Situated off California’s Santa Barbara coast, the Santa Ynez project operated by Sable Offshore has become a litmus test of President Trump’s determination to revive oil production in a state pursuing a future beyond it. After a decade of shutdowns, its return depended on the Trump administration’s intervention in a prolonged regulatory battle.
Originally developed by ExxonMobil, the Santa Ynez complex comprises the Hondo, Harmony and Heritage platforms and their associated onshore infrastructure. Its troubles began in May 2015, when Plains All American’s Line 901 pipeline ruptured due to external corrosion near Refugio State Beach, spilling almost 3,000 barrels of crude. The failure cut off the project’s route to local refineries and broader market, forcing production to stop. ExxonMobil eventually sold the assets to Sable in 2024 for a total consideration of $643 million.
Restarting the production proved difficult. Pipeline safety requirements, permitting disputes and court orders kept the development from returning to normal operations. Those obstacles unfolded against Democrat-led California’s broader push to reduce its dependence on fossil fuels: in 2021, Governor Gavin Newsom asked state regulators to analyze how to phase out oil extraction by 2045. Sable announced in May 2025 that it had restarted production from Harmony, a claim California officials disputed, saying the activity was well testing. The offshore platforms sit in federal waters, beyond the state’s direct reach, but the oil initially went into storage while its onshore pipeline route, which California regulated at the time, remained blocked.
The Trump administration then helped reopen that route in two steps. In December 2025, the federal Pipeline and Hazardous Materials Safety Administration (PHMSA) reclassified the onshore pipelines as interstate infrastructure at Sable’s request, asserting federal oversight, and approved their restart plan on Dec. 22. After the conflict between the US and Iran started in late February 2026, just as the ensuing energy crisis hit the markets, Energy Secretary Chris Wright invoked the Defense Production Act to direct the restoration of operations on March 13, citing supply risks and military dependence on foreign oil. Sable resumed pipeline shipments the following day. However, California’s Democratic administration challenged both interventions, turning the project’s revival into a continuing fight over federal and state authority.
Democratic control of the House and Senate, won in the early November midterms, will not automatically reverse those decisions. The new Congress takes office in January, while Trump retains executive authority and the ability to veto legislation. But congressional committees can investigate the administration’s intervention, demand records and use spending negotiations to seek restrictions. Members of California’s congressional delegation have already started: in May they wrote to Sable’s CEO asking the company to preserve records and promising continued oversight in the next Congress. For Sable, the likely exposure is greater scrutiny and less scope for additional legislative support, rather than an immediate congressional shutdown. Courts remain the more direct threat to the legal foundations of its pipeline operations. Sable CEO Jim Flores said on the company’s earnings call that the rulings it has won, including one upholding PHMSA’s jurisdiction over the pipeline, are on appeal at the Ninth Circuit.
That uncertainty matters because the commercial margin for disruption is already narrow. Sable’s shares fell by more than half on November 9, touching a record low of 76 cents at one point, after it disclosed the consequences of its sole customer Chevron stopping purchases of crude in early October due to refinery maintenance and storage-tank upgrades, and warned of substantial doubt about its ability to continue as a going concern. Chevron had been the project’s only outlet, and apparently an interruption at one customer was enough to turn a production recovery into a liquidity crisis.
Management says the position has since improved. On its earnings call, Sable said all four major Los Angeles-area refineries were taking its crude after agreements with three additional buyers, among them Marathon and PBF Energy. Those relationships, however, began with starter volumes. The company was pursuing a bulk sale of up to 1.3 million barrels to finance its Q4 spending budget of $165 million to $175 million (including debt payments), with a $100 million unsecured loan basket and, if needed, a private placement of shares as fallbacks. It ended September with $38 million in cash. And while additional customers reduce concentration risk, they do not immediately repair the cash shortfall left by October’s interruption.
