INFORMATION
COLLECTION
REQUEST
RENEWAL
FOR
THE
ACID
RAIN
PROGRAM
UNDER
THE
CLEAN
AIR
ACT
AMENDMENTS
TITLE
IV
June
25,
2003
1
INFORMATION
COLLECTION
REQUEST
RENEWAL
FOR
THE
ACID
RAIN
PROGRAM
UNDER
THE
CLEAN
AIR
ACT
AMENDMENTS
TITLE
IV
(
JANUARY
1999
THROUGH
JANUARY
2002)

SUPPORTING
STATEMENT
1.
IDENTIFICATION
OF
THE
INFORMATION
COLLECTION
1.1
Background
Title
IV
of
the
Clean
Air
Act
Amendments
of
1990
(
the
acid
rain
title)
establishes
goals
to
reduce
annual
emissions
of
sulfur
dioxide
(
SO2)
and
nitrogen
oxides
(
NO
x)
and
to
place
a
national
cap
on
sulfur
dioxide
emissions
beginning
in
the
year
2000.
Emissions
reductions
are
mandated
in
two
phases:


Beginning
in
1995
(
Phase
I),
part
of
the
SO2
and
NO
x
reductions
are
to
be
achieved
through
emissions
reduction
requirements
at
110
of
the
largest,
highestemitting
power
plants;


Beginning
in
the
year
2000
(
Phase
II),
the
SO2
and
NO
x
reduction
goals
are
to
be
reached
through
more
stringent
requirements
at
virtually
all
fossil
fuel
power
plants.

To
help
meet
emissions
reduction
goals,
Title
IV
provides
for
a
program
that
allocates
emissions
allowances
to
affected
utility
units
based
on
a
national
target
for
SO2
reductions,
and
allows
market
forces
to
achieve
the
targeted
reductions
in
the
most
cost­
effective
manner.
Under
this
program,
each
affected
unit
receives
its
allocation
of
allowances
every
year.
An
affected
unit
must
hold
one
allowance
for
each
ton
of
SO2
it
emits.
Affected
utilities
and
individuals
may
buy
and
sell
allowances,
or
save
them
for
future
use
or
sale.

The
ability
to
buy
and
sell
(
or
transfer)
allowances
provides
substantial
economic
benefits,
by
encouraging
the
greatest
emissions
reductions
where
costs
of
reductions
are
lowest.
This
concept
of
allowance
transfers
cannot
be
implemented,
however,
unless
regulations
governing
emissions
monitoring
and
permitting
of
acid
rain
sources
are
in
place
as
well.
To
ensure
compliance
with
the
emissions
reduction
requirements
and
to
provide
the
national
consistency
needed
to
foster
the
allowance
market,
sections
408
and
412
of
Title
IV
require
the
designated
representative
of
the
owners
and
operators
of
each
affected
acid
rain
source
to
obtain
an
operating
permit
for
the
affected
source
and
to
certify
that
an
approved
emissions
monitoring
system
has
been
installed
and
is
properly
operated
at
each
affected
unit's
source
of
emissions.

Emissions
monitoring
and
reporting
is
the
foundation
upon
which
the
allowance
trading
system
is
based.
Without
accurate
monitoring
and
reporting
of
emissions,
the
integrity
of
the
2
allowance
system
would
be
undermined,
and
there
would
be
no
assurance
that
emissions
had
been
reduced.

Acid
rain
permits
will
allow
sources
the
flexibility
to
comply
with
the
emissions
reduction
requirements
of
Title
IV
by
employing
one
or
more
compliance
options
for
SO2.
The
procedures
specified
in
the
acid
rain
permits
regulations,
including
the
use
of
standardized
forms,
ensure
that
the
intended
flexibility
and
accountability
is
preserved
as
the
Acid
Rain
Program
is
implemented
nationwide
by
different
permitting
authorities.

Participation
in
the
annual
auction
is
voluntary.
Information
will
be
collected
by
EPA's
Acid
Rain
Division,
or
its
designated
agent,
and
will
be
used
to
conduct
and
facilitate
administration
of
the
auction.
Auction
participants
must
submit
a
bid
form
and
payment
method.

Section
410
of
Title
IV
provides
that
sources
of
SO2
emissions
that
are
not
regulated,
i.
e.,
small
utility
units
and
industrial
boilers,
may
elect
to
"
opt
in"
to
the
allowance
allocation
and
trading
program.
To
opt
in,
the
source
owner
or
operator
must
submit
an
opt­
in
permit
application
to
EPA.
Sources
that
opt
in
(
1)
will
become
affected
sources,
(
2)
will
receive
an
annual
allocation
of
allowances,
and
(
3)
may
sell
any
allowances
they
do
not
use
for
their
own
emissions.
Because
opting
in
is
voluntary,
only
those
unaffected
sources
that
would
profit
by
opting
in
are
expected
to
do
so.

Although
the
principal
purpose
of
Title
IV
of
the
Clean
Air
Act
is
to
reduce
acid
rain
by
requiring
reductions
in
emissions
of
SO2
and
NO
x,
it
is
also
the
purpose
of
this
title
to
encourage
energy
conservation
and
pollution
prevention
as
a
long­
range
strategy
for
reducing
air
pollution
and
other
adverse
effects
of
energy
production
and
use.
As
an
incentive
for
electric
utilities
to
(
1)
implement
energy
conservation
measures
and
(
2)
use
renewable
energy,
section
404(
f)
of
Title
IV
establishes
provisions
for
qualifying
electric
utilities
to
receive
allowances
from
the
Conservation
and
Renewable
Energy
Reserve
for
SO2
emissions
avoided
through
either
of
these
two
options.

The
NO
x
emission
reductions
will
be
achieved
through
maximum
allowable
emission
rates
for
coal­
fired
utility
boilers.
The
allowable
rate
for
a
given
boiler
depends
on
the
type
of
boiler.
The
NO
x
regulations
for
coal­
fired
boilers
are
applied
to
two
groups
of
boilers,
as
specified
by
the
Clean
Air
Act
Amendments
of
1990
(
CAAA).
Boilers
in
each
group
become
affected
at
different
times,
as
described
below.
Group
1
boilers
are
(
1)
dry
bottom
wall­
fired
boilers
that
do
not
apply
cell
burner
technology
or
(
2)
tangentially
fired
boilers.
Group
2
boilers
are
all
other
types
of
utility
boilers,
including
(
1)
wet
bottom
wall­
fired
boilers,
(
2)
cyclones,
and
(
3)
boilers
applying
cell
burner
technology.
In
Phase
I,
which
began
January
1,
1996
for
NO
x,
NO
x
emission
limitations
apply
only
to
Group
1
boilers
that
are
subject
to
the
Phase
I
SO
2
limitations.
In
Phase
II,
beginning
January
1,
2000,
NO
x
emission
limitations
become
effective
for
all
boilers
(
Group
1
and
Group
2).

1.2
Information
to
Be
Collected
EPA
has
developed
regulations
to
implement
the
emissions
reduction
provisions
of
Title
3
IV
of
the
Clean
Air
Act
Amendments
that
cover

Allowance
tracking
and
transfers
(
section
403);


Energy
conservation
and
renewable
energy
incentives
(
section
404);


Permits
(
section
408);


Emissions
monitoring
(
section
412);


Auctions
(
section
416);


Opt­
in
(
section
410
a­
g);


Annual
Compliance
Certification
(
sections
403
&
408);


Small
diesel
(
section
410
h);
and
°
NO
x
permitting.

This
Information
Collection
Request
(
ICR)
addresses
the
paperwork
burden
related
to
(
1)
transferring
and
tracking
allowances;
(
2)
obtaining
and
distributing
allowances
from
the
Conservation
and
Renewable
Energy
Reserve;
(
3)
obtaining
and
issuing
permits
and
compliance
plans
(
e.
g.,
submitting
permit
applications);
(
4)
submitting
and
certifying
emissions
monitoring
plans;
(
5)
the
allocation
of
allowances
to
small
diesel
refineries;
(
6)
the
opt­
in
program;
(
7)
annual
year­
end
compliance
certification
reporting;
(
8)
NO
x
permitting,
and,
(
9)
all
labor
associated
with
recording
and
reporting
emissions
data
under
Title
IV
of
the
Clean
Air
Act
Amendments
of
1990.
Burden
estimates
provided
in
this
ICR
are
for
the
period
from
January
31,
1999
to
January
31,
2002.
This
ICR
covers
the
last
year
of
Phase
I,
1999.
The
burden
and
cost
of
continuous
emission
monitoring
is
reflected
in
this
ICR
and
includes
all
Phase
I
and
Phase
II
units.

Allowance
Transfers
All
participants
in
the
allowance
transfer
system
will
be
required
to
complete
and
submit
an
allowance
transfer
form
for
each
allowance
transfer.
This
can
be
done
either
electronically
or
using
a
paper
form.
Participants
in
the
transfer
system
that
are
not
affected
sources
under
Title
IV
will
also
be
required
to
file
a
one
time
account
information
application
to
establish
an
account
in
the
Allowance
Tracking
System
(
ATS).

Conservation
and
Renewable
Energy
Reserve
To
receive
allowances
for
emissions
avoided
through
the
use
of
energy
conservation
measures
or
renewable
energy,
utilities
must
submit
an
application
to
receive
allowances
that
(
1)
designates
and
verifies
the
measures
used
to
avoid
emissions,
(
2)
calculates
the
tons
of
emissions
avoided,
and
(
3)
demonstrates
qualification
to
receive
allowances
from
the
Conservation
and
Renewable
Energy
Reserve.

Permits
Permit
applicants
are
required
to
submit
an
acid
rain
permit
application
for
each
affected
source.
The
permit
application
must
include,
for
each
unit
at
the
source,
(
1)
general
information
on
the
unit,
(
2)
a
complete
compliance
plan
for
each
unit,
and
(
3)
the
Acid
Rain
Program
standard
requirements.

Emissions
Monitoring
4
To
meet
the
emissions
monitoring
record­
keeping
and
reporting
requirements,
affected
units
are
required
to
(
1)
submit
a
monitoring
plan
and
certification
of
monitors,
(
2)
record
hourly
pollutant
and
flow
monitor
data,
and
(
3)
submit
electronic
quarterly
reports
of
their
emissions
data
to
EPA.
Operators
of
new
electric
generating
units
of
25
megawatts
(
MW)
capacity
or
less
may
receive
a
CEMS
exception
if
they
certify
their
use
of
very­
low­
sulfur
fuel.

Submissions
Purposes
and
Procedures
Allowance
transfer
notifications
may
be
submitted
to
EPA
electronically
or
on
paper.
Emissions
reports
must
be
submitted
electronically.
All
Phase
II
permit
applications
must
be
submitted
on
paper.

The
allowance
transfer
submittal
is
used
to
record
allowance
transfers
for
compliance
purposes
and
to
track
the
disposition
of
all
allowances
in
the
system.
Applications
for
allowances
from
the
Energy
Conservation
and
Renewable
Energy
Reserve
provide
information
on
the
emissions
avoided
through
the
use
of
energy
conservation
measures
and
renewable
energy,
and
are
used
to
allocate
allowances
from
the
reserve.

Acid
rain
permit
applications
are
used
to
issue
operating
permits
to
affected
sources
under
the
Acid
Rain
Program.
Because
the
permit
applications
and
permits
are
public
documents,
they
provide
an
opportunity
for
the
affected
public
to
examine
activities
undertaken
by
affected
sources.
The
designated
representative
certification,
which
designates
a
responsible
official
through
whom
the
owners
and
operators
of
each
affected
source
and
each
affected
unit
can
trade
allowances
and
obtain
and
maintain
permits,
serves
to
remove
EPA
from
involvement
in
disputes
between
owners
and
operators
of
affected
units.

Monitoring
plan
submissions
are
used
by
EPA
to
verify
that
the
emissions
monitoring
system
at
a
unit
meets
the
requirements
set
forth
in
Title
IV
of
the
Act
and
in
the
implementing
regulations.
Results
of
continuous
emission
monitoring
system
performance
tests
allow
EPA
to
certify
that
monitors
perform
well
enough
to
produce
accurate
emissions
data.
Emissions
data
is
used
to
monitor
compliance
with
emissions
requirements
under
Title
IV
and
to
provide
a
basis
for
analyzing
progress
in
meeting
air
quality
objectives.
Allowance
tracking
information,
emissions
data,
and
the
contents
of
permit
applications
all
provide
information
for
the
allowance
market
and
the
general
public.

Opt­
in
Program
This
ICR
also
addresses
the
paperwork
burden
for
small
utility
units
and
industrial
boilers
that
opt­
in.
The
Agency
has
identified
five
burden
areas
associated
with
a
source's
opting
in
to
the
allowance
allocation
and
trading
program.
These
areas
are
(
1)
completing
the
permit
application,
(
2)
recording
and
reporting
emissions
data,
(
3)
compliance
reporting,
and
(
4)
withdrawing
from
the
program.
Estimates
for
the
opt­
in
program
detail
the
burden
for
both
operating
and
shut­
down
opt­
ins.

The
Opt­
in
program
requires
respondents
to
submit
an
acid
rain
permit
application.
For
5
all
respondents,
the
application
must
provide
(
1)
general
information
about
the
source,
(
2)
specific
data
about
the
source's
fuel
consumption
and
operating
data
for
1985,
1986,
1987,
and
(
3)
data
on
the
source's
actual
and
allowable
emission
rates
for
1985,
as
well
as
the
current
allowable
emission
rate.
The
permit
application
and
proposed
thermal
energy
compliance
plan
for
sources
that
opt
in
and
shut
down
must
include
information
describing
the
source's
plans
for
the
replacement
of
thermal
energy.

To
meet
emissions
monitoring,
record­
keeping
and
reporting
requirements,
sources
that
opt­
in
and
continue
operating
will
be
required
to
(
1)
submit
a
monitoring
plan
and
certification
of
monitors,
(
2)
record
hourly
pollutant
and
flow
monitor
data,
and
(
3)
submit
quarterly
reports
of
their
emissions
data
to
EPA.
Sources
that
opt
in
and
shut
down
will
not
have
to
perform
tasks
associated
with
emissions
monitoring,
reporting,
and
recording.

Meanwhile,
to
meet
requirements
for
reporting
compliance,
respondents
must
submit
an
annual
compliance
certification
report
in
which
they
(
1)
report
their
utilization
information,
(
2)
report
any
replacement
of
thermal
energy,
and
(
3)
report
on
allowances
transferred
as
a
result
of
the
replacement
of
thermal
energy.
Finally,
all
sources
that
have
opted
in
and
later
decide
to
withdraw
will
be
required
to
complete
withdrawl
notification.

Annual
Compliance
Certification
Compliance
with
the
SO
2
emission
limitations
is
determined
annually.
To
meet
the
annual
compliance
requirements
for
Phase
I,
the
designated
representative
for
each
Phase
I
affected
unit
must
submit
(
1)
an
Annual
Compliance
Certification
Report
stating
whether
the
unit
was
in
compliance
with
all
Acid
Rain
Program
requirements
for
the
calendar
year,
and
(
2)
a
Utilization
Accounting
form
that
calculates
the
annual
utilization
and
other
operating
data.

In
addition,
if
a
source
is
underutilized
or
claims
sulfur­
free
generation,
the
designated
representative
must
submit
a
Dispatch
System
Data
Report
that
states
dispatch
system
utilization,
sales,
and
emissions
rate
information.

The
designated
representative
also
has
the
option
of
submitting
an
allowance
deduction
form
to
identify
specific
serial
numbered
allowances
to
be
deducted
for
annual
compliance.

In
Phase
II,
the
designated
representative
for
each
affected
unit
must
submit
an
Annual
Compliance
Certification
Report
stating
whether
the
unit
was
in
compliance
with
all
Acid
Rain
Program
requirements
for
the
calendar
year,
and
has
the
option
of
submitting
an
allowance
deduction
form
to
identify
specific
serial
numbered
allowances
to
be
deducted
for
annual
compliance.

NOx
Permitting
An
owner
or
operator
of
a
Phase
II,
Group
1
unit
may
meet
the
requirements
of
the
NO
x
regulations
through
one
of
three
compliance
options:
6

meeting
the
standard
limits

obtaining
approval
for
an
emissions
averaging
plan

obtaining
an
alternative
emissions
limitation
(
AEL)

Two
or
more
units
may
average
their
NO
x
emissions,
as
provided
for
by
Title
IV.
In
an
approved
NO
x
emissions
averaging
group,
the
NO
x
emission
rates
of
some
of
the
individual
units
may
exceed
their
respective
emission
limitations,
as
long
as
the
Btu­
weighted
average
NO
x
emission
rate
for
the
entire
group
is
less
than
or
equal
to
the
weighted
average
of
the
emission
limitations
for
the
individual
units.
The
ability
to
average
emissions
is
expected
to
allow
utilities
to
meet
the
NO
x
requirements
at
lower
cost.

Title
IV
also
provides
that
an
owner
or
operator
of
an
affected
unit
may
petition
EPA
for
a
higher,
alternative
emission
limitation
(
AEL)
if
the
unit
cannot
meet
the
emission
limitations
even
after
a
retrofit
with
low
NO
x
burner
technology
.
The
opportunity
to
obtain
AELs
will
allow
for
adjustment
of
emission
limitations
for
specific
units
where
the
technologies
on
which
the
limitations
were
based
do
not
provide
the
expected
level
of
emission
reductions
in
practice.

Meeting
the
standard
limit
is
the
least
burdensome
administratively
for
sources.
All
owners
and
operators
of
affected
units
are
eligible
to
comply
with
the
NO
x
regulations
using
this
option.
The
submission
of
an
application
for
emissions
averaging,
or
an
AEL,
or
early
election
is
optional
and
voluntary.

For
units
that
comply
by
meeting
the
standard
limits
or
that
choose
to
early
elect,
applicants
were
required
only
to
identify
the
unit.

Applicants
seeking
approval
for
emissions
averaging
are
required
to
identify
the
units
in
the
group,
assign
alternative
contemporaneous
emissions
limitations
to
each
unit,
and
demonstrate
that
the
Btu­
weighted
average
of
these
alternative
limits
is
less
than
or
equal
to
the
Btu­
weighted
average
of
the
limits
that
would
apply
in
the
absence
of
averaging.

All
applicants
for
AELs
are
required
to
demonstrate
that
they
are
eligible
for
an
AEL,
by
providing
(
1)
evidence
that
the
appropriate
emissions
control
equipment
has
been
installed,
and
(
2)
monitoring
data
showing
that
the
unit
cannot
meet
the
applicable
emission
rate.

The
total
respondent
reporting
burden
for
this
collection
of
information
is
estimated
to
be
1,330,327
hours
in
1999,
1,220,183
hours
in
2000,
and
1,220,156
hours
in
2001.
The
total
burden
to
EPA
is
estimated
to
be
17,477
hours
in
1999,
17,174
hours
in
2000,
and
19,986
hours
in
2001.

2.
NEED
FOR
AND
USE
OF
THE
COLLECTION
This
section
describes
EPA's
need
for
the
information
collections
described
above
and
the
legal
authority
for
conducting
collections.
The
users
of
collected
information
are
also
described.
7
2.1
Need/
Authority
for
the
Collection
Section
403(
b)
of
Title
IV
of
the
Clean
Air
Act
Amendments
of
1990
provides
for
the
transfer
of
allowances
among
designated
representatives
of
owners
and
operators
of
affected
sources
and
any
person
who
holds
allowances.
Transfers
of
allowances
will
not
be
deemed
effective
until
written
certification
of
the
transfer,
signed
by
a
responsible
official
of
each
party
to
the
transfer,
is
received
and
recorded
by
EPA.
Section
403(
d)
of
Title
IV
requires
that
EPA
develop
a
system
for
issuing,
recording,
and
tracking
allowances
(
intended
to
help
ensure
an
orderly
and
competitive
allowance
system).

Conservation
and
Renewable
Energy
Reserve
Section
404(
f)
of
Title
IV
establishes
provisions
for
qualifying
electric
utilities
to
receive
allowances
from
the
Conservation
and
Renewable
Energy
Reserve
for
SO2
emissions
avoided
through
the
use
of
qualifying
energy
conservation
measures
or
renewable
energy.
The
allowances
will
be
allocated
on
a
first
come,
first
served
basis
during
the
period
from
January
1,
1992
to
December
31,
2000.

Permits
Section
408
of
Title
IV
and
Title
V
of
the
Clean
Air
Act
Amendments
of
1990
require
that
the
designated
representative
of
the
owners
and
operators
of
each
affected
source
under
the
Acid
Rain
Program
obtain
a
permit.
Section
408
also
specifies
that
EPA
must
issue
acid
rain
permits
for
Phase
I
of
the
Acid
Rain
Program
and
that
permits
must
have
a
term
of
five
years.
In
Phase
II,
the
permitting
authority,
usually
a
State
or
local
agency,
will
issue
the
permits
that
will
also
have
a
term
of
five
years.

Emissions
Monitoring
Section
412(
a)
of
Title
IV
requires
the
use
of
CEM
systems
(
or
alternative
monitoring
systems
demonstrated
to
be
equivalent)
at
each
affected
unit's
source
of
emissions.
Section
504(
a)
of
Title
V
requires
that
the
results
of
any
required
monitoring
be
submitted
to
the
permitting
authority
no
less
often
than
every
six
months.
The
information
collection
is
consistent
with
satisfying
these
minimum
statutory
requirements.
Note
that
reports
are
submitted
quarterly
rather
than
semiannually.
The
Acid
Rain
Advisory
Committee
recommended
that
EPA
collect
emissions
data
on
a
quarterly
basis
and
this
schedule
has
proven
to
allow
for
effective
implementation
of
the
program.

Auctions
Although
participation
in
the
annual
auction
is
voluntary,
the
information
to
be
collected
is
necessary
to
operate
and
administer
the
program
and
is
required
specifically
under
Title
IV,
Section
416(
d)(
2).

Small
Diesel
Refineries
Section
410(
h)
of
the
Act
creates
a
program
for
allocation
of
allowances
to
small
diesel
refineries
for
desulfurization
of
diesel
fuel.
Each
year
of
the
program
(
1993­
1999),
eligible
refiners
will
submit
information
regarding
the
amount
of
diesel
fuel
desulfurized.
This
program
is
8
voluntary,
the
benefit
of
allowance
allocations
is
tied
to
the
submittal
of
necessary
information.

Opt­
in
Section
410(
a)
of
Title
IV
of
the
Clean
Air
Act
Amendments
of
1990
allows
the
owner
or
operator
of
any
SO2
source
that
is
not
an
affected
unit
under
section
403(
e),
404,
or
405
to
elect
to
designate
that
source
as
an
affected
source
and
receive
allowances
under
Title
IV.
Section
410(
a)
requires
sources
opting
in
to
submit
a
permit
application
and
a
compliance
plan
to
the
Administrator.

Section
410(
b)
requires
the
Administrator
to
establish
a
baseline
utilization
rate
for
SO2
emissions
for
opt­
in
sources
based
on
fuel
consumption
and
operating
data
for
calendar
years
1985,
1986,
1987.
Section
410(
c)
requires
the
Administrator
to
establish
a
limit
for
SO2
emissions
based
on
the
baseline
utilization
rate
and
the
lesser
of
the
source's
actual
or
allowable
1985
emissions.

Section
410(
e)
requires
that
the
Administrator
issue
allowances
to
sources
that
become
affected
sources
under
Section
410.
The
number
of
allowances
is
to
be
based
on
calculations
made
under
Section
410(
c).

NOx
Permitting
Section
408
of
Title
IV
of
the
Clean
Air
Act
Amendments
of
1990
specifies
that
utility
owners
and
operators
of
units
affected
under
Title
IV
must
submit
permit
applications
and
compliance
plans
(
including
NO
x
compliance
plans),
and
that
EPA
must
issue
permits.

°
Section
408
provides
general
authority
for
the
information
collections
under
this
ICR
related
to
compliance
options.
In
addition,


Section
407(
e)
of
Title
IV
allows
the
owner
or
operator
of
two
or
more
affected
units
to
petition
the
permitting
authority
for
a
NO
x
averaging
plan.


