“If we continued to fight this out in court, [Sable] likely would have sought to recover lost revenue from the pipeline not being in operation,” said Supervisor Steve Lavagnino. “That could amount to millions of dollars the County would be on the hook for.”
The Environmental Defense Center and others are calling for the County to retract their agreement with Sable and hold a public hearing on the matter. That appears to be unlikely.
Remaining hurdles for Sable include approval by the State Fire Marshall after the valves are installed and operational, State Lands Commission approval of lease assignments from Exxon to Sable, and approval of the oil spill contingency plan by the State Dept. of Fish and Wildlife.
Sable believes they can resume production this year. That seems unlikely, but a 2025 restart is now a distinct possibility.
Sable’s stock price soared after the company reached an agreement with Santa Barbara County that will allow them to comply with the California Fire Marshall’s requirement to install shutdown valves on the onshore pipeline that failed in 2015. That pipeline is necessary to transport production from the Santa Ynez Unit, which is currently operated by Sable.
The significance of a resumption of SYU production is illustrated in the chart below. The 3 SYU platforms accounted for more than 2/3 of Pacific OCS production before the Refugio pipeline spill in June 2015.
This agreement with the County is a major step forward, but there are still regulatory and legal hurdles to clear before production resumes.
In the SEC filing that announces the agreement with Santa Barbara County, Sable affirms their 2024 restart expectations. However, a resumption of production in 2024 is highly unlikely given the administrative challenges that remain. A restart in 2025 would be a major accomplishment and a very good outcome for Sable.
Pasted below is the full text of the SEC filing (emphasis added):
Santa Barbara County (the “County”), on August 30, 2024, acknowledged that the County does not have jurisdiction over Pacific Pipeline Company’s (“PPC”) installation of 16 new safety valves in the County along PPC’s Las Flores Pipeline System (the “Pipeline”) in accordance with Assembly Bill 864. The County’s acknowledgement was delivered in the form of a conditional settlement agreement dated August 30, 2024 (the “Safety Valve Settlement Agreement”) among the County, PPC and PPC’s parent company Sable Offshore Corp. (“Sable”), and a subsequent acknowledgement by the County’s planning and development staff.
The Safety Valve Settlement Agreement is predicated upon a prior settlement agreement between PPC’s predecessor in interest, Celeron Pipeline Company, and the County in a federal case styled Celeron Pipeline Company of California v. County of Santa Barbara (Case No. CV 87-02188), which was executed in 1988.
Pursuant to the Safety Valve Settlement Agreement, PPC agreed to the following additional surveillance and response enhancements in the County:
i. PPC will create a Santa Barbara County-based Surveillance and Response Team, trained in PPC’s Tactical Response Plan, which will be responsible for timely initial incident response and equipped with key resources to deploy in early containment, particularly for those regions of the Pipeline between Gaviota and Las Flores Canyon;
ii. PC will provide Santa Barbara first responders with additional training and equipment to assist in PPC’s incident response efforts; and
iii. PPC will undertake the following Pipeline system enhancements: (1) install and operate and maintain primary and secondary Operations Control Centers in Santa Barbara County, and (2) refurbish the Gaviota pump in its existing station.
PPC, Sable and the County have further agreed, in the Safety Valve Settlement Agreement, to file a stipulation to dismiss the pending lawsuit, Pacific Pipeline Company and Sable Offshore Corp. v. Santa Barbara County Planning Commission and Board of Supervisors (Case No. 2:23-cv-09218-DMG-MRW) within 15 days of final installation of all 16 underground safety valves in the County.
Sable affirms that initial restart of production from Sable’s Santa Ynez Unit is expected in fourth quarter 2024.
An assessment prepared for Hunterbrook Capital draws the same conclusions regarding the prospects for production, calling the restart “a pipe dream” (presumably the pun was intended given the pipeline permitting quagmire). Hunterbrook’s chart (pasted below) illustrates the regulatory labyrinth facing Sable.
Hunterbrook has also flagged Sable’s ability to continue as a “going concern.” That may be a valid concern, but Sable’s success is very much in Exxon’s best interest. Exxon must have evaluated Sable and been comfortable with their management. Otherwise, they wouldn’t have made the deal.
Does Exxon want the massive SYU headache to revert back to their portfolio, as provided for in their agreement with Sable, if production doesn’t restart by January 1, 2026? Unless Exxon thinks they have a better option than Sable, they will presumably be flexible about the deadline.
Meanwhile, a judge denied the temporary restraining order requested by Sable to prohibit release of redacted portions of their oil spill contingency plan. Sable had argued that revealing “trade secrets” and specific locations and vulnerabilities of the pipelines could pose a “threat to national security.”
Earlier this month we awarded a Chutzpah Award to groups that helped block every attempt to resume production in the Santa Ynez Unit and are now suing to terminate the leases for non-production.
