Natural Gas Storage and Downside Risks

It’s natural gas producers’ turn in the barrel. Natural gas prices are falling to historic lows amid higher-than-expected storage builds, but downside risks are severe and perhaps underappreciated. Domestic demand for natural gas has been crushed by COVID, and LNG exports are out of the money until September – and possibly beyond. Moreover, additional natural gas supply may be coming online as $40/barrel oil prices tempt Permian producers to increase oil output – and ramp up associated natural gas production. Natural gas storage levels could soon start to bump up against regional or even national capacity constraints, further pressuring prices and giving even more heartburn for the U.S. oil and gas complex.

U.S. storage levels are rising rapidly

Natural gas consumption is highly seasonal, peaking in the winter, decreasing in the spring, rebounding in the summer for power load (but not, typically, to winter levels), and moderating in the fall – at which point the cycle starts over again. Injections to inventories occur in the “shoulder months” of the fall and spring, with storage drawdowns occurring in the winter (and, depending on the location, in the summer).

Inventories for most commodities have risen amid the COVID-19 coronavirus, and natural gas is no different. Natural gas demand is down sharply on physical distancing, lockdowns, lower industrial consumption, and, of course, moderating temperatures. Supply has also fallen, but not by a countervailing amount, and U.S. natural gas inventories are rising rapidly.

It’s no coincidence that natural gas regional inventories are rising fastest in the U.S. South Central Region (which includes the major gas-producing states of Texas, Louisiana, Oklahoma, along with five other states). This region includes 4 out of the 6 currently operating LNG export terminals (and about 90% of existing nameplate capacity), so it is disproportionately affected by LNG exports. With LNG exports down, feedgas volumes are lower and… more volumes are flowing into regional storage.

Still, note that the pace of injections into storage along the Gulf Coast has slowed, at least for now. We expect that this is attributable to higher-than-average temperatures, not a fundamental rebalancing of supply and demand. Indeed, if associated gas production from the Permian rises later this year, the region may not be able to absorb the supply on its own.

Storage max-out: European LNG demand to the rescue?

A growing gas glut could prove tricky. The EIA reports “demonstrated peak capacity” storage from the entire United States of about 4,261 Billion cubic feet (Bcf), while the South Central region can hold about 1,429 Bcf. Due to the supply and demand trends discussed above, however, U.S. natural gas storage is at risk of a capacity max-out, perhaps especially in the South Central Region. In the near-term, max-out is largely dependent on two demand factors: 1) summer temperatures and 2) recovery in LNG exports. Warmer-than-average summer temperatures in the U.S. (particularly in the South) would support natural gas demand; recent forecasts seem to support higher gas burn. Similarly, increasing feed gas demand for LNG exports could slow U.S.-level and regional builds. Still, European demand for U.S. LNG may be limited due to elevated natural gas storage levels on the continent, therefore U.S. will have to look to Asia and S. America as viable LNG markets in 2H 2020.

Don’t count on LNG exports to Europe saving Henry Hub

European natural gas storage already exceeds 5-year averages, but let’s be clear: there are two severe downside risks to European demand. The first major risk is – stop us if you’ve heard this before – COVID. Europe appears to have tamed the virus for now, but most epidemiologists believe cases could surge again during flu season. The second major risk is that Europe may experience another unseasonably warm winter. Winter 2019/2020 was Europe’s hottest on record, and most scientists and forecasters believe the continent will be in for another warm winter, limiting its demand for LNG. Forward curves indicate that U.S. LNG export cargoes will be in the money as soon as October, but we’re hearing from our market contacts that they remain very mindful of downside risks.

If TTF and JKM prices don’t rise as much as expected, LNG cargo cancellations could continue, pressuring U.S. natural gas inventories, particularly in the South Central Region. The Henry Hub futures curve is in contango, indicating more optimism about future expected spot prices. That optimism could be rewarded, but we also see plenty of reasons to be concerned about a gas storage max-out.