May 2025, Vol. 252, No. 5
Features
SoCalGas' Aliso Canyon Site, Home to Historic Methane Leak, Moves Toward Closure
By Richard Nemec, Contributing Editor, North America
(P&GJ) — At the end of 2024, nearly a decade after the largest U.S. methane gas leak at California’s major underground natural gas storage site, state regulators decided on a multi-year process that eventually could close the 100 Bcf Aliso Canyon storage facility, operated by Sempra Energy’s Southern California Gas (SoCalGas).
While the full ramifications of this for the state and the gas industry nationally are mostly unknown, it is safe to call this a major milestone for energy storage, at a time when fossil fuels face a fundamental transformation.
The California Public Utilities Commission (CPUC) has unanimously approved a plan to develop a process to wind down the storage facility, as demand for natural gas falls in the coming years, which is widely anticipated. The regulators’ vote took place amidst a large contingent of activist residents living near the 3,200-acre storage facility, who have been lobbying for closure of Aliso Canyon since it sprung a four-month leak from a storage well in the fall of 2015.
CPUC members empathized with the residents but indicated their core responsibility was “ensuring safe, reliable and affordable energy utility service.”
California Gov. Gavin Newsom has indicated that eventually Aliso Canyon will be closed, but that will be managed by the constitutionally independent CPUC.
“Aliso Canyon must be closed for good, but without harming working families with skyrocketing utility bills,” Newsom said at the time, in December 2024. “Reducing reliance on the facility has gone slower than I would like, but the CPUC has set out a reasonable path that protects residents near the facility and doesn’t throw the natural gas market into chaos.”
From late October 2015 until mid-February 2016, the disaster spewed 109,000 tons of methane and other chemicals into the air, forcing more than 8,000 families to leave their homes. Many of those families complained of medical ailments, including headaches, nosebleeds and nausea, from the leaking methane.
The CPUC’s proposal calls for moving ahead with potentially closing Aliso Canyon, once Southern California’s demand for natural gas declines to a point at which peak demand can be served without the site. That is projected to happen in the next decade.
On a national and global basis, there is little indication that underground storage is soon to be extinct. Repositories like the U.S. Energy Information Administration (EIA), even in the face of massive cutbacks in the federal government, is still putting out regular reports on U.S. storage levels.
In March of this year, U.S. total natural gas underground storage capacity was at 9.32 Tcf, up from 9.318 Tcf the previous month and up from 9.278 Tcf a year earlier. This is a change of 0.02% from last month and 0.45% from one year ago, according to the EIA, reflecting a flat trajectory in the near-term.
At current consumption and production rates, the United States has enough natural gas reserves to last approximately 86 years, based on current estimates of projected demand and reserves, including EIA’s projections for plentiful dry gas supplies.
In late March, EIA released its Weekly Natural Gas Storage Report, indicating that working gas in storage increased by 9 Bcf from the previous week, compared to analysts’ forecast of 3 Bcf. In the previous week, working gas in storage decreased by 62 Bcf. In the same report, EIA offered its 10-year projection through 2034 on the gas storage market overall.
In EIA’s most recent complete annual data, the demonstrated peak capacity for gas storage increased 3% in 2023, after three consecutive annual decreases in that industry metric, which adds up all of the nation’s largest working gas volumes recorded at each of 384 storage fields around the country. This is a different indicator than “design capacity” or nameplate, the latter of which is based on a combination of nonoperating factors such reservoir characteristics, installed equipment and operating procedures authorized by state and federal regulators.
“The declines in demonstrated peak capacity reflected less use of existing gas storage fields and less investment in new [facilities] and expansion,” EIA analysts indicated, adding that the largest single decrease was caused by the aftermath at California’s Aliso Canyon.
In contrast, the recent increase nationally was mostly spurred by the CPUC’s decision to increase the working capacity at Aliso by 67%, pushing the overall western storage capacity up by 27%.
EIA and other industry sources indicate that market conditions both now and in the future will impact whether — and how much — growth there is in storage capacity. The federal statistical agency notes that there are slightly more factors that can recede growth, such as increased domestic supplies and lower prices that allow customers to avoid having to rely on storage, greater use of high-deliverability storage and increased pipeline capacity.
