Internal
and
Deliberative
Draft
­
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not
quote,
cite,
copy,
or
distribute
August
22,
2003
1
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
51
and
52
[
FRL­
6212­
3;
Electronic
Docket
OAR­
2002­
0068;

Legacy
Docket
A­
2002­
04]

Prevention
of
Significant
Deterioration
(
PSD)
and
Nonattainment
New
Source
Review
(
NSR):
Equipment
Replacement
Provision
of
the
Routine
Maintenance,
Repair
and
Replacement
Exclusion
AGENCY:
Environmental
Protection
Agency
(
EPA).

ACTION:
Final
Rule.

SUMMARY:
The
EPA
is
finalizing
revisions
to
the
regulations
governing
the
NSR
programs
mandated
by
parts
C
and
D
of
title
I
of
the
Clean
Air
Act
(
CAA).
Today's
changes
reflect
EPA's
incorporation
of
comments
from
the
proposed
rule
for
"
Prevention
of
Significant
Deterioration
(
PSD)
and
Nonattainment
New
Source
Review
(
NSR):
Routine
Maintenance,

Repair
and
Replacement"
(
67
FR
80290;
December
31,
2002).

These
changes
provide
a
category
of
equipment
replacement
activities
that
are
exempt
from
Major
NSR
requirements
under
the
routine
maintenance,
repair
and
replacement
(
RMRR)

exclusion.
The
changes
are
intended
to
provide
greater
regulatory
certainty
without
sacrificing
the
current
level
of
environmental
protection
and
benefit
derived
from
the
NSR
program.
We
believe
that
these
changes
will
facilitate
the
Internal
and
Deliberative
Draft
­
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not
quote,
cite,
copy,
or
distribute
August
22,
2003
2
safe,
efficient,
and
reliable
operation
of
affected
facilities.

EFFECTIVE
DATE:
This
final
rule
is
effective
on
[
INSERT
DATE
60
DAYS
AFTER
PUBLICATION
IN
THE
FEDERAL
REGISTER].

ADDRESSES:
Docket.
Docket
No.
A­
2002­
04
(
Electronic
docket
OAR­
2002­
0068),
containing
supporting
information
used
to
develop
the
proposed
rule
and
today's
final
rule,
is
available
for
public
inspection
and
copying
between
8:
00
a.
m.
and
4:
30
p.
m.,
Monday
through
Friday
(
except
government
holidays)
at
the
Air
and
Radiation
Docket
and
Information
Center
(
6102T),
Room
B­
108,
EPA
West
Building,
1301
Constitution
Avenue,
NW,
Washington,
D.
C.
20460;
telephone
(
202)
566­
1742,
fax
(
202)
566­
1741.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.

Worldwide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
this
final
rule
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature,
a
copy
of
the
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules:

http://
www.
epa.
gov/
ttn/
oarpg.

FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Dave
Svendsgaard,

Information
Transfer
and
Program
Integration
Division
(
C339­

03),
U.
S.
EPA
Office
of
Air
Quality
Planning
and
Standards,
Internal
and
Deliberative
Draft
­
Do
not
quote,
cite,
copy,
or
distribute
August
22,
2003
3
Research
Triangle
Park,
North
Carolina
27711,
telephone
919­

541­
2380,
or
electronic
mail
at
svendsgaard.
dave@
epa.
gov,

for
questions
on
this
rule.

SUPPLEMENTARY
INFORMATION
Regulated
Entities
Entities
potentially
affected
by
this
final
action
include
sources
in
all
industry
groups.
The
majority
of
sources
potentially
affected
are
expected
to
be
in
the
following
groups:

Industry
Group
SICa
NAICSb
Electric
Services
491
221111,
221112,
221113,

221119,
221121,
221122
Petroleum
Refining
291
324110
Industrial
Inorganic
Chemicals
281
325181,
325120,
325131,

325182,
211112,
325998,

331311,
325188
Industrial
Organic
Chemicals
286
325110,
325132,
325192,

325188,
325193,
325120,

325199
Miscellaneous
Chemical
Products
289
325520,
325920,
325910,

325182,
325510
Natural
Gas
Liquids
132
211112
Natural
Gas
Transport
492
486210,
221210
Pulp
and
Paper
Mills
261
322110,
322121,
322122,

322130
Paper
Mills
262
322121,
322122
Internal
and
Deliberative
Draft
­
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not
quote,
cite,
copy,
or
distribute
August
22,
2003
4
Automobile
Manufacturing
371
336111,
336112,
336211,

336992,
336322,
336312,

336330,
336340,
336350,

336399,
336212,
336213
Pharmaceuticals
283
325411,
325412,
325413,

325414
a
Standard
Industrial
Classification
b
North
American
Industry
Classification
System.

Entities
potentially
affected
by
this
final
action
also
include
State,
local,
and
tribal
governments
that
are
delegated
authority
to
implement
these
regulations.

Outline
The
information
presented
in
this
preamble
is
organized
as
follows:

I.
General
Information
A.
How
can
I
get
copies
of
this
document
and
other
related
information?
1.
Docket
2.
Electronic
Access
B.
Where
can
I
obtain
additional
information?
II.
Background
A.
What
is
the
RMRR
exclusion?
B.
Why
is
the
specification
of
categories
of
RMRR
activities
appropriate?
C.
Process
Used
to
Develop
This
Rule
D.
What
We
Proposed
III.
Equipment
Replacement
Provision
A.
Overview
and
Justification
for
Today's
Final
Action
B.
What
is
an
identical
or
functionally
equivalent
replacement
and
why
is
such
an
activity
RMRR?
C.
What
cost
limit
has
been
placed
on
the
equipment
replacement
approach?
D.
What
will
be
the
basis
of
applying
the
20­
percent
threshold?
E.
What
basic
design
parameters
are
being
established
Internal
and
Deliberative
Draft
­
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quote,
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or
distribute
August
22,
2003
5
to
qualify
for
the
equipment
replacement
provision?
F.
What
collection
of
equipment
should
be
considered
in
applying
the
equipment
replacement
provision
and
how
should
it
be
defined?
G.
Consideration
of
Non­
emitting
Units
as
Part
of
the
Process
Unit
H.
What
is
the
accounting
basis
for
the
process
unit?
I.
Enforcement
J.
Quantitative
Analysis
K.
Consideration
of
Other
Options
1.
Annual
Maintenance,
Repair
and
Replacement
Allowance
2.
Capacity­
Based
Option
3.
Age­
Based
Option
L.
Specific
List
of
Excluded
Activities
M.
Stand­
alone
Exclusion
for
Energy
Efficiency
Projects
N.
Legal
Basis
IV.
Administrative
Requirements
for
This
Rule
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
J.
Executive
Order
12988
­
Civil
Justice
Reform
V.
Effective
Date
for
Today's
Requirements
VI.
Statutory
Authority
I.
General
Information
A.
How
can
I
get
copies
of
this
document
and
other
related
information?

1.
Docket.
EPA
has
established
an
official
public
docket
Internal
and
Deliberative
Draft
­
Do
not
quote,
cite,
copy,
or
distribute
August
22,
2003
6
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
Internal
and
Deliberative
Draft
­
Do
not
quote,
cite,
copy,
or
distribute
August
22,
2003
7
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
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
in
section
I.
A.
1.
of
this
preamble.
EPA
intends
to
work
towards
providing
electronic
access
to
all
of
the
publicly
available
docket
materials
through
EPA's
electronic
public
docket.

For
additional
information
about
EPA's
electronic
Internal
and
Deliberative
Draft
­
Do
not
quote,
cite,
copy,
or
distribute
August
22,
2003
1
We
broadly
use
the
term
"
New
Source
Review,"
or
NSR,
to
encompass
both
the
PSD
and
the
Non­
attainment
New
Source
Review
program.

8
public
docket
visit
EPA
Dockets
online
or
see
67
FR
38102,

May
31,
2002.

B.
Where
can
I
obtain
additional
information?

In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
today's
final
rule
is
also
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).

Following
signature
by
the
EPA
Administrator,
a
copy
of
this
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.

II.
Background
A.
What
is
the
RMRR
exclusion?

Under
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
NSR1
pollutant
or
emission
of
a
new
pollutant;
and
(
2)
a
significant
net
emissions
increase
of
that
pollutant
from
Internal
and
Deliberative
Draft
­
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not
quote,
cite,
copy,
or
distribute
August
22,
2003
2
Once
a
modification
is
determined
to
be
major,
NSR
requirements
apply
only
to
those
specific
NSR
pollutants
for
which
there
would
be
a
significant
net
emissions
increase.

9
the
major
stationary
source.
2
Owners
and
operators
of
major
stationary
sources
are
required
to
obtain
major
NSR
permits
prior
to
beginning
actual
construction
of
a
modification
that
meets
this
definition.
The
regulations
provide
that
certain
activities
do
not
constitute
a
"
physical
change
or
change
in
the
method
of
operation"
under
the
definition
of
"
major
modification."
One
category
of
such
activities
is
routine
maintenance,
repair
and
replacement
(
RMRR).
Until
today,
the
NSR
regulations
have
not
further
specified
what
types
of
activities
are
encompassed
by
this
term.

B.
Why
is
the
specification
of
categories
of
RMRR
activities
appropriate?

In
the
past,
the
RMRR
exclusion
has
been
applied
on
a
case­
by­
case
basis.
However,
this
case­
by­
case
approach
has
certain
drawbacks.
Unless
an
owner
or
operator
seeks
an
applicability
determination
from
his
or
her
reviewing
authority,
it
can
be
difficult
for
the
owner
or
operator
to
know
with
certainty
whether
a
particular
activity
constitutes
RMRR.
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
where
uncertainty
about
the
interpretation
of
the
exclusion
for
RMRR
has
resulted
in
delay
or
cancellation
of
activities
that
would
have
Internal
and
Deliberative
Draft
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or
distribute
August
22,
2003
10
maintained
and
improved
the
reliability,
efficiency,
and
safety
of
existing
energy
capacity.

Applicability
determinations
can
be
costly
and
time
consuming
for
reviewing
authorities
and
industry
alike.
If
a
source
proceeds
without
a
reviewing
authority
determination
and
is
later
found
to
have
made
an
incorrect
determination
on
its
own,
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
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.
Industry
commenters
strongly
echoed
these
concerns,
expressing
that
the
expense
and
delay
associated
with
NSR
scrutiny,
whether
or
not
the
project
is
ultimately
judged
to
be
subject
to
major
NSR,
has
caused
a
number
of
facilities
to
forego
Internal
and
Deliberative
Draft
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distribute
August
22,
2003
11
needed
and
beneficial
maintenance,
repair,
and
replacement
projects,
including
ones
that
would
likely
have
reduced
emissions.
In
our
June
2002
report
to
the
President,
we
similarly
concluded
that
the
NSR
program
has
impeded
or
resulted
in
the
cancellation
of
projects
that
would
have
maintained
and
improved
the
reliability,
efficiency,
or
safety
of
existing
energy
capacity.

Finally,
the
source
may
install
less
efficient
or
less
modern
equipment
in
order
to
be
more
certain
that
it
is
within
the
RMRR
regulatory
bounds,
or
it
may
agree
to
limit
its
hours
of
operation
or
capacity
to
ensure
no
increase
in
emissions.
Any
of
these
approaches
could
make
the
source
less
productive
than
it
would
be
otherwise.
This
loss
of
productivity
would
not
be
caused
by
any
legal
requirement
but
rather
by
the
uncertainty
of
what
NSR
requirements
would
potentially
apply.
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
supplementing
our
RMRR
provision
to
provide
a
clearer,
more
objective
approach
which
includes
specific
categories
of
activities
that
will
be
automatically
considered
to
be
RMRR
in
the
future.
Such
categories
will
remove
disincentives
to
undertaking
RMRR
activities
and
provide
more
certainty
both
to
source
owners
and
operators
Internal
and
Deliberative
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2003
12
who
could
better
plan
activities
at
their
facilities,
and
to
reviewing
authorities
who
could
better
focus
resources
on
other
areas
of
their
environmental
programs
rather
than
on
time­
consuming
RMRR
determinations.

We
believe
that
today's
rule
will
facilitate
projects
that
enhance
key
operational
elements,
such
as
efficiency,

safety,
reliability,
and
environmental
performance.
We
anticipate
that
improved
safety
and
reliability
will
result
in
more
stable
process
operations
and
reduce
periods
of
startup,
shutdown,
and
malfunction
and
the
increased
emissions
usually
associated
with
them.
Accordingly,

establishing
categories
of
activities
that
will
qualify
as
RMRR
promotes
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.

C.
Process
Used
to
Develop
This
Rule
In
the
1992
"
WEPCO
Rule"
preamble,
we
declared
our
intent
to
issue
guidance
on
the
subject
of
RMRR.
In
1994,

as
an
outgrowth
of
meetings
with
the
Clean
Air
Act
Advisory
Committee,
we
developed,
for
discussion
purposes
only,
a
preliminary
draft
that
presented
possible
ways
of
how
RMRR
could
be
defined.
We
received
a
substantial
volume
of
comments
on
this
document.
We
subsequently
decided
not
to
Internal
and
Deliberative
Draft
­
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not
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or
distribute
August
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2003
13
include
this
preliminary
draft
approach
in
our
1996
NSR
proposed
rulemaking.
(
61
FR
38250)

In
2001,
the
President's
National
Energy
Policy
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.

Our
Report
to
the
President
illustrated
the
problems
associated
with
our
prior
case­
by­
case
approach
to
identifying
RMRR
activities
and
underscored
the
advantages
of
establishing
an
objective
bright­
line
approach
for
administering
the
RMRR
provision.

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
as
to
how
the
RMRR
provision
might
be
improved.
The
proposed
RMRR
rule
reflected
many
of
the
ideas
discussed
in
those
meetings.

Today's
final
rule
on
the
equipment
replacement
provision
is
based
on
careful
consideration
of
comments
received
on
the
proposed
RMRR
rule,
where
we
sought
comment
on
all
aspects
of
our
proposed
approaches.
Today's
rule
represents
final
action
on
only
one
part
of
what
we
proposed
in
December
2002
 
the
equipment
replacement
provision.
We
have
decided,
for
now,
not
to
take
final
action
on
the
proposed
annual
Internal
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Deliberative
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August
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2003
14
maintenance,
repair
and
replacement
allowance
approach.

D.
What
We
Proposed
The
RMRR
proposal
offered
for
comment
two
cost­
based
approaches
for
determining
what
constitutes
routine
maintenance,
repair,
and
replacement.
Under
the
proposal,

facilities
could
have
relied
on
a
facility­
wide
annual
maintenance,
repair
and
replacement
allowance
and/
or
an
equipment
replacement
cost
threshold
to
determine
whether
major
NSR
requirements
were
triggered
by
performing
plant
maintenance,
repair
and
replacement
activities.
The
proposal
additionally
outlined
two
options
based
on
the
capacity
and
age
of
a
facility.
EPA
solicited
comment
on
all
aspects
of
the
proposed
approaches
as
well
as
any
other
viable
option
for
clarifying
the
term
"
routine
maintenance,

repair,
and
replacement."
We
took
public
comment
on
the
proposed
rule
until
May
2,
2003
 
120
days
following
publication
in
the
Federal
Register.

Under
the
"
annual
maintenance,
repair
and
replacement
allowance,"
an
annual
maintenance
cost
allowance
would
be
established
for
each
industrial
facility
based
on
an
industry­
specific
percentage.
For
the
percentage,
we
considered
using
the
Internal
Revenue
Service
"
Annual
Asset
Guideline
Repair
Allowance
Percentages"
(
AAGRAP),
which
for
years
has
been
used
as
an
integral
part
of
an
exclusion
Internal
and
Deliberative
Draft
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or
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August
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2003
15
under
the
New
Source
Performance
Standard
(
NSPS)
program.
A
multi­
year
allowance
approach,
in
addition
to
the
annual
approach,
was
also
offered
for
consideration
in
the
proposal.

Safeguards
were
proposed
to
ensure
that
the
types
of
activities
undertaken
under
the
annual
allowance
are
not
activities
that
should
be
subject
to
greater
scrutiny.

These
safeguards
include:
1)
no
new
unit
may
be
installed;

2)
no
unit
may
be
replaced
in
its
entirety;
and
3)
changes
may
not
cause
an
increase
in
the
short­
term
emission
rate
of
any
regulated
NSR
pollutant.

Under
the
"
equipment
replacement
provision,"
or
ERP,
we
proposed
to
streamline
the
process
for
determining
if
major
NSR
permitting
requirements
apply
to
replacement
of
existing
equipment
with
identical
new
equipment
or
with
functionally
equivalent
equipment.
Per­
activity
thresholds,
potentially
up
to
50
percent
of
the
cost
of
replacing
the
process
unit,

were
suggested
by
the
proposal.
As
long
as
the
threshold
was
not
exceeded
and
the
basic
design
parameters
remained
unchanged,
the
activity
would
be
considered
RMRR
under
this
approach.

Under
the
proposal,
all
activities
that
fell
within
the
annual
maintenance,
repair
and
replacement
allowance
or
the
equipment
replacement
threshold
and
that
met
all
the
other
criteria
for
these
provisions
would
be
considered
RMRR
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and
Deliberative
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2003
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We
broadly
use
the
term
"
activities"
to
mean
all
maintenance
and
non­
maintenance
projects
conducted
at
a
stationary
source,
some
of
which
may
trigger
major
NSR.

16
without
further
review.
Activities
that
were
unable
to
be
accommodated
under
the
annual
maintenance,
repair
and
replacement
allowance
or
the
equipment
replacement
threshold
could
still
qualify
for
the
RMRR
exclusion
after
a
case­

bycase
review
in
accordance
with
current
rules.

We
solicited
comments
on
all
aspects
of
our
RMRR
proposal.

III.
Equipment
Replacement
Provision
A.
Overview
and
Justification
for
Today's
Final
Action
Today,
we
are
revising
certain
provisions
of
the
major
NSR
program
by
finalizing
the
equipment
replacement
provision
(
ERP)
to
specify
activities3
that
will
automatically
qualify
for
the
RMRR
exclusion.
This
rule
is
effective
on
[
INSERT
DATE
60
DAYS
AFTER
PUBLICATION
IN
THE
FEDERAL
REGISTER].
At
this
time,
we
are
not
taking
action
on
our
proposed
annual
maintenance,
repair
and
replacement
allowance
approach.

Although
many
commenters
requested
that
we
further
clarify
the
case­
by­
case
approach
for
determining
whether
an
activity
is
RMRR,
we
are
not
taking
action
on
this
suggestion
at
this
time.
We
are
still
considering
what,
if
any,
changes
should
be
made
to
that
policy.
In
the
Internal
and
Deliberative
Draft
­
Do
not
quote,
cite,
copy,
or
distribute
August
22,
2003
4
For
the
sake
of
clarity,
we
are
choosing
to
use
the
term
"
part,"
and
not
"
component"
as
we
used
in
the
proposed
rule,
because
"
part"
is
a
more
inclusive
term
and
reflects
that
the
ERP
should
be
applied
broadly
to
cover
replacements
of
both
large
components,
such
as
economizers,
reheaters,
etc.
at
a
steam
electric
generating
facility
or
an
industrial
boiler,
as
well
as
small
items,
such
as
screws,
washers,
gaskets,
etc.

