United
States
Office
of
Air
Quality
Environmental
Protection
Planning
and
Standards
August
2003
Agency
Research
Triangle
Park,
NC
27711
http://
www.
epa.
gov/
ttn/
nsr/
rule_
dev.
html
Technical
Support
Document
for
the
Prevention
of
Significant
Deterioration
and
Nonattainment
Area
New
Source
Review:
Routine
Maintenance,
Repair
and
Replacement
Regulations
Technical
Support
Document
for
the
Prevention
of
Significant
Deterioration
and
Nonattainment
Area
New
Source
Review:
Routine
Maintenance,
Repair
and
Replacement
Regulations
Integrated
Implementation
Group
Information
Transfer
and
Program
Integration
Division
Office
of
Air
Quality
Planning
and
Standards
U.
S.
Environmental
Protection
Agency
Research
Triangle
Park,
NC
27711
August
2003
i
This
document
has
been
reviewed
by
the
Information
Transfer
and
Program
Integration
Division
of
the
Office
of
Air
Quality
Planning
and
Standards,
EPA,
and
approved
for
publication.
Mention
of
trade
names
or
commercial
products
is
not
intended
to
constitute
endorsement
or
recommendation
for
use.
Copies
of
this
report
are
available
through
the
Library
Services
Office
(
MD­
35),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park
NC
27711,
(
919)
541­
2777,
or
from
National
Technical
Information
Service,
5285
Port
Royal
Road,
Springfield
VA
22161.
You
may
also
access
this
document
on
EPA's
website
at
http://
www.
epa.
gov/
ttn/
nsr/
rule_
dev.
html.
Table
of
Contents
ii
Acronym
List
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vi
Chapter
1
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General
Comments
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1­
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1.1
Overview
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1­
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1.2
Procedural
Comments
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1­
1
1.2.1
Extend
Comment
Deadline
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1­
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1.2.2
Requests
Public
Hearing
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1
1.2.3
Sufficiency
of
Rulemaking
Process
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1­
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1.2.4
Implementation
of
Provisions
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1­
1
1.3
General
Support
for
Proposal
Rule
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1­
2
1.4
General
Opposition
to
Proposal
Rule
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1­
3
1.5
Proposed
RMRR
Alternatives
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1­
3
1.6
Implementation
of
the
Proposed
RMRR
Approaches
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1­
3
Chapter
2
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Annual
Maintenance,
Repair
and
Replacement
Allowance
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1
2.1
Overview
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2­
1
Chapter
3
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Equipment
Replacement
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3­
1
3.1
Overview
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3­
1
3.2
General
Support
or
Opposition
for
EPA's
Proposal
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3­
1
3.2.1
General
Support
for
Proposal
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3­
1
3.2.2
Opposition
to
Proposal
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3­
4
3.2.3
Legal
Rationale
for
Proposal
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3­
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Response:
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3­
16
3.3
Basic
Approach
for
Equipment
Replacement
Option
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3­
22
3.3.1
Support
Proposed
Option
of
Applying
Percentage
on
a
Component
Basis
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3­
22
3.3.2
Support
for
Applying
Percentage
to
Components
Replaced
Collectively
Over
a
Fixed
Period
of
Time
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3­
24
3.3.3
Support
for
Other
Approach
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3­
24
Response:
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3­
25
3.4
Definition
of
Process
Unit
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3­
26
3.4.1
General
Definition
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3­
26
3.4.2
Definition
Applied
to
Specific
Industry
Categories
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3­
27
Table
of
Contents
iii
Response:
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3­
31
3.5
Fixed
Capital
Cost
Percentage
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3­
33
3.5.1
General
Support
for
Proposal
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3­
33
3.5.2
Opposition
to
Proposed
Replacement
Value
Threshold
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3­
34
Response:
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3­
35
3.5.3
Whether
to
Set
Different
Fixed
Capital
Cost
Percentages
for
Different
Industry
Sectors
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3­
38
3.5.4
Information
Provided
on
RMRR
Activities
and
Costs
in
Specific
Industry
Sectors
.
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3­
39
Response:
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3­
40
3.6
Basic
Design
Parameters
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3­
42
3.6.1
Generally
Supportive
Comments
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3­
42
3.6.2
Opposition
to
Basic
Design
Parameters
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3­
44
Response:
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3­
49
3.7
Definition
of
Functionally
Equivalent
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3­
51
3.7.1
How
to
Define
Functionally
Equivalent
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3­
51
3.7.2
Generally
Supportive
Comments
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3­
53
Response:
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3­
54
3.8
Cost
Basis
for
Equipment
Replacement
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3­
58
3.8.1
General
Support
for
Proposal
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3­
58
3.8.2
General
Support
for
Other
Methods
for
Cost
Basis
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3­
59
Response:
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3­
60
3.9
Calculating
Costs
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3­
60
3.9.1
Cost
Estimation
Method
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3­
60
3.9.2
Including
Costs
of
Control
Equipment
in
Equipment
Cost
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3­
62
Response:
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3­
65
3.10
Stationary
Source
or
Process
Unit
Basis
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.
3­
66
3.10.1
General
Support
for
Stationary
Source
Basis
.
.
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3­
66
3.10.2
General
Support
for
Process
Unit
Basis
.
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3­
66
Response:
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3­
67
3.11
Costs
Related
to
Unanticipated
Shutdowns
.
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3­
67
3.11.1
Support
for
Excluding
Costs
for
Unanticipated
Shutdowns
.
.
.
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.
3­
68
3.11.2
Support
Other
Approach
to
Shutdowns
.
.
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.
3­
69
Table
of
Contents
iv
Response:
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3­
71
3.12
How
to
Treat
Non­
emitting
Units
.
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.
3­
72
3.12.1
General
Support
for
Excluding
Non­
emitting
Units
From
ERP
.
.
.
.
.
3­
72
3.12.2
Oppose
Excluding
Non­
emitting
Units
From
ERP
.
.
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3­
73
Response:
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3­
73
Chapter
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
.
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4­
1
4.1
Overview
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4­
1
4.2
Capacity­
based
Option
.
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4­
1
4.2.1
Support
Capacity­
based
Option
.
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4­
1
4.2.2
Oppose
Capacity­
based
Option
.
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4­
4
Response:
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4­
5
4.3
Age­
based
Option
.
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4­
6
4.3.1
Support
Age­
based
Option
.
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4­
6
4.3.2
Oppose
Age­
based
Option
.
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4­
7
Response:
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4­
9
4.4
Retaining
Case­
by­
case
Approach
.
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4­
10
4.4.1
Support
Retaining
Case­
by­
case
Approach
.
.
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.
4­
10
4.4.2
Oppose
Retaining
Case­
by­
case
Approach
.
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4­
12
Response:
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4­
12
4.5
Comments
on
Other
Options
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4­
12
4.5.1
Exclude
Activities
Properly
Classified
as
an
"
Expense"
on
the
Source's
Federal
Income
Taxes
.
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4­
12
Response:
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4­
14
4.5.2
List
of
Excluded
Activities
.
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4­
15
Response:
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4­
17
4.5.3
Other
Suggested
Exclusions
.
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4­
17
Response:
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4­
17
Response:
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4­
18
Response:
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4­
21
Table
of
Contents
v
Chapter
5
­
Energy
Efficiency
Projects
.
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5­
1
5.1
Overview
.
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5­
1
5.2
Stand­
Alone
Exclusion
for
Energy
Efficiency
Projects
.
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.
5­
1
5.2.1
Support
for
a
Stand­
Alone
Exclusion
.
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5­
1
5.2.2
Opposition
to
a
Stand­
Alone
Exclusion
.
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5­
3
Response:
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.
5­
4
5.3
Effect
of
NSR
on
Energy
Efficiency
and
Other
Beneficial
Projects
.
.
.
.
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.
.
5­
4
Chapter
6
­
Analyses
of
Proposed
Regulatory
Action
.
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6­
1
6.1
Overview
.
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6­
1
6.2
IPM
and
Other
Analyses
.
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.
6­
1
6.2.1
Validity
of
IPM
Assumptions
.
.
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6­
1
Response:
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6­
3
6.2.2
Power
Sector
Conclusions
.
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6­
5
Response:
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6­
7
6.2.3
Applicability
of
IPM
to
Other
Industries
.
.
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6­
8
Response:
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6­
8
6.2.4
NEMS
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6­
9
Response:
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6­
9
6.2.5
June
2002
Report
to
the
President
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6­
10
Response:
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6­
10
6.2.6
Other
Analyses
Needed
.
.
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6­
10
Response:
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6­
12
6.2.7
Comments
on
August
2002
Information
Collection
Request
.
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6­
12
Response:
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6­
12
6.3
Executive
Order
12866
Analyses
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6­
12
Response:
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6­
13
Appendix
A:
Public
Commenters
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A­
1
vi
Acronym
List
AMA
Annual
Maintenance
Allowance
AQRV
Air
Quality
Related
Value
BACT
Best
Available
Control
Technology
BAT
Best
Available
Technology
BBS
Bulletin
Board
System
CAA
Clean
Air
Act
CAAA
1990
Amendments
to
the
Clean
Air
Act
CAM
Compliance
Assurance
Monitoring
CEMS
Continuous
Emissions
Monitoring
System
CERCLA
Comprehensive
Environmental
Response
Compensation
and
Liability
Act
CFC
Chlorofluorocarbon
CFR
Code
of
Federal
Regulations
CMA
Chemical
Manufacturers
Association
CMS
Continuous
Monitoring
System
CO
Carbon
Monoxide
COMS
Continuous
Opacity
Monitoring
System
DOE
Department
of
Energy
DOI
Department
of
Interior
EPA
United
States
Environmental
Protection
Agency
ERC
Emission
Reduction
Credit
ERP
Equipment
Replacement
Provision
FACA
Federal
Advisory
Committee
Act
FERC
Federal
Energy
Regulatory
Commission
FLM
Federal
Land
Manager
FR
Federal
Register
HAP
Hazardous
Air
Pollutant
HCFC
Hydrochlorofluorocarbons
ICR
Information
Collection
Request
IRS
Internal
Revenue
Service
LAER
Lowest
Achievable
Emissions
Rate
MACT
Maximum
Achievable
Control
Technology
MRRT
Monitoring,
Recordkeeping,
Reporting,
and
Testing
MSWLF
Municipal
Solid
Waste
Landfill
MWC
Municipal
Waste
Combustor
NAA
NSR
Nonattainment
Area
New
Source
Review
NAAQS
National
Ambient
Air
Quality
Standards
NEMS
National
Energy
Modeling
System
NEPA
National
Environmental
Policy
Act
NERC
Nuclear
Energy
Regulatory
Commission
NESHAP
National
Emission
Standards
for
Hazardous
Air
Pollutants
vii
NNSR
Nonattainment
New
Source
Review
NOA
Notice
of
Availability
NOx
Nitrogen
Oxides
NPDES
National
Pollutant
Discharge
Elimination
System
NPS
National
Park
Service
NSPS
New
Source
Performance
Standards
NSR
New
Source
Review
OAQPS
Office
of
Air
Quality
Planning
and
Standards
ODP
Ozone
Depleting
Potential
ODS
Ozone
Depleting
Substance
OMB
Office
of
Management
and
Budget
OSHA
Occupational
Safety
and
Health
Administration
OTR
Ozone
Transport
Region
P2
Pollution
Prevention
PAL
Plantwide
Applicability
Limitation
PC­
CMO
Physical
Change
or
Change
in
Method
of
Operation
PCP
Pollution
Control
Project
PM
Particulate
Matter
PM
10
Particulate
Matter
less
than
10
microns
in
diameter
POTW
Publicly
Owned
Treatment
Works
PSD
Prevention
of
Significant
Deterioration
PTE
Potential
to
Emit
RACT
Reasonably
Available
Control
Technology
RBLC
RACT/
BACT/
LAER
Clearinghouse
RCRA
Resource
Conservation
and
Recovery
Act
RECLAIM
Regional
Clean
Air
Incentives
Market
RFA
Regulatory
Flexibility
Analysis
RFP
Reasonable
Further
Progress
RIA
Regulatory
Impact
Analysis
RMRR
Routine
Maintenance,
Repair,
and
Replacement
SARA
Superfund
Amendments
and
Reauthorization
Act
SCR
Selective
Catalytic
Reduction
SCAQMD
South
Coast
Air
Quality
Management
District
SIC
Standard
Industrial
Classification
SIL
Significant
Impact
Level
SIP
State
Implementation
Plan
SO
2
Sulfur
Dioxide
STAPPA/
ALAPCO
State
and
Territorial
Air
Pollution
Program
Administrators/
Association
of
Local
Air
Pollution
Control
Officials
TPY
tons
per
year
UT/
A
Undemonstrated
Technology
Application
VOC
Volatile
Organic
Compound
WEPCO
Wisconsin
Electric
Power
Company
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
1­
1
Chapter
1
­
General
Comments
1.1
Overview
1.2
Procedural
Comments
1.2.1
Extend
Comment
Deadline
Many
State/
local,
industry,
environmental,
and
citizen
commenters
requested
that
EPA
extend
the
public
comment
deadline
beyond
March
2,
2003.

Response:

To
respond
to
these
requests,
the
public
comment
period
was
extended
to
May
2,
2003.

1.2.2
Requests
Public
Hearing
Many
State/
local,
industry,
environmental,
and
citizen
commenters
requested
that
EPA
hold
a
public
hearing
on
the
proposed
rule.
Most
of
the
commenters
requested
that
EPA
hold
a
public
hearing
in
specific
locations
that
would
be
easily
accessible
to
them
.

Response:

To
accomodate
these
requests,
EPA
held
five
public
hearings
on
March
31,
2003.
They
were
in
Albany
NY,
Research
Triangle
Park
NC,
Romulus
MI,
Dallas
TX
and
Salt
Lake
City
UT.

1.2.3
Sufficiency
of
Rulemaking
Process
Three
State/
local
commenters
(
1268,
1438,
1443)
and
one
industry
commenter
(
898)
said
EPA
has
not
provided
sufficient
notice
of
the
substance
of
the
rule
to
allow
for
meaningful
comments.
Two
of
the
commenters
(
1438,
1443)
pointed
out
that
according
to
the
Administrative
procedures
Act,
the
notice
of
proposed
rule
making
must
include
"
either
the
terms
or
substance
of
the
proposed
rule
or
a
description
of
the
subjects
and
issues
involved."
5
USC
553(
b).
Additionally,
these
commenters
noted
that
the
CAA
contains
similar
requirements
at
42
USC
7607(
d).
Commenter
1438
added
that
the
like­
for­
like
replacement
exclusion
is
based
on
a
cost
percentage,
which
is
not
set
forth.
Commenter
1268
said
it
recognized
that
rulemaking
involves
the
consideration
of
options,
but
this
proposal
oversteps
the
limits
of
the
administrative
rulemaking
procedure.
Before
adoption
of
any
new
categorical
exclusions
to
NSR
or
clarifying
and
simplifying
the
existing
RMRR
exclusions,
it
is
critical
that
EPA
publish
a
clearly
defined
and
specific
proposal
for
further
comment.
1
­
General
Comments
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
1­
2
Commenter
1438
added
that
the
preamble
to
the
proposed
rule
indicates
that
in
the
process
of
developing
the
rule
EPA
engaged
in
significant
interagency
consultations,
including
meetings
with
the
representatives
from
the
DOE,
DOI,
and
OMB.
In
addition,
EPA
"
held
conference
calls
with
various
stakeholders
during
October
2001.
.
.
."
All
of
these
consultations
and
any
additional
communications
involving
EPA
and
this
subject
matter
during
the
development
of
this
rule
must
be
included
in
the
docket
in
accordance
with
the
CAA
requirements
in
42
USC
7607(
d)(
6)(
C).

Response:

EPA
strongly
believes
that
the
proposal
notice
contained
sufficient
notice
fo
the
options
under
consideration.
Related
to
the
concern
about
the
cost
percentage
for
the
ERP
not
being
specified,
On
page
80301
of
December
31,
2002
Federal
Register
notice,
there
is
an
explicit
discussion
of
the
possibility
of
using
50
percent
or
some
lesser
number.
Reasons
were
offered
in
favor
of
both
higher
and
lower
numbers
and
comments
were
taken
on
all
of
these
possibilities.
As
to
the
concern
about
whether
all
material
that
is
required
to
has
been
placed
in
the
rulemaking
docket,
sll
relevant
materials
required
under
the
Clean
Air
Act
have
been
included
in
the
docket.

1.2.4
Implementation
of
Provisions
Two
State/
local
commenters
(
1438,
1443)
said
EPA
may
not
lawfully
make
the
proposed
requirements
mandatory,
because
they
are
a
relaxation
of
current
provisions.
Commenter
1438
said
the
proposed
preamble
does
not
address
existing
requirements
that
States
must
adopt
all
definitions
in
40
CFR
51.165(
a)(
1)
and
51.166(
b)
unless
"
the
state
specifically
demonstrates
that
[
the
state's
preferred]
definition
is
more
stringent,
or
at
least
as
stringent,
in
all
respects
as
the
[
federal]
definition...."
Because
both
of
the
new
exemptions
are
in
addition
to
and
not
in
lieu
of
all
existing
exclusions,
a
State's
refusal
to
adopt
the
new
exemption
is
by
sheer
force
of
logic
"
at
least
as
stringent"
as
the
new
Federal
exemption.
Under
such
circumstances,
section
116
of
the
CAA
preserves
the
right
of
each
State
to
decline
to
adopt
the
new
exemption.
In
addition,
because
the
purpose
of
the
new
rule
is
not
to
reduce
emissions,
the
States
should
not
be
required
to
show
that
not
adopting
the
rule
is
"
at
least
as
stringent"
as
adopting
it.

Response:

As
to
the
concern
about
the
environmental
impact
of
the
final
rule,
our
analysis
on
the
electric
utility
industry
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.
1
­
General
Comments
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
1­
3
Regarding
the
applicability
of
our
analysis
to
non­
utility
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
SO
2
cap
for
utilities
cannot
be
extended
to
non­
utilities
that
are
not
similarly
capped.
However,
our
model
runs
for
NO
x
reflected
the
absence
of
a
cap,
and
are
therefore
valid
for
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
maintenance
activities
covered
by
the
final
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
seen
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.

Therefore,
we
affirm
the
overall
conclusion
of
our
analysis
 
that
the
final
rule
has
no
practical
effect
on
the
environmental
benefits
of
major
NSR
in
the
future.
Not
withstanding
that
conclusion,
the
final
changes
are
not
mandatory
requirements
of
the
NSR
and
PSD
programs.
The
decision
to
adopt
them
is
left
to
the
discretion
of
the
State
or
local
agency.

1.3
General
Support
for
Proposal
Rule
Many
industry
commenters
generally
supported
the
proposed
rule.
These
commenters
believed
it
would
provide
regulatory
certainty
and
streamlining,
thus
allowing
regulated
sources
to
improve
efficiency
and
productivity
while
reducing
emissions.
The
industry
commenters
believed
the
proposed
rule
correctly
implemented
the
statutory
requirements.
Some
citizen
commenters
also
supported
the
proposed
rule
for
the
same
reasons.

One
State/
local
agency
(
1240)
supported
the
equipment
replacement
approach
in
the
proposed
rule,
maintaining
that
it
would
provide
regulatory
certainty.
The
State/
local
agency
(
1240)
believed
EPA
should
promulgate
the
ERP
as
proposed.

One
Federal
agency
(
1101)
supported
the
proposed
rule,
believing
it
to
reduce
regulatory
burden.
The
Federal
commenter
(
1101)
requested
clarification
of
several
issues,
however.

Several
university
power
plant
managers
(
901,
1073,
1442,
1477)
also
supported
the
proposed
rule.
These
commenters
noted
that
an
RMRR
exclusion
was
necessary
to
successful
1
­
General
Comments
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
1­
4
operation
of
their
facilities.
Three
of
the
commenters
(
901,
1442,
and
1477)
preferred
the
equipment
replacement
approach.

One
industry
commenter
(
1515)
said
RMRR
exclusions
are
essential
for
complex
manufacturing
facilities
from
a
regulatory
agency
resource
standpoint.
A
petroleum
refinery,
for
example,
may
issue
thousands
of
change
orders
each
year,
with
the
vast
majority
(
over
99
percent)
of
these
activities
small
in
scope
and
not
significant
in
terms
of
emissions
from
the
facility.
With
a
means
to
easily
identify
presumptively
RMRR
activities,
permitting
authorities
could
be
saved
countless
hours
of
wasted
effort.

Commenter
1515
also
noted
that
complex
manufacturing
facilities
(
for
example,
pulp
mills,
petroleum
refineries)
are
characterized
by
intricate
and
interrelated
production
processes,
with
many
separate
emissions
points.
As
a
result,
in
most
cases
no
single
"
add­
on"
control
is
available
to
dramatically
affect
emissions.
Instead,
emissions
are
often
best
reduced
over
time
by
many
small
changes.
The
basic
structure
of
such
plant
operations
makes
clear
that
they
present
needs
for
RMRR
reform
and
opportunities
for
gain
from
NSR
reform.

1.4
General
Opposition
to
Proposal
Rule
Many
State/
local,
citizen,
and
environmental
commenters
generally
opposed
the
proposed
rule.
These
commenters
maintained
the
proposed
rule
did
not
comport
with
the
statutory
requirements
for
major
modifications,
and
would
be
detrimental
for
air
quality
and
public
health.
The
State/
local
commenters
also
opposed
the
proposed
rule,
particularly
the
annual
maintenance
allowance
approach,
because
it
would
be
difficult
and
burdensome
to
implement.
A
few
tribal
agencies
and
legislators
also
opposed
the
rule,
believing
it
would
exacerbate
public
health
concerns.

Response:

EPA
believes
there
is
a
need
for
a
provision
to
adresss
equipment
replacements
under
the
RMRR
exclusion
to
provide
greater
regualtory
certainty
and
has
issued
a
final
rule
for
that
purpose.
EPA
agrees
with
the
commenters
that
the
equipment
replacement
provision
(
ERP)
will
reduce
regulatory
burden
on
industry
and
State
and
local
revieiwng
authorities
by
making
it
easer
to
judge
whether
an
individual
project
is
falls
within
the
RMRR
exclusion.

EPA
disagrees
with
the
commenters
that
stated
that
the
proposed
rule
did
not
comport
with
the
Clean
Air
Act
requirements
for
major
modifications.
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
1
­
General
Comments
Internal
and
Deliberative
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1­
5
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
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
alifetime
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,
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,
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
1
­
General
Comments
1
As
discussed
below,
our
regulations
provided
a
comparable
exclusion
from
NSPS
at
the
time
of
the
1977
Amendments
that
established
the
NSR
program.

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6
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
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.
1
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.
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
pre­
existing
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
1
­
General
Comments
2
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.

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7
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
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
"
likekind
replacement
of
the
kind
addressed
by
the
final
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
enforcement­
related
cases,
we
have
previously
interpreted
"
change"
such
that
all
changes,
even
trivial
ones,
are
encompassed
by
the
Act,
and
thus
we
generally
interpreted
the
exclusion
as
being
limited
to
de
minimis
circumstances.
However,
EPA
does
have
the
authority
to
interpret
these
key
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.
2
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,"
1
­
General
Comments
3
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.

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8
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.
3
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
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.
1
­
General
Comments
Internal
and
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2003
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1­
9
Some
commenters
argued
that,
to
further
the
purposes
of
the
statute,
any
interpretation
must
result
in
the
eventual
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
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
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
1
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2003
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10
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
as
much
flexibility
as
possible
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
effectively
limit
emissions
from
new
and
modified
sources,
it
was
not
designed
to
achieve
emission
reductions
from
every
existing
source.

1.5
Proposed
RMRR
Alternatives
Many
industry
commenters
generally
supported
a
combination
of
the
annual
maintenance
allowance
and
equipment
replacement
approaches.

Some
industry
commenters,
several
university
commenters,
and
one
State/
local
agency
preferred
the
equipment
replacement
approach.
Some
industry
commenters
(
951,
1077,
1078,
1202,
446)
suggested
that
the
equipment
replacement
approach
include
functionally
equivalent
repairs
and
functionally
equivalent
maintenance.
These
commenters
reasoned
that
if
the
replacement
of
an
entire
component
is
routine,
then
the
repair
of
that
component
should
also
be
routine.
The
commenters
gave
examples
of
common
repairs
that
they
considered
functionally
equivalent
repairs,
such
as
boiler
tube
repairs.
Other
commenters
(
1136,
1201)
emphasized
that
the
equipment
replacement
approach
should
allow
replacement
of
parts
that
are
not
broken.

Two
State/
local
agencies
(
1107,
1146)
and
one
industry
commenter
(
506)
preferred
the
annual
maintenance
allowance
approach.

Most
State/
local
agencies,
environmental
groups,
citizens,
tribal
agencies,
and
legislators
generally
opposed
any
of
the
proposed
approaches
for
an
RMRR
exclusion.

Chapter
4
includes
comments
on
age­
based,
capacity­
based,
and
case­
by­
case
RMRR
exemptions.

EPA
agrees
with
the
commenters
and
believes
that
there
is
a
need
for
a
final
rule
on
how
equipment
replacements
should
be
treated
under
the
RMRR
exclusion
and
therefore,
has
isued
a
final
rule.
Although
EPA
believes
in
the
need
for
additional
changes
to
the
RMRR
exclusion
to
provide
greater
certainty,
EPA
has
decided
not
to
take
action
on
an
annual
maintenance,
repair
and
replacement
allowance
option
for
an
RMRR
exclusion
at
this
time.
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2003
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1.6
Implementation
of
the
Proposed
RMRR
Approaches
Several
State
and
local
commenters
expressed
concern
over
the
expertise
in
financial
analysis
that
they
believed
would
be
necessary
to
implement
the
proposed
RMRR
approaches,
particularly
the
AMA.
These
commenters
stated
that
their
staffs
were
not
equipped
to
conduct
the
financial
analysis
required
under
this
approach.
Some
commenters
indicated
that
reliance
on
replacement
costs
will
require
cost
verification
for
each
facility,
which
will
be
extremely
resource
intensive
and
subject
to
debate.
State/
local
commenters
frequently
believed
that
the
changes
would
impose
a
significant
new
burden
on
State/
local
regulatory
agencies.
One
of
the
commenters
believed
that
the
increased
burden
would
likely
necessitate
significant
increases
in
current
permit
and
emissions
fees.

An
environmental
commenter
believed
that
neither
State/
local
agencies
nor
EPA
have
accountants
on
staff
to
implement
the
AMA
approach,
which
would
be
too
complicated
and
onerous.
The
environmental
commenter
also
believed
the
AMA
would
be
too
complicated
for
the
general
public
to
understand.
Thus,
the
public
would
be
denied
the
opportunity
to
participate
in
the
protection
of
air
quality
in
their
communities.

Industry
commenters
were
generally
less
concerned
with
the
implementation
burden
of
the
proposed
RMRR
approaches,
although
many
believed
that
the
AMA
would
be
significantly
more
complex
and
burdensome
than
the
ERP.
Several
recommended
that
we
simplify
the
AMA,
with
some
suggesting
ways
to
bring
the
AMA
more
in
line
with
existing
accounting,
recordkeeping,
and
reporting
requirements.

A
number
of
commenters,
primarily
from
industry,
discussed
how
the
AMA
and
the
ERP
could
be
implemented
together.
Some
common
suggestions
were
the
following.


Give
the
AMA
and
ERP
independent
validity.
Activities
excluded
under
the
ERP
would
not
be
counted
against
the
AMA.


If
a
source
initially
elects
to
operate
under
the
AMA
but
subsequently
finds
that
it
will
exceed
the
allowance,
it
should
be
able
to
review
all
its
projects
and
delete
from
the
AMA
accounts
all
the
meet
the
requirements
of
the
ERP.


First,
track
activities
against
the
AMA.
Any
activities
that
exceed
the
AMA
would
be
evaluated
under
the
ERP.
Any
activities
that
were
not
excluded
under
the
ERP
would
be
evaluated
using
the
case­
by­
case
approach.


First,
any
expenditures
properly
deducted
as
expenses
on
the
source's
Federal
income
taxes
would
be
automatically
classified
as
RMRR.
(
Several
industry
commenters
suggested
this
addition
to
the
RMRR
rule.)
Next,
any
activities
that
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12
qualified
under
the
ERP
would
be
classified
as
RMRR.
Any
expenses
and
ERPexcluded
activities
would
count
against
the
AMA;
that
is,
they
would
use
up
the
allowance
for
other
activities
but
would
not
be
disqualified
themselves
if
they
exceeded
the
allowance.
Any
other
activities
that
did
not
fit
within
the
AMA
would
be
evaluated
using
the
case­
by­
case
approach.

EPA
has
decided
not
to
take
action
on
an
annual
maintenance,
repair
and
replacement
allowance
option
for
an
RMRR
exclusion
at
this
time.
All
of
the
issues
raised
by
the
commenters
will
be
addressed
when
a
final
action
is
taken.
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2003
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1
Chapter
2
­
Annual
Maintenance,
Repair
and
Replacement
Allowance
2.1
Overview
On
December
31,
2002,
we
proposed
a
change
to
the
NSR
program
to
provide
specific
categories
of
activities
that
EPA
will
consider
RMRR.
(
67
FR
80290)
We
proposed
several
possible
approaches
for
specifically
defining
an
exclusion
from
major
NSR
for
RMRR,
including
an:
annual
maintenance,
repair
and
replacement
allowance;
equipment
replacement
provision;
capacity­
based
option;
and
aged­
based
option.
We
are
not
taking
final
action
on
an
annual
maintenance,
repair
and
replacement
allowance
option
for
an
RMRR
exclusion,
and
therefore
public
comments
on
this
option
are
not
relevant.
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and
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3­
1
Chapter
3
­
Equipment
Replacement
3.1
Overview
We
received
public
comments
supporting
or
opposing
the
equipment
replacement
option
for
routine
maintenance,
repair,
and
replacement.
We
also
received
comments
on
the
basic
approach
for
equipment
replacement,
definition
of
process
unit,
capital
cost
percentage,
basic
design
parameters,
functional
equivalence,
the
cost
basis
for
equipment
replacement,
cost
estimation
method,
basis
for
equipment
replacement,
treatment
of
catastrophic
events
and
failures,
non­
emitting
units,
and
implementation.
These
are
summarized
in
sections
3.2
through
3.12.

We
have
attempted
to
include
all
relevant
comments
on
the
equipment
replacement
provision
(
ERP)
in
this
document.
Because
there
were
a
number
of
overlapping
issues
between
the
ERP
and
the
annual
maintenance,
repair
and
replacement
allowance
option,
we
have
attempted
to
inlcude
in
this
document
any
comments
that
were
made
to
these
issues
even
if
they
were
not
specifically
addressed
to
the
ERP.

3.2
General
Support
or
Opposition
for
EPA's
Proposal
Comment:

3.2.1
General
Support
for
Proposal
A
large
number
of
industry
commenters
(
533,
577,
636,
840,
841,
865,
896,
897,
900,
902,
910,
914,
920,
921,
927,
941,
942,
951,
1000,
1007,
1013,
1045,
1050,
1051,
1063,
1066,
1077,
1078,
1082,
1083,
1086,
1088,
1090,
1091,
1096,
1097,
1098,
1099,
1100,
1105,
1109,
1110,
1112,
1113,
1114,
1123,
1124,
1126,
1129,
1130,
1132,
1133,
1134,
1136,
1137,
1138,
1149,
1159,
1160,
1202,
1204,
1209,
1212,
1233,
1236,
1237,
1238,
1245,
1246,
1265,
1271,
1282,
1283,
1287,
1292,
1301,
1343,
1346,
1356,
1363,
1367,
1368,
1371,
1374,
1392,
1395,
1399,
1402,
1403,
1404,
1440,
1441,
1446,
1451,
1453,
1456,
1463,
1465,
1474,
1620,
1626,
1629,
1630,
1792,
1793,
1794,
1798,
1852,
1866,
1868
)
supported
the
ERP
for
RMRR.
Also
expressing
support
for
the
ERP
were
several
State/
local
commenters
(
1240,
1270),
one
legislative
commenter
(
1411),
one
municipal
commenter
(
1069),
four
university
commenters
(
901,
1073,
1442,
1477),
and
one
Federal
commenter
(
1101).

Several
industry
commenters
(
910,
1110,
1129,
1132)
said
the
ERP
will
streamline
the
NSR
applicability
analysis.
Four
industry
commenters
(
902,
951,
1082,
1620,
1793)
and
several
State/
local
commenters
(
1240,
1270)
believed
the
ERP
would
be
easier
to
implement
than
the
AMA.
One
industry
commenter
(
927)
said
the
identical
replacement
provision
will
codify
existing
practices,
where
replacement
has
no
impact
on
emissions
and
would
clearly
represent
RMRR
3
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2
activities.
One
industry
commenter
(
1368)
supported
the
definition
of
process
unit,
which
they
interpreted
as
congruent
with
the
NSPS
definition
of
affected
facility.

Many
commenters
expressed
conditional
support
for
the
ERP,
recommending
certain
changes
that
they
felt
needed
to
be
made
to
improve
the
proposal.
One
industry
commenter
(
902)
strongly
supported
the
ERP
if
applied
on
a
component­
by­
component
basis
(
vs.
aggregating
costs
over
a
fixed
period
of
time)
and
with
a
caveat
that
NSR
would
only
be
triggered
by
an
emissions
increase,
regardless
of
whether
the
activity
exceeded
the
equipment
replacement
cost
threshold.
One
industry
commenter
(
1077)
supported
the
ERP
in
combination
with
a
capacity­
based
option,
on
the
assumption
that
repair
and
maintenance
is
to
be
excluded
as
well
as
equipment
replacement.
Two
industry
commenters
(
577,
1100)
did
not
fully
support
the
ERP
but
believed
it
to
be
more
workable
than
the
AMA.

One
industry
commenter
(
577)
attempted
to
collect
data
from
turbine
customers
and
found
that
a
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.

An
industry
commenter
(
941)
gave
an
example
of
the
clarity
that
the
ERP
would
provide.
Without
the
ERP,
the
source
is
limited
to
some
fraction
of
boiler
tubes
allowed
to
be
replaced
at
a
given
time;
with
the
ERP,
replacement
of
all
boiler
tubes
would
rightfully
be
considered
routine.
Another
industry
commenter
(
1124)
said
the
ERP
will
remove
regulatory
burdens
for
types
of
equipment
replacements
that
are
in
fact
"
routine,"
such
as
replacement
of
tubes
in
industrial
boilers.
This
commenter
gave
several
examples
where
a
project
was
planned
but
not
performed,
because
a
too­
narrow
interpretation
of
what
of
"
routine"
is
would
have
resulted
in
NSR:


In
a
refinery
wax
plant,
a
fugitive
emission
problem
with
a
filtering
system
was
addressed
by
modifying
the
existing
flange
design.
A
preferable
alternative
not
pursued
was
to
completely
replace
the
filter
units
with
new
units.
That
approach
was
rejected
in
part
because
it
was
not
an
exact
replacement
and
would
therefore
probably
have
triggered
NSR
with
attendant
permit
requirements
and
lag
time.
The
rejected
approach
would
have
had
many
benefits,
including
better
reliability
and
more
modern
technology.
The
new
unit
would
have
done
the
same
job
as
the
existing
unit
and
been
easier
to
operate
and
maintain.


By
replacing
the
doors
on
a
raw
material
storage
shed
to
reduce
or
eliminate
emissions
of
fugitive
dust,
a
plant
would
be
able
to
shield
the
contents
of
the
shed
from
moisture,
thus
improving
process
efficiency.


A
paper
mill
used
a
hopper­
and­
shaker
grate
arrangement
to
feed
bark
to
a
dualfueled
(
bark
and
coal)
boiler.
The
system
never
worked
well,
and
distribution
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across
the
firing
grate
was
uneven,
leading
to
less
than
optimal
firing
conditions.
Replacing
the
hopper­
and­
shaker
grate
arrangement
with
a
screw­
feed
system
would
have
improved
feed
distribution
on
the
grate,
leading
to
greater
combustion
efficiency
and
would
have
increased
the
ability
to
substitute
bark
for
coal
as
a
fuel
at
any
operating
level.


Replacing
a
paper
machine
vacuum
pump
with
a
more
efficient
unit
would
have
allowed
a
paper
mill
to
increase
the
proportion
of
recycled
paper
that
could
be
used
in
the
feedstock,
reducing
costs
and
benefitting
the
environment,
with
no
increase
in
emissions
rate.
Greater
vacuum
would
translate
to
a
lower­
moisture
mat
and
less
energy
requirements
for
drying.


A
veneer
dryer
feed­
out
system
that
frequently
jammed
could
be
replaced
with
one
that
did
not
jam.
This
replacement
would
decrease
machine
downtime,
thus
improving
process
reliability
and
availability
of
process
capacity.


Soot
blowers
at
a
boiler
could
be
replaced
with
blowers
that
improved
steam
tube
cleaning.
Loss
in
heat
transfer
efficiency
would
be
reduced.
The
boiler
would
be
able
to
operate
at
its
full
rated
capacity
and
for
longer
periods
between
shutdowns
for
cleaning.

Another
industry
commenter
(
1465)
said
the
ERP
would
have
a
significant
positive
impact
on
the
commenter's
paper
and
wood
product
manufacturing
operations
in
5
States
at
13
locations
that
are
major
sources
under
PSD.
This
commenter
claims
that
current
NSR
RMRR
rule
provisions
and
guidance
have
not
provided
much
needed
certainty
and
have
impeded
work
necessary
to
maintain
reliable
manufacturing
operations.
EPA's
RMRR
interpretations
appear
to
continually
change
and
have
become
increasingly
constrictive;
uncertainty
surrounding
RMRR
has
the
potential
to
adversely
affect
the
reliability
of
commenter's
suppliers,
most
notably
electric
power
utilities
but
also
chemical
and
fuel
suppliers.

