1U.
S.
Department
of
Energy,
Energy
Information
Administration,
2004.
"
U.
S.
LNG
Markets
and
Uses:
June
2004
Update,"
http://
www.
eia.
doe.
gov/
pub/
oil_
gas/
natural_
gas/
feature_
articles/
2004/
lng/
lng2004.
pdf.

Page
1
of
29
Memorandum
From:
Carey
A.
Johnston,
P.
E.
USEPA/
OW/
OST
ph:
(
202)
566
1014
johnston.
carey@
epa.
gov
To:
Public
Record
for
the
Effluent
Guidelines
Program
Plan
for
2004/
2005
DCN
01227,
Section
3.23
EPA
Docket
Number
OW­
2003­
0074
(
www.
epa.
gov/
edockets/)

Date:
August
19,
2004
Re:
Overview
of
Liquefied
Natural
Gas
(
LNG)
Import
Terminals
For
CWA
Section
304(
m)
Effluent
Guidelines
Planning
Introduction
Liquefied
natural
gas
(
LNG)
has
become
an
increasingly
important
part
of
the
U.
S.
energy
market.
Interest
in
LNG
imports
has
been
rekindled
by
higher
U.
S.
natural
gas
prices
in
recent
years,
as
well
as
increased
competition
and
technological
advances
that
have
lowered
costs
for
liquefaction,
shipping,
storing,
and
re­
gasification
of
LNG.
1
LNG
is
cooled
to
about
minus
260
oF
and
transported
by
vessels
to
import
facilities
for
re­
gasification.

During
the
re­
gasification
process,
the
LNG
is
warmed
from
minus
260
oF
to
40
oF
and
experiences
a
three­
fold
increase
in
volume.
Typically,
LNG
at
import
terminals
is
stored
only
until
it
can
be
re­
gasified
and
injected
into
the
pipeline
grid
or
until
it
can
be
trucked
directly
to
customers.
In
order
to
minimize
wait
times
for
the
ships
and
to
avoid
congestion,
operators
of
LNG
marine
terminals
process
cargoes
quickly.
Each
U.
S.
import
terminal
is
equipped
with
storage
tanks
capable
of
holding
between
two
and
three
tanker
loads
of
LNG.
Some
new
and
expanded
facilities
in
the
United
States
will
have
a
capacity
closer
to
four
tanker
loads.
(
DOE
2004)
LNG
import
terminals
may
use
surface
waters
for
this
heat
exchange
process
and
may
use
biocides
(
e.
g.,
sodium
hypochlorite)
to
control
biofouling
of
their
intake
structures.

This
memorandum
provides
an
overview
of:
(
1)
the
existing
and
planned
LNG
import
terminals
in
the
United
States;
(
2)
estimates
of
pollutant
discharges
for
existing
and
proposed
2U.
S.
DOE,
Office
of
Fossil
Energy,
Order
Granting
Long­
Term
Authorization
to
Import
Liquified
Natural
Gas,
Order
No.
1042,
http://
www.
fe.
doe.
gov/
programs/
gasregulation/
authorizations/
orders/
ord1042.
pdf,
April
19,
1995.
Page
2
of
29
LNG
import
terminals;
and
(
3)
the
technology
options
available
to
reduce
or
eliminate
pollutant
discharges.

1.0
Existing
LNG
Import
Terminals
in
the
U.
S.

The
LNG
industry
in
the
United
States
has
experienced
periods
of
prolonged
downturns,
in
part
owing
to
price
competition
from
domestic
sources
of
natural
gas.
(
DOE
2004)
Currently
there
are
five
existing
onshore
LNG
import
terminals
and
no
existing
offshore
LNG
import
terminals.
The
five
existing
onshore
LNG
import
terminals
are
presented
in
Table
1.

Table
1:
Five
Existing
Onshore
LNG
Import
Terminals
Location
2003
LNG
Imports,
Billion
cubic
feet
(
Bcf)
2004
LNG
Storage
Capacity,
Billion
cubic
feet
(
Bcf)
Operator
Lake
Charles,
LA
238.2
6.3
Southern
Union
Cove
Point,
MD
66.1
5.0
Dominion
Everett,
MA
158.3
3.5
Tractebel
Elba
Island,
GA
43.9
4.0
El
Paso/
Southern
LNG
Guayanilla
Bay,
Puerto
Rico
1302
N/
A
Enron/
Edison
Mission
(
EcoElectrica)

Sources:
(
DOE
2004),
(
DOE
1995)

Although
LNG
imports
exceeded
historical
highs
in
2003,
even
at
the
current
pace
they
represent
only
about
2.7
percent
of
U.
S.
consumption
and
13
percent
of
imports.
Through
expansions
at
three
of
the
four
facilities,
the
United
States
will
increase
its
peak
re­
gasification
capacity
by
more
than
40
percent
from
the
2002
level
(
3.2
Bcf/
d)
to
approximately
4.6
Bcf/
d
in
2005.
Additionally,
through
recently
announced
additional
expansion
projects
at
Lake
Charles
and
Cove
Point,
capacity
would
reach
about
6.2
Bcf/
d
by
2008.
(
DOE
2004)

Since
the
1970s,
none
of
the
four
existing
continental
U.
S.
LNG
import
terminals
use
surface
water
for
their
vaporization
operations,
only
as
an
emergency
backup
source
to
their
3
E­
mail
communication
from
James
Kelly,
CH­
IV
International,
to
Carey
A.
Johnston,
U.
S.
EPA,
April
28,
2004.

4
Frangesh,
Neal,
2004.
Memorandum
from
Neal
Frangesh,
LGA
Engineering,
to
David
Moses,
U.
S.
DOE,
"
Existing
U.
S.
LNG
Import
Terminals:
Sources
of
Cooling
Water
and
Firewater,"
July
19,
2004.

5E­
mail
communication
from
Elizabeth
Aldridge,
Hutton
&
Williams,
to
Carey
A.
Johnston,
U.
S.
EPA,
June
24,
2004.
Page
3
of
29
firewater
systems.
3,4
For
example,
at
the
Dominion
Cove
Point,
MD,
facility
all
water
used
on
site
is
withdrawn
from
groundwater
wells
and
is
heated
in
the
vaporizers
and
used
to
warm
the
LNG
and
convert
back
to
a
gaseous
state.
5
Additionally,
the
EcoElectrica
facility
in
Puerto
Rico
does
use
surface
water
for
makeup
and
discharges
blowdown
for
the
power
plant
cooling
tower,
but
does
not
discharge
wastewater
for
the
LNG
processing
(
warming
or
cooling).
The
EcoElectrica
facility
integrates
LNG
vaporization
with
its
power
plant
operations.
Figure
1
describes
how
this
facility
uses
a
glycol
re­
circulating
heat
exchanger
in
combination
with
a
electric
power
generator
to
re­
gasify
the
LNG.

Figure
1:
EcoElectrica
Simplified
Flow
Diagram
6Remarks
of
Suedeen
G.
Kelly,
Commissioner
of
Federal
Energy
Regulatory
Commission,
to
the
Natural
Gas
Roundtable
of
Washington,
"
The
Challenge
of
Natural
Gas
Interchangeability
and
Quality,"
Washington,
D.
C.,
February
24,
2004.
See
http://
www.
ferc.
gov/
press­
room/
sp­
current/
02­
24­
04­
kelly.
pdf.

7Gaul,
Damien,
2001.
U.
S.
Department
of
Energy,
Energy
Information
Administration,
"
U.
S.
LNG
Markets
and
Uses,"
See
http://
www.
eia.
doe.
gov/
pub/
oil_
gas/
natural_
gas/
feature_
articles/
2003/
lng/
lng2003.
pdf
8
University
of
Houston,
2003.
"
Introduction
to
LNG,"
http://
www.
energy.
uh.
edu/
LNG/
documents/
IELE_
introduction_
to_
LNG.
pdf,
January
2003.

9
Kelly,
Edward,
2004.
"
Factors
Limit
LNG's
Role
In
U.
S.
Market,"
American
Oil
and
Gas
Reporter,
March
2004.

10U.
S.
Department
of
Energy,
2004.
"
Annual
Energy
Outlook
2004
with
Projections
to
2025,"
DOE/
EIA­
0383
(
2004),
January
2004.
See
http://
www.
eia.
doe.
gov/
oiaf/
aeo/.

11Meyer,
Keith,
2004.
The
Regasification
of
North
America,
World
Energy,
Vol.
7,
No.
1,
http://
www.
worldenergysource.
com/
articles/
pdf/
meyer_
WE_
v7n1.
pdf.
Page
4
of
29
2.0
Planned
LNG
Import
Terminals
in
the
U.
S.

A
competition
to
build
LNG
import
terminals
is
taking
place
among
U.
S.
and
foreign
companies
in
many
regions
of
North
America
because
of
the
perceived
opportunity
in
the
growing
LNG
industry.
6
Interest
in
LNG
imports
has
been
rekindled
by
higher
U.
S.
natural
gas
prices
in
recent
years
and
technological
advances
that
have
lowered
costs
for
liquefaction,
re­
gasification,
shipping,
and
storing
of
LNG.
7,8
Potential
investment
in
re­
gasification
facilities
in
the
U.
S.
is
estimated
at
$
15
billion.
9
Although
LNG
imports
currently
make
up
a
small
percentage
of
total
gas
supplies,
higher
natural
gas
prices
and
recent
expansions
of
existing
LNG
import
terminals
and
the
constructions
of
new
terminals
will
likely
boost
the
net
import
of
LNG
from
overseas.
Net
LNG
imports
are
estimated
to
increase
from
0.2
trillion
cubic
feet
in
2002
to
2.2
and
4.8
trillion
cubic
feet
in
2010
and
2025,
respectively,
as
planned
expansions
at
the
four
existing
terminals
are
completed
and
new
terminals
are
projected
to
start
coming
into
operation
in
2007.10
As
shown
in
Figure
2
a
number
of
LNG
import
terminals
have
been
proposed
for
development
to
meet
the
increased
demand
for
natural
gas.
(
FERC
2004)
There
are
at
least
40
company
announcements
of
proposed
terminals
targeted
for
North
America.
Many
of
these
projects
are
already
before
regulators,
and,
as
of
June
2004,
some
have
achieved
regulatory
success.
(
DOE,
2004).
Many
of
these
proposed
projects
are
planned
for
the
Gulf
of
Mexico
(
GOM)
area
due
to
the
area's
largest
demand
for
natural
gas
and
significant
pipeline
infrastructure.
11
Page
5
of
29
Existing
Terminals
with
Approved
Expansions
A.
Everett,
MA
:
1.035
Bcfd
(
Tractebel
 
DOMAC)

B.
Cove
Point,
MD
:
1.0
Bcfd
(
Dominion
 
Cove
Point
LNG)

C.
Elba
Island,
GA
:
1.2
Bcfd
(
El
Paso
 
Southern
LNG)

D.
Lake
Charles,
LA
:
1.2
Bcfd
(
Southern
Union
 
Trunkline
LNG)

Approved
Terminals
1.
Hackberry,
LA
:
1.5
Bcfd,
(
Sempra
Energy)

2.
Port
Pelican:
1.6
Bcfd,
(
Chevron
Texaco)

3.
Bahamas
:
0.84
Bcfd,
(
AES
Ocean
Express)*

4.
Gulf
of
Mexico:
0.5
Bcfd,
(
El
Paso
Energy
Bridge
GOM,
LLC)

5.
Bahamas
:
0.83
Bcfd,
(
Calypso
Tractebel)*

Proposed
Terminals
and
Expansions
 
FERC
6.
Freeport,
TX
:
1.5
Bcfd,
(
Cheniere/
Freeport
LNG
Dev.)

