Document ID: EPA-HQ-OW-2004-0002-0659
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-11-30T05:00Z

SUMMARY
OF
DATA
TO
BE
USED
IN
ECONOMIC
MODELING
Prepared
for
James
Covington,
III
Engineering
an
Analysis
Division
Office
of
Water
U.
S
Environmental
Protection
Agency
401
M
Street,
SW
Washington,
DC
20460
Prepared
by
Eastern
Research
Group,
Inc.
110
Hartwell
Avenue
Lexington,
MA
02421
March
2000
2
SUMMARY
OF
DATA
TO
BE
USED
IN
ECONOMIC
MODELING
1.0
Introduction
EPA
is
developing
a
methodology
to
examine
the
economic
and
financial
impacts
of
the
syntheticbased
drilling
fluids
(
SBF)
guidelines
on
deepwater
oil
and
gas
projects
in
response
to
comments
from
industry
that
these
projects
are
vastly
different
from
the
projects
analyzed
as
part
of
the
Offshore
Oil
and
Gas
Effluent
Guidelines
economic
analysis.
At
proposal,
EPA
relied
on
the
results
of
that
latter
analysis
showing
Gulf
of
Mexico
projects
to
be
only
minimally
affected
by
even
the
most
stringent
drilling
waste
option
(
the
zero
discharge
option).
Because
of
the
unique
nature
of
deepwater
projects
and
because
of
their
greater
distance
from
shore,
industry
believes
deepwater
projects
need
to
be
evaluated
for
economic
impacts
resulting
from
options
considered
for
the
rule.

EPA
is
thus
developing
a
computer
model
similar
to
the
one
used
for
the
Offshore
rulemaking
(
U.
S.
EPA,
1993),
and
also
nearly
identical
to
the
one
developed
for
the
Main
Pass
operations
in
the
Gulf
of
Mexico
investigated
during
the
Coastal
Oil
and
Gas
Effluent
Guidelines
rulemaking
(
see
U.
S.
EPA,

1996).
This
model
uses
a
discounted
cash
flow
approach
to
determine
whether
a
regulatory
action
would
have
impacts
on
production,
project
life,
net
present
value,
or
other
potentially
measurable
impacts.
The
major
differences
of
this
model
compared
to
the
Main
Pass
model
are
the
inputs.
EPA
collected
information
on
projects
in
the
deep
water
Gulf
of
Mexico
from
industry
and
others
to
develop
the
appropriate
parameters
for
model
deepwater
projects,
including
production
figures,
produced
water
treatment
costs,
other
operating
and
maintenance
(
O&
M)
costs,
project
construction
costs,
wellhead
oil
and
gas
prices,
and
other
information.
This
information
will
be
used
in
two
versions
of
the
financial
model­­
one
for
existing
projects
(
the
BAT
model)
and
one
for
new
projects
(
the
NSPS
model).
The
collected
data
are
available
in
Section
III.
G.
2
of
the
Rulemaking
Record.

The
following
sections
present
the
general
data
requirements
for
modeling
deepwater
projects
3
(
Section
2),
the
specific
projects
that
will
be
used
for
modeling
impacts
on
deepwater
projects,
along
with
summaries
of
data
collected
that
characterize
the
financial
conditions
at
these
projects
(
Section
3),

construction
timing
assumptions
that
will
be
made
for
projects
expected
to
be
built
in
the
future
(
for
use
in
the
NSPS
model
version­­
see
Section
4),
and
an
estimate
of
capital
and
operating
costs
incurred
in
the
baseline,
given
data
collected
and
assumptions
provided
by
industry
(
see
Section
5).
The
last
section
(
Section
6)
discusses
some
preliminary
observations
that
can
be
made
about
the
potential
for
impacts
on
deepwater
projects
prior
to
the
actual
running
of
the
financial
model.

2.0
Data
Inputs
Required
by
the
Deepwater
Oil
and
Gas
Financial
Model
To
model
the
baseline
and
postcompliance
financial
situation
in
the
deepwater
Gulf
of
Mexico,

EPA
needs
a
variety
of
information
that
characterizes
deepwater
oil
and
gas
projects.
Table
1
shows
the
data
required
for
input
to
the
model,
the
source
of
the
data,
and
any
assumptions
associated
with
the
data.

