
1
MEMORANDUM
Date:
October
5,
2004
To:
316b
Rulemaking
Record
From:
Anne
Jones
and
Ian
Cadillac,
ERG,
Inc.
Subject:
Detailed
Methodology
and
Results
for
Oil
and
Gas
Production
Platforms
(
Non­
CBI)

EPA
determined
that
the
only
new
platforms
likely
to
be
affected
by
the
proposed
316(
b)
Phase
III
regulations
are
those
in
the
deepwater
Gulf
and
Alaska
(
U.
S.
EPA,
2004a).
EPA
further
determined
that
a
new
Alaska
platform
was
not
well
represented
by
survey
data,
which
captured
data
only
for
a
very
old
platform
that
is
at
the
end
of
its
productive
life;
the
newest
Cook
Inlet
platform
employs
a
strikingly
different
construction
technology
and
may
have
an
entirely
different
production
profile
(
U.
S.
2004a).
We
therefore
focused
our
modeling
efforts
on
the
deepwater
Gulf
of
Mexico.

According
to
survey
data
provided
by
the
316(
b)
survey
of
oil
and
gas
facilities,
only
one
existing
surveyed
deepwater
structure
met
316(
b)
regulatory
criteria
(
deepwater
structures
are
not
typically
traditional
fixed
platforms;
for
convenience,
however,
the
term
"
platform"
is
used
to
describe
deepwater
structures
of
all
types).
The
surveyed
platform
became
the
basis
for
representing
new
deepwater
Gulf
platforms.
ERG
turned
to
our
Deepwater
Gulf
Model,
developed
during
the
course
of
our
analysis
of
EPA's
effluent
guidelines
for
synthetic
drilling
fluids
(
U.
S.
EPA,
2000)
as
the
starting
point
to
assess
impacts
on
new
deepwater
Gulf
projects.

1.
Overview
of
the
Deepwater
Gulf
Model
and
Modifications
Made
for
the
Purposes
of
this
Analysis
The
Deepwater
Gulf
Model
simulates
the
costs
and
petroleum
production
dynamics
expected
at
the
platform
or
project
level
in
the
development
and
operation
of
a
deepwater
Gulf
oil
and
gas
project.
Data
to
define
a
project
and
its
petroleum
reservoir
are
entered
into
the
model.
Then,
through
a
series
of
internal
algorithms,
the
model
calculates
the
economic
and
engineering
characteristics
of
the
project.

The
model
is
structured
to
be
flexible.
It
is
capable
of
modeling
projects
that
are
dynamic,
with
development
occurring
over
a
multiyear
drilling
period,
under
a
specific,
assumed,
drilling
plan.
Furthermore,
inputs
for
a
wide
variety
of
variables
that
define
the
development
and
production
project
can
be
use­
specified.
These
inputs
include,
in
addition
to
drilling
schedule,
operating
costs,
initial
petroleum
production
decline
rates,
tax
rate
schedules,
and
wellhead
prices.

The
model
calculates
cost
and
production
performance
for
each
year
of
the
projects'
estimated
lifetimes.
Additional
outputs
from
the
model
include
total
production
volume,
project
revenues
and
both
present
value
and
nondiscounted
summary
statistics.
Annual
values
and
summary
statistics
are
used
to
evaluate
both
the
project
and
the
effects
of
impingement
and
entrainment
(
I&
E)
control
options.

ERG
made
a
few
modifications
to
the
model
for
two
reasons.
First,
only
one
model
project
needed
to
be
developed
(
rather
than
a
large
number
of
modeled
projects
as
was
done
for
the
synthetic
drilling
fluids
2
analysis).
ERG
dispensed
with
some
of
the
flexibility
within
the
model
and
hardwired
survey
data
and
incremental
costs
directly
into
the
main
modeling
spreadsheet.
Incremental
costs
were
simply
set
to
zero
for
a
baseline
case
in
a
separate,
but
otherwise
identical,
spreadsheet
file.
Second,
EPA
wrote
the
survey
questions
prior
to
deciding
to
use
the
Deepwater
Gulf
Model,
so
certain
information
on
baseline
capital
expenditures
were
not
disaggregated
into
well
drilling
costs
versus
other
capital
expenditures.
No
drilling
schedule
was
provided,
and
decline
rates
were
not
provided
(
although
the
respondent
did
provide
actual
and
projected
production
rates
for
10
years).

