IPA10-BC-135

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION Thirty-Fourth Annual Convention & Exhibition, May 2010

FLNG OR FGTL? INVESTMENT DECISION INPUT

W.D. Hartell*

J.R. Greenwald* ABSTRACT Large remote deepwater gas discoveries have unique challenges with regard to becoming commercial projects. Two options are floating Liquefied Natural Gas (FLNG) and floating "Gas to Liquids" (FGTL). These technologies include several subsets that have specific advantages and disadvantages depending on a range of investment decision inputs which will determine which option is appropriate for a particular development. Input to these decisions will include governmental or regulatory requirements, gas reservoir characteristics, facility issues, product pricing, location of market(s), and risk. Government or regulatory requirements include taxation, cost recovery, domestic market obligations, and procurement rules (including local content). Gas reservoir characteristics include reserves, production profiles, presence of oil/condensate, and gas composition (methane C1, ethane C2, propane C3, butane C4, C5

+, water, mercury, H2S, CO2, etc.). Facility issues range from technical to commercial/contractual. Technical facility issues include the number or size of floating facilities required for production, storage, offloading, and transport; processing risks (reliability or safety); metocean constraints; project schedules; constructability (including newbuild or conversion); and operability. Commercial/ contractual facility issues include capital requirements and timing; purchase or lease; depreciation; cost recovery. Product pricing issues include selecting the market(s); determining pricing mechanisms/formulas (floors, caps, ties to market prices of other products, ability and timing of repricing); market constraints (facilities for redelivery and storage, take or pay); market trends; and “carbon” view of selected product. Location of the market(s) affects both pricing (domestic markets versus international markets) and transport costs (capital and operating costs for some number of * Hess Indonesia

vessels to transport the product to market). Risks are wide ranging and can be underappreciated when making the investment decision. Technical risks could include intermittent variability or long term change of reservoir characteristics; ability to deliver the floating production facilities on schedule; variability in process performance (out of spec products); safety (process or marine operations); and maintainability (vessel or process equipment). Commercial/contractual risks include issues with product pricing variability; market economic fluctuations (including implementation of take or pay or cargo deferrals); and governmental or regulatory changes in laws, regulations (including Domestic Market Obligations), taxation; or cost recovery.

LNG utilizes technology with significant onshore facility experience and this experience has been used to develop compact technologies applicable to offshore applications. FLNG is being progressed for several offshore developments, but has not yet been operated offshore.

GTL has three processing options to produce “liquids”: gas to methanol, gas to dimethyl ether (DME), and gas to “synthetic crude” (syncrude). Methanol and DME facilities have been extensively operated onshore and this experience has helped develop compact technologies for offshore applications. Syncrude produced by the Fischer-Tropsch process has a few large onshore facilities. Reformer and reactor technologies have been advanced in pilot facilities to improve suitability for compact offshore applications. So far only one GTL pilot facility is being readied for offshore operations.

This paper will provide investment decision input for the monetization of large remote deepwater gas developments involving all these considerations. INTRODUCTION

Large remote deepwater gas discoveries have unique challenges with regard to becoming commercial projects. Two options are floating

© IPA, 2011 - 34th Annual Convention Proceedings, 2010

Liquefied Natural Gas (FLNG) and floating "Gas to Liquids" (FGTL). These technologies include several subsets that have specific advantages and disadvantages depending on a range of investment decision inputs which will determine which option is appropriate for a particular development. Input to these decisions will include governmental or regulatory requirements, gas reservoir characteristics, facility issues, product pricing, location of market(s), and risk. MONETIZATION OPTIONS Floating Liquefied Natural Gas (FLNG) FLNG is currently the most applicable monetization option for deepwater gas discoveries with large production rates/reserves, long distance to markets, and long term product pricing from international gas markets. Variations on these three basic assumptions would affect project economics and likely influence the required transfer and redelivery pricing contracts. A nominal onshore LNG train of 4 million tonnes per annum (MTA) could require a gas inlet rate of up to 650 MMCFD (requiring reserves of 4.4 TCF over 20 years). (Assumptions: Gas 1020 BTU/SCF, 10% fuel/losses, 340 days/yr production, LNG 53.35 MMBTU/tonne.). Offshore FLNG facilities (example in Figure 1) have been studied by multiple contractor consortiums with train sizes from 1 to 4.5 MTA, with a commonly assumed midsize range of about 1.5 to 1.7 MTA which would require gas inlet rates up to 256 to 290 MMSCFD (with corresponding required 20 year reserves of 1.7 to 2 TCF). Larger FLNG projects were announced by operators Shell, Inpex, and Petrobras/BG in 2009 (Shell 2009, Inpex 2009, and Petrobras 2009). FLNG production and storage facilities require large amounts of capital and long construction schedules for constructing cryogenic process facilities and storage tanks, contracting and building specialty transport vessels and, at the other end of the transport route, potentially permitting and constructing regasification facilities. FLNG technology has been significantly advanced in recent years by specialist technology companies partnering with marine engineering companies and shipping companies to target independent upstream E&P companies with so called “stranded” gas reserves (Wood 2008). The technology for FLNG is fairly complex and the engineering of process and cryogenic systems for offshore applications has

been actively progressed. Significant technical options now exist for FLNG (Kerbers 2009 and Perez 2009).