Section
407(
d)
provides
for
AELs
for
utility
units
that
cannot
meet
the
applicable
limitation
using
low
NO
x
burner
technology
or
the
technology
on
which
the
limitation
was
based.
Section
407(
d)
specifies
that
an
owner
or
operator
requesting
an
AEL
must
show
the
permitting
authority
that
(
1)
appropriate
control
equipment
has
been
properly
installed,
and
(
2)
the
equipment
has
been
properly
operated
for
a
period
of
fifteen
months
(
or
another
period
of
time
as
established
by
regulation)
and
operating
and
monitoring
data
for
such
period
demonstrate
that
the
unit
cannot
meet
the
applicable
emission
rate.
The
owner
or
operator
must
also
specify
an
emission
rate
that
the
unit
can
meet
on
an
annual
average
basis.

2.2
Practical
Utility/
Users
of
the
Data
Allowance
Transfers
9
Information
collected
on
allowance
transfers
will
be
used
by
EPA
or
its
designated
agent
to
track
allowances
for
the
purpose
of
determining
compliance
with
the
Acid
Rain
Program.
Information
on
allowance
transfers
will
also
be
used
by
participants
in
the
allowance
market
and
the
public
to
evaluate
the
activities
of
utilities,
and
by
EPA
for
program
evaluation.

Auctions
EPA
or
its
designated
agent
will
use
the
information
collected
for
the
allowance
auction
to
conduct
and
facilitate
administration
of
auctions.
The
basic
information
requested
will
require
little
evaluation.
Bids
submitted
for
auctions
will
be
ranked
to
select
winning
bidders
and
to
conduct
transfers
of
emission
allowances.
The
auction
information
results
will
also
be
used
by
participants
in
the
allowance
market
and
by
state
public
utility
commissions
in
evaluating
their
states'
utilities
activities.

Conservation
and
Renewable
Energy
Reserve
Information
collected
on
the
use
of
energy
conservation
measures
and
renewable
energy
will
be
used
by
EPA
to
issue
allowances
from
the
Conservation
and
Renewable
Energy
Reserve.

Permits
Acid
rain
permit
applications,
including
proposed
compliance
plans,
will
be
used
by
EPA
and
permitting
authorities
to
issue
operating
permits
and
to
allocate
allowances.
A
permit
application
will
be
legally
binding
on
the
owners,
operators,
and
designated
representative
of
a
source
until
the
actual
permit
is
issued.
This
aspect
of
the
permit
application
reduces
significantly
the
uncertainty
imposed
on
a
source
due
to
possible
delays
at
EPA.
EPA
will
use
the
acid
rain
permit
as
a
binding
document
for
determining
each
unit's
compliance
with
the
Acid
Rain
Program.
Affected
sources
may
rely
on
the
permit
for
information
on
the
requirements
with
which
they
must
comply.
Because
permit
applications
and
permits
will
be
public
documents,
they
may
be
used
by
the
public
to
examine
activities
undertaken
by
affected
sources.

Emissions
Monitoring
Data
from
emissions
monitoring
is
indispensable
to
successful
implementation
of
the
Acid
Rain
Program
for
two
reasons:


Title
IV
of
the
Act
clearly
states
that
its
primary
purpose
is
to
reduce
the
adverse
effects
of
acid
deposition
by
reducing
annual
emissions
of
sulfur
dioxide
and
nitrogen
oxides.
For
sulfur
dioxide
emissions,
the
statutory
objective
is
achieved
through
an
emissions
trading
program.
For
nitrogen
oxide
emissions,
the
statutory
objective
is
achieved
through
annual
emission
limitations
on
certain
units.


EPA
can
only
enforce
the
sulfur
dioxide
trading
program
and
the
nitrogen
oxide
emission
limitation
program
by
having
accurate
emissions
data
for
each
affected
unit.

Electric
utilities,
energy
consultants,
and
power
marketing
companies
can
use
the
Acid
Rain
program
emissions
data
to
project
future
SO
2
allowance
costs
and
availability.
Academic
10
institutions
can
perform
data
modeling
to
evaluate
environmental
benefits
and
estimate
health
effects
of
SO
2
reductions.
EPA
and
other
agencies
use
it
to
try
to
correlate
the
reduction
of
SO
2
emissions
with
a
decrease
in
acid
precipitation,
and
also
to
measure
the
impacts
of
other
existing
and
proposed
emissions
trading
programs.

Together,
the
allowance
trading
system,
operating
permits,
and
emissions
data
provide
the
accountability
to
allow
the
Acid
Rain
Program
to
function
without
more
stringent
command
and
control
approaches.

Opt­
in
Information
collected
on
opt­
in
respondents
is
used
by
EPA
to
record
which
sources
are
to
be
designated
affected
sources,
and
hence
are
to
be
bound
by
the
regulations
of
the
CAAA
that
are
relevant
to
affected
sources.

Opt­
in
permit
applications
are
used
by
EPA
to
issue
operating
permits.
A
permit
application
is
legally
binding
on
the
owners,
operators,
and
designated
representative
of
a
source
until
the
actual
permit
is
issued.
This
aspect
of
the
permit
application
reduces
significantly
any
uncertainty
during
the
period
of
time
required
to
issue
a
permit.
EPA
uses
the
opt­
in
permit
as
a
binding
document
for
determining
each
source's
compliance
with
Acid
Rain
Program.
Fuel
usage
and
emissions
rate
data
in
the
opt­
in
application
is
used
to
allocate
allowances
to
the
opt­
in
source.

The
information
on
annual
utilization
and
the
replacement
of
thermal
energy,
if
covered
by
a
Thermal
Energy
Plan,
contained
in
the
annual
compliance
report
is
used
by
EPA
to
determine
compliance
with
the
Act.

For
respondents
who
choose
to
withdraw
from
the
program,
the
withdrawl
notification
is
essential
to
notify
EPA
to
discontinue
the
allocation
of
allowances
to
the
source
and
enforcement
of
the
acid
rain
provisions.

Annual
Compliance
Certification
This
information
will
be
used
by
EPA
to
determine
annual
compliance.

NOx
Permitting
Information
collected
on
NO
x
compliance
plans
will
be
used
by
EPA
to
evaluate
these
compliance
plans.
Information
collected
on
applications
for
emissions
averaging
groups
or
AELs
will
be
used
by
EPA
to
determine
whether
to
approve
these
applications.
This
information
may
also
be
used
by
the
regulated
community
and
the
public
to
evaluate
the
activities
of
utilities,
and
by
EPA
for
program
evaluation.

3.
NONDUPLICATION,
CONSULTATIONS,
AND
OTHER
COLLECTION
CRITERIA
11
This
section
describes
(
1)
efforts
by
EPA
to
learn
whether
the
information
requested
is
available
from
other
sources,
(
2)
consultations
with
respondents
and
data
users
to
plan
collections,
monitor
their
usefulness,
and
minimize
the
collection
burden,
(
3)
effects
of
less
frequent
collections,
and
(
4)
justification
for
deviations
from
OMB's
general
guidelines.

3.1
Nonduplication
Almost
all
information
requested
from
respondents
under
this
ICR
is
required
by
statute
and,
in
most
cases,
is
not
available
from
other
sources.
Review
of
the
proposed
forms
resulted
in
the
elimination
of
many
redundant
requirements.

Where
EPA
needs
information
that
has
already
been
submitted,
EPA
is
simply
requiring
a
photocopy
of
the
prior
submittal.

3.2
Consultations
The
data
requirements
for
the
Acid
Rain
Program
were
developed
with
the
benefit
of
extensive
consultation
with
the
Acid
Rain
Advisory
Committee
(
ARAC)
during
five
meetings
in
1991
lasting
two
to
three
days
each.
The
Committee
was
composed
of
representatives
of
those
entities
most
affected
by
or
interested
in
the
information
requirements
of
the
Acid
Rain
Program.
Representation
on
the
Committee
was
provided
for
industry,
states,
and
environmental
groups.
Other
parties
consulted
include
the
Utility
Air
Regulatory
Group
(
UARG),
the
State
and
Territorial
Air
Pollution
Program
Administrators
(
STAPPA),
and
the
Association
of
Local
Air
Pollution
Control
Officers
(
ALAPCO).

Recommendations
provided
by
ARAC
strongly
supported
the
use
of
standardized
reporting
forms
for
acid
rain
permit
applications:


Utilities
affirmed
that
standardized
forms
reduce
uncertainty
about
what
constitutes
a
complete
application
and
thus
reduce
the
need
to
supply
additional
information
in
a
second
submission;


States
asserted
that
the
use
of
standardized
forms
developed
by
EPA
would
reduce
the
time
and
effort
states
will
need
to
implement
an
acid
rain
permit
program;
and

Environmental
groups
argued
that
the
use
of
standardized
forms
provides
greater
assurance
that
permits
will
be
enforceable
in
a
consistent
manner
nationwide.

Many
ARAC
recommendations
were
incorporated
into
the
acid
rain
regulations
regarding
permits
and
the
related
standardized
forms.

Furthermore,
since
the
beginning
of
implementation
of
the
Acid
Rain
Program,
12
representatives
from
the
utility
industry,
monitoring
equipment
vendors,
software
programmers,
consultants
working
together
with
utilities,
and
other
interested
parties
have
offered
comments
on
the
existing
rule
requirements,
standard
forms
and
electronic
data
reporting
formats
used
to
implement
the
Part
75
program.
The
EPA
has
used
these
comments
to
revise
the
rules,
forms
and
reporting
formats,
especially
changes
in
the
formats
to
cover
a
wider
group
of
units.
In
particular,
the
revised
forms
and
electronic
data
reporting
format
have
been
revised
in
the
past
to
address
reporting
requirements
for
gas­
fired
units
and
oil­
fired
units
that
are
using
pre­
approved
monitoring
exceptions
to
the
use
of
CEMS.
Industry
groups
have
also
worked
together
with
EPA
to
revise
the
recordkeeping
and
reporting
requirements
in
revisions
to
Part
75
in
1995
and
1996.
Comments
and
suggestions
from
working
groups,
comprised
of
UARG,
Class
of
85
Regulatory
Response
Group,
and
the
PJM
Powerpool
also
were
incorporated
in
designing
the
annual
compliance
forms.

For
the
current
revisions
to
Part
75,
EPA
has
solicited
and
obtained
input
from
a
number
of
affected
utilities
and
other
interested
parties.
The
Agency
convened
an
informal
workgroup
to
provide
ideas
on
the
revisions
during
the
development
stage,
released
a
pre­
proposal
draft
of
the
revisions
and
received
numerous
written
comments
on
that
draft.
The
Agency
also
gathered
cost
information
directly
from
vendors,
testing
companies,
affected
utilities
and
other
sources
(
see
Docket
A­
97­
35,
Item
IV­
A­
5).
In
addition,
the
Agency
received
formal
comments
on
the
revisions
following
the
publication
of
the
proposed
version
of
revisions
in
the
Federal
Register
on
May
21,
1998
(
63
FR
28032).
Most
of
the
rule
revisions
(
and
accompanying
revisions
to
the
reporting
formats)
are
a
result
of
input
from
these
interested
parties.

3.3
Effects
of
Less
Frequent
Collection
Collection
of
allowance
transfer
information
for
each
transfer
of
allowances
is
necessary
to
effectively
implement
a
system
for
issuing,
recording,
and
tracking
allowances,
which
is
required
by
statute.

Conservation
and
Renewable
Energy
Reserve
Collection
of
applications
for
allowances
from
the
Conservation
and
Renewable
Energy
Reserve
for
emissions
avoided
through
the
use
of
conservation
measures
or
renewable
energy
is
required
by
statute
and
is
vital
to
(
1)
determine
qualification
for
these
allowances,
and
(
2)
establish
the
sequence
for
allocating
allowances
on
a
first­
come,
first­
served
basis.

Permits
The
requirement
for
the
designated
representatives
of
owners
and
operators
of
affected
sources
to
submit
permit
applications,
including
proposed
compliance
plans,
every
five
years
is
a
statutory
requirement.
The
periodic
compliance
reports
or
notifications
required
for
specific
compliance
options
are
essential
to
(
1)
enhance
enforcement
of
emissions
limitations
requirements,
and
(
2)
ensure
that
utilities
receiving
bonus
allowances
and
extensions
comply
with
the
conditions
upon
which
they
were
granted
the
allowances.
13
Emissions
Monitoring
Submission
of
monitoring
plans
once
and
submission
of
the
results
of
any
required
monitoring
to
EPA
no
less
often
than
every
six
months
are
required
by
statute.
More
frequent
collections
of
emissions
data
(
i.
e.,
quarterly),
however,
allows
the
opportunity
to
check
data
for
errors
and
provide
rapid
feedback
on
needed
adjustments
to
data
collection
systems,
and
thereby
promotes
accurate
and
reliable
emissions
data.
For
this
same
reason,
existing
federal
and
state
emission
monitoring
programs
often
require
quarterly
reporting,
or
in
some
cases,
monthly.
Less
frequent
collection,
such
as
semi­
annually
or
annually,
would
increase
the
amount
of
preparation
and
review
time
at
the
end
of
the
year
both
for
regulated
sources
and
for
EPA.
This
would
slow
down
the
process
of
true
up
and
end
of
year
verification
of
compliance.

Records
of
monitoring
information
are
to
be
kept
at
the
source
for
3
years
after
the
date
of
creation
of
the
record.
In
certain
circumstances,
fuel
flowmeter
calibration
and
Appendix
E
testing
records
may
have
to
be
kept
for
up
to
five
years
if
the
owner
or
operator
takes
advantage
of
rule
provisions
that
allow
up
to
five
years
between
tests.
These
5
year
recordkeeping
requirements
only
apply
if
the
owner
or
operator
voluntarily
elects
either
of
these
options
as
a
cost­
effective
approach
for
the
owner
or
operator's
specific
circumstances.

Allowance
Allocation
&
Small
Diesel
Refiners
Collections
under
Section
410(
h)
are
necessary
for
the
integrity
of
the
allowance
allocation
program.
Information
collection
for
the
allowance
allocations
for
small
diesel
refineries
must
be
yearly,
through
April
2000,
to
correspond
to
the
congressionally­
mandated
annual
allowance
allocations.

Opt­
in
Collection
of
permit
applications
for
the
opt­
in
program
occurs
only
once
every
five
years,
thus
minimizing
the
respondent
burden.
This
collection
is
necessary
for
the
operation
of
the
program;
without
it,
EPA
would
not
know
which
sources
wanted
to
opt
in,
nor
their
baseline
utilization,
nor
the
lower
of
their
1985
actual
or
allowable
emission
rate.
Collection
of
withdrawal
notifications
also
occurs
once;
this
is
also
a
necessary
collection.

Annual
Compliance
Certification
The
Statute
indicates
that
compliance
is
to
be
determined
annually
by
comparing
the
allowances
held
by
the
unit
to
the
unit's
total
annual
emissions.

NOx
Permitting
The
Agency
is
required
by
statute
to
include
NO
x
compliance
plans
as
part
of
the
Acid
Rain
permits.
NO
x
compliance
plans
are
not
required
during
the
period
of
this
ICR,
but
some
averaging
plan
revisions
are
expected.
Permits
incorporating
approval
of
compliance
plans
will
be
valid
for
a
period
of
five
years.

3.4
General
Guidelines
14
Section
403(
d)
of
Title
IV
requires
that
EPA
establish
a
system
for
issuing,
recording,
and
tracking
allowances.
To
track
allowances
accurately
and
to
help
ensure
the
orderly
and
competitive
functioning
of
the
allowance
system,
it
is
essential
that
participants
be
able
to
report
information
on
allowance
transfers
as
they
occur.

The
general
requirement
that
permit
applicants
submit
information
on
standard
forms
is
established
by
Section
502(
b)
of
Title
V.
The
five­
year
life
of
an
acid
rain
permit
is
established
by
Section
408(
a)
of
Title
IV.
This
information
collection
does
not
violate
the
guidelines
set
forth
by
OMB.
In
some
cases,
records
of
Part
75,
Appendix
E
test
results
or
fuel
flowmeter
calibration
test
results
may
need
to
be
retained
for
up
to
five
years,
but
only
if
the
owner
or
operator
chooses
to
take
advantage
of
the
ability
to
extend
the
period
between
tests
up
to
five
years.
In
all
other
circumstances,
Part
75
monitoring
records
must
be
kept
for
only
three
years.

3.5
Confidentiality
and
Sensitive
Questions
Information
collected
through
this
activity
is
not
confidential
or
of
a
sensitive
nature.

4.
THE
RESPONDENTS
AND
THE
INFORMATION
REQUESTED
This
section
lists
the
major
categories
of
businesses
that
participate
in
the
Acid
Rain
Program,
the
data
items
requested
from
program
participants,
and
the
activities
in
which
the
participants
must
engage
to
assemble
or
submit
the
required
data
items.

4.1
Respondents/
SIC
Codes
Title
IV
applies
to
"
utility
units,"
which
are
defined
to
include
units
that
serve
a
generator
producing
electricity
for
sale
or
that
did
so
in
1985.
Entities
owning
"
utility
units"
that
are
likely
to
participate
in
allowance
transactions
are
electric
service
providers
(
SIC
code
4911)
and
selected
firms
in
the
non­
utility
generation
industry,
such
as
coal
mining
service
companies
(
SIC
code
1241).
Participants
in
transactions
and
the
annual
auctions
include
security
and
commodity
brokers
and
dealers
(
SIC
code
62),
management
and
business
consulting
service
organizations
(
SIC
codes
8742
and
8748,
respectively),
non­
profit
organizations
and
natural
gas
companies
(
SIC
code
1311).
Affected
units
under
Title
IV,
particularly
units
affected
under
Phase
II,
are
the
likely
applicants
for
allowances
from
the
Conservation
and
Renewable
Energy
Reserve.
Section
405(
i)(
2)
applies
to
a
limited
group
of
"
utility
units."
Entities
owning
"
utility
units"
that
will
likely
submit
information
under
this
section
are
electric
service
providers,
SIC
code
4911.

Small
Diesel
Refiners
Section
410(
h)
is
limited
to
small
diesel
refiners
who
meet
the
eligibility
requirements
set
out
clearly
in
the
Act.
(
SIC
code
2911)

Emissions
Monitoring
15
Utility
units
affected
under
Phase
II
are
required
to
submit
emissions
monitoring
data
under
this
ICR;
the
initial
list
of
units
affected
under
Phase
II
was
promulgated
on
March
23,
1993.
Some
additional
new
units
will
be
affected
under
the
Acid
Rain
Program
and
must
meet
emissions
monitoring
requirements.

Opt­
in
Potential
participants
in
the
opt­
in
program
are
facilities
that
emit
SO2
but
are
not
designated
affected
units
under
Title
IV.
Such
facilities
include
utility
units
that
serve
an
electric
generator
of
less
than
25
MW
that
produces
electricity
for
sale
or
that
did
so
in
1985.
Entities
owning
utility
units
under
25
MW
that
may
participate
in
the
opt­
in
program
are
electric
service
providers
(
SIC
code
4911).
Other
potential
participants
are
industrial
boilers
that
are
represented
in
a
wide
range
of
SIC
categories.

4.2
Information
Requested
This
section
lists
the
data
items
requested
from
affected
sources
for
the
collections
described
in
this
ICR.
This
section
also
defines
the
activities
in
which
respondents
must
engage
to
assemble,
submit,
or
store
these
data
items.

4.2.1
Data
items,
Including
Recordkeeping
Requirements
Allowance
Transfers
All
participants
to
allowance
transfers
will
be
required
to
complete
and
submit
an
allowance
transfer
form
or
provide
the
following
information
for
each
allowance
transfer:


Allowance
tracking
system
account
number;


Name,
phone
number,
and
facsimile
number
of
the
authorized
account
representative,
along
with
the
representative's
signature
and
date
of
submission;
and

Serial
numbers
of
allowances
to
be
transferred.

Certificate
of
Representation
Existing
Phase
I
and
Phase
II
affected
sources
have
been
assigned
an
allowance
tracking
system
number
and
have
appointed
a
designated
representative
by
submitting
a
certificate
of
representation.
New
units
that
are
affected
must
submit
the
certificate
of
representation
before
commencing
commercial
operation,
and
will
then
be
assigned
an
allowance
tracking
system
number.
The
data
items
requested
for
the
certificate
of
representation
are
as
follows:


Source
identification;


Name,
address,
telephone
and
facsimile
number
of
the
designated
representative;


Name,
address,
telephone
and
facsimile
number
of
the
alternate
designated
representative;


List
of
"
owners
and
operators"
of
the
source
and
each
unit
at
the
source;
16

Certification
statement;


Signature
of
designated
representative;


Signature
of
alternate
designated
representative;
and

Date
signed.

Notification
for
Distribution
of
Proceeds
from
EPA
Auctions
EPA
will
send
one
check
for
each
plant
represented
for
the
proceeds
from
the
auctions
and
sales
of
allowances.
The
following
information
is
required
for
this
notification
for
distribution
of
proceeds:


Authorized
Account
Representative
(
AAR)
Identification;


Name
of
the
company
the
check
should
be
endorsed
to;
°
The
company's
tax
payer
identification
number;
°
Plant
name
and
plant
code;
and

Signature
of
AAR.

General
Account
Holders
(
Allowance
Market
Participants)
Entities
that
are
not
affected
sources
(
such
as
individuals
holding
allowances)
are
required
to
submit
a
completed
account
information
application
or
provide
the
following
information
to
obtain
an
allowance
tracking
system
account
number,
prior
to
or
simultaneous
with
the
first
transfer:


Organization
or
company
name
(
if
applicable);


Name,
mailing
address,
phone
number,
and
facsimile
number
of
the
authorized
account
representative;
°
Name
of
the
alternate
authorized
account
representative
(
optional);


A
list
of
all
persons
subject
to
a
binding
agreement
for
the
authorized
account
representative
to
represent
their
ownership
interest
with
respect
to
the
allowances
held
in
the
account;
and

Certification
statement
and
the
signatures
and
date
for
the
authorized
account
representative,
and
alternate
authorized
account
representative,
if
any.

Conservation
and
Renewable
Energy
Reserve
In
order
to
receive
allowances
from
the
Conservation
and
Renewable
Energy
Reserve
for
emissions
avoided,
each
electric
utility
must
submit
an
application
to
EPA.
The
application
requires
the
following
items:


Name
and
phone
number
of
the
person(
s)
who
completed
the
application;
and
name
and
phone
number
of
contact
person.


Demonstration
of
qualification
to
receive
allowances
for
emissions
avoided;


A
list
of
the
qualified
energy
conservation
measures
implemented
and
the
qualified
renewable
energy
sources
used
for
purposes
of
avoiding
emissions
during
the
previous
calendar
year;


Verification
of
(
1)
installation
of
energy
conservation
measures
and
the
energy
17
savings
attained,
and
(
2)
plant
operation
using
renewable
energy
and
the
energy
generation
attributable
to
renewable
energy
input;


For
utilities
using
the
EPA
Conservation
Verification
Protocol,
the
information
and
methodologies
used
in
determining
energy
savings,
including
a
description
of
the
conservation
measures,
the
dates
of
claimed
savings,
the
number
of
installations,
the
calculations
used
to
determine
energy
savings,
aggregate
statistical
information
needed
to
calculate
confidence
levels,
and
a
description
of
any
comparison
groups;


Calculations
of
the
number
of
tons
of
emissions
avoided
by
implementing
conservation
measures
or
using
renewable
energy;
and

Identification
of
allowance
tracking
account(
s)
to
which
the
Reserve
allowances
are
to
be
allocated.

Permits
To
initially
obtain
a
Phase
I
acid
rain
permit,
applicants
for
permits
were
required
in
the
original
ICR
to
submit
a
certificate
of
representation
and
an
acid
rain
permit
application
for
each
affected
source.

If
the
designated
representative
of
a
unit
expects
to
comply
with
the
applicable
emissions
limitations
by
holding
the
requisite
number
of
allowances
and
expects
to
meet
the
applicable
NO
x
emissions
limitations,
no
further
application
information
will
be
required
for
Phase
I.
If
the
designated
representative
of
a
unit
elects
to
use
one
or
more
compliance
options,
specific
information
to
support
the
use
of
the
proposed
options
may
be
required.
These
options
and
the
information
requirements
for
each
are
as
follows:

Substitution
Plan
§
72.41

Identification
of
Table
1
Units

Identification
of
Substitution
Units

(
a)
Baseline
from
NADB
version
2.1

(
b)
Lesser
of
actual
or
allowable
1985
emissions
rate
per
NADB
version
2.1

(
c)
Product
of
(
a)
*
(
b)
/
2000.


