Natural Gas Market Indicators – June 12, 2024

Natural Gas Market Summary

Heat waves in California and the Desert Southwest over the first week of June resulted in a significant spike in regional power demand, according to the EIA. While net U.S. natural gas consumption saw a modest increase of 0.3 percent for the week ending June 5, this change was balanced by a 3.5 percent decrease in residential and commercial consumption as the North experienced moderate temperatures. Still, prices have remained below historic averages over the first half of 2024 and market volatility remains low relative to 2022. Cash prices climbed from $0.86 to $1.23 MMBtu in the SoCal Border, and from $1.62 to $1.89 MMBtu in the PG&E Citygate. While impactful, these increases were smaller than impacts seen from heatwaves last year. EIA reports the price stability may be attributed to increased underground storage, which remains well above the five-year average. As of June 12, July futures prices are roughly $3.04 per MMBtu.

Reported Prices

According to EIA’s Today in Energy, natural gas prices became less volatile in 2023 compared to 2022. Historical volatility refers to short term price movements relative to the average over a set period of time. After experiencing a historical volatility of 171% in February 2022, the most since 1994, the first quarter of 2024 had an average Henry Hub front-month futures historical price volatility of 80%. While higher than the 2023 average of 69%, the price volatility is lower than the 2022 average of 91%.

Trading for July contracts opened at $2.98 per MMBtu on June 9, increasing to $3.04 per MMBtu as of June 12, as reported data from EIA and CME. On June 7, prices reached a 21 week high. Additionally, Yahoo! Finance reports that May saw a 30% price increase. According to CME, futures are expected to remain above $2.00 per MMBtu through September, then rise above $3.00 per MMBtu in October and through December of 2025.

Regionally, Western cash prices climbed during a heat wave beginning on June 4, according to EIA’s Southern California Daily Energy Report. In the SoCal Border, cash prices rose from $0.86 to $1.23 per MMBtu. Comparatively, in the August 2023 heatwave, spot prices at SoCal Border spiked from $2.46 to $3.27 per MMBtu. The decrease in cash price fluctuation given an extreme weather event breaks away from Western market trends in recent years.


For the week ending  June 8, the weather was 36.1 percent warmer than last year and 25.6 percent warmer than normal as measured by cooling degree days. New England, Middle Atlantic, Mountain, and Pacific regions all experienced a large percent increase in cooling degree days when compared to the same week last year with a 128.6, 150.0, 110.7, and 400.0 percent increase respectively. The sharp increase in the Pacific can be attributed to the heat dome that settled over California and the Desert Southwest on June 4. The heat wave experienced its peak on June 6 with temperatures in Death Valley Valley, California reaching 122 degrees Farenheit, breaking calendar day records, according to NASA.

According to NOAA’s 16 day forecast, temperatures across the U.S. are anticipated to be warmer while excessive periods of heat continue to be forecasted thoughout various regions of the US. The week of June 11 to 16 parts of the West, Southwest and East predict higher-than-normal temperatures. Some areas of the Southeast and Midwest are expected to join this trend the following week. The heat wave is a part of broader trends influenced by ongoing climate patterns and the waning of El Niño conditions. As of June 1o, there is no reported hurricane acitivity according to NOAA.


Total U.S. consumption rose 0.3 percent, or 0.2 Bcf per day week over week from 66.8 to 67.0 Bcf per day for the week ending June 5, as reported by the EIA. The small change in net U.S. consumption was a result of a 3.5 percent decrease in residential and commercial consumption (0.3 Bcf per day) offset by a 0.7 percent increase in power consumption (0.2 Bcf per day) and a 1.3 percent increase in the industrial sector (0.3 Bcf per day).

According to data from EIA, gas fired generation increased from 0.5 to 1.4 Bcf per day in California and from 0.2 to 2.1 Bcf per day in the Desert Southwest. The heat wave beginning on June 4 coincided with this increase in power consumption in California and the Desert Southwest, which created large fluctuations in regional power demand as cooling load increased.   


The EIA reports 99.7 Bcf per day in production for the week ending June 5, a 0.7 Bcf per day decrease from last week’s production of 100.4 Bcf per day. At this time last year, the natural gas production was averaging 103.1 Bcf per day, resulting in an average year-over-year decrease of 3.4 Bcf per day. According to EIA, monthly U.S. marketed natural gas production is on track for continued loss, seeing decline since February.

LNG Markets

Natural gas deliveries to U.S. LNG export terminals increased 0.2 Bcf per day from 13.0 Bcf per day to 13.2 Bcf per day for the week ending June 7, according to the EIA Natural Gas Weekly Update. Additionally, twenty-six LNG vessels with a combined LNG-carrying capacity of 94 Bcf departed the U.S. between May 30 and June 5.

International futures out of JKM and TTF experienced marginal changes for the week ending June 5. Futures out of JKM decreased $0.02 per MMBtu from $11.96 to $11.98 per MMBtu, $2.73 higher than prices year-over-year. Futures out of TTF increased $0.14 per MMBtu from $10.86 to $11.00 per MMBtu, $3.05 higher than prices year-over-year. As of February 2024, Congo Brazzaville has become an LNG exporting country according to EIA’s Today in Energy. Their first facility has a production capacity of 29 Bcf per year with a second facility producing 115 Bcf per year, scheduled to begin operations in 2025.

Working Gas in Underground Storage

There was a 98 Bcf increase in net injections into underground storage for the week ending in May 31, bringing total working stocks to 2,893 Bcf according to the EIA’s Natural Gas Storage Dashboard.  The reported underground storage levels are 25 percent, or 581 Bcf higher than the five-year average, and 14.8 percent, or 373 Bcf higher year-over-year. In the Pacific region, storage is 53 Bcf higher than the 5-year average. According to EIA’s Today in Energy, increased storage capacities help reduce exposure to price volatility.

Pipeline Imports and Exports

According to the EIA, Imports from Canada increased an average of 0.1 Bcf per day, or 1.5 percent for the week ending June 5. Additionally, exports to Mexico decreased by .2 Bcf per day, or 2.9 percent for the same week.

Rig Count

Baker Hughes reports a total of 594 rigs for the week ending June 7, a week-over-week decline of 6 rigs; four of which were oil-directed and two gas-directed.

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Natural Gas Market Indicators – June 12, 2024