The Office of Electric Reliability and the Office of Energy Policy and Innovation are pleased to present a summary of the 2024 Summer Energy Market and Electric Reliability Assessment. This report reflects staff’s analyses and forecasts about energy markets and electric reliability for the upcoming summer. This presentation discusses select key findings from the report. The complete report will be posted on the Commission’s website, www.ferc.gov
This coming summer, temperatures are expected to be above normal across the U.S, resulting in additional electricity demand for cooling. The U.S. National Oceanic and Atmospheric Administration (NOAA) forecasts a 60-70% likelihood of above-normal temperatures for the months of June, July, and August in the eastern and western United States, and increased chances of above-normal temperatures for the months of July, August, and September especially in the Northwest and Southwest regions
The North American Electric Reliability Corporation (NERC) forecasts that all regions will have sufficient generating resources to meet expected summer demand and some regions may require operating mitigations under extreme summer conditions.
Total net summer generating capacity is projected to grow by 3.4% in summer 2024 to 1,207 gigawatts (GW), compared to last summer, with most additions coming from solar and wind resources and most retirements from coal resources. On the demand side, the U.S. Energy Information Administration (EIA) projects that total load will increase by 4.4% relative to summer 2023 for the continental United States.
Average wholesale electricity prices for summer 2024 in most areas of the country are expected to be close to, or slightly lower than, prices in summer 2023 because of modest declines in generation fuel costs. According to EIA, natural gas prices are expected to be lower this summer than last due to relatively high natural gas inventories, 23% greater than last year. Summer natural gas production will remain almost unchanged relative to last summer’s record levels. Consistent with previous summers, natural gas demand is expected to grow – primarily due to increased feed gas demand for LNG exports.
For this summer’s hydro conditions, the North American Drought Monitor states that roughly 39% of the United States is affected by drought or abnormally dry conditions, potentially affecting hydropower output in summer 2024. Lower levels of snowpack in the West may reduce hydropower output and may increase the reliance on natural gas for electricity generation (or power burn) in the West to meet electricity demand for air conditioning.
Weather drives summer demand for energy. Warmer temperatures in the summer typically increase the demand for electricity for cooling and natural gas for power burn to generate that electricity. Weather can also impact the supply of energy. Major weather events, such as hurricanes making landfall along the Gulf Coast, can impact the production of crude oil and natural gas, or damage electric equipment.
As shown in the figure, NOAA forecasts that temperatures this summer will be above normal for most of the United States. Additionally, several forecasting groups have issued early-season warnings of a potentially active hurricane season for 2024 given continued record-warm ocean temperatures and a shift to a La Niña weather pattern. These conditions also increase the risk of more frequent and stronger storm development, and earlier in the season.
Nationwide net summer capacity additions and retirements (measured in GW) are expected to follow recent trends in which most capacity additions have come from solar and wind resources and most retirements from coal resources. The figure shown provides a projection for September 2024 of net summer capacity, the maximum output that generating capacity can provide between June 1 through September 30, across RTOs/ISOs and other regions in the United States, along with the share of generating capacity by resource. Capacity reflected in this chart includes expected additions and retirements from the end of last summer through the end of summer 2024 as well as capacity in place before that period.
Nationwide net summer capacity is expected to increase from 1,167 GW to 1,207 GW since last summer. By the end of this summer, natural gas-fired capacity is projected to represent 42% of the capacity mix across the United States, followed by coal at 14%, wind at 13%, and solar at 10% according to EIA. Of note, battery storage capacity is expected to grow by just under 7 GW, from 5.4 GW in summer 2023 to 12.2 GW in summer 2024.
The largest resource additions expected through summer 2024 include several projects around 600 MW in capacity, including the Menifee Power Bank battery facility in CAISO, the High Banks onshore wind facility in SPP, and the Fox Squirrel Solar facility in PJM. The 1,150-MW Unit 4 reactor at the Vogtle nuclear plant in Georgia entered commercial service on April 29. Also of note, two large offshore wind plants are scheduled to come on-line this year: the 800-MW Vineyard Wind 1 off the coast of Massachusetts and the 130-MW South Fork Wind off Long Island.
I will now turn it over to my colleague Jerry Chiang.
Thank you.
Natural gas prices are expected to be lower this summer at most of the major U.S. trading hubs compared to the final settled futures prices of last summer. As of May 1, 2024, the Henry Hub futures contract prices averaged $2.25/MMBtu for this summer, down 9% from last summer’s settled average of $2.46/MMBtu. Lower futures prices at the Henry Hub for this summer appear largely driven by the warmer-than-normal 2023-24 winter and continued robust natural gas production leading to a sizable inventory surplus.
