FLNG conversions cost-competitive with onshore projects

July 2, 2018
Floating LNG (FLNG) plants converted from existing vessels can come online at a price comparable to low-cost onshore plants. At current LNG prices, however, there is little room for larger newbuild FLNG’s and even conversions face uncertain prospects.

Jim Scott

DRL Engineering

Houston

Floating LNG (FLNG) plants converted from existing vessels can come online at a price comparable to low-cost onshore plants. At current LNG prices, however, there is little room for larger newbuild FLNG’s and even conversions face uncertain prospects.

Background

In May 2011 Royal Dutch Shell sanctioned the first FLNG project, Prelude, offshore northwest Australia. This was followed in March 2012 by Petronas announcing its own FLNG in the South China Sea offshore Malaysia, PFLNG1. Expectations were high that the offshore gas industry had found a solution to commercially developing stranded offshore fields. Plans were in place for both Shell and Petronas to implement further FLNG projects. Shell had identified the need for FLNG vessels at Abadi, Sunrise, Browse, and Exmouth Plateau, and Petronas for PFLNG2 on the Rotan field in the South China Sea. Other Operators also identified potential FLNG developments and began early project planning. In 2011-12 the future of FLNG was promising, with multiple projects on the drawing board.

In 2018, however, the FLNG market has changed significantly. LNG’s market price has fallen below $10/MMBtu. DRL Engineering expects producing and planned FLNG projects to produce less than 2% of global LNG supply by end 2018. Prelude FLNG’s execution schedule has slipped from the planned 64 months to more than 85 months, with associated higher-than-sanctioned costs. The combination of lower LNG prices and high or uncertain FLNG plant cost, has raised doubts regarding the long-term viability of new FLNG projects. Numerous FLNG projects sanctioned in 2011-12 have been cancelled or are on hold.

This article analyzes FLNG’s competitiveness with onshore LNG, giving insight into FLNG’s long-term viability.

FLNG projects sanctioned to date are Prelude (May 2011), PFLNG1 (March 2012), Pacific Rubiales Energy’s Caribbean FLNG (April 2012), Golar LNG’s Hilli Episeyo offshore Cameroon (August 2014), and Eni SPA’s Coral South offshore Mozambique (June 2017). PFLNG1 became the first FLNG to begin LNG production (Dec. 5, 2016) and the second, Hilli Episeyo, started production Mar. 18, 2018.

Caribbean FLNG construction finished in early 2016, but vessel owners Exmar are looking for a new operating location following Pacific Rubiales’s cancellation of the project due to low LNG prices. The Prelude project is forecasting first LNG in mid-2018.

FLNG project performance to date has been mixed with Prelude and PFLNG1 both being delivered with relatively high unit development costs. PFLNG1, however, was delivered on time and within sanctioned budget. The Hilli Episeyo conversion—completed by Keppel Shipyard and using Black & Veatch technology—delivered a project with cost and schedule performance to match onshore LNG.

Benchmarking

The benchmark number commonly used in LNG project analysis, both onshore and offshore, is the capital cost/tonne of LNG produced in a year. This analysis will examine two main benchmark metrics: LNG plant cost measured in tonnes/year (tpy) and integrated LNG project cost, also on a tpy basis. FLNG plant cost includes the cost of the hull, turret, topsides, mooring, and marine installation. Integrated cost also includes the cost of the gas supply in terms of drilling and completion, pipelines, compression, gas conditioning, and subsea infrastructure.

FLNG cost data show that newbuild FLNG’s, such as Prelude and PFLNG1, have a high plant cost/tpy relative to FLNG conversions (Fig. 1). The Hilli Episeyo conversion FLNG at $500/tpy, represents best-in-class cost performance for an LNG plant either onshore or offshore.

Deployed in shallow water off Cameroon, Hilli Episeyo is a conversion of a 1975-built Moss LNG carrier. It has a design capacity of 2.4 million tonnes/year (mtpy), produced by four 0.6 mtpy trains, and a storage capacity of 125,000 cu m.

Fig. 2 illustrates the commercial difficulties the first FLNG project faced. Newbuild FLNG plants are significantly costlier than low-cost onshore plants. FLNG conversion projects, however, are on par with the lowest onshore LNG project costs, a significant breakthrough for the FLNG industry.

Fig. 3 shows how good the potential is for FLNG developments based on a Golar-type FLNG conversion. It also shows that the first two newbuild FLNG’s, Prelude and PFLNG1, have costs similar to high-cost onshore developments such as Ichthys (Inpex Corp.), Wheatstone (Chevron Australia Pty. Ltd.), and Gorgon (Chevron Corp., ExxonMobil, Royal Dutch Shell, Osaka Gas, Tokyo Gas, Chubu Electric Power).

Cost factors

A few factors contribute to the favorable cost comparison of FLNG conversion relative to newbuild FLNG’s. Converting an existing LNG carrier avoids the cost of building a new hull, which in Prelude’s case totaled more than $1 billion. Selecting a process based on plant simplification and efficiency also keeps costs down.

