1
MEMORANDUM
TO:
EPA
Docket:
OAR
2004­
0076
FROM:
USEPA,
Clean
Air
Markets
Division
SUBJECT:
Unfunded
Mandates
Reform
Act
(
UMRA)
Analysis
for
Proposed
Federal
Implementation
Plan
for
Clean
Air
Interstate
Rule
and
Proposed
Response
to
North
Carolina's
Section
126
Petition
DATE:
August
23,
2005
Background
and
Overview
of
Proposed
Rulemaking
Title
II
of
the
UMRA
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,
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).

The
EPA
believes
that
the
requirements
of
Section
202
of
UMRA
apply
to
the
proposed
Federal
implementation
plans
(
FIP)
for
the
Clean
Air
Interstate
Rule
(
CAIR)
and
section
126
action
because
this
proposed
action
could
result
in
the
establishment
of
enforceable
mandates
directly
applicable
to
sources
(
including
sources
owned
by
State
and
local
governments)
that
could
result
in
costs
greater
than
$
100
million
in
any
one
year.
The
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least­
costly,
most
cost­
effective
or
least­
burdensome
alternative
that
achieves
the
objectives
of
the
rule.

On
May
12,
2005
EPA,
as
authorized
by
section
301
of
the
Clean
Air
Act,
published
the
CAIR
in
the
Federal
Register
to
ensure
compliance
with
the
requirements
of
section
110(
a)(
2)(
D)
of
the
CAA,
relating
to
interstate
transport
of
air
pollution.
In
a
final
rule
signed
the
same
day
as
2
the
CAIR
and
published
on
April
25,
2005,
EPA
found
that
States
have
failed
to
submit
SIPs
to
satisfy
the
interstate
transport
requirements
under
section
110(
a)(
2)(
D)(
i)
of
the
CAA
for
the
PM2.5
and
8­
hour
ozone
NAAQS.
(
70
FR
21147).
These
findings
give
EPA
the
authority
to
issue
a
FIP
at
any
time
to
correct
the
deficiencies
and
require
that
the
Administrator
issue
a
FIP
for
each
State,
within
two
years
of
making
such
findings,
unless
a
SIP
revision
correcting
the
deficiency
is
approved
by
EPA
before
a
FIP
is
promulgated.
In
March
2004,
North
Carolina
submitted
a
petition
to
EPA
pursuant
to
Section
126
of
the
Clean
Air
Act
contending
that
emissions
from
certain
facilities
in
upwind
States
contribute
significantly
to
nonattainment
in
and
interfere
with
maintenance
by
the
State
of
North
Carolina
with
the
PM2.5
and
eight­
hour
ozone
standards.
The
petition
requests
that
EPA
find
that
emissions
of
NOx
and
SO
2
from
large
electric
generating
units
(
EGUs)
in
12
States
are
significantly
contributing
to
nonattainment
with
and
interfering
with
maintenance
of
the
PM2.5
standard
and
that
NOx
emissions
from
EGUs
in
five
States
are
significantly
contributing
to
8­
hour
ozone
nonattainment
and
interfering
with
maintenance
of
the
standard.
If
EPA
makes
such
findings,
EPA
would
be
authorized
to
establish
Federal
emissions
limits
for
the
affected
sources.
EPA
has
entered
into
a
consent
decree
with
the
State
of
North
Carolina,
agreeing
to
respond
to
the
petition
through
notice­
and­
comment
rulemaking,
and
to
issue
proposed
findings
and
any
necessary
control
remedies
by
August
1,
2005.

During
the
CAIR
rulemaking
process,
the
Agency
did
not
reach
a
conclusion
regarding
the
applicability
of
the
UMRA
requirements
to
the
CAIR.
Notwithstanding,
the
Agency
prepared
a
written
statement
for
the
CAIR
Supplemental
Notice
of
Proposed
Rulemaking
(
SNPR)
consistent
with
the
requirements
of
Section
202
of
the
UMRA.
Furthermore,
as
EPA
stated
in
the
CAIR
proposal,
the
Agency
is
not
obligated
to
develop
under
Section
203
of
the
UMRA
a
small
government
agency
plan
for
the
CAIR.
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
the
CAIR.

