Document ID: EPA-HQ-OAR-2003-0053-2106
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2005-03-10T05:00Z

6560­
50­
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
51,
72,
73,
74,
77,
78
and
96
[
OAR­
2003­
0053;
FRL
]

[
RIN
2060­
AL76]

Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule);
Revisions
to
Acid
Rain
Program;
Revisions
to
the
NOx
SIP
Call
AGENCY:
Environmental
Protection
Agency
(
EPA).

ACTION:
Final
Rule.

SUMMARY:
In
today's
action,
EPA
finds
that
28
States
and
the
District
of
Columbia
contribute
significantly
to
nonattainment
of
the
national
ambient
air
quality
standards
(
NAAQS)
for
fine
particles
(
PM2.5)
and/
or
8­
hour
ozone
in
downwind
States.
The
EPA
is
requiring
these
upwind
States
to
revise
their
State
implementation
plans
(
SIPs)
to
include
control
measures
to
reduce
emissions
of
sulfur
dioxide
(
SO2)

and/
or
nitrogen
oxides
(
NOx).
Sulfur
dioxide
is
a
precursor
to
PM2.5
formation,
and
NOx
is
a
precursor
to
both
ozone
and
PM2.5
formation.
Reducing
upwind
precursor
emissions
will
assist
the
downwind
PM2.5
and
8­
hour
ozone
nonattainment
areas
in
achieving
the
NAAQS.
Moreover,
attainment
will
be
achieved
in
a
more
equitable,
cost­
effective
manner
than
if
each
nonattainment
area
attempted
to
achieve
attainment
by
implementing
local
emissions
reductions
alone.
2
Based
on
State
obligations
to
address
interstate
transport
of
pollutants
under
section
110(
a)(
2)(
D)
of
the
Clean
Air
Act
(
CAA),
EPA
is
specifying
statewide
emissions
reduction
requirements
for
SO2
and
NOx.
The
EPA
is
specifying
that
the
emissions
reductions
be
implemented
in
two
phases.
The
first
phase
of
NOx
reductions
starts
in
2009
(
covering
2009­
2014)
and
the
first
phase
of
SO2
reductions
starts
in
2010
(
covering
2010­
2014);
the
second
phase
of
reductions
for
both
NOx
and
SO2
starts
in
2015
(
covering
2015
and
thereafter).
The
required
emissions
reductions
requirements
are
based
on
controls
that
are
known
to
be
highly
cost
effective
for
electric
generating
units
(
EGUs).

Today's
action
also
includes
model
rules
for
multi­

State
cap
and
trade
programs
for
annual
SO2
and
NOx
emissions
for
PM2.5
and
seasonal
NOx
emissions
for
ozone
that
States
can
choose
to
adopt
to
meet
the
required
emissions
reductions
in
a
flexible
and
cost­
effective
manner.

Today's
action
also
includes
revisions
to
the
Acid
Rain
Program
regulations
under
title
IV
of
the
CAA,
particularly
the
regulatory
provisions
governing
the
SO2
cap
and
trade
program.
The
revisions
are
made
because
they
streamline
the
operation
of
the
Acid
Rain
SO2
cap
and
trade
program
and/
or
3
facilitate
the
interaction
of
that
cap
and
trade
program
with
the
model
SO2
cap
and
trade
program
included
in
today's
action.
In
addition,
today's
action
provides
for
the
NOx
SIP
Call
cap
and
trade
program
to
be
replaced
by
the
CAIR
ozone­
season
NOx
trading
program.

DATES:
The
effective
date
of
today's
action,
except
for
the
revisions
to
40
CFR
parts
72,
73,
74,
and
77
of
the
Acid
Rain
Program
regulations,
is
[
INSERT
DATE
60
DAYS
FROM
PUBLICATION].
States
must
submit
to
EPA
for
approval
enforceable
plans
for
complying
with
the
requirements
of
this
rule
by
[
INSERT
DATE
18
MONTHS
FROM
SIGNATURE].
The
effective
date
for
today's
revisions
to
40
CFR
parts
72,
73,

74,
and
77
of
the
Acid
Rain
Program
regulations
is
July
1,

2006.

ADDRESSES:
The
EPA
has
established
a
docket
for
this
action
under
Docket
ID
No.
OAR­
2003­
0053.
All
documents
in
the
docket
are
listed
in
the
EDOCKET
index
at
http://
www.
epa.
gov/
edocket.
Although
listed
in
the
index,

some
information
is
not
publicly
available,
i.
e.,

Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
Certain
other
material,
such
as
copyrighted
material,
is
not
placed
on
the
Internet
and
will
be
publicly
available
only
in
hard
copy
form.
Publicly
available
docket
materials
are
available
4
either
electronically
in
EDOCKET
or
in
hard
copy
at
the
EPA
Docket
Center,
EPA
West,
Room
B102,
1301
Constitution
Avenue,
NW,
Washington,
DC.
The
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,

excluding
legal
holidays.
The
telephone
number
for
the
Public
Reading
Room
is
(
202)
566­
1744,
and
the
telephone
number
for
the
Air
Docket
is
(
202)
566­
1742.

FOR
FURTHER
INFORMATION
CONTACT:
For
general
questions
concerning
today's
action,
please
contact
Carla
Oldham,
U.
S.

EPA,
Office
of
Air
Quality
Planning
and
Standards,
Air
Quality
Strategies
and
Standards
Division,
Mail
Code
C539­

02,
Research
Triangle
Park,
NC,
27711,
telephone
(
919)
541­

3347,
e­
mail
at
oldham.
carla@
epa.
gov.
For
legal
questions,

please
contact
Elliott
Zenick,
U.
S.
EPA,
Office
of
General
Counsel,
Mail
Code
2344A,
1200
Pennsylvania
Avenue,
NW,

Washington,
DC,
20460,
telephone
(
202)
564­
1822,
e­
mail
at
zenick.
elliott@
epa.
gov.
For
questions
regarding
air
quality
analyses,
please
contact
Norm
Possiel,
U.
S.
EPA,
Office
of
Air
Quality
Planning
and
Standards,
Emissions
Monitoring
and
Analysis
Division,
Mail
Code
D243­
01,
Research
Triangle
Park,
NC,
27711,
telephone
(
919)
541­
5692,
e­
mail
at
possiel.
norm@
epa.
gov.
For
questions
regarding
the
EGU
cost
analyses,
emissions
inventories,
and
budgets,
please
contact
Roman
Kramarchuk,
U.
S.
EPA,
Office
of
Atmospheric
Programs,
5
Clean
Air
Markets
Division,
Mail
Code
6204J,
1200
Pennsylvania
Avenue,
NW,
Washington,
DC,
20460,
telephone
(
202)
343­
9089,
e­
mail
at
kramarchuk.
roman@
epa.
gov.
For
questions
regarding
statewide
emissions
inventories,
please
contact
Ron
Ryan,
U.
S.
EPA,
Office
of
Air
Quality
Planning
and
Standards,
Emissions
Monitoring
and
Analysis
Division,

Mail
Code
D205­
01,
Research
Triangle
Park,
NC,
27711,

telephone
(
919)
541­
4330,
e­
mail
at
ryan.
ron@
epa.
gov.
For
questions
regarding
emissions
reporting
requirements,
please
contact
Bill
Kuykendal,
U.
S.
EPA,
Office
of
Air
Quality
Planning
and
Standards,
Emissions
Monitoring
and
Analysis
Division,
Mail
Code
D205­
01,
Research
Triangle
Park,
NC,

27711,
telephone
(
919)
541­
5372,
e­
mail
at
kuykendal.
bill@
epa.
gov.
For
questions
regarding
the
model
cap
and
trade
programs,
please
contact
Sam
Waltzer,
U.
S.

EPA,
Office
of
Atmospheric
Programs,
Clean
Air
Markets
Division,
Mail
Code
6204J,
1200
Pennsylvania
Avenue,
NW,

Washington,
DC,
20460,
telephone
(
202)
343­
9175,
e­
mail
at
waltzer.
sam@
epa.
gov.
For
questions
regarding
analyses
required
by
statutes
and
executive
orders,
please
contact
Linda
Chappell,
U.
S.
EPA,
Office
of
Air
Quality
Planning
and
Standards,
Air
Quality
Strategies
and
Standards
Division,

Mail
Code
C339­
01,
Research
Triangle
Park,
NC,
27711,

telephone
(
919)
541­
2864,
e­
mail
at
chappell.
linda@
epa.
gov.
6
For
questions
regarding
the
Acid
Rain
Program
regulation
revisions,
please
contact
Dwight
C.
Alpern,
U.
S.
EPA,
Office
of
Atmospheric
Programs,
Clean
Air
Markets
Division,
Mail
Code
6204J,
1200
Pennsylvania
Avenue,
NW,
Washington,
DC,

20460,
telephone
(
202)
343­
9151,
e­
mail
at
alpern.
dwight@
epa.
gov.

SUPPLEMENTARY
INFORMATION:

Regulated
Entities
Except
for
the
revisions
to
the
Acid
Rain
Program
regulations,
this
action
does
not
directly
regulate
emissions
sources.
Instead,
it
requires
States
to
revise
their
SIPs
to
include
control
measures
to
reduce
emissions
of
NOx
and
SO2.
The
emissions
reductions
requirement
assigned
to
the
States
are
based
on
controls
that
are
known
to
be
highly
cost
effective
for
EGUs.

Entities
potentially
regulated
by
the
revisions
to
the
Acid
Rain
Program
regulations
in
this
action
are
fossilfuel
fired
boilers,
turbines,
and
internal
combustion
engines,
including
those
that
serve
generators
producing
electricity,
generate
steam,
or
cogenerate
electricity
and
steam.
Regulated
categories
and
entities
include:
7
Category
NAICS
code1
Examples
of
potentially
regulated
entities
Industry
221112
and
others
Electric
service
providers,
boilers,
turbines,
and
internal
combustion
engines
from
a
wide
range
of
industries.

Federal
government
221122
Fossil
fuel­
fired
electric
utility
steam
generating
units
owned
by
the
Federal
government.

State/
local/
Tribal
government
221122
921150
Fossil
fuel­
fired
electric
utility
steam
generating
units
owned
by
municipalities.
Fossil
fuel­
fired
electric
utility
steam
generating
units
in
Indian
Country.

1
North
American
Industry
Classification
System.
2
Federal,
State,
or
local
government­
owned
and
operated
establishments
are
classified
according
to
the
activity
in
which
they
are
engaged.

This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
the
revisions
to
the
Acid
Rain
Program
regulations
in
this
action.
This
table
lists
the
types
of
entities
that
EPA
is
aware
could
potentially
be
regulated.

Other
types
of
entities
not
listed
in
the
table
could
also
be
regulated.
To
determine
whether
your
facility
is
regulated,
you
should
carefully
examine
the
applicability
criteria
in
40
CFR
§
§
72.6
and
74.2
and
the
exemptions
in
40
CFR
§
§
72.7
and
72.8.
If
you
have
questions
regarding
the
applicability
of
the
revisions
to
the
Acid
Rain
Program
8
regulations
in
this
action
to
a
particular
entity,
consult
persons
listed
in
the
preceding
FOR
FURTHER
INFORMATION
section.

Website
for
Rulemaking
Information
The
EPA
has
also
established
a
website
for
this
rulemaking
at
http://
www.
epa.
gov/
cleanairinterstaterule/

(
formerly
at
http://
www.
epa.
gov/
interstateairquality/)
which
includes
the
rulemaking
actions
and
certain
other
related
information
that
the
public
may
find
useful.

Outline
I.
Overview
A.
What
Are
the
Central
Requirements
of
this
Rule?
B.
Why
Is
EPA
Taking
this
Action?
1.
Policy
Rationale
for
Addressing
Transported
Pollution
Contributing
to
PM2.5
and
Ozone
Problems
a.
The
PM2.5
Problem
b.
The
8­
hour
Ozone
Problem
c.
Other
Environmental
Effects
Associated
with
SO2
and
NOx
Emissions
2.
The
CAA
Requires
States
to
Act
as
Good
Neighbors
by
Limiting
Downwind
Impacts
3.
Today's
Rule
Will
Improve
Air
Quality
C.
What
was
the
Process
for
Developing
this
Rule?
D.
What
Are
the
Major
Changes
Between
the
Proposals
and
the
Final
Rule?

II.
EPA's
Analytical
Approach
A.
How
Did
EPA
Interpret
the
Clean
Air
Act's
Pollution
Transport
Provisions
in
the
NOx
SIP
Call?
1.
Clean
Air
Act
Requirements
2.
The
NOx
SIP
Call
Rulemaking
a.
Analytical
Approach
of
NOx
SIP
Call
b.
Regulatory
Requirements
c.
SIP
Submittal
and
Implementation
Requirements
3.
Michigan
v.
EPA
Court
Case
4.
Implementation
of
the
NOx
SIP
Call
B.
How
Does
EPA
Interpret
the
Clean
Air
Act's
Pollution
Transport
Provisions
in
Today's
Rule?
1.
CAIR
Analytical
Approach
a.
Nature
of
Nonattainment
Problem
and
Overview
of
Today's
Approach
b.
Air
Quality
Factor
c.
Cost
Factor
d.
Other
Factors
e.
Regulatory
Requirements
f.
SIP
Submittal
and
Implementation
Requirements
2.
What
Did
Commenters
Say
and
What
Is
EPA's
Response?
a.
Aspects
of
Contribute­
Significantly
Test
III.
Why
Does
This
Rule
Focus
on
SO2
and
NOx,
and
How
Were
Significant
Downwind
Impacts
Determined?
A.
What
is
the
Basis
for
EPA's
Decision
to
Require
Reductions
in
Upwind
Emissions
of
SO2
and
NOx
to
Address
PM2.5
related
transport?
1.
How
did
EPA
determine
which
pollutants
were
necessary
to
control
to
address
interstate
transport
for
PM2.5?
a.
What
did
EPA
propose
regarding
this
issue
in
the
NPR?
b.
How
does
EPA
address
public
comments
on
its
proposal
to
address
SO2
and
NOx
emissions
and
not
other
pollutants?

b.
How
Did
EPA
Determine
That
Reductions
in
Interstate
Transport,
as
Well
as
Reductions
in
Local
Emissions,
Are
Warranted
to
Help
Ozone
Nonattainment
Areas
to
Meet
the
8­
hour
Ozone
Standard?
1.
What
Did
EPA
Say
in
its
Proposal
Notice?
2.
What
Did
Commenters
Say?
a.
The
Need
for
Reductions
in
Interstate
Ozone
Transport
b.
Magnitude
of
Ozone
Reductions
Achieved
c.
Why
Is
EPA
Addressing
Ozone
Transport
in
this
Rule,
Given
That
EPA
Already
Issued
the
NOx
SIP
Call?
1.
EPA's
Legal
Authority
to
Require
Controls
Beyond
the
NOx
SIP
Call
2.
Authority
to
Revisit
NOx
SIP
Call
Requirements
C.
Comments
on
Excluding
Future
Case
Measures
from
the
Emissions
Baselines
Used
to
Estimate
Downwind
Ambient
Contribution
D.
What
Criteria
Should
Be
Used
to
Determine
Which
States
10
are
Subject
to
this
Rule
Because
They
Contribute
to
PM2.5
Nonattainment?
1.
What
is
the
Appropriate
Metric
for
Assessing
Downwind
PM2.5
Contribution?
a.
Notice
of
Proposed
Rulemaking
b.
Comments
and
EPA's
Responses
c.
Today's
Action
2.
What
is
the
Level
of
the
PM2.5
Contribution
Threshold?
a.
Notice
of
Proposed
Rulemaking
b.
Comments
and
EPA's
Responses
c.
Today's
Action
E.
What
Criteria
Should
be
Used
to
Determine
Which
States
are
Subject
to
this
Rule
Because
They
Contribute
to
Ozone
Nonattainment?
1.
Notice
of
Proposed
Rulemaking
2.
Comments
and
EPA
Responses
3.
Today's
Action
F.
Issues
Related
to
Timing
of
the
CAIR
Controls
IV.
What
Amounts
of
SO2
and
NOx
Emissions
Did
EPA
Determine
Should
Be
Reduced?
A.
What
Methodology
Did
EPA
Use
to
Determine
the
Amounts
of
SO2
and
NOx
Emissions
that
Must
Be
Eliminated?
1.
The
EPA's
Cost
Modeling
Methodology
2.
EPA's
Proposed
Methodology
to
Determine
Amounts
of
Emissions
that
Must
be
Eliminated
a.
Overview
of
EPA
Proposal
for
the
Levels
of
Reductions
and
Resulting
Caps,
and
their
Timing
b.
Regulatory
History:
NOx
SIP
Call
c.
Proposed
Criteria
for
Emissions
Reduction
Requirements
3.
What
Are
the
Most
Significant
Comments
that
EPA
Received
about
its
Proposed
Methodology
for
Determining
the
Amounts
of
SO2
and
NOx
Emissions
that
Must
Be
Eliminated,
and
What
Are
EPA's
Responses?
4.
EPA's
Evaluation
of
Highly
Cost­
Effective
SO2
and
NOx
Emissions
Reductions
Based
on
Controlling
EGUs
a.
SO2
Emissions
Reductions
Requirements
b.
NOx
Emissions
Reductions
Requirements
B.
What
Other
Sources
Did
EPA
Consider
when
Determining
Emission
Reduction
Requirements?
1.
Potential
Sources
of
Highly
Cost­
Effective
Emissions
Reductions
a.
Mobile
and
Area
Sources
b.
Non­
EGU
Boilers
and
Turbines
c.
Other
Non­
EGU
Stationary
Sources
C.
Schedule
for
Implementing
SO2
and
NOx
Emissions
Reduction
Requirements
for
PM2.5
and
Ozone
1.
Overview
11
2.
Engineering
Factors
Affecting
Timing
for
Control
Retrofits
a.
NPR
b.
Comments
c.
Responses
3.
Assure
Financial
Stability
D.
Control
Requirements
in
Today's
Final
Rule
1.
Criteria
Used
to
Determine
Final
Control
Requirements
2.
Final
Control
Requirements
V.
Determination
of
State
Emissions
Budgets
A.
What
Is
the
Approach
for
Setting
State­
by­
State
Annual
Emissions
Reductions
Requirements
and
EGU
Budgets?
1.
SO2
Emissions
Budgets
a.
State
Annual
SO2
Emission
Budget
Methodology
b.
Final
SO2
State
Emission
Budget
Methodology.
c.
Use
of
SO2
budgets
2.
NOx
Annual
Emissions
Budgets
a.
Overview
b.
State
Annual
NOx
Emissions
Budget
Methodology
c.
Final
Annual
State
NOx
Emission
Budgets
d.
Use
of
Annual
NOx
Budgets
e.
NOx
Compliance
Supplement
Pool
B.
What
Is
the
Approach
for
Setting
State­
by­
State
Emissions
Reductions
Requirements
and
EGU
Budgets
for
States
with
NOx
Ozone
Season
Reduction
Requirements?
1.
States
Subject
to
Ozone­
season
Requirements
VI.
Air
Quality
Modeling
Approach
and
Results
A.
What
Air
Quality
Modeling
Platform
Did
EPA
Use?
1.
Air
Quality
Models
a.
The
PM2.5
Air
Quality
Model
and
Evaluation
b.
Ozone
Air
Quality
Modeling
Platform
and
Model
Evaluation
c.
Model
Grid
Cell
Configuration
2.
Emissions
Inventory
Data
3.
Meteorological
Data
B.
How
did
EPA
Project
Future
Nonattainment
for
PM2.5
and
8­
Hour
Ozone?
1.
Projection
of
Future
PM2.5
Nonattainment
a.
Methodology
for
Projecting
Future
PM2.5
Nonattainment
b.
Projected
2010
and
2015
Base
Case
PM2.5
Nonattainment
Counties
2.
Projection
of
Future
8­
Hour
Ozone
Nonattainment
a.
Methodology
for
Projecting
Future
8­
Hour
Ozone
Nonattainment
b.
Projected
2010
and
2015
Base
Case
8­
Hour
Ozone
Nonattainment
Counties
12
C.
How
did
EPA
Assess
Interstate
Contributions
to
Nonattainment?
1.
PM2.5
Contribution
Modeling
Approach
2.
8­
Hour
Ozone
Contribution
Modeling
Approach
D.
What
Are
the
Estimated
Interstate
Contributions
to
PM2.5
and
8­
Hour
Ozone
Nonattainment?
1.
Results
of
PM2.5
Contribution
Modeling
2.
Results
of
8­
Hour
Ozone
Contribution
Modeling
E.
What
are
the
Estimated
Air
Quality
Impacts
of
the
Final
Rule?
1.
Estimated
Impacts
on
PM2.5
Concentrations
and
Attainment
2.
Estimated
Impacts
on
8­
Hour
Ozone
Concentrations
and
Attainment
F.
What
are
the
Estimated
Visibility
Impacts
of
the
Final
Rule?
1.
Methods
for
Calculating
Projected
Visibility
in
Class
I
Areas
2.
Visibility
Improvements
in
Class
I
Areas
VII.
SIP
Criteria
and
Emissions
Reporting
Requirements
A.
What
Criteria
Will
EPA
Use
to
Evaluate
the
Approvability
of
a
Transport
SIP?
1.
Introduction
2.
Requirements
for
States
Choosing
to
Control
EGUs
a.
Emissions
Caps
and
Monitoring
b.
Using
the
Model
Trading
Rules
c.
Using
a
Mechanism
Other
than
the
Model
Trading
Rules
d.
Retirement
of
Excess
Title
IV
Allowances
3.
Requirements
for
States
Choosing
to
Control
Sources
Other
than
EGUs
a.
Overview
of
Requirements
b.
Eligibility
of
Non­
EGU
Reductions
c.
Emissions
Controls
and
Monitoring
d.
Emissions
Inventories
and
Demonstrating
Reductions
4.
Controls
on
Non­
EGUs
Only
5.
Use
of
Banked
Allowances
and
the
Compliance
Supplement
Pool
B.
State
Implementation
Plan
Schedules
1.
State
Implementation
Plan
Submission
Schedule
a.
EPA's
Authority
to
Require
Section
110(
a)(
2)(
D)
Submissions
in
Accordance
with
the
Schedule
of
Section
110(
a)(
1)
b.
EPA's
Authority
to
Require
Section
110(
a)(
2)(
D)
Submissions
Prior
to
Formal
Designation
of
Nonattainment
Areas
under
Section
107
c.
EPA's
Authority
to
Require
Section
110(
a)(
2)(
D)
Submissions
Prior
to
State
Submission
of
Nonattainment
13
Area
Plans
Under
Section
172
d.
EPA's
Authority
to
Require
Section
110(
a)(
2)(
D)
Submissions
Prior
to
Completion
of
the
Next
Review
of
the
PM2.5
and
8­
hour
Ozone
NAAQS
e.
EPA's
Authority
to
Require
States
to
Make
Section
110(
a)(
2)(
D)
Submissions
within
18
Months
of
this
Final
Rule
C.
What
Happens
If
a
State
Fails
to
Submit
a
Transport
SIP
or
EPA
Disapproves
the
Submitted
SIP?
1.
Under
What
Circumstances
Is
EPA
Required
to
Promulgate
a
FIP?
2.
What
Are
the
Completeness
Criteria?
3.
When
Would
EPA
Promulgate
the
CAIR
Transport
FIP?
D.
What
Are
the
Emissions
Reporting
Requirements
for
States?
1.
Purpose
and
Authority
2.
Pre­
existing
Emission
Reporting
Requirements
3.
Summary
of
the
Proposed
Emissions
Reporting
Requirements
4.
Summary
of
Comments
Received
and
EPA's
Responses
5.
Summary
of
the
Emissions
Reporting
Requirements
VIII.
Model
NOx
and
SO2
Cap
and
Trade
Programs
A.
What
Is
the
Overall
Structure
of
the
Model
NOx
and
SO2
Cap
and
Trade
Programs?
B.
What
Is
the
Process
for
States
to
Adopt
the
Model
Cap
and
Trade
Programs
and
How
Will
It
Interact
with
Existing
Programs?
1.
Adopting
the
Model
Cap
and
Trade
Programs
2.
Flexibility
in
Adopting
Model
Cap
and
Trade
Rules
C.
What
Sources
Are
Affected
under
the
Model
Cap
and
Trade
Rules?
1.
25
MW
Cut­
off
2.
Definition
of
Fossil
Fuel­
fired
3.
Exemption
for
Cogeneration
Units
a.
Efficiency
Standard
for
Cogeneration
Units
b.
One­
third
Potential
Electric
Output
Capacity
c.
Clarifying
"
For
Sale"
d.
Multiple
Cogeneration
Units
D.
How
Are
Emission
Allowances
Allocated
to
Sources?
1.
Allocation
of
NOx
and
SO2
Allowances
a.
Required
Aspects
of
a
State
NOx
Allocation
Approach
b.
Flexibility
and
Options
for
a
State
NOx
Allowance
Allocations
Approach
E.
What
Mechanisms
Affect
the
Trading
of
Emission
Allowances?
1.
Banking
a.
The
CAIR
NPR
and
SNPR
Proposal
for
the
Model
Rules
and
14
Input
from
Commenters
b.
The
Final
CAIR
Model
Rules
and
Banking
2.
Interpollutant
Trading
Mechanisms
a.
The
CAIR
NPR
Proposal
for
the
Model
Rules
and
Input
from
Commenters
b.
Interpollutant
Trading
and
the
Final
CAIR
Model
Rules
F.
Are
There
Incentives
for
Early
Reductions?
1.
Incentives
for
Early
SO2
Reductions
a.
The
CAIR
NPR
and
SNPR
Proposal
for
the
Model
Rules
and
Input
from
Commenters
b.
SO2
Early
Reduction
Incentives
in
the
Final
CAIR
Model
Rules
2.
Incentives
for
Early
NOx
Reductions
a.
The
CAIR
NPR
and
SNPR
Proposal
for
the
Model
Rules
and
Input
from
Commenters
b.
NOx
Early
Reduction
Incentives
in
the
Final
CAIR
Model
Rules
G.
Are
There
Individual
Unit
"
Opt­
In"
Provisions?
1.
Applicability
2.
Allowing
Single
Pollutant
3.
Allocation
Method
for
Opt­
Ins
4.
Alternative
Opt­
In
Approach
5.
Opting
Out
6.
Treatment
of
Units
that
Permanently
Shutdown
7.
Regulatory
Relief
for
Opt
in
Units
H.
What
Are
the
Source­
Level
Emissions
Monitoring
and
Reporting
Requirements?
I.
What
is
Different
between
CAIR's
Annual
and
Seasonal
NOx
Model
Cap
and
Trade
Rules?
J.
Are
There
Additional
Changes
to
Proposed
Model
Cap
and
Trade
Rules
Reflected
in
the
Regulatory
Language?

IX.
Interactions
with
Other
Clean
Air
Act
Requirements
A.
How
Does
this
Rule
Interact
with
the
NOx
SIP
Call?
B.
How
Does
this
Rule
Interact
with
the
Acid
Rain
Program?
1.
Legal
Authority
for
Using
Title
IV
Allowances
in
CAIR
Model
SO2
Cap­
and­
Trade
Program
2.
Legal
Authority
for
Requiring
Retirement
of
Excess
Title
IV
Allowances
if
State
Does
Not
Use
CAIR
Model
SO2
Cap­
and­
Trade
Program
3.
Revisions
to
Acid
Rain
Regulations
C.
How
Does
the
Rule
Interact
with
the
Regional
Haze
Program?
1.
How
Does
this
Rule
Relate
to
Requirements
for
Best
Available
Retrofit
Technology
(
Bart)
under
the
Visibility
Provisions
of
the
CAA?
a.
Supplemental
Notice
of
Proposed
Rulemaking
b.
Comments
and
EPA's
Responses
15
c.
Today's
Action
2.
What
improvements
did
EPA
make
to
the
BART
versus
CAIR
modeling,
and
what
are
the
new
results?
a.
Supplemental
Notice
of
Proposed
Rulemaking
b.
Comments
and
EPA
Responses
c.
Today's
Action
D.
How
Will
EPA
Handle
State
Petitions
Under
Section
126
of
the
CAA?
E.
Will
Sources
Subject
to
CAIR
Also
Be
Subject
To
New
Source
Review?

X.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
1.
What
Economic
Analyses
Were
Conducted
for
the
Rulemaking?
2.
What
Are
the
Benefits
and
Costs
of
this
Rule?
a.
Control
Scenario
b.
Cost
Analysis
and
Economic
Impacts
c.
Human
Health
Benefit
Analysis
d.
Quantified
and
Monetized
Welfare
Benefits
3.
How
Do
the
Benefits
Compare
to
the
Costs
of
This
Final
Rule?
4.
What
are
the
Unquantified
and
Unmonetized
Benefits
of
CAIR
Emissions
Reductions?
a.
What
are
the
Benefits
of
Reduced
Deposition
of
Sulfur
and
Nitrogen
to
Aquatic,
Forest,
and
Coastal
Ecosystems?
b.
Are
There
Health
or
Welfare
Disbenefits
of
CAIR
That
Have
Not
Been
Quantified?
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
D.
Unfunded
Mandates
Reform
Act
E.
Executive
Order
13132:
Federalism
F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
G.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
and
Safety
Risks
H.
Executive
Order
13211:
Actions
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
Advancement
Act
J.
Executive
Order
12898:
Federal
Actions
to
Address
Environmental
Justice
in
Minority
Populations
and
Low­
Income
Populations
K.
Congressional
Review
Act
L.
Judicial
Review
CFR
Revisions
and
Additions
(
Rule
Text)
Part
51
16
1"
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Interstate
Air
Quality
Rule);
Proposed
Rule,"
(
69
FR
4566,
January
30,
2004)
(
NPR
or
January
Proposal);
"
Supplemental
Proposal
for
the
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule);
Proposed
Rule,"
(
69
FR
32684,
June
10,
2004)
(
SNPR
or
Supplemental
Proposal).
Part
72
Part
73
Part
74
Part
77
Part
78
Part
96
I.
Overview
By
notice
of
proposed
rulemaking
dated
January
30,
2004
and
by
notice
of
supplemental
rulemaking
dated
June
10,

2004,
EPA
proposed
to
find
that
certain
States
must
reduce
emissions
of
SO2
and/
or
NOx
because
those
emissions
contribute
significantly
to
downwind
areas
in
other
States
that
are
not
meeting
the
annual
PM2.5
NAAQS
or
the
8­
hour
ozone
NAAQS.
1
Today,
EPA
takes
final
action
requiring
28
States
and
the
District
of
Columbia
to
adopt
and
submit
revisions
to
their
State
implementation
plans
(
SIPs),
under
the
requirements
of
CAA
section
110(
a)(
2)(
D),
that
would
eliminate
specified
amounts
of
SO2
and/
or
NOx
emissions.

Each
State
may
independently
determine
which
emissions
sources
to
subject
to
controls,
and
which
control
measures
to
adopt.
The
EPA's
analysis
indicates
that
emissions
reductions
from
electric
generating
units
(
EGUs)
are
highly
17
2These
data
are
from
EPA's
most
recent
IPM
modeling
reflecting
the
final
CAIR
of
today's
notice.
These
results
may
differ
slightly
from
those
appearing
in
elsewhere
in
this
preamble
and
the
RIA,
which
were
largely
based
upon
a
model
run
that
included
Arkansas,
Delaware,
and
New
Jersey
in
the
annual
CAIR
requirements
and
also
did
not
apply
an
ozone
season
cap
on
any
States
(
the
modeling
was
completed
before
EPA
had
determined
the
final
scope
of
CAIR
because
of
the
length
of
time
necessary
to
perform
air
quality
modeling).

3These
values
represent
reductions
from
future
projected
emissions
without
CAIR.
In
2010
CAIR
will
reduce
SO2
by
4.3
million
tons
from
2003
levels
and
in
2015,
it
will
reduce
SO2
emissions
by
5.4
million
tons
from
2003
levels.
In
2009,
CAIR
will
reduce
NOx
levels
by
1.7
million
tons
from
2003
levels
and
in
2010
it
will
reduce
NOx
levels
by
2.0
million
tons
from
2003
levels.
cost
effective,
and
EPA
encourages
States
to
adopt
controls
for
EGUs.
States
that
do
so
must
place
an
enforceable
limit,
or
cap,
on
EGU
emissions
(
see
section
VII
for
discussion).
The
EPA
has
calculated
the
amount
of
each
State's
EGU
emissions
cap,
or
budget,
based
on
reductions
that
EPA
has
determined
are
highly
cost
effective.
States
may
allow
their
EGUs
to
participate
in
an
EPA­
administered
cap
and
trade
program
as
a
way
to
reduce
the
cost
of
compliance,
and
to
provide
compliance
flexibility.
The
cap
and
trade
programs
are
described
in
more
detail
in
section
VIII.

The
EPA
estimates
that
today's
action
will
reduce
SO2
emissions
by
3.5
million
tons2
in
2010
and
by
3.8
million
tons
in
2015;
and
would
reduce
annual
NOx
emissions
by
1.2
million
tons
in
2009
and
by
1.5
million
tons
in
2015.3
18
4It
should
be
noted
that
the
banking
provisions
of
the
cap
and
trade
program
which
encourage
sources
to
make
significant
reductions
before
2010
also
allow
sources
to
operate
above
these
cap
levels
until
all
of
the
banked
allowances
are
used,
therefore
EPA
does
not
project
that
these
caps
will
be
met
in
2010
or
2015.
(
These
numbers
are
for
the
23
States
and
the
District
of
Columbia
that
are
affected
by
the
annual
SO2
and
NOx
requirements
of
CAIR.)
If
all
the
affected
States
choose
to
achieve
these
reductions
through
EGU
controls,
then
EGU
SO2
emissions
in
the
affected
States
would
be
capped
at
3.6
million
tons
in
2010
and
2.5
million
tons
in
20154;
and
EGU
annual
NOx
emissions
would
be
capped
at
1.5
million
tons
in
2009
and
1.3
million
tons
in
2015.
The
EPA
estimates
that
the
required
SO2
and
NOx
emissions
reductions
would,
by
themselves,
bring
into
attainment
52
of
the
79
counties
that
are
otherwise
projected
to
be
in
nonattainment
for
PM2.5
in
2010,
and
57
of
the
74
counties
that
are
otherwise
projected
to
be
in
nonattainment
for
PM2.5
in
2015.
The
EPA
further
estimates
that
the
required
NOx
emissions
reductions
would,
by
themselves,
bring
into
attainment
3
of
the
40
counties
that
are
otherwise
projected
to
be
in
nonattainment
for
8­
hour
ozone
in
2010,
and
6
of
the
22
counties
that
are
projected
to
be
in
nonattainment
for
8­

hour
ozone
in
2015.
In
addition,
today's
rule
will
improve
PM2.5
and
8­
hour
ozone
air
quality
in
the
areas
that
would
remain
nonattainment
for
those
two
NAAQS
after
19
implementation
of
today's
rule.
Because
of
today's
rule,

the
States
with
those
remaining
nonattainment
areas
will
find
it
less
burdensome
and
less
expensive
to
reach
attainment
by
adopting
additional
local
controls.
The
Clean
Air
Interstate
Rule
(
CAIR)
will
also
reduce
PM2.5
and
8­
hour
ozone
levels
in
attainment
areas,
providing
significant
health
and
environmental
benefits
in
all
areas
of
the
eastern
US.

The
EPA's
CAIR
and
the
previously
promulgated
NOx
SIP
Call
reflect
EPA's
determination
that
the
required
SO2
and
NOx
reductions
are
sufficient
to
eliminate
upwind
States'

significant
contribution
to
downwind
nonattainment.
These
programs
are
not
designed
to
eliminate
all
contributions
to
transport,
but
rather
to
balance
the
burden
for
achieving
attainment
between
regional­
scale
and
local­
scale
control
programs.

The
EPA
conducted
a
regulatory
impact
analysis
(
RIA),

entitled
"
Regulatory
Impact
Analysis
for
the
Final
Clean
Air
Interstate
Rule
(
March
2005)"
that
estimates
the
annual
private
compliance
costs
(
1999$)
of
$
2.4
billion
for
2010
and
$
3.6
billion
for
2015,
if
all
States
make
the
required
emissions
reductions
through
the
power
industry.

Additionally,
the
RIA
includes
a
benefit­
cost
analysis
demonstrating
that
substantial
net
economic
benefits
to
20
5
Benefit
and
cost
estimates
reflect
annual
SO2
and
NOx
controls
for
Arkansas
that
are
not
a
part
of
the
final
CAIR
program.
For
this
reason,
these
estimates
are
slightly
overstated.
society
will
be
achieved
from
the
emissions
reductions
required
in
this
rulemaking.
For
determination
of
net
benefits,
the
above
private
costs
were
converted
to
social
costs
that
are
lower
since
transfer
payments,
such
as
taxes,

are
removed
from
the
estimates.
The
EPA
analysis
shows
that
today's
action
inclusive
of
the
concurrent
New
Jersey
and
Delaware
proposal
will
generate
annual
net
benefits
of
approximately
$
71.4
or
$
60.4
billion
in
2010
and
$
98.5
or
$
83.2
billion
in
2015.5
These
alternate
net
benefit
estimates
reflect
differing
assumptions
about
the
social
discount
rate
used
to
estimate
the
benefits
and
costs
of
the
rule.
The
lower
estimates
reflect
a
discount
rate
of
7
percent
and
the
higher
estimates
a
discount
rate
of
3
percent.
In
2015,
the
total
annual
quantified
benefits
are
$
101
or
$
86.3
billion
and
the
annual
social
costs
are
$
2.6
or
$
3.1
billion
 
benefits
outweigh
costs
in
2015
by
a
ratio
of
39
to
1
or
28
to
1
(
3
percent
and
7
percent
discount
rates,
respectively).
These
estimates
do
not
include
the
value
of
benefits
or
costs
that
we
cannot
monetize.

In
2015,
we
estimate
that
PM­
related
annual
benefits
include
approximately
17,000
fewer
premature
fatalities,

8,700
fewer
cases
of
chronic
bronchitis,
22,000
fewer
non­
21
fatal
heart
attacks,
10,500
fewer
hospitalization
admissions
(
for
respiratory
and
cardiovascular
disease
combined)
and
result
in
significant
reductions
in
days
of
restricted
activity
due
to
respiratory
illness
(
with
an
estimate
of
9.9
million
fewer
minor
restricted
activity
days)
and
approximately
1,700,000
fewer
work
loss
days.
We
also
estimate
substantial
health
improvements
for
children
from
reduced
upper
and
lower
respiratory
illness,
acute
bronchitis,
and
asthma
attacks.

Ozone
health­
related
benefits
are
expected
to
occur
during
the
summer
ozone
season
(
usually
ranging
from
May
to
September
in
the
Eastern
U.
S.).
Based
upon
modeling
for
2015,
annual
ozone­
related
health
benefits
are
expected
to
include
2,800
fewer
hospital
admissions
for
respiratory
illnesses,
280
fewer
emergency
room
admissions
for
asthma,

690,000
fewer
days
with
restricted
activity
levels,
and
510,000
fewer
days
where
children
are
absent
from
school
due
to
illnesses.

In
addition
to
these
significant
health
benefits,
the
rule
will
result
in
ecological
and
welfare
benefits.
These
benefits
include
visibility
improvements;
reductions
in
acidification
in
lakes,
streams,
and
forests;
reduced
eutrophication
in
water
bodies;
and
benefits
from
reduced
ozone
levels
for
forests
and
agricultural
production.
22
6Technical
support
document:
"
Regional
and
State
SO2
and
NOx
Emissions
Budgets"
is
included
in
the
docket.

Technical
support
document:
"
Air
Quality
Modeling"
is
included
in
the
docket.

7"
Response
to
Significant
Comments
on
the
Proposed
Clean
Air
Interstate
Rule"
is
included
in
the
docket.
Several
other
documents
containing
detailed
explanations
of
other
key
elements
of
today's
rule
are
also
included
in
the
docket.
These
include
a
detailed
explanation
of
how
EPA
calculated
the
State­
by­
State
EGU
emissions
budgets,
and
a
detailed
explanation
of
the
air
quality
modeling
analyses
which
support
this
rule.
6
Responses
to
comments
that
are
not
addressed
in
the
preamble
to
today's
rule
are
included
in
a
separate
document.
7
The
remaining
sections
of
the
preamble
describe
the
final
CAIR
requirements
and
our
responses
to
comments
on
many
of
the
most
important
features
of
the
CAIR.
Section
II,
"
EPA's
Analytical
Approach,"
summarizes
EPA's
overall
analytical
approach
and
responds
to
general
comments
on
that
approach.
Section
III,
"
What
Pollutants
and
States
Are
Covered
By
This
Rule?,"
outlines
the
rationale
for
the
CAIR
focus
on
SO2
and
NOX,
which
are
precursors
that
contribute
to
PM2.5
(
SO2,
NOx)
or
ozone
(
NOx)
transport,
and
the
analytic
approach
EPA
used
to
determine
which
States
had
large
enough
downwind
ambient
air
quality
impacts
to
become
subject
to
today's
requirements.
Section
IV,
"
What
Amounts
23
of
SO2
and
NOX
Emissions
Did
EPA
Determine
Should
Be
Reduced?,"
describes
EPA's
methodology
for
determining
the
amounts
of
SO2
and
NOX
emissions
reductions
required
under
today's
rule.
Section
V,
"
Determination
of
State
Emissions
Budgets,"
describes
how
EPA
determined
the
State­
by­
State
emissions
reductions
requirements
and,
in
the
event
States
elect
to
control
EGUs,
the
State­
by­
State
EGU
emissions
budgets.
Section
VI,
"
Air
Quality
Modeling
Approach
and
Results,"
describes
the
technical
aspects
of
the
air
quality
modeling
and
summarizes
the
numerical
results
of
that
modeling.
Section
VII,
"
SIP
Criteria
and
Emissions
Reporting
Requirements,"
describes
the
SIP
submission
date
and
other
SIP
requirements
associated
with
the
emissions
controls
that
States
might
adopt.
Section
VIII,
"
NOX
and
SO2
Model
Cap
and
Trade
Programs,"
describes
the
EPA
administered
cap
and
trade
programs
that
States
electing
to
control
emissions
from
EGUs
are
encouraged
to
adopt.

Section
IX,
"
Interactions
with
Other
Clean
Air
Act
Requirements,"
discusses
how
this
rule
interacts
with
the
acid
rain
provisions
in
CAA
title
IV,
the
NOX
SIP
Call,
the
best
available
retrofit
technology
(
BART)
requirements,
and
other
CAA
or
regulatory
requirements.
Finally,
section
X,

"
Statutory
and
Executive
Order
Reviews,"
describes
the
applicability
of
various
administrative
requirements
for
24
8In
today's
final
rule,
when
we
use
the
term
"
transport"
we
mean
to
include
the
transport
of
both
fine
particles
(
PM2.5)
and
their
precursor
emissions
and/
or
transport
of
both
ozone
and
its
precursor
emissions.
today's
rule
and
how
EPA
addressed
these
requirements.

A.
What
Are
the
Central
Requirements
of
this
Rule?

In
today's
action,
we
establish
SIP
requirements
for
the
affected
upwind
States
under
CAA
section
110(
a)(
2).

Clean
Air
Act
section
110(
a)(
2)(
D)
requires
SIPs
to
contain
adequate
provisions
prohibiting
air
pollutant
emissions
from
sources
or
activities
in
those
States
that
contribute
significantly
to
nonattainment
in,
or
interfere
with
maintenance
by,
any
other
State
with
respect
to
a
NAAQS.

Based
on
air
quality
modeling
analyses
and
cost
analyses,

EPA
has
concluded
that
SO2
and
NOX
emissions
in
certain
States
in
the
eastern
part
of
the
country,
through
the
phenomenon
of
air
pollution
transport,
8
contribute
significantly
to
downwind
nonattainment,
or
interfere
with
maintenance,
of
the
PM2.5
and
8­
hour
ozone
NAAQS.
The
EPA
is
requiring
SIP
revisions
in
28
States
and
the
District
of
Columbia
to
reduce
SO2
and/
or
NOX
emissions,
which
are
important
precursors
of
PM2.5
(
NOX
and
SO2)
and
ozone
(
NOX).

The
23
States
along
with
the
District
of
Columbia
that
must
reduce
annual
SO2
and
NOX
emissions
for
the
purposes
of
the
PM2.5
NAAQS
are:
Alabama,
Florida,
Georgia,
Illinois,
25
Indiana,
Iowa,
Kentucky,
Louisiana,
Maryland,
Michigan,

Minnesota,
Mississippi,
Missouri,
New
York,
North
Carolina,

Ohio,
Pennsylvania,
South
Carolina,
Tennessee,
Texas,

Virginia,
West
Virginia,
and
Wisconsin.

The
25
States
along
with
the
District
of
Columbia
that
must
reduce
NOX
emissions
for
the
purposes
of
the
8­
hour
ozone
NAAQS
are:
Alabama,
Arkansas,
Connecticut,
Delaware,

Florida,
Illinois,
Indiana,
Iowa,
Kentucky,
Louisiana,

Maryland,
Massachusetts,
Michigan,
Mississippi,
Missouri,

New
Jersey,
New
York,
North
Carolina,
Ohio,
Pennsylvania,

South
Carolina,
Tennessee,
Virginia,
West
Virginia,
and
Wisconsin.
In
addition
to
making
the
findings
of
significant
contribution
to
nonattainment
or
interference
with
maintenance,
EPA
is
requiring
each
State
to
make
specified
amounts
of
SO2
and/
or
NOX
emissions
reductions
to
eliminate
their
significant
contribution
to
downwind
States.

The
affected
States
and
the
District
of
Columbia
are
required
to
adopt
and
submit
the
required
SIP
revision
with
the
necessary
control
measures
by
18
months
from
the
signature
date
of
today's
rule.

The
emissions
reductions
requirements
are
based
on
controls
that
EPA
has
determined
to
be
highly
cost
effective
for
EGUs.
However,
States
have
the
flexibility
to
choose
the
measures
to
adopt
to
achieve
the
specified
emissions
26
reductions.
If
the
State
chooses
to
control
EGUs,
then
it
must
establish
a
budget
­­
that
is,
an
emissions
cap
­­
for
those
sources.
Today's
rule
defines
the
EGU
budgets
for
each
affected
State
if
a
State
chooses
to
control
only
EGUs.

The
rule
also
explains
the
emission
reduction
requirements
if
a
State
chooses
to
achieve
some
or
all
of
its
required
emission
reductions
by
controlling
sources
other
than
EGUs.

Due
to
feasibility
constraints,
EPA
is
requiring
emissions
reductions
be
implemented
in
two
phases.
The
first
phase
of
NOX
reductions
starts
in
2009
(
covering
2009­
2014)
and
the
first
phase
of
SO2
reductions
starts
in
2010
(
covering
2010­

2014);
the
second
phase
of
reductions
for
both
NOX
and
SO2
starts
in
2015
(
covering
2015
and
thereafter).
For
States
subject
to
findings
of
significant
contribution
for
PM2.5,

EPA
is
establishing
annual
emissions
budgets.
For
States
subject
to
findings
of
significant
contribution
for
8­
hour
ozone,
the
CAIR
specifies
ozone­
season
NOX
emissions
budgets.
States
subject
to
findings
for
both
PM2.5
and
ozone
will
have
both
an
annual
and
an
ozone
season
NOX
budget.

The
EPA
is
providing,
as
an
option
to
States,
model
cap
and
trade
programs
for
EGUs.
The
EPA
will
administer
these
programs,
which
will
be
governed
by
rules
provided
by
EPA
that
States
may
adopt
or
incorporate
by
reference.
27
With
respect
to
federally
recognized
Indian
Tribes,
the
applicability
of
this
rule
is
governed
by
three
factors:
the
flexible
regulatory
framework
for
Tribes
provided
by
the
CAA
and
the
Tribal
Authority
Rule
(
TAR);
the
absence
of
any
existing
EGUs
on
Tribal
lands
in
the
CAIR
region;
and
the
existence
of
reservations
within
the
geographic
areas
which
we
determined
to
contribute
significantly
to
nonattainment
areas.

Under
CAA
section
301(
d)
as
implemented
by
the
TAR,

eligible
Indian
Tribes
may
implement
all,
but
are
not
required
to
implement
any,
programs
under
the
CAA
for
which
EPA
has
determined
that
it
is
appropriate
to
treat
Tribes
similarly
to
States.
Tribes
may
also
implement
"
reasonably
severable"
elements
of
programs
(
40
CFR
49.7(
c)).
In
the
absence
of
Tribal
implementation
of
a
CAA
program
or
programs,
EPA
will
utilize
Federal
implementation
for
the
relevant
area
of
Indian
country
as
necessary
or
appropriate
to
protect
air
quality,
in
consultation
with
the
Tribal
government.

The
TAR
contains
a
list
of
provisions
for
which
it
is
not
appropriate
to
treat
Tribes
in
the
same
manner
as
States
(
40
CFR
49.4).
The
CAIR
is
based
on
the
States'
obligations
under
CAA
section
110(
a)(
2)(
D)
to
prohibit
emissions
which
would
contribute
significantly
to
nonattainment
in,
or
28
interfere
with
maintenance
by,
other
States
due
to
pollution
transport.
Because
CAA
section
110(
a)(
2)(
D)
is
not
among
the
provisions
we
determined
to
be
inappropriate
to
apply
to
Tribes
in
the
same
manner
as
States,
that
section
is
applicable,
where
necessary
and
appropriate,
to
Tribes.

However,
among
the
CAA
provisions
not
appropriate
for
Tribes
are
"[
s]
pecific
plan
submittal
and
implementation
deadlines
for
NAAQS­
related
requirements..."
(
40
CFR
49.4(
a)).
Therefore,
Tribes
are
not
required
to
submit
implementation
plans
under
section
110(
a)(
2)(
D).
Moreover,

because
no
Tribal
lands
in
the
CAIR
region
currently
contain
any
of
the
sources
(
EGUs)
on
which
we
based
the
emissions
reductions
requirements
applicable
to
States,
there
are
no
emission
reduction
requirements
applicable
to
Tribes.

At
the
same
time,
the
existence
of
the
CAIR
cap
and
trade
program
in
some
or
all
of
the
affected
States
will
have
implications
for
any
future
construction
of
EGUs
on
Tribal
lands.
The
geographic
scope
of
the
CAIR
cap
and
trade
program
is
being
determined
by
a
two
step­
process:
the
EPA's
determination
of
which
States
significantly
contribute
to
downwind
areas,
and
the
decision
by
those
affected
States
whether
to
satisfy
their
emission
reduction
requirement
by
participating
in
the
CAIR
cap
and
trade
program.

With
respect
to
the
first
step
of
this
process
29
9In
this
regard,
the
construction
of
a
new
EGU
on
a
reservation
would
be
analogous
to
the
construction
of
a
new
EGU
within
a
county
or
region
of
a
CAIR­
affected
State
that
does
not
presently
contain
any
EGUs.
This
is
not
meant
to
imply
that
Tribes
are
in
any
way
legally
similar
to
counties,
only
that,
within
the
CAIR
region,
the
geographic
scale
of
reservations
is
more
similar
to
counties
than
to
States.

10Although
it
is
possible
that
the
CAIR
cap
and
trade
program
may
cover
a
discontinuous
area
depending
on
which
States
participate,
the
failure
of
a
State
to
participate
(
significant
contribution
test),
notwithstanding
the
political
autonomy
of
Tribes,
we
view
the
zero­
out
modeling
as
representing
the
entire
geographic
area
within
the
State
being
considered,
regardless
of
the
jurisdictional
status
of
areas
within
the
State.
Therefore,
any
EGU
constructed
in
the
future
on
a
reservation
within
a
CAIR­
affected
State
would
be
located
in
an
area
which
we
have
already
determined
to
significantly
contribute
to
downwind
nonattainment.
9
With
respect
to
decisions
by
States
to
participate
in
the
CAIR
cap
and
trade
program,
because
Tribal
governments
are
autonomous,
such
a
decision
would
not
be
directly
binding
for
any
Tribe
located
within
the
State.

Nonetheless,
as
a
matter
of
a
policy,
cap
and
trade
programs
by
their
nature
must
apply
consistently
throughout
the
geographic
region
of
the
program
in
order
to
be
effective.
Otherwise,
the
existence
of
areas
not
covered
by
the
cap
could
create
incentives
to
locate
sources
there,
and
thereby
undermine
the
environmental
goals
of
the
program.
10
30
does
not
raise
the
same
environmental
integrity
concern.
A
state
that
does
not
participate
in
the
cap
and
trade
program
must
still
submit
a
SIP
that
limits
emissions
to
the
levels
mandated
by
the
CAIR
emission
reduction
requirements,
taking
into
account
any
emissions
from
new
sources.
In
light
of
these
considerations,
in
the
event
of
any
future
planned
construction
of
EGUs
on
Tribal
lands
within
the
CAIR
region,
EPA
intends
to
work
with
the
relevant
Tribal
government
to
regulate
the
EGU
through
either
a
Tribal
implementation
plan
(
TIP)
or
a
Federal
implementation
plan
(
FIP).
We
anticipate
that
at
a
minimum,
a
proposed
EGU
on
a
reservation
within
a
State
participating
in
the
CAIR
cap
and
trade
program
would
need
to
be
made
subject
to
the
cap
and
trade
program.
In
the
case
of
a
new
EGU
on
a
reservation
in
a
CAIR­
affected
State
which
chose
not
to
participate
in
the
cap
and
trade
program,
the
new
EGU
might
also
be
required,
through
a
TIP
or
FIP,
to
participate
in
the
program.
This
would
depend
on
the
potential
for
emissions
shifting
and
other
specific
circumstances
(
e.
g.,

whether
the
EGU
would
service
the
electric
grid
of
States
involved
in
the
cap
and
trade
program.)
Again,
EPA
will
work
with
the
relevant
Tribal
government
to
determine
the
appropriate
application
of
the
CAIR.

Finally,
as
discussed
in
the
SNPR,
Tribes
have
objected
to
emissions
trading
programs
that
allocate
allowances
based
on
historic
emissions,
on
the
grounds
that
this
rewards
31
first­
in­
time
emitters
at
the
expense
of
those
who
have
not
yet
enjoyed
a
fair
opportunity
to
pursue
economic
development.
Comments
on
the
CAIR
proposal
from
Tribes
requested
a
Federal
set­
aside
of
allowances
for
Tribes,
or
other
special
Tribal
allowance
provisions.
The
few
comments
received
from
States
on
the
issue
generally
opposed
allocations
based
on
Indian
country
status.
One
State
expressed
a
willingness
to
share
its
emissions
budget
with
Tribes
in
the
event
an
EGU
locates
in
Indian
country.

The
EPA
does
not
believe
there
is
sufficient
information
to
design
Tribal
allocation
provisions
at
this
time.
A
program
designed
to
address
concerns
which
remain
largely
speculative
is
likely
to
create
more
problems
through
unintended
consequences
than
it
solves.
Therefore,

rather
than
create
a
Federal
allowance
set­
aside
for
Tribes,

EPA
will
work
with
Tribes
and
potentially
affected
States
to
address
concerns
regarding
the
equity
of
allowance
allocations
on
a
case­
by­
case
basis
as
the
need
arises.
The
EPA
may
choose
to
revisit
this
issue
through
a
separate
rulemaking
in
the
future.

B.
Why
Is
EPA
Taking
this
Action?

Emissions
reductions
to
eliminate
transported
pollution
are
required
by
the
CAA,
as
noted
above.
There
are
strong
policy
reasons
for
addressing
interstate
pollution
32
transport.

1.
Policy
Rationale
for
Addressing
Transported
Pollution
Contributing
to
PM2.5
and
Ozone
Problems
Emissions
from
upwind
States
can
alone,
or
in
combination
with
local
emissions,
result
in
air
quality
levels
that
exceed
the
NAAQS
and
jeopardize
the
health
of
residents
in
downwind
communities.
Control
of
PM2.5
and
ozone
requires
a
reasonable
balance
between
local
and
regional
controls.
If
significant
contributions
of
pollution
from
upwind
States
that
can
be
abated
by
highly
cost­
effective
controls
are
unabated,
the
downwind
area
must
achieve
greater
local
emissions
reductions,
thereby
incurring
extra
clean­
up
costs.
Requiring
reasonable
controls
for
both
upwind
and
local
emissions
sources
should
result
in
achieving
air
quality
standards
at
a
lesser
cost
than
a
strategy
that
relies
solely
on
local
controls.
For
all
these
reasons,
addressing
interstate
transport
in
advance
of
the
time
that
States
must
adopt
local
nonattainment
plans,
will
make
it
easier
for
States
to
develop
their
nonattainment
plans
because
the
States
will
know
the
degree
to
which
the
pollution
flowing
into
their
nonattainment
areas
will
be
reduced.

The
EPA
addressed
interstate
pollution
transport
for
33
11"
Finding
of
Significant
Contribution
and
Rulemaking
for
Certain
States
in
the
Ozone
Transport
Assessment
Group
Region
for
Purposes
of
Reducing
Regional
Transport
of
Ozone;
Rule,"
(
63
FR
57356;
October
27,
1998).
ozone
in
the
NOX
SIP
Call
rule
published
in
1998.11
Today's
rulemaking
is
EPA's
first
attempt
to
address
interstate
pollution
transport
for
PM2.5.
The
NOX
SIP
Call
is
substantially
reducing
ozone
transport,
helping
downwind
areas
meet
the
1­
hour
and
8­
hour
ozone
standards.
The
EPA
has
reassessed
ozone
transport
in
this
rulemaking
for
two
reasons.
First,
several
years
have
passed
since
promulgation
of
the
NOX
SIP
Call
and
updated
air
quality
and
emissions
data
are
available.
Second,
some
areas
are
expected
to
face
substantial
difficulty
in
meeting
the
8­

hour
ozone
standards.
As
a
result,
EPA
has
determined
it
is
important
to
assess
the
degree
to
which
ozone
transport
will
remain
a
problem
after
full
implementation
of
the
NOX
SIP
Call,
and
to
assess
whether
further
controls
are
warranted
to
ensure
continued
progress
toward
attainment.
The
modeling
for
the
CAIR
includes
the
NOX
SIP
Call
in
the
baseline
and
examines
later
years
than
the
NOX
SIP
Call
analyses.

a.
The
PM2.5
Problem
By
action
dated
July
18,
1997,
we
revised
the
NAAQS
for
particulate
matter
(
PM)
to
add
new
standards
for
fine
34
particles,
using
as
the
indicator
particles
with
aerodynamic
diameters
smaller
than
a
nominal
2.5
micrometers,
termed
PM2.5
(
62
FR
38652).
We
established
health­
and
welfarebased
(
primary
and
secondary)
annual
and
24­
hour
standards
for
PM2.5.
The
annual
standards
are
15
micrograms
per
cubic
meter,
based
on
the
3­
year
average
of
annual
mean
PM2.5
concentrations.
The
24­
hour
standard
is
a
level
of
65
micrograms
per
cubic
meter,
based
on
the
3­
year
average
of
the
annual
98th
percentile
of
24­
hour
concentrations.
The
annual
standard
is
generally
considered
the
most
limiting.

Fine
particles
are
associated
with
a
number
of
serious
health
effects
including
premature
mortality,
aggravation
of
respiratory
and
cardiovascular
disease
(
as
indicated
by
increased
hospital
admissions,
emergency
room
visits,

absences
from
school
or
work,
and
restricted
activity
days),

lung
disease,
decreased
lung
function,
asthma
attacks,
and
certain
cardiovascular
problems
such
as
heart
attacks
and
cardiac
arrhythmia.
The
EPA
has
estimated
that
attainment
of
the
PM2.5
standards
would
prolong
tens
of
thousands
of
lives
and
would
prevent,
each
year,
tens
of
thousands
of
hospital
admissions
as
well
as
hundreds
of
thousands
of
doctor
visits,
absences
from
work
and
school,
and
respiratory
illnesses
in
children.

Individuals
particularly
sensitive
to
fine
particle
35
exposure
include
older
adults,
people
with
heart
and
lung
disease,
and
children.
More
detailed
information
on
health
effects
of
fine
particles
can
be
found
on
EPA's
website
at:

http://
www.
epa.
gov/
ttn/
naaqs/
standards/
pm/
s_
pm_
index.
html.

At
the
time
EPA
established
the
PM2.5
primary
NAAQS
in
1997,
we
also
established
welfare­
based
(
secondary)
NAAQS
identical
to
the
primary
standards.
The
secondary
standards
are
designed
to
protect
against
major
environmental
effects
caused
by
PM
such
as
visibility
impairment
 
including
in
Class
I
areas
which
include
national
parks
and
wilderness
areas
across
the
country
 
soiling,
and
materials
damage.

As
discussed
in
other
sections
of
this
preamble,
SO2
and
NOX
emissions
both
contribute
to
fine
particle
concentrations.
In
addition,
NOX
emissions
contribute
to
ozone
problems,
described
in
the
next
section.
We
believe
the
CAIR
will
significantly
reduce
SO2
and
NOX
emissions
that
contribute
to
the
PM2.5
and
8­
hour
ozone
problems
described
here.

The
PM2.5
ambient
air
quality
monitoring
for
the
2001­

2003
period
shows
that
areas
violating
the
standards
are
located
across
much
of
the
eastern
half
of
the
United
States
and
in
parts
of
California,
and
Montana.
Based
on
these
nationwide
data,
82
counties
have
at
least
one
monitor
that
violates
either
the
annual
or
the
24­
hour
PM2.5
standard.
36
Most
areas
violate
only
the
annual
standard;
a
small
number
of
areas
violate
both
the
annual
and
24­
hour
standards;
and
no
areas
violate
just
the
24­
hour
standard.
The
population
of
these
82
counties
totals
over
56
million
people.

Only
two
States
in
the
western
part
of
the
U.
S.,

California
and
Montana,
have
counties
that
exceeded
the
PM2.5
standards.
On
the
other
hand,
in
the
eastern
part
of
the
U.
S.,
124
sites
in
69
counties
(
with
total
population
of
34
million)
violated
the
annual
PM2.5
standard
of
15.0
micrograms
per
cubic
meter
(

g/
m3)
over
the
3­
year
period
from
2001
to
2003,
while
469
sites
met
the
annual
standard.

No
sites
in
the
eastern
part
of
the
United
States
exceeded
the
daily
PM2.5
standard
of
65

g/
m3.
The
69
violating
counties
are
located
in
a
region
made
up
of
16
States
(
plus
the
District
of
Columbia),
extending
eastward
from
St.
Louis
County,
Missouri,
the
western­
most
violating
county
and
including
the
following
States:
Alabama,
Delaware,
Georgia,

Illinois,
Indiana,
Kentucky,
Maryland,
Missouri,
Michigan,

New
Jersey,
New
York,
North
Carolina,
Ohio,
Pennsylvania,

Tennessee,
West
Virginia,
and
the
District
of
Columbia.

The
EPA
published
the
PM2.5
attainment
and
nonattainment
designations
on
January
5,
2005
(
70
FR
944).
The
designations
will
be
effective
on
April
5,
2005.

Because
interstate
transport
is
not
believed
to
be
a
37
significant
contributor
to
exceedances
of
the
PM2.5
standards
in
California
or
Montana,
today's
final
CAIR
does
not
cover
these
States.

b.
The
8­
hour
Ozone
Problem
By
action
dated
July
18,
1997,
we
promulgated
identical
revised
primary
and
secondary
ozone
standards
that
specified
an
8­
hour
ozone
standard
of
0.08
parts
per
million
(
ppm).

Specifically,
under
the
standards,
the
3­
year
average
of
the
fourth
highest
daily
maximum
8­
hour
average
ozone
concentration
may
not
exceed
0.08
ppm.
In
general,
the
revised
8­
hour
standards
are
more
protective
of
public
health
and
the
environment
and
more
stringent
than
the
preexisting
1­
hour
ozone
standards.
All
areas
that
were
violating
the
1­
hour
ozone
standard
at
the
time
of
the
8­

hour
ozone
designations
were
also
designated
as
nonattainment
for
the
8­
hour
ozone
standard.
More
areas
do
not
meet
the
8­
hour
standard
than
do
not
meet
the
1­
hour
standard.
The
EPA
published
the
8­
hour
ozone
attainment
and
nonattainment
designations
in
the
Federal
Register
on
April
30,
2004
(
69
FR
23858).
The
designations
were
effective
on
June
15,
2004.
Pursuant
to
EPA's
final
rule
to
implement
the
8­
hour
ozone
standard
(
69
FR
23951;
April
30,
2004),
EPA
will
revoke
the
1­
hour
ozone
standard
on
June
15,
2005,
1
year
after
the
effective
date
of
the
8­
hour
designations.
38
Short­
term
(
1­
to
3­
hour)
and
prolonged
(
6­
to
8­
hour)

exposures
to
ambient
ozone
have
been
linked
to
a
number
of
adverse
health
effects.
Short­
term
exposure
to
ozone
can
irritate
the
respiratory
system,
causing
coughing,
throat
irritation,
and
chest
pain.
Ozone
can
reduce
lung
function
and
make
it
more
difficult
to
breathe
deeply.
Breathing
may
become
more
rapid
and
shallow
than
normal,
thereby
limiting
a
person's
normal
activity.
Ozone
also
can
aggravate
asthma,
leading
to
more
asthma
attacks
that
require
a
doctor's
attention
and
the
use
of
additional
medication.

Increased
hospital
admissions
and
emergency
room
visits
for
respiratory
problems
have
been
associated
with
ambient
ozone
exposures.
Longer­
term
ozone
exposure
can
inflame
and
damage
the
lining
of
the
lungs,
which
may
lead
to
permanent
changes
in
lung
tissue
and
irreversible
reductions
in
lung
function.
A
lower
quality
of
life
may
result
if
the
inflammation
occurs
repeatedly
over
a
long
time
period
(
such
as
months,
years,
a
lifetime).

People
who
are
particularly
susceptible
to
the
effects
of
ozone
include
children
and
adults
who
are
active
outdoors,
people
with
respiratory
diseases,
such
as
asthma,

and
people
with
unusual
sensitivity
to
ozone.

In
addition
to
causing
adverse
health
effects,
ozone
affects
vegetation
and
ecosystems,
leading
to
reductions
in
39
agricultural
crop
and
commercial
forest
yields;
reduced
growth
and
survivability
of
tree
seedlings;
and
increased
plant
susceptibility
to
disease,
pests,
and
other
environmental
stresses
(
e.
g.,
harsh
weather).
In
long­
lived
species,
these
effects
may
become
evident
only
after
several
years
or
even
decades
and
have
the
potential
for
long­
term
adverse
impacts
on
forest
ecosystems.
Ozone
damage
to
the
foliage
of
trees
and
other
plants
can
also
decrease
the
aesthetic
value
of
ornamental
species
used
in
residential
landscaping,
as
well
as
the
natural
beauty
of
our
national
parks
and
recreation
areas.
The
economic
value
of
some
welfare
losses
due
to
ozone
can
be
calculated,
such
as
crop
yield
loss
from
both
reduced
seed
production
(
e.
g.,
soybean)

and
visible
injury
to
some
leaf
crops
(
e.
g.,
lettuce,

spinach,
tobacco),
as
well
as
visible
injury
to
ornamental
plants
(
i.
e.,
grass,
flowers,
shrubs).
Other
types
of
welfare
loss
may
not
be
quantifiable
(
e.
g.,
reduced
aesthetic
value
of
trees
growing
in
heavily
visited
national
parks).
More
detailed
information
on
health
effects
of
ozone
can
be
found
at
the
following
EPA
website:

http://
www.
epa.
gov/
ttn/
naaqs/
standards/
ozone/
s_
o3_
index.
html
.

Almost
all
areas
of
the
country
have
experienced
some
progress
in
lowering
ozone
concentrations
over
the
last
20
40
12
EPA
454/
K­
04­
001,
April
2004.
years.
As
reported
in
the
EPA's
report,
"
The
Ozone
Report:

Measuring
Progress
Through
2003,"
12
national
average
levels
of
1­
hour
ozone
improved
by
29
percent
between
1980
and
2003
while
8­
hour
levels
improved
by
21
percent
over
the
same
time
period.
The
Northeast
and
West
regions
have
shown
the
greatest
improvement
since
1980.
However,
most
of
that
improvement
occurred
during
the
first
part
of
the
period.

In
fact,
during
the
most
recent
10
years,
ozone
levels
have
been
relatively
constant
reflecting
little
if
any
air
quality
improvement.
For
this
reason,
ozone
has
exhibited
the
slowest
progress
of
the
six
major
pollutants
tracked
nationally.

Although
ambient
ozone
levels
remained
relatively
constant
over
the
past
decade,
additional
control
requirements
have
reduced
emissions
of
the
two
major
ozone
precursors,
VOC
and
NOX,
although
at
different
rates.

Emissions
of
VOCs
were
reduced
by
32
percent
from
1990
levels,
while
emissions
of
NOX
declined
by
22
percent.

Ozone
remains
a
significant
public
health
concern.

Presently,
wide
geographic
areas,
including
most
of
the
nation's
major
population
centers,
experience
unhealthy
ozone
levels,
that
is,
concentrations
violating
the
NAAQS
for
8­
hour
ozone.
These
areas
include
much
of
the
eastern
41
part
of
the
United
States
and
large
areas
of
California.

More
specifically,
297
counties
with
a
total
population
of
over
124
million
people
currently
violate
the
8­
hour
ozone
standard.
Most
of
these
ozone
violations
occur
in
the
eastern
half
of
the
United
States:
268
counties
with
a
population
of
over
93
million.

When
ozone
and
PM2.5
are
examined
jointly,
322
counties
with
131
million
people
are
violating
at
least
one
of
the
standards
while
57
counties
nationwide
have
concentrations
violating
both
standards
with
a
total
population
of
over
49
million
people.
Of
these,
46
counties
with
a
population
of
over
28
million
are
in
the
Eastern
United
States.

c.
Other
Environmental
Effects
Associated
with
SO2
and
NOX
Emissions
Today's
action
will
result
in
benefits
in
addition
to
the
enumerated
human
health
and
welfare
benefits
resulting
from
reductions
in
ambient
levels
of
PM2.5
and
ozone.

Reductions
in
NOX
and
SO2
will
contribute
to
substantial
visibility
improvements
in
many
parts
of
the
Eastern
U.
S.

where
people
live,
work,
and
recreate,
including
Federal
Class
I
areas
such
as
the
Great
Smoky
Mountains.
Reductions
in
these
pollutants
will
also
reduce
acidification
and
eutrophication
of
water
bodies
in
the
region.
In
addition,

reduced
mercury
emissions
are
anticipated
as
a
result
of
42
this
rule.
Reduced
mercury
emissions
will
lessen
mercury
contamination
in
lakes
and
thereby
potentially
decrease
both
human
and
wildlife
exposure
to
mercury­
contaminated
fish.

2.
The
CAA
Requires
States
to
Act
as
Good
Neighbors
by
Limiting
Downwind
Impacts
The
CAA
includes
the
"
good
neighbor"
provision
of
section
110(
a)(
2)(
D),
which
requires
that
every
SIP
prohibit
emissions
from
any
source
or
other
type
of
emissions
activity
in
amounts
that
will
contribute
significantly
to
nonattainment
in
any
downwind
State,
or
that
will
interfere
with
maintenance
in
any
downwind
State.
In
today's
action,

EPA
is
determining
that
28
States
and
the
District
of
Columbia,
all
in
the
eastern
part
of
the
United
States,
have
emissions
of
SO2
and/
or
NOX
that
will
contribute
significantly
to
nonattainment,
or
interfere
with
maintenance,
of
the
PM2.5
NAAQS
and/
or
the
8­
hour
ozone
NAAQS
in
another
State.
Under
EPA's
general
authority
to
clarify
the
applicability
of
CAA
requirements,
as
provided
in
CAA
section
301(
a)(
1),
EPA
is
establishing
the
amount
of
SO2
and
NOX
emissions
that
each
affected
State
must
prohibit
by
submitting
appropriate
SIP
provisions
to
EPA.
The
improvements
in
air
quality
will
assist
downwind
States
in
developing
their
SIPs
to
provide
for
attainment
and
maintenance
in
those
nonattainment
areas.
43
3.
Today's
Rule
Will
Improve
Air
Quality
The
EPA
has
estimated
the
improvements
in
emissions
and
air
quality
that
would
result
from
implementing
the
CAIR.

These
improvements,
which
are
substantial,
are
summarized
earlier
in
this
section.

C.
What
was
the
Process
for
Developing
this
Rule?

By
action
dated
January
30,
2004,
EPA
issued
a
proposal
that
included
many
of
the
components
of
today's
action.

"
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Interstate
Air
Quality
Rule);
Proposed
Rule,"
(
69
FR
4566).
The
Administrator
signed
the
proposed
rule
 
termed,
at
that
time,
the
Interstate
Air
Quality
Rule
 
on
December
17,
2003,
and
EPA
posted
it
on
its
website
for
this
rule
on
that
date.
The
website
address
at
that
time
was
http://
www.
epa.
gov/
interstateairquality.
(
The
address
has
since
changed
to
http://
www.
epa.
gov/
cleanairinterstaterule/.)

The
EPA
held
public
hearings
on
the
proposal,
in
conjunction
with
a
proposed
rulemaking
concerning
mercury
and
other
hazardous
air
pollutants
from
EGUs,
on
February
25­
26,
2004,
in
Chicago,
Illinois;
Philadelphia,

Pennsylvania;
and
Research
Triangle
Park,
North
Carolina.

The
comment
period
for
the
NPR
closed
on
March
30,
2004.

The
EPA
received
over
6,700
comments
on
the
proposal.
44
By
action
dated
June
10,
2004,
EPA
issued
a
supplemental
notice
of
proposed
rulemaking
(
SNPR),

"
Supplemental
Proposal
for
the
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule);
Proposed
Rule,"
(
69
FR
32684).
The
Administrator
signed
the
SNPR
for
this
rule
 
now
called
the
Clean
Air
Interstate
Rule
 
on
May
18,
2004,
and
EPA
placed
it
on
the
website
on
that
date.
The
SNPR
included,
among
other
things,
proposed
regulatory
language
for
the
rule,

revised
proposals
concerning
State­
level
emissions
budgets,

proposed
State
reporting
requirements
and
SIP
approvability
criteria,
and
proposed
model
cap
and
trade
rules.
The
SNPR
also
proposed
that
under
certain
circumstances
the
CAIR
requirements
could
replace
the
BART
requirements
of
CAA
sections
169A
and
169B.
The
EPA
held
a
public
hearing
on
the
SNPR
on
June
3,
2004,
in
Alexandria,
Virginia.
The
comment
period
for
the
SNPR
closed
on
July
26,
2004.
The
EPA
received
over
400
comments
on
the
SNPR.

By
a
notice
of
data
availability
(
NODA)
dated
August
6,

2004,
EPA
announced
the
availability
of
additional
documents
for
this
action.
"
Availability
of
Additional
Information
Supporting
the
Rule
To
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule),"

(
69
FR
47828).
The
documents
had
been
placed
on
the
website
45
on
or
about
July
27,
2004,
and
in
the
EDOCKET
on
that
date,

or
shortly
thereafter.
The
EPA
allowed
public
comment
on
those
additional
documents
until
August
27,
2004.
Around
30
comments
were
received
on
the
NODA.

The
EPA
has
responded
to
all
significant
public
comments
either
in
this
preamble
or
in
the
response
to
comment
document
which
is
contained
in
the
docket.

Comments
on
Rulemaking
Process
Some
commenters
expressed
concerns
about
certain
aspects
of
this
process.
One
concern
was
that
EPA
did
not
allow
sufficient
time
to
comment
on
the
SNPR.
Commenters
noted
that
important
program
elements
 
including
regulatory
language
 
appeared
for
the
first
time
in
the
SNPR,
but
EPA
held
a
public
hearing
on
the
SNPR
7
days
before
the
SNPR
was
published
in
the
Federal
Register
and
only
16
days
after
the
SNPR
had
been
posted
on
the
website.
The
EPA
believes
that
the
16­
day
period
preceding
the
public
hearing,
and
the
total
of
45
days
to
comment
on
the
SNPR
following
its
publication
in
the
Federal
Register,
constituted
an
adequate
opportunity
for
members
of
the
public
to
comment
on
the
SNPR.

Commenters
also
expressed
concern
that
certain
technical
documents
were
not
made
available
in
sufficient
time
to
comment.
However,
EPA
had
placed
all
technical
46
support
documents
for
the
NPR
in
the
EDOCKET
as
of
the
date
of
publication
of
the
NPR,
and
all
technical
support
documents
for
the
SNPR
had
been
placed
in
the
EDOCKET
as
of
the
date
of
publication
of
the
SNPR.

Commenters
also
expressed
concern
that
in
the
SNPR,
EPA
proposed
significant
changes
to
other
regulatory
programs.

The
EPA
agrees
that
the
SNPR
did
include
proposed
changes
to
certain
regulatory
programs,
i.
e.,
the
requirements
for
BART
under
CAA
sections
169A
and
169B
(
concerning
visibility),

certain
provisions
(
primarily
concerning
the
allowanceholding
requirement)
in
the
title
IV
(
Acid
Rain
Program)

rules,
and
certain
emissions
reporting
rules
under
the
NOX
SIP
Call
(
40
CFR
51.122)
and
Consolidated
Emissions
Reporting
Rule
(
CERR)
(
title
40,
part
51,
subpart
A).
The
EPA
believes
that
to
the
extent
the
requirements
for
BART
and
emissions
reporting
rule
revisions
are
tied
to
the
CAIR,

affected
members
of
the
public
had
adequate
notice
of
those
revisions.
(
These
revisions
are
described
in
section
VII.)

However,
the
SNPR
contained
some
revisions
to
the
emissions
reporting
rules
that
were
not
tied
to
the
transport
provisions.
The
EPA
is
not
taking
final
action
today
on
the
proposal
for
the
emissions
reporting
rules
that
were
not
tied
to
the
transport
provisions
and
instead
is
issuing
a
new
proposal
for
them,
which
will
provide
additional
notice
47
and
opportunity
to
comment.

Further,
the
Acid
Rain
Program
rule
revisions,
although
connected
to
the
CAIR,
apply
to
all
persons
subject
to
the
Acid
Rain
Program,
including
persons
who
are
not
affected
by
the
CAIR.
(
These
revisions
are
described
in
section
IX.)

Specifically,
as
explained
in
section
IX,
the
revisions
to
the
Acid
Rain
Program
rules
are
aimed
at
facilitating
coordination
of
the
Acid
Rain
Program
and
the
CAIR
model
SO2
cap
and
trade
rule
and/
or
are
being
adopted
on
their
own
merits,
independently
of
the
need
to
coordinate
with
the
CAIR.
Most
of
the
proposed
revisions
involve
changing
from
unit­
by­
unit
to
source­
by­
source
compliance
with
the
allowance­
holding
requirement
of
the
Acid
Rain
Program
and
therefore
affect
every
source
subject
to
the
Acid
Rain
Program,
whether
or
not
the
source
is
also
in
a
State
covered
by
the
CAIR.
The
change
to
source­
by­
source
compliance
increases
a
source's
flexibility
to
use
­­
in
meeting
the
allowance­
holding
requirement
­­
allowances
held
by
any
unit
at
the
source.
This
flexibility
reduces
the
likelihood
that
sources
will
incur
large
excess
emissions
penalties
from
inadvertent,
minor
errors
(
e.
g.,
in
how
allowances
are
distributed
among
the
units
at
the
source),

while
preserving
the
environmental
goals
of
the
Acid
Rain
Program.
The
remaining
revisions
to
the
Acid
Rain
Program
48
rules
similarly
cover
all
Acid
Rain
Program
sources.

Indeed,
none
of
the
comments
on
the
proposed
Acid
Rain
Program
rule
revisions
stated
that
the
revisions
would
apply
only
to
certain
Acid
Rain
Program
sources,
but
rather
seemed
to
treat
the
revisions
as
applying
program­
wide.
As
discussed
in
section
IX,
EPA
is
finalizing,
with
minor
modifications,
the
Acid
Rain
Program
rule
revisions.

Commenters
also
expressed
concern
that
between
the
NPR
and
the
SNPR,
EPA
had
proposed
program
elements
in
a
piecemeal
fashion,
which
made
it
more
difficult
to
comprehend
and
comment
on
the
rule,
and
that
the
SNPR's
comment
period
was
too
short
to
allow
the
public
adequate
opportunity
to
comment
on
the
numerous
and
complex
issues
raised
in
that
proposal.
The
EPA
recognizes
the
challenges
faced
by
commenters
in
this
rulemaking,
however,
we
believe
that
the
comment
periods
for
the
NPR
and
SNPR
were
adequate,

and
note
that
we
did
receive
extensive
and
highly
detailed,

technical
comments
on
both
proposals.

D.
What
Are
the
Major
Changes
Between
the
Proposals
and
the
Final
Rule?

The
EPA
is
finalizing
a
number
of
revisions
to
the
proposed
elements
of
the
CAIR.
These
revisions
are
in
response
to
information
received
in
public
comments
and
new
analyses
conducted
by
EPA.
The
following
is
a
summary
list
49
of
those
changes:

°
The
first
phase
of
NOX
reductions
starts
in
2009
(
covering
2009­
2014)
instead
of
2010.
The
first
phase
of
the
SO2
reductions
still
starts
in
2010
(
covering
2010­

2014).

°
The
emissions
inventories
used
for
PM2.5
and
8­
hour
ozone
air
quality
modeling
have
been
updated
and
improved;

we
modeled
PM2.5
using
the
Community
Multiscale
Air
Quality
Model
(
CMAQ)
and
meteorology
for
2001
instead
of
the
Regional
Model
for
Simulating
Aerosols
and
Deposition
(
REMSAD)
and
meteorology
for
1996.

°
The
final
CAIR
does
not
cover
Kansas
based
on
new
analyses
of
its
contribution
to
downwind
PM2.5
nonattainment.

°
Arkansas,
Delaware,
Massachusetts,
and
New
Jersey
are
not
subject
to
the
CAIR
based
on
their
contribution
to
PM2.5
nonattainment
and
maintenance.
However,
they
remain
subject
to
NOX
emissions
reductions
requirements
on
the
basis
of
their
contribution
to
downwind
8­
hour
ozone
nonattainment.

This
requirement
is
for
the
ozone
season
rather
than
the
entire
year.
The
EPA
is
issuing
a
new
proposal
to
include
Delaware
and
New
Jersey
for
the
PM2.5
NAAQS
based
on
additional
considerations.

°
The
change
in
States
covered
by
the
rule
necessitates
a
50
re­
analysis
of
the
NOX
budgets
for
all
covered
States.
This
changes
the
amount
of
the
budget,
but
not
the
procedure
EPA
used
to
calculate
it.

°
The
SIP
approval
criteria
have
been
changed
to
no
longer
exclude
measures
otherwise
required
by
the
CAA
from
being
included
in
the
State's
compliance
with
CAIR.

°
A
200,000
ton
compliance
supplement
pool
was
added
for
NOX.
Allowances
from
this
pool
can
either
be
awarded
to
sources
that
make
early
reductions
or
to
sources
that
demonstrate
need.

°
All
States
for
which
EPA
has
made
a
finding
with
respect
to
ozone
are
subject
to
an
ozone
season
cap.
In
order
to
implement
this
ozone
season
cap,
EPA
has
finalized
an
ozone
season
NOX
trading
program
in
addition
to
the
annual
NOX
and
SO2
trading
programs
that
were
proposed.

°
A
number
of
changes
were
made
to
the
trading
rule
including:
changes
to
the
model
NOX
allocation
methodology
(
to
fuel
weight
allocations)
and
the
addition
of
opt
in
provisions.

°
The
EPA
is
not
finalizing
some
of
the
emissions
reporting
requirements
in
response
to
public
comments
indicating
we
gave
inadequate
notice
of
the
changes
that
were
proposed
to
be
applicable
to
all
States,
not
just
those
affected
by
the
CAIR
emission
reduction
requirements.
These
51
are
being
reproposed,
with
modifications,
in
a
separate
action
to
allow
additional
opportunity
for
public
comment
by
all
affected
States
and
other
parties.

II.
EPA's
Analytical
Approach
Overview
Today's
rulemaking
is
based
on
the
"
good
neighbor"

provision
of
CAA
section
110(
a)(
2)(
D),
which
requires
States
to
develop
SIP
provisions
assuring
that
emissions
from
their
sources
do
not
contribute
significantly
to
downwind
nonattainment,
or
interfere
with
maintenance,
of
the
NAAQS.

The
EPA
interpreted
this
provision,
and
developed
a
detailed
methodology
for
applying
it,
in
the
NOx
SIP
Call
rulemaking,

which
concerned
interstate
transport
of
ozone
precursors.

Today's
rule
requires
upwind
States
to
submit
SIP
revisions
requiring
their
sources
to
reduce
emissions
of
certain
precursors
that
significantly
contribute
to
nonattainment
in,
or
interfere
with
maintenance
of,
the
PM2.5
and
8­
hour
ozone
national
ambient
air
quality
standards
in
downwind
States.
The
EPA
developed
today's
rule
relying
heavily
on
the
NOx
SIP
Call
approach.

This
section
of
the
preamble
outlines
the
key
aspects
of
today's
approach,
some
of
which
are
described
in
greater
detail
in
other
sections
of
the
preamble.
The
EPA
received
comments
on
today's
approach
that
we
respond
to
either
in
52
this
section
or
in
the
other
sections
of
the
preamble.
This
section
also
describes
how
today's
approach
varies
from
the
NOx
SIP
Call,
which
variations
result
from,
among
other
things,
the
fact
that
today's
action
regulates
a
different
pollutant
(
PM2.5)
with
a
different
precursor
(
SO2).

A.
How
Did
EPA
Interpret
the
Clean
Air
Act's
Pollution
Transport
Provisions
in
the
NOx
SIP
Call?

1.
Clean
Air
Act
Requirements
The
central
CAA
provisions
concerning
pollutant
transport,
for
purposes
of
today's
action,
are
found
in
section
110(
a)(
2)(
D).
Under
these
provisions,
each
SIP
must
 
(
D)
contain
adequate
provisions
(
i)
prohibiting
...
any
source
or
other
type
of
emissions
activity
within
the
State
from
emitting
any
air
pollutant
in
amounts
which
will
 
(
I)
contribute
significantly
to
nonattainment
in,
or
interfere
with
maintenance
by,
any
other
State
with
respect
to
any
...
national
primary
or
secondary
ambient
air
quality
standard
....

2.
The
NOx
SIP
Call
Rulemaking
Promulgated
by
action
dated
October
27,
1998,
the
NOx
SIP
Call
was
EPA's
principal
effort
to
reduce
interstate
transport
of
precursors
for
both
the
1­
hour
ozone
NAAQS
and
53
13
In
the
NOx
SIP
Call,
because
the
same
criteria
applied,
the
discussion
of
the
"
contribute
significantly
to
nonattainment"
test
generally
also
applied
to
the
"
interfere
with
maintenance"
test.
However,
in
the
NOx
SIP
Call,
EPA
stated
that
the
"
interfere
with
maintenance"
test
applied
with
respect
to
only
the
8­
hour
ozone
NAAQS
(
63
FR
57379­
80).
the
8­
hour
ozone
NAAQS.
(
See
"
Finding
of
Significant
Contribution
and
Rulemaking
for
Certain
States
in
the
Ozone
Transport
Assessment
Group
Region
for
Purposes
of
Reducing
Regional
Transport
of
Ozone;
Rule,"
(
63
FR
57356).)
In
that
rulemaking,
EPA
imposed
seasonal
NOx
reduction
requirements
on
22
States
and
the
District
of
Columbia
in
the
eastern
part
of
the
country.

a.
Analytical
Approach
of
NOx
SIP
Call
In
the
NOx
SIP
Call,
EPA
interpreted
section
110(
a)(
2)(
D)
to
authorize
EPA
to
determine
the
amount
of
emissions
in
upwind
States
that
"
contribute
significantly"

to
downwind
nonattainment
or
"
interfere
with"
downwind
maintenance,
and
to
require
those
States
to
eliminate
that
amount
of
emissions.
The
EPA
recognized
that
States
must
retain
full
authority
to
choose
the
sources
to
control,
and
the
control
mechanisms,
to
achieve
those
reductions.

The
EPA
set
out
several
criteria
or
factors
for
the
"
contribute
significantly"
test,
and
further
indicated
that
the
same
criteria
should
apply
to
the
"
interfere
with
maintenance"
provision:
13
54
...
EPA
determined
the
amount
of
emissions
that
significantly
contribute
to
downwind
nonattainment
from
sources
in
a
particular
upwind
State
primarily
by
(
i)
evaluating,
with
respect
to
each
upwind
State,
several
air
quality
related
factors,

including
determining
that
all
emissions
from
the
State
have
a
sufficiently
great
impact
downwind
(
in
the
context
of
the
collective
contribution
nature
of
the
ozone
problem);
and
(
ii)
determining
the
amount
of
that
State's
emissions
that
can
be
eliminated
through
the
application
of
costeffective
controls.
Before
reaching
a
conclusion,

EPA
evaluated
several
secondary,
and
more
general,

considerations.
These
include:


The
consistency
of
the
regional
reductions
with
the
attainment
needs
of
the
downwind
areas
with
nonattainment
problems

The
overall
fairness
of
the
control
regimes
required
of
the
downwind
and
upwind
areas,

including
the
extent
of
the
controls
required
or
implemented
by
the
downwind
and
upwind
areas

General
cost
considerations,
including
the
55
relative
cost­
effectiveness
of
additional
downwind
controls
compared
to
upwind
controls
63
FR
57403.

i.
Air
Quality
Factor
The
first
factor
concerns
evaluating
the
impact
on
downwind
air
quality
of
the
upwind
State's
emissions.
As
EPA
stated
in
the
NOx
SIP
Call:

...
EPA
specifically
considered
three
air
quality
factors
with
respect
to
each
upwind
State....


The
overall
nature
of
the
ozone
problem
(
i.
e.,
"
collective
contribution")


The
extent
of
the
downwind
nonattainment
problems
to
which
the
upwind
State's
emissions
are
linked,
including
the
ambient
impact
of
controls
required
under
the
CAA
or
otherwise
implemented
in
the
downwind
areas

The
ambient
impact
of
the
emissions
from
the
upwind
State's
sources
on
the
downwind
nonattainment
problems
63
FR
57376.

The
EPA
explained
the
first
factor,
collective
contribution,
by
noting,

[
V]
irtually
every
nonattainment
problem
is
caused
by
numerous
sources
over
a
wide
geographic
area...[.
This]
factor
suggest[
s]
that
the
solution
to
the
problem
is
the
implementation
over
a
wide
area
of
controls
on
many
sources,
each
of
which
may
have
a
small
or
unmeasureable
ambient
impact
by
itself.

63
FR
57377.

The
second
air
quality
factor
 
the
extent
of
downwind
56
14
Although
EPA's
air
quality
modeling
techniques
examined
all
of
the
upwind
State's
emissions
of
ozone
precursors
(
including
VOC
and
NOx),
only
the
NOx
emissions
had
meaningful
interstate
impacts.
nonattainment
problems
 
concerns
whether
downwind
areas
should
be
considered
to
be
in
nonattainment.
This
determination
took
into
account
the
then­
current
air
quality
of
the
area,
the
predicted
future
air
quality
(
assuming
the
implementation
of
required
controls,
but
not
the
transport
requirements
that
were
the
subject
of
the
NOx
SIP
Call),
and
the
boundaries
of
the
area
in
light
of
designation
status
(
63
FR
57377).

The
EPA
applied
the
third
air
quality
factor
 
the
ambient
impact
of
emissions
from
the
upwind
sources
 
by
projecting
the
amount
of
the
upwind
State's
entire
inventory
of
anthropogenic
emissions
to
the
year
2007,
and
then
quantifying,
through
the
appropriate
air
quality
modeling
techniques,
the
impact
of
those
emissions
on
downwind
nonattainment.
14
Specifically,
(
i)
EPA
determined
the
minimum
threshold
impact
that
the
upwind
State's
emissions
must
have
on
a
downwind
nonattainment
area
to
be
considered
potentially
to
contribute
significantly
to
nonattainment;

and
then
(
ii)
for
States
with
impacts
above
that
threshold,

EPA
developed
a
set
of
metrics
for
further
evaluating
the
contribution
of
the
upwind
State's
emissions
on
a
downwind
nonattainment
area
(
63
FR
57378).
The
EPA
considered
a
57
State
with
emissions
that
had
a
sufficiently
great
impact
to
contribute
significantly
to
the
downwind
area
(
depending
on
application
of
the
cost
factor).
In
general,
EPA
established
the
thresholds
at
a
relatively
low
level,
which
reflected
the
collective
contribution
phenomenon.
That
is,

because
the
ozone
problem
is
caused
by
many
relatively
small
contributions,
even
relatively
small
contributors
must
participate
in
the
solution.

ii.
Cost
Factor
The
cost
factor
is
the
second
major
factor
that
EPA
applied
to
determine
the
significant
contribution
to
nonattainment:
"
EPA
...
determined
whether
any
amounts
of
the
NOx
emissions
may
be
eliminated
through
controls
that,

on
a
cost­
per­
ton
basis,
may
be
considered
to
be
highly
cost
effective."
(
See
63
FR
57377.)

(
I)
Choice
of
Highly
Cost­
effective
Standard
The
EPA
selected
the
standard
of
highly
cost
effective
in
order
to
assure
State
flexibility
in
selecting
control
strategies
to
meet
the
emissions
reduction
requirements
of
the
rulemaking.
That
is,
the
rulemaking
required
the
States
to
achieve
specified
levels
of
emissions
reductions
 
the
levels
achievable
if
States
implemented
the
control
strategies
that
EPA
identified
as
highly
cost
effective
 
but
the
rulemaking
did
not
mandate
those
highly
cost­
58
effective
control
strategies,
or
any
other
control
strategy.

Indeed,
in
calculating
the
amount
of
the
required
emissions
reductions
by
assuming
the
implementation
of
highly
costeffective
control
strategies,
EPA
assured
that
other
control
strategies
 
ones
that
were
cost
effective,
if
not
highly
cost
effective
­­
remained
available
to
the
States.

(
II)
Determination
of
Highly
Cost­
Effective
Amount
The
EPA
determined
the
dollar
amount
considered
to
be
highly
cost
effective
by
reference
to
the
cost
effectiveness
of
recently
promulgated
or
proposed
NOx
controls.
The
EPA
determined
that
the
average
cost
effectiveness
of
controls
in
the
reference
list
ranged
up
to
approximately
$
1,800
per
ton
of
NOx
removed
(
1990$),
on
an
annual
basis.
The
EPA
considered
the
controls
in
the
reference
list
to
be
cost
effective.

The
EPA
established
$
2,000
(
1990$)
in
average
cost
effectiveness
for
summer
ozone
season
emissions
reductions
as,
at
least
directionally,
the
highly
cost­
effective
amount.
Identifying
this
amount
on
an
ozone
season
basis
was
appropriate
because
the
NOx
SIP
Call
concerned
the
ozone
standard,
for
which
emissions
reductions
during
only
the
summer
ozone
season
are
necessary.
This
level
of
costs
reflected
the
fact
that
in
general,
States
with
downwind
ozone
nonattainment
areas
had
already
implemented
extensive
59
controls.
Accordingly,
it
was
evident
that
the
level
of
upwind
controls
EPA
selected
would
prove
necessary
for
the
downwind
areas
to
reach
attainment.

(
III)
Source
Categories
The
EPA
then
determined
that
the
source
categories
for
which
highly
cost­
effective
controls
were
available
included
EGUs,
large
industrial
boilers
and
turbines,
and
cement
kilns.
At
the
same
time,
EPA
determined,
for
those
source
categories,
the
level
of
controls
that
would
cost
an
amount
consistent
with
the
highly
cost­
effective
amount
and
that
would
be
feasible.
The
EPA
considered
other
source
categories,
but
found
that
highly
cost­
effective
controls
were
not
available
from
them
for
various
reasons,
including
the
size
of
the
sources,
the
relatively
small
amount
of
emissions
from
the
sources,
or
the
control
costs.

iii.
Other
Factors
The
EPA
also
relied
on
several
other,
secondary
considerations
before
concluding
that
the
identified
amount
of
emissions
reductions
were
required.
The
first
concerned
the
consistency
of
regional
reductions
with
downwind
attainment
needs.
The
EPA
ascertained
the
ozone
air
quality
impacts
of
the
required
emissions
reductions,
and
determined
that
those
impacts
improved
air
quality
downwind,
but
not
to
the
point
that
would
raise
questions
about
whether
the
60
amount
of
reductions
was
more
than
necessary
(
63
FR
57379).

The
second
general
consideration
was
"
the
overall
fairness
of
the
control
regimes"
to
which
the
downwind
and
upwind
areas
were
subject.
The
EPA
explained:

Most
broadly,
EPA
believes
that
overall
notions
of
fairness
suggest
that
upwind
sources
which
contribute
significant
amounts
to
the
nonattainment
problem
should
implement
cost­
effective
reductions.
When
upwind
emitters
exacerbate
their
downwind
neighbors'
ozone
nonattainment
problems,
and
thereby
visit
upon
their
downwind
neighbors
additional
health
risks
and
potential
clean­
up
costs,
EPA
considers
it
fair
to
require
the
upwind
neighbors
to
reduce
at
least
the
portion
of
their
emissions
for
which
highly
costeffective
controls
are
available.
In
addition,
EPA
recognizes
that
in
many
instances,
areas
designated
as
nonattainment
under
the
1­
hour
NAAQS
have
incurred
ozone
control
costs
since
the
early
1970s.
Moreover,
virtually
all
components
of
their
NOx
and
VOC
inventories
are
subject
to
SIPrequired
or
Federal
controls
designed
to
reduce
ozone.
Furthermore,
these
areas
have
complied
with
almost
all
of
the
specific
control
requirements
under
the
CAA,
and
generally
are
moving
towards
compliance
with
their
remaining
obligations.
The
CAA's
sanctions
and
FIP
provisions
provide
assurance
that
these
remaining
controls
will
be
implemented.
By
comparison,
many
upwind
States
in
the
midwest
and
south
have
had
fewer
nonattainment
problems
and
have
incurred
fewer
control
obligations.

(
63
FR
57379.)

The
third
general
consideration
was
"
general
cost
considerations."
The
EPA
noted
that
"
in
general,
areas
that
currently
have,
or
that
in
the
past
have
had,
nonattainment
problems
...
have
already
incurred
ozone
control
costs."

The
next
set
of
controls
available
to
these
nonattainment
areas
would
be
more
expensive
than
the
controls
available
to
61
the
upwind
areas.
The
EPA
found
that
this
cost
scenario
further
confirmed
the
reasonableness
of
the
upwind
control
obligations
(
63
FR
57379).

In
the
NOx
SIP
Call,
EPA
considered
all
of
these
factors
together
in
determining
the
level
of
controls
considered
to
be
highly
cost
effective.
This
level
of
controls
reflected
the
then­
present
state
of
ozone
controls:

Within
the
region,
the
nonattainment
areas
were
already
required
to
 
and
had
already
implemented
 
VOC
and
NOx
controls
that
covered
much
of
their
inventory.
However,
the
upwind
States
in
the
region
generally
had
not
done
so
(
except
to
the
extent
of
their
ozone
nonattainment
areas).

In
this
context,
EPA
considered
it
reasonable
to
impose
an
additional
control
burden
on
the
upwind
States.
Air
quality
modeling
showed
that
even
with
this
additional
level
of
upwind
controls,
residual
nonattainment
remained,
so
that
further
reductions
from
downwind
and/
or
upwind
areas
would
be
necessary.

b.
Regulatory
Requirements
After
ascertaining
the
controls
that
qualified
as
highly
cost
effective,
EPA
developed
a
methodology
for
calculating
the
amount
of
NOx
emissions
that
each
State
was
required
to
reduce
on
grounds
that
those
emissions
contribute
significantly
to
nonattainment
downwind.
The
62
total
amount
of
required
NOx
emissions
reductions
was
the
sum
of
the
amounts
that
would
be
reduced
by
application
of
highly
cost­
effective
controls
to
each
of
the
source
categories
for
which
EPA
determined
that
such
controls
were
available
(
63
FR
57378).

The
largest
of
these
source
categories
was
EGUs.
The
EPA
determined
the
amount
of
reductions
associated
with
EGU
controls
by
applying
the
control
rate
that
EPA
considered
to
reflect
highly
cost­
effective
controls
to
each
State's
EGU
heat
input.
That
heat
input,
in
turn,
was
adjusted
to
reflect
projected
growth.

Each
affected
State
retained
the
authority
to
achieve
the
required
level
of
reductions
by
implementing
whatever
controls
on
whatever
sources
it
wished,
and
EPA
determined
that
there
were
other
source
categories
for
which
costeffective
if
not
highly
cost­
effective,
controls
were
available
(
63
FR
57378).
If
the
States
chose
to
control
EGUs,
then
the
NOx
SIP
Call
mandated
certain
requirements
 
including
a
statewide
cap
on
EGU
NOx
emissions
 
but
also
made
available
an
EPA­
administered
regionwide
EGU
allowance
trading
program
that
the
States
could
choose
to
adopt.

c.
SIP
Submittal
and
Implementation
Requirements
At
the
time
EPA
promulgated
the
NOx
SIP
Call,
States
already
had
SIPs
for
the
1­
hour
ozone
NAAQS
in
place.
In
63
the
NOx
SIP
Call,
EPA
determined
that
the
1­
hour
SIPs
for
the
affected
States
were
deficient,
and
EPA
called
on
these
States,
under
CAA
section
110(
k)(
5),
to
submit,
within
12
months
of
promulgation
of
the
NOx
SIP
Call,
SIP
revisions
to
cure
the
deficiency
by
complying
with
the
NOx
SIP
Call
regulatory
requirements.
The
EPA
further
required
that
the
NOx
SIP
Call­
required
controls
be
implemented
as
expeditiously
as
practicable.
The
EPA
determined
this
date
to
be
within
3
years
of
the
SIP
submittal
date
(
with
that
period
extended
to
the
beginning
of
the
next
ozone
season),

in
light
of
the
various
constraints
that
EGUs
would
confront
in
implementing
controls.

For
the
SIPs
due
under
the
8­
hour
ozone
NAAQS,
in
the
NOx
SIP
Call,
EPA
did
not
incorporate
a
section
110(
k)(
5)

SIP
call,
but
instead
required
States
to
submit,
under
section
110(
a)(
1)­(
2),
SIP
revisions
to
fulfill
the
requirements
of
section
110(
a)(
2)(
D).
The
EPA
required
these
8­
hour
ozone
SIPs
to
be
submitted
 
and
the
controls
mandated
therein
to
be
implemented
 
on
the
same
schedule
as
the
1­
hour
SIPs.

However,
EPA
stayed
the
8­
hour
ozone
requirements
of
the
NOx
SIP
Call,
due
to
litigation
concerning
the
8­
hour
ozone
NAAQS.
To
date,
EPA
has
not
lifted
that
stay.

3.
Michigan
v.
EPA
Court
Case
64
15
By
action
dated
January
18,
2000,
EPA
promulgated
another
rulemaking
that
was
related
to
the
NOx
SIP
Call,
known
as
the
Section
126
Rule
(
65
FR
2674).
The
D.
C.
Circuit
generally
upheld
this
rule,
although
it
remanded
for
better
explanation
the
EGU
heat
input
growth
methodology.
Appalachian
Power
Co.
v.
EPA,
249
F.
3d
1032
(
D.
C.
Cir.,
2001).
Petitioners
brought
legal
challenges
to
various
components
of
the
NOx
SIP
Call's
analytical
approach
in
the
United
States
Court
of
Appeals
for
the
District
of
Columbia
Circuit,
in
Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.
Cir.,
2000),

cert.
denied,
532
U.
S.
904
(
2001).
The
Court
upheld
the
essential
features
of
the
air
quality
modeling
part
of
EPA's
approach,
id.
at
673;
as
well
as
EPA's
definition
of
"
contribute
significantly"
to
include
the
factor
of
highly
cost­
effective
controls,
id.
at
679.
The
Court
did
vacate
or
remand
certain
specific
applications
of
EPA's
approach,

and
delayed
the
implementation
date
to
May
31,
2004.
See,

e.
g.,
id.
at
67,681­
85,
692­
94.
In
addition,
in
a
subsequent
case
that
reviewed
separate
EPA
rulemakings
making
technical
corrections
to
the
NOx
SIP
Call,
the
D.
C.

Circuit
remanded
for
a
better
explanation
EPA's
methodology
for
computing
the
growth
component
in
the
EGU
heat
input
calculation.
Appalachian
Power
Co.
v.
EPA,
251
F.
3d
1026
(
D.
C.
Cir.,
2001).
15
4.
Implementation
of
the
NOx
SIP
Call
The
court
decisions
left
intact
most
of
the
NOx
SIP
65
Call
requirements.
All
States
subject
to
those
requirements
 
which
EPA
has
termed
the
NOx
SIP
Call
Phase
I
requirements
 
submitted
SIPs
incorporating
them,
and
requiring
control
implementation
by
May
31,
2004
or
earlier.
The
EPA
has
approved
those
SIPs.

The
EPA
responded
to
the
D.
C.
Circuit's
EGU
growth
remand
decisions
through
a
Federal
Register
action
that
provided
a
more
detailed
explanation
and
other
supporting
information
for
the
EGU
growth
methodology
(
67
FR
21868;
May
1,
2002).
The
Court
subsequently
upheld
that
explanation.

West
Virginia
v.
EPA,
362
F.
3d
861
(
D.
C.
Cir.
2004).
In
addition,
by
action
dated
April
21,
2004,
EPA
promulgated
a
rulemaking
that
responded
to
other
remanded
and
vacated
issues,
and
included
the
remaining
requirements
 
termed
the
NOx
SIP
Call
Phase
II
requirements
­­
for
the
affected
States
(
69
FR
21604).

B.
How
Does
EPA
Interpret
the
Clean
Air
Act's
Pollution
Transport
Provisions
in
Today's
Rule?

1.
CAIR
Analytical
Approach
Today,
EPA
adopts
much
the
same
interpretation
and
application
of
section
110(
a)(
2)(
D)
for
regulating
downwind
transport
of
precursors
of
PM2.5
and
8­
hour
ozone
as
EPA
adopted
for
the
NOx
SIP
Call.
We
are
adjusting
some
aspects
of
the
NOx
SIP
Call
analytic
approach
for
various
reasons,
66
including
the
need
to
account
for
regulation
of
a
different
pollutant
(
PM2.5)
with
an
additional
precursor
(
SO2).

a.
Nature
of
Nonattainment
Problem
and
Overview
of
Today's
Approach
As
described
in
section
I,
above,
the
interstate
transport
component
of
current
nonattainment
of
the
PM2.5
and
8­
hour
ozone
NAAQS
is
primarily
confined
to
the
eastern
part
of
the
country,
although
in
an
area
that
is
larger,
by
several
States,
than
the
area
that
EPA
focused
on
in
the
NOx
SIP
Call
for
only
ozone.
As
described
in
section
III,
it
is
evident
that
local
controls
alone
cannot
be
counted
on
to
solve
the
nonattainment
problems,
although
uncertainties
remain
in
the
state
of
knowledge
of
these
nonattainment
problems
as
well
as
the
precise
role
interstate
and
local
controls
should
play.
As
in
the
case
of
the
NOx
SIP
Call,

it
is
not
reasonable
to
expect
a
local
area
to
bear
the
entire
burden
of
solving
the
air
quality
problems,
even
if
doing
so
were
technically
possible.

Turning
to
the
interstate
component
of
the
nonattainment
problems,
as
discussed
in
section
III
below,

for
PM2.5,
we
find
sufficient
information
is
available
to
address
the
adverse
downwind
impacts
caused
by
SO2
and
NOx,

and
to
develop
emissions
reductions
requirements
for
SO2
and
NOx.
However,
we
do
not
have
sufficient
information
to
67
address
other
precursors.
As
discussed
in
section
III
below,
for
8­
hour
ozone,
we
reiterate
the
finding
of
the
NOx
SIP
Call
that
NOx
emissions,
and
not
VOC
emissions,
are
of
primary
importance
for
interstate
transport
purposes.

We
interpret
CAA
section
110(
a)(
2)(
D)
to
require
SIPs
in
upwind
States
to
eliminate
the
amounts
of
emissions
that
contribute
significantly
to
downwind
nonattainment
or
interfere
with
downwind
maintenance.
As
described
below,
in
today's
rule,
EPA
determines
that
upwind
States'
emissions
contribute
significantly
to
nonattainment
or
interfere
with
maintenance
of
the
PM2.5
NAAQS.

To
quantify
the
amounts
of
those
emissions
that
contribute
significantly
to
nonattainment,
we
primarily
focus
on
the
air
quality
factor
reflecting
the
upwind
State's
ambient
impact
on
downwind
nonattainment
areas,
and
the
cost
factor
of
highly
cost­
effective
controls.
However,

as
with
the
NOx
SIP
Call,
EPA
also
considers
other
factors,

which
serve
to
establish
the
broad
context
for
applying
the
air
quality
and
cost
factors.
Today,
we
adopt
the
formulation
of
those
factors
as
described
in
the
CAIR
NPR,

which
has
little
conceptual
difference
from
EPA's
application
of
those
factors
in
the
NOx
SIP
Call.

Discussion
of
issues
relating
to
maintenance
are
found
in
section
III
below.
68
b.
Air
Quality
Factor
i.
PM2.5
With
respect
to
the
PM2.5
NAAQS,
as
described
in
section
VI,
we
employed
air
quality
modeling
techniques
to
assess
the
impact
of
each
upwind
State's
entire
inventory
of
anthropogenic
SO2
and
NOx
emissions
on
downwind
nonattainment
and
maintenance.
For
air
quality
and
technical
reasons
described
below,
EPA
determined
that
upwind
SO2
and
NOx
emissions
contribute
significantly
to
nonattainment
as
of
the
year
2010.
Therefore,
EPA
projected
SO2
and
NOx
emissions
to
the
year
2010,
assuming
certain
required
controls
(
but
not
controls
required
under
CAIR),

and
then
modeled
the
impact
of
those
projected
emissions
(
termed
the
base
case
inventory)
on
downwind
PM2.5
nonattainment
in
that
year.

As
discussed
in
section
III,
we
adopt
today
a
threshold
air
quality
impact
of
0.2

g/
m3,
so
that
an
upwind
State
with
contributions
to
downwind
nonattainment
below
this
level
would
not
be
subject
to
regulatory
requirements,
but
a
State
with
contributions
at
or
higher
than
this
level
would
be
subject
to
further
evaluation.

Because
of
the
inherent
differences
between
the
PM2.5
and
ozone
NAAQS,
this
threshold
necessarily
differs
from
the
threshold
chosen
for
the
NOx
SIP
Call
in
terms
of:
(
i)
the
69
16
The
second
air
quality
factor
described
in
the
NOx
SIP
Call
 
the
extent
of
downwind
nonattainment
 
is
reflected
in
the
identification
of
downwind
PM2.5
nonattainment
areas,
discussed
elsewhere
in
today's
final
action.
The
third
air
quality
factor
 
the
ambient
impact
of
upwind
emissions
 
is
reflected
in
the
threshold
level.
metrics
selected
to
evaluate
the
threshold,
and
(
ii)
the
specific
level
of
the
threshold.
Even
so,
the
threshold
EPA
proposed
for
PM2.5
is
generally
consistent
with
the
approach
taken
in
the
NOx
SIP
Call
for
the
threshold
level
for
ozone
in
that
both
are
relatively
low.
This
level
reflects
the
fact
that
PM2.5
nonattainment,
like
ozone,
is
caused
by
many
sources
in
a
broad
region,
and
therefore
may
be
solved
only
by
controlling
sources
throughout
the
region.
As
with
the
NOx
SIP
Call,
the
collective
contribution
condition
of
PM2.5
air
quality
is
reflected
in
the
proposed
relatively
low
threshold.
16
The
EPA
determined
that
as
of
2010,
23
upwind
States
and
the
District
of
Columbia
will
have
contributions
to
downwind
PM2.5
nonattainment
areas
that
are
sufficiently
high
to
meet
the
air
quality
factor
of
the
transport
test.

ii.
8­
Hour
Ozone
With
respect
to
the
8­
hour
ozone
NAAQS,
we
also
employed,
as
described
in
section
VI,
air
quality
modeling
techniques
to
assess
the
impact
of
each
upwind
State's
entire
inventory
of
NOx
and
VOC
emissions
on
downwind
70
nonattainment.
The
EPA
determined
that
upwind
NOx
emissions
contribute
significantly
to
8­
hour
ozone
nonattainment
as
of
the
year
2010.
Therefore,
EPA
projected
NOx
emissions
to
the
year
2010,
assuming
certain
required
controls
(
but
not
controls
required
under
CAIR),
and
then
modeled
the
impact
of
those
projected
emissions
(
termed
the
base
case
inventory)
on
downwind
8­
hour
ozone
nonattainment
in
that
year.

For
the
8­
hour
ozone
air
quality
factor,
EPA
employs
the
same
threshold
amounts
and
metrics
that
it
used
in
the
NOx
SIP
Call.
That
is,
as
described
in
section
VI,

emissions
from
an
upwind
State
contribute
significantly
to
nonattainment
if
the
maximum
contribution
is
at
least
2
parts
per
billion,
the
average
contribution
is
greater
than
one
percent,
and
certain
other
numerical
criteria
are
met.

The
EPA
determined
that
as
of
2010,
25
upwind
States
and
the
District
of
Columbia
will
have
contributions
to
downwind
nonattainment
areas
that
are
sufficiently
high
to
meet
the
air
quality
factor
of
the
transport
test.

c.
Cost
Factor
The
second
major
factor
that
EPA
applies
is
the
cost
factor.
As
in
the
case
of
the
NOx
SIP
Call,
EPA
interprets
this
factor
as
mandating
emissions
reductions
in
amounts
that
would
result
from
application
of
highly
cost­
effective
71
controls.
We
ascertain
the
level
of
costs
as
highly
cost
effective
by
reference
to
the
cost
effectiveness
of
recent
controls.
As
we
stated
in
the
CAIR
NPR,
in
determining
the
appropriate
level
of
controls,
we
considered
feasibility
issues
 
­
as
we
did
in
the
NOx
SIP
Call
­­
specifically,

"
the
applicability,
performance,
and
reliability
of
different
types
of
pollution
control
technologies
for
different
types
of
sources;
...
and
other
implementation
costs
of
a
regulatory
program
for
any
particular
group
of
sources."
(
See
CAIR
NPR,
69
FR
4585.)

As
described
in
section
IV,
today
we
conclude
that
at
present,
EGUs
are
the
only
source
category
for
which
highly
cost­
effective
SO2
and
NOx
controls
are
available.
In
making
this
determination,
we
examined
what
information
is
available
concerning
which
source
categories
emit
relatively
large
amounts
of
emissions,
and
what
difficulties
sources
have
in
implementing
controls.
These
criteria
are
similar
to
those
considered
in
the
NOx
SIP
Call.

As
discussed
in
section
IV,
for
PM2.5,
today's
action
finalizes
our
proposal
to
identify
as
highly
cost
effective
the
dollar
amount
of
cost
effectiveness
that
falls
near
the
low
end
of
the
reference
range
for
both
annual
SO2
controls
and
annual
NOx
controls.
We
identify
this
level
based
on
the
overall
context
of
the
PM2.5
implementation
program,
72
discussed
below.

For
upwind
States
affecting
downwind
8­
hour
ozone
nonattainment
areas,
we
apply
the
cost
factor
for
ozoneseason
NOx
controls
in
much
the
same
manner
as
for
the
NOx
SIP
Call,
although
some
aspects
of
the
analysis
have
been
updated.
The
level
of
NOx
control
identified
as
highly
cost
effective
is
more
stringent
than
in
the
NOx
SIP
Call.

d.
Other
Factors
As
with
the
NOx
SIP
Call,
EPA
considers
other
factors
that
influence
the
application
of
the
air
quality
and
cost
factors,
and
that
confirm
the
conclusions
concerning
the
amounts
of
emissions
that
upwind
States
must
eliminate
as
contributing
significantly
to
downwind
nonattainment.

Specifically,
as
we
stated
in
the
CAIR
NPR,
"
We
are
striving
in
this
proposal
to
set
up
a
reasonable
balance
of
regional
and
local
controls
to
provide
a
cost
effective
and
equitable
governmental
approach
to
attainment
with
the
NAAQS
for
fine
particles
and
ozone."
(
See
69
FR
4612.)
In
this
manner,
we
broadly
incorporate
the
fairness
concept
and
relative­

costof
control
(
regional
costs
compared
to
local
costs)
concept
that
we
generally
considered
in
the
NOx
SIP
Call.

i.
PM2.5
Controls
For
PM2.5,
we
promulgated
the
NAAQS
in
1997,
we
issued
designations
of
areas
in
December
2004
(
70
FR
944;
January
73
5,
2005),
and
we
intend
to
promulgate
implementation
requirements
during
2005.
We
project
that
by
2010,
without
CAIR
or
other
controls
not
already
adopted,
80
counties
in
the
CAIR
region
would
be
in
nonattainment
of
the
annual
standard.

Our
state
of
knowledge
is
incomplete
as
to
the
best
control
regime
to
achieve
attainment
and
maintenance
of
this
NAAQS
in
individual
areas,
but
we
do
know
that
transported
SO2
and
NOx
emissions
are
important
contributors
to
PM2.5
nonattainment.
In
addition,
we
have
concluded
that
available
controls
for
at
least
the
portion
of
these
emissions
from
EGUs
are
feasible
and
relatively
inexpensive
on
a
cost­
per­
ton
basis,
and
generate
significant
ambient
benefits.
These
ambient
benefits
include
bringing
many
areas
into
attainment
and
decreasing
PM2.5
levels
in
the
rest
of
the
nonattainment
areas.
Moreover,
available
information
indicates
that
local
controls
are
likely
to
be
relatively
more
expensive
on
a
per­
ton
basis,
and
will
not
reduce
emissions
sufficiently
to
bring
many
areas
into
attainment.

In
light
of
this
information,
we
plan
to
proceed
by
requiring
the
level
of
regulatory
control
specified
today
on
upwind
SO2
and
NOx
emissions.
We
consider
today's
action
to
be
both
prudent
and
effective
within
the
circumstances
of
74
the
developing
PM2.5
implementation
program.
This
action
is
one
of
the
initial
steps
in
implementing
the
PM2.5
NAAQS.

States,
localities,
and
Tribes,
as
well
as
EPA,
will
continue
to
evaluate
the
efficacy
of
local
controls.

Finally,
as
discussed
in
section
VI,
air
quality
modeling
confirms
that
these
regional
controls
are
not
more
than
is
necessary
for
downwind
areas
to
attain.

This
overall
plan
is
well
within
the
ambit
of
EPA's
authority
to
proceed
with
regulation
on
a
step­
by­
step
basis.
The
time
frame
for
section
110(
a)(
2)(
D)
SIPs,

described
in
section
VII,
makes
clear
that
EPA
has
the
authority
to
establish
the
upwind
reduction
obligations
before
having
full
information
about
how
best
to
achieve
attainment
goals,
including
having
full
information
about
downwind
control
costs
and
the
efficacy
of
downwind
control
measures.

ii.
Ozone
Controls
The
EPA
determined
the
level
of
required
NOx
reductions
for
purposes
of
8­
hour
ozone
transport
through
much
the
same
process
as
for
purposes
of
PM2.5
transport.

e.
Regulatory
Requirements
i.
Annual
SO2
and
NOx
Emissions
Reductions
Although
EPA
determined
that
upwind
emissions
will
contribute
significantly
to
both
PM2.5
nonattainment
and
8­
75
hour
ozone
nonattainment
in
2010,
the
amount
of
requisite
emissions
controls
cannot
feasibly
be
implemented
by
2009
for
NOx,
or
2010
for
SO2.
Instead,
EPA
has
determined
to
implement
the
reductions
in
two
phases
for
each
pollutant:

2009
for
NOx,
and
2010
for
SO2
initially,
with
lower
caps
for
both
in
2015.

As
described
in
section
IV,
EPA
evaluated
the
cost
of
emissions
reductions
under
consideration
against
the
level
of
highly
cost­
effective
controls.
Through
a
multi­
year
process
involving
studies
and
other
regulatory
and
legislative
efforts,
as
well
as
involvement
with
citizen,

industry,
and
State
stakeholders,
EPA
arrived
at
an
amount
of
SO2
emissions
reductions
for
evaluation
purposes
for
the
CAIR
region.
The
EPA
ascertained
the
costs
of
these
reductions
and
today
determines
that
they
should
be
considered
highly
cost
effective.
These
amounts
correspond
to
reducing
Title
IV
SO2
allowances
for
utilities
by
65
percent
in
2015
and
50
percent
in
2010
in
CAIR
States.

As
described
in
section
V,
EPA
further
determined
that
these
emissions
reductions
requirements
should
be
allocated
to
the
States
in
proportion
to
the
title
IV
SO2
allowances
allocated
under
the
CAA
to
their
EGUs.
This
approach
is
consistent
with
the
system
Congress
established
for
allocating
title
IV
allowances
and
facilitates
76
implementation
of
the
SO2
interstate
trading
program.

For
annual
NOx
emissions,
EPA
determined
a
target
regionwide
amount
of
both
emissions
reductions
and
the
EGU
budget
by
multiplying
current
heat
input
by
emission
rates
of
0.125
lb/
mmBtu
and
0.15
lb/
mmBtu
for
2015
and
2010,

respectively.
The
EPA
then
evaluated
those
amounts
through
the
Integrated
Planning
Model
(
IPM),
which
indicated
the
associated
amounts
of
heat
input
and
emission
rates
projected
for
those
years.
The
IPM
indicated
that
the
amounts
of
heat
input
for
2015
and
2010
were
higher
than
current
heat
input
(
in
light
of
the
increased
electricity
demand
for
2015
and
2010),
and
that
the
emissions
rates
were
lower
than
0.125
lb/
mmBtu
(
2015)
and
0.15
lb/
mmBtu
(
2010).

The
IPM
calculated
the
costs
to
achieve
those
emissions
reductions
and
EGU
budget
(
assuming
EGU
controls)
by
2015
and
2009,
which
costs
EPA
determined
were
highly
cost
effective
and
feasible,
respectively.
The
EPA
used
this
same
approach
to
determine
the
seasonal
budget
for
NOx
reductions
for
purposes
of
the
ozone
standard.

As
described
in
section
V,
we
allocated
this
regionwide
amount
to
the
individual
States
in
accordance
with
their
average
heat
input
from
EGUs
both
subject
to
and
not
subject
to
title
IV.
We
adjusted
heat
input
for
type
of
fuel
used.

The
EPA
believes
that
this
method
is
a
reasonable
indicator
77
of
each
State's
appropriate
share
of
the
requirements.
This
method
differs
from
what
EPA
used
in
the
NOx
SIP
Call,
which
relied
on
State­
specific
projections
of
growth
in
heat
input.

We
require
implementation
of
the
PM2.5
and
8­
hour
ozone
reductions
in
two
phases,
in
2009
and
2015.
As
discussed
in
section
IV,
these
dates
are
the
most
expeditious
that
are
practicable
 
the
same
standard
for
the
implementation
period
in
the
NOx
SIP
Call
 
based
on
engineering
and
financial
factors;
the
performance
and
applicability
of
control
measures;
and
the
impact
of
implementation
on,
in
the
case
of
EGUs,
electricity
reliability.
The
EPA
considered
these
same
factors
in
determining
the
implementation
period
for
the
NOx
SIP
Call
requirements,
but
factual
differences
lead
to
the
two­
phase
approach
adopted
in
today's
action.

As
discussed
in
section
VII,
each
upwind
State
may
achieve
the
required
reductions
by
regulating
any
sources
of
SO2
or
NOx
that
it
wishes.
However,
if
the
State
chooses
to
regulate
certain
source
categories
(
such
as
EGUs),
it
must
comply
with
certain
requirements
(
such
as
capping
EGU
emissions),
and
it
may
take
advantage
of
certain
opportunities
(
such
as
participation
in
the
EPA­
administered
EGU
cap
and
trade
program).
Some
aspects
of
these
78
requirements
and
the
cap
and
trade
program
differ
from
those
in
the
NOx
SIP
Call,
as
explained
in
section
VIII.
However,

like
the
NOx
SIP
Call,
the
State
may
allow
sources
to
opt
in
to
the
CAIR
trading
program,
as
described
in
section
VIII.

f.
SIP
Submittal
and
Implementation
Requirements
Today
EPA
requires
that
the
PM2.5
and
8­
hour
ozone
SIPs
be
submitted
within
18
months
of
promulgation
of
today's
action.
This
period
is
6
months
longer
than
the
SIPs
due
under
the
NOx
SIP
Call.
This
difference
is
due
to
the
fact
that
PM2.5
implementation
is
only
now
beginning,
and
it
makes
sense
to
keep
the
NOx
SIPs
due
under
the
8­
hour
ozone
requirements
on
the
same
schedule
as
the
NOx
and
SO2
SIPs
due
under
the
PM2.5
requirements.

2.
What
Did
Commenters
Say
and
What
Is
EPA's
Response?

Many
of
the
comments
on
today's
action
concern
various
aspects
of
EPA's
analytical
approach.
Most
of
those
comments
are
discussed
elsewhere
in
today's
action.

Comments
on
the
most
basic
elements
of
EPA's
approach
are
discussed
here.

a.
Aspects
of
Contribute­
Significantly
Test
i.
Date
for
Evaluation
of
Downwind
Impacts
Comment:
Some
commenters
took
issue
with
EPA's
approach
of
determining
the
upwind
State's
air
quality
impact
on
downwind
areas
by
modeling
only
the
State's
2010
base
case
79
emissions
(
that
is,
projected
2010
emissions
before
the
2010
CAIR
controls).
These
commenters
stated
that
although
evaluating
the
upwind
State's
base
case
emissions
in
2010
might
indicate
whether
that
State's
air
quality
impact
on
downwind
areas
is
sufficiently
high
to
justify
imposition
of
the
2010
(
Phase
I)
controls,
it
does
not
justify
imposition
of
the
2015
(
Phase
II)
controls.
Rather,
according
to
the
commenters,
EPA
should
conduct
further
air
quality
modeling
that
evaluates
the
upwind
State's
2015
base
case
emissions
 
taking
into
account
the
CAIR
2010
controls
but
not
the
CAIR
2015
controls
 
to
determine
whether
the
State
continues
(
even
after
imposition
of
the
CAIR
2010
controls)
to
have
a
sufficient
downwind
ambient
impact
to
justify
the
2015
controls.

Commenters
added
that,
in
their
view,
PM2.5
precursors
generally
were
decreasing
after
2010,
the
PM2.5
nonattainment
problem
was
generally
diminishing
as
well,
and
the
contribution
of
some
upwind
States
to
downwind
areas
was
relatively
small.
These
facts,
according
to
the
commenters,

indicated
that
some
upwind
States
should
not
be
subject
to
the
2015
reductions
requirement.

Some
commenters
stated,
more
broadly,
that
the
threshold
contribution
level
selected
by
EPA
should
be
considered
a
floor,
so
that
upwind
States
should
be
obliged
80
to
reduce
their
emissions
only
to
the
level
at
which
their
contribution
to
downwind
nonattainment
does
not
exceed
that
threshold
level.

Response:
The
EPA
views
the
CAIR
emission
reduction
requirements
as
a
single
action,
but
one
that
cannot
be
fully
implemented
in
2009
(
for
NOx)
or
2010
(
for
SO2),
and
must
instead
be
partially
deferred
until
2015,
solely
for
reasons
of
feasibility.
Under
these
circumstances,
EPA
does
not
believe
it
appropriate
to
re­
evaluate
the
2015
component,
as
commenters
have
suggested.

Under
EPA's
approach,
which
mirrors
that
of
the
NOx
SIP
Call,
EPA
projects,
for
each
upwind
State,
SO2
and
NOx
inventories,
as
of
2010,
taking
into
account
controls
required
under
other
CAA
provisions
and
controls
adopted
by
State
and
local
agencies.
The
EPA
then
uses
air
quality
modeling
techniques
to
determine
the
impact
of
these
emissions
on
downwind
air
quality.
The
EPA
then
requires
upwind
States
whose
emissions
have
a
sufficiently
high
impact
to
eliminate
the
amount
of
their
emissions
that
could
be
eliminated
through
application
of
highly
cost­
effective
controls.
These
emissions
reductions
must
be
implemented
as
expeditiously
as
practicable.
Were
it
feasible
to
implement
all
the
reductions
by
2009
(
for
NOx)
or
2010
(
for
SO2),
EPA
would
so
require.
Because
part
of
the
emissions
reductions
81
cannot
feasibly
be
implemented
until
2015,
EPA
is
requiring
today's
two­
phase
approach.
This
analytic
method
is
the
same
as
for
the
NOx
SIP
Call,
except
that
in
that
rulemaking
all
of
the
required
emissions
reductions
could
feasibly
be
implemented
in
one
phase.

As
in
the
case
of
the
NOx
SIP
Call,
EPA
takes
the
view
that
once
a
State's
emissions
are
determined
to
contribute
to
downwind
nonattainment
by
at
least
a
threshold
amount,

then
the
upwind
State
should
reduce
its
emissions
by
the
amount
that
would
result
from
implementation
of
highly
costeffective
controls.
This
approach
is
justified
by
the
benefits
of
reducing
the
upwind
contribution
to
downwind
nonattainment,
coupled
with
the
relatively
low
costs.

However,
EPA
does
consider
the
ambient
impacts
of
the
required
emissions
reductions.
For
today's
action,
air
quality
modeling
indicates
that
the
regionwide
emissions
reductions
do
not
reduce
PM2.5
levels
beyond
what
is
needed
for
attainment
and
maintenance.
(
See
also
section
III
below.)
Most
important
for
present
purposes,
as
long
as
the
controls
yield
downwind
benefits
needed
to
reduce
the
extent
of
nonattainment,
the
controls
should
not
be
lessened
simply
because
they
may
have
the
effect
of
reducing
the
upwind
State's
contribution
to
below
the
initial
threshold.

The
D.
C.
Circuit,
in
upholding
the
NOx
SIP
Call,
82
rejected
similar
arguments
to
those
raised
by
commenters
(
Michigan
v.
EPA,
213
F.
3d
at
679).
In
the
NOx
SIP
Call
rulemaking,
commenters
argued
that
EPA's
analytic
approach
to
the
"
contribute
significantly"
test
was
flawed
because
it
meant
that
States
with
different
impacts
downwind
would
nevertheless
have
to
implement
the
same
level
of
controls
(
i.
e.,
those
that
were
highly
cost
effective).
Commenters
urged
EPA
to
recast
its
approach
by
limiting
an
upwind
State's
emissions
reductions
to
the
point
at
which
the
remaining
emissions
no
longer
caused
a
downwind
ambient
impact
above
the
threshold
level
for
significance.

("
Responses
to
Significant
Comments
on
the
Proposed
Finding
of
Significant
Contribution
and
Rulemaking
for
Certain
States
in
the
Ozone
Transport
Assessment
Group
(
OTAG)
Region
for
Purposes
of
Reducing
Regional
Transport
of
Ozone
(
62
FR
60318;
November
7,
1997
and
63
FR
25902;
May
11,
1998),"

U.
S.
E.
P.
A.
(
September
1998),
Docket
Number
A­
96­
56­
VI­
C­
1,

at
213­
16.)

Petitioners
challenging
the
NOx
SIP
Call
in
Michigan
v.

EPA
used
the
same
arguments
to
contend
that
EPA's
analytic
approach
in
the
NOx
SIP
Call
was
arbitrary
and
capricious.

The
Court
dismissed
these
arguments,
stating:

...
EPA
required
that
all
of
the
covered
jurisdictions,
regardless
of
amount
of
contribution,
reduce
their
NOx
by
an
amount
achievable
with
"
highly
cost­
effective
controls."
83
Petitioners
claim
that
EPA's
uniform
control
strategy
is
irrational....
[
T]
hey
observe
that
where
two
states
differ
considerably
in
the
amount
of
their
respective
NOx
contributions
to
downwind
nonattainment,
under
the
EPA
rule
even
the
small
contributors
must
make
reductions
equivalent
to
those
achievable
by
highly
cost­
effective
measures.
This
of
course
flows
ineluctably
from
the
EPA's
decision
to
draw
the
"
significant
contribution"
line
on
a
basis
of
cost
differentials.
Our
upholding
of
that
decision
logically
entails
upholding
this
consequence.

(
Michigan
v.
EPA,
213
F.
3d
at
679.)

Thus,
the
Court
approved
EPA's
approach
of
requiring
the
same
control
level
on
all
affected
States,
without
concern
as
to
the
arguably
inconsistent
ambient
impacts
that
may
result.
By
the
same
token,
in
today's
action,
EPA's
approach
should
be
accepted
notwithstanding
that
the
upwind
controls
could,
at
least
in
theory,
result
in
an
ambient
impact
that
is
below
the
initial
threshold.
For
this
reason,
there
is
no
basis
to
conduct
a
separate
evaluation
of
the
2015
controls.

ii.
Residual
Nonattainment
Comment:
A
commenter
expressed
concern
that
too
many
areas
will
remain
out
of
attainment
for
the
PM2.5
and
8­
hour
ozone
NAAQS
even
after
implementation
of
the
CAIR
rule.

Response:
Section
110(
a)(
2)(
D)
of
the
CAA
requires
upwind
States
to
prohibit
the
amount
of
emissions
that
contribute
significantly
to
downwind
nonattainment,
but
does
not
require
the
upwind
States
to
prohibit
sufficient
84
emissions
to
assure
that
the
downwind
areas
attain.
Rather,

downwind
areas
continue
to
bear
the
responsibility
of
addressing
remaining
nonattainment.

iii.
Relationship
of
Reductions
to
Attainment
Dates
Comment:
Some
commenters,
who
viewed
the
CAIR
as
imposing
unduly
light
obligations
on
upwind
States,
argued
that
because
States
with
nonattainment
areas
must
develop
SIPs
that
provide
for
attainment
regardless
of
the
cost
of
the
requisite
controls,
and
because
the
courts
have
viewed
attainment
deadlines
as
central
to
the
CAA,
EPA
should
require
that
upwind
emissions
contributing
to
downwind
nonattainment
must
be
eliminated
by
the
downwind
attainment
dates,
and
not
later.

Other
commenters,
who
viewed
the
CAIR
as
imposing
unduly
heavy
obligations
on
upwind
States,
argued
that
EPA
had
no
authority
to
require
upwind
emissions
reductions
after
the
downwind
attainment
dates
because
by
that
time,

the
upwind
emissions
were
no
longer
contributing
to
nonattainment.
These
commenters
further
argued
that
EPA
has
no
authority
to
accelerate
the
emissions
reductions
because
the
controls
could
not
feasibly
be
implemented
by
an
earlier
date.

Response:
We
note
first
that
part
of
this
issue
is
moot
since
EPA
is
requiring
NOx
controls
in
2009,
within
the
85
statutory
time
periods
for
attainment.
With
respect
to
remaining
issues,
EPA's
interpretation
and
application
of
the
"
contribute
significantly
to
nonattainment"
standard
of
section
110(
a)(
2)(
D)
is
not
necessarily
constrained
by
the
downwind
area's
attainment
date
in
either
manner
suggested
by
the
commenters.

First,
although
it
is
true
that
the
nonattainment
area
requirements
and
deadlines
in
CAA
title
I,
part
D,
mean
that
the
downwind
area
must
achieve
attainment
by
its
attainment
date
without
regard
to
the
feasibility
of
emissions
reductions
from
sources
in
that
nonattainment
area,
section
110(
a)(
2)(
D)
by
its
terms
does
not
apply
those
constraints
to
sources
in
the
upwind
States.
Rather,
EPA's
interpretation
of
the
"
contribute
significantly
to
nonattainment"
standard
­
 
which
incorporates
feasibility
considerations
in
determining
the
implementation
period
for
the
upwind
emissions
controls
­­
continues
to
apply.

Often,
upwind
emissions
reductions
affect
at
least
several
downwind
areas
with
different
attainment
dates.
The
EPA
does
not
read
section
110(
a)(
2)(
D)
to
require
that
the
pace
of
upwind
reductions
be
controlled
by
the
earliest
downwind
attainment
date.
Rather,
EPA
views
the
pace
of
reductions
as
being
determined
by
the
time
within
which
they
may
feasibly
be
achieved.
In
some
cases,
upwind
sources
are
86
themselves
in
a
nonattainment
area
that
has
a
longer
attainment
date
than
the
downwind
area,
and
it
may
not
be
feasible
for
those
upwind
sources
to
implement
reductions
prior
to
the
downwind
attainment
date.
Therefore,
the
upwind
emissions
may
be
projected
to
continue
to
affect
adversely
nonattainment
in
the
downwind
area
even
after
the
downwind
attainment
date,
in
the
manner
described
above.

Further,
emissions
reductions
after
the
attainment
date
may
be
important
to
prevent
interference
with
maintenance
of
the
standards.

The
CAIR
will
achieve
substantial
reductions
in
time
to
help
many
nonattainment
areas
attain
the
standards
by
the
applicable
attainment
dates.
The
design
of
the
SO2
program,

including
the
declining
caps
in
2010
and
2015
and
the
banking
provisions,
will
steadily
reduce
SO2
emissions
over
time,
achieving
reductions
in
advance
of
the
cap
dates;
and
the
2009
and
2015
NOx
reductions
will
be
timely
for
many
downwind
nonattainment
areas.
Although
many
of
today's
nonattainment
areas
will
attain
before
all
the
reductions
required
by
CAIR
will
be
achieved,
it
is
clear
that
CAIR's
reductions
will
still
be
needed
through
2015
and
beyond.

EPA
has
determined
that
each
upwind
State's
2010
and
2015
emissions
reductions
will
be
necessary
because,
for
purposes
of
both
PM2.5
and
8­
hour
ozone,
we
reasonably
predict
that
a
87
downwind
receptor
linked
to
that
upwind
State
will
either:

(
i)
remain
in
nonattainment
and
continue
to
experience
significant
contribution
to
nonattainment
from
the
upwind
State's
emissions;
or
(
ii)
attain
the
relevant
NAAQS
but
later
revert
to
nonattainment
due,
for
example,
to
continued
growth
of
the
emissions
inventory.
This
is
discussed
in
detail
in
section
III
below.

iv.
Factors
to
Consider
in
Future
Rulemaking
In
the
January
and
June
CAIR
proposals,
we
discussed
regional
control
requirements
and
budgets
based
on
a
showing
of
"
significant
contribution"
by
upwind
States
to
nonattainment
in
downwind
States
(
69
FR
at
4611­
13,
32720).

The
CAA
section
110(
a)(
2)(
D),
which
provides
the
authority
for
CAIR,
states
among
other
things
that
SIPs
must
contain
adequate
provisions
prohibiting,
consistent
with
the
CAA,

sources
or
other
types
of
emissions
activity
within
a
State
from
emitting
pollutants
in
amounts
that
will
"
contribute
significantly
to
nonattainment
in,
or
interfere
with
maintenance
by,
any
other
State
with
respect
to"
the
NAAQS.

In
CAIR,
EPA
has
interpreted
section
110(
a)(
2)(
D)
to
require
that
certain
States
reduce
emissions
by
specified
amounts,
and
has
determined
those
amounts
based
on
the
availability
of
highly
cost
effective
controls
for
identified
source
categories.
Following
this
88
interpretation,
EPA
has
calculated
CAIR's
emissions
reduction
requirements
based
on
the
availability
of
highly
cost­
effective
reductions
of
SO2
and
NOx
from
EGUs
in
States
that
meet
EPA's
proposed
inclusion
criteria.

One
approach
cited
in
the
January
2004
CAIR
proposal
for
ensuring
that
both
the
air
quality
component
and
the
cost
effectiveness
component
of
the
section
110
"
contribute
significantly"
determination
is
met,
is
to
consider
a
source
category's
contribution
to
ambient
concentrations
above
the
attainment
level
in
all
nonattainment
areas
in
affected
downwind
states.
Id.
In
the
June
supplemental
proposal,
we
requested
comment
on
a
further
refinement
of
this
concept
 
i.
e.,
whether
a
source
category
should
be
included
in
a
broad
regional
rule
promulgated
pursuant
to
section
110(
a)(
2)(
D)
only
if
the
proposed
level
of
additional
control
of
that
category
would
meet
a
specified
threshold.

Under
that
approach,
EPA
said
it
might
determine,
for
example,
that
in
the
context
of
a
broad
multi­
state
SIP
call,
emissions
reductions
from
particular
source
category
are
"
highly
cost
effective"
only
if
emissions
reductions
from
that
source
category
would
result
in
at
least
0.5
percent
of
U.
S.
counties
and/
or
parishes
coming
into
attainment
with
a
NAAQS.
The
EPA
noted
that,
given
the
number
of
counties
and
parishes
in
the
United
States,
this
89
requirement
would
be
met
if
at
least
16
counties
were
brought
into
attainment
with
a
NAAQS
as
a
result
of
the
proposed
level
of
control
on
a
particular
source
category.

The
Agency
received
comments
both
supporting
and
opposing
the
adoption
of
this
test
as
a
part
of
the
"
highly
cost
effective"
component
of
the
"
contribute
significantly"

requirement
of
CAA
section
110(
a)(
2)(
d).
Commenters
supporting
this
test
asserted
that
it
was
consistent
with
the
Clean
Air
Act's
overall
focus
on
State,
rather
than
federal,
control
over
which
sources
should
be
regulated,
and
also
was
consistent
with
ensuring
that
broad,
regional
SIP
calls,
such
as
the
one
at
issue
in
this
case,
focus
only
on
source
categories
the
control
of
which
will
result
in
substantial
overall
improvements
in
air
quality.
Commenters
opposing
this
screen
with
respect
to
the
application
of
section
110(
a)(
2)(
D)
asserted,
in
general,
that
the
test
would
be
inconsistent
with
the
analysis
used
by
the
Agency
in
the
NOx
SIP
call
and
with
the
language
of
section
110(
a)(
2)(
D).

We
have
determined
that
it
is
not
appropriate
to
adopt
a
statutory
interpretation
embodying
a
"
bright
line"
rule
that
0.5
percent
of
the
U.
S.
counties
and/
or
parishes
must
be
brought
from
nonattainment
into
attainment
from
controlling
emissions
from
a
particular
source
category,
in
90
order
for
reductions
from
that
source
category
to
be
considered
highly
cost
effective.
We
continue
to
believe,

however,
that
broad
multi­
state
rules
under
section
110(
a)(
2)(
D),
such
as
the
one
we
are
finalizing
today,

should
play
a
limited
role
under
the
Clean
Air
Act
and
must
be
justified
by
a
careful
evaluation
of
the
air
quality
improvement
that
will
result
from
the
controls
under
consideration.
Therefore,
we
intend
to
undertake
any
future
broad,
multi­
state
rulemakings
under
section
110(
a)(
2)(
D)

regarding
transported
emissions
only
when,
as
here,
they
produce
substantial
air
quality
benefits
across
a
broad
area
and
have
beneficial
air
quality
impacts
on
a
significant
number
of
downwind
nonattainment
areas,
including
bringing
many
areas
into
attainment.
We
do
not
at
this
time
anticipate
the
need
for
any
such
rulemakings
in
the
future.

We
believe
that
today's
action,
coupled
with
current
and
upcoming
national
rules
and
local
or
subregional
programs
adopted
by
States,
will
be
sufficient
to
address
the
remaining
nonattainment
problems.

In
evaluating
whether
to
undertake
national
or
regional
transport
rulemakings
in
the
future,
we
believe
it
is
not
only
appropriate
but
necessary
to
consider
the
effectiveness
of
the
proposed
emissions
reductions
in
improving
downwind
air
quality.
We
believe
it
will
be
reasonable
to
initiate
a
91
broad
multi­
state
rulemaking
under
section
110(
a)(
2)(
D)

based
on
a
determination
that
particular
emissions
reductions
are
highly
cost
effective
only
when
those
reductions
will
bring
a
significant
number
of
downwind
areas
into
attainment.
In
adopting
this
approach
for
determining
whether
a
future
broad,
multi­
state
SIP
call
is
appropriate,

we
note
that
other
CAA
mechanisms,
such
as
SIP
disapproval
authority
and
State
petitions
under
section
126,
are
available
to
address
more
isolated
instances
of
the
interstate
transport
of
pollutants.

The
EPA
projects
that
control
of
SO2
and
NOx
through
CAIR
will
bring
72
counties
into
attainment
with
the
PM2.5
and
ozone
NAAQS.
The
total
number
represents
approximately
3
percent
of
the
counties/
parishes
in
the
United
States,
and
is
clearly
a
significant
number
of
areas.
What
will
be
considered
a
significant
number
of
areas
in
any
future
cases
will
need
to
be
determined
on
a
case­
by­
case
basis.

III.
Why
Does
This
Rule
Focus
on
SO2
and
NOx,
and
How
Were
Significant
Downwind
Impacts
Determined?

This
section
discusses
the
basis
for
EPA's
decision
to
require
reductions
in
upwind
emissions
of
SO2
and
NOx
to
address
PM2.5
transport
and
to
require
reductions
in
upwind
emissions
of
NOx
to
address
ozone­
related
transport.
In
addition,
this
section
discusses
how
EPA
determined
which
92
States
are
subject
to
today's
rule
because
their
sources'

emissions
will
significantly
contribute
to
nonattainment
of
the
PM2.5
or
8­
hour
ozone
standards,
or
interfere
with
maintenance
of
those
standards,
in
downwind
States.
The
EPA
assessed
individual
upwind
States'
ambient
impacts
on
downwind
States
and
established
a
threshold
value
to
identify
those
States
whose
impact
constitutes
a
significant
contribution
to
air
quality
violations
in
the
downwind
States.
The
EPA
used
air
quality
modeling
of
emissions
in
each
State
to
estimate
the
ambient
impacts.
The
technical
issues
concerning
the
modeling
platform
and
approach
are
discussed
in
section
VI,
Air
Quality
Modeling
Approach
and
Results.
EPA
also
considered
the
potential
for
upwind
state
emissions
to
interfere
with
maintenance
of
the
PM2.5
and
8­

hour
ozone
NAAQS
in
downwind
areas.

A.
What
is
the
Basis
for
EPA's
Decision
to
Require
Reductions
in
Upwind
Emissions
of
SO2
and
NOx
to
Address
PM2.5
related
transport?

1.
How
did
EPA
determine
which
pollutants
were
necessary
to
control
to
address
interstate
transport
for
PM2.5?

a.
What
did
EPA
propose
regarding
this
issue
in
the
NPR?

Section
II
of
the
January
2004
proposal
summarized
key
scientific
and
technical
aspects
of
the
occurrence,

formation,
and
origins
of
PM2.5,
as
well
as
findings
and
93
17More
complete
discussions
of
the
key
scientific
underpinnings
that
form
the
basis
of
these
conclusions
in
the
proposal
and
the
discussion
of
these
issues
in
this
section
of
today's
notice
can
be
found
in
the
recently
completed
EPA
Criteria
Document
(
USEPA,
National
Center
for
Environmental
Assessment,
Air
Quality
Criteria
for
Particulate
Matter,
October
2004)
and
the
NARTSO
assessment
of
fine
particles
(
NARSTO,
Particulate
Matter
Science
for
Policy
Makers
­
A
NARSTO
Assessment,
February
2003).
observations
relevant
to
formulating
control
approaches
for
reducing
the
contribution
of
transport
to
fine
particle
problems
(
69
FR
4575­
87).
Key
concepts
and
provisional
conclusions
drawn
from
this
discussion
can
be
summarized
as
follows:
17
(
1)
Fine
particles
(
measured
as
PM2.5
for
the
NAAQS)
consist
of
a
diverse
mixture
of
substances
that
vary
in
size,

chemical
composition,
and
source.
The
PM2.5
includes
both
"
primary"
particles
that
are
emitted
directly
to
the
atmosphere
as
particles,
and
"
secondary"
particles
that
form
in
the
atmosphere
through
chemical
reactions
from
gaseous
precursors.
The
major
components
of
fine
particles
in
the
Eastern
US
can
be
grouped
into
five
categories:
carbonaceous
material
(
including
both
primary
and
secondary
organic
carbon
and
black
carbon),
sulfates,
nitrates,
ammonium,
and
crustal
material,
which
includes
suspended
dust
as
well
as
some
other
directly
emitted
materials.
The
major
gaseous
precursors
of
PM2.5
include
SO2,
NOx,
ammonia
(
NH3),
and
certain
volatile
organic
compounds.
94
(
2)
Examination
of
urban
and
rural
monitors
indicate
that
in
the
Eastern
U.
S.,
sulfates,
carbonaceous
material,

nitrates,
and
ammonium
associated
with
sulfates
and
nitrates
are
typically
the
largest
components
of
transported
PM2.5,

while
crustal
material
tends
to
be
only
a
small
fraction.

(
3)
Atmospheric
interactions
among
particulate
ammonium
sulfates
and
nitrates
and
gas
phase
nitric
acid
and
ammonia
vary
with
temperature,
humidity,
and
location.
Both
ambient
observations
and
modeling
simulations
suggest
that
regional
SO2
reductions
are
effective
at
reducing
sulfate
and
associated
ammonium,
and,
therefore,
PM2.5.
Under
certain
conditions
reductions
in
particulate
ammonium
sulfates
can
release
ammonia
as
a
gas,
which
then
reacts
with
gaseous
nitric
acid
to
form
nitrate
particles,
a
phenomenon
called
"
nitrate
replacement."
In
such
conditions
SO2
reductions
would
be
less
effective
in
reducing
PM2.5,
unless
accompanied
by
reductions
in
NOx
emissions
to
address
the
potential
increase
in
nitrates.