5
We
note
that
certain
ancillary
costs
incurred
during
a
given
replacement
activity
should
not
be
associated
with
the
activity,
such
as
replacement
power
that
must
be
purchased
during
the
maintenance
shutdown
of
an
electric
utility.

17
meantime,
the
case­
by­
case
approach
will
remain
available
for
the
owner
or
operator
of
a
source
to
use
as
an
alternative
and/
or
supplement
to
today's
ERP.

Under
today's
rule,
an
activity
(
or
aggregations
of
activities)
can
qualify
for
the
ERP
if:
(
1)
it
involves
replacement
of
any
existing
part(
s)
4
of
a
process
unit
with
part(
s)
that
are
identical
or
that
serve
the
same
purpose
as
the
replaced
part(
s);
(
2)
the
fixed
capital
cost
of
the
replaced
part(
s)
plus
costs
of
any
associated
activities
(
e.
g.,
labor,
contract
services,
major
equipment
rental,
and
associated
repair
and
maintenance
activities)
5
does
not
exceed
20
percent
of
the
current
replacement
value
of
the
process
unit;
and
(
3)
the
replacement(
s)
does
not
alter
the
basic
design
parameters
of
the
process
unit
or
cause
the
process
unit
to
exceed
any
emission
limitation
or
operational
limitation
(
that
has
the
effect
of
constraining
emissions)
that
applies
to
any
part
of
the
process
unit
and
that
is
legally
enforceable.

Today's
final
rule
specifies
the
procedures
by
which
Internal
and
Deliberative
Draft
­
Do
not
quote,
cite,
copy,
or
distribute
August
22,
2003
6
Actually
proposed
as
"
fuel
consumption
specifications."

7
Replacement
value
can
be
either
an
estimate
of
the
fixed
capital
cost
of
constructing
a
new
process
unit
or
the
current
appraised
value
of
the
process
unit.

18
the
owner
or
operator
of
a
source
selects
the
basic
design
parameters
for
EUSGUs
and
for
other
types
of
process
units.

Specifically,
for
EUSGUs,
we
have
clarified
our
proposed
approach
by
specifying
maximum
hourly
heat
input
and
fuel
consumption
rate6
as
basic
design
parameters.
We
are
also
allowing
owners
or
operators
of
EUSGUs
the
option
to
select
a
pair
of
parameters
based
on
the
process
unit's
output
 
more
specifically,
maximum
hourly
electric
output
rate
or
maximum
steam
flow
rate
 
as
an
alternative
to
the
previously
proposed
input­
based
parameters.
Likewise,
we
are
retaining
our
proposed
approach
of
specifying
maximum
rate
of
fuel
or
material
input
for
other
types
of
process
units,
but
we
also
allow
you
to
use
maximum
rate
of
product
output
if
you
prefer
an
output­
based
basic
design
parameter.

In
addition,
we
allow
you
to
propose
an
alternative
basic
design
parameter(
s),
if
the
above
options
are
inappropriate
for
your
process
unit.

We
are
not
specifically
defining
the
basis
for
determining
the
replacement
value
of
a
new
process
unit.

Instead,
the
final
rules
provide
you
with
the
flexibility
of
using
any
of
the
following:
(
1)
replacement
cost7;
(
2)
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19
invested
cost,
adjusted
for
inflation;
(
3)
the
insurance
value,
where
the
insurance
value
covers
complete
replacement
of
the
process
unit
(
rather
than,
for
example,
lost
revenue
replacement);
or
(
4)
another
accounting
procedure
to
establish
a
replacement
value
of
the
process
unit
if
such
accounting
procedure
is
based
on
Generally
Accepted
Accounting
Principles
(
GAAP).
The
GAAP
are
the
conventions,

rules
and
procedures
that
define
accepted
accounting
practice
for
recording
and
reporting
financial
information,

including
broad
guidelines
as
well
as
detailed
procedures.

The
basic
doctrine
was
set
forth
by
the
Accounting
Principles
Board
of
the
American
Institute
of
Certified
Public
Accountants,
which
was
superseded
in
1973
by
the
Financial
Accounting
Standards
Board.

Once
you
choose
to
use
options
3
or
4
to
determine
the
replacement
value
for
a
particular
process
unit,
you
must
continue
to
use
the
same
basis
to
evaluate
any
additional
activities
that
you
undertake
on
that
process
unit
within
that
same
fiscal
year.
If
you
have
provided
this
notice,

then
the
reviewing
authority
will
assume
that
the
same
method
will
be
used
for
subsequent
fiscal
years
unless
you
send
a
notice
to
them
declaring
your
intent
to
use
another
method.
In
the
absence
of
providing
any
notification
to
your
reviewing
authority,
you
must
use
option
1
or
2.

The
final
rules
also
set
forth
a
definition
of
process
Internal
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Deliberative
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August
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2003
20
unit,
specifically
delineate
the
boundary
of
the
process
unit
for
certain
specified
industries,
and
define
a
functionally
equivalent
replacement.
A
more
detailed
discussion
of
these
requirements
and
our
rationale
for
this
action
is
contained
in
other
parts
of
this
preamble
section.

Today's
final
rules
are
designed
to
allow
you
to
engage
in
activities
that
facilitate
the
safe,
reliable
and
efficient
operation
of
your
source.
We
believe
that
today's
final
action
improves
the
major
NSR
program
by
providing
you
with
additional
certainty
as
to
what
equipment
replacement
activities
qualify
for
the
RMRR
exclusion.
By
adding
certainty
to
the
process,
we
are
removing
the
disincentives
to
undertaking
routine
equipment
replacements
and
promoting
proper
operational
planning
to
facilitate
safe,
reliable
and
efficient
operations.
When
an
activity
qualifies
for
the
ERP,
it
will
be
considered
RMRR
and
excluded
from
major
NSR
without
regard
to
other
considerations.
In
many
cases,
we
believe
that
maintaining
safe,
reliable
and
efficient
operations
will
have
the
corresponding
environmental
benefit
of
reducing
the
amount
of
pollution
generated
per
product
produced.
The
final
rules
also
will
reduce
the
resource
burden
on
reviewing
authorities
resulting
from
implementation
of
the
existing,
case­
by­
case
process
for
determining
RMRR.
In
these
respects,
the
final
rules
are
Internal
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Draft
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2003
21
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.

B.
What
is
an
identical
or
functionally
equivalent
replacement
and
why
is
such
an
activity
RMRR?

We
proposed
to
exempt
the
replacement
of
existing
equipment
with
identical
or
"
functionally
equivalent"
parts.

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
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
respects
or
improved
in
some
ways
in
comparison
with
the
equipment
that
is
removed.

Moreover,
the
technology
employed
in
certain
types
of
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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.

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
(
e.
g.,
for
electric
utility
steam
generating
units,
this
would
mean
maximum
heat
input
and
fuel
consumption
specifications).
Efficiency,
however,
is
not
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.

Examples
of
functionally
equivalent
replacements
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8As
discussed
in
more
detail
below,
although
such
activities
would
be
functionally
equivalent,
they
would
still
need
to
meet
other
criteria
to
qualify
for
the
ERP.
For
example,
a
functionally
equivalent
replacement
does
not
qualify
for
the
ERP
if
it
results
in
a
change
to
a
basic
design
parameter
of
the
affected
unit.
If
an
activity
does
not
qualify
for
RMRR
under
the
ERP,
the
case­
by­
case
RMRR
approach
would
still
be
available
to
the
owner
or
operator
under
those
circumstances.

23
include8:

1.
Replacing
worn
out
pipes
in
a
chemical
process
plant
with
pipes
that
are
constructed
of
different
metallurgy
(
e.
g.,
to
help
reduce
corrosion,
erosion,
or
chemical
compatibility
problems).

2.
Replacing
an
analog
controller
with
a
digital
controller,
even
though
a
similar
analog
controller
can
still
be
purchased
and
even
though
the
new
controller
would
allow
for
more
precise
control.
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.
In
this
case,
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.
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3.
Replacing
an
existing
mill
or
pulverizer
(
e.
g.,

grinding
clinker
in
a
cement
factory
or
coal
for
a
boiler)
with
a
new
one
of
a
different
type
because
both
new
and
old
equipment
serve
the
same
purpose
(
even
if
the
characteristics
of
the
ground
material
would
be
different
before
and
after
the
replacement).

4.
Replacing
existing
spray
paint
nozzles
with
new
ones
that
might
atomize
the
spray
better
or
have
a
higher
transfer
efficiency
because
the
"
before"
and
"
after"

nozzles
serve
the
same
function.

At
the
same
time,
there
are
numerous
activities
that
occur
at
facilities
that
may
fall
within
the
bounds
of
the
cost
threshold
percentage,
basic
design
parameters,
and
other
backstop
features
of
today's
rule,
but
nevertheless
cannot
qualify
for
the
RMRR
exclusion
on
the
grounds
that
the
equipment
is
neither
identical
nor
functionally
equivalent.
An
example
of
this
would
be
a
chemical
processing
facility
where
the
owner
or
operator
makes
a
physical
change
that
allows
the
production
of
a
new
end
product
using
the
same
raw
materials
as
used
before
in
the
same
amounts
as
before.
This
would
not
be
a
functionally
equivalent
replacement
activity
because
the
facility
is
able
to
produce
an
end
product
after
making
the
change
that
the
facility
was
not
capable
of
making
before
the
change.
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Consequently,
this
activity
would
not
qualify
as
RMRR
under
today's
ERP.

As
we
observed
at
the
time
of
our
RMRR
proposal,
we
believe
that
most
identical
and
functionally
equivalent
replacements
are
necessary
for
the
safe,
efficient
and
reliable
operations
of
virtually
all
industrial
operations;

are
not
of
regulatory
concern;
will
improve
air
quality
(
e.
g.,
by
decreasing
startup,
shutdown,
and
malfunctions);

and
thus
should
qualify
for
the
ERP
under
the
RMRR
exclusion.
We
believe
industrial
facilities
are
constructed
with
the
understanding
that
certain
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,
the
replaced
part
is
inherent
to
both
the
design
and
purpose
of
the
process
unit,
and
there
is
no
reason
to
believe
that
such
activity
will
cause
an
emissions
increase.
Moreover,

most
of
these
replacements
are
conducted
at
industrial
facilities
to
maintain
proper
operations
and
to
implement
good
engineering
practices.

As
we
also
observed
at
proposal,
when
equipment
is
wearing
out
or
breaking
down,
it
often
is
replaced
with
equipment
that
serves
the
same
purpose
but
is
different
in
some
respects
or
improved
in
some
ways
in
comparison
to
the
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equipment
that
is
removed.
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
are
needed.

Several
commenters
said
the
equipment
replacement
provision
will
streamline
the
major
NSR
applicability
analysis.
A
number
of
commenters
believed
the
ERP
would
be
easier
to
implement
than
the
proposed
annual
maintenance,

repair
and
replacement
allowance
approach.
One
commenter
said
that
allowing
identical
replacements
to
be
excluded
from
major
NSR
will
codify
existing
industrial
practices,

where
replacement
has
no
impact
on
emissions
and
would
clearly
represent
RMRR.

Many
commenters
expressed
support
for
the
ERP,
but
recommended
certain
changes
that
they
felt
needed
to
be
made
to
improve
the
proposal.
One
commenter
supported
the
ERP
in
combination
with
a
capacity­
based
option,
on
the
assumption
that
repair
and
maintenance
is
to
be
excluded
as
well
as
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2003
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equipment
replacement.

One
commenter
attempted
to
collect
data
from
turbine
customers
and
found
that
achieving
a
level
of
data
collection
necessary
for
the
ERP
was
far
from
simple,

because
the
cost
of
maintenance
activities
is
affected
by
such
things
as
variability
in
engine
model,
package
technology,
and
type
of
maintenance
contract.
Another
commenter
gave
an
example
of
the
benefit
that
the
ERP
may
provide.
Without
the
ERP,
the
commenter
said
the
source
is
limited
to
some
fraction
of
boiler
tubes
allowed
to
be
replaced
at
a
given
time,
whereas
with
the
ERP,
replacement
of
all
boiler
tubes
would,
in
the
commenter's
opinion,

rightfully
be
considered
routine.
Another
commenter
said
the
ERP
will
remove
regulatory
burdens
for
types
of
equipment
replacements
that
are
in
their
view
"
routine,"

such
as
replacement
of
tubes
in
industrial
boilers.
They
added
that,
without
a
clearer
understanding
of
which
activities
are
RMRR,
they
may
be
inclined
to
delay
conducting
such
replacements.

Many
other
commenters
generally
opposed
any
kind
of
RMRR
exclusion,
including
one
based
on
equipment
replacement.
Some
of
these
commenters
believed
the
ERP
was
problematic
because
it
would
allow
a
source
to
replace
an
entire
process
unit
over
time.
Two
of
the
commenters
opposed
the
ERP
because
they
felt
it
would
create
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disincentives
for
the
implementation
of
Plantwide
Applicability
Limits
(
PAL)
and
Clean
Unit
provisions
from
the
recently
finalized
rule.

One
commenter
said
that
from
an
engineering
standpoint,

for
a
power
plant,
the
difference
between
routine
maintenance
and
a
major
plant
refurbishing
project
is
clear.

According
to
the
commenter,
routine
maintenance
is
frequent
and
follows
a
predictable
pattern.
The
commenter
characterized
routine
maintenance
at
power
plants
as:

repair
of
leaking
pipes,
pumps,
valves,
and
fans;
cleaning
and
lubrication
of
parts;
and
inspections.
The
commenter,

added
that
permanent
staff
do
this
work
either
while
the
plant
is
operating
or
during
only
brief
periods
of
downtime.

The
commenter
asserted
that
activities
that
are
not
routine
require
long
plant
or
process
unit
shutdowns,
are
done
infrequently,
and
are
major
capital
projects
for
which
special
funding
is
set
aside
as
a
result
of
years
of
planning
and
design
work.

One
commenter
said
the
proposal
will
allow
emissions
increases
that
will
be
difficult
to
offset
through
other
regulations.
One
commenter
objected
to
the
ERP
for
a
number
of
reasons:
(
1)
The
provision
does
not
prevent
replacement
with
different
equipment;
(
2)
it
does
not
promote
efficiency
improvements
or
application
of
good
air
pollution
controls;
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and
(
3)
it
would
allow
replacements
that
would
significantly
increase
emissions.
This
commenter
said
replacement
of
air
pollution
controls
should
trigger
best
available
control
technology
(
BACT)
or
lowest
achievable
emission
rate
(
LAER)

requirements.
Two
local
air
pollution
control
agencies
in
California
noted
that
they
currently
already
exempt
all
replacements
with
identical
equipment
from
major
NSR
when
certain
conditions
are
met.

Commenters
generally
had
similar
viewpoints
on
allowing
both
identical
and
functionally
equivalent
equipment
replacements
qualify
as
RMRR.
However,
some
commenters
expressed
greater
concern
related
to
exempting
the
replacement
of
equipment
with
functionally
equivalent
equipment.
Primarily
their
concerns
were
rooted
in
the
fact
that
a
functionally
equivalent
replacement
part
could
lead
to
increases
in
operational
efficiency
or
productivity,
and
these
commenters
asserted
that
these
sorts
of
process
enhancements
should
be
not
be
exempt
as
RMRR.

We
agree
with
the
commenters
who
felt
identical
and
functionally
equivalent
replacement
activities
generally
should
be
exempted
as
RMRR.
We
also
agree
with
the
commenters
who
believe
that
this
provision
will
streamline
the
major
NSR
applicability
process
and
will
bring
clarity.

The
provision
we
are
finalizing
will
allow
a
source
to
make
a
simple
determination
as
to
whether
a
replacement
piece
of
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equipment
qualifies
as
identical
or
functionally
equivalent.

This
type
of
determination
will
be
straightforward
and
easier
for
the
source
to
implement
than
the
current
case­

bycase
analysis
required
to
determine
a
replacement
falls
within
the
RMRR
exclusion.
We
support
the
air
pollution
agencies
that
have
already
exempted
these
types
of
changes
from
NSR.

We
disagree
with
those
commenters
who
believe
that
this
provision
will
create
disincentives
for
sources
to
accept
a
PAL
or
have
emission
units
designated
as
Clean
Units.
A
PAL
offers
a
source
many
incentives
related
to
major
NSR:
(
1)

ability
to
bring
on
entirely
new
emissions
units
with
no
Federal
preconstruction
permit,
as
long
as
emissions
caps
are
not
exceeded;
(
2)
ability
to
make
modifications
to
existing
sources
without
performing
a
major
NSR
applicability
test;
and
(
3)
reduced
need
to
keep
records
or
otherwise
track
for
major
NSR
purposes
any
maintenance,

repair
and
replacement
activities
or
modifications
at
the
facilities.
A
Clean
Unit
designation
offers
similar
advantages
as
a
PAL,
although
under
a
PAL
you
can
bring
on
new
emissions
units
but
you
cannot
do
so
with
a
Clean
Unit.

These
advantages
will
still
be
the
driving
force
for
sources
to
elect
to
use
the
PAL
or
Clean
Unit
provisions,
and
we
do
not
believe
this
final
rule
will
significantly
detract
from
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their
appeal.

We
also
believe
that
there
is
value
in
providing
a
clearer
distinction
between
routine
equipment
replacement
and
major
plant
refurbishing.
For
pieces
of
equipment
used
at
industrial
facilities,
most
manufacturers
have
wellestablished
procedures
for
the
inspection
and
replacement
that
are
part
of
the
regular
maintenance
necessary
to
provide
for
the
equipment's
safe,
efficient
and
reliable
operation.
Some
of
these
replacements
are
relatively
large
in
terms
of
cost
and
can
be
infrequent,
but
all
are
necessary
to
maintain
the
safe,
efficient
and
reliable
use
of
the
process
unit.
We
believe
it
is
important
to
allow
for
these
replacements
within
certain
limits,
which
are
discussed
below.

We
disagree
with
suggestions
from
commenters
that
the
time
period
between
activities,
standing
alone,
provides
an
appropriate
or
clear
distinction
between
routine
and
nonroutine
activities.
In
fact,
we
think
the
major
NSR
applicability
provisions
impose
constraints
on
capital
planning
and
maintenance
processes
at
industrial
facilities.