Conversely, greater reliability on intermittent solar and wind sources for electricity and a growing LNG export market can help grow storage.
In late April, the American Gas Association (AGA) released a report concluding that additional gas storage is “urgent” in the United States. Entitled “Natural Gas Storage: A Strategic Asset for Grid Reliability, System Resilience and Operational Flexibility in a Changing Energy Landscape,” AGA cited several drivers for more storage, including constraints on gas infrastructure from rapidly increasing demand caused by ever-growing needs for data centers and a resurgence in U.S.-based manufacturing.
AGA notes that additional storage development has slowed, requiring some policy considerations and more flexible gas storage. “Over the past few years, gas production, pipeline capacity, and demand have all grown significantly while underground storage capacity has remained largely flat,” said Karen Harbert, AGA’s CEO. Market fundamentals are pointing the way to expanded storage, according to Richard Meyer, AGA vice president for energy markets, analysis and standards.
In 2024, the global gas storage market size accounted for 42.41 billion cubic meters (Bcm) and grew to 50.30 Bcm in 2025, with predictions that it will surpass 233.52 Bcm by 2034, representing a healthy compound annual growth rate (CAGR) of 3.5% between 2024 and 2034. Within these totals, the North American gas storage market size is calculated at 19.08 Bcm in 2024 and is expected to grow at a fastest CAGR of 18.72% during the forecast year.
These are not projections for a dying part of the industry. However, the future need and prospects for gas storage have to be examined, in the context of an increasingly low-carbon energy world.
As such, academic experts, such as Rice University’s Ken Medlock, senior director at the Center for Energy Studies in the Baker Institute for Public Policy, look at storage’s future as “nuanced” but generally enhanced in a low-carbon environment.
“In a low carbon world, gas storage will be more valuable to provide flexibility to energy systems that are increasingly reliant on intermittent resources,” Medlock told P&GJ. “If, however, low carbon means a lot more SMR [steamed methane reforming] and geothermal, then that need abates. However, it will take at least a decade, likely much longer, to reach the scale needed for that to be an issue. So, [for] the next 15–20 years at least, will see a strong need for storage services.”
He points out that even with the unprecedented leak at Aliso Canyon nine years ago, depleted oil and gas fields continue to be the leading type of U.S. underground gas storage. Less than 10% of storage in the U.S. is salt cavern (slightly more than 7%). The majority is depleted reservoirs. “The safety record, as a whole, for depleted reservoir storage is rather strong,” Medlock noted.
Prospects for expanding salt cavern storage are limited by cost and need. Depleted reservoir development is lower cost, so it typically dominates.
“Electrification can raise the need for gas storage, especially as more gas is used in power generation,” Medlock said. “LNG exports can present a different need. Other regions, especially those that do not have native storage, can increasingly use U.S. storage as LNG export capacity increases. So, more LNG exports could increase demand for storage in the U.S., allowing flows to ramp on a seasonal basis.”
At this year’s annual CERAWeek energy conference in Houston in March, it became evident that the Trump administration wants to drive U.S. artificial intelligence (A.I.) development and the large increases in electric power that will be required through the spread of various data centers. Newly named Energy Secretary Chris Wright signaled that this means more gas-fired generation. And although he didn’t specify it, that means more gas storage, as experts like Medlock have noted.
Wright told the Houston audience that the Trump administration intends to move “at warp speed” to both remain competitive in A.I. and keep the lights on as demand grows for more and more power in the tech sector. “We have the talent, innovative spirit, and leading companies to win, but all that won’t matter if we can’t deliver the energy,” Wright said in Houston. “A.I. is an energy intensive manufacturing industry.”
At the beginning of 2025 there are about a half-dozen major new or expansion projects for LNG exports, concentrated on the Texas/Louisiana Gulf Coast. In the South region, some 13 Bcf of storage was added in 2023, according to EIA, with salt caverns adding 9 Bcf and other types of storage accounting for 4 Bcf.