FlexLNG have placed four orders for 1.7 MTA capacity LNG FPSOs with main contractor Samsung (FlexLNG 2009) and engineering subcontractor Kanfa Aragon (Utkilen 2009). The topsides process system selected was a dual-train nitrogen expander cycle (Utkilen 2009) with turndown to less than 25%, which mitigates some of the process technical risks. SBM and Linde have proposed a single multistage mixed refrigerant system (LiMuM) for a 2.5 MTA (~365MMSCFD) capacity LNG FPSO (Harland 2008). Hoegh LNG has proposed CB&I technology for LNG (Lummus/Randall NicheLNG with dual independent refrigerant (methane and nitrogen) cycles) and Daewoo technology for the ship (Hasle 2009). Their proposed system is for a 1.6 MTA capacity FPSO with 3 x 75MMSCFD trains, with turndown to 70% (based on turbo–expander limitations), but only one train could be used which results in 25% of peak processing capacity, so there is a good range of process functionality. BW Offshore has proposed Mustang’s nitrogen expander cycle (NDX-1) with four-trains (0.5 MTA each) for a 2 MTA (~300MMSCFD) capacity FPSO (Unum 2009). The turndown of their proposed system is about 20-25% of peak processing capacity.

Simple, safe processes (like the nitrogen expander process) are attractive for offshore applications even if they have somewhat higher power consumption and lower thermal process efficiencies than more complex processes. Complex processes (like multiple refrigeration loop and multi-refrigerant processes) work well onshore where maintenance and reliability assurance is able to be delivered at lower cost. Offshore maintenance and reliability assurance costs can be high and work can be difficult to perform in a congested, marine environment. Initial energy efficiency savings from one type of process can be potentially offset by maintenance and reliability costs including reduced uptime from more complicated processes. It is also important to select process equipment that has been proved in marine environments (especially with FPSO vessel motions) like gas turbine drivers on the primary compressors, expander compressors with magnetic bearings and light rotors, and brazed aluminum heat exchangers and cold boxes (Walther 2008). FlexLNG has reported contract costs for their first FPSO vessel (hull+utilities) of ~US$460 million

(FlexLNG 2009) and topsides of ~US$200 million + integration costs (Utiliken 2009). Future similarly sized LNG FPSOs could cost ~US$1-1.3 billion (in line with FlexLNG’s guidance of US$ 550-700 CAPEX per tonne of LNG annual capacity) depending on specific reservoir fluids data and project specific commercial and contracting arrangements. BW Offshore has suggested a value of US$550-800 CAPEX per tonne of LNG annual capacity as an applicable budgetary number (Unum 2009). Several major oil and gas companies are pursuing FLNG technologies for large remote gas fields. Shell announced a contract award to Samsung for a 3.5 MTA FLNG FPSO offshore Australia (Shell 2009). Inpex announced a 4.5 MTA FLNG FPSO for the Masela (Abadi) Project offshore Indonesia (Inpex 2009) and received preliminary Indonesian Government approvals (Sasistiya 2009). Petronas and BG Group announced FEED contracts for a 3 MTA FLNG FPSO offshore Santos Basin, Brazil (Petronas 2009, SBM 2009, Technip 2009, and Saipem 2009). There may be economies of scale for large projects to have a single large FLNG production host vessel, but there is also the option to have multiple medium sized FPSOs in large fields. Medium sized FPSOs would be quicker to fabricate (using conventional shipyard infrastructure and “slots”) and commission; there could be a learning curve effect when designing and fabricating (i.e. assembly line with enough backlog); they would have a different production risk profile; and they could allow phased ramp-up and ramp-down of production capacity based on staged field developments (including time to drill deepwater production wells if required) or reservoir performance (and allow re-allocation of FPSOs to other developments if required). Multiple medium sized FPSOs could allow simultaneous offloadings of LNG to transport ships which might reduce production downtime or operability risks with a single large FLNG host production vessel. Individual FPSO vessels could come into shipyards for periodic classification surveys or equipment modifications as required whilst other FLNG vessels remained working in the field. Larger sized FLNG vessels (nominal 450 meters length by 70 meters beam) can have reduced pitch and yaw motions compared to medium sized FLNG vessels (nominal 336 meters length by 50 meters beam), but roll responses may not be significantly different (both beam dimensions are small compared to wave lengths of significant beam seas).