Some
of
these
assumptions,
particularly
the
assumptions
on
baseline
operating
costs,
may
be
subject
to
change,
based
on
discussions
with
industry.

Table
1:
Data
Needs,
Assumptions,
and
Sources
of
Data
for
the
Oil
and
Gas
Financial
Model.

Parameter
Comment
Lease
cost
From
MMS
data
(
MMS,
1999a).
See
Table
2.

Number
of
wells
drilled
to
date
From
MMS
data
(
MMS,
1999d).
See
Table
4.

Structure
characteristics
(
e.
g.,
type
of
platform)
From
MMS
data
(
Regg,
1999).
See
Table
2.

Project
timing
(
number
of
years
between
leasing
and
exploratory
drilling,
between
exploration
and
delineation,
between
delineation
and
development,
and
between
development
and
operation)
From
MMS
data.
See
Table
3
for
data
and
sources
of
data.

Geophysical
and
Geological
Costs
$
500,000
per
lease
(
Parker,
1999a).

Drilling
costs
$
20
million
for
platform­
based
development
wells,
$
30
million
for
subsea
wells,
$
25
million
for
exploratory
wells.
Sidetracks
should
be
one­
half
the
cost
of
a
regular
borehole
(
Parker,
1999b;
2000b).

Incremental
drilling
costs
(
or
savings)
Provided
by
EPA's
engineering
contractor
(
McIntyre,
2000).
Parameter
Comment
4
Platform
(
additional
infrastructure)
cost
$
8/
BOE
original
proved
reserves
for
small
project,
$
7/
BOE
for
medium
project
and
$
5/
BOE
for
large
project.
Pipeline
costs
are
assumed
to
be
$
500,000
per
foot
with
a
$
13
million
initial
cost
for
small­
diameter
pipelines
and
$
750,000
per
foot
with
a
$
35
million
initial
cost
for
large­
diameter
pipelines
(
Parker
2000b).
Pipeline
lengths
were
obtained
from
MMS
(
MMS,
2000.
See
Table
4.

Rate
of
installation
of
development
wells
Data
from
MMS
(
MMS,
1999d),
with
projections
depending
on
past
history
and
size
of
reserve.
Reserve
size
will
be
allowed
to
vary
up
to
3
times
its
conservative,
original
proved
size
to
accommodate
reasonable
worst­
case
estimates
of
numbers
of
wells
drilled
in
each
project
postcompliance.

Peak
production
rate
Using
MMS
data
on
production
(
MMS,
1999b)
for
the
most
recently
installed
wells
in
a
project
(
generally
those
which
began
production
in
1998),
EPA
estimated
the
peak
production
rate
of
wells
at
each
project.
See
Table
2.

Current
existing
production
Data
from
MMS
(
MMS,
1999b).
See
Table
2.

Production
decline
rates
The
Offshore
EIA
assumes
15
percent
per
year
declines
after
a
year
at
peak
production
for
all
well
types.
EPA
will
continue
to
use
this
assumption.
Note
that
production
overall
at
a
project
will
not
decline
at
15
percent
per
year
until
the
last
development
well
is
installed.

Operation
&
maintenance
costs
(
excluding
variable
costs
of
produced
water
treatment
&
discharge)
$
2/
BOE
of
production
for
small
projects,
$
1.75/
BOE
for
medium
projects
and
$
1.50/
BOE
for
large
projects
(
Parker,
2000a).

Initial
produced
water
production
Data
from
MMS
(
MMS,
1999b).
See
Table
2.

O&
M
costs
for
produced
water
(
per
bbl)
50
cents
per
bbl
of
produced
water
(
Parker,
2000b).

Marginal
corporate
tax
rates
The
Offshore
EIA
used
34
percent,
which
EPA
will
continue
to
use.

Severance
taxes
The
Offshore
EIA
used
no
severance
tax
in
federal
waters,
which
is
still
the
case.

