Monetizing Offshore Gas Reserves - LNG...
Transcript of Monetizing Offshore Gas Reserves - LNG...
HONFLEUR LLC March 2016 www.honfleurllc.com
Monetizing Offshore Gas Reserves
HONFLEUR LLC March 2016 www.honfleurllc.com
The known offshore hydrocarbon
basins, where the USGS has
estimated a mean reserve potential
of 3,190 Tcf (trillion cubic feet), or
57% of the world’s undiscovered
conventional non-associated gas
resources, requires Floating Liquefied Natural Gas (FLNG or
Floating LNG) to commercialize these yet to be discovered
and developed resources. FLNG technologies will allow
producers to monetize those basins where offshore to
shore pipelines are uneconomic, or scenarios where there
is a lack of nearby natural gas markets accessible through
current and future regasification hubs (see resource map
below).
In this paper, Honfleur LLC Managing Partners Clay Jones
and Terrel LaRoche assess the reasons which provide the
commercial justification that FLNG is a viable combination
of proven technologies to safely and reliably exploit
previously inaccessible offshore wet gas resources
worldwide. Additionally, FLNG is commercially sound and
competitve with onshore LNG developments, thereby
expecting commisurate rates of return. As with land-based
LNG facilities, National Oil Companies, International Oil
Companies, Joint Venture Partners, and Lenders to these
projects must entertain a long-term, strategic view around
FLNG projects in order to maximize the exploitatioin of the
targeted hydrocarbon resource, amortize the FLNG project
Capex, and satisfy the long-term commercial obligations of
the offtake LNG purchaser in order to maximize the overall
project returns.
A Brief History of LNG
Historically, the increasing global demand for hydrocarbons
has underpinned the energy industry’s investment in new
technologies, and the re-application of existing
technologies to new technological challenges and
environments. The ability to create, adapt and reapply
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technologies has allowed the energy industry to “go
further, reach deeper and change the view” of the world’s
known recoverable resources. Continued technological
growth has created the viability of FLNG, and will allow it to
safely produce high-quality, commercially competitive, and
economically extractable natural gas on demand from new
offshore basins.
In terms of new technology application, Floating LNG today
contrasts to where land based Liquefied Natural Gas plant
applications were roughly 50 years ago. By the mid-1960’s,
a few LNG liquefaction plants were in operation along with
LNG regasification terminal facilities to receive the LNG
product. This was the fledgling Algeria to Canvey Island in
the U.K. and other Western European LNG trade points
that changed in two primary ways. First, the development
of the North Sea in the late 1960’s and early 1970’s (a
technology advancement gleaned from the period of 1948
through the 1960’s U.S. Gulf of Mexico offshore
developments) and second, the decision by utility buyers
world-wide to diversify their fossil fuels from coal and oil to
natural gas due to the Arab Oil Embargo of 1972. Economic
drivers provided the genesis for the LNG business to
prosper from these early applications, thereby allowing
imported LNG to become a viable solution to the problem
of fuel diversification for utility buyers, and for LNG
liquefaction plants to monetize gas reserves that had no
other available market.
FLNG is a combination of known technologies that are used
in new applications and environments to extract
unreachable hydrocarbons. The recent analogy is the use of
highly evolved fracing technologies and human ingenuity
within the large U.S. shale plays beginning in 2005. These
technological successes would not have been possible
without the use and evolution of fracing technologies
originally developed in the 1970’s and applied to straight-
hole wellbores within tight gas formations, combined with
the development of accurate offshore directional drilling
techniques. While the combination of FLNG technologies
require operational experience to set the standard for
operations and maintenance, the basic underlying
technology risks (e.g. “will it work?”) have been
successfully proven.
The application of FLNG is driven by three factors related to
the resource. First, most petroleum geologists acknowledge
that approximately 95% of onshore gas resources are
known. Second, large gas resources tend to be in older
geological provinces where time and pressure at depth
“cook” the hydrocarbons into a gas and gas-condensate
form. Third, these older and deeper formations are found
not onshore, but in offshore deep marine environments.
The largest basins remaining to be developed include those
in the Arctic, East and West Africa offshore, the Antarctic
(including the Southern Bite of Australia and offshore New
Zealand), the Greater Northwest Shelf offshore Australia
and Southeast Asia. FLNG applications will allow these
basins to be safely, competitively and economically
developed.
