annual
maintenance,
repair
and
replacement
allowance
from
a
facilitywide
standpoint
is
more
consistent
with
current
industry
practices.
In
large,
complex
manufacturing
facilities
such
as
refineries,
several
major
processes
are
constantly
being
maintained
but
larger
maintenance
activities
may
be
rotated
throughout
the
plant
during
different
years
to
accommodate
fiscal
and
operating
cycles.
Requiring
these
facilities
to
divide
their
plants
into
separate
process
units
for
maintenance
accounting
would
create
disincentives
to
the
source
in
administering
the
allowance.
A
source­
wide
approach
also
may
be
more
sensible
to
account
for
situations
in
which
shared
services
(
e.
g.,
electrical
distribution,
wastewater
treatment)
cannot
be
attributed
to
a
single
process
at
a
facility.
On
the
other
hand,
setting
the
annual
maintenance,
repair
and
replacement
allowance
at
the
source­
wide
level
presents
the
possibility
that
an
owner
or
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/
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31,
2002
/
Proposed
Rules
operator
could
forego
maintenance
at
some
process
units
and
engage
in
activities
at
others
that
are
not
truly
RMRR
and
seek
to
use
the
maintenance,
repair
and
replacement
allowance
as
a
shield
for
these
activities.
Setting
the
annual
maintenance,
repair
and
replacement
allowance
at
the
process
unit
level
would
help
to
alleviate
this
concern.
On
balance,
however,
we
are
not
persuaded
that
this
concern
is
wellfounded
If
the
allowance
level
is
set
correctly,
the
only
way
an
owner
or
operator
could
attempt
the
kind
of
misuse
of
the
allowance
described
above
would
be
to
forego
maintenance,
repair
and
replacement
activities
at
other
process
units
 
activities
that
are
important
to
keep
those
other
process
units
in
good
working
order.
It
seems
unlikely
that
an
owner
or
operator
would
think
that
a
prudent
or
sensible
course.
Finally,
we
note
that
it
likely
is
more
difficult
to
develop
reliable
estimates
of
what
it
typically
costs
an
owner
or
operator
to
maintain
a
process
unit.
That
being
the
case,
the
most
likely
way
a
process­
unit­
based
allowance
would
be
developed
would
be
by
taking
the
numbers
that
would
underlie
a
sourcewide
allowance
and
allocating
them
to
process
units.
This
approach
could
present
its
own
opportunities
for
gaming
the
system.
We
are
proposing
to
set
the
annual
maintenance,
repair
and
replacement
allowance
at
the
source­
wide
level.
(
See
§
51.165(
a)(
1)(
v)(
C)(
1),
§
51.166(
b)(
2)(
iii)(
a),
§
52.21(
b)(
2)(
iii)(
a),
and
§
52.24(
f)(
5)(
iii)(
a)
of
proposed
rules.)
We
believe
that
this
approach
is,
on
balance,
easier
to
implement
for
both
the
reviewing
authorities
and
the
industry
and
is
more
consistent
with
current
industry
maintenance
and
financial
practices.
We
specifically
request
comment
on
the
use
of
a
sourcewide
limit,
a
process
unit
limit,
or
any
other
means
of
applying
a
cost
threshold.
In
addition,
as
noted
in
section
VII,
we
request
comment
on
our
proposed
definition
of
process
unit.

D.
Basis
for
Annual
Maintenance,
Repair
and
Replacement
Allowance
Percentage
The
proposed
annual
maintenance,
repair
and
replacement
allowance
for
each
source
would
be
determined
by
multiplying
the
replacement
cost
of
the
source
by
an
annual
maintenance,
repair
and
replacement
allowance
percentage
specified
by
rule.
(
See
§
51.165(
a)(
1)(
xxxxii),
§
51.166(
b)(
53),
§
52.21(
b)(
55),
and
§
52.24(
f)(
25)
of
proposed
rules.)
As
stated
previously,
the
goal
of
this
portion
of
the
rule
is
to
provide
a
clear
exclusion
for
the
activities
whose
total
costs
fall
below
specified
thresholds.
We
intend
to
set
these
thresholds
on
an
industry­
specific
basis,
and
believe
the
following
sources
of
information
should
be
useful
in
establishing
these
thresholds:
the
IRS
AAGRAP,
standard
engineering
reference
manuals,
and
actual
industry
data
available
to
the
EPA.
The
IRS
AAGRAP
is
the
value
used
in
an
exclusion
under
the
NSPS
for
increases
in
production.
The
IRS
AAGRAP
values
provide
repair
allowance
percentages
for
specific
industries
in
order
to
reflect
differing
maintenance
needs.
These
percentages
range
from
0.5
percent
to
20
percent
of
invested
cost.
For
instance,
the
aerospace
industry
has
an
AAGRAP
value
of
7.5
percent,
electric
utility
steam
generation
has
a
value
of
5
percent,
and
cement
plants
have
a
value
of
3
percent.
There
is
good
reason
to
think
that
the
industry­
specific
basis
and
the
specific
percentages
are
appropriate
in
the
RMRR
context.
For
example,
the
AAGRAP
values
have
been
used
for
over
20
years
in
the
NSPS
program,
so
they
are
time­
tested
and
appear
to
work
well
in
that
context.
Moreover,
because
the
values
were
developed
in
the
first
instance
to
differentiate
between
costs
that
should
be
capitalized
for
tax
accounting
purposes
and
costs
that
properly
should
be
expensed,
the
values
should
be
well
suited
to
distinguishing
maintenance,
repair
and
replacement
from
nonroutine
activities
in
the
NSR
context.
However,
the
AAGRAP
is
based
on
the
invested
cost
of
the
facility,
not
the
replacement
cost,
which
may
or
may
not
require
us
to
make
some
adjustments.
Also,
there
are
some
industries
for
which
an
AAGRAP
is
not
available.
The
policy
reasons
behind
the
use
of
AAGRAP
in
the
tax
context
also
may
not
be
the
same
as
those
we
need
to
consider
in
the
NSR
context,
notwithstanding
the
fact
that
the
AAGRAP
has
been
used
in
the
NSPS
context.
Finally,
the
IRS
has
moved
to
other
approaches.
We
solicit
comment
on
the
extent
to
which
the
AAGRAP,
or
some
derivative
of
the
AAGRAP,
may
appropriately
be
employed
if
we
determine
that
a
safe
harbor
based
on
replacement
cost
is
preferable.
There
are
also
standard
reference
manuals
that
provide
cost
estimation
information
that
is
considered
to
be
up
to
date.
Plant
Design
and
Economics
for
Chemical
Engineers,
by
Peters
and
Timmerhaus,
and
Perry's
Chemical
Engineer's
Handbook,
by
Perry
and
Green,
are
two
widely
used
resources.
They
provide
a
range
of
annual
maintenance
and
repair
costs
from
2
percent
to
10
percent
of
the
fixed
capital
investment
of
the
stationary
source.
These
two
resources,
however,
are
limited
to
the
chemical
process
industry
and
may
not
have
broader
applicability
to
other
industry
sectors
(
although
there
may
be
comparable
resources
for
other
industries).
Based
on
information
contained
in
the
resources
mentioned
above,
the
appropriate
annual
maintenance
percentages
would
be
in
the
range
of
0.5
percent
to
20
percent,
depending
on
the
industry.
To
the
extent
that
we
have
data,
we
intend
in
the
final
rule
to
set
different
percentages
for
specific
industry
categories.
In
selecting
appropriate
industry­
specific
percentages,
it
would
be
helpful
if
further
information
is
made
available
to
us
during
the
public
comment
period
for
this
proposal;
therefore,
we
are
requesting
that
information
relating
to
types
of
maintenance,
repair
and
replacement
activities
undertaken
and
costs
associated
with
those
activities
be
provided
during
the
public
comment
period
on
this
proposed
rule.
For
example,
relevant
information
for
the
electric
utility
industry
might
be
available
from
the
NERC/
GADS
database,
the
Federal
Energy
Regulatory
Commission,
or
the
Integrated
Environmental
Control
Model
maintained
by
the
Energy
and
Environmental
Center
at
Carnegie­
Mellon
University.
Commenters
should
provide
actual
source,
company
or
industry
information,
as
well
as
any
other
data
underlying
summaries.
Substantiated
claims
and
estimates
will
be
given
greater
consideration
than
information
not
supported
by
actual
data.
If
there
is
a
lack
of
information
with
which
to
set
industry
specific
percentages,
we
may
elect
to
set
a
default
value.
We
are
seeking
comment
on
the
appropriate
default
percentage
to
be
used,
and/
or
methods
available
to
determine
that
percentage.