The
effect
of
the
existing
provisions,
such
as
the
emissions
baseline,
is
to
force
companies
to
plan
maintenance
actions
on
a
relatively
short
horizon
(
either
5
or
10
years,

depending
on
the
emissions
baseline).
Failure
to
address
maintenance
within
this
horizon
creates
potentially
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significant
ramifications
such
as
the
need
to
accept
permanent
limits
on
your
operations.
This
can
force
companies
to
act
sooner
than
needed
or
to
take
steps
that
have
no
rational
relationship
to
the
circumstances,
with
the
result
that
maintenance
actions
are
dictated
by
regulatory
constraints
rather
than
by
economic
or
plant
efficiency.

We
disagree
with
commenters
who
expressed
particular
concern
about
functionally
equivalent
replacements.
We
continue
to
believe
such
activities
should
be
encouraged
and
should
qualify
as
RMRR.
Even
though
a
functionally
equivalent
part
varies
in
some
respects
from
the
replaced
part,
we
feel
the
important
factor
to
consider
is
whether
the
replacement
will
serve
the
same
purpose
as
the
replaced
part.
We
acknowledge
that
a
functionally
equivalent
replacement
can
result
in
an
increase
in
efficiency
and,

consequently,
productivity.
In
fact,
one
of
our
goals
is
to
promote
such
outcomes.
However,
we
believe
that
the
basic
design
parameter
safeguard
is
appropriate
to
assure
that
the
ERP
only
exempts
from
major
NSR
functionally
equivalent
replacements
that
do
not
result
in
a
significant
change
to
the
fundamental
characteristics
of
the
process
unit.

Moreover,
the
two
local
programs
in
California
that
exempt
the
replacement
of
equipment
with
identical
equipment
also
allow
the
replacement
of
equipment
with
functionally
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33
equivalent
equipment
without
considering
such
action
to
be
a
modification.
However,
due
to
local
air
quality
considerations,
the
local
programs
establish
minimum
pollution
control
requirements
that
are
imposed
in
some
circumstances
when
functionally
equivalent
equipment
replacements
occur.
Nothing
in
today's
rule
would
prevent
a
State
or
local
program
from
imposing
additional
requirements
necessary
to
meet
Federal,
State
or
local
air
quality
goals.

After
reviewing
the
comments
on
our
proposal,
we
have
decided
to
promulgate
what
we
proposed
in
December
2002
for
the
RMRR
equipment
replacement
provision
with
relatively
minor
changes.
We
decided
that
another
safeguard,
in
addition
to
the
proposed
safeguards,
would
provide
added
certainty
by
constraining
the
meaning
of
"
functionally
equivalent."
The
additional
safeguard
is
that
an
exempted
replacement
cannot
cause
a
revision
of
the
source's
emission
limitation
in
its
permit.
More
specifically,
today's
rule
stipulates
that
activities
that
cause
the
process
unit
to
exceed
any
emission
limitation
or
operational
limitation
(
that
has
the
effect
of
constraining
emissions)
that
applies
to
any
part
of
the
process
unit
cannot
qualify
as
RMRR
under
the
ERP.

Thus,
today's
final
rule
allow
you
to
categorize
identical
and
functionally
equivalent
equipment
replacements
as
RMRR
if
the
fixed
capital
cost
of
such
replacement
plus
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34
the
cost
of
associated
activities
does
not
exceed
20
percent
of
the
replacement
value
of
the
process
unit,
and
if
the
replacement
does
not
alter
a
basic
design
parameter
of
the
process
unit
or
cause
the
process
unit
to
exceed
any
emission
limitation
or
operational
limitation
(
that
has
the
effect
of
constraining
emissions)
that
applies
to
the
process
unit.

C.
What
cost
limit
has
been
placed
on
the
equipment
replacement
approach?

The
next
concept
presented
in
the
proposal
is
the
costbased
limitation
on
the
scope
of
the
ERP.
The
purpose
of
this
threshold
is
to
distinguish
between
those
equipment
replacement
activities
that
should
automatically
qualify
as
RMRR
without
further
consideration
and
those
activities
that
should
undergo
case­
specific
consideration.
This
concept
is
borrowed
from,
and
closely
akin
to,
the
long­
established
reconstruction
provision
under
the
NSPS
program.
For
the
reasons
explained
below,
we
have
decided
to
establish
a
20­

percent
cost
threshold
under
the
ERP.

In
the
proposal,
we
observed
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
Internal
and
Deliberative
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9In
the
proposal,
it
was
incorrectly
stated
that
applicability
of
the
NSPS
was
triggered
if
a
project
exceeded
50
percent
of
the
cost
of
replacing
the
affected
facility.
As
stated
in
this
notice,
if
an
activity
exceeds
this
cost
threshold,
that
only
triggers
further
evaluation,
not
the
automatic
application
of
the
NSPS
to
the
source.

35
replacement
of
equipment
with
identical
or
functionally
equivalent
equipment
involves
a
large
portion
of
an
existing
process
unit.
We
solicited
comment
on
a
range
of
equipment
replacement
cost
thresholds
such
as
one
based
on
the
NSPS
program.
Under
the
NSPS
program,
when
the
cost
of
a
project
at
an
existing
affected
facility
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),
then
the
source
must
notify
and
provide
information
to
the
permitting
authority.
After
considering
a
range
of
factors,
including
the
cost
of
the
project,
the
estimated
life
of
the
facility
after
the
replacements,
the
extent
to
which
the
replaced
equipment
causes
or
contributes
to
the
emissions
from
the
source,
and
any
economic
or
technical
limitations
on
compliance
with
the
NSPS,
the
reviewing
authority
determines
whether
the
proposed
project
is
a
reconstruction.
9
We
observed
that,
in
some
respects,
an
equipment
replacement
cost
threshold
set
at
the
NSPS
reconstruction
test
could
be
an
appropriate
approach
for
distinguishing
between
routine
and
nonroutine
identical
and
functionally
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equivalent
replacements
under
the
major
NSR
program.
As
under
the
NSPS
program,
we
do
not
believe
it
is
reasonable
to
exclude
from
major
NSR
those
activities
that
involve
the
total
replacement
of
an
existing
entire
process
unit.

Finally,
we
noted
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
ERP.
For
example,
since
under
NSPS
when
a
source
undertakes
a
replacement
activity
at
an
existing
affected
facility
that
constitutes
half
or
more
of
the
facility's
capital
replacement
value,
our
rules
require
a
case­
by­
case
determination
as
to
whether
such
replacements
constitute
construction.
It
is
reasonable
to
conclude
that
some
percentage
lower
than
the
50­
percent
reconstruction
threshold
would
be
suitable
in
requiring
case­
by­
case
consideration
of
the
question
whether
equipment
replacements
constitute
a
modification
of
an
existing
process
unit
under
major
NSR.
We
solicited
comments
on
the
appropriate
level
of
any
percentage.

Many
commenters
supported
the
threshold
of
50
percent
of
replacement
value
as
the
upper
limit
on
equipment
replacement.
They
felt
this
number
is
consistent
with
existing
regulatory
requirements
and
would
accord
the
flexibility
originally
intended
under
the
CAA
for
RMRR
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37
activities,
while
at
the
same
time
assuring
that
major,

nonroutine
projects
remain
subject
to
major
NSR
applicability
review,
and
they
felt
this
number
is
consistent
with
a
common­
sense
interpretation
of
the
regulations.

They
also
believed
a
50­
percent
cutoff
to
be
consistent
with
reconstruction
definitions
used
in
many
NSPS
and
National
Emission
Standards
for
Hazardous
Air
Pollutants
regulations.
Some
commenters
stated
that
a
50­
percent
cutoff
for
the
ERP
would
be
valid
for
the
same
reason
as
for
the
NSPS
reconstruction
test;
significant
changes
to
a
process
unit
are
necessary
before
retrofit
controls
should
be
considered,
provided
there
is
no
increase
in
emissions.

Many
other
commenters
opposed
the
50­
percent
replacement
value
threshold.
They
believed
the
capital
replacement
percentage
should
be
much
less
than
50
percent.

One
commenter
preferred
that
the
sum
of
equipment
replacement
costs
for
a
single
process
unit
over
any
period
of
5
consecutive
years
should
not
exceed
50
percent
of
the
replacement
value
of
the
process
unit.
Another
commenter
said
the
replacement
percentage
should
not
be
higher
than
25
percent.
Another
commenter
suggested
a
replacement
percentage
of
5
to
10
percent
to
reduce
the
risk
of
replacement
of
an
entire
process
unit
over
time
without
installation
of
BACT.
One
commenter
said
a
more
appropriate
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percentage
for
electricity
producers
is
0.1
to
1.0
percent.

Another
commenter
said
the
threshold
should
be
5
percent,

1
percent,
or
even
less,
as
shown
by
an
NSR
enforcement
case
against
the
Tennessee
Valley
Authority
(
TVA).

Another
commenter
believed
the
50­
percent
number
has
no
practical
effect
in
protecting
public
health
and
the
environment,
and
the
commenter
was
not
aware
of
any
projects
that
have
exceeded
50
percent
in
cost.

While
opposed
to
the
ERP
in
general,
one
commenter
said
the
cost
threshold
should
be
as
high
a
percentage
as
possible,
so
as
not
to
promote
premature
replacement
of
equipment
that
is
repairable.
Another
commenter
said
the
50­
percent
number
from
the
NSPS
is
archaic
and
not
environmentally
protective.
This
commenter
suggested
that
the
threshold
instead
be
24
percent.
The
commenter
believed
this
lower
percentage
is
appropriate
because
the
lifetime
of
high­
cost
materials
will
considerably
exceed
5
years.

We
agree
with
those
commenters
who
see
a
relationship
between
establishing
a
threshold
under
the
major
NSR
program
for
the
ERP
and
the
threshold
established
for
the
NSPS
program.
However,
we
disagree
that
the
thresholds
for
the
two
programs
should
be
the
same.
The
NSPS
threshold
was
intended
to
identify
those
projects
that,
even
though
they
did
not
qualify
as
a
modification,
nevertheless
are
of
such
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magnitude
that
they
should
be
given
further
consideration
as
projects
possibly
tantamount
to
new
construction.
The
50­

percent
NSPS
threshold
is
not
a
bright
line
in
the
sense
that
all
projects
that
exceed
50
percent
are
automatically
considered
as
reconstruction.
Rather,
as
discussed
above,

it
is
a
threshold
intended
to
alert
permitting
authorities
to
significant
projects
and
allow
case­
by­
case
decisions
based
on
a
series
of
regulatory
factors.

The
ERP
replicates
the
NSPS
concept
in
some
ways.
It
identifies
a
threshold
below
which
there
is
no
need
for
further
inquiry
into
whether
an
activity
qualifies
for
the
ERP
and
above
which
there
is
a
need
for
a
case­
by­
case
determination.
The
major
difference
between
the
ERP
and
the
NSPS
reconstruction
test
is
that
the
ERP
deals
with
modifications,
not
reconstructions.
This
difference
weighs
in
favor
of
establishing
the
equipment
replacement
threshold
at
something
less
than
the
reconstruction
threshold.
It
is
logical
and
practical
to
conclude,
as
some
of
the
commenters
do,
that
by
using
the
word
"
modification"
the
CAA
intended
to
capture
projects
on
a
smaller
scale
than
reconstructions.

As
noted
above,
we
have
set
the
ERP
cost
threshold
at
20
percent.
This
value
is
less
than
one­
half
of
the
50­
percent
reconstruction
threshold
and,
therefore,
fits
well
within
this
conceptual
framework.

Another
relevant
consideration
in
choosing
an
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appropriate
ERP
cost
threshold
is
the
decision
of
the
U.
S.

Court
of
Appeals
for
the
Seventh
Circuit
in
the
Wisconsin
Electric
Power
Company
(
WEPCO)
case.
See
893
F.
2d
901
(
7th
Cir.
1990).
This
decision
directly
addressed
the
questions
of
what
level
of
"
like
kind"
replacement
activities
qualify
as
changes
under
the
major
NSR
program.

In
the
WEPCO
case,
the
Court
considered
a
project
involving
5
coal­
fired
units
at
WEPCO's
Port
Washington
plant.
Each
unit
was
rated
at
80
megawatts
of
electrical
output
capacity.
The
project
involved
the
replacement
of
numerous
major
parts.
The
information
submitted
by
WEPCO
showed
that
the
company
intended
to
replace
several
parts
that
are
essential
to
the
operation
of
the
Port
Washington
plant.
In
particular,
the
WEPCO
would
replace
the
rear
steam
drums
on
the
boilers
at
units
2,
3,
4,
and
5.

According
to
WEPCO,
these
steam
drums
were
a
type
of
"
header"
for
the
collection
and
distribution
of
steam
and/
or
water
within
the
boilers.
They
measure
60
feet
long,
50.5
inches
in
diameter,
and
5.25
inches
thick,
and
WEPCO
viewed
their
replacement
as
necessary
to
continue
operation
of
the
units
in
a
safe
condition.
In
addition,
at
each
of
the
emissions
units,
WEPCO
planned
to
repair
or
replace
several
other
integral
parts,
including
replacement
of
the
air
heaters
at
units
1,
2,
3,
and
4.
The
WEPCO
also
planned
to
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renovate
major
mechanical
and
electrical
auxiliary
systems
and
common
plant
support
facilities.
The
WEPCO
intended
to
perform
the
work
over
a
4­
year
period,
utilizing
successive
9­
month
outages
at
each
unit.
The
cost
of
the
project
was
estimated
in
1988
to
be
$
87.5
million.
The
Court
determined,
at
our
urging,
that
the
changes
did
constitute
a
"
physical
change"
under
the
NSR
rules.

In
the
case
of
a
steam
electric
generating
facility,

the
process
unit
definition
provided
in
today's
rule
is
nearly
identical
to
the
make­
up
of
the
"
comparable
new
facility"
that
was
used
in
the
NSPS
evaluation
of
the
WEPCO
renovation
project.
However,
one
difference
is
that
the
cost
of
pollution
control
equipment
is
not
considered
in
evaluating
the
changes
in
WEPCO
against
the
process
unit
definition
in
today's
rule.
The
WEPCO
had
electrostatic
precipitators
on
each
of
its
5
process
units,
so
this
needs
to
be
factored
in.
In
addition,
the
WEPCO
evaluation
dealt
with
5
boilers,
each
with
its
own
turbine­
generator
set;
to
be
consistent
with
today's
definition
of
steam
electric
generating
facility,
we
would
likely
treat
each
boiler
unit
as
belonging
to
a
different
process
unit.
However,
since
all
of
the
boilers
underwent
similar
renovations,
for
simplicity
we
can
assume
that
all
of
the
process
unitspecific
activity
costs
are
equivalent.

Using
1991
dollars,
consistent
with
the
timeframe
of
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and
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2003
10
Using
the
Chemical
Engineering
magazine's
Annual
Plant
Cost
Index
(
composite),
$
87.5
million
in
1988
dollars
is
equal
in
real
terms
to
(
361.3/
342.5)
multiplied
by
87.5
million,
or
$
92.3
million
in
1991
dollars.

11We
note
that
the
U.
S.
District
Court
for
the
Southern
District
of
Ohio
recently
issued
an
opinion
in
the
Agency's
NSR
42
the
Seventh
Circuit
Court's
decision,
it
appears
that
the
value
of
the
5
process
units
at
the
400­
megawatt
WEPCO
Port
Washington
facility
would
be
approximately
$
321
million
based
on
1991
model
plant
values
provided
by
the
International
Energy
Agency.
The
1988
project
cost
of
$
87.5
million
scaled
up
to
1991
dollars
results
in
an
adjusted
project
cost
of
$
92.3
million.
10
Thus,
the
capital
cost
percentage
for
the
replacement
activities
at
WEPCO,
averaged
over
its
5
process
units,
amounts
to
29
percent.

Alternatively,
using
the
project
cost
of
"
at
least
$
70.5
million"
as
cited
in
the
1991
decision
by
the
Seventh
Circuit,
and
using
the
same
value
for
process
unit
cost,
we
compute
at
least
22
percent.
The
20­
percent
threshold
is,

therefore,
beneath
the
scope
of
the
projects
at
issue
in
the
WEPCO
case.
Therefore,
while
we
recognize
that
the
WEPCO
court
did
not
specifically
endorse
as
RMRR
all
maintenance,

repair
and
replacement
activities
falling
below
the
cost
percentage
in
that
case,
the
percentage
we
are
adopting
today
certainly
does
not
run
afoul
of
the
limits
established
in
WEPCO.
11
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enforcement
case
against
Ohio
Edison.
(
cite)
The
case
included
a
series
of
projects
with
absolute
and
relative
costs
well
below
those
at
issue
in
WEPCO.
The
court
determined,
again
at
our
urging,
that
these
projects
did
not
qualify
for
the
existing
RMRR
exclusion.
The
Agency
asserted
in
that
case
that
the
then
existing
RMRR
exclusion
should
be
applied
in
a
narrow
fashion
such
that
only
de
minimis
projects
should
be
excluded
under
that
rule.
The
Agency
sought
and
received
from
the
court
broad
deference
with
regard
to
the
Agency's
interpretation
of
the
CAA
and
the
relevant
EPA
rules.
As
explained
fully
in
Section
N
below,
EPA
today
is
adopting
for
future
purposes
a
new
interpretation
of
the
CAA
and
is
finalizing
a
revision
to
the
RMRR
regulation.
The
decision
in
Ohio
Edison
does
not
preclude
the
interpretation
and
regulation
finalized
in
today's
action.

43
The
20­
percent
threshold
also
is
supported
by
available
data
for
the
electric
utility
sector.
We
have
a
robust
and
detailed
set
of
information
available
on
maintenance,
repair
and
replacement
activities
for
the
electric
utility
sector.

Information
about
the
electric
utility
sector
assures
us
that
we
have
established
the
right
ERP
threshold
for
this
sector.

Two
comment
letters
(
from
the
Utility
Air
Regulatory
Group
(
UARG)
and
from
the
American
Lung
Association
(
ALA),

et
al.)
were
particularly
helpful
in
understanding
the
issues
associated
with
the
electric
utility
sector.
The
UARG
provided
as
an
attachment
to
its
comment
letter
a
document
describing
major
repair
and
replacement
activities
that
its
members
believe
must
be
undertaken
at
utility
generating
stations
in
order
to
keep
those
facilities
operational.
The
UARG
noted
that
capital
costs
incurred
for
repair
and
replacement
activities
at
an
individual
process
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unit
additionally
include
activities
more
minor
than
those
addressed
in
the
document.
The
UARG
grouped
repair
and
replacement
activities
into
project
families;
within
each
project
family
were
per­
component
costs
($/
kW)
for
numerous
equipment
replacement
activities.
We
have
reviewed
the
list
of
projects
supplied
by
UARG
and
have
concluded
that
these
types
of
replacement
activities
are
necessary
and
helpful
in
maintaining,
facilitating,
restoring
or
improving
the
safety,
reliability,
availability,
or
efficiency
of
process
units.
Therefore,
these
types
of
individual
activities
and
groups
of
activities
should
qualify
for
the
ERP
and
be
excluded
from
major
NSR
without
case­
specific
review.
We
also
believe
that
it
is
reasonably
expected
in
the
electric
utility
industry
for
groups
of
these
activities
to
be
implemented
at
the
same
time.
Such
groupings
should
also
be
excluded
without
case­
specific
review.
When
we
compare
the
20­
percent
ERP
cost
percentage
to
the
UARG
data,
we
find
that
individual
replacement
projects
would,
in
fact,
qualify
for
the
ERP
and
that
limited
groupings
of
these
projects
would
qualify.
However,
larger
groupings
of
these
projects
 
groupings
that
are
not
usually
seen
in
the
industry
 
would
not
qualify
for
the
ERP.
This
shows
that
the
20­

percent
threshold
will
be
effective
in
distinguishing
between
activities
(
and
aggregations
of
activities)
that
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should
not
require
case­
specific
review
to
be
excluded
from
major
NSR
and
those
that
do.

