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July contract settles at $1.482/MMBtu

EIA reports 120 Bcf injection, largest in 14 months

US LNG feedgas averages 4.1 Bcf/d in June

New York — NYMEX prompt-month Henry Hub futures prices plunged to a 25-year low on June 25 as rising gas storage inventories and pandemic-related demand weakness continue to weigh on the market.

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In early trading, the NYMEX contract dipped 11.5 cents to around $1.48/MMBtu after the US Energy Information Administration reported a massive 120 Bcf injection to gas storage – the largest one-week addition to stocks in nearly 14 months, EIA data shows.

At market close, the NYMEX July contract settled at $1.482/MMBtu, according to S&P Global Platts data.

"If you were looking for a dead cat bounce, we got more of a dead cat splat," said Phil Flynn, Price Futures Group senior market analyst. "Everyone was hoping we'd get a bottom, but the injection number is too overwhelming to ignore. Those holding hope that we'd see some sort of recovery are throwing in the towel [now]," he said.

In the cash market, prices across the Southeast and Texas Gulf Coasts also came renewed pressure on June 25. In morning trading, spot Henry Hub fell 9 cents to $1.49/MMBtu. In east Texas, Houston Ship Channel hub tumbled nearly 16 cents to trade at $1.41/MMBtu – its lowest in 21 years, S&P Global Platts data shows.

Gulf Coast supply pressure

Weakening gas prices along the US Gulf Coast come as the region grapples with mounting supply.

Since early April, US LNG feedgas demand has declined from record highs at over 9.6 Bcf/d to an average 4.1 Bcf/d in June, led by steep declines at Freeport LNG and at Cheniere Energy's Sabine Pass and Corpus Christi terminals, data compiled by S&P Global Platts Analytics shows.

Earlier this week, market sources told S&P Global Platts that another 40 cargoes previously scheduled for August lifting had been cancelled by offtakers – likely extending the weakness in feedgas demand through the remaining summer months.

Much of the growing surplus has, and will continue to make its way into storage. On June 25, the EIA reported a 39 Bcf addition to South Central storage, lifting regional stocks to an estimated 1.212 Tcf.

Over the past 10 years, South Central storage inventories have reached their highest at 1.37 Tcf – likely an approximate reflection of regional capacity. Assuming underground storage and salt domes across the Gulf Coast states could fill to 1.4 Tcf, the region would still have less than 190 Bcf in remaining capacity before inventories reach tank top.

Beginning in July, stronger seasonal demand across the Gulf Coast has historically prompted modest inventory drawdowns through early September when stocks typically begin rising again.

Over the balance of 2020, though, even five-year average storage activity – including modest summer withdrawals – would see South Central levels surpass their prior record high by mid-October.

Regional production

Adding further bearishness to the outlook for summer gas prices, oil and gas producers across numerpis US shale plays appear to be hitting the brakes on recent production curtailments.

"Some of the more recent numbers in the Permian is daunting," said Art Gelber, president of Gelber & Associates in Houston. "We thought there would be more cuts to oil production [there]," he said.

Over the past two weeks, Permian Basin gas production has averaged nearly 10.9 Bcf/d, up from a 16-month low at just 9.8 Bcf/d on May 20, Platts Analytics data shows.

Operators in other basins, that typically supply the Gulf Coast market – like Appalachia and the SCOOP/STACK, have also announced plans to resume production at previously shut-in wells.

On June 18, Continental Resources said that it would resume over 50% of its previously curtailed oil production in July, likely boosting associated gas production in the Bakken and SCOOP/STACK.

The US' largest gas producer, EQT, is also likely to resume at least some of its previously curtailed output next month, potentially bringing some 1.4 Bcf/d in Appalachian production back online.