Document ID: EPA-HQ-OAR-2002-0058-0634
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-02-26T05:00Z

UNFUNDED
MANDATES
REFORM
ACT
ANALYSIS
FOR
THE
INDUSTRIAL
BOILERS
AND
PROCESS
HEATERS
NESHAP
RULEMAKING
UNDER
THE
CLEAN
AIR
ACT
(
February
2004)

This
document
provides
an
analysis
of
the
effects
of
the
U.
S.
Environmental
Protection
Agency's
("
EPA")
industrial/
commercial/
institutional
(
henceforth
called
"
industrial")
maximum
achievable
control
technology
(
MACT)
rulemaking
under
Title
III
of
the
Clean
Air
Act
on
State,
local,
and
tribal
governments,
and
the
public
sector
as
required
by
the
Unfunded
Mandates
Reform
Act
of
1995
("
UMRA").
The
Agency
has
determined
that
an
UMRA
analysis
is
required
because
this
MACT
rulemaking
will
affect
units
operated
by
State
and
local
governments,
and
will
impose
a
cost
on
the
private
sector
greater
than
$
100
million
in
any
one
year.

This
UMRA
analysis
examines
the
impacts
of
the
rule
on
units
that
are
owned
by
State,
local,
and
tribal
governments.
This
analysis
is
drawn
from
the
economic
impact
analysis
conducted
for
the
rule,
and
this
analysis
is
available
in
the
public
docket.

Background
on
the
Rule
and
Affected
Sources
Sources
affected
by
this
rule
include
all
industrial
boilers
and
process
heaters
located
at
a
major
facility.
For
this
rule,
a
fuel
means
any
material
combusted
in
a
boiler
or
process
heater
that
is
not
considered
a
solid
waste.
Affected
sources
do
not
include
municipal
waste
combustors,
medical
waste
incinerators,
fossil
fuel­
fired
electric
utility
steam
generating
units,
commercial
and
industrial
solid
waste
incineration
units,
recovery
boilers
or
furnaces,
or
hazardous
waste
combustors
required
to
have
a
permit
under
section
3005
of
the
Solid
Waste
Disposal
Act
or
are
subject
to
40
CFR
part
63,
subpart
EEE.

The
rule
is
set
at
the
MACT
floor
established
for
both
existing
and
new
sources.
For
existing
sources,
the
MACT
floor
is
the
median
of
the
best
performing
12
percent
of
affected
sources
(
i.
e.,
the
industrial
boiler
or
process
heater
units
representing
the
94th
percentile).
The
median
is
the
control
technology
in
the
middle
of
the
range
of
the
best
performing
12
percent
of
sources.
After
establishing
this
technology
basis,
the
Agency
then
examined
the
available
emissions
data
to
determine
achievable
emissions
limits.
The
resulting
emissions
limits
associated
with
the
MACT
floors
for
each
pollutant
represent
the
maximum
pound
per
mmBTU
heat
input
emission
rate
reported
for
the
given
pollutant/
control
technology
combination
for
each
subcategory,
of
which
there
are
nine.
For
new
sources,
the
Agency
determined
the
MACT
floor
for
each
pollutant
category
by
identifying
the
best­
controlled
source
for
each
subcategory
on
a
pollutant
category­
by­
pollutant
category
basis.
The
Agency
then
examined
the
available
emissions
data
from
affected
sources
to
determine
achievable
emission
limits.
The
resulting
emissions
limits
associated
with
the
MACT
floors
for
each
pollutant
are
based
on
the
highest
data
point
from
a
unit
using
the
"
best"
technology,
since
such
a
value
is
a
reasonable
estimate
of
the
performance
of
the
"
best­
controlled
similar
unit"
under
the
worst
foreseeable
circumstances.
The
emissions
limits
per
pollutant
for
both
existing
and
new
sources
are
listed
below
in
Table
1.

