TECHNICAL
APPENDIX
POTENTIAL
IMPACTS
OF
IMPLEMENTATION
OF
THE
8­
HOUR
OZONE
NAAQS
TECHNICAL
SUPPORT
DOCUMENT
Prepared
for:

Ozone
Policy
and
Strategies
Group
Office
of
Air
Quality
Planning
and
Standards
U.
S.
Environmental
Protection
Agency
Research
Triangle
Park,
NC
27711
Prepared
by:

E.
H.
Pechan
&
Associates,
Inc.
5528­
B
Hempstead
Way
Springfield,
VA
22151
July
21,
2005
Pechan
Report
No.
05.07.002/
9010.466
PECHAN
July
2005
Document
No.
05.07.002/
9010.466
1
Draft
Report
I.
INTRODUCTION
This
technical
support
document
was
prepared
to
support
the
U.
S.
Environmental
Agency
(
EPA)
in
proposed
rulemaking
for
implementation
of
the
8­
hour,
0.08ppm
Ozone
National
Ambient
Air
Quality
Standard.
The
results
contained
in
this
document
estimate
emission
reductions
of
NOx
and
VOC,
control
costs,
and
economic
and
energy
impacts
of
implementing
the
standard.

The
technical
inputs
used
for
the
analysis
include
emissions
inventories
and
air
quality
modeling
results
developed
by
EPA
for
the
Clean
Air
Interstate
Rule
and
ozone
8­
hour
design
values
derived
from
ambient
ozone
measurements.
These
were
combined
by
EPA
to
develop
emissions
and
air
quality
relationships,
and
estimates
of
the
VOC
and
NOx
emission
reduction
targets
(
ERT)
needed
to
obtain
the
ozone
standard
in
2010.
Attainment
costs
were
calculated
by
first
applying
required
presumptive
controls,
if
needed,
and
then
additional
control
measures,
in
the
order
of
least­
cost
per
ton,
to
meet
NOx
and
VOC
reduction
target
at
the
cheapest
cost.

Estimates
of
the
economic
impacts
and
energy
costs
are
estimated.
Energy
impacts
are
provided
as
addition
energy
costs
and
as
a
measure
of
the
additional
electricity,
coal
and
natural
gas
due
to
implantation
of
the
standard.
The
economic
impacts
reported
are
the
average
revenue
per
industrial
sector
and
the
mean
and
median
control
costs
provided
as
the
percentage
of
revenue
per
affected
establishment.

This
technical
support
document
includes
two
assessments
 
a
more
flexible
and
a
less
flexible
option.
While
both
require
reasonably
available
control
technology
(
RACT)
and
reasonable
further
progress
(
RFP)
requirements,
the
regulatory
baseline
provides
for
more
flexible
RACT
and
RFP
implementation
framework
requirements.
The
results
presented
in
the
sections
below
provide
estimates
of
the
differences
in
cost,
emission
reductions,
energy
and
economic
impacts
between
meeting
the
less
flexible
implementation
framework
requirements
for
RACT
and
RFP
versus
the
regulatory
baseline.
The
data
input
details,
methodology,
results,
and
limitations
for
each
assessment
are
noted
in
the
sections
that
follow.

I
I.
REASONABLE
FURTHER
PROGRESS
REQUIREMENTS
ASSESSMENT
Reasonable
further
progress
is
the
incremental
reductions
in
the
emissions
of
the
applicable
air
pollutant
pursuant
to
Part
D
of
the
Clean
Air
Act
(
CAA)
and
its
Amendments.
The
RFP
requirements
in
the
CAA
are
intended
to
ensure
that
each
ozone
non­
attainment
area
provide
for
sufficient
precursor
emission
reductions
to
attain
the
national
ambient
air
quality
standards
for
ozone.
More
specifically,
Section
182(
c)(
2)
of
the
Act
requires
that
each
serious
and
above
ozone
non­
attainment
area
achieve
actual
VOC
emission
reductions
of
at
least
three
percent
per
year
averaged
over
each
consecutive
three­
year
period
beginning
six
years
after
enactment
of
the
Act.
One
option
under
consideration
with
respect
to
mandatory
reasonable
further
progress
under
the
8­
hour
ozone
rule
(
RFP;
also
sometimes
described
as
rate
of
progress­­
ROP),
is
to
assume
that
an
additional
15%
VOC
emission
reduction
is
needed
despite
the
area
already
having
had
and
met
a
15%
reduction
for
the
1­
hour
standard.
Note
that
this
is
the
less
flexible
alternative.
PECHAN
July
2005
Document
No.
05.07.002/
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Draft
Report
However,
only
a
subset
of
the
designated
non­
attainment
areas
may
be
subject
to
RFP
requirements.
In
order
to
determine
areas
where
requirements
may
exist,
EPA
examined
the
classifications
of
designated
Subpart
2
non­
attainment
areas,
as
well
as,
the
design
values
for
designated
Subpart
1
areas.
Only
Subpart
2
areas
classified
as
moderate
or
above,
and
Subpart
1
areas
that
are
"
moderate­
like"
(
design
values
greater
than
0.92ppm)
may
have
RFP
requirements.