FLNG Project Sponsors and Partners Various stakeholders will be involved in FLNG led
developments. The leaseholders for offshore exploration
and development licenses reside in two major categories.
The first are national oil companies – NOC’s - that promote
hydrocarbon developments. Some examples include
Petronas, ENH (Mozambique), TPDC (Tanzania) but also
include entities like Gazprom. Second are the international
oil companies – IOC’s - such as ExxonMobil, BP, Shell,
Indian Oil, Sinopec and Statoil.
While the NOC and IOC leaseholders drive the exploration
and development efforts, careful strategic and economic
consideration will be given to the involvement of potential
FLNG joint venture partners, which include shipbuilders
such as Hyundai, Daewoo, MODEC, Moss Maritime,
Samsung, and SBM offshore, topside design and
construction companies such as Keppel Offshore & Marine,
JCG Corporation and KBR, technology suppliers such as
Technip, Air Products and Chemicals, General Electric, and
Black & Veatch, and pure equity investors such as
Infrastructure Funds and Sovereign Funds.
Status of Current FLNG Projects Currently, there are three (3) FLNG projects in various
stages of design, construction, installation and
commissioning. The first is Shell’s Prelude FLNG project,
whose stakeholders include Shell (67.5%), INPEX (17.5%),
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KOGAS (10%) and CPC (5%). The project is a 3.6 mtpa
(million tonnes per annum) liquefaction facility to produce
the Prelude and Concerto Fields in the Browse Basin
located 300 miles offshore northeast of Broome, Western
Australia. The total reserves to be produced are reported to
be 3 Tcf (trillion cubic feet) of wet natural gas. The FLNG
ship is 488 meters by 74 meters. Key contractors include a
consortium of Technip and Samsung. Estimated initial LNG
production is expected to be 1st
Qtr. of 2017.
Source: Internet, Shell Prelude FLNG
The second FLNG project is Petronas PFLNG SATU, which is
owned 100% by Petronas. The project is a 1.2 mtpa FLNG
liquefaction facility that will produce the Kanowit Field, 112
miles offshore Bintulu, Malaysia. The total reserves to be
produced are estimated to be 1 Tcf of wet gas reserves.
The FLNG ship is 365 meters by 60 meters. Construction is
ongoing at the Daewoo shipyards in South Korea. The initial
LNG production is scheduled no later than 1st
Qtr. 2017.
The third project is Petronas FLNG 2 which is owned by
stakeholders Murphy Oil (80%) and Petronas (20%). The
project is a 1.5 mtpa liquefaction facility, which will
produce the Rotan Field in Block H with estimated wet gas
reserves of 0.95 Tcf. Engineering and procurement is
managed by JGC, and the construction is by SHI (Samsung
Heavy Industries). The keel for this project was laid in late
2015, with anticipated deployment scheduled for 2018.
There are other FLNG projects under consideration which
have not proceeded beyond pre-FEED (Front End
Engineering and Design). Woodside Petroleum is
considering Browse Floating LNG at 3.6 mtpa as an option
to a land based liquefaction facility, to develop the 13.3 Tcf
of dry natural gas and 360 million barrels of condensate
from the Torosa, Brecknock and Calliance Fields in the
Browse Basin, offshore Western Australia. Woodside is
expected to take a full FEED decision by mid-2016.
ExxonMobil and BHP
have been studying
Scarborough Floating
LNG, a 3.6 mtpa facility
which would develop the
10 Tcf Scarborough Field
offshore Western
Australia.
Inpex and Shell proposed
Abadi FLNG to SKK Migas
(the Indonesian Special
Task Force) to develop
the Abadi field located
offshore in the Arafura Sea, 106 miles southwest of
Saumiaki. Ownership includes Inpex (60%), Shell (30%) and
PT EMP Energi Indonesia (10%). Reported development
drilling has estimated the reserves to be greater than 10
Tcf. The project is large scale at 7.5 mtpa, increasing from
its original design of 2.5 mtpa FLNG design. Final
Investment Decision (FID) had not as yet been taken.
Most recently, ENI has announced the first planned
development of its Block 4 offshore Mozambique East
Africa. The Coral Floating LNG project is a 3.4 mtpa
liquefaction facility that would produce wet gas from the
Coral Field, which holds an estimated 5 Tcf of reserves. The
government of Mozambique has approved the
development as of late February 2016.
