Tight US gas market could test economics of LNG exports
A drop in US gas output and increased domestic demand heading into the winter has tightened the US' supply-demand balance and lifted domestic gas prices, keeping netbacks for delivering LNG to Asian and European markets tight.
Winter forward prices at the US Henry Hub have held close to record highs in recent weeks, with December-February prices averaging $3.40/mn Btu on 24 September, the highest mid-winter prices since at least late-September 2015.
Domestic gas prices set most US LNG offtakers' feedgas costs, which for Cheniere's term fob customers are 115pc of the final Nymex Henry Hub settlement for the month in which a cargo is loaded. US LNG offtakers also incur take-or-pay liquefaction fees of $2.25-3.50/mn Btu, which are likely considered sunk costs. This could test the economic viability of US LNG exports, with spot US fob prices for loading this winter having held a tight premium to feedgas costs in recent weeks.
Argus Gulf Coast fob (AGC) December-January prices were assessed between 55¢/mn Btu and 80¢/mn Btu above feedgas costs on 24 September. The differential between the AGC front-month price and the corresponding Henry Hub-linked feedgas price tightened from an average of $4.27/mn Btu in 2018 to 12¢/mn Btu so far in 2020, and was even negative for a couple of months in late spring and early summer.
The US Energy Information Administration (EIA) said in its September Short-Term Energy Outlook that it expects Henry Hub prices to average $3.47/mn Btu in December-February, which would leave feedgas costs at an average 48¢/mn Btu discount to prevailing fob prices.
Reduced gas output has supported prices at the Henry Hub, with US production at 87bn ft³/d (896bn m³/yr) on 17-23 September, down from 104.7bn ft³/d a year earlier, according to the EIA. It expects US gas production to average 86.4bn ft³/d in October-March, down from the 95.23bn ft³/d record reached a year earlier.
The US had 73 working gas rigs last week, up by two from the previous week but 75 lower than a year earlier, according to oil field services provider Baker Hughes. The number of US oil rigs, where associated gas is produced, fell even more sharply, to 179 last week from 719 a year earlier. US oil and gas producers have idled about 540 rigs since early March as efforts to contain the Covid-19 pandemic caused global demand and oil prices to plummet. The Nymex WTI front-month price of $39.50/bl on average so far in September has provided little incentive for US producers to ramp up oil production, limiting growth of associated-gas output.
With little prospect of a rebound in production growth in the near term, a rise in domestic demand could tighten the US gas market further this winter — although with US gas inventories standing 12pc above the five-year average on 18 September, according to the EIA, the country still has something of a buffer.
Measures to control the Covid-19 pandemic continue to complicate the demand outlook. But a return to more seasonal winter weather this year may drive demand higher than in the milder 2019-20 winter. The US National Oceanic and Atmospheric Administration predicted a 75pc chance that La Nina weather conditions would continue through the northern hemisphere this winter, which leads to colder weather in the northern parts of the US but milder and drier weather in the south.
US LNG exports are expected to rebound this winter, as fewer cargoes have been cancelled by offtakers for October and November loadings compared with earlier this summer. And a rebound in feedgas demand from liquefaction facilities could contribute to any tightness in the US gas market. Gas deliveries to US liquefaction plants reached 6.96bn ft³/d on 17 September, their highest since early May. Deliveries fell in the subsequent days as tropical storm Beta forced ports in Louisiana and Texas to close temporarily, but rebounded in recent days. Gas flows to the 5.75mn t/yr Cove Point facility held at zero since 21 September, when the facility started annual maintenance.
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