Thus
ERG
used
the
cumulative
capital
expenditures
as
of
year
end
2002
and
assumed
that
these
expenditures
(
minus
the
year­
by­
year
expenditures
shown
for
1998
through
2002
in
the
survey)
were
made
during
the
construction
phase
of
the
project
development
over
a
period
of
several
years
(
defined
by
when
development
drilling
is
identified
by
MMS
data
(
MMS,
2004b)
and
proceeding
until
the
platform
install
date
(
MMS,
2003),
split
evenly
over
the
intervening
years.
ERG
made
the
simplifying
assumption
that
the
cumulative
capital
expenditures
were
in
earlier
year
dollars
and
used
the
Producer
Price
Index
to
convert
these
dollars
to
2003
dollars.
Moving
the
cumulative
outlay
into
the
early
time
frame
of
construction
could
slightly
overstate
the
present
value
of
these
costs
within
the
new
model.
Converting
the
dollars
to
2003
dollars
may
overstate
realistic
baseline
construction
costs
of
similar
new
deepwater
projects,
since
the
2003
PPI
for
the
oil
and
gas
extraction
industry
took
a
sudden,
large,
and
uncharacteristic
leap
upwards
in
that
year.
Most
years
from
the
mid
1990s
through
2002,
the
index
indicated
prices
not
changing
radically
from
year
to
year,
however,
the
index
went
from
107.0
in
2002
to
160.1
in
2003.
ERG
would
not
expect
this
inflation
factor
to
hold
over
the
course
of
several
years,
so
believes
that
the
construction
costs
so
developed
may
be
fairly
high
relative
to
what
new
projects
may
actually
cost
to
construct,
although
these
costs
are
within
the
range
of
construction
costs
seen
for
deepwater
Gulf
projects
(
U.
S.
EPA,
2000).
This
calculation
can
be
seen
in
the
316b
Platform
Impact
Model
(
DCN
7­
4038;
CBI),
which
is
the
modified
version
of
the
Deepwater
Gulf
Model
specifically
created
for
the
analysis
of
impacts
from
316(
b)
requirements
on
a
deepwater
structure.

There
is
no
issue
with
disaggregating
drilling
costs,
since
the
actual
and
projected
capital
expenditures
are
provided
on
a
year­
by­
year
basis.
Large
outlays,
combined
with
increases
in
production
in
a
given
year
probably
represent
the
addition
of
development
wells.
As
long
as
these
costs
and
production
effects
are
hardwired
into
the
model
it
is
of
no
consequence
that
ERG
does
not
assume
a
particular
drilling
schedule
or
well
drilling
cost.

A
survey­
specified
decline
rate
is
not
available,
but
is
not
necessary
to
the
analysis.
ERG
used
the
survey
data
for
5
years
of
actual
production
and
5
years
of
projected
production
of
oil,
gas,
and
water.
ERG
projected
beyond
the
5
years
of
projected
production
by
fitting
an
average
decline
rate
per
year
for
oil
and
gas
that
best
explained
the
declines
seen
in
the
5
years
of
projections
according
to
the
survey.
ERG
did
the
same
for
the
increases
in
water
production
as
well.
Information
on
estimated
total
technically
recoverable
reserves
from
the
survey
was
used
to
ensure
that
ERG's
projections
beyond
those
provided
by
the
respondent
did
not
exceed
the
technically
recoverable
amounts,
and
seemed
reasonable
with
respect
to
the
respondent's
estimate
of
economically
recoverable
reserves.
These
calculations
can
be
seen
in
the
spreadsheet
named
"
Platform
Model
Input
Calculations"
(
DCN
7­
4040;
CBI)

1.1
Model
Phases
The
project
life
of
a
deepwater
Gulf
operation
producing
oil
and/
or
gas
is
divided
into
five
phases:
1)
from
lease
bid
to
the
start
of
exploration,
2)
from
the
start
of
exploration
to
the
start
of
delineation,
3)
3
from
the
start
of
delineation
to
the
start
of
development,
4)
from
the
start
of
development
to
the
start
of
production,
and
5)
production.

For
new
operations,
ERG
evaluates
operations
at
the
beginning
of
phase
1­
lease
bid
through
all
5
phases.
The
project
modeled
is
assumed
to
operate
as
long
as
it
generates
positive
operating
cash
flow
for
up
to
30
years
(
further
projections
add
little
additional
to
present
value
calculations).
Algorithms
within
the
model
evaluate
project
economics
annually,
and
the
project
is
shut
down
when
operating
cash
flow
goes
negative.

1.2
Economic
Overview
of
the
Model
The
economic
characteristics
of
the
model
phases
are
quite
different.
Phases
one
through
four
generate
cash
outflows;
no
revenues
are
earned
during
those
periods.
The
fifth
phase,
production,
typically
generates
net
cash
inflows.
During
this
phase,
the
project
continues
to
operate
as
long
as
operating
cash
inflows
exceed
nondiscretionary
cash
expenses.