Royalty
rate
Royalty
rates
for
each
lease
have
been
obtained
from
MMS
(
MMS,
1999a).
They
are
generally
12.5
to
16.7
percent.
These
are
maximum
rates,
and
they
can
be
adjusted
downward.
EPA
will
assume
that
maximum
rates
will
be
applied,
however.
See
Table
2.
Parameter
Comment
5
Depreciation
The
Offshore
EIA
used
the
modified
accelerated
cost
recovery
system.
EPA
will
continue
to
use
this
depreciation
schedule.

Basis
for
depreciation
The
Offshore
EIA
used
100
percent
of
total
capitalized
costs.
EPA
will
continue
using
this
value.

Capitalized
costs
The
Offshore
EIA
assumed
intangible
drilling
costs
are
expensed,
that
IDCs
represent
60
percent
of
the
cost
of
production
wells
and
their
infrastructure,
that
integrated
producers
can
expense
70
percent
of
IDCs
(
42
percent
of
well
drilling
costs)
and
independents
can
expense
100
percent
(
60
percent
of
well
drilling
costs),
with
the
remainder
capitalized
and
treated
as
depreciable
assets.

Inflation
rate
EPA
is
using
3
percent.

Depletion
Allowance
For
independents,
15
percent
percentage
depletion
on
up
to
1,000
barrels
of
oil
equivalent
(
BOE)
is
assumed.
For
majors
EPA
will
use
cost
basis
depletion,
which
the
tax
code
defines
as
(
leasehold
costs
adjusted
for
inflation
minus
depreciation
minus
salvage
[
assumed
0])
times
(
barrels
of
oil
produced
that
year
divided
by
recoverable
reserves
remaining
at
the
beginning
of
the
year
[
includes
number
produced
that
year]).

Real
discount
rate
OMB
suggests
the
use
of
a
7
percent
real
discount
rate
for
economic
analyses.
EPA
will
use
7
percent.

Wellhead
price
of
oil
and
gas
Based
on
the
past
10
years
of
average
wellhead
prices
for
Federal
Offshore
oil
and
gas
(
API,
1999),
and
assuming
a
$
2/
bbl
reduction
from
average
wellhead
oil
prices
and
a
10
percent
reduction
from
average
wellhead
gas
prices
to
reflect
greater
transport
distances
associated
with
the
deepwater
fields
(
Parker,
1999a),
EPA
is
using
$
15/
bbl
for
oil
and
$
1.80/
Mcf
for
gas.
EPA
will
perform
sensitivity
analyses
on
lower
and
higher
oil
and
gas
prices
as
well.

3.0
Model
Projects
EPA
investigated
a
number
of
deepwater
projects
for
use
as
model
projects.
These
projects
included
all
currently
operating
projects,
as
well
as
a
number
that
should
come
on
line
shortly.
Over
30
projects
fit
this
description.
From
these
initial
projects,
EPA
selected
as
many
as
possible
to
use
in
6
modeling
deepwater
projects.
Data
availability
was
the
primary
criterion
used
in
selecting
the
model
projects.
EPA
selected
all
deepwater
projects
for
analysis
that
operated
in
1998
and
that
had
original
proved
reserves
data
available
in
public
documents.
The
most
recent
publicly
available
documents
on
proved
reserves
are
those
provided
by
MMS
on
their
website,
and
these
documents
are
current
through
December
31,
1996
(
MMS,
1999e).
Proved
reserves
are
used
to
distinguish
the
relative
size
of
projects,

since
the
indication
of
the
ultimate
size
of
a
project
is
reserves,
not
necessarily
the
current
production
(
new
projects
that
have
not
completed
the
maximum
number
of
wells
that
would
be
productive
at
any
one
time
would
end
up
classified
as
smaller
than
they
will
eventually
become).
Size
of
project
is
important,
since
results
will
be
reported
over
a
group
of
projects
(
i.
e,
results
for
small,
medium,
and
large
projects)
rather
than
project­
by­
project.
Size
of
reserves
also
allows
EPA
to
determine
how
many
wells
might
be
drilled
at
a
project
over
time.

