SoCal Natural Gas Prices Climb as El Paso Pipeline Outage Bites

A regional market breaks from the national trend

On the first Friday of October, most of the U.S. natural gas market sold off. Southern California went the other way. Spot prices fell across most of the country as traders set prices for a three-day weekend package against mild early-autumn demand. The national average dropped 16 cents. Southern California held its gains because pipeline limits and late-season heat kept the regional market tight11.

The gains came the day before. On Thursday, Oct. 1, SoCal Citygate rose 56.5 cents to $4.440/MMBtu. The SoCal Border average climbed 52.5 cents to $3.505, and PG&E Citygate in Northern California gained 16 cents to $3.915. NGI's national spot average rose only 6 cents to $2.50512. The two coasts moved in opposite directions. Algonquin Citygate in New England fell to $1.365, and Tennessee Zone 6 200L dropped to $1.33012. At its peak, SoCal Citygate traded $1.44 above Henry Hub, its widest premium since Sept. 11. Midday data showed the weekend package trading even higher, near $4.6515.

This is an old story in California. Weather moves prices, but the state's location at the end of long pipelines decides how far they move.

The pipe problem behind the premium

The main cause was the El Paso Natural Gas system, which carries Permian Basin gas west toward California. On Sept. 27, El Paso declared force majeure at its Seligman C compressor station in Yavapai County, Arizona. The outage cut 170 MMcf/d of capacity on the North Mainline15. It was the third Seligman outage since August, and it pushed the SoCal premium over Waha, the Permian benchmark, above $1.8011. By the start of the Oct. 1 gas day, El Paso had also posted capacity reductions on its Plains Station and Lordsburg segments12.

Southern California Gas responded the same day. It asked for proposals to help meet minimum-flow requirements at its Ehrenberg, Blythe and Otay Mesa delivery points on the Southern System. It said it preferred firm physical supply but would consider interruptible gas. The utility framed the request as planning for future supply, not an emergency purchase, and offers were due Oct. 1512. When a utility formally asks for help keeping its southern entry points supplied, it is a sign that operators see real reliability risk, not just a pricing quirk.

The geography explains why. A large share of Southern California's gas comes from the Permian, so Waha and SoCal Citygate sit at opposite ends of the same westbound pipelines13. A failed compressor in Arizona cuts what can reach Los Angeles and leaves more gas stranded in West Texas. Producers there take the discount, and California buyers pay the premium.

Heat made a tight system tighter

The pipeline cuts came during an unusual October heat wave. Forecasts put Pacific region power burn near 4.8 Bcf/d over the following week, up from about 2.9 Bcf/d the week before and 1.9 Bcf/d a year earlier. The European weather model showed California and Nevada cooling demand at more than four times normal over 15 days15. Gas-fired generation on the California Independent System Operator's grid averaged about 11 GW on Oct. 1, up 48% in a day and 61% from a year earlier15. Utilities were also still trying to refill storage drained by August and early-September heat15.

Storage is the backstop, and California's is limited. Aliso Canyon, the state's largest storage field, could hold 86.2 Bcf without regulatory caps. It has run at reduced capacity since a 2015 leak, and its cap now sits at 68.6 Bcf13. History shows what happens when weather, storage and pipelines all fail together: SoCal Citygate hit a record $144/MMBtu during Winter Storm Uri in February 2021 and traded between $20 and $50 for most of December 202213.

The rally faded, but the risk remains

The October premium did not last. By Oct. 8, spot prices in California were falling alongside the pipeline-constrained East19. By mid-month, Southern California forwards had weakened against Northern California as regional demand cooled, border prices fell and gas-fired generation dropped 53%17. That suggests the early-October spike was mainly about weather and a temporary outage, not a permanent rise in the regional price level.

The longer-term risk has not gone away, though. Forward curves still put SoCal Citygate above PG&E Citygate, with winter 2027-28 premiums reaching about $6.65/MMBtu17. A California buyers' cooperative warned public agencies heading into winter that the state's dependence on long-distance pipelines leaves it exposed to maintenance, outages and capacity limits16. In our reading, the market is calm, not safe: one cold snap during another compressor outage could bring the premium back quickly.