Several
industry
commenters
(
1136,
1202)
said
the
ERP
should
allow
replacement
of
a
part
that
is
not
broken
for
the
purpose
of
preventative
maintenance.
Some
industry
commenters
(
951,
1077,
1078,
1202,
446)
suggested
that
the
equipment
replacement
approach
include
functionally
equivalent
repairs
and
functionally
equivalent
maintenance.
These
commenters
reasoned
that
if
the
replacement
of
an
entire
component
is
routine,
then
the
repair
of
that
component
should
also
be
routine.
The
commenters
gave
examples
of
common
repairs
that
they
considered
functionally
equivalent
repairs,
such
as
boiler
tube
repairs.
Other
commenters
(
1136,
1201,
1202)
emphasized
that
the
equipment
replacement
approach
should
allow
replacement
of
parts
that
are
not
broken.
3
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6,
2003
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or
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3­
4
One
industry
commenter
(
1136)
stated
that
the
ERP
was
of
paramount
importance
to
APPA's
electric
utility
members,
and
another
industry
commenter
(
533)
stated
that
the
ERP
would
allow
electric
utilities
to
undertake
the
numerous
relatively
low­
cost
maintenance,
repair,
and
replacement
projects
needed
to
maintain
facilities
in
a
manner
that
ensures
a
safe,
reliable,
and
efficient
power
supply.
One
industry
commenter
(
1797)
described
the
practice
in
the
electric
utility
industry
of
maintaining
one
or
more
spare
turbine
engines
that
are
installed
when
an
inservice
turbine
is
removed
for
routine
maintenance.
This
reduces
the
downtime
for
electric
generating
units
due
to
maintenance
repairs.
The
industry
commenter
requested
that
EPA
define
this
practice
as
RMRR.

One
industry
commenter
(
1095)
said
the
ERP
should
give
consideration
to
regional
cost
differences.
Two
industry
commenters
(
1110,
1132)
suggested
that
EPA
may
want
to
consider
granting
special
consideration
for
precious
metal
replacement.
One
of
these
industry
commenters
(
1132)
noted
that
the
cost
to
replace
gold
or
platinum
may
even
exceed
50
percent
of
the
cost
of
the
other
equipment
in
a
chemical
process
unit,
if
the
unit
has
few
components.

One
industry
commenter
(
910)
stated
that
the
ERP
was
necessary
because
the
annual
allowance
alone
would
not
cover
the
full
range
of
replacement
projects
that
are
undertaken
for
safety,
reliability,
and
efficiency
reasons
at
electric
generating
facilities
and
would
not
cover
component
replacements
necessitated
by
catastrophic
failures
or
events.

One
State/
local
commenter
(
1240)
noted
that
any
short­
term
increase
in
actual
emissions
as
a
result
of
less
process
unit
downtime
for
maintenance
and
repair
may
be
balanced
by
a
longterm
decrease
in
actual
emissions
as
a
result
of
more
efficient
operation
and
the
greater
incentive
to
conduct
RMRR.

3.2.2
Opposition
to
Proposal
Many
State/
local
commenters
(
838,
912,
946,
1107,
1146,
1150,
1151,
1199,
1206,
1264,
1268,
1361,
1443,
1471,
1486,
1448),
citizen
commenters
(
784,
1573,
1761,
1952,
1953)
and
environmental
commenters
(
514,
522,
600,
617,
621,
627,
712,
713,
1150,
1631,
1628)
opposed
the
equipment
replacement
approach
for
RMRR.
Three
industry
commenters
(
797,
909,
1145),
a
university
commenter
(
1085),
and
a
Federal
commenter
(
Environment
Canada,
1002)
also
opposed
the
ERP.

The
environmental
and
citizen
commenters
generally
opposed
any
kind
of
RMRR
exclusion,
including
one
based
on
equipment
replacement.
However,
some
of
the
State/
local,
environmental,
and
citizen
commenters
also
believed
the
ERP
was
problematic
because
it
would
allow
a
source
to
replace
an
entire
process
unit
over
time.
Two
of
the
State/
local
commenters
(
1107
and
1146)
opposed
the
ERP
because
they
felt
it
would
create
disincentives
for
the
implementation
of
PALs
and
Clean
Unit
provisions
from
the
recently
finalized
rule.
The
3
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and
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2003
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3­
5
university
commenter
(
1085)
opposed
the
ERP
primarily
due
to
cost
variability.
One
State/
local
commenter
(
1443)
believed
a
percentage
of
replacement
cost
has
no
linkage
to
whether
a
project
is
routine,
as
some
expensive
projects
are
routine
and
some
relatively
inexpensive
ones
are
nonroutine.
The
commenter
was
strongly
opposed
to
the
sole
use
of
cost
in
determining
what
constitutes
RMRR.
The
Federal
commenter
(
1002)
opposed
the
ERP
in
part
because
of
the
potential
for
uneven
application
of
the
exemption;
a
same­
cost
project
would
be
exempt
at
a
larger
plant
but
not
at
a
smaller
one.
While
opposing
the
ERP,
one
citizen
commenter
(
784)
found
it
less
objectionable
than
the
AMA.

One
environmental
commenter
(
1150)
said
that
from
an
engineering
standpoint,
for
a
power
plant,
the
difference
between
routine
maintenance
and
a
major
plant
refurbishing
project
is
clear.
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.
Permanent
staff
do
this
work
either
while
the
plant
is
operating
or
during
only
brief
periods
of
downtime.
Activities
that
are
not
routine
require
long
plant
or
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
industry
commenter
(
1630)
opposed
the
ERP
as
proposed
but
said
they
could
support
the
provision
if
it
allowed
any
equipment
replacement
so
long
as
the
replacement
did
not
increase
the
process
unit
maximum
hourly
emission
rate.
An
environmental
commenter
(
1150)
said
any
ERP
that
EPA
might
adopt
should
exclude
equipment
replacement
that
changes
the
basic
design
parameters
of
the
process
unit
or
results
in
an
increase
of
total
annual
emissions.

One
State/
local
commenter
(
912)
expressed
concern
that
the
lack
of
an
NSPS­
like
test
on
emissions
means
that
non­
routine
replacements
could
result
that
increase
emissions
but
avoid
NSR.
Another
State/
local
commenter
(
1471)
said
the
proposal
will
allow
emissions
increases
that
will
be
difficult
to
offset
through
other
regulations.
Two
State/
local
commenters
(
1199,
1361)
objected
to
the
ERP
because
no
reporting
is
required.
One
of
these
State/
local
commenters
(
1361)
felt
the
proposal
was
not
specific
enough
to
allow
for
meaningful
comment.
One
of
these
State/
local
commenters
(
1199)
objected
to
the
ERP
for
numerous
reasons.
The
ERP
does
not
prevent
of
replacement
with
different
equipment.
It
does
not
promote
efficiency
improvements
or
application
of
good
air
pollution
controls.
It
would
allow
replacements
that
would
significantly
increase
emissions.
This
commenter
said
replacement
of
air
pollution
controls
should
trigger
BACT/
LAER
requirements.
Further,
this
commenter
said
the
ERP
should
provide
for
aggregation
so
that
entire
units
cannot
be
replaced
over
time.
Another
State/
local
commenter
(
1146)
stated
that
if
the
ERP
is
promulgated,
it
should
only
be
allowed
for
units
that
have
already
applied
BACT
and
performed
the
associated
air
quality
analysis.
Also,
the
ERP
should
require
companies
to
submit
project
lists
and
associated
costs
to
the
permitting
authority.

3.2.3
Legal
Rationale
for
Proposal
3
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3­
6
We
received
a
number
of
comments
directed
to
the
legal
rationale
for
the
proposed
rule.
Some
comments
were
specific
to
the
ERP,
some
were
specific
to
the
AMA,
and
others
addressed
both
approaches.
As
we
discussed
in
Chapter
2
of
this
document,
we
are
not
promulgating
an
AMA
option
for
RMRR
exclusion;
therefore,
we
are
not
addressing
comments
directed
solely
to
the
legal
rationale
of
the
AMA
approach.
In
this
section,
we
address
those
comments
directed
to
only
the
ERP,
as
well
as
comments
that
address
both
approaches
without
particular
distinction.

3.2.3.1
Support
for
Both
Approaches
Some
industry
commenters
(
1113,
1124/
1515,
1132,
1160,
1201,
1202,
1213)
said
that
both
of
EPA's
proposed
approaches
are
clearly
legal.
Commenters
said
EPA
should
expand
its
discussion
of
its
legal
authority
in
the
preamble.

Commenters
1113,
1160,
and
1515
said
both
approaches
are
fully
consistent
with
the
statute
and
Congressional
objectives.
Commenter
1160
added
that
construing
the
pertinent
statutory
language,
EPA
has
always
taken
a
position
that
Congress
did
not
intend
to
make
every
activity
at
an
individual
sources
subject
to
NSR
requirements.
Successive
amendments
of
the
statute
and
Congressional
consideration
of
the
scope
of
the
NSR
programs
have
validated
EPA's
historical
position
and
interpretations.
These
include
a
number
of
"
commonsense"
exclusions
from
the
potential
scope
of
the
NSPS
program,
the
predicate
for
the
NSR
program.
These
exclusions
were
for
increases
in
operating
hours
or
production
rates
and
for
maintenance,
repair
and
replacement
projects
that
are
routine
in
the
particular
industry.
The
commonsense
regulatory
exclusions
that
defined
the
scope
of
the
NSPS
program
became
the
legislative
outer
boundaries
of
the
NSR
programs.

Commenters
1132,
1201
and
1202
said
that
EPA
has
three
distinct
yet
overlapping
sources
of
legal
authority
to
promulgate
the
proposed
provisions:


EPA
has
authority
to
explain
and
implement
the
statutory
definition
of
"
modification."
For
there
to
be
a
"
modification,"
there
must
first
be
a
physical
or
operational
"
change."
The
proposal
is
well
within
EPA's
authority
to
explain
and
implement
the
statutory
test
of
"
change."
CAA
§
111(
a)(
4).


EPA
has
authority
to
clarify
and
simplify
the
existing
the
existing
regulatory
RMRR
provision.
The
proposal
reflects
EPA's
recognition
that
the
existing
RMRR
provision
has
become
burdened
by
complexity
and
subjective
assessment
that
it
no
longer
provides
adequate
guidance.


EPA
has
authority
as
an
exercise
of
its
inherent
de
minimis
authority
to
alleviate
severe
administrative
burdens
as
explicated
by
the
United
States
Court
of
Appeals
3
­
Equipment
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Internal
and
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2003
Do
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or
distribute
3­
7
for
the
District
of
Columbia
Circuit
in
Alabama
Power
Co.
v.
Costle,
636
F.
2d.
323
(
D.
C.
Cir.
1979).
The
current
case­
by­
case
approach
has
become
burdensome
for
regulators
and
the
regulated,
diverting
resources
from
significant
issues.
The
commenters
(
1201
and
1202)
concluded
that,
while
the
de
minimis
authority
is
clearly
available
to
support
promulgation,
they
urged
EPA
to
base
its
action
on
one
or
both
of
the
other
two
sources
of
legal
authority
cited
above.


Regarding
EPA's
de
minimis
authority,
commenter
1132
added
that
an
agency's
de
minimis
authority
does
not
depend
on
grants
of
authority
from
Congress.
Instead,
it
is
the
ability
to
not
implement
Congressional
directives
when
it
determines
there
is
little
benefit
to
doing
so.
Thus,
the
two
exclusions
can
be
viewed
as
proper
use
of
the
agency's
de
minimis
authority.

Commenters
1132,
1201
and
1202
said
that
the
proposed
"
safe
harbor"
provisions
are
within
EPA's
authority
to
explain
and
implement
the
statute.
The
commenters
said
the
plain
language
of
the
statutory
modification
definition
combined
with
the
history
of
the
construction
of
that
term
demonstrate
the
legality
of
the
proposal.
The
commenters
said
that
use
of
the
term
"
change"
in
the
definition
indicates
that
Congress
did
not
intend
activities
within
normal
plant
operating
parameters
and
design
to
trigger
an
NSR
inquiry.
The
commenters
concluded
that
"
routine
maintenance,
repair,
and
replacement,"
"
an
increase
in
the
production
rate,
if
such
increase
does
not
exceed
the
operating
design
capacity
of
the
affected
facility,"
"
an
increase
in
the
hours
of
operation,"
and
"
the
use
of
an
alternative
fuel
or
raw
material
if
.
.
.
the
affected
facility
is
designed
to
accommodate
such
alternative
use"
are
not
"
changes"
because
they
all
reflect
the
contemplated
normal
operation
of
the
unit.

Commenters
1132,
1201
and
1202
said
Congress'
adoption
of
the
NSPS
definition
for
the
NSR
program
reaffirmed
the
exclusion
for
RMRR
activities.
Because
Congress
specifically
looked
to
the
NSPS
program
as
the
source
of
the
definition
of
modification
for
the
PSD
program
(
see
CAA
§
169(
2)(
C)),
it
must
be
assumed
that
Congress
approved
EPA's
previous
administrative
interpretations
concerning
that
term,
endorsing
the
concept
that
any
change
must
be
from
the
"
base
case."
The
regulatory
clarification
that
RMRR
and
the
other
clarification
as
to
what
constitutes
a
"
change"
for
purposes
of
the
definition
of
a
"
modification"
are
now
part
of
the
statutory
definition
of
modification,
which
EPA
is
not
free
to
discard.
EPA
is
free,
however,
to
clarify
the
scope
of
the
definition,
which
EPA's
proposal
would
do.

Commenter
1213
provided
an
extensive
summary
of
the
development
of
both
the
NSPS
and
NSR
programs
and
how
key
provisions
interrelate.
The
commenter
concluded
that
the
rulemakings
to
develop
and
revise
the
new
source
programs,
Congress'
action
in
both
the
1977
and
1990
CAA
Amendments,
and
the
implementation
history
of
the
new
source
programs
all
confirm
that
RMRR
activities
that
ensure
safe
and
reliable
operation
of
sources
as
originally
designed
and
constructed
are
not
the
types
of
activities
that
constitute
"
modifications"
under
the
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new
source
programs.
Only
activities
that
increase
the
capacity
of
a
source
to
emit
beyond
its
capability
as
originally
designed
and
constructed,
or
activities
that
restore
capacity
to
longdeteriorated
units
by
means
of
unprecedented
component
replacements
for
that
industry,
may
be
modifications
that
require
application
of
the
new
source
programs.
EPA's
proposal
is
completely
consistent
with
these
legal
principles.
The
commenter
urged
EPA
to
adopt
the
foregoing
legal
support
as
justification
for
its
final
RMRR
rule.

Commenters
1132,
1201
and
1202
said
EPA's
historical
application
of
the
term
"
modification"
recognized
that
a
fundamental
change
must
be
made
to
trigger
an
NSR
inquiry.
The
commenters
provided
a
review
of
the
history
of
EPA's
actions
to
demonstrate
that
the
proposed
safe
harbor
provisions
are,
in
fact,
consistent
with
approaches
EPA
has
previously
adopted.
Thus,
they
are
within
the
realm
of
activities
EPA
has
previously
excluded
from
the
program,
and
which
exclusion
was
affirmed
by
Congress
when
it
adopted
the
NSPS
modification
definition
for
purposes
of
NSR.

According
to
commenters
1132,
1201
and
1202,
under
Chevron,
U.
S.
A.
v.
NRDC,
467
U.
S.
837
(
1984),
the
Agency
is
authorized
to
adopt
a
reasonable
interpretation
of
the
statutory
definition
of
"
modification,"
incorporating
bright­
line
tests
to
ease
administrative
burdens.
The
commenters
said
Congress
did
not
intend
to
apply
new
source
programs
to
existing
facilities
that
are
merely
operated
as
existing
facilities
and
reserved
new
source
programs
for
activity
that
creates
new
pollution.
When
Congress
amended
the
CAA
in
1977
and
1990,
it
established
a
consistent
statutory
definition
of
"
modification"
that
is
clearly
valid
under
the
first
prong
of
the
Chevron
test,
which
asks
whether
Congress
has
evinced
a
clear
intent
on
the
precise
question
at
issue.
Even
if
it
were
assumed
that
Congress
had
not
spoken
directly
to
the
issue,
the
Agency
has
the
authority
to
make
policy
choices
consistent
with
the
statutory
purpose.
(
Chemical
Manufacturers
Association
v.
EPA,
859
F.
2d
977,
984
(
D.
C.
Cir.
1988).
In
this
case,
the
Administrator
may
also
rely
on
his
general
authority
to
"
prescribe
such
regulations
as
are
necessary
to
carry
out
his
functions
[
under
the
Clean
Air
Act]."
The
NSR
provisions
adopted
in
1977
are
preceded
by
a
Congressional
statement
of
policies
demonstrating
that
Congress
wanted
to
accommodate
the
policies
of
environmental
protection
and
economic
growth.
An
interpretation
of
the
CAA
concluding
that
operation
of
an
existing
facility
as
it
was
designed
and
constructed
to
operate
does
not
change
that
existing
source
into
a
"
new
source"
represents
a
reasonable
accommodation
of
conflicting
policies
that
Congress
committed
to
EPA's
discretion
and
is
thus
sustainable
under
the
Chevron
decision.

Commenters
1132,
1201
and
1202
added
that
case
law
supports
bright­
line
tests
in
regulations
to
avoid
the
regulatory
burden
of
case­
by­
case
adjudication.
Because
the
regulatory
costs
and
uncertainties
associated
with
the
present
system
of
case­
by­
case
adjudications
for
practically
every
case
are
intolerable,
a
"
bright­
line"
safe
harbor
is
needed.
EPA's
use
of
monetary
"
bright­
line"
tests
with
regard
to
various
aspects
of
NSR
is
reasonable
implementation
of
the
RMRR
test.
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Industry
commenter
1515
stated
the
RMRR
exclusion
is
part
of
the
CAA.
When
Congress
enacted
the
NSR
program
in
1977,
it
expressly
adopted
the
same
definition
of
"
physical
change
or
change
in
the
method
of
operation"
that
the
1970
Act
had
used
for
NSPS.
The
courts
have
recognized
that
the
PSD
provisions
of
the
CAA
incorporated
the
section
111
definition
of
"
source"
concerning
modifications,
and
at
the
time
of
this
Congressional
action,
EPA's
section
111
regulations
contained
an
RMRR
exclusion.
When
Congress
amended
the
CAA
in
1990,
it
did
not
change
the
definition
of
either
"
physical
change
or
change
in
the
method
of
operation"
or
the
RMRR
exclusion.
The
commenter
said
EPA's
RMRR
proposal
does
not
rest
on
a
de
minimis
theory
but
rather
on
EPA's
power
to
interpret
the
inherently
ambiguous
terms
"
physical
change
or
change
in
the
method
of
operation"
and
"
routine
maintenance,
repair
and
replacement."

Commenter
1515
noted
that
the
basic
architecture
of
both
the
PSD
program
and
the
nonattainment
NSR
program
shows
unmistakably
that
Congress
intended
the
programs
to
limit
air
pollution
increases,
not
to
reduce
emissions.
Congress
sought
to
reduce
air
emissions
through
other
requirements,
such
as
specific
emissions
standards
(
e.
g.,
MACT)
and
State
Implementation
Plans.
Indeed,
the
courts
have
consistently
held
that
a
source
that
increases
its
emissions
through
a
physical
or
operational
change
can
avoid
NSR
if
the
source
reduces
emissions
elsewhere
so
as
to
avoid
an
overall
increase.

Commenter
1515
observed
that
since
the
early
1970s,
EPA
has
structured
RMRR
as
an
exclusion
from
the
emissions
increase
test
but
that
EPA's
current
RMRR
proposal
carefully
limits
that
departure.

[
Note
to
reviewers:
NEDA/
CARP
(
1134)
provided
extensive
legal
rationale
but
it
was
all
specific
to
the
AMA
and
so
is
not
included
in
this
ERP
chapter.]

3.2.3.2
Opposition
to
Both
Approaches
Some
industry
commenters
(
909),
State/
local
commenters
(
1437,
1241,
1443),
and
environmental
groups
(
1150)
provided
legal
reasons
for
their
opposition
to
the
proposed
changes
to
the
definition
of
RMRR.

Commenter
1241
said
EPA's
proposal
is
illegal.
Congress
has
clearly
expressed
its
intent
to
control
emissions
from
modified
sources
and
eliminate
grandfathering
over
time.
EPA
does
not
have
the
power
to
depart
from
this
clearly
expressed
Congressional
intent
behind
the
NSR
provisions.
Notably,
EPA
is
fully
aware
of
these
limitations
on
its
authority;
it
has
repeatedly
recognized
them
in
its
PSD
rulemaking
that
followed
the
Alabama
Power
decision,
in
its
1996
and
1998
NSR
reform
proposals,
in
the
administrative
decision
in
In
re
Tennessee
Valley
Authority,
Docket
no.
CAA­
2000­
04­
008
(
September
15,
2000)
and,
most
recently,
in
briefs
filed
in
its
NSR
enforcement
cases.
However,
candidly
acknowledging
that
this
proposal
is
guided
by
the
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recommendations
of
the
energy
task
force
empaneled
by
Vice
President
Cheney
(
67
FR
80290),
rather
than
any
fealty
to
Congressional
purpose,
EPA
has
disregarded
the
limitations
on
its
authority
in
offering
this
proposal.
The
commenter
provided
several
examples
to
support
its
argument
(
see
pp.
7
­
27).

Commenter
1150
said
the
broad,
categorical
exclusions
that
EPA
proposes
would
exempt
from
NSR
requirements
physical
changes
or
operational
[
changes]
that
increase
emissions
by
significant
(
i.
e.,
by
non­
de
minimis)
amounts.
In
fact,
the
proposed
exclusions
would
exempt
numerous
and
substantial
physical
or
operational
changes
that
cause
immense
emissions
increases.
Any
action
to
finalize
any
or
all
of
the
proposed
exemptions
would
therefore
be
arbitrary,
capricious,
and
otherwise
not
in
accordance
with
law.
The
commenter
provided
a
TVA
enforcement
example
and
an
Alcoa
enforcement
example
to
support
their
claims.

Commenter
1150
said
the
proposed
rule's
new
applicability
thresholds
already
have
been
held
unlawful.
In
Alabama
Power,
the
D.
C.
Circuit
held
that
the
CAA
does
not
limit
the
definition
of
"
modification"
to
"
physical
changes
exceeding
a
certain
magnitude."
Notwithstanding
that
holding,
EPA
proposes
to
exclude
any
physical
activity
that
did
not
exceed
a
certain
magnitude
(
e.
g.,
activity's
cost
in
relation
to
the
facility
or
unit
or
whether
the
activity
causes
an
increase
in
the
capacity
of
a
process
unit).
In
WEPCO,
the
Seventh
Circuit
held
that
Congress
did
not
intend
to
require
that
physical
activity
work
a
basis
or
fundamental
change
in
a
facility
before
it
would
qualify
as
a
"
physical
change."
Instead
the
Court
found
that
physical
activity
is
a
"
physical
change,"
and
thus
a
modification,
even
though
it
constituted
a
"
like­
kind"
replacement.
EPA
has
proposed
a
rule
that
contradicts
this
direction.

Commenter
1150
said
EPA
does
not
have
the
legal
authority
to
create
the
proposed
exemptions
because
they
deviate
from
the
statute's
plain
language.
The
Agency
may
not
rely
on
any
residual
de
minimis
authority
because
it
has
not,
and
cannot,
demonstrate
that
the
burdens
of
defining
"
modification"
to
include
anything
less
than
what
is
covered
under
the
proposed
exemptions
would
yield
a
gain
of
trivial
or
no
value,
or
lead
to
absurd
or
futile
results
so
as
to
permit
the
exemptions.
To
the
extent
available,
EPA
may
only
invoke,
and
already
has
invoked,
de
minimis
authority
in
creating
"
significant"
emissions
thresholds
for
NSR
modifications.
Even
if
EPA
has
additional
de
minimis
authority
for
deviations
from
the
term
"
any
physical
change
in.
or
change
in
the
method
of
operation
of,"
EPA
has
not
shown
that
its
proposed
rule
would
meet
the
rigorous
requirements
of
the
de
minimis
and
"
administrative
necessity"
doctrines.
For
these
reasons,
the
Agency's
proposed
rule
is
unlawful,
arbitrary,
and
capricious,
and
may
not
be
adopted.
The
commenter
provided
extensive
support
for
these
assertions.
See
pp.
24
­
47.

Commenter
1150
said
the
proposed
rule
unlawfully
merges
the
NSR
program
with
the
NSPS
program.
As
reflected
in
the
statutory
scheme,
and
recognized
repeatedly
by
Congress,
the
courts,
and
EPA
itself,
these
programs
are
designed
to
achieve
fundamentally
different
purposes
in
the
nation's
air
pollution
control
strategy.
While
both
programs
are
concerned
with
balancing
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environmental
protection
and
economic
growth,
they
strike
this
balance
in
significantly
different
ways.
The
commenter
added
that
the
courts
have
long
recognized
the
different
purposes
and
requirements
of
the
NSR
and
NSPS
programs
and
have
rejected
attempts
to
import
provisions
and
rationales
from
one
program
to
the
other.
In
Alabama
Power,
the
D.
C.
Circuit
upheld
EPA's
application
of
the
"
bubble
concept"
to
calculate
emissions
increases
in
NSR,
after
having
rejected
its
use
in
the
NSPS
program.
In
WEPCO,
the
Seventh
Circuit
observed
that
by
1977
the
NSPS
program,
with
its
focus
on
hourly
rates
of
emissions,
had
resulted
in
"
only
varying
degrees
of
success
in
controlling
pollution
in
different
parts
of
the
country."
Consequently,
Congress
added
the
PSD
program.
Commenter
1150
said
proposals
to
incorporate
provisions
of
the
NSPS
program
into
the
NSR
program
must
be
evaluated
within
the
statutory
and
legal
framework.

Commenter
1150
said
the
proposed
rule
would
exempt
activity
that
is
not
routine.
The
commenter
cited
examples
where
EPA
acknowledged
the
narrow
nature
of
"
routine"
activities
that
would
probably
exclude
like­
kind
replacements
and
would
definitely
exclude
"
once­
in­
alifetime
projects
and
other
similar
findings
in
the
TVA
enforcement
case.
Notwithstanding
EPA's
acknowledgment
in
TVA
and
SIGECO,
and
the
Court's
holding
in
the
latter
case,
that
EPA's
"
extremely
limited
authority
to
exempt
activities
from
the
definition
of
modification"
necessitates
a
narrow
reading
of
"
routine
maintenance"
exclusion,
the
Agency
now
proposes
to
deem
broad
swaths
of
emissions­
increasing
activity
"
routine"
and
thus
exempt
from
the
NSR
requirements.

Commenter
1150
said
EPA
has
failed
to
consider
the
full
purpose
and
intent
of
the
NSR
program
and
instead
regards
the
promotion
of
"
the
productive
capacity
of
[
the
Nation's]
population"
as
its
only
mandate,
completely
eschewing
its
obligation
to
protect
air
quality
and
public
health.
This
interpretation
of
the
statute,
and
the
subsequent
assumption
that
it
possesses
the
authority
to
broaden
an
exemption
never
intended
under
the
law,
contradicts
the
clear
and
unequivocal
primary
purpose
of
the
statute
to
protect
air
quality
and
public
health.
EPA
also
fails
to
address
several
other
relevant
factors
pertaining
to
the
scope
and
accomplishments
of
NSR
that
are
critical
to
the
ultimate
issue
of
whether
EPA
has
the
legal
authority
to
broaden
the
very
narrow
exemption
for
RMRR
currently
permitted.
For
example:


EPA
fails
to
mention
that
it
is
legally
restricted
from
expanding
the
already
tenuous
exemptions
for
RMRR,
nor
does
it
explain
who
the
proposed
rule
will
not
indefinitely
grandfather
existing
sources
from
the
reach
of
the
program.


EPA
fails
to
reference
the
ongoing
enforcement
actions,
or
how
the
positions
it
adopts
in
the
proposal,
will
undermine
the
arguments
put
forward
by
the
Department
of
Justice.


EPA
makes
statements
in
the
proposal
that
are
telling
of
its
belief
that
the
NSR
provisions
are
inconsequential.
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Other
than
its
rather
vague
reliance
on
the
noncontrolling
preamble
to
the
statute,
the
Agency
has
provided
no
legal
justification
for
a
proposal
that
contradicts
years
of
accepted
Agency
policy
as
well
as
the
legal
positions
it
has
taken
in
enforcing
the
program.
Neither
does
it
explain
how
it
may
now
adopt
an
overly
broad
interpretation
of
an
exemption
created
entirely
by
regulation,
which
unit
now
it
has
insisted
should
be
narrow.

Some
commenters
(
909,
1437)
said
the
NSR
proposal
is
inconsistent
with
the
legislative
intent
of
the
CAA
and
would
unlawfully
frustrate
our
nation's
ability
to
meet
its
important
goals
under
the
CAA.
First,
the
CAA's
legislative
history
firmly
indicates
that
Congress
exempted
the
aging
fleet
of
existing
power
plants
from
comprehensive
NSR
requirements
only
on
certain
very
strict
conditions.
At
the
same
time,
Congress
specifically
contemplated
that
any
older
power
plants
that
did
not
retire
would
eventually
be
required
to
undertake
modifications
to
extend
their
useful
life
and
that
it
would
be
appropriate
to
install
state­
of­
the­
art
emissions
controls
at
that
time.
As
noted
by
the
Court
in
Alabama
Power,
the
CAA's
NSR
requirements
for
facility
modifications
were
intended
to
ensure
that
so­
called
"
grandfathered"
facilities
did
not
receive
"
perpetual
immunity"
from
all
standards
under
the
NSR
program.
Furthermore,
Congress
emphatically
stressed
that
the
CAA
was
intended
to
be
a
"
technology­
forcing"
scheme
to
push
the
development
of
new
technologies
to
be
used
in
new
power
plants
and
modifications
of
existing
plants
and
to
forcefully
require
the
installation
of
state­
of­
the­
art
pollution
controls
at
specified
times.

Thus,
as
the
legislative
history
clearly
shows,
at
the
time
of
the
1977
CAA
amendments
Congress
agreed
that
many
existing
power
plant
facilities
that
might
otherwise
be
subject
to
new
regulatory
controls
would
soon
reach
the
end
of
their
expected
life
and
therefore
should
be
exempted
from
the
stringent
new
NSR
requirements.
However,
Congress
chose
to
require
that
any
otherwise
exempt
power
plants
that
made
modifications
that
significantly
increased
the
older
plant's
air
emissions
would
need
to
retrofit
these
facilities
with
pollution
controls
similar
to
those
required
for
new
facilities.
EPA's
proposed
RMRR
rule
clearly
violates
the
legislative
intent
of
the
CAA
and
plainly
contradicts
the
fundamental
principles
of
the
NSR
program,
since
it
would
effectively
allow
high­
emitting
power
plants
that
are
well
past
their
original
useful
life
to
install
equipment,
perform
replacements,
and
indefinitely
postpone
full
compliance
with
the
NSR
program,
so
long
as
these
activities
satisfied
the
extremely
generous
financial
thresholds
under
the
proposed
rule.
The
commenter
said
that
Congress
never
envisioned
such
a
result.

Commenter
909
said
the
proposed
rule
would
improperly
contravene
the
CAA's
statutory
mandate
that
"
modifications"
to
existing
power
plants
must
comply
with
NSR
requirements,
because
it
excludes
a
potentially
vast
array
of
facility
changes
from
the
NSR
requirements
for
plant
modifications
and,
thereby,
could
lead
to
significant
increases
in
emissions
of
harmful
pollutants.
For
example,
allowing
facilities
to
implement
generating
efficiency
improvements
at
3
­
Equipment
Replacement
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
3­
13
existing
power
units,
which
almost
certainly
would
lead
to
increased
air
emissions
from
these
units
by
increasing
the
amount
of
hours
per
year
that
the
units
can
run
where
they
are
dispatched
on
an
efficiency
basis,
without
complying
with
NSR
would
clearly
circumvent
Congress'
mandate
that
such
improvements
may
be
implemented
only
after
installing
modern
air
pollution
controls.

Commenter
909
said
the
proposed
RMRR
definition
conflicts
with
court
decisions
on
the
scope
of
EPA's
authority,
which
have
already
rejected
prior
efforts
to
establish
improperly
broad
exclusions
from
the
CAA's
definition
of
"
modification."
For
example,
in
Alabama
Power,
the
Court
struck
down
the
Agency's
proposed
regulatory
exemption
from
NSR
for
"
non­
major"
facility
modifications.
The
Court
also
recognized
that
the
CAA
does
not
authorize
EPA
to
allow
aging
power
plants
to
indefinitely
postpone
or
avoid
their
need
to
install
state­
of­
the­
art
pollution
controls
if
these
plants
implement
physical
changes
that
result
in
increased
emissions
of
air
pollutants.
However,
EPA's
proposal
would
lead
to
this
result
and
cannot
be
supported
by
the
law
and
must
be
either
substantially
revised
or
withdrawn.
The
commenter
noted
cases
where
the
courts
have
struck
down
prior
rulemakings
by
EPA
and
other
Federal
agencies
based
on
the
determination
that
these
rules
were
contrary
to
the
Agency's
statutory
authority.

Commenter
909
said
the
proposed
definition
violates
EPA's
well­
established
interpretation
of
the
RMRR
exemption
by
creating
new,
expansive
categories
of
RMRR
activities
that
would
be
excluded
from
NSR
requirements.
The
courts
have
consistently
affirmed
EPA's
narrow
interpretation
of
the
RMRR
exclusion.
For
example,
in
one
recent
case
(
SIGECO
II,
2003
WL
367901,
at
17)
the
Court
said:
"
Although
routine
maintenance
is
not
defined
in
regulations,
the
EPA's
narrow
interpretation
is
consistent
with
the
plain
language
of
the
regulation."
Recent
court
decisions
have
also
emphasized
that
a
narrow
interpretation
of
the
RMRR
exclusion
is
necessary
in
order
to
ensure
that
the
NSR
program
is
properly
administered.

Commenters
1241
and
1437
said
section
193
of
the
CAA
would
be
violated
under
the
proposal
because
it
would
allow
backsliding.
Commenter
1437
said
section
193
prohibits
modifications
to
pre­
1990
regulations
for
nonattainment
areas,
"
unless
the
modification
insures
equivalent
or
greater
emission
reductions"
as
the
existing
regulations.
Nothing
in
the
proposed
rule
ensures
that
facilities
will
not
take
advantage
of
the
optional
nature
of
the
rule
to
calculate
which
version
(
proposed
vs.
existing)
will
allow
it
to
operate
with
the
least
restrictions.
Nothing
in
the
proposed
rule
ensures
that
this
will
not
result
in
unlawful
backsliding.
Also,
both
of
the
new
exclusions
are
in
addition
to
and
not
in
place
of
the
existing
definition.
Every
activity
that
was
exempt
from
NSR
previously
remains
exempt.
All
activities
within
the
annual
allowance
are
now
exempt
in
addition
to
those
previously
exempt
activities.
The
result
is
unlawful
backsliding.

Commenter
1241
added
that,
in
addition
to
ensuring
emissions
reductions,
section
193
serves
to
ensure
the
CAA
is
a
technology­
forcing
statute
by
prohibiting
sources
from
taking
into
consideration
technology
or
economics
in
meeting
their
requirements
and
holding
sources
to
stricter
emission
limitations,
not
more
relaxed
requirements,
as
time
goes
on
and
air
pollution
3
­
Equipment
Replacement
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and
Deliberative
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6,
2003
Do
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or
distribute
3­
14
control
technology
develops.
However,
EPA's
proposal
holds
sources
to
less
stringent
control
requirements
than
the
current
exemption
since
it
allows
sources
to
make
changes,
regardless
of
emission
consequences,
without
triggering
NSR,
which
violates
section
193.

Commenter
1443
said
EPA
lacks
authority
to
exempt
modifications
that
result
in
greater
than
de
minimis
emissions
increases
or
that
allow
"
perpetual
immunity"
from
NSR
standards.
In
Alabama
Power,
the
D.
C.
Circuit
explained
that
EPA
has
the
power
to
exempt
de
minimis
activity
from
the
PSD
requirements
based
on
the
principle
"
that
the
law
does
not
concern
itself
with
trifling
matters."
The
Court
recognized
that
"
there
is
likely
a
basis
for
an
implication
of
a
de
minimis
authority
to
provide
exemptions
when
the
burdens
of
regulation
yield
a
gain
of
trivial
or
no
value."
Moreover,
the
D.
C.
Circuit
recognized
that
"
alterations
of
almost
any
plant
occur
continuously;
whether
to
replace
depreciated
capital
goods,
to
keep
pace
with
technological
advances,
or
to
respond
to
changing
consumer
demands;"
nevertheless,
it
held
that
"
Congress
wished
to
apply
the
permit
process"
to
these
"
industrial
changes"
if
they
result
in
an
increase
in
plantwide
emissions.
Therefore,
there
is
no
authority
under
Alabama
Power
to
exempt
plant
modifications
that
result
in
non­
de
minimis
increases
or
that
allow
"
perpetual
immunity"
from
NSR
standards.

3.2.3.3
Support
for
ERP
Approach
Some
commenters
provided
reasons
for
their
assertion
that
the
ERP
approach
is
clearly
legal
(
1078,
1124/
1515,
1131,
1138,
1202,
1988).