In
addition,
those
Subpart
1
or
2
areas
that
have
the
aforementioned
characteristics
can
avert
RFP
requirements
by
achieving
an
8­
hour
design
value
of
0.84ppm
or
less
in
2010
via
the
clean
data
policy.
To
determine
which
of
the
areas
could
avert
such
requirements,
EPA
used
base
case
simulations
of
the
Comprehensive
Air
Quality
Model
with
Extension
(
CAMx)
for
the
areas
outside
California.
EPA's
analysis
showed
that
11
non­
attainment
areas
classified
as
moderate
and
above
are
projected
to
exceed
the
8­
hour
ozone
standard
in
2010.
These
areas
may
be
subject
to
a
RFP
requirement
and
additional
calculations,
as
described
below,
were
needed
in
order
to
make
this
determination.

A.
CALCULATION
METHODOLOGY
The
first
step
needed
to
determine
if
additional
RFP
emission
reductions
are
required
in
the
11
areas
is
to
compare
VOC
emission
estimates
of
2002
with
2008.
This
is
because
the
VOC
emission
reductions
obtained
from
2002
to
2008
as
a
result
of
on­
the­
books
Federal
and
local
air
pollution
control
programs
count
toward
the
15%
reduction
requirement.
For
8­
hr
ozone
Implementation
rule,
2002
is
considered
as
the
base
year.

For
this
analysis,
we
used
2001,
2007
and
2010
annual
emission
inventories
by
non­
attainment
area
and
sector
(
stationary
non­
point,
off­
road,
on­
road,
point
and
electricity
generating
units).
2002
emissions,
by
non­
attainment
area
and
sector,
were
estimated
by
the
linear
interpolation
of
the
2001
and
2007
inventories.
Similarly,
2008
emissions
were
interpolated
from
the
2007
and
2010
projected
inventories.

The
RFP
requirement
for
each
non­
attainment
area
is
calculated
by
subtracting
85%
of
2002
emissions
(
i.
e.
reduction
by
15%)
from
the
2008
emissions.
If
this
value
is
greater
than
zero,
this
is
the
RFP
reduction
requirement
for
that
non­
attainment
area.
If
that
value
is
less
than
or
equal
to
zero,
no
further
RFP
reduction
is
required.

The
one
variation
to
this
calculation
is
that
mobile
source
reductions
are
discounted
by
13%
(
i.
e.,
only
87%
of
mobile
source
reductions
are
creditable
toward
the
RFP
progress
requirements).
The
reason
this
discount
is
applied
is
because
there
are
certain
reductions
in
motor
vehicle
emissions
that
will
occur
in
the
future
but
are
the
result
of
actions
taken
prior
to
the
enactment
of
the
1990
Clean
Air
Act
Amendments.

B.
SAMPLE
CALCULATION
Below
is
a
sample
calculation
for
Chicago­
Gary­
Lake
County,
IL­
IN
non­
attainment
area:

2001
emissions
totals
=
136,743
tons
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05.07.002/
9010.466
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Draft
Report
2007
emissions
totals
=
103,531
tons
2010
emissions
totals
=
124,683
tons
Interpolation
of
2001
&
2007
yields
2002
emissions=
131,208
tons
Interpolation
of
2007&
2010
yields
2008
emissions
=
110,581
tons
After
discounting
of
mobile
emissions
by
13%,
2002
emission
=
128,060
tons.

Additional
VOC
tons
required
to
reduce
=
(
2008
Emissions)
­
(
85%
of
2002
Emissions)
=
(
110,581)
­
(
0.85
x
128,060)
=
1,731
tons
C.
RESULTS
Table
1
shows
the
VOC
progress
requirements
to
meet
a
15%
reduction
from
2002
emission
levels
by
2008.
The
15%
reduction
calculation
allows
100%
credits
for
VOC
reductions
obtained
from
2002
to
2008
through
implementation
of
other
emission
reduction
programs
 
except
for
the
mobile
source
discount
described
above.

Table
1.
What
are
the
reasonable
further
progress
requirements
for
VOC
in
nonattainment
areas
that
are
projected
to
exceed
the
O3
NAAQS
in
2010?

Area
Name
Base
Case
2010
VOC
emissions
(
tons)
Estimated
Additional
VOC
Reductions
to
Meet
a
Stringent
15%
RFP
Requirements
(
tons)**
Estimated
Additional
VOC
Reductions
Observed
in
2010
as
a
%
of
2010
Base
Case
Emissions
Baltimore
74,205
0
0%
Chicago
124,683
1,731
1.4%
Cleveland
143,384
3,049
2.1%
Dallas
163,259
4,561
2.8%
Houston
180,976
0
0%
Milwaukee
78,997
803
1.0%
New
York
City
543,482
0
0%
Philadelphia
267,448
0
0%
Providence
57,929
8,209
14%
Sheboygan
7,576
402
5.3%
Washington
DC
130,638
0
0%

III.
DIFFERENCE
IN
COST,
EMISSIONS
REDUCTIONS
ENERGY,
and
ECONOMIC
IMPACTS
In
this
section,
the
total
control
cost,
emission
reductions,
energy
cost,
and
economic
impacts
differences
between
the
two
options
are
provided.
The
regulatory
baseline
for
the
difference
analysis
is
the
more
flexible
implementation
framework
for
RACT
and
RFP.

A.
ANALYSIS
METHODOLOGY
Twelve
nonattainment
areas
outside
of
California
are
included
in
this
analysis.
These
are
the
designated
non­
attainment
areas
where
adopting
the
less
flexible
RACT
and
RFP
options
could
lead
to
cost,
emission
reduction,
energy,
and/
or
economic
impact
differences
relative
to
more
PECHAN
July
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Document
No.
05.07.002/
9010.466
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Draft
Report
flexible
RACT
and
RFP
options.
These
areas
are
shown
in
Table
2.
This
table
provides
the
details
of
the
RACT,
RFP
and
ERT
requirements
for
each
area
under
both
the
more
flexible
and
less
flexible
options.
ERT
requirements
are
the
reductions
in
NOx
and
VOC
that
are
needed
by
2010
to
meet
the
8­
hr
ozone
standard.

