US loses capacity to surprise
The fourth quarter's dramatic price rise and fall is not expected to be repeated
The US benchmark Henry Hub front-month contract saw unprecedented volatility in the fourth quarter of 2018. But a combination of milder-than-average weather since November, and the prospect of production increases and infrastructure delivery in 2019, lead analysts to predict a much calmer 2019.
In fact, the main risk to prices-as-usual is seen on the downside for the summer, dependent on temperatures and hence storage withdrawals for the remainder of Q1.
The Chicago Mercantile Exchange (CME) Nymex Henry Hub front-month futures contract had been trading in a $2.65-3.30/mn Btu range from mid-April until early November, shooting higher to a peak of over $4.70/mn Btu on 28 November. The fall in December was equally precipitous, dropping back to under $2.95/mn Btu by the last day of the year.
The main driver of the November spike was colder-than-expected weather in November, exacerbated by lower-than-normal storage inventories. Gas markets tend to be more vulnerable to exaggerated price moves due to colder weather earlier or later than the peak demand season.
To incentivise November storage withdrawals, spot prices need to rise above the highest price for re-injection into store, usually the spring shoulder season, with the April contract most often seen as the best proxy. But the prospect of greater injection demand in April can then lift that contract, setting off a bull cycle.
The impact of November weather was heightened by storage stocks that were around 500bn ft³ below the five-year average going into winter—a deficit about which the market had, ironically, been relatively unconcerned. This then blew out to around 720bn ft³ on the cold snap, says Andrew Bradford, CEO of Denver-based analysis firm BTU Analytics. But, despite the dramatic rise in prompt prices, he notes that the summer '19 contracts "didn't really move", indicating that most traders felt the storage shortfall was a short-term issue and would not have longer-term implications.
"We are pretty bearish about the futures curve for summer"—Bradford, BTU Analytics
The deficit "was not much of a concern all summer, because production is now just so high", agrees Anastasia Dialynas, lead North American oil and gas analyst at Bloomberg NEF (BNEF) in New York, before the colder-than-expected conditions introduced "fear" into the market. As well as fundamentals, though, she also thinks that traders looking to unwind oil-gas spread trades in a volatile crude market exacerbated the swings in Henry Hub which, while the world's most liquid gas trading venue, is still much less deep than Nymex WTI.
Just as colder-than-expected weather drove prices higher, warmer temperatures compared to the norm in December hastened the collapse, with mild conditions from the country's most important demand centres continuing into January and its short-term forecasts. Going into 2019, daily storage withdrawals were "anaemic" compared to usual levels, says Bradford, and the inventory deficit to the five-year average had been reduced to under 465bn ft³. Based on normal weather for the remainder of the winter, BTU forecasts see the deficit close to zero by March.
Clearing the blockage
Analysts agree that output expansion in 2018 has been impressive—"2018 was the year of production growth, 2019 will be the year of debottlenecking, especially in the second half of the year," says Michael Stoppard, chief global gas strategist at consultancy IHS Markit.
According to the International Energy Agency (IEA), the US Department of Energy sees 2018 production up 10pc year-on-year with an additional 80bn m³ (equivalent to 7.7bn ft³/d) of output. BTU shares the view of a backloaded infrastructure expansion—expecting the 1.9bn ft³/d GC Express pipeline, boosting Permian evacuation capacity, and the 1.44bn ft³/d Midship route out of Oklahoma both to arrive in October.
BTU sees 2019 Permian production continuing to rise, by as much as 3bn ft³/d. But it sees other growth hotspots beginning to cool. While Appalachian supply has been seeing "several bn ft³/d increases for quite some time", incremental supply in 2019 is put in a 1-2.5bn ft³/d range, says Bradford.
But, while supply growth may be slowing, it is still likely to outstrip increases in demand should 2019 deliver normal weather. On weather-as-normal assumptions, BTU is forecasting a 500bn ft³ storage surplus by the summer, a significant swing from summer 2018's deficit. The firm sees a 1.5bn-ft³/d drop in residential and commercial demand in the absence of 2018's colder weather, and Bradford says that, based on December/January weather, it is likely to re-forecast an even sharper drop.
This drop in residential requirements is more than enough to absorb BTU's projections of a 0.3bn ft³/d increase in both power-sector and industrial demand and a 0.6bn ft³/d jump in exports to Mexico. The increasing limitation to power-sector growth is a concern for Jean-Baptiste Dubreuil, senior gas analyst at the IEA. "It is unclear how much more coal can be displaced," he says. "It used to be that gas captured 100pc of every coal retirement; that does not hold any more, wind and solar are going to capture some of it," says Bradford. New highly efficient gas-fired power plants, particularly on the East Coast and the Appalachians are also producing more electricity for less gas, introducing an element of gas-on-gas competition, he continues.