The
new
equipment
replacement
test
would
encourage
projects
that
are
"
routine"
within
standard
dictionary
meanings
of
the
word
("
customary,
standard,
and
usual"),
which
is
sufficient
to
justify
EPA's
action
(
1124/
1515,
1131,
1138,
1988).
While
"
routine"
also
can
mean
"
performed
as
part
of
a
routine,
unvarying,
mechanical"
process,
adopting
such
a
definition
would
forbid
sources
to
use
the
RMRR
exclusions
for
anything
they
had
not
done
before,
thus
turning
the
RMRR
exclusion
into
a
drag
on
innovation
and
not
an
encouragement
to
it.
This
approach
would
forbid
a
source
from
implementing
a
new
approach
to
work
safety
or
energy
conservation
without
an
NSR
review
first.
(
1138,
1515,
1988)


EPA's
proposal
to
only
grant
RMRR
status
to
projects
that
do
not
change
the
function
of
the
unit
or
increase
its
input
capacity
will
focus
the
exclusion
on
such
replacements.
In
the
landmark
International
Harvester
case
(
478
F.
2d
642
(
D.
C.
Cir.
1973),
the
D.
C.
Circuit
found
that
the
burden
of
proof
that
an
agency
imposes
on
an
applicant
for
regulatory
control
must
consider
"
the
nature
and
consequences
of
risk
or
error."
Efficiency,
safety,
reliability,
and
availability
improvement
has
many
collateral
environmental
and
human
benefits
that
a
more
ordinary
construction
project
does
not.
For
that
reason,
International
Harvester
requires
3
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3­
15
EPA's
rules
to
allow
such
changes
to
qualify
for
RMRR
status
based
on
a
lesser
showing
than
would
be
required
to
support
an
NSR
exclusion
for
a
less
beneficial
project.
The
case
addressed
requirements,
and
it
is
even
more
clear
that
EPA
has
the
discretion
to
impose
a
lesser
burden
of
proof
on
projects
with
such
collateral
environmental
benefits.
(
1124/
1515,
1131,
1138,
1988)


The
change
that
EPA
has
proposed
is
also
quite
similar
to
the
change
upheld
in
Chevron,
USA
Inc.
v.
NRDC,
467
U.
S.
843
(
1984)
and
should
be
affirmed
for
the
same
reason.
Chevron
addressed
EPA's
rule
amendment
to
exempt
sources
with
unit­
level
emissions
increases
from
NSR
if
they
reduced
emissions
elsewhere
in
the
source
by
enough
to
avoid
a
significant
source­
wide
emissions
increase.
In
making
this
change,
EPA
changed
its
applicability
rules
to
reduce
the
number
of
new
and
modified
units
that
would
be
subjected
to
NSR.
The
Supreme
Court
upheld
this
deregulatory
step
as
a
proper
exercise
of
EPA
discretion.
It
found
that
Congress
had
given
EPA
the
power
to
balance
between
the
goal
of
clean
air
and
the
goal
of
a
healthy
economy
when
setting
regulations.
EPA's
ERP
is
exactly
parallel
to
the
change
at
issue
in
Chevron
in
that
it
is
a
reduction
of
the
scope
of
NSR
that
EPA
can
reasonably
conclude
will
benefit
both
the
economy
and
the
environment.
(
1124/
1515,
1131,
1138,
1988)


The
proposed
ERP
is
simply
a
clarification
of
the
"
replacement
portion"
of
the
RMRR
test.
At
the
time
Congress
adopted
the
definition
of
"
modification"
from
the
NSPS
program
for
purposes
of
the
PSD
program
in
1977,
EPA's
regulations
provided
that
"[
m]
aintenance,
repair,
and
replacement
which
the
Administrator
determines
to
be
routine
for
a
source
category,
subject
to
the
provisions
of
paragraph
(
c)
of
this
section
and
§
60.15"
is
not
to
be
considered
a
"
change."
(
39
FR
36946,
36949)
The
proposed
ERP
simply
is
the
Administrator's
determination
that
the
replacement
of
components
with
identical
or
functionally
equivalent
components
and
that
do
not
exceed
a
certain
cost
percentage
determined
for
each
industry
sector
are
routine
for
that
sector.
(
1201,
1202)


The
functional
equivalence
test
is
legally
defensible
because,
similar
to
the
RMRR
cost
allowance,
this
safe
harbor
speaks
directly
to
the
nature,
extent,
and
purpose
elements
of
the
five­
factor
test
and
represents
an
appropriate
application
of
those
factors.
It
also
comports
well
with
the
recognition
in
WEPCO
that
like­
kind
replacements
are
less
likely
to
trigger
NSR
than
new
construction.
(
1078)

3.2.3.4
Opposition
to
ERP
Approach
Commenter
1150
objected
to
EPA's
proposal
to
use
the
NSPS
reconstruction
provision
in
the
ERP.
The
commenter
said
the
NSPS
reconstruction
provision
was
intended
to
draw
a
clear
3
­
Equipment
Replacement
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
3­
16
line
between
"
modified"
and
"
new"
facilities,
the
former
not
subject
to
NSPS
unless
there
has
been
an
emissions
rate
increase.
"
Reconstructed"
facilities,
like
new
facilities,
are
subject
to
NSPS
regardless
of
whether
emissions
from
the
plant
of
which
they
are
part
increase.
EPA's
proposal
to
use
the
NSPS
reconstruction
provision's
replacement
cost
threshold
concept
to
determine
whether
equipment
replacement
qualifies
as
RMRR
turns
the
purpose
of
the
reconstruction
provisions
on
its
head.
Whereas
the
impact
on
emissions
is
the
determinative
factor
of
whether
NSPS
is
triggered
until
the
cost
of
plant
refurbishment
or
life­
extension
project
exceeds
the
reconstruction
threshold,
in
which
case
the
NSPS
automatically
applies,
this
proposal
would
allow
a
source
to
avoid
NSR
altogether
so
long
as
the
cost
of
the
plant
refurbishment
or
life
extension
project
does
not
reach
the
threshold,
regardless
of
the
impact
the
change
may
have
on
emissions.
Morever,
since
equipment
replacement
would
not
constitute
a
"
physical
change"
and
therefore
would
not
be
considered
a
modification
until
it
crossed
the
cost
threshold,
EPA
would
still
allow
a
project
to
qualify
as
RMRR
once
it
crossed
the
threshold
and
to
avoid
NSR,
under
the
case­
by­
case
test.
The
commenter
concluded
the
proposal
would
foster
the
very
circumvention
of
the
law
that
EPA
was
striving
to
prevent
when
it
adopted
the
NSPS
reconstruction
provisions.
The
commenter
added
that
maintaining
the
unit's
basic
design
parameters
would
offer
no
safeguard
to
ensure
the
statutory
purpose
of
the
NSR
program.

Response:

The
final
rule
is
designed
to
allow
you
to
engage
in
activities
that
facilitate
the
safe,
reliable
and
efficient
operation
of
your
source.
We
believe
that
the
final
rule
improves
the
major
NSR
program
by
providing
you
with
additional
certainty
as
to
what
activities
qualify
as
"
routine"
equipment
replacements
under
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
as
routine
under
the
ERP,
it
will
be
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
also
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
rule
is
consistent
with
the
central
purpose
of
the
CAA,
"
to
protect
and
enhance
the
quality
of
the
Nation's
air
resources
so
as
to
promote
the
public
health
and
welfare
and
the
productive
capacity
of
its
population."
CAA
section
101.

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
3
­
Equipment
Replacement
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
3­
17
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
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
alifetime
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,
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,
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
3
­
Equipment
Replacement
4
As
discussed
below,
our
regulations
provided
a
comparable
exclusion
from
NSPS
at
the
time
of
the
1977
Amendments
that
established
the
NSR
program.

Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
3­
18
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
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.
4
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.
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
pre­
existing
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
3
­
Equipment
Replacement
5
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.

Internal
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August
6,
2003
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cite,
copy,
or
distribute
3­
19
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
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
"
likekind
replacement
of
the
kind
addressed
by
the
final
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
enforcement­
related
cases,
we
have
previously
interpreted
"
change"
such
that
all
changes,
even
trivial
ones,
are
encompassed
by
the
Act,
and
thus
we
generally
interpreted
the
exclusion
as
being
limited
to
de
minimis
circumstances.
However,
EPA
does
have
the
authority
to
interpret
these
key
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.
5
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,"
3
­
Equipment
Replacement
6
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.

Internal
and
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Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
3­
20
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.
6
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
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.
3
­
Equipment
Replacement
Internal
and
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Draft
August
6,
2003
Do
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quote,
cite,
copy,
or
distribute
3­
21
Some
commenters
argued
that,
to
further
the
purposes
of
the
statute,
any
interpretation
must
result
in
the
eventual
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
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
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
3
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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
as
much
flexibility
as
possible
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
effectively
limit
emissions
from
new
and
modified
sources,
it
was
not
designed
to
achieve
emission
reductions
from
every
existing
source.

Many
specific
comments
were
raised
with
respect
to
the
ERP.
These
comments
are
addressed
in
the
following
sections.

3.3
Basic
Approach
for
Equipment
Replacement
Option
We
solicited
comment
on
whether
the
ERP
should
be
implemented
on
a
component­
bycomponent
basis
or
on
some
other
reasoned
basis,
such
as
applying
the
percentage
to
components
that
are
replaced
collectively
over
a
fixed
period
of
time.

3.3.1
Support
Proposed
Option
of
Applying
Percentage
on
a
Component
Basis
Numerous
industry
commenters
supported
an
ERP
cost
threshold
on
a
component­
bycomponent
basis,
as
opposed
to
supporting
application
of
the
threshold
to
an
aggregation
of
(
not
necessarily
related)
replacement
activity
costs
over
a
fixed
time
period
(
902,
951,
1050,
1082,
1088,
1096,
1098,
1124,
1129,
1131,
1133,
1134,
1136,
1138,
1159,
1160,
1213,
1245,
1368,
1443,
1446,
1612,
1793,
1794,
1797,
1988).

It
should
be
noted
that
many
of
the
above­
enumerated
commenters
actually
expressed
their
support
in
terms
of
a
"
project­
by­
project"
basis,
noting
similarity
to
the
NSPS
reconstruction
test.
We
generally
grouped
together
comments
supporting
either
a
"
component­
by­
component"
or
"
project­
by­
project"
basis,
where
it
was
apparent
that
the
commenters
were
not
in
support
of
aggregating
costs
of
(
not
necessarily
related)
activities
over
a
fixed
period
of
time.
The
meaning
of
certain
comments
is
ambiguous,
given
the
different
terms
and
commenters'
different
interpretations
of
the
comparison
to
the
NSPS
reconstruction
test,
and
so
in
some
cases
we
grouped
comments
by
relying
on
the
context
in
which
they
were
made.
Therefore,
some
comments
supporting
a
project­
by­
project
basis
in
which
it
was
clear
by
the
context
that
the
commenter
was
referring
to
a
continuous
project
without
limitation
to
a
specific
period
of
time
appear
in
section
3.3.3
(
support
for
other
approach).
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One
industry
commenter
(
1129)
felt
the
need
to
add
that
their
support
on
a
componentby
component
basis
was
based
on
their
assumption
that
the
term
"
component"
meant
a
complete
piece
of
equipment.
Another
industry
commenter
(
902)
strongly
supported
the
ERP
if
applied
on
a
component­
by­
component
basis
or
on
the
basis
of
aggregating
activities
on
a
project
level,
as
opposed
to
over
a
one­
year
time
period.

Two
of
the
industry
commenters
(
1082,
1797)
noted
that
the
different
components
of
an
electric
generating
unit
can
clearly
be
identified
and
include
such
equipment
as
economizers,
reheaters,
condensers,
waterwall
tubes,
and
feedwater
heaters.
These
commenters
believed
applying
the
ERP
on
a
component­
by­
component
basis
would
be
easiest
to
administer
and
would
offer
fewer
opportunities
to
manipulate
the
regulations.
For
example,
if
the
ERP
were
applied
to
all
replacements
taking
place
within
a
set
period
of
time
(
such
as
one
year),
a
company
could
simply
spread
its
replacement
projects
out
over
a
longer
time
period
to
avoid
the
cost
restriction.

One
industry
commenter
(
1129)
believed
that
applying
the
percentage
to
components
that
are
replaced
collectively
over
a
fixed
period
of
time
would
only
further
complicate
the
NSR
program
and
would
create
an
administrative
nightmare.

One
electric
industry
commenter
(
951)
stated
that
related
projects
should
be
combined
for
evaluation
in
some
cases
but
unrelated
projects
should
not
be
combined,
even
if
undertaken
in
the
same
outage.

One
industry
commenter
(
1136)
opposed
aggregation
of
costs
over
any
period
of
time
because
of
the
potential
for
burdensome
recordkeeping
requirements.
The
commenter
believed
that
the
performance
specification
safeguard
is
adequate
and
no
aggregation
of
costs
would
then
be
necessary.
The
commenter
did
not
believe
that
EPA's
concern
about
disaggregating
projects
was
realistic,
because
the
utility
industry
would
not
remove
a
generating
unit
from
service
multiple
times
simply
to
disaggregate
projects.

One
industry
commenter
(
1443)
believed
that
the
more
activities
are
aggregated
together
for
a
cost
determination,
the
more
potential
would
exist
for
abuse
and
enforcement
problems.

One
industry
commenter
(
1160)
said
it
would
seem
logical
and
appropriate
to
aggregate
equipment
replacement
costs
if
multiple
pieces
of
equipment
are
replaced
as
part
of
the
same
project.
For
that
reason,
the
commenter
supports
a
component­
by­
component
basis.

One
State/
local
commenter
(
1268)
supported
a
component­
by­
component
basis
for
the
ERP
in
that
they
want
it
to
apply
to
components
rather
than
to
entire
pieces
of
emitting
equipment
or
emissions
units.
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One
industry
commenter
(
1794)
stated
that
it
has
always
been
recognized
under
NSPS
that
the
50­
percent
threshold
applied
to
one­
time
expenditures
to
repair
a
piece
of
equipment
or
component
of
a
process,
and
not
to
a
summation
of
costs
of
repairs
which
occurs
over
an
extended
period
of
time.

3.3.2
Support
for
Applying
Percentage
to
Components
Replaced
Collectively
Over
a
Fixed
Period
of
Time
One
industry
commenter
(
1077)
supported
an
annual
period
for
the
equipment
replacement
option.
The
commenter
believed
component­
by­
component
cost
tracking
would
be
difficult.

3.3.3
Support
for
Other
Approach
While
it
was
not
strictly
within
the
intent
of
our
solicitation,
some
industry
commenters
(
920,
921,
1001,
1201,
1202)
expressed
support
of
a
project
basis
(
without
limitation
to
a
fixed
period
of
time)
as
opposed
to
a
component
basis.
Two
industry
commenters
(
920,
921)
based
their
support
of
a
project
basis
on
an
interpretation
that
the
NSPS
regulations
allow
a
project
to
extend
over
a
period
of
time.
They
provided
the
example
of
a
superheater
replacement
project
spread
over
a
period
of
3
years,
with
one
third
of
the
replacement
accomplished
in
each
year.
Citing
this
example,
the
commenters
stated
that
they
did
not
support
the
concept
of
applying
a
percentage
on
a
component­
by­
component
basis,
because
the
component­
by­
component
approach
would
increase
the
work
effort
as
well
as
resulting
in
frequent
requests
to
the
reviewing
agency
for
approvals.

One
industry
commenter
(
1346)
supported
a
process
unit
basis
as
opposed
to
a
component
basis.
They
support
a
process
unit
basis
over
a
component
basis
for
the
reason
that
in
situations
where
components
are
small
in
cost
and
size
they
believe
the
component
would
very
rarely
qualify
because
the
source
would
always
fail
the
fifty­
percent
(
50%)
test.

One
industry
commenter
(
1000)
suggested
that
if
the
final
regulation
provides
a
"
budget"
for
equipment
replacement,
the
budget
should
not
be
applied
on
either
a
component­
bycomponent
basis
or
an
approach
related
to
"
components
that
are
replaced
collectively
over
a
fixed
period
of
time."
The
commenter
believed
that
whatever
approach
is
selected
should
allow
the
budget
sufficient
flexibility
to
reflect
unusually
maintenance­
intensive
situations,
such
as
for
bagasse­
fired
boilers.

Response:

In
the
proposal,
we
solicited
comment
on
whether
implementing
the
ERP
on
a
component­
by­
component
basis
or
on
some
other
reasoned
basis,
such
as
applying
the
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25
percentage
to
components
that
are
replaced
collectively
over
a
fixed
period
of
time,
may
be
more
workable.

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
instance,
based
on
an
assessment
only
of
the
parts
of
a
facility
involved
in
the
activity.
Prospectively,
a
per­
activity
basis
works
well
with
this
approach.
We
are
not
going
final
with
a
component­
by­
component
approach.

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
the
final
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.
We
have
rejected
aggregation
based
on
replacement
activities
which
are
largely
unrelated,
but
which
occur
during
the
same
equipment
outage,
such
as
replacement
of
turbine
seals
and
replacement
of
superheater
tubing
sections.
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.

3.4
Definition
of
Process
Unit
Comment:

3.4.1
General
Definition
Several
industry
commenters
(
841,
896,
902,
951,
1050,
1066,
1078,
1083,
1090,
1091,
1096,
1100,
1124,
1132,
1138,
1159,
1212,
1292,
1465,
1866),
a
State/
local
commenter
(
1240),
and
a
Federal
commenter
(
1101)
supported
the
proposed
general
definition
of
"
process
unit,"
to
apply
to
the
equipment
replacement
cost
percentage.
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One
industry
commenter
(
1105)
urged
EPA
to
allow
flexibility
in
defining
"
plant,"
in
order
to
suit
the
specific
facility
and
owner
circumstances.

Several
State/
local
commenters
(
1199,
1268,
1361,
1471)
said
the
proposed
definition
is
too
vague
or
broad.
One
State/
local
commenter
(
1206)
said
the
process
unit
definition
is
inherently
inconsistent.
Another
State/
local
commenter
(
1361)
added
that
the
proposed
definition
is
inconsistent
with
title
V
of
the
CAA.
Another
State/
local
commenter
(
1199)
urged
EPA
to
change
the
definition
of
process
unit
to
limit
the
scope
of
what
is
allowed
in
the
replacement
provision,
so
that
the
source
of
emissions
(
for
example,
an
entire
coal
boiler)
would
not
be
allowed
to
be
replaced
without
NSR.
The
replacement
unit's
scope
should
be
limited
to
an
emission
unit.

One
industry
commenter
(
1160)
found
two
objections
to
the
proposed
definition:
(
1)
It
is
unnecessarily
complicated
to
use
a
different
definition
than
that
which
serves
as
the
basis
for
the
maintenance
allowance,
and
for
the
NSR
source
definition
as
a
whole;
and
(
2)
allocating
shared
components
and
shared
capacity
would
not
work
well.
For
these
reasons,
the
commenter
recommends
using
the
entire
facility
as
the
basis
for
determining
replacement
costs.

As
an
alternative
to
the
proposed
definition
of
process
unit,
one
industry
commenter
(
1238)
suggested
that
"
process
unit"
be
defined
as
"
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product."

One
industry
commenter
(
1124)
supported
the
process
unit
definition
on
the
condition
that
if
NSR
is
triggered
through
it,
it
would
be
on
an
emissions
unit
basis.

Five
industry
commenters
(
1110,
1124,
1132,
1202,
1866)
compared
the
RMRR
proposal's
definition
of
"
process
unit"
(
toward
producing
or
storing
a
completed
product)
to
the
definition
that
is
used
by
section
112(
g)
and
that
appears
in
40
CFR
63.41
(
toward
producing
or
storing
an
intermediate
or
final
product).
One
of
the
industry
commenters
(
1866)
supports
the
more
narrow
proposed
definition.
Two
industry
commenters
(
1124,
1202)
said
the
RMRR
rule's
definition
should
be
consistent
with
that
used
by
section
112(
g),
broad
enough
to
encompass
interrelated
operations.
While
supporting
the
RMRR
proposal's
definition,
two
industry
commenters
(
1110,
1132)
recommended
that
EPA
provide
regulatory
flexibility
by
allowing
a
facility
the
option
to
choose
which
definition
they
will
use.

Two
industry
commenters
(
841,
1090)
believed
the
definition
of
"
process
unit"
is
sufficient
for
a
determination
without
encumbering
the
rule
with
an
exhaustive,
but
inevitably
incomplete,
list
of
process
units
throughout
the
industrial
sector.
Listing
units
may
confuse
rather
than
clarify.
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One
industry
commenter
(
1100)
generally
supported
the
proposed
definition
of
"
process
unit"
ERP,
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
industry
commenters
(
1129,
1204,
1346)
asserted
that
pollution
control
equipment
should
be
included
in
the
process
unit
definition.
One
industry
commenter
(
1346)
said
pollution
control
equipment
is
often
integral
to
the
process
and
may
produce
an
intermediate
product.
One
environmental
commenter
(
1150)
believed
the
proposed
rule
was
unclear
as
to
whether
pollution
control
equipment
is
part
of
the
process
unit.

3.4.2
Definition
Applied
to
Specific
Industry
Categories
One
industry
commenter
(
1137)
said
some
of
the
examples
that
are
intended
to
illuminate
what
a
process
unit
is
(
that
is,
the
industry
category­
specific
definitions)
need
to
be
revised
or
eliminated.

One
State/
local
commenter
(
1268)
said
the
definition
for
pulp
and
paper
mills
is
incorrect.
One
industry
commenter
(
1465)
did
not
support
the
detailed
process
unit
definition
for
pulp
and
paper
mills
because
the
definition
does
not,
and
cannot,
capture
all
possible
elements
and
configurations.
This
commenter
said
the
general
process
unit
definition
was
sufficient.

One
commenter
(
1124)
supported
the
definition
of
a
refinery
process
unit.

Two
industry
commenters
(
1138,
1212)
provided
a
detailed
description
and
figures
illustrating
a
natural
gas
compressor
station,
and
the
commenters
said
each
compressor
system,
together
with
its
proportionate
share
of
common
support
equipment,
would
logically
be
considered
a
separate
process
unit.
Each
engine/
compressor
system
operates
independently.
Another
industry
commenter
(
1367)
said
the
proposed
definition
for
natural
gas
pipeline
compressor
stations
needed
more
clarification,
or
uncertainty
regarding
the
scope
and
application
of
the
equipment
replacement
exclusion
would
remain.
This
commenter
explained
that
for
the
midstream
segment
of
this
industry,
where
internal
combustion
engines
operate
as
components
of
compressor
skid
assemblies,
and
such
assemblies
can
operate
alone
or
in
series,
the
final
rule
should
include
a
narrative
description
of
the
natural
gas
compression
process
unit
and
cited
40
CFR
52.21(
b)(
56)(
ii).
This
industry
commenter
(
1367)
and
another
industry
commenter
(
1096)
offered
the
following
clarification:
"
For
facilities
operating
in
the
midstream
segment
of
the
natural
gas
industry,
the
compression
process
unit
consists
of
those
portions
of
a
natural
gas
compressor
station,
natural
as
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.
Like­
kind
and
functionally
equivalent
replacement
of
equipment
(
including,
but
not
limited
to,
internal
combustion
engines)
within
the
compression
process
shall
qualify
as
RMRR."
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Six
industry
commenters
(
902,
1082,
1129,
1368,
1399,
1629,
1794)
supported
the
EPA's
definition
of
process
unit
for
a
steam
electric
generating
facility.
One
industry
commenter
(
1629)
recommended
expanding
the
definition
to
include
pumps,
fans,
cooling
tower,
and
raw
water
and
wastewater
treatment
systems.
Another
industry
commenter
(
1794)
stated
that
it
was
important
not
to
exclude
components
which
serve
a
dual
purpose,
such
as
low­
NOx
burners.
Referring
to
the
description
for
pulverized
coal­
fired
facilities,
one
industry
commenter
(
1129)
said
the
ash
handling
equipment
should
be
added
and
also
said
EPA
should
also
clarify
that
administrative
buildings
(
including
warehousing)
are
not
included
in
the
process
unit.
Two
industry
commenters
(
902,
1082)
said
equipment
that
does
not
contribute
to
the
production
of
electricity
should
be
excluded
from
the
definition
of
process
unit.
The
commenter
gave
the
examples
of
water
intake
systems,
cooling
water
towers,
transformers
and
other
downstream
electrical
equipment.

One
industry
commenter
(
1126)
said
the
definition
of
"
process
unit"
for
the
utility
industry
should
be
expanded
to
include
the
coal
handling
system,
boiler,
turbine,
stack,
and
generator,
as
well
as
emission
control
equipment.

One
industry
commenter
(
1204)
said
the
incinerator
process
unit
definition
should
include
pollution
control
equipment,
because
the
pollution
control
equipment
is,
like
refuse
pits,
steam
generators,
and
fans,
integral
to
the
unit
operation
at
waste­
to­
energy
facilities.

One
industry
commenter
(
1238)
said
the
process
unit
for
tire
manufacturing
facilities
should
be
the
entire
plant,
just
like
EPA
appears
to
consider
a
cement
plant
to
be
a
single
process
unit.

For
the
flat
glass
industry,
an
industry
commenter
(
1066)
provided
a
description
of
the
equipment
necessary
to
produce
a
finished
primary
glass
product
and
said
each
production
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.

Fiberglass
production
was
described
by
an
industry
commenter
(
1066).
Fiberglass
production
is
completed
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
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directly
cut
or
packaged
or
wound
onto
spools
for
packaging
for
sale
to
customers
or
for
additional
later
processing.

An
industry
commenter
(
1066)
said
a
process
unit
for
production
of
precipitated
amorphous
silica
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.

Two
industry
commenters
(
1066,
1110)
suggested
a
definition
of
a
complex
chemical
manufacturing
process
unit.
The
definition
of
a
chemical
manufacturing
process
unit
could
be
modeled
after
the
definition
of
a
process
unit
in
the
Hazardous
Organics
NESHAP,
suggested
one
industry
commenter
(
1066).
A
chemical
manufacturing
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
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.
One
industry
commenter
(
1110)
commented
that
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
byproduct
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.

The
definition
of
a
process
unit
in
coatings
manufacturing
could
be
modeled
after
the
Miscellaneous
Organics
NESHAP,
suggested
an
industry
commenter
(
1066).
A
coatings
manufacturing
process
would
include
all
equipment
that
collectively
functions
to
product
a
product
or
isolated
intermediate.
It
consists
of
one
or
more
unit
operations.
A
coatings
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.
Nondedicated
solvent
recovery
operations
located
within
a
contiguous
area
within
the
affected
source
are
considered
a
single
process.
A
storage
tank
that
is
used
to
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accumulate
used
solvent
from
multiple
batches
of
a
single
process
for
purposes
of
solvent
recovery
does
not
represent
the
end
of
the
process.
Nondedicated
formulation
operations
(
not
including
mixing,
as
defined)
occurring
within
a
contiguous
area
are
considered
a
single
process
that
is
used
to
formulate
numerous
materials
and/
or
products.

Several
sugar
industry
commenters
(
920,
921,
1123)
gave
two
possible
definitions
of
process
unit
for
their
industry.
These
commenters
(
920,
921,
1123)
emphasized
that
the
process
unit
should
cover
all
of
the
regulated
air
emission
points
at
the
plant.


For
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.


For
a
sugar
mill,
the
process
unit
would
consist
of
all
regulated
air
emission
sources
at
the
plant.
Excluded
air
emission
sources
are
all
unregulated
and
insignificant
emission
units
as
identified
in
the
facility's
title
V
operating
permit.

One
industry
commenter
(
840)
said
underground
mining
equipment
should
be
excluded
from
the
industry­
specific
lists
of
process
units
because
it
contributes
very
little
to
ambient
air
emissions,
is
heavily
regulated
with
regard
to
respirable
dust,
and
is
a
separate
process
unit.

One
industry
commenter
(
1129)
agreed
with
EPA's
proposal
to
proportionately
allocate,
based
on
capacity,
those
components
shared
by
two
or
more
process
units.
For
electric
utilities,
another
industry
commenter
(
1136)
supported
allocating
the
cost
of
shared
equipment
based
on
a
pro
rata
share
of
megawatts
produced.

One
industry
commenter
(
840)
believed
underground
mining
equipment
should
be
exempt
from
NSR,
because
it
contributes
very
little
to
ambient
air
emissions,
is
heavily
regulated
by
MSHA
with
regard
to
respirable
dust,
and
is
a
separate
process
unit
that
provides
ore
to
this
commenter's
entire
facility
(
six
surface
process
units).

Response:

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
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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.
The
examples
were
drawn
from
five
selected
industry
categories
 
electric
utilities,
refineries,
cement
manufacturers,
pulp
and
paper
producers,
and
incinerators.

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,
which
means
that
our
proposed
definition
must
altered
for
the
final
rule
to
include
those
processes
that
produce
"
intermediates."
We
acknowledge
that
the
term
"
intermediates"
is
susceptible
to
misinterpretation,
which
can
cause
confusion
and
lead
to
less
regulatory
certainty.
There
is
no
intention
for
this
rule
to
impart
any
regulatory
significance
to
informal
uses
of
the
term
"
intermediate."
By
"
intermediates,"
we
mean
a
recognizable
product
of
facility
operations.
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
block
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
completed
product,
and
those
operations
that
produce
a
recognizable
intermediate
product.

We
disagree
with
the
commenters
who
wish
to
include
pollution
control
equipment
in
the
definition.
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
replacement
of
pollution
control
equipment
may
lead
to
emissions
increases,
you
will
either
undergo
major
NSR
for
your
increases
or
you
may
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
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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
both
cases,
these
pieces
of
control
equipment
are
integral
to
the
process
and,
thus,
should
be
included
as
part
of
the
process
unit.
We
are
also
clarifying
in
the
final
rule
that
administrative
buildings
(
including
warehousing)
are
not
to
be
included
in
the
process
unit,
but
other
types
of
nonemitting
units
that
are
integral
to
the
processing
equipment
should
be
included.

We
also
have
included
in
our
final
rule
industry­
specific
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
cognizant
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
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
a
version
of
these
examples
in
the
final
rule
to
make
sure
sources
have
a
benchmark
against
which
they
can
evaluate
with
greater
confidence
whether
a
particular
replacement
comes
within
the
ERP.
We
are
not
planning
to
finalize
examples
provided
by
other
industries
at
this
time,
given
that
we
would
have
to
propose
them
first,
as
we
did
for
the
three
industry­
specific
process
unit
definitions
being
finalized
today.
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
as
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
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.
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°
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
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
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
unit.
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Nondedicated
solvent
recovery
operations
located
within
a
contiguous
area
within
the
affected
source
are
considered
a
single
process
unit.
A
storage
tank
that
is
used
to
accumulate
used
solvent
from
multiple
batches
of
a
single
process
for
purposes
of
solvent
recovery
does
not
represent
the
end
of
the
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
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
also
decided
to
continue
to
require
that
owners
or
operators
who
have
parts
shared
by
two
or
more
process
units
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.

3.5
Fixed
Capital
Cost
Percentage
Comment:

3.5.1
General
Support
for
Proposal
Many
industry
commenters
(
636,
840,
841,
865,
896,
900,
902,
910,
941,
942,
951,
1013,
1050,
1066,
1077,
1078,
1079,
1082,
1083,
1091,
1096,
1099,
1105,
1110,
1129,
1132,
1133,
1136,
1138,
1149,
1201,
1202,
1204,
1237,
1238,
1246,
1265,
1292,
1301,
1368,
1441,
1446,
1453,
1463,
1465,
1620,
1629,
1792,
1793,
1794,
1799,
1866)
supported
the
proposed
threshold
of
50
percent
of
replacement
cost
as
the
upper
limit
on
equipment
replacement.
Two
university
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commenters
(
901,
1477)
and
a
legislative
commenter
(
1411)
also
supported
this
50­
percent
cutoff.

One
industry
commenter
(
1129)
said
the
proposal
is
consistent
with
existing
regulatory
requirements
and
would
accord
the
flexibility
originally
intended
under
the
CAA
for
routine
maintenance
projects,
while
at
the
same
time
assuring
that
major,
non­
routine
projects
remain
subject
to
NSR
applicability
review.
Another
industry
commenter
(
1066)
believed
the
proposed
approach
is
consistent
with
a
commonsense
interpretation
of
the
regulations
and
is
undoubtedly
how
many
have
already
interpreted
the
requirements.

Several
industry
commenters
(
896,
951,
1110,
1132,
1265,
1453,
1465,
1793)
believed
a
50­
percent
cutoff
to
be
consistent
with
reconstruction
definitions
used
in
many
NSPS
and
NESHAP
regulations.
Two
industry
commenters
(
1465,
1793)
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.

One
industry
commenter
(
1866)
added
that
EPA's
concerns
about
an
unbounded
component
replacement
provision
may
be
unfounded,
because
technological
advances
and
obsolescence
make
it
unlikely
that
replacement
projects
would
eventually
replace
an
entire
source.
This
commenter
said
the
NSPS
reconstruction
test,
which
is
discussed
as
a
possible
approach
to
limit
the
ERP,
has
a
long
regulatory
history
and
seems
appropriate
for
differentiating
between
projects
that
are
routine
replacement
and
projects
that
are
tantamount
to
creating
a
new
process
unit.
Another
industry
commenter
(
951)
believed
there
is
no
reason
to
use
a
lower
cutoff.

One
industry
commenter
(
1204)
only
supported
the
50­
percent
replacement
value
threshold
if
there
are
not
mitigating
factors.
If
a
specific,
unique,
functionally
equivalent
replacement
exceeds
the
threshold,
there
should
be
an
available
regulatory
process
to
determine
the
actual
environmental
effects
of
the
change.
If
the
replacement
can
be
shown
to
have
no
impact
on
emissions
and
is
part
of
a
non­
emitting
portion
of
the
unit,
it
should
be
viewed
as
an
exempt
replacement.
Another
industry
commenter
(
1078)
said
the
50­
percent
cost
threshold
is
reasonable,
if
it
includes
only
the
cost
of
the
component
itself
and
there
is
no
aggregation
of
independent
replacements.
One
industry
commenter
(
1083)
said
a
straightforward
methodology
for
calculating
costs
is
needed.
One
industry
commenter
(
902)
made
clear
that
the
commenter's
support
of
the
50­
percent
cost
threshold
relies
on
an
assurance
that
NSR
applicability
will
not
automatically
be
triggered
when
the
capital
cost
exceeds
the
50­
percent
threshold,
as
long
as
there
is
no
increase
in
emissions
from
the
RMRR
activity.

One
industry
commenter
(
1078)
said
the
ERP
cost
threshold
test
should
be
essentially
equivalent
to
the
NSPS
reconstruction
test,
based
on
the
proposed
definition
of
process
unit.
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Two
industry
commenters
(
1082,
1797)
supported
the
50­
percent
replacement
value
threshold,
if
replacement
project
costs
are
aggregated
over
a
one­
year
period.
Another
industry
commenter
(
1446)
supported
the
50­
percent
replacement
value
threshold
if
applied
to
a
collection
of
replacement
activities.
If
instead
the
percentage
is
applied
on
a
per­
component
basis,
these
commenters
(
1082,
1446,
1797)
recommended
a
threshold
of
5
percent
for
the
electric
generating
industry.
Two
of
the
commenters
(
1082,
1446)
stated
that
the
5­
percent
threshold
is
based
on
an
evaluation
of
some
of
the
commenters'
large
routine
replacement
projects
that
electric
generating
units
undertake:
turbine
blades;
sections
of
the
waterwall
tubes;
reheaters;
superheaters;
and
economizers.

3.5.2
Opposition
to
Proposed
Replacement
Value
Threshold
Some
commenters
opposed
any
percentage;
other
commenters
believed
a
50­
percent
ERP
cost
threshold
was
too
high.

Many
State/
local
commenters
(
946,
1146,
1199,
1206,
1268,
1270,
1361,
1448,
1471,
1622),
two
industry
commenters
(
797,
898),
an
environmental
commenter
(
1150),
and
two
citizen
commenters
(
784,
850)
opposed
the
50­
percent
replacement
value
threshold.

Three
State/
local
commenters
(
1199,
1471,
1622)
believed
the
capital
replacement
percentage
should
be
much
less
than
50
percent.
One
State/
local
commenter
(
1622)
preferred
that
the
total
replacement
cost
for
a
single
process
unit
over
any
period
of
5
consecutive
years
should
not
exceed
50
percent
of
the
replacement
cost
of
the
process
unit.
One
State/
local
commenter
(
1270)
said
the
replacement
percentage
should
not
be
higher
than
25
percent.
One
State/
local
commenter
(
1146)
suggested
a
replacement
percentage
of
5
to
10
percent
if
the
ERP
moves
forward,
to
reduce
the
risk
of
replacement
of
an
entire
unit
over
time
without
installation
of
BACT.
One
citizen
commenter
said
a
more
appropriate
percentage
for
electricity
producers
is
0.1
to
1.0
percent.
One
State/
local
commenter
(
1361)
said
the
threshold
should
be
5
percent,
1
percent,
or
even
less,
as
shown
by
the
Tennessee
Valley
Authority
(
TVA)
case.
One
State/
local
commenter
(
1268)
suggested
using
a
de
minimis
value,
rather
than
50
percent,
if
the
ERP
is
included
in
the
final
rule.
This
commenter
said
an
analogy
to
NSPS
reconstruction
is
misplaced,
because
NSPS
includes
an
emissions
test
as
well
as
the
cost
threshold.

One
State/
local
commenter
(
1206)
believed
the
50­
percent
number
has
no
practical
effect
in
protecting
public
health
and
the
environment,
and
the
commenter
is
not
aware
of
any
projects
that
have
exceeded
50
percent
in
cost.
Another
State/
local
commenter
(
1448)
was
concerned
that,
whatever
percentage
is
used
for
the
ERP
cost
threshold,
sources
could
abuse
the
ERP
by
either
adding
a
new
process
unit
or
replacing
an
entire
process
unit
piecemeal
over
several
years.
One
State/
local
commenter
stated
generally
that
the
cost
thresholds
were
too
permissive,
but
this
commenter
did
not
provide
any
alternatives.
3
­
Equipment
Replacement
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2003
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37
One
industry
commenter
(
898)
believed
that
EPA
did
not
establish
a
reasoned
basis
to
support
50
percent
as
the
proper
ERP
cost
threshold.
The
commenter
stated
that
EPA
should
have
used
the
WEPCO
four­
factor
test
that
considers
the
nature
and
extent,
purpose,
cost,
and
frequency
of
activities
in
order
to
establish
that
the
given
percentage
has
any
connection
to
the
concept
of
routine,
because
otherwise
the
rule
is
arbitrary
and
capricious.
The
commenter
further
added
that
if
EPA
fails
to
articulate
the
ERP
cost
threshold
(
and
to
articulate
six
other
issues
listed
by
the
commenter)
before
promulgating
RMRR
rules,
the
EPA
will
run
afoul
of
section
553
of
the
Administrative
Procedure
Act
("
APA").

While
opposed
to
the
ERP
in
general,
one
industry
commenter
(
797)
said
the
cost
threshold
for
the
ERP
should
be
as
high
a
percentage
as
possible,
so
as
not
to
promote
premature
replacement
of
equipment
that
is
repairable.

The
environmental
commenter
(
1150)
opposed
the
equipment
replacement
approach
in
general
but
added
that
if
EPA
is
to
adopt
a
cost­
based
exemption,
the
threshold
should
be
much
lower
than
50
percent.

One
citizen
commenter
(
850)
said
the
50­
percent
number
from
the
NSPS
is
archaic
and
environmentally
nonprotective.
This
commenter
suggested
that
the
ERP
cost
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.