While
not
required
for
the
CAIR,
EPA
analyzed
the
economic
impacts
of
the
CAIR
on
government
entities
for
informational
purposes.
Specifically,
EPA
identified
81
State
and
municipality
owned
electric
generating
entities
potentially
affected
by
the
emission
reduction
requirements,
and
analyzed
the
potential
impact
on
these
entities.
That
analysis
assumed
that
all
States
would
adopt
the
CAIR
model
trading
rules
and
thus
it
quantified
the
impact
of
applying
the
model
trading
rules
to
sources
in
States
affected
by
the
CAIR.
The
analysis
did
not
examine
potential
indirect
economic
impacts
associated
with
the
CAIR,
such
as
employment
effects
in
industries
providing
fuel
and
pollution
control
equipment,
or
the
potential
effects
of
electricity
price
increases
on
industries
and
households.

The
Agency
is
now
proposing
FIPs
for
all
States
affected
by
the
CAIR.
The
FIPs
would
serve
as
a
backstop
measure
to
achieve
the
emission
reductions
requirements
established
by
the
CAIR
until
States
have
approved
State
implementation
plans
(
SIPs)
to
achieve
the
reductions.
The
Agency
also
proposes
EPA's
response
to
a
petition
submitted
by
the
State
of
North
Carolina
under
section
126
of
the
CAA.
The
EPA
is
proposing
Federal
cap
and
trade
programs
for
electric
3
1
The
IPM
is
a
multiregional,
dynamic,
deterministic
linear
programming
model
of
the
U.
S.
electric
power
sector.
The
Agency
uses
IPM
to
examine
costs
and,
more
broadly,
analyze
the
projected
impact
of
environmental
polices
on
the
electric
power
sector
in
the
48
contiguous
States
and
the
District
of
Columbia.
Documentation
for
IPM
can
be
found
at
www.
epa.
gov/
airmarkets/
epa­
ipm.
generation
units
(
EGUs)
as
the
control
strategy
for
the
FIPs
as
well
as
the
section
126
action.
The
proposed
Federal
cap
and
trade
programs
are
virtually
identical
to
the
CAIR
model
trading
rules.
The
government­
entity
analysis
prepared
for
the
CAIR
identifies
the
maximum
potential
impact
of
the
CAIR
FIP
and
section
126
response,
and
the
Agency
relied
on
the
CAIR
analysis
to
determine
the
potential
impact
of
the
proposed
CAIR
FIP
and
section
126
action
on
governmental
entities.

As
explained
in
more
detail
in
the
CAIR
regulatory
impact
analysis
(
RIA),
the
Agency
used
the
Integrated
Planning
Model
(
IPM)
1
to
model
emission
and
economic
impacts
of
the
CAIR.
The
EPA's
modeling
assumed
that
affected
States
would
adopt
regulations
that
implement
the
CAIR
model
trading
programs,
and
we
modeled
the
CAIR
requirements
on
a
geographic
region
that
is
almost
identical
to
the
region
that
would
be
affected
by
the
proposed
CAIR
FIPs
 
the
CAIR
modeling
included
annual
SO
2
and
NO
x
requirements
for
Arkansas,
however
this
State
would
be
subject
only
to
ozone
season
NOx
requirements
under
the
proposed
FIP.
(
Therefore,
the
total
impacts
of
the
proposed
FIPs
on
government­
owned
entities
are
somewhat
overstated
in
the
CAIR
analysis
because
that
analysis
assumed
annual
reduction
requirements
in
Arkansas.)
The
section
126
response
would
affect
a
subset
of
the
CAIR
States.