E.
How
To
Calculate
Costs
In
order
for
a
cost­
based
approach
to
be
equitable,
all
owners
or
operators
must
include
the
same
categories
of
expenses
in
both
the
replacement
cost
and
the
cost
sought
to
be
covered
by
the
allowance.
Therefore,
we
believe
it
may
be
appropriate
to
require
that
costs
be
calculated
using
an
approach
along
the
lines
set
out
as
the
elements
of
Total
Capital
Investment
as
defined
in
the
EPA
Air
Pollution
Control
Cost
Manual
(
http://
www.
epa.
gov/
ttn/
catc/
dir1/
c_
allchs.
pdf).
While
the
manual
contains
basic
concepts
that
could
be
used
to
estimate
total
capital
investment
at
a
process
unit,
it
is
geared
toward
cost
calculations
for
add­
on
control
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/
Proposed
Rules
equipment.
On
the
other
hand,
the
underlying
concepts
are
taken
from
work
done
by
the
American
Association
of
Cost
Engineers
to
define
the
components
of
cost
calculations
for
all
types
of
processes,
not
just
emission
control
equipment.
We
invite
comment
on
whether
we
should
use
the
manual
as
the
mechanism
for
standardizing
these
calculations,
whether
we
should
use
other
manuals,
or
whether
it
might
make
sense
to
give
sources
a
range
of
manuals
whose
approach
to
this
question
we
believe
may
be
appropriate
for
their
circumstances.
We
also
invite
comment
on
whether
EPA
should
require
use
of
the
manuals
identified
or
simply
provide
assurance
that
if
methods
in
an
identified
manual
are
used,
EPA
will
accept
them.
Under
the
EPA
Manual,
Total
Capital
Investment
includes
the
costs
required
to
purchase
equipment,
the
costs
of
labor
and
materials
for
installing
the
equipment
(
direct
installation
costs),
costs
for
site
preparation
and
buildings,
and
certain
other
indirect
installation
costs.
However,
any
costs
associated
with
the
installation
and
maintenance
of
pollution
control
equipment
would
be
excluded
from
the
cost
calculation.
For
the
purposes
of
this
maintenance,
repair
and
replacement
allowance,
we
believe
that
equipment
that
serves
a
dual
purpose
of
process
equipment
and
control
equipment
(
that
is,
combustion
equipment
used
to
produce
steam
and
to
control
Hazardous
Air
Pollutant
emissions,
exhaust
conditioning
in
the
semiconductor
industry,
etc.)
should
be
considered
process
equipment.
We
ask
for
comment
on
this
point.
Direct
installation
costs
include
costs
for
foundations
and
supports,
erecting
and
handling
the
equipment,
electrical
work,
piping,
insulation,
and
painting.
Indirect
installation
costs
include
such
costs
as
engineering
costs;
construction
and
field
expenses
(
that
is,
costs
for
construction
supervisory
personnel,
office
personnel,
rental
of
temporary
offices,
etc.);
contractor
fees
(
for
construction
and
engineering
firms
involved
in
the
activity);
startup
and
performance
test
costs;
and
contingencies.
We
are
also
considering
whether
or
not
to
exclude
costs
associated
with
the
unanticipated
shutdown
of
equipment,
due
to
component
failure
or
catastrophic
failures
such
as
explosions
or
fires,
from
the
costs
that
must
be
included
in
the
allowance.
If
costs
associated
with
unanticipated
outages
are
excluded,
these
activities
would
be
subjected
to
a
case­
by­
case
review
of
NSR
applicability.
We
request
comment
on
whether
or
not
repairs
and
replacements
resulting
from
the
unanticipated
shutdown
of
equipment,
or
of
an
entire
source,
should
be
included
in
the
annual
maintenance,
repair
and
replacement
allowance
calculations.

F.
Applicability
Safeguards
We
are
proposing
to
include
some
safeguards
in
our
rules.
There
are
some
relatively
inexpensive
activities
that
can
be
undertaken
at
a
facility
that
we
believe
should
not
be
included
within
the
maintenance,
repair
and
replacement
allowance
because,
due
to
their
very
nature,
they
may
significantly
alter
the
design
of
the
source
or
they
may
result
in
significantly
greater
emissions.
Ineligibility
for
the
allowance
does
not
mean
that
the
activities
will
necessarily
be
subject
to
NSR.
These
activities
will
still
be
eligible
for
treatment
as
RMRR
under
a
case­
by­
case
review,
may
qualify
for
other
exclusions,
may
not
require
a
major
NSR
permit
because
of
emissions
limitations
in
a
synthetic
minor
limitation,
or
may
be
netted
out
of
NSR
applicability.
We
are
proposing
to
include
three
such
safeguards.
(
See
§
51.165(
a)(
1)(
xxxxii)(
B),
§
51.166(
b)(
53)(
ii),
§
52.21(
b)(
55)(
ii),
and
§
52.24(
f)(
25)(
ii)
of
proposed
rules.)
The
first
of
the
safeguards
is
that
no
new
process
unit
may
be
added
under
the
annual
maintenance,
repair
and
replacement
allowance.
The
addition
of
a
new
process
unit
is
not
maintenance,
repair
or
replacement
of
existing
equipment
at
a
stationary
source
in
order
to
ensure
continued
safe
and
reliable
operation
and
hence
should
not
qualify
for
the
allowance.
The
second
safeguard
is
that
an
owner
or
operator
may
not
use
the
maintenance,
repair
and
replacement
allowance
to
replace
an
entire
process
unit.
We
do
not
believe
that
replacement
of
an
entire
process
unit
should
qualify
for
the
allowance.
Because
of
their
nature,
wholesale
exchanges
of
a
process
unit
should
be
subject
to
greater
scrutiny
in
determining
NSR
applicability
than
use
of
the
maintenance,
repair
and
replacement
allowance
would
entail.
The
third
safeguard
is
not
allowing
any
activity
that
results
in
an
increase
in
maximum
achievable
hourly
emissions
rate
of
a
regulated
NSR
pollutant
at
the
stationary
source
or
in
the
emission
of
any
regulated
NSR
pollutant
not
previously
emitted
to
be
excluded
under
the
annual
maintenance,
repair
and
replacement
allowance.
Such
activities
are
more
likely
to
result
in
possible
significant
emissions
increases
and,
therefore,
should
not
be
excluded
from
NSR
on
the
basis
that
they
fall
within
the
maintenance,
repair
and
replacement
allowance.
We
request
comment
on
the
appropriateness
and
adequacy
of
these
proposed
safeguards
or
any
additional
safeguards
that
may
be
appropriate.

G.
Timing
of
Determination
Under
the
annual
maintenance,
repair
and
replacement
allowance
as
proposed,
an
owner
or
operator
will
sum
the
costs
of
maintenance,
repair
and
replacement
activities
from
least
to
most
expensive
to
determine
which
activities
are
excluded
pursuant
to
the
allowance.
Actual
activity
costs
will
not
be
known
until
activities
are
underway
or
completed.
We
have
considered
two
options
for
the
timing
of
the
decision
regarding
qualification
of
activities
under
the
annual
maintenance,
repair
and
replacement
allowance
when
summing
activities
in
this
manner.
The
first
is
to
require
application
of
the
allowance
prior
to
construction
based
on
planned
activities
and
estimated
costs.
The
second
is
to
perform
an
endof
year
reconciliation
after
the
activity
costs
are
known.
If
an
end­
of­
year
reconciliation
is
used,
actual
costs
incurred
would
be
known.
However,
if
costs
exceed
the
annual
maintenance,
repair
and
replacement
allowance,
some
activities
that
have
already
been
started
or
completed
will
have
to
be
evaluated
on
a
case­
by­
case
basis
unless
already
excluded
from
major
NSR
on
some
other
basis.
If
it
is
determined
that
the
activity
is
not
RMRR
and
does
not
qualify
for
another
exclusion,
and
it
results
in
a
significant
emissions
increase
and
a
significant
net
emissions
increase,
and
it
is
consequently
subject
to
the
requirements
of
NSR,
the
owner
or
operator
would
be
in
violation
of
the
CAA
for
failure
to
obtain
the
necessary
permit
prior
to
commencing
construction.
In
addition,
if
in
a
nonattainment
area,
the
owner
or
operator
could
be
required
to
obtain
offsets,
which
may
not
be
readily
available
in
the
area.
The
owner
or
operator
may
also
be
faced
with
penalties
for
constructing
without
a
permit.
In
practice,
however,
we
do
not
believe
this
scenario
is
likely
to
occur.
We
expect
that
an
owner
or
operator
who
intended
to
rely
on
the
annual
maintenance,
repair
and
replacement
allowance
would
have
planned
the
year's
activities
accordingly
and
would
be
tracking
activities
throughout
the
year
in
order
to
avoid
this
situation.
We
believe
requiring
an
end­
of­
year
reconciliation
strikes
a
reasonable
balance,
since
it
will
lead
owners
or
operators
to
make
preconstruction
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251
/
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December
31,
2002
/
Proposed
Rules
estimates
of
activities
and
costs
in
order
to
determine
qualification
for
the
exclusion
but
will
not
require
them
to
become
involved
in
permitting­
type
actions
with
respect
to
excluded
activities.
Finally,
it
is
not
possible
for
an
owner
or
operator
to
plan
all
maintenance,
repair
and
replacement
needs,
so
there
will
be
inaccuracies
in
any
estimation
no
matter
how
diligent
an
owner
or
operator
may
be
in
seeking
to
plan
these
activities.
We
have
considered
two
other
possible
ways
to
address
this
situation.
The
first
is
to
allow
any
unplanned
activity
to
undergo
a
case­
by­
case
determination
of
RMRR.
However,
this
method
might
create
an
incentive
to
omit
smaller,
less
expensive
activities
from
the
preconstruction
estimation
in
order
to
avoid
a
case­
by­
case
review
on
larger
activities.
The
second
is
to
make
ineligible
for
the
use
of
the
maintenance,
repair
and
replacement
allowance
any
activity
that
was
not
included
in
the
preconstruction
estimation.
But
that
seems
unreasonable,
since
as
noted
above
actual
activity
costs
may
be
unintentionally
underestimated
or
omitted,
resulting
in
actual
activity
costs
exceeding
the
annual
maintenance,
repair
and
replacement
estimates.
After
considering
the
options,
we
believe
that
an
evaluation
based
on
actual
data
rather
than
estimates
is
preferable.
Careful
planning
by
an
owner
or
operator
should
reduce
the
likelihood
that
the
annual
allowance
is
exceeded
for
activities
that
the
owner
believes
will
come
within
the
allowance.
Moreover,
a
prudent
owner
or
operator
who
believes
his
RMRR
activities
will
be
close
to
exceeding
the
allowance
will
determine
whether
more
costly
activities
are
otherwise
excluded,
evaluate
them
under
the
case­
by­
case
test,
or
seek
an
applicability
determination
or
a
permit
to
assure
compliance
with
NSR
requirements.
Therefore,
we
are
proposing
to
determine
qualification
for
the
exclusion
through
an
end­
of­
year
reconciliation.
(
See
§
51.165(
a)(
1)(
xxxxii)(
A)(
5),
§
51.166(
b)(
53)(
i)(
e),
§
52.21(
b)(
55)(
i)(
e),
and
§
52.24(
f)(
25)(
i)(
e)
of
proposed
rules).
One
other
possible
approach
to
this
question
would
be
to
sum
costs
in
the
order
they
occur,
rather
than
from
least
expensive
to
most
expensive.
Under
that
approach,
an
owner
or
operator
would
maintain
a
running
total
of
maintenance,
repair
and
replacement
costs
and
could
determine
before
beginning
construction
on
a
subsequent
activity
if
there
was
room
under
the
annual
maintenance,
repair
and
replacement
allowance.
However,
this
process
might
encourage
an
owner
or
operator
to
delay
less
costly
activities
in
order
to
use
the
annual
maintenance,
repair
and
replacement
allowance
for
activities
that
are
both
larger
and
more
atypical
and,
therefore,
might
not
qualify
for
RMRR
treatment.
Maintaining
the
least
expensive
to
most
expensive
methodology
discussed
above,
we
could
address
the
issue
through
an
expedited
case­
by­
case
review
of
larger
activities.
An
owner
or
operator
would
be
responsible
for
obtaining
a
case­
by­
case
determination
from
the
reviewing
authority
for
larger
activities
to
ensure
that
an
activity
would
still
be
considered
RMRR
if
it
is
later
found
that
the
activity
could
not
be
accommodated
under
the
annual
maintenance,
repair
and
replacement
allowance.
This,
however,
is
inconsistent
with
our
intent
that
owners
or
operators
be
able
to
use
these
provisions
without
obtaining
an
advance
determination
from
the
reviewing
authority.
Finally,
rather
than
establishing
an
annual
cost
threshold
to
define
what
activities
fit
within
the
allowance,
we
could
establish
a
threshold
per
activity.
Activities
whose
costs
fell
below
the
threshold
could
proceed
as
RMRR.
Activities
with
costs
above
the
threshold
would
be
ineligible
to
use
the
allowance,
and
thus
could
only
constitute
RMRR
if
they
either
fell
within
the
portion
of
the
RMRR
exclusion
for
equipment
replacements
or
constitute
RMRR
upon
an
application
of
the
case­
by­
case
test.
We
are
proposing
a
similar
approach
for
replacement
of
equipment
with
functional
equivalents.
But
we
believe
that
any
broader
activity­
based
approach
would
have
the
undesirable
consequence
of
forcing
industry
and
the
reviewing
authorities
to
address
potentially
complex
questions
about
how
to
define
whether
activities
are
truly
separate
and
hence
below
the
threshold
or
whether
they
are
part
of
some
larger
activity
that
exceeds
the
threshold.
To
summarize,
at
this
time
we
are
proposing
an
annual
maintenance,
repair
and
replacement
allowance;
to
sum
activities
from
least
expensive
to
most
expensive
to
determine
eligibility;
and
an
end­
of­
year
review
and
report.
We
request
comment
on
each
of
these
aspects
of
the
proposal
and
any
additional
approaches
that
commenters
wish
to
recommend.
VII.
Discussion
of
Issues
Under
the
Equipment
Replacement
Approach
We
recognize
that
there
are
numerous
occasions
when,
to
maintain,
facilitate,
restore,
or
improve
efficiency,
reliability,
availability,
or
safety
within
normal
facility
operations,
facilities
replace
existing
equipment
with
either
identical
equipment
or
equipment
that
serves
the
same
function.
Such
replacements
may
be
conducted
immediately
after
component
failure
or
they
may
be
conducted
preventively
to
assure
a
source's
continued
safe,
reliable
and
efficient
operation.
We
believe
that
many
such
replacements
typically
should
be
considered
RMRR
activities.
But,
allowing
replacement
of
equipment
with
``
functionally
equivalent''
or
``
identical''
equipment
to
qualify
as
RMRR,
if
unbounded,
could
theoretically
allow
replacement
of
an
entire
production
line
or
utility
boiler.
Thus,
there
must
also
be
some
reasonable
bound
to
equipment
replacements
that
qualify.
The
following
discussion
addresses
key
considerations
in
determining
the
appropriate
boundary
for
the
types
of
replacement
activities
that
should
be
excluded
under
the
equipment
replacement
provision
of
the
RMRR
exclusion.

