Circa the final quarter of 2018, the LNG industry finds itself in what must seem a familiar position. European LNG imports are once again rising, driven largely by a rise in LNG shipping costs. A new wave of liquefaction projects is underway, with everything to gain for project developers able to attract investment. Commoditisation is still a core objective, but questions remain to be answered before a global pricing benchmark starts to look realistic.
The LNG industry is a cyclical one. The upfront costs of developing new projects mean that lenders require a high degree of certainty before committing capital. If they are to take risks, they’ll do it all together, or not at all. Imperfectly pegged to the expected level of supply, expansions in the fleet of LNG carriers follow a somewhat similar pattern, with periodic overshoots and undershoots. And commoditisation needs a level of flexibility that only an amply supplied, well-developed market can bring.
But there are some important differences this time around. Firstly, demand looks a lot different today than it did ten years ago, at the start of the previous supply cycle. Globally, the focus has shifted away from power generation, and towards industrial applications such as fertilisers, manufacturing and petrochemicals. The IEA forecasts that industry will account for 40% of global natural gas demand growth by the year 2023.
In Europe, the story changes somewhat. Power generation will remain a core component of LNG demand, with the continent looking to maintain a reliable power grid despite the retirement of coal-fired power plants. Shoring up storage volumes in the face of declining European gas production will also be a priority. Small-scale applications and marine bunkering will deliver new market opportunities worldwide.
Secondly, climate change and air pollution are much bigger drivers today than they were a decade ago. That has created an opportunity for LNG as a less carbon intensive, lower emissions alternative to coal and oil. But it also means that if natural gas and LNG are to secure their place in the energy transition, they will need to tackle the looming problem of methane emissions – at the wellhead, along the supply chain, and at the point of use.
Thirdly, uncertainties about trade tensions and project financing have thrown a new set of challenges in the path of project developers. Success for US LNG producers has had much to do with the country’s cheap and abundant natural gas supply, and the considerable savings garnered from the conversion of existing LNG terminal infrastructure into export facilities. Escalating tensions between the US and China may detract from these advantages.
Meanwhile, the growth of the LNG spot market – although perhaps sometimes overstated – will favour projects backed by investors with long balance sheets. For the remainder, minimising the risk of investment will be critical; either by keeping expected capital expenditure within realistic limits, by simplifying commercial offtake structures, or by implementing some form of shared equity financing model.
Those are the broad strokes of the discussion that took place during the LNG Global Congress in London this October. Read on as we drill a little deeper into the details, what they may mean for the LNG industry going forward, and how they will make this supply cycle different from the last.
Rising demand from China
Scroll back to 2017. Up until that point, if you had only been paying attention to the demand forecasts issued by the major energy agencies and consultancies, the sudden rise in Chinese LNG imports would have seemed like a bolt from the blue. The currently anticipated 2023-2024 supply gap, and the urgency with which project developers must now seek to secure financing, is in large part due to the fact that buyers base their assumptions upon the advice of analysts and forecasters, few of whom believed that such a rapid increase was possible.
Had you been listening to the demand projections issued by the Chinese state, you would have received a very different impression. Following on from his keynote at LNGgc, the IEA’s Head of Gas, Coal and Power markets explained the reasons for the discrepancy. The IEA’s projections were based on the amount of liquefied natural gas that the country’s infrastructure would allow it to effectively import and distribute. What analysts stopped short of predicting, however, was that China would import more gas than it was actually capable of delivering to consumers – with predictable consequences.
“If anything China was overly zealous in being able to convert people over to gas” Fraser told attendees. To prevent a recurrence of bottlenecks and regional supply shortages, he believes that we may see China moderating its coal-to-gas switching in the immediate future – perhaps placing more emphasis on the mitigation and dispersion of coal burning, rather than its elimination. Nonetheless, the underlying trends are such that the IEA predicts “quite robust” Chinese demand growth over the next five years.
In her presentation, Liu Xiaoli of the National Development and Reform Commission of China provided some more detail about the numbers involved. The commission forecasts an average annual growth rate for natural gas consumption of between 7.7% and 8.6% through to the year 2030, by which time total annual demand will be somewhere between 580 and 670 bcm.
Broken down by sector, Xiaoli provided the following estimates. Gas users in the residential sector and heating system will rise from 44% of urban residents in 2017, to 70% by 2030. Gas-fired power capacity will rise from 76.3 GW in 2017, to 110 GW by 2020 and 250 GW by 2030, much of that in the form of combined heat and power plants. LNG bunkering demand will reach 27 bcm by 2020, and 31 bcm by 2025. Finally industry, the largest sectoral contributor to natural gas demand, will rise from 72.7 bcm in 2017, to 175 bcm by 2030.
