Thursday, 17 January 2019

LNG supply – FID back in fashion

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Related images

  • Figure  1 - Sample project costs, US$bn/Mtpa
  • Figure  2 -  Potential supply additions, Mtpa
  • Figure 3 -  Distributors’ supply, BCM
  • Figure 4 -  China pipeline imports, Mt, y/y
  • Figure 5 -  Long-term contracts by destination, Mtpa
  • Figure 6 -  Contracts by start date and duration, Mt

Throughout 2018, gas producers have been basking in prices that make producing LNG look much more attractive than it has for the previous two years. By Trevor Sikorski, head of natural gas and carbon, Energy Aspect.

Over the course of the year,  Asian LNG prices have persisted at around US$8/mmbtu for summer delivery and well above US$10/mmbtu for winter delivery, compared with the sub-US$5/mmbtu seen in summer 2014. The global market has been kept tighter predominantly by the strength in Chinese LNG demand – plus 12 million tonnes (mt) y/y in 2017 and plus 16 million tonnes per annum (mtpa) in 2018.

LNG contract prices are also rising along with oil prices, which have averaged US$73/barrel over the last three months – an increase that has pushed most Brent-linked LNG contract prices above US$9/mmbtu.

As a result of this buoyancy, and with producers suggesting that the market will see some structural tightening as early as 2021 or 2022, there has been a resurgence of interest in supply projects over the last year.

In this article we look at the characteristics of new LNG projects, the prospects for Chinese demand and how new LNG supply will have to compete for buyers with existing volumes facing contract expiry.

Plenty of projects raring to go

We have seen reports of buyers coming back to the market that are not shying away from long-term deals. While there are plenty of reported deals to back that up, the deals tend to be for smaller volumes – a 1mtpa deal is becoming typical – and tend to have much more flexibility in terms of what the buyer can do.

The bulk of these agreements still appear to contain a Dated Brent index, or an implicit Henry Hub index for US volumes. While there has been more activity in the LNG supply sphere, new big projects seem either to need multiple supply agreements in place before proceeding or have project partners able to take merchant risk and build the project on the back of a strong balance sheet.

The projects close to final investment decision (FID) have a wide range of characteristics and include:

* Existing project expansions, which tend to have lower capital costs and take advantage of existing infrastructure and gas production, such as Qatar’s three new trains, Sabine Pass T6, and Papua New Guinea (PNG) LNG’s Trains 3, 4 and 5. In May 2018, Corpus Christi T3 took an FID.

Of these, Qatar – which has announced it would expand its production capacity from 77mtpa to 110mtpa, with that 33 bcm spread over four super trains – looks highly likely. Also, the ExxonMobil-led 8mtpa, three-train expansion of its PNG LNG site looks a good bet as one of the best-performing projects seen in recent years.

* Low-cost brownfield sites in the US remain plentiful, but the reasonably limited balance sheets of the developers mean they rely on offtake agreements covering a large part of the facilities’ offtake. This includes Venture Global’s Calcasieu Pass project, Tellurian’s Driftwood LNG and Pembina’s Jordan Cove LNG.

The biggest headwind to these US projects advancing has been the trade war between China and the US that has seen China put a 10% retaliatory tariff on the import of US LNG. Since then, few US LNG cargoes have been sent to China, and while this episode persists, we do not expect US projects to be successful in landing long-term Chinese buyers.

* New greenfield sites with largely-stranded upstream gas assets for which project FIDs have been delayed during the last few years, but which are now seeing a resurgence in interest. These projects often have buyers, particularly from China, for which equity share in the underlying gas production is of interest – and LNG is the way to monetise such exposure to resource.

Such projects, usually involving high capex, also typically have a major involved that is willing to take some merchant risk and take volumes into their supply portfolios. One such project is the 14mtpa LNG Canada project that took an FID in October 2018.

Other greenfield projects include the two proposed projects in Mozambique – the Anadarko-led 12mtpa Mozambique LNG project is possibly the more likely – and two projects based in Russia. Rosneft has been advancing its own 6mtpa project at Sakhalin and Novatek’s 20mtpa Arctic LNG-2 project, which has Total involved.


Figure 1 and 2


Eggs in the Chinese basket

China has been the key demand-side driver in the LNG market over the last two years, adding 12mt of demand y/y in 2017 and heading close to 16mt y/y in 2018. For the coming years, there are really two key questions on China – how much more demand and how much more regas capacity will there be?

* Industrial sector demand surges – 2018 has seen another surge in underlying Chinese demand, which was up by 33bcm y/y over the first nine months of the year. The biggest y/y changes have been in the summer months of Q2 2018 and Q3 2018, which posted average monthly growth of 28%.

While it is unclear exactly what goes into the official figures of end-user demand in China and, more specifically, if that includes storage injections – which we expect to be higher y/y – all evidence points to continuing high growth in the country’s gas consumption.

Analysis of China’s largest private distribution companies shows that the industrial coal-to-gas switch remains the key driver of China’s gas demand growth, while residential connections are also rising at a faster pace this year.