Henry Hub: lots of supply, more exports

The national picture explains why California's spike stood out. Henry Hub spot fell from $3.10 on Oct. 20 to $2.52 on Oct. 26, its lowest since November 2024. It then bounced to $2.769. The November futures contract expired at $2.776, and December took over as the front month near $3.069. Hedge funds held a record short position across seven benchmark Henry Hub contracts, the second record in two weeks10. The Energy Information Administration (EIA) reported an 80 Bcf storage injection for the week ending Oct. 23, more than expected12.

Supply is the main reason. U.S. production hit a record 113.3 Bcf/d in August and September2, and the EIA expects Henry Hub to average $3.48 this year and $3.16 in 2027 as output keeps growing3. Bank of America is the main outlier, forecasting $4.00 in 2027 on strong LNG demand3.

LNG exports are the main source of support. Reported feedgas figures differ by source and timeframe. Reuters-based figures put October flows to the nine major export plants at 18.3 Bcf/d, below April's monthly record of 18.8 Bcf/d4. Daily figures were higher: one analysis said feedgas jumped to 21.2 Bcf/d in late October9, and another estimated a preliminary daily record near 20.8 Bcf/d on Oct. 18 as the Golden Pass terminal ramped up6. The figures conflict on whether a record has been set, but they agree on the direction: export plants are taking more gas each month.

The gap with overseas prices is huge. On Oct. 13, Henry Hub traded at $3.12 while Europe's TTF benchmark was $28.202. Those high overseas prices barely reach U.S. buyers because export plants were already running near full capacity3. That will change as more export capacity comes online. By 2030, a fifth or more of U.S. gas production could be tied to global LNG markets2. Analysts also expect LNG competition to complicate the coming winter in California17.

Data centers add new demand to the West

AI data centers are the other source of new demand, and they matter along the El Paso corridor. Arizona Public Service used about 90% of its planned capacity this summer, and an early analysis found data centers accounted for half of its demand growth. The utility expects peak demand to rise 40% by 203130. More gas burned for power in Arizona means more competition for the same pipeline capacity that feeds Southern California.

Estimates of how much gas data centers will need vary widely. BloombergNEF projects data-center gas use rising by 15 Bcf/d over the decade to 203524. Morgan Stanley's probability-weighted base case is 4.8 Bcf/d by 2030, and RBC estimates about 6.1 Bcf/d25. Pipeline companies are already building for it: Kinder Morgan's project backlog reached $14.4 billion on data-center and utility demand23. Voters in Texas, Georgia and Iowa will also decide on Nov. 3 whether to allow state-level data-center moratoriums23.

Oil and gasoline: the same constraints in a different market

Petroleum markets show a similar pattern on a larger scale. West Texas Intermediate (WTI) crude rose to $104.12 a barrel on Oct. 30, up about 12% over the month and roughly 71% from a year earlier, on fears of renewed U.S. strikes on Iran31. The EIA estimates Middle East producers have cut output by more than 11 million barrels per day33.

U.S. production is high but cannot offset that. Output was 13.965 million barrels per day in August, and weekly estimates were near 13.99 million in October31. AAA put the national gasoline average at $4.22 on Oct. 29, compared with $3.04 a year earlier34. California was the most expensive state at $5.9434. In Los Angeles County, prices fell for the 30th time in 31 days to $5.977 after an early switch to winter-blend fuel20. Diesel was about $6.35 nationally, just below its September record37.

Whether the product is gas through Arizona or crude through the Strait of Hormuz, prices depend less on how much is produced than on whether it can be delivered. Record U.S. output has not stopped a California utility from soliciting supply for its southern delivery points or stopped gasoline from reaching $6 in Los Angeles. Until there is more pipeline, storage and export capacity, regional price spikes will keep breaking from the national averages.