(
4)
Reductions
in
ammonia
can
reduce
the
ammonium,
but
not
the
sulfate
portion
of
sulfate
particles.
The
relative
efficacy
of
reducing
nitrates
through
NOx
or
ammonia
control
varies
with
atmospheric
conditions;
the
highest
particulate
nitrate
concentrations
in
the
East
tend
to
occur
in
cooler
months
and
regions.
At
present,
our
knowledge
about
95
sources,
emissions,
control
approaches,
and
costs
is
greater
for
NOx
than
for
ammonia.
Existing
programs
to
reduce
NOx
from
stationary
and
mobile
sources
are
well
underway.
From
a
chemical
perspective,
as
NOx
reductions
accumulate
relative
to
ammonia,
the
atmospheric
chemical
system
would
move
towards
an
equilibrium
in
which
ammonium
nitrate
reductions
become
more
responsive
to
further
NOx
reductions
relative
to
ammonia
reductions.

(
5)
Much
less
is
known
about
the
sources
of
regional
transport
of
carbonaceous
material.
Key
uncertainties
include
how
much
of
this
material
is
due
to
biogenic
as
compared
to
anthropogenic
sources,
and
how
much
is
directly
emitted
as
compared
to
formed
in
the
atmosphere.

(
6)
Observational
evidence
suggests
that
the
substantial
reductions
in
SO2
emissions
in
the
eastern
U.
S.
since
1990
have
indeed
caused
observed
reductions
in
PM2.5
sulfate.

The
relatively
small
historical
reductions
in
NOx
emissions
do
not
allow
observations
to
be
used
similarly
to
test
the
effectiveness
of
NOx
reductions.

Based
on
the
understanding
of
current
scientific
and
technical
information,
as
well
as
EPA's
air
quality
modeling,
as
summarized
in
the
January
30
proposal,
EPA
concluded
that
it
was
both
appropriate
and
necessary
to
focus
on
control
of
SO2
and
NOx
emissions
as
the
most
96
effective
approach
to
reducing
the
contribution
of
interstate
transport
to
PM2.5.

EPA
proposed
not
to
control
emissions
that
affect
other
components
of
PM2.5,
noting
that
"
current
information
relating
to
sources
and
controls
for
other
components
identified
in
transported
PM2.5
(
carbonaceous
particles,

ammonium,
and
crustal
materials)
does
not,
at
this
time,

provide
an
adequate
basis
for
regulating
the
regional
transport
of
emissions
responsible
for
these
PM2.5
components."
(
69
FR
4582).
For
all
of
these
components,
the
lack
of
knowledge
of
and
ability
to
quantify
accurately
the
interstate
transport
of
these
components
limited
EPA's
ability
to
include
these
components
in
this
rule.

b.
How
does
EPA
address
public
comments
on
its
proposal
to
address
SO2
and
NOx
emissions
and
not
other
pollutants?

i.
Overview
of
comments
on
this
issue
A
large
number
of
commenters
including
states,
affected
industries,
environmental
groups,
academics,
and
other
members
of
the
public
agreed
with
EPA's
proposal
to
require
cost­
effective
multipollutant
reductions
of
SO2
and
NOx
to
address
interstate
transport
contributions
to
PM2.5
problems.
Fewer
commenters
who
supported
controlling
SO2
and
NOx
commented
on
inclusion
of
additional
pollutants,
but
several
also
agreed
that
it
would
be
premature
at
this
time
97
to
require
control
of
emissions
of
other
chemical
components
and
precursors
to
address
such
transport.
These
commenters
suggested
that
SO2
and
NOx
emissions
from
EGUs
and
other
sources
indeed
contribute
significantly
to
downwind
PM2.5.

They
argued
that
control
of
other
components
is
premature
because
of
a
lack
of
knowledge,
either
about
the
interstate
contributions
of
other
components
or
of
control
measures
for
these
components.
EPA
generally
accepts
and
agrees
with
these
conclusions.

A
number
of
commenters
disagreed
to
varying
degrees
with
part
or
all
of
EPA's
proposed
focus
on
SO2
and
NOx.

The
main
points
raised
by
these
commenters
can
be
grouped
as
follows:

(
1)
The
focus
on
SO2
and
NOx
is
not
appropriate
because
sulfates
and
nitrates
may
not
be
(
or
are
not)
the
most
important
determinants
of
the
health
effects
of
PM2.5.

(
2)
EPA
should
mandate,
or
at
least
permit,
states
to
control
other
precursors
and
particle
emissions
in
addition
to,
or
instead
of,
SO2
and
NOx.
Commenters
sometimes
made
specific
recommendations
with
respect
to
additional
pollutants,
including
carbonaceous
(
including
organic)

particles
and
precursors,
ammonia,
and
other
direct
emissions,
including
crustal
material.

(
3)
The
focus
on
SO2
may
be
appropriate,
but
the
basis
for
98
18R.
J.
Klemm,
et
al.,"
Daily
Mortality
and
Air
Pollution
in
Atlanta:
Two
Year
of
Data
from
ARIES
"(
accepted,
Inhalation
Toxicology)
requiring
NOx
control
is
not
clear.

ii)
Summary
of
EPA's
response
to
the
major
comments
on
this
issue
The
following
subsections
summarize
both
key
comments
and
EPA's
responses
organized
by
the
major
categories
outlined
above.
As
noted
in
Section
I,
EPA
has
developed
and
placed
in
the
rulemaking
docket
a
detailed
response
to
these
and
other
public
comments.

(
a)
SO2
and
NOx
may
be
less
important
to
health
than
other
transport­
related
components.

Comment:
Several
commenters
argued
that
the
proposed
focus
on
SO2
and
NOx
was
premature,
citing
the
potential
for
differential
toxicity
of
various
PM2.5
components,
and
in
some
cases
advancing
evidence
(
e.
g.
the
Electric
Power
Research
Institute
Aerosol
Research
and
Inhalation
Studies
[
ARIES])
18
that
other
components
such
as
organic
particles
appear
to
be
more
responsible
for
health
effects
of
particles
than
sulfates
and
nitrates.
Several
argued
that
the
relative
contribution
of
components
to
health
impacts
is
an
important
uncertainty
that
should
be
researched
more
carefully
before
proposing
to
control
only
SO2
and
NOx.

Response:
Today's
rulemaking
establishes
requirements
99
for
SIP
submissions
under
section
110(
a)(
2)(
D).
Those
SIP
submissions
must
prohibit
emissions
that
contribute
significantly
to
nonattainment
of
a
NAAQS
in
a
downwind
State.
EPA
determined
in
the
1997
rulemaking
promulgating
the
PM2.5
NAAQS
that
specified
levels
of
PM2.5
adversely
affect
human
health,
and
that
sulfates
and
nitrates
are
components
of
PM2.5
(
62
FR
38652,
July
18,
1997).
SO2
and
NOx,
in
turn,
are
precursors
to
fine
particulate
sulfates
and
nitrates.
Comments
that
sulfates
and
nitrates
do
not
cause
adverse
health
effects
are
more
appropriately
raised
in
the
context
of
past
or
ongoing
reviews
of
the
PM
NAAQS.

Because
today's
action
forms
part
of
implementing
and
not
establishing
the
PM
NAAQS,
comments
relating
to
the
evidence
supporting
or
not
supporting
health
effects
of
all
or
portions
of
pollutants
regulated
by
the
PM2.5
NAAQS
are
not
germane
to
this
rulemaking.

Nevertheless,
we
discuss
briefly
EPA's
current
response
regarding
the
contributions
of
different
components
of
PM2.5
to
health
effects.
In
establishing
the
current
PM2.5
NAAQS,

EPA
found
that
there
was
ample
evidence
to
associate
various
health
effects
with
the
measured
mass
concentration
of
particles
smaller
than
a
nominal
2.5
micrometers
(
um),

termed
PM2.5.
EPA
recognizes
that
the
toxicity
of
different
chemical
components
of
PM2.5
may
vary,
and
that
the
observed
100
19USEPA,
National
Center
for
Environmental
Assessment,
Air
Quality
Criteria
for
Particulate
Matter,
October
2004.
effects
may
be
the
result
of
the
mixture
of
particles
and
gases.
While
research
is
underway
to
better
identify
whether
some
chemical
components
are
more
responsible
for
health
effects
than
others,
results
now
available
from
such
research
are
limited
and
inconclusive.
A
number
of
studies
included
in
the
recent
EPA
PM
criteria
document19
have
found
effects
to
be
associated
with
one
or
more
of
the
major
components
and
sources
of
PM2.5,
including
sulfates,

nitrates,
organic
materials,
PM2.5
mass,
coal
combustion,

and
mobile
sources.
The
criteria
document
concludes
that
these
studies
suggest
that
many
different
chemical
components
of
fine
particles
and
a
variety
of
different
types
of
source
categories
are
all
linked
to
premature
mortality
and
other
serious
health
effects,
either
independently
or
in
combinations,
but
that
it
is
not
possible
to
reach
clear
conclusions
about
differential
effects
of
PM
components.
Accordingly,
individual
studies
or
groups
of
studies
such
as
ARIES
cannot
be
used
to
single
out
any
particular
component
of
PM2.5
as
wholly
responsible
(
or
not
at
all
responsible)
for
the
array
of
health
effects
that
have
been
found
to
be
associated
with
various
chemical
and
mass
indicators
of
fine
particles.
EPA
and
other
101
federal
agencies
continue
to
promote
and
support
the
epidemiological
and
toxicological
studies
needed
to
better
understand
the
effects
of
different
chemical
components
and
different
size
particles
on
health
effects.

In
the
meantime,
EPA
believes
that,
given
the
substantial
evidence
of
significant
health
effects
of
fine
particles,
it
is
important
to
move
forward
expeditiously
to
address
both
transported
and
local
sources
of
all
the
major
components
of
fine
particles
in
an
effort
to
implement
and
attain
the
PM2.5
standards.
Today's
rule
is
focused
on
the
contribution
of
interstate
transport
of
nitrate
and
sulfates
to
PM2.5
in
nonattainment
areas.
EPA
has,
however,
already
adopted
other
rules
that
are
reducing
emissions
and
exposures
to
these
and
other
major
components
of
fine
particles
on
a
national,
regional,
and
local
basis.

Recent
national
mobile
rules
and
programs,
in
particular,

have
focused
on
carbonaceous
materials
emitted
from
gasoline
and
both
highway
and
non­
road
diesel
powered
mobile
sources
(
65
FR
6698;
66
FR
5002;
69
FR
38958).
States
with
nonattainment
areas
will
also
be
required
to
address
local
sources
of
PM2.5
in
order
to
meet
progress
and
attainment
requirements.
Together,
the
collective
effect
of
these
programs
ensures
a
balanced
approach
to
reducing
all
of
the
major
components
of
PM2.5
from
transported
and
local
102
sources.

(
b)
Inclusion
of
other
PM2.5
precursors
and
components
Comment:
A
number
of
commenters
recommended
that
EPA
either
mandate
or
at
least
permit
controls
on
the
emissions
that
cause
interstate
transport
of
other
components
of
PM2.5,
in
addition
to
or
as
a
substitute
for,
SO2
and
NOx
controls.
Several
commenters
recommended
that
EPA
include
emissions
reductions
related
to
the
components
of
PM2.5
other
than
sulfate
and
nitrate.
While
many
commenters
suggested
addressing
all
of
the
important
contributors
to
PM2.5,
including
those
not
regulated
under
this
Rule,
others
highlighted
only
one
or
two
additional
components
as
most
important
to
include.
Of
the
PM2.5
components,
direct
emissions
and
precursors
to
carbonaceous
PM2.5
and
ammonia
emissions
were
the
omitted
contributors
most
frequently
discussed.

Some
of
these
commenters
argued
that,
by
limiting
the
rule
to
SO2
and
NOx
and
excluding
other
sources
of
ambient
PM2.5,
EPA
would
be
limiting
the
choices
that
states
have
to
address
their
downwind
interstate
transport
contributions.

These
commenters
argued
that
this
limitation
is
contrary
to
the
Clean
Air
Act,
which
generally
gives
states
the
discretion
to
choose
their
own
emission
control
strategies.

Commenters
further
asserted
that
the
roles
of
other
103
components
in
PM2.5
are
sufficiently
well
understood
that
they
should
be
included
in
state
SIPs
for
PM2.5
transport,

and
could
partially
satisfy
the
PM2.5
reductions
anticipated
by
this
rule.

Response:
The
three
main
classes
of
PM2.5
precursors
that
are
not
included
in
this
rulemaking
are
carbonaceous
material
(
including
both
primary
emissions
and
VOC
emissions
that
form
secondary
organic
aerosol),
ammonia,
and
crustal
material.
As
noted
in
the
proposal(
69
FR
4576)
and
as
mentioned
in
several
comments,
these
components
comprise
a
measurable
faction
of
PM2.5
throughout
the
Eastern
U.
S.,
and
the
contribution
of
carbonaceous
material,
in
particular,
is
often
substantial.
In
addition,
emissions
contributing
to
these
components
in
one
state
likely
do
affect
PM2.5
concentrations
in
other
states
to
some
extent.
However,
the
extent
of
those
downwind
contributions
to
nonattainment
has
not
been
quantified
adequately
and
current
scientific
understanding
makes
such
a
determination
more
uncertain
than
is
the
case
for
SO2
and
NOx.
Responses
to
recommendations
for
including
each
of
these
three
classes
in
the
transport
rule
are
summarized
below.

(
i)
Carbonaceous
Material
For
carbonaceous
material,
uncertainties
in
both
the
quantity
and
origins
of
emissions
contributing
to
both
104
20V.
Rao,
N.
Frank,
A.
Rush,
F.
Dimmick.
Chemical
Speciation
of
PM2.5
in
Urban
and
Rural
Area,
in
The
Proceedings
of
the
Air
&
Waste
Management
Association
Symposium
on
Air
Quality
Measurement
Methods
and
Technology,
San
Francisco,
November
13­
1,
2002.
primary
and
secondary
carbonaceous
material
on
regional
scales
(
including
emissions
from
fires
and
from
biogenic
sources)
limit
the
quality
of
regional
scale
modeling
of
carbonaceous
PM2.5.
This
in
turn
causes
substantial
uncertainties
in
determining
the
amount
of
interstate
transport
from
carbonaceous
material
and
of
the
costs
and
effectiveness
of
emission
controls.
Modeling
and
monitoring
the
relative
amount
of
organic
particles
that
come
from
the
formation
of
secondary
organic
particles,
versus
primary
organic
particles,
is
also
highly
uncertain.

In
addition,
comparison
of
urban
and
nearby
rural
PM
composition
monitors20
in
the
eastern
US
find
a
significantly
larger
amount
of
carbonaceous
materials
in
urban
areas
as
compared
to
rural
areas,
suggesting
that
a
substantial
fraction
of
carbonaceous
particles
in
urban
areas
come
from
local
sources.
By
contrast,
urban
and
nonurban
monitors
in
the
East
show
greater
homogeneity
for
regional
sulfate
concentrations
as
compared
to
carbonaceous
materials,
suggesting
regional
sources
are
most
important
for
sulfates.
Results
for
nitrates
suggest
both
a
mixture
of
regional
and
local
sources.
Furthermore,
as
noted
above
105
21Jang,
M;
Czoschke,
N.
M.;
Lee,
S.:
Kamens,
R.
M.,
Heterogeneous
Atmospheric
Aerosol
Production
by
Acid­
Catalyzed
Particle
Phase
Reactions,
Science,
2002,
298:
814­
817.
and
in
the
proposal
(
69
FR
4577­
78),
while
the
relative
contributions
of
different
sources
to
regional
sulfate
and
nitrates
can
be
quantified
with
certainty,
the
contributions
of
different
sources
to
carbonaceous
materials
on
a
regional
scale
are
less
clear.
Moreover,
as
noted
in
the
NPR
preamble,
some
research
into
mechanisms
of
formation
of
organic
particles
suggests
that
both
NOx
and
SO2
reductions
might
be
of
some
benefit
in
lowering
the
amount
of
secondary
organic
particles.
21
Current
models
are
not,
however,

capable
of
quantifying
such
potential
benefits.

While
EPA
does
not
believe
that
enough
is
known
about
the
relative
effectiveness
or
costs
of
reducing
anthropogenic
sources
of
carbonaceous
particles
on
transported
PM2.5,
EPA
agrees
that
control
of
known
source
categories
of
these
materials
can
have
a
significant
benefit
in
reducing
the
significant
local
contribution.
For
this
reason,
EPA
has
already
enacted
other
national
rules
that
will
reduce
emissions
of
primary
carbonaceous
PM2.5
from
mobile
sources,
the
largest
contributor
to
such
emissions.

In
addition
to
reducing
PM2.5
in
nonattainment
areas,
these
regulations
will
also
have
the
benefit
of
reducing
a
large
106
22Battye,
W.,
V.
P.
Aneja,
and
P.
A.
Roelle,
Evaluation
and
improvement
of
ammonia
emissions
inventories,
Atmospheric
Environment,
2003,
37:
3873­
3883.

23As
pointed
out
by
one
commenter,
a
hypothetical
new
program
resulting
in
major
regional
reductions
of
ammonia
would
reduce
the
effectiveness
of
NOx
controls.
However,
given
the
uncertainties
in
emissions,
the
dispersed
nature
of
ammonia
sources
and
the
lack
of
present
controls,
an
effort
to
develop
a
new
regional
ammonia
program
would
likely
take
significantly
longer
than
the
additional
NOx
measure
of
whatever
interstate
transport
of
carbonaceous
PM2.5
occurs.

(
ii)
Ammonia
While
current
models
are
able
to
address
the
major
chemical
mechanisms
involving
particulate
ammonium
compounds,
regional­
scale
ammonia
emissions,
particularly
from
agricultural
sources,
are
highly
uncertain.
22
Given
the
relative
lack
of
experience
in
controlling
such
sources,

the
costs
and
effectiveness
of
actions
to
reduce
regional
ammonia
emissions
are
not
adequately
quantified
at
present.

As
noted
above,
ammonium
would
not
exist
in
PM2.5
if
not
for
the
presence
of
sulfuric
acid
or
nitric
acid;
hence,

decreases
in
SO2
and
NOx
can
be
expected
ultimately
to
decrease
the
ammonium
in
PM2.5
as
well.
The
additional
regional
limits
on
SO2
and
NOx
emissions
outlined
in
today's
notice
added
to
those
reductions
provided
under
current
programs
would
likewise
be
expected
to
reduce
the
PM2.5
effectiveness
of
any
ammonia
control
initiative.
23
Unlike
107
reductions
EPA
is
adopting
today.
ammonium,
sulfuric
acid
has
a
very
low
vapor
pressure
and
would
exist
in
the
particle
with
or
without
ammonia.

Therefore,
while
SO2
reductions
would
reduce
particulate
ammonium,
changes
in
ammonia
would
be
expected
to
have
very
little
effect
on
the
sulfate
concentration.

In
addition
to
the
above
considerations,
because
ammonium
nitrates
are
highest
in
the
winter,
when
ammonia
emissions
are
lowest,
reducing
wintertime
NOx
emissions
may
represent
a
more
certain
path
towards
reducing
this
winter
peak
than
ammonia
reductions.
Moreover,
reductions
in
ammonia
emissions
alone
would
also
tend
to
increase
the
acidity
of
PM2.5
and
of
precipitation.
As
noted
in
the
proposal,
this
might
have
untoward
environmental
or
health
consequences.

Some
commenters
highlighted
ammonia
as
an
important
pollutant
with
multiple
effects
on
the
environment,

including
its
contributions
to
PM2.5.
These
commenters
highlighted
that
ammonia
emissions
are
not
currently
regulated
extensively,
and
suggested
that
EPA
strengthen
its
efforts
to
better
understand
the
many
effects
of
ammonia
emissions
and
better
research
options
for
controlling
ammonia,
so
that
it
can
be
regulated
where
appropriate
in
the
future
programs.
EPA
generally
agrees
with
these
108
commenters.

(
iii)
Crustal
Material
The
contributions
of
crustal
materials
to
PM2.5
nonattainment
are
usually
small,
and
the
interstate
transport
of
crustal
materials
is
even
smaller.
Emissions
of
crustal
materials
on
regional
scales
are
uncertain,

highly
variable
in
space
and
time,
and
may
not
be
easily
controlled
in
some
cases,
suggesting
significant
uncertainties
in
quantifying
emissions
and
the
costs
and
effectiveness
of
control
actions.
Emissions
reductions
of
SO2
and
NOx
will
likely
reduce
some
of
the
direct
emissions
of
PM2.5
from
EGUs
and
other
industries,
which
are
responsible
for
a
portion
of
the
"
crustal
material"
measured
downwind
at
receptors.

(
c)
Summary
of
response
to
requiring
or
allowing
reductions
in
other
pollutants.

After
reviewing
public
comments
in
light
of
the
current
understanding
of
alternative
pollutants
as
summarized
above,

EPA
diagrees
with
those
commenters
who
suggested
that
the
final
Clean
Air
Interstate
Rule
should
require
states
to
address
the
interstate
transport
of
carbonaceous
material
(
including
VOCs),
ammonia,
and/
or
crustal
material
in
the
present
rulemaking.

At
present,
the
sources
and
emissions
contributing
to
109
24EPA
OAQPS
CMAQ
Evaluation
for
2001"
Docket
#
OAR­
2003­
0053­
1716
these
components
on
regional
scales
are
not
sufficiently
quantified.
In
addition,
the
representation
of
atmospheric
physics
and
chemistry
for
these
components
in
air
quality
models
is
in
some
cases
poor
in
comparison
with
current
understanding
of
SO2
and
NOx
(
most
notably
for
sources
and
amounts
of
secondary
organic
aerosol
production.
24
Consequently,
quantification
of
the
interstate
transport
of
these
components
is
significantly
more
uncertain
than
for
SO2
and
NOx
emissions.
Given
these
uncertainties
in
regional
emissions
and
interstate
transport
of
these
components,
EPA
has
determined
that
it
would
be
premature
to
quantify
interstate
impacts
of
these
emissions
through
zeroout
modeling,
as
was
done
for
SO2
and
NOx
emissions.

In
addition,
the
costs
of
control
measures,
their
effectiveness
at
reducing
emissions,
as
well
as
their
ultimate
effectiveness
at
reducing
PM2.5
concentrations
at
downwind
receptors
are
all
uncertain.
EPA
does
not
believe
it
could
reasonably
evaluate
whether
such
State
emissions
contributed
significantly
to
transport,
or
what
level
of
control
would
address
the
significant
contribution.

Commenters
have
not
provided
us
specific
data
and
information
to
allow
such
assessments.

EPA
also
disagrees
with
commenters
who
argue
that
EPA
110
should,
for
the
purposes
of
this
rule,
permit
the
States
to
substitute
controls
of
sources
of
any
of
these
other
three
components
for
the
required
limits
on
SO2
and
NOx.
Given
the
greater
uncertainties
in
estimating
the
contribution
of
alternative
source
emissions,
States
would
have
difficulty
developing,
and
EPA
would
have
difficulty
in
approving,
SIPs
that,
by
controlling
these
components,
purport
to
reduce
an
upwind
State's
impact
on
downwind
PM2.5
nonattainment
by
an
equivalent
amount
to
that
required
in
today's
final
rule.

As
explained
in
the
proposal,
a
decision
not
to
regulate
these
components
of
PM2.5
in
the
present
rulemaking
does
not
preclude
state
or
local
PM2.5
implementation
plans
from
reducing
emissions
of
carbonaceous
material,
ammonia,

or
crustal
material,
in
order
to
achieve
attainment
with
PM2.5
standards,
in
cases
where
there
is
evidence
that
such
controls
will
be
effective
on
a
local
basis.
Although
uncertainties
exist
in
addressing
long­
range
transport
of
these
pollutants,
state
and
local
air
quality
management
agencies
will
need
to
evaluate
reasonable
control
measures
for
sources
of
these
pollutants
in
developing
SIPs
due
in
2008.
We
expect
continuous
improvements
will
be
made
in
our
understanding
of
source
emissions
and
PM2.5
components
not
addressed
under
CAIR.
To
assist
future
air
quality
management
decisions,
EPA
is
actively
supporting
research
111
into
better
understanding
the
emissions,
atmospheric
processes,
long
range
transport,
and
opportunities
for
control
of
these
PM2.5
components.

(
d)
Justification
for
Including
NOx
in
Determining
Significant
Contributions
and
for
Regulating
NOx
Emissions
for
PM2.5
Transport
Some
commenters
questioned
the
EPA's
basis
for
requiring
emissions
reductions
of
NOx,
in
addition
to
SO2,

for
the
purposes
of
controlling
interstate
transport
of
PM2.5.
These
comments,
and
EPA's
response,
are
discussed
below.
Other
comments
addressing
EPA's
basis
for
requiring
NOx
for
ozone
are
addressed
in
a
subsequent
section.

Like
SO2,
NOx
emissions
are
understood
to
affect
PM2.5
on
regional
scales,
due
in
part
to
the
time
needed
to
convert
NOx
emissions
to
nitrate.
Like
SO2
but
unlike
precursors
of
other
components
of
PM2.5,
emissions
of
NOx
are
well
quantified
for
EGUs
and
with
reasonable
accuracy
for
other
urban
and
regional
sources,
and
the
transport
of
NOx
and
PM2.5
derived
from
NOx
can
also
be
quantified
with
a
fair
degree
of
certainty.
In
addition,
SO2
and
NOx
interact
as
part
of
the
same
chemical
system
in
the
atmosphere.

Controlling
SO2
emissions
without
concurrently
controlling
NOx
emissions
can
lead
to
nitrate
replacement
whereby
SO2
emissions
reductions
will
be
less
effective
than
expected.
112
25NARSTO,
Particulate
Matter
Science
for
Policy
Makers
­
A
NARSTO
Assessment,
February
2003.
Finally,
SO2
and
NOx
share
common
sources
in
fossil
fuel
combustion.
As
such,
controlling
emissions
of
both
precursors
in
a
coordinated
way
presents
opportunities
to
reduce
the
overall
cost
of
the
control
program.
25
Commenters
questioned
EPA's
methodology
of
evaluating
whether
an
upwind
State
contributes
significantly
to
PM2.5
nonattainment
by
considering
(
through
the
"
zero­
out"
air
quality
modeling
technique)
SO2
and
NOx
emissions
simultaneously.
These
commenters
argued
that
zeroing
out
SO2
and
NOx
emissions
simultaneously
precludes
determining
the
contribution
of
each
component
to
downwind
nonattainment.
Because
sulfates
generally
comprise
a
greater
fraction
of
PM2.5
than
nitrates
in
the
Eastern
U.
S.,

these
commenters
argued
that
the
basis
for
requiring
NOx
controls
is
weaker
than
for
SO2,
and
has
not
been
determined
directly
by
EPA.

EPA's
multi­
pollutant
approach
of
modeling
SO2
and
NOx
contributions
at
the
same
time
is
consistent
both
with
sound
science
and
with
the
requirements
of
CAA
section
110(
a)(
2)(
D),
as
EPA
interpreted
and
applied
them
in
the
NOx
SIP
Call.
This
provision
requires
each
State
to
submit
a
SIP
to
prohibit
"
any
source
or
other
type
of
emissions
113
activity
within
the
State
from
emitting
any
air
pollutant
in
amounts
which
will
...
contribute
significantly
to
nonattainment"
downwind.
As
discussed
in
Section
II
above,

in
the
NOx
SIP
Call,
a
rulemaking
in
which
EPA
regulated
NOx
emissions
as
precursors
for
ozone,
EPA
found
that
ozone
resulted
from
the
combined
contributions
of
many
emitters
over
a
multistate
region,
a
phenomenon
that
EPA
termed
"
collective
contribution"
(
63
FR
57356­
86).
As
a
result,

EPA
evaluated
each
State's
contribution
to
nonattainment
downwind
by
considering
the
impact
of
the
entirety
of
that
State's
NOx
emissions
on
downwind
nonattainment.
Once
EPA
determined
the
State's
entire
NOx
emissions
inventory
to
have
at
least
a
minimum
downwind
impact,
then
EPA
required
the
State
to
eliminate
the
portion
of
those
emissions
that
could
be
reduced
through
highly
cost­
effective
controls.

EPA
considered
this
approach
to
be
consistent
with
the
section
110(
a)(
2)(
D)
requirements.

In
a
companion
rulemaking,
the
Section
126
Rule,
EPA
found
that
certain,
individual
NOx
emitters
must
be
subject
to
Federal
regulation
due
to
their
impact
on
downwind
nonattainment
(
65
FR
2674).
EPA
based
this
finding
on
the
same
notion
of
"
collective
contribution,"
that
is,
NOx
emissions
from
those
individual
sources
were
part
of
the
upwind
State's
total
NOx
inventory,
the
total
NOx
inventory
114
had
a
sufficiently
high
impact
on
downwind
nonattainment,

and
therefore
the
individual
NOx
emitters
should
be
subject
to
control
without
any
separate
determination
as
to
their
individual
impacts
on
downwind
nonattainment.

The
D.
C.
Circuit
accepted
EPA's
collective
contribution
approach
upholding
most
of
the
NOx
SIP
Call
regulation,
in
Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.
Cir.
2000),
cert.
denied
532
U.
S.
904
(
2001).
Similarly,
the
D.
C.
Circuit
upheld
most
aspects
of
EPA's
Section
126
Rule,
including
the
collective
contribution
basis
for
finding
that
emissions
from
the
individual
sources
should
be
subject
to
regulation.

Appalachian
Power
co.
v.
EPA,
249
F.
3d
1032
(
D.
C.
Cir.
2001)

(
per
curium).

As
discussed
elsewhere,
PM2.5
is
similar
to
ozone
in
that
it
is
the
result
of
emissions
from
many
sources
over
a
multi­
state
region.
Accordingly,
EPA
considers
that
the
phenomenon
of
"
collective
contribution"
is
associated
with
PM2.5
as
well.

In
the
CAIR
NPR,
EPA
selected
SO2
and
NOx
as
the
appropriate
precursors
to
be
controlled
for
PM2.5
transport,

for
several
reasons
presented
above.
As
in
the
NOx
SIP
Call,
today's
rulemaking,
under
CAA
section
110(
a)(
2)(
D),

requires
EPA
to
evaluate
whether
a
particular
upwind
State
must
submit
a
SIP
that
prohibits
"
any
source
or
other
type
115
of
emissions
activity
within
the
State
from
emitting
any
air
pollutant
in
amounts
which
will
...
contribute
significantly
to
nonattainment"
downwind.
In
making
this
determination,

EPA
considers
the
effects
of
all
of
the
appropriate
precursors
 
here,
both
SO2
and
NOx
 
from
all
of
the
State's
sources
on
downwind
PM2.5
nonattainment.
If
that
collective
contribution
to
downwind
PM2.5
nonattainment
is
sufficiently
high,
then
EPA
requires
the
upwind
State
to
eliminate
those
precursors
to
the
extent
of
the
availability
of
highly
cost­
effective
controls.

EPA's
approach
to
evaluating
a
State's
impact
on
downwind
nonattainment
by
considering
the
entirety
of
the
State's
SO2
and
NOx
emissions
is
also
consistent
with
the
chemical
interactions
in
the
atmosphere
of
SO2
and
NOx
in
forming
PM2.5.
The
contributions
of
SO2
and
NOx
emissions
are
generally
not
additive,
but
rather
are
interrelated
due
to
the
nitrate
replacement
phenomenon,
as
well
as
other
complex
chemical
reactions
that
can
include
organic
compounds
as
well.
As
commenters
point
out,
the
nature
of
these
reactions
can
vary
with
location
and
time.
The
nonlinear
nature
of
some
of
these
reactions
can
produce
differing
results
depending
on
the
relative
amount
of
reductions
and
copollutants.
Reductions
in
sulfates
can
increase
nitrates
and,
in
some
conditions,
modest
reductions
116
26NARSTO,
Particulate
Matter
Science
for
Policy
Makers
­
A
NARSTO
Assessment,
February
2003
27
"
Regulatory
Impact
Analysis
for
the
Final
Clean
Air
Interstate
Rule
(
March
2005)."
in
nitrates
can
increase
sulfates
although
through
different
mechanisms.
Large
regional
reductions
in
both
pollutants,

however,
are
more
likely
to
result
in
a
significant
reductions
in
fine
particles.
26
Based
on
its
current
understanding
of
regional
air
pollution
and
modeling
results,
EPA
believes
that
adopting
a
broad
new
program
of
regional
controls
to
continue
the
downward
trajectory
in
both
SOx
and
NOx
begun
in
base
programs
such
as
the
national
mobile
source
rules
and
Title
IV,
as
well
as
the
NOx
SIP
call,
will
ultimately
result
in
significant
benefits
not
only
in
reducing
PM2.5
nonattainment,
but
improving
public
health,
reducing
regional
haze,
and
addressing
multimedia
environmental
concerns
including
acid
deposition
and
nutrient
loadings
in
sensitive
coastal
estuaries
in
the
East.
27
Some
commenters
argued
that
the
benefits
combining
NOx
with
SO2
reductions,
if
any,
would
be
small,
and
further
argued
that
the
effect
of
any
nitrate
reductions
in
the
environment
would
be
further
diminished
by
measurement
losses
that
can
occur
in
the
filter
in
the
method
used
to
measure
PM2.5.
In
so
doing,
they
questioned
the
scientific
117
28
Blanchard,
C.
L.,
and
G.
M.
Hidy
(
2004)
Effects
of
projected
utility
SO2
and
NOx
emission
reductions
on
particulate
nitrate
and
PM2.5
mass
concentrations
in
the
Southeastern
United
States,
Report
to
Southern
Company.
See
CAIR
docket.
basis
for
nitrate
replacement,
suggesting
that
this
response
to
changes
in
SO2
emissions
may
not
happen
in
all
places
and
at
all
times.
The
commenters
referenced
a
study
in
the
Southeastern
U.
S.
by
Blanchard
and
Hidy28,
which
they
claim
calls
into
question
whether
nitrate
replacement
actually
occurs.
In
fact,
the
study
finds
evidence
that
nitrate
replacement
occurs:
"
the
sulfate
decreases
were
an
input
to
the
model
calculations,
but
their
effect
on
fine
PM
mass
was
modified
by
concomitant
decreases
in
ammonium
and
increases
in
nitrate."
A
second
study
by
the
same
authors,
using
essentially
the
same
dataset
and
methods,
and
referenced
both
by
EPA
in
the
NPR
and
by
the
commenters,
gives
very
strong
support
for
the
existence
of
nitrate
replacement,
as
well
as
for
coordinating
SO2
and
NOx
reductions,
as
indicated
by
the
following
conclusions:
"
reductions
in
sulfate
through
SO2
reduction
at
constant
NOx
levels
would
not
result
in
proportional
reduction
in
PM2.5
mass
because
particulate
nitrate
concentrations
would
increase.
However,

if
both
NOx
and
SO2
emissions
are
reduced,
then
it
may
be
possible
to
achieve
sulfate
reductions
without
concomitant
118
29Blanchard
C.
L.,
and
G.
M.
Hidy
(
2003).
Effects
of
changes
in
sulfate,
ammonia,
and
nitric
acid
on
pariculate
nitrate
concentrations
in
the
Southeeastern
United
States,
J.
Air
&
Waste
Manage.
Assoc.,
53:
283­
290
30NARSTO,
Particulate
Matter
Science
for
Policy
Makers
­
A
NARSTO
Assessment,
February
2003
nitrate
increases..."
29
Nitrate
replacement
is
well
documented
in
the
scientific
literature
as
a
possible
response
of
PM2.5
to
changes
in
SO2
emissions.
30
While
these
commenters
are
correct
that
nitrate
replacement
is
not
expected
to
occur
at
all
places
and
at
all
times,
even
where
average
conditions
are
not
favorable
for
nitrate
replacement,
hourly
variability
in
those
conditions
can
create
conditions
favorable
for
nitrate
replacement
at
particular
times.

Nitrate
replacement
theory
predicts
no
conditions
under
which
SO2
reductions
would
decrease
nitrate,
and
suggests
that
nitrate
may
increase
under
fairly
common
conditions.
31
Consequently,
the
net
effect
of
SO2
reductions
can
be
only
to
increase
nitrate
or
not
to
have
any
effect.
The
variability
of
conditions
occurring
over
a
year
means
that
SO2
reductions
would
be
expected
to
increase
nitrate
on
balance.

Even
if
the
studies
referenced
by
these
commenters
showed
that
nitrate
replacement
does
not
occur
in
some
119
32
For
example,
West,
J.
J.,
A.
S.
Ansari,
and
S.
N.
Pandis
(
1999)
Marginal
PM2.5,
nonlinear
aerosol
mass
response
to
sulfate
reductions
in
the
Eastern
U.
S.,
J.
Air
&
Waste
Manage.
Assoc.,
49:
1415­
1424.
circumstances,
other
studies
suggest
that
the
conditions
for
nitrate
replacement
are
common
in
the
Eastern
U.
S.
32
Suggesting
that
nitrate
replacement
does
not
occur
under
some
conditions
does
not
imply
that
NOx
should
not
be
controlled,
when
it
is
known
that
nitrate
replacement
occurs
under
other
common
conditions.

EPA
recognizes
that
the
relative
reductions
in
PM2.5
from
implementation
of
the
CAIR
will
be
greater
for
SO2
than
for
NOx.
Nevertheless,
overall
costs
for
reducing
NOx
in
the
CAIR
region
are
much
lower
than
SO2
because
a
large
portion
of
the
region
has
already
installed
NOx
controls
for
ozone
in
the
summer
months.
Our
revised
modeling
approaches
took
into
account
the
differences
commenters
note
between
actual
nitrate
concentrations
in
the
atmosphere
and
what
is
measured
as
PM2.5.
Nevertheless
emissions
of
both
pollutants
clearly
contribute
to
interstate
transport
of
ambient
fine
particles,
and
EPA
concludes
that
the
best
approach
in
this
situation
is
to
provide
highly
cost
effective
reductions
for
both
pollutants.
Moreover,
in
warmer
conditions
when
apparent
nitrate
changes
from
NOx
reductions
as
measured
on
PM2.5
monitors
are
small,
the
120
actual
reductions
in
particulate
and
gaseous
nitrates
in
the
ambient
environment
are
larger;
accordingly,
NOx
reductions
combined
with
SO2
reductions
can
be
expected
to
reduce
health
risk,
visibility
impairment,
and
other
environmental
damages.

After
considering
the
public
comments,
EPA
concludes
that
it
should
adopt
the
approach
it
proposed
for
addressing
interstate
transport
of
pollutants
that
affect
PM2.5,
for
the
reasons
presented
here
and
in
the
proposal.
That
is,
in
today's
action,
EPA
is
requiring
states
to
take
steps
to
control
emissions
of
SO2
and
NOx
on
the
basis
of
their
contributions
to
nonattainment
of
PM2.5
standards
in
downwind
states.
EPA
concludes
that
we
do
not
now
have
a
sufficient
basis
for
including
emissions
of
other
components
(
carbonaceous
material,
ammonia,
and
crustal
material)
that
contribute
to
PM2.5
in
determining
significant
contributions
and
in
requiring
emission
reductions
of
these
components.
121
122
123
124
125
126
33Ozone
Transport
Assessment
Group,
OTAG
Final
Report,
1997.

34NARSTO,
An
Assessment
of
Tropospheric
Ozone
Pollution
 
A
North
American
Perspective,
July
2000.

35National
Research
Council,
Rethinking
the
Ozone
Problem
in
Urban
and
Regional
Air
Pollution,
1991.

36NARSTO,
An
Assessment
of
Tropospheric
Ozone
Pollution
 
A
North
American
Perspective,
July
2000.
127
37U.
S.
EPA,
Latest
Findings
on
National
Air
Quality,
August
2003.
In
the
notice
of
proposed
rulemaking,
EPA
noted
that
we
continue
to
rely
on
the
assessment
of
ozone
transport
made
in
great
depth
by
the
OTAG
in
the
mid­
1990s.
As
indicated
in
the
NOx
SIP
call
proposal,
the
OTAG
Regional
and
Urban
Scale
Modeling
and
Air
Quality
Analysis
Work
Groups
reached
the
following
conclusions:

Q.
Regional
NOx
emissions
reductions
are
effective
in
producing
ozone
benefits;
the
more
NOx
reduced,
the
128
38
include
VOC
emissions
in
this
rule.
greater
the
benefit.

R.
Controls
for
VOC
are
effective
in
reducing
ozone
locally
and
are
most
advantageous
to
urban
nonattainment
areas.
(
62
FR
60320,
November
7,
1997).

EPA
proposed
to
reaffirm
this
conclusion
in
this
rulemaking,
and
proposed
to
address
only
NOx
emissions
for
the
purpose
of
reducing
interstate
ozone
transport.

Some
commenters
suggested
that
in
this
rulemaking
EPA
should
require
regional
reductions
in
VOC
emissions
as
well
as
NOx
emissions
in
this
rulemaking.
38
129
EPA
expects
that
States
will
need
to
examine
the
extent
to
which
VOC
emissions
affect
ozone
pollution
levels
across
state
lines,

and
identify
areas
where
multi­
state
VOC
strategies
might
assist
in
meeting
the
8­
hour
standard,
in
planning
for
attainment.

b.
How
Did
EPA
Determine
That
Reductions
in
Interstate
Transport,
as
Well
as
Reductions
in
Local
Emissions,
Are
Warranted
to
Help
Ozone
Nonattainment
Areas
to
Meet
the
8­

hour
Ozone
Standard?

1.
What
Did
EPA
Say
in
its
Proposal
Notice?

In
the
NPR,
EPA
noted
that
the
Agency
promulgated
the
NOx
SIP
call
in
1998
to
address
interstate
ozone
transport
problems
in
the
Eastern
U.
S.
EPA
noted
that
it
made
sense
to
re­
evaluate
whether
the
NOx
SIP
call
was
adequate
at
the
same
time
that
the
Agency
was
assessing
the
need
for
emissions
reductions
to
address
interstate
PM2.5
problems
because
of
overlap
in
the
pollutants
and
relevant
sources,

and
the
timetables
for
States
to
submit
local
attainment
plans.
EPA
presented
a
new
analysis
of
the
extent
of
130
residual
8­
hour
ozone
attainment
projected
to
remain
in
2010,
and
the
extent
and
severity
of
interstate
pollution
transport
contributing
to
downwind
nonattainment
in
that
year.

The
proposal
notice
said
that
based
on
a
multi­
part
assessment,
EPA
had
concluded
that:

°
"
Without
adoption
of
additional
emissions
controls,
a
substantial
number
of
urban
areas
in
the
central
and
eastern
regions
of
the
U.
S.
will
continue
to
have
levels
of
8­
hour
ozone
that
do
not
meet
the
national
air
quality
standards.

°
...
EPA
has
concluded
that
small
contributions
of
pollution
transport
to
downwind
nonattainment
areas
should
be
considered
significant
from
an
air
quality
standpoint,
because
these
contributions
could
prevent
or
delay
downwind
areas
from
achieving
the
standards.

°
...
EPA
has
concluded
that
interstate
transport
is
a
major
contributor
to
the
projected
(
8­
hour
ozone)

nonattainment
problem
in
the
eastern
U.
S.
in
2010.
...

(
T)
he
nonattainment
areas
analyzed
receive
a
transport
contribution
of
more
than
20
percent
of
the
ambient
ozone
concentrations,
and
21
of
47
had
a
transport
contribution
of
more
than
50
percent.

°
Typically,
two
or
more
States
contribute
transported
131
pollution
to
a
single
downwind
area,
so
that
the
"
collective
contribution"
is
much
larger
than
the
contribution
of
any
single
State.

EPA
also
concluded
that
highly
cost
effective
reductions
in
NOx
emissions
were
available
within
the
eastern
region
where
it
determined
interstate
transport
was
occurring,
and
that
requiring
those
highly
cost
effective
reductions
would
reduce
ozone
in
downwind
nonattainment
areas.

In
addition,
the
proposal
examined
the
effect
of
hypothetical
across­
the­
board
emissions
reductions
in
nonattainment
areas.
The
notice
stated
that
EPA
had
conducted
a
preliminary
scoping
analysis
in
which
hypothetical
total
NOx
and
VOC
emissions
reductions
of
25
percent
were
applied
in
all
projected
nonattainment
areas
east
of
the
continental
divide
in
2010,
yet
approximately
8
areas
were
projected
to
have
ozone
levels
exceeding
the
8­

hour
standard.
Based
on
experience
with
state
plans
for
meeting
the
one­
hour
ozone
standard,
EPA
said
this
scenario
was
an
indication
that
attaining
the
8­
hour
standard
will
entail
substantial
cost
in
a
number
of
nonattainment
areas,

and
that
further
regional
reductions
are
warranted.

2.
What
Did
Commenters
Say?

a.
The
Need
for
Reductions
in
Interstate
Ozone
Transport
132
Some
commenters
argued
that
EPA
should
not
conduct
another
rulemaking
to
control
interstate
contributions
to
ozone
because
local
contributions
in
nonattainment
regions
appear,
according
to
the
commenters,
to
have
larger
impacts
than
regional
NOx
emissions.
The
commenters
cited
EPA's
sensitivity
modeling
of
hypothetical
25
percent
reductions
as
supporting
this
view.

EPA
disagrees
that
comparing
the
sensitivity
modeling
and
the
CAIR
control
modeling
is
a
valid
way
to
compare
the
effectiveness
of
local
and
regional
controls.
The
two
scenarios
do
not
reduce
emissions
by
equal
tonnage
amounts,

equal
percentages
of
the
inventory,
or
equal
cost.
These
scenarios
therefore
do
not
support
an
assessment
of
the
relative
effectiveness
of
local
and
regional
controls.

While
EPA
in
general
agrees
that
emissions
reductions
in
a
nonattainment
area
will
have
a
greater
effect
on
ozone
levels
in
that
area
than
similar
reductions
a
long
distance
away,
EPA
does
not
agree
that
the
modeling
supports
the
conclusion
that
all
additional
controls
to
promote
attainment
with
the
8­
hour
standard
should
be
local.
The
level
of
reduction
assumed
was
a
hypothetical
level,
not
a
level
determined
to
be
reasonable
cost
nor
a
mandated
level
of
reduction.
The
commenters
provided
no
evidence
that
reasonable
local
controls
alone
would
result
in
attainment
133
throughout
the
East.
However,
EPA
did
receive
comments
that
such
a
level
would
result
in
costly
controls
and
might
not
be
feasible
in
some
areas
that
have
previously
imposed
substantial
controls.

EPA
believes
it
is
clear
that
further
reductions
in
emissions
contributing
to
interstate
ozone
transport,
beyond
those
required
by
the
NOx
SIP
call,
are
warranted
to
promote
attainment
of
the
8­
hour
ozone
standard
in
the
eastern
U.
S.

As
explained
elsewhere
in
this
notice,
EPA
analyzed
interstate
transport
remaining
after
the
NOx
SIP
call,
and
determined
 
considering
both
the
impact
of
interstate
transport
on
downwind
nonattainment,
and
the
potential
for
highly
cost
effective
reductions
in
upwind
States
 
that
25
States
significantly
contribute
to
8­
hour
ozone
nonattainment
downwind.
The
importance
of
transport
is
illustrated,
as
mentioned
above,
by
EPA's
findings
for
the
final
rule
that
(
1)
all
the
2010
nonattainment
counties
analyzed
were
projected
to
receive
a
transport
contribution
of
24
percent
or
more
of
the
ambient
ozone
concentrations,

and
(
2)
that
16
of
38
counties
are
projected
to
have
a
transport
contribution
of
more
than
50
percent.

In
addition,
EPA
received
multiple
comments
from
state
associations
and
individual
states
strongly
agreeing
that
further
reductions
in
interstate
ozone
transport
are
134
warranted
to
promote
attainment
with
the
8­
hour
standard,
to
protect
public
health,
and
to
address
equity
concerns
of
downwind
states
affected
by
transport.
For
example,

comments
from
the
Maryland
Department
of
the
Environment
stated,
"
Our
15
year
partnership
with
researchers
from
the
University
of
Maryland
has
produced
data
that
shows
on
many
summer
days
the
ozone
levels
floating
into
Maryland
area
are
already
at
80
to
90
percent
of
the
1­
hour
ozone
standard
and
actually
exceed
the
new
8­
hour
ozone
standard
before
any
Maryland
emissions
are
added.
...
Serious
help
is
needed
from
EPA
and
neighboring
states
to
solve
Maryland's
air
pollution
problems.
...
Local
reductions
alone
will
not
clean
up
Maryland's
air."
The
comments
of
the
Ozone
Transport
Commission
stated
that
even
after
levels
of
control
envisioned
by
EPA
in
2010
(
under
the
Clear
Skies
Act),
interstate
transport
from
other
states
would
continue
to
affect
the
Ozone
Transport
Region
created
by
the
Clean
Air
Act
(
Connecticut,
Delaware,
the
District
of
Columbia,

Maine,
Maryland,
Massachusetts,
New
Hampshire,
New
Jersey,

New
York,
Pennsylvania,
Rhode
Island,
Vermont,
and
Virginia).
"
Our
modeling
demonstrates
that
even
in
the
extreme
example
of
zero
anthropogenic
emissions
within
the
OTR
(
Ozone
Transport
Region),
145
of
146
monitors
show
a
significant
(>
25%)
increment
of
the
8­
hour
standard
taken
up
135
by
transport
from
outside
the
OTR."
Comments
from
the
North
Carolina
Department
of
Environment
and
Natural
Resources
stated,
"
The
reductions
proposed
in
[
EPA's
rule]
in
the
other
states
are
needed
to
ensure
that
North
Carolina
can
attain
and
maintain
the
health­
based
air
quality
standards
for
...
8­
hour
ozone."

b.
Magnitude
of
Ozone
Reductions
Achieved
Commenters
stated
that
NOx
reductions
should
not
be
pursued
because
the
8­
hour
ozone
reductions
in
projected
nonattainment
counties
resulting
from
the
required
NOx
reductions
are
too
small
 
1­
2
ppb
in
only
certain
areas.

According
to
commenters,
these
benefits
are
smaller
than
the
threshold
for
determining
significant
contribution.

EPA
disagrees
with
the
notion
that
if
air
quality
improvements
would
be
limited,
then
nothing
further
should
be
done
to
address
interstate
transport.
Based
on
the
difference
between
the
base
case
and
CAIR
control
case
modeling
results,
EPA
has
concluded
that
interstate
air
quality
impacts
are
significant
from
an
air
quality
standpoint,
and
that
highly
cost
effective
reductions
are
available
to
reduce
ozone
transport.
State
comments
have
corroborated
EPA's
conclusion
that
a
number
of
areas
will
face
high
local
control
costs,
or
even
be
unable
to
attain
the
8­
hour
ozone
standard,
without
further
reductions
in
136
interstate
transport.
Therefore,
EPA
believes
it
is
important
for
upwind
states
to
modify
their
SIPs
so
that
they
contain
adequate
provisions
to
prohibit
significant
contributions
to
downwind
nonattainment
or
interference
with
maintenance
as
the
statute
requires.
EPA
has
established
an
amount
of
required
emissions
reductions
based
on
controls
that
are
highly
cost
effective.
The
resulting
improvements
in
downwind
ozone
levels
are
needed
for
attainment,
public
health
and
equity
reasons.

The
2
ppb
significance
threshold
that
commenters
cite
is
part
of
the
test
that
EPA
used
to
identify
which
States
should
be
evaluated
for
inclusion
in
a
rule
requiring
them
to
reduce
emissions
to
reduce
interstate
transport.
(
See
section
VI.)
This
2
ppb
threshold
is
based
on
the
impact
on
a
downwind
area
of
eliminating
all
emissions
in
an
upwind
State.
The
ozone
reductions
from
CAIR
will
improve
public
health
and
will
decrease
the
extent
and
cost
of
local
controls
needed
for
attainment
in
some
areas.
In
addition,

base
case
modeling
for
this
rule
shows
that
of
the
40
counties
projected
in
nonattainment
in
2010,
16
counties
are
within
2
ppb
of
the
standard,
6
counties
are
within
3
ppb,

and
3
counties
are
within
4
ppb.
In
2015,
projected
base
case
ozone
concentrations
in
over
70
percent
of
nonattaining
counties
(
i.
e.,
16
of
22
counties)
are
within
5
ppb
of
the
137
standard.

Reducing
NOx
emissions
has
multiple
health
and
environmental
benefits.
Controlling
NOx
reduces
interstate
transport
of
fine
particle
levels
as
well
as
ozone
levels,

as
discussed
elsewhere
in
this
notice.
Although
EPA
is
not
relying
on
other
benefits
for
purposes
for
setting
requirements
in
this
rule,
reducing
NOx
emissions
also
helps
to
reduce
unhealthy
ozone
and
PM
levels
within
a
State,
as
well
as
reduce
acid
deposition
to
soils
and
surface
waters,

eutrophication
of
surface
and
coastal
waters,
visibility
degradation,
and
impacts
on
terrestrial
and
wetland
systems
such
as
changes
in
species
composition
and
diversity.

c.
Why
Is
EPA
Addressing
Ozone
Transport
in
this
Rule,

Given
That
EPA
Already
Issued
the
NOx
SIP
Call?

1.
EPA's
Legal
Authority
to
Require
Controls
Beyond
the
NOx
SIP
Call
Commenters
emphasized
that
in
the
NOx
SIP
call,
EPA
determined
the
States
whose
emissions
contribute
significantly
to
nonattainment,
EPA
mandated
NOx
emissions
reductions
that
would
eliminate
those
significant
contributions,
and
EPA
indicated
that
it
would
reconsider
the
matter
in
2007.
This
commenter
argued
that
for
the
States
included
in
the
NOx
SIP
call,
EPA
may
not,
as
a
legal
matter,
conduct
further
rulemaking
at
this
time
because
the
138
affected
States
are
no
longer
contributing
significantly
to
nonattainment
downwind.
In
any
event,
the
commenters
said,

EPA
should
abide
by
its
statement
that
it
would
revisit
the
matter
in
2007,
and
EPA
should
not
do
so
earlier.
139
140
2.
Authority
to
Revisit
NOx
SIP
Call
Requirements
Commenters
added
that
the
purpose
of
the
CAIR
rulemaking
seemed
to
be
to
account
for
the
fact
that
control
costs
have
changed
since
the
date
of
the
NOx
SIP
Call.
The
commenters
said
that
control
costs
will
frequently
fluctuate,
but
that
such
fluctuations
should
not
merit
revised
rulemaking.

In
response,
we
would
note
that
EPA
conducted
an
updated
analysis
for
air
quality
impacts,
not
only
costs,
in
determining
that
further
reductions
in
interstate
ozone
transport
are
warranted.
That
air
quality
analysis
showed
a
substantial,
continuing
interstate
transport
problem
for
areas
after
implementation
of
the
NOx
SIP
call.
EPA
does
have
the
legal
authority
to
reconsider
the
scope
of
the
area
that
significantly
contributes
and
the
level
of
control
determined
to
be
"
highly
cost­
effective"
based
on
new
information.
Updated
information
shows
that
lower
NOx
burners
and
SCR
achieve
better
performance
than
previously
141
estimated
and
as
a
result
are
more
cost
effective
than
previously
anticipated.
This
rule
follows
the
NOx
SIP
Call
by
six
years;
EPA
does
not
believe
that
this
represents
a
too­
frequent
re­
evaluation,
particularly
given
the
stay
of
the
8­
hour
basis
for
the
NOx
SIP
call
(
See,
e,
g,
CAA
section
109
(
d)(
1)
requiring
EPA
to
reevaluate
the
NAAQS
themselves
every
five
years.)
So
both
updated
air
quality
and
cost
information
supports
further
NOx
controls
to
reduce
interstate
transport.

Some
commenters
argued
that
EPA
should
delay
imposing
control
obligations
on
upwind
States
for
the
8­
hour
ozone
NAAQS
until
after
EPA
has
implemented
local
control
requirements,
and
after
all
of
the
NOx
SIP
Call
control
requirements
are
implemented
and
evaluated.
Others
said
EPA
should
not
impose
requirements
on
non­
SIP­
call
States
until
after
all
8­
hour
controls
 
NOx
SIP
Call
and
local
 
are
implemented.

We
agree
that
the
NOx
SIP
call
should
be
taken
into
account
in
evaluating
the
need
for
further
interstate
transport
controls.
We
have
taken
the
NOx
SIP
call
into
account
by
including
the
effect
of
the
NOx
SIP
call
in
the
base
case
used
for
the
CAIR
analysis,
and
by
conducting
analyses
to
confirm
that
CAIR
will
achieve
greater
ozoneseason
reductions
than
the
SIP
call.
EPA
disagrees
that
the
142
Agency
should
wait
for
implementation
of
local
controls
before
determining
transport
controls.
There
is
no
legal
requirement
that
EPA
wait
to
determine
transport
controls
until
after
local
controls
are
implemented.
EPA's
basis
for
this
legal
interpretation
is
explained
in
section
II.
A.

above.
In
addition,
the
Agency
believes
it
is
important
to
address
interstate
transport
expeditiously
for
public
health.

C.
Comments
on
Excluding
Future
Case
Measures
from
the
Emissions
Baselines
Used
to
Estimate
Downwind
Ambient
Contribution
The
EPA
received
comments
that
the
2010
analytical
baseline
for
evaluating
whether
upwind
emissions
meet
the
air
quality
portion
of
the
"
contribute
significantly"

standard
should
reflect
local
control
measures
that
will
be
required
in
the
downwind
nonattainment
areas,
or
broader
statewide
measures
in
downwind
states,
to
attain
the
PM2.5
or
8­
hour
ozone
NAAQS
by
the
relevant
attainment
dates,
many
of
which
are
(
or
are
anticipated
to
be)
2010
or
earlier.

This
single
target
year
was
chosen
both
to
address
analytical
tool
constraints
and
to
reasonably
reflect
future
conditions
in
or
near
the
initial
attainment
years
for
both
ozone
and
PM
nonattainment
areas.
The
EPA
did
include
in
the
baseline
most
of
the
specifically
required
measures
that
143
can
be
identified
at
this
time,
but
did
not
include
any
further
measures
that
would
be
needed
for
satisfying
"
rate
of
progress"
requirements
or
for
attainment
of
the
PM2.5
and
8­
hour
ozone
standards.
If
EPA
had
included
further
local
controls,
the
commenters
contend,
fewer
upwind
States
would
have
exceeded
our
significant
contribution
thresholds.

We
reject
any
notion
that
in
determining
the
need
for
transport
controls
in
upwind
states,
EPA
should
assume
that
the
affected
downwind
areas
must
"
go
all
the
way
first"
 
that
is,
assume
that
downwind
areas
put
on
local
in­
state
controls
sufficient
to
reach
attainment,
or
assume
that
downwind
states
with
nonattainment
areas
implement
statewide
control
measures.
EPA
does
not
believe
these
are
appropriate
assumptions.
The
former
assumption
would
eviscerate
the
meaning
of
CAA
section
110(
a)(
2)(
D).
The
latter
assumption
would
make
the
downwind
state
solely
responsible
for
reductions
in
any
case
where
a
downwind
state
could
attain
through
in­
state
controls
alone,
even
if
the
upwind
state
contribution
was
significantly
contributing
to
nonattainment
problems
in
the
downwind
state.
We
do
not
believe
that
this
approach
would
be
consistent
with
the
intent
of
section
110(
a)(
2)(
D),
which
in
part
is
to
hold
upwind
states
responsible
for
an
appropriate
share
of
downwind
nonattainment
and
maintenance
problems,
and
to
144
prevent
scenarios
in
which
downwind
states
must
impose
costly
extra
controls
to
compensate
for
significant
pollution
contributions
from
uncontrolled
or
poorly
controlled
sources
in
upwind
states.
In
addition,
this
approach
could
raise
costs
of
meeting
air
quality
standards
because
highly
cost
effective
controls
in
upwind
states
would
be
foregone.

Rather,
in
the
particular
circumstances
presented
here,

we
think
the
adoption
of
regional
controls
at
this
time
under
section
110(
a)(
2)(
D)
is
consistent
with
sound
policy
and
section
110.
Based
on
our
analysis,
the
states
covered
by
CAIR
make
a
significant
contribution
to
downwind
nonattainment
and
the
required
reductions
are
highly
cost
effective.
The
reductions
will
reduce
regional
pollution
problems
affecting
multiple
downwind
areas,
will
make
it
possible
for
states
to
determine
the
extent
of
local
control
needed
knowing
the
reductions
in
interstate
pollution
that
are
required,
will
address
interstate
equity
issues
that
can
hamper
control
efforts
in
downwind
states,
and
reflect
considerations
discussed
in
detail
in
section
VII.

Although
some
commenters
advocated
specifically
including
statutorily
mandated
future
nonattainment
area
controls
in
the
analytical
baseline,
it
would
be
difficult
as
a
practical
matter
to
predict
the
extent
of
local
145
controls
that
will
be
required
(
beyond
controls
previously
required)
in
each
area
in
advance
of
final
implementation
rules
interpreting
the
Act's
requirements
for
PM2.5
and
8­

hour
ozone,
and
before
the
state
implementation
plan
process.
Subpart
2
provisions
that
apply
to
certain
ozone
nonattainment
areas
are
quite
specific
regarding
some
mandatory
measures;
we
believe
the
CAIR
baseline
for
the
most
part
captures
these
measures.
(
See
Response
to
Comments.)

As
noted
above,
the
choice
of
a
single
analytical
year
of
2010
was
made
to
reflect
baseline
conditions
at
a
date
at
or
near
the
attainment
dates
for
different
pollutants
and
classes
of
areas.
Because
the
attainment
date
for
many
ozone
areas
is
2009
or
earlier,
it
should
be
noted
that
the
analyses
in
2010
may
slightly
overestimate
the
benefits
of
a
number
of
national
rules
for
mobile
sources
that
grow
with
time.
As
noted
elsewhere,
these
differences
are
unlikely
to
be
significant.

D.
What
Criteria
Should
Be
Used
to
Determine
Which
States
are
Subject
to
this
Rule
Because
They
Contribute
to
PM2.5
Nonattainment?

1.
What
is
the
Appropriate
Metric
for
Assessing
Downwind
PM2.5
Contribution?

a.
Notice
of
Proposed
Rulemaking
146
In
the
NPR,
we
proposed
as
the
metric
for
identifying
a
State
as
significantly
contributing
(
depending
upon
further
consideration
of
costs)
to
downwind
nonattainment,
the
predicted
change,
due
to
the
upwind
State's
emissions,
in
PM2.5
concentration
in
the
downwind
nonattainment
area
that
receives
the
largest
ambient
impact.
EPA
proposed
this
metric
in
the
form
of
a
range
of
alternatives
for
a
"
bright
line,"
that
is,
ambient
impacts
at
or
greater
than
the
chosen
threshold
level
indicated
that
the
upwind
State's
emissions
do
contribute
significantly
(
depending
on
cost
considerations),
and
that
ambient
impacts
below
the
threshold
mean
that
the
upwind
State's
emissions
do
not
contribute
significantly
to
nonattainment.
As
detailed
in
section
VI
below,
EPA
conducted
the
analysis
through
air
quality
modeling
that
removed
the
upwind
State's
anthropogenic
SO2
and
NOx
emissions,
and
determined
the
difference
in
downwind
ambient
PM2.5
levels
before
and
after
removal.
The
modeling
results
indicate
a
wide
range
of
maximum
downwind
nonattainment
impacts
from
the
37
States
that
we
evaluated.
The
largest
maximum
contribution
is
1.67
micrograms
per
cubic
meter
(

g/
m3),
from
Ohio
to
both
Allegheny
and
Beaver
counties
in
Pennsylvania.

b.
Comments
and
EPA's
Responses
The
EPA
proposed
to
use
the
maximum
contribution
on
any
147
downwind
nonattainment
area
for
assessing
downwind
PM2.5
contributions.
Many
commenters
expressed
agreement
with
our
proposed
metric,
however,
many
others
disagreed.
One
group
of
these
commenters
indicated
that
EPA
should
distinguish
the
relative
contribution
from
States
using
two
parameters:

(
1)
how
many
downwind
nonattainment
receptors
they
contribute
to,
and
(
2)
how
much
they
contribute
to
each
such
receptor.
The
commenters
indicated
that
this
approach
would
avoid
inequities
created
by
the
disproportionate
impact
of
some
upwind
contributors
on
their
downwind
neighbors.
EPA
interprets
these
comments
to
suggest
a
metric
that
collectively
includes
both
of
these
parameters,
such
as
the
sum
of
all
downwind
impacts
on
all
affected
receptors.
This
metric
would
result
in
higher
values
for
States
contributing
to
multiple
receptors
and
at
relatively
high
levels,
and
lower
values
for
States
contributing
to
fewer
receptors
and
at
relatively
low
levels.

The
EPA's
proposed
metric
does
address
how
much
each
State
contributes
to
a
downwind
neighbor;
however,
EPA
does
not
believe
that
multiple
downwind
receptors
need
to
be
impacted
in
order
for
a
particular
state
to
be
required
to
make
emissions
reductions
under
CAA
section
110(
a)(
2)(
D).

Under
this
provision,
an
upwind
State
must
include
in
the
SIP
adequate
provisions
that
prohibit
that
State's
emissions
148
that
"
contribute
significantly
to
nonattainment
in
...
any
other
State...."
(
Emphasis
added.)
Our
interpretation
of
this
provision
is
that
the
emphasized
terms
make
clear
that
the
upwind
State's
emissions
must
be
controlled
as
long
as
they
contribute
significantly
to
a
single
nonattainment
area.

One
commenter
agreed
with
EPA's
use
of
maximum
annual
average
downwind
contribution,
but
suggested
that
EPA
consider
additional
metrics
such
as:
(
a)
contributions
to
adverse
health
and
welfare
effects
from
short­
term
PM2.5
concentrations;
(
b)
contributions
to
worst
20
percent
haze
levels
in
Class
1
areas;
and
(
c)
contributions
to
adverse
effects
of
sulfur
and
nitrogen
deposition
to
acid
sensitive
surface
waters
and
forest
soils.
The
EPA
appreciates
that
these
metrics
all
have
merit
in
their
focus
on
the
health
and
environmental
consequences
of
emissions,
however,
in
determining
a
metric
for
significant
contributions,
we
must
focus
on
implementation
of
CAA
section
110(
a)(
2)(
D)

provisions
regarding
significant
contribution
to
nonattainment
of
the
PM2.5
NAAQS.

Another
commenter
suggested
EPA
use
the
maximum
annual
average
impact,
as
we
proposed,
but
add
the
maximum
daily
PM2.5
contribution.
The
commenter
notes
that
this
additional
metric
would
indicate
whether
specific
149
meteorological
events
drive
the
concentration
change
or
whether
there
is
a
consistent
pattern
of
transport
from
one
area
to
another.
It
is
not
clear
to
EPA
how
the
single
data
point
of
the
maximum
daily
contribution
indicates
a
consistent
pattern
of
transport
from
one
area
to
another
since
it
is
a
measure
from
only
a
single
day.
Further,
EPA
does
not
agree
that
multiple
days
of
impact
is
a
relevant
criterion
for
evaluating
whether
a
State
contributes
significantly
to
nonattainment,
since
in
theory,
a
single
high­
contribution
event
could
be
the
cause
or
a
substantial
element
of
nonattainment
of
the
annual
average
PM2.5
standard.
Because
we
currently
do
not
observe
nonattainment
of
the
daily
average
PM2.5
standard
in
Eastern
areas,

nonattainment
of
the
annual
average
PM2.5
standard
is
the
relevant
evaluative
measure.

Some
commenters
suggested
separately
evaluating
the
NOx­
and
SO2­
related
impacts
(
i.
e.,
particulate
nitrate
and
particulate
sulfate)
on
nonattainment.
As
discussed
in
section
II
of
this
notice,
EPA's
approach
to
evaluating
a
State's
impact
on
downwind
nonattainment
by
considering
the
entirety
of
the
State's
SO2
and
NOx
emissions
is
consistent
with
the
chemical
interactions
in
the
atmosphere
of
SO2
and
NOx
in
forming
PM2.5.
The
contributions
of
SO2
and
NOx
emissions
are
generally
not
additive,
but
rather
are
150
interrelated
due
to
complex
chemical
reactions.

c.
Today's
Action
The
EPA
continues
to
believe
that
for
each
upwind
State
analyzed,
the
change
in
the
annual
PM2.5
concentration
level
in
the
downwind
nonattainment
area
that
receives
the
largest
impact
is
a
reasonable
metric
for
determining
whether
a
State
passes
the
"
air
quality"
portion
of
the
"
contribute
significantly"
test,
and
therefore
that
State
should
be
considered
further
for
emissions
reductions
(
depending
upon
the
cost
of
achieving
those
reductions).
This
single
concentration­
based
metric
is
adequate
to
capture
the
impact
of
SO2
and
NOx
emissions
on
downwind
annual
PM2.5
concentrations.

2.
What
is
the
Level
of
the
PM2.5
Contribution
Threshold?

a.
Notice
of
Proposed
Rulemaking
In
the
NPR,
the
EPA
proposed
to
establish
a
State­
level
annual
average
PM2.5
contribution
threshold
from
anthropogenic
SO2
and
NOx
emissions
that
was
a
small
percentage
of
the
annual
air
quality
standard
of
15.0

g/
m3.

The
EPA
based
this
proposal
on
the
general
concept
that
an
upwind
State's
contribution
of
a
relatively
low
level
of
ambient
impact
should
be
regarded
as
significant
(
depending
on
the
further
assessment
of
the
control
costs).
We
based
our
reasoning
on
several
factors.
EPA's
modeling
indicates
151
that
at
least
some
nonattainment
areas
will
find
it
difficult
or
impossible
to
attain
the
standards
without
reductions
in
upwind
emissions.
In
addition,
our
analysis
of
"
base
case"
PM2.5
transport
shows
that,
in
general,
PM2.5
nonattainment
problems
result
from
the
combined
impact
of
relatively
small
contributions
from
many
upwind
States,

along
with
contributions
from
in­
State
sources
and,
in
some
cases,
substantially
larger
contributions
from
a
subset
of
particular
upwind
States.
In
the
NOx
SIP
Call
rulemaking,

we
termed
this
pattern
of
contribution
 
which
is
also
present
for
ozone
nonattainment
 
"
collective
contribution."

In
the
case
of
PM2.5,
we
have
found
collective
contribution
to
be
a
pronounced
feature
of
the
PM2.5
transport
problem,
in
part
because
the
annual
nature
of
the
PM2.5
NAAQS
means
that
throughout
the
entire
year
and
across
a
range
of
wind
patterns
 
rather
than
during
just
one
season
of
the
year
or
on
only
the
few
worst
days
during
the
year
which
may
share
a
prevailing
wind
direction
 
emissions
from
many
upwind
States
affect
the
downwind
nonattainment
area.

As
a
result,
to
address
the
transport
affecting
a
given
nonattainment
area,
many
upwind
States
must
reduce
their
emissions,
even
though
their
individual
contributions
may
be
relatively
small.
Moreover,
as
noted
above,
the
EPA's
air
152
quality
modeling
indicates
that
at
least
some
nonattainment
areas
will
find
it
difficult
or
impossible
to
attain
the
standards
without
reductions
in
upwind
emissions.
In
combination,
these
factors
suggest
a
relatively
low
value
for
the
PM2.5
transport
contribution
threshold
is
appropriate.
For
reasons
specified
in
the
NPR
(
69
FR
4584),
EPA
initially
proposed
a
value
of
0.15
ug/
m3
(
1%
of
the
annual
standard)
for
the
significance
criterion,
but
also
presented
analyses
based
on
an
alternative
of
0.10
ug/
m3
and
called
for
comment
on
this
alternative
as
well
as
on
"
the
use
of
higher
or
lower
thresholds
for
this
purpose"

(
69
FR
4584).

The
EPA
adopted
a
conceptually
similar
approach
to
that
outlined
above
for
determining
that
the
significance
level
for
ozone
transport
in
the
NOx
SIP
Call
rulemaking
should
be
a
small
number
relative
to
the
NAAQS.
The
D.
C.
Circuit
Court,
in
generally
upholding
the
NOx
SIP
Call,
viewed
this
approach
as
reasonable.
Michigan
v.
EPA,
213
F.
3d
663,
674­

80
(
D.
C.
Cir.
2000),
cert.
denied,
532
U.
S.
904
(
2001).

After
describing
EPA's
overall
approach
of
establishing
a
significance
level
and
requiring
States
with
impacts
above
the
threshold
to
implement
highly
cost­
effective
reductions,

the
Court
explained:
"
EPA's
design
was
to
have
a
lot
of
States
make
what
it
considered
modest
NOx
reductions...."
153
Id.
at
675.
Indeed,
the
Court
intimated
that
EPA
could
have
established
an
even
lower
threshold
for
States
to
pass
the
air
quality
component:

EPA
has
determined
that
ozone
has
some
adverse
health
effects
 
however
slight
 
at
every
level
[
citing
National
Ambient
Air
Quality
Standards
for
Ozone,
62
FR
38856
(
1997)].
Without
consideration
of
cost
it
is
hard
to
see
why
any
ozone­
creating
emissions
should
not
be
regarded
as
fatally
"
significant"
under
section
110(
a)(
2)(
D)(
i)(
I)."

213
F.
3d
at
678
(
emphasis
in
original).

We
believe
the
same
approach
applies
in
the
case
of
PM2.5
transport.

b.
Comments
and
EPA's
Responses
Many
commenters
indicated
that
EPA
did
not
adequately
justify
the
proposed
annual
average
PM2.5
contribution
threshold
level
of
0.15

g/
m3.
Some
commenters
favor
the
alternative
0.10

g/
m3
proposed
by
EPA,
citing
their
agreement
with
EPA's
rationale
for
0.10

g/
m3
while
criticizing
as
arbitrary
EPA's
rationale
for
0.15

g/
m3.

Some
commenters
argued
that
the
public
health
impact
portion
of
EPA's
rationale
for
establishing
a
relatively
low­
level
threshold
was
not
relevant.
The
commenters
said
154
that
EPA
previously
determined,
in
establishing
the
PM2.5
NAAQS,
that
ambient
levels
at
or
above
15.0

g/
m3
were
of
concern
for
protecting
public
health,
not
the
much
lower
levels
that
EPA
proposed
as
the
thresholds.
In
the
NPR,
we
stated
that
we
considered
that
there
are
significant
public
health
impacts
associated
with
ambient
PM2.5,
even
at
relatively
low
levels.
In
generally
upholding
the
NOx
SIP
Call,
the
D.
C.
Circuit
noted
a
similar
reason
for
establishing
a
relatively
low
threshold
for
ozone
impacts.

Michigan
v.
EPA,
213
F.
3d
663,
678
(
D.
C.
Cir.
2000),
cert.

denied,
532
U.
S.
904
(
2001).
EPA
notes
that
by
using
a
metric
that
focuses
on
the
contribution
of
upwind
areas
to
downwind
areas
that
are
above
15.0

g/
m3,
relatively
low
contributions
to
levels
above
the
annual
PM2.5
standard
are
highly
relevant
to
public
health
protection.

Many
commenters
offered
alternative
thresholds
higher
than
0.15

g/
m3,
citing
previous
EPA
rules
or
policies
as
justification
for
the
alternative
level.
Some
suggested
the
PM2.5
threshold
should
be
equivalent
in
percentage
terms
to
the
threshold
employed
for
assessing
maximum
downwind
8­
hour
ozone
contributions.
The
threshold
for
maximum
downwind
8­

hour
ozone
concentration
impact
used
in
the
NOx
SIP
Call,

and
proposed
for
use
in
the
CAIR,
is
2
parts
per
billion
(
ppb),
or
about
2.5
percent
of
the
standard
level
of
80
ppb.
155
Applying
the
2.5
percent
criterion
to
the
15.0

g/
m3
annual
PM2.5
standard
would
yield
a
significance
threshold
of
0.35

g/
m3.

EPA
disagrees
with
the
comment
that
the
thresholds
for
annual
PM2.5
and
8­
hour
ozone
should
be
an
equivalent
percentage
of
their
respective
NAAQS.
Both
the
forms
and
averaging
times
of
the
two
standards
are
substantially
different,
with
8­
hour
ozone
based
on
the
average
of
the
4th
highest
daily
8­
hour
maximum
values
from
each
of
3
years,

and
PM2.5
based
on
the
average
of
annual
means
from
3
successive
years.
These
fundamental
differences
in
time
scales,
and
thus
in
the
patterns
of
transport
that
are
relevant
to
contributing
to
nonattainment,
do
not
suggest
a
transparent
reason
for
presuming
that
the
contribution
thresholds
should
be
equivalent.
As
discussed
above,
when
more
States
make
smaller
individual
contributions
because
of
the
annual
nature
of
the
PM2.5
standard,
it
makes
sense
to
have
a
threshold
for
PM2.5
that
is
a
smaller
percentage
of
its
NAAQS.

Other
commenters
suggested
that
in
setting
the
maximum
downwind
PM2.5
threshold,
EPA
should
take
into
consideration
the
measurement
precision
of
existing
PM2.5
monitors.
The
commenters
assert
that
such
measurement
carries
"
noise"
in
the
range
of
0.5
­
0.6

g/
m3.
Because
many
daily
average
156
monitor
readings
are
averaged
to
calculate
the
annual
average,
the
precision
of
the
annual
average
concentration
is
better
than
the
figures
cited
by
the
commenters.
Indeed,

the
annual
standard
is
expressed
as
15.0

g/
m3,
rounded
to
the
nearest
1/
10th

g,
because
such
small
differences
are
meaningful
on
an
annual
basis.
While
disagreeing
with
the
specific
amounts
suggested
by
commenters,
EPA
recognizes
that
the
PM2.5
threshold
specified
in
the
proposal
contains
two
digits
beyond
the
decimal
place,
while
the
NAAQS
specifies
only
one.
EPA
agrees
that
specification
of
a
threshold
value
of
0.15
ug/
m3
does
suggest
an
overly
precise
test
that
might
need
to
take
into
account
modeled
difference
in
PM2.5
values
as
low
as
0.001
ug/
m3.

Other
commenters
indicated
that
modeling
"
noise"
 
that
is,
imprecision
 
is
a
relevant
consideration
for
establishing
a
threshold
whose
evaluation
depends
on
air
quality
modeling
analysis.
These
commenters
indicated
that
a
threshold
of
5
percent
of
the
NAAQS
(
i.
e.,
0.75

g/
m3)
is
more
reasonable
considering
modeling
sensitivity.
The
commenters
were
not
clear
about
what
they
mean
by
modeling
"
noise"
and
did
not
explain
how
it
relates
to
the
use
of
a
threshold
metric
in
the
context
of
the
CAIR.

In
responding
to
the
comment,
we
have
considered
some
possible
contributors
to
what
the
commenter
describes
as
157
"
noise."
There
is
the
possibility
that
the
air
quality
model
has
a
systematic
bias
in
predicting
concentrations
resulting
from
a
given
set
of
emissions
sources.
The
EPA
uses
the
model
outputs
in
a
relative,
rather
than
an
absolute,
sense
so
that
any
modeling
bias
is
constrained
by
real
world
results.
As
described
further
in
section
VI,
EPA
conducts
a
relative
comparison
of
the
results
of
a
base
case
and
a
control
case
to
estimate
the
percentage
change
in
ambient
PM2.5
from
the
current
year
base
case,
holding
meteorology,
other
source
emissions,
and
other
factors
contributing
to
uncertainty
constant.
With
this
technique,

any
absolute
modeling
bias
is
cancelled
out
because
the
same
model
limitations
and
uncertainties
are
present
in
each
set
of
runs.

Another
possible
source
of
noise
is
in
the
relative
comparison
of
two
model
runs
conducted
on
different
computers.
Since
the
computers
used
by
EPA
to
run
air
quality
models
do
not
have
any
significant
variability
in
their
numerical
processes,
two
model
runs
with
identical
inputs
result
in
outputs
that
are
identical
to
many
significant
digits.
On
the
other
hand,
EPA
believes
it
is
not
appropriate
or
necessary
to
carry
such
results
to
a
level
of
precision
that
is
beyond
that
required
by
the
PM2.5
158
39In
attainment
modeling
for
the
annual
PM2.5
NAAQS,
results
are
carried
to
the
second
place
beyond
the
decimal,
in
contrast
to
the
three
places
beyond
decimal
noted
above
for
the
proposed
threshold.

40See
40
CFR
51.165(
b)(
2).
New
or
modified
major
sources
in
attainment
or
unclassifiable
areas
must
undergo
preconstruction
permit
review,
adopt
best
available
control
technology,
and
obtain
emissions
offsets
if
they
are
determined
to
"
cause
or
contribute"
to
a
violation
of
the
NAAQS.
"
Cause
or
contribute"
is
defined
as
an
impact
that
exceeds
5

g/
m3
(
3.3
percent)
of
the
150

g/
m3
24­
hour
average
PM10
NAAQS
,
or
1

g/
m3
(
2
percent)
of
the
annual
average
PM10
NAAQS.

41See
40
CF
R
51.166(
i)(
5)(
i).
Proposed
new
sources
or
existing­
source
modifications
that
would
contribute
less
than
10

g/
m3
(
or
5.3%)
of
the
150

g/
m3
PM10
24­
hour
average
NAAQS,
estimated
using
on
a
screening
model,
may
avoid
the
requirement
of
collecting
and
submitting
ambient
air
quality
data.
NAAQS
itself39.

Many
commenters
noted
that
EPA's
proposed
threshold
of
0.15

g/
m3,
or
one
percent
of
the
annual
PM2.5
NAAQS
of
15.0

g/
m3,
is
lower
than
the
single­
source
contribution
thresholds
employed
for
PM10
in
certain
other
regulatory
contexts.
Commenters
cited
several
different
thresholds,

including
thresholds
governing
the
applicability
of
the
preconstruction
review
permit
program
and
the
emissions
reduction
requirement
for
certain
major
new
or
modified
stationary
sources
located
in
attainment
or
unclassified
areas;
40
and
thresholds
in
the
PSD
rules
that
may
relieve
proposed
sources
from
performing
comprehensive
ambient
air
quality
analyses.
41
159
Since
the
thresholds
referred
to
by
the
commenters
serve
different
purposes
than
the
CAIR
threshold
for
significant
contribution,
it
does
not
follow
that
they
should
be
made
equivalent.
The
implication
of
the
thresholds
cited
by
the
commenters
is
not
that
single­
source
contributions
below
these
levels
indicate
the
absence
of
a
contribution.
Rather,
these
thresholds
address
whether
further
more
comprehensive,
multi­
source
review
or
analysis
of
appropriate
control
technology
and
emissions
offsets
are
required
of
the
source.
A
source
with
estimated
impacts
below
these
levels
is
recognized
as
still
affecting
the
airshed
and
is
subject
to
meeting
applicable
control
requirements,
including
best
available
control
technology,

designed
to
moderate
the
source's
impact
on
air
quality.

The
purpose
of
the
CAIR
threshold
for
PM2.5
is
to
determine
whether
the
annual
average
contribution
from
a
collection
of
sources
in
a
State
is
small
enough
not
to
warrant
any
additional
control
for
the
purpose
of
mitigating
interstate
transport,
even
if
that
control
were
highly
cost
effective.

One
commenter
suggested
that
EPA
also
establish
and
evaluate
a
threshold
for
a
potential
new
tighter
24­
hour
PM2.5
standard
(
e.
g.,
1
percent
of
30

g/
m3).
EPA
must
base
its
criteria
on
evaluation
of
the
current
PM2.5
standards
and
not
standards
that
may
be
considered
in
the
future.
160
42This
truncation
convention
for
PM2.5
is
similar
to
that
used
in
evaluating
modeling
results
in
applying
the
ozone
significance
screening
criterion
of
2
ppb
in
the
NOx
SIP
call
and
the
CAIR
proposal
(
Technical
Support
Document
fo
the
Interstate
Air
Quality
Rule
Air
Quality
Modeling
Analyses",
January
2004.
Docket
#
OAR­
2003­
0053­
0162),
as
well
as
today's
final
action.
c.
Today's
Action
EPA
continues
to
believe
that
the
threshold
for
evaluating
the
air
quality
component
of
determining
whether
an
individual
State's
emissions
"
contribute
significantly"

to
downwind
nonattainment
of
the
annual
PM2.5
standard,

under
CAA
section
110(
a)(
2)(
D)
should
be
very
small
compared
to
the
NAAQS.
We
are,
however,
persuaded
by
commenters
arguments
on
monitoring
and
modeling
that
the
precision
of
the
threshold
should
not
exceed
that
of
the
NAAQS.
Rounding
the
proposal
value
of
0.15,
the
nearest
single
digit
corresponding
to
about
1%
of
the
PM2.5
annual
NAAQS
is
0.2
ug/
m3.
The
final
rule
is
based
on
this
threshold.
EPA
has
decided
to
apply
this
threshold
such
that
any
model
result
that
is
below
this
value
(
0.19
or
less)
indicates
a
lack
of
significant
contribution,
while
values
of
0.20
or
higher
exceed
the
threshold.
42
Using
this
metric
for
determining
whether
a
State
"
contributes
significantly"
(
before
considering
cost)
to
PM2.5
nonattainment,
our
updated
modeling
shows
that
Kansas,

Massachusetts,
New
Jersey,
Delaware,
and
Arkansas
(
all
161
43Today's
action,
including
the
updated
modeling,
fulfills
EPA's
commitment
in
the
NOx
SIP
Call
(
which
EPA
finalized
in
1998)
to
reevaluate
interstate
ozone
contributions
by
2007.
See
63
FR
57399;
October
27,
1998.
included
in
the
original
proposal)
no
longer
exceed
the
0.2

g/
m3
annual
average
PM2.5
contribution
threshold.
Of
these
states,
only
Arkansas
would
exceed
the
threshold
of
0.15
ug/
m3
that
was
included
in
the
proposal.

E.
What
Criteria
Should
be
Used
to
Determine
Which
States
are
Subject
to
this
Rule
Because
They
Contribute
to
Ozone
Nonattainment?

1.
Notice
of
Proposed
Rulemaking
In
assessing
the
contribution
of
upwind
States
to
downwind
8­
hour
ozone
nonattainment,
EPA
proposed
to
follow
the
approach
used
in
the
NOx
SIP
Call
and
to
employ
the
same
contribution
metrics,
but
with
an
updated
model
and
updated
inputs
that
reflect
current
requirements
(
including
the
NOx
SIP
Call
itself).
43
The
air
quality
modeling
approach
we
proposed
to
quantify
the
impact
of
upwind
emissions
includes
two
different
methodologies:
zero­
out
and
source
apportionment.

As
described
in
section
VI,
EPA
applied
each
methodology
to
estimate
the
impact
of
all
of
the
upwind
State's
NOx
emissions
on
each
downwind
nonattainment
areas.

The
EPA's
first
step
in
evaluating
the
results
of
162
44See
the
CAIR
Air
Quality
Modeling
TSD
for
description
of
the
methodology
used
to
calculate
these
metrics.
these
methodologies
was
to
remove
from
consideration
those
States
whose
upwind
contributions
were
very
low.

Specifically,
EPA
considered
an
upwind
State
not
to
contribute
significantly
to
a
downwind
nonattainment
area
if
the
State's
maximum
contribution
to
the
area
was
either
(
1)

less
than
2
ppb,
as
indicated
by
either
of
the
two
modeling
techniques;
or
(
2)
less
than
one
percent
of
total
nonattainment
in
the
downwind
area.
44
If
the
upwind
State's
impact
exceeded
these
thresholds,

then
EPA
conducted
a
further
evaluation
to
determine
if
the
impact
was
high
enough
to
meet
the
air
quality
portion
of
the
"
contribute
significantly"
standard.
In
doing
so,
the
EPA
organized
the
outputs
of
the
two
modeling
techniques
into
a
set
of
"
metrics."
The
metrics
reflect
three
key
contribution
factors:

!
the
magnitude
of
the
contribution
(
actual
amount
of
ozone
contributed
by
emissions
in
the
upwind
State
to
nonattainment
in
the
downwind
area);

!
the
frequency
of
the
contribution
(
how
often
contributions
above
certain
thresholds
occur);
and
!
the
relative
amount
of
the
contribution
(
the
total
ozone
contributed
by
the
upwind
State
compared
to
the
total
amount
of
nonattainment
ozone
in
the
downwind
163
area).

The
specific
metrics
on
which
EPA
proposed
to
rely
are
the
same
as
those
used
in
the
NOx
SIP
Call.
Table
III­
1
lists
them
for
each
of
the
two
modeling
techniques,
and
identifies
their
relationship
to
the
three
key
contribution
factors.

Table
III­
1.
Ozone
Contribution
Factors
and
Metrics
Factor:
Modeling
Technique
Zero­
out
Source
Apportionment
Magnitude
of
Contribution
Maximum
contribution
Maximum
contribution;
and
Highest
daily
average
contribution
(
ppb
and
percent)

Frequency
of
Contribution
Number
and
percent
of
exceedances
with
contributions
in
various
concentration
ranges
Number
and
percent
of
exceedances
with
contributions
in
various
concentration
ranges
Relative
Amount
of
Contribution
Total
contribution
relative
to
the
total
exceedance
ozone
in
the
downwind
area;
and
Population­
weighted
total
contribution
relative
to
the
total
populationweighted
exceedance
ozone
in
the
downwind
area
Total
average
contribution
to
exceedance
hours
in
the
downwind
area
164
In
the
NPR,
EPA
proposed
threshold
values
for
the
metrics.
An
upwind
State
whose
contribution
to
a
downwind
area
exceeded
the
threshold
values
for
at
least
one
metric
in
each
of
at
least
two
of
the
three
sets
of
metrics
was
considered
to
contribute
significantly
(
before
considering
cost)
to
that
downwind
area.
To
reiterate,
the
three
sets
of
metrics
reflect
the
factors
of
magnitude
of
contribution,

frequency
of
contribution,
and
relative
percentage
on
nonattainment.

In
fact,
EPA
noted
in
the
NPR
that
for
each
upwind
State,
the
modeling
disclosed
at
least
one
linkage
with
a
downwind
nonattainment
area
in
which
all
factors
(
magnitude,

frequency,
and
relative
amount)
were
found
to
indicate
large
and
frequent
contributions.
In
addition,
EPA
noted
in
the
NPR
that
each
upwind
State
contributed
to
nonattainment
problems
in
at
least
two
downwind
States
(
except
for
Louisiana
and
Arkansas
which
contributed
to
nonattainment
in
only
1
downwind
State).

In
addition,
EPA
noted
in
the
NPR
that
for
most
of
the
individual
linkages,
the
factors
yield
a
consistent
result
across
all
three
sets
of
metrics
(
i.
e.,
either
(
i)
large
and
frequent
contributions
and
high
relative
contributions
or
(
ii)
small
and
infrequent
contributions
and
low
relative
165
contributions).
In
some
linkages,
however,
not
all
of
the
factors
are
consistent.
The
EPA
believes
that
each
of
the
factors
provides
an
independent,
legitimate
measure
of
contribution.

In
the
NPR,
the
EPA
applied
the
evaluation
methodology
described
above
to
each
upwind­
downwind
linkage
to
determine
which
States
contribute
significantly
(
before
considering
cost)
to
nonattainment
in
the
40
downwind
counties
in
nonattainment
for
ozone
in
the
East.
The
analysis
of
the
metrics
for
each
linkage
was
presented
in
the
AQMTSD
for
the
NPR.
The
modeling
analysis
supporting
the
final
rule
is
an
update
to
the
NPR
modeling,
and
is
described
in
more
detail
in
section
VI
below.

2.
Comments
and
EPA
Responses
Some
commenters
submitted
comments
specifically
on
the
8­
hour
ozone
metrics.
One
commenter
asserted
that
in
calculating
the
"
Relative
Amount
of
Contribution"
metric,

EPA
treats
the
modeled
reductions
from
zeroing
out
a
State's
emissions
as
impacting
only
the
portion
of
the
downwind
receptor's
ambient
ozone
level
that
exceeds
the
8­
hour
average
84
ppb
level.
The
commenter
asserted
that
this
approach
falsely
treats
the
upwind
state's
emissions
as
contributing
to
the
amount
of
ozone
that
exceeds
the
NAAQS,

and
thus
inflates
the
ambient
impact
of
those
emissions.
166
The
commenter
concluded
that
it
would
be
more
appropriate
to
treat
the
upwind
emissions
as
impacting
all
of
the
downwind
ozone
level
(
not
just
the
portion
greater
than
84
ppb).
We
interpret
this
comment
to
mean
that
in
expressing
an
upwind
State's
contribution
as
a
percentage,
the
denominator
of
the
percentage
should
be
the
downwind
area's
total
ozone
contribution,
rather
than
the
downwind
area's
ozone
excess
above
the
NAAQS,
but
that
the
same
threshold
should
be
used
to
evaluate
contribution.
This
would
tend
to
result
in
fewer
upwind
States
being
found
to
be
significant
with
respect
to
this
metric.

We
believe
that
it
is
important
to
examine
the
ozone
contribution
relative
to
the
amount
of
ozone
above
the
NAAQS
as
well
as
the
amount
relative
to
total
nonattainment
ozone.

Both
approaches
have
merit.
The
intent
of
the
relative
contribution
metric,
as
calculated
for
the
zero­
out
modeling,
is
to
view
the
contribution
of
the
upwind
State
relative
to
the
amount
that
the
downwind
area
is
in
nonattainment;
that
is,
the
amount
of
ozone
above
the
NAAQS.

However,
our
relative
amount
metric
for
the
source
apportionment
modeling
does
treat
the
amount
of
contribution
relative
to
the
total
amount
of
ozone
when
ozone
concentrations
are
predicted
to
be
above
the
NAAQS.
To
be
found
a
significant
contributor,
an
upwind
State
must
be
167
above
the
threshold
for
both
the
zero­
out­
based
metric
and
the
source­
apportionment­
based
metric.
Thus,
our
approach
to
considering
the
significance
of
interstate
ozone
transport
captures
both
approaches
for
examining
the
relative
amount
of
contribution
and
does
not
favor
one
approach
over
the
other,
as
discussed
above.

3.
Today's
Action
EPA
is
finalizing
the
methodology
proposed
in
the
NPR,

and
discussed
above,
for
evaluating
the
air
quality
portion
of
the
"
contribute
significantly"
standard
for
ozone.

F.
Issues
Related
to
Timing
of
the
CAIR
Controls
1.
Overview
A
number
of
commenters
questioned
the
need
for
CAIR
requirements
considering
that
cap
dates
of
2010
and
2015
are
later
than
the
attainment
dates
that,
in
the
absence
of
extensions,
would
apply
to
certain
downwind
PM2.5
areas
and
ozone
nonattainment
areas.
Other
commenters,
noting
that
states
will
be
required
to
adopt
controls
in
local
attainment
plans,
questioned
whether
CAIR
controls
would
still
be
needed
to
avoid
significant
contribution
to
downwind
nonattainment,
or
whether
the
controls
would
still
be
needed
to
the
extent
required
by
the
rule.

Of
course,
CAIR
will
achieve
substantial
reductions
in
time
to
help
many
nonattainment
areas
attain
the
standards
168
45
As
in
the
NOx
SIP
Call
rulemaking,
EPA
interprets
the
"
interfere
with
maintenance"
statutory
requirement
"
much
the
same
as
the
term
`
contribute
significantly'",
that
is,
"
through
the
same
weight­
of­
evidence
approach."
63
FR
at
57379.
Furthermore,
we
believe
the
"
interfere
with
maintenance"
prong
may
come
into
play
only
in
circumstances
where
EPA
or
the
state
can
reasonably
determine
or
project,
based
on
available
data,
that
an
area
in
a
downwind
state
will
achieve
attainment,
but
due
to
emissions
growth
or
other
relevant
factors
is
likely
to
fall
back
into
nonattainment.
Id.
by
the
applicable
attainment
dates.
The
design
of
the
SO2
program,
including
the
declining
caps
in
2010
and
2015
and
the
banking
provisions,
will
steadily
reduce
SO2
emissions
over
time,
achieving
reductions
in
advance
of
the
cap
dates;

and
the
2009
and
2015
NOx
reductions
will
be
timely
for
many
downwind
nonattainment
areas.

Although
many
of
today's
nonattainment
areas
will
attain
before
all
the
reductions
required
by
CAIR
will
be
achieved,
it
is
clear
that
CAIR's
reductions
will
still
be
needed
through
2015
and
beyond.
EPA's
air
quality
modeling
has
demonstrated
that
upwind
States
have
a
sufficiently
large
impact
on
downwind
areas
to
require
reductions
in
2010
and
2015
under
CAA
section
110(
a)(
2)(
D).
Under
this
provision,
SIPs
must
prohibit
emissions
from
sources
in
amounts
that
"
will
contribute
significantly
to
...

nonattainment"
or
"
will
interfere
with
maintenance".
45
EPA
has
evaluated
the
attainment
status
of
the
downwind
receptors
in
2010
and
2015,
and
has
determined
that
each
169
upwind
State's
2010
and
2015
emissions
reductions
are
necessary
to
the
extent
required
by
the
rule
because
a
downwind
receptor
linked
to
that
upwind
State
will
either
(
i)
remain
in
nonattainment
and
continue
to
experience
significant
contribution
to
nonattainment
from
the
upwind
State's
emissions;
or
(
ii)
attain
the
relevant
NAAQS
but
later
revert
to
nonattainment
due,
for
example,
to
continued
growth
of
the
emissions
inventory.

The
argument
that
the
CAIR
reductions
are
justified,
in
part,
by
the
need
to
prevent
interference
with
maintenance,

is
a
limited
one.
EPA
does
not
believe
that
the
"
interfere
with
maintenance"
language
in
section
110(
a)(
2)(
D)
requires
an
upwind
state
to
eliminate
all
emissions
that
may
have
some
impact
on
an
area
in
a
downwind
state
that
is
(
or
once
was)
in
nonattainment
and
that,
therefore,
will
need
(
or
now
needs)
to
maintain
its
attainment
status.
Instead,
we
believe
that
CAIR
emission
reductions
are
needed
beyond
2010
and
2015,
in
part,
to
prevent
upwind
states
from
significantly
interfering
with
maintenance
in
other
states
because
our
analysis
shows
it
is
likely
that,
in
the
absence
of
the
CAIR,
a
current
or
projected
attainment
area
will
revert
to
nonattainment
due
to
continued
emissions
growth
or
other
relevant
factors.
We
are
not
taking
the
position
that
CAIR
controls
are
automatically
justified
to
prevent
170
interference
with
maintenance
in
every
area
initially
modeled
to
be
in
nonattainment.

We
also
note
that
considering
the
emission
controls
needed
for
maintenance,
along
with
the
controls
needed
to
reach
attainment
in
the
first
place,
is
consistent
with
the
goal
of
promoting
a
reasonable
balance
between
upwind
state
controls
and
local
(
including
all
in­
state)
controls
to
attain
and
maintain
the
NAAQS.
As
discussed
in
section
IV
of
this
notice,
in
the
ideal
world,
the
states
and
EPA
would
have
enough
information
(
and
powerful
enough
analytical
tools)
to
allow
us
to
identify
a
mix
of
control
strategies
that
would
bring
every
area
of
the
country
into
attainment
at
the
lowest
overall
cost
to
society.
Under
such
an
approach,
we
would
evaluate
the
impact
of
every
emissions
source
on
air
quality
in
all
nonattainment
areas,
the
cost
of
different
options
for
controlling
those
sources,
and
the
cost­
effectiveness
of
those
controls
in
terms
of
cost
per
increment
of
air
quality
improvement.
Such
an
approach
would
obviously
make
it
easier
for
a
state
to
develop
an
appropriate
set
of
control
requirements
for
sources
located
in
that
state
based
on
(
1)
the
need
to
bring
its
own
nonattainment
areas
into
attainment
and
(
2)
its
responsibility
under
section
110(
a)(
2)(
D)
to
prevent
significant
contribution
to
nonattainment
in
downwind
states
171
46
This
does
not
mean
that
the
upwind
state
would
be
responsible
for
making
all
the
reductions
necessary
to
bring
the
downwind
state's
nonattainment
area
into
attainment;
how
much
would
be
required
of
each
state
is
a
separate
question.
Again
in
the
ideal
world,
we
would
be
able
to
find
the
right
mix
of
controls
in
both
states
so
that
attainment
would
be
and
interference
with
maintenance
in
those
states.

Such
an
approach
would
also
make
it
much
easier
for
the
Agency
to
decide
on
efficiency
grounds
whether
to
take
action
under
section
126
(
or
under
section
110(
a)(
2)(
D)
if
a
state
failed
to
meet
its
obligations
under
that
section)
for
purposes
of
either
attainment
or
maintenance
of
a
NAAQS
in
another
state.
In
the
simplest
example,
we
might
need
to
consider
a
case
in
which
a
downwind
state
with
a
nonattainment
area
is
seeking
reductions
from
an
upwind
state
based
on
the
claim
that
emissions
from
the
upwind
state
are
contributing
significantly
to
the
nonattainment
problem
in
the
downwind
state.
In
such
a
case,
the
first
question
is
whether
the
upwind
state
should
be
required
to
take
any
action
at
all,
and
in
the
ideal
world,
it
would
be
simple
to
answer
this
question.
If
emission
reductions
from
sources
in
the
upwind
state
are
more
cost­
effective
than
emission
reductions
in
the
downwind
state
­
in
terms
of
cost
per
increment
of
improvement
in
air
quality
in
the
downwind
nonattainment
area
­
then
the
upwind
state
would
need
to
take
some
action
to
control
emissions
from
sources
in
that
state.
46
On
the
other
hand,
if
controls
on
sources
in
the
172
achieved
at
the
lowest
total
cost.
upwind
state
are
not
more
cost­
effective
in
terms
of
cost
per
increment
of
improvement
in
air
quality,
then
the
Agency
would
not
take
action
under
sections
126
or
110(
a)(
2)(
D);

rather,
the
downwind
state
would
need
to
meets
its
attainment
and
maintenance
needs
by
controlling
sources
within
its
own
jurisdiction.
Of
course,
factors
other
than
efficiency,
such
as
equity
or
practicality,
also
might
affect
the
decision.

Unfortunately,
we
do
not
have
adequate
information
or
analytical
tools
(
ideally
a
detailed
linear
programming
model
that
fully
integrates
both
control
costs
and
ambient
impacts
of
sources
in
each
State
on
each
of
the
downwind
receptors)
to
allow
us
to
undertake
the
analysis
described
above
at
this
time.
However,
the
Agency
believes
that
CAIR
is
consistent
with
this
basic
approach
and
will
result
in
upwind
states
and
downwind
states
sharing
appropriate
responsibility
for
attainment
and
maintenance
of
the
relevant
NAAQS,
considering
efficiency,
equity
and
practical
considerations.
Under
CAIR,
the
required
reductions
in
upwind
states
(
including
those
projected
to
occur
after
2015)
are
highly
cost
effective,
measured
in
cost­
per­
ton
of
emissions
reduction,
as
documented
in
section
IV.
This
suggests
that,
regardless
of
whether
the
CAIR
reductions
173
47
Tables
describing
cost
effectiveness
of
various
control
measures
and
programs
are
provided
in
section
IV.
These
show
that
the
cost
per
ton
of
non­
power­
sector
control
options
that
states
might
consider
for
attainment
purposes
typically
is
higher
than
for
CAIR
controls.
assist
downwind
areas
in
achieving
attainment
or
in
subsequently
maintaining
the
relevant
NAAQS,
the
upwind
controls
will
be
reasonable
in
cost
relative
to
a
further
increment
of
local
controls
that,
in
most
cases,
will
have
a
substantially
higher
cost
per
ton
­­
particularly
in
areas
that
need
greater
local
reductions
and
require
reductions
from
a
variety
of
source
types.
47
Thus,
we
believe
that
CAIR
is
consistent
with
the
goal
of
attaining
and
maintaining
air
quality
standards
in
an
efficient,
as
well
as
equitable,
manner.

Another
reason
for
considering
both
attainment
and
maintenance
needs
at
this
time
is
EPA's
expectation
that
most
nonattainment
areas
will
be
able
to
attain
the
PM2.5
and
8­
hour
ozone
standards
within
the
time
periods
provided
under
the
statute.
Considering
both
types
of
downwind
needs
shows
that
there
is
a
strong
basis
for
CAIR's
requirements
despite
the
potential
for
most
receptor
areas
to
attain
before
all
the
emission
reductions
required
by
CAIR
are
achieved.

2.
By
Design,
the
CAIR
Cap
and
Trade
Program
Will
Achieve
Significant
Emissions
Reductions
Prior
to
the
Cap
174
48
A
similar
glide
path
will
occur
prior
to
the
effective
date
of
the
Phase
I
SO2
cap
because
this
cap
will
complement
and
extend
the
cap
the
currently
exists
under
the
Acid
Rain
program.
Deadlines
EPA
notes
that
Phase
I
of
CAIR
is
the
initial
step
on
the
slope
of
emissions
reduction
(
i.
e.,
the
"
glide
path")

leading
to
the
final
control
levels.
Because
of
the
incentive
to
make
early
emission
reductions
that
the
cap
and
trade
program
provides,
reductions
will
begin
early
and
will
continue
to
increase
through
Phases
I
and
II.
Therefore,

all
the
required
Phase
II
emission
reductions
will
not
take
place
on
January
1,
2015,
the
effective
date
of
the
second
phase
cap.
Rather,
these
reductions
will
accrue
throughout
the
implementation
period,
as
the
sources
install
controls
and
start
to
test
and
operate
them.
The
resulting
glide
path
of
reductions
with
CAIR
Phase
II
will
provide
important
reductions
to
areas
coming
into
attainment
over
the
2010
to
2014
period.
48
3.
Additional
Justification
for
the
SO2
and
NOx
Annual
Controls
Our
modeling
indicates
that
it
is
very
plausible
that
a
significant
number
of
downwind
PM2.5
receptors
are
likely
to
remain
in
nonattainment
in
2010
and
beyond.
As
noted
above
(
Preamble
Table
VI­
10),
the
Agency
has
evaluated
a
wide
175
range
of
emission
control
options
and
found
that
the
average
ambient
reduction
in
PM2.5
concentrations
achievable
through
aggressive
but
feasible
local
controls
is
1.26
ug/
m3.
In
the
2010
base
case
(
which
does
not
consider
potential
local
controls
or
2010
CAIR
controls,
but
does
consider
all
other
emission
controls
required
to
be
in
effect
as
of
that
date),

nearly
half
the
receptor
counties
would
be
in
nonattainment
by
more
than
this
amount.
This
indicates
that
nonattainment
is
of
sufficient
severity
to
make
it
likely
that,
in
the
absence
of
CAIR,
many
of
these
areas
would
need
an
attainment
date
extension
of
at
least
one
year.

Our
base
case
modeling
further
shows
that
every
upwind
state
is
linked
to
at
least
one
receptor
area
projected
to
have
nonattainment
of
this
severity.
Tables
VI­
10
and
VI­
11.
Thus,
there
is
a
reasonable
likelihood
that
CAIR
controls
will
be
needed
from
all
of
the
upwind
states
to
prevent
significant
contribution
to
these
downwind
receptors'
nonattainment.

Nor
is
the
amount
of
reduction
in
excess
of
what
is
needed
for
attainment.
We
project
that
even
with
CAIR
controls,
almost
all
of
the
upwind
states
in
2010
remain
linked
with
at
least
one
downwind
receptor
that
would
not
attain
by
the
same
substantial
margin
exceeding
the
average
of
aggressive
local
controls.
Tables
VI­
10
and
VI­
8.
This
176
not
only
indicates
that
the
2010
CAIR
controls
are
not
excessive,
but
that
local
controls
will
still
be
necessary
for
attainment.

In
addition,
there
is
potential
for
residual
nonattainment
in
2015
in
view
of
the
severity
of
PM2.5
levels
in
some
areas,
uncertainties
about
the
levels
of
reductions
in
PM2.5
and
precursors
that
will
prove
reasonable
over
the
next
decade,
the
potential
for
up
to
two
1­
year
extensions
for
areas
that
meet
certain
air
quality
levels
in
the
year
preceding
their
attainment
date,
and
historical
examples
in
which
areas
did
not
meet
their
statutory
attainment
dates
for
other
NAAQS.

With
respect
to
the
argument
that
phase
II
emission
reductions
that
will
be
achieved
after
2015
are
not
needed
because
all
receptors
will
have
attained
before
2015,
we
think
it
likely
that
some
PM2.5
nonattainment
areas
may
qualify
for
2014
attainment
dates
and
eventually,
one­
year
attainment
date
extensions,
and
that
there
may
be
residual
nonattainment
in
2015.
We
continue
to
project
that
nearly
half
the
downwind
receptors
in
the
2015
base
case
will
be
in
nonattainment
by
amounts
exceeding
the
average
ambient
reduction
(
again,
1.26
ug/
m3)
attributable
to
local
controls
we
believe
would
be
aggressive
but
feasible
for
2010.
Table
VI­
11.
The
history
of
progress
in
development
of
emission
177
reduction
strategies
and
technologies
indicates
that
greater
local
reductions
could
be
achieved
by
2015
than
in
2010;

nonetheless,
this
potential
nonattainment
is
of
sufficient
severity
to
make
it
plausible
that
at
least
some
of
these
areas
will
need
an
extension.
In
such
cases,
this
would
eliminate
the
issue
of
timing
raised
by
commenters,
since
CAIR
controls
would
no
longer
be
following
attainment
dates.

Our
modeling
further
shows
that,
in
the
2015
base
case
(
which
does
not
include
CAIR
controls),
all
the
upwind
states
in
the
CAIR
region
are
linked
to
areas
projected
to
exceed
the
standard
by
at
least
2
ug/
m3.
Tables
VI­
11
and
VI­
8.
Given
the
reasonable
potential
for
continued
nonattainment,
it
is
reasonable
to
require
2015
CAIR
controls
from
each
upwind
state
to
prevent
significant
contribution
to
nonattainment.

Moreover,
even
with
2015
CAIR
controls
(
but
not
attainment
SIP
controls),
almost
all
of
the
upwind
states
remain
linked
with
at
least
one
downwind
receptor
that
would
not
attain
by
at
least
this
same
substantial
margin
(
at
least
1.26
ug/
m3).
Id.
This
shows
that
the
2015
CAIR
controls
are
not
more
than
are
necessary
to
attain
the
NAAQS
(
and
also
shows
the
necessity
for
local
controls
in
order
to
attain).
Thus,
we
conclude
that
the
further
PM2.5
reductions
achieved
by
the
second
phase
cap
will
likely
be
178
needed
to
assure
all
relevant
areas
reach
attainment
by
applicable
deadlines.

Even
if
some
of
these
areas
make
more
progress
than
we
predict,
many
downwind
receptor
areas
would
be
likely
in
2010
and
2015
to
continue
to
have
air
quality
only
marginally
better
than
the
standard,
and
be
at
risk
of
returning
to
nonattainment.
Air
quality
is
unlikely
to
be
appreciably
cleaner
than
the
standard
because
many
areas
will
need
steep
reductions
merely
to
attain,
given
that
we
project
nonattainment
by
wide
margins
(
as
explained
above).

Moreover,
we
project
that
without
CAIR,
PM2.5
levels
would
worsen
in
19
downwind
receptor
counties
between
2010
and
2015,
reflecting
changes
in
local
and
upwind
emissions.

Air
Quality
Modeling
Technical
Support
Document,
November,

2004.
This
suggests
a
reasonable
likelihood
that,
without
CAIR,
these
areas
would
return
to
nonattainment.
See
63
FR
at
57379­
80
(
finding
in
NOX
SIP
Call
that
upwind
emissions
interfere
with
maintenance
of
8­
hour
ozone
standard
under
section
110(
a)(
2)(
D)(
i)
where
increases
in
emissions
of
ozone
precursors
are
projected
due
to
growth
in
emissions
generating
activity,
resulting
in
receptors
no
longer
attaining
the
standard).
These
downwind
receptors
link
to
all
but
two
of
the
upwind
states,
and
the
remaining
two
upwind
states
are
linked
to
receptors
where
projected
PM2.5
179
levels
between
2010
and
2015
improve
only
slightly,
leaving
their
air
quality
only
marginally
in
attainment.
Response
to
Comments,
section
III.
C.
In
light
of
documented
year­
to­
year
variations
in
PM2.5
levels,
these
receptors
would
have
a
reasonable
probability
of
returning
to
nonattainment
in
the
absence
of
CAIR.

Emissions
trends
after
2015
give
rise
to
further
maintenance
concerns.
Between
2015
and
2020,
emissions
of
PM2.5
and
certain
precursors
are
projected
to
rise.
We
do
not
have
air
quality
modeling
for
2020.
However,
for
PM2.5
and
every
precursor,
the
2015­
2020
emission
trend
is
less
favorable
than
the
2010­
2015
emission
trend.
Given
the
PM2.5
increases
our
air
quality
modeling
found
for
19
counties
between
2010
and
2015,
the
emission
trends
suggest
greater
maintenance
concerns
in
the
2015­
2020
period
than
during
the
2010­
2015
period.
See
Response
to
Comments
section
III.
C.

Accordingly,
we
believe
that
given
these
projected
trends,
and
the
likelihood
of
only
borderline
attainment,

CAIR
controls
from
every
upwind
state
in
the
CAIR
region
are
needed
to
prevent
interference
with
maintenance
of
the
PM2.5
standard.
The
projected
upwards
pressure
on
PM2.5
concentrations
in
most
receptor
areas
indicates
that
the
amount
of
upwind
reductions
is
not
more
than
necessary
to
180
prevent
interference
with
maintenance
of
the
standards,

again
given
the
likelihood
of
initial
attainment
by
narrow
margins.

4.
Additional
Justification
for
Ozone
NOx
Requirements
We
believe
that
most
8­
hour
ozone
areas
will
be
able
to
attain
by
their
attainment
deadlines
through
existing
measures,
2009
CAIR
NOx
reductions,
and
additional
local
measures.
However,
we
also
believe
that
a
limited
number
of
downwind
receptor
areas
will
remain
in
nonattainment
with
the
ozone
standard
after
2010.
This
is
due
to
the
severity
of
projected
ozone
levels
in
certain
areas,
uncertainties
about
the
levels
of
emissions
reductions
in
that
will
prove
reasonable
over
the
next
decade,
and
historical
difficulties
with
attaining
the
1­
hour
ozone
standard.

For
ozone,
the
historic
difficulties
that
many
areas,

particularly
large
urban
areas,
have
experienced
in
attaining
the
ozone
NAAQS
raises
the
possibility
that
some
areas
may
not
attain
by
their
attainment
dates,
and
may
request
a
voluntary
bump
up
to
a
higher
classification
pursuant
to
section
181
(
b)
(
2)
to
gain
an
extension,
or
may
fail
to
attain
by
the
attainment
date
and
be
bumped
up
under
section
181
(
b)
(
2).
These
authorities
were
used
in
the
course
of
implementing
the
1­
hour
ozone
NAAQS.

Our
base
case
modeling
(
without
CAIR,
and
without
state
181
49
Attainment
deadlines
for
moderate
ozone
areas
are
to
be
no
later
than
June
2010;
an
approvable
attainment
plan
must
demonstrate
the
reductions
needed
for
attainment
will
be
achieved
by
the
ozone
season
in
the
preceding
year.
controls
implementing
the
8­
hour
standard)
projects
geographically
widespread
nonattainment
with
the
8­
hour
ozone
NAAQS
in
2015.
Tables
VI­
12
and
VI­
13.
Five
counties
that
link
to
14
upwind
states
have
projected
ozone
levels
that
exceed
the
8­
hour
standard
by
6
ppb
or
more,
and
20
upwind
states
are
linked
to
counties
projected
to
exceed
the
8­
hour
standard
by
more
than
4
ppb.
These
two
sets
of
linkages
show
that
under
a
scenario
in
which
several
of
the
receptors
with
the
highest
ozone
levels
did
not
attain,
CAIR
reductions
would
be
justified
to
prevent
significant
contributions
from
many
of
the
upwind
states
in
the
CAIR
ozone
region.

The
fact
that
receptors
show
significant
nonattainment
even
after
implementation
of
the
phase
II
CAIR
reductions,

as
shown
in
Table
VI­
13,
indicates
that
these
reductions
would
not
be
more
than
necessary
to
prevent
significant
contribution
to
nonattainment
in
residual
areas.
Even
if
all
ozone
nonattainment
areas
in
the
CAIR
region
could
achieve
reductions
sufficient
to
meet
the
level
of
the
8­
hour
ozone
standard
in
200949
based
on
local
controls,

2009
CAIR
NOx
reductions,
and
existing
programs,
we
believe
that
numerous
downwind
receptor
areas
would
remain
close
182
50
We
recognize
that
in
the
absence
of
substantial
evidence,
variability
alone
would
not
be
a
sufficient
basis
for
applying
the
"
interfere
with
maintenance"
prong
of
section
110(
a)(
2)(
D).
Here,
however,
where
there
is
a
substantial
enough
to
the
standard
to
be
at
risk
of
falling
back
into
nonattainment
for
the
reasons
discussed
below.
These
receptor
areas
are
linked
to
all
states
in
the
CAIR
ozone
region.

First,
it
is
highly
unlikely
that
the
receptor
areas
will
be
able
to
attain
by
a
wide
margin.
This
is
primarily
because
many
of
those
areas
will
need
substantial
emissions
reductions
merely
to
attain.
This
is
supported
by
modeling
showing
that
in
the
2010
base
case,
30
percent
of
the
receptors
are
projected
to
be
in
nonattainment
by
the
wide
margin
of
6
ppb
or
more,
indicating
the
steep
emissions
reductions
necessary
just
to
come
into
attainment.
Table
VI­
12.
We
recognize
that,
unlike
the
trend
in
key
PM
receptor
areas,
our
modeling
projects
that
the
ozone
levels
in
ozone
receptor
areas
will
improve
somewhat
between
2010
and
2015
due
chiefly
to
downward
trends
in
NOx
emissions
projected
under
existing
requirements.
Nonetheless,
as
shown
in
detail
in
the
Response
to
Comments,
the
projected
improvements
in
ozone
levels
in
the
receptor
areas
are
less
(
often
considerably
less)
than
historic
variability
in
monitored
8­
hour
ozone
design
values
from
one
three
year
period
to
the
next.
50
We
believe
this
variability
is
mostly
183
body
of
historical
data
documenting
the
variability
in
ozone
concentrations,
we
believe
it
is
appropriate
to
consider
variability
in
determining
whether
emission
reductions
from
upwind
states
are
necessary
to
prevent
interference
with
maintenance
of
the
ozone
standard
in
downwind
states.
attributable
to
changing
weather
conditions
(
which
significantly
affect
the
rate
at
which
ozone
is
formed
in
the
atmosphere
and
movement
of
ozone
after
it
is
formed),

rather
than
variability
in
the
emissions
inventory.
Thus,

absent
the
second
phase
CAIR
cap,
these
receptors
remain
vulnerable
to
falling
back
into
nonattainment.
The
receptors
for
which
this
is
the
case
link
to
each
of
the
upwind
states
in
the
ozone
CAIR
region.

IV.
What
Amounts
of
SO2
and
NOx
Emissions
Did
EPA
Determine
Should
Be
Reduced?

In
today's
rule,
EPA
requires
annual
SO2
and
NOx
emissions
reductions
and
ozone­
season
NOx
emissions
reductions
to
eliminate
the
amount
of
emissions
that
contribute
significantly
to
nonattainment
of
the
NAAQS
for
PM2.5
and
ozone.
The
NOx
reductions
are
phased
in
beginning
in
2009,
the
SO2
reductions
beginning
in
2010,
and
both
are
lowered
in
2015.
In
this
section
of
the
preamble,
EPA
explains
its
analysis
of
the
cost
portion
of
the
contribute­
184
significantly
test,
which
determines
the
amount
of
required
emissions
reductions.
The
cost
portion
requires
analysis
of
whether
the
control
program
under
review
is
highly
cost
effective,
and
other
factors
that
are
discussed
below
in
section
IV.
A.

In
section
IV.
A
of
today's
preamble,
EPA
explains
its
methodology
for
determining
the
amounts
of
SO2
and
NOx
emissions
that
must
be
eliminated
for
compliance
with
the
CAIR.
Section
IV.
A
is
divided
into
IV.
A.
1,
IV.
A.
2,
IV.
A.
3,

and
IV.
A.
4.
In
IV.
A.
1,
EPA
explains
the
methodology
that
the
Agency
used
to
model
control
costs
for
evaluation
of
cost
effectiveness.
In
IV.
A.
2,
EPA
describes
the
methodology
that
was
proposed
in
the
NPR
for
determining
the
amounts
of
emissions
that
must
be
eliminated,
including
an
overview
of
the
proposed
methodology,
a
description
of
the
NOx
SIP
Call
regulatory
history
in
relation
to
the
proposed
methodology,
and
a
description
of
EPA's
proposed
criteria
for
determining
emission
reduction
requirements.
Section
IV.
A.
3
summarizes
some
comments
received
regarding
the
proposed
methodology.
Section
IV.
A.
4
describes
EPA's
evaluation
of
highly
cost­
effective
SO2
and
NOx
emissions
reductions
based
on
controlling
EGUs.

Section
IV.
A.
4
is
further
divided
into
IV.
A.
4.
a
and
IV.
A.
4.
b,
which
address
SO2
and
NOx
emission
reduction
185
requirements,
respectively.
Section
IV.
A.
4.
a
describes
EPA's
evaluation
of
highly
cost­
effective
SO2
reduction
requirements,
beginning
with
a
summary
of
the
proposal
and
then
describing
today's
final
determination.
In
IV.
A.
4.
b.,

EPA
describes
its
evaluation
of
highly
cost­
effective
NOx
reduction
requirements,
also
beginning
with
a
summary
of
the
proposal
and
then
describing
today's
final
determination.

Section
IV.
A.
4.
b
first
addresses
annual
NOx
reductions,
and
then
addresses
ozone
season
NOx
reductions.
The
final
regionwide
CAIR
SO2
and
NOx
control
levels
are
provided
within
section
IV.
A,
while
a
more
detailed
description
of
today's
final
emission
reduction
requirements
is
presented
in
section
IV.
D.

In
section
IV.
B
of
today's
preamble,
EPA
discusses
other
(
non­
EGU)
sources
that
the
Agency
considered
in
developing
today's
rule.

Section
IV.
C
of
today's
preamble
explains
the
schedule
for
implementing
today's
SO2
and
NOx
emissions
reductions
requirements.
This
section
begins
with
an
overview
of
the
schedule
(
see
section
IV.
C.
1),
then
provides
a
detailed
discussion
of
the
engineering
factors
that
affect
timing
for
control
retrofits
(
section
IV.
C.
2).
Within
IV.
C.
2,
EPA
first
describes
the
NPR
discussion
of
engineering
factors
including
the
availability
of
boilermaker
labor
as
a
186
limitation
(
IV.
C.
2.
a),
then
presents
some
comments
received
(
IV.
C.
2.
b)
and
EPA's
responses
(
IV.
C.
2.
c).
In
section
IV.
C.
3,
EPA
discusses
the
financial
stability
of
the
power
sector
in
relation
to
the
schedule
for
the
CAIR.

Section
IV.
D
of
today's
preamble
provides
a
detailed
description
of
the
final
CAIR
emission
reduction
requirements.
Regionwide
SO2
and
NOx
control
levels,

projected
base
case
emissions
and
emissions
after
the
CAIR,

and
projected
emissions
reductions
are
presented.
Section
IV.
D
begins
with
a
description
of
the
criteria
used
to
determine
final
control
requirements
and
provides
the
details
of
the
final
requirements.

A.
What
Methodology
Did
EPA
Use
to
Determine
the
Amounts
of
SO2
and
NOx
Emissions
that
Must
Be
Eliminated?

1.
The
EPA's
Cost
Modeling
Methodology
The
EPA
conducted
analysis
using
the
Integrated
Planning
Model
(
IPM)
that
indicates
that
its
CAIR
SO2
and
NOx
reduction
requirements
are
highly
cost
effective.
Cost
effectiveness
is
one
portion
of
the
contribute­
significantly
test.
The
EPA
uses
the
IPM
to
examine
costs
and,
more
broadly,
analyze
the
projected
impact
of
environmental
policies
on
the
electric
power
sector
in
the
48
contiguous
States
and
the
District
of
Columbia.
The
IPM
is
a
multiregional
dynamic,
deterministic
linear
programming
model
of
187
the
U.
S.
electric
power
sector.
The
EPA
used
the
IPM
to
evaluate
the
cost
and
emissions
impacts
of
the
policies
required
by
today's
action
to
limit
annual
emissions
of
SO2
and
NOx
and
ozone
season
emissions
of
NOx
from
the
electric
power
sector
(
on
the
assumption
that
all
affected
States
choose
to
implement
reductions
by
controlling
EGUs
using
the
model
cap
and
trade
rule).

The
EPA
conducted
analyses
for
the
final
CAIR
using
the
2004
update
of
the
IPM,
version
2.1.9.
Documentation
describing
the
2004
update
is
in
the
CAIR
docket
and
on
EPA's
website.
Some
highlights
of
the
2004
update
include:

updated
inventory
of
electric
generating
units
(
EGUs)
and
installed
pollution
control
equipment;
updated
State
emission
regulations;
updated
coal
choices
available
to
generating
units;
updated
natural
gas
supply
curves;
updated
SCR
and
SNCR
cost
assumptions;
updated
assumptions
on
performance
of
NOx
combustion
controls;
updated
title
IV
SO2
bank
assumptions;
updated
heat
rates
and
SO2
and
NOx
emission
rates;
and,
updated
repowering
costs.

The
National
Electric
Energy
Data
System
(
NEEDS)

contains
the
generation
unit
records
used
to
construct
model
plants
that
represent
existing
and
planned/
committed
units
in
EPA
modeling
applications
of
the
IPM.
The
NEEDS
includes
basic
geographic,
operating,
air
emissions,
and
other
data
188
51
An
exception
was
made
to
the
run
year
mapping
for
an
IPM
sensitivity
run
that
examined
the
impact
of
a
NOx
Compliance
Supplement
Pool
(
CSP).
In
that
run
the
years
2009
through
2012
were
mapped
to
2010
and
2008
was
mapped
to
2008.
on
all
the
generation
units
that
are
represented
by
model
plants
in
EPA's
v.
2.1.9
update
of
the
IPM.

The
IPM
uses
model
run
years
to
represent
the
full
planning
horizon
being
modeled.
That
is,
several
years
in
the
planning
horizon
are
mapped
into
a
representative
model
run
year,
enabling
the
IPM
to
perform
multiple
year
analyses
while
keeping
the
model
size
manageable.
Although
the
IPM
reports
results
only
for
model
run
years,
it
takes
into
account
the
costs
in
all
years
in
the
planning
horizon.
In
EPA's
v.
2.1.9
update
of
the
IPM,
the
years
2008
through
2012
are
mapped
to
run
year
2010,
and
the
years
2013
through
2017
are
mapped
to
run
year
2015.51
Model
outputs
for
2009
and
2010
are
from
the
2010
run
year.
Model
outputs
for
2015
are
from
the
2015
run
year.

The
EPA
used
the
IPM
to
conduct
the
cost­
effectiveness
analysis
for
the
emissions
control
program
required
by
today's
action.
The
model
was
used
to
project
the
incremental
electric
generation
production
costs
that
result
from
the
CAIR
program.
These
estimates
are
used
as
the
basis
for
EPA's
estimate
of
average
cost
and
marginal
cost
of
emissions
reductions
on
a
per
ton
basis.
The
model
was
also
used
to
project
the
marginal
cost
of
several
State
189
programs
that
EPA
considers
as
part
of
its
base
case.

In
modeling
the
CAIR
with
the
IPM,
EPA
assumes
interstate
emissions
trading.
While
EPA
is
not
requiring
States
to
participate
in
an
interstate
trading
program
for
EGUs,
we
believe
it
is
reasonable
to
evaluate
control
costs
assuming
States
choose
to
participate
in
such
a
program
since
that
will
result
in
less
expensive
reductions.
The
EPA's
IPM
analyses
for
the
CAIR
includes
all
fossil
fuelfired
EGUs
with
generating
capacity
greater
than
25
MW.

The
EPA's
IPM
modeling
accounts
for
the
use
of
the
existing
title
IV
bank
of
SO2
allowances.
The
projected
EGU
SO2
emissions
in
2010
and
2015
are
above
the
cap
levels,

because
of
the
use
of
the
title
IV
bank.
The
annual
SO2
emissions
reductions
that
are
achieved
in
2010
and
2015
are
based
on
the
caps
that
EPA
determined
to
be
highly
cost
effective,
including
the
existence
of
the
title
IV
bank.

The
final
CAIR
requires
annual
SO2
and
NOx
reductions
in
23
States
and
the
District
of
Columbia,
and
also
requires
ozone
season
NOx
reductions
in
25
States
and
the
District
of
Columbia.
Many
of
the
CAIR
States
are
affected
by
both
the
annual
SO2
and
NOx
reduction
requirements
and
the
ozone
season
NOx
requirements.

The
EPA
initially
conducted
IPM
modeling
for
today's
final
action
using
a
control
strategy
that
is
similar
but
190
52
The
EPA
began
our
emissions
and
economic
analyses
for
the
CAIR
before
the
air
quality
analysis,
which
affects
the
States
covered
by
the
final
rule,
was
completed.
not
identical
to
the
final
CAIR
requirements.
52
Many
of
the
analyses
for
the
final
CAIR
are
based
on
that
initial
modeling,
as
explained
further
below.
The
control
strategy
that
EPA
initially
modeled
included
three
additional
States
(
Arkansas,
Delaware
and
New
Jersey)
within
the
region
required
to
make
annual
SO2
and
NOx
reductions.
However,

these
three
States
are
not
required
to
make
annual
reductions
under
the
final
CAIR.
(
In
the
"
Proposed
Rules"

section
of
today's
Federal
Register,
EPA
is
publishing
a
proposal
to
include
Delaware
and
New
Jersey
in
the
CAIR
region
for
annual
SO2
and
NOx
reductions.)
The
addition
of
these
three
States
made
a
total
of
26
States
and
the
District
of
Columbia
covered
by
annual
SO2
and
NOx
caps
for
the
initial
model
run.
The
initial
model
run
also
included
individual
State
ozone
season
NOx
caps
for
Connecticut
and
Massachusetts,
and
did
not
include
ozone
season
NOx
caps
for
any
other
States.

The
Agency
conducted
revised
final
IPM
modeling
that
reflects
the
final
CAIR
control
strategy.
The
final
IPM
modeling
includes
regionwide
annual
SO2
and
NOx
caps
on
the
23
States
and
the
District
of
Columbia
that
are
required
to
make
annual
reductions,
and
includes
a
regionwide
ozone
191
season
NOx
cap
on
the
25
States
and
the
District
of
Columbia
that
are
required
to
make
ozone
season
reductions.
The
EPA
modeled
the
final
CAIR
NOx
strategy
as
an
annual
NOx
cap
with
a
nested,
separate
ozone
season
NOx
cap.

In
this
section
of
today's
preamble,
the
projected
CAIR
costs
and
emissions
are
generally
derived
from
the
final
IPM
run
reflecting
the
final
CAIR.
However,
some
of
EPA's
analyses
are
based
on
the
initial
IPM
run,
described
above,

which
reflected
a
similar
but
not
identical
control
strategy
to
the
final
CAIR.
Analyses
that
are
presented
in
this
section
of
the
preamble
that
are
based
on
the
initial
IPM
run
include:
IPM
sensitivity
runs
that
examine
the
effects
of
using
the
Energy
Information
Administration
(
EIA)
natural
gas
price
and
electricity
growth
assumptions;
marginal
cost
effectiveness
curves
developed
using
the
Technology
Retrofitting
Updating
Model;
estimates
of
average
annual
SO2
and
NOx
control
costs
and
average
non­
ozone
season
NOx
control
costs,
and
projected
control
retrofits
used
in
the
feasibility
analysis.
The
air
quality
analysis
in
section
VI
of
today's
preamble
and
the
benefits
analysis
in
section
X,
as
well
as
the
analyses
presented
in
the
Regulatory
Impact
Analysis
(
RIA),
are
based
on
emissions
projections
from
the
initial
IPM
run.

The
EPA
believes
that
the
differences
between
the
192
initial
IPM
run
that
the
Agency
used
for
many
of
the
analyses
for
the
CAIR,
and
the
final
IPM
run
reflecting
the
final
CAIR
requirements,
have
very
little
impact
on
projected
control
costs
and
emissions.
For
the
two
IPM
runs,
projected
marginal
costs
of
CAIR
annual
NOx
reductions
in
2009
and
2015
are
identical.
In
addition,
for
the
two
IPM
runs,
projected
marginal
costs
of
CAIR
annual
SO2
reductions
in
2010
and
2015
are
almost
identical.
Also,
the
2009
and
2015
projected
annual
NOx
emissions
in
the
region
encompassing
the
States
that
are
affected
by
the
final
CAIR
annual
NOx
requirements
are
virtually
identical
when
compared
between
the
two
model
runs
(
difference
between
projected
NOx
emissions
is
less
than
1
percent
for
2009
and
less
than
2
percent
for
2015).
In
addition,
the
2010
and
2015
projected
annual
SO2
emissions
in
the
region
encompassing
the
States
that
are
affected
by
the
final
CAIR
annual
SO2
requirements
are
virtually
the
same
when
compared
between
the
two
runs
(
difference
between
projected
SO2
emissions
is
less
than
1
percent
for
2010
and
less
than
2
percent
for
2015).
These
comparisons
confirm
EPA's
belief
that
the
initial
IPM
run
very
closely
represents
the
final
CAIR
program.

The
IPM
output
files
for
the
model
runs
used
in
CAIR
analyses
are
available
in
the
CAIR
docket.
A
Technical
193
Support
Document
in
the
CAIR
docket
entitled
"
Modeling
of
Control
Costs,
Emissions,
and
Control
Retrofits
for
Cost
Effectiveness
and
Feasibility
Analyses"
further
explains
the
IPM
runs
used
in
the
analyses
for
section
IV
of
the
preamble.

2.
EPA's
Proposed
Methodology
to
Determine
Amounts
of
Emissions
that
Must
be
Eliminated
a.
Overview
of
EPA
Proposal
for
the
Levels
of
Reductions
and
Resulting
Caps,
and
their
Timing
In
the
NPR,
the
amounts
of
SO2
and
NOx
emissions
reductions
that
EPA
proposed
could
be
cost
effectively
eliminated
in
the
CAIR
region
in
2010
and
2015,
and
the
amount
of
the
proposed
EGU
emissions
caps
for
SO2
and
NOx
that
would
exist
if
all
affected
States
achieved
those
reductions
by
capping
EGU
emissions,
appear
in
Tables
IV­
1
and
IV­
2,
respectively.

Table
IV­
1.
­
Projected
SO2
and
NOx
Emission
Reductions
in
the
CAIR
Region
in
2010
and
2015
for
the
Proposed
Rule
(
Million
Tons)
1
Pollutant
2010
2015
SO2
3.6
3.7
NOx
1.5
1.8
1
CAIR
Notice
of
Proposed
Rulemaking
(
69
FR
4618,
January
30,

2004).
The
proposed
annual
SO2
and
NOx
caps
covered
a
28­
State
(
AL,
194
AR,
DE,
FL,
GA,
IL,
IN,
IA,
KS,
KY,
LA,
MD,
MA,
MI,
MN,
MI,
MO,
NJ,
NY,

NC,
OH,
PA,
SC,
TN,
TX,
VA,
WV,
WI)
plus
the
DC
region.
In
addition,
we
proposed
an
ozone­
season
only
cap
for
Connecticut.

TABLE
IV­
2.
­
Proposed
Annual
Electric
Generating
Unit
SO2
and
NOx
Emissions
Caps
in
the
CAIR
Region
(
Million
Tons)
1
Pollutant
2010
­
2014
2015
and
later
SO2
3.9
2.7
NOx
1.6
1.3
1
CAIR
Notice
of
Proposed
Rulemaking
(
69
FR
4618,
January
30,

2004).
The
proposed
annual
SO2
and
NOx
caps
covered
a
28­
State
(
AL,
AR,

DE,
FL,
GA,
IL,
IN,
IA,
KS,
KY,
LA,
MD,
MA,
MI,
MN,
MI,
MO,
NJ,
NY,
NC,

OH,
PA,
SC,
TN,
TX,
VA,
WV,
WI)
plus
the
DC
region.
In
addition,
we
proposed
an
ozone­
season
only
cap
for
Connecticut.

In
the
NPR,
EPA
evaluated
the
amounts
of
SO2
and
NOx
emissions
in
upwind
States
that
contribute
significantly
to
downwind
PM2.5
nonattainment
and
the
amounts
of
NOx
emissions
in
upwind
States
that
contribute
significantly
to
downwind
ozone
nonattainment.
That
is,
EPA
determined
the
amounts
of
emissions
reductions
that
must
be
eliminated
to
help
downwind
States
achieve
attainment,
by
applying
highly
cost­
effective
control
measures
to
EGUs
and
determining
the
emissions
reductions
that
would
result.
195
From
past
experience
in
examining
multi­
pollutant
emissions
trading
programs
for
SO2
and
NOx,
EPA
recognized
that
the
air
pollution
control
retrofits
that
result
from
a
program
to
achieve
highly
cost­
effective
reductions
are
quite
significant
and
can
not
be
immediately
installed.

Such
retrofits
require
a
large
pool
of
specialized
labor
resources,
in
particular,
boilermakers,
the
availability
of
which
will
be
a
major
limiting
factor
in
the
amount
and
timing
of
reductions.

Also,
EPA
recognized
that
the
regulated
industry
will
need
to
secure
large
amounts
of
capital
to
meet
the
control
requirements
while
managing
an
already
large
debt
load,
and
is
facing
other
large
capital
requirements
to
improve
the
transmission
system.
Furthermore,
allowing
pollution
control
retrofits
to
be
installed
over
time
enables
the
industry
to
take
advantage
of
planned
outages
at
power
plants
(
unplanned
outages
can
lead
to
lost
revenue)
and
to
enable
project
management
to
learn
from
early
installations
how
to
deal
with
some
of
the
engineering
challenges
that
will
exist,
especially
for
the
smaller
units
that
often
present
space
limitations.

Based
on
these
and
other
considerations,
EPA
determined
in
the
NPR
that
the
earliest
reasonable
deadline
for
compliance
with
the
final
highly
cost­
effective
control
196
levels
for
reducing
emissions
was
2015
(
taking
into
consideration
the
existing
bank
of
title
IV
SO2
allowances).

First,
the
Agency
confirmed
that
the
levels
of
SO2
and
NOx
emissions
it
believed
were
reasonable
to
set
as
annual
emissions
caps
for
2015
lead
to
highly
cost­
effective
controls
for
the
CAIR
region.

Once
EPA
determined
the
2015
emissions
reductions
levels,
the
Agency
determined
a
proposed
first
(
interim)

phase
control
level
that
would
commence
January
1,
2010,
the
earliest
the
Agency
believed
initial
pollution
controls
could
be
fully
operational
(
in
today's
final
action,
the
first
NOx
control
phase
commences
in
2009
instead
of
in
2010,
as
explained
in
detail
in
section
IV.
C).
The
first
phase
would
be
the
initial
step
on
the
slope
of
emissions
reductions
(
the
glide­
path)
leading
to
the
final
(
second)

control
phase
to
commence
in
2015.
The
EPA
determined
the
first
phase
based
on
the
feasibility
of
installing
the
necessary
emission
control
retrofits,
as
described
in
section
IV.
C.

Although
EPA's
primary
cost­
effectiveness
determination
is
for
the
2015
emissions
reductions
levels,
the
Agency
also
evaluated
the
cost
effectiveness
of
the
first
phase
control
levels
to
ensure
that
they
were
also
highly
cost
effective.

Throughout
this
preamble
section,
EPA
reports
both
the
2015
197
and
2010
(
and
2009
for
NOx)
cost­
effectiveness
results,

although
the
first
phase
levels
were
determined
based
on
feasibility
rather
than
cost
effectiveness.
The
2015
emissions
reductions
include
the
2010
(
and
2009
for
NOx)

emissions
reductions
as
a
subset
of
the
more
stringent
requirements
that
EPA
is
imposing
in
the
second
phase.

b.
Regulatory
History:
NOx
SIP
Call
In
the
NPR,
EPA
generally
followed
the
statutory
interpretation
and
approach
under
CAA
section
110(
a)(
2)(
D)

developed
in
the
NOx
SIP
Call
rulemaking.
Under
this
interpretation,
the
emissions
in
each
upwind
State
that
contribute
significantly
to
nonattainment
are
identified
as
being
those
emissions
that
can
be
eliminated
through
highly
cost­
effective
controls.

In
the
NOx
SIP
Call,
EPA
relied
primarily
on
the
application
of
highly
cost­
effective
controls
in
determining
the
amount
of
emissions
that
the
affected
States
were
required
to
eliminate.
Specifically,
EPA
developed
a
reference
list
of
the
average
cost
effectiveness
of
recently
promulgated
or
proposed
controls,
and
compared
the
cost
effectiveness
of
those
controls
to
the
cost
effectiveness
of
the
NOx
SIP
Call
controls
under
consideration.
In
addition,

EPA
considered
several
other
factors,
including
the
fact
that
downwind
nonattainment
areas
had
already
implemented
198
ozone
controls
but
upwind
areas
generally
had
not,
the
fact
that
some
otherwise
required
local
controls
would
be
less
cost­
effective
than
the
regional
controls,
and
the
overall
ambient
effects
of
the
reductions
required
in
the
NOx
SIP
Call
(
63
FR
57399­
57403;
October
27,
1998).

i.
Highly
Cost­
effective
Controls
In
the
NOx
SIP
Call,
EPA
presented
control
costs
in
1990
dollars
(
1990$).
For
the
electric
power
industry,

these
expenditures
were
the
increase
in
annual
electric
generation
production
costs
in
the
control
region
that
result
from
the
rule.
In
the
CAIR
NPR,
SNPR,
and
today's
final
action,
EPA
presents
the
same
type
of
electric
generation
as
well
as
other
costs
in
1999$,
and
rounds
all
values
related
to
the
cost
per
ton
of
air
emissions
controls
to
the
nearest
100
dollars.

In
the
NOx
SIP
Call,
EPA's
decision
on
the
amount
of
required
NOx
emissions
reductions
was
that
this
amount
must
be
computed
on
the
assumption
of
implementing
highly
costeffective
controls.
The
determination
of
what
constituted
highly
cost
effective
controls
was
described
as
a
two­
part
process:
(
1)
the
setting
of
a
dollar­
limit
upper
bound
of
highly
cost­
effective
emissions
reductions;
and
(
2)
a
determination
of
what
level
of
control
below
this
upperbound
was
appropriate
based
upon
achievability
and
other
199
factors.

With
respect
to
setting
the
upper
bound
of
potential
highly
cost­
effective
controls,
EPA
determined
this
level
on
the
basis
of
average
cost
effectiveness
(
the
average
cost
per
ton
of
pollutant
removed).
The
EPA
explained
that
it
relied
on
average
cost
effectiveness
for
two
reasons:

Since
EPA's
determination
for
the
core
group
of
sources
is
based
on
the
adoption
of
a
broad­
based
trading
program,
average
cost
effectiveness
serves
as
an
adequate
measure
across
sources
because
sources
with
high
marginal
costs
will
be
able
to
take
advantage
of
this
program
to
lower
their
costs.
In
addition,

average
cost­
effectiveness
estimates
are
readily
available
for
other
recently
adopted
NOx
control
measures
(
63
FR
57399).

At
that
time,
EPA
acknowledged
that
average
cost
effectiveness
did
not
directly
address
the
fact
that
certain
units
might
have
higher
costs
relative
to
the
average
cost
of
reduction
(
e.
g.,
units
with
lower
capacity
factors
tend
to
have
higher
costs):

[
I]
ncremental
cost
effectiveness
helps
to
identify
whether
a
more
stringent
control
option
imposes
much
higher
costs
relative
to
the
average
cost
per
ton
for
200
further
control.
The
use
of
an
average
cost
effectiveness
measure
may
not
fully
reveal
costly
incremental
requirements
where
control
options
achieve
large
reductions
in
emissions
(
relative
to
the
baseline)
(
63
FR
57399).

Examination
of
marginal
cost
effectiveness
 
which
examines
what
the
cost
would
be
of
the
next
ton
of
reduction
after
the
defined
control
level
 
would
fill
this
gap.

However,
for
the
NOx
SIP
Call
rulemaking,
adequate
information
concerning
marginal
cost
effectiveness
was
not
available.

For
the
NOx
SIP
Call,
to
determine
the
average
cost
effectiveness
that
should
be
considered
to
be
highly
cost
effective,
EPA
developed
a
"
reference
list"
of
NOx
emissions
controls
that
are
available
and
of
comparable
cost
to
other
recently
undertaken
or
planned
NOx
measures.
The
EPA
explained
that
"
the
cost
effectiveness
of
measures
that
EPA
or
States
have
adopted,
or
proposed
to
adopt,
forms
a
good
reference
point
for
determining
which
of
the
available
additional
NOx
control
measures
can
most
easily
be
implemented
by
upwind
States
whose
emissions
impact
downwind
nonattainment
problems."
(
63
FR
57400).
The
EPA
explained
201
that
the
measures
on
the
reference
list
had
already
been
implemented
or
were
planned
to
be
implemented,
and
therefore
could
be
assumed
to
be
less
expensive
than
other
measures
to
be
implemented
in
the
future.
The
EPA
found
that
the
costs
of
the
measures
on
the
reference
list
approached
but
were
below
$
2,000
per
ton
(
1990$).
The
EPA
concluded
that
"
controls
with
an
average
cost
effectiveness
[
of]
less
than
$
2,000
[
1990$,
or
$
2,500
(
1999$)]
per
ton
of
NOx
removed
[
should
be
considered]
to
be
highly
cost­
effective."
(
63
FR
57400).
Notably,
the
reference
costs
were
taken
from
the
supporting
analyses
used
for
the
regulatory
actions
covering
the
NOx
pollution
controls
 
they
are
what
regulatory
decision
makers
and
the
public
believed
were
the
control
costs.

Mindful
of
this
$
2,000
limit
[
1990$,
or
$
2,500
(
1999$)],
EPA
considered
a
control
level
that
would
have
resulted
in
estimated
average
costs
of
approximately
$
1,800
(
1990$)
per
ton.
However,
EPA
concluded
that
because
the
corresponding
level
of
controls
 
nominally
a
0.12
lb/
mmBtu
control
level
 
was
not
well
enough
established,
EPA
was
"
not
as
confident
about
the
robustness"
of
the
cost
estimates.
Moreover,
EPA
expressed
concern
that
its
"
level
of
comfort"
was
not
as
high
as
it
would
have
liked
that
the
nominal
0.12
lb/
mmBtu
control
level
"
will
not
lead
to
202
installation
of
SCR
technology
at
a
level
and
in
a
manner
that
will
be
difficult
to
implement
or
result
in
reliability
problems
for
electric
power
generation"
(
63
FR
57401).

Accordingly,
EPA
selected
the
next
control
level
that
it
had
evaluated
 
a
nominal
0.15
lb/
mmBtu
level
 
which
would
result
in
an
average
cost
of
approximately
$
1,500
[
1990$,
or
$
1,900
(
1999$)]
per
ton.
The
EPA
determined
that
this
control
level
did
not
present
the
uncertainty
concerns
associated
with
the
0.12
level.
The
EPA
added,
in
this
1998
rule:
"
With
a
strong
need
to
implement
a
program
by
2003
that
is
recognized
by
the
States
as
practical,
necessary,

and
broadly
accepted
as
highly
cost­
effective,
the
Agency
has
decided
to
base
the
emissions
budgets
for
EGUs
on
a
0.15
...
level."
(
63
FR
57401
­
57402).
The
EPA
summarized
its
approach
as
determining
"
the
required
emission
levels
...

based
on
the
application
of
NOx
controls
that
achieve
the
greatest
feasible
emissions
reduction
while
still
falling
within
a
cost­
per­
ton
reduced
range
that
EPA
considers
to
be
highly
cost­
effective...."
(
63
FR
57399).

The
bulk
of
the
cost
for
reducing
NOx
emissions
for
EGUs
is
in
the
capital
investment
in
the
control
equipment,

which
would
be
the
same
whether
controls
are
installed
for
ozone
season
only,
or
for
annual
controls.
The
increased
costs
to
run
the
equipment
annually
instead
of
only
in
the
203
ozone
season
is
relatively
small.
Although
the
NOx
SIP
Call
is
an
ozone
season
NOx
reduction
program,
most
of
the
NOx
control
costs
on
the
reference
list
are
for
annual
reductions.
If
the
NOx
SIP
Call
were
an
annual
program
instead
of
seasonal,
its
average
control
costs
would
be
lower,
relative
to
the
annual
control
costs
in
the
reference
list.

ii.
Other
Factors
In
the
NOx
SIP
Call,
although
considering
air
quality
and
cost
to
be
the
primary
factors
for
determining
significant
contribution,
EPA
identified
several
other
factors
that
it
generally
considered.
As
one
factor,
EPA
reviewed
"
overall
considerations
of
fairness
related
to
the
control
regimes
required
of
the
downwind
and
upwind
areas,"

particularly,
the
fact
that
the
major
urban
nonattainment
areas
in
the
East
had
implemented
controls
on
virtually
all
portions
of
their
inventory
of
ozone
precursors,
but
upwind
sources
had
not
implemented
reductions
intended
to
reduce
their
impacts
downwind
(
63
FR
57404).

As
another
factor,
EPA
generally
considered
"
the
cost
effectiveness
of
additional
local
reductions
in
the
...

ozone
nonattainment
areas."
The
EPA
included
in
the
record
information
that
nationally,
on
average,
additional
local
measures
would
cost
more
than
the
cost
of
the
upwind
204
controls
required
under
the
NOx
SIP
Call.
This
consideration
further
indicated
that
the
regional
controls
under
the
NOx
SIP
Call
were
highly
cost
effective
(
63
FR
57404).

In
addition,
EPA
conducted
air
quality
modeling
to
determine
the
impact
of
the
controls,
and
found
that
they
benefitted
the
downwind
areas
without
being
more
than
necessary
for
those
areas
to
attain
(
63
FR
57403
­
57404).

c.
Proposed
Criteria
for
Emissions
Reduction
Requirements
i.
General
Criteria
In
the
CAIR
NPR,
EPA
proposed
criteria
for
determining
the
appropriate
levels
of
annual
emissions
reductions
for
SO2
and
NOx
and
ozone­
season
emissions
reductions
for
NOx.