The
model
deals
with
a
number
of
basic
cash
flows
(
or
resource
transfers)
in
the
development
and
production
phases.
The
basic
cash
flows
are
as
follows:

Leasing
Phase:
Lease
bid­
cost
of
acquiring
rights
to
explore
and
develop
a
tract
of
land
Exploration
Phase:
G&
G
costs­
geological
and
geophysical
expenses
incurred
prior
to
drilling
exploration
well
costs­
cost
of
drilling
and
exploration
well
Incremental
drilling
costs­
additional
cost
of
drilling
due
to
new
regulations
concerning
drilling
waste
Delineation
Phase:
Delineation
well
costs­
costs
of
drilling
a
delineation
well
Incremental
drilling
cost­
additional
costs
of
drilling
due
to
regulations
concerning
drilling
waste
Development
Phase:
Development
well
costs
 
cost
of
drilling
a
development
well
Cost
of
building
and
installing
a
petroleum
production
platform
Infrastructure
costs
 
costs
of
production
equipment
installed
on
the
platform
(
in
this
particular
model,
these
two
costs
are
not
disaggregated)
Production
Phase:
Revenue
from
oil
and
gas
production
 
production
levels
multiplied
by
assumed
wellhead
price.
O&
M
costs
 
costs
of
operating
and
maintaining
the
well.
These
costs
are
divided
into
fixed
and
variable
components.

2
STEP
BY
STEP
DESCRIPTION
OF
THE
MODEL
This
section
presents
a
sequential
overview
of
how
the
model
operates.
Due
to
the
way
the
model
was
constructed,
the
first
part
of
the
model
starts
with
the
production
phase
and
ends
with
the
shut
down
of
the
project
either
after
30
years
of
production
or
when
the
project
becomes
unprofitable.

The
following
discussion
is
based
on
the
computer
printout
in
Figure
1.
Identification
numbers
for
specific
lines
are
given
in
the
left­
hand
margin.
All
dollar
values
(
e.
g.,
costs
and
revenues)
are
expressed
in
thousands
of
2003
dollars.
All
numbers
in
this
exhibit
are
for
example
purposes
only.
None
are
associated
with
actual
survey
responses
to
protect
confidential
business
information
(
CBI).
The
model
examined
here
4
is
dynamic
and
used
for
modeling
a
number
of
circumstances.
As
a
result,
some
lines
are
not
appropriate
for
modeling
the
proposed
316b
rule
impacts
and
are
therefore
not
used.
These
lines
are
noted
in
the
discussion
below
and
on
the
attached
model
printout.

Line
1
identifies
the
operation
and
the
I&
E
option
being
analyzed.

Line
2
is
the
real
discount
rate,
i.
e.,
the
cost
of
capital.
This
value
is
used
throughout
the
model
to
discount
future
cash
inflows,
and
production
so
that
they
can
be
summarized
in
present
value
terms.
The
rate
used
is
7
percent,
as
OMB
guidance
suggests
(
OMB,
2003).

Line
3
is
the
inflation
rate.
This
parameter
is
used
to
reduce
the
value
of
the
deductions
for
depreciation
and
cost­
basis
depletion
in
future
years.
The
rate
used
is
3
percent.

Lines
4
and
5
contain
information
relevant
to
the
calculation
of
project
taxes.
The
flag
in
Line
4
indicates
whether
the
operation
modeled
is
an
integrated
(
major)
or
independent
company.
Majors
must
calculate
depletion
on
a
cost
basis,
while
independents
may
choose
to
do
so
on
either
a
cost
or
a
percentage
basis.

Major
and
independent
operators
also
differ
with
respect
to
the
treatment
of
capital
investments
in
calculating
taxable
income.
Independents
may
expense
100
percent
of
their
"
intangible
drilling
costs
(
IDCs),
while
majors
may
expense
only
70
percent.
The
expensing
of
these
costs
reduces
taxable
income
in
the
year
in
which
they
are
expensed
and
may
provide
a
significant
tax
shelter.

It
is
assumed
that
the
taxpayer
(
oil
company)
elects
to
expense
IDCs
in
the
year
in
which
they
are
incurred.
IDCs
are
estimated,
on
average,
to
represent
60
percent
of
the
costs
of
production
wells
and
their
infrastructure
(
ERG,
2000).
Hence,
independents
may
expense
60
percent
of
total
production
well
drilling
costs
(
1.00
x
0.60),
and
majors
may
expense
42
percent
(
0.70
x
0.60).
The
percentage
of
drilling
costs
that
are
eligible
for
expensing
is
giving
in
Line
5.
5
Table
1
Exogenous
Variables
Provided
to
EPA
Economic
Model
Parameter
Source
of
Data
Lease
cost
Geological
and
geophysical
expense
Real
discount
rate
Inflation
rate
Years
between
lease
sale
and
exploration
Percent
of
cost
considered
expensible
intangible
drilling
costs
Federal
corporate
tax
rate
Drilling
cost
per
exploratory
well
Years
between
start
of
exploration
and
delineation
Number
of
delineation
wells
drilled
Cost
per
delineation
well
Total
platform
cost
Years
between
delineation
and
development
Number
of
development
wells
drilled
Drilling
cost
per
development
well
I&
E
capital
costs
Oil
and
gas
production
decline
rate
Royalty
rate
Depreciation
schedule
Years
between
development
and
production
Oil
production
rates
Gas
production
rate
Wellhead
price
per
barrel
­
oil
Wellhead
price
per
Mcf
­
gas
Total
operating
costs
(
including
cost
of
produced
water
disposal)
Annual
I&
E
control
equipment
operating
cost
MMS,
2004a
U.
S.
EPA,
2000
(
assumption)
OMB,
2003
ERG
assumption
MMS,
2004a,
2004b
ERG
assumption
(
see
also
ERG,
2000).