Multiple
listings
are
provided
for
the
Dallas
and
Raleigh
areas
because
EPA
designated
more
counties
under
8­
hr
ozone
standard
than
the
1­
hour
ozone
standard.
As
a
result
and
since
these
areas
were
designated
as
Moderate
or
above
for
their
1­
hr
non­
attainment
designation,
RACT
is
required
only
in
the
new
counties.
Our
analysis
assumes
that
all
counties
previously
designated
as
moderate
or
above
non­
attainment
for
the
1­
hr
ozone
standard
have
met
their
RACT
requirements
in
the
base
case.
Multiple
listings
are
provided
for
Chicago
because
EPA
modeling
determined
that
certain
counties
in
the
non­
attainment
area
required
NOx
reductions,
while
others
needed
VOC
reductions,
to
meet
the
ozone
standard.

While
in
the
real
world
RACT
applicability
is
determined
on
a
case
by
case
basis
by
the
State,
we
make
the
following
assumptions
to
identify
RACT
controls
in
counties
where
they
are
required.

 
Current
NOx
control
efficiency
is
zero
(
i.
e.
uncontrolled
utility
and
non­
utility
source)
 
Total
annual
NOx
emissions
of
the
source
is
greater
than
100
tons
(
i.
e.,
large
source)
 
Control
efficiency
of
the
selected
control
measure
is
less
than
81
percent
for
NOx
 
Control
cost
is
less
than
$
1,580
per
ton
NOx
reduced
(
i.
e.,
cost
effective
control
is
available)
 
Control
measure
has
the
lowest
NOx
control
efficiency
from
that
source
(
i.
e.,
minimum
control
available)

1.
Difference
Analysis
Methodology
The
cost
and
control
measure
database
used
in
this
analysis
was
created
using
AirControlNET.
AirControlNET
is
a
comprehensive
database
of
control
measures
and
cost
information
for
reducing
the
emissions
of
criteria
pollutants.
The
system
links
cost,
applicability,
and
control
efficiency
information
to
emission
inventory
data
to
calculate
control
costs
and
emission
reductions
by
individual
source
and
control
measure.
It
provides
information
on
control
efficiency,
capital
cost,
operating
and
maintenance
cost,
annualized
cost,
cost
effectiveness,
and
cost
per
year
for
each
control
measure/
source
combination.

The
cost
of
meeting
the
emission
reduction
requirements
is
determined
under
each
option
and
area.
This
is
done
by
using
control
techniques,
efficiencies,
and
cost
databases
in
concert
with
the
incremental
emission
reduction,
mandatory
control
measures,
and
progress
requirements
mentioned
above.
Where
controls
are
prescriptive
(
i.
e.
RACT
and/
or
RFP),
the
costing
is
straight
forward
and
a
command
and
control
approach
is
used.
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Draft
Report
Table
2.
Does
meeting
the
requirements
of
each
of
the
options
and
ERT
result
in
additional
cost?

More
Flexible
Option
Less
Flexible
Option
Area*
RACT
Remaining
RFP
Requirement
Remaining
ERT
Requirement
RACT
Remaining
RFP
Requirement
Remaining
ERT
Requirement
Allegan
Co,
MI
(
1)
None
None
None
Yes
None
None
Chicago,
IL
(
2)
None
None
Yes
None
Yes
Yes
Chicago­
Gary­
Lake
County,
IL­
IN
(
Cook,
IL
&
L
(
2)
None
None
Yes
None
None
Yes
Columbus,
OH
(
1)
None
None
None
Yes
None
None
Dallas,
TX
­
5
Counties
Area
(
2)
Yes
Yes
None
Yes
None
None
Dallas,
TX
(
2)
None
None
Yes
None
Yes
Yes
Door
Co,
WI
(
1)
None
None
None
Yes
Yes
None
Indianapolis,
IN
(
1)
None
None
None
Yes
None
None
Knoxville,
TN
(
1)
None
None
None
Yes
None
None
Milwaukee,
WI
(
2)
None
None
Yes
None
Yes
Yes
Providence
(
All
RI),
RI
(
2)
None
None
Yes
None
Yes
Yes
Raleigh­
Durham
(
1)
None
None
None
None
None
None
Raleigh­
Durham­
Chapel
Hill
(
5
Counties)
(
1)
None
None
None
Yes
None
None
South
Bend­
Elkhart,
IN
(
1)
None
None
None
Yes
None
None
Youngstown­
Warren­
Sharon,
OH­
PA
(
1)
None
None
None
Yes
None
None
*(
1)
­
Subpart
1
Area
(
2)
­
Subpart
2
Area
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Draft
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For
each
non­
attainment
area,
control
measures
are
applied,
on
the
least­
cost
basis,
until
the
additional
reductions
are
obtained
to
meet
the
ERTs
provided
by
EPA.
The
least­
cost
algorithm
first
applies
the
cheapest
control
by
pollutant
(
on
a
cost
per
ton
basis),
if
the
target
is
not
met
then
the
second
least
expensive
control
is
applied
and
so
forth
until
the
reduction
target
is
met
or
exceeded.
The
model
first
applies
VOC
controls
and
then
NOx
controls.
For
non­
attainment
areas
where
the
anticipated
differences
are
the
result
of
both
the
RACT
and
RFP,
the
emissions
reductions
from
RACT
and
RFP
are
creditable
toward
the
ERT
requirements.
This
approach
avoids
overstating
the
emission
reduction
differences
between
the
options.