The
EPA
stated
that
it
considers
a
variety
of
factors
in
evaluating
the
source
categories
from
which
highly
cost­
effective
reductions
may
be
available
and
the
level
of
reduction
assumed
from
that
sector.
These
include:


the
availability
of
information,


the
identification
of
source
categories
emitting
relatively
large
amounts
of
the
relevant
emissions,


the
performance
and
applicability
of
control
measures,


the
cost
effectiveness
of
control
measures,
and

engineering
and
financial
factors
that
affect
the
availability
of
control
measures
(
69
FR
4611).
205
53
U.
S.
Environmental
Protection
Agency,
Office
of
Air
and
Radiation,
EPA's
Clean
Air
Power
Initiative,
October
1996.
Further,
EPA
stated
that
overall,
"
We
are
striving
...

to
set
up
a
reasonable
balance
of
regional
and
local
controls
to
provide
a
cost­
effective
and
equitable
governmental
approach
to
attainment
with
the
NAAQS
for
fine
particles
and
ozone."
(
69
FR
4612)

The
EPA
has
used
these
types
of
criteria
in
a
number
of
efforts
to
develop
regional
and
national
strategies
to
reduce
interstate
transport
of
SO2
and
NOx.
Starting
in
1996,
EPA
performed
analysis
and
engaged
in
dialogue
with
power
companies,
States,
environmental
groups
and
other
interested
groups
in
the
Clean
Air
Power
Initiative
(
CAPI).
53
In
that
study
of
national
emission
reduction
strategies,
EPA
initially
considered
an
emissions
cap
based
on
a
50
percent
reduction
in
SO2
emissions
from
title
IV
levels
(
i.
e.,
4.5
million
tons
nationwide)
in
2010.
For
NOx,
EPA
initially
looked
at
ozone
season
and
non­
ozone
season
caps.
Commencing
in
2000,
the
ozone
season
emissions
cap
would
be
based
on
an
emission
rate
of
0.20
lb/
mmBtu,
and
in
2005,
the
ozone
season
cap
would
be
reduced
to
a
level
based
on
0.15
lb/
mmBtu
(
these
cap
levels
would
be
similar
to
the
phased
caps
adopted
by
the
Ozone
Transport
Commission
(
OTC)
States).
The
non­
ozone
season
cap
would
be
based
on
206
54
U.
S.
Environmental
Protection
Agency,
Office
of
Air
and
Radiation,
Analysis
of
Emission
Reduction
Options
for
the
Electric
Power
Industry,
March
1999.

55
EPA's
Clear
Skies
Act
analysis
is
on
the
web
at:
www.
epa.
gov/
air/
clearskies/
technical.
html.
the
proposed
title
IV
phase
II
NOx
rule.
The
EPA
also
considered
other
options
in
the
CAPI
study,
including
setting
NOx
caps
based
on
emission
rates
of
0.20
lb/
mmBtu
and
0.25
lb/
mmBtu;
setting
NOx
caps
based
on
rates
of
0.15
lb/
mmBtu
and
0.20
lb/
mmBtu
but
lowering
the
SO2
allowance
cap
by
60
percent
instead
of
50
percent;
and,
keeping
a
NOx
cap
based
on
a
rate
of
0.15
lb/
mmBtu
but
lowering
the
SO2
allowance
cap
by
50
percent
in
2005
instead
of
in
2010.

The
EPA
did
a
follow­
up
study
in
1999
and
discussed
those
results
with
various
stakeholder
groups,
as
well.
54
That
study
considered
a
variety
of
SO2
emission
caps
ranging
from
a
40
percent
reduction
from
title
IV
cap
levels
in
2010
to
a
55
percent
reduction
from
title
IV
cap
levels
in
2010.

The
1999
study
did
not
consider
additional
reductions
in
NOx
emissions
beyond
those
required
under
the
NOx
SIP
Call.

In
the
last
several
years,
EPA
has
performed
significant
additional
analysis
in
support
of
the
proposed
Clear
Skies
Act.
55
That
legislation,
proposed
in
2002
and
2003,
would
include
nationwide
SO2
caps
of
4.5
million
tons
in
2010
and
3.0
million
tons
in
2018
(
i.
e.,
50
percent
and
67
percent
reductions
from
title
IV
cap
levels).
The
Clear
207
Skies
Act
also
includes
a
two­
phase,
two­
zone
NOx
emission
cap
program,
with
the
first
phase
in
2008
and
the
second
phase
in
2018.
In
the
2003
legislation,
the
first
phase
NOx
caps
would
result
in
effective
NOx
emissions
rates
of
0.16
lb/
mmBtu
in
the
east
and
0.20
lb/
mmBtu
in
the
west,
and
the
second
phase
would
result
in
effective
emission
rates
of
0.12
lb/
mmBtu
in
the
east
and
0.20
lb/
mmBtu
in
the
west.

ii.
Reliance
on
Average
and
Marginal
Cost
Effectiveness
In
the
CAIR
NPR,
EPA
supported
the
conclusion
that
its
emissions
caps
are
highly
cost
effective
based
upon
"(
1)

comparison
to
the
average
cost
effectiveness
of
other
regulatory
actions
and
(
2)
comparison
to
the
marginal
cost
effectiveness
of
other
regulatory
actions."
(
69
FR
4585).

We
supplemented
these
comparisons
of
cost­
effectiveness
tables
with
an
auxiliary
evaluation
of
the
marginal
costs
curves,
which
allowed
us
to
show
that
the
selected
control
levels
would
be
"
below
the
point
at
which
there
would
be
significant
diminishing
returns
on
the
dollars
spent
for
pollution
control."
(
69
FR
4614).

Although
in
the
NOx
SIP
Call,
EPA
based
the
required
controls
on
average
cost
alone,
in
today's
rule,
EPA
uses
both
average
and
marginal
costs,
including
an
evaluation
of
the
marginal
cost
curves.
At
the
time
of
the
NOx
SIP
Call,

marginal
cost
information
was
not
as
readily
available.
208
Today,
such
information
is
available
for
both
SO2
and
NOx
controls,
although
marginal
cost
information
remains
more
limited
and
EPA
has
had
to
specifically
develop
marginal
cost
estimates
for
use
in
this
rulemaking.

Marginal
costs
are
a
useful
measure
of
cost
effectiveness
because
they
indicate
how
much
any
additional
level
of
control
at
the
margin
will
cost
relative
to
other
actions
that
are
available.
Using
both
average
and
marginal
control
costs,
provides
a
more
complete
picture
of
the
costs
of
controls
than
using
average
costs
alone.
Average
costs
provide
a
means
for
a
straightforward
comparison
between
the
CAIR
and
other
emissions
reductions
programs
for
which
average
costs
are
generally
the
only
type
of
costs
available.
Where
marginal
cost
information
is
available,
it
enables
EPA
to
compare
the
costs
of
the
CAIR
at
the
stringency
level
being
considered
to
the
costs
of
the
last
increment
of
control
in
other
programs.
Moreover,

evaluation
of
marginal
cost
curves
allows
us
to
corroborate
that
the
selected
level
of
stringency
of
the
selected
program
stops
short
of
the
point
where
the
returns
begin
to
diminish
significantly.

Projected
marginal
cost
information
for
controlling
emissions
from
EGUs
is
now
available
for
some
State
programs,
because
EPA
includes
the
programs
in
its
base
case
209
power
sector
modeling
using
the
IPM
to
develop
the
incremental
costs
of
electricity
production
for
the
CAIR.

Marginal
EGU
control
costs
from
State
programs
modeled
using
the
IPM
were
compared
to
projected
marginal
EGU
control
costs
under
the
CAIR,
as
discussed
in
more
detail
below.

3.
What
Are
the
Most
Significant
Comments
that
EPA
Received
about
its
Proposed
Methodology
for
Determining
the
Amounts
of
SO2
and
NOx
Emissions
that
Must
Be
Eliminated,

and
What
Are
EPA's
Responses?

Some
commenters
took
issue
with
EPA's
reliance
on
cost­
per­
ton­
of­
emissions­
reductions
as
the
metric
for
determining
cost
effectiveness.
These
commenters
observed
that
this
metric
does
not
take
into
account
that
any
given
ton
of
pollutant
reduction
may
have
different
impacts
on
ambient
concentration
and
human
exposure.
Some
of
these
commenters
advocated
use
of
a
metric
based
on
cost
per
unit
of
pollutant
concentration
reduced.
Another
stated
that
EPA
should
account
for
cost
effectiveness
based
on
geographical
location
relative
to
the
area
of
nonattainment.

Still
other
commenters
took
a
contrasting
view.
They
argued
that
a
metric
based
on
cost­
per­
ambient­
impact
might
be
useful
in
justifying
control
cost
effectiveness
for
source
categories
within
an
individual
nonattainment
area
as
part
of
an
attainment
SIP,
but
not
for
evaluating
costs
of
controlling
long­
range
transport.
These
commenters
stated
that
it
is
impractical
to
calculate
cost
effectiveness
of
210
control
on
the
basis
of
cost
per
unit
reduction
in
ambient
concentration.
One
queried:
"
Where
would
the
ambient
reduction
be
measured?
100
miles
downwind?
1,500
miles
downwind?"

The
EPA
agrees
that
optimally,
the
cost­
per­
ambient­
impact
of
controls
could
play
a
major
role
in
determining
upwind
control
obligations
(
although
equitable
considerations
and
other
factors
identified
in
the
NOx
SIP
Call
rulemaking
and
today's
action
may
also
play
a
role).
The
EPA
recognized
the
potential
importance
of
this
factor
during
the
NOx
SIP
Call
rulemaking
and
endeavored
to
develop
technical
information
to
support
it.
However,
in
that
rulemaking,
EPA
was
not
able
to
develop
an
approach
to
quantify,
with
sufficient
accuracy,
cost­
per­
ambient
impact
because
the
NOx
SIP
Call
region
was
large
B
covering
approximately
half
of
the
continental
U.
S.
and
including
approximately
half
the
States
B
and
many
upwind
States
with
different
emissions
inventories
had
widely
varied
impacts
on
many
different
nonattainment
areas
downwind.

This
problem
B
the
complexity
of
the
task
and
the
dearth
of
analytic
tools
B
remains
today
for
both
PM2.5
and
8­
hour
ozone
regional
transport.
Not
surprisingly,
no
commenter
presented
to
EPA
the
analytic
tools,
which
we
would
expect
would
consist
of
a
complex,
computerized
program
that
could
integrate,
on
a
State­
by­
State
basis,

both
control
costs
and
ambient
impacts
by
each
State
on
each
211
of
its
downwind
receptors
under
the
CAIR
control
scenario.

In
the
absence
of
a
scientifically
defensible,

practicable
method
for
implementing
a
program
design
approach
based
on
the
cost­
per­
ambient­
impact
of
emissions
reductions,
EPA
is
not
able
to
employ
such
an
approach.

However,
EPA
believes
it
appropriate
to
continue
to
examine
ways
to
develop
such
an
approach
for
future
use.

A
few
commenters
suggested
that
EPA
should
use
a
cost­
benefit
analysis
for
determining
reduction
levels.
One
noted
that
cost­
benefit
analysis
can
help
find
the
reduction
levels
that
maximize
societal
net
benefit
(
benefits
minus
costs),
and
suggested
the
Agency
should
compare
the
marginal
cost
of
each
ton
of
pollutant
reduced
to
the
marginal
benefit
achieved,
as
well
as
compare
the
total
costs
to
the
total
benefits.
Another
stated
that
an
optimal
allocation
of
resources
is
where
the
marginal
cost
equals
the
marginal
benefit,
and
observed
that
comparing
the
average
cost
to
the
average
benefit
of
the
controls
proposed
in
the
CAIR
NPR
yields
an
average
benefit
significantly
higher
than
the
average
cost.
This
commenter
concluded
that
EPA
should
require
controls
beyond
the
controls
described
in
the
NPR
as
highly
cost
effective.

Although
EPA
strongly
agrees
that
examination
of
costs
and
benefits
is
very
useful,
in
today's
rulemaking,
EPA
does
not
interpret
CAA
section
110(
a)(
2)(
D)
to
base
the
amount
of
212
emissions
reductions
on
benefits
other
than
progress
towards
attainment
of
the
PM2.5
or
the
8­
hour
ozone
NAAQS.
The
EPA's
interpretation
does,
however,
use
cost
effectiveness
per
ton
of
pollutant
reduced,
and
we
are
using
that
analytic
tool
for
setting
SO2
and
NOx
emission
reduction
requirements.
Additionally,
EPA
has
prepared
a
cost­
benefit
analysis
to
inform
the
Agency
and
public
of
the
many
other
important
impacts
of
this
rulemaking.

A
few
commenters
suggested
that
the
Agency
should
set
its
NOx
and
SO2
reduction
requirements
based
on
Best
Available
Control
Technology
(
BACT)
emission
rates
for
EGUs.

Although
not
clearly
stated,
the
commenters
appear
to
suggest
BACT
level
controls
for
both
existing
and
new
units.

The
emission
reduction
requirements
that
EPA
determined
are
based
on
the
application
of
highly
cost­
effective
controls
that
are
a
step
that
the
Agency
is
taking
at
this
time
to
eliminate
emissions
that
contribute
significantly
to
nonattainment
of
the
ozone
and
fine
particle
NAAQS.
As
explained
elsewhere,
this
step
is
reasonable
in
light
of
the
current
status
of
implementation
for
those
NAAQS.

Basing
emission
reduction
requirements
on
a
presumption
of
BACT
emission
rates
across
the
board
would
require
scrubbers
and
SCRs
on
all
coal­
fired
units
and
SCRs
on
all
gas­
fired
and
oil­
fired
units.
The
cost
of
these
213
controls
would
vary
considerably
from
source
to
source,
be
expensive
for
many
sources,
and
may
cause
substantial
fuel
switching
to
natural
gas
and
closure
of
smaller
coal­
fired
units.
Having
considered
this
suggestion
for
deeper
regional
reductions
that
would
not
be
as
cost
effective
as
the
highly
cost­
effective
reductions
in
today's
rule,
EPA
believes
that
a
more
tailored
approach,
such
as
the
CAIR
level
control
as
well
as
local
controls
under
SIPs
(
where
necessary),
is
a
more
reasonable
approach
to
achieving
the
level
of
ambient
improvement
needed
for
attainment
throughout
the
United
States.

4.
EPA's
Evaluation
of
Highly
Cost­
Effective
SO2
and
NOx
Emissions
Reductions
Based
on
Controlling
EGUs
a.
SO2
Emissions
Reductions
Requirements
i.
CAIR
Proposal
for
SO2
The
NPR
focused
primarily
on
determining
highly
costeffective
amounts
of
emissions
reductions
based
on,
as
in
the
NOx
SIP
Call,
comparison
to
reference
lists
of
the
cost
effectiveness
of
other
regulatory
controls.
In
the
NPR,
EPA
developed
reference
lists
for
both
the
average
cost
effectiveness
and
the
marginal
cost
effectiveness
of
those
other
controls.
These
reference
lists
indicated
that
the
average
annual
costs
per
ton
of
SO2
removed
ranged
from
$
500
to
$
2,100;
and
marginal
costs
of
SO2
removal
ranged
from
214
$
800
to
$
2,200.

Moreover,
EPA
further
considered
the
cost
effectiveness
of
alternative
stringency
levels
for
this
regulatory
proposal.
That
is,
EPA
examined
changes
in
the
marginal
cost
curve
at
varying
levels
of
emissions
reductions.
The
EPA
determined
in
the
NPR
that
the
"
knee"
in
the
marginal
cost­
effectiveness
curve
­
the
point
at
which
the
marginal
cost
per
ton
of
SO2
removed
begins
to
increase
at
a
noticeably
higher
rate
 
appears
to
start
above
$
1,200
per
ton
(
69
FR
4613
­
4615).

In
the
NPR,
EPA
then
provided
further
analysis
of
a
two­
phase
SO2
reduction
program.
The
final
(
second)
phase,

in
2015,
would
reduce
SO2
emissions
in
the
CAIR
region
by
the
amount
that
results
from
making
a
65
percent
reduction
from
the
title
IV
Phase
II
allowance
levels
(
taking
into
consideration
the
existing
bank
of
title
IV
SO2
allowances).

The
first
phase,
in
2010,
would
reduce
SO2
emissions
in
the
CAIR
region
by
a
lesser
amount,
i.
e.,
a
50
percent
reduction
from
title
IV
Phase
II
allowance
levels
(
again,
taking
into
consideration
the
banked
title
IV
SO2
allowances).
The
EPA
developed
this
target
SO2
control
level
for
further
evaluation
because,
based
on
all
of
the
earlier
work
performed
on
multi­
pollutant
power
plant
reduction
programs
and
general
consideration,
with
technical
support,
of
215
overall
emissions
reductions,
costs
to
industry
and
the
general
public,
ambient
improvement,
and
consistency
with
the
emerging
PM2.5
implementation
program,
we
believed
it
would
meet
the
criteria
set
forth
above.

Then,
EPA
conducted
cost
analyses
of
this
control
level
using
the
IPM
as
well
as
additional
analysis
of
the
implications
of
this
control
level
to
determine
if
it
did
indeed
meet
those
criteria.
The
IPM
analysis
considered
the
increase
in
annual
electric
generation
production
costs
in
the
CAIR
region
that
result
from
the
rule.
The
EPA
evaluated
the
cost
effectiveness
of
the
final
phase
(
2015)

cap
to
determine
if
it
is
highly
cost
effective;
and,
we
also
evaluated
the
cost
effectiveness
of
the
2010
cap.
The
EPA
used
the
IPM
to
estimate
cost
effectiveness
of
the
CAIR
in
the
future.
The
IPM
incorporates
projections
of
future
electricity
demand,
and
thus
heat
input
growth.
The
EPA's
IPM
analyses
for
the
CAIR
includes
all
fossil
fuel­
fired
EGUs
with
capacity
greater
than
25
MW.
A
description
of
the
IPM
is
included
elsewhere
in
this
preamble,
and
a
detailed
model
documentation
is
in
the
docket.

The
SO2
annual
control
costs
that
were
presented
in
the
CAIR
NPR
were
average
costs
of
$
700
per
ton
and
$
800
per
ton
for
years
2010
and
2015,
respectively,
and
marginal
costs
of
$
700
per
ton
and
$
1,000
per
ton
for
years
2010
and
2015.
In
216
addition,
the
NPR
included
the
results
of
sensitivity
analyses
that
examined
costs
of
the
proposed
SO2
controls
based
on
the
Energy
Information
Administration's
projections
for
electricity
growth
and
natural
gas
prices.
These
sensitivity
analyses
showed
marginal
SO2
control
costs
of
$
900
per
ton
and
$
1,100
per
ton
for
years
2010
and
2015,

respectively.
The
EPA
proposed
to
consider
the
SO2
emissions
reductions
proposed
in
the
NPR
as
highly
cost
effective
because
they
were
consistent
with
the
lower
end
of
the
reference
list
range
of
cost
per
ton
of
SO2
reduction
for
controls
on
both
an
average
and
a
marginal
cost
basis
(
69
FR
4613
­
4615).

ii.
Analysis
of
SO2
Emission
Reduction
Requirements
for
Today's
Final
Rule
(
I)
Reference
Lists
of
Cost­
Effective
SO2
Controls
For
today's
action,
EPA
updated
the
reference
list
of
controls
included
in
the
NPR
of
the
average
and
marginal
costs
per
ton
of
recent
SO2
control
actions.
The
EPA
systematically
developed
a
list
of
cost
information
from
both
recent
actions
and
proposed
actions.
The
EPA
compiled
cost
information
for
actions
taken
by
the
Agency,
and
examined
the
public
comments
submitted
after
the
NPR
was
published,
to
identify
all
available
control
cost
information
to
provide
the
updated
reference
list
for
217
6
The
updated
reference
list
includes
estimated
average
costs
for
SO2
reductions
from
EGUs
under
best
available
retrofit
technology
(
BART)
requirements.
The
BART
rule
was
proposed
and
has
not
been
finalized
(
69
FR
25184;
May
5,
2004).
today's
preamble.
The
updated
reference
list
includes
both
average
and
marginal
costs
of
control,
to
which
EPA
compares
the
CAIR
control
costs,
and
the
list
represents
what
regulatory
decision
makers
and/
or
the
public
believes
are
the
control
costs.
56
Table
IV­
3
provides
average
costs
of
SO2
controls.

This
table
includes
average
costs
for
recent
BACT
permitting
decisions
for
SO2.
Under
EPA's
New
Source
Review
(
NSR)

program,
if
a
company
is
planning
to
build
a
new
plant
or
modify
an
existing
plant
such
that
a
significant
net
increase
in
emissions
will
occur,
the
company
must
obtain
a
NSR
permit
that
addresses
controls
for
air
emissions.
BACT
is
the
type
of
control
required
by
the
NSR
program
for
existing
sources
in
attainment
areas.
The
BACT
decisions
are
determined
on
a
case­
by­
case
basis,
usually
by
State
or
local
permitting
agencies,
and
reflect
consideration
of
average
and
incremental
cost
effectiveness.
These
decisions
are
relevant
for
EPA's
reference
list
of
average
costs
of
SO2
controls,
because
they
represent
cost­
effective
controls
that
have
been
demonstrated.

Table
IV­
3.
Average
Costs
per
Ton
of
Annual
SO2
Controls
218
SO
2
Control
Action
Average
Cost
per
Ton
Best
Available
Control
Technology
(
BACT)
Determinations
$
400
B
$
2,100
1
Nonroad
Diesel
Engines
and
Fuel
$
800
2
Proposed
Best
Available
Retrofit
Technology
(
BART)
for
Electric
Power
Sector
$
2,600
­
$
3,400
3
1
These
numbers
reflect
a
range
of
cost­
effectiveness
data
entered
into
EPA's
RACT/
BACT/
LAER
Clearinghouse
(
RBLC)
for
add­
on
SO2
controls
(
www.
epa.
gov/
ttn/
catc/).
We
identified
actions
in
the
data
base
for
large,
utility­
scale,
coal­
fired
boiler
units
for
which
cost
effectiveness
data
were
reported.
The
range
of
costs
shown
here
is
for
boilers
ranging
from
30
MW
to
an
estimated
790
MW
(
we
used
a
conversion
factor
of
10
mmBtu/
hr
=
1
MW
for
units
for
which
size
was
reported
in
mmBtu/
hr).
Emission
limits
for
these
actions
ranged
from
0.10
lb/
mmBtu
to
0.27
lb/
mmBtu.
Add­
on
controls
reported
for
these
units
are
dry
or
wet
scrubbers
(
in
one
case
with
added
alkali
and
in
one
case
with
a
baghouse).
Where
the
dollar­
year
was
not
reported
we
assumed
1999
dollars.
The
cost
range
presented
in
the
NPR
was
$
500
­
$
2,100
B
today's
range
includes
additional
BACT
costs
that
were
entered
into
the
clearinghouse
after
the
NPR
was
published.
2
Control
of
Emissions
of
Air
Pollution
From
Nonroad
Diesel
Engines
and
Fuel;
Final
Rule
(
69
FR
39131;
June
29,
2004).
The
value
in
this
table
represents
the
long­
term
cost
per
ton
of
emissions
reduced
from
the
total
fuel
and
engine
program
(
cost
per
ton
of
emissions
reduced
in
the
year
2030).
1999$
per
ton.
3
The
EPA
IPM
modeling
2004,
available
in
the
docket.
The
EPA
modeled
the
Regional
Haze
Requirements
as
source
specific
limits
(
90
percent
SO2
reduction
or
0.1
lb/
mmBtu
rate;
except
the
five
state
WRAP
region
for
which
we
did
not
model
SO2
controls
beyond
what
is
done
for
the
WRAP
cap
in
the
base
case
modeling).
Estimated
average
costs
based
on
this
modeling
are
$
2,600
per
ton
in
2015
and
$
3,400
per
ton
in
2020.
1999$
per
ton.

Table
IV­
4
provides
the
marginal
cost
per
ton
of
recent
State
and
regional
decisions
for
annual
SO2
controls.

Table
IV­
4.
Marginal
Costs
per
Ton
of
Annual
SO2
Controls
SO
2
Control
Action
Marginal
Cost
per
Ton
New
Hampshire
Rule
$
600
1
WRAP
Regional
SO
2
Trading
Program
$
1,100
B
$
2,200
2
1
The
EPA
IPM
Base
Case
modeling
August
2004,
available
in
the
docket.
(
1999$
per
ton).
We
modeled
New
Hampshire's
State
Bill
ENV­
A2900,
which
caps
SO2
emissions
at
all
existing
fossil
steam
units.
2
"
An
Assessment
of
Critical
Mass
for
the
Regional
SO
2
Trading
Program,"
prepared
for
Western
Regional
Air
Partnership
Market
Trading
Forum
by
ICF
Consulting
Group,
September
27,
2002,
available
in
the
docket.
This
analysis
looked
at
the
implications
of
one
or
more
States
choosing
to
opt­
out
of
the
WRAP
regional
SO
2
trading
program.
(
1999$
per
ton)
219
(
II)
Cost
Effectiveness
of
the
CAIR
Annual
SO2
Reductions
In
the
NPR,
EPA
evaluated
an
annual
SO2
control
strategy
based
on
a
specified
level
of
emissions
reductions
from
EGUs.
Available
information
indicated
that
emissions
reductions
from
this
industry
would
be
the
most
cost
effective.
(
As
noted
elsewhere,
EPA
considered
control
strategies
for
other
source
categories,
but
concluded
that
they
would
not
qualify
as
highly
cost­
effective
controls.)

Of
course,
under
today's
rule,
although
EPA
calculates
the
amount
of
emissions
reductions
States
must
achieve
by
evaluation
of
the
EGU
control
strategy,
States
remain
free
to
achieve
those
reductions
by
implementing
controls
on
any
sources
they
wish.

For
today's
action,
EPA
updated
the
predicted
annual
SO2
control
costs
included
in
the
NPR.
The
EPA
analyzed
the
costs
of
the
CAIR
using
an
updated
version
of
the
IPM
(
documentation
for
the
IPM
update
is
in
the
docket).

Further,
EPA
modified
the
modeling
to
match
the
final
CAIR
strategy
(
see
section
IV.
A.
1
for
a
description
of
EPA's
CAIR
IPM
modeling).

The
EPA
also
updated
its
analysis
of
the
sensitivity
of
the
marginal
cost
results
to
assumptions
of
higher
electric
growth
and
natural
gas
prices
than
we
used
in
the
base
case.
These
sensitivity
analyses
were
based
on
the
220
7
The
EPA
used
the
difference
between
EIA's
estimates
for
well­
head
natural
gas
prices
and
minemouth
coal
prices
to
determine
the
sensitivity
of
IPM's
results
to
higher
natural
gas
prices.
The
EPA
describes
this
sensitivity
analysis
as
"
EIA
natural
gas
prices".
For
electric
demand,
we
replaced
EPA's
assumed
annual
growth
of
1.6
percent
with
EIA's
projection
of
annual
growth
of
1.8
percent.
Energy
Information
Administration's
Annual
Energy
Outlook
for
2004.57
In
determining
whether
our
control
strategy
is
highly
cost
effective,
EPA
believes
it
is
important
to
account
for
the
variable
levels
of
cost
effectiveness
that
these
sensitivity
analyses
indicate
may
occur
if
electricity
demand
or
natural
gas
prices
are
appreciably
higher
than
assumed
in
the
IPM.
Those
two
factors
are
key
determinants
of
control
costs
and,
over
the
relatively
long
implementation
period
provided
under
today's
action,
a
meaningful
degree
of
risk
arises
that
these
factors
may
well
vary
to
the
extent
indicated
by
the
sensitivity
analyses.

As
a
result,
EPA
wanted
to
examine
the
marginal
costs
that
would
occur
under
the
scenarios
modeled
in
the
sensitivity
analyses
to
see
how
they
differed
from
the
costs
using
EPA's
assumptions.

Table
IV­
5
provides
the
average
and
marginal
costs
of
annual
SO2
reductions
under
the
CAIR
for
2010
and
2015.

(
When
presenting
estimated
CAIR
control
costs
in
section
IV
of
this
preamble,
EPA
uses
"
Main
Case"
to
indicate
the
221
primary
CAIR
IPM
analyses,
as
differentiated
from
other
IPM
analyses
such
as
sensitivity
runs
used
to
examine
the
impacts
of
varying
assumptions
about
natural
gas
price
and
electric
growth.)

Table
IV­
5.
Estimated
Costs
per
Tons
of
SO2
Controlled
Under
CAIR,
Cap
Levels
Beginning
in
2010
and
2015
1
Type
of
Cost
Effectiveness
2010
2015
Average
Cost
­
Main
Case
$
500
$
700
Marginal
Cost
­
Main
Case
$
700
$
1,000
Sensitivity
Analysis:
Marginal
Cost
Using
EIA
Electric
Growth
and
Natural
Gas
Prices
$
800
$
1,200
1
The
EPA
IPM
modeling
2004,
available
in
the
docket.
1999$
per
ton.

These
estimated
SO2
control
costs
under
the
CAIR
reflect
annual
EGU
SO2
caps
of
3.6
million
tons
in
2010
and
2.5
million
tons
in
2015
within
the
CAIR
region.
Based
on
IPM
modeling,
EPA
projects
that
SO2
emissions
in
the
CAIR
region
will
be
about
5.1
million
tons
in
2010
and
4.0
million
tons
in
2015.
The
projected
emissions
are
above
the
cap
levels
because
of
the
use
of
the
existing
title
IV
bank
of
SO2
allowances.
Average
costs
shown
for
2015
are
an
estimate
of
the
average
cost
per
ton
to
achieve
the
total
difference
in
projected
emissions
between
the
base
case
conditions
and
the
CAIR
in
the
year
2015
(
the
2015
average
costs
are
not
based
on
the
increment
in
reductions
between
2010
and
2015).
(
A
more
detailed
description
of
the
final
222
CAIR
SO2
and
NOx
control
requirements
is
provided
below
in
today's
preamble.)

(
III)
SO2
Cost
Comparison
for
CAIR
Requirements
The
EPA
believes
that
if
an
SO2
control
strategy
has
a
cost
effectiveness
that
is
at
the
low
end
of
the
updated
reference
tables,
the
approach
should
be
considered
to
be
highly
cost
effective.
The
costs
in
the
reference
range
should
be
considered
to
be
cost
effective
because
they
represent
actions
that
have
already
been
taken
to
reduce
emissions.
In
deciding
to
require
these
actions,

policymakers
at
the
local,
State
and
Federal
levels
have
determined
them
to
be
cost­
effective
reductions
to
limit
or
reduce
emissions.
Thus,
costs
at
the
bottom
of
the
range
must
necessarily
be
considered
highly
cost
effective.

Today's
action
requires
SO2
emissions
reductions
(
or
an
EGU
emissions
cap)
in
2015.
The
EPA
has
determined
that
those
emissions
reductions
are
highly
cost
effective.
In
addition,
today's
action
requires
that
some
of
those
SO2
emissions
reductions
(
or
a
higher
EGU
emissions
cap)
be
implemented
by
2010.
The
EPA
has
examined
the
cost
effectiveness
of
implementing
those
earlier
emissions
reductions
(
or
cap)
by
2010,
and
determined
that
they
are
also
highly
cost
effective.

The
cost
of
the
SO2
reductions
required
under
today's
223
8
The
updated
reference
list
of
average
SO2
control
costs
includes
estimated
average
EGU
costs
under
BART.
The
BART
rule
has
been
proposed
but
not
finalized
(
69
FR
25184;
May
5,
2004).
action
 
if
the
States
choose
to
implement
those
reductions
through
EGUs,
for
which
the
most
cost­
effective
reductions
are
available
 
on
average
and
at
the
margin,
are
at
the
lower
end
of
the
range
of
cost
effectiveness
of
other,

recent
SO2
control
requirements.
58
This
is
true
for
our
analysis
of
both
the
costs
EPA
generally
expects
as
well
as
the
somewhat
higher
costs
that
would
result
from
higher
than
expected
electricity
demand
and
natural
gas
prices,
as
indicated
in
the
sensitivity
analyses
that
EPA
has
done.

Specifically,
the
average
cost
effectiveness
of
the
SO2
requirements
is
$
700
per
ton
removed
in
2015.
This
amount
falls
toward
the
low
end
of
the
reference
range
of
average
costs
per
ton
removed
of
$
400
to
$
3,400.
Similarly,
the
marginal
cost
effectiveness
of
the
SO2
requirements
ranges
from
$
1,000
to
$
1,200
for
2015
(
with
the
higher
end
of
the
range
based
on
the
sensitivity
analyses).
These
amounts
fall
toward
the
lower
end
of
the
reference
range
of
marginal
cost
per
ton
removed
of
$
600
to
$
2,200.

The
EPA
believes
that
selecting
as
highly
cost­
effective
amounts
toward
the
lower
end
of
our
average
and
marginal
cost
ranges
for
SO2
and
NOx
control
is
appropriate
because
today's
rulemaking
is
an
early
step
in
224
the
process
of
addressing
PM2.5
and
8­
hour
ozone
nonattainment
and
maintenance
requirements.
The
CAA
requires
States
to
submit
section
110(
a)(
2)(
D)
plans
to
address
interstate
transport,
and
overall
attainment
plans
to
ensure
the
NAAQS
are
met
in
local
areas.
By
taking
the
early
step
of
finalizing
the
CAIR,
we
are
requiring
a
very
substantial
air
emission
reduction
that
addresses
interstate
transport
of
PM2.5
as
well
as
a
further
reduction
in
interstate
transport
of
ozone
beyond
that
required
by
the
NOx
SIP
Call
Rule.
Much
of
the
air
quality
improvement
resulting
from
reduced
transport
is
likely
to
occur
through
broad
and
deep
emissions
reductions
from
the
electric
power
sector,
which
has
been
a
major
part
of
the
transport
problem.
Other
air
quality
benefits
will
occur
as
the
result
of
Federal
mobile
source
regulations
for
new
sources,

which
cover
passenger
vehicles
and
light
trucks,
heavy­
duty
trucks
and
buses,
and
non­
road
diesel
equipment.

Against
this
backdrop
of
Federal
actions
that
lower
air
emissions
(
As
well
as
some
substantial
State
control
programs),
States
will
develop
plans
designed
to
achieve
the
standards
in
their
local
nonattainment
areas.
The
EPA
has
not
yet
promulgated
rules
interpreting
the
CAA's
requirements
for
SIPs
for
PM2.5
and
ozone
nonattainment
225
9
EPA
did
promulgate
Phase
I
of
the
ozone
implementation
rule
in
April
2004
(
69
FR
23951;
April
30,
2004)
but
has
not
issued
Phase
II
of
the
rule,
which
will
interpret
CAA
requirements
relating
to
local
controls
(
e.
g.,
RACT,
RACM,
RFP).
areas,
59
nor
have
States
developed
plans
to
demonstrate
attainment.
As
a
result,
there
are
significant
uncertainties
regarding
potential
reductions
and
control
costs
associated
with
State
plans.
We
believe
that
some
areas
are
likely
to
attain
the
standards
in
the
near
term
through
early
CAIR
reductions
and
local
controls
that
have
costs
per
ton
similar
to
the
levels
we
have
determined
to
be
highly
cost
effective.
We
expect
that
other
areas
with
higher
PM2.5
or
ozone
levels
will
determine
through
the
attainment
planning
process
that
they
need
greater
emissions
reductions,
at
higher
costs
per
ton,
to
reach
attainment
within
the
CAA's
timeframes.
For
those
areas,
States
will
need
to
assess
targeted
measures
for
achieving
local
attainment
in
a
cost­
effective
(
but
not
necessarily
highly
cost­
effective)
manner,
in
combination
with
the
CAIR's
significant
reductions.
Given
the
uncertainties
that
exist
at
this
early
stage
of
the
implementation
process,
EPA
believes
this
rule
is
a
rational
approach
to
determining
the
highly
cost­
effective
reductions
in
PM2.5
and
ozone
precursors
that
should
be
required
for
interstate
transport
purposes.
226
As
discussed
above,
the
Agency
believes
this
approach
is
consistent
with
our
action
in
the
NOx
SIP
Call.
While
the
cost
level
selected
for
the
NOx
SIP
Call
was
not
at
the
low
end
of
the
reference
range
of
costs,
if
the
NOx
SIP
Call
costs
were
for
annual
rather
than
seasonal
controls
they
would
have
been
lower
relative
to
the
annual
control
costs
on
the
list.
This
would
make
the
relationship
between
the
cost
of
the
NOx
SIP
Call
and
the
reference
costs
used
in
that
rulemaking,
more
similar
to
relative
costs
of
CAIR
compared
to
its
reference
lists.
Also,
significant
local
controls
for
meeting
the
1­
hour
ozone
standard
had
already
been
adopted
in
many
areas.

Although
EPA's
primary
cost­
effectiveness
determination
is
for
the
2015
emissions
reductions
levels,
the
Agency
also
evaluated
the
cost
effectiveness
of
the
interim
phase
control
levels
to
ensure
that
they
were
also
highly
cost
effective.
For
the
SO2
requirements
for
2010,
the
average
cost
effectiveness
is
$
500
per
ton
removed,
and
the
marginal
cost
effectiveness
ranges
from
$
700
to
$
800.
The
2010
costs
indicate
that
the
interim
phase
CAIR
reductions
are
also
highly
cost­
effective.

(
IV)
Cost
Effectiveness:
Marginal
Cost
Curves
for
SO2
Control
As
noted
above,
the
Agency
also
considered
another
227
factor
to
corroborate
its
conclusion
concerning
the
cost
effectiveness
of
the
selected
levels
of
control:
the
cost
effectiveness
of
alternative
stringency
levels
for
today's
action.
Specifically,
EPA
examined
changes
in
the
marginal
cost
curve
at
varying
levels
of
emissions
reductions
for
EGUs.
Figure
IV­
1
shows
that
the
"
knee"
in
the
2010
marginal
cost­
effectiveness
curve
 
the
point
where
the
cost
of
controlling
a
ton
of
SO2
from
EGUs
is
increasing
at
a
noticeably
higher
rate
 
appears
to
occur
at
about
$
2,000
per
ton
of
SO2.
Figure
IV­
2
shows
that
the
"
knee"
in
the
2015
marginal
cost­
effectiveness
curve
also
appears
to
occur
at
about
$
2,000
per
ton
of
SO2.
(
As
discussed
above,
the
projected
marginal
costs
of
SO2
reductions
for
the
CAIR
are
$
700
per
ton
in
2010
and
$
1,000
per
ton
in
2015.)
The
EPA
used
the
Technology
Retrofitting
Updating
Model
(
TRUM),
a
spreadsheet
model
based
on
the
IPM,
for
this
analysis.
(
The
EPA
based
these
marginal
SO2
cost­
effectiveness
curves
on
the
electric
growth
and
natural
gas
price
assumptions
in
the
main
CAIR
IPM
modeling
run.
Marginal
cost
effectiveness
curves
based
on
other
electric
growth
and
natural
gas
price
assumptions
would
look
different,
therefore
it
would
not
be
appropriate
to
compare
the
curves
here
to
the
marginal
costs
based
on
the
IPM
modeling
sensitivity
run
that
used
EIA
assumptions.)
These
results
make
clear
that
this
rule
is
228
10
EPA
is
using
the
knee
in
the
curve
analysis
solely
to
show
that
the
required
emissions
reductions
are
very
cost
effective.
The
marginal
cost
curve
reflects
only
emissions
reduction
and
cost
information,
and
not
other
considerations.
We
note
that
it
might
be
reasonable
in
a
particular
regulatory
action
to
require
emissions
reductions
past
the
knee
of
the
curve
to
reduce
overall
costs
of
meeting
the
NAAQS
or
to
achieve
benefits
that
exceed
costs.
It
should
be
noted
that
similar
analysis
for
other
source
categories
may
yield
different
curves.
Marginal
Cost
Curve
of
Abatement
for
SO2
Emissions
from
EGUs
in
2010
(
NOx
Emissions
at
1.5
million
tons)

$­
$
500
$
1,000
$
1,500
$
2,000
$
2,500
$
3,000
1.00
2.00
3.00
4.00
5.00
6.00
Million
Tons
of
SO2
Emitted
in
CAIR
Region
Source:
EPA
TRUM
Analysis,
August
2004
Marginal
Cost
(
1999$/
ton)

SO2
Price
($/
ton)
Figure
IV­
1.
very
cost
effective
because
the
control
level
is
below
the
point
at
which
the
cost
begins
to
increase
at
a
significantly
higher
rate.

In
this
manner,
these
results
corroborate
EPA's
findings
above
concerning
the
cost
effectiveness
of
the
emissions
reductions.
60
229
Marginal
Cost
Curve
of
Abatement
for
SO2
Emissions
from
EGUs
in
2015
(
NOx
Emissions
at
1.3million
tons)

$­
$
500
$
1,000
$
1,500
$
2,000
$
2,500
$
3,000
1.00
2.00
3.00
4.00
5.00
6.00
7.00
Million
Tons
of
SO2
Emittedin
CAIR
Region
Source:
EPA
TRUM
Analysis,
August
2004
Marginal
Cost
(
1999$/
ton)

SO2
Price
($/
ton)
Figure
IV
­
2.

b.
NOx
Emissions
Reductions
Requirements
i.
The
CAIR
Proposal
for
NOx
and
Subsequent
Analyses
for
Regionwide
Annual
and
Ozone
Season
NOx
Control
Levels
In
this
section,
EPA
describes
its
proposed
method
for
determining
regionwide
NOx
control
levels
and
the
method
used
for
the
final
CAIR.

In
the
CAIR
NPR,
EPA
updated
the
reference
list
included
in
the
NOx
SIP
Call
for
the
average
annual
cost
effectiveness
of
recent
or
proposed
NOx
controls,
and
determined
that
these
amounts
ranged
from
approximately
$
200
230
to
$
2,800.
In
addition,
in
the
NPR,
EPA
developed
a
reference
list
for
marginal
annual
cost
effectiveness
for
NOx
controls,
and
determined
that
these
amounts
ranged
from
approximately
$
1,400
to
$
3,000
(
69
FR
4614
­
4615).

In
the
NPR,
EPA
proposed
a
two­
phased
annual
NOx
control
program,
with
a
final
phase
in
2015
and
a
first
phase
in
2010.
The
regionwide
emissions
reduction
requirements
that
EPA
proposed
 
and
the
budget
levels
that
would
apply
if
all
States
chose
to
implement
the
reductions
from
EGUs
 
were
based
on
using
a
combination
of
recent
historical
heat
input
and
NOx
emissions
rates
for
fossil
fuel­
fired
EGUs.
For
historical
heat
input,
EPA
proposed
determining
the
highest
heat
input
from
units
affected
by
the
Acid
Rain
Program
for
each
affected
State
for
the
years
1999­
2002.
The
EPA
then
summed
this
heat
input
for
all
of
the
States
affected
for
annual
NOx
reductions.
For
2015,

EPA
calculated
a
proposed
regionwide
annual
NOx
budget
by
multiplying
this
heat
input
by
an
emission
rate
of
0.125
lb/
mmBtu,
and
for
2010
by
multiplying
by
0.15
lb/
mmBtu.

In
developing
the
CAIR
NPR,
when
EPA
considered
the
appropriate
amount
of
annual
SO2
emissions
reductions,
EPA
relied
on
the
existing
title
IV
annual
SO2
cap
as
a
starting
point.
However,
in
considering
the
appropriate
amount
of
NOx
reductions,
the
situation
is
different
because
title
IV
231
does
not
cap
NOx
emissions.
Therefore,
EPA
and
the
States
have
focused
on
emissions
caps
based
on
a
combination
of
heat
input
and
NOx
emission
rates.
Emission
rates
similar
to
the
rates
used
to
develop
the
CAIR
NPR
have
been
considered
in
the
past.
For
example,
the
CAPI
1996
study,

noted
above,
contemplated
NOx
caps
based
on
an
emission
rate
of
0.15
lb/
mmBtu
(
and
other
options
based
on
NOx
rates
of
0.20
lb/
mmBtu
and
0.25
lb/
mmBtu).
The
NOx
SIP
Call
is
based
on
an
emission
rate
of
0.15
lb/
mmBtu.

The
methodology
described
in
the
NPR
is
best
understood
as
the
means
for
developing
the
target
2015
annual
NOx
control
level
(
or
emissions
budget)
for
further
evaluation
through
IPM.
The
EPA
developed
this
level
mindful
of
its
experience
to
date
with
the
NOx
SIP
Call
and
the
earlier
work
EPA
has
performed
on
multi­
pollutant
power
plant
reduction
programs.
The
EPA
also
considered
available
technical
information
on
pollution
controls,
costs
to
industry
and
the
general
public,
ambient
air
improvement,

and
consistency
with
the
emerging
PM2.5
implementation
program,
in
developing
its
target
control
level.

Recent
advances
in
combustion
control
technology
for
NOx
reductions,
as
well
as
widespread
use
of
selective
catalytic
reduction
(
SCR)
on
U.
S.
coal­
fired
EGU
boilers
achieving
NOx
emission
rates
of
0.06
lb/
mmBtu
and
below,
232
provide
evidence
that
even
lower
average
NOx
emission
rates
are
more
highly
cost­
effective
than
rates
considered
in
the
past
(
based
on
analyzing
EGUs),
possibly
on
the
order
of
0.12
lb/
mmBtu
or
less.
The
EPA
developed
the
target
annual
NOx
control
level
(
or
emissions
budget)
with
the
understanding
that
the
evaluation
of
that
level
might
indicate
that
average
emission
rates
on
the
order
of
0.12
lb/
mmBtu
or
less
might
be
highly
cost
effective
for
the
final
(
2015)
control
phase,
and
an
interim
level
resulting
in
an
average
emission
rate
of
less
than
0.15
lb/
mmBtu
might
be
feasible
for
the
first
phase.

The
EPA
did
evaluate
the
target
annual
NOx
control
levels
(
or
emissions
budgets)
using
the
IPM.
The
EPA
confirmed
that
the
2015
level
is
highly
cost
effective.
The
Agency
also
evaluated
the
cost
effectiveness
of
the
proposed
2010
cap
to
assure
that
the
interim
phase
reductions
would
also
be
highly
cost
effective.
The
EPA's
IPM
analyses
for
the
CAIR
includes
all
fossil
fuel­
fired
EGUs
with
generating
capacity
greater
than
25
MW.

The
proposed
cap
for
the
first
phase
was
developed
taking
into
consideration
how
much
pollution
control
for
NOx
and
SO2
could
be
installed
without
running
into
a
shortage
of
skilled
labor,
in
particular
boilermakers
(
EPA's
assumptions
regarding
boilermaker
labor
are
described
in
233
11
The
EPA
does
not
collect
annual
heat
input
data
from
these
non­
Acid
Rain
units.
EIA
does
collect
heat
input
from
such
units,
however
there
are
some
limitations
to
the
data.
First,
there
are
no
requirements
specifying
how
the
data
should
be
collected
or
quality
assured.
Second,
the
data
is
collected
on
a
plant­
wide
basis
rather
than
on
a
unit­
byunit
basis.
section
IV.
C.
2
of
this
preamble).
The
Agency
focused
on
providing
substantial
reductions
of
both
SO2
and
NOx
emissions
at
the
outset
of
the
proposed
program,
leading
to
significant
retrofits
of
Flue
Gas
Desulfurization
units
(
FGD)
for
SO2
control
and
SCR
for
NOx
control.

In
the
NPR,
EPA
explained
that
using
the
highest
Acid
Rain
Program
heat
input
for
each
State
to
develop
a
regionwide
heat
input
amount,
rather
than
the
average
Acid
Rain
Program
heat
input,
provided
a
cushion
that
represented
a
reasonable
adjustment
to
reflect
that
there
are
some
non­
Acid
Rain
units
that
operate
in
these
States
that
will
be
subject
to
the
proposed
CAIR
emission
reduction
levels.

The
EPA
explained
that
it
did
not
use
heat
input
data
from
non­
Acid
Rain
units
in
the
proposal
because
it
did
not
have
all
the
necessary
data
available
at
the
time
the
NPR
was
developed.
61
Using
the
highest
of
recent
years'
Acid
Rain
Program
heat
input
provided
an
approximation
of
the
regionwide
heat
input,
although
it
did
not
include
heat
input
from
non­
Acid
Rain
sources.
Multiplying
the
approximate
recent
heat
input
by
0.125
lb/
mmBtu
to
develop
a
234
proposed
regionwide
annual
2015
NOx
cap
could
reasonably
be
expected
to
yield
an
average
effective
NOx
emission
rate
(
considering
all
EGUs
potentially
affected
by
CAIR
for
annual
reductions,
not
only
the
Acid
Rain
units,
and
considering
growth
in
heat
input)
somewhat
less
than
0.125
lb/
mmBtu.
Likewise,
multiplying
the
approximate
recent
heat
input
by
0.15
lb/
mmBtu
to
develop
a
regionwide
annual
2010
NOx
cap
could
reasonably
be
expected
to
yield
an
average
effective
NOx
emission
rate
for
all
CAIR
units
of
about
0.15
lb/
mmBtu
or
less.

Although
EPA
calculated
 
in
essence,
as
a
target
level
for
further
evaluation
 
the
proposed
regionwide
annual
NOx
control
levels
(
or
emissions
budgets)
based
on
heat
input
from
only
Acid
Rain
Program
units,
the
Agency
evaluated
the
cost
effectiveness
of
the
control
levels
using
heat
input
from
all
EGUs
that
potentially
would
be
affected
by
the
proposed
CAIR.
The
EPA
evaluated
cost
effectiveness
using
the
IPM,
which
includes
both
Acid
Rain
units
and
non­
Acid
Rain
units.
Further,
the
IPM
incorporates
assumptions
for
electricity
demand
growth,
and
thus
heat
input
growth.

Specifically,
EPA
evaluated
these
target
annual
NOx
caps
on
EGUs
for
2010
and
2015
 
and
therefore
the
associated
regionwide
emissions
reductions
 
using
the
IPM,

which,
in
effect,
demonstrated
that
these
proposed
NOx
235
12
These
projected
average
NOx
emissions
rates
are
from
updated
IPM
modeling
done
in
2004.
The
IPM
modeling
done
prior
to
the
NPR
also
projected
similar
average
emission
rates,
about
0.15
lb/
mmBtu
and
0.11
lb/
mmBtu
in
2010
and
2015,
respectively.
emissions
cap
levels
can
be
met
using
highly
cost­
effective
controls
with
the
expected
levels
of
electricity
demand
in
2010
and
2015,
respectively.
Those
expected
levels
of
electricity
demand
are
higher
than
the
electricity
demand
during
the
1999
to
2002
years
upon
which
EPA
based
heat
input;
and
as
a
result,
the
amount
of
heat
input
necessary
to
meet
the
projected
electricity
demand
is
expected
to
be
higher
than
the
amount
that
EPA
developed
for
evaluation
purposes
through
the
method
described
above.
The
projected
average
future
emissions
rates
that
would
be
associated
with
the
2010
and
2015
heat
input
levels
needed
to
meet
electricity
demand
(
coupled
with
the
NOx
emissions
budgets
developed
through
the
methodology
described
above)
would
be
about
0.14
lb/
mmBtu
and
0.11
lb/
mmBtu
in
2010
and
2015,

respectively.
62
These
average
rates
would
be
for
all
units
affected
by
annual
NOx
controls
under
CAIR,
including
non­

Acid
Rain
units.
Thus,
the
heat
input
is
projected
to
be
higher
in
2010
and
2015
than
the
recent
historic
heat
input
used
to
develop
the
target
emissions
budgets,
and
the
projected
NOx
emission
rates
in
2010
and
2015
are
lower
than
the
0.15
lb/
mmBtu
and
0.125
lb/
mmBtu
rates
that
were
used
to
236
develop
the
budgets.
IPM
determined
the
costs
of
meeting
these
average
future
NOx
emission
rates
of
0.14
lb/
mmBtu
and
0.11
lb/
mmBtu.
EPA
considers
these
emission
rates
to
be
highly
cost­
effective
and
feasible.

In
the
NPR,
EPA
proposed
an
interim
(
Phase
I)
annual
NOx
phase
in
2010
and
a
final
(
Phase
II)
annual
NOx
phase
in
2015.
However,
in
today's
final
rule,
EPA
is
promulgating
a
Phase
I
for
NOx
in
2009
(
with
the
Phase
II
for
NOx
in
2015,

as
proposed).
EPA
determined
the
regionwide
NOx
control
levels
for
2009
and
2015
for
today's
final
action
using
the
same
methodology
as
we
used
to
determine
proposed
levels.

The
Agency
evaluated
the
cost
effectiveness
of
the
final
reduction
requirements
(
and
average
NOx
emission
rates)

using
IPM
and
determined
them
to
be
highly
cost­
effective,

assuming
controls
on
EGUs.
EPA's
evaluation
of
the
cost
effectiveness
of
the
emission
reduction
strategy
we
assumed
in
establishing
the
final
CAIR
control
levels
is
discussed
further
below.

The
average
NOx
emission
rates
in
the
first
and
second
phases
of
CAIR
will
be
lower
than
the
nominal
emission
rate
on
which
the
NOx
SIP
Call
was
based,
which
was
0.15
lb/
mmBtu.
In
the
NOx
SIP
Call,
EPA
also
considered
a
control
level
based
on
a
lower
nominal
emission
rate,
0.12
lb/
mmBtu.
However,
at
that
time
the
use
of
SCR
was
not
237
sufficiently
widespread
to
allow
EPA
to
conclude
that
the
controls
necessary
to
meet
a
tighter
cap
could
be
installed
in
the
required
timeframe,
without
causing
reliability
problems
for
the
electric
power
sector.
Now,
through
the
experience
gained
from
the
NOx
SIP
Call,
EPA
has
confidence
that
with
SCR
technology
average
emissions
rates
lower
than
the
NOx
SIP
Call
nominal
emission
rate
can
be
achieved
on
a
regionwide
basis.

In
the
CAIR
NPR,
after
determining
the
regionwide
control
level
and
evaluating
it
to
assure
that
it
is
highly
cost­
effective,
the
Agency
then
apportioned
the
regionwide
budgets
to
the
affected
States.
The
EPA
proposed
to
apportion
regionwide
NOx
budgets
to
individual
States
on
the
basis
of
each
State's
share
of
recent
average
heat
input.

In
the
NPR,
EPA
used
the
average
share
of
Acid
Rain
Program
heat
input.
However,
as
discussed
in
the
SNPR
and
the
NODA,

in
order
to
distribute
more
equitably
to
States
their
share
of
the
regionwide
NOx
budgets,
EPA
then
considered
each
State's
proportional
share
of
recent
average
heat
input
using
data
from
non­
Acid
Rain
Program
sources
as
well
as
Acid
Rain
Program
sources.
The
EPA
obtained
EIA
heat
input
data
reported
for
non­
Acid
Rain
sources
and
combined
the
EIA
heat
inputs
with
Acid
Rain
heat
inputs
to
determine
each
State's
share
of
combined
average
recent
heat
input.
238
The
fact
that
EPA
distributed
the
regionwide
budget
to
individual
States
based
on
their
proportional
share
of
heat
input
from
Acid
Rain
and
non­
Acid
Rain
units
combined
does
not
affect
the
determination
of
the
regionwide
budgets
themselves.
The
regionwide
budgets
were
determined
to
be
highly
cost­
effective
when
tested
for
all
units
 
both
non­

Acid
Rain
units
as
well
as
Acid
Rain
units
 
that
would
be
affected
by
CAIR.
(
EPA's
method
for
apportioning
regionwide
NOx
budgets
to
States
is
discussed
in
more
detail
elsewhere
in
today's
preamble.
That
discussion
includes
an
explanation
of
the
differences
between
the
State
budgets
that
were
presented
in
the
NPR,
the
SNPR,
and
the
NODA.
In
addition,
see
the
TSD
entitled
"
Regional
and
State
SO2
and
NOx
Emissions
Budgets.")

In
the
NPR,
EPA
proposed
that
Connecticut
contributed
significantly
to
downwind
ozone
nonattainment,
but
not
to
PM2.5
nonattainment.
Thus,
the
Agency
proposed
that
Connecticut
would
not
be
subject
to
an
annual
NOx
control
requirement
and
was
not
included
in
the
region
proposed
for
annual
controls.
We
proposed
that
Connecticut
would
be
affected
by
an
ozone
season­
only
NOx
control
level,
and
proposed
to
calculate
Connecticut's
ozone
season
control
level
in
a
parallel
way
to
how
the
regionwide
annual
NOx
control
levels
were
calculated.
That
is,
EPA
selected
the
239
highest
of
the
same
4
years
of
(
ozone
season­
only)
heat
input
used
for
the
regionwide
budget
calculation,
and
multiplied
that
heat
input
by
the
same
NOx
emission
rates
used
to
calculate
the
regionwide
control
levels.

Connecticut
is
the
only
State
for
which
an
ozone
season
budget
was
proposed.

The
EPA
used
the
same
methodology
for
developing
regionwide
budgets
for
today's
final
rule
as
was
proposed
in
the
NPR.
For
the
final
CAIR,
EPA
found
that
23
States
and
the
District
of
Columbia
contribute
significantly
to
downwind
PM2.5
nonattainment
and
found
that
25
States
and
the
District
of
Columbia
contribute
significantly
to
downwind
ozone
nonattainment
(
section
III
in
today's
preamble
describes
the
significance
determinations).
CAIR
requires
annual
NOx
reductions
in
all
States
determined
to
contribute
significantly
to
downwind
PM2.5
nonattainment,

and
requires
ozone
season
NOx
reductions
in
all
States
determined
to
contribute
significantly
to
downwind
ozone
nonattainment
(
many
of
the
CAIR
States
are
affected
by
both
annual
and
ozone
season
NOx
reduction
requirements).
The
final
CAIR
ozone
season
NOx
reductions
are
required
in
two
phases,
with
Phase
I
commencing
in
2009
and
Phase
II
in
2015,
the
same
years
as
the
annual
NOx
reduction
requirements.
240
As
described
above,
the
Agency
proposed
ozone
season
NOx
reduction
requirements
for
Connecticut,
and
did
not
propose
ozone
season
reductions
in
any
other
State.
For
today's
final
rule,
EPA
requires
ozone
season
reductions
in
all
States
contributing
significantly
to
downwind
ozone
nonattainment.
The
EPA
determined
regionwide
ozone
season
NOx
control
levels
for
the
final
CAIR
using
the
same
methodology
as
was
used
for
the
annual
NOx
reduction
requirements
(
which
is
the
same
method
that
was
proposed
for
Connecticut's
ozone
season
budget).
That
is,
EPA
determined
the
highest
(
ozone
season)
heat
input
from
Acid
Rain
Program
units
for
the
years
1999­
2002
for
each
State,
then
summed
this
heat
input
for
all
of
the
States
affected
for
ozone
season
NOx
reductions.
For
the
final
2015
control
level,

EPA
calculated
a
regionwide
ozone
season
NOx
budget
by
multiplying
this
heat
input
by
an
emission
rate
of
0.125
lb/
mmBtu,
and
for
2009
by
multiplying
by
0.15
lb/
mmBtu.
The
Agency
evaluated
the
cost
effectiveness
of
these
ozone
season
NOx
control
levels
(
and
average
NOx
emission
rates)

using
IPM
and
determined
them
to
be
highly
cost­
effective,

assuming
controls
on
EGUs.
EPA's
evaluation
of
the
cost
effectiveness
of
the
final
CAIR
control
requirements
is
discussed
further
below.

Based
on
EPA's
analysis
of
proposed
annual
NOx
control
241
13
The
control
costs
for
this
model
sensitivity
that
were
presented
in
the
NPR
were
in
error
(
69
FR
4615).
The
corrected
costs
from
the
sensitivity
are
as
shown
here.
levels,
in
the
NPR
the
Agency
presented
average
costs
for
annual
NOx
control
of
$
800
per
ton
and
$
700
per
ton
for
2010
and
2015,
and
marginal
costs
of
$
1,300
per
ton
and
$
1,500
per
ton
for
2010
and
2015.
In
the
NPR,
EPA
also
presented
marginal
costs
of
annual
NOx
control
from
sensitivity
analyses
that
used
EIA
assumptions
for
electricity
growth
and
natural
gas
prices.
Those
marginal
control
costs
were
$
1,300
per
ton
and
$
1,600
per
ton
for
2010
and
2015,

respectively.
The
EPA
also
presented
costs
from
a
sensitivity
model
run
that
used
EIA
assumptions
for
electricity
growth
and
natural
gas
price
and
higher
SCR
costs.
These
marginal
control
costs
were
$
1,700
per
ton
and
$
2,200
per
ton
for
2010
and
2015,
respectively.
63
In
the
NPR,
EPA
also
presented
the
average
cost
effectiveness
for
ozone
season­
only
NOx
control
of
$
1,000
per
ton
and
$
1,500
per
ton
for
2010
and
2015,
respectively,

and
a
marginal
cost
for
ozone
season­
only
control
of
$
2,200
per
ton
and
$
2,600
per
ton
for
2010
and
2015.
The
EPA
also
presented
average
costs
for
the
non­
ozone
season
(
remaining
seven
months
of
the
year)
control
of
$
700
per
ton
and
$
500
per
ton
in
2010
and
2015,
respectively.
(
As
noted
above,

the
capital
costs
of
installing
NOx
control
equipment
would
242
be
largely
identical
whether
the
equipment
will
be
operated
during
the
ozone
season
only
or
for
the
entire
year.

However,
the
amount
of
reductions
would
be
less
if
the
control
equipment
were
operated
only
during
the
ozone
season
compared
to
annual
operation.)

EPA
proposed
the
conclusion
that
these
costs
met
the
criteria
for
highly
cost­
effective
emissions
reductions
for
NOx
(
69
FR
4613
­
4615).

As
with
SO2,
EPA
also
considered
the
cost
effectiveness
of
alternative
stringency
levels
for
this
regulatory
proposal
(
examining
changes
in
the
marginal
cost
curve
at
varying
levels
of
emission
reductions).

ii.
What
Are
the
Most
Significant
Comments
that
EPA
Received
about
Proposed
NOx
Emission
Reduction
Requirements,

and
What
Are
EPA's
Responses?

Some
commenters
expressed
concern
that
EPA
did
not
account
for
growth
of
heat
input
in
calculating
regionwide
NOx
emissions
budgets,
noting
that
growth
was
used
in
the
calculation
of
the
regional
budget
for
the
NOx
SIP
Call.

Commenters
suggest
that,
by
not
taking
heat
input
growth
into
account,
EPA
developed
regionwide
budgets
that
are
unduly
stringent.

On
the
other
hand,
some
commenters
noted
that
they
supported
EPA's
proposal
to
base
regionwide
budgets
on
243
historical
heat
input
and
did
not
want
EPA
to
use
growth
projections
for
calculating
regionwide
NOx
emissions
budgets.
Some
stated
that
using
actual,
historic
heat
input
numbers
would
be
more
straightforward
than
using
growth
projections,
and
some
pointed
to
complications
with
the
growth
projection
methodologies
used
in
the
NOx
SIP
Call.

EPA
recognizes
that
it
employed
a
growth
factor
in
the
NOx
SIP
Call.
There,
EPA
determined
the
amount
of
the
regional
emissions
reductions
and
budgets
by
applying
a
growth
factor
to
a
historic
heat
input
baseline.
The
D.
C.

Circuit,
after
first
remanding
that
growth
methodology
for
a
better
explanation,
upheld
it.
West
Virginia
v.
EPA,
362
F.
3d
861
(
D.
C.
Cir.,
2004).
See
67
FR
21
868
(
May
1,
2002).

For
CAIR,
as
described
above,
EPA
developed
a
target
level
for
the
proposed
NOx
regionwide
cap
based
on
recent
historic
heat
input
and
assumed
emission
rates
of
0.125
lb/
mmBtu
and
0.15
lb/
mmBtu
for
2015
and
2010,
respectively.

The
EPA
evaluated
these
target
NOx
emissions
levels
using
IPM,
which
indicated
that
those
target
caps
 
in
conjunction
with
expected
electricity
demand
for
2015
and
2010
 
would
result
from
higher
heat
input
levels
and
lower
average
emissions
rates
(
about
0.11
lb/
mmBtu
and
0.14
lb/
mmBtu
for
2015
and
2010,
respectively)
than
the
amounts
assumed
in
developing
the
target
NOx
caps.
Most
importantly,
IPM
244
indicated
the
cost
levels
associated
with
those
projected
2015
and
2010
average
NOx
emission
rates,
and
EPA
has
determined
that
those
cost
levels
are
highly
cost­
effective.

For
the
final
rule,
EPA
revised
its
analyses
to
reflect
the
2009
initial
NOx
control
phase,
and
determined
that
the
final
CAIR
requirements
are
highly
cost­
effective.
EPA's
methodology,
in
which
the
CAIR
emissions
reductions
are
predicted
to
be
cost­
effective
under
conditions
of
projected
electricity
growth
that,
in
turn,
projects
heat
input
growth,
in
effect
accounts
for
heat
input
growth.
Moreover,

the
amount
of
heat
input
growth
is
the
amount
determined
by
IPM,
a
state­
of­
the­
art
model
of
the
electricity
sector
(
detailed
documentation
for
IPM
is
in
the
docket).

Some
commenters
suggested
that
EPA
adjust
the
NOx
regionwide
budget
amounts
to
include
heat
input
from
non­

Acid
Rain
units.
For
example,
some
suggested
adding
the
non­
Acid
Rain
unit
heat
input
amounts
that
EPA
used
in
apportioning
regionwide
NOx
budgets
to
the
States,
to
the
total
regionwide
heat
inputs
that
EPA
used
to
calculate
regionwide
NOx
budgets.

The
regionwide
budgets
determined
in
the
NPR
were
target
levels
developed
as
a
starting
point
for
further
evaluation.
The
regionwide
heat
input
amounts
and
NOx
emission
rates
used
to
develop
target
budget
levels
were
245
inherently
imprecise.
As
discussed
above,
IPM
modeling
indicates
that
the
projected
future
heat
input
amounts
(
based
on
electricity
growth)
are
greater
than
the
recent
historic
regionwide
amount
used
to
develop
the
target
budget
levels,
and
the
future
average
emission
rates
for
all
units
affected
by
CAIR
annual
NOx
controls
(
including
non­
Acid
Rain
units)
are
less
than
the
rates
used
to
develop
the
target
budget
levels.
IPM
indicates
that
the
target
regionwide
NOx
budget
levels
(
and
corresponding
future
average
NOx
emission
rates
and
heat
input
levels)
are
highly
cost­
effective
for
all
CAIR
units,
including
non­
Acid
Rain
units.
The
EPA
does
not
believe
it
is
necessary
to
adjust
the
target
regionwide
budget
levels
to
include
the
relatively
small
additional
amount
of
heat
input
from
non­

Acid
Rain
units.
The
method
the
Agency
used
to
develop
target
levels
was
not
intended
to
be
a
precise
methodology
for
determining
the
NOx
caps;
rather,
it
was
a
reasonable
method
for
selecting
a
target
level
to
be
evaluated
further.

Upon
evaluation
of
the
target
level,
EPA
determined
that
it
can
be
achieved
using
highly
cost­
effective
controls
for
all
affected
EGUs,
including
non­
Acid
Rain
units.

iii.
Analysis
of
NOx
Emission
Reduction
Requirements
for
Today's
Final
Rule
(
I)
Reference
Lists
of
Cost­
Effective
Controls
246
64
The
updated
reference
list
includes
estimated
average
NOx
control
costs
under
BART.
The
BART
rule
has
been
proposed
but
not
finalized
(
69
FR
25184;
May
5,
2004).
For
today's
action,
EPA
updated
the
reference
list
of
controls
included
in
the
NPR
of
the
average
and
marginal
costs
per
ton
of
recent
NOx
control
actions.
The
EPA
systematically
developed
a
list
of
cost
information
from
recent
actions
and
proposed
actions.
The
Agency
sought
cost
information
for
actions
taken
by
EPA,
and
examined
the
comments
submitted
after
the
NPR
was
published,
to
identify
all
available
control
cost
information
to
provide
the
updated
reference
list
for
today's
preamble.
The
updated
reference
list
includes
both
average
and
marginal
costs
of
control
to
which
EPA
compares
the
CAIR
control
costs,

although
the
Agency
has
limited
information
on
marginal
costs
of
other
programs.

The
EPA's
updated
summary
of
average
costs
of
annual
NOx
controls
are
shown
in
Table
IV­
6.
The
results
of
this
reexamination
show
that
costs
of
recent
actions
are
generally
very
similar
to
those
identified
in
the
NOx
SIP
Call.
The
cost
figures
are
presented
in
1999
dollars.
64
247
Table
IV­
6.
Average
Costs
per
Ton
of
Annual
NOx
Controls
NO
x
Control
Action
Average
Cost
per
Ton
Marine
Compression
Ignition
Engines
Up
to
$
200
2
Off­
highway
Diesel
Engine
$
400
­
$
700
2
Nonroad
Diesel
Engines
and
Fuel
$
600
1
Marine
Spark
Ignition
Engines
$
1,200
­
$
1,800
2
Tier
2
Vehicle
Gasoline
Sulfur
$
1,300
­
$
2,300
2
Revision
of
New
Source
Performance
Standards
for
NOx
Emissions
­
EGUs
$
1,700
3
2007
Highway
Heavy
Duty
Diesel
Standards
$
1,600
­
$
2,100
2
National
Low
Emission
Vehicle
$
1,900
2
Tier
1
Vehicle
Standards
$
2,100
­
$
2,800
2
Revision
of
New
Source
Performance
Standards
for
NOx
Emissions
­
Industrial
Units
$
2,200
3
On­
board
Diagnostics
$
2,300
2
Texas
NO
x
Emission
Reduction
Grants
FY
2002
­
2003
$
300
­
$
12,700
4
Best
Available
Retrofit
Technology
(
BART)
for
Electric
Power
Sector
$
800
5
1
Control
of
Emissions
of
Air
Pollution
From
Nonroad
Diesel
Engines
and
Fuel;
Final
Rule
(
69
FR
39131;
June
29,
2004).
The
value
in
this
table
represents
the
long­
term
cost
per
ton
of
emissions
reduced
from
the
total
fuel
and
engine
program
(
cost
per
ton
of
emissions
reduced
in
the
year
2030).
This
value
includes
the
cost
for
NOx
plus
NMHC
reductions.
1999$
per
ton.
2
Control
of
Air
Pollution
from
New
Motor
Vehicles:
Heavy­
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Control
Requirements;
Final
Rule
(
66
FR
5102;
January
18,
2001).
The
values
shown
for
2007
Highway
HD
Diesel
Stds
are
discounted
costs.
Costs
shown
in
this
table
include
a
VOC
component.
1999$
per
ton.
3
Proposed
Revision
of
Standards
of
Performance
for
Nitrogen
Oxide
Emissions
From
New
Fossil­
Fuel
Fired
Steam
Generating
Units;
Proposed
Revision
to
Reporting
Requirements
for
Standards
of
Performance
for
New
Fossil­
Fuel
Fired
Steam
Generating
Units;
Proposed
Rule
(
62
FR
36953;
July
9,
1997),
Table
4
(
the
Agency's
estimate
of
average
control
costs
was
unchanged
for
the
NSPS
revisions
final
rule,
published
September
5,
1998).
In
the
CAIR
NPR,
we
included
a
value
from
the
range
of
NOx
controls
for
coal­
fired
EGUs
from
Table
2
in
the
proposed
NSPS
proposed
rule
(
62
FR
36951).
1999$
per
ton.
4
Costs
shown
in
this
table
are
the
range
of
project
costs
reported
for
projects
that
were
FY
2002
­
2003
recipients
of
the
TERP
Emission
Reductions
Incentive
Grants
Program.
These
costs
may
not
be
in
1999
dollars.
(
www.
tnrcc.
state.
tx.
us/
oprd/
sips/
grants.
html)
5
The
EPA
IPM
modeling
2004
of
the
proposed
BART
for
the
electric
248
power
sector
(
69
FR
25184,
May
5,
2004),
available
in
the
docket.
The
EPA
modeled
the
Regional
Haze
Requirements
as
a
source
specific
0.2
lb/
mmBtu
NOx
emission
rate
limit.
Estimated
average
costs
based
on
this
modeling
are
$
800
per
ton
in
2015
and
2020.
1999$
per
ton.

Table
IV­
7
presents
modeled
marginal
costs
for
recent
State
annual
NOx
rules.

Table
IV­
7.
Marginal
Costs
per
Ton
of
Reduction,
Recent
Annual
NOx
Rules
NO
X
Control
Action
Marginal
Cost
per
Ton
Texas
Rules
$
2,000
­
$
19,600
1
1
The
EPA
IPM
Base
Case
modeling
August
2004,
available
in
the
docket.
1999$
per
ton.
We
modeled
Senate
Bill
7
and
Ch.
117,
which
impose
varying
NOx
control
requirements
in
different
areas
of
the
State;
the
range
of
marginal
costs
shown
here
reflects
the
range
of
requirements.

The
EPA
does
not
believe
that
it
has
sufficient
information,
for
today's
rulemaking,
to
treat
controls
on
source
categories
other
than
certain
EGUs
as
providing
highly
cost­
effective
emissions
reductions.
The
CAA
Section
110
permits
States
to
choose
the
sources
and
source
categories
that
will
be
controlled
in
order
to
meet
applicable
emission
and
air
quality
requirements.
This
means
that
some
States
may
choose
to
meet
their
CAIR
obligations
by
imposing
control
requirements
on
sources
other
than
EGUs.

As
examples
of
cost­
effective
actions
that
States
can
take
in
efforts
to
provide
for
attainment
with
the
air
quality
standards,
Table
IV­
8
presents
estimated
average
costs
for
potential
local
mobile
source
NOx
control
actions.
249
The
EPA
received
these
cost
data
during
the
public
comments
on
the
NPR.

Table
IV­
8.
Average
Costs
of
Potential
Local
Mobile
Source
Control
Actions
to
Reduce
NOx
Emissions
($
per
Ton)
1
Source
Category
Average
Cost
per
Ton
MWCOG
Analysis:
Mobile
Source,
Bicycle
racks
in
DC
$
9,000
MWCOG
Analysis:
Mobile
Source,
Telecommuting
Centers
$
7,300
MWCOG
Analysis:
Mobile
Source,
Government
Action
Days
(
ozone
action
days)
$
5,000
MWCOG
Analysis:
Mobile
Source,
Permit
Right
Turn
on
Red
$
1,200
MWCOG
Analysis:
Mobile
Source,
Employer
Outreach
$
3,500
MWCOG
Analysis:
Mobile
Source,
Mass
Marketing
Campaign
$
2,900
MWCOG
Analysis:
Mobile
Source,
Transit
Prioritization
$
8,500
1
Washington
DC
Metro
Area
MWCOG
Analysis
of
Potential
Reasonably
Available
Control
Measures
(
RACM).
Projects
determined
to
be
"
Possible"
by
MWCOG
but
not
RACM
because
benefits
from
the
possible
control
measures
do
not
meet
the
8.8
tpd
NOx
or
34.0
tpd
VOC
threshold
necessary
for
RACM.
These
costs
may
not
be
in
1999
dollars.
(
www.
mwcog.
org/
uploads/
committee­
documents/
z1ZZXg20040217144350.
pdf)
Comments
submitted
to
the
EPA
CAIR
docket
from
the
Clean
Air
Task
Force
et
al.,
dated
March
30,
2004,
included
costs
from
the
MWCOG
analysis.

(
II)
Cost
Effectiveness
of
CAIR
Annual
NOx
Reductions
Table
IV­
9
provides
the
average
and
marginal
costs
of
annual
NOx
reductions
under
CAIR
for
2009
and
2015.
These
costs
are
updated
from
the
NPR
figures
 
the
EPA
analyzed
the
costs
of
the
CAIR
using
an
updated
version
of
IPM
(
documentation
for
the
IPM
update
is
in
the
docket).

Further,
EPA
modified
the
modeling
to
match
the
final
CAIR
strategy
(
see
section
IV.
A.
1
for
a
description
of
EPA's
CAIR
IPM
modeling).
250
15
The
CSP
consists
of
200,000
tons,
which
is
apportioned
to
each
of
the
23
States
and
the
District
of
Columbia
that
are
required
by
CAIR
to
make
annual
NOx
reductions,
as
well
as
the
2
States
(
Delaware
and
New
Jersey)
for
which
EPA
is
proposing
to
require
annual
NOx
reductions.
CAIR
provides
for
a
Compliance
Supplement
Pool
(
CSP)
of
NOx
allowances
that
can
be
used
for
compliance
with
the
annual
NOx
reduction
requirements.
The
CSP
is
discussed
in
detail
later
in
this
preamble.
The
EPA
used
IPM
to
model
marginal
costs
of
CAIR
with
the
CSP.
The
magnitude
of
the
NOx
CSP
is
relatively
small
compared
to
the
annual
NOx
budget,
65
thus
the
CSP
does
not
significantly
impact
the
marginal
costs
(
see
Table
IV­
9).

As
with
SO2
marginal
costs,
EPA
considered
the
sensitivity
of
the
NOx
marginal
cost
results
to
assumptions
of
higher
electric
growth
and
future
natural
gas
prices
than
the
Agency
used
in
the
base
case,
as
shown
in
Table
IV­
9.

Table
IV­
9.
Estimated
Costs
per
Ton
of
Annual
NOx
Controlled
Under
CAIR
1
Type
of
Cost
Effectiveness
2009
2015
Average
Cost
­
Main
Case
$
500
$
700
Marginal
Cost
­
Main
Case
$
1,300
$
1,600
Marginal
Cost
B
With
Compliance
Supplement
Pool
(
CSP)
$
1,300
$
1,600
Sensitivity
Analysis:
Marginal
Cost
Using
Alternate
Electricity
Growth
and
Natural
Gas
Price
Assumptions
$
1,400
$
1,700
1
The
EPA
IPM
modeling
2004,
available
in
the
docket.
1999$
per
ton.

These
estimated
NOx
control
costs
under
CAIR
reflect
251
annual
EGU
NOx
caps
of
1.5
million
tons
in
2009
and
1.3
million
tons
in
2015
within
the
CAIR
annual
NOx
control
region
(
the
23
States
and
DC
that
must
make
annual
reductions).
In
both
the
main
IPM
modeling
case
and
the
modeling
case
that
includes
the
CSP,
projected
annual
NOx
emissions
in
the
CAIR
region
will
be
about
1.5
million
tons
in
2009
and
1.3
million
tons
in
2015.
The
projected
emissions
are
very
similar
in
both
modeling
cases
because
the
CSP
is
relatively
small
compared
to
the
annual
NOx
budget.

Average
costs
shown
for
2015
are
based
on
the
amount
of
reductions
that
would
achieve
the
total
difference
in
projected
emissions
between
the
base
case
conditions
and
CAIR
in
the
year
2015.
These
costs
are
not
based
on
the
increment
in
reductions
between
2009
and
2015.
(
A
more
detailed
description
of
the
final
CAIR
SO2
and
NOx
control
requirements
is
provided
later
in
today's
preamble.)

Most
of
the
States
subject
to
today's
PM2.5
control
requirements
have
been
subject
to
the
NOx
SIP
Call
requirements.
Some
sources
in
these
States
have
installed
SCRs,
and
run
them
during
the
ozone
season.
These
sources
might
comply
with
the
PM2.5
annual
NOx
requirements
by,
at
least
in
part,
running
the
SCR
controls
for
the
remaining
months
of
the
year.
Under
these
circumstances,
the
252
compliance
costs
for
the
PM2.5
SIP
requirements
are
lower.

Table
IV­
10
provides
estimated
costs
per
ton
of
NOx
for
non­
ozone
season
reductions
under
CAIR.
These
figures
are
updated
from
the
NPR
calculations
 
the
EPA
analyzed
the
costs
of
the
CAIR
using
an
updated
version
of
IPM
(
documentation
for
the
IPM
update
is
in
the
docket)
and
modeled
controls
on
a
region
that
more
closely
matches
the
region
affected
by
CAIR.

Table
IV­
10.
Predicted
Costs
per
Ton
of
Non­
Ozone
Season
NOx
Controlled
Under
CAIR
1
Type
of
Cost
Effectiveness
2009
2015
Average
Cost
$
500
$
500
1
The
EPA
IPM
modeling
2004,
available
in
the
docket.
1999$
per
ton.

The
estimated
non­
ozone
season
NOx
costs,
like
the
annual
NOx
costs,
are
on
the
low
end
of
the
cost
effectiveness
range
described
in
Table
IV­
6.
The
EPA
considers
the
2015
and
also
the
2009
costs
to
represent
highly
cost­
effective
controls.

Environmental
Defense
reached
similar
conclusions
regarding
the
cost
effectiveness
of
non­
ozone
season
NOx
reductions,
as
described
in
their
report
"
A
Plan
for
All
Seasons:
Costs
and
Benefits
of
Year­
Round
NOx
Reductions
in
Eastern
States
(
2002)."
As
stated
in
that
report,
"[
As
Figure
4
shows,]
extending
NOx
reductions
throughout
the
253
year
results
in
dramatic
decreases
in
the
per­
ton
costs
of
NOx
emission
reductions
for
the
19
NOx
SIP
Call
States.

This
is
because
the
bulk
of
the
cost
for
reducing
NOx
emissions
from
power
plants
lies
in
the
capital
investment
in
the
control
equipment.
Once
the
primary
investment
has
been
made,
it
costs
relatively
little
to
continue
running
the
control
equipment
beyond
the
summer
months
required
by
EPA's
NOx
SIP
Call."
Environmental
Defense
based
these
conclusions
on
analysis
conducted
by
Resources
for
the
Future
(
RFF).
In
an
RFF
paper,
"
Cost­
Effective
Reduction
of
NOx
Emissions
from
Electricity
Generation
(
July
2001),"
RFF
draws
similar
conclusions.

(
III)
NOx
Cost
Comparison
for
CAIR
Requirements
The
EPA
believes
that
selecting
as
highly
costeffective
amounts
at
the
lower
end
of
these
average
and
marginal
cost
ranges
is
appropriate
for
reasons
explained
above
in
this
section
of
the
preamble.

As
discussed
above,
although
in
the
NOx
SIP
Call
the
cost
level
selected
was
not
at
the
low
end
of
the
reference
range
of
costs,
if
the
NOx
SIP
Call
costs
were
for
annual
rather
than
seasonal
controls
they
would
have
been
lower
relative
to
the
other
control
costs
on
the
reference
list
which
were
mostly
for
annual
programs.

For
annual
NOx,
the
range
of
average
cost
effectiveness
254
extends
broadly,
from
under
$
200
to
thousands
of
dollars
(
Table
IV­
6).
The
2015
estimated
average
costs
for
CAIR
annual
NOx
control
of
$
700
are
consistent
with
the
lower
end
of
this
range.

Less
information
is
available
for
the
marginal
costs
of
controls
than
for
average
costs.
Looking
at
the
available
marginal
costs
(
Table
IV­
7),
the
2015
CAIR
marginal
costs
for
annual
NOx
controls
are
at
the
lower
end
of
the
range.

The
EPA
also
evaluated
the
cost
effectiveness
of
the
2009
cap,
and
concluded
that
the
2009
requirements
are
highly
cost­
effective.

(
IV)
Cost
Effectiveness:
Marginal
Cost
Curves
for
Annual
NOx
Control
As
with
SO2
controls,
EPA
also
considered
the
cost
effectiveness
of
alternative
stringency
levels
for
NOx
control
for
today's
action
by
examining
changes
in
the
marginal
cost
curve
at
varying
levels
of
emissions
reductions.
Figure
IV­
3
shows
that
the
"
knee"
in
the
2010
marginal
cost
effectiveness
curve
for
EGUs
 
the
point
where
the
cost
of
controlling
a
ton
of
NOx
begins
to
increase
at
a
noticeably
higher
rate
 
appears
to
occur
at
over
$
1,700
per
ton
of
NOx.
Although
EPA
conducted
this
marginal
cost
curve
analysis
based
on
an
initial
NOx
control
phase
in
2010,
the
255
16
EPA
is
using
the
knee
in
the
curve
analysis
solely
to
show
that
the
required
emissions
reductions
are
very
cost
effective.
The
marginal
cost
curve
reflects
only
emissions
reduction
and
cost
information,
and
not
other
considerations.
We
note
that
it
might
be
reasonable
in
a
particular
regulatory
action
to
require
emissions
reductions
past
the
knee
of
the
curve
to
reduce
overall
costs
of
meeting
the
NAAQS
or
to
achieve
benefits
that
exceed
costs.
results
would
be
very
similar
for
2009,
which
is
the
initial
NOx
phase
in
the
final
CAIR.
Figure
IV­
4
shows
that
the
"
knee"
in
the
2015
marginal
cost
effectiveness
curve
for
EGUs
appears
to
occur
at
over
$
1,700
per
ton
of
NOx.
(
The
EPA
based
these
marginal
NOx
cost
effectiveness
curves
on
the
electricity
growth
and
natural
gas
price
assumptions
in
the
main
CAIR
IPM
modeling
run.
Marginal
cost
effectiveness
curves
based
on
other
electric
growth
and
natural
gas
price
assumptions
would
look
different,
therefore
it
would
not
be
appropriate
to
compare
the
curves
here
to
the
marginal
costs
based
on
the
IPM
modeling
sensitivity
run
that
used
EIA
assumptions.)
The
EPA
used
the
Technology
Retrofitting
Updating
Model
(
TRUM),
a
spreadsheet
model
based
on
IPM,
for
this
analysis.
These
results
make
clear
that
this
rule
is
very
cost­
effective
because
the
control
level
is
below
the
point
at
which
the
cost
begins
to
increase
at
a
significantly
higher
rate.

In
this
manner,
these
results
corroborate
EPA's
findings
above
concerning
the
cost
effectiveness
of
the
emissions
reductions.
66
256
As
in
the
case
of
SO2
controls,
described
above,
it
should
be
noted
that
similar
analysis
for
other
source
categories
may
yield
different
curves.
257
M
a
rg
in
a
l
C
o
st
C
u
rv
e
o
f
A
b
a
te
m
e
n
t
fo
r
A
n
n
u
a
l
N
O
X
Em
issio
n
s
fro
m
EG
U
s
in
2
0
1
0
(
S
O
2
Em
issio
n
s
a
t
5
.3
m
i
l
l
io
n
to
n
s)

$
1
,0
0
0
$
1
,5
0
0
$
2
,0
0
0
$
2
,5
0
0
$
3
,0
0
0
0
.5
0
1
.0
0
1
.5
0
2
.0
0
2
.5
0
M
illio
n
T
o
n
s
o
f
N
O
x
Em
it
te
d
in
C
A
IR
R
e
g
io
n
S
o
u
r
c
e
:
EP
A
T
RU
M
A
n
a
lys
is
,
A
u
g
u
s
t
2
0
0
4
Marginal
Cost
(
1999$/
ton)
N
O
x
P
r
ic
e
($
/
to
n
)

Marginal
Cost
Curve
of
Abatement
for
Annual
NOX
Emissions
from
EGUs
in
2015
(
SO2
Emissions
at
4.1
million
tons)

$
1,000
$
1,500
$
2,000
$
2,500
$
3,000
0.50
1.00
1.50
2.00
2.50
Million
Tons
of
NOx
Emitte
d
in
CAIR
Re
gion
Source
:
EPA
TRUM
Analy
sis,
August
2004
Marginal
Cost
(
1999$/
ton)

NOx
Price
($/
ton)
Figure
IV­
3
Figure
IV­
4
258
(
V)
Cost
Effectiveness
of
Ozone
Season
NOx
Reductions
The
CAIR
requires
ozone
season
NOx
emissions
reduction
for
all
States
determined
to
contribute
significantly
to
ozone
nonattainment
downwind
(
25
States
and
the
District
of
Columbia).
The
EPA
used
IPM
to
model
average
and
marginal
costs
of
the
ozone
season
reductions
assuming
EGU
controls.

In
this
modeling
case,
EPA
modeled
an
ozone
season
NOx
cap
for
the
region
affected
by
CAIR
for
downwind
ozone
nonattainment,
but
did
not
include
the
CAIR
annual
SO2
or
NOx
caps.
Based
on
that
modeling,
Table
IV­
11
provides
estimated
average
and
marginal
costs
of
regionwide
ozone
season
NOx
reductions
for
2009
and
2015.
Table
IV­
11
shows
the
estimated
cost
effectiveness
of
today's
ozone
season
NOx
control
requirements
for
8­
hour
transport
SIPs.

Table
IV­
11.
Estimated
Costs
per
Ton
of
Ozone
Season
NOx
Controlled
Under
CAIR
1
Type
of
Cost
Effectiveness
2009
2015
Average
Cost
$
900
$
1,800
Marginal
Cost
$
2,400
$
3,000
1
The
EPA
IPM
modeling
2004,
available
in
the
docket.
1999$
per
ton.

These
estimated
NOx
control
costs
are
based
on
ozone
season
EGU
NOx
caps
of
0.6
million
tons
in
2009
and
0.5
million
tons
in
2015
within
the
CAIR
ozone
season
NOx
259
17
For
both
the
NOx
SIP
Call
and
CAIR,
the
NOx
control
costs
on
the
reference
lists
are
generally
for
annual
reductions.
The
EPA
compared
the
costs
of
ozone
season
reductions
under
the
NOx
SIP
Call,
as
well
as
ozone
season
CAIR
NOx
reductions,
to
the
annual
reduction
programs
on
the
reference
lists.
control
region.
Average
costs
shown
for
2015
are
based
on
the
amount
of
reductions
that
would
achieve
the
total
difference
in
projected
emissions
between
the
base
case
conditions
and
CAIR
in
the
year
2015.
These
costs
are
not
based
on
the
increment
in
reductions
between
2009
and
2015.

(
A
more
detailed
description
of
the
final
CAIR
SO2
and
NOx
control
requirements
is
provided
later
in
today's
preamble.)

The
EPA
believes
that
selecting
as
highly
costeffective
amounts
at
the
lower
end
of
the
average
and
marginal
cost
ranges
is
appropriate
for
reasons
explained
above
in
section
IV
in
this
preamble.

In
the
NOx
SIP
Call,
EPA
identified
average
costs
of
$
2,500
(
1999$)
(
or
$
2,000
(
1990$))
as
highly
costeffective
67
The
estimated
average
costs
of
regionwide
ozone
season
NOx
control
under
CAIR
are
$
1,800
per
ton
in
2015
and
$
900
per
ton
in
2009.
Thus,
with
respect
to
average
costs
the
controls
for
the
final
phase
(
2015)
cap,

which
are
below
the
$
2,500
identified
in
the
NOx
SIP
Call,

are
also
highly
cost­
effective,
as
are
those
for
the
2009
cap.
In
addition,
the
estimated
average
costs
of
CAIR
ozone
260
18
In
the
NOx
SIP
Call
EPA
used
average,
not
marginal,
costs
to
evaluate
cost
effectiveness.
For
the
reasons
discussed
above
we
are
evaluating
both
average
and
marginal
costs
for
CAIR.
season
NOx
control
are
at
the
lower
end
of
the
reference
range
of
average
annual
NOx
control
costs
(
the
reference
list
of
average
annual
NOx
control
costs
is
presented
above).

Similarly,
the
estimated
marginal
costs68
of
ozone
season
CAIR
NOx
controls
are
within
EPA's
reference
range
of
marginal
costs,
at
the
lower
end
of
the
range
(
the
reference
list
of
marginal
annual
NOx
control
costs
is
presented
above).
We
note
that
the
marginal
costs
in
the
reference
range
are
for
annual
NOx
reductions,
and
would
likely
be
higher
for
ozone
season
only
programs.
Considering
both
average
and
marginal
costs,
the
CAIR
ozone
season
control
level
is
highly
cost­
effective.

For
purposes
of
estimating
costs
of
ozone
season
control
under
CAIR,
EPA
set
up
this
modeling
case
with
CAIR
ozone
season
NOx
requirements
but
without
the
annual
NOx
requirements.
The
Agency
believes
that
the
cost
of
the
ozone
season
CAIR
requirements
will
actually
be
lower
than
the
costs
presented
here
because
interactions
will
occur
between
the
CAIR
annual
and
ozone
season
NOx
control
261
19
Estimated
costs
for
regionwide
CAIR
NOx
controls
during
the
ozone
season
are
higher
than
the
average
and
marginal
costs
for
CAIR
annual
NOx
controls.
This
is
because,
as
noted
above,
the
capital
costs
of
installing
NOx
control
equipment
would
be
largely
identical
whether
the
SCR
will
be
operated
during
the
ozone
season
only
or
for
the
entire
year.
However,
the
amount
of
reductions
would
be
less
if
the
control
equipment
were
operated
only
during
the
ozone
season
compared
to
annual
operation.
requirements.
69
In
addition,
for
States
in
both
programs,

the
same
controls
achieving
annual
reductions
for
PM
purposes
will
achieve
ozone
season
reductions
for
ozone
purposes;
this
is
not
reflected
in
our
cost­
per­
ton
estimates.

As
with
SO2
controls,
and
annual
NOx
controls,
EPA
also
considered
the
cost
effectiveness
of
alternative
stringency
levels
for
CAIR
NOx
reductions
for
ozone
purposes
by
examining
changes
in
the
marginal
cost
curve
at
varying
levels
of
emissions
reductions.
Figure
IV­
5
shows
that
the
"
knee"
in
the
2010
marginal
cost
effectiveness
curve
for
ozone
season
NOx
reductions
from
EGUs
 
the
point
where
the
cost
of
controlling
an
ozone
season
ton
of
NOx
begins
to
increase
at
a
noticeably
higher
rate
 
appears
to
occur
somewhere
between
$
3,000
and
$
4,000
per
ton
of
NOx.

Although
EPA
conducted
this
marginal
cost
curve
analysis
based
on
an
initial
NOx
control
phase
in
2010
the
results
would
be
very
similar
for
2009,
which
is
the
initial
NOx
phase
in
the
final
CAIR.
Figure
IV­
6
shows
that
the
"
knee"
262
20
EPA
is
using
the
knee
in
the
curve
analysis
solely
to
show
that
the
required
emissions
reductions
are
very
cost
effective.
The
marginal
cost
curve
reflects
only
emissions
reduction
and
cost
information,
and
not
other
considerations.
We
note
that
it
might
be
reasonable
in
a
particular
regulatory
action
to
require
emissions
reductions
past
the
knee
of
the
curve
to
reduce
overall
costs
of
meeting
the
NAAQS
or
to
achieve
benefits
that
exceed
costs.
As
in
the
case
of
SO2
controls,
described
above,
it
should
be
noted
that
similar
analysis
for
other
source
categories
may
yield
different
curves.
in
the
2015
marginal
cost
effectiveness
curve
for
ozone
season
NOx
reductions
from
EGUs
appears
to
occur
somewhere
between
$
3,000
and
$
4,000
per
ton
of
NOx.
The
EPA
used
the
Technology
Retrofitting
Updating
Model
(
TRUM),
a
spreadsheet
model
based
on
the
IPM,
for
this
analysis.
These
results
make
clear
that
CAIR
NOx
reductions
for
ozone
purposes
are
very
cost­
effective
because
the
control
level
is
below
the
point
at
which
the
cost
begins
to
increase
at
a
significantly
higher
rate.

In
this
manner,
these
results
corroborate
EPA's
findings
above
concerning
the
cost
effectiveness
of
the
emissions
reductions.
70
263
Marginal
Cost
Curve
of
Ozone
Season
NOx
Abatement
in
2010
(
Base
case
SO2
emissions)

$
2,000
$
2,500
$
3,000
$
3,500
$
4,000
$
4,500
$
5,000
$
5,500
$
6,000
$
6,500
$
7,000
­
0.10
0.20
0.30
0.40
0.50
0.60
0.70
Million
Tons
of
NOx
Emitted
in
CAIR
Ozone
Region
during
Ozone
Season
Marginal
Cost
(
1999
$/
ton)

NOx
Price
($/
ton)

Results
using
TRUM;
IPM
results
would
differ.
Figure
IV­
5
264
M
a
r
g
in
a
l
C
o
s
t
C
u
r
v
e
o
f
O
z
o
n
e
S
e
a
s
o
n
N
O
x
A
b
a
te
m
e
n
t
in
2
0
1
5
(
B
a
s
e
c
a
s
e
S
O
2
e
m
is
s
io
n
s
)

$
2
,0
0
0
$
2
,5
0
0
$
3
,0
0
0
$
3
,5
0
0
$
4
,0
0
0
$
4
,5
0
0
$
5
,0
0
0
$
5
,5
0
0
$
6
,0
0
0
$
6
,5
0
0
$
7
,0
0
0
­
0
.1
0
0
.2
0
0
.3
0
0
.4
0
0
.5
0
0
.6
0
0
.7
0
M
i
l
l
i
o
n
T
o
n
s
o
f
N
O
x
E
m
i
t
t
e
d
i
n
C
A
IR
O
z
o
n
e
R
e
g
i
o
n
d
u
r
i
n
g
O
z
o
n
e
S
e
a
s
o
n
Marginal
Cost
(
1999
$/
ton)
N
O
x
P
r
ic
e
($
/
to
n
)

R
e
s
u
lts
u
s
in
g
T
R
U
M
;
IP
M
r
e
s
u
lts
w
o
u
ld
d
if
fe
r
.
Figure
IV­
6
265
B.
 
What
Other
Sources
Did
EPA
Consider
when
Determining
Emission
Reduction
Requirements?

1.
 
Potential
Sources
of
Highly
Cost­
Effective
Emissions
Reductions
In
today's
rulemaking,
EPA
determines
the
amount
of
regionwide
emissions
reductions
required
by
determining
the
amount
of
emissions
reductions
that
could
be
achieved
through
the
application
of
highly
cost­
effective
controls
on
certain
EGUs.
The
EPA
has
reviewed
other
source
categories,

but
concludes
that
for
purposes
of
today's
rulemaking,
there
is
insufficient
information
to
conclude
that
highly
cost­
effective
controls
are
available
for
other
source
categories.

b.
Mobile
and
Area
Sources
In
the
NPR
(
69
FR
4610),
EPA
explained
that
"
it
did
not
identify
highly
cost­
effective
controls
on
mobile
or
area
sources."
No
comments
were
received
suggesting
that
mobile
or
area
sources
should
be
controlled.
Therefore,
in
developing
emission
reduction
requirements,
EPA
is
not
assuming
any
emissions
reductions
from
mobile
or
area
sources.

b.
 
Non­
EGU
Boilers
and
Turbines
The
largest
single
category
of
stationary
source
non­

EGUs
are
large
non­
EGU
boilers
and
turbines.
This
source
266
category
emits
both
SO2
and
NOx.
In
the
CAIR
NPR,
EPA
proposed
not
to
include
any
potential
SO2
or
NOx
emissions
reductions
from
non­
EGU
boilers
and
turbines
as
constituting
"
highly
cost­
effective"
reductions
and
thus
to
be
taken
into
account
in
establishing
emissions
requirements
because
EPA
believed
it
had
insufficient
information
on
their
control
costs,
particularly
costs
associated
with
the
integration
of
NOx
and
SO2
controls.
In
addition,
based
on
information
EPA
does
have,
projected
base
case
(
without
the
CAIR)
emissions
of
SO2
and
NOx
from
these
sources
are
significantly
lower
than
projected
EGU
emissions.
The
EPA
projects
that
in
2010
under
base
case
conditions,
EGUs
would
contribute
70
percent
of
SO2
in
the
CAIR
region
compared
to
15
percent
from
non­

EGU
boilers
and
turbines
in
the
CAIR
region.
The
Agency
also
predicts
that
in
2010
under
the
base
case,
EGUs
would
contribute
25
percent
of
NOx
emissions
in
the
CAIR
region
compared
to
16
percent
from
non­
EGU
boilers
and
turbines
in
the
CAIR
region.
Thus,
simply
on
an
absolute
basis,
non­
EGU
emissions
are
relatively
less
significant
than
emissions
from
EGUs.
The
EPA
is
finalizing
its
proposed
approach
to
these
sources
and
has
not
based
today's
requirements
on
any
presumed
availability
of
highly
cost­
effective
emissions
reductions
from
non­
EGU
boilers
and
turbines.

A
number
of
commenters
believe
EPA
should
determine
267
that
emissions
reductions
from
non­
EGUs
should
be
taken
into
account
in
establishing
emission
requirements
because,
they
believe,
highly
cost­
effective
controls
are
available
for
these
sources.
These
commenters
argued
that
highly
costeffective
controls
are
available
for
these
sources
and
that
EPA
should
have
sufficient
emissions
and
control
cost
information
because
the
same
sources
were
included
in
the
NOx
SIP
Call.

In
addition,
while
it
is
true
that
these
sources
were
included
in
the
NOx
SIP
Call,
EPA
only
addressed
NOx
reductions
from
these
sources.
Neither
SO2
reductions
nor
monitoring
of
SO2
emissions
is
required
by
the
NOx
SIP
Call.

As
a
result,
for
these
sources,
EPA
has
less
reliable
SO2
emissions
data
and
very
little
information
on
the
integration
of
NOx
and
SO2
controls.
Although
EPA
has
more
information
on
NOx
emissions
from
these
sources
because
of
the
NOx
SIP
Call
(
and
other
programs
in
the
northeastern
U.
S.),
the
geographic
coverage
of
the
CAIR
includes
some
States
that
were
not
included
in
the
NOx
SIP
Call,
some
of
which
States
contain
significant
amounts
of
industry.
The
EPA
has
even
less
emissions
data
from
non­
EGUs
in
these
non­
SIP
call
States
affected
by
the
CAIR.
While
EPA
has
incorporated
State­
submitted
emissions
inventory
data
for
1999
into
its
analysis
for
the
CAIR,
even
this
data
is
268
generally
lacking
information
on
fuel,
sulfur
content,
and
existing
controls.
Without
this
data,
it
is
very
difficult
to
assess
the
emission
reduction
opportunities
available
for
non­
EGU
boilers
and
turbines.
Furthermore,
with
regards
to
NOx,
many
non­
EGU
boilers
and
turbines
are
making
reductions
using
low
NOx
burners
(
the
control
technology
EPA
assumed
in
making
the
cost­
effectiveness
determinations
in
the
NOx
SIP
Call).
Since
these
controls
are
operated
year­
round,
annual
emissions
reductions
are
already
being
obtained
from
many
of
these
units.
Additional
reductions
would
likely
be
less
cost
effective.

Another
commenter
stated
that
non­
EGU
"
major
sources"

are
subject
to
the
requirements
of
title
V
of
the
CAA
and,

therefore,
EPA
should
have
adequate
emissions
data
provided
as
part
of
the
sources'
permitting
obligations.
However,

title
V
simply
requires
that
a
source's
permit
include
the
substantive
requirements
(
such
as
emission
monitoring
requirements)
imposed
by
other
sections
of
the
CAA
and
does
not
itself
impose
any
substantive
requirements.
Thus,
the
mere
fact
that
a
source
is
a
major
source
required
to
have
a
title
V
permit
does
not
mean
that
the
source
is
monitoring
and
submitting
emissions,
fuel,
and
control
device
data.

Many
such
sources
do
not,
in
fact,
provide
such
data.

One
commenter
submitted
cost
information
for
FGD
269
technology
applications
on
industrial
boilers.
However,
the
information
submitted
by
the
commenter
was
based
on
the
use
of
a
limited
number
of
technologies
and
for
a
limited
number
of
boiler
sizes.
The
EPA
does
not
believe
that
the
limited
information
demonstrates
that
SO2
emissions
from
these
sources
could
be
controlled
in
a
highly
cost­
effective
manner
across
the
entire
sector
in
question,
or
to
what
level
the
emissions
could
be
controlled.

Some
commenters
recommended
including
non­
EGU
boilers
and
turbines
because
in
the
future,
after
reductions
from
EGUs
are
made,
the
relative
contribution
of
non­
EGU
boilers
and
turbines
to
the
total
NOx
and
SO2
emissions
will
increase.
The
EPA
agrees
that
the
relative
contribution
of
non­
EGUs
to
total
NOx
and
SO2
emissions
will
increase
in
the
future
if
States
choose
to
meet
their
CAIR
emissions
reduction
obligations
solely
by
way
of
emission
reductions
made
by
EGUs.
However,
EPA
does
not
believe
that
this,
by
itself,
provides
any
basis
for
determining
that
in
the
context
of
this
rule
emissions
reductions
from
non­
EGUs
should
be
determined
to
be
highly
cost­
effective.
As
discussed
above,
EPA
believes
it
is
necessary
to
have
more
reliable
emissions
data
and
better
control
cost
information
for
these
sources
before
assuming
reductions
from
them
in
the
CAIR.
The
EPA
is
working
to
improve
its
inventory
of
270
emissions
and
control
cost
information
for
non­
EGU
boilers
and
turbines.
Specifically,
we
are
assessing
the
emission
inventory
submittals
for
2002
made
by
States
in
response
to
the
relatively
new
requirements
of
40
CFR
part
51
(
the
Consolidated
Emission
Reporting
Rule),
and
we
will
work
with
States
whose
submissions
appear
to
have
gaps
in
required
data.
We
also
note
that
EPA
provides
financial
and
technical
support
for
the
efforts
of
the
five
Regional
Planning
Organizations
to
coordinate
among
and
assist
States
in
improving
emission
inventories.

Another
commenter
expressed
concern
that
if
the
decision
whether
to
control
large
industrial
boilers
is
left
to
the
States,
the
result
may
be
inequitable
treatment
of
EGUs
on
a
State­
by­
State
basis,
particularly
with
respect
to
allowances,
and
therefore
it
would
make
sense
to
require
NOx
and
SO2
reductions
from
large
industrial
boilers.
Section
110
of
the
CAA
leaves
the
ultimate
choice
of
what
sources
to
control
to
the
States,
and
EPA
cannot
require
States
to
control
non­
EGUs.
Even
if
EPA
had
included
reductions
from
non­
EGUs
in
determining
the
total
amount
of
reductions
required
under
the
CAIR,
EPA
could
not
have
required
any
State
to
achieve
those
reductions
through
emission
limitations
on
non­
EGUs.

The
recent
economic
circumstances
faced
by
the
271
manufacturing
sector
accentuates
EPA's
concerns
about
the
lack
of
reliable
emissions
data
and
control
information
regarding
non­
EGUs.
We
note
that
the
U.
S.
manufacturing
sector
was
adversely
affected
by
the
latest
business
cycle
slowdown.
As
noted
in
the
2004
Economic
Report
of
the
President,
the
manufacturing
sector
was
hit
earlier,
longer,

and
harder
than
other
sectors
of
the
economy.
The
2004
Report
also
points
out
that,
although
manufacturing
output
has
dropped
much
more
than
the
real
gross
domestic
product
(
GDP)
during
past
business
cycles,
the
latest
recovery
has
been
unusual
because
it
has
been
weaker
for
the
manufacturing
sector
than
the
recovery
in
the
real
GDP.
The
disparity
across
sectors
(
and
even
within
individual
sectors)
in
the
economic
condition
of
firms
reinforces
EPA's
concerns
about
moving
forward
to
consider
emission
controls
on
non­
EGUs
at
this
time.

As
explained
elsewhere
in
this
preamble,
although
the
CAIR
does
not
require
that
States
achieve
the
required
emissions
reductions
by
controlling
particular
source
categories,
we
expect
that
States
will
meet
their
CAIR
obligations
by
requiring
emissions
reductions
from
EGUs
because
such
reductions
are
highly
cost
effective.
We
believe
the
States
are
in
the
best
position
to
make
decisions
regarding
any
additional
control
requirements
for
272
non­
EGU
sources.
In
making
such
decisions,
States
may
take
into
consideration
all
relevant
factors
and
information,

such
as
differences
across
States
in
the
need
for
control,

differences
in
relative
contribution
of
various
sources,
and
differences
in
the
operating
and
economic
conditions
across
sources.

c.
 
Other
Non­
EGU
Stationary
Sources
In
the
NPR
and
in
the
technical
support
document
entitled
"
Identification
and
Discussion
of
Sources
of
Regional
Point
Source
NOx
and
SO2
Emissions
Other
Than
EGUs
(
January
2004),"
EPA
applied
a
similar
rationale
for
non­
EGU
stationary
sources
other
than
boilers
and
turbines.
For
SO2,
EPA
noted
that
the
emissions
from
such
sources
were
a
relatively
small
part
of
the
emissions
inventory,
and
we
also
noted
the
lack
of
information
on
costs.
For
NOx,
we
explained
that
more
information
was
available
than
for
SO2.

This
is
because
the
NOx
SIP
Call
included
consideration
of
emissions
control
measures
for
internal
combustion
(
IC)

engines
and
cement
kilns,
and
developed
cost
estimates
for
other
NOx­
emitting
categories
such
as
process
heaters
and
glass
manufacturing.
However,
we
believed
 
as
for
boilers
and
turbines,
discussed
above
 
that
insufficient
information
on
emission
control
options
and
costs,
was
available
to
apply
these
measures
to
the
entire
geographic
273
area
covered
by
the
proposed
rule.

No
adverse
comments
were
received
suggesting
inclusion
of
SO2
emissions
reductions
from
non­
EGU
stationary
sources
other
than
boilers
and
turbines.
Accordingly,
EPA
has
determined
not
to
consider
SO2
reductions
from
these
other
non­
EGU
stationary
sources.

Several
commenters
suggested
that
EPA
should
have
been
able
to
consider
NOx
emissions
reductions
from
non­
EGU
categories
other
than
boilers
and
turbines,
such
as
internal
combustion
(
IC)
engines
and
refinery
fluid
catalytic
cracking
units.
These
commenters
believed
such
reductions
were
demonstrated
to
be
cost
effective,
and
questioned
EPA's
assertion
that
insufficient
information
is
available.

Finally,
some
commenters
believe
EPA
should
have,
at
a
minimum,
required
that
controls
for
NOx
SIP
Call
sources
 
including
large
IC
engines
and
cement
kilns
 
should
be
extended
from
the
ozone
season
to
the
entire
year.

We
believe
it
likely
that
inclusion
in
today's
requirements
of
reductions
from
any
highly
cost­
effective
controls
 
if
available
 
for
these
categories
would
have
very
small
effects.
First,
most
of
the
States
included
in
the
CAIR
rule
were
also
included
in
the
NOx
SIP
Call,
so
that
many
of
the
emissions
reductions
that
would
be
available
from
these
sources
have
already
occurred
due
to
274
implementation
of
the
NOx
SIP
Call.
Second,
in
the
States
included
in
the
CAIR
rule,
but
which
were
not
covered
by
the
NOx
SIP
Call,
only
a
small
portion
of
NOx
emissions
come
from
cement
kilns
and
IC
engines
compared
to
EGUs.

Moreover,
in
some
parts
of
this
geographic
area,
in
particular
for
Texas,
many
sources
in
these
source
categories
are
already
regulated
under
ozone
nonattainment
plans
(
including
SIPs
for
the
Texas
cities
of
Houston,

Galveston,
and
Dallas).

Regarding
the
commenters'
recommendation
that
extending
NOx
SIP
Call
control
requirements
to
a
year­
round
basis
for
large
IC
engines
and
cement
kilns
should
be
considered
to
be
highly
cost
effective,
EPA
believes
that
few
emissions
reductions
would
be
achieved
from
doing
so.
The
types
of
controls
that
were
applied
in
the
NOx
SIP
Call
States,
while
required
to
be
in
place
only
during
the
ozone
season,
will,

as
a
practical
matter,
be
applied
on
a
year­
round
basis,

whether
or
not
so
required
by
today's
rule.
Most,
if
not
all,
of
the
NOx
SIP
Call
States
have
developed
regulations
to
control
NOx
emissions
from
IC
engines
and
cement
kilns
during
the
ozone
season.
The
control
of
choice
to
meet
these
reductions
from
large
lean
burn
IC
engines
is
low
emission
combustion
(
LEC),
which
for
retrofit
applications
is
a
substantial
equipment
modification
of
the
engine's
275
combustion
system.
The
engine
will
operate
with
LEC
year
round
because
this
modification
is
a
permanent
change
to
the
engine.
Most,
if
not
all,
new
large
lean­
burn
IC
engines
have
LEC.
In
addition,
year­
round
emissions
controls
are
already
required
for
rich­
burn
engines
greater
than
500
hp
which
will
likely
install
nonselective
catalyst
reduction
to
comply
with
the
recently
adopted
hazardous
air
pollutant
standards
(
see
final
rule
for
reciprocating
IC
engines,
69
FR
33474,
June
15,
2004).
For
cement
kilns,
the
controls
of
choice
are
low
NOx
burners
and
mid­
kiln
firing.
Low
NOx
burners
(
LNB)
are
a
permanent
part
of
the
kiln,
so
that
the
kiln
will
operate
year­
round
with
LNB.
Mid­
kiln
firing
is
a
kiln
modification
for
which
a
solid
and
slow
burning
fuel
(
typically
tires)
is
injected
in
the
mid­
kiln
area.
Due
to
tipping
fees
and
fuel
credits,
mid­
kiln
firing
results
in
an
operating
cost
savings.
After
this
system
is
installed,

year­
round
operation
is
expected.

C.
Schedule
for
Implementing
SO2
and
NOx
Emissions
Reduction
Requirements
for
PM2.5
and
Ozone
1.
Overview
In
the
NPR,
EPA
proposed
a
two­
phased
schedule
for
implementing
the
CAIR
annual
emission
reduction
requirements:
implementation
of
the
first
phase
would
be
required
by
January
1,
2010
(
covering
2010­
2014),
and
that
276
for
the
second
phase
by
January
1,
2015
(
covering
after
2014).
The
EPA
based
its
proposal
on
its
analysis
of
engineering,
financial,
and
other
factors
that
affect
the
timing
for
installing
the
emission
controls
that
would
be
most
cost­
effective
 
and
are
therefore
the
most
likely
to
be
adopted
­
for
States
to
meet
the
CAIR
requirements.

Those
air
pollution
controls
are
primarily
retrofitted
FGD
systems
(
i.
e.,
scrubbers)
for
SO2
and
SCR
systems
for
NOx
on
coal­
fired
power
plants.

The
EPA's
projections
showed
a
significant
number
of
affected
sources
installing
these
controls.
The
proposed
two­
phased
schedule
allowed
the
implementation
of
as
much
of
the
controls
as
feasible
by
an
early
date,
with
a
later
time
for
the
remaining
controls.

The
EPA
received
detailed,
technical
comments
from
commenters
who
argued
that
the
controls
could
not
be
implemented
until
later
than
proposed,
and
from
other
commenters
who
argued
that
the
controls
could
be
implemented
sooner
than
proposed.
The
EPA
has
reviewed
the
comments
and
has
conducted
additional
research
and
analyses
to
verify
availability
of
adequate
industrial
resources,
including
boilermakers,
for
constructing
the
emission
control
retrofits
required
by
CAIR.
These
analyses
are
based
on
conservative
assumptions,
including
those
suggested
by
the
277
21
The
NOx
SIP
Call
Rule
allowed
approximately
3­
1/
2
years
for
implementation
of
all
NOx
Controls.
commenters,
to
ensure
that
the
requirements
imposed
by
CAIR
do
not
result
in
shortages
of
the
required
resources
that
could
substantially
increase
construction
costs
for
pollution
controls
and
reduce
the
cost
effectiveness
of
this
program.

Today,
EPA
is
taking
final
action
to
require
the
annual
emissions
reductions
on
the
same
two­
phase
schedule
as
proposed.
However,
the
requirements
for
the
first
phase
include
two
separate
compliance
deadlines:
implementation
of
NOx
reductions
are
required
by
January
1,
2009
(
covering
2009­
2014)
and
for
SO2
reductions
by
January
1,
2010
(
covering
2010­
2014).
The
compliance
deadline
requirements
for
the
second
phase
are
the
same
as
proposed.
The
EPA
believes
that
its
action
is
consistent
with
the
Agency's
obligations
under
the
CAA
to
require
emission
reductions
for
obtaining
NAAQS
to
be
achieved
as
soon
as
practicable.
The
EPA
applied
the
same
criterion
in
implementing
the
NOx
SIP
Call,
which
was
based
on
a
single­
phased
schedule.
71
2.
Engineering
Factors
Affecting
Timing
for
Control
Retrofits
a.
NPR
In
the
NPR,
EPA
identified
the
availability
of
278
boilermakers
as
an
important
constraint
for
the
installation
of
significant
amounts
of
SCR
and
FGD
retrofits.

Boilermakers
are
skilled
laborers
that
perform
various
specialized
construction
activities,
including
welding
and
rigging,
for
boilers
and
high
pressure
vessels.
The
air
pollution
control
devices,
such
as
scrubber
and
SCR
vessels,

require
boilermakers
for
their
construction.
Apprentices
with
no
prior
work­
related
experience
complete
a
four­
year
training
program,
to
become
full
boilermakers.
For
apprentices
with
relevant
experience,
this
training
period
could
be
shorter.
For
example,
union
members
representing
the
shipbuilding
trade
could
be
expedited
into
the
boilermaker
division
within
a
year.

The
boilermaker
constraint
was
considered
more
important
for
the
initiation
of
the
first
phase
of
CAIR,

since
the
NOx
SIP
Call
experience
had
shown
that
many
sources
would
be
adverse
to
committing
significant
funds
to
install
controls
until
after
SIPs
were
finalized.
With
the
States
required
to
finalize
SIPs
in
18
months
after
the
signing
of
the
final
rule,
the
sources
would
have
three
years
in
which
to
complete
purchasing,
construction,
and
startup
activities
associated
with
these
controls,
to
meet
the
proposed
CAIR
deadline.

The
EPA's
projections
showed
power
plants
installing
279
51.4
gigawatts
(
GW)
of
FGD
and
28.2
GW
of
SCR
retrofits
during
the
first
CAIR
phase.
These
projections
include
retrofits
for
CAIR
as
well
as
retrofits
for
Base
Case
policies
(
i.
e.,
retrofits
for
existing
regulatory
requirements).
We
estimated
the
total
boilermaker­
years
required
for
installing
these
controls
at
12,700,
which
was
based
on
the
boilermakers
being
utilized
over
a
period
of
18
months
during
the
installation
process.
Also,
based
on
the
projected
boilermaker
population
in
the
timeframe
relevant
to
the
installation
of
these
controls,
we
estimated
that
14,700
boilermaker­
years
were
available
over
the
same
18­
month
period.
The
availability
of
approximately
15
percent
more
boilermaker­
years
than
required,
as
shown
by
these
estimates,
confirms
the
adequacy
of
this
critical
resource
for
CAIR
and
EPA
assumed
this
to
be
a
reasonable
contingency
factor.

The
EPA
also
determined
that
installation
of
the
projected
amounts
of
FGD
and
SCR
retrofits
could
be
completed
within
the
three­
year
period
available
for
CAIR.

This
determination
was
based
on
a
previous
report
prepared
by
EPA
for
the
proposed
Clear
Skies
Act,
"
Engineering
and
Economic
Factors
Affecting
the
Installation
of
Control
Technologies
for
Multi­
Pollutant
Strategies,"
(
docket
no.

OAR­
2003­
0053­
0106).
According
to
this
report,
an
average
280
of
21
months
are
required
to
install
SCR
on
one
unit,
and
27
months
to
install
a
scrubber
on
one
unit.
For
multiple
units
within
the
same
plant,
installation
of
controls
would
normally
be
staggered
to
avoid
operational
disruptions.
The
EPA
projected
that
the
maximum
number
of
multiple­
unit
controls
required
for
each
affected
facility
could
all
be
installed
within
three
years.
The
NPR
proposal
included
a
second
phase,
with
a
compliance
deadline
of
January
1,
2015.

The
EPA's
projections
showed
power
plants
installing
19.1
GW
of
FGD
and
31.7
GW
of
SCR
retrofits
by
2015,
which
included
retrofits
for
CAIR
as
well
as
retrofits
for
Base
Case
policies
(
i.
e.,
retrofits
for
existing
regulatory
requirements).
Availability
of
boilermaker
labor
was
not
an
important
constraint
for
this
phase.

b.
Comments
The
EPA
received
several
comments
relating
to
the
requirements
for
the
two­
phased
implementation
program,
the
emission
caps
and
compliance
deadline
for
each
phase,
and
resources
required
to
install
necessary
controls.
The
commenters
offered
opposing
viewpoints,
which
can
be
broadly
categorized
as
follows:

i.
Several
commenters
indicated
that
the
compliance
deadline
of
2010
for
the
first
phase
was
not
attainable
and
argued
that
EPA
should
either
extend
the
deadline,
or
set
281
higher
emission
caps
for
this
phase.
The
commenters
raised
the
following
specific
points
in
support
of
their
concerns:

(
I)
The
time
allowed
for
completing
various
activities
from
planning
to
startup
of
the
required
controls
was
not
sufficient.
Other
related
activities,
including
project
financing
and
obtaining
a
landfill
permit
for
the
scrubber
waste,
could
also
require
more
time
than
what
the
rule
allowed.
In
addition,
the
short
implementation
period
would
require
simultaneous
outages
of
too
many
units
to
tie
the
new
equipment
into
the
existing
systems,
which
would
affect
the
reliability
of
the
electrical
grid.

(
II)
Implementation
of
controls
to
the
required
large
number
of
units
would
cause
shortages
in
the
supply
of
critical
industrial
resources,
especially
boilermakers.
An
analysis
performed
by
a
commenter
showed
a
shortfall
in
the
supply
of
boilermaker
labor
during
the
construction
period
relevant
to
CAIR
retrofits.
This
commenter
anticipated
that
certain
key
variables
would
be
greater
in
value
than
those
used
by
EPA
and
based
their
analysis
on
higher
SCR
prices,
EIA­
projected
higher
natural
gas
prices
and
electricity
demand
factors,

and
more
stringent
boilermaker
duty
rates
(
boilermaker­
year/
MW)
and
availability
factors.

ii.
Commenters
who
favored
more
stringent
compliance
deadlines
argued
that
the
required
controls
could
be
282
installed
in
less
time
and
more
controls
could
be
built
in
early
years.
These
commenters
raised
the
following
specific
points
in
support
of
their
concerns:

(
I)
The
compliance
deadlines
for
the
two
phases
did
not
support
the
ozone
and
fine
particulate
(
PM2.5)
attainment
dates
mandated
by
the
CAA.
The
Phase
I
deadline
should
be
accelerated
to
meet
these
attainment
dates.
Sufficient
industrial
resources,
including
boilermakers,
would
be
available
to
support
such
an
acceleration.
While
some
commenters
supported
an
earlier
Phase
I
deadline
of
January
1,
2008,
the
others
supported
a
deadline
of
January
1,
2009.

Some
of
these
commenters
also
suggested
that
the
Phase
I
deadline
be
accelerated
only
for
NOx.

(
II)
The
EPA's
estimates
for
the
boilermaker
availability
were
too
conservative.
A
boilermaker
labor
analysis
performed
by
one
commenter
showed
an
adequate
supply
of
this
resource
to
support
installation
of
all
Phase
I
and
II
controls
by
the
start
of
the
first
phase
(
by
2010),
thereby
eliminating
the
need
for
two
phases.

(
III)
The
time
allowed
for
installing
controls
for
Phase
II
was
excessive.
The
initiation
of
this
phase
could
be
moved
forward.

iii.
Several
commenters
supported
EPA's
assumptions
used
in
support
of
the
adequacy
of
the
implementation
period
and
283
resources
to
build
the
required
CAIR
controls.
These
assumptions
included
the
overall
construction
schedule
durations
for
SCR
and
FGD
systems
and
boilermaker
unit
rates.

c.
Responses
The
EPA
reviewed
the
above
comments
and
performed
additional
research
and
analyses,
including
new
IPM
runs
that
incorporated
higher
SCR
and
natural
gas
costs
and
greater
electric
demand.
We
also
found
that
more
units
had
installed
SCR
under
the
NOx
SIP
Call
and
other
regulatory
actions
than
what
our
records
previously
showed.
This
increase
in
the
number
of
existing
SCR
installations
was
also
incorporated
into
these
IPM
runs.
In
addition,
the
number
of
existing
FGD
installations
was
also
revised
slightly
downward,
for
the
same
reason.

The
revised
IPM
analyses
for
today's
final
action
show
that
the
amounts
of
controls
that
need
to
be
put
on
for
Phase
I
are
39.6
GW
of
FGD
and
23.9
GW
of
SCR.
These
amounts
represent
a
reduction
from
the
estimates
for
the
NPR.
For
Phase
II,
the
amount
of
the
required
controls
are
32.4
GW
of
FGD
and
26.6
GW
of
SCR.
These
amounts
represent
an
increase
from
the
estimates
for
the
NPR.
The
amounts
shown
for
both
phases
reflect
all
retrofits
required
for
the
CAIR
and
Base
Case
(
non­
CAIR)
policies.
The
retrofit
284
projections
for
the
Base
Case
policies
are
included,
since
some
of
the
available
boilermaker
labor
would
be
consumed
in
building
these
retrofits
during
the
CAIR
time­
frame.

The
EPA
also
contacted
the
International
Brotherhood
of
Boilermakers
(
IBB),
U.
S.
Bureau
of
Labor
Statistics
(
BLS),

and
National
Association
of
Construction
Boilermaker
Employers
(
NACBE)
to
verify
its
assumptions
on
boilermakers
population,
percentage
of
boilermakers
available
to
work
on
the
control
retrofit
projects,
and
average
annual
hours
of
boilermaker
employment.
Except
for
the
boilermaker
population,
the
information
received
as
a
result
of
these
investigations
validated
EPA's
assumptions.
IBB
also
confirmed
that
the
boilermaker
population
would
at
least
be
maintained
at
the
current
level
of
26,000
members,
during
the
period
relevant
to
construction
of
CAIR
retrofits.
It
did
not
want
to
forecast
growth
and
historically
has
not
done
so.
Therefore,
instead
of
the
28,000
boilermaker
forecasted
population
used
in
the
NPR,
we
have
conservatively
used
a
boilermaker
population
of
26,000
for
the
final
CAIR.
A
detailed
discussion
on
these
assumptions
and
the
information
received
from
these
sources
is
available
in
the
docket
to
this
rulemaking
as
a
technical
support
document
(
TSD),
entitled
"
Boilermaker
Labor
and
Installation
Timing
Analysis."
285
The
responses
to
the
most
significant
comments
on
these
issues
are
summarized
in
the
following
sections.

i.
Issues
Related
to
Compliance
Deadline
Extension
(
I)
Adequacy
of
Phase
I
Implementation
Period
Today's
action
initiates
State
activities
in
conjunction
with
EPA
to
set
up
the
administrative
details
of
CAIR.
With
the
first
phase
compliance
deadline
of
January
1,
2009,
for
NOx
and
January
1,
2010,
for
SO2,
the
affected
sources
would
have
approximately
3­
3/
4
and
4­
3/
4
years
for
the
implementation
of
the
overall
requirements
for
this
phase,
respectively.
The
final
SIPs
would
be
submitted
at
the
end
of
the
first
18
months
of
these
implementation
periods.
The
remaining
2­
1/
4
and
3­
1/
4
years
would
be
available
for
the
sources
to
complete
activities
required
for
the
procurement
and
installation
of
NOx
and
SO2
controls,

respectively.
For
the
reasons
outlined
below,
EPA
believes
that
these
deadlines
provide
enough
time
to
install
the
required
Phase
I
controls.

(
A)
Engineering/
Construction
Schedule
Issues
The
EPA
notes
that,
for
CAIR,
the
States
would
finalize
the
SIPs
in
18
months
after
the
rule
is
signed,
and
that
until
then,
the
majority
of
sources
required
to
install
controls
may
not
initiate
activities
that
require
commitment
of
major
funds.
However,
some
activities,
such
as
planning,
286
preparation
of
conceptual
designs,
selection
of
technologies,
and
contacts
with
equipment
suppliers
can
be
started
or
completed
prior
to
the
finalization
of
SIPs,
at
least
for
major
sources
expected
to
require
longer
implementation
periods.
In
addition,
other
activities,
such
as
permitting
and
financing
can
be
started
after
the
rule
is
finalized.
This
is
based
on
the
NOx
SIP
Call
experience.

After
the
SIPs
are
finalized,
the
sources
would
have
approximately
2­
1/
4
and
3­
1/
4
years
in
which
to
complete
purchasing,
detailed
design,
fabrication,
construction,
and
startup
of
the
required
NOx
and
SO2
controls,
respectively.

This
assumes
that
activities,
such
as
planning
and
selection
of
technologies,
have
already
been
started
or
completed,

prior
to
the
start
of
these
2­
1/
4­
and
3­
1/
4­
year
periods.

As
discussed
in
the
NPR
proposal,
EPA
projects
an
average
single­
unit
installation
time
of
21
months
for
SCR
and
27
months
for
a
scrubber.
Our
revised
IPM
analysis
for
the
final
rule
shows
that
many
facilities
would
install
controls
on
multiple
units
(
a
maximum
of
six
for
SCR
and
five
for
FGD)
at
the
same
plant.
We
expect
these
facilities
to
stagger
these
installations
to
minimize
operational
disruptions.

The
EPA
also
projects
that
SCRs
and
scrubbers
could
be
installed
on
the
multiple
units
in
the
available
time
287
periods
of
2­
1/
4
and
3­
1/
4
years,
respectively.
The
issues
related
to
the
availability
of
boilermakers
and
the
ability
of
the
plants
requiring
multiple­
unit
controls
to
stagger
their
installations
during
these
periods
are
discussed
later
in
this
preamble.

As
compared
to
projections
in
the
NPR
proposal,
earlier
signing
of
the
final
rule
adds
approximately
three
additional
months
to
the
overall
implementation
periods
for
SO2
controls.
Furthermore,
EPA's
projections
for
the
final
rule
show
fewer
Phase
I
NOx
and
SO2
controls
being
added
than
the
projections
in
the
NPR
proposal.
Since
the
compliance
deadline
for
NOx
has
been
moved
up
a
year
from
the
proposal,

a
three­
month
earlier
rule
promulgation
provides
more
time
for
implementing
SO2
controls
only.
However,
since
it
does
allow
use
of
critical
resources,
such
as
boilermakers,
for
SO2
controls
to
be
spread
over
a
longer
period
of
time,
the
net
effect
would
be
to
make
more
of
these
resources
available
for
both
SO2
and
NOx
controls
(
as
compared
to
a
scenario
where
promulgation
was
not
three
months
earlier).

This
is
especially
true
since
the
implementation
periods
for
both
NOx
and
SO2
controls
would
start
at
the
same
time
and
the
plants
installing
these
controls
would
be
competing
for
the
same
resources
until
January
1,
2009,
the
compliance
deadline
for
NOx.
The
EPA,
therefore,
believes
that
2­
1/
4­
288
and
3­
1/
4­
year
time
periods
provide
reasonable
amounts
of
time
from
the
approval
of
State
programs
by
September
2006,

until
the
commencement
of
compliance
deadlines
for
meeting
the
NOx
and
SO2
emission
requirements.

Certain
commenters
have
provided
their
own
estimates
of
schedule
requirements
for
installing
the
required
controls.

In
some
cases,
these
estimates
are
longer
than
those
determined
by
EPA.
For
scrubbers,
including
spray
dryer
and
wet
limestone
or
lime
type
systems,
the
control
implementation
requirements
provided
by
the
commenters
range
from
30
to
54
months
for
the
overall
project
and
18
to
36
months
for
the
phase
following
equipment
awards.
In
this
case,
the
lowest
18­
month
schedule
requirement
cited
applies
to
spray
dryers,
whereas
the
shortest
schedule
cited
for
wet
scrubbers
for
the
activities
following
the
equipment
awards
is
24
months.
For
SCR,
the
control
implementation
requirements
cited
by
the
commenters
range
from
24
to
36
months
for
the
overall
project
and
17
to
25
months
for
the
phase
following
the
equipment
awards.

One
commenter
has
pointed
out
that
the
construction
schedule
requirements
for
the
FGD
and
SCR
retrofit
projects
have
shortened,
because
of
the
lessons
learned
from
a
significant
number
of
such
projects
completed
during
the
last
few
years.
The
EPA
notes
that
a
recent
announcement
289
22
Reference:
Announcement
by
Wheelabrator
Air
Pollution
Control
Inc.
for
award
of
a
wet
limestone
scrubber
system
for
K.
C.
Coleman
Generating
Station,
Western
Kentucky
Energy
Corp.,
August
2,
2004,
and
other
related
documents.
(
docket
no.
OAR­
2003­
0053­
1953)
for
a
new
485
MW
limestone
scrubber
facility
indicates
a
construction
schedule
duration
(
from
equipment
award
to
startup)
of
only
18
months.
72
This
is
well
below
the
schedule
requirement
cited
by
the
commenters
for
a
wet
limestone
scrubber.

The
EPA
also
notes
that
most
of
the
commenters'

schedule
estimates
are
consistent
with
the
time
periods
available
for
completing
the
CAIR­
related
NOx
and
SO2
projects.
Some
of
the
longer
schedules
submitted
by
commenters
would
exceed
the
CAIR
Phase
I
dates.
However,

EPA
considers
these
longer
schedules
to
be
speculative,
as
these
commenters
did
not
justify
them.
The
major
factors
that
influence
schedule
requirements
include
size
of
the
installation,
degree
of
retrofit
difficulty,
and
plant
location.
The
EPA
does
not
expect
these
factors
to
make
a
difference
of
more
than
a
few
months
between
the
schedule
requirements
of
various
installations.
The
commenters
who
have
cited
long
schedule
requirements
that
fall
at
the
higher
end
of
the
above
ranges
have
not
provided
any
data
to
support
the
wide
differences
between
their
schedules
and
those
proposed
by
others,
including
EPA.
It
should
also
be
290
23
Summary
of
telephone
calls
with
States
to
discuss
landfill
permit
timing
(
docket
no.
OAR­
2003­
0053­
1927)
noted
that
EPA's
schedules
are
based
on
information
from
several
actual
SCR
and
scrubber
installations.
Therefore,

EPA
cannot
accept
the
excessive
schedule
requirements
proposed
by
these
commenters.

(
B)
Landfill
Permit
Issue
The
EPA
contacted
several
key
States
requiring
FGD
retrofits,
to
investigate
the
amount
of
time
required
to
obtain
a
landfill
permit
for
scrubber
waste.
We
note
that
not
all
scrubber
installations
would
require
landfills,
as
some
scrubber
designs
produce
saleable
waste
products,
such
as
gypsum.

Specifically,
EPA
contacted
Georgia,
Ohio,
Indiana,

Alabama,
Pennsylvania,
West
Virginia,
Tennessee,
and
Kentucky.
73
Except
for
Kentucky,
all
States
indicated
that
their
permit
approval
periods
ranged
from
12
to
27
months.

Some
of
these
States
indicated
that
permit
approval
may
require
more
time
than
27
months,
but
only
for
the
cases
in
which
major
landfill
design
issues
persist
or
the
permit
applicant
has
not
provided
complete
and
proper
information
with
the
permit
application.

The
Kentucky
Department
of
Environmental
Protection
indicated
that,
based
on
their
historical
records,
the
291
average
permit
approval
period
was
3­
1/
2
years.
They
also
stated
that
the
State
was
sensitive
to
an
applicant's
time
restrictions
and
the
permit
approval
times
had
varied
depending
on
the
level
of
urgency
surrounding
a
permit
application.
They
further
confirmed
that
they
would
work
with
the
industry
to
meet
compliance
deadlines,
such
as
those
required
by
CAIR,
as
efficiently
as
possible.

Based
on
the
above
investigations,
EPA
notes
that
the
landfill
permitting
requirements
quoted
by
all
States
fall
well
within
the
4­
3/
4­
year
implementation
period
for
Phase
I.
Also,
landfill
permitting
activities
as
well
as
its
design
and
construction
can
be
accomplished,
independent
of
the
design
and
construction
of
the
FGD
system.
The
EPA,

therefore,
believes
that
landfill
permitting
is
not
a
constraint
for
compliance
with
the
rule.

(
C)
Project
Financing
Issue
Commenters
representing
small
units
or
units
owned
by
the
co­
operatives
raised
concerns
that
arrangement
of
financing
for
control
retrofits
could
take
long
periods
of
time.
However,
EPA's
projections
show
a
larger
portion
of
the
smaller
units
installing
controls
only
during
the
second
phase.
These
projections
also
show
that
only
a
few
co­
operative
units
would
require
installation
of
controls.

Therefore,
EPA
believes
that
the
Phase
I
implementation
292
periods
of
approximately
3­
3/
4
and
4­
3/
4
years
for
NOx
and
SO2
controls,
respectively,
provide
enough
time
for
completing
the
financing
activity
for
all
controls.
Of
course,
if
individual
sources
face
difficulties
in
meeting
deadlines
to
implement
controls,
they
may
use
the
allowance­
trading
provisions
of
CAIR
to
defer
implementation
of
controls.

(
D)
Electrical
Grid
Reliability
Issue
Based
on
available
data
for
the
NOx
SIP
Call,

approximately
68
GW
of
SCR
retrofits
were
started
up
during
the
years
from
2001
to
2003.
This
included
approximately
42
GW
of
SCRs
in
2003
alone,
which
exceeds
the
combined
capacity
of
SCR
and
FGD
retrofits
for
CAIR
that
we
expect
to
be
started
up
in
any
one
year.
The
EPA
projects
that
startup
of
the
23.9
GW
of
SCR
and
39.6
GW
of
FGD
capacity
required
for
Phase
I
would
be
spread
over
a
period
of
two
years
(
2008
and
2009).
The
total
capacity
of
units
starting
up
in
each
year
is
therefore
expected
to
be
approximately
32
GW
(
half
of
the
combined
SCR
and
FGD
capacity
of
63.5
GW).

The
NOx
SIP
Call
experience
shows
that
outages
required
to
complete
installation
of
the
large
SCR
capacity,

especially
during
2003,
did
not
have
an
adverse
impact
on
the
electrical
grid
reliability.
The
EPA
notes
that
the
outage
requirement
for
SCR
usually
exceeds
that
for
293
24
Reference:
"
NERC,
Generating
Availability
Data
System:
All
MW
Sizes
­
Coal­
Fired
Generation
Report,
http://
www.
nerc.
com/~
filez/
gar.
html,
October
17,
2003
scrubbers,
since
SCR
is
located
closer
to
the
boiler
and
it
may
be
more
intrusive
to
the
existing
equipment.
As
shown
above,
the
CAIR
retrofits
are
projected
to
include
more
scrubbers
than
SCRs
and
the
capacity
of
these
retrofits
starting
up
in
any
one
year
is
below
the
capacity
of
the
NOx
SIP
Call
units
that
started
up
in
2003.
Therefore,
the
overall
outage
requirement
for
CAIR
would
be
less
than
that
experienced
for
the
NOx
SIP
Call.

Based
on
published
industry
data,
the
planned
outage
times
for
coal­
fired
units
from
2001­
2002
(
SCR
buildup
years)
decreased
by
over
two
percent
compared
to
the
previous
two
years
from
1998­
1999.74
The
reduction
in
the
overall
outage
time
in
the
2001­
2002
period
also
shows
that
the
SCR
retrofits
did
not
adversely
affect
the
grid
reliability.
Therefore,
EPA
believes
that
the
concern
regarding
electrical
grid
reliability
is
unwarranted
for
CAIR
retrofits.

(
II)
Availability
of
Boilermaker
Labor
in
Phase
I
The
EPA
has
performed
several
analyses
to
verify
the
adequacy
of
the
available
boilermaker
labor
for
the
installation
of
CAIR's
Phase
I
controls.
These
analyses
were
not
just
based
on
using
EPA's
assumptions
for
the
key
294
factors
affecting
the
boilermaker
availability,
but
also
the
assumptions
suggested
by
commenters
for
these
factors
to
determine
how
sure
we
could
be
on
our
key
conclusions.
If
there
was
insufficient
labor
for
the
amount
of
air
pollution
controls
that
will
need
to
be
installed,
the
program
would
be
in
jeopardy.
For
instance,
shortages
in
manpower
could
lead
to
high
wage
rates
that
could
substantially
increase
construction
costs
for
pollution
controls
and
reduce
the
cost
effectiveness
of
this
program.
During
the
peak
of
the
NOx
SIP
Call
SCR
construction
period,
the
power
industry
did
experience
an
increase
in
the
SCR
construction
costs.
One
of
the
reasons
cited
for
these
higher
costs
was
an
increased
demand
for
boilermaker
labor.
The
EPA
strongly
wanted
to
avoid
this
possibility
for
CAIR.
The
EPA
also
wanted
to
be
very
sure
that
the
levels
of
controls
and
timing
of
the
program's
start
were
appropriate.
Therefore,
EPA
tended
to
make
conservative
assumptions
and
to
test
the
sensitivity
of
key
assumptions
that
were
uncertain.

Boilermakers
population,
percentage
of
boilermakers
available
to
work
on
the
control
retrofit
projects,
and
average
annual
hours
of
boilermaker
employment
are
some
of
the
key
factors
that
affect
boilermaker
availability.
As
discussed
previously,
EPA's
assumptions
on
these
factors
295
were
validated
or
revised
through
our
discussions
with
IBB,

BLS,
and
NACBE.

Two
other
key
factors
that
also
have
an
impact
on
boilermaker
availability
include
the
number
of
required
SCR
and
FGD
retrofits
and
boilermaker
duty
rates
(

boilermakeryear
MW,
i.
e.,
the
number
of
boilermaker
years
needed
to
install
SCR
or
FGD
on
one
MW
of
electric
generation
capacity).
The
EPA's
projections
for
the
required
SCR
and
FGD
retrofits
are
based
on
the
IPM
analyses
performed
for
the
final
rule.
The
basis
for
the
boilermaker
duty
rates
used
by
EPA
is
a
report
prepared
by
EPA
for
the
proposed
Clear
Skies
Act,
"
Engineering
and
Economic
Factors
Affecting
the
Installation
of
Control
Technologies
for
Multi­
Pollutant
Strategies."

Some
commenters
have
suggested
use
of
EIA's
projections
of
natural
gas
prices
and
electricity
demand
rates
that
are
higher
than
EPA's
projections
used
in
the
IPM
analyses.
Use
of
higher
values
for
these
parameters
would
increase
the
number
of
required
control
retrofits.
While
not
agreeing
with
these
commenters
that
EIA's
projections
should
replace
the
data
that
EPA
uses,
we
acknowledge
that
there
is
reasonable
uncertainty
concerning
these
assumptions
and
that
addressing
the
uncertainty
explicitly
by
considering
EIA's
alternative
assumptions
is
prudent,
given
the
importance
of
296
having
sufficient
labor
resources
to
meet
the
program's
requirements
in
2010.
Therefore,
EPA
has
performed
a
sensitivity
analysis
to
determine
the
required
control
retrofits
resulting
from
the
use
of
these
EIA
projections,

and
then
used
the
increased
amounts
of
the
required
control
retrofits
to
determine
their
impacts
on
the
boilermaker
availability.

The
EPA
also
received
comments
suggesting
that
the
SCR
costs
used
in
our
IPM
analyses
were
below
the
levels
experienced
in
recent
SCR
installations.
We
note
that
the
SCR
costs
were
revised
in
the
IPM
analyses
performed
for
the
final
rule,
to
reflect
recent
industry
experience.
One
commenter
reported
SCR
capital
costs
that
exceeded
our
revised
costs.
The
EPA
does
not
agree
with
these
reported
costs,
as
they
are
not
supported
by
the
overall
cost
data
submitted
by
the
commenter.
However,
to
address
the
concern
with
the
SCR
costs
in
general,
we
have
performed
a
sensitivity
analysis
to
determine
the
impact
of
increasing
the
SCR
capital
and
fixed
O&
M
costs
by
30
percent.

An
increase
in
the
SCR
costs
would
affect
the
amounts
of
the
required
control
retrofits.
Table
IV­
12
shows
the
projected
Phase
I
SCR
and
FGD
retrofits
for
the
above
two
alternate
cases,
based
on
using
EIA's
projections
for
297
natural
gas
prices
and
electricity
demand
rates
and
higher
SCR
costs.

Table
IV­
12.
IPM
Projections
for
Total
Capacities
of
FGD
and
SCR
Retrofit
Projects
for
Coal­
Fired
Electric
Generation
Units
for
CAIR
Phase
I
Using
EPA
and
Commenter
Assumptions
Retrofit
Type
EPA
Base
Case
Assumptions
EIA
Projections1
EIA
Projections
and
Higher
SCR
Costs2
CAIR
FGD,
GW
37
45.4
47.9
Non­
CAIR
FGD,
GW
2.6
3.7
Included
Above
CAIR
SCR,
GW
18.2
20.6
25.2
Non­
CAIR
SCR,
GW
5.7
4.6
Included
Above
1
The
required
control
retrofits
shown
are
based
on
using
EIA
projections
for
natural
gas
prices
and
electricity
demand
rates.
2
The
required
control
retrofits
shown
are
based
on
using
EIA
projections
for
natural
gas
prices
and
electricity
demand
rates
as
well
as
30
percent
higher
SCR
capital
and
fixed
O&
M
costs.

As
shown
in
Table
IV­
12
above,
the
alternate
case
using
just
the
EIA's
projections
for
natural
gas
prices
and
electricity
demand
rates
requires
the
largest
amounts
of
control
retrofits.
Therefore,
a
boilermaker
availability
analysis
was
performed
for
just
this
case.

One
commenter
has
suggested
use
of
higher
boilermaker
duty
rates
for
both
SCR
and
FGD
retrofits,
based
on
an
industry
survey
they
had
conducted.
Use
of
higher
duty
rates
would
result
in
more
boilermakers
being
needed
to
install
the
controls.
Table
IV­
13
shows
the
boilermaker
298
duty
rates
used
by
EPA
as
well
as
those
suggested
by
this
commenter.

Table
IV­
13.
Boilermaker
Duty
Rates
for
SCR
and
FGD
Systems
for
Coal­
Fired
Electric
Generation
Units
Source
FGD
SCR
EPA's
estimate,
boilermaker­
year/
MW
0.152
0.175
Commenter­
suggested,
boilermaker­
year/
MW1
0.269
0.343
1The
duty
rate
values
shown
are
average
values
calculated
by
using
the
FGD
and
SCR
correlations
provided
by
the
commenter
along
with
the
MW
size
of
individual
units
projected
by
the
IPM
to
require
FGD
or
SCR
controls
for
Phase
I
of
CAIR.

Our
review
of
the
limited
supporting
information
submitted
by
the
commenter
about
their
survey
for
these
duty
rates
shows
that
they
are
based
on
data
from
a
small
number
of
installations
and
represent
scope
of
work
at
each
power
plant
that
is
well
above
the
average
installation
conditions
used
in
determining
the
duty
rates
used
by
EPA.
Therefore,

EPA
considers
these
commenter­
suggested
duty
rates
to
represent
the
upper
end
of
the
range
of
values
that
would
be
expected
for
the
SCR
and
FGD
controls
under
consideration.

This
is
also
supported
by
the
average
duty
rate
(
0.199)

submitted
by
one
other
commenter
for
installing
FGDs,
which
is
well
below
the
average
duty
rate
(
0.269)
suggested
by
the
first
commenter.
However,
EPA
also
notes
that
the
duty
rate
suggested
by
the
second
commenter
is
higher
than
that
(
0.152)
used
by
EPA.
299
The
EPA
conducted
the
boilermaker
analysis
for
the
final
rule
using
alternative
assumptions
for
boilermaker
duty
rates.
These
alternative
assumptions
yield
a
range
of
estimates
of
the
amount
of
control
that
could
feasibly
be
installed.
In
keeping
with
EPA's
desire
to
be
very
sure
that
there
is
sufficient
boilermaker
labor
available
during
the
CAIR's
Phase
I
construction
period,
the
Agency
has
considered
the
most
stringent
duty
rates
suggested
by
the
first
commenter,
as
well
as
other
duty
rates
(
see
Table
IV­

13),
in
analyzing
the
impact
on
the
boilermaker
availability.
The
EPA
considers
this
to
be
a
bounding
analysis
in
which
the
estimates
based
on
the
most
stringent
duty
rates
reflect
conditions
with
the
highest
retrofit
difficulty
level
that
EPA
could
realistically
expect
to
occur.
We
expect
that
the
average
boilermaker
duty
rates
applicable
to
the
overall
boiler
population
required
to
retrofit
controls
under
this
rule
would
not
fall
outside
of
the
values
used
by
EPA
and
those
suggested
by
the
first
commenter.

In
the
NPR,
only
the
union
boilermakers
belonging
to
the
IBB
were
considered
in
the
EPA's
availability
analysis.

Some
commenters
have
pointed
out
that
additional
sources
of
boilermakers
will
be
available
for
CAIR.
Two
such
sources
include
non­
union
and
Canadian
boilermakers.
IBB
has
300
25
Reference:
"
Email
from
Institute
of
Clean
Air
Companies,"
September
15,
2004
(
See
Appendix
B,
Boilermaker
Labor
Analysis
and
Installation
Timing)
confirmed
that
1,325
Canadian
boilermakers
were
brought
in
to
support
the
NOx
SIP
Call
SCR
work
in
2003.
The
EPA
also
projects
that
approximately
15
percent
of
FGDs
and
43
percent
of
SCRs
will
be
installed
for
Phase
I
in
the
traditionally
non­
union
States
and
believes
there
will
be
nonunion
labor
available
in
these
States.
One
source
has
confirmed
that
substantial
amount
of
SCR
retrofit
work
during
the
2000­
2002
period
was
executed
by
non­
union
labor.
75
Based
on
these
data,
we
have
conservatively
assumed
that
1,000
boilermakers
from
Canada
will
be
available
and
10
percent
of
the
retrofits
would
be
installed
by
non­
union
boilermakers
for
Phase
I.