EIA expects U.S. LNG exports to increase by nearly 2 Bcf/d in 2025, as export capacity grows with three new domestic projects due to begin operations during the year. Longer term, five additional U.S. projects are due to come online by 2028, along with three projects in Canada and two in Mexico over the same timeframe, according to the Washington, DC-based Center for LNG (CLNG).
On Dec. 26, the Arlington, Virginia-based Venture Global LNG Plaquemines facility became the eighth LNG export terminal in the United States, shipping its first cargo after achieving initial production in mid-December, EIA’s Victoria Zaretskaya reported earlier this year.
Upon completion of a second phase, Plaquemines LNG’s total nominal capacity will be 2.6 Bcf/d (3.2 Bcf/d peak). Plaquemines LNG is one of two U.S. LNG export terminals that started LNG production in 2024. Corpus Christi Stage 3 (an expansion of the existing Corpus Christi LNG export terminal) also started production last December.
“Nominal capacity is the volume of LNG produced in a calendar year under normal operating conditions, based on the engineering design of a facility,” Zaretskaya noted in her EIA summary. “Peak capacity is the volume of LNG produced under optimal operating conditions, including modifications to production processes that increase operational efficiency.” Venture Global LNG plans to commission and start exporting LNG from Plaquemines Phase 2 in September 2025.
When both phases of Plaquemines LNG are completed and Corpus Christi LNG Stage 3 starts exporting, EIA estimates that LNG nominal production capacity in the United States will total 15.4 Bcf/d (18.7 Bcf/d peak), and that nominal LNG export capacity will expand to 21.2 Bcf/d (25.2 Bcf/d peak) by 2028, once three other U.S. LNG export projects currently under construction — Golden Pass LNG, Rio Grande LNG and Port Arthur LNG — are completed, according to Zaretskaya.
In late 2022, the American Petroleum Institute (API) released two updated standards on gas storage facilities, covering both salt caverns and depleted hydrocarbon and aquifer reservoirs. The Washington, D.C.-based industry standards and lobbying organization used the action to underscore its belief that underground storage is a “vital part” of the gas supply transformation to adjust to changing consumer and government demands.
“These updated standards will help ensure underground storage facilities are designed, maintained and operated at the highest level, while advancing health, safety and sustainability in communities where we operate,” API’s Anchal Liddar, a senior vice president, noted at the time.
The standards came in the wake of the continuing push back in areas like the upscale neighborhoods that developed around Aliso Canyon in California, which was developed in the early 1970s before suburbia spread out to its previously isolated location.
API maintains that what its officials call the “current global energy crisis” underscores the continuing importance of “advanced solutions that ensure continued access to affordable, reliable energy while also tackling the climate challenge.” Storage, obviously, is part of the advanced solutions API has in mind.
As is true of the natural gas industry generally, storage is maneuvering to find its place in the long term, and it appears the transition will be longer, more complex and less certain than may have been the case a decade earlier. The stark contrast in political administrations’ approaches to energy is an indication of the need for flexibility.
Working natural gas capacity ended the 2023 heating season 5% above the five-year average. Despite robust gas production, increased electric power and export demand, natural gas storage experienced reduced injections, and the industry reported below-average net injections into working gas in all regions west of the Rocky Mountains.
However, higher-than-normal inventory levels at the beginning of the refill season in the East, Midwest and South-Central regions, as a result of a relatively mild heating season, likely played a significant role in easing injection demand.
Colder-than-normal temperatures during recent winters contributed to reduced inventories in the Pacific and Mountain regions, resulting in summer injections that exceeded the five-year average to replenish working gas inventories. The Pacific and Mountain regions entered the 2023 refill season below the five-year average by 56.8% and 10.1%, respectively. They ended the refill season well above the five-year average. Current stocks in both regions exceed their highest levels since 2019, according to EIA.
As the federal statistics keepers were publishing this updated storage capacity analysis for all of 2023, all five EIA storage regions showed inventories above the five-year (2019–2023) inventory range. What does this mean for the future of storage in the next few years? No one seems prepared to make any bold predictions.
Richard Nemec is a long-time contributing editor to P&GJ. He can be reached at [email protected].
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