Natural Gas Market Indicators – February 1, 2023
Market Summary
- EIA reports a 6.2 Bcf per day week over week increase in natural gas consumption, the largest driver being the residential and commercial sectors.
- On January 31 prompt-month future prices at the TTF dropped to $17.76 per MMBtu and to $19.49 at the JKM. These are the lowest prompt-month future prices since December 7, 2021, two months prior to Russia’s invasion of Ukraine.
- As of January 20, storage stocks for the lower 48 are 107 Bcf higher than year-ago levels, and 128 Bcf higher than the five-year average.
- According to the EIA, proved reserves of U.S. natural gas increased 32% to a record 625.4 trillion cubic feet in 2021.
Weather
Cold temperatures have settled over most of the U.S., with lows in large parts of the Midwest dropping as low as the negative teens on January 31. Over the first weekend in February a cold front is expected to descend from Canada bringing even more icy temperatures to the upper Midwest and the Northeast. NOAA’s 16-day forecast predicts the colder temperatures will push into the Northeast, before marginally warmer temperatures settle across most of the country towards the end of the first full week of February. For the week ending January 28, the weather in the U.S. was 18.5 percent warmer than last year and 9 percent warmer than normal as measured by heating degree days. All regions experienced warmer temperatures than last year except the Mountain and Pacific regions.
Demand
EIA’s Natural Gas Weekly Update reported a 6.2 Bcf per day increase in U.S. consumption from 93.4 Bcf per day to 99.6 Bcf per day for the week ending January 25. The increase in consumption was primarily driven by a week-over-week increase in demand in the residential and commercial sectors of 4.4 Bcf per day. Power generation demand accounted for 1.4 Bcf per day increase in demand.
Production
Proved reserves of U.S. natural gas increased 32% to a record 625.4 trillion cubic feet in 2021, according to the Energy Information Administration. Proved reserves represent estimates of the volume of natural gas that can be recovered in future years from known reservoirs under existing economic and operating conditions. The EIA and PointLogic report dry production fell by 0.5 Bcf per day from 100.5 to 100 Bcf per day for the week ending January 25. The last week of January has seen additional production cuts due to the extreme cold weather across the US. The Drilling Productivity Report released by the EIA on January 17 reported gas production estimates for January and February; the top three producing regions being the Appalachia, Permian, and Haynesville. EIA anticipates the Appalachia region to produce roughly 35.3 Bcf per day in January and 35.4 Bcf per day in February, and the Permian to produce an average of 21.6 Bcf per day in January and 21.7 Bcf per day in February. The Haynesville region is expected to produce 16.4 Bcf per day in January and 16.6 in February. S&P Global reports Texas set a new national record for gas production in 2022 of roughly 30.7 Bcf per day from State wells. Although Texas holds the new national record for production, the Appalachian Basin states of Pennsylvania, Ohio, and West Virginia collectively produced 34 Bcf per day in 2022.
Pipeline Imports and Exports
According to PointLogic, imports from Canada dropped 0.1 Bcf per day week over week from to 5.2 Bcf per day. The decrease in imports is also down 2.0 Bcf per day from year ago levels. Exports to Mexico remained unchanged week over week at 5.5 Bcf per day while decreasing 0.3 Bcf per day from an average of 5.8 one year ago.
LNG Markets
The Natural Gas Weekly Update released by the EIA reported overall natural gas deliveries to LNG export terminals increased 1% from 12.4 Bcf per day to 12.5 Bcf per day, accounting for a 0.1 Bcf per day week over week increase. Reuters reported on January 26 that the Freeport LNG terminal in Texas received approval from the Federal Energy Regulatory Commission (FERC) and the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) to begin cooling down some of the plant’s piping systems. The cooling process is the first step in bringing Freeport fully back online, however Freeport will have to receive additional authorization from FERC to reinstate service to the liquefaction trains, which means that Freeport is likely several weeks away from reinstating full capacity. The Department of Energy reported an increase in the sale and purchase agreements (SPA) in 2022, totaling roughly 6.0 Bcf per day or LNG. These agreements are contracts for a firm amount of LNG over a fixed period of longevity which outline specific terms of transfer between the seller and buyer. The 6.0 Bcf per day of LNG will be exported from eight projects. Corpus Christi Stage 3 and Plaquemines are under construction, Delfin, Lake Charles LNG, Port Arthur Phase 1, and Rio Grande LNG are approved, and CP2 and Commonwealth LNG are proposed. DOE reports 74% of the SPAs signed with perspective projects in 2022 are for 20-year terms which begin once the project begins commercial operations; the earliest of which is 2024. Prompt-month future prices for natural gas in Europe and Asia continue to drop even as LNG export terminals continue to run at full capacity. On January 31 prompt-month future prices at the TTF dropped to $17.76 per MMBtu and to $19.49 at the JKM. These are the lowest prompt-month future prices since December 7, 2021, two months prior to Russia’s invasion of Ukraine.
Working Gas in Underground Storage
The Energy Information Administration’s weekly storage report posted a net withdrawal of 91 Bcf, pushing total working natural gas in underground storage for the lower 48 from 2,902 Bcf to 2,729 Bcf for week ending January 20. Storage stocks for the lower 48 are 107 Bcf higher than year ago levels, and 128 Bcf higher than the five-year average, a remarkable outcome given that stocks substantially lagged the five-year average for much of the second half of 2022. EIA reports the average rate of withdrawals from storage is 23% lower than the five-year average thus far in this withdrawal season (November 2022 – March 2023).
Rig Count
The total U.S. rig count remained consistent week over week with a total of 771 rigs as of January 28. Although total rig count is unchanged week over week, four oil-directed rigs closed and four gas-directed rigs began operation. Total rig count is up 161 rigs year over year.
Reported Prices
The EIA’s Weekly Storage Report forecasts natural gas prices to remain below $4.00 per MMBtu until November of 2023. EIA’s Weekly Natural Gas Update reported regional spot price changes for the week ending January 25 were mixed with decreases in pricing in the West and increases at most locations east of the Rocky Mountains. The most notable week-over-week change was the decrease of $4.76 per MMBtu from $20.08 per MMBtu to $15.32 per MMBtu on January 24 at the PG&E Citygate which had previously seen prices climb substantially. Spot prices as of January 30th remain below $3.00 per MMBtu in New York City, the Mid-Atlantic, Louisiana, and Houston. New England is trading at roughly $3.20 per MMBtu while the Midwest is trading roughly at $4.10 per MMBtu. Prompt-month futures at the Henry Hub have dropped precipitously since December 13. On February 1 prompt-month future prices at the Henry Hub were trading at around $2.57 per MMBtu, a 57 percent decrease from December 13 when the same futures were trading at around $6.00. Future prices reported out of Henry Hub remain below $3.00 through June of 2023.
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