The Technology and Economic Feasibility of Offshore Liquefied Natural Gas
Receiving Terminals in the United States
By
Parker E. Larson
B.S. Marine Engineering and Shipyard Management
United States Merchant Marine Academy, 2001
Submitted to the Department of Ocean Engineering
in Partial Fulfillment of the Requirements for the Degree of
Master of Science in Ocean Systems Management
at the
Massachusetts Institute of Technology
MASSACHUSETTS INSTITUTE
OF TECHNOLOGY
AUG 2 5 2003
June 2003
D Parker E. Larson, MMIII. All rights reserved
LIBRARIES
The author hereby grants MIT permission to reproduce and to
distribute publicly paper and electronic copies of this thesis document in whole or in part.
c3~x
/
Signature of Author.........
........... ...............
Department of Ocean Engineering
d
May 9, 2003
Certified by.......
"
Accepted by.............
flir. Hzr r's. Marcus, Professor of Marine Systems
Thesis Supervisor
............
Engineering
Ocean
of
Professor
Dr. Michael Triaitafyllou,
Chairman, Department Committee on Graduate Students
BAPRKE
Page Intentionally Left Blank
2
The Technology and Economic Feasibility of Offshore Liquefied Natural Gas
Receiving Terminals in the United States
by
Parker E. Larson
Submitted to the Department of Ocean Engineering in Partial Fulfillment
of the Requirements for the Degree of
Master of Science in Ocean Systems Management
ABSTRACT
The United States could face a gap in the supply of natural gas of about 5 Tcf by 2020.
With the large forecasted growth of liquefied natural gas in the United States and the
apparent need for additional import or regasification terminals, building onshore terminals
remains to be a monumental challenge. By reducing political, state, and local regulatory
involvement, offshore terminals can mitigate many of the problems that surround the
importing of liquefied natural gas into the United States.
This paper outlines the latest technology in the liquefied natural gas industry. A computerbased simulation model which calculates the unit costs for the regasification and storage of
each of the four different offshore LNG receiving terminal options, as well as the
associated shipping costs, is applied. The quantitative results of model favor the
Conversion Gas Imports Salt-Cavern Storage and Bishop Process as the most feasible
receiving terminal option. The subjective results reveal that there is too little of a
difference in the unit costs and too much sensitivity to unforeseen costs of the four
offshore receiving terminal options to dictate which option is optimal. It is determined that
offshore receiving terminals will mitigate the lack of receiving terminals in the United
States; however, the type of receiving terminal used is dependent on several other
variables.
Thesis Supervisor: Dr. Henry S. Marcus
Title: Professor of Marine Systems
3
ACKNOWLEDGEMENTS
This thesis would not have been possible without the help and support of Dr. Henry S.
Marcus who was not only instrumental in bringing me to MIT in the first place, but has
been extremely supportive with my research. I would like to thank ConocoPhillips for its
support of this research. Also, I would to thank ASEE for its financial support of my time
spent at MIT. Furthermore, I would like to thank Perry Connell for his help along side of
me in our LNG research. Lastly, thanks go to my family and friends for their support
while I have been at MIT.
4
TABLE OF CONTENTS
ABSTRACT ..........................................................................................................................
3
ACKNOW LEDGEM ENTS.............................................................................................
4
TABLE OF CONTENTS ..................................................................................................
5
LIST OF FIGURES .......................................................................................................
7
LIST OF TABLES .......................................................................................................
9
NOM ENCLATURE AND ACRONYM S....................................................................
10
CHAPTER 1: INTRODUCTION.................................................................................
12
PU RPO SE ...........................................................................................................................
B A C K G R O UN D ...................................................................................................................
PR OC ED U R E ......................................................................................................................
12
13
15
CHAPTER 2: LNG'S ROLE IN NORTH AMERICA.............................................17
OV ER V IEW ........................................................................................................................
17
REGULATORY FRAMEWORK..............................................................................................24
EVOLUTION OF INDUSTRY ..............................................................................................
31
CHAPTER 3: NEXT GENERATION OF LNG TECHNOLOGY.............34
O VER V IEW ........................................................................................................................
34
OFFSHORE HANDLING AND TRANSFER TECHNOLOGIES ................................................
35
GAS HYDRATES AND OTHER NATURAL GAS TECHNOLOGY ..............................................
41
CHAPTER 4: FINANCIAL CHALLENGES FOR LNG PROJECTS ....................
FINANCIAL ISSUES WITH LNG MARKET........................................................................
LNG SPOT M ARKET......................................................................................................
44
44
52
CHAPTER 5: OFFSHORE LNG RECEIVING TERMINALS................54
GRAVITY-BASED STRUCTURE...........................................................................................54
FLOATING STORAGE AND REGASIFICATION UNIT .............................................................
EL PASO ENERGY BRIDGE .................................................................................................
57
59
CONVERSION GAS IMPORTS BISHOP PROCESS AND SALT CAVERN STORAGE.................61
CHAPTER 6: RESULTS.............................................................................................
66
MODEL DESCRIPTION....................................................................................................
66
LIMITATIONS OF M ODEL ................................................................................................
72
RE SU LTS ...........................................................................................................................
73
CHAPTER 7: CONCLUSIONS.......................................................................................92
S U MM A RY .........................................................................................................................
5
92
RECOM MENDATIONS FOR FUTURE W ORK
......................................................................... 94
W O R KS CITED .................................................................................................................96
W O R K S C ON SU LTED ..................................................................................................100
A PPEN DICES ..................................................................................................................103
6
LIST OF FIGURES
Figure 1 - LNG Value Chain [Stone, 2002].....................................................................14
Figure 2 - Natural Gas Production, Consumption, and Imports (Tcf) [Martin, 2003].........18
Figure 3 - Everett LNG Terminal [Quillen, 2002]..........................................................20
Figure 4 - Cove Point LNG Terminal Storage and Regasification [EIA, 2002]..............21
Figure 5 - Cove Point LNG Terminal Receiving Point [Zeus, 2001]..............................21
22
Figure 6 - Elba Island LNG Terminal [El Paso, 2002] ...................................................
Figure 7 - Lake Charles LNG Terminal [CMS, 2003].....................................................23
26
Figure 8 - LOOP's Marine Terminal [DOTD, 1999] .......................................................
Figure 9 - FERC Approval Process [FERC, 2003]..........................................................30
Figure 10 - Existing and Proposed LNG Terminals [FERC, 2003].................................33
Figure 11 - FMC Chiksan LNG Marine Loading Arms [Offshore Technology, 2003] ...... 36
Figure 12 - FMC Boom-to-Tanker Offloading System [Offshore Technology, 2003] ....... 37
Figure 13 - Tandem Offloading Arrangement [Scherz, 2003]....................37
Figure 14 - Side-by-side Offloading Arrangement [Scherz, 2003]..................................38
Figure 15 - CALM Buoy [Scherz, 2003].............................................................................38
Figure 16 - Conventional Jetty Head and Gerris Mooring Arrangements [TotalFinaElf,
39
2 00 1] ............................................................................................................................
Figure 17 - Weathervaning Mooring Arrangement [TotalFinaElf, 2001] ....................... 40
Figure 18 - FMC Extending Loading Arm [FMC Loading Systems, 2003]....................40
Figure 19 - GBS cross-section [Foster Wheeler, 2002]...................................................54
Figure 20 - GBS terminal [Foster Wheeler, 2002]..........................................................56
Figure 21 - Moss Maritime FSRU design [Moss, 2002].................................................57
Figure 22 - IHI Concept Flow of an FSRU LNG Storage and Regasification Plant [IHI,
58
2 00 3 ] ............................................................................................................................
Figure 23 - IHI FSRU in Side-To-Side and Tandem Offloading Positions [IHI, 2003]......59
Figure 24 - El Paso Energy Bridge [El Paso, 2002]........................................................60
Figure 25 - CGI Bishop Process and Salt Cavern Storage [CGI, 2003]..........................62
Figure 26 - Volume of Natural Gas in U.S. [EIA, 2002].................................................63
Figure 27 - Salt Cavern Storage Well [CGI, 2003]..........................................................64
Figure 28 - Gulf Coast Salt Dome [CGI, 2003]..............................................................64
Figure 29 - Flow Chart of LNG Receiving Terminal Unit Cost Model...........................68
Figure 30 - Sensitivity of Total Unit Costs to Daily Sendout .......................................... 75
Figure 31 - Base Case Unit Cost Breakdown...................................................................76
Figure 32 - Sensitivity of Unit Shipping Costs to Days Lost to Bad Weather ................ 78
Figure 33 - Sensitivity of Unit Shipping Costs to Tanker Capacity ................................ 80
Figure 34 - Sensitivity of Regasification Storage Capital Costs to Daily Natural Gas
1
S en d o u t.........................................................................................................................8
Figure 35 - Sensitivity of GBS Total Unit Cost to Regasification & Shipping Project
84
Discount R ates .............................................................................................................
Figure 36 - Sensitivity of FSRU Total Unit Cost to Regasification & Shipping Project
85
Discount R ates .............................................................................................................
7
Figure 37 - Sensitivity of Energy Bridge Total Unit Cost to Regasification & Shipping
86
Project Discount R ates ............................................................................................
Figure 38 - Sensitivity of CGI Total Unit Cost to Regasification & Shipping Project
87
D iscou nt R ates .............................................................................................................
88
Figure 39 - Added Cost Fluctuations to GBS Project Base Case ...................................
89
.................................
Case
Base
to
FSRU
Project
Fluctuations
Added
Cost
Figure 40 Figure 41 - Added Cost Fluctuations to Energy Bridge Project Base Case....................90
Figure 42 - Added Cost Fluctuations to CGI Project Base Case ..................................... 91
8
LIST OF TABLES
Table
Table
Table
Table
1- Existing US LNG Import Terminals [Candelet, 2003]......................................24
31
2 - LN G Timeline [Avila, 2002]............................................................................
3 - LNG Project Risks and Mitigants [CWC Group, 2003]...................................50
4 - LNG Storage Advantages for Concrete and Steel [Berner, 2003]....................55
9
NOMENCLATURE AND ACRONYMS
BANANA - "Build Absolutely Nothing Anywhere Near Anything"
Bcf - billion cubic feet
CNG - Compressed Natural Gas
DEIS - Draft Environmental Impact Statement
DOE - Department of Energy
DOT - Department of Transportation
DWPA - Deepwater Port Act
EIA - Energy Information Administration
EPA - Environmental Protection Agency
EPC - Engineering, Procurement, and Construction
FEIS - Final Environmental Impact Statement
FERC - Federal Energy Regulatory Commission
FPSO - Floating Production Storage and Offloading unit
FSRU - Floating Storage and Regasification Unit
FSU - Floating Storage Unit
FWS - Full Well Stream (Pipeline)
GBS - Gravity Based Structure
GTL - Gas-To-Liquid
LD - Liquidated Damages
LNG - Liquefied Natural Gas
10
LNGRV - Liquefied Natural Gas Regasification Vessel
LOOP - Louisiana Offshore Oil Port
LPG - Liquid Petroleum Gas
MARAD - Maritime Administration
Mcf - thousand cubic feet
MMBtu - million BTUs
MMcf - million cubic feet
NIMBY - "Not In My Backyard"
NGA - Natural Gas Act
NGH - Natural Gas Hydrates
NGO - Non-Governmental Organization
O&M - Operation and Maintenance
SPA - Sales and Purchase Agreement
Tcf - trillion cubic feet
USCG - United States Coast Guard
11
CHAPTER 1: INTRODUCTION
PURPOSE
According to the EIA, the U.S. could face a gap in the supply of natural gas of
about 5 Tcf by 2020. As noted by the University of Houston's Institute of Energy, Law
and Enterprise:
The EIA expects LNG imports to reach 0.8 Tcf a year by 2020, or
about three % of our total consumption. The demand for LNG is
expected to grow. To make LNG available for use in the U.S., energy
companies must invest in the LNG value chain, which is a number of
different operations that are highly linked and dependent upon one
another. Natural gas can be economically produced and delivered to
the U.S. as LNG in a price range of about $2.50 - $3.50 MMBtu at
Henry Hub in Louisiana, depending largely on shipping cost [Houston,
2003].
This need for further natural gas supplies, together with the reopening of existing
LNG facilities at Cove Point, Maryland and Elba Island, Georgia has brought in public
attention on the safety and security of LNG facilities. Moreover, the terrorist attacks on
September 11, 2001 have only widened the scrutiny of the LNG industry.
Federal, state, and local jurisdictions share concern for the safety and protection of
onshore LNG facilities. However, with the large forecasted growth of LNG in the U.S.
and the apparent need for additional import or regasification terminals, building terminals
onshore remains to be a monumental challenge.
The solution appears to be the construction of offshore regasification and storage
LNG terminals.
By reducing or eliminating the NIMBY controversy and by reducing
major state and local regulatory involvement, offshore terminals will mitigate most of the
problems that surround the importing of LNG into the U.S.
12
Therefore, this research has four primary goals:
1. To provide a current look at the natural gas sector of the energy
industry.
2. To introduce and examine new technologies pertaining to the LNG
value chain.