In California, -- as shown in the slide -- natural gas prices are expected to decline by more than 30%, but to remain the highest among the surveyed hubs. Prices are projected to average $3.62/MMBtu at SoCal-Citygate, which serves Southern California Gas, and $3.12/MMBtu at PG&E Citygate, which serves PG&E. The California natural gas market relies on natural gas pipeline import supplies from the Pacific Northwest, the Rockies, and the Southwest. However, California natural gas storage operators have maintained higher inventories of natural gas in storage relative to past summers, particularly in southern California, which has contributed to the lower futures prices seen on this slide. Several major regional pipelines into California have scheduled maintenance or outages that could extend into peak demand periods this summer, which may result in occasional price premiums.
Notable among other trading hubs, the natural gas price at the Waha hub in the Permian Basin is expected to decline by 47%, averaging $1.08/MMBtu, from last summer’s settled futures prices of $2.04/MMBtu. Natural gas prices are expected to increase only in the Northeast and the Mid-Atlantic albeit at less than 15%, likely reflecting modest reductions in Northeast production coupled with increased regional demand.
Next slide, please.
Summer natural gas production is forecast to average 102.3 billion cubic feet per day (Bcfd), a slight decline of 1.6% relative to last summer’s record levels.
Summer natural gas demand is forecast to increase 1.7% from summer 2023 levels, averaging 96.7 Bcfd, continuing demand growth seen since 2020. However, the growth rate in demand has slowed relative to recent years as the rate of growth in exports has slowed and because growth in demand for power burn—gas consumption for electricity generation—is slowing and is expected to remain flat at around 43.4% of total demand this summer. The share of U.S. natural gas-fired electricity generation relative to total U.S. electricity generation is also forecast to average close to 45%.
As of April 1, 2024, FERC- authorized export liquefaction capacity in the United States was 14.23 Bcf across seven LNG export facilities, all of which are expected to be in service this summer. Net natural gas exports from LNG terminals and by pipelines are expected to average 14 Bcfd this summer, an increase of 1.4 Bcfd from last summer’s levels. This comes at a time of sustained demand for LNG cargos in the European market and elevated international prices.
Next slide, please.
I will now turn the presentation over to my colleague An Jou Hsiung, who will discuss electric reliability trends.
Thank you, Jerry.
This slide illustrates electricity demand growth compared to last summer. Further, it shows all regions anticipate that their available resources and net transfers will exceed their net internal demand.
NERC forecasts net demand for electricity to increase by approximately 0.41% or 3.2 GW for summer 2024 compared to summer 2023 levels. The growth in net demand is concentrated in the PJM, SPP, and ERCOT regions, along with the SERC-Florida and WECC-Southwest subregions. NERC forecasts net demand reductions for the -New York ISO, WECC-California/Mexico and WECC-Northwest sub-regions.
To serve electricity demand, NERC forecasts a national increase of 1.8%, or almost 17.5 GW, in total system resources and net firm transfers, increasing system resources from 958.5 GW in summer 2023 to 976 GW in summer 2024.
NERC will highlight some additional details on several Regions in a few moments.
Drought conditions persist in much of the United States in 2024, with potential hydropower impacts in certain regions, including the Southwest, central and northern United States, which face elevated risks compared to summer 2023. Drought conditions currently affect 19% of the Continental United States. Canada is also experiencing abnormally dry or drought conditions and faces potential re-occurrence of wildfires this summer, which could impact U.S.-Canada energy transfers and affect both U.S. and Canadian solar output during extreme smoke conditions.
As of May 8, 2024, Northwestern and North-Central United States snowpack is down, while California reports slightly higher than average levels of snowpack heading into the summer than was reported a year ago.
Supply chain disruptions during summer 2024 could negatively affect the electric industry’s work on construction, operations, reliability, and security. Supply chain issues have made it more difficult for generators and transmission owners to schedule maintenance outages, to determine when new transmission resources will come online and when line upgrades can be completed, and to interconnect new resources.
Data centers are a key part of the recent growth in electricity demand. The rapid growth of emerging technologies like Artificial Intelligence and Machine Learning has fueled growth in data centers’ capacity in recent years. For example, PJM expects 2.3% net energy for load growth in 2024 and accredits the increase to continued data center construction, along with the electrification of transportation and industry.
I will now turn the presentation over to my colleague, Mark Olson, from NERC for additional analysis.
NERC’s comments are not provided in advance.
Thank you, I will turn back to my FERC colleagues for concluding statements.
The full report posted on the Commission’s website covers the topics discussed in this presentation in greater detail, as well as additional information on demand response, electricity infrastructure, natural gas exports and imports.