The
ALA
commenters
provided
with
their
comments
the
results
of
their
analysis
of
projects
at
issue
in
an
NSR
enforcement
case
against
Tennessee
Valley
Authority
(
TVA).

As
shown
in
the
ALA
comment
letter,
the
Clean
Air
Task
Force
and
the
Natural
Resources
Defense
Council
looked
at
costs
for
14
projects
on
a
process
unit
basis,
in
year
2001
dollars,
from
the
publicly
available
record
for
the
case.

For
all
but
one
of
the
challenged
projects,
the
ALA
commenters
calculated
a
cost
of
less
than
4
percent
of
process
unit
replacement
cost.
The
ALA
commenters
submitted
results
of
this
analysis
with
their
opposition
to
a
sourcewide
5­
percent
maintenance
allowance.
As
noted
above,
we
concluded
in
our
2002
report
to
the
President
that
the
NSR
program
­
and
the
RMRR
provision
in
particular
­
has
in
fact
resulted
in
delay
or
cancellation
of
activities
that
would
have
maintained
and
improved
the
reliability,
efficiency,

and
safety
of
existing
energy
capacity.
The
primary
purpose
of
today's
rule
is
to
rectify
this
problem.
Thus,
to
the
extent
the
projects
addressed
by
ALA
qualify
for
the
ERP,
we
now
believe
that
such
projects
should
be
excluded
from
major
NSR.

D.
What
will
be
the
basis
of
applying
the
20­
percent
threshold?
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In
the
proposal,
we
solicited
comment
on
whether
implementing
the
ERP
on
a
per­
activity
basis
or
on
some
other
reasoned
basis,
such
as
applying
the
percentage
to
components
that
are
replaced
collectively
over
a
fixed
period
of
time,
may
be
more
workable.

Many
commenters
stated
that
the
ERP
should
be
implemented
on
a
per­
activity
(
or
aggregation
of
activities)

basis.
Two
of
the
commenters
cited
longstanding
NSR
precedent
as
the
basis
of
their
comments,
while
two
other
commenters
relied
on
NSPS
precedent.
Another
commenter
thought
the
per­
activity
approach
would
be
less
confusing
than
summing
activities
over
a
fixed
period
of
time.
Other
commenters
believed
the
equipment
replacement
threshold
should
in
fact
be
applied
on
a
5­
year
rolling
average.

We
have
decided
to
apply
the
percentage
threshold
on
a
per­
activity
(
or
aggregation
of
activities)
basis.
This
is
consistent
with
how
major
NSR
has
been
applied
in
the
past
and
will
continue
to
the
apply
in
the
future,
with
the
exception
of
those
sources
which
establish
a
PAL.
The
major
NSR
program
is
a
preconstruction
program
that
requires
applicability
to
be
determined
for
a
given
activity
at
a
facility
and,
as
necessary,
permitting
to
occur
prior
to
the
time
activities
are
commenced.
The
major
NSR
program
also
requires
applicability
to
be
determined,
in
the
first
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instance,
based
on
an
assessment
only
of
the
parts
of
a
facility
involved
in
the
activity.
A
per­
activity
basis
works
well
with
this
approach.
We
are
not
going
final
with
a
"
component­
by­
component"
approach
that
we
solicited
comment
on
through
our
RMRR
proposal.

There
would
be
obvious
problems
if
we
chose
any
of
the
other
approaches
suggested
in
the
proposal
or
suggested
by
commenters
(
for
example,
annual
basis
or
5­
year
rolling
average).
One
of
the
primary
concerns
with
applying
the
percentage
to
activities
performed
over
a
span
of
time
is
that
we
would
be
restructuring
the
major
NSR
program
to
operate
based
on
after­
the­
fact
determinations.
This
raises
the
difficult
question
of
what
happens
under
this
type
of
approach
if
you
learn
after
commencement
of
an
activity
that
it
does
not
qualify
under
the
ERP.
This
situation
is
largely
avoided
by
the
per­
activity
approach
that
we
are
establishing
in
today's
rule.

It
should
be
noted
that
activities
that
are
related
must
be
aggregated
under
the
ERP,
in
the
same
way
as
they
would
have
to
be
aggregated
for
other
NSR
applicability
purposes.
Under
our
current
policy
of
aggregation,
two
or
more
replacement
activities
that
occur
at
the
same
time
are
not
automatically
considered
a
single
project
solely
because
they
happen
at
the
same
time.
For
example,
a
steam
turbine
rotor
replacement
project
and
a
boiler
tube
replacement
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project
would
not
be
aggregated
simply
because
they
occur
during
the
same
maintenance
outage
and
on
the
same
process
unit.
Further
inquiry
into
the
nature
of
the
activities
and
their
relationship
to
each
other
is
needed
before
deciding
whether
the
activities
must
be
aggregated
under
NSR.
Also,

non­
replacement
activities
that
are
part
of
a
larger
replacement
activity
should
be
included
when
calculating
costs
for
a
replacement
activity
against
the
capital
cost
threshold.

E.
What
basic
design
parameters
are
being
established
to
qualify
for
the
equipment
replacement
provision?

In
the
proposal,
equipment
replacements
were
only
eligible
for
the
ERP
if
they
did
not
change
the
basic
design
parameters
of
the
process
unit.
We
proposed
that
maximum
heat
input
and
fuel
consumption
specifications
for
EUSGUs
and
maximum
material/
fuel
input
specifications
for
other
types
of
process
units
are
basic
design
parameters.
We
solicited
comments
on
limiting
the
eligibility
of
the
ERP
this
way
and
on
the
basic
design
parameters
we
proposed.

Several
commenters
expressed
concerns
with
either
the
use
of
these
specific
parameters,
or
the
restriction
of
the
regulated
community
to
only
this
set
of
design
parameters.

Other
comments
centered
around
an
inconsistency
in
how
EPA
has
accounted
for
efficiency
in
the
basic
design
parameter
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safeguard.
The
commenters
stated
that,
while
EPA
stated
in
the
proposed
preamble
that
efficiency
is
not
a
basic
design
parameter,
the
basic
design
parameter
safeguard,
as
proposed,
has
the
potential
to
bar
equipment
replacements
that
achieve
significant
gains
in
efficiency.

Commenters
from
all
sides
supported
EPA's
approach
to
handling
activities
intended
to
improve
an
affected
process
unit's
performance
beyond
its
basic
design
parameters.
In
these
circumstances,
commenters
asserted
that
actions
that
extend
beyond
the
definition
of
RMRR
should
be
subject
to
the
full
scope
of
major
NSR.
Commenters
from
the
gas
transmission
industry
concurred
and
amplified
this
concept,

stating
that
an
engine
that
is
"
uprated"
at
the
time
of
overhaul
should
undergo
major
NSR.

We
recognize
that
the
proposed
basic
design
parameters
are
inconsistent
with
some
industry
conventions,
and
that
we
should
allow
for
industry­
specific
flexibility
or
specify
additional
source
category­
specific
parameters.
For
example,
for
natural
gas
transmission
compressor
stations,

commenters
explained
that
brake
horsepower
is
the
conventional
design
capacity
parameter.
We
received
similar
comments
from
other
industries,
including
cement
and
surface
coaters,
who
objected
to
limiting
their
facilities
to
the
proposed
basic
design
parameters.
Accordingly,
we
have
decided
to
provide
flexibility
by
providing
a
menu
of
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choices
from
which
the
owners
or
operators
may
select
and
also
by
allowing
for
owners
or
operators
to
propose
alternative
basic
design
parameters
to
their
reviewing
authority
which
would
then
be
incorporated
in
a
Federally
enforceable
permit,
such
as
a
title
V
operating
permit.

In
addition
to
this
flexibility,
there
may
be
a
need
for
additional
flexibility
in
using
the
basic
design
parameters
that
are
spelled
out
in
today's
rule.
For
instance
with
boilers,
maximum
steam
production
rate
is
often
used
by
the
industry,
and
it
may
make
sense
in
some
cases
to
set
the
design
parameters
based
on
those
values
rather
than
on
maximum
heat
input.
Likewise,
a
crude
oil
distillation
tower
may
have
several
capacities
that
are
a
function
of
the
type
of
crude
that
is
to
be
processed,
and
so
a
refiner
may
need
to
have
a
set
of
basic
design
parameters
for
their
crude
towers.
These
situations
can
be
addressed
by
the
source
proposing
alternative
parameters
or
sets
of
parameters
to
their
reviewing
authority.

Also,
there
should
be
flexibility
in
how
the
basic
design
parameters
are
demonstrated.
For
example,
in
order
to
establish
the
heat
input
value
that
the
process
unit
has
demonstrated
it
is
capable
of
achieving,
an
electric
generating
unit
should
have
the
flexibility
to
reference
available
credible
information,
such
as
results
of
historic
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maximum
capability
tests,
design
information
from
the
manufacturer,
or
engineering
calculations.
Results
from
tests
performed
by
electric
utilities
in
the
context
of
providing
assurances
to
generation
dispatch
systems
and
regional
or
national
power
pools
may
be
used
to
establish
the
process
unit's
maximum
heat
input.
A
review
of
such
data
or
other
available
operational
data
or
design
information
can
reveal
the
heat
input
that
the
process
unit
is
capable
of
achieving
in
its
"
pre­
activity"
configuration,

and
this
can
be
compared
to
a
"
post­
activity"
heat
input
value.
Plant
operators,
where
the
specified
basic
design
parameters
are
inappropriate
for
the
process,
can
propose
what
the
measure
of
performance
will
be
for
these
process
units,
including
the
use
of
permit
limits
on
amount
of
production,
to
their
reviewing
authority.
For
process
units
having
multiple
end
products
and
raw
materials,
the
owner
or
operator
should
consider
the
primary
product
or
primary
raw
material
when
selecting
a
basic
design
parameter.

Many
pieces
of
equipment
are
purchased
based
on
their
capacity
or
output.
Consequently,
for
both
utilities
and
non­
utilities,
we
have
modified
the
proposed
basic
design
parameters
to
include
output­
based
alternatives
in
today's
final
rule.
For
utilities,
the
owner
or
operator
can
select
maximum
hourly
electric
output
rate
and
maximum
steam
flow
rate
as
its
basic
design
parameters,
as
an
alternative
to
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using
input­
based
measures
of
maximum
hourly
fuel
consumption
rate
and
maximum
hourly
heat
input.
(
We
are
clarifying
from
the
proposal
that
the
correct
parameter
is
maximum
hourly
heat
input,
not
maximum
heat
input.)
Sources
may
request
that
their
reviewing
authorities
specify
fuel
type
(
such
as
coal
or
oil)
when
setting
basic
design
parameters
at
a
combustion
device
that
can
accommodate
multiple
fuel
types,
and,
for
coal­
fired
units,
they
should
consider
that
the
fuel
consumption
rate
will
vary
depending
on
the
quality
of
the
coal
for
a
given
heat
input.
When
establishing
fuel
consumption
specifications
in
terms
of
weight
or
volume,
the
minimum
fuel
quality
based
on
BTU
content
should
be
used
for
coal­
fired
units.

Regardless
of
whether
the
source
selects
a
basic
design
parameter(
s)
specified
in
today's
rule
or
gets
approval
from
their
reviewing
authority
to
use
an
alternative
parameter(
s),
our
expectation
is
that,
for
reasons
not
unlike
our
approach
to
specifying
appropriate
averaging
times
under
our
policy
on
practical
enforceability,
the
source
should
avoid
long
term
averaging
periods
(
e.
g.,
a
12­

month
fixed
period)
in
applying
the
basic
design
parameter(
s).

Thus,
an
equipment
replacement
that
improves
a
process
unit's
efficiency
by
enabling
the
unit
to
return
to
its
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design
parameters
can
qualify
as
RMRR
even
if
current
actual
emissions
increase
as
a
result.
For
example,
if
boiler
tubes
or
refractory
are
replaced
on
a
boiler
process
unit,

and
these
activities
are
beneath
the
capital
cost
threshold
and
are
within
the
unit's
basic
design
parameters,
then
they
would
qualify
as
RMRR
under
the
ERP
even
if
this
improves
the
unit's
efficiency.

In
the
rare
cases
where
a
facility
does
not
have
established
design
parameters,
we
believe
that
a
reasonable
look
back
period
should
be
used
for
establishing
the
preactivity
values
for
basic
design
parameters,
rather
than
taking
the
condition
of
the
process
unit
immediately
before
the
activity.
We
have
therefore
established
a
5­
year
look
back
period,
consistent
with
that
for
the
NSPS
hourly
emissions
increase
test,
for
these
situations.

We
were
urged
by
some
commenters
to
incorporate
a
de
minimis
increase
level
in
the
basic
design
parameters
that
would
allow
projects
to
qualify
for
the
ERP
even
though
the
activities
would
result
in
a
minor
change
to
the
relevant
basic
design
parameters.
They
argued
that
some
effects
resulting
from
the
replacement
may
not
be
apparent
before
the
equipment
has
been
replaced.
They
argued
that
allowing
for
small
changes
in
basic
design
parameters
would
add
greater
certainty
to
the
ERP
because
unforeseen
small
changes
would
not
cause
an
activity
to
lose
the
exclusion
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after
the
fact.
While
we
sympathize
with
the
commenter's
concern,
we
do
not
believe
that
de
minimis
changes
can
be
justified
under
the
ERP.
Today's
rule
is
based
on
the
notion
that
certain
replacement
activities
should
not
be
considered
changes
under
NSR.
It
is
hard
for
us
to
say
a
change
has
not
occurred
when
an
activity
causes
basic
design
parameters
to
change.

In
sum,
we
continue
to
believe
that
an
identical
or
functionally
equivalent
replacement
should
not
qualify
for
the
ERP
if
the
activity
causes
the
process
unit
to
exceed
its
specified
basic
design
parameters.
Without
such
a
requirement,
significant
alteration
of
a
process
unit's
fundamental
design
could
be
accomplished
under
the
guise
of
the
ERP.
Such
an
outcome
obviously
does
not
square
with
the
idea
that
identical
or
functionally
equivalent
replacements
are
not
"
changes"
under
the
major
NSR
program.
Our
final
rule
is
different
from
the
proposal,
however,
in
that
it
provides
greater
flexibility
in
defining
basic
design
parameters
for
process
units.
We
were
persuaded
by
commenters
who
expressed
concerns
that
the
proposed
approaches
did
not
adequately
encompass
all
affected
operations
and
industry
sectors.

F.
What
collection
of
equipment
should
be
considered
in
applying
the
equipment
replacement
provision
and
how
should
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it
be
defined?

In
the
proposal,
we
raised
the
issue
of
what
collection
of
equipment
should
be
considered
in
applying
the
threshold
under
the
ERP.
We
proposed
the
term
"
process
unit"
as
the
appropriate
collection
to
accommodate
the
intended
coverage
of
activities
under
the
ERP.
The
purpose
of
this
term
is,

to
the
extent
possible,
to
align
implementation
of
the
ERP
with
generally
accepted
and
practical
understandings
of
what
constitutes
a
discrete
production
process.
The
general
definition
that
we
proposed
was
based
closely
on
the
definition
of
process
unit
contained
in
40
CFR
63.41
and
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.

To
help
illustrate
these
concepts,
we
further
proposed
five
industry­
specific
examples
of
how
this
definition
of
process
unit
might
be
applied.

Some
commenters
compared
the
proposal's
definition
of
"
process
unit"
("...
producing
or
storing
a
completed
product...")
to
the
definition
that
is
used
by
section
112(
g)
and
that
appears
in
40
CFR
63.41
("...
producing
or
storing
an
intermediate
or
final
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product...").
One
of
the
commenters
supported
the
more
narrow
proposed
definition.
Two
commenters
said
the
rule's
definition
should
be
consistent
with
that
used
by
section
112(
g),
which
they
believe
is
broad
enough
to
encompass
interrelated
operations.
While
supporting
the
RMRR
proposal's
definition,
two
commenters
recommended
that
EPA
provide
regulatory
flexibility
by
allowing
a
facility
the
option
to
choose
which
definition
it
will
use.

One
commenter
generally
supported
the
proposed
definition
of
"
process
unit,"
but
this
commenter
believed
that
"
the
delineation
of
a
process
unit
should
be
made
by
regulated
entity
rather
than
explicitly
defined
in
a
rule."

Three
commenters
asserted
that
pollution
control
equipment
should
be
included
in
the
process
unit
definition.

One
industry
commenter
said
pollution
control
equipment
is
often
integral
to
the
process
and
may
produce
an
intermediate
product.
One
environmental
commenter
believed
the
proposed
rule
was
unclear
as
to
whether
pollution
control
equipment
is
part
of
the
process
unit.

Several
commenters
said
the
proposed
definition
is
too
vague
or
broad.
Another
commenter
added
that
the
proposed
definition
is
inconsistent
with
title
V
of
the
CAA.
Another
commenter
urged
EPA
to
change
the
definition
of
process
unit
to
limit
the
scope
of
what
is
allowed
in
the
ERP,
so
that
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the
source
of
emissions
(
for
example,
an
entire
coal
boiler)

would
not
be
allowed
to
be
replaced
without
major
NSR.
The
commenter
asserted
that
the
replacement
unit's
scope
should
be
limited
to
an
emission
unit.

Most
commenters
agreed
that
the
general
process
unit
definition
is
sufficient.
However,
a
number
of
commenters
suggested
that
we
revise
or
eliminate
some
of
the
process
unit
examples
(
that
is,
the
industry
category­
specific
definitions),
and
others
were
concerned
that
the
proposed
definitions
do
not
support
the
detailed
process
unit
definition
for
a
specific
industry
because
the
definitions
will
never
capture
all
possible
elements
and
configurations.

We
received
comments
from
several
industry
representatives
suggesting
changes
to
our
proposed
industryspecific
definitions,
and
also
to
request
that
we
delineate
other
process
unit
types
explicitly
in
the
rule.