Roll resonance periods can be similar for both vessel sizes, so operability (process or offloading) can be similar in seastates where the heading of the vessels are towards wind-seas (i.e. weathervaning on turrets) but where beam swell components produce significant motions (after Ewans 2003). Offloading systems would be determined by the applicable operating location of the vessel – for moderate environments “side by side offloading” is likely and for more severe environments “tandem offloading” (with aerially supported hoses) is likely. Both technical options are available from multiple equipment suppliers to all FLNG consortiums. Medium sized LNG FPSOs are more attractive underwriting risks, so that “hull and machinery” insurance should be available as opposed to much larger special purpose vessels that might be difficult to insure without substantial self-insurance cover. Marine insurance markets (Marsh and Willis) have estimated underwriting limits of about US$2.5 billion for a single vessel and process equipment. Medium sized LNG FPSOs may be easier to lease since they could more easily be redeployed than a single large LNG FPSO which might not be a good technical or commercial fit on other field developments. For PSCs with cost recovery and integrated upstream/downstream facilities, a national regulator may be able to redeploy these medium sized LNG FPSOs into other field developments, including fields with reserve lives below the threshold for field specific facilities. So at this time, four (4) major contractor consortiums including FlexLNG/Samsung/Kanfa Aragon,SBM/Linde,Hoegh/CB&I(Lummus/Randall), and BW Offshore/Mustang are proposing medium sized LNG FPSOs for project developments. Typical commercial terms would result in a return on capital of about 11% in the case of lease options, but alternate commercial and contracting methods are available. Almost 360 of the world LNG transport fleet of 400 vessels (existing plus current order book) are vessels ranging from 125,000 m3 (~ 2.6 BCF) up to 260,000 m3 (~5.4 BCF). Delivery costs for a 157,000 m3 tanker were reported ~US$220-230 million (The Star Online 2008), but costs have softened with a number of newbuild orders postponed or cancelled in 2009. Typical vessel transit speeds are in the range of 18-20 knots. Charter costs nominally were in the region of US$80,000/day plus fuel costs, port fees, insurance, and overheads – so assumed total daily LNG transport costs can be approximately

US$100,000/day. Wood Mackenzie reported 2009 spot charter market rates were much lower due to the financial crisis – as low as US$25,000++/day then back up to US$50,000++/day (Palti 2009), but it is not recommended to use these lower rates for longer term financial investment decisions. Calculations on distance to market, production rates, storage requirements, and other parameters should be run to determine the number of transport vessels needed for a particular LNG project and from this number of ships, the effective cost per MMBTU should be calculated. This transport cost to various potential markets would affect the market price required by sellers or offered by buyers (depending on who ships the LNG). FOB (free-on-board) contracting versus DES (delivery ex-ship) terms have varied widely, but in the Pacific markets FOB has become more common, so the transport costs are considered by the buyers when they offer their pricing terms to the sellers.

Floating Gas to Liquids (FGTL)

“Gas to liquids” (GTL) has been a proven technology for a long time and there are at least three routes to “liquids” – gas to methanol, gas to DME, and gas to “synthetic crude”. FGTL is an option being considered over the past few years, but not yet monetized for actual major projects. a. Methanol A lower cost GTL option is to utilize gas to produce methanol. This product is easily transported as “liquid” in conventional chemical shuttle tankers to markets. The storage pressure for methanol is ambient. All gas components are utilized so there is nothing leftover to be flared or reinjected – usually only a water effluent stream. Associated CO2 in the production stream is actually beneficial to product production. A medium sized onshore methanol train of 1 million tonnes per annum-(MTA) could require a gas inlet rate of 105 MMCFD (requiring reserves of 710 BCF over 20 years) and would cost ~US$500 million. (Assumptions: Gas 1020 BTU/SCF, 10 % fuel/losses, 340 days/yr production, Methanol 32 MMBTU/tonne.) Floating Methanol facilities have been studied with train sizes from 0.4 to 4 MTA, corresponding to required gas inlet rates of 42 to 420 MMSCFD (or 20 year reserves of 290 BCF to 2.9 TCF). Coogee Chemicals / Mogal Marine-Mitsubishi (Coogee and Figure 2) and PetroWorld/ Foster Wheeler/ StarChem/ Waller Marine (Waller) have

been consortiums who have proposed and studied Methanol FPSOs. Coogee Chemicals has a compact onshore plant in Australia that has been producing methanol for almost 10 years. MEO Australia (2008) is working a 4 MTA offshore methanol development option (above a shallow water shoal far from land, but the concept of remote compact facilities is applicable).