Using
the
data
availability
criterion,
EPA
reduced
the
number
of
projects
that
can
be
modeled
to
twenty.
One
project
did
not
operate
in
1998,
and
the
others
either
have
not
yet
started
producing,
or
are
so
new
that
original
proved
reserves
had
not
been
calculated
for
them
in
December
1996.
The
twenty
projects
include
four
small
projects
(
original
proved
reserves
of
10
million
BOE
or
less,
eight
medium­
size
projects
(
original
proved
reserves
approximately
between
10
million
and
100
million
BOE),
and
eight
large
projects
(
original
proved
reserves
over
100
million
BOE).
These
twenty
projects
will
be
used
to
model
existing
deepwater
projects
under
BAT
options.
EPA
further
limited
the
number
of
projects
to
15
for
NSPS
modeling
purposes.
The
five
projects
removed
(
Lena,
Alabaster,
Cognac,
Bullwinkle,
and
Pompano)
are
either
too
old
or
their
technologies
are
too
dated
for
the
purposes
of
projecting
what
future
projects
will
look
like
(
Parker,
2000b).

Table
2
shows
each
of
the
projects
that
are
used
in
the
BAT
model,
along
with
the
publicly
available
data
associated
with
them
(
production
figures
for
1998,
number
of
leases
associated
with
the
field
that
are
held
by
the
primary
operator,
lease
bid
price
in
1998
dollars,
royalty
rates,
and
type
of
project
[
e.
g.,
subsea,
tension­
leg
platform,
or
fixed
platform]),
among
other
information.

4.0
Timing
Assumptions
for
NSPS
Models
7
The
timing
of
the
project
construction
is
important
data
in
the
NSPS
model.
Table
3
presents
the
information
obtained
from
various
MMS
databases
that
allow
the
timing
assumptions
for
NSPS
projects
to
be
made.
Data
for
the
15
NSPS
model
projects
include
the
platform
construction
date,
the
year
of
first
production,
the
first
lease
year,
the
discovery
date,
the
delineation
date
(
inferred
from
when
the
next
exploratory
wells
were
drilled
after
the
discovery
well),
beginning
of
construction
date
(
generally
inferred
from
date
of
first
development
well
drilling
or
pipeline
construction
permit
date),
and
beginning
of
production
date
(
generally
the
earliest
production
date
seen
for
any
well
in
the
project).
In
a
few
cases
the
years
between
construction
and
production
were
reduced
from
5
years
to
4
years
(
see
notes
to
Table
9
Table
3.
Timing
Data
and
Assumptions
for
NSPS
Projects
Project
Name
Lease
Year
Discovery
Date
Delineation
Date
Beginning
Construction
Date
Platform
Completion
Date
1st
Production
Date
#
Years
Lease
to
Discovery
#
Years
Discovery
to
Delineation
#
Years
Delineation
to
Construction
#
Years
Construction
to
Production
Shasta
`
80
`
81
`
83
`
94
­­
`
95
1
2
11
1
Diamond
`
84
`
93
`
93
`
93
­­
`
93
9
0
0
0
VK862
`
91
`
95
`
95
`
95
­­
`
95
4
0
0
0
Rocky
`
93
`
96
­­
`
96
­­
`
96
3
0
0
0
Zinc
`
74
`
79
`
79
`
92
­­
`
93
5
0
13
1
Neptune
`
83
`
88
`
89
`
94
`
96
`
97
5
1
5
3
Popeye
`
83
`
85
`
85
`
94
­­
`
96
2
0
9
2
Jolliet
`
80
`
82
`
82
`
87
`
89
`
90
2
0
5
3
Cooper
`
84
`
90
`
90
`
90
`
95
`
95
6
0
0
5
Amberjack
`
83
`
84
`
87
`
91
`
91
`
91
1
3
2
2
Mars
`
85
`
92
`
89
`
91
`
96
`
96
4
0
3
4
Tahoe
`
84
`
85
`
85
`
89
­­
`
94
1
0
4
5
Mensa
`
83
`
87
`
87
`
96
­­
`
97
4
0
9
1
Auger
`
84
`
87
`
87
`
90
`
94
`
94
3
0
3
4
Ram­
Powell
`
84
`
85
`
86
`
97
`
97
`
97
1
1
6
5
Notes:
Years
between
construction
and
production
counted
for
Zinc
and
Popeye
from
pipeline
application
dates
(
1992
and
1994,
respectively).
Ram­
Powell
and
Amberjack
show
no
years
between
1st
development
well
drilled
and
platform
completion
date,
so
the
difference
between
delineation
date
and
first
development
well
drilled
is
split
to
estimate
the
length
of
the
construction
phase.
Mars
has
a
discovery
date
of
1992,
but
the
discovery
well
was
drilled
in
1989
and
thus
1989
is
assumed
the
actual
discovery
year
for
computing
the
time
between
discovery
and
delineation.