Response:

The
purpose
of
the
cost­
based
limitation
on
the
scope
of
the
ERP
is
to
distinguish
between
those
equipment
replacement
activities
that
should
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
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
3
­
Equipment
Replacement
7In
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.

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2003
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3­
38
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.
7
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
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
replaces
portions
of
an
existing
affected
facility
that
amounts
to
half
its
capital
replacement
value,
we
believe
its
important
to
consider
on
a
case­
by­
case
basis
whether
such
replacements
constitute
construction.
It
could
be
argued
that
some
percentage
lower
than
the
50­
percent
reconstruction
threshold
might
be
suitable
in
requiring
consideration
of
the
question
whether
equipment
replacements
constitute
a
modification
of
an
existing
process
unit.
We
solicited
comments
on
the
appropriate
level
of
any
percentage.

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
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
3
­
Equipment
Replacement
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39
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
key
factor
in
choosing
an
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
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
the
final
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
the
final
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
the
final
definition
of
steam
electric
generating
facility,
we
would
likely
treat
each
boiler
unit
as
belonging
to
a
3
­
Equipment
Replacement
8
Using
the
Chemical
Engineering
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.
This
cost
index
is
found
in
Chemical
Engineering
magazine.

Internal
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3­
40
different
process
unit.
However,
since
all
of
the
boilers
underwent
similar
renovations,
for
simplicity
we
can
assume
that
all
of
the
process
unit­
specific
activity
costs
are
equivalent.

Using
1991
dollars,
consistent
with
the
timeframe
of
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.
8
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
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
percentages
we
are
adopting
today
certainly
does
not
run
afoul
of
the
limits
established
in
WEPCO.

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
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
3
­
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41
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
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
source­
wide,
5­
percent
maintenance
allowance.
For
the
reasons
explained
above,
to
the
extent
the
projects
addressed
by
ALA
constitute
identical
or
functionally
equivalent
replacements,
we
now
believe
that
such
projects
should
be
encouraged
because
they
maintain,
facilitate,
restore
or
improve
the
safety,
reliability,
availability,
or
efficiency
of
the
process
unit.
Therefore,
we
believe
such
projects
should
qualify
for
the
ERP
in
the
future.

Comment:

3.5.3
Whether
to
Set
Different
Fixed
Capital
Cost
Percentages
for
Different
Industry
Sectors
Several
sugar
industry
commenters
(
920,
921,
1123)
believed
an
ERP
cost
threshold
of
50
percent
could
be
appropriate
but
preferred
that
EPA
establish
industry­
specific
thresholds.
However,
these
commenters
stated
that
they
did
not
have
adequate
data
to
suggest
a
specific
percentage
for
their
industry.

One
State/
local
commenter
(
1270)
suggested
that
industry­
specific
considerations
should
be
taken
into
account
in
setting
the
cost
threshold.

Two
industry
commenters
(
1110,
1132)
favored
applying
the
50­
percent
cutoff
to
all
industries
because
applying
other
percentages
on
an
industry­
or
process­
type
basis
would
unnecessarily
complicate
the
replacement
analysis.
3
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2003
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or
distribute
3­
42
One
industry
commenter
(
897)
said
the
appropriate
threshold
percentages
should
be
based
on
industrial
standards
but
added
that
a
facility
with
special
circumstances
should
have
the
regulatory
means
to
request
an
alternate
method
of
calculating
this
threshold.

3.5.4
Information
Provided
on
RMRR
Activities
and
Costs
in
Specific
Industry
Sectors
For
natural
gas
transmission,
one
industry
commenter
(
1138)
performed
an
analysis
of
maintenance
and
repair
costs
at
eighteen
compressor
stations
under
the
proposed
ERP
framework
(
see
pp.
11­
14,
51­
52).
This
commenter's
analysis
concluded
that
the
proposed
50­
percent
cost
threshold
on
a
process
unit
basis
is
appropriate
for
the
natural
gas
transport
industry,
if
replacement
of
non­
emitting
units
and
catastrophically
failed
units
is
excluded.
Two
natural
gas
industry
commenters
(
1096,
1138)
asserted
that
the
rule
should
encourage
the
practice
of
offsite
maintenance.
Both
offsite
and
onsite
maintenance
should
be
counted
against
the
50­
percent
cost
threshold.
One
of
the
industry
commenters
(
1138)
explained
that
the
gas
turbines
(
internal
combustion
engines)
used
at
natural
gas
compressor
stations
have
been
designed
for
offsite
maintenance
and
often
cannot
be
cost
effectively
maintained
onsite.
Instead,
the
manufacturer
"
changes
out"
the
turbine
by
removing
the
components
in
need
of
maintenance
(
typically
the
gas
producer
and
power
train)
and
replaces
them
with
components
from
the
manufacturer's
inventory.
Such
change­
outs
take
place
every
30,000
to
50,000
hours
of
turbine
operation,
or
every
3
to
5
years.
The
national
pipeline
industry
undertakes
several
hundred
turbine
change­
outs
per
year.
A
change­
out
takes
2
days,
where
onsite
maintenance
of
a
turbine
would
take
6
weeks
and
would
also
increase
the
overall
cost
of
gas
transmission
by
increasing
the
need
for
backup
compressor
capacity.
Further,
offsite
maintenance
allows
for
verification
in
test
cells
that
the
changed­
out
turbine
components
meet
emission
standards
before
they
are
returned
to
the
fleet.

Several
sugar
industry
commenters
(
920,
921,
1000,
1123)
believed
their
industry
should
have
a
higher
replacement
percentage
than
other
steam
generating
units
due
to
the
heat
and
corrosive
compounds.
The
commenters
explained
that
their
bagasse
fuel
(
from
sugar
cane)
has
a
high
sand
content,
which
is
extremely
corrosive.
Moreover,
the
boilers
are
idle
for
several
months
per
year,
at
which
time
they
are
subject
to
humidity
and
rain,
leading
to
corrosion
of
tubes,
components,
and
equipment.
One
of
these
commenters
(
1000)
noted
that
boiler
tubes,
air
heater
tubes,
superheater
tubes,
refractory,
economizer
tubes,
and
induced
fan
drafts
routinely
require
maintenance
or
partial
replacement.

The
environmental
commenter
(
1150)
asserted
that
the
total
project
expenditures
to
upgrade
each
of
the
three
boilers
at
the
Alcoa
Sandow
Betterment
Project
were
less
than
15
percent
of
the
capital
cost
of
a
new
unit.

The
environmental
commenter
(
1150)
provided
extensive
information
documenting
RMRR
costs
for
utilities,
primarily
from
various
court
cases
and
enforcement
actions.
The
3
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and
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2003
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or
distribute
3­
43
commenter
(
1150)
noted
that
the
following
were
not
considered
routine
replacement
in
court
cases:
replacement
of
cyclones;
replacement
of
lower
furnace
walls
(
including
headers
and
footers);
replacement
of
waterwall
tubes
in
front,
rear
and
sidewalls
of
both
furnaces;
replacement
of
burner
tube
panels
and
superheater
platen
elements;
replacements
with
redesigned
components.

The
environmental
commenter
(
1150)
stated
that
the
following
equipment
replacement
activities
would
not
increase
emissions
and
would
therefore
be
exempt
from
major
NSR
regardless
of
a
routine
maintenance
exemption:
replacement
of
a
pump
associated
with
a
distillation
column;
replacement
of
a
pump
associated
with
a
distillation
column;
replacement
of
worn
out
pipes
in
a
chemical
process
plant;
and
replacement
of
controllers
at
a
series
of
batch
digesters.

The
environmental
commenter
(
1150)
stated
that
by
the
year
2000,
almost
75
percent
of
power
plants
were
more
than
20
years
old.
The
commenter
noted
that
at
20­
25
years,
various
major
components
of
an
electric
generating
unit
wear
out,
a
condition
referred
to
as
"
component
end
of
life."
Absent
replacement
of
the
components,
the
decline
continues
after
20­
25
years.
The
environmental
commenter
(
1150)
cited
the
component
replacement
schedule
from
Babcock
and
Wilcox's
reference,
Steam,
Its
Generation
and
Use.

One
industry
commenter
(
1213)
has
compiled
data
from
DOE
to
produce
curves
that
an
electric
utility
owner/
operator
could
use
to
select
replacement
cost
for
a
source
based
on
size
and
fuel
type.
(
See
Document
ID
1215
in
the
docket.)
This
commenter
also
provided
a
paper
describing
major
repair
and
replacement
projects
that
are
undertaken
at
utility
generating
stations
in
order
to
keep
them
operational.
(
See
Document
ID
1221
in
the
docket.)

One
industry
commenter
(
1621)
noted
that
re­
bricking
of
ovens,
furnaces,
and
some
boilers
is
a
periodic
maintenance
requirement
that
is
necessary
to
assure
good
product
quality,
process
control,
and
fuel
efficiency.
Minor
re­
bricking
may
occur
on
a
yearly
or
bi­
yearly
basis;
major
re­
bricking
projects
may
be
required
every
10
to
15
years.

Response:

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.

We
have
determined
that
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.
3
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2003
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or
distribute
3­
44
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
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
casespecific
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
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
source­
wide,
5­
percent
maintenance
allowance.
For
the
reasons
explained
above,
to
the
extent
the
projects
addressed
by
ALA
constitute
identical
or
functionally
equivalent
replacements,
we
now
believe
that
such
projects
should
be
encouraged
because
they
maintain,
facilitate,
restore
or
improve
the
safety,
reliability,
availability,
or
efficiency
of
the
process
unit.
Therefore,
we
believe
such
projects
should
qualify
for
the
ERP
in
the
future.

3.6
Basic
Design
Parameters
Comment:

3.6.1
Generally
Supportive
Comments
3.6.1.1
EUSGUs
3
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Several
industry
commenters
(
1099,
1136,
1213,
1629,
1792)
supported
the
use
of
maximum
heat
input
and
fuel
consumption
as
the
appropriate
design
parameters
for
electric
generating
units.
One
industry
commenter
(
1629)
added
that
the
final
rule
should
clarify
that
the
correct
parameter
is
maximum
hourly
heat
input.
Two
industry
commenters
(
1099,
1213)
requested
that
EPA
provide
sufficient
flexibility
in
how
the
parameters
are
determined,
and
one
industry
commenter
(
1792)
requested
sufficient
flexibility
to
account
for
problems
that
may
have
been
corrected
to
obtain
the
true
design
rate
of
a
unit.

One
industry
commenter
(
1794)
stated
that
it
may
not
be
necessary
to
specify
both
the
heat
input
and
fuel
consumption
as
design
parameters
for
EUSGUs
because
fuel
consumption
is
essentially
duplicative
of
the
heat
input
value.
Also,
the
fuel
consumption
rate
for
coal­
fired
units
will
vary
depending
on
the
quality
of
the
coal
for
a
given
heat
input.
If
EPA
decides
to
retain
fuel
consumption
as
a
design
specification,
then
the
industry
commenter
recommended
that
the
minimum
fuel
quality
based
on
Btu
content
should
be
used
for
coal­
fired
units.

One
industry
commenter
(
1078)
stated
that
the
use
of
the
basic
design
parameters
is
a
reasonable
safeguard,
but
EPA
should
not
include
"
fuel
specifications"
for
EUSGUs.
It
is
too
vague
and
could
encompass
almost
anything.
EPA
should
either
specify
fuel
consumption
rates
(
which
is
redundant
with
maximum
heat
input),
or
fuel
type
(
such
as
coal
or
oil).

One
industry
commenter
(
1129)
said
the
primary
design
parameter
for
EUSGUs
is
the
manufacturer's
maximum
designed
steam
flow
rating
or
the
maximum
historical
steam
flow,
whichever
is
higher.

One
industry
commenter
(
1794)
recommended
that
the
final
rule
clarify
that
the
owner
can
establish
the
basic
design
for
maximum
heat
input
of
an
electric
generating
unit
by
referencing
available
credible
information,
including
results
of
historic
maximum
capability
tests,
operating
design
information,
or
engineering
calculations
which
may
establish
the
heat
input
value
the
unit
has
demonstrated
it
is
capable
of
achieving.
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
unit's
maximum
heat
input.
A
review
of
such
data
or
other
available
operational
data
or
design
information
can
reveal
the
heat
input
which
the
unit
is
capable
of
achieving
in
its
"
pre­
change"
configuration
and
this
can
be
compared
to
a
"
post­
change"
heat
input
value.
This
should
be
a
case­
by­
case
analysis
and
demonstration,
not
a
simplistic
formulaic
test.

According
to
one
industry
commenter
(
797),
replacement
of
power
turbines
and
combustion
units
is
called
for
every
30,000
to
50,000
hours
of
operation.
Unless
components
are
upgraded
during
these
replacements,
the
heat
input
remains
the
same
and
so
does
the
emissions
rate.
The
commenter
believes
that
such
replacement
should
be
considered
routine
maintenance.
3
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3­
46
3.6.1.2
Miscellaneous
general
comments
on
basic
design
parameters
Several
industry
commenters
(
951,
1066,
1096,
1099,
1112)
agreed
with
the
EPA's
use
of
maximum
heat
input
and
fuel
specifications
for
basic
design
parameters.
One
industry
commenter
(
1112)
recommended
that
EPA
provide
sufficient
flexibility
for
plant
owners
to
determine
how
basic
design
parameters
are
determined.

One
industry
commenter
(
1100)
supported
the
concept
of
using
basic
design
parameters
within
the
equipment
replacement
approach,
but
recommended
further
clarification
be
provided
for
efficiency
improvements.
The
industry
commenter
recommended
that
an
equipment
replacement
that
improves
a
process
unit's
efficiency
by
enabling
the
unit
to
return
to
its
original
design
parameters
be
considered
RMRR
even
if
current
actual
emissions
increase
as
a
result.
For
example,
if
boiler
tubes
or
refractory
are
replaced
on
a
boiler,
these
activities
should
be
RMRR
since
they
return
the
unit
to
its
original
design
parameters
and
improve
the
unit's
efficiency.

Several
industry
commenters
(
920,
921,
1000,
1123)
supported
maximum
design
heat
input
as
the
basic
design
parameter
for
boilers.
These
industry
commenters
(
920,
921,
1000,
1123)
noted
that
this
parameter
could
also
be
expressed
in
terms
of
maximum
design
steam
production
rate,
which
is
how
Florida
has
permitted
their
bagasse
boilers.

One
industry
commenter
(
1136)
supported
EPA's
use
of
the
term
"
process
unit"
to
determine
if
there
is
a
change
in
a
design
parameter.

One
industry
commenter
(
941)
said
EPA
cannot
practicably
disallow
changes
in
fuel
or
raw
material
input
specifications
for
all
complex
industrial
sources.
Even
where
manufacturer's
design
specifications
exist
for
a
unit,
they
serve
to
define
the
unit's
guaranteed
maximum
capacity
rather
than
its
actual
maximum
capacity.
Many
units
routinely
and
properly
operate
above
their
design
specifications.

3.6.1.3
Look
back
period
for
determining
basic
design
parameters
Several
industry
commenters
(
941,
1050,
1099,
1112,
1123,
1368,
1629)
recommended
that
a
reasonable
look
back
period
should
be
used
for
establishing
the
pre­
change
values
for
basic
design
parameters,
not
the
condition
of
the
process
unit
immediately
before
the
change.
The
industry
commenters
suggested
a
5­
year
look
back
period,
consistent
with
that
for
the
NSPS
hourly
emissions
increase
test.

3.6.1.4
De
minimis
changes
in
emissions
or
basic
design
parameters
One
industry
commenter
(
941)
stated
that
because
the
results
of
RMRR
are
not
always
predictable
in
advance,
the
final
rule
should
provide
that
unanticipated
and
unintended
small
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increases
in
hourly
emission
do
not
disqualify
a
project
from
the
equipment
replacement
exclusion.

Two
industry
commenter
(
858,
896)
and
one
university
commenter
(
901)
requested
that
a
de
minimis
change
in
design
parameters
be
allowed
when
making
equipment
changes
because
some
effects
resulting
from
the
change
may
not
be
apparent
before
the
change
is
made.
One
industry
commenter
(
896)
added
that
such
a
change
be
allowed
as
long
as
emissions
do
not
increase
above
maximum
design
levels.
The
university
commenter
added
that
such
a
change
be
allowed
as
long
as
emissions
do
increase
above
the
permitted
maximum
hourly
emission
rates.

3.6.1.5
Develop
basic
design
parameters
for
specific
industries
Two
industry
commenters
(
1138,
1446)
supported
the
basic
design
parameter
approach,
but
believed
that
the
definition
of
basic
design
parameter
for
non­
utilities
and
non­
fossil­
fuel
burning
sources
in
the
proposed
rule
is
too
rigid
and
is
inconsistent
with
the
natural
gas
transport
industry
conventions.
One
industry
commenter
(
1138)
urged
EPA
to
modify
the
definition
to
allow
for
industry­
specific
flexibility
or
specify
additional
source
category­
specific
parameters.
For
the
natural
gas
transmission
compressor
stations,
the
commenter
suggested
using
brake
horsepower
(
bhp)
as
the
conventional
design
capacity
parameter.
All
regulated
natural
gas
transmission
compressor
stations
maintain
consistent,
accurate,
and
certified
records
of
process
unit
bhp
capacity.

One
State/
local
commenter
(
1270)
stated
that
while
it
would
take
considerable
time
and
effort
to
develop
basic
design
parameters,
there
is
no
other
way
to
implement
the
proposed
option
since
no
two
processes
are
the
same.

3.6.2
Opposition
to
Basic
Design
Parameters
3.6.2.1
General
opposition
to
basic
design
approach
An
industrial
commenter
(
636)
noted
that
in
many
cases,
the
boiler
design
fuel
specification
is
fabricated
to
satisfy
certain
boiler
design
criteria
with
inherent
operating
latitude,
and
there
is
no
actual
fuel
which
can
meet
those
specifications.
Fuel
changes
should
not
be
considered
replacements.

One
industry
commenter
(
902)
was
strongly
opposed
to
fully
defining
specific
design
parameters
in
the
regulation
because
published
design
standards
in
the
rule
would
quickly
become
outdated,
thereby
requiring
frequent
revisions
in
the
regulation.

One
industry
commenter
(
1301)
stated
that
requiring
equipment
replacements
to
not
alter
the
basic
design
parameters
of
a
process
unit
is
a
nebulous
requirement
that
EPA
should
carefully
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consider
before
going
final.
For
the
petroleum
refining
industry,
the
commenter
was
particularly
concerned
that
the
concept
of
material
input
specifications
is
a
nominal
one
that
has
practical
value
only
in
the
design
phase
but
not
in
the
operations
phase.

One
industry
commenter
(
909)
believed
that
activities
intended
to
improve
an
affected
unit's
performance,
beyond
what
would
otherwise
be
reasonably
achieved
by
the
equipment
absent
a
specific
activity,
clearly
qualify
as
actions
that
extend
beyond
the
reasonable
definition
of
RMRR
and
should
instead
be
subject
to
the
full
scope
of
NSR.
The
commenter
further
stated
that
the
recent
revisions
to
the
NSR
regulations
(
67
FR
80186)
allow
for
reasonable
actions
to
improve
unit
performance.

One
industry
commenter
(
942)
opposed
the
basic
design
parameter
constraints,
stating
that
they
would
exclude
projects
that
result
in
efficiency
improvements.

One
State/
local
commenter
(
1012)
said
that
RMRR
should
not
be
allowed
for
changes
in
basic
design
parameters.

An
industry
commenter
(
1238)
urged
EPA
to
eliminate
the
requirement
that
the
new
equipment
not
alter
the
basic
design
parameters
of
the
unit.
The
commenter
expressed
concern
that
regulators
may
use
the
provision
to
bar
changes
that
carry
out
the
same
function
but
do
so
through
an
improved
design
from
qualifying
for
RMRR
exclusion.

3.6.2.2
Opposition
to
input
parameters;
preference
for
design
specifications
or
emission
rate
Several
industry
commenters
(
814,
941,
1013,
1114,
1133,
1204,
1237,
1463)
and
two
university
commenters
(
901,
1477)
noted
that
many
pieces
of
equipment
are
not
rated
or
specified
based
on
"
material
input"
or
"
fuel
input."
Instead,
EPA
should
also
define
"
design
specifications"
because
many
pieces
of
equipment
are
purchased
based
on
their
capacity
or
output.
Therefore,
EPA
should
rely
on
the
manufacturer's
documented
design
information
to
identifying
the
basic
design
parameters
for
any
piece
of
equipment
rather
than
attempting
to
specify
it
in
the
rule.
Several
of
the
industry
commenters
(
941,
1013,
1114,
1133,
1237)
said
that
a
determination
should
be
based
on
maximum
hourly
emissions
before
and
after
the
change,
and
one
industry
commenter
(
1463)
recommended
using
annual
emissions.
One
industry
commenter
(
941)
added
that
this
design­
based
approach
is
already
a
condition
of
the
RMRR
allowance
approach
and
has
been
used
in
other
long­
established
CAA
programs
like
NSPS.

One
industry
commenter
(
1110)
believed
that
the
proposal
suggests
that
basic
design
parameters
are
limited
to
the
maximum
fuel
or
material
input
specifications
for
non­
utility
process
units.
Another
industry
commenter
(
1132)
urged
EPA
to
remove
the
basic
design
parameter
requirements
in
light
of
other
safeguards
in
the
proposed
rule.
Both
industry
commenters
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recommended
that
an
increase
in
material
input
should
be
allowed
as
long
as
there
is
no
increase
in
emissions
above
maximum
achievable
levels.
Therefore,
the
safeguard
that
reads
"
does
not
alter
the
basic
design
parameters"
should
be
replaced
with
"
should
not
increase
the
maximum
design
emission
rate."

In
reference
to
the
cement
industry,
one
industry
commenter
(
1283)
stated
that
EPA
should
clarify
the
definition
of
basic
design
parameters.
The
current
definition
is
ambiguous
because
maximum
fuel
and
material
input
specifications
have
no
relevance
in
this
industry.
The
industry
commenter
recommended
that
maximum
clinker
generation
capacity
of
the
kiln
system
be
used
as
the
basic
design
parameter
for
the
cement
industry.

For
surface
coating
operations,
one
industry
commenter
(
1202)
stated
that
there
are
problems
with
use
of
paint
input
as
a
basic
design
parameter.
Any
replacement
of
paint
guns
could
affect
paint
usage
and
would
be
viewed
as
a
basic
design
parameter
change.
Because
maximum
input
varies
with
the
paint
type
and
characteristics,
material
input
does
not
represent
a
basic
design
parameter
for
surface
coating
operations.
The
industry
commenter
recommended
using
transfer
efficiency
and
quality
of
paint
job,
not
material
input
rates,
for
the
basic
design
parameters
for
automobile
surface
coating.

One
State/
local
commenter
(
1443)
believes
that
defining
the
term
"
basic
design
parameters"
solely
based
upon
maximum
heat
input
and
fuel
consumption
specifications,
or
maximum
material/
fuel
input
specifications,
will,
under
the
guise
of
"
replacement,"
allow
a
wide
range
of
changes
that
should
be
considered
NSR
modifications.
There
are
many
changes
at
air
emission
sources
that
do
not
alter
maximum
heat
input
and
fuel
consumption
specifications,
or
maximum
material/
fuel
input
specifications,
yet
involve
significant
modifications
that
are
unrelated
to
routine
replacement.
The
commenter
suggested
that
any
equipment
modification
resulting
in
a
change
in
the
equipment
description
in
the
permit
should
be
subject
to
NSR.

An
environmental
commenter
(
1150)
believed
the
basic
design
parameters
of
maximum
heat
input
and
fuel
consumption
are
too
narrow
and
will
be
difficult
to
administer.
The
environmental
commenter
also
believed
that
changes
in
heat
input
or
fuel
consumption
due
to
equipment
replacement
are
difficult
to
evaluate.
For
example,
some
utilities
have
claimed
that
nameplate
capacity
only
represented
the
manufacturer's
guarantee
and
not
the
maximum
capacity
of
the
unit,
thereby
justifying
an
increase
to
a
higher
heat
input
rate.
The
commenter
believed
that
many
other
basic
design
parameters
should
be
included,
but
did
not
list
these
specifically.
If
EPA
decides
to
retain
the
ERP,
the
commenter
urged
EPA
to
exclude
equipment
replacement
that
changes
the
basic
design
parameters
of
the
process
unit
or
results
in
an
increase
of
total
annual
emissions.

An
industrial
commenter
(
1134)
stated
that
for
many
industries,
it
is
difficult
to
associate
basic
design
parameters
with
either
hourly
emissions
or
input
specifications.
However,
if
EPA
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includes
a
basic
design
parameter
test
in
the
final
rule,
the
commenter
urged
EPA
to
allow
flexibility
to
plant
operators
to
establish
what
the
measure
of
performance
will
be
for
process
units,
including
the
use
of
permit
limits
on
amount
of
production.

A
State/
local
commenter
(
1199)
recommended
that
any
design
parameter
that
could
affect
actual
emissions
should
be
considered
a
basic
design
parameter
which
may
not
be
changed
without
agency
approval.

3.6.2.3
Oppose
basic
design
parameter
approach
because
functional
equivalence
is
adequate
Several
industry
commenters
(
1132,
1134,
1292,
1799,
1866,
1868)
indicated
that
the
functionally
equivalent
safeguard
is
sufficient
to
assure
that
replacement
components
cannot
be
designed
to
materially
change
the
process
unit.

Two
industry
commenters
(
1201,
1202)
stated
that
the
basic
design
parameter
test
introduces
substantial
confusion
into
the
rule
without
adding
any
additional
benefit
that
is
not
already
inherent
in
the
term
"
functionally
equivalent."
One
of
the
commenters
(
1202)
added
that
for
the
automobile
surface
finishing
industry,
the
test
would
exclude
the
precise
projects
that
the
equipment
replacement
approach
is
designed
to
cover.

An
industry
commenter
(
1079)
supported
the
concept
of
including
in
RMRR
the
replacement
of
existing
equipment
that
serves
the
same
basic
function.
However,
EPA's
proposal
that
basic
design
parameters
of
the
affected
process
units
not
be
changed
is
vague
and
subject
to
the
same
type
of
interpretive
abuses
by
regulatory
agencies
that
occur
now.
The
commenter
cites
as
an
example
of
the
impracticality
of
the
design
parameter
limitation
a
crude
oil
distillation
tower
that
may
have
several
capacities
that
are
a
function
of
the
type
of
crude
that
is
to
be
processed.
Of
particular
concern
to
this
commenter
was
EPA's
suggestion
that
changes
in
fuel
or
raw
material
input
specifications
be
prohibited,
and
recommended
an
ERP
under
which
the
exclusive
design
criterion
is
whether
a
component
is
"
identical
or
functionally
equivalent"
to
the
replaced
component.

One
industry
commenter
(
1237)
generally
opposed
the
use
of
basic
design
parameters
as
the
basis
for
evaluating
whether
equipment
replacements
are
RMRR
because
this
test
could
exclude
many
component
replacements
that
can
properly
be
deemed
functionally
equivalent.
The
commenter
urged
EPA
to
only
use
design
parameters
when
they
have
been
used
to
establish
federally
enforceable
permit
limits,
similar
to
existing
exclusions
for
changes
in
fuels
or
raw
materials
that
a
unit
is
otherwise
capable
of
accommodating.

3.6.2.4
Oppose
including
efficiency
as
a
basic
design
parameter
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Several
industry
commenters
(
902,
920,
921,
951,
1000,
1013,
1078,
1112,
1123,
1213,
1368)
said
efficiency
should
not
be
a
basic
design
parameter
to
avoid
penalizing
facilities
for
process
efficiency
enhancements.

The
industry
commenter
(
1794)
supported
EPA's
statement
that
an
improvement
in
efficiency
does
not
change
a
process
units's
basic
design
parameters.
The
industry
commenter
(
1794)
recommended
that
EPA
clarify
in
the
final
rule
that
efficiency
improvements
and
the
use
of
new
technology
are
not
considered
changes
in
design
parameters.

Two
commenters
(
1799,
1868)
believed
that
the
basic
design
parameters
safeguard
has
the
potential
to
bar
component
replacements
that
achieve
significant
gains
in
efficiency,
contrary
to
EPA's
stated
intent.

One
industry
commenter
(
1793)
supported
EPA's
exclusion
of
efficiency
as
a
basic
design
parameter.
The
commenter
also
recommended
that
this
option
specifically
include
work
that
enhances
safety
and
reliability.
The
commenter
stated
that
RMRR
projects
that
enhance
efficiency,
safety,
and
reliability
will
invariably
improve
environmental
performance.
The
commenter
asserted
that
improved
safety
and
reliability
will
result
in
more
stable
process
operation
and
reduce
periods
of
startup,
shutdown,
and
malfunction
and
the
increased
emissions
usually
associated
with
them.

3.6.2.5
Support
including
efficiency
as
a
basic
design
parameter
Several
industry
commenters
(
1132,
1201,
1202,
1866)
stated
that
efficiency
changes
are
likely
to
always
affect
basic
design
parameters
because
allowing
a
higher
production
rate
per
unit
time
will
require
a
higher
input
rate.
Two
of
the
industry
commenters
(
1201,
1202)
suggested
that
an
alternative
safeguard
would
be
that
no
permitted
emission
limits
(
hourly,
annual,
or
per
unit
of
production
limits)
need
to
be
revised
.

One
State/
local
commenter
(
1268)
urged
EPA
to
include
efficiency,
operating
rate,
utilizations,
fuel
adaptability,
and
useful
economic
life
as
basic
design
parameters,
in
addition
to
the
input
parameters
in
the
proposal.

One
industry
commenter
(
909)
opposed
excluding
efficiency
as
a
design
parameter.
The
commenter
explained
that
efficiency
is
a
critical
and
fundamental
aspect
of
a
power
generating
unit's
ability
to
maintain
financial
viability,
particularly
for
those
facilities
participating
in
competitive
markets,
and
should
be
considered
a
key
design
parameter
for
all
power
plants.

Response:
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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.

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
to
allow
for
facilities
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
the
final
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.
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
maximum
capability
tests,
operating
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.
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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
specifications
in
the
final
rule.
Also,
for
utilities,
we
added
the
basic
design
parameter
of
maximum
design
steam
flow
rating
and
clarified
from
the
proposal
that
the
correct
parameter
is
maximum
hourly
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,
the
minimum
fuel
quality
based
on
BTU
content
should
be
used
for
coal­
fired
units.

Thus,
an
equipment
replacement
that
improves
a
process
unit's
efficiency
by
enabling
the
unit
to
return
to
its
original
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
return
the
unit
to
its
original
design
parameters
and
improve
the
unit's
efficiency,
then
they
would
qualify
as
RMRR
under
the
ERP.

Several
commenters
supported
maximum
design
heat
input
as
the
basic
design
parameter
for
boilers.
This
parameter
could
also
be
expressed
in
terms
of
maximum
design
steam
production
rate,
which
is
consistent
with
how
the
Florida
Department
of
Environmental
Quality
permits
bagasse
boilers.

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
pre­
activity
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
not
make
it
impermissible
under
the
ERP.
They
argued
that
this
would
help
when
replacing
equipment
because
some
effects
resulting
from
the
replacement
may
not
be
apparent
before
the
equipment
has
been
replaced.
We
do
not
believe
this
approach
is
necessary
if
accurate
design
parameters
are
established.
If
the
basic
design
parameters
of
the
process
unit
are
exceeded
by
even
a
minimal
amount,
then
the
activity
cannot
qualify
as
RMRR
under
the
ERP.

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
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
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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.

3.7
Definition
of
Functionally
Equivalent
Comment:

3.7.1
How
to
Define
Functionally
Equivalent
3.7.1.1
In
terms
of
performance
or
function
(
design
parameters)

Industry
commenter
1204
said
EPA
should
consider
the
similarity
of
the
equipment's
performance
or
function
such
as
the
equipment's
rating
in
term
of
the
process
input,
output,
or
capacity,
as
documented
by
the
manufacturer
in
determining
functional
equivalency.
EPA
should
establish
a
allowable
percentage
difference
or
range
that
would
be
acceptable.
Similarly,
another
industry
commenter
(
1797)
believed
that
equipment
replacements
that
serve
the
same
function
as
the
original
equipment
and
that
do
not
change
the
unit's
design
parameters
should
be
considered
routine,
regardless
of
their
cost.

One
industry
commenter
(
1136)
supported
EPA's
proposal
to
define
"
equipment
replacement."
The
industry
commenter
suggested
the
following
definition:
"
the
replacement
of
a
component
of
a
process
unit
with
a
component
that
may
be
out
of
better
materials
or
design,
so
long
as
the
replacement
component
does
not
enhance
the
ability
of
the
process
unit
to
handle
greater
material
inputs."

One
industry
commenter
(
1441)
asserted
that
EPA
has
properly
designed
the
proposal
to
include
"
functionally
equivalent"
component
replacements,
in
addition
to
identical
components.
The
commenter
suggested
the
following
revised
definition
functionally
equivalent
component:

Functionally
equivalent
component
means
a
component
that
serves
the
same
basic
purposes
as
the
replaced
component.
A
functionally
equivalent
component
need
not
be
identical
to
the
replaced
component.
A
new
component
is
functionally
equivalent
if
it
serves
the
same
purpose
or
function
but
is
different
in
some
respect
or
improved
in
some
way
in
comparison
to
the
equipment
that
is
removed.

One
industry
commenter
(
858)
requested
that
the
definition
of
functionally
equivalent
include
a
provision
for
a
de
minimis
change
in
design
parameters
that
may
result
when
a
component
is
replaced
with
another
that
is
functionally
equivalent.
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3.7.1.2
In
terms
of
emissions
Several
industry
commenters
(
636,
1083,
1630)
recommended
that
the
equipment
replacement
option
be
revised
to
allow
equipment
to
be
replaced
with
the
same,
similar,
or
improved
equipment
so
long
as
the
replacement
did
not
increase
the
process
unit's
maximum
hourly
emission
rate.
Under
this
revised
option,
the
replacement
could
increase
efficiency,
so
long
as
the
maximum
hourly
emission
rate
did
not
increase.
Two
other
industry
commenters
(
927,
1204)
also
supported
the
functionally
equivalent
replacement
provisions
with
no
increase
in
emissions,
but
did
not
specifically
mention
hourly
emissions.

3.7.1.3
In
terms
of
efficiency
One
industry
commenter
(
1136)
urged
EPA
to
clarify
that
efficiency
improvements
that
result
from
functionally
equivalent
replacements
are
desirable
and
are
excluded
from
NSR.
More
specifically,
another
industry
commenter
(
1110)
asserted
that
sometimes
functionally
equivalent
replacements
increase
efficiency
and
yield,
which
then
allow
for
additional
material
input.
The
commenter
believed
that
this
safeguard
is
therefore
contrary
to
EPA's
stated
position
that
efficiency
should
not
be
considered
a
design
parameter
and
NSR
should
not
impede
energy
and
process
efficiency
improvements.

One
industry
commenter
(
577)
concurred
that
an
engine
that
is
"
uprated"
at
the
time
of
overhaul
should
undergo
NSR.
"
Uprates"
are
product
enhancements
that
allow
increased
output
for
the
same
package.

3.7.1.4
In
terms
of
various
factors
An
industry
commenter
(
1204)
said
operators
should
be
allowed
to
invest
in
more
costly
replacement
equipment
if
that
equipment
is
functionally
equivalent
to
its
replacement,
enhances
safety
and
lowers
environmental
impacts.
The
rule
should
specifically
identify
environmentally
beneficial
replacements
as
RMRR
regardless
of
cost.

One
university
commenter
(
901)
believed
operators
should
be
allowed
to
invest
in
functionally
equivalent
equipment
replacement,
regardless
of
cost,
if
it
enhances
safety.

Another
industry
commenter
(
1134)
supported
EPA's
use
of
the
phrase
"
serves
the
same
purpose"
to
define
functionally
equivalent.
The
commenter
stated
that
it
is
essential
that
any
codification
of
the
term
assures
that
the
replacement
equipment
does
not
need
to
be
identical,
can
be
made
of
better
materials,
and
can
increase
productivity
provided
that
the
replaced
equipment
does
not
allow
the
process
unit
to
do
something
it
could
not
previously
do.
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A
State/
local
commenter
(
1361)
recommended
that
the
definition
of
functionally
equivalent
component
be
revised.
According
to
the
commenter,
the
proposed
definition
of
"
a
component
that
serves
the
same
purpose
as
the
replaced
component"
would
allow
replacement
of
an
entire
process
unit
(
such
as
a
boiler).
The
commenter
suggested
adding
language
such
as
"
considering
functional
equivalence,
efficiency,
capacity
of
the
component,
design
specifications,
etc."

3.7.1.5
In
general
Industry
commenter
(
1453)
argues
that
definition
of
"
identical
and
functional"
must
be
flexible;
equipment
manufacturers
often
change
designs
so
it
is
not
always
possible
to
buy
exact
duplicate
equipment.
Similarly,
an
industry
commenter
(
1238)
recommended
that
EPA
define
"
functionally
equivalent"
broadly.
Tire
and
engineered
rubber
products
manufacturers
often
operate
machinery
for
many
years
before
it
needs
to
be
replaced.
It
is
often
impossible
to
find
identical
or
nearly
identical
replacements,
and
often
it
would
not
make
sense
to
do
so.
New
replacement
equipment
might
carry
out
a
very
similar
function
but
still
be
distinct
from,
and
appear
fairly
different
than)
the
original
equipment.

3.7.2
Generally
Supportive
Comments
Several
industry
commenters
(
636,
927,
941,
1007,
1013,
1069,
1110,
1129,
1130,
1136,
1149,
1159,
1204,
1441,
1453,
1868)
supported
EPA's
inclusion
of
functionally
equivalent
equipment
replacements.
Three
State/
local
commenters
(
1044,
1240,
1443)
supported
a
narrow
provision
for
replacement
of
"
identical"
components.
One
Federal
agency
commenter
(
1101)
supported
the
exclusion
for
replacement
of
identical
equipment
and
replacement
with
functionally
equivalent
equipment.

One
industry
commenter
(
1136)
stated
that
it
is
often
impossible
to
find
identical
replacement
parts,
and
it
would
be
detrimental
to
their
customers
not
to
take
advantage
of
material
and
engineering
improvements
of
functionally
equivalent
parts
that
perform
better.
Thus,
the
equipment
replacement
approach
will
allow
electric
utilities
to
improve
the
efficiency
of
their
boilers,
system
reliability,
and
equipment
safety
by
replacing
equipment
with
functionally
equivalent
equipment
made
of
better
materials.