7.
Fall
River,
MA
:
0.8
Bcfd,
(
Weaver's
Cove
Energy/
Hess
LNG)

8.
Long
Beach,
CA
:
0.7
Bcfd,
(
SES/
Mitsubishi)

9.
Corpus
Christi,
TX
:
2.6
Bcfd,
(
Cheniere
LNG
Partners)

10.
Sabine,
LA
:
2.6
Bcfd
(
Cheniere
LNG)

11.
Corpus
Christi,
TX
:
1.0
Bcfd
(
Vista
Del
Sol
­
ExxonMobil)

12.
Sabine,
TX
:
1.0
Bcfd
(
Golden
Pass
­
ExxonMobil)

13.
Logan
Township,
NJ
:
1.2
Bcfd
(
Crown
Landing
LNG
 
BP)

14.
Lake
Charles,
LA:
0.6
Bcfd
(
Southern
Union
 
Trunkline
LNG)

15.
Bahamas
:
0.5
Bcfd,
(
Seafarer
­
El
Paso/
FPL
)

16.
Corpus
Christi,
TX:
1.0
Bcfd
(
Occidental
Energy
Ventures)

17.
Providence,
RI
:
0.5
Bcfd
(
Keyspan
&
BG
LNG)

18.
Port
Arthur,
TX:
1.5
Bcfd
(
Sempra)

Proposed
Terminals
 
Coast
Guard
19.
California
Offshore:
1.5
Bcfd,
(
Cabrillo
Port
 
BHP
Billiton)

20.
Louisiana
Offshore
:
1.0
Bcfd
(
Gulf
Landing
 
Shell)

21.
So.
California
Offshore
:
0.5
Bcfd,
(
Crystal
Energy)

22.
Louisiana
Offshore
:
1.0
Bcfd
(
Main
Pass
McMoRan
Exp.)

23.
Gulf
of
Mexico:
n/
a
(
Compass
Port
­
ConocoPhillips)

Planned
Terminals
and
Expansions
24.
Brownsville,
TX
:
n/
a,
(
Cheniere
LNG
Partners)

25.
Mobile
Bay,
AL:
1.0
Bcfd,
(
ExxonMobil)

26.
Somerset,
MA
:
0.65
Bcfd
(
Somerset
LNG)

27.
Belmar,
NJ
Offshore
:
n/
a
(
El
Paso
Global)

28.
Altamira,
Tamulipas
:
1.12
Bcfd,
(
Shell)

29.
Baja
California,
MX
:
1.0
Bcfd,
(
Sempra
&
Shell)

30.
Baja
California
­
Offshore
:
1.4
Bcfd,
(
Chevron
Texaco)

31.
California
­
Offshore
:
0.5
Bcfd,
(
Chevron
Texaco)

32.
St.
John,
NB
:
0.5
Bcfd,
(
Canaport
 
Irving
Oil)

33.
Point
Tupper,
NS
1.0
Bcf/
d
(
Bear
Head
LNG
­
Access
Northeast
Energy)

34.
Pleasant
Point,
ME
:
0.5
Bcf/
d
(
Quoddy
Bay,
LLC)

35.
St.
Lawrence,
QC
:
n/
a
(
Enbridge/
Gaz
Met)

36.
Lázaro
Cárdenas,
MX
:
0.5
Bcfd
(
Tractebel/
Repsol)

37.
Gulf
of
Mexico
:
1.0
Bcfd
(
Pearl
Crossing
­
ExxonMobil)

38.
Mobile
Bay,
AL:
1.0
Bcfd
(
Cheniere
LNG
Partners)

39.
Cherry
Point,
WA:
0.5
Bcfd
(
Cherry
Point
Energy
LLC)

40.
Cove
Point,
MD
:
0.8
Bcfd
(
Dominion)

41.
Puerto
Libertad,
MX:
1.3
Bcfd
(
Sonora
Pacific
LNG)

42.
Offshore
Boston,
MA:
0.8
Bcfd
(
Northeast
Gateway
 
Excelerate
Energy)

43.
Kitimat,
BC:
0.34
Bcfd
(
Galveston
LNG)

*
US
pipeline
approved;
LNG
terminal
pending
in
Bahamas
Existing
and
Proposed
North
American
LNG
Terminals
June
2004
FERC
Office
of
Energy
Projects
A
C
1
3
5
2
4
32
7
27
15
6
24
28
9
19
8
26
22
21
33
35
34
36
20
29
30
11
37
10
12
17
13
B
31
25
14
39
40
16
38
23
18
D
41
US
Jurisdiction
FERC
US
Coast
Guard
42
43
Figure
2:
Existing
and
Proposed
North
American
LNG
Import
Terminals
12U.
S.
Federal
Energy
Regulatory
Commission,
2004.
"
LNG
Briefing,"
http://
www.
ferc.
gov/
industries/
gas/
indus­
act/
lng­
briefing.
pps,
April
2004.

13
Hall,
Wayne
F.
2004.
"
The
North
American
LNG
Supply
Chain:
Strategies
for
Economic
Growth,"
World
Energy,
Vol.
7,
No.
1,
http://
www.
worldenergysource.
com/
articles/
pdf/
hall_
WE_
v7n1.
pdf.
Page
6
of
29
0
5
10
15
20
25
30
35
40
45
In­
Service
and
Approved
Pending
­

FERC
Pending
­

Coast
Guard
Planned
B
c
f
p
e
r
D
a
y
Planned
Pending
­
Coast
Guard
Pending
­
FERC
In­
Service
and
A
pproved
As
shown
in
Figure
3,
the
Federal
Energy
Regulatory
Commission
(
FERC)
estimates
that
the
planned
and
pending
LNG
import
terminals
will
tripled
the
U.
S.
capacity
to
import
LNG.
12
However,
not
all
planned
LNG
import
terminals
will
be
built.
It
is
estimated
that
in
order
to
provide
the
needed
LNG
supply
to
the
U.
S.
gas
system,
10
to
12
LNG
import
terminals
will
be
built
within
the
decade
with
an
investment
of
more
than
$
5
billion.
13
Figure
3:
Existing
and
Proposed
North
American
LNG
Terminals
2.1
New
Onshore
LNG
Import
Terminals
Current
information
indicates
that
all
new
onshore
LNG
import
terminals
are
proposing
to
use
LNG
vaporization
systems
with
no
wastewater
discharges
(
e.
g.,
integration
with
other
industrial
facilities,
ambient
air
vaporization
through
heating
towers,
gas­
fired
heaters).
Table
2
lists
proposed
new
onshore
LNG
import
terminals
and
their
vaporization
design.
14
E­
mail
communication
from
James
Martin,
FERC,
to
Carey
A.
Johnston,
U.
S.
EPA,
August,
4,
2004.

Page
7
of
29
Table
2:
Proposed
U.
S.
Onshore
LNG
Import
Terminals14
No.
Project
Name/
Operator/
FERC
Docket
No.
Location
Sendout
Capacity
Vaporizer
Design
1
Freeport
LNG
Project
(
Cheniere/
Freeport)

CP03­
75­
000
$
400
million
facility
cost
Freeport,
TX
1.5
Bcf/
d
Closed­
loop:

Air
heat
exchanger
(
heating
tower)

Supplemental
gas­
fired
heater
for
cold
weather
2
Sabine
Pass
LNG
and
Pipeline
Project
(
Cheniere)

CP04­
38­
000
CP04­
47­
000
$
600
million
facility
cost
Cameron
Parish,
LA
(
across
from
Sabine
Pass)
2.6
Bcf/
d
Closed­
loop:

Gas­
fired
heater
3
Cheniere
Corpus
Christi
LNG
Terminal
and
Pipeline
Project
(
Cheniere)

CP04­
37­
000
CP04­
44­
000
$
450
million
facility
cost
Corpus
Christi,
TX
2.6
Bcf/
d
Closed­
loop:

Gas­
fired
heater
4
Golden
Pass
LNG
Terminal
and
Pipeline
Project
(
ExxonMobil)

PF04­
1­
000
$
600
million
facility
cost
Sabine,
TX
Phase
1:

1
Bcf/
d
Phase
2:

2
Bcf/
d
Closed­
loop:

Gas­
fired
heater
No.
Project
Name/
Operator/
FERC
Docket
No.
Location
Sendout
Capacity
Vaporizer
Design
Page
8
of
29
5
Vista
del
Sol
LNG
Terminal
Project
(
ExxonMobil)

PF04­
3­
000
PF04­
9­
000
$
600
million
facility
cost
Corpus
Christi,
TX
Phase
1:

1
Bcf/
d
Closed­
loop:

Gas­
fired
heater
6
Ingleside
Energy
Center
LNG
Project
(
Occidental)

PF04­
9­
000
Corpus
Christi,
TX
1
Bcf/
d
Closed­
loop:

Water
heat
exchanger
(
waste
water
from
the
chemical
plant)

7
Port
Arthur
LNG
Receiving
Terminal
Project
(
Sempra)

Docket
No.
PF04­
11­
000
Port
Arthur,
TX
1.5
Bcf/
d
Closed­
loop:

Gas­
fired
heater
8
Cameron
LNG,
LLC
(
Sempra
Energy)

CP02­
374­
000
CP02­
376­
000
CP02­
377­
000
CP02­
378­
000
$
700
million
facility
cost
Hackberry,
LA
1.5
Bcf/
d
Closed­
loop
9
Weaver's
Cove
LNG
CP04­
36­
000
$
250
million
facility
cost
Fall
River,
MA
0.4
Bcf/
d
Closed­
loop:
Gas­
fired
heater
10
BP
Crown
Landing
LNG
PF04­
2­
000
PF04­
5­
000
$
500
million
facility
cost
Logan
Township,
NJ
1.2
Bcf/
d
Closed­
loop:
Gas­
fired
heater
No.
Project
Name/
Operator/
FERC
Docket
No.
Location
Sendout
Capacity
Vaporizer
Design
Page
9
of
29
11
Long
Beach
LNG
(
Sound
Energy
Solutions)

CP04­
58­
000
$
400
million
facility
cost
Long
Beach,
CA
0.7
Bcf/
d
Closed­
loop:
Gas­
fired
heater
12
Keyspan
&
BG
LNG
CP04­
223­
000
CP04­
293­
000
Providence,
RI
0.5
Bcf/
d
Closed­
loop:
Gas­
fired
heater
13
Somerset
LNG
Somerset,
MA
14
Cheniere
Mobile
Mobile,
AL
(
Pinto
Island)
1.0
Bcfd
Closed­
loop
15
Cherry
Point
Energy
LLC
­
online
in
2008
Columbia
River,
OR
0.5
Bcf/
d
16
Somerset
LNG
Somerset,
MA
17
Waterbury
LNG
­
online
in
2007
Waterbury,
CT
1.2
Bcf/
d
18
Cheniere
LNG
Brownsville,
TX
2
Bcf/
d
Note:
The
FERC
docket
for
each
onshore
LNG
import
terminal
can
be
accessed
using
the
docket
number
and
the
following
website:

http://
elibrary.
ferc.
gov/
idmws/
docket_
search.
asp.
15The
Federal
OCS
starts
approximately
10
miles
from
the
Florida
and
Texas
shores.