IRS,
2002
U.
S.
EPA,
2000
MMS,
2004b
MMS,
2004b
U.
S.
EPA,
2000
Survey
data
MMS,
2004b
MMS,
2004b
U.
S.
EPA,
2000
U.
S.
EPA,
2004b
Calculated
using
Survey
data
MMS,
2004a
IRS,
2003
MMS,
2004b
Survey
data
Survey
data
Survey
data
Survey
data
Survey
data
(
used
directly
and
calculated)

U.
S.
EPA,
2004b
Lines
6­
32
relate
to
the
production
phase.
In
the
production
phase
of
the
project,
a
variety
of
financial
and
engineering
variables
interact
to
form
the
project's
economic
history.
Lines
6,
7,
and
8
are
not
used
in
this
model.
Production
figures
from
1998
through
2007
are
taken
directly
from
the
survey
responses
and
hardwired
into
the
model
(
numbers
shown
are
not
actual
survey
data).
Beyond
that
time
frame,
oil
and
gas
decline
rates
and
water
increase
rates
are
calculated
from
the
reported
survey
data.
Thus
Line
9
is
not
used.

Line
10,
the
cost
escalator
is
not
used.

The
royalty
rates
paid
to
the
lessor
of
the
land
(
in
this
case
the
federal
government)
are
provided
in
Lines
11
and
12.
Federal
and
state
corporate
tax
rates
are
listed
in
Lines
13
and
14.
State
taxes
are
assumed
zero,
since
most
oil
and
gas
corporations
locate
headquarters
in
states
without
corporate
taxes.
Lines
15
and
16
provide
the
number
of
years
over
which
depreciation
occurs
and
the
depreciation
schedule
for
capitalized
oil
and
gas
equipment.
State
severance
taxes
are
not
applicable
so
Lines
17
and
18
are
zero.
6
Basic
information
describing
the
production
phase
of
the
project
is
listed
in
lines
19
through
23.
Line
19
is
not
used
in
this
model.
Line
20
gives
the
number
of
years
between
construction
and
production,
and
is
an
input
in
the
spreadsheet
named
"
316bplatform.
wk9".
The
MMS
data
to
construct
the
time
line
on
this
spreadsheet
are
also
shown
on
this
spreadsheet.
Because
the
MMS
data
identify
which
deepwater
project
is
being
modeled,
it
is
being
treated
as
CBI
data.
Lines
21
through
25
are
not
used.

The
wellhead
prices
for
oil
and
gas
are
entered
on
Lines
26
and
27.
These
values
are
as
reported
by
the
respondent
that
were
used
for
their
projection
purposes.
The
prices
shown
are
not
the
actual
survey
prices,
which
are
treated
as
CBI.

Line
28
indicates
the
number
of
days
per
year
that
a
platform
or
project
produces.
ERG
assumes
the
project
operates
continuously.

Line
29
is
not
used.
Annual
operating
costs
are
used
directly
or
are
derived
from
survey
data
but
the
numbers
shown
here
are
not
from
the
survey
.
Lines
30
through
32
are
not
used.

2.2.1
Production
Volume
Calculations
The
next
several
lines
in
the
model
calculate
the
annual
production
volumes
for
oil
and
gas,
based
on
the
production
data
provided
by
the
respondent.
Line
33
is
not
used.
Line
34,
the
total
barrels
of
oil
produced
per
day
is
calculated
as
the
production
for
the
year
reported
by
the
respondent
divided
by
Line
28
(
365
days
per
year).
For
years
after
2007
(
the
last
year
of
actual
or
projected
production
given
in
the
survey)
EPA
calculated
a
decline
rate
per
year
for
oil
and
gas.
These
calculations
are
based
on
the
average
declines
as
shown
in
the
year­
by­
year
projections
provided
by
the
respondent.
As
before,
numbers
used
in
the
example
are
not
those
used
in
the
actual
CBI
model.
MMcf
of
gas
per
day,
Line
40,
is
calculated
in
the
same
manner.
The
annual
oil
and
gas
production
numbers
in
Lines
36
and
41
are
the
estimated
daily
production
numbers
multiplied
by
the
number
of
days
of
production
per
year
(
Line
35).

The
price
per
barrel
is
repeated
in
Line
37
for
convenience
in
cross­
checking
the
gross
revenues
from
oil
production
(
Line
43).
Lines
42
and
44
list
the
wellhead
price
per
Mcf
of
gas
and
gross
revenues
from
gas
production.