For offshore production facilities, vessel motions can be critical to operability of GTL process equipment. Velocys (Tonkovich 2008) has developed compact multiple microchannel plant for the production of methanol onboard an FPSO. The microchannels reportedly increase process efficiency and speed of flow, so that vessel motions in marine conditions do not affect the contents of process equipment by influencing liquid levels and causing process upsets. In addition the process is claimed to minimize fresh water requirements by recycling and recovering water from the process stream. Other proposed offshore methanol process facility designs have been addressing the challenge of FPSO motions on the fluids contained in process vessels and columns.

Methanol is a marketable product sold as a feedstock for further petrochemical processes like the production of olefins. There is a more conventional market for methanol as a source of chemical derivatives like formaldehyde, acetic acid, methyl methacrylate (MMA), and Methy Tert-Butyl Ether (MTBE), but it is not a market sufficiently large to absorb significant additional supply without impacting the unit price. As the market evolves to utilize methanol as a fuel (Direct Methanol Fuel Cell (DMFC)) or petrochemical feedstock (Methanol to Olefins (MTO)) – replacing higher priced condensate – pricing should be more robust to the impact of greater volumes of methanol. The MTO process would involve an intermediate step where offshore methanol is converted onshore to DME and then to olefins. Recent pricing for methanol has been in the range of US$200/tonne which is about US$7/MMBTU. For many remote deepwater gas field applications, methanol could be an attractive development options with scalability (wide range of economic production rates and reserves) and commercial flexibility (ability to lease process facilities from third parties and deliver “high value BTU” product to relatively unconstrained “liquids markets” in conventional FOB chemical shuttle tankers). This development option might also be combined with other development options based on the needs of a particular field, country, or market (Figure 4).

b. Dimethyl Ether (DME)

A somewhat higher cost option (but also higher revenue) is to utilize gas to produce DME. The storage pressure for DME is 88.5 psig / 0.61 MPa (@25degC) which is lower than pressurized LPG (232 psig / 1.6 MPa). Cryogenic storage at -25degC and ambient pressure is also an option (similar to LPG). All gas components are utilized so there is nothing leftover to be flared or reinjected – usually only a water effluent stream. Associated CO2 in the production stream is actually beneficial to product production.

As with all complex process systems, vessel motions of the offshore production facilities can be critical to operability of GTL process equipment. Similar technical challenges and risks exist for either methanol or DME offshore process facilities. Methanol has been processed onshore (by dehydration using catalysts) to produce DME. Toyo Engineering (Mii 2005) has onshore plant technology for a Jumbo DME plant which could produce 3,500 TPD (1.2 MTA) (from 6,000 TPD (2 MTA) of methanol) and would require feed gas of 163 MMSCFD (corresponding to reserves of 1.4 TCF over 25 years) and could cost ~US$600 million. This technology is reportably able to be utilized in a marine environment onboard FPSO vessels and Toyo has a consortium with Velocys and MODEC to pursue this option (Toyo 2007). There is also a direct route from gas to DME which is potentially applicable for offshore production options. JFE (Ohno 2006) has developed a direct synthesis route from methane to DME and built and successfully operated a 100 TPD demonstration plant for more than five years to advance the technology. JFE (Ohno 2007) estimated that a 6,000 TPD (2 MTA) DME facility could require feed gas of 225 MMSCFD (corresponding to reserves of 1.6 TCF over 20 years) and could cost ~US$1 billion. A DME facility of this size would have two trains, each train with two 1,500 TPD DME reactors. Total and JFE have been studying this plant size for a commercial onshore facility in Qatar (Wood 2008). No studies of offshore applications have been reported, but other than the normal marine project challenges (space constraints and vessel motions), there appears to be no unsolvable issues, so continued technology development would be very attractive to deepwater gas resource stakeholders. A large offshore DME facility could supply 3-5% of current and predicted near-term Asian demand for

DME. This demand is likely a "moving target" since the market is predicted to grow significantly as the advantages and benefits of DME continue to be realized. In addition to the olefins feedstock market, DME is an attractive product as an LPG additive or replacement; as an automotive fuel; or as a fuel for power generation. For countries in SE Asia, the LPG additive/replacement option may be particularly attractive and DME can be mixed into LPG in amounts up to 20% with minimal modifications to existing infrastructure (Ohno 2007). DME has the advantage of being non-toxic so it is safe to handle and transport. Some of DME’s technical, commercial, and marketing considerations are well covered by Ohno (2007). In this reference, JFE presented some ideas of predicted DME product market valuation based on marketing work in Japan and China – on a BTU basis, the value of DME could be approximately equal to crude product pricing which would be very attractive (“high value BTU” product). DME recent pricing has been in the range of US$370/tonne which is about US$9/MMBTU. With a few more years of technology development, DME could become an attractive development option with scalability (wide range of economic production rates and reserves) and commercial flexibility (ability to lease process facilities from third parties and deliver high value BTU product to relatively unconstrained “liquids markets” in conventional FOB LPG shuttle tankers). This development option might also be combined with other development options based on the needs of a particular field, country, or market (Figure 4).