A.
Replacement
of
Existing
Equipment
With
Identical
or
Functionally
Equivalent
Equipment
One
of
today's
proposals
deals
with
replacing
equipment
with
identical
or
functionally
equivalent
equipment.
This
proposal
is
based
on
our
view
that
most
replacements
of
existing
equipment
that
are
necessary
for
the
safe,
efficient,
and
reliable
operation
of
practically
all
industrial
operations
are
not
of
regulatory
concern
and
should
qualify
for
the
RMRR
exclusion.
Industrial
facilities
are
constructed
with
the
understanding
that
equipment
failures
are
common
and
ongoing
maintenance
programs
are
routine.
Delaying
or
foregoing
maintenance
could
lead
to
failure
of
the
production
unit
and
may
create
or
add
to
safety
concerns.
When
such
equipment
replacement
occurs
and
the
replacement
is
identical,
the
replacement
is
inherent
to
both
the
original
design
and
purposes
of
the
facility,
and
ordinarily
will
not
increase
emissions.
For
example,
if
a
pump
associated
with
a
distillation
column
fails
and
is
replaced
with
an
identical
new
pump,
we
believe
that
such
a
common
activity
is
and
should
be
considered
an
excluded
replacement.
We
believe
that
activities
like
such
pump
replacements
are
routine
and
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/
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December
31,
2002
/
Proposed
Rules
should
not
trigger
NSR
permitting
requirements.
We
also
recognize
that
this
principle
extends
beyond
the
replacement
of
equipment
with
identical
equipment.
When
equipment
is
wearing
out
or
breaks
down,
it
often
is
replaced
with
equipment
that
serves
the
same
purpose
or
function
but
is
different
in
some
respect
or
improved
in
some
way
in
comparison
to
the
equipment
that
is
removed.
For
example,
when
worn
out
pipes
are
replaced
in
a
chemical
process
plant,
the
replacement
pipes
sometimes
are
constructed
of
new
or
different
materials
to
help
reduce
corrosion,
erosion,
or
chemical
compatibility
problems.
Moreover,
the
technology
employed
in
certain
types
of
equipment
is
constantly
changing
and
evolving.
When
equipment
of
this
sort
needs
to
be
replaced,
it
often
is
simply
not
possible
to
find
the
old­
style
technology.
Owners
or
operators
may
have
no
choice
but
to
purchase
and
install
equipment
reflecting
current
design
innovations.
Even
if
it
is
possible
to
find
old­
style
equipment,
owners
or
operators
have
obvious
incentives
for
wanting
to
use
the
best
equipment
that
suits
the
given
need
when
replacements
must
be
installed.
A
good
example
was
presented
to
us
by
the
forest
products
industry
during
our
review
of
the
NSR
program's
impacts
on
the
energy
sector.
A
company
in
that
sector
needed
to
replace
outdated
analog
controllers
at
a
series
of
six
batch
digesters.
The
original
controllers
were
no
longer
manufactured.
The
new
digital
controllers,
costing
approximately
$
50,000,
are
capable
of
receiving
inputs
from
the
digester
vessel
temperature,
pressure,
and
chemical/
steam
flow.
The
new
controllers
would
have
more
precisely
filled
and
pressurized
digesters
with
chips,
chemicals,
and
steam,
thus
bringing
a
batch
digester
on
line
faster.
The
source
determined
that
this
activity
would
not
be
considered
routine
under
today's
NSR
rules
and
decided
not
to
proceed
with
the
project.
The
limiting
principle
here
is
that
the
replacement
equipment
must
be
identical
or
functionally
equivalent
and
must
not
change
the
basic
design
parameters
of
the
affected
process
unit
(
for
example,
for
electric
utility
steam
generating
units,
this
would
mean
maximum
heat
input
and
fuel
consumption
specifications).
Efficiency,
however,
should
not
be
considered
a
basic
design
parameter,
as
NSR
should
not
impede
industry
in
making
energy
and
process
efficiency
improvements
which,
on
balance,
will
be
beneficial
both
economically
and
environmentally.
This
should
address
the
concern
and
perception
that
the
NSR
program
serves
as
a
barrier
to
activities
undertaken
to
facilitate,
restore,
or
improve
efficiency,
reliability,
availability,
or
safety
of
a
facility.
We
also
note,
however,
that
taken
to
the
extreme,
even
without
a
change
in
basic
design
parameters,
an
identical
or
functionally
equivalent
replacement
activity
can
still
go
beyond
the
bounds
of
the
RMRR
exclusion.
For
example,
instead
of
replacing
a
pump,
what
if
a
chemical
manufacturing
facility
replaced
an
entire
production
unit?
Even
if
the
replacement
was
identical,
we
likely
would
not
consider
the
activity
to
be
an
excluded
replacement.
Such
an
activity
effectively
constitutes
construction
of
a
new
process
unit
in
much
the
same
way
the
construction
of
an
entirely
new
process
unit
at
an
existing
stationary
source
could
not
constitute
RMRR.
This
is
not
the
kind
of
activity
that
sources
typically
engage
in
to
maintain
their
plants,
and
it
is
the
kind
of
activity
that
would
likely
be
a
logical
point
for
owners
or
operators
to
install
state­
of­
the­
art
controls.
We
recognize
that
it
may
sometimes
be
difficult
to
determine
where
to
draw
the
line
between
an
activity
that
should
be
treated
as
an
excluded
replacement
activity
and
one
that
should
be
viewed
as
a
physical
change
that
might
constitute
a
major
modification
when
the
replacement
of
equipment
with
identical
or
functionally
equivalent
equipment
involves
a
large
portion
of
an
existing
unit.
At
the
same
time,
we
believe
it
is
important
to
provide
some
clear
parameters
for
making
this
determination.
To
that
end,
we
are
soliciting
comment
on
an
equipment
replacement
cost
approach
based
on
the
NSPS
program
to
determine
whether
identical
or
functionally
equivalent
replacement
activities
constitute
RMRR
without
regard
to
other
considerations.
Under
the
NSPS
program,
a
project
at
an
existing
affected
source
triggers
any
applicable
NSPS
when
the
cost
of
the
project
exceeds
50
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
a
comparable
entirely
new
unit
 
