The Santa Barbara County Planning Commission has approved the transfer of the onshore pipeline from Exxon to Sable Offshore. Although the Environmental Defense Center (EDC) is appealing that decision to the Board of Supervisors, the Board’s vote will likely be a 2-2 tie. Supervisor Hartmann’s property is close to the pipeline and she has recused herself from votes on the matter. A 2-2 vote would be a win for Sable, because a tie vote means the planning commission decision stands.
As an investment, Sable is a “pure California permitting play,” which means the risks are high. The company’s chances for success are almost entirely dependent on receiving the necessary approvals from State and local agencies.
Sable’s share price soared to $23.43 on 9/3 after the company reached agreement with Santa Barbara on the installation of required pipeline valves. The price bounced further to $28.30 on 9/19 before falling sharply to $19.43 on 10/9 after being cited for failing to get California Coastal Commission approval to install the required valves. The price rebounded to $24 following the County Planning Commission’s approval of the transfer from Exxon to Sable before settling at $23 on Friday, the date of the EDC appeal.
Expect the financial and psychological roller coaster ride to continue.
199 oil and gas leases were wrongfully acquired at Sales 257, 259, and 261 with the intent of developing these leases for carbon disposal purposes. Repsol was the sole bidder at Sale 261 for 36 nearshore Texas tracts in the Mustang Island and Matagorda Island areas (red blocks at the western end of the map above). Exxon acquired 163 nearshore Texas tracts (blue in map above) at Sales 257 (94) and 259 (69).
Despite false starts by Exxon and Repsol (see above summary), no carbon sequestration (disposal) leases may be issued or developed until implementing regulations have been promulgated. In that regard, no news is good news for those who are less than enamored with CO2 disposal in the Gulf of Mexico.
The implementing regulations will be controversial. Most operating companies prioritize GoM production over GoM disposal. Most environmental organizations are strongly opposed to CO2 disposal schemes that sustain fossil fuel production and benefit fossil fuel producers. Taxpayers are leery of subsidizing these projects and absorbing increased costs for energy and consumer goods.
The Administration is, of course, well aware of this opposition and will not be publishing implementing regulations prior to the election. The next Administration, regardless of the election outcome, will no doubt take a hard look at these issues before proposing regulations.
The few oil and gas producers that are rather cynically hoping to cash in on CO2 disposal in the GoM will therefore have to wait, perhaps for a long time.
Platform Holly, California State waters in the Santa Barbara Channel, formerly operated by Venoco
Platform Holly sits immediately offshore from the Univ. of California at Santa Barbara, and UCSB scientists have studied the platform and surrounding ecology extensively. Multiple studies have shown that production from Holly reduced natural seepage and methane pollution from shallow formations beneath the Channel. Platform Holly was thus a “net negative” hydrocarbon polluter.
The natural seepage in the Santa Barbara Channel was important to the earliest inhabitants of the area. The Chumash used the tar for binding and sealing purposes, including caulking their canoes. Since Holly shut down in 2015 following the Refugio pipeline spill, offshore workers and supply boat crews have reported a considerable increase in gas seepage.
Earlier this month, it was reported that well plugging operations at Holly had now been completed, but decisions regarding the final decommissioning of the platform remain.
Venoco declared bankruptcy in 2015 and the State of California became the platform owner. According to the State Lands Commission, Exxon will pay the costs for decommissioning the platform. This is because Exxon acquisition Mobil operated the platform from 1993-1997 before Venoco became owner.
The most recent Holly development is that Venoco has settled its law suit with Plains, the company responsible for the 2015 Refugio pipeline spill that halted production from Holly. Terms of the settlement have not been disclosed.
Note: As an aside, I’m curious as to whether Mobil provided a decommissioning guarantee as part of the sale to Venoco or whether the State is simply holding ExxonMobil accountable as a legacy owner. If it’s the latter, why isn’t bp (bp acquisition Arco was Holly’s operator from 1966-1993) also liable? Is it a matter of Mobil being the more recent predecessor owner?
While exploration technology has improved significantly, the success rate for wildcat exploratory wells is still only about 30%. According to Rystad, only eight of the 27 high-impact wells drilled in 2023 resulted in commercial discoveries.
In baseball terms, the smaller independents are typically singles hitters, drilling development wells and gleaning reserves from established fields. The majors tend to be home run hitters. They swing hard and often miss, but when they hit, the rewards are great!
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.