An
industry
commenter
(
1110)
stated
that
the
key
phrase
"
identical
or
functionally
equivalent"
will
provide
clarity
and
certainty
for
this
provision
because
an
identical
replacement
is
not
always
possible.

Another
industry
commenter
(
1868)
noted
that
in
its
permitting
experience
the
only
safe
choice
has
often
been
to
use
only
identical
replacements,
particularly
during
plant
turnarounds
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when
the
replacement
could
not
be
forecast
until
the
plant
was
shutdown,
and
pursuing
a
permit
determination
would
have
taken
too
long.
The
proposal
would
help
alleviate
this
problem.

Response:

We
originally
proposed
to
exempt
the
replacement
of
existing
equipment
with
identical
or
"
functionally
equivalent"
parts.
An
identical
replacement
is
a
replacement
of
a
part
with
another
part
that
is
the
same
model
number
and
size
as
the
original
part
and
may
differ
from
the
original
part
in
only
insignificant
ways.
A
functionally
equivalent
replacement,
on
the
other
hand,
occurs
when
a
part
is
replaced
with
another
part
that
serves
the
same
purpose
as
the
replaced
part,
but
differs
from
the
replaced
part
in
a
more
noticeable
way.
For
a
functionally
equivalent
replacement,
the
replaced
part
may
not
only
be
a
different
model
number
or
an
equivalent
model
from
a
competitive
manufacturer,
but
it
may
also
be
a
part
that
has
been
updated
or
improved
since
the
time
of
the
original
part's
manufacture.
This
may
include:

°
replacing
worn
out
pipes
in
a
chemical
process
plant
with
pipes
that
are
constructed
of
different
metallurgy.

°
replacing
an
analog
controllers
with
a
digital
controllers,
even
though
that
the
new
controller
would
allow
for
more
precise
control.

°
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).

°
replacing
an
old
economizer
in
a
boiler
with
a
new
one
that
contained
different
geometry,
internal
design
and/
or
metallurgy,
even
if
the
replacement
improves
fuel
efficiency,
or
reduces
erosion
or
plugging
due
to
fly
ash.
The
economizer's
function
is
to
do
precisely
that
 
help
economize
by
reliably
reducing
fuel
consumption
per
unit
of
output.
Both
new
and
old
economizers
serve
that
same
function.
The
same
logic
holds
for
replacements
of,
or
within,
air
preheaters
and
condensers,
because
these
are
heat
exchangers
designed
to
improve
plant
efficiency
with
a
given
amount
of
heat
input.
°
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
the
final
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
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include
[
OUR
EXAMPLE:
a
plant
that
changes
a
boiler
from
a
forced
draft
to
an
induced
draft
fan
configuration.
Despite
the
relatively
minimal
cost
of
such
an
activity
and
the
fact
that
the
boiler
continues
to
operate
in
fundamentally
the
same
way
after
the
change,
the
induced
draft
fan
plainly
represents
a
change
from
the
forced
draft
fan
system
in
numerous
operational
ways
 
REVIEW
TEAM
WILL
OFFER
A
REPLACEMENT
EXAMPLE??].
Consequently,
this
activity
would
not
qualify
as
RMRR
under
the
final
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
original
design
and
purposes
of
the
source,
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
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.

We
agree
with
the
commenters
who
felt
most
of
these
identical
and
functionally
equivalent
replacement
activities
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
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
by­
case
analysis
required
to
determine
a
replacement
falls
within
the
RMRR
exclusion.
We
support
the
air
pollution
agencies
that
have
already
exempted
this
type
of
change
from
NSR,
although
as
discussed
below,
we
have
concerns
about
doing
so
without
appropriate
backstops,
even
for
identical
equipment
replacements.
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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
the
same
advantages
as
a
PAL
except
for
the
ability
to
bring
on
new
emissions
units.
These
advantages
will
still
be
the
driving
force
for
sources
to
elect
a
PAL
or
a
Clean
Unit,
and
we
do
not
believe
this
final
rule
will
significantly
detract
from
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
well­
established
procedures
for
the
inspection
and
replacement
of
parts
of
the
equipment
that
are
part
of
the
regular
maintenance
necessary
to
provide
for
the
equipment's
safe,
efficient
and
reliable
operation.
Some
of
these
replacements
are
large
in
terms
of
cost
and
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
as
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
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
efficiency.

We
disagree
with
commenters
concerns
about
functionally
equivalent
replacements
and
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,
our
goal
is
to
promote
such
outcomes.
However,
we
believe
that
the
basic
design
parameter
safeguard
that
we
proposed
is
appropriate
to
assure
that
the
ERP
only
categorizes
functionally
equivalent
replacements
that
do
not
result
in
a
significant
change
to
the
fundamental
characteristics
of
the
process
unit.
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Moreover,
the
two
local
programs
that
exempt
the
replacement
of
equipment
with
identical
equipment
also
allow
the
replacement
of
equipment
with
functionally
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
the
final
rule
would
prevent
a
State
or
local
program
from
imposing
control
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,
is
necessary
to
emphasize
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,
the
final
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,
the
final
rule
allow
you
to
categorize
identical
and
functionally
equivalent
equipment
replacements
as
RMRR
if
the
fixed
capital
cost
of
such
replacement
plus
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
any
part
of
the
process
unit.

3.8
Cost
Basis
for
Equipment
Replacement
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
commenter
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
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
specifically
walled
off
their
comments
on
the
proposed
accounting
methods
from
application
to
the
ERP.

Comment:

3.8.1
General
Support
for
Proposal
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Several
industry
commenters
(
1066,
1105,
1110,
1143,
1301,
1346,
1441)
supported
determining
applicability
of
the
ERP
on
the
basis
of
replacement
cost.

One
commenter
(
1346)
believed
data
for
invested
costs
become
less
available
over
time.

One
commenter
(
1066)
favored
replacement
cost
over
invested
cost
for
several
reasons.
Replacement
cost
is
more
easily
obtained
than
invested
cost.
Most
manufacturers
will
have
information
concerning
the
replacement
cost
of
a
process
unit,
because
such
costs
are
commonly
used
when
evaluating
various
business
scenarios
relating
to
manufacturing
costs.
Also,
use
of
replacement
cost
is
consistent
with
NSPS.

One
commenter
(
1301)
supported
use
of
replacement
cost
for
a
facility
for
both
the
AMA
and
ERP
approaches.
The
commenter
believed
that
while
the
invested
cost
for
a
facility
is
typically
available,
it
is
obsolete
after
only
a
couple
of
years.
The
commenter
also
believed
adjusting
the
invested
cost
for
inflation
using
typically
available
inflation
factors
is
inappropriate
for
use
in
the
context
of
heavy
industrial
construction.
Furthermore,
the
commenter
believed
that
while
there
are
specialized
industry­
specific
cost
adjustment
factors
for
various
industries
(
such
as
the
Nelson­
Farr
factors
for
the
petroleum
process
industries),
these
are
by
necessity
generic
and
do
not
take
into
account
crucial
factors
such
as
facility
location
and
seasonal
cost
variance.

While
favoring
replacement
cost,
one
industry
commenter
(
1105)
said
determining
the
replacement
cost
of
a
plant
or
component
can
be
a
daunting
task,
so
the
commenter
recommended
that
EPA
allow
the
use
of
installed
cost
as
an
option,
indexed
by
a
standard
reference
method
such
as
the
Handy­
Whitman
index.

One
industry
commenter
(
1346)
supported
the
use
of
replacement
cost
instead
of
invested
cost
in
calculations
for
the
AMA
and
the
ERP
threshold
test.
The
commenter
believed
data
for
invested
costs
become
less
available
over
time
making
it
difficult
to
reach
agreement
on
the
costs
to
be
used.
However,
the
commenter
suggested
that
replacement
costs
are
more
readily
available
making
it
easier
for
both
the
regulated
community
and
the
agencies
to
perform
the
calculations
and
to
reach
agreement.

One
industry
commenter
(
1143)
believed
that
replacement
cost
must
be
calculated
based
on
"
current"
cost
to
replace
a
plant.
Objective
measurements,
such
as
property
records
and
insurance
policies,
used
to
establish
casualty
claims
are
sound
basis
for
the
use
of
replacement
cost,
and
make
more
sense
than
original
capital
invested.
The
commenter
asked
that
the
final
rule
clearly
define
what
is
covered
under
replacement
cost.

3.8.2
General
Support
for
Other
Methods
for
Cost
Basis
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Three
industry
commenters
(
1079,
1110,
1132)
recommended
that
EPA
allow
the
use
of
either
a
replacement
cost
estimate
(
determined
using
cost
estimation
techniques
currently
employed
by
the
company)
or
inflation­
adjusted
original
investment.

One
industry
commenter
(
1368)
endorsed
UARG's
method
of
using
a
dollar­
per­
kilowatt
rate
for
calculating
costs.
This
model
is
specific
to
source
and
fuel
type
and
could
be
updated
periodically.
The
commenter
also
believed
site­
specific
replacement
costs
should
be
allowed,
where
approved
by
the
reviewing
authority.

One
industry
commenter
(
1797)
recommended
that
EPA
identify
a
dollar­
per­
kilowatt
value,
periodically
adjusted
for
inflation,
for
the
replacement
cost
of
a
process
unit
rather
than
of
the
entire
plant.
The
commenter
suggested
that
a
dollar­
per­
kilowatt
value
could
be
established
for
different
size
ranges
of
units,
e.
g.,
small,
medium
and
large,
for
units
burning
different
fuel
types,
and
for
different
geographic
regions.

One
industry
commenter
(
1469)
preferred
using
the
replacement
cost
method
for
both
the
AMA
and
ERP
approaches;
however,
this
commenter
stated
that
invested
cost
adjusted
for
inflation
may
be
the
only
option
for
traditional
gas­
fired
units
at
a
steam
electric
generating
unit
or
plant.
The
commenter
also
stated
that
an
alternative
would
be
to
use
a
cost
for
a
same­
capacity
combined­
cycle
unit(
s)
and
that
the
rule
should
allow
the
owner/
operator
and
the
permitting
authority
some
flexibility
to
use
alternative
cost
methods.

Four
industry
commenters
(
1001,
1082,
1201,
1202)
suggested
EPA
affirm
that
replacement
costs
can
be
calculated
by
several
different
methods.
The
commenters
suggested
that
EPA
provide
a
list
of
acceptable
options
for
calculating
replacement
value,
such
as
current
engineering
appraisal,
basis
adjusted
for
inflation
or
according
to
an
industry
standard,
or
insurance
coverage
limits.

Response:

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).

We
are
allowing
sources
to
determine
the
applicability
of
the
final
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
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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.

3.9
Calculating
Costs
Comment:

3.9.1
Cost
Estimation
Method
3.9.1.1
Use
of
EPA
Air
Pollution
Control
Cost
Manual
Most
commenters
did
not
support
use
of
the
EPA
Air
Pollution
Control
Cost
Manual
(
APCCM)
to
standardize
calculations
for
replacement
and
repair
costs
for
RMRR
in
general.

Two
industry
commenters
(
951,
1066)
believed
use
of
the
APCCM
alone
is
acceptable.
One
industry
commenter
(
1066)
supports
use
of
the
APCCM
because
it
is
based
on
standard
cost
estimation
methods.

Two
industry
commenters
(
1301,
1463)
and
several
State/
local
commenters
(
519,
946,
1033,
1199,
1264,
1268,
1412)
objected
to
the
use
of
the
APCCM.
Two
industry
commenters
(
1301,
1463)
asserted
that
EPA
should
not
require
the
use
of
any
specific
document
or
method
to
calculate
costs.
Two
State/
local
commenters
(
946,
1199)
stated
that
the
APCCM
should
not
be
used
to
estimate
costs
for
RMRR
because
the
algorithms
contained
in
EPA's
APCCM
do
not
relate
to
the
determination
of
RMRR
costs
and
it
is
inappropriate
to
apply
them
for
this
and
other
purposes
unrelated
to
their
intended
use.
Two
State/
local
commenters
(
1033,
1268)
believed
that
the
control
cost
manual
is
not
readily
applicable
to
standardize
costs
for
the
AMA
because
the
APCCM
covers
costs
for
air
pollution
control
devices
and
not
the
costs
of
process
operations
or
maintenance
activities.
One
of
the
State/
local
commenters
(
1033)
also
stated
that
the
proposed
cost
analysis
is
complex,
costly,
and
time
consuming.
Most
sources
would
have
to
hire
outside
consultants
to
perform
the
cost
analysis
which
would
subject
sources
to
an
economic
burden
just
to
keep
their
equipment
running
safely
and
properly.
Two
State/
local
commenters
(
519,
1264)
suggested
EPA
develop
a
costing
manual
specific
to
RMRR.

One
industry
commenter
(
1463)
opposed
mandatory
use
of
the
APCCM
or
other
specific
manuals
to
standardize
calculations
for
the
replacement
cost
basis
and
repairs.
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One
industry
commenter
(
1124)
opposed
use
of
the
APCCM
based
on
a
detailed
analysis
of
the
manual.
The
commenter
concluded
that
the
methodology
used
in
the
APCCM
would
not
be
practical
because:
(
1)
The
amount
of
highly
specialized
information
required
to
develop
reasonable
cost
estimates
would
make
the
use
of
a
manual
for
estimating
costs
of
individual
process
units
plants
extremely
difficult;
(
2)
in
almost
all
cases,
site­
specific
information
would
be
required;
(
3)
substantial
time
and
expense
would
be
involved;
and
(
4)
the
methodology
would
require
specialized
engineering.

3.9.1.2
Choosing
among
identified
cost
manuals
One
industry
commenter
(
951)
believed
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
every
situation.

3.9.1.3
Support
other
costing
sources/
methods
One
industry
commenter
(
858)
suggested
that
the
rule
accommodate
a
facility's
current
accounting
practices.
One
industry
commenter
(
1132)
recommended
that
EPA
allow
sources
to
determine
replacement
costs
using
cost
estimation
techniques
currently
employed
by
companies.
One
industry
commenter
(
1138)
recommended
a
flexible
approach
to
determining
"
fixed
capital
cost."
Another
industry
commenter
(
951)
believed
site­
specific
information
should
be
considered
in
calculating
RMRR
costs.
One
industry
commenter
(
1105)
suggested,
as
an
alternative,
that
EPA
state
a
presumptive
cost
metric,
such
as
$/
kW,
to
be
used
as
a
baseline,
with
the
presumption
being
rebuttable.

Several
industry
commenters
(
865,
1077,
1463)
tended
not
to
support
a
single
method
for
determining
the
typical
RMRR
costs
for
particular
industries.
One
commenter
(
1077)
agreed
that
the
APCCM
could
provide
a
useful
methodology
but
cautioned
that
a
detailed
engineering
cost
estimate
is
required
to
calculate
the
replacement
cost
for
a
steam
electric
plant,
and
such
a
sitespecific
cost
estimate
could
be
prohibitively
expensive
for
the
industry.
This
commenter
recommended
that
EPA
consider
other
methods
that
do
not
require
site­
specific
cost
methods.

Two
industry
commenters
(
1112,
1212)
believed
EPA
should
allow
for
alternative
methods
of
calculating
replacement
costs.
One
commenter
(
1112)
suggested
such
methods
could
include
the
APCCM
and
methods
previously
accepted
by
FERC
and
the
State
utility
commissions.

One
industry
commenter
(
865)
recommended
that
EPA
allow
sources
to
use
insurance
valuation
methods
such
as
the
Handy­
Whitman
Index
to
determine
replacement
costs
for
electric
utility
replacement
costs
under
both
the
AMA
and
ERP.
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In
opposing
use
of
any
specific
manual
for
cost
calculations,
one
industry
commenter
(
1463)
said
they
use
a
variety
of
sources
to
compute
costs,
including
values
from
the
Nelson
Refinery
Construction
Index
Factors,
Solomon
Refinery
Study,
and
licensors
of
the
respective
process
unit
(
Kellogg,
UOP,
etc.)

One
industry
commenter
(
858)
said
a
uniform
basis
for
determining
facility
replacement
cost
should
be
used
to
account
for
the
variability
of
land
and
labor
costs
across
the
country.
Also,
a
scheme
should
be
developed
to
uniformly
account
for
leased
vs.
owned
facilities
(
such
as
by
requiring
everyone
to
assume
purchase
instead
of
lease
in
cost
development).

3.9.2
Including
Costs
of
Control
Equipment
in
Equipment
Cost
3.9.2.1
Support
including
costs
of
control
equipment
in
equipment
cost
Two
industry
commenters
(
1126,
1441)
asserted
that
the
costs
of
required
air
pollution
control
equipment
should
be
included
in
the
replacement
cost
for
a
stationary
source/
process
unit
(
for
both
the
AMA
and
ERP).
Another
industry
commenter
(
1136)
said
pollution
control
costs
should
be
included
in
replacement
cost
calculations
(
for
the
AMA
option).
This
commenter
stated
that
to
differentiate
between
costs
of
expenditures
to
maintain
pollution
controls
and
other
generating
equipment
would
add
tremendous
additional
administrative
costs
and
would
call
for
multiple
judgments.
Second,
the
commenter
said,
pollution
controls
are
inherent
in
the
design
and
proper
maintenance
of
combustion
equipment.
The
design
and
maintenance
of
the
firewalls
of
a
boiler,
burner
nozzles,
the
even
pulverization
and
distribution
of
coal
into
the
firebox,
and
the
efficient
operation
of
superheaters
and
economizers
(
bundles
of
water
tubing)
are
related
to
complete
and
effective
combustion
and
have
a
direct
relationship
on
emissions
from
facilities,
as
well
as
the
maintenance
of
fluidized
combustion
beds,
precipitator
and
scrubber
components.
Moreover,
if
a
facility
has
to
be
reconstructed
or
constructed
anew,
it
must
be
equipped
with
pollution
controls.
Third,
the
commenter
said,
their
operators
do
not
distinguish
between
capital
used
for
maintenance
and
capital
for
pollution
controls.

Three
industry
commenters
(
896,
1110,
1346)
believed
pollution
control
equipment
should
not
be
excluded
from
the
definition
of
"
process
unit"
because
such
equipment
is
treated
in
many
regulations
and
permits
as
an
integral
part
of
the
overall
process
unit.
The
commenters
believed
all
pollution
control
equipment
should
be
considered
part
of
the
"
process
unit"
in
order
to
fully
account
for
the
investment
included
with
a
process,
as
well
as
to
avoid
potential
confusion
and
regulatory
ambiguity
with
regard
to
the
scope
of
"
process
unit,"
given
the
extreme
variability
in
types
of
process
units
and
the
frequent
"
dual­
purpose"
nature
of
recovery
and
control
equipment
in
chemical
manufacturing
processes.
One
commenter
(
1110)
also
suggested
that
having
to
split
out
the
pollution
control
equipment
and
establish
accounting
systems
that
accomplish
this
would
only
add
additional
costs
without
any
demonstrable
emission
reduction
or
cost
improvement
of
the
NSR
program.
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One
State/
local
commenter
(
1270)
recommended
that
pollution
control
equipment
be
considered
part
of
the
process
unit
when
determining
the
basis
for
cost.
The
commenter
believed
that
control
equipment
in
most
cases
is
required
to
be
in
place
for
the
process
line
to
operate
and
must
be
maintained
in
the
same
manner
as
process
equipment
and
that
there
are
a
number
of
control
devices
that
emit
collateral
pollutants
when
operating
as
designed.

In
support
of
our
proposal,
four
industry
commenters
(
902,
1129,
1138,
1212)
believed
equipment
serving
a
dual
purpose
of
process
equipment
and
control
equipment
should
be
considered
process
equipment
and
should
be
included
in
the
replacement
cost
calculation
basis.
Two
commenters
(
1138,
1212)
stated
that
this
is
of
particular
importance
to
natural
gas
transport
facility
process
units
because
the
majority
of
pollution
control
has
been
and
continues
to
be
achieved
through
clean
combustion
technology.
Such
technology
constitutes
inherent
pollution
control,
integral
to
the
process
unit
combustion
system
design,
without
which
the
unit
could
not
operate.

3.9.2.2
Oppose
including
costs
of
control
equipment
in
equipment
cost
Several
industry
commenters
(
840,
897,
910,
920,
921,
951,
979,
1000,
1096,
1109,
1123,
1212,
1367)
opposed
including
pollution
control
equipment
in
the
equipment
costs
for
the
ERP.
One
commenter
(
951)
believed
that
add­
on
or
exhaust­
mounted
control
devices
should
not
be
included
in
either
the
AMA
or
the
ERP
cost
estimate.
Rules
should
be
designed
to
apply
uniformly,
and
excluding
pollution
control
equipment
helps
achieve
that
purpose.

One
industry
commenter
(
1137)
believed
that
EPA
should
authorize
sources
to
determine
whether
pollution
control
equipment
should
be
excluded
from
the
ERP.
This
commenter
believed
that
a
blanket
exclusion
could
create
problems
of
interpretation
because
the
term
"
pollution
control
equipment"
is
ambiguous
when
considering
certain
components.

One
industry
commenter
(
1138)
supports
the
proposed
approach,
where
the
cost
of
addon
pollution
control
equipment
is
not
counted
against
a
source's
ERP
allowance,
but
expenditures
on
equipment
that
serve
both
a
pollution
control
and
a
process
function
are
counted.

One
industry
commenter
(
910)
believed
RMRR
activities
performed
on
pollution
control
and
dual­
purpose
equipment
should
not
be
considered
for
either
the
ERP
or
the
AMA,
because
these
activities
are
separately
addressed
in
the
pollution
control
exception.

One
industry
commenter
(
1100)
believed
maintenance,
repair,
and
replacement
of
air
pollution
control
equipment
or
equipment
used
to
determine
compliance
with
emission
limits
such
as
continuous
emission
monitoring
systems
should
always
be
considered
RMRR.
The
commenter
also
believed
that
even
though
some
air
pollution
control
equipment
(
such
as
a
pneumatic
transfer
system
utilizing
a
bagfilter)
has
a
dual
purpose
as
process
equipment,
this
equipment
should
be
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considered
as
air
pollution
control
equipment
if
permit
conditions
require
routine
inspection
and
maintenance
of
the
control
equipment.

Two
industry
commenters
(
1050,
1213)
believed
EPA
should
expressly
state
in
the
rule
language
that
MRR
activities
for
pollution
control
equipment
are
not
physical
changes
or
changes
in
the
method
of
operation
under
the
NSR
program.

One
industry
commenter
(
1399)
believed
the
installation
of
pollution
control
equipment
would
be
best
addressed
under
the
pollution
control
exclusion;
pollution
control
maintenance
and
repair
activities
would
not
be
expected
to
result
in
an
emissions
increase
from
the
source,
and
thus
they
would
not
be
modifications
even
if
they
were
changes.

One
industry
commenter
(
942)
proposed
that
maintenance
and
repair
of
pollution
control
equipment
or
monitoring
equipment
be
categorically
defined
as
RMRR.
Another
industry
commenter
(
1159)
believed
a
broad
exclusion
from
NSR
applicability
should
be
provided
for
maintaining
and
installing
pollution
control
equipment.

Response:

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
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
manual
contains
basic
concepts
that
could
be
used
to
estimate
total
capital
investment
at
a
process
unit,
it
is
geared
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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
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.

3.10
Stationary
Source
or
Process
Unit
Basis
Comment:

3.10.1
General
Support
for
Stationary
Source
Basis
Several
industry
commenters
(
951,
1045,
1113,
1126,
1136,
1160,
1212,
1213,
1237,
1292,
1301,
1630)
believed
the
ERP
should
be
applied
on
a
stationary
source
basis
as
opposed
to
a
process
unit
basis.

Two
commenters
(
1237,
1292),
while
supporting
a
cost
threshold
for
the
entire
facility,
said
EPA
should
provide
the
option
to
use
a
process
unit
basis
instead.

One
commenter
(
1113)
said
replacement
cost
should
be
based
on
the
stationary
source
or
facility
because
the
industry
already
is
familiar
with
the
facility
approach
used
in
the
NSPS,
it
is
consistent
with
other
programs
(
no
additional
examples
provided),
and
it
will
lead
to
better
acceptability
within
the
regulated
community.
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One
commenter
(
1160)
supported
a
stationary
source
basis
for
several
reasons.
NSR
has
always
focused
on
entire
stationary
sources
which,
for
the
utility
industry,
would
be
the
entire
power
plant.
To
allocate
costs
of
components
that
are
shared,
on
the
basis
of
capacity,
raises
questions
about
how
capacity
should
be
determined,
as
is
discussed
in
the
proposal
preamble.
Also,
a
stationary
source
basis
would
be
easier
to
implement
by
both
the
regulated
and
regulating
communities.

One
commenter
(
1213)
stated
that
a
source
that
is
a
fossil
fuel­
fired
power
plant
should
not
include
other
electric
generation
or
industrial
processes
that
may
be
collocated.

3.10.2
General
Support
for
Process
Unit
Basis
Several
industry
commenters
(
896,
902,
910,
1077,
1079,
1098,
1100,
1134,
1138,
1143,
1792)
supported
a
process
unit
basis
for
administering
the
ERP.

One
industry
commenter
(
1792)
supported
applying
the
equipment
replacement
option
on
a
process
unit
basis
because
the
source
is
looking
at
replacing
equipment
on
a
specific
unit.

One
industry
commenter
(
1100)
said
the
RMRR
rule
should
be
no
more
stringent
than
the
reconstruction
provision
contained
within
the
August
7,
1980
NSR
rule,
which
references
the
NSPS
regulations
addressing
reconstruction
and
which
allows
either
an
entire
plant
or
an
individual
piece
of
process
equipment
to
be
a
"
source."
One
industry
commenter
(
1143)
thought
a
process
unit
basis
would
be
consistent
with
CAA
section
112(
g).

Response:

As
we
discussed
in
section
3.4
of
this
document,
we
raised
the
issue
of
what
collection
of
equipment
should
be
considered
in
applying
the
cost
threshold
under
the
ERP.
We
proposed
the
term
"
process
unit"
as
the
appropriate
collection.
We
stated
in
the
proposal
that
"[
w]
e
solicit
comment
on
the
proposed
definition
of
'
process
unit'
and
whether
another
approach
might
be
more
effective."
We
did
not
intend
that
other
"
approaches"
would
include
changing
the
basis
of
the
ERP
from
a
process
unit
to
the
stationary
source.
We
solicited
comment
on
a
process
unit
versus
stationary
source
basis
only
in
connection
with
the
annual
maintenance
allowance.

The
types
of
other
"
approaches"
to
the
process
unit
basis
that
we
envisioned
were
those
discussed
in
section
3.4
(
for
example,
whether
the
definition
of
process
unit
should
include
pollution
control
equipment,
whether
process
unit
should
be
defined
for
specific
industries
or
only
in
general
terms,
and
whether
the
definition
should
be
consistent
with
40
CFR
63.41).
While
we
understand
the
concerns
raised
by
those
commenters
who
supported
a
stationary
source
basis
for
the
ERP,
we
did
not
consider
making
such
a
change
for
the
final
rule.
We
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believe
a
process
unit
basis
is
necessary
for
the
cost
basis
used
for
the
final
rule
as
discussed
in
section
3.8.

3.11
Costs
Related
to
Unanticipated
Shutdowns
We
solicited
comment
on
whether
or
not
repairs
and
replacements
resulting
from
the
unanticipated
shutdown
of
equipment,
or
of
an
entire
source,
should
be
included
in
the
ERP
calculations.

Industry
commenters
generally
supported
an
ERP
that
excludes
costs
relating
to
unanticipated
shutdowns
from
having
to
satisfy
the
cost
threshold
test.
These
comments
are
summarized
in
section
3.11.1.
Some
commenters
did
not
believe
costs
for
activities
relating
to
unanticipated
shutdowns
should
be
exempt
from
NSR
review,
and
other
commenters
expressed
support
for
a
separate
exclusion
(
outside
the
ERP)
for
these
costs;
these
comments
are
summarized
in
section
3.11.2.

Comment:

3.11.1
Support
for
Excluding
Costs
for
Unanticipated
Shutdowns
from
Cost
Threshold
Many
industry
commenters
(
840,
858,
941,
1001,
1088,
1099,
1110,
1114,
1124,
1131,
1133,
1137,
1138,
1201,
1202,
1212,
1236,
1283,
1301/
1618,
1441,
1793,
1794,
1866,
1988)
said
replacement
of
units
that
have
failed
catastrophically
should
not
be
subject
to
the
ERP
cost
threshold.

Several
commenters
(
941,
1110,
1114,
1124,
1131,
1133,
1236,
1988)
added
that
it
would
not
be
practical
to
fit
every
correction
of
such
failures
into
the
cost
safeguard.
These
commenters,
as
well
as
two
others
(
1138,
1212),
also
believed
that
industrial
facilities
are
highly
motivated
to
avoid
such
catastrophic
failures,
in
part
because
of
the
risk
of
human
injury
and
production
interruptions
and
the
expense
of
correcting
them.
Therefore,
companies
would
not
abuse
such
an
exclusion.
One
commenter
(
1283)
noted
that
these
types
of
costs
cannot
be
planned
for
and
are
thus
not
included
in
maintenance
or
equipment
replacement
budgets.

An
industry
commenter
(
1143)
stated
that
emergency
shutdowns
should
always
be
viewed
as
routine.

One
industry
commenter
(
1138)
who
supported
the
exclusion
of
costs
for
unanticipated
shutdowns
and
failures
believed
failures
do
take
place
occasionally
and
can
result
in
a
sudden,
unplanned
partial
or
total
loss
of
equipment
for
a
given
natural
gas
compressor
station.
When
such
a
failure
occurs,
the
affected
turbine
or
engine
must
be
replaced
immediately
to
avoid
a
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disruption
in
gas
supply.
Such
replacement
fits
easily
within
most
elements
of
the
equipment
replacement
test.
However,
it
might
violate
the
ERP
cost
threshold,
because
the
old
turbine
may
be
a
total
loss
with
no
exchange
value.
Yet,
replacing
a
catastrophically
failed
turbine
or
engine
is
clearly
"
routine,"
because
companies
will
always
replace
such
failures.
Requiring
such
replacements
to
go
through
NSR
could
force
the
compressor
station
to
go
off
line
pending
the
permitting
process.
The
commenter
believed
the
RMRR
exclusion
is
designed
precisely
to
prevent
the
regulatory
process
from
creating
such
forced
downtime.

One
industry
commenter
(
1137)
believed
EPA
should
provide
that
maintenance
and
repair
costs
associated
with
unanticipated
shutdown
of
equipment
and
other
catastrophic
events
will
automatically
be
excluded
under
the
RMRR
exclusion,
and
costs
of
replacement
equipment
components
will
be
excluded
as
long
as
the
components
are
identical
or
functionally
equivalent
to
the
ones
that
are
replaced.

Two
industry
commenters
(
1212,
1138)
provided
examples
of
unanticipated
equipment
failures
and
catastrophic
events
for
which
replacement
should
be
allowed
without
regard
to
the
ERP
cost
threshold:
fires
and
explosions
resulting
in
loss
of
equipment;
mechanical
failure
of
turbine
components
resulting
in
unplanned
shutdown;
and
mechanical
failure
of
reciprocating
engine
components
(
e.
g.,
cylinder
heads,
pistons,
piston
rods)
resulting
in
unplanned
shutdown.

3.11.2
Support
Other
Approach
to
Shutdowns
Two
State/
local
commenters
(
1199,
1361)
opposed
an
ERP
exclusion
for
activities
resulting
from
shutdowns.
One
commenter
(
1361)
stated
that
in
light
of
the
extensive
exemptions
from
NSR
and
the
proposed
AMA
discussed
in
the
RMRR
proposal,
there
is
no
need
for
any
further
allowance
for
exclusions.
The
other
commenter
(
1199)
added
that
maintenance
activities
performed
during
forced
outages
are
simply
maintenance
and
should
be
considered
as
such
and
that
the
fact
that
exempting
forced
outages
is
even
being
considered
indicates
EPA's
intent
to
virtually
eliminate
NSR
for
existing
sources.

One
State/
local
commenter
(
1241)
suggested
that
costs
associated
with
RMRR
activities
resulting
from
unanticipated
shutdown
of
equipment
should
be
included
in
any
annual
RMRR
calculation.
According
to
the
commenter,
an
exclusion
for
such
costs
would
be
subject
to
manipulation
by
regulated
entities.
The
commenter
added
that
RMRR
activities
due
to
an
unanticipated
shutdown
of
equipment
from
catastrophic
failure
should
be
subject
to
NSR
because
the
associated
costs
are
not
routine
maintenance.
Thus,
such
activities
likely
constitute
a
major
modification
and
should
not
be
subject
to
a
blanket
exclusion
from
the
NSR
program.
Rather,
the
commenter
believes,
they
should
continue
to
be
evaluated
on
a
case­
by­
case
basis
using
the
established
review
criteria
for
"
routine
maintenance"
expenditures.
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One
industry
commenter
(
1446)
suggested
that
with
a
properly
designed
program
based
on
equipment
replacement,
even
emergency
repairs
and
catastrophic
failures
should
be
able
to
be
reasonably
accommodated
within
such
a
program.

An
industry
commenter
(
1792)
suggested
that
costs
associated
with
unanticipated
shutdown
of
equipment
or
catastrophic
equipment
failure
should
be
allowed
to
be
included
in
the
ERP
calculations
at
the
company's
discretion.
Other
industry
commenters
(
1050,
1077,
1098,
1213,
1245,
1368)
said
it
should
be
left
to
the
source
owner/
operator's
discretion
whether
to
include
unanticipated
shutdown
of
equipment
or
catastrophic
equipment
failure
costs
in
the
allowance
calculation
under
the
AMA
approach;
however;
to
the
extent
that
such
costs
were
not
included,
the
owner/
operator
could
evaluate
such
unplanned
activities
under
either
the
ERP
approach
or
the
case­
by­
case
approach.

One
industry
commenter
(
1630)
believed
that
the
cost
limit
contained
in
the
ERP
would
not
address
catastrophic
or
large­
scale
failures
at
facilities.
The
commenter
suggested
that
EPA
either
significantly
increase
the
allowable
percentage
for
replacement
costs,
subjecting
the
exemption
to
potential
misuse,
or
require
the
facility
to
undergo
a
case­
by­
case
determination
for
approval.
The
commenter
believes
that
such
failures
are
within
the
RMRR
category
but
would
likely
subject
a
facility
to
NSR
permitting
or
an
extended
outage
while
seeking
approval
under
the
proposed
system.

One
industry
commenter
(
1112)
suggested
that
the
replacement
of
damaged
or
failed
components
related
to
unanticipated
shutdowns
or
catastrophic
failures
be
allowed
if
replaced
by
functionally
equivalent
components.
In
cases
where
the
replacement
does
not
meet
the
functionally
equivalent
description,
the
commenter
believed
such
replacements
be
addressed
under
the
AMA
approach.
In
cases
where
the
unplanned
event
causes
the
source
to
exceed
the
allowance,
the
commenter
suggested
using
a
case­
by­
case
approach
to
evaluate
whether
the
replacements
were
routine.
The
commenter
also
believed
that
because
such
shutdowns
and
catastrophic
failures
are
unplanned,
EPA
should
provide
the
source
owner
with
flexibility
to
select
which
demonstration
of
routine
should
be
used.

Several
industry
commenters
(
1083,
1113,
1134,
1136,
1160,
1246,
1465)
supported
a
separate
exclusion
for
catastrophic
events.


One
commenter
(
1113)
requested
that
EPA
adopt
a
presumptive
exclusion
with
a
safeguard
that
no
increase
in
hourly
emissions
be
allowed
without
permit
review.
This
commenter
believed
these
types
of
outages
are
unplanned
and
are
not
a
base
consideration
in
planning
routine
maintenance
and
repair.
However,
forced
outages
do
occur
and
the
need
to
make
these
potential
repairs
should
be
taken
into
consideration.
If
the
EPA
were
to
find
repairs
or
replacement
activities
that
did
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not
apply
to
the
forced
outage,
the
costs
should
then
be
subject
to
the
facility's
equipment
replacement
evaluation
procedures.


One
commenter
(
1134)
believed
that
when
there
is
an
explosion,
fire,
or
flood,
the
objective
ought
to
be
to
rebuild
a
facility
without
NSR
review.


One
commenter
(
1136)
did
not
believe
EPA
should
treat
expenses
differently
based
on
whether
outages
are
"
planned"
or
"
unplanned"
with
respect
to
the
AMA.
However,
this
commenter
stated
that
there
should
be
a
separate
NSR
exclusion
for
repair
and
replacement
resulting
from
catastrophic
occurrences.
Sources
need
to
repair
and
replace
units,
possibly
at
tremendous
cost,
and
simply
cannot
go
through
NSR.


One
commenter
(
1160)
recommended
that
the
safeguard
remain
that
no
increase
in
hourly
emission
rates
would
be
allowed
without
triggering
NSPS.
The
commenter
noted
that
in
the
utility
industry,
events
of
unanticipated
shutdown
of
equipment
due
to
component
or
catastrophic
failures
are
referred
to
as
forced
outages.
This
commenter
stated
that
treating
forced
outage
projects
separately
from
the
AMA
and
ERP
approaches
is
sensible
and
works
best
because
by
definition
forced
outage
events
are
unplanned.
The
commenter
believed
EPA
is
assuming
that
if
forced
outage
costs
are
excluded
from
the
AMA,
they
would
be
subject
to
caseby
case
RMRR
review
and
said
this
is
precisely
the
wrong
result,
because
case­
bycase
RMRR
review
is
too
long
and
no
longer
workable.
The
commenter
added
that
companies
should
be
required
to
report
to
their
pertinent
regulatory
agency
about
the
repairs
or
replacements
that
they
undertake
to
fix
forced
outage
damage,
including
providing
information
about
the
forced
outage
itself.


Without
an
exclusion,
said
one
commenter
(
1465),
delays
of
1
to
2
years
could
be
incurred
to
undergo
NSR
prior
to
initiating
construction
to
re­
establish
manufacturing
capacity.