that
is,
the
current
capital
replacement
value
of
the
existing
affected
source.
40
CFR
60.15(
b).
In
essence,
such
a
``
reconstruction''
is
tantamount
to
new
construction
and,
therefore,
triggers
any
applicable
NSPS
even
if
the
project
would
otherwise
be
excluded.
We
recognize
that,
in
some
respects,
an
equipment
replacement
cost
threshold
such
as
the
NSPS
reconstruction
test
may
be
viewed
as
the
proper
tool
to
be
used
in
the
future
for
distinguishing
between
routine
and
non­
routine
identical
and
functionally
equivalent
replacements
under
the
NSR
program.
As
noted
above,
we
do
not
believe
it
is
reasonable
to
exclude
from
NSR
activities
that
involve
the
total
replacement
of
an
existing
entire
process
unit.
By
extension,
it
is
therefore
logical
and
consistent
to
conclude
that
activities
which,
based
on
their
cost,
effectively
constitute
replacement
of
the
process
unit
should
not
qualify
as
RMRR.
Thus,
we
believe
that
the
50
percent
capital
replacement
threshold
used
under
the
NSPS
might
constitute
an
appropriate
limitation
on
when
identical
or
functionally
equivalent
replacements
should
qualify
as
RMRR
under
the
equipment
replacement
provision
without
regard
to
other
considerations.
We
also
recognize,
however,
that
there
are
other
considerations
pointing
in
favor
of
a
threshold
lower
than
the
50
percent
reconstruction
threshold
that
may
be
appropriate
to
bound
the
equipment
replacement
provision.
For
example,
since
under
NSPS
half
of
the
capital
replacement
value
of
an
existing
affected
facility
effectively
constitutes
construction
of
a
new
unit,
it
could
be
argued
that
some
percentage
less
than
the
50
percent
reconstruction
threshold
might
be
a
suitable
line
of
demarcation
in
determining
whether
identical
replacements
constitute
a
modification
of
an
existing
unit.
We
are
soliciting
comment
on
whether
the
proposed
approach
is
workable,
whether
the
capital
replacement
percentage
should
be
50
percent
or
another
lesser
percentage,
and
whether
different
percentages
should
apply
to
different
industrial
groupings
or
different
types
of
industrial
processes.
For
example,
it
may
be
appropriate
to
set
a
higher
percentage
for
process
operations
that
involve
heat
and
corrosive
compounds.
Such
processes
may
require
more
expensive
replacements,
and
a
greater
degree
of
maintenance
activities
than
other
types
of
processes.
In
addition,
we
solicit
comment
on
whether
this
equipment
replacement
provision
should
be
implemented
on
a
component­
bycomponent
basis,
or
some
other
reasoned
basis
such
as
applying
the
percentage
to
components
that
are
replaced
collectively
over
a
fixed
period
of
time.
We
recognize
that
there
are
widely
divergent
views
as
to
how
expansive
the
RMRR
exclusion
should
be.
From
our
perspective,
the
most
important
thing
we
can
do
to
improve
air
quality
in
the
United
States
with
respect
to
stationary
sources
is
to
make
substantial
reductions
in
NOX
and
SO2
emissions
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
from
facilities
in
the
utility
sector.
Our
current
view,
however,
is
that
if
the
rules
clearly
establish
a
narrow
RMRR
exclusion
and
set
out
to
require
permits
for
replacement
of
larger
components
or
the
replacement
of
components
with
more
efficient
ones,
owners
or
operators
will
comply
with
these
rules
but
will
find
ways
to
make
the
replacements
without
having
to
obtain
permits
and
install
state­
of­
the­
art
controls.
As
a
result,
such
rules
will
not
achieve
significant
reductions
in
NOX
or
SO2
on
a
prospective
basis.
As
discussed
below,
these
owners
or
operators
will
likely
avoid
having
to
make
such
reductions
through
one
of
several
ways
plainly
permissible
under
NSR.
For
example,
when
a
power
plant
operator
plans
to
undertake
an
activity
that
the
operator
believes
may
not
qualify
as
RMRR
and
is
assessing
compliance
alternatives,
that
operator
is
faced
with
three
options:
(
1)
Proceed
with
the
activity
pursuant
to
an
NSR
permit,
which
could
require
more
than
$
100
million
to
be
spent
on
air
pollution
controls;
(
2)
forego
the
activity,
which
likely
would
result
in
a
permanent
reduction
in
capacity
or
utilization
of
the
facility
or
might
reduce
efficiency
and
increase
emissions
per
unit
of
product
manufactured
or
energy
produced;
or
(
3)
proceed
with
the
activity,
but
take
steps
to
limit
future
emissions
such
that
the
activity
would
not
result
in
a
significant
net
emissions
increase.
We
also
believe
that
few
owners
or
operators
would
choose
the
first
option.
This
option
would
make
economic
sense
only
in
circumstances
where
the
current
capacity
and
utilization
of
the
facility
are
so
low
that
the
major
investment
in
air
pollution
controls
would
provide
an
incrementally
better
payback
than
the
option
of
investing
the
same
money
in
other
assets
or
in
the
development
of
a
new
power
plant.
We
also
believe
that
few
owners
or
operators
would
elect
the
second
option.
It
makes
no
sense
in
most
cases
for
the
owners
or
operators
of
costly
power
plants
to
let
these
assets
significantly
deteriorate
over
time,
because
the
value
of
the
asset
will
eventually
be
lost.
We
believe
that
most
owners
or
operators
would
select
the
third
option.
We
note
that
industry
commenters
during
our
review
of
the
impact
of
NSR
on
the
energy
sector
argued
that
this
option
would,
over
time,
result
in
a
substantial
reduction
in
the
capacity
of
their
facilities.
For
example,
the
Tennessee
Valley
Authority
reported
that,
over
the
last
20
years,
it
would
have
lost
32
percent
of
its
coal
system's
energy
capability
if
it
had
capped
emissions
under
a
``
narrow''
routine
maintenance
exclusion.
In
similar
analyses,
Southern
Company
estimated
that
it
would
have
experienced
an
energy
shortfall
of
57.5
million
MW­
hr,
and
First
Energy
estimated
that
it
would
have
lost
39
percent
of
its
coal­
fired
generating
capacity
between
1981
and
2000.
West
Associates,
the
Western
System
Coordinating
Council,
and
the
National
Rural
Electric
Cooperative
Association
reported
similar
results.
Notwithstanding
these
assessments,
we
believe
that
most
owners
or
operators
would
proceed
with
activities
and
take
emissions
limitations.
To
the
extent
that
such
limitations
might
curtail
full
utilization
of
the
facility,
incremental
control
measures
of
modest
cost
would
likely
be
taken
to
recover
the
``
lost''
utilization.
For
example,
use
of
a
slightly
lower
sulfur
coal
could
produce
the
marginally
lower
SO2
emissions
that
would
be
needed
to
recapture
some
capacity.
Likewise,
various
types
of
relatively
low­
cost
combustion
or
process
control
modifications
could
be
employed
to
reduce
NOX
emissions.
Thus,
it
is
not
probable
that
owners
or
operators
would
respond
to
a
narrow
exclusion
by
installing
state­
of­
the­
art
controls
every
time
they
need
to
replace
a
major
component.
At
the
same
time,
a
narrow
RMRR
exclusion
of
this
type
would
not
allow
in
many
cases
the
replacement
of
equipment
with
equipment
that
improves
process
efficiency.
This
would
cause
owners
or
operators
to
forego
replacements
that
would
improve
air
quality
because
they
would
allow
greater
efficiency.
For
these
reasons,
a
narrow
RMRR
exclusion
that
is
clearly
established
is
not
expected
to
achieve
significant
reductions
in
historic
emissions
levels,
and
might
even
lead
to
area
wide
emissions
increases.
Most
facilities
would
take
lawful
steps
to
avoid
having
to
obtain
an
NSR
permit
that
would
impose
strict
limitations,
even
when
replacements
would
be
found
under
this
narrow
exclusion
to
be
non­
routine.

B.
Defining
``
Process
Unit''
for
Evaluating
Equipment
Replacement
Cost
Percentage
In
this
section,
we
discuss
issues
related
to
what
collection
of
equipment
should
be
considered
in
applying
the
equipment
replacement
approach.
We
are
proposing
the
term
``
process
unit''
as
the
appropriate
collection.
A
definition
of
process
unit
currently
is
included
in
40
CFR
63.41.
We
have
built
upon
that
definition
to
accommodate
the
intended
coverage
of
activities
under
the
equipment
replacement
approach.
The
purpose
of
this
term
is,
as
best
as
possible,
to
align
implementation
of
the
provision
with
generally
accepted
and
practical
understandings
of
what
constitutes
a
discrete
production
process.
The
general
definition
would
read
as
follows:

Process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
facility
may
contain
more
than
one
process
unit.

Our
primary
goal
in
defining
this
term
is
to
encompass
integrated
manufacturing
operations
that
produce
a
completed
product
rather
than
smaller
pieces
of
such
operations.
To
help
illustrate
these
concepts,
we
developed
and
have
included
in
the
proposed
rules
some
industry­
specific
examples
of
how
this
definition
might
be
applied.
The
examples
are
drawn
from
a
few
selected
industry
categories
 
electric
utilities,
refineries,
cement
manufacturers,
pulp
and
paper
producers,
and
incinerators.
Because
of
the
centrality
of
the
``
process
unit''
concept
to
the
usefulness
of
the
equipment
replacement
provision,
it
is
our
desire
to
include
a
version
of
these
examples
in
the
final
rule
to
make
sure
sources
have
a
benchmark
against
which
they
can
evaluate
with
greater
confidence
whether
a
particular
replacement
comes
within
the
equipment
replacement
provision
of
the
RMRR
exclusion.
We
also
request
comment
on
whether
associated
pollution
control
equipment
should
typically
not
be
considered
part
of
the
process
unit.
We
are
proposing
to
exclude
such
equipment
from
the
definition.
 