Because
the
Federal
cap
and
trade
programs
for
electric
generation
units
(
EGUs)
EPA
is
proposing
as
the
control
strategy
for
the
FIPs
as
well
as
the
section
126
action
are
virtually
identical
to
the
CAIR
model
trading
rules,
the
analysis
and
written
statement
prepared
for
CAIR
satisfies
the
requirements
of
section
202
of
the
UMRA
with
respect
to
the
proposed
CAIR
FIP
and
section
126
action.
The
analysis
prepared
for
CAIR
is
presented
below
(
the
same
analysis
is
presented
in
chapter
8
in
the
Regulatory
Impact
Analysis
for
the
CAIR,
available
in
the
CAIR
docket).
In
addition
to
the
intergovernmental
consultations
that
EPA
carried
out
during
the
CAIR
process,
the
Agency
also
consulted
with
governmental
agencies
during
development
of
the
proposed
CAIR
FIP
and
section
126
response.
The
EPA
convened
a
Small
Business
Advocacy
Review
Panel
and
conducted
outreach
to
small
entity
representatives,
including
representatives
of
small
government
entities,
to
obtain
the
advice
and
recommendations
of
small
entities
that
potentially
would
be
subject
to
the
proposed
CAIR
FIP
and
section
126
response
(
the
resulting
report
is
in
the
docket
for
this
proposal).
The
Agency
conducted
CAIR
outreach
meetings
and
invited
representatives
of
all
States
that
would
be
affected
by
the
proposed
CAIR
FIP
and
section
126
response.

Identification
of
Government­
Owned
Entities
Using
eGRID
data,
EPA
identified
State
and
municipality­
owned
utilities
and
subdivisions
4
2
EGRID
is
EPA's
Emissions
&
Generation
Resource
Integrated
Database,
which
contains
emissions
and
resource
mix
data
for
virtually
every
power
plant
and
company
that
generates
electricity
in
the
United
States.
eGRID
is
available
at
www.
epa.
gov/
cleanenergy/
egrid/
download.
htm.
in
the
CAIR
region.
2
EPA
then
used
IPM
output
(
from
modeling
based
on
assuming
that
affected
States
adopt
regulations
that
implement
the
CAIR
model
trading
rules)
to
associate
these
plants
with
individual
generating
units.
Entities
that
did
not
own
at
least
one
unit
with
a
generating
capacity
of
greater
than
25
MW
were
omitted
from
the
analysis
because
of
their
exemption
from
the
CAIR.
This
exempts
179
entities
owned
by
State
or
local
governments.
Additionally,
government­
owned
entities
for
which
IPM
does
not
project
generation
in
either
2010
or
2015
under
the
base
case
or
CAIR
were
exempted
from
this
analysis,
because
they
are
not
projected
to
be
operating
and
thus
will
not
face
the
costs
of
compliance
with
the
CAIR.
Five
municipal
entities
were
dropped
from
the
analysis
for
this
reason.
Thus,
EPA
identified
81
State
and
municipality­
owned
utilities
that
are
potentially
affected
by
the
CAIR,
out
of
a
possible
265,
which
are
summarized
in
Table
1.

Table
1.
Summary
of
Potential
Impacts
on
Government
Entities
under
CAIR
EGU
Ownership
Type
Potentially
Affected
Entities
Projected
Annualized
Costs
($
1,000,000)
Number
of
Government
Entities
with
Compliance
Costs
>
1%
of
Generation
Revenues
Number
of
Government
Entities
with
Compliance
Costs
>
3%
of
Generation
Revenues
2010
2015
2010
2015
2010
2015
Subdivision
5

$
15.2

$
1.7
3
3
0
1
State
7

$
134.2

$
110.5
0
2
0
0
Municipal
69

$
162.5

$
97.9
17
34
17
22
Total
81

$
311.9
 
$
210.2
20
39
17
23
Note:
The
total
number
of
potentially
affected
entities
in
this
table
excludes
the
184
entities
that
have
been
dropped
because
they
will
not
be
affected
by
CAIR.
Also,
the
total
number
of
entities
with
costs
greater
than
1
percent
or
3
percent
of
revenues
includes
only
entities
experiencing
positive
costs.
A
negative
cost
value
implies
that
the
group
of
entities
experiences
a
net
savings
under
CAIR.
Source:
IPM
and
TRUM
analysis
Overview
of
Analysis
and
Results
After
identifying
potentially
affected
government
entities,
EPA
estimated
the
impact
of
the
CAIR
in
2010
and
2015
based
on
the
following:


total
impacts
of
compliance
on
government
entities
and
5

ratio
of
small
entity
impacts
to
revenues
from
electricity
generation.

