Energy traders are betting the experts are getting it wrong on natural gas.
While oil careened toward a bear market in November, methane traded on Nymex has been on a tear: It gained 16 percent so far this month, with front-month futures hitting their highest level since 2016 on Friday at $3.82 per million British thermal units, or mmbtu.
Hedge funds reckon the rally isn’t over: Their net long position in futures and options last Tuesday was 242,841 contracts, only a sliver down from the record 251,690 contracts. The short component of that positioning is looking particularly thin, at just 71,503 contracts. Barring its dip over the past month, that’s the weakest short bet in more than a decade.
What’s strange about this is that non-market experts aren’t seeing it. To be sure, natural gas storage levels are looking low — at 3.2 trillion cubic feet they’re the smallest, for this time of year, since 2003, according to the U.S. Energy Information Administration. Still, production of 87.5 billion cubic feet a day last week is surging, up more than 10bcfd from a year earlier.
The EIA expects prices to average $2.98/mmbtu through 2019, about 22 percent below current levels. Gas pricing is highly seasonal, but even compared to the EIA’s $3.20/mmbtu forecast for the October-March winter heating season, current and past futures prices are some 7.4 percent above estimates — and the managed money funds are betting we’re heading higher.
It’s not obvious what the government analysts are missing. LNG exports have certainly become a bigger issue as China’s own winter heating gas demands have risen and the U.S. has opened liquefaction plants in Louisiana and Maryland. That doesn’t explain things for this winter, though — existing plants are already running at close to full tilt.
Four other terminals totaling 6 bcfd are due to open next year, but first cargoes at most of those aren’t due to go out until spring, and LNG facilities take a while to ramp up to full capacity. At best, they’ll take an extra 1.33 bcfd off the domestic market over the March quarter, analysts estimate.
It’s a similar issue with pipeline exports to Mexico. At present they’re already running close to capacity, according to Bloomberg New Energy Finance, so they can’t suck out much more than they’re already doing. Sempra Energy’s undersea Sur de Texas-Tuxpan pipe will start building up to a 2.6 bcfd draw at some point before the end of the year, but on its own that’s a relatively small change.
Meanwhile, the bulk of additional natural gas demand in recent years has come not from exports but from industrial and utility users that have been switching away from coal — and their activities, too, tend to be relatively predictable. Both use about 22 billion cubic feet a day during the coldest months in December and January, when power generators ease back consumption to make way for residential users while the industrial sector ticks up marginally. The latest forecasts for winter weather suggest that, if anything, the coming few months are likely to be a bit warmer than average.
Implied volatility derived from options pricing is at a three-year high, so there’s still a great deal of uncertainty out there. Natural gas futures prices tend to drop off a cliff between January and May, and we’re just two weeks out from the rollover of the December contract. At least we won’t have to wait long to find out who’s right.