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
that
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal­
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
 
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.

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2002
/
Proposed
Rules
 
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
 
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
 
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
We
solicit
comment
on
the
proposed
definition
of
``
process
unit''
and
whether
another
approach
might
be
more
effective.
We
also
solicit
comment
on
the
particular
process
units
identified
in
specific
industries,
whether
there
are
better
ways
of
identifying
those
process
units
in
those
industries,
and
whether
other
process
units
should
be
specifically
identified
as
part
of
the
rule.
Finally,
today's
proposed
approaches
for
replacement
of
existing
equipment
with
identical
or
functionally
equivalent
equipment
rely
on
the
concept
of
a
process
unit,
but
it
is
possible
that
it
is
not
appropriate
for
replacement
of
nonemitting
components
because
such
replacements
may
not
have
emissions
consequences
in
the
first
place
and
hence
would
not
warrant
scrutiny
under
NSR.
Similarly,
it
is
possible
that
maintenance,
repair
and
replacement
activities
performed
on
non­
emitting
units
should
not
be
included
in
the
activities
that
would
have
to
be
accounted
for
under
the
annual
maintenance,
repair
and
replacement
allowance
provision
of
the
RMRR
exclusion.
We
solicit
comment
on
how
these
various
activities
should
be
handled
in
the
context
of
today's
proposal,
bearing
in
mind
that
forthcoming
proposed
NSR
rules
for
future
activities
involving
debottlenecking
will
specifically
address
changes
made
at
non­
emitting
units
that
affect
emissions
at
other
process
units
at
a
stationary
source
among
other
issues.
However,
we
request
comment
on
limiting
today's
proposed
approaches
to
changes
made
at
emitting
units
or
modifying
them
so
as
to
differentiate
between
changes
made
at
emitting
versus
non­
emitting
units.

C.
Miscellaneous
Issues
In
addition
to
the
issues
noted
above,
we
also
request
comment
on
the
following
matters.
First,
we
solicit
comments
on
the
topic
of
basic
design
parameters.
Our
proposal
states
that
maximum
heat
input
and
fuel
consumption
specifications
(
for
electric
utility
steam
generating
units)
and
maximum
material/
fuel
input
specifications
(
for
other
types
of
units)
are
basic
design
parameters.
We
solicit
comment
on
whether
that
provides
sufficient
definition
of
this
term,
whether
further
definition
is
appropriate,
or
whether
there
are
industry­
specific
considerations
that
should
be
taken
into
account.
Second,
in
calculating
costs,
we
propose
that
owners
or
operators
should
use
the
same
principles
and
guidelines
as
discussed
above
with
respect
to
calculating
costs
for
the
maintenance,
repair
and
replacement
allowance.
We
request
comment
on
whether
these
same
principles
and
requirements
are
applicable
and
workable
for
the
equipment
replacement
provision.
Third,
in
addition
to
soliciting
comment
on
the
approaches
described
above,
we
are
also
soliciting
comment
on
whether
the
maintenance,
repair
and
replacement
allowance
and
this
equipment
replacement
provision
should
both
be
adopted
or
whether
just
the
equipment
replacement
provision
is
sufficient?
In
addition,
if
we
assume
that
both
approaches
are
adopted,
how
should
they
work
together?
Should
an
RMRR
activity
that
is
excluded
under
the
equipment
replacement
provision
also
count
against
your
annual
maintenance,
repair
and
replacement
allowance?
We
are
soliciting
comment
on
whether
to
adopt
any
or
all
of
these
approaches
and
how
they
might
fit
together.
Lastly,
EPA
strongly
supports
efforts
to
improve
energy
efficiency
at
existing
power
plants.
These
activities
reduce
the
amount
of
criteria
pollutants
(
SO2
and
NOX)
emitted
per
unit
of
electricity
generated
and
also
reduce
greenhouse
gas
emissions.
During
our
study
of
the
impact
of
NSR
on
the
energy
sector,
we
received
information
concerning
a
number
of
instances
where
activities
that
would
have
improved
energy
efficiency
were
not
implemented
because
they
would
have
resulted
in
significant
annual
emission
increases
that
would
have
triggered
NSR.
Some
have
commented
that
any
activity
that
produces
any
improvement
in
energy
efficiency
should
be
exempt
from
NSR.
However,
given
the
continuing
improvement
in
materials
and
design,
almost
any
component
replacement
can
be
expected
to
have
some
beneficial
impact
on
the
energy
efficiency
of
the
unit
and,
left
unbounded,
this
approach
could
result
in
the
replacement
of
an
entire
boiler
with
a
new,
more
efficient
boiler
without
state­
of­
the­
art
pollution
controls.
As
mentioned
above,
however,
we
do
not
think
replacement
of
an
entire
boiler
is
properly
viewed
as
routine.
We
also
do
not
believe
that
the
need
to
install
state­
of­
the­
art
controls
on
new
boilers
will
deter
sources
from
installing
new
boilers
if
they
are
otherwise
prepared
to
do
so.
These
issues
prompt
EPA
to
solicit
comment
in
several
areas.
To
the
extent
that
an
activity
is
the
replacement
of
existing
equipment
that
serves
the
same
function
as
the
equipment
replaced,
does
not
alter
the
basic
design
parameters
of
the
process
unit,
and
otherwise
meets
the
provisions
of
our
proposed
equipment
replacement
approach,
described
above,
it
would
be
excluded
from
NSR
under
the
proposal.
There
may,
however,
be
rare
instances
where
activities
do
not
involve
replacing
existing
equipment,
are
not
otherwise
excluded
from
NSR,
and
nevertheless
promote
efficiency.
Is
there
a
need
for
a
separate
``
stand­
alone''
exclusion
for
such
activities?
If
so,
should
there
be
other
limitations
on
the
scope
of
such
activities?
Are
there
activities
that
result
in
a
minor
improvement
in
efficiency
but
a
very
large
increase
in
annual
emissions?
If
so,
what
are
the
characteristics
of
such
activities
and
how
should
EPA
treat
them?
Today,
we
solicit
comment
broadly
on
the
impact
of
the
NSR
program
on
decisions
to
proceed
with
activities
that
produce
net
benefits
to
human
health
and
the
environment,
including,
but
not
limited,
to
energy
efficiency
activities.
We
also
solicit
comments
on
the
extent
to
which
our
proposals
can
promote
energy
efficiency
while
preserving
the
benefits
of
the
NSR
program.