Crude quality adds another constraint. Santa Ynez produces heavy, sulfur-rich oil (around 15-20°API and 4-5% sulfur content), and management acknowledges ample competing heavy-crude supply, with walk-up pricing still about $30 a barrel below Brent. The planned restart of the Hondo platform should help: Sable expects its lighter, sweeter production to improve the combined blend, with approximately 10,000 b/d forecast from the platform in December. That could improve marketability, but more production also increases the volume requiring a reliable outlet and adds pressure on storage at Las Flores Canyon and along the pipeline, where Sable is already holding unsold October crude.
The trajectory of California’s broader hydrocarbon industry makes that outlet increasingly uncertain. Crude production in the state averaged roughly 245,000 b/d through August 2026, down from about 550,000 b/d in 2015. The long decline is due to an aging producing base and an increasingly restrictive policy environment. Newsom has directed regulators to study ending extraction by 2045, and the state has restricted new wells near homes and schools.
Refining is decreasing alongside production. In the last 6 years, closures and renewable-fuel conversions have removed plants operated by Marathon, Phillips 66 and Valero from the conventional refining market. California’s July 2026 refineries’ listing shows 11 facilities with combined crude-processing capacity of approximately 1.34 million b/d. For Sable, that creates an uncomfortable distinction: California remains heavily dependent on imported oil while offering fewer potential customers for additional local barrels.
In 2026, total seaborne imports to the state were at around 890,000 b/d, down from last year’s average of 1.04 million b/d. While the main pillar of crude imports is still Alaskan North Slope (around 200,000 b/d in March-October 2026), deliveries of Middle Eastern volumes from Iraq, the UAE and Saudi Arabia (35% of total foreign crude imports in 2025) have been disrupted by the war. They were partially substituted by Latin American crude from Brazil, Guyana and Ecuador. In October 2026, Latin American barrels accounted for 72% of California’s total oil imports. Besides the ongoing US-Iran war, California’s imports were also affected by the most recent refinery closure that took place this spring, when Valero shut down its 145,000 b/d Benicia plant.
Therefore, falling crude imports do not only signal crisis-related cuts or improved self-sufficiency; they reflect a shrinking refining system that requires less feedstock.
That adjustment is already visible in clean product imports to California. Clean product imports reached an all-time high in the first two months of the US-Iran conflict, averaging 270,000 b/d across March-April. Since then, imported volumes have subsided somewhat (aided by the return of the El Segundo refinery), but the Golden State remains heavily dependent on South Korean refined product supply for its regional needs. Moreover, the temporary Jones Act waiver is due to expire on November 15, and the decision on whether to extend it rests with the Trump administration, while US maritime groups are urging the White House to let it lapse. Without the waiver, shipments of products from the Gulf Coast to PADD 5 would again be limited to US-flagged vessels. Historically, the Gulf Coast barely exported any products to California, but Trump’s waiver allowed for a record flow of 70,000 b/d in May-October, mostly consisting of gasoline and blending feedstocks.
California’s lack of pipeline connections to Gulf Coast refineries makes maritime deliveries particularly important. Hence, the Golden State will be increasingly exposed to wider market availability of products, supplanting domestic processing with distant supply.
Sable is exploring a maritime solution of its own: an offshore storage and treating vessel that would allow shuttle tankers to carry crude to domestic or international buyers. In a February filing, the company put the cost of that strategy at about $475 million, subject to regulatory clearances. If Democrats at the federal level were to back local Californian opposition to moving Sable’s crude by pipeline, this route could push California’s offshore production toward foreign markets, with Asia one possible destination. Such a route could broaden Sable’s customer base and reduce dependence on disputed onshore infrastructure, but, again, it requires approvals, investment and buyers at prices that justify the additional logistics and acknowledge the relative difficulty of handling Santa Ynez barrels.
The resulting situation encapsulates the troubled future of California’s hydrocarbon industry: an offshore project revived in the name of domestic energy security could eventually seek customers abroad while the state itself imports more refined products. Federal intervention helped to reopen a pipeline, but it cannot guarantee that California’s shrinking refining industry will absorb the oil, or that Sable Offshore can finance the wait.
By Natalia Katona for Oilprice.com
