Of particular interest are mandated reviews of the:
RIsk Management and Financial Assurance Rule: Those who want to gut this rule should come to the table with proposals that better protect the taxpayer from decommissioning liabilities. Pretending that decommissioning financial risks don’t exist or that they are someone else’s (or the govt’s) problem is unacceptable.
5 Year leasing program – This review is urgently needed. See this and this!
BOP/Well Control Rule – This keystone safety rule has undergone multiple reviews in recent years. Because of the rule’s importance, further review for continuous improvement purposes may nonetheless be warranted. Here are the blog comments on the current version of the rule.
After a zero fatality year in 2023, the first in at least 60 years, Jason Mathews of BSEE advises that one worker was killed during US OCS oil and gas operations in 2024.
The fatality occurred during decommissioning operations on the Helix D/B EPIC HEDRON at Talos Energy’s Ship Shoal Block 225 “D” platform in the Gulf. The platform was to be reefed in Eugene Island Block 276.
The victim, who worked for Triton Diving Services, was moving hoses on the port side of the barge and got caught between the bulwark and counterweight of the crawler crane (see picture below).
The victim’s family have filed a wrongful death lawsuit against Helix Energy Services and Triton Diving Services. The plaintiffs assert that prior to the crane movement the crane operator and crew had not undertaken measures to assure that the crane’s swing area was clear of other crew members. Per their filing, Triton and Helix were negligent as follows:
As expected, the White House announced the largest ever permanent ban on offshore oil and gas leasing in the US, and to the best of my knowledge, anywhere in the world.
The sheer magnitude of the ban makes other such withdrawals appear modest by comparison. It’s amazing how bold Presidents (and their handlers) become when they are about to leave office.
The permanent ban includes:
The entire Atlantic Outer Continental Shelf (OCS): While there are no current oil and gas leases in the US Atlantic, the region is highly prospective and could contain more than 20 billion barrels of oil equivalent (BOE).
The Eastern Gulf of Mexico: This is the OCS area that many petroleum geologists find most attractive. The best prospects are >100 miles from shore which minimizes coastal risks, and the high natural gas potential aligns with Florida legislation supporting the use of gas for power generation.
The entire Pacific OCS: While the resources are substantial, their loss has been a foregone conclusion for 25 years. When you can’t even decommission old platforms or restore production on important existing facilities (i.e. the Santa Ynez Unit), how can you possibly expect to issue new leases?
The remainder of the OCS offshore western Alaska. The wishes of the majority of Alaskans, who support offshore exploration and development, have been largely ignored for decades.
President-elect Trump has vowed to reverse President Biden’s leasing ban, but that may not be so easy. This is not a matter of simply reversing an executive order. Sec. 12(a) of OCSLA grants the authority to withdraw lands to the President and does not provide for reversal by future Presidents. The attached NYU Law brief concludes that “a subsequent president lacks authority to restore previously withdrawn lands to the federal oil and gas leasing inventory.”
The new Administration will no doubt have a different view than that expressed in the NYU Law brief, but any reversal decision will likely be challenged in court.
Those who wrote and approved Sec. 12(a) should have had more foresight. However, 72 years ago the authors presumably thought Presidents would only use the authority to remove small, especially sensitive areas from leasing consideration, and never thought that a President would remove both of our oceans and much of the Gulf of Mexico!
Congress could of course reverse the Biden bans, but given the complexity of offshore energy issues, such legislation may be difficult to pass.
Commonwealth Fusion Systems (CFS) will independently finance, build, own, and operate a grid-scale fusion power plant in Chesterfield County, Virginia.
Dominion Energy will provide non-financial collaboration, including development and technical expertise as well as leasing rights for the proposed site.
This pioneering plant will generate 400 MW of continuous energy on 25 acres (total site is 100 acres). By comparison, Dominion Energy’s offshore wind project, which will include 176 turbines and 3 offshore substations, will intermittently produce (on average) 1092 MW (2600 MW x 0.42 capacity factor).
Gov. Youngkin emphasized that the project will be financed entirