LNG project costs and the luck of the draw

LNG World Shipping has assessed the cost per tonne of annual output capacity for 37 LNG projects in play over the 2013-2021 period. The results highlight some obvious conclusions – such as the fact that Australia has been a high-cost place to bring seven challenging, worldscale projects on stream simultaneously – and many more subtle conclusions.

The project-cost review encompassed schemes completed since 2013, those under construction, those at an advanced planning stage and targeted for a pre-2021 start-up and several that have been cancelled over the past three years.

The total project cost used to calculate each scheme’s cost per tonne of annual LNG production capacity includes the engineering procurement and construction (EPC) contractor’s costs and those incurred by the owners following the final investment decision (FID). We excluded the costs associated with financing.

When considering the investments required to bring 37 LNG projects to fruition, we concluded that direct cost per tonne comparisons are fraught with difficulties because each individual project is unique, comprising a range of variables.

Aside from the terminal’s location, each particular venture’s logistics challenges and market conditions during the time it takes to realise an LNG project, the vagaries include access to finance, choice of technologies, local and geopolitical issues, FID timing and human factors. All invariably have a role to play in any cost profile.

In any construction project that costs billions, employs thousands, utilises cutting-edge technology and takes upwards of four years to complete, there is every likelihood of cost overruns and time delays.

US-Australia divide

The most obvious contrast when reviewing project costs worldwide is between the US and Australia. Both countries have seven new projects underway, if we consider US-based Sabine Pass to be three separate phases, and both will emerge among the world’s top three LNG producers when all the schemes are completed in 2018.

Developers of the Australian and US projects decided to proceed with their ventures before the oil and LNG price bubbles burst in mid-2014. The price collapse, along with a slackening demand for energy and prospects for a prolonged supply surplus, present the investors in these schemes with longer payback times than they had envisaged.

There the similarities end. The seven Australian projects cost an aggregate US$183 billion and will provide an LNG production capacity of 61.8 million tonnes per annum (mta). Thus each tonne of Australia’s new annual LNG output will cost US$3,000 on average.

In contrast, the seven US schemes will provide 64.7 mta of output capacity at a total cost of US$53.5 billion, putting the average per tonne cost at only US$825.

The Australian projects were always going to be comparatively high-cost ventures. Three of the seven LNG terminals – Queensland Curtis LNG, Gladstone LNG and Australia Pacific LNG – are adjacent to each other on Curtis Island in Queensland’s port of Gladstone. All three rely on gas piped more than 500 km and extracted from Queensland’s vast coal seams using hundreds of wells and new technology previously untried on this scale.

The other four projects use the rich gas resources found off Western Australia. Three of these – Gorgon, Wheatstone and Ichthys – feature onshore liquefaction plants and required long stretches of subsea pipeline and extensive dredging, and have built large, greenfield terminals at remote locations.

The fourth Western Australia scheme, Shell Prelude, is using an offshore liquefaction plant that will be the largest floating structure ever built. Although siting the vessel at the gas field saves on costs unique to land-based projects, Prelude is the result of extensive development work and embraces a slew of new technologies. 

As the first LNG project of this type and magnitude for a deepwater location, it will not be cheap on a cost per tonne basis.

Australia has had other domestic issues to contend with. The combination of a strong Australian dollar and shortages of manpower and materials to mount seven major projects concurrently in a country that has a relatively small population and economy has had unavoidable inflationary consequences.

All the Australian projects have fallen victim to cost overruns. In mid-2005, for example, when the Gorgon LNG partners launched the project’s front-end engineering and design (FEED) phase, the scheme was expected to cost a total of US$10 billion, or US$640 per tonne of capacity, with the first cargoes to be loaded in 2010 and 20 per cent of output dispatched to new import terminals on the US west coast.

Then the fates intervened. Today, Gorgon is only just getting ready to dispatch its first export cargo and the returns will be nothing like those anticipated – at least not until the global gas supply and demand situation comes more into balance. 

In the intervening years, Gorgon project costs have skyrocketed to US$54 billion, or US$3,462 per tonne and match the cost of all seven US projects put together. The scheme’s developers will also be competing with US LNG exporters to find buyers for Gorgon volumes not committed under long-term sales contracts.

US shale play

A decade ago the US was getting the infrastructure in place to give Japan a run for its money as the world’s leading LNG importer. The development of technology to enable the country to exploit its vast shale gas resources has turned that scenario on its head and the US is now poised to become a leading LNG exporter, assisted by some remarkable advantages.

Six of the seven US export projects under construction are using existing import terminals that have sat largely idle in recent years. With most of the storage tanks and marine jetties in place, the terminals have only had to add liquefaction plant and gas feed arrangements.

Accessing labour, materials and equipment has not caused undue problems in such a large economy and linking the terminals with the shale gas reserves has been facilitated by the country’s vast network of pipelines, particularly in the Gulf coast region where the shale plays are in close proximity to terminals now being given  bi-directional capability.

Another positive is the Panama Canal. The opening of the waterway’s enlarged locks in the coming year will make it easier to deliver US LNG to customers in Asia in LNG carriers of up to 180,000m³.

The magnitude of domestic shale resources has prompted more than 25 US LNG project proposals. Industry watchers acknowledge that the seven under way enjoy strategic first-mover status and question whether a slack market can support many additional export schemes.

To understand the difficulty sustaining a project proposal in today’s market, despite an attractive cost profile, look no further than the FLNG venture that Excelerate Energy proposed for Port Lavaca on the Gulf coast.

Following FEED studies, Excelerate stated it could put a 4.4 mta, barge-mounted, jetty-moored liquefaction facility into operation at the Texas port by 2018 at an attractive per tonne cost of US$545.

However, the company shelved the venture earlier this year due to the rapid switch from a seller’s to a buyer’s market. Excelerate Energy failed to line up any buyers for Lavaca output in the face of such widespread competition. Meanwhile, the cost of maintaining the initiative was becoming prohibitive.           

 

What price Canada?

Canada is also poised to fill gaps that may emerge in global demand for LNG in the 2020s. It has some 21 proposed export projects with an aggregate output of more than 150 mta but none have reached FID.

Seventeen of the Canadian schemes lie along the coast of British Columbia and would be well placed to serve Pacific Basin customers, particularly in north Asia. But although British Columbia liquefaction plants avoid the Panama Canal fees that will impact US exports, and will have lower shipping costs, Canada’s ambitions face challenges.

One stumbling block is the competition for available markets, from Australia and the US and from Russia and Mozambique. Canada must also resolve land-rights squabbles with Native American tribal groups and build long pipelines from Alberta and the remote gas fields in the northeastern corner of British Columbia.

The three British Columbia projects that are most advanced in planning and permitting and that have the best chances of a pre-2021 start-up are Pacific NorthWest LNG, Douglas Channel LNG and Woodfibre LNG, with anticipated per tonne production costs of US$2,667, US$1,000 and US$762.

Part two of this project cost per tonne analysis will compare the costs of offshore and onshore projects and deepsea against nearshore floaters.