We now learn that the State Fire Marshall has rejected the resumption of production because Sable, the current operator, is not installing automatic shutdown valves on the oil pipeline. The catch is that Sable was denied permits needed to install the valves. So, on the one hand the Fire Marshall is requiring shutdown valves (a reasonable requirement), and on the other hand the County is prohibiting the installation of those valves!
According to the Fire Marshall’s office, this is the first time a company has been denied permits to install valves mandated by the State – yet another dubious distinction for the Santa Ynez Unit.
Followers of the US OCS oil and gas program have observed some impressive chutzpah over the years, but a new law suit challenging the extension of Santa Ynez Unit leases raises the bar.
Groups that helped block every attempt to resume production in the Santa Ynez Unit are now suing to terminate the leases for non-production.Brilliant!🥇
“Without these extensions, each of the leases would have expired and ExxonMobil would have been required to permanently cease its oil and gas operations, plug its wells, and decommission its other infrastructure.”See the full text of the law suit.
The limited media coverage of the lawsuit originated from a single Reuters article. Apparently Reuters learned about the suit and reached out to the litigants. Their article quoted Louisiana Attorney General Liz Murrill as follows:
“This is a really egregious direct assault on intermediate level producers of oil and gas, and that affects a lot of business in our state,” Murrill told Reuters in an interview.
That quote is all we have from the AGs. Why the absence of announcements:
Interest in working with industry and the Federal govt to seek policy solutions that best address OCS decommissioning issues? (This would be encouraging.)
State of Louisiana, Louisiana Oil & Gas Association, State of Mississippi, State of Texas, Gulf Energy Alliance, Independent Petroleum Association of America and U S Oil & Gas Association
Defendant:
Deb Haaland, U S Dept of Interior, Bureau of Ocean Energy Management, Elizabeth Klein, Steve Feldgus and James Kendall
Case Number:
2:2024cv00820
Filed:
June 17, 2024
Court:
US District Court for the Western District of Louisiana
Presiding Judge:
James D Cain
Referring Judge:
Thomas P LeBlanc
Nature of Suit:
Other Statutes: Administrative Procedures Act/Review or Appeal of Agency Decision
Cause of Action:
28 U.S.C. § 2201 Constitutionality of State Statute(s)
California State Lands Commission decision on the pipeline right of ways (ROWs) in state waters. (Those ROWs had expired.)
Transfer of leases to Sable – Environmental groups, the California Coastal Commission and/or other parties could file suit challenging the transfer of the leases to Sable.
According to John, the question is not whether production will resume in 2024, but whether it will ever resume. And John reminds us that as of 1/1/2026, the SYU and all of the headaches revert to Exxon. See the SYU overview below:
Decommissioning financial assurance issues are complex!
This blog has raised significant concerns about BOEM’s decommissioning financial assurance rule, and will continue to comment on decommissioning policy. That said, decommissioning issues are complex and have challenged industry and government in the US and internationally for decades. Add well plugging practices, corrosion, storm risks, reefing vs. total removal, alternative uses for old platforms, and pipeline and seafloor equipment abandonment to the myriad of financial issues and you get a sense of the breadth and complexity of decommissioning issues.
Decommissioning is unique in that the issues divide sectors of the offshore industry that are typically aligned (majors vs. smaller producers). The environmental community is also divided with the reefing and fishing advocates opposing those who insist on complete removal.
Given these divisions, and decommissioning’s operational, environmental, and political complexities, highly partisan assertions are common. A recent article about the financial assurance rule includes a number of such assertions, and provides a framework for discussing some of the more prominent issues. Excerpts from the article and my comments follow.
“This costly rule became final on April 15, 2024, but in the 10 months since its initial proposal, BOEM did nothing to alleviate concerns for smaller companies that comprise of 76 percent of oil and gas operators in the Gulf.“
Comments:
While I concur that shelf operations and the independent companies that conduct them are important, 94% of OCS oil production and 80% of the gas (2023 data) were from deepwater facilities (>1000′ WD) which are largely the domain of the majors (although the participation of independents in the deepwater sector is increasing).
In 2023, four majors – Shell, bp, Oxy (Anadarko) and Chevron – accounted for 2/3 of the Gulf’s total oil production.
1467 of the remaining 1527 GoM platforms are in <1000 feet of water and are almost exclusively operated by small producers. So 96% of the platforms are producing only 6% of the oil and 20% of the gas.
This dichotomy presents a major challenge for BOEM which must protect the public from decommissioning liabilities without unfairly penalizing small producers.
Having worked for respected political appointees from both parties, my experience has been that the smaller producers (somewhat surprisingly) have more political influence than the majors. For this reason, along with the general lack of attention to financial assurance issues in the early years of the offshore program, the standard bond requirement was ridiculously low for much of the program’s history, and supplemental financial assurance assessments were typically inadequate (and still are which is why the new rule was promulgated).
Attention to decommissioning issues grew exponentially in the early 1990s. Prior to that time, platform removal, like well plugging, was classified as “abandonment,” a term that was considered too harsh when bankruptcy issues and the Brent Spar controversy in the North Sea attracted worldwide attention.
“Records obtained via the Freedom of Information Act show private meetings between Interior officials and representatives of the major oil companies as they cooperated on this rule.“
Comments:
The linked FOIA records are not at all problematic. They pertain to meetings prior to the publication of the draft rule, which are appropriate and desirable.
Some of these meetings were in response to BOEM’s request for input regarding their review of the OCS oil and gas program. Such meetings are particularly helpful when a new administration is trying to assess the direction of the program.
Indeed 42 of the 71 pages in the FOIA were official industry comments in response to the BOEM request.
Per the Regulations.gov docket on the financial assurance rule, BOEM also met with stakeholders after the proposed rule was published. Those meetings are allowed as long as the regulator simply receives input and does not signal decisions regarding the content of the final rule.
The docket shows that BOEM had 8 listening sessions with advocates for independent producers. These included 2 sessions with the Gulf Energy Alliance and 6 sessions with individual independent producers.
BOEM also had 2 listening sessions with Oceana, a prominent environmental organization, and multiple sessions with tribal organizations.
The only sessions with representatives from major producers were a single session with API and a single session with Shell, the Gulf’s largest producer.
These meetings (after the proposed rule was published) are noted in the docket as required.
I am concerned that many listening session documents (from all sides of the decommissioning financial assurance issue) were removed from the docket at the direction of OIRA/OMB, purportedly because they included privileged information. This is rather troubling given the number of deletions and the complete absence of information about those meetings. What types of privileged information were these organizations providing and why is there no information whatsoever on these meetings? At a minimum, a list of attendees and general summary for each meeting should have been posted, as was our practice in the past.
“Big Oil must think it won’t miss the small competitors the rule will drive from the market.“
Comments:
There is important synergy between the major producers and independents, and no reason for driving smaller companies from the market.
The independents are critical to sustaining the shelf infrastructure and the associated service companies, which helps to facilitate deepwater development. Majors also benefit from partnering with independents on lease acquisitions, development projects, and lease assignments.
Financial assurance for decommissioning of transferred assets is the one area of significant conflict, particularly when there have been multiple ownership changes since the facilities were initially transferred.
“Historically, joint and several liability protected these small businesses from the financial demands of surety bonds.”
Comments:
Surety bonds, or other forms of financial assurance, have always been required. As previously noted, the amounts were often inadequate.
Joint and several liability was not established in the regulations until May 22,1997. Whether companies are liable for facilities transferred prior to that date has yet to be considered in court.
1130 of the 1527 remaining GoM platforms were installed prior to May 22,1997. Many of these platforms were no doubt transferred prior to that date, which means the liability of the initial owner is uncertain.
Predecessor liability does not apply to new wells and platforms constructed by the current lessees.
Joint and several liability was never intended to relieve current lessees from their financial assurance responsibility, which is why assignors were required to provide such assurance. BOEM is correct in strengthening their enforcement of this requirement.
“The new rule is largely silent on joint and several liability, causing some uncertainty.”
Comment: The joint and several liability provision remains in place at 30 CFR 250.1701(a) BOEM has added language to part 556.704, to clarify, correctly in my opinion, that they may withhold approval of any transfer or assignment of any lease interest if the financial assurance requirements have not been satisfied.
Companies may not be able to acquire the needed financial assurances because the market likely will not even exist.
Comment: The history of small producer failures is no doubt a concern to financial institutions. BOEM offers multiple financial assurance options, some of which have been questioned on this blog. If a company can’t qualify, it’s not the responsibility of the public to assume their decommissioning risks.
What makes matters worse is that all this cost covers a risk that is effectively a rounding error historically and in the context of the royalties flowing from the offshore oil and gas industry. According to BOEM, taxpayers have borne decommissioning liability totaling $58 million – from a single company that lacked predecessor owners of the platform to call on to cover unfunded cleanup costs.
Those who seek to minimize the Federal government’s risk exposure should consider the findings in the 2024 GAO report. Per that report, “BOEM held about $3.5 billion in supplemental bonds to cover between $40 billion and $70 billion in total estimated decommissioning costs as of June 2023.”
When will we find out who will be paying the hundreds of millions needed to decommission long-idled Platforms Hogan and Houchin in the Santa Barbara Channel?
Decommissioning financial assurance is a responsibility of lessees, not the taxpayer.
Bud's Offshore Energy (BOE) 