Based
on
EPA
data,
an
average
32
GW
of
new
gas­
fired,

combined
cycle
generating
capacity
was
being
added
annually,

during
the
NOx
SIP
Call
SCR
construction
years
of
2002
and
2003.
A
substantial
number
of
boilermakers
were
involved
in
the
construction
of
these
gas­
fired
projects.
Since
projections
for
the
timeframe
relevant
to
CAIR
retrofits
show
only
a
small
amount
of
new
electric
generating
capacity
being
added,
the
number
of
boilermakers
involved
in
the
building
of
new
plants
would
be
smaller
and
more
of
the
boilermaker
population
would
be
available
to
work
on
the
301
26
Reference:
"
Annual
Energy
Outlook
2005
(
Early
Release),
Tables
A9
and
9,"
December
2004,
http://
www.
eia.
doe.
gov/
oiaf/
aeo/
index.
html.
Phase
I
retrofits.
As
pointed
out
by
one
commenter,
the
boilermakers
available
due
to
this
projected
drop
in
the
building
of
new
generation
capacity
represents
a
third
additional
source
of
boilermakers
for
CAIR.

The
EPA
projects
only
an
insignificant
amount
of
new
coal­
fired
generating
capacity
being
added
during
Phase
I.

The
most
recent
EIA's
projections
also
do
not
show
any
new
coal
fired
capacity
being
added
between
2007
and
2010,
the
timeframe
relevant
to
boilermaker­
related
construction
activities
for
CAIR.
76
However,
EPA's
projections
do
show
approximately
15
GW
of
new
or
repowered
gas­
fired
capacity
being
added,
during
2007­
2010.
The
EIA's
projections
for
new
gas­
fired
capacity
addition
during
Phase
I
are
well
below
those
of
EPA's.
We
used
the
more
conservative
EPA
projections
for
new
generating
capacity
additions
and
the
gas­
fired
capacity
additions
during
the
NOx
SIP
Call
period
to
estimate
the
additional
boilermaker
labor
that
would
become
available
for
the
Phase
I
retrofits.
This
estimate
shows
that
approximately
28
percent
more
boilermakers
would
302
27
TSD,
"
Boilermaker
Labor
and
Installation
Timing
Analysis,"
(
Docket
no.
OAR­
2003­
0053)
be
available
to
work
on
the
CAIR
retrofits,
because
of
a
slowdown
in
the
construction
of
new
power
plants.
77
In
the
boilermaker
availability
analyses
performed
by
EPA,
the
required
boilermaker­
years
were
determined
for
each
case,
based
on
the
amounts
of
SCR
and
FGD
retrofits
being
installed
and
the
pertinent
boilermaker
availability
factors
and
duty
rates.
The
required
boilermaker­
years
were
then
compared
to
the
available
boilermaker
years
to
verify
adequacy
of
the
boilermaker
labor.
All
sources
of
boilermakers
were
considered
in
these
analyses,
including
the
union
boilermakers
and
the
boilermakers
from
the
three
additional
sources
discussed
previously.

The
EPA's
boilermaker
availability
analyses
firmly
support
CAIR's
Phase
I
requirements.
Using
EPA's
projections
of
FGD
and
SCR
retrofits
installed
for
Phase
I
and
EPA's
assumptions
for
boilermaker
duty
rates,
there
are
ample
boilermakers
available
with
a
large
contingency
factor
to
support
the
predicted
levels
of
CAIR
retrofits.
For
the
most
conservative
analysis
using
the
boilermaker
duty
rates
suggested
by
one
commenter
and
the
EIA's
projections
for
natural
gas
prices
and
electricity
demand
rates,
there
are
sufficient
boilermakers
available
with
a
contingency
factor
of
approximately
14
percent.
303
In
the
NPR
proposal,
EPA
estimated
that
a
contingency
factor
of
15
percent
was
available
to
offset
any
increases
in
boilermaker
requirements
due
to
unforeseen
events,
such
as
sick
leave,
time
lost
due
to
inclement
weather,
time
lost
due
to
travel
between
job­
sites,
inefficiencies
created
due
to
project
scheduling
issues,
etc.
The
EPA
had
considered
this
15
percent
contingency
factor
to
be
adequate
for
these
unforeseen
events.
We
also
note
that
EPA
did
not
receive
any
comments
suggesting
a
need
for
a
higher
contingency
factor.

The
EPA
also
notes
that
the
above
boilermaker
labor
estimates
have
not
considered
the
benefits
of
the
experiences
gained
by
the
U.
S.
construction
industry
from
the
recent
buildup
of
large
amounts
of
air
pollution
controls,
including
the
NOx
SIP
Call
SCRs.
As
pointed
out
by
one
commenter,
such
experiences
include
use
of
modular
construction,
which
can
result
in
a
significant
reduction
in
the
required
boilermaker
labor
for
CAIR
retrofits.
Also,
as
a
result
of
this
controls
buildup,
an
increased
number
of
experienced
designers
and
construction
personnel
have
become
available
to
the
industry.
Some
of
these
benefits
may
be
offset
by
factors,
such
as
the
increased
level
of
retrofit
difficulty
expected
for
the
CAIR
retrofits,
especially
for
the
small
size
units.
However,
we
believe
that
the
net
304
effect
of
this
experience
is
a
more
efficient
use
of
the
boilermaker
labor
in
the
construction
of
the
air
pollution
control
retrofits
projects.
Unfortunately,
EPA
cannot
quantify
the
value
of
this
experience
in
determining
its
overall
impact
on
boilermaker
requirements.

Therefore,
EPA
considers
the
14
percent
contingency
in
the
available
boilermaker­
years
for
the
above
bounding
analysis
using
commenter­
suggested
assumptions
to
be
adequate.

ii.
Issues
Related
to
Compliance
Deadline
Acceleration
(
I)
Acceleration
of
Phase
I
Compliance
Deadline
As
a
result
of
EPA's
review
of
the
comments
received
and
further
investigations
conducted
by
the
Agency
for
the
final
rule,
the
compliance
deadline
for
implementing
Phase
I
NOx
controls
has
been
moved
up
by
one
year.
We
believe
that
the
affected
plants
would
have
sufficient
time
with
this
change
to
meet
the
CAIR
requirements
associated
with
NOx
emissions,
as
long
as
the
compliance
deadline
for
implementing
SO2
controls
is
not
changed.
The
EPA
does
not
agree
that
accelerating
the
originally
proposed
Phase
I
compliance
deadline
of
January
1,
2010,
for
implementing
both
NOx
and
SO2
controls
is
possible.
These
issues
are
discussed
below::

(
A)
Two­
Year
Phase
I
Acceleration
for
NOx
and
SO2
Controls
305
With
today's
final
action
and
allowing
18
months
for
the
SIPs,
sources
installing
controls
would
have
approximately
3­
1/
4
years
for
implementing
the
rule's
requirements.
Some
commenters
suggested
moving
Phase
I
forward
by
two
years,
with
a
new
compliance
deadline
of
January
1,
2008,
which
would
reduce
the
implementation
period
to
1­
1/
4
years.
It
is
recognized
that
sources
generally
would
not
initiate
any
implementation
activities
that
require
major
funding,
before
the
final
SIPs
are
available.

The
EPA's
projections
show
that,
for
SCR
installation
on
one
unit,
an
average
21­
month
schedule
is
required
to
complete
purchasing,
construction,
and
startup
activities.

For
the
same
activities
for
FGD,
an
average
27­
month
schedule
is
required.
As
can
be
seen,
the
total
time
required
for
just
one
SCR
or
FGD
installation
exceeds
the
1­
1/
4­
year
implementation
period
available
for
Phase
I,
if
the
compliance
deadline
is
moved
to
January
1,
2008.

(
B)
One­
Year
Phase
I
Acceleration
for
NOx
and
SO2
Controls
If
the
Phase
I
compliance
deadline
for
both
NOx
and
SO2
controls
is
moved
up
by
one
year,
the
affected
facilities
would
have
2­
1/
4
years
or
27
months
to
complete
installation
of
these
controls.
As
discussed
in
the
preceding
section,

FGD
installation
on
one
unit
requires
an
average
27­
month
306
schedule
to
complete
purchasing,
construction,
and
startup
activities.

The
sources
installing
controls
on
more
than
one
unit
at
the
same
facility
would
likely
stagger
the
outage­
related
activities,
such
as
final
hookup
of
the
new
equipment
into
the
existing
plant
settings
and
startup,
to
minimize
operational
disruptions
and
avoid
losing
too
much
generating
capacity
at
one
time.
The
EPA
projects
that
an
average
2­
month
period
is
required
to
complete
the
outage
construction
activities
and
a
one­
month
period
to
complete
the
startup
activities
for
FGD.
Therefore,
if
back­
to­
back
outages
are
assumed
for
a
plant
installing
FGD
on
just
two
units,
the
27
months
needed
to
install
FGD
on
the
first
unit
and
an
additional
three
months
needed
for
outage
activities
on
the
second
unit
would
result
in
an
overall
schedule
requirement
of
30
months.
This
30­
month
schedule
exceeds
the
available
27­
month
implementation
period,
if
the
compliance
deadline
is
moved
up
by
one
year.
For
plants
installing
FGD
controls
on
more
than
two
units
and
performing
hookup
construction
and
startup
activities
in
back­
to­
back
outages,
an
additional
three
months
would
be
added
to
the
30­
month
schedule
requirement
for
each
additional
unit.
307
The
EPA
notes
that
certain
plants
installing
multipleunit
controls
may
be
able
to
meet
the
compliance
deadline
requirement
by
using
alternative
approaches,
such
as
simultaneous
unit
outages
and
purchase
of
allowances
to
defer
installation
of
controls
on
some
units.
However,
our
projections
for
the
final
rule
show
that
some
facilities
would
be
installing
FGD
controls
on
five
multiple
units
at
a
single
site.
Moreover,
these
projections
show
26
plants
requiring
FGD
retrofit
on
more
than
one
unit,
which
represents
a
major
portion
of
the
total
number
of
plants
required
to
install
such
controls
under
CAIR.
We
believe
it
would
not
be
appropriate
to
expect
this
number
of
plants
to
resort
to
alternative
means
to
accommodate
such
installations,
such
as
simultaneous
unit
outages
or
purchasing
of
allowances.

For
FGD
retrofits,
some
plants
would
be
required
to
obtain
solid
waste
landfill
permits.
As
discussed
previously,
the
time
required
to
obtain
these
permits
could
range
from
one
to
3­
1/
2
years.
With
the
compliance
deadline
moved
up
by
one
year,
the
overall
implementation
period
would
be
reduced
from
4­
3/
4
to
3­
3/
4
years.
For
those
plants
subjected
to
a
3­
1/
2­
year
permit
approval
period,

only
three
months
would
be
available
to
prepare
the
permit
applications
at
the
beginning
of
the
compliance
period
and
308
to
prepare
the
landfill
area
for
accepting
the
waste
after
permit
approval.
The
EPA
does
not
believe
that
three
months
is
adequate
for
such
activities.
These
plants
would,

therefore,
need
the
4­
3/
4­
year
implementation
period
to
complete
activities
related
to
landfills
associated
with
the
FGD
systems.

The
EPA
also
performed
an
analysis
to
verify
if
the
available
boilermaker
labor
is
adequate
to
support
the
January
1,
2009,
compliance
deadline
for
both
NOx
and
SO2.

This
analysis
was
performed,
using
commenter­
suggested
boilermaker
duty
rates
and
EIA's
assumptions
for
the
natural
gas
prices
and
electricity
demand
rates.
The
results
show
that
given
these
assumptions
sufficient
number
of
boilermakers
will
not
be
available
and
that
there
will
be
a
shortfall
of
approximately
32
percent
in
the
boilermakers
available
to
support
Phase
I
activities
for
this
case.

Considering
the
constraints
identified
in
the
above
analyses
for
the
FGD
installation
schedule
requirements
and
boilermaker
labor
availability,
EPA
believes
that
it
is
not
reasonable
to
move
the
Phase
I
compliance
deadline
for
both
NOx
and
SO2
caps
to
January
1,
2009.

(
C)
One­
Year
Phase
I
Acceleration
for
NOx
Controls
Only
An
one
year
acceleration
would
result
in
a
compliance
deadline
of
January
1,
2009,
for
installing
Phase
I
NOx
309
controls.
With
this
change,
the
affected
sources
installing
these
controls
would
have
approximately
2­
1/
4
years
for
implementing
the
rule's
requirements,
following
the
approval
of
State
programs.
However
the
implementation
period
for
installing
FGD
controls
would
still
be
at
3­
1/
4
years.

As
shown
previously,
21
months
would
be
required
to
complete
purchasing,
construction,
and
startup
of
SCR
on
one
unit.
For
multiple­
unit
installations
with
back­
to­
back
unit
outages
for
the
tie­
in
construction
and
startup,
the
available
2­
1/
4­
year
implementation
period
would
permit
staggering
of
SCR
installations
on
a
maximum
of
three
units
(
see
the
above
referenced
TSD).
For
a
plant
requiring
SCR
retrofit
on
more
than
three
units,
simultaneous
outages
of
two
units
would
become
necessary.
However,
EPA
notes
that
there
are
only
six
plants
projected
to
require
SCR
installation
on
more
than
three
units
and,
therefore,
it
is
expected
that
simultaneous
outages
of
two
units
at
each
of
these
plants
would
not
have
an
adverse
impact
on
the
reliability
of
the
electrical
grid.

In
addition,
the
plants
installing
SCR
on
more
than
three
units
at
the
same
site
would
have
two
other
options
to
meet
the
rule's
requirements,
without
having
to
resort
to
simultaneous
two­
unit
outages.
First,
these
plants
would
be
able
to
defer
installation
of
SCRs
on
some
of
the
units
by
310
28
The
200,000­
ton
Compliance
Supplement
Pool
is
apportioned
to
each
of
the
23
States
and
the
District
of
Columbia
that
are
required
by
CAIR
to
make
annual
NOx
reductions,
as
well
as
the
2
States
(
Delaware
and
New
Jersey)
for
which
EPA
is
proposing
to
require
annual
NOx
reductions.
receiving
allocated
allowances
or
purchasing
allowances
from
the
200,000­
ton
Compliance
Supplement
Pool
being
made
available
as
part
of
CAIR.
78
Second,
the
outage
activities
for
some
of
the
units
at
these
plants
could
be
extended
into
the
first
quarter
of
2009,
which
is
beyond
the
compliance
deadline
of
January
1,
2009,
since
these
units
would
not
generate
NOx
emissions
during
an
outage
and
therefore
not
require
any
allowances
to
compensate
for
them.
The
EPA's
projections
show
that,
of
the
above
six
plants
installing
SCR
on
more
than
three
units,
four
of
them
require
SCR
retrofits
on
four
units
each.
If
it
is
assumed
that
these
four
plants
would
perform
outage
activities
on
the
fourth
unit
during
the
first
quarter
of
2009,
there
would
only
be
two
plants
left
that
would
be
required
to
either
purchase
allowances
or
perform
work
during
simultaneous
outages.

The
EPA
also
notes
that
the
total
schedule
requirements
for
multiple­
unit
plants
can
be
reduced
further
by
performing
some
of
the
activities,
especially
those
related
to
planning
and
engineering,
prior
to
the
2­
1/
4­
year
period.

Also,
with
the
total
installation
time
requirement
for
FGD
being
more
than
that
for
SCR,
EPA
expects
the
outages
311
associated
with
most
Phase
I
FGDs
to
take
place
after
January
1,
2009.
The
overall
impact
of
the
outages
taken
for
these
SCR
and
FGD
retrofits
would,
therefore,
be
minimized.

The
EPA
also
performed
an
analysis
to
determine
the
impact
of
an
one­
year
acceleration
in
the
NOx
compliance
deadline
on
Phase
I
boilermaker
labor
requirements.
Since
the
amounts
of
the
required
Phase
I
NOx
and
FGD
retrofits
are
not
affected
by
this
change,
the
overall
boilermaker
requirements
for
this
phase
will
remain
the
same
as
previously
reported
for
the
case
with
the
same
compliance
deadline
for
both
NOx
and
SO2.
However,
with
the
new
NOx
compliance
deadline,
installation
of
all
NOx
retrofits
would
have
to
be
completed
by
January
1,
2009,
and
some
of
the
FGD
construction
work
requiring
boilermakers
would
also
be
done
during
this
period.
The
EPA
assumed
that,
along
with
completing
installation
of
all
SCRs,
35
percent
of
the
boilermaker
labor
required
to
install
all
FGDs
would
be
used
in
the
period
prior
to
January
1,
2009.
This
is
a
conservative
assumption,
since
the
amount
of
boilermaker
labor
used
for
this
period
would
be
greater
than
50
percent
of
the
total
Phase
I
boilermaker
labor
requirement.
The
analysis
performed
by
EPA
shows
that
sufficient
boilermakers
would
be
available
with
a
contingency
factor
of
312
approximately
14
percent
to
install
all
SCR
controls
and
35
percent
of
the
FGD
retrofit
work
by
January
1,
2009.
This
analysis
is
based
on
the
most
conservative
assumptions,

using
the
boilermaker
duty
rates
suggested
by
one
commenter
and
the
EIA's
projections
for
natural
gas
prices
and
electricity
demand
rates.
Based
on
the
above
analyses,

EPA
believes
that
moving
the
compliance
deadline
for
Phase
I
for
both
NOx
and
SO2
is
not
practical.
However,
a
one
year
acceleration
in
the
compliance
deadline
for
NOx
only
is
feasible.
Since
EPA
is
obligated
under
the
CAA
to
require
emission
reductions
for
obtaining
NAAQS
to
be
achieved
as
soon
as
practicable,
we
have
based
the
final
rule
on
two
separate
Phase
I
compliance
deadlines
of
January
1,
2009,

and
January
1,
2010,
for
NOx
and
SO2,
respectively.

(
II)
Implementing
All
Controls
in
Phase
I
The
EPA
proposed
a
phased
program
with
the
consideration
that
for
engineering
and
financial
reasons,
it
would
take
a
substantial
amount
of
time
to
install
the
projected
controls.
This
program
would
require
one
of
the
most
extensive
capital
investment
and
engineering
retrofit
programs
ever
undertaken
in
the
U.
S.
for
pollution
control.

The
capital
investment
for
pollution
control
for
CAIR
that
would
be
installed
by
2015
is
estimated
to
be
approximately
15
billion
dollars.
By
2015,
close
to
340
control
unit
313
retrofits
will
occur.
This
is
occurring
at
a
time
when
the
industry
also
faces
another
major
infrastructure
challenge
 
upgrading
transmission
capacity
to
make
the
grid
more
reliable
and
economic
to
operate.
This
also
will
cost
tens
of
billions
of
dollars.

The
proposed
program's
objective
was
to
eliminate
upwind
states'
significant
contribution
to
downwind
nonattainment,
providing
air
quality
benefits
as
soon
as
practicable.
A
phased
approach
was
also
considered
necessary
because
more
of
the
difficult­
to­
retrofit
and
finance,
smaller
size
units
would
be
included
in
the
second
phase,
which
would
allow
them
to
complete
activities
necessary
for
implementing
the
required
controls
as
well
as
provide
them
an
opportunity
to
benefit
from
the
lessons
learned
during
the
first
phase.

In
general,
environmental
controls
resulting
from
legislative
or
regulatory
actions
are
applied
to
those
units
first
that
offer
superior
choices
from
constructability
and
cost­
effectiveness
standpoints.
Experience
gained
by
the
industry
from
these
installations
can
then
be
used
to
develop
innovative
solutions
for
any
constructability
issues
and
to
improve
cost
effectiveness,
as
these
technologies
are
applied
to
harder­
to­
control
units.
The
EPA
believes
that
314
this
phenomenon
applies
to
the
application
of
the
SCR
and
FGD
technologies
at
coal­
fired
power
plants.

In
the
last
few
years,
SCR
and
FGD
systems
have
been
added
to
several
existing
coal­
fired
units,
under
the
NOx
SIP
Call
and
Acid
Rain
Program.
These
were
mainly
large
units
that
had
features,
such
as
spacious
layouts,
amenable
to
the
retrofit
of
the
new
air
pollution
control
equipment.

The
units
installing
controls
during
Phase
I
of
CAIR
would,

in
general,
be
smaller
in
size
and
would
offer
relatively
more
difficult
settings
to
accommodate
the
new
equipment.

These
units
would
certainly
benefit
from
the
experience
the
industry
has
gained
from
the
installations
completed
in
recent
years.

A
large
portion
of
the
units
(
47
percent)
projected
to
implement
controls
during
the
second
phase
consists
of
even
smaller
units,
less
than
200
MW
in
size.
Compared
to
larger
units,
the
retrofits
for
these
smaller
units
would
be
more
difficult
to
plan,
design,
and
build.
Historically,
smaller
units
have
been
built
with
less
equipment
redundancy,

smaller
capacity
margins,
and
more
congested
layouts.
It
is
likely,
therefore,
to
be
more
difficult
and
require
additional
design
efforts
to
accommodate
the
new
equipment
into
the
existing
settings
for
the
smaller
units.
Use
of
lessons
learned
by
firms
constructing
these
units
from
the
315
previous
installations,
including
those
to
be
built
during
the
first
phase,
would
help
streamline
this
process
and
maintain
the
cost
effectiveness
of
these
installations.

Moving
a
large
portion
of
the
retrofits
required
for
these
smaller
units
to
the
second
phase
also
provides
more
time
to
complete
the
required
retrofit
activities.

Because
EPA's
projections
for
the
second
phase
include
a
large
proportion
of
smaller
units,
the
total
number
of
units
requiring
NOx
and
SO2
controls
exceeds
that
in
the
first
phase
(
186
vs.
153).
Requiring
an
acceleration
of
the
second
phase
controls
to
be
completed
in
the
first
phase
would,
therefore,
more
than
double
the
number
of
retrofits
required
for
the
first
phase
from
153
to
339.
Based
on
data
available
from
EPA
and
other
sources,
the
industry
completed
95
SCR
installations
for
the
NOx
SIP
Call
in
2002
and
2003.

If
the
2004
projections
for
the
NOx
SIP
Call
are
added
to
this
number,
the
total
number
of
SCR
retrofits
over
the
2002­
2004
period
would
be
140.
This
is
less
than
half
the
number
that
would
be
required
for
CAIR
during
a
similar
period,
if
the
Phase
II
requirements
are
implemented
along
with
the
Phase
I
requirements.
Also,
the
combined
capacity
for
FGD
and
SCR
retrofits
required
for
Phase
I
would
be
122.5
GW,
which
is
approximately
57
percent
greater
than
the
installed
SIP­
Call
SCR
capacity
for
the
2002­
2004
period.
316
Such
a
change
in
the
rule
would
therefore
amount
to
imposing
a
requirement
over
the
power
industry
that
is
significantly
more
demanding
and
burdensome
than
what
the
industry
was
required
to
do
under
the
NOx
SIP
Call
rule.

The
EPA
notes
that
critical
resources
other
than
the
boilermakers
are
needed
for
the
installation
of
SCR
and
FGD
controls,
such
as
construction
equipment,
engineering
and
construction
staffs
belonging
to
different
trades,

construction
materials,
and
equipment
manufacturers.
Some
commenters,
based
on
their
experience
with
NOx
SIP
Call,

also
pointed
out
that
the
requirement
for
some
of
these
resources,
especially
construction
equipment
(
e.
g.,
large
cranes
used
to
mount
SCR
and
scrubber
vessels
above
ground),

construction
materials,
equipment
manufacturing
shop
capacities,
and
engineering
and
construction
management
teams
overseeing
these
projects,
is
affected
directly
by
the
number
of
installations.
The
greater
the
requirement
is
to
install
a
large
number
of
retrofits
by
2010,
the
greater
would
be
the
need
for
all
these
resources,
which
would
be
limited
in
the
short
term,
as
demands
from
equipment
vendors,
project
teams,
and
material
suppliers
ramp
up.
In
the
NOx
SIP
Call,
this
led
to
shortages
and
bottlenecks
in
projects
in
certain
areas,
causing
increased
project
times
317
and
costs.
The
EPA
wants
to
avoid
creating
a
similar
situation
by
requiring
too
much
at
once.

The
EPA
has
also
acknowledged
the
increase
in
SCR
costs
during
the
NOx
SIP
Call
implementation
period,
most
likely
due
to
an
increase
in
construction
costs
(
resulting
from
increased
demand
for
boilermaker
labor)
and
steel
prices.

The
EPA
has
revised
its
estimates
of
SCR
capital
costs
in
the
IPM
runs
for
the
final
rule
and
believes
the
conservatism
in
its
FGD
capital
costs
also
accounts
for
this
factor.

The
EPA
believes
that
moving
the
Phase
II
requirements
to
the
Phase
I
period
could
cause
near­
term
shortages
in
some
of
the
critical
resources.
This
would
further
increase
compliance
costs
and
could
remove
the
highly
cost­
effective
nature
of
these
controls
and
lead
to
a
greater
demand
for
natural
gas.

In
addition
to
the
above,
financing
a
large
amount
of
controls
for
Phase
I
may
prove
challenging,
especially
for
the
coal
plants
owned
by
deregulated
generators.
As
discussed
later
in
this
section,
such
generators
are
continuing
to
face
serious
financial
challenges,
and
many
have
below
investment
grade
credit
ratings.
This
significantly
complicates
the
financing
of
costly
retrofit
controls.
Such
plants
would
also
not
have
the
certainty
of
318
regulatory
recovery
of
investments
in
pollution
control,
and
would
have
to
rely
on
the
market
to
recover
their
costs.

Having
a
second
phase
cap
would
allow
these
companies
additional
time
to
strengthen
their
finances
and
improve
their
cash
flow.

In
the
interest
of
being
prudent
in
evaluating
the
need
to
phase
in
the
program,
EPA
also
performed
an
analysis
to
determine
if
the
available
boilermaker
labor
would
be
adequate
to
support
installation
of
all
Phase
I
and
II
controls
in
2010.
This
analysis
was
conservatively
based
on
using
commenter­
suggested
boilermaker
duty
rates
and
EIA's
projections
for
gas
prices
and
electricity
demand
rates.

The
results
show
that
a
sufficient
number
of
boilermakers
will
not
be
available
and
that
there
will
be
a
shortfall
of
approximately
25
percent
in
the
boilermakers
available
to
support
Phase
I
activities
for
this
case.

Based
on
the
above
analyses,
EPA
believes
that
implementation
of
controls
for
both
phases
in
Phase
I
is
impractical.
We
also
believe
that
it
is
prudent
and
reasonable
in
requiring
the
industry
to
undertake
this
massive
retrofit
program
on
a
two­
phase
schedule,
to
be
largely
completed
in
less
than
a
decade.

(
III)
Acceleration
of
Phase
II
Compliance
Deadline
319
The
EPA
does
not
believe
that
acceleration
of
the
compliance
deadline
for
the
second
phase
is
reasonable.
As
pointed
out
earlier,
a
large
portion
of
the
units
projected
to
install
controls
during
the
second
phase
consists
of
small
units,
less
than
200
MW
in
size.
Due
to
the
issues
related
to
financing
of
the
retrofit
projects
for
some
of
these
units
and
considering
that
planning
and
designing
of
controls
for
these
units
is
likely
to
take
longer,
EPA
does
not
consider
the
schedule
acceleration
to
be
appropriate.

EPA
notes
that
Phase
I
of
CAIR
is
the
initial
step
on
the
slope
of
emissions
reduction
(
the
glide­
path)
leading
to
the
final
control
levels.
Because
of
the
incentive
to
make
early
emission
reductions
that
the
cap­
and­
trade
program
provides,
reductions
will
begin
early
and
will
continue
to
increase
through
Phases
I
and
II.
The
EPA,
therefore,
does
not
believe
that
all
of
the
required
Phase
II
emission
reductions
would
take
place
on
January
1,
2015,
the
compliance
deadline.
These
reductions
are
expected
to
accrue
throughout
the
implementation
period,
as
the
sources
install
controls
and
start
to
test
and
operate
them.

The
EPA
also
notes
that
the
five­
year
implementation
period
for
Phase
II
is
consistent
with
other
regulations
and
statutory
requirements,
such
as
title
IV
for
SO2
and
NOx
controls.
In
addition,
some
commenters
have
cited
a
need
320
for
a
six­
year
period
for
obtaining
financing
for
plants
owned
by
the
co­
operatives.
These
facilities
are
likely
to
commit
funds
for
major
activities,
only
after
financing
has
been
obtained.
Therefore,
for
such
facilities,
a
period
of
approximately
four
years
would
be
available
for
procuring,

installing,
and
startup
activities,
assuming
that
the
financing
activities
were
started
right
after
the
rule
is
finalized.
Since
the
plants
owned
by
co­
operatives
are
usually
small
in
size,
they
are
likely
to
require
and
be
benefitted
by
the
extra
time
allowed
to
them
by
this
four­
year
implementation
period.

The
EPA
also
performed
an
analysis
to
verify
adequacy
of
the
available
boilermaker
labor
for
pollution
control
retrofits
the
power
industry
will
install
to
comply
with
the
Phase
II
CAIR
requirements.
A
36­
month
construction
period
requiring
boilermakers
was
conservatively
selected
for
this
analysis.
Based
on
the
IPM
analysis
for
the
final
rule,

conservatively,
the
power
industry
will
build
27.5
GW
of
FGD
and
26.6
GW
of
SCR
retrofits
for
compliance
with
lower
emission
caps
that
go
into
effect
for
NOx
and
SO2
in
2015.

The
analysis
was
based
on
using
EIA's
projections
for
the
natural
gas
prices
and
electricity
demand
rates
and
the
commenter­
suggested
boilermaker
duty
rates.
The
results
321
show
availability
of
ample
boilermakers
with
a
contingency
factor
of
46
percent
to
support
Phase
II
activities.

The
EPA
notes
that
the
retrofits
that
will
occur
in
Phase
II
will
be
smaller,
more
numerous,
and
more
challenging,
since
the
easiest
controls
will
likely
be
installed
in
Phase
I.
Therefore,
having
a
greater
contingency
factor
(
as
we
do)
is
warranted.
This
is
further
supported
when
the
uncertainty
in
predicting
the
construction
activities
in
the
areas
outside
of
air
pollution
controls
is
considered.
Notably
after
2010,
the
excess
generation
capacity
that
we
have
today
is
no
longer
expected
to
be
present
and
there
may
be
a
shift
towards
a
requirement
for
increasing
generation
capacity.
Increased
construction
of
new
power
plants
will
have
a
direct
impact
on
the
availability
of
boilermakers
for
the
Phase
II
controls.
The
EPA
believes
that
a
higher
contingency
factor
for
Phase
II
is
desirable
to
ensure
that
the
industry
will
succeed
in
getting
the
required
reductions
at
the
required
time.

Any
acceleration
of
the
Phase
II
compliance
deadline
will
also
cause
an
appreciable
reduction
in
the
above
estimated
contingency
factor
for
boilermaker
labor.
For
example,
based
on
EPA
analysis,
an
acceleration
of
one
year
is
projected
to
reduce
this
contingency
factor
to
only
about
322
one
percent.
Therefore,
EPA
believes
that
acceleration
of
the
Phase
II
compliance
deadline
cannot
be
justified.

3.
Assure
Financial
Stability
The
EPA
recognizes
that
the
power
sector
will
need
to
devote
large
amounts
of
capital
to
meet
the
control
requirements
of
the
first
phase.
Furthermore,
over
the
next
ten
years,
the
power
sector
is
facing
additional
financial
challenges
unrelated
to
environmental
issues,
including
economic
restructuring
impacts,
investments
related
to
domestic
security
and
investments
related
to
electrical
infrastructure.
Among
the
consideration
of
other
factors,

EPA
believes
it
is
important
to
take
into
account
the
ability
of
the
power
sector
to
finance
the
controls
required
under
CAIR.
A
detailed
assessment
of
the
status
of
the
financial
health
of
the
U.
S.
Utility
Industry,
particularly
of
the
unregulated
sector
is
offered
in
the
TSD,
"
U.
S.

Utility
Industry
Financial
Status
and
Potential
Recovery."

Commenters
have
noted
that
they
appreciate
EPA's
growing
realization
that
many
companies
may
have
difficulty
securing
financing,
and
the
agency's
establishment
of
a
two­
phase
reduction
program
on
both
technical
and
financial
grounds.

Utilities
and
non­
utility
generating
companies
have
felt
significant
financial
pressure
over
the
past
5
years.
323
The
years
2000
and
2001
saw
the
escalation
and
fallout
from
the
California
energy
crisis,
the
bankruptcy
of
Enron,
and
a
massive
building
program,
largely
on
the
side
of
the
merchant
generating
sector.
Subsequent
low
power
margins
and
large
debt
obligations
have
led
to
a
significant
number
of
credit
downgrades
of
utilities
and
power
generators
and
the
bankruptcy
of
coal­
generating
merchant
companies.

According
to
Standard
and
Poor's,
a
leading
provider
of
investment
ratings,
there
were
almost
ten
times
more
downgrades
of
utility
credit
in
2002
and
2003
than
there
were
upgrades.
While
more
recently
the
sector
has
stabilized,
a
significant
number
of
owners
of
coal­
fired
capacity
in
the
CAIR
region,
particularly
those
with
deregulated
capacity,
are
still
at
below
investment­
grade
credit
ratings.

In
general,
EPA
believes
that
regulated
plants,
given
appropriate
regulatory
requirements,
should
not
face
significant
financial
problems
meeting
their
obligations
under
CAIR.
While
EPA
recognizes
that
issues
such
as
the
expiration
of
rate
caps
and
the
time
lags
associated
with
regulatory
approval
and
recovery
may
provide
cash
flow
challenges,
regulated
electricity
rates
are
generally
seen
as
a
positive
factor
in
credit
ratings,
as
entities
are
allowed
a
recovery
on
prudent
investment
through
rate
cases
324
29
In
fact,
between
nine
and
eleven
(
depending
on
the
credit
agency)
of
the
twenty
largest
owners
of
deregulated
coal
capacity
in
the
U.
S.
currently
have
below­
investmentgrade
credit
ratings.
(
and,
in
some
jurisdictions,
the
recovery
of
allowance
expenditures
through
fuel
adjustment
clauses).

Deregulated
coal
capacity
(
operating
in
an
environment
of
market
prices
rather
than
electricity
rates
set
by
regulators)
has
no
such
guarantees,
and
would
need
to
recover
investments
in
pollution
control
from
market
prices
(
which
in
many
cases
are
not
set
by
coal
units).

Additionally,
deregulated
entities,
because
of
their
more
aggressive
building
and
borrowing
strategies
and
reliance
on
market
prices
(
which
now
reflect
the
current
capacity
overbuild),
have
faced
more
significant
financial
difficulties
(
including
a
number
of
bankruptcies)
and
are
currently
in
a
weaker
position
financially.
79
A
number
of
firms
that
have
avoided
financial
distress
in
the
near
term
have
done
so
by
renegotiating
their
pending
debt,
postponing
payment.
A
good
portion
of
this
debt
is
of
a
shorter­
term
nature,
and
will
be
coming
due
in
the
next
five
years.

Such
financial
difficulties
increase
the
cost
of
capital
necessary
for
capital
expenditures
and
affect
the
availability
of
such
capital,
making
required
controls
more
expensive.
Recent
financial
troubles
have
been
cited
as
the
reason
for
the
deferment
or
cancellation
of
pollution
325
control
expenditures.
Should
interest
rates
rise
in
the
future,
it
will
become
more
difficult
and
costly
for
utilities
seeking
financing.

These
problems
impact
a
significant
segment
of
coal
generators,
as
deregulated
coal
capacity
makes
up
about
a
third
of
all
U.
S.
coal
capacity
and
almost
90
percent
of
this
deregulated
capacity
would
be
affected
by
CAIR
requirements.

Given
the
lead
times
needed
to
plan
and
construct
such
equipment,
as
well
as
the
financial
uncertainty
many
of
the
plant
owners
are
confronting,
companies
may
find
it
difficult
to
install
controls
at
their
plants
too
quickly.

The
EPA
believes
that
the
choice
of
timing
of
the
emission
caps
in
CAIR
would
allow
firms
time
to
improve
their
current
and
near­
term
financial
difficulties
(
through
reorganization,
mergers,
sales,
etc.).
Phasing
in
the
more
stringent
emission
caps
by
2015
would
also
spread
investment
requirements
and
resulting
cash
flow
demands,
rather
than
forcing
firms
to
finance
a
large
spike
in
investments
in
a
very
short
time
period,
while
they
are
still
trying
to
recover
financially.

The
timing
of
controls
expected
to
be
installed
as
a
result
of
CAIR
are
similar
to
that
noted
in
EPA's
analysis
of
the
Clear
Skies
proposal.
The
EPA
looked
in
detail
at
the
potential
financial
impact
of
the
Clear
Skies
program
326
(
particularly
focusing
on
the
deregulated
coal
sector).
The
EPA
found
that
some
individual
deregulated
coal
plants
might
be
adversely
affected,
but
on
average
such
plants
would
actually
experience
a
small
financial
improvement
under
Clear
Skies.
Baseload
deregulated
coal
plants
would
benefit
from
even
slight
increases
in
the
price
of
natural
gas
(

units
burning
natural
gas
generally
set
the
wholesale
price
of
electricity
on
the
margin
in
the
regions
where
deregulated
coal
is
located).
These
units
would
also
be
recipients
of
allocated
allowances.
Overall,
the
phased
in
nature
of
CAIR,
the
fact
that
most
coal
plants
continue
to
be
regulated
and
the
fact
that
sources
would
also
receive
allowances,
would
all
mitigate
the
financial
impact
of
this
rule.

EPA
believes
that
the
timing
requirements
finalized
today
reflect
a
prudent
and
cautious
approach
designed
to
assure
that
the
industry
will
succeed
in
implementing
this
program.
The
EPA
believes
that
deferring
the
second
phase
to
2015
will
provide
enough
time
for
companies
to
raise
additional
capital
needed
to
install
controls.
Also,
we
believe
that
the
implementation
period
should
account
(
at
least
broadly)
for
the
possibility
that
electricity
demand
or
natural
gas
prices
may
increase
more
than
assumed,
and
therefore
that
additional
control
equipment
would
be
needed.

Allowing
until
2015
for
implementation
of
the
more
stringent
327
30
The
survey
results
are
in
"
A
Survey
of
State
Incentives
Encouraging
Improved
Environmental
Performance
of
Base­
Load
Electric
Generation
Facilities:
Policy
and
Regulatory
Initiatives,"
at
http://
www.
naruc.
org/
displayindustryarticle.
cfm?
articlenbr=
2
1826
control
levels
in
today's
rule
will
provide
more
flexibility
in
the
event
of
greater
electricity
demand
and
will
ensure
that
power
plants
in
the
CAIR
region
will
have
the
ability,

both
technical
and
financial,
to
make
the
pollution
control
retrofits
required.

EPA
is
currently
cooperating
with
the
National
Association
of
Regulatory
Utility
Commissioners
(
NARUC)
in
developing
a
menu
of
policy
options
and
financial
incentives
for
encouraging
improved
environmental
performance
for
generation.
A
survey
of
a
number
of
States
was
conducted
as
part
of
this
effort,
and
policies
such
as
pre­
approval
statutes
for
compliance
plans,
state
income
tax
credits,

accelerated
depreciation,
and
special
treatment
of
allowance
transactions
were
cited
as
examples
of
such
policies80.
Such
policies
will
ease
some
of
the
financial
pressures
of
CAIR
by
providing
greater
regulatory
certainty
and
lowering
the
effective
costs
of
controls.

D.
Control
Requirements
in
Today's
Final
Rule
1.
Criteria
Used
to
Determine
Final
Control
Requirements
The
EPA's
general
approach
to
developing
emission
reduction
requirements
 
basing
the
requirements
on
the
328
application
of
highly
cost­
effective
controls
 
was
adopted
in
the
NOx
SIP
Call
and
has
been
sustained
in
court.
In
the
NPR,
the
Agency
proposed
this
approach
for
developing
SO2
and
NOx
emission
reduction
requirements.
The
majority
of
commenters
accepted
this
basic
approach
for
determining
reduction
requirements.
Some
commenters
did
suggest
other
approaches,
however,
as
discussed
above.

Many
commenters
suggested
that
the
CAIR
regionwide
SO2
and
NOx
control
levels
should
be
more
or
less
stringent
than
the
levels
proposed
in
the
NPR.
The
EPA
has
determined
that
the
control
levels
that
we
are
finalizing
today
are
highly
cost­
effective
and
feasible,
and
constitute
substantial
reductions
that
address
interstate
transport,
at
the
outset
of
State
and
EPA
efforts
to
bring
about
attainment
of
the
PM2.5
NAAQS
(
the
EPA
believes
that
most
if
not
all
States
will
obtain
CAIR
reductions
by
capping
emissions
from
the
power
sector).
Today,
EPA
finalizes
the
use
of
both
average
and
marginal
cost
effectiveness
of
controls
as
the
basis
for
determining
the
highly
cost­
effective
amounts.

In
the
CAIR
NPR,
EPA
proposed
criteria
for
determining
the
appropriate
levels
of
SO2
and
NOx
emissions
reductions,

and
stated
that
EPA
considered
a
variety
of
factors
in
evaluating
the
source
categories
from
which
highly
costeffective
reductions
may
be
available
and
the
level
of
reduction
assumed
from
that
sector
(
69
FR
4611).
The
EPA
has
329
reviewed
comments
on
its
NPR,
SNPR
and
NODA
and
conducted
further
analyses
with
respect
to
the
proposed
criteria,
and
is
finalizing
its
control
requirements
in
today's
action.

Following
is
a
brief
summary
of
EPA's
conclusions
based
on
the
criteria.

The
availability
of
information,
and
the
identification
of
source
categories
emitting
relatively
large
amounts
of
the
relevant
emissions,
are
two
criteria
used
in
EPA's
evaluation
of
the
CAIR
program.
In
the
NPR,
EPA
stated
that
EGUs
are
the
most
significant
source
of
SO2
emissions
and
a
very
substantial
source
of
NOx
in
the
affected
region,
and
further
stated
that
highly
cost­
effective
control
technologies
are
available
for
achieving
significant
SO2
and
NOx
emissions
reductions
from
EGUs.
We
requested
comment
on
sources
of
information
for
emissions
and
costs
from
other
sectors
(
69
FR
4610).
A
detailed
discussion
regarding
non­

EGU
sources
is
provided
above.
The
EPA
has
not
received
additional
information
that
would
change
its
proposed
control
strategy.

Another
criterion
is
the
performance
and
applicability
of
control
measures.
The
NPR
included
a
detailed
discussion
of
the
performance
and
applicability
of
SO2
and
NOx
control
technologies
for
EGUs.
In
particular,
EPA
discussed
FGD
for
SO2
removal
and
SCR
for
NOx
removal,
both
of
which
are
fully
demonstrated
and
available
pollution
control
technologies
on
330
31
Detailed
documentation
of
EPA's
IPM
update,
including
updated
control
cost
assumptions,
is
in
the
docket.
The
SCR
control
cost
assumptions
were
presented
in
a
peer­
reviewed
paper
by
Sikander
Khan
and
Ravi
Srivastava,
"
Updating
Performance
and
Cost
of
NOx
Control
Technologies
in
the
Integrated
Planning
Model,"
at
the
Combined
Power
Plant
Air
Pollution
Control
Mega
Symposium,
August
30­
September
2,
2004,
Washington
D.
C.
coal­
fired
EGU
boilers
(
69
FR
4612).
None
of
the
commenters
provided
information
that
differed
from
EPA's
assessment
of
the
performance
of
these
control
measures.
In
addition,
the
commenters
generally
supported
EPA's
assumptions
on
the
applicability
of
these
controls.

The
cost
effectiveness
of
control
measures
is
another
criterion
used
in
EPA's
analysis.
As
discussed
in
detail
above,
EPA
determined
that
the
proposed
control
levels
are
highly
cost­
effective,
and
is
finalizing
the
levels
in
today's
action.
The
EPA
used
IPM
to
analyze
the
cost
effectiveness
of
the
proposed
and
final
CAIR
control
requirements.
IPM
incorporates
assumptions
about
the
capital
costs
and
fixed
and
variable
operations
and
maintenance
costs
of
control
measures
for
EGUs.
Several
commenters
suggested
that
the
SCR
control
cost
assumptions
that
we
used
in
IPM
analysis
for
the
NPR
were
too
low.

Consequently,
we
increased
the
SCR
control
cost
assumptions
in
IPM
and
conducted
cost
effectiveness
modeling
for
the
final
control
requirements
using
these
updated
costs.
81
Commenters
generally
supported
our
FGD
control
costs
331
assumptions,
which
are
largely
unchanged
from
the
NPR
modeling
to
the
modeling
for
today's
final
rule.

And
finally,
EPA
considered
engineering
and
financial
factors
that
affect
the
availability
of
control
measures.

The
EPA
conducted
a
detailed
analysis
of
engineering
factors
that
affect
timing
of
control
retrofits,
including
an
evaluation
of
the
comments
received.
EPA's
analysis
supports
its
proposed
compliance
schedule,
a
two­
phase
emissions
control
program
with
the
final
phase
commencing
in
2015,
and
with
a
first
phase
commencing
in
2010
for
SO2
reductions
and
in
2009
for
NOx
reductions.
Further,
EPA's
analysis
demonstrates
that
it
would
not
be
realistically
possible
to
start
the
program
sooner,
or
to
impose
more
stringent
emissions
caps
in
the
first
phase.

Based
on
EPA's
review
of
comments
and
analysis,
EPA
determined
that
the
proposed
control
requirements
are
reasonable
with
respect
to
engineering
factors.
As
discussed
above,
EPA
also
considered
how
to
avoid
creating
financial
instability
for
the
affected
sector,
and
how
to
ensure
the
capital
needed
for
the
required
controls
would
be
readily
available.
Assuming
States
choose
to
control
EGUs,

the
power
sector
will
need
to
devote
large
amounts
of
capital
to
meet
the
CAIR
control
requirements.
332
The
EPA
explained
that
implementing
CAIR
as
a
two­
phase
program,
with
the
more
stringent
control
levels
commencing
in
the
second
phase,
will
allow
time
for
the
power
sector
to
address
any
financial
challenges.
EPA's
evaluation
of
engineering
and
financial
factors
supports
the
decision
to
implement
CAIR
as
a
two­
phase
program,
with
the
final
(
second)
compliance
level
commencing
in
2015
and
a
first
phased­
in
level
starting
in
2010
for
SO2
reductions
and
in
2009
for
NOx
reductions.
A
description
of
the
final
CAIR
control
requirements
follows.

2.
Final
Control
Requirements
Today's
final
rule
implements
new
annual
SO2
and
NOx
emissions
control
requirements
to
reduce
emissions
that
significantly
contribute
to
PM2.5
nonattainment.
The
final
rule
also
requires
new
ozone
season
NOx
emissions
control
requirements
to
reduce
emissions
that
significantly
contribute
to
ozone
nonattainment.

The
final
rule
requires
annual
SO2
and
NOx
reductions
in
the
District
of
Columbia
and
the
following
23
States:

Alabama,
Florida,
Georgia,
Illinois,
Indiana,
Iowa,

Kentucky,
Louisiana,
Maryland,
Michigan,
Minnesota,

Mississippi,
Missouri,
New
York,
North
Carolina,
Ohio,

Pennsylvania,
South
Carolina,
Tennessee,
Texas,
Virginia,

West
Virginia,
and
Wisconsin.
(
In
the
"
Proposed
Rules"
333
section
of
today's
action,
EPA
is
publishing
a
proposal
to
include
Delaware
and
New
Jersey
in
the
CAIR
region
for
annual
SO2
and
NOx
reductions.)

In
addition,
the
final
rule
requires
ozone
season
NOx
reductions
in
the
District
of
Columbia
and
the
following
25
States:
Alabama,
Arkansas,
Connecticut,
Delaware,
Florida,

Illinois,
Indiana,
Iowa,
Kentucky,
Louisiana,
Maryland,

Massachusetts,
Michigan,
Mississippi,
Missouri,
New
Jersey,

New
York,
North
Carolina,
Ohio,
Pennsylvania,
South
Carolina,
Tennessee,
Virginia,
West
Virginia,
and
Wisconsin.

The
CAIR
requires
many
of
the
affected
States
to
reduce
annual
SO2
and
NOx
emissions
as
well
as
ozone
season
NOx
emissions.
However,
there
are
3
States
for
which
only
annual
emission
reductions
are
required
(
Georgia,
Minnesota
and
Texas).
Likewise,
there
are
5
States
for
which
only
ozone
season
reductions
are
required
(
Arkansas,
Connecticut,

Delaware,
Massachusetts,
and
New
Jersey).
The
following
20
States
and
the
District
of
Columbia
are
required
to
make
both
annual
and
ozone
season
reductions:
Alabama,
Florida,

Illinois,
Indiana,
Iowa,
Kentucky,
Louisiana,
Maryland,

Michigan,
Mississippi,
Missouri,
New
York,
North
Carolina,

Ohio,
Pennsylvania,
South
Carolina,
Tennessee,
Virginia,

West
Virginia
and
Wisconsin.

Table
IV­
14
shows
the
amounts
of
regionwide
annual
SO2
and
NOx
emissions
reductions
under
CAIR
that
EPA
projects,
334
32
For
a
discussion
of
the
emission
reduction
requirements
if
States
choose
to
control
sources
other
than
EGUs,
see
section
VII
of
this
preamble.
if
States
choose
to
meet
their
CAIR
obligations
by
controlling
EGUs.
Table
IV­
15
shows
the
amounts
of
regionwide
ozone
season
NOx
emissions
reductions
under
CAIR
that
EPA
projects,
if
States
choose
to
meet
their
CAIR
obligations
by
controlling
EGUs.
If
all
affected
States
choose
to
implement
these
reductions
through
controls
on
EGUs,
the
regionwide
annual
SO2
and
NOx
emissions
caps
that
would
apply
for
EGUs
are
also
shown
in
the
Table
IV­
14,
and
ozone
season
NOx
caps
for
EGUs
are
in
Table
IV­
15.
Base
case
emissions
levels
for
affected
EGUs
as
well
as
emissions
with
CAIR
are
also
shown
in
Table
IV­
14
and
Table
IV­
15,

based
on
IPM
modeling.

EPA
is
finalizing
the
regionwide
EGU
SO2
emissions
caps
 
if
States
choose
to
comply
by
controlling
EGUs
 
as
shown
in
Table
IV­
1482.
As
indicated
above,
EPA
identified
SO2
budget
amounts,
as
target
levels
for
further
evaluation,
by
adding
together
the
title
IV
Phase­
II
allowances
for
all
of
the
States
in
the
CAIR
region,
and
making
a
50
percent
reduction
for
the
2010
cap
and
a
65
percent
reduction
for
the
2015
cap.
The
EPA
determined,
through
IPM
analysis,
that
the
resulting
regionwide
emissions
caps
(
if
all
States
335
33
For
a
discussion
of
the
emission
reduction
requirements
if
States
choose
to
control
sources
other
than
EGUs,
see
section
VII
of
this
preamble.
choose
to
obtain
reductions
from
EGUs)
are
highly
costeffective
levels.

Also,
EPA
is
finalizing
the
regionwide
EGU
annual
and
ozone
season
NOx
emission
caps
 
if
States
choose
to
comply
by
controlling
EGUs
 
as
shown
in
Table
IV­
14
and
Table
IV­

15.83
As
indicated
above,
EPA
identified
NOx
budget
amounts,

as
target
levels
for
further
evaluation,
through
the
methodology
of
determining
the
highest
recent
Acid
Rain
Program
heat
input
from
years
1999­
2002
for
each
affected
State,
summing
the
highest
State
heat
inputs
into
a
regionwide
heat
input,
and
multiplying
the
regionwide
heat
input
by
0.15
lb/
mmBtu
and
0.125
lb/
mmBtu
for
2009
and
2015,

respectively.
The
EPA
determined,
through
IPM
analysis,
that
the
resulting
regionwide
emissions
caps
(
if
all
States
choose
to
obtain
reductions
from
EGUs)
are
highly
costeffective
levels.

The
emission
reductions,
EGU
emissions
caps,
and
emissions
shown
in
Table
IV­
14
are
for
the
23
States
and
the
District
of
Columbia
that
are
required
to
make
annual
SO2
and
NOx
reductions
for
CAIR.
(
Table
IV­
14
does
not
include
information
for
the
5
States
that
are
required
to
make
ozone
season
reductions
only.)
336
The
emission
reductions,
EGU
emissions
caps,
and
emissions
shown
in
Table
IV­
15
are
for
the
25
States
and
the
District
of
Columbia
that
are
required
to
make
ozone
season
NOx
reductions
for
CAIR.
(
Table
IV­
15
does
not
include
information
for
the
3
States
that
are
required
to
make
annual
reductions
only.)

EPA
is
requiring
the
CAIR
SO2
and
NOx
emissions
reductions
in
two
phases.
For
States
affected
by
annual
SO2
and
NOx
emission
reductions
requirements,
the
final
(
second)

phase
commences
January
1,
2015,
and
the
first
phase
begins
January
1,
2010
for
SO2
reductions
and
January
1,
2009
for
NOx
reductions.
For
States
affected
by
ozone
season
NOx
emission
reductions
requirements,
the
final
(
second)
phase
commences
May
1,
2015
and
the
first
phase
starts
May
1,

2009.
Notably,
the
first
phase
control
requirements
are
effective
in
years
2010
through
2014
for
SO2
and
in
years
2009
through
2014
for
NOx,
and
the
2015
requirements
are
for
that
year
and
thereafter.
337
34
Table
IV­
14
includes
regionwide
information
for
the
23
States
and
DC
that
are
required
by
CAIR
to
make
annual
emission
reductions.
It
does
not
include
information
for
the
5
CAIR
States
that
are
required
to
make
ozone
season
reductions
only.
The
CAIR
requires
NOx
emission
reductions
in
a
total
of
28
States
and
DC.
For
20
States
and
DC,
both
annual
and
ozone
season
NOx
reductions
are
required.
For
3
States
only
annual
reductions
are
required,
and
for
5
States
only
ozone
season
reductions
are
required.
The
total
projected
NOx
emission
reductions
that
will
result
from
CAIR
 
if
all
States
control
EGUs
 
include
the
annual
reductions
shown
in
Table
IV­
14
(
for
23
States
and
DC)
plus
the
ozone
season
reductions
in
the
5
States
required
to
make
ozone
season
reductions
only.
EPA
projects
the
total
NOx
reductions,
in
all
28
CAIR
States
and
DC,
to
be
1.2
million
tons
in
2009
and
1.5
million
tons
in
2015.
Note
that
the
values
in
this
table
represent
the
final
CAIR
policy
and
differ
slightly
from
the
values
in
the
RIA
(
which
were
based
on
an
earlier
and
slightly
different
IPM)
(
see
more
detailed
discussion
both
earlier
in
this
section
and
in
the
RIA).
TABLE
IV­
14.
Final
Rule
SO2
and
NOx
Annual
Base
Case
Emissions,
Emission
Caps,
Emissions
After
CAIR
and
Emission
Reductions
in
the
Region
Required
to
Make
Annual
SO2
and
NOx
Reductions
(
23
State
and
DC)
for
the
Interim
Phase
(
2010
for
SO2
and
2009
FOR
NOx)
and
Final
Phase(
2015
FOR
SO2
AND
NOx)
for
EGUs(
Million
Tons)
84
First
Phase
(
2010
for
SO2
and
2009
for
NOx)

Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
After
CAIR
Emissions
Reduced
SO2
8.7
3.6
5.1
3.5
NOx
2.7
1.5
1.5
1.2
Sum
11.4
NA
6.6
4.8
Second
Phase
(
2015
for
SO2
and
NOx)

Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
After
CAIR
Emissions
Reduced
SO2
7.9
2.5
4.0
3.8
NOx
2.8
1.3
1.3
1.5
Sum
10.6
NA
5.3
5.3
NOTE:
Numbers
may
not
add
due
to
rounding.
338
35
Table
IV­
15
shows
regionwide
information
for
the
25
States
and
DC
that
are
required
to
make
ozone
season
emission
reductions
under
CAIR.
It
does
not
include
information
for
the
3
States
that
are
required
to
make
annual
emission
reductions
only.
1
The
emission
caps
that
EPA
used
to
make
its
determination
of
highly
cost­
effective
controls
and
the
emission
reductions
associated
with
those
caps
are
shown
in
Table
IV­
14.
For
a
discussion
of
the
emission
reduction
requirements
if
States
control
source
categories
other
than
EGUs,
see
section
VII
in
this
preamble.
Emissions
shown
here
are
for
EGUs
with
capacity
greater
than
25
MW.
2
The
District
of
Columbia
and
the
following
23
States
are
affected
by
CAIR
for
annual
SO2
and
NOx
controls:
AL,
FL,
GA,
IA,
IL,
IN,
KY,
LA,
MD,
MI,
MN,
MO,
MS,
NY,
NC,
OH,
PA,
SC,
TN,
TX,
VA,
WV,
WI.
3
The
2010
SO2
emissions
cap
applies
to
years
2010
through
2014.
The
2009
NOx
emissions
cap
applies
to
years
2009
through
2014.
The
2015
caps
apply
to
2015
and
beyond.
4
Due
to
the
use
of
the
existing
bank
of
SO2
allowances,
the
estimated
SO2
emissions
in
the
CAIR
region
in
2010
and
2015
are
higher
than
the
emissions
caps.
5
Over
time
the
banked
SO2
emissions
allowances
will
be
consumed
and
the
2015
cap
level
will
be
reached.
SO2
emissions
levels
can
be
thought
of
as
on
a
flexible
"
glide
path"
to
meet
the
2015
CAIR
cap
with
increasing
reductions
over
time.
The
annual
SO2
emissions
levels
in
2020
with
CAIR
are
forecasted
to
be
3.3
million
tons
within
the
region
encompassing
States
required
to
make
annual
reductions,
an
annual
reduction
of
4.4
million
tons
from
base
case
levels.

Table
IV­
15.
­
Final
Rule
NOx
Ozone
Season
Base
Case
Emissions,
Emissions
Caps,
Emissions
after
Cair
and
Emission
Reductions
in
the
Region
Required
to
Make
Ozone
Season
NOx
Reductions
(
25
States
and
DC)
for
the
Interim
Phase
(
2009)
and
Final
Phase
(
2015)
for
Electric
Generation
Units
(
Million
Tons)
85
Ozone
Season
NOx
Phase
Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
after
CAIR
Emissions
Reduced
2009
0.7
0.6
0.6
0.1
2015
0.7
0.5
0.5
0.2
1
The
emission
caps
that
EPA
used
to
make
its
determination
of
highly
cost­
effective
controls
and
the
emission
reductions
associated
with
those
caps
are
shown
in
Table
IV­
15.
For
a
discussion
of
the
emission
reduction
requirements
if
States
control
source
categories
other
than
EGUs,
see
section
VII
in
this
preamble.
Emissions
shown
here
are
for
EGUs
with
capacity
greater
than
25
MW.
339
2
The
District
of
Columbia
and
the
following
25
States
are
affected
by
CAIR
for
ozone
season
NOx
controls:
AL,
AR,
CT,
DE,
FL,
IA,
IL,
IN,
KY,
LA,
MA,
MD,
MI,
MO,
MS,
NJ,
NY,
NC,
OH,
PA,
SC,
TN,
VA,
WV,
WI.
3
The
2009
NOx
emissions
cap
applies
to
years
2009
through
2014.
The
2015
cap
applies
to
2015
and
beyond.

Table
IV­
16
shows
the
estimated
amounts
of
regionwide
annual
SO2
and
NOx
emissions
reductions
that
would
occur
if
EPA
finalizes
its
proposal
to
find
that
Delaware
and
New
Jersey
contribute
significantly
to
downwind
PM2.5
nonattainment,
and
if
all
affected
States
choose
to
control
EGUs
(
the
proposal
is
published
in
the
"
Proposed
Rules"

section
of
today's
action).
In
that
case,
the
estimated
regionwide
annual
SO2
and
NOx
emissions
caps
that
would
apply
for
EGUs
are
as
shown
in
Table
IV­
16.
Annual
base
case
emissions
levels
for
EGUs
in
the
CAIR
region
(
including
Delaware
and
New
Jersey)
as
well
as
emissions
with
CAIR
are
also
shown
in
the
Table,
based
on
IPM
modeling.
If
EPA
finalizes
its
proposal
to
include
Delaware
and
New
Jersey
for
PM2.5
requirements,
then
the
ozone
season
requirements
would
not
change
for
States
required
to
make
ozone
season
reductions
for
CAIR.
Based
on
EPA
modeling
with
Delaware
and
New
Jersey
included
in
the
PM2.5
region
(
and
if
all
affected
States
choose
to
control
EGUs),
the
EGU
emissions
caps
and
the
ozone
season
NOx
emissions
and
emission
reductions
associated
with
those
caps,
for
the
25
States
and
the
District
of
Columbia
that
are
required
to
make
ozone
340
36
For
a
discussion
of
the
emission
reduction
requirements
if
States
choose
to
control
sources
other
than
EGUs,
see
section
VII
of
this
preamble.
season
NOx
reductions,
would
be
as
shown
in
Table
IV­
15,

above86.
341
37
Table
IV­
16
includes
regionwide
information
for
the
25
States
and
DC
that
will
be
required
to
make
annual
emission
reductions
if
EPA
finalizes
its
proposal
to
require
annual
reductions
in
Delaware
and
New
Jersey
under
CAIR.
The
table
does
not
include
information
for
the
3
States
(
Arkansas,
Connecticut,
and
Massachusetts)
that
would
be
affected
by
CAIR
for
ozone
season
reductions
only.
Table
IV­
16.
­
SO2
and
NOx
Annual
Base
Case
Emissions,
Emissions
Caps,
Emissions
after
Cair
and
Emission
Reductions
in
the
Region
Required
to
Make
Annual
SO2
and
NOx
Reductions
(
25
States
and
Dc)
for
the
Initial
Phase
(
2010
for
SO2
and
2009
for
NOx)
and
Final
Phase
(
2015
for
SO2
and
NOx)
for
Electric
Generation
Units
If
Epa
Finalizes
its
Proposal
to
Include
Delaware
and
New
Jersey
for
Pm2.5
Requirements
(
Million
Tons)
87
First
Phase
(
2010
for
SO2
and
2009
for
NOx)

Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
After
CAIR
Emissions
Reduced
SO2
8.8
3.7
5.2
3.6
NOx
2.8
1.5
1.5
1.2
Sum
11.5
NA
6.7
4.8
Second
Phase
(
2015
for
SO2
and
NOx)

Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
After
CAIR
Emissions
Reduced
SO2
7.9
2.6
4.1
3.9
NOx
2.8
1.3
1.3
1.5
Sum
10.7
NA
5.3
5.4
NOTE:
Numbers
may
not
add
due
to
rounding.

1
The
emission
caps
that
EPA
used
to
make
its
determination
of
highly
cost­
effective
controls
and
the
emission
reductions
associated
with
those
caps
are
shown
in
Table
IV­
16.
For
a
discussion
of
the
emission
reduction
requirements
if
States
control
source
categories
other
than
EGUs,
see
section
VII
in
this
preamble.
Emissions
shown
here
are
for
EGUs
with
capacity
greater
than
25
MW.
2
The
District
of
Columbia
and
the
following
25
States
would
be
affected
by
CAIR
for
annual
SO2
and
NOx
controls
if
EPA
finalizes
its
proposal
to
include
DE
and
NJ:
AL,
DE,
FL,
GA,
IA,
IL,
IN,
KY,
LA,
MD,
MI,
MN,
MO,
MS,
NJ,
NY,
NC,
OH,
PA,
SC,
TN,
TX,
VA,
WV,
WI.
3
The
2010
SO2
emissions
cap
would
apply
to
years
2010
through
2014.
The
2009
NOx
emissions
cap
would
apply
to
years
2009
through
2014.
The
2015
caps
would
apply
to
2015
and
beyond.
342
4
Due
to
the
use
of
the
existing
bank
of
SO2
allowances,
the
estimated
SO2
emissions
in
the
CAIR
region
in
2010
and
2015
would
be
higher
than
the
emissions
caps.
5
Over
time
the
banked
SO2
emissions
allowances
would
be
consumed
and
the
2015
cap
level
would
be
reached.
SO2
emissions
levels
can
be
thought
of
as
on
a
flexible
"
glide
path"
to
meet
the
2015
CAIR
cap
with
increasing
reductions
over
time.
The
annual
SO2
emissions
levels
in
2020
with
CAIR,
within
the
region
of
States
required
to
make
annual
reductions
(
including
Delaware
and
New
Jersey),
are
forecasted
to
be
3.3
million
tons,
an
annual
reduction
of
4.4
million
tons
from
base
case
levels.

EPA
apportioned
the
EGU
caps
 
and
associated
required
regionwide
emission
reductions
 
on
a
State­
by­
State
basis.

The
affected
States
may
determine
the
necessary
controls
on
SO2
and
NOx
emissions
to
achieve
the
required
reductions.

EPA's
apportionment
method
and
the
resulting
State
EGU
emissions
budgets
are
described
in
Section
V
in
today's
preamble.

To
achieve
the
required
SO2
and
NOx
reductions
in
the
most
cost­
effective
manner,
EPA
suggests
that
States
implement
these
reductions
by
controlling
EGUs
under
a
cap
and
trade
program
that
EPA
would
implement.

However,
the
States
have
flexibility
in
choosing
the
sources
that
must
reduce
emissions.
If
the
States
choose
to
require
EGUs
to
reduce
their
emissions,
then
States
must
impose
a
cap
on
EGU
emissions,
which
would
in
effect
be
an
annual
emissions
budget.
Provisions
for
allocating
SO2
and
NOx
allowances
to
individual
EGUs
 
which
apply
if
a
State
chooses
to
control
EGUs
and
elects
to
allow
them
to
participate
in
the
interstate
cap
and
trade
program
 
are
343
presented
elsewhere
in
today's
preamble.
If
a
State
wants
to
control
EGUs,
but
does
not
want
to
allow
EGUs
to
participate
in
the
interstate
cap
and
trade
program,
the
State
has
flexibility
in
allocating
allowances,
but
it
must
cap
EGUs.
Sources
that
are
subject
to
the
emission
reduction
requirements
under
title
IV
continue
to
be
subject
to
those
requirements.

If
the
States
choose
to
control
other
sources,
then
they
must
employ
methods
to
assure
that
those
other
sources
implement
controls
that
will
yield
the
appropriate
amount
of
annual
emissions
reduction.
See
Section
VII
(
SIP
Criteria
and
Emissions
Reporting
Requirements)
in
today's
preamble.

Implementation
of
the
cap
and
trade
program
is
discussed
in
Section
VIII
in
today's
preamble.

For
convenience,
we
use
specific
terminology
to
refer
to
certain
concepts.
"
State
budget"
refers
to
the
statewide
emissions
that
may
be
used
as
an
accounting
technique
to
determine
the
amount
of
annual
or
ozone
season
emissions
reductions
that
controls
may
yield.
It
does
not
imply
that
there
is
a
legally
enforceable
statewide
cap
on
emissions
from
all
SO2
or
NOx
sources.
"
Regionwide
budget"
refers
to
the
amount
of
emissions,
computed
on
a
regionwide
basis,

which
may
be
used
to
determine
State­
by­
State
requirements.

It
does
not
imply
that
there
is
a
legally
enforceable
regionwide
cap
on
emissions
from
all
SO2
or
NOx
sources.
344
"
State
EGU
budget"
refers
to
the
legally
enforceable
annual
or
ozone
season
emissions
cap
on
EGUs
a
State
would
apply
should
it
decide
to
control
EGUs.

V.
Determination
of
State
Emissions
Budgets
The
EPA
outlined
in
the
NPR
and
SNPR
its
proposals
regarding
a
methodology
for
setting
both
regional
and
State­
level
SO2
and
NOx
budgets.
Section
IV
explains
how
the
region
wide
budgets
were
developed.
This
section
V
describes
how
EPA
apportions
the
regionwide
emissions
reductions
 
and
the
associated
EGU
caps
 
on
a
State­
by­

State
basis,
so
that
the
affected
States
may
determine
the
necessary
controls
of
SO2
and
NOx
emissions.

In
the
NPR
and
SNPR,
EPA
proposed
annual
SO2
and
NOx
caps
for
States
contributing
to
fine
particle
nonattainment
and
separate
ozone­
season
only
caps
for
States
contributing
to
ozone
 
but
not
fine
particle
 
nonattainment.
The
EPA
is
finalizing
an
annual
cap
for
both
SO2
and
NOx
for
States
that
contribute
to
fine
particle
nonattainment.
In
addition,
EPA
is
finalizing
an
ozone­
season
only
cap
for
NOx
for
all
States
that
contribute
to
ozone
nonattainment.

States
have
several
options
for
reducing
emissions
that
significantly
contribute
to
downwind
nonattainment.
They
can
adopt
EPA's
approach
of
reducing
the
emissions
in
a
cost­
effective
manner
through
an
interstate
cap­
and­
trade
345
program.
This
approach
would,
by
definition,
achieve
the
required
cost­
effective
reductions.
Alternately,
States
could
achieve
all
of
the
necessary
emissions
reductions
from
EGUs,
but
choose
not
to
use
EPA's
interstate
emissions
trading
program.
In
this
case,
a
State
would
need
to
demonstrate
that
it
is
meeting
the
EGU
budgets
outlined
in
this
section.
Finally,
States
could
obtain
at
least
some
of
their
required
emissions
reductions
from
sources
other
than
EGUs.
Additional
detail
on
these
options
is
provided
in
section
VII.

A.
What
Is
the
Approach
for
Setting
State­
by­
State
Annual
Emissions
Reductions
Requirements
and
EGU
Budgets?

This
section
presents
the
final
methodologies
used
for
apportioning
regionwide
emission
reduction
requirements
or
budgets
to
the
individual
States.

In
the
CAIR
NPR,
EPA
proposed
methods
for
determining
the
SO2
and
NOx
emission
reduction
requirements
or
budgets
for
each
affected
State.
In
the
June
2004
SNPR,
EPA
proposed
corrections
and
improvements
to
the
proposals
in
the
CAIR
NPR.
In
the
August
2004
NODA,
EPA
presented
the
corrected
NOx
budgets
resulting
from
the
improvements
proposed
in
the
SNPR.

1.
SO2
Emissions
Budgets
a.
State
Annual
SO2
Emission
Budget
Methodology
346
As
noted
elsewhere
in
today's
preamble,
the
regionwide
annual
budget
for
2015
and
beyond
is
based
on
a
65
percent
reduction
of
title
IV
allowances
allocated
to
units
in
the
CAIR
States
for
SO2
control.
The
regionwide
annual
SO2
budget
for
the
years
2010­
2014
is
based
on
a
50
percent
reduction
from
title
IV
allocations
for
all
units
in
affected
States.

In
the
NPR
and
SNPR,
EPA
also
proposed
calculating
annual
State
SO2
budgets
based
on
each
State's
allowances
under
title
IV
of
the
1990
CAA
Amendments.
We
are
finalizing
this
proposed
approach
for
determining
State
annual
SO2
budgets.

State
annual
budgets
for
the
years
2010­
2014
(
Phase
I)

are
based
on
a
50
percent
reduction
from
title
IV
allocations
for
all
units
in
the
affected
State.
The
State
annual
budget
for
2015
and
beyond
(
Phase
II)
is
based
on
a
65
percent
reduction
of
title
IV
allowances
allocated
to
units
in
the
affected
State
for
SO2
control.

Some
commenters
criticized
EPA's
basing
State
budgets
on
title
IV
allocations
since
these
were
based
largely
on
1985­
1987
historic
heat
input
data.
Commenters
argue
that
the
initial
allocation
was
not
equitable
and
that
in
any
event,
the
electric
power
sector
has
changed
significantly.

They
conclude
that
State
budgets
should
reflect
those
differences.
Commenters
have
also
commented
that
tying
SO2
347
allocations
to
title
IV
also
does
not
let
States
account
for
units
that
are
exempt
from
title
IV
or
for
new
units
that
have
come
online
since
1990.

While
acknowledging
these
concerns,
EPA
believes,
for
a
number
of
reasons,
that
setting
State
budgets
according
to
title
IV
allowances
represents
a
reasonable
approach.

The
EPA
believes
that
basing
budgets
on
title
IV
allowances
is
necessary
in
order
to
ensure
the
preservation
of
a
viable
title
IV
program,
which
is
important
for
reasons
discussed
in
section
IX
of
this
preamble.
Such
reasons
include
the
desire
to
maintain
the
trust
and
confidence
that
has
developed
in
the
functioning
market
for
title
IV
allowances.
The
EPA
believes
it
is
important
not
to
undermine
such
confidence
(
which
is
an
essential
underpinning
to
a
viable
market­
based
system)
recognizing
that
it
is
a
key
to
the
success
of
a
trading
program
under
the
CAIR.

The
title
IV
program
represents
a
logical
starting
point
for
assessing
emissions
reductions
for
SO2,
since
it
is
the
current
effective
cap
on
SO2
emissions
for
Acid
Rain
units,
which
make
up
the
large
majority
of
affected
EGU
CAIR
units.
It
is
from
this
starting
emissions
cap,
that
further
CAIR
reductions
are
required.
Consequently,
EPA
proposes
State­
level
reductions
based
on
reductions
from
the
initial
348
allocations
of
title
IV
allowances
to
individual
units
at
sources
(
power
plants)
in
States
covered
by
the
CAIR.

The
setting
of
SO2
budgets
differs
from
the
setting
of
NOx
budgets
for
the
CAIR,
in
part,
because
of
this
difference
in
starting
points
­
since
there
is
no
existing
NOx
regional
annual
cap,
and
no
currency
for
emissions,
on
which
sources
rely.
Furthermore,
Congress,
as
part
of
title
IV
of
the
CAA,
decided
upon
the
allocations
of
title
IV
allowances
specifically
for
the
control
of
SO2,
and
not
for
NOx.

Moreover,
Congress
decided
to
allocate
title
IV
allowances
in
perpetuity,
realizing
that
the
electricity
sector
would
not
remain
static
over
this
time
period.

Congress
clearly
did
not
choose
a
policy
to
regularly
revisit
and
revise
these
allocations,
believing
that
its
allocations
methodology
for
title
IV
allowances
would
be
appropriate
for
future
time
periods.

The
EPA
realizes,
putting
aside
concerns
of
linkage
to
title
IV,
that
there
are
numerous
potential
methodologies
of
dividing
up
the
regional
budgets
among
the
States.
Also,

EPA
believes,
that
while
initial
allocations
of
State
budgets
are
important
for
distributional
reasons,
under
a
cap­
and­
trade
system,
they
would
not
impact
the
attainment
of
the
environmental
objectives
or
the
overall
cost
of
this
rule.
349
Each
of
the
alternate
methods
also
has
certain
shortcomings,
many
of
which
have
been
identified
by
commenters.
Basing
allowances
on
historic
emissions,
for
instance,
would
penalize
States
that
have
already
gone
through
significant
efforts
to
clean
up
their
sources.

Basing
allowances
on
heat
input
has
advantages,
but
cannot
accommodate
States
that
have
worked
to
improve
their
energy
efficiency.
Basing
allowances
on
output
would
provide
gasfired
units
with
many
more
allowances
than
they
need,
rather
than
giving
them
to
the
coal­
fired
units
that
will
be
incurring
the
greatest
costs
from
the
tighter
caps.

The
EPA
did
look
at
a
number
of
allowance
outcomes
using
alternate
potential
methods
for
allocating
SO2
allowances.
These
methods
included
allocating
on
the
basis
of
historic
emissions,
heat
input
(
with
alternatives
based
on
heat
input
from
all
fossil
generation,
and
heat
input
from
coal­
and
oil­
fired
generation
only)
and
output
(
with
alternatives
based
on
all
generation
and
all
fossil­
fired
generation).
Allocating
allowances
based
on
title
IV
yields
results
that
fall
within
a
reasonable
range
of
results
obtained
from
using
these
alternate
methodologies.
In
fact,

calculating
State
budgets
using
title
IV
allowances
yields
budgets
generally
at
or
within
the
ranges
of
budgets
calculated
using
the
other
methods
in
more
than
two­
thirds
of
the
States,
which
account
for
over
85
percent
of
the
350
total
heat
input
in
the
region
from
1999­
2002.
This
analysis
is
discussed
further
in
the
response
to
comments
document.

b.
Final
SO2
State
Emission
Budget
Methodology
The
EPA
is
finalizing
the
budgets
as
noted
in
the
SNPR,

adjusting
for
the
proper
inclusion
of
States
covered
under
the
final
CAIR.
The
final
State
budgets
are
included
in
Table
V­
1
below.
Details
of
the
data
and
methodology
used
to
calculate
these
budgets
are
included
in
the
accompanying
"
Regional
and
State
SO2
and
NOx
Emissions
Budgets"
Technical
Support
Document.

Table
V­
1.
Final
Annual
Electric
Generating
Units
SO2
Budgets
State
State
SO2
Budget
2010*

(
tons)
State
SO2
Budget
2015**

(
tons)
Alabama
157,582
110,307
District
of
Columbia
708
495
Florida
253,450
177,415
Georgia
213,057
149,140
Illinois
192,671
134,869
Indiana
254,599
178,219
Iowa
64,095
44,866
Kentucky
188,773
132,141
Louisiana
59,948
41,963
Maryland
70,697
49,488
Michigan
178,605
125,024
Minnesota
49,987
34,991
Mississippi
33,763
23,634
Missouri
137,214
96,050
New
York
135,139
94,597
North
Carolina
137,342
96,139
Ohio
333,520
233,464
Pennsylvania
275,990
193,193
351
South
Carolina
57,271
40,089
Tennessee
137,216
96,051
Texas
320,946
224,662
Virginia
63,478
44,435
West
Virginia
215,881
151,117
Wisconsin
87,264
61,085
Total
3,619,196
2,533,434
*
Annual
budget
for
SO2
tons
covered
by
allowances
for
2010­
2014.

**
Annual
budget
for
SO2
tons
covered
by
allowances
for
2015
and
thereafter.

c.
Use
of
SO2
Budgets
These
specific
levels
of
the
proposed
State
budgets
would
actually
provide
binding
statewide
caps
on
EGU
emissions
for
States
that
choose
to
control
only
EGUs
but
do
not
want
to
participate
in
the
trading
program.
For
States
choosing
to
participate
in
the
trading
program,
these
State
budgets
would
not
be
binding,
instead,
the
States'
SO2
reductions
would
be
achieved
solely
through
the
application
of
required
retirement
ratios
as
discussed
in
section
VII
of
this
preamble.
For
States
controlling
both
EGUs
and
non­

EGUs
(
or
controlling
only
non­
EGUs),
these
State
budgets
would
be
used
to
calculate
the
emissions
reductions
requirements
for
non­
EGUs
and
the
remaining
reduction
requirement
for
EGUs.
This
is
described
in
more
detail
in
the
section
VII
discussion
on
SIP
approvability.

2.
NOx
Annual
Emissions
Budgets
a.
Overview
352
In
this
section,
EPA
discusses
the
apportioning
of
regionwide
NOx
annual
emission
reduction
requirements
or
budgets
to
the
individual
States.
In
the
January
2004
proposal,
we
proposed
State
EGU
annual
NOx
budgets
based
on
each
State's
average
share
of
recent
historic
heat
input.

In
the
SNPR,
we
proposed
the
same
input­
based
methodology,

but
revised
the
budgets
based
on
more
complete
heat
input
data.
Also,
EPA
took
comment
on
an
alternative
methodology
that
determines
State
budgets
by
multiplying
heat
input
data
by
adjustment
factors
for
different
fuels.
In
the
August
NODA,
EPA
presented
the
corrected
annual
NOx
budgets
resulting
from
the
improved
methodology
proposed
in
the
SNPR.

b.
State
Annual
NOx
Emissions
Budget
Methodology
1.
Proposed
and
Discussed
NOx
Emission
Budget
Methodology
As
noted
elsewhere
in
today's
preamble,
EPA
determined
historical
annual
heat
input
data
for
Acid
Rain
Program
units
in
the
applicable
States
and
multiplied
by
0.15
lb/
mmBtu
(
for
2009)
and
0.125
lb/
mmBtu
(
for
2015)
to
determine
total
annual
NOx
regionwide
budgets
for
the
CAIR
region.
The
EPA
applied
these
rates
to
each
individual
State's
total
highest
annual
heat
input
for
any
year
from
1999
through
2002.
Thus,
EPA
used
the
heat
input
total
for
353
the
year
in
which
a
State's
total
heat
input
was
the
highest.

In
the
January
2004
proposal,
we
proposed
annual
NOx
State
budgets
for
a
28­
State
(
and
D.
C.)
region
based
on
each
jurisdiction's
average
heat
input
 
using
heat
input
data
from
Acid
Rain
Program
units
­
over
the
years
1999
through
2002.
We
summed
the
average
heat
input
from
each
of
the
applicable
jurisdictions
to
obtain
a
regional
total
average
annual
heat
input.
Then,
each
State
received
a
pro
rata
share
of
the
regional
NOx
emissions
budget
based
on
the
ratio
of
its
average
annual
heat
input
to
the
regional
total
average
annual
heat
input.

In
the
SNPR,
EPA
proposed
to
revise
its
determination
of
State
NOx
budgets
by
supplementing
Acid
Rain
Program
unit
data
with
annual
heat
input
data
from
the
U.
S.
Energy
Information
Administration
(
EIA),
for
the
non­
Acid
Rain
unit
data.
A
number
of
commenters
had
suggested
that
this
would
better
reflect
the
heat
input
of
the
units
that
will
be
controlled
under
the
CAIR,
and
EPA
agrees.

In
the
SNPR,
EPA
asked
for,
and
subsequently
received,

comments
on
determining
State
budgets
by
multiplying
heat
input
data
by
adjustment
factors
for
different
fuels.
The
factors
would
reflect
the
inherently
higher
emissions
rate
of
coal­
fired
units,
and
consequently
the
greater
burden
on
coal
units
to
control
emissions.
354
2.
Today's
Rule
As
noted
earlier
in
the
case
of
SO2,
EPA
recognizes
that
the
choice
of
method
in
setting
State
budgets,
with
a
given
regionwide
total
annual
budget,
makes
little
difference
in
terms
of
the
levels
of
resulting
regionwide
annual
SO2
and
NOx
emissions
reductions.
If
States
choose
to
control
EGUs
and
participate
in
the
cap­
and­
trade
program,
allowances
could
be
freely
traded,
encouraging
least­
cost
compliance
over
the
entire
region.
In
such
a
case,
the
least­
cost
outcome
would
not
depend
on
the
relative
levels
of
individual
State
budgets.

A
number
of
commenters
have
stated,
without
supporting
analysis
or
evidence,
that
budgets
based
on
heat
input,
(
and
particularly
those
that
would
use
different
fuel
factors)
do
not
encourage
efficiency.
Economic
theory
indicates
that
neither
a
heat
input,
nor
an
output­
based
approach,
if
allocated
once
and
based
on
a
historical
baseline,
would
provide
any
incentives
for
more
or
less
efficient
generation
(
changes
in
future
behavior
would
have
no
impact
on
allocations).
The
cap­
and­
trade
system
itself,
regardless
of
how
the
allowances
are
distributed,
provides
the
primary
incentive
for
more
efficient,
cleaner
generation
of
electricity.
355
1
States
receiving
larger
budgets
under
this
approach
are
generally
expected
to
be
those
having
to
make
the
most
reductions.
The
EPA
is
finalizing
an
approach
of
calculating
State
budgets
through
a
fuel­
adjusted
heat­
input
basis.
State
budgets
would
be
determined
by
multiplying
historic
heat
input
data
(
summed
by
fuel)
by
different
adjustment
factors
for
the
different
fuels.
These
factors
reflect
for
each
fuel
(
coal,
gas
and
oil),
the
1999­
2002
average
emissions
by
State,
summed
for
the
CAIR
region,
divided
by
average
heat
input
by
fuel
by
State,
summed
for
the
CAIR
region.
The
resulting
adjustment
factors
from
this
calculation
are
1.0
for
coal,
0.4
for
gas
and
0.6
for
oil.
The
factors
would
reflect
the
inherently
higher
emissions
rate
of
coal­
fired
plants,
and
consequently
the
greater
burden
on
coal
plants
to
control
emissions.

Such
an
approach
provides
States
with
allowances
more
in
proportion
with
their
historical
emissions.
It
provides
for
a
more
equitable
budget
distribution
by
recognizing
that
different
States
are
facing
the
reduction
requirements
with
different
starting
stocks
of
generation,
with
different
starting
emission
profiles.
88
The
fuel
burned
is
a
key
factor
in
differentiating
the
generation.

However,
this
approach
is
not
equivalent
to
an
approach
based
strictly
on
historical
emissions
(
which
would
give
356
fewer
allowances
to
States
which
have
already
cleaned
up
their
coal
plants).
Under
the
approach
we
are
finalizing
today,
heat
input
from
all
coal,
whether
clean
or
uncontrolled,
would
be
counted
equally
in
determining
State
budgets.
Likewise,
all
heat
input
from
gas,
whether
clean
or
uncontrolled,
from
a
steam­
gas
unit
or
from
a
combinedcycle
plant,
would
be
counted
equally
in
determining
State
budgets.

It
is
not
expected
that
this
decision
would
disadvantage
States
with
significant
gas­
fired
generation.

One
reason
is
that
the
calculation
of
the
adjusted
heat
input
for
natural
gas
generation
generally
includes
significant
historic
heat
input
and
emissions
from
older,

less
efficient
and
dirtier
steam
gas
units.
These
units'

capacity
factors
are
declining
and
are
expected
to
decline
further
over
time
as
new,
cleaner
and
more
efficient
combined­
cycle
gas
units
increase
their
generation.

It
is
important
to
note
that
the
methodology
by
which
the
NOx
State
budgets
are
determined
need
not
be
used
by
individual
States
in
determining
allocations
to
specific
sources.
As
discussed
in
section
VIII
of
this
document
(
Model
Trading
Rule),
EPA
is
offering
States
the
flexibility
to
allocate
allowances
from
their
budgets
as
they
see
fit.

Finally,
EPA
discussed
in
the
January
2004
proposal,
a
methodology
used
in
the
NOx
SIP
Call
(
67
FR
21868)
that
357
2
With
a
methodology
similar
to
that
used
in
the
NOx
SIP
Call,
annual
State
NOx
budgets
would
be
set
by
using
a
base
heat
input
data,
then
adjusting
it
by
a
calculated
growth
rate
for
each
jurisdiction's
annual
EGU
heat
inputs
applied
State­
specific
growth
rates
for
heat
input
in
setting
State
budgets.
89
The
EPA,
in
the
SNPR,
noted
that
it
is
not
proposing
to
use
this
method
for
the
CAIR
because
we
believe
that
other
methods
are
reasonable,
and
that
methods
involving
State­
specific
growth
rates
present
certain
challenges
due
to
the
inherent
difficulties
in
predicting
State­
specific
growth
in
heat
input
over
a
lengthy
period,

especially
for
jurisdictions
that
are
only
a
part
of
a
larger
regional
electric
power
dispatch
region.
Several
commenters
stated
their
support
for
incorporating
growth,

believing
that
not
taking
growth
into
account
would
penalize
States
with
higher
growth.
However,
a
significant
number
of
commenters
stated
their
opposition
to
using
growth
in
setting
State
budgets,
noting
the
problems
that
arose
in
the
NOx
SIP
Call.
The
EPA
believes
that
setting
budgets
using
a
heat
input
approach,
without
a
growth
adjustment,
is
fair,

would
be
simpler
and
would
involve
less
risk
of
resulting
litigation.

c.
Final
Annual
State
NOx
Emission
Budgets
The
final
annual
State
Nox
emission
budgets
following
this
method
are
included
in
Table
V­
2
below.
Details
of
the
numbers
and
methodology
used
to
calculate
these
budgets
are
358
included
in
the
"
Regional
and
State
SO2
and
NOx
Emissions
Budgets"
Technical
Support
Document.

Table
V­
2.
Final
Annual
Electric
Generating
Units
NOx
Budgets
State
State
NOx
Budget
2009*

(
tons)
State
NOx
Budget
2015**
(
tons)
Alabama
69,020
57,517
District
of
Columbia
144
120
Florida
99,445
82,871
Georgia
66,321
55,268
Illinois
76,230
63,525
Indiana
108,935
90,779
Iowa
32,692
27,243
Kentucky
83,205
69,337
Louisiana
35,512
29,593
Maryland
27,724
23,104
Michigan
65,304
54,420
Minnesota
31,443
26,203
Mississippi
17,807
14,839
Missouri
59,871
49,892
New
York
45,617
38,014
North
Carolina
62,183
51,819
Ohio
108,667
90,556
Pennsylvania
99,049
82,541
South
Carolina
32,662
27,219
Tennessee
50,973
42,478
Texas
181,014
150,845
Virginia
36,074
30,062
West
Virginia
74,220
61,850
Wisconsin
40,759
33,966
Total
1,504,871
1,254,061
*
Annual
budget
for
NOx
tons
covered
by
allowances
for
2009­
2014.

**
Annual
budget
for
NOx
tons
covered
by
allowances
for
2015
and
thereafter.

d.
Use
of
Annual
NOx
Budgets
These
proposed
State
budgets
would
serve
as
effective
binding
caps
on
State
emissions,
if
States
chose
to
control
359
only
EGUs,
but
did
not
want
to
participate
in
the
trading
program.
For
States
controlling
both
EGUs
and
non­
EGUs
(
or
controlling
only
non­
EGUs),
these
budgets
would
be
compared
to
a
baseline
level
of
emissions
to
calculate
the
emissions
reductions
requirements
for
non­
EGUs
and
the
required
caps
for
EGUs.
This
process
is
described
in
more
detail
in
the
section
VII
discussion
on
SIP
approvability.

e.
NOx
Compliance
Supplement
Pool
As
is
discussed
in
section
I,
EPA
is
establishing
a
NOx
compliance
supplement
pool
of
198,494
tons,
which
would
result
in
a
total
compliance
supplement
pool
of
approximately
200,000
tons
of
NOx
when
combined
with
EPA's
proposed
rulemaking
to
include
Delaware
and
New
Jersey.
The
EPA
is
apportioning
the
compliance
supplement
pool
to
States
based
on
the
assumption
that
a
State's
need
for
allowances
from
the
pool
is
proportional
to
the
magnitude
of
the
State's
required
emissions
reductions
(
as
calculated
using
the
State's
base
case
emissions
and
annual
NOX
budget).
The
EPA
is
apportioning
the
200,000
tons
of
NOx
on
a
pro­
rata
basis,
based
on
each
State's
share
of
the
total
emissions
reductions
requirement
for
the
region
in
2009.
This
is
consistent
with
the
methodology
used
in
the
NOx
SIP
Call.

Table
V­
3
presents
each
State's
compliance
supplement
pool.

Table
V­
3.
State
NOx
Compliance
Supplement
Pools
(
tons)
360
State
Base
Case
2009
Emissions
2009
State
Annual
NOX
Budget
Reduction
Requirement
Compliance
Supplement
Pool*
Alabama
132,019
69,020
62,999
10,166
District
Of
Columbia
0
144
0
0
Florida
151,094
99,445
51,649
8,335
Georgia
143,140
66,321
76,819
12,397
Illinois
146,248
76,230
70,018
11,299
Indiana
233,833
108,935
124,898
20,155
Iowa
75,934
32,692
43,242
6,978
Kentucky
175,754
83,205
92,549
14,935
Louisiana
49,460
35,512
13,948
2,251
Maryland
56,662
27,724
28,938
4,670
Michigan
117,031
65,304
51,727
8,347
Minnesota
71,896
31,443
40,453
6,528
Mississippi
36,807
17,807
19,000
3,066
Missouri
115,916
59,871
56,045
9,044
New
York
45,145
45,617
0
0
North
Carolina
59,751
62,183
0
0
Ohio
263,814
108,667
155,147
25,037
Pennsylvania
198,255
99,049
99,206
16,009
South
Carolina
48,776
32,662
16,114
2,600
Tennessee
106,398
50,973
55,425
8,944
Texas
185,798
181,014
4,784
772
Virginia
67,890
36,074
31,816
5,134
West
Virginia
179,125
74,220
104,905
16,929
Wisconsin
71,112
40,759
30,353
4,898
CAIR
Region
Subtotal
198,494
Delaware
9,389
4,166
5,223
843
New
Jersey
16,760
12,670
4,090
660
Total
199,997
*
Note:
Rounding
to
the
nearest
whole
allowance
results
in
a
total
compliance
supplement
pool
of
199,997
tons.
361
B.
What
Is
the
Approach
for
Setting
State­
by­
State
Emissions
Reductions
Requirements
and
EGU
Budgets
for
States
with
NOx
Ozone
Season
Reduction
Requirements?

1.
States
Subject
to
Ozone­
Season
Requirements
In
the
NPR,
EPA
proposed
that
Connecticut
contributes
significantly
to
ozone
nonattainment
in
another
State,
but
not
to
fine
particle
nonattainment.
As
a
result
of
subsequent
air
quality
modeling,
EPA
has
also
found
that
Massachusetts,
New
Jersey,
Delaware
and
Arkansas
contribute
significantly
to
ozone
nonattainment
in
another
State,
but
not
to
fine
particle
nonattainment.
In
this
final
rule,
EPA
is
establishing
a
regionwide
ozone­
season
budget
for
all
States
that
contribute
significantly
to
ozone
nonattainment
in
another
State,
regardless
of
their
contribution
to
fine
particle
nonattainment.
The
following
25
States,
plus
the
District
of
Columbia,
are
found
to
contribute
significantly
to
ozone
nonattainment:
Alabama,
Arkansas,
Connecticut,

Delaware,
Florida,
Illinois,
Indiana,
Iowa,
Kentucky,

Louisiana,
Maryland,
Massachusetts,
Michigan,
Mississippi,

Missouri,
New
Jersey,
New
York,
North
Carolina,
Ohio,

Pennsylvania,
South
Carolina,
Tennessee,
Virginia,
West
Virginia,
and
Wisconsin.

These
States
are
subject
to
an
ozone
season
NOx
cap,

which
covers
the
5
months
of
May
through
September.
The
362
EPA
is
calculating
the
ozone
season
cap
level
for
the
25
States
plus
the
District
of
Columbia
region
by
multiplying
the
region's
ozone
season
heat
input
by
0.15
lb/
mmBtu
for
2009
and
0.125
lb/
mmBtu
for
2015.
Heat
input
for
the
region
was
estimated
by
looking
at
reported
ozone
season
Acid
Rain
heat
inputs
for
each
State
for
the
years
1999
through
2002,

and
selecting
the
single
year
highest
heat
input
for
each
State
as
a
whole.

As
is
the
case
for
the
annual
NOx
State
Budgets,
EPA
is
finalizing
an
approach
of
calculating
ozone
season
NOx
State
budgets
through
a
fuel­
adjusted
heat
input
basis.
State
budgets
would
be
determined
by
multiplying
State­
level
average
historic
ozone­
season
heat
input
data
(
summed
by
fuel)
by
different
adjustment
factors
for
the
different
fuels
(
1.0
for
coal,
0.4
for
gas,
and
0.6
for
oil).
The
total
ozone
season
State
budgets
are
then
determined
by
calculating
each
State's
share
of
total
fuel­
adjusted
heat
input,
and
multiplying
this
share
by
the
regionwide
budget.

The
budgets
for
these
States
in
2009
and
2015
are
included
in
Table
V­
4
below.

Table
V­
4.
Final
Seasonal
Electricity
Generating
Unit
NOx
Budgets
(
tons)

State
State
NOx
Budget
2009*
State
NOx
Budget
363
2015**
Alabama
32,182
26,818
Arkansas
11,515
9,596
Connecticut
2,559
2,559
Delaware
2,226
1,855
District
of
Columbia
112
94
Florida
47,912
39,926
Illinois
30,701
28,981
Indiana
45,952
39,273
Iowa
14,263
11,886
Kentucky
36,045
30,587
Louisiana
17,085
14,238
Maryland
12,834
10,695
Massachusetts
7,551
6,293
Michigan
28,971
24,142
Mississippi
8,714
7,262
Missouri
26,678
22,231
New
Jersey
6,654
5,545
New
York
20,632
17,193
North
Carolina
28,392
23,660
Ohio
45,664
39,945
Pennsylvania
42,171
35,143
South
Carolina
15,249
12,707
Tennessee
22,842
19,035
Virginia
15,994
13,328
West
Virginia
26,859
26,525
Wisconsin
17,987
14,989
Total
567,744
484,506
*
Seasonal
budget
for
NOx
tons
covered
by
allowances
for
2009­
2014.

For
States
that
have
lower
EGU
budgets
under
the
NOx
SIP
Call
than
their
2009
CAIR
budget,
table
V­
4
includes
their
SIP
Call
budget.
For
Connecticut,
the
NOx
SIP
Call
budget
is
also
used
for
2015
and
beyond.

**
Seasonal
budget
for
NOx
tons
covered
by
allowances
for
2015
and
thereafter.

VI.
Air
Quality
Modeling
Approach
and
Results
Overview
In
this
section
we
summarize
the
air
quality
modeling
approach
used
for
the
proposed
rule,
we
address
major
comments
on
the
fundamental
aspects
of
EPA's
proposed
364
approach,
and
we
describe
the
updated
and
improved
approach,

based
on
those
comments,
that
we
are
finalizing
today.
This
section
also
contains
the
results
of
EPA's
final
air
quality
modeling,
including:
(
1)
identifying
the
future
baseline
PM2.5
and
8­
hour
ozone
nonattainment
counties
in
the
East;

(
2)
quantifying
the
contribution
from
emissions
in
upwind
States
to
nonattainment
in
these
counties;
(
3)
quantifying
the
air
quality
impacts
of
the
CAIR
reductions
on
PM2.5
and
8­
hour
ozone;
and
(
4)
describing
the
impacts
on
visibility
in
Class
I
areas
of
implementing
CAIR
compared
to
implementing
the
regional
haze
requirement
for
best
available
retrofit
technology
(
BART).

We
present
the
air
quality
models,
model
configuration,

and
evaluation;
and
then
the
emissions
inventories
and
meteorological
data
used
as
inputs
to
the
air
quality
models.
Next,
we
provide
the
updated
interstate
contributions
for
PM2.5
and
8­
hour
ozone
and
those
States
that
make
a
significant
contribution
to
downwind
nonattainment,
before
considering
cost.
Finally,
we
present
the
estimated
impacts
of
the
CAIR
emissions
reductions
on
air
quality
and
visibility.
As
described
below,
our
air
quality
modeling
for
today's
rule
utilizes
the
Community
Multiscale
Air
Quality
(
CMAQ)
model
in
conjunction
with
2001
meteorological
data
for
simulating
PM2.5
concentrations
and
365
associated
visibility
effects
and
the
Comprehensive
Air
Quality
Model
with
Extensions
(
CAMx)
with
meteorological
data
for
three
episodes
in
1995
for
simulating
8­
hour
ozone
concentrations.
Our
approach
to
modeling
both
PM2.5
and
8­

hour
ozone
involves
applying
these
tools
(
i.
e.,
CMAQ
for
PM2.5
and
CAMx
for
8­
hour
ozone)
using
updated
emissions
inventory
data
for
2001,
2010,
and
2015
to
project
future
baseline
concentrations,
interstate
transport,
and
the
impacts
of
CAIR
on
projected
nonattainment
of
PM2.5
and
8­

hour
ozone.
We
provide
additional
information
on
the
development
of
our
updated
CAIR
air
quality
modeling
platform,
the
modeling
analysis
techniques,
model
evaluation,
and
results
for
PM2.5
and
8­
hour
ozone
modeling
in
the
CAIR
Notice
of
Final
Rulemaking
Emissions
Inventory
Technical
Support
Document
(
NFR
EITSD)
and
the
Air
Quality
Modeling
Technical
Support
Document
(
NFR
AQMTSD).

A.
What
Air
Quality
Modeling
Platform
Did
EPA
Use?

1.
Air
Quality
Models
a.
The
PM2.5
Air
Quality
Model
and
Evaluation
Overview
In
the
NPR,
we
used
the
Regional
Model
for
Simulating
Aerosols
and
Deposition
(
REMSAD)
as
the
tool
for
simulating
base
year
and
future
concentrations
of
PM2.5.
Like
most
photochemical
grid
models,
the
predictions
of
REMSAD
are
366
based
on
a
set
of
atmospheric
specie
mass
continuity
equations.
This
set
of
equations
represents
a
mass
balance
in
which
all
of
the
relevant
emissions,
transport,

diffusion,
chemical
reactions,
and
removal
processes
are
expressed
in
mathematical
terms.
The
modeling
domain
used
for
this
analysis
covers
the
entire
continental
United
States
and
adjacent
portions
of
Canada
and
Mexico.

The
EPA
applied
REMSAD
for
an
annual
simulation
using
meteorology
and
emissions
for
1996.
We
used
the
results
of
this
1996
Base
Year
model
run
to
evaluate
how
well
the
modeling
system
(
i.
e.,
the
air
quality
model
and
input
data
sets)
replicated
measured
data
over
the
time
period
and
domain
simulated.
We
performed
a
model
evaluation
for
PM2.5
and
speciated
components
(
e.
g.,
sulfate,
nitrate,
elemental
carbon,
organic
carbon,
etc.)
as
well
as
nitrate,
sulfate
and
ammonium
wet
deposition,
and
visibility.
The
evaluation
used
available
1996
ambient
measurements
paired
with
REMSAD
predictions
corresponding
to
the
location
and
time
periods
of
the
measured
data.
We
quantified
model
performance
using
various
statistical
and
graphical
techniques.
Additional
information
on
the
model
evaluation
procedures
and
results
are
included
in
the
Notice
of
Proposed
Rulemaking
Air
Quality
Modeling
Technical
Support
Document
(
NPR
AQMTSD).

The
EPA
received
numerous
comments
on
various
elements
of
the
proposed
PM2.5
air
quality
modeling
approach.
The
367
major
comments
are
responded
to
below.
Other
comments
are
addressed
the
Response
to
Comment
(
RTC)
document.
Regarding
REMSAD,
commenters
argued
that:
(
1)
the
REMSAD
model
is
an
inappropriate
tool
for
modeling
PM2.5;
(
2)
the
scientific
formulation
of
the
model
is
simplistic
and
outdated
and
that
other
models
with
better
science
are
available
and
should
be
used;
and
(
3)
results
from
REMSAD
are
directionally
correct
but
better
tools
should
be
used
as
the
basis
for
the
final
determinations
on
transport
and
projected
nonattainment.

We
agree
that
models
with
more
refined
science
are
available
for
PM2.5
modeling
and
we
have
selected
one
of
these
models,
the
CMAQ
as
the
tool
for
PM2.5
modeling
for
the
final
CAIR.
The
CMAQ
model
is
a
publicly
available,

peer­
reviewed,
state­
of­
the­
science
model
with
a
number
of
science
attributes
that
are
critical
for
accurately
simulating
the
oxidant
precursors
and
non­
linear
organic
and
inorganic
chemical
relationships
associated
with
the
formation
of
sulfate,
nitrate,
and
organic
aerosols.

Several
of
the
important
science
aspects
of
CMAQ
that
are
superior
to
REMSAD
include:
(
1)
updated
gaseous/
heterogeneous
chemistry
that
provides
the
basis
for
the
formation
of
nitrates
and
includes
a
current
inorganic
nitrate
partitioning
module;
(
2)
in­
cloud
sulfate
chemistry,

which
accounts
for
the
non­
linear
sensitivity
of
sulfate
formation
to
varying
pH;
(
3)
a
state­
of­
the­
science
368
secondary
organic
aerosol
module
that
includes
a
more
comprehensive
gas­
particle
partitioning
algorithm
from
both
anthropogenic
and
biogenic
secondary
organic
aerosol;
and
(
4)
the
full
CB­
IV
chemistry
mechanism,
which
provides
a
complete
simulation
of
aerosol
precursor
oxidants.

However,
even
though
REMSAD
does
not
have
all
the
scientific
refinements
of
CMAQ,
we
believe
that
REMSAD
treats
the
key
physical
and
chemical
processes
associated
with
secondary
aerosol
formation
and
transport.
Thus,
we
believe
that
the
conclusions
based
on
the
proposal
modeling
using
REMSAD
are
valid
and
therefore
support
today's
findings
based
only
on
CMAQ
that:
(
1)
there
will
be
widespread
PM2.5
nonattainment
in
the
eastern
U.
S.
in
2010
and
2015
absent
the
reductions
from
CAIR;
(
2)
upwind
States
in
the
eastern
part
of
the
United
States
contribute
to
the
PM2.5
nonattainment
problems
in
other
downwind
States;
(
3)

States
with
high
emissions
tend
to
contribute
more
than
States
with
low
emissions;
(
4)
States
close
to
nonattainment
areas
tend
to
contribute
more
than
other
States
farther
upwind;
and
(
5)
the
CAIR
controls
will
produce
major
benefits
in
terms
of
bringing
areas
into
or
closer
to
attainment.

Comments
and
Responses
(
i)
REMSAD
Science
and
Evaluation
369
90
Even
so,
EPA
acknowledges
that
REMSAD
has
certain
limitations
not
found
in
CMAQ.
Comment:
Some
commenters
stated
that
REMSAD
is
an
inappropriate
model
for
use
in
simulating
PM2.5.
Other
commenters
said,
more
specifically,
that
the
chemical
mechanism
in
REMSAD
(
i.
e.,
micro
CB­
IV)
is
simplified
and
not
validated,
and
that
the
model
has
not
been
scientifically
peer­
reviewed.

Response:
The
EPA
disagrees
with
comments
claiming
that
REMSAD
is
an
inappropriate
tool
for
modeling
PM2.5.
The
EPA
believes
that
REMSAD
is
appropriate
for
regional
and
national
modeling
applications
because
the
model
does
include
the
key
physical
and
chemical
processes
associated
with
secondary
aerosol
formation
and
transport.
90
Specifically,
REMSAD
simulates
both
gas
phase
and
aerosol
chemistry.
The
gas
phase
chemistry
uses
a
reducedform
version
of
Carbon
Bond
chemical
mechanism
(
micro­

CBIV
Formation
of
inorganic
secondary
particulate
species,

such
as
sulfate
and
nitrate,
are
simulated
through
chemical
reactions
within
the
model.
Aerosol
sulfate
is
formed
in
both
the
gas
phase
and
the
aqueous
phase.
The
REMSAD
model
also
accounts
for
the
production
of
secondary
organic
aerosols
through
chemistry
processes
involving
volatile
organic
compounds
(
VOC)
and
directly
emitted
organic
370
91
Whitten,
G.
memorandum:
Comparison
of
REMSAD
Reduced
Chemistry
to
Full
CB­
4.
February
19,
2001.
particles.
Emissions
of
non­
reactive
particles
(
e.
g.,

elemental
carbon)
are
treated
as
inert
species
which
are
advected
and
deposited
during
the
simulation.

With
regard
to
comments
on
the
micro
CB­
IV
chemical
mechanism,
although
this
mechanism
treats
fewer
organic
carbon
species
compared
to
the
full
CB­
IV,
the
inorganic
portion
of
the
reduced
mechanism
is
identical
to
the
full
chemical
mechanism.
The
intent
of
the
CB­
IV
mechanism
is
to:
(
a)
provide
a
faithful
representation
of
the
linkages
between
emissions
of
ozone
precursor
species
and
secondary
aerosol
precursor
species;
(
b)
treat
the
oxidizing
capacity
of
the
troposphere,
represented
primarily
by
the
concentrations
of
radicals
and
hydrogen
peroxide;
and
(
c)

simulate
the
rate
of
oxidation
of
the
nitrogen
oxide
(
NOx)

and
sulfur
dioxide
(
SO2),
which
are
precursors
to
secondary
aerosols.
The
EPA
agrees
that
micro
CB­
IV
is
simplified
compared
to
the
full
CB­
IV
mechanism.
However,
performance
testing
of
micro
CB­
IV
indicates
that
this
simplified
mechanism
is
similar
to
the
full
CB­
IV
chemical
mechanism
in
simulating
ozone
formation
and
approximates
other
species
reasonably
well
(
e.
g.,
hydroxyl
radical,
hydroperoxy
radical,
the
operator
radical,
hydrogen
peroxide,
nitric
acid,
and
peroxyacetyl
nitrate).
91
371
The
REMSAD
model
was
subjected
to
a
scientific
peerreview
(
Seigneur
et
al.,
1999)
and
EPA
has
incorporated
the
major
science
improvements
that
were
recommended
by
the
peer­
review
panel.
These
improvements
were
included
in
the
version
of
REMSAD
used
for
the
NPR
modeling.
Specifically,

the
following
updates
have
been
implemented
into
REMSAD
Version
7.06,
which
was
used
for
the
proposed
CAIR
control
strategy
simulations:
(
1)
the
nighttime
chemistry
treatment
was
updated
to
improve
the
treatment
of
the
gas
phase
species
NO3
and
N2O5;
(
2)
the
effects
of
temperature
and
pressure
dependence
on
chemical
rates
were
added;
(
3)
the
MARS­
A
aerosol
partitioning
module
was
added
for
calculating
particle
and
gas
phase
fractions
of
nitrate;
(
4)
aqueous
phase
formation
of
sulfate
was
updated
by
including
reactions
for
oxidation
of
SO2
by
ozone
and
oxygen,
(
5)

peroxynitric
acid
(
PNA)
chemistry
was
added;
and
(
6)
a
module
for
calculating
biogenic
and
anthropogenic
secondary
organic
aerosols
was
developed
and
integrated
into
REMSAD.

We
believe
that
these
changes
adequately
respond
to
the
peer
review
comments
and
have
bolstered
the
scientific
credibility
of
this
model.

(
ii)
Use
of
CMAQ
Instead
of
REMSAD
for
PM2.5
Modeling
Comment:
Some
commenters
claimed
that
REMSAD
is
outdated
and
that
other
models
with
more
sophisticated
science
are
372
available.
Commenters
said
that
EPA
should
utilize
the
best
available
science
through
use
of
the
most
comprehensive
photochemical
model
for
simulating
aerosols.
Commenters
specifically
stated
that
EPA
should
use
more
recently
developed
models
such
as
the
CMAQ
model
or
the
aerosol
version
of
the
Comprehensive
Air
Quality
Model
with
Extensions
(
CAMx­
PM).

Response:
The
EPA
agrees
that
photochemical
models
are
now
available
that
are
more
scientifically
sophisticated
than
REMSAD.
In
this
regard,
and
in
response
to
commenters'

recommendations
on
specific
models,
EPA
has
selected
CMAQ
as
the
modeling
tool
for
the
final
CAIR
modeling
analysis.
As
stated
above,
the
CMAQ
model
is
a
publicaly
available,

peerreviewed
state­
of­
the­
science
model
with
a
number
of
science
attributes
that
are
critical
for
accurately
simulating
the
oxidant
precursors
and
non­
linear
organic
and
inorganic
chemical
relationships
associated
with
the
formation
of
sulfate,
nitrate,
and
organic
aerosols.
As
listed
above,
the
important
science
aspects
of
CMAQ
that
are
superior
to
REMSAD
include:
(
1)
updated
gaseous/
heterogeneous
chemistry
that
provides
the
basis
for
the
formation
of
nitrates
and
includes
a
current
inorganic
nitrate
partitioning
module;
(
2)
in­
cloud
sulfate
chemistry,

which
accounts
for
the
non­
linear
sensitivity
of
sulfate
373
formation
to
varying
pH;
(
3)
a
state­
of­
the­
science
secondary
organic
aerosol
module
that
includes
a
more
comprehensive
gas­
particle
partitioning
algorithm
from
both
anthropogenic
and
biogenic
secondary
organic
aerosol;
and
(
4)
the
full
CB­
IV
chemistry
mechanism,
which
provides
a
complete
simulation
of
aerosol
precursor
oxidants.

(
iii)
Model
Evaluation
Comment:
A
number
of
commenters
claimed
that
EPA's
air
quality
model
evaluation
for
1996
was
deficient
because
it
lacked
sufficient
ambient
measurements,
especially
in
urban
areas,
to
judge
model
performance.
Commenters
said
that
EPA
should:
(
1)
update
the
evaluation
to
a
more
recent
time
period
in
order
to
take
advantage
of
greatly
expanded
ambient
PM2.5
species
measurements,
especially
in
urban
areas;
and
(
2)
calculate
model
performance
statistics
over
monthly
and/
or
seasonal
time
periods
using
daily/
weekly
observed/
model­
predicted
data
pairs.

Some
commenters
said
that
the
1996
data
were
so
limited
that
it
is
not
possible
to
determine
whether
REMSAD
could
be
used
with
confidence
to
assess
the
effects
of
emissions
changes.
Still,
other
commenters
said
that
the
performance
of
REMSAD
for
the
1996
modeling
platform
was
poor.

Commenters
acknowledged
that
there
are
no
universally
accepted
or
EPA­
recommended
quantitative
criteria
for
374
judging
the
acceptability
of
PM2.5
model
performance.
In
the
absence
of
such
model
performance
acceptance
criteria,

some
commenters
said
that
performance
should
be
judged
by
comparing
EPA's
model
performance
results
to
the
range
of
results
obtained
by
other
groups
in
the
air
quality
modeling
community
who
conducted
other
recent
regional
PM2.5
model
applications.
A
few
commenters
also
identified
specific
model
performance
ranges
and
criteria
that
they
said
should
be
achievable
for
sulfate
and
PM2.5,
given
the
current
state­
of­
science
for
aerosol
modeling
and
measurement
uncertainty.
The
specific
values
cited
by
these
commenters
are
±
30
percent
to
±
50
percent
for
fractional
bias,
50
percent
to
75
percent
for
fractional
error,
and
50
percent
for
normalized
error.

Response:
The
EPA
agrees
that
the
limited
amount
of
ambient
PM2.5
species
data
available
in
1996
affected
our
ability
to
evaluate
model
performance,
especially
in
urban
areas,
and
there
were
deficiencies
in
the
performance
of
REMSAD
using
the
1996
model
inputs.
Also,
EPA
agrees
that
a
model
evaluation
should
be
performed
for
a
more
recent
time
period
in
order
to
address
these
concerns.
Thus,
we
conclude
that
the
1996
modeling
platform
which
includes
1996
emissions,

1996
meteorology,
and
1996
ambient
data
should
be
updated
and
improved,
as
recommended
by
commenters.
375
92
The
2001
modeling
platform
is
described
in
full
in
the
NFR
EITSD
and
NFR
AQMTSD.
The
EPA
has
developed
a
new
modeling
platform
which
includes
emissions,
meteorological
data,
and
other
model
inputs
for
2001.
This
platform
was
used
to
confirm
the
ability
of
our
modeling
system
to
replicate
ambient
PM2.5
and
component
species
in
both
urban
and
rural
areas
and,

thus,
establish
the
credibility
of
this
platform
for
PM2.5
modeling
as
part
of
CAIR.
92
In
2001,
there
was
an
extensive
set
of
ambient
PM2.5
measurements
including
133
urban
Speciation
Trends
Network
(
STN)
monitoring
sites
across
the
nation,
with
105
of
these
in
the
East.
This
network
did
not
exist
in
1996.
Also,
the
number
of
mainly
suburban
and
rural
monitoring
sites
in
the
Clean
Air
Status
and
Trends
Network
(
CASTNET)
and
Interagency
Monitoring
of
Protected
Visual
Environments
(
IMPROVE)
network
has
increased
to
over
200
in
2001,
compared
to
approximately
120
operating
in
1996.

The
EPA
evaluated
CMAQ
for
the
2001
modeling
platform
using
the
extensive
set
of
2001
monitoring
data
for
PM2.5
species.
The
evaluation
included
a
statistical
analysis
in
which
the
model
predictions
and
measurements
were
paired
in
space
and
in
time
(
i.
e.,
daily
or
weekly
to
be
consistent
with
the
sampling
protocol
of
the
monitoring
network).

Model
performance
statistics
were
calculated
for
each
376
93
For
the
purposes
of
this
analysis,
we
have
defined
"
East"
as
the
area
to
the
east
of
100
degrees
longitude,
which
runs
from
approximately
the
eastern
half
of
Texas
through
the
eastern
half
of
North
Dakota.
network
with
separate
statistics
for
sites
in
the
West
and
the
East.
93
In
response
to
comments
that
performance
statistics
should
be
calculated
over
monthly
and/
or
seasonal
time
periods,
we
elected
to
use
seasonal
time
periods
in
order
to
be
consistent
with
our
use
of
quarterly
average
PM2.5
species
as
part
of
the
procedure
for
projecting
future
concentrations,
as
described
below
in
section
VI.
B.
1.
In
addition,
the
sampling
frequency
at
the
CASTNET,
IMPROVE,

and
STN
sites
may
not
provide
sufficient
samples
in
a
1­

month
period
to
provide
a
robust
calculation
of
model
performance
statistics.
Details
of
EPA's
model
evaluation
for
CMAQ
using
the
2001
modeling
platform
are
in
the
report
"
Updated
CMAQ
Model
Performance
Evaluation
for
2001"
which
can
be
found
in
the
docket
for
today's
rule.

The
EPA
agrees
that
there
are
no
universally
accepted
performance
criteria
for
PM2.5
modeling
and
that
performance
should
be
judged
by
comparison
to
the
performance
found
by
other
groups
in
the
air
quality
modeling
community.
In
this
respect,
we
have
compared
our
CMAQ
2001
model
performance
results
to
the
range
of
performance
found
in
other
recent
377
94
These
other
modeling
studies
represent
a
wide
range
of
modeling
analyses
which
cover
various
models,
model
configurations,
domains,
years
and/
or
episodes,
chemical
mechanisms,
and
aerosol
modules.
regional
PM2.5
model
applications
by
other
groups.
94
Details
of
this
comparison
can
be
found
in
the
CMAQ
evaluation
report.
Below
is
a
summary
of
performance
results
from
other,
non­
EPA
modeling
studies,
for
summer
sulfate
and
winter
nitrate.
It
should
be
noted
that
nitrate
and
sulfate
are
the
two
species
most
relevant
for
CAIR.

Overall,
the
general
range
of
fractional
bias
(
FB)
and
fractional
error
(
FE)
statistics
for
the
better
performing
model
applications
are
as
follows:

­
summer
sulfate
is
in
the
range
of
­
10
percent
to
+
30
percent
for
FB
and
35
percent
to
50
percent
for
FE;
and
­
winter
nitrate
is
in
the
range
of
+
50
percent
to
+
70
percent
for
FB
and
85
percent
to
105
percent
for
FE.

The
corresponding
performance
statistics
for
EPA's
2001
CMAQ
application
as
well
as
the
1996
REMSAD
application
used
for
the
proposal
modeling
are
provided
in
Table
VI­
1.

Table
VI­
1.
Selected
Performance
Evaluation
Statistics
from
the
CMAQ
2001
Simulation
and
the
REMSAD
1996
Simulation.

Eastern
U.
S.
CMAQ
2001
REMSAD
1996
FB
(%)
FE
(%)
FB
(%)
FE
(%)

Sulfate
(
Summer)
STN
14
44
­
­

IMPROVE
10
42
­
20
51
378
CASTNet
3
22
­
21
59
Nitrate
(
Winter)
STN
15
73
­
­

IMPROVE
21
92
67
103
The
results
indicate
that
the
performance
for
CMAQ
in
2001
is
within
the
range
or
better
than
that
found
by
other
groups
in
recent
applications.
The
performance
also
meets
the
benchmark
goals
suggested
by
several
commenters.
In
addition,
the
CMAQ
performance
is
considerably
improved
over
that
of
the
REMSAD
1996
performance
for
summer
sulfate
and
winter
nitrate,
which
were
near
the
bounds
or
outside
the
range
of
other
recent
applications.

The
CMAQ
model
performance
results
give
us
confidence
that
our
applications
of
CMAQ
using
the
new
modeling
platform
provide
a
scientifically
credible
approach
for
assessing
PM2.5
concentrations
for
the
purposes
of
CAIR.

b.
Ozone
Air
Quality
Modeling
Platform
and
Model
Evaluation
Overview
The
EPA
used
the
CAMx,
version
3.10
in
the
NPR
to
assess
8­
hour
ozone
concentrations
and
the
impacts
of
ozone
and
ozone
precursor
transport
on
elevated
levels
of
ozone
across
the
eastern
U.
S.
The
CAMx
is
a
publicly
available
Eulerian
model
that
accounts
for
the
processes
that
are
involved
in
the
production,
transport,
and
destruction
of
ozone
over
a
specified
three­
dimensional
domain
and
time
period.
The
CAMx
model
was
run
with
1995/
96
base
year
379
emissions
to
evaluate
the
performance
of
the
modeling
platform
to
replicate
observed
concentrations
during
the
three
1995
episodes.
This
evaluation
was
comprised
principally
of
statistical
assessments
of
hourly,
1­
hour
daily
maximum,
and
8­
hour
daily
maximum
ozone
predictions.

As
described
in
the
NPR
AQMTSD,
model
performance
of
CAMx
for
ozone
was
judged
against
the
results
from
previous
regional
ozone
model
applications.
This
analysis
indicates
that
model
performance
was
comparable
to
or
better
than
that
found
in
previous
applications
and
is,
therefore,
acceptable
for
the
purposes
of
CAIR
ozone
modeling.

The
EPA
did
not
receive
comments
on
the
CAMx
model
or
the
model
performance
for
ozone.
The
EPA
did
receive
comments
on
the
choice
of
episodes
for
ozone
modeling,
the
meteorological
data
for
these
episodes,
the
spatial
resolution
of
our
modeling,
and
consistency
between
ozone
and
PM2.5
modeling
in
terms
of
methods
for
projecting
future
air
quality
concentrations.
As
described
below
and
in
the
RTC
document
and
NFR
AQMTSD,
we
continue
to
believe
that:

(
1)
the
three
1995
episodes
are
representative
episodes
for
regional
modeling
of
8­
hour
ozone;
and
(
2)
the
meteorological
data
for
these
episodes
and
spatial
resolution
are
adequate
for
use
in
our
modeling
for
CAIR.

Thus,
the
ozone
air
quality
assessments
in
today's
rule
rely
on
CAMx
modeling
of
meteorological
data
for
the
three
1995
380
episodes
for
the
domain
and
spatial
resolution
used
for
the
NPR.
As
discussed
below,
we
ran
CAMx
for
the
updated
2001
emissions
inventory
and
the
updated
2010
and
2015
Base
Case
inventories
as
part
of
the
process
to
project
8­
hour
ozone
for
these
future
year
scenarios.
We
revised
our
method
of
projecting
future
ozone
concentrations
to
be
consistent
with
the
method
we
are
using
for
PM2.5.

c.
Model
Grid
Cell
Configuration
As
described
in
the
NPR
AQMTSD,
the
PM2.5
modeling
for
the
proposal
was
performed
for
a
domain
(
i.
e.,
area)

covering
the
48
States
and
adjacent
portions
of
Canada
and
Mexico.
Within
this
domain,
the
model
predictions
were
calculated
for
a
grid
network
with
a
spatial
resolution
of
approximately
36
km.
Our
8­
hour
ozone
modeling
for
proposal
was
performed
using
a
nested
grid
network.
The
outer
portion
of
this
grid
has
a
spatial
resolution
of
approximately
36
km.
The
inner
"
nested"
area,
which
covers
a
large
portion
of
the
eastern
U.
S.,
has
a
resolution
of
approximately
12
km.

Comment:
Some
commenters
said
that
the
36
km
grid
cell
size
used
by
EPA
in
modeling
PM2.5
and
the
36
km/
12
km
grid
resolution
used
for
ozone
modeling
are
too
coarse
and
are
inconsistent
with
EPA's
draft
modeling
guidance.
381
95
U.
S.
EPA,
2000:
Draft
Guidance
for
Demonstrating
Attainment
of
the
Air
Quality
Goals
for
PM2.5
and
Regional
Haze;
Draft
1.1,
Office
of
Air
Quality
Planning
and
Standards,
Research
Triangle
Park,
NC.

96
U.
S.
EPA,
1999:
Draft
Guidance
on
the
Use
of
Models
and
Other
Analyses
in
Attainment
Demonstrations
for
the
8­
Hour
Ozone
NAAQS,
Office
of
Air
Quality
Planning
and
Standards,
Research
Triangle
Park,
NC.
Response:
We
disagree
with
these
comments
and
continue
to
believe
that
the
grid
dimensions
for
our
PM2.5
modeling
and
our
8­
hour
ozone
modeling
are
not
too
coarse
nor
are
they
inconsistent
with
our
draft
guidance
documents
for
PM2.5
modeling95
and
ozone
modeling.
96
The
draft
guidance
for
PM2.5
modeling
states
that
36
km
resolution
is
acceptable
for
regional
scale
applications
in
portions
of
the
domain
outside
of
nonattainment
areas.
For
portions
of
the
domain
which
cover
nonattainment
areas,
12
km
resolution
or
less
is
recommended
by
the
guidance.
However,
as
stated
in
the
guidance
document,
these
recommendations
were
based
on
guidance
for
8­
hour
ozone
modeling
because
there
was
a
lack
of
PM2.5
modeling
at
different
grid
resolutions
at
the
time
the
guidance
was
drafted.
In
addition,
the
PM2.5
guidance
states
that
exceptions
to
these
recommendations
can
be
made
on
a
case­
by­
case
basis.

For
several
reasons,
we
believe
that
36
km
resolution
is
sufficient
for
PM2.5
modeling
for
the
purposes
of
CAIR.

First,
recent
analyses
that
compare
36
km
to
12
km
modeling
382
97
VISTAS
Emissions
and
Air
Quality
Modeling­
Phase
I
Task
4cd
Report:
Model
Performance
Evaluation
and
Model
Sensitivity
Tests
for
Three
Phase
I
Episodes.
ENVIRON
International
Corporation,
Alpine
Geophysics,
and
University
of
California
at
Riverside,
September
7,
2004.
of
PM2.597
indicate
that
spatial
mean
concentrations
of
gas
phase
and
aerosol
species
at
36
km
and
12
km
are
quite
similar.
A
comparison
of
model
predictions
versus
observations
indicates
that
the
model
performance
is
similar
at
12
km
and
36
km
in
both
rural
and
urban
areas.
Thus,

using
12
km
resolution
does
not
necessarily
provide
any
additional
confidence
in
the
results.
Second,
ambient
measurements
of
sulfate
and
to
a
significant
extent
nitrate,

which
are
the
pollutants
of
most
importance
for
CAIR,
do
not
exhibit
large
spatial
differences
between
rural
and
urban
areas,
as
described
elsewhere
in
today's
rule.
This
implies
that
it
is
not
necessary
to
use
fine
resolution
modeling
in
order
to
properly
capture
the
regional
concentration
patterns
of
these
pollutants.

Our
draft
8­
hour
ozone
modeling
guidance
recommends
using
36
km
resolution
for
regional
modeling
with
nested
grid
cells
not
exceeding
12
km
over
urban
portions
of
the
modeling
domain.
The
guidance
states
that
4
to
5
km
resolution
for
urban
areas
is
preferred,
if
feasible.
In
addition,
if
12
km
modeling
is
used
then
plume­
in­
grid
383
98
Irwin,
J.
et.
al.
"
Examination
of
model
predictions
at
different
horizontal
grid
resolutions."
Submitted
for
Publication
to
Environmental
Fluid
Mechanics.
treatment
for
large
point
sources
of
NOx
should
be
considered.

Our
modeling
for
CAIR
is
consistent
with
this
guidance
in
that
we
use
36
km
resolution
for
the
outer
portions
of
the
region;
12
km
resolution
covering
nearly
all
urban
areas
in
the
domain;
and
a
plume­
in­
grid
algorithm
for
major
NOx
point
sources
in
the
region.
In
addition,
analyses
that
compare
model
12
km
resolution
to
4
km
resolution
for
portions
of
our
1995
episodes
indicate
that
the
spatial
fields
predicted
at
both
12
km
and
4
km
have
many
common
features
in
terms
of
the
areas
of
high
and
low
ozone.
98
In
a
comparison
of
model
predictions
to
observation,
the
12
km
modeling
was
found
to
be
somewhat
more
accurate
than
the
finer
4
km
modeling.

2.
Emissions
Inventory
Data
For
the
proposed
rule,
emissions
inventories
were
created
for
the
48
contiguous
States
and
the
District
of
Columbia.
These
inventories
were
estimated
for
a
2001
base
year
to
reflect
current
emissions
and
for
2010
and
2015
future
baseline
scenarios.
The
inventories
were
prepared
for
electric
generating
units
(
EGUs),
industrial
and
commercial
sources
(
non­
EGUs),
stationary
area
sources,
384
on­
road
vehicles,
and
non­
road
engines.
The
inventories
contained
both
annual
and
typical
summer
season
day
emissions
for
the
following
pollutants:
oxides
of
nitrogen
(
NOx);
volatile
organic
compounds
(
VOC);
carbon
monoxide
(
CO);
sulfur
dioxide
(
SO2);
direct
particulate
matter
with
an
aerodynamic
diameter
less
than
10
micrometers
(
PM10)
and
less
than
2.5
micrometers
(
PM2.5);
and
ammonia
(
NH3).
A
summary
of
the
development
of
these
inventories
is
provided
below.
Additional
information
on
the
emissions
inventory
used
for
proposal
can
be
found
in
the
NPR
AQMTSD.

Because
the
complete
2001
National
Emission
Inventory
(
NEI)
and
future­
year
projections
consistent
with
that
NEI
were
not
available
in
a
form
suitable
for
air
quality
modeling
when
needed
for
the
proposal,
we
developed
a
reasonably
representative
"
proxy"
inventory
for
2001.
For
the
EGU,
mobile,
and
non­
road
emissions
sectors,
1996­
to­

2001
adjustment
ratios
were
created
by
dividing
State­
level
total
emissions
for
each
pollutant
for
2001
by
the
corresponding
consistent
1996
emissions.
These
adjustment
ratios
were
then
multiplied
by
the
REMSAD­
ready
1996
emissions
for
these
two
sectors
to
produce
REMSAD­
ready
files
for
the
2001
proxy.
For
non­
EGUs
and
stationary
area
sources,
linear
interpolations
were
performed
between
the
REMSAD­
ready
1996
emissions
and
the
REMSAD­
ready
2010
Base
385
Case
emissions
to
produce
2001
proxy
emissions
for
these
two
sectors.
Details
on
the
creation
of
the
2001
proxy
inventory
used
for
proposal
are
provided
in
the
NPR
AQMTSD.

The
NPR
future
2010
and
2015
base
case
emissions
reflect
projected
economic
growth
and
control
programs
that
are
to
be
implemented
by
2010
and
2015,
respectively.

Control
programs
included
in
these
future
base
cases
include
those
State,
local,
and
Federal
measures
already
promulgated
and
other
significant
measures
expected
to
be
promulgated
before
the
final
rule
is
implemented.
Future
year
2010
and
2015
Base
Case
EGU
emissions
were
obtained
from
versions
2.1
and
2.1.6
of
the
Integrated
Planning
Model
(
IPM).

Comment:
Several
commenters
stated
that
the
emission
inventory
used
for
the
"
proxy"
2001
base
year
was
not
sufficient
for
the
rulemaking,
primarily
because
it
was
developed
from
a
1996
modeling
inventory
by
applying
various
adjustment
factors.
Commenters
suggested
that:
(
1)
more
upto
date
inventories
were
now
available
and
should
be
used;

(
2)
the
most
recent
Continuous
Emissions
Monitoring
(
CEM)

data
or
throughput
information
should
be
used
to
derive
a
2001
EGU
inventory;
and
(
3)
EPA
should
use
the
2001
MOBILE6
and
NONROAD2002
models
for
estimating
on­
road
mobile
and
non­
road
engine
emissions,
respectively.
386
Response:
The
EPA
believes
that
the
base
year
for
modeling
should
be
as
recent
as
possible,
given
the
availability
of
nationally
complete
emissions
estimates
and
ambient
monitoring
data.
For
the
analyses
of
the
final
rule,
EPA
has
used
a
base
year
inventory
developed
specifically
for
2001.
The
base
year
inventory
for
the
electric
utility
sector
now
uses
measured
CEM
emissions
data
for
2001.
The
non­
EGU
point
source
and
stationary­
area
source
sectors
are
based
on
the
final
1999
NEI
data
submittals
from
State,

local,
and
Tribal
air
agencies.
This
inventory
is
the
latest
available
quality­
assured
and
reviewed
national
emission
data
set
for
these
sectors.
The
1999
data
for
non­

EGU
point
and
stationary­
area
sources
were
projected
to
represent
a
2001
inventory
using
State/
county­
specific
and
sector­
specific
growth
rates.
The
on­
road
mobile
inventory
uses
MOBILE
version
6.2
and
the
non­
road
engines
inventory
uses
the
NONROAD2004
model,
both
with
updated
input
parameters
to
calculate
emissions
for
2001.
More
detailed
information
on
the
development
of
the
emissions
inventories
can
be
found
in
the
NFR
EITSD.

Comment:
Commenters
stated
that
EPA
failed
to
develop
an
accurate
and
comprehensive
ammonia
emission
inventory
from
soil,
fertilizer,
and
animal
husbandry
sources.
387
Response:
The
2001
inventory
used
for
the
analyses
for
the
final
rule
includes
a
new
national
county­
level
ammonia
inventory
developed
by
EPA
using
the
latest
emission
rates
selected
based
on
a
comprehensive
literature
review,
and
activity
levels
as
provided
by
the
U.
S.
Census
of
Agriculture
for
animal
husbandry.
The
2001
inventory
from
fertilizer
application
sources
was
compiled
from
State
and
local
submissions
to
EPA
for
1999,
augmented
as
necessary
with
EPA
estimates,
and
grown
to
2001
using
State/

countyspecific
and
category­
specific
growth
rates.
With
regard
to
background
soil
emissions
of
NH3,
EPA
believes
that
the
current
state
of
understanding
of
background
soil
ammonia
releases
and
sinks
is
insufficient
to
warrant
including
these
emission
sources
in
modeling
inventories
at
this
time.

Comment:
Two
commenters
indicated
that
EPA
should
revise
2010
and
2015
base
case
emissions
by
improving
the
methods
for
estimating
economic
growth
and
not
rely
on
the
Bureau
of
Economic
Analysis
(
BEA)
data
used
for
proposal.

Response:
In
response
to
these
comments,
EPA
has
refined
its
economic
growth
projections.
In
addition
to
updated
versions
of
the
MOBILE6,
NONROAD,
and
IPM
models,
EPA
developed
new
economic
growth
rates
for
stationary,
area,

and
non­
EGU
point
sources.
For
these
two
sectors,
the
final
approach
uses
a
combination
of:
(
1)
regional
or
national
388
fuel­
use
forecast
data
from
the
U.
S.
Department
of
Energy
for
source
types
that
map
to
fuel
use
sectors
(
e.
g.,

commercial
coal,
industrial
natural
gas);
(
2)
State­
specific
growth
rates
from
the
Regional
Economic
Model,
Inc.
(
REMI)

Policy
Insight
®
model,
version
5.5;
and
(
3)
forecasts
by
specific
industry
organizations
and
Federal
agencies.
For
more
detail
on
the
growth
methodologies,
please
refer
to
the
NFR
EITSD.

3.
Meteorological
Data
In
order
to
solve
for
the
change
in
pollutant
concentrations
over
time
and
space,
the
air
quality
model
requires
certain
meteorological
inputs
that,
in
part,
govern
the
formation,
transport,
and
destruction
of
pollutant
material.
Two
separate
sets
of
meteorological
inputs
were
used
in
the
air
quality
modeling
completed
as
part
of
the
NPR.
The
meteorological
input
files
for
the
proposal
PM2.5
modeling
were
developed
from
a
Fifth­
Generation
NCAR
/

Pennsylvania
State
Mesoscale
Model
(
MM5)
model
simulation
for
the
entire
year
of
1996.
The
gridded
meteorological
data
for
the
three
1995
ozone
episodes
were
developed
using
the
Regional
Atmospheric
Modeling
System
(
RAMS).
Both
of
these
models
are
publicly­
available,
widely­
used,
prognostic
meteorological
models
that
solve
the
full
set
of
physical
and
thermodynamic
equations
which
govern
atmospheric
389
motions.
Further,
each
of
these
specific
meteorological
data
sets
has
been
utilized
in
past
EPA
rulemaking
modeling
analyses
(
e.
g.,
the
Nonroad
Land­
based
Diesel
Engines
Standards).

Comment:
Several
commenters
claimed
that
the
1996
meteorological
modeling
data
used
to
support
the
fine
particulate
modeling
were
outdated
and
non­
representative.

We
also
received
recommendations
from
commenters
on
benchmarks
to
be
used
as
goals
for
judging
the
adequacy
of
meteorological
modeling.

Response:
The
EPA
draft
PM2.5
modeling
guidance
which
provides
general
recommendations
on
meteorological
periods
to
model
for
PM2.5
purposes
lists
three
primary
general
criteria
for
consideration:
a)
variety
of
meteorological
conditions;
b)
existence
of
an
extensive
air
quality/
meteorological
data
bases;
and
c)
sufficient
number
of
days.
The
approach
recommended
in
the
guidance
for
modeling
annual
PM2.5
is
to
use
a
single,
representative
year.
Based
on
the
comments
received
and
the
criteria
outlined
in
the
guidance,
EPA
developed
meteorological
data
for
the
entire
calendar
year
of
2001.
This
year
was
chosen
for
the
PM2.5
modeling
platform
based
on
several
factors,

specifically:
(
1)
it
corresponds
to
the
most
recent
set
of
emissions
data;
(
2)
there
are
considerable
ambient
PM2.5
390
99
Environ,
Enhanced
Meteorological
Modeling
and
Performance
Evaluation
for
Two
Texas
Ozone
Episodes.
August
2001.
species
data
for
use
in
model
evaluation
(
as
described
in
section
VI.
A.
1.,
above);
and
(
3)
Federal
Reference
Method
(
FRM)
PM2.5
data
for
this
year
are
included
in
the
calculation
of
the
most
recent
PM2.5
design
values
used
for
designating
PM2.5
nonattainment
areas.
In
view
of
these
factors,
EPA
believes
that
2001
meteorology
are
representative
for
PM2.5
modeling
for
the
purposes
of
this
rule.

The
new
2001
meteorological
data
used
for
PM2.5
modeling
were
derived
from
an
updated
version
of
the
MM5
model
used
for
the
1996
meteorology
used
for
proposal.
The
version
of
MM5
used
for
the
2001
simulation
contains
more
sophisticated
physics
options
with
respect
to
features
like
cloud
microphysics
and
land­
surface
interactions,
and
more
refined
vertical
resolution
of
the
atmosphere
compared
to
the
version
used
for
modeling
1996
meteorology.
While
there
are
currently
no
universally
accepted
criteria
for
judging
the
adequacy
of
meteorological
model
performance,
EPA
compared
the
2001
MM5
model
performance
against
the
benchmark
goals99
recommended
by
some
commenters.
The
benchmark
goals
suggest
that
temperature
bias
should
be
391
within
the
range
of
approximately
+
0.5
degrees
C
and
errors
less
than
or
equal
to
2.0
degrees
C
are
typical.

In
general,
the
model
performance
statistics
for
our
2001
meteorological
modeling
are
in
line
with
the
above
benchmark
goals.
Specfically,
the
mean
temperature
bias
of
our
2001
meteorological
modeling
was
approximately
0.6
degrees
C
and
the
mean
error
was
approximately
2.0
degrees
C.
The
evaluation
of
the
2001
MM5
for
humidity
(
water
vapor
mixing
ratio)
shows
biases
of
less
than
0.5
g/
kg
and
errors
of
approximately
1
g/
kg,
which
compare
favorably
to
the
goals
of
+
1
g/
kg
for
bias
and
2
g/
kg
or
less
error.
Model
performance
for
winds
in
our
2001
simulation
was
also
improved
compared
to
what
has
historically
been
found
in
MM5
modeling
studies.
The
index
of
agreement
for
surface
winds
in
the
2001
case
equaled
0.86,
which
is
far
better
than
the
benchmark
goal
of
0.60.
The
precipitation
evaluation
results
show
that
the
model
generally
replicates
the
observed
data,
but
is
overestimating
precipitation
in
the
summer
months.
More
information
about
the
model
performance
evaluation
and
the
MM5
configuration
is
provided
in
the
NFR
AQMTSD.

Comment:
Several
groups
criticized
the
lack
of
quantitative
meteorological
model
evaluation
data
for
the
1995
RAMS
meteorological
modeling
used
for
episodic
ozone
modeling.
392
100
Hogrefe,
C.
et.
al.
"
Evaluating
the
performance
of
regional­
scale
photochemical
modeling
systems:
Part
1­
meteorological
predictions."
Atmospherics
Environment,
vol.
35
(
2001),
pp.
4159­
4174.
Response:
A
peer­
reviewed,
quantitative
evaluation
of
the
RAMS
model
performance
for
this
meteorological
period
is
provided
by
Hogrefe,
et.
al.
100
This
analysis
was
performed
using
RAMS
predictions
for
June
through
August
of
1995.
The
results
show
that
the
RAMS
biases
and
errors
are
generally
in
line
with
past
meteorological
model
simulations
by
other
groups
outside
EPA.
The
EPA
remains
satisfied
that
the
1995
RAMS
meteorological
inputs
for
the
three
CAMx
ozone
modeling
episodes
are
of
sufficient
quality
and
we
have
continued
to
use
these
inputs
for
the
ozone
analyses
for
the
final
rule.

Comment:
The
EPA
received
several
comments
on
the
episodes
selected
for
ozone
modeling.
There
was
general
criticism
that
the
ozone
modeling
did
not
follow
EPA's
own
guidance
for
the
selection
of
episodes.
Additionally,
there
was
specific
criticism
that
the
episodes
did
not
provide
for
a
reasonable
test
of
the
8­
hour
ozone
NAAQS
in
some
areas.

Response:
The
draft
8­
hour
ozone
guidance
recommends,
at
a
minimum,
that
four
criteria
be
used
to
select
episodes
which
are
appropriate
to
model.
This
guidance
is
generally
intended
for
local
attainment
demonstrations,
as
opposed
to
regional
transport
analyses,
but
it
does
recommend
that
in
393
applying
a
regional
model
one
should
choose
episodes
meeting
as
many
of
the
criteria
as
possible,
though
it
acknowledges
there
may
be
tradeoffs.
Given
the
large
number
of
nonattainment
areas
within
the
ozone
domain,
it
would
be
extremely
difficult
to
assess
the
criteria
on
a
area­
by­
area
basis.
However,
from
a
general
perspective,
the
1995
episodes
address
all
of
the
primary
criteria,
which
include:

1)
a
variety
of
meteorological
conditions;
2)
measured
ozone
values
that
are
close
to
current
air
quality;
3)
extensive
meteorological
and
air
quality
data;
and
4)
a
sufficient
number
of
days.
More
detail
is
provided
in
the
NFR
AQMTSD,

but
here
is
a
brief
description
of
how
each
of
the
four
primary
criteria
are
met
by
the
1995
cases.

With
regard
to
the
criteria
of
meteorological
variations,
we
have
completed
inert
tracer
simulations
for
each
of
the
three
1995
episodes
that
show
different
transport
patterns
in
all
three
cases.
For
example
the
June
case
involves
east­
to­
west
transport;
the
July
case
involves
west­
to­
east
transport;
and
the
August
case
involves
southto
north
transport.
In
a
separate
analysis
to
determine
whether
the
1995
modeling
days
correspond
to
commonly
occurring
and
ozone­
conducive
meteorology,
EPA
has
applied
a
multi­
variate
statistical
approach
for
characterizing
daily
meteorological
patterns
and
investigating
their
relationship
to
8­
hour
ozone
concentrations
in
the
eastern
U.
S.
Across
394
the
16
sites
for
which
the
analysis
was
completed,
there
were
five
to
six
distinct
sets
of
meteorological
conditions,

called
regimes,
that
occurred
during
the
ozone
seasons
studied.
An
analysis
of
the
8­
hour
daily
maximum
ozone
concentrations
for
each
of
the
meteorological
regimes
was
undertaken
to
determine
the
distribution
of
ozone
concentrations
and
the
frequency
of
occurrence
of
each
regimes.
The
EPA
determined
that
between
60
and
70
percent
of
the
episode
days
we
modeled
are
associated
with
the
most
frequently
occurring,
high
ozone
potential,
meteorological
regimes.
These
results
also
provide
support
that
the
episodes
being
modeled
are
representative
of
conditions
present
when
high
ozone
concentrations
are
measured
throughout
the
modeling
domain.
For
the
second
criteria,

EPA
has
completed
an
analysis
which
shows
that
the
1995
episodes
contain
observed
8­
hour
daily
maximum
ozone
values
that
approximate
recent
ambient
concentrations
over
the
eastern
U.
S.
Additional
analyses
performed
by
EPA
and
others
have
concluded
that
each
of
the
three
episodes
involves
widespread
areas
of
elevated
ozone
concentrations.

The
synoptic
meteorological
pattern
of
the
July
1995
episode
has
been
identified
by
one
of
the
commenters
as
representing
a
classic
set
of
conditions
necessary
for
high
ozone
over
the
eastern
U.
S.
While
the
ozone
was
not
quite
as
widespread
in
the
June
and
August
1995
episodes,
these
395
periods
also
contained
exceedances
of
the
8­
hour
ozone
NAAQS
in
most
portions
of
the
region.

We
believe
that
there
is
ample
meteorological
and
air
quality
data
available
to
support
an
evaluation
of
the
modeling
for
these
episodes.
Specifically,
there
were
over
700
ozone
monitors
reporting
across
the
domain
for
use
in
model
evaluation.
As
noted
above,
the
model
performance
for
these
episodes
compares
favorably
to
the
recommendations
in
EPA's
urban
modeling
guidance.
In
addition,
the
modeling
period
is
comprised
of
30
days,
not
including
model
ramp­
up
periods
which
is
considerably
more
than
is
typically
used
in
an
attainment
demonstration
modeling
submitted
to
EPA
by
a
State.
Finally,
EPA's
draft
ozone
guidance
also
indicates
as
one
of
four
secondary
criteria
that
extra
weight
can
be
assigned
to
modeling
episodes
for
which
there
is
prior
experience
in
modeling.
The
1995
CAIR
ozone
episodes
have
been
successfully
used
to
drive
the
air
quality
modeling
completed
for
several
recent
notice­
and­
comment
rulemakings
(
Tier­
2,
Heavy
Duty
Engine,
and
NonRoad).
Based
on
the
analyses
discussed
above
and
the
adherence
to
the
modeling
guidance,
EPA
is
satisfied
that
the
1995
CAMx
episodes
are
appropriate
for
continued
use.

B.
How
did
EPA
Project
Future
Nonattainment
for
PM2.5
and
8­
Hour
Ozone?
396
1.
Projection
of
Future
PM2.5
Nonattainment
a.
Methodology
for
Projecting
Future
PM2.5
Nonattainment
In
the
NPR,
we
assessed
the
prospects
for
future
attainment
and
nonattainment
in
2010
and
2015
of
the
PM2.5
annual
NAAQS.
The
approach
for
identifying
areas
expected
to
be
nonattainment
for
PM2.5
in
the
future
involved
using
the
model
predictions
in
a
relative
way
to
forecast
current
PM2.5
design
values
to
2010
and
2015.
The
modeling
portion
of
this
approach
included
annual
simulations
for
2001
proxy
emissions
and
for
2010
and
2015
Base
Case
emissions
scenarios.
As
described
below,
the
predictions
from
these
runs
were
used
to
calculate
relative
reduction
factors
(
RRFs)
which
were
then
applied
to
current
PM2.5
design
values
from
FRM
sites
in
the
East.
This
approach
is
consistent
with
the
procedures
in
the
draft
of
EPA's
PM2.5
modeling
guidance.

To
determine
the
current
PM2.5
air
quality
for
use
in
projecting
design
values
to
the
future,
we
selected
the
higher
of
the
1999­
2001
or
2000­
2002
design
value
(
the
most
recent
ambient
data
at
the
time
of
the
proposal)
for
each
monitor
that
measured
nonattainment
in
2000­
2002.
For
those
sites
that
were
attaining
the
PM2.5
standard
based
on
their
2000­
2002
design
value,
we
used
the
value
from
this
period
397
as
the
starting
point
for
projecting
2010
and
2015
air
quality
at
these
sites.

The
procedure
for
calculating
future
year
PM2.5
design
values
is
called
the
Speciated
Modeled
Attainment
Test
(
SMAT).
The
test
uses
model
predictions
in
a
relative
sense
to
estimate
changes
expected
to
occur
in
each
major
PM2.5
species.
These
species
are
sulfate,
nitrate,
organic
carbon,
elemental
carbon,
crustal,
and
un­
attributed
mass.

The
relative
change
in
model­
predicted
species
concentrations
were
applied
to
ambient
species
measurements
in
order
to
project
each
species
for
the
future
year
scenarios.
We
applied
a
spatial
interpolation
to
the
IMPROVE
and
STN
speciation
data
as
a
means
for
estimating
species
composition
fractions
for
the
FRM
monitoring
sites.

Future
year
PM2.5
was
calculated
by
summing
the
projected
concentrations
of
each
species.
The
SMAT
technical
procedures,
as
applied
for
the
NPR,
are
contained
in
the
NPR
and
NPR
AQMTSD.

As
noted
above,
the
procedures
for
determining
future
year
PM2.5
concentrations
were
applied
for
each
FRM
site.

For
counties
with
only
one
FRM
site,
the
forecast
design
value
for
that
site
was
used
to
determine
whether
or
not
the
county
was
predicted
to
be
nonattainment
in
the
future.
For
counties
with
multiple
monitoring
sites,
the
site
with
the
highest
future
concentration
was
selected
for
that
county.
398
Those
counties
with
future
year
concentrations
of
15.1

g/
m3
(
as
rounded
up
from
15.05

g/
m3)
or
more
were
predicted
to
be
nonattainment.
Based
on
the
modeling
performed
for
the
NPR,

61
counties
in
the
East
were
forecast
to
be
nonattainment
for
the
2010
Base
Case.
Of
these,
41
were
forecast
to
remain
nonattainment
for
the
2015
Base
Case.

Comment:
Some
commenters
said
that
EPA
has
not
established
the
credibility
of
using
models
in
a
relative
sense
to
estimate
future
PM2.5
concentrations
and
that
poor
performance
of
REMSAD
for
1996
calls
into
question
the
use
of
models
to
adequately
determine
the
effects
of
changes
in
emissions.
One
commenter
said
that
a
mechanistic
model
evaluation,
in
which
model
predictions
of
PM2.5
precursor
photochemical
oxidants
are
compared
to
corresponding
measurements,
is
an
approach
for
gaining
confidence
in
the
ability
of
a
model
to
provide
a
credible
response
to
emission
changes.