Industrial demand is particularly important, according to Trevor Sikorski of Energy Aspects, because the sector is effectively insulated against variations in the price differential between gas and coal. Even if coal prices should sink, Sikorski assured attendees, the physical replacement of coal-fired boilers with gas-fired alternatives means that industrial demand is assured. Switching between coal and gas in the power sector, on the other hand, is much more dynamic and price responsive. “It’s a completely different structure,” Sikorski explained.
Another important thing to bear in mind is that economic forces are the strongest driver of industrial gas consumption, making it less vulnerable to unpredictable changes in policy. “Only 40% of the growth in industrials was a direct result of government policy,” Sikorski told the conference. The rest came from the underlying expansion of gas use in the sector.
Methane leakage and the climate agenda
For LNG and natural gas to grow their market share against competing energy sources, pricing will be crucial. But so will perception. The switch to LNG as a bunkering fuel, and the switch from coal-to-gas, are for the most part not driven by cost considerations, but by the perception that natural gas is a cleaner alternative with a reduced impact on our climate.
And it is – but only if emissions of methane, a potent GHG, are kept within set limits. If emissions along the supply chain rise above approximately 3.2% of total extracted gas, things change. Upwards of that number, the fuel’s contribution to climate change, particularly in the short term, exceeds that of coal.
So far the problem has received nowhere near the same level of scrutiny as CO2 emissions. But as natural gas and LNG move onto centre stage as a transitionary fuel, more attention is being focused on the issue.
In her keynote at LNGgc, the EU Commission’s Anna Samsel von Haasteren made the prevention of methane emissions a central message. “Reducing methane leakage along the value chain is necessary for maintaining the credibility of gas as a transition fuel over the coming decades,” she told the conference.
The credibility issue has particular relevance to the use of LNG as a marine fuel. Marine LNG engines burn the majority of the fuel they use, but not all of it. What escapes is referred to as methane slip, and ranges from as little as 0.1% to as high as 3.5% of total fuel consumption, depending on the efficiency of the engine.
Sjaak Klap, of the Dutch shipping company Spliethoff, expressed concern that more clarity may be needed on what the priorities are for reducing shipping emissions. “When we talk about LNG bunkering, what is it that we’re talking about?” He asked.
Should sulphur and particulate matter emissions be the priority, in which case even the least efficient LNG engines are unambiguously preferable? Or is climate change on the cards as well? “We need to redefine green, because some investors will be very confused if we do not make that clear to them,” Klap said.
Another area in which clarity is lacking is the regulatory approach to methane emissions. Von Haasteren pointed out that there is at present no obligation placed on the natural gas industry within the EU to bring levels down. “Do we need a new strategy, and a strategy in particular for methane? I think the question has to be answered with a clear yes,” she told attendees.
In her outline of what a “tailor made” strategy might look like, she listed several priorities, including better reporting, focusing on the super emitters, stimulating energy diplomacy and initiating bilateral dialogues with the worst offending countries.
Although reducing atmospheric methane concentrations is a laudable objective, there was some pushback from audience members on the culpability of the natural gas industry for rising methane levels. Rudolph Hubert, of LNG Austria, pointed out that there is a contradiction between the uncertainty that still exists about the different sectoral emitters of methane and von Haasteren’s singling out of shale gas production as a likely culprit.
Mike Fulwood of the Oxford Institute for Energy Studies made a similar point, observing that satellite graphics of global methane emissions hotspots seem to implicate coal production in East Asia and deforestation in South America as the worst offenders.
Financing and project costs
After a sustained period of increase since the start of the century, the average cost of developing new projects has over the last four years begun to fall. Keeping costs from rising again will be critical to delivering LNG at an affordable price; a particularly important consideration when exporting to emerging economies for whom cheap coal may seem a more fiscally prudent option.
In his presentation at the LNG Global Congress, the Oxford Institute for Energy Studies’ Claudio Steuer provided some advice on how to minimise the risk of cost overruns. “You need to start with which gas fields you’re going to develop, and what requirements they have,” he told attendees. “You also have to keep in mind that it’s normally better to have repeat designs,” he added. The advantage of standardisation is that it allows for the replication of expertise, methodology and equipment between operations.