16U.
S.
Coast
Guard,
2004.
Deepwater
Ports
Standards
Division
Website,
http://
www.
uscg.
mil/
hq/
gm/
mso/
mso5.
htm.
Page
10
of
29
2.2
New
Offshore
LNG
Import
Terminals
EPA
identified
eleven
company
announcements
of
proposed
U.
S.
offshore
LNG
import
terminals
with
one
company
proposing
a
pilot
study
(
see
Table
3).
A
large
majority
of
the
these
facilities
are
planned
for
the
Federal
Outer
Continental
Shelf
in
the
Gulf
of
Mexico
(
GOM).
The
Federal
OCS
generally
starts
three
miles
from
shore
and
extends
out
to
the
outer
territorial
boundary
(
about
200
miles).
15
The
U.
S.
Coast
Guard
is
responsible
for
developing
and
maintaining
regulations
and
standards
for
deepwater
ports.
Current
projects
include
regulations
for
deepwater
ports
(
33
CFR
Subchapter
NN),
specifically
updating
existing
rules
and
adding
provisions
for
natural
gas.
The
passage
of
the
Maritime
Transportation
Security
Act
of
2002
(
MTSA),
which
added
natural
gas
to
the
Deepwater
Port
Act,
heightened
interest
within
the
energy
industry
to
develop
deepwater
ports.

The
U.
S.
Coast
Guard
has
primary
authority
over
construction
and
siting
of
offshore
LNG
facilities,
and
oversees
preparation
of
environmental
impact
statements
that
examine
the
potential
impact
of
the
new
facilities,
as
required
by
the
National
Environmental
Policy
Act
and
the
Deepwater
Port
Act
of
1974
(
DWPA),
as
amended
(
33
USC
1501
et
seq).
As
specified
by
the
DWPA,
the
environmental
review
and
analysis
must
be
completed
within
356
days
of
the
published
Notice
of
Intent.
Coast
Guard
oversight
of
the
offshore
facilities
continues
as
long
as
the
facilities
are
operational,
as
the
agency
has
responsibility
for
the
safety
and
security
of
LNG
facilities
and
vessels
in
U.
S.
coastal
waters.
(
DOE
2004)
Eight
deepwater
port
license
applications
have
been
received
since
the
MTSA
was
signed
into
law.
16
EPA
was
able
to
use
information
in
these
deepwater
port
license
applications
to
characterize
the
wastewater
discharges
for
some
of
these
proposed
offshore
LNG
import
terminals.
Page
11
of
29
Table
3:
Proposed
U.
S.
Offshore
LNG
Import
Terminals
No.
Company
(
Facility
Name)
Offshore
Location
EPA
NPDES
Permit
Information
USCG
Deepwater
Port
Licensing
Information
(
Docket
No.)

1
Excelerate
(
GOM
Energy
Bridge)
West
Cameron
603
­
GOM
100
miles
offshore
LA
Yes
Yes
(
14294)

2
ChevronTexaco
(
Port
Pelican)
Vermillion
140
­
GOM
37
nautical
miles
from
LA
Yes
Yes
(
14134)

3
Shell
(
Gulf
Landing)
West
Cameron
213
­
GOM
38
nautical
miles
from
LA
Yes
Yes
(
16860)

4
BHP
Billiton
(
Cabrillo
Port)
Offshore
Oxnard,
CA
13.9
miles
from
CA
No
Yes
(
16877)

5
ConocoPhillips
(
Compass
Port)
Mobile
Block
910
88o12'
West,
30o5'
North
No
Yes
(
17659)

6
Freeport
McMoRan
(
Main
Pass
Energy
Hub)
Main
Pass
299
­
GOM
16
miles
from
LA
No
Yes
(
17696)

7
Crystal
Energy
(
Clearwater
Port)
Offshore
Ventura,
CA
11
miles
from
CA
No
Yes
(
TBD)

8
ExxonMobil
(
Pearl
Crossing)
West
Cameron
220
­
GOM
41
miles
offshore
LA
No
Yes
(
18474)

9
ChevronTexaco
(
Port
Penguin)
Offshore
CA
Exact
Location:
TBD
No
No
No.
Company
(
Facility
Name)
Offshore
Location
EPA
NPDES
Permit
Information
USCG
Deepwater
Port
Licensing
Information
(
Docket
No.)

Page
12
of
29
10
El
Paso
Global
Offshore
Belmar,
NJ
Exact
Location:
TBD
No
No
11
Excelerate
Energy
(
Northeast
Gateway)
Offshore
Boston,
MA
Exact
Location:
TBD
No
No
12
Conversion
Gas
Imports
Vermillion
179
­
GOM
No
No
Note:
"
EPA
NPDES
Permit
Information"
indicates
whether
the
company
has
applied
for
an
NPDES
permit
application.
"
USCG
Deepwater
Port
Licensing
Information"
indicates
whether
the
company
has
applied
for
a
deepwater
port
license.
The
USCG
docket
for
each
Deepwater
Port
license
application
can
be
accessed
using
the
docket
number
and
the
following
website:

http://
dms.
dot.
gov/
search/
searchFormSimple.
cfm.
17El
Paso
Energy
Bridge
GOM
LLC
Application
for
Deepwater
Port
License,
http://
dmses.
dot.
gov/
docimages/
pdf84/
219001_
web.
pdf,
December
20,
2002.

18U.
S.
EPA,
2003.
El
Paso
Energy
Bridge
Gulf
of
Mexico,
LLC
Draft
NPDES
Permit
No.
GM0000003,
Fact
Sheet,
http://
www.
epa.
gov/
region6/
6wq/
npdes/
genpermt/
gm3factsheet.
pdf.
Page
13
of
29
Excelerate
­
GOM
Energy
Bridge
Excelerate
is
proposing
to
construct,
own,
and
operate
an
LNG
import
terminal
100
miles
offshore
in
the
GOM.
The
Excelerate
GOM
Energy
Bridge
deepwater
port
will
consist
of
a
submerged
turret
loading
(
STL)
system
that
is
comprised
of
a
submerged
turret
buoy;
chains,
lines
and
anchors;
a
flexible
riser;
and
a
subsea
manifold.
Gas
will
be
delivered
to
the
deepwater
port
by
conventional
LNG
vessels
which
incorporate
shipboard
re­
gasification
capabilities.
17
The
vessels
that
will
be
used
to
deliver
natural
gas
to
the
Excelerate
GOM
Energy
Bridge
deepwater
port
will
have
a
capacity
to
hold
138,000
m3
of
LNG
and,
unlike
all
other
LNG
vessels
currently
in
operation,
will
re­
gasify
the
LNG
on­
board
at
the
point
of
delivery
so
that
imports
will
consist
of
gas
in
its
vaporous
state,
rather
than
in
a
liquefied
state.
The
a
water
depth
at
this
deepwater
port
is
280
feet.
18
This
import
terminal
will
vaporize
and
deliver
natural
gas
on
average
approximately
0.55
Bcfd
of
LNG.
A
fully
loaded
LNG
vessel
will
be
able
to
discharge
its
cargo
in
about
six
to
eight
days,
depending
on
operating
conditions.
The
approximate
cost
of
the
STL
subsea
system
is
$
50.7
million
with
a
projected
completion
date
of
December
2004.

The
draft
Environmental
Assessment
for
the
Excelerate
(
formerly
El
Paso
Energy
Bridge
Gulf
of
Mexico,
LLC)
LNG
import
terminal
notes
that
the
total
seawater
demand
for
the
vessel
is
133
million
gallons
per
day
(
MGD).
The
sea
water
intake
serves
the
following
purposes:
(
1)
total
demand
dedicated
to
the
regasification
system
(
76.1
MGD);
(
2)
vessel's
main
condenser
cooling
system
(
46.9
MGD);
and
(
3)
vessel's
other
cooling
systems
(
10
MGD).

Each
specially
configured
LNG
vessel
will
integrate
complete
offshore
re­
gasification
capabilities
into
its
shipboard
system.
The
re­
gasification
system
can
operate
in
open
loop
mode,
closed
loop
mode,
or
together
in
a
combination
mode.
In
the
open
loop
mode,
the
LNG
vessel
will
intake
seawater
from
the
surrounding
area
to
heat
the
LNG.
The
warm
seawater
will
pass
through
the
shell
and
tube
vaporizer
indirectly
heating
the
LNG.
Then
the
LNG
vessel
will
discharge
this
water
through
its
keel.

In
the
closed
loop
mode,
steam
from
the
LNG
vessel
propulsion
boilers
will
heat
water
circulated
in
a
closed
loop
through
the
shell
and
tube
vaporizer
and
a
steam
heater.
After
the
cycle,
the
water
will
be
re­
circulated
through
the
system.
There
is
no
seawater
intake
or
discharge
for
the
re­
gasification
process
in
the
closed
loop
mode.
The
closed
loop
mode
allows
for
LNG
regasification
when
surrounding
seawater
temperatures
are
too
cold
for
the
more
efficient
open
loop
mode.
In
the
open
loop
mode,
the
system
can
re­
gasify
up
to
0.69
Bcfd.
However,
due
to
operating
constraints
related
to
downstream
pipelines,
the
system
for
the
Excelerate
LNG
import
terminal
will
re­
gasify
a
maximum
of
0.55
Bcfd
in
the
open
loop
mode.
Closed
loop
steam
operations
can
re­
gasify
up
to
0.45
Bcfd.
19U.
S.
EPA,
2003.
Port
Pelican
LLC
Draft
NPDES
Permit
No.
GM0000001,
Fact
Sheet,
http://
www.
epa.
gov/
earth1r6/
6wq/
npdes/
genpermt/
draftgm0000001.
pdf.

