Today’s report (week ended 17 May): EIA net change: +100 bcf, EA: +104 bcf
- To align with today’s print, we downwardly adjusted production by 0.2 bcf/d and increased the last vestiges of res-com demand by 0.4 bcf/d.
Next Thursday’s report (week ending 24 May): EA preliminary: +99 bcf
- A 2.8 bcf/d surge in gas into power w/w nearly offsets a 2.5 bcf/d w/w decrease in res-com demand. A nearly 0.3 bcf/d w/w decline in production is offset by a 0.3 bcf/d gain in net Canadian trade, leaving the injection level more or less flat w/w.
Global gas glut
Freeport LNG T1 and Cameron LNG T1 have been taking in feedgas steadily in the past few days, so some delay risk has started to dissipate regarding the LNG projects due online this injection season. However, the Henry Hub-TTF and Henry Hub-JKM arbs for summer 2019 are narrowing, although still open. We foresee a risk of further narrowing in arbs as Europe has made little progress in reducing its massive y/y storage surplus, which is around 830 bcf (23.6 bcm) currently. That overhang must drop to 420 bcf by end-October for European inventories to be within the bounds of physical capacity.
The concern over that potential oversupply is manifesting itself in the TTF. European prices have taken a step down this week, with only 35 bcf of that overhang having been worked off w/w. The TTF is trading near $4.15/mmbtu (€12.65/MWh), which means it is near the level at which a very efficient coal-fired plant could be displaced by an 8 mmbtu/MWh heat rate gas unit, which would imply nearly all coal-fired generation in Europe is uneconomic.
While low gas prices below that fuel switching trigger should drive more coal-to-gas switching, there are several factors that could limit some switching as well. First, coal has met some support around $60/t and carbon has been fairly rangebound, trading between $26.8-31.30/t. Moving forward, the key issue for pricing is if storage concerns become dire enough to drive gas prices toward the coal parity price trigger, which is currently at $3.70/mmbtu (€11.1/MWh). At that point, gas burn in the European power sector would be maximised if there is sufficient power demand and depending on the amount of non-fossil fuel generation in the system. We estimate that total incremental demand in summer 2019 from the power sector could be 1.8 bcf/d.
That $3.70/mmbtu is a fairly significant level given that it is below the current breakeven to ship cargoes from the US to Europe at current freight rates. We expect freight rates to move higher as the injection season progresses and think there is a very real chance that Henry Hub near-curve prices could see a modest rise in sympathy with cash prices whenever deep cooling load takes hold in the US. A potential closing of the arb to Europe is possible late this injection season, though not our reference case. However, if cargoes have been hedged, they will be lifted. Those that have not been hedged run the risk of not being lifted, which risks Henry Hub prices moving back down. Though the ultimate amount of rejected cargoes could be minimal, the threat of them being left in the US (as natural gas) as the forward arbitrage windows close could be enough to shift US prices down to pry that arbitrage window open again. While a race to the bottom could ensue, those lower Henry Hub prices would drive more demand either by keeping the export arbitrage window open or by pushing more gas into the US power sector.
Still, at current prices, the arb to Europe remains open by a margin of nearly $0.50/mmbtu. Given the notice period to lift cargoes at Cheniere facilities (it is already past the 20th day of the calendar month), decisions made today are only going to impact August loadings. Currently, there is steep contango in the TTF market, with the M+1 and M+2 contracts at a discount to Aug-19 to Oct-19 as the late injection season is pricing in winter risk including whether Russia will be able to contractually flow gas through Ukraine in Q1 20.
Not to be outdone, the JKM has fallen in price substantially as well. We believe that a JKM-TTF spread below $0.60/mmbtu will be needed this summer to make Europe the main destination for US-sourced cargoes. Yesterday, the JKM-TTF spread fell below $0.60/mmbtu.
To be fair, these calculations make some assumptions about what is a fixed cost and what is a variable cost. Much LNG trade is conducted with vessels that are under long-term charter, so that cost is not variable and requires a narrower Henry Hub to TTF or JKM spread for a trade to be economically attractive. In other words, the arbitrage window is not one-size-fits-all. The same is true for regasification capacity—the costs may not be considered variable.
While the Henry Hub open interest has picked up modestly since last winter, TTF futures on ICE have seen a marked uptick in aggregate open interest, confirming the rising exposure of the global gas trade to the European benchmark (see Fig 2).
|Fig 1: Henry Hub LNG netbacks, $/mmbtu||Fig 2: US, Europe gas futures open interest, lots|
|Source: Refinitiv, Energy Aspects||Source: Bloomberg, Energy Aspects|
|Fig 3: TTF injection season curve, $/mmbtu||Fig 4: Weekly EIA storage change, bcf|
|Source: Refinitiv, Energy Aspects||Source: EIA, Energy Aspects|