Sum
of
(
c)
for
all
substitution
units
(
equals
all
allowances
available
annually
under
Substitution
plan)
(
optional)


Statement
that
allowances
will
be
allocated
annually
only
to
each
substitution
unit
or
List
showing
distribution
of
allowances
among
Appendix
A
and
substitution
units

First
and
last
calendar
years
for
plan

Special
provisions

Standard
certification

Name
and
signature
of
each
designated
representative
Reduced
Utilization
Plan
§
72.43
18

Unit
Identification

Methods
to
be
employed
to
account
for
planned
reduction
in
utilization

Designation/
identification
of
compensating
units
and
sulfur­
free
generators
(
if
any)


For
compensating
units,
allowance
calculation

For
units
not
in
the
utility
system,
documentation
of
system
directives
or
contractual
agreements
to
provide
power

First
and
last
calendar
years
of
compliance
plan
(
if
known)


Special
provisions

Standard
certification
New
Unit
Exemption
§
72.7
Operators
of
new
units
that
serve
generators
with
a
nameplate
capacity
of
25
MW
or
less
and
use
fuel
with
a
sulfur
content
by
weight
of
less
than
0.5
percent
may
obtain
an
exemption
from
monitoring,
permitting,
and
allowance
requirements
if
they
submit
a
certification
with
the
following
information:


Unit
Identification
°
Nameplate
capacity
of
the
generators
served
by
the
unit
°
The
fuels
currently
burned
and
their
sulfur
content
by
weight

Certification
that
the
owners
and
operators
will
comply
with
all
necessary
requirements

Standard
certification
at
§
72.21(
d)(
2)

Retired
Unit
Exemption
Operators
of
affected
units
that
are
retired
prior
to
the
issuance
(
including
renewal)
of
a
Phase
II
Acid
Rain
Permit
for
that
unit
may
obtain
an
exemption
from
monitoring
if
they
submit
a
certification
with
the
following
information:

°
Unit
identification
°
Certification
that
the
unit
is
permanently
retired
and
will
comply
with
all
necessary
requirements
°
Standard
certification
at
§
72.21(
d)(
2)

Industrial
Unit
Exemption
°
Unit
identification
°
Statement
that
the
unit
is
not
a
cogeneration
unit
°
List
of
the
current
owners
and
operators
of
the
unit
and
a
statement
that
the
owners
and
operators
principle
business
is
not
the
sale
of
electricity
°
Summary
of
the
terms
of
the
interconnection
agreement
°
A
copy
of
the
interconnection
agreement
°
Nameplate
capacity
of
each
generator
served
by
the
unit
°
Starting
in
1985,
actual
annual
electrical
output
of
each
generator,
total
electricity
produced
for
sale,
and
total
electricity
produced
and
sold
under
the
interconnection
19
agreement
°
Certification
statements
All
data
items
requested
from
permit
applicants
must
be
submitted
on
standard
forms.
Most
of
the
information
requested
in
the
forms
is
specifically
required
by
law.

Emissions
Monitoring
Emissions
monitoring
requirements
specify
that
affected
sources
must
(
1)
submit
a
monitoring
plan
for
each
affected
unit
at
a
source,
(
2)
submit
data
for
certification
of
each
monitor,
and
(
3)
record
hourly
operational,
pollutant
monitor,
and
flow
monitor
data
for
each
affected
unit
and
submit
quarterly
reports
of
their
emissions
data
to
EPA.
Appendices
A
and
B
to
this
ICR
contain
a
list
of
the
data
items
required
by
the
recordkeeping
and
reporting
provisions
of
Part
75.

Respondents
are
required
by
40
CFR
75.64
to
submit
the
quarterly
emissions
data
electronically,
by
direct
electronic
submission
to
EPA,
and
must
also
include
a
certification
statement
by
the
designated
representative
of
the
unit.
All
records
are
to
be
kept
for
three
years,
with
two
possible
exceptions
under
voluntary
options
that
are
discussed
in
section
3(
c)
of
this
ICR.

The
Part
75
revisions
add
or
revise
a
number
of
recordkeeping
and
reporting
terms.
Many
of
these
are
necessary
to
demonstrate
that
the
unit
qualifies
for
particular
exceptions
or
exemptions
that
are
allowed
under
the
revisions.
Items
have
been
added
to
support
reporting
of:
data
to
qualify
units
as
low
mass
emitters;
data
to
qualify
units
as
peaking
units
or
gas­
fired
units;
data
to
qualify
units
for
Appendix
I
procedures;
data
to
qualify
a
unit
for
off­
line
calibration;
and
data
to
qualify
units
for
quality
assurance
test
extensions
and
exemptions.
Requirements
have
also
been
added
to
support
data
reporting
for
units
with
multiple
range
analyzers,
additional
operating
load
data,
reporting
of
recertification
or
other
events,
flow/
load
checks,
moisture
data,
and
fuel
flow/
load
checks.
Provisions
have
also
been
included
for
optional
electronic
reporting
of
the
designated
representative
information,
certification,
and
signature.

Auctions
For
auctions,
participants
are
required
to
submit
a
bid
form
and
payment
method
at
least
six
days
prior
to
the
date
of
the
auction.
Sealed
bids
will
be
submitted
on
a
standard
bid
form
developed
by
EPA.
Each
bid
will
provide
the
following
basic
information:


Name

Account
number
(
or
new
account
information)


Allowance
quantity
and
price,
and

Type
of
auction
The
bid
will
also
specify
an
acceptable
method
of
payment
for
the
total
bid
price
regardless
of
the
type
of
auction
(
spot
or
advance).
Full
payment
for
allowances
­­
in
an
20
acceptable
form
­­
will
be
required
with
the
bid
at
the
time
of
submission.

Allowance
Allocations
for
Small
Diesel
Refiners
EPA
requires
that
the
refinery's
annual
request
for
allowances
include
the
following
information:

°
Certification
that
all
motor
fuel
produced
by
the
refinery
for
which
allowances
are
claimed
shall
have
met
the
requirements
of
subsection
211(
i)
of
the
Clean
Air
Act
and
EPA
implementing
regulations;

°
For
calendar
years
1994
through
1999,
inclusive,
photocopies
of
Form
810
for
each
month
in
the
respective
calendar
year.

All
operating
and
idle
petroleum
refineries
and
blending
plants
in
the
50
states,
the
District
of
Columbia,
Puerto
Rico,
the
Virgin
Islands,
Guam,
and
other
U.
S.
possessions
are
required
to
file
EIA
(
Energy
Information
Administration)
Form
810
on
a
monthly
basis
to
the
Department
of
Energy.
Although
the
forms
collect
data
on
all
of
the
operations
of
the
refinery,
there
are
specific
data
requirements
that
identify
the
throughput
of
crude
oil
and
existing
and
planned
data
requirements
dealing
with
distillate
(
diesel
fuel)
throughput
and
desulfurization.
These
are
the
pieces
of
data
that
Congress
intended
for
EPA
to
use
to
evaluate
refineries
for
program
eligibility
and
allowance
allocations.

In
addition,
each
refinery
which
is
eligible
for
these
allowances
and
chooses
to
receive
the
allowances
must
submit
a
one
time
Allowance
Account
Information
Form.
This
form
allows
the
refinery
to
be
entered
into
EPA's
Allowance
Tracking
System
which
will
be
accessible
by
the
refinery
for
trading
allowances.
The
requirements
for
establishing
a
general
account
are
covered
under
the
Allowance
Transfers
section
of
this
ICR
and
in
40
CFR
Part
73
Subpart
C
of
the
acid
rain
regulations.

Opt­
in
To
obtain
an
opt­
in
permit,
applicants
are
required
to
submit
a
certificate
of
representation
and
an
opt­
in
permit
application
for
each
source.
For
all
respondents,
the
application
must
provide
(
1)
general
information
on
the
source,
(
2)
specific
data
about
the
source's
fuel
consumption
and
operating
data
for
1985,
1986,
and
1987,
and
(
3)
data
on
the
source's
actual
and
allowable
emission
rates
for
1985,
as
well
as
the
current
allowable
emission
rate.
For
permit
applicants
who
plan
to
opt
in
and
shut
down,
the
compliance
plan
is
based
on
a
statement
describing
the
source's
plans
for
shutting
down
and
replacing
thermal
energy.

The
general
information
required
of
all
opt­
in
sources
include
the
following
items,
as
listed
in
Section
74.16
or
another
section
as
listed
below:


Source
name
and
location;


Name,
address,
telephone
and
facsimilie
number
of
the
designated
representative;


Name,
address,
telephone
and
facsimilie
number
of
the
alternate
designated
21
representative;


Statement
of
certification;


Complete
record
of
fuel
consumption
and
operating
data
for
calendar
years
1985,
1986,
1987,
or
other
acceptable
baseline;


Actual
and
allowable
emission
rates
for
1985,
or
if
source
was
not
operating
in
1985,
for
a
calendar
year
to
be
determined
by
the
Administrator,
as
well
as
the
current
allowable
emission
rate;


Statement
provisions
as
indicated
at
72.9;
and

Signature
of
designated
representative
and
date
of
signature.

In
addition,
sources
that
opt
in
and
continue
to
operate
must
meet
the
emission
monitoring
requirements
that
were
listed
above.

As
part
of
the
annual
compliance
certification
report
required
in
Section
74.43
for
opt­
in
units,
respondents
must
report
utilization
information,
and
replacement
of
thermal
energy
and
resulting
transfer
of
allowances.
The
following
information
must
be
reported,
as
required
in
Sections
74.44
and
74.47:


Source
name
and
location;


Name,
mailing
address,
telephone
and
facsimilie
number
of
source
representative;


Benchmark
utilization,
annual
utilization,
average
utilization,
end­
of­
year
determination
of
reduced
utilization,
and
the
calculation
of
allowances
deducted
for
reduced
utilization
(
if
any);


Amount
of
thermal
energy
replaced
(
if
the
source
has
shut
down
or
if
the
utlization
rate
has
fallen
due
to
replacement
of
thermal
energy
by
another
source),
and
the
name
and
location
of
the
source
or
sources
providing
replacement
thermal
energy;


A
calculation
of
the
number
of
allowances
transferred
to
each
source
providing
replacement
thermal
energy;


Allowance
tracking
system
account
number
of
the
replacement
units;
and

Dated
signatures
for
all
designated
representatives.

All
respondents
who
choose
to
withdraw
from
the
program
will
be
required
to
notify
the
Agency
of
their
decision
and
provide
the
following
information,
as
required
in
Section
74.18:


Source
account
number;


Name,
address,
telephone
and
facsimilie
number
of
the
designated
representative;
and

A
certification
that
emissions
requirements
will
be
met
through
Dec.
31
of
the
current
year,
and
that
all
remaining
allowances
will
be
surrendered
at
that
time.

Annual
Compliance
Certifcation
As
part
of
the
annual
compliance
certification
report
required
in
Section
72.90,
the
designated
representative
for
a
Phase
I
affected
source
must
provide
the
following
information
by
March
1,
1999
and
March
1,
2000:
22

Source
name,
State,
and
ORIS
Code;


Allowance
Tracking
System
account
number
and
general
compliance
information;
°
Dispatch
System
name;


Baseline
utilization,
annual
utilization,
and
annual
generation;
°
the
calculation
of
allowances
deducted
for
underutilization
(
if
any);
and

Dated
signatures
for
the
designated
representatives.

The
designated
representative
may
also
need
to
provide
the
following
information
under
section
72.92:
°
Dispatch
system
baseline
and
adjusted
utilization;
°
Dispatch
system
sales
(
baseline
and
current
year);
°
Fraction
of
generation
within
dispatch
system
and
dispatch
system
emissions
rate;
°
Fraction
of
generation
from
NUGs
and
NUG
emissions
rate;
and
°
Dated
signatures
for
all
designated
representatives.

and
the
following
information
under
section
72.91(
a)(
5):
°
Sulfur­
free
generator
name;
°
Baseline
and
calendar
year
generation;
°
List
of
units
claiming
sulfur­
free
generation;
°
Generation
available
for
shifting;
and
°
Dated
signatures
for
all
designated
representatives.

In
addition,
if
the
designated
representative
chooses
to
identify
the
specific
serialized
allowances
to
be
deducted
from
the
unit's
ATS
account,
then
the
following
information
is
required:
°
Allowance
Tracking
System
account
number;
°
Type
of
deduction;
°
Serial
numbers
of
the
allowance
blocks
to
be
deducted;
and
°
Dated
signature
of
the
designated
representative.

Finally,
if
a
unit
is
claiming
that
a
reduction
in
utilization
is
due
to
savings
from
energy
conservation
or
improved
unit
efficiency
measures,
then
section
72.91(
b)
requires
the
designated
representative
to
submit
a
confirmation
report
to
verify
the
savings.
The
confirmation
report
requires
the
following
information:
°
Source
name,
State,
ORIS
Code
and
Boiler
number;


Allowance
Tracking
System
account
number
and
dispatch
system
name;
°
Verified
savings
from
energy
conservation
or
improved
unit
efficiency
measures;
°
Estimated
savings
from
energy
conservation
or
improved
unit
efficiency
measures;
°
Either
a
certification
of
the
verified
savings
by
the
State
utility
regulatory
authority,
or
other
documentation
(
may
be
EPA's
Conservation
Verification
Protocol)
that
verifies
the
savings;
°
A
calculation
of
the
number
of
allowances
to
be
credited
or
deducted;
and
°
Dated
signature
of
the
designated
representative.
23
The
annual
compliance
certification
report
required
in
Section
72.90,
for
a
Phase
II
affected
source
must
provide
the
following
information
by
March
1,
2001
and
each
year
thereafter:


Source
name,
State,
and
ORIS
Code;


Allowance
Tracking
System
account
number
and
general
compliance
information;


Dated
signatures
for
the
designated
representatives.

In
addition,
if
the
designated
representative
chooses
to
identify
the
specific
serialized
allowances
to
be
deducted
from
the
unit's
ATS
account,
then
the
following
information
is
required:
°
Allowance
Tracking
System
account
number;
°
Serial
numbers
of
the
allowance
blocks
to
be
deducted;
and
°
Dated
signature
of
the
designated
representative.

NOx
Permitting
Regardless
of
the
compliance
option
selected,
the
following
elements
must
be
included
in
the
compliance
plan
for
each
source:


Identification
of
the
source;


Identification
of
each
affected
unit
at
the
source
that
is
subject
to
these
regulations;


Identification
of
the
boiler
type
of
each
unit;
and

Identification
of
the
compliance
option
proposed
for
each
unit.

For
the
standard
emission
limits,
the
designated
representative
must
simply
check
a
box
on
the
form
indicating
the
appropriate
limit.

For
an
emissions
averaging
plan,
the
following
information
must
be
submitted:


Identification
of
each
unit
in
the
plan;


Each
unit's
applicable
emission
limitation;


The
alternative
contemporaneous
applicable
emission
limitation
for
each
unit
(
in
lb/
mmBtu);


The
annual
heat
input
limit
for
each
unit
(
in
lb/
mmBtu);


The
calculation
for
the
equation
outlined
in
Step
2
of
the
EPA
form
for
emissions
averaging;
and

The
effective
date
of
the
plan.

For
an
AEL,
the
designated
representative
must
submit
the
following
information:

AEL
Demonstration
Period
For
an
AEL,
the
designated
representative
must
first
submit
an
application
for
an
AEL
demonstration
period.
The
application
must
contain
the
following
information
in
accordance
with
24
40
CFR
§
76.10(
d):


Identification
of
the
unit;


The
type
of
control
technology
installed.
If
low
NO
x
burner
technology
incorporating
advanced
and/
or
separated
overfire
air
is
technically
infeasible,
a
justification
including
a
technical
analysis
and
evaluative
report
from
the
vendor
of
the
system
or
from
an
independent
architectural
and
engineering
firm
explaining
why;


Documentation
that
the
installed
NO
x
emission
control
system
has
been
designed
to
meet
the
applicable
emission
limitation
and
that
the
system
has
been
properly
installed;


The
date
the
specific
unit
commenced
operation
following
the
installation
of
the
NO
x
control
equipment,
or
the
date
the
specific
unit
became
subject
to
the
emission
limitations
(
whichever
is
later);


The
dates
of
the
operating
period
(
minimum
of
3
continuous
months);


Certification
by
the
designated
representative
that
the
unit
and
the
NO
x
control
equipment
were
operated
during
the
operating
period
in
accordance
with
specifications
and
procedures
designed
to
achieve
the
applicable
emission
limitation,
with
the
operating
conditions
upon
which
the
design
of
the
NO
x
control
equipment
was
based,
and
with
vendor
specifications
and
procedures;


A
brief
statement
describing
the
reason
or
reasons
an
AEL
demonstration
period
is
required
for
the
specific
unit;


For
the
control
technology,
load
range,
O
2
range,
coal
volatile
matter
range,
and
percentage
of
combustion
air
introduced
through
overfire
air
ports;


Description
of
planned
modifications;


List
of
parametric
tests
to
be
conducted
in
accordance
with
40
CFR
§
76.15;


Identification
of
the
continuous
emission
monitoring
data
submitted
pursuant
to
40
CFR
Part
75
that
is
to
be
used
in
assessing
this
application;


An
interim
AEL,
in
lb/
mmBtu;
and

The
proposed
dates
of
the
demonstration
period.

Final
AEL
After
the
demonstration
period,
the
owner
or
operator
may
petition
the
permitting
authority
for
a
final
AEL.
The
petition
must
include
the
following
information
in
accordance
with
40
CFR
§
76.10(
e):


Identification
of
the
unit;


Certification
that
the
affected
unit
and
the
NO
x
control
equipment
have
been
properly
operated
during
the
demonstration
period;


Certification
that
the
affected
unit
has
installed
all
emission
control
equipment,
made
any
operational
modifications,
and
completed
any
upgrades
and/
or
maintenance
to
equipment
specified
in
the
demonstration
period
plan;


A
clear
description
of
each
step
or
modification
taken
during
the
demonstration
25
period;


Engineering
design
calculations
and
drawings
that
show
the
technical
specifications
for
installation
of
any
additional
operational
or
emission
control
modifications
installed
during
the
demonstration
period;


Identification
of
the
continuous
monitoring
data
submitted
pursuant
to
40
CFR
Part
75
that
is
to
be
used
in
assessing
this
application;


A
report,
based
on
the
parametric
testing,
that
describes
the
reasons
for
the
failure
of
the
installed
NO
x
control
equipment
to
meet
the
applicable
emission
limitation;


The
minimum
NO
x
emission
rate,
in
lb/
mmBtu,
that
the
affected
unit
is
able
to
achieve
on
an
annual
average
basis;


All
supporting
data
and
calculations
documenting
the
determination
of
the
proposed
AEL;
and

For
affected
units
that
have
installed
an
alternative
technology,
demonstration
that
the
annual
average
reduction
of
NO
x
emissions
is
greater
than
65
percent.

Recordkeeping
All
records
are
to
be
kept
for
three
years,
except
for
permitting
records
which
are
to
be
kept
for
the
duration
of
the
permit,
or
up
to
five
years
and
certain
new
monitoring
provisions.

4.2.2
Respondent
activities
Allowance
Transfers
Participants
in
the
allowance
transfer
system
that
are
not
affected
units
are
required
to
perform
two
tasks:
(
1)
negotiate
an
agreement
to
designate
an
authorized
account
representative
and
file
an
account
information
application
to
open
an
Allowance
Tracking
System
general
account;
and
(
2)
complete
and
submit
allowance
transfers.
Designating
an
authorized
account
representative
and
filing
an
account
information
application
is
required
one
time
only,
prior
to
or
concurrent
with
conducting
the
first
transfer
of
allowances.
For
each
transfer
of
allowances,
participants
are
required
to
complete
and
submit
an
allowance
transfer
form
or
otherwise
provide
the
required
information.
Phase
I
or
Phase
II
units
that
were
required
to
submit
a
certification
of
representation
under
the
initial
ICR,
must
continue
to
prepare
and
submit
allowance
transfer
information
for
each
allowance
transfer.

General
account
holders
and
affected
units
may
change
the
authorized
account
representatives
by
submitting
a
subsequent
allowance
account
information
form
or
certificate
of
representation
form
respectively.

Conservation
and
Renewable
Energy
Reserve
The
tasks
that
must
be
performed
by
utilities
applying
for
allowances
from
the
Conservation
and
Renewable
Energy
Reserve
are
(
1)
designate
the
qualified
energy
conservation
measures
implemented
and
the
qualified
renewable
energy
sources
used
to
avoid
emissions,
(
2)
verify
installation
of
energy
conservation
measures
or
the
plant
operation
using
renewable
energy,
26
and
the
resulting
benefits,
(
3)
calculate
the
tons
of
emissions
avoided,
and
(
4)
demonstrate
qualification
to
receive
allowances
for
emissions
avoided.
Generally,
because
utilities
already
perform
these
tasks
to
satisfy
state
requirements,
utilities
do
not
need
to
duplicate
these
efforts
to
apply
for
allowances
from
the
Reserve.
Rather,
utilities
primarily
assemble
the
information
resulting
from
these
activities
in
an
application
and
submit
this
application
to
EPA.

Obtaining
a
Permit
The
primary
tasks
to
obtain
a
permit
are
listed
below.
These
tasks
will
be
performed
only
by
new
units
during
the
period
covered
by
this
ICR.
In
general,
sources
with
existing
units,
must
reapply
at
least
6
months
prior
to
the
expiration
of
an
existing
permit.
Since
most
permits
will
begin
expiring
late
in
2002,
the
reapplications
to
the
permitting
authority
will
be
covered
by
the
next
ICR
renewal.


Designate
a
representative
of
the
owners
and
operators
of
a
source.
Read
the
designated
representative
certification
procedures.
Negotiate
an
agreement
to
designate
a
representative
for
each
unit
at
a
source.
Complete
and
submit
the
certification.
This
task
is
only
relevant
for
a
new
Phase
II
source
or
if
a
source
changes
the
designated
representative.


Prepare
the
permit
application.
Read
the
permit
application
instructions,
then
collect
relevant
information
for
the
permit
application.
Complete
the
Phase
II
acid
rain
permit
application.
Where
appropriate,
provide
specific
information
to
support
the
use
of
compliance
options
for
NO
x.
Review
the
information
for
accuracy
and
appropriateness
and
report
the
information
to
the
permitting
authority.

Emissions
Monitoring
The
primary
tasks
that
are
performed
by
respondents
to
meet
the
emissions
monitoring
requirements
are
(
1)
completing
and
submitting
appropriate
monitoring
plan
forms
for
each
affected
source
and
each
affected
unit
at
a
source;
(
2)
conducting
tests
to
certify
the
operation
of
monitors,
and
submitting
test
results
to
EPA;
(
3)
recording
hourly
emissions
data
(
this
activity
generally
is
performed
electronically);
(
4)
operation
and
maintenance
activities
associated
with
the
monitoring,
including
quality
assurance
activities;
(
5)
assuring
data
quality,
preparing
quarterly
reports
of
emissions
data
and
submitting
these
reports
to
EPA;
and
(
6)
responding
to
error
messages
generated
by
EPA.
In
addition,
respondents
must
purchase
the
necessary
monitoring
hardware
(
or
pay
for
fuel
sampling
and
analysis
in
some
cases)
and
purchase
the
electronic
data
reporting
software
(
or
software
upgrades).

Small
Diesel
Refiners
Small
diesel
refineries
will
need
to
read
the
preamble
and
final
rule
to
learn
the
procedures
for
qualifying
for
allowance
allocations.
If
facility
management
wishes
to
participate,
a
responsible
official
will
need
to
gather
Forms
EIA­
810
for
each
month
of
the
previous
year
and
prepare
a
transmittal
letter.

Opt­
in
In
order
to
provide
the
information
discussed
in
the
previous
section,
participants
must
27
complete
three
tasks
to
participate
in
the
opt­
in
program:
(
1)
submit
a
permit
application,
(
2)
meet
monitoring
requirements,
and
(
3)
submit
annual
compliance
reports.
Respondents
who
choose
to
withdraw
will
be
required
to
submit
a
withdrawal
notification.

The
primary
tasks
that
must
be
completed
to
obtain
a
permit
and
the
activities
associated
with
them
are
listed
below.
These
tasks
will
be
performed
only
once
during
the
period
covered
by
this
ICR.


Designate
a
representative
of
the
owners
and
operators
of
a
source.
Read
the
designated
representative
certification
procedures.
Negotiate
an
agreement
to
designate
a
representative
for
each
source.
Complete
and
submit
the
certification.