One
industry
commenter
(
897)
suggested
that
costs
from
natural
disasters,
accidents,
intentional
sabotage
and
inadequate
workmanship
be
excluded
from
any
NSR
review
as
long
as
these
projects
include
like­
kind
replacement
of
equipment,
do
not
increase
production,
and
do
not
increase
emissions.
The
commenter
believed
in
some
situations
the
environment
and
safety
can
be
at
risk
if
a
facility
cannot
immediately
proceed
with
these
types
of
projects
without
risk
of
noncompliance
issues.

Two
industry
commenters
(
1023,
1130)
recommended
addressing
projects
required
to
respond
to
unanticipated
forced
outages
or
catastrophic
events
under
the
capacity­
and
age­
based
options.
However,
if
EPA
decided
not
to
adopt
a
capacity­
or
age­
based
RMRR
approach,
the
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commenters
recommended
exempting
these
types
of
equipment
repair
or
replacement
projects
from
NSR,
provided
the
new
equipment
is
as
clean
or
cleaner
from
an
air
emissions
standpoint.
Additionally,
the
commenters
believed
any
permits
needed
to
enforce
this
requirement
should
not
require
emission
offsets
in
nonattainment
areas.

Response:

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
under
the
ERP
or
for
another
exclusion
from
major
NSR
in
their
applicable
rules.
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.

3.12
How
to
Treat
Non­
emitting
Units
Comment:

3.12.1
General
Support
for
Excluding
Non­
emitting
Units
From
ERP
Many
industry
commenters
(
506,
558,
910,
951,
1001,
1050,
1096,
1098,
1099,
1100,
1129,
1138,
1212,
1213,
1367,
1368)
and
one
State/
local
commenter
(
1199)
supported
excluding
non­
emitting
equipment
from
the
ERP
approach.
One
commenter
(
506)
stated
that
triggering
the
NSR
review
process
for
maintenance
activities
is
an
impediment
to
continuous
improvement
projects
for
certain
products
and
process,
even
if
actual
emissions
decrease
or
only
non­
emitting
units
on
the
process
line
are
affected.
Delays
or
postponements
of
project
maintenance
work
adversely
affect
the
reliability,
safety
and
productivity
of
operations
and
cost
control
efforts.
Two
industry
commenters
(
1098,
1099)
suggested
that
EPA
develop
a
list
specific
to
each
industry
that
qualifies
as
non­
emitting
equipment
or
processes.
One
commenter
(
1212)
recommended
that
work
at
clearly
non­
emitting
units,
specifically
including
foundation
regrouting
and
repair
and
frametop
replacement,
should
be
excluded
from
the
ERP.
Two
commenters
(
1213,
1368)
noted
that
an
economizer
is
an
example
of
a
non­
emitting
component
that
should
be
excluded
from
the
ERP.
Three
commenters
(
1050,
1213,
1368)
believed
that
non­
emitting
units
cannot
result
in
an
increase
of
emissions
and
thus
do
not
need
to
be
evaluated
under
NSR.
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One
industry
commenter
(
1399)
agreed
with
the
EPA
proposal
that
the
source
for
an
EUSGU
would
consist
of
those
portions
of
the
plant
that
contribute
directly
to
the
production
of
electricity
and
would
exclude
all
non­
emitting
activities.

Several
industry
commenters
(
1079,
1091,
1110,
1132,
1137,
1292)
believed
that
EPA
should
authorize
sources
to
determine
whether
non­
emitting
units/
components
should
be
excluded
from
the
ERP.
One
commenter
(
1137)
believed
that
a
blanket
exclusion
could
create
problems
of
interpretation
because
the
term
"
non­
emitting
components"
is
ambiguous
when
considering
certain
components.
Another
industry
commenter
(
1110),
while
conceding
that
conceptually
exclusion
of
non­
emitting
units
seems
reasonable,
indicated
that
this
could
become
a
very
burdensome
activity.
The
commenter
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.
The
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).
The
commenter
also
suggested
that
some
major
investments
that
are
non­
emitting
(
such
as
office
buildings)
can
be
readily
identified.
For
these
components
or
units,
a
facility
may
want
to
remove
the
maintenance
cost
and
investment
from
the
analysis.

One
industry
commenter
(
1463)
believed
that
non­
emitting
units
should
be
excluded,
but
only
for
purposes
of
determining
whether
the
reconstruction
safeguard
has
been
exceeded.
NSR
emission
impacts
are
evaluated
on
an
emissions
unit
basis
as
opposed
to
a
process
unit
basis.
This
commenter
stated
that
for
the
purpose
of
determining
whether
a
unit
has
been
reconstructed,
EPA
should
provide
an
option
to
perform
the
calculation
on
an
emissions
unit
basis.
This
approach
would
eliminate
reconstruction
evaluations
of
projects
that
primarily
affect
non­
emitting
process
equipment.
For
all
other
purposes,
calculations
would
be
performed
on
a
process
unit
basis.

One
industry
commenter
(
841)
believed
that
activities
that
involve
non­
emitting
units
whose
actions
would
not
affect
an
emitting
unit
are
clearly
outside
the
purpose
of
the
RMRR
rule
and
carry
no
significance
in
NSR
applicability
determinations.
The
commenter
also
believed
that
any
activities
to
a
non­
emitting
unit
that
do
affect
an
emitting
unit,
either
upstream
or
downstream
of
the
process,
are
already
subject
to
NSR
applicability.

3.12.2
Oppose
Excluding
Non­
emitting
Units
From
ERP
Two
industry
commenters
(
902,
1141)
did
not
support
requirements
to
apply
the
ERP
to
non­
emitting
components
unless
these
components
have
the
potential
to
affect
capacity
or
the
nature
of
emissions
from
upstream
or
downstream
emissions
units.
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One
industry
commenter
(
1066)
believed
it
would
be
simpler
to
include
non­
emitting
equipment
when
determining
the
replacement
cost
of
a
process
unit,
due
to
the
difficulty
in
separating
the
costs
of
emitting
and
non­
emitting
equipment.
The
commenter
also
believed
it
would
be
difficult
to
determine
allocation
of
shared
equipment
in
the
cost
analysis.

Two
industry
commenters
(
1023,
1130)
stated
that
equipment
changes
involving
RMRR
of
non­
emitting
units
on
process
lines
should
not
be
subject
to
the
ERP.
Rather,
they
should
be
categorically
exempted
from
NSR
permitting
requirements,
unless
the
project
debottlenecks
a
process
unit
and
results
in
an
increase
in
actual
emissions.
One
industry
commenter
(
840)
similarly
suggested
that
non­
emitting
units
should
be
exempt
from
NSR.

Response:

An
exclusion
from
counting
costs
under
the
ERP
for
non­
emitting
units
could
create
problems
of
interpretation
because
the
term
"
non­
emitting
components"
is
ambiguous
when
considering
certain
components.
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
nonemitting
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
the
final
rule.
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1
Chapter
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
4.1
Overview
In
the
RMRR
proposal
preamble,
we
discussed
and
solicited
comment
on
two
potential
RMRR
approaches
for
which
we
did
not
propose
regulatory
language:
(
1)
a
capacity­
based
option,
and
(
2)
an
age­
based
option.
We
received
public
comments
supporting
and
opposing
both
these
options,
which
are
summarized
below
in
sections
4.2
(
capacity­
based
option)
and
4.3
(
agebased
option).
Comments
in
favor
of
and
against
retaining
the
case­
by­
case
approach
for
RMRR
are
summarized
below
in
section
4.4.
Some
commenters
suggested
other
RMRR
approaches;
these
comments
are
summarized
below
in
section
4.5.

4.2
Capacity­
based
Option
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.
The
primary
objective
of
RMRR
is
to
keep
a
unit
operating
at
capacity
and/
or
availability.
In
addition,
the
linkage
between
capacity
and
environmental
impact
is
more
apparent
than
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.

Comment:

4.2.1
Support
Capacity­
based
Option
A
number
of
industry
commenters
(
840,
865,
900,
920,
921,
951,
1000,
1005,
1013,
1045,
1050,
1052,
1077,
1078,
1090,
1098,
1099,
1112,
1123,
1126,
1129,
1130,
1136,
1145,
1159,
1160,
1213,
1237,
1282,
1356,
1368,
1392,
1399,
1441,
1469,
1620,
1629,
1792)
supported
a
capacity­
based
option.
These
commenters
generally
indicated
that
a
capacity­
based
option
would
be
simpler
and
less
burdensome
to
use
than
the
AMA,
and
some
also
stated
that
it
would
be
simpler
than
the
ERP.
Among
these
supporters,
some
preferred
the
capacity­
based
option
over
the
both
AMA
and
ERP,
some
preferred
the
capacity­
based
option
in
combination
with
the
ERP,
and
some
preferred
the
capacity­
based
option
in
addition
to
the
AMA
and
ERP.

Some
of
these
industry
commenters
(
1078,
1213,
1469)
indicated
that
it
would
be
no
more
difficult
to
implement
a
capacity­
based
option
than
the
AMA
or
ERP.
Some
commenters
(
1213,
1469)
stated
that
the
most
difficult
aspects
of
a
capacity­
based
option
are
(
1)
determining
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
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2
the
maximum
achievable
hourly
emissions
rate
(
which
also
must
be
determined
for
the
AMA),
and
(
2)
determining
capacity
(
which,
in
the
form
of
the
basic
design
parameters,
must
also
be
determined
for
the
ERP).

Some
of
the
industry
commenters
(
1126,
1441)
strongly
supported
a
properly
designed,
simple
capacity­
based
approach
with
enforceable
parameters
specific
to
power
plants.
These
commenters
proposed
detailed
modifications
to
the
approach
discussed
in
the
preamble,
with
a
focus
only
on
power
plants.
Their
proposed
approach
had
the
following
structure.


The
capacity­
based
option
could
be
used
for
any
project
that
met
all
the
following
conditions.

 
The
project
does
not
require
installation
of
an
entirely
new
unit
or
entirely
new
replacement
unit.
 
The
cost
of
the
project
does
not
exceed
50
percent
of
the
capital
cost
of
a
comparable
entirely
new
process
unit.
 
The
project
does
not
result
in
an
increase
in
the
maximum
achievable
hourly
emissions
or
maximum
unit
design
capacity.
 
The
plant
files
a
request
for
a
determination
of
NSR
applicability,
and
receives
a
notice
of
non­
applicability
from
the
air
pollution
control
agency,
prior
to
commencing
construction.


The
capacity­
based
option
should
be
enforceable
based
on
metrics
already
required
and
reported
under
existing
EPA
regulations,
whenever
possible.


The
basis
for
determining
such
RMRR
exclusion
always
should
be
emissions;
only
RMRR
activities
having
an
impact
on
emissions
need
be
subject
to
NSR.


The
capacity­
based
option
should
not
require
sources
to
establish
a
complex
and
burdensome
accounting
system.


Projects
that
do
not
qualify
for
the
capacity­
based
option
could
still
qualify
under
the
equipment
replacement
option
or
the
case­
by­
case
option.

These
commenters
(
1126,
1441)
made
the
following
assertions
about
their
proposed
capacity­
based
approach.


The
capacity­
based
approach,
taken
together
with
the
proposed
ERP
and
the
existing
case­
by­
case
approach,
would
address
the
full
spectrum
of
RMRR
for
the
utility
industry.
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
3

If
adopted,
the
proposed
approach
would
be
simpler
than
the
proposed
AMA
approach
and
could
serve
to
replace
that
approach.

Some
industry
commenters
(
840,
1356,
1620)
explicitly
supported
the
safeguards
presented
in
our
RMRR
proposal
for
a
capacity­
based
option.

A
number
of
industry
commenters
presented
ideas
on
the
basis
on
which
changes
in
capacity
should
be
determined.

°
Some
commenters
(
1356,
1620)
suggested
the
maximum
achievable
hourly
emissions
rate.
One
of
the
commenters
(
1620)
specified
that
the
baseline
emissions
rate
should
be
determined
based
on
a
5­
year
look
back
period.

°
One
commenter
(
1013)
suggested
maximum
hourly
emissions,
stating
that
this
is
the
most
appropriate
surrogate
for
a
change
in
capacity
because
it
is
consistent
with
existing
NSPS
procedures
and
with
averaging
periods
for
ambient
air
quality
monitoring
and
standards.


One
commenter
(
1392)
suggested
maximum
potential
hourly
emissions,
based
on
a
5­
year
look
back
period.


Some
commenters
(
920,
921,
1000,
1123)
stated
that
capacity
can
be
easily
determined
for
boilers
as
the
steam
production
or
heat
input;
for
other
types
of
processes,
one
can
use
unit
of
output
per
unit
of
time.
In
both
cases,
the
commenters
suggested
using
historical
operation
 
based
on
source
tests
and
operating
records
 
to
determine
capacity.


One
commenter
(
1129)
suggested
using
the
maximum
steaming
capacity
of
the
process
unit.


One
commenter
(
840)
indicated
that
in
their
industry,
capacity
is
clearly
defined
by
the
ore
feed
rate
and
the
soda
ash
production
rate,
which
are
already
tracked
and
reported
and
serve
as
the
basis
for
determining
the
maximum
achievable
hourly
emission
rate.


One
commenter
(
1629)
suggested
the
maximum
hourly
heat
input
for
utilities,
based
on
a
5­
year
look
back
period.


One
commenter
(
1078)
suggested
the
recent
and
expected
maximum
heat
input.

Some
industry
commenters
(
1050,
1112,
1213,
1282,
1368,
1469)
supported
a
capacitybased
option
provided
that
the
maximum
achievable
hourly
emissions
rate
safeguard
was
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
4
determined
based
on
a
reasonable
look
back
period
(
i.
e,
5
years
for
utilities),
the
source
retains
the
responsibility
for
determining
unit
capacity,
and
the
rule
uses
input
capacity
(
not
output­
based
measures)
for
determining
capacity.
Similarly,
some
other
industry
commenters
(
1136,
1159)
supported
a
capacity­
based
option
as
long
as
capacity
is
based
on
input,
not
output;
otherwise,
they
contended,
this
option
would
not
be
consistent
with
the
goal
of
enabling
efficiency
improvements.

One
industry
commenter
(
1792)
supported
a
capacity­
based
approach
only
if
a
stand­
alone
exclusion
for
activities
that
promote
efficiency
was
also
promulgated.
Otherwise,
the
commenter
asserted,
a
capacity­
based
approach
could
prevent
utilities
from
performing
activities
that
make
the
facilities
more
efficient.
Similarly,
another
industry
supporter
of
a
capacity­
based
approach
(
1098)
indicated
that
the
RMRR
provisions
may
need
to
include
some
form
of
the
other
approaches
to
account
for
energy
efficiency
projects
at
utilities,
which
could
increase
capacity.

One
industry
commenter
(
1099)
supported
the
capacity­
based
option
"
so
long
as
the
owner
of
the
unit
can
use
a
sufficient
look
back
period
that
is
representative
of
unit
operation
on
an
hourly
basis."
This
commenter
suggested
that
the
5­
year
look
back
test
used
in
the
NSPS
hourly
emissions
increase
test
would
be
appropriate.
However,
the
commenter
did
not
specify
whether
this
comment
is
related
to
determining
the
baseline
for
a
capacity
increase
or
for
the
safeguard
that
would
not
allow
an
increase
in
the
maximum
achievable
hourly
emissions
rate.

One
industry
commenter
(
1090)
who
supports
a
capacity­
based
option
asserted
that
the
option
should
be
implemented
at
the
stationary
source
or
process
unit
level.
The
commenter
indicated
that
many
sources
in
the
mining
industry
have
permitted
capacities
at
these
plant
levels.

One
industry
commenter
(
1237)
urged
us
to
continue
considering,
in
addition
to
the
AMA
and
ERP,
the
option
of
defining
RMRR
as
any
changes
in
a
process
unit
that
do
not
increase
the
unit's
maximum
capacity.
The
commenter
believed
this
approach
may
be
more
workable
for
some
industries
(
e.
g.,
electric
utilities)
than
others
but
could
have
benefits
in
conjunction
with
the
AMA
and
ERP.

One
industry
commenter
(
1130)
said
a
combination
of
capacity­
and
age­
based
options
would
provide
an
effective
foundation
for
the
RMRR
rule.
The
commenter
recommended
making
the
capacity­
based
option
available
to
all
facilities
on
an
equipment­
specific
basis
until
the
equipment
is
completely
depreciated
based
on
IRS
guidelines.
This
approach
could
also
be
used
to
address
projects
required
to
respond
to
unanticipated
forced
outages
and
catastrophic
events.
Under
this
option,
any
repairs
or
maintenance
designed
to
recover,
but
not
exceed,
the
original
design
capacity
of
the
equipment
would
be
exempt
from
NSR
until
the
equipment
is
fully
depreciated.
After
that
point
in
time,
annual
repair
and
maintenance
projects
would
be
eligible
for
NSR
exemptions
if
costs
incurred
did
not
exceed
the
facility's
AMA.

4.2.2
Oppose
Capacity­
based
Option
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
5
A
number
of
industry
(
900,
902,
1001,
1082,
1096,
1110,
1114,
1132,
1137,
1138,
1211,
1238,
1367,
1463,
1798,
1866),
State/
local
(
1107,
1268,
1270,
1361,
1443),
and
environmental
(
1150)
commenters
opposed
a
capacity­
based
option.
Their
reasons
for
opposing
this
option
included
the
following.


It
is
often
difficult
to
define
the
capacity
of
a
process
unit.
(
Industry
commenters
1110,
1132,
1238,
1463)


It
would
not
exempt
efficiency
projects.
Encouraging
efficiency
improvements
was
a
primary
purpose
for
NSR
reform.
(
Industry
commenters
1110,
1132,
1463,
1798)


It
would
not
be
workable
at
complex
manufacturing
sources.
(
Industry
commenter
1114)


"
Capacity"
is
a
useful
shorthand
term
for
the
processing
capability
of
a
petroleum
process
unit,
but
it
usually
correlates
exactly
only
with
a
historical
feed
or
product
slate
no
longer
available
or
made.
Thus
it
would
not
serve
well
as
a
threshold
for
determining
applicability
of
the
RMRR
exclusion.
(
Industry
commenter
1301)


It
would
be
inconsistent
with
the
statutory
definition
of
modification.
(
Environmental
commenter
1150)


It
would
be
too
complex.
(
Industry
commenter
902,
State/
local
commenter
1107)


It
appears
to
be
covered
by
the
actual­
to­
projected­
actual
test.
(
State/
local
commenter
1270)


It
would
be
arbitrary.
(
State/
local
commenter
1443)


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.
(
Industry
commenter
1866)


Projects
that
do
not
increase
capacity
may
nonetheless
be
nonroutine
and
may
result
in
significant
air
quality
impacts.
(
State/
local
commenter
1268)


The
proposal
is
too
vague
for
informed
comment.
To
be
acceptable,
a
capacitybased
approach
would
have
to
be
independent
of
the
AMA
and/
or
ERP
and
would
have
to
be
subject
to
the
safeguards
proposed
for
the
AMA.
(
State/
local
commenter
1361)
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
6
Some
industry
commenters
(
1124,
1131,
1133)
asserted
that
EPA
should
not
establish
a
mandatory
capacity­
based
approach.
However,
these
commenters
did
not
oppose
it
as
a
voluntary
approach
that
sources
could
choose.

Response:

We
agree
with
commenters
that,
in
principle,
a
capacity
basis
for
RMRR
might
be
easier
to
use
before
beginning
actual
construction
than
some
of
the
cost­
based
approaches.
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.

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.

4.3
Age­
based
Option
We
also
proposed
an
age­
based
approach
to
the
RMRR
exclusion.
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.

Comment:

4.3.1
Support
Age­
based
Option
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
7
One
environmental
commenter
(
540)
stated
that
EPA
should
establish
a
normal
lifetime,
tailored
to
each
industry,
beyond
which
industry
would
need
to
install
BACT
or
shut
down.

One
State/
local
commenter
(
1268)
indicated
that
an
age­
based
NSR
trigger
is
a
potentially
useful
mechanism
to
provide
certainty
that
old,
high­
emitting
equipment
will
eventually
be
shut
down
or
upgraded
to
BACT.
The
commenter
believed
that
such
certainty
can
justify
substantial
flexibility
for
certain
modifications.
The
commenter
suggested
that
age­
based
NSR
could
be
combined
with
capacity
limitations
to
allow
many
modifications
to
occur
in
the
interim
without
NSR.
As
a
condition
of
such
flexibility,
the
commenter
stated,
the
facility
would
need
to
be
modeled
at
maximum
potential
emissions
and
demonstrate
protection
of
air
quality.
Furthermore,
the
commenter
indicated,
EPA
would
need
to
re­
propose
the
rule
with
specific
provisions
to
allow
interested
parties
the
opportunity
to
make
meaningful
comment
before
adopting
any
agebased
exemption
component
to
the
NSR
program.

One
industry
commenter
(
1130)
said
a
combination
of
capacity­
and
age­
based
options
would
provide
an
effective
foundation
for
the
RMRR
rule.
The
commenter
recommended
making
the
capacity­
based
option
available
to
all
facilities
on
an
equipment­
specific
basis
until
the
equipment
is
completely
depreciated
based
on
IRS
guidelines.
This
approach
could
also
be
used
to
address
projects
required
to
respond
to
unanticipated
forced
outages
and
catastrophic
events.
Under
this
option,
any
repairs
or
maintenance
designed
to
recover,
but
not
exceed,
the
original
design
capacity
of
the
equipment
would
be
exempt
from
NSR
until
the
equipment
is
fully
depreciated.
After
that
point
in
time,
annual
repair
and
maintenance
projects
would
be
eligible
for
NSR
exemptions
if
costs
incurred
did
not
exceed
the
facility's
AMA.

4.3.2
Oppose
Age­
based
Option
A
number
of
industry
(
797,
900,
902,
920,
921,
942,
1000,
1001,
1013,
1050,
1078,
1082,
1083,
1086,
1096,
1098,
1099,
1110,
1112,
1114,
1123,
1124,
1126,
1129,
1131,
1132,
1133,
1134,
1136,
1137,
1138,
1159,
1160,
1211,
1213,
1237,
1238,
1301,
1367,
1368,
1395,
1399,
1441,
1463,
1465,
1629,
1792,
1793,
1798,
1866),
State/
local
(
1107,
1270,
1361,
1443),
and
environmental
(
1150)
commenters
opposed
an
age­
based
option.
Their
reasons
for
opposing
this
option
included
the
following.


The
age
of
a
source
alone
is
not
a
legitimate
reason
to
require
the
addition
of
pollution
control
equipment;
age
has
no
bearing
on
a
unit's
environmental
impact;
some
facilities
maintain
equipment
better
than
others.
(
Industry
commenters
900,
920,
921,
1000,
1123,
1159)


There
is
not
a
legal
basis
for
specifying
levels
of
controls
based
on
a
unit's
age.
(
Industry
commenters
1078,
1099,
1129,
1213;
environmental
commenter
1150)
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
8

It
is
not
consistent
with
Congressional
intent.
(
Industry
commenters
1050,
1213,
1629)


Proper
maintenance
of
equipment
may
extend
its
life,
and
should
be
encouraged.
An
age­
based
option
would
discourage
this.
(
Industry
commenters
1114,
1798)


This
option
would
discriminate
against
industries
with
equipment
that
has
a
long
useful
life.
(
Industry
commenter
1238)


The
age
of
a
process
unit
is
an
ambiguous
concept.
Questions
arise
about
the
procedure
for
calculating
a
unit's
age.
It
is
not
uncommon
to
transfer
usable
equipment
from
a
decommissioned
process
unit
to
a
new
one,
or
to
purchase
used
process
equipment
from
another
party.
(
Industry
commenter
1301)


It
would
be
difficult
to
implement
on
a
consistent
and
equitable
basis.
(
Industry
commenters
902,
1110,
1132,
1160,
1463,
1866;
State/
local
commenter
1107)


The
age­
based
option
of
25­
50
years
is
very
arbitrary
and
not
workable.
(
Industry
commenters
1110,
1132;
State/
local
commenter
1443)


It
would
arbitrarily
put
an
unnecessary
burden
on
older
plants
and
would
not
improve
the
reliability,
safety,
or
efficiency
of
the
nation's
energy
system.
(
Industry
commenter
1441)


Economics
and
technological
advancement
determine
the
useful
life
of
a
process
unit.
To
impose
an
arbitrarily
defined
"
useful
life"
at
the
end
of
which
controls
are
required
imposes
unnecessary
economic
burdens
and
places
U.
S.
manufacturing
capacity
at
a
competitive
disadvantage
in
global
markets.
(
Industry
commenters
1465,
1793)


Many
industrial
facilities
already
have
equipment
that
is
more
than
50
years
old.
The
only
way
the
option
could
work
is
to
start
the
clock
from
the
date
of
rule
promulgation.
(
Industry
commenter
1013)


Due
to
economic
and
other
constraints,
the
lifetime
of
a
unit
cannot
be
precisely
defined.
The
lifetime
of
an
electric
generating
boiler
is
defined
by
the
care
taken
to
maintain
it,
consumer
demand,
the
size
of
the
system,
the
local
climate,
and
economics
of
replacing
the
unit,
among
other
factors.
If
the
life
of
a
unit
is
defined
for
the
purposes
of
air
pollution
regulation,
it
may
establish
an
unwillingness
to
upgrade
and
modernize
with
pollution
controls
because
it
may
not
be
possible
to
recapture
the
costs
of
these
investments.
(
Industry
commenter
1136)
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
9

The
useful
lifetime
of
a
piece
of
production
equipment
or
of
an
industrial
boiler,
water
treatment
plant,
or
physical
plant
is
defined
by
the
care
taken
to
maintain
it,
consumer
demand
for
the
product
it
produces,
the
nature
of
the
process
and
product
(
i.
e.,
heavy
industry
versus
light
industry),
the
economics
of
replacing
the
unit
or
abandoning
a
production
process,
and
many
other
factors.
(
Industry
commenter
1134)


It
could
result
in
non­
routine
activities
being
undertaken.
(
Industry
commenter
902)


It
would
allow
companies
to
piece­
meal
a
brand
new
plant
in
a
relatively
short
time
period.
(
State/
local
commenter
1270)


Process
units
can
maintain
productive
capacity,
efficiency,
and
environmental
performance
well
beyond
what
might
be
assumed.
Sources
should
not
be
penalized
for
their
prudent
decisions
to
extend
the
productive
life
of
their
facilities
as
necessary
to
remain
competitive
in
the
global
marketplace.
(
Industry
commenter
1866)


It
would
significantly
delay
promulgation
of
the
RMRR
rule.
(
Industry
commenter
1211)


Environmental
impacts,
not
the
age
of
the
unit,
must
be
the
basis
for
any
applicability
determinations.
(
State/
local
commenter
1361)

Response:

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
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
age­
based
approach
would
discriminate
against
them.

We
are
disinclined
to
establish
a
normal
lifetime,
tailored
to
each
industry,
beyond
which
industry
would
need
to
install
BACT
or
shut
down,
as
one
commenter
suggested,
because
this
type
of
approach
would
obviously
require
a
substantial
amount
of
time.

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
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
10
maintain
equipment
better
than
others.
We
have
several
basic
concerns
with
the
age­
based
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
an
age­
based
approach.

4.4
Retaining
Case­
by­
case
Approach
Since
its
inception,
the
RMRR
exclusion
has
been
applied
on
a
case­
by­
case
basis.
In
interpreting
this
exclusion,
we
have
followed
certain
criteria.
The
preamble
to
the
1992
"
WEPCO
Rule"
(
57
FR
32314)
and
applicability
determinations
made
to
date
describe
our
current
approach
to
assessing
what
activities
constitute
RMRR.
These
applicability
determinations
are
available
electronically
from
the
Region
7
NSR
Policy
and
Guidance
Database
(
http://
www.
epa.
gov/
Region7/
programs/
artd/
air/
nsr/
nsrpg.
htm).
Other
relevant
documents
include
decisions
by
EPA's
Environmental
Appeals
Board
and
court
briefs
filed
on
behalf
of
EPA.
The
EAB
decisions
can
be
found
on
EPA's
website
(
http://
www.
epa.
gov/
eab/).
To
summarize
these
documents,
to
determine
whether
proposed
work
at
a
facility
is
RMRR,
the
reviewing
authority
made
a
case­
by­
case
determination
weighing
the
nature,
extent,
purpose,
frequency,
and
the
cost
of
the
work
as
well
as
other
relevant
factors
to
arrive
at
a
common­
sense
finding.
See
also
Wisconsin
Electric
Power
Company
(
WEPCO)
v.
Reilly,
893
F.
2d
901,
910
(
Seventh
Cir.
1990).
None
of
these
factors,
in
and
of
itself,
was
conclusive.
Instead,
a
reviewing
authority
would
take
account
of
how
each
of
these
factors
might
apply
in
a
particular
circumstance
to
arrive
at
a
conclusion
considering
the
project
as
a
whole.
If
an
owner
or
operator
was
uncertain
whether
he
or
she
is
applying
the
NSR
regulations
correctly,
we
encouraged
the
owner
or
operator
to
consult
the
appropriate
reviewing
authority
for
assistance.

Comment:

4.4.1
Support
Retaining
Case­
by­
case
Approach
A
number
of
industry
(
814,
941,
1001,
1045,
1069,
1077,
1091,
1100,
1112,
1124,
1134,
1136,
1137,
1199.
1201,
1202,
1204,
1236,
1292,
1392,
1399,
1441,
1797,
1866,
1868),
State/
local
(
838,
912,
946,
1012,
1033,
1206,
1240,
1268,
1361,
1366,
1464,
1471,
1622,
1643),
and
university
(
901,
1442,
1477)
commenters
supported
retaining
the
case­
by­
case
approach
for
determining
whether
an
activity
is
RMRR.
These
commenters
variously
referred
to
the
case­
bycase
approach
as
the
four­
factor
approach,
the
five­
factor
approach,
the
multi­
factor
approach,
the
narrative
WEPCO
test,
and
Detroit
Edison.
Some
commenters
were
explicit
in
their
support,
while
others
implicitly
supported
this
approach
in
assuming
that
it
would
apply
if
an
activity
did
not
qualify
for
an
automatic
exclusion
under
the
other
proposed
approaches.

Several
of
the
supportive
commenters
had
suggestions
for
clarifying
the
case­
by­
case
approach.
These
suggestions
included
the
following.
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
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August
6,
2003
Do
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quote,
cite,
copy,
or
distribute
4­
11

Clarify
that
it
is
supposed
to
exclude
from
NSR
any
activity
intended
to
maintain,
facilitate,
restore,
improve
the
efficiency,
reliability,
availability
or
safety.
Clarify
the
test
to
introduce
replicability
and
predictability
into
the
system.
(
Industry
commenters
1001,
1078,
1201,
1202,
1292,
1399)


Clarify
that
frequency
is
not
a
dispositive
factor
under
the
case­
by­
case
approach.
(
Industry
commenter
1001)


Create
guidelines
for
how
applicability
determinations
requests
should
be
processed.
For
example,
we
should
commit
to
requesting
all
additional
information
within
21
days
and
a
final
response
within
30
days
of
receipt
of
all
information.
(
Industry
commenters
1001,
1202)


Affirmatively
state
that
it
is
to
be
used
specifically
for
applying
a
broader
definition
of
RMRR
than
provided
under
other
approaches.
(
Industry
commenters
814,
1078,
1204)


Clarify
that
the
consideration
of
RMRR
criteria
should
be
based
on
routine
events
for
an
industry,
not
for
an
individual
facility.
When
a
repair
or
replacement
is
necessary,
the
commenter
considers
situation­
specific
factors
that
include
among
others
cost,
reliability,
efficiency,
and
performance.
Given
the
complexity
of
the
commenter's
facilities,
a
specific
device
or
solution
may
be
installed
only
once
in
a
given
facility,
even
if
it
is
a
routine
choice
across
the
industry.
Without
this
clarification,
projects
considered
routine
based
on
industry
practice
and
common
sense
could
be
disallowed
based
on
frequency
at
an
individual
facility.
(
Industry
commenter
1868)


In
considering
the
"
purpose"
of
an
activity,
weight
should
be
given
to
the
improvement
of
efficiency,
safety,
and
reliability.
The
commenter
noted
that
in
the
proposal's
discussion
of
the
equipment
replacement
option,
we
identified
many
of
the
reasons
why
identical
replacements
are
not
always
possible
or
desirable.
The
commenter
believed
that
discussion
is
accurate,
should
apply
to
case­
by­
case
determinations
as
well,
and
provides
ample
justification
that
these
elements
should
be
given
weight
during
evaluation
of
a
project's
purpose.
(
Industry
commenter
1868)


Evaluate
case­
by­
case
projects
under
the
so­
called
narrative
test
articulated
in
the
WEPCO
determinations
issued
by
EPA
in
1988
and
1989.
The
commenter
urged
EPA
to
reinstate
these
determinations
and
not
the
14­
criteria
"
Detroit
Edison"
determination
as
the
principle
articulation
of
the
"
narrative
case­
by­
case"
test.
The
commenter
wanted
the
case­
by­
case
determination
to
be
available
for
projects
such
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
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and
Deliberative
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August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
12
as
turbine
rebuilds
that
are
routine
but
would
not
satisfy
either
the
AMA
or
ERP
proposed
tests.
(
Industry
commenter
1136)


Codify
criteria
for
characterizing
whether
a
change
is
routine,
based
on
the
criteria
relied
upon
in
current
case­
by­
case
determinations
and
including
safeguards
against
changes
likely
to
increase
emissions.
(
State/
local
commenters
1268,
1471)
Commenter
1268
favors
this
action
in
conjunction
with
development
of
two
lists
for
each
major
industrial
sector
to
identify
activities
that
would
and
would
not
be
considered
routine;
the
clarified
case­
by­
case
approach
would
be
used
for
activities
that
do
not
appear
on
either
list.


Improve
implementation
of
case­
by­
case
determinations
by
using
simple,
online
forms.
(
State/
local
commenter
1361)

One
association
of
local
agencies
(
1206)
that
does
not
support
the
RMRR
proposals
stated
that
we
have
not
presented
a
convincing
argument
that
there
is
a
problem
with
the
current
framework
for
implementing
RMRR
(
i.
e.,
the
case­
by­
case
approach).
The
commenter
indicated
that
an
informal
poll
of
its
members
shows
there
are
very
few
issues
with
case­
by­
case
assessments
of
RMRR.
The
commenter
suggested
that
we
should
consult
with
the
permitting
agencies
to
verify
industry­
provided
examples
of
problems
with
the
current
system.

One
State/
local
commenter
(
1643)
recommended
that
we
restrict
the
case­
by­
case
approach
by
limiting
the
number
of
activities
or
their
total
cost.

4.4.2
Oppose
Retaining
Case­
by­
case
Approach
An
environmental
commenter
(
1150)
generally
did
not
support
an
RMRR
exclusion.

Response:

The
final
rule
allows
the
option
for
an
owner
or
operator
to
chose
to
use
the
ERP
for
determining
whether
activities
at
their
facility
are
RMRR.
The
rule,
however,
also
retains
the
case­
by­
case
approach.
Under
the
final
rule,
the
case­
by­
case
approach
can
continued
to
be
used
by
an
owner
or
operator
to
determine
if
activitites
at
their
source
are
RMRR.
It
also
will
continue
to
be
used
by
an
owner
or
operator
to
determine
whether
activities
at
their
source
which
do
not
fall
within
the
ERP
and,
therefore
need
closer
scrutiny,
are
RMRR.
We
believe
it
is
essential
to
retain
the
case­
by­
case
approach
for
these
purposes.
There
may
be
sources
where
the
ERP
is
not
an
effective
and
less
burdensome
means
for
determining
whether
activities
are
RMRR.
It
is
important
to
allow
owners
or
operators
of
these
types
of
sources
the
right
to
use
the
case­
by­
case
approach.
It
is
also
critical
to
retain
the
case­
by­
case
approach
for
reviewing
activities
which
do
not
fall
within
the
ERP.
These
activities
while
of
greater
cost
still
may
4
­
Approaches
for
RMRR
Other
than
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AMA
or
ERP
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and
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2003
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copy,
or
distribute
4­
13
qualify
as
RMRR
when
all
of
the
factors
are
evalusted
and
it
is
important
to
retain
the
approach
for
this
purpose.

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
meantime,
the
case­
by­
case
approach
will
remain
available
to
use
as
an
alternative
and/
or
supplement
to
the
ERP.

The
ERP
we
are
finalizing
will
allow
a
source
to
make
a
simple
determination
as
to
whether
a
replacement
piece
of
equipment
is
identical
or
not.
This
type
of
determination
will
be
straightforward
and
easier
for
most
owners
or
operators
to
implement
than
the
current
case­
bycase
analysis
required
to
determine
whether
a
replacement
is
routine.

4.5
Comments
on
Other
Options
Comment:

4.5.1
Exclude
Activities
Properly
Classified
as
an
"
Expense"
on
the
Source's
Federal
Income
Taxes
Several
industry
commenters
(
906,
927,
941,
942,
1000,
1001,
1079,
1083,
1091,
1097,
1109,
1110,
1123,
1124,
1131,
1132,
1133,
1134,
1137,
1138,
1149,
1200,
1211,
1283,
1363,
1395,
1868)
suggested
allowing
automatic
RMRR
status
for
any
activity
properly
classified
as
an
expense
(
as
opposed
to
a
capital
expenditure)
on
a
source's
Federal
income
tax
return.
One
of
these
industry
commenters
(
1083)
listed
several
examples
of
expensed
RMRR
items.

A
State/
local
commenter
(
1643)
asserted
that
if
we
promulgate
a
cost­
based
allowance,
it
would
be
better
to
allow
only
those
costs
submitted
to
the
IRS
as
maintenance
to
be
exempt
from
NSR.
The
commenter
preferred
this
approach
so
that
reviewing
authorities
could
rely
on
trained
IRS
personnel
to
assure
that
the
work
performed
was
indeed
RMRR.

The
industry
proponents
of
this
approach
generally
indicated
that
activities
that
are
"
expensed"
under
IRS
regulations
clearly
fall
within
the
intent
of
the
RMRR
exclusion.
As
support,
these
industry
commenters
frequently
cited
IRS
regulations.


Under
26
CFR
1.167(
a)­
11(
d)(
2)(
i)(
a),
"
repairs"
are
defined
as
"
expenditures
which
do
not
substantially
prolong
the
life
of
an
asset
or
materially
increase
its
value
or
adapt
it
for
a
substantially
different
use...."