Sources:
MMS,
1999a;
MMS,
1999b;
MMS,
1999d;
MMS,
1999f;
and
MMS,
2000.
11
3)
due
to
the
way
the
model
is
constructed
(
up
to
4
years
of
construction
time
are
hardwired
into
the
model).
This
change
should
have
little
to
no
effect
on
model
results.

5.0
Model
Project
Costs
Table
4
presents
the
cost
information
provided
by
the
industry
working
group
(
Parker,
1999a,

1999b,
and
2000)
used
with
the
data
extracted
from
MMS.
The
first
column
of
Table
4
uses
the
total
barrels
of
oil
equivalent
produced
in
1998
(
See
Table
2)
to
compute
annual
operating
costs,
assuming
these
costs
are
$
2.00/
BOE
for
small,
$
1.75/
BOE
for
medium
and
$
1.50/
BOE
for
large
projects.
The
O&
M
cost
for
produced
water
treatment
is
computed
as
$
0.50
times
the
total
annual
volume
of
water
shown
in
Table
2
(
the
model
will
vary
this
cost
over
time,
since
water
production
can
increase
over
time).
Costs
of
drilling
wells
are
assumptions
provided
by
industry
as
shown
in
Table
1
(
Parker,
1999b).
The
well
counts
in
table
2
are
then
broken
down
by
development,
sidetrack,
and
exploratory
designations.
When
numbers
of
wells
times
appropriate
well
costs
are
computed,
the
result
can
be
seen
in
the
column
entitled
Total
Well
Cost
To
Date.
Platform
cost
uses
the
Original
Proved
Reserves
reported
in
Table
2
times
the
assumed
$
7/
BOE
for
medium
projects
and
$
5/
BOE
for
large
projects
(
Parker,
1999b)
(
note:
small
projects
are
subsea
completions
and
thus
do
not
have
platform
costs
associated
with
them).
Pipeline
length
is
obtained
from
MMS
(
2000).
Pipeline
costs
are
provided
by
industry
(
Parker,
2000b).
In
addition,
the
following
assumptions
are
used
in
computing
the
costs
of
pipelines:

If
several
pipelines
were
installed
on
or
about
the
same
day
at
a
project
(
e.
g.,
one
gas
pipeline
and
one
oil
pipeline),
one
fixed
pipeline
setup
cost
is
assumed
to
apply
and
the
total
miles
of
all
pipelines
times
the
appropriate
per
mile
cost
is
used
(
depending
on
size
reported­­
see
below).

All
pipelines
with
dimensions
of
14"
or
less
are
assumed
small.
Those
over
14"
are
considered
large.

Pipelines
labeled
"
UMB"
are
umbilical
lines
(
electrical
cables,
etc.),
which
may
have
an
additional
cost,
but
these
tend
to
be
very
small
(
3
inches).
Costs
were
not
computed
for
these
lines.

Costs
for
proposed
pipelines
that
have
an
approval
date
similar
to
other
active
pipelines,
but
that
did
not
go
into
service
at
the
same
time
are
not
estimated
because
it
is
assumed
that
the
operator
would
have
installed
a
proposed
pipeline
at
the
time
the
others
were
installed
to
save
set
up
costs,
but
since
they
did
not,
it
is
assumed
the
operators
changed
their
minds
about
installing
that
12
pipeline.
Also
not
estimated
were
costs
for
any
pipelines
that
had
a
"
cancel"
code,
but
costs
for
any
pipelines
no
longer
in
use
or
removed
are
estimated.