Prepare
the
permit
application.
Read
the
permit
application
instructions,
then
collect
relevant
information
for
the
permit
application.
Complete
written
forms,
including
an
application
for
an
opt­
in
permit.
Review
the
information
for
accuracy
and
appropriateness.
Submit
the
information
to
EPA,
sending
copies
to
the
appropriate
EPA
regional
office.

Respondents
who
opt
in
and
continue
to
operate
must
also
perform
the
task
required
under
the
emissions
monitoring
section
above.
Respondents
who
opt
in
and
shut
down
do
not
need
to
perform
any
tasks
related
to
monitoring.

To
withdraw
from
the
program,
respondents
must
notify
EPA
of
their
decision
to
withdraw.
Notification
entails
providing
EPA
with
the
data
items
presented
in
Section
3.2.1..

Opt­
in
sources
covered
by
a
thermal
energy
plan,
must
also
report
information
concerning
the
replacement
of
thermal
energy,
including
the
identification
of
the
source
or
sources
providing
replacement
thermal
energy,
and
the
allowances
transferred
as
a
result
of
the
replacement
of
thermal
energy.

Annual
Compliance
Certification
The
respondents
will
need
to
read
the
instructions,
collect
the
relevant
information
and
fill
out
the
appropriate
forms.
The
tasks
associated
with
compliance
reporting
in
Phase
I
are
(
1)
certifying
compliance
by
submitting
an
Annual
Compliance
Certification
Report
for
the
source,
(
2)
reporting
utilization
information
for
the
past
year
by
submitting
a
Utilization
Accounting
form
for
each
Phase
I
affected
unit,
(
3)
supplying
dispatch
system
information,
if
any
Phase
I
unit
in
the
dispatch
system
is
underutilized,
using
the
Dispatch
System
Data
Report,
(
4)
for
reduced
utilization
plans,
providing
sulfur­
free
generator
apportionment
information,
(
5)
if
the
designated
representative
chooses,
identifying
the
serial
numbers
of
allowances
to
be
deducted
using
the
Allowance
Deduction
Form,
and
(
6)
if
claiming
energy
conservation
or
improved
unit
efficiency
savings,
supplying
verified
data
using
the
Energy
Conservation
and
Improved
Unit
Efficiency
Confirmation
Report
by
July
1.

In
addition,
any
substitution
or
compensating
unit
in
a
State
where
a
state­
enforced
emission
cap
applies,
the
source
must
submit
additional
"
State
Cap"
information.
28
Submitting
annual
compliance
certifications
is
required
for
all
Phase
I
affected
units
by
March
1,
1999
and
March
1,
2000.

The
tasks
associated
with
compliance
reporting
in
Phase
II
are
(
1)
certifying
compliance
by
submitting
an
Annual
Compliance
Certification
Report
for
the
source,
and
(
2)
if
the
designated
representative
chooses,
identifying
the
serial
numbers
of
allowances
to
be
deducted
using
the
Allowance
Deduction
Form
NOx
Permitting
The
primary
tasks
for
a
NO
x
compliance
plan
are
listed
below.


Prepare
the
NO
x
compliance
plan
application.
Read
the
application
instructions,
then
collect
relevant
information.
Analyze
compliance
options
and
plan
compliance.
Complete
written
forms.
Review
the
information
for
accuracy
and
appropriateness
and
report
the
information
to
the
permitting
authority.
Preparing
a
NO
x
compliance
plan
application
may
include
interpreting
the
rule,
collecting
information
and
completing
and
submitting
a
NO
x
extension
plan,
a
NO
x
averaging
plan,
or
an
AEL
petition.

During
the
period
covered
by
this
ICR,
tasks
for
permitting
will
be
performed
only
by
sources
choosing
to
revise
NO
x
averaging
plans
in
accordance
with
Section
408.

5.
THE
INFORMATION
COLLECTED
­­
AGENCY
ACTIVITIES,
COLLECTION
METHODOLOGY,
AND
INFORMATION
MANAGEMENT
The
first
part
of
this
section
describes
Agency
(
EPA)
activities
related
to
the
acquisition,
analysis,
storage,
and
distribution
of
the
information
collected
from
(
1)
participants
in
allowance
transfers,
(
2)
applicants
for
allowances
from
the
Conservation
and
Renewable
Energy
Reserve,
(
3)
permit
applicants,
(
4)
designated
representatives
of
affected
sources
that
are
required
to
submit
monitoring
plans
and
emissions
data,
(
5)
participants
in
the
annual
auction,
and
(
6)
participants
associated
with
allocation
of
allowances
to
small
diesel
refineries,
(
7)
the
opt­
in
program,
(
8)
annual
compliance
certification,
and
(
9)
NO
x
permitting.
The
second
part
describes
the
information
management
techniques
employed
to
increase
the
efficiency
of
collections.
The
third
part
discusses
the
burden
or
benefits
of
the
collection
activities
described
in
this
ICR
to
small
entities.
The
last
part
outlines
the
schedule
for
collecting
information.

5.1
Agency
Activities
Allowance
Transfers
Collections
associated
with
operating
the
allowance
transfer
system
requires
EPA
to
(
1)
track
allowance
holders
and
maintain
allowance
accounts,
(
2)
review
allowance
transfer
information
for
completeness
and
ensure
that
all
requirements
are
met,
(
3)
record
allowance
29
transfers,
and
(
4)
notify
both
participants
in
a
transfer
whether
the
transfer
was
recorded.
EPA
has
developed
a
computer
system
called
the
Allowance
Tracking
System
(
ATS)
to
track
allowances
and
maintain
information
on
accounts.

Conservation
and
Renewable
Energy
Reserve
Activities
that
must
be
performed
by
EPA
to
distribute
allowances
from
the
Conservation
and
Renewable
Energy
Reserve
include
(
1)
registering
applications
and
reviewing
applications
for
completeness,
(
2)
performing
substantive
reviews
of
applications
to
determine
whether
all
necessary
criteria
to
receive
allowances
have
been
met,
(
3)
transferring
allowances
from
the
Reserve
or
notifying
applicants
of
their
failure
to
qualify
for
allowances
from
the
Reserve,
and
(
4)
for
utilities
using
the
EPA
Conservation
Verification
Protocol,
verifying
the
quantified
energy
savings
from
conservation
measures.

Permits
EPA
staff
administering
the
permit
program
perform
the
following
task:


Review
certificates
of
representation,
enter
the
information
in
the
Allowance
Tracking
System,
and
notify
the
representative.

Permitting
authority
staff,
generally
at
the
state
or
local
level,
perform
the
following
tasks:


Review
permit
applications
and
issue
permits.
Receive
and
review
permit
applications
and
record
submissions.
Provide
notice
to
applicants
whether
permit
applications
are
complete.
Reformat
collected
data
items
to
constitute
proposed
and
final
permits.
Provide
opportunities
for
public
comment
and
participation.

Emissions
Monitoring
The
major
EPA
activities
related
to
emissions
monitoring
and
reporting
include
(
1)
reviewing
monitoring
plans
and
certification
applications,
and
(
2)
processing,
reviewing
and
evaluating
reports
of
quarterly
emissions
data
from
affected
units.
EPA
has
developed
a
computer
system
called
the
Emissions
Tracking
System
(
ETS)
to
track
and
maintain
this
information.
EPA
also
answers
respondent
questions
and
conducts
audits
of
data
submissions.
To
enable
sources
to
perform
self­
audits
of
submissions,
EPA
also
has
recently
developed
the
Monitoring
Data
Checking
(
MDC)
software
for
use
by
affected
sources.
This
software
should
enable
sources
to
run
automated
quality
checks
of
reports
prior
to
submittal
to
EPA
and
reduce
the
burden
of
having
to
respond
to
EPA
generated
error
messages.

Auctions
The
statute
allows
EPA
to
delegate
or
contract
out
the
function
of
administering
auctions.
The
EPA
has
entered
into
an
agreement
with
the
Chicago
Board
of
Trade
(
CBOT)
whereby
the
CBOT
shall
administer
the
auctions.
CBOT
will
not
charge
fees
for
their
services,
bid
for
allowances
in
the
auctions,
or
transfer
allowances
in
the
EPA
Allowance
Tracking
System.
EPA
is
allowing,
however,
clearing
members
of
the
Board
of
Trade
Clearing
Corporation
(
BOTCC)
to
bid
on
their
own
behalf
or
their
customers'
without
having
to
submit
an
EPA
letter
of
Credit
Form
30
or
certified
check.
Payment
is
being
guaranteed
through
the
BOTCC,
which
provides
trade
clearance
and
settlement
services
for
CBOT.
BOTCC
members
may
charge
bidders
a
fee
for
bidding
on
their
behalf.

CBOT
staff
administering
the
auctions
(
auction
agents)
need
to
review
procedures
and
prepare
to
conduct
the
auctions
on
an
annual
basis.
The
CBOT
receives
the
sealed
bids
and
payments,
enters
the
information
provided
on
bid
forms
into
a
computer
system,
and
deposits
the
checks
into
a
designated
bank
account.
(
Collectively,
these
activities
comprise
handling
of
bids
and
checks.)
After
bids
are
recorded,
CBOT
ranks
the
bids
using
a
computer
program
and
allocates
the
allowances.
CBOT
announces
the
results
in
a
press
conference/
release.
Finally,
after
payment
is
verified,
EPA
records
the
transfer
of
allowances
and
transfers
the
proceeds
from
the
auction
to
the
owners
and
operators
from
whom
the
allowances
were
withheld.
EPA
has
developed
a
computer
system
to
track
the
payment
of
proceeds.

Opt­
in
EPA
staff
administering
the
opt­
in
permit
program
perform
the
following
tasks
for
each
opt­
in
applicant:


Review
certification
of
representation,
record
information,
and
notify
representative.


Review
permit
application.
Receive
and
review
permit
application
and
record
submission.
Provide
notice
to
applicant
as
to
whether
permit
application
is
complete.
Reformat
collected
data
items
to
constitute
proposed
and
final
permit.


Notify
applicant
regarding
allowances.
Notify
the
opt­
in
permit
applicant
of
the
number
of
allowances
the
applicant
would
receive
each
year
as
an
opt­
in
source.


Issue
permit,
notify
the
public
and
affected
states.
Upon
notification
of
the
applicant's
decision
to
proceed
with
the
permit
application,
provide
opportunities
for
public
comment
and
participation.

EPA
activities
related
to
withdrawals
will
be
to
process
the
withdrawal
notification,
and
ensure
that
all
unused
allowances
have
been
surrendered
at
the
end
of
the
calendar
year.

Annual
Compliance
Certification
EPA
activities
related
to
compliance
reporting
are
(
1)
review
end­
of­
year
compliance
submissions,
(
2)
calculate
and
deduct
the
allowances
from
each
affected
unit,
and
(
3)
send
the
designated
representatives
an
allowance
reconciliation
report.

NOx
Permitting
Agency
staff
perform
the
following
task.


Review
NO
x
compliance
plan
applications.
Receive
and
review
applications
and
record
submissions.
Provide
notice
to
applicants
whether
applications
are
complete.
31
5.2
Collection
Methodology
and
Management
To
ensure
consistency
nationwide
and
to
expedite
(
1)
data
entry,
(
2)
the
allocation
of
allowances
from
Reserves,
and
(
3)
permit
issuance,
EPA
requires
that
standard
reporting
forms
or
equivalent
formats
or
standard
electronic
reporting
formats
be
used
to
submit
all
information
to
be
collected
under
this
ICR.
The
standard
forms
are
included
in
Appendix
C.

Currently,
respondents
to
collections
for
allowance
transfer
information
may
submit
the
required
information
on
a
standard
written
form,
or
using
an
electronic
format.
Permit
applications
and
annual
compliance
certifications
are
submitted
on
standard
paper
forms,
as
are
certifications
for
new
and
retired
unit
exemptions.
Also
to
ensure
consistency
and
to
expedite
data
entry,
EPA
requires
that
standard
electronic
data
reporting
(
EDR)
formats
be
used
to
submit
information
to
be
collected
under
Part
75
and,
under
the
rule
revisions,
EPA
also
will
require
that
data
be
sent
via
direct
electronic
submission
to
EPA
beginning
in
the
year
2001.
The
revised
draft
EDR
formats
(
version
2.1)
that
correspond
to
the
revisions
to
Part
75
are
included
as
Appendix
A
to
this
document.

Several
computer
systems
and
associated
databases
have
been
developed
to
(
1)
track
allowances,
(
2)
record
quarterly
emissions
monitoring
data,
(
3)
track
auction
proceed
payments,
and
(
4)
calculate
the
number
of
allowances
to
be
deducted
each
year.
The
systems
and
databases
are
designed
to
coordinate
the
information
for
easy
access
and
use
by
the
Agency,
states,
regulated
community,
and
the
public.

EPA
has
established
an
Acid
Rain
Home
Page
on
the
Internet,
which
includes
detailed
information
collected
from
emissions
reports,
allowance
transfer
submissions,
auctions,
and
annual
compliance
information.
Those
without
access
to
the
Internet
may
use
the
Acid
Rain
Hotline
to
request
information,
including
the
Annual
Compliance
Reports
or
other
summary
reports.

5.3
Small
Entity
Flexibility
For
the
purposes
of
the
Acid
Rain
Program,
EPA
has
adopted
the
Small
Business
Administration's
definition
of
a
"
small"
electric
power
utility
as
one
that
generates
a
total
of
less
than
4
billion
kilowatt­
hours
per
year.
Generally,
although
about
two­
thirds
of
the
affected
sources
in
Phase
II
generate
a
total
of
less
than
4
billion
kilowatt­
hours
per
year
and
are
required
to
participate
in
some
collections
under
this
ICR
(
e.
g.,
submitting
information
for
certification
of
monitors
and
submitting
quarterly
emissions
monitoring
reports),
the
costs
to
these
sources
for
collections
under
this
ICR
are
small
relative
to
the
revenues
they
generate.

All
affected
sources
under
the
Clean
Air
Act
Amendments
of
1990
are
required
to
submit
permit
applications
and
to
respond
to
other
collections
under
this
ICR,
according
to
the
same
parameters
(
with
the
exception
of
operators
of
new
units
of
25
MW
or
less,
who
may
receive
an
exemption
from
the
Acid
Rain
Program
requirements
if
they
qualify).
Retired
units
may
also
be
exempted
from
some
reporting
requirements.
32
The
use
of
standardized
forms
will
enable
small
entities
to
understand
and
complete
permit
application
submissions
without
the
level
of
staffing
which
would
be
necessary
in
the
absence
of
such
forms.

The
small
diesel
program
is
available
primarily
to
small
businesses.
To
best
accommodate
the
needs
of
businesses,
small
and
large,
EPA
has
minimized
the
collection
burden
by
requiring
certified
reproductions
of
already
existing
information.

In
the
January
11,
1993
final
Acid
Rain
Core
Rules,
EPA
provided
for
a
conditional
exemption
from
the
emissions
reduction,
permitting,
and
emissions
monitoring
requirements
of
the
Acid
Rain
Program
for
new
units
having
a
nameplate
capacity
of
25
MWe
or
less
that
burn
fuels
with
a
sulfur
content
no
greater
than
0.05
percent
by
weight,
because
of
the
high
cost
of
monitoring
emissions
from
these
sources
and
the
de
minimis
nature
of
their
emissions.

The
Part
75
rule
revisions
also
create
an
additional
small
unit
exception.
This
exception
incorporates
optional
reduced
monitoring,
quality
assurance,
and
reporting
requirements
into
Part
75
for
units
that
combust
natural
gas
and/
or
fuel
oil
and
that
emit
no
more
than
25
tons
of
SO
2
and
no
more
than
50
tons
of
NO
x
annually
and
that
calculate
no
more
than
25
tons
of
SO
2
and
no
more
than
50
tons
of
NO
x
annually
based
on
required
procedures
for
calculating
and
reporting
emissions.
Qualifying
utilities
will
no
longer
be
required
to
keep
monitoring
equipment
installed
on
(
or
conduct
sulfur­
in­
fuel
sampling
for)
low
mass
emissions
units,
nor
will
they
be
required
to
perform
quality
assurance
or
quality
control
tests.
Moreover,
emissions
reporting
requirements
will
be
significantly
simplified
for
these
units.

Even
if
a
gas­
or
oil­
fired
unit
does
not
qualify
for
this
"
low
mass
emissions
unit"
exception,
the
revisions
also
significantly
reduce
the
costs
and
burdens
associated
with
fuel
sampling
and
QA
activities
for
these
units.
As
discussed
in
the
Regulatory
Impact
Analysis
(
RIA)
of
the
final
Acid
Rain
Implementation
Regulations
(
October
19,
1992),
smaller
utilities
are
more
likely
to
be
dependent
on
these
oil­
and
gas­
fired
units,
especially
very
small
utilities
(
see
p.
5­
14
of
that
RIA
document).

Further
reductions
in
requirements
aimed
specifically
for
small
entities
are
limited
because
of
the
statutory
requirements
that
all
affected
units
use
CEMS
(
or
an
equivalent
method)
to
record
and
report
emissions
data
for
Title
IV
purposes.

5.4
Collection
Schedule
Allowance
Transactions
There
is
no
specific
collection
schedule
associated
with
allowance
transactions.

Conservation
and
Renewable
Energy
Reserve
Submitting
applications
for
allowances
from
the
Conservation
and
Renewable
Energy
Reserve
is
voluntary.
Allowances
from
the
Reserve
will
be
allocated
on
a
first­
come,
first­
served
basis
during
the
period
from
January
1,
1992
to
December
31,
2000.
33
Permits
Each
Phase
I
acid
rain
permit
is
effective
from
January
1,
1995,
until
December
31,
1999.
Revisions
to
the
permit
may
be
submitted
at
any
time.
Phase
II
permit
applications,
which
were
required
by
January
1,
1996,
are
covered
in
the
initial
ICR.

Emissions
Monitoring
Monitoring
plans
must
be
submitted
only
once,
although
certain
elements
of
the
monitoring
plan
are
submitted
(
and
updated
as
necessary)
routinely
as
part
of
the
EDR
format.
The
revisions
to
Part
75
further
clarify
what
monitoring
elements
need
to
be
submitted
in
hard
copy
versus
electronic
form.

Only
new
units
will
have
to
apply
for
certification
during
the
1999­
2001
time
period.
While
some
monitors
will
be
required
to
apply
for
recertification,
there
is
no
set
schedule
for
recertification.

Quarterly
reports
are
due
for
each
quarter
during
the
life
of
this
information
collection
request.
In
addition,
EPA
has
provided
for
notifications
to
the
Agency
for
semi­
annual
or
annual
quality
assurance
testing
and
for
situations
where
a
unit
will
have
a
revised
certification
deadline
(
for
example,
notifications
of
unit
start­
up
for
new
units).
As
part
of
the
revisions,
EPA
will
exempt
units
that
have
been
shutdown
from
quarterly
reporting
during
the
shutdown,
even
though
such
units
could
resume
operation
after
providing
notice
to
EPA.

Auctions
The
spot
and
advance
auctions
are
currently
held
before
March
31
of
each
year.
The
cutoff
date
for
submission
of
bids
is
only
a
few
days
prior
to
the
auction
in
order
to
limit
the
time
EPA
holds
the
bidders'
money.

Allowance
Allocations
&
Small
Diesel
Refiners
For
the
410(
h)
small
diesel
refiners
program,
submittals
for
eligibility
can
be
made
at
any
time.
EPA
believes
that
all
eligible
small
diesel
refineries
have
already
submitted
the
eligibility
applications.
Information
for
the
allocation
of
allowances
must
be
submitted
annually.
Submissions
are
accepted
no
later
than
April
1
of
the
year
following
the
eligible
desulfurization.
Allowances
for
the
small
diesel
refineries
program
are
available
from
October,
1993
through
December,
1999.

Opt­
in
Opting
in
to
the
allowance
program
requires
just
one
information
collection
(
although
monitoring
information
for
affected
sources
must
be
collected
quarterly).
Opt­
in
permit
applications
may
be
submitted
to
EPA
and
the
permitting
authority
at
any
time.
Permits
must
be
renewed
at
that
time,
and
every
five
years
thereafter.
Revisions
to
the
permit
may
be
submitted
at
any
time.

Monitoring
plans
must
be
submitted
only
once,
at
the
time
the
opt­
in
permit
application
is
submitted.
The
data
upon
which
EPA
will
base
its
certification
of
each
emissions
monitor
may
be
34
submitted
after
the
source
receives
a
draft
opt­
in
permit,
but
must
be
submitted
before
the
source
may
be
designated
an
affected
source.
(
Monitors
must
be
installed,
certified
by
EPA,
and
operating
before
the
source
may
be
designated
an
affected
source.)
Emissions
data
to
meet
reporting
requirements
are
collected
quarterly,
30
days
after
the
end
of
each
calendar
quarter,
beginning
at
the
end
of
the
first
quarter
in
which
the
source
becomes
an
affected
source.

Compliance
reports
must
be
sent
annually.
Allowance
transfer
information
must
be
submitted
once
for
each
transfer;
a
certificate
of
representation
needs
to
be
submitted
only
once,
at
the
same
time
as
the
opt­
in
application.

Withdrawing
requires
only
one
information
collection.

Annual
Compliance
Certification
This
information
is
collected
annually
from
March
through
July
for
the
preceding
calendar
year.

NOx
Permitting
Revisions
to
NO
x
averaging
palns
may
be
submitted
at
any
time.

6.
ESTIMATING
THE
BURDEN
AND
COST
OF
COLLECTIONS
This
section
estimates
the
paperwork
burden
and
cost
of
(
1)
tracking
and
transferring
allowances,
(
2)
obtaining
and
distributing
allowances
from
the
Conservation
and
Renewable
Energy
Reserve,
(
3)
obtaining
and
issuing
permits,
(
4)
submitting
monitoring
plans,
obtaining
certification
of
each
monitor,
and
recording
and
reporting
data
from
CEM
systems,
(
5)
the
auction
program,
(
6)
allowance
allocation
to
small
diesel
refineries,
(
7)
the
opt­
in
program,
(
8)
end­
of­
year
compliance
activities,
and
(
9)
NO
x
permitting.

First,
assumptions
regarding
allowance
transfers
are
presented,
followed
by
the
annual
respondent
and
Agency
burden
and
cost
estimates
associated
with
allowance
transfers.
Subsequent
sections
separately
address
allowances
for
energy
conservation
and
renewable
energy
use,
permits,
emissions
monitoring,
auctions,
opt­
in,
and
annual
compliance.
Finally,
aggregate
annual
burden
hour
and
cost
estimates
to
respondents
and
to
EPA
for
collections
covered
by
this
ICR
are
presented.

Estimating
Labor
Costs
To
calculate
labor
costs,
EPA
used
the
following
amounts:
$
66.05
per
hour
for
managers,
$
45.44
per
hour
for
technicians,
and
$
21.20
per
hour
for
clerical
workers.
As
noted
above,
these
rates
were
derived
by
using
the
rates
from
the
previous
ICR
and
updating
them
with
the
Employment
Cost
Index
to
June
1998.

The
labor
cost
to
the
Agency,
$
42.81
per
hour,
was
also
derived
by
updating
the
rate
from
35
the
previous
ICR.

6.1
Tracking
and
Transferring
Allowances
Labor
burden
and
costs
for
collections
associated
with
tracking
and
transferring
allowances
are
functions
of
the
number
of
transfers
anticipated.
Based
on
number
of
transfers
recorded
by
EPA
in
1997,
EPA
is
assuming
that
about
1,500
privately
submitted
allowance
transfers
will
be
made
each
year,
1999
through
2001.

6.1.1
Estimate
of
Respondent
Burden
and
Costs
for
Transfers
Exhibit
1
presents
the
annual
burden
and
costs
to
participants
in
allowance
transfers.
Participants
that
are
not
affected
units
are
required
to
negotiate
an
agreement
to
designate
an
authorized
account
representative
and
file
a
new
account
application;
this
activity
is
required
only
one
time,
prior
to
or
simultaneous
with
the
participant's
first
transfer
of
allowances.
All
participants
are
required
to
complete
and
submit
allowance
transfer
information
for
each
transfer
of
allowances.
EPA
estimates
about
30
hours
to
designate
an
authorized
account
representative
and
to
open
a
general
account,
and
about
2
hours
to
prepare
and
submit
information
for
an
allowance
transfer.