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LNG Markets The current 2016 worldwide liquefaction capacity is
267 mtpa, and is divided geographically as shown in the pie
chart, below.
Total global capacity is expected to grow over the next
several years with the addition of U.S. onshore shale gas
sourced liquefaction facilities such as Sabine Pass, Cameron
LNG and Freeport LNG, and Western Australia’s offshore
projects such as Gorgon LNG and Ichthys LNG.
There remains plenty of regasification capacity (“regas”)
with the global total estimated at 681.5 mtpa, or more
than double current liquefaction capacity as shown in the
next pie chart, below.
The Asian segment for regas capacity is dominated by
Japan and Korea which utilize their regas facilities at high
rates in the 70%-75% range for baseload utility service. In
contrast, European regas facilities have utilization rates
averaging in the 20%-25% range. On a global basis, there
exists ample regas capacity to absorb the liquefaction
facilities currently under construction, as well as future
FLNG projects.
FLNG Combines Successful Technologies Onshore liquefaction facilities, offshore oil & gas FPSO’s
(Floating Production Storage and Offloading), and subsea
completion technologies have been successfully proven in
operation, all of which will be utilized by FLNG
developments.
Source: Internet, digital subsea completion layout
Prior to taking FID on an offshore FLNG development,
careful consideration is given to many critical technical
project elements. Some of these include the field
development plan which contemplates well locations
(subsea bed and bottom-hole), subsea production,
flowlines and pipelines. A key element for FLNG topsides
design is the expected gas quality and co-products
(condensate, propane, butane) in the production stream
and the expected quality requirements for the LNG and co-
products. Finally, field specific issues such as inerts in the
gas stream and FLNG re-deployment flexibility are also
considered.
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Hg MercuryRemoval
FLNG Process Flow
CondensateStabilization
CondensateStorage
CO2 Acid GasRemoval
NGLExtraction
H2ODehydration
Fractionation
RefrigerantStorage
End Flash
LNG Storage&
LNG Loading
Liquefaction
LPG Storage&
LPG Loading
Condensate
LNG
C4Butane
C3Propane
ReservoirFeed Gas
FuelGas
In addition to the subsea development plan, considerable
thought is given to the FLNG design, construction and
deployment of the vessel fabrication, or “bare boat” which
will be undertaken by builders with large scale shipyards
capable of handling up to 20,000 personnel working round
the clock shifts.
Builders include Hyundai Heavy Industries (HHI), Daewoo
Shipbuilding and Marine Engineering (DSME) and Samsung
Heavy Industries (SHI).
The topsides design will include mooring, gas compression,
gas treatment, impurity removal, fractionation,
sequestration, liquefaction, refrigeration, utilities, storage
and offloading, accommodations and mooring.
The key technology suppliers for the topsides include, but
are not limited to companies such as Shell, Chart, Air
Products, Linde, and Black & Veatch for the cryogenic heat
exchangers and cold boxes. Refrigeration and compression
is typically provided by General Electric, Dresser, Siemens
and Rolls-Royce. LNG Storage technology is provided by
Tractebel, Samsung, Techint, Bechtel, CB&I and Moss
Marine.
FLNG Process Flow A key design challenge for FLNG projects is that the total
topside equipment, vessels, towers, mooring systems and
other structure must fit onto a 5 - 8 acre foot print on a
ship. This is in contrast to an onshore liquefaction facility
that may have a 40 -60 acre footprint.
Included in the smaller footprint, FLNG facilities are
designed for gas conditioning and fractionation, elements
that are not typically included in onshore liquefaction
facilities as the inlet gas to be liquefied is already dry gas
absent of condensates and natural gas liquids (NGL’s).
These areas are reflected as highlighted ellipses shown in
the FLNG Process Flow diagram, below.
The amount of gas conditioning and the capacity of the
cryogenic refrigeration for fractionation of NGL’s are
dependent on the expected gas quality (Btu content and
gallons per thousand cubic feet of NGL’s). These
considerations are taken in relationship to the gas
specifications required by the offtake or final customer.
EPC and Contract Forms Contractors that can provide the overall planning,
supervision and implementation of a Floating LNG project
include KBR, Technip, Samsung, JGC, Chiyoda, Daewoo and
Hyundai, plus other contractors with expertise in this
space.