Over the horizon
With "sluggish demand" from other sources "hard to get excited about", the key role of the arrival of new LNG projects to bolster demand could hardly be clearer. The US' Energy Information Agency (EIA) in December predicted US liquefaction capacity to grow from 3.6bn ft³/d from the existing Sabine Pass trains 1-4 and Cove Point facilities to 4.9bn ft³/d by year-end 2018 with first exports from two additional plants, Sabine T5 and Corpus Christi T5, that have already begun production. The 2019 arrival of Cameron T1-3, Freeport T1-2, Elba Island and Corpus Christi T2 will further boost capacity to 8.9bn ft³/d by year-end.
While delays have affected Cameron, Freeport and Elba Island, most analysts expect these projects to materialise in 2019, indeed the previous delays largely strengthen sentiment that the most advanced projects are imminent. Cameron T3 is the main candidate seen at risk of slipping into 2020.
The key question is less about capacity growth than volume growth. The EIA predicts an average of 2.9bn ft³/d in 2018 rising to a mean 5.2bn ft³/d in 2019 as last year's arrivals ramp up and 2019 additions arrive and begin their build-up. But other analysts see this as conservative, not least because, according to BTU estimates, current LNG liquefaction demand is already running at just under 5bn ft³/d. Both BTU and BNEF foresee average 2019 LNG export requirements around the 6.5bn ft³/d mark, with the former putting the year-on-year increase at just over 3bn ft³/d.
Thus far, US LNG export facilities have run at utilisation rates of around 80-85pc, says BNEF's Dialynas. Liquefaction's role in absorbing production growth as other demand sources deliver only modest growth or under-perform makes it key to support US prices.
"A lot of the projects coming on have supply contracts behind them for a large portion of the volumes," she says, leading to expectations that high utilisation will continue. The pricing structure of sales and purchase agreements (SPAs) has become much less transparent since US independent Cheniere's early Sabine Pass SPAs which laid out the terms in relatively explicit detail. New project developers tout differentiation in pricing as "their edge", says Dialynas.
But BTU, BNEF, IHS Markit and consultancy Wood Mackenzie are all in broad agreement that the vast majority of the new contracted capacity arriving and ramping up in 2019 is based broadly on the model pioneered by Cheniere, on a fixed cost and percentage of the Henry Hub price. Discussions on other models are "in vogue, but yet to be really demonstrated" says IHS Markit's Stoppard.
The two main alternatives seen by analysts are a risk-sharing model between US upstream producers and exporters and oil indexation, although December's memorandum of understanding between trader Vitol and US project developer Tellurian for a 15-year SPA based on the Platts' east Asian JKM price introduced a third possible option.
8.9bn ft³/d - US liquefaction capacity by end-2019
In the risk-sharing model, buyers of export volumes would look to get exposure to low well-head prices in exchange for giving US producers a greater ability to benefit from higher international prices. Oil linkage is thought to be popular with certain LNG buyers with end-user demand portfolios, for the sake of familiarity if nothing else. Going forward, US LNG export contracts may be "an amalgam, a formulaic price mixing gas and oil", says Dialynas.
Assuming the first wave of LNG exports is largely on a fixed-cost-plus-Henry Hub percentage basis, the most important factor in determining the global competitiveness of US exports is whether the fixed cost is considered "sunken" and thus the short-run marginal cost within liquefaction decision making. Analysts are in unanimous agreement that, for contract lifters, the fixed fee will be regarded as equivalent to a capex cost and thus not figure in liquefaction economics. Similarly, infrastructure developers with incremental capacity will base their decision making on US sourcing costs alone.
US exports should thus be expected to maintain high utilisation rates unless European and Asian markets drop to below the price of the Henry Hub percentage—115pc in several contracts—and the transport costs to destination countries.
And IHS Markit's Stoppard suggests that, even if these regional arbitrages were compressed down to these levels, it would be surprising if there was an immediate reaction in terms of a drop-off in US exports and in liquefaction demand. "That is not how the world operates in practice," he says, citing complexities such as volumes pre-sold at levels different to the current spot prices and the fact that multiple off-takers from the same plant may have different strategies and portfolios, hampering a concerted reaction from that facility.
But the main obstacle he sees is technical, namely that the extent to which a liquefaction unit can ramp up and down is much more limited than, for example, a gas-fired power plant. There is some limited flexibility but very quickly a facility faces a decision whether to produce at or above a certain base level or switch off entirely. Given that shutting a plant in and then restarting it is a challenging, time-consuming and costly undertaking that requires a certain amount of forward planning, it is unlikely stakeholders would take such a decision lightly, based on a brief window of unfavourable spot-price economics.
It is not, though, impossible that, if the US became the swing producer in an oversupplied global LNG market, a sustained period of low international prices could see US supply switch away from liquefaction to storage injections, with the second quarter, as the softest period in global demand, offering the most potential for this scenario, says Stoppard.
Even without the prospect of a drop-off in LNG export demand, the summer quarter's price robustness is a cause for concern for BTU's Bradford. The firm's forecast for average Henry Hub price for 2019 is just above the $3/mn Btu, but "we are pretty bearish about the futures curve for summer", predicting a "tough summer for gas-focused E&P companies". IHS Markit's forecast is for sub-$3/mn Btu prices, striking a further bearish note.