Response:
The
EPA
believes
the
future
year
nonattainment
projections
should
be
based
on
using
model
predictions
in
a
relative
sense.
By
applying
the
model
in
a
relative
way,

each
measured
component
of
PM2.5
is
adjusted
upward
or
downward
based
on
the
percent
change
in
that
component,
as
determined
by
the
ratio
of
future
year
to
base
year
model
predictions.
The
EPA
feels
that
by
using
this
approach,
we
399
are
able
to
reduce
the
risk
that
overprediction
or
underprediction
of
PM2.5
component
species
may
unduly
affect
our
projection
of
future
year
nonattainment.

The
EPA
agrees
with
commenters
that
one
way
to
establish
confidence
in
the
credibility
of
this
approach
is
to
determine
whether
model
predictions
of
PM2.5
precursors
are
generally
comparable
to
corresponding
measured
data.
In
this
regard,
we
compared
the
CMAQ
predictions
to
observations
for
several
precursor
gases
for
which
measurements
were
available
in
2001.
These
gases
include
sulfur
dioxide,
nitric
acid,
and
ozone.

The
results
for
the
East
are
summarized
in
Table
VI­
2.

Additional
details
on
this
analysis
can
be
found
in
the
CMAQ
evaluation
report.
The
results
indicate
that
for
both
summer
and
winter
ozone,
the
fractional
bias
and
error
is
within
the
recommended
range
for
urban
scale
ozone
modeling
included
in
EPA's
draft
guidance
for
8­
hour
ozone
modeling.

For
the
other
species
examined,
there
are
limited
ambient
data
and
few
other
studies
against
which
to
compare
our
findings.
Still,
our
performance
results
for
these
species
are
within
the
range
suggested
as
acceptable
by
commenters
for
sulfate
(
i.
e.,
±
30
percent
to
±
60
percent
for
fractional
bias
and
50
percent
to
75
percent
for
fractional
error).

Thus,
CMAQ
is
considered
appropriate
and
credible
for
use
in
projecting
changes
in
future
year
PM2.5
concentrations
and
400
the
resultant
health/
economic
benefits
due
to
the
emissions
reductions.

Table
VI­
2.
CMAQ
Model
Performance
Statistics
for
Ozone,
Total
Nitrate,
and
Nitric
Acid
in
the
East.

Eastern
U.
S.
CMAQ
2001
FB
(%)
FE
(%)

Ozone
AIRS
(
Summer)
13
21
AIRS
(
Winter)
­
9
31
Sulfur
Dioxide
CASTNet
(
Summer)
31
48
CASTNet
(
Winter)
39
43
Nitric
Acid
CASTNet
(
Summer)
29
39
CASTNet
(
Winter)
­
21
55
Comment:
Several
commenters
said
that
EPA's
SMAT
approach
is
flawed
and
suggested
alternative
methods
for
attributing
individual
species
mass
to
the
FRM
measured
PM2.5
mass.
One
commenter
detailed
several
different
methods
to
apportion
the
FRM
mass
to
individual
PM2.5
species.
They
refer
to
two
different
estimation
methods
as
the
"
FRM
equivalent"

approach
and
the
"
best
estimate"
approach.

Response:
The
EPA
agrees
that
alternative
methodologies
can
be
used
to
apportion
PM2.5
species
fractions
to
the
FRM
data.
We
believe
that
revising
SMAT
to
use
a
methodology
similar
to
an
"
FRM
equivalent"
methodology,
as
described
in
the
Notice
of
Data
Availability
(
69
FR
47828;
August
6,

2004),
is
warranted.
Since
nonattainment
designation
401
101
Procedures
for
Estimating
Future
PM2.5
Values
for
the
CAIR
Final
Rule
by
Application
of
the
(
Revised)
Speciated
Modeled
Attainment
Test
(
SMAT),
docket
number
OAR­
2003­
0053­
1907.
determinations
and
future
year
nonattainment
projections
are
based
on
measured
FRM
data,
we
believe
that
the
PM2.5
species
data
should
be
adjusted
to
best
conform
to
what
is
measured
on
the
FRM
filters.
Based
on
comments,
EPA
has
revised
our
technique
for
projecting
current
PM2.5
data
to
incorporate
some
aspects
of
the
commenter's
"
FRM
equivalent"

methodology.
As
described
in
more
detail
in
the
NFR
AQMTSD,

we
believe
our
revised
methodology
to
be
the
most
technically
appropriate
way
of
estimating
what
is
measured
on
the
FRM
filters.

Full
documentation
of
the
revised
EPA
SMAT
methodology
is
contained
in
the
updated
SMAT
report101.
In
brief,
we
revised
the
SMAT
methodology
to
take
into
account
several
known
differences
between
what
is
measured
by
speciation
monitors
and
what
is
measured
on
FRM
filters.
Among
the
revisions
were
calculations
to
account
for
nitrate,

ammonium,
and
organic
carbon
volatilization,
blank
PM2.5
mass,
particle
bound
water,
the
degree
of
neutralization
of
sulfate,
and
the
uncertainty
in
estimating
organic
carbon
mass.

Comment:
Several
commenters
noted
that
the
future
year
design
values
were
based
on
projections
of
the
1999
 
2001
402
and/
or
2000­
2002
FRM
monitoring
data
and
that
there
are
more
recent
design
value
data
available
for
the
2001­
2003
design
value
period.
Commenters
also
noted
that
the
2001­
2003
data
shows
lower
PM2.5
concentrations
at
the
majority
of
sites
and
therefore,
by
projecting
the
highest
design
value,
we
are
overestimating
the
future
year
PM2.5
values.

Response:
As
stated
above,
the
PM2.5
projection
methodology
in
the
NPR
used
the
higher
of
the
1999­
2001
or
2000­
2002
PM2.5
design
value
data.
The
draft
modeling
guidance
for
PM2.5
specifies
the
use
of
the
higher
of
the
three
design
value
periods
which
straddle
the
emissions
year.
The
emissions
year
is
2001
and
therefore
the
three
periods
would
be
1999­
2001,
2000­
2002,
and
2001­
2003.
Since
the
2001­
2003
data
is
now
available,
we
are
using
it
as
part
of
the
current
year
PM2.5
calculations
for
the
final
rule.

The
observation
by
a
commenter
that
the
2001­
2003
data
are
generally
lower
than
in
the
previous
two
design
value
periods
(
i.
e.,
1999­
2001
and
2000­
2002)
leads
to
the
issue
of
how
to
reduce
the
influence
of
year­
to­
year
variability
in
meteorology
and
emissions
on
our
estimate
of
current
air
quality.
As
a
consequence
of
this
year­
to­
year
variability
in
concentrations,
relying
on
design
values
from
any
single
period,
as
in
the
approach
used
for
proposal,
may
not
provide
a
robust
representation
of
current
air
quality
for
403
use
in
forecasting
the
future.
Specifically,
the
lower
PM2.5
values
in
2001­
2003
may
not
be
representative
of
the
current
modeling
period.
To
address
the
issue
of
year­

toyear
variability
in
the
ambient
data
we
have
modified
our
methodology
to
use
an
average
of
the
three
design
value
periods
that
straddle
the
base
year
emissions
year
(
i.
e.,

2001).
In
this
case
it
is
the
average
of
the
1999­
2001,

2000­
2002,
and
2001­
2003
design
values.
The
average
of
the
three
design
values
is
not
a
straight
5­
year
average.

Rather,
it
is
a
weighted
average
of
the
1999­
2003
period.

That
is,
by
averaging
1999­
2001,
2000­
2002,
and
2001­
2003,

the
value
from
2001
is
weighted
three
times;
2000
and
2002
are
each
weighted
twice
and
1999
and
2003
are
each
weighted
once.
This
approach
has
the
desired
benefits
of:
(
1)

weighting
the
PM2.5
values
towards
the
middle
year
of
the
5­

year
period,
which
is
the
2001
base
year
for
our
emissions
projections;
and
(
2)
smoothing
out
the
effects
of
year­

toyear
variability
in
emissions
and
meteorology
that
occurs
over
the
full
5­
year
period.
We
have
adopted
this
method
for
use
in
projecting
future
PM2.5
nonattainment
for
the
final
rule
analysis.
We
plan
to
incorporate
this
new
methodology
into
the
next
draft
version
of
our
PM2.5
modeling
guidance.
404
b.
Projected
2010
and
2015
Base
Case
PM2.5
Nonattainment
Counties
For
the
final
rule,
we
have
revised
the
projected
PM2.5
nonattainment
counties
for
2010
and
2015
by
applying
CMAQ
for
the
entire
year
(
i.
e.,
January
through
December)
of
2001
using
2001
Base
Year
and
2010
and
2015
future
Base
Case
emissions
from
the
new
modeling
platform,
as
described
in
section
VI.
A.
2.
The
2010
and
2015
Base
Case
PM2.5
nonattainment
counties
were
determined
applying
the
updated
SMAT
method
using
current
1999­
2003
PM2.5
air
quality
coupled
with
the
PM2.5
species
from
the
2001
Base
Year
and
2010
and
2015
Base
Case
CMAQ
model
runs.
For
counties
with
multiple
monitoring
sites,
the
site
with
the
highest
future
concentration
was
selected
for
that
county.
Those
counties
with
future
year
design
values
of
15.05

g/
m3
or
higher
were
predicted
to
be
nonattainment.
The
result
is
that,
without
controls
beyond
those
included
in
the
Base
Case,
79
counties
in
the
East
are
projected
to
be
nonattainment
for
the
2010
Base
Case.
For
the
2015
Base
Case,
74
counties
in
the
East
are
projected
to
be
nonattainment
for
PM2.5.

In
light
of
the
uncertainties
inherent
in
regionwide
modeling
many
years
into
the
future,
of
the
79
nonattainment
counties
projected
for
the
2010
Base
Case,
we
have
the
most
confidence
in
our
projection
of
nonattainment
for
those
405
counties
that
are
not
only
forecast
to
be
nonattainment
in
2010,
based
on
the
SMAT
method,
but
that
also
measure
nonattainment
for
the
most
recent
period
of
available
ambient
data
(
i.
e.,
2001­
2003).
In
our
analysis
for
the
2010
Base
Case,
there
are
62
such
counties
in
the
East
that
are
both
"
modeled"
nonattainment
and
currently
have
"
monitored"
nonattainment.
We
refer
to
these
counties
as
having
"
modeled
plus
monitored"
nonattainment.
Out
of
an
abundance
of
caution,
we
are
using
only
these
62
"
modeled
plus
monitored"
counties
as
the
downwind
receptors
in
determining
which
upwind
States
make
a
significant
contribution
to
PM2.5
in
downwind
States.

The
79
counties
in
the
East
that
we
project
will
be
nonattainment
for
PM2.5
in
2010
and
the
subset
of
62
counties
that
are
also
"
monitored"
nonattainment
in
2001­

2003,
are
identified
in
Table
VI­
3.
The
2015
Base
Case
PM2.5
nonattainment
counties
are
provided
in
Table
VI­
4.

Table
VI­
3.
Projected
PM2.5
Concentrations
(

g/
m3)
for
Nonattainment
Counties
in
the
2010
Base
Case.

State
County
2010
Base
"
Modeled
+
Monitored"

Alabama
DeKalb
Co
15.23
No
Alabama
Jefferson
Co
18.57
Yes
Alabama
Montgomery
Co
15.12
No
Alabama
Morgan
Co
15.29
No
Alabama
Russell
Co
16.17
Yes
Alabama
Talladega
Co
15.34
No
Delaware
New
Castle
Co
16.56
Yes
District
of
Columbia
15.84
Yes
406
State
County
2010
Base
"
Modeled
+
Monitored"

Georgia
Bibb
Co
16.27
Yes
Georgia
Clarke
Co
16.39
Yes
Georgia
Clayton
Co
17.39
Yes
Georgia
Cobb
Co
16.57
Yes
Georgia
DeKalb
Co
16.75
Yes
Georgia
Floyd
Co
16.87
Yes
Georgia
Fulton
Co
18.02
Yes
Georgia
Hall
Co
15.60
No
Georgia
Muscogee
Co
15.65
No
Georgia
Richmond
Co
15.68
No
Georgia
Walker
Co
15.43
Yes
Georgia
Washington
Co
15.31
No
Georgia
Wilkinson
Co
16.27
No
Illinois
Cook
Co
17.52
Yes
Illinois
Madison
Co
16.66
Yes
Illinois
St.
Clair
Co
16.24
Yes
Indiana
Clark
Co
16.51
Yes
Indiana
Dubois
Co
15.73
Yes
Indiana
Lake
Co
17.26
Yes
Indiana
Marion
Co
16.83
Yes
Indiana
Vanderburgh
Co
15.54
Yes
Kentucky
Boyd
Co
15.23
No
Kentucky
Bullitt
Co
15.10
No
Kentucky
Fayette
Co
15.95
Yes
Kentucky
Jefferson
Co
16.71
Yes
Kentucky
Kenton
Co
15.30
No
Maryland
Anne
Arundel
Co
15.26
Yes
Maryland
Baltimore
City
16.96
Yes
Michigan
Wayne
Co
19.41
Yes
Missouri
St.
Louis
City
15.10
No
New
Jersey
Union
Co
15.05
Yes
New
York
New
York
Co
16.19
Yes
North
Carolina
Catawba
Co
15.48
Yes
North
Carolina
Davidson
Co
15.76
Yes
North
Carolina
Mecklenburg
Co
15.22
No
Ohio
Butler
Co
16.45
Yes
Ohio
Cuyahoga
Co
18.84
Yes
Ohio
Franklin
Co
16.98
Yes
Ohio
Hamilton
Co
18.23
Yes
Ohio
Jefferson
Co
17.94
Yes
Ohio
Lawrence
Co
16.10
Yes
Ohio
Mahoning
Co
15.39
Yes
Ohio
Montgomery
Co
15.41
Yes
Ohio
Scioto
Co
18.13
Yes
407
State
County
2010
Base
"
Modeled
+
Monitored"

Ohio
Stark
Co
17.14
Yes
Ohio
Summit
Co
16.47
Yes
Ohio
Trumbull
Co
15.28
No
Pennsylvania
Allegheny
Co
20.55
Yes
Pennsylvania
Beaver
Co
15.78
Yes
Pennsylvania
Berks
Co
15.89
Yes
Pennsylvania
Cambria
Co
15.14
Yes
Pennsylvania
Dauphin
Co
15.17
Yes
Pennsylvania
Delaware
Co
15.61
Yes
Pennsylvania
Lancaster
Co
16.55
Yes
Pennsylvania
Philadelphia
Co
16.65
Yes
Pennsylvania
Washington
Co
15.23
Yes
Pennsylvania
Westmoreland
Co
15.16
Yes
Pennsylvania
York
Co
16.49
Yes
Tennessee
Davidson
Co
15.36
No
Tennessee
Hamilton
Co
16.89
Yes
Tennessee
Knox
Co
17.44
Yes
Tennessee
Sullivan
Co
15.32
No
West
Virginia
Berkeley
Co
15.69
Yes
West
Virginia
Brooke
Co
16.63
Yes
West
Virginia
Cabell
Co
17.03
Yes
West
Virginia
Hancock
Co
17.06
Yes
West
Virginia
Kanawha
Co
17.56
Yes
West
Virginia
Marion
Co
15.32
Yes
West
Virginia
Marshall
Co
15.81
Yes
West
Virginia
Ohio
Co
15.14
Yes
West
Virginia
Wood
Co
16.66
Yes
Table
VI­
4.
Projected
PM2.5
Concentrations
(

g/
m3)
for
Nonattainment
Counties
in
the
2015
Base
Case.

State
County
2015
Base
Alabama
DeKalb
Co
15.24
Alabama
Jefferson
Co
18.85
Alabama
Montgomery
Co
15.24
Alabama
Morgan
Co
15.26
Alabama
Russell
Co
16.10
Alabama
Talladega
Co
15.22
Delaware
New
Castle
Co
16.47
District
of
Columbia
15.57
Georgia
Bibb
Co
16.41
408
State
County
2015
Base
Georgia
Chatham
Co
15.06
Georgia
Clarke
Co
16.15
Georgia
Clayton
Co
17.46
Georgia
Cobb
Co
16.51
Georgia
DeKalb
Co
16.82
Georgia
Floyd
Co
17.33
Georgia
Fulton
Co
18.00
Georgia
Hall
Co
15.36
Georgia
Muscogee
Co
15.58
Georgia
Richmond
Co
15.76
Georgia
Walker
Co
15.37
Georgia
Washington
Co
15.34
Georgia
Wilkinson
Co
16.54
Illinois
Cook
Co
17.71
Illinois
Madison
Co
16.90
Illinois
St.
Clair
Co
16.49
Illinois
Will
Co
15.12
Indiana
Clark
Co
16.37
Indiana
Dubois
Co
15.66
Indiana
Lake
Co
17.27
Indiana
Marion
Co
16.77
Indiana
Vanderburgh
Co
15.56
Kentucky
Boyd
Co
15.06
Kentucky
Fayette
Co
15.62
Kentucky
Jefferson
Co
16.61
Kentucky
Kenton
Co
15.09
Maryland
Baltimore
City
17.04
Maryland
Baltimore
Co
15.08
Michigan
Wayne
Co
19.28
Mississippi
Jones
Co
15.18
Missouri
St.
Louis
City
15.34
New
York
New
York
Co
15.76
North
Carolina
Catawba
Co
15.19
North
Carolina
Davidson
Co
15.34
Ohio
Butler
Co
16.32
Ohio
Cuyahoga
Co
18.60
Ohio
Franklin
Co
16.64
Ohio
Hamilton
Co
18.03
Ohio
Jefferson
Co
17.83
Ohio
Lawrence
Co
15.92
Ohio
Mahoning
Co
15.13
Ohio
Montgomery
Co
15.16
Ohio
Scioto
Co
17.92
Ohio
Stark
Co
16.86
409
State
County
2015
Base
Ohio
Summit
Co
16.14
Ohio
Trumbull
Co
15.05
Pennsylvania
Allegheny
Co
20.33
Pennsylvania
Beaver
Co
15.54
Pennsylvania
Berks
Co
15.66
Pennsylvania
Delaware
Co
15.52
Pennsylvania
Lancaster
Co
16.28
Pennsylvania
Philadelphia
Co
16.53
Pennsylvania
York
Co
16.22
Tennessee
Davidson
Co
15.36
Tennessee
Hamilton
Co
16.82
Tennessee
Knox
Co
17.34
Tennessee
Shelby
Co
15.17
Tennessee
Sullivan
Co
15.37
West
Virginia
Berkeley
Co
15.32
West
Virginia
Brooke
Co
16.51
West
Virginia
Cabell
Co
16.86
West
Virginia
Hancock
Co
16.97
West
Virginia
Kanawha
Co
17.17
West
Virginia
Marshall
Co
15.52
West
Virginia
Wood
Co
16.69
2.
Projection
of
Future
8­
Hour
Ozone
Nonattainment
a.
Methodology
for
Projecting
Future
8­
Hour
Ozone
Nonattainment
The
approach
for
projecting
future
8­
hour
ozone
concentrations
used
by
EPA
in
the
NPR
was
based
on
applying
the
model
in
a
relative
sense
to
estimate
the
change
in
ozone
between
the
base
year
(
2001)
and
each
future
scenario.

Projected
8­
hour
ozone
design
values
in
2010
and
2015
were
estimated
by
combining
the
relative
change
in
model
predicted
ozone
from
2001
to
the
future
scenario
with
an
estimate
of
the
base
year
ambient
8­
hour
ozone
design
value.
410
These
procedures
for
calculating
future
case
ozone
design
values
are
consistent
with
EPA's
draft
modeling
guidance
for
8­
hour
ozone
attainment
demonstrations.
The
draft
guidance
specifies
the
use
of
the
higher
of
the
design
values
from
(
a)
the
period
that
straddles
the
emissions
inventory
base
year
or
(
b)
the
design
value
period
which
was
used
to
designate
the
area
under
the
ozone
NAAQS.
At
the
time
of
the
proposal,
2000­
2002
was
the
design
value
period
which
both
straddled
the
2001
base
year
inventory
and
was
also
the
latest
period
available.

Comment:
Commenters
noted
that
the
procedures
used
by
EPA
for
projecting
future
8­
hour
ozone
concentrations
differ
from
the
procedures
used
for
projecting
PM2.5.
These
commenters
said
that
EPA
should
harmonize
the
two
approaches.

Response:
In
response
to
comments,
we
have
made
several
changes
in
the
approach
to
projecting
future
8­
hour
ozone
nonattainment
in
order
to
follow
an
approach
that
is
consistent
with
the
manner
in
which
PM2.5
projections
are
determined.
The
approach
we
are
using
to
project
PM2.5
for
the
final
rule
analysis
is
described
in
section
VI.
B.
1,

above.
In
order
to
harmonize
the
ozone
approach
with
the
approach
used
for
PM2.5,
we
are
using
the
weighted
average
of
the
design
values
for
the
periods
that
straddle
the
411
emission
base
year
(
i.
e.,
2001).
These
periods
are
1999­

2001,
2000­
2002,
and
2001­
2003.
In
this
approach,
the
fourth­
high
ozone
value
from
2001
is
weighted
3
times,
2000
and
2002
are
weighted
twice,
and
1999
and
2003
are
weighted
once.
This
has
the
desired
effect
of
weighting
the
projected
ozone
values
towards
the
middle
year
of
the
5­
year
period,

which
is
the
emissions
year
(
2001),
while
accounting
for
the
emissions
and
meteorological
variability
that
occurs
over
the
full
5­
year
period.
The
average
weighted
concentration
is
expected
to
be
more
representative
as
a
starting
point
for
future
year
projections
than
choosing
(
a)
the
single
design
value
period
that
straddles
the
base
year
or
(
b)
the
design
value
used
for
designations.
We
plan
to
incorporate
this
new
methodology
into
the
next
draft
version
of
our
ozone
modeling
guidance.

Comment:
One
commenter
claimed
that
the
2010
and
2015
ozone
projections
in
the
proposal
base
cases
were
too
optimistic,

that
is,
that
the
modeling
was
underestimating
the
number
of
areas
that
may
be
in
nonattainment
in
the
future.
The
commenter
urged
a
more
conservative
approach
to
assessing
the
future
attainment
status
of
areas.

Response:
The
technical
basis
for
the
comment
stemmed
from
the
assertion
that
the
regional
ozone
modeling
that
EPA
performed
for
the
proposal
was
not
of
"
SIP­
quality."
The
412
EPA
response
to
the
specific
technical
issues
with
regard
to
episode
selection
and
grid
resolution
can
be
found
in
section
VI.
A
as
well
as
in
the
response
to
comments
document.
The
EPA
remains
confident
that
the
CAIR
8­
hour
ozone
modeling
platform
is
appropriate
for
assessing
potential
levels
of
future
nonattainment.

b.
Projected
2010
and
2015
Base
Case
8­
Hour
Ozone
Nonattainment
Counties
For
the
final
rule,
we
have
revised
our
projections
of
ozone
nonattainment
for
the
2010
and
2015
Base
Cases
by
applying
CAMx
for
the
three
1995
ozone
episodes
using
2001
Base
Year
and
2010
and
2015
future
Base
Case
emissions
from
the
new
modeling
platform,
as
described
in
section
VI.
A.
2.

The
revised
2010
and
2015
Base
Case
8­
hour
ozone
nonattainment
counties
were
determined
by
applying
the
relative
change
in
8­
hour
ozone
predicted
by
these
CAMx
model
runs
to
the
weighted
average
1999­
2003
8­
hour
ozone
concentrations
as
described
above
and,
in
more
detail,
in
the
NFR
AQMTSD.
For
counties
with
multiple
monitoring
sites,
the
site
with
the
highest
future
concentration
was
selected
for
that
county.
Those
counties
with
future
year
design
values
of
85
parts
per
billion
(
ppb)
or
higher
were
predicted
to
be
nonattainment.
413
As
a
result
of
our
updated
modeling
we
project
that,

without
controls
beyond
those
in
the
Base
Case,
there
will
be
40
8­
hour
ozone
nonattainnment
counties
in
2010
and
22
nonattainment
counties
in
2015.
All
of
the
40
counties
that
we
are
projecting
to
be
nonattainment
for
the
2010
Base
Case
are
also
measuring
nonattainment
based
on
the
most
recent
design
value
period
(
i.
e.,
2001­
2003).
We
refer
to
these
counties
as
"
modeled
plus
monitored"
nonattainment,
as
described
above
in
section
IV.
B.
1
for
PM2.5.
We
are
using
these
40
counties
as
the
downwind
receptors
to
determine
which
States
make
a
significant
contribution
to
8­
hour
ozone
nonattainment
in
downwind
States.

The
counties
we
are
projecting
to
be
nonattainment
for
8­
hour
ozone
in
the
2010
Base
Case
and
2015
Base
Case
are
listed
in
Table
VI­
5
and
Table
VI­
6,
respectively.

Table
VI­
5.
Projected
2010
Base
Case
8­
hour
Ozone
Nonattainment
Counties
and
Concentrations
(
ppb).

State
County
2010
Base
Connecticut
Fairfield
Co
92.6
Connecticut
Middlesex
Co
90.9
Connecticut
New
Haven
Co
91.6
Delaware
New
Castle
Co
85.0
District
of
Columbia
85.2
Georgia
Fulton
Co
86.5
Maryland
Anne
Arundel
Co
88.8
Maryland
Cecil
Co
89.7
Maryland
Harford
Co
93.0
Maryland
Kent
Co
86.2
Michigan
Macomb
Co
85.5
New
Jersey
Bergen
Co
86.9
414
State
County
2010
Base
New
Jersey
Camden
Co
91.9
New
Jersey
Gloucester
Co
91.8
New
Jersey
Hunterdon
Co
89.0
New
Jersey
Mercer
Co
95.6
New
Jersey
Middlesex
Co
92.4
New
Jersey
Monmouth
Co
86.6
New
Jersey
Morris
Co
86.5
New
Jersey
Ocean
Co
100.5
New
York
Erie
Co
87.3
New
York
Richmond
Co
87.3
New
York
Suffolk
Co
91.1
New
York
Westchester
Co
85.3
Ohio
Geauga
Co
87.1
Pennsylvania
Bucks
Co
94.7
Pennsylvania
Chester
Co
85.7
Pennsylvania
Montgomery
Co
88.0
Pennsylvania
Philadelphia
Co
90.3
Rhode
Island
Kent
Co
86.4
Texas
Denton
Co
87.4
Texas
Galveston
Co
85.1
Texas
Harris
Co
97.9
Texas
Jefferson
Co
85.6
Texas
Tarrant
Co
87.8
Virginia
Arlington
Co
86.2
Virginia
Fairfax
Co
85.7
Wisconsin
Kenosha
Co
91.3
Wisconsin
Ozaukee
Co
86.2
Wisconsin
Sheboygan
Co
88.3
Table
VI­
6.
Projected
2015
Base
Case
8­
hour
Ozone
Nonattainment
Counties
and
Concentrations
(
ppb).

State
County
2015
Base
Connecticut
Fairfield
Co
91.4
Connecticut
Middlesex
Co
89.1
Connecticut
New
Haven
Co
89.8
Maryland
Anne
Arundel
Co
86.0
Maryland
Cecil
Co
86.9
Maryland
Harford
Co
90.6
Michigan
Macomb
Co
85.1
New
Jersey
Bergen
Co
85.7
415
State
County
2015
Base
New
Jersey
Camden
Co
89.5
New
Jersey
Gloucester
Co
89.6
New
Jersey
Hunterdon
Co
86.5
New
Jersey
Mercer
Co
93.5
New
Jersey
Middlesex
Co
89.8
New
Jersey
Ocean
Co
98.0
New
York
Erie
Co
85.2
New
York
Suffolk
Co
89.9
Pennsylvania
Bucks
Co
93.0
Pennsylvania
Montgomery
Co
86.5
Pennsylvania
Philadelphia
Co
88.9
Texas
Harris
Co
97.3
Texas
Jefferson
Co
85.0
Wisconsin
Kenosha
Co
89.4
C.
How
did
EPA
Assess
Interstate
Contributions
to
Nonattainment?

1.
PM2.5
Contribution
Modeling
Approach
For
the
proposed
rule,
EPA
performed
State­
by­
State
zero­
out
modeling
to
quantify
the
contribution
from
emissions
in
each
State
to
future
PM2.5
nonattainment
in
other
States
and
to
determine
whether
that
contribution
meets
the
air
quality
prong
(
i.
e.,
before
considering
cost)

of
the
"
contribute
significantly"
test.
The
zero­
out
modeling
technique
provides
an
estimate
of
downwind
impacts
by
comparing
the
model
predictions
from
the
2010
Base
Case
to
the
predictions
from
a
run
in
which
all
anthropogenic
SO2
and
NOx
emissions
are
removed
from
specific
States.

Counties
forecast
to
be
nonattainment
for
PM2.5
in
the
proposal
2010
Base
Case
were
used
as
receptors
for
416
quantifying
interstate
contributions
of
PM2.5.
For
each
State­
by­
State
zero­
out
run
we
projected
the
annual
average
PM2.5
concentration
at
each
receptor
using
the
proposed
SMAT
technique,
as
described
in
the
NPR
AQMTSD.
The
contribution
from
an
upwind
State
to
nonattainment
at
a
given
downwind
receptor
was
determined
by
calculating
the
difference
in
PM2.5
concentration
between
the
2010
Base
Case
and
the
zeroout
run
at
that
receptor.
We
followed
this
process
for
each
State­
by­
State
zero­
out
run
and
each
receptor.
For
each
upwind
State,
we
identified
the
largest
contribution
from
that
State
to
a
downwind
nonattainment
receptor
in
order
to
determine
the
magnitude
of
the
maximum
downwind
contribution
from
each
State.
The
maximum
downwind
contribution
was
proposed
as
the
metric
for
determining
whether
or
not
the
contribution
was
significant.
As
described
in
section
III,

EPA
proposed,
in
the
alternative,
a
criterion
of
0.10

g/
m3
and
0.15

g/
m3
for
determining
whether
emissions
in
a
State
make
a
significant
contribution
(
before
considering
cost)
to
PM2.5
nonattainment
in
another
State.
Details
on
these
procedures
can
be
found
in
the
NPR
AQMTSD.

Comments:
Commenters
questioned
the
use
of
zero­
out
modeling
and
said
that
EPA
should
support
the
development
of
a
source
apportionment
model
for
PM2.5
contributions.
The
commenter
recommended
that
EPA
delay
the
final
rule
until
417
such
a
technique
can
be
used.
Another
commenter
provided
results
of
a
sulfate
source
apportionment
technique
currently
under
development
along
with
modeling
results
which
showed
that
the
zero­
out
technique
and
source
apportionment
for
sulfate
provide
similar
results
in
terms
of
the
magnitude
and
extent
of
downwind
impacts.
The
commenter
noted
that
the
results
suggest
that
zero­
out
modeling
may
somewhat
underestimate
the
transport
of
sulfate.

Response:
The
EPA
continues
to
believe
that
the
zero­
out
technique
is
a
credible
method
for
quantifying
interstate
PM2.5
contributions.
This
is
supported
by
a
commenter's
results
showing
that
the
zero­
out
technique
and
source
apportionment
appear
to
give
similar
results.
We
accept
the
commenter's
modeling
for
sulfate
source
apportionment
results
which
indicate
that
the
zero­
out
technique
does
not
overestimate
interstate
transport.
Moreover,
EPA
rejects
the
notion
that
we
should
delay
needed
reductions
while
we
await
alternative
assessment
techniques.

2.
8­
Hour
Ozone
Contribution
Modeling
Approach
In
the
proposal,
EPA
quantified
the
impact
of
emissions
from
specific
upwind
States
on
8­
hour
ozone
concentrations
in
projected
downwind
nonattainment
areas.
The
procedures
we
followed
to
assess
interstate
ozone
contribution
for
the
418
proposal
analysis
are
summarized
below.
We
are
using
these
same
procedures
along
with
the
updated
CAMx
modeling
platform,
as
described
in
section
VI.
A.,
to
assess
ozone
contributions
for
today's
rule.
Details
on
these
procedures
can
be
found
in
the
NFR
AQMTSD.

We
applied
two
different
modeling
techniques,
zero­
out
and
source
apportionment,
to
assess
the
contributions
of
emissions
in
upwind
States
on
8­
hour
ozone
nonattainment
in
downwind
States.
The
outputs
of
the
two
modeling
techniques
were
evaluated
in
terms
of
three
key
contribution
factors
to
determine
which
States
make
a
significant
contribution
to
downwind
ozone
nonattainment
as
described
in
section
VI.
B.
2.

The
zero­
out
and
source
apportionment
modeling
techniques
provide
different,
but
equally
valid,
technical
approaches
to
quantifying
the
downwind
impact
of
emissions
from
upwind
States.
The
zero­
out
modeling
analysis
provides
an
estimate
of
downwind
impacts
by
comparing
the
model
predictions
from
the
2010
Base
Case
and
the
predictions
from
a
model
run
in
which
all
anthropogenic
NOx
and
VOC
emissions
are
removed
from
specific
States.
The
source
apportionment
modeling
quantifies
downwind
impacts
by
tracking
and
allocating
the
amounts
of
ozone
formed
from
man­
made
NOx
and
VOC
emissions
in
upwind
States.
Because
large
portions
of
the
six
States
419
102
The
six
States
are
Kansas,
Nebraska,
North
Dakota,
Oklahoma,
South
Dakota,
and
Texas.
along
the
western
border
of
the
modeling
domain102
are
outside
the
area
covered
by
our
modeling,
EPA
did
not
analyze
the
contributions
to
downwind
ozone
nonattainment
for
these
States.

In
the
analysis
done
at
proposal,
EPA
considered
three
fundamental
factors
for
evaluating
whether
emissions
in
an
upwind
State
make
large
and/
or
frequent
contributions
to
downwind
nonattainment:
(
1)
the
magnitude
of
the
contribution;
(
2)
the
frequency
of
the
contribution;
and
(
3)

the
relative
amount
of
the
contribution
when
compared
against
contributions
from
other
areas.
The
factors
are
the
basis
for
several
metrics
that
can
be
used
to
assess
a
particular
impact.
The
metrics
used
in
this
analysis
were
the
same
as
those
used
in
the
NOx
SIP
Call.

Within
these
three
factors,
eight
specific
metrics
were
calculated
to
assess
the
contribution
of
each
of
the
31
States
to
the
residual
nonattainment
counties.
For
the
zero­
out
modeling,
EPA
considered:
(
1)
the
maximum
contribution
(
magnitude);
(
2)
the
number
and
percentage
of
exceedances
with
contributions
in
certain
concentration
ranges
(
frequency);
(
3)
the
total
contribution
relative
to
the
total
exceedance
level
ozone
in
the
receptor
area
(
relative
amount);
and
(
4)
the
population­
weighted
total
420
contribution
relative
to
the
total
population­
weighted
exceedance
level
ozone
in
the
receptor
area
(
relative
amount).
For
the
source
apportionment
modeling
EPA
considered:
(
5)
the
maximum
contribution
(
magnitude);
(
6)

the
highest
daily
average
contribution
(
magnitude);
(
7)
the
number
and
percentages
of
exceedances
with
contributions
in
certain
concentration
ranges
(
frequency);
and
(
8)
the
total
average
contribution
to
exceedance
ozone
in
the
downwind
area
(
relative
amount).
The
values
for
these
metrics
were
calculated
using
only
those
periods
during
which
the
model
predicted
8­
hour
average
ozone
concentrations
greater
than
or
equal
to
85
ppb
in
at
least
one
of
the
model
grid
cells
associated
with
the
receptor
county
in
the
2010
base
case.

Grid
cells
were
linked
to
a
specific
nonattainment
county
if
any
part
of
the
grid
cell
covered
any
portion
of
the
projected
2010
nonattainment
county.

The
first
step
in
evaluating
the
contribution
factors
was
to
screen
out
linkages
for
which
the
contributions
were
clearly
small.
This
initial
screening
was
based
on
two
criteria:
(
1)
the
maximum
contribution
had
to
be
greater
than
or
equal
to
2
ppb
from
either
of
the
two
modeling
techniques;
and
(
2)
the
total
average
contribution
to
exceedance
of
ozone
in
the
downwind
area
had
to
be
greater
than
1
percent.
If
either
screening
test
was
not
met,
then
the
linkage
was
not
considered
significant.
Those
linkages
421
that
had
contributions
which
exceeded
the
screening
criteria
were
evaluated
further
in
steps
2
through
4.

In
step
2,
we
evaluated
the
contributions
in
each
linkage
based
on
the
zero­
out
modeling
and
in
step
3
we
evaluated
the
contributions
in
each
linkage
based
on
the
source
apportionment
modeling.
In
step
4,
we
considered
the
results
of
both
step
2
and
step
3
to
determine
which
of
the
linkages
were
significant.
For
both
techniques,
EPA
determined
whether
the
linkage
is
significant
by
evaluating
the
magnitude,
frequency,
and
relative
amount
of
the
contributions.
Each
upwind
State
that
made
relatively
large
and/
or
frequent
contributions
to
nonattainment
in
the
downwind
area,
based
on
these
factors,
was
considered
to
contribute
significantly
to
nonattainment
in
the
downwind
area.

The
EPA
believes
that
each
of
the
factors
provides
an
independent
measure
of
contribution,
however,
there
had
to
be
at
least
two
different
factors
that
indicated
large
and/
or
frequent
contributions
in
order
for
the
linkage
to
be
found
significant.
In
this
regard,
the
finding
of
a
significant
contribution
for
an
individual
linkage
was
not
based
on
any
single
factor.
Further,
each
of
the
modeling
approaches
had
to
show
at
least
one
indicator
of
a
large
and/
or
frequent
contribution
in
order
for
the
linkage
to
be
found
significant.
The
EPA
received
several
general
422
comments
on
the
procedures
for
assessing
interstate
contributions
of
ozone
to
projected
residual
nonattainment
areas,
as
discussed
below.

Comment:
A
commenter
opposed
the
use
of
population­
weighted
metrics
to
determine
whether
an
upwind
State's
impact
on
a
location
in
another
State
is
significant.

Response:
The
commenter's
concern
was
that
transport
contributions
to
rural
areas
with
low
populations
were
not
being
weighted
appropriately.
This
is
not
a
valid
concern
because
the
relative
contribution
factor
from
the
zero­
out
modeling
is
presumed
to
be
met
if
either
of
the
two
criteria
(
population­
weighted,
or
non­
population­
weighted)
show
large
contributions.

Comment:
Also,
EPA
received
a
specific
comment
on
a
certain
linkage
that
was
deemed
to
be
significant
in
the
analysis
done
to
support
the
NPR.
The
commenter
objected
to
the
conclusion
that
Mississippi
significantly
contributes
to
residual
ozone
exceedances
near
Memphis.
The
objection
resulted
from
issues
with
grid
resolution,
episode
selection,
and
the
fact
that
the
zero­
out
and
source
apportionment
modeling
for
Mississippi
included
some
emissions
from
Tennessee
and
Arkansas
due
to
the
irregular
State
boundaries.
423
Response:
As
noted
in
section
VI.
B.
2,
Crittenden
County,
AR
is
no
longer
projected
to
be
a
nonattainment
area
in
the
2010
Base
Case.
As
a
result,
the
issue
of
Mississippi's
contribution
to
ozone
in
the
Memphis
area
is
moot.

D.
What
Are
the
Estimated
Interstate
Contributions
to
PM2.5
and
8­
Hour
Ozone
Nonattainment?

1.
Results
of
PM2.5
Contribution
Modeling
In
this
section,
we
present
the
interstate
contributions
from
emissions
in
upwind
States
to
PM2.5
nonattainment
in
downwind
nonattainment
counties.
States
which
contribute
0.2

g/
m3
or
more
to
PM2.5
nonattainment
in
another
State
are
determined
to
contribute
significantly
(
before
considering
cost).
We
calculated
the
interstate
PM2.5
contributions
using
the
State­
by­
State
zero­
out
modeling
technique,
as
indicated
above
in
section
VI.
C.
1.

This
technique
is
described
in
the
NFR
AQMTSD.
We
performed
zero­
out
modeling
using
CMAQ
for
each
of
37
States
individually
(
i.
e.,
Alabama,
Arkansas,
Connecticut,

Delaware,
Florida,
Georgia,
Illinois,
Indiana,
Iowa,
Kansas,

Kentucky,
Louisiana,
Maine,
Maryland
combined
with
the
District
of
Columbia,
Massachusetts,
Michigan,
Minnesota,

Mississippi,
Missouri,
Nebraska,
New
Hampshire,
New
Jersey,

New
York,
North
Carolina,
North
Dakota,
Ohio,
Oklahoma,

Pennsylvania,
Rhode
Island,
South
Carolina,
South
Dakota,
424
103
As
noted
above,
we
combined
Maryland
and
the
District
of
Columbia
as
a
single
entity
in
our
contribution
modeling.
This
is
a
logical
approach
because
of
the
small
size
of
the
District
of
Columbia
and,
hence,
its
emissions
and
its
close
proximity
to
Maryland.
Under
our
analysis,
Maryland
and
the
District
of
Columbia
are
linked
as
significant
contributors
to
the
same
downwind
nonattainment
counties.
EPA
received
no
adverse
comment
on
this
approach.
We
also
considered
these
entities
separately,
and
in
view
of
the
close
proximity
of
these
two
areas
we
believe
that
Maryland
is
linked
as
a
significant
contributor
to
nonattainment
in
the
District
of
Columbia
and
that
the
District
of
Columbia
is
linked
as
a
significant
contributor
to
nonattainment
in
Maryland.
Tennessee,
Texas,
Vermont,
Virginia,
West
Virginia,
and
Wisconsin).

We
calculated
each
State's
contribution
to
PM2.5
in
each
of
the
62
counties
that
are
projected
to
be
nonattainment
in
the
2010
Base
Case
(
i.
e.,
"
modeled"

nonattainment)
and
are
also
"
monitored"
nonattainment
in
2001­
2003,
as
described
in
section
VI.
B.
1.
b.
The
maximum
contribution
from
each
upwind
State
to
downwind
PM2.5
nonattainment
is
provided
in
Table
VI­
7.
The
contributions
from
each
State
to
nonattainment
in
each
nonattainment
county
are
provided
in
the
NFR
AQMTSD.
Based
on
the
Stateby
State
modeling,
there
are
23
States
and
the
District
of
Columbia103
which
contribute
0.2

g/
m3
or
more
to
downwind
PM2.5
nonattainment
(
Alabama,
the
District
of
Columbia,

Florida,
Georgia,
Illinois,
Indiana,
Iowa,
Kentucky,

Louisiana,
Maryland,
Michigan,
Minnesota,
Mississippi,

Missouri,
New
York,
North
Carolina,
Ohio,
Pennsylvania,
425
South
Carolina,
Tennessee,
Texas,
Virginia,
West
Virginia,

and
Wisconsin).
In
Table
VI­
8,
we
provide
a
list
of
the
downwind
nonattainment
counties
to
which
each
upwind
State
contributes
0.2

g/
m3
or
more
(
i.
e.,
the
upwind
State­

todownwind
nonattainment
"
linkages").

Table
VI­
7.
Maximum
Downwind
PM2.5
Contribution
(

g/
m3)
for
each
of
37
States.

Upwind
State
Maximum
Downwind
Contribution
Upwind
State
Maximum
Downwind
Contribution
Alabama
0.98
Nebraska
0.07
Arkansas
0.19
New
Hampshire
<
0.05
Connecticut
<
0.05
New
Jersey
0.13
Delaware
0.14
New
York
0.34
Florida
0.45
North
Carolina
0.31
Georgia
1.27
North
Dakota
0.11
Illinois
1.02
Ohio
1.67
Indiana
0.91
Oklahoma
0.12
Iowa
0.28
Pennsylvania
0.89
Kansas
0.11
Rhode
Island
<
0.05
Kentucky
0.90
South
Carolina
0.40
Louisiana
0.25
South
Dakota
<
0.05
Maine
<
0.05
Tennessee
0.65
Maryland/
DC
0.69
Texas
0.29
Massachusetts
0.07
Vermont
<
0.05
Michigan
0.62
Virginia
0.44
Minnesota
0.21
West
Virginia
0.84
Mississippi
0.23
Wisconsin
0.56
Missouri
1.07
426
Table
VI­
8.
Upwind
State­
to­
Downwind
Nonattainment
County
Significant
"
Linkages"
for
PM2.5.

Upwind
States
Total
Linkage
s
Downwind
Counties
AL
21
Bibb
GA
Cabell
WV
Catawba
NC
Clark
IN
Clarke
GA
Clayton
GA
Cobb
GA
Davidson
NC
DeKalb
GA
Dubois
IN
Fayette
KY
Floyd
GA
Fulton
GA
Hamilton
OH
Hamilton
TN
Jefferson
KY
Knox
TN
Lawrence
OH
Scioto
OH
Vanderburgh
IN
Walker
GA
FL
7
Bibb
GA
Clarke
GA
Clayton
GA
Cobb
GA
DeKalb
GA
Jefferson
AL
Russell
AL
GA
17
Butler
OH
Cabell
WV
Catawba
NC
Clark
IN
Davidson
NC
Fayette
KY
Hamilton
OH
Hamilton
TN
Jefferson
AL
Jefferson
KY
Kanawha
WV
Knox
TN
Lawrence
OH
Montgomery
OH
Russell
AL
Scioto
OH
Vanderburgh
IN
IL
23
Allegheny
PA
Butler
OH
Cabell
WV
Clark
IN
Cuyahoga
OH
Dubois
IN
Fayette
KY
Franklin
OH
Hamilton
OH
Hamilton
TN
Jefferson
AL
Jefferson
KY
Kanawha
WV
Lake
IN
Lawrence
OH
Mahoning
OH
Marion
IN
Montgomery
OH
Scioto
OH
Stark
OH
Summit
OH
Vanderburgh
IN
Wayne
MI
IN
46
Allegheny
PA
Beaver
PA
Berkeley
WV
Bibb
GA
Brooke
WV
Butler
OH
Cabell
WV
Cambria
PA
Catawba
NC
Clarke
GA
Clayton
GA
Cobb
GA
Cook
IL
Cuyahoga
OH
Davidson
NC
DeKalb
GA
Fayette
KY
Floyd
GA
Franklin
OH
Fulton
GA
Hamilton
OH
Hamilton
TN
Hancock
WV
Jefferson
AL
Jefferson
KY
Jefferson
OH
Kanawha
WV
Knox
TN
Lancaster
PA
Lawrence
OH
Madison
IL
Mahoning
OH
Marion
WV
Marshall
WV
Montgomery
OH
Ohio
WV
Russell
AL
St.
Clair
IL
Scioto
OH
Stark
OH
Summit
OH
Walker
GA
Wayne
MI
Washington
PA
Westmoreland
PA
Wood
WV
IA
5
Cook
IL
Lake
IN
Madison
IL
Marion
IN
St.
Clair
IL
KY
35
Allegheny
PA
Butler
OH
Cabell
WV
Catawba
NC
Clark
IN
Clarke
GA
Cobb
GA
Cuyahoga
OH
Davidson
NC
Dubois
IN
Floyd
GA
Franklin
OH
Hamilton
OH
Hamilton
TN
Jefferson
AL
Jefferson
OH
427
Kanawha
WV
Knox
TN
Lawrence
OH
Madison
IL
Mahoning
OH
Marion
IN
Marion
WV
Marshall
WV
Montgomery
OH
Ohio
WV
St.
Clair
IL
Scioto
OH
Stark
OH
Summit
OH
Vanderburgh
IN
Walker
GA
Washington
PA
Westmoreland
PA
Wood
WV
LA
2
Jefferson
AL
Russell
AL
MD/
DC
13
Berkeley
WV
Berks
PA
Cambria
PA
Dauphin
PA
Delaware
PA
District
of
Columbia
Lancaster
PA
New
Castle
DE
New
York
NY
Philadelphia
PA
Union
NJ
Westmoreland
PA
York
PA
MI
36
Allegheny
PA
Beaver
PA
Berks
PA
Brooke
WV
Butler
OH
Cabell
WV
Cambria
PA
Clark
IN
Cook
IL
Cuyahoga
OH
Dauphin
PA
Delaware
PA
Fayette
KY
Franklin
OH
Hamilton
OH
Hancock
WV
Jefferson
OH
Lake
IN
Lancaster
PA
Lawrence
OH
Mahoning
OH
Marion
IN
Marion
WV
Marshall
WV
Montgomery
OH
New
Castle
DE
Ohio
WV
Philadelphia
PA
Scioto
OH
Stark
OH
Summit
OH
Union
NJ
Washington
PA
Westmoreland
PA
Wood
WV
York
PA
MN
2
Cook
IL
Lake
IN
MO
9
Clark
IN
Cook
IL
Dubois
IN
Jefferson
KY
Lake
IN
Madison
IL
Marion
IN
St.
Clair
IL
Vanderburgh
IN
MS
1
Jefferson
AL
NY
5
Berks
PA
Lancaster
PA
New
Castle
DE
New
Haven
CT
Union
NJ
NC
7
Anne
Arundel
MD
Baltimore
City
Bibb
GA
Clarke
GA
District
of
Columbia
Kanawha
WV
Knox
TN
OH
51
Anne
Arundel
MD
Allegheny
PA
Baltimore
City
Beaver
PA
Berkeley
WV
Berks
PA
Bibb
GA
Brooke
WV
Cabell
WV
Cambria
PA
Catawba
NC
Clark
IN
Clarke
GA
Clayton
GA
Cobb
GA
Cook
IL
Dauphin
PA
Davidson
NC
DeKalb
GA
Delaware
PA
District
of
Columbia
Dubois
IN
Fayette
KY
Floyd
GA
Fulton
GA
Hamilton
TN
Hancock
WV
Jefferson
AL
Jefferson
KY
Kanawha
WV
Knox
TN
Lake
IN
Lancaster
PA
Madison
IL
Marion
IN
Marion
WV
Marshall
WV
New
Castle
DE
New
York
NY
Ohio
WV
Philadelphia
PA
Russell
AL
St.
Clair
IL
Union
NJ
Vanderburgh
IN
Walker
GA
Washington
PA
Wayne
MI
428
Westmoreland
PA
Wood
WV
York
PA
PA
25
Anne
Arundel
MD
Baltimore
City
Berkeley
WV
Brooke
WV
Cabell
WV
Catawba
NC
Clarke
GA
Cuyahoga
OH
Davidson
NC
District
of
Columbia
Hancock
WV
Jefferson
OH
Kanawha
WV
Lawrence
OH
Mahoning
OH
Marion
WV
Marshall
WV
New
Castle
DE
New
York
NY
Ohio
WV
Stark
OH
Summit
OH
Union
NJ
Wayne
MI
Wood
WV
SC
9
Bibb
GA
Catawba
NC
Clarke
GA
Clayton
GA
Cobb
GA
Davidson
NC
DeKalb
GA
Fulton
GA
Russell
AL
TN
23
Bibb
GA
Butler
OH
Cabell
WV
Catawba
NC
Clark
IN
Clarke
GA
Clayton
GA
Cobb
GA
Davidson
NC
DeKalb
GA
Dubois
IN
Fayette
KY
Floyd
GA
Fulton
GA
Hamilton
OH
Jefferson
AL
Jefferson
KY
Kanawha
WV
Lawrence
OH
Russell
AL
Scioto
OH
Vanderburgh
TN
Walker
GA
TX
2
Madison
IL
St
Clair
IL
VA
13
Anne
Arundel
MD
Baltimore
City
Berkeley
WV
Berks
PA
Catawba
NC
Dauphin
PA
Davidson
NC
Delaware
PA
District
of
Lancaster
PA
New
Castle
DE
Philadelphia
PA
York
PA
WV
33
Anne
Arundel
MD
Allegheny
PA
Baltimore
City
Beaver
PA
Berks
PA
Butler
OH
Cambria
PA
Catawba
NC
Clarke
GA
Cuyahoga
OH
Dauphin
PA
Davidson
NC
Delaware
PA
District
of
Columbia
Fayette
KY
Franklin
OH
Hamilton
OH
Jefferson
OH
Knox
TN
Lancaster
PA
Lawrence
OH
Mahoning
OH
Montgomery
OH
New
Castle
DE
New
York
NY
Philadelphia
PA
Scioto
OH
Stark
OH
Summit
OH
Union
NJ
Washington
PA
Westmoreland
PA
York
PA
WI
4
Cook
IL
Lake
IN
Marion
IN
Wayne
MI
2.
Results
of
8­
Hour
Ozone
Contribution
Modeling
In
this
section,
we
present
the
results
of
air
quality
modeling
to
determine
which
upwind
States
contribute
significantly
(
before
considering
cost)
to
8­
hour
ozone
429
104
As
noted
above,
we
combined
Maryland
and
the
District
of
Columbia
as
a
single
entity
in
our
contribution
modeling.
nonattainment
in
downwind
States.
The
analytical
procedures
to
determine
which
States
make
a
significant
contribution
are
based
on
the
zero­
out
and
source
apportionment
modeling
techniques
using
CAMx,
as
described
in
section
VI.
C.
2
and
in
the
NFR
AQMTSD.

We
performed
ozone
contribution
modeling
using
both
of
these
techniques
for
31
States
in
the
East
and
the
District
of
Columbia
(
i.
e.,
Alabama,
Arkansas,
Connecticut,
Delaware,
Georgia,

Florida,
Iowa,
Illinois,
Indiana,
Kentucky,
Louisiana,

Massachusetts,
Maine,
Maryland
combined
with
the
District
of
Columbia,
Michigan,
Minnesota,
Mississippi,
Missouri,
New
Hampshire,
New
Jersey,
New
York,
North
Carolina,
Ohio,

Pennsylvania,
Rhode
Island,
South
Carolina,
Tennessee,
Vermont,

Virginia,
West
Virginia,
and
Wisconsin).

We
evaluated
the
interstate
ozone
contributions
from
each
of
the
31
upwind
States
and
the
District
of
Columbia
to
each
of
the
40
counties
that
are
projected
to
be
nonattainment
in
the
2010
Base
Case
(
i.
e.,
"
modeled"
nonattainment)
and
are
also
"
monitored"
nonattainment
in
2001­
2003,
as
described
in
section
VI.
B.
2.
b.
We
analyzed
the
contributions
from
upwind
States
to
these
counties
in
terms
of
various
metrics,
described
above
and
in
more
detail
in
the
NFR
AQMTSD.

Based
on
the
State­
by­
State
modeling,
there
are
25
States
and
the
District
of
Columbia104
which
make
a
significant
430
This
is
a
logical
approach
because
of
the
small
size
of
the
District
of
Columbia
and,
hence,
its
emissions
and
its
close
proximity
to
Maryland.
Under
our
analysis,
Maryland
and
the
District
of
Columbia
are
linked
as
significant
contributors
to
the
same
downwind
nonattainment
counties.
EPA
received
no
adverse
comment
on
this
approach.
We
also
considered
these
entities
separately,
and
in
view
of
the
close
proximity
of
these
two
areas
we
believe
that
Maryland
is
linked
as
a
significant
contributor
to
nonattainment
in
the
District
of
Columbia
and
that
the
District
of
Columbia
is
linked
as
a
significant
contributor
to
nonattainment
in
Maryland.
contribution
(
before
considering
cost)
to
8­
hour
ozone
nonattainment
in
downwind
States
(
i.
e.,
Alabama,
Arkansas,

Connecticut,
Delaware,
the
District
of
Columbia,
Florida,
Iowa,

Illinois,
Indiana,
Kentucky,
Louisiana,
Massachusetts,
Maryland,

Michigan,
Mississippi,
Missouri,
New
Jersey,
New
York,
North
Carolina,
Ohio,
Pennsylvania,
South
Carolina,
Tennessee,

Virginia,
West
Virginia,
and
Wisconsin).
In
Table
VI­
9,
we
provide
a
list
of
the
downwind
nonattainment
counties
to
which
each
upwind
State
makes
a
significant
contribution
(
i.
e.,
the
upwind
State­
to­
downwind
nonattainment
"
linkages").
431
Table
VI­
9.
Upwind
State­
to­
Downwind
Nonattainment
County
Significant
"
Linkages"
for
8­
hour
Ozone.

Upwind
States
Total
Linkages
Downwind
Counties
AL
3
Fulton
GA
Harris
TX
Jefferson
TX
AR
3
Galveston
TX
Harris
TX
Jefferson
TX
CT
2
Kent
RI
Suffolk
NY
DE
13
Bucks
PA
Camden
NJ
Chester
PA
Gloucester
NJ
Hunterdon
NJ
Mercer
NJ
Middlesex
NJ
Monmouth
NJ
Montgomery
PA
Morris
NJ
Ocean
NJ
Philadelphia
PA
Suffolk
NY
FL
1
Fulton
GA
IA
3
Kenosha
WI
Macomb
MI
Sheboygan
WI
IL
5
Geauga
OH
Kenosha
WI
Macomb
MI
Ozaukee
WI
Sheboygan
WI
IN
5
Geauga
OH
Kenosha
WI
Macomb
MI
Ozaukee
WI
Sheboygan
WI
KY
3
Fulton
GA
Geauga
OH
Macomb
MI
LA
3
Galveston
TX
Harris
TX
Jefferson
TX
MA
2
Kent
RI
Middlesex
NJ
MD/
DC
23
Arlington
VA
Bergen
NJ
Bucks
PA
Camden
NJ
Chester
PA
District
of
Columbia
Erie
NY
Fairfax
VA
Fairfield
CT
Gloucester
NJ
Hunterton
NJ
Mercer
NJ
Middlesex
NJ
Monmouth
NJ
Montgomery
PA
Morris
NJ
New
Castle
DE
New
Haven
CT
Ocean
NJ
Philadelphia
PA
Richmond
NY
Suffolk
NY
Westchester
NY
MI
19
Anne
Arundel
MD
Bergen
NJ
Bucks
PA
Camden
NJ
Cecil
MD
Chester
PA
Erie
NY
Geauga
OH
Gloucester
NJ
Kent
MD
Mercer
NJ
Middlesex
NJ
Monmouth
NJ
Morris
NJ
New
Castle
DE
Ocean
NJ
Philadelphia
PA
Richmond
NY
Suffolk
NY
MO
4
Geauga
OH
Kenosha
WI
Ozaukee
WI
Sheboygan
WI
MS
2
Harris
TX
Jefferson
TX
NC
8
Anne
Arundel
MD
Fulton
GA
Harford
MD
Kent
MD
Newcastle
DE
Suffolk
NY
Bucks
PA
Chester
PA
NJ
10
Erie
NY
Fairfield
CT
Kent
RI
Middlesex
CT
Montgomery
PA
New
Haven
CT
Philadelphia
Richmond
NY
Suffolk
NY
Westchester
NY
NY
9
Fairfield
CT
Kent
RI
Mercer
NJ
Middlesex
CT
Middlesex
NJ
Monmouth
NJ
Morris
NJ
New
Haven
CT
Ocean
NJ
432
OH
28
Anne
Arundel
MD
Arlington
VA
Bergen
NJ
Bucks
PA
Camden
NJ
Cecil
MD
Chester
PA
District
of
Columbia
Fairfax
VA
Fairfield
CT
Gloucester
NJ
Harford
MD
Hunterton
NJ
Kent
MD
Kent
RI
Macomb
MI
Mercer
NJ
Middlesex
CT
Middlesex
NJ
Monmouth
NJ
Montgomery
PA
Morris
NJ
New
Castle
DE
New
Haven
CT
Ocean
NJ
Philadelphia
Suffolk
NY
Westchester
NY
PA
25
Anne
Arundel
MD
Arlington
VA
Bergen
NJ
Camden
NJ
Cecil
MD
District
of
Columbia
Erie
NY
Fairfax
VA
Fairfield
CT
Gloucester
NJ
Harford
MD
Hunterton
NJ
Kent
MD
Kent
RI
Mercer
NJ
Middlesex
CT
Middlesex
NJ
Monmouth
NJ
Morris
NJ
New
Castle
DE
New
Haven
CT
Ocean
NJ
Richmond
NY
Suffolk
NY
Westchester
NY
SC
1
Fulton
GA
TN
1
Fulton
GA
VA
26
Anne
Arundel
MD
Bergen
NJ
Bucks
PA
Camden
NJ
Cecil
MD
Chester
PA
District
of
Columbia
Erie
NY
Fairfield
CT
Gloucester
NJ
Harford
MD
Hunterton
NJ
Kent
MD
Kent
RI
Mercer
NJ
Middlesex
CT
Middlesex
NJ
Monmouth
NJ
Morris
NJ
New
Castle
DE
New
Haven
CT
Ocean
NJ
Philadelphia
Richmond
NY
Suffolk
NY
Westchester
NY
WI
2
Erie
NY
Macomb
MI
WV
25
Anne
Arundel
MD
Bergen
NJ
Bucks
PA
Camden
NJ
Cecil
MD
Chester
PA
Fairfax
VA
Fairfield
CT
Fulton
GA
Gloucester
NJ
Harford
MD
Hunterton
NJ
Kent
MD
Mercer
NJ
Middlesex
NJ
Monmouth
NJ
Montgomery
PA
Morris
NJ
New
Castle
DE
New
Haven
CT
Ocean
NJ
Philadelphia
Richmond
NY
Suffolk
NY
Westchester
NY
E.
What
are
the
Estimated
Air
Quality
Impacts
of
the
Final
Rule?

In
this
section,
we
describe
the
air
quality
modeling
performed
to
determine
the
projected
impacts
on
PM2.5
and
8­
hour
ozone
of
the
SO2
and
NOx
emissions
reductions
in
the
control
region
modeled.
The
modeling
used
to
estimate
the
air
quality
433
105
In
addition
to
the
SO2
and
NOx
reductions
in
these
States,
we
also
modeled
summer­
season
only
EGU
NOx
controls
for
Connecticut
and
Massachusetts,
which
significantly
contribute
to
ozone,
but
not
to
PM2.5
nonattainment
in
downwind
areas.
impact
of
these
reductions
assumes
annual
SO2
and
NOx
controls
for
Arkansas,
Delaware,
and
New
Jersey
in
addition
to
the
23­

States
plus
the
District
of
Columbia.
Since
Arkansas,
Delaware,

and
New
Jersey
are
not
included
in
the
final
CAIR
region
for
PM2.5,
the
modeled
estimated
impacts
on
PM2.5
are
overstated
for
today's
final
rule.
However,
EPA
plans
to
propose
to
include
these
three
States
in
the
CAIR
region
for
PM2.5
through
a
separate
regulatory
process.
Thus,
the
estimates
are
reflective
of
the
total
impacts
expected
for
CAIR
assuming
Arkansas,

Delaware,
and
New
Jersey
will
become
part
of
the
annual
SO2
and
NOx
trading
program.

As
discussed
in
section
IV,
EPA
analyzed
the
impacts
of
the
regional
emissions
reductions
in
both
2010
and
2015.
These
impacts
are
quantified
by
comparing
air
quality
modeling
results
for
the
regional
control
scenario
to
the
modeling
results
for
the
corresponding
2010
and
2015
Base
Case
scenarios.
The
2010
and
2015
emissions
reductions
from
the
power
generation
sector
include
a
two­
phase
cap
and
trade
program
covering
the
control
region
modeled
(
i.
e.,
the
23
States
plus
the
District
of
Columbia
included
in
today's
rule
and
Arkansas,
Delaware,
and
New
Jersey).
105
Phase
1
of
the
regional
strategy
(
the
2010
434
106
For
the
purposes
of
this
discussion,
we
have
calculated
the
percent
reduction
in
total
EGU
emissions
which
includes
units
greater
than
and
less
than
25
MW.
reductions)
is
forecast
to
reduce
total
EGU
SO2
emissions106
in
the
control
region
modeled
by
40
percent
in
2010.
Phase
2
(
the
2015
reductions)
is
forecast
to
provide
a
48
percent
reduction
in
EGU
SO2
emissions
compared
to
the
Base
Case
in
2015.
When
fully
implemented
post­
2015,
we
expect
this
rule
to
result
in
more
than
a
70
percent
reduction
in
EGU
SO2
emissions
compared
to
current
emissions
levels.
The
reductions
at
full
implementation
occur
post­
2015
due
to
the
existing
title
IV
bank
of
SO2
allowances,

which
can
be
used
under
the
CAIR
program.
The
net
effect
of
the
strategy
on
total
SO2
emissions
in
the
control
region
modeled
considering
all
sources
of
emissions,
is
a
28
percent
reduction
in
2010
and
a
32
percent
reduction
in
2015.

For
NOx,
Phase
1
of
the
strategy
is
forecast
to
reduce
total
EGU
emissions
by
44
percent
in
2009.
Total
NOx
emissions
across
the
control
region
(
i.
e.,
includes
all
sources)
are
11
percent
lower
in
the
2010
CAIR
scenario
compared
to
the
emissions
in
the
2010
Base
Case.
In
Phase
2,
EGU
NOx
emissions
are
projected
to
decline
by
54
percent
in
2015
in
this
region.
Total
NOx
emissions
from
all
anthropogenic
sources
are
projected
to
be
reduced
by
14
percent
in
2015.
The
percent
change
in
emissions
by
State
for
SO2
and
NOx
in
2010
and
2015
for
the
regional
control
strategy
modeled
are
provided
in
the
NFR
EITSD.
435
1.
Estimated
Impacts
on
PM2.5
Concentrations
and
Attainment
We
determined
the
impacts
on
PM2.5
of
the
CAIR
regional
strategy
by
running
the
CMAQ
model
for
this
strategy
and
comparing
the
results
to
the
PM2.5
concentrations
predicted
for
the
2010
and
2015
Base
Cases.
In
brief,
we
ran
the
CMAQ
model
for
the
regional
strategy
in
both
2010
and
2015.
The
model
predictions
were
used
to
project
future
PM2.5
concentrations
for
CAIR
in
2010
and
2015
using
the
SMAT
technique,
as
described
in
section
VI.
B.
1.
We
compared
the
results
of
the
2010
and
2015
regional
strategy
modeling
to
the
corresponding
results
from
the
2010
and
2015
Base
Cases
to
quantify
the
expected
impacts
of
CAIR.

The
impacts
of
the
SO2
and
NOx
emissions
reductions
expected
from
CAIR
on
PM2.5
in
2010
and
2015
are
provided
in
Table
VI­
10
and
Table
VI­
11,
respectively.
In
these
tables,
counties
shown
in
bold/
italics
are
projected
to
come
into
attainment
with
CAIR.

Table
VI­
10.
Projected
PM2.5
Concentrations
(

g/
m3)
for
the
2010
Base
Case
and
CAIR
and
the
Impact
of
CAIR
Regional
Controls
in
2010.

State
County
2010
Base
Case
2010
CAIR
Impact
of
CAIR
Alabama
DeKalb
Co
15.23
13.97
­
1.26
Alabama
Jefferson
Co
18.57
17.46
­
1.11
Alabama
Montgomery
Co
15.12
14.10
­
1.02
Alabama
Morgan
Co
15.29
14.11
­
1.18
Alabama
Russell
Co
16.17
15.15
­
1.02
Alabama
Talladega
Co
15.34
14.00
­
1.34
Delaware
New
Castle
Co
16.56
14.84
­
1.72
District
of
Columbia
15.84
13.68
­
2.16
436
State
County
2010
Base
Case
2010
CAIR
Impact
of
CAIR
Georgia
Bibb
Co
16.27
15.17
­
1.10
Georgia
Clarke
Co
16.39
14.96
­
1.43
Georgia
Clayton
Co
17.39
16.29
­
1.10
Georgia
Cobb
Co
16.57
15.35
­
1.22
Georgia
DeKalb
Co
16.75
15.70
­
1.05
Georgia
Floyd
Co
16.87
15.87
­
1.00
Georgia
Fulton
Co
18.02
16.98
­
1.04
Georgia
Hall
Co
15.60
14.28
­
1.32
Georgia
Muscogee
Co
15.65
14.57
­
1.08
Georgia
Richmond
Co
15.68
14.64
­
1.04
Georgia
Walker
Co
15.43
14.22
­
1.21
Georgia
Washington
Co
15.31
14.22
­
1.09
Georgia
Wilkinson
Co
16.27
15.22
­
1.05
Illinois
Cook
Co
17.52
16.88
­
0.64
Illinois
Madison
Co
16.66
15.96
­
0.70
Illinois
St.
Clair
Co
16.24
15.54
­
0.70
Indiana
Clark
Co
16.51
15.15
­
1.36
Indiana
Dubois
Co
15.73
14.37
­
1.36
Indiana
Lake
Co
17.26
16.48
­
0.78
Indiana
Marion
Co
16.83
15.54
­
1.29
Indiana
Vanderburgh
Co
15.54
14.26
­
1.28
Kentucky
Boyd
Co
15.23
13.38
­
1.85
Kentucky
Bullitt
Co
15.10
13.67
­
1.43
Kentucky
Fayette
Co
15.95
14.17
­
1.78
Kentucky
Jefferson
Co
16.71
15.44
­
1.27
Kentucky
Kenton
Co
15.30
13.72
­
1.58
Maryland
Anne
Arundel
Co
15.26
12.98
­
2.28
Maryland
Baltimore
city
16.96
14.88
­
2.08
Michigan
Wayne
Co
19.41
18.23
­
1.18
Missouri
St.
Louis
City
15.10
14.40
­
0.70
New
Jersey
Union
Co
15.05
13.60
­
1.45
New
York
New
York
Co
16.19
14.95
­
1.24
North
Carolina
Catawba
Co
15.48
14.07
­
1.41
North
Carolina
Davidson
Co
15.76
14.36
­
1.40
North
Carolina
Mecklenburg
Co
15.22
13.92
­
1.30
Ohio
Butler
Co
16.45
15.03
­
1.42
Ohio
Cuyahoga
Co
18.84
17.11
­
1.73
Ohio
Franklin
Co
16.98
15.13
­
1.85
Ohio
Hamilton
Co
18.23
16.61
­
1.62
Ohio
Jefferson
Co
17.94
15.64
­
2.30
Ohio
Lawrence
Co
16.10
14.11
­
1.99
Ohio
Mahoning
Co
15.39
13.40
­
1.99
437
State
County
2010
Base
Case
2010
CAIR
Impact
of
CAIR
Ohio
Montgomery
Co
15.41
13.83
­
1.58
Ohio
Scioto
Co
18.13
15.98
­
2.15
Ohio
Stark
Co
17.14
15.08
­
2.06
Ohio
Summit
Co
16.47
14.69
­
1.78
Ohio
Trumbull
Co
15.28
13.50
­
1.78
Pennsylvania
Allegheny
Co
20.55
18.01
­
2.54
Pennsylvania
Beaver
Co
15.78
13.61
­
2.17
Pennsylvania
Berks
Co
15.89
13.56
­
2.33
Pennsylvania
Cambria
Co
15.14
12.72
­
2.42
Pennsylvania
Dauphin
Co
15.17
12.88
­
2.29
Pennsylvania
Delaware
Co
15.61
13.94
­
1.67
Pennsylvania
Lancaster
Co
16.55
14.09
­
2.46
Pennsylvania
Philadelphia
Co
16.65
14.98
­
1.67
Pennsylvania
Washington
Co
15.23
12.99
­
2.24
Pennsylvania
Westmoreland
Co
15.16
12.60
­
2.56
Pennsylvania
York
Co
16.49
14.20
­
2.29
Tennessee
Davidson
Co
15.36
14.26
­
1.10
Tennessee
Hamilton
Co
16.89
15.57
­
1.32
Tennessee
Knox
Co
17.44
16.16
­
1.28
Tennessee
Sullivan
Co
15.32
14.01
­
1.31
West
Virginia
Berkeley
Co
15.69
13.43
­
2.26
West
Virginia
Brooke
Co
16.63
14.42
­
2.21
West
Virginia
Cabell
Co
17.03
15.08
­
1.95
West
Virginia
Hancock
Co
17.06
14.89
­
2.17
West
Virginia
Kanawha
Co
17.56
15.27
­
2.29
West
Virginia
Marion
Co
15.32
12.90
­
2.42
West
Virginia
Marshall
Co
15.81
13.46
­
2.35
West
Virginia
Ohio
Co
15.14
12.81
­
2.33
West
Virginia
Wood
Co
16.66
14.14
­
2.52
Table
VI­
11.
Projected
PM2.5
Concentrations
(

g/
m3)
for
the
2015
Base
Case
and
CAIR
and
the
Impact
of
CAIR
Regional
Controls
in
2015.

State
County
2015
Base
Case
2015
CAIR
Impact
of
CAIR
Alabama
DeKalb
Co
15.24
13.46
­
1.78
Alabama
Jefferson
Co
18.85
17.36
­
1.49
Alabama
Montgomery
Co
15.24
13.87
­
1.37
Alabama
Morgan
Co
15.26
13.85
­
1.41
Alabama
Russell
Co
16.10
14.66
­
1.44
438
State
County
2015
Base
Case
2015
CAIR
Impact
of
CAIR
Alabama
Talladega
Co
15.22
13.35
­
1.87
Delaware
New
Castle
Co
16.47
14.41
­
2.06
District
of
Columbia
15.57
13.11
­
2.46
Georgia
Bibb
Co
16.41
14.83
­
1.58
Georgia
Chatham
Co
15.06
13.86
­
1.20
Georgia
Clarke
Co
16.15
14.10
­
2.05
Georgia
Clayton
Co
17.46
15.85
­
1.61
Georgia
Cobb
Co
16.51
14.67
­
1.84
Georgia
DeKalb
Co
16.82
15.29
­
1.53
Georgia
Floyd
Co
17.33
15.79
­
1.54
Georgia
Fulton
Co
18.00
16.47
­
1.53
Georgia
Hall
Co
15.36
13.48
­
1.88
Georgia
Muscogee
Co
15.58
14.06
­
1.52
Georgia
Richmond
Co
15.76
14.23
­
1.53
Georgia
Walker
Co
15.37
13.65
­
1.72
Georgia
Washington
Co
15.34
13.67
­
1.67
Georgia
Wilkinson
Co
16.54
15.01
­
1.53
Illinois
Cook
Co
17.71
16.95
­
0.76
Illinois
Madison
Co
16.90
16.07
­
0.83
Illinois
St.
Clair
Co
16.49
15.64
­
0.85
Illinois
Will
Co
15.12
14.27
­
0.85
Indiana
Clark
Co
16.37
14.79
­
1.58
Indiana
Dubois
Co
15.66
14.16
­
1.50
Indiana
Lake
Co
17.27
16.36
­
0.91
Indiana
Marion
Co
16.77
15.38
­
1.39
Indiana
Vanderburgh
Co
15.56
14.17
­
1.39
Kentucky
Boyd
Co
15.06
12.95
­
2.11
Kentucky
Fayette
Co
15.62
13.54
­
2.08
Kentucky
Jefferson
Co
16.61
15.13
­
1.48
Kentucky
Kenton
Co
15.09
13.26
­
1.83
Maryland
Baltimore
city
17.04
14.50
­
2.54
Maryland
Baltimore
Co
15.08
12.75
­
2.33
Michigan
Wayne
Co
19.28
17.95
­
1.33
Mississippi
Jones
Co
15.18
14.06
­
1.12
Missouri
St.
Louis
city
15.34
14.50
­
0.84
New
York
New
York
Co
15.76
14.33
­
1.43
North
Carolina
Catawba
Co
15.19
13.45
­
1.74
North
Carolina
Davidson
Co
15.34
13.61
­
1.73
Ohio
Butler
Co
16.32
14.67
­
1.65
Ohio
Cuyahoga
Co
18.60
16.67
­
1.93
Ohio
Franklin
Co
16.64
14.57
­
2.07
Ohio
Hamilton
Co
18.03
16.10
­
1.93
439
State
County
2015
Base
Case
2015
CAIR
Impact
of
CAIR
Ohio
Jefferson
Co
17.83
15.26
­
2.57
Ohio
Lawrence
Co
15.92
13.71
­
2.21
Ohio
Mahoning
Co
15.13
12.94
­
2.19
Ohio
Montgomery
Co
15.16
13.33
­
1.83
Ohio
Scioto
Co
17.92
15.55
­
2.37
Ohio
Stark
Co
16.86
14.58
­
2.28
Ohio
Summit
Co
16.14
14.18
­
1.96
Ohio
Trumbull
Co
15.05
13.08
­
1.97
Pennsylvania
Allegheny
Co
20.33
17.47
­
2.86
Pennsylvania
Beaver
Co
15.54
13.09
­
2.45
Pennsylvania
Berks
Co
15.66
12.99
­
2.67
Pennsylvania
Delaware
Co
15.52
13.52
­
2.00
Pennsylvania
Lancaster
Co
16.28
13.33
­
2.95
Pennsylvania
Philadelphia
Co
16.53
14.53
­
2.00
Pennsylvania
York
Co
16.22
13.46
­
2.76
Tennessee
Davidson
Co
15.36
14.02
­
1.34
Tennessee
Hamilton
Co
16.82
14.94
­
1.88
Tennessee
Knox
Co
17.34
15.61
­
1.73
Tennessee
Shelby
Co
15.17
14.19
­
0.98
Tennessee
Sullivan
Co
15.37
13.77
­
1.60
West
Virginia
Berkeley
Co
15.32
12.73
­
2.59
West
Virginia
Brooke
Co
16.51
14.05
­
2.46
West
Virginia
Cabell
Co
16.86
14.64
­
2.22
West
Virginia
Hancock
Co
16.97
14.54
­
2.43
West
Virginia
Kanawha
Co
17.17
14.66
­
2.51
West
Virginia
Marshall
Co
15.52
12.87
­
2.65
West
Virginia
Wood
Co
16.69
13.88
­
2.81
As
described
in
section
VI.
B.
1,
we
project
that
79
counties
in
the
East
will
be
nonattainment
for
PM2.5
in
the
2010
Base
Case.
We
estimate
that,
on
average,
the
regional
strategy
will
reduce
PM2.5
in
these
79
counties
by
1.6

g/
m3.
In
over
90
percent
of
the
nonattainment
counties
(
i.
e.,
74
out
of
79
counties),
we
project
that
PM2.5
will
be
reduced
by
at
least
1.0
440

g/
m3.
In
over
25
percent
of
the
79
nonattainment
counties
(
i.
e.,
23
of
the
79
counties),
we
project
PM2.5
concentrations
will
decline
by
of
more
than
2.0

g/
m3.
Of
the
79
counties
that
are
nonattainment
in
the
2010
Base,
we
project
that
51
counties
will
come
into
attainment
as
a
result
of
the
SO2
and
NOx
emissions
reductions
expected
from
the
regional
controls.
Even
those
28
counties
that
remain
nonattainment
in
2010
after
implementation
of
the
regional
strategy
will
be
closer
to
attainment
as
a
result
of
these
emissions
reductions.

Specifically,
the
average
reduction
of
PM2.5
in
the
28
residual
nonattainment
counties
is
projected
to
be
1.3

g/
m3.
After
implementation
of
the
regional
controls,
we
project
that
18
of
the
28
residual
nonattainment
counties
in
2010
will
be
within
1.0

g/
m3
of
the
NAAQS
and
12
counties
will
be
within
0.5

g/
m3
of
attainment.

In
2015
we
are
projecting
that
PM2.5
in
the
74
Base
Case
nonattainment
counties
will
be
reduced
by
1.8

g/
m3,
on
average,

as
a
result
of
the
SO2
and
NOx
reductions
in
the
regional
strategy.
In
over
90
percent
of
the
nonattainment
counties
(
i.
e.,
67
of
the
74
counties)
concentrations
of
PM2.5
are
predicted
to
be
reduced
by
at
least
1.0

g/
m3.
In
over
35
percent
of
the
counties
(
i.
e.,
27
of
the
74
counties),
we
project
the
regional
strategy
to
reduce
PM2.5
by
more
than
2.0

g/
m3.
As
a
result
of
the
reductions
in
PM2.5,
56
nonattainment
counties
are
projected
to
come
into
attainment
in
2015.
The
remaining
18
441
nonattainment
counties
are
projected
to
be
closer
to
attainment
with
the
regional
strategy.
Our
modeling
results
indicate
that
PM2.5
will
be
reduced
in
the
range
of
0.7

g/
m3
to
2.9

g/
m3
in
these
18
counties.
The
average
reduction
across
these
18
residual
nonattainment
counties
is
1.5

g/
m3.

Thus,
the
SO2
and
NOx
emissions
reductions
which
will
result
from
the
regional
strategy
will
greatly
reduce
the
extent
of
PM2.5
nonattainment
by
2010
and
beyond.
These
emissions
reductions
are
expected
to
substantially
reduce
the
number
of
PM2.5
nonattainment
counties
in
the
East
and
make
attainment
easier
for
those
counties
that
remain
nonattainment
by
substantially
lowering
PM2.5
concentrations
in
these
residual
nonattainment
counties.

2.
Estimated
Impacts
on
8­
Hour
Ozone
Concentrations
and
Attainment
We
determined
the
impacts
on
8­
hour
ozone
of
the
regional
strategy
by
running
the
CAMx
model
for
this
strategy
and
comparing
the
results
to
the
ozone
concentrations
predicted
for
the
2010
and
2015
Base
Cases.
In
brief,
we
ran
the
CAMx
model
for
the
regional
strategy
in
both
2010
and
2015.
The
model
predictions
were
used
to
project
future
8­
hour
ozone
concentrations
for
the
regional
strategy
in
2010
and
2015
using
the
Relative
Reduction
Factor
technique,
as
described
in
section
VI.
B.
1.
We
compared
the
results
of
the
2010
and
2015
regional
442
strategy
modeling
to
the
corresponding
results
from
the
2010
and
2015
Base
Cases
to
quantify
the
expected
impacts
of
the
regional
controls.

The
results
of
the
regional
strategy
ozone
modeling
are
expressed
in
terms
of
the
expected
reductions
in
projected
8­
hour
concentrations
and
the
implications
for
future
nonattainment.

The
impacts
of
the
regional
NOx
emissions
reductions
on
8­
hour
ozone
in
2010
and
2015
are
provided
in
Table
VI­
12
and
Table
VI­

13,
respectively.
In
these
tables,
counties
shown
in
bold/
italics
are
projected
to
come
into
attainment
with
the
regional
controls.

Table
VI­
12.
Projected
8­
hour
Concentrations
(
ppb)
for
the
2010
Base
Case
and
CAIR
and
the
Impact
of
CAIR
Regional
Controls
in
2010.

State
County
2010
Base
Case
2010
CAIR
Impact
of
CAIR
Connecticut
Fairfield
Co
92.6
92.2
­
0.4
Connecticut
Middlesex
Co
90.9
90.6
­
0.3
Connecticut
New
Haven
Co
91.6
91.3
­
0.3
District
of
Columbia
District
of
Columbia
85.2
85.0
­
0.2
Delaware
New
Castle
Co
85.0
84.7
­
0.3
Georgia
Fulton
Co
86.5
85.1
­
1.4
Maryland
Anne
Arundel
Co
88.8
88.6
­
0.2
Maryland
Cecil
Co
89.7
89.5
­
0.2
Maryland
Harford
Co
93.0
92.8
­
0.2
Maryland
Kent
Co
86.2
85.8
­
0.4
Michigan
Macomb
Co
85.5
85.4
­
0.1
New
Jersey
Bergen
Co
86.9
86.0
­
0.9
New
Jersey
Camden
Co
91.9
91.6
­
0.3
New
Jersey
Gloucester
Co
91.8
91.3
­
0.5
New
Jersey
Hunterdon
Co
89.0
88.6
­
0.4
New
Jersey
Mercer
Co
95.6
95.2
­
0.4
443
State
County
2010
Base
Case
2010
CAIR
Impact
of
CAIR
New
Jersey
Middlesex
Co
92.4
92.1
­
0.3
New
Jersey
Monmouth
Co
86.6
86.4
­
0.2
New
Jersey
Morris
Co
86.5
85.5
­
1.0
New
Jersey
Ocean
Co
100.5
100.3
­
0.2
New
York
Erie
Co
87.3
86.9
­
0.4
New
York
Richmond
Co
87.3
87.1
­
0.2
New
York
Suffolk
Co
91.1
90.8
­
0.3
New
York
Westchester
Co
85.3
84.7
­
0.6
Ohio
Geauga
Co
87.1
86.6
­
0.5
Pennsylvania
Bucks
Co
94.7
94.3
­
0.4
Pennsylvania
Chester
Co
85.7
85.4
­
0.3
Pennsylvania
Montgomery
Co
88.0
87.6
­
0.4
Pennsylvania
Philadelphia
Co
90.3
89.9
­
0.4
Rhode
Island
Kent
Co
86.4
86.2
­
0.2
Texas
Denton
Co
87.4
86.8
­
0.6
Texas
Galveston
Co
85.1
84.6
­
0.5
Texas
Harris
Co
97.9
97.4
­
0.5
Texas
Jefferson
Co
85.6
85.0
­
0.6
Texas
Tarrant
Co
87.8
87.2
­
0.6
Virginia
Arlington
Co
86.2
86.0
­
0.2
Virginia
Fairfax
Co
85.7
85.4
­
0.3
Wisconsin
Kenosha
Co
91.3
91.0
­
0.3
Wisconsin
Ozaukee
Co
86.2
85.8
­
0.4
Wisconsin
Sheboygan
Co
88.3
87.7
­
0.6
Table
VI­
13.
Projected
8­
hour
Concentrations
(
ppb)
for
the
2015
Base
Case
and
CAIR
and
the
Impact
of
CAIR
Regional
Controls
in
2015.

State
County
2015
Base
Case
2015
CAIR
Impact
of
CAIR
Connecticut
Fairfield
Co
91.4
90.6
­
0.8
Connecticut
Middlesex
Co
89.1
88.4
­
0.7
444
State
County
2015
Base
Case
2015
CAIR
Impact
of
CAIR
Connecticut
New
Haven
Co
89.8
89.1
­
0.7
Maryland
Anne
Arundel
Co
86.0
84.9
­
1.1
Maryland
Cecil
Co
86.9
85.4
­
1.5
Maryland
Harford
Co
90.6
89.6
­
1.0
Michigan
Macomb
Co
85.1
84.2
­
0.9
New
Jersey
Bergen
Co
85.7
84.5
­
1.2
New
Jersey
Camden
Co
89.5
88.3
­
1.2
New
Jersey
Gloucester
Co
89.6
88.2
­
1.4
New
Jersey
Hunterdon
Co
86.5
85.4
­
1.1
New
Jersey
Mercer
Co
93.5
92.4
­
1.1
New
Jersey
Middlesex
Co
89.8
88.8
­
1.0
New
Jersey
Ocean
Co
98.0
96.9
­
1.1
New
York
Erie
Co
85.2
84.2
­
1.0
New
York
Suffolk
Co
89.9
89.0
­
0.9
Pennsylvania
Bucks
Co
93.0
91.8
­
1.2
Pennsylvania
Montgomery
Co
86.5
84.9
­
1.6
Pennsylvania
Philadelphia
Co
88.9
87.5
­
1.4
Texas
Harris
Co
97.3
96.4
­
0.9
Texas
Jefferson
Co
85.0
84.1
­
0.9
Wisconsin
Kenosha
Co
89.4
88.8
­
0.6
As
described
in
section
VI.
B.
1,
we
project
that
40
counties
in
the
East
would
be
nonattainment
for
8­
hour
ozone
under
the
assumptions
in
the
2010
Base
Case.
Our
modeling
of
the
regional
controls
in
2010
indicates
that
3
of
these
counties
will
come
into
attainment
of
the
8­
hour
ozone
NAAQS
and
that
ozone
in
16
of
the
40
nonattainment
counties
will
be
reduced
by
1
ppb
or
more.
In
addition,
our
modeling
predicts
that
8­
hour
ozone
exceedances
(
i.
e.,
8­
hour
ozone
of
85
ppb
or
higher)
within
nonattainment
areas
are
expected
to
decline
by
5
percent
in
2010
with
CAIR.
Of
the
37
counties
that
are
projected
to
remain
445
nonattainment
in
2010
after
the
regional
strategy,
nearly
half
(
i.
e.,
16
of
the
37
counties)
are
within
2
ppb
of
attainment.

In
2015,
we
project
that
6
of
the
22
counties
which
are
nonattainment
for
8­
hour
ozone
in
the
Base
Case
will
come
into
attainment
with
the
regional
strategy.
Ozone
concentrations
in
over
70
percent
(
i.
e.,
16
of
22
counties)
of
the
2015
Base
Case
nonattainment
counties
are
projected
to
be
reduced
by
1
ppb
or
more
as
a
result
of
the
regional
strategy.
Exceedances
of
the
8­
hour
ozone
NAAQS
are
predicted
to
decline
in
nonattainment
areas
by
14
percent
with
regional
controls
in
place
in
2015.

Thus,
the
NOx
emissions
reductions
which
will
result
from
the
regional
strategy
will
help
to
bring
8­
hour
ozone
nonattainment
areas
in
the
East
closer
to
attainment
by
2010
and
beyond.

F.
What
are
the
Estimated
Visibility
Impacts
of
the
Final
Rule?

1.
Methods
for
Calculating
Projected
Visibility
in
Class
I
Areas
The
NPR
contained
example
future
year
visibility
projections
for
the
20
percent
worst
days
and
20
percent
best
days
at
Class
I
areas
that
had
complete
IMPROVE
monitoring
data
in
1996.
Changes
in
future
visibility
were
predicted
by
using
the
REMSAD
model
to
generate
relative
visibility
changes,
then
applying
those
changes
to
measured
current
visibility
data.

Details
of
the
visibility
modeling
and
calculations
can
be
found
in
the
NPR
AQMTSD.
An
example
visibility
calculation
was
given
in
Appendix
M
of
the
NPR
AQMTSD
along
with
the
predicted
446
107
The
CAIR
scenario
modeled
for
the
visibility
analysis
included
controls
in
Arkansas,
Delaware,
and
New
Jersey.
improvement
in
visibility
(
in
deciviews)
on
the
20
percent
best
and
worst
days
at
44
Class
I
areas.
The
data
contained
in
Appendix
M
was
for
informational
purposes
only
and
was
not
used
in
the
significant
contribution
determination
or
control
strategy
development
decisions.

The
SNPR
contained
visibility
calculations
in
support
of
the
"
better­
than­
BART"
analysis.
The
better­
than­
BART
analysis
employed
a
two­
pronged
test
to
determine
if
the
modeled
visibility
improvements
from
the
CAIR
cap
and
trade
program
for
EGU's
were
"
better"
than
the
visibility
improvements
from
a
nationwide
BART
program.
The
analysis
used
the
visibility
calculation
methodology
detailed
in
the
NPR
TSD.
Detailed
results
of
the
SNPR
better­
than­
BART
analysis
are
contained
in
the
SNPR
AQMTSD.
The
better­
than­
BART
analysis
for
the
final
rule
is
addressed
in
section
IX.
C.
2
of
the
preamble.
Additional
information
on
the
visibility
calculation
methodology
is
contained
in
the
NFR
AQMTSD.

2.
Visibility
Improvements
in
Class
I
Areas
For
the
NFR
we
have
modeled
several
new
CAIR107
and
CAIR
+

BART
cases
to
re­
examine
the
better­
than­
BART
two­
pronged
test.

We
have
modeled
an
updated
nationwide
BART
scenario
as
well
as
a
CAIR
in
the
East/
BART
in
the
West
scenario.
The
results
were
analyzed
at
116
Class
I
areas
that
have
complete
IMPROVE
data
447
for
2001
or
are
represented
by
IMPROVE
monitors
with
complete
data.
Twenty
nine
of
the
Class
I
areas
are
in
the
East
and
87
are
in
the
West.
The
results
of
the
visibility
analysis
are
summarized
in
section
IX.
C.
2.
Detailed
results
for
all
116
Class
I
areas
are
presented
in
the
NFR
AQMTSD.

VII.
SIP
Criteria
and
Emissions
Reporting
Requirements
This
section
describes:
(
1)
the
criteria
we
will
use
in
determining
approvability
of
SIPs
submitted
to
meet
the
requirements
of
today's
rulemaking;
(
2)
the
dates
for
submittal
of
the
SIPs
that
are
required
under
the
CAIR;
(
3)
the
consequences
of
either
failing
to
submit
such
a
SIP
or
submitting
a
SIP
which
is
disapproved;
and
(
4)
the
emissions
inventory
reporting
requirements
for
States.

A.
What
Criteria
Will
EPA
Use
to
Evaluate
the
Approvability
of
a
Transport
SIP?

1.
Introduction
The
approvability
criteria
for
CAIR
SIP
submissions
are
finalized
today
in
40
CFR
51.123
(
NOx
emissions
reductions)
and
in
40
CFR
51.124
(
SO2
emissions
reductions).
Most
of
the
criteria
are
substantially
similar
to
those
that
currently
apply
to
SIP
submissions
under
CAA
section
110
or
part
D
448
(
nonattainment).
For
example,
each
submission
must
describe
the
control
measures
that
the
State
intends
to
employ,
identify
the
enforcement
methods
for
monitoring
compliance
and
managing
violations,
and
demonstrate
that
the
State
has
legal
authority
to
carry
out
its
plan.

This
part
of
the
preamble
explains
additional
approvability
criteria
specific
to
the
CAIR
that
were
proposed
and
discussed
in
the
CAIR
NPR
or
in
the
CAIR
SNPR,
and
are
being
promulgated
today.
As
explained
in
both
the
CAIR
NPR
and
the
CAIR
SNPR,
EPA
proposed
that
each
affected
State
must
submit
SIP
revisions
containing
control
measures
that
assure
that
a
specified
amount
of
NOx
and
SO2
emissions
reductions
are
achieved
by
specified
dates.

Although
EPA
determined
the
amount
of
emissions
reductions
required
by
identifying
specific,
highly
cost­
effective
control
levels
for
EGUs,
EPA
explained
in
the
CAIR
NPR
and
the
CAIR
SNPR
that
States
have
flexibility
in
choosing
which
sources
to
control
to
achieve
the
required
emissions
reductions.
As
long
as
a
State's
emissions
reductions
requirements
are
met,
a
State
may
impose
controls
on
EGUs
only,
on
non­
EGUs
only,
or
on
a
combination
of
EGUs
and
non­
EGUs.
The
SIP
approvability
criteria
are
intended
to
provide
as
much
certainty
as
possible
that,
whichever
sources
a
State
chooses
to
control,
the
controls
will
result
in
the
required
amount
of
emissions
reductions.
449
In
the
CAIR
NPR,
EPA
proposed
a
"
hybrid"
approach
for
the
mechanisms
used
to
ensure
emissions
reductions
are
achieved.

This
approach
incorporates
elements
of
an
emissions
"
budget"

approach
(
requiring
an
emissions
cap
on
affected
sources)
and
an
"
emissions
reduction"
approach
(
not
requiring
an
emissions
cap).

In
this
hybrid
approach,
if
States
impose
control
measures
on
EGUs,
they
would
be
required
to
impose
an
emissions
cap
on
all
EGUs,
which
would
effectively
be
an
emissions
budget.
And,
as
stated
in
the
CAIR
NPR,
if
States
impose
control
measures
on
non­
EGUs,
they
would
be
encouraged
but
not
required
to
impose
an
emissions
cap
on
non­
EGUs.
In
the
CAIR
NPR,
we
requested
comment
on
the
issue
of
requiring
States
to
impose
caps
on
any
source
categories
that
the
State
chooses
to
regulate.

In
the
CAIR
SNPR,
we
proposed
to
modify
the
hybrid
approach
and
require
States
that
choose
to
control
large
industrial
boilers
or
turbines
(
greater
than
250
MMBTU/
hr)
to
impose
an
emissions
cap
on
all
such
sources
within
their
State.
This
is
similar
to
EPA's
approach
in
the
NOx
SIP
Call
which
required
States
to
include
an
emissions
cap
on
such
sources
as
well
as
on
EGUs
if
the
SIP
submittals
included
controls
on
such
sources.

(
See
40
CFR
51.121(
f)(
2)(
ii).)

A
few
commenters
supported
the
use
of
emissions
caps
on
any
source
category
subject
to
CAIR
controls,
including
non­
EGUs,

because
it
would
be
the
most
effective
way
to
demonstrate
compliance
with
the
budget.
A
few
other
commenters
opposed
the
450
use
of
an
emissions
cap
on
non­
EGUs,
saying
either
that
States
should
have
the
flexibility
to
determine
whether
to
impose
a
cap,
or
that
such
a
requirement
would
result
in
increased
costs
for
non­
EGUs
including
cogeneration
units
that
are
non­
EGUs.
No
commenter
opposing
such
a
requirement
provided
any
information
indicating
that
such
a
requirement
would
be
ineffective
or
impracticable.
Today
EPA
is
adopting
the
modified
approach,
as
described
in
the
CAIR
SNPR,
that
States
choosing
to
control
EGUs
or
large
industrial
boilers
or
turbines
must
do
so
by
imposing
an
emissions
cap
on
such
sources,
similar
to
what
was
required
in
the
NOx
SIP
Call.

Extensive
comments
were
received
regarding
the
need
for
an
ozone
season
NOx
cap
in
States
identified
to
be
contributing
significantly
to
the
region's
ozone
nonattainment
problems.
In
proposal,
EPA
stated
that
the
annual
NOx
cap
under
CAIR
reduced
NOx
emissions
sufficiently
enough
to
not
warrant
a
regional
ozone
season
NOx
cap.
Commenters
remained
very
concerned
that
the
annual
NOx
cap
would
not
aid
ozone
attainment.
While
EPA
feels
that
the
annual
NOx
limit
will
most
likely
be
protective
in
the
ozone
season,
a
seasonal
cap
will
provide
certainty,

which
EPA
agrees
is
very
important
in
the
effort
to
help
areas
achieve
ozone
attainment.
Today,
EPA
is
finalizing
an
ozone
season
NOx
cap
for
States
shown
to
contribute
significantly
for
ozone.
As
is
further
explained
in
section
VIII,
EPA
is
also
finalizing
an
ozone
season
trading
program
that
States
may
use
451
to
achieve
the
required
emissions
reductions.
This
program
will
subsume
the
existing
NOx
SIP
Call
trading
program.
Therefore,

any
State
that
wishes
to
continue
including
its
sources
in
an
interstate
trading
program
run
by
EPA
to
achieve
the
emissions
reductions
required
by
EPA
must
modify
its
SIP
to
conform
with
this
new
trading
program.

The
EPA
will
automatically
find
that
a
State
is
continuing
to
meet
its
NOx
SIP
Call
obligation
if
it
achieves
all
of
its
required
CAIR
emissions
reductions
by
capping
EGUs,
it
modifies
its
existing
NOx
SIP
Call
to
require
its
non­
EGUs
currently
participating
in
the
NOx
SIP
Call
budget
trading
program
to
conform
to
the
requirements
of
the
CAIR
ozone
season
NOx
trading
program
with
a
trading
budget
that
is
the
same
or
tighter
than
the
budget
in
the
currently
approved
SIP,
and
it
does
not
modify
any
of
its
other
existing
NOx
SIP
Call
rules.
If
a
State
chooses
to
achieve
the
ozone
season
NOx
emissions
reduction
requirements
of
CAIR
in
another
way,
it
will
also
be
required
to
demonstrate
that
it
continues
to
meet
the
requirements
of
the
NOx
SIP
Call.

Specific
criteria
for
approval
of
CAIR
SIP
submissions
as
promulgated
by
today's
action
are
described
below.
The
criteria
are
dependent
on
the
types
of
sources
a
State
chooses
to
control.

2.
Requirements
for
States
Choosing
to
Control
EGUs
452
a.
Emissions
Caps
and
Monitoring
As
explained
in
the
CAIR
NPR
(
69
FR
4626),
and
in
the
CAIR
SNPR
(
69
FR
32691),
EPA
proposed
requiring
States
to
apply
the
"
budget"
approach
if
they
choose
to
control
EGUs;
that
is,
each
State
must
cap
total
EGU
emissions
at
the
level
that
assures
the
appropriate
amount
of
reductions
for
that
State.
The
requirement
to
cap
all
EGUs
is
important
because
it
prevents
shifting
of
utilization
(
and
resulting
emissions)
to
uncapped
EGUs.
The
EGUs
are
part
of
a
highly
interconnected
electricity
grid
that
makes
utilization
shifting
likely
and
even
common.

The
units
are
large
and
offer
the
same
market
product
(
i.
e.,

electricity),
and
therefore
the
units
that
are
least
expensive
to
operate
are
likely
to
be
operated
as
much
as
possible.
If
capped
and
uncapped
units
are
interconnected,
the
uncapped
units'
costs
would
tend
to
decrease
relative
to
the
capped
units,
which
must
either
reduce
emissions
or
use
or
buy
allowances,
and
the
uncapped
units'
utilization
would
likely
increase.
The
cap
ensures
that
emissions
reductions
from
these
interconnected
sources
are
actually
achieved
rather
than
emissions
simply
shifting
among
sources.
The
caps
constitute
the
State
EGU
Budgets
for
SO2
and
NOx.
Additionally,
EPA
proposed
that,
if
States
choose
to
control
EGUs,
they
must
require
EGUs
to
follow
part
75
monitoring,
recordkeeping,
and
reporting
requirements.
Part
75
monitoring
and
reporting
453
requirements
have
been
used
effectively
for
determining
NOx
and
SO2
emissions
from
EGUs
under
the
title
IV
Acid
Rain
program
and
the
NOx
SIP
Call
program
and
in
combination
with
emissions
caps
are
an
integral
part
of
those
programs.
(
Additional
explanation
for
the
need
for
Part
75
monitoring
is
given
in
the
NPR
and
SNPR
and
is
incorporated
here.)
Therefore,
today,
EPA
adopts
the
requirements
for
emission
caps
and
Part
75
monitoring
for
EGUs
in
these
States.

b.
Using
the
Model
Trading
Rules
As
proposed,
if
a
State
chooses
to
allow
its
EGUs
to
participate
in
EPA­
administered
interstate
NOx
and
SO2
emissions
trading
programs,
the
State
must
adopt
EPA's
model
trading
rules,
as
described
elsewhere
in
today's
preamble
and
in
§
§
96.101­­
96.176
(
for
NOx)
and
§
§
96.201­­
96.276
(
for
SO2),
set
forth
below.
Additionally,
EPA
proposed
that
for
the
States
for
which
EPA
made
a
finding
of
significant
contribution
for
both
ozone
and
PM2.5,
participation
in
both
the
NOx
and
SO2
trading
programs
would
be
required
in
order
to
be
included
in
the
EPAadministered
program.
States
for
which
the
finding
was
for
ozone
only
could
choose
to
participate
in
only
the
EPAadministered
NOx
trading
program
through
adoption
of
the
NOx
model
trading
rule.
The
EPA
stated
that
States
adopting
EPA's
model
trading
rules,
modified
only
as
specifically
allowed
by
EPA,
will
meet
the
requirement
for
applying
an
emissions
cap
and
454
requirement
to
use
part
75
monitoring,
recordkeeping,
and
reporting
for
EGUs.

Some
commenters
opposed
EPA's
proposal
to
require
participation
in
both
the
NOx
and
SO2
trading
programs
because
some
States
may
want
to
participate
in
the
EPA­
administered
trading
programs
for
only
NOx
or
only
SO2.
A
few
commenters
claimed
that
the
requirement
to
participate
in
both
programs
would
limit
State
flexibility
or
is
an
"
all
or
nothing"

approach;
other
commenters
objected
that
there
was
no
environmental
basis
for
such
a
requirement;
and
one
commenter
suggested
that
States
not
affected
by
CAIR
but
that
volunteer
to
control
emissions
should
be
permitted
to
join
the
program
for
one
or
both
pollutants.
Additionally,
commenters
cited
a
need
for
an
ozone
season
NOx
program.

The
EPA
has
taken
the
comments
into
account
and
in
today's
action
agrees
to
allow
a
State
identified
to
contribute
significantly
for
PM2.5
(
and
therefore
required
to
make
annual
SO2
and
NOx
reductions)
to
participate
in
the
EPA­
administered
CAIR
trading
program
for
either
SO2
or
NOx,
not
necessarily
both,
so
long
as
the
State
adopts
the
model
rule
for
the
applicable
trading
program.

In
response
to
extensive
comments
relating
to
EPA's
proposal
to
forego
a
seasonal
NOx
cap
because
EPA
demonstrated
that
the
annual
NOx
cap
was
sufficiently
stringent,
EPA
is
finalizing
an
ozone
season
NOx
trading
program
for
States
455
identified
as
contributing
significantly
for
ozone.
These
States
will
be
subject
to
an
ozone
season
NOx
cap
and
an
annual
NOx
cap
if
the
State
is
also
identified
as
contributing
significantly
for
PM
2.5.
Therefore,
today's
action
includes
an
additional
model
rule
for
an
ozone
season
NOx
trading
program
(
40
CFR
96,
subparts
AAAA
through
IIII).
The
States
that
may
use
the
ozone
season
NOx
trading
program
but
not
the
annual
NOx
trading
program
are
those
States
in
the
CAIR
region
identified
as
contributing
significantly
for
ozone
only
(
Arkansas,

Connecticut,
Delaware,
Massachusetts,
and
New
Jersey).

As
discussed
in
the
proposal,
EPA
is
finalizing
the
option
for
New
Hampshire
and
Rhode
Island
to
participate
in
the
regional
trading
program
through
use
of
the
CAIR
ozone
season
NOx
model
rule
because
sources
in
these
States
have
made
investments
in
NOx
controls
in
the
past
based
on
the
existence
of
a
regional
ozone
season
NOx
trading
program.
Additionally,

the
States'
combined
projected
2010
and
2015
NOx
emissions
are
less
than
one­
half
of
one
percent
of
the
total
CAIR
regional
NOx
cap
and
therefore
would
not
create
a
significant
increase
in
the
CAIR
cap.
All
comments
received
were
supportive
of
this
approach
and
EPA
is
finalizing
it
today.

None
of
these
States
(
Arkansas,
Connecticut,
Delaware,

Massachusetts,
New
Hampshire,
New
Jersey,
or
Rhode
Island)
has
the
option
to
participate
in
the
EPA­
administered
CAIR
SO2
trading
program
nor
the
annual
CAIR
NOx
trading
program
because
456
108Title
IV
allowances
can
however
be
traded
freely
across
the
boundary
of
the
CAIR
region
without
any
significant,
negative
environmental
consequence.
The
potential
negative
consequences
have
been
addressed
through
other
requirements
discussed
below,
like
the
retirement
of
excess
title
IV
allowances.
there
are
no
PM2.5­
related
emissions
reductions
required
under
today's
action
in
those
States.
(
Of
course,
sources
in
these
States
will
still
be
subject
to
the
Acid
Rain
SO2
cap­
and­
trade
program.)
Likewise,
Texas,
Minnesota
and
Georgia
may
not
participate
in
the
ozone
season
NOx
program,
because
they
have
not
been
shown
to
contribute
significantly
to
the
regional
ozone
problem.
They
are,
however,
required
to
make
annual
NOx
and
SO2
reductions
and
may
choose
to
participate
in
the
annual
NOx
and
annual
SO2
trading
program
to
meet
their
CAIR
obligations.

Except
for
the
special
cases
of
Rhode
Island
and
New
Hampshire,
other
States
outside
of
the
CAIR
region
may
not
participate
in
the
CAIR
trading
programs
for
either
pollutant,

because
they
were
not
shown
to
contribute
significantly
to
PM2.5
or
ozone
nonattainment
in
the
CAIR
region.
Allowing
States
outside
of
the
CAIR
region
to
participate
would
generally
create
an
opportunity
 
­
through
net
sales
of
allowances
from
the
non­

CAIR
States
to
CAIR
States­­
for
emission
increases
in
States
that
have
been
shown
to
contribute
significantly
to
nonattainment
in
the
CAIR
region.
108
A
State
may
not
participate
in
the
EPA­
administered
trading
programs
if
they
choose
to
get
a
portion
of
CAIR
reductions
from
457
non­
EGUs.
(
This
is
also
discussed
in
Section
VIII.)
EPA
maintains
that
requiring
certain
consistencies
among
States
in
the
regionwide
trading
programs
that
EPA
has
offered
to
run
does
not
unfairly
limit
States'
flexibility
to
choose
an
approach
for
achieving
CAIR
mandated
reductions
that
is
best
suited
for
a
particular
State's
unique
circumstances.
States
are
free
to
achieve
the
reductions
through
whatever
alternative
mechanisms
the
States
wish
to
design;
for
example,
a
group
of
States
could
cooperatively
implement
their
own
multi­
State
trading
programs
that
EPA
would
not
administer.

c.
Using
a
Mechanism
Other
than
the
Model
Trading
Rules
If
States
choose
to
control
EGUs
through
a
mechanism
other
than
the
EPA­
administered
NOx
and
SO2
emissions
trading
programs,
then
the
States
(
i)
must
still
impose
an
emissions
cap
on
total
EGU
emissions
and
require
part
75
monitoring,

recordkeeping,
and
reporting
requirements
on
all
EGUs,
and
(
ii)

must
use
the
same
definition
of
EGU
as
EPA
uses
in
its
model
trading
rules,
i.
e.,
the
sources
described
as
"
CAIR
units"
in
§
96.102,
§
96.202,
and
§
96.302.
A
few
commenters
expressed
concern
that
these
requirements
limit
States'
discretion
in
designing
control
measures
to
meet
the
CAIR
requirements,
but
failed
to
offer
any
reason
why
the
requirements
would
be
impracticable
or
ineffective.
The
EPA
believes
that
the
requirements
are
necessary
for
a
number
of
reasons.
The
458
requirements
to
cap
all
EGUs
and
to
use
the
same
definition
of
EGU
are
important
because
they
prevent
shifting
of
utilization
(
and
resulting
emissions)
from
capped
to
uncapped
sources.
In
this
case,
not
requiring
a
cap
on
total
EGU
emissions
in
these
States
is
likely
to
result
in
increased
utilization
and
consequently
increased
emissions
in
these
States.
The
requirement
to
use
part
75
monitoring
ensures
the
accuracy
of
monitored
data
and
consistency
of
reporting
among
sources
(
and
thus
the
certainty
that
emissions
reductions
actually
occurred)

across
all
States.
Furthermore,
most
EGUs
are
currently
monitoring
and
reporting
using
part
75
so
it
does
not
impose
an
additional
requirement.
Therefore,
EPA
is
finalizing
the
proposed
approach.

If
a
State
chooses
to
design
its
own
intrastate
or
interstate
NOx
or
SO2
emissions
trading
programs,
the
State
must,
in
addition
to
meeting
the
requirements
of
the
rules
finalized
in
today's
action,
consider
EPA's
guidance,
"
Improving
Air
Quality
with
Economic
Incentive
Programs,"
January,
2001
(
EPA­
452/
R­
01­
001)
(
available
on
EPA's
website
at:

http://
www.
epa.
gov/
ttn/
ecas/
incentiv.
html).
The
State's
programs
are
subject
to
EPA
approval.
The
EPA
will
not
administer
a
State­
designed
trading
program.
Additionally,
it
should
be
noted
that
allowances
from
any
alternate
trading
program
may
not
be
used
in
the
EPA­
administered
trading
programs.
459
d.
Retirement
of
Excess
Title
IV
Allowances
The
CAIR
NPR
proposed
requirements
on
SIPs
relating
to
the
effects
of
title
IV
SO2
allowance
allocations
for
2010
and
beyond
that
are
in
excess
of
the
State's
CAIR
EGU
SO2
emissions
budget.
The
requirements
were
intended
to
ensure
that
the
excess
is
not
used
in
a
manner
that
would
lead
to
a
significant
increase
in
supply
of
title
IV
allowances,
the
collapse
of
the
price
of
title
IV
allowances,
the
disruption
of
operation
of
the
title
IV
allowance
market
and
the
title
IV
SO2
cap­
and­
trade
system,
and
the
potential
for
increased
emissions
in
all
States
prior
to
2010
and
in
non­
CAIR
States
in
2010
and
later.
These
negative
impacts
on
the
title
IV
allowance
market
and
on
air
quality,
which
are
discussed
in
detail
in
section
IX.
B.
below,

would
undermine
the
efficacy
of
the
title
IV
program
and
could
erode
confidence
in
cap­
and­
trade
programs
in
general.
To
avoid
these
impacts,
EPA
proposed
to
require
retirement
of
the
excess
title
IV
allowances
through
a
retirement
ratio
mechanism.

The
EPA
proposed,
as
a
mechanism
for
removing
these
additional
allowances
and
meeting
the
50
percent
reduction
required
under
phase
I
(
2010­
2014),
that
each
affected
EGU
had
to
hold,
and
EPA
would
retire,
two
vintage
2010­
2014
allowances
for
every
ton
of
SO2
that
the
unit
emits.
Further,
EPA
proposed
that,
for
phase
II
(
which
begins
in
2015)
when
a
65
percent
reduction
is
required,
each
affected
EGU
had
to
hold,
and
EPA
460
would
retire,
three
vintage
2015
and
beyond
allowances
for
every
ton
of
SO2
that
the
unit
emits.
This
3­
to­
1
ratio
would
result
in
slightly
more
reductions
than
EPA
has
determined
were
necessary
to
eliminate
the
significant
contribution
by
an
upwind
State.

In
the
CAIR
SNPR,
EPA
proposed
two
alternatives
for
addressing
the
issue
of
the
additional
allowances.
Under
the
first
alternative,
affected
EGUs
had
to
hold,
and
EPA
would
retire,
vintage
2015
and
beyond
allowances
at
a
rate
of
2.86­
to­

1
rather
than
3­
to­
1,
which
would
result
in
exactly
the
amount
of
reductions
EPA
has
determined
are
necessary
to
eliminate
a
State's
significant
contribution.

Alternatively,
also
in
the
CAIR
SNPR,
EPA
proposed
requiring
the
retirement
of
2015
and
beyond
vintage
allowances
at
a
3­
to­
1
ratio
and
permitting
States
to
convert
the
additional
reductions
into
allowances
in
their
rules.
The
EPA
also
suggested
that
some
States
may
want
to
use
these
reserved
allowances
to
create
an
incentive
for
additional
local
emissions
reductions
that
will
be
needed
to
bring
all
areas
into
attainment
with
the
PM2.5
NAAQS.

As
part
of
today's
final
CAIR
rulemaking,
EPA
is
finalizing
a
ratio
of
2.86­
to­
one.
The
ratio
ultimately
represents
a
reduction
of
65
percent
from
the
final
title
IV
cap
level,
which
has
been
found
to
be
highly
cost­
effective.
For
a
detailed
discussion
regarding
EPA's
determination
of
highly
cost­
461
effective,
please
refer
to
Section
IV
of
the
final
CAIR
preamble.
As
discussed
earlier,
EPA
must
employ
a
uniform
ratio
across
sources
to
ensure
consistency
and
the
same
costeffectiveness
level
across
sources.
Therefore,
EPA
will
use
a
Phase
II
ratio
of
2.86­
to­
1
for
all
States
affected
by
CAIR
who
choose
to
participate
in
the
trading
program.

Today,
EPA
is
finalizing
the
general
requirement
that
all
SIPs
must
include
a
mechanism
to
ensure
that
excess
SO2
allowances
are
retired.
Furthermore,
for
States
that
participate
in
the
EPA­
administered
cap­
and­
trade
program,
EPA
is
finalizing
a
specific
mechanism
that
States
must
use.

i.
States
Participating
in
the
EPA­
Administered
SO2
Trading
Program
If
a
State
chooses
to
participate
in
the
EPA­
administered
trading
program,
the
State's
excess
title
IV
allowance
retirement
mechanism
must
follow
the
provisions
of
the
SO2
model
trading
rule
that
requires
that
vintage
2010
through
2014
title
IV
allowances
be
retired
at
a
ratio
of
two
allowances
for
every
ton
of
emissions
and
that
vintage
2015
and
beyond
title
IV
allowances
be
retired
at
a
ratio
of
2.86
allowances
for
every
ton
of
emissions.
Pre­
2010
vintage
allowances
would
be
retired
at
a
ratio
of
one
allowance
for
every
ton
of
emissions.
(
See
discussion
of
the
model
SO2
cap
and
trade
rule
in
section
VIII
of
today's
preamble.)
States
using
the
model
SO2
cap­
and­
trade
462
rule
satisfy
the
requirement
for
retirement
of
excess
title
IV
allowances.

ii.
States
not
Participating
in
the
EPA­
Administered
SO2
Trading
Program
In
the
CAIR
NPR,
EPA
stated
that
if
a
State
does
not
choose
to
participate
in
the
EPA­
administered
trading
programs
but
controls
only
EGUs,
the
State
may
choose
the
specific
method
to
retire
allowances
in
excess
of
its
budget.
The
EPA
considered
alternative
ways
for
retiring
these
excess
allowances
and,
as
stated
in
the
CAIR
SNPR,
believed
that
the
use
by
different
States
of
different
means
to
address
this
concern
could
undermine
the
regionwide
emissions
reduction
goals
of
the
CAIR
rulemaking.
The
EPA
further
described
its
concerns
in
section
II
of
the
preamble
to
the
CAIR
SNPR.
(
See
69
FR
32686­
32688.)

Because
of
these
concerns,
in
the
CAIR
SNPR,
EPA
withdrew
the
CAIR
NPR
proposal
on
this
point
and
re­
proposed
that
all
States
use
a
2­
for­
1
retirement
ratio
for
vintage
2010
through
2014
allowances
and
a
2.86­
for­
1
or
a
3­
for­
1
retirement
ratio
for
vintage
2015
and
beyond
allowances
to
address
concerns
about
title
IV
allowances
that
exceed
State
budgets.
The
EGUs
would
have
a
total
emissions
cap
enforced
by
the
State.
The
SNPR
described
that
for
sources
affected
by
both
title
IV
and
CAIR,

allowance
deductions
and
associated
compliance
determinations
would
be
sequential.
That
is,
title
IV
compliance
would
be
463
determined
and
then
CAIR
compliance
would
be
determined.
So,
in
2010­
2014,
after
surrendering
one
vintage
2010
through
2014
allowance
for
each
ton
of
emissions
for
title
IV
compliance,
the
source
would
then
surrender
one
additional
allowance
(
for
a
total
of
two
allowances
for
each
ton
which
meets
the
CAIR
requirement).
Similarly,
in
2015
and
beyond,
after
surrendering
one
vintage
2015
and
beyond
allowance
for
each
ton
of
emissions
for
title
IV
compliance,
the
source
would
surrender
1.86
or
2
additional
allowances
and
therefore
meet
the
CAIR
requirement.

Commenters
argued
that
in
States
where
EGUs
are
not
trading
under
CAIR
that
the
excess
title
IV
allowances
could
be
removed
in
a
variety
of
ways
and
that
EPA
did
not
need
to
require
each
State
do
this
the
same
way,
only
that
each
State
ensure
that
they
are
removed.

Today,
EPA
adopts
the
following
requirement:
if
a
State
does
not
choose
to
participate
in
the
EPA­
administered
trading
programs
but
controls
only
EGUs,
the
State
must
include
in
its
SIP
a
mechanism
for
retiring
the
excess
title
IV
allowances
(
i.
e.,
the
difference
between
total
allowance
allocations
in
the
State
and
the
State
EGU
SO2
budget).
To
meet
this
requirement,

the
State
may
use
the
above­
described
retirement
mechanism
or
may
develop
a
different
mechanism
that
will
achieve
the
required
retirement
of
excess
allowances.
464
3.
Requirements
for
States
Choosing
to
Control
Sources
Other
than
EGUs
a.
Overview
of
Requirements
As
noted
in
both
the
CAIR
NPR
and
the
CAIR
SNPR,
if
a
State
chooses
to
require
emissions
reductions
from
non­
EGUs,
the
State
must
adopt
and
submit
SIP
revisions
and
supporting
documentation
designed
to
quantify
the
amount
of
reductions
from
the
non­
EGU
sources
and
to
assure
that
the
controls
will
achieve
that
amount.
Although
EPA
did
not
propose
in
the
CAIR
NPR
that
States
be
required
to
impose
an
emissions
cap
on
those
sources,

but
instead
solicited
comment
on
the
issue,
EPA
proposed
in
the
CAIR
SNPR
that
States
be
required
to
impose
an
emissions
cap
in
certain
cases
on
non­
EGU
sources.
(
See
discussion
in
VII.
A.
1
of
today's
preamble.)

If
a
State
chooses
to
obtain
some,
but
not
all,
of
its
required
reductions
for
SO2
or
NOx
emissions
from
non­
EGUs,
it
would
still
be
required
to
set
an
EGU
budget
for
SO2
or
NOx
respectively,
but
it
would
set
such
a
budget
at
some
level
higher
than
shown
in
Tables
V­
1,
V­
2,
or
V­
4
in
today's
preamble,
thus
allowing
more
emissions
from
EGUs.
The
difference
between
the
amount
of
a
State's
SO2
budget
in
Table
V­
1
and
a
State's
selected
higher
EGU
SO2
budget
would
be
the
amount
of
SO2
emissions
reductions
the
State
demonstrates
it
will
achieve
from
non­
EGU
sources.
By
the
same
token,
the
465
109In
the
CAIR
SNPR,
EPA
mistakenly
cited
the
EGU
budget
numbers
from
Tables
VI­
9
and
VI­
10
in
the
CAIR
NPR
(
69
FR
4619­
20)
when
it
should
have
cited
Tables
II­
1
and
II­
2
in
the
CAIR
SNPR.
The
EPA
used
the
correct
numbers,
however,
in
the
proposed
regulatory
text
in
the
CAIR
SNPR
(
69
FR
32729­
30
and
69
FR
32733­
34
(
§
§
51.123(
e)(
2)
and
51.124(
e)(
2)).
difference
between
the
amount
of
a
State's
annual
NOx
budget
in
Table
V­
2
and
a
State's
selected
higher
annual
EGU
NOx
budget
would
be
the
amount
of
annual
NOx
emissions
reductions
the
State
demonstrates
it
will
achieve
from
non­
EGU
sources.
109
Further,

the
difference
between
the
amount
of
a
State's
seasonal
NOx
budget
in
Table
V­
4
and
a
State's
selected
higher
ozone
season
EGU
NOx
budget
would
be
the
amount
of
ozone
season
NOx
emissions
reductions
the
State
demonstrates
it
will
achieve
from
non­
EGU
sources.

Special
concerns
about
SO2
allowances
In
the
case
where
a
State
requires
a
portion
of
its
SO2
emissions
reductions
from
non­
EGU
sources
and
a
portion
from
EGUs,
there
remains
a
concern
about
the
impact
of
excess
title
IV
allowances
above
a
State's
EGU
cap,
particularly
on
the
operation
of
the
title
IV
SO2
cap­
and­
trade
program.

Consequently,
today,
we
are
adopting
the
requirement
that
these
States
include
a
mechanism
for
retirement
of
the
allowances
in
excess
of
the
State's
SO2
budget.

Like
a
State
choosing
to
control
only
EGUs
but
not
to
participate
in
the
trading
program,
a
State
that
chooses
to
466
control
non­
EGUs
and
EGUs
must
adopt
a
mechanism
for
retiring
surplus
title
IV
allowances.
The
number
of
title
IV
allowances
that
must
be
retired
is
equal
to
the
difference
between
the
number
of
title
IV
allowances
allocated
to
EGUs
in
that
State
and
the
SO2
budget
the
State
sets
for
EGUs
under
this
rule.
If
the
State
uses
a
retirement
mechanism
(
as
discussed
in
VII.
A.
2.
d.)
in
which
a
source
surrendering
allowances
under
the
title
IV
SO2
cap­
and­
trade
program
surrenders
more
allowances
than
otherwise
required
under
title
IV,
the
total
number
of
allowances
surrendered
per
ton
of
emissions
in
this
case
will
be
less
than
2
to
1
in
Phase
1
and
less
than
2.86
to
1
in
Phase
2.

This
is
because
the
non­
EGUs
will
control
to
achieve
a
portion
of
the
CAIR
SO2
reduction
required,
and
so
there
will
be
a
smaller
surplus
of
title
IV
allowances
than
if
all
the
required
reductions
were
achieved
by
EGUs.
The
appropriate
retirement
factor
will
equal
two
times
the
State's
SO2
budget
in
Phase
I
or
2.86
times
the
State's
SO2
budget
in
Phase
II
as
noted
in
Table
V­
1
of
the
budget
section,
divided
by
the
State's
selected
higher
EGU
SO2
budget
(
taking
into
account
non­
EGU
reductions).

The
factor
could
then
be
used
as
the
EGU
retirement
ratio
for
compliance
purposes
in
a
scenario
where
a
State
has
decided
to
control
SO2
emissions
from
EGUs
through
a
mechanism
other
than
the
EPA­
administered
trading
program.

A
simplified
example
can
help
illustrate
this.
Let
us
assume
a
State's
sources
were
allocated
a
total
of
200
467
allowances
under
title
IV.
Under
CAIR,
in
Phase
I,
the
State's
reduction
requirement
would
thus
be
100
tons.
Suppose
this
State
decided
that
25
tons
would
be
reduced
by
non­
EGUs
and
the
remaining
75
tons
would
be
reduced
by
the
EGUs.
(
The
State's
budget
for
EGUS
would
increase
to
125
tons.)
The
State
would
also
need
to
retire
75
excess
title
IV
allowances.
This
could
be
accomplished
by
requiring
each
Acid
Rain
source
to
surrender
a
total
of
1.6
vintage
2010
through
2014
allowances
(
200
allowances
allocated
in
the
State
/
125
tons
in
State
EGU
budget)
per
ton
of
SO2
emissions.
The
allowances
surrendered
would
satisfy
the
Acid
Rain
Program
requirement
of
surrendering
one
allowance
per
ton
of
emissions,
as
well
as
achieving
the
additional
retirement
requirement
under
CAIR
since
200
allowances
would
be
used
for
EGUs
to
emit
the
EGU
budget
of
125
tons
of
SO2.
(
Pre­
2010
allowances
continue
to
be
available
for
use
on
a
one­
allowance­
per­
ton­
of­
emissions
basis
here
as
in
other
situations.)

This
is
consistent
with
EPA's
overall
approach.
If
this
same
State
decided
to
get
all
reductions
(
i.
e.,
100
tons)
from
EGUs,
the
State
would
require
EGUs
to
retire
100
additional
allowances
by
surrendering
a
total
of
2
vintage
2010
through
2014
allowances
(
200
allowances
allocated
in
the
State
/
100
tons
in
State
EGU
budget)
per
ton
of
SO2
emissions.

The
demonstration
of
emissions
reductions
from
non­
EGUs
is
a
critical
requirement
of
the
SIP
revision
due
from
a
State
that
468
chooses
to
control
non­
EGUs.
The
State
must
take
into
account
the
amount
of
emissions
attributable
to
the
source
category
in
both
(
i)
the
base
case,
in
the
implementation
years
2010
and
2015,
i.
e.,
without
assuming
any
SIP­
required
reductions
under
the
CAIR
from
non­
EGUs;
and
(
ii)
in
the
control
case,
in
the
implementation
years
2010
and
2015,
i.
e.,
assuming
SIP­
required
reductions
under
the
CAIR
from
non­
EGUs.
We
proposed
an
alternative
methodology
for
calculating
the
base
case
for
certain
large
non­
EGU
sources,
as
described
below,
but
generally
the
difference
between
emissions
in
the
base
case
and
emissions
in
the
control
case
equals
the
amount
of
emissions
reductions
that
can
be
claimed
from
application
of
the
controls
on
non­

EGUs.
(
See
discussion
later
in
this
section
for
criteria
applicable
to
development
of
the
baseline
and
projected
control
emissions
inventories.)

States
that
meet
the
lesser
of
their
CAIR
ozone
season
NOx
budget
or
NOx
SIP
Call
EGU
trading
budget
using
the
CAIR
ozone
season
NOx
trading
program
also
satisfy
their
NOx
SIP
Call
requirements
for
EGUs.
States
may
also
choose
to
include
all
of
their
NOx
SIP
Call
non­
EGUs
in
the
CAIR
ozone
season
NOx
program
at
their
NOx
SIP
Call
levels
(
i.
e.,
the
non­
EGU
trading
budget
remains
the
same).

To
the
extent
EPA
allows
through
the
Regional
Haze
Rule
and
a
State
then
chooses
to
use
EPA
analysis
to
show
that
CAIR
reductions
from
EGUs
meet
BART
requirements,
States
that
achieve
469
a
portion
of
their
CAIR
reductions
from
sources
other
than
EGUs
and
wanting
to
show
that
even
with
those
reductions
the
EGUs
will
meet
BART
requirements
must
make
a
supplemental
demonstration
that
BART
requirements
are
satisfied.

b.
Eligibility
of
Non­
EGU
Reductions
In
the
CAIR
SNPR,
EPA
proposed
that,
in
evaluating
whether
emissions
reductions
from
non­
EGUs
would
count
towards
the
emissions
reductions
required
under
the
CAIR,
States
may
only
include
reductions
attributable
to
measures
that
are
not
otherwise
required
under
the
CAA.
Specifically,
EPA
proposed
that
States
must
exclude
non­
EGU
reductions
attributable
to
measures
otherwise
required
by
the
CAA,
including:
(
1)
measures
required
by
rules
already
in
place
at
the
date
of
promulgation
of
today's
final
rule,
such
as
adopted
State
rules,
SIP
revisions
approved
by
EPA,
and
settlement
agreements;
(
2)

measures
adopted
and
implemented
by
EPA
(
or
other
Federal
agencies)
such
as
emissions
reductions
required
pursuant
to
the
Federal
Motor
Vehicle
Control
Program
for
mobile
sources
(
vehicles
or
engines)
or
mobile
source
fuels,
or
pursuant
to
the
requirements
for
National
Emissions
Standards
for
Hazardous
Air
Pollutants;
and
(
3)
specific
measures
which
are
mandated
under
the
CAA
(
which
may
have
been
further
defined
by
EPA
rulemaking)

based
on
the
classification
of
an
area
which
has
been
designated
470
nonattainment
for
a
NAAQS,
such
as
vehicle
inspection
and
maintenance
programs.

In
discussing
this
proposal,
EPA
noted
that
States
required
to
make
CAIR
SIP
submittals
may
also
be
required
to
make
separate
SIP
submittals
to
meet
other
requirements
applicable
to
non­
EGUs,
e.
g.,
nonattainment
SIPs
required
for
areas
designated
nonattainment
under
the
PM2.5
or
8­
hour
ozone
NAAQS
or
regional
haze
SIPs.
The
EPA
noted
it
is
likely
that
CAIR
SIP
submittals
will
be
due
before
or
at
the
same
time
as
some
of
these
other
SIP
submittals.
We
therefore
proposed
that
States
relying
on
reductions
from
controls
on
non­
EGUs
must
commit
in
the
CAIR
SIP
revisions
to
replace
the
emissions
reductions
attributable
to
any
CAIR
SIP
measure
if
that
measure
is
subsequently
determined
to
be
required
to
meet
any
other
SIP
requirement.

Some
commenters
objected
to
the
proposed
exclusion
of
credit
for
measures
which
are
mandated
under
the
CAA
based
on
the
classification
of
an
area
which
has
been
designated
nonattainment
for
a
NAAQS,
as
well
as
to
the
proposed
requirement
that
such
measures
must
be
replaced
if
they
are
later
determined
to
be
required
in
meeting
separate
SIP
requirements.
These
commenters
reasoned
that
such
a
requirement
would
not
be
applied
to
EGUs
and
would
impose
unnecessary
and
costly
burdens
on
non­
EGUs,
thus
creating
an
incentive
for
States
to
avoid
controlling
non­
EGUs
and
to
impose
all
CAIR
reduction
requirements
on
EGUs.
One
commenter
further
objected
471
that,
as
long
as
a
measure
was
not
included
in
the
base
case
EPA
used
to
determine
a
State's
contribution
to
other
States'

nonattainment
under
CAA
section
110(
a)(
2)(
D),
there
is
no
justification
for
excluding
CAIR
credit
for
such
measure,
and
that
EPA's
proposed
exclusion
of
credit
for
any
measure
"
otherwise
required
by
the
CAA"
is
inconsistent
with
the
NOx
SIP
Call.

In
response
to
these
comments,
EPA
agrees
that
it
is
not
appropriate
to
apply
this
proposed
restriction
inconsistently
to
EGUs
and
non­
EGUs.
Thus,
EPA
is
adopting
a
modified
form
of
the
proposed
criteria
for
the
eligibility
of
non­
EGU
emissions
reductions,
eliminating
the
requirement
that
States
must
exclude
non­
EGU
reductions
attributable
to
measures
otherwise
required
by
the
CAA
based
on
the
classification
of
an
area
which
has
been
designated
nonattainment
for
a
NAAQS.
Consequently,
the
final
rule
allows
credit
for
measures
that
a
State
later
adopts
in
response
to
requirements
which
result
from
an
area's
nonattainment
classification,
such
as
reasonably
available
control
technology
(
RACT).
With
this
change,
all
emissions
reductions
are
eligible
for
credit
in
meeting
CAIR
except:
(
1)

measures
adopted
or
implemented
by
the
State
as
of
the
date
of
promulgation
of
today's
final
rule,
such
as
adopted
State
rules,

SIP
revisions
approved
by
EPA,
and
settlement
agreements;
and
(
2)
measures
adopted
or
implemented
by
the
Federal
government
(
e.
g.,
EPA
or
other
Federal
agencies)
as
of
the
date
of
472
submission
of
the
SIP
revision
by
the
State
to
EPA,
such
as
emissions
reductions
required
pursuant
to
the
Federal
Motor
Vehicle
Control
Program
for
mobile
sources
(
vehicles
or
engines)

or
mobile
source
fuels,
or
pursuant
to
the
requirements
for
National
Emissions
Standards
for
Hazardous
Air
Pollutants.

This
exclusion
of
credit
is
consistent
with
EPA's
approach
in
the
NOx
SIP
Call,
although
a
direct
comparison
of
the
creditability
requirements
in
the
CAIR
and
in
the
NOx
SIP
Call
is
not
possible
due
to
the
timing
and
context
in
which
both
rules
were
developed.
The
NOx
SIP
Call
used
statewide
budgets
for
all
sources
as
an
accounting
tool
to
determine
the
adequacy
of
a
strategy,
while
the
CAIR
takes
a
different
approach
in
which
baseline
emission
inventories
for
non­
EGU
sectors
will,
if
needed,
be
developed
later.
The
NOx
SIP
Call
did,
as
does
the
CAIR,
restrict
States
from
taking
credit
for
any
Federal
measures
adopted
after
promulgation
of
the
rule
(
63
FR
57427­

28).
It
also
did
not
allow
credit
for
already
adopted
measures,

but
the
timing
of
the
NOx
SIP
Call
was
such
that
nonattainment
planning
measures
would
have
already
likely
been
adopted
as
the
SIP
deadlines
for
adoption
of
such
measures
had
passed.
In
today's
action,
nonattainment
planning
measures
adopted
after
the
promulgation
of
today's
rule
will
be
allowed
credit
under
CAIR.

In
order
to
take
credit
for
CAIR
reductions
from
non­
EGUs,

the
reductions
must
be
beyond
what
is
required
under
the
NOx
SIP
473
Call.
That
is,
a
reduction
must
be
in
the
non­
ozone
season
or
it
must
be
beyond
what
is
expected
in
the
ozone
season.

Nonozone
season
reductions
must
also
be
beyond
what
is
in
the
base
case,
particularly
for
units
that
have
low
NOx
burners
and
certain
SCRs
(
e.
g.,
ones
required
to
be
run
annually).
The
reductions
must
be
in
addition
to
those
already
expected.
If
ozone
season
reductions
are
considered,
the
non­
EGU
NOx
SIP
Call
trading
budget
must
be
adjusted
by
the
increment
of
CAIR
reductions
beyond
the
levels
in
the
NOx
SIP
Call.
This
removes
the
corresponding
allowances
from
the
market
and
ensures
that
the
emissions
do
not
shift
to
other
sources.

After
evaluating
the
eligibility
of
non­
EGU
reductions
in
accordance
with
the
requirements
discussed
here,
States
must
exclude
credit
for
ineligible
measures
by
(
i)
including
such
measures
in
both
the
baseline
and
controlled
emissions
inventory
cases,
if
they
have
already
been
adopted;
or
(
ii)
excluding
them
from
both
the
base
and
control
emissions
inventory
cases
if
they
have
not
yet
been
adopted.
(
See
discussion
later
in
this
section
regarding
development
of
emissions
inventories
and
demonstration
of
non­
EGU
reductions.)

c.
Emissions
Controls
and
Monitoring
As
noted
in
section
VII.
A.
1.,
we
modified
the
"
hybrid"

approach
described
in
the
CAIR
NPR
as
it
applies
to
certain
non­

EGUs,
and
adopt
today
the
approach
described
in
the
CAIR
SNPR.
474
Specifically,
for
States
that
choose
to
impose
controls
on
large
industrial
boilers
and
turbines,
i.
e.,
those
whose
maximum
design
heat
input
is
greater
than
250
mmBtu/
hr,
to
meet
part
or
all
of
their
emissions
reductions
requirements
under
the
CAIR,

State
rules
must
include
an
emissions
cap
on
all
such
sources
in
their
State.
Additionally,
in
this
situation,
States
must
require
those
large
industrial
boilers
and
turbines
to
meet
part
75
requirements
for
monitoring
and
reporting
emissions
as
well
as
recordkeeping.
This
ensures
consistency
in
measurement
and
certainty
of
reductions
and
has
been
proven
technologically
and
economically
feasible
in
other
programs.

If
a
State
chooses
to
control
non­
EGUs
other
than
large
industrial
boilers
and
turbines
to
obtain
the
required
emissions
reductions,
the
State
must
either
(
i)
impose
the
same
requirements,
i.
e.,
an
emissions
cap
on
total
emissions
from
non­
EGUs
in
the
source
category
in
the
State
and
part
75
monitoring,
reporting
and
recordkeeping
requirements;
or
(
ii)

demonstrate
why
such
requirements
are
not
practicable.
In
the
latter
case,
the
State
must
adopt
appropriate
alternative
requirements
to
ensure
that
emissions
reductions
are
being
achieved
using
methods
that
quantify
those
emissions
reductions,

to
the
extent
practicable,
with
the
same
degree
of
assurance
that
reductions
are
being
quantified
for
EGUs
and
non­
EGU
boilers
and
turbines
using
part
75
monitoring.
This
is
to
ensure
that,
regardless
of
how
a
State
chooses
to
meet
the
CAIR
475
110The
many
EPA
guidance
documents
and
tools
for
preparing
emission
inventory
estimates
for
SO2
and
NOx
are
available
at
the
following
websites:
http://
www.
epa.
gov/
ttn/
chief/
net/
general.
html,
http://
www.
epa.
gov/
ttn/
chief/
eiip/
techreport/,
http://
www.
epa.
gov/
ttn/
chief/
publications.
html#
general,
emissions
reduction
requirements,
all
reductions
made
by
States
to
comply
with
the
CAIR
have
the
same,
high
level
of
certainty
as
that
achieved
through
the
cap­
and­
trade
approach.
Further,

if
a
State
adopts
alternative
requirements
that
do
not
apply
to
all
non­
EGUs
in
a
particular
source
category
(
defined
to
include
all
sources
where
any
aspect
of
production
of
one
or
more
such
sources
is
reasonably
interchangeable
with
that
of
one
or
more
other
such
sources),
the
State
must
demonstrate
that
it
has
analyzed
the
potential
for
shifts
in
production
from
the
regulated
sources
to
unregulated
or
less
stringently
regulated
sources
in
the
same
State
as
well
as
in
other
States
and
that
the
State
is
not
including
reductions
attributable
to
sources
that
may
shift
emissions
to
such
unregulated
or
less
regulated
sources.

d.
Emissions
Inventories
and
Demonstrating
Reductions
To
quantify
emissions
reductions
attributable
to
controls
on
non­
EGUs,
the
States
must
submit
both
baseline
and
projected
control
emissions
inventories
for
the
applicable
implementation
years.
We
have
issued
many
guidance
documents
and
tools
for
preparing
such
emissions
inventories,
some
of
which
apply
to
specific
sectors
States
may
choose
to
control.
110
While
much
of
476
http://
www.
epa.
gov/
ttn/
chief/
software/
index.
html,
and
http://
www.
epa.
gov/
ttn/
chief/
efinformation.
html.

111The
2010
modeling
date
is
relevant
for
both
SO2
and
NOx
even
though
NOx
requirements
begin
in
2009.
See
Section
IV
for
discussion.
that
guidance
is
applicable
to
today's
rulemaking,
there
are
some
key
differences
between
quantification
of
emissions
reduction
requirements
under
a
SIP
designed
to
help
achieve
attainment
with
a
NAAQS
and
emissions
reduction
requirements
under
a
SIP
designed
to
reduce
emissions
that
contribute
significantly
to
a
downwind
State's
nonattainment
problem
or
interfere
with
maintenance
in
a
downwind
State.
Because
States
are
taking
actions
as
a
result
of
their
impact
on
other
States,

and
because
the
impacted
States
have
no
authority
to
reduce
emissions
from
other
States,
the
emissions
reduction
estimates
become
even
more
important.
(
For
a
complete
discussion,
see
69
FR
32693;
June
10,
2004.)

Specifically,
when
we
review
CAIR
SIPs
for
approvability,

we
intend
to
review
closely
the
emissions
inventory
projections
for
non­
EGUs
to
evaluate
whether
emissions
reduction
estimates
are
correct.
We
intend
to
review
the
accuracy
of
baseline
historical
emissions
for
the
subject
sources,
assumptions
regarding
activity
and
emissions
growth
between
the
baseline
year
and
2010111
and
2015,
and
assumptions
about
the
effectiveness
of
control
measures.
477
Before
describing
the
specific
steps
involved
in
this
quantification
process,
EPA
notes
that
a
few
commenters
objected
to
the
proposed
requirements
as
arbitrary
restrictions
intended
to
discourage
States'
discretion
in
imposing
control
measures
on
non­
EGUs
since
these
requirements
would
use
what
the
commenters
describe
as
extremely
conservative
emissions
baseline
and
emissions
reduction
estimates.
No
commenter
refuted
EPA's
explanation,
noted
above,
of
the
need
for
stringent
requirements
to
ensure
greater
accuracy
of
emission
inventories
and
greater
certainty
of
reduction
estimates
used
in
SIPs
addressing
transported
pollutants.
The
EPA
maintains
that
the
need
for
more
accurate
inventories
and
more
certain
reduction
estimates
justifies
the
requirements
discussed
below.
Further,
no
commenter
provided
an
alternate
method
of
addressing
EPA's
concerns
about
the
development
of
such
inventories
and
reduction
estimates.
Thus,
EPA
is
finalizing
its
proposed
approach.

iii.
Historical
Baseline
To
quantify
non­
EGU
reductions,
as
the
first
step,
a
historical
baseline
must
be
established
for
emissions
of
SO2
or
NOx
from
the
non­
EGU
source(
s)
in
a
recent
year.
The
historical
baseline
inventory
should
represent
actual
emissions
from
the
sources
prior
to
the
application
of
the
controls.
We
expect
that
States
will
choose
a
representative
year
(
or
average
of
several
years)
during
2002­
2005
for
this
purpose.
478
The
requirements
for
estimating
the
historical
baseline
inventory
that
follow
reflect
EPA's
view
that,
when
States
assign
emissions
reductions
to
non­
EGU
sources,
achievement
of
those
reductions
should
carry
a
high
degree
of
certainty,
just
as
EGU
reductions
can
be
quantified
with
a
high
degree
of
certainty
in
accordance
with
the
applicable
part
75
monitoring
requirements.
Because
the
non­
EGU
emissions
reductions
are
estimated
by
subtracting
controlled
emissions
from
a
projected
baseline,
if
the
historical
baseline
overestimates
actual
emissions,
the
estimated
reductions
could
be
higher
than
the
actual
reductions
achieved.

For
non­
EGU
sources
that
are
subject
to
part
75
monitoring
requirements,
historical
baselines
must
be
derived
from
actual
emissions
obtained
from
part
75
monitored
data.
For
non­
EGU
sources
that
do
not
have
part
75
monitoring
data,
historical
baselines
must
be
established
that
estimate
actual
emissions
in
a
way
that
matches
or
approaches
as
closely
as
possible
the
certainty
provided
by
the
part
75
measured
data
for
EGUs.
For
these
sources,
States
must
estimate
historical
baseline
emissions
using
source­
specific
or
category­
specific
data
and
assumptions
that
ensure
a
source's
or
source
category's
actual
emissions
are
not
overestimated.

To
determine
the
baseline
for
sources
that
do
not
have
part
75
measured
data,
States
must
use
emission
factors
that
ensure
that
emissions
are
not
overestimated
(
e.
g.,
emission
factors
at
479
the
low
end
of
a
range
when
EPA
guidance
presents
a
range)
or
the
State
must
provide
additional
information
that
shows
with
reasonable
confidence
that
another
value
is
more
appropriate
for
estimating
actual
emissions.
Other
monitoring
or
stack
testing
data
can
be
considered,
but
care
must
be
taken
not
to
overestimate
baselines.
If
a
production
or
utilization
factor
is
part
of
the
historical
baseline
emissions
calculation,
a
factor
that
ensures
that
emissions
are
not
overestimated
must
be
used,
or
additional
data
must
be
provided.
Similarly,
if
a
control
or
rule
effectiveness
factor
enters
into
the
estimate
of
historical
baseline
emissions,
such
a
factor
must
be
realistic
and
supported
by
facts
or
analysis.
For
these
factors,
a
high
value
(
closer
to
100
percent
control
and
effectiveness)
ensures
that
emissions
are
not
overestimated.

iv.
Projections
of
2010
and
2015
Baselines
The
second
step
in
quantifying
SO2
or
NOx
emissions
reductions
for
non­
EGUs
is
to
use
the
historical
baseline
emissions
and
project
emissions
that
would
be
expected
in
2010
and
2015
without
the
CAIR.
This
step
results
in
the
2010
and
2015
baseline
emissions
estimates.

The
EPA
proposed
and
requested
comment
on
two
procedures
for
estimating
the
future
baselines:
one
relies
on
projections
based
on
a
number
of
estimated
parameters;
the
second
uses
the
lower
of
this
projection
and
actual
historical
emissions.
480
Today,
EPA
finalizes
the
second
approach
for
determining
2010
and
2015
emissions
baselines.

To
estimate
future
emissions,
States
must
use
state­
of­

theart
methods
for
projecting
the
source
or
source
category's
economic
output.
Economic
and
population
forecasts
must
be
as
specific
as
possible
to
the
applicable
industry,
State,
and
county
of
the
source
and
must
be
consistent
with
both
national
projections
and
relevant
official
planning
assumptions,

including
estimates
of
population
and
vehicle
miles
traveled
developed
through
consultation
between
State
and
local
transportation
and
air
quality
agencies.
However,
if
these
official
planning
assumptions
are
themselves
inconsistent
with
official
U.
S.
Census
projections
of
population
or
with
energy
consumption
projections
contained
in
the
most
recent
Annual
Energy
Outlook
published
by
the
U.
S.
Department
of
Energy,
then
adjustments
must
be
made
to
correct
the
inconsistency,
or
the
SIP
must
demonstrate
how
the
official
planning
assumptions
are
more
accurate.
If
the
State
expects
changes
in
production
method,
materials,
fuels,
or
efficiency
to
occur
between
the
baseline
year
and
2010
or
2015,
the
State
must
account
for
these
changes
in
the
projected
2010
and
2015
baseline
emissions.
For
example,
if
a
source
has
publicly
announced
a
change
or
applied
for
a
permit
for
a
change,
it
should
be
reflected
in
the
projections.
The
projection
must
also
reflect
any
adopted
481
regulations
that
are
ineligible
control
measures
and
that
will
affect
source
emissions.

As
stated
above,
EPA
is
requiring
States
to
use
the
lower
of
historical
baseline
emissions
or
projected
2010
or
2015
emissions,
as
applicable,
for
a
source
category.
This
is
because
changes
in
production
method,
materials,
fuels,
or
efficiency
often
play
a
key
role
in
changes
in
emissions.

Because
of
factors
such
as
these,
emissions
can
often
stay
the
same
or
even
decrease
as
productivity
within
a
sector
increases.

These
factors
that
contribute
to
emission
decreases
can
be
very
difficult
to
quantify.
Underestimating
the
impact
of
these
types
of
factors
can
very
easily
result
in
a
projection
for
increased
emissions
within
a
sector,
when
a
correct
estimate
will
result
in
a
projection
for
decreased
emissions
within
the
sector.
A
few
commenters
opposed
this
methodology
as
arbitrary
but
failed
to
explain
why
EPA's
concerns,
as
described
above,

are
not
valid.
Commenters
also
failed
to
propose
other
methodologies
for
addressing
these
concerns.
Thus,
EPA
is
finalizing
the
use
of
this
second
methodology.

v.
Controlled
Emissions
Estimates
for
2010
and
2015
The
third
step
is
to
develop
the
2010
and
2015
controlled
emissions
estimates
by
assuming
the
same
changes
in
economic
output
and
other
factors
listed
above
but
adding
the
effects
of
the
new
controls
adopted
for
the
purpose
of
meeting
the
CAIR.
482
The
controls
may
take
the
form
of
regulatory
requirements,
e.
g.,

emissions
caps,
emission
rate
limits,
technology
requirements,

or
work
practice
requirements.
The
State's
estimate
of
the
effect
of
the
control
regulations
must
be
realistic
in
light
of
the
specific
provisions
for
monitoring,
reporting,
and
enforcement
and
experience
with
similar
regulatory
approaches.

