|Reference||Low LNG Price||High LNG Price||Fast Builds Plus High LNG Price||2018–22 Range|
|Liquefied natural gas (LNG) exports (Bcf/d)||27.3||15.3||39.9||48.2||3.0||10.8|
|Henry Hub spot price (2022$/MMBtu)||$3.77||$3.28||$4.31||$4.81||$2.23||$6.52|
|Natural gas consumption (Bcf/d)||82.2||82.5||81.9||81.7||82.7||87.7|
|Industrial natural gas consumption, excluding lease and plant fuel (Bcf/d)||27.3||27.4||26.9||26.7||22.2||23.3|
|Electric power natural gas consumption (Bcf/d)||21.2||22.8||19.7||18.6||29.0||32.3|
|Natural gas share of electricity generation||22%||23%||20%||19%||34%||40%|
|Electric power price (2022¢/kWh)||11.0¢||11.0¢||11.1¢||11.2¢||12.1¢||12.3¢|
|Data source: U.S. Energy Information Administration, Annual Energy Outlook 2023
Note: Bcf/d=billion cubic feet per day, $/MMBtu=dollars per million British thermal units, ¢/kWh=cents per kilowatthour
LNG export facilities in the United States have a combined operating capacity under real world operating conditions of 11.4 Bcf/d with an additional 7.3 Bcf/d of capacity under construction. A further 18.3 Bcf/d of possible LNG export capacity has received full regulatory approval from the U.S. Department of Energy (DOE) and the Federal Energy Regulatory Commission (FERC) but has not yet received a final investment decision, an important step before construction can begin.
Within the model, the key determinants of LNG export volumes are international LNG prices and the rate at which new LNG export terminals can be constructed. Model results showed that higher LNG exports results in upward pressure on U.S. natural gas prices and that lower U.S. LNG exports results in downward pressure. Our projected price of U.S. natural gas at the Henry Hub in 2050 varied from $3.30 per million British thermal units (MMBtu) to $4.80/MMBtu, depending on the volume of U.S. exports in the cases we explored. In the AEO2023 Reference case, we projected a price of nearly $3.80/MMBtu, and we projected prices as high as nearly $6.40/MMBtu in the Low Oil and Gas Supply Case and as low as nearly $2.80/MMBtu in the High Oil and Gas Supply case.
Future dry natural gas production ranged from 104.1 Bcf/d in the Low LNG Price case to 134.6 Bcf/d in the Fast Builds Plus High LNG Price case, based on varying amounts of U.S. LNG exports. Natural gas production on the Gulf Coast and in the Southwest was the most affected by LNG export volumes because these producing regions are located near LNG export terminals.
We saw lesser effects on domestic natural gas consumption. Natural gas consumption in the electric power sector was the most sensitive to the varying U.S. LNG export volumes, ranging from a 7% increase in the Low LNG Price case to a 12% decrease in the Fast Builds Plus High LNG Price case compared with the Reference case in 2050. Natural gas consumption in the manufacturing sector responded slightly to natural gas price signals, ranging from a low of 26.7 Bcf/d in the Fast Builds Plus High LNG Price case to a high of 27.4 Bcf/d in the Low LNG Price case. In total, U.S. natural gas consumption changed only slightly across the cases because decreases in domestic consumption are largely offset by additional natural gas consumption required to support higher levels of LNG production and transmission. Total consumption varied from a 0.4% increase in the Low LNG Price case to a 0.8% decrease in the Fast Builds Plus High LNG Price case relative to the Reference case.
To assess how U.S. LNG exports responded to different assumptions about international LNG prices and the corresponding effects that those prices would have on the U.S. natural gas market, we developed three cases using our National Energy Modeling System (NEMS). These three cases incorporate assumptions that drive variations in the amount of LNG the United States will export through 2050.
We model U.S. energy markets explicitly in NEMS. Through 2027, the Reference case and all side cases published in AEO2023 incorporate U.S. LNG export projects that are either operating or under construction as of August 2022. After 2027, the cases run through NEMS add more U.S. LNG export capacity based on price differentials between international LNG prices and the cost of exporting LNG from the United States for delivery in Asia and Europe, along with annual constraints on the ability to build new capacity. As international LNG prices increase compared with domestic natural gas prices, U.S. LNG export capacity becomes more economical to build.
Up to the constraint on building new capacity, this price difference drives the amount of U.S. LNG that is exported within the model.2 In all cases, NEMS assumes that a maximum of 90% of baseload capacity can be utilized, which reflects real world operating conditions of LNG export facilities. The utilization of LNG export capacity might be further reduced if the regional spot price plus liquefaction, shipping, and regasification costs exceeds the LNG price in Asia or Europe.3
We developed two side cases, Low LNG Price and High LNG Price, in which we adjust assumptions in NEMS that change projected international LNG prices in Europe and Asia. These prices help determine the economics of building liquefaction facilities and exporting LNG given U.S. natural gas prices, shipping costs, and LNG prices abroad. We developed a third side case, the Fast Builds Plus High LNG Price case, which uses the same price parameters as the High LNG Price case. In addition, this case loosens the additional constraints we place in NEMS on how quickly new LNG export capacity is allowed to come online, which represents growing investments and efficiency gains in the construction of liquefaction units and allows more of these facilities to be constructed simultaneously in the model.
All three cases assume current laws and regulations, including our integration of the Inflation Reduction Act (IRA), with provisions as defined in the Appendix of the AEO2023 narrative. We use macroeconomic assumptions from S&P Global IHS Markit as of November 2022.