Assuming
that
1,500
transfers
will
be
made
annually,
the
burden
to
respondents
will
be
about
4,950
hours
annually.
The
cost
to
respondents
will
be
about
$
260,000
annually.
36
EXHIBIT
1
ANNUAL
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
ALLOWANCE
TRANSFERS
Tasks
Burden
Hours
per
Occurrence
Cost
per
Occurrencea
Total
Burdenb
Total
Cost
1.
Designate
an
authorized
account
representative
and
file
new
account
application
Managerial
10
$
661
650
$
42,965
Technical
15
$
682
975
$
44,330
Clerical
5
$
106
325
$
6,890
2.
Prepare
and
submit
allowance
transfer
information
Managerial
1
$
66
1,500
$
99,000
Technical
1
$
45
1,500
$
67,500
TOTAL
4,950
$
260,685
a
1998
dollars.
b
Assumes
65
participants
file
new
account
applications
and
1,500
transfers
are
made.

6.1.2
Estimate
of
Agency
Burden
and
Costs
for
Transfers
Agency
burden
and
costs
are
divided
into
those
costs
associated
with
enhancing
a
tracking
system
and
those
associated
with
transferring
allowances.

Allowance
Tracking
System
The
allowance
system
regulations
set
the
general
requirements
for
the
tracking
system,
which
has
been
developed
by
EPA.
In
order
to
track
allowances,
the
allowance
tracking
system
must
include
information
on
(
1)
allowance
allocations
for
each
affected
unit,
(
2)
allowance
transfers
and
deductions,
and
(
3)
allowance
holders.
Also,
to
allow
for
the
transfer
of
future
year
allowances,
the
allowance
tracking
system
will
contain
allowance
information
for
thirty
years
into
the
future.
EPA
has
made
the
information
compiled
in
the
allowance
tracking
system
publicly
available
in
several
formats
on
the
internet
and
is
continually
working
to
improve
electronic
access.

EPA
incurs
annual
operation
and
maintenance
(
O&
M)
costs
for
running
an
electronic
transmission
network,
system
enhancement,
general
maintenance,
and
employee
salaries.
These
O&
M
costs
are
estimated
at
$
100,000
to
$
200,000
per
year
(
or
an
average
of
about
$
150,000
37
annually).

Allowance
Transfer
System
Upon
receipt
of
an
allowance
transfer
notification,
EPA
will
(
1)
review
allowance
transfer
information
for
completeness
and
ensure
that
all
requirements
have
been
met,
(
2)
record
allowance
transfers,
and
(
3)
notify
both
participants
to
a
transfer
whether
the
transfer
was
recorded.
EPA
estimates
that
it
will
require
an
average
of
one
hour
to
perform
these
activities
for
each
notification.
Assuming
1,500
transfers
will
be
made
each
year,
the
annual
burden
to
EPA
will
be
about
1,500
hours.
The
cost
to
EPA
will
be
about
$
64,500
annually.
Exhibit
2
summarizes
the
Agency
burden
and
cost
estimates
for
recording
and
transferring
allowances.

EXHIBIT
2
ANNUAL
AGENCY
BURDEN/
COST
ESTIMATES
FOR
ALLOWANCE
TRANSFERS
Tasks
Burden
Hours
Per
Occurrence
Cost
Per
Occurrencea
Total
Burdenb
(
Hours)
Total
Cost
Review
allowance
transfer
information,
record
transfer,
and
notify
transfer
participants
1
$
43
1,500
$
64,500
TOTAL
1,500
$
64,500
a
1998
dollars.
b
Assumes
1,500
transfers
are
made
annually.

6.2
Obtaining
and
Distributing
Allowances
From
the
Conservation
and
Renewable
Energy
Reserve
Although
it
is
difficult
to
predict
the
number
of
utilities
that
will
apply
for
allowances
from
the
Conservation
and
Renewable
Energy
Reserve,
based
on
previous
years
this
analysis
assumes
that
20
applications
will
be
submitted
in
1999
and
10
applications
each
year
thereafter.
EPA
is
also
assuming
that
only
one
application
for
allowances
will
be
submitted
by
any
one
utility
in
a
particular
year.

6.2.1
Estimate
of
Respondent
Burden
and
Costs
Exhibit
3
depicts
the
annual
respondent
burden
and
costs
associated
with
obtaining
allowances
from
the
Conservation
and
Renewable
Energy
Reserve.
Each
utility
applying
for
allowances
from
the
Reserve
is
required
to
perform
the
following
tasks:
(
1)
designate
energy
conservation
measures
implemented
and
renewable
energy
sources
used
to
avoid
emissions;
(
2)
verify
savings
from
energy
conservation
measures
and/
or
amount
of
generation
from
renewable
energy;
(
3)
calculate
the
tons
of
emissions
avoided;
and
(
4)
demonstrate
qualification
to
receive
38
allowances
for
emissions
avoided.
Because
most
states
already
collect
information
on
these
activities
from
utilities,
the
primary
burden
to
utilities
will
be
that
associated
with
assembling
and
submitting
to
EPA
the
application
to
receive
allowances
from
the
Reserve.
Assuming
it
will
take
applicants
about
46
hours
to
assemble
and
submit
an
application
to
receive
allowances
from
the
Reserve
to
EPA,
and
an
additional
32
hours
if
the
applicant
chooses
to
assemble
and
submit
the
information
required
in
the
EPA
Conservation
Verification
Protocol,
the
total
annual
burden
to
respondents
will
be
952
hours
in
1999
and
492
hours
in
subsequent
years.
The
total
annual
cost
to
utilities
applying
for
allowances
from
the
Conservation
and
Renewable
Energy
Reserve
will
be
$
45,446
in
1999
and
$
23,486
in
subsequent
years.

EXHIBIT
3
ANNUAL
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
CONSERVATION
AND
RENEWABLE
ENERGY
ALLOWANCES
Tasks
Burden
Hours
per
Application
Cost
per
Applicationa
Total
Burden
(
Hours)
Total
Costs
1999
2000
and
2001
1999
2000
and
2001
1.
Assemble
and
submit
an
application
to
receive
allowances
from
the
Reserveb
Managerial
11
$
727
220
110
$
14,540
$
7,270
Technical
30
$
1,363
600
300
$
27,260
$
13,630
Clerical
5
$
106
100
50
$
2,120
$
1,060
2.
Assemble
and
submit
the
information
required
in
the
EPA
Conservation
Verification
Protocolc
Managerial
7
$
462
7
7
$
462
$
462
Technical
22
$
1,000
22
22
$
1,000
$
1,000
Clerical
3
$
64
3
3
$
64
$
64
TOTAL
952
492
$
45,446
$
23,486
a
1998
dollars.
b
Assumes
20
applications
in
1999
and
10
applications
each
year
thereafter.
c
Assumes
1
applicant
will
utilize
the
EPA
Conservation
Verification
Protocol.

6.2.2
Estimate
of
Agency
Burden
and
Costs
Exhibit
4
depicts
the
annual
burden
and
costs
to
EPA
associated
with
distributing
allowances
from
the
Conservation
and
Renewable
Energy
Reserve.
Tasks
performed
by
EPA
39
related
to
the
distribution
of
allowances
from
the
Reserve
include
the
following:
(
1)
register
applications
and
review
applications
for
completeness;
(
2)
perform
substantive
reviews
of
applications
to
determine
whether
all
necessary
criteria
to
receive
allowances
have
been
met;
(
3)
transfer
allowances
from
the
Reserve
or
notify
applicants
of
their
failure
to
qualify
for
allowances
from
the
Reserve;
and
(
4)
for
utilities
that
choose
to
use
the
EPA
Conservation
Verification
Protocol,
verify
the
quantified
energy
savings
from
conservation
measures.
Assuming
it
takes
EPA
about
11
hours
to
process
each
application
and
transfer
allowances
(
or
notify
applicants),
the
total
annual
Agency
for
distributing
allowances
from
the
Reserve
is
an
estimated
125
hours
in
1999
and
65
hours
each
year
thereafter.
At
a
cost
of
$
40
per
hour,
the
total
annual
cost
to
EPA
will
be
$
5,354
in
1999,
and
$
2,784
in
subsequent
years.

EXHIBIT
4
ANNUAL
AGENCY
BURDEN/
COST
ESTIMATES
FOR
CONSERVATION
AND
RENEWABLE
ENERGY
ALLOWANCES
Tasks
Burden
Hours
per
Application
Cost
per
Applicationa
Total
Burden
(
Hours)
Total
Costs
1999
2000
and
2001
1999
2000
and
2001
1.
Register
application
and
review
for
completenessb
1
$
43
20
10
$
860
$
430
2.
Perform
substantive
review
of
applicationb
4
$
171
80
40
$
3,420
$
1,710
3.
Transfer
allowances
from
the
Reserve
or
notify
applicantsb
1
$
43
20
10
$
860
$
430
4.
Verify
energy
savings
based
upon
the
EPA
Conservation
Verification
Protocolc
5
$
214
5
5
$
214
$
214
TOTAL
125
65
$
5,354
$
2,784
a
1998
dollars.
b
Assumes
20
applications
in
1999
and
10
applications
each
year
thereafter.
c
Assumes
1
applicant
will
utilize
the
EPA
Conservation
Verification
Protocol.

6.3
Obtaining
and
Issuing
Permits
This
part
presents
estimates
of
the
level
of
effort
required
and
the
associated
costs
to
permit
applicants
and
either
EPA
or
the
permitting
authority
of
obtaining
and
issuing
permits.
This
analysis
estimates
the
cost
and
burden
only
for
new
sources
required
to
obtain
permits
for
Phase
II
and
for
sources
changing
designated
representatives.
The
initial
submittal
of
all
Phase
I
and
II
permit
applications
for
existing
sources
were
covered
in
the
initial
information
collection
request.
40
Also,
because
1999
is
the
last
year
of
Phase
I,
EPA
assumes
that
no
sources
will
modify
their
Phase
I
permit
before
it
expires
on
Dec.
31,
1999.

All
applicants
for
permits
will
be
required
to
submit
a
general
acid
rain
permit
application
for
each
affected
source
that
covers
all
units
at
the
source.

6.3.1
Estimate
of
Respondent
Burden
and
Costs
for
Permiting
Exhibit
5
depicts
the
burden
and
costs
to
respondents
for
(
1)
selecting
a
new
designated
representative,
(
2)
submitting
a
Phase
II
permit
application,
(
3)
submitting
a
retired
unit
exemption,
(
4)
submitting
a
new
unit
exemption,
and
(
5)
submitting
an
industrial
unit
exemption.
Based
on
the
past
few
years
of
operation,
EPA
assumes
that
each
year
60
Certificate
of
representation
forms
will
be
submitted
to
appoint
new
designated
representatives,
5
new
sources
will
submit
Phase
II
permit
applications,
5
units
will
submit
retired
unit
exemptions,
15
units
will
submit
new
unit
exemptions,
and
5
sources
will
submit
industrial
unit
exemptions.

The
total
annual
respondent
burden
is
estimated
to
be
2,435
hours.
The
costs
associated
with
the
permitting
process
are
estimated
at
$
141,320
annually.
41
EXHIBIT
5
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
PERMITS
Tasks
Burden
Hours
Per
Occurrence
Cost
Per
Occurrencea
Total
Burden
(
Hours)
Total
Cost
Change
designated
representativeb
Managerial
Technical
Clerical
28
3.5
3.5
$
1,849
$
159
$
74
1,680
210
210
$
110,904
$
9,540
$
4,440
Phase
II
permit
applicationsc
Managerial
Technical
Clerical
4
4
2
$
264
$
182
$
42
40
40
20
$
2,640
$
1,820
$
420
Retired
unit
exemptiond
Managerial
Technical
Clerical
2
2
1
$
132
$
91
$
21
10
10
5
$
660
$
455
$
105
New
unit
exemptione
Managerial
Technical
Clerical
2
3
1
$
132
$
136
$
21
30
45
15
$
1,980
$
2,040
$
315
Industrial
unit
exemptionf
Managerial
Technical
Clerical
10
10
4
$
661
$
454
$
85
50
50
20
$
3,305
$
2,270
$
425
TOTAL
2,435
$
141,320
a
1998
dollars.
b
Assumes
that
60
certificate
of
representation
forms
will
be
submitted.
c
Assumes
10
new
sources
will
submit
Phase
II
permit
applications
each
year.
d
Assumes
5
units
will
submit
retired
unit
exemptions
each
year.
e
Assumes
15
units
will
submit
new
unit
exemptions
each
year.
f
Assumes
5
units
will
submit
industrial
unit
exemptions
each
year.
42
EXHIBIT
6
ANNUAL
AGENCY/
PERMITTING
AUTHORITY
BURDEN/
COST
ESTIMATES
FOR
PERMITS
Tasks
Burden
Hours
Per
Occurrence
Cost
Per
Sourcea
Total
Burden
(
Hours)
Total
Cost
1.
Review
certificates
of
representation
and
record
informationb
2.
Review
permit
application,
and
issue
draft,
proposed
and
final
permitc
3.
Review
and
approve
or
disapprove
retired,
new,
and
industrial
unit
exemptionsd
1
15
8
$
43
$
642
$
342
60
150
200
$
2,580
$
6,420
$
8,550
TOTAL
410
$
17,550
a
1998
dollars.
b
Assumes
60
sources
submit
a
certificate
of
representation
c
Assumes
10
new
permit
applications
per
year.
d
Assumes
5
retired,
15
new,
and
5
industrial
unit
exemption
submissions
per
year.
6.3.2
Estimate
of
Agency/
Permitting
Authority
Burden
and
Costs
for
Permitting
Exhibit
6
presents
the
burden
and
costs
to
EPA
or
the
permitting
authority
to
review
and
process
permit
information.
The
primary
tasks
performed
by
EPA
are
reviewing
certificates
of
representation,
and
reviewing
industrial
unit
exemption
submissions.
The
primary
tasks
performed
by
the
permitting
authority
are
reviewing
permit
applications,
notifying
the
public,
and
issuing
proposed
and
final
permits,
and
reviewing
new
and
retired
unit
exemptions.
Reviewing
a
certificate
of
representation
and
determining
completeness
notice
is
estimated
to
require
one
hour.
Reviewing
the
permit
application,
notifying
the
public,
and
issuing
proposed
and
final
permits
is
estimated
to
require
15
hours
per
occurrence.
The
Agency's
total
annual
effort
will
be
about
410
hours.
The
total
cost
to
EPA
for
all
permiting
activities
will
be
about
$
17,550.

6.4
Emissions
Monitoring
Recording
and
Reporting
This
section
estimates
the
paperwork
burden
and
cost
of
submitting
monitoring
plans,
43
obtaining
certification
of
each
monitoring
system,
conducting
monitor
quality
assurance
activities,
and
recording
and
reporting
data
from
CEM
systems
(
or
approved
alternatives).

The
legislative
requirements
in
Title
IV
require
all
affected
Phase
I
and
Phase
II
sources
to
install
SO
2
and
NO
x
CEM
systems,
opacity
monitors
(
COMS),
and
flow
monitors
(
or
approved
alternatives).
Data
handling
or
reporting
is
required
by
the
law,
but
not
specified.
Under
the
promulgated
regulations,
however,
EPA
imposes
data
handling,
reporting,
and
recordkeeping
requirements.
The
EPA
requires
that
all
affected
units
required
to
install
CEM
systems
use
a
data
acquisition
and
handling
system
(
DAHS)
to
record
hourly
CEM
and
flow
monitor
data
in
the
EDR
format.
Affected
gas­
and
oil­
fired
units
may
elect
to
use
the
approved
alternative
SO
2
monitoring
method
and
record
fuel
sulfur
analysis
data,
and
then
use
a
DAHS
to
record
and
report
hourly
fuel
flow
values
from
a
fuel
flow
meter
in
the
EDR
format.
In
addition,
peaking
units
that
burn
natural
gas
and/
or
fuel
oil
may
use
an
excepted
method
for
calculating
NO
x
emission
rates.
Under
the
Part
75
revisions,
EPA
will
allow
certain
low
mass
emission
units
to
use
assumed
emission
factors
together
with
operational
data
to
calculate
emissions,
and
will
allow
certain
oil­
and
gas­
fired
units
to
use
an
optional
flow
monitoring
methodology.

Affected
sources
are
required
to
complete
and
submit
a
monitoring
plan
and
obtain
certification
of
each
monitor
(
on
standard
forms)
for
each
affected
unit
at
the
source.
These
plans
and
certifications,
which
are
only
submitted
once,
have
already
been
submitted
for
most
units.
Sources,
however,
may
need
to
submit
revised
plans
or
even
recertify
if
they
change
some
aspect
of
their
existing
plan.
New
units
will
still
need
to
submit
plans
and
certifications
for
the
first
time.
In
addition,
all
affected
units
are
required
to
submit
quarterly
reports
of
their
emissions
data
to
EPA;
these
reports
include
much
of
the
basic
monitoring
plan
data
as
well.

To
develop
this
renewal
ICR,
EPA
took
into
account
both
changes
in
assumptions
about
the
underlying
burdens
and
costs
of
Part
75,
and
the
effect
of
the
rule
revisions.
The
changed
assumptions
about
the
baseline
burdens
and
costs
reflect
EPA's
experience
in
implementing
the
program
as
well
as
information
supplied
from
interested
stakeholders.
For
the
rule
revisions,
many
of
the
revisions
were
assumed
to
be
cost
neutral.
Most
of
those
changes
reflect
rule
clarifications
or
minor
revisions
that
were
requested
by
affected
utilities.
A
few
revisions
were
estimated
to
increase
burdens
and/
or
costs,
while
several
items
were
estimated
to
decrease
burdens
and/
or
costs.
The
items
in
each
of
these
categories
are
identified
in
Table
6­
1.
44
Table
6­
1:
Summary
of
Impacts
of
Major
Rule
Revisions
A.
Rule
Revisions
Assumed
to
Be
Cost/
Burden
Neutral
!
Clarifications
to
certification/
recertification
process
!
Data
validation
clarifications
!
Span/
range
clarifications
!
Backup
monitoring
flexibility
changes
!
Restrictions
on
number
of
RATA
attempts
!
Deletion
of
four
month
RATA
waiting
period
!
Changes
to
the
RATA
test
procedures
!
Direct
electronic
submission
of
quarterly
reports
!
Appendix
H/
protocol
gas
changes
!
New
Appendix
I
optional
flow
monitoring
method
!
Gas
sampling
procedures
for
Acid
Rain
units
combusting
gaseous
fuel
other
than
natural
gas
!
Option
for
electronic
signature
!
Diluent
cap
provisions
!
Complex
stack
provisions
!
Petition
process
clarifications
!
Partial
operating
hour
reporting
!
QA/
QC
plan
clarifications
B.
Rule
Revisions
Assumed
to
Increase
Costs/
Burdens*

!
DAHS
software
changes
!
Moisture
monitoring
quality
assurance
!
Flow­
to­
load
test
for
flow
monitors
!
Flow­
to­
load
test
for
fuel
flowmeters
(
optional)

C.
Rule
Revisions
Assumed
to
Decrease
Costs/
Burdens
!
RATA
grace
periods
!
RATA
flexibility
for
gas­
fired
SO
2
CEMS
units
!
Reduced
flow
monitor
RATA
requirements
!
Use
of
QA
operating
quarters
rather
than
calendar
quarters
!
Calculation
procedures
for
units
with
low
mass
emissions
!
Reduced
Appendix
D
fuel
sampling
!
Reduced
Appendix
D
flowmeter
testing
!
Elimination
of
sampling
for
CO
2
missing
data
!
Deferred
unit
reporting
changes
!
Elimination
of
reporting
for
missing
data
causes/
cures
*
In
addition
to
the
increase
in
burden
caused
directly
by
the
rule,
the
respondent
burden
will
increase
slightly
in
the
first
year
following
the
rule
revisions
due
to
the
additional
time
necessary
to
review
the
rule
and
debug
software.

To
assess
how
the
rule
revisions
affect
the
respondents'
burdens
and
costs,
EPA
analyzed
45
existing
data
reported
by
the
affected
units
to
classify
and
characterize
the
affected
population.
The
result
of
this
analysis
characterizes
the
total
number
of
reporting
units
into
the
following
model
categories
(
units
that
will
be
able
to
take
advantage
of
the
low
mass
emitter
excepted
methodology
have
been
subtracted
from
the
numbers
below):

!
Model
A
(
units
with
SO
2,
flow,
NO
x,
and
CO
2
CEMS):
1070
total
units.

!
Model
B
(
units
with
opacity
CEMS
as
a
result
of
Title
IV):
475
total
units.
(
Note:
these
units
also
are
classified
under
other
models
for
SO
2,
NO
x,
and
CO
2
requirements.)

!
Model
C
(
oil­
fired
units
with
Appendix
D
for
SO
2
and
CEMS
for
NO
x/
CO
2):
39
total
units
with
an
estimated
103
fuel
flowmeters.

!
Model
D
(
gas­
fired
units
with
Appendix
D
for
SO
2
and
CEMS
for
NO
x/
CO
2):
377
total
units
with
an
estimated
1073
fuel
flowmeters.

!
Model
E
(
oil­
fired
units
using
both
Appendix
D
and
E):
35
total
units
with
an
estimated
61
fuel
flowmeters.

!
Model
F
(
gas­
fired
units
using
both
Appendix
D
and
E):
90
total
units
with
an
estimated
216
fuel
flowmeters.

!
Model
G
(
units
with
moisture
monitors
necessary
for
moisture
correction):
107
total
units.
(
Note:
These
units
are
also
classified
under
other
models
for
SO
2,
NO
x,
and
CO
2
requirements.)

These
estimates
were
derived
from
data
reported
to
EPA
by
the
affected
sources.
The
analyses
of
data
reported
to
EPA
by
the
affected
sources
were
also
used
to
develop
information
on:
units
with
fewer
than
168
operating
hours
on
a
quarterly
basis;
units
requiring
semi­
annual
RATAs;
average
operational
hours
in
which
oil
is
burned;
and
units
combusting
gaseous
fuel
other
than
natural
gas.
All
of
this
information
was
used
to
develop
estimates
of
the
number
of
respondents
that
are
expected
to
be
affected
by
various
elements
of
the
rule
revisions.

To
estimate
the
burden
and/
or
cost
of
each
incidence
of
the
various
rule
revisions,
EPA
had
available
prior
estimates
of
the
costs
of
various
activities,
estimates
provided
by
affected
utilities
in
comments
to
the
Agency,
cost
estimates
provided
by
vendors,
testing
companies,
and
utilities,
and
estimates
based
on
the
Agency's
experience
in
implementing
the
program.
In
addition,
the
hourly
labor
rates
for
managerial,
technical
and
clerical
staff
reflect
the
labor
rates
used
in
the
existing
ICR
but
updated
to
1998
dollars
using
the
Employment
Cost
Index,
consistent
with
Agency
ICR
guidance.

The
following
sections
6.4.1,
6.4.2,
6.4.4,
and
6.4.5
indicate
the
respondent
burdens
and
costs
of
Part
75
implementation.
Section
6.4.3
discusses
the
Agency
burdens
and
costs.

6.4.1
Estimating
Respondent
Burden
The
primary
tasks
performed
by
owners
and
operators
of
affected
units
are
(
1)
reviewing
the
regulations,
forms
and
instructions,
(
2)
responding
to
EPA
generated
error
messages,
(
3)
reprogramming
a
DAHS
and
debugging
the
software,
(
4)
completing
and
submitting
monitoring
46
plans
for
each
unit
at
the
source,
(
5)
performing
appropriate
tests
and
providing
test
results
to
certify
each
monitor,
(
6)
performing
quality
assurance
testing
and
maintenance
upon
monitors,
(
7)
assuring
the
quality
of
emissions
data,
preparing
quarterly
reports
of
emissions
data,
and
submitting
reports
to
EPA;
and
(
8)
fuel
sampling.

(
i)
Regulatory
Review.
EPA
estimates
that
the
time
to
review
instructions
and
requirements
should
be
24
manager
hours
and
24
technician
hours
per
year,
per
source,
in
1999.
This
increase
reflects
the
cost
of
familiarization
with
the
rule
revisions
and
the
new
EDR
version
2.1.
The
estimate
decreases
after
the
first
year
to
be
consistent
with
the
labor
estimates
used
in
the
previous
ICR
for
years
1997
and
1998
(
4
manager
hours
and
4
technician
hours
for
both
2000
and
2001).