In
addition,
the
State's
analysis
must
examine
the
possibility
that
the
controls
may
cause
production
and
emissions
to
shift
to
unregulated
or
less
stringently
regulated
sources
in
the
same
State
or
another
State.
If
all
sources
of
a
source
category
(
defined
to
include
all
sources
where
any
aspect
of
production
is
reasonably
interchangeable)
within
the
State
are
regulated
with
the
same
stringency
and
compliance
assurance
provisions,
the
analysis
of
production
and
emissions
shifts
need
only
consider
the
possibility
of
shifts
to
other
States.
If
only
a
portion
of
a
source
category
within
a
State
is
regulated,

the
analysis
must
also
include
any
in­
State
shifting.
In
estimating
controlled
emissions
in
2010
and
2015,
assumptions
regarding
control
measures
that
are
not
eligible
for
CAIR
reduction
credit
must
be
the
same
as
in
the
2010
and
2015
baseline
estimates.
For
example,
a
State
may
not
take
credit
for
reductions
in
the
sulfur
content
of
nonroad
diesel
fuel
that
are
required
under
the
recent
Federal
nonroad
fuel
rule
(
69
FR
38958;
June
29,
2004).
By
including
the
effect
of
this
Federal
rule
in
both
the
baseline
and
controlled
emissions
estimates
for
483
2010
and
2015,
the
State
will
appropriately
exclude
this
ineligible
reduction
when
it
subtracts
the
controlled
emissions
estimates
from
the
baseline
emissions
estimates.

The
method
that
we
are
adopting
today
specifies
the
2010
and
2015
emissions
reductions
which
can
be
counted
toward
satisfying
the
CAIR.
The
method
requires
the
use
of
the
historical
baseline
or
the
baseline
emission
estimates,

whichever
is
lower.
That
is,
the
reduction
is
calculated
as
follows:
(
i)
for
2010,
the
difference
between
the
lower
of
historical
baseline
or
2010
baseline
emissions
estimates
and
the
2010
controlled
emissions
estimates,
minus
any
emissions
that
may
shift
to
other
sources
rather
than
be
eliminated;
and
(
ii)

for
2015,
the
difference
between
the
lower
of
historical
baseline
or
2015
baseline
emissions
estimates
and
the
2015
controlled
emissions
estimates,
minus
any
emissions
that
may
shift
to
other
sources
rather
than
be
eliminated.

4.
Controls
on
Non­
EGUs
Only
Although
we
stated
that
we
believe
it
is
unlikely
States
may
choose
to
control
only
non­
EGUs,
we
proposed
in
the
CAIR
SNPR
provisions
for
determining
the
specified
emissions
reductions
that
must
be
obtained
if
States
pursue
this
alternative,
and
we
adopt
those
provisions
today.
The
reason
we
think
it
is
unlikely
is
based
on
States'
emissions
profiles.

Most
SO2
emissions
are
from
EGUs
and
therefore
it
is
unlikely
484
112See
"
Technical
Support
Document
for
the
Clean
Air
Interstate
Rule
Notice
of
Final
Rulemaking:
Regional
and
State
SO2
and
NOx
Emissions
Budgets"
for
tables
containing
information
to
calculate
these
amounts
for
both
SO2
and
NOx.
that
a
State
can
achieve
the
required
emissions
reductions
without
regulating
EGUs
to
some
degree.
In
addition,
SO2
emissions
reductions
from
EGUs
are
highly
cost
effective.

States
that
choose
this
path
must
ensure
that
the
amount
of
non­

EGU
reductions
is
equivalent
to
all
of
the
emissions
reductions
that
would
have
been
required
from
EGUs
had
the
State
chosen
to
assign
all
the
emissions
reductions
to
EGUs.
For
SO2
emissions,

this
amount
in
2010
would
be
50
percent
of
a
State's
title
IV
SO2
allocations
for
all
units
in
the
State
and,
for
2015,
65
percent
of
such
allocations.
For
NOx
emissions,
this
amount
would
be
the
difference
between
a
State's
EGU
budget
for
NOx
under
the
CAIR
and
its
NOx
baseline
EGU
emissions
inventory
as
projected
in
the
Integrated
Planning
Model
(
IPM)
for
2010
and
2015,
respectively.
112
In
addition,
the
same
requirements
described
elsewhere
in
this
part
of
today's
preamble
regarding
the
eligibility
of
non­

EGU
reductions,
emissions
control
and
monitoring,
emissions
inventories
and
demonstration
of
reductions,
will
apply
to
the
situation
where
a
State
chooses
to
control
only
non­
EGUs.

E.
Use
of
Banked
Allowances
and
the
Compliance
Supplement
Pool
In
the
CAIR
NPR,
EPA
stated
that
States
may
allow
EGUs
to
demonstrate
compliance
with
the
State
EGU
SO2
budget
by
using
485
title
IV
allowances
(
i)
that
were
banked,
or
(
ii)
that
were
obtained
in
the
current
year
from
sources
in
other
States
(
69
FR
4627).
The
EPA
adopts
this
provision
in
today's
action.
The
EPA
adopts
a
similar
provision
for
the
use
of
banked
NOx
SIP
Call
allowances
(
pre­
2009)
to
demonstrate
compliance
with
the
State
EGU
ozone
season
NOx
budget.
See
also
the
CAIR
NPR
(
69
FR
4633).
Therefore,
State
rules
may
allow
the
use
of
pre­
2010
title
IV
and
pre­
2009
NOx
SIP
Call
allowances
banked
in
the
title
IV
and
NOx
SIP
Call
trading
programs
for
compliance
in
the
CAIR.
States
participating
in
the
EPA­
administered
CAIR
trading
programs
must
allow
the
use
of
these
pre­
2010
title
IV
allowances
or
pre­
2009
NOx
SIP
Call
allowances
in
accordance
with
EPA's
model
trading
rules.

Additionally,
States
with
annual
NOx
reduction
requirements
may
use
compliance
supplement
pool
(
CSP)
allowances
as
described
in
sections
V
and
VIII.
Distribution
of
the
CSP
is
essentially
the
same
as
the
process
used
in
the
NOx
SIP
Call,

through
one
or
both
of
two
mechanisms.
States
may
distribute
CSP
allowances
on
a
pro­
rata
basis
to
sources
that
implement
NOx
control
measures
resulting
in
reductions
in
2007
or
2008
that
are
beyond
what
is
required
by
any
applicable
State
or
Federal
emissions
limitation
(
early
reductions).
The
second
CSP
distribution
mechanism
that
a
State
can
use
is
to
issue
CSP
allowances
based
on
the
demonstration
of
a
need
for
an
extension
of
the
2009
deadline
for
implementing
emission
controls.
The
486
demonstration
must
show
unacceptable
risk
either
to
a
source's
own
operation
or
its
associated
industry­­
for
EGUs,
power
supply
reliability,
for
non­
EGUs
risk
comparable
to
that
described
for
the
electricity
industry.
See
also
63
FR
57356
for
further
discussion
of
these
points.

Pre­
2010
title
IV
SO2
allowances,
pre­
2009
NOx
SIP
Call
allowances
and
CAIR
annual
NOx
CSP
allowances
can
all
be
counted
toward
a
States
efforts
to
achieve
its
CAIR
reduction
obligations
regardless
of
whether
the
CAIR
trading
programs
are
used
or
not.

B.
State
Implementation
Plan
Schedules
1.
State
Implementation
Plan
Submission
Schedule
In
the
NPR,
we
proposed
to
require
States
to
submit
SIPs
to
address
interstate
transport
in
accordance
with
the
provisions
of
this
rule
approximately
18
months
from
the
date
of
this
final
rule
(
69
FR
4624).
After
careful
consideration
of
the
comments
we
received
concerning
this
issue,
we
have
concluded
that
States
should
submit
SIPs
to
satisfy
this
final
rule
as
expeditiously
as
possible,
but
no
later
than
18
months
from
the
date
of
today's
action.
Under
this
schedule,
upwind
States'
transport
SIPs
to
meet
CAA
section
110(
a)(
2)(
D)
will
be
due
before
the
downwind
States'
PM2.5
and
8­
hour
ozone
nonattainment
area
SIPs
under
CAA
section
172(
b).
We
expect
that
the
downwind
States'

8­
hour
ozone
nonattainment
area
SIPs
will
be
due
by
June
15,
487
113By
statute,
the
date
for
submission
of
nonattainment
area
SIPs
is
to
be
no
later
than
3
years
from
the
date
of
nonattainment
designation.
Section
172(
b).
2007,
and
their
PM2.5
nonattainment
SIPs
will
be
due
by
April
5,

2008.113
We
believe
that
this
sequence
for
SIP
submissions
to
address
upwind
interstate
transport
and
downwind
nonattainment
areas
is
consistent
both
with
the
applicable
provisions
of
the
CAA
and
with
sound
policy
objectives.
The
CAA
provides
for
this
sequence
of
submissions
in
section
110(
a)(
1)
and
(
a)(
2),
which
provide
that
the
submittal
period
for
SIPs
required
by
section
110(
a)(
2)(
D)
runs
from
the
earlier
date
of
the
NAAQS
revision,

and
in
section
172(
b),
which
provides
that
the
submittal
period
for
the
nonattainment
area
SIPs
runs
from
the
later
date
of
designation.
Clean
Air
Act
section
110(
a)(
1)
requires
each
State
to
submit
a
SIP
to
EPA
"
within
3
years
...
after
the
promulgation
of
a
[
NAAQS]
(
or
any
revision
thereof)."
Section
110(
a)(
2)
makes
clear
that
this
SIP
must
include,
among
other
things,
provisions
to
address
the
requirements
of
section
110(
a)(
2)(
D).
We
read
these
provisions
together
to
require
that
each
upwind
State
must
submit,
within
3
years
of
a
new
or
revised
NAAQS,
SIPs
that
address
the
section
110(
a)(
2)(
D)

requirement.
By
contrast,
the
schedule
provided
in
section
172(
b)
is
only
applicable
to
the
nonattainment
area
SIP
requirements.
488
Section
110(
a)
imposes
the
obligation
upon
States
to
make
a
submission,
but
the
contents
of
that
submission
may
vary
depending
on
the
facts
and
circumstances.
In
particular,
the
data
and
analytical
tools
available
at
the
time
the
section
110(
a)(
2)(
D)
SIP
is
developed
and
submitted
to
EPA
necessarily
affect
the
content
of
the
submission.
Where,
as
here,
the
data
and
analytical
tools
to
identify
a
significant
contribution
from
upwind
States
to
nonattainment
areas
in
downwind
States
are
available,
the
State's
SIP
submission
must
address
the
existence
of
the
contribution
and
the
emission
reductions
necessary
to
eliminate
the
significant
contribution.
In
other
circumstances,

however,
the
tools
and
information
may
not
be
available.
In
such
circumstances,
the
section
110(
a)(
2)(
D)
SIP
submission
should
indicate
that
the
necessary
information
is
not
available
at
the
time
the
submission
is
made
or
that,
based
on
the
information
available,
the
State
believes
that
no
significant
contribution
to
downwind
nonattainment
exists.
EPA
can
always
act
at
a
later
time
after
the
initial
section
110(
a)(
2)(
D)

submissions
to
issue
a
SIP
call
under
section
110(
k)(
5)
to
States
to
revise
their
SIPs
to
provide
for
additional
emission
controls
to
satisfy
the
section
110(
a)(
2)(
D)
obligations
if
such
action
were
warranted
based
upon
subsequently­
available
data
and
analyses.
This
is
precisely
the
circumstance
that
was
presented
at
the
time
of
the
NOx
SIP
Call
in
1998
when
EPA
issued
a
section
110(
k)(
5)
SIP
call
to
states
regarding
their
section
489
110(
a)(
2)(
D)
obligations
on
the
basis
of
new
information
that
was
developed
years
after
the
States'
SIPs
had
been
previously
approved
as
satisfying
section
110(
a)(
2)(
D)
without
providing
for
additional
controls
since
the
information
available
at
the
earlier
point
in
time
did
not
indicate
the
need
for
such
additional
controls.

Not
only
is
this
sequencing
consistent
with
the
CAA,
it
is
consistent
with
sound
policy
considerations.
The
upwind
reductions
required
by
today's
action
will
facilitate
attainment
planning
by
the
States
affected
by
transport
downwind.
Rather
than
being
"
premature"
as
some
commenters
suggested,
EPA's
understanding
of
the
data
and
models
leads
the
Agency
to
believe
that
requiring
the
States
to
address
the
upwind
transport
contribution
to
downwind
nonattainment
earlier
in
the
process
as
a
first
step
is
a
reasonable
approach
and
is
fully
consistent
with
the
statutory
structure.
This
approach
will
allow
downwind
States
to
develop
SIPs
that
address
their
share
of
emissions
with
knowledge
of
what
measures
upwind
States
will
have
adopted.

In
addition,
most
of
the
downwind
States
that
will
benefit
by
today's
rulemaking
are
themselves
significant
contributors
to
violations
of
the
standards
further
downwind
and,
thus,
are
subject
to
the
same
requirements
as
the
States
further
upwind.

The
reductions
these
downwind
States
must
implement
due
to
their
additional
role
as
upwind
States
will
help
reduce
their
own
PM2.5
and
8­
hour
ozone
problems
on
the
same
schedule
as
490
emissions
reductions
for
the
upwind
States.
We
believe
that
providing
18
months
from
the
date
of
today's
action
for
States
to
submit
the
transport
SIPs
required
by
this
rule
is
appropriate
and
reasonable,
for
the
reasons
discussed
more
fully
below.

a.
EPA's
Authority
to
Require
Section
110(
a)(
2)(
D)
Submissions
in
Accordance
with
the
Schedule
of
Section
110(
a)(
1).

A
number
of
commenters
objected
to
EPA's
proposal
to
require
States
to
submit
the
transport
SIPs
on
the
schedule
set
forth
in
section
110(
a)(
1).
The
commenters
argued
that
section
110(
a)(
1)
does
not
apply
to
the
requirements
of
section
110(
a)(
2)(
D),
because
the
former
refers
to
plans
that
States
must
adopt
"
to
implement,
maintain,
and
enforce"
the
NAAQS
"
within"
the
State,
whereas
the
latter
refers
to
plans
that
prevent
emissions
that
affect
nonattainment
or
maintenance
of
the
NAAQS
in
places
outside
the
State.
According
to
the
commenters,
because
section
110(
a)(
1)
SIPs
purportedly
need
not
address
the
interstate
transport
issues
governed
by
section
110(
a)(
2)(
D),
the
States
have
no
current
obligation
to
prevent
such
interstate
transport
and,
by
extension,
there
is
no
basis
for
the
CAIR
at
this
time.

The
EPA
disagrees
with
the
commenters.
A
State's
SIP
must
of
course
provide
for
"
implementation,
maintenance,
and
491
enforcement"
of
the
NAAQS
"
within"
the
State
because
States
lack
authority
to
impose
requirements
on
sources
in
other
States;

i.
e.,
any
plan
submitted
by
a
State
will
necessarily
be
applicable
to
sources
"
within"
that
State.
The
CAA,
however,

also
requires
that
such
SIPs
must
be
submitted
to
EPA
no
later
than
three
years
after
promulgation
of
a
new
or
revised
NAAQS
and
must
contain
adequate
provisions
regarding
interstate
transport
from
emission
sources
within
the
State
in
compliance
with
section
110(
a)(
2)(
D).
The
explicit
terms
of
the
statute
provide
for
the
State
submission
of
initial
SIPs
after
promulgation
of
a
new
NAAQS,
and
provide
that
such
SIPs
should
address
interstate
transport.
Section
110(
a)(
1)
provides
that:

[
e]
ach
State
shall...
adopt
and
submit
to
the
Administrator,
within
3
years
(
or
such
shorter
period
as
the
Administrator
may
prescribe)
after
the
promulgation
of
a
national
primary
ambient
air
quality
standard
(
or
any
revision
thereof)
...
a
plan
which
provides
for
implementation,

maintenance,
and
enforcement
of
such
primary
standard
in
each
[
area]
within
such
State.

Section
110(
a)(
2)
provides,
in
relevant
part,
that:

[
e]
ach
implementation
plan
submitted
by
a
State
under
this
Act
shall
be
adopted
by
the
State
after
reasonable
notice
492
and
public
hearing.
Each
such
plan
shall
...(
D)
contain
adequate
provisions
­
(
i)
prohibiting
...
any
source
or
other
type
of
emissions
activity
within
the
State
from
emitting
any
air
pollutant
in
amounts
which
will
­
(
I)

contribute
significantly
to
nonattainment
in,
or
interfere
with
maintenance
by,
any
other
State
with
respect
to
[
the
NAAQS].

By
referencing
each
implementation
plan
in
section
110(
a)(
2),
it
is
clear
that
the
implementation
plans
required
under
section
110(
a)(
1)
must
satisfy
the
requirements
of
section
110(
a)(
2)(
D).

Thus,
the
plain
meaning
of
these
provisions,
read
together,
is
that
SIP
submissions
are
required
within
3
years
of
promulgation
of
a
new
or
revised
NAAQS,
and
that
the
SIP
submissions
must
meet
the
requirements
of
section
110(
a)(
2)(
D).

By
contrast,
other
requirements
of
section
110(
a)(
2)
are
not
triggered
by
EPA's
promulgation
of
a
new
or
revised
NAAQS,

but
rather
by
EPA's
final
designation
of
nonattainment
areas.

For
example,
section
110(
a)(
2)(
I)
by
its
terms
indicates
that
State
SIPs
must
meet
that
requirement
not
on
the
schedule
of
section
110(
a)(
1),
but
instead
on
the
schedule
of
section
172(
b).

The
explicit
distinction
in
the
statute
between
requirements
that
States
must
meet
on
the
schedule
of
section
110(
a)(
1)

versus
the
schedule
of
section
172(
b)
reinforces
the
conclusion
493
114
Under
section
107(
d),
EPA
is
required
to
identify
all
areas
of
each
State
as
falling
into
one
of
these
three
categories.
that
States
are
to
meet
the
initial
requirements
of
section
110(
a)(
2)(
D)
within
the
schedule
of
section
110(
a)(
1).

In
this
context,
it
is
important
to
note
that
the
requirements
of
section
110(
a)(
1)
plans
are
not
limited
to
areas
designated
attainment,
nonattainment,
or
unclassifiable.
114
Section
110(
a)(
1)
requires
each
State
to
develop
and
submit
a
plan
that
provides
for
the
implementation,
maintenance,
and
enforcement
of
the
NAAQS
in
"
each"
area
of
the
State.

Similarly,
the
requirement
in
section
110(
a)(
2)(
D)
that
SIPs
must
prohibit
interstate
transport
of
air
pollutants
that
significantly
contribute
to
downwind
nonattainment
is
not
limited
to
any
particular
category
of
formally
designated
areas
in
the
State.
The
provisions
apply
to
emissions
activities
that
occur
anywhere
in
a
state,
regardless
of
its
designation.
If,
as
the
commenters
suggested,
the
requirements
of
section
110(
a)(
2)(
D)
plans
are
governed
not
by
section
110(
a)(
1),
but
rather
by
the
schedule
of
section
172,
that
would
lead
to
the
absurd
result
that
upwind
States
need
only
reduce
emissions
from
designated
nonattainment
areas
to
prevent
significant
contribution
to
nonattainment
or
interference
with
maintenance
in
a
downwind
State.
Given
that
large
portions
of
many
upwind
States
may
be
designated
as
attainment
for
the
NAAQS
for
local
494
115
The
EPA
notes
that
under
the
provisions
of
section
107(
d),
certain
portions
of
an
upwind
State
that
are
monitoring
attainment
may
be
designated
nonattainment
because
they
contribute
to
violations
of
the
NAAQS
in
a
"
nearby"
area.
Nevertheless,
there
will
be
portions
of
upwind
States
that
include
emissions
sources
that
are
not
in
designated
nonattainment
areas,
whether
because
of
local
monitored
nonattainment,
or
because
of
contribution
to
a
nearby
nonattainment
area,
yet
these
portions
of
the
upwind
State
may
contain
sources
that
cause
emissions
that
States
must
address
to
meet
the
requirements
of
section
110(
a)(
2)(
D).
purposes,
yet
still
contain
large
sources
of
emissions
that
affect
downwind
States
through
interstate
transport,
EPA
believes
that
Congress
could
not
have
intended
the
prohibitions
of
section
110(
a)(
2)(
D)
to
apply
only
to
nonattainment
areas
in
upwind
States.
115
Indeed,
the
language
of
section
110(
a)(
2)

itself
does
not
support
such
an
interpretation.
Therefore,
the
alternative
schedule
provided
in
section
172(
b)
applicable
only
to
nonattainment
areas
cannot
be
the
schedule
that
governs
the
State
submission
of
transport
SIPs.
This
leaves
the
schedule
of
section
110(
a)(
1)
as
the
only
appropriate
schedule
in
the
case
of
SIPs
following
EPA
promulgation
of
new
or
revised
NAAQS.

The
commenters
also
disputed
that
the
schedule
of
section
110(
a)(
1)
applies
to
the
section
110(
a)(
2)(
D)
requirement
because
there
are
other
elements
of
section
110(
a)(
2)
that
States
could
not
meet
on
that
schedule.
As
an
example,
the
commenters
pointed
to
section
110(
a)(
2)(
I)
which
requires
States
to
meet
certain
obligations
imposed
upon
designated
nonattainment
areas.
As
formal
designation
under
the
generally
495
applicable
provisions
of
section
107(
d)
could
take
up
to
3
years
following
promulgation
of
a
new
or
revised
NAAQS,
and
section
172(
b)
allows
up
to
3
additional
years
for
State
submission
of
nonattainment
area
SIPs,
the
commenters
concluded
that
States
could
not
meet
section
110(
a)(
2)(
I)
on
the
schedule
of
section
110(
a)(
1).
From
the
fact
that
States
could
not
meet
all
of
the
elements
of
the
section
110(
a)(
2)
requirement
within
3
years,

the
commenters
inferred
that
EPA
cannot
require
States
to
meet
any
of
the
requirements
in
section
110(
a)(
2),
including
section
110(
a)(
2)(
D).

EPA
disagrees
with
the
commenters'
approach
to
the
interpretation
of
the
statute.
The
EPA
agrees
that
there
are
certain
provisions
of
section
110(
a)(
2)
that
are
governed
not
by
the
schedule
of
section
110(
a)(
1),
but
instead
by
the
timing
requirement
of
section
172(
b),
e.
g.,
section
110(
a)(
2)(
I).
Other
items
in
section
110(
a)(
2),
however,
do
not
depend
upon
prior
designations
in
order
for
States
to
develop
a
SIP
to
begin
to
comply
with
them,
e.
g.,
section
110(
a)(
2)(
B)(
pertaining
to
monitoring);
section
110(
a)(
2)(
E)(
stipulating
that
States
must
provide
for
adequate
resources);
and
section
110(
a)(
2)(
K)
(
pertaining
to
modeling).

Most
important,
section
110(
a)(
2)(
D)
itself
does
not
apply
only
to
impacts
on
downwind
nonattainment
areas,
and
thus
does
not
presuppose
prior
designations
in
either
upwind
496
or
downwind
States,
or
suggest
that
section
110(
a)(
2)(
D)
is
somehow
inapplicable
until
the
submission
of
nonattainment
area
plans.
By
its
explicit
terms,
section
110(
a)(
2)(
D)

requires
States
to
prohibit
emissions
from
"
any
source
or
other
types
of
emissions
activity
within
the
State"
that
"
contribute
to
nonattainment
in,
or
interfere
with
maintenance
by"
any
other
State.
A
plain
reading
of
the
statute
indicates
that
the
emissions
at
issue
can
emanate
from
any
portion
of
an
upwind
State
and
that
the
impacts
of
concern
can
occur
in
any
portion
of
the
downwind
State
While
EPA
agrees
that
there
is
overlap
between
the
submission
requirements
of
sections
110(
a)(
1)
and
(
a)(
2)
and
section
172(
c),
EPA
believes
that
the
plain
language
of
these
sections
requires
States
to
submit
plans
that
comply
with
section
110(
a)(
2)(
D)
prior
to
the
deadline
for
nonattainment
area
SIPs
established
by
section
172,
and
that
there
is
nothing
that
compels
a
contrary
conclusion
in
the
language
of
section
172.
Section
172(
b)
provides
that
State
plans
for
nonattainment
areas
must
meet
"
the
applicable
requirements
of
[
section
172(
c)]
and
section
110(
a)(
2)"
(
emphasis
added).

Thus,
the
statute
itself
explicitly
indicates
that
the
State
submissions
for
nonattainment
plans
must
meet
those
requirements
of
section
110(
a)(
2)
that
are
"
applicable,"
not
each
requirement
regardless
of
applicability.
In
the
current
497
116
As
noted
earlier,
what
will
be
needed
to
meet
section
110(
a)(
2)
may
vary,
depending
upon
the
specific
facts
and
circumstances
surrounding
a
new
or
revised
NAAQS.
See,
e.
g.,
Proposed
Requirements
for
Implementation
Plans
and
Ambient
Air
Quality
Surveillance
for
Sulfur
Oxides
(
Sulfur
Dioxide)
National
Ambient
Air
Quality
Standard,
60
FR
12492,
12505
(
March
7,
1995).
In
the
context
of
a
proposed
5­
minute
NAAQS
for
SO2,
EPA
tentatively
concluded
that
existing
SIP
provisions
for
the
24­
hour
and
annual
SO2
NAAQS
were
probably
sufficient
to
meet
many
elements
of
section
110(
a)(
2).
The
EPA
did
not
explicitly
discuss
State
obligations
under
section
110(
a)(
2)(
D)
for
the
5­
minute
NAAQS
in
the
proposal,
but
the
nature
of
the
pollutant,
the
sources,
and
the
proposed
NAAQS
are
such
that
interstate
transport
would
not
have
been
the
critical
regionwide
concern
that
it
is
for
the
PM2.5
and
8­
hour
ozone
NAAQS.
The
EPA
does
not
expect
States
to
make
SIP
submissions
establishing
emission
controls
for
the
purpose
of
addressing
interstate
transport
without
having
adequate
information
available
to
them.

117
The
EPA
notes
that
the
8­
hour
ozone
designations
became
effective
on
June
15,
2004,
and
that
the
PM2.5
designations
will
become
effective
on
April
5,
2005.
The
EPA
believes
situation,
EPA
believes
that
it
is
appropriate
to
view
the
CAA
as
requiring
States
to
make
a
submission
to
meet
the
requirement
of
section
110(
a)(
2)(
D)
in
accordance
with
the
schedule
of
section
110(
a)(
1),
rather
than
under
the
schedule
for
nonattainment
SIPs
in
section
172(
b).
116
b.
EPA's
Authority
to
Require
Section
110(
a)(
2)(
D)

Submissions
Prior
to
Formal
Designation
of
Nonattainment
Areas
under
Section
107.

A
number
of
commenters
argued
that
EPA
has
no
authority
to
require
States
to
comply
with
section
110(
a)(
2)(
D)
until
after
EPA
formally
designates
nonattainment
areas
for
the
PM2.5
and
8­
hour
ozone
NAAQS.
117
These
commenters
claimed
498
that
the
issue
raised
by
the
commenters
is
thus
moot
with
respect
to
both
the
8­
hour
ozone
and
PM2.5
nonattainment
areas
because
those
designations
are
now
complete.
that
section
107(
d)
and
provisions
of
the
Transportation
Equity
Act
for
the
21st
Century
(
TEA­
21)
governing
the
designation
of
PM2.5
and
8­
hour
ozone
nonattainment
areas
preclude
EPA
from
interpreting
the
CAA
to
require
States
to
submit
SIPs
that
comply
with
section
110(
a)(
2)(
D)
on
the
schedule
contemplated
by
section
110(
a)(
1).
In
the
view
of
the
commenters,
EPA
could
not
reasonably
expect
States
to
determine
whether
and
to
what
extent
their
in­
State
sources
significantly
contributed
to
nonattainment
in
other
States
within
the
initial
3­
year
timeframe,
in
advance
of
nonattainment
area
designations.
According
to
the
commenters,
section
107(
d)
and
TEA­
21
negate
the
timing
requirements
of
section
110(
a)(
1),
so
that
States
have
no
current
obligation
to
address
interstate
transport
and
thus
there
is
no
basis
for
today's
action.

The
EPA
disagrees
with
the
commenters'
view
of
the
interaction
of
section
110
and
section
107(
d).
The
statute
does
not
require
EPA
to
have
completed
the
designations
process
before
the
Agency
or
a
State
could
assess
the
existence
of,
or
extent
of,
significant
contribution
from
one
State
to
another.
In
addition,
the
technical
approach
by
which
EPA
determines
significant
contribution
from
upwind
to
499
118
For
reasons
discussed
in
more
detail
above,
EPA
interprets
the
requirement
of
section
110(
a)(
2)(
D)
to
be
among
those
that
Congress
intended
States
to
meet
within
the
3­
year
timeframe
of
section
110(
a)(
1).
The
EPA
agrees
that
other
requirements,
such
as
those
of
section
110(
a)(
2)(
I),
are
subject
to
the
different
timing
requirements
of
section
172(
b).
downwind
States
does
not
depend
upon
the
prior
completion
of
the
designation
process.

The
EPA
believes
that
the
statute
does
not
compel
the
conclusion
that
States
may
postpone
compliance
with
section
110(
a)(
2)(
D)
until
some
future
point
after
completion
of
the
designation
process.
As
discussed
above,
a
reading
of
the
plain
language
of
sections
110(
a)(
1)
and
110(
a)(
2)
indicates
that
States
must
adopt
and
submit
a
plan
to
EPA
within
3
years
after
promulgation
of
a
new
or
revised
NAAQS
(
the
same
time
at
which
designations
are
generally
due
under
section
107),
and
that
each
such
plan
must
meet
the
applicable
requirements
of
section
110(
a)(
2)(
D).
118
Significantly,
neither
section
110(
a)(
1)
nor
section
110(
a)(
2)(
D)
are
limited
to
"
nonattainment"
areas.
By
their
explicit
terms,
both
provisions
apply
to
all
areas
within
the
State,
regardless
of
whether
EPA
has
formally
designated
the
areas
as
attainment,
nonattainment,
or
unclassifiable,

pursuant
to
section
107(
d).
As
to
causes,
section
110(
a)(
2)(
D)
compels
States
to
address
any
"
emissions
activity
within
the
State,"
not
solely
emissions
from
500
formally
designated
nonattainment
areas,
nor
does
it
in
any
other
terms
suggest
that
designations
of
upwind
areas
must
first
have
occurred.
As
to
impacts,
section
110(
a)(
2)(
D)

refers
only
to
prevention
of
"
nonattainment"
in
other
States,

not
to
prevention
of
nonattainment
in
designated
nonattainment
areas
or
any
similar
formulation
requiring
that
designations
for
downwind
nonattainment
areas
must
first
have
occurred.
By
comparison,
other
provisions
of
the
CAA
do
clearly
indicate
when
they
are
applicable
to
designated
nonattainment
areas,
rather
than
simply
to
nonattainment
more
generally
(
e.
g.,
sections
107(
d)(
1)(
A)(
i),
181(
b)(
2)(
A),
and
211(
k)(
10)(
D)).
Because
section
110(
a)(
2)(
D)
refers
only
to
"
nonattainment,"
not
to
"
nonattainment
areas,"
EPA
concludes
that
the
section
does
not
presuppose
the
existence
of
formally
designated
nonattainment
areas,
but
rather
to
ambient
air
quality
that
does
not
attain
the
NAAQS.

The
EPA
believes
that
this
plain
reading
of
the
provisions
is
also
the
most
logical
approach.
A
reading
that
section
110(
a)(
2)(
D)
means
that
States
have
no
obligation
to
address
interstate
transport
unless
and
until
there
are
formally
designated
nonattainment
areas
pursuant
to
section
107
would
be
inconsistent
with
the
larger
goal
of
the
CAA
to
encourage
expeditious
attainment
of
the
NAAQS.
In
this
immediate
instance,
currently
available
air
quality
monitoring
data
and
modeling
make
it
clear
that
many
areas
of
501
the
eastern
portion
of
the
country
are
in
violation
of
both
the
PM2.5
and
8­
hour
ozone
NAAQS.
Air
quality
modeling
studies
generally
available
to
the
States
demonstrate
that,

and
quantify
the
extent
to
which,
SO2
and
NOx
emissions
from
sources
in
upwind
States
are
contributing
to
violations
of
the
PM2.5
and
8­
hour
ozone
NAAQS
in
downwind
States.

Following
the
example
of
the
NOx
SIP
Call,
EPA
has
an
effective
analytical
approach
to
determine
whether
that
interstate
contribution
is
significant,
in
accordance
with
section
110(
a)(
2)(
D).
Thus,
EPA
currently
has
the
information
and
tools
that
it
needs
to
determine
what
the
initial
PM2.5
and
8­
hour
ozone
SIPs
from
upwind
States
should
include
as
appropriate
NOx
and
SO2
emissions
reductions
in
order
to
prevent
emissions
that
significantly
contribute
to
nonattainment
in
downwind
States.
The
designation
process
under
section
107
is
the
means
by
which
States
and
EPA
decide
the
precise
boundaries
of
the
nonattainment
areas
in
the
downwind
States.
Both
PM2.5
and
ozone
are
regional
phenomena,
however,
and
information
as
to
the
precise
boundaries
of
nonattainment
areas
is
not
necessary
to
implement
the
requirements
of
section
110(
a)(
2)(
D)
for
these
pollutants.
Consequently,
it
was
not
necessary
for
EPA
to
wait
until
after
completion
of
formal
designation
of
nonattainment
area
boundaries
before
undertaking
this
rulemaking.
Moreover,
EPA
believes
that
taking
action
now
502
will
achieve
public
health
protections
more
quickly
as
it
will
enable
States
to
develop
implementation
plans
more
expeditiously
and
efficiently.

The
EPA
disagrees
with
the
commenters'
view
of
the
relationship
between
section
110(
a)(
2)
and
section
107
and
their
apparent
view
of
the
method
by
which
EPA
analyzes
whether
there
is
a
contribution
from
an
upwind
State
to
a
downwind
State,
and
whether
that
contribution
is
significant.

EPA
has,
in
this
case,
used
the
detailed
data
from
the
extensive
network
of
air
quality
monitors
to
identify
which
States
have
monitors
that
are
currently
showing
violations
of
the
PM2.5
and
8­
hour
ozone
NAAQS.
In
the
NPR,
EPA
stated
that
based
upon
data
for
the
3­
year
period
from
2000
­
2002,

"
120
counties
with
monitors
exceed
the
annual
PM2.5
NAAQS
and
297
counties
with
monitor
readings
exceed
the
8­
hour
ozone
NAAQS"
(
69
FR
4566,
4581;
January
30,
2004)(
emphasis
added).

The
geographic
distribution
of
monitors
with
data
registering
current
violations
indicated
that
there
is
nonattainment
of
both
the
PM2.5
and
8­
hour
ozone
NAAQS
throughout
the
eastern
United
States
and
in
other
portions
of
the
country
including
California.
For
analyses
of
future
ambient
conditions,
EPA
used
various
modeling
tools
to
predict
that,
in
the
absence
of
the
CAIR,
there
would
be
counties
with
monitors
that
would
continue
to
show
violations
of
the
PM2.5
and
8
hour
ozone
NAAQS
in
2010
and
2015.
In
subsequent
steps,
EPA
analyzed
503
whether
the
emissions
from
upwind
States
contributed
to
the
ambient
conditions
at
the
monitors
registering
NAAQS
violations
in
downwind
States,
and
thereafter
determined
whether
that
contribution
would
be
significant
pursuant
to
section
110(
a)(
2)(
D).

In
none
of
these
steps,
however,
did
EPA
need
to
know
the
precise
boundaries
of
the
nonattainment
areas
that
may
ultimately
result
from
the
section
107
designation
process.

The
determination
of
attainment
status
in
a
given
county
is
based
primarily
upon
the
monitored
ambient
measurements
of
the
applicable
pollutant
in
the
county.
Thus,
it
is
the
readings
at
the
monitors
that
are
the
appropriate
information
for
EPA
to
evaluate
in
assessing
current
and
future
interstate
transport
at
that
monitor
in
that
county,
not
the
exact
dimensions
of
the
area
that
may
ultimately
comprise
the
formally
designated
nonattainment
area.
The
ultimate
size
of
nonattainment
areas
will
have
a
bearing
on
other
components
of
the
State's
nonattainment
area
SIP.
The
size
of
such
nonattainment
areas,
however,
is
not
meaningful
in
assessing
whether
interstate
transport
from
another
State
or
States
has
an
impact
at
a
violating
monitor,
and
whether
the
transport
significantly
contributes
to
nonattainment,
that
the
other
State
or
States
should
address
to
comply
with
section
110(
a)(
2)(
D).
Thus,
EPA
believes
that
basing
the
significant
contribution
analysis
upon
the
counties
with
monitors
that
504
register
nonattainment,
without
regard
to
the
precise
boundaries
of
the
nonattainment
areas
that
may
ultimately
result
from
the
formal
designation
process
under
section
107,

is
the
proper
approach.

For
similar
reasons,
EPA
also
disagrees
with
the
commenters'
assertion
that
the
provisions
of
TEA­
21
preclude
EPA's
interpretation
of
the
timing
requirements
of
sections
110(
a)(
1)
and
110(
a)(
2).
However,
TEA­
21
did
address
the
need
to
create
a
new
network
of
monitors
to
assess
the
geographic
scope
and
location
of
PM2.5
nonattainment.
Also,

TEA­
21
did
provide
that
such
a
network
should
be
up
and
running
by
December
31,
1999.
TEA­
21
did
lay
out
a
schedule
for
the
collection
of
data
over
a
period
of
3
years
in
order
to
make
subsequent
regulatory
decisions.
From
these
facts,

the
commenters
concluded
that
TEA­
21
necessarily
contradicts
EPA's
position
that
States
must
now
take
action
to
address
significant
contribution
to
downwind
nonattainment
in
their
initial
section
110(
a)(
1)
SIPs,
merely
because
the
initial
three­
year
period
following
the
promulgation
of
a
new
or
revised
NAAQS
specified
in
section
110(
a)(
1)
has
expired.

The
EPA
believes
that
nothing
in
TEA­
21
explicitly
or
implicitly
altered
the
timing
requirements
of
section
110(
a)(
1)
for
compliance
with
section
110(
a)(
2)(
D),
although
EPA
recognizes
that
the
data
from
monitoring
funded
by
that
Act
contributed
to
the
Agency's
development
of
the
SIP
505
requirements
in
today's
rulemaking.
The
provisions
of
TEA­
21
pertained
to
the
installation
of
a
network
of
monitors
for
PM2.5,
and
to
the
timing
of
designation
decisions
for
PM2.5
and
8­
hour
ozone.
To
be
specific,
TEA­
21
had
two
primary
purposes
for
the
new
NAAQS:
(
1)
to
gather
information
"
for
use
in
the
determination
of
area
attainment
or
nonattainment
designations"
for
the
PM2.5
NAAQS;
and
(
2)
to
ensure
that
States
had
adequate
time
to
consider
guidance
from
EPA
concerning
"
drawing
area
boundaries
prior
to
submitting
area
designations"
for
the
8­
hour
ozone
NAAQS.
TEA­
21
sections
6101(
b)(
1)
and
(
2).
The
EPA
interprets
the
third
stated
purpose
of
TEA­
21
to
refer
to
ensuring
consistency
of
timing
between
the
Regional
Haze
program
requirements
and
the
PM2.5
NAAQS
requirements.
With
respect
to
timing,
TEA­
21
similarly
only
referred
to
the
dates
by
which
States
and
EPA
should
take
their
respective
actions
concerning
designations.
For
PM2.5,
TEA­
21
provided
that
States
were
required
"
to
submit
designations
referred
to
in
section
107(
d)(
1)
...
within
1
year
after
receipt
of
3
years
of
air
quality
monitoring
data."
TEA­
21
section
6102(
c)(
1).
For
8­
hour
ozone,
TEA­
21
required
States
to
submit
designation
recommendations
within
2
years
after
the
promulgation
of
the
new
NAAQS,
and
required
EPA
to
make
final
designations
within
1
year
after
that
(
TEA­

21
sections
6103(
a)
and
(
b)).
In
all
of
these
provisions,

TEA­
21
only
addresses
SIP
timing
in
the
context
of
the
506
designation
process
of
section
107(
d).
As
explained
in
more
detail
above,
EPA
does
not
believe
that
the
timing
of
section
110(
a)(
1)
and
section
110(
a)(
2)(
D)
obligations
depend
upon
the
prior
designation
of
areas
in
accordance
with
section
107(
d).

The
EPA
also
notes
that
legislation
subsequent
to
TEA­
21
further
supports
this
conclusion.
In
the
2004
Consolidated
Appropriations
Act,
Congress
further
amended
section
107
to
provide
specific
dates
by
which
States
and
EPA
must
make
PM2.5
designations.
42
USC
section
7407
note.
The
Act
now
requires
States
to
have
made
their
initial
recommendations
for
PM2.5
designations
by
February
15,
2004,
and
requires
EPA
to
take
action
on
those
recommendations
and
make
its
final
designation
decisions
no
later
than
December
31,
2004.
Again,

these
requirements
pertain
only
to
formal
designations,
and
do
not
directly
affect
the
obligations
of
States
to
meet
other
SIP
requirements.
Neither
TEA­
21
nor
the
2004
Appropriations
Act
language
altered
the
section
110(
a)(
1)

schedule
for
compliance
with
section
110(
a)(
2)(
D).

The
commenters
suggested
that
because
Congress
provided
more
time
for
making
formal
designations
pursuant
to
section
107,
it
necessarily
follows
that
States
should
not
have
to
meet
the
requirements
of
section
110(
a)(
2)(
D)
on
the
schedule
of
section
110(
a)(
1).
The
EPA
believes
that
Congress
did
not,
through
TEA­
21
or
other
actions,
alter
the
existing
507
submission
schedule
for
SIPs
to
address
interstate
transport.

By
contrast,
Congress
did
explicitly
alter
the
schedule
for
submission
of
plan
revisions
to
address
Regional
Haze.
From
this,
EPA
infers
that
Congress
did
not
intend
EPA
to
delay
action
to
address
the
issue
of
interstate
transport
for
the
8­
hour
or
PM
2.5
NAAQS.
Thus,
EPA
must
still
ensure
that
States
submit
SIPs
in
accordance
with
the
substantive
requirements
of
section
110(
a)(
2)(
D).
However,
because
EPA
and
the
States
now
have
the
data
and
analyses
to
establish
the
presence
and
magnitude
of
interstate
transport,
in
part
through
the
monitoring
data
gathered
pursuant
to
TEA­
21,
the
Agency
believes
that
that
it
is
now
appropriate
to
require
States
to
address
interstate
transport
at
this
time
in
the
manner
set
forth
in
today's
rule.

c.
EPA's
Authority
to
Require
Section
110(
a)(
2)(
D)

Submissions
Prior
to
State
Submission
of
Nonattainment
Area
Plans
Under
Section
172.

Some
commenters
suggested
that
EPA
cannot
determine
the
existence
of
a
significant
contribution
from
upwind
States
to
downwind
States
until
EPA
actually
receives
the
nonattainment
area
SIPs
from
each
State
and
evaluates
how
much
"
residual"

nonattainment
remains.
If
the
reasoning
of
these
commenters
were
adopted,
downwind
States
would
have
to
construct
SIPs
to
attain
the
NAAQS
without
first
knowing
what
upwind
States
508
might
ultimately
do
to
reduce
interstate
transport.

Presumably,
the
theory
is
that
the
downwind
States
may
choose
to
control
their
own
local
emissions
sources
more
aggressively
so
that
sources
in
upwind
States
could
avoid
installation
of
highly
cost­
effective
emission
controls,

notwithstanding
the
continued
significant
impacts
of
emissions
from
upwind
sources
on
downwind
States.

Alternatively,
the
rationale
may
be
that
EPA
should
wait
until
submission
of
upwind
State
nonattainment
area
SIPs
to
discover
whether
and
to
what
degree
the
SIPs
address
interstate
transport
to
downwind
States.

For
reasons
already
discussed
more
fully
above,
EPA
does
not
believe
that
the
statute
requires
a
"
wait
and
see"

approach
to
discover
what,
if
anything,
States
may
ultimately
do
to
address
the
problem
of
regional
interstate
transport.

Section
110(
a)(
1)
requires
"
each"
State
to
submit
a
SIP
within
3
years
after
a
new
or
revised
NAAQS
addressing
the
requirements
of
section
110(
a)(
2)(
D).
When
the
data
and
the
analyses
needed
to
establish
the
existence
of
interstate
transport
of
pollutants
and
to
determine
whether
there
is
a
significant
contribution
to
nonattainment
or
interference
with
maintenance
by
one
State
in
another
State
are
available,

as
here
after
the
monitoring
funded
by
TEA­
21,
EPA
believes
that
it
may
act
upon
that
information
prior
to
State
SIP
submissions
to
ensure
that
States
address
such
contribution
509
expeditiously,
as
it
is
doing
in
this
rulemaking.
The
EPA
believes
it
is
a
better
policy
to
assist
the
States
to
address
the
regional
component
of
the
nonattainment
problem
in
a
way
that
is
equitable,
timely,
cost
effective,
and
certain.

The
EPA
acknowledges
that
historically,
especially
in
the
case
of
1­
hour
ozone,
the
Agency
has
not
had
the
data
and
the
analytical
tools
to
help
upwind
States
to
address
interstate
transport
as
early
in
the
SIP
process
as
it
is
doing
today
for
PM2.5
and
8­
hour
ozone.
The
CAA
has
required
States
to
regulate
ozone
or
its
regulatory
predecessors
since
1970.
For
many
years,
States
and
EPA
focused
on
the
adoption
and
implementation
of
local
controls
to
bring
local
nonattainment
areas
into
attainment.
Thus,
historically,

local
areas
bore
the
burden
of
achieving
attainment
through
imposition
of
control
measures
on
local
sources.
By
comparison,
upwind
States
did
not
have
to
adopt
local
controls
in
attainment
areas
and
typically
did
not
adopt
such
controls
solely
to
lessen
the
impact
of
their
emissions
on
downwind
States.
Since
1977,
the
CAA
has
also
imposed
a
series
of
local
control
obligations
on
1­
hour
ozone
nonattainment
areas,
such
as
RACT
for
stationary
sources,

inspection
and
maintenance
for
mobile
sources,
and
other
requirements
that
became
increasingly
more
stringent,
based
upon
the
level
of
local
nonattainment.
In
spite
of
these
510
local
control
efforts,
there
continued
to
be
a
widespread
problem
with
nonattainment
that
resulted,
in
part,
from
unaddressed
interstate
transport.
A
lack
of
information
and
analytical
tools
hindered
the
ability
of
EPA
and
the
States
to
address
the
regional
interstate
transport
component
of
1­

hour
ozone
nonattainment,
until
the
NOx
SIP
Call
in
1998.

While
it
is
thus
true
that
the
NOx
SIP
Call
postdated
the
submission
of
nonattainment
area
SIPs,
this
should
not
be
construed
as
evidence
that
the
statute
precludes
the
States
and
EPA
from
addressing
interstate
transport
earlier
in
the
process
for
the
8­
hour
ozone
and
PM
2.5
NAAQS.

Given
that
EPA
and
the
States
indisputably
have
the
requisite
information
to
identify
interstate
transport
at
this
stage
of
SIP
development,
EPA
believes,
based
upon
its
experience
in
implementing
the
1­
hour
ozone
NAAQS,
that
it
is
preferable
to
take
action
under
section
110(
a)(
2)(
D)
to
address
the
regional
transport
component
of
the
PM2.5
and
8­

hour
ozone
nonattainment
problem.
States,
both
upwind
and
downwind,
will
still
have
an
obligation
to
control
emissions
from
sources
within
their
boundaries
for
the
purposes
of
local
area
attainment
and
maintenance
of
the
NAAQS.
The
EPA
does
not
believe,
however,
that
it
is
either
required
by
the
statute,
or
in
accordance
with
sound
policy,
for
the
Agency
to
wait
until
submission
of
the
nonattainment
area
SIPs
of
downwind
States
to
discover
whether
or
not
those
SIPs
will
511
control
local
sources
sufficiently
to
provide
for
eventual
attainment
regardless
of
continued
significant
contribution
through
interstate
transport
from
upwind
States.
To
the
contrary,
past
experience
with
the
1­
hour
ozone
NAAQS
has
demonstrated
that
delayed
action
to
address
the
interstate
component
of
nonattainment
will
potentially
lead
to
delays
in
attainment
as
downwind
areas
struggle
to
overcome
the
impacts
of
transport.
Indeed,
a
number
of
scientific
and
technical
assessments
of
ozone
and
PM2.5
by
the
NRC
and
the
Ozone
Transport
Assessment
Group
have
identified
addressing
interstate
transport
as
a
critical
issue
in
developing
SIPs.

d.
EPA's
Authority
to
Require
Section
110(
a)(
2)(
D)

Submissions
Prior
to
Completion
of
the
Next
Review
of
the
PM2.5
and
8­
hour
Ozone
NAAQS.

Commenters
also
asserted
that
EPA
should
not
take
any
action
to
implement
the
8­
hour
ozone
and
PM2.5
NAAQS,
until
completion
of
the
next
NAAQS
review
cycle.
According
to
the
commenters,
a
series
of
statements
by
EPA
and
others
indicated
an
intention
to
take
no
action
to
implement
the
NAAQS
until
after
the
next
review
cycle,
and
that
statutes
passed
by
Congress
confirm
that
EPA
is
to
take
no
such
action.

The
EPA
disagrees
with
the
assertion
that
it
should
take
no
action
to
implement
the
1997
PM2.5
and
8­
hour
ozone
NAAQS
512
until
completion
of
the
next
NAAQS
review.
Section
110(
a)

explicitly
requires
States
to
begin
to
submit
SIPS
within
3
years
after
promulgation
of
a
new
or
revised
NAAQS.
The
CAA
also
requires
EPA
to
take
action
upon
State
SIP
submissions
within
specific
timeframes.
States
are
likewise
explicitly
obligated
to
attain
existing
NAAQS
within
certain
specified
timeframes.
None
of
these
basic
statutory
submission,

review,
or
attainment
obligations
are
stayed
or
delayed
due
to
the
fact
that
there
may
be
an
ongoing
NAAQS
review
cycle.

Indeed,
under
section
109,
EPA
is
to
review
all
NAAQS
on
an
ongoing
basis,
every
5
years.
If
the
mere
existence
of
a
NAAQS
review
cycle
were
grounds
to
suspend
implementation
of
a
NAAQS,
it
would
undermine
the
very
goals
of
the
statute.

The
commenters
argued
that
certain
statements
made
by
EPA
and
others
in
guidance
memoranda
and
elsewhere
preclude
EPA
from
taking
any
action
to
implement
the
PM2.5
and
8­
hour
ozone
NAAQS.
The
EPA
believes
that
the
commenters
are
misconstruing
those
statements,
and
that
the
statements
merely
reflect
the
Agency's
assumption
that
the
NAAQS
review
cycle
would
occur
on
the
normal
schedule.
It
would
be
nonsensical
to
suggest
that,
if
for
any
reason,
the
NAAQS
review
cycle
were
delayed,
that
the
CAA
would
permit
no
implementation
of
the
existing
NAAQS.
Such
an
approach
would
invite
and
encourage
inappropriate
interference
in
the
NAAQS
review
cycle
as
a
means
of
subverting
the
CAA.
513
The
commenters
further
argued
that
Congress
has
taken
action
to
prevent
implementation
of
the
8­
hour
ozone
and
PM2.5
NAAQS
pending
the
next
NAAQS
review
cycle.
The
EPA
does
not
see
any
such
intention
on
the
part
of
Congress.
In
TEA­
21
and
the
2004
Consolidated
Appropriations
Act,
Congress
has
amended
section
107
to
provide
specific
dates
by
which
States
and
EPA
must
make
designations.
Significantly,

Congress
did
not
alter
the
existing
statute
with
respect
to
any
other
deadlines
for
SIP
submissions,
or
with
respect
to
implementation
of
the
PM2.5
and
8­
hour
ozone
NAAQS
generally.

By
contrast,
in
the
2004
Consolidated
Appropriations
Act,

Congress
did
explicitly
alter
the
date
by
which
States
must
submit
plan
revisions
to
address
Regional
Haze.
See,
Section
7(
A),
42
USC
section
7407
note.
From
this
explicit
action,

one
must
infer
that
Congress
could
have
taken
action
to
alter
the
submission
date
for
plans
to
address
PM2.5
or
8­
hour
ozone,
had
it
intended
to
alter
the
existing
statutory
scheme.
Most
importantly,
however,
Congress
did
not
make
any
of
the
changes
effected
in
TEA­
21
or
the
2004
Consolidated
Appropriations
Act
dependent
upon
completion
of
the
next
NAAQS
review.
To
the
contrary,
Congress
directed
EPA
to
take
certain
actions
notwithstanding
the
fact
that
there
were
and
are
ongoing
reviews
of
the
NAAQS.
From
this,
EPA
infers
that
Congress
did
not
intend
EPA
to
defer
all
action
to
implement
514
the
existing
NAAQS,
including
today's
action
to
assist
States
to
address
the
requirements
of
section
110(
a)(
2)(
D).

e.
EPA's
Authority
to
Require
States
to
Make
Section
110(
a)(
2)(
D)
Submissions
within
18
Months
of
this
Final
Rule.

Some
commenters
questioned
EPA's
proposal
to
require
States
to
make
SIP
submissions
in
response
to
this
action
as
expeditiously
as
practicable
but
no
later
than
within
18
months.
A
number
of
commenters
suggested
that
this
schedule
is
too
short
because
of
the
magnitude
or
complexity
of
the
task
or
because
of
the
typical
duration
of
State
rulemaking
processes.
Other
commenters
suggested
that
EPA
should
follow
the
example
of
the
NOx
SIP
Call
more
closely
and
provide
a
shorter
period
than
the
Agency
proposed.

The
EPA
has
concluded
that
the
proposed
18­
month
schedule
is
reasonable
given
the
circumstances
and
given
the
scope
of
the
actions
that
we
are
requiring
States
to
take.

We
issued
the
PM2.5
and
8­
hour
ozone
NAAQS
revisions
in
July
1997.
More
than
3
years
have
already
elapsed
since
promulgation
of
the
NAAQS,
and
States
have
not
submitted
SIPs
to
address
their
section
110(
a)(
2)(
D)
obligations
under
the
new
NAAQS.
We
recognize
that
litigation
over
the
new
PM2.5
and
8­
hour
ozone
NAAQS
created
substantial
uncertainty
as
to
whether
the
courts
would
uphold
the
new
NAAQS,
and
that
this
uncertainty,
as
a
practical
matter,
rendered
it
more
515
difficult
for
States
to
develop
SIPs.
Moreover,
in
the
case
of
PM2.5,
additional
time
was
needed
for
creation
of
an
adequate
monitoring
network,
collection
of
at
least
3
years
of
data
from
that
network,
and
analysis
of
those
data.

In
addition,
in
the
NPR,
the
SNPR,
and
today's
action,

we
have
provided
States
with
a
great
deal
of
data
and
analysis
concerning
air
quality
and
control
costs,
as
well
as
policy
judgments
from
EPA
concerning
the
appropriate
criteria
for
determining
whether
upwind
sources
contribute
significantly
to
downwind
nonattainment
under
section
110(
a)(
2)(
D).
We
recognize
that
States
would
face
great
difficulties
in
developing
transport
SIPs
to
meet
the
requirements
of
today's
action
without
these
data
and
policies.
In
light
of
these
factors
and
the
fact
that
States
can
no
longer
meet
the
original
three­
year
submittal
date
of
section
110(
a)(
1),
we
believe
that
States
need
a
reasonable
period
of
time
in
which
to
comply
with
the
requirements
of
today's
action.

In
the
comparable
NOx
SIP
Call
rulemaking,
EPA
provided
12
months
for
the
affected
States
to
submit
their
SIP
revisions.
One
of
the
factors
that
we
considered
in
setting
that
12­
month
period
was
that
upwind
States
had
already,
as
part
of
the
Ozone
Transport
Assessment
Group
process
begun
3
years
before
the
NOx
SIP
Call
rulemaking,
been
given
the
opportunity
to
consider
available
control
options.
Because
516
119
See,
e.
g.,
section
182(
a)(
2)(
A)(
providing
a
6­
month
schedule
for
submission
of
a
revision
to
provide
for
RACT
today's
action
requires
affected
States
to
control
both
SO2
and
NOx
emissions,
and
to
do
so
for
the
purpose
of
addressing
both
the
PM2.5
and
8­
hour
ozone
NAAQS,
we
believe
it
is
reasonable
to
allow
affected
States
more
time
than
was
allotted
in
the
NOx
SIP
Call
to
develop
and
submit
transport
SIPs.

Another
factor
that
we
have
considered
is
that
under
section
110(
k)(
5),
the
CAA
stipulates
that
EPA
may
provide
up
to
18
months
for
SIP
submissions
to
correct
substantially
inadequate
plans.
While
today's
action
is
not
pursuant
to
section
110(
k)(
5),
we
believe
that
the
provision
provides
an
analogy
for
the
appropriate
schedule
on
which
EPA
should
expect
States
to
make
the
submission
required
by
today's
action.
We
believe
it
would
not
be
appropriate
to
set
a
longer
schedule
for
submission
of
the
plan
than
would
have
been
possible
under
section
110(
k)(
5)
had
the
States
submitted
a
plan
on
the
original
3­
year
schedule
contemplated
in
section
110(
a)(
1)
that
did
not
provide
for
the
emissions
reductions
today's
action
requires.
While
the
CAA
does
require
States
to
make
some
SIP
submissions
on
shorter
schedules,
we
conclude
that
the
complexities
of
the
action
required
by
today's
rulemaking
militate
in
favor
of
a
longer
schedule.
119
517
corrections);
section
189(
d)
(
providing
12
months
for
submission
of
plan
revisions
to
ensure
attainment
and
required
emissions
reductions).
The
former
revision
could
be
relatively
limited
in
scope,
but
the
latter
might
entail
submission
of
a
completely
revised
SIP.
Finally,
we
note
that
by
making
findings
that
States
have
thus
far
failed
to
submit
SIPs
to
meet
the
requirements
of
section
110(
a)(
2)(
D)
for
the
8­
hour
ozone
and
PM2.5
NAAQS,

EPA
has
an
obligation
to
implement
a
Federal
implementation
plan
(
FIP)
to
address
interstate
transport
no
later
than
24
months
after
that
finding,
if
the
States
fail
to
take
appropriate
action.
Given
this
schedule
for
the
FIP
obligation,
EPA
believes
that
it
is
reasonable
to
require
States
to
take
action
to
meet
the
section
110(
a)(
2)(
D)

obligation
with
respect
to
the
significant
contribution
identified
in
today's
rule
within
no
more
than
18
months.

Such
a
schedule
will
allow
States
adequate
time
to
develop
submissions
to
meet
this
requirement
and
will
afford
EPA
adequate
time
to
review
such
submissions
before
the
imposition
of
a
FIP
in
lieu
of
a
SIP,
if
necessary.

Thus,
EPA
has
concluded
that
States
should
submit
SIPs
to
reduce
interstate
transport,
as
required
by
this
final
action,
as
expeditiously
as
practicable
but
no
later
than
18
months
from
today's
date.
Such
a
schedule
will
provide
both
upwind
and
downwind
States,
and
those
States
that
are
in
both
positions
relative
to
other
States,
to
develop
SIPs
that
will
518
facilitate
expeditious
attainment
of
the
PM2.5
and
the
8­
hour
ozone
standards.
C.
What
Happens
If
a
State
Fails
to
Submit
a
Transport
SIP
or
EPA
Disapproves
the
Submitted
SIP?

1.
Under
What
Circumstances
Is
EPA
Required
to
Promulgate
a
FIP?

Under
section
110(
c)(
1),
EPA
is
required
to
promulgate
a
FIP
within
2
years
of:
(
1)
finding
that
a
State
has
failed
to
make
a
required
submittal;
or
(
2)
finding
that
a
submittal
received
does
not
satisfy
the
minimum
completeness
criteria
established
under
section
110(
k)(
1)(
A)
(
40
CFR
part
51,

appendix
V);
or
(
3)
disapproving
a
SIP
submittal
in
whole
or
in
part.
Section
110(
c)(
1)
mandates
that
EPA
promulgate
a
FIP
unless
the
States
corrects
the
deficiency
and
EPA
approves
the
SIP
before
the
time
EPA
would
promulgate
the
FIP.

2.
What
Are
the
Completeness
Criteria?

Any
SIP
submittal
that
is
made
with
respect
to
the
final
CAIR
requirements
first
would
be
determined
to
be
either
incomplete
or
complete.
A
finding
of
completeness
is
not
a
determination
that
the
submittal
is
approvable.
Rather,
it
means
the
submittal
is
administratively
and
technically
sufficient
for
EPA
to
proceed
with
its
review
to
determine
whether
the
submittal
meets
the
statutory
and
regulatory
requirements
for
approval.
Under
40
CFR
51.123
and
40
CFR
519
51.124
(
the
proposed
new
regulations
for
NOx
and
SO2
SIP
requirements,
respectively),
a
submittal,
to
be
complete,

must
meet
the
criteria
described
in
40
CFR,
part
51,
appendix
V,
"
Criteria
for
Determining
the
Completeness
of
Plan
Submissions."
These
criteria
apply
generally
to
SIP
submissions.

Under
CAA
section
110(
k)(
1)
and
section
1.2
of
appendix
V,
EPA
must
notify
States
whether
a
submittal
meets
the
requirements
of
appendix
V
within
60
days
of,
but
no
later
than
6
months
after,
EPA's
receipt
of
the
submittal.
If
a
completeness
determination
is
not
made
within
6
months
after
submission,
the
submittal
is
deemed
complete
by
operation
of
law.
For
rules
submitted
in
response
to
the
CAIR,
EPA
intends
to
make
completeness
determinations
expeditiously.

3.
When
Would
EPA
Promulgate
the
CAIR
Transport
FIP?

The
EPA
views
seriously
its
responsibility
to
address
the
issue
of
regional
transport
of
PM2.5,
ozone,
and
precursor
emissions.
Decreases
in
NOx
and
SO2
emissions
are
needed
in
the
States
named
in
the
CAIR
to
enable
the
downwind
States
to
develop
and
implement
plans
to
achieve
the
PM2.5
and
8­
hour
ozone
NAAQS
and
provide
clean
air
for
their
residents.
Thus,
EPA
intends
to
promulgate
the
FIP
shortly
after
the
CAIR
SIP
submission
deadline
for
States
that
fail
to
submit
approvable
SIPs
in
order
to
help
assure
that
the
520
downwind
States
realize
the
air
quality
benefits
of
regional
NOx
and
SO2
reductions
as
soon
as
practicable.
This
is
consistent
with
Congress'
intent
that
attainment
occur
in
these
downwind
nonattainment
areas
"
as
expeditiously
as
practicable"
(
sections
181(
a),
172(
a)).
To
this
end,
EPA
intends
to
propose
the
FIP
prior
to
the
SIP
submission
deadline.

The
FIP
proposal
would
achieve
the
NOx
and
SO2
emissions
reductions
required
under
the
CAIR
by
requiring
EGUs
in
affected
States
to
reduce
emissions
through
participation
in
Federal
NOx
and
SO2
cap­
and­
trade
programs.
The
EPA
intends
to
integrate
these
Federal
trading
programs
with
the
model
trading
programs
that
States
may
choose
to
adopt
to
meet
the
CAIR.
Although
EPA
would
be
proposing
FIPs
for
all
States
affected
by
the
CAIR,
EPA
will
only
issue
a
final
FIP
for
those
jurisdictions
that
fail
to
respond
adequately
to
the
CAIR.

The
EPA's
goal
is
to
have
approvable
SIPs
that
meet
the
requirements
of
the
CAIR.
We
remain
ready
to
work
with
the
States
to
develop
fully
approvable
SIPs,
which
would
eliminate
the
need
for
EPA
to
promulgate
a
FIP.

D.
What
Are
the
Emissions
Reporting
Requirements
for
States?

The
EPA
believes
that
it
is
essential
that
achievement
of
the
emissions
reductions
required
by
the
CAIR
be
verified
521
on
a
regular
basis.
Emission
reporting
is
the
principal
mechanism
to
verify
these
reductions
and
to
assure
the
downwind
affected
States
and
EPA
that
the
ozone
and
PM2.5
transport
problems
are
being
mitigated
as
required
by
the
rule.
Therefore,
the
final
rule
establishes
a
small
set
of
new
emission
reporting
requirements
applicable
to
States
affected
by
the
CAIR,
covering
certain
emissions
data
not
already
required
under
existing
emission
reporting
regulations.
The
rule
language
also
removes
a
current
emission
reporting
requirement
related
to
the
NOX
SIP
call,

which
we
believe
is
not
necessary,
for
reasons
explained
below.
A
number
of
other
proposed
changes
in
emission
reporting
requirements
which
would
have
affected
States
not
subject
to
the
final
CAIR
are
not
included
in
the
final
rule,

for
reasons
explained
below.
We
will
repropose
these
other
changes,
with
modifications,
in
a
separate
proposal
to
allow
additional
opportunity
for
public
comment.

1.
Purpose
and
Authority
Because
we
are
consolidating
and
harmonizing
the
new
emission
reporting
requirements
promulgated
today
with
two
pre­
existing
sets
of
emission
reporting
requirements,
we
review
here
the
purpose
and
authority
for
emission
reporting
requirements
in
general.
522
Emissions
inventories
are
critical
for
the
efforts
of
State,
local,
and
Federal
agencies
to
attain
and
maintain
the
NAAQS
that
EPA
has
established
for
criteria
pollutants
such
as
ozone,
PM,
and
CO.
Pursuant
to
its
authority
under
sections
110
and
172
of
the
CAA,
EPA
has
long
required
SIPs
to
provide
for
the
submission
by
States
to
EPA
of
emissions
inventories
containing
information
regarding
the
emissions
of
criteria
pollutants
and
their
precursors
(
e.
g.,
VOCs).
The
EPA
codified
these
requirements
in
subpart
Q
of
40
CFR
part
51,
in
1979
and
amended
them
in
1987.

The
1990
Amendments
to
the
CAA
revised
many
of
the
provisions
of
the
CAA
related
to
the
attainment
of
the
NAAQS
and
the
protection
of
visibility
in
Class
I
areas.
These
revisions
established
new
periodic
emissions
inventory
requirements
applicable
to
certain
areas
that
were
designated
nonattainment
for
certain
pollutants.
For
example,
section
182(
a)(
3)(
A)
required
States
to
submit
an
emissions
inventory
every
three
years
for
ozone
nonattainment
areas
beginning
in
1993.
Similarly,
section
187(
a)(
5)
required
States
to
submit
an
inventory
every
three
years
for
CO
nonattainment
areas.

The
EPA,
however,
did
not
immediately
codify
these
statutory
requirements
in
the
CFR,
but
simply
relied
on
the
statutory
language
to
implement
them.

In
1998,
EPA
promulgated
the
NOX
SIP
call
which
requires
the
affected
States
and
the
District
of
Columbia
to
submit
523
120
Other
CAA
provisions
relevant
to
this
final
rule
include
section
172(
c)(
3)
(
provides
that
SIPs
for
nonattainment
areas
must
include
comprehensive,
current
inventory
of
actual
emissions,
including
periodic
revisions);
section
182(
a)(
3)(
A)
(
emissions
inventories
from
ozone
nonattainment
areas);
and
section
187(
a)(
5)
(
emissions
inventories
from
CO
SIP
revisions
providing
for
NOX
reductions
to
reduce
their
adverse
impact
on
downwind
ozone
nonattainment
areas.
(
63
FR
57356,
October
27,
1998).
As
part
of
that
rule,
codified
in
40
CFR
51.122,
EPA
established
emissions
reporting
requirements
to
be
included
in
the
SIP
revisions
required
under
that
action.

Another
set
of
emissions
reporting
requirements,
termed
the
Consolidated
Emissions
Reporting
Rule
(
CERR),
was
promulgated
by
EPA
in
2002,
and
is
codified
at
40
CFR
part
51
subpart
A.
(
67
FR
39602,
June
10,
2002).
These
requirements
replaced
the
requirements
previously
contained
in
subpart
Q,

expanding
their
geographic
and
pollutant
coverages
while
simplifying
them
in
other
ways.

The
principal
statutory
authority
for
the
emissions
inventory
reporting
requirements
outlined
in
this
final
rule
is
found
in
CAA
section
110(
a)(
2)(
F),
which
provides
that
SIPs
must
require
"
as
may
be
prescribed
by
the
Administrator...
(
ii)
periodic
reports
on
the
nature
and
amounts
of
emissions
and
emissions­
related
data
from
such
sources."
Section
301(
a)
of
the
CAA
provides
authority
for
EPA
to
promulgate
regulations
under
this
provision.
120
524
nonattainment
areas).
2.
Pre­
existing
Emission
Reporting
Requirements
As
noted
above,
prior
to
this
final
rule,
two
sections
of
title
40
of
the
CFR
contained
emissions
reporting
requirements
that
are
applicable
to
States:
subpart
A
of
part
51
(
the
CERR)
and
section
51.122
in
subpart
G
of
part
51
(
the
NOX
SIP
Call
reporting
requirements).

Under
the
NOX
SIP
Call
requirements
in
section
51.122,

emissions
of
NOX
for
a
defined
5­
month
ozone
season
(
May
1
through
September
30)
and
for
work
weekday
emissions
for
point,
area
and
mobile
sources
that
the
State
has
subjected
to
emissions
control
to
comply
with
the
requirements
of
the
NOX
SIP
Call,
are
required
to
be
reported
by
the
affected
States
to
EPA
every
year.
However,
emissions
of
sources
reporting
directly
to
EPA
as
part
of
the
NOX
trading
program
are
not
required
to
be
reported
by
the
State
to
EPA
every
year.
The
affected
States
are
also
required
to
report
ozone
season
emissions
and
typical
summer
daily
emissions
of
NOX
from
all
sources
every
third
year
(
2002,
2005,
etc.)
and
in
2007.
This
triennial
reporting
process
does
not
have
an
exemption
for
sources
participating
in
the
emissions
trading
programs.
Section
51.122
also
requires
that
a
number
of
data
elements
be
reported
for
each
source
in
addition
to
ozone
525
season
NOX
emissions.
These
data
elements
describe
certain
of
the
source's
physical
and
operational
parameters.

Emissions
reporting
under
the
NOX
SIP
Call
as
first
promulgated
was
required
starting
for
the
emissions
reporting
year
2002,
the
year
prior
to
the
start
of
the
required
emissions
reductions.
The
reports
are
due
to
EPA
on
December
31
of
the
calendar
year
following
the
inventory
year.
For
example,
emissions
from
all
sources
and
types
in
the
2002
ozone
season
were
required
to
be
reported
on
December
31,

2003.
However,
because
the
Court
which
heard
challenges
to
the
NOX
SIP
Call
delayed
the
implementation
by
one
year
to
2004,
no
State
was
required
to
start
reporting
until
the
2003
inventory
year.
EPA
promulgated
a
rule
to
subject
Georgia
and
Missouri
to
the
NOX
SIP
Call
with
an
implementation
date
of
2007.
(
See
69
FR
21604,
April
21,
2004.)
We
have
recently
proposed
to
stay
the
NOX
SIP
Call
for
Georgia
(
see
70
FR
9897,
March
1,
2005).
Missouri's
emissions
reporting
begins
with
2006.
These
emissions
reporting
requirements
under
the
NOX
SIP
Call
affect
the
District
of
Columbia
and
18
of
the
28
States
affected
by
the
proposed
CAIR.

As
noted
above,
the
other
set
of
pre­
existing
emissions
reporting
requirements
is
codified
at
subpart
A
of
part
51.

Although
entitled
the
Consolidated
Emissions
Reporting
Rule
(
CERR),
this
rule
left
in
place
the
separate
§
51.122
for
the
526
NOX
SIP
Call
reporting.
The
CERR
requirements
were
aimed
at
obtaining
emissions
information
to
support
a
broader
set
of
purposes
under
the
CAA
than
were
the
reporting
requirements
under
the
NOX
SIP
Call.
The
CERR
requirements
apply
to
all
States.

Like
the
requirements
under
the
NOX
SIP
Call,
the
CERR
requires
reporting
of
all
sources
at
3­
year
intervals
(
2005,

2008,
etc.).
It
requires
reporting
of
certain
large
sources
every
year.
However,
the
required
reporting
date
under
the
CERR
is
5
months
later
than
under
the
NOX
SIP
Call
reporting
requirements.
Also,
emissions
must
be
reported
for
the
whole
year,
for
a
typical
day
in
winter,
and
a
typical
day
in
summer,
but
not
for
the
5­
month
ozone
season
as
is
required
by
the
NOX
SIP
Call.
Finally,
the
CERR
and
the
NOX
SIP
Call
differ
in
what
non­
emissions
data
elements
must
be
reported.

3.
Summary
of
the
Proposed
Emissions
Reporting
Requirements
On
June
10,
2004,
EPA
published
a
SNPR
(
69
FR
32684)
to
EPA's
January
30,
2004
proposal
(
69
FR
4566).
The
EPA's
main
objective
with
respect
to
emissions
reporting
was
to
add
limited
new
requirements
for
emissions
reports
to
serve
the
additional
purposes
of
verifying
the
CAIR­
required
emissions
reductions.
The
SNPR
also
sought
to
harmonize
the
CERR
and
NOX
SIP
Call
reporting
requirements
with
respect
to
specific
data
elements
and
consolidate
them
entirely
in
subpart
A,
and
527
to
reduce
and
simplify
the
reporting
requirements
in
several
ways.
These
latter
changes
were
proposed
to
be
applicable
to
all
States,
not
just
those
affected
by
the
CAIR
emissions
reduction
requirements.
The
major
changes
included
in
the
SNPR
are
described
below.

Amendments
were
proposed
to
subpart
A,
which
contains
§
51.1
through
51.45
and
an
appendix,
and
to
§
51.122.
We
also
proposed
to
add
a
new
§
51.125.

°
In
§
51.122,
the
NOX
SIP
Call
provisions,
we
proposed
to
abolish
certain
requirements
entirely,
and
to
replace
certain
requirements
with
a
cross
reference
to
subpart
A
so
that
detailed
lists
of
required
data
elements
appeared
only
in
subpart
A.
As
proposed,
§
51.122
would
then
have
specified
what
pollutants,
sources,
and
time
periods
the
States
subject
to
the
NOX
SIP
Call
must
report
and
when,
but
would
no
longer
have
listed
the
detailed
data
elements
required
for
those
reports.

°
The
proposed
new
§
51.125
would
have
been
functionally
parallel
to
§
51.122,
specifying
all
the
pollutants,

sources,
and
time
periods
the
States
subject
to
the
proposed
CAIR
must
report
and
when,
referencing
subpart
A
for
the
detailed
data
elements
required.

°
The
proposed
amended
subpart
A
would
have
listed
the
detailed
data
elements
for
all
three
reporting
programs
(
CERR,
NOX
SIP
Call,
and
CAIR)
as
well
as
provided
528
information
on
submittal
procedures,
definitions,
and
other
generally
applicable
provisions.

Taken
together,
the
pre­
existing
emissions
reporting
requirements
under
the
NOX
SIP
Call
and
CERR
were
already
rather
comprehensive
in
terms
of
the
States
covered
and
the
information
required.
Therefore,
the
practical
impact
of
the
proposed
changes
would
have
imposed
only
three
new
requirements.

First,
in
Arkansas,
Florida,
Iowa,
Louisiana,

Mississippi
and
Wisconsin
for
which
we
proposed
and
are
finalizing
a
finding
of
significant
contribution
to
ozone
nonattainment
in
another
State
but
which
were
not
among
the
22
States
already
subject
to
the
NOX
SIP
Call,
the
required
emissions
reporting
would
be
expanded
to
match
those
of
the
22
States.
The
proposed
change
would
require
that
they
report
NOX
emissions
during
the
5­
month
ozone
season
and
for
a
typical
summer
day,
in
addition
to
the
existing
requirement
for
reporting
emissions
for
the
full
year.
We
proposed
that
this
new
requirement
begin
with
the
triennial
inventory
year
prior
to
the
CAIR
implementation
date.
This
would
be
the
2008
inventory
year,
the
report
for
which
would
be
due
to
EPA
by
June
1,
2010.

Second,
under
the
existing
CERR,
yearly
reporting
is
required
only
for
sources
whose
emissions
exceed
specified
amounts.
The
SNPR
proposed
that
the
28
States
and
the
529
121We
used
the
term
"
non­
point
source"
in
the
SNPR
to
refer
to
a
stationary
source
that
is
treated
for
inventory
purposes
as
part
of
an
aggregated
source
category
rather
than
as
an
individual
facility.
In
the
existing
subpart
A
of
part
51,
such
emissions
sources
are
referred
to
as
"
area
sources."
However,
the
term
"
area
source"
is
used
in
section
112
of
the
CAA
to
indicate
a
non­
major
source
of
hazardous
air
pollutants,
which
could
be
a
point
source.
As
emissions
inventory
activities
increasingly
encompass
both
NAAQS­
related
pollutants
and
hazardous
air
pollutants,
the
differing
uses
of
"
area
source"
can
cause
confusion.
Accordingly,
EPA
proposed
to
substitute
the
term
"
non­
point
source"
for
the
term
"
area
source"
in
subpart
A,
§
51.122,
and
the
new
§
51.125
to
avoid
confusion.
We
are
not
finalizing
this
change
in
terminology
in
today's
rule.
District
of
Columbia
subject
to
the
CAIR
for
reasons
of
PM2.5
must
report
to
EPA
each
year
a
set
of
specified
data
elements
for
all
sources
subject
to
new
controls
adopted
specifically
to
meet
the
CAIR
requirements
related
to
PM2.5,
unless
the
sources
participate
in
an
EPA­
administered
emissions
trading
program.
We
proposed
that
this
new
requirement
begin
with
the
2009
inventory
year,
the
report
for
which
will
be
due
to
EPA
by
June
1,
2011.
This
new
requirement
would
have
no
effect
on
States
that
fully
comply
with
the
CAIR
by
requiring
their
EGUs
to
participate
in
the
CAIR
model
cap­
and­
trade
programs.

Third,
in
all
States,
we
proposed
to
expand
the
definition
of
what
sources
must
report
in
point
source
format,
so
that
fewer
sources
would
be
included
in
non­
point
source
emissions.
121
We
proposed
to
base
the
requirement
for
point
source
format
reporting
on
whether
the
source
is
a
530
major
source
under
40
CFR
part
70
for
the
pollutants
for
which
reporting
is
required,
i.
e.,
for
CO,
VOC,
NOX,
SO2,

PM2.5,
PM10
and
ammonia
but
without
regard
to
emissions
of
hazardous
air
pollutants.

A
number
of
other
proposed
changes
would
have
reduced
reporting
requirements
on
States
or
provided
them
with
additional
options.
Two
of
the
proposed
changes
in
this
category
are
of
special
note
in
understanding
the
final
requirements
of
today's
rule.
(
The
remainder
of
these
changes
were
explained
in
the
SNPR
at
69
FR
32697.)

°
The
NOX
SIP
Call
rule
requires
the
affected
States
to
submit
emissions
inventory
reports
for
a
given
ozone
season
to
EPA
by
December
31
of
the
following
year.
The
CERR
requires
similar
but
not
identical
reports
from
all
States
by
the
following
June
1,
five
months
later.
We
proposed
to
move
the
December
31
reporting
requirement
to
the
following
June
1,
the
more
generally
applicable
submission
date
affecting
all
50
States.
We
asked
for
comment
on
whether
allowing
this
5­
month
delay
is
consistent
with
the
air
quality
goals
served
by
the
emissions
reporting
requirements.
However,
we
also
asked
for
comment
on
the
alternative
of
moving
forward
to
December
31
all
or
part
of
the
June
1
reporting
for
all
50
States.
In
particular,
we
solicited
comment
on
531
requiring
that
point
sources
be
reported
on
December
31
and
other
sources
on
June
1.

°
We
also
proposed
to
eliminate
a
requirement
of
the
NOX
SIP
Call
for
a
special
all­
sources
report
by
affected
States
for
the
year
2007,
due
December
31,
2008.

4.
Summary
of
Comments
Received
and
EPA's
Responses
A
number
of
commenters
objected
to
the
45­
day
comment
period
as
being
too
short
to
allow
for
full
understanding
of
and
comment
on
the
emissions
reporting
changes
that
EPA
had
proposed.
With
respect
to
this
issue,
EPA
believes
that
the
comment
period
was
sufficient
for
those
proposed
changes
that
would
affect
the
States
subject
to
the
emissions
reductions
requirements
of
the
CAIR
and
that
are
specifically
directed
at
ensuring
the
effectiveness
of
the
CAIR,
namely:
(
1)
the
requirement
for
six
more
States
to
report
ozone
season
emissions,
and
(
2)
the
requirement
for
all
subject
States
to
report
annual
emissions
from
controlled
sources
every
year
if
those
sources
are
not
participating
in
the
emission
trading
programs.
These
proposed
changes
are
easy
to
understand
on
their
face,
and
also
have
close
precedents
in
the
NOX
SIP
Call.
Moreover,
the
States
affected
by
these
proposed
reporting
requirements
were
identified
as
being
subject
to
the
proposed
emissions
reduction
requirements
of
the
CAIR
in
the
original
NPR,
and
thus
they
knew
to
be
alert
to
the
contents
of
the
SNPR.
We
also
consider
the
comment
period
532
sufficient
with
respect
to
two
other
specific
elements
of
the
proposal,
namely
(
3)
the
proposal
to
eliminate
the
2007
inventory
reporting
requirement
under
the
NOX
SIP
Call
and
(
4)
the
proposal
to
change
the
reporting
date
for
the
NOX
SIP
Call
from
December
31
(
12
months
after
the
end
of
the
reported
year)
to
June
1
(
17
months
after
the
end
of
the
reported
year).
These
were
also
readily
understood
proposals,
and
the
States
affected
by
them
were
among
those
initially
identified
as
subject
to
the
CAIR
itself.
A
number
of
substantive
comments
were
received
on
these
four
proposed
changes.
Therefore,
we
have
concluded
that
it
is
appropriate
to
consider
the
substantive
comments
that
were
received
on
these
four
elements
of
the
SNPR,
and
to
take
final
action
on
them.
The
disposition
of
the
remaining
elements
of
the
SNPR
is
discussed
further
below.

The
EPA
received
one
comment
from
the
Mississippi
Department
of
Environmental
Quality
on
the
proposed
requirement
that
Mississippi
and
five
other
States
report
ozone
season
emissions.
Mississippi
disagreed
that
they
should
be
included
with
the
other
States
subject
to
the
CAIR
provisions,
including
the
emissions
reporting
provisions.

The
EPA
has
concluded
that
the
analysis
performed
to
support
CAIR
and
discussed
earlier
in
this
preamble
amply
demonstrates
that
Mississippi
should
be
included
in
the
CAIR
and
subject
to
the
CAIR
emissions
reporting
requirements.
533
We
did
not
receive
comments
specifically
on
the
proposal
to
require
States
to
report
annual
emissions
every
year
from
sources
controlled
to
comply
with
the
CAIR,
if
those
sources
are
not
participating
in
the
emission
trading
programs
operated
by
EPA.
While
we
expect
the
number
of
such
sources
to
be
small
if
not
zero,
we
continue
to
believe
that
tracking
their
emissions
from
year
to
year
is
appropriate,
and
we
are
finalizing
this
requirement.
Since
the
CERR
already
contains
a
requirement
for
every­
year
reporting
of
emissions
from
point
sources
above
certain
emission
thresholds,
this
requirement
will
have
an
incremental
impact
only
if
States
choose
to
control
fairly
small
point
sources
or
nonpoint
or
mobile
sources
as
part
of
their
plan
for
meeting
the
CAIR
requirements.

The
EPA
received
several
comments
regarding
the
elimination
of
the
NOX
SIP
Call
special
all­
sources
2007
emissions
inventory.
These
comments
all
favored
the
elimination
of
the
2007
emissions
inventory,
which
EPA
is
promulgating
in
today's
rule.
We
would
like
to
clarify
that
the
NOX
SIP
Call
contained
no
requirement
that
any
State
make
a
retrospective
demonstration
that
actual
statewide
emissions
of
NOX
were
within
any
limit.
The
requirement
for
the
2007
inventory
was
for
the
purpose
of
program
evaluation
by
EPA.

As
explained
in
the
SNPR,
we
believe
that
in
light
of
the
data
on
2007
emissions
that
will
be
available
from
the
NOX
534
trading
program
and
the
further
reductions
in
NOX
required
by
the
CAIR,
the
2007
inventory
submissions
from
the
States
are
not
needed
for
this
purpose.

The
EPA
also
proposed
to
harmonize
the
report
due
dates
for
the
NOX
SIP
Call,
currently
12
months
after
the
end
of
the
reported
year,
and
for
the
CERR,
currently
17
months
after
the
end
of
the
reported
year.
The
EPA
proposed
to
harmonize
the
dates
for
both
at
17
months,
but
asked
for
comments
on
a
12­
month
due
date.
Several
comments
were
received,
all
favoring
harmonizing
the
report
due
date
at
17
months.
While
we
continue
to
believe
in
the
efficiency
advantage
of
harmonized
submission
date
requirements,
we
are
not
finalizing
this
change.
The
EPA
has
reconsidered
this
part
of
the
proposed
emissions
reporting
requirements
and
believes
that
it
may
be
in
the
interest
of
the
public
to
move
in
the
direction
of
shortening
the
emissions
reporting
cycle
for
all
three
reporting
requirements
(
CERR,
NOX
SIP
Call,
and
CAIR),
rather
than
accepting
the
longer
CERR
cycle
for
all
three
reporting
requirements.
In
today's
final
rule,
we
are
retaining
the
12­
month
submission
date
requirement
of
the
original
NOX
SIP
Call
for
the
States
already
subject
to
it.

For
the
six
States
that
are
newly
subject
to
reporting
ozone
season
NOX
emissions
and
for
the
new
requirement
for
everyyear
reporting
by
sources
controlled
to
meet
the
CAIR
requirements
for
SO2
and
NOX
annual
emissions
reductions
but
535
not
included
in
the
trading
programs,
the
required
reporting
date
for
States
will
be
June
1,
17
months
after
the
end
of
the
reported
year,
as
was
proposed.
We
will
address
reporting
deadlines
comprehensively
in
a
separate
NPR
which
will
propose
a
unified,
but
shorter
period
of
time
to
report
to
EPA.
This
separate
notice
will
allow
for
more
public
comment
on
the
reporting
cycle.
The
dual
approach
to
reporting
due
dates
retained
in
today's
rule
will
be
combined
into
unified
due
dates
and
will
be
influenced
by
comments
received
in
response
to
our
proposal
when
the
separate
rulemaking
is
completed.

Regarding
elements
of
the
proposed
requirements
beyond
these
four,
i.
e.,
the
requirements
that
would
have
affected
States
not
subjected
to
the
CAIR
emissions
reduction
requirements
as
well
as
CAIR
States,
many
commenters
said
that
EPA
should
not
have
included
changes
to
national
emissions
reporting
requirements
in
a
proposed
rule
placing
emissions
reduction
requirements
on
only
certain
States.

Commenters
also
questioned
whether
EPA
had
given
adequate
time
for
comment
on
the
more
detailed
revisions
in
required
data
elements,
definitions,
etc.
Substantively,
many
commenters
supported
some
or
all
of
the
proposed
changes,
but
some
commenters
objected
to
some
of
them.

The
EPA
has
considered
these
comments.
Without
conceding
EPA's
legal
authority
to
include
these
provisions
536
in
the
final
rule
in
light
of
the
history
of
proposal,
public
hearing,
and
comment
period,
EPA
has
­
in
an
abundance
of
caution
­
decided
to
omit
these
provisions
from
today's
rule
(
see
section
VIII.
D.
5
Summary
of
the
Emissions
Reporting
Requirements
below
for
the
changes
which
are
being
finalized
today).
We
will
repropose
them,
with
modifications,
in
a
separate
NPR
to
allow
additional
opportunity
for
public
comment
by
all
affected
States
and
other
parties.

5.
Summary
of
the
Emissions
Reporting
Requirements
As
a
result
of
the
comments
received,
EPA
has
revised
the
emissions
reporting
requirements
of
today's
rule
by
limiting
new
requirements
to
the
ones
where
sufficient
notice
and
opportunity
for
comment
was
clearly
given
in
the
June
10,

2004,
SNPR
and
that
either:
(
1)
are
necessary
for
the
monitoring
of
the
implementation
of
the
emissions
reduction
requirements
of
the
CAIR,
or
(
2)
are
changes
in
reporting
under
the
NOX
SIP
Call
linked
to
the
CAIR.
Three
specific
emissions
reporting
provisions
that
change
the
pre­
existing
requirements
are
included
in
today's
rule.

1.
Alabama,
Arkansas,
Connecticut,
Delaware,
Florida,

Illinois,
Indiana,
Iowa,
Kentucky,
Louisiana,

Maryland,
Massachusetts,
Michigan,
Mississippi,

Missouri,
New
Jersey,
New
York,
North
Carolina,

Ohio,
Pennsylvania,
South
Carolina,
Tennessee,

Virginia,
West
Virginia,
Wisconsin
and
the
District
537
of
Columbia,
which
are
subject
to
the
CAIR
for
reasons
of
ozone,
are
made
subject
to
emission
reporting
requirements
for
NOX
that
are
very
similar
to
the
existing
requirements
of
the
NOX
SIP
Call,
which
already
affects
all
but
six
of
these
States.
For
these
six
States
(
Arkansas,
Florida,

Iowa,
Louisiana,
Mississippi
and
Wisconsin)
a
new
requirement
is
that
they
report
NOX
emissions
during
the
5­
month
ozone
season
from
all
sources
every
three
years,
in
addition
to
reporting
emissions
for
the
full
year
and
for
a
summer
day
as
was
already
required.
This
new
requirement
begins
with
the
triennial
inventory
year
2008.
For
all
the
listed
States,
a
new
requirement
is
to
report
to
EPA
for
2009
and
each
year
thereafter
the
ozoneseason
and
summer
day
NOX
emissions,
plus
a
set
of
specified
other
data
elements,
for
all
sources
subject
to
new
controls
adopted
specifically
to
meet
the
CAIR
requirements
related
to
ozone,
unless
the
sources
participate
in
an
EPA­
administered
emissions
trading
program.
These
reports
will
be
due
June
1
of
the
second
year
following
the
end
of
the
reported
year,
i.
e.,
17
months
after
the
end
of
the
reported
year.
The
existing
CERR
includes
several
other
reporting
requirements
which
in
538
conjunction
with
this
new
requirement
will
meet
the
needs
for
monitoring
the
implementation
of
required
NOX
emissions
reductions.

2.
Alabama,
Florida,
Georgia,
Illinois,
Indiana,
Iowa,

Kentucky,
Louisiana,
Maryland,
Michigan,
Minnesota,

Mississippi,
Missouri,
New
York,
North
Carolina,

Ohio,
Pennsylvania,
South
Carolina,
Tennessee,

Texas,
Virginia,
West
Virginia,
Wisconsin
and
the
District
of
Columbia,
which
are
subject
to
the
CAIR
for
reasons
of
PM2.5,
must
report
to
EPA
each
year
annual
NOX
and
SO2
emissions,
plus
a
set
of
specified
other
data
elements,
for
all
sources
subject
to
new
controls
adopted
specifically
to
meet
the
CAIR
requirements
related
to
PM2.5,
unless
the
sources
participate
in
an
EPA­
administered
emissions
trading
program.
Previously,
these
states
may
have
been
required
to
report
these
sources
only
every
third
year,
depending
on
their
size.
The
existing
CERR
includes
several
other
reporting
requirements
which
in
conjunction
with
this
new
requirement
will
meet
the
needs
for
monitoring
the
implementation
of
required
NOX
and
SO2
emissions
reductions.

3.
The
EPA
has
determined
that
the
requirement
in
the
NOX
SIP
Call
for
a
special
all­
sources
report
by
539
12240
CFR
51.122
is
also
amended:
(
1)
to
remove
a
reference
to
now­
obsolete
electronic
data
reporting
processes
(
a
"
housekeeping"
deletion
that
was
specifically
included
in
the
proposed
rule
text
with
the
SNPR),
and
(
2)
to
make
a
minor
technical
correction
to
properly
indicate
which
of
the
latitude
versus
longitude
data
elements
corresponds
to
the
x­
coordinate
and
which
to
the
y­
coordinate
(
a
correction
that
was
implicitly
proposed
in
the
SNPR
in
that
51.122
was
proposed
to
refer
to
51
subpart
A
for
all
its
data
element
descriptions).
affected
States
for
the
year
2007,
due
December
31,

2008,
is
no
longer
needed
to
administer
provisions
in
the
NOX
SIP
Call.
Accordingly,
EPA
is
eliminating
this
requirement
in
today's
rule.

The
final
rule
accomplishes
these
changes
by
making
minimal
changes
to
the
existing
provisions
of
40
CFR
part
51.

Subpart
A,
which
contains
the
CERR
requirements,
is
not
amended
at
all.
40
CFR
51.122,
the
section
containing
emission
inventory
reporting
requirements
for
the
NOX
SIP
Call,
is
substantively
amended
only
to
delete
the
requirement
for
the
2007
inventory
report.
122
A
new
section
40
CFR
51.125
is
added
to
contain
the
two
new
emission
inventory
reporting
requirements
specifically
related
to
the
new
CAIR
requirements
for
emissions
reductions,
regarding
ozone­
season
emissions
of
NOX
and
every­
year
reporting
of
NOX
and
SO2
emissions
from
all
sources
controlled
but
not
participating
in
the
EPA
trading
programs.
The
new
40
CFR
51.125
refers
to
40
CFR
subpart
A
for
the
other
specific
data
elements
that
must
be
reported.
540
VIII.
Model
NOx
and
SO2
Cap
and
Trade
Programs
A.
What
Is
the
Overall
Structure
of
the
Model
NOx
and
SO2
Cap
and
Trade
Programs?

The
EPA
is
finalizing
model
rules
for
the
CAIR
annual
NOx,
CAIR
ozone­
season
NOx,
and
SO2
trading
programs
that
States
can
use
to
meet
the
emission
reduction
requirements
in
the
CAIR.
These
rules
are
designed
to
be
referenced
by
States
in
State
rulemaking.
State
use
of
the
model
cap
and
trade
rules
helps
to
ensure
consistency
between
the
State
programs,
which
is
necessary
for
the
market
aspects
of
the
regional
trading
program
to
function
properly.
It
also
allows
the
CAIR
Program
to
build
on
the
successful
Acid
Rain
Program.
Consistency
in
the
CAIR
requirements
from
State­
to­

State
benefits
the
affected
sources,
as
well
as
EPA,
which
administers
the
program
on
behalf
of
States.

This
section
focuses
on
the
structure
which
maintains
the
existing
NOx
SIP
Call
rules
(
in
part
96,
subparts
A
through
J)
while
adding
parallel
rules
for
the
CAIR
annual
NOx
(
in
subparts
AA
through
II),
CAIR
SO2
(
in
subparts
AAA
through
III),
and
the
CAIR
ozone­
season
NOx
(
in
subparts
AAAA
through
IIII)
of
the
model
rules.
Commenters
generally
supported
the
proposed
structure
of
the
model
rules,
as
well
as
the
use
of
the
cap
and
trade
approach,
which
are
maintained
in
the
final
rules.
Later
sections
of
today's
541
rule
discuss
specific
aspects
of
the
model
rules
that
have
been
modified
or
maintained
in
response
to
comment.

The
EPA
designed
the
model
rules
to
parallel
the
NOx
SIP
Call
model
trading
rules
(
part
96)
and
to
coordinate
with
the
Acid
Rain
Program.
Mirroring
the
structure
of
existing
part
96
in
the
final
CAIR
NOx
and
SO2
model
rules
will
ease
the
transition
to
the
CAIR
rules
as
many
States
and
sources
are
already
familiar
with
the
layout
of
the
NOx
SIP
Call
rule.

In
addition,
because
the
EPA
proposed
new
CAIR
model
trading
rules
 
separate
from
the
existing
NOx
SIP
Call
model
rule
in
part
96
 
States
can
continue
to
reference
part
96
(
subparts
A
through
J)
through
2008.
The
CAIR
ozone­
season
NOx
cap
and
trade
program
that
the
EPA
has
included
in
today's
final
rule
is
intended
for
use
by
CAIR
ozone­
affected
sources
as
well
as
those
subject
to
the
NOx
SIP
Call
in
2009
and
beyond.
Those
States
that
wish
to
use
an
EPA­
administered,
ozone­
season
cap
and
trade
program
to
achieve
the
reductions
mandated
by
the
CAIR
or
the
NOx
SIP
Call,
must
use
the
CAIR
ozone­
season
NOx
model
rule
(
subparts
AAAA
through
IIII)
in
2009
and
beyond.

The
model
rules
rely
on
the
detailed
unit­
level
emissions
monitoring
and
reporting
procedures
of
part
75
and
consistent
allowance
management
practices.
(
Note
that
full
CAIR­
related
SIP
requirements,
i.
e.,
part
51,
are
discussed
in
section
VII
of
today's
preamble.)
Additionally,
section
IX.
B
of
today's
preamble
discusses
the
final
revisions
to
542
parts
72
through
77
in
order
to,
among
other
things,

facilitate
the
interaction
of
the
title
IV
Acid
Rain
Program's
SO2
cap
and
trade
provisions
and
those
of
the
CAIR
SO2
trading
program.

Road
Map
of
Model
Cap
and
Trade
Rules
The
following
is
a
brief
"
road
map"
to
the
final
CAIR
NOx
and
SO2
cap
and
trade
programs.
Please
refer
to
the
detailed
discussions
of
the
CAIR
programmatic
elements
throughout
today's
rule
for
further
information
on
each
aspect.

State
Participation
­

D.
States
have
flexibility
to
achieve
emissions
reductions
however
they
chose,
including
developing
and
implementing
their
own
trading
program.

E.
States
may
elect
to
participate
in
an
EPA­
managed
cap
and
trade
program.
To
participate,
a
State
must
adopt
the
model
cap
and
trade
rules
finalized
in
this
section
of
today's
rule
with
flexibility
to
modify
sections
regarding
NOx
allocations
and
whether
to
include
individual
unit
opt­
in
provisions.

F.
States
may
participate
in
EPA­
managed
cap
and
trade
programs
for
either
the
annual
NOx,
the
ozone­
season
NOx,
the
SO2,
or
any
combination.
The
State
can
only
choose
to
participate
in
the
EPA­
administered,
CAIR
cap
543
123
Rhode
Island
(
RI)
is
the
only
State
currently
participating
in
the
NOx
SIP
Call
cap
and
trade
program
that
is
not
affected
by
today's
ozone
finding.
As
is
explained
in
section
IX,
RI
may
join
the
CAIR
ozone­
season
trading
program
as
a
means
of
satisfying
its
NOx
SIP
Call
requirements.
and
trade
program(
s)
that
is(
are)
relevant
to
thier
finding(
s).

G.
The
annual
NOx
model
rule
is
to
be
used
by
only
those
States
that
are
affected
by
the
CAIR
PM2.5
finding.

H.
The
ozone­
season
NOx
model
rule
is
designed
to
be
used
by
those
States
that
are
affected
by
the
CAIR
ozone
finding
as
well
as
take
the
place
of
the
NOx
SIP
Call
requirements123.
The
CAIR
ozone­
season
NOx
program
will
be
the
only
ozone­
season
NOx
program
that
EPA
will
administer.
Because
the
EPA
will
no
longer
run
a
NOx
SIP
Call
trading
program,
States
may
include
their
NOx
SIP
Call
sources
if
they
adopt
the
EPA­
administered
CAIR
ozone­
season
NOx
program.

I.
The
SO2
model
rule
is
designed
to
satisfy
the
ongoing
statutory
requirements
of
the
title
IV
Acid
Rain
SO2
cap
and
trade
program
 
with
simultaneous
compliance
with
title
IV
and
the
CAIR
 
for
sources
in
the
CAIR
region
that
are
affected
by
both
the
Acid
Rain
Program
and
the
CAIR.

Trading
Sources
­
544
J.
States
must
achieve
all
of
the
mandated
emission
reductions
from
EGUs
to
participate
in
EPA­
managed
cap
and
trade
programs.
States
may
include
other
NOx
SIP
Call
trading
sources
in
the
ozone­
season
CAIR
NOx
cap
and
trade
program
and
still
participate
in
EPA­
managed
cap
and
trade
programs.

K.
States
may
participate
in
EPA­
managed
cap
and
trade
programs
whether
or
not
they
adopt
the
optional
individual
opt­
in
provisions
of
the
model
rule.

However,
if
the
State
chooses
to
allow
individual
sources
to
opt­
in,
the
opt­
in
requirements
must
reflect
the
requirements
of
the
model
rule.

Emission
Allowances
­

A.
The
CAIR
annual
NOx
cap
and
trade
program
will
rely
upon
CAIR
annual
NOx
allowances
allocated
by
the
States.
The
NOx
SIP
Call
allowances
and
CAIR
ozone­
season
NOx
allowances
cannot
be
used
for
compliance
with
the
annual
CAIR
reduction
requirement.
(
Note
that
allowances
from
the
Compliance
Supplement
Pool
(
CSP)
will
be
CAIR
annual
NOx
allowances.)

B.
The
CAIR
ozone­
season
NOx
cap
and
trade
program
will
rely
upon
CAIR
ozone­
season
NOx
allowances
allocated
by
the
States.
In
addition,
pre­
2009
NOx
SIP
Call
allowances
can
be
banked
into
the
program
and
used
by
CAIR­
affected
sources
for
compliance
with
the
CAIR
545
ozone­
season
NOx
program.
The
NOx
SIP
Call
allowances
of
vintages
2009
and
later
can
not
be
used
for
compliance
with
any
EPA­
administered
cap
and
trade
programs.

C.
The
CAIR
SO2
cap
and
trade
program
will
rely
upon
title
IV
SO2
allowances
but
may
also
include
additional
CAIR
SO2
allowances,
should
a
State
not
require
all
of
their
SO2
emissions
reductions
from
EGUs
in
their
budget
demonstration.
Pre­
2010
title
IV
SO2
allowances
can
be
used
for
compliance
with
the
CAIR.

D.
Sulfur
dioxide
reductions
are
achieved
by
requiring
sources
to
retire
more
than
one
allowance
for
each
ton
of
SO2
emissions.
The
emission
value
of
an
SO2
allowance
is
independent
of
the
year
in
which
it
is
used,
but
is
based
upon
it's
vintage
(
i.
e.,
the
year
in
which
the
allowance
is
issued).
Sulfur
dioxide
allowances
of
vintage
2009
and
earlier
offset
one
ton
of
SO2
emissions.
Vintages
2010
through
2014
offset
0.5
tons
of
emissions.
And,
vintages
2015
and
beyond
offset
0.35
tons
of
emissions.

Allocation
of
Allowances
to
Sources
­

E.
For
SO2
allowances,
sources
have
already
received
allowances
through
title
IV.

F.
NOx
allowances
(
for
both
the
annual
and
ozone­
season
programs)
will
be
allocated
based
upon
the
State's
546
2
The
200,000
total
includes
the
share
of
the
CSP
that
DE
and
NJ
would
receive
if
the
EPA
finalizes
a
parallel
rule
finding
that
they
are
significant
contributors
for
PM2.5.
chosen
allocation
methodology.
The
EPA's
model
NOx
rules
have
provided
an
example
allocation,
complete
with
regulatory
text,
that
may
be
used
by
State's
or
replaced
by
text
that
implements
a
States
alternative
allocation
methodology.

Compliance
Supplement
Pool
(
CSP)
­

G.
Each
State
will
have
a
share
of
the
CSP
that
is
comprised
of
200,000124
CAIR
annual
NOx
allowances
of
vintage
year
2009.
The
State
may
distribute
the
CSP
allowances
based
upon
the
criteria,
found
in
the
SIP
Approvability
section
of
today's
rule,
for
early
reductions
and
need.

Emission
Monitoring
and
Reporting
by
Sources
­

A.
Sources
monitor
and
report
their
emissions
using
part
75.
This
includes
individual
sources
that
opt­
in
to
the
program.

B.
Source
information
management,
emissions
data
reporting,

and
allowance
trading
is
done
through
on­
line
systems
similar
to
those
currently
used
for
the
Acid
Rain
SO2
and
NOx
SIP
Call
Programs.
547
125Compliance
with
the
title
IV
Acid
Rain
Program
will
be
determined
separately
from
CAIR
compliance.
C.
Emission
monitoring
and
reporting
for
both
the
CAIR
annual
and
ozone­
season
NOx
cap
and
trade
programs
will
use
part
75.

Compliance
and
Penalties
­

A.
Compliance
for
the
annual
and
ozone­
season
NOx
cap
and
trade
programs,
as
well
as
the
SO2
program,
will
be
determined
separately.
125
B.
For
the
NOx
and
SO2
cap
and
trade
programs,
any
source
found
to
have
excess
emissions
must:
(
1)
surrender
allowances
sufficient
to
offset
the
excess
emissions;

and,
(
2)
surrender
allowances
from
the
next
control
period
equal
to
three
times
the
excess
emissions.

Comments
Regarding
the
Use
of
a
Cap
and
Trade
Approach
and
the
Proposed
Structure
Commenters
overwhelmingly
supported
the
use
of
a
cap
and
trade
approach
and
the
overall
framework
of
the
model
rules
to
achieve
the
mandated
emissions
reductions.
Some
supported
the
use
of
cap
and
trade
for
achieving
regional
emissions
reductions
but
noted
the
need
to
have
additional
measures
that
ensure
that
emission
reductions
take
place
in
nonattainment
areas.
This
is
in
line
with
the
EPA's
strategy
of
reducing
transported
SO2
and
NOx
through
a
regionwide
cap
548
and
trade
approach
and
encouraging
States
to
take
complementary
measures
to
address
their
particular,

persistent
nonattainment
issues.
(
Note
that
comments
on
specific
mechanisms
within
the
cap
and
trade
program
are
discussed
in
the
topic­
specific
sections
that
follow.)

B.
What
Is
the
Process
for
States
to
Adopt
the
Model
Cap
and
Trade
Programs
and
How
Will
It
Interact
with
Existing
Programs?

1.
Adopting
the
Model
Cap
and
Trade
Programs
States
may
choose
to
participate
in
the
EPA­
administered
cap
and
trade
programs,
which
are
a
fully
approvable
control
strategy
for
achieving
all
of
the
emissions
reductions
required
under
today's
rulemaking
in
a
highly
cost­
effective
manner.
States
may
simply
reference
the
model
rules
in
their
State
rules
and,
thereby,
comply
with
the
requirements
for
statewide
budget
demonstrations
detailed
in
section
VII.
B
of
today's
preamble.
Affected
States
for
both
PM2.5
and
ozone
can
adopt
the
annual
NOx
and
SO2
cap
and
trade
programs
in
part
96,
subparts
AA
through
II,
part
96
subparts
AAA
through
III,
and
AAAA
through
IIII.
States
with
ozone­
season
only
CAIR
requirements
(
i.
e.,
Arkansas,
Connecticut,
Delaware,

Massachusetts,
and
New
Jersey)
can
adopt
the
ozone­
season
CAIR
NOx
program
(
subparts
AAAA
through
IIII).
Part
96
subparts
AA
through
II
and
AAA
through
III
can
be
used
by
549
States
that
are
affected
for
only
PM2.5
(
i.
e.,
Georgia,

Minnesota,
and
Texas).
States
that
elect
to
achieve
the
required
reductions
by
regulating
other
sources
or
using
other
approaches
will
follow
alternate
State
requirements,

also
described
in
section
VII.
B
of
today's
preamble.

As
proposed,
the
EPA
is
requiring
States
that
wish
to
participate
in
the
EPA­
managed
cap
and
trade
program
to
use
the
model
rule
to
ensure
that
all
participating
sources,

regardless
of
which
State
in
the
CAIR
region
they
are
located,
are
subject
to
the
same
trading
and
allowance
holding
requirements.
Further,
requiring
States
to
use
the
complete
model
rule
provides
for
accurate,
certain,
and
consistent
quantification
of
emissions.
Because
emissions
quantification
is
the
basis
for
applying
the
emissions
authorization
provided
by
each
allowance
and
emissions
authorizations
(
in
the
form
of
allowances)
are
the
valuable
commodity
traded
in
the
market,
the
emissions
quantification
requirements
of
the
model
rule
are
necessary
to
maintain
the
integrity
of
the
cap
and
trade
approach
of
the
program
and
therefore,
to
ensure
that
the
environmental
goals
of
the
program
are
met.

For
States
Electing
to
Participate
in
the
EPA­
Administered
Ozone­
Season
CAIR
NOx
Cap
and
Trade
Program
States
that
wish
to
achieve
their
CAIR
ozone­
season
requirements
through
an
EPA­
administered
ozone­
season
NOx
cap
550
and
trade
program
will
adopt
the
CAIR
model
rule
in
subparts
AAAA
through
IIII.
(
Note
that
the
EPA­
administered
annual
NOx
CAIR
cap
and
trade
program
is
independent
of
ozone­
season
CAIR
NOx
model
rule.)
Because
the
EPA
will
no
longer
administer
the
trading
program
for
the
NOx
SIP
Call,
States
that
wish
to
continue
to
meet
their
NOx
SIP
Call
obligations
through
an
EPA­
administered
cap
and
trade
program
will
also
adopt
the
CAIR
ozone­
season
model
rule.
NOx
SIP
Call
States
will
"
sun
set"
their
NOx
SIP
Call
rules
for
sources
that
will
move
into
the
CAIR
NOx
ozone­
season
program.
Part
96,

sections
A
­
J
(
i.
e.,
the
NOx
SIP
Call
trading
rule)
will
continue
to
be
available
for
the
NOx
SIP
Call
and
will
not
be
removed
for
the
CAIR.
The
CAIR
model
rules
specifically
address
how
NOx
SIP
Call
allowances
carry
forward
into
the
CAIR
NOx
ozone­
season
program.
(
Section
IX.
A
provides
additional
discussion
of
interactions
between
the
CAIR
and
the
NOx
SIP
Call).

For
States
Electing
to
Participate
in
the
EPA­
Administered
Annual
NOx
Cap
and
Trade
Program
States
that
are
PM2.5
affected
and
wish
to
participate
in
an
EPA­
administered
annual
NOx
cap
and
trade
program
will
adopt
the
CAIR
model
rule
in
subparts
AA
through
II.
States
may
participate
by
either
adopting
the
model
rule
provisions
by
reference
or
codifying
the
model
rule
in
their
State
regulations.
551
For
States
Electing
to
Participate
in
the
EPA­
Administered
SO2
Cap
and
Trade
Program
States
may
simply
adopt
new
provisions,
whether
by
incorporating
by
reference
the
CAIR
SO2
cap
and
Trade
rule
(
part
96,
subparts
AAA
through
III)
or
codifying
the
provisions
of
the
CAIR
SO2
cap
and
trade
rules,
in
order
to
participate
in
the
EPA­
administered
SO2
cap
and
trade
program.
The
CAIR
SO2
model
rule
works
in
conjunction
with
the
Acid
Rain
Program
provisions,
which
are
implemented
at
the
Federal
level
and
will
stay
in
place.
Today's
action
also
finalizes
some
revisions
to
the
Acid
Rain
Program
(
i.
e.,

parts
72,
73,
74,
75,
and
78).
(
Section
IX.
B
of
today's
preamble
provides
additional
discussion
of
interactions
between
the
CAIR
and
the
Acid
Rain
Program
and
changes
to
the
Acid
Rain
Program).

Comments
Regarding
the
Process
for
Adopting
the
Model
Rules
Commenters
supported
the
EPA's
proposed
process
and
emphasized
the
importance
of
workable
model
rules,
because
States
with
limited
resources
are
likely
to
incorporate
them
by
reference
or
heavily
rely
on
them
as
the
basis
for
State
rules.

2.
Flexibility
in
Adopting
Model
Cap
and
Trade
Rules
It
is
important
to
have
consistency
on
a
State­
to­
State
basis
with
the
basic
requirements
of
the
cap
and
trade
approach
when
implementing
a
multi­
State
cap
and
trade
552
program.
Such
consistency
ensures
the:
preservation
of
the
integrity
of
the
cap
and
trade
approach
so
that
the
required
emissions
reductions
are
achieved;
smooth
and
efficient
operation
of
the
trading
market
and
infrastructure
across
the
multi­
State
CAIR
region
so
that
compliance
and
administrative
costs
are
minimized;
and
equitable
treatment
of
owners
and
operators
of
regulated
sources.
However,
the
EPA
believes
that
some
limited
differences
are
possible
without
jeopardizing
the
environmental
and
other
goals
of
the
program.
Therefore,
the
final
rule
allows
States
to
modify
the
model
rule
language
to
best
suit
their
unique
circumstances
in
a
few,
specific
areas.

First,
States
have
the
flexibility
to
include,
as
full
trading
partners,
all
trading
sources
affected
by
the
NOx
SIP
Call
in
the
ozone­
season
CAIR
NOx
cap
and
trade
program.

This
is
an
outgrowth
of
the
development
of
the
CAIR
ozoneseason
NOx
program,
which
will
be
the
only
ozone­
season
NOx
cap
and
trade
program
administered
by
the
EPA.

In
addition,
States
may
develop
their
own
NOx
allocations
methodologies,
provided
allocation
information
is
submitted
to
the
EPA
in
the
required
timeframe.
(
Section
VIII.
D
of
today's
preamble
discusses
unit­
level
allocations
and
the
related
comments
in
greater
detail.
This
includes
a
discussion
of
the
provisions
establishing
the
advance
notice
States
must
provide
for
unit­
by­
unit
allocations).
553
Lastly,
States
using
the
model
cap
and
trade
rules
may
elect
to
include
provisions
that
allow
individual
units
to
"
opt­
in"
to
the
cap
and
trade
programs.
States
that
wish
to
include
this
mechanism
must
adopt
provisions
discussed
in
section
VIII.
G
of
today's
rulemaking.
Adopting
the
individual
unit
opt­
in
provisions,
which
would
allow
non­
EGUs
that
meet
the
opt­
in
requirements
to
enter
into
the
EPAmanaged
cap
and
trade
programs,
does
not
preclude
a
State
from
participating
in
the
EPA­
administered
cap
and
trade
programs.

C.
What
Sources
Are
Affected
under
the
Model
Cap
and
Trade
Rules?

In
the
January
2004
NPR,
the
EPA
proposed
a
method
for
developing
budgets
that
assumed
reductions
only
from
EGUs.

Electric
Generating
Units
were
defined
as:
fossil
fuel­
fired,

non­
cogeneration
EGUs
serving
a
generator
with
a
nameplate
capacity
of
greater
than
25
MWe;
and
fossil
fuel­
fired
cogeneration
EGUs
meeting
certain
criteria
(
referred
to
as
the
"
1/
3
potential
electric
output
capacity
criteria").
In
the
SNPR,
we
proposed
model
cap
and
trade
rules
that
applied
to
the
same
categories
of
sources.
We
are
finalizing
the
nameplate
capacity
cut­
off
that
we
proposed
in
the
NPR
for
developing
budgets
and
that
we
proposed
in
the
SNPR
for
the
applicability
of
the
model
trading
rules.
We
are
also
finalizing
the
"
fossil
fuel­
fired"
definition
and
the
1/
3
554
electric
output
capacity
criteria
that
were
proposed.
The
actual
rule
language
in
the
SNPR
describing
the
sources
to
which
the
model
rules
apply
is
being
slightly
revised
to
be
clearer
in
response
to
some
comments
that
the
proposed
language
was
not
clear.

1.
25
MW
Cut­
Off
The
EPA
is
retaining
the
25
MW
cut­
off
for
EGUs
for
budget
and
model
rule
purposes.
The
EPA
believes
it
is
reasonable
to
assume
no
further
control
of
air
emissions
from
smaller
EGUs.
Available
air
emissions
data
indicate
that
the
collective
emissions
from
small
EGUs
are
relatively
small
and
that
further
regulating
their
emissions
would
be
burdensome,

to
both
the
regulated
community
and
regulators,
given
the
relatively
large
number
of
such
units.
For
example,
NOx
and
SO2
emissions
from
EGUs
of
25
MW
or
less
in
the
CAIR
region
represent
approximately
one
percent
and
two
percent
of
total
NOx
and
SO2
emissions
from
EGUs,
respectively.
There
are
over
4000
EGUs
of
25
MW
or
less
in
the
CAIR
region.

Consequently,
EPA
believes
that
administrative
actions
to
control
this
large
group
with
small
emissions
would
be
inordinate
and
thus
does
not
believe
these
small
units
should
be
included.
This
approach
of
using
a
25
MW
cut­
off
for
EGUs
is
consistent
with
existing
SO2
and
NOx
cap
and
trade
programs
such
as
the
NOx
SIP
Call
(
where
existing
and
new
EGUs
at
or
under
this
cut­
off
are,
for
similar
reasons,
not
required
to
555
be
included)
and
the
Acid
Rain
Program
(
where
this
cut­
off
is
applied
to
existing
units
and
to
new
units
combusting
clean
fuel).
Also,
EPA's
New
Source
Performance
Standards
use
an
applicability
threshold
of
approximately
25
MW
under
subpart
Da.

One
commenter
suggested
a
plant­
wide
cut­
off
of
250
MW.

This
commenter
suggested
that
including
units
between
25
and
250
MW
would
cause
these
units
to
shutdown
but
failed
to
provide
any
analysis
to
support
its
claim.
Such
a
cut­
off
would
be
inconsistent
with
other
existing
SO2
and
NOx
cap
and
trade
programs
as
noted
above.
The
EPA
estimates
that
approximately
1/
3
of
the
SO2
reductions,
and
30
percent
of
the
NOx
reductions,
required
under
today's
rule
come
from
plants
between
25
MW
and
250
MW.
Our
modeling
shows
that
some
units
below
250
MW
will
put
on
controls
as
part
of
our
highly
cost­
effective
set
of
control
actions.
The
units
also
have
the
option
to
coal­
switch,
alter
dispatch,
and/
or
purchase
allowances.

Another
commenter
suggested
that,
in
lieu
of
the
language
proposed
in
the
SNPR,
the
EPA
adopt
a
definition
for
EGU
that,
according
to
the
commenter,
is
the
Acid
Rain
Program's
definition
of
affected
utility.
The
commenter
stated
that
the
Acid
Rain
definition
of
EGU
is
"
all
fossil
fuel­
fired
units
with
a
nameplate
capacity
greater
than
25
MW
supplying
more
than
1/
3
of
potential
electrical
output
to
the
556
126
For
example,
certain
cogeneration
units
and
new
units
25
MW
or
less
that
burn
only
clean
fuel
are
exempt
from
the
Acid
Rain
Program.
grid."
However,
the
commenter
misstated
the
Acid
Rain
definition
and
confused
the
Acid
Rain
applicability
provisions
concerning
utility
units
in
general
with
those
provisions
concerning
cogeneration
units
in
particular.
The
Acid
Rain
Program
covers,
with
certain
exceptions,
126
all
existing
fossil
fuel­
fired
units
greater
than
25
MW
that
produce
any
electricity
for
sale;
and
new
fossil
fuel­
fired
units
that
produce
any
electricity
for
sale.
The
language
referenced
by
the
commenter
concerning
potential
electrical
output
applies,
in
the
Acid
Rain
Program,
only
to
cogeneration
units,
not
all
fossil
fuel­
fired
units.
For
non­
cogeneration
units,
there
is
no
exemption
from
Acid
Rain
Program
requirements
based
on
the
unit
selling
a
"
small"

amount
of
electricity
for
sale.
The
provisions
in
the
NPR
and
the
SNPR
concerning
cogeneration
units
are
discussed
below.

2.
Definition
of
Fossil
Fuel­
Fired
The
EPA
is
finalizing
the
proposed
definition
of
fossil
fuel­
fired,
i.
e.,
where
any
amount
of
fossil
fuel
is
used
at
any
time.
This
is
the
same
definition
that
is
used
in
the
Acid
Rain
Program.
One
commenter
suggested
that
the
proposed
definition
is
too
broad
and
that
the
EPA
should
use
in
the
557
CAIR
Program
the
same
definition
that
is
used
in
the
NOx
SIP
Call,
i.
e.,
where
a
unit
uses
fossil
fuel
for
at
least
50
percent
of
its
annual
heat
input
during
a
specified
period.

The
same
commenter
also
proposed
excluding
large
wood­
fired
boilers
and
black
liquor
recovery
furnaces.
The
commenter's
definition
would
result
in
units
already
subject
to
the
Acid
Rain
Program
in
a
given
State
being
excluded
from
the
CAIR
Program
and
the
model
cap
and
trade
rules
applicable
in
that
State.
Such
exclusion
would
make
it
more
difficult
to
coordinate
the
Acid
Rain
Program
and
the
CAIR
Program.

Consequently,
the
EPA
rejects
the
commenter's
more
restricted
definition
of
fossil
fuel­
fired.

The
EPA
recognizes
that
new
(
i.
e.,
post
1990)
units
that
are
25
MW
or
less
and
burn
other
than
clean
fuels
are
subject
to
the
Acid
Rain
Program
but
not
to
the
CAIR
Program.

However,
there
are
very
few
such
units,
and
EPA
has
decided
to
exclude
any
units
that
are
25
MW
or
less
on
other
grounds
discussed
above.

3.
Exemption
for
Cogeneration
Units
As
proposed,
EPA
is
finalizing
an
exemption
from
the
model
cap
and
trade
programs
for
cogeneration
units,
i.
e.,

units
having
equipment
used
to
produce
electricity
and
useful
thermal
energy
for
industrial,
commercial,
heating,
or
cooling
purposes
through
sequential
use
of
energy
and
meeting
certain
operating
and
efficiency
standards
(
discussed
below).
558
The
EPA
is
adopting
the
proposed
definition
of
cogeneration
unit
and
the
proposed
criteria
for
determining
which
cogeneration
units
qualify
for
the
exemption
from
the
model
cap
and
trade
programs.

The
CAIR
trading
program
has
different
applicability
provisions
for
non­
cogeneration
units
and
cogeneration
units.

If
a
unit
initially
qualifies
as
a
cogeneration
unit,
and
for
the
exemption
from
the
trading
program
for
certain
cogeneration
units,
but
subsequently
loses
its
cogenerationunit
status
(
e.
g.,
due
to
changes
in
operation),
such
unit
loses
the
cogeneration­
unit
exemption
and
becomes
subject
to
the
applicability
criteria
for
non­
cogeneration
units,

regardless
of
any
future
changes
in
the
unit
or
its
operations.
If,
under
the
non­
cogeneration
unit
applicability
criteria,
the
unit
becomes
subject
to
the
trading
program,
the
unit
will
remain
subject
to
the
program
in
the
future.
Conversely
if
a
unit
initially
does
not
qualify
as
a
cogeneration
unit,
such
unit
becomes
subject
to
the
applicability
criteria
for
non­
cogeneration
units,

regardless
of
any
future
changes
in
the
unit.
If,
under
such
criteria,
the
unit
is
subject
to
the
trading
program,
the
unit
will
remain
subject
to
the
program
in
the
future.
This
approach
to
applicability
means
that
units
(
other
than,
in
some
cases,
opt­
in
units)
cannot
go
in
and
out
of
the
trading
program,
which,
if
allowed,
would
make
it
difficult
for
the
559
EPA,
States,
and
owners
or
operators
to
determine
which
units
should
be
complying
with
trading
program
requirements,
and
during
what
years,
and
would
likely
result
in
more
noncompliance
problems.

a.
Efficiency
Standard
for
Cogeneration
Units
The
EPA
proposed
operating
and
efficiency
standards
(
i.
e.,
the
useful
thermal
energy
output
of
the
unit
must
be
no
less
than
a
certain
percent
of
the
total
energy
output
and,
in
some
cases,
useful
power
must
be
no
less
than
a
certain
percent
of
total
energy
input)
in
the
SNPR
that
a
unit
must
meet
in
order
to
qualify
as
a
cogeneration
unit.

If
the
unit
qualifies
as
a
cogeneration
unit,
then
it
may
be
eligible
for
exemption
from
the
CAIR,
depending
upon
whether
it
meets
additional
operating
criteria,
discussed
below.
As
discussed
in
the
NPR,
the
EPA
proposed
the
same
operating
and
efficiency
standards
for
all
fossil
fuel­
fired
units
(
regardless
of
whether
they
burn
coal,
oil,
or
gas).
In
addition,
not
applying
the
operating
and
efficiency
standards
to
coal­
fired
units
would
be
counter
productive
to
the
EPA's
efforts
to
reduce
SO2
and
NOx
emissions
under
this
proposed
rule
because
of
the
relatively
high
SO2
and
NOx
emissions
from
coal­
fired
units.
In
particular,
without
application
of
the
efficiency
standards
to
coal­
fired
units,
highly
inefficient
coal­
fired
units,
which
have
particularly
high
emissions
per
MWhr
generated,
could
be
exempt
from
the
CAIR
560
Program.
In
addition,
if
coal­
fired
units
were
not
subject
to
the
operating
standard,
the
potential
would
exist
for
a
coal­
fired
unit
to
provide
only
a
token
amount
of
useful
thermal
energy
and
still
qualify
for
a
cogeneration
unit
exemption
from
the
CAIR
Program,
despite
having
relatively
high
emissions.

One
commenter
suggested
that
the
EPA
should
not
use
the
efficiency
standards
for
solid
fuel­
fired
cogeneration
units,

because
it
may
require
some
coal­
fired
cogeneration
units
that
were
exempt
from
the
Acid
Rain
Program
to
purchase
CAIR
allowances.
However,
the
EPA
analysis
indicates
that
most
existing
solid
fuel­
fired
cogeneration
units
affected
by
this
rule
will
meet
the
proposed
standard.
See
TSD
entitled
"
Cogeneration
Unit
Efficiency
Calculations"
in
the
docket.

To
the
extent
any
solid
fuel­
fired
cogeneration
units
cannot
meet
the
efficiency
standard
and
become
affected
units
under
the
CAIR,
the
EPA
believes
that,
considering
their
relatively
high
emissions
of
SO2
and
NOx
compared
to
oil
and
gas­
fired
units,
it
is
important
to
require
these
sources
to
meet
the
efficiency
standards
or
be
subject
to
the
emission
limits
under
the
CAIR
Program.

Another
commenter
suggested
that
the
efficiency
standards
should
not
apply
to
solid
fuel­
fired
cogeneration
units
because
solid
fuel­
fired
unit
efficiency
is
based
on
HHV
(
higher
heating
value)
while
gas,
or
oil­
fired
unit
561
127
The
range
included
solid
fuel­
fired
cogeneration
units
from
25
MW
to
250
MW.
efficiency
is
based
on
LHV
(
lower
heating
value).
The
EPA
analyzed
a
range127
of
solid
fuel­
fired
cogeneration
units
and
calculated
their
efficiencies
to
see
if
they
would
meet
the
minimum
efficiency
standard.
All
of
the
units
selected
satisfied
the
proposed
efficiency
standard.
See
TSD
entitled
"
Cogeneration
Unit
Efficiency
Calculations"
in
the
docket.

As
a
result,
the
EPA
believes
that
most
solid
fuel­
fired
cogeneration
units
will
meet
the
proposed
efficiency
standard.
The
efficiency
standard
the
EPA
is
adopting
is
the
Public
Utility
Regulatory
Act
(
PURPA)
of
thermal
efficiency
of
42.5
percent.
See
TSD
entitled,
"
Cogeneration
Unit
Efficiency
Calculations"
for
further
discussion,
is
based
on
LHV.
If
the
efficiency
of
a
solid­
fuel­
fired
unit
is
expressed
in
terms
of
HHV,
it
can
easily
be
converted
to
LHV
for
purposes
of
determining
whether
it
meets
the
efficiency
standard.
Therefore,
the
reason
given
by
the
commenter
(
that
solid
fuel­
fired
unit
efficiency
is
expressed
in
terms
of
HHV)
is
not
grounds
for
not
applying
an
efficiency
standard
to
these
units.
One
commenter
supported
applying
the
same
efficiency
standard
to
solid
fuel­
fired
units
as
the
EPA
proposed.
The
EPA
is
finalizing
its
proposed
cogeneration
unit
definition,
which
applies
the
same
operating
and
562
efficiency
standards
to
all
units
regardless
of
the
type
of
fossil
fuel
burned.

b.
One­
third
Potential
Electric
Output
Capacity
The
EPA
is
finalizing
the
1/
3
potential
electric
output
capacity
criteria
in
the
NPR
and
SNPR.
Under
the
proposals,

the
following
cogeneration
units
are
EGUs:
any
cogeneration
unit
serving
a
generator
with
a
nameplate
capacity
of
greater
than
25
MW
and
supplying
more
than
1/
3
potential
electric
output
capacity
and
more
than
219,000
MW­
hrs
annually
to
any
utility
power
distribution
system
for
sale.
These
criteria
are
similar
to
those
used
in
the
Acid
Rain
Program
to
determine
whether
a
cogeneration
unit
is
a
utility
unit
and
the
NOx
SIP
Call
to
determine
whether
a
cogeneration
unit
is
an
EGU
or
a
non­
EGU.
The
primary
difference
between
the
proposed
criteria
and
the
1/
3
potential
electric
criteria
for
the
Acid
Rain
and
NOx
SIP
Call
Programs
is
that
these
programs
applied
the
criteria
to
the
initial
operation
of
the
unit
and
then
to
3­
year
rolling
average
periods
while
the
proposed
CAIR
criteria
are
applied
to
each
individual
year
starting
with
the
commencement
of
operation.
The
EPA
believes
that
using
an
individual
year
approach
would
streamline
the
application
and
administration
of
this
exemption.
No
adverse
comments
were
received
on
using
an
individual
year
approach
as
opposed
to
a
3­
year
rolling
average.
In
addition,
the
criteria
under
the
Acid
Rain
563
Program
and
the
NOx
SIP
Call
are
applied
somewhat
differently
to
units
commencing
construction
on
or
before
November
15,

1990
and
units
commencing
construction
after
November
15,

1990.
Several
commenters
suggested
exempting
all
cogeneration
units
under
the
PURPA
instead
of
using
the
proposed
criteria
and
cite
the
high
efficiency
of
cogeneration
as
a
reason
for
a
complete
exemption.
The
EPA
believes
it
is
important
to
include
in
the
CAIR
Program
all
units,
including
cogeneration
units,
that
are
substantially
in
the
business
of
selling
electricity.
The
proposed
1/
3
potential
electric
output
criteria
described
above
are
intended
to
do
that.

Inclusion
of
all
units
substantially
in
the
electricity
sales
business
minimizes
the
potential
for
shifting
utilization,
and
emissions,
from
regulated
to
unregulated
units
in
that
business
and
thereby
freeing
up
allowances,

with
the
result
that
total
emissions
from
generation
of
electricity
for
sale
exceed
the
CAIR
emissions
caps.
The
fact
that
units
in
the
electricity
sales
business
are
generally
interconnected
through
their
access
to
the
grid
significantly
increases
the
potential
for
utilization
shifting.

One
commenter
suggested
that
the
1/
3
of
potential
electric
output
capacity
criteria
be
applied
on
an
annual
basis.
The
EPA
agrees
that
the
criteria
should
be
applied
564
annually.
The
proposed
and
final
model
cap
and
trade
rules
adopt
that
approach.

c.
Clarifying
"
For
Sale"

Several
commenters
requested
the
EPA
confirm
that,
for
purposes
of
applying
the
1/
3
potential
electric
output
criteria,
simultaneous
purchases
and
sales
of
electricity
are
to
be
measured
on
a
"
net"
basis,
as
is
done
in
the
Acid
Rain
Program.
At
least
one
commenter
suggested
that
the
net
approach
also
be
applied
to
purchase
and
sales
that
are
not
simultaneous.
For
purposes
of
applying
the
1/
3
potential
electric
output
criteria
in
the
CAIR
Program
and
the
model
cap
and
trade
rules,
EPA
confirms
that
the
only
electricity
that
counts
as
a
sale
is
electricity
produced
by
a
unit
that
actually
flows
to
a
utility
power
distribution
system
from
the
unit.
Electricity
that
is
produced
by
the
unit
and
used
on­
site
by
the
electricity­
consuming
component
of
the
facility
will
not
count,
including
cogenerated
electricity
that
is
simultaneously
purchased
by
the
utility
and
sold
back
to
such
facility
under
purchase
and
sale
agreements
under
the
PURPA.
However,
electric
purchases
and
sales
that
are
not
simultaneous
will
not
be
netted;
the
1/
3
potential
electric
output
criteria
will
be
applied
on
a
gross
basis,
except
for
simultaneous
purchase
and
sales.
This
is
consistent
with
the
approach
taken
in
the
Acid
Rain
Program.

d.
Multiple
Cogeneration
Units
565
Some
commenters
suggested
aggregating
multiple
cogeneration
units
that
are
connected
to
a
utility
distribution
system
through
a
single
point
when
applying
the
1/
3
potential
electric
output
capacity
criteria.
These
commenters
suggested
that
it
is
not
feasible
to
determine
which
unit
is
producing
the
electricity
exported
to
the
outside
grid.
The
EPA
proposed
to
determine
whether
a
unit
is
affected
by
the
CAIR
on
an
individual­
unit
basis.
This
unit­
based
approach
is
consistent
with
both
the
Acid
Rain
Program
and
the
NOx
SIP
Call.
The
EPA
considers
this
approach
to
be
feasible
based
on
experience
from
these
existing
programs,
including
for
sources
with
multiple
cogeneration
units.
The
EPA
is
unaware
of
any
instances
of
cogeneration
unit
owners
being
unable
to
determine
how
to
apply
the
1/
3
potential
electric
output
capacity
criteria
where
there
are
multiple
cogeneration
units
at
a
source.

In
a
case
where
there
are
multiple
cogeneration
units
with
only
one
connection
to
a
utility
power
distribution
system,
the
electricity
supplied
to
the
utility
distribution
system
can
be
apportioned
among
the
units
in
order
to
apply
the
1/
3
potential
electric
output
capacity
criteria.
A
reasonable
basis
for
such
apportionment
must
be
developed
based
on
the
particular
circumstances.
The
most
accurate
way
of
apportioning
the
electricity
supplied
to
the
utility
power
distribution
system
seems
to
be
apportionment
based
on
the
566
amount
of
electricity
produced
by
each
unit
during
the
relevant
period
of
time.

Exemption
for
Independent
Power
Production
(
IPP)
Facilities:

Some
commenters
stated
that
certain
IPP
facilities
are
exempt
from
the
Acid
Rain
Program
and
that
they
should
also
be
exempt
from
the
CAIR
Program
and
model­
cap
and
trade
rules.
Under
the
Acid
Rain
Program,
an
IPP
facility
that
has,
as
of
November
15,
1990,
a
qualifying
power
purchase
commitment
(
including
a
sales
price)
to
sell
at
least
15
percent
of
planned
net
output
capacity
and
has
installed
net
output
capacity
not
exceeding
130
percent
of
planned
net
output
capacity
is
exempt.
However,
if
the
power
purchase
commitment
changes
after
November
15,
1990
in
a
way
that
allows
the
cost
of
compliance
with
the
Acid
Rain
Program
to
be
shifted
to
the
purchaser,
then
the
IPP
facility
loses
the
exemption.
For
example,
expiration
or
termination
of
the
power
purchase
commitment
or
modification
so
that
the
price
is
increased
(
e.
g.,
changed
to
a
market
price)
results
in
loss
of
the
exemption.
The
purpose
of
the
exemption
is
to
protect
IPP
facilities
subject
to
contract
prices
that
were
set
before
passage
of
the
CAA
Amendments
of
1990
(
including
the
Acid
Rain
Program
in
title
IV)
and
that
did
not
allow
passthrough
of
the
costs
of
Acid
Rain
Program
compliance.

However,
the
EPA
maintains
that
this
exemption
was
aimed
at
easing
the
transition
of
such
facilities
into
the
Acid
Rain
567
Program
and
that
there
is
no
basis
for
maintaining
this
exemption
for
every
subsequent
cap
and
trade
program.
In
addition,
this
exemption
was
not
used
in
the
NOx
SIP
Call.

D.
How
Are
Emission
Allowances
Allocated
to
Sources?

It
is
important
to
have
consistency
on
a
State­
by­
State
basis
with
the
basic
requirements
of
the
cap
and
trade
approach
when
implementing
a
multi­
State
cap
and
trade
program.
This
will
ensure
that:
the
integrity
of
the
cap
and
trade
approach
is
preserved
so
that
the
required
emissions
reductions
are
achieved;
the
compliance
and
administrative
costs
are
minimized;
and
source
owners
and
operators
are
equitably
treated.
However,
the
EPA
believes
that
some
limited
differences,
such
as
allowance
allocation
methodologies
for
NOx
allowances,
are
possible
without
jeopardizing
the
environmental
and
other
goals
of
the
program.

1.
Allocation
of
NOx
and
SO2
Allowances.

Each
State
participating
in
EPA­
administered
cap
and
trade
programs
must
develop
a
method
for
allocating
(
i.
e.,

distributing)
an
amount
of
allowances
authorizing
the
emissions
tonnage
of
the
State's
CAIR
EGU
budget.
For
NOx
allowances,
each
State
has
the
flexibility
to
allocate
its
allowances
however
they
choose,
so
long
as
certain
timing
requirements
are
met.
568
For
SO2,
as
noted
in
the
January
2004
proposal,
States
will
have
no
discretion
in
their
allocation
approach
since
the
CAIR
SO2
cap
and
trade
program
uses
title
IV
SO2
allowances,
which
have
been
already
allocated
in
perpetuity
to
individual
units
by
title
IV
of
the
CAA.

a.
Required
Aspects
of
a
State
NOx
Allocation
Approach.

While
it
is
the
EPA's
intent
to
provide
States
with
as
much
flexibility
as
possible
in
developing
allocation
approaches,
there
are
some
aspects
of
State
allocations
that
must
be
consistent
for
all
States.
All
State
allocation
systems
are
required
to
include
specific
provisions
that
establish
when
States
notify
the
EPA
and
sources
of
the
unit­
by­
unit
allocations.
These
provisions
establish
a
deadline
for
each
State
to
submit
to
the
EPA
its
unit­
by­
unit
allocations
for
processing
into
the
electronic
allowance
tracking
system.
Since
the
Administrator
will
then
expeditiously
record
the
submitted
allowance
allocations,

sources
will
thereby
be
notified
of,
and
have
access
to,

allocations
with
a
minimum
lead
time
(
about
3
years)
before
the
allowances
can
be
used
to
meet
the
NOx
emission
limit.

Today's
action
finalizes
the
proposal
to
require
States
to
submit
unit­
by­
unit
allocations
of
allowances
for
a
given
year
no
less
than
3
years
prior
to
January
1
of
the
allowance
569
128
If
the
deadline
for
States
to
submit
SIPs
is
September
of
2006,
then
this
would
result
in
notification
period
of
less
than
3
years
for
the
first
year
of
CAIR.
vintage
year,
which
approach
was
supported
by
commenters.
128
Requiring
States
to
submit
allocations
and
thereby
provide
a
minimum
lead
time
before
the
allowances
can
be
used
to
meet
the
NOx
emission
limit
ensures
that
an
affected
source
 
regardless
of
the
State
in
the
CAIR
region
in
which
the
unit
is
located
 
will
have
sufficient
time
to
plan
for
compliance
and
implement
their
compliance
planning.
Allocating
allowances
less
than
3
years
in
advance
of
the
compliance
year
may
reduce
a
CAIR
unit's
ability
to
plan
for
and
implement
compliance
and,
consequently,
increase
compliance
costs.
For
example,
a
shorter
lead
time
would
reduce
the
period
for
buying
or
selling
allowances
and
could
prevent
sources
from
participating
in
allowance
futures
markets,
a
mechanism
for
hedging
risk
and
lowering
costs.

Further,
requiring
a
uniform,
minimum
lead­
time
for
submission
of
allocations
allows
the
EPA
to
perform
its
allocation­
recordation
activities
in
a
coordinated
and
efficient
manner
in
order
to
complete
expeditiously
the
recordation
for
the
entire
CAIR
region
and
thereby
promote
a
fair
and
competitive
allowance
market
across
the
region.
570
These
minimum
requirements
apply
to
the
NOx
allocation
approach
and
are
not
relevant
for
the
SO2
cap
and
trade
program,
which
relies
on
title
IV
allowances.

b.
Flexibility
and
Options
for
a
State
NOx
Allowance
Allocations
Approach.

Allowance
allocation
decisions
in
a
cap­
and­
trade
program
raise
essentially
distributional
issues,
as
economic
forces
are
expected
to
result
in
economically
efficient
and
environmentally
similar
outcomes
regardless
of
the
manner
in
which
allowances
are
initially
distributed.
Consequently,

for
CAIR
NOx
allowances,
States
are
given
latitude
in
developing
their
allocation
approach.
NOx
allocation
methodology
elements
for
which
States
will
have
flexibility
include:

B.
The
cost
of
the
allowance
distribution
(
e.
g.,
free
distribution
or
auction);

C.
The
frequency
of
allocations
(
e.
g.,
permanent
or
periodically
updated);

D.
The
basis
for
distributing
the
allowances
(
e.
g.,

heat­
input
or
power
output);
and,

E.
The
use
of
allowance
set­
asides
and
their
size,
if
used
(
e.
g.,
new
unit
set­
asides
or
set­
asides
for
energy
efficiency,
for
development
of
Integrated
Gasification
Combined
Cycle
(
IGCC)
generation,
for
renewables,
or
for
small
units).
571
Some
commenters
have
argued
against
giving
States
flexibility
in
determining
NOx
allocations,
citing
concerns
about
complexity
of
operating
in
different
markets
and
about
the
robustness
of
the
trading
system.
The
EPA
maintains
that
offering
such
flexibility,
as
it
did
in
the
NOx
SIP
Call,

does
not
compromise
the
effectiveness
of
the
trading
program.

A
number
of
commenters
have
argued
against
allowing
(
or
requiring)
the
use
of
allowance
auctions,
while
others
did
not
believe
that
the
EPA
should
recommend
auctions.
For
today's
final
action,
while
there
are
some
clear
potential
benefits
to
using
auctions
for
allocating
allowances
(
as
noted
in
the
SNPR),
the
EPA
believes
that
the
decision
regarding
utilizing
auctions
should
ultimately
be
made
by
the
States.
Therefore,
EPA
is
not
requiring,
restricting,
or
barring
State
use
of
auctions
for
allocating
allowances.

A
number
of
commenters
supported
allowing
the
use
of
allowance
set­
asides
for
various
purposes.
In
today's
final
action,
the
EPA
is
leaving
the
decision
on
using
set­
asides
up
to
the
States,
so
that
States
may
craft
their
allocation
approach
to
meet
their
State­
specific
policy
goals.

i.
Example
Allowance
Allocation
Methodology
In
the
SNPR,
EPA
included
an
example
(
offered
for
informational
guidance)
of
an
allocation
methodology
that
includes
allowances
for
new
generation
and
is
administratively
straightforward.
In
today's
preamble,
EPA
572
is
including
in
today's
preamble,
this
"
modified
output"

example
allocations
approach,
as
was
outlined
in
the
SNPR.

The
EPA
maintains
that
the
choice
of
allocation
methodology
does
not
impact
the
achievement
of
the
specific
environmental
goals
of
the
CAIR
Program.
This
methodology
is
offered
simply
as
an
example,
and
individual
States
retain
full
latitude
to
make
their
own
choices
regarding
what
type
of
allocation
method
to
adopt
for
NOx
allowances
and
are
not
bound
in
any
way
to
adopt
the
EPA's
example.

This
example
method
involves
input­
based
allocations
for
existing
fossil
units,
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.
Providing
allowances
for
new
sources
addresses
a
number
of
commenter
concerns
about
the
negative
effect
of
new
units
not
having
access
to
allowances.

Under
the
example
method,
allocations
are
made
from
the
State's
EGU
NOx
budget
for
the
first
five
control
periods
(
2009
through
2013)
of
the
model
cap
and
trade
program
for
existing
sources
on
the
basis
of
historic
baseline
heat
input.
Commenters
expressed
some
concern
regarding
the
proposed
January
1,
1998
cut­
off
on­
line
date
for
considering
units
as
existing
units.
The
cut­
off
on­
line
date
was
selected
so
that
any
unit
meeting
the
cut­
off
date
would
have
573
at
least
5
years
of
operating
data,
i.
e.,
data
for
1998
through
2002
(
which
was
the
last
year
for
which
annual
data
was
available).
The
EPA
is
still
concerned
with
ensuring
that
particular
units
are
not
disadvantaged
in
their
allocations
by
having
insufficient
operating
data
on
which
to
base
the
allocations.
The
EPA
believes
that
a
5
year
window,

starting
from
commencement
of
operation,
gives
units
adequate
time
to
collect
sufficient
data
to
provide
a
fair
assessment
of
their
operations.
Annual
operating
data
is
now
available
for
2003.
The
EPA
is
finalizing
January
1,
2001
as
the
cutoff
on­
line
date
for
considering
units
as
existing
units
since
units
meeting
the
cut­
off
date
will
have
at
least
5
years
of
operating
data
(
i.
e.,
data
for
2001
through
2005).

The
allowances
for
2014
and
later
will
be
allocated
from
the
State's
EGU
NOx
budget
annually,
6
years
in
advance,

taking
into
account
output
data
from
new
units
with
established
baselines
(
modified
by
the
heat
input
conversion
factor
to
yield
heat
input
numbers).
As
new
units
enter
into
service
and
establish
a
baseline,
they
are
allocated
allowances
in
proportion
to
their
share
of
the
total
calculated
heat
input
(
which
is
existing
unit
heat
input
plus
new
units'
modified
output).
Allowances
allocated
to
existing
units
slowly
decline
as
their
share
of
total
calculated
heat
input
decreases
with
the
entry
of
new
units.

After
5
years
of
operation,
a
new
unit
will
have
an
574
adequate
operating
baseline
of
output
data
to
be
incorporated
into
the
calculations
for
allocations
to
all
affected
units.

The
average
of
the
highest
3
years
from
these
5
years
will
be
multiplied
by
the
heat­
input
conversion
factor
to
calculate
the
heat
input
value
that
will
be
used
to
determine
the
new
unit's
allocation
from
the
pool
of
allowances
for
all
sources.

Under
the
EPA
example
method,
existing
units
as
a
group
will
not
update
their
heat
input.
This
will
eliminate
the
potential
for
a
generation
subsidy
(
and
efficiency
loss)
as
well
as
any
potential
incentive
for
less
efficient
existing
units
to
generate
more.
This
methodology
will
also
be
easier
to
implement
since
it
will
not
require
the
updating
of
existing
units'
baseline
data.
Retired
units
will
continue
to
receive
allowances
indefinitely,
thereby
creating
an
incentive
to
retire
less
efficient
units
instead
of
continuing
to
operate
them
in
order
to
maintain
the
allowances
allocations.

Moreover,
new
units
as
a
group
will
only
update
their
heat
input
numbers
once
­
for
the
initial
5­
year
baseline
period
after
they
start
operating.
This
will
eliminate
any
potential
generation
subsidy
and
be
easier
to
implement,

since
it
will
not
require
the
collection
and
processing
of
data
needed
for
regular
updating.
575
The
EPA
believes
that
allocating
to
existing
units
based
on
a
baseline
of
historic
heat
input
data
(
rather
than
output
data)
is
desirable,
because
accurate
protocols
currently
exist
for
monitoring
this
data
and
reporting
it
to
the
EPA,

and
several
years
of
certified
data
are
available
for
most
of
the
affected
sources.
The
EPA
expects
that
any
problems
with
standardizing
and
collecting
output
data,
to
the
extent
that
they
exist,
can
be
resolved
in
time
for
their
use
for
new
unit
calculations.
Given
that
units
keep
track
of
electricity
output
for
commercial
purposes,
this
is
not
likely
to
be
a
significant
problem.

A
number
of
commenters
expressed
support
for
the
EPA's
proposal
in
the
SNPR
that
the
heat
input
data
for
existing
units
be
adjusted
by
multiplying
it
by
different
factors
based
on
fuel­
type.
Contrary
to
some
commenters'
claims,

determining
allocations
with
fuel
factors
would
not
create
disincentives
for
efficiency.
With
the
use
of
a
single
baseline
for
existing
units,
neither
adjusted
input,
nor
input,
nor
output
based
allocations
would
provide
additional
incentives
for
energy
efficiency.
All
sources
have
incentives
to
reduce
emissions
(
improving
efficiency
is
a
way
of
doing
this)
as
a
result
of
the
cap
and
trade
program,
not
because
of
the
choice
of
an
allocation
based
on
a
single
historic
baseline.
576
The
EPA
acknowledges
that
since
allowances
have
value,

different
allocations
of
allowances
clearly
do
impact
the
distribution
of
wealth
among
different
generators.
However,

in
general,
the
economics
of
power
generation
dictate
that
generators
selling
power
will
seek
to
operate
(
and
burn
fuel)

to
meet
energy
demand
in
a
least­
cost
manner.
The
cost
of
the
power
generated
(
reflecting
the
bid
price
per
megawatt
hour)
will
include
the
cost
of
allowances
to
cover
emissions,

whether
the
generator
uses
allowances
that
it
already
owns,

or
whether
it
needs
to
purchase
additional
allowances.
With
a
liquid
market
for
allowances,
allocations
for
existing
sources
(
whose
baseline
does
not
change)
are
a
sunk
benefit
or
sunk
cost,
not
impacting
the
existing
generator's
behavior
on
the
margin.
Thus,
the
use
of
fuel
factors
in
our
allocating
method
would
not
be
expected
to
result
in
changes
in
generators'
choices
for
fuel
efficiency.

In
its
example
allocation
approach,
the
EPA
is
including
adjustments
of
heat
input
by
fuel
type
based
on
average
historic
NOx
emissions
rates
by
three
fuel
types
(
coal,

natural
gas,
and
oil)
for
the
years
1999­
2002.
As
noted
in
the
SNPR,
such
calculations
would
lead
to
adjustment
factors
of
1.0
for
coal,
0.4
for
gas
and
0.6
for
oil.
The
factors
would
reflect
the
inherently
different
emissions
rates
of
different
fossil­
fired
units
(
and
consequently
also
reflect
the
different
burdens
to
control
emissions.
577
129Energy
Information
Administration,
"
Annual
Energy
Outlook
2004,
With
Projections
to
2025",
January
2004.
Assumptions
for
the
NEMS
model.
http://
www.
eia.
doe.
gov/
oiaf/
archive/
aeo04/
assumption/
tbl38.
h
tml
However,
allocating
to
new
(
not
existing)
sources
on
the
basis
of
input
(
and
particularly
fuel­
adjusted
heat
input)

would
serve
to
subsidize
less­
efficient
new
generation.
For
a
given
amount
of
generation,
more
efficient
units
will
have
the
lower
fuel
input
or
heat
input.
Allocating
to
new
units
based
on
heat
input
could
encourage
the
building
of
less
efficient
units
since
they
would
get
more
allowances
than
an
equivalent
efficient,
lower
heat­
input
unit.
The
modified
output
approach,
as
described
below,
will
encourage
new,

clean
generation,
and
will
not
reward
less
efficient
new
coal
units
or
less
efficient
new
gas
units.