The
rule
affects
both
existing
and
new
industrial
boilers
and
process
heaters.
Emission
limits
were
developed
for
large,
small,
and
limited
use
solid,
liquid,
and
gas
fuel­
fired
units.
Large
units
are
those
with
heat
input
capacities
greater
than
10
MMBtu/
hr.
Small
units
are
those
with
heat
input
capacities
less
than
or
equal
to
10
MMBtu/
hr.
Limited
use
units
are
those
with
capacity
utilizations
less
than
or
equal
to
10
percent
as
required
in
a
federally
enforceable
permit.
You
must
meet
the
emission
limits
and
work
practice
standards
for
the
subcategories
in
Table
1
of
this
preamble
for
each
of
the
pollutants
listed.
Emission
limits
and
work
practice
standards
were
developed
for
new
and
existing
sources;
and
for
large,
small,
and
limited
use
solid,
liquid,
and
gas
fuel­
fired
units.
Large
units
are
those
watertube
boilers
and
process
heaters
with
heat
input
capacities
greater
than
10
million
British
thermal
units
per
hour
(
MMBtu/
hr).
Small
units
are
any
firetube
boilers
or
any
boiler
and
process
heater
with
heat
input
capacities
less
than
or
equal
to
10
MMBtu/
hr.
Limited
use
units
are
those
large
units
with
capacity
utilizations
less
than
or
equal
to
10
percent
as
required
in
a
federally
enforceable
permit.

If
your
new
or
existing
boiler
or
process
heater
is
permitted
to
burn
a
solid
fuel
(
either
as
a
primary
fuel
or
a
backup
fuel),
or
any
combination
of
solid
fuel
with
liquid
or
gaseous
fuel,
the
unit
is
in
one
of
the
solid
subcategories.
If
your
new
or
existing
boiler
or
process
heater
burns
a
liquid
fuel,
or
a
liquid
fuel
in
combination
with
a
gaseous
fuel,
the
unit
is
in
one
of
the
liquid
subcategories,
except
if
the
unit
burns
liquid
only
during
periods
of
gas
curtailment.
If
your
new
or
existing
boiler
or
process
heater
burns
a
gaseous
fuel
not
combined
with
any
liquid
or
solid
fuels,
or
burns
liquid
fuel
only
during
periods
of
gas
curtailment
or
gas
supply
emergencies,
the
unit
is
in
the
gaseous
subcategory.

TABLE
1.
EMISSION
LIMITS
AND
WORK
PRACTICE
STANDARDS
FOR
BOILERS
AND
PROCESS
HEATERS
(
pounds
per
million
British
thermal
units
(
lb/
MMBtu))

Source
Subcategory
Particulate
Matter
(
PM)
or
Total
Selected
Metals
Hydrogen
Chloride
(
HCl)
Mercury
(
Hg)
Carbon
Monoxide
(
CO)(
ppm)

New
Boiler
or
Process
Heater
Solid
Fuel,
Large
Unit
0.025
or
0.0003
0.02
0.000003
400
(@
7%
oxyg
en)

Solid
Fuel,
Small
Unit
0.025
or
0.0003
0.02
0.000003
­­

Solid
Fuel,
Limited
Use
0.025
or
0.0003
0.02
0.000003
400
(@
7%
oxyg
en)

Liquid
Fuel,
Large
Unit
0.03
­­
0.0005
­­
400
(@
3%
oxyg
en)

Liquid
Fuel,
Small
Unit
0.03
­­
0.0009
­­
­­

Liquid
Fuel,
Limited
Use
0.03
­­
0.0009
­­
400
(@
3%
oxyg
en)

Gaseous
Fuel
Large
Unit
­­
­­
­­
­­
400
(@
3%
oxyg
en)
Gaseous
Fuel
Small
Unit
­­
­­
­­
­­
­­

Gaseous
Fuel
Limited
Use
­­
­­
­­
­­
400
(@
3%
oxyg
en)

Existing
Boiler
or
Process
Heater
Solid
Fuel,
Large
Unit
0.07
or
0.002
0.09
0.000009
­­

Solid
Fuel,
Small
Unit
­­
­­
­­
­­
­­

Solid
Fuel,
Limited
Use
0.21
or
0.002
­­
­­
­­

Liquid
Fuel,
Large
Unit
­­
­­
­­
­­
­­

Liquid
Fuel,
Small
Unit
­­
­­
­­
­­
­­

Liquid
Fuel,
Limited
Use
­­
­­
­­
­­
­­

Gaseous
Fuel
­­
­­
­­
­­
­­

aTotal
non­
mercury
metal
HAPs
include:
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
and
nickel.