Definitions
were
submitted
for
sugar
mills,
chemical
manufacturing
plants,
surface
coating
operations,
flat
glass
manufacturing,
fiberglass
manufacturing,
and
gas
compressor
stations.

One
industry
commenter
agreed
with
our
proposed
approach
to
proportionately
allocate,
based
on
capacity,
the
cost
of
those
components
shared
by
two
or
more
process
units.
Another
commenter
suggested
that,
for
electric
utilities,
we
allocate
the
cost
of
shared
equipment
based
on
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a
pro
rata
share
of
megawatts
produced.

We
agree
with
the
commenters
who
favor
using
a
process
unit
as
the
basis
for
administering
the
ERP
and
including
a
definition
of
process
unit
in
the
final
rule.
We
also
agree
with
the
commenters
who
suggested
that
the
definition
of
process
unit
should
be
consistent
with
the
definition
in
40
CFR
63.41,
and
we
have
altered
the
final
rule
definition
to
include
those
processes
that
produce
"
intermediates."
We
acknowledge
that,
without
further
explanation,
the
term
"
intermediates"
is
susceptible
to
misinterpretation,
which
can
cause
confusion
and
lead
to
less
regulatory
certainty.

Thus,
we
provide
the
following
explanation
as
to
how
we
intend
to
interpret
today's
rule.

By
"
intermediates,"
we
mean
the
intended
product
of
an
integrated
facility
operation.
For
example,
for
an
automotive
manufacturing
plant,
while
the
completed
product
would
be
the
driveable
vehicle
ready
for
shipping
to
the
showroom,
an
intermediate
product
could
be
the
engine
or
the
painted
body
shell.
In
this
case,
we
would
not
consider
smaller
production
operations,
such
as
the
production
of
the
pistons
or
wheel
well
frame,
to
be
an
intermediate
in
the
context
of
our
final
rule
definition
for
process
unit.
Our
primary
goal
in
defining
this
term
"
process
unit"
is
to
encompass
integrated
manufacturing
operations
that
produce
a
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completed
product,
and
those
operations
that
produce
an
intermediate
as
the
product
of
the
process
unit.

We
disagree
with
the
commenters
who
wish
to
include
all
pollution
control
equipment
in
the
definition
of
process
unit.
We
feel
that
periodic
replacement
of
parts
of
emissions
control
equipment
should
be
encouraged
and
would
rarely
lead
to
actual
emissions
increases.
In
instances
where
identical
or
functionally
equivalent
replacement
of
pollution
control
equipment
occurs,
it
is
likely
you
will
qualify
for
a
Pollution
Control
Project
exclusion.
See
67
FR
80186.
We
do
agree,
however,
that
where
the
control
equipment
is
an
integral
part
of
the
process
it
should
be
included.
Therefore,
we
are
excluding
associated
pollution
control
equipment
from
the
definition
of
the
"
process
unit,"

except
for
control
equipment
that
serves
a
dual
purpose
in
the
process.
We
know
there
are
industries
where
pollution
control
equipment
performs
a
dual
purpose;
for
example,

condensers
often
serve
to
control
emissions
of
organic
air
pollutants
while
serving
as
a
integral
part
of
the
operation
of
a
fractionation
column.
A
low­
NOx
burner
is
another
example
of
a
dual­
purpose
part.
In
such
cases,
to
provide
clarity
and
simplify
administration
of
the
ERP,
our
rule
provides
that
dual
purpose
equipment
should
be
considered
part
of
the
process.
We
are
also
clarifying
in
today's
rule
that
administrative
buildings
(
including
warehousing)
are
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not
to
be
included
in
the
process
unit,
but
other
types
of
non­
emitting
units
that
are
integral
to
the
processing
equipment
should
be
included.

We
also
have
included
in
our
final
rule
industryspecific
examples
of
how
this
definition
might
be
applied.

The
examples
are
drawn
for
three
selected
industrial
processing
categories
 
electric
utilities,
refineries,
and
incinerators.
We
proposed
each
of
these
detailed
definitions
and
received
mostly
support
from
commenters
on
their
accuracy.
While
we
also
proposed
detailed
definitions
for
two
other
industries
 
pulp
and
paper
and
cement
producers
 
we
have
decided
not
to
finalize
those
definitions
after
receiving
comments
from
the
relevant
industry
trade
association
asserting
that
the
definitions
did
not,
and
could
not,
capture
all
of
their
industry's
configurations
and
they
believed
the
generic
process
unit
definition
was
sufficient
for
their
industry.
Because
of
the
centrality
of
the
"
process
unit"
concept
to
the
usefulness
of
the
ERP,
it
is
our
desire
to
include
specific
definitions
for
steam
electric
generating
facilities,

petroleum
refineries,
and
incinerators
in
the
final
rule
to
provide
as
much
certainty
as
possible
for
facilities
in
these
industries.
As
noted
above,
thse
defintions
also
should
be
useful
for
those
in
other
industries
who
will
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apply
our
general
definition
because
the
industry
specific
definitions
provide
clear
examples
of
how
we
intend
the
general
definition
to
be
interpreted
and
applied.
During
the
public
comment
period
on
the
proposal,
several
commenters
submitted
additional
industry
specific
definitions
and
asked
us
to
put
them
in
the
final
rule.
We
are
not
finalizing
these
suggested
definitions
at
this
time,

because
we
did
not
include
them
in
the
proposed
rule.

However,
provided
below
are
the
process
unit
definitions
that
commenters
submitted
to
us
and
that
we
think
comport
well
with
the
general
definition
of
process
unit
promulgated
today.

°
For
a
natural
gas
compressor
station,
each
compressor
system,
together
with
its
proportionate
share
of
common
support
equipment
is
a
separate
process
unit.
For
facilities
operating
in
the
midstream
segment
of
the
natural
gas
industry,
the
gas
compression
process
unit
consists
of
those
portions
of
a
natural
gas
compressor
station,
natural
gas
liquids
extraction
and
production
plant,
and
natural
gas
processing
plant
that
contain
the
combination
of
equipment
necessary
to
compress
natural
gas
for
the
purpose
of
establishing
and
maintaining
the
process
flow
and
delivery
of
such
gas
and
liquids.

°
For
a
flat
glass
manufacturing
plant,
each
production
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line
within
a
facility
should
be
a
separate
process
unit.
Flat
glass
production
is
completed
on
a
continuous
line
where
raw
materials
are
added
at
one
end,
a
continuous
ribbon
of
glass
is
formed,
and
finished
glass
is
packaged
at
the
other
end.
The
flat
glass
production
line
consists
of:
the
batch
house,

where
raw
materials
are
stored
and
weighed;
the
furnace
and
refiner,
where
the
raw
materials
are
melted;
the
bath,
where
the
glass
ribbon
is
formed;
the
lehr,
where
the
ribbon
is
annealed;
and
the
cutting
and
packaging
equipment,
where
the
glass
is
removed
from
the
line
for
sale
to
customers
or
for
additional
processing
later.

°
For
a
fiberglass
production
facility,
each
production
line
is
a
separate
process
unit.
Fiberglass
is
manufactured
on
a
continuous
line
where
raw
materials
are
melted
at
one
end
to
form
a
continuous
strand
of
fiberglass
that
is
packaged
at
the
other
end.
The
fiberglass
production
line
begins
with
the
batch
house,

where
raw
materials
are
stored
and
weighed.
In
the
melter,
forehearth,
and
refiner,
the
raw
materials
are
melted
and
refined.
From
the
refiner,
glass
fibers
are
formed
through
controlled
bushings.
From
the
bushings,

the
continuous
strand
fibers
are
either
directly
cut
or
packaged
or
wound
onto
spools
for
packaging
for
sale
to
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customers
or
for
additional
later
processing.

°
For
the
production
of
precipitated
amorphous
silica,

the
process
unit
includes,
but
is
not
limited
to:
raw
material
storage
and
handling
equipment
used
for
mixing
sand
and
other
raw
materials
prior
to
addition
to
the
furnace;
the
furnace
itself;
the
raw
material
storage
and
handling
equipment
for
the
cullet
dissolving
and
silica
precipitation
process;
all
dissolving,

precipitation,
and
filtration
tanks
and
equipment;
and
drying
equipment.
Further,
the
process
unit
includes
all
the
product
packaging,
storage,
handling,
and
transfer
equipment.

°
For
a
chemical
manufacturing
plant,
the
process
unit
would
include
all
the
equipment
assembled
and
connected
by
pipes
or
ducts
to
process
raw
materials
and
to
manufacture
an
intended
primary
product
and
associated
byproducts
or
intermediates.
The
process
unit
can
consist
of
more
than
one
unit
operation.
Chemical
manufacturing
process
units
may
include,
but
are
not
limited
to:
raw
material
storage,
and
air
oxidation
reactors
and
their
associated
product
separators
and
recovery
devices;
reactors
and
their
associated
product
separators
and
recovery
devices;
distillation
units
and
their
associated
distillate
receivers
and
recovery
devices;
associated
unit
operations;
associated
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recovery
devices;
and
any
feed,
intermediate
and
product
storage
vessels,
product
transfer
racks,
and
connected
ducts
and
piping.
A
chemical
manufacturing
process
unit
includes
pumps,
compressors,
agitators,

pressure
relief
devices,
sampling
connection
systems,

open­
ended
valves
or
lines,
valves,
connectors,

instrumentation
systems,
and
control
devices
or
systems.
For
a
chemical
manufacturing
facility,
there
are
several
types
of
process
units:
those
that
separate
and
distill
raw
material
feedstocks;
those
that
change
molecular
structures
through
reactions
or
polymerization;
those
that
"
finish"
the
reacted
or
polymerized
product,
through
compounding,
blending,
or
similar
operations;
auxiliary
facilities,
such
as
boilers
and
by­
product
fuel
production;
and
those
that
load,
unload,
blend,
or
store
products.
Process
equipment
that
acts
to
control
emissions,
such
as
condensers,
recovery
devices,
and
oxidizers,
is
considered
part
of
the
process
unit.

°
For
a
coatings
facility,
the
process
unit
includes
any,

all,
or
a
combination
of
raw
material
storage,

reaction,
recovery,
separation,
purification,
blending
or
other
activity,
operation,
manufacture,
or
treatment.
Cleaning
operations
are
part
of
the
process
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unit.
Nondedicated
solvent
recovery
operations
located
within
a
contiguous
area
within
the
affected
source
are
considered
a
single
process
unit.
Nondedicated
formulation
operations
(
not
including
mixing,
as
defined)
occurring
within
a
contiguous
area
are
considered
a
single
process
unit
that
is
used
to
formulate
numerous
materials
and/
or
products.

°
At
a
sugar
mill,
there
are
two
types
of
process
units.

One
type
of
process
unit
includes
all
of
the
portions
of
the
plant
that
contribute
directly
to
the
production
of
steam.
This
process
unit
includes
the
combination
of
systems
from
the
bagasse
handling
system
through
to
the
emission
stack,
including
the
bagasse
handling
equipment,
feedwater
system,
combustion
air
system,

boiler,
burners,
air
preheaters,
superheaters,
flues,

stack,
and
fuel
oil
storage
and
piping
system.
The
second
type
of
process
unit
includes
those
portions
of
the
plant
that
contribute
directly
to
the
production
of
refined
sugar
from
raw
sugar
and
the
associated
packaging
and
shipping
operations.

Finally,
we
have
made
some
slight
corrections
to
the
process
unit
definitions
that
we
proposed
based
on
comments
we
received
on
the
proposed
definitions.

There
are
numerous
industries
that
have
industrial
boilers
at
their
facility
to
provide
electricity
and
steam
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to
their
operations.
As
a
general
rule,
we
would
expect
these
boilers
to
be
treated
as
a
separate
process
unit
from
the
other
unit
operations
occurring
at
the
facility.
We
would
expect
the
boundaries
of
the
process
units
for
such
boilers
to
be
consistent
with
the
boundaries
established
under
the
definition
for
a
steam
electric
generating
facility
in
today's
rule,
which
encompasses
all
equipment
from
coal
handling
to
the
emission
stacks.

We
also
decided
to
continue
to
require
that
owners
or
operators
who
have
parts
shared
by
two
or
more
process
units
to
proportionately
allocate,
based
on
capacity,
the
cost
of
those
parts.
And
we
agree
with
the
commenter
that
an
equitable
approach
for
electric
utilities
having
parts
shared
by
two
or
more
process
units
is
to
allocate
the
cost
of
shared
equipment
based
on
the
pro
rata
share
of
megawatts
produced
by
each
process
unit.

G.
Consideration
of
Non­
emitting
Units
as
Part
of
the
Process
Unit
Many
commenters
supported
excluding
non­
emitting
equipment
from
the
ERP.
One
commenter
stated
that
triggering
the
major
NSR
review
process
for
maintenance
activities
is
an
impediment
to
continuous
improvement
projects
for
certain
products
and
processes,
even
if
actual
emissions
decrease
or
only
non­
emitting
units
on
the
process
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line
are
affected.
Delays
or
postponements
of
project
maintenance
work
adversely
affect
the
reliability,
safety
and
productivity
of
operations
and
cost
control
efforts.

Another
commenter
recommended
that
work
at
clearly
nonemitting
units,
specifically
including
foundation
regrouting
and
repair
and
frametop
replacement,
should
be
excluded
from
this
rule.
Three
commenters
believed
that
non­
emitting
units
cannot
result
in
an
increase
of
emissions
and
thus
do
not
need
to
be
evaluated
under
major
NSR.

A
blanket
exclusion
for
non­
emitting
units
could
create
problems
of
interpretation
because
the
term
"
non­
emitting
components"
is
ambiguous
when
considering
certain
components.
Commenters
asserted
that
identifying
and
separating
out
non­
emitting
components
can
be
a
complex
undertaking,
and
may
be
contrary
to
the
goal
of
a
clear
and
straightforward
option.
One
commenter
provided
the
following
examples:
(
1)
Piping
systems
(
although
pipe
connectors
are
a
source
of
fugitive
emissions,
the
pipe
normally
is
not);
and
(
2)
structural
supports
for
a
process
unit
(
separating
out
the
cost
of
supports
from
an
investment
basis
throughout
a
facility
will
be
difficult).

Another
commenter
believed
it
would
be
difficult
to
separate
the
costs
of
emitting
and
non­
emitting
equipment
when
determining
the
cost
of
the
process
unit.
The
commenter
also
believed
it
would
be
difficult
to
determine
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allocation
of
shared
equipment
in
the
cost
analysis.

We
are
concerned
that,
if
owners
or
operators
were
allowed
to
strip
away
all
of
the
non­
emitting
parts
from
a
process
unit
definition,
it
would
create
significant
ambiguity
in
the
rule
and
could
result
in
significant
variation
in
how
the
rule
is
applied
to
similar
sources
in
different
jurisdictions.
In
addition,
we
simply
do
not
think
it
is
practical
or
logical
to
separate
"
non­
emitting"

parts
of
a
process
unit
from
"
emitting"
parts.
We
believe
that
integrated
manufacturing
operations
(
that
is,
process
units)
typically
include
both
types
of
equipment.

Separating
emitting
from
non­
emitting
equipment
would
create
an
artificial
divide
that
contrasts
sharply
with
physical
and
operational
reality.

As
noted
above,
however,
we
do
believe
that
a
distinction
should
be
made
between
non­
emitting
equipment
that
is
part
of
a
process
unit
and
non­
emitting
equipment
that
is
functionally
distinct
from
the
process
unit.
For
example,
most
production
facilities
have
buildings
or
space
to
house
administrative
offices,
such
as
offices
for
the
plant
accounting
staff.
Such
non­
emitting
facilities
should
not
be
considered
part
of
any
process
unit
under
today's
rule.

H.
What
is
the
accounting
basis
for
the
process
unit?
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In
the
proposal,
the
accounting
basis
for
the
ERP
discussed
was
the
same
as
for
the
NSPS
reconstruction
provision,
which
is
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
unit.
We
also
discussed
for
the
annual
maintenance,
repair
and
replacement
allowance
using
the
invested
cost
of
a
unit
as
the
accounting
basis.
We
proposed
that
it
would
be
appropriate
to
require
that
costs
be
calculated
using
an
approach
along
the
lines
set
out
in
the
EPA
Air
Pollution
Control
Cost
Manual
(
http://
www.
epa.
gov/
ttn/
catc/
dir1/
c_
allchs.
pdf).

Finally,
we
solicited
comment
on
whether
the
costs
associated
with
the
unanticipated
shutdown
of
equipment,
due
to
component
failure
or
catastrophic
failures
such
as
explosions
or
fires,
should
be
included
in
evaluating
costs
under
the
ERP.

In
reviewing
comments,
we
recognized
that
some
commenters
appeared
to
direct
their
comments
on
the
accounting
methods
at
the
annual
maintenance,
repair
and
replacement
allowance,
and
not
necessarily
the
ERP.
Often,

we
came
to
this
conclusion
simply
by
the
way
the
commenters
organized
their
comments,
and
not
by
any
specific
statements
in
the
comment
letter.
However,
since
we
asked
for
comment
on
the
accounting
approaches
as
they
would
be
applied
to
both
the
annual
maintenance,
repair
and
replacement
allowance
and
the
ERP,
we
believe
that
comments
that
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appeared
to
be
dedicated
to
the
annual
maintenance,
repair
and
replacement
allowance
should
also
apply
to
our
evaluation
of
the
accounting
for
the
ERP,
except
in
the
case
where
the
commenter
specified
that
their
comments
on
the
proposed
accounting
methods
applied
only
to
the
Annual
MRR
allowance
or
the
ERP.
Likewise,
for
considering
whether
costs
associated
with
unanticipated
shutdown
of
equipment,

we
considered
the
comments
to
apply
to
both
the
ERP
and
the
annual
maintenance,
repair
and
replacement
allowance
unless
the
commenter
specifically
noted
that
the
comment
should
not
be
applied
to
both
of
the
proposed
rule
provisions.

Most
commenters
asked
for
flexibility
on
whether
a
facility
should
use
replacement
value,
invested
cost
or
insurance
valuation
as
the
basis
for
the
calculations.
They
felt
that
all
were
of
equal
merit
and
different
ones
would
be
available
at
different
facilities
so
EPA
should
not
prescribe
only
one
type.

Most
commenters
did
not
support
the
sole
use
of
the
EPA
Air
Pollution
Control
Cost
Manual
(
APCCM)
to
standardize
calculations
for
replacement
and
repair
costs
for
RMRR
in
general.
Most
commenters
felt
that
the
APCCM
is
a
worthy
reference
for
costing
but
also
that
sources
should
not
be
limited
to
only
one
manual,
because
a
single
manual
is
likely
to
have
shortcomings
and
not
be
able
to
represent
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every
situation.