Under
the
example
method,
allowances
will
be
allocated
to
new
units
of
each
fuel­
type
with
an
appropriate
baseline
on
a
"
modified
output"
basis.
The
new
unit's
modified
output
will
be
calculated
by
multiplying
its
gross
output
by
a
heat
rate
conversion
factor
of
7,900
btu/
kWh
for
coal
units
and
6,675
btu/
kWh
for
oil
and
gas
units.
The
7,900
btu/
kWh
value
for
the
conversion
factor
for
new
coal
units
is
an
average
of
heat­
rates
for
new
pulverized
coal
plants
and
new
IGCC
coal
plants
(
based
upon
assumptions
in
EIA's
Annual
Energy
Outlook
(
AEO)
2004129).
The
6,675
btu/
kWh
value
for
the
conversion
578
factor
for
new
gas
units
is
an
average
of
heat­
rates
for
new
combined
cycle
gas
units
(
also
based
upon
assumptions
in
EIA's
AEO
2004).
A
single
conversion
rate
for
each
fuel­
type
will
create
consistent
and
level
incentives
for
efficient
generation,
rather
than
favoring
new
units
with
higher
heatrates

For
new
cogeneration
units,
their
share
of
the
allowances
will
be
calculated
by
converting
the
available
thermal
output
(
btu)
of
useable
steam
from
a
boiler
or
useable
heat
from
a
heat
exchanger
to
an
equivalent
heat
input
by
dividing
the
total
thermal
output
(
btu)
by
a
general
boiler/
heat
exchanger
efficiency
of
80
percent.

New
combustion
turbine
cogeneration
units
will
calculate
their
share
of
allowances
by
first
converting
the
available
thermal
output
of
useable
steam
from
a
heat
recovery
steam
generator
(
HRSG)
or
useable
heat
from
a
heat
exchanger
to
an
equivalent
heat
input
by
dividing
the
total
thermal
output
(
btu)
by
the
general
boiler/
heat
exchanger
efficiency
of
80
percent.
To
this
they
will
add
the
electrical
generation
from
the
combustion
turbine,
converted
to
an
equivalent
heat
input
by
multiplying
by
the
conversion
factor
of
3,413
btu/
kWh.
This
sum
will
yield
the
total
equivalent
heat
input
for
the
cogeneration
unit.

Steam
and
heat
output,
like
electrical
output,
is
a
useable
form
of
energy
that
can
be
utilized
to
power
other
579
processes.
Because
it
would
be
nearly
impossible
to
adequately
define
the
efficiency
in
converting
steam
energy
into
the
final
product
for
all
of
the
various
processes,
this
approach
focuses
on
the
efficiency
of
a
cogeneration
unit
in
capturing
energy
in
the
form
of
steam
or
heat
from
the
fuel
input.

Commenters
expressed
concern
about
a
single
conversion
factor,
arguing
for
different
factors
for
different
fuels
and
technologies.
The
EPA
recognizes
these
concerns
and
agrees
that
different
new
fossil­
generation
units
have
inherently
different
heat
rates,
largely
dictated
by
the
technology
needed
to
burn
different
fuels.
A
single
conversion
rate
for
all
units
would
provide
new
gas­
fired
combined
cycle
units
with
relatively
more
allowances,
relative
to
their
emissions,

than
it
would
for
new
coal­
fired
units.

The
EPA
maintains
that
providing
each
new
source
an
equal
amount
of
allowances
per
MWh
of
output,
given
the
fuel
it
is
burning,
is
an
equitable
approach.
Since
electricity
output
is
the
ultimate
product
being
produced
by
EGUs,
a
single
conversion
factor
for
each
fuel,
based
on
output,

ensures
that
all
new
sources
burning
a
particular
fuel
will
be
treated
equally.

Some
commenters
support
allocating
allowances
to
all
new
generation,
not
just
fossil
fuel­
fired
CAIR
units.
The
EPA
notes
that
including
new
non­
CAIR
and
non­
fossil
units
in
the
580
130
Some
commenters
stated
that,
if
allocations
were
provided
for
non­
emitting
new
generation,
they
also
should
be
provided
to
all
such
generation,
including
nuclear
units.

131
For
instance,
would
the
addition
of
a
single
new
wind
turbine
at
a
wind­
farm
constitute
a
"
new
unit"?
allowance
distribution
would
raise
issues,
about
which
the
EPA
lacks
sufficient
information
for
resolution
at
this
time
for
the
EPA's
example
method.
It
would
be
necessary
to
clearly
define
what
types
of
generating
facilities
that
could
participate
and
what
would
constitute
"
new"
non­
fossil
generation.
130
Commenters
did
not
provide
any
analysis
of
the
impact
of
possible
definitions
on
generation
mix,
or
electricity
markets.
Further,
in
order
to
include
all
generation,
there
would
be
a
need
to
establish
application
and
data
collections
procedures
and
determine
appropriate
size
cut­
offs
and
boundaries
of
this
generation
­
since
in
many
such
instances
there
is
no
clear
analog
to
discrete
fossil
"
units".
131
There
also
are
associated
issues
about
developing
appropriate
measurement
and
data
reporting
requirements
for
such
sources.
Commenters
supporting
this
approach
did
not
address
any
of
these
matters
in
any
detail.

However,
the
EPA
encourages
States
that
are
interested
in
including
such
units
in
their
updating
allocations
to
consider
potential
solutions
and
include
them
in
their
SIPs.

Under
the
example
method,
new
units
that
have
entered
581
132
As
noted
earlier
in
this
section,
the
EPA
is
now
considering
new
units
to
be
those
that
went
online
after
January
1,
2001
rather
than
1998.
service,
but
have
not
yet
started
receiving
allowances
through
the
update,
will
receive
allowances
each
year
from
a
new
source
set­
aside.
The
new
source
allowances
from
the
set­
aside
will
be
distributed
based
on
their
actual
emissions
from
the
previous
year.
Such
an
allocation
approach
will
generally
provide
new
units
sufficient
allowances
to
cover
their
emissions
during
the
interim
period
before
the
units
are
allocated
allowances
on
the
same
basis
as
existing
units.

Today's
example
method
includes
a
new
source
set­
aside
equal
to
5
percent
of
the
State's
emission
budget
for
the
years
2009­
2013
and
3
percent
of
the
State's
emission
budget
for
the
subsequent
years.
In
the
SNPR,
the
EPA
proposed
a
level
2
percent
set­
aside
for
all
years.

Commenters
noted
their
concern
that
the
amount
of
the
set­
aside
in
the
early
years
of
the
program
should
be
higher
to
reflect
the
fact
that
the
set­
aside
will
initially
need
to
accommodate
all
new
units
entering
into
service
from
1998
through
2010.132
In
order
to
estimate
the
need
for
allocations
for
new
units,
the
EPA
looked
at
the
NOx
emissions
from
units
that
went
online
starting
in
1999
as
projected
by
the
Integrated
Planning
Model
(
IPM)
runs
582
modeling
CAIR
for
the
years
2010
and
2015.
These
IPM
emissions
projections
indicated
over
57,000
tons
of
NOx
emissions
in
2010
and
about
74,000
tons
of
NOx
emission
by
2015
from
new
sources
need
to
be
covered
under
set­
asides
throughout
the
CAIR
region.
The
2010
number
represents
almost
4
percent
of
the
Phase
I
NOx
regional
cap,
while
the
2015
number
represents
about
6
percent
of
the
Phase
I
regional
cap.
Consequently,
today's
example
method
includes
a
5
percent
set­
aside
for
the
initial
period
(
2009­
2013).
It
should
be
noted
that
by
2014,
the
set­
aside
would
need
to
cover
new
sources
from
the
entire
period
2004­
2013.

The
choice
of
a
3
percent
new
source
set­
aside,
starting
in
2014,
reflects
concerns
that
adequate
allowances
be
provided
for
the
10
years
of
new
units
to
be
covered
by
the
set­
aside
in
2014
and
subsequent
years.
(
The
set
aside
in
2014,
for
example,
would
need
to
accommodate
all
units
that
went
on­
line
between
2004
and
2013).

Individual
States
using
a
version
of
the
example
method
may
want
to
adjust
this
initial
5
year
set­
aside
amount
to
a
number
higher
or
lower
than
5
percent
to
the
extent
that
they
expect
to
have
more
or
less
new
generation
going
on­
line
during
the
2001­
2013
period.
They
may
also
want
to
adjust
the
subsequent
set­
aside
amount
to
a
number
higher
or
lower
than
3
percent
to
the
extent
that
they
expect
more
or
less
new
generation
going
on­
line
after
2004.
States
may
also
583
want
to
set
this
percentage
a
little
higher
than
the
expected
need,
since,
in
the
event
that
the
amount
of
the
set­
aside
exceeds
the
need
for
new
unit
allowances,
the
State
may
want
to
provide
that
any
unused
set­
aside
allowances
will
be
redistributed
to
existing
units
in
proportion
to
their
existing
allocations.

For
the
example
method,
the
EPA
is
finalizing
the
approach
that
new
units
will
begin
receiving
allowances
from
the
set­
aside
for
the
control
period
immediately
following
the
control
period
in
which
the
new
unit
commences
commercial
operation,
based
on
the
unit's
emissions
for
the
preceding
control
period.
Thus,
a
source
will
be
required
to
hold
allowances
during
its
start­
up
year,
but
will
not
receive
an
allocation
for
that
year.

States
will
allocate
allowances
from
the
set­
aside
to
all
new
units
in
any
given
year
as
a
group.
If
there
are
more
allowances
requested
than
in
the
set­
aside,
allowances
will
be
distributed
on
a
pro­
rata
basis.
Allowance
allocations
for
a
given
new
unit
in
following
years
will
continue
to
be
based
on
the
prior
year's
emissions
until
the
new
unit
establishes
a
baseline,
is
treated
as
an
existing
unit,
and
is
allocated
allowances
through
the
State's
updating
process.
This
will
enable
new
units
to
have
a
good
sense
of
the
amount
of
allowances
they
will
likely
receive
­

in
proportion
to
their
emissions
for
the
previous
year.
This
584
133
With
the
alternate
approach
from
the
NOx
SIP
Call,
States
could
distribute
a
new
source
set­
aside
for
a
control
period
based
on
full
utilization
rates,
at
the
end
of
the
year
the
actual
allowance
allocation
would
be
adjusted
to
account
for
actual
unit
utilization/
output,
and
excess
allowances
would
be
returned
and
redistributed,
first
taking
into
account
new
unit
requests
that
were
not
able
to
be
addressed.
methodology
will
not
provide
allowances
to
a
unit
in
its
first
year
of
operation;
however
it
is
a
methodology
that
is
straightforward,
reasonable
to
implement,
and
predictable.

In
the
SNPR,
the
example
method
from
the
NOx
SIP
Call
model
rule
was
proposed
as
an
alternate
approach.
133
However,

the
EPA
has
found
this
approach
to
be
complicated
for
both
the
States
and
the
EPA
to
implement.
Additionally,
the
NOx
SIP
Call
approach
would
introduce
a
higher
level
of
uncertainty
for
sources
in
the
allocation
process
than
necessary.

While
the
EPA
is
offering
an
example
allocation
method
with
accompanying
regulatory
language,
the
EPA
reiterates
that
it
is
giving
States'
flexibility
in
choosing
their
NOx
allocations
method
so
they
may
tailor
it
to
their
unique
circumstances
and
interests.
Several
commenters,
for
instance,
have
noted
their
desire
for
full
output­
based
allocations
(
in
contrast
to
the
hybrid
approach
in
the
example
above).
In
the
past,
EPA
had
sponsored
a
work
group
to
assist
States
wishing
to
adopt
output­
based
NOx
585
134
Auctions
could
provide
States
with
a
non­
distortionary
source
of
revenue.

135
5
percent
of
the
allowances
would
go
to
a
new
source
setaside
allocations
for
the
NOx
SIP
Call
and
believes
it
is
a
viable
approach
worth
considering.
Documents
from
meetings
of
this
group
and
the
resulting
guidance
report
(
found
at
http://
www.
epa.
gov/
airmarkets/
fednox/
workgrp.
html)
together
with
additional
resources
such
as
the
EPA­
sponsored
report
"
Output­
Based
Regulations:
A
Handbook
for
Air
Regulators"

(
found
at
http://
www.
epa.
gov/
cleanenergy/
pdf/
output_
rpt.
pdf)

can
help
States,
should
they
choose
to
adopt
any
output­
based
elements
in
their
allocation
plans.

As
an
another
alternative
example,
States
could
decide
to
include
elements
of
auctions
into
their
allowance
allocation
programs.
134
An
example
of
an
approach
where
CAIR
NOx
allowances
could
be
distributed
to
sources
through
a
combination
of
an
auction
and
a
free
allocation
is
provided
below.

During
the
first
year
of
the
trading
program,
94
percent
of
the
NOx
allowances
could,
for
example,
be
allocated
to
affected
units
with
an
auction
held
for
the
remaining
1
percent
of
the
NOx
allowances135.
Each
subsequent
year,
an
additional
1
percent
of
the
allowances
(
for
the
first
20
years
of
the
program),
and
then
an
additional
2.5
percent
586
thereafter,
could
be
auctioned
until
eventually
all
the
allowances
are
auctioned.
With
such
a
system,
for
the
first
20
years
of
the
trading
programs,
the
majority
of
allowances
would
be
distributed
for
free
via
the
allocation.
Allowances
allocated
for
these
earlier
years
are
generally
more
valuable
than
allowances
allocated
for
later
years
because
of
the
time
value
of
money.
Thus,
most
emitting
units
would
receive
relatively
more
allowances
in
the
early
years
of
the
program,

when
they
are
facing
the
expenses
of
taking
actions
to
control
their
emissions.
Even
though
the
proportion
of
allowances
allocated
to
existing
sources
declines
in
the
later
years
of
the
program,
these
sources
receive
for
free
a
very
significant
share
of
the
total
value
of
allowances
(
because
the
discounted
present
value
of
allowances
allocated
in
the
early
years
of
the
program
is
greater
than
the
discounted
present
value
of
the
allowances
auctioned
later).

Auctions
could
be
designed
by
the
State
to
promote
an
efficient
distribution
of
allowances
and
a
competitive
market.
Allowances
would
be
offered
for
sale
before
or
during
the
year
for
which
such
allowances
may
be
used
to
meet
the
requirement
to
hold
allowances.
States
would
decide
on
the
frequency
and
timing
of
auctions.
Each
auction
would
be
open
to
any
person,
who
would
submit
bids
according
to
auction
procedures,
a
bidding
schedule,
a
bidding
means,
and
by
fulfilling
requirements
for
financial
guarantees
as
587
specified
by
the
State.
Winning
bids,
and
required
payments,

for
allowances
would
be
determined
in
accordance
with
the
State
program
and
ownership
of
allowances
would
be
recorded
in
the
EPA
Allowance
Tracking
System
after
the
required
payment
is
received.

The
auction
could
be
a
multiple­
round
auction.

Interested
bidders
would
submit
before
the
auction,
one
or
more
initial
bids
to
purchase
a
specified
quantity
of
NOx
allowances
at
a
reserve
price
specified
by
the
State,

specifying
the
appropriate
account
in
the
Allowance
Tracking
System
in
which
such
allowances
would
be
recorded.
Each
bid
would
be
guaranteed
by
a
certified
check,
a
funds
transfer,

or,
in
a
form
acceptable
to
the
State,
a
letter
of
credit
for
such
quantity
multiplied
by
the
reserve
price.
For
each
round
of
the
auction,
the
State
would
announce
current
round
reserve
prices
for
NOx
and
determine
whether
the
sum
of
the
acceptable
bids
exceeds
the
quantity
of
such
allowances,

available
for
auction.
If
the
sum
of
the
acceptable
bids
for
NOx
allowances
exceeds
the
quantity
of
such
allowances
the
State
would
increase
the
reserve
price
for
the
next
round.

After
the
auction,
the
State
would
publish
the
names
of
winning
and
losing
bidders,
their
quantities
awarded,
and
the
final
prices.
The
State
would
return
payment
to
unsuccessful
bidders
and
add
any
unsold
allowances
to
the
next
relevant
auction.
588
In
summary,
today's
action
provides,
for
States
participating
in
the
EPA­
administered
CAIR
NOx
cap
and
trade
program,
the
flexibility
to
determine
their
own
methods
for
allocating
NOx
allowances
to
their
sources.
Specifically,

such
States
will
have
flexibility
concerning
the
cost
of
the
allowance
distribution,
the
frequency
of
allocations,
the
basis
for
distributing
the
allowances,
and
the
use
and
size
of
allowance
set­
asides.

E.
What
Mechanisms
Affect
the
Trading
of
Emission
Allowances?

1.
Banking
a.
The
CAIR
NPR
and
SNPR
Proposal
for
the
Model
Rules
and
Input
from
Commenters
Banking
is
the
retention
of
unused
allowances
from
1
calendar
year
for
use
in
a
later
calendar
year.
Banking
allows
sources
to
make
reductions
beyond
required
levels
and
"
bank"
the
unused
allowances
for
use
later.
Generally
speaking,
banking
has
several
advantages:
it
can
encourage
earlier
or
greater
reductions
than
are
required
from
sources,

stimulate
the
market
and
encourage
efficiency,
and
provide
flexibility
in
achieving
emissions
reductions
goals.
When
sources
reduce
their
SO2
and
NOx
emissions
in
the
early
phases,
the
cap
and
trade
program
creates
an
emissions
"
glide
path"
that
provides
earlier
environmental
benefits
and
lower
589
cost
of
compliance.
This
"
glide
path"
does
allow
emissions
to
exceed
the
cap
and
trade
program
budget
 
especially
in
the
initial
years
after
the
adoption
of
a
more
stringent
cap.

The
use
of
banked
allowances
from
the
Acid
Rain
and
NOx
SIP
Call
Programs
in
the
CAIR
NOx
and
SO2
cap
and
trade
programs
is
discussed
below
in
section
VIII.
F
of
this
preamble.

The
January
30,
2004
CAIR
NPR
and
June
10,
2004
CAIR
SNPR
proposed
that
the
CAIR
NOx
and
SO2
cap
and
trade
programs
allow
banking
and
the
use
of
banked
allowances
without
restrictions.
Allowing
unrestricted
banking
and
the
use
of
banked
allowances
is
consistent
with
the
existing
Acid
Rain
SO2
cap
and
trade
program.
The
NOx
SIP
Call
cap
and
trade
program,
however,
has
some
restrictions
on
the
use
of
banked
allowances,
a
procedure
called
"
flow
control,"

described
in
detail
in
the
June
10,
2004
CAIR
SNPR.

Comments
Regarding
Unrestricted
Banking
after
the
Start
of
the
CAIR
NOx
and
SO2
Cap
and
Trade
Programs
Many
commenters
supported
the
EPA's
proposal
to
allow
unrestricted
banking
and
the
use
of
banked
allowances
for
both
SO2
and
NOx,
agreeing
that
flow
control
is
a
complex
and
confusing
procedure
with
undemonstrated
environmental
benefit.
Further,
they
agreed
that
banking
with
no
restrictions
on
use
will
encourage
early
emissions
reductions,
stimulate
the
trading
market,
encourage
efficient
590
pollution
control,
and
provide
flexibility
to
affected
sources
in
meeting
environmental
objectives.

Other
commenters
objected
to
the
EPA's
proposal
to
allow
unrestricted
use
of
banked
allowances.
All
of
these
commenters
supported
some
use
of
flow
control
in
the
CAIR
cap
and
trade
programs,
most
supporting
its
use
for
both
SO2
and
NOx.

Some
commenters
disagreed
with
the
EPA's
assessment
that
the
use
of
flow
control
in
the
Ozone
Transport
Commission
(
OTC)
cap
and
trade
program
was
complicated
to
understand
and
implement
and
caused
market
complexity.
One
commenter
further
elaborated
that
flow
control
was
accepted
by
industry.
Another
commenter
claimed
that
the
EPA
has
not
analyzed
the
impact
of
the
flow
control
mechanism.

Some
commenters
supportive
of
flow
control
stated
that
flow
control
was
"
successful"
in
the
OTC
and
NOx
SIP
Call
trading
programs
and
"
worked
well"
and
"
achieved
the
desired
effect,"
without
supporting
those
statements.

b.
The
Final
CAIR
Model
Rules
and
Banking
The
EPA
acknowledges
that
the
OTC
NOx
cap
and
trade
program
has
functioned
for
several
years
despite
the
complexity
introduced
by
the
flow
control
procedures.

Industry
and
other
allowance
traders
have
adapted
to
these
complex
procedures,
yet
there
are
ongoing
questions
from
the
regulated
community
about
how
the
procedures
actually
work.
591
As
an
example,
one
commenter,
while
disagreeing
with
the
EPA's
assertion
that
flow
control
is
overly
complex,
goes
on
to
describe
incorrectly
the
implementation
of
flow
control.

The
NOx
SIP
Call
cap
and
trade
program
includes
similar
procedures
but
flow
control
was
not
triggered
in
the
first
2
years
of
the
program
(
2003
and
2004),
so
there
is
no
experience
to
be
drawn
from
that
program.

The
EPA
maintains
that
the
benefits
of
utilizing
these
complex
procedures
is
questionable.
The
EPA
has
analyzed
the
use
of
the
flow
control
procedures
in
a
paper
released
in
March
2004,
"
Progressive
Flow
Control
in
the
OTC
NOx
Budget
Program:
Issues
to
Consider
at
the
Close
of
the
1999
to
2002
Period."
The
lessons
learned
from
this
analysis
were
as
follows:

1)
Flow
control
can
create
market
pricing
complexity
and
uncertainty.
The
need
for
implementation
of
flow
control
for
a
particular
control
period
is
not
known
more
than
a
few
months
in
advance,
and
the
value
of
banked
allowances
varies
from
year
to
year,
depending
on
whether
flow
control
has
been
triggered
for
the
particular
year.
Therefore,
when
deciding
how
much
to
control,
a
source
has
some
increased
uncertainty
about
the
value
of
any
excess
allowances
it
generates.

2)
Flow
control
can
have
a
bigger
impact
on
small
entities
than
on
large
entities.
Large
firms
with
multiple
allowance
accounts
can
shift
banked
allowances
among
those
592
accounts
to
minimize
the
number
of
banked
allowances
surrendered
at
a
discounted
rate.

3)
Flow
control
does
not
directly
affect
short­
term
emissions,
so
it
may
not
serve
the
environmental
goals
for
which
it
was
created.

Incorporating
these
lessons
learned,
the
EPA
is
finalizing
the
CAIR
NOx
and
SO2
cap
and
trade
programs
with
no
flow
control
mechanism.

2.
Interpollutant
Trading
Mechanisms
a.
The
CAIR
NPR
Proposal
for
the
Model
Rules
and
Input
from
Commenters
Mechanisms
for
interpollutant
trading
allow
reduced
emissions
of
one
pollutant
to
be
exchanged
for
increased
emissions
of
another
pollutant
where
both
pollutants
cause
the
same
environmental
problem
(
e.
g.,
are
precursors
of
a
third
pollutant).
Interpollutant
trading
mechanisms
are
typically
based
upon
each
precursor's
contribution
to
a
particular
environmental
problem
and
are
often
controversial
and
scientifically
difficult
to
design
because
of
the
complexities
of
environmental
chemistry.
Determination
of
conversion
factors
(
i.
e.,
transfer
ratios
that
relate
the
impact
of
one
pollutant
to
the
impact
of
another
pollutant)

can
be
dependent
upon
location,
the
presence
of
other
pollutants
that
are
necessary
for
chemical
reactions,
the
time
of
emissions,
and
other
considerations.
593
The
January
30,
2004
CAIR
NPR
did
not
propose
a
specific
interpollutant
trading
mechanism
but
rather
took
comment
on
interpollutant
trading
in
general
as
well
as
the
following
specific
issues:

(
1)
What
would
be
the
exchange
rate
(
i.
e.,
the
transfer
ratio)
for
the
two
pollutants
(
2)
How
can
the
transfer
ratio
best
achieve
the
goals
of
PM2.5
and
ozone
reductions
in
downwind
States
and,

(
3)
How
would
the
interpollutant
trading
accommodate
the
different
geographic
regions
of
the
PM2.5
and
ozone
programs?

Comments
Regarding
the
Potential
Interpollutant
Trading
The
EPA
received
several
comments
on
interpollutant
trading
with
the
most
commenters
generally
opposed
to
including
provisions
to
allow
for
the
interchangability
of
SO2
and
NOx
allowances.

Several
commenters
pointed
out
that
the
CAIR
ozone
attainment
benefits
result
from
the
NOx
emissions
reductions,

and
contend
that
the
EPA
has
not
shown
that
SO2
emissions
impact
ozone.
Therefore,
the
commmenters
conclude
that
it
would
be
inappropriate
for
SO2
allowances
to
be
traded
and
used
for
compliance
with
the
NOx
cap.
Some
commenters
supported
the
consideration
or
use
of
interpollutant
trading
if
it
was
one­
directional,
i.
e.,
NOx
allowances
could
be
used
for
compliance
with
the
SO2
allowance
holding
requirements,
594
but
not
vice
versa.
This
could
result
in
fewer
NOx
emissions
and
more
SO2
emissions.

Some
commenters
supported
the
consideration
or
use
of
interpollutant
trading
and
emphasized
the
scientific
difficulty
in
developing
accurate
transfer
ratios.
Of
these
commenters,
some
added
that
interpollutant
trading
would
be
appropriate
if
the
EPA
conducted
a
thorough
analysis
of
the
potential
impacts
that
interpollutant
trading
would
have
on:

nonattainment
areas'
ability
to
come
into
attainment;
the
allowance
markets
and
prices;
and
the
integrity
of
the
NOx
caps
in
light
of
the
potentially
large
SO2
allowance
bank
that
might
be
carried
forward
into
the
CAIR
trading
programs.

A
few
commenters
noted
that
the
EPA
is
directed
by
the
CAA
to
study
interpollutant
trading
and
has
approved
SIPs
that
allow
the
trading
of
ozone
precursors
under
specific
circumstances.

b.
Interpollutant
Trading
and
the
Final
CAIR
Model
Rules
Interpollutant
trading
can
provide
some
additional
compliance
flexibility,
and
potentially
lower
compliance
costs,
if
appropriately
applied
to
multiple
pollutants
that
have
reasonably
well
known
impacts
on
the
same
environmental
problem.
The
EPA
acknowledges
that
it
has
the
authority
to
create
interpollutant
trading
programs
and
has
done
so,
in
other
regulatory
contexts,
in
the
past.
However,
for
several
595
reasons,
the
EPA
determined
that
direct
interpollutant
trading
is
not
appropriate
in
the
CAIR.

The
final
CAIR
includes
separate
annual
SO2
and
annual
NOx
model
rules
to
address
PM2.5
precursor
emissions,
and
an
ozone­
season
NOx
model
rule
to
address
summertime
ozone
precursor
emissions.
The
EPA
believes
it
is
not
appropriate
for
the
CAIR
model
rules
to
allow
annual
SO2
or
NOx
allowances
to
be
used
for
compliance
with
ozone­
season
NOx
allowance
holding
requirements
because
this
has
the
potential
to
adversely
impact
the
ozone­
season
emissions
reductions
and
ozone
air
quality
improvements
from
CAIR.
This
is
significant
because
the
EPA,
as
required
by
the
CAA,
has
promulgated
a
national
air
quality
standard
for
8­
hour
ozone
based
on
a
determination
that
the
standard
is
necessary
to
protect
public
health.
Section
110(
a)
2(
D)
requires
States
to
prohibit
emissions
in
amounts
that
will
significantly
contribute
to
nonattainment
in,
or
interfere
with
maintenance
by,
any
other
State
with
respect
to
any
air
quality
standard,

including
ozone.
In
this
rule,
EPA
has
designed
the
annual
(
SO2
and
NOx)
and
ozone­
season
(
NOx)
emission
caps
to
achieve
the
emissions
reductions
necessary
to
address
each
State's
significant
contribution
to
downwind
PM2.5
and
ozone
nonattainment,
respectively,
and
to
prevent
interference
with
maintenance.
If
sources
were
permitted
to
use
annual
SO2
or
annual
NOx
allowances
for
compliance
with
ozone­
season
NOx
596
allowance
holding
requirements
(
i.
e.,
the
ozone­
season
NOx
cap),
then
there
would
be
no
assurance
that
upwind
States'

ozone­
season
NOx
reduction
obligations
would
be
met,
and
CAIR's
projected
ozone
improvements
in
downwind
nonattainment
areas
could
be
significantly
reduced.
As
a
result,
should
interpollutant
trading
be
permitted
between
the
annual
and
ozone­
season
programs,
the
EPA
could
not
demonstrate
that
the
use
of
a
CAIR
ozone­
season
cap
and
trade
program
would
result
in
the
emissions
reductions
necessary
to
satisfy
upwind
States'
obligations
under
section
110(
a)
2(
D)
to
reduce
NOx
for
ozone
purposes.

The
EPA
believes
it
is
also
inappropriate
to
use
annual
NOx
allowances
for
compliance
with
the
annual
SO2
allowance
holding
requirements,
and
vice
versa.
The
EPA
agrees
with
commenters
that
emphasize
that
the
chemical
interactions
for
PM2.5
precursors
are
scientifically
complex
and
must
be
accurately
reflected
in
any
transfer
ratio
in
order
to
maintain
the
integrity
of
the
market.
For
example,
EPA
analysis
has
shown
(
see
January
30,
2004
NPR)
that
PM2.5
precursors,
such
as
NOx
and
SO2,
may
have
non­
linear
interactions
in
the
formation
of
PM2.5.
Any
uniform,

interpollutant
transfer
ratio
would
have
to
be
an
average
and
would
introduce
significant
variability
concerning
the
impact
of
interpollutant
trading
on
emissions
and
significant
uncertainty
concerning
the
achievement
of
the
CAIR
Program's
597
emission
reduction
goals.
The
EPA
did
not
receive
a
response
to
the
request
in
the
January
30,
2004
NPR
for
information
on
an
appropriate
value
for
a
potential
transfer
ratio.
While
the
EPA
did
receive
one
comment
that
recommended
the
use
of
a
trading
ratio
of
two
NOx
allowances
for
one
SO2
allowance,
no
comments
presented
supporting
analysis
that
could
be
used
to
develop
transfer
ratios.

While
many
commenters
supportive
of
allowing
interpollutant
trading
in
the
CAIR
claimed
that
it
would
provide
additional
compliance
flexibility
to
sources,
the
EPA
contends
that
use
of
the
newly
created
CAIR
trading
markets
is
sufficiently
flexible.
Sources
may
develop
integrated,

multi­
pollutant
control
strategies
and
use
the
separate
allowance
markets
to
mitigate
differences
in
control
costs
(
within
the
boundaries
of
emissions
caps).
In
other
words,
a
source
can
choose
the
level
to
which
they
can
cost
effectively
control
one
pollutant
and,
if
necessary,
buy
or
sell
emission
allowances
of
the
other
pollutant
to
compensate
for
any
expensive
or
inexpensive
control
cost.
When
markets
are
used
to
provide
for
trading
of
multiple
pollutants,

sources
benefit
from
the
additional
compliance
flexibility
while
the
caps
assure
the
achievement
of
the
overarching
environmental
goals.

In
the
June
10,
2004
SNPR,
the
EPA
solicited
comment
on
how
an
interpollutant
trading
mechanism
might
accommodate
the
598
slightly
different
geographic
regions
found
to
be
significant
contributors
for
PM2.5
and
ozone
under
the
CAIR.
No
commenters
provided
supporting
analysis
or
input
on
this
issue.

In
summary,
the
EPA
received
comments
that
generally
opposed
including
a
specific
interpollutant
trading
mechanism.
No
commenters
provided
analysis
to
demonstrate
the
benefit
of
including
a
specific
interpollutant
trading
mechanism
nor
was
there
analysis
provided
in
response
to
the
EPA's
solicitation
in
the
June
10,
2004
SNPR
for
input
on:

transfer
ratios,
addressing
two
different
environmental
issues,
and
having
slightly
different
annual
NOx
and
ozone
season
NOx
control
regions.
Furthermore,
because
the
NOx
and
SO2
markets
provide
very
flexible
mechanisms
for
trading
of
the
two
pollutants,
the
EPA
does
not
believe
there
is
a
compelling
need
to
go
further
at
this
time.
Therefore,
EPA
is
not
finalizing
provisions
in
the
CAIR
model
rules
that
specifically
address
interpollutant
trades.

F.
Are
There
Incentives
for
Early
Reductions?

When
sources
reduce
their
SO2
and
NOx
emissions
during
the
first
phase
of
a
multi­
phase
cap
and
trade
program,
it
creates
the
emissions
"
glide
slope"
of
a
cap
and
trade
approach
that
provides
early
environmental
benefit
and
lowers
the
cost
of
compliance.
Early
reduction
credits
(
ERCs)
can
599
provide
an
incentive
for
sources
to
install
and/
or
operate
controls
before
the
implementation
dates.
Allowing
emission
allowances
from
existing
programs
to
be
used
for
compliance
in
the
new
program
is
another
mechanism
to
encourage
early
reductions
prior
to
the
start
of
a
cap
and
trade
program.

This
section
discusses
the
potential
use
of
mechanisms
to
provide
incentives
for
early
reductions
in
the
CAIR.

1.
Incentives
for
Early
SO2
Reductions
a.
The
CAIR
NPR
and
SNPR
Proposal
for
the
Model
Rules
and
Input
from
Commenters.

The
January
30,
2004
CAIR
NPR
and
June
10,
2004
CAIR
SNPR
acknowledge
the
benefit
of
early
reductions
and
provide
for
the
use
of
title
IV
SO2
allowances
of
vintage
years
2009
and
earlier
to
be
used
for
compliance
in
the
CAIR
at
a
oneto
one
ratio.
In
other
words,
title
IV
allowances
can
be
banked
into
the
CAIR
Program.
This
provides
incentive
for
title
IV
sources
to
reduce
their
emissions
in
years
2009
and
earlier
because
these
allowances
may
be
used
for
CAIR
compliance
without
being
discounted
by
the
retirement
ratios
applied
to
the
2010
and
later
SO2
allowances.
No
other
mechanism,
such
as
SO2
ERCs
were
proposed
by
the
EPA.

Comments
Regarding
the
Incentives
for
Early
SO2
Reductions
The
EPA
received
comments
on
incentives
for
early
SO2
reductions
with
the
majority
supporting
the
EPA
proposal
to
encourage
early
emission
reductions
by
allowing
the
CAIR
600
sources
to
use
2009
and
earlier
vintage
title
IV
SO2
allowances
for
CAIR
compliance.
Some
supporters
noted
concerns
in
meeting
the
CAIR's
stringent
Phase
I
SO2
requirements
as
another
reason
to
allow
the
banking
of
undiscounted
title
IV
allowances
into
the
CAIR.

Some
commenters
expressed
concern
that
achieving
the
SO2
caps
would
be
delayed
if
a
large
number
of
SO2
allowances
were
being
banked
into
the
CAIR.
Based
upon
experience
with
implementing
the
Acid
Rain
Program,
the
EPA
acknowledged
in
the
SNPR
that
crediting
early
reductions
does
create
a
glide
slope
 
where
emissions
are
reduced
below
the
baseline
before
the
implementation
date
and
"
glide"
down
to
the
ultimate
cap
level
sometime
after
the
program
begins.
This
gradual
reduction
in
emissions
is
a
key
component
to
cap
and
trade
programs
having
lower
cost
of
compliance
than
command­

andcontrol
approaches.
One
commenter
proposed
that
the
EPA
needs
to
assess
the
likelihood
that
allowing
the
banking
of
undiscounted
title
IV
allowances
would
delay
the
attainment
of
the
Phase
I
SO2
cap
until
Phase
II.
Because
the
EPA
included
this
mechanism
(
i.
e.,
the
use
of
2009
and
earlier
vintage
SO2
allowances
for
compliance
in
the
CAIR)
in
the
policy
case
modeled
as
part
of
this
rulemaking,
EPA
analysis
includes
the
benefits
and
costs
that
would
result
from
the
level
of
SO2
reductions
that
would
take
place
with
banking
of
undiscounted
title
IV
allowances.
601
One
commenter
advocated
the
use
of
SO2
ERCs.
It
was
not
clear
whether
these
would
be
awarded
in
addition
to
banking
title
IV
allowances
into
the
CAIR
or
the
ERC
mechanism
would
take
the
place
of
banking
SO2
allowances
into
the
CAIR.

b.
SO2
Early
Reduction
Incentives
in
the
Final
CAIR
Model
Rules.

The
CAIR
SO2
model
rule
allows
CAIR
sources
to
use
title
IV
SO2
allowances
of
vintage
2009
and
earlier
for
compliance
with
the
CAIR
at
a
one­
to­
one
ratio.
This
approach
was
part
of
the
CAIR
policy
case
assumptions
used
in
the
rulemaking
modeling
and
the
EPA
has
shown
that
the
SO2
cap
and
trade
program,
with
this
early
incentive
mechanism,
will
achieve
the
level
of
SO2
reductions
needed
to
meet
the
CAIR
goals.

These
reductions
take
place
on
a
glide
slope
that
includes
early
emissions
reductions
as
well
as
some
use
of
the
SO2
allowance
bank
as
sources
gradually
reduce
emissions
toward
the
cap
levels.

The
EPA
did
not
include
SO2
ERCs
because
the
Acid
Rain
Program
cap
and
trade
program,
which
affects
a
large
segment
of
the
CAIR
source
universe,
makes
it
impossible
to
determine
whether
sources
are
reducing
their
SO2
emissions
below
levels
required
by
existing
(
i.
e.,
the
Acid
Rain
Program)
programs.

Furthermore,
given
that
most
sources
with
substantial
emissions
receive
SO2
emission
allowances
under
the
Acid
Rain
Program,
a
significant
number
of
SO2
allowances
are
expected
602
to
be
banked
into
the
CAIR.
These
banked
allowances
would
be
available
to
CAIR
sources
in
the
early
years
of
the
program
and
make
ERCs
largely
unnecessary.

2.
Incentives
for
Early
NOx
Reductions
a.
The
CAIR
NPR
and
SNPR
Proposal
for
the
Model
Rules
and
Input
from
Commenters.

In
the
June
10,
2004
SNPR,
the
EPA
proposed
to
provide
incentives
for
early
NOx
reductions
by
allowing
the
use
of
NOx
SIP
Call
allowances
of
vintage
2009
and
earlier
to
be
used
for
compliance
in
the
CAIR.
Further,
the
EPA
did
not
propose,
but
solicited
comment
on
the
potential
use
of
NOx
ERCs
to
provide
an
additional
incentive
for
sources
to
reduce
NOx
emissions
prior
to
CAIR
implementation.
In
addition
to
the
general
solicitation
for
comment
on
NOx
ERCs,
the
EPA
solicited
input
on
the
following
specific
approaches
that
could
be
utilized:
(
1)
the
EPA
could
maintain
the
NOX
SIP
Call
requirements
and
allow
sources
to
use
ERCs
only
for
compliance
with
the
annual
limitation,
to
ensure
that
ozoneseason
NOX
limitations
are
met.
Under
this
scenario,
the
additional
States
subject
to
the
CAIR
that
have
been
found
to
significantly
contribute
to
ozone
nonattainment
may
also
have
to
be
included
in
the
ozone
season
cap;
(
2)
the
EPA
could
limit
the
period
of
time
during
which
ERCs
could
be
created
and
banked;
(
3)
the
EPA
could
cap
the
amount
of
ERCs
that
can
603
be
created;
and
(
4)
the
EPA
could
apply
a
discount
rate
to
ERCs.

Comments
Regarding
the
Incentives
for
Early
NOx
Reductions
The
EPA
did
not
receive
comment
on
the
proposed
use
of
NOx
SIP
Call
allowances
of
vintage
years
2009
and
earlier
for
compliance
in
the
CAIR.
In
fact,
several
commenters
characterized
the
CAIR
proposal
as
not
including
any
incentives
for
early
NOx
emissions
reductions.

The
EPA
received
several
comments
on
the
potential
use
of
NOx
ERCs
with
the
majority
in
favor
of
some
sort
of
ERC
mechanism.
Several
commenters
advocated
the
use
of
ERCs
to
mitigate
concerns
that
they
would
not
be
able
to
meet
the
stringent
Phase
I
CAIR
reduction
requirements.
One
commenter
wanted
early
reductions
to
facilitate
the
ozone
attainment
in
2010
but
believed
2010
attainment
could
only
be
helped
if
there
were
some
restrictions
on
the
number
of
ERCs
that
could
be
created.

Some
ERC
supporters
wanted
credit
for
wintertime
emissions
reductions
only,
while
a
few
believed
that
credit
should
be
given
for
reductions
at
any
time
of
year.
One
commenter
advocated
providing
ERCs
for
wintertime
reductions
only
as
part
of
a
broader
proposal
to
create
a
bifurcated
NOx
trading
system
(
i.
e.,
separate
wintertime
and
summertime
allowances
and
trading
markets.)
604
Many
of
the
commenters
supporting
the
use
of
ERCs
advocated
that
they
be
distributed
from
a
pool
of
allowances
similar
to
the
CSP
used
in
the
NOx
SIP
Call.
(
The
NOx
SIP
Call
CSP
was
a
fixed
pool
of
NOx
allowances
that
were
distributed
on
a
first
come­
first
serve,
prorated,
or
need
basis,
depending
upon
the
State).
Commenters
noted
that
the
CSP
approach
has
already
been
part
of
a
litigated
rulemaking
and
provides
the
added
benefit
of
limiting
the
total
number
of
allowances
that
can
be
distributed
for
early
reductions.

Other
commenters
proposed
that
should
the
final
approach
use
a
pool
of
allowances,
this
pool
should
not
remove
allowances
from
the
existing
State
NOx
budget.
Another
commenter
suggested
that
allowances
from
a
CSP
could
be
distributed
based
upon
a
NOx
emission
rate,
such
as
0.25
lbs/
mmBtu.

Allowances
could
be
distributed
to
any
source
emitting
below
the
target
emission
rate.

Several
commenters
were
concerned
that
too
many
NOx
ERCs
(
as
well
as
NOx
SIP
Call
allowances)
could
be
introduced
into
the
CAIR
and
the
ability
of
the
NOx
cap
and
trade
program
to
meet
the
annual
and
ozone­
season
reduction
goals
could
be
compromised.
Some
commenters
suggested
that
crediting
early
reductions
at
a
discount
(
e.
g.,
two
tons
of
NOx
reductions
earn
1
ERC)
could
mitigate
this
concern.
Other
commenters
noted
that
a
CSP­
style
mechanism
also
provides
safeguards
against
an
overabundance
of
ERCs.
Another
commmenter
noted
605
that
restrictions
on
the
use
of
ERCs
similar
to
the
progressive
flow
control
(
PFC)
mechanism
used
in
the
NOx
SIP
Call
 
PFC
restricts
the
use
of
banked
NOx
allowances
for
compliance
in
years
where
the
NOx
bank
is
greater
than
10
percent
of
the
allocations
 
could
help
to
ease
concerns
of
flooding
the
market
with
NOx
ERCs.

One
commenter
believed
that
the
EPA's
projection
that
the
potential
pool
of
NOx
ERCs
could
be
as
large
as
3.7
million
tons
(
presented
in
the
June
10,
2004
SNPR)
is
unrealistically
high.
The
commenter
contended
that
technical
limitations
of
Selective
Catalytic
Reduction
(
SCR)

operation
would
not
permit
facilities
to
simply
run
all
of
their
SCRs
year­
round.
More
specifically,
the
commenter
believes
the
lower
operating
loads,
typically
of
the
wintertime
dispatch,
would
not
meet
the
minimum
conditions
necessary
for
SCR
operation
(
i.
e.,
at
lower
capacity
the
stack
gas
temperatures
will
not
support
the
use
of
the
catalyst).
Fewer
wintertime
opportunities
to
operate
the
SCRs
is
believed
by
the
commenter
to
result
in
a
smaller
projected
ERC
estimate.
This
was
an
estimate
used
for
discussion
purposes
and
was
not
directly
used
in
the
development
of
the
CSP.

A
few
commenters
advocated
providing
credits
to
any
source
that
reduced
emission
rates
below
those
used
to
determine
the
CAIR
State
budgets.
One
commenter
suggested
606
that
the
rates
be
based
on
those
rates
used
to
determine
the
NOx
SIP
Call
caps.

A
few
commenters
proposed
that
the
EPA
should
develop
a
strategy
for
crediting
NOx
reductions
from
sources
that
have
implemented
control
measures
in
response
to
State­
level
regulations
that
are
more
stringent
than
the
NOx
SIP
Call.

Another
commenter
advocated
only
providing
ERCs
in
States
subject
to
both
the
NOx
SIP
Call
and
the
CAIR.

Some
commenters
did
not
support
the
use
of
NOx
ERCs
in
any
form.
These
commenters
believe
that
the
use
of
ERCs
would
delay
attainment
of
the
CAIR
emission
caps.

b.
NOx
Early
Reduction
Incentives
in
the
Final
CAIR
Model
Rules.

The
CAIR
ozone­
season
NOx
cap
and
trade
rule
will
allow
the
proposed
use
of
NOx
SIP
Call
allowances
of
vintage
years
2008
and
earlier
for
compliance
in
the
CAIR.
This
mechanism
would
provide
incentive
for
sources
in
NOx
SIP
Call
States
to
reduce
their
ozone­
season
NOx
emissions
and
bank
additional
allowances
into
the
CAIR.
Because
today's
final
ozone­
season
cap
and
trade
rule
includes
a
mandatory
ozone­
season
NOx
cap
in
2009
(
this
modification
is
discussed
in
section
IV),
the
provisions
to
allow
the
banking
of
NOx
SIP
Call
allowances
into
the
CAIR
are
adjusted
to
reflect
this
implementation
date.
607
136
The
200,000
ton
pool
includes
the
1,503
tons
that
would
be
DE
and
NJ's
share.
Section
V
of
today's
action
describes
in
detail
the
State­
by­
State
apportionment
of
the
total
CSP.
The
CAIR
annual
NOx
cap
and
trade
rule
will
provide
additional
incentives
for
early
annual
NOx
reductions
by
creating
a
CSP
for
CAIR
States
from
which
they
can
distribute
allowances
for
early,
surplus
NOx
emissions
reductions
in
the
years
2007
and
2008.
The
earning
of
CAIR
CSP
allowances
for
NOx
emission
reductions
does
not
begin
until
2007
because
this
is
the
first
year
after
the
State
SIP
submittal
deadlines.
The
CAIR
CSP
will
provide
a
total
of
200,000136
CAIR
annual
NOx
allowances
of
vintage
2009
in
addition
to
the
annual
CAIR
NOx
budgets.

The
CAIR's
CSP
is
patterned
after
the
NOx
SIP
Call's
CSP,
which
is
part
of
an
established
and
extensively
litigated
rulemaking.
Similarities
include:
limiting
the
total
number
of
allowances
that
can
be
distributed;
limiting
the
years
in
which
CSP
allowances
can
be
earned;
populating
the
CSP
with
allowances
vintaged
the
first
compliance
year;

and
using
distribution
criteria
of
early
reductions
and
need.

The
EPA
will
apportion
the
CSP
to
the
States
based
upon
their
share
of
the
final,
regionwide
NOx
CAIR
reductions.

Similar
to
the
NOx
SIP
Call,
States
may
distribute
these
CAIR
NOx
allowances
to
sources
based
upon
either:
(
1)
a
demonstration
by
the
source
to
the
State
of
NOx
emissions
608
reductions
in
surplus
of
any
existing
NOx
emission
control
requirements;
or
(
2)
a
demonstration
to
the
State
that
the
facility
has
a
"
need"
that
would
affect
electricity
grid
reliability.
Sources
that
wish
to
receive
CAIR
CSP
allowances
based
upon
a
demonstration
of
surplus
emissions
reductions
will
be
awarded
one
CAIR
annual
NOx
allowance
for
every
ton
of
NOx
emissions
reductions.
(
Should
a
State
receive
more
requests
for
allowances
than
their
share
of
the
CAIR
CSP,
the
State
would
pro­
rate
the
allowance
distribution.)
Determination
of
surplus
emissions
must
use
emissions
data
measured
using
part
75
monitoring.

The
EPA
elected
to
include
the
CSP
in
response
to
several
comments
noting
the
benefit
of
early
NOx
reductions
and
some
commenters
concerns
in
complying
with
the
stringent
Phase
I
CAIR
NOx
cap.
While
EPA
analysis
has
shown
that
sources
had
sufficient
time
to
install
NOx
emission
controls,

the
EPA
does
believe
that
it
would
be
appropriate
to
provide
some
mechanism
to
alleviate
the
concerns
of
some
sources
which
may
have
unique
issues
with
complying
with
the
2009
implementation
deadline.
In
addition
to
mitigating
some
of
the
uncertainty
regarding
the
EPA
projections
of
resources
to
comply
with
CAIR,
the
CAIR
CSP
also
effectively
provides
incentives
for
early,
surplus
NOx
reductions.

The
EPA
agrees
with
the
comments
that
advocate
allowing
sources
to
earn
CAIR
annual
NOx
allowances
only
for
those
609
reductions
that
are
in
surplus
of
the
sources'
existing
NOx
reduction
requirements.
By
allowing
sources
in
NOx
SIP
Call
and
non­
NOx
SIP
Call
States
to
demonstrate
that
their
yearround
early
reductions
are
truly
"
surplus"
and,
therefore,

deserving
of
CSP
allowances,
the
EPA
is
responding
to
comments
that
the
EPA
should
allow
sources
in
non­
NOx
SIP
Call
States
to
receive
credit
for
early
reductions.
Some
commenters
advocated
crediting
sources
in
the
ozone­
season
NOx
cap
and
trade
program
that
emitted
below
the
emission
rate
used
to
determine
the
ozone­
season
budget.
The
EPA
did
not
accept
this
recommendation
because
a
source
that
is
allowed
to
bank
NOx
SIP
Call
allowances
into
the
CAIR
ozoneseason
NOx
program
and
receive
early
reduction
credit
from
CAIR's
CSP
would
be
essentially
"
double­
counting"
that
emission
reduction.

The
EPA
did
not
restrict
the
use
of
the
NOx
allowances
awarded
from
the
CSP
because
several
aspects
of
the
CSP
already
address
concerns
that
too
many
total
credits
would
be
distributed
and
that
they
would
flood
the
markets.
First,

the
CSP
is
a
finite
pool
of
NOx
allowances.
Second,
by
requiring
sources
to
reduce
one
ton
of
NOx
emissions
for
every
NOx
allowance
awarded
from
the
CSP
ensures
that
significant
reductions
are
made
prior
to
the
CAIR
implementation
date.

G.
Are
There
Individual
Unit
"
Opt­
In"
Provisions?
610
In
the
SNPR,
EPA
described
a
potential
approach
for
allowing
certain
units
to
voluntarily
participate
in,
or
"
opt­
in,"
to
the
CAIR.
Originally,
EPA
proposed
to
have
no
opt­
in
provision
but
included
language
in
the
SNPR
on
what
a
potential
opt­
in
provision
may
look
like.
This
"
potential"

opt­
in
provision
would
have
allowed
non­
EGU
boilers
and
turbines
that
exhaust
to
a
stack
or
duct
and
monitor
and
report
in
accordance
with
part
75
to
opt
into
the
CAIR
The
opt­
in
unit
would
have
been
required
to
opt­
in
for
both
SO2
and
NOx.
The
allocation
method
for
opt­
ins
assumed
a
percentage
SO2
reduction
from
a
baseline
and
for
NOx,

allocations
were
equal
to
a
baseline
heat
input
multiplied
by
a
specified
NOx
emissions
rate,
the
same
NOx
emissions
rate
EGUs
were
subject
to
in
the
assumed
EGU
budgets.
Allocations
were
updated
annually
and
after
opting
in
units
would
have
had
to
stay
in
the
CAIR
for
a
minimum
of
5
years.
The
EPA
received
many
comments
in
favor
of
and
very
few
comments
against
including
an
opt­
in
provision
in
the
final
rule.
As
a
result,
EPA
is
including
an
opt­
in
provision
in
this
final
rule
that
is
based
on
the
approach
described
in
the
SNPR
but
includes
several
modifications
and
additions
in
response
to
comments
as
described
below.
In
general,
EPA
believes
there
is
value
to
including
an
opt­
in
provision
but
believes
that
sources
that
opt­
in
should
be
responsible
for
a
certain
level
of
reduction
below
its
baseline
because
of
the
additional
611
flexibility
provided
to
that
source
by
opting
into
a
regional
trading
program
and
because
of
the
possibility
that
participation
in
the
CAIR
may
reduce
or
eliminate
future
potential
required
reductions.
Therefore,
the
following
optin
approach
has
as
its
goals
to
provide
more
flexibility
to
the
units
opting
in
as
well
as
to
potentially
provide
more
cost­
effective
reductions
for
the
affected
EGUs
but
also
to
ensure
a
certain
level
of
reduction
from
the
units
opting
into
the
program.

1.
Applicability
Some
commenters
suggested
that
the
opt­
in
provision
not
be
limited
to
boilers
and
turbines
but
should
be
open
to
any
unit.
The
EPA
strongly
believes
that
any
unit
participating
in
an
emissions
trading
program
be
subject
to
accurate
and
reliable
monitoring
and
reporting
requirements.
This
is
the
purpose
of
part
75.
The
EPA
has
developed
criteria
for
boilers
and
turbines
to
satisfy
the
requirements
of
part
75
but
has
not
developed
criteria
for
all
non­
boilers
and
turbines
and,
therefore,
cannot
be
confident
their
emissions
can
be
monitored
with
the
high
degree
of
accuracy
and
reliability
required
by
a
cap­
and­
trade
program.
Continuous
Emissions
Monitoring
Systems
or
"
CEMS"
are
typically
what
is
required
by
EPA
to
participate
in
a
cap­
and­
trade
program.

In
response
to
comments
received
suggesting
that
non­
boilers
and
turbines
be
allowed
to
opt­
in,
EPA
is
612
expanding
applicability
of
the
opt­
in
provision
to
include,

in
addition
to
boilers
and
turbines,
other
fossil
fuel­
fired
combustion
devices
that
vent
all
emissions
through
a
stack
and
meet
monitoring,
recordkeeping,
and
recording
requirements
of
part
75.

2.
Allowing
Single
Pollutant
Some
commenters
suggested
that
sources
should
be
allowed
to
opt­
in
for
only
one
pollutant
instead
of
requiring
the
source
to
opt­
in
for
both
SO2
and
NOx
as
EPA
proposed.
These
commenters
argued
that
some
sources
may
only
emit
significant
amounts
of
one
of
the
two
regulated
pollutants
and
that
it
would
not
make
sense
to
require
reductions
in
both
pollutants
from
such
a
source.
The
EPA
agrees
with
this
comment
and
will
allow
units
to
opt­
in
for
one
pollutant,
i.
e.,
NOx,
SO2,

or
both.
Another
commenter
suggested
that
EPA
allow
non­
EGUs
subject
to
the
NOx
SIP
Call
to
opt
into
the
CAIR
for
NOx
only
without
requiring
any
reductions
in
SO2.
This
commenter
argued
that
these
non­
EGUs
could
simply
turn
on
their
SCRs
during
the
non­
ozone
season
and
easily
achieve
significant
NOx
reductions.
The
EPA
agrees
that
the
relatively
small
number
of
non­
EGUs
subject
to
the
NOx
SIP
Call
that
have
SCRs
could
achieve
significant
NOx
reductions
by
operating
their
SCRs
during
the
non­
ozone
season.
As
stated
above,
EPA
is
allowing
sources
to
opt­
in
for
one
pollutant
and
thus
non­

EGUs
subject
to
the
NOx
SIP
call
may
opt­
in
for
NOx
only.
613
3.
Allocation
Method
for
Opt­
Ins
In
the
SNPR,
EPA
proposed
allocating
allowances
to
optin
units
on
a
yearly
basis.
The
amount
of
allowances
allocated
would
be
calculated
by
multiplying
an
emission
rate
by
the
lesser
of
a
baseline
heat
input
or
the
actual
heat
input
monitored
at
the
unit
in
the
prior
year.

The
baseline
heat
input
would
be
calculated
by
using
the
most
recent
3
years
of
quality­
assured
part
75
monitoring
data.
When
less
than
3
years
of
quality­
assured
part
75
monitoring
data
is
available,
the
heat
input
would
be
based
on
quality­
assured
part
75
monitoring
data
from
the
year
before
the
unit
opted
in.

For
SO2,
EPA
proposed
that
the
emission
rate
used
to
calculate
allocations
would
be
the
lesser
of,
the
most
stringent
State
or
Federal
SO2
emission
rate
that
applied
in
the
preceding
year
or
the
emission
rate
representing
50
percent
of
the
unit's
baseline
SO2
emission
rate
(
in
lbs/
mmBtu)
for
the
years
2010
through
2014
and
35
percent
of
the
unit's
baseline
SO2
emission
rate
(
in
lbs/
mmBtu)
for
2015
and
beyond.
For
NOx,
EPA
proposed
that
the
emission
rate
would
be
the
lower
of
the
unit's
baseline
emission
rate,
the
most
stringent
State
or
Federal
NOx
emission
limitation
that
applies
to
the
opt­
in
unit
at
any
time
during
the
calender
year
prior
to
opting
into
the
CAIR
Program,
or
0.15
lb/
mmBtu
614
for
the
years
2010
through
2014
and
0.11
lbs/
mmBtu
for
the
years
2015
and
beyond.

In
today's
final
rule,
EPA
is
making
a
number
of
changes
to
its
proposed
methodology
for
calculating
allocations
for
opt­
in
units.

With
regards
to
baseline
heat
input,
EPA
is
requiring
that
sources
may
only
use
part
75
monitored
data
for
years
in
which
they
have
maintained
at
least
a
90
percent
monitor
availability.
The
EPA
is
making
this
change
because
part
75
contains
missing
data
provisions
that
require
substitution
of
data
when
monitors
are
unavailable.
When
units
have
low
monitor
availability,
units
are
required
to
report
more
conservative
(
e.
g.,
higher)
heat
input
values.
This
is
to
provide
an
incentive
to
maintain
high
monitor
availability
(
since
under
a
cap
and
trade
program
sources
would
be
required
to
turn
in
more
allowances
if
they
reported
higher
emissions).
When
setting
baselines,
sources
have
the
opposite
incentive,
reporting
a
higher
heat
input
would
result
in
a
higher
baseline
and
thus
a
greater
allocation.

With
regards
to
the
SO2
emission
rate
used
to
calculate
allocations,
EPA
is
requiring
that
the
emission
rate
used
to
calculate
allocations
would
be
the
lesser
of,
the
most
stringent
State
or
Federal
SO2
emission
rate
that
applies
to
the
unit
in
the
year
that
the
unit
is
being
allocated
for,
or
the
emission
rate
representing
70
percent
of
the
unit's
615
baseline
SO2
emission
rate
(
in
lbs/
mmBtu).
The
EPA
is
changing
the
percentage
emission
reduction
upon
which
allocations
are
based
because
some
commenters
suggested
that
instead
of
using
percentage
emission
reduction
requirements
that
are
the
same
as
the
requirements
for
EGUs
as
a
basis
for
allocating
to
opt­
ins,
EPA
should
require
emissions
reductions
based
on
similar
marginal
cost
of
control.
The
EPA
agrees
with
the
basic
concept
that
emissions
reductions
for
opt­
ins
should
be
based
on
similar
marginal
costs.
One
commenter
submitted
results
from
a
study
of
industrial
boiler
NOx
and
SO2
control
costs
that
indicated
the
use
of
similar
marginal
cost
of
control
would
result
in
approximately
a
30
percent
reduction
in
NOx
and
SO2
by
2010.
While
the
commenter
provided
limited
data
to
allow
EPA
to
evaluate
the
commenter's
estimates,
EPA
is
using
this
percentage
reduction
requirement
for
the
opt­
in
provision.
The
same
commenter
stated
that
it
may
be
possible
to
achieve
more
than
a
30
percent
reduction
in
SO2
and
NOx
by
2015
by
employing
future
unspecified
technology
advances.
Because
these
future
technology
advances
are
not
specified
nor
demonstrated,
EPA
is
not
requiring
more
than
a
30
percent
reduction
in
SO2
and
NOx
in
2015
and
beyond
for
opt­
ins.
The
EPA
is
changing
the
requirement
to
use
the
lowest
required
emission
rate
for
the
year
preceding
the
year
in
which
allowances
are
being
allocated
to
the
lowest
emission
rate
for
the
year
in
which
616
allowances
are
being
allocated.
The
EPA
is
making
this
change
because
EPA
believes
that
such
data
should
be
available
and
that
this
more
accurately
reflects
the
intent
of
the
rule
to
ensure
that
the
source
is
not
being
allocated
a
greater
number
of
allowances
than
the
emissions
a
source
would
be
allowed
to
emit
under
the
regulations
it
is
subject
to
in
the
year
the
allocations
are
being
made.
The
EPA
is
finalizing
parallel
provisions
with
respect
to
NOx.

4.
Alternative
Opt­
In
Approach
Some
commenters
suggested
that
EPA
include
an
alternative
approach
to
opting
into
the
CAIR.
This
alternative
would
allow
units
to
opt­
in
as
early
as
2010
and
receive
allocations
at
their
current
emission
levels
in
return
for
a
commitment
to
make
deeper
reductions
by
2015
than
would
be
required
under
the
general
opt­
in
provision
described
above.
Therefore,
for
the
years
2010
through
2014,

the
unit
would
be
allocated
allowances
based
on
the
same
heat
input
used
under
the
general
opt­
in
provision
(
e.
g.,
the
lesser
of
the
baseline
heat
input
or
the
heat
input
for
the
year
preceding
the
year
in
which
allocations
are
being
made)

multiplied
by
an
emission
rate.
This
emission
rate
would
be
the
lower
of
the
emission
rate
for
the
year
or
years
before
the
unit
opted
in
or
the
the
most
stringent
State
or
Federal
emission
rate
required
in
the
year
that
the
unit
opts
in.

For
SO2
for
the
years
2015
and
beyond,
the
unit
would
be
617
allocated
allowances
based
on
the
same
heat
input
multiplied
by
an
emission
rate.
This
emission
rate
would
be
the
lower
of
a
90
percent
reduction
from
the
baseline
emission
rate
or
the
most
stringent
State
or
Federal
emission
rate
required
in
the
baseline
year.
For
NOx,
the
same
methodology
would
be
used,
except
that
the
emission
rate
used
for
the
years
2015
and
beyond
would
be
the
lower
of
0.15
lbs/
mmBtu
or
the
most
stringent
State
or
Federal
emission
rate
required
in
the
baseline
year.
The
EPA
believes
the
environmental
benefit
of
achieving
deeper
emissions
reductions
in
the
future
(
2015)

from
sources
that
may
otherwise
not
make
such
deep
emissions
reductions
is
worth
including
in
this
final
rule.

5.
Opting
Out
In
the
SNPR,
EPA
proposed
that
opt­
in
units
be
required
to
remain
in
the
program
a
minimum
of
5
years
after
which
time
they
could
voluntarily
withdraw
from
the
CAIR.
Some
commenters
expressed
concern
over
this
proposed
approach,

arguing
that
because
EGUs
affected
by
the
CAIR
are
not
allowed
to
voluntarily
withdraw
from
the
CAIR
that
opt­
in
sources
should
not
be
allowed
to
voluntarily
withdraw
either.

The
EPA
recognizes
that
opt­
in
sources
such
as
industrial
boilers
and
turbines
tend
to
be
more
sensitive
to
changing
market
forces
than
EGUs.
As
a
result,
EPA
believes
it
is
appropriate
to
allow
opt­
in
sources
who
voluntarily
participate
in
an
emissions
reductions
program
to
be
able
to
618
end
their
participation
or
("
opt­
out")
after
a
specified
period
of
time.
As
proposed,
EPA
believes
a
period
of
5
years
is
appropriate
and
is
finalizing
a
rule
to
allow
opt­
in
sources
to
opt­
out
after
participating
in
the
CAIR
for
5
years.
This
option
to
opt­
out
after
5
years
does
not
apply
to
sources
that
opt­
in
under
the
alternative
approach.

Sources
that
opt­
in
under
the
alternative
approach
may
not
opt­
out
at
any
time.

6.
Regulatory
Relief
for
Opt­
in
Units
The
CAIR
does
not
offer
relief
from
other
regulatory
requirements,
existing
or
future,
for
units
that
opt­
in
to
the
CAIR
cap
and
trade
program.
Any
revision
of
requirements
for
other,
non­
CAIR
programs
would
be
done
under
rulemakings
specific
to
those
programs.

As
discussed
above,
EPA
is
including
two
different
approaches
for
opt­
in
units
to
follow,
a
general
and
an
alternative
approach.
The
EPA
is
including
both
approaches
in
this
final
rule
in
response
to
comments
supportive
of
including
an
alternative
means
and
to
provide
greater
flexibility
for
sources
to
participate
in
the
CAIR
trading
program.
Opt­
in
sources
may
select
which
approach
is
more
appropriate
for
their
particular
situation.
An
opt­
in
source
may
not
switch
from
one
approach
to
the
other
once
in
the
program.
States
have
the
flexibility
to
choose
to
include
both
of
these
approaches,
one
of
these
approaches,
or
none
of
619
them
in
their
SIPs.
EPA
is
not
requiring
States
to
include
an
individual
unit
opt­
in
provision
because
the
participation
of
individual
opt­
in
units
is
not
required
to
meet
the
goals
of
the
CAIR.
However,
States
cannot
choose
to
have
an
individual
unit
opt­
in
approach
different
than
what
EPA
has
finalized
in
this
rule
and
still
participate
in
the
inter­

State
trading
program
administered
by
EPA.

H.
What
Are
the
Source­
Level
Emissions
Monitoring
and
Reporting
Requirements?

In
the
NPR,
the
EPA
proposed
that
sources
subject
to
the
CAIR
monitor
and
report
NOx
and
SO2
mass
emissions
in
accordance
with
40
CFR
part
75.

The
model
trading
rules
incorporate
part
75
monitoring
and
are
being
finalized
as
proposed.
The
majority
of
CAIR
sources
are
measuring
and
reporting
SO2
mass
emissions
year
round
under
the
Acid
Rain
Program,
which
requires
part
75
monitoring.
Most
CAIR
sources
are
also
reporting
NOx
mass
emissions
year
round
under
the
NOX
SIP
Call.
The
CAIRaffected
Acid
Rain
sources
that
are
located
in
States
that
are
not
affected
by
the
NOx
SIP
Call
currently
measure
and
report
NOx
emission
rates
year
round,
but
do
not
currently
report
NOx
mass
emissions.
These
sources
will
need
to
modify
only
their
reporting
practices
in
order
to
comply
with
the
proposed
CAIR
monitoring
and
reporting
requirements.
620
Because
so
many
sources
are
already
using
part
75
monitoring,
there
were
very
few
comments
on
the
source­
level
monitoring
requirements
in
this
rulemaking.
The
comments
the
EPA
received
related
to
sources
not
currently
monitoring
under
part
75.
Commenters
suggested
that
alternative
forms
of
monitoring
(
e.
g.,
part
60
monitoring)
would
be
appropriate
for
these
sources.
The
EPA
disagrees.
Consistent,
complete
and
accurate
measurement
of
emissions
ensures
that
each
allowance
actually
represents
one
ton
of
emissions
and
that
one
ton
of
reported
emissions
from
one
source
is
equivalent
to
one
ton
of
reported
emissions
from
another
source.

Similarly,
such
measurement
of
emissions
ensures
that
each
single
allowance
(
or
group
of
SO2
allowances,
depending
upon
the
SO2
allowance
vintage)
represents
one
ton
of
emissions,

regardless
of
the
source
for
which
it
is
measured
and
reported.
This
establishes
the
integrity
of
each
allowance,

which
instills
confidence
in
the
underlying
market
mechanisms
that
are
central
to
providing
sources
with
flexibility
in
achieving
compliance.
Part
75
has
flexibility
relating
to
the
type
of
fuel
and
emission
levels
as
well
as
procedures
for
petitioning
for
alternatives.
The
EPA
believes
this
provides
the
requested
flexibility.

Should
a
State(
s)
elect
to
use
the
example
allocation
approach,
the
EPA
would
modify
the
part
75
monitoring
and
reporting
requirements
to
collect
information
used
in
621
determining
the
allowance
allocations
for
Combined
Heat
and
Power
(
CHP)
units.
More
specifically,
provisions
for
the
monitoring
and
reporting
of
the
BTU
content
of
the
steam
output
would
be
added
to
the
existing
requirements.
The
information
on
electricity
output
currently
reported
under
part
75
would
not
need
to
be
revised
to
allow
States
to
implement
the
example
allowance
allocation
approach.

In
the
SNPR,
the
EPA
proposed
continuous
measurement
of
SO2
and
NOX
emissions
by
all
existing
affected
sources
by
January
1,
2008
using
part
75
certified
monitoring
methodologies.
New
sources
have
separate
deadlines
based
upon
the
date
of
commencement
of
operation,
consistent
with
the
Acid
Rain
Program.
These
deadlines
are
finalized
as
proposed.

I.
What
is
Different
between
CAIR's
Annual
and
Seasonal
NOx
Model
Cap
and
Trade
Rules?

Today's
action
finalizes
not
only
the
proposed
CAIR
annual
NOx
program
and
annual
SO2
program,
but
also
a
CAIR
ozone­
season
NOx
program.
Because
the
CAIR
ozone­
season
NOx
program
is
the
only
ozone­
season
NOx
cap
and
trade
program
that
the
EPA
will
administer,
NOx
SIP
Call
States
wishing
to
meet
their
NOx
SIP
Call
obligations
through
an
EPAadministered
regional
NOx
program
will
also
use
the
CAIR
ozone­
season
rule.
The
EPA
believes
that
States
and
affected
622
sources
will
benefit
from
having
a
single,
consistent
regional
NOx
cap
and
trade
program.
This
section
of
today's
action
highlights
any
key
differences
between
the
CAIR
ozoneseason
NOx
model
rule
and
the
NOx
SIP
Call
model
rule,
as
well
as
the
CAIR
annual
and
ozone­
season
NOx
model
rules.

Differences
Between
the
CAIR
Ozone­
Season
NOx
Model
Rule
and
the
NOx
SIP
Call
Model
Rule
While
the
CAIR
ozone­
season
NOx
model
rule
closely
mirrors
the
NOx
SIP
Call
rule
(
as
does
the
other
CAIR
rules),

the
EPA
has
incorporated
into
the
CAIR
model
rules
its
experience
with
implementing
trading
programs
(
including
seasonal
NOx
programs).
These
modifications
include
the
following.

F.
Unrestricted
banking:
The
CAIR
ozone­
season
NOx
model
rule
will
not
include
any
restrictions
on
the
banking
of
NOx
SIP
Call
allowances
(
vintages
2008
and
earlier)
or
CAIR
ozone­
season
NOx
allowances.
The
NOx
SIP
Call
rules
include
"
progressive
flow
control"
provisions
that
reduce
the
value
of
banked
allowances
in
years
where
the
bank
is
above
a
certain
percentage
of
the
cap.
(
See
section
VIII.
E.
1
of
today's
rule
for
a
detailed
discussion).

G.
Facility
level
compliance:
The
CAIR
ozone­
season
NOx
model
rule
will
allow
sources
to
comply
with
the
allowance
holding
requirements
at
the
facility
level.
623
The
NOx
SIP
Call
rules
required
unit­
by­
unit
level
compliance
with
certain
types
of
allowance
accounts
providing
some
flexibility
for
sources
with
multiple
affected
units.
(
See
the
June
2004
SNPR,
section
IV
for
a
detailed
discussion).

The
EPA
believes
that
these
changes
improve
the
programs
and
that
both
CAIR
and
NOx
SIP
Call
affected
sources
will
benefit
from
complying
with
a
single,
regionwide
cap
and
trade
program.

Differences
Between
the
CAIR
Ozone­
Season
and
Annual
NOx
Model
Rules
The
CAIR
ozone­
season
and
annual
NOx
model
rules
are
designed
to
be
identical
with
the
exception
of
(
1)
provisions
that
relate
to
compliance
period
and
(
2)
the
mechanism
for
providing
incentives
for
early
NOx
reductions.
For
compliance
related
provisions,
the
EPA
attempted
to
maintain
as
much
consistency
as
possible
between
the
CAIR
annual
and
ozone­
season
NOx
model
rules.
For
example,
reporting
schedules
remain
synchronized
(
i.
e.,
quarterly
reporting)
for
both
of
the
CAIR
NOx
model
rules.
For
the
annual
and
ozoneseason
NOx
model
rules,
the
EPA
did
define
12
month
and
5
month
compliance
periods,
respectively.

Incentives
for
early
NOx
reductions
differ
between
the
CAIR
annual
and
ozone­
season
programs.
For
the
annual
NOx
program,
early
reductions
may
be
rewarded
by
States
through
a
624
CSP.
(
See
section
VIII.
F.
2
of
today's
action
for
a
detailed
discussion.)
The
CAIR
ozone­
season
NOx
model
rule
provides
incentive
for
early
emissions
reductions
by
allowing
the
banking
of
pre­
2009
NOx
SIP
Call
allowances
into
the
CAIR
ozone­
season
program.

J.
Are
There
Additional
Changes
to
Proposed
Model
Cap
and
Trade
Rules
Reflected
in
the
Regulatory
Language?

The
proposed
and
final
rules
are
modeled
after,
and
are
largely
the
same
as,
the
NOx
SIP
Call
model
trading
rule.

Today's
final
rule
includes
some
relatively
minor
changes
to
the
model
rules'
regulatory
text
that
improve
the
implementability
of
the
rules
or
clarify
aspects
of
the
rules
identified
by
the
EPA
or
commenters.
(
Note
that
sections
VIII.
B
through
VIII.
H
of
today's
action
highlight
the
more
significant
modifications
included
in
the
final
model
rules).

One
example
of
a
relatively
minor
change
is
the
inclusion
of
language
in
the
SO2
model
rule
that
implements
the
retirement
ratio
(
2.00)
used
for
allowances
allocated
for
2010
to
2014
and
the
retirement
ratio
(
2.86)
used
for
allowances
allocated
for
2015
and
later,
that
clarifies
the
compliance
deduction
process
and
that
provides
for
roundingup
of
fractional
tons
to
whole
tons
of
excess
emissions.

More
specifically,
the
definition
of
"
CAIR
SO2
allowance"

states
that
an
allowance
allocated
for
2010
to
2014
625
authorizes
emissions
of
0.50
tons
of
SO2
and
that
an
allowance
allocated
for
2015
or
later
authorizes
emissions
of
0.35
tons
of
SO2
 
which
corresponds
with
the
2.86
retirement
ratio.

Other,
less
significant
modifications
were
also
included
in
the
regulatory
text
of
the
final
model
rules.
These
include:

H.
Units
and
sources
are
identified
separately
for
NOx
and
SO2
programs
(
e.
g.,
CAIR
NOx
units,
CAIR
Nox
ozone
season
units,
and
CAIR
SO2
units)
since
States
can
participate
in
one,
two,
or
three
trading
programs;

I.
The
definition
of
"
nameplate
capacity"
is
clarified;

J.
The
language
on
closing
of
general
accounts
is
clarified;
and,

K.
Process
of
recordation
of
CAIR
SO2
allowance
allocations
and
transfers
on
rolling
30­
year
periods
is
added
to
make
it
consistent
with
Acid
Rain
regulations.

Another
example
of
where
today's
final
model
trading
rules
incorporate
relatively
minor
changes
from
the
proposed
model
trading
rules
involves
the
provisions
in
the
standard
requirements
concerning
liability
under
the
trading
programs.

The
proposed
CAIR
model
NOX
and
SO2
trading
rules
include,

under
the
standard
requirements
in
§
96.106(
f)(
1)
and
(
2)
and
§
96.206(
f)(
1)
and
(
2),
provisions
stating
that
any
person
who
knowingly
violates
the
CAIR
NOx
or
SO2
trading
programs
or
626
knowingly
makes
a
false
material
statement
under
the
trading
programs
will
be
subject
to
enforcement
action
under
applicable
State
or
Federal
law.
Similar
provisions
are
included
in
§
96.6(
f)(
1)
and
(
2)
of
the
final
NOx
SIP
Call
model
trading
rule.
The
final
CAIR
model
NOx
and
SO2
trading
rules
exclude
these
provisions
for
the
following
reasons.

First,
the
proposed
rule
provisions
are
unnecessary
because,

even
in
their
absence,
applicable
State
or
Federal
law
authorizes
enforcement
actions
and
penalties
in
the
case
of
knowing
violations
or
knowing
submission
of
false
statements.

Moreover,
these
proposed
rule
provisions
are
incomplete.

They
do
not
purport
to
cover,
and
have
no
impact
on,

liability
for
violations
that
are
not
knowingly
committed
or
false
submissions
that
are
not
knowingly
made.
Applicable
State
and
Federal
law
already
authorizes
enforcement
actions
and
penalties,
under
appropriate
circumstances,
for
nonknowing
violations
or
false
submissions.
Because
the
proposed
rule
provisions
are
unnecessary
and
incomplete,
the
final
CAIR
model
NOx
and
SO2
trading
rules
do
not
include
these
provisions.
However,
the
EPA
emphasizes
that,
on
their
face,
the
provisions
that
were
proposed,
but
eliminated
in
the
final
rules,
in
no
way
limit
liability,
or
the
ability
of
the
State
or
the
EPA
to
take
enforcement
action,
to
only
knowing
violations
or
knowing
false
submissions.

IX.
Interactions
with
Other
Clean
Air
Act
Requirements
627
A.
How
Does
this
Rule
Interact
with
the
NOx
SIP
Call?

A
majority
of
States
affected
by
the
CAIR
are
also
affected
by
the
NOx
SIP
Call.
This
section
addresses
the
interactions
between
the
two
programs.

The
EPA
proposed
that
States
achieving
all
of
the
annual
NOx
reductions
required
by
the
CAIR
from
only
EGUs
would
not
need
to
continue
to
impose
seasonal
NOx
limitations
on
EGUs
from
which
they
required
reductions
for
purposes
of
complying
with
the
NOx
SIP
Call.
Also,
EPA
proposed
that
States
would
have
the
option
of
retaining
such
seasonal
NOx
limitations.

The
EPA
also
proposed
to
keep
the
NOx
SIP
Call
in
place
for
non­
EGUs
currently
subject
to
the
NOx
SIP
Call
and
to
continue
working
with
States
to
run
the
NOx
SIP
Call
Budget
Trading
Program
for
all
sources
that
would
remain
in
the
program.
In
response
to
commenters,
EPA
is
making
several
modifications
to
its
proposed
approach.

States
Affected
by
the
CAIR
for
Ozone
and
PM2.5
Will
Be
Subject
to
a
Seasonal
and
an
Annual
NOx
Limitation
A
number
of
commenters
recommended
leaving
the
current
NOx
SIP
Call
ozone
season
NOx
limitation
in
place
as
a
way
to
ensure
that
ozone
season
NOx
reductions
from
EGUs
required
by
the
NOx
SIP
Call
would
continue
to
be
achieved.
Some
commenters
argued
this
would
also
help
non­
EGUs
currently
subject
to
the
NOx
SIP
Call
by
allowing
them
to
continue
trading
with
EGUs
in
a
seasonal
NOx
program.
Many
of
the
628
same
commenters
suggested
a
dual­
season
or
bifurcated
CAIR
trading
program
as
a
mechanism
for
maintaining
an
ozone
season
NOx
limitation
for
EGUs
under
the
CAIR.
In
response
to
these
commenters,
EPA
is
requiring
that
States
subject
to
the
CAIR
for
PM2.5
be
subject
to
an
annual
limitation
and
that
States
subject
to
the
CAIR
for
ozone
be
subject
to
an
ozone
season
limitation.
This
means
that
States
subject
to
the
CAIR
for
both
PM2.5
and
ozone
are
subject
to
both
an
annual
and
an
ozone
season
NOx
limitation.
The
annual
and
ozone
season
NOx
limitations
are
described
in
section
IV.

States
subject
to
the
CAIR
for
ozone
only
are
only
subject
to
an
ozone
season
NOx
limitation.
To
implement
these
NOx
limitations,
EPA
will
establish
and
operate
two
NOx
trading
programs,
i.
e.,
a
CAIR
annual
NOx
trading
program
and
a
CAIR
ozone
season
NOx
trading
program.
The
CAIR
ozone
season
NOx
trading
program
will
replace
the
current
NOx
SIP
Call
as
discussed
in
more
detail
later
in
this
section.

What
Will
Happen
to
Non­
EGUs
Currently
in
the
NOx
SIP
Call?

A
number
of
commenters
were
concerned
that
the
cost
of
compliance
for
non­
EGUs
in
the
NOx
SIP
Call
would
increase
if
they
were
not
allowed
to
continue
to
trade
with
EGUs.
In
response
to
these
commenters,
EPA
is
modifying
its
proposed
approach.
The
EPA
is
allowing
States
affected
by
the
NOx
SIP
Call
that
wish
to
use
EPA's
model
trading
rule
to
include
629
non­
EGUs
currently
covered
by
the
NOx
SIP
Call
in
the
CAIR
ozone
season
NOx
trading
program.
This
will
ensure
that
non­

EGUs
in
the
NOx
SIP
Call
will
continue
to
be
able
to
trade
with
EGUs
as
they
currently
do
under
the
NOx
SIP
Call.
This
will
not
require
States
to
get
additional
reductions
from
non­
EGUs.
Budgets
for
these
units
would
remain
the
same
as
they
are
currently
under
the
NOx
SIP
Call.
States
will,

however,
be
required
to
modify
their
existing
NOx
SIP
Call
regulations
to
reflect
the
replacement
of
the
NOx
SIP
Call
with
the
CAIR
ozone
season
NOx
trading
program.
The
EPA
will
continue
to
operate
the
NOx
SIP
Call
trading
program
until
implementation
of
the
CAIR
begins
in
2009.
The
EPA
will
no
longer
operate
the
NOx
SIP
Call
trading
program
after
the
2008
ozone
season
and
the
CAIR
ozone
season
NOx
trading
program
will
replace
the
NOx
SIP
Call
trading
program.
If
States
affected
by
the
NOx
SIP
Call
do
not
wish
to
use
EPA's
CAIR
ozone
season
NOx
trading
program
to
achieve
reductions
from
non­
EGU
boilers
and
turbines
required
by
the
NOx
SIP
Call,
they
would
be
required
to
submit
a
SIP
Revision
deleting
the
requirements
related
to
non­
EGU
participation
in
the
NOx
SIP
Call
Budget
Trading
Program
and
replacing
them
with
new
requirements
that
achieve
the
same
level
of
reduction.
630
Compliance
with
the
NOx
SIP
Call
for
States
that
Are
Subject
to
Both
the
CAIR
Ozone
Season
NOx
Reduction
Requirements
and
the
NOx
SIP
Call
If
the
only
changes
a
State
makes
with
respect
to
its
NOx
SIP
Call
regulations
are:
1)
to
bring
non­
EGUs
that
are
currently
participating
in
the
NOx
SIP
Call
Budget
Trading
Program
into
the
CAIR
ozone
season
program
using
the
same
non­
EGU
budget
and
applicability
requirements
that
are
in
their
existing
NOx
SIP
Call
Budget
Trading
Program;
and
2)
to
achieve
all
of
the
emissions
reductions
required
under
the
CAIR
from
EGUs
by
participating
in
the
CAIR
ozone
season
NOx
trading
program,
EPA
will
find
that
the
State
continues
to
meet
the
requirements
of
the
NOx
SIP
Call.

If
the
only
changes
a
State
makes
with
respect
to
its
NOx
SIP
Call
regulations
are
not
those
described
above,
see
section
VII
for
a
discussion
of
how
the
State
would
satisfy
its
NOx
SIP
Call
obligations.

States
in
the
NOx
SIP
Call
but
not
Affected
by
the
CAIR
(
Rhode
Island)

Rhode
Island
is
the
only
State
in
the
NOx
SIP
Call
that
is
not
affected
by
the
CAIR.
To
continue
meeting
its
NOx
SIP
Call
obligations
in
2009
and
beyond,
Rhode
Island
will
have
two
choices.
It
may
either
modify
its
NOx
SIP
Call
trading
rule
to
conform
to
the
new
CAIR
ozone
season
NOx
trading
rule
if
it
wishes
to
allow
its
sources
to
continue
to
participate
631
in
an
interstate
NOx
trading
program
run
by
EPA
or,
it
will
need
to
develop
an
alternative
method
for
obtaining
the
required
NOx
SIP
Call
reductions.
In
either
case,
Rhode
Island
must
continue
to
meet
the
budget
requirements
of
the
existing
NOx
SIP
Call.

Use
of
Banked
SIP
Call
Allowances
in
the
CAIR
Program
As
explained
earlier
in
today's
final
rule,
banked
allowances
from
the
NOx
SIP
Call
may
be
used
in
the
CAIR
ozone
season
NOx
trading
program.

Other
Comments
and
EPA's
Responses
One
commenter
wrote
that
because
attainment
demonstrations
for
early
action
compacts
were
made
based
on
having
EGUs
and
non­
EGUs
together
in
the
NOx
SIP
Call,
EPA
could
not
allow
EGUs
to
leave
the
NOx
SIP
Call
and
still
have
valid
early
action
compacts
(
EACs).
As
discussed
above,
EPA
is
allowing
States
to
keep
EGUs
and
non­
EGUs
in
the
NOx
SIP
Call
together
in
one
ozone
season
program
(
CAIR
ozone
season
trading
program).
The
NOx
reductions
required
by
the
CAIR
ozone
season
trading
program
are
slightly
more
stringent
than
the
reductions
required
by
the
NOx
SIP
Call.
As
a
result,

the
attainment
demonstrations
for
EACs
would
remain
valid
under
the
CAIR.
Having
said
that,
the
EAC
program
will
have
ended
(
April
2008)
before
the
CAIR
rule
is
implemented.

Thus,
the
compacts
will
no
longer
be
applicable
when
the
CAIR
takes
effect.
632
Another
commenter
proposed
to
have
non­
EGUs
under
the
NOx
SIP
Call
subject
to
an
annual
NOx
cap
similar
to
EGUs
under
the
CAIR
so
that
non­
EGUs
could
continue
to
trade
with
EGUs.
By
adopting
a
CAIR
ozone
season
trading
program
that
includes
non­
EGUs
covered
by
the
NOx
SIP
Call,
non­
EGUs
will
be
able
to
continue
to
trade
with
EGUs.

B.
How
Does
this
Rule
Interact
with
the
Acid
Rain
Program?

As
EPA
developed
this
regulatory
action,
much
consideration
was
given
to
interactions
between
the
existing
title
IV
Acid
Rain
Program
and
today's
action
designed
to
achieve
significant
reductions
in
SO2
emissions
beyond
title
IV.
Requiring
sources
to
reduce
emissions
beyond
what
title
IV
mandates
has
both
environmental
and
economic
implications
for
the
existing
title
IV
SO2
cap
and
trade
program.
In
the
absence
of
an
approach
for
taking
account
of
the
title
IV
program,
a
new
program
(
i.
e.,
the
CAIR)
that
imposes
a
significantly
tighter
cap
on
SO2
emissions
for
a
region
encompassing
most
of
the
sources
and
most
of
the
SO2
emissions
covered
by
title
IV
would
likely
result
in
a
significant
excess
in
the
supply
of
title
IV
allowances,
a
collapse
of
the
price
of
title
IV
allowances,
disruption
of
operation
of
the
title
IV
allowance
market
and
the
title
IV
SO2
cap
and
trade
system,
and
the
potential
for
increased
SO2
emissions.
The
potential
for
increased
emissions
would
exist
in
the
entire
country
for
the
years
before
the
CAIR
633
implementation
deadline
and
would
continue
after
implementation
for
States
not
covered
by
the
CAIR.
These
negative
impacts,
particularly
those
on
the
operation
of
the
title
IV
cap
and
trade
system,
would
undermine
the
efficacy
of
the
title
IV
program
and
could
erode
confidence
in
cap
and
trade
programs
in
general.

Title
IV
has
successfully
reduced
emissions
of
SO2
using
the
cap
and
trade
approach,
eliminating
millions
of
tons
of
SO2
from
the
environment
and
encouraging
billions
of
dollars
of
investments
by
companies
in
pollution
controls
to
enable
the
sale
of
allowances
reflecting
excess
emissions
reductions
and
in
allowance
purchases
for
compliance.
In
view
of
these
already
achieved
reductions
and
existing
investments
under
title
IV,
the
likelihood
of
disruption
of
the
allowance
market
and
the
title
IV
cap
and
trade
system,
and
the
potential
for
SO2
emission
increases,
it
is
necessary
to
consider
ways
to
preserve
the
environmental
benefits
achieved
under
title
IV
and
maintain
the
integrity
of
the
market
for
title
IV
allowances
and
the
title
IV
cap
and
trade
system.

The
EPA
maintains
that
it
is
appropriate
to
provide
States
the
opportunity
to
achieve
the
SO2
emission
reductions
required
under
today's
action
by
building
on,
and
avoiding
undermining,
this
existing,
successful
program.

The
EPA
has
developed,
in
the
model
SO2
cap
and
trade
rule,
an
approach
to
build
on
and
coordinate
with
the
title
634
IV
SO2
program
to
ensure
that
the
required
reductions
under
today's
action
are
achieved
while
preserving
the
efficacy
of
the
title
IV
program.
The
EPA's
approach
provides
States
the
opportunity
to
impose
more
stringent
control
requirements
for
EGUs'
SO2
emissions
than
under
title
IV
through
an
EPAadministered
cap
and
trade
program
that
requires
the
use
of
title
IV
allowances
for
compliance
at
a
ratio
of
2
allowances
per
ton
of
emissions
for
allowances
allocated
for
2010
through
2014
and
2.86
allowances
per
ton
of
emissions
for
allowances
allocated
for
2015
or
thereafter.
(
The
program
also
allows
the
use
of
banked
title
IV
allowances
allocated
for
years
before
2010
to
be
used
at
a
ratio
of
1
allowance
per
ton
of
emissions.)
Title
IV
allowances
continue
to
be
freely
transferable
among
sources
covered
by
the
Acid
Rain
Program
and
sources
covered
by
the
model
SO2
cap
and
trade
program
under
CAIR.
However,
each
title
IV
allowance
used
to
comply
with
a
source's
allowance­
holding
requirement
in
the
CAIR
model
SO2
cap
and
trade
program
is
removed
from
the
source's
allowance
tracking
system
account
and
cannot
be
used
again
for
compliance,
either
in
the
CAIR
model
SO2
cap
and
trade
program
or
the
Acid
Rain
Program.

In
addition,
as
discussed
above,
if
a
State
wants
to
achieve
the
SO2
emissions
reductions
required
by
today's
action
through
more
stringent
EGU
emission
limitations
only
but
without
using
the
model
cap
and
trade
program,
then
EPA
635
is
requiring
that
the
State
include
in
its
SIP
a
mechanism
for
retiring
the
excess
title
IV
allowances
that
will
result
from
imposition
of
these
more
stringent
EGU
requirements.
In
this
case,
the
State
must
retire
an
amount
of
title
IV
allowances
equal
to
the
total
amount
of
title
IV
allowances
allocated
to
the
units
in
the
State
minus
the
amount
of
title
IV
allowances
equivalent
to
the
tonnage
cap
set
by
the
State
on
SO2
emissions
by
EGUs,
and
the
State
can
choose
what
retirement
mechanism
to
use.

Further,
as
discussed
above,
if
a
State
wants
to
meet
the
SO2
emissions
reductions
requirement
in
today's
action
through
reductions
by
both
EGUs
and
non­
EGUs,
then
EPA
is
also
requiring
the
State's
SIP
to
include
a
mechanism
for
retiring
excess
title
IV
allowances.
In
that
case,
the
amount
of
title
IV
allowances
that
must
be
retired
equals
the
total
amount
of
title
IV
allowances
allocated
to
the
units
in
the
State
minus
the
amount
of
title
IV
allowances
equivalent
to
the
tonnage
cap
set
by
the
State
on
EGU
SO2
emissions,
and
the
State
can
choose
what
retirement
mechanism
to
use.

Finally,
as
discussed
above,
if
the
State
wants
to
achieve
the
SO2
emissions
reductions
requirement
in
today's
action
through
reductions
by
non­
EGUs
only,
then
EPA
is
not
imposing
any
requirement
to
retire
title
IV
allowances.

1.
Legal
Authority
for
Using
Title
IV
Allowances
in
CAIR
Model
SO2
Cap
and
Trade
Program.
636
The
EPA
maintains
that
it
has
the
authority
to
approve
and
administer,
if
requested
by
a
State
in
the
SIP
submitted
in
response
to
today's
action,
the
new
CAIR
model
SO2
cap
and
trade
program
meeting
the
SO2
emission
reduction
requirement
in
today's
action
that
requires
use
of
title
IV
allowances
to
comply
with
the
more
stringent
allowance­
holding
requirement
of
the
new
program
and
retirement
under
the
CAIR
SO2
cap
and
trade
program
and
the
Acid
Rain
Program
of
title
IV
allowances
used
for
such
compliance.
Some
commenters
claim
that
EPA's
establishment
of
such
a
cap
and
trade
program
using
title
IV
allowances
that
sources
must
hold
generally
at
a
ratio
of
greater
than
one
allowance
per
ton
of
SO2
emissions
is
contrary
to
title
IV.
Most
of
these
commenters
prefer
the
approach
of
allowing
States
to
use
a
new
EPAadministered
cap
and
trade
program
to
meet
lawful
emission
reduction
requirements
under
title
I
and
of
allowing
(
but
not
requiring)
sources
to
use
title
IV
allowances
in
the
new
program.
However,
these
commenters
argue
that
title
IV
prohibits
requiring
sources
to
use
title
IV
allowances
in
such
a
program,
whether
at
the
same
tonnage
authorization
(
i.
e.,
one
allowance
per
ton
of
emissions)
established
in
title
IV
or
at
a
different
tonnage
authorization.
Other
commenters
state
that
title
IV
does
not
bar
EPA
from
establishing
a
new
cap
and
trade
program
that
requires
the
use
of
title
IV
allowances.
637
The
EPA
maintains
that
it
has
the
authority
under
section
110(
a)(
2)(
D)
and
title
IV
to
establish
a
new
cap
and
trade
program
requiring
the
use
of
title
IV
allowances
at
a
different
tonnage
authorization
than
under
the
Acid
Rain
Program
and
the
retirement
of
such
allowances
for
purposes
of
both
programs.
First,
as
discussed
in
section
V
above,
EPA
has
the
authority
under
section
110(
a)(
2)(
D)
to
establish
a
new
SO2
cap
and
trade
program,
administered
by
EPA
if
requested
in
a
State's
SIP,
to
prohibit
emissions
that
contribute
significantly
to
nonattainment,
or
interfere
with
maintenance,
of
the
PM
2.5
NAAQS.
Further,
EPA
notes
that
under
section
402(
3),
a
title
IV
allowance
is:

an
authorization,
allocated
to
an
affected
unit
by
the
Administrator
under
this
title
[
IV],
to
emit,
during
or
after
a
specified
calendar
year,
one
ton
of
sulfur
dioxide.
42
U.
S.
C.
7651(
a)(
3).

However,
section
403(
f)
states
that:

An
allowance
allocated
under
this
title
is
a
limited
authorization
to
emit
sulfur
dioxide
in
accordance
with
the
provision
of
this
title
[
IV].
Such
allowance
does
not
constitute
a
property
right.
Nothing
in
this
title
[
IV]
or
in
any
other
provision
of
law
shall
be
construed
to
limit
the
authority
of
the
United
States
to
terminate
or
limit
such
authorization.
Nothing
in
this
section
relating
to
allowances
shall
be
construed
as
affecting
the
application
of,
or
compliance
with,
any
other
provision
of
this
Act
to
an
affected
unit
or
source,
including
the
provisions
related
to
applicable
National
Ambient
Air
Quality
Standards
and
State
implementation
plans.
42
U.
S.
C.
7651b(
f).
638
1
The
EPA's
interpretation
is
based
on
the
language
of
section
403(
f)
and
the
legislative
history
of
the
provision.
The
language
in
CAA
section
403(
f)
contrasts
with
language
that
was
in
section
503(
f)
of
the
House
bill
­­
but
was
excluded
from
the
final
version
of
the
Clean
Air
Act
Amendments
of
1990
­­
referring
to
the
authority
of
the
"
United
States"
to
terminate
or
limit
such
authorization
"
by
Act
of
Congress"
and
stating
that
"[
a]
llowances
under
this
title
may
not
be
extinguished
by
the
Administrator."
U.
S.
Senate
Committee
on
Environment
and
Public
Works,
A
Legislative
History
of
The
Clean
Air
Act
Amendments
of
1990
(
Legis.
Hist.
of
CAAA),
S.
Prt.
38,
103d
Cong.,
1st
Sess.,
Vol.
II
at
2224
(
Nov.
1993).
Further,
unlike
CAA
section
403(
f),
the
House
bill
did
not
state
that
an
allowance
did
not
constitute
a
property
right.
Section
403(
f)
of
the
Senate
bill
that
was
considered,
along
with
the
House
bill,
in
conference
committee
had
language
different
than
both
CAA
section
403(
f)
and
the
House
bill
and
stated
that
"
allowances
may
be
limited,
revoked
or
otherwise
modified
in
accordance
with
the
provisions
of
this
title
or
other
authority
of
the
Administrator"
and
that
an
allowance
"
does
not
constitute
a
property
right."
Legis.
Hist.
of
CAAA,
Vol.
III
at
4598.
While
the
scope
of
the
reference
to
the
"
United
States"
in
CAA
section
403(
f)
is
not
clear,
EPA
maintains
that
the
term
is
clearly
broad
enough
to
include
the
Administrator.
Moreover,
even
if
the
term
were
considered
ambiguous
with
regard
to
the
Administrator,
EPA
believes
that
interpreting
the
term
to
include
the
Administrator
is
reasonable.
Specifically,
EPA
maintains
that,
by
eliminating
the
explicit
House
bill
language
that
required
Congressional
action
and
including
the
general
reference
to
the
"
United
States"
and
the
"
not
a
property
right"
language,
CAA
section
403(
f)
essentially
adopted
the
Senate's
approach
and
allows
the
United
States
­­
either
through
Congressional
or
administrative
(
i.
e.,
EPA)
action
­
­
to
terminate
or
limit
the
allowance
authorization.
See
Legis.
Hist.
of
CAAA,
Vol.
I
at
754,
1034,
and
1084
(
Oct.
EPA
interprets
the
reference
in
section
403(
f)
to
the
authority
of
the
"
United
States"
to
terminate
or
limit
the
authorization
otherwise
provided
by
a
title
IV
allowance
to
mean
that
EPA
(
acting
in
accordance
with
its
authority
under
other
provisions
of
the
CAA),
as
well
as
Congress,
has
such
authority.
137
Therefore,
EPA
maintains
that
it
has
the
639
27,
2000
floor
statements
of
Sen.
Symms,
Sen.
Baucus,
and
Sen.
McClure
indicating
EPA
has
authority
to
take
such
action);
but
see
Cong.
Rec.
at
E
3672
(
Nov.
1,
2000)(
extension
of
remarks
of
Cong.
Oxley
indicating
that
only
Congress
has
such
authority).
authority
to
establish
a
new
cap
and
trade
program
in
accordance
with
section
110(
a)(
2)(
D)
that
requires:
the
holding
of
title
IV
allowances
under
a
more
limited
authorization
(
i.
e.,
2
or
2.86
allowances
per
ton
of
emissions)
by
sources
in
States
participating
in
the
new
program;
and
the
termination
of
the
authorization
through
retirement
under
the
new
program
and
the
Acid
Rain
Program
of
those
title
IV
allowances
used
to
meet
the
allowance­
holding
requirement
of
the
new
program.

Commenters'
arguments
based
on
title
IV
The
commenters
claiming
that
EPA
is
barred
by
title
IV
from
requiring
use
of
title
IV
allowances
at
a
reduced
tonnage
authorization
in
a
new
cap
and
trade
program
rely
on
the
above­
noted
provision
in
section
402(
3)
stating
that
an
allowance
is
an
authorization
to
emit
one
ton
of
SO2.

However,
this
provision
does
not
bar
EPA
from
requiring
either:
use
of
title
IV
allowances
in
a
new
cap
and
trade
program
under
a
different
title
of
the
CAA
at
a
reduced
tonnage
authorization;
or
retirement
in
this
new
program
and
the
Acid
Rain
Program
of
allowances
used
in
this
manner.

At
the
outset,
it
should
be
noted
that
the
CAIR
model
SO2
cap
and
trade
program
does
not
change
the
tonnage
640
2
As
discussed
below,
today's
action
revises
the
Acid
Rain
Program
regulations
to
provide
for
source­
based,
instead
of
unit­
based,
compliance
with
the
allowance­
holding
requirement.
These
revisions
are
adopted
for
reasons
independent
of
the
adoption
of
the
CAIR
model
SO2
cap
and
trade
program,
as
well
as
to
facilitate
the
coordination
of
these
two
SO2
trading
programs.
authorization
of
individual
title
IV
allowances
for
purposes
of
the
Acid
Rain
Program
until
such
an
allowance
is
used
to
meet
the
allowance­
holding
requirement
of
the
CAIR
SO2
program.
The
authorization
provided
by
each
title
IV
allowance
for
a
source
to
emit
one
ton
of
SO2
emissions,
as
well
as
the
requirement
that
each
source
hold
title
IV
allowances
covering
annual
SO2
emissions,
continue
to
be
in
effect
in
the
Acid
Rain
Program
whether
or
not
the
source
is
also
covered
by
the
CAIR
SO2
program.
In
fact,
the
Acid
Rain
Program
regulations
continue
to
reflect
both
this
tonnage
authorization
and
this
allowance­
holding
requirement.
138
See
final
revisions
to
40
CFR
§
73.35
adopted
in
today's
action.

Moreover,
the
CAIR
model
SO2
cap
and
trade
rule
coordinates
the
determinations
­­
made
by
EPA
for
sources
subject
to
both
title
IV
and
the
CAIR
­­
of
compliance
with
the
title
IV
and
CAIR
allowance­
holding
requirements
so
that
such
determinations
are
made
in
a
multi­
step,
end­
of­
year
process
of
comparing
allowances
held
and
emissions.
First,
EPA
determines
whether
the
source
holds
sufficient
title
IV
allowances
to
comply
with
the
one­
allowance­
per­
ton­
of­
641
3
The
commenters'
assertion
that
the
sources
in
a
State
that
does
not
participate
in
the
CAIR
SO2
cap
and
trade
program
will
be
cut
off
from
the
Acid
Rain
cap
and
trade
program
is
incorrect
on
its
face.
Such
a
source
will
continue
to
be
subject
to
the
allowance­
holding
requirement
and
the
compliance
process
in
§
73.35
and
will
not
be
subject
to
the
allowance­
holding
requirement
and
the
compliance
process
in
the
CAIR
model
SO2
cap
and
trade
rule.
emissions
requirement
in
the
Acid
Rain
Program
as
provided
in
§
73.35;
and
subsequently
EPA
determines
whether
the
source
holds
the
additional
title
IV
allowances
that,
when
added
to
those
held
for
Acid
Rain
Program
compliance,
are
sufficient
to
meet
the
CAIR
allowance­
holding
requirement.
Violations
of
the
Acid
Rain
allowance­
holding
requirement
will
result
in
imposition
of
the
penalty
for
excess
emissions
(
i.
e.,
the
one­
allowance
offset
plus
$
2,000
(
inflation­
adjusted)
per
ton
of
excess
emissions)
under
CAA
section
411
and
§
§
73.35(
d)
and
77.4.
See
final
§
96.254(
b)(
1)
adopted
in
today's
action.

Thus,
the
Acid
Rain
allowance­
holding
requirement
continues
as
a
separate
requirement
and
reflects
the
one­
allowance­

perton
of­
emissions
authorization
under
section
402(
3).
139
In
contrast
with
the
one­
allowance­
per­
ton­
of­
emissions
requirement
under
the
Acid
Rain
Program,
the
CAIR
SO2
cap
and
trade
program
requires
each
source
generally
to
hold
2
or
2.86
Acid
Rain
allowances
for
each
ton
of
SO2
emissions.

Contrary
to
the
commenters'
claim,
this
CAIR
allowanceholding
requirement
is
not
barred
by
the
definition
of
the
term
"
allowance"
in
section
402(
3).
While
section
402(
3)
642
4
The
commenters
also
seem
to
argue
that
the
allowance
definition
itself
bars
EPA
from
requiring
use
of
Acid
Rain
allowances
in
the
CAIR
SO2
trading
program
even
on
a
oneallowance
per­
ton­
of­
emissions
basis.
However,
as
noted
above,
the
definition
is
silent
on
whether
title
IV
allowances
may
or
may
not
be
used
outside
the
Acid
Rain
Program.
defines
the
term
"
allowance"
as
an
authorization
to
emit
one
ton
of
SO2,
this
provision
expressly
applies
the
definition
to
the
term
"[
a]
s
used
in
this
title
[
IV]"
and
therefore
does
not
apply
to
the
treatment
of
title
IV
allowances
in
a
different
program
under
a
different
title
of
the
CAA.

Moreover,
as
noted
above,
section
403(
f)
allows
EPA
to
limit
(
or
terminate)
the
authorization
to
emit
that
an
allowance
otherwise
provides
under
section
402(
3).
Consequently,
the
allowance
definition
in
section
402(
3)
does
not
bar
the
treatment
of
a
title
IV
allowance
as
authorizing
less
than
one
ton
of
SO2
emissions
under
the
CAIR
SO2
cap
and
trade
program
established
under
title
I.
140
Once
a
title
IV
allowance
is
used
to
meet
the
more
stringent
allowance­
holding
requirement
in
the
CAIR
SO2
program,
that
allowance
is
deducted
from
the
source's
allowance
tracking
system
account
and
cannot
be
used
again,

either
in
the
CAIR
SO2
program
or
the
Acid
Rain
Program.
As
noted
above,
EPA
has
the
authority
under
section
403(
f)
to
require
this
termination
of
such
a
title
IV
allowance's
tonnage
authorization
for
purposes
of
the
Acid
Rain
Program.
643
In
addition
to
referencing
section
402(
3)
to
support
claims
that
EPA
is
barred
from
adopting
the
CAIR
model
cap
and
trade
program
provisions
on
the
use
of
title
IV
allowances,
the
commenters
rely
on
other
title
IV
provisions
that
they
characterize
as
setting
a
"
title
IV
cap"
on
SO2
emissions.
Stating
that
the
requirement
to
use
title
IV
allowances
in
the
CAIR
model
SO2
cap
and
trade
program
has
the
effect
of
reducing
the
"
title
IV
cap,"
these
commenters
indicate,
with
little
explanation,
that
such
requirement
is
unlawful.
In
mentioning
the
title
IV
cap,
the
commenters
are
apparently
referring
to
the
fact
that
section
403(
a)(
1)

(
requiring
allowance
allocations
resulting
in
emissions
not
exceeding
8.90
million
tons
of
SO2)
and
section
405(
a)(
3)

(
requiring
additional
allocations
of
50,000
allowances)

require
EPA
to
allocate
annually,
starting
in
2010,
a
total
amount
of
allowances
authorizing
no
more
than
8.95
million
tons
of
SO2
emissions.
The
commenters'
argument
about
how
the
CAIR
model
SO2
cap
and
trade
program
effectively
reduces
the
"
title
IV
cap"
appears
to
be
that
elimination
of
the
ability
to
use,
in
the
Acid
Rain
Program,
title
IV
allowances
that
will
be
used
for
compliance
in
the
CAIR
model
SO2
cap
and
trade
program
has
the
effect
of
reducing
the
annual
8.95
million
ton
cap
on
SO2
emissions.
This
effective
reduction
of
the
"
title
IV
cap"
seems
to
occur
when
title
IV
allowances
are
used
in
the
CAIR
SO2
trading
program
with
a
reduced
644
5
Similarly,
to
the
extent
title
IV
allowances
are
used
in
the
CAIR
SO2
trading
program
by
non­
Acid
Rain
sources,
the
"
title
IV
cap"
seems
to
be
effectively
reduced
because
more
allowances
are
used
in
the
CAIR
SO2
trading
program
and
effectively
removed
from
use
in
the
Acid
Rain
Program.
6
In
light
of
this
provision,
the
statement
in
the
NPR
(
particularly
as
it
is
interpreted
by
the
commenters)
that
EPA
lacks
authority
to
tighten
the
requirements
of
title
IV
(
69
FR
4618,
col.
1)
is
overly
broad
and
is
not
repeated
or
adopted
in
today's
preamble.
tonnage
authorization
so
that
more
title
IV
allowances
are
deducted
per
ton
of
emissions
than
would
be
deducted
for
compliance
with
the
Acid
Rain
Program.
141
The
commenters
claim
that
such
a
reduction
in
the
8.95
million
ton
cap
is
contrary
to
title
IV.

In
asserting
an
overarching
principle
that
EPA
is
barred
from
adopting
any
requirement
that
would
have
the
effect
of
reducing
the
8.95
million
ton
cap
under
title
IV,
the
commenters
do
not
point
to
any
specific
statutory
provision
in
support.
The
EPA
maintains
that
not
only
are
there
no
such
supporting
provisions,
but
also
certain
title
IV
provisions
contradict
this
purported
principle.

Specifically,
while
sections
403
and
405
require
annual
allowance
allocations
authorizing
no
more
than
8.95
million
tons
of
emissions,
section
403(
f)
provides,
as
noted
above,

that
EPA
may
terminate
or
limit
the
one­
allowance­
per­
ton­

ofemissions
authorization
for
a
title
IV
allowance.
142
Because
any
termination
or
limitation
of
the
tonnage
authorization
provided
by
a
title
IV
allowance
for
purposes
of
the
Acid
645
Rain
Program
would
have
the
effect
of
reducing
the
total
tonnage
of
emissions
allowed
by
the
allowance
allocations
(
i.
e.,
the
8.95
million
ton
cap)
under
sections
403
and
405,

the
commenters'
claim
that
EPA
is
barred
from
adopting
any
provision
that
has
such
an
effect
is
wrong
on
its
face.

Commenters'
argument
based
on
Clean
Air
Markets
Group
case
The
commenters
also
state
that
the
CAIR
model
SO2
cap
and
trade
program
is
unlawful
under
the
court's
holding
in
Clean
Air
Markets
Group
v.
Pataki,
338
F.
3d
82
(
2d
Cir.

2003).
According
to
the
commenters,
the
required
use
of
title
IV
allowances
in
the
CAIR
SO2
program
constitutes
an
unlawful
interference
with
the
operation
of
the
interstate
title
IV
SO2
trading
program,
presumably
similar
to
the
unlawful
interference
found
by
the
court
in
Clean
Air
Markets
Group.
However,
the
commenters
provide
little
explanation
of
how
such
use
of
title
IV
allowances
(
with
or
without
a
reduced
tonnage
authorization)
purportedly
interferes
with
interstate
operation
of
the
Acid
Rain
Program
and
how
the
holding
in
Clean
Air
Markets
Group
applies
to
the
CAIR
SO2
program.

In
Clean
Air
Markets
Group,
the
Court
reviewed
a
State
law
that
imposed
a
monetary
assessment
on
any
title
IV
allowance
sold
by
a
New
York
utility
to
a
utility
in
any
of
14
specified
States
or
subsequently
transferred
to
such
a
646
utility,
with
the
assessment
equaling
the
proceeds
received
in
the
allowance
sale.
The
law
also
required
that
each
allowance
sold
include
a
covenant
barring
subsequent
transfer
of
the
allowance
to
a
utility
in
any
of
those
States.
The
Court
held
that
the
State
law
was
pre­
empted
by
title
IV
because
the
State
law
impermissibly
interfered
with
the
method
chosen
by
Congress
in
title
IV
to
reduce
utilities'

SO2
emissions,
i.
e.,
the
opportunity
for
nationwide
trading
of
title
IV
allowances.
Id.
at
87­
88.
In
particular,
the
Court
found
that
the
assessment
of
100
percent
of
sale
proceeds
"
effectively
bans"
sales
of
any
allowance
by
New
York
utilities
to
utilities
in
the
specified
States
and
that
the
restrictive
covenant
"
indisputedly
decreases"
the
value
of
the
allowances.
Id.
at
88.

The
EPA
maintains
that
today's
action
is
distinguishable
from
the
facts
and
holding
in
Clean
Air
Markets
Group.
In
particular,
EPA
believes
that
the
exercise
of
its
explicit
authority
under
section
403(
f)
to
limit
the
tonnage
authorization
of
a
title
IV
allowance
in
the
CAIR
SO2
cap
and
trade
program
and
to
terminate
the
tonnage
authorization
in
the
Acid
Rain
Program
once
the
allowance
is
used
in
the
CAIR
SO2
program
is
consistent
with
­­
and
necessary
to
preserve
­

­
the
operation
of
the
Acid
Rain
Program.
Therefore,
EPA
concludes
that
its
approach
of
limiting
and
terminating
of
the
tonnage
authorization
of
title
IV
allowances
does
not
647
impermissibly
interfere
with
the
interstate
operation
of
the
Acid
Rain
Program
and
is
reasonable.

Unlike
the
circumstances
in
Clean
Air
Markets
Group,

under
EPA's
approach
in
today's
action,
each
title
IV
allowance
is
freely
transferable
nationwide
unless
and
until
a
source
uses
the
allowance
to
meet
the
allowance­
holding
requirements
of
the
CAIR
SO2
program,
at
which
time
the
allowance
is
deducted
from
the
source's
allowance
tracking
system
account
and
retired
for
purposes
of
both
the
CAIR
SO2
program
and
the
Acid
Rain
Program.
Further,
EPA
expects
that
the
ability
to
use
title
IV
allowances
to
meet
the
more
stringent
emission
limitation
under
the
CAIR
SO2
program
to
maintain
or
increase
(
not
decrease)
the
value
of
each
title
IV
allowance,
until
the
allowance
is
used
to
meet
the
CAIR
SO2
program
allowance­
holding
requirement
and
is
retired.

Of
course,
this
retirement
of
title
IV
allowances
once
they
are
used
to
meet
the
CAIR
allowance­
holding
requirement
means
that
they
cannot
thereafter
be
transferred
to
any
person
or
be
used
again,
e.
g.,
to
meet
the
Acid
Rain
Program
allowance­
holding
requirement.
As
noted
by
the
Court
in
Clean
Air
Markets
Group,
section
403(
b)
provides
that
title
IV
allowances
"
may
be
transferred
among
designated
representatives
of
owners
or
operators
of
affected
sources
under
[
title
IV]
and
any
other
person
who
holds
such
allowances,
as
provided
by
the
allowance
system
regulations"
648
7
While
section
403(
b)(
as
well
as
section
403(
d))
refer
specifically
to
the
allowance
system
regulations
required
to
be
promulgated
by
the
EPA
Administrator
within
18
months
of
November
15,
1990
(
the
enactment
date
of
the
CAA),
the
EPA
Administrator
has
authority
under
section
301
to
amend
such
regulations
"
as
necessary
to
carry
out
his
functions
under
[
the
CAA]."
42
U.
S.
C.
7601.
promulgated
by
EPA.
143
42
U.
S.
C.
7651b(
b).
Moreover,
section
403(
d)(
1)
requires
that
the
allowance
system
regulations
"
specify
all
necessary
procedures
and
requirements
for
an
orderly
and
competitive
functioning
of
the
allowance
system."

42
U.
S.
C.
7651b(
d).
In
the
context
of
these
statutory
requirements,
EPA
maintains
that,
on
balance,
the
retirement
of
title
IV
allowances
used
for
compliance
in
the
CAIR
model
SO2
cap
and
trade
program
does
not
constitute
impermissible
interference
with
the
interstate
operation
of
the
Acid
Rain
Program,
but
rather
is
consistent
with,
and
necessary
to
preserve,
the
operation
of
the
Acid
Rain
Program.

As
noted
above,
the
imposition
of
an
SO2
emission
limitation
(
such
as
in
today's
action)
that
is
significantly
more
stringent
than
the
one
under
title
IV
and
covers
most
of
the
sources
and
emissions
covered
by
title
IV
­
 
but
without
addressing
the
impact
on
the
Acid
Rain
Program
­­
would
likely
have
several
adverse
consequences.
These
adverse
consequences
would
be:
a
significant
excess
of
title
IV
allowances;
a
collapse
of
the
price
of
title
IV
allowances;

disruption
of
the
title
IV
allowance
market
and
the
title
IV
SO2
cap
and
trade
system;
and
potential
SO2
emission
649
increases,
particularly
in
States
outside
the
CAIR
SO2
region.
The
EPA
modeling
indicates
that,
in
2010,
EGU
SO2
emissions
in
States
not
affected
by
the
CAIR
SO2
program
would
increase
by
about
260,000
tons
(
or
about
29
percent
of
the
approximately
0.9
million
tons
of
SO2
emissions
projected
for
the
non­
CAIR
SO2
region
in
2010)
in
the
absence
of
an
approach
for
addressing
the
impact
of
the
CAIR
SO2
program
on
title
IV.
This
is
because,
with
the
imposition
of
the
more
stringent
CAIR
SO2
emission
limitation
in
the
CAIR
SO2
region,

this
more
stringent
limitation
becomes
the
binding
limitation
for
sources
in
that
region.
These
CAIR
SO2
sources
must
comply
with,
and
cannot
use
title
IV
allowances
to
exceed,

the
CAIR
SO2
emission
limitation.
Consequently,
the
portion
of
the
title
IV
allowances
that
equals
the
difference
between
the
CAIR
and
the
title
IV
emission
limitations
is
excess
and
would
be
available
for
use
only
by
Acid
Rain
sources
that
are
outside
the
CAIR
SO2
region.

This
excess
amount
of
title
IV
allowances
is
potentially
very
significant.
Today's
action
requires
that
the
States
in
the
CAIR
SO2
region
achieve
an
amount
of
SO2
emission
reductions
in
2010
and
2015
equal
to
50
percent
and
65
percent,
respectively,
of
the
amount
of
title
IV
allowances
(
about
7.3
million
allowances
out
of
the
total
nationwide
allocation
of
8.95
million
allowances)
allocated
to
the
units
in
the
CAIR
SO2
region.
If
the
States
achieve
all
the
650
8
The
surpluses
for
2010
and
2015
respectively
are
calculated
as:
7.3
million
allowances
minus
((
100
percent
minus
the
percentage
reduction
requirement
for
the
year)
times
7.3
million
allowances).

9
The
4.8
million
ton
figure
is
the
sum
of:
3.65
million
tons
of
emissions
(
equal
to
the
tonnage
equivalent
of
the
allowance
allocations
in
the
CAIR
SO2
region);
plus
about
0.9
million
tons
of
emissions
in
the
non­
CAIR
SO2
region
required
CAIR
SO2
reductions
through
emission
reductions
by
EGUs
(
which
are
largely
the
same
units
that
are
subject
to
the
Acid
Rain
Program)
and
if
EGUs
held
only
one
title
IV
allowance
for
each
ton
of
SO2
emissions
as
required
in
the
Acid
Rain
Program,
the
amount
of
surplus
allowances
allocated
to
the
States
in
the
CAIR
SO2
region
would
be
about
3.65
million
allowances
and
4.75
million
allowances,
respectively
in
2010
and
2015.144
Moreover,
the
vast
majority
of
EGUs
nationwide
(
about
90
percent)
and
of
EGU
SO2
emissions
nationwide
(
about
90
percent)
are
covered
by
the
CAIR
SO2
program.
The
net
result
would
be
a
large
surplus
of
title
IV
allowances
that
would
not
be
usable
in
the
CAIR
SO2
region
and
would
be
usable
only
by
the
small
subset
of
EGUs
(
about
10
percent)
located
in
non­
CAIR
SO2
region
States.
Looking
at
the
nation
as
a
whole
(
both
CAIR
and
non­
CAIR
SO2
States)

in
2010,
there
would
be
total
allocations
in
the
Acid
Rain
Program
of
8.95
million
title
IV
allowances
but,
according
to
EPA
modeling
and
analysis
of
the
CAIR
without
a
requirement
to
retire
surplus
title
IV
allowances,
total
projected
SO2
emissions
for
EGUs
of
only
about
4.8
million
tons.
145
Based
651
with
the
retirement
of
surplus
title
IV
allowances;
plus
260,000
tons
of
increased
non­
CAIR
SO2
region
emissions
if
the
surplus
title
IV
allowances
are
not
retired.
on
the
principles
of
supply
and
demand,
EPA
concludes
that,

with
the
amount
of
allowances
allocated
nation
wide
exceeding
SO2
emissions
for
EGUs
nationwide
in
2010
by
about
86
percent
(
i.
e.,
8.95
million
allowances
minus
4.8
million
tons
divided
by
4.8
million
tons),
the
value
of
title
IV
allowances
would
fall
to
zero,
and
all
but
260,000
of
the
surplus
allowances
would
have
no
market
and
so,
as
a
practical
matter,
would
not
be
transferable.

The
EPA
notes
that
this
effect
on
allowances
would
occur
no
matter
how
the
State
implements
the
more
stringent
SO2
emission
limitation
required
under
the
CAIR,
e.
g.,
whether
implementation
is
through
a
new
cap
and
trade
program
(
like
in
the
model
rule)
or
through
a
fixed
(
command
and
control)

tonnage
emission
limit
imposed
on
each
individual
source.

Consequently,
the
alternatives
faced
by
EPA
are
either:
(
1)

to
establish
a
CAIR
model
cap
and
trade
program
(
or
allow
States
to
use
another
means
of
achieving
CAIR
SO2
emissions
reductions)
that
does
not
retire
the
3.65
million
surplus
allowances
and
that
results
in
the
devaluation
of
all
title
IV
allowances
to
zero
and
the
effective
non­
transferability
of
all
but
260,000
of
the
3.65
million
surplus
allowances
in
2010;
or,
as
provided
in
today's
action,
(
2)
to
adopt
a
CAIR
SO2
model
cap
and
trade
program
(
or
another
means
of
achieving
652
reductions)
that
retires
the
3.65
million
surplus
allowances
and
that
results
in
the
non­
transferability
of
the
entire
3.65
million
surplus
of
title
IV
allowances
and
ensures
the
remaining,
unused
title
IV
allowances
have
market
value.

Thus,
with
regard
to
the
impact
on
the
transferability
of
title
IV
allowances,
EPA's
decision
to
adopt
the
second
alternative
of
retiring
the
surplus
allowances
adversely
affects
the
transferability
of
only
a
relatively
small
amount
(
260,000
out
of
8.95
million
per
year)
of
allowances,
as
compared
to
the
amount
of
allowances
whose
transferability
would
be
adversely
affected
under
the
first
alternative.

Moreover,
with
the
total
collapse
of
the
title
IV
allowance
price
in
the
Acid
Rain
Program,
the
nationwide
cap
and
trade
system
under
title
IV
­­
which
would
be
the
binding
cap
and
trade
system
only
for
sources
in
the
States
outside
the
CAIR
SO2
region
­­
would
lose
all
efficacy.
The
title
IV
cap
and
trade
system
operates
by:
making
owners
of
sources
pay
for
the
authorization
to
emit
SO2
by
surrendering,
to
EPA,
allowances
that
have
a
market
value;
and
by
allowing
owners
(
e.
g.,
those
who
choose
to
reduce
emissions)
to
sell
unused
allowances.
Whether
the
sources'
allowances
were
originally
allocated
to
the
sources
or
were
purchased,
the
owners
must
decide
the
extent
to
which
it
is
more
efficient
to
give
up
the
market
value
of
such
allowances
or
to
reduce
emissions.
If
title
IV
allowances
were
to
have
no
market
653
10
See
Sen.
Rep.
No.
101­
228,
101st
Cong.,
1st
Sess.
at
324
(
Dec.
20,
1989)(
stating
that
"[
a]
llowances
are
intended
to
function
like
a
currency
that
is
sufficiently
valuable
to
stimulate
efforts
to
acquire
it
through
innovative
and
aggressive
efforts
to
reduce
emissions
more
than
required"
and
that,
in
the
event
of
"
inflation
in
the
currency,"
the
incentives
to
"
reduce
pollution...
will
be
seriously
weakened."
In
the
instant
case,
without
a
requirement
to
retire
excess
title
IV
allowances,
the
currency
would
be
inflated
to
a
value
of
zero.
See
also
Legis.
Hist.
of
CAAA,
Vol.
I
at
1033
(
Oct.
27,
1990
floor
statement
of
Sen.
Baucus
explaining
that
"[
s]
ince
units
can
gain
cash
revenues
from
the
sale
of
allowances
they
do
not
use,
they
will
have
a
financial
incentive
both
to
make
greater­
than­
required
reductions
and/
or
reductions
earlier
than
required"
and
that
"
incentives
created
by
the
allowance
market
should
stimulate
innovations
in
the
technologies
and
strategies
used
to
reduce
emissions"
including
energy
efficiency).
value,
the
title
IV
cap
and
trade
system
would
no
longer
affect
the
choice
of
whether
to
emit
or
to
reduce
emissions.
146
The
EPA
maintains
that
such
a
result
is
contrary
to
Congressional
intent.
The
purposes
of
title
IV
include
not
only
reductions
of
annual
SO2
emissions
from
1980
levels,
but
also
the
encouragement
of
"
energy
conservation,
use
of
renewable
and
clean
alternative
technologies,
and
pollution
prevention
as
a
long­
range
strategy,
consistent
with
the
provisions
of
this
title,
for
reducing
air
pollution
and
other
adverse
impacts
of
energy
production
and
use."
42
U.
S.
C.
7651(
b).
Reflecting
these
purposes,
Congress
required
EPA
to
promulgate
allowance
system
regulations
for
the
Acid
Rain
Program
that
would
promote
"
an
orderly
and
competitive
functioning
of
the
allowance
system."
42
U.
S.
C.
7651b(
d)(
1).
654
11
While
the
title
IV
cap
and
trade
system
could
be
replaced
by
a
new
CAIR
SO2
cap
and
trade
system
that
did
not
address
the
problems
caused
by
surplus
title
IV
allowance,
that
new
cap
and
trade
system
would
not
be
nationwide
like
the
title
IV
cap
and
trade
system
and
so
would
not
cover
sources
outside
the
CAIR
SO2
region.
See
Sen.
Rep.
No.
101­
228,
101st
Cong.,
1st
Sess.
at
320
(
explaining
that
"
the
allowance
system
is
intended
to
maximize
the
economic
efficiency
of
the
program
both
to
minimize
costs
and
to
create
incentives
for
aggressive
and
innovative
efforts
to
control
pollution").
As
discussed
above,
if
title
IV
allowances
were
to
have
no
market
value,

the
cap
and
trade
system
under
title
IV
would
no
longer
affect
owners'
decisions
on
whether
to
emit
or
to
control
emissions
and
so
would
no
longer
provide
encouragement
(
e.
g.,

incentives
for
innovation)
for
avoidance
or
reduction
of
SO2
emissions.
147
In
addition,
EPA
is
concerned
that
such
disruption
of
the
title
IV
allowance
market
and
the
title
IV
SO2
cap
and
trade
system
would
significantly
erode
confidence
in
cap
and
trade
programs
in
general
and
the
CAIR
model
cap
and
trade
programs
in
particular.
As
noted
above,
under
the
Acid
Rain
Program,
companies
have
made
billions
of
dollars
of
investments
in
emission
controls
in
order
to
be
able
to
sell
excess
title
IV
allowances
and
in
purchasing
title
IV
allowances
for
future
compliance
(
e.
g.,
under
annual,
1­
day
allowance
auctions
held
by
EPA,
one
as
recently
as
March
22,
655
12
The
EPA
notes
that
the
potential
for
increased
emissions
within
the
CAIR
SO2
region
would
occur
before
the
implementation
of
the
CAIR
SO2
program
and
is
addressed
by
2004
when
title
IV
allowances
were
purchased
for
about
$
50
million).
While
in
a
market­
based
program
like
the
Acid
Rain
Program,
investments
are
necessarily
subject
to
the
vagaries
of
the
market,
EPA
believes
that
it
should
try,
to
the
extent
possible
consistent
with
statutory
requirements,
to
avoid
taking
administrative
actions
that
would
cause
such
extensive
disruption
of
the
Acid
Rain
Program.
Allowing
such
disruption
to
occur
could
significantly
reduce
the
willingness
of
owners
of
sources
in
new
cap
and
trade
programs
to
invest
in
measures
that
would
result
in
excess
allowances
for
sale
or
to
purchase
allowances
for
compliance.

To
the
extent
owners
would
ignore
the
allowance­
trading
option
and
simply
control
emissions
to
the
level
equal
to
their
source's
allocations,
this
would
obviate
the
incentives
for
innovation,
and
hamper
realization
of
the
potential
for
cost
savings,
that
would
otherwise
be
provided
by
new
cap
and
trade
programs
(
such
as
the
CAIR
model
cap
and
trade
programs).

Finally,
as
noted
above,
such
disruption
of
the
Acid
Rain
Program
would
potentially
result
in
significantly
increased
SO2
emissions
(
about
29
percent
in
2010)
in
States
covered
by
the
Acid
Rain
Program
but
outside
the
CAIR
SO2
region.
148
This
would
have
the
effect
of
reversing,
at
least
656
allowing
pre­
2010
banked
title
IV
allowances
to
be
used
to
meet
the
CAIR
allowance
holding
requirement
beginning
in
2010.
13
While
the
potential
for
increased
emissions
outside
the
CAIR
SO2
region
supports
EPA's
conclusion,
EPA
maintains
that,
even
in
the
absence
of
any
such
increase,
the
other
considerations
discussed
above
are
sufficient
to
justify
the
conclusion
that
the
retirement
of
title
IV
allowances
does
not
impermissibly
interfere
with
the
Acid
Rain
Program
and
is
reasonable.
in
part,
the
beneficial
effect
that
the
Acid
Rain
Program
has
had
on
SO2
emissions
in
those
States,
even
though
the
overall
goal
of
nationwide
SO2
emissions
reductions
would
still
be
met.
See
42
U.
S.
C.(
a)(
1)
(
Congressional
finding
that
"
the
presence
of
acidic
compounds
and
their
precursors
in
the
atmosphere
and
in
deposition
from
the
atmosphere
represents
a
threat
to
natural
resources,
ecosystems,
materials,

visibility,
and
public
health").

In
light
of
these
considerations,
149
EPA
concludes,
on
balance,
that
structuring
the
CAIR
model
SO2
cap
and
trade
program
in
a
way
that
avoids
such
extensive
disruption
of
the
Acid
Rain
Program
(
i.
e.,
by
requiring
retirement
from
the
Acid
Rain
Program
of
title
IV
allowances
used
for
compliance
in
the
CAIR
SO2
program)
does
not
constitute
impermissible
interference
with
the
interstate
operation
of
the
Acid
Rain
Program.
Rather,
this
approach
in
the
model
SO2
cap
and
trade
rule
is
consistent
with,
and
preserves,
such
operation
­­
while
providing
States
a
tool
for
imposing
the
more
stringent
SO2
emission
limitations
required
under
title
I
­­
657
and
is
a
reasonable
exercise
of
EPA's
authority
under
section
403(
f)
to
terminate
or
limit
the
tonnage
authorization
of
title
IV
allowances.

2.
Legal
Authority
for
Requiring
Retirement
of
Excess
Title
IV
Allowances
if
State
Does
Not
Use
CAIR
Model
SO2
cap
and
trade
Program.

As
discussed
above,
a
State
has
the
additional
options
of
achieving
the
SO2
emissions
reductions
required
by
today's
actions
through:
EGU
emission
reductions
only
but
without
using
the
model
SO2
cap
and
trade
rule;
some
EGU
and
some
non­
EGU
emissions
reductions;
or
non­
EGU
reductions
only.

The
requirement
to
retire
excess
title
IV
allowances
applies
only
in
the
first
and
second
of
these
three
additional
options.
The
State
must
retire
an
amount
of
title
IV
allowances
equal
to
the
total
amount
of
title
IV
allowances
allocated
to
units
in
the
State
minus
the
amount
of
allowances
equivalent
to
the
tonnage
cap
set
by
the
State
on
EGUs'
SO2
emissions
and
can
choose
what
mechanism
to
use
to
achieve
such
retirement.
The
EPA
has
the
authority
to
require
that
the
State
include
in
its
SIP
a
mechanism
for
retiring
the
excess
title
IV
allowances
that
will
result
under
these
two
options.

As
discussed
above,
EPA
has
the
authority
under
section
403(
f)
to
terminate
or
limit
the
authorization
to
emit
otherwise
provided
by
a
title
IV
allowance.
Specifically,
658
EPA
has
the
authority
to:
require
that
any
EGU
SO2
emission
reduction
program,
chosen
by
a
State
to
meet
(
in
full
or
in
part)
the
requirements
of
section
110(
a)(
2)(
D),
include
provisions
for
retiring
excess
title
IV
allowances
resulting
from
the
implementation
of
the
more
stringent
emission
reduction
requirement
under
the
State
program;
and
to
require
that
such
retired
title
IV
allowances
cannot
be
used
in
the
Acid
Rain
Program.
As
discussed
above,
the
commenters'

claims
that
such
a
retirement
requirement
is
barred
by
title
IV
(
relying
on,
e.
g.,
the
section
402(
3)
definition
of
"
allowance"
and
on
the
"
title
IV
cap")
lack
merit.
Also,
for
the
reasons
discussed
above,
the
retirement
requirement
is
not
unlawful
under
Clean
Air
Markets
Group
and
is
a
reasonable
exercise
of
EPA's
authority
under
section
403(
f)

to
terminate
or
limit
the
tonnage
authorization
of
title
IV
allowances.

Some
commenters
also
claim
that
the
retirement
requirement
unlawfully
constrains
the
States'
authority
to
determine
in
the
first
instance
the
control
measures
to
use
in
meeting
emission
reduction
requirements
necessary
to
comply
with
section
110(
a)(
2)(
D).
According
to
the
commenters,
since
only
EGUs
are
subject
to
title
IV,
the
requirement
to
retire
title
IV
allowances
is
in
effect
a
mandate
that
the
State
control
EGU
emissions.
659
However,
EPA
is
imposing
the
requirement
for
a
State
mechanism
to
retire
title
IV
allowances
only
if
the
State
decides
in
the
first
instance
to
require
any
EGU
SO2
emissions
reductions
to
meet
the
emission
reduction
requirements
under
today's
action.
A
State
that
decides
not
to
require
any
EGU
SO2
emissions
reductions
for
this
purpose
is
not
required
to
retire
title
IV
allowances.
Further,
the
amount
of
the
required
allowance
retirement
is
limited
to
the
amount
of
EGU
SO2
emissions
reductions
that
the
State
decides
in
the
first
instance
to
require
from
EGUs
(
i.
e.,
the
total
title
IV
allowance
allocations
in
the
State
minus
the
tonnage
amount
of
the
cap
set
by
the
State
for
EGUs'
SO2
emissions).
In
short,
the
allowance
retirement
requirement
echoes
the
State's
decision
in
the
first
instance
concerning
the
amount
of
SO2
emissions
reductions
to
require
from
EGUs
in
the
State.
The
EPA
simply
requires
the
State
to
implement
the
State's
EGU­
SO2­
emission­
reduction­
requirement
decision
in
a
manner
that
avoids
the
otherwise
likely,
extreme
disruption
of
the
title
IV
SO2
cap
and
trade
system
that
is
described
above.
Further,
the
State
may
choose
what
mechanism
to
include
in
its
SIP
revision
for
achieving
the
required
allowance
retirement,
and
EPA
will
review
the
effectiveness
of
the
mechanism
in
achieving
such
retirement,
and
approve
and
adopt
the
mechanism
if
appropriate,
in
an
EPA
rulemaking
concerning
the
SIP
revision.
Therefore,
EPA
concludes
that
660
the
allowance­
retirement
requirement
is
lawful
and
is
a
reasonable
condition
for
EPA
approval
of
those
State
SIPs
that
require
EGU
SO2
emission
reductions
without
using
the
CAIR
model
SO2
trading
program.

The
EPA
notes
that
the
requirement
to
retire
excess
title
IV
allowances
­­
where
a
State
adopts
the
CAIR
model
SO2
trading
program
or
where
a
State
SIP
obtains
EGU
emissions
reductions
through
some
other
means
­­
is
reflected
in
provisions
in
both
the
proposed
rules
in
the
SNPR
(
i.
e.,

in
proposed
§
§
51.124(
p)
and
96.254(
b))
and
in
the
final
rules
adopted
by
today's
action
(
i.
e.,
in
final
§
§
51.124(
p)
and
96.254(
b)).
In
reviewing
the
proposed
rules
in
light
of
the
comments
received,
EPA
has
concluded
that,
for
consistency
and
clarity,
the
Acid
Rain
Program
regulations
should
also
reference
this
same
retirement
requirement.
Consequently,

today's
action
adds
a
new
paragraph
(
a)(
3)
to
§
73.35
of
the
Acid
Rain
Program
regulations
that
reiterates
the
requirement
­­
addressed
in
the
preamble
and
regulations
in
both
the
SNPR
and
today's
action
­­
that
title
IV
allowances
previously
used
to
meet
the
allowance­
holding
requirement
in
the
CAIR
model
trading
program
in
§
96.254(
b)
or
otherwise
retired
in
accordance
with
§
51.124(
p)
cannot
be
used
to
meet
the
allowance­
holding
requirement
in
the
Acid
Rain
Program.

Additional
revisions
of
the
Acid
Rain
Program
regulations
are
discussed
below.
661
3.
Revisions
to
Acid
Rain
Regulations.

In
the
SNPR,
EPA
proposed
to
revise
the
Acid
Rain
Program
regulations,
effective
July
1,
2005,
to
implement
the
allowance­
holding
requirement
on
a
source­
by­
source,
rather
than
on
a
unit­
by­
unit,
basis.
Instead
of
requiring
each
unit
to
hold
an
amount
of
allowances
in
its
Allowance
Tracking
System
account
(
as
of
the
allowance
transfer
deadline)
at
least
equal
to
the
tonnage
of
SO2
emissions
for
the
unit
in
the
preceding
calendar
year,
the
proposal
required
each
source
to
hold
an
amount
of
allowances
in
its
Allowance
Tracking
System
account
at
least
equal
to
the
tonnage
of
SO2
emissions
for
all
affected
units
at
the
source
for
such
calendar
year.
Because
language
reflecting
or
referencing
the
unit­
by­
unit
compliance
approach
is
included
in
many
provisions
of
the
Acid
Rain
Program
regulations,
a
significant
number
of
proposed
rule
revisions
were
necessary
to
implement
source­
by­
source
allowance
holding.

In
today's
final
rule,
EPA
is
adopting,
with
minor
modifications,
the
proposed
rule
revisions
implementing
source­
by­
source
compliance
with
the
allowance­
holding
requirement.
As
explained
in
detail
in
the
SNPR
(
69
FR
32698­
32701),
EPA
finds
that:
title
IV
is
ambiguous
with
regard
to
whether
unit­
by­
unit
compliance
is
required
and
so
EPA
has
discretion
in
this
matter;
it
is
important
to
provide
additional
compliance
flexibility
by
allowing
a
unit
at
a
662
source
to
use
allowances
from
any
other
unit
at
the
same
source;
and
many
other,
non­
allowance­
holding
provisions
of
title
IV
evidence
a
unit­
by­
unit
orientation.
Further,
as
discussed
in
the
SNPR,
EPA
concludes
that
the
adoption
of
source­
level
compliance
reasonably
balances
these
considerations.
In
balancing
these
considerations,
EPA
also
concludes
that
company­
level
compliance
is
not
appropriate
because
it
represents
too
much
of
a
deviation
from
the
unitby
unit
orientation
in
the
non­
allowance­
holding
provisions
of
title
IV
and
is
likely
to
require
much
more
dramatic
changes
in
the
operation
of
the
Acid
Rain
Program.
See
69
FR
32699­
700.
It
is
important
to
note
that
the
final
rule
revisions,
like
the
proposed
revisions,
change
only
the
allowance­
holding
requirement
and
not
the
emissions
monitoring
and
reporting
requirements,
which
continue
to
be
applied
unit
by
unit.

In
today's
action,
EPA
is
making
the
source­

levelcompliance
rule
revisions
effective
July
1,
2006,
which
is
1
year
later
than
proposed.
The
shift
from
unit­
level
to
source­
level
compliance
will
require
software
changes
and
testing
to
ensure
that
the
Allowance
Tracking
System
operates
properly.
Currently,
EPA
is
in
the
process
of
conducting
a
general
review
and
re­
engineering
of
the
Allowance
Tracking
System
and
Emissions
Tracking
System
and
anticipates
completing
the
process
in
2006.
The
process
of
shifting
the
663
Allowance
Tracking
System
to
source­
level
compliance
will
be
much
more
efficient
and
less
likely
to
have
adverse
results
on
the
system
if
the
shift
is
coordinated
with
the
general
review
and
re­
engineering
and
therefore
implemented
starting
July
1,
2006.
Further,
as
discussed
below,
this
delay
of
implementation
for
1
additional
year
will
give
owners
additional
time
to
make
changes
that
they
determine
are
necessary
in
order
to
adapt
to
source­
level
compliance.

Some
commenters
support
the
shift
to
source­
by­
source
allowance
holding,
and
some
oppose
the
change.
One
commenter
opposing
the
change
claims
that
a
source­
by­
source
allowanceholding
requirement
is
"
contrary
to
market­
based
principles."

According
to
the
commenter,
market­
based
systems
give
operators
the
tools
for
achieving
compliance
through
allowance
transfers,
but
with
source­
level
compliance
the
operators
do
not
have
to
take
any
action
to
maintain
sufficient
allowances
because
EPA
will
move
the
allowances
around
for
them.

The
commenter's
argument
is
based
on
an
incorrect
premise.
Whether
compliance
is
unit­
by­
unit
or
source­

bysource
the
owner
or
owners
of
the
affected
units
at
each
source
must
take
the
same
types
of
actions
in
order
to
comply
with
the
applicable
allowance­
holding
requirement.
In
particular,
under
source­
level
compliance,
such
owner
or
owners
must
reduce
emissions,
retain
allowances
allocated
to
664
such
units,
obtain
additional
allowances,
or
take
a
combination
of
these
actions
to
ensure
that
the
Allowance
Tracking
System
account
for
the
source
holds
enough
allowances
to
cover
the
total
emissions
of
the
affected
units
at
the
source.
The
owner
or
owners
also
have
the
option
of
reducing
emissions
below
allocations
so
that
there
are
extra
allowances
available
to
hold
for
future
use
or
sale.
If
the
owner
or
owners
do
not
have
enough
allowances
to
cover
the
emissions
from
the
source,
EPA
will
not
move,
on
its
own
initiative,
allowances
into
the
source's
compliance
account
from
other
sources'
accounts
or
from
general
accounts,
even
if
there
are
extra
allowances
in
the
other
accounts.
The
only
difference
between
the
types
of
actions
owners
must
take
under
the
unit­
level
and
source­
level
approaches
is
that,

under
unit­
level
compliance,
the
owners
must
transfer
allowances
from
one
unit
at
a
source
to
a
second
unit
at
that
source
in
order
to
use
the
first
unit's
allowances
for
compliance
by
the
second
unit
while,
under
source­
level
compliance,
any
allowance
held
for
compliance
for
the
first
unit
can
be
used
­­
without
a
transfer
­­
for
compliance
by
the
second
unit.
This
difference
is
reflected
in
the
Allowance
Tracking
System,
which,
under
the
unit­
level
approach,
includes
a
separate
account
for
each
unit
and,

under
the
source­
level
approach,
includes
a
single
account
for
all
the
affected
units
at
a
single
source.
665
In
summary,
the
mechanism,
and
the
owners'

responsibilities,
for
achieving
compliance
with
the
allowance­
holding
requirements
are
analogous
under
unit­

byunit
and
source­
by­
source
compliance,
except
that,
under
source­
by­
source
compliance,
allowances
need
not
be
transferred
among
units
at
the
same
source.
The
EPA
does
not
believe
that
the
source­
by­
source
approach
is
any
less
market­
based
than
the
unit­
by­
unit
approach.
Owners
will
still
have
the
ability
to
reduce
emissions
or
purchase
or
sell
allowances
and
the
responsibility
to
take
actions
(
including
the
holding
of
extra
allowances)
to
ensure
they
have
enough
allowances
to
cover
emissions.
Moreover,
the
market­
price
of
allowances
will
still
play
a
crucial
role
in
owners'
decisions
on
what
actions
to
take.
The
EPA's
adoption
of
source­
by­
source
compliance
preserves
marketbased
principles,
while
reasonably
balancing
of
the
ambiguity
of
title
IV,
the
need
for
additional
compliance
flexibility,

and
the
unit­
by­
unit
orientation
of
many
provisions
in
title
IV.
See
69
FR
32699­
700.

The
commenter
also
argues
that
having
a
source­
level
allowance­
holding
requirement
in
the
Acid
Rain
Program
(
and
the
CAIR
model
cap
and
trade
program)
is
inconsistent
with
unit­
level
compliance
in
the
NOx
SIP
Call
cap
and
trade
program.
However,
other
than
pointing
out
this
difference,

the
commenter
fails
to
explain
why
the
programs
must
be
666
identical
in
this
regard.
Based
on
experience
with
the
Acid
Rain
Program
(
as
well
as
the
NOx
SIP
Call
trading
program),

EPA
concludes
that
a
source­
level
allowance­
holding
requirement
will
result
in
a
somewhat
less
complicated
program
and
a
reduced
likelihood
of
inadvertent,
minor
errors,
while
achieving
the
program's
environmental
goals.

See
69
FR
32699­
700.

The
commenter
suggests
that,
instead
of
adopting
sourcelevel
compliance,
EPA
revise
the
Acid
Rain
Program
regulations
to
allow
for
source
over­
draft
accounts,
like
those
allowed
in
the
NOx
SIP
Call
cap
and
trade
program.

Under
the
NOx
SIP
Call
program,
each
source
may
have
a
source
over­
draft
account,
in
which
may
be
held
extra
allowances
that
may
be
used
for
compliance
by
any
affected
unit
at
the
source.
However,
EPA
believes
that
source­
level
compliance
is
a
better
approach
than
unit­
level
compliance
with
overdraft
accounts.
Relatively
few
owners
in
the
NOx
SIP
Call
cap
and
trade
program
actually
put
allowances
in
over­
draft
accounts,
and
achievement
of
compliance
is
made
more
complicated
by
the
ability
of
all
units
at
a
source
to
draw
on
the
over­
draft
account
(
if
any
allowances
are
put
in
it)

but
the
inability
of
any
unit
to
use
extra
allowances
held
instead
by
another
unit
at
the
source.
Consequently,
rather
than
adopting
in
the
Acid
Rain
Program
the
unit­
level
approach
with
over­
draft
accounts,
EPA
is
today
adopting
the
667
source­
level
approach
in
the
Acid
Rain
Program
and
may
consider
in
the
future,
as
appropriate,
adopting
the
sourcelevel
approach
in
other
programs
using
unit­
level
compliance.

One
commenter
states
that
EPA
should
revise
the
Acid
Rain
Program
regulations
to
allow
owners,
each
year,
the
option
of
choosing
whether
to
use
unit­
level
or
source­
level
compliance.
According
to
the
commenter,
significant
investments
have
been
made
to
monitor
and
report
emissions
and
surrender
allowances
under
the
existing
Acid
Rain
Program
regulations,
and
shifting
to
source­
level
compliance
will
require
substantial
resources
and
time.
The
commenter
also
states
that
unit­
based
compliance
should
be
retained
as
an
option
"
to
accommodate
joint
ownership
and
other
special
arrangements
that
may
not
affect
an
entire
facility."

The
EPA
rejects
the
suggestion
of
allowing
each
owner
the
option,
for
each
year
and
for
each
source,
of
choosing
between
unit­
level
and
source­
level
compliance.
Such
an
approach
would
significantly
complicate
the
achievement
by
sources,
and
the
determination
by
EPA,
of
compliance.
The
potential
for
error
(
e.
g.,
due
to
erroneous
assumptions
about
whether
unit­
or
source­
level
compliance
would
be
applicable
to
a
particular
source
for
a
particular
year)
on
the
part
of
owners
or
EPA
would
be
significantly
increased.
Moreover,

this
complicated
approach
would
result
in
inconsistent
668
treatment
from
source
to
source
and
year
to
year.
Further,

the
commenter
provided
only
vague
assertions
about
the
benefits
of
unit­
based
compliance
in
certain
circumstances
and
did
not
assert
­­
much
less
show
­­
that
source­
level
compliance
cannot
be
accommodated
under
those
circumstances.

