Natural Gas Market Summary

The natural gas market has seen notable fluctuations, with Henry Hub’s prompt-month futures climbing to approximately $1.70 per MMBtu and expectations of an increase to over $2.00 per MMBtu from June to November, as indicated by data from CME. This period has been characterized by a dynamic interplay of factors including variable spot prices across the United States, with Northern California witnessing the highest at $2.37. The weather forecast by NOAA anticipates colder than normal temperatures across the East Coast, affecting the demand and consumption patterns. The Energy Information Administration (EIA) reports a decrease in demand across all sectors, notably in the residential and commercial sectors, amidst a backdrop of warmer weather conditions. Production levels remain robust despite slight decreases and strategic production curtailments by major producers in response to price trends. The LNG market is adjusting, with a slight decrease in deliveries to export terminals and strategic moves like Venture Global LNG’s acquisition of transport vessels to meet global demand, underscoring the industry’s adaptability amidst geopolitical pressures to reduce reliance on Russian LNG. Storage levels are high, reflecting the mild winter and efficient storage management, while the rig count indicates a decrease in drilling activities. These dynamics paint a complex picture of the natural gas market, influenced by environmental conditions, demand fluctuations, strategic industry responses, and broader geopolitical factors.

Reported Prices

Prompt-month futures reported out of Henry Hub rose to roughly $1.70 per MMBtu as of March 20, and have increased above $2.00 per MMBtu for futures between June and October of this year. Spot prices are variable across the country, with the highest spot price of $2.37 out of Northern California.

Weather

NOAA expects colder than normal temperatures to descend from Canada across the East Coast, delaying consistent Spring temperatures by a few days. NOAA anticipates the colder temperatures to persist through the weekend before abating slightly for the last full week of March. The weather in the U.S. was roughly 38 percent warmer than last year and 26 percent warmer than normal as measured by heating degree days. The weather in the month of February was nine percent warmer than last year and sixteen percent warmer than normal.  

Demand

Demand declined across all sectors, as reported by the Energy Information Administration (EIA). Total U.S. consumption dropped 1.7 Bcf per day from 81 to 79.3 Bcf per day week-over-week. The 79.3 Bcf per day in demand for the week ending March 13 is a 13.1 Bcf per day decline in demand from one year ago. The largest decline week-over-week was from the residential and commercial sectors, which saw a 1.1 Bcf per day decline from 27.1 to 26 Bcf per day for the week ending March 13. The two percent week-over-week decline in demand coincides with an overall increase in temperatures across the country last week, and the subsequent drop in heating demand. As the conclusion of March approaches, it brings the end of the 2023 – 2024 winter heating season. Taking a comparative view of the 2023–2024 winter to the 2022–2023 winter, average demand for the residential and commercial sectors and the industrial sector has dropped. This preliminary data from S&P Global Commodity Insights indicates the average daily demand for the residential and commercial sectors for November of 2022 through March 2023 was 36 Bcf per day, while the average daily demand for November2023 through March 19 2024 is roughly 35 Bcf per day. Although there is still one week left in the month, and thus one week left in the 2023 – 2024 winter heating season, we can see on average that demand has dropped 1 Bcf per day for the residential and commercial sectors season over season. Preliminary data from S&P Global Commodity Insights also shows demand for the Industrial sectors remained unchanged season over season with an average daily use of 24 Bcf per day. The power generation sector is where the average daily demand flips. The average daily demand for power generation was roughly 31 Bcf per day for the 2022 – 2023 winter heating season, while the average daily demand thus far for the 2023 – 2024 winter heating season is 32 Bcf per day. The 2 Bcf per day increase in demand for power generation season over season indicates an increased reliance on natural gas for power generation given the relatively mild winter heating season throughout the U.S.

Production

Production remains above 100 Bcf per day week-over-week as the average production was 101.6 Bcf per day for the week ending March 13, only 0.3 Bcf per day lower than the week prior. Reuters reported in early March that EQT, the top U.S. natural gas producer, will curtail roughly one Bcf per day of natural gas production through the end of the month as a response to the consistently low prompt-month futures. Additionally, on March 12 Reuters reported that CNX Resources will delay well completion on 11 wells in the Marcellus Shale as a response to the EQT announcement. This pause on well completion could be seen as a direct reaction to the slow down in production announced by EQT as producers begin to react to consistently low natural gas prices and the market begins balance. The EIA’s March 18 release of the Drilling Productivity Report is somewhat reflective of this announcement as EIA’s projections forecast a month-over-month decline in production from five of the seven production regions, with the highest declines occurring in the Hayneville and Appalachia, which are marginally offset by increases in the Permian and Bakken regions. Taking a retrospective look, the March 13 release of the EIA’s Today in Energy expounds on how winter storms Uri, Elliott, and Heather have interrupted weekly U.S. natural gas production by more than 15 Bcf per day. The EIA analysis indicates all three winter storms had the largest impact on the Permian Basin production as some of the infrastructure is not weatherized. As a result of the declines in production during winter storms Uri and Elliott, the Railroad Commission of Texas approved Texas’s first weatherization rule to protect natural gas flows to power generators during weather emergencies. The creation of this weatherization rule to protect natural gas flows to power generators could create an interesting dynamic on prioritizing natural gas to power generators over other end uses.

Pipeline Imports and Exports

The EIA reports a marginal increase of roughly 0.1 Bcf per day in pipeline imports from Canada, a 2.1 percent change, week-over-week for the week ending March 13. While imports from Canada increased, pipeline exports to Mexico declined 0.1 Bcf per day from 6.4 to 6.3 Bcf per day for the same report week.

LNG Markets

The EIA Natural Gas Weekly Update reports the average natural gas deliveries to U.S. LNG export terminals declined 1.3 percent week-over-week from an average of 13.5 Bcf per day to 13.3 Bcf per day for the week ending March 13. Twenty-six LNG vessels with a combined carrying capacity of 94 Bcf departed the U.S. between March 7 and March 13. Reuters reports Venture Global LNG will be acquiring a fleet of nine LNG transport vessels to expand their ability to meet projected LNG demand across the globe. The nine transport vessels will be the first vessels owned by Venture Global as all previous transport vessels were owned by other companies and leased for use. The first of the nine transport vessels is anticipated to be delivered later this year. This purchase announcement by Venture Global LNG came one day after a Bloomberg article unpacks comments from European Commissioner for Energy Kadri Simson stating that the European Union must continue efforts to cut purchases of Russian LNG for the remainder of 2024. Kadri is quoted expounding the importance of U.S. supplies: “In the EU, we are progressively building up pressure on European players to reduce Russian LNG purchases, and here again confidence in US supplies is important”.

Working Gas in Underground Storage

The Energy Information Administration Natural Gas Storage Dashboard reports a marginal decrease of 9 Bcf to storage stocks for the week ending March 8. The withdrawal places underground storage stocks at roughly 2,325 Bcf which is 17 percent higher year-over-year and 37 percent higher than the five-year average. As the conclusion of the winter heating season approaches, underground storage capacity across the country is, on average, 57 percent full, reflecting the strong injection season leading up to this winter, and the subsequent mild winter heating season. The above-average storage levels are also reflective of the 24 percent lower rate of withdrawal this winter heating season compared to the five-year average.

Rig Count

Baker Hughes reports 629 rigs for the week ending March 15, a decline of 125 from the 754 active rigs one year ago. As of March 15, 116 rigs were gas-directed and 510 were oil-directed.

For questions please contact Juan Alvarado | jalvarado@aga.org or Morgan Hoy | mhoy@aga.org

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