2.2.2
Income
Statement
Lines
43
through
75
comprise
an
income
and
cash
flow
statement
that
is
repeated
annually
for
a
30­
year
project
lifetime
(
these
lines
are
repeated
for
years
11­
20
and
years
21­
30,
which
are
not
reproduced.
Since
most
projects
become
uneconomical
during
this
30­
year
time­
frame,
line
66
checks
for
negative
net
cash
flow.
When
cash
flow
is
negative,
ERG
assumes
the
project
shuts
down
and
actual
production,
revenues,
and
cash
flows
are
reset
to
zero
in
lines
67
through
73.
Lines
43
and
44
list
revenues
from
oil
and
gas
productions.
Total
gross
revenues
for
the
year
are
given
in
line
45.
Royalty
payments
(
lines
46
and
47;
see
lines
11
and
12
for
royalty
rates)
are
calculated
on
the
basis
of
gross
revenues.
Lines
48
and
49
are
not
used,
since
no
severance
is
paid
in
the
deepwater
Gulf.

Net
revenues,
line
50,
are
calculated
as:

Net
Revenues
=
Total
Gross
Revenues
­
Royalty
Payments
7
Thus,
for
year
1
of
production
in
the
example
in
Figure
1
(
year
13
of
the
project):

Net
Revenues
=
$
24,125
­
$
1,141
­
$
1,875
=
$
21,109
Operating
costs
are
given
in
Lines
51a
through
52.
Line
51e
lists
the
total
operating
costs
estimated
for
the
platform
itself.
The
total
in
line
51e
includes
incremental
permitting,
monitoring,
fixed,
and
variable
operating
costs
listed
in
the
four
lines
above
(
lines
51a
through
51d
respectively).
Incremental
operating
costs
for
compliance
with
the
316(
b)
regulation
appear
in
line
52.
The
latter
figure
reflects
incremental
costs
due
to
drilling
waste
requirements.

Operating
earnings
(
line
53)
are
defined
as
net
revenues
(
line
50)
minus
total
operating
costs
(
line
51e)
minus
I&
E
control
operating
costs
(
line
52).
For
year
2
of
production
(
year
14
of
the
project):

Operating
Earnings
=
Net
Revenues
­
Operating
Costs
­
I&
E
Control
Operating
Costs
=
$
599,922
­
$
1,223
­
$
45
=
$
598,654
Lines
54
and
55
divides
capital
costs
into
two
categories
for
use
in
calculating
the
project's
taxable
income.
Line
54
contains
the
capital
costs
that
can
be
expensed
(
IDCs,
or
costs
for
drilling
new
wells
are
multiplied
by
the
percentage
in
line
5).
ERG
assumes
that
oil
and
gas
companies
expense
the
maximum
allowable
portion
of
their
capital
costs.
Line
55
contains
the
capital
costs
that
must
be
capitalized,
including
I&
E
control
capital
costs
and
nonexpensible
development
drilling
costs.

The
adjusted
deprecation
allowance
in
line
58
is
calculated
on
the
basis
of
the
capitalized
costs
in
line
55
and
the
accelerated
depreciation
schedule
in
line
16.
Because
the
model's
values
are
given
in
constant
dollars,
this
figure
must
then
be
adjusted
for
inflation,
using
the
rate
in
line
3.
This
adjusted
value
is
taken
as
a
deduction
against
the
taxable
income
associated
with
the
project.

In
the
following
year,
the
adjusted
depreciation
allowance
contains
the
second­
year
effects
from
the
capital
cost
for
the
previous
year
and
any
first­
year
effects
from
the
capital
costs
for
the
second
year
of
the
project's
life.

Line
57,
earnings
before
interest,
taxes
and
oil
depletion
allowance
(
ODA),
is
derived
by
subtracting
expensed
capital
costs
and
depreciation
and
amortization
from
operating
earnings.

The
adjusted
depletion
allowance
(
line
58)
is
a
means
of
treating
annual
oil
and
gas
production
as
a
wasting
asset
for
tax
purposes.
For
major
producers,
the
depletion
allowance
is
calculated
on
a
cost
basis,
while
for
independents,
it
is
calculated
on
a
percentage
basis.

Earnings
before
interest
and
taxes
(
EBIT,
line
57)
is
defined
as
earnings
before
interest
and
ODA
(
line
76)
minus
the
adjusted
oil
depletion
allowance
(
line
58).
The
figure
on
line
57
forms
the
basis
for
calculating
federal
income
taxes
in
line
60
(
Line
61,
state
taxes,
is
zero).
Federal
taxes
are
based
on
the
rate
given
in
line
13.
Earnings
before
interest
and
after
taxes
are
given
in
line
62.

Project
cash
flows
from
operations,
line
63,
are
determined
by
adding
costs
expensed
for
tax
purposes,
depreciation,
and
depletion
back
into
earnings
after
taxes.
8
Whether
or
not
the
project
continues
to
operate
is
determined
on
the
basis
of
operating
earnings
(
line
53).
If
(
net
revenues
­
total
operating
costs
­
I&
E
control
operating
costs)
is
less
than
0,
the
project
is
assumed
to
shut
down.
Under
such
circumstances,
net
cash
flow
from
operations
(
line
63)
will
also
be
0.
The
model
prints
a
"
1"
in
line
66
for
years
in
which
the
project
operates
and
a
"
0"
for
years
in
which
the
project
does
not
operate.