One
setup
cost
and
one
set
of
mileage
costs
are
assumed
for
one
project
with
pipelines
within
pipelines.
There
are
six
4"
pipelines
within
a
28"
pipeline,
all
in
a
3­
mile
stretch.
The
18"
cost
of
setup
and
pipeline
cost
per
mile
were
used.

Costs
for
very
short
pipelines
(
e.
g.,
under
100
feet)
were
ignored.

Costs
are
assigned
to
the
project
regardless
of
who
the
pipeline
operator
is
(
in
some
cases
the
project
operator
is
not
the
pipeline
operator).

Using
all
of
these
assumptions,
the
total
pipeline
cost
is
computed.

Costs
of
leases
are
shown
in
Table
2,
and
are
used
for
computing
the
total
project
development
costs
in
last
column
of
Table
4.
Note
that
projects
not
assigned
a
total
investment
cost
to
date
are
those
that
will
not
be
used
in
the
NSPS
modeling.

6.0
Preliminary
Observations
Based
on
the
data
collected
to
date
and
the
assumptions
provided
by
industry,
the
following
observations
are
made.

Zero
discharge
of
drilling
waste
will
cost
an
additional
$
151,420
for
each
deepwater
exploratory
well
and
$
125,020
for
each
deepwater
development
well
(
McIntyre,
2000).
Industry
has
provided
baseline
costs
of
drilling
deepwater
wells
of
$
20
to
$
30
million
for
deepwater
development
wells
and
$
25
million
for
deepwater
exploratory
wells.
Zero
discharge
costs
thus
are
only
about
0.6
percent
of
baseline
drilling
costs.
Furthermore,
a
typical
(
median)
small
project
currently
(
1998)
produces
revenues
of
about
$
13.0
million
per
year
(
based
on
an
assumed
$
15/
bbl
of
oil
and
$
1.80
per
Mcf
of
gas),
a
typical
medium
project
produces
revenues
of
about
$
51.8
million
per
year,
and
a
large
project
currently
produces
revenues
of
about
$
214.8
million
per
year
(
see
Table
4
for
estimated
revenues).
Zero
discharge
costs
per
year
(
assuming
approximately
2
wells
per
year
are
added
at
all
but
the
small
projects,
which
are
assumed
to
add
one
every
other
year
for
this
exercise)
are
no
more
than
0.5
percent
of
average
current
project
annual
revenues
for
each
size
group.
13
Furthermore,
because
well
drilling
is
not
an
operating
cost
(
which
drives
operating
earnings
and
thus
affects
shut­
in
decisions),
lifetime
production
will
only
be
affected
if
the
net
present
value
of
the
project
is
positive
in
the
baseline
and
negative
in
the
postcompliance
scenario.
If
this
happens,
the
project
either
is
assumed
to
shut
in
(
or
never
be
built)
as
a
response
to
the
rule,
or
stop
drilling
wells,
if
it
appears
that
the
revenues
from
those
wells
are
unlikely
to
cover
the
incremental
costs
of
drilling
the
wells
postcompliance.
Thus
except
for
very
marginal
projects,
or
for
projects
near
the
end
of
their
economic
lives
(
with
a
very
small
remaining
earnings
stream),
EPA
does
not
expect
these
costs
to
drive
the
net
present
value
of
most
projects
negative.
However,
because
averages
can
obscure
the
effects
at
the
most
vulnerable
projects,
EPA
will
be
looking
closely
at
the
potential
for
option
costs
to
cause
any
measurable
impacts
at
projects
that
do
conform
to
the
parameters
of
the
average
project
using
the
financial
model.

Although
model
outputs
will
be
reported
in
the
aggregate
by
project
size,
each
individual
project
will
be
represented
in
the
model
inputs
to
allow
EPA
to
identify
impacts
more
precisely.