Under
26
CFR
1.162­
4,
a
taxpayer
may
deduct
as
an
expense
the
cost
of
"
incidental
repairs
which
neither
materially
add
to
the
value
of
the
property
nor
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
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and
Deliberative
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August
6,
2003
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4­
14
appreciably
prolong
its
life,
but
keep
it
in
an
ordinary
efficient
operating
condition...."

The
industry
supporters'
arguments
in
support
of
an
exclusion
for
expensed
activities
included
the
following:


It
would
provide
the
source
with
certainty
regarding
the
treatment
of
an
activity
under
NSR.


It
would
utilize
well­
understood,
existing
systems
and
accounting
procedures
to
determine
whether
an
item
can
be
claimed
as
an
expense.


Company
auditors
and
the
IRS
would
provide
a
crosscheck
on
expense
determinations,
making
this
approach
readily
enforceable.


The
national
emphasis
on
reasonable
accounting
at
major
corporations
should
give
adequate
assurance
that
this
approach
cannot
be
abused
without
fear
of
significant
consequences.


It
would
greatly
simplify
recordkeeping,
as
compared
to
the
AMA.


It
would
ease
the
burden
on
reviewing
authorities
for
making
RMRR
determinations.

A
number
of
the
industry
supporters
(
941,
1079,
1083,
1123,
1124,
1131,
1133,
1134,
1137,
1200)
recommended
that
we
institute
the
exclusion
for
expensed
activities
in
addition
to
the
AMA.
Some
of
these
commenters
recommended
that
we
promulgate
this
approach
right
away
(
in
combination
with
the
ERP)
to
provide
RMRR
certainty
immediately,
expecting
that
it
will
take
longer
to
complete
development
of
the
AMA.

A
few
industry
commenters
(
1000,
1132,
1138,
1149)
preferred
the
expense
exclusion
in
place
of
the
AMA.
These
commenters
believed
that
the
expense
exclusion
would
be
simpler
and
more
straightforward
for
sources
to
implement
and
would
avoid
some
of
the
issues
related
to
the
AMA.
These
commenters
found
the
proposed
AMA
to
be
administratively
burdensome
and
difficult
to
develop
fully.

Some
industry
supporters
of
an
expense
exclusion
(
1124,
1131,
1133,
1134)
suggested
that
we
could
promulgate
this
approach
immediately
as
a
logical
outgrowth
of
the
AMA
proposal.
Some
of
these
commenters
(
1124,
1131,
1133)
pointed
out
that
the
AMA
proposal
suggests
granting
RMRR
status
to
any
projects
that
would
fall
within
the
"
repair
guidelines"
of
IRS
publication
534
and
therefore
could
be
deducted
as
expenses
from
an
income
tax
return
(
citing
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
15
67
FR
80298).
The
commenters
suggested
that
it
would
be
simpler
and
more
defensible
simply
to
grant
RMRR
status
to
expensed
items
directly.

Another
industry
commenter
(
1079)
suggested
that
the
expense
exclusion
could
be
promulgated
as
a
logical
outgrowth
of
either
the
AMA
proposal
or
the
ERP
proposal.
A
few
industry
supporters
(
906,
1110)
suggested
that
the
expense
exclusion
could
be
implemented
within
the
ERP.
These
commenters
recommended
that
we
provide
in
the
final
rules
that
expensed
items
qualify
for
the
ERP
and
that
the
safeguards
within
the
ERP
apply
only
to
capital
replacements.

One
industry
supporter
(
1149)
suggested
a
single
safeguard
for
the
expense
exclusion,
stating
that
the
exclusion
should
not
apply
to
an
activity
that
would
increase
the
maximum
hourly
emissions
of
an
NSR
pollutant
or
cause
emissions
of
an
NSR
pollutant
not
previously
emitted.
This
commenter
also
recognized
that
an
IRS
audit
could
result
in
changing
the
classification
of
an
activity
from
an
expense
deduction
to
a
capital
expenditure.
In
this
case,
the
commenter
asserted,
the
source
must
have
the
opportunity
to
retroactively
review
the
activity
to
determine
whether
it
qualifies
as
RMRR
under
the
ERP
or
case­
by­
case
approach.

Some
industry
commenters
who
generally
support
the
expense
exclusion
under
IRS
regulations
(
1138,
1211)
requested
that
we
extend
this
approach
for
companies
that
operate
interstate
natural
gas
pipelines
to
allow
an
automatic
RMRR
exemption
for
activities
deducted
as
expenses
pursuant
to
Federal
Energy
Regulatory
Commission
(
FERC)
guidelines.
These
commenters
indicated
that
the
FERC
guidelines
are
well
established
and
well
regulated.

One
industry
commenter
(
951)
acknowledged
that
some
companies
arbitrarily
expense
some
costs
that
could
be
capitalized
and
added
that
this
is
a
standard
procedure
for
regulated
utilities
optimizing
their
rate
bases.

Response:

We
agree
that
activities
for
maintenance
and
repair
activities
that
are
expensed
should
be
excluded
from
NSR
applicability.
We
are
putting
forth
for
comment
a
separate,
supplemental
proposal
that
will
address
how
activities
can
qualify
for
routine
maintenance
and
repair
under
the
RMRR
exclusion.
For
equipment
replacement
activities,
the
ERP
includes
a
percentage
cost
threshold
that
does
not
distinguish
between
expensed
and
capitalized
costs.
Further,
we
do
not
have
confidence
that
the
guidelines
(
such
as
for
IRS
and
FERC
reporting)
for
expensing
versus
capitalizing
costs
of
replacement
equipment
are
consistently
applied
across
companies.
Therefore,
we
do
not
at
this
time
see
a
benefit
to
an
expensing
approach
in
conjunction
with
the
ERP.

4.5.2
List
of
Excluded
Activities
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
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4­
16
Comment:

Several
State/
local
(
820,
838,
946,
1012,
1033,
1148,
1138,
1199,
1211,
1268,
1361,
1366,
1464,
1622,
1643)
and
industry
(
1098,
1100,
1124,
1131,
1133,
1445,
1797)
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.
One
State/
local
commenter
(
1366)
provided
a
list
of
routine
activities.
Commenters
suggested
various
ways
that
such
lists
could
fit
into
the
overall
RMRR
program.
Some
specific
suggestions
follow.


Create
lists
of
what
is
and
what
is
not
routine
through
a
notice
an
comment
rulemaking,
in
addition
to
codifying
the
case­
by­
case
approach.
(
State/
local
commenters
838,
946,
1012,
1033,
1366,
1464,
1622)


Develop
a
list
of
activities
that
qualify
as
RMRR,
but
not
as
a
substitute
for
finalizing
the
two
proposed
options.
The
list
should
not
be
presumptive;
that
is,
it
must
not
be
assumed
that
activities
not
on
the
list
are
not
RMRR.
(
Industry
commenters
1124,
1131,
1133)


Codify
criteria
for
characterizing
whether
a
change
is
routine,
based
on
the
criteria
relied
upon
in
current
case­
by­
case
determinations.
Such
criteria
should
provide
for
detailed
safeguards
against
changes
that
would
be
likely
to
result
in
emissions
increases.
In
addition,
to
add
certainty
and
to
streamline
the
process,
develop
lists
of
activities
that
would
and
would
not
be
considered
routine
for
each
major
industrial
sector.
For
projects
and
industry
sectors
not
included
in
these
lists,
the
case­
by­
case
determination
process
would
apply,
according
to
the
codified
criteria.
(
State/
local
commenters
1624,
1268,
1624)


In
place
of
the
AMA,
develop
a
list
of
activities
that
are
considered
to
be
RMRR.
Activities
that
do
not
appear
on
the
list
would
then
be
evaluated
according
to
the
ERP.
Any
activities
that
do
not
qualify
under
either
of
these
two
tests
would
then
be
evaluated
on
a
case­
by­
case
basis.
(
Industry
commenter
1797)


One
environmental
commenter
(
1150)
did
not
generally
support
a
routine
maintenance
exclusion.
If
we
were
to
adopt
one,
however,
the
commenter
preferred
a
list
of
specific
activities
that
were
excluded.


Prepare
specific
guidelines
for
different
types
of
sources
regarding
activities
that
are
and
are
not
considered
routine.
A
list
of
qualifying
activities,
analogous
to
the
list
of
pollution
control
projects,
would
provide
clarity.
This
commenter
suggested
two
ways
in
which
we
could
develop
a
list
of
qualifying
activities.
First,
review
records
for
ongoing
enforcement
activity,
to
identify
activities
that
we
have
and
have
not
already
alleged
to
be
routine.
There
is
an
ample
body
of
knowledge
for
4
­
Approaches
for
RMRR
Other
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AMA
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ERP
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and
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2003
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17
electric
power
plants.
Second,
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
non­
routine
activities.
(
State/
local
commenter
1148)


Develop
lists
that
include
specific
process
equipment,
and
the
nature,
frequency,
extent,
and
purpose
of
the
activities
acceptable
as
RMRR.
These
lists
should
also
provide
a
schedule
for
updating
emission
standards
for
future
activities,
on
a
periodic
basis,
to
allow
facilities
to
plan
future
emission
control
installations
and
to
assist
States
in
attaining
air
quality
improvement
goals.
(
State/
local
commenter
1361)


Industry­
specific
lists
of
routine
and
non­
routine
activities
would
provide
the
best
interim
clarification
to
NSR
until
legislative
reform
is
in
place.
For
activities
on
the
non­
routine
list,
sources
would
be
entitled
to
a
full
case­
by­
case
determination
if
they
so
choose.
A
project
that
does
not
result
in
an
emissions
increase
would
not
trigger
NSR,
even
if
it
appeared
on
the
list
of
non­
routine
projects.
Supplementary
rulemakings
defining
activities
for
each
industry
sector
could
follow.
This
commenter
offered
their
experience
that
could
be
helpful
in
identifying
activities
in
each
category
for
the
electric
industry
sector.
(
Industry
commenter
1445)


Adopt
a
list
of
activities
that
are
considered
RMRR.
Begin
with
the
existing
list
of
pollution
control
equipment,
and
add
other
activities
as
sources
get
RMRR
determinations.
Pump
replacement,
as
described
on
67
FR
80300
of
the
RMRR
proposal,
could
be
on
the
list
of
RMRR
activities.
(
State/
local
commenter
1643)


The
list
approach
can
be
promulgated
as
a
logical
outgrowth
of
the
ERP.
(
Industry
commenter
1211)

Some
industry
commenters
(
942,
1001,
1091,
1134,
1202,
1292)
opposed
the
development
of
lists
of
activities
that
are
considered
RMRR.
Some
of
the
commenters
(
1001,
1202,
1292)
contended
that
such
lists
would
become
quickly
outdated.
One
of
the
commenters
(
1202)
asserted
that
taking
time
to
develop
such
lists
would
only
further
delay
clarifying
the
RMRR
exclusion.
Another
commenter
(
942)
contended
that
there
are
simply
too
many
activities
to
attempt
to
list
them.
Because
of
the
potential
for
such
lists
to
contain
gaps
and
become
quickly
outdated,
one
commenter
(
1292)
suggested
that
such
lists
may
actually
cause
more
confusion
than
they
solve
and
thrust
the
regulated
community
back
into
a
case­
by­
case
review
structure.

Response:

We
believe
there
are
simply
too
many
activities
in
too
many
industries
to
effectively
improve
major
NSR
implementation
through
creation
of
lists.
Moreover,
we
agree
with
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
18
commenters
who
said
lists
of
excluded
or
non­
excluded
activities
would
provide
only
a
"
snapshot
in
time"
that
would
need
to
be
reviewed
and
periodically
updated
for
each
industry
sector.
We
have
consequently
decided
to
not
list
activities
that
have
a
categorical
exclusion
for
routine
equipment
replacements.

4.5.3
Other
Suggested
Exclusions
Comment:

Some
industry
commenters
(
942,
1098,
1100,
1629,
1866)
recommended
that
the
final
rule
make
clear
that
the
maintenance,
repair
and
replacement
of
air
pollution
control
devices
are
not
subject
to
review
under
major
NSR.
Some
of
these
commenters
(
942,
1100)
suggested
that
this
outcome
be
accomplished
by
categorically
determining
that
such
activities
for
control
devices
and
monitoring
equipment
are
RMRR.
Another
industry
commenter
(
897)
suggested
that
the
installation
of
control
devices
not
be
subject
to
NSR.
These
comments
were
generally
made
in
the
context
of
whether
control
device
costs
should
be
included
in
the
AMA;
the
commenters
favored
excluding
these
costs
from
the
AMA
and
favored
excluding
these
activities
from
NSR
generally.

Response:

As
we
stated
in
section
3.4.2,
in
response
to
comments
received
on
industry
categoryspecific
definitions
of
"
process
unit,"
ee
disagree
with
the
commenters
who
wish
to
include
pollution
control
equipment
in
the
definition.
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
replacement
of
pollution
control
equipment
may
lead
to
emissions
increases,
you
will
either
undergo
major
NSR
for
your
increases
or
you
may
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
both
cases,
these
pieces
of
control
equipment
are
integral
to
the
process
and,
thus,
should
be
included
as
part
of
the
process
unit.

Comment:

Some
industry
commenters
(
577,
797,
906,
1201,
1797)
requested
that
certain
activities
be
specifically
classified
as
RMRR.
Activities
they
requested
to
be
classified
as
RMRR
included
the
following.
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
19

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
components
are
upgraded,
the
heat
input
remains
the
same
and
so
does
the
emissions
rate.
(
Industry
commenters
577,
797,
906,
1082,
1797)


Replacement
of
the
high­
pressure
section
of
a
steam
turbine
with
GE's
"
dense
pack"
turbine
blade
system.
(
Industry
commenter
1201)


Replacement
of
a
furnace,
cupola,
or
melter
liner.
The
commenter
suggested
language
to
be
included
in
the
final
RMRR
as
an
example
of
an
activity
that
qualifies
as
RMRR.
(
Industry
commenter
1045)


Boiler
tuning.
(
Industry
commenter
1100)

Response:

We
believe
there
are
simply
too
many
activities
in
too
many
industries
to
effectively
improve
major
NSR
implementation
through
creation
of
lists.
Moreover,
we
agree
with
commenters
who
said
lists
of
excluded
or
non­
excluded
activities
would
provide
only
a
"
snapshot
in
time"
that
would
need
to
be
reviewed
and
periodically
updated
for
each
industry
sector.
We
have
consequently
decided
to
not
list
activities
that
have
a
categorical
exclusion
for
routine
equipment
replacements.

Comment:

[
May
choose
to
"
un­
bulletize"
some
of
the
following
comments
in
order
to
respond
to
them
individually.
Preamble
language
for
some
of
them
follows,
in
italics.]

Some
commenters
suggested
other
approaches
to
the
RMRR
exclusion
and
other
exclusions
from
NSR.
These
suggestions
included
the
following.


One
industry
commenter
(
914)
recommended
that
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
be
defined
as
RMRR.
This
commenter
went
on
to
request
that
we
clarify
that
if
there
is
no
increase
in
potential
to
emit
and
no
change
in
a
design
parameter,
a
change
is
not
subject
to
NSR
and
whether
the
change
qualifies
as
RMRR
is
not
a
consideration.
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
20

One
industry
commenter
(
1100)
did
not
believe
that
the
proposed
approaches
negate
the
need
for
an
improved
definition
of
RMRR.
The
commenter
suggested
the
following.

 
The
activity
cannot
involve
the
construction
of
a
new
"
process
unit."
 
The
activity
cannot
involve
the
replacement
of
an
entire
process
unit
based
on
a
test
no
more
stringent
than
the
NSPS
test.
 
The
activity
must
be
identical
or
functionally
equivalent
and
must
not
change
the
basic
design
parameters
of
the
affected
process
unit.
 
The
activity
cannot
increase
the
source's
maximum
achievable
hourly
emissions
rate
of
any
NSR
pollutant
above
levels
that
can
be
achieved
when
the
source
is
operated
within
the
basic
design
parameters
of
the
process
unit.
 
Certain
activities,
e.
g.,
boiler
tuning,
and
maintenance,
repair
and
replacement
of
air
pollution
equipment
or
CEMS,
should
be
categorically
exempted
as
RMRR.

We
agree
with
commenters
that
prohibiting
changes
in
basic
design
parameters
and
in
emission
limitations
are
appropriate
safeguards
for
determining
which
activities
qualify
for
the
ERP.
The
ERP
stipulates
that
activities
that
cause
the
process
unit
to
exceed
any
emission
limitation,
operational
limitation
(
that
has
the
effect
of
constraining
emissions),
or
work
or
work
practice
requirement
(
that
has
the
effect
of
constraining
emissions)
that
applies
to
any
part
of
the
process
unit
cannot
qualify
for
the
ERP.

Accordingly,
you
may
categorize
identical
replacement
activities
as
routine
equipment
replacements
under
the
RMRR
exclusion
if
the
fixed
capital
cost
of
such
replacement
plus
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,
operational
limitation
(
that
has
the
effect
of
constraining
emissions),
or
work
practice
requirement
(
that
has
the
effect
of
constraining
emissions)
that
applies
to
any
part
of
the
process
unit.

Similar
to
identical
replacements,
replacements
with
functionally
equivalent
equipment
qualify
for
the
ERP,
subject
to
certain
safeguards.
That
is,
the
fixed
capital
cost
of
such
replacements
plus
the
cost
of
associated
activities
may
not
exceed
20
percent
of
the
fixed
capital
cost
of
constructing
a
new
process
unit,
and
the
replacement
may
not
alter
a
basic
design
parameter
of
the
process
unit
nor
require
a
permit
revision
related
to
the
emissions.

Also,
for
utilities,
we
added
the
basic
design
parameter
of
maximum
design
steam
flow
rating
and
clarified
from
the
proposal
that
the
correct
parameter
is
maximum
hourly
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
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
21
depending
on
the
quality
of
the
coal
for
a
given
heat
input.
When
establishing
fuel
consumption
specifications,
the
minimum
fuel
quality
based
on
BTU
content
should
be
used
for
coal­
fired
units.

Comment:

One
State/
local
commenter
(
1044)
recommended
that
the
rest
of
the
nation
adopt
California's
NSR
regulations.

Response:

Two
local
air
pollution
control
agencies
noted
that
they
currently
already
exempt
all
replacements
with
identical
equipment
from
NSR.

As
observed
at
the
time
of
our
RMRR
proposal,
we
believe
that
most
identical
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,
so
we
are
finalizing
the
provision
for
identical
replacement
of
equipment
essentially
as
we
proposed
it.

We
support
the
air
pollution
agencies
that
have
already
exempted
this
type
of
change
from
NSR,
although
we
have
concerns
about
doing
so
without
appropriate
backstops,
even
for
identical
equipment
replacements.

Comment:

Some
environmental
commenters
(
514,
522)
suggested
that
the
best
approach
to
providing
regulatory
certainty
to
industry
would
be
to
require
all
facilities
to
adopt
modern
emission
controls
by
a
specified
date
or
according
to
a
specific
timeline.
One
of
these
commenters
(
514)
endorsed
the
approach
suggested
by
the
National
Academy
of
Public
Administration
of
requiring
all
large
pollution
sources
to
adopt
modern
pollution
controls
within
5
years.

Response:

The
purpose
of
the
NSR
program
is
to
protect
public
health
and
welfare,
as
well
as
national
parks
and
wilderness
areas,
as
new
sources
of
air
pollution
are
built
and
when
existing
sources
are
modified
in
a
way
that
significantly
increases
air
pollutant
emissions.
Specifically,
NSR's
purpose
is
to
ensure
that
when
new
sources
are
built
or
existing
sources
undergo
major
modifications:
(
1)
air
quality
improves
if
the
change
occurs
where
the
air
currently
does
not
meet
federal
air
quality
standards;
and
(
2)
air
quality
is
not
significantly
degraded
where
the
air
currently
meets
federal
standards.
The
fundamental
philosophy
underlying
the
NSR
program
is
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
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6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
22
that
a
source
should
install
modern
pollution
control
equipment
when
it
is
built
(
for
new
sources)
or
when
it
makes
a
major
modification
(
for
existing
sources).
Congress
believed
that
incorporating
pollution
controls
into
the
design
and
construction
when
new
units
are
built,
or
when
major
modifications
occur,
is
generally
more
efficient
than
adding
on
controls
after
construction.
The
type
of
program
the
commenter
is
describing
is
more
similar
to
other
programs
under
the
Clean
Air
Act
such
as
the
maximum
achievable
control
technology
(
MACT)
program
for
hazardous
air
pollutants,
the
Acid
Rain
Program
or
the
Regional
Nitrogen
Oxides
Strategy.
These
programs
were
specifically
designed
to
get
reductions
from
existing
sources
on
a
set
timeframe.
EPA
is
very
supportive
of
these
programs
and
of
President
Bush's
Clear
Skies
legislation
which
would
get
significant
reductions
of
air
pollution
from
electric
utilties.
However,
the
NSR
program
was
not
designed
for
that
purpose
and
EPA
cannot
effect
that
end
through
a
change
in
its
regulations.

Comment:

One
environmental
commenter
(
948)
believed
the
EPA
should
require
mandatory
advance
determinations
of
NSR
applicability
for
routine
maintenance
exclusions.
This
commenter
also
believed
the
proposed
rule
will
put
utilities
that
have
complied
with
NSR
at
a
competitive
disadvantage.

Response:

Maintenance
activities
are
necessary
and
helpful
in
maintaining,
facilitating,
restoring
or
improving
the
safety,
reliability,
availability,
or
efficiency
of
industrial
facilities
and
are
performed
everyday
at
the
facilities.
To
require
mandatory
advance
determinatiosn
would
bring
a
grinding
halt
to
such
activities
as
sources
waited
on
determinations
from
reviewing
authorities
and
would
place
an
enormous
workload
on
those
revieiwng
authorities.
EPA
does
not
believe
it
would
serve
any
benefit
to
require
such
advance
determination.

Comment:

One
industry
commenter
(
951)
believed
that
any
project
that
is
part
of
a
long­
term
service
agreement
should
be
categorically
exempted
from
NSR.

Response:

EPA
believes
that
activities
which
qualify
as
RMRR
should
be
exempt
from
NSR
reqgardless
of
whether
they
have
been
covered
by
such
a
long­
term
service
agreement.
We
believe
offering
the
ERP
as
an
option
for
evaluating
whether
activities
are
RMRR
and
the
caseby
case
approach
are
the
ap[
propriate
mechanisms
for
identifying
activities
that
fall
within
the
RMRR
exclusion.
4
­
Approaches
for
RMRR
Other
than
the
AMA
or
ERP
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
4­
23
Comment:

One
industry
commenter
(
951)
believed
that
any
project
involving
steam
turbine
overhaul
work
should
be
categorically
exempted
from
NSR.

Response:

As
noted
above,
we
believe
there
are
simply
too
many
activities
in
too
many
industries
to
effectively
improve
major
NSR
implementation
through
creation
of
lists.
Moreover,
we
agree
with
commenters
who
said
lists
of
excluded
or
non­
excluded
activities
would
provide
only
a
"
snapshot
in
time"
that
would
need
to
be
reviewed
and
periodically
updated
for
each
industry
sector.
We
have
consequently
decided
to
not
list
activities
that
have
a
categorical
exclusion
for
routine
equipment
replacements.
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
5­
1
Chapter
5
­
Energy
Efficiency
Projects
5.1
Overview
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.

We
received
public
comments
supporting
and
opposing
a
stand­
alone
exclusion
from
NSR
for
energy
efficiency
projects.
These
comments
are
summarized
in
section
5.2.
We
also
requested
and
received
a
few
comments
on
the
impacts
of
the
existing
NSR
program
on
energy
efficiency
projects
and
other
activities
that
produce
net
benefits
to
human
health
and
the
environment.
These
comments
are
summarized
in
section
5.3.

5.2
Stand­
Alone
Exclusion
for
Energy
Efficiency
Projects
Comment:

5.2.1
Support
for
a
Stand­
Alone
Exclusion
Several
industry
commenters
(
902,
906,
920,
921,
1000,
1050,
1052,
1078,
1091,
1098,
1099,
1110,
1112,
1123,
1129,
1132,
1136,
1137,
1160,
1213,
1236,
1292,
1368,
1463,
1629,
1792,
1798)
supported
a
stand­
alone
general
exclusion
from
NSR
for
energy
efficiency
projects.
One
State/
local
commenter
(
1199)
supported
NSR
exemptions
for
a
specified
list
(
to
be
developed
by
us)
of
well­
defined
efficiency
improvements
that
do
not
result
in
equipment
reconstruction
or
emissions
increases.
A
number
of
the
supportive
industry
commenters
suggested
safeguards
to
be
included
in
a
stand­
alone
exclusion,
as
follows.


Some
commenters
(
906,
1110,
1132)
favored
specifically
excluding
from
the
definition
of
"
major
modification"
activities/
projects
that
promote
energy
efficiency
and/
or
resource
conservation
by
meeting
all
of
the
following
criteria:
(
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
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.
One
of
the
commenters
(
906)
gave
the
example
of
a
cogeneration
facility
that
adds
inlet
air
coolers
to
its
gas
turbine
generator.


One
commenter
(
1129)
stated
that
there
should
be
an
NSR
exclusion
for
situations
where
a
company
makes
operational
changes
or
adds
new
equipment
to
improve
operational
efficiency,
provided
that
there
is
(
1)
no
increase
in
maximum
hourly
5
­
Energy
Efficiency
Projects
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
5­
2
emission
rates
and
(
2)
no
increase
in
the
design
capacity.
The
commenter
strongly
encouraged
EPA
to
clarify
this
exclusion
in
a
separate,
stand­
alone,
"
capacitybased
exclusion.


One
commenter
(
1160)
proposed
safeguards
that
would
function
similarly
to
the
Clean
Unit
test
contained
in
the
December
2002
NSR
final
rules.
This
commenter
would
apply
a
new
emissions
increase
test
for
projects
that
increase
energy
efficiency.
Under
the
commenter's
proposed
test,
the
EPA
would
deem
the
project
not
to
result
in
an
emissions
increase
if
it:
(
1)
reduces
emissions
on
a
pollutant­
per­
product­
output
basis,
and
(
2)
does
not
increase
maximum
hourly
emission
rates.
The
commenter
contended
that
these
safeguards
would
protect
against
the
rare
efficiency
project
that
might
otherwise
result
in
large
emissions
increases.


Some
commenters
(
920,
921,
1000,
1123)
supported
an
exclusion
for
any
project
intended
solely
to
improve
energy
efficiency
of
a
unit,
both
for
utilities
and
nonutilities
These
commenters
suggested
that
the
exclusion
be
limited
to
projects
that
do
not
increase
raw
material
or
fuel
input
to
achieve
the
higher
production
rate.
The
commenters
indicated
that
facilities
would
be
required
to
submit
annual
reports
on
raw
material
and
fuel
usage
rates,
along
with
production
data,
to
ensure
that
the
project
qualified.


Some
commenters
(
1099,
1112,
1213,
1368,
1629)
supported
addition
of
an
NSR
provision
that
indicates
that
efficiency
improvement
projects
that
do
not
constitute
MRR
are
not
considered
physical
changes
or
changes
in
the
method
of
operation,
with
the
safeguard
that
the
project
must
not
increase
the
maximum
capacity
of
the
unit
to
emit
pollutants,
as
determined
on
an
hourly
basis
over
the
past
5
years.


One
commenter
(
1463)
supported
the
stand­
alone
energy
efficiency
project
exclusion
for
projects
that
increase
production
without
increasing
emissions
per
unit
of
production,
with
the
same
safeguards
as
proposed
for
AMA.


One
commenter
(
1798)
stated
that
electric
generating
units
and
natural
gas
pipeline
facilities
should
have
the
flexibility
to
conduct
RMRR
activities
to
improve
efficiency
without
regard
to
cost,
up
to
the
50­
percent
reconstruction
cost
threshold.

Some
of
the
supportive
industry
commenters
above
suggested
that
the
stand­
alone
exclusion
for
energy
efficiency
projects
be
expanded
to
cover
other
types
of
projects,
as
follows.


Some
commenters
(
906,
1110,
1132)
favored
including
projects
that
promote
resource
conservation.
5
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Efficiency
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3

One
commenter
(
902)
recommended
that
sources
be
allowed
to
propose
any
projects
that
can
be
demonstrated
to
produce
net
benefits
to
human
health
and
the
environment,
including
(
but
not
limited
to)
energy
efficiency
activities.


Some
commenters
(
1098,
1792)
supported
including
projects
that
increase
reliability
and
safety.
One
of
these
commenters
(
1792)
stated
that
along
with
this
expanded
stand­
alone
exclusion,
the
commenter
would
support
a
capacity­
based
approach
to
RMRR.

One
supportive
industry
commenter
(
1136)
urged
EPA,
either
separately
or
in
the
definition
of
"
functionally
equivalent,"
to
clarify
that
efficiency
improvements
are
desirable
and
are
excluded
from
NSR.
Another
supportive
industry
commenter
(
1078)
indicated
that
the
standalone
exclusion
for
energy
efficiency
projects
might
not
be
necessary,
given
that
the
AMA
provides
a
safe
harbor
for
all
types
of
activities,
not
just
maintenance,
repair,
and
replacement
actions.

One
supportive
industry
commenter
(
1137)
indicated
that
EPA's
adoption
of
the
ERP
and
AMA
should
be
helpful
in
accommodating
energy
efficiency
projects,
and
that
the
actual­
toprojected
actual
test
contained
in
the
December
2002
NSR
final
rules
also
should
remove
impediments
to
energy
efficiency
projects.
Nevertheless,
the
commenter
stated
that
these
new
provisions
would
not
eliminate
hurdles
to
many
efficiency
projects,
and
urged
EPA
to
work
with
industry
to
determine
whether
an
appropriately­
crafted
efficiency
exclusion
could
be
developed..
Because
the
commenter
believes
that
clarification
of
the
RMRR
requirements
is
urgently
needed,
the
commenter
recommended
that
EPA
move
forward
to
finalize
the
RMRR
proposals
without
waiting
for
a
stand­
alone
energy
efficiency
exclusion
to
be
developed.

5.2.2
Opposition
to
a
Stand­
Alone
Exclusion
Some
State/
local
(
1270,
1361,
1443,
1643),
Federal
(
1002),
and
citizen
(
784)
commenters
opposed
a
stand­
alone
exclusion
from
NSR
for
energy
efficiency
projects.
The
commenters
added
the
following
reasons
for
their
opposition.


State/
local
commenter
1270
asserted
that
experience
shows
that
the
positive
impact
of
an
energy
improvement
project
will
not
always
outweigh
the
environmental
impact;
the
commenter
would
like
to
retain
the
ability
to
review
energy
improvement
projects.


State/
local
commenter
1443
and
citizen
commenter
784
pointed
out
that
efficiency
upgrades
will
frequently
create
incentives
to
further
utilize
a
source
and
subsequently
increase
mass
emissions.
Citizen
commenter
784
stated
that
if
activities
that
result
in
small
efficiency
gains
can
qualify
as
RMRR,
older,
dirtier
5
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4
electric
generating
units
will
be
better
able
to
out­
compete
newer,
much
cleaner
plants
(
that
have
higher
costs
due
to
emission
controls).


State/
local
commenter
1443
also
stated
that
the
exclusion
of
efficiency
increases
is
not
sufficiently
related
to
the
concept
of
"
routine"
and
is
thus
arbitrary.
The
commenter
expressed
the
belief
that
the
proposed
RMRR
rules
are
not
protective
of
air
quality,
and
that
any
additional
exemptions
will
only
make
this
problem
worse.
The
commenter
stated
that
if
best
available
controls
are
not
required
at
the
time
of
equipment
installation,
the
State
will
be
forced
to
later
implement
more
stringent
requirements
on
existing
sources
that
will
be
more
costly
than
the
same
reduction
would
be
if
obtained
through
NSR.


State/
local
commenter
1643
indicated
that
exempting
energy
efficiency
projects
would
lead
to
uncontrolled
emissions
increases.


Federal
commenter
1002
suggested
that
such
an
exclusion
could
create
uncertainty
and
an
opportunity
for
interpretation
by
regulators
and
industry
users
fo
the
NSR
program.


State/
local
commenter
1361
stated
that
the
elimination
of
an
applicability
determination
for
any
industry
that
"
improves
energy
efficiency,"
without
any
further
definition
of
the
term,
qualifications
on
appropriate
activities,
or
an
appropriate
examination
of
emissions
and
air
quality
impacts
is
not
justified.
This
commenter
contended
that
like
other
activities,
these
projects
must
be
subject
to
appropriate
oversight
and
environmental
reviews.

Response:

We
strongly
support
efforts
to
improve
energy
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
the
final
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.

5.3
Effect
of
NSR
on
Energy
Efficiency
and
Other
Beneficial
Projects
Some
industry
commenters
(
533,
1001,
1052,
1095,
1124,
1129,
1131,
1132,
1133,
1138,
1201,
1236,
1237)
provided
comments
on
the
impact
of
the
NSR
program
on
decisions
to
proceed
with
activities
that
produce
net
benefits
to
human
health
and
the
environment,
including,
5
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6,
2003
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5­
5
but
not
limited
to,
energy
efficiency
activities.
These
commenters
generally
indicated
that
in
recent
years
EPA
has
broadened
the
applicability
of
NSR
beyond
the
original,
intended
scope,
which
was
substantial
modifications.
The
commenters
generally
contended
that
the
expense
and
delay
associated
with
NSR
scrutiny,
whether
or
not
the
project
is
ultimately
judged
to
be
subject
to
NSR,
has
caused
many
facilities
to
forego
needed
and
beneficial
maintenance,
repair,
and
replacement
projects,
even
those
that
would
reduce
emissions.
Some
of
the
commenters
provided
examples
of
such
projects
that
have
been
discouraged
or
foregone
due
to
such
concerns.
Some
of
the
commenters
indicated
that
projects
that
improve
efficiency,
availability,
reliability,
and
safety
are
both
economically
and
environmentally
beneficial,
and
properly
should
be
considered
RMRR.

One
of
these
industry
commenters
(
1201)
stated
that
it
is
in
the
unique
position
of
having
not
only
its
operating
facilities
but
also
its
products
impacted
by
the
NSR
program.
This
commenter
markets
several
products
that
are
aimed
at
making
industrial
and
utility
power
generation
more
efficient
(
examples
provided,
including
DensePack
replacement
turbine
blades),
and
stated
that
in
the
current
climate,
companies
have
no
idea
which
projects
will
be
considered
RMRR
and
which
must
undergo
NSR.

Some
State/
local
commenters
(
1241,
1361)
offered
a
different
perspective
on
the
effect
of
NSR
on
energy
efficiency
projects:


One
State/
local
commenter
(
1241)
argued
that
EPA
is
incorrect
in
stating
that
energy
efficiency
projects
are
being
discouraged
by
NSR,
particularly
under
the
new
actual­
to­
projected­
actual
applicability
test.
This
commenter
added
that
any
projects
that
are
discouraged
by
NSR
are
ones
that
increase
emissions.


One
State/
local
commenter
(
1361)
asserted
that
the
December
2002
final
NSR
rules
provide
a
broad
range
of
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.
This
commenter
also
stated
that
the
proposed
RMRR
rules
will
allow
facilities
to
use
accounting
principles
to
undertake
activities
that
are
not
specifically
excluded.
The
commenter
contended
that
the
analyses
undertaken
by
EPA
to
determine
the
impacts
of
each
of
these
rules
indicates
that
little
environmental
benefit
will
result
from
their
implementation,
and
potentially
increased
emissions,
environmental
harm,
public
health
impacts,
and
exacerbated
air
quality
improvement
efforts
will
result.
For
these
reasons,
the
commenter
opposes
this
combination
of
regulations.

Response:

We
strongly
support
efforts
to
improve
energy
efficiency
at
existing
power
plants.
These
activities
reduce
the
amount
of
air
pollution
emitted
per
unit
of
electricity
generated
and
also
5
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2003
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6
reduce
greenhouse
gas
emissions.
We
believe
that
the
final
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.
Internal
and
Deliberative
Draft
August
6,
2003
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or
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6­
1
Chapter
6
­
Analyses
of
Proposed
Regulatory
Action
Italics
represent
EPA
responses
in
preamble
or
from
CAMD.
Bold
italics
represent
EC/
R's
thoughts
on
remaining
gaps
and
possible
approaches
to
addressing
them.

6.1
Overview
We
requested
comments
on
the
IPM
analysis
of
the
emission
consequences
of
the
proposed
RMRR
options.
Public
comments
on
the
IPM
analysis
are
in
section
6.2.
Other
comments
addressed
the
requirements
of
Executive
Order
12866,
which
are
included
in
section
6.3.

6.2
IPM
and
Other
Analyses
6.2.1
Validity
of
IPM
Assumptions
Comment:

Five
environmental
(
1127,
1150,
1195,
1472,
1649),
five
State/
local
commenters
(
1241,
1243,
1264,
1361,
1643),
and
one
citizen
commenter
(
1823)
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.

One
environmental
commenter
(
1150)
noted
that
the
IPM
is
a
valid
tool
for
the
purpose
of
comparing
the
outcome
of
the
proposed
rule
with
a
base
case
that
reflects
the
enforcment
of
the
CAA
without
the
rule.
However,
several
environmental
commenters
(
1127,
1150,
1195,
1472,
1649)
and
one
State/
local
commenter
(
1241)
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
(
1150,
1195,
1241),
EPA
also
erroneously
assumes
that
this
lack
of
major
maintenance
and
refurbishment
will
have
very
little
impact
on
the
performance
of
those
power
plants,
when
in
reality
their
emissions
would
increase
significantly.
Commenter
1241
added
that
an
assumption
that
"
grandfathered"
plants
will
continue
to
operate
in
perpetuity
without
controls
is
contrary
to
Congressional
intent.
Commenters
said
the
baseline
assumption
should
be
that
at
some
future
date
older
plants
will
either
have
to
be
renovated
or
shutdown.

The
commenters
(
1127,
1150,
1472,
1649)
cite
the
Clean
Air
Task
Force
analysis
for
power
plants,
which
estimates
that
EPA's
proposed
rule
changes
will
result
in
at
least
7
million
more
tons
of
SO
2
and
2.4
million
more
tons
of
NOx
annually.
The
commenters
said,
using
EPA's
own
methods
to
translate
the
incremental
increases
in
pollution
expected
by
2020,
the
Clean
Air
Task
Force
estimates
that
finalization
of
the
proposed
rules
will
result
in
the
following.