3. To observe the financial and political challenges for LNG projects.
4. To discover the primary cost drivers related to the regasification and
shipping facets of the LNG value chain thru a computer-based
simulation model.
BACKGROUND
LNG is the liquid form of natural gas that can be used for cooking and heating.
Natural gas is a fuel that is used for generating electricity. It is one of the cleanest, safest,
and most useful of all energy sources. Natural gas makes up approximately one-fourth of
the total energy consumed in the U.S. Currently, the U.S. uses "peakshaving" as the most
regular use of LNG. Peakshaving is where a facility that both stores and vaporizes LNG is
intended to operate on an intermittent basis to meet short term peak gas demands [Houston,
2003]. This allows local gas and electric power companies to store gas for peak demand
that cannot be met through a standard pipeline source.
The utility companies will liquefy pipeline gas when it is plentiful and available at
off-peak prices. These companies will also purchase LNG from import terminals that are
supplied from overseas liquefaction facilities. As gas demand increases, stored LNG is
changed back into a gaseous state to add to the utility's pipeline supply.
13
Today's LNG developments are stimulated by a rise in natural gas consumption.
This natural gas consumption exceeds the growth of other feasible energy sources. While
oil continues to be the principal hydrocarbon energy source, gas is seen as a fuel of the
immediate future.
Up to now, LNG has played only a speculative role in being a
competitive player within the energy infrastructure.
Offshore Field
Production V
*Gas
4'%
*,Harbor,
Pier
LNG
Plant
Pipeline
FWS
Wellhead
Platfom
Shipping
GP P Receiving
Power Plant
Terminal
Figure 1 - LNG Value Chain [Stone, 2002]
Within the LNG supply chain, as shown in Figure 1, the understood bottleneck in
the U.S. is the lack of receiving terminals. LNG demand growth is constrained in the U.S.
by limited access to the market. Siting for new traditional onshore terminals is extremely
difficult for political, environmental, safety, and security reasons. The public perception of
LNG is that it is "ultra-hazardous" [Daughdrill, 2003]. This was illustrated by a purely
politically motivated shutdown of the Everett facility for six weeks after September 11,
14
2001. Furthermore, there is a higher level of USCG and FERC scrutiny for onshore LNG
terminals.
For the reasons mentioned above, offshore LNG terminals appear to be the
answer to alleviate the bottleneck of receiving terminals in the LNG supply chain.
Offshore LNG terminals represent billion dollar investments in inexperienced
technology. The likely business exposure is significant and the investors have expressed a
need for a framework to assist in the investment decision. This paper will describe the new
technology involved in the regasification and storage phase of the LNG value chain with
respect to offshore terminals. Furthermore, this paper will provide a framework that will
contribute to a better understanding of the advantages and disadvantages of the various
economic decisions for offshore LNG facilities and their corresponding technological
options.
PROCEDURE
This discussion will begin with a review of the role of LNG in North America.
There will be a look into why LNG is growing in attractiveness and why LNG will
continue to expand worldwide.
In addition, the market fundamentals of LNG and the
obstacles in the regulatory framework will be discussed.
Then, the next generation of LNG technology will be introduced.
Other
components technology of the LNG value chain will be revealed. This section will also
show the current trends of LNG and how the latest technology is meeting market demands.
Most importantly, there will be a look at the newest offshore transfer and handling
technologies and how they impact LNG trade.
15
Additionally, a look at the different
physical and chemical states of natural gas including LNG, CNG, GTL, and NGH will be
displayed. This section will show what the futures of these natural gas states are and what
the applications of the natural gas states are.
After the technology relating to LNG and the natural gas industry has been
presented, the economics and financial challenges will be discussed. There will be a look
at strategies to mitigate risk and protect investment. Furthermore, the LNG spot market
and its history will be established.
Finally, there will be a look into an economic model that will try to establish the
key cost drivers pertaining to regasification terminals in the U.S. Sensitivity analyses of
some of the cost drivers will be illustrated along with an explanation of the model outlining
given assumptions and parameters.
16
CHAPTER 2: LNG's ROLE IN NORTH AMERICA
OVERVIEW
Looking into the future, there is a continuation of the trend where the growth in
energy demand is met predominantly by natural gas. Phil Bainbridge from BP Energy
states:
"The characteristics of the North American market are well known - it is
growing fast - not so much in percentage terms but in the volume of new
demand growth generated by the world's biggest gas economy. The
market is highly liquid and sophisticated. There is a disaggregated value
chain providing opportunities in each part for different players."
[Bainbridge, 2002]
Even the most conservative projections indicate a growth in total gas demand in North
America of over 5 Tcf over a ten year period. That is nearly double the volume of the next
largest growth market, which is China. The current and forecasted discrepancy in
consumption and production is illustrated in Figure 2:
17
35
History
Projections
et Imports
30
25
Consumption
20
Natural Gas Not Imports, 2001 and 2025
(trillion cubic feet)
Production
15
10
2025
5
Iqnefd. Naural (a
PipeIint
0
1970
1975
1980
1985
1990
1995
2000
2I
2I
2005
2010
1
2015
1
2020
2025
Figure 2 - Natural Gas Production, Consumption, and Imports (Tcf) [Martin, 2003]
Mark Howard, BP's global technology team leader for LNG and gas processing,
refers to many driving forces which are propelling LNG into its "second age" [Howard,
2001]. With the deregulation of markets, there are more opportunities to supply LNG into
the North America. Approximately one-third of all the natural gas produced is consumed
in North America and North America is calling for more energy to meet its needs. Energy
supply issues have been a concern in recent years.
Currently, there are four onshore LNG receiving terminals here in the U.S. While
over the years they have varied significantly in use, all four play important roles in either
providing peakshaving or regular use. The following gives a description of each:
18
Everett, Massachusetts
The Everett Marine Terminal has a capacity of approximately 160 Bcf/year,
although plans to add another 200 Bcf/year in capacity have been announced. The Everett
facility, shown in Figure 3, is located northwest of central Boston, Massachusetts, on the
Mystic River and began operation in 1971. Everett has one unloading berth and two
aboveground storage tanks. One tank has a 60,000 m3 capacity and the other has a 95,000
m3 capacity, for a total of 155,000 m 3 . These tanks can hold the equivalent of 1.19 ships
worth of LNG, assuming the average LNG ship cargo is 130,000 m3 . In addition to
supplying natural gas to the Algonquin pipeline, the facility has the capability to load 1
million gallons/day or more of LNG into trailers for roadway transport to other facilities.
The facility has been expanded several times with pipeline connections and increased truck
loading capability. Although the facility operators are planning to expand the vaporizing
capabilities, the limited availability of land precludes additional tankage and this
effectively places a cap on facility growth.
19
Figure 3 - Everett LNG Terminal [Quillen, 2002]
Cove Point, Maryland
Cove Point is located on the Chesapeake Bay at Cove Point in Lusby, Maryland, about 50
miles south of Washington, DC. The facility, shown in Figure 4 and Figure 5, was
constructed in 1978 and operated as an LNG import and storage facility from 1978 to
1980, before being shut down. Since 1995, it has primarily been used as a peakshaving
facility to customers in the mid-Atlantic and Southeastern regions. Cove Point has two
LNG ship unloading berths and four aboveground storage tanks. All four storage tanks
have a capacity of 59,630 m3 for a total capacity of 238,520 M 3 . This is equivalent to 1.83
ship cargos, assuming a net cargo of 130,000 m 3 per ship. The facility's total receiving
capacity is 435 Bcf/year, or about 150 cargos. Since Cove Point is surrounded by open
20
land, expansion would be possible, but it has been limited by an agreement with the Sierra
Club that prohibits expansion beyond its current boundaries.
Figure 4 - Cove Point LNG Terminal Storage and Regasification [EIA, 2002]
Figure 5 - Cove Point LNG Terminal Receiving Point [Zeus, 2001]
21
Elba Island, Georgia
Located on Elba Island, near Savannah, Georgia, the LNG facility was completed
in 1978 and operated until 1980 when it was shut down. The facility, shown in Figure 6,
was recently recommissioned and received its first cargo in October 2001. Presently, the
Elba Island facility consists of one berth and three above ground storage tanks. All three
tanks have a 60,000 m 3 capacity, or 180,000 m3 total. This equals 1.38 ship cargos,
assuming a 130,000 million m3 net cargo per ship. Elba Island also has five submergedtype vaporizers with a total vaporization design capacity of approximately 160 Bcf/year.
These vaporizers are being expanded and should increase the terminal's capacity to 292
Bcf/year.
Figure 6 - Elba Island LNG Terminal [El Paso, 2002]
22
Lake Charles, Louisiana
The Lake Charles LNG import terminal shown in Figure 7 is located on the
Calcasui River, south of Lake Charles, Louisiana. Construction was completed in 1982,
but the facility only operated for a year before being shut down. It was reopened in 1989
and has remained in operation since that time. Lake Charles has one berth and three
aboveground tanks. Each of the Lake Charles tanks has a 95,400 m 3 capacity, for a total of
286,200 m3 , equivalent to 2.20 cargos, or about 58 cargos per year. The Lake Charles
import terminal also has seven submerged-vaporizers with a design capacity of 365
Bcf/year. Plans have been announced to increase the vaporization capacity by adding
another 73 Bcf/year. Other expansion plans have been proposed which include the addition
of another berth for unloading LNG ships.
Figure 7 - Lake Charles LNG Terminal [CMS, 2003]
Of the four existing LNG import terminals, only Lake Charles has some unused
capacity. Furthermore, capacity owners have existing contracts or supply projects in
development. Table 1 gives an insight on the current capacity owners and supply sources
23
of the existing terminals. This gives one a perspective of where the LNG is being imported
from and why the computer based simulation model used in Chapter 6 was constructed as
such.
Table 1- Existing US LNG Import Terminals [Candelet, 2003]
Terminal
Everett
Capacity Owner
Tractebel
Cove Point
BP
Statoil
Shell
El Paso
Marathon
Shell (Expansion)
Elba Island
Lake Charles
BG
Supply Source
Trinidad
Algeria
Trinidad
Snovhit
Nigeria
BG Trinidad
Equatorial Guinea
Nigeria
Venezuela
Trinidad
Egypt
Balance Uncommitted
REGULATORY FRAMEWORK
The regulatory framework that lies within this industry is quite complex.
The
University of Houston's Institute of Energy, Law and Enterprise offers the following
insight on the various roles of the federal, state, and local government agencies and
explains the roles of each:
The USCG is responsible for assuring the safety of all marine operations at the
LNG terminals and on tankers in U.S. coastal waters. The DOT regulates LNG tanker
operations.
The FERC is responsible for permitting new LNG regasification
terminals in the U.S. and ensuring safety at these facilities through inspections and
24
other forms of oversight. In order to maintain a competitive environment for supply
and pricing, the FERC is considering its role concerning
the commercial
arrangements by which producers of LNG have access to U.S. terminals.
The
FERC's jurisdiction includes authority for permitting new long distance natural gas
pipelines to be developed in the U.S., as well as for safe and environmentally sound
operation of the overall "interstate" natural gas pipeline system (pipelines that cross
state boundaries). The U.S. EPA and state environmental agencies establish air and
water standards with which the LNG industry must comply. Other federal agencies
involved in environmental protection and safety protection include the U.S. Fish and
Wildlife Service, U.S. Army Corps of Engineers (for coastal facilities and wetlands),
U.S. Minerals Management Service (for offshore activities), and National Oceanic
and Atmospheric Administration (for any activities near marine sanctuaries). The
U.S. DOE - Office of Fossil Energy helps to coordinate across federal agencies that
have regulatory and policy authority for LNG. State, county, and local (municipal)
agencies play roles to ensure safe and environmentally sound construction and
operation of LNG industry facilities. The LNG industry is responsible for safe
operations and facility security in cooperation with local police and fire departments
[Houston, 2003].
Prior to November 25, 2002, the FERC had jurisdiction over the siting of LNG
import terminals located both onshore and offshore. Furthermore, an environmental report
was required by 18 CFR 153.8(a)(7) as specified under Section 380.3 and 380.12 [Brown,
25
2003]. The DWPA was only applied to oil terminals on the U.S. Outer Continental Shelf.
Up to this point, LOOP was the only offshore port built under the Act.
Figure 8 - LOOP's Marine Terminal [DOTD, 1999]
LOOP, shown in Figure 8, is the world's first and only deepwater port operating
under U.S. and Louisiana licenses.
LOOP provides tanker offloading and temporary
storage services for crude oil transported on some of the largest tankers in the world
[DOTD, 1999]. This is because most tankers offloading at LOOP are too large for U.S.
coastal ports.
This was significant because on November 25, 2002, President Bush signed the
Maritime TransportationSecurity Act of 2002. In essence, the Act added natural gas to the
DWPA in Section 106. Several important provisions were added for offshore natural gas
terminals. Law firm Van Ness Feldman summarized the provisions as the following:
26
- Jurisdiction: The Act provides that the licensing, siting, construction, or
operation of deepwater ports for natural gas are subject to the exclusive jurisdiction
of the DWPA specifically excluding any jurisdiction under the Natural Gas Act.