The
projects
likeliest
to
show
some
potential
for
impact
under
the
zero
discharge
scenario
are
the
smallest
projects
(
both
existing
and
new,
if
the
existing
projects
continue
to
drill),
the
oldest
existing
projects
(
such
as
Lena
and
Cognac,
which
have
produced
over
80
percent
of
their
original
proved
reserves
as
of
1996),
or
very
marginal
projects.
Because
any
project
could
be
marginal
when
all
the
factors
are
accounted
for,
even
the
relatively
small
cost
of
the
SBF
rule
under
the
zero
discharge
scenario
could
have
an
impact
on
one
or
more
projects,
although,
at
this
time,
EPA
believes
this
possibility
is
small.
Under
the
discharge
options,
however,
any
costs
are
so
small
(
ranging
from
a
cost
savings
of
$
53,000
per
well
to
a
cost
of
about
$
8,000
per
well
[
McIntyre,
2000]
that
it
is
unlikely
these
costs
would
have
any
measurable
impacts
on
deepwater
projects.
Nevertheless,
EPA
will
model
these
regulatory
options
as
well.

REFERENCES
American
Petroleum
Institute
(
API),
1999.
Basic
Petroleum
Data
Book.
Petroleum
Industry
Statistics.
January,
1999.

McIntyre,
Jamie,
2000.
Personal
communication
between
Anne
Jones,
Eastern
Research
Group
and
Jamie
McIntyre,
Pechan­
Avanti,
February
1,
2000.

MMS,
1999a.
www.
gomr/
mms.
gov/
homepg/
pubinfo/
freeascii/
leasing/
freelease.
html.
"
Lease
Data,"
ASCII
file,
downloaded
9/
30/
99.
14
MMS,
1999b.
www.
gomr/
mms.
gov/
homepg/
pubinfo/
freeascii/
product/
freeproduct.
html.
"
Production
for
1998."
ASCII
file,
downloaded
9/
27/
99.

MMS,
1999c.
www.
gomr/
mms.
gov/
homepg/
pubinfo/
freeascii/
geologic/
freegeol.
html.
"
Field
Names
Master
List
Appendix
B
and
Appendix
C."
ASCII
files,
downloaded
10/
25/
99.

MMS,
1999d.
www.
gomr/
mms.
gov/
homepg/
pubinfo/
freeascii/
well/
freewell.
html.
"
Borehole."
ASCII
file,
downloaded
9/
1/
99.

MMS,
1999e.
www.
gomr/
mms.
gov/
homepg/
pubinfo/
freeascii/
geologic/
estimated1996.
html,
"
96_
his.
zip."
"
Reserve
History
for
Proved
Fields
by
Field
and
Year,
December
31,
1996.

MMS,
1999f.
www.
gomr/
mms.
gov/
homepg/
pubinfo/
freeascii/
platform/
freeplat.
html.
"
Platform
Masters."
ASCII
file,
downloaded
December
15,
1999.

MMS,
2000.
www.
gomr/
mms.
gov/
homepg/
pubinfo/
pdfindex.
html.
"
Segment
List
in
Comes
From
Order."
PDF
file,
February
3,
2000.

Parker,
Michael,
1999a.
Personal
communication
between
Michael
Parker,
Exxon,
and
EPA,
December
7,
1999.

Parker,
Michael,
1999b.
Personal
communication
between
Michael
Parker,
Exxon,
and
EPA,
December
20,
1999.

Parker,
Michael,
2000a.
Personal
communication
between
Michael
Parker,
Exxon,
and
EPA,
January
3,
2000.

Parker,
Michael,
2000b.
Personal
communication
between
Michael
Parker,
Exxon,
and
EPA,
February
2,
2000.

Regg,
James,
1999.
"
Deepwater
Production
and
Discoveries,"
MMS,
August
4,
1999.

U.
S.
EPA,
1993.
Economic
Impact
Analysis
of
Final
Effluent
Limitations
Guidelines
and
Standards
of
Performance
for
the
Offshore
Oil
and
Gas
Industry.
EPA­
821­
R­
93­
004,
January,
1993.

U.
S.
EPA,
1996.
Economic
Impact
Analysis
of
Final
Effluent
Limitations
Guidelines
and
Standards
for
the
Coastal
Subcategory
of
the
Oil
and
Gas
Extraction
Point
Source
Category,
EPA­
821­
R­
96­
022,
October,
1996.