The
financial
burden
to
owners
of
EGUs
under
CAIR
is
composed
of
compliance
and
administrative
costs.
This
section
outlines
the
compliance
and
administrative
costs
for
the
81
potentially
affected
government­
owned
units
in
the
CAIR
region.

Methodology
for
Estimating
Impacts
of
CAIR
on
Government
Entities
The
primary
burden
on
State
and
municipal
governments
that
operate
utilities
under
CAIR
is
the
cost
of
installing
control
technology
on
units
to
meet
SO
2
and
NO
x
emission
limits
or
the
cost
of
purchasing
allowances.
However,
an
entity
can
comply
with
CAIR
through
any
combination
of
the
following:
installing
retrofit
technologies,
purchasing
allowances,
switching
to
a
cleaner
fuel,
or
reducing
emissions
through
a
reduction
in
generation.
Additionally,
units
with
more
allowances
than
needed
can
sell
these
allowances
on
the
market.
The
chosen
compliance
strategy
will
be
primarily
a
function
of
the
unit's
marginal
control
costs
and
its
position
relative
to
the
marginal
control
costs
of
other
units.

To
attempt
to
account
for
each
potential
control
strategy,
EPA
estimates
compliance
costs
as
follows:
C
Compliance
=
 
C
Operating+
Retrofit
+
 
C
Fuel
+
 
C
Allowances
+
 
C
Transaction
 
 
R
where
C
represents
a
component
of
cost
as
labeled,
and
 
R
represents
the
retail
value
of
foregone
electricity
generation.

In
reality,
compliance
choices
and
market
conditions
can
combine
such
that
an
entity
may
actually
experience
a
savings
in
any
of
the
individual
components
of
cost.
Under
CAIR,
for
example,
EPA
projects
that
the
price
of
low­
sulfur
coal
will
fall
as
many
units
install
scrubbers
and
switch
away
from
low­
sulfur
coal
to
cheaper
bituminous
coal,
such
that
many
entities
burning
low­
sulfur
coal
actually
experience
a
reduction
in
fuel
costs
as
a
result
of
the
demand
shift.
Similarly,
although
some
units
will
forgo
some
level
of
electricity
generation
(
and
thus
revenues)
to
comply,
this
impact
will
be
lessened
on
these
entities
by
the
projected
increase
in
electricity
prices
under
CAIR
as
well
as
reductions
in
fuel
costs,
while
those
not
reducing
generation
levels
will
see
an
increase
in
electricity
revenues.
Elsewhere,
units
burning
high­
or
medium­
sulfur
coal
might
decide
to
pay
relatively
more
for
low­
sulfur
coal
under
CAIR
and
sell
allowances
on
the
market,
in
the
hopes
of
negating
some
or
all
of
their
compliance
cost.
Because
this
analysis
evaluates
the
total
costs
along
each
of
these
four
compliance
strategies
for
each
entity,
it
inevitably
captures
savings
or
gains
such
as
those
described.
As
a
result,
what
we
describe
as
cost
is
really
more
of
a
measure
of
the
net
economic
impact
of
the
rule
on
small
entities.

In
this
analysis,
EPA
used
IPM­
parsed
output
for
the
base
case
and
CAIR
(
http://
www.
epa.
gov/
airmarkets/
epa­
ipm/
iaqr.
html)
to
estimate
compliance
cost
at
the
unit
level.
These
costs
were
then
summed
for
each
small
entity,
adjusting
for
ownership
share.
Compliance
cost
estimates
were
based
on
the
following:
operating
and
retrofit
costs,
sale
or
purchase
of
allowances,
and
the
change
in
fuel
costs
or
electricity
generation
revenues
under
CAIR
relative
to
6
3A
similar
approach
was
used
in
impact
analyses
for
the
prior
section
126
action
and
FIP
for
the
NO
x
SIP
Call.
the
base
case.
These
components
of
compliance
cost
were
estimated
as
follows:

(
1)
Retrofit
and
operating
costs:
Using
the
IPM­
parsed
output
for
the
base
case
and
CAIR
(
http://
www.
epa.
gov/
airmarkets/
epa­
ipm/
iaqr.
html),
EPA
identified
units
that
install
control
technology
under
CAIR
and
the
technology
installed.
The
equations
for
calculating
retrofit
costs
were
adopted
from
EPA's
Technology
Retrofit
and
Updating
Model
(
TRUM).
The
model
calculates
the
capital
cost
(
in
$/
MW);
the
fixed
operation
and
maintenance
(
O&
M)
cost
(
in
$/
MW­
year);
the
variable
O&
M
cost
(
in
$/
MWh);
and
the
total
annualized
retrofit
cost
for
units
projected
to
install
FGD,
SCR,
or
SNCR.