* Licenses for Deepwater Ports: The Act prohibits the transportation of natural
gas between a deepwater port and the shores of the U.S. unless the DOT has issued
a license for such port. The Act defines "natural gas" to mean either unmixed
natural gas or any mixture of natural or artificial gas, including compressed gas or
LNG. In addition, the Act requires DOT, in cooperation with the Department of
Interior, to establish and enforce regulations for the safe construction and operation
of natural gas pipelines on the Outer Continental Shelf.
- Facility Approval: The Act requires DOT to approve or deny an application for a
deepwater port for natural gas within 90 days following the last public hearing on a
proposed license. Under the Act, DOT is not required to publish in the Federal
Register the geographic area of proposed deepwater ports for natural gas.
* Facility Development: Under the Act, deepwater ports for natural gas are not
subject to the common carrier and nondiscrimination provisions of the DPA.
Rather, the Act expressly authorizes licensees of deepwater ports for natural gas to
exclusively utilize the entire capacity of the deepwater port and storage facilities.
27
9
Regulations: Within 30 days following enactment, the heads of Federal
departments or agencies, including the Coast Guard, having expertise or
jurisdiction over any aspect of the construction or operation of deepwater ports for
natural gas are required to submit to DOT written comments as to such expertise or
statutory responsibilities under the DPA or any other Federal law. The Act
authorizes DOT to issue any interim and final rules necessary under the DPA for
the application and issuance of licenses for a deepwater port for natural gas, as soon
as practicable following enactment.
. Environment. The Act provides that "deepwater ports" are considered a "new
source" for purposes of the Clean Air Act and the Federal Water Pollution Control
Act. In addition, the Act requires that all applications for licenses comply with the
National Environmental Policy Act [Feldman, 2002].
The key to this was that the FERC jurisdiction was now eliminated for offshore
natural gas import terminals that were licensed under the DWPA [Daughdrill, 2003]. The
USCG and the MARAD are now responsible for processing the license application.
The challenges that are now present for offshore LNG terminals with the DWPA
amendments are as follows:
" There are no current U.S. offshore LNG terminals
" Regulatory requirements are in transition
28
"
Staffing and experience of regulators is low (last DWP application was
processed 25 years ago)
" Exposed offshore waters represent a challenging operating environment
" Offshore LNG terminals will likely be more expensive to build than onshore
terminals
*
Remote location makes facility security and asset protection more difficult
[Daughdrill, 2003]
Despite these challenges, there are many advantages to having offshore LNG
terminals. First, the safety and security concerns are moved offshore.
Moreover, one
reduces major state and local regulatory involvement. The latter two reasons illustrate the
political rationale why offshore terminals are more feasible. Additionally, the permitting
risk is reduced significantly.
Furthermore, the benefits of building an LNG terminal offshore can be readily seen
when one looks at the FERC approval process for building an onshore terminal shown in
Figure 9.
With an onshore terminal, there needs to be an economic oversight of the
following LNG terminal services:
*
Market Entry
" Access
*
Rate Design
* Public Need/Public Interest
29
I ntironiental Re
FERC
ievN I
Public Interest Review
Approval
Notce of Intent
\Ota f \PrImIiition
W.IzzL MMz.M
I
L
Process
Interventitmis
& Site Vit
Protests
I
Data Requests
Sely Renew
&
Scop ng !Netings
E
Analysil
Tech Conference
A"elncV ('o0krdInat ion
I
(O)ptionial)
U
I
DEIS
Im
I
I
II
MM"
I
I
Authorization
I
Figure 9 - FERC Approval Process [FERC, 2003]
Also, there are siting issues with the LNG terminal due to:
*
Safety Concerns
" Security Concerns
*
Environmental Issues
*
Plant Design
30
Anaklyt
Preliminary Detei InatIon
I
FEIS
D,,4tt Requests
(C ptiont
EVOLUTION OF INDUSTRY
The LNG industry developed from experiments in the U.S. in 1950s, with the first
delivery of LNG to the United Kingdom in 1959 and commercial deliveries of LNG from
Algeria to the United Kingdom and France in 1964 and 1965. The industry then saw major
growth with new markets in Japan from 1969, supplied from Alaska and Brunei, and later
Indonesia, Malaysia and Australia. The oil price shock in 1973 encouraged the further
development of LNG as it improved the competitive position of LNG and led to the
development of oil price indexation in LNG supply contracts [Flower, 2002].
Table 2
gives a look at the LNG timeline.
Table 2 - LNG Timeline [Avila, 2002]
1914
1939
1968
1971
1978
1979
1980
LNG Timeline
First patent awarded for LNG. (Patents involving cryogenic liquids in general date back into the mid-1800s.)
First commercial LNG peakshaving plant built in West Virginia.
Boston Gas Co. imports first LNG into U.S.
Distrigas Corporation opens receiving and regasification terminal in Everett, MA.
LNG imported for baseload supply for first time. Cove Point, MD, and Elba Island, GA, terminal open.
LNG imports peak at 253 billion cubic feet.
Falling prices and dispute with Algerian exports leads to shut down of Cove Point and Elba Island terminals.
However, Elba Island terminal begins to serve as a peaking terminal.
1995
Lake Charles, LA, terminal opens.
Lake Charles terminal closes, and Elba Island terminal closes completely.
Natural gas prices slump drastically. Distrigas stops buying Algerian LNG because the company is unable to
market it.
No imports of LNG arrive in U.S. for the first time since 1974.
Distrigas resumes purchasing Algerian LNG. Lake Charles terminal reopens and also resumes LNG imports
from Algeria.
Algeria renovates liquefaction plants; U.S. imports curtailed. Cove Point terminal adds a process to convert
natural gas into LNG and begins operating as a natural gas storage site.
1996
Spot purchases of LNG begin entering U.S. from sources other than Algeria (Abu Dhabi and Australia).
1981
1982
1985
1986
1988
1999
2001
First LNG shipment from Trinidad arrives in Boston.
Elba Island terminal reopens in October. Williams Company is granted FERC approval to reactivate Cove
Point terminal.
31
The first deliveries of Algerian LNG to the U.S. occurred in 1972, but despite the
construction of four U.S. receiving terminals, LNG sales to the U.S. collapsed and
remained at a low level through the 1980s and 1990s, returning to their 1979 peak in 2000.
During the 1980s and early 1990s further LNG markets developed in Europe and in Korea
and Taiwan. The late 1990s and early 2000s have seen rapid growth with expanding LNG
markets in the U.S., Spain, Portugal and Greece and new production facilities in Oman,
Qatar, Nigeria and Trinidad [Flower, 2002].
Because of rising natural gas prices in the 1970s, LNG project sponsors anticipated
large profits and constructed the four U.S. LNG receiving terminals, previously mentioned
in the chapter. Dreams of high profits never materialized, however, because natural gas
prices began a precipitous decline after their 1983 peak, and all but one of the four were
mothballed. The facility at Everett remained in operation only because it was located in a
heavily concentrated market center where demand was high and the cost of bringing
conventional supplies to market by pipeline was high enough to exceed the cost of LNG.
A large number of new facilities have been proposed to serve U.S. markets.
Figure 10 shows the existing and proposed LNG terminals as of early 2003. Some
of the parties proposing the terminals readily indicate that although prices have fallen since
their proposals were first put forth, they expect future prices to be in a range where LNG is
economical relative to competing supply sources. Although LNG was in the past used
mainly for peaking purposes, the expanding use of natural gas for electricity generation
potentially makes it a less seasonal commodity. Thus, if the economics of LNG become
32
more favorable in the U.S., higher utilization of LNG facilities can be expected, just as
pipeline capacity utilization is increasing [EIA, 2002].
Existing Terminals with Expansions
A.
B.
C.
D.
E.
Everett. MA: 0.715 Bcd (Tractetel)
Cove Point, MD: 1.0 Bcd (Dominion)
Elba Island. GA: 1.2 Befd (El Paso)
Lake Charles. LA: 1.3 Rcfd (CMS Energy)
Guayanilla Bay, P.R.: 0.093 Bcfd (Eco Electrica)
Proposed Terminals - FERC
A
1. Hackberry. LA: 1.5 Bcfd, 2006 (Dynegy.Sempra)
2. Bahamas: 0.83 1cid, 205 (AES Ocean Express U.S.
Pipeline Only)
3. Bahamas: 0.83 Scld, 2005 (Calypso Tractebel - U. S'.
Pipeline Only)
-
6
Proposed Terminals - Coast Guard
4. Poit Pelican: 1 Bcd, 2005 (Chevron Texaco)
B
5. Gulf of Mexico: 0.5 Scd, 2004 (El Paso Global)
Planned Terminals
St. John, NB: 0.5 Bfd, 2005+(Irving Oil)
7. Fall River, MA: 0.4 Bcfd, 2006 (Weaver's Cove Ene rgy)
8. Belmar, NJ Offshort : NA, N/A (El Paso Global)
9. Bahamas: 0.5 BcId, 2005 (E Paso Sea Fare)
6.
D
O
Tarnpa, FL: 0.5 Befd. 2005+(BP)
Freepori, TX: 0.55 BcMd, 20t +(Cheniere LNG Par tners)
Brownsville. TX: 0.55 Bfd, 2006(Cheniere LNG P artners)
Corpus Christi. TX.: 0.55 Bcfd, 2035+(Cheniere LP NG Partners)
Altamira, Tamulipas: 0.5-1 Bcfd. 2004 (El Paso)
S. California Offshore: 0.5 Bcfd. 2005 (Chevon T exaco)
16. Baja C alifornia: 0.7 Rid, 2305 (El Paso)
17. Baja California: 1.0 Bed, 2005 (Marathonj
1. Baja California: 0.5 Bfd, 2305 (Chevron Texaco)
1). Baja California: 1.0 Rcfd. 2005 (CMS Energy)
20. L os Angeles H arbor. CA: N/A. NA (Mitsubishi)
10.
11.
12.
13.
14.
Is.
Figure 10 - Existing and Proposed LNG Terminals [FERC, 2003]
33
CHAPTER 3: NEXT GENERATION OF LNG TECHNOLOGY
OVERVIEW
Currently, LNG technology is becoming more efficient on both the upstream and
downstream side of the LNG value chain. There has been an increase in size of both
liquefaction facilities and LNG ships over the past 40 years. For this reason, unit cost of
LNG has declined. However, this has been accompanied by rising investment in larger
LNG project facilities and the reliance on growing markets to realize the larger capacities
of a single train of LNG production.
Capital cost estimates for LNG projects are being challenged in several ways as
efforts throughout the industry aim to reduce capital costs. Technology developments aim
at capital cost reduction at all functions in the LNG chain:
" Larger LNG train size to achieve greater scale economy
*
Higher thermal efficiency in the liquefaction process
" Gas treatment process tailored to specific feedgas composition
*
Larger compressors and gas turbine drivers for the refrigerant process
" Increased plant efficiency and availability
*
Larger LNG storage tanks
" Larger LNG ships
" Higher natural gas sendout rates from regasification plants [Greenwald, 1998]
34
Although worldwide natural gas supplies for LNG facilities are abundant and can
be produced inexpensively, the processing and transportation equipment is capital
intensive and highly specialized. It requires hundreds of millions of dollars of investment
for each new facility [EIA Report, 1998]. This chapter will describe new technology in the
various facets of the LNG value chain on the upstream and downstream end.
OFFSHORE HANDLING AND TRANSFER TECHNOLOGIES
A key issue for offshore receiving terminals is designing for the relative motion
between terminal and LNG carrier during cargo handling operations. Whether offloading
through a loading arm or via some other special system for the transfer of cryogenic liquid
between the terminal and the LNG carrier, the stresses on the transfer system can be
significant.
Transfer of LNG at cryogenic temperatures through a loading hose also
presents the industry with technical challenges in managing system stress [ABS, 2002].
The LNG market is undergoing a major resurgence of activity both onshore and
offshore.
The transfer of cryogenic liquid such as LNG has become a very important
technological advancement in the industry. One of the originators of cryogenic transfer
systems is FMC Loading Systems. Since 1963, FMC has come up with the following
different offloading concepts:
*
Conventional onshore jetties with LNG Marine Loading Arms
" Offshore LNG plant on a gravity structure with offloading carried out using
Chiksan LNG Marine Loading Arms
35
*
Ship-to-Ship transfer between an LNG carrier and a FPSO or FSU using the
Chiksan LNG Marine Loading Arms shown in Figure 11 designed for
significant wave heights of up to 4.0 meters
*
Tandem loading between a dedicated LNG carrier and a FPSO or FSU using an
FMC Boom-to-Tanker as show in Figure 12 required for severe sea conditions;
the first Boom-to-Tanker system has been used at Brunei LNG for 23 years
with no LNG shipment missed; the system is designed for wave heights up to
5.0 meters [Offshore Technology, 2003]
Figure 11 - FMC Chiksan LNG Marine Loading Arms [Offshore Technology, 2003]
36
Figure 12 - FMC Boom-to-Tanker Offloading System [Offshore Technology, 2003]
In the past, the actual ship-to-receiving facility transfer of some type of liquid,
typically LPG, could be done with either a tandem arrangement which is show in Figure 13
or a side-by-side arrangement which is show in Figure 14. The GBS and FSRU receiving
terminals both use side-by-side arrangements. A single point mooring system is a common
mooring system that weathervanes around an anchored point offering maximum utilization
and minimum expense. The Catenary Anchored Leg Mooring buoys or CALM buoys,
shown in Figure 15, are frequently used.