ENN, for example, increased its industrial and commercial (I/C) customer base by 34% y/y in H1 2018, with the installed supply capacity to this customer section increasing by 18mcm/d (23%) y/y.

The company’s residential customer base also grew strongly, by 2.2m customers or 13.4% y/y. Over H1 2018, ENN’s reported I/C demand increased by 1.23 bcm (24%) y/y while residential demand was up by 0.4 bcm (36%) y/y, with a cold Q1 2018 supporting heating demand.

Industrial demand accounted for 59% of ENN’s gas sales, commercial demand for 15%, residential demand for 19% and transport for 7%. Of all of that I/C, only some 40% of it was driven by the targeted subsidy policies aimed at specific municipalities in NE China with the country’s worst air pollution.

While new industrial connections will add significant and consistent year-round growth, there is growing penetration in the temperature-sensitive residential and commercial sectors. In addition, the gas system managed last winter by what was reported to be considerable volumes of load shedding, and meeting that unsatisfied load this year on its own would provide additional winter demand.

Over all of 2018, demand is likely to grow by 38 bcm y/y, and with little suggesting that China is going to slow its quest for cleaner air, such high rates of growth look likely to persist in the coming years.

China has not even yet really pushed gas into power, so once the city gas networks get built out and gas penetration in urban areas becomes more complete, at least five years from now, then China still has power to start to decarbonise.

* LNG is entering a period where further growth needs new regas – On the supply side, domestic Chinese gas production has had a mixed year, with a very disappointing H1 2018 followed by improved readings in Q3 2018. Overall, we expect Chinese production to be up by around 10-12 bcm in 2018 and to come in at a similar range in the coming three years.

Pipeline imports will be increasing, but in the last gas year (October 2017 – September 2018), those came in at 48bcm, just 7bcm short of the capacity on the three lines of the West-East pipeline. While Russian gas supplies are likely to start in Q1 2020, it will take at least five years to ramp up to the 38bcm y/y level — and all of that only covers around one year of growth.

This leaves a considerable supply gap for China to fill. Some 11mtpa of new regas capacity has been added since the start of Q4 2017, and for 2019 we expect that another 5.9mtpa of Regas will be added – albeit mostly during Q4 2019. In 2020, the numbers look bigger at 16.5mtpa, but again, almost all of that is scheduled for a December start-up.

The key here is that China is beginning to bump up against import capacity constraints, so the speed with which it tightens the LNG market will be increasingly dictated by the speed with which it adds regasification. This is really in the hands of China, but the risk to the market is that, for whatever reason, the regas additions slow down.


Figure 3 and 4


Competition with other long-term volumes

While Chinese demand looks to stay strong and limited only by import capacity, the LNG market is facing a period when a group of existing legacy gas contracts are starting to expire and have yet to be extended. Annual contract volumes peak in 2019, with some 439mtpa of supply under a term supply contract. By 2025, the level of annual LNG under term contracts falls to 355mtpa.

This period of expiry will help further restructure LNG contracts, particularly as it comes against a background of heightened interest in new LNG supply projects.

Existing and new volumes will be competing for buyers, so we expect to see LNG supply contracts become increasingly flexible, with a greater move to a FOB basis from an ex-ship basis, as well as more short-term, with a greater prevalence of contracts with terms below 10 years.

We also see contracts adding pressure for prices to be lower, with Brent slopes coming in more regularly at 12% or hub prices serving as an index. Existing volumes will need to compete with new US volumes offered at US$8-9/mmbtu.

The largest suppliers for which existing contracts are coming to an end are Qatar (21.6mtpa, 24% of current supply), Malaysia (12.7mtpa, 56% of supply) and Algeria (11.7mtpa, 100%). In total, there are four exporters that see all of their contracted exports end by 2025, with Algeria joined by Brunei, Equatorial Guinea and UAE.

All of the six exporters seeing the largest volumes of contracted LNG going to expiry in the period to 2025 are looking at maintaining or expanding LNG exports going forward. Those exporters might look to spread the costs of new build across all of their volumes to effectively compete with US brownfield.

On the buy-side, Japan sees a hefty loss of some 30mtpa of volume under contracts but is still left with some 66mtpa under contract by 2025. Imports in 2017 were 84mt.

The drop in contract volumes will move Japan from being contractually long by some 15mtpa to being contractually short by that period, even given an outlook for LNG demand growth due to a slow programme of nuclear restarts. Some 34mtpa of supply with European and US destinations are also to expire by 2025, and with much of those volumes already in the hands of portfolio players, contract extensions will depend on being attractive enough for the contracted portfolios of LNG traders.

As ever, the key on the demand side is China, which is now looking under-contracted for its existing volumes. China is now on target to import some 52mtpa in 2018, which already exceeds its average annual contracted volumes out to 2025 of around 50 mtpa.

Given another 10-12mtpa of likely Chinese demand growth in 2019, the big selling opportunity will be into the Chinese market. The current Chinese reticence to sign up for US volumes could dampen some of the competitive pressure between sellers coming from the combination of new and existing supplies being marketed at the same time.


Figures 5 and 6

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