20Port
Pelican
LLC
Application
for
Deepwater
Port
License,
http://
dmses.
dot.
gov/
docimages/
pdf84/
210833_
web.
pdf,
December
27,
2002.

21Draft
Environmental
Impact
Statement
for
Port
Pelican
LLC
Deepwater
Port
License
Application,
http://
dmses.
dot.
gov/
docimages/
pdf86/
244607_
web.
pdf,
Page
14
of
29
Excelerate
is
proposing
to
operate
the
specially
configured
LNG
vessels
in
open
loop
mode
exclusively.
(
USCG,
2003)
The
open
loop
mode
would
draw
seawater
from
the
surrounding
area
at
approximately
23.0
ft
below
the
water
surface.
Intake
structures
on
the
LNG
vessels
are
sized
to
provide
approximately
133
MGD
seawater
for
both
standard
ship
operations
(
57
MGD)
and
the
warming
water
for
the
LNG
vaporizers
(
76
MGD).

All
of
the
seawater
entering
the
sea
chest
intakes
either
for
ship
operations
or
for
the
regasification
process
will
pass
through
a
copper
cathode
antifouling
system.
The
copper
anodes
release
a
small
amount
of
copper
into
the
ships
seawater
system
at
the
intake
to
prevent
biota
in
the
seawater
from
establishing
within
the
seawater
flow
path.
This
will
also
control
non­
native
species.
The
copper
concentration
in
all
of
the
seawater
discharge
will
be
approximately
0.002
mg/
L
(
2
ppb).

ChevronTexaco
­
Port
Pelican
Port
Pelican
LLC,
a
subsidiary
of
ChevronTexaco,
is
proposing
to
construct,
own,
and
operate
an
LNG
import
terminal
37
nautical
miles
offshore.
19
The
water
depth
at
the
offshore
LNG
import
terminal
will
be
approximately
79
to
86
feet.
The
Port
Pelican
import
terminal
will
consist
of
two
concrete
gravity
based
structure
(
GBS)
units
fixed
to
the
seabed,
which
will
include
integral
LNG
storage
tanks,
support
deck
mounted
LNG
receiving
and
vaporization
equipment
and
utilities,
berthing
accommodations
for
LNG
carriers,
facilities
for
delivery
of
natural
gas
to
a
pipeline
transportation
system,
and
personnel
accommodations.
20
The
Port
Pelican
import
terminal
will
be
constructed
in
two
phases.
Phase
I
includes
the
installation
of
two
GBS
structures
with
internal
storage
tanks
and
facilities
for
LNG
offloading,
send
out
and
vaporization
to
deliver
a
peak
1.0
Bcfd
of
natural
gas
to
pipeline.
Phase
II
will
increase
the
capacity
to
2.0
Bcfd
of
natural
gas
to
pipeline.
The
approximate
cost
for
this
project
is
approximately
$
800
million
for
both
phases.
Phase
I
is
expect
to
be
complete
by
2006
with
Phase
II
completed
by
2008.
The
following
information
comes
from
the
Port
Pelican
LLC
application
for
deepwater
port
license
and
draft
Environmental
Impact
Statement.
21
Sea
water
will
flow
through
intake
screens
to
eliminate
debris
and
marine
life
before
being
pumped
to
the
vaporizers
through
strainers.
To
control
biofouling,
sodium
hypochlorite
will
be
injected
into
the
pump
suction
to
achieve
a
free
chlorine
concentration
of
0.2
ppm.
In
addition,
each
pump
will
be
shocked
for
20
minutes
three
times
per
day
at
a
level
of
2.0
ppm
free
chlorine.
Page
15
of
29
Two
parallel
vaporization
trains
(
average
capacity
of
0.8
Bcfd
and
peak
capacity
of
1.0
Bcfd
each)
will
be
provided,
one
in
Phase
I
and
a
second
in
Phase
II,
to
vaporize
LNG
and
deliver
natural
gas
at
a
pressure
of
up
to
1,440
psig.
Each
1.0
Bcfd
train
consists
of
six
0.2
Bcfd,
each
with
an
LNG
sendout
pump,
an
Open
Rack
Vaporizer
(
ORV),
and
a
seawater
lift
pump.
Five
of
the
six
trains
will
be
operating
during
peak
sendout
rate
(
1.0
Bcfd
each),
and
one
will
be
used
as
a
spare.
The
LNG
flow
rate
will
be
approximately
178
tons/
hour
to
deliver
0.2
Bcfd
of
gas.

The
LNG
sendout
pumps
will
discharge
LNG
into
the
ORVs
where
it
is
warmed
and
flashed
by
seawater
heat
exchange
at
a
peak
vaporizing
capacity
of
0.2
Bcfd.
ORV
technology
uses
seawater
flowing
over
a
series
of
panel
coils
to
warm
the
LNG
that
is
flowing
countercurrent
within
the
panels
(
Figure
4).
Sea
water
flows
through
intake
screens
to
eliminate
debris
and
marine
life,
and
is
then
pumped
to
ORVs
through
strainers.

Figure
4:
Open
Rack
Vaporizer
(
from
Port
Pelican
LLC
Deepwater
Port
License
Application)
22Gulf
Landing
LLC
Application
for
Deepwater
Port
License,
http://
dmses.
dot.
gov/
docimages/
pdf88/
265164_
web.
pdf,
January
14,
2004.

23U.
S.
EPA,
2003.
Gulf
Landing
LLC
Draft
NPDES
Permit
No.
GM0000004,
Fact
Sheet,
http://
www.
epa.
gov/
earth1r6/
6wq/
npdes/
gmpn/
gm4fact.
pdf.
Page
16
of
29
Seawater
lift
pumps
bring
treated
seawater
to
the
top
of
ORVs.
From
there
it
cascades
over
the
ORV
panel
coils
and
creates
a
falling
film
of
water
which
exchanges
heat
with
the
upward­
flowing
high
pressure
LNG
from
the
sendout
pumps.
This
process
will
warm
the
LNG
to
approximately
35
º
F
and
in
the
process
vaporize
it;
and
it
will
cool
the
water
by
approximately
20
°
F.
The
cooled
water
is
collected
in
a
concrete
basin
and
discharged
to
the
GOM
after
it
passes
once
through
the
system.

The
maximum
seawater
intake
rate
is
12,250
gallons
per
minute
(
GPM)
per
pump
with
an
intake
velocity
of
0.5
feet
per
second
(
fps)
per
pump.
Seawater
then
flows
from
the
bottom
of
the
ORVs
into
a
trench
routed
to
the
seawater
outfall.
At
peak
capacity,
the
seawater
lift
pumps
will
circulate
88.2
MGD
of
water
through
the
ORVs
during
Phase
I
(
five
out
of
six
trains
in
use),
and
at
the
completion
of
the
Phase
II
expansion,
water
circulated
would
be
176.4
MGD
(
10
out
of
12
trains
in
use).
During
normal
operations,
four
trains
will
circulate
70.5
MGD
of
seawater
during
Phase
I,
and
eight
trains
will
circulate
141
MGD
of
seawater
during
Phase
II
through
the
ORVs.

Shell
­
Gulf
Landing
The
Shell
Gulf
Landing
LNG
terminal
facility
(
Gulf
Landing
LLC)
will
receive
LNG
from
marine
vessels,
store
the
gas,
then
re­
gasify
the
LNG
and
deliver
it
to
pipelines
for
distribution
and
sales
to
the
United
States.
The
facility
throughput
is
planned
at
7.7
million
tonnes
per
annum
of
LNG.
This
will
be
provided
by
approximately
135
carriers
per
year,
dependent
upon
the
size
of
the
carriers
used.
Each
LNG
carrier
will
unload
its
cargo
into
the
terminal
storage
tanks.
This
process
takes
approximately
24
hours
from
arrival
to
departure.
The
facility
will
vaporize
and
deliver
natural
gas
at
a
rate
of
approximately
1.0
Bcfd
on
a
continuous
basis.
The
approximate
cost
is
$
700
million.
Installation
of
the
terminal
is
schedule
for
the
4th
quarter
of
2008
with
the
first
deliveries
of
LNG
schedule
for
January
2009.22
Gulf
Landing
LLC
has
proposed
discharges
from
six
outfalls:
(
1)
thermal
water
for
open
rack
vaporizer
(
ORV)
at
136
MGD;
(
2)
deck
drainage
wastewater
at
0.0058
MGD;
(
3)
uncontaminated
deck
water
at
0.0209
MGD;
(
4)
desalinization
rejected
water
at
0.0254
MGD;
(
5)
treated
sanitary
&
domestic
wastewater
at
0.0075
MGD;
and
(
6)
firewater
bypass
at
0.5035
MGD.
23
Outfall
001
discharges
seawater
that
is
passed
through
the
ORV
process
system.
Seawater
from
the
intake
structure
is
screened
and
treated
with
sodium
hypochlorite
at
the
intake
pumps
to
control
marine
growth
in
the
system.
The
treated
seawater
is
then
distributed
to
the
ORV
system.
The
ORV
serves
as
the
warming
energy
to
gasify
the
LNG.
The
water
is
cooled
during
this
heat
exchange
to
about
18oF
from
the
ambient
intake
seawater
temperature.
24Cabrillo
Port
Application
for
Deepwater
Port
License,
http://
dmses.
dot.
gov/
docimages/
p77/
265927.
doc,
January
21,
2004.
Page
17
of
29
The
seawater
is
treated
with
sodium
hypochlorite,
at
a
continuos
rate
of
approximately
2.0
mg/
l.
Periodically,
each
pump
will
be
shocked
with
5.0
mg/
l
for
one
hour
during
every
8­
hours
of
pump
run
time.
At
capacity,
the
facility
will
have
four
pumps.