Figure 13 - Tandem Offloading Arrangement [Scherz, 2003]
37
=0~~~~-
- - -.- -- w b clm - - --
Figure 14 - Side-by-side Offloading Arrangement [Scherz, 2003]
Figure 15 - CALM Buoy [Scherz, 2003]
In the past, there has been a lot of success with LPG offshore transfer. Propane and
butane has been transferred at approximately -45' C. The challenge with the transfer of
LNG is that the transfer system must accommodate fluid at approximately -160 ' C. There
must be a secure mooring arrangement in place. Furthermore, there needs to be minimum
relative motion between the LNG vessel and the transfer facility. This can be
accomplished using extended travel loading arms and flexible cryogenic lines [Scherz,
2003].
38
For fixed receiving terminals, there are several different mooring options. In
locations where there are benign conditions, conventional jetty head arrangements and
gerris arrangements are often used as seen in Figure 16. Currently, the CGI Bishop
Process would use a conventional jetty head as its mooring option.
Conventional
etty Head
The Gerris
Figure 16 - Conventional Jetty Head and Gerris Mooring Arrangements [TotalFinaElf, 2001]
Mooring arrangements that take advantage of weathervaning are more flexible than fixed
arrangements in multi-state conditions. Figure 17 shows an example of a turret moored
arrangement with a flexible hose line. The El Paso Energy Bridge system uses an internal
CALM buoy that can weathervane. The ability to weathervane significantly increases the
offloading transfer success rate during rough or severe conditions. Other weathervaning
innovations include a rotating dock or a rotating boom with a flexible hose line.
39
Figure 17 - Weathervaning Mooring Arrangement [TotalFinaElf, 2001]
Link technologies are another important part of LNG offshore transfer and
handling. FMC has developed and tested an extended loading arm, illustrated in Figure 18,
suitable for ship-to-ship LNG transfer. Moreover, subsea cryogenic pipelines have been
developed to ensure the flow of LNG from the offshore marine facility to the shore. A
typical subsea cryogenic pipeline includes an inner pipe capable of handling cryogenic
liquids, specialized insulation material, an intermediate barrier of low temperature steel,
and an outer pipe of steel [Interpipe, 2002].
Figure 18 - FMC Extending Loading Arm [FMC Loading Systems, 2003]
40
GAS HYDRATES AND OTHER NATURAL GAS TECHNOLOGY
While this paper describes LNG and its application to the energy industry, there are
other natural gas technologies that are being looked at as possible solutions to bridge the
forecasted energy supply gap in the near future. The following section gives a quick look
at the different hydrate and natural gas technologies that are currently in the industry.
Domestically produced and readily available to end-users through the existing
utility infrastructure, natural gas has become increasingly popular as an alternative
transportation fuel. Natural gas is also clean burning and produces significantly fewer
harmful emissions than reformulated gasoline. LNG technology is widely used for largescale transport of natural gas for long distances by ship. Annually, about 100 million tons
of LNG are transported and traded worldwide. For comparison, the worldwide transport
and across-border trading of natural gas by pipeline is about three times this
[Gudmundsson, 2001].
Aside from LNG, CNG technology is widely used to store energy in cars and
buses. Such small-scale use of CNG is expanding worldwide. Natural gas storage in highpressure bottles exists.
Promoters of CNG ocean transport technology say that
advancements in design, compression, ship construction techniques, materials, and gas
management systems have improved the relative economics of their technology over
pipelines, LNG, and deepwater re-injection, offering an attractive transport medium in
many locations. Furthermore, unlike synthetic hydrates, the technology is fully understood
and ready for commercial adaptation on a large scale. CNG ocean transport, they believe,
41
can either provide a long term dedicated fleet capable of moving hundreds of billions of
cubic feet per year, or it can offer a short term flexible solution to reserves awaiting
pipeline construction or in need of extended well tests [Zeus, 2001].
Another natural gas technology is GTL. GTL is a process for converting natural
gas into synthetic oil, which can then be further processed into fuels and other
hydrocarbon-based products. In the simplest of terms, the GTL process tears natural gas
molecules apart and reassembles them into longer chain molecules, like those that
comprise crude oil.
However, with this particular conversion process, the result is an
extremely pure, synthetic crude oil that is virtually free of contaminants such as sulfur,
aromatics and metals. This synthetic crude can then be refined into products such as diesel
fuel, naphtha, wax and other liquid petroleum or specialty products [Rockwell, 2003].
The GTL process chemically converts natural gas (methane) molecules into other
compounds. Once converted, these liquids are stable and will remain in the liquid state.
LNG, on the other hand, is only a change of state.
It is when gaseous methane is
cryogenically chilled and changed into liquid methane at -260' F. It is still methane and
will return to the gaseous phase if allowed to warm up to ambient conditions. GTL and
LNG are similar in that the goal of both processes is to convert isolated natural gas
reserves into something that can be efficiently transported to market. They are also similar
in that both processes are very capital intensive, and must be done on a large scale to be
economical [Conoco, 2003].
The last most commonly noted natural gas technology is NGH. NGH can store 180
to 200 times the volume of natural gas as that of the hydrate.
42
This property makes
hydrates economically interesting for storage and transport of natural gas. NGH can be
stabilized above freezing at moderate pressures, or below freezing at atmospheric
pressures. According to Ben C. Gerwick, Inc., approximately 80% of new gas fields are
smaller than 0.25 Tcf, which is an appropriate size for NGH development. Furthermore,
Gerwick claims that the use of NGH peak storage facilities can economically satisfy the
growing demand for natural gas power plants, while minimizing new pipeline construction
[Berner, 2003].
43
CHAPTER
4: FINANCIAL CHALLENGES FOR LNG PROJECTS
FINANCIAL ISSUES WITH LNG MARKET
Over the past 30 years, the capital cost of implementing LNG projects has risen
steadily due to both substantial rates of inflation and increasingly larger project facilities
designed to exploit economies of scale. There has been a trend of larger ships built to span
to more distant markets.
A large challenge of LNG projects in modern times is that
billions of dollars of debt financing is needed for project implementation [Greenwald,
1998].
Before starting an LNG project, it is necessary to consider the market fundamentals
and risk considerations.
Since the traditional supply basins in the U.S. and Canada are
facing decline, there is opportunity within these LNG projects. Furthermore, there is a
very mature infrastructure of pipelines and storage facilities already in place.
Another
opportunity is in place due to the price transparency and strong forward price curve. With
the FERC deciding to waive "open access" for onshore terminals, there is more
opportunity for potential investors [Khettry, 2003].
However, one must consider the risk of these projects. First, there are multiple
stranded gas supplies basins competing for access. Also, limited terminal capacity favors
expansion LNG suppliers.
There is a merchant power glut that leaves few end-users
willing to commit to long term purchase contracts [Margulis, 2003].
44
The natural gas supplies for LNG facilities are abundant and can be produced
inexpensively.
In spite of this, the processing and transportation equipment is capital
intensive and highly specialized, requiring hundreds of millions of dollars of investment
for each new facility. For each cubic foot of natural gas delivered to end-users, less than
30 %of the cost is for the commodity itself [EIA, 2002].
The balance reflects the costs of processing and transportation.
LNG projects,
regardless of where in the value chain, can vary significantly due to site-specific
construction costs. The EIA breaks LNG projects into the different elements of an entire
project:
- Abundant low-cost natural gas reserves
A successful LNG project must have enough proved reserves of natural gas
available to support liquefaction capacity for the life of the plant (20+ years). In
addition, production costs (including applicable production taxes levied by the host
government) need to be low (typically, less than 1.0 $/Mcf, and preferably on the
order of 0.5 $/Mcf).
- A liquefaction facility
The liquefaction plant is typically the most expensive element of an LNG project.
The cost depends on a host of site-specific factors, including the project's scale,
with larger projects having lower unit costs. Operating costs are relatively minor.
45
Liquefaction is a very energy-intensive process, with typically about 8-9 % of the
plant's input used as plant fuel.
- LNG tankers
Each project requires several dedicated LNG tankers. These are among the most
complex and expensive merchant ships ever built because of their double hulls and
special cryogenic lining. Each new 135,000 m 3 (3 Bcf) capacity tanker costs
approximately $160 million. The tanker's LNG cargo is kept cool by evaporating a
fraction of the cargo ("boiloff") and burning it as boiler fuel. Typically, 0.15-0.25
% of the cargo is consumed per day, during which the tanker will travel about 480
nautical miles.
- Regasification plant
LNG can be unloaded only in specialized terminals, which typically include a jetty
and unloading facilities, LNG storage equal to at least a single tanker cargo,
regasification facilities, and connections to pipelines. The cost of the regasification
terminal varies with capacity, local construction costs, and the amount and type of
site preparation costs. Regasification plant costs are typically considerably lower
than liquefaction plant costs. Regasification energy requirements consume a further
1.5-3.0 % of the delivered LNG. The marginal cost of either utilizing excess
capacity at an existing regasification plant with excess capacity or expanding the
46
capacity of an existing plant would be far lower than the cost of building a new
Greenfield facility [EIA, 2002].
An LNG project is not likely to proceed unless the developers receive some
assurance that they will be able to earn an acceptable return on their investments.
A
successful LNG project requires a price that is low enough to motivate consumers to use
large volumes of natural gas, yet still high enough to persuade developers and borrowers to
actually build the project [EIA, 2002].
One risk that cannot be ignored is the likely
formation of an LNG cartel, given that so few countries control such a large portion of the
world's stranded natural gas reserves, and its power to affect LNG prices. While the spot
market is a common way to enter the LNG market, LNG developers will still seek long
term contracts for their product at a price that is sufficient enough to cover their capital
costs and service debts even in a lower than anticipated energy price environment [Lewis,
2003].
Financially, there are two primary alternative structures for setting up an LNG
terminal. The first is a merchant structure. Under this structure, there is cognizance of a
growing spot market. Debt has to be supported by back-to-back contracts, due to there
being an often occurrence of collapse in merchant power deals [Margulis, 2003]. The main
characteristic of a merchant operation is that the terminal entity is the signatory of the
Sales and Purchase Agreement.
The Sales and Purchase Agreement is generally the final contract. It defines the
terms under which the buyers and sellers will work together over the life of the project. It
47
will cover issues like invoicing, payment, LNG composition, default provisions,
procedures for dispute resolution and arbitration, force majeure, communications, and so
forth [LNG Express, 2003]. Under the merchant structure, the terminal entity is supported
by back-to-back off-take agreements and it sits contractually between the LNG producer
and the gas user. Furthermore, a merchant structure effectually pays for its own services
through the margin achieved between the cost of gas and the sales price into the local
market.
The merchant entity is effectively responsible to its customer for making
deliveries of gas and taking all upstream operating risks with the exception for force
majeure [CWC Group, 2003].
The second type of alternative structure is a tolling structure.
Under this
arrangement, the terminal infrastructure is built and financed by a special purpose entity
that contracts out its services to the user in exchange for a fee. The user is either the seller
of LNG or more typically, the purchaser of regasified gas [Khettry, 2003].
The fee
represents the entity's only source of cash flow and over operating expenses, debt service
(interest and principal amortization), taxes, and shareholders returns. The tolling unit may
be subject to certain volume fluctuation reflecting the volume variations provisions of the
Sales and Purchase Agreement itself. To deal with this risk, a tolling unit will typically be
remunerated through a combination of a capacity fee and a usage fee. The capacity fee is
sized to cover variable operating costs, minimum debt service obligations and the base
return on equity, and is paid based on the level of usage to reflect the tolling unit's
obligation to make the capacity available [CWC Group, 2003].
48
Howard L. Margulis of Holland & Knight, LLP outlines the salient features of a
bankable LNG Sales and Purchase Agreement below:
" Long term contract based on the concept of take or pay.
" Some of the more recent contracts signed have Liquidated Damages for
shortfall quantities.
*
Force Majeure risk should be allocated fairly.
*
Condition precedents to the effectiveness of the Sales Purchase Agreement
should be as objective and unambiguous as possible.
" Quality specification of the LNG should match with the quality specification of
gas required by the end-users.
*
Allowances for loading port delays should be minimized.
* Both the Buyer and the Seller should have termination rights under extended
Force Majeure.
"
Should be a clause that in the event of certain circumstances beyond their
control, the Buyer and Seller shall cooperate even though the LNG Sales and
Purchase Agreement will have its sale price indexed to an index [Margulis,
2003].
Due to the integrated nature of the LNG chain, the risks along the entire chain have
to be properly mitigated. Table 3 gives a detailed explanation of the possible risks in LNG
projects and the likely mitigants.
