Natural Gas Market Indicators – January 17, 2023

Market Summary

Weather

Winter Storm Elliott brought Blizzard conditions from West to East over the final weeks of 2022. The winter event produced wind chills in the negative 20s across the Midwest and temperatures in the single digits on the East Coast. Substantially warmer temperatures followed Winter Storm Elliott, but the increasing temperatures brought heavy rain to the West Coast. NOAA’s 16-day forecast predicts warmer temperatures on the West and East coasts while colder temperatures descend from the North to the Midwest. The second half of January will see the colder temperatures push to the East. In general, weather throughout the U.S. was 14 percent warmer than last year and roughly 21 percent warmer than normal as measured by heating degree days for the week ending January 14. All regions, except for the Pacific, experienced both warmer temperatures than last year, and all regions experienced warmer temperatures than normal. In contrast, temperatures in December were roughly 28 percent colder than normal as measured by heating degree days.

Demand

According to S&P Global Commodity Insights, on December 23, 2022, total demand including LNG exports breached 160 bcf per day, breaking the previous record of 150 bcf per day set on January 30th of 2019. The demand spike was primarily caused by Winter Storm Elliott. S&P also reported average U.S. demand was roughly 138 Bcf per day from December 20th to December 27th, setting a record for average demand over the course of a week. The Northeast saw the largest spike in demand, rising to roughly 37 Bcf per day on December 24th, a 4.2 Bcf per day increase from the previous week. Moving forward to January, the Energy Information Administration reports PointLogic data showing that over the course of the week ending January 11, natural gas demand rose roughly 14 percent, for total demand of 93.1 Bcf per day. The largest week-over-week demand increase occurred in the commercial and residential sectors as demand rose roughly 27 percent.

Production

Temperatures produced by Winter Storm Elliott caused wellhead freeze-offs which resulted in a 9.1 Bcf per day drop in production, from 96.2 Bcf to a seven-day average of 87.1 Bcf per day as reported by S&P Global. The majority of the production reduction occurred in the Northeast, Midcon, and Texas. The Northeast experienced the largest drop in production, falling from 34.6 Bcf per day the week prior to December 25th, to 24.6 Bcf per day on Christmas Day. S&P Global reports this is the lowest level of production since November 2017. Due to a week-over-week loss in production, some local distribution companies relied on storage withdrawals to help ensure customer demand was met. EIA and PointLogic report dry gas production rose 1 Bcf per day week over week from 99.2 Bcf per day to 100.2 Bcf per day for the week ending January 11.

LNG Markets

The Natural Gas Weekly Update by the EIA reported overall natural gas deliveries to LNG export terminals increased from 11.6 Bcf per day to 12.3 Bcf per day, representing a 0.7 bcf per day week over week increase. Deliveries to LNG export terminals in South Louisiana increased from 8.1 Bcf per day to 8.7 Bcf per day, a 0.6 Bcf per day week-over-week increase. Bloomberg reports prompt month futures at the Japan-Korea Marker were trading around $28 per MMBtu as of January 11, and prompt month futures at the Dutch TTF decreased roughly $1.17 per MMBtu to approximately $22 per MMBtu for the same report week.

Pipeline Imports and Exports

According to PointLogic, imports from Canada rose 1.3 Bcf per day week over week from 4.2 Bcf per day to 5.5 Bcf per day. The 5.5 Bcf per day average is still down 0.6 Bcf per day from the same time last year. Exports to Mexico increased 0.5 Bcf per day from 4.9 Bcf per day to 5.4 Bcf per day for the week ending January 11.

Underground Storage

The Energy Information Administration’s weekly storage report posted a net injection of 11 Bcf, pushing total working gas in underground storage for the lower 48 to 2,902 Bcf for week ending January 6. It is uncommon for net injections to occur outside the injection season, but the injection represents a welcome respite following large withdrawals during Winter Storm Elliot.

Rig Count

The total U.S. rig count decreased by 7, four of which were gas-directed rigs. As of January 6, 772 total rigs remain in service across the U.S. Total rig count is up 184 rigs year over year.

Reported Prices

The Energy Information Administration released a briefing on the volatility of wholesale electricity prices in 2022. The briefing outlines major events in 2022 which led to price fluctuations, beginning in January of 2022 when pipeline constraints in New England caused wholesale electricity prices to average $160/MWh for the month of January. EIA also mentions the July heatwave in Texas, and the September heat wave that affected most of the Western U.S. as sources of volatility. Record breaking demand in Texas from the July heatwave pushed wholesale electricity prices to average $182 per MWh, while wholesale electricity prices averaged $134 per MWh for the CAISO region; California’s grid operator. December continued the year of records as Winter Storm Elliott pushed wholesale electricity prices to record highs in California of $257 per MWh. The European Union energy ministers came to an agreement in late December of 2022 to cap natural gas prices at 180 euros per MWH when the TTF prompt month futures exceed the cap. Reuters reports the European energy ministers hope establishing a price cap will limit the impacts of the Russian and Ukrainian War while better preparing the entirety of Europe for the upcoming storage refill season and 2023 winter heating season. Henry Hub prompt month futures have been trading below $4.00 since January 11 following the price increases induced by the colder temperatures brought on by Winter Storm Elliott. EIA’s weekly storage report forecasts natural gas prices to remain below $4.00 per MMBtu until November of 2023.

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