BHP
Billiton
­
Cabrillo
Port
The
BHP
Billiton
proposes
to
construct,
own,
and
operate
an
LNG
import
terminal,
Cabrillo
Port,
approximately
13.9
miles
off
the
coast
of
Ventura
County
in
Southern
California,
in
2,900
feet
of
water.
The
permanently
moored
import
facility
(
floating
storage
&
re­
gasification
unit)
will
include
three
storage
tanks,
eight
vaporizers,
and
an
underwater,
21.1
mile
pipeline
that
would
connect
to
an
existing
onshore
pipeline.
Maximum
water
depth
at
the
location
of
the
planned
mooring
is
about
2,900
feet.
The
floating
storage
and
re­
gasification
facility
will
vaporize
and
deliver
natural
gas
at
a
maximum
rate
of
approximately
1.5
billion
cubic
foot
a
day,
with
an
anticipated
average
rate
of
0.6
to
0.9
Bcfd.
The
BHP
Billiton
LNG
import
terminal
is
designed
to
accommodate
LNG
carriers
ranging
in
capacity
from
100,000
m3
to
220,000
m3.
LNG
carriers
typically
will
be
offloaded
at
a
rate
of
80,000
gallons
per
minute
of
LNG
through
the
liquid
loading
arms
and
stored
in
the
LNG
storage
tanks
at
a
temperature
of
approximately
minus
260
°
F.
This
LNG
import
terminal
is
projected
to
have
320,000
m3
in
storage
capacity
at
the
receiving
facility.
The
approximate
cost
of
this
project
is
$
550
million
with
a
projected
completion
date
of
2008.
The
following
information
comes
from
the
Cabrillo
Port
application
for
deepwater
port
license.
24
The
BHP
Billiton
LNG
import
terminal
is
designed
to
no
use
sea
water
for
the
regasification
process.
This
facility
is
proposing
to
use
submerged
combustion
vaporizers
using
LNG
as
the
fuel.
The
LNG
is
pumped,
as
liquid,
up
to
the
1,500
psig
natural
gas
send
out
pressure
and
maintained
at
that
pressure
through
the
vaporization
process.
The
vaporization
portion
of
the
process
re­
gasifies
the
LNG.
The
process
will
consist
of
eight
submerged
combustion
vaporizers
(
SCVs).
Each
will
have
a
maximum
capacity
of
198
short
tons
per
hour
of
LNG
vaporized.
The
SCVs
will
superheat
the
resultant
natural
gas
to
a
temperature
of
about
41
°
F
at
a
pressure
of
about
1,500
psig.
The
combustion
vaporization
process
is
thermally
stabilized
by
submersion
in
a
water
bath.
No
compression
of
the
natural
gas
is
required.

BHP
Billiton
evaluated
several
options
including
the
intermediate
fluid
vaporizers
(
IFV)
and
open
rack
vaporizers
(
ORV).
IFV
and
ORV
use
seawater
as
a
heat
source
while
SCV
uses
natural
gas
combustion.
For
the
BHP
Billiton
LNG
import
terminal
the
IFV
and
ORV
alternatives
would
require
about
50
MGD
of
seawater.
In
these
alternatives,
seawater
would
flow
through
the
vaporizers
and
then
would
be
returned
to
the
ocean
at
a
lower
than
ambient
temperature.
BHP
Billiton
identified
that
the
primary
benefit
of
IFV
and
ORV
relative
to
the
proposed
SCV
is
lower
air
emissions.
SCV
burns
natural
gas
equivalent
to
2%
of
the
LNG
throughput
to
generate
heat.
Other
industry
estimates
suggest
that
this
energy
penalty
is
closer
to
1.5%.
(
Hall,
2004)
The
combustion
process
relies
on
natural
gas
from
LNG,
so
it
is
a
cleaner
fuel.
With
SCV
the
exhaust
Page
18
of
29
gases
also
flow
directly
through
a
water
bath,
which
acts
as
a
quench
and
abatement
system.
The
SCV
air
emissions
will
include
oxides
of
nitrogen
(
NOx),
and
carbon
dioxide.
IFV
and
ORV
would
introduce
some
air
emissions,
which
are
of
an
order
of
magnitude
less
than
SCV's
because
of
the
incremental
electricity
necessary
to
operate
the
large
seawater
pumps.

BHP
Billiton
identified
concerns
over
the
potential
intake
of
50
MGD
of
seawater
associated
with
the
IFV
and
ORV
alternatives.
Specifically,
BHP
Billiton
identified
concerns
over
entrainment
and
impingement
of
marine
species,
thermal
plumes,
turbidity,
treated
water
discharge
and
noise.
Impingement
could
occur
when
fish
and
other
aquatic
life
are
trapped
against
the
water
intake
screens.
These
screens
prevent
marine
organisms
and
debris
from
entering
and
interfering
with
the
re­
gasification
process.
Entrainment
occurs
when
aquatic
organisms,
including
eggs
and
larvae,
are
drawn
into
the
water
intakes,
through
the
facility,
and
then
pumped
back
out.

Thermal
plumes
could
result
from
the
constant
discharge
of
large
quantities
of
relatively
cold,
and
therefore
relatively
dense,
water.
BHP
Billiton
identified
that
the
proposed
mooring
location
is
of
sufficient
depth
that
a
thermal
plume
would
not
be
likely
to
impact
the
sea
floor.
Turbidity
would
be
a
result
of
a
thermal
plume
disturbing
sea
floor
sediments.
Additionally,
the
IFV
and
ORV
alternatives
would
likely
use
sodium
hypochlorite
or
another
oxidizer
to
control
the
growth
of
marine
organisms
in
the
IFV
and
ORV
equipment.
BHP
Billiton
identified
that
discharge
of
the
residual
sodium
hypochlorite
in
IFV
and
ORV
water
could
impact
marine
organisms,
and
would
require
a
NPDES
permit.
Noise
would
be
generated
by
the
large
seawater
pumps
required
for
the
seawater
intake
alternatives.

In
general,
BHP
Billiton
identified
that
the
use
of
IFV
and
ORV
would
be
difficult
to
permit
and
operate
because
of
water
discharge
rules
and
restrictions
and
impacts
to
marine
biota.
The
use
of
SCV
would
produce
air
emissions
that
could
be
minimized
by
emission
control
technology.
BHP
Billiton
selected
SCV
for
the
proposed
re­
gasification
process.

ConocoPhillips
­
Compass
Port
Compass
Port
LLC,
a
wholly
owned
subsidiary
of
ConocoPhillips
Company,
proposes
to
construct,
own,
and
operate
an
LNG
import
terminal
33
miles
from
the
southern
city
limit
of
Mobile,
Alabama
and
11
miles
south
of
Dauphin
Island,
Alabama,
in
a
water
depth
of
approximately
70
feet.
The
facility
will
vaporize
and
deliver
natural
gas
at
a
rate
of
approximately
1
billion
cubic
foot
a
day
on
a
continuous
basis.
The
maximum
unloading
period
for
a
ship
is
designed
to
be
20
hours
at
this
LNG
import
terminal.
To
achieve
this
rate,
the
unloading
system
will
be
designed
to
deliver
255,000
cubic
meters
of
LNG
from
a
ship
to
the
storage
tanks
within
12
to
14
hours.
The
expected
completion
date
is
2009.

As
shown
in
Figure
5,
Compass
Port
LLC
import
terminal
will
incorporate:
(
1)
docking
facilities
for
conventional
LNG
carriers;
(
2)
unloading
facilities
for
the
unloading
of
LNG
cargo;
(
3)
two
full
containment
tanks
for
the
storage
of
LNG;
(
4)
re­
gasification
facilities
to
convert
25Compass
Port
Application
for
Deepwater
Port
License,
http://
dmses.
dot.
gov/
docimages/
pdf89/
284087_
web.
pdf,
March
29,
2004.
Page
19
of
29
LNG
into
natural
gas;
(
5)
an
offshore
natural
gas
pipeline;
and
(
6)
related
facilities
to
support
the
operation
of
Compass
Port.
25
Construction
and
installation
of
the
proposed
port
will
take
approximately
42
months
to
complete,
beginning
in
2005,
providing
for
approximately
12
months
for
pre­
construction
activities.
The
following
information
comes
from
the
Compass
Port
LLC
application
for
deepwater
port
license.

Figure
5:
Compass
Port
LLC
Proposed
LNG
Import
Terminal
The
Compass
Port
LLC
import
terminal
will
consist
of
two
concrete
gravity­
based
structures
fixed
to
the
seabed
that
contain
the
integral
LNG
storage
tanks,
the
LNG
regasification
facilities,
and
other
operational
equipment
including
mooring
platforms,
a
docking
platform
that
contains
LNG
unloading
equipment,
and
a
flare
platform.
There
also
will
be
a
separate
platform
for
support
facilities
such
as
personnel
quarters,
and
other
auxiliary
structures.

The
Compass
Port
LLC
import
terminal
will
utilize
a
total
of
six
water
intake
structures
and
ORV
for
the
re­
gasification
process.
Each
intake
structure
will
consist
of
a
hollow
steel
caisson
that
will
extend
from
a
manifold
on
the
cellar
deck
of
the
re­
gasification
platform
to
beneath
the
water
surface.
Each
steel
caisson
will
be
fixed
to
the
re­
gasification
platform
jacket
structure
by
a
series
of
welded
supports.
A
submersible
pump
will
be
located
in
each
intake
structure
and
will
have
a
maximum
design
pumping
capacity
of
30.4
MGD.
In
normal
operation
only
four
pumps
are
working
and
in
cold
weather
conditions
five
pumps
are
working
for
a
total
design
intake
flow
of
152.2
MGD.
The
sixth
pump
is
a
kept
and
maintained
as
a
spare.
26Deepwater
Port
License
Application
for
the
Main
Pass
Energy
Project,
http://
dmses.
dot.
gov/
docimages/
pdf89/
284544_
web.
pdf,
February
2004.
Page
20
of
29
To
minimize
biological
fouling,
seawater
will
be
treated
with
sodium
hypochlorite
applied
at
a
continuous
rate
of
approximately
0.2
mg/
l.
Periodically,
each
pump
will
be
shocked
with
2.0
mg/
l
of
hypochlorite
for
20
minutes
during
every
8
hours
of
pump
run
time.
The
facility
will
not
shock
any
more
than
one
unit
at
a
time.

Freeport
McMoRan
­
Main
Pass
Energy
Hub
The
Main
Pass
Energy
Hub
(
MPEH)
is
proposed
to
deliver
an
average
of
1.0
Bcfd
of
LNG.
The
water
depth
at
the
LNG
import
terminal
is
approximately
210
feet.
The
project
involves
the
reuse
of
four
existing
platforms
and
three
smaller
bridge
supports
along
with
the
interconnecting
bridges
formerly
used
in
sulphur
mining
operations
at
Main
Pass
299.
This
LNG
import
terminal
will
use
salt
caverns
its
design
and
ORVs
to
re­
gasify
LNG
at
a
design
capacity
of
1.6
Bcfd.
26
The
vaporized
natural
gas
heated
to
40
°
F.
The
approximate
cost
of
this
project
is
$
500
million
with
a
projected
completion
date
of
2006.
The
following
description
of
the
MPEH
is
from
the
deepwater
port
license
application
for
the
Main
Pass
Energy
Project.