In
the
event
that
the
project
is
shut
down,
certain
variables
must
be
recalculated
to
reflect
that
oil
and
gas
are
no
longer
produced
and
sold.
Lines
67
through
75
restate
production
volumes,
revenues,
and
cash
flow
in
the
even
of
a
shutdown
(
i.
e.,
production
and
revenues
are
set
to
zero
after
the
projects
shuts
down).
The
model
allows
a
negative
tax
to
be
calculated
in
the
shutdown
year
and
continues
to
calculate
depreciation
after
shutdown
because
it
is
assumed
that
the
project
is
part
of
a
larger,
ongoing
company
and
that
such
deductions
can
be
used
to
adjust
taxable
income
from
the
company's
other
operations.

Additional
lines,
not
marked
with
line
numbers,
repeat
lines
33
to
75
and
are
used
to
take
production
cash
flow
out
to
30
years
of
production.
This
completes
the
production
phase
portion
of
the
model.

2.3
Earlier
Phases
The
next
numbered
lines
apply
the
earlier
capital
expenditures.
Lines
76
through
84
are
inputs
for
the
leasing
phase
of
the
model.
The
least
cost,
Line
76,
is
a
user­
specified
input,
the
value
of
which
is
based
on
the
lease
bid
of
the
lease
or
leases
associated
with
the
project
(
from
MMS,
2004a).
In
the
model,
the
lease
bid
is
not
adjusted
to
2003
dollars
because
lease
bids
do
not
appear
to
be
strongly
associated
with
inflationary
spikes,
and
given
the
uncharacteristic
leap
in
the
PPI
index
for
2003,
ERG
did
not
see
that
the
lease
bid
should
be
adjusted
with
the
PPI
index.
Instead,
ERG
investigated
recent
lease
bids
to
see
if
an
unadjusted
lease
bid
would
be
reasonably
representative.
The
lease
bid
associated
with
the
project
modeled
is
at
the
higher
end
of
the
more
recent
lease
bids
seen
in
the
MMS
data
(
MMS,
2004a).
Overall,
lease
bid
costs
are
a
small
fraction
of
total
lease
development
costs.
ERG
inflated
the
remaining
lease
development
costs
to
2003
dollars,
which
may
have
already
led
to
an
overstatement
of
baseline
development
costs
given
the
unusually
high
PPI
for
the
oil
and
gas
extraction
industry
associated
with
2003.

Line
77
represents
the
costs
of
geological
and
geophysical
(
G&
G)
investigation
of
the
site
as
a
percentage
of
lease
cost.
The
value
shown
in
line
77
is
based
on
information
from
U.
S.
EPA
(
2000).
The
total
leasehold
cast,
Line
78,
is
the
sum
of
the
lease
bid
and
G&
G
expenses.
The
total
leasehold
costs
is
a
cash
outflow
in
Year
0
of
the
project;
the
value
is
therefore
the
present
value
of
the
leasehold
cost.
The
leasehold
cost
forms
the
basis
for
the
depletion
allowance
as
calculated
on
a
cost
basis
for
major
integrated
producers.

Lines
79
through
81
present
data
for
wells
assumed
to
be
drilled
for
exploration
and
delineation.
Line
82
takes
timing
assumption
inputs
and
places
the
time
between
lease
sale
and
start
of
production
here.
This
value
is
taken
from
data
presented
in
the
Summary
of
Data
report.
Lines
83
and
84
are
not
used
in
this
model.

Lines
85
through
94
calculate
the
exploration
costs
for
the
project
based
on
numbers
of
exploratory
wells
drilled
(
MMS,
2004b)
and
assumed
costs
of
drilling
(
from
U.
S.
EPA,
2000).
Line
85
presents
the
numbers
of
years
between
lease
sale
and
start
of
exploration.
This
timing
assumption
was
derived
using
MMS
(
2004b).
Line
86
is
the
baseline
cost
of
drilling
an
exploratory
well,
which
was
taken
9
from
U.
S.
EPA
(
2000).
Lines
87
and
88
are
not
used.
Line
89
is
the
number
of
exploratory
wells
drilled.
One
exploratory
well
per
find
is
assumed.
All
other
exploratory
wells
(
as
identified
in
MMS,
2004b)
are
assumed
delineation
wells.
Line
90
adds
lines
86
and
87
for
a
total
exploratory
well
cost.
Line
91
assumes
in
this
model
that
all
exploration
wells
at
this
project
are
successful
(
alternative
assumptions
are
not
used
in
this
model).
Line
92
is
not
used.
Lines
93
and
94
split
the
expensed
and
capitalized
portions
on
the
bases
of
line
5
(
percent
costs
expensed),
which
varies
depending
on
whether
the
project
is
owned
by
a
major
or
an
independent.

