Natural Gas

Prices: The front-month natural gas futures contract for delivery at the Henry Hub settled at $8.12 per million British thermal units (MMBtu) on August 4, up $2.39/MMBtu from July 1, 2022 (Figure 9). The average price for front-month natural gas futures contracts in July was $7.19/MMBtu, down 41 cents/MMBtu from June’s average of $7.60/MMBtu when the front-month natural gas futures price topped $9.00/MMBtu on two days.

Natural gas injections into storage in June were 2% higher than the five-year (2017–2021) average. That trend reversed in July as 10% less natural gas was injected into storage than the five-year average. We estimate that storage inventories ended July at 2,493 billion cubic feet (Bcf), 12% less than the five-year average level.

The front-month Henry Hub futures price fell from $9.29/MMBtu on June 7, the day before the outage at Freeport LNG, to $5.42/MMBtu on June 30, likely because of market anticipation that the decrease in natural gas available for export would lead to an increase in natural gas supply available in the U.S. market. With more natural gas supply available, market participants may have anticipated more natural gas injections into storage. However, higher-than-normal temperatures in July increased consumption of natural gas for electric power generation to meet air-conditioning demand. We estimate that an average of 41.8 billion cubic feet per day (Bcf/d) of natural gas was consumed in the electric power sector during July, 2.2 Bcf/d more than the five-year average and 5.0 Bcf/d more than in June. At the same time, we estimate that dry natural gas production averaged 96.4 Bcf/d in July, down 0.6 Bcf/d from June.

Summer space cooling: During May, June, and July, the United States experienced 800 cumulative cooling degree days (CDD), or 69 (9%) more than the prior 10-year (2011–2020) average (Figure 10), and the most CDDs for this time period since 2018. Higher-than-normal temperatures led to more consumption of natural gas for electric power generation to meet air-conditioning demand. We estimate that natural gas consumption in the electric power sector averaged 36.2 Bcf/d from May through July, 2.1 Bcf/d more than the same time period in 2021 and 3.4 Bcf/d more than the five-year average. The strong demand has led to lower-than-average injections into natural gas storage for three of the four months so far during this injection season (April–October) and has contributed to the deficit in the storage inventory compared with the five-year average. The sustained lower-than-average storage inventories have put upward pressure on the Henry Hub spot natural gas price.

Natural gas share of electricity generation: In recent years, the electric power sector substituted natural gas-fired generation with coal-fired generation when natural gas prices rose. However, in recent months, coal power plants have responded less to price than in the past, most likely as a result of continued coal capacity retirements, constraints in fuel delivery to coal plants, and lower-than-average stocks at coal plants. Additionally, growth in electricity generation capacity from renewable sources is limiting the dispatch of both coal and natural gas. The Henry Hub spot natural gas price has remained elevated since the beginning of the year, but natural gas has maintained a more than 60% share of fossil-fuel sourced electricity generation (Figure 11). The Henry Hub spot price increased $3.76/MMBtu from January to May, but the natural gas share of fossil-fuel sourced electricity generation also increased from 60% in January to 67% in May despite the higher fuel cost.