c. Synthetic Crude The most common usage of the term GTL is for the production of “synthetic crude”, usually by the Fischer-Tropsch (F-T) process. GTL is suitable for projects with a range of production rates/reserves and distances to markets, and should attract product pricing from international “clean hydrocarbon” markets. An example of a proposed GTL FPSOs is shown in Figure 3. GTL production process facilities are large and complicated and therefore would require significant amounts of capital and longer construction schedules. Both FPSOs and transport vessels may also have issues depending on the exact product chemistry (i.e. if too much wax is produced, there could be flow assurance issues). If the production chemistry is focused on paraffinic hydrocarbons,

the resulting product is called “synthetic crude” or syncrude, and conventional liquid storage and transport vessels can be used. There have been suggestions to eliminate additional product upgrading (hydrocracking and fractionation) offshore and just stop the process after some kind of “transportable” liquid is produced, but this is likely an economic decision based on CAPEX requirements and product pricing. The need for further onshore processing could constrain the potential marketing of the offshore product and therefore may not be attractive. The technology for GTL is complex and the choice of processes (syngas, reactor, catalysts, and product upgrading/refining) for offshore (compact) applications has been progressed to implementation on several pilot projects. Multiple proprietary F-T technology applications have been in development and used in both small and large onshore plants (Apanel 2005, Hansen 2005, and Olsvik 2005), but there are also non-F-T GTL technologies being developed and tested (Gattis 2004). The potential use of an oxygen plant (Air Separation Unit (ASU) feeding oxygen into an Auto Thermal Reformer (ATR) to produce the require synthesis gas (syngas)) onboard an FPSO is a risk decision based on proximity to hydrocarbon facilities. Risks can be mitigated with actions on facility layout, equipment spacing, fire and blast walls, etc. ATR produces reusable heat for other process systems. Steam Methane Reformer (SMR) technology to produce syngas has been developed and proposed by Velocys/Toyo/Modec (Simmons 2008 and Tonkovich September 2008) to eliminate the offshore oxygen plant requirement. Using SMR feeding syngas into microchannel process units is designed to minimize water requirements and to modularize the equipment, which would help with space constraints onboard an FPSO. Pilot scale testing has been ongoing to validate the technology. Conventional SMRs have been used for some time in onshore methanol plants. CompactGTL (CGTL) is using an SMR for its offshore GTL pilot plant application on a Petrobras FPSO, offshore Brazil. The CGTL process uses a SMR to convert produced gas to syngas which is then compressed and flowed to a Fischer-Tropsch reactor (FTR) from which it emerges as synthetic crude oil, water, and a residual stream of hydrogen, carbon monoxide, and gas. Both the CGTL SMR and FTR are microchannel assemblies based on plate-and-fin heat exchanger technology (Beckman 2009).

Other syngas production technologies called non-catalytic partial oxidation (POX), catalytic partial oxidation (CPOX), heat exchange reforming (HER) and “compact” reforming (CPR) have been developed and tested for potential use (Apanel 2005). Major operating companies like Shell, BP, and ConocoPhillips are pursuing these other syngas technologies. Some of these technologies have been studied for offshore applications. The selection of reactor technologies is important for space optimization (size of reactor vessels), risk mitigation (reactor / process temperatures), catalyst selection (life cycle costs), and GTL product selection. One challenge is to correctly select the process details to help minimize lighter hydrocarbon production (C1 to C4) whilst not making too much soft (C20-C34) and hard (C35+) waxes (which would present flow assurance risks). There may be a need to perform mild hydrocracking of the wax fractions to increase diesel production (which would help mitigate flow assurance risks) (Apanel 2005). Offshore GTL facilities have been estimated to cost ~30% more than onshore GTL facilities (Olsvik 2005). GTL is more capital intensive for the process facilities compared to LNG, but is less expensive in storage/transport (no cryogenic ships with special insulated tanks) and redelivery (no regasification facilities) costs. In similar onshore studies (Rahman 2008 and Economides 2005), GTL was compared with LNG for the development of a 650 MMSCFD field (required reserves of 4.4 TCF over 20 years):

• GTL facilities would produce 65,000 BPD of GTL products (Naptha 17,000 BPD, Diesel 44,000 BPD, and LPG 4,000 BPD). GTL facility costs were estimated to be US$ 1.82 billion (@US$28,000/BPD of capacity in most recent study).

• LNG facilities would produce 4 MTA. LNG

facility costs were estimated to be US$ 800 million (@US$200/tonne/annum). Cost for LNG ships (assuming ~10-12,000km route, so 6 ships of 135,000 m3 capacity at US$ 140 million/ship) was US$ 840 million. Regasification facilities were estimated at 30% of liquefaction plant investment, or US$ 240 million. Total assumed investment for LNG was US$ 1.88 billion.