(
ii)
Response
to
Error
Messages.
The
EPA
provides
feedback
to
sources
so
that
suspected
errors
in
submissions
by
sources
are
noted
and
corrected.
With
the
release
of
the
MDC
software,
EPA
expects
the
burdens
for
this
activity
to
decrease
over
time.
Thus,
for
1999,
this
ICR
uses
the
same
burden
estimates
as
were
used
for
the
1997/
1998
period
(
4
manager
hours
and
8
technical
hours
per
reporting
unit
per
year),
but
then
decreases
those
hours
to
2
manager
and
6
technical
hours
for
the
years
2000
and
2001.
In
addition,
this
activity
should
be
inapplicable
for
the
simplified
reporting
required
of
low
mass
emissions
units,
and,
therefore,
the
total
number
of
respondents
for
this
activity
excludes
those
units.

(
iii)
DAHS
Upgrade
and
Debugging.
Each
source
must
purchase
(
or
create)
and
install
computer
software
designed
to
implement
the
electronic
data
reporting
(
EDR)
formats
required
under
the
Acid
Rain
Program.
Because
of
the
rule
revisions,
the
existing
software
will
have
to
be
upgraded.
The
costs
of
the
upgrade
are
discussed
in
Section
6.4.2,
below.
The
Agency
estimates
that
sources
will
incur
8
manager
and
16
technical
hours
in
1999
to
coordinate
the
purchase
and
installation
of
the
upgraded
software.
In
addition,
consistent
with
the
prior
ICR,
EPA
estimates
that
each
source
will
have
some
burdens
for
debugging
the
software.
Consistent
with
the
previous
ICR,
EPA
assumes
a
relatively
high
burden
in
the
first
year
of
implementing
the
new,
upgraded
software
followed
by
only
a
minor
amount
of
burden
in
the
second
and
third
years
(
see
line
4
of
Exhibit
7).
Sources
that
have
only
low
mass
emissions
units
will
not
be
impacted
by
these
requirements
and
are
excluded
from
the
total
number
of
respondents
for
these
line
items
in
Exhibit
7.

(
iv)
Monitoring
Plans.
Consistent
with
the
existing
ICR,
completing
and
submitting
monitoring
plans
is
estimated
to
require
an
average
of
about
20
hours
per
source
initially.
All
firsttime
monitoring
plan
submissions
will
be
received
prior
to
the
time
period
covered
in
this
revised
ICR,
except
for
new
units.
Thus,
consistent
with
the
existing
ICR,
EPA
is
assuming
that
initial
monitoring
plans
were
all
prepared
prior
to
the
1999­
2001
period.
The
burden
associated
with
revising
the
monitoring
plan
is
included
in
the
time
for
preparing
and
submitting
each
quarterly
emissions
report.

(
v)
Monitor
Certification.
In
the
previous
ICR,
EPA
estimated
that
performing
tests
to
certify
or
recertify
each
monitor
and
submitting
the
test
results
would
require
hiring
a
contractor
for
47
about
7
days
at
only
a
negligible
direct
labor
burden
to
affected
sources.
Based
on
the
information
gathered
as
part
of
the
rule
revisions,
EPA
has
modified
these
assumptions
to
include
labor
burdens
for
this
activity
and
reduce
the
contractor
costs.
Because
only
recertifications
are
included
in
the
estimated
activities
for
1999­
2001,
the
Agency
estimates
a
labor
burden
of
50
hours
and
a
contractor
cost
of
$
3,400
per
respondent.
The
cost
and
burden
figures
exclude
the
costs
and
burdens
associated
with
conducting
a
RATA
as
part
of
the
recertification
process
because
those
costs
are
incorporated
within
the
annual
QA
costs
for
previously
certified
monitoring
systems.

(
vi)
Quality
Assurance.
Quality
assurance
(
QA)
testing
and
maintenance
upon
monitoring
systems
is
the
largest
burden
item
under
the
Acid
Rain
CEM
Program.
Those
requirements
generally
include
daily,
quarterly
and
annual
QA
requirements,
depending
on
the
monitoring
approach
being
used.
For
reporting
units
that
use
a
full
set
of
CEMS
(
SO
2,
flow,
NO
x
and
CO
2),
the
Agency
has
developed
a
per
unit
labor
burden
based
primarily
on
information
gathered
from
affected
sources.
For
units
that
also
are
required
to
install
and
maintain
a
continuous
opacity
monitoring
system
(
COMS)
as
a
result
of
Part
75,
additional
labor
burdens
apply.
For
units
that
rely
on
Appendix
D
excepted
methods
for
SO
2
but
use
a
NO
x
and
CO
2
CEMS,
reduced
labor
burden
estimates
apply
because
the
quality
assurance
activities
for
the
excepted
methods
are
less
than
for
a
CEMS.
The
labor
burdens
for
these
excepted
methods
were
derived
primarily
from
cost
estimates
provided
by
a
group
of
affected
utilities
(
see
Docket
A­
97­
35,
Item
II­
D­
48).
For
units
that
rely
on
the
excepted
methods
under
both
Appendix
D
and
E
(
i.
e.,
units
without
CEMS),
the
burden
estimates
are
reduced
further
because
no
CEMS
QA
is
required.
Finally,
for
the
relatively
small
number
of
units
that
require
moisture
correction,
labor
burdens
for
moisture
monitoring
QA
activities
have
been
added
based
on
information
supplied
by
an
affected
utility
(
see
Docket
A­
97­
35,
Item
II­
D­
94).
Using
the
data
discussed
above,
EPA
estimates
that
the
average
respondent
(
using
a
weighted
average
for
the
units
that
fall
under
Models
A­
G)
will
require
approximately
500
labor
hours
to
meet
the
QA
requirements
of
Part
75.
Consistent
with
the
existing
ICR,
this
labor
is
expected
to
be
almost
entirely
technician
labor.

(
vii)
Quarterly
Reports.
Tasks
performed
by
utilities
in
preparing
quarterly
reports
include:
(
1)
assuring
the
quality
of
the
data,
(
2)
preparing
the
quarterly
report,
(
3)
revising
the
monitoring
plan,
if
necessary,
(
4)
preparation
of
hard
copy
documentation
accompanying
the
quarterly
reports,
and
managerial
review.
The
EPA
estimates
that,
taking
into
account
the
rule
revisions,
the
requirements
to
assure
data
quality,
prepare
quarterly
reports
of
emissions,
revise
monitoring
plans
where
appropriate,
and
submit
these
reports
will
require
on
average
about
204
hours
per
year
for
each
unit
(
except
16
hours
per
year
for
low
mass
emissions
units).

Exhibit
7
summarizes
the
annual
respondent
burdens.

6.4.2
Estimating
Respondent
Costs
Exhibit
7
summarizes
the
annual
respondent
costs.
The
following
discussion
describes
how
those
costs
were
derived.

(
i)
Estimating
Labor
Costs
48
In
estimation
of
labor
costs,
EPA
used
the
following
amounts:
$
66.05
per
hour
for
managers
and
$
45.44
per
hour
for
technicians.
As
noted
above,
these
rates
were
derived
by
using
the
rates
from
the
previous
ICR
and
updating
them
with
the
Employment
Cost
Index
to
June
1998.

(
ii)
Estimating
Total
Capital
and
Annual
Operations
and
Maintenance
Costs
Capital/
start­
up
costs
include
the
cost
of
installing
required
CEMS
or
alternatives.
The
Agency
has
also
included
a
cost
for
the
purchase
of
monitoring
equipment.
These
costs
were
covered
in
the
Regulatory
Impact
Analysis
of
the
Final
Acid
Rain
Implementation
Regulations
(
October
19,
1992)
but
were
not
included
in
ICRs
prior
to
the
effective
date
of
the
1995
revisions
to
the
Paperwork
Reduction
Act.
The
Agency
has
developed
these
estimates
based
on
Agency
CEM
cost
models,
comments
from
various
affected
utilities,
and
other
information
gathered
during
the
rulemaking
process
(
see,
for
example,
Docket
A­
97­
35,
Item
IV­
A­
5).
The
cost
estimates
vary
depending
on
how
many
and
what
type
of
monitors
are
required.
A
capital
cost
estimate
is
included
for
each
of
the
Models
A­
G
on
Exhibit
7.

Operation
and
maintenance
costs
(
exclusive
of
labor
costs)
reflect
ongoing
costs
to
a
unit
and
include
both
contractor
costs
for
the
required
recertification,
diagnostic,
and
quality
assurance
(
QA)
testing,
and
other
direct
maintenance­
related
expenses
(
e.
g.,
spare
parts
and
calibration
gases).
These
cost
estimates
have
been
derived
from
EPA
CEM
cost
models,
existing
ICRs,
Agency
staff
experience
under
the
Acid
Rain
Program,
information
gathered
during
development
of
the
Part
75
revisions,
and
supplemental
estimates
provided
by
affected
utilities
and
others
related
to
the
various
cost
items
(
see,
e.
g.,
EPA
Air
Docket
A­
97­
35,
Item
II­
D­
48).
The
total
cost
for
these
items
(
other
than
fuel
sampling)
is
estimated
at
$
30,380
for
a
unit
with
a
full
set
of
CEMS.
Units
using
alternate
methodologies
have
reduced
costs.
The
fuel
sampling
costs
are
presented
as
a
separate
line
item,
and
are
estimated
to
be
$
581,100
per
year,
for
all
units.
Based
on
information
received
from
affected
utilities,
the
Agency
has
included
fuel
sampling
as
an
O&
M
cost
rather
than
a
source
labor
burden
(
see
Docket
A­
97­
35,
Items
IV­
A­
5
and
IV­
G­
3).

Note
that
testing
contractor
costs
for
certification,
recertification
and
annual
RATAs
also
are
presented
as
other
direct
costs
and
are
not
converted
to
equivalent
source
labor
hours.
This
approach
is
consistent
with
the
common
business
practice
for
obtaining
outside
contractors
to
conduct
certification/
recertification
tests
and
annual
relative
accuracy
test
audits.
For
initial
certification,
the
certification
test
costs
are
commonly
bundled
with
equipment
purchase
contracts,
according
to
information
provided
by
a
range
of
CEMS
equipment
vendors.
For
RATAs
that
are
conducted
either
as
part
of
the
annual
quality
assurance
requirements
or
as
part
of
recertification,
industry
contacts
have
indicated
that
RATA
testing
is
usually
performed
under
a
fixed
price
contract
basis,
except
for
travel
costs
that
may
be
billed
on
an
hourly
basis
beyond
the
basic
contract
cost.
For
annual
RATAs,
the
sources
indicated
that
an
annual
contract
between
a
testing
company
and
utility
is
often
used.
One
municipal
utility
representative
indicated
that
the
applicable
municipal
regulations
required
that
outside
contracts
be
on
a
flat
fee,
not
hourly,
basis.

(
iii)
Capital/
Start­
up
vs.
Operating
and
Maintenance
(
O
&
M)
Costs
49
Capital
costs
reflect
one­
time
costs
for
purchase
of
equipment
which
will
be
used
over
a
period
of
years.
Conversely,
operating
and
maintenance
costs
are
those
costs
which
are
incurred
on
an
annual
or
other
scheduled
basis.
For
instance,
costs
associated
with
quality
assurance
activities,
such
as
spare
parts
or
contractor
costs
for
work,
will
be
incurred
on
an
annual
basis.

(
iv)
Annualizing
Capital
Costs
The
capital
costs
of
equipment
were
annualized
over
a
10­
year
period,
with
the
average
estimated
CEM
system
life
based
on
input
from
CEM
vendors.
Costs
were
annualized
at
a
discount
rate
of
seven
percent.
The
annualized
cost
of
the
necessary
DAHS
upgrade
purchase
associated
with
the
rule
revision
is
$
1,658,384
total,
per
year,
for
all
sources.
The
capital
costs
of
purchasing
required
monitoring
equipment
were
also
annualized
at
a
rate
of
7%,
for
a
10
year
period.
The
annualized
cost
of
CEM
systems
and
fuel
flowmeters
is
estimated
to
total
approximately
$
90,400,000
per
year,
for
all
units.
50
EXHIBIT
7
ANNUAL
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
EMISSIONS
REPORTING
Information
Collection
Activity
Hours/
Costs
Per
Respondent
Total
Hours
and
Costs
Respon.

Hours/
Year
Labor
Cost/
Year
Contractor/

O&
M
Cost
Capital/

Startup
Cost
Number
of
Respon.
Total
Hours/
Year
Total
Cost/
Year
1999
2000/

2001
1999
2000/

2001
1999/
2000/

2001
1999/
2000/

2001
1999/
2000/

2001
1999
2000/

2001
1999
2000/

2001
1.
Review
Instructions
and
Requirements
48
8
$
2,676
$
446
$
0
$
0
728
34,944
5,824
$
1,947,953
$
324,659
2.
Respond
to
EPA
Generated
Error
Messages
12
8
$
628
$
405
$
0
$
0
1611
19,332
12,888
$
1,011,257
$
652,036
3.
Reprogram
DAHS
for
EDR
V2.1
24
0
$
1,255
$
0
$
0
$
2,278
700
16,800
0
$
2,473,408
$
1,594,600
4.
DAHS
Debugging
104
16
$
5,056
$
809
$
0
$
0
700
72,800
11,200
$
3,538,864
$
566,636
5.
Recertify
Monitors
50
50
$
3,055
$
3,055
$
3,400
$
0
128
6,400
6,400
$
826,263
$
826,263
6.
Perform
QA
Testing
and
Maintenance
Model
A
530
530
$
25,114
$
25,114
$
30,380
$
71,195
1070
567,100
567,100
$
135,556,909
$
135,556,909
Model
B
171
171
$
7,770
$
7,770
$
288
$
3,560
475
81,225
81,225
$
5,518,664
$
5,518,664
Model
C
395
395
$
18,361
$
18,361
$
17,400
$
29,475
39
15,405
15,405
$
2,544,204
$
2,544,204
Model
D
395
395
$
18,361
$
18,361
$
17,400
$
29,475
377
148,915
148,915
$
24,593,972
$
24,593,972
Model
E
35
35
$
1,693
$
1,693
$
1,800
$
1,424
35
1,225
1,225
$
172,111
$
172,111
Model
F
35
35
$
1,693
$
1,693
$
1,800
$
1,424
90
3,150
3,150
$
442,571
$
442,571
Model
G
0
40
$
0
$
1,818
$
8,000
$
854
107
0
4,280
$
0
$
1,141,861
7.
Assure
Data
Quality,

Prepare
Reports
(
inc.

monitor
plan
update),

Submit
Reports
204
204
$
10,094
$
10,094
$
0
$
0
1787
364,548
364,548
$
18,038,264
$
18,038,264
7a.
LME
Reporting
(
188)
(
188)
($
9,285)
($
9,285)
$
0
$
0
176
(
33,088)
(
33,088)
($
1,634,104)
($
1,634,104)

8.
Annual
Fuel
Sampling
0
0
$
0
$
0
$
581,100
$
0
­­
0
0
$
581,100
$
581,100
TOTAL:
1,298,756
1,189,072
$
195,611,436
$
190,919,746
ANNUAL
AVERAGE:
1,225,633
$
192,483,642
51
6.4.3
Estimating
Agency
Burden
and
Cost
The
tasks
that
will
be
performed
by
EPA
include
processing,
reviewing,
and
evaluating
emissions
data
reports
submitted
by
utilities.
As
in
the
existing
ICR,
EPA
estimates
that
an
average
of
2
hours
will
be
required
to
perform
these
tasks
for
each
quarterly
data
report
submitted
by
an
affected
source.
Assuming
that
affected
sources
will
submit
1787
quarterly
emissions
reports
to
EPA,
the
total
annual
burden
incurred
by
the
Agency
will
be
14,296
hours.
The
total
annual
cost
to
EPA
to
process,
review,
and
evaluate
1787
quarterly
emissions
reports
will
be
$
612,012.
Exhibit
8
summarizes
the
Agency
burden
and
costs
associated
with
emissions
reporting.

EXHIBIT
8
Annual
Agency
Burden/
Cost
Estimates
for
Emissions
Reporting
Tasks
Quarterly
Burden
Hours
Per
Report
Quarterly
Cost
Per
Reporta,
b
Number
of
Reportsc
Total
Burden
Per
Year
(
hours)
(
1999­
2001)
Total
Cost
Process,
review,
and
evaluate
quarterly
report
and
issue
feedback
letter
2
$
85.62
1787
14,296
$
612,012
a
Based
on
an
average
total
compensation
rate
of
$
42.81
per
hour
b
1998
dollars
c
Assumes
1787
emission
data
reports
each
quarter.

6.4.4
Estimating
the
Respondent
Universe
and
Total
Burden
and
Costs
EPA
estimates
that:
(
a)
728
sources
will
review
instructions
and
requirements;
(
b)
700
sources
(
this
number
excludes
sources
with
only
low
mass
emissions
units)
will
reprogram
and
debug
DAHS
computer
software;
(
c)
1787
units
will
submit
quarterly
reports;
and
(
d)
1611
units
will
respond
to
EPA
generated
error
messages
and
perform
QA
testing
and
maintenance
(
units
using
the
low
mass
emitter
methodology
are
excluded
from
these
activities).
In
addition,
EPA
estimates
that
approximately
128
units
will
recertify
per
year.
Exhibit
7
shows
the
total
burden
and
total
cost
based
on
this
respondent
universe.

6.4.5
Bottom
Line
Burden
Hours
and
Cost
Tables
(
i)
Respondent
Tally
52
Exhibit
7
summarizes
the
aggregate
burden
and
cost
estimates
to
respondents
from
January
1999
through
January
2001
for
collections
associated
with
implementation
of
Part
75.

(
ii)
The
Agency
Tally
Exhibit
8
summarizes
the
aggregate
burden
and
cost
estimates
to
EPA
for
collection,
analysis,
and
storage
of
the
data.

(
iii)
Variations
in
the
Annual
Bottom
Line
The
EPA
expects
a
small
variation
in
the
annual
bottom
line,
reflecting
the
reduced
time
in
2000/
2001
to
review
instructions,
reprogram
a
DAHS,
develop
flow­
to­
load
tests
and
debug
computer
software.
The
variation
is
not
expected
to
be
greater
than
25%.

6.5
Auctions
This
part
presents
estimates
of
the
burden
and
costs
to
participants
and
the
Federal
government
associated
with
the
auction
program
.
EPA
has
delegated
the
administration
of
the
auctions
to
the
Chicago
Board
of
Trade
(
CBOT).

Auctions
are
held
only
once
a
year.
No
restrictions
are
placed
on
the
number
of
allowances
for
which
a
participant
may
bid.
Multiple
bids
from
a
given
participant
are
permitted,
but
each
bid
is
treated
individually
and
requires
a
separate
bid
form.
Based
on
the
average
number
of
bids
in
the
six
auctions
to
date,
EPA
estimates
that
220
bids
will
be
received
each
year.

6.5.1
Estimate
of
Respondent
Burden
and
Costs
Exhibit
9
depicts
the
burden
and
costs
to
auction
participants.
Auction
participants
must
complete
and
submit
the
bid
form
along
with
a
certified
check
or
letter
of
credit.
EPA
estimates
that
the
auction
bid
form
takes
approximately
30
minutes
to
prepare,
and
obtaining
a
means
of
payment
takes
approximately
one
hour.
This
estimate
includes
time
allocated
to
research
the
required
information,
fill
out
the
form,
arrange
for
a
certified
check
or
letter
of
credit,
and
send
the
material
to
EPA.
The
burden
and
cost
to
auction
participants
is
estimated
to
be
330
hours
and
$
20,460
per
year
respectively.
53
EXHIBIT
9
ANNUAL
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
AUCTIONS
Collection
Activities
Burden
Hours
Per
Bid
Cost
Per
Bida
Burden
Hours
Per
Year
Cost
Per
Year
1.
Completing
bid
formsb
0.5
$
31
110
$
6,820
2.
Obtaining
means
of
paymentb
1
$
62
220
$
13,640
TOTAL:
1.5
$
93
330
$
20,460
a
Based
on
an
average
rate
of
$
62
per
hour
(
For
costing
purposes,
it
is
assumed
that
80
percent
of
the
total
hours
will
be
Managerial
($
66.05/
hr.)
and
20
percent
will
be
Technical
($
45.44/
hr.).
These
estimates
are
based
on
1998
dollars.
b
The
220
bids
represents
an
average
number
of
bids
per
year
based
on
EPA's
experience
with
the
auction
program.

6.5.2
Estimate
of
Agency
Burden
and
Costs
Exhibit
10
depicts
the
burden
and
cost
to
EPA
for
the
auction
program.
The
CBOT
incurs
most
of
the
burden
and
cost
associated
with
the
auction,
including;
the
handling
of
bids
and
checks,
and
tabulation
of
the
results.
The
burden
and
cost
to
CBOT
is
not
included
in
this
ICR.

Based
on
past
experience,
the
burden
and
cost
to
the
Agency
will
be
about
the
same
each
year.
Setting
up
and
revising
allowance
tracking
system
(
ATS)
accounts
for
auction
participants
is
estimated
to
take
40
hours,
checking
and
announcing
the
auction
results
is
estimated
to
take
60
hours,
and
transferring
allowances
and
proceeds
is
expected
to
require
60
hours
per
year.
As
Exhibit
10
shows,
the
total
burden
to
EPA
for
auction
activities
is
160
hours
at
a
cost
of
$
6,850.

EXHIBIT
10
ANNUAL
AGENCY
BURDEN/
COST
ESTIMATES
FOR
AUCTIONS
Collection
Activities
Burden
Hours
Per
Year
Cost
Per
Yeara
1.
Setup
ATS
accounts
40
$
1,712
2.
Check
and
announce
results
60
$
2,569
54
3.
Transfer
of
allowances
and
proceeds
60
$
2,569
TOTAL:
160
$
6,850
a
1998
dollars.

6.6.
Allowance
Allocation
to
Small
Diesel
Refineries
This
information
collection
activity
involves
the
collection
of
verification
data
for
eligibility
and
participation
in
the
voluntary
small
diesel
refiners
allowance
program.

EPA
is
assuming
that
all
eligible
refineries
and
units
have
already
reviewed
the
final
rule
and
preamble.
For
the
purpose
of
this
analysis,
the
burden
is
distributed
among
the
management,
technical,
and
clerical
levels.

6.6.1.
Estimate
of
Respondent
Burden
and
Costs
EPA's
voluntary
small
diesel
refinery
program
currently
has
19
participating
refineries.
The
labor
burden
and
costs
for
this
collection
are
a
function
of
the
number
of
facilities
that
choose
to
participate.
EPA
is
assuming
that
all
19
refineries
currently
participating
will
be
eligible
and
continue
to
participate
each
year
through
1999.

Exhibit
11
presents
the
annual
burden
and
costs
to
participants
of
applying
for
allowances.

EXHIBIT
11
ANNUAL
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
THE
SMALL
DIESEL
REFINERY
PROGRAMa
Task
Burden
Hours
per
Occurrence
Cost
per
Occurrenceb
Total
Burden
Hoursc
Total
Costs
Annual
Application
for
Allowances
Managerial
Technical
Clerical
.5
1
.5
$
33
$
45
$
11
9.5
19
9.5
$
627
$
855
$
209
Total
2
$
89
38
$
1,691
a
Annual
burden
for
years
1999
and
2000,
the
last
year
of
the
program.
b
1998
dollars.
c
Assumes
19
small
diesel
refineries
apply
each
year.

In
each
year
of
the
program,
an
eligible
refiner
must
maintain
the
monthly
EIA
Form
810'
s,
total
the
desulfurized
diesel
fuel
throughput
for
the
year,
use
the
total
and
the
formula
contained
in
55
the
Act
to
calculate
the
allowance
allocation,
and
certify
the
accuracy
of
the
information
in
an
application
cover
letter
to
EPA.

EPA
expects
19
applications
to
be
submitted
in
1999
and
2000
by
small
diesel
refiners.
Since,
each
application
takes
about
2
hours
to
complete,
the
total
burden
will
be
38
hours
per
year.

6.6.2.
Estimate
of
Agency
Burden
and
Costs
Exhibit
12
presents
the
Agency's
burden
and
costs
for
the
program
annually.

EXHIBIT
12
ANNUAL
AGENCY
BURDEN/
COST
ESTIMATES
FOR
THE
SMALL
DIESEL
REFINERY
PROGRAMa
Task
Burden
Hours
per
Occurrence
Cost
Per
Occurrenceb
Total
Burden
Hoursc
Total
Costs
Review
Annual
Applications
2
$
86
38
$
1,634
a
Annual
burden
for
years
1999
and
2000,
the
last
year
of
the
program.
b
1998
dollars.
c
Assumes
19
small
diesel
refineries
apply
each
year.