(
2)
Sale
or
purchase
of
allowances:
EPA
estimated
the
value
of
initial
SO
2
and
NO
x
allowance
holdings.
For
SO
2,
units
were
assumed
to
retain
their
Phase
II
allowance
allocations
as
determined
under
EPA's
1998
reallocation
of
Acid
Rain
allowances,
adjusted
to
reflect
the
50
percent
reduction
in
2010
and
65
percent
reduction
in
2015
under
CAIR.
The
value
of
banked
SO
2
allowances
was
not
considered
in
this
analysis.
Because
the
use
of
banked
allowances
is
expected
to
be
a
significant
compliance
strategy,
this
analysis
most
likely
overstates
annualized
compliance
costs.
For
NO
x,
the
State
emission
budgets
were
assumed
to
be
apportioned
to
units
on
a
heat­
input
basis.
Each
unit
was
assumed
to
receive
a
share
of
the
State
NO
x
emission
budget
equal
to
its
share
of
the
total
State
heat
input
for
that
year
in
the
base
case.
This
is
a
simplification
of
what
is
included
in
the
model
rule,
which
proposes
allocating
NO
x
allowances
based
on
heat
input
from
1999
through
1992.3
However,
States
can
ultimately
decide
how
to
allocate
NO
x
allowances.

To
estimate
the
value
of
allowances
holdings,
allocated
allowances
were
subtracted
from
projected
emissions,
and
the
difference
was
then
multiplied
by
the
allowance
price
projected
by
IPM.
Units
were
assumed
to
purchase
or
sell
allowances
to
exactly
cover
their
projected
emissions
under
CAIR.

(
3)
Fuel
costs:
Fuel
costs
were
estimated
by
multiplying
fuel
input
(
MMBtu)
by
region
and
fuel
type­
adjusted
fuel
prices
($/
MMBtu)
from
TRUM.
The
change
in
fuel
expenditures
under
CAIR
was
then
estimated
by
taking
the
difference
in
fuel
costs
between
CAIR
and
the
base
case.

(
4)
Value
of
electricity
generated:
EPA
estimated
electricity
generation
by
first
estimating
the
unit
capacity
factor
and
maximum
fuel
capacity.
The
unit
capacity
factor
is
estimated
by
dividing
fuel
input
(
MMBtu)
by
maximum
fuel
capacity
(
MMBtu).
The
maximum
fuel
capacity
was
estimated
by
multiplying
capacity
7
4
All
costs
are
reported
in
1999
dollars.

5
Neither
the
costs
nor
the
revenues
of
units
that
retire
under
CAIR
are
included
in
this
portion
of
the
analysis.
Because
these
units
are
better
off
retiring
under
CAIR
than
continuing
operation,
the
true
cost
of
the
rule
on
these
units
is
not
represented
by
our
modeling.
The
true
cost
of
CAIR
for
these
units
is
the
differential
between
their
costs
in
the
base
case
and
the
costs
of
meeting
their
customers'
demand
under
the
rule.
(
MW)
*
8,760
operating
hours
*
heat
rate
(
MMBtu/
MWh).
The
value
of
electricity
generated
was
then
estimated
by
multiplying
capacity
(
MW)*
capacity
factor*
8,760*
regional­
adjusted
retail
electricity
price
($/
MWh).

(
5)
Administrative
costs:
Because
most
affected
units
are
already
monitored
as
a
result
of
other
regulatory
requirements,
EPA
considered
the
primary
administrative
cost
to
be
transaction
costs
related
to
purchasing
or
selling
allowances.
EPA
assumed
that
transaction
costs
were
equal
to
1.5
percent
of
the
total
absolute
value
of
a
unit's
allowances.
This
assumption
is
based
on
market
research
by
ICF
Consulting.