49
Table 3 - LNG Project Risks and Mitigants [CWC Group, 2003]
RISK
Cost overrun and completion risk of
regasification facility, marine works, and
pipelines
MITIGANT
- Fixed price turnkey EPC contract
- Contingency of 10 - 15% of EPC cost to be budgeted as part of
project cost
- Sponsors to provide completion support to the satisfaction of
lenders
- Well-regarded EPC contractor with experience in constructing regas
and marine facilities of the size and type planned by LNG company
- Liquidated Damages of 20% of contract price for delays
- LDs of 10% of contract price for inability to me Guaranteed
Performance Standards
- Maximum LD liability of contractor capped at 20% of Contract Price
Cost overrun and completion risk of endusers' facility
- Fixed price turnkey EPC contract for end-users' facilities
- Adequate level of budgeted contingency and completion support
- EPC contract to provide adequate LDs to pay damages for inability
to take regasified LNG from LNG company
- Well-regarded EPC contractor and use of proven technology
- Independent Engineer's technical report
The operator of the regas facility may not
be able to operate the facility effectively
- An experienced and well-regarded operator for the regas facility
and marine works
- O&M contract to provide adequate incentives and penalties to
motivate the operator
- Adequate LDs for demurrage, excess boiloff gas, etc.
- Adopt a comprehensive safety management system which should
become operative during the plant design phase
50
MITIGANT
RISK
The operator of the end-user's facility may
not be able to operate the facility
effectively
- Many end-users already have existing facilities with experienced
and well-regarded operators
- Due diligence will be required on the operators of end-users
- O&M contract to provide adequate incentives and penalties to
motivate the operator
- Adequate LDs for non-performance
Sufficient gas offtakers may not be
available for LNG company to sell its entire
capacity
- Adequate demand exists
- At U.S. 3.0-3.5 $/MMBtu, LNG is competitive compared to piped
gas for some markets
- Use of LNG leads to increased efficiency in power generation
- LNG is environmentally benign and thus, easily acceptable to
offtakers
The project faces the risk of accidental
damages and third party liability resulting
from events
like pipeline leakage, fire, etc.
- Adequate insurance to cover business interruption and third party
liability
- Sponsors to provide support for this party liabilities in excess of
insurance
- Risks to be shared if gas transporter is company other than LNG
company
The international lenders might be
unwilling to take a view on the credit of
end-users for 10-15 years
- Lenders will need to get comfortable with the credit risk of the entity
back stopping the SPA, and the level of merchant risk, if any
51
LNG SPOT MARKET
An LNG spot market is a market option that offers short term contracts for set
amounts of natural gas, thus establishing prices that vary in real time.
Gas companies
operate on-site liquefaction, storage, and regasification plants while others depend on
what's called satellite peakshaving facilities that cannot liquefy natural gas, but can store
and regasify LNG delivered to them by cryogenic trucks [AGA, 2002].
James P. Lewis, chairman of Project Technical Liaison Associates, concludes the
following:
Underground natural gas storage pretty much meets winter demand
needs except on the coldest five to 10 days. If you're a Boston gas
utility, underground storage in Pennsylvania isn't that big of a help
when demand suddenly spikes. What you need is peakshaving
capability at the point of use rather than having to transport gas from
underground storage. Using LNG in the peakshaving mode provides a
local, high-deliverability source of supplemental supply [Lewis, 2002].
There have been very few peakshaving plants that have been built since the mid1970s. With the projections showing a large increase in LNG demand, there should be a
need for additional peakshaving capacity. In fact, there is already a development of an
LNG spot market in the Atlantic Basin. The evidence of this is as follows:
*
50 %of US cargoes in 2000 were spot sales.
*
8 %of total LNG sold in 2000 were spot sales.
0
Distrigas has re-routed LNG to US and substituted with European gas.
*
TotalFinaElf has re-routed cargoes originally for the US to European
destinations.
*
The plan of major LNG players based on increased spot trading [Stohle, 2002].
In the 1980s, the U.S. regulatory regime and the gas "bubble" was reshaped and
resulted in significant hardship for many industry players [Candelet, 2003]. Consequently,
all for import terminals were affected, with only the Everett, terminal staying open. The
Cove Point and Elba Island terminals were mothballed, and used only for peakshaving.
Lake Charles only imported limited volumes.
Since 1990, domestic production has only grown by approximately 4.5 Bcf/day.
Unless new supply or imports are found, the supply gap could be up to 16 Bcf/day by 2010
[BG Group, 2003]. There is a view amongst industry leaders that peakshaving with LNG
could be a solution. The following outlines the basic steps that are in a spot trade:
"
Put Master Agreement in place
" Agree and confirm date of loading/unloading
" Confirm type of deal and price (Complete Term Sheet)
" Place and obtain letter of credit
" Load cargo
*
Delivery of cargo
*
Agree on quantity delivered
" Agree payment due based on quantity and market price
*
Make payment for delivered cargo
*
Close out the letters of credit [Candelet, 2003]
53
J7~C~
-
--
-
CHAPTER 5: OFFSHORE LNG RECEIVING TERMINALS
GRAVITY-BASED STRUCTURE
A GBS system for receiving terminals is a large, concrete structure that can be
situated in water deep enough (15-30 meters) to enable birthing of the largest LNG tankers
without dredging.
Consequently, this significantly reduces the overall environmental
impact relative to the installation of a land-based terminal [Stone, 2002].
They would be built, outfitted with tankage, mated with its topsides, towed to the
terminal site and ballasted down to the sea floor. The most effective means of founding
the GBS in soft soils is by constructing concrete skirts. These concrete skirts are simply
vertical structures that cut through the solid foundation to stiffer material below [Foster
Wheeler, 2002]. Figure 19 shows the cross-section of the GBS sitting in the soil.
___<~.i...............
Figure 19 - GBS cross-section [Foster Wheeler, 2002]
The advantage of using concrete as opposed to using steel is that concrete is very
well-suited for cryogenic liquids such as LNG. Furthermore, concrete is less expensive
54
-
--
~
than steel, therefore lowering construction costs. Table 4 shows the advantages for using
concrete and steel for LNG storage.
Table 4 - LNG Storage Advantages for Concrete and Steel [Berner, 2003]
LNG Storage Advantages
Advantages for Concrete Hulls
Superior Cryogenic Behavior
Good Separation of Processing/Storage
Reduced Down-Time Due to Inspection
Reduced Maintenance Costs
Economies of Scale
Good Impact Resistance
Low Center of Gravity/Good Station Keeping
Behavior/Reduced Motions
Excellent Fatigue Life
High Mass Moment of Inertia
Slower Thermal Response/Better Insulation
Resistance to Fatigue and Crack
Propagation
Resistance to Buckling
Advantages for Steel Hulls
Fabrication in Existing Shipyards
Potentially Lower First Cost for One Hull
Traditional Engineering
Traditional Construction
More Steel Fabricators are Available
More Steel Designers are Available
Greater Flexibility Reduces Thermal
Stresses
Not Subject to Freeze-Thaw Damage
Prestressing Not Required
Impermeable to Gas and Liquids
Similar to Numerous LNG/LPG Ships
Does Not Require a Membrane Liner
In addition, Foster Wheeler evaluated the use of concrete substructures for support
of LNG production facilities and storage and revealed the following benefits:
*
Concrete is well suited to local construction
"
Concrete substructures built in purpose built graving docks are not size
constrained
*
Concrete floating substructures realize superior motions compared to steel hulls
*
Concrete substructures are well suited to the storage of LNG
*
Concrete substructures are resistant to LNG spill conditions
*
Concrete is a durable material
" Concrete substructure operating expenses are minimal [Foster Wheeler, 2002]
55
-
The great advantage of the GBS terminal concept shown in Figure 20 is that it is
very easily expandable. Additional GBS units may be constructed and installed adjacent to
existing facilities and linked to the existing GBS by simple shallow water jackets and a
bridging structure. If expansion occurs, the GBS terminal provides much more breakwater
protection than the original installation as well as more berthing capability. Therefore, the
flexibility of the GBS solution is its greatest attraction.
Figure 20 - GBS terminal [Foster Wheeler, 2002]
56
-~
-~ --
-
~U~i~7f~
FLOATING STORAGE AND REGASIFICATION UNIT
An FSRU is a large, floating steel structure that has storage and regasification of
LNG capabilities. The FSRU really acts as a hybrid of both an offshore storage unit and
an oceangoing LNG ship. The FSRU shown in Figure 21 is connected to a gas pipeline.
The vessel would receive LNG from LNG carriers, store the product, and offload the gas to
a local pipeline via a turret/swivel and riser arrangement [Lloyds, 2002].
Figure 21 - Moss Maritime FSRU design [Moss, 2002]
IHI1 Marine United illustrates the concept flow of its proposed LNG storage and
regasification plant in Figure 21.
The advantage of using an FSRU is that it can be
offloaded in a side-to-side position or a tandem position.
57
The Moss Maritime
UT~1TJ1YffLL T*_i~~-
-
-~
configuration shown in Figure 22 illustrates the side-to-side position. Figure 23 shows the
IHI FSRU in both a tandem and side-to-side offloading position.
Another advantage of the FSRU is that it is able to weathervane.
opposed to the GBS which is in a fixed position.
This is as
While the GBS provides a greater
windbreak, the FSRU is allowed to move around its single point mooring system in
different sea states.
RECEIVING
+S
GE-
PP R
-. -
B00STNER
GAIWCAT ON ANDFEED
[LNG STORAGE SYSIEh
4
BOIL OFF GAS
|
ABSORBER
BOG
UNIT
COMPRESSOR
BOIL OFF SYSTEM
GASIFICATI
REGASIFIED
NATURAL GAS
SYSTEM
4
I
IUTILITIES1
Figure 22 - IHI Concept Flow of an FSRU LNG Storage and Regasification Plant [IHI, 2003]
58
Figure 23 - IHI FSRU in Side-To-Side and Tandem Offloading Positions [IHI, 2003]
EL PASo ENERGY BRIDGE
The El Paso Energy Bridge is what Lloyd's Register defines as an LNG
Regasification Vessel or LNGRV.
The LNGRV is effectively an LNG carrier, but
regasifies the LNG onboard and directly sends the natural gas from the ship to a local
pipeline.
This facility requires a Submerged Turret Production system, which is a
connectable mooring/swivel [Lloyds, 2002]. A mooring/gas transfer buoy or equivalent
system is required, along with a regasification plant.
El Paso has unveiled its LNGRV which it calls the Energy Bridge. The Energy
Bridge, shown in Figure 24, brings LNG into the U.S. via this Energy Bridge using LNG
ships that will anchor miles offshore, regasify the LNG onboard the ship, and feed gas
directly into pipelines.
59
-q
Figure 24 - El Paso Energy Bridge [El Paso, 2002]
A consortium headed by Exmar, a Belgian shipper and operating company, will
initially build three of these ships, with the first to be delivered during the fourth quarter of
2004 [Antosh, 2002]. With the LNG being regasified onboard the ships, this avoids the
expensive issue of building a storage and regasification terminal itself. An offshore buoy
and turret system is used in place of a standard terminal.
Similar to the FSRU, the
submerged buoy and turret system is capable of weathervaning.
For about a decade, Energy Bridge ships have been used in the North Sea and over
1400 connections have been made with a 100% success rate [Harmon, 2003].
Ideally,
these facilities will be 10 or 12 miles from shore and in at least 35 meters of water. The
system uses conventional LNG tankers that are simply modified with pumps and a
vaporizer that is added to the deck. There is no reduction in LNG tank capacity.
60
While the system can offload in almost any sea state, the big disadvantage is that
since the LNG is regasified onboard the ship, it takes approximately 8 days for a 135,000
m 3 LNG tanker to offload as opposed to about a 22-24 hour turnaround time to offload
LNG itself. Furthermore, it feeds the natural gas into the subsea pipeline at 0.5 Bcf/day.
For the latter two reasons, the Energy Bridge is aimed at serving small to medium-sized
markets that do not have a land terminal [Antosh, 2002].
CONVERSION GAS IMPORTS BISHOP PROCESS AND SALT CAVERN STORAGE
The most unique solution to the receiving terminal capacity shortage is CGI's
This is a patented process that utilizes both
Bishop Process and Salt Cavern Storage.
onshore and offshore salt caverns for storage as opposed to steel or concrete tanks. The
Bishop Process, illustrated in Figure 25 is a patented process that:
" receives LNG cargo from the ship
*
pumps it to cavern injection pressures
" warms the process stream to salt compatible temperatures using high
pressure/high capacity heat exchangers outside of the caverns
" directly injects the dense vapor stream into salt caverns for storage [CGI, 2003]
61
LNG Process
Flatform
Cavern
Platform
To subsea gas cathering
Irtra stu cture
'2000 PS
Cavem Gas
StorageII
Figure 25 - CGI Bishop Process and Salt Cavern Storage [CGI, 2003]
Since there are more than 1000 caverns storing hydrocarbons in North America
already, CGI believes that this is the appropriate solution for LNG storage. The Gulf of
Mexico is particularly rich in salt formations.
Since there is already a large energy
infrastructure in that area as shown in Figure 26, the CGI Bishop Process has the
advantage of having large sendout capacities. Michael McCall of CGI notes:
Over the past 35 years, we have believed that LNG must move from a
storage tank at the liquefaction facility to a storage tank at the
receiving facility. It works well, its safe, accepted, and no longer
presents any unique technical challenge. But siting, security, and
economic issues are forcing us to rethink this method. The CGI
"Bishop Process" terminal will profoundly impact the next generation
of LNG receiving terminals. Rather than receiving and storing liquid
natural gas until such time that it is vaporized and delivered to the
customer, CGI's terminals are 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 sendout limitations associated with cavern storage. The caverns can receive
62
flow from a ship and redeliver to a pipeline grid at rates greater than 3
Bcf/day [McCall, 2003].