There are several contracting forms for FLNG projects that
have been repurposed from offshore platform
construction, FPSO and shipbuilding contracts. The most
common is the EPCIC contract which includes engineering,
procurement, construction, installation and commissioning.
Other forms include LSTK with a firm completion date
(lump sum turnkey) and EPCPM (engineering,
procurement, construction, project management).
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Source: Internet, Petronas’ FLNG Facility at DSME shipyard
LNG Capex Costs As liquefaction facilities were developed, the unit costs per
tonne of LNG produced in a year (US$ per tonne per
annum, or “tpa”) have improved due to evolving
technology and larger project scale. The Liquefaction Plant
Cost, below is referenced from Oxford Institute for Energy
Studies, LNG Plant Escalation, February 2014, B. Songhurst.
All projects reflected in the chart
with a few noted FLNG exceptions
are onshore LNG plant costs.
Additionally, transposed on the
chart is Honfleur LLC’s Strawman
FLNG at US$ 1,500 tpa. This is for
a 1.5 mtpa project which is
outlined later in the economic
section of this white paper. An
interesting note from the
information presented is the
improving tpa cost trend, (using
2008 US$) from the early 1970’s
through 2010. The overall capital
costs would vary depending on
location and the overall LNG
project scope, including storage
and export terminal
infrastructure. However, this tpa trend changed after 2010,
with unit costs rising above US$ 1,000 tpa. Reasons for this
tpa cost increase can be explained with increasing labor
costs, local exchange rate costs, greater infrastructure
requirements due to location, rising material costs, and
inefficient project/construction management processes. Of
note is Snohvit LNG having scope for piping, site work,
carbon sequestration and barge mounted facilities. Gorgon
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LNG on Barrow Island offshore Western Australia has a long
development timeline, carbon sequestration, and high
requirements for overall environmental compliance.
Finally, Shell’s Prelude, a Floating LNG project, is shown as
an estimate based on reported capital costs, is using its
own proprietary technologies, is designed to operate in
Hurricane Class 5 conditions, and has design flexibility for
its topsides to process a wide range of gas quality
specifications.
Commercial Structures There are two (2) basic commercial structures (Integrated
or Segregated) that an NOC or IOC producer will use for
FLNG developments.
The Integrated Commercial Structure combines the
upstream resource development and midstream FLNG
ownership into one common unit, as shown below.
From a producer’s point of view, the integrated approach is
an efficient structure whereby gas production, treating,
liquefaction and monetization align the commercial risks
and the benefits between all the owners.
Some challenges to the integrated structure include a
blended return on capital employed, which might
otherwise enhance upstream returns if FLNG is separated.
Multiple field developments timelines may require re-
deployment but change the overall ownership
participation. Involving joint venture partners in this
structure will expose them to the complete upstream and
midstream project benefits and risks alike. Financing under
this structure will require a combined reserve based
lending (RBL) and midstream FLNG financing elements.
The Shell Prelude FLNG and Petronas PFLNG SATU are likely
using some form of the integrated structure.
The Segregated Commercial Structure includes two
variations - a profit center approach or a tolling approach.
The first structure, the Profit Center Approach, below,
segregates the upstream resource development with its gas
sales agreement counterparty (GSA) from the midstream
FLNG project with it sales purchase agreement
counterparty (SPA).
Benefit of the profit center approach is the counterparty
risk in GSA’s and LNG SPA’s is familiar to project lenders.
Potential joint venture partner participations are “ring-
fenced” in the specific area of involvement, either
upstream, midstream FLNG, or both. Finally, upstream and
midstream parties can have different commercial and
financing arrangements using this basic structure.
From a producer’s perspective, a challenge to the profit
center approach is the midstream FLNG entity has total
control over the monetization of the producer’s
production. Additionally, there may be a third party
marketing company involved through both the GSA and the
LNG SPA, which can further complicate the overall
commercial structure. Finally, separate financings will raise
multiple inter-creditor issues. By example, the GSA could
be indexed to Henry Hub and the LNG SPA could be
indexed to JCC (Japanese Customs Cleared Crude). Project
lenders will likely not desire the potential mismatch
between the contracts, and would prefer a consistent index
for both upstream resource development and the
midstream FLNG. Onshore liquefaction projects have used
a form of this structure.
The second Segregated Commercial Structure is a
Tolling Approach as shown below, whereby the key
contract is the tolling agreement (TA) or terminal use
agreement (TUA).
