Judge Stephen V. Wilson said the Defense Production Act (DPA) is a “significant statutory grant of authority to the executive, giving the President substantial discretionary power to compel private industry, allocate resources, and incentivize domestic production for national defense.”
The opinion also granted the Trump administration’s request to modify a federal consent decree entered in 2020 which governs the restart of the Las Flores pipeline system.
The order removes the California Office of the State Fire Marshal as the primary agency responsible for Sable’s compliance with the oil spill consent decree, and substitutes the Pipeline and Hazardous Materials Safety Administration.
Despite favorable environmental reviews from both the Obama and Trump Administrations, the California Coastal Commission, empowered by the Courts, voted last week to prohibit the resumption of hydraulic well stimulation at DCOR’s Platform Gilda (map above).
Of course, as is always the case offshore California, the regulatory and legal battles will continue. The Secretary of Commerce may choose to overrule the CCC, in which case further litigation is certain.
This dispute comes at a time when the CCC, which operates with extraordinary autonomy, is undergoing a performance review by Commerce. Needless to say, the Commission and its supporters are not thrilled with the oversight.
In light of the spotlight on “offshore fracking,” I wanted to draw attention to a 2019 National Academies workshop that considered this very issue. I had the opportunity to participate in this workshop and was impressed by the input from industry and govt representatives.
Key points from the workshop:
If wells are not completed effectively, the value of drilling is negated, and it is impossible to deliver the oil or gas production needed to make the wells economically sustainable.
The frac pack (as is proposed for Platform Gilda) is one of the most commonly used completion techniques worldwide.
A gravel pack uses sieved sand as a filter to prevent formation sand from entering the wellbore, while the frac pack combines the gravel pack with hydraulic fracturing to create wide fractures filled with sieved sand that aid in connecting the reservoir to the wellbore.
Frac packs can create 50- to 250-foot fractures to stimulate production in a well.
Well stimulation offshore, which has been in practice for decades, has far less negative impact potential than well stimulation onshore.
Hydraulic fracturing minimizes the number of wells needed to develop a reservoir with the result being less environmental impact potential. This completion technique allows for the development of natural resources not previously considered commercially viable.
Offshore California, oil and gas formations typically have low permeability, and production is dependent on natural fractures. The objective is to enhance the flow of oil and gas from the tight matrix pores into the fractures.
The workshop graphic below highlights the differences in well stimulation risks onshore vs. offshore. The graphic is a bit unfair in that the onshore risks are being effectively mitigated. The main point is that much of the onshore risk potential doesn’t exist for offshore well stimulation.
This article provides information on the history of OCS Lease P-0166 and updates the decommissioning status of California OCS Platforms Hogan and Houchin which are in federal waters offshore Santa Barbara County, California. Listed below are key events in the history of the OCS Lease P-0166. More details are provided in the attachment which was prepared by John Smith who before retiring from BOEM in 2017 was actively involved in the long-running supplemental bond dispute between MMS/BOEM and Signal Hill Services, Inc., which began shortly after MMS approved the assignment of OCS Lease (P-0166) held by Phillps Petroleum Corporation (now ConocoPhillips Corp.) and two other companies to Signal Hill Services Inc. (Signal) in 1991.
Year/Month
Lease Activity
1967
U.S. Bureau of Land Management grants OCS Lease P-0166 to Phillips Petroleum Corp., Continental Oil Company, and Cities Service Company.
1967 – 1968
Hogan and Houchin platforms are installed.
1967 – 2010
75 wells were drilled from the platforms, the majority in 1967-1968 and 1970s.
February 1991
MMS approves assignment of the lease to Signal.
September 2019
Production is terminated at platforms.
October 2020
Signal relinquishes the lease to BOEM.
November 2020
BSEE orders ConocoPhillips Corp. (COP) and other predecessor lessees to decommission the Hogan and Houchin platforms.
January 2021
COP and other predecessor lessees file an appeal with IBLA contesting BSEE/BOEM determination they held decommissioning obligations.
February 2021
IBLA grants approval of Partial Stay Agreement between BSEE/BOEM and appellants to maintain and monitor the platforms.
November 2024
Signal files for bankruptcy under Chapter 7 of the U.S. Bankruptcy Code.
2021 – 2026
Monitoring, maintenance and major refurbishment of the platforms are ongoing to support safety of offshore personnel involved in well plugging and abandonment operations.
Since OCS lease P-0166 was relinquished in 2020, removal of Hogan/Houchin platforms has been stalled by a prolonged dispute over decommissioning obligations between BSEE/BOEM and predecessor OCS lessees (ConocoPhillips Corp., OXY USA Inc., Devon Energy Resources Inc.). The IBLA case has now been ongoing for more than 5 years and has the potential to set a precedent based on the arguments of the appellants who assert:
They had no accrued decommissioning obligations at the time of the 1991 assignment of the lease because pursuant to their 1961 OCS lease agreement decommissioning obligations did not accrue until the lease was relinquished, which occurred in 2020 when Signal quitclaimed the lease to BOEM.
The OCS rules changes promulgated in 1997, which stated a lessee’s decommissioning obligation “accrues to the lessee when a well is drilled, the platform or other facility is installed, or the obstruction is created.” (30 CFR 250.110), cannot be applied retroactively.
The 1961 OCS lease did not include a term by which the lessee agrees to be bound by “future” OCS regulations, which later became a standard provision in OCS lease agreements.
The IBLA case is very concerning because there is currently no financial security available to cover the costs of decommissioning the Hogan and Houchin platforms which were very conservatively estimated by BSEE to total $85 million in 2020. If the IBLA or judicial courts eventually rule COP and former lease owners did not accrue decommissioning obligations, either in whole or in part, the federal government and American taxpayers will be responsible for covering the unfunded decommissioning obligations.
An average of approximately 39 wells were online throughout the month of June 2026, representing a 50% increase over approximately 26 wells online on average in April 2026.
In July 2026, an average of approximately 47 wells at Platforms Harmony and Heritage were online, producing an average of approximately 721 gross barrels of oil per day per well. Sable expects to bring all 77 production wells on these two platforms online during the third quarter of 2026 and expects Platform Hondo to come online in September 2026.
Wireline campaign for Perforation Additions (“Perf Adds”) and producing well optimization at Platform Harmony commenced in August 2026.
Five completed Perf Adds forecasted to produce an incremental 600 estimated gross barrels of oil per day, each, are expected to come online at Platform Hondo along with the restart of the platform in September 2026.
An additional four Perf Adds at Platform Hondo forecasted to produce an incremental estimated 600 gross barrels of oil per day are planned for completion and to be brought online in early Q4 2026.
Sales
July 2026 preliminary oil sales estimate of approximately 38,000 gross barrels of oil per day. August 2026 oil sales average to date is approximately 42,000 gross barrels of oil per day through August 9th.
Due to the California regulatory environment, local refineries were not able to plan in advance for SYU first sales and ultimately were forced to displace various imported cargos in the second quarter. As a result, Sable incurred $18.5 million of non-recurring demurrage charges throughout the quarter, recognized in operational expenses.
The sudden supply influx of Pacific Outer Continental Shelf (“Pacific OCS”) crude has forced refiners to temporarily limit throughput of Pacific OCS crude and charge quality deducts for sulfur content and other items.
Starting in July 2026, Sable was temporarily constrained to a maximum of 40,000 average gross barrels of oil per day of oil sales throughput by downstream partners. We expect this short-term constraint to be alleviated starting in the back half of August.
California refineries are expected to adjust their crude oil supply slate starting in September 2026 to begin accepting more Pacific OCS barrels from the SYU and less imported barrels, alleviating the SYU throughput constraint altogether.
Sable is also in active negotiations to implement waterborne crude oil marketing solutions from existing marine terminals in the Los Angeles area in the near-term in order to improve marketing optionality.
Additionally, the pending acquisition of the Crimson Utilities (San Pablo Bay Pipeline) pipeline network by a third party could provide further relief and marketing optionality to California oil producers with access to the San Francisco refinery market once that pipeline potentially restarts operations.
“After careful consideration, it was determined there is no path forward to permit these projects in the U.S. for the foreseeable future.”
Comment: The poor prospects for these leases had more to do with bad investment decisions than permitting challenges. The company is fortunate to be able to rollover their lease bonuses into LNG infrastructure and gas turbine purchases.
The relinquished leases:
OCS-A 0539: RWE paid the highest bonus ever, $1.1 billion, for this lease at theirrational exuberance Atlantic wind sale in Feb. 2022. The amount was $305 million higher than the next highest bonus for any offshore lease.
OCS-G 37334: RWE was the only bidder at the 2023 Gulf wind lease sale. A second Gulf wind sale received no bids.
The wind adverse U.S. Administration offered RWE a lifeline that allows them to reinvest in more prospective projects:
LNG infrastructure: a financial investment of $900 million to acquire an indirect 16% stake in the Louisiana LNG Project. RWE proceeds will be used to fund the construction of the terminal.
Natural gas turbine reservations: To support the expansion of its growing flexible power generation work in the U.S., RWE Americas has signed a $300 million turbine reservation agreement securing future generating capacity to meet growing U.S. electricity demand. The company is developing a pipeline of 15 natural gas peaking projects across target markets in the U.S.
Apparently, the attached letter from 50 U.S. environmental groups asking RWE not to keep their wind leases was not persuasive (and perhaps RWE didn’t appreciate the implied threat of litigation against a deal that was in the company’s best interest).
Per EIA, Gulf of America oil production declined in May by over 200,000 bopd from April’s record production, which was corrected upward by 2000 bopd. Was the April number anomalous? We’ll need additional monthly data and the audited ONRR numbers to get a better read.
EIA posted corrected April and May totals of 30,000 bopd for the Pacific (California OCS), a 150% increase from February owing to the Sable Santa Ynez Unit restart. Although Pacific OCS production has been in the doldrums for years, the region has an impressive record of 202,000 bopd from Dec 1995.
A 7/28/2026 Dept. of Justice brief submitted to the Ninth Circuit Court of Appeals cites the 5/28/2026 Supreme Court decision in Flowers Foods Inc. v. Brock in asserting that Sable’s onshore pipeline segments are interstate and subject to Federal jurisdiction.
This filing is part of multi-faceted litigation involving Federal preemption, a 2020 Consent Decree, emergency special permits, and state environmental concerns. The Ninth Circuit is handling the expedited briefings and consolidation of petitions.
DoJ’s core argument is that Sable’s onshore segments do not interrupt the continuous “flow of commerce” from Outer Continental Shelf (OCS) offshore extraction → onshore processing → further transport to terminals (e.g., in Kern County). Thus, the system qualifies as interstate commerce subject to Federal (PHMSA) oversight rather than state regulation.
The Flowers Foods Inc. v. Brock case considered similar flow of commerce issues. The SCOTUS agreed with the Tenth Circuit that Brock delivery franchisees were engaged in interstate commerce even if they never cross State lines. The gist of the decision is as follows (emphasis added, full decision attached):
The Federal Arbitration Act (FAA) requires courts to enforce many private arbitration agreements, but it also provides that “nothing” in the law shall be used to compel arbitration in disputes involving the “contracts of employment” of any class of workers “engaged in . . . interstate commerce.” 9 U. S. C. §1. This case poses the question whether someone can qualify as a worker under the §1 exemption if he never crosses state lines and never interacts with vehicles that do. Flowers Foods, Inc., is a large producer of packaged baked goods with bakeries in 19 States. To get its products to market, the company depends in part on franchisees who buy the distribution rights to Flowers’s products in specific geographic territories. Angelo Brock is one such franchisee serving the Denver area; he picks up Flowers’s products from a warehouse in Colorado and delivers them to local stores, all without leaving the State. In 2022, Brock sued Flowers in federal district court alleging that the company had underpaid him and other distributors in violation of various federal and state laws. Flowers moved to compel arbitration, arguing that the FAA generally requires courts to stay or dismiss cases when the parties have agreed to resolve their disputes by arbitration and that Brock had signed a distribution agreement promising to arbitrate any disagreement. The district court denied Flowers’s motion, and the Tenth Circuit affirmed. Resting its decision on 9 U. S. C. §1, the Tenth Circuit reasoned that Brock belonged to a class of workers engaged in interstate commerce and thus the court lacked authority to compel arbitration.
We should soon find out what the Ninth Circuit thinks!
GWEC, the voice of the wind industry, continues to scale down estimates for floating turbines. In 2024, the GWEC expected 835MW of floating wind to be installed in 2027. Last year, this was lowered to 278MW, and expectations dropped further in the 2026 report to just 42MW. A similar trend applies to GWEC’s forecasts for the following years.
Despite strong support from the State, California’s offshore wind sector faces major challenges:
Deepwater technology: California offshore wind development is totally dependent on expensive and still unproven floating turbine technology. Norway, once a world leader in floating wind, has lost enthusiasm and is now requiring floating projects to be ‘quality-assured.’
Infrastructure: Major port upgrades, new transmission lines to bring power ashore, and specialized vessels are required. The supply chain is immature.
Costs: High capital costs plus storage costs (e.g. batteries) for reliability.
Two of the three Central Coast wind lessees (diagram below) have agreed to lease buyback deals. A lease cancellation letter is attached. The State is challenging the buyback agreements, and is thus in the difficult position of opposing deals that the wind developers voluntarily agreed to and believe are in their best interest. Does the State lose regardless of the outcome of their challenge?
The third Central Coast lessee, Equinor, is curtailing wind investments and has no plans to pursue new offshore wind projects in the US. A buyback deal with Equinor would be complicated by the company’s Empire Wind commitments, and is probably unnecessary given that Equinor has taken itself out of the game.
The two Northern California leases are still active, but the focus has been on regional planning. Funding for necessary infrastructure projects is uncertain and any wind lease development is far in the future.
The National Defense Authorization Act (NDAA), as passed by the House this week, includes an amendment (attached) authorizing the Federal govt to acquire all lands along the Santa Ynez Pipeline System route. Wesley Hunt (TX), who introduced the amendment, comments in the short video below. The Senate has yet to approve the bill.
Assuming Sable’s attorneys are able to continue navigating through the legal minefield, the success of the project will depend on the performance of Sable’s well operations and production teams, and the extent to which they have the authority and confidence to curtail operations when deemed necessary to protect workers and the environment. In that regard, MMA engineers and inspectors have an important role in identifying risks and assuring that they are mitigated.
Excerpt from the amendment:
SEC. 28ll. ACQUISITION OF EASEMENTS FOR DEFENSE FUEL SUPPLY INFRASTRUCTURE. (a) AUTHORITY TO ACQUIRE.—The Secretary of Defense is authorized to acquire, by purchase, donation, exchange, or condemnation, on behalf of the United States, such permanent easements over all lands along the route of the Santa Ynez Pipeline System, including all lands owned or otherwise held by the State of California or any agency, department, or instrumentality thereof, as the Secretary of Defense determines necessary to ensure continuous pipeline transportation of crude oil from the Santa Ynez Unit to domestic refineries supplying Department of Defense installations in the State of California
The cessation of production at Platform Holly 10 years ago has contributed to the periodic surges in natural seepage that soil Santa Barbara area beaches (see the Instagram post above).
The correlation between production at Platform Holly, which lies just offshore from the Univ. of California at Santa Barbara (UCSB), and seepage in the Coal Oil Point area (map below) was apparent to those who worked at Holly. That association was confirmed by UCSB studies:
“Emeritus Professor James Boles collected and analyzed decades of data on methane seeping from the seafloor southeast of Platform Holly, just offshore from Isla Vista. He and colleagues Grant Garven at Tufts University and Chris Peltonen at Beacon West Energy Group determined that production of oil and natural gas from the platform reduced natural methane seepage into the waters of the Santa Barbara Channel, confirming earlier regional studies. The findings appear in the journal Marine and Petroleum Geology.“
This blog called Platform Holly a “net negative hydrocarbon polluter,“ because production from Holly reduced natural seepage and methane pollution from shallow formations beneath the Channel. Steel subsea pyramids (“tents”) installed by Arco in 1982 collected seafloor methane seepage, an added environmental benefit from the platform operations. As described in a 2014 presentation posted by the California State Lands Commission,“production at Platform Holly has resulted in significant improvement in local air quality.”
Further per UCSB:
After combing through 20 years of data, the authors found that production at Platform Holly significantly reduced the amount of methane seeping into the tents. For example, production from a well drilled 1 kilometer beneath the tents immediately reduced the natural seepage. In contrast, the seepage increased when production ceased from that well. “This indicates a direct link between the oil reservoir and the natural seepage in the area,” Boles noted.
Production at Holly ceased 10 years ago; the tents have been removed and the platform is being decommissioned. However, methane bubbles in the Channel and periodic beach tar will continue to remind us of Holly’s positive environmental legacy.
Map showing areas ( shaded ) of natural oil seeps offshore from Coal Oil Point near Santa Barbara, California. Inset map shows the Channel Islands ( I ) designated SM San Miguel, SR Santa Rosa, SC Santa Cruz, A Anacapa, SN San Nicholas, SB Santa Barbara, and SCL Santa Catalina. Seep fields were mapped between 1946 and 1973 (modified from Hornafius et al. 1999)
Bud's Offshore Energy (BOE) 