EPA
reviews
each
annual
application,
submitted
by
an
eligible
refiner,
and
determines
whether
or
not
the
allowance
calculations
have
been
made
properly.
EPA
then
allocates
allowances
to
the
eligible
refiners
at
the
completion
of
the
annual
review
process.
To
assist
the
refineries,
EPA
also
announces
the
allocations
in
a
Federal
Register
notice.

6.7
The
Opt­
in
Program
This
subsection
describes
projections
for
(
1)
the
number
and
types
of
sources
that
elect
to
participate
in
the
opt­
in
program
from
January
1999
through
January
2002,
(
2)
the
paperwork
burden
hours
for
both
respondents
and
EPA
associated
with
the
program,
and
(
3)
the
total
costs
of
the
tasks
required
by
the
opt­
in
program.

Over
the
three
years
covered
by
this
ICR,
EPA
estimates
that
3
sources
will
opt
in
to
the
program,
all
will
be
operating
sources
and
all
will
join
in
1999.
These
figures
are
based
on
the
number
of
opt­
in
applications
EPA
has
received
over
the
past
three
years.

6.7.1
Respondent
Burden/
Cost
Estimates
for
The
Opt­
in
Program
56
The
tasks
under
this
program
are
divided
into
the
major
categories
of
reporting
­­
permitting,
emissions
monitoring,
and
annual
compliance
certification.
This
section
includes
only
the
burden
for
these
task
categories
for
opt­
in
sources.
Those
affected
sources
covered
by
the
mandatory
requirements
of
the
Acid
Rain
Program
are
covered
in
previous
sections.

A.
Opt­
in
Permit
Applications
EPA
estimates
that
3
opt­
in
sources
will
submit
permit
applications
in
the
first
year
covered
by
this
ICR.
All
will
be
operating
sources.
The
sources
must
select
a
designated
representative,
report
operating
and
fuel
consumption
data
from
past
years,
and
report
the
actual
and
allowable
emissions
rates
for
1985
as
well
as
the
current
allowable
emission
rate.
The
estimated
total
respondent
burden
related
to
opt­
in
permit
applications
is
525
hours,
and
the
estimated
total
respondent
cost
is
$
27,078.
Exhibit
13
presents
the
respondent
burden
and
costs
associated
with
opt­
in
permit
applications
for
1999.

B.
Emissions
Data
Reporting
Emissions
reporting
is
performed
only
by
operating
sources.
The
tasks
for
opt­
in
sources
are
identical
to
other
affected
sources
and
are
listed
in
Exhibit
7.
The
burden
and
costs
for
emissions
reporting
from
opt­
in
sources
are
included
in
the
total
in
Exhibit
7.

C.
Annual
Compliance
Certification
Annual
compliance
certification
is
performed
by
all
opt­
in
sources.
Each
opt­
in
source
is
required
to
submit
an
annual
compliance
certification
report
and
opt­
in
utilization
form.
Additionally,
if
the
source
is
covered
by
a
thermal
energy
compliance
plan,
it
must
submit
a
thermal
energy
compliance
report.
If
an
opt­
in
source
has
reduced
utilization
due
to
energy
conservation
or
improved
unit
efficiency
measures,
it
has
the
option
of
submitting
an
energy
confirmation
and
improved
unit
efficiency
confirmation
report
to
verify
the
savings
and
offset
the
corresponding
reduced
utilization.
To
date
none
of
the
opt­
in
sources
have
verified
energy
conservation
or
improved
unit
efficiency
measures,
so
EPA
is
assuming
no
sources
will
do
so
during
the
three
years
covered
by
this
ICR.
Finally,
EPA
assumes
that
each
opt­
in
source
will
submit
one
optional
allowance
deduction
form,
which
specifies
the
serial
numbered
allowances
for
deduction.

Total
respondent
burden
and
costs
for
annual
compliance
certification
by
opt­
in
sources
are
an
estimated
962
hours
and
$
47,274,
respectively.
Exhibit
14
presents
respondent
burden
and
costs
for
annual
compliance
certification
by
opt­
in
sources.

6.7.2.
Agency
Burden/
Cost
Estimates
for
the
Opt­
in
Program
In
1999­
2002,
the
Agency's
burden
includes;
processing
opt­
in
applications,
processing
quarterly
emissions
reports
(
which
is
included
in
Exhibit
8),
and
reviewing
and
certifying
annual
compliance
reports.
The
Agency's
estimated
total
burden
related
to
the
opt­
in
program
is
308
hours
57
in
1999,
and
65
hours
in
subsequent
years.
The
estimated
total
cost
is
$
13,186
in
1999
and
$
2,782
in
subsequent
years.
Exhibit
15
presents
the
Agency's
burden
and
costs
for
opt­
in
program.
58
EXHIBIT
13
1999
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
OPT­
IN
PERMIT
APPLICATIONS
Tasks
Burden
Hours
per
Occurrence
Cost
per
Occurrencea
Total
Burden
(
hours)
b
Total
Cost
1.
Select
a
designated
representative
Managerial
Technical
Clerical
2.
Prepare
opt­
in
permit
application
Managerial
Technical
Clerical
3.
Prepare
thermal
energy
compliance
planc
Managerial
Technical
Clerical
4.
Complete
withdrawal
notificationd
Managerial
Technical
Clerical
28
3.5
3.5
40
90
10
15
50
5
2
2
1
$
1,849
$
159
$
74
$
2,642
$
4,090
$
212
$
991
$
2,272
$
106
$
132
$
91
$
21
84
10.5
10.5
120
270
30
0
0
0
0
0
0
$
5,547
$
477
$
222
$
7,926
$
12,270
$
636
0
0
0
0
0
0
Total
525
$
27,078
a
1998
dollars.
b
Assumes
3
opt­
in
sources
submit
permit
applications
in
1999.
c
Assumes
no
sources
file
a
thermal
energy
compliance
plan.
d
Assumes
that
sources
that
have
made
the
investment
to
opt­
in
will
not
withdraw.
59
EXHIBIT
14
ANNUAL
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
OPT­
IN
ANNUAL
COMPLIANCE
CERTIFICATION
Tasks
Burden
Hours
Per
Occurrence
Cost
Per
Occurrencea
Total
Burden
(
Hours)
Total
Cost
Review
instructions,
complete,
and
submit
the
following
reports:

1.
Annual
compliance
certification
reportb
Managerial
Technical
Clerical
2.5
4
.5
$
165
$
182
$
11
32.5
52
6.5
$
2,145
$
2,366
$
143
2.
Opt­
in
Utilization
formb
Managerial
Technical
Clerical
8
30
2
$
528
$
1,363
$
42
104
390
26
$
6,864
$
17,719
$
546
3.
Thermal
energy
compliance
report
(
shutdown
opt­
in
sources
and
replacement
units)
c
Managerial
Technical
Clerical
20
40
5
$
1,321
$
1,818
$
106
80
160
20
$
5,284
$
7,272
$
424
4.
Allowance
deduction
form
(
optional)
d
Managerial
Technical
Clerical
5.
Energy
conservation/
Improved
unit
efficiency
confirmation
reporte
Managerial
Technical
Clerical
6.
Excess
emissions
penalty
paymente
Managerial
Technical
Clerical
2
4.5
.5
5
24
1
4
4
1
$
132
$
204
$
11
$
330
$
1,091
$
21
$
264
$
182
$
21
26
58.5
6.5
0
0
0
0
0
0
$
1,716
$
2,652
$
143
0
0
0
0
0
0
TOTAL
962
$
47,274
a
1998
dollars.
b
Assumes
13
opt­
in
sources.
c
Assumes
4
sources
file
reports.
d
Assumes
one
allowance
deduction
form
per
source.
60
e
EPA
assumes
no
sources
will
claim
savings
from
energy
conservation
or
improved
unit
efficiency
or
have
excess
emissions.
61
EXHIBIT
15
ANNUAL
AGENCY
BURDEN/
COSTS
FOR
THE
OPT­
IN
PROGRAM
Task
Burden
Hours
per
Occurrenc
e
Cost
per
Occurrencea
Total
Burden
Hours
Total
Costs
1999
2000­
2001
1999
2000­
2001
1.
Review
certificates
of
representation
and
record
informationb
1
$
43
3
0
$
129
0
2.
Review
permit
application,
issue
proposed
and
final
permit,
and
assign
allowancesb
80
$
3,425
240
0
$
10,275
0
3.
Review
and
process
annual
compliance
certification
submissionsc
2
$
86
26
26
$
1,118
$
1,118
4.
Deduct
allowances
and
send
reconciliation
reportsc
3
$
128
39
39
$
1,664
$
1,664
Total
308
65
$
13,186
$
2,782
a
1998
dollars.
b
Assumes
3
opt­
in
sources
submit
permit
applications
in
1999.
c
Assumes
13
opt­
in
sources
each
year.

6.8
Annual
Compliance
Certification
6.8.1
Respondent
Burden
and
Cost
Estimates
A.
Phase
I
Sources
Annual
compliance
certification
is
performed
by
all
Phase
I
affected
sources
in
the
spring
of
1999
and
2000.
Each
Phase
I
affected
source,
which
includes
any
source
with
compensating
or
substitution
units,
is
required
to
submit
an
annual
compliance
certification
report
for
the
source
and
a
utilization
accounting
form
for
each
Phase
I
affected
unit
at
the
source.
Based
on
the
first
three
years
of
the
program,
EPA
estimates
that
400
units
at
175
sources
will
be
affected
in
1998
and
1999
(
261
Table
1
units
at
110
sources
and
139
substitution
and
compensating
units
at
65
sources).

If
any
unit
is
underutilized
or
is
covered
by
a
reduced
utilization
plan
claiming
shifts
to
sulfur­
free
generators,
then
a
dispatch
system
data
report
must
be
submitted
for
the
dispatch
system
containing
that
unit.
EPA
estimates
that
25
dispatch
systems
will
need
to
submit
the
dispatch
system
data
report
each
year.
62
If
a
unit
has
a
reduced
utilization
plan
covering
energy
conservation
or
improved
unit
efficiency
measures,
it
has
the
option
of
submitting
an
energy
confirmation
and
improved
unit
efficiency
confirmation
report
to
verify
the
savings
and
offset
the
corresponding
reduced
utilization.
EPA
estimates
that
2%
of
the
400
units
will
verify
energy
conservation
or
improved
unit
efficiency
measures.

Affected
units
have
the
option
of
identifying
specific
serial
numbered
allowances
to
be
deducted
by
EPA.
EPA
assumes
that
each
unit
will
submit
one
optional
allowance
deduction
form
each
year.

A
sulfur­
free
generator
that
is
claimed
by
more
than
one
unit
under
reduced
utilization
plans
will
need
to
submit
a
sulfur­
free
generator
apportionment
form.
EPA
estimates
that
about
20
sulfur­
free
generators
will
need
to
submit
this
information.

Substitution
and
compensating
units
in
a
State
with
a
"
State­
enforced
emission
cap"
must
submit
additional
information.
This
information
is
to
be
at
the
operating
company
level.
EPA
expects
a
total
of
eight
operating
companies
located
in
four
different
States
to
submit
this
information.

Total
respondent
burden
for
annual
compliance
certification
by
Phase
I
affected
sources
is
estimated
to
total
21,339
hours,
for
a
total
cost
of
$
1,039,211.
Exhibit
16
presents
respondent
burden
and
costs
for
annual
compliance
certification.

B.
Phase
II
Sources
Beginning
in
the
spring
of
2001,
annual
compliance
certification
must
be
performed
by
all
affected
sources.
Each
affected
source
must
submit
an
annual
compliance
certification
report.
In
addition
to
the
compliance
certification
report,
affected
units
have
the
option
of
identifying
specific
serial
numbered
allowances
to
be
deducted
by
EPA.
EPA
assumes
that
each
unit
will
submit
one
optional
allowance
deduction
form
each
year.
EPA
estimates
that
2,300
units
at
750
sources
will
be
affected
in
Phase
II.

Total
respondent
burden
for
annual
compliance
certification
by
Phase
II
affected
sources
is
estimated
to
total
21,350
hours,
for
a
total
cost
of
$
1,066,600.
Exhibit
16
presents
respondent
burden
and
costs
for
annual
compliance
certification.
63
EXHIBIT
16
ANNUAL
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
ANNUAL
COMPLIANCE
CERTIFICATION
DURING
THE
PERIOD
1999­
2001
Tasks
Burden
Hours
Per
Occurrence
Cost
Per
Occurrencea
Total
Burden
(
Hours)
Total
Cost
1999­
2000
2001
1999­
2000
2001
1.
Annual
compliance
certification
reportb
Managerial
Technical
Clerical
2.5
4
.5
$
165
$
182
$
11
437.5
700
87.5
1875
3000
375
$
28,875
$
31,850
$
1,925
$
123,750
$
136,500
$
8,250
2.
Utilization
Accounting
formc
Managerial
Technical
Clerical
8
30
2
$
528
$
1,363
$
42
3,200
12,000
800
NA
$
211,200
$
545,200
$
16,800
NA
3.
Dispatch
system
data
reportd
Managerial
Technical
Clerical
8
16
2
$
528
$
727
$
42
200
400
50
NA
$
13,200
$
18,175
$
1,050
NA
4.
Sulfur­
free
generator
apportionment
informatione
Managerial
Technical
Clerical
3.5
10
.5
$
231
$
454
$
11
70
200
10
NA
$
4,620
$
9,080
$
220
NA
5.
Allowance
deduction
form
(
optional)
f
Managerial
Technical
Clerical
6.
Energy
conservation/
Improved
unit
efficiency
confirmation
reportg
Managerial
Technical
Clerical
7.
State
enforceable
cap
informationh
Managerial
Technical
Clerical
8.
Excess
emissions
penalty
paymenti
Managerial
Technical
Clerical
2
4.5
.5
5
24
1
2
15
1
4
4
1
$
132
$
204
$
11
$
330
$
1,091
$
21
$
132
$
682
$
21
$
264
$
182
$
21
800
1,800
200
40
192
8
16
120
8
0
0
0
4,600
10,350
1,150
NA
NA
0
0
0
$
52,800
$
81,600
$
4,400
$
2,640
$
8,728
$
168
$
1,056
$
5,456
$
168
$
0
$
0
$
0
$
303,600
$
469,200
$
25,300
NA
NA
$
0
$
0
$
0
TOTAL
21,339
21,350
$
1,039,211
$
1,066,600
a
1998
dollars.
b
Assumes
175
Phase
I
and
750
Phase
II
affected
sources.
c
Assumes
400
Phase
I
and
2,300
Phase
II
affected
units.
d
Assumes
25
dispatch
systems
must
report.
e
Assumes
20
sulfur­
free
generators
must
report
information.
f
Assumes
one
allowance
deduction
form
per
unit.
g
Assumes
2%
of
Phase
I
affected
units
(
8
units)
claim
savings
from
energy
conservation
or
improved
unit
efficiency.
h
Assumes
8
operating
companies
must
report
information.
i
EPA
assumes
that
no
sources
will
have
excess
emissions.
64
6.8.2.
Agency
Burden
and
Cost
Estimates
The
three
primary
tasks
performed
by
the
Agency
during
annual
compliance
certification
are;
reviewing
and
processing
the
annual
form
submissions,
calculating
and
deducting
allowances,
and
sending
out
allowance
deduction
or
reconciliation
reports
to
the
source
designated
representatives.
Based
on
the
estimated
400
Phase
I
and
2,300
Phase
II
affected
units,
EPA
expects
the
annual
Agency
burden
to
total
600
hours,
and
cost
$
25,200
in
1999
and
2000,
and
3,450
hours
and
$
144,900
in
2001.
Exhibit
17
presents
the
Agency's
annual
burden
and
cost
for
annual
compliance
certification.

EXHIBIT
17
ANNUAL
AGENCY
BURDEN/
COSTS
FOR
ANNUAL
COMPLIANCE
CERTIFICATION
FOR
THE
PERIOD
(
1999­
2001)

Task
Burden
Hours
per
Occurrence
Cost
per
Occurrencea
Total
Burden
Hours
Total
Costs
1999­
2000
2001
1999­
2000
2001
1.
Review
and
process
annual
compliance
certification
submissionsb
.5
$
21
200
1,150
$
8,400
$
48,300
2.
Calculate
and
deduct
allowancesb
.5
$
21
200
1,150
$
8,400
$
48,300
3.
Send
allowance
reconciliation
reportsb
.5
$
21
200
1,150
$
8,400
$
48,300
Total
600
3,450
$
25,200
$
144,900
a
1998
dollars.
b
Assumes
400
Phase
I
and
2,300
Phase
II
affected
units
submit
reports.

6.9
NOx
Permitting
This
section
estimates
the
paperwork
burden
and
cost
of
revising
Phase
II
NO
x
averaging
plans.
This
is
the
only
respondent
burden
for
NO
x
permitting
for
the
period
covered
by
this
ICR.
Because
Phase
II
No
x
permits
were
due
January
1,
1998,
most
of
the
burden
and
costs
were
incurred
under
the
previous
ICR.

In
order
to
estimate
the
number
of
expected
submissions,
EPA
estimates
that
10%
of
the
roughly
40
averaging
plans
on
file
will
be
revised
each
year.

6.9.1
Estimate
of
Respondent
Burden
and
Costs
65
Exhibit
18
presents
the
burden
and
costs
to
applicants
for
preparing
and
submitting
a
revised
NO
x
averaging
plan.

For
each
emissions
averaging
plan,
EPA
estimates
that
the
applicant
will
require
about
10
hours:
50
percent
managerial
labor,
40
percent
technical
labor,
and
10
percent
clerical
labor.
The
total
respondent
burden
for
NO
x
permitting,
as
shown
in
Exhibit
18,
is
estimated
to
be
40
hours
each
year.
The
costs
associated
with
NO
x
permitting
are
estimated
at
$
2,132
per
year.

EXHIBIT
18
RESPONDENT
BURDEN/
COST
ESTIMATES
FOR
NOx
PERMITTING
Tasks
Burden
Hours
per
occurrence
Cost
per
Occurrencea
Total
Burden
Hours
Total
Cost
1.
Prepare
emissions
averaging
plan
revisionb
Managerial
Technical
Clerical
5
4
1
$
330
$
182
$
21
20
16
4
$
1,320
$
728
$
84
Total
40
$
2,132
a
1998
dollars.
b
Assumes
4
respondents
revise
emissions
averaging
plans.

6.9.2.
Estimate
of
Agency/
Permitting
Authority
Burden
and
Costs
for
NOx
Exhibit
19
presents
the
paperwork
burden
and
costs
to
EPA
or
the
permitting
authority
for
NO
x
permitting.
The
total
annual
burden
and
cost
for
revising
NO
x
averaging
plans
is
estimated
at
40
hours
and
$
1,608,
respectively.

The
tasks
involved
in
reviewing
applications
will
include
reviewing
forms
for
completeness
and
revising
the
averaging
plans.
66
EXHIBIT
19
AGENCY
BURDEN/
COST
ESTIMATES
FOR
NO
x
PERMITTING
Tasks
Burden
Hours
Per
Occurrence
Cost
Per
Occurrencea
Total
Burden
Hours
Total
Cost
1.
Revise
NO
x
averaging
plansb
10
$
428
40
$
1,712
a
1998
dollars.
b
Assumes
4
emissions
averaging
plan
revisions
are
submitted
each
year.

6.10
Summary
of
Burden
Hours
and
Costs
Exhibit
20
summarizes
the
aggregate
burden
and
cost
estimates
to
respondents
from
January
1999
through
January
2002
for
collections
associated
with
allowance
transfers,
energy
conservation
and
renewable
energy
allowances,
permits,
emissions
reporting,
auctions,
small
diesel
refinery
allowances,
the
opt­
in
program,
annual
compliance
certifications,
and
NO
x
permitting.
Exhibit
21
summarizes
the
aggregate
burden
and
cost
estimates
to
EPA
and
permitting
authorities
for
these
collections.

6.11
Reasons
for
Change
in
Burden
This
ICR
renewal
reflects
a
few
differences
from
the
previous
ICR.
This
section
discusses
the
changes
in
burden
since
the
last
clearance.

Overall,
the
estimated
annual
burden
in
1996
from
the
last
clearance
was
2,839,120
hours.
This
ICR
estimates
the
annual
burden
in
1999
will
be
1,330,327
hours,
which
decreases
the
burden
by
1,508,793
hours.
The
reasons
for
this
burden
decrease
are
explained
below.

Some
of
the
change
in
burden
for
this
collection
is
due
to
adjustments.
Adjustments
stem
from
actions
outside
the
Agency's
control.
It
includes
changes
to
the
number
of
responses
and
the
time
it
takes
to
respond
to
a
particular
activity.
The
adjustments
and
corresponding
change
in
burden
are
as
follows.

!
The
annual
number
of
new
allowance
account
applications
decreased
from
75
to
65
and
allowance
transfer
submissions
dropped
from
2,125
to
1,500.
This
changed
the
annual
burden
hours
for
allowance
transfer
activities
from
6,500
to
4,950.
67
!
The
annual
number
of
conservation
and
renewable
energy
reserve
applications
dropped
from
40
to
20
and
the
number
of
applicants
using
EPA's
conservation
verification
protocol
fell
from
4
to
1.
This
change
decreased
the
burden
from
1,968
hours
to
952
hours.

!
Permitting
activities
were
estimated
to
require
6,046
burden
hours
in
1996.
The
estimated
annual
burden
hours
for
permitting
under
this
ICR
are
2,435.
This
burden
change
reflects
some
rule
requirements
that
were
not
applicable
before,
including
industrial
unit
exemptions
are
now
covered
by
this
collection,
while
other
tasks,
such
as
the
submission
of
Phase
I
permit
modifications,
submission
of
repowering
information,
and
defining
dispatch
systems,
are
no
longer
covered
by
this
collection.

!
The
estimated
number
of
auction
bids
received
each
year
increased
from
200
to
220.
This
slightly
increased
the
burden
for
annual
auctions
from
300
hours
to
330
hours.

!
The
estimated
number
of
sources
applying
to
opt­
in
to
the
Acid
Rain
Program
was
reduced
from
9
to
3
and
the
burden
for
emission
data
reporting
was
shifted
from
the
opt­
in
section
to
the
emissions
reporting
section
.
This
results
in
the
estimated
burden
dropping
from
37,097
hours
in
1996
to
1,487
hours
in
1999.

!
The
burden
for
reporting
annual
compliance
certification
information
is
estimated
to
decrease
slightly
from
22,439
hours
to
21,339
due
to
fewer
sulfur­
free
generator
forms
and
fewer
units
claiming
energy
conservation
savings.

!
Because
the
previous
collection
covered
the
submission
of
all
NO
x
compliance
plans,
while
this
collection
covers
only
revisions
to
NO
x
averaging
plans,
the
burden
dropped
from
30,786
hours
to
40
hours.

!
This
ICR
uses
updated
information
to
classify
and
categorize
the
types
of
units
affected
by
Part
75
and
what
type
of
monitoring
they
have
used
to
comply
with
Part
75.
The
number
of
sources
has
been
increased
from
727
to
728
and
the
number
of
units
has
been
increased
from
1600
to
1787
to
reflect
the
current
information
in
the
Agency's
data
system
used
to
track
Part
75
monitoring
information.
Note,
however,
that
the
inclusion
of
the
low
mass
emissions
unit
provisions
generally
eliminate
any
increase
in
burdens
or
costs
that
would
be
expected
to
occur
as
a
result
of
these
increases
in
total
affected
sources
and
units.