Hilli Episeyo’s selection of the Black & Veatch process based on single mixed refrigerant technology was a significant contributor to low-cost development. This technology weighs roughly 25% less per tpy than the double mixed refrigerant LNG process selected by Prelude. Scope is the biggest driver in cost and Hilli Episeyo achieved its low cost with a topside weight roughly 30% less than the average of FLNG projects (Fig. 4).

Hilli Episeyo’s capital cost is $1.2 billion, or $500/tpy, which is lower than that achieved at onshore Sabine Pass Trains 1-4 ($700/tpy, including terminal). Hilli Episeyo was executed at a time when oil and gas construction costs were low, but it gives encouragement for the future of FLNG.

Plant cost makes up roughly 56% of the total cost of any integrated LNG project (Fig. 5). Integrated project costs include drilling and completion, upstream costs, owners cost, and downstream costs (the onshore plant or FLNG). If an FLNG project can combine low plant costs with low upstream and drilling costs the overall project can have a competitive advantage even versus low cost onshore projects.

Fig. 6 shows that newbuild FLNGs Prelude and PFLNG1 cannot deliver as competitive a solution as low-cost onshore integrated projects like Tangguh Train 3, Donggi Senoro, or even Yamal. Coral South’s cost forecast, however, is similar to Australian coal bed methane projects like Gladstone, Queensland Curtis, and Australia Pacific.

Fortuna FLNG’s forecast, based on a conversion similar to Hilli Episeyo and including four subsea wells initially and seven wells in total, if achieved, would deliver best-in-class cost performance aligned with low-cost integrated onshore LNG projects. Even so, in June 2018 Schlumberger withdrew from its OneLNG Fortuna-development joint venture with Golar, citing a lack of progress on finalizing debt financing and despite Golar pointing out that recent LNG price increases had strengthened the solid returns already anticipated for the project.

The accompanying table shows the main component costs for recent integrated LNG projects. Some have high drilling costs such as the coal bed nethane projects in Queensland, Australia, where drilling and completion contribute $706-933/tpy. Other projects like Sakhalin II, Wheatstone, and Ichthys have high upstream costs ($973-1,395/tpy). Still others have high LNG plant costs, including Ichthys, Gorgon, Wheatstone, Prelude, and PFLNG1, all of which have plant costs near or above $2,000/tpy.

FLNG conversion projects, however, as demonstrated by Fortuna, are still economically tenuous when LNG prices are less than $10/MMbtu. Fortuna had relatively low upstream and LNG plant costs. Drilling costs were also moderate. Another aspect favoring Fortuna was that, although in deep water (1,790 m), it is in a region with a benign sea state. And yet the project struggled to be financed.

New FLNG Projects will continue to face stiff economic scrutiny in the current soft market. Figs. 7 and 8 show the Japanese LNG spot price and price relationship between LNG and Brent crude, respectively. LNG-project breakeven prices must cover not only capital expenditure but also operating and shipping costs. Only low-cost FLNG projects stand a chance at making a profit in a $10/MMbtu market. At $8/MMbtu (~$50/bbl Brent), an integrated project would have to deliver a capital cost of less than $1,200/tpy (Fig. 9). The forecast for Fortuna was $1,221/tpy.

Shipping costs are included in the indicative LNG breakeven price. LNG plants that are closer to their demand market will have lower shipping costs. Fig. 10 shows indicative shipping costs by distance.

Project schedule is another important execution component. Newbuild FLNG take longer to complete than onshore plants for comparable throughput (Fig. 11). FLNG conversions, however, have a similar execution duration as onshore plants.

Offshore stranded-gas fields that can produce roughly 400 MMscfd are ideal candidates for a 2.4-mtpy conversion FLNG. An FLNG plant can also theoretically be redeployed to a new site when the gas supply at its original field is exhausted. Hilli Episeyo is scheduled to be on-station near Cameroon for an initial 8 years with plans for future use still being developed.

FLNG conversions are a viable competitor to onshore plants if the stranded gas reserves are at least 2 tcf and accompanied by a benign sea state. Where there are numerous stranded gas fields of less than 2 tcf it also may be possible to use a single 2.4-mpty FLNG conversion which can be redeployed to each field.

Fig. 12 shows the relationship between annual LNG production and reservoir size.

The next FLNG conversion project after Fortuna will be for BP and Kosmos Energy’s Tortue-Ahmeyim field in the C-8 block offshore Mauritania and Saint-Louis Profond block offshore Senegal. TechnipFMC won the front-end engineering and design contract for Tortue FLNG. The converted vessel is expected to have 500-MMcfd capacity with the fields’ recoverable gas estimated at 15 tcf.

Successful replication of Hilli Episeyo’s outcomes will help increase FLNG cost and schedule certainty and improve investors’ willingness to invest in the industry. Prelude look-alike FLNG projects, however, are unlikely.

The author

Jim Scott ([email protected]) is a project analyst with DRL Engineering, Houston. Before joining DRL, Scott held numerous cost-estimating and benchmarking roles for Royal Dutch Shell offshore projects in Asia Pacific, Gulf of Mexico, and the North Sea. He graduated from Heriot Watt University, Edinburgh, Scotland, with a BA Honors (1976) in economics.