Published: April 16, 2025
By Concentric Staff Writer
Key takeaways:
- Rising electricity demand was the story nationally in 2024, rising by 2.8 percent, primarily in the California Independent System Operator (CAISO), Electric Reliability Council of Texas (ERCOT), and the Mid-Atlantic region.
- Generation retirements, which are worrying federal energy regulators, were primarily coal-fired power plants, followed by natural gas-fired plants, with the bulk of them in the Midcontinent Independent System Operator (MISO).
- Independent system operators (ISOs) and regional transmission organizations (RTOs) made progress on clogged interconnection queues, with the capacity of projects in queues dropping for the first time on an annual basis.
- There were also declines in wholesale electricity and natural gas prices across all ISOs and RTOs.
Last year was a tale of rising national energy demand, extreme weather that affected the electric grid, increased renewables, and slight progress on clogged interconnection queues, according to a new report from federal energy regulators.
The State of the Markets Report for 2024, issued March 20 by the Federal Energy Regulatory Commission (FERC), notes that after flat load growth in recent years, electricity demand grew by 2.8 percent over the year nationally. The largest load growth in 2024 was in California, while the biggest decrease was in the New York ISO. Half of the RTOs and ISOs saw load growth in 2023-2024 while the other half saw decreases, the report says.
FERC Chairman Mark Christie, who has been vocal on the issues of preparing the grid for forecasted increased demand, expressed alarm over generation retirements and an influx of renewables that have lower dispatch potential compared to conventional resources.
“This report is consistent with reports we have been regularly receiving from NERC [North American Electric Reliability Corporation] as well as RTO sources, such as from PJM and MISO,” Christie said in a news release. “The combination of rapidly increasing electricity demand, driven by hyperscale customers such as data centers, paired with the alarming rate of base load generation retirements and lack of new dispatchable generation, is not sustainable and must be addressed.”
The resource type seeing the most retirements was coal-fired power plants, although there were substantial retirements of natural gas-fired plants. The majority of retirements were in MISO, which had 3.6 GW of retirements last year in its region.
The biggest increase in electric load was in Southwest Power Pool (SPP) over the four-year period ending in 2024 with 8.3 percent, while the New York ISO saw the largest decrease at 4 percent. The largest increase over the 2020–2024 period was also in SPP. There were also declines in natural gas prices and wholesale energy prices in all ISOs and RTOs, but no corresponding price drops for retail consumers.
Extreme weather in the CAISO, ERCOT, and the Mid-Atlantic drove most of the demand growth in 2024, according to the report by FERC staff. There were also power outages and the disruption of oil and gas production on the Atlantic coast.
NERC projects that the pace of growth in electricity load will accelerate, estimated to grow by 132 gigawatts by the summer of 2029 and by 149 GW by the winter of 2029. Although natural gas prices spiked in January 2024 on cold weather, nationwide natural gas prices fell year over year and remained below the five-year average. One exception was in the Northeast, where natural gas prices rose slightly over 2023.
Natural gas prices, which drive wholesale electricity prices in many areas, dropped at major hubs outside the Northeast, such as the benchmark Henry Hub in Louisiana, which fell by 11 percent to $2.25 per million British thermal units (MMBtu), averaged over the year. The lower prices were mainly a result of higher-than-average storage levels, bolstered by little change in natural gas production and demand.
Natural gas demand reached an all-time high in 2024, according to the report, averaging 102.8 billion cubic feet per day (Bcfd) in the year, including net exports, while domestic consumption averaged 90.2 Bcfd. While growth in demand slowed over the year—at .5 percent compared to the five-year average of 3.1 percent growth in 2019–2023—the average of 36.9 Bcfd natural gas burn was a historical high. This was 4.2 percent growth year over year, with natural gas burned for electricity being the largest component of demand.
“Power burn exceeded the prior year’s level and the five-year average in nearly every month of 2024 in response to lower natural gas prices, coal power plant retirements, and natural gas-fired generation additions,” the report says.
U.S. dry natural gas production decreased slightly, by .3 Bcfd, ending at an average of 103.2 Bcfd. The most production came from the Permian Basin, followed by West Texas and Louisiana. Natural gas production in the Permian Basin increased 2.1 Bcfd or 13 percent over the year. The Waha Hub in West Texas had the lowest average spot natural gas price over the year, at $.05 per MMBtu, compared to $1.52 in 2023.