At
peak
vaporization
rate,
all
the
ORVs
will
be
in
operation.
Nine
operating
ORVs
are
required
to
meet
the
1.6
Bcfd
design
vaporization
capacity
with
the
gas
conditioning
plant
in
operation.
ORVs
utilize
seawater
as
the
heating
medium
for
vaporization
of
LNG.
The
heat
transfer
surface
will
be
vertical,
panel­
shaped
tubes
of
aluminum­
zinc
alloy
for
seawater
resistance,
and
an
aluminum
base/
tube
assembly.
LNG
will
flow
upward
inside
finned
heat
transfer
tubes,
with
seawater
flowing
downward
along
the
outside
of
the
tubes.

Six
seawater
lift
pumps
will
be
provided,
each
with
a
design
capacity
of
33.4
MGD
(
total
of
approximately
200
MGD)
and
a
differential
head
of
120
psi.
Normally,
five
pumps
will
be
in
operation
and
one
will
be
an
installed
spare.
During
winter
operations
when
seawater
temperatures
are
lower,
the
sixth
seawater
lift
pump
may
be
operated
to
obtain
adequate
heat
transfer.
Seawater
will
be
pumped
to
the
top
of
the
ORVs
where
it
will
be
distributed
in
overhead
troughs
to
create
a
water
film
falling
as
a
sheet
in
contact
with
the
vertical
tube
surface.
The
seawater
temperature
will
be
reduced
by
approximately
22
°
F
through
the
ORV
and
will
be
collected
in
a
basin
for
discharge
back
to
the
sea.

Waters
used
in
the
vaporization
of
the
LNG
will
be
discharged
through
three
outfall
pipes
at
least
120
feet
(
37
meters)
below
MSL.
Each
outfall
pipe
will
have
two
45­
degree
deflectors
at
the
terminus
in
order
to
promote
mixing
with
the
surrounding
waters.
Sodium
hypochlorite
will
be
injected
continuously
into
the
suction
of
the
operating
seawater
lift
pumps
for
bio­
fouling
control
at
a
rate
to
attain
a
residual
chlorine
level
of
0.5
to
1.0
ppm.
The
system
will
be
designed
to
inject
up
to
2.0
ppm
continuously
and
up
to
5.0
ppm
on
a
"
shock"
basis
into
each
of
the
operating
pumps
and
operating
ORV
inlet
branch
headers
for
20
minutes
every
24
hours;
these
latter
shock
injections
will
be
staggered
so
that
no
more
than
one
point
is
shock­
dosed
at
any
one
time.
Operations
will
monitor
the
residual
chlorine
levels
and
adjust
the
dosing
rate
as
needed.
27Larson,
Eric,
2004.
Presentation
by
Eric
Larson,
California
Department
of
Fish
and
Game,
"
Navigational
Safety
&
Environmental
Issues",
http://
www.
energy.
ca.
gov/
lng/
documents/
2004­
02­
24_
DFG_
LARSON.
PDF,
February
24,
2004.

28Crystal
Energy
LLC,
2004.
Press
Release,
"
Crystal
Energy
Secures
Agreement
for
Domestic
Energy
Supply
to
Meet
Urgent
Natural
Gas
Demand,"
http://
www.
crystalenergyllc.
com/
pdf/
media/
AGPA.
pdf,
January
28,
2004.

29See
http://
www.
crystalenergyllc.
com/
faq_
operation.
php
30Crystal
Energy
LLC,
2004.
Press
Release,
"
Crystal
Energy
Moves
Forward
to
Bring
Needed
Natural
Gas
to
California,"
http://
www.
crystalenergyllc.
com/
pdf/
media/
CrystalFilingPressRelease_
FINAL.
pdf,
February
11,
2004.
Page
21
of
29
At
peak
capacity,
the
seawater
lift
pumps
will
circulate
approximately
200
MGD
of
water
through
the
ORVs.
ORV
maintenance
will
consist
of
occasional
cleaning,
the
frequency
of
which
will
depend
on
the
cleanliness
of
the
seawater.
Daily
observation
will
ensure
that
ice
does
not
build
up
on
the
panels.

Crystal
Energy
­
Clearwater
Port
Crystal
Energy
LLC
signed
a
long­
term
lease
agreement
to
retrofit
an
existing
offshore
oil
and
gas
facility
(
Platform
Grace),
located
11
miles
offshore
of
Ventura
County
in
federal
waters,
as
an
LNG
import
terminal.
The
water
depth
at
Platform
Grace
is
318
feet.
27
The
proposed
project
is
estimated
to
deliver
more
than
200
billion
cubic
feet
of
natural
gas
from
Alaska
annually
to
California.
28
Crystal
Energy
LLC
estimates
that
approximately
two
to
four
ships
per
month
will
offload
at
this
LNG
import
terminal.
Each
ship
will
carry
approximately
2.75
billion
cubic
feet
of
LNG,
which
will
take
approximately
four
days
to
offload.
The
peak
LNG
transmission
capacity
for
the
project
is
projected
to
be
1.275
Bcfd
with
an
average
LNG
transmission
capacity
of
0.8
Bcfd.
This
LNG
import
terminal
will
not
store
any
of
the
offloaded
LNG
at
the
receiving
facility
(
Platform
Grace).
The
approximate
costs
of
this
project
is
$
160
million
with
a
projected
completion
date
of
2006.

Use
of
this
platform
as
a
liquefied
natural
gas
receiving
and
processing
facility
will
require
the
installation
of
a
cool
down
tank,
four
liquefied
natural
gas
pumps,
four
liquefied
natural
gas
vaporizers,
and
reinstalling
and
upgrading
the
platform's
power
production
capability.
29
Crystal
Energy
LLC
recently
filed
its
deepwater
port
application
with
the
U.
S.
Coast
Guard,
however,
the
docket
for
this
application
has
not
been
established.
Initial
indications
are
that
this
facility
will
use
SCVs
to
re­
gasify
the
LNG
and
not
discharge
any
wastewaters
associated
with
its
vaporization
process.
This
project
also
identifies
that
it
would
supply
local
jurisdictions
with
"
up
to
40
million
gallons
of
clean
water
annually
that
are
a
byproduct
of
the
re­
gasification
process."
30
31Federal
Register.
69
FR
43619.
July
21,
2004.

32Deepwater
Port
License
Application
for
Pearl
Crossing
LNG
Project,
Environmental
Report,
http://
dmses.
dot.
gov/
docimages/
pdf89/
288088_
web.
pdf,
May
2004.
Page
22
of
29
Construction
costs
for
the
Crystal
Clearwater
Port
project,
which
is
anticipated
to
begin
operation
in
2007,
are
estimated
at
$
300
million.
The
estimated
life
of
the
facility
is
approximately
50
to
100
years.
This
is
based
upon
the
original
structural
design
of
the
platform
for
offshore
oil
and
gas
drilling
and
production
operations.

ExxonMobil
(
Pearl
Crossing)

The
application
plan
calls
for
the
proposed
deepwater
port
to
be
located
in
the
Gulf
of
Mexico,
approximately
41
miles
south
of
the
Louisiana
coast
in
West
Cameron
Block
220.
It
will
be
located
in
a
water
depth
of
approximately
62
feet.
31
The
proposed
Pearl
Crossing
LNG
Terminal
is
a
concrete
Gravity
Based
Structure
(
GBS).
The
terminal
proposes
to
install
two
integral
liquefied
natural
gas
storage
tanks
and
serve
as
the
platform
for
vessels
to
offload
and
regasify
LNG.
The
proposed
GBS
is
a
double­
walled
concrete
structure,
rectilinear
in
shape,
that
would
measure
approximately
590
feet
long
by
295
feet
wide.
The
structure
would
rest
on
the
seabed
with
a
total
terminal
footprint
(
GBS
plus
jacket
structures)
area
of
approximately
12
acres.
The
terminal
would
include
LNG
storage
tanks,
equipment
for
receiving
and
vaporization
of
LNG,
electric
power
generation,
water
purification,
nitrogen
generation,
sewage
treatment
and
accommodations
for
up
to
60
persons.
The
total
net
working
capacity
of
the
two
integral
LNG
storage
tanks
would
be
250,000
m3.

Pearl
Crossing
would
have
the
ability
to
accommodate
two
LNG
carriers
alongside
that
will
have
capacities
ranging
from
125,000
to
250,000
m3
per
vessel.
This
would
allow
one
incoming
LNG
carrier
to
be
secured
to
prepare
to
offload
cargo,
while
another
LNG
carrier
is
completing
an
offloading
cycle.
Offloading
rates
are
expected
to
equal
14,000
m3
per
hour
of
LNG.
Peak
send
out
for
this
project
is
projected
to
average
over
2.0
Bcfd
with
a
peak
capacity
of
2.8
Bcfd.

The
re­
gasification
process
would
be
accomplished
through
thirteen
electric
pumps
that
will
each
supply
19
MGD
of
seawater
for
the
ORV.
Assuming
a
inlet
to
outlet
water
temperature
decrease
of
20oF,
a
volume
of
247
MGD
of
surface
water
is
required
for
peak
vaporization.
32
Seawater
would
be
treated
with
hypochlorite
produced
by
an
electrolytic
chlorination
unit
prior
to
entering
the
seawater
pump
intake
lines.

ChevronTexaco
­
Port
Penguin
This
is
an
off­
shore
Gravity
Based
Structure
(
GBS)
project
similar
to
the
Chevron/
Texaco
project
proposed
for
Baja
California,
Mexico.
This
project
is
to
have
an
LNG
throughput
of
0.5
33See
http://
www.
energy.
ca.
gov/
lng/
projects.
html.

34See
http://
www.
conversiongas.
com/
html/
news.
html.
Page
23
of
29
Bcfd.
ChevronTexaco
has
discussed
the
project
publicly
but
has
not
proposed
a
specific
site.
The
location
of
this
project
has
yet
to
be
determined
but
will
most
likely
be
in
southern
California.
33
El
Paso
Global
(
Belmar,
NJ
Offshore)

EPA
was
unable
to
gather
information
on
this
facility.

Excelerate
Energy
(
Northeast
Gateway)

This
facility
is
proposed
to
be
sited
offshore
of
Boston,
MA.
The
average
vaporization
rate
is
projected
to
be
0.8
Bcfd
(
see
Figure
2).
EPA
was
unable
to
gather
additional
information
on
this
proposed
facility.