For
the
RFP
requirements,
there
are
no
prescribed
control
measure.
In
this
case,
a
least­
cost
algorithm
was
also
used
to
identify
and
apply
the
control
measures
to
meet
the
progress
requirements,
where
applicable.
First,
the
potential
sources
of
emission
and
reductions
and
their
costs
are
identified.
Next,
the
lowest
cost,
second
lowest,
third
lowest,
and
so
forth
control
measures
are
selected
until
the
progress
requirement
is
met.
Because
of
the
discrete
nature
of
control
measures
and
their
efficiencies,
sometimes
the
emission
reduction
or
progress
target
is
exceeded.

The
reductions
required
to
meet
RFP
targets
are
allowed
from
sources
within
100
km
radius
for
VOC
reductions
and
within
200
km
radius
for
NOx
reductions
was
selected
on
least
cost
basis.
However,
each
time
a
source/
control
measure
from
outside
the
non­
attainment
area
boundary
is
selected
to
meet
RFP
target
requirement,
the
RFP
target
for
that
area
is
recalculated.
RFP
target
recalculation
is
performed
by
adding
the
selected
source
emissions
to
the
base
inventory
of
the
area.
The
RFP
target
recalculation
followed
the
RFP
target
calculation
methods
described
above.

Similarly,
and
after
applying
RACT
and
RFP,
if
an
area
requires
additional
reductions
to
meet
the
ERT,
source/
controls
within
100
km
radius
for
VOC
reductions
and
within
200
km
radius
for
NOx
reductions
are
allowed
for
selected
on
least
cost
basis.

2.
Energy
Impact
Methodology
This
section
provides
the
methodology
used
to
estimate
the
energy
cost
differences
(
electricity,
natural
gas,
and
coal)
associated
with
adoption
of
each
of
the
two
scenarios.
The
installation
of
air
pollution
controls
at
polluting
facilities
produces
increases
in
energy
usage
due
to
additional
energy
requirements
of
add­
on
control
devices,
energy
deficits,
and
changes
in
the
combustion
processes.
Most
air
pollution
control
devices
impose
an
additional
energy
demand
to
operate
devices
such
as
fans,
pumps,
and
monitoring
equipment.
As
an
example,
in
selective
catalytic
reduction
systems
(
SCR),
fans
create
the
additional
demand
for
energy
because
the
catalyst
core
that
forms
the
reactor
reduces
flue
gas
pressure
and
velocity.
For
a
selective
non­
catalytic
reduction
system
(
SNCR),
energy
loses
in
the
combustion
process
occur
due
to
improper
flow
of
inlet
air
or
fuel
rates,
improper
design
of
combustion
zones,
and
the
restricted
movement
of
exhaust
gases.

The
net
energy
usage
for
add­
on
control
devices
are
estimated
using
data
obtained
from
EPA's
Control
Cost
Manual
and
Control
Cost
worksheets
available
from
EPA's
website
PECHAN
July
2005
Document
No.
05.07.002/
9010.466
7
Draft
Report
(
http://
www.
epa.
gov/
ttn/
catc/
dir1/
c_
allchs.
pdf).
The
add­
on
control
measures
evaluated
include
four
control
devices:
SCR,
SNCR,
water
injection,
and
thermal
incineration.

Energy
costs
by
fuel
type
are
estimated
based
on
the
cost
of
electricity,
coal,
or
natural
gas
(
obtained
from
the
Control
Cost
Manual)
calculated
as
a
percentage
of
the
total
annualized
for
that
control
measure.
Using
a
SCR
system
installed
on
wall
coal­
fired
industrial
boiler
as
an
example:

Given
that:

Electricity
cost
=
$
0.05/
kW
Number
of
SCR
operating
hours
=
8,760
hr/
yr
SCR
power
consumption
=
445
kW
Capacity
Factor
=
27%
Total
Annualized
Cost
of
SCR
at
this
facility
=
$
1,452,942/
yr
then,

Electricity
Cost
=
445
kW
x
8,760
hr/
yr
x
0.27
x
0.05/
kW
=
$
52,626/
yr
and;

Electricity
Cost
as
%
of
Total
Annualized
Cost
=
$
52,626/$
1,452,942
=
3.6%.

Table
3
summarizes
the
electricity,
coal
and
natural
gas
as
a
percentage
of
the
total
annual
cost
for
each
control.

Table
3.
What
are
the
energy
costs
as
a
%
of
the
total
annualized
control
cost?

%
of
Total
Annual
Cost
Control
Measure
Electricity
Natural
Gas
Coal
SCR
3.6
0
0
SNCR
1.3
0
3.8
Water
Injection
3.6
0
0
NGR
0
85.5
0
Thermal
incineration
8.2
6.1
0
3.
Economic
Impact
Differences
In
general,
implementation
of
the
less
flexible
option
increases
the
cost
and
the
economic
impact
where
these
controls
were
required.
These
increased
requirements
result
in
more
economic
sectors
being
affected
under
the
less
flexible
option.