“Prices at the Waha Hub are typically lower than those at most natural gas trading hubs in the country due to a combination of limited natural gas pipeline takeaway capacity and growing gas production associated with oil-focused drilling,” the report says. “Waha spot natural gas prices were negative for 158 days, or 43 percent of the year, in 2024 as the region faced pipeline outages and takeaway capacity constraints.”
The biggest average price drops over the year were at SoCal Gas Citygate and PG&E Citygate in California, which saw a 62-percent drop to $4.12 per MMBtu at SoCal Gas Citygate and $3 per MMBtu at PG&E Citygate. There were also smaller natural gas price decreases—about 10 percent—at the Midcontinent hubs of Chicago Citygates in the Chicago area and NGPL-Midcon, which serves parts of Kansas, Oklahoma, and the Texas Panhandle.
Natural gas production averaged 103.2 Bcfd in 2024, a drop of .3 percent compared to the previous year, while natural gas demand grew by .5 percent to an average of 102.8 Bcfd. Prices outside the Northeast fell year over year by between $.18/MMBtu and $4.12/MMBtu across the major hubs.
However, prices at Northeast hubs rose, including 14 percent at Transco Zone 6 N.Y. serving New York City, 3 percent at Algonquin Citygates in the Boston area, and 2 percent at Eastern Gas South in Appalachia. This was due to cold weather, including a cold snap in mid-January that pushed up demand and prices.
As far as power generation, while most new capacity additions came from solar, natural gas, battery storage, and wind resources, natural gas retained a large share of the resource mix at about 42.4 percent nationally. Coal generation dropped by 3.3 percent; utility-scale solar grew by 32 percent; and wind rose by 7.7 percent in the lower 48 states. Net generation also rose in 2024 from the previous year, hitting 4,151 terawatt-hours (TWh).
Capacity prices in organized markets with capacity markets—PJM Interconnection, MISO, and ISO New England—also rose due to “electricity market dynamics,” according to FERC.
RTOs and ISOs adjusted their resource adequacy requirements, such as in SPP, which introduced new seasonal resource adequacy requirements, and in MISO, which set higher planning reserve margins for load-responsible entities. Challenges facing resource adequacy included the changing resource mix, extreme weather, and shifts in load profiles.
FERC in November 2024 approved SPP’s proposed tariff revisions to add a winter season resource adequacy requirement for load-responsible entities that took effect Jan. 1, 2025. The revisions required that these entities comply with winter resource-adequacy requirements or pay a deficiency payment.
Last year also marked the first time that the total capacity of new generation projects in interconnection queues dropped on an annual basis. Total capacity in queues around the country totaled 2,289 GW at the end of the year, the vast majority being solar, energy storage, and hybrid storage projects. These resource types represented 81 percent of the capacity in interconnection queues. Despite this, the resource types that made up most of the capacity entering queues in 2024 were natural gas generation and storage.
Efforts to clear out clogged interconnection queues continue, bolstered by FERC’s issuance in July 2023 of its Order No. 2023 that included many new processes for ISOs and RTOs to clear out queues. Individual RTOs and ISOs also enacted their own queue reform initiatives.
The largest amount of active interconnection queue capacity was in the Western region, with 590 GW, followed by MISO with 439 GW, and ERCOT with 351 GW. In MISO, the largest resource type sitting in interconnection queues was solar (241 GW), “which was the largest amount of active capacity in interconnection queues for all fuel types in all regions,” the report says.
More than 5,000 circuit miles of transmission projects entered service in 2024 nationally, mostly to address reliability needs. The most miles were built in CAISO, which had 2,000 miles of reliability projects built (as opposed to policy-driven projects), followed by ERCOT, MISO, and PJM, which had about 200 miles of new reliability-driven transmission added.
Across all the RTOs and ISOs, transmission projects driven by load growth included about 900 circuit miles—the second-largest category of new transmission. The smallest category of new transmission were policy-driven projects, with four such projects entering service in the year—two in CAISO and one in PJM and MISO, respectively. There was only one economic-driven project completed in the year.
The majority of projects were at the 138-kilovolt level, with this type making up 170 projects and almost 1,100 circuit miles, the report says. The majority of these were in ERCOT and PJM.
Sources used in this article:
FERC State of the Markets Report for 2024
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
