As illustrated in the charts below, Cox has the distinction of being the Gulf of Mexico (world?) leader in aging offshore platforms. Per BOEM data, Cox (includes affiliates Energy XXI GOM and EPL) operates more than 1/4 of all GoM platforms. 44% of these platforms were installed prior to 1980, 114 of which are major structures (defined in notes below). 27 of these major structures were installed prior to 1960!
Notes: (1) A major structure contains at least 6 well completions or more than 2 pieces of production equipment. (2) The platform numbers in an earlier post are incomplete in that they include only structures with helidecks.
Along with Cox Operating, six affiliates also filed: MLCJR , M21K, EPL Oil & Gas, Cox Oil Offshore, Energy XXI Gulf Coast, and Energy XXI GOM.
The BOEM platform data base lists only Cox Operating (276 platforms), EPL (10 platforms), and Energy XXI GOM (26 platforms) as current operators of OCS platforms. However, according to the Cox Operating website, the company operates 600 producing wells on 500 structures. Presumably, ~200 of those structures are in State waters.
In 2020, the OPEC price war drove oil prices down, while stay-at-home orders and well shut-ins associated with the COVID-19 global pandemic sharply reduced production.
The debtors’ assets suffered significant damage from five named storms and hurricanes during 2020 and 2021, leading to further reductions in production. Comment: According to BSEE, 7 tropical systems affected GoM operations in 2021, so the number of storms is not in dispute. The extent to which maintenance or preparedness issues contributed to the damage is unknown.
In 2020, a foreign-flagged vessel struck a platform owned by one of the debtors resulting in major damage and substantial losses of production. Comment: Apparently, this is the incident being cited. According to the BSEE report, the operator (Cox) was not at fault. Per BSEE: (1) The navigational lights and foghorn on the platform were maintained and in operational order, (2) the allision was not due to any platform related error, and (3) the platform’s operator and safety system responded in accordance with the regulations.
At this time, the debtors’ production volume is half what it was in 2019. Comment: Comparing the 2019 and 2022 production data, OCS oil and gas production are down by about 30% and 40% respectively. However, the 50% reduction figure seems reasonable given the likelihood of further reductions in State water production and in 2023.
A Metairie-based oil company that’s one of the largest independent operators still working in the state’s shallow coastal waters has filed for bankruptcy protection, leaving dozens of south Louisiana service and supply companies facing potential bankruptcies of their own.
Bankruptcy court documents show Cox’s estimated liabilities are close to $500 million – more than $200 million of which is owed to small businesses in the Houma-Thibodeaux and Acadiana areas.
Court documents indicate that Cox followed a path that led to financial trouble for other companies in recent years: using debt to acquire large fields of aging wells in shallow Gulf waters.
This blog is primarily concerned with the potential impacts of the bankruptcy on safety performance, the plugging of wells, and the decommissioning of old facilities. Per BOEM’s data base, Cox currently operates 276 Gulf of Mexico platforms, all in shallow shelf waters. The company is reported (Nola.com) to owe $8 million in bond premiums needed to support well plugging operations.
Cox has not been an active driller of late with only 2 well starts since 1/1/2022 (BSEE borehole file).
Cox has been a major generator of INCs (incidents of noncompliance) with 437 INCs YTD. Cox has been responsible for 47% of all GoM INCs in 2023. Cox’s INC to inspection ratio was 2.46 vs. a combined ratio of 0.50 (490/972) for all other GoM operators.
Cox is currently ranked 11th and 18th respectively in GoM gas and oil production with 7.2 billion cu ft and 1.8 million barrels produced YTD.
Platforms Hogan and Houchin: These platforms are currently being manned, monitored and maintained as part of an agreement between BSEE, BOEM, DOI Solicitors Office, and the three predecessor lessees as they await a decision on the predecessors’ appeal to the IBLA. BSEE estimates an approximately $5 million deficit in financial assurance to decommission 21 orphaned sidetrack wells associated with these platforms.
Although the status of the decommissioning account for these platforms has not been disclosed, permanently abandoning these 21 wells will be costly. if the over/under is an additional $5 million, bet on the over.
After the wells are plugged, the platforms have to be removed at great cost to someone (hopefully not the taxpayer), and when will the matter of who pays finally be resolved?
When will the 9/20/2020 Inspector General report that found significant irregularities in the use of the decommissioning escrow funds be made publicly available?
The data in the paper appear to be reasonably accurate. However, there is one glaring error regarding Pacific operations, and the reference to the Macondo blowout in the environmental discussion is rather provocative and misleading.
Per the authors:
California wells are drilled in relatively shallow water—mostly less than 100 feet—while GoM wells can be in up to 10,000 feet of water.
With regard to the environmental risks, the Nature Energy paper’s reference to the Macondo blowout, while muted, is what some media outlets embraced. Per the authors:
Releases from improperly abandoned wells will probably be chronic and small compared with Macondo, but the underlying biochemical and ecological processes that influence the ecological impacts have many similarities.
The Macondo well blew out while it was being suspended in preparation for subsequent completion operations. Ill advised changes to the well suspension plan were among the primary contributing factors to the blowout (see diagram below). The Macondo well was entirely different from the depleted end-of-life wells that are the subject of the paper.