The
EPA
maintains
that
the
only
reasonable
options
for
the
allowance­
holding
requirement
in
the
Acid
Rain
Program
are
either
generally
requiring
compliance
by
all
sources
each
year
on
a
unit­
level
basis
(
as
in
the
existing
regulations)

or
requiring
compliance
by
all
sources
each
year
on
a
sourcelevel
basis
(
as
in
the
proposed
revisions
to
the
regulations).
For
the
reasons
discussed
above,
EPA
believes
that
source­
level
compliance
for
the
allowance­
holding
requirement
is
preferable.
By
postponing
until
July
1,
2006
the
effective
date
of
the
rule
revisions
shifting
to
sourcelevel
compliance
(
with
the
result
that
2006
is
the
first
year
of
source­
level
compliance),
EPA
is
providing
owners
a
reasonable
amount
of
time
to
make
any
necessary
adjustments,

such
as
those
claimed
by
the
commenter.
Further,
as
noted
above,
the
rule
revisions
change
only
the
allowance­
holding
requirement
and
not
the
emissions
monitoring
and
reporting
requirements.
This
should
limit
the
scope
of
adjustments
necessary
for
owners
to
implement
source­
level
compliance
and
will
preserve
the
availability
of
reliable,
unit­
level
emissions
data.
669
14
This
approach
is
consistent
with
the
SNPR,
where
EPA
proposed
to
convert
all
references,
including
any
initially
missed
in
the
SNPR,
from
unit­
to
source­
level
compliance
(
69
FR
32700).
Because
unit­
level
compliance
is
reflected
throughout
the
Acid
Rain
Program
regulations,
numerous
revisions
of
the
regulations
are
necessary
to
implement
source­
level
compliance.
(
None
of
these
changes
are
to
the
emissions
monitoring
and
reporting
provisions
in
part
75
since
monitoring
and
reporting
continue
to
be
on
a
unit
basis.)

One
commenter
requested
that
EPA
provide
"
more
in­
depth
detail"
on
the
proposed
revisions.
However,
in
the
SNPR,
EPA
described
the
types
of,
and
reasons
for,
revisions
that
are
necessary
for
source­
level
compliance
(
69
FR
32700­
01)
and
set
forth
all
of
the
specific,
proposed
changes
(
69
FR
3273­

41).
Moreover,
no
commenters
stated
that
they
did
not
understand
any
specific,
proposed
revision
or
the
reason
for
any
specific
revision.
The
EPA
notes
that
in
reviewing
the
proposed
Acid
Rain
rule
revisions
in
light
of
the
comments,

EPA
found
some
additional
references
in
the
Acid
Rain
rule
to
unit­
level
compliance
that
should
be
revised
to
reflect
source­
level
compliance.
In
today's
action,
EPA
is
adopting
revisions
of
these
additional
references
(
e.
g.,
changing
references
to
a
"
unit's
account"
or
a
"
unit
account"
to
a
source's
"
compliance
account")
that
are
analogous
to
the
revisions
specifically
identified
in
the
SNPR.
150
670
Another
commenter
opposed
the
rule
revisions
implementing
source­
level
compliance
on
several
other
grounds.
The
commenter
claims,
without
citing
any
statutory
support,
that
the
Acid
Rain
Program
is
based
on
"
control
of
emissions
at
the
unit
level"
so
that,
in
the
event
of
excess
emissions,
the
"
source
as
a
whole
would
not
be
punished"
and
"
corrective
action
could
take
place"
at
the
particular
unit.

According
to
the
commenter,
source­
level
compliance
will:

make
it
harder
to
determine
which
unit
caused
excess
emissions;
make
the
existing
Acid
Rain
permits
meaningless;

make
the
individual
unit
allowance
allocations
meaningless;

and
cause
confusion
over
which
units
at
a
source
are
affected
units.

While
there
are
many
non­
allowance­
holding
provisions
in
title
IV
that
have
a
unit­
by­
unit
orientation,
EPA
disagrees
with
the
commenter's
basic
assertion
that
the
purpose
of
the
Acid
Rain
Program
is
to
control
emissions
on
a
unit­
by­
unit
basis
and
that
there
is
a
need
to
"
distinguish"
the
compliance
of
each
individual
unit.
The
provisions
concerning
application
of
the
allowance­
holding
requirement
are
ambiguous
as
to
whether
EPA
must
implement
the
requirement
on
a
unit­
level
or
a
source­
level,
and
the
environmental
benefits
of
the
Acid
Rain
Program
will
still
be
realized
with
source­
level
compliance.
See
69
FR
32699­
700.

Further,
while
EPA
will
determine
compliance
on
a
source­
by­
671
source
basis,
nothing
in
the
regulations
prevents
owners
(
e.
g.,
owners
of
units
at
sources
with
multiple
units
and
multiple
owners
or
owners
of
units
with
multiple
owners
and
exhausting
through
a
common
stack)
from
determining
by
agreement
which
owners
will
bear
any
excess
emissions
penalties
that
occur
at
the
plant
and
have
to
take
correction
actions.
Indeed,
owners
are
likely
to
already
have
these
types
of
agreements
in
cases
of
units
or
sources
with
multiple
owners.
This
is
because
the
Acid
Rain
Program
regulations
already
allow
a
unit
at
a
multi­
unit
source
to
use
some
allowances
from
other
units
at
the
source
(
albeit
to
cover
most
but
not
all
of
the
potential
excess
emissions)
and
already
allow
one
unit
exhausting
from
a
common
stack
to
use
allowances
from
another
unit
at
that
stack
(
without
any
limitation
on
such
use).
See
40
CFR
73.35(
b)(
3)
and
(
e).
In
addition,
while
the
Acid
Rain
permits
will
have
to
be
revised
in
the
future
to
reflect
source­
level
compliance,
today's
rule
does
not
make
source­
level
compliance
effective
until
2006.
Permits
will
not
have
to
be
revised
until
around
the
end
of
2006,
which
should
provide
States
a
reasonable
opportunity
to
amend
the
permits.
Contrary
to
the
claims
of
the
commenter,
source­
level
compliance
does
not
make
the
unit­
by­
unit
allocations
meaningless;
the
unit­
by­
unit
allocations
(
set
forth
in
Table
2
of
§
72.10)
will
determine
the
amount
of
allocations
reflected
in
each
Allowance
672
Tracking
System
source
account,
which
amount
will
equal
the
sum
of
the
allocations
for
all
affected
units
at
the
source.

Finally,
the
commenter
failed
to
explain
how
the
source­
level
allowance­
holding
requirement
could
cause
"
confusion"
over
which
units
are
affected
units.
This
source­
level
requirement
does
not
change
the
applicability
provisions,

which
are
still
applied
unit
by
unit.

As
discussed
in
the
SNPR,
EPA
proposed
­­
in
addition
to
the
rule
revisions
to
implement
source­
level
compliance
­­

other
revisions
of
the
Acid
Rain
Program
regulations
in
order
to
facilitate
coordination
of
the
Acid
Rain
Program
and
the
CAIR
SO2
cap
and
trade
program.
These
additional
revisions
were
described
and
explained
in
the
SNPR
(
69
FR
32701).
The
EPA
is
adopting
these
revisions
for
the
reasons
in
the
SNPR,

as
amplified
below.
Most
of
these
revisions
are
supported,

or
not
opposed,
by
commenters,
but
some
commenters
objected
to
certain
revisions.

For
example,
EPA
noted
that
it
had
recently
changed
the
"
cogeneration
unit"
definition
in
§
72.2
in
June
2002
(
67
FR
40394,
40420;
June
12,
2002).
The
original
definition
in
§
72.2
had
been
used
since
the
commencement
of
the
Acid
Rain
Program.
The
only
significant
difference
between
the
original
and
revised
definitions
is
that
the
former
refers
to
a
unit
"
having
the
equipment
used
to
produce"
electricity
and
useful
thermal
energy
through
sequential
use
of
energy,
while
673
the
latter
simply
refers
to
a
unit
"
that
produces"

electricity
and
useful
thermal
energy
in
that
manner.
The
reason
that
EPA
gave
for
revising
the
definition
in
June
2002
was
to
conform
with
the
definition
in
the
Section
126
rule.

However,
the
Section
126
rule
(
and
the
NOx
SIP
Call)
did
not
actually
specify
a
"
cogeneration
unit"
definition.

Consequently,
there
is
no
reason
to
use
the
June
2002
revised
definition.
Moreover,
EPA
is
concerned
that
the
change
in
the
definition
of
"
cogeneration
unit"
as
of
June
2002
may
cause
confusion
or
raise
question
about
what
units
qualify
for
exemptions
for
"
cogeneration
units"
from
the
Acid
Rain
Program.
Under
these
circumstances,
EPA
concludes
that
the
definition
should
be
changed
back
to
the
original
definition
in
§
72.2
and,
in
any
event,
intends
to
interpret
the
June
2002
revised
definition
as
having
the
same
meaning
as
the
original
definition.
One
commenter
raised
concerns
that
EPA
did
not
provide
any
"
detailed
analysis"
of
the
implications
of
changing
the
"
cogeneration
unit"
definition.
However,
as
discussed
above,
the
change
simply
reinstates
the
definition
that
had
been
used
in
the
Acid
Rain
Program
from
the
initial
promulgation
of
implementing
regulations
in
1993
until
2002.

No
commenter
asserted
that
reverting
to
the
longstanding,

original
definition
would
be
disruptive.

Another
Acid
Rain
Program
rule
revision
proposed
in
the
SNPR
is
the
elimination
of
the
requirement
for
owners
and
674
operators
to
submit
an
annual
compliance
certification
report
for
each
source.
One
commenter
expressed
concern,
because
the
purpose
of
the
annual
certification
is
to
ensure
that
the
designated
representative
is
"
aware
and
has
assured
the
quality
of
the
data"
being
submitted
to
EPA.
However,
as
noted
in
the
SNPR,
designated
representatives
must
evidence
such
awareness
and
compliance
by
submitting,
with
each
quarterly
emissions
report,
a
certification
that
the
monitoring
and
reporting
requirements
under
part
75
of
the
Acid
Rain
Program
regulations
have
been
met.
See
40
CFR
75.64(
c).
Quarterly
emissions
reports
are
available
on­
line
to
the
public
and
the
States.
In
addition,
owners
and
operators
of
sources
subject
to
the
Acid
Rain
Program
must
submit,
under
title
V
of
the
CAA,
annual
compliance
certification
reports
concerning
all
CAA
requirements
(
including
Acid
Rain
Program
requirements).
Under
these
circumstances,
EPA
maintains
that
the
separate
Acid
Rain
Program
annual
compliance
certification
reports
are
duplicative
and
unnecessary.
The
EPA
notes
that
it
appears
that
few,
if
any,
requests
for
copies
of
these
Acid
Rain
Program
reports
have
been
made
by
States
or
any
other
persons
since
the
commencement
of
the
Acid
Rain
Program.
Apparently,

other
certifications
and
submissions
required
of
owners
and
operators
have
been
sufficient
for
the
purposes
cited
by
the
commenter.
675
The
SNPR
also
included
proposed
revisions
eliminating
the
requirement
under
the
Acid
Rain
Program
for
a
1­
day
newspaper
notice
for
designation
of
designated
representatives
and
authorized
account
representatives.
One
commenter
suggests
that
this
notice
should
be
replaced
by
a
requirement
to
notify
the
State
permitting
authority.
The
EPA
notes
that
information
on
designated
representatives
and
authorized
account
representatives
is
already
available
to
State
permitting
authorities
through
on­
line
access
to
the
Allowance
Tracking
System.
Moreover,
EPA
is
in
the
process
of
developing,
and
anticipates
establishing
in
the
near
future,
the
ability
to
send
State
permitting
authorities
(
at
their
request)
on­
line
notices
of
changes
in
designated
representatives
(
who
are
also
the
authorized
account
representatives
for
affected
sources'
accounts).

Other
proposed
Acid
Rain
Program
rule
revisions
on
which
EPA
received
adverse
comment
are
the
removal
of
§
73.32
(
prescribing
the
contents
of
an
allowance
account)
and
§
73.51
(
prohibiting
the
transfer
of
allowances
from
a
future
year
subaccount
to
a
subaccount
for
an
earlier
year).
Section
73.32
sets
forth
a
rather
self­
evident
list
of
information
that
must
be
recorded
in
an
allowance
account
in
the
Allowance
Tracking
System,
such
as
the
name
of
the
authorized
account
representative,
the
persons
represented
by
the
authorized
account
representative,
and
the
transfers
of
676
15
In
reviewing
the
proposed
Acid
Rain
Program
rule
revisions,
EPA
found
some
additional
references
to
"
subaccounts"
that
were
not
specifically
noted
in
the
SNPR.
For
consistency
and
clarity
in
the
Acid
Rain
Program
rules,
EPA
is
adopting
in
today's
action
revisions
(
e.
g.,
changing
the
term
"
subaccount"
to
"
compliance
account")
of
these
additional
references,
which
revisions
are
analogous
to
those
specifically
set
forth
in
the
SNPR.
This
approach
is
consistent
with
the
SNPR,
where
EPA
proposed
to
convert
all
references,
including
any
initially
missed
in
the
SNPR,
from
subaccount
to
compliance
account,
(
69
FR
32700).
allowances
in
and
out
of
the
account.
This
section
also
references
information
on
compliance
or
current
year
subaccounts
and
future
year
subaccounts,
as
well
as
emissions
information.
As
discussed
in
the
SNPR,
several
items
on
the
list
of
informational
contents
for
allowance
accounts
are
out­
of­
date
in
that
they
do
not
reflect
how
the
electronic
Allowance
Tracking
System
operates
or
will
operate
in
the
near
future.
For
example,
the
electronic
Allowance
Tracking
System
does
not
currently
use
or
refer
to
subaccounts,
which
will
continue
to
be
unnecessary
in
the
context
of
sourcelevel
compliance.
151
See
69
FR
32700­
01.
In
addition,
while
§
73.32
states
that
emissions
data
are
reflected
in
the
Allowance
Tracking
System
account,
such
data
are
currently
available
instead
through
the
electronic
Emissions
Tracking
System.
Because
the
information
list
in
§
73.32
contains
either
self­
evident
items
or
items
that
are
out­
of­
date
and
because
the
NOx
Allowance
Tracking
System
has
been
operating
successfully
even
though
the
model
NOx
Budget
cap
and
trade
rule
and
State
cap
and
trade
rules
under
the
NOx
SIP
Call
677
lack
a
provision
analogous
to
§
73.32,
EPA
is
removing
§
73.32.

EPA
notes
that
the
removal
of
the
section
will
not
mean
that
the
information
contained
in
allowance
accounts
"
can
be
changed
at
will."
The
format
for
allowance
accounts
is
set
forth
in
the
electronic
Allowance
Tracking
System
and
implements
the
requirements
in
the
Acid
Rain
Program
regulations
concerning
the
holding,
transferring,
recording,

and
deducting
of
allowances.

Section
73.51
prohibits
the
transfer
of
allowances
from
a
future
year
subaccount
to
a
subaccount
for
an
earlier
year.

The
removal
of
this
section
is
consistent
with
the
elimination
throughout
the
rest
of
the
Acid
Rain
Program
regulations,
as
discussed
in
the
SNPR
(
id.),
of
any
references
to
such
subaccounts.
Further,
the
prohibition
on
using
allowances
allocated
for
a
year
to
meet
the
allowanceholding
requirement
for
a
prior
year
is
retained
in
other
provisions
of
the
Acid
Rain
Program
regulations.

Consequently,
EPA
is
removing
§
73.51.

C.
How
Does
the
Rule
Interact
with
the
Regional
Haze
Program?

This
section
discusses
the
relationship
of
the
CAIR
cap
and
trade
program
for
EGUs
with
the
regional
haze
program
under
sections
169A
&
169B
of
the
CAA,
in
particular
the
requirements
for
Best
Available
Retrofit
Technology
(
BART)

for
certain
source
categories
including
EGUs.
The
678
legislative
and
regulatory
background
of
the
BART
provisions
were
presented
in
some
detail
in
the
SNPR.
(
See
69
FR
32684,

32702
 
704,
June
10,
2004).
In
brief,
BART
regulations
consist
of
two
components.
The
first,
promulgated
in
1980,

addresses
visibility
impairment
that
can
be
"
reasonably
attributed"
to
a
single
source
or
small
group
of
sources.

(
45
FR
80085;
December
2,
1980,
codified
at
40
CFR
51.302.

The
second
component
addresses
BART
in
relation
to
regional
haze
(
visibility
impairment
caused
by
a
multitude
of
broadly
distributed
sources)
and
was
promulgated
as
part
of
the
Regional
Haze
Rule.
(
64
FR
35714;
July
1,
1999).
Certain
parts
of
the
BART
provisions
in
that
rule
were
vacated
by
the
U.
S.
Court
of
Appeals
for
the
D.
C.
Circuit
in
American
Corn
Growers
et
al.
v.
EPA,
291
F.
3d
1
(
D.
C.
Cir.,
2002).
To
address
that
decision,
in
May
2004,
EPA
proposed
changes
to
the
Regional
Haze
Rule
and
reproposed
the
Guidelines
for
BART
Determinations
(
originally
proposed
in
2001)
(
69
FR
25185,

May
5,
2004).

On
February
18,
2005,
the
D.
C.
Circuit
decided
another
case
dealing
with
BART
and
a
BART
alternative
program,
Center
for
Energy
and
Economic
Development
v.
EPA,
No.
03­
1222,(
D.
C.

Cir.
Feb.
18,
2005)("
CEED").
In
this
case,
the
court
granted
a
petition
challenging
provisions
of
the
regional
haze
rule
governing
the
optional
emissions
trading
program
for
certain
679
152
Arizona,
California,
Colorado,
Oregon,
Idaho,
Nevada,
New
Mexico,
Utah,
and
Wyoming,
153
The
trading
program
is
referred
to
as
a
"
backstop"
because
under
the
WRAP
Annex,
States
have
the
opportunity
to
achieve
specified
emission
milestones
using
voluntary
measures,
with
the
trading
program
coming
into
effect
only
if
those
milestones
are
exceeded.
western
States
and
Tribes
(
the
"
WRAP
Annex
Rule").
The
holdings
of
the
case
are
relevant
to
today's
action
in
several
respects.

Most
importantly
for
purposes
of
the
CAIR,
CEED
affirmed
EPA's
interpretation
of
CAA
169A(
b)(
2)
as
allowing
for
non­

BART
alternatives
where
those
alternatives
make
greater
progress
than
BART.
(
CEED,
slip.
op.
at
13)(
finding
that
EPA's
interpretation
of
CAA
169(
a)(
2)
as
requiring
BART
only
as
necessary
to
make
reasonable
progress
passes
the
twopronged
Chevron
test).

The
particular
provisions
involved
in
CEED
applied,
on
an
optional
basis,
only
to
nine
western
States152
(
none
of
which
are
in
the
CAIR
region)
and
the
Tribes
therein.
The
provisions,
contained
in
40
CFR
51.309
("
§
309")
required
among
other
things
that
States
choosing
to
participate
in
a
"
backstop"
153
cap
and
trade
program
must
demonstrate
that
the
emissions
reductions
under
the
program
resulted
in
greater
progress
towards
the
national
visibility
goals
than
would
BART.
At
issue
was
the
particular
methodology
required
for
this
demonstration.
Specifically,
EPA's
rule
required
that
visibility
improvements
under
source­
specific
BART
 
the
680
154
The
methodology
is
prescribed
in
40
CFR
51.308(
e)(
2)
and
incorporated
into
§
309
by
reference
at
40
CFR
51.309(
f).
benchmark
for
comparison
to
the
cap
and
trade
program
 
must
be
calculated
based
on
the
application
of
BART
controls
to
all
sources
subject
to
BART.
154
Although
American
Corn
Growers
had
vacated
this
cumulative
visibility
approach
in
the
context
of
determining
BART
for
individual
sources,
EPA
believed
that
it
was
still
permissible
to
require
this
methodology
in
the
context
of
a
BART­
alternative
program.

The
D.
C.
Circuit
in
CEED
held
otherwise,
stating:
"
EPA
cannot
under
§
309
require
states
to
exceed
invalid
emission
reductions
(
or,
to
put
it
more
exactly,
limit
them
to
a
§
309
alternative
defined
by
an
unlawful
methodology)."
(
Id.

at
14).

Thus,
CEED
firmly
established
two
principles:
(
1)
the
CAA
allows
States
to
substitute
other
programs
for
BART
where
the
alternative
achieves
greater
progress,
and
(
2)
EPA
may
not
require
States
to
evaluate
visibility
improvement
on
a
cumulative
basis
as
a
condition
for
approval
of
a
BARTalternative
The
first
principle
validates
EPA's
proposal
to
allow
the
CAIR
to
substitute
for
BART.
The
second
principle
is
not
at
issue
in
the
CAIR
context,
because
EPA
is
not
proposing
to
impose
the
cumulative
visibility
methodology
upon
States,
nor
to
require
States
to
treat
the
CAIR
as
having
satisfied
their
BART
obligations.
681
Nonetheless,
EPA
has
determined
that
it
is
premature
to
make
a
final
determination
regarding
the
sufficiency
of
the
CAIR
as
a
BART
alternative,
primarily
because
(
1)
the
guidelines
for
source­
specific
BART
determinations,
in
response
to
American
Corn
Growers
have
not
been
finalized,

and
(
2)
there
is
now
a
need
to
revise
the
Regional
Haze
Rule
and
the
guidelines
for
BART­
alternative
programs
in
response
to
CEED.
The
source­
specific
BART
guidelines
will
be
finalized
on
or
before
April
15,
2005,
under
a
consent
decree.
The
rule
changes
and
revisions
to
the
BARTalternative
guidelines
will
be
proposed
soon
thereafter.

Therefore,
we
are
making
no
final
determination
in
today's
action
with
respect
to
BART.
The
EPA
continues
to
believe,
however,
that
the
CAIR
will
result
in
greater
progress
in
visibility
improvement
than
BART,
as
explained
below.

1.
How
Does
this
Rule
Relate
to
Requirements
for
BART
under
the
Visibility
Provisions
of
the
CAA?

a.
Supplemental
Notice
of
Proposed
Rulemaking
In
the
SNPR,
we
proposed
that
States
which
adopt
the
CAIR
cap
and
trade
program
for
SO2
and
NOx
would
be
allowed
to
treat
the
participation
of
EGUs
in
this
program
as
a
substitute
for
the
application
of
BART
controls
for
these
682
155
The
SNPR
preamble
used
the
term
"
exemption"
in
describing
this
policy.
As
clarified
below,
and
as
consistent
with
the
proposed
regulatory
language,
the
better­
than­
BART
policy
is
not
actually
an
exemption
but
rather
an
alternative
means
of
compliance.
pollutants
to
affected
EGUs.
155
To
give
this
option
effect,

we
proposed
an
amendment
to
the
Regional
Haze
Rule
which
would
add
a
section
at
40
CFR
51.308(
e)(
3),
as
follows:

(
3)
A
State
that
opts
to
participate
in
the
Clean
Air
Interstate
Rule
cap­
and­
trade
program
under
part
96
AAA­
EEE
need
not
require
affected
BARTeligible
EGUs
to
install,
operate,
and
maintain
BART.
A
State
that
chooses
this
option
may
also
include
provisions
for
a
geographic
enhancement
to
the
program
to
address
the
requirement
under
§
51.302(
c)
related
to
BART
for
reasonably
attributable
impairment
from
the
pollutants
covered
by
the
CAIR
cap
and
trade
program.

This
proposal
is
consistent
with
currently
existing
provisions
which
allow
States
to
develop
cap
and
trade
programs
or
other
alternative
measures
in
lieu
of
the
application
of
BART
on
a
source
specific
basis.
(
See
40
CFR
51.308(
e)(
2)
and
64
FR
35714,
35741
 
35743,
July
1,
1999).

The
proposal
was
based
on
the
application
of
the
proposed
two­
pronged
test
for
whether
an
alternative
to
BART
is
"
better
than
BART"
which
was
proposed
in
the
2001
BART
guidelines
and
reproposed
without
changes
in
our
May,
2004
683
proposed
guidelines
for
BART
determinations
(
69
FR
25184,

May
5,
2004).

Specifically,
the
re­
proposed
BART
Guidelines
provide
that
if
the
geographic
distribution
of
emissions
reductions
is
anticipated
to
be
similar
under
both
programs,
the
trading
program
(
or
other
alternative
measure)
must
be
shown
to
achieve
greater
overall
emissions
reductions
than
the
application
of
source­
specific
BART.
If
the
trading
program
is
anticipated
to
result
in
a
different
geographic
distribution
of
emissions
reductions
than
would
sourcespecific
BART,
the
trading
program
must
be
shown
to
result
in
no
decline
in
visibility
at
any
Class
I
area,
and
in
an
overall
improvement
in
visibility
on
an
average
basis
over
all
affected
Class
I
areas
(
69
FR
25184,
25231).
Because
we
had
not
yet
determined
whether
there
is
a
difference
in
the
geographic
distribution
of
emissions
reductions
between
the
CAIR
and
the
application
of
source­
specific
BART
in
the
CAIR
region,
we
assessed
the
difference
between
the
two
programs
by
evaluating
the
visibility
impacts
of
each
program,
using
this
proposed
two­
pronged
test.

The
emissions
projections
and
air
quality
modeling
used
to
demonstrate
that
the
CAIR
satisfies
this
proposed
twopronged
test
were
presented
in
a
document
entitled
Supplemental
Air
Quality
Modeling
Technical
Support
Document
(
TSD)
for
the
Clean
Air
Interstate
Rule
(
May
4,
2004).
In
684
brief,
we
found
that
the
CAIR
would
not
result
in
a
degradation
of
visibility
from
current
conditions
at
any
Class
I
Area
nationwide.
Within
the
CAIR­
affected
States
and
New
England,
EPA
found
that
the
CAIR
would
produce
greater
visibility
benefits
 
specifically,
an
average
improvement
of
2.0
deciviews,
as
compared
to
1.0
for
BART.

The
EPA
also
found
that
average
visibility
improvement
for
Class
I
areas
nationwide
would
be
0.7
deciviews
under
the
CAIR,
compared
to
0.4
deciviews
under
BART.
The
EPA
noted
in
the
SNPR
and
the
TSD
that
because
the
emissions
scenarios
used
in
these
analyses
were
developed
for
different
purposes,
the
scenarios
varied
slightly
from
the
scenarios
which
would
be
ideal
for
this
test.
The
EPA
committed
to
conduct
additional
analyses,
and
those
analyses
have
now
been
done.
The
new
modeling
and
results
are
discussed
in
more
detail
in
section
IX.
C.
2
below.

b.
Comments
and
EPA's
Responses
Several
commenters
argued
that
a
categorical
exclusion
of
sources
from
BART
would
violate
the
CAA,
as
interpreted
by
the
U.
S.
Court
of
Appeals
for
the
D.
C.
Circuit
in
American
Corn
Growers
v.
EPA,
291
F.
3d
1,
2002,
by
illegally
constraining
the
discretion
Congress
conferred
to
States
in
making
BART
determinations
and
by
depriving
States
of
an
adequate
opportunity
to
evaluate
the
emissions
reductions
in
light
of
the
BART
requirement.
Some
States
also
expressed
a
685
desire
to
retain
their
discretion
to
require
BART.

Additionally,
some
commenters
asserted
that
EPA
could
not
offer
an
exemption
to
BART
unless
the
conditions
for
exemptions
provided
by
CAA
169A(
c)
are
met,
including
a
showing
that
the
source
in
question
will
not,
alone
or
in
combination
with
other
sources,
emit
any
pollutant
which
may
reasonably
be
anticipated
to
cause
or
contribute
to
impairment
at
any
Class
I
area,
and
the
concurrence
of
the
appropriate
Federal
Land
Manager
with
the
exemption
determination.

The
EPA
agrees
that
under
the
CAA
and
the
American
Corn
Growers
case,
EPA
may
not
preclude
a
State
from
conducting
its
own
BART
analysis,
nor
from
requiring
BART
controls
at
individual
sources
as
determined
appropriate
through
such
analysis.
Accordingly,
as
noted
above,
the
proposed
regulatory
change
to
the
Regional
Haze
Rule
would
provide
that
a
CAIR
affected
State
"
need
not
require
affected
BARTeligible
EGUs
to
install,
operate,
and
maintain
BART"
if
such
State
opts
to
participate
in
the
CAIR
cap
and
trade
program.
The
optional
nature
of
this
language
("
need
not"

rather
than
"
may
not")
is
consistent
with
the
American
Corn
Growers
decision,
because
it
does
not
attempt
to
mandate
that
States
must
consider
the
CAIR
as
having
met
the
requirements
of
BART.
686
The
SNPR
preamble
summarized
the
proposal
by
stating
that
"
EPA
proposes
that
BART­
eligible
EGUs
in
any
State
affected
by
CAIR
may
be
exempted
from
BART
controls
for
SO2
and
NOx
if
that
State
complies
with
the
CAIR
requirements
through
adoption
of
the
CAIR
cap­
and­
trade
programs
for
SO2
and
NOx
emissions."
(
69
FR
3270).
That
statement
accurately
reflected
the
optional
nature
of
the
better­
than­

BART
substitution
policy,
by
providing
that
sources
"
may"
be
granted
such
regulatory
flexibility.
However,
the
use
of
the
term
"
exempted"
in
this
context
was
somewhat
imprecise.

EPA
agrees
that
sources
may
not
be
"
exempt"
from
BART
requirements
unless
the
requirements
of
169A(
c)
are
fulfilled.
The
better­
than­
BART
policy
is
not
an
"
exemption"
from
BART;
it
is
an
alternative
regulatory
program
that
would
allow
Congressionally
required
emissions
reductions
from
BART­
eligible
sources
to
be
made
in
a
more
cost­
effective
manner.
Moreover,
as
explained
elsewhere
in
the
SNPR
and
again
below,
BART­
eligible
EGUs
would
not
be
"
exempt"
from
BART
because,
until
the
emissions
reductions
required
by
the
CAIR
are
fully
realized,
such
sources
would
remain
subject
to
the
possibility
of
being
required
to
install
BART
controls
if
deemed
necessary
to
meet
requirements
regarding
reasonably
attributable
visibility
impairment,
as
provided
by
40
CFR
51.302.
687
Several
commenters
asserted
that
because
Congress
singled
out
26
source
categories
for
the
application
of
BART,
there
is
no
basis
in
law
for
EPA
to
"
exempt"
some
of
these
categories.
These
comments
amount
to
facial
challenges
of
EPA's
authority
to
approve
SIPs
which
contain
alternative
strategies,
rather
than
source­
specific
BART
requirements,
for
BART­
eligible
sources.

The
EPA's
authority
to
approve
alternative
measures
to
BART,
where
those
measures
achieve
greater
reasonable
progress
than
would
BART,
was
recently
upheld
by
the
D.
C.

Circuit.
(
CEED,
slip.
op.
at
13).
See
also
Central
Arizona
Water
Conservation
District
v.
EPA,
990
F.
2d
1531,1543,

(
1993)(
Upholding
EPA's
interpretation
of
CAA
169A(
b)(
2)
as
providing
discretion
to
adopt
implementation
plan
provisions
other
than
those
provided
by
BART
analyses
in
situations
where
the
agency
reasonably
concludes
that
more
reasonable
progress
will
thereby
be
attained).

Similarly,
some
commenters
stated
that
the
CAIR
could
not
substitute
for
BART
because
the
CAIR
and
BART
are
authorized
by
separate
parts
of
the
CAA.
They
argue
that
allowing
reductions
required
by
a
provision
of
the
CAA
not
linked
to
visibility
improvement
to
substitute
for
BART
would
alter
Congress'
"
mandate"
that
certain
source
categories
make
reductions
for
visibility
in
excess
of
what
688
156
CAIR
is
linked
to
visibility
improvements
insofar
as
it
attempts
to
make
progress
towards
attainment
of
the
PM2.5
NAAQS,
which
would,
among
other
things,
improve
visibility.
other
CAA
provisions
require
of
those
sources.
156
Commenters
also
point
to
Regional
Haze
Rule
section
308(
e)(
2),
as
evidence
that
reductions
from
other
programs
such
as
title
IV
and
the
NOx
SIP
Call
must
be
achieved
in
addition
to,
and
not
as
a
substitute
for,
BART.
Commenters
also
argue
that
EPA
(
and
States)
will
need
all
available
tools,
including
BART,
to
meet
visibility
and
NAAQS
requirements.

Again,
under
our
interpretation
of
CAA
section
169A(
b)(
2)
as
upheld
in
CEED
and
Central
Arizona
Water,

Congress
did
not
"
mandate"
that
emission
reductions
from
certain
source
categories
be
obtained
by
the
installation
of
BART
controls.
Instead,
the
CAA
allows
for
alternative
measures
to
BART
 
whether
for
EGUs
or
non­
EGUs
 
where
those
measures
result
in
greater
reasonable
progress,
and
as
explained
below,
we
have
determined
that
greater
reasonable
progress
can
be
obtained
from
the
EGU
sector
through
the
use
of
the
CAIR
cap
and
trade
program.
However,
if
a
State
believes
more
progress
can
be
made
at
affected
Class
I
areas
by
utilizing
BART,
the
State
need
not
make
the
determination
that
the
CAIR
substitutes
for
BART
in
that
State.

Therefore,
EPA
is
not
eliminating
any
tools
available
to
the
States.
689
157
See
"
2002
Base
Year
Emission
Inventory
SIP
Planning:
8­
hr
Ozone,
PM2.5
and
Regional
Haze
Programs,
"
November
8,
2002,
Guidance
Memorandum,
http://
www.
epa.
gov/
ttn/
oarpg/
t1/
memoranda/
2002bye_
gm.
pdf
158
The
purpose
of
providing
a
cut­
off
year
for
SIP
measures
to
which
the
alternative
must
be
surplus
is
to
prevent
an
untenable
situation
where
programs
being
developed
simultaneously
must
be
surplus
to
each
other.
Establishing
a
baseline
year
allows
States
to
continue
to
make
reductions
between
that
baseline
date
and
the
submittal
of
regional
haze
SIPs
without
being
"
penalized"
for
those
reductions
by
not
being
allowed
to
count
them
as
contributing
to
reasonable
progress
towards
the
national
visibility
goal.
With
respect
to
Regional
Haze
Rule
section
308(
e)(
2),

EPA
does
not
believe
that
this
section
provides
any
support
for
the
notion
that
emissions
reductions
from
other
programs
must
necessarily
be
in
addition
to,
not
substitute,
for
BART.
We
first
note
that
the
decision
in
CEED
necessitates
revisions
to
308(
e)(
2),
at
least
in
the
provisions
requiring
visibility
to
be
evaluated
on
a
cumulative
basis
in
defining
the
BART
benchmark
for
comparison
to
BART
alternative
programs.
It
remains
to
be
seen
whether
308(
e)(
2)(
iv),

which
requires
that
emissions
reductions
from
the
BART
alternative
be
"
surplus
to
reductions
resulting
from
measures
adopted
to
meet
requirements
as
of
the
baseline
date
of
the
SIP,"
will
be
changed.
Even
if
that
section
remains
unchanged,
the
CAIR
complies
with
it.
The
baseline
date
of
Regional
Haze
SIPs
is
2002.157
Since
any
emissions
reduction
requirements
to
meet
the
CAIR
would
necessarily
be
adopted
after
2002,
CAIR­
required
reductions
would
clearly
be
surplus
to
measures
adopted
as
of
the
baseline
year.
158
690
Several
commenters
argued
that
the
question
of
whether
BART
is
better
than
the
CAIR
is
properly
addressed
in
the
BART
rulemaking,
not
in
today's
action,
and
that
the
betterthan
BART
determination
is
otherwise
premature.
While
EPA
believes
that
our
current
analysis
demonstrates
that
the
CAIR
is
better
than
BART
(
based
on
the
criteria
in
our
May
2004
BART
proposal),
and
that
the
range
of
uncertainty
regarding
the
presumptive
BART
controls
for
EGUs
to
be
finalized
in
the
BART
guidelines
is
not
likely
to
alter
that
demonstration,
we
agree
that
we
cannot
make
a
final
determination
that
CAIR
is
better
than
BART
until
the
changes
to
the
regional
haze
regulations
required
by
both
American
Corn
Growers
and
CEED
are
finalized.

Several
commenters
felt
the
CAIR
should
be
considered
better
than
BART
for
a
State
whether
or
not
that
State
participates
in
the
CAIR
cap
and
trade
program,
as
long
as
the
State
achieves
its
emission
reduction
requirement
under
the
CAIR.
Conversely,
one
commenter
felt
that
CAIR
reductions
should
be
considered
better
than
BART
only
when
a
State
does
not
participate
in
the
cap
and
trade
program,

thereby
ensuring
that
the
reductions
will
occur
in­
State.

Our
preliminary
demonstration
that
the
CAIR
results
in
more
reasonable
progress
than
BART
for
EGUs
is
based
on
a
comparison
of
emissions
reductions
from
EGUs,
and
attendant
air
quality
effects,
under
the
CAIR
as
compared
to
under
691
BART
as
proposed
in
May,
2004.
If
emissions
reductions
are
achieved
from
other
source
sectors,
a
similar
analysis
would
have
to
be
conducted
for
those
sector(
s)
before
it
could
be
determined
that
the
reductions
were
better
than
BART
for
affected
source
categories.
For
example,
if
a
State
either
wants
to
use
EGU
emissions
reductions
under
the
CAIR
to
substitute
for
BART
for
non­
EGUs,
or
use
non­
EGU
emissions
reductions
to
substitute
for
BART
for
EGUs,
that
could
be
allowed
as
an
alternative
measure
to
BART
provided
a
similar
"
better­
than­
BART"
determination
is
made
for
the
sectors
involved.

A
few
commenters
believed
EPA
should
not
limit
the
substitution
of
the
CAIR
for
BART
to
States
that
are
required
to
meet
CAIR
for
both
SO2
and
NOx
on
an
annual
basis,
but
rather
should
also
allow
it
for
States
which
are
only
required
to
reduce
NOx
during
the
ozone
season.

Because
the
modeling
scenarios
were
based
on
the
pollutants
covered
by
the
CAIR
in
each
affected
State,
our
better­
than­

BART
demonstration
is
limited
to
those
scenarios.
A
State
subject
to
the
CAIR
for
NOx
purposes
only
would
have
to
make
a
supplementary
demonstration
that
BART
has
been
satisfied
for
SO2,
as
well
as
for
NOx
on
an
annual
basis.

A
few
commenters
believed
that
the
CAIR
should
satisfy
BART
for
purposes
of
reasonably
attributable
visibility
impairment
as
well
as
BART
for
purposes
of
regional
haze.
692
Several
others
commented
that
it
was
appropriate
or
legally
necessary
to
preserve
the
authority
of
Federal
Land
Managers
(
FLMs)
and
States
to
certify
impairment
and
make
reasonable
attribution
determinations,
which
could
subject
a
source
to
BART
requirements
even
if
the
source
is
a
participant
in
the
CAIR
cap
and
trade
program.
These
commenters
supported
the
use
of
a
strategy
similar
to
that
employed
by
the
Western
Regional
Air
Partnership,
which
relies
upon
a
Memorandum
Of
Understanding
(
MOU)
between
the
FLMs
and
the
States
regarding
the
criteria
by
which
certifications
of
impairment
may
be
made,
along
with
the
possibility
of
"
geographic
enhancements"
to
the
cap
and
trade
program
to
accommodate
the
imposition
of
source­
specific
BART
control
requirements
on
a
source
within
the
cap
and
trade
program.

As
proposed
in
the
SNPR,
EPA
continues
to
believe
that
reasonably
attributable
visibility
impairment
determinations
under
40
CFR
51.302
must
continue
to
be
a
viable
option
in
order
to
insure
against
any
possibility
of
hot­
spots.
We
believe
that
a
certification
of
reasonably
attributable
visibility
impairment
is
fairly
unlikely,
given
that
there
have
been
few
such
certifications
since
1980,
and
given
that
the
reductions
from
the
CAIR
and
other
recent
initiatives
will
make
such
certifications
decreasingly
likely.
We
believe
sources
can
be
given
sufficient
regulatory
certainty
to
enable
effective
participation
in
a
cap
and
trade
program
693
159
The
question
of
whether
section
169A(
b)(
2)
requires
BART
based
on
contribution
to
impairment
at
any
Class
I
area
is
separate
from
the
question
of
whether
this
section
requires
source­
specific
BART
under
all
circumstances.
As
noted
earlier,
we
interpret
section
169A
(
b)(
2)
as
requiring
BART
only
as
needed
to
make
reasonable
progress,
thus
allowing
for
alternative
measures
which
make
greater
reasonable
progress.
through
the
use
of
MOUs
and
geographic
enhancement
provisions.

Some
commenters
believe
that
because
section
169A(
b)(
2)(
A)
requires
BART
for
an
eligible
source
which
may
reasonably
be
anticipated
to
cause
or
contribute
to
any
impairment
of
visibility
in
any
Class
I
area,
EPA
is
without
basis
in
law
or
regulation
to
base
a
better­
than­
BART
determination
on
an
analysis
that
does
not
evaluate
visibility
improvement
at
each
and
every
Class
I
area,
or
one
that
uses
averaging
of
visibility
improvement
across
different
Class
I
areas.

The
criteria
we
applied
in
our
present
analysis
 
that
greater
reasonable
progress
is
defined
as
no
degradation
at
any
Class
I
area,
and
greater
overall
average
improvement
 
have
not
been
finalized.
However,
we
disagree
with
comments
that
169A(
b)(
2)'
s
requirement
of
BART
for
sources
reasonably
anticipated
to
contribute
to
impairment
at
any
Class
I
area159
means
that
an
alternative
to
the
BART
program
must
be
shown
to
create
improvement
at
each
and
every
Class
I
area.

Even
if
a
BART
alternative
is
deemed
to
satisfy
BART
for
694
regional
haze
purposes,
based
on
average
overall
improvement
as
opposed
to
improvement
at
each
and
every
Class
I
Area,

169A(
b)(
2)'
s
trigger
for
BART
based
on
impairment
at
any
Class
I
area
remains
in
effect,
because
a
source
may
become
subject
to
BART
based
on
"
reasonably
attributable
visibility
impairment"
at
any
area.
(
The
EPA
believes
it
is
unlikely
that
a
State
or
FLM
will
have
need
to
certify
reasonably
attributable
visibility
impairment
(
RAVI)
with
respect
to
any
EGU
in
the
CAIR
region,
but
nevertheless
believes
it
is
necessary
to
preserve
this
safeguard).

We
also
received
a
number
of
comments
regarding
the
broader
relationship
between
the
CAIR
and
regional
haze,

including
whether
the
CAIR
meets
reasonable
progress
requirements,
as
well
as
BART,
for
affected
States;
whether
EPA
should
allow
non­
CAIR
States
to
opt
in
to
the
CAIR
cap
and
trade
program
to
meet
their
BART
requirements;
and
whether
regional
haze
provisions
should
be
used
as
a
basis
for
expanding
the
CAIR
rule
to
the
rest
of
the
States
which
were
not
included
on
the
basis
of
contribution
to
PM2.5
and
ozone
nonattainment.
The
EPA's
responses
to
comments
on
these
broader
issues,
which
are
not
germane
to
the
issue
of
whether
the
CAIR
may
substitute
for
BART
for
affected
EGUs,

are
contained
in
the
Response
to
Comment
Document.

c.
Today's
Action
695
As
discussed
above,
EPA
has
the
authority
to
approve
SIPs
which
rely
upon
a
cap
and
trade
program
as
an
alternative
to
BART.
However,
at
this
time,
we
are
deferring
a
final
determination
that,
in
EPA's
view,
the
CAIR
makes
greater
progress
than
BART
for
CAIR­
affected
States
until
such
time
as
the
BART
guidelines
for
EGUs
and
the
criteria
for
BART­
alternative
programs
are
finalized.

At
that
time,
contingent
upon
supporting
analysis
and
our
final
rules
governing
the
regional
haze
program,
EPA
will
make
a
final
determination
as
to
whether
the
CAIR
makes
greater
progress
than
BART,
and
can
be
relied
on
as
an
alternative
measure
in
lieu
of
BART.

2.
What
Improvements
Did
EPA
Make
to
the
Bart
Versus
the
CAIR
Modeling,
and
What
Are
the
New
Results?

a.
Supplemental
Notice
of
Proposed
Rulemaking
For
the
better­
than­
BART
analysis
in
the
SNPR,
we
used
the
Integrated
Planning
Model
(
IPM)
to
estimate
emissions
expected
after
implementation
of
a
source­
specific
BART
approach
and
after
implementation
of
the
CAIR
cap
and
trade
program
for
EGUs.
We
then
used
the
Regional
Modeling
System
for
Aerosols
and
Deposition
(
REMSAD)
air
quality
model
to
project
the
visibility
impact
of
these
IPM
emissions
predictions
for
both
the
CAIR
and
the
nationwide
sourcespecific
BART
scenarios.
Specifically,
EPA
evaluated
the
model
results
for
the
20
percent
best
days
(
that
is,
least
696
visibility
impaired)
and
the
20
percent
worst
days
at
44
Class
I
areas
throughout
the
country.
Thirteen
of
these
Class
I
areas
are
within
States
affected
by
the
CAIR
proposal,
and
31
Class
I
areas
are
outside
the
CAIR
region
 
29
in
States
to
the
west
of
the
CAIR
region,
and
2
in
New
England
States
northeast
of
the
CAIR
region.

As
explained
in
the
SNPR,
the
"
CAIR"
scenario
modeled
was
imperfect
for
purposes
of
this
analysis
in
that
it
assumed
SO2
reductions
on
a
nationwide
basis
(
rather
than
in
the
CAIR
region
only)
and
assumed
NOx
reductions
requirements
in
a
slightly
different
geographic
region
than
covered
by
the
proposed
CAIR.
The
ideal
scenario
would
have
correctly
represented
the
geographic
scope
of
the
CAIR
SO2
and
NOx
reduction
requirements,
and
included
source­
specific
BART
controls
in
areas
outside
the
CAIR
region.
(
This
corrected
scenario
has
been
modeled
for
the
NFR,
as
explained
below).

The
SNPR
REMSAD
modeling
showed
that
under
the
proposed
two­
pronged
test,
CAIR
controls
achieved
equal
or
greater
visibility
improvement
than
the
application
of
sourcespecific
BART
to
EGUs
nationwide.
The
modeling
predicted
that
the
CAIR
cap
and
trade
program
will
not
result
in
degradation
of
visibility,
compared
to
existing
(
1998­
2002)

visibility
conditions,
at
any
of
the
44
Class
I
areas
considered.
It
also
indicated
that
CAIR
emissions
697
reductions
as
modeled
produce
significantly
greater
visibility
improvements
than
source­
specific
BART.

Specifically,
for
the
15
Eastern
Class
I
areas
analyzed,
the
average
visibility
improvement
(
on
the
20
percent
worst
days)
expected
solely
as
a
result
of
the
CAIR
was
2.0
deciviews,
and
the
average
degree
of
improvement
predicted
for
source­
specific
BART
was
1.0
deciviews.
Similarly,
on
a
national
basis,
the
visibility
modeling
showed
that
for
all
44
Class
I
areas
evaluated,
the
average
visibility
improvement,
on
the
20
percent
worst
days,
in
2015
was
0.7
deciviews
under
the
CAIR
cap
and
trade
program,
but
only
0.4
deciviews
under
the
source­
specific
BART
approach.

b.
Comments
and
EPA
Responses
Several
commenters
noted
that
EPA
did
not
model
the
"
correct"
emissions
scenarios
to
compare
the
CAIR
and
BART
controls.
They
suggested
that
a
model
run
with
the
CAIR
controls
in
the
East
and
BART
controls
in
the
West
should
be
compared
to
a
model
run
with
nationwide
BART
controls.

The
EPA
agrees
(
as
we
have
already
noted
in
the
SNPR)

that
the
suggested
comparison
of
model
runs
is
a
more
appropriate
comparison
of
the
CAIR
and
BART.
The
SNPR
better­
than­
BART
analysis
was
limited
by
the
availability
of
the
model
results
at
the
time.
For
the
NFR,
we
have
modeled
nationwide
BART
for
EGUs
as
proposed
in
the
May
2004
guidelines
and
a
separate
scenario
consisting
of
CAIR
698
160
Because
the
presumptive
controls
in
the
BART
guidelines
are
applicable
to
coal­
fired
EGUs,
the
BART
analysis
does
not
assume
controls
on
oil­
and
gas­
fired
units.
However,
NOx
emissions
from
all
(
not
just
BART­
eligible)
oil
and
gas
steam
plants
and
simple
cycle
turbines
in
the
CAIR
region
in
the
2010
base
case
are
projected
to
be
about
40,000
tons,
or
less
than
1.5%
of
the
projected
total
2010
EGU
emissions.
By
comparison,
the
modeling
of
the
scenario
of
the
CAIR
(
with
BART
in
the
non­
CAIR
region)
resulted
in
640,000
tons
of
NOx
per
year
less
than
the
projected
emissions
under
a
nationwide
BART
scenario.
Therefore,
even
if
the
40,000
tons
of
NOx
emissions
from
oil
and
gas
EGUs
were
reduced
to
zero
under
the
BART
scenario,
the
CAIR
will
still
produce
significantly
greater
emission
reductions
than
BART.
Also,
not
all
of
the
oil
and
gas
units
associated
with
those
40,000
tons
would
be
eligible
for
BART.
The
IPM
does
not
predict
any
difference
in
SO2
emissions
from
oil
or
gas
fired
units
between
the
CAIR
and
BART.
161
See
"
Memo
From
Perrin
Quarles
Associates,
Inc.
Re
Follow­
Up
on
Units
Potentially
Affected
by
BART,
July
19,
2004,"
as
Appendix
A
to
the
"
Better
than
BART"
TSD.
reductions
in
the
CAIR­
affected
States
plus
BART­
reductions
in
the
remaining
States
(
excluding
Alaska
and
Hawaii).

Additionally,
we
have
improved
the
BART
control
assumptions
(
in
both
scenarios)
by
increasing
the
number
of
BARTeligible
units
included.
Specifically,
in
the
SNPR
analysis,
controls
were
"
required"
(
i.
e.,
assumed
by
the
model)
for
BART­
eligible
EGUs
greater
than
250
MW
capacity,

for
both
NOx
and
SO2.
For
today's
action,
BART
controls
are
assumed
for
SO2
for
all
BART­
eligible
EGU
units
greater
than
100
MW,
and
NOx
controls
for
all
BART­
eligible
EGU
units
greater
than
25
MW.
160
This,
along
with
a
review
of
potentially
BART­
eligible
EGUs,
has
expanded
the
universe
of
units
assumed
subject
to
BART
in
the
modeling
from
302
to
491.161
699
162
Some
Class
I
areas
do
not
have
IMPROVE
monitors
and
are
represented
by
nearby
IMPROVE
sites.
163
This
is
the
number
of
IMPROVE
sites
that
are
located
at
or
represent
Class
I
areas.
There
are
additional
IMPROVE
protocol
monitoring
sites
that
are
not
located
at
Class
I
areas.
Several
commenters
noted
that
the
better­
than­
BART
visibility
analysis
only
covered
44
Class
I
areas
and
did
not
adequately
address
visibility
in
all
areas
of
the
country.

For
the
NFR,
we
have
significantly
expanded
the
number
of
Class
I
areas
covered
by
the
analysis.
The
NPR
and
SNPR
visibility
analysis
was
limited
by
the
availability
of
observed
data
from
Inter­
agency
Monitoring
of
Protected
Visual
Environments
(
IMPROVE)
monitors
during
the
meteorological
modeling
year
of
1996.
There
was
complete
IMPROVE
data
at
44
IMPROVE
sites
which
represented
68
Class
I
areas.
162
All
of
the
regions
of
the
country
(
as
defined
by
IMPROVE)
were
represented
by
at
least
one
site,
except
the
Northern
Great
Lakes
region.
For
the
final
rule,
the
modeling
has
been
updated
to
use
a
meteorological
year
of
2001.
Therefore,
the
IMPROVE
data
for
2001
was
used
for
the
NFR
better­
than­
BART
analysis.
For
2001,
there
were
81
IMPROVE
sites
with
complete
data,
163
representing
116
Class
I
areas.
The
NFR
analysis
accounts
for
visibility
changes
at
80
percent
of
the
active
IMPROVE
sites
in
the
lower
48
States.
More
importantly
for
today's
rulemaking,
the
number
700
164
There
are
5
Class
I
areas
in
the
East
and
33
Class
I
areas
in
the
West
(
outside
of
the
CAIR
control
region)
that
do
not
have
complete
IMPROVE
data
for
2001.
165
"
Demonstration
that
CAIR
Satisfies
the
`
Better­
than­
BART'
Test
As
proposed
in
the
Guidelines
for
Making
BART
Determinations,"
March,
2005.
of
Class
I
areas
in
the
East
has
been
increased
from
15
to
29
and
now
covers
all
IMPROVE­
defined
visibility
regions
within
the
CAIR­
affected
States,
including
the
Northern
Great
Lakes.
164
We,
therefore,
believe
the
expanded
geographic
scope
of
Class
I
areas
covered
is
sufficient
for
purposes
of
this
analysis.

c.
Today's
Action
We
have
compared
the
two
model
runs
(
BART
nationwide
and
BART
in
the
West
with
the
CAIR
in
the
East)
using
the
proposed
two­
pronged
better­
than­
BART
test.
The
results
were
analyzed
at
the
116
Class
I
areas
that
have
complete
IMPROVE
data
for
2001
or
are
represented
by
IMPROVE
monitors
with
complete
data.
Twenty
nine
of
the
Class
I
areas
are
in
the
East
and
87
are
in
the
West.
Detailed
modeling
results
for
all
116
Class
I
areas
are
contained
in
the
Better­
than­

BART
TSD.
165
Results
applicable
to
the
better­
than­
BART
proposed
two­
pronged
test
are
summarized
below.

The
updated
visibility
analysis
reaffirms
that
under
the
proposed
two­
pronged
test,
CAIR
controls
are
better
than
BART
for
EGUs.
The
modeling
predicts
that
the
CAIR
cap
and
trade
program
will
not
result
in
degradation
of
visibility
701
166
See
Better­
than
BART
TSD
for
results
at
each
Class
I
Area.
on
the
20
percent
best
or
20
percent
worst
days
compared
to
the
2015
baseline
conditions,
at
any
of
the
116
Class
I
areas
considered.
166
With
respect
to
the
greater­
average­
improvement
prong,

the
modeling
indicates
that
CAIR
emissions
reductions
in
the
East
produce
significantly
greater
visibility
improvements
than
source­
specific
BART.
Specifically,
for
the
29
Eastern
Class
I
areas
analyzed,
the
average
visibility
improvement,

on
the
20
percent
worst
days,
expected
solely
as
a
result
of
the
CAIR
applied
in
the
East
and
BART
applied
in
the
West
is
1.6
dv,
as
compared
to
the
average
degree
of
improvement
predicted
for
nationwide
source­
specific
BART
of
0.7
dv.

Similarly,
on
a
national
basis,
the
visibility
modeling
showed
that
for
all
116
Class
I
areas
evaluated,
the
average
visibility
improvement,
on
the
20
percent
worst
days,
in
2015
was
0.5
dv
under
the
CAIR
cap
and
trade
program
in
the
East
and
BART
in
the
West,
but
only
0.2
deciviews
under
the
nationwide
source­
specific
BART
approach.

The
modeling
showed
similar
results
for
the
20
percent
best
visibility
days,
although
there
is
less
visibility
improvement
on
the
best
days
compared
to
the
worst
days.

For
the
29
Eastern
Class
I
areas
analyzed,
the
average
visibility
improvement,
on
the
20
percent
best
days,
702
167
Eastern
Class
I
areas
are
those
in
the
CAIR
affected
states,
except
areas
in
west
Texas
which
are
considered
western
and
therefore
included
in
the
national
average,
plus
those
in
New
England.
expected
solely
as
result
of
the
CAIR
applied
in
the
East
and
BART
applied
in
the
West
is
0.4
dv,
as
compared
to
the
average
degree
of
improvement
predicted
for
nationwide
source­
specific
BART
of
0.2
dv.
On
a
national
basis,
the
visibility
modeling
showed
that
for
all
116
class
I
areas
evaluated,
the
average
visibility
improvement,
on
the
20
percent
best
days,
in
2015
was
0.1
dv
under
both
the
CAIR
cap
and
trade
program
in
the
East
and
BART
in
the
West,
and
under
the
nationwide
source­
specific
BART
approach.
The
results
are
summarized
in
table
IX­
1.

Table
IX­
1
Average
Visibility
Improvement
in
2015
vs.
2015
Base
Case
(
deciviews)

CAIR
+
BART
in
West
Nationwide
BART
Class
I
Areas
East167
National
East
National
20%
Worst
Days
1.6
0.5
0.7
0.2
20%
Best
Days
0.4
0.1
0.2
0.1
The
results
clearly
indicate
that
the
CAIR
will
achieve
greater
reasonable
progress
than
BART
as
proposed,
measured
by
the
proposed
better­
than­
BART
test.
At
this
time,
we
can
foresee
no
circumstances
under
which
BART
for
EGUs
could
produce
greater
visibility
improvement
than
the
CAIR.

However,
for
the
reasons
noted
in
section
IX.
C.
1.
above,
we
are
deferring
a
final
determination
of
whether
the
CAIR
703
makes
greater
reasonable
progress
than
BART
until
the
BART
guidelines
for
EGUs
and
the
criteria
for
BART­
alternative
programs
are
finalized.

D.
How
Will
EPA
Handle
State
Petitions
Under
Section
126
of
the
CAA?

Section
126
of
the
CAA
authorizes
a
downwind
State
to
petition
EPA
for
a
finding
that
any
new
(
or
modified)
or
existing
major
stationary
source
or
group
of
stationary
sources
upwind
of
the
State
emits
or
would
emit
in
violation
of
the
prohibition
of
section
110(
a)(
2)(
D)(
i)
because
their
emissions
contribute
significantly
to
nonattainment,
or
interfere
with
maintenance,
of
a
NAAQS
in
the
State.
If
EPA
makes
such
a
finding,
EPA
is
authorized
to
directly
regulate
the
affected
sources.
Section
126
relies
on
the
same
statutory
provision
that
underlies
the
CAIR.

In
the
January
30,
2004
CAIR
proposal,
EPA
set
forth
its
general
view
of
the
approach
it
expected
to
take
in
responding
to
any
section
126
petition
that
might
be
submitted
which
relies
on
essentially
the
same
record
as
the
CAIR.
That
approach
is
the
one
EPA
used
in
addressing
section
126
petitions
that
were
submitted
to
EPA
in
1997
while
EPA
was
developing
the
NOx
SIP
Call
to
control
ozone
transport.
In
the
NOx
SIP
Call
rule,
we
determined
under
section
110(
a)(
2)(
D)
that
the
SIP
for
each
affected
State
(
and
the
District
of
Columbia)
must
be
revised
to
eliminate
704
the
amount
of
emissions
that
contributes
significantly
to
nonattainment
in
downwind
States.
The
emissions
reductions
requirement
was
based
on
the
quantity
of
emissions
that
could
be
eliminated
by
the
application
of
highly
costeffective
controls
on
specified
sources
in
that
State.
In
May
1999,
shortly
after
promulgation
of
the
NOx
SIP
Call,

EPA
took
final
action
on
the
section
126
petitions
(
64
FR
28250;
May
25,
1999).
The
Section
126
action
relied
on
essentially
the
same
record
as
the
NOx
SIP
Call.
In
addition,
we
established
a
section
126
remedy
based
on
the
same
set
of
highly
cost­
effective
controls.
In
the
May
1999
Section
126
Rule,
we
determined
which
petitions
had
technical
merit,
but
we
stopped
short
of
granting
the
findings
for
the
petitions.
Instead,
we
stated
that
because
we
had
promulgated
the
NOx
SIP
Call
­
a
transport
rule
under
section
110(
a)(
2)(
D)
­
as
long
as
an
upwind
State
remained
on
track
to
comply
with
that
rule,
EPA
would
defer
making
the
section
126
findings.
The
findings
would
be
triggered
at
either
of
two
future
dates
if
specified
progress
had
not
been
made
by
those
times.
The
Section
126
Rule
included
a
provision
under
which
the
rule
would
be
automatically
withdrawn
for
sources
in
a
State
once
that
State
submitted
and
EPA
fully
approved
a
SIP
that
complied
with
the
NOx
SIP
Call.
(
See
64
FR
28271­
28274;
May
25,
1999.)
The
reason
for
this
withdrawal
would
be
the
fact
that
the
affected
State's
705
SIP
revision
would
fulfill
the
section
110(
a)(
2)(
D)

requirements,
so
that
there
would
no
longer
be
any
basis
for
the
section
126
finding
with
respect
to
that
State.
In
this
manner,
the
NOx
SIP
Call
and
the
Section
126
Rules
would
be
harmonized.

Under
the
CAIR
proposal,
EPA
received
comments
regarding
its
intended
approach
for
acting
on
any
future
section
126
petitions
that
might
be
filed.
Many
commenters
expressed
support
for
the
approach
that
EPA
had
outlined.

Other
commenters
raised
issues
regarding
the
timing
of
emissions
reductions
under
a
new
section
126
action.
Some
pointed
out
that
the
CAIR
compliance
date
would
be
later
than
the
3
years
allowed
for
compliance
under
section
126.

Some
were
concerned
that
the
proposed
CAIR
compliance
date
is
later
than
many
attainment
dates
and
States
may
need
section
126
petitions
in
order
to
get
earlier
upwind
reductions
in
order
to
meet
their
attainment
dates.
Some
questioned
the
legal
basis
for
linking
the
two
rules.

Several
commenters
expressed
concern
that
EPA
would
be
restricting
the
use
of
or
weakening
the
section
126
provision.
A
number
of
commenters
urged
EPA
not
to
prejudge
any
petition,
but
to
evaluate
each
on
its
own
merit.
Some
thought
that
any
petitions
submitted
prior
to
designations
or
before
States
had
had
the
opportunity
to
prepare
SIPs
would
be
premature
and
should
be
denied.
Others
suggested
706
that
CAIR
might
not
solve
all
the
transport
problems
and
that
States
would
need
to
retain
the
section
126
tool
to
seek
further
reductions.

After
issuing
the
CAIR
proposal,
EPA
received,
on
March
19,
2004,
a
section
126
petition
from
North
Carolina
seeking
reductions
in
upwind
NOx
and
SO2
for
purposes
of
reducing
PM2.5
and
8­
hour
ozone
levels
in
North
Carolina.
The
petition
relies
in
large
part
on
the
technical
record
for
the
proposed
CAIR.

When
we
propose
action
on
the
North
Carolina
petition,

we
will
set
forth
our
view
of
the
interaction
between
section
110(
a)(
2)(
D)
and
section
126.
In
that
proposal,
we
will
take
into
consideration
and
respond
to
the
section
126­

related
comments
we
received
on
the
CAIR.
The
EPA
will
provide
a
comment
period
and
opportunity
for
a
public
hearing
on
the
specifics
of
that
section
126
proposal,

including
an
opportunity
to
comment
on
our
view
of
the
interaction
of
the
2
statutory
provisions.

E.
Will
Sources
Subject
to
CAIR
Also
Be
Subject
To
New
Source
Review?

The
EPA
did
not
propose
any
provisions
in
the
CAIR
related
to
new
source
review
(
NSR).
Nonetheless,
we
received
some
comments
on
the
relationship
between
CAIR
and
the
NSR
provisions
that
may
apply
to
emissions
sources
also
impacted
by
the
CAIR.
Many
commenters
indicated
that
if
an
707
168See
40
CFR
51.165(
a)(
1)(
xxv)
and
51.165(
e),
40
CFR
51.166
(
b)(
31)
and
51.166(
v),
and
40
CFR
51.21(
b)(
32)
and
52.21(
z).
EGU
is
part
of
an
EPA­
administered
regional
cap
and
trade
program
for
NOx
and
SO2,
then
that
EGU
should
be
exempted
from
NSR
for
the
covered
pollutants.
The
commenters
cited
Clear
Skies
legislation
as
containing
provisions
affecting
NSR
for
covered
sources.
In
this
final
rule,
EPA
is
not
addressing
or
revising
the
provisions
of
NSR.

It
should
be
noted
that
pollution
control
measures
implemented
by
EGUs
in
compliance
with
the
CAIR
may
be
eligible
for
an
exemption
under
the
NSR
pollution
control
project
provision.
168
These
provisions
provide
an
exemption
from
major
NSR
for
controls
such
as
selective
catalytic
reduction
(
SCR)
for
NOx
control
and
wet
scrubbers
for
SO2
control,
provided
that
certain
conditions
identified
in
the
provisions
are
met.

X.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,

1993),
the
Agency
must
determine
whether
a
regulatory
action
is
"
significant"
and
therefore
subject
to
Office
of
Management
and
Budget
(
OMB)
review
and
the
requirements
of
the
Executive
Order.
The
Order
defines
"
significant
regulatory
action"
as
one
that
is
likely
to
result
in
a
rule
that
may:
708
1.
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
Tribal
governments
or
communities;

2.
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;

3.
Materially
alter
the
budgetary
impact
of
entitlements,

grants,
user
fees,
or
loan
programs
or
the
rights
and
obligations
of
recipients
thereof;
or
4.
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.

In
view
of
its
important
policy
implications
and
potential
effect
on
the
economy
of
over
$
100
million,
this
action
has
been
judged
to
be
an
economically
"
significant
regulatory
action"
within
the
meaning
of
the
Executive
Order.
As
a
result,
today's
action
was
submitted
to
OMB
for
review,
and
EPA
has
prepared
an
economic
analysis
of
the
rule
entitled
"
Regulatory
Impact
Analysis
of
the
Final
Clean
Air
Interstate
Rule"
(
March
2005).

1.
What
Economic
Analyses
Were
Conducted
for
the
Rulemaking?
709
The
analyses
conducted
for
this
final
rule
provide
several
important
analyses
of
impacts
on
public
welfare.

These
include
an
analysis
of
the
social
benefits,
social
costs,
and
net
benefits
of
the
regulatory
scenario.
The
economic
analyses
also
address
issues
involving
small
business
impacts,
unfunded
mandates
(
including
impacts
for
Tribal
governments),
environmental
justice,
children's
health,
energy
impacts,
and
requirements
of
the
Paperwork
Reduction
Act
(
PRA).

2.
What
Are
the
Benefits
and
Costs
of
this
Rule?

The
benefit­
cost
analysis
shows
that
substantial
net
economic
benefits
to
society
are
likely
to
be
achieved
due
to
reductions
in
emissions
resulting
from
this
rule.
The
results
detailed
below
show
that
this
rule
would
be
highly
beneficial
to
society,
with
annual
net
benefits
(
benefits
less
costs)
of
approximately
$
71.4
or
$
60.4
billion
in
2010
and
$
98.5
or
$
83.2
billion
in
2015.
These
alternative
net
benefits
estimates
occur
due
to
differing
assumptions
concerning
the
social
discount
rate
used
to
estimate
the
annual
value
of
the
benefits
and
costs
of
the
rule
with
the
lower
estimates
relating
to
a
discount
rate
of
7
percent
and
the
higher
estimates
a
discount
rate
of
3
percent.
All
amounts
are
reflected
in
1999
dollars.

The
benefits
and
costs
reported
for
the
CAIR
represent
estimates
for
the
final
CAIR
program
that
includes
the
CAIR
710
promulgated
rule
and
the
concurrent
proposal
to
include
annual
SO2
and
NOx
controls
for
New
Jersey
and
Delaware.

The
modeling
used
to
provide
these
estimates
also
assumes
annual
SO2
and
NOx
controls
for
Arkansas
that
are
not
a
part
of
the
final
CAIR
program
resulting
in
a
slight
overstatement
of
the
reported
benefits
and
costs.

a.
Control
Scenario
Today's
rule
sets
forth
requirements
for
States
to
eliminate
their
significant
contribution
to
down­
wind
nonattainment
of
the
ozone
and
PM2.5
NAAQS.
In
order
to
reduce
this
significant
contribution,
EPA
requires
that
certain
States
reduce
their
emissions
of
SO2
and
NOx.
The
EPA
derived
the
quantities
by
calculating
the
amount
of
SO2
and
NOx
emissions
that
EPA
believes
can
be
controlled
from
the
electric
power
industry
in
a
highly
cost­
effective
manner.
The
EPA
considered
all
promulgated
CAA
requirements
and
known
State
actions
in
the
baseline
used
to
develop
the
estimates
of
benefits
and
costs
for
this
rule.
For
a
more
complete
description
of
the
reduction
requirements
and
how
they
were
calculated,
see
section
IV
of
today's
rulemaking.

Although
States
may
choose
to
obtain
the
emissions
reductions
from
other
source
categories,
for
purposes
of
analyzing
the
impacts
of
the
rule,
EPA
is
assuming
the
application
of
the
controls
that
it
has
identified
to
be
highly
cost
effective
on
all
EGUs
in
the
transport
region.
711
b.
Cost
Analysis
and
Economic
Impacts
For
the
affected
region,
the
projected
annual
private
incremental
costs
of
the
CAIR
to
the
power
industry
are
$
2.4
billion
in
2010
and
$
3.6
billion
in
2015.
These
costs
represent
the
private
compliance
cost
to
the
electric
generating
industry
of
reducing
NOx
and
SO2
emissions
to
meet
the
caps
set
forth
in
the
rule.
Estimates
are
in
1999
dollars.

In
estimating
the
net
benefits
of
regulation,
the
appropriate
cost
measure
is
"
social
costs."
Social
costs
represent
the
welfare
costs
of
the
rule
to
society.
These
costs
do
not
consider
transfer
payments
(
such
as
taxes)
that
are
simply
redistributions
of
wealth.
The
social
costs
of
this
rule
are
estimated
to
be
approximately
$
1.9
billion
in
2010
and
$
2.6
billion
in
2015
assuming
a
3
percent
discount
rate.
These
costs
become
$
2.1
billion
in
2010
and
$
3.1
billion
in
2015
assuming
a
7
percent
discount
rate.

Overall,
the
impacts
of
the
CAIR
are
modest,

particularly
in
light
of
the
large
benefits
we
expect.

Ultimately,
we
believe
the
industry
will
pass
along
most
of
the
costs
of
the
rule
to
consumers,
so
that
the
costs
of
the
rule
will
largely
fall
upon
the
consumers
of
electricity.

Retail
electricity
prices
are
projected
to
increase
roughly
2.0­
2.7
percent
with
the
CAIR
in
the
2010
and
2015
712
timeframe,
and
then
drop
below
the
2.0
percent
increase
level
thereafter.
The
effects
of
the
CAIR
on
natural
gas
prices
and
the
power­
sector
generation
mix
are
relatively
small,
with
a
1.6
percent
or
less
increase
in
natural
gas
prices
projected
from
2010
to
2020.
There
will
be
continued
reliance
on
coal­
fired
generation,
that
is
projected
to
remain
at
roughly
50
percent
of
total
electricity
generated.

A
relatively
small
amount
of
coal­
fired
capacity,
about
5.3
GW
(
1.7
percent
of
all
coal­
fired
capacity
and
0.5
percent
of
all
generating
capacity),
is
projected
to
be
uneconomic
to
maintain.
For
the
most
part,
these
units
are
small
and
infrequently
used
generating
units
that
are
dispersed
throughout
the
CAIR
region.
Units
projected
to
be
uneconomic
to
maintain
may
be
"
mothballed,"
retired,
or
kept
in
service
to
ensure
transmission
reliability
in
certain
parts
of
the
grid.
The
EPA's
analysis
does
not
address
these
choices.

As
demand
grows
in
the
future,
additional
coal­
fired
generation
is
projected
to
be
built
under
the
CAIR.
As
a
result,
coal
production
for
electricity
generation
is
projected
to
increase
from
2003
levels
by
about
15
percent
in
2010
and
25
percent
by
2020,
and
we
expect
a
small
shift
towards
greater
coal
production
in
Appalachia
and
the
interior
coal
regions
of
the
country
with
the
CAIR.
713
For
today's
rule,
EPA
analyzed
the
costs
using
the
Integrated
Planning
Model
(
IPM).
The
IPM
is
a
dynamic
linear
programming
model
that
can
be
used
to
examine
the
economic
impacts
of
air
pollution
control
policies
for
SO2
and
NOx
throughout
the
contiguous
U.
S.
for
the
entire
power
system.
Documentation
for
IPM
can
be
found
in
the
docket
for
this
rulemaking
or
at
www.
epa.
gov/
airmarkets/
epa­
ipm.

c.
Human
Health
Benefit
Analysis
Our
analysis
of
the
health
and
welfare
benefits
anticipated
from
this
rule
are
presented
in
this
section.

Briefly,
the
analysis
projects
major
benefits
from
implementation
of
the
rule
in
2010
and
2015.
As
described
below,
thousands
of
deaths
and
other
serious
health
effects
would
be
prevented.
We
are
able
to
monetize
annual
benefits
of
approximately
$
73.3
or
$
62.6
billion
in
2010
(
based
upon
a
3
percent
or
7
percent
discount
rate,
respectively)
and
$
101
billion
or
$
86.3
billion
in
2015
(
based
upon
a
discount
rate
of
3
percent
or
7
percent,
respectively,
1999
dollars).

Table
X­
1
presents
the
primary
estimates
of
reduced
incidence
of
PM­
and
ozone­
related
health
effects
for
the
years
2010
and
2015
for
the
regulatory
control
strategy.
In
2015,
we
estimate
that
PM­
related
annual
benefits
include
approximately
17,000
fewer
premature
fatalities,
8,700
fewer
cases
of
chronic
bronchitis,
22,000
fewer
non­
fatal
heart
attacks,
10,500
fewer
hospitalizations
(
for
respiratory
and
714
169
Thurston,
G.
D.
and
K.
Ito.
2001.
"
Epidemiological
Studies
of
Acute
Ozone
Exposures
and
Mortality".
J
Expo
Anal
Environ
Epidemiology
11
(
4):
286­
294.
cardiovascular
disease
combined)
and
result
in
significant
reductions
in
days
of
restricted
activity
due
to
respiratory
illness
(
with
an
estimate
of
9.9
million
fewer
cases)
and
approximately
1,700,000
fewer
work­
loss
days.
We
also
estimate
substantial
health
improvements
for
children
from
reduced
upper
and
lower
respiratory
illness,
acute
bronchitis,
and
asthma
attacks.

Ozone
health­
related
benefits
are
expected
to
occur
during
the
summer
ozone
season
(
usually
ranging
from
May
to
September
in
the
Eastern
U.
S.).
Based
upon
modeling
for
2015,
annual
ozone­
related
health
benefits
are
expected
to
include
2,800
fewer
hospital
admissions
for
respiratory
illnesses,
280
fewer
emergency
room
admissions
for
asthma,

690,000
fewer
days
with
restricted
activity
levels,
and
510,000
fewer
days
where
children
are
absent
from
school
due
to
illnesses.

While
we
did
not
include
in
our
primary
benefits
analysis
separate
estimates
of
the
number
of
premature
deaths
that
would
be
avoided
due
to
reductions
in
ozone
levels,
recent
studies
suggest
a
link
between
short­
term
ozone
exposures
with
premature
mortality
independent
of
PM
exposures.
Based
upon
a
recent
report
by
Thurston
and
Ito,

(
2001),
169
the
EPA
Science
Advisory
Board
has
recommended
715
170
Bell,
M.
L.,
A.
McDermott,
S.
Zeger,
J.
Samet,
F.
Dominichi.
2005.
"
Ozone
and
Mortality
in
95
U.
S.
Urban
Communities
from
1987
to
2000."
Journal
of
the
American
Medical
Association.
Forthcoming.
that
EPA
reevaluate
the
ozone
mortality
literature
for
possible
inclusion
of
ozone
mortality
in
the
estimate
of
total
benefits.
More
recently,
a
comprehensive
analysis
using
data
from
the
National
Morbidity,
Mortality
and
Air
Pollution
Study
(
NMMAPS)
found
a
significant
association
between
daily
ozone
levels
and
daily
mortality
rates
(
Bell
et
al.
2004).
170
The
analysis
estimated
a
0.5
percent
increase
in
daily
mortality
associated
with
a
10
ppb
increase
in
ozone,
based
on
data
from
95
major
urban
areas.

Using
a
similar
magnitude
effect
estimate,
sensitivity
analysis
estimates
suggest
that
in
2015,
the
CAIR
would
result
in
an
additional
500
fewer
premature
deaths
annually
due
to
reductions
in
daily
ambient
ozone
concentrations.

The
EPA
has
sponsored
three
independent
meta­
analyses
of
the
ozone
mortality
epidemiology
literature
to
inform
a
determination
on
inclusion
of
this
important
health
impact
in
the
primary
benefits
analysis
for
future
regulations.

Table
X­
2
presents
the
estimated
monetary
value
of
reductions
in
the
incidence
of
health
and
welfare
effects.

Annual
PM­
related
and
ozone­
related
health
benefits
are
estimated
to
be
approximately
$
72.1
or
$
61.4
billion
in
2010
(
3
percent
and
7
percent
discount
rate,
respectively)
and
716
$
99.3
or
$
84.5
billion
in
2015
(
3
percent
or
7
percent
discount
rate,
respectively).
Estimated
annual
visibility
benefits
in
southeastern
Class
I
areas
are
approximately
$
1.14
billion
in
2010
and
$
1.78
billion
in
2015.
All
monetized
estimates
are
stated
in
1999$.
These
estimates
account
for
growth
in
real
gross
domestic
product
(
GDP)
per
capita
between
the
present
and
the
years
2010
and
2015.
As
the
table
indicates,
total
benefits
are
driven
primarily
by
the
reduction
in
premature
fatalities
each
year,
that
accounts
for
over
90
percent
of
total
benefits.

Table
X­
3
presents
the
total
monetized
net
benefits
for
the
years
2010
and
2015.
This
table
also
indicates
with
a
"
B"
those
additional
health
and
environmental
benefits
of
the
rule
that
we
were
unable
to
quantify
or
monetize.
These
effects
are
additive
to
the
estimate
of
total
benefits.
A
listing
of
the
benefit
categories
that
could
not
be
quantified
or
monetized
in
our
benefit
estimates
are
provided
in
Table
X­
4.
We
are
not
able
to
estimate
the
magnitude
of
these
unquantified
and
unmonetized
benefits.

While
EPA
believes
there
is
considerable
value
to
the
public
for
the
PM­
related
benefit
categories
that
could
not
be
monetized,
we
believe
these
benefits
may
be
small
relative
to
those
categories
we
were
able
to
quantify
and
monetize.

In
contrast,
EPA
believes
the
monetary
value
of
the
ozonerelated
premature
mortality
benefits
could
be
substantial.
717
As
previously
discussed,
we
estimate
that
ozone
mortality
benefits
may
yield
as
many
as
500
reduced
premature
mortalities
per
year
and
may
increase
the
benefits
of
CAIR
by
approximately
$
3
billion
annually.

d)
Quantified
and
Monetized
Welfare
Benefits
Only
a
subset
of
the
expected
visibility
benefits
­

those
for
Class
I
areas
in
the
southeastern
U.
S.
are
included
in
the
monetary
benefits
estimates
we
project
for
this
rule.
We
believe
the
benefits
associated
with
these
non­
health
benefit
categories
are
likely
significant.
For
example,
we
are
able
to
quantify
significant
visibility
improvements
in
Class
I
areas
in
the
Northeast
and
Midwest,

but
are
unable
at
present
to
place
a
monetary
value
on
these
improvements.
Similarly,
we
anticipate
improvement
in
visibility
in
residential
areas
where
people
live,
work
and
recreate
within
the
CAIR
region
for
which
we
are
currently
unable
to
monetize
benefits.
For
the
Class
I
areas
in
the
southeastern
U.
S.,
we
estimate
annual
benefits
of
$
1.78
billion
beginning
in
2015
for
visibility
improvements.
The
value
of
visibility
benefits
in
areas
where
we
were
unable
to
monetize
benefits
could
also
be
substantial.

We
also
quantify
nitrogen
and
sulfur
deposition
reductions
expected
to
occur
as
a
result
of
the
CAIR
and
discuss
potential
benefits
from
these
reductions
in
section
X.
A.
4
of
this
preamble.
While
we
are
unable
to
estimate
a
718
dollar
value
associated
with
these
benefits,
we
are
able
to
quantify
acidification
improvements
in
lakes
in
the
Northeast
including
the
Adirondacks
and
potential
benefits
of
reductions
in
nitrogen
deposition
to
estuaries
such
as
the
Chesapeake
Bay.

TABLE
X­
1.
Estimated
Annual
Reductions
in
Incidence
of
Health
Effectsa
Health
Effect
2010
Annual
Incidence
Reduction
2015
Annual
Incidence
Reduction
PM­
Related
Endpoints:

Premature
Mortalityb,
c
Adult,
age
30
and
over
Infant,
age
<
1
year
13,000
29
17,000
36
Chronic
bronchitis
(
adult,
age
26
and
over)
6,900
8,700
Non­
fatal
myocardial
infarction
(
adult,
age
18
and
over)
17,000
22,000
Hospital
admissions
­
respiratory
(
all
ages)
d
4,300
5,500
Hospital
admissions
­
cardiovascular
(
adults,
age
>
18)
e
3,800
5,000
Emergency
room
visits
for
asthma
(
age
18
years
and
younger)
10,000
13,000
Acute
bronchitis,
(
children,
age
8­
12)
16,000
19,000
Lower
respiratory
symptoms
(
children,
age
7­
14)
190,000
230,000
Upper
respiratory
symptoms
(
asthmatic
children,
age
9­
18)
150,000
180,000
Asthma
exacerbation
(
asthmatic
children,
age
6­
18)
240,000
290,000
Work
Loss
Days
1,400,000
1,700,000
Minor
restricted
activity
days
(
adults
age
18­
65)
8,100,000
9,900,000
Ozone­
Related
Endpoints:

Hospital
admissions­
respiratory
causes
(
adult,
65
and
older)
f
610
1,700
Hospital
admissions
­
respiratory
380
1,100
719
171Pope,
C.
A.,
III,
R.
T.
Burnett,
M.
J.
Thun,
E.
E.
Calle,
D.
Krewski,
K.
Ito,
and
G.
D.
Thurston.
2002.
"
Lung
Cancer,
Cardiopulmonary
Mortality,
and
Long­
term
Exposure
to
Fine
Particulate
Air
Pollution."
Journal
of
American
Medical
Association
287:
1132­
1141.
172Woodruff,
T.
J.,
J.
Grillo,
and
K.
C.
Schoendorf.
1997.
"
The
Relationship
Between
Selected
Causes
of
Postneonatal
Infant
Mortality
and
Particulate
Infant
Mortality
and
Particulate
Air
Pollution
in
the
United
States."
Environmental
Health
Perspectives
105(
6):
608­
612.
causes
(
children,
under
2)

Emergency
room
visit
for
asthma
(
all
ages)
100
280
Minor
restricted
activity
days
(
adults,
age
18­
65)
280,000
690,000
School
absence
days
180,000
510,000
aIncidences
are
rounded
to
two
significant
digits.
These
estimates
represent
benefits
from
the
CAIR
nationwide.
The
modeling
used
to
derive
these
incidence
estimates
are
reflective
of
those
expected
for
the
final
CAIR
program
including
the
CAIR
promulgated
rule
and
the
proposal
to
include
annual
SO2
and
NOx
controls
for
New
Jersey
and
Delaware.
Modeling
used
to
develop
these
estimates
assumes
annual
SO2
and
NOx
controls
for
Arkansas
resulting
in
a
slight
overstatement
of
the
reported
benefits
and
costs
for
the
complete
CAIR
program.

bPremature
mortality
benefits
associated
with
ozone
are
not
analyzed
in
the
primary
analysis.
cAdult
mortality
based
upon
studies
by
Pope,
et
al
2002.171
Infant
mortality
based
upon
studies
by
Woodruff,
Grillo,
and
Schoendorf,
1997.172
d
Respiratory
hospital
admissions
for
PM
include
admissions
for
chronic
obstructive
pulmonary
disease
(
COPD),
pneumonia
and
asthma.
e
Cardiovascular
hospital
admissions
for
PM
include
total
cardiovascular
and
subcategories
for
ischemic
heart
disease,
dysrhythmias,
and
heart
failure.
f
Respiratory
hospital
admissions
for
ozone
include
admissions
for
all
respiratory
causes
and
subcategories
for
COPD
and
pneumonia.

TABLE
X­
2.
Estimated
Annual
Monetary
Value
of
Reductions
in
Incidence
of
Health
and
Welfare
Effects
(
Millions
of
1999$)
a,
b
Health
Effect
Pollutant
2010
Estimated
Value
of
Reductions
2015
Estimated
Value
of
Reductions
Premature
mortalityc,
d
Adult
>
30
years
3
percent
discount
rate
7
percent
discount
rate
Child
<
1
year
PM2.5
$
67,300
$
56,600
$
168
$
92,800
$
78,100
$
222
Chronic
bronchitis
(
adults,
26
and
over)
PM2.5
$
2,520
$
3,340
Non­
fatal
acute
myocardial
infarctions
3
percent
discount
rate
7
percent
discount
rate
PM2.5
$
1,420
$
1,370
$
1,850
$
1,790
720
173U.
S.
Environmental
Protection
Agency,
2000.
Guidelines
for
Preparing
Economic
Analyses.
www.
yosemite1.
epa.
gov/
ee/
epa/
eed/
hsf/
pages/
Guideline.
html.

Office
of
Management
and
Budget,
The
Executive
Office
of
the
President,
2003.
Circular
A­
4.
http://
www.
whitehouse.
gov/
omb/
circulars.
Hospital
admissions
for
respiratory
causes
PM2.5,
O3
$
45.2
$
78.9
Hospital
admissions
for
cardiovascular
causes
PM2.5
$
80.7
$
105
Emergency
room
visits
for
asthma
PM2.5,
O3
$
2.84
$
3.56
Acute
bronchitis
(
children,
age
8­
12)
PM2.5
$
5.63
$
7.06
Lower
respiratory
symptoms
(
children,
age
7­
14)
PM2.5
$
2.98
$
3.74
Upper
respiratory
symptoms
(
asthma,
age
9­
11)
PM2.5
$
3.80
$
4.77
Asthma
exacerbations
PM2.5
$
10.3
$
12.7
Work
loss
days
PM2.5,
$
180
$
219
Minor
restricted
activity
days
(
MRADs)
PM2.5,
O3
$
422
$
543
School
absence
days
O3
$
12.9
$
36.4
Worker
productivity
(
outdoor
workers,
age
18­
65)
O3
$
7.66
$
19.9
Recreational
visibility,
81
Class
I
areas
PM2.5
$
1,140
$
1,780
Monetized
Total
e
Base
estimate:
3
percent
discount
rate
7
percent
discount
rate
PM2.5,
O3
$
73,300
+
B
$
62,600
+
B
$
101,000
+
B
$
86,300
+
B
a
Monetary
benefits
are
rounded
to
three
significant
digits.
These
estimates
represent
benefits
from
the
CAIR
nationwide
for
NOx
and
SO2
emissions
reductions
from
electricity­
generating
units
sources
(
with
the
exception
of
ozone
and
visibility
benefits).
Ozone
benefits
relate
to
the
eastern
United
States.
Visibility
benefits
relate
to
Class
I
areas
in
the
southeastern
United
States.
The
benefit
estimates
reflected
relate
to
the
final
CAIR
program
that
includes
the
CAIR
promulgated
rule
and
the
proposal
to
include
annual
SO2
and
NOx
controls
for
New
Jersey
and
Delaware.
Modeling
used
to
develop
these
estimates
assumes
annual
SO2
and
NOx
controls
for
Arkansas
resulting
in
a
slight
overstatement
of
the
reported
benefits
and
costs
for
the
complete
CAIR
program.
b
Monetary
benefits
adjusted
to
account
for
growth
in
real
GDP
per
capita
between
1990
and
the
analysis
year
(
2010
or
2015).
c
Valuation
assumes
discounting
over
the
SAB
recommended
20
year
segmented
lag
structure
described
in
the
Regulatory
Impact
Analysis
for
the
Final
Clean
Air
Interstate
Rule
(
March
2005).
Results
show
3
percent
and
7
percent
discount
rates
consistent
with
EPA
and
OMB
guidelines
for
preparing
economic
analyses
(
US
EPA,
2000
and
OMB,
2003).
173
d
Adult
mortality
based
upon
studies
by
Pope
et
al
2002.
Infant
mortality
based
upon
studies
by
Woodruff,
Grillo,
and
Schoendorf,
1997.
e
B
represents
the
monetary
value
of
health
and
welfare
benefits
not
monetized.
A
detailed
listing
is
provided
in
Table
X­
4.
721
3.
How
Do
the
Benefits
Compare
to
the
Costs
of
This
Final
Rule?

The
estimated
annual
private
costs
to
implement
the
emission
reduction
requirements
of
the
final
rule
for
the
CAIR
region
are
$
2.36
in
2010
and
$
3.57
billion
in
2015
(
1999$).
These
costs
are
the
annual
incremental
electric
generation
production
costs
that
are
expected
to
occur
with
the
CAIR.
The
EPA
uses
these
costs
as
compliance
cost
estimates
in
developing
cost­
effectiveness
estimates.

In
estimating
the
net
benefits
of
regulation,
the
appropriate
cost
measure
is
`
social
costs.'
Social
costs
represent
the
welfare
costs
of
the
rule
to
society.
These
costs
do
not
consider
transfer
payments
(
such
as
taxes)
that
are
simply
redistributions
of
wealth.
The
social
costs
of
this
rule
are
estimated
to
be
approximately
$
1.9
billion
in
2010
and
$
2.6
billion
in
2015
assuming
a
3
percent
discount
rate.
These
costs
become
$
2.1
billion
in
2010
and
$
3.1
billion
in
2015,
if
one
assumes
a
7
percent
discount
rate.

Thus,
the
net
benefit
(
social
benefits
minus
social
costs)

of
the
program
is
approximately
$
71.4
+
B
billion
or
$
60.4
+

B
billion
(
3
percent
and
7
percent
discount
rate,

respectively)
annually
in
2010
and
$
98.5
+
B
billion
or
$
83.2
+
B
billion
annually
(
3
percent
and
7
percent
discount
rate,
respectively)
in
2015.
Implementation
of
the
rule
is
722
expected
to
provide
society
with
a
substantial
net
gain
in
social
welfare
based
on
economic
efficiency
criteria.

The
annualized
regional
cost
of
the
CAIR,
as
quantified
here,
is
EPA's
best
assessment
of
the
cost
of
implementing
the
CAIR,
assuming
that
States
adopt
the
model
cap
and
trade
program.
These
costs
are
generated
from
rigorous
economic
modeling
of
changes
in
the
power
sector
due
to
the
CAIR.

This
type
of
analysis
using
IPM
has
undergone
peer
review
and
been
upheld
in
Federal
courts.
The
direct
cost
includes,
but
is
not
limited
to,
capital
investments
in
pollution
controls,
operating
expenses
of
the
pollution
controls,
investments
in
new
generating
sources,
and
additional
fuel
expenditures.
The
EPA
believes
that
these
costs
reflect,
as
closely
as
possible,
the
additional
costs
of
the
CAIR
to
industry.
The
relatively
small
cost
associated
with
monitoring
emissions,
reporting,
and
recordkeeping
for
affected
sources
is
not
included
in
these
annualized
cost
estimates,
but
EPA
has
done
a
separate
analysis
and
estimated
the
cost
to
less
than
$
42
million
(
see
section
X.
B.,
Paperwork
Reduction
Act).
However,

there
may
exist
certain
costs
that
EPA
has
not
quantified
in
these
estimates.
These
costs
may
include
costs
of
transitioning
to
the
CAIR,
such
as
the
costs
associated
with
the
retirement
of
smaller
or
less
efficient
EGUs,
employment
shifts
as
workers
are
retrained
at
the
same
company
or
re­
723
employed
elsewhere
in
the
economy,
and
certain
relatively
small
permitting
costs
associated
with
title
IV
that
new
program
entrants
face.
Costs
may
be
understated
since
an
optimization
model
was
employed
that
assumes
cost
minimization,
and
the
regulated
community
may
not
react
in
the
same
manner
to
comply
with
the
rules.
Although
EPA
has
not
quantified
these
costs,
the
Agency
believes
that
they
are
small
compared
to
the
quantified
costs
of
the
program
on
the
power
sector.
The
annualized
cost
estimates
presented
are
the
best
and
most
accurate
based
upon
available
information.
In
a
separate
analysis,
EPA
estimates
the
indirect
costs
and
impacts
of
higher
electricity
prices
on
the
entire
economy
[
see
Regulatory
Impact
Analysis
for
the
Final
Clean
Air
Interstate
Rule,
Appendix
E
(
March
2005)].

The
costs
presented
here
are
EPA's
best
estimate
of
the
direct
private
costs
of
the
CAIR.
For
purposes
of
benefitcost
analysis
of
this
rule,
EPA
has
also
estimated
the
additional
costs
of
the
CAIR
using
alternate
discount
rates
for
calculating
the
social
costs,
parallel
to
the
range
of
discount
rates
used
in
the
estimates
of
the
benefits
of
the
CAIR
(
3
percent
and
7
percent).
Using
these
alternate
discount
rates,
the
social
costs
of
the
CAIR
are
$
1.9
billion
in
2010
and
$
2.6
billion
in
2015
using
a
discount
rate
of
3
percent,
and
$
2.1
billion
in
2010
and
$
3.1
billion
in
2015
using
a
discount
rate
of
7
percent.
The
costs
of
724
the
CAIR
using
the
adjusted
discount
rates
are
lower
than
the
private
costs
of
the
CAIR
generated
using
IPM
because
the
social
costs
do
not
include
certain
transfer
payments,

primarily
taxes,
that
are
considered
a
redistribution
of
wealth
rather
than
a
social
cost.

Table
X­
3.
Summary
of
Annual
Benefits,
Costs,
and
Net
Benefits
of
the
Clean
Air
Interstate
Rulea
(
Billions
of
1999
dollars)

Description
2010
(
Billions
of
1999
dollars)
2015
(
Billions
of
1999
dollars)

Social
Costsb
3
percent
discount
rate
7
percent
discount
rate
$
1.91
$
2.14
$
2.56
$
3.07
Social
Benefits
c,
d,
e
3
percent
discount
rate
7
percent
discount
rate
$
73.3
+
B
$
62.6
+
B
$
101
+
B
$
86.3
+
B
Health­
related
benefits
3
percent
discount
rate
7
percent
discount
rate
$
72.1
+
B
$
61.4
+
B
$
99.3
+
B
$
84.5
+
B
Visibility
benefits
$
1.14
+
B
$
1.78
+
B
Annual
Net
Benefits
(
Benefits­
Costs)
e,
f
3
percent
discount
rate
7
percent
discount
rate
$
71.4
+
B
$
60.4
+
B
$
98.5
+
B
$
83.2
+
B
a
All
estimates
are
rounded
to
three
significant
digits
and
represent
annualized
benefits
and
costs
anticipated
for
the
years
2010
and
2015.
Estimates
relate
to
the
complete
CAIR
program
including
the
CAIR
promulgated
rule
and
the
proposal
to
include
annual
SO2
and
NOx
controls
for
New
Jersey
and
Delaware.
Modeling
used
to
develop
these
estimates
assumes
annual
SO2
and
NOx
controls
for
Arkansas
resulting
in
a
slight
overstatement
of
the
reported
benefits
and
costs
for
the
complete
CAIR
program.
b
Note
that
costs
are
the
annual
total
costs
of
reducing
pollutants
including
NOx
and
SO2
in
the
CAIR
region.
c
As
this
table
indicates,
total
benefits
are
driven
primarily
by
PMrelated
health
benefits.
The
reduction
in
premature
fatalities
each
year
accounts
for
over
90
percent
of
total
monetized
benefits
in
2015.
Benefits
in
this
table
are
nationwide
(
with
the
exception
of
ozone
and
visibility)
and
are
associated
with
NOx
and
SO2
reductions
for
the
EGU
source
category.
Ozone
benefits
represent
benefits
in
the
eastern
United
States.
Visibility
benefits
represent
benefits
in
Class
I
areas
in
the
southeastern
United
States.
d
Not
all
possible
benefits
or
disbenefits
are
quantified
and
monetized
in
this
analysis.
B
is
the
sum
of
all
unquantified
benefits
and
725
174United
States
Environmental
Protection
Agency,
2000.
Guidelines
for
Preparing
Economic
Analyses.
www.
yosemite1.
epa.
gov/
ee/
epa/
eed/
hsf/
pages/
Guideline.
html.

Office
of
Management
and
Budget,
The
Executive
Office
of
the
President,
2003.
Circular
A­
4.
www.
http://
www.
whitehouse.
gov/
omb/
circulars.
disbenefits.
Potential
benefit
categories
that
have
not
been
quantified
and
monetized
are
listed
in
Table
X­
4.
e
Valuation
assumes
discounting
over
the
SAB­
recommended
20
year
segmented
lag
structure
described
in
chapter
4
of
the
Regulatory
Impact
Analysis
for
the
Clean
Air
Interstate
Rule
(
March
2005).
Results
reflect
3
percent
and
7
percent
discount
rates
consistent
with
EPA
and
OMB
guidelines
for
preparing
economic
analyses
(
U.
S.
EPA,
2000
and
OMB,
2003).
174
f
Net
benefits
are
rounded
to
the
nearest
$
100
million.
Columnar
totals
may
not
sum
due
to
rounding.

Every
benefit­
cost
analysis
examining
the
potential
effects
of
a
change
in
environmental
protection
requirements
is
limited
to
some
extent
by
data
gaps,
limitations
in
model
capabilities
(
such
as
geographic
coverage),
and
uncertainties
in
the
underlying
scientific
and
economic
studies
used
to
configure
the
benefit
and
cost
models.
Gaps
in
the
scientific
literature
often
result
in
the
inability
to
estimate
quantitative
changes
in
health
and
environmental
effects.
Gaps
in
the
economics
literature
often
result
in
the
inability
to
assign
economic
values
even
to
those
health
and
environmental
outcomes
that
can
be
quantified.
While
uncertainties
in
the
underlying
scientific
and
economics
literatures
(
that
may
result
in
overestimation
or
underestimation
of
benefits)
are
discussed
in
detail
in
the
economic
analyses
and
its
supporting
documents
and
references,
the
key
uncertainties
which
have
a
bearing
on
726
the
results
of
the
benefit­
cost
analysis
of
this
rule
include
the
following:

°
EPA's
inability
to
quantify
potentially
significant
benefit
categories;

°
Uncertainties
in
population
growth
and
baseline
incidence
rates;

°
Uncertainties
in
projection
of
emissions
inventories
and
air
quality
into
the
future;

°
Uncertainty
in
the
estimated
relationships
of
health
and
welfare
effects
to
changes
in
pollutant
concentrations
including
the
shape
of
the
C­
R
function,
the
size
of
the
effect
estimates,
and
the
relative
toxicity
of
the
many
components
of
the
PM
mixture;

°
Uncertainties
in
exposure
estimation;
and
°
Uncertainties
associated
with
the
effect
of
potential
future
actions
to
limit
emissions.

Despite
these
uncertainties,
we
believe
the
benefit­
cost
analysis
provides
a
reasonable
indication
of
the
expected
economic
benefits
of
the
rulemaking
in
future
years
under
a
set
of
reasonable
assumptions.

In
valuing
reductions
in
premature
fatalities
associated
with
PM,
we
used
a
value
of
$
5.5
million
per
statistical
life.
This
represents
a
central
value
consistent
with
a
range
of
values
from
$
1
to
$
10
million
727
175
Mrozek,
J.
R.
and
L.
O.
Taylor,
What
determines
the
value
of
a
life?
A
Meta
Analysis,
Journal
of
Policy
Analysis
and
Management
21
(
2),
pp.
253­
270.
suggested
by
recent
meta­
analyses
of
the
wage­
risk
value
of
statistical
life
(
VSL)
literature.
175
The
benefits
estimates
generated
for
this
rule
are
subject
to
a
number
of
assumptions
and
uncertainties,
that
are
discussed
throughout
the
Regulatory
Impact
Analysis
document
[
Regulatory
Impact
Analysis
for
the
Final
Clean
Air
Interstate
Rule
(
March
2005)].
As
Table
X­
2
indicates,

total
benefits
are
driven
primarily
by
the
reduction
in
premature
fatalities
each
year.
Elaborating
on
the
previous
uncertainty
discussion,
some
key
assumptions
underlying
the
primary
estimate
for
the
premature
mortality
category
include
the
following:

(
1)
EPA
assumes
inhalation
of
fine
particles
is
causally
associated
with
premature
death
at
concentrations
near
those
experienced
by
most
Americans
on
a
daily
basis.
Plausible
biological
mechanisms
for
this
effect
have
been
hypothesized
for
the
endpoints
included
in
the
primary
analysis
and
the
weight
of
the
available
epidemiological
evidence
supports
an
assumption
of
causality.

(
2)
EPA
assumes
all
fine
particles,
regardless
of
their
chemical
composition,
are
equally
potent
in
causing
premature
mortality.
This
is
an
important
728
176U.
S.
EPA.
(
2004).
Air
Quality
Criteria
for
Particulate
Matter.
Research
Triangle
Park,
NC:
National
Center
for
Environmental
Assessment­
RTP
Office;
Report
No.
EPA/
600/
P­
99/
002aD.
assumption,
because
the
proportion
of
certain
components
in
the
PM
mixture
produced
via
precursors
emitted
from
EGUs
may
differ
significantly
from
direct
PM
released
from
automotive
engines
and
other
industrial
sources,

but
no
clear
scientific
grounds
exist
for
supporting
differential
effects
estimates
by
particle
type.

(
3)
EPA
assumes
the
C­
R
function
for
fine
particles
is
approximately
linear
within
the
range
of
ambient
concentrations
under
consideration.
In
the
PM
Criteria
Document,
EPA
recognizes
that
for
individuals
and
specific
health
responses
there
are
likely
threshold
levels,
but
there
remains
little
evidence
of
thresholds
for
PM­
related
effects
in
populations.
176
Where
potential
threshold
levels
have
been
suggested,
they
are
at
fairly
low
levels
with
increasing
uncertainty
about
effects
at
lower
ends
of
the
PM2.5
concentration
ranges.
Thus,
EPA
estimates
include
health
benefits
from
reducing
the
fine
particles
in
areas
with
varied
concentrations
of
PM,
729
including
both
regions
that
are
in
attainment
with
fine
particle
standard
and
those
that
do
not
meet
the
standard.

The
EPA
recognizes
the
difficulties,
assumptions,
and
inherent
uncertainties
in
the
overall
enterprise.
The
analyses
upon
which
the
CAIR
is
based
were
selected
from
the
peer­
reviewed
scientific
literature.
We
used
up­
to­
date
assessment
tools,
and
we
believe
the
results
are
highly
useful
in
assessing
this
rule.

There
are
a
number
of
health
and
environmental
effects
that
we
were
unable
to
quantify
or
monetize.
A
complete
benefit­
cost
analysis
of
the
CAIR
requires
consideration
of
all
benefits
and
costs
expected
to
result
from
the
rule,
not
just
those
benefits
and
costs
which
could
be
expressed
here
in
dollar
terms.
A
listing
of
the
benefit
categories
that
were
not
quantified
or
monetized
in
our
estimate
are
provided
in
Table
X­
4.
These
effects
are
denoted
by
"
B"
in
Table
X­
3
above,
and
are
additive
to
the
estimates
of
benefits.

4.
What
are
the
Unquantified
and
Unmonetized
Benefits
of
the
CAIR
Emissions
Reductions?

Important
benefits
beyond
the
human
health
and
welfare
benefits
resulting
from
reductions
in
ambient
levels
of
PM2.5
and
ozone
are
expected
to
occur
from
this
rule.
These
other
benefits
occur
both
directly
from
NOx
and
SO2
730
emissions
reductions,
and
indirectly
through
reductions
in
co­
pollutants
such
as
mercury.
These
benefits
are
listed
in
Table
X­
4.
Some
of
the
more
important
examples
include:

Reductions
in
NOx
and
SO2
emissions
required
by
the
CAIR
will
reduce
acidification
and,
in
the
case
of
NOx,

eutrophication
of
water
bodies.
Reduced
nitrate
contamination
of
drinking
water
is
another
possible
benefit
of
the
rule.
This
final
rule
will
also
reduce
acid
and
particulate
deposition
that
cause
damages
to
cultural
monuments,
as
well
as,
soiling
and
other
materials
damage.

To
illustrate
the
important
nature
of
benefit
categories
we
are
currently
unable
to
monetize,
we
discuss
two
categories
of
public
welfare
and
environmental
impacts
related
to
reductions
in
emissions
required
by
the
CAIR:

reduced
acid
deposition
and
reduced
eutrophication
of
water
bodies.

a.
What
Are
the
Benefits
of
Reduced
Deposition
of
Sulfur
and
Nitrogen
to
Aquatic,
Forest,
and
Coastal
Ecosystems?

Atmospheric
deposition
of
sulfur
and
nitrogen,
more
commonly
known
as
acid
rain,
occurs
when
emissions
of
SO2
and
NOx
react
in
the
atmosphere
(
with
water,
oxygen,
and
oxidants)
to
form
various
acidic
compounds.
These
acidic
compounds
fall
to
earth
in
either
a
wet
form
(
rain,
snow,

and
fog)
or
a
dry
form
(
gases
and
particles).
Prevailing
winds
can
transport
acidic
compounds
hundreds
of
miles,
731
across
State
borders.
Acidic
compounds
(
including
small
particles
such
as
sulfates
and
nitrates)
cause
many
negative
environmental
effects,
including
acidification
of
lakes
and
streams,
harm
to
sensitive
forests,
and
harm
to
sensitive
coastal
ecosystems.

v.
Acid
Deposition
and
Acidification
of
Lakes
and
Streams
The
extent
of
adverse
effects
of
acid
deposition
on
freshwater
and
forest
ecosystems
depends
largely
upon
the
ecosystem's
ability
to
neutralize
the
acid.
The
neutralizing
ability
[
key
indicator
is
termed
Acid
Neutralizing
Capacity
(
ANC)]
depends
largely
on
the
watershed's
physical
characteristics:
geology,
soils,
and
size.
Waters
that
are
sensitive
to
acidification
tend
to
be
located
in
small
watersheds
that
have
few
alkaline
minerals
and
shallow
soils.
Conversely,
watersheds
that
contain
alkaline
minerals,
such
as
limestone,
tend
to
have
waters
with
a
high
ANC.
Areas
especially
sensitive
to
acidification
include
portions
of
the
Northeast
(
particularly,
the
Adirondack
and
Catskill
Mountains,

portions
of
New
England,
and
streams
in
the
mid­
Appalachian
highlands)
and
southeastern
streams.

Some
of
the
impacts
of
today's
rulemaking
on
acidification
of
water
bodies
have
been
quantified.
In
particular,
this
rule
will
result
in
improvements
in
the
acid
buffering
capacity
for
lakes
in
the
Northeast
and
732
177Banzhaf,
Spencer,
Dallas
Burtraw,
David
Evans,
and
Alan
Krupnick.
"
Valuation
of
Natural
Resource
Improvements
in
the
Adirondacks,"
Resources
for
the
Future
(
RFF),
September
2004.
Adirondack
Mountains.
Specifically,
12
percent
of
Adirondack
lakes
are
projected
to
be
chronically
acidic
in
the
base
case.
However,
we
project
that
the
CAIR
rule
will
eliminate
chronic
acidification
in
lakes
in
the
Adirondack
Mountains
by
2030.
In
addition,
today's
rule
is
expected
to
decrease
the
percentage
of
chronically
acidic
lakes
throughout
Northeast
from
6
to
1
percent.
However,
some
lakes
in
the
Adirondacks
and
New
England
will
continue
to
experience
episodic
acidification
even
after
implementation
of
this
rule.

In
a
recent
study,
177
Resources
for
the
Future
(
RFF)

estimates
total
benefits
(
i.
e.,
the
sum
of
use
and
nonuse
values)
of
natural
resource
improvements
for
the
Adirondacks
resulting
from
a
program
that
would
reduce
acidification
in
40
percent
of
the
lakes
in
the
Adirondacks
that
were
of
concern
for
acidification.
While
this
study
requires
further
evaluation,
the
RFF
study
suggests
that
the
benefits
of
acid
deposition
reductions
for
the
CAIR
are
likely
to
be
substantial
in
terms
of
the
total
monetized
value
for
ecological
endpoints
(
although
likely
small
in
comparison
to
the
estimated
premature
mortality
benefits
estimates).

vi.
Acid
Deposition
and
Forest
Ecosystem
Impacts
733
Current
understanding
of
the
effects
of
acid
deposition
on
forest
ecosystems
focuses
on
the
effects
of
ecological
processes
affecting
plant
uptake,
retention,
and
cycling
of
nutrients
within
forest
ecosystems.
Recent
studies
indicate
that
acid
deposition
is
at
least
partially
responsible
for
decreases
in
base
cations
(
calcium,
magnesium,
potassium,

and
others)
from
soils
in
the
northeastern
and
southeastern
United
States.
Losses
of
calcium
from
forest
soils
and
forested
watersheds
have
now
been
documented
as
a
sensitive
early
indicator
of
soil
response
to
acid
deposition
for
a
wide
range
of
forest
soils
in
the
United
States.

In
red
spruce
stands,
a
clear
link
exists
between
acid
deposition,
calcium
supply,
and
sensitivity
to
abiotic
stress.
Red
spruce
uptake
and
retention
of
calcium
is
impacted
by
acid
deposition
in
two
main
ways:
leaching
of
important
stores
of
calcium
from
needles
and
decreased
root
uptake
of
calcium
due
to
calcium
depletion
from
the
soil
and
aluminum
mobilization.
These
changes
increase
the
sensitivity
of
red
spruce
to
winter
injuries
under
normal
winter
conditions
in
the
Northeast,
result
in
the
loss
of
needles,
slow
tree
growth,
and
impair
the
overall
health
and
productivity
of
forest
ecosystems
in
many
areas
of
the
eastern
United
States.
In
addition,
recent
studies
of
sugar
maple
decline
in
the
Northeast
demonstrate
a
link
between
low
base
cation
availability,
high
levels
of
aluminum
and
734
manganese
in
the
soil,
and
increased
levels
of
tree
mortality
due
to
native
defoliating
insects.

Although
sulfate
is
the
primary
cause
of
base
cation
leaching,
nitrate
is
a
significant
contributor
in
watersheds
that
are
nearly
nitrogen
saturated.
Base
cation
depletion
is
a
cause
for
concern
because
of
the
role
these
ions
play
in
surface
water
acid
neutralization
and
their
importance
as
essential
nutrients
for
tree
growth
(
calcium,
magnesium
and
potassium).

This
regulatory
action
will
decrease
acid
deposition
in
the
transport
region
and
is
likely
to
have
positive
effects
on
the
health
and
productivity
of
forest
systems
in
the
region.

vii.
Coastal
Ecosystems
Since
1990,
a
large
amount
of
research
has
been
conducted
on
the
impact
of
nitrogen
deposition
to
coastal
waters.
Nitrogen
is
often
the
limiting
nutrient
in
coastal
ecosystems.
Increasing
the
levels
of
nitrogen
in
coastal
waters
can
cause
significant
changes
to
those
ecosystems.

In
recent
decades,
human
activities
have
accelerated
nitrogen
nutrient
inputs,
causing
excessive
growth
of
algae
and
leading
to
degraded
water
quality
and
associated
impairments
of
estuarine
and
coastal
resources.

Atmospheric
deposition
of
nitrogen
is
a
significant
source
of
nitrogen
to
many
estuaries.
The
amount
of
735
nitrogen
entering
estuaries
due
to
atmospheric
deposition
varies
widely,
depending
on
the
size
and
location
of
the
estuarine
watershed
and
other
sources
of
nitrogen
in
the
watershed.
There
are
a
few
estuaries
where
atmospheric
deposition
of
nitrogen
contributes
well
over
40
percent
of
the
total
nitrogen
load;
however,
in
most
estuaries
for
which
estimates
exist,
the
contribution
from
atmospheric
deposition
ranges
from
15­
30
percent.
The
area
of
the
country
with
the
highest
air
deposition
rates
(
30
percent
deposition
rates)
includes
many
estuaries
along
the
northeast
seaboard
from
Massachusetts
to
the
Chesapeake
Bay
and
along
the
central
Gulf
of
Mexico
coast.

In
1999,
National
Oceanic
and
Atmospheric
Administration
(
NOAA)
published
the
results
of
a
5­
year
national
assessment
of
the
severity
and
extent
of
estuarine
eutrophication.
An
estuary
is
defined
as
the
inland
arm
of
the
sea
that
meets
the
mouth
of
a
river.
The
138
estuaries
characterized
in
the
study
represent
more
than
90
percent
of
total
estuarine
water
surface
area
and
the
total
number
of
U.
S.
estuaries.
The
study
found
that
estuaries
with
moderate
to
high
eutrophication
represented
65
percent
of
the
estuarine
surface
area.

Eutrophication
is
of
particular
concern
in
coastal
areas
with
poor
or
stratified
circulation
patterns,
such
as
the
Chesapeake
Bay,
Long
Island
Sound,
and
the
Gulf
of
736
Mexico.
In
such
areas,
the
"
overproduced"
algae
tends
to
sink
to
the
bottom
and
decay,
using
all
or
most
of
the
available
oxygen
and
thereby
reducing
or
eliminating
populations
of
bottom­
feeder
fish
and
shellfish,
distorting
the
normal
population
balance
between
different
aquatic
organisms,
and
in
extreme
cases,
causing
dramatic
fish
kills.
Severe
and
persistent
eutrophication
often
directly
impacts
human
activities.
For
example,
fishery
resource
losses
can
be
caused
directly
by
fish
kills
associated
with
low
dissolved
oxygen
and
toxic
blooms.

Declines
in
tourism
occur
when
low
dissolved
oxygen
causes
noxious
smells
and
floating
mats
of
algal
blooms
create
unfavorable
aesthetic
conditions.
Risks
to
human
health
increase
when
the
toxins
from
algal
blooms
accumulate
in
edible
fish
and
shellfish,
and
when
toxins
become
airborne,

causing
respiratory
problems
due
to
inhalation.
According
to
the
NOAA
report,
more
than
half
of
the
nation's
estuaries
have
moderate
to
high
expressions
of
at
least
one
of
these
symptoms
 
an
indication
that
eutrophication
is
well
developed
in
more
than
half
of
U.
S.
estuaries.

This
rule
is
anticipated
to
reduce
nitrogen
deposition
in
the
CAIR
region.
Thus,
reductions
in
the
levels
of
nitrogen
deposition
will
have
a
positive
impact
upon
current
eutrophic
conditions
in
estuaries
and
coastal
areas
in
the
region.
While
we
are
unable
to
monetize
the
benefits
of
737
178
Sweeney,
Jeff.
"
EPA's
Chesapeake
Bay
Program
Air
Strategy."
October
26,
2004.
such
reductions,
the
Chesapeake
Bay
Program
estimated
the
reduced
mass
of
delivered
nitrogen
loads
likely
to
result
from
the
CAIR,
based
upon
the
CAIR
proposal
deposition
estimates
published
in
January
2004.
Atmospheric
deposition
of
nitrogen
accounts
for
a
significant
portion
of
the
nitrogen
loads
to
the
Chesapeake
with
28
percent
of
the
nitrogen
loads
from
the
watershed
coming
from
air
deposition.
Based
upon
the
CAIR
proposal,
nitrogen
deposition
rates
published
in
the
January
2004
proposal,
the
Chesapeake
Bay
Program
finds
that
the
CAIR
will
likely
reduce
the
nitrogen
loads
to
the
Bay
by
10
million
pounds
per
year
by
2010.178
These
substantial
nitrogen
load
reductions
more
than
fulfill
the
EPA's
commitment
to
reduce
atmospheric
deposition
delivered
to
the
Chesapeake
Bay
by
8
million
pounds.

B.
Are
There
Health
or
Welfare
Disbenefits
of
the
CAIR
that
Have
Not
Been
Quantified?

In
contrast
to
the
additional
benefits
of
the
rule
discussed
above,
it
is
also
possible
that
this
rule
will
result
in
disbenefits
in
some
areas
of
the
region.
Current
levels
of
nitrogen
deposition
in
these
areas
may
provide
passive
fertilization
for
forest
and
terrestrial
ecosystems
738
where
nutrients
are
a
limiting
factor
and
for
some
croplands.

The
effects
of
ozone
and
PM
on
radiative
transfer
in
the
atmosphere
can
also
lead
to
effects
of
uncertain
magnitude
and
direction
on
the
penetration
of
ultraviolet
light
and
climate.
Ground
level
ozone
makes
up
a
small
percentage
of
total
atmospheric
ozone
(
including
the
stratospheric
layer)
that
attenuates
penetration
of
ultraviolet
­
b
(
UVb)
radiation
to
the
ground.
The
EPA's
past
evaluation
of
the
information
indicates
that
potential
disbenefits
would
be
small,
variable,
and
with
too
many
uncertainties
to
attempt
quantification
of
relatively
small
changes
in
average
ozone
levels
over
the
course
of
a
year
(
EPA,
2005a).
The
EPA's
most
recent
provisional
assessment
of
the
currently
available
information
indicates
that
potential
but
unquantifiable
benefits
may
also
arise
from
ozone­
related
attenuation
of
UVb
radiation
(
EPA,
2005b).

Sulfate
and
nitrate
particles
also
scatter
UVb,
which
can
decrease
exposure
of
horizontal
surfaces
to
UVb,
but
increase
exposure
of
vertical
surfaces.
In
this
case
as
well,
both
the
magnitude
and
direction
of
the
effect
of
reductions
in
sulfate
and
nitrate
particles
are
too
uncertain
to
quantify
(
EPA,
2004).
Ozone
is
a
greenhouse
gas,
and
sulfates
and
nitrates
can
reduce
the
amount
of
solar
radiation
reaching
the
earth,
but
EPA
believes
that
we
739
are
unable
to
quantify
any
net
climate­
related
disbenefit
or
benefit
associated
with
the
combined
ozone
and
PM
reductions
in
this
rule.

Table
X­
4.
Unquantified
and
Non­
Monetized
Effects
of
the
Clean
Air
Interstate
Rule
Pollutant/
Effects
Effects
Not
Included
in
Primary
Estimates
­
Changes
in:

Ozone
Healtha
Premature
mortalityb
Chronic
respiratory
damage
Premature
aging
of
the
lungs
Non­
asthma
respiratory
emergency
room
visits
Increased
exposure
to
UVb
Ozone
Welfare
Yields
for
­
commercial
forests
­
fruits
and
vegetables
­
commercial
and
non­
commercial
crops
Damage
to
urban
ornamental
plants
Impacts
on
recreational
demand
from
damaged
forest
aesthetics
Ecosystem
functions
Increased
exposure
to
UVb
PM
Healthc
Premature
mortality
­
short
term
exposuresd
Low
birth
weight
Pulmonary
function
Chronic
respiratory
diseases
other
than
chronic
bronchitis
Non­
asthma
respiratory
emergency
room
visits
Exposure
to
UVb
(+/­)
e
PM
Welfare
Visibility
in
many
Class
I
areas
Residential
and
recreational
visibility
in
non­
Class
I
areas
Soiling
and
materials
damage
Damage
to
ecosystem
functions
Exposure
to
UVb
(+/­)
e
Nitrogen
and
Sulfate
Deposition
Welfare
Commercial
forests
due
to
acidic
sulfate
and
nitrate
deposition
Commercial
freshwater
fishing
due
to
acidic
deposition
Recreation
in
terrestrial
ecosystems
due
to
acidic
deposition
Existence
values
for
currently
healthy
ecosystems
Commercial
fishing,
agriculture,
and
forests
due
to
nitrogen
deposition
Recreation
in
estuarine
ecosystems
due
to
nitrogen
deposition
Ecosystem
functions
Passive
fertilization
740
Pollutant/
Effects
Effects
Not
Included
in
Primary
Estimates
­
Changes
in:

Mercury
Health
Incidences
of
neurological
disorders
Incidences
of
learning
disabilities
Incidences
of
developmental
delays
Potential
reproductive
effectsf
Potential
cardiovascular
effectsf,
including:
Altered
blood
pressure
regulationf
Increased
heart
rate
variability
f
Myocardial
infarctionf
Mercury
Deposition
Welfare
Impact
on
birds
and
mammals
(
e.
g.,
reproductive
effects)
Impacts
to
commercial,
subsistence,
and
recreational
fishing
Notes:

a
In
addition
to
primary
economic
endpoints,
there
are
a
number
of
biological
responses
that
have
been
associated
with
ozone
health
effects
including
increased
airway
responsiveness
to
stimuli,
inflamation
in
the
lung,
acute
inflammation
and
respiratory
cell
damage,
and
increased
susceptibility
to
respiratory
infection.
The
public
health
impact
of
these
biological
responses
may
be
partly
represented
by
our
quantified
endpoints.

b
Premature
mortality
associated
with
ozone
is
not
currently
included
in
the
primary
analysis.
Recent
evidence
suggests
that
short­
term
exposures
to
ozone
may
have
a
significant
effect
on
daily
mortality
rates,
independent
of
exposure
to
PM.
EPA
is
currently
conducting
a
series
of
meta­
analyses
of
the
ozone
mortality
epidemiology
literature.
EPA
will
consider
including
ozone
mortality
in
primary
benefits
analyses
once
a
peer
reviewed
methodology
is
available.

c
In
addition
to
primary
economic
endpoints,
there
are
a
number
of
biological
responses
that
have
been
associated
with
PM
health
effects
including
morphological
changes
and
altered
host
defense
mechanisms.
The
public
health
impact
of
these
biological
responses
may
be
partly
represented
by
our
quantified
endpoints.

d
While
some
of
the
effects
of
short
term
exposures
are
likely
to
be
captured
in
the
estimates,
there
may
be
premature
mortality
due
to
short
term
exposure
to
PM
not
captured
in
the
cohort
study
upon
which
the
primary
analysis
is
based.

e
May
result
in
benefits
or
disbenefits.
741
f
These
are
potential
effects
as
the
literature
is
insufficient.

B.
Paperwork
Reduction
Act
In
compliance
with
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.),
EPA
submitted
a
proposed
Information
Collection
Request
(
ICR)
(
EPA
ICR
number
2512.01)
to
the
OMB
for
review
and
approval
on
July
19,
2004
(
FR
42720­
42722).

The
ICR
describes
the
nature
of
the
information
collection
and
its
estimated
burden
and
cost
associated
with
the
final
rule.
In
cases
where
information
is
already
collected
by
a
related
program,
the
ICR
takes
into
account
only
the
additional
burden.
This
situation
arises
in
States
that
are
also
subject
to
requirements
of
the
Consolidated
Emissions
Reporting
Rule
(
EPA
ICR
number
0916.10;
OMB
control
number
2060­
0088)
or
for
sources
that
are
subject
to
the
Acid
Rain
Program
(
EPA
ICR
number
1633.13;
OMB
control
number
2060­

0258)
or
NOx
SIP
Call
(
EPA
ICR
number
1857.03;
OMB
number
2060­
0445)
requirements.

The
EPA
solicited
comments
on
specific
aspects
of
the
information
collection.
The
purpose
of
the
ICR
is
to
estimate
the
anticipated
monitoring,
reporting,
and
recordkeeping
burden
estimates
and
associated
costs
for
States,
local
governments,
and
sources
that
are
expected
to
result
from
the
CAIR.

The
recordkeeping
and
reporting
burden
to
sources
resulting
from
States
choosing
to
participate
in
a
regional
742
cap
and
trade
program
are
expected
to
be
less
than
$
42
million
annually
at
the
time
the
monitors
are
implemented.

This
estimate
includes
the
annualized
cost
of
installing
and
operating
appropriate
SO2
and
NOx
emissions
monitoring
equipment
to
measure
and
report
the
total
emissions
of
these
pollutants
from
affected
EGUs
serving
generators
greater
than
25
megawatt
electrical.
The
burden
to
State
and
local
air
agencies
includes
any
necessary
SIP
revisions,

performing
monitoring
certification,
and
fulfilling
audit
responsibilities.

In
accordance
with
the
Paperwork
Reduction
Act,
on
July
19,
2004,
an
ICR
was
made
available
to
the
public
for
comment.
The
60­
day
comment
period
expired
September
19,

2004
with
no
public
comments
received
specific
to
the
ICR.

C.
Regulatory
Flexibility
Act
The
Regulatory
Flexibility
Act
(
5
U.
S.
C.
§
601
et
seq.)(
RFA),
as
amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
(
Public
Law
No.
104­
121)(
SBREFA),

provides
that
whenever
an
agency
is
required
to
publish
a
general
notice
of
rulemaking,
it
must
prepare
and
make
available
an
initial
regulatory
flexibility
analysis,
unless
it
certifies
that
the
rule,
if
promulgated,
will
not
have
"
a
significant
economic
impact
on
a
substantial
number
of
small
entities."
5
U.
S.
C.
§
605(
b).
Small
entities
include
small
743
businesses,
small
organizations,
and
small
governmental
jurisdictions.

For
purposes
of
assessing
the
impacts
of
today's
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
a
small
business
that
is
identified
by
the
North
American
Industry
Classification
System
(
NAICS)
Code,
as
defined
by
the
Small
Business
Administration
(
SBA);
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,

school
district
or
special
district
with
a
population
of
less
that
50,000;
and
(
3)
a
small
organization
that
is
any
not­
for­
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
Table
X­
5
lists
entities
potentially
impacted
by
this
rule
with
applicable
NAICS
code.

X­
5.
Potentially
Regulated
Categories
and
Entities
Category
NAICS
code1
Examples
of
potentially
regulated
entities
Industry
221112
Fossil
fuel­
fired
electric
utility
steam
generating
units.

Federal
government
2211122
Fossil
fuel­
fired
electric
utility
steam
generating
units
owned
by
the
Federal
government.

State/
local/
Tribal
government
2211122
921150
Fossil
fuel­
fired
electric
utility
steam
generating
units
owned
by
municipalities.
Fossil
fuel­
fired
electric
utility
steam
generating
units
in
Indian
Country.

1
North
American
Industry
Classification
System.
744
2
Federal,
State,
or
local
government­
owned
and
operated
establishments
are
classified
according
to
the
activity
in
which
they
are
engaged.

According
to
the
SBA
size
standards
for
NAICS
code
221112
Utilities­
Fossil
Fuel
Electric
Power
Generation,
a
firm
is
small
if,
including
its
affiliates,
it
is
primarily
engaged
in
the
generation,
transmission,
and
or
distribution
of
electric
energy
for
sale
and
its
total
electric
output
for
the
preceding
fiscal
year
did
not
exceed
4
million
megawatt
hours.

Courts
have
interpreted
the
RFA
to
require
a
regulatory
flexibility
analysis
only
when
small
entities
will
be
subject
to
the
requirements
of
the
rule.
See
Michigan
v.

EPA,
213
F.
3d
663,
668­
69
(
D.
C.
Cir.,
2000),
cert.
den.
121
S.
Ct.
225,
149
L.
Ed.
2d
135
(
2001).

This
rule
would
not
establish
requirements
applicable
to
small
entities.
Instead,
it
would
require
States
to
develop,
adopt,
and
submit
SIP
revisions
that
would
achieve
the
necessary
SO2
and
NOx
emissions
reductions,
and
would
leave
to
the
States
the
task
of
determining
how
to
obtain
those
reductions,
including
which
entities
to
regulate.

Moreover,
because
affected
States
would
have
discretion
to
choose
the
sources
to
regulate
and
how
much
emissions
reductions
each
selected
source
would
have
to
achieve,
EPA
could
not
predict
the
effect
of
the
rule
on
small
entities.
745
Although
not
required
by
the
RFA,
the
Agency
has
conducted
a
small
business
analysis.

Overall,
about
445
MW
of
total
small
entity
capacity,

or
1.0
percent
of
total
small
entity
capacity
in
the
CAIR
region,
is
projected
to
be
uneconomic
to
maintain
under
the
CAIR
relative
to
the
Base
Case.
In
practice,
units
projected
to
be
uneconomic
to
maintain
may
be
"
mothballed,"

retired,
or
kept
in
service
to
ensure
transmission
reliability
in
certain
parts
of
the
grid.
Our
IPM
modeling
is
unable
to
distinguish
between
these
potential
outcomes.

The
EPA
modeling
identified
264
small
entities
within
the
CAIR
region
based
upon
the
definition
of
small
entity
outlined
above.
From
this
analysis,
EPA
excluded
189
small
entities
that
were
not
projected
to
have
at
least
one
unit
with
a
generating
capacity
of
25
MW
or
great
operating
in
the
base
case.
Thus,
we
found
that
75
small
entities
may
potentially
be
affected
by
the
CAIR.
Of
these
75
small
entities,
28
may
experience
compliance
costs
in
excess
of
one
percent
of
revenues
in
2010,
and
46
may
in
2015,
based
on
the
Agency's
assumptions
of
how
the
affected
States
implement
control
measures
to
meet
their
emissions
budgets
as
set
forth
in
this
rulemaking.
Potentially
affected
small
entities
experiencing
compliance
costs
in
excess
of
1
percent
of
revenues
have
some
potential
for
significant
impact
resulting
from
implementation
of
the
CAIR.
However,
746
it
is
the
Agency's
position
that
because
none
of
the
affected
entities
currently
operate
in
a
competitive
market
environment,
they
should
be
able
to
pass
the
costs
of
complying
with
the
CAIR
on
to
rate­
payers.
Moreover,
the
decision
to
include
only
units
greater
than
25
MW
in
size
exempts
185
small
entities
that
would
otherwise
be
potentially
affected
by
the
CAIR.

Two
other
points
should
be
considered
when
evaluating
the
impact
of
the
CAIR,
specifically,
and
cap
and
trade
programs
more
generally,
on
small
entities.
First,
under
the
CAIR,
the
cap
and
trade
program
is
designed
such
that
States
determine
how
NOx
allowances
are
to
be
allocated
across
units.
A
State
that
wishes
to
mitigate
the
impact
of
the
rule
on
small
entities
might
choose
to
allocate
NOx
allowances
in
a
manner
that
is
favorable
to
small
entities.

Finally,
the
use
of
cap
and
trade
in
general
will
limit
impacts
on
small
entities
relative
to
a
less
flexible
command­
and­
control
program.

D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
Public
Law
104­
4)(
UMRA),
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
Tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
2
U.
S.
C.

1532,
EPA
generally
must
prepare
a
written
statement,
747
including
a
cost­
benefit
analysis,
for
any
proposed
or
final
rule
that
"
includes
any
Federal
mandate
that
may
result
in
the
expenditure
by
State,
local,
and
Tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$
100,000,000
or
more
...
in
any
one
year."
A
"
Federal
mandate"
is
defined
under
section
421(
6),
2
U.
S.
C.
658(
6),
to
include
a
"
Federal
intergovernmental
mandate"
and
a
"
Federal
private
sector
mandate."
A
"
Federal
intergovernmental
mandate,"
in
turn,

is
defined
to
include
a
regulation
that
"
would
impose
an
enforceable
duty
upon
State,
Local,
or
Tribal
governments,"

section
421(
5)(
A)(
i),
2
U.
S.
C.
658(
5)(
A)(
i),
except
for,

among
other
things,
a
duty
that
is
"
a
condition
of
Federal
assistance,"
section
421(
5)(
A)(
i)(
I).
A
"
Federal
private
sector
mandate"
includes
a
regulation
that
"
would
impose
an
enforceable
duty
upon
the
private
sector,"
with
certain
exceptions,
section
421(
7)(
A),
2
U.
S.
C.
658(
7)(
A).

Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed
under
section
202
of
the
UMRA,
section
205,
2
U.
S.
C.
1535,
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.

The
EPA
prepared
a
written
statement
for
the
final
rule
consistent
with
the
requirements
of
section
202
of
the
UMRA.
748
Furthermore,
as
EPA
stated
in
the
rule,
EPA
is
not
directly
establishing
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,

including
Tribal
governments.
Thus,
EPA
is
not
obligated
to
develop
under
section
203
of
the
UMRA
a
small
government
agency
plan.
Furthermore,
in
a
manner
consistent
with
the
intergovernmental
consultation
provisions
of
section
204
of
the
UMRA,
EPA
carried
out
consultations
with
the
governmental
entities
affected
by
this
rule.

For
several
reasons,
however,
EPA
is
not
reaching
a
final
conclusion
as
to
the
applicability
of
the
requirements
of
UMRA
to
this
rulemaking
action.
First,
it
is
questionable
whether
a
requirement
to
submit
a
SIP
revision
would
constitute
a
Federal
mandate
in
any
case.
The
obligation
for
a
State
to
revise
its
SIP
that
arises
out
of
section
110(
a)
of
the
CAA
is
not
legally
enforceable
by
a
court
of
law,
and
at
most
is
a
condition
for
continued
receipt
of
highway
funds.
Therefore,
it
is
possible
to
view
an
action
requiring
such
a
submittal
as
not
creating
any
enforceable
duty
within
the
meaning
of
section
421(
5)(
9a)(
I)

of
UMRA
(
2
U.
S.
C.
658
(
a)(
I)).
Even
if
it
did,
the
duty
could
be
viewed
as
falling
within
the
exception
for
a
condition
of
Federal
assistance
under
section
421(
5)(
a)(
i)(
I)
of
UMRA
(
2
U.
S.
C.
658(
5)(
a)(
i)(
I)).
749
As
noted
earlier,
however,
notwithstanding
these
issues,
EPA
prepared
for
the
final
rule
the
statement
that
would
be
required
by
UMRA
if
its
statutory
provisions
applied,
and
EPA
has
consulted
with
governmental
entities
as
would
be
required
by
UMRA.
Consequently,
it
is
not
necessary
for
EPA
to
reach
a
conclusion
as
to
the
applicability
of
the
UMRA
requirements.

The
EPA
conducted
an
analysis
of
the
economic
impacts
anticipated
from
the
CAIR
for
government­
owned
entities.

The
modeling
conducted
using
the
IPM
projects
that
about
340
MW
of
municipality­
owned
capacity
(
about
0.4
percent
of
all
subdivision,
State
and
municipality
capacity
in
the
CAIR
region)
would
be
uneconomic
to
maintain
under
the
CAIR,

beyond
what
is
projected
in
the
Base
Case.
In
practice,

however,
the
units
projected
to
be
uneconomic
to
maintain
may
be
'
mothballed,'
retired,
or
kept
in
service
to
ensure
transmission
reliability
in
certain
parts
of
the
grid.
For
the
most
part,
these
units
are
small
and
infrequently
used
generating
units
that
are
dispersed
throughout
the
CAIR
region.

The
EPA
modeling
identified
265
State
or
municipallyowned
entities,
as
well
as
subdivisions,
within
the
CAIR
region.
The
EPA
excluded
from
the
analysis
government­
owned
entities
that
were
not
projected
to
have
at
least
one
unit
with
generating
capacity
of
25
MW
or
greater
in
the
Base
750
Case.
Thus,
we
excluded
184
entities
from
the
analysis.
We
found
that
81
government
entities
will
be
potentially
affected
by
CAIR.
Of
the
81
government
entities,
20
may
experience
compliance
costs
in
excess
of
1
percent
of
revenues
in
2010,
and
39
may
in
2015,
based
on
our
assumptions
of
how
the
affected
States
implement
control
measures
to
meet
their
emissions
budgets
as
set
forth
in
this
rulemaking.

Government
entities
projected
to
experience
compliance
costs
in
excess
of
1
percent
of
revenues
have
some
potential
for
significant
impact
resulting
from
implementation
of
the
CAIR.
However,
as
noted
above,
it
is
EPA's
position
that
because
these
government
entities
can
pass
on
their
costs
of
compliance
to
rate­
payers,
they
will
not
be
significantly
impacted.
Furthermore,
the
decision
to
include
only
units
greater
than
25
MW
in
size
exempts
179
government
entities
that
would
otherwise
be
potentially
affected
by
the
CAIR.

The
above
points
aside,
potentially
adverse
impacts
of
the
CAIR
on
State
and
municipality­
owned
entities
could
be
limited
by
the
fact
that
the
cap
and
trade
program
is
designed
such
that
States
determine
how
NOx
allowances
are
to
be
allocated
across
units.
A
State
that
wishes
to
mitigate
the
impact
of
the
rule
on
State
or
municipalityowned
entities
might
choose
to
allocate
NOx
allowances
in
a
manner
that
is
favorable
to
these
entities.
Finally,
the
751
use
of
cap
and
trade
in
general
will
limit
impacts
on
entities
owned
by
small
governments
relative
to
a
less
flexible
command­
and­
control
program.

E.
Executive
Order
13132:
Federalism
Executive
Order
13132,
entitled
"
Federalism"
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
"
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications."

"
Policies
that
have
federalism
implications"
is
defined
in
the
Executive
Order
to
include
regulations
that
have
"
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,

or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government."

This
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
The
CAA
establishes
the
relationship
between
the
Federal
government
and
the
States,
and
this
rule
does
not
impact
that
relationship.
Thus,
Executive
Order
13132
does
not
apply
to
this
rule.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
752
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicited
comment
on
this
rule
from
State
and
local
officials.

F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
Executive
Order
13175,
entitled
"
Consultation
and
Coordination
with
Indian
Tribal
Governments"
(
65
FR
67249,

November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
"
meaningful
and
timely
input
by
Tribal
officials
in
the
development
of
regulatory
policies
that
have
Tribal
implications."
This
rule
does
not
have
"
Tribal
implications"
as
specified
in
Executive
Order
13175.

This
rule
addresses
transport
of
pollution
that
are
precurors
for
ozone
and
PM2.5.
The
CAA
provides
for
States
and
Tribes
to
develop
plans
to
regulate
emissions
of
air
pollutants
within
their
jurisdictions.
The
regulations
clarify
the
statutory
obligations
of
States
and
Tribes
that
develop
plans
to
implement
this
rule.
The
Tribal
Authority
Rule
(
TAR)
give
Tribes
the
opportunity
to
develop
and
implement
CAA
programs,
but
it
leaves
to
the
discretion
of
the
Tribe
whether
to
develop
these
programs
and
which
programs,
or
appropriate
elements
of
a
program,
the
Tribe
will
adopt.

This
rule
does
not
have
Tribal
implications
as
defined
by
Executive
Order
13175.
It
does
not
have
a
substantial
753
direct
effect
on
one
or
more
Indian
Tribes,
because
no
Tribe
has
implemented
a
federally
enforceable
air
quality
management
program
under
the
CAA
at
this
time.
Furthermore,

this
rule
does
not
affect
the
relationship
or
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
Tribes.
The
CAA
and
the
TAR
establish
the
relationship
of
the
Federal
government
and
Tribes
in
developing
plans
to
attain
the
NAAQS,
and
this
rule
does
nothing
to
modify
that
relationship.
Because
this
rule
does
not
have
Tribal
implications,
Executive
Order
13175
does
not
apply.

If
one
assumes
a
Tribe
is
implementing
a
Tribal
Implementation
Plan,
today's
rule
could
have
implications
for
that
Tribe,
but
it
would
not
impose
substantial
direct
costs
upon
the
Tribe,
nor
preempt
Tribal
law.
As
provided
above,
EPA
has
estimated
that
the
total
annual
private
costs
for
the
rule
for
the
CAIR
region
as
implemented
by
State,

Local,
and
Tribal
governments
is
approximately
$
2.4
billion
in
2010
and
$
3.6
billion
in
2015
(
1999$).
There
are
currently
very
few
emissions
sources
in
Indian
country
that
could
be
affected
by
this
rule
and
the
percentage
of
Tribal
land
that
will
be
impacted
is
very
small.
For
Tribes
that
choose
to
regulate
sources
in
Indian
country,
the
costs
would
be
attributed
to
inspecting
regulated
facilities
and
enforcing
adopted
regulations.
754
Although
Executive
Order
13175
does
not
apply
to
this
rule,
EPA
consulted
with
Tribal
officials
in
developing
this
rule.
The
EPA
has
encouraged
Tribal
input
at
an
early
stage.
Also,
EPA
held
periodic
meetings
with
the
States
and
the
Tribes
during
the
technical
development
of
this
rule.

Three
meetings
were
held
with
the
Crow
Tribe,
where
the
Tribe
expressed
concerns
about
potential
impacts
of
the
rule
on
their
coal
mine
operations.
In
addition,
EPA
held
three
calls
with
Tribal
environmental
professionals
to
address
concerns
specific
to
the
Tribes.
These
discussions
have
given
EPA
valuable
information
about
Tribal
concerns
regarding
the
development
of
this
rule.
The
EPA
has
provided
briefings
for
Tribal
representatives
and
the
newly
formed
National
Tribal
Air
Association
(
NTAA),
and
other
national
Tribal
forums.
Input
from
Tribal
representatives
has
been
taken
into
consideration
in
development
of
this
rule.

G.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
and
Safety
Risks
Executive
Order
13045,
"
Protection
of
Children
from
Environmental
Health
and
Safety
Risks"
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that
(
1)
is
determined
to
be
"
economically
significant"
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
755
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
Section
5
 
501
of
the
Order
directs
the
Agency
to
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.

This
final
rule
is
not
subject
to
the
Executive
Order,

because
it
does
not
involve
decisions
on
environmental
health
or
safety
risks
that
may
disproportionately
affect
children.
The
EPA
believes
that
the
emissions
reductions
from
the
strategies
in
this
rule
will
further
improve
air
quality
and
will
further
improve
children's
health.

H.
Executive
Order
13211:
Actions
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
Executive
Order
13211
(
66
FR
28355,
May
22,
2001)

provides
that
agencies
shall
prepare
and
submit
to
the
Administrator
of
the
Office
of
Regulatory
Affairs,
OMB,
a
Statement
of
Energy
Effects
for
certain
actions
identified
as
"
significant
energy
actions."
Section
4(
b)
of
Executive
Order
13211
defines
"
significant
energy
actions"
as
"
any
action
by
an
agency
(
normally
published
in
the
Federal
Register)
that
promulgates
or
is
expected
to
lead
to
the
promulgation
of
a
final
rule
or
regulation,
including
notices
of
inquiry,
advance
notices
of
final
rulemaking,
and
756
notices
of
final
rulemaking
(
1)
(
i)
a
significant
regulatory
action
under
Executive
Order
12866
or
any
successor
order,
and
(
ii)
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy;
or
(
2)
designated
by
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs
as
a
"
significant
energy
action."
This
final
rule
is
a
significant
regulatory
action
under
Executive
Order
12866,
and
this
rule
may
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.

If
States
choose
to
obtain
the
emissions
reductions
required
by
this
rule
by
regulating
EGUs,
EPA
projects
that
approximately
5.3
GWs
of
coal­
fired
generation
may
be
removed
from
operation
by
2010.
In
practice,
however,
the
units
projected
to
be
uneconomic
to
maintain
may
be
'
mothballed,'
retired,
or
kept
in
service
to
ensure
transmission
reliability
in
certain
parts
of
the
grid.
For
the
most
part,
these
units
are
small
and
infrequently
used
generating
units
that
are
dispersed
throughout
the
CAIR
region.
Less
conservative
assumptions
regarding
natural
gas
prices
or
electricity
demand
would
create
a
greater
incentive
to
keep
these
units
operational.
The
EPA
projects
that
the
average
annual
electricity
price
will
increase
by
less
than
2.7
percent
in
the
CAIR
region
and
that
natural
gas
prices
will
increase
by
less
than
1.6%.
The
EPA
does
757
not
believe
that
this
rule
will
have
any
other
impacts
that
exceed
the
significance
criteria.

The
EPA
believes
that
a
number
of
features
of
today's
rulemaking
serve
to
reduce
its
impact
on
energy
supply.

First,
the
optional
trading
program
provides
considerable
flexibility
to
the
power
sector
and
enables
industry
to
comply
with
the
emission
reduction
requirements
in
the
most
cost­
effective
manner,
thus
minimizing
overall
costs
and
the
ultimate
impact
on
energy
supply.
The
ability
to
use
banked
allowances
from
the
existing
title
IV
SO2
trading
program
and
the
NOx
SIP
Call
Trading
Program
also
provide
additional
flexibility.
Second,
the
CAIR
caps
are
set
in
two
phases
and
provide
adequate
time
for
EGUs
to
install
pollution
controls.
For
more
details
concerning
energy
impacts,
see
the
Regulatory
Impact
Analysis
for
the
Final
Clean
Air
Interstate
Rule
(
March
2005).

I.
National
Technology
Transfer
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Public
Law
No.
104­
113;
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
its
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
758
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.

This
rule
would
require
all
sources
that
participate
in
the
trading
program
under
part
96
to
meet
the
applicable
monitoring
requirements
of
part
75.
Part
75
already
incorporates
a
number
of
voluntary
consensus
standards.

Consistent
with
the
Agency's
Performance
Based
Measurement
System
(
PBMS),
part
75
sets
forth
performance
criteria
that
allow
the
use
of
alternative
methods
to
the
ones
set
forth
in
part
75.
The
PBMS
approach
is
intended
to
be
more
flexible
and
cost­
effective
for
the
regulated
community;
it
is
also
intended
to
encourage
innovation
in
analytical
technology
and
improved
data
quality.
At
this
time,
EPA
is
not
recommending
any
revisions
to
part
75;
however,
EPA
periodically
revises
the
test
procedures
set
forth
in
part
75.
When
EPA
revises
the
test
procedures
set
forth
in
part
75
in
the
future,
EPA
will
address
the
use
of
any
new
voluntary
consensus
standards
that
are
equivalent.

Currently,
even
if
a
test
procedure
is
not
set
forth
in
part
75
EPA
is
not
precluding
the
use
of
any
method,
whether
it
constitutes
a
voluntary
consensus
standard
or
not,
as
long
as
it
meets
the
performance
criteria
specified;
however,
any
759
179
U.
S.
Environmental
Protection
Agency,
1998.
Guidance
for
Incorporating
Environmental
Justice
Concerns
in
EPA's
NEPA
Compliance
Analyses.
Office
of
Federal
Activities,
Washington,
D.
C.,
April,
1998.
alternative
methods
must
be
approved
through
the
petition
process
under
Sec.
75.66
before
they
are
used
under
part
75.

J.
Executive
Order
12898:
Federal
Actions
to
Address
Environmental
Justice
in
Minority
Populations
and
Low­
Income
Populations
Executive
Order
12898,
"
Federal
Actions
to
Address
Environmental
Justice
in
Minority
Populations
and
Low­
Income
Populations,"
requires
Federal
agencies
to
consider
the
impact
of
programs,
policies,
and
activities
on
minority
populations
and
low­
income
populations.
According
to
EPA
guidance,
179
agencies
are
to
assess
whether
minority
or
lowincome
populations
face
risks
or
a
rate
of
exposure
to
hazards
that
are
significant
and
that
"
appreciably
exceed
or
is
likely
to
appreciably
exceed
the
risk
or
rate
to
the
general
population
or
to
the
appropriate
comparison
group."

(
EPA,
1998)

In
accordance
with
Executive
Order
12898,
the
Agency
has
considered
whether
this
rule
may
have
disproportionate
negative
impacts
on
minority
or
low
income
populations.
The
Agency
expects
this
rule
to
lead
to
reductions
in
air
pollution
and
exposures
generally.
For
this
reason,

negative
impacts
to
these
sub­
populations
that
appreciably
760
exceed
similar
impacts
to
the
general
population
are
not
expected.

K.
Congressional
Review
Act
The
Congressional
Review
Act,
5
U.
S.
C.
801
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
The
EPA
will
submit
a
report
containing
this
rule
and
other
required
information
to
the
U.
S.
Senate,
the
U.
S.

House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
rule
in
the
Federal
Register.
A
Major
rule
cannot
take
effect
until
60
days
after
it
is
published
in
the
Federal
Register.
This
action
is
a
"
major
rule"
as
defined
by
5
U.
S.
C.
804(
2).

L.
Judicial
Review
Section
307(
b)(
1)
of
the
CAA
indicates
which
Federal
Courts
of
Appeal
have
venue
for
petitions
of
review
of
final
actions
by
EPA.
This
Section
provides,
in
part,
that
petitions
for
review
must
be
filed
in
the
Court
of
Appeals
for
the
District
of
Columbia
Circuit
if
(
i)
the
agency
action
consists
of
"
nationally
applicable
regulations
promulgated,
or
final
action
taken,
by
the
Administrator,"

or
(
ii)
such
action
is
locally
or
regionally
applicable,
if
761
"
such
action
is
based
on
a
determination
of
nationwide
scope
or
effect
and
if
in
taking
such
action
the
Administrator
finds
and
publishes
that
such
action
is
based
on
such
a
determination."

Any
final
action
related
to
CAIR
is
"
nationally
applicable"
within
the
meaning
of
section
307(
b)(
1).
As
an
initial
matter,
through
this
rule,
EPA
interprets
section
110
of
the
CAA,
a
provision
which
has
nationwide
applicability.
In
addition,
CAIR
applies
to
28
States
and
the
District
of
Columbia.
CAIR
is
also
based
on
a
common
core
of
factual
findings
and
analyses
concerning
the
transport
of
pollutants
between
the
different
States
subject
to
it.
Finally,
EPA
has
established
uniform
approvability
criteria
that
would
be
applied
to
all
States
subject
to
CAIR.
For
these
reasons,
the
Administrator
also
is
determining
that
any
final
action
regarding
CAIR
is
of
nationwide
scope
and
effect
for
purposes
of
section
307(
b)(
1).
Thus,
any
petitions
for
review
of
final
actions
regarding
CAIR
must
be
filed
in
the
Court
of
Appeals
for
the
District
of
Columbia
Circuit
within
60
days
from
the
date
final
action
is
published
in
the
Federal
Register.

List
of
Subjects
in
40
CFR
Part
51
Administrative
practice
and
procedure,
Air
pollution
control,
Intergovernmental
relations,
Nitrogen
oxides,
Ozone,
Particulate
matter,
Regional
haze,
Reporting
and
recordkeeping
requirements,
Sulfur
dioxide
List
of
Subjects
in
40
CFR
Parts
72,
73,
74,
77
and
78
Acid
rain,
Administrative
practice
and
procedure,
Air
pollution
control,
Electric
utilities,
Intergovernmental
relations,
Nitrogen
oxides,
Reporting
and
recordkeeping
requirements,
Sulfur
dioxide
List
of
Subjects
in
40
CFR
Part
96
Administrative
practice
and
procedure,
Air
pollution
control,
Electric
utilities,
Nitrogen
oxides,
Reporting
and
recordkeeping
requirements,
Sulfur
dioxide
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Interstate
Air
Quality
Rule)
page
____
of
____
763
______________________________

Dated:

______________________________

Stephen
L.
Johnson
Acting
Administrator