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This is the basic structure used by onshore U.S. liquefaction
projects where the reservoir in the tolling approach
structure is replaced by U.S. shale gas and a GSA contract.
The benefits to this structure allow the producer to retain
title to the raw gas and LNG produced in the liquefaction
process, while segregating returns on capital employed by
the upstream and by the midstream FLNG project. The
processing fees can act as a “capacity payment” on the
FLNG project depending on the volume requirements
negotiated in the TA on a ship and pay basis (midstream
FLNG takes some or all volume and reserve risk), or a ship
or pay basis (producer takes all reserve related risks).
Challenges to the tolling structure depend on the basis of
payment in the TA. On a ship or pay basis, the producer
takes all the reserve risks. A key feature of FLNG is it likely
has useful life after depleting the resource. The producer
may not have rights associated with re-deployment of the
FLNG facility after reservoir depletion. Lastly, this structure
may complicate any profit sharing or contracted for
production arrangements the producer has with the
governmental body regarding the TA payments.
Third party provided FPSO’s in the past have had issues
with lease payment treatment (essentially a TA or TUA) by
governmental bodies, both in qualifying the payments
under the TA and the discussion of ownership of the
FPSO if capital recovery is granted.
Honfleur’s Strawman FLNG Economics Honfleur has developed a detailed economic model by
which to measure the commercial viability of FLNG
projects. The Honfleur model begins with the resource
to model existing wet gas flows; additional drilling
activity to exploit the resource and provide full field life
with long-term flow from the reservoir to the FLNG;
gas analysis and processing recoveries for condensate,
LPG (propane/butane), and LNG at a market Btu value
to access all international offtake markets; revenue
underpinned by market strips commiserate with the
offtake commodities produced; Capex for both
reservoir development and volume maintenance; Capex for
a “full kit” FLNG vessel segregated in major equipment
costs; Opex consistent with operations of FLNG; and
earnings which are summarized in the model tables
presented herein.
Honfleur’s Strawman FLNG model inputs are summarized
below:
Reserves 1.5 Tcf
Flow Rate 250 MMcfd (million cubic feet per day)
Strips As of 3/1/2016
LNG Henry Hub + $3.50/MMBtu
LPG (NGL) Koch Trading (Mt. Belvieu)
Condensate WTI x 70% (discount to crude)
Processing Inlet Gas – 1393.5 Btu/cf
Fuel/Loss 10% of Inlet
Recoveries Ethane rejection (30% recovery of NGL’s)
Outlet LNG 1087 Btu/cf
Capex Upstream US$ 1.04 billion
Capex FLNG US$ 2.25 billion
Opex US$ 1.00/Mcf inlet
Other key assumptions in the economics:
All cashflow is pretax without burdens (no PRRT); delays
due to weather, or extended completion tests were not
included; no additional pipes beyond subsea tie-backs to
FLNG were assumed.
The forecasted cashflow is shown below.
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Upstream development is initially US$ 800 million for up to
20 wells producing 12.5 MMcfd per well. This capital is
shown brought forward to 2016. The US$ 2.25 billion in
Capex for the FLNG project spans three (3) years before
installation and commissioning begins first production in
2019.
The resultant revenue stream is made up from LNG (60%),
LPG (32%), and condensate (8%). This shows the
importance of co-products – LPG (propane/butane) and
condensate - expected from a rich gas-condensate
resource.
The Field Life vs Unit Cost table below emphasizes the
importance of field life (overall reserves recovered) vs. unit
capex costs.
The long term commodity prices used from the forward
strips in US$ are as of 1/1/2019:
Henry Hub $2.914/MMBtu
+ $3.50/MMBtu
= $6.414/MMBtu
Ethane $0.20/gallon
Propane $0.461/gallon
I-Butane $0.568/gallon
N-Butane $0.571/gallon
C5+ $0.813/gallon
Condensate $45.97/Bbl x 70% = $32.179/Bbl
The total for each field life shown is US$ 7.48/MMBtu,
which is the total revenue received for all three (3) co-
products sold at the strip prices assumed (projected as flat
for all years forecasted after 5 years in this analysis).
At full field recovery of 1.5 Tcf in year 16, unit cost is
US$ 0.68/Mcf for the full upstream Capex, and
US$ 1.47/Mcf for the FLNG Capex for a total of $2.16/Mcf.