In
order
to
show
these
differences,
the
costs
and
emissions
were
summed
by
NAICS
code
and
non­
attainment
area
and
examined
when
differences
in
controls
costs
were
observed.
Point
sources
were
summarized
separately
from
the
area/
mobile
sources.
To
estimate
economic
PECHAN
July
2005
Document
No.
05.07.002/
9010.466
8
Draft
Report
impacts,
control
costs
were
compared
to
average
revenue
by
area
and
sector
obtained
from
the
U.
S.
Census
Bureau.

For
example,
in
Chicago,
IL
for
NAICS
Code
441
(
Motor
Vehicle
and
Part
Dealer)
three
point
source
controls
were
chosen.

The
total
revenue
obtained
from
census
data
was
$
8,732,937,000
(
see
US
Census
website
at
http://
www.
census.
gov/
epcd/
ec97/
us/
US000.
HTM).
The
difference
in
potential
economic
impact
was
calculated
as
the
median
control
cost
and
average
control
cost
for
NAICS
code
331
and
presented
as
the
percent
of
average
revenue.

Total
control
cost
=
$
369,326
Cost
as
percent
of
Revenue:

Average
Cost
=
$
369,326/$
8,732,937,000
=
0.00411
%

Average
control
costs
were
used
for
point
sources
as
measures
of
the
potential
economic
impact.
This
is
possible
because
the
number
of
controls
and
the
number
of
units
are
available.
However
for
area
and
mobile
sources,
the
number
of
sources
in
each
category
and
the
allocation
are
not
available
hence
the
total
cost
(
aggregated
control
cost)
to
the
total
revenue
was
used
to
present
the
economic
impact.

B.
RESULTS
In
this
section,
the
total
control
cost,
emission
reductions,
energy
cost,
and
economic
impacts
differences
between
the
less
and
more
flexible
options
are
provided.

1.
Difference
Analysis
The
results
of
the
difference
analysis
are
provided
in
Tables
3.2
and
3.3.
Table
3.2
provides
a
summary
of
the
differences
in
NOx
and
VOC
emissions
reductions
by
non­
attainment
area.
All
reductions
are
presented
as
annual
tons
per
year
reduced.
For
each
non­
attainment
area
the
reductions
are
provided
for
RACT,
RFP,
and
ERT
for
both
the
less
and
more
flexible
options.
The
differences
shown
in
Table
3.2
are
presented
as
the
less
flexible
option
minus
the
more
flexible
option.
This
means
for
differences
greater
than
1,
the
less
flexible
option
requires
more
emission
reductions.
This
is
usually
the
case.
The
analysis
results
showed
that
small,
but
quantifiable
NOx
emission
reduction
differences
were
observed
for
Columbus
OH,
Indianapolis,
IN,
Knoxville,
TN,
Raleigh/
Durham,
NC,
South
Bend,
IN,
and
Youngstown­
Warren­
Sharon,
OH­
PA.
VOC
differences
were
observed
for
Chicago,
Dallas,
Milwaukee,
and
Providence.
Table
3.3
shows
the
costs
associated
with
these
emission
reduction
differences.
Appendix
A
provides
the
detail
results
of
the
difference
analysis
including
NOx
and
VOC
ERTs
and
comments
about
each
non­
attainment
area
and
run.

2.
Energy
Impact
PECHAN
July
2005
Document
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05.07.002/
9010.466
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Draft
Report
Table
3.5
summarizes
the
electricity,
coal
and
natural
gas
costs
for
the
non­
attainment
areas
where
there
are
cost
differences
between
the
two
options.
In
this
table,
the
energy
requirements
are
noted
first
in
dollar
terms
and
then
in
physical
terms
given
certain
fuel
cost
and
energy
price
assumptions
from
Energy
Information
Administration
­
DOE.
These
data
were
obtained
from
http://
www.
eia.
doe.
gov/
emeu/
international/
prices.
html#
Fuels
In
terms
of
economic
impacts,
the
anticipated
differences
in
terms
of
numbers
of
facilities
affected,
economic
sector
(
North
American
Industrial
Classification
Code),
and
annualized
control
cost
are
identified.
The
annualized
cost
for
affected
facilities
is
compared
to
an
annual
revenue
surrogate
to
illustrate
the
amount
of
the
cost
difference
relative
to
the
price
of
the
product
or
service.

Table
7
shows
the
NAICS
level
data
for
points
sources
where
differences
were
observed.
Economic
impact
differences
were
observed
between
in
Columbus,
Knoxville,
Providence,
Raleigh,
and
Youngstown.
For
all
but
two
instances,
the
impacts
were
less
than
1%
of
revenue.
For
area
source
categories,
the
difference
in
control
cost
between
the
two
options
is
shown
in
Table
8.
Only
one
category
had
an
impact
more
than
1%.

3.
Economic
Impacts
Table
7
shows
the
NAICS
level
data
for
points
sources
where
differences
were
observed.
Economic
impact
differences
were
observed
between
in
Chicago,
Green
Bay,
 ..
NAICS
data,
when
there
is
difference
in
control
cost
between
the
two
options
(
area
and
mobile
sources),
is
shown
in
Table
8.

In
terms
of
economic
impacts,
the
anticipated
differences
in
terms
of
numbers
of
facilities
affected,
economic
sector
(
North
American
Industrial
Classification
Code),
and
annualized
control
cost
are
identified.
The
annualized
cost
for
affected
facilities
is
compared
to
an
annual
revenue
surrogate
to
illustrate
the
amount
of
the
cost
difference
relative
to
the
price
of
the
product
or
service.