Figure 26 - Volume of Natural Gas in U.S. [EIA, 2002]
The use of salt cavern storage is thought of as a disruptive technology for the
storage of LNG.
The reason this technology has been looked at before is because
conventional LNG technology has historically been modeled on Japanese practices, which
is onshore receiving terminals with large storage tanks [McCall, 2003].
However, salt
caverns are already used as a medium for hydrocarbon storage.
These salt caverns shown in Figure 27 and Figure 28 are formed with a leaching
process by injecting a water stream down a well bore. The water washes the cavern via the
bore inner annulus [CGI, 2003]. A brine solution is formed during this process and escapes
up the bore outer annulus. The pressures needed in the caverns are a function of the depth
63
of the cavern.
CGI calculates that 12 Bcf of natural gas storage can be formed in
approximately 12 months for about $40 million [CGI, 2003].
STORAGE WELL
GULF COAST SALT DOME
Figure 28 - Gulf Coast Salt Dome [ICGI, 2003]
Figure 27 -Salt Cavern Storage Well [CGI,
2003]
On state and federally owned lands, there are established protocols to lease salt
cavern storage rights. Federal and state lands held by others with oil and gas exploration
leases can be simultaneously leased for salt cavern storage as, since salt cavern storage is
considered an "alternate use on a non-interference basis with existing exploration and
production leases" [McCall, 2003].
Moreover, CGI believes that this system would work well in conjunction with El
Paso's Energy Bridge concept.
Since the Energy Bridge concept uses offshore delivery
points, the LNG tankers would send the dense phase gas directly into the salt caverns for
storage [Guegel, 2002]. Financially, the salt cavern solution would offer great economies
64
of scale if it is feasible, which is an advantage considering that the U.S. wants to
dramatically increase natural gas usage over the next decade.
65
CHAPTER
6: RESULTS
MODEL DESCRIPTION
The regasification and storage facet of the LNG value chain is the smallest portion
of cost when compared to the shipping, liquefaction, and exploration and production sides.
However, this paper is directed to show the current options for offshore LNG receiving
terminals and the advantages and disadvantages of each.
This chapter describes a
computer-based simulation model which calculates the unit costs for the regasification and
storage of each of the four different offshore LNG receiving terminal options, as well as
the associated shipping costs.
The unit cost in this case is defined as the cost per unit of capacity ($/Mcf)
discounted at a given amount over a given period of years for a project. By doing this, one
can compare the various unit costs for the different receiving terminal options by
manipulating the different variables and inputting different assumptions in the model.
Since the regasification and storage facet of the value chain is directly correlated to
the shipping side, it is important to show both sides with the respective unit costs and
variables. There are three primary reasons why the regasification/storage and the shipping
costs are related.
First, the cost of the LNG tanker can be dependent on the receiving terminal option.
This is the case with the El Paso Energy Bridge. There is about a 10-15% increase in the
66
LNG tanker construction cost due to the tanker being modified with extra pumps and
vaporizers necessary to regasify the LNG onboard the ship.
Second, the turnaround time, which is defined as the time between the arrival and
departure of a ship in port, is directly related to the type of LNG receiving terminal. For
example, since the El Paso Energy Bridge regasifies the LNG onboard, the turnaround time
in port is significantly longer. Furthermore, the CGI system uses the Bishop Process to
regasify the LNG; consequently, it takes a couple hours longer than the standard method of
offloading LNG.
Variations in turnaround time ultimately affect the amount of trips
necessary and the amount of ships needed to fulfill a given needed daily sendout of natural
gas.
Third, depending on the receiving terminal option, the expected number of days
lost to bad weather during offloading can change greatly. For example, thus far the El
Paso Energy Bridge has a 100% offloading success rate in the North Sea. On the other
hand, the other receiving terminals offload the LNG in the liquefied state. Therefore, it is
more difficult to offload and more benign conditions are desired. Moreover, depending on
the receiving terminal option design, the terminal can be more or less influenced by
different sea state and weather conditions. This is shown with the GBS system creating a
larger breakwater with its design or the FSRU being able to weathervane around a single
point mooring.
Trade Route Assumptions
The LNG Receiving Terminal Unit Cost Model is flow-charted in Figure 29. The
first task in using the model is to define the trade route assumptions. In this case, the most
67
Trade Route Assumptions
Base Case Sendout
Assumptions
LNG Shipping & Transfer
Assumptions
Project Assumptions
Determine Unit Costs and
Output Results
Figure 29 - Flow Chart of LNG Receiving Terminal Unit Cost Model
common import route used for LNG into the U.S. is the trade route from West Africa to the
Gulf Coast.
The three key variables defined in the base case are assumed to be:
Round Trip Distance:
12,000 nm
Overhaul Days per Year
30 days (*this is a conservative estimate)
Turnaround Time:
22 - 24 hours (*Energy Bridge is 192 hours)
Daily Sendout Assumptions
Next, a daily natural gas sendout assumption should be imputed into the model.
The number, measured in Bcf/day, is the most important input for the model. This sendout
assumption is the key factor in determining the overall capital costs of the shipping and
regasification aspects of the value chain. Note that the sendout affects the capital costs
more so than the unit costs.
68
Base Case Daily Sendout Assumptions:
GBS:
0.9 Bef/day
FSRU:
0.6 Bcf/day
Energy Bridge:
0.5 Bcf/day
CGI:
1.7 Bcf/day
LNG Shipping & Transfer Assumptions
Of lesser importance, the LNG shipping assumptions should be imputed into the
model.
The LNG boiloff and regasification losses are part of these assumptions.
As
described in Chapter 4, the tanker's LNG cargo is kept cool by evaporating a fraction of
-
the cargo, which is known as the boiloff, and burning it as boiler fuel. Typically, 0.15
0.25% of the cargo is consumed per day. In addition, regasification energy requirements
consume a further 1.5 - 3.0% of the delivered LNG.
The base case boiloff and
regasification losses in this case are the following:
Boiloff per Day:
0.2%
Regasification Losses:
2.5%
Furthermore, there is an automatic load factor of 98% included in the model formulas.
This is not a direct input, but can be adjusted in the formulas.
Project Assumptions:
The final assumptions to be imputed into the model are associated around the
regasification plant project itself. In most LNG projects' analyses, project discount rates
are around 10 - 17%. The discount rate is an important factor in determining the net
present value of a project. The results of the model will illustrate the sensitivity of unit
69
costs to a determined discount rate. Additionally, the length of a project in accordance to
the discount rate is imputed. This number is generally in the range of 15-30 years. The
model allows for one to determine the discount rate and the length of the project for both
the shipping and regasification side. The assumption in the base case is that the project
will include the new construction of LNG tankers and the receiving terminal.
Furthermore, the cost of the ships is to be determined.
In the model, the
assumption used in the base case is that an LNG tanker that has a capacity of 135,000 m 3
costs $0.165 billion. With the Energy Bridge, the base case assumption is adjusted for the
additional regasification equipment that is outfitted to the ship. The model allows for
economies of scale. This is a function of the LNG tanker capacity input which is another
adjustable and powerful input of the model.
Additionally, another significant assumption input is the days lost to bad weather
during offloading. Another way of saying this is the days lost to unsuitable sea states and
weather conditions. The base case assumption for each receiving terminal option is quite
significant because this variable is independent of other inputs. The base case assumptions
used in the model are determined by the author's evaluation of each terminal's ability to
The Energy Bridge is almost negligible for this
offload LNG in certain conditions.
variable because the regasification is done onboard and because this method has had a
100% success rate in the past. The following outlines the base case assumptions used in
the model for the project assumptions:
Discount Rate:
15%
Length of Project:
20 years
70
Cost of LNG Tankers:
$0.165 billion (Energy Bridge is $0.182 billion)
LNG Tanker Capacity:
135,000 m3
Days Lost to Bad Weather (Offloading):
GBS:
7 days
FSRU:
10 days
Energy Bridge:
1 day
CGI:
12 days
Finally, the model outputs the results of its calculations.
This is done
instantaneously and is actually adjusted in real time as the variables are adjusted. The
main outputs of the model are listed below:
*
Unit Capital Cost of the Regasification Terminal
" Capital Regasification Cost Total
" Cost per Ship
" Trip Time in Days
*
Adjusted Natural Gas Offload per Trip
*
Ship Required to Meet Gas Demand
" Total Trips per Year
" Capital Shipping Cost Total
" Unit Capital Shipping Cost
" Total Regasification & Shipping Unit Cost
71
While these are all outputs, the key outputs in the model and the unit costs for the
receiving and shipping parts of the project. Since these two facets are directly correlated,
the total unit cost based on the receiving terminal option is noteworthy as well.
LIMITATIONS OF MODEL
It must be noted that there are limitations to this model. The model is designed
around the premise that a given receiving terminal will be able to deliver a daily sendout of
natural gas between 0.2 - 4.0 Bcf/day. This is demonstrated by the fact that one cannot
input an unlimited daily sendout rate and expect to have realistic unit costs. Most current
receiving terminal projects usually have a design capacity for up to 1 Bcf/day sendout, but
never use it. However, it is predicted that over the next few decades this will change.
Additionally, the model is primarily originated around its base case and
consequently, most of the formulas used in the model and costs in the model are results of
this. For instance, the model is based around the case that the LNG is coming from West
Africa. While this is a very likely scenario, it is not always the case. Furthermore, the
model does allow for one to change the base case assumption of 12,000 nm distance round
trip. In spite of this, the greater this number is changed the more likely the results will be
less accurate.
Another important limitation is the relationship between the daily sendout and the
storage capacity of the receiving terminal.
The model assumes correctly that as the
sendout demand increases, so does the cost of building the receiving terminal. It even
72
accounts for economies of scale. Nevertheless, designs such as the FSRU and the El Paso
Energy Bridge cannot be infinitely big in capacity. With the Energy Bridge, the tanker
itself acts as the storage. Unless there is a shipping infrastructure that can handle 500,000
m 3 LNG tankers, it is not feasible to input a large sendout rate into the model.
Furthermore, the model does not give an insight of the operating expenses of each
receiving terminal option. This is done because while every receiving terminal option
varies significantly in construction cost, they share the same fundamental operating
expenses as each other. In addition, the unit costs of service numbers are diminutive in
comparison to the capital unit costs.
RESULTS
The basic question that the computer simulation model seeks to answer is: what is
the total unit cost of both the regasification/storage side and the shipping side as a function
of the daily sendout? Furthermore, the model seeks to answer this question as well: what
are the key cost drivers that are necessary to observe when comparing different receiving
terminal options?
A graph of total unit cost as a function of daily sendout is given in Figure 30. It
should be noted that economies of scale exist, but to a different degree for each of the
options. The CGI option has the largest apparent economies of scale. This is the case
because salt caverns can be created much larger with relatively little effort. This is as
opposed to a GBS system where one is essentially just adding more concrete structure or
an FSRU where one is building with more steel to create more capacity.
73
When total unit costs are compared between different options at different daily
sendouts, it becomes clear that the Energy Bridge is best suited for small or medium size
markets. The unit costs are greater for the Energy Bridge, but Energy Bridge offers certain
intangibles that make it difficult to dismiss as a viable option. The Energy Bridge is a
proven technology and can handle any sea state. LNG transfer is still a relatively young
technology part of the LNG industry. Until the transfer of LNG is a stable technology, key
cost drivers such as the days lost to poor sea conditions will always remain.
Figure 31 shows the unit cost breakdowns of each receiving terminal option.
According to the model, the CGI system offers the lowest unit costs for its base case. CGI
has the lowest unit costs largely because it is a relatively inexpensive process to drill
underground salt caverns that are used for storage. The CGI system does offer the greatest
sendout capabilities. An extremely appealing characteristic of the salt caverns is that they
can be expanded to large amounts for relatively little cost. The CGI system has the largest
upside of any of the other receiving terminal options.
While this is significant as a
receiving terminal option with great potential, it is still a new concept and it's a disruptive
technology.
One of the key cost drivers for a receiving terminal is the amount of days it will
lose due to not being able to offload LNG in poor weather conditions. The CGI system in
the base case has the poorest ability to offload LNG in rough or severe sea conditions. The
primary reason for this is because the concept involves a conventional jetty as its terminal.
As discussed in Chapter 3, the conventional jetty systems are limited to more benign sea
conditions.
74
Sensitivity of Total Unit Costs to Daily Sendout
$1.30
-
-
$1.35
$1.25
I
A
$1.20
\t
$1.10-
0.0
'S
n~ rx
-
$1.15
,i
I
I
I
I
I
0.5
1.0
1.5
2.0
2.5
Daily Sendout (Bcf/day)
-+-GBS -I-
FSRU ,-t
Energy Bridge -X- CGI
Figure 30 - Sensitivity of Total Unit Costs to Daily Sendout
75
3.0
Base Case Unit Cost Breakdowns
$1.40
$1.00
-
$0.80
-
$1.20
* Shipping
o Regasification
'U
$0.40
-
$0.60 +-
$0.20 4-
$0.00
-!--
GBS
FSRU
Energy Bridge
CGI
Receiving Terminal Option
Figure 31 - Base Case Unit Cost Breakdown
76
The Energy Bridge has the greatest ability to offload in any conditions. Figure 32 shows
the sensitivity of the different terminal options unit costs to the days they would lose not
being able to offload. The graph shows just the shipping unit costs as opposed to the total
unit costs in order to illustrate how key of a cost driver this is.