• Relative investment CAPEX costs were about equal in these two studies. Note that, since

these studies, LNG process facilities costs have risen significantly, but have likely been reduced again as a result of recent economic conditions – costs of US$500-600/LNG tonne/annum should be used for future economic comparisons. GTL costs went up similarly, but have recently started to reduce for the same reasons.

• OPEX costs were compared for production facilities plus shipping costs and found to be about equal between the two monetization options. Shipping costs increase significantly for longer distances to market for LNG compared to GTL due to the high cost of LNG transport ships (Pyrdol 2007).

• Relative revenue streams were harder to estimate, since both studies used older product pricing, but using some of the assumptions in both studies with current pricing, it appears that the revenue stream from GTL should be significantly higher than LNG. The concept of “high value BTUs” applies for GTL products and support for this hypothesis is contained in Pyrdol (2007) and Reeve (2009).

• Offshore applications would have different cost allocations, but the same relative economics should apply.

With a few more years of technology development, FGTL should become an attractive development option with scalability (wide range of economic production rates and reserves) and commercial flexibility (ability to lease process facilities from third parties and deliver high value BTU product to relatively unconstrained “liquids markets” in conventional FOB shuttle tankers). This development option might also be combined with other development options based on the needs of a particular field, country, or market (Figure 4). INVESTMENT DECISION INPUTS Investment decisions have to be made to select which of the previously discussed options are appropriate for a particular development. Input to these decisions will include governmental or regulatory requirements, gas reservoir characteristics, facility issues, product pricing, location of market(s), and risks. Government / Regulatory Requirements a. Taxation (PSC or Concession) The method of taxation and how investments and any incentives are capitalized or recovered can

influence the investment decision – the developer will need to decide whether to capitalize or expense some of the costs (i.e. build and own the FPSO versus contract and lease the FPSO). Taxation may also lead to decisions to partially monetize the gas inside the PSC or Concession and monetize the rest of the potential value externally – i.e. produce and sell (transportable) methanol offshore to a non-PSC entity (at commercial market prices), then process to DME onshore and sell to get remainder of market value possible from the original gas feedstock.

b. Cost Recovery (PSC or Concession)

Large capital investment requirements of either FLNG or FGTL investment decisions can lead to complex and time-consuming approval processes by regulators when considering multi-billion dollar investments. The source of capital for these large investments (financing, partnerships, tolling arrangements, build-operate-transfer agreements, etc.) can all be influenced by the cost recovery procedures and regulations applicable for a particular country or development.

c. Domestic Market Obligations (DMOs)

DMOs can require the developer to sell a certain portion of the production to the domestic market of a country, usually at some specified percentage of the market price or at lower domestic prices. Domestic market prices of gas can be very low, whilst domestic market prices for methanol, DME, or synfuel are typically more world market priced. If no “gas” is actually produced on the floating facilities in a transportable form, then the developer will need to negotiate alternate arrangements with the regulators. DMOs are also typically time-related obligations, so that the developer may have a specified initial period to maximize production and revenue, which is not necessarily ideal for a sustained plateau production profile (as in LNG developments).

d. Procurement Rules (including local content)

High technology projects can be challenging to achieve high percentages of local content depending on the maturity of the technology. More recently developed technologies may be limited to a few international suppliers and may be difficult to source in local markets. There may even be only one international suppliers of certain technologies. Complicated FPSO ship vessels or process equipments/integrations may also require experienced shipyards located in other countries to achieve the necessary economic inputs (costs and delivery schedules) to ensure projects are viable to all stakeholders.

Gas Reservoir Characteristics a. Reserves Duration of Production, Production Profiles, and shape of Production Profiles (rapid ramp up and then longer decline down (normal oil and gas projects as well as GTL projects since products sold into open market) versus ramp up with subsequent sustained plateau) are significant reserves issues that can affect investment decisions. b. Presence of oil / condensate Liquid hydrocarbons like oil (in separate reservoir horizons or as an oil rim) or condensate (usually associated) can provide useful economic support to development decisions for the gas resource. The amounts would affect the floating vessel production and storage requirements. c. Gas composition (C1-C6+, water, mercury,

H2S, CO2,etc.) The “richness” of the gas (high amounts of C3 and C4 for example) can provide another economic benefit to development decisions (adding a LPG development option). The presence of unwanted components (such as water, mercury, H2S, or CO2) can lead to higher costs (and more space requirements on the floating facilities) to process them out of the market product stream (for technical or commercial reasons). Facility Issues a. Technical • Number or size of floating facilities for

production, storage, offloading, and transport – floating facilities have less opportunity for economies of scale (compared with onshore projects) – only limited ability to add additional process facilities on FPSO host vessels - normally have to add additional FPSO vessels. LNG allows the transport of large volumes of gas over long distances. Individual LNG transport vessels can carry up to ~6 BCF. Offloading facilities are more complex, but they can be used to feed remote domestic gas markets including power and fertilizer plants (depending on economics and pricing). More MMBTUs can be shipped as GTL products in the same sized transport vessel compared to LNG products.