C.
LIMITATIONS
It
is
the
States
that
will
implement
the
RACT
and
RFP
requirements
and
other
elements
of
the
implementation
framework.
What
is
presented
here
is
a
simulation
that
should
offer
directionally
sound
results.
The
less
flexible
option
should
cost
more
in
dollar,
energy,
and
economic
impact
terms
while
getting
more
emission
reductions.
However,
in
some
instances
these
additional
emission
reductions
may
be
for
one
ozone
precursor
(
VOC)
while
the
emission
reduction
target
may
be
in
terms
of
the
other
ozone
precursor
(
NOx)
PECHAN
July
2005
Document
No.
05.07.002/
9010.466
10
Draft
Report
Table
4.
What
are
the
emission
reduction
differences
between
the
two
options?

Area
*
RACT
VOC
Emission
Reduction
TPY
RACT
NOx
Emission
Reduction
TPY
Remaining
RFP
VOC
Emission
Reductions
TPY
Remaining
RFP
NOx
Emission
Reductions
TPY
Remaining
ERT
VOC
Emission
Reductions
TPY
Remaining
ERT
NOx
Emission
Reductions
TPY
Total
VOC
TPY
Total
NOx
TPY
Allegan
Co,
MI
(
1)
­
Less
Flexible
0
0
0
0
0
0
0
0
Allegan
Co,
MI
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Chicago,
IL
(
2)
­
Less
Flexible
0
0
2,713
0
0
62,335
2,713
62,335
Chicago,
IL
(
2)
­
More
Flexible
0
0
0
0
0
62,335
0
62,335
0
0
2,713
0
0
0
2,713
0
Chicago­
Gary­
Lake
County,
IL­
IN
(
Cook,
IL
&
L
(
2)
­
Less
Flexible
0
0
0
0
53,807
0
53,807
0
Chicago­
Gary­
Lake
County,
IL­
IN
(
Cook,
IL
&
L
(
2)
­
More
Flexible
0
0
0
0
53,807
0
53,807
0
0
0
0
0
0
0
0
0
Columbus,
OH
(
1)
­
Less
Flexible
0
1,061
0
0
0
0
0
1,061
Columbus,
OH
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
1,061
0
0
0
0
0
1,061
Dallas,
TX
­
5
Counties
Area
(
2)
­
Less
Flexible
0
3,367
0
0
0
0
0
3,367
Dallas,
TX
­
5
Counties
Area
(
2)
­
More
Flexible
0
3,367
1,867
0
0
0
0
3,367
0
0
­
1,867
0
0
0
0
0
Dallas,
TX
(
2)
­
Less
Flexible
0
0
8,945
0
0
28,693
8,945
28,693
Dallas,
TX
(
2)
­
More
Flexible
0
0
1,867
0
0
28,693
1,867
28,693
0
0
7,078
0
0
0
7,078
0
Door
Co,
WI
(
1)
­
Less
Flexible
0
0
1,025
0
0
0
1,025
0
Door
Co,
WI
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
0
1,025
0
0
0
1,025
0
Indianapolis,
IN
(
1)
­
Less
Flexible
0
723
0
0
0
0
0
723
Indianapolis,
IN
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
723
0
0
0
0
0
723
Knoxville,
TN
(
1)
­
Less
Flexible
0
4,030
0
0
0
0
0
4,030
Knoxville,
TN
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
4,030
0
0
0
0
0
4,030
Milwaukee,
WI
(
2)
­
Less
Flexible
0
0
1,085
0
0
24,867
1,085
24,867
Milwaukee,
WI
(
2)
­
More
Flexible
0
0
0
0
0
24,867
0
24,867
0
0
1,085
0
0
0
1,085
0
PECHAN
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Draft
Report
Table
4
(
continued)

Area*
RACT
VOC
Emission
Reduction
TPY
RACT
NOx
Emission
Reduction
TPY
Remaining
RFP
VOC
Emission
Reductions
TPY
Remaining
RFP
NOx
Emission
Reductions
TPY
Remaining
ERT
VOC
Emission
Reductions
TPY
Remaining
ERT
NOx
Emission
Reductions
TPY
Total
VOC
TPY
Total
NOx
TPY
Providence
(
All
RI),
RI
(
2)
­
Less
Flexible
0
0
8,254
0
0
940
8,254
940
Providence
(
All
RI),
RI
(
2)
­
More
Flexible
0
0
0
0
0
940
0
940
0
0
8,254
0
0
0
8,254
0
Raleigh­
Durham
(
1)
­
Less
Flexible
0
0
0
0
0
0
0
0
Raleigh­
Durham
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Raleigh­
Durham­
Chapel
Hill
(
5
Counties)
(
1)
­
Less
Flexible
0
965
0
0
0
0
0
965
Raleigh­
Durham­
Chapel
Hill
(
5
Counties)
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
965
0
0
0
0
0
965
South
Bend­
Elkhart,
IN
(
1)
­
Less
Flexible
0
333
0
0
0
0
0
333
South
Bend­
Elkhart,
IN
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
333
0
0
0
0
0
333
Youngstown­
Warren­
Sharon,
OH­
PA
(
1)
­
Less
Flexible
0
1,302
0
0
0
0
0
1,302
Youngstown­
Warren­
Sharon,
OH­
PA
(
1)
­
More
Flexible
0
0
0
0
0
0
0
0
0
1,302
0
0
0
0
0
1,302
*
(
1)
Subpart
1
Area
(
2)
Subpart
2
Area
PECHAN
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Draft
Report
Table
5.
What
are
the
cost
differences
between
the
two
options
in
millions
of
1997
$?