Chevron slide: Advances in seismic imaging help characterize deepwater development opportunities
A new JPT article features comments from BOE contributor Lars Herbst on advances in HPHT technology, control systems, sensors and transmitters, and automation that are facilitating the next era of deepwater development.
Well capping technology, which provides a tertiary well control capability, is an essential element of post-Macondo exploration and development. Lars points to the importance of BSEE’s unannounced drill program to verify that capping stacks can be transported and installed in a timely manner. Chevron expresses pride in leading a team that deployed and installed a capping stack in 6,200 feet of water in a drill monitored by BSEE. During that drill, a remotely operated vehicle (ROV) closed 10 valves to shut in a simulated well.
Exxon’s Jayme Meier aptly characterizes the challenge and excitement of deepwater development:
“You are floating on a surface, and you have to be able to pinpoint exactly where you’re going to land subsea hardware, exactly where you’re going to moor an FPSO and hit target boxes that are a few feet by a few feet, and they’re 6,000 ft below you,” she said. “It is the most exciting thing that I’ve ever been involved in. And it involves technology, technical know-how, and an ability to really plan the base plan and the contingency plan.”
Advances in deepwater technology are indeed impressive, but continuous improvement must always be the objective. In that regard, Lars rightfully emphasizes the importance of sustaining research through the industry’s up and down cycles.
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.”
To find the sole exploratory well being drilled in the vast North American Atlantic, you have to exit “wind-only” US waters, head NE to St. John’s, NL (advancing your watch by 1.5 hours 😉), and transit another 317 miles NE to the Stena DrillMAX working for Exxon in the Orphan Basin.
The latest (8/20/2024) CNLOPB report (below) is that operations are ongoing. The well was spudded 3 months ago. That is about all they can disclose without compromising confidentiality. Even seemingly innocuous information like the current and projected well depth provides the opportunity to speculate about geologic conditions and current well activities.
Reuters has published an interesting article on the Exxon/CNOOC vs. Chevron/Hess dispute scheduled for arbitration next year in Paris. According to Reuters (emphasis added):
“Getting the panel to consider the appraised value is central to Exxon’s claim that the deal is an asset acquisition disguised as a merger. Exxon believes the Guyana asset is so valuable that the merger would trigger a change of control and give Exxon and CNOOC a right of first refusal to the asset sale, the people said.“
The Exxon argument implies that Hess’s only major asset is its share of Stabroek, which is hardly the case. Hess’s 30% Stabroek share is without question an important asset with great long-term potential, but Hess is also a major player elsewhere, most notably in the Bakken formation in North Dakota and the Gulf of Mexico. Implying that Hess was a single asset acquisition is thus misleading:
In Q4 of 2023, Hess produced 194,000 boepd in the Bakken formation vs. a Stabroek share of 128,000 bopd.
In 2023, Hess produced 20 million barrels of oil in the GoM and 40 bcf of gas making them the 8th highest oil producer and 7th highest gas producer.
Hess acquired 20 GoM leases in Sale 261, ranking first in total high bids ($88 million) among all participants.
Chevron and Hess GoM assets have significant potential for synergy. The combined company would be the 3rd largest GoM oil producer (behind Shell and bp) and the second largest gas producer (behind only Shell).
This dispute will continue to smolder given the delay in the arbitration hearings until May 2025. As previously mentioned, I believe the Government of Guyana should have intervened. I’m all for companies settling their disputes privately, but this dispute is over Guyanese resources, and the protracted delay could have implications for Guyana.
An International Chamber of Commerce panel has set a May 2025 date for the hearing on the dispute over Chevron’s acquisition of Hess’s share of Guyana’s Stabroek field. This is a massive delay considering the impact of this arbitration case on Chevron’s purchase of Hess.
As noted in a previous post, the Exxon/CNOOC position seems to be a stretch. Chevron did not buy the Stabroek share; they bought the company that holds that share. Hess is to be part of Chevron and there would be no change of control from the standpoint of the partnership. The panel will decide, but given the May 2025 hearing date, we probably won’t know the outcome for a year.
The Guyanese government has not taken a position in this dispute, but in my opinion, there are reasons for them to be concerned. Stabroek is Guyana’s offshore gem, their most important economic asset. The dispute has to affect teamwork and communication.
From safety, environmental, and production standpoints, do you want feuding partners managing such an important national asset? Those are Guyanese resources that the Stabroek partners are licensed to produce. I would have liked to have seen the government tell them to get this resolved in 30 days or we’ll resolve it for them.
Bud's Offshore Energy (BOE) 