One of the crucial cost drivers for a receiving terminal is the amount of days it will
lose due to not being able to offload LNG in poor weather conditions. The CGI system in
the base case has the poorest ability to offload LNG in rough or severe sea conditions. The
primary reason for this is because the concept involves a conventional jetty as its terminal.
As discussed in Chapter 3, the conventional jetty systems are limited to more benign sea
conditions. The Energy Bridge has the greatest ability to offload in any conditions. Figure
33 shows the sensitivity of the different terminal options unit costs to the days they would
lose not being able to offload. The graph shows just the shipping unit costs as opposed to
the total unit costs in order to illustrate how significant of a cost driver this is.
The GBS structure is very large and provides a good windbreak.
The problem
incurred with such a large structure is that ship-to-GBS LNG transfer is a relatively fixed
transfer.
Unlike the FSRU, which has the ability to rotate, in the GBS LNG transfer
scenario, transfer success in more dependent on the transfer and handling system fixed to
either the LNG tanker or the GBS terminal itself. Despite this possible limitation, the GBS
still provides a much greater windbreak than the FSRU system.
Therefore, the GBS
should have fewer days lost than the FSRU, which is indicated in the base case
assumptions.
77
Sensitivity of Unit Shipping Costs to Days Lost to Bad Weather
(Offloading)
$1.80-
$1.60
I
$1.40
$1.20
$1.00
0
$0.80
$0.60
$0.40
$0.20
$0.00
0
2
4
6
10
8
12
14
16
Days
--- GBS FSRU CGI -5-- Energy Bridge
Figure 32 - Sensitivity of Unit Shipping Costs to Days Lost to Bad Weather
78
18
20
The FSRU type of receiving terminal can either have side-by-side transfer, tandem
transfer, or both when offloading LNG depending on the design. Despite the fact that there
is a great deal of give and flexibility inherit to the FSRU design, the structure provides
little breakwater and therefore is not as optimal of a design as the GBS in less benign
conditions.
Another cost driver that should be examined is the tanker size. Figure 33 shows the
sensitivity of the shipping unit costs to variations in tanker capacity in the model. In the
graph, we can conclude that all the receiving terminals options have similar sensitivities to
this. It appears that smaller economies of scale exist and that an increase in tanker capacity
has little effect in the shipping unit cost. This conclusion corresponds with the relatively
small increases in LNG tanker sizes over the past few decades. Currently, as shown in the
base case assumption, an LNG tanker with a capacity of 135,000 m3 is the standard. The
infrastructure for much large LNG tankers is simply not prevalent.
One of the more telling stories of the model is the sensitivity of the storage costs on
the regasification facet of the LNG chain to expected daily sendout demands. Figure 34
shows the difference between the receiving terminal options with these capital costs. The
Energy Bridge is not included in this graph because there is not storage at the "terminal."
The storage takes place in the LNG tanker. The GBS capital storage costs are clearly the
highest and most sensitive to changes in sendout.
However, these storage costs do not
reflect the unit costs. The storage costs are still significant in that they give investors a
look at the magnitude of a given LNG project.
79
Sensitivity of Unit Shipping Costs to Tanker Capacity
$1.10
Base case
135,000 m3
$1.05
1.
$1.00
I
I
$0.95
$0.90
$0.85
100,000
110,000
120,000
140,000
130,000
150,000
160,000
170,000
Tanker Capacity (m)
-+-GBS
-U-
FSRU
--
Energy Bridge
-OX-GI
Figure 33 - Sensitivity of Unit Shipping Costs to Tanker Capacity
80
180,000
Sensitivity of Regasification Storage Capital Costs to Daily Natural
Gas Sendout
$1.20
$1.00
$0.80
$0.60
$0.40
-
0
$0.20
$0.00
0.2
1.2
0.7
1.7
2.2
Daily Sendout (Bcf/day)
-+-GBS
-U-FSRU
CGI
Figure 34 - Sensitivity of Regasification Storage Capital Costs to Daily Natural Gas Sendout
81
Although the GBS option has substantial capital costs to accommodate a given
sendout demand, the GBS option provides much more flexibility in the possibility of
expansion to a terminal. This is as opposed to the FSRU option, which is built at a certain
capacity and is far more difficult to simply "add on" to. An FSRU can be compared to a
regular tanker without the "guts." Clearly, the CGI system provides the cheapest and best
economies of scale when referring to capital storage costs. As mentioned in Chapter 5, the
storage feature of the CGI system is a relatively inexpensive project.
Next, the model gives one a look at the sensitivity of total unit costs to variations in
expected discount rates for both the regasification and shipping facets of the LNG value
chain. Figures 35-38 show the result of a two-way table with respect to two variables:
regasification terminal discount rate and shipping project discount rate.
The base case
assumption was that both projects would have a 15% discount rate. The power of the
model is that since the discount rate is really up to the individuals involved in an LNG
project, the rates for both sides of the value chain can be imputed together and the output
of the total unit costs can be determined.
The graphs illustrate different total unit cost ranges that result from two discount
rate inputs. The significance of the graphs is that they show the sensitivity of the total
units to discount rate inputs. We can clearly see that in Figure 38, the CGI option is the
least sensitive to variations in the two discount rates as measured by the slope of the lines.
In Figure 35, Figure 36, and Figure 37, the other receiving terminal options have similar
sensitivities to the discount rates. However, the total unit cost ranges vary depending on
the receiving terminal option.
82
Finally, there must be a subjective examination at how other unforeseen or
excluded capital costs will affect the quantitative results of the model.
Costs such as
operating costs, siting/pipeline costs, and shipping costs due to the addition or subtraction
of ships required for a given project size can bear a significant change in the unit cost
outputs in the model. In Figure 39, Figure 40, Figure 41, and Figure 42, one can observe
that as realistic variations to these unforeseen or excluded capital costs are figured into the
model, the unit cost outputs of the model are varied significantly enough to mire the base
case output results.
For example, in Figure 39, one can see the impact of the unforeseen addition of just
one ship to the LNG project. The $165 million capital cost increase changes the total unit
cost from $1.20/Mcf to $1.28/Mcf. Furthermore, if the siting/pipeline costs added another
$100 million to the project, one can see that the new total unit cost would increase
$0.05/Mcf.
This is noteworthy because it makes the intangible factors pertaining to
selecting a given offshore receiving terminal option more influential than the estimated
comparative unit costs.
83
Sensitivity of GBS Total Unit Cost to Regasification & Shipping
Project Discount Rates
20%
19%
18%
-17%
16%
B
15%
e
*$1.40-$1.50
o $1.30-$1.40
14%
0
M$1.20-$1.30
O$1.10-$1.20
(D
13%
--
12%
-11%
i ..
0 $1.00-$1.10
N$0.90-$1.00
E $0.80-$0.90
$/Mcf
10%
-9%
8%
9%
10%
11%
12%
13%
14%
15%
16%
17%
18%
19%
20%
Regasification Discount Rates
Figure 35 - Sensitivity of GBS Total Unit Cost to Regasification & Shipping Project Discount Rates
84
Sensitivity of FSRU Total Unit Cost to Regasification & Shipping
Project Discount Rates
.19%
18%
17%
-16%
O
-15%
2.
0$1.40-$1.50
-14%
e
E $1.30-$1.40
N$1.20-$1.30
0
0$1.10-$1.20
!!
0 $1.00-$1.10
-13%
-11%
*
N$0.90-$1.00
-12%
O $0.80-$0.90
$/Mcf
-10%
-9%
8%
'!
9%
i
1
10%
11%
I
12%
13%
14%
I
15%
I
16%
I
17%
8%
I
18%
19%
20%
Regasification Discount Rate
Figure 36 - Sensitivity of FSRU Total Unit Cost to Regasification & Shipping Project Discount Rates
85
&
Sensitivity of Energy Bridge Total Unit Costs to Regasification
Shipping Project Discount Rates
-19%
-18%
15%
.
-00
,
-17%
13%
12%
I 1/0
0
0$1.15-$1.25
+
14%
*$1.45-$1.55
o $1.35-$1.45
0$1.25-$1.35
0$1.05-$1.15
'D
*$0.95-$1.05
o3$0.85-$0.95
$/Mcf
-10%
9%
8%
i
1
9%
10%
11
11%
12%
13%
14%
1
1
15%
16%
8%
17%
18%
19%
20%
Regasification Discount Rate
Figure 37 - Sensitivity of Energy Bridge Total Unit Cost to Regasification & Shipping Project Discount
Rates
86
Sensitivity of CGI Total Unit Cost to Regasification & Shipping
Project Discount Rates
-20%
-19%
-18%
-17%
15%
.
6%
*$1.35-$1.45
0$1.25-$1.35
14%
13%
-,NEE==
12%
11%
(0
0$1.15-$1.25
0$1.05-$1.15
0$0.95-$1.05
*$0.85-$0.95
0$0.75-$0.85
$/Mcf
-10%
-9%
8%
9%
10%
11%
12%
%
13%
14%
1%1
15% 16%
1%
17%
1
18%
1%
19%
2 8%
20%
Regasification Discount Rate
Figure 38 - Sensitivity of CGI Total Unit Cost to Regasification & Shipping Project Discount Rates
87
Possible Added Cost Fluctuations to GBS LNG Project Base Case
Added Ship Costs ($ billions)
A # of
Ships
-2
-1
0
+1
+2
+3
A Capital
Cost
-$0.330
-$0.165
$0.000
$0.165
$0.330
$0.495
A %
New Shipping
Cost
$1.83
$2.00
$2.16
$2.33
$2.49
$2.66
-15%
-8%
0%
8%
15%
23%
New Total Unit
Cost
$1.07
$1.14
$1.20
$1.28
$1.34
$1.42
Siting/Pipeline Costs ($ billions)
+A Capital New Regas
Cost
Cost
$0.69
$0.00
$0.74
$0.05
$0.79
$0.10
$0.84
$0.15
$0.89
$0.20
$0.94
$0.25
%
0%
7%
15%
22%
29%
36%
New Total
Unit Cost
$1.20
$1.23
$1.25
$1.27
$1.29
$1.31
Operating Costs ($/Mcf)
+A Unit
Cost
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
New Total
Unit Cost
$1.20
$1.25
$1.30
$1.35
$1.40
$1.45
A
0%
4%
8%
13%
17%
21%
Figure 39 - Added Cost Fluctuations to GBS Project Base Case
88
Possible Added Cost Fluctuations to FSRU LNG Project Base Case
Added Ship Costs ($ billions)
New Shipping
Cost
$1.22
$1.39
$1.55
$1.72
$1.88
$2.05
A Capital
Cost
-$0.330
-$0.165
$0.000
$0.165
$0.330
$0.495
A # of
Ships
-2
-1
0
+1
+2
+3
A %
-21%
-11%
0%
11%
21%
32%
New Total Unit
Cost
$1.02
$1.13
$1.24
$1.34
$1.44
$1.55
Siting/Pipeline Costs ($ billions)
+A Capital New Regas
Cost
Cost
$0.40
$0.00
$0.45
$0.05
$0.50
$0.10
$0.55
$0.15
$0.60
$0.20
$0.65
$0.25
New Total
Unit Cost
$1.24
$1.27
$1.30
$1.33
$1.37
$1.40
%
0%
13%
25%
38%
51%
63%
Operating Costs ($/Mcf)
New Total
Unit Cost
$1.24
$1.29
$1.34
$1.39
$1.44
$1.49
A
%
+A Unit
Cost
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
0%
4%
8%
12%
16%
20%
Figure 40 - Added Cost Fluctuations to FSRU Project Base Case
89
Possible Added Cost Fluctuations to Energy Bridge LNG Project Base Case
Added Ship Costs ($ billions)
A # of
-2
-1
0
+1
+2
+3
A Capital
-$0.364
-$0.182
$0.000
$0.182
$0.364
$0.546
A %
-27%
-13%
0%
13%
27%
40%
New Shipping
$1.00
$1.18
$1.36
$1.54
$1.72
$1.91
New Total Unit
$1.00
$1.14
$1.27
$1.41
$1.55
$1.69
Siting/Pipeline Costs ($ billions)
+A Capital New Regas
$0.32
$0.00
$0.37
$0.05
$0.42
$0.10
$0.47
$0.15
$0.52
$0.20
$0.57
$0.25
A%
0%
16%
32%
47%
63%
79%
New Total
$1.27
$1.32
$1.35
$1.39
$1.43
$1.47
Operating Costs ($/Mcf)
New Total
$1.27
$1.32
$1.37
$1.42
$1.47
$1.52
A
0%
4%
8%
12%
16%
20%
%
+A Unit
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
Figure 41 - Added Cost Fluctuations to Energy Bridge Project Base Case
90
Possible Added Cost Fluctuations to CGI LNG Project Base Case
Added Ship Costs ($ billions)
A # of
-2
-1
0
+1
+2
+3
New Shipping
$4.30
$4.47
$4.63
$4.80
$4.96
$5.13
A Capital
-$0.330
-$0.165
$0.000
$0.165
$0.330
$0.495
A%
-7%
-4%
0%
4%
7%
11%
New Total Unit
$1.08
$1.12
$1.15
$1.19
$1.23
$1.26
Siting/Pipeline Costs ($ billions)
+A Capital New Regas
$0.52
$0.00
$0.57
$0.05
$0.62
$0.10
$0.67
$0.15
$0.72
$0.20
$0.77
$0.25
New Total
$1.15
$1.16
$1.17
$1.19
$1.20
$1.21
A%
0%
10%
19%
29%
39%
48%
Operating Costs ($/Mcf)
New Total
$1.15
$1.20
$1.25
$1.30
$1.35
$1.40
A
0%
4%
9%
13%
17%
22%
%
+A Unit
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
Figure 42 - Added Cost Fluctuations to CGI Project Base Case
91
CHAPTER 7: CONCLUSIONS
SUMMARY
The research in this paper has provided an analytical outlook on determining the
feasibility of various LNG receiving terminal options. In performing this research, certain
conclusions have been reached by the author. Quantitatively, one can look at the results
provided in Chapter 6 and see that the CGI system provides the greatest economies of scale
and the lowest unit costs. It is senseless to simply state that one terminal option is simply
better than another without evaluating the location and the sendout demands. However,
the following conclusions can be stated:
*
The CGI system provides the lowest unit costs and best economies of scale
" The CGI is the most unproven technology
" The Energy Bridge is the most proven technology
*
The Energy Bridge has higher total unit costs and a slow transfer of cargo
" The GBS system provides the best scalability
" The FSRU system the easiest to construct
" The GBS system uses concrete for LNG storage and hence, has the best
cryogenic storage properties
When determining the offshore receiving terminal option, one has to consider the
latter conclusions.