Conversion
Gas
Imports
Conversion
Gas
Imports
(
CGI)
is
conducting
a
study
using
salt
caverns
instead
of
manmade
storage
tanks
to
temporarily
store
LNG.
The
CGI
proposed
terminal
is
designed
to
receive
LNG
directly
from
the
tanker,
pump
the
liquid
stream
to
cavern
injection
pressures,
warm
it
to
salt
compatible
temperatures,
and
inject
the
warmed
dense
phase
natural
gas
into
salt
caverns
for
storage.
There
are
no
vaporizer
send­
out
limitations
associated
with
cavern
storage.
The
caverns
can
receive
flow
from
a
ship
and
redeliver
to
a
pipeline
grid
at
rates
greater
than
3
Bcfd.
LNG
vessels
are
offloaded
at
rates
comparable
to
the
unloading
rates
at
conventional
liquid
tank
based
terminals.

CGI
chose
a
Gulf
of
Mexico
location
in
30
meters
of
water,
75
kilometers
off
Louisiana
on
Vermilion
block
179,
for
the
upcoming
study
because
it
is
close
to
existing
pipelines
and
on
top
of
a
salt
formation
starting
300
meters
below
the
seabed.
34
CGI's
proposed
re­
gasification
system
uses
a
simple
pipe
in
pipe
co­
axial
flow
arrangement
(
LNG
in
inner
pipe
and
seawater
between
the
inner
pipe
and
outer
pipe)
running
a
calculated
distance
(
2,500
feet)
along
the
ocean
floor
from
the
offshore
underground
salt
caverns
to
shore.
No
gasified
LNG
is
used
in
the
warming
process.
It
is
unclear
what
quantity
of
seawater
is
used
for
this
re­
gasification
system.
35Port
Pelican
LLC
Application
for
Deepwater
Port
License,
Environmental
Report,
Page
2­
25,
http://
dmses.
dot.
gov/
docimages/
pdf84/
210835_
web.
pdf,
December
27,
2002.
Page
24
of
29
3.0
Estimates
of
Pollutant
Discharges
for
Existing
and
Proposed
LNG
Import
Terminals
3.1
Existing
LNG
Import
Terminals
As
discussed
in
Section
1.0,
none
of
the
five
existing
onshore
U.
S.
LNG
import
terminals
discharge
wastewaters
associated
with
their
vaporization
operations.
Irregular
water
discharges
occur
at
these
facilities
but
only
as
they
relate
to
their
firewater
systems.
Consequently,
with
respect
to
the
vaporization
operations
at
these
facilities,
EPA
estimated
that
minimal
or
no
pollutants
are
generated
or
discharged.

3.2
Proposed
Onshore
LNG
Import
Terminals
As
discussed
in
Section
2.1,
none
of
the
proposed
onshore
U.
S.
LNG
import
terminals
are
projecting
to
discharge
wastewaters
associated
with
their
vaporization
operations.
Consequently,
with
respect
to
the
vaporization
operations
at
these
facilities,
EPA
estimated
that
minimal
or
no
pollutants
will
be
generated
or
discharged.

3.3
Proposed
Offshore
LNG
Import
Terminals
As
discussed
in
Section
2.2,
EPA
was
able
to
identify
that
six
of
the
proposed
offshore
U.
S.
LNG
import
terminals
are
designed
to
use
surface
water
and
anti­
biofouling
chemicals
for
their
vaporization
operations.
Table
4
provides
estimates
of
the
wastewater
and
pollutant
discharges
associated
with
these
facilities.
EPA
was
also
able
to
identify
that
two
proposed
offshore
U.
S.
LNG
import
terminals
are
designed
not
to
use
surface
water
for
their
vaporization
operations.
Consequently,
with
respect
to
the
vaporization
operations
at
these
two
facilities,
EPA
estimated
that
minimal
or
no
pollutants
will
be
generated
or
discharged.

The
main
pollutant
source
for
the
water
intake
vaporization
designs
is
associated
with
the
anti­
biofouling
chemicals
added
to
the
surface
water.
There
are
two
chemicals
proposed
for
biofouling
control,
copper
and
sodium
hypochlorite.
Copper
and
chlorine
can
be
toxic
to
fish
and
marine
phytoplankton.
Sodium
hypochlorite
will
rapidly
dissociate
in
water
to
form
hypochlorous
acid
and
hypochlorite.
Upon
mixing
with
seawater,
the
hypochlorite
will
rapidly
react
with
bromide
in
seawater
producing
hypobromide.
Hypobromide
will
react
with
humic
material
to
form
brominated
complex
organic
material
and
to
a
smaller
extent
with
ammonia
to
form
bromamines.
When
the
discharged
chlorine
mixes
with
the
receiving
seawater,
the
reaction
of
chlorine
will
immediately
start.
35
Page
25
of
29
Table
4:
Estimated
Pollutant
Loadings
for
Proposed
Offshore
LNG
Import
Terminals
Company
(
Facility
Name)
Estimated
Discharge
(
MGD)
Anti­
Biofouling
Chemical
Average
Anti­

Biofouling
Chemical
Conc.
(
mg/
L)
"
Shock"
Anti­
Biofouling
Chemical
Conc.
(
mg/
L)

and
Duration
(
min./
day)
Annual
Discharge
of
Anti­
Biofouling
Chemicals
(
Pounds/
yr)

Excelerate
(
GOM
Energy
Bridge)
133
Copper
0.002
0
810
ChevronTexaco
(
Port
Pelican)
141
Sodium
Hypochlorite
0.2
(
free
chlorine)
2
mg/
L
60
min.
per
day
118,099
Shell
(
Gulf
Landing)
136
Sodium
Hypochlorite
2
(
free
chlorine)
5
mg/
L
180
min.
per
day
983,775
BHP
Billiton
(
Cabrillo
Port)
N/
A
N/
A
N/
A
N/
A
N/
A
ConocoPhillips
(
Compass
Port)
152.2
Sodium
Hypochlorite
0.2
(
free
chlorine)
2
mg/
L
60
min.
per
day
127,480
Freeport
McMoRan
(
Main
Pass
Energy
Hub)
200
Sodium
Hypochlorite
0.5
to
1.0
(
free
chlorine)
2
to
5
mg/
L
20
min.
per
day
317,265
to
642,990
Crystal
Energy
(
Clearwater
Port)
N/
A
N/
A
N/
A
N/
A
N/
A
ExxonMobil
(
Pearl
Crossing)*
247
Sodium
Hypochlorite
0.2
(
free
chlorine)
2
mg/
L
60
min.
per
day
206,882
*
Note:
Average
anti­
biofouling
chemical
concentrations
for
this
facility
were
estimated
from
the
Shell
(
Port
Pelican)
facility.

N/
A:
Not
applicable
as
this
the
vaporization
system
for
this
facility
does
not
generate
wastewater.
Page
26
of
29
4.0
Pollution
Prevention
and
Treatment
Technology
Options
Available
to
Reduce
or
Eliminate
Pollutant
Discharges
As
highlighted
in
this
memorandum,
the
re­
gasification
process
of
LNG
is
an
endothermic
process
and
requires
a
heat
source.
The
LNG
would
be
pumped
through
some
heating
system,
where
it
would
absorb
heat
and
vaporize,
or
re­
gasify,
into
natural
gas.
Different
pollution
prevention
or
treatment
technology
options
are
available
for
onshore
verses
offshore
LNG
import
terminals.
Offshore
LNG
import
terminals
may
have
significant
space
limitations
which
could
significantly
increase
the
costs
and
economic
impacts
and
affect
the
technical
feasibility
of
implementing
technology
options
available
for
onshore
facilities.
Moreover,
one
technology
option
for
onshore
facilities,
closed
loop
re­
cycle
with
waste
heat
from
another
industrial
facility,
is
not
available
for
offshore
facilities
due
to
their
remoteness.

4.1
Onshore
LNG
Import
Terminals
Onshore
LNG
import
terminals
are
better
able
to
design
their
operations
in
order
to
not
require
wastewater
discharges.
All
existing
onshore
LNG
import
terminals
use
LNG
vaporization
systems
with
no
wastewater
discharges
and
current
information
indicates
that
all
new
onshore
LNG
import
terminals
are
proposing
to
use
LNG
vaporization
systems
with
no
wastewater
discharges.

4.1.1
Existing
Onshore
LNG
Import
Terminals
As
previous
mentioned,
EPA
identified
that
none
of
the
four
existing
continental
U.
S.
LNG
import
terminals
use
surface
water
for
their
vaporization
operations,
only
as
an
emergency
backup
source
to
their
firewater
systems.
For
example,
at
the
Dominion
Cove
Point,
MD,
facility
all
water
used
on
site
is
withdrawn
from
groundwater
wells
and
is
heated
in
the
vaporizers
and
used
to
warm
the
LNG
and
convert
back
to
a
gaseous
state.

The
remaining
existing
U.
S.
onshore
LNG
import
terminal,
the
EcoElectrica
facility
in
Puerto
Rico,
does
use
surface
water
for
makeup
and
discharges
blowdown
for
the
power
plant
cooling
tower,
but
does
not
discharge
wastewaters
for
the
LNG
processing.
The
EcoElectrica
LNG
import
terminal
is
a
closed­
loop
facility
that
is
integrated
with
a
500
megawatt
electric
power
generator.
This
integration
has
benefitted
the
LNG
import
capabilities
and
boosted
the
electric
power
generator
output
by
10%
(
Hall,
2004).

The
fact
that
all
five
existing
onshore
LNG
import
terminals
use
LNG
vaporization
systems
with
no
wastewater
discharges
demonstrates
that
zero
discharge
technologies
are
available
for
this
industrial
sector.

4.1.2
New
Onshore
LNG
Import
Terminals
As
detailed
in
Table
2,
current
information
shows
that
all
new
onshore
LNG
import
terminals
are
proposing
to
use
LNG
vaporization
systems
with
no
wastewater
discharges
(
e.
g.,
36Export­
Import
Bank
of
the
United
States,
2004.
Environmental
Guidelines
­
Table
10
Liquefied
Natural
Gas
(
LNG)
Liquefaction
Plants
And
Regasification
Facilities,
http://
www.
exim.
gov/
products/
policies/
environment/
envtbl10.
html,
Revised
:
July
2,
2004.

37Walker,
Bobbi,
2004.
Letter
from
Bobbi
Walker,
Gulf
of
Mexico
Fishery
Management
Council,
to
Rolland
Schmitten,
NOAA
National
Marine
Fisheries
Service,
June
9,
2004.
Page
27
of
29
integration
with
other
industrial
facilities,
heating
towers,
gas­
fired
heaters).
Operating
LNG
import
terminals
in
a
closed­
loop
manner
(
i.
e.,
no
surface
water
withdrawals)
is
also
consistent
with
recent
recommendations
by
the
Export­
Import
Bank
of
the
United
States
and
the
Gulf
of
Mexico
Fishery
Management
Council
to
reduce
effluent
discharges
and
minimize
impingement
and
entrainment
of
aquatic
organisms
and
the
associated
damages
to
recreational
and
commercial
fisheries
and
essential
fish
habitat.
36,37
Some
new
facilities
are
also
proposing
to
use
waste
heat
from
nearby
industrial
facilities
for
their
re­
gasification
(
e.
g.,
Ingleside
Energy
Center
LNG
Import
Terminal,
Corpus
Christi,
TX).