D.
Quantitative
Analysis
We
have
attempted
to
analyze
quantitatively
the
possible
emissions
consequences
of
the
range
of
different
approaches
to
the
RMRR
exclusion
described
above
to
evaluate
if
our
policy
conclusions
are
correct.
Our
analysis
was
conducted
using
the
Integrated
Planning
Model
(
IPM).
This
analysis
was
done
for
electric
utilities
because
we
have
a
powerful
model
to
perform
such
an
analysis
that
we
do
not
have
for
other
industries.
We
think
the
results
for
the
electric
utilities
accurately
reflects
the
trends
we
would
see
in
other
industries.
This
model
and
technical
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251
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December
31,
2002
/
Proposed
Rules
information
describing
it
can
be
found
in
the
docket.
The
analysis
included
several
relevant
scenarios.
In
the
first
scenario,
we
assumed
that
efficiency
and
capacity
of
relevant
units
modestly
decrease
over
time.
This
scenario
was
intended
to
reflect
the
consequences
of
a
new
rule
with
a
relatively
``
narrow''
RMRR
exclusion,
under
which
we
would
assume
that
there
would
be
slow
and
steady
deterioration
of
relevant
generating
assets.
As
explained
above,
we
do
not
actually
believe
that
such
a
trend
would
occur
under
such
a
new
RMRR
exclusion,
because
plants
would
take
steps
to
limit
emissions
and
perhaps
implement
incremental
controls
to
recapture
lost
capacity.
Nevertheless,
we
believe
that
this
scenario
offers
a
bounding
analysis
for
seeing
whether
a
narrow
RMRR
exclusion
can
have
significant
emissions
benefits
because
our
model
assumes
well
controlled
and
highly
efficient
new
generating
assets
rather
than
recaptured
capacity
from
incrementally
better
controlled
existing
units.
In
the
other
scenarios,
we
assumed
that
utilization,
efficiency,
or
capacity
of
relevant
units
modestly
increases
over
time.
These
scenarios
were
intended
to
reflect
the
consequences
of
a
new
rule
with
a
``
broader''
RMRR
exclusion,
which
would
allow
facility
availability
and/
or
output
over
time
without
triggering
major
NSR.
These
scenarios
present
various
combinations
of
assumptions
on
possible
incremental
changes
to
relevant
operational
parameters
and
are
intended
to
encompass
the
range
of
possible
operational
outcomes
that
might
be
associated
with
the
proposed
RMRR
exclusion.
The
IPM
analyses
of
these
scenarios
proves
the
point
made
above,
that
the
breadth
of
the
RMRR
exclusion
would
have
no
practical
impact
on,
let
alone
being
the
controlling
factor
in
determining,
the
emissions
reductions
that
will
be
achieved
in
the
future
under
the
major
NSR
program.
The
analyses
show
that
emissions
of
SO2
are
essentially
the
same
under
all
scenarios.
This
stands
to
reason
because
nationwide
emissions
of
SO2
from
the
power
sector
are
capped
by
the
title
IV
Acid
Rain
Program.
For
NOX,
these
analyses
show
modest
relative
decreases
in
some
cases
and
modest
relative
increases
in
other
cases.
These
predicted
changes
represent
only
a
modest
fraction
of
nationwide
NOX
emissions
from
the
power
sector,
which
hover
around
4.3
million
tons
per
year
(
tpy).
At
this
time,
we
do
not
have
adequate
information
to
predict
with
confidence
which
modeled
scenario
is
most
likely
to
occur
if
the
options
under
consideration
are
adopted.
What
these
analyses
indicate,
however,
is
that
regardless
of
which
scenario
is
closest
to
what
comes
to
pass,
none
of
the
proposed
provisions
related
to
the
RMRR
exclusion
will
have
a
significant
impact
on
emissions
from
the
power
sector.
The
DOE
also
attempted
to
analyze
quantitatively
the
possible
emissions
consequences
of
the
range
of
different
approaches
to
the
RMRR
exclusion
described
above.
Using
the
National
Energy
Modeling
System
(
NEMS),
a
variety
of
changes
in
energy
efficiency
and
availability
were
evaluated,
as
well
as
the
effect
on
emissions
resulting
from
these
changes.
This
analysis
concluded
that
efficiency
improvements
resulting
from
increased
maintenance
are
expected
to
decrease
emissions,
whereas
availability
improvements
are
expected
to
increase
emissions.
In
the
cases
represented
in
this
analysis,
the
impacts
of
the
assumed
reductions
in
heat
rates
tend
to
dominate
the
corresponding
effects
of
the
assumed
availability
increases.
Data
regarding
the
emissions
reductions
that
are
achieved
under
other
CAA
programs
further
illustrate
the
relative
limits
of
the
major
NSR
program
as
a
tool
for
achieving
significant
emissions
reductions.
For
example,
the
title
IV
Acid
Rain
Program
has
reduced
SO2
emissions
from
the
electric
utility
industry
by
more
than
7
million
tpy
and
will
ultimately
result
in
reductions
of
approximately
10
million
tpy.
The
Tier
2
motor
vehicle
emissions
standards
and
gasoline
sulfur
control
requirements
will
ultimately
achieve
NOX
reductions
of
2.8
million
tpy.
Standards
for
highway
heavy­
duty
vehicles
and
engines
will
reduce
NOX
emissions
by
2.6
million
tpy.
Standards
for
non­
road
diesel
engines
are
anticipated
to
reduce
NOX
emissions
by
about
1.5
million
tpy.
The
NOX
``
SIP
call''
will
reduce
NOX
emissions
by
over
1
million
tpy.
Altogether,
these
and
other
similar
programs
achieve
emissions
reductions
that
far
exceed
those
attributable
to
the
major
NSR
program
and
dwarf
any
possible
emissions
consequences
attributable
to
future
promulgation
of
a
rule
based
on
today's
proposal.
A
copy
of
our
IPM
analysis
and
the
DOE
NEMS
analysis
are
included
in
the
docket
for
this
rulemaking.
We
ask
for
comment
on
all
aspects
of
these
analyses
and
on
the
policy
discussion
provided
above.

VIII.
Other
Options
Considered
In
addition
to
the
cost­
based
approaches
discussed
above,
we
are
considering
two
additional
options
for
addressing
RMRR.
These
options
are
discussed
below,
and
we
are
requesting
comment
on
these
options.
We
are
also
interested
in
other
possible
alternatives.

A.
Capacity­
Based
Option
We
are
considering
the
alternative
option
of
developing
an
RMRR
provision
based
on
the
capacity
of
a
process
unit.
Under
such
an
approach,
an
owner
or
operator
could
undertake
any
activity
that
did
not
increase
the
capacity
of
the
process
unit.
Such
an
approach
would
require
safeguards
similar
to
those
in
the
proposed
costbased
approaches
in
order
to
ensure
that
activities
that
should
be
subject
to
the
NSR
program
are
not
inappropriately
excluded.
These
safeguards
would
exclude
the
construction
of
a
new
process
unit,
the
replacement
of
an
entire
process
unit,
and
activities
that
result
in
an
increase
in
maximum
achievable
hourly
emissions
rate
of
a
regulated
NSR
pollutant
from
use
of
the
exclusion
or
the
emission
of
any
regulated
NSR
pollutant
not
previously
emitted
by
the
stationary
source.
Basing
RMRR
on
capacity
is
appealing
for
several
reasons.
The
primary
objective
of
RMRR
is
to
keep
a
unit
operating
at
capacity
and/
or
availability.
In
addition,
the
linkage
between
capacity
and
environmental
impact
is
more
apparent
than
cost
and
environmental
impact.
Finally,
this
type
of
approach
might,
in
principle,
be
easier
to
use
before
beginning
actual
construction
than
the
cost­
based
approaches.
The
difficulty
with
using
a
capacitybased
approach
is
defining
the
capacity
of
a
process
unit.
Capacity
may
be
defined
based
on
input
or
output.
Nameplate
capacity
of
a
process
unit
may
vary
greatly
from
the
capacity
at
which
the
process
unit
may
be
able
to
operate.
It
may
be
more
appropriate
in
some
industries
to
measure
capacity
based
on
input
while
in
others
on
output.
As
an
example,
in
a
review
of
promulgated
and
proposed
Maximum
Achievable
Control
Technology
standards,
six
of
eleven
standards
measured
capacity
based
on
unit
output
while
five
based
capacity
on
input.
In
fact,
the
NSPS
exclusion
for
increases
in
production
rate
at
40
CFR
60.14(
e)
originally
was
dependent
upon
the
``
operating
design
capacity''
of
an
affected
unit.
In
proposed
revisions
to
the
NSPS
program
published
on
October
15,
1974,
we
state
(
39
FR
36948):

The
exemption
of
increases
in
production
rate
is
no
longer
dependent
upon
the
``
operating
design
capacity.''
This
term
is
not
easily
defined,
and
for
certain
industries
the
``
design
capacity''
bears
little
relationship
to
the
actual
operating
capacity
of
the
facility.

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2002
/
Proposed
Rules
We
are
requesting
comment
on
this
capacity­
based
option,
as
well
as
comments
on
possible
methods
to
address
any
of
the
issues
relating
to
implementation
of
such
an
option.

B.
Age­
Based
Option
Under
an
age­
based
approach,
any
process
unit
under
a
specified
age
could
undergo
any
activity
that
does
not
increase
the
capacity
of
a
process
unit
on
a
maximum
hourly
basis
without
triggering
the
requirements
of
the
major
NSR
program.
However,
the
activities
could
not
constitute
reconstruction
of
the
process
unit;
that
is,
their
cost
could
not
exceed
50
percent
of
the
cost
of
a
replacement
process
unit.
The
age
of
the
process
unit
would
likely
be
in
the
range
of
25
 
50
years.
An
owner
or
operator
would
have
to
become
a
Clean
Unit
as
defined
at
40
CFR
51.165(
c)(
3),
51.166(
t)(
3),
and
52.21(
x)(
3),
once
the
age
of
a
process
unit
exceeds
the
age
threshold.
Such
an
approach
would
provide
an
owner
or
operator
a
clear
understanding
of
RMRR
for
an
extended
period
of
time.
It
also
may
provide
the
owner
or
operator
greater
flexibility
than
under
the
current
system
for
a
limited
period
of
time.
Like
the
capacity­
based
approach,
this
approach
would,
in
principle,
allow
for
a
fairly
simple
preconstruction
determination
of
applicability.
We
see
several
difficulties
in
developing
this
type
of
approach.
The
first
is
defining
capacity.
The
second
is
establishing
the
age
cut­
off
for
the
exclusion.
The
useful
life
of
equipment
is
difficult
to
establish
and
may
vary
greatly.
The
third
is
that
some
of
the
activities
that
would
be
allowed
at
newer
sources
do
not
fit
within
any
ordinary
meaning
of
RMRR
and
some
of
the
activities
that
would
be
forbidden
at
older
facilities
would
come
within
that
meaning.
Fourth,
some
sources
may
consciously,
and
appropriately,
engage
in
aggressive
RMRR
as
a
method
of
maximizing
the
life
span
of
its
process
units,
and
an
age­
based
approach
would
discriminate
against
them.
We
are
requesting
comment
on
this
age­
based
option,
as
well
as
comments
on
possible
methods
to
address
the
issues
raised
above
with
respect
to
this
option.

IX.
Administrative
Requirements
for
This
Proposed
Rulemaking
A.
Executive
Order
12866
 
Regulatory
Planning
and
Review
Under
Executive
Order
12866
[
58
FR
51,735
(
October
4,
1993)],
we
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligations
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
OMB
has
notified
us
that
it
considers
this
an
``
economically
significant
regulatory
action''
within
the
meaning
of
the
Executive
Order.
We
have
submitted
this
action
to
OMB
for
review.
Changes
made
in
response
to
OMB
suggestions
or
recommendations
will
be
documented
in
the
public
record.
All
written
comments
from
OMB
to
EPA
and
any
written
EPA
response
to
any
of
those
comments
are
included
in
the
docket
listed
at
the
beginning
of
this
notice
under
ADDRESSES.
In
addition,
consistent
with
Executive
Order
12866,
EPA
consulted
extensively
with
the
State,
local
and
tribal
agencies
that
will
be
affected
by
this
rule.
We
have
also
sought
involvement
from
industry
and
public
interest
groups.