• Process Risks – (reliability or safety) including

efficiency of process (conversion rates and

quality of product (in specification or not) at a range of process conditions); intrinsic safety of process (i.e. Oxygen plant? Fired Heaters? Rotating equipment? Temperatures?); and weight and footprint of process systems including potential impact on vessel size for any process changes. DME uses well proven process technology and has been advanced significantly over the past 5-10 years for compact (offshore) applications. Carbon / Thermal efficiencies of various processes range from 92/88% LNG, 85/70% MeOH / DME, and 77/60% GTL (syncrude) (Patel 2005) – with considerable technical development work ongoing to improve efficiencies of the three GTL processes – these efficiencies obviously affect economics, but the relative MMBTU pricings more than offset the variances in these numbers at 2010 pricing levels.

• Metocean Constraints – (that affect host

facility’s ability to receive production, or to process fluids without upsets inside columns or other process equipment, or to offload products to shuttle vessels) including Waves / Swells / Currents / Winds could affect the process selection (or costs to mitigate these constraints) based on site conditions.

• Safety issues – including (a) Equipment layout

and spacing (fire, blast, leak, spill considerations); (b) Product storage (temperatures (cryogenic, exothermic), sloshing, flow assurance); (c) Vessel operations in proximity to FPSO (crew/supply, shuttle vessels, offloading); and (d) HSE (hazards for operational personnel). DME biodegrades in soil and water, is non-carcinogenic, non-mutagenic, and virtually non-toxic. DME can be stored and transported in the same facilities as LPG.

• Project Schedules – availability (startup dates,

time to ramp up to full design rates, operational uptime, and varying well rate flexibilities) can affect economic returns and therefore process selection.

• Constructability (newbuild or conversion) –

FLNG FPSOs will likely be newbuilds due to safety considerations (simultaneous operations) but FGTL FPSOs could possibly be conversions depending on the process design basis. The choice of newbuild versus conversion could have an impact on the project delivery schedules.

• Operability – Being able to be operable at a range of reservoir conditions and rates and metocean conditions will have significant impact on production uptime and therefore economics. The selected process and product options need to be designed to be as robust as possible to give maximum operational performance. Prior to delivery from a shipyard, full quayside performance (acceptance) testing is possible to demonstrate operability at a range of production rates prior to delivery to the remote deepwater site location.

• Maintenance – including multiple process trains

with isolation; ability to store/ handle/ service/ replace critical equipment or components; and storage and handling of Process Chemicals (including flow assurance, corrosion, process catalysts

b. Commercial / Contractual • Capital Requirements and Timing - The nature

of the exported product (gas or liquid) affects the type of sales agreements able to be negotiated, which in turn will affect the financing ability of a development (i.e. long term take or pay LNG contracts with clear pricing adjustment formulas (including floors) could facilitate bank financing).

• Purchase or Lease - floating production

facilities can be redeployed on other projects in other locations so they are more feasible to be leased from third parties. Leased facilities are likely to be more generic for a range of potential field conditions and may be available sooner based on engineering have been already completed and shipyard slots already booked. Constraints of cost recovery or procurement/contracting procedures may impact the ability to select this option.

Product pricing a. Selecting the Market The concept of constrained markets is important in the product decision – typically a significant LNG investment decision would need a long term market contract with high international LNG pricing, whilst GTL “syncrude” would be sold into more open “liquids markets” with multiple redelivery options and linkage to international product pricing. There is much more competition for long-term LNG market contracts and LNG markets are relatively

