Monetizing Offshore Gas Reserves - LNG...

12
HONFLEUR LLC March 2016 www.honfleurllc.com Monetizing Offshore Gas Reserves

Transcript of Monetizing Offshore Gas Reserves - LNG...

Page 1: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

Monetizing Offshore Gas Reserves

Page 2: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

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

Page 3: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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%),

Page 4: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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.

Page 5: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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.

Page 6: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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).

Page 7: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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

Page 8: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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).

Page 9: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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.

Page 10: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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.

Page 11: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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.

Page 12: Monetizing Offshore Gas Reserves - LNG Hublnghub.biz/wp-content/uploads/2016/06/Honfleur-Floating-LNG... · Monetizing Offshore Gas Reserves. ... competitve with onshore LNG developments,

HONFLEUR LLC March 2016 www.honfleurllc.com

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