For
solid
fuel­
fired
boilers
or
process
heaters,
sources
may
choose
one
of
two
emission
limit
options:
(
1)
existing
and
new
affected
units
may
choose
to
limit
PM
emissions
to
the
level
listed
in
Table
1
of
this
preamble,
or
(
2)
existing
and
new
affected
units
may
choose
to
limit
total
selected
metals
emissions
to
the
level
listed
in
Table
1
of
this
preamble.

Sources
meeting
the
emission
limits
must
also
meet
operating
limits.

We
have
provided
several
alternative
compliance
options
in
the
final
rule.
Sources
may
choose
to
demonstrate
compliance
based
on
the
fuel
pollutant
content.
Sources
are
also
allowed
to
demonstrate
compliance
for
existing
solid
fuel­
fired
units
using
emissions
averaging.
In
addition,
sources
of
hydrochloric
acid
(
HCl)
and
manganese
(
Mn)
can
also
take
advantage
of
a
alternative
compliance
option
if
the
risk
level
of
their
emissions
is
low
enough.

For
more
information
on
the
provisions
of
the
rule,
please
refer
to
the
preamble.

Of
the
57,000
industrial
boilers
and
process
heaters
known
to
operate
at
a
major
source
facility
in
the
United
States,
only
3,730
existing
ones
(
or
6
percent)
are
likely
to
incur
costs
associated
with
this
rule.

According
to
the
economic
impact
analysis,
the
rule
is
expected
to
affect
257
existing
sources
nationwide
owned
by
54
different
government
entities.
Of
these
54
entities,
13
are
communities,
and
27
are
universities.
The
remaining
14
are
spread
across
these
government
entities:
the
federal
government,
States,
and
counties.
Virtually
all
of
the
existing
sources
affected
at
these
facilities
are
industrial
boilers
that
are
fossil
fuel­
fired
and
provide
electric
power
to
consumers.
For
more
information,
please
refer
to
the
"
Economic
Impact
Analysis
of
Air
Pollution
Regulations:
Boilers
and
Process
Heaters
NESHAP"
which
is
in
the
docket.

Benefit
and
Cost
Impacts
for
this
Rule
The
annual
compliance
costs
to
existing
affected
sources,
which
include
the
costs
of
control
and
monitoring,
recordkeeping,
and
reporting
requirements,
are
estimated
at
$
863
million
(
1999
dollars)
for
implementation
of
the
rule
through
2005.
It
should
be
noted
that
the
impacts
of
this
rule
are
estimated
through
2005.
Annual
compliance
costs
to
new
affected
sources,
of
which
there
are
380,
are
estimated
at
$
26
million
(
1999
dollars)
through
2005.
The
benefits
of
this
rule
include
the
reduction
of
hazardous
air
pollutants
(
HAP)
that
are
metals
such
as
arsenic,
cadmium,
chromium,
lead,
manganese,
mercury,
and
nickel.
Virtually
all
of
these
metal
HAPs
are
known,
probable,
or
possible
carcinogens.
Other
HAPs
whose
emissions
will
be
reduced
by
this
rule
are
hydrochloric
acid
and
hydrogen
fluoride.
Other
benefits
of
this
rule
include
the
reduction
of
criteria
pollutants
such
as
particulate
matter
(
both
PM10
and
PM2.5)
and
sulfur
dioxide
(
SO2).
The
estimated
HAP
emissions
reductions
from
existing
sources
are
58,500
tons
per
year
through
2005.
Emissions
of
HCl
will
be
reduced
by
42,000
tpy
for
existing
units.
Emissions
of
mercury
will
be
reduced
by
1.9
tpy
for
existing
units.
Emissions
of
total
selected
nonmercury
metals
(
i.
e.,
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
nickel,
and
selenium)
will
be
reduced
by
1,100
tpy
for
existing
units.
The
coarse
particulate
(
PM10)
emission
reductions
from
existing
sources
are
estimated
to
be
562,000
tons
per
year
through
2005,
the
fine
particulate
(
PM2.5)
are
estimated
at
159,000
tons
through
2005
and
the
SO2
emissions
reductions
from
existing
sources
are
estimated
at
113,000
tons
per
year
through
2005.
The
additional
emissions
reductions
from
new
sources
is
a
very
small
fraction
of
the
estimated
emission
reductions
from
existing
sources;
the
total
reduction
of
HAPs
from
new
sources
is
only
73
tons
per
year
through
2005.
Of
these
reductions,
72
tons
per
year
of
HCL
are
reduced,
1.4
tons
per
year
of
the
total
selected
nonmercury
metals,
and
0.006
tons
per
year
of
mercury
are
reduced.
For
non­
HAP
emissions,
the
reductions
from
new
sources
are
as
follows:
480
tons
per
year
of
PM10,
134
tons
per
year
of
PM2.5,
and
110
tons
per
year
of
SO2.