Managing costs may not be the toughest challenge project developers face, however. “The commercial and financial complexities of taking FID on an LNG project are just as challenging as managing some of the technical aspects and achieving a low cost,” Steuer said, likening the complexity of the process to that of a game of three-dimensional chess.
One speaker with a very definite view on how best to play this game is Texas LNG CEO Vivek Chandra. Speaking on the second day of the conference, Chandra told attendees that the coming round of FIDs should not be taken for granted.
“I don’t think there’s a single country in the world that will produce more gas tomorrow than they produce today – except for the US,” he said. “But demand is going up. So there’s a dichotomy here… and if the buyers don’t start actually making some decisions, we’re not going to see a lot of projects coming up.”
In Chandra’s estimation, there are three ingredients a project needs to succeed without IOC backing: high value, low risk and realistic size. As trade tensions with China mount, the last of these may prove to be the decider between the projects that are greenlighted, and those that are not. “I don’t see a lot of big volume long term contracts happening until the tension has been resolved,” Chandra said. “Everybody is going to make excuses about why their big, ambitious LNG schedule is going to be delayed.”
A lack of large SPAs creates room for the smaller players to thrive, however. All of the large projects “need big chunky contracts,” Chandra told the conference. “You can’t have half a tonne here, half a tonne there.” That’s because with more than two or three customers per liquefaction train, “the logistics become impossible.”
Smaller projects with smaller offtake agreements will not experience the same difficulty. Chandra identified several projects which may fit into this category, including Jordan Cove LNG, Magnolia LNG, Annova LNG, and his own project, Texas LNG.
In the opening address to the second day, chairman David Ledesma identified Coral FLNG as another project with a promising approach to securing project financing. “The commercial offtake structure was simplified as much as possible to balance against the other project risks,” he said. “Yes value was left on the table, but the project got to financial close.”
The path to commoditisation is a long one
Each of factors described so far – the expansion of the Chinese market for natural gas, the growing importance of climate change as a driver of LNG demand, and the new challenges involved with cost management and project financing – describes a facet of the LNG industry that has undergone significant change since the previous LNG supply cycle. With the advent of destination free, hub-indexed US LNG cargoes, commoditisation has also gathered pace since the last round of FIDs. But the lasting impression from the debate at LNGgc was of how much remains to be achieved before the LNG market attains the same level of regional coherence, pricing transparency and market liquidity as a true commodity like oil.
In fact, the direction of travel is not all forward. Peter Fraser of the IEA pointed out that the share of destination free cargoes fell in 2017, with buyers waiving the right to re-export in favour of satisfying domestic demand. Should the market tighten five years from now, this trend is likely to be reinforced.
Part of the problem with the expectations surrounding LNG as a commodity is that it will never be fully comparable with a commodity like oil. Carmen Lopez-Contrerras from Repsol, told attendees that “I think we tend to forget that LNG is a transportation method [rather than a fuel], and as such we don’t yet have a set price.”
Another issue is the difficulty of developing liquidity in the Asian market. Patrick Dugas, Head of LNG Trading at Total, drew attention to the liquidity of the region’s leading pricing benchmark, Platts JKM. The churn rate for the benchmark, which describes the number of times a cargo is resold after the initial purchase, is less than 1, Dugas said. “A market is liquid once the churn rate reaches at least 10,” he added. Asia still has some way to go before it can be considered a truly liquid market.
The key question must always be what can be done to promote liquidity in global LNG markets. One of the main challenges is creating greater pricing transparency, particularly in Asia. “In the end, trading is only going to be efficient when we know the final destination price that was paid,” Chandra told attendees. Without this kind of transparency, the churn rate is destined to remain lower than that of a truly liquid market.
Greater transparency should also help to encourage the involvement of other market players. “the key-word is third-party access,” Dugas told the conference. Making it easier for international players to trade LNG volumes in the Asia-Pacific region would help to more closely integrate Asia with the North American and European trading hubs.
Nonetheless, focusing on abstractions such as pricing transparency and third-party access without ensuring that the fundamentals are in place is unlikely to achieve the desired effect. In Rudolph Huber’s opinion, infrastructure will always be the key issue. “Third-party access is certainly a step in the right direction, I just doubt that it will be enough to break Asia open. Asia’s problems are physical, they’re not contractual,” he told the conference. “If we take Japan as an example, it’s virtually impossible to move a molecule from one end of the country to the other using the pipeline network – and there’s no storage to speak of.”