°
20,000
additional
premature
deaths
per
year
6
­
Analyses
of
Proposed
Regulatory
Action
Internal
and
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6,
2003
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6­
2
°
400,000
additional
asthma
attacks
per
year
°
12,000
additional
cases
of
chronic
bronchitis
per
year
°
More
than
$
100
billion
per
year
in
the
economic
costs
associated
with
these
negative
health
effects.

Because
of
these
and
other
impacts,
the
commenters
said
EPA
should
withdraw
the
proposal.

One
environmental
commenter
(
1195)
said
the
IPM
runs
were
designed
to
demonstrate
that
an
expanded
set
of
maintenance
and/
or
refurbishment
activities
at
coal­
fired
power
plants
from
NSR
would
not
lead
to
increased
emissions.
The
commenter
said
EPA
misrepresented
the
base
case
by
assuming
that
power
plant
owners
would
continue
to
run
their
plants
without
initiating
any
serious
maintenance.
As
a
result,
the
heat
rate
and
capacity
of
each
plant
would
worsen
slightly,
but
the
overall
availability
of
the
plants
would
not
be
affected.
In
contrast,
under
the
no­
NSR
cases,
the
heat
rates
improve
and
the
capacity
increases.
The
commenter
said
a
realistic
base
case
is
one
that
shows
that
as
plants
age
they
would
be
either
retired
and
replaced
with
cleaner
plants,
or
they
would
be
refurbished
and
would
reduce
their
emissions
significantly
as
BACT
is
applied.
Compared
to
a
realistic
base
case,
all
of
the
EPA's
no­
NSR
cases
would
show
significant
increases
in
emissions.
The
Clean
Air
Task
Force
has
estimated
that
a
realistic
base
case
reflecting
current
regulations
would
show
SO
2
dropping
by
over
75
percent
and
NOx
dropping
by
65
percent
by
2020.

One
State/
local
commenter
(
1241)
said
another
erroneous
assumption
is
that
if
EPA's
proposals
are
not
adopted,
efficiency
improvement
projects
that
reduce
emissions
will
be
deterred
by
a
program
that
regulates
only
activities
that
increase
emissions.
The
commenter
said
this
assumption
defies
common
sense
and
is
inconsistent
with
the
historical
record.
EPA's
reference
to
the
Report
to
the
President
is
insubstantial
as
that
report
only
refers
to
unspecified
"
anecdotal
evidence"
of
foregone
efficiency
projects.
In
contrast,
in
preparing
its
Report
to
Congress,
the
National
Academy
of
Public
Administration
(
NAPA)
found
"
no
data
to
evaluate
the
situations
in
which
NSR
has
obstructed
these
projects."
The
commenter
added
that
this
assumption
is
further
degraded
by
EPA's
failure
to
distinguish
between
power
plants
and
other
sources
and
its
failure
to
consider
the
impact
of
the
recently
finalized
rules,
which
change
the
method
for
calculating
emissions
increases
at
sources
other
than
power
plants.
The
commenter
argued
that
not
all
efficiency
improvement
projects
reduce
emissions
and
that
any
adverse
emissions
impact
is
relatively
minor
compared
to
the
significant
emission
benefits
from
installing
BACT­
level
controls
on
currently
uncontrolled
plants.

One
State/
local
commenter
(
1643)
believed
the
assumptions
in
the
IPM
model
were
incorrect.
The
commenter
disagreed
that
increased
capacity
would
be
from
incrementally
better
controlled
existing
units.
Instead,
the
commenter
believed
the
comparison
should
be
between
existing
units
with
BACT/
LAER
controls
and
existing
units
without
BACT/
LAER
controls.
6
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August
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2003
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or
distribute
6­
3
One
State/
local
commenter
(
1361)
said
that
instead
of
improving
the
environment,
improvements
in
reliability
of
a
facility
would
allow
it
to
run
at
a
higher
capacity,
for
more
sustained
periods
of
time,
leading
to
increased
capacity,
and
a
commensurate
increase
in
emissions.

One
citizen
commenter
(
1823)
stated
that
the
proposed
rule
is
based
on
unproven
computer
models
using
questionable
assumptions.

One
State/
local
commenter
(
1264)
said
the
"
use
of
model
data,
rather
than
the
use
of
accurate
inventory
data,
leads
to
imprecise
estimates
that
minimize
the
impacts
of
this
rule,
especially
regarding
issues
such
as
transported
pollution."
This
commenter
concluded
that
"
EPA
owes
the
public
a
realistic
analysis
of
the
effects
of
the
proposed
rules,
and
a
clear
demonstration
that
this
proposal
will
not
only
benefit,
but
protect
the
public
as
well.
EPA
must
guarantee
that
this
proposal
will
result
in
real
pollution
reductions,
using
real
data."

One
State/
local
commenter
(
1243)
also
had
extensive
comments
on
the
validity
of
the
IPM
analyses,
especially
as
they
relate
to
the
power
sector.
See
section
6.2.2,
below,
for
more
information.

Response:

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.
Because
of
the
high
retrofit
costs
of
BACT,
many
facilities
would
never
install
BACT,
but
would
remain
operational
by
conducting
maintenance
to
the
extent
possible
allowed
under
the
current
RMRR
exclusion,
and,
where
changes
were
nonroutine,
by
taking
production
limits
and
incremental
control
measures
to
escape
major
NSR,
etc.
There
would
be
some
decline
in
efficiency,
as
the
EPA's
base
case
modeled,
but
the
units
would
likely
remain
viable,
generating
assets
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
presented
by
the
commenters.

Furthermore,
in
the
future,
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
SO
2.
To
the
degree
these
modifications
come
at
facilities
that
are
otherwise
projected
to
be
controlled
because
of
existing
SO
2
and
NOx
requirements,
there
would
be
no
difference
in
effect
between
the
model
runs
and
alternative
scenarios.
Our
analysis
confirms
that
efficiency
improvements
result
in
environmental
benefits
that
offset
(
or
more
than
offset)
emissions
increases
from
improved
availability,
but
that
previous
major
NSR
rules
discouraged
6
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6­
4
these
improvements.
Therefore,
we
affirm
the
overall
conclusion
of
our
analysis
 
that
this
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.

Related
to
the
one
commenters
concern
that
it
is
erroneous
to
assume
that
if
EPA's
proposals
are
not
adopted,
efficiency
improvement
projects
that
reduce
emissions
will
be
deterred
by
a
program
that
regulates
only
activities
that
increase
emissions,
as
noted
in
its
Report
to
the
President
on
new
Source
Review
in
2002
EPA
found
that
NSR
discourages
some
types
of
energy
efficiency
improvements
when
the
benefit
to
the
company
of
peforming
such
improvements
is
outweighed
by
the
costs
to
retrofit
pollution
controls
or
to
take
measures
necessary
to
avoid
a
significant
net
increase.
EPA
also
noted
that
some
maintenance
activities
can
have
energy
efficiency
effects
and
resultant
emission
increases
and
that
these
activities
may
be
discouraged
if
there
is
a
need
to
go
through
NSR
review.
As
to
the
reference
in
the
NAPA
report,
the
report
also
stated
that
"
there
is
no
reason
to
doubt
that
the
industry
has
accurately
reported
some
maintenance
and
efficiency
projects
rendered
uneconomic
in
substantial
part
due
to
NSR."
The
report
aslo
stated
"
to
the
extent
that
well­
controlled
sources
perceive
obstacles
to
improving
their
efficiency
and
maintaining
their
equipment,
NSR
may
indeed
be
producing
illogical
outcomes."

Several
commenters
addressed
the
capacity­
based
assumptions
we
used
in
the
IPM.
For
example,
one
commenter
said
that
instead
of
improving
the
environment,
improvements
in
reliability
of
a
facility
would
allow
it
to
run
at
a
higher
capacity,
for
more
sustained
periods
of
time,
leading
to
increased
capacity,
and
a
commensurate
increase
in
emissions.
We
agree
that
improvements
at
a
facility
would
increase
its
capacity
factor
and
this
is
what
we
modeled.
We
do
not
agree
that
this
increase
in
capacity
factor
would
lead
to
an
increase
in
emissions
under
most
scenarios.
In
particular,
SO
2
emissions
for
utilities
are
capped
under
title
IV,
so
any
increase
in
emissions
at
one
facility
would
have
to
be
offset
by
a
decrease
at
another
facility.
For
NOx,
which
is
not
capped,
the
analysis
shows
that
emissions
may
decrease
or
increase
slightly,
depending
in
large
part
on
how
much
the
capacity
factor
is
assumed
to
increase.
However,
the
small
change
in
NOx
emissions
(
up
or
down)
is
insignificant
when
compared
to
total
utility
sector
NOx
emissions
of
about
4
million
tons
per
year.

We
also
disagree
with
commenters
who
thought
our
use
of
the
IPM
as
an
analytical
tool
was
invalid.
We
have
used
the
IPM
for
many
rulemakings
dating
back
to
1996.
These
include
the
title
IV
NOx
rulemaking
and
the
NOx
SIP
call.
During
these
rulemakings,
all
aspects
of
the
model
were
subject
to
public
review
and,
in
many
cases,
we
updated
the
model
in
response
to
public
comments.
Furthermore,
during
the
NOx
SIP
call
litigation,
our
use
of
IPM
was
challenged
and
subsequently
upheld
by
the
D.
C.
Circuit.

Commenters
also
challenged
our
use
of
a
model
instead
of
"
real"
plant
data
to
evaluate
the
impacts
of
the
proposed
changes
to
the
RMRR
program.
Because
power
plants
are
all
connected
to
a
grid
selling
electricity
to
consumers,
actions
at
one
plant
can
affect
actions
at
6
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Regulatory
Action
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and
Deliberative
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2003
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6­
5
another.
For
instance,
an
increase
of
generation
at
one
plant
would
be
offset
by
a
decrease
of
emissions
at
another
plant.
Analysis
of
individual
plants
would
not
capture
this
complex
interaction,
but
use
of
the
IPM
does
capture
it.
Furthermore,
IPM
models
the
power
sector
using
a
number
of
model
plants.
These
model
plants
are
based
on
inventory
data
collected
from
real
plants
and
are
carefully
designed
to
represent
those
real
plants,
with
the
result
that
IPM
accurately
models
the
effect
that
this
rule
will
have
on
emissions
from
the
power
sector.

6.2.2
Power
Sector
Conclusions
Comment:

One
industry
commenter
(
1218)
supported
the
conclusions
EPA
drew
from
the
IPM
and
National
Energy
Modeling
System
(
NEMS)
analyses.
In
contrast,
three
State/
local
commenters
(
1241,
1243,
946)
said
the
IPM
analysis
was
deficient
with
respect
to
estimated
impacts
of
the
proposed
RMRR
changes
on
the
electric
utility
sector.

One
industry
commenter
(
1218)
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
with
EPA's
findings
in
a
1989
report,
"
1989
EPA
Base
Case
Forecasts,"
which
demonstrated
that
continuing
to
allow
utilities
to
undertake
activities
including
on­
going
annual
operating
and
maintenance
activities
and
a
major
refurbishment
when
the
unit
reached
30
years
of
operating
life
are
exactly
the
type
of
activities
allowed
under
EPA's
RMRR
proposal.

One
State/
local
commenter
(
1243)
listed
several
reasons
why
the
IPM
analysis
is
deficient
with
respect
to
what
impact
the
proposed
changes
in
the
RMRR
criteria
relative
to
the
current
criteria
would
have
on
air
emissions
and
costs
from
the
electric
utility
sectors.
This
is
because
of
the
following.

°
The
study
only
analyzes
the
impact
of
various
scenarios
on
the
national
emissions
of
SO
2
and
NOx
,
rather
than
on
emissions
emanating
from
single
stationary
sources,
or
individual
power
plants,
as
the
PSD
rules
require.
The
problem
created
by
analyzing
the
wrong
type
of
air
quality
impact
is
compounded
in
this
study,
since
the
computer
models
include
the
national
cap
on
SO
2
emissions,
which
eliminates
any
possibility
of
increased
SO
2
emissions
at
the
national
level.
State/
local
commenter
(
1241)
agreed.

°
The
base
cases
that
the
study
creates
do
not
correspond
to
a
reasonable
representation
of
the
historical
record
since
the
PSD
regulations
were
adopted,
nor
do
they
attempt
to
explicitly
represent
what
impact
the
current
NSR/
PSD
regulations
are
likely
to
have
on
air
emissions
at
either
a
local
(
stationary
source)
6
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Action
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and
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2003
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6­
6
or
national
level.
Thus,
the
base
cases
fail
to
represent
a
realistic
baseline
from
which
changes
in
air
emissions
due
to
changes
in
RMRR
criteria
can
be
measured.

°
The
alternative
regulatory
scenarios
do
not
correspond
in
any
clear
and
explicit
way
to
any
proposed
set
of
alternative
RMRR
criteria.
Thus,
it
becomes
meaningless
to
compare
the
computer
model
results
for
any
of
the
alternative
scenarios
to
the
NSR
base
cases
for
the
purpose
of
determining
what
the
impact
on
air
emissions
might
be
of
alternative
RMRR
criteria.

°
The
analysis
does
not
include
any
engineering
results
relating
the
impact
of
costeffective
repairs
and
replacements
at
any
given
type
of
coal­
fired
generating
unit
on
that
unit's
operating
parameters,
i.
e.,
availability,
heat
rate,
or
capacity
of
such
units.
Without
knowing
these
impacts
on
unit
performance,
one
cannot
know
which
types
of
repairs
would
or
would
not
likely
occur
either
under
the
current
NSR
regulations
or
under
alternative
criteria.
Only
the
frequency
of
occurrence
of
cost­
effective
repairs
and
replacements
that
might
increase
air
emissions
from
a
stationary
source
might
be
affected
by
changing
the
RMRR
criteria.
However,
the
study
does
not
state
which
proposed
changes
in
RMRR
might
lead
to
this
situation.

°
The
complex
computer
modeling
results
for
the
numerous
scenarios
simply
confirm
the
intuitively
obvious
theoretical
hypotheses
that
overall
increases
in
coal
generating
unit
capacity
and
availability
on
a
national
average
basis
tend
to
increase
air
emissions
from
the
electric
sector,
and
that
decreases
in
average
coal
plant
heat
rates
on
a
national
average
tend
to
decrease
air
emissions
from
the
electric
sector.
Thus,
the
complex
modeling
does
not
provide
any
quantitative
information
that
is
directly
relevant
to
knowing
which
types
of
potential
repairs
and
replacements
at
which
generating
units
would
likely
cause
a
violation
of
the
current
NSR
regulations
and
alternative
RMRR
criteria
and
which
would
not.

°
The
historical
data
(
last
20
years)
indicate
that
while
average
coal
plant
heat
rates
have
remained
quite
constant
(
or
slowly
decreased)
in
spite
of
numerous
repairs
and
replacements,
the
average
plant
availabilities
have
continued
to
increase
fairly
steadily
at
a
significantly
greater
rate.
These
historical
trends
under
the
current
NSR
rules
are
completely
contrary
to
the
trends
EPA
included
in
the
NSR
base
case
analyzed
by
the
IPM
model.

One
State/
local
commenter
(
946)
said
the
use
of
model
plants
and
other
generalized
assumptions
creates
imprecision
regarding
IPM­
predicted
impacts
of
a
given
rule
change
on
individual
facilities.
In
fact,
it
is
quite
possible
that
the
use
of
national
average
characteristics
would
tend
to
minimize
the
projected
impacts
of
the
proposed
rule.
6
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and
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2003
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or
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6­
7
Response:

We
agree
with
the
commenter
that
the
recent
analysis
and
the
estimated
impact
on
emissions
is
consistent
with
the
previous
EPA
report
in
1989.
Our
analysis
confirms
that
efficiency
improvements
result
in
environmental
benefits
that
offset
(
or
more
than
offset)
emissions
increases
from
improved
availability,
but
that
previous
major
NSR
rules
discouraged
these
improvements.

We
used
the
IPM
model
to
develop
a
bounding
analysis
of
the
effects
of
the
final
rule.
We
analyzed
several
scenarios
which
represent
the
range
of
possible
outcomes
within
the
electric
utility
sector
based
on
our
assessment
of
how
companies
manage
their
plants
given
the
regulatory
consequences
of
the
NSR
program.
Our
goal
was
to
provide
a
bounding
analysis;
it
was
not
possible
using
IPM
to
generate
a
list
of
specific
projects
at
specific
facilities
that
would
result
from
our
final
rule
and
to
then
compute
the
emissions
and
other
consequences
of
such
projects.
Rather,
we
made
an
overall
assessment
of
the
range
of
effects
that
such
projects
could
have
if
carried
out
across
the
utility
sector
according
to
reasonable
expectations
(
example
projects
are
discussed
in
Appendix
A
of
the
RIA).
We
then
made
estimates
of
what
range
of
effects
could
be
expected
on
parameters
such
as
heat
rate,
availability,
and
emissions
of
various
pollutants.
These
effects
were
estimated
using
the
engineering
judgement
of
EPA
experts
familiar
with
the
electric
utility
industry.
Because
we
modeled
across
a
range
of
different
parameters,
we
expect
that
the
actual
effect
of
the
rule
on
the
electric
generating
sector
will
be
somewhere
within
the
range
we
analyzed.
We
continue
to
believe
that
this
analysis
is
appropriate
for
the
purposes
of
the
RIA.

6.2.3
Applicability
of
IPM
to
Other
Industries
Comment:

Two
State/
local
commenters
(
946,
1264)
believed
that
the
IPM
model
"
cannot
accurately
model
the
impacts
of
other
large
sources
such
as
refineries,
steel
mills,
and
chemical
manufacturers."
One
State/
local
commenter
(
1443)
questioned
the
applicability
of
an
analysis
of
the
utility
sector
to
other
industries,
particularly
relatively
small
sources
that
are
subject
to
NSR
compliance
for
sources
emitting
as
little
as
10
tons
per
year
of
VOCs
or
NOx.
According
to
the
commenter,
EPA
has
no
basis
to
conclude
that
the
proposed
revisions
would
be
beneficial
or
detrimental
in
the
most
polluted
area
of
the
country
(
SCAQMD).

Response:

We
believe
that
the
conclusions
of
this
analysis
are
generally
applicable
to
all
industrial
sectors.
We
do
not
have
tools
like
IPM
for
modeling
the
response
of
non­
utility
sectors,
so
our
ability
to
present
a
quantitative
bounding
analysis
specific
to
any
other
sector
is
limited.
We
also
note
that
there
are
some
important
differences
between
the
utility
sector
and
other
sectors.
6
­
Analyses
of
Proposed
Regulatory
Action
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
6­
8
Unlike
utilities,
other
sectors:
(
1)
are
not
subject
to
a
nationwide
SO
2
cap;
(
2)
are
not
interconnected
and
thus
do
not
experience
potentially
large
changes
in
utilization
resulting
from
changes
in
dispatch
order;
(
3)
were,
until
March
2003,
subject
to
the
actual­
to­
potential
test
for
NSR
applicability;
and
(
4)
generally
have
lower
emissions,
such
that
emissions
are
not
nearly
as
sensitive
to
small
changes
in
utilization.

Despite
these
differences,
we
believe
that
the
overall
conclusions
of
the
IPM
analysis
are
valid
for
other
sectors.
The
largest
stationary
sources
of
SO
2
and
NOx
emissions
other
than
electric
utilities
are
industrial
boilers.
These
units
are
very
similar
to
boilers
in
the
electric
utility
industry.
They
usually
only
provide
steam
or
energy
for
the
industrial
facility
where
they
are
located,
although
in
some
cases
they
may
serve
multiple
facilities.
We
believe
the
IPM
runs
showing
the
impacts
on
NOx
emissions,
which
were
not
subjected
to
a
cap
in
our
analysis,
resulting
from
different
scenarios
with
a
range
of
effects
on
capacity
or
efficiency
are
equally
valid
related
to
SO
2
and
NOx
emissions
from
industrial
boilers.
In
some
cases
there
may
be
small
increases
and
in
other
cases
there
would
be
an
overall
reduction
in
emissions.

For
all
other
industrial
sources,
we
believe
that,
in
general,
facilities
in
these
sectors
have
regular
maintenance,
repair
and
equipment
replacement
cycles.
Work
is
performed
during
these
cycles
to
ensure
that
a
facility
maintains
its
productive
capacity
and
facilitates
its
safe
and
reliable
operation.
Equipment
replacement
activities
generally
just
maintain
the
operational
capability
of
the
facility.
In
some
cases,
it
may
increase
the
production
efficiency
of
the
facility
which
will
usually
reduce
the
amount
of
emissions
per
product.
These
changes
generally
do
not
affect
the
overall
emissions
of
the
facility,
because
the
emissions
are
driven
by
total
production
at
the
facility,
which
in
turn
is
driven
by
the
demand
for
the
product
 
not
by
the
fact
that
there
has
been
an
equipment
replacement.
We
do
not
believe
the
final
rule
will
lead
to
any
increases
in
emissions
for
these
sectors
nationally.
We
believe
that
the
modeled
effects
of
utilities
dominate
the
effects
for
non­
utilities,
and
the
overall
conclusion
of
the
utility
analysis
 
that
the
structure
of
the
ERP
has
no
practical
impact
on
emissions
reductions
under
the
NSR
program
 
is
valid,
despite
our
inability
to
model
these
other
sectors
individually.

6.2.4
NEMS
Comment:

Environmental
commenter
1195
said
while
the
NEMS
model
may
have
translated
the
assumed
improvements
correctly
into
emissions
reductions,
there
is
no
basis
set
forth
for
the
level
of
improvements
that
are
assumed.
For
example,
heat
rate
improvements
of
5,
10,
and
15
percent
are
suggested,
but
no
basis
for
this
level
of
improvement
is
provided.
The
commenter
said
cost
is
always
an
important
factor
in
projects
to
improve
heat
rate,
and
cited
work
done
for
a
major
Northeastern
utility
in
the
early­
to
mid­
1990s
that
found
very
little
additional
heat
rate
improvement
was
cost
effective.
6
­
Analyses
of
Proposed
Regulatory
Action
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
6­
9
One
State/
local
commenter
(
1243)
said
the
use
of
the
NEMS
model
does
not
add
any
significant
findings
to
the
impact
analysis.
The
commenter
noted
that
the
model
scenarios
related
to
the
5­,
10­,
and
15­
percent
improvements
in
heat
rates
are
very
large
relative
to
what
can
likely
be
achieved
from
strictly
an
engineering
perspective,
not
to
speak
of
a
cost­
effective
basis.
The
commenter
added
that
no
causal
linkage
was
made
between
specific
sets
of
plant
operating
parameters
and
specific
proposed
changes
in
the
RMRR
criteria.
Similarly,
the
NEMS
analysis
omitted
any
increased
maintenance
costs
that
would
be
necessary
in
order
to
achieve
the
improvements
in
plant
performance.
Finally,
the
analysis
only
reports
NEMS
results
for
national
emissions
of
air
pollutant,
not
stationary
source­
specific
levels
of
air
emissions.
The
commenter
concluded
that
the
analysis
is
not
particularly
useful
for
understanding
the
likely
impact
the
proposed
RMRR
criteria
will
have
on
air
emissions,
until
the
impact
of
these
new
criteria
on
likely
coal
plant
operating
parameters
is
quantified
relative
to
existing
criteria.

Response:

The
analysis
was
designed
to
analyze
a
range
of
scenarios
related
to
heat
rate
improvements.
Between
the
IPM
runs
and
the
NEMS
runs,
efficiency
gains
of
0,
1.6,
3.2,
5,
10
and
15
percent
were
examined.
We
believe
that
this
broad
range
of
estimates
represents
a
number
of
possible
realities.
However,
we
agree
that
heat
rate
improvements
on
the
lower
end
or
the
range
are
more
likely,
which
is
why
we
examined
a
range
of
heat
rate
improvements
of
less
than
5
percent.

Also
need
to
address
comments
regarding
overall
sufficiency
of
analysis.
Specifically,
the
lack
of
a
causal
linkage
between
specific
sets
of
plant
operating
parameters
and
specific
proposed
changes
in
the
RMRR
criteria,
impact
of
increased
maintenance
costs
that
would
be
necessary
in
order
to
achieve
the
improvements
in
plant
performance,
and
stationary
sourcespecific
levels
of
air
emissions.
Explain
that
the
DOE
analysis
was
included
as
a
supplement
intended
to
evaluate
a
variety
of
changes
in
energy
efficiency
and
availability,
as
well
as
the
effect
on
emissions
resulting
from
the
RMRR
changes?
Explain
why
no
increases
in
maintenance
costs
were
assumed?
More?

6.2.5
June
2002
Report
to
the
President
Comment:

One
State/
local
commenter
(
1243)
said
the
June
2002
Report
to
the
President
does
not
contribute
significantly
to
the
RMRR
analysis.
The
commenter
said
EPA's
concern
that
a
possible
repair
or
replacement
that
would
lead
to
substantial
efficiency
improvement
would
not
be
done
because
it
would
trigger
a
need
for
expensive
pollution
controls
is
overblown.
In
fact,
the
commenter
said,
the
current
NSR
criteria
for
when
pollution
controls
are
needed
are
simply
designed
to
keep
emissions
at
or
below
historical
levels.
Thus
a
repair
or
replacement
that
makes
a
plant
more
efficient,
absent
a
commensurate
increase
in
utilization
of
the
source,
may
reduce
6
­
Analyses
of
Proposed
Regulatory
Action
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
6­
10
emissions.
Even
in
the
face
of
an
increase
of
capacity
or
availability,
the
plant
owner
could
agree
to
a
permit
restriction
on
the
number
of
hours
of
operation
to
avoid
an
emissions
increase.
So
long
as
the
repair
or
replacement
were
cost
effective
given
the
agreed
upon
limit
to
the
capacity
factor,
then
there
would
be
no
disincentive
caused
by
the
current
NSR
regulations
in
making
such
a
repair.

Response:

As
noted
in
its
Report
to
the
President
on
new
Source
Review
in
2002
EPA
found
that
NSR
discourages
some
types
of
energy
efficiency
improvements
when
the
benefit
to
the
company
of
peforming
such
improvements
is
outweighed
by
the
costs
to
retrofit
pollution
controls
or
to
take
measures
necessary
to
avoid
a
significant
net
increase.
EPA
also
noted
that
some
maintenance
activities
can
have
energy
efficiency
effects
and
resultant
emission
increases
and
that
these
activities
may
be
discouraged
if
there
is
a
need
to
go
through
NSR
review.
While
limits
on
operations
may
be
taken,
these
limits
would
have
a
tendency
to
accumulate
over
time
as
more
and
more
such
maintenance
projects
were
undetaken
causing
over
time
severe
limitations
on
the
operational
capability
of
the
source.

6.2.6
Other
Analyses
Needed
Comment:

One
Federal
(
1001),
two
environmental
(
540,
1150),
and
three
State/
local
(
946,
1361,
1443)
commenters
said
additional
analyses
are
needed
to
support
EPA's
conclusion
that
the
proposed
RMRR
criteria
are
beneficial.

Environmental
commenter
1150
said
the
proposal
lacks
any
reference
to
the
gains
accomplished
by
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.

Environmental
commenter
1150
said
it
is
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,
EPA
has
stated
that
it
cannot
accurately
quantify
the
effects
the
proposed
rule
will
have
on
emissions.
Before
promulgating
a
final
rule,
EPA
should
provide
such
a
quantitative
assessment
of
the
rule.

Federal
commenter
1002
said
that
there
was
no
explicit
analysis
or
consideration
of
the
impact
that
the
proposal
would
have
on
"
grandfathered"
coal­
fired
power
plants
or
on
the
6
­
Analyses
of
Proposed
Regulatory
Action
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
6­
11
emissions
from
geographic
regions
such
as
the
Midwest
where
many
of
the
old
power
plants
and
industrial
facilities
are
located.
Such
analyses
would
be
important
not
only
for
assessing
possible
U.
S.­
Canada
transboundary
air
pollution
consequences
but
also
the
possible
air
pollution
transport
impact
that
could
exist
within
the
United
States
between
the
Midwestern
states
where
many
of
the
"
grandfathered"
plants
are
located
and
the
Northeastern
states.

One
State/
local
commenter
(
946)
said
EPA
owes
the
public
a
more
convincing
demonstration,
based
on
location
and
region­
specific
information
using
actual
emissions
data
from
actual
facilities.
Another
State/
local
commenter
(
1361)
said
EPA
has
not
demonstrated
that
the
RMRR
proposal
will
have
a
net
environmental
benefit.
This
commenter
was
particularly
concerned
about
the
impact
of
the
proposal
on
nonattainment
areas
that
suffer
from
pollutant
transport
from
upwind
states.

One
environmental
commenter
(
540)
said
EPA
failed
to
provide
a
basic
analysis
of
the
age
of
affected
industrial
units
and
the
application
of
the
NSR
RMRR
provisions.
The
commenter
said
EPA
should
evaluate
the
impacted
industries
by
highlighting
the
impacted
units,
their
age
of
operations,
expected
"
normal
life,"
and
whether
BACT
has
been
installed.

One
State/
local
commenter
(
1443)
said
EPA
and
DOE
have
not
considered
the
intangible
benefits
resulting
from
NSR
programs.
In
particular,
the
emission
limitations
imposed
through
NSR
have
created
incentives
for
sources
to
develop
innovative
means
to
control
such
emissions,
which
is
particularly
important
to
heavily
polluted
areas.
Examples
include
development
of
low­
NOx
burner
technology
and
low­
VOC
coatings
and
solvents.

Response:

As
shown
in
the
final
RIA,
it
is
clear
that,
for
the
electric
generating
sector,
the
overall
scope
of
the
routine
maintenance
exclusion
has
little
practical
impact
on
the
benefits
that
would
be
achieved
in
the
future
under
the
NSR
program.
Capped
SO
2
emissions
remain
unchanged,
and
NO
x
emissions
change
slightly
depending
upon
which
modeled
scenario
is
closest
to
what
actually
occurs.
This
change
is
particularly
insignificant
when
compared
to
the
power
sector's
national
NO
x
emissions
of
over
4
million
tons
per
year,
or
the
more
than
7
million
tons
per
year
of
NO
x
reductions
expected
from
recently
promulgated
rules.

In
addition,
the
EPA
believes
that
the
conclusions
of
this
analysis
are
generally
applicable
to
all
industrial
sectors.
We
do
not
have
tools
like
IPM
for
modeling
the
response
of
non­
utility
sectors,
so
our
ability
to
present
a
quantitative
bounding
analysis
specific
to
any
other
sector
is
limited.
We
also
note
that
there
are
some
important
differences
between
the
utility
sector
and
other
sectors.
Unlike
utilities,
other
sectors:
(
1)
are
not
subject
to
a
nationwide
SO
2
cap,
(
2)
are
not
interconnected
and
thus
do
not
experience
potentially
large
changes
in
utilization
resulting
from
changes
in
dispatch
order,
(
3)
were,
until
March
2003,
subject
to
the
6
­
Analyses
of
Proposed
Regulatory
Action
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
6­
12
actual­
to­
potential
test
for
NSR
applicability,
and
(
4)
generally
have
lower
emissions,
such
that
emissions
are
not
nearly
as
sensitive
to
small
changes
in
utilization.

Despite
these
differences,
the
EPA
believes
that
the
overall
conclusions
of
the
IPM
analysis
are
valid
for
other
sectors.
The
largest
stationary
sources
of
SO2
and
NOx
emissions
other
electric
utilities
are
industrial
boilers.
These
units
are
very
similar
to
boilers
in
the
electric
utility
industry.
They
usually
only
provide
steam
or
energy
for
the
industrial
facility
where
they
are
located
though
in
some
cases
they
may
serve
multiple
facilities.
We
believe
the
IPM
runs
showing
the
impacts
on
NOx
emissions,
which
were
not
subjected
to
a
cap
in
our
analysis,
resulting
from
different
scenarios
which
a
range
of
effects
on
capacity
or
efficiency
are
equally
valid
related
to
SO2
and
NOx
emissions
from
industrial
boilers.
In
some
cases
there
may
be
small
increases
and
in
other
cases
there
would
be
an
overall
reduction
in
emissions.

For
all
other
industrial
sources,
we
believe
that,
in
general,
facilities
in
these
sectors
have
regular
maintenance,
repair
and
equipment
replacement
cycles.
Work
is
performed
during
these
cycles
to
ensure
that
a
facility
maintains
its
productive
capacity
and
facilitates
its
safe
and
reliable
operation.
Equipment
replacement
activities
generally
just
maintain
the
operational
capability
of
the
facility.
In
some
cases,
it
may
increase
the
production
efficiency
of
the
facility
which
will
usually
reduce
the
amount
of
emissions
per
product.
These
changes
generally
do
not
affect
the
overall
emissions
of
the
facility
because
the
emissions
are
driven
by
total
production
at
the
facility
which
in
turn
is
driven
by
the
demand
for
the
product
 
not
by
the
fact
that
there
has
been
an
equipment
replacement.
We
do
not
believe
the
final
rule
will
lead
to
any
increases
in
emissions
for
these
sectors
nationally.
The
EPA
believes
that
the
modeled
effects
of
utilities
dominate
the
effects
for
non­
utilities,
and
the
overall
conclusion
of
the
utility
analysis
 
that
the
structure
of
the
RMRR
replacement
has
no
practical
impact
on
emissions
reductions
under
the
NSR
program
 
is
valid,
despite
our
inability
to
model
these
other
sectors
individually.

6.2.7
Comments
on
August
2002
Information
Collection
Request
Comment:

Environmental
commenter
1150
said
the
August
2002
ICR
pertains
solely
to
the
burdens,
costs
and
benefits
to
regulated
sources.
The
fact
that
EPA
did
not
seek
comment
on
expected
emission
reductions
or
health
benefits
(
or
costs),
skews
the
analysis
and
renders
any
conclusion
arbitrary
and
capricious.
The
commenter
said
in
a
rulemaking
of
this
magnitude
that
EPA
has
the
authority
and
obligation
to
conduct
a
thorough
review
of
both
the
economic
and
emissions
aspects
of
NSR
through
a
systematic
collection
of
data
from
the
regulated
industry.
Instead,
the
commenter
said
EPA
has
been
woefully
deficient
in
collecting
and
maintaining
data
necessary
to
the
proper
enforcement
of
the
program.
The
commenter
cited
conclusions
summarized
in
a
report
by
NAPA
on
the
NSR
program
in
support
of
his
views.

Response:
6
­
Analyses
of
Proposed
Regulatory
Action
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
6­
13
The
primary
purposes
of
the
Paperwork
reduction
Act
is
minimize
the
paperwork
burden
for
individuals,
small
businesses,
educational
and
nonprofit
institutions,
Federal
contractors,
State,
local
and
tribal
governments,
and
other
persons
resulting
from
the
collection
of
information
by
or
for
the
Federal
Government
and
ensure
the
greatest
possible
public
benefit
from
and
maximize
the
utility
of
information
created,
collected,
maintained,
used,
shared
and
disseminated
by
or
for
the
Federal
Government.
The
information
collection
request
prepared
for
a
regualtion
is
to
document
the
paperwork
burden
being
placed
on
individuals,
small
businesses,
educational
and
nonprofit
institutions,
Federal
contractors,
State,
local
and
tribal
governments,
and
other
persons
EPA
and
the
States
have
other
means
available
to
them
under
the
Clean
Air
Act
to
collect
information
and
to
enforce
applicable
requirements.
These
are
not
the
focus
of
an
information
collection
request
for
a
specific
rule.

6.3
Executive
Order
12866
Analyses
Comment:

Six
environmental
commenters
(
712,
713,
714,
738,
1150,
1514)
said
EPA
failed
to
meet
its
requirements
under
E.
O.
12866
to
provide
the
required
RIA.
They
said
one
should
be
developed
and
the
public
should
have
a
chance
to
review
it.

One
environmental
commenter
(
1150)
stated
that
EPA
has
failed
to
meet
procedural
requirements
of
E.
O.
12866,
including
section
6(
a),
which
requires
EPA
to
involve
those
intended
to
benefit
from
and
be
burdened
by
the
regulation
before
proposing
it,
section
6(
a)(
3)(
B)(
ii),
which
requires
EPA
to
explain
the
statutory
basis
for
its
proposal,
and
section
6(
a)(
3)(
C)(
ii),
which
requires
EPA
to
assess
impacts
on
public
health,
safety,
and
the
natural
environment.
The
commenter
concluded
that
any
action
by
EPA
to
promulgate
the
proposed
rule
would
be
arbitrary,
capricious,
and
otherwise
not
in
accordance
with
law.

Other
environmental
commenters
(
712,
713,
714,
738)
stated
that
EPA
has
failed
to
provide
the
required
RIA,
even
though
the
OMB
has
found
that
the
rule
is
economically
significant.
These
commenters
(
712,
713,
714,
738,
1514)
requested
that
EPA
fully
analyze
the
health
and
environmental
impacts
of
the
proposed
rule
and
prepare
an
RIA.
They
suggested
that
the
proposed
rule
will
have
major
health
and
environmental
impacts
if
implemented
and
cited
various
estimates
of
adverse
impacts.
For
example,
a
study
by
AbT
Associates
concluded,
among
other
things,
that
requiring
power
plants
to
install
modern
air
pollution
controls
would
prevent
over
18,700
premature
deaths
each
year
and
provide
well
over
$
100
billion
per
year
in
monetary
benefits.
Delaying
these
improvements
will
lead
to
tremendous
health
and
monetary
costs.

One
commenter
(
1514)
said
the
public
should
have
an
opportunity
to
review
the
RIA
as
part
of
the
public
comment
process.

Response:
6
­
Analyses
of
Proposed
Regulatory
Action
Internal
and
Deliberative
Draft
August
6,
2003
Do
not
quote,
cite,
copy,
or
distribute
6­
14
To
comply
with
the
Executive
Order,
EPA
prepared
a
draft
Regulatory
Impact
Analysis
(
RIA)
at
the
time
of
proposal
and
made
that
available
for
public
comment.
Based
on
these
comments
EPA
has
prepared
a
final
RIA
which
has
been
submitted
and
cleared
by
OMB
and
placed
in
the
docket
for
this
rulemaking.