Burdens
and
costs
have
been
refined
further
by
the
division
of
respondents
into
different
categories
for
purposes
of
estimating
the
burdens
and
costs
associated
with
QA
activities.
The
Agency
developed
seven
models
to
better
explain
the
distribution
of
various
monitoring
methods.
See
section
6.4,
above,
for
a
description
of
each
model.
Also,
as
discussed
in
Section
6.4,
above,
EPA
has
modified
several
assumptions
about
the
labor
burdens
associated
with
various
activities
based
on
experience
in
implementing
the
program
and
input
from
various
interested
parties.
In
the
first
Acid
Rain
Program
ICR
(
1992),
the
burdens
and
costs
associated
with
these
activities
were
not
estimated.
Under
the
1995
ICR,
EPA
included
an
initial
estimate
of
average
burden
for
QA
activities
of
over
1360
hours
per
year,
per
unit.
At
that
time,
the
68
Agency
had
insufficient
information
to
incorporate
different
estimates
for
different
types
of
monitoring
configurations
and
did
not
have
detailed
information
from
which
to
estimate
total
QA­
related
burdens
and
costs.
Based
on
information
from
affected
sources,
external
studies,
and
the
ability
of
this
ICR
to
distinguish
between
units
using
CEMS
and
units
using
alternative
monitoring
methodologies,
this
number
has
been
reduced
to
an
average
of
approximately
500
hours
(
see,
e.
g.,
Docket
A­
97­
35,
Item
IV­
A­
5).
The
net
result
of
the
adjustments
to
the
emissions
monitoring
burden
is
a
decrease
of
approximately
1,385,000
hours
from
the
previous
ICR.

Other
changes
in
the
burden
are
due
to
rule
changes.
The
rule
revisions
create
substantial
changes
in
many
aspects
of
the
baseline,
although
a
large
part
of
these
changes
are
reflected
in
costs,
not
labor
burdens.
The
rule
revisions
that
create
these
changes
are
summarized
in
Table
6­
1,
above.

The
most
significant
cost
(
but
not
burden)
savings
will
come
from
the
revisions
to
the
flow
monitor
quality
assurance
provisions.
Based
on
data
provided
by
a
group
of
utilities
(
see
Docket
A­
97­
35,
Item
II­
D­
48),
the
Agency
estimates
that
replacing
the
annual
three­
level
RATA
with
a
two­
level
RATA
for
most
units
that
use
a
flow
CEMS,
and
a
one­
level
RATA
for
the
remaining
units
that
use
a
flow
CEMS,
will
create
an
overall
cost
savings
of
approximately
$
3,500,000
per
year
related
to
test
contractor
cost.
In
addition
to
savings
related
to
test
contractor
costs,
units
will
realize
savings
in
that
they
will
not
need
to
perform
RATAs
at
load
levels
inconsistent
with
typical
operating
levels.
Based
on
data
provided
by
the
same
group
of
utilities,
those
savings
are
estimated
at
a
total
of
about
$
25,000,000
per
year.
Because
units
would
be
required
to
perform
a
three­
load
RATA
at
least
once
every
five
years,
the
net
annual
cost
reduction
(
including
both
test
contractor
and
operational
cost
savings)
associated
with
these
revisions
is
estimated
to
be
slightly
more
than
$
29
million.
These
estimates
are
based
on
the
expectation
that
10%
of
the
CEMS
model
units/
stacks
would
be
eligible
for
the
reduction
to
the
one­
level
RATA,
and
the
other
90%
would
be
eligible
for
the
reduction
to
the
two­
level
RATA
four
out
of
every
five
years.

Another
set
of
revisions
that
are
expected
to
create
significant
savings
are
the
fuel
flowmeter
testing
provisions.
These
changes
include
both
changing
the
frequency
of
visual
inspections
from
one
to
three
years,
and
allowing
owners
or
operators
to
use
an
optional
fuel
flow­
to­
load
test
in
place
of
an
annual
flowmeter
accuracy
test.
Note
that
a
flowmeter
accuracy
test
would
still
be
required
every
five
years.
The
net
effect
of
these
changes
would
be
to
realize
some
reduced
labor
burdens,
as
well
as
significant
cost
savings
(
approximately
$
5­
5.5
million)
associated
with
meters
that
would
otherwise
be
removed
for
annual
calibration/
accuracy
testing
off­
site.

The
fuel
sampling
revisions
will
allow
oil­
fired
units
to
switch
from
daily
sampling
and
analysis
of
fuel
to
either
weekly
composite
analysis
or
sampling
at
the
same
frequency
as
fuel
shipments
are
received
(
the
conservative
estimate
used
assumes
weekly
shipments).
Based
on
fuel
sampling
and
analysis
costs
provided
by
utilities,
these
revisions
are
estimated
to
reduce
costs
by
over
$
3
million.
In
addition,
the
Agency
also
estimates
that
revisions
to
§
§
75.35
and
75.36
which
would
allow
the
use
of
a
substitute
data
algorithm
instead
of
sampling
procedures
in
certain
circumstances
will
have
a
cost
savings
of
about
$
650,000
annually.
69
There
are
several
other
rule
revisions
that
are
expected
to
result
in
savings.
First,
test
deadlines
will
be
based
on
quarters
with
a
minimum
of
168
operating
hours
rather
than
on
calendar
quarters.
This
revision
will
assist
those
sources
that
have
insignificant
operating
hours
in
certain
calendar
quarters.
Based
on
operating
hour
information
in
the
Agency's
database,
this
revision
will
result
in
a
total
labor
burden
reduction
of
approximately
29,800
per
year
and
cost
savings
of
about
$
945,000
per
year,
for
a
total
savings
of
about
$
2,360,000.

Based
on
a
query
of
the
Agency's
database,
the
Agency
estimates
that
150
units
are
currently
subject
to
the
requirement
that
deferred
units
report
their
status
as
shutdown.
The
rule
revision
eliminating
this
requirement
will
reduce
the
labor
burden
per
unit
by
2
hours
per
year,
for
a
total
savings
of
about
300
hours,
or
$
16,725.

The
Agency
estimates
that
exempting
gas­
fired
units
with
SO
2
monitors
from
SO
2
RATAs
will
create
an
overall
reduction
in
cost
of
$
200,000,
including
an
estimated
reduction
in
labor
hours
of
500
per
year
and
approximately
$
175,000
savings
in
contractor
costs
per
year.
This
estimate
is
based
on
a
query
of
the
Agency's
database
indicating
that
there
are
20
units
that
will
be
able
to
take
advantage
of
this
provision.

Under
the
grace
periods
for
RATA
and
linearity
tests,
EPA
estimates
that
about
20
units
per
year
will
not
need
to
incur
costs
to
startup
solely
to
perform
linearity
or
RATA
tests.
The
estimated
savings
per
affected
unit
is
$
75,000,
based
on
cost
estimates
from
a
group
of
utilities.
The
total
savings
per
year
is
therefore
estimated
at
$
1,500,000.

Based
on
cost
estimates
provided
by
a
group
of
utilities,
the
Agency
believes
that
the
rule
revision
eliminating
the
requirement
to
report
causes
and
cures
for
missing
data
will
result
in
a
burden
savings
of
about
45,000
hours,
or
$
2,065,000
per
year.

Finally,
the
Agency
estimates
that
176
units
will
qualify
for
the
revisions
allowing
the
use
of
assumed,
rather
than
measured,
values
for
units
with
low
mass
emissions.
The
Agency
estimates
that
28
sources
will
consist
of
only
low
mass
emissions
units.
The
estimated
reduction
in
burden
for
reporting
for
each
affected
unit
is
188
hours
(
divided
between
manager
and
technical
hours).
The
total
burden
decrease
for
reporting
is
therefore
approximately
33,090
hours
per
year,
or
$
1,634,000.
Low
mass
emissions
units
will
also
have
decreased
quality
assurance
costs.
The
annual
anticipated
burden
decrease
is
about
29,750
hours
and
$
1,350,000
in
contractor
costs.
Because
of
the
simplified
reporting
for
these
units,
EPA
also
believes
that
these
units
will
not
incur
burdens
associated
with
responding
to
EPA
generated
error
messages.
This
assumption
further
reduces
the
burden
by
1,645
hours
per
year.
Finally,
because
of
the
simplified
reporting,
sources
that
consist
only
of
low
mass
emissions
units
will
not
incur
burdens
or
costs
associated
with
reprogramming
and
debugging
DAHS
software.
This
change
will
result
in
decreased
labor
burdens
of
approximately
1490
hours
per
year,
and
decreased
annualized
capital
costs
of
approximately
$
63,750.
The
total
estimated
dollar
savings
for
the
rule
change
is
therefore
approximately
$
4,625,000
per
year.
70
Among
the
rule
revisions,
there
are
a
few
provisions
that
EPA
believes
will
lead
to
burden
and
cost
increases.
The
most
significant
is
the
necessary
reprogramming
of
the
DAHS.
The
Agency
believes
that
the
costs
to
implement
the
rule
revisions
in
the
DAHS
systems
will
consist
of
some
inhouse
labor
hours,
but
that
the
majority
of
the
cost
will
be
the
capital
cost
for
each
source
to
purchase
upgraded
software.
See
the
line
item
in
Exhibit
7
for
an
estimate
of
the
effect
of
this
activity.
EPA
estimates
that,
on
average,
a
source
will
incur
about
24
hours
of
in­
plant
labor
and
$
16,000
in
other
costs
to
reprogram
the
DAHS.
The
in­
plant
labor
is
a
burden
that
will
only
occur
in
1999,
and
totals
about
17,500
hours,
or
$
913,960.
The
capital
costs
of
the
DAHS
purchase
are
estimated
at
$
16,000,
and
were
annualized
over
a
ten
year
period,
for
a
per
year
total
cost
of
$
1,658,384
for
all
sources.

The
flow/
load
ratio
test
for
flow
CEMS
will
also
lead
to
an
increased
burden,
although
these
burdens
are
significantly
more
than
offset
by
the
reduced
burdens
and
costs
associated
with
the
revisions
to
the
flow
RATA
requirements.
The
reduced
flow
RATA
requirements
would
not
be
promulgated
without
the
new
flow­
to­
load
test.
The
Agency
estimates
a
total
cost
of
about
$
3,200,000
in
1999
to
develop
appropriate
software
for
conducting
the
flow/
load
test.
Beginning
in
2000/
2001,
the
estimated
total
burden
for
conducting
the
test,
reviewing
test
results
and
performing
extra
RATAs
due
to
test
failure
is
estimated
to
be
approximately
21,500
labor
hours
and
$
162,000
in
contractor
costs
for
all
sources,
for
a
total
per
year
beginning
of
2000
of
about
$
1,226,600.

EPA
estimates
a
total
burden
increase
to
implement
the
new
moisture
monitor
QA
provisions
of
about
4,300
hours
per
year,
and
operation
and
maintenance
costs
of
$
860,000
per
year.
Based
on
analyses
of
data
reported
by
affected
sources,
EPA
estimates
that
approximately
107
units/
stacks
would
be
affected
by
the
addition
of
those
new
QA
procedures.
Note
that
this
cost
also
will
not
be
incurred
until
2000,
as
this
revision
is
not
effective
in
1999.

EPA
has
also
refined
the
estimate
in
the
previous
ICR
of
time
necessary
to
review
new
rule
requirements.
The
previous
Part
75
ICR
assumed
that
there
would
be
a
per
source
burden
of
6
managerial
hours
and
10
technician
hours
per
year
in
the
first
year
(
1996)
to
review
the
instructions
and
requirements
of
the
rule,
while
those
hours
decreased
to
4
manager
and
4
technical
hours
in
the
second
and
third
years
(
1997
and
1998).
Based
on
the
scope
of
the
Part
75
revisions,
EPA
believes
that
the
burden
for
1999,
the
first
year
the
rules
would
be
in
effect,
should
be
24
manager
hours
and
24
technical
hours
per
year.
The
burden
after
the
first
year
would
be
reduced
consistent
with
the
burden
estimates
for
this
activity
in
years
1997
and
1998
under
the
existing
ICR
(
4
manager
and
4
technical
hours
per
year
per
source
for
2000/
2001).
The
total
increased
burden
due
to
the
rule
revisions
is
therefore
approximately
23,300
hours
(
1999
only).
The
Agency
also
estimates
a
burden
increase
due
to
a
greater
demand
for
software
debugging
in
the
first
year
of
implementing
upgraded
DAHS
software.
Based
on
the
existing
ICR,
EPA
estimates
a
total
burden
increase
of
about
61,800
hours
in
1999.
In
2000
and
2001,
the
burden
is
estimated
consistent
with
the
existing
ICR
(
16
hours
per
source).

The
Part
75
rule
revisions
would
have
the
overall
effect
of
significantly
reducing
the
costs
as
well
as
burdens
of
the
Acid
Rain
CEM
Program.
Without
the
Part
75
revisions,
implementation
71
costs
would
be
estimated
at
$
236,631,210,
per
year,
for
the
1999­
2001
period.
With
the
rule
revisions,
the
annual
average
estimated
costs
are
$
192,483,642.
For
labor
burden,
the
annual
average
without
the
rule
revisions
would
be
1,303,901
hours;
with
the
rule
revisions,
the
estimated
annual
average
is
1,225,633
hours,
or
a
decrease
of
78,268
hours..

6.12
Burden
Statement
The
respondent
reporting
burden
for
this
collection
of
information
is
estimated
to
be
1,330,327
hours
in
1999,
1,220,183
hours
in
2000,
and
1,220,156
hours
in
2001.
The
burden
to
EPA
is
estimated
to
be
17,477
hours
in
1999,
17,174
hours
in
2000,
and
19,986
hours
in
2001.
Send
comments
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
to
the
Director,
Regulatory
Information
Division;
U.
S.
Environmental
Protection
Agency
(
2137);
401
M
Street,
SW,
Washington,
D.
C.
20460;
and
to
the
Office
of
information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
Street,
NW,
Washington,
DC
20503,
marked
"
Attention:
Desk
Officer
for
EPA."
Include
the
OMB
control
number
(
2060­
0258)
in
any
correspondence.
72
EXHIBIT
21
AGGREGATE
ANNUAL
RESPONDENT
BURDEN
AND
COST
OF
COLLECTIONS
Program
Total
Burden
(
Hours)
Total
Costsa
1999
2000
2001
1999
2000
2001
1.
Allowance
transfers
4,950
4,950
4,950
$
260,685
$
260,685
$
260,685
2.
Energy
conservation
and
renewable
energy
allowances
952
492
492
$
45,446
$
23,486
$
23,486
3.
Permits
2,435
2,435
2,435
$
141,320
$
141,320
$
141,320
4.
Emissions
reporting
1,298,756
1,189,072
1,189,072
$
195,611,436
$
190,919,746
$
190,919,746
5.
Auctions
330
330
330
$
20,460
$
20,460
$
20,460
6.
Small
diesel
refinery
allowances
38
38
0
$
1,691
$
1,691
$
0
7.
Opt­
inb
1,487
1,487
1,487
$
74,352
$
74,352
$
74,352
8.
Annual
compliance
certification
21,339
21,339
21,350
$
1,039,211
$
1,039,211
$
1,066,600
9.
NO
x
permitting
40
40
40
$
2,132
$
2,132
$
2,132
TOTAL
1,330,327
1,220,183
1,220,156
$
197,196,733
$
192,483,083
$
192,508,781
a
1998
dollars.

b
Includes
permitting
and
annual
compliance
certification
burdens
for
opt­
in
sources.
73
EXHIBIT
22
AGGREGATE
ANNUAL
AGENCY
BURDEN
AND
COST
OF
COLLECTIONS
Program
Total
Burden
(
Hours)
Total
Costsa
1999
2000
2001
1999
2000
2001
1.
Allowance
transfers
1,500
1,500
1,500
$
64,500
$
64,500
$
64,500
2.
Energy
conservation
and
renewable
energy
allowances
125
65
65
$
5,354
$
2,784
$
2,784
3.
Permits
410
410
410
$
17,550
$
17,550
$
17,550
4.
Emissions
reporting
5.
Auctions
6.
Small
diesel
refinery
allowances
7.
Opt­
in
8.
Annual
compliance
certification
9.
NO
x
permitting
10.
Operation
&
Maintenance
of
data
systemsb
14,296
160
38
308
600
40
NA
14,296
160
38
65
600
40
NA
14,296
160
0
65
3,450
40
NA
$
612,012
$
6,850
$
1,634
$
13,186
$
25,200
$
1,712
$
150,000
$
612,012
$
6,850
$
1,634
$
2,782
$
25,200
$
1,712
$
150,000
$
612,012
$
6,850
$
0
$
2,782
$
144,900
$
1,712
$
150,000
TOTAL
17,477
17,174
19,986
$
897,998
$
885,024
$
1,003,090
a
1998
dollars.
74
b
Average
annual
operation
and
maintenance
costs
associated
with
running
electronic
data
systems
are
assumed
to
be
incurred
by
an
EPA
contractor.
Therefore,
EPA
will
not
incur
any
labor
burden
for
these
activities.
Appendix
A
:
Data
Items
Required
to
be
Reported
Electronically
Under
the
Recordkeeping
and
Reporting
Sections
of
Part
75
This
Appendix
contains
the
Electronic
Data
Reporting
(
EDR)
Formats
indicating
the
data
elements
that
must
be
recorded
and
reported
electronically
under
the
following
sections
of
the
rule:

!
Monitoring
Plan
Requirements
(
§
75.53)

!
General
Recordkeeping
Requirements
(
§
75.57)

!
Recordkeeping
For
Special
Situations
(
§
75.58)

!
Quality
Assurance
Recordkeeping
(
§
75.59)

!
Certification
Application
(
§
75.63)

!
Quarterly
Reports
(
§
75.64)
75
Appendix
B:
Other
Data
Items
Required
Under
the
Recordkeeping
and
Reporting
Sections
of
Part
75
In
addition
to
the
data
collected
electronically
in
the
EDR,
the
following
additional
recordkeeping
and/
or
reporting
is
required
under
Part
75.
Items
which
must
be
recorded
and
kept
on­
site,
rather
than
reported/
submitted
to
the
Agency,
are
marked
with
an
asterisk.

Monitoring
Plan
Requirements
(
§
75.53):

!
Information,
including
identification
of
the
test
strategy;
protocol
for
the
relative
accuracy
test
audit;
other
relevant
test
information;
calibration
gas
levels
for
the
calibration
error
test
and
linearity
check;
calculations
for
determining
maximum
potential
concentration,
maximum
expected
concentration,
maximum
potential
flow
rate,
maximum
potential
NO
x
emission
rate,
and
span;
and
apportionment
strategies
!
Description
of
site
locations
for
each
monitoring
component
in
the
continuous
emission
or
opacity
monitoring
systems
!
A
data
flow
diagram
denoting
the
complete
information
handling
path
from
output
signals
of
continuous
emission
monitoring
system
components
to
final
reports
!
A
schematic
diagram
identifying
entire
gas
handling
system
from
boiler
to
stack
for
all
affected
units
!
Stack
and
duct
engineering
diagrams
showing
the
dimensions
and
location
of
fans,
turning
vanes,
air
preheaters,
monitor
components,
probes,
reference
method
sampling
ports,
and
other
equipment
that
affects
the
monitoring
system
location,
performance,
or
quality
control
checks
General
Recordkeeping
Requirements
(
§
75.57):

!
Causes
of
any
missing
data
periods
and
the
actions
taken
to
cure
such
causes*

Recordkeeping
For
Special
Situations
(
§
75.58):

For
units
with
add­
on
SO2
or
NOx
emission
controls
following
the
provisions
of
§
75.34(
a)(
1)
or
(
a)(
2):

!
Parametric
data
which
demonstrate
the
proper
operation
of
the
add­
on
emission
controls*

!
A
flag
indicating
that
the
add­
on
emission
controls
are
operating
properly*

Quality
Assurance
Recordkeeping
(
§
75.59):

For
calibration
error
tests
of
continuous
emission
or
flow
monitoring
systems:
76
!
Certification
from
the
cylinder
gas
vendor
or
CEMS
vendor
that
calibration
gas,
as
defined
in
the
applicable
sections
of
Part
75,
was
used
to
conduct
calibration
error
testing*

!
Description
of
any
adjustments,
corrective
actions,
or
maintenance
following
test*

For
daily
interference
checks
of
flow
monitoring
systems:

!
Description
of
any
adjustments,
corrective
actions,
or
maintenance
following
test*

For
relative
accuracy
test
audits:

!
Description
of
any
adjustments,
corrective
actions,
or
maintenance
following
test*

!
The
flow
polynomial
equation
used
to
linearize
the
flow
monitor
and
the
numerical
values
of
the
polynomial
coefficients
of
that
equation*

Other
required
quality
assurance
test
data
items:

!
Hardcopy
quality
assurance
relative
accuracy
test
reports,
certification
reports,
or
recertification
reports
for
pollutant
concentration
or
stack
flow
CEMS
including
test
results,
printouts,
reference
method
data,
equations,
calibration
gas
certificates,
laboratory
calibrations,
test
protocols,
diagrams,
and
names
of
personnel
involved
in
the
testing.
For
each
relative
accuracy
test
audit,
supporting
information
sufficient
to
substantiate
compliance
with
all
applicable
sections
and
appendices
in
this
Part.*
(
not
reported
unless
requested)

!
An
indication
of
which
data
have
been
excluded
from
the
quarterly
span
and
range
evaluations
of
the
SO
2
and
NO
X
monitors
and
the
reasons
for
excluding
the
data*

Excepted
monitoring
systems
for
gas­
fired
and
oil­
fired
units:

!
Test
results
for
each
transmitter
or
transducer
accuracy
test
for
an
orifice­,
nozzle­,
or
venturi­
type
flowmeter*
(
note:
test
summary
is
reported
electronically)

!
For
units
with
add­
on
SO
2
and
NO
x
emission
controls
following
the
provisions
of
§
75.34(
a)(
1)
or
(
a)(
2):
a
list
of
operating
parameters
for
the
add­
on
emission
controls,
and
the
range
of
each
operating
parameter
in
the
list
that
indicates
the
add­
on
emission
controls
are
properly
operating
Notifications
(
§
75.61):

The
DR
shall
submit
notification
for
the
following
events
on
an
as­
applicable
basis:

!
Initial
certification
tests,
recertification
tests,
new
unit/
stack,
new
flue
gas
desulfurization
system
operation,
unit
shutdown/
recommencement,
use
of
backup
fuels
for
Appendix
E
procedures,
combustion
of
emergency
fuels
under
Appendix
D
or
E.
77
Certification
Application
(
§
75.63):

Each
application
for
initial
certification
or
recertification
shall
contain
the
following
information,
as
applicable:

!
Certification
or
recertification
application
form
(
EPA
form
7610­
14)

!
The
results
of
the
test(
s)
required
by
§
75.20,
including
the
type
of
test
conducted,
testing
date,
information
required
by
§
75.56
or
§
75.59,
as
applicable,
and
the
results
of
any
failed
tests
that
affect
data
validation
!
Any
changed
portions
of
the
hardcopy
monitoring
plan
information
required
under
§
§
75.53(
c)
and
(
d),
or
§
§
75.53(
e)
and
(
f),
as
applicable
!
Designated
representative
signature
!
If
the
owner
or
operator
is
applying
to
use
the
optional
low
mass
emissions
excepted
methodology
in
§
75.19(
c)
in
lieu
of
a
certified
monitoring
system,
a
statement
that
the
unit
burns
only
natural
gas
or
fuel
oil
and
a
list
of
the
fuels
that
are
burned
or
a
statement
that
the
unit
is
projected
to
burn
only
natural
gas
or
fuel
oil
and
a
list
of
the
fuels
that
are
projected
to
be
burned;
a
statement
that
the
unit
meets
the
applicability
requirements
in
§
§
75.19(
a)
and
(
b);
and
any
unit
historical
actual
and
projected
emissions
data
and
calculated
emissions
data
demonstrating
that
the
affected
unit
qualifies
as
a
low
mass
emissions
unit
under
§
§
75.19(
a)
and
(
b)

Quarterly
Reports
(
§
75.64):

!
Compliance
certification
(
in
hardcopy
or
optionally
in
electronic
format)

Opacity
Reports
(
§
75.65):

!
Excess
emission
of
opacity
(
reported
to
applicable
State
or
local
air
pollution
control
agency)

Quality
Assurance/
Quality
Control
Program
(
Section
1
of
Appendix
B
to
Part
75)

!
Written
QA/
QC
plan
that
describes
in
detail
(
or
that
refers
to
separate
documents
containing)
complete,
step­
by­
step
procedures
and
operations
For
preventative
maintenance,
quality
assurance
testing,
fuel
sampling
and
sample
retention*

!
Maintenance
records
of
all
testing,
maintenance,
and
repair
activities,
including:
date,
time,
and
description
of
any
testing,
adjustment,
repair,
replacement,
or
preventive
maintenance
action*
78
Appendix
C:
Acid
Rain
Program
Forms
and
Instructions