Results
A
summary
of
economic
impacts
on
government­
owned
entities
is
presented
in
Table
1.
According
to
EPA's
analysis,
the
total
net
economic
impact
on
each
category
of
government­
owned
entity
(
State
and
municipality­
owned
utilities
and
subdivisions)
is
expected
to
be
negative
in
both
2010
and
2015.4
IPM
modeling
of
CAIR
projects
that
approximately
340
MW
(
8
units
of
219
in
this
analysis)
of
municipality­
owned
capacity
would
be
uneconomic
to
maintain
under
CAIR,
beyond
what
is
projected
in
the
base
case.
This
represents
about
0.4
percent
of
all
subdivision,
State,
and
municipality
capacity
in
the
CAIR
region.
For
comparison,
overall
affected
capacity
under
CAIR,
about
5.3GW,
or
1.7
percent
of
all
coal­
fired
capacity
is
projected
to
be
uneconomic
to
maintain
relative
to
the
base
case.
This
comparison
suggests
that
government
entities
should
not
face
a
disproportionate
burden
under
CAIR.
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.

As
was
done
for
the
small
entities
analysis,
EPA
further
assessed
the
economic
and
financial
impacts
of
the
rule
using
the
ratio
of
compliance
costs
to
the
value
of
revenues
from
electricity
generation
in
the
base
case,
also
focusing
specifically
on
entities
for
which
this
measure
is
greater
than
1
percent.
5
EPA
projects
that
20
government
entities
will
have
compliance
costs
greater
than
1
percent
of
revenues
from
electricity
generation
in
2010,
and
39
will
in
2015.
Entities
that
are
projected
to
experience
negative
compliance
costs
under
CAIR
are
not
included
in
those
totals.
This
approach
is
more
indicative
of
a
significant
impact
when
an
analysis
is
8
looking
at
entities
operating
in
a
competitive
market
environment.
Government­
owned
entities
do
not
operate
in
a
competitive
market
environment
and
therefore
will
be
able
to
recover
expenses
under
CAIR
through
rate
increases.
Given
this,
EPA
considers
the
1
percent
measure
in
this
case
a
crude
measure
of
the
extent
to
which
rate
increases
will
be
made
at
publicly
owned
companies.

The
distribution
across
entities
of
economic
impacts
as
a
share
of
base
case
revenue
is
summarized
in
Table
2.
For
state­
owned
entities
and
subdivisions,
the
maximum
economic
impact
as
a
share
of
base
case
revenues
is
approximately
3
percent.
A
few
municipality­
owned
entities
experience
economic
impacts
that
are
significantly
higher
than
the
capacity­
weighted
average
for
this
group.
In
the
cases
where
entities
are
projected
to
experience
positive
net
costs
that
are
a
high
percentage
of
revenues,
these
entities
do
not
find
it
economic
to
retrofit
and
are
unable
to
switch
to
a
lower­
sulfur
coal.
Thus,
these
entities
comply
primarily
through
the
purchase
of
allowances
and
reductions
in
generation.

Table
2.
Distribution
of
Economic
Impacts
on
Government
Entities
under
CAIR
EGU
Ownership
Type
Capacity­
Weighted
Average
Economic
Impacts
as
a
%
of
Generation
Revenues
Min
Max
2010
2015
2010
2015
2010
2015
Sub­
division
 
3.6%
 
2.0%
 
80.0%
 
27.6%
1.9%
3.1%

State
 
5.2%
 
3.9%
 
11.4%
 
10.2%
0.2%
2.8%

Municipal
 
5.9%
 
0.3%
 
13.8%
 
20.4%
17.2%
43.5%

All
 
4.2%
 
2.3%

80.0%
 
27.6%
17.2%
43.5%

Source:
IPM
and
TRUM
analysis
Additionally,
a
few
entities
are
projected
to
experience
negative
net
costs
that
are
a
high
percentage
of
base
case
revenues.
These
entities
have
units
that
are
able
to
switch
to
a
cheaper,
lower­
sulfur
coal
to
comply
with
CAIR
and
are
able
to
maintain
or
increase
generation
levels,
thus
increasing
revenues.
Additionally,
entities
in
regions
for
which
we
project
large
electricity
price
increases
relative
to
other
regions
tend
to
be
among
those
at
the
lower
end
of
the
distribution.