Many
commenters
supported
an
exclusion
of
costs
for
unanticipated
shutdowns
and
failures.
They
noted
that
strong
incentives
exist
to
avoid
fires,
explosions
and
other
unanticipated
equipment
failures
because
of
the
risk
of
human
injury
and
production
interruptions
and
because
of
the
expense
involved
in
restoring
lost
capacity.
As
a
result,

they
contend
that
a
catastrophic
event
already
penalizes
the
facility
dramatically,
but
then
to
impose
the
case­
by­
case
analysis
would
only
exacerbate
their
troubles.
They
explained
that
failures
take
place
occasionally
and
can
result
in
a
sudden,
unplanned
partial
or
total
loss
of
equipment.
When
such
a
failure
occurs
at
a
natural
gas
compressor
station,
the
turbine
or
engine
concerned
must
be
replaced
immediately
to
avoid
a
disruption
in
gas
supply.

Other
facilities
may
have
similar
pressures
to
maintain
their
product
around
the
clock.
Such
replacement
fits
easily
within
most
elements
of
the
equipment
replacement
test.
Commenters
asserted
that
replacing
a
catastrophically
failed
turbine
or
engine
is
clearly
"
routine,"
since
companies
will
always
replace
such
failures.

Other
commenters,
however,
opposed
an
exclusion
for
unanticipated
shutdowns
and
failures
on
the
grounds
that
maintenance
activities
performed
during
forced
outages
are
simply
maintenance
and
should
be
considered
as
such,
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particularly
given
that
the
proposed
RMRR
rule
approaches
and
the
December
2002
final
rules
already
have
given
the
industry
a
number
of
exclusion
options.

We
are
allowing
sources
to
determine
the
applicability
of
today's
rule
on
the
basis
of
replacement
value,
with
an
option
for
sources
to
notify
their
reviewing
authority
in
writing
if
they
desire
to
use
another
option
(
for
example,

invested
cost
or
insurance
value
where
the
insurance
value
covers
only
the
complete
replacement
of
the
process
unit).

The
equipment
replacement
cost
should
be
based
on
the
current
replacement
value
of
the
entire
process
unit
at
the
time
of
conducting
the
activity.

Typically,
replacement
value
is
more
easily
obtained
than
invested
cost.
Most
manufacturers
will
have
information
concerning
the
replacement
value
of
a
process
unit,
because
such
costs
are
commonly
used
when
evaluating
various
business
scenarios
relating
to
manufacturing
costs.

Also,
use
of
replacement
value
is
consistent
with
the
NSPS
provisions.

In
addition
to
determining
the
replacement
value
of
a
process
unit,
in
our
final
rule
we
allow
for
the
use
of
several
other
accepted
methods
in
different
industries
for
estimating
such
values.
Replacement
values
are
the
estimated
value
of
replacing
a
unit
and
can
be
based
on
a
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2003
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current
appraisal.
In
lieu
of
replacement
cost,
you
can
also
use
inflation­
adjusted
original
investment,
insurance
limits
if
insured
for
full
replacement
of
the
unit,
or
other
cost
estimation
techniques
currently
employed
by
the
company,
as
long
as
the
company
follows
GAAP
and
if
approved
by
the
reviewing
authority.

A
dollar­
per­
kilowatt
rate
for
calculating
costs
may
be
appropriate
for
utilities.
This
model
is
specific
to
source
and
fuel
type
and
is
updated
periodically.
We
allow
sources
to
use
insurance
valuation
methods
such
as
the
Handy­
Whitman
Index
to
determine
replacement
costs
for
electric
utilities.

Other
sources
to
compute
costs
include
the
Nelson
Refinery
Construction
Index
Factors,
Solomon
Refinery
Study,
and
licensors
of
the
respective
process
unit
(
e.
g.,
Kellogg,

UOP).

In
order
for
a
cost­
based
approach
to
be
equitable,
all
owners
or
operators
must
include
the
same
categories
of
expenses
in
both
the
process
unit
replacement
value
and
the
replacement
activities
sought
to
be
exempted.
Therefore,

although
the
final
rule
does
not
mandate
any
particular
approach,
we
believe
it
is
generally
appropriate
to
calculate
costs
using
an
approach
similar
to
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
Internal
and
Deliberative
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August
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2003
74
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
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.

In
certain
cases,
other
manuals
might
make
more
sense
depending
on
their
circumstances.

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
should
be
excluded
from
the
cost
calculation,
as
per
our
discussion
in
the
previous
section
of
this
preamble.
We
believe
equipment
that
serves
a
dual
purpose
of
process
equipment
and
control
equipment
(
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.

Direct
installation
costs
include
costs
for
foundations
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22,
2003
75
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
(
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
agree
with
commenters
who
oppose
a
categorical
exclusion
for
unanticipated
shutdowns
and
failures.
Whether
an
activity
is
planned
or
unanticipated,
major
NSR
applicability
should
function
the
same
way.
Therefore,

replacements
resulting
from
unanticipated
outages
are
not
excluded
from
major
NSR
unless
they
qualify
as
RMRR
or
for
another
exclusion
from
major
NSR.
To
the
degree
they
exceed
the
ERP
cost
threshold,
replacement
activities
resulting
from
unanticipated
shutdowns
or
failures
should
be
evaluated
on
a
case­
by­
case
basis
for
RMRR.
In
the
case
of
a
catastrophic
loss,
unless
you
increase
your
plant
size
considerably,
it
is
likely
that
you
would
replace
your
failed
equipment
with
a
more
efficient
and
cleaner
part,
and
such
replacement
would
not
trigger
major
NSR
because
the
actual­
to­
projected­
actual
applicability
test
would
not
result
in
an
emissions
increase.

I.
Enforcement
Internal
and
Deliberative
Draft
­
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not
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or
distribute
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2003
76
Today's
rule
provides
revisions
to
the
major
NSR
program
to
specify
categories
of
equipment
replacement
activities
that
EPA
will
consider
RMRR
in
the
future.
As
recognized
by
the
U.
S.
Supreme
Court,
an
agency
may
not
promulgate
retroactive
rules
absent
express
congressional
authority.
See
Bowen
v.
Georgetown
Univ.
Hosp.,
488
U.
S.

204,
208,
102
L.
Ed.
2d
493,
109
S.
Ct.
468
(
1988).
The
Clean
Air
Act
contains
no
such
expressed
grant
of
authority
and
EPA
does
not
intend
by
its
actions
today
to
create
retroactive
applicability
for
today's
rule.
42
U.
S.
C.

§
§
7401
et
seq.

None
of
today's
rule
revisions
apply
to
any
changes
that
are
the
subject
of
existing
enforcement
actions
that
the
Agency
has
brought
and
none
constitute
a
defense
thereto.
Furthermore,
prior
applicability
determinations
on
major
modifications
and
the
control
requirements
that
currently
apply
to
sources
remain
valid
and
enforceable.

As
noted
above,
today
we
are
changing
certain
exemptions
to
the
major
NSR
program
by
taking
final
action
on
the
ERP.
If
you
are
subsequently
determined
not
to
have
met
the
applicable
provisions
of
these
new
alternatives,
you
will
be
subject
to
any
applicable
enforcement
provisions
(
including
the
possibility
of
citizens'
suits)
under
the
applicable
sections
of
the
Act.
Sanctions
for
violations
of
Internal
and
Deliberative
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or
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2003
77
these
provisions
may
include
monetary
penalties
of
up
to
$
27,500
per
day
of
violation,
as
well
as
the
possibility
of
injunctive
relief,
which
may
include
the
requirement
to
install
air
pollution
controls.

J.
Quantitative
Analysis
At
proposal,
we
presented
a
quantitative
analysis
of
the
possible
emissions
consequences
of
the
range
of
different
approaches
to
the
RMRR
exclusion,
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
stated
that
the
results
for
electric
utilities
accurately
reflect
the
trends
we
would
see
in
other
industries.

The
IPM
analyses
of
different
scenarios
showed
that
the
breadth
of
the
RMRR
exclusion
would
have
no
practical
impact
on,
let
alone
be
the
controlling
factor
in
determining,
the
emissions
reductions
that
will
be
achieved
in
the
future
under
the
major
NSR
program.
The
analyses
showed
that
emissions
of
SO2
are
essentially
the
same
under
all
scenarios,
but
that
under
today's
rule
these
emission
levels
will
be
met
in
a
more
economically
efficient
manner
than
the
base
case.
This
stands
to
reason
because
nationwide
emissions
of
SO2
from
the
power
sector
are
capped
by
the
Internal
and
Deliberative
Draft
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2003
78
title
IV
Acid
Rain
Program.
For
NOx,
these
analyses
showed
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.
What
these
analyses
indicate,
however,
is
that
regardless
of
which
scenario
is
closest
to
what
comes
to
pass,
today's
rule
will
not
have
a
significant
impact,
up
or
down,
on
emissions
from
the
power
sector.
However,
we
expect
the
rule
to
result
in
significant
improvements
in
safety,
reliability,
and
other
relevant
operational
parameters.

The
DOE
also
presented
further
analysis
of
the
possible
emissions
consequences
of
the
range
of
different
approaches
to
the
RMRR
exclusion.
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
regulatory
revisions.
This
analysis
concluded
that
efficiency
improvements
resulting
from
increased
maintenance,
repair
and
replacement
are
expected
to
decrease
emissions,
whereas
availability
improvements
are
expected
to
increase
emissions.
In
the
Internal
and
Deliberative
Draft
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or
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2003
79
cases
represented
in
this
analysis,
the
emissions
reductions
from
assumed
reductions
in
heat
rates
tended
to
dominate
the
corresponding
effects
of
the
assumed
availability
increases.

A
number
of
commenters
said
that
the
underlying
assumptions
EPA
used
in
the
IPM
analysis
were
flawed
and
resulted
in
erroneous
conclusions
regarding
the
emission
reduction
potential
of
the
proposed
RMRR
rules.
Several
commenters
stated
that
EPA's
IPM
analysis
incorrectly
assumes
that
no
major
modifications
at
any
older
units
would
ever
trigger
the
requirement
to
add
new
pollution
controls.

In
addition,
according
to
commenters,
EPA
also
erroneously
assumes
that
this
lack
of
major
maintenance,
repair
and
replacement
will
have
very
little
impact
on
the
performance
of
those
power
plants,
when
in
reality
their
emissions
would
increase
significantly.
The
commenters
cite
a
Clean
Air
Task
Force
analysis
for
power
plants,
which
estimates
that
EPA's
rule
revisions
will
result
in
at
least
7
million
more
tons
of
SO2
and
2.4
million
more
tons
of
NOx
annually.
Some
commenters
also
questioned
the
appropriateness
of
using
EPA's
analysis
for
the
electric
generating
sector
to
draw
conclusions
about
non­
utilities.

One
commenter
said
the
IPM
and
DOE
NEMS
analyses
correctly
demonstrate
that
EPA's
RMRR
proposal
will
have
no
appreciable
impact
on
emissions
from
the
power
sector.

According
to
the
commenter,
this
conclusion
is
consistent
Internal
and
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2003
80
with
EPA's
findings
in
a
1989
report,
"
1989
EPA
Base
Case
Forecasts,"
which
demonstrated
that
continuing
to
allow
utilities
to
undertake
activities
including
ongoing
annual
operating
and
maintenance
activities
and
a
major
refurbishment
when
the
unit
reached
30
years
of
operating
life
would
have
no
appreciable
impact
on
emissions
from
the
power
sector,
just
as
EPA's
and
DOE's
recent
analysis
confirmed.

One
commenter
said
the
proposal
lacks
any
reference
to
the
gains
accomplished
by
major
NSR,
the
ongoing
enforcement
actions,
settlements
reached
as
a
result
of
those
actions,

or
the
potential
gains
from
the
investigations
now
pending.

EPA's
reliance
on
improvements
in
productive
capacity
as
the
measure
of
success
fails
to
consider
that
productive
capacity
must
be
balanced
with
the
interests
of
health
and
welfare.
The
commenter
also
noted
that
critical
to
EPA's
burden
to
consider
all
the
relevant
factors
leading
to
its
conclusion
that
the
exemptions
are
necessary
and
appropriate
is
at
the
very
least
an
assessment
of
the
expected
effects
on
emissions,
which
in
turn
will
determine
the
public
health
benefits
and
costs
of
the
proposed
rule.
Although
data
on
emission
reductions
achieved
under
the
existing
program
are
available,
we
have
stated
that
we
cannot
precisely
quantify
the
effects
the
proposed
rule
will
have
on
emissions.
Some
Internal
and
Deliberative
Draft
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or
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August
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2003
81
commenters
stated
that
before
promulgating
a
final
rule,
EPA
should
provide
such
a
quantitative
assessment
of
the
rule.

We
disagree
with
the
commenters
who
believe
that
emissions
would
be
significantly
higher
for
electric
utilities
than
are
estimated
under
the
IPM
model
runs.

These
commenters'
arguments
rely
on
the
assumption
that
EPA's
base
case
is
invalid
because,
if
major
NSR
rules
were
left
unchanged,
eventually
all
coal­
fired
utilities
would
either
apply
BACT
or
deteriorate
so
badly
that
they
would
have
to
shut
down.
We
do
not
believe
this
assumption
is
accurate.
Our
experience
suggests
that
under
the
current
NSR
program,
managers
of
coal­
fired
electric
generating
facilities
take
whatever
actions
are
necessary
to
avoid
triggering
major
NSR,
primarily
because
of
its
high
retrofit
costs
and
delays.
If
some
maintenance,
repair
and
replacement
activities
could
trigger
major
NSR,
facilities
will
limit
their
activities
to
those
projects
that
do
not
trigger
major
NSR,
and
will
take
enforceable
restrictions
on
fuel
use
or
other
actions
to
avoid
major
NSR.
This
results
in
some
decline
in
efficiency
and
capacity,
as
the
EPA's
base
case
modeled,
but
the
units
would
likely
remain
viable
electric
generating
units
for
years
without
triggering
BACT
requirements.
Thus,
we
believe
our
base
case
represents
a
far
more
realistic
assessment
of
what
would
happen
under
current
major
NSR
rules
than
the
dramatic
BACT
reductions
Internal
and
Deliberative
Draft
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August
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2003
82
presented
by
these
commenters.

Furthermore,
while
some
of
the
facilities
may
be
modified
and
subjected
to
control,
nationwide
emissions
as
estimated
in
the
model
runs
would
still
rise
to
the
level
of
the
Acid
Rain
cap
for
SO2.
To
the
degree
these
modifications
come
at
facilities
that
are
otherwise
projected
to
be
controlled
because
of
existing
SO2
and
NOx
requirements,
there
would
be
no
difference
in
effect
between
the
model
runs
and
alternative
scenarios.
We
agree
with
the
commenter
who
noted
that
the
recent
analysis
and
the
estimated
impact
on
emissions
is
consistent
with
the
previous
EPA
report
in
1989.
Our
recent
analysis
confirms
that
efficiency
improvements
have
the
potential
to
result
in
environmental
benefits
that
offset
(
or
more
than
offset)

emissions
increases
from
improved
availability,
but
that
previous
major
NSR
rules
discouraged
these
improvements.

Regarding
the
applicability
of
our
analysis
to
nonutility
sectors,
we
continue
to
believe
that
our
conclusions
are
valid
for
all
sectors,
and
further,
that
the
effects
from
the
electric
utility
industry
dominate
those
from
other
sectors.
We
acknowledge
that
the
results
for
the
SO2
cap
for
utilities
cannot
be
extended
to
non­
utilities
that
are
not
similarly
capped.
However,
our
model
runs
for
NOx
reflected
the
absence
of
a
cap,
and
are
therefore
valid
for
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and
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2003
83
other
uncapped
sectors.
Thus
in
the
case
of
industrial
boilers,
which
behave
similarly
to
utilities,
we
would
expect
to
see
similar
efficiency
improvements
and
availability
improvements
occurring
in
tandem,
resulting
in
either
modest
increases
or
decreases.
Because
the
overall
emissions
from
this
sector
are
significantly
smaller
than
for
utilities,
the
modeled
effects
for
utilities
are
expected
to
dominate
the
analysis.

Finally,
for
other
industrial
sectors,
we
do
not
anticipate
that
emissions
increases
will
result
from
equipment
replacement
activities
that
qualify
as
RMRR
under
today's
rule.
While
some
efficiency
improvements
may
result,
the
overall
effect
of
these
improvements
will
not
be
to
induce
greater
demand
and
greater
emissions,
as
was
shown
by
the
modeling
for
utilities
(
i.
e.,
demand
depends
on
independent
factors).
Indeed,
without
increased
demand,

efficiency
improvements
that
lower
emissions
per
unit
of
output
would
result
in
a
decrease
in
emissions.

[
ADD
INSERT
HERE
FROM
AL
MCGARTLAND:
If
you
consider
the
long­
term
effects
of
this
rule....]

In
addition,
we
note
that
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
Internal
and
Deliberative
Draft
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2003
84
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
rule.

Therefore,
based
on
the
information
evaluated,
we
affirm
the
overall
conclusion
of
our
analysis
 
that
today's
rule
has
no
practical
effect
on
the
environmental
benefits
of
major
NSR
in
the
future.
We
have
presented
additional,

more
detailed
supporting
information
in
our
final
RIA
and
our
response
to
comments
document,
both
of
which
can
be
found
in
the
docket
for
today's
action.

K.
Consideration
of
Other
Options
In
addition
to
the
cost­
based
approaches
that
we
Internal
and
Deliberative
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August
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2003
85
proposed,
we
also
asked
for
comment
on
age­
based
and
capacity­
based
approaches,
and
any
other
viable
option
for
addressing
RMRR.

1.
Annual
Maintenance,
Repair
and
Replacement
Allowance
We
are
not
taking
action
on
the
proposed
Annual
Maintenance,
Repair
and
Replacement
Allowance
option
for
the
RMRR
exclusion,
and
therefore
public
comments
on
this
option
are
not
addressed
at
this
time.
We
will
address
comments
on
our
proposed
Annual
Maintenance,
Repair
and
Replacement
Allowance
if
and
when
we
take
final
action
on
that
proposal.

2.
Capacity­
Based
Option
As
mentioned
above,
we
considered
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
does
not
increase
the
capacity
of
the
process
unit.
Basing
RMRR
on
capacity
has
appeal
for
several
reasons.
For
starters,
an
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
that
between
cost
and
environmental
impact.
Finally,
this
type
of
approach
might,
in
principle,
be
easier
to
use
before
beginning
actual
construction
than
some
of
the
cost­
based
approaches.

Several
commenters
were
concerned
with
defining
the
capacity
of
a
process
unit.
Capacity
may
be
defined
based
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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.
Commenters
felt
that
a
capacity­
based
approach
would
not
be
workable
at
complex
manufacturing
sources,
because
"
capacity"
as
a
useful
shorthand
term
for
the
processing
capability
correlates
exactly
only
with
a
historical
feed
or
product
slate
no
longer
available
or
made.
A
number
of
commenters
supported
a
capacity­
based
option,
generally
indicating
that
a
capacity­
based
option
would
be
simpler
and
less
burdensome
to
use
than
the
other
proposed
approaches.