B.
Executive
Order
13132
 
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
are
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
This
proposed
rule
does
not
have
federalism
implications.
Nevertheless,
in
developing
this
rule,
we
consulted
with
affected
parties
and
interested
stakeholders,
including
State
and
local
authorities,
to
enable
them
to
provide
timely
input
in
the
development
of
this
rule.
A
summary
of
stakeholder
involvement
appears
above
in
section
III.
C.
of
today's
proposed
rule.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
State
and
local
programs,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
While
this
proposed
rule
will
result
in
some
expenditures
by
the
States,
we
expect
those
expenditures
to
be
limited
to
$
580,160
for
the
estimated
112
affected
reviewing
authorities.
This
figure
includes
the
small
increase
in
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
revise
the
State's
State
Implementation
Plan
(
SIP).
However,
this
revision
provides
sources
permitted
by
the
States
greater
certainty
in
application
of
the
program,
which
should
in
turn
reduce
the
overall
burden
of
the
program
on
State
and
local
authorities.
Thus,
the
requirements
of
Executive
Order
13132
do
not
apply
to
this
rule.

C.
Executive
Order
13175
 
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
EPA
believes
that
this
proposed
rule
does
not
have
tribal
implications
as
specified
in
Executive
Order
13175.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
The
purpose
of
today's
proposed
rule
is
to
add
greater
flexibility
to
the
existing
major
NSR
regulations.
These
changes
will
benefit
reviewing
authorities
and
the
regulated
community,
including
any
major
source
owned
by
a
tribal
government
or
located
in
or
near
tribal
land,
by
providing
increased
certainty
as
to
when
the
requirements
of
the
NSR
program
apply.
Taken
as
a
whole,
today's
proposed
rule
should
result
in
no
added
burden
or
compliance
costs
and
should
not
substantially
change
the
level
of
environmental
performance
achieved
under
the
previous
rules.
The
EPA
anticipates
that
initially
these
changes
will
result
in
a
small
increase
in
the
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
be
included
in
the
State's
SIP.
Nevertheless,
these
options
and
revisions
will
ultimately
provide
greater
operational
flexibility
to
sources
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Proposed
Rules
permitted
by
the
States,
which
will
in
turn
reduce
the
overall
burden
on
the
program
on
State
and
local
authorities
by
reducing
the
number
of
required
permit
modifications.
In
comparison,
no
tribal
government
currently
has
an
approved
Tribal
Implementation
Plan
(
TIP)
under
the
CAA
to
implement
the
NSR
program.
The
Federal
government
is
currently
the
NSR
reviewing
authority
in
Indian
country.
Thus,
tribal
governments
should
not
experience
added
burden,
nor
should
their
laws
be
affected
with
respect
to
implementation
of
this
rule.
Additionally,
although
major
stationary
sources
affected
by
today's
proposed
rule
could
be
located
in
or
near
Indian
country
and/
or
be
owned
or
operated
by
tribal
governments,
such
affected
sources
would
not
incur
additional
costs
or
compliance
burdens
as
a
result
of
this
rule.
Instead,
the
only
effect
on
such
sources
should
be
the
benefit
of
the
added
certainty
and
flexibility
provided
by
the
rule.
The
EPA
recognizes
the
importance
of
including
tribal
consultation
as
part
of
the
rulemaking
process.
Nonetheless,
to
this
point
we
have
not
specifically
consulted
with
tribal
officials
on
this
proposed
rule.
We
are
committed
to
work
with
any
tribal
government
to
resolve
any
issues
that
we
may
have
overlooked
in
today's
proposed
rules
and
that
may
have
an
adverse
impact
in
Indian
country.
As
a
result,
today
we
are
announcing
our
intention
to
develop
and
implement
a
consultation
process
with
tribal
governments
to
ensure
that
the
concerns
of
tribal
officials
are
considered
before
finalizing
this
proposed
rule.
EPA
specifically
solicits
additional
comment
on
this
proposed
rule
from
tribal
officials.

D.
Executive
Order
13045
 
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045,
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that
(
1)
is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
we
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonable
alternatives
that
we
considered.
This
proposed
rule
is
not
subject
to
Executive
Order
13045,
because
we
do
not
have
reason
to
believe
the
environmental
health
or
safety
risks
addressed
by
this
action
present
a
disproportionate
risk
to
children.
We
believe
that
this
package
as
a
whole
will
result
in
equal
or
better
environmental
protection
than
currently
provided
by
the
existing
regulations,
and
do
so
in
a
more
streamlined
and
effective
manner.

E.
Paperwork
Reduction
Act
The
EPA
prepared
an
Information
Collection
Request
(
ICR)
document
(
ICR
No.
1713.04).
You
may
obtain
a
copy
from
Sandy
Farmer
by
mail
at
the
U.
S.
Environmental
Protection
Agency,
Office
of
Environmental
Information,
Collection
Strategies
Division
(
2822),
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460
 
0001,
by
e­
mail
at
farmer.
sandy@
epa.
gov,
or
by
calling
(
202)
260
 
2740.
A
copy
may
also
be
downloaded
from
the
internet
at
http://
www.
epa.
gov/
icr.
The
information
that
ICR
No.
1713.04
covers
is
required
for
EPA
to
carry
out
its
required
oversight
function
of
reviewing
preconstruction
permits
and
assuring
adequate
implementation
of
the
program.
In
order
to
carry
out
its
oversight
function,
EPA
must
have
available
to
it
information
on
proposed
construction
and
modifications.
This
information
collection
is
necessary
for
the
proper
performance
of
EPA's
functions,
has
practical
utility,
and
is
not
unnecessarily
duplicative
of
information
we
otherwise
can
reasonably
access.
We
have
reduced,
to
the
extent
practicable
and
appropriate,
the
burden
on
persons
providing
the
information
to
or
for
EPA.
The
collection
of
information
is
authorized
under
42
U.
S.
C.
7401
et
seq.
According
to
ICR
No.
1713.04,
the
first
3
years
of
this
proposed
rulemaking
will
potentially
incur
a
burden
of
17,400
hours
and
1,305,000
dollars
to
affected
sources,
and
2,906
hours
and
107,522
dollars
for
the
Federal
government,
and
15,680
hours
and
580,160
hours
for
reviewing
authorities.
These
costs
are
based
upon
an
estimated
number
of
1,450
affected
sources.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purpose
of
responding
to
the
information
collection;
adjust
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
respond
to
a
collection
of
information;
search
existing
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
We
will
continue
to
present
OMB
control
numbers
in
a
consolidated
table
format
to
be
codified
in
40
CFR
part
9
of
the
Agency's
regulations,
and
in
each
CFR
volume
containing
EPA
regulations.
The
table
lists
the
section
numbers
with
reporting
and
record
keeping
requirements,
and
the
current
OMB
control
numbers.
This
listing
of
the
OMB
control
numbers
and
their
subsequent
codification
in
the
CFR
satisfy
the
requirements
of
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.)
and
OMB's
implementing
regulations
at
5
CFR
part
1320.

F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
Any
small
business
employing
fewer
than
500
employees;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not­
for­
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
In
determining
whether
a
rule
has
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
the
impact
of
concern
is
any
significant
adverse
economic
impact
on
small
entities,
since
the
primary
purpose
of
the
regulatory
flexibility
analyses
is
to
identify
and
address
regulatory
alternatives
``
which
minimize
any
significant
economic
impact
of
the
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2002
/
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Rules
proposed
rule
on
small
entities.''
5
U.
S.
C.
603
and
604.
Thus,
an
agency
may
certify
that
a
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
if
the
rule
relieves
regulatory
burden,
or
otherwise
has
a
positive
economic
effect
on
all
of
the
small
entities
subject
to
the
rule.
Today's
proposed
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
because
it
will
decrease
the
regulatory
burden
of
the
existing
regulations
and
have
a
positive
effect
on
all
small
entities
subject
to
the
rule.
This
rule
improves
operational
flexibility
for
owners
and
operators
of
major
stationary
sources
and
clarifies
applicable
requirements
for
determining
if
a
change
qualifies
as
a
major
modification.
We
have
therefore
concluded
that
today's
proposed
rule
will
relieve
regulatory
burden
for
all
small
entities.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.

G.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
 
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
UMRA,
we
generally
must
prepare
a
written
statement,
including
a
cost­
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector
of
$
100
million
or
more
in
any
one
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
us
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
least
costly,
most
cost­
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
our
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
believe
the
proposed
rule
changes
will
actually
reduce
the
regulatory
burden
associated
with
the
major
NSR
program
by
improving
the
operational
flexibility
of
owners
and
operators
and
clarifying
the
requirements.
Because
the
program
changes
provided
in
the
proposed
rule
are
not
expected
to
result
in
any
increases
in
the
expenditure
by
State,
local,
and
tribal
governments,
or
the
private
sector,
we
have
not
prepared
a
budgetary
impact
statement
or
specifically
addressed
the
selection
of
the
least
costly,
most
cost­
effective,
or
least
burdensome
alternative.
Because
small
governments
will
not
be
significantly
or
uniquely
affected
by
this
rule,
we
are
not
required
to
develop
a
plan
with
regard
to
small
governments.
Therefore,
this
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.

H.
National
Technology
Transfer
and
Advancement
Act
of
1995
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(
NTTAA),
Public
Law
No.
104
 
113,
section
12(
d)
(
15
U.
S.
C.
272
note)
directs
us
to
use
voluntary
consensus
standards
(
VCS)
in
our
regulatory
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
VCS
are
technical
standards
(
for
example,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
voluntary
consensus
standards
bodies.
The
NTTAA
directs
us
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
VCS.
Although
this
rule
does
involve
the
use
of
technical
standards,
it
does
not
preclude
the
State,
local,
and
tribal
reviewing
agencies
from
using
VCS.
Today's
proposed
rulemaking
is
an
improvement
of
the
existing
NSR
permitting
program.
As
such,
it
only
ensures
that
promulgated
technical
standards
are
considered
and
appropriate
controls
are
installed,
prior
to
the
construction
of
major
sources
of
air
emissions.
Therefore,
we
are
not
considering
the
use
of
any
VCS
in
today's
rulemaking.
I.
Executive
Order
13211
 
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
proposed
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355
(
May
22,
2001))
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution
or
use
of
energy.
Today's
proposed
rule
improves
the
ability
of
sources
to
maintain
the
reliability
of
production
facilities,
and
effectively
utilize
and
improve
existing
capacity.