The
various
components
of
annualized
incremental
cost
under
CAIR
to
each
group
of
government
entities
are
summarized
in
Table
3.
Overall,
with
the
exceptions
of
subdivisions
in
2010,
each
group
is
a
net
purchaser
of
allowances.
Additionally,
each
group
experiences
both
a
reduction
in
fuel
expenditures
and
an
increase
in
electricity
revenue
under
CAIR.
Incremental
fuel
costs
are
negative
because
of
the
combination
of
a
reduction
in
total
coal
use,
switching
to
bituminous
coal,
and
reduced
low­
sulfur
coal
prices
under
CAIR.
Additionally,
although
total
electricity
generation
by
government
entities
falls
slightly
under
CAIR,
the
total
loss
in
revenues
is
9
more
than
exceeded
by
the
revenue
gains
projected
as
a
result
of
retail
electricity
prices
rising
under
CAIR.

Summary
of
Government
Entity
Impacts
The
EPA
examined
the
potential
economic
impacts
on
State
and
municipality­
owned
entities
associated
with
the
CAIR
based
on
assumptions
of
how
the
affected
States
will
implement
control
measures
to
meet
their
emission
reduction
requirements.
These
impacts
were
calculated
for
the
CAIR
rulemaking
to
provide
additional
understanding
of
the
nature
of
potential
impacts
and
additional
information
to
the
States
as
they
revise
SIPs
to
meet
the
emissions
budgets
set
by
the
CAIR
rulemaking.
As
noted
above,
because
the
Federal
cap
and
trade
programs
for
electric
generation
units
(
EGUs)
EPA
is
proposing
as
the
control
strategy
for
the
FIPs
as
well
as
the
section
126
action
are
virtually
identical
to
the
CAIR
model
trading
rules,
the
CAIR
analysis
(
which
assumed
that
States
would
adopt
the
CAIR
model
trading
rules)
meets
the
requirements
of
section
202
of
UMRA
for
the
proposed
CAIR
FIP
and
section
126
action.

Table
3.
Incremental
Annualized
Costs
under
CAIR
Summarized
by
Ownership
Group
and
Cost
Category
($
1,000,000)

EGU
Ownership
Type
Retrofit
+
Operating
Cost
Net
Purchase
of
Allowances
Fuel
Cost
Lost
Electricity
Revenue
Administrative
Cost
2010
2015
2010
2015
2010
2015
2010
2015
2010
2015
Subdivision
10.4
9.4
 
1.6
1.7
 
3.2
 
8.4
 
20.9
 
4.5
0.0
0.1
State
20.1
25.9
29.2
52.5
 
116.8
 
143.1
 
67.0
 
46.3
0.3
0.5
Municipal
21.3
26.7
39.3
94.8
 
120.0
 
156.8
 
103.7
 
63.7
0.7
1.0
Source:
IPM
and
TRUM
analysis
According
to
EPA's
analysis,
the
total
net
economic
impact
on
government­
owned
entities
is
expected
to
be
negative
in
both
2010
and
2015.
However,
IPM
modeling
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
CAIR,
beyond
what
is
projected
in
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.

Of
the
81
government
entities
considered
in
this
analysis
and
the
265
government
entities
in
the
CAIR
region
that
are
included
in
EPA's
modeling,
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
10
revenues
have
some
potential
for
significant
impact
resulting
from
implementation
of
the
proposed
CAIR
FIP
and
section
126
action.
However,
the
majority
of
entities
facing
potentially
significant
impacts
are
located
in
States
with
regulated
electricity
markets,
where
they
have
the
ability
to
pass
some
or
all
of
their
compliance
cost
on
to
ratepayers.
In
addition,
the
decision
to
include
only
units
greater
than
25
MW
in
size
exempts
179
government
entities
that
would
otherwise
be
potentially
affected
by
regulations
implementing
the
CAIR
trading
programs.
Finally,
the
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.