Once
the
various
exploration
costs
and
cash
flows
have
been
calculated,
they
are
put
in
present
value
terms
as
of
the
lease
year.
For
all
Gulf
of
Mexico
deepwater
projects,
exploration
costs
are
incurred
in
Year
0
plus
number
of
years
between
lease
sale
and
star
of
exploration.
In
this
case,
exploration
expenses
start
in
Year
1.

If
an
exploration
well
discovers
petroleum,
delineation
wells
may
be
drilled
to
confirm
the
size
and
extent
of
the
reservoir.
One
year
is
assumed
to
pass
between
the
start
of
exploration
and
the
start
of
delineation
(
Line
95;
MMS
[
2004b]
provides
timing
assumptions).
In
this
model
four
delineation
wells
(
based
on
data
obtained
as
presented
in
MMS,
2004b)
are
drilled,
Line
96,
each
costing
the
same
as
an
exploratory
well
(
Line
97).
Line
98
is
not
used.
One
platform
is
used
for
this
project
in
Line
99.

The
delineation
costs
(
Line
100)
assume
the
number
of
delineation
wells
are
evenly
divided
over
the
number
of
years
between
delineation
and
development;
in
this
case
4
wells
have
been
divided
over
4
years.
Lines
101
and
102
split
out
the
expensed
and
capitalized
portion
of
these
costs
in
each
year.

Once
the
various
delineation
costs
and
cash
flows
have
been
calculated,
they
are
put
in
present
value
terms
using
a
half­
year
convention.

During
the
development
phase,
the
infrastructure
required
to
extract
oil
reserves
from
a
site
is
constructed.
Development
drilling
is
also
conducted
to
increase
production.
Line
103
shows
the
number
of
years
between
delineation
and
construction
(
based
on
data
presented
in
MMS
[
2004b
and
2003]).
The
costs
of
constructing
platforms,
including
the
costs
of
production
equipment,
are
entered
on
Line
104.
Line
105
contains
the
capital
costs
associated
with
the
proposed
316(
b)
rule.

Since
the
development
phase
of
an
oil
and
gas
project
may
overlap
with
the
production
phase,
the
model
is
designed
to
incorporate
the
annual
costs
of
development
and
increase
in
production
from
new
wells
into
estimates
of
total
annual
expenses
and
revenues.
These
costs
and
revenues
are
accounted
for
in
the
production
portion
of
the
model
described
earlier.
Because
production
figures
are
hardwired,
the
calculation
of
production
increases
based
on
wells
drilled
is
not
used.
The
number
of
wells
drilled
during
the
construction
phase
is
shown
in
Line
106.
Line
107
is
not
used
in
this
model
(
considered
unnecessary
detail,
since
drilling
costs
and
construction
costs
do
not
have
to
be
clearly
disaggregated).
Line
108
is
not
used
in
this
model.
Drilling
costs
per
development
well
are
shown
in
Lines
109
and
110.

Lines
111
through
122
calculate
the
costs
incurred
each
year
from
the
drilling
of
production
wells
and
the
construction
of
production
equipment.
The
number
of
years
over
which
construction
occurs
is
provided
by
the
timing
assumption
in
Line
20.
In
this
case
the
timing
assumption
is
2
years
(
with
the
costs
incurred
beginning
in
the
second
year),
thus
the
costs
are
spread
over
one
year,
as
shown.
(
Lines
111
and
112
repeat
the
information
from
lines
109
and
110.)
Line
113
adds
in
the
option
costs
for
any
wells
drilled
after
completion
of
the
construction
phase.
Line
114
starts
the
clock
for
when
production
begins,
after
the
10
construction
phase
ends.
Line
115
brings
in
the
numbers
of
wells
drilled
in
any
year
after
construction,
given
the
drilling
schedule.
Line
116
is
not
used.
The
total
drilling
costs
in
each
year
are
given
in
Line
117.
Line
118
splits
the
capital
costs
of
the
platform
(
line
106)
over
the
total
years
of
construction.
Line
119
splits
the
regulatory
option
costs
in
line
105
over
three
years.
Line
120
totals
capital
expenditures.
Lines
121
and
122
split
these
expenditures
into
those
which
can
be
expensed
and
those
which
must
be
capitalized
on
the
basis
of
line
5.

Expensed
development
costs,
Line
120,
are
the
product
of
total
drilling
costs
(
Line
117)
and
the
percent
of
drilling
costs
eligible
for
expensing
(
Line
5).
All
costs
not
eligible
for
expensing
are
capitalized
and
are
treated
as
depreciable
assets
for
tax
purposes.
Note,
in
particular,
that
any
capital
costs
of
I&
E
control
are
not
eligible
for
expensing
as
per
tax
code
requirements.
Capitalized
development
costs
appear
in
Line
122.