X.
Statutory
Authority
The
statutory
authority
for
this
action
is
provided
by
sections
101,
111,
114,
116,
and
301
of
the
CAA
as
amended
(
42
U.
S.
C.
7401,
7411,
7414,
7416,
and
7601).
This
rulemaking
is
also
subject
to
section
307(
d)
of
the
CAA
(
42
U.
S.
C.
7407(
d)).

List
of
Subjects
in
40
CFR
Parts
51
and
52
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.

Dated:
November
22,
2002.
Christine
Todd
Whitman,
Administrator.

For
the
reasons
set
out
in
the
preamble,
title
40,
chapter
I
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:

PART
51
 
[
AMENDED]

1.
The
authority
citation
for
part
51
continues
to
read
as
follows:

Authority:
23
U.
S.
C.
101;
42
U.
S.
C.
7401
 
7671q.

Subpart
I
 
[
Amended]

2.
Section
51.165
is
amended:
a.
By
revising
paragraph
(
a)(
1)(
v)(
C)(
1).
b.
By
adding
paragraphs
(
a)(
1)(
xliii)
through
(
xlvii).
The
revision
and
additions
read
as
follows:

§
51.165
Permit
requirements.

(
a)
*
*
*
(
1)
*
*
*
(
v)
*
*
*
(
C)
*
*
*
(
1)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
(
a)(
1)(
v)(
C)(
1)(
i)
and
(
ii)
of
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1
EPA
has
not
determined
this
value.
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
(
a)(
1)(
v)(
C)(
1)(
i)
and
(
ii)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
i)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
(
a)(
1)(
xliii)
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
(
a)(
1)(
xliii)(
A)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
ii)
The
replacement
of
components
of
a
process
unit
with
identical
or
functionally
equivalent
components,
provided
that:
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
the
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
nonutilities
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
(
a)(
1)(
xlv)
and
(
a)(
1)(
xlvi)
of
this
section,
respectively.
*
*
*
*
*
(
xliii)
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
×
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.
TABLE
1
OF
§
51.165(
A)(
1)(
XLIII).
 
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
Other
(
A)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
1)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
2)
Costs
incurred
for
all
activities
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source
that
are
not
excluded
under
paragraph
(
a)(
1)(
xliii)(
B)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
i)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
ii)
All
activities
prior
to
the
point
on
the
cost­
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
3)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
4)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
B)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
1)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
2)
Constitutes
construction
of
a
new
process
unit;
or
(
3)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
(
xliv)(
A)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
B)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
1)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal­
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
2)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
3)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
4)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
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251
/
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December
31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
5)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
(
xlv)
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
(
xlvi)
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
(
a)(
1)(
xlvii)
of
this
section.
(
xlvii)
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*
3.
Section
51.166
is
amended:
a.
By
revising
paragraph
(
b)(
2)(
iii)(
a).
b.
By
adding
paragraphs
(
b)(
53)
through
(
57).
The
revision
and
additions
read
as
follows:

§
51.166
Prevention
of
significant
deterioration
of
air
quality.

*
*
*
*
*
(
b)
*
*
*
(
2)
*
*
*
(
iii)
*
*
*
(
a)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
(
b)(
2)(
iii)(
a)(
1)
and
(
2)
of
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
(
b)(
2)(
iii)(
a)(
1)
and
(
2)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
1)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
(
b)(
53)
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
(
b)(
53)(
i)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
2)
The
replacement
of
components
of
a
process
unit
with
identical
or
functionally
equivalent
components,
provided
that:
(
i)
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
(
ii)
The
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
non­
utilities,
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
(
b)(
55)
and
(
b)(
56)
of
this
section.
*
*
*
*
*
(
53)
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
×
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.

TABLE
1
OF
§
51.166(
B)(
53).
 
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
Other
(
i)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
a)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
b)
Costs
incurred
for
all
activities
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore,
or
improve
the
efficiency,
reliability,
availability,
or
safety
of
that
stationary
source
that
are
not
excluded
under
paragraph
(
b)(
53)(
ii)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
1)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
2)
All
activities
prior
to
the
point
on
the
cost­
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
c)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
d)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
ii)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
a)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
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Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
b)
Constitutes
construction
of
a
new
process
unit;
or
(
c)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
(
54)(
i)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
ii)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
a)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal­
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
b)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
c)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
d)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
e)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
(
55)
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
(
56)
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
(
b)(
57)
of
this
section.
(
57)
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*

Appendix
S
 
[
Amended]

4.
In
Appendix
S
to
Part
51
Section
II
is
amended:
a.
By
revising
paragraph
A.
5(
iii)
(
a).
b.
By
adding
paragraphs
A.
21
through
25.
The
revision
and
additions
read
as
follows:

Appendix
S
to
part
51
 
Emission
Offset
Interpretative
Ruling
*
*
*
*
*

II.
Initial
Screening
Analyses
and
Determination
of
Applicable
Requirements
A.
*
*
*
5.
*
*
*
(
iii)
*
*
*
(
a)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
A.
5
(
iii)(
a)(
1)
and
(
2)
of
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
A.
5
(
iii)(
a)(
1)
and
(
2)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
1)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
A.
21
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
A.
21
(
i)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
2)
The
replacement
of
components
of
a
process
unit
with
identical
or
functionally
equivalent
components,
provided
that:
(
i)
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
(
ii)
The
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
non­
utilities,
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
A.
23
and
A.
24
of
this
section,
respectively.
*
*
*
*
*
21.
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
×
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.

TABLE
1.
OF
SECTION
II.
A.
21.
 
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
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67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
TABLE
1.
OF
SECTION
II.
A.
21.
 
INDUSTRY
SECTOR
PERCENTAGES
 
Continued
Industry
sector
Industry
sector
percentage
Other
(
i)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
a)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
b)
Costs
incurred
for
all
activities
not
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source
that
are
not
excluded
under
A.
21
(
ii)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
1)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
2)
All
activities
prior
to
the
point
on
the
cost­
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
c)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
d)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
ii)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
a)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
b)
Constitutes
construction
of
a
new
process
unit;
or
(
c)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
22.
(
i)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
ii)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
a)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal­
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boilers,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
b)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
c)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
d)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
e)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
23.
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
24.
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
A.
25
of
this
section.
25.
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.

*
*
*
*
*

PART
52
 
[
AMENDED]

1.
The
authority
citation
for
part
52
continues
to
read
as
follows:

Authority:
42
U.
S.
C.
7401,
et
seq.

Subpart
A
 
[
Amended]

2.
Section
52.21
is
amended:
a.
By
revising
paragraph
(
b)(
2)(
iii)(
a).
b.
By
adding
paragraphs
(
b)(
55)
through
(
59).
The
revision
and
additions
are
revised
to
read
as
follows:

§
52.21
Prevention
of
significant
deterioration
of
air
quality.

*
*
*
*
*
(
b)
*
*
*
(
2)
*
*
*
(
iii)
*
*
*
(
a)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
(
b)(
2)(
iii)(
a)(
1)
and
(
2)
of
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
(
b)(
2)(
iii)(
a)(
1)
and
(
2)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
1)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
(
b)(
55)
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
(
b)(
55)(
i)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
2)
The
replacement
of
components
of
a
process
unit
with
identical
or
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
functionally
equivalent
components,
provided
that:
(
i)
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
(
ii)
The
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
non­
utilities,
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
(
b)(
57)
and
(
b)(
58)
of
this
section.
*
*
*
*
*
(
55)
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
x
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.

TABLE
1
OF
§
52.21(
B)(
55).
 
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
Other
(
i)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
a)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
b)
Costs
incurred
for
all
activities
not
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source
that
are
not
excluded
under
paragraph
(
b)(
55)(
ii)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
1)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
2)
All
activities
prior
to
the
point
on
the
cost­
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
c)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
d)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
ii)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
a)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
b)
Constitutes
construction
of
a
new
process
unit;
or
(
c)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
(
56)
(
i)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
ii)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
a)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal­
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
b)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
c)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
d)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
e)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
(
57)
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
(
58)
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
(
b)(
59)
of
this
section.
(
59)
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
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251
/
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31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*
3.
Section
52.24
is
amended:
a.
By
revising
paragraph
(
f)(
5)(
iii)(
a).
b.
By
adding
paragraphs
(
f)(
25)
through
(
29).
The
revision
and
additions
read
as
follows:

§
52.24
Statutory
restriction
on
new
sources.

*
*
*
*
*
(
f)
*
*
*
(
5)
*
*
*
(
iii)
*
*
*
(
a)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
(
f)(
5)(
iii)(
a)(
1)
and
(
2)
of
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
(
f)(
5)(
iii)(
a)(
1)
and
(
2)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
1)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
(
f)(
25)
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
(
f)(
25)(
i)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
2)
The
replacement
of
components
of
a
process
unit
with
identical
or
functionally
equivalent
components,
provided
that:
(
i)
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
(
ii)
The
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
non­
utilities,
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
(
f)(
27)
and
(
f)(
28)
of
this
section,
respectively.
*
*
*
*
*
(
25)
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
x
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.

TABLE
1
OF
§
52.24(
F)(
25).
 
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
Other
(
i)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
a)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
b)
Costs
incurred
for
all
activities
not
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source
that
are
not
excluded
under
paragraph
(
f)(
25)(
ii)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
1)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
2)
All
activities
prior
to
the
point
on
the
cost­
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
c)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
d)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
ii)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
a)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
b)
Constitutes
construction
of
a
new
process
unit;
or
(
c)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
(
26)
(
i)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
ii)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
a)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal­
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
b)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
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/
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December
31,
2002
/
Proposed
Rules
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
c)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
d)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
e)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
(
27)
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
(
28)
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
(
f)(
29)
of
this
section.
(
29)
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*
[
FR
Doc.
02
 
31900
Filed
12
 
30
 
02;
8:
45
am]

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