Area*
RACT
Remaining
RFP
Requirement
Remaining
ERT
Requirement
Total
Difference
Allegan
Co,
MI
(
1)
­
Less
Flexible
­
­
­
­

Allegan
Co,
MI
(
1)
­
More
Flexible
­
­
­
­
­

Chicago,
IL
(
2)
­
Less
Flexible
­
0.5
104.1
104.6
Chicago,
IL
(
2)
­
More
Flexible
­
­
104.1
104.1
0.5
Chicago­
Gary­
Lake
County,
IL­
IN
(
Cook,
IL
&
L
(
2)
­
Less
Flexible
­
­
184.9
184.9
Chicago­
Gary­
Lake
County,
IL­
IN
(
Cook,
IL
&
L
(
2)
­
More
Flexible
­
­
184.9
184.9
­

Columbus,
OH
(
1)
­
Less
Flexible
1.0
­
­
1.0
Columbus,
OH
(
1)
­
More
Flexible
­
­
­
­
1.0
Dallas,
TX
­
5
Counties
Area
(
2)
­
Less
Flexible
0.9
­
­
0.9
Dallas,
TX
­
5
Counties
Area
(
2)
­
More
Flexible
0.9
­
­
0.9
­
PECHAN
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Draft
Report
Table
5
(
continued)

Area*
RACT
Remaining
RFP
Requirement
Remaining
ERT
Requirement
Total
Difference
Dallas,
TX
(
2)
­
Less
Flexible
­
2.1
41.2
43.3
Dallas,
TX
(
2)
­
More
Flexible
­
­
41.2
41.2
2.1
Door
Co,
WI
(
1)
­
Less
Flexible
­
0.3
­
0.3
Door
Co,
WI
(
1)
­
More
Flexible
­
­
­
­
0.3
Indianapolis,
IN
(
1)
­
Less
Flexible
0.8
­
­
0.8
Indianapolis,
IN
(
1)
­
More
Flexible
­
­
­
­
0.8
Knoxville,
TN
(
1)
­
Less
Flexible
1.0
­
­
1.0
Knoxville,
TN
(
1)
­
More
Flexible
­
­
­
­
1.0
Milwaukee,
WI
(
2)
­
Less
Flexible
­
0.0
34.2
34.2
Milwaukee,
WI
(
2)
­
More
Flexible
­
­
34.2
34.2
0.0
PECHAN
July
2005
Document
No.
05.07.002/
9010.466
14
Draft
Report
Table
5
(
continued)

Area*
RACT
Remaining
RFP
Requirement
Remaining
ERT
Requirement
Total
Difference
Providence
(
All
RI),
RI
(
2)
­
Less
Flexible
­
14.1
1.6
15.7
Providence
(
All
RI),
RI
(
2)
­
More
Flexible
­
­
1.6
1.6
14.1
Raleigh­
Durham
(
1)
­
Less
Flexible
­
­
­
­

Raleigh­
Durham
(
1)
­
More
Flexible
­
­
­
­
­

Raleigh­
Durham­
Chapel
Hill
(
5
Counties)
(
1)
­
Less
Flexible
0.4
­
­
0.4
Raleigh­
Durham­
Chapel
Hill
(
5
Counties)
(
1)
­
More
Flexible
­
­
­
­
0.4
South
Bend­
Elkhart,
IN
(
1)
­
Less
Flexible
0.4
­
­
0.4
South
Bend­
Elkhart,
IN
(
1)
­
More
Flexible
­
­
­
­
0.4
Youngstown­
Warren­
Sharon,
OH­
PA
(
1)
­
Less
Flexible
0.8
­
­
0.8
Youngstown­
Warren­
Sharon,
OH­
PA
(
1)
­
More
Flexible
­
­
­
­
0.8
21.5
*
(
1)
Subpart
1
Area
(
2)
Subpart
2
Area
PECHAN
July
2005
Document
No.
05.07.002/
9010.466
15
Draft
Report
Table
6.
What
is
the
energy
impact
difference
anticipated
in
1997$?

NAA
Electricity
$
Electricity
(
KWH)
s
Natural
Gas
$
Natural
Gas
(
m3)
Coal
$
Coal
(
metric
tons)

Indianapolis,
IN
0
0
527,375
5,412,4595
0
0
Youngstown­
Warren­
Sharon,
OH­
PA
1,962
43,6032
587,161
6,026,043
5,736
161
Knoxville,
TN
9,422
126,9762
0
0
27,541
771
Raleigh­
Durham,
NC
1,572
34,940
219,271
2,250,378
4,596
129
Total
12,956
34,9406
1,333,807
13,688,8797
37,872
1,061
PECHAN
July
2005
Document
No.
05.07.002/
9010.466
16
Draft
Report
Table
7.
What
are
the
economic
impacts,
by
NAICS
and
area,
when
differences
in
costs
are
observed
between
the
two
options
for
point
sources?