These compare to an all in unit Capex cost of $5.79/Mcf for
a field life of only six (6) years and recovered reserves of
0.57 Tcf.
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The Field Life vs IRR/Reserves table below reflects a pretax
rate of return (IRR) over the same field life time period. The
table emphasizes two points: the importance of capital
costs for the FLNG versus rate of return, and the impact of
the LNG SPA fee.
The Base Case at US$ 1,500 tpa for the FLNG
(US$2.25 billion) is shown as the second curve starting at
less than 5% IRR in a six (6) year deployment and peaking at
a 15% IRR in year 16. The topmost curve reflects a capex
for the Strawman FLNG that is at US$ 1,052 tpa (a 42.5%
savings over our base case), which improves the overall
rate of return (the top curve) to near 20% at year 16. The
two bottom-most curves assume the LNG SPA at the base
capex of US$ 1,500 tpa but lowers the fee added to Henry
Hub to $3.00/MMBtu and $2.50/MMBtu respectively from
the assumed base case of $3.50/MMBtu for the LNG sold.
While the lower fees impact the overall capital returns,
they do not have as large an impact because of the
contribution of 40% of the revenue from NGL’s sold as LPG
and condensate sales.
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Conclusions There are many factors that control deployment of FLNG as
a competitive economic solution for offshore non-
associated gas fields. The key factors include:
Competition – FLNG is competitive with greenfield land-
based liquefaction facilities. Co-products enhance revenue
(Condensates; NGLs sold as LPG). Terminals are not
required, only offloading capability ship to ship. Re-
deployment from depleted reserves to a new resource
provides commercial optionality.
Markets – LNG markets continue to grow as liquefaction
facilities are added into the global supply base. FLNG will
be a part of the continued expansion of LNG supplies.
Regas facilities have spare capacity to meet LNG demand.
Retiring coal and nuclear power generation will support
LNG growth. Global / regional GDP growth will demand
new LNG supplies.
Capital Sourcing - The blending of proven technologies with
multiple FLNG stakeholders will attract the use of
structured project finance debt to enhance equity returns.
FLNG counterparties provide creditworthy financing
platforms. Contracts between stakeholders are understood
and accepted by the energy financing community.
Deployment of Petronas PFLNG SATU and Shell Prelude in
the next 12 months provides surety of the technologies
used in FLNG.
Resource - The underlying resource preferably should fully
amortize the capital costs for upstream development and
FLNG for an extended period (10-15 years) at current prices
assuming a “reasonable range” US$ per tonne per annum
capex for the FLNG. Deployments for less than six (6) years
will likely require re-deployment to capture all capital costs
for development.
Capital costs – FLNG capital costs are the key driver due to
the extended period of production required to recover the
capital employed. Equity sponsors that fully involve
themselves in the FLNG project and drive results, rigorous
project design and scoping, and the development of
realistic corresponding budgets, schedules, and execution
metrics will realize successful FLNG ventures.
Re-deployment Options - Shorter term developments at
five (5) years or less can effectively use FLNG by ensuring
that the “kit” of the topsides is originally designed to
handle a broad spectrum of produced gas quality and
quantity, or can be modified with minimal capex to address
new reservoir gas compositions. Re-deployment will allow
for a lower unit cost of production for shorter term
developments by spreading the capital costs over a longer
time period.
Shorter term LNG SPA’s - LNG buyers will need to become
more willing to sign short term LNG SPA’s. Buyers can tie
their supplies to a “portfolio” of FLNG ships which have
varying terms of development. This ability to sign short
term contracts will also be further facilitated by developing
a spot LNG market that can fill gaps in LNG supply created
by the time required for re-deployment and development
of FLNG.
Insurance carriers – An established FLNG operating regime
that minimizes catastrophic risk exposure should provide
for “reasonable” insurance premiums that are affordable
for the producer and FLNG owner.
Authors Clay Jones is a Managing Partner at Honfleur LLC. Contact
him at [email protected] or (832) 282-1164.
Terrel LaRoche is a Managing Partner of Honfleur LLC.
Contact him at [email protected] or
(832) 527-9002.
About Honfleur Honfleur LLC is a provider of global Independent
Engineering Services to project owners and lenders on
major capital projects, acquisitions, divestitures and
privatizations. Visit Honfleur LLC at www.honfleurllc.com