The
Agency
is
not
able
to
monetize
the
benefits
from
the
HAP
emission
reductions
due
to
a
lack
of
scientific
data.
However,
the
Agency
is
able
to
monetize
the
benefits
from
the
PM10,
PM2.5,
and
SO2
emissions
reductions.
The
monetized
benefits
from
these
reductions
from
existing
sources
are
substantial:
$
16.1
billion
(
1999
dollars),
which
is
the
Agency's
primary
benefits
estimate
for
this
rule.
The
difference
between
the
primary
benefits
estimate
and
the
estimated
annual
costs
is
$
15.3
billion
(
1999
dollars).
It
should
be
noted
that
there
are
a
large
number
of
benefits
from
the
PM
and
SO2
emission
reductions
that
could
not
be
monetized,
and
these
are
defined
as
"
B"
in
the
RIA.
These
benefits
are
listed
below
in
Table
2.
For
more
information
on
the
compliance
costs
and
benefits,
please
refer
to
the
"
Regulatory
Impact
Analysis
for
the
Industrial
Boilers
and
Process
Heaters
NESHAP"
which
is
in
the
docket.
TABLE
2.
C
UNQUANTIFIED
BENEFIT
CATEGORIES
Unquantified
benefit
categories
associated
with
HAP
Unquantified
benefit
categories
associated
with
PM
Health
Categories
C
Airway
responsiveness
C
Pulmonary
inflammation
C
Increases
susceptibility
to
respiratory
infection
C
Acute
inflammation
and
respiratory
cell
damage
C
Chronic
respiratory
damage/
Premature
aging
of
lungs
C
Emergency
room
visits
for
asthma
C
Changes
in
pulmonary
function.

C
Morphological
changes.
Altered
host
defense
mechanisms
C
Other
chronic
respiratory
disease
C
Emergency
room
visits
for
asthma
C
Emergency
visits
for
non­
asthma
respiratory
and
cardiovascular
causes
C
Lower
and
upper
respiratory
systems
C
Acute
bronchitis
C
Shortness
of
breath
C
Increased
school
absence
rates
C
Materials
damage
C
Damage
to
ecosystems
(
e.
g.,
acid
sulfate
deposition).

C
Nitrates
in
drinking
water
C
Visibility
in
recreational
and
residential
areas
Welfare
Categories
C
Ecosystem
and
vegetation
effects
C
Damage
to
urban
ornamentals
(
e.
g.
grass,
flowers,
shrubs,
and
trees
in
urban
areas)

C
Commercial
field
crops
C
Fruit
and
vegetable
crops
C
Reduced
yields
of
tree
seedlings,
commercial
and
non­
commercial
forests
C
Damage
to
ecosystems
C
Materials
damage
This
rule
requires
the
minimum
level
of
control
and
paperwork
burden
to
existing
and
new
industrial
boilers
and
process
heaters
that
is
consistent
with
the
requirements
of
the
Clean
Air
Act.
Other
alternatives
considered
that
provided
more
than
the
minimum
level
of
control
were
deemed
as
not
cost­
effective
for
the
Agency
to
implement.
For
an
explanation
of
the
choice
of
regulatory
alternatives
for
this
rule,
refer
to
the
preamble.
Hence,
the
Agency
has
tried
to
keep
the
impacts
from
compliance
with
this
rule
to
a
minimum
for
the
affected
sources,
including
government
entities.