The CGI system is currently undergoing performance tests to
92
objectively determining the feasibility of the system. The CGI system could easily become
a common receiving terminal option in the future once the system has become more
established. The Energy Bridge system is more suited toward the Atlantic Basin or smaller
energy markets where the higher unit costs can be covered.
Furthermore, the Energy
Bridge is not as capital intensive as the other receiving terminal systems.
The GBS system has competitive unit costs with great scalability. This is a very
appealing receiving terminal option if the capital costs to implement the system can be
provided.
Since LNG projects are large capital intensive projects, this makes it more
difficult to realize.
option.
The FSRU system seems to provide the most "middle-of-the-road"
The unit costs are competitive and the knowledge of the technology is vast.
However, the FSRU option does not provide the best scalability. Furthermore, the LNG
storage properties of steel tanks are not as optimal when compared to the concrete GBS
system. Despite this, steel tanks are still the most commonly used method of LNG storage.
By subjectively and quantitatively evaluating the offshore LNG receiving terminal
options with the information and tools provided in the paper and the computer model, one
can determine which receiving terminal options are the best suited for specific locations
and sendout demands. In addition, by understanding the limitations of the computer model
as well as the power of the model, one can make appropriate decisions based on given
assumptions and inputs.
As shown in Figures 39-42, additional costs that have been excluded from the
model can have a considerable impact on the different unit cost outputs that the model
provides. With this in mind, one cannot take the unit cost results alone and justify one
93
receiving terminal option to be more optimal than another without considering possible
unanticipated costs that can greatly influence the unit cost outputs. Additional operating
costs, siting/pipeline costs, and shipping costs, for example, can completely change cost
estimates for an LNG project. Therefore, it is noted that when deciding on an offshore
receiving terminal option, one should consider the intangible factors such as: difficultly in
obtaining a permit,
ease of reducing
NIMBY concerns,
and general
location
considerations, of equal or greater importance than the quantitative unit and capital cost
outputs.
Offshore LNG receiving terminals will undoubtedly become a very real solution to
the lack of supply capacity for LNG here in the U.S.
By reducing NIMBY concerns,
regulatory obstacles, political apprehension, and security concerns, offshore LNG
terminals appear to be the answer to alleviatir ig LNG importing issue in the near future.
As transfer and handling technologies increas e, unit costs will only improve and make
various terminal options more attractive.
RECOMMENDATIONS FOR FUTURE WORK
To further improve the LNG computer-based simulation model, additional research
into the remaining facets of the LNG value chain should be examined.
accomplished to determine how the other facets affect one another.
This should be
Furthermore,
examination upon where the largest cost savings in the value chain occur is very
significant.
The expansion of the LNG computer-based simulation model should be
conducted to further detail other associated terminal costs and to allow for unforeseen
94
costs.
With a greater understanding of the LNG value chain in its entirety, one can
understand how each link in the chain affects one another and therefore, a better capability
of how to eliminate supply and cost bottlenecks in the system can be exercised.
95
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102
APPENDICES
103
Gravity Based Structure (GBS) - Base Case
Natural Gas Sendout (Bcf/day)
0.9
Assumptions
Estimated Regasification Costs ($ billions)
Discount Rate
Storage
15%
$0.36
Years
20
Vaporization
.... ninei~n&Others
$0.18
$0.15
Sendout (MMcf/day)
Annual Sendout (MMcf/year)
900
328500
Capital Regasification Cost Total
$0.69
Unit Capital Cost ($/Mcf)
$0.29
Estimated Shipping Costs ($ billions)
Cost per Ship
Distance* (nm)
$95,643,056
$688,460,830
Unit Capital Cost ($/Mcf)
$0.291
$0.165
12,000
Trip Time (days)
Average Turnaround Time (hrs)
Overhaul Time per Year (days)
30
22
30
LNG Tanker Capacity m3
LNG Boil Off per Day
LNG Regasification Loss
135,000
0.2%
2.5%
Days Lost to Bad Weather per Trip
Adjusted Natural Gas Offload per Trip (Bcf)
Trips per Year per Ship
Ships Required
Y4...........
.
Capital Shipping Cost Total
Annual Cash Flow Payment
Present Value
7
2.85
8.84
13
..................................
Assumptions
Discount Rate
Years
Sendout (MMcf/day)
15%
20
900
115.44
Annual Sendout (MMcf/year)
328500
$2.16
Annual Cash Flow Payment
Present Value
Unit Capital Shipping Cost ($/Mcf)
$300,092,745
$2,160,136,957
$0.914
Unit Shipping Cost ($/Mcf)
$0.91
TOTAL REGAS. & SHIPPING UNIT COST ($/Mcf)
$1.20
West Africa to Gulf Coast round trip
All variables in blue are directly adjustable
*** All variables in red are base case assumptions but can be changed
Appendix A - GBS Base Case
104
Floating Storage Regasification Unit (FSRU) - Base Case
Natural Gas Sendout (Bcf/day)
0.6
Assumptions
Estimated Regasification Costs ($ billions)
Storage
Vaporization
ineering &Others
....
$0.13
$0.12
$.0.15
Capital Regasification Cost Total
$0.40
Unit Capital Cost ($/Mcf)
$0.25
Estimated Shipping Costs ($ billions)
Cost per Ship
Distance* (nm)
Discount Rate
Years
Sendout (MMcf/day)
Annual Sendout (MMcf/year)
15%
20
600
219000
Annual Cash Flow Payment
Present Value
Unit Capital Cost ($/Mcf)
$54,899,860
$395,181,886
$0.251
$0.165
12,000
Trip Time (days)
30
Average Turnaround Time (hrs)
22
Overhaul Time per Year (days)
LNG Tanker Capacity mr
30
135,000
LNG Boil Off per Day
0.2%
LNG Regasification Loss
Days Lost to Bad Weather per Trip
Adjusted Natural Gas Off load per Trip (Bcf)
Trips per Year per Ship
2.5%
10
2.85
8.19
Discount Rate
Years
15%
20
Ships Required
perYear
9
7tal.Trips
76.96
Sendout (MMcf/day)
Annual Sendout (MMcf/year)
600
219000
Capital Shipping Cost Total
$1.55
$215,890,908
$1,554,032,665
Unit Shipping Cost ($/Mcf)
$0.99
Annual Cash Flow Payment
Present Value
Unit Capital Shipping Cost ($/Mcf)
TOTAL REGAS. & SHIPPING UNIT COST ($/Mcf)
$1.24
Assumptions
West Africa to Gulf Coast round trip
All variables in blue are directly adjustable
- All variables in red are base case assumptions but can be changed
Appendix B - FSRU Base Case
105
$0.986
El Paso Energy Bridge - Base Case
Natural Gas Sendout (Bcf/day)
0.5
Assumptions
Estimated Regasification Costs ($ billions)
Storage
Vaporization
Othe.rs
... .ineering
Capital Regasification Cost Total
Discount Rate
$0.00
Years
$0.00
Sendout (MMcf/day)
Annual Sendout (MMcf/year)
$0.3................$..32..
$0.32
Annual Cash Flow Payment
Unit Capital Cost ($/Mcf)
$0.24
15%
20
500
182500
$43,884,677
Present Value
Unit Capital Cost ($/Mcf)
$315,892,048
$0.240
Estimated Shipping Costs ($ billions)
Cost per Ship
$0.182
Distance* (nm)
12,000
Trip Time (days)
Average Turnaround Time (hrs)
Overhaul Time per Year (days)
30
192
30
LNG Tanker Capacity m3
LNG Boil Off per Day
LNG Regasitication Loss
135,000
0.2%
2.5%
Days Lost to Bad Weather per Trip
Adjusted Natural Gas Offload per Trip (Bcf)
Trips per Year per Ship
1
2.85
8.59
Ships Required
Tot
..
T psperYear.
7
Assumptions
Discount Rate
Years
15%
20
Sendout (MMcf/day)
500
Annual Sendout (MMcf/year)
6.............4..............
64.13
.
Capital Shipping Cost Total
182500
$1.36
Annual Cash Flow Payment
$188,629,728
Unit Shipping Cost ($/Mcf)
$1.03
Present Value
Unit Capital Shipping Cost ($/Mcf)
$1,357,800,395
$1.034
TOTAL REGAS. & SHIPPING UNIT COST ($/Mcf)
$1.27
*West Africa to Gulf Coast round trip
All variables in blue are directly adjustable
*** All variables in red are base case assumptions but can be changed
Appendix C - El Paso Energy Bridge Base Case
106
Conversion Gas Imports Bishop Process and Salt Cavern Storage - Base Case
1.7
Natural Gas Sendout (Bcf/day)
Assumptions
Estimated Regasification Costs ($ billions)
Storage
Vaporization
.
Ene!eri~ng .O~thes..... .
Capital Regasification Cost Total
.
Unit Capital Cost ($/Mcf)
$0.05
$0.32
$0.15
$0.52
Discount Rate
Years
Sendout (MMcf/day)
Annual Sendout (MMcf/year)
Annual Cash Flow Payment
15%
20
1700
620500
$71,942,759
$0.12
Present Value
Unit Capital Cost ($/Mcf)
$517,860,611
$0.116
Estimated Shipping Costs ($ billions)
Cost per Ship
$0.165
Distance* (nm)
12,000
Trip Time (days)
Average Turnaround Time (hrs)
Overhaul Time per Year (days)
LNG Tanker Capacity mJ
30
24
30
135,000
0.2%
LNG Boil Off per Day
2.5%
LNG Regasification Loss
Days Lost to Bad Weather per Trip
12
Adjusted Natural Gas Offload per Trip (Bcf)
2.85
Trips per Year per Ship
7.79
Ships Required
28
... lTip.jp t .......... ......................... _.......... 218.06 Annual Sendout (MMcf/year) 620500
Assumptions
Discount Rate
Years
Sendout (MMcf/day)
15%
20
1700
$4.63
Annual Cash Flow Payment
$642,836,083
Unit Shipping Cost ($/Mcf)
$1.04
Present Value
Unit Capital Shipping Cost ($/Mcf)
$4,627,282,746
$1.036
TOTAL REGAS. & SHIPPING UNIT COST ($/Mcf)
$1.15
Capital Shipping Cost Total
West Africa to Gulf Coast round trip
All variables in blue are directly adjustable
*** All variables in red are base case assumptions but can be changed
Appendix D - CGI System Base Case
107
LNG
kem
metric tomne LNG
I Metric Tonne
1
00712
Kwirrl LNG
013373,7
00238 000379
LNG
000696
Ino
c k matr iNG
U fC
0 - LNC
I cubic meter- GI cubic foot - Gas
I Mcf- Gas
I MMBtu - Gas
I Gallon
589.67
I Barrel
14.04
I Cubic Meter I Cubic Foot
78.827
2232
42
0,159
5.615
I Pound
2,204.6
15.
O
0448
0.0127
6.290
0.178
264.172
7.482
1
0.283
35315
1
988.0
0 000734
0,00002
0.0208
0.0193
0,0103
0 0003
0.292
0.272
0,433
0.00164
0,012
12.266
11.402
0.00005
0.0464
0.432
0.0579
0.0016
16
0.046
46.0
42.7
Appendix E - LNG Conversion Chart [Houston, 2003]
108
1640
1.524
28.0