Another
large
concern
of
commenters
was
that
a
capacity­
based
approach
could
prevent
facilities
from
performing
activities
that
make
the
facilities
more
efficient.
RMRR
provisions
need
to
include
some
form
of
the
other
approaches
to
account
for
energy
efficiency
projects
at
utilities,
which
could
increase
output
capacity
(
i.
e.,

production)
without
necessarily
increasing
heat
input
or
fuel
consumption.
Some
commenters
noted
that
maximum
hourly
emissions
is
a
more
appropriate
surrogate
for
a
change
in
capacity,
because
it
is
consistent
with
existing
NSPS
procedures
and
with
averaging
periods
for
ambient
air
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quality
monitoring
and
standards.

We
agree
that
an
appropriate
capacity­
based
approach
would
have
to
be
tailored
to
various
types
of
sources,
with
capacity
based
on
input
for
some
and
on
output
for
others.

As
an
example,
in
a
review
of
promulgated
and
proposed
Maximum
Achievable
Control
Technology
standards,
six
of
eleven
standards
measured
capacity
based
on
process
unit
output
while
five
standards
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
facility.
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."

We
also
agree
that
a
capacity­
based
approach
has
its
limitations,
as
described
by
the
commenters.
We
have
concluded
that
the
ERP
eliminates
the
need
to
implement
the
capacity
based
approach.
We
have
decided
not
to
finalize
a
capacity­
based
approach.

3.
Age­
Based
Option
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Under
our
proposed
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.
We
also
proposed
that
the
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.

Very
few
commenters
expressed
any
interest
in
developing
this
type
of
approach.
Their
concerns
centered
around
defining
capacity
and
establishing
the
age
cut­
off
(
because
the
useful
life
of
equipment
is
difficult
to
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establish
and
may
vary
greatly).
Other
concerns
raised
by
commenters
were
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,
and
also
that
some
sources
may
consciously,
and
appropriately,
engage
in
aggressive
RMRR
as
a
method
of
maximizing
the
life
span
of
its
process
units,
and
an
agebased
approach
would
discriminate
against
them.

One
commenter
stated
that
EPA
should
establish
a
normal
lifetime,
tailored
to
each
industry,
beyond
which
industry
would
need
to
install
BACT
or
shut
down.
This
type
of
approach
would
obviously
require
a
substantial
amount
of
time
and
analytical
effort.

The
age
of
a
source
alone
is
not
a
legitimate
reason
to
require
the
addition
of
pollution
control
equipment.
Age
has
no
direct
bearing
on
a
unit's
environmental
impact;
some
facilities
maintain
equipment
better
than
others.
We
have
decided
not
to
promulgate
an
age­
based
approach.
We
have
several
basic
concerns
with
this
approach
that
we
have
not
been
able
to
reconcile.
We
also
believe
that
the
equipment
replacement
approach
largely
addresses
the
commenters'

concerns
regarding
the
age­
based
approach.

Thus,
we
have
decided
not
to
finalize
a
rule
using
this
approach.
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L.
Specific
List
of
Excluded
Activities
Several
commenters
supported
the
development
of
lists
of
activities
that
are
considered
RMRR;
some
of
these
commenters
also
supported
developing
lists
of
activities
that
do
not
qualify
as
RMRR.
Commenters
suggested
various
ways
in
which
such
lists
could
fit
into
the
overall
RMRR
program.
We
are
concerned,
however,
that
such
a
list
would
have
to
be
implemented
through
rulemaking,
which
would
require
a
considerable
amount
of
time,
analytical
effort,

and
resources.

A
commenter
suggested
two
ways
by
which
we
could
develop
a
list
of
qualifying
activities.
First,
we
could
review
records
for
ongoing
enforcement
activity,
to
identify
activities
that
we
have
and
have
not
already
alleged
to
be
RMRR.
There
is
an
ample
body
of
knowledge
for
electric
power
plants.
Second,
we
could
identify
where
activities
would
fall
with
respect
to
the
cost
criteria,
then
adjust
the
classification
of
each
activity
based
on
the
WEPCO
criteria
to
prepare
lists
of
routine
and
nonroutine
activities.

Some
commenters
felt
that
industry­
specific
lists
of
routine
and
nonroutine
activities
would
provide
the
best
interim
clarification
to
major
NSR
until
legislative
reform
is
in
place.
Other
commenters
opposed
the
development
of
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lists
of
activities
that
are
considered
RMRR,
contending
that
such
lists
would
become
quickly
outdated.

Some
commenters
requested
that
certain
activities
be
specifically
classified
as
RMRR.
These
activities
included
the
following:

S
The
common
practice
of
changing
out
the
engine
core
in
a
combustion
turbine
when
it
is
due
for
overhaul
(
to
reduce
downtime).
The
removed
engine
core
is
overhauled
offline,
and
is
then
available
to
be
switched
in
for
the
next
like­
kind
engine
core
that
reaches
the
point
of
overhaul.
Unless
the
parts
are
upgraded,
the
heat
input
remains
the
same
and
so
does
the
emissions
rate.

S
Any
change
that
does
not
increase
the
achievable
hourly
emissions
(
as
determined
based
on
the
permit
and/
or
original
design
parameters)
of
existing
equipment,

processes,
and
emissions
units.

Another
commenter
suggested
the
following
list:

S
Certain
activities,
for
example,
boiler
tuning
and
maintenance,
repair
and
replacement
of
air
pollution
equipment
or
CEMS
should
be
categorically
exempted
as
RMRR.

S
Any
project
that
is
part
of
a
long­
term
service
agreement
(
primarily
gas
turbines)
should
be
categorically
exempted
from
major
NSR.
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S
Any
project
involving
steam
turbine
overhaul
work
should
be
categorically
exempted
from
major
NSR.

We
believe
there
are
simply
too
many
activities
in
too
many
industries
to
effectively
improve
major
NSR
implementation
through
creation
of
lists.
Moreover,
lists
would
be
a
"
snapshot
in
time"
that
would
need
to
be
reviewed
and
periodically
updated
for
each
industry
sector.
We
have
consequently
decided
not
to
list
equipment
replacements
activities
that
are
categorically
excluded
as
RMRR.

M.
Stand­
alone
Exclusion
for
Energy
Efficiency
Projects
In
the
proposal,
we
acknowledged
that
certain
types
of
projects
that
improve
energy
efficiency
would
not
qualify
as
RMRR.
We
solicited
comment
on
whether
there
was
the
need
for
a
"
stand­
alone"
exclusion
for
activities
that
promote
energy
efficiency.

Many
commenters
supported
a
stand­
alone
exclusion
from
major
NSR
for
energy
efficiency
projects.
With
the
following
safeguards,
they
favored
specifically
excluding
from
the
definition
of
"
major
modification"

activities/
projects
that
promote
energy
efficiency
and/
or
resource
conservation
when:
(
1)
The
project
results
in
lower
emissions
per
unit
of
production
or
lower
energy
utilization
per
unit
of
production;
(
2)
the
percent
decrease
in
emissions
or
energy
utilization
per
unit
of
production
is
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greater
than
the
percent
increase
in
maximum
hourly
emission
rates;
(
3)
project
costs
do
not
exceed
50
percent
of
the
replacement
value
of
the
process
unit;
and
(
4)
the
project
does
not
result
in
an
increase
in
allowable
emissions.

Other
commenters
pointed
out
that
efficiency
upgrades
will
frequently
create
incentives
to
further
utilize
a
source
and
subsequently
increase
mass
emissions.
One
commenter
stated
that
if
activities
that
result
in
small
efficiency
gains
can
qualify
as
RMRR,
older,
dirtier
electric
generating
units
will
be
better
able
to
out­
compete
newer,
much
cleaner
plants
(
that
have
higher
costs
due
to
emission
controls).

One
commenter
stated
that
EPA
is
incorrect
in
stating
that
energy
efficiency
projects
are
being
discouraged
by
major
NSR,
particularly
under
the
new
actual­
to­

projectedactual
applicability
test.
This
commenter
added
that
the
only
projects
that
are
discouraged
by
major
NSR
are
ones
that
increase
emissions.
This
commenter
felt
that
the
December
2002
final
major
NSR
rules
provide
a
broad
range
of
major
NSR
exemptions
(
including
revised
baseline
determinations,
Clean
Unit
designations,
pollution
control
projects,
PALS,
and
combinations
of
these
provisions,
as
well
as
an
RMRR
exemption)
under
which
energy
efficiency
projects
will
certainly
occur.

We
strongly
support
efforts
to
improve
energy
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efficiency
at
existing
power
plants.
These
activities
reduce
the
amount
of
air
pollution
emitted
per
unit
of
electricity
generated
and
also
reduce
greenhouse
gas
emissions.
We
believe
that
today's
ERP
supports
energy
efficiency
projects
and
that
the
actual­
to­
projected­
actual
applicability
test
contained
in
the
December
2002
NSR
final
rules
also
should
remove
impediments
to
energy
efficiency
projects.
Together,
these
rules
will
obviate
the
need
for
a
specified
RMRR
provision
for
energy
efficiency
projects.

Thus,
at
this
time
we
are
not
finalizing
a
provision
to
categorically
exclude
energy
efficiency
projects
from
major
NSR.

N.
Legal
Basis
The
modification
provisions
of
the
NSR
program
in
parts
C
and
D
of
title
I
of
the
CAA
are
based
on
the
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
of
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted."
As
we
observed
in
the
notice
of
proposed
rulemaking
for
this
rule,
that
definition
contemplates
that
you
will
first
determine
whether
a
physical
or
operational
change
will
occur.
If
so,
then
you
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proceed
to
determine
whether
the
physical
or
operational
change
will
result
in
an
emissions
increase
over
baseline
levels.

Real­
world,
common­
sense
usage
of
the
word
"
change"
in
"
physical
change"
and
"
change
in
the
method
of
operation"

shows
that
"
change"
is
susceptible
to
multiple
meanings.

As
we
have
noted
previously,
"
EPA
has
always
recognized
that
Congress
did
not
intend
that
every
activity
at
an
existing
facility
be
considered
a
physical
or
operational
change
for
purposes
of
NSR."
57
FR
32,314,
32,319
(
July
21,
1992).

Conceivably,
"
change"
could
encompass
a
range
of
activities
from
periodically
replacing
filters
in
production
machinery,

to
once
in­
a­
lifetime
anticipated
replacement
of
a
component,
to
complete
replacement
of
a
production
unit.

For
example,
all
cars
must
periodically
have
their
oil
"
changed."
When
considered
from
one
perspective,
this
activity
does
represent
a
"
change"
because
old
oil
is
removed
and
new
oil
is
added.
From
another
perspective,

however,
this
activity
would
not
be
considered
a
change
because
it
does
not
alter
any
significant
characteristic
of
the
car.

More
to
the
point,
chemical
and
pharmaceutical
manufacturing
operations
often
are
designed,
operated,
and
permitted
as
"
multi­
function"
facilities.
These
facilities
have
numerous
pieces
of
equipment
(
such
as
storage
tanks,
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reactors,
distillation
columns,
centrifuges,
filter
dryers,

etc.)
that
can
be
reconfigured
to
accommodate
a
wide
variety
of
products
and
operating
conditions.
When
switching
from
product
X
to
product
Y,
a
plant
can
make
substantial
"
changes"
in
the
types
of
equipment
used,
the
processing
conditions,
and
the
raw
materials,
reagents,
solvents,
and
other
processing
materials.
In
this
case,
the
same
basic
equipment
is
used
to
make
a
wide
variety
of
end
products.

But,
as
long
as
the
facility
is
operated
as
designed
and
permitted,
we
would
not
consider
(
and
have
not
considered
over
the
20+
year
life
of
the
NSR
program)
such
changes
to
be
physical
or
operational
"
changes"
for
purposes
of
administering
the
NSR
program.

Similarly,
manufacturing
equipment
often
is
built
with
expendable
parts.
For
example,
industrial
gas
turbines,

such
as
those
used
to
drive
compressors
on
natural
gas
pipelines,
regularly
need
to
have
parts
replaced
as
they
wear
out
due
to
the
high
temperature
and
pressure
conditions
inside
the
turbine.
In
fact,
these
gas
turbines
are
built
with
the
knowledge
and
expectation
that
such
replacements
will
be
needed.
In
recognition
of
this
fact,
under
the
New
Source
Performance
Standard
for
gas
turbines,
40
C.
F.
R.
Part
60
Subpart
GG,
we
have
concluded
that
"
replacement
of
stator
blades,
turbine
nozzles,
turbine
buckets,
fuel
nozzles,
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August
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2003
97
combustion
chambers,
seals,
and
shaft
packings"
are
not
"
changes"
for
regulatory
purposes.
Cite
to
EPA­
450/
2­
77­

017a,
background
support
document
for
GG.
Such
replacements
are
akin
to
getting
a
new
set
of
brakes
on
a
car
 
not
something
that
happens
often,
not
an
activity
that
is
necessarily
inexpensive,
but
plainly
an
activity
that
is
an
expected
part
of
maintaining
and
operating
the
facility
and
one
that
does
not
represent
an
alteration
of
the
affected
process
unit.

As
the
preceding
examples
suggest,
identifying
activities
that
are
"
changes"
for
NSR
purposes
 
and
thus
potentially
trigger
the
need
for
an
NSR
permit
 
requires
the
exercise
of
Agency
expertise.
The
application
of
agency
expertise
to
the
interpretation
of
this
statutory
term
is
the
classic
situation
in
which
an
agency
has
been
accorded
deference
under
Chevron,
U.
S.
A.,
Inc.
v.
NRDC,
467
U.
S.
837
(
1984).

Historically,
we
have
asserted
the
power
to
interpret
the
relevant
statutory
terms.
For
example,
even
though
both
the
NSPS
and
NSR
programs
incorporate
the
definition
of
"
modification"
from
section
111,
from
the
outset
EPA
has
adopted
quite
disparate
readings
of
the
term
in
our
rules.

See
57
Fed.
Reg.
32314,
32316
(
July
21,
1992)
(
WEPCO
rule
discussion
of
how
emission
increases
are
calculated
differently
for
the
NSPS
and
NSR
programs).
The
NSPS
program
Internal
and
Deliberative
Draft
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quote,
cite,
copy,
or
distribute
August
22,
2003
12
As
discussed
below,
our
regulations
provided
a
comparable
exclusion
from
NSPS
at
the
time
of
the
1977
Amendments
that
established
the
NSR
program.

98
requires
a
change
to
result
in
an
increase
in
the
hourly
potential
to
emit
of
the
facility.
40
C.
F.
R.
60.14(
a)
­

(
b).
In
contrast,
under
NSR,
we
require
an
increase
in
annual
emissions.
E.
g.,
40
C.
F.
R.
51.165(
a)(
1)(
x).
These
disparate
tests
reflect
the
Agency's
view
that
the
statutory
term
"
modification"
must
be
construed
with
a
view
to
what
makes
sense
in
particular
statutory
context,
and
are
not
obvious
on
their
face.

The
exclusions
from
NSR
we
adopted
in
1980
also
reflect
the
exercise
of
the
Chevron
discretion.
Not
only
did
we
adopt
the
RMRR
exclusion
at
that
time,
but
we
also
adopted
exclusions
for
increases
in
the
hours
of
operation,
fuel
changes,
and
raw
material
changes.
Only
the
RMRR
exclusion
arguably
could
be
justified
as
de
minimis.
For
example,
by
doubling
hours
of
operation,
a
500
ton­
per­
year
emitting
plant
could
conceivably
double
its
emissions.
12
The
extra
500
tpy
is
far
above
any
level
EPA
has
ever
thought
justifiable
as
de
minimis.
E.
g.,
40
C.
F.
R.
51.166(
b)(
23)(
i)

(
definition
of
"
significant").
Nor
is
it
likely
that
these
other
exclusions
could
be
based
on
some
inherent
power
to
adopt
categorical
exemptions
from
the
Act's
commands.
See
Alabama
Power
Company
v.
Costle,
636
F.
2d
323,
359
(
D.
C.
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and
Deliberative
Draft
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August
22,
2003
99
Cir.
1980)
("
categorical
exemptions
.
.
.
are
not
favored").

Accordingly,
these
other
exclusions
must
be
justified
as
an
exercise
of
Chevron
discretion.

It
is
important
to
note
that,
in
1977
when
Congress
incorporated
by
reference
into
the
NSR
program
the
preexisting
NSPS
statutory
definition
of
modification,
EPA
had
already
adopted
and
had
been
administering
regulations
and
policy
under
the
NSPS
program
related
to
the
meaning
of
the
term
"
modification."
Our
rules
and
policy
provided
that
certain
significant
activities
did
not
constitute
physical
or
operational
changes
under
the
NSPS
program
prior
to
1977
(
or,
for
that
matter,
under
the
NSPS
program
as
administered
today).
In
addition
to
the
gas
turbine
example
provided
above,
perhaps
the
best
indication
that
EPA
did
not
consider
the
terms
"
modification"
or
"
change"
to
cover
everything
other
than
de
minimis
activities
is
the
exclusion
for
production
rate
increases
under
the
NSPS
program.
40
C.
F.
R.

Section
60.14(
e)(
2).

Under
this
provision,
projects
valued
at
millions
of
dollars
can
be
implemented
 
with
no
limitations
on
the
nature
of
the
project
 
without
triggering
applicable
NSPSs.

For
example,
up
to
10
percent
of
the
asset
value
of
affected
operations
at
a
kraft
pulp
mill
can
be
invested
in
a
project
without
triggering
the
applicable
NSPS,
40
C.
F.
R.
Part
60
Subpart
BB.
The
affected
facilities
at
a
kraft
pulp
mill
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2003
100
typically
are
valued
in
excess
of
$
100
million.
Cite.

Therefore,
an
owner
or
operator
can
implement
projects
costing
millions
of
dollars
without
triggering
the
applicable
NSPS.
This
holds
true
regardless
of
the
nature
of
the
project
 
it
can
be
a
"
like­
kind"
replacement
of
the
kind
addressed
by
today's
rule
or
it
can
result
in
a
substantial
change
in
the
nature
of
the
operation.
Thus,

under
the
NSPS
program
that
existed
when
Congress
enacted
NSR
and
incorporated
into
NSR
the
applicable
NSPS
definitions,
projects
of
substantial
cost
that
result
in
substantial
change
in
affected
facilities
were
not
considered
"
changes."
The
same
is
true
under
the
NSPS
program
as
it
stands
today.