Impacts
on
Government
Entities
A
screening
analysis
conducted
as
part
of
the
economic
impact
analysis
for
this
rule
identified
13
small
communities
(
defined
by
the
Small
Business
Administration
as
communities
with
a
population
of
less
than
50,000
people)
that
may
be
affected.
All
of
these
communities
own
and
operate
affected
public
power
producers.
For
this
report,
public
power
producers
are
defined
as
nonprofit
publically
owned
electrical
utilities
operated
by
municipalities,
counties,
and
states
or
other
publicly
owned
bodies
such
as
public
utility
districts.
Rural
electric
cooperatives
are
not
part
of
this
definition.

The
vast
majority
of
small
municipal
systems
with
affected
boilers
are
located
in
the
Midwest
(
11
of
13,
or
85
percent).
Four
of
these
eleven
municipal
systems
are
located
in
Minnesota,
two
in
Michigan,
two
in
Indiana,
and
one
each
in
Iowa,
Ohio,
and
Wisconsin.
The
other
two
small
municipal
systems
are
found
in
Vermont
and
California.
6
Public
power
producers
do
not
pay
local
or
State
taxes.
However,
they
are
typically
under
agreements
to
make
annual
contributions
to
state
and
local
government
operating
funds.
In
addition,
they
are
not
guaranteed
a
rate
of
return
as
regulated
public
utilities
are,
but
their
rates
are
set
by
agreement
with
local
councils
and
these
rates
are
typically
adjusted
to
reflect
changes
in
operating
costs.

Municipal
utilities
have
the
ability
to
generate
capital
through
the
issuance
of
tax
exempt
municipal
bonds.
These
municipal
bonds
are
exempt
from
federal
income
tax,
and
this
allows
these
utilities
finance
capital
projects
at
a
more
affordable
rate.
Additionally,
the
local
governments
investing
in
municipal
utilities
generally
issue
revenue
bonds
rather
than
general
obiligation
bonds.
This
ensures
that
the
debt
is
paid
back
through
revenues
from
electricity
generation
and
does
not
obligate
the
local
government
or
community
tax
base.

Of
these
communities,
6
are
expected
to
have
annual
compliance
costs
of
1
percent
or
greater
of
their
revenues
through
2005.
The
median
compliance
costs
as
a
percent
of
revenues
for
all
13
communities
is
0.9
percent
with
only
one
community
having
compliance
costs
as
a
percent
of
revenues
much
greater
than
that
(
7.4
percent).
For
more
information,
please
refer
to
the
"
Economic
Impact
Analysis
of
Air
Pollution
Regulations:
Boilers
and
Process
Heaters,"
which
is
in
the
docket.

It
is
expected
that
the
impacts
to
government
entities
resulting
from
this
rule
should
be
a
small
proportion
of
the
impacts
to
affected
entities.
Only
$
2.9
million
of
the
annual
costs
for
this
rule
will
be
borne
by
small
communities.

References
1.
U.
S.
Environmental
Protection
Agency,
Office
of
Air
Quality
Planning
and
Standards.
"
Economic
Analysis
of
Air
Pollution
Regulations:
Boilers
and
Process
Heaters."
Research
Triangle
Park,
North
Carolina.
November,
2003.

2.
U.
S.
Environmental
Protection
Agency,
Office
of
Air
Quality
Planning
and
Standards.
"
Regulatory
Impact
Analysis
for
the
Proposed
Industrial
Boilers
and
Process
Heaters
NESHAP."
Research
Triangle
Park,
North
Carolina.
November,
2003.

3.
American
Public
Power
Association
(
APPA).
2002.
Straight
Answers
to
False
Charges
About
Public
Power.
Washington,
D.
C.,
APPA.
Obtained
on
November
13,
2003
at
http://
www.
appanet.
org/
about/
publicpower/
index.
cfm.