The
integration
of
an
LNG
import
terminal
with
a
nearby
or
on­
site
industrial
operation
is
a
`
win­
win'
solution
as
it
provides
a
resource
(
cold
water
from
LNG
import
terminal)
to
a
nearby
or
on­
site
industrial
facility.
This
integration
can
lead
to
the
following
benefits
for
the
nearby
or
on­
site
industrial
facility:
(
1)
increase
operational
efficiency,
reduce
operating
costs,
and
(
2)
reduce
or
eliminate
thermal
and
chemical
pollution
and
potential
entrainment
or
impingement
impacts
from
heat
exchanger
surface
water
intakes.
One
estimate
suggests
that
an
electric
power
generator
using
cold
water
from
an
LNG
import
terminal
can
boost
its
efficiency
by
1
to
2%,
resulting
in
cost
savings
(
Hall,
2004).
Finally,
this
integration
reduces
or
eliminates
the
potential
entrainment
or
impingement
impacts
associated
with
the
LNG
re­
gasification
process.
Finally,
this
integration
reduces
or
eliminates
the
potential
entrainment
or
impingement
impacts
as
well
as
the
thermal
and
chemical
pollution
associated
with
the
water
intake
LNG
re­
gasification
processes.

The
fact
that
all
proposed
onshore
LNG
import
terminals
are
designed
to
use
LNG
vaporization
systems
with
no
wastewater
discharges
demonstrates
that
zero
discharge
technologies
are
available
for
this
industrial
sector.

4.2
New
Offshore
LNG
Import
Terminals
As
detailed
in
this
memorandum,
the
wastewater
generation
and
pollutant
discharges
associated
with
this
industrial
sector
are
primarily
related
to
the
selected
vaporization
design.
There
are
various
re­
gasification
technologies
proposed
for
offshore
LNG
import
terminals
include:
(
1)
open
rack
vaporizers
(
ORV);
(
2)
submerged
combustion
vaporizers
(
SCV);
(
3)
shell
and
tube
vaporizors
(
STV);
(
4)
closed­
loop
heat
exchangers;
and
(
5)
intermediate
fluid
vaporizers
(
IFV).
Additionally,
the
CGI
re­
gasification
process
detailed
above
may
find
use
in
future
LNG
import
terminals.
The
follow
discussion
provides
a
summary
of
the
considerations
when
selecting
a
vaporization
design
and
the
potential
for
discharging
wastewater
and
pollutants.

Open
Rack
Vaporizer
(
ORV)
Technology
Page
28
of
29
It
appears
likely
that
six
proposed
U.
S.
offshore
LNG
import
terminals
will
use
Open
Rack
Vaporizer
(
ORV)
technology
for
re­
gasification
of
LNG
(
i.
e.,
Port
Pelican,
Gulf
Landing,
Compass
Port,
Main
Pass
Energy
Hub,
Pearl
Crossing,
Port
Penguin).
As
describe
above,
this
regasification
technology
uses
large
quantities
of
seawater
(
e.
g.,
130
to
250
MGD)
flowing
over
a
series
of
panel
coils
to
warm
the
LNG
that
is
flowing
countercurrent
within
the
panels.
Sea
water
flows
through
intake
screens
and
is
then
pumped
to
ORVs
through
strainers.
Sodium
hypochlorite
is
injected
into
intake
pumps
as
an
anti­
biofouling
agent.
Potential
pollution
prevention
options
for
facilities
that
use
ORV
might
include
better
monitoring
and
evaluation
of
biofouling
to
reduce
the
amount
of
chemicals
used
in
biofouling
control
and
dechlorination
(
e.
g.,
use
of
dechlorinating
agents
such
as
sodium
metabisulfite).

Submerged
Combustion
Vaporizer
(
SCV)
Technology
It
appears
likely
that
two
proposed
U.
S.
offshore
LNG
import
terminals
will
use
Submerged
Combustion
Vaporizer
(
SCV)
technology
for
re­
gasification
of
LNG
(
i.
e.,
Cabrillo
Port,
Crystal
Energy).
As
describe
above,
this
re­
gasification
technology
uses
submerged
combustion
vaporizers
using
LNG
as
the
fuel.
The
SCVs
will
superheat
the
resultant
natural
gas
to
a
temperature
of
about
41
°
F.
The
combustion
vaporization
process
is
thermally
stabilized
by
submersion
in
a
water
bath.
No
compression
of
the
natural
gas
is
required.

As
previously
mentioned,
the
chief
environmental
benefit
of
this
re­
gasification
technology
is
that
it
eliminates
the
issues
associated
with
water
intakes
(
i.
e.,
impingement
and
entrainment
of
aquatic
organisms)
and
discharges
(
i.
e.,
thermal
and
chemical
pollution).
Additionally,
offshore
LNG
import
terminals
could
use
a
combination
of
SCV
and
vaporization
systems
that
use
water
(
e.
g.,
ORVs)
to
reduce
wastewater
discharges.
The
combination
of
SCV
and
ORV
systems
also
provides
a
benefit
of
redundant
vaporization
systems
in
case
of
equipment
failure.

Overall
the
SCV
system
has
lower
capital
costs
than
ORV
systems
and
quick
start­
up
but
has
higher
operating
costs
(
especially
at
gas
prices
higher
than
$
1.9/
MMBtu).
SCV
burns
natural
gas
equivalent
to
1.5
to
2%
of
the
LNG
throughput
to
generate
heat.
However,
EPA
considers
this
technology
option
as
potentially
viable
for
all
LNG
import
terminals
as
two
of
the
proposed
offshore
LNG
import
terminals
are
projecting
to
use
SCV
systems
(
i.
e.,
Cabrillo
Port,
Crystal
Energy).

The
combustion
process
relies
on
natural
gas
from
LNG,
so
it
is
a
cleaner
fuel.
With
SCV
the
exhaust
gases
also
flow
directly
through
a
water
bath,
which
acts
as
a
quench
and
abatement
system.
The
SCV
air
emissions
will
include
oxides
of
nitrogen
(
NOx),
and
carbon
dioxide.
The
chief
environmental
benefit
of
this
re­
gasification
technology
is
that
it
eliminates
the
issues
associated
with
water
intakes
(
i.
e.,
impingement
and
entrainment
of
aquatic
organisms)
and
discharges
(
i.
e.,
thermal
and
chemical
pollution).

Shell
and
Tube
Vaporizors
Page
29
of
29
It
appears
likely
that
one
proposed
U.
S.
offshore
LNG
import
terminals
will
use
shell
and
tube
vaporizor
(
STV)
technology
for
re­
gasification
of
LNG
(
i.
e.,
GOM
Energy
Bridge).
This
regasification
technology
uses
seawater
from
seachests
to
provide
the
necessary
heat.
The
warming
seawater
will
pass
through
the
shell
and
tube
vaporizer
and
indirectly
heat
the
LNG.
As
describe
above,
this
re­
gasification
technology
can
use
large
quantities
of
seawater
(
e.
g.,
approximately
76
MGD).
Sodium
hypochlorite
is
injected
into
intake
pumps
as
an
anti­
biofouling
agent.
Potential
pollution
prevention
options
for
facilities
that
use
STV
might
include
better
monitoring
and
evaluation
of
biofouling
to
reduce
the
amount
of
chemicals
used
in
biofouling
control
and
dechlorination
(
e.
g.,
use
of
dechlorinating
agents
such
as
sodium
metabisulfite).

Closed­
loop
Heat
Exchangers
It
appears
likely
that
one
proposed
U.
S.
offshore
LNG
import
terminals
has
the
potential
to
the
use
closed­
loop
heat
exchangers
for
re­
gasification
of
LNG
(
i.
e.,
GOM
Energy
Bridge).
In
the
closed
loop
mode,
steam
from
the
LNG
vessel
propulsion
boilers
will
heat
water
circulated
in
a
closed
loop
through
the
shell
and
tube
vaporizer
and
a
steam
heater.
After
the
cycle,
the
water
will
be
re­
circulated
through
the
system.
There
is
no
seawater
intake
or
discharge
for
the
regasification
process
in
the
closed
loop
mode.
The
closed
loop
mode
allows
for
LNG
regasification
when
surrounding
seawater
temperatures
are
too
cold
for
the
more
efficient
open
loop
mode.
The
chief
environmental
benefit
of
this
re­
gasification
technology
is
that
it
eliminates
the
issues
associated
with
water
intakes
(
i.
e.,
impingement
and
entrainment
of
aquatic
organisms)
and
discharges
(
i.
e.,
thermal
and
chemical
pollution).
The
main
disadvantage
of
this
re­
gasification
system
verses
the
shell
and
tube
vaporizors
(
open
loop)
re­
gasification
system
is
that
decreased
rate
of
LNG
vaporization.

Intermediate
Fluid
Vaporizer
(
IFV)
Technology
It
appears
likely
that
no
proposed
U.
S.
offshore
LNG
import
terminals
will
use
Intermediate
Fluid
Vaporizer
(
IFV)
technology
for
re­
gasification
of
LNG.
This
re­
gasification
technology
uses
glycol/
water
mix
to
exchange
heat
with
the
LNG
via
a
shell
and
tube
exchanger.
The
cold
glycol
mix
is
circulated
continuously
in
a
closed
loop.
A
plate
and
frame
or
other
type
heat
exchanger
heats
the
glycol
mix
using
seawater
as
the
heating
medium.
The
equipment
necessary
for
this
system
includes
common
heat
exchangers
and
pumps.
Pumps
are
required
for
the
seawater
and
for
the
circulated
glycol
mix.
The
quantity
of
circulated
seawater
is
identical
to
that
required
for
the
ORV,
given
environmental
limits
between
the
inlet
and
return
water
temperature.
The
LNG
is
vaporized
from
the
heat
gained
by
the
glycol
and
the
glycol
acquires
heat
from
the
seawater.
The
design
must
maintain
LNG
and
glycol
carefully
to
avoid
freezing
on
the
glycol
side
of
the
vaporizer.
Sodium
hypochlorite
is
injected
into
intake
pumps
as
an
anti­
biofouling
agent.
Potential
pollution
prevention
options
for
facilities
that
use
IFV
might
include
better
monitoring
and
evaluation
of
biofouling
to
reduce
the
amount
of
chemicals
used
in
biofouling
control
and
dechlorination
(
e.
g.,
use
of
dechlorinating
agents
such
as
sodium
metabisulfite).