Cost
as
%
of
Revenue
Area
Name
NAICS
Control
Cost
Average
Establishment
Revenue
($
1000)
Mean
Median
NAICS
Description
Columbus,
OH
3272
$
238,688
$
108,021
0.2210
0.2331
Glass
and
Glass
Product
Manufacturing
Columbus,
OH
327212
$
571,722
$
262,028
0.2182
0.2333
Other
Pressed
and
Blown
Glass
and
Glassware
Manufacturing
Columbus,
OH
452910
$
95,277
$
23,688
0.4022
0.4022
Warehouse
Clubs
and
Superstores
Indianapolis,
IN
327213
$
231,816
$
24,184
0.9585
0.9585
Glass
Container
Manufacturing
Knoxville,
TN
311221
$
285,218
$
9,631
2.9614
2.9614
Wet
Corn
Milling
Knoxville,
TN
324122
$
58,704
$
9,629
0.6096
0.6096
Asphalt
Shingle
and
Coating
Materials
Manufacturing
Knoxville,
TN
327310
$
44,057
$
4,268
1.0324
1.0324
Cement
Manufacturing
Knoxville,
TN
332114
$
105,153
$
3,303
3.1836
3.1836
Custom
Roll
Forming
Knoxville,
TN
332117
$
266,140
$
0
Powder
Metallurgy
Part
Manufacturing
Providence
(
All
RI),
RI
313221
$
12,766
$
8,945
0.1427
0.1427
Narrow
Fabric
Mills
Providence
(
All
RI),
RI
313311
$
148,384
$
55,725
0.2663
0.2524
Broadwoven
Fabric
Finishing
Mills
Providence
(
All
RI),
RI
313320
$
50,911
$
19,944
0.2553
0.2376
Fabric
Coating
Mills
Providence
(
All
RI),
RI
314991
$
11,872
$
1,946
0.6099
0.6099
Rope,
Cordage,
and
Twine
Mills
Raleigh­
Durham­
Chapel
Hill
(
5
Counties)
221111
$
753,211
$
315,521
0.2387
0.6837
Hydroelectric
Power
Generation
Yonugstown­
Warren­
Sharon,
OH­
PA
324199
$
96,135
$
16,133
0.5959
0.5959
All
Other
Petroleum
and
Coal
Products
Manufacturing
Yonugstown­
Warren­
Sharon,
OH­
PA
221111
$
687,140
$
77,024
0.8921
0.8921
Hydroelectric
Power
Generation
PECHAN
July
2005
Document
No.
05.07.002/
9010.466
17
Draft
Report
Table
8.
What
are
the
economic
impacts,
by
NAICS
and
area,
when
differences
in
costs
are
observed
between
the
two
options
for
area
sources?

Cost
as
%
of
Revenue
Area
Name
NAICS
Control
Cost
No.
of
Establishments
Average
County
or
Establishment
Revenue
($
1000)
Mean
Median
NAICS
Description
Chicago,
IL
441
$
359,326
1,049
$
8,732,937
0.0041
0.0061
Motor
Vehicle
and
Parts
Dealers
Chicago,
IL
446
$
43,160
181
$
315,206
0.0137
0.0170
Health
and
Personal
Care
Stores
Chicago,
IL
32412
$
0
0
$
544,453
0.0000
0.0000
Asphalt
Paving,
Roofing,
and
Saturated
Materials
Manufacturing
Chicago,
IL
44­
45
$
82,750
6,701
$
20,531,805
0.0004
0.0005
Retail
Trade
Dallas,
TX
441
$
200,110
543
$
2,133,241
0.0094
0.0106
Motor
Vehicle
and
Parts
Dealers
Dallas,
TX
446
$
68,868
274
$
300,401
0.0229
0.0255
Health
and
Personal
Care
Stores
Dallas,
TX
562
$
442,768
341
$
304,595
0.1454
0.5623
Waste
Management
and
Remediation
Services
Dallas,
TX
32412
$
0
0
$
80,811
0.0000
0.0000
Asphalt
Paving,
Roofing,
and
Saturated
Materials
Manufacturing
Dallas,
TX
44­
45
$
53,960
3,558
$
7,907,424
0.0007
0.0008
Retail
Trade
Door
Co,
WI
321
$
7,038
23
$
69,084
0.0102
0.0102
Wood
Product
Manufacturing
Door
Co,
WI
324
$
0
0
$
35,388
0.0000
0.0000
Petroleum
and
Coal
Products
Manufacturing
Door
Co,
WI
326
$
57,305
24
$
296,622
0.0193
0.0167
Plastics
and
Rubber
Products
Manufacturing
Door
Co,
WI
337
$
15,470
39
$
370,721
0.0042
0.0039
Furniture
and
Related
Product
Manufacturing
Door
Co,
WI
441
$
56,512
287
$
1,476,822
0.0038
0.0038
Motor
Vehicle
and
Parts
Dealers
Door
Co,
WI
447
$
157,683
199
$
327,953
0.0481
0.0528
Gasoline
Stations
Door
Co,
WI
562
$
8,080
20
$
44,506
0.0182
0.0273
Waste
Management
and
Remediation
Services
Door
Co,
WI
31­
33
$
21,127
502
$
7,732,375
0.0003
0.0007
Manufacturing
Milwaukee,
WI
324
$
0
0
$
43,911
0.0000
0.0000
Petroleum
and
Coal
Products
Manufacturing
Milwaukee,
WI
562
$
24,429
363
$
740,592
0.0033
0.0029
Waste
Management
and
Remediation
Services
Providence
(
All
RI),
RI
324
$
0
0
$
55,222
0.0000
0.0000
Petroleum
and
Coal
Products
Manufacturing
Providence
(
All
RI),
RI
325
$
10,804,849
60
$
625,949
1.7262
1.5799
Chemical
Manufacturing
Providence
(
All
RI),
RI
441
$
32,200
362
$
1,503,577
0.0021
0.0014
Motor
Vehicle
and
Parts
Dealers
Providence
(
All
RI),
RI
31­
33
$
3,015,749
250
$
1,664,666
0.1812
0.2714
Manufacturing