We
recognize
that
the
Agency
previously
has
not
specifically
asserted
that
our
interpretation
of
"
change"

and
the
exclusions
from
NSR
are
based
on
an
exercise
of
Chevron
discretion.
In
some
instances,
such
as
in
a
decision
of
the
EAB,
In
re:
Tennessee
Valley
Authority,
9
E.
A.
D.
357
(
EAB
2000),
and
in
briefs
in
various
enforcementrelated
cases,
we
have
previously
interpreted
"
change"
such
that
virtually
all
changes,
even
trivial
ones,
are
encompassed
by
the
Act.
Thus,
we
generally
interpreted
the
exclusion
as
being
limited
to
de
minimis
circumstances.

However,
EPA
does
have
the
authority
to
interpret
these
key
Internal
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2003
13
We
have
taken
positions
in
numerous
court
filings
concerning
the
proper
interpretation
and
usage
of
key
statutory
terms,
such
as
"
physical
change"
and
"
any
physical
change."
These
positions
were
based
on
reasonable
statutory
interpretations
of
which
the
regulated
community
had
fair
notice,
and
continue
to
be
the
law
governing
prior
activities
at
covered
facilities.
We
now,
however,
are
using
our
Chevron
authority
to
define
key
terms
for
future
activities
at
covered
facilities
because
the
terms
have
multiple
meanings
and
we
now
believe
the
new
definitions
are
most
appropriate
for
the
Clean
Air
Act
regulatory
regime
going
forward.

14
We
note
that
the
word
"
any"
is
simply
a
modifier
that
does
not
change
the
meaning
of
the
word
it
modifies.
For
example,
using
the
term
"
any"
to
modify
the
word
"
car"
does
not
somehow
change
or
expand
the
meaning
of
the
word
"
car."
"
Any"
simply
means
that,
once
you
have
decided
what
a
car
is,
then
all
objects
meeting
the
definition
are
encompassed.

101
terms
through
rulemaking.
Upon
further
consideration
of
the
history
of
our
actions,
the
statute,
and
its
legislative
history,
EPA
believes
that
a
different
view
is
permissible,

and,
for
policy
reasons
discussed
above,
more
appropriate.

Therefore,
we
adopt
this
view
prospectively
in
today's
action.
13
The
argument
that
our
authority
to
exclude
certain
activities
from
being
modifications
under
new
source
review
can
only
be
based
on
a
de
minimis
rationale
sometimes
relies
on
the
word
"
any"
used
to
modify
"
physical
change"
and
"
change
in
the
method
of
operation,"
pointing
to
the
word
"
any"
in
the
definition
of
"
modification"
as
a
signal
from
Congress
that
the
term
"
change"
must
be
interpreted
as
encompassing
the
broadest
possible
sense
of
the
term.
Such
an
interpretation
is
not
compelled
by
the
language
and
legislative
history
of
the
statute,
as
demonstrated
by
the
manner
in
which
we
have
interpreted
the
word
"
change"
under
both
the
NSPS
and
the
NSR
programs.
14
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2003
102
Nothing
in
the
appellate
caselaw
directly
disposes
of
this
issue
in
a
manner
that
prevents
a
new
interpretation
today.
Two
cases,
Alabama
Power
and
Wisconsin
Electric
Power
Co.
v.
Reilly,
893
F.
2d
901
(
7th
Cir.
1990)
("
WEPCO"),
are
relied
on
by
some
commenters
to
assert
that
EPA
must
interpret
"
modification"
and
"
change"
expansively
and
base
all
exclusions
on
a
de
minimis
rationale.
However,
in
Alabama
Power,
the
issue
before
the
court
was
the
emissions
increase
portion
of
the
definition
of
"
modification."
The
court
would
have
allowed
de
minimis
increases
in
emissions
to
be
exempt
from
requirements
applying
to
"
modifications"

under
new
source
review
but
not
emissions
increases
equal
to
the
thresholds
set
by
statute
for
new
construction.
636
F.
2d
at
399
­
400.
The
court
did
not
have
before
it
the
issue
of
what
is
a
"
change"
and
did
not
decide
this
issue.

In
WEPCO,
both
parties
advanced
the
view
that
the
statute
was
clear
on
its
face.
EPA
advanced
the
view
that
the
term
"
modification"
is
necessarily
broad,
and
that
only
de
minimis
departures
are
appropriate.
WEPCO
asserted
that
the
plain
meaning
of
the
term
"
physical
change"
allowed
for
the
five
large
scale
rehabilitation
projects
it
contemplated
at
its
Port
Washington
plant.
The
WEPCO
court
held
that
the
rehabilitation
projects
at
issue
were
too
large
to
reasonably
conclude
that
they
should
not
be
treated
as
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2003
15As
pointed
out
above,
we
note
that
the
U.
S.
District
Court
for
the
Southern
District
of
Ohio
recently
issued
an
opinion
in
the
Agency's
NSR
enforcement
case
against
Ohio
Edison.
(
cite)
The
case
included
a
series
of
projects
with
absolute
and
relative
costs
well
below
those
at
issue
in
WEPCO.
The
court
determined,
again
at
our
urging,
that
these
projects
did
not
qualify
for
the
existing
RMRR
exclusion.
The
Agency
asserted
in
that
case
that
the
then
existing
RMRR
exclusion
should
be
applied
in
a
narrow
fashion
such
that
only
de
minimis
projects
should
be
excluded
under
that
rule.
The
Agency
sought
and
received
from
the
court
broad
deference
with
regard
to
the
Agency's
interpretation
of
the
CAA
and
the
relevant
EPA
rules.
EPA
today
is
adopting
for
future
purposes
a
new
interpretation
of
the
CAA
and
is
finalizing
a
revision
to
the
RMRR
regulation.
The
decision
in
Ohio
Edison
does
not
preclude
the
interpretation
and
regulation
finalized
in
today's
action.

103
physical
changes.
The
court's
holding
that
the
statute
did
not
require
the
interpretation
advanced
by
WEPCO
does
not
deny
EPA
the
discretion
to
decide
to
adopt
a
different,

reasonable
interpretation
of
the
term
"
modification."

While
the
Court
in
WEPCO
decided
that
the
projects
in
that
case
were
physical
changes,
the
decision
in
WEPCO
does
not
answer
the
question
of
where
to
draw
the
line
between
activities
that
should
and
should
not
be
considered
"
changes."
Nevertheless,
contrary
to
the
suggestions
of
several
commenters,
the
projects
at
issue
in
WEPCO
would
have
cost
more
than
the
20
percent
of
replacement
cost
threshold
selected
today
and,
barring
other
applicable
exclusions,
would
have
been
subject
to
case­
by­
case
review
in
the
PSD
program.
See
section
III.
D.
above.
15
Some
commenters
argued
that,
to
further
the
purposes
of
the
statute,
any
interpretation
must
result
in
the
eventual
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2003
104
elimination
of
so­
called
"
grandfathered"
facilities.
We
recognize
the
need
to
reduce
emissions
from
many
existing
plants
 
regardless
of
whether
they
are
"
grandfathered"

(
because
they
have
never
gone
through
NSR)
or
whether
they
have
previously
gone
through
NSR
but
can
further
reduce
their
emissions.
EPA
and
States
have
issued
regulations
under
a
variety
of
statutory
provisions
to
accomplish
this
goal
in
the
past,
and
we
will
continue
to
do
so
in
the
future.
We
do
not
believe,
however,
the
modification
provisions
of
the
Act
should
be
interpreted
to
ensure
that
all
major
facilities
eventually
trigger
NSR.
In
fact,
such
an
interpretation
cannot
be
squared
with
the
plain
language
of
the
Act.

An
existing
source
 
whether
grandfathered
or
not
 
triggers
NSR
only
if
it
makes
a
physical
or
operational
change
that
results
in
an
emissions
increase.
Thus,
a
facility
can
conceivably
continue
to
operate
indefinitely
without
triggering
NSR
 
making
as
many
physical
or
operational
changes
as
it
desires
 
as
long
as
the
changes
do
not
result
in
emissions
increases.
This
outcome
is
an
unavoidable
consequence
of
the
plain
statutory
language
and
is
at
odds
with
the
notion
that
Congress
intended
that
every
major
source
would
eventually
trigger
NSR.
Moreover,
there
is
nothing
in
the
legislative
history
of
the
1977
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22,
2003
105
Amendments,
which
created
the
NSR
program,
to
suggest
that
Congress
intended
to
force
all
then­
existing
sources
to
go
through
NSR.
To
the
extent
that
some
members
of
Congress
expressed
that
view
during
the
debate
over
the
1990
amendments,
such
statements
are
not
probative
of
what
Congress
meant
in
1977.
Central
Bank
of
Denver,
N.
A.
v.

First
Interstate
Bank
of
Denver,
N.
A.,
511
U.
S.
164,
185
­

86
(
1994),
and
cases
cited.

In
deciding
to
incorporate
by
reference
the
statutory
definition
of
"
modification"
in
section
111,
Congress's
intent
cannot
have
been
to
preclude
us
from
adopting
an
interpretation
of
"
modification"
or
"
change"
that
differs
from
one
that
sweeps
in
all
activities
at
a
source.
Under
the
NSPS
program,
this
interpretation
did
not
apply
at
the
time
of
the
1977
amendments.
When
the
NSPS
definition
of
"
modification"
was
adopted
as
part
of
the
NSR
program
in
1977,
the
Congressional
Record
explained
that
this
provision,
"[
i]
mplements
conference
agreement
to
cover
"
modification"
as
well
as
"
construction"
by
defining
"
construction"
in
part
C
to
conform
to
usage
in
other
parts
of
the
Act."
123
Cong.
Rec.
36331
(
Nov.
1,
1977)(
emphasis
added).
Although
we
do
not
assert
that
the
NSPS
interpretation
is
the
only
one
we
could
have
adopted
for
NSR
purposes
(
we
followed
quite
a
different
interpretation
from
1980­
2002),
at
the
very
least
it
delineates
a
zone
of
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and
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106
discretion
within
which
EPA
may
operate.

Our
interpretation
today
of
physical
or
operational
change
in
a
flexible
way
furthers
the
purposes
of
the
statute.
Congress
made
it
clear
that
the
CAA
in
general,

and
the
NSR
program
in
particular,
should
be
administered
in
a
manner
that
protects
the
environment
and
promotes
the
productive
capacity
of
the
nation.
CAA
Section
101(
b)(
1).

The
Chevron
Court
noted,
"
Congress
sought
to
accommodate
the
conflict
between
the
economic
interest
in
permitting
capital
improvements
to
continue
and
the
environmental
interest
in
improving
air
quality"
when
it
established
the
NSR
program.

Chevron,
467
U.
S.
at
851.
Generally,
we
believe
that
these
goals
are
best
accomplished
by
providing
state
and
local
governments
with
discretion
to
make
decisions
as
to
what
emissions
reductions
are
needed
in
their
jurisdictions
to
attain
and
maintain
good
air
quality.
See
CAA
Section
101(
a)(
3).

It
is
now
clear
that
many
power
plants
and
industrial
facilities
must
substantially
reduce
their
emissions
in
order
to
allow
States
to
meet
the
stringent
federal
air
quality
standards
that
the
Supreme
Court
upheld
in
2002.

Under
the
Clean
Air
Act,
Congress
designed
a
number
of
regulatory
programs
that
will
collectively
achieve
the
necessary
reductions.
Although
the
NSR
program
will
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107
effectively
limit
emissions
from
new
and
modified
sources,

it
was
not
designed
to
achieve
emission
reductions
from
every
existing
source.

IV.
Administrative
Requirements
for
This
Rule
A.
Executive
Order
12866
­
Regulatory
Planning
and
Review
Under
Executive
Order
12866
[
58
Federal
Register
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.
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and
Deliberative
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or
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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,
we
consulted
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
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109
the
various
levels
of
government."

This
final
rule
does
not
have
federalism
implications.

Nevertheless,
as
described
in
section
II.
C.
of
this
notice,

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.
This
rule
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.
We
expect
this
rule
will
result
in
some
expenditures
by
the
States,
we
expect
those
expenditures
to
be
limited
to
$
580,000
for
the
estimated
112
affected
reviewing
authorities.
This
estimate
reflects
the
small
increase
in
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
revise
their
State
Implementation
Plans
(
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
Internal
and
Deliberative
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2003
110
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."
We
believe
that
this
rule
does
not
have
tribal
implications
as
specified
in
Executive
Order
13175.
Thus,
Executive
Order
13175
does
not
apply.

The
purpose
of
today's
final
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
major
NSR
program
apply.
Taken
as
a
whole,
today's
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
and
guidance.

We
anticipate
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
permitted
by
the
States,
which
will
in
turn
reduce
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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
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
outreach
as
part
of
the
rulemaking
process.
In
addition
to
affording
tribes
an
opportunity
to
comment
on
this
rule
through
the
proposal,
on
which
two
tribes
did
submit
comments,
we
have
also
alerted
tribes
of
this
action
through
our
website
and
quarterly
newsletter.
To
this
point
we
have
not
specifically
consulted
with
tribal
officials
on
this
rule,
but
we
are
committed
to
work
with
any
tribal
government
to
resolve
any
issues
that
we
may
have
overlooked
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in
today's
rules
and
that
may
have
an
adverse
impact
in
Indian
country.

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
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,
based
on
our
analysis
of
electric
utilities,
this
rule
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.
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E.
Paperwork
Reduction
Act
Since
no
recordkeeping
or
reporting
is
required
by
the
ERP,
this
action
does
not
impose
an
information
collection
burden
under
the
provisions
of
the
Paperwork
Reduction
Act,

44
U.
S.
C.
3501
et
seq.

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
purposes
of
collecting,

validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
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
in
40
CFR
are
listed
in
40
CFR
part
9.

F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Internal
and
Deliberative
Draft
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or
distribute
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2003
114
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.

We
determined
it
is
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
this
final
rule.
We
have
also
determined
that
this
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
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
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
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significant
economic
impact
of
this
rule
on
small
entities."

5
U.
S.
C.
Sections
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
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
rule
will
relieve
regulatory
burden
for
all
small
entities.

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,
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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
cost­
effective
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.
Internal
and
Deliberative
Draft
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not
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cite,
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or
distribute
August
22,
2003
117
We
believe
these
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
rule
are
not
expected
to
result
in
a
significant
increase
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
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
Internal
and
Deliberative
Draft
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not
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cite,
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or
distribute
August
22,
2003
118
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
rule
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
rule.

I.
Executive
Order
13211
­
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
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
rule
improves
the
ability
of
sources
to
maintain
the
reliability
of
production
facilities,
and
effectively
utilize
and
improve
existing
capacity.
Internal
and
Deliberative
Draft
­
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not
quote,
cite,
copy,
or
distribute
August
22,
2003
119
J.
Executive
Order
12988
­
Civil
Justice
Reform
This
final
rule
does
not
have
any
preemptive
or
retroactive
effect.
This
action
meets
applicable
standards
in
sections
3(
a)
and
3(
b)(
2)
of
Executive
Order
12988,
Civil
Justice
Reform,
to
minimize
litigation,
eliminate
ambiguity,

and
reduce
burden.

V.
Effective
Date
for
Today's
Requirements
All
of
these
changes
will
take
effect
in
the
Federal
PSD
program
(
codified
at
§
52.21)
on
[
INSERT
DATE
60
DAYS
AFTER
DATE
OF
PUBLICATION
OF
FINAL
RULES
IN
THE
FEDERAL
REGISTER].
This
means
that
these
rules
will
apply
on
[
INSERT
DATE
60
DAYS
AFTER
DATE
OF
PUBLICATION
OF
FINAL
RULES
IN
THE
FEDERAL
REGISTER]
in
any
area
without
an
approved
PSD
program,
for
which
we
are
the
reviewing
authority,
or
for
which
we
have
delegated
our
authority
to
issue
permits
to
a
State
or
local
reviewing
authority.

To
be
approvable
under
the
SIP,
State
and
local
agency
programs
implementing
part
C
(
PSD
permit
program
in
§
51.166)

or
part
D
(
nonattainment
NSR
permit
program
in
§
51.165)
must
include
today's
changes
as
minimum
program
elements.
State
and
local
agencies
should
assure
that
any
program
changes
under
§
§
51.165
and
51.166
are
consistently
accounted
for
in
other
SIP
planning
measures.
State
and
local
agencies
must
adopt
and
submit
revisions
to
their
part
51
permitting
programs
implementing
these
minimum
program
elements
no
Internal
and
Deliberative
Draft
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or
distribute
August
22,
2003
120
later
than
[
INSERT
DATE
3
YEARS
AFTER
PUBLICATION
OF
FINAL
REGULATION
IN
FEDERAL
REGISTER].
That
is,
for
both
nonattainment
and
attainment
areas,
the
SIP
revisions
must
be
adopted
and
submitted
within
3
years
from
today.
The
Act
does
not
specify
a
date
for
submission
of
SIPs
when
we
revise
the
PSD
and
NSR
rules.
We
believe
it
is
appropriate
to
establish
a
date
analogous
to
the
date
for
submission
of
new
SIPs
when
a
NAAQS
is
promulgated
or
revised.
Under
section
110(
a)(
1)
of
the
Act,
as
amended
in
1990,
that
date
is
3
years
from
promulgation
or
revision
of
the
NAAQS.

Accordingly,
we
have
established
3
years
from
today's
revisions
as
the
required
date
for
submission
of
conforming
SIP
revisions.
We
have
made
conforming
changes
to
the
PSD
regulations
at
§
51.166(
a)(
6)(
i)
to
indicate
that
State
and
local
agencies
must
adopt
and
submit
plan
revisions
within
3
years
after
new
amendments
are
published
in
the
Federal
Register.

Today's
rule
revises
the
Federal
PSD
program
located
at
40
CFR
52.21
to
include
the
new
equipment
replacement
provision
of
the
RMRR
exclusion.
The
part
52
regulations
governing
Federal
permitting
programs
include
the
Federal
PSD
rule
at
40
CFR
52.21
as
well
as
the
various
sections
of
subparts
C
through
DDD
of
part
52
that
incorporate
the
Federal
permitting
program
by
reference
for
those
Internal
and
Deliberative
Draft
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22,
2003
121
jurisdictions
where
EPA
applies
part
52.21
as
a
Federal
Implementation
Plan
because
such
jurisdictions
lack
an
approved
SIP
to
implement
the
PSD
program.
Because
today's
final
rule
adds
additional
paragraphs
to
the
part
52.21
rules,
we
will
be
revising
the
references
in
subparts
C
through
DDD
to
appropriately
reflect
the
program
that
applies.
This
final
action
will
be
taken
in
a
separate
Federal
Register
notice
and
will
not
change
the
effective
date
of
today's
final
changes.

VI.
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)).
Internal
and
Deliberative
Draft
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not
quote,
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or
distribute
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22,
2003
122
RMRR
 
Page
??
of
??(?)

LIST
OF
SUBJECTS
40
CFR
Parts
51
and
52
Environmental
protection,
Administrative
practices
and
procedures,
Air
pollution
control,
Intergovernmental
relations.

____________________

Dated:

_____________________

Marianne
Lamont
Horinko,

Acting
Administrator.
