U.S. LNG export terminals are running at their operationally available and contracted levels and will continue to do so, with no economically driven cargo cancellations anywhere on the horizon. Global gas prices are well supported by low storage levels in Europe, and it will take time to refill inventories, which means these high prices are not going away anytime soon. The upshot: U.S. LNG will have a very different kind of summer than it did last year, when global prices were at historic lows and many U.S. terminals saw more cargo cancellations than exports. Feedgas in April this year averaged 10.77 Bcf/d, nearly 3 Bcf/d higher than last year, and as we progress into summer, the year-on-year delta will become even more pronounced. Barring any major operational issues, feedgas demand will stay around 11 Bcf/d, which is the level needed for the terminals to produce at full capacity. That’s in stark contrast to last summer, when feedgas demand cratered and averaged as low as 3.34 Bcf/d in July as cargo cancellations peaked. Today, we look at what’s supporting global gas prices, how that impacts export economics for U.S. LNG, and what that means for feedgas demand in the months ahead.
At this time last year, the U.S. LNG export market was on the cusp of virtually grinding to a halt as the pandemic triggered nationwide lockdowns around the world, closing ports, and crushing energy consumption. The resulting demand destruction and severe supply imbalance sent natural gas and LNG prices in Europe and Asia to record lows. International price spreads for LNG collapsed to well below the marginal cost of U.S. exports for the entire summer. The upside-down economics led to mass cargo cancellations, solidifying the U.S.’s role as a marginal LNG supplier in the global market. Further, all this was happening through much of the natural gas injection season (April through October), compounding the supply glut in the U.S. and amplifying the domestic market’s seasonality (see An LNG Market for All Seasons). It didn’t take long for the LNG market to flip again, however, once the lockdowns eased and demand began to recover. The global balance swung from oversupplied to undersupplied as cargo cancellations subsided last fall, and a tighter balance has persisted since then.
A look at global prices illustrates just how much the market changed in a relatively short time. Figure 1 plots historical CME/NYMEX futures prices for Asia’s LNG benchmark Japan-Korea Marker (JKM; orange line), Europe’s Dutch Title Transfer Facility (TTF; yellow line), and UK National Balancing Point (NBP; gray line) gas indices, and the U.S. benchmark Henry Hub (blue line). The takeaway is that international prices went from a lofty $8-$12/MMBtu in 2018 — $6-$10/MMBtu above Henry Hub — to converging across the board with Henry Hub near $2/MMBtu in 2020 and then, within a matter of months, not only staging a full recovery to pre-pandemic levels but also surpassed them. The July 2020 JKM contract expired barely above $2/MMBtu. Contrast that with the February 2021 prompt contract, which had a single-day close as high as $19.70/MMBtu and expired above $18/MMBtu. The prompt TTF contract also rallied beyond its 2018 high to above $10/MMBtu by January 2021, and NBP wasn’t too far behind.
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