Some media outlets ran with the Macondo angle, weak as it was. This ABC news piece featured numerous Macondo pictures. Other outlets noted that Macondo was a temporarily abandoned well, which it was not. The Macondo well never got to that point.
National Commission, Chief Counsel’s Report, p. 132
“BSEE will continue to evaluate the process for issuing decommissioning orders and will continue to issue decommissioning orders to jointly and severally liable parties on a case-by-case basis.“
Although the news release for BSEE’s final decommissioning rule asserts that the regulations “provide the certainty requested by industry,” that does not seem to be the case. The main change in the final rule was to delete the reverse chronological order (RCO) provision which called for issuing decommissioning orders to the most recent predecessor first. Instead, BSEE may continue to issue decommissioning orders arbitrarily.
While deleting the RCO provision may be advantageous for the regulator, and in some cases for the public, claiming that the decision provides certainty for industry is quite a stretch. BSEE may continue to issue a decommissioning order to anyone in the ownership chain, whether the company was a recent lessee or one that had owned the lease decades ago. Original or early lessees may be held liable for decommissioning old facilities regardless of subsequent damage, modifications, or neglected maintenance.
The absence of a defined procedure for issuing decommissioning orders may also expose BSEE to new legal challenges, particularly in cases where a company has not held the lease for decades. A 1988 letter from the Director of the Minerals Management Service to Amoco (attached below) explicitly relieves the assignor (predecessor) of decommissioning liability after the lease has been assigned. A revised bonding rule published on May 22, 1997 reversed that policy, but decommissioning liability for leases assigned prior to the 1997 rule may still be very much in question.
Another concern is the split jurisdiction for decommissioning between BSEE and BOEM. The financial, land management, operational, and environmental aspects of decommissioning are inextricably intertwined and attempts to divide these responsibilities between two bureaus with separate regulations is a prescription for gaps, overlap, inconsistency, inefficiency, disputes, and confusion. Decommissioning should be regulated holistically, not with separate “BOEM-only” and “BSEE-only” regulations.
Finally, wind facility decommissioning may prove to be even more challenging given the higher facility density and economic uncertainties. The regulatory regime needs to be clearly established early in the development phase.
With this deal, Exxon is essentially lending Flame, Sable’s management team and PIPE investors the money to buy the facilities from itself. If they are able to get them back online, great, Exxon gets its $623 million loan paid back with 10% interest. If not, it presumably repossesses the facilities and their associated headaches.
My former colleague John Smith, an expert on Pacific Region decommissioning, advises me that production has ceased at Platform Irene in the Santa Maria Basin offshore California. Irene, the first platform installed in the Santa Maria District in 1985, was a milestone in Pacific OCS development.
Only 7 of the 23 Pacific OCS platforms are still producing. Attached is an updated summary table that John prepared for an upcoming SPE event in Alaska.
Carbon-Zero US LLC of Dallas (a Cox Oil affiliate) has applied for up to $12 million in U.S. Department of Energy funds to develop a pilot sequestration hub in offshore storage fields about 20 miles from Grand Isle, according to officials from Cox Operating LLC, the Dallas operator that owns some of the storage fields.
Cox Operating LLC will “repurpose facilities and equipment” for the carbon storage project, according to a news release.
Should this company be authorized to repurpose Gulf of Mexico facilities for carbon sequestration?
Per BSEE Incident of Non-Compliance (INC) data for 2022, Cox had more component shut-in INCs (132) than any other company. Cox was second to the Fieldwood companies in the number of warning and facility shut-in INCs, and in the total number of INCs. 48% of the Cox INCs required either a component or facility shut-in.
Cox had an INC/facility-inspection ratio of 0.77, nearly 50% higher than the GoM average of 0.53.
Per the posted BSEE district investigation reports for 2022, Cox was responsible for 9 of the 30 incidents that were significant enough to require investigation. That is more than twice as many as any other company (next highest was 4).
The incidents included 3 serious injuries, 2 fires, a large gas leak, and oil spills of 114, 129, and 660 gallons. Per the posted reports, only one other company had an oil spill of >1 bbl. (Note: Only spills of > 1 bbl are routinely investigated by BSEE. One bbl = 42 gallons.)
While INCs were issued for only 3 of the 9 Cox incidents, a review of the reports suggests that INCs should have been issued for at least 4 of the other incidents.
Cox operates 375 platforms with installation dates as early as 1949. 134 of their platforms are > 50 years old. Only 66 were installed in the last 20 years and only 6 in the last 10 years (most recent December 2014). How will the carbon sequestration plans affect their massive decommissioning obligations?
Many of the Cox platforms were assigned by predecessor lessees. Those predecessors can only be held responsible for the decommissioning of facilities they installed, not for more recent wells or platforms and not for facilities that are repurposed for carbon sequestration.
Also, as noted in the discussion of Exxon’s 94 Sale 257 oil and gas leases, a competitively issued alternate use RUE is required (30 CFR § 585.1007) before sequestration operations may be conducted on an oil and gas lease.
Bud's Offshore Energy (BOE) 