All
costs
prior
to
production
are
written
to
an
annual
cash
flow
table
(
not
reproduced
here),
which
is
used
in
the
calculation
of
net
present
value.
This
table
also
takes
into
account
depreciation
and
depletion
allowances
and
calculates
a
tax
shield.
Capital
expenditures
that
occur
after
the
beginning
of
production
are
visible
in
the
production
phase
cash
flow
in
lines
54­
65.

3.
RESULTS
ERG
used
the
Platform
Impact
Model
to
create
two
versions.
One
establishes
baseline
financial
conditions
(
no
permitting,
O&
M,
or
technology
costs
are
applied).
ERG
also
created
a
second
version
showing
post­
compliance
conditions
with
the
compliance
costs
applied
in
the
years
in
which
they
are
expected
to
be
incurred.
The
costs
and
the
years
in
which
they
are
incurred
are
taken
from
DCN
7­
4018,
the
316b
Compliance
Cost
Model
The
model
uses
the
costs
of
compliance
for
the
various
cost
components
and
identifies
the
years
in
which
they
are
incurred
for
20
years
of
newly
constructed
production
platforms/
structures.
ERG
used
the
cost
timing
schedule
and
costs
for
the
2007
deepwater
facility
(
i.
e.,
a
production
facility
assumed
to
come
on
line
in
2007)
as
presented
in
DCN
7­
4018.

The
model
outputs
from
the
two
versions
of
the
model
can
then
be
compared.
The
number
of
years
of
operation
(
which
is
determined
by
the
year
in
which
costs
exceed
net
revenues)
are
the
same
on
both
spreadsheets,
thus
production
losses
are
estimated
to
be
zero.
Net
present
value
is
reduced
slightly
in
the
post­
compliance
model
version.
The
magnitude
of
reduction
corresponds
to
the
present
value
of
total
compliance
costs
(
including
permitting,
monitoring,
O&
M
and
capital/
installation
costs)
as
a
proportion
of
baseline
project
net
present
value.
The
exact
results
of
this
reduction
in
NPV
are
considered
CBI,
since
knowledge
of
the
costs
of
compliance
and
the
percentage
reduction
in
NPV
could
allow
baseline
NPV
to
be
calculated.
Since
baseline
NPV
is
estimated
using
survey
data,
this
estimated
NPV
is
considered
CBI.
Complete
results,
both
baseline
and
post­
compliance,
can
be
seen
in
DCN
7­
4038
(
the
Platform
Impact
Model)
in
the
CBI
portion
of
the
rulemaking
record.

4.
REFERENCES
ERG.
2000.
Summary
of
Data
to
Be
Used
in
Economic
Analysis.
Report
to
James
Covington,
III,
U.
S.
EPA.
March
2000.

MMS,
2004a.
Lease
Data.
Download
of
MMS
data
included
in
the
rulemaking
record,
DCN
7­
4041.
11
MMS,
2004b.
Wellbore.
Selected
data
records
shown
for
the
affected
lease
in
DCN
7­
4038.
Entire
database
available
at
http://
www.
gomr.
mms.
gov/
homepg/
pubinfo/
freeASCII/
well/
freewell.
htm.

MMS,
2003.
Platform
Masters
Database.
Download
of
MMS
data
included
in
the
rulemaking
record,
DCN
7­
4025
OMB
(
Office
of
Management
and
Budget).
2003.
OMB
Circular
A­
4,
Regulatory
Analysis.
Informing
Regulatory
Decisions:
2003
Report
to
Congress
on
the
Costs
and
Benefits
of
Federal
Regulations
and
Impended
Mandates
on
State,
Local,
and
Tribal
Entities.
Appendix
D
and
Appendix
F.
Washington,
DC:
Office
of
Management
and
Budget.

U.
S.
Department
of
the
Treasury.
2002.
Internal
Revenue
Service
(
IRS).
2002
Instructions
for
Forms
1120
&
1120­
A,
page
17
(
Federal
tax
rates).

U.
S.
Department
of
the
Treasury.
2003.
Internal
Revenue
Service
(
IRS).
2003
How
To
Depreciate
Property,
page
71
U.
S.
Environmental
Protection
Agency
(
U.
S.
EPA).
2004a.
Economic
Analysis
for
the
Proposed
Section
316(
b)
Phase
III
Facilities.
November,
2004.

U.
S.
Environmental
Protection
Agency
(
U.
S.
EPA).
2004b.
Technical
Development
Document
for
the
Proposed
Section
316(
b)
Phase
III
Facilities.
November,
2004.

U.
S.
Environmental
Protection
Agency
(
U.
S.
EPA)
2000.
Economic
Analysis
of
Final
Effluent
Limitations
Guidelines
and
Standards
for
Synthetic­
Based
Drilling
Fluids
and
Other
Non­
Aqueous
Drilling
Fluids
in
the
Oil
and
Gas
Extraction
Point
Source
Category.
EPA­
821­
B­
98­
020.
December
2000.