smaller than the markets for liquids, so it would be easier to access better product pricing for GTL product contracts, even spot market contracts. Potential LNG supply from currently proposed SE Asia projects has been reported to exceed forecast Asian LNG demand by 57% (Sethuraman 2009), so this could affect LNG markets and pricing and possibly future product selection decisions. Onshore storage for LNG redeliveries is very expensive and limited – economic market conditions in 2009 led to several spot market deliveries of LNG to North America markets solely based on the ability to store LNG in existing facilities in spite of low spot market prices. The economic deterioration of spot LNG markets in 2009 has also shown that commercially risked decisions might accelerate development of GTL technologies to allow the selection of GTL production and export options targeted for the less constrained and broader “liquids markets”. Methanol redeliveries can be stored in commercially available third party chemical storage facilities. Methanol pricing is well defined and long term contracts are possible. DME redeliveries can use existing onshore LPG infrastructure. DME is fungible in Propane, Diesel and Natural Gas Markets and therefore long term or spot contracts are available. DME as a partial blending replacement for LPG has clear domestic and international markets. GTL redeliveries can use existing liquid hydrocarbon (oil, condensate, fuels, and refined products) infrastructure. The market pull of “clean hydrocarbons” may provide pricing advantages. Redeliveries of GTL products are easily accommodated in onshore storage facilities which are readily available and cheap compared to onshore LNG storage facilities. Patel (2005), Pyrdol (2007) and Reeve (2009) detail the concept of GTL products being more valuable on a MMBTU basis than LNG. GTL products are “high value BTU” products and can be more valuable than LNG on an MMBTU basis. Relative values between the three GTL products (methanol, DME, or syncrude) vary according to the assumed feedstock cost – in current markets DME is a more economic choice (Lee 2009). b. Pricing Adjustments Product pricing fluctuations (including transfer pricing (if applicable), product price formulas, price floors, spot/long term contracts, and the ability or not to revise pricing formulas as the markets change). Long-term LNG Contract pricing issues (Culotta 2008 and Eng 2008) could affect ongoing development economics. Without price floors,

investment decisions may be risked and high capital options may be penalized. LNG can offer reduced exposure to pricing risk downside with long term contracts that have price floors. LNG pricing formulas are well defined (Eng 2008) and contractual methodology exists to revise pricing periodically (Culotta 2008). c. Take or Pay The ability to defer or cancel shipments, with or without commercial payments or future rate commitments in long term contracts can affect economics especially if no other substitute market is readily accessible. Curtailment of some LNG redeliveries to Taiwan, Korea, and Japan in 2009 and the lack of a robust alternative spot market led to gas production reductions at several international LNG process facilities thereby affecting economics. Cost Comparisons Various charts have been produced over the past few years (one example in Wood GPA 2008) to show production rates and distances to markets that favor certain products and process technologies. All of these charts have had a general story that high rates and short distances favor pipelines, whilst high rates and longer distances favor LNG. These charts can only tell part of the story, so manual evaluation on a case by case basis is required to help determine the best production and export option choice. Usually not addressed on these charts are the relative economics of different product pricing on an MMBTU basis and how this could vary and should be risked. Location specific details like PSC/Concession contractual and commercial requirements including Domestic Market Obligations, cost recovery, transfer pricing (where applicable), and tax considerations are also not usually addressed and they can fundamentally change the monetization decision. In the case of large production rates, the facility size may become an issue for safety risked decisions which could influence the choice of product and process technology. Work on GTL has narrowed the relative economics of GTL versus LNG for long distances. LNG may eventually be considered as a “bounded” option. GTL may eventually be shown both “below” (lower rates for the same distance) and to the “right” (longer distances for same production rates) than gas market options. Maximizing high value BTUs for a given production rate and distance to market at the same time as minimizing CAPEX and OPEX

costs should allow the correct monetization decisions to be made. CONCLUSIONS FLNG is clearly the most ready monetization option at this time. Actual FLNG designs and projects have been progressed within the industry and shipyard slots are being booked. Multiple technology partners and contractor consortiums have made and are ready to make firm, lump sum (or lease) turnkey proposals for potential projects. Continued technological development should allow FGTL to become a more feasible monetization option with the pull of high value BTU products. Multiple and varied risks and advantages associated with each development option, FLNG and FGTL, can significantly influence choice selection as shown in this paper. Deepwater LNG or GTL FPSOs may have a perception of operability risk (either reduced uptime affecting reliability of deliveries or process issues leading to reduced product quality) that could lead buyers to offer lower market pricing contracts for the products and this will need to be addressed by developers to get the best economic results whichever choice is made. For large remote deepwater gas fields there may be development scenarios with multiple FPSOs, as shown in Figure 4, to handle different parts of the value chain and allow multiple products (FLNG and FGTL) to be produced and marketed to optimize the economic returns for the field reserves. ACKNOWLEDGEMENTS The authors would like to express appreciation to Hess Corporation for permission to make this presentation. Any opinions, conclusions, or recommendations expressed in this paper are those of the authors and do not necessarily reflect the views of Hess. REFERENCES Apanel, G. 2005. GTL Update. SPE Paper 93580, presented at the 14th SPE Middle East Oil & Gas Show and Conference, Bahrain, 12-15 March.http://www.spe.org/spe-site/spe/spe/jpt/2006/04/Synopsis93580.pdf Beckman, Jeremy, 2009. Gas-syncrude conversion increases remote field development options, Offshore, December http://www.offshore-mag.com/index/article-display/2468881275/articles/offshore/

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Figure 1 – LNG FPSO (FlexLNG)

Figure 2 – Methanol FPSO (Coogee)

Figure 3 – GTL FPSO (Syntroleum Bluewater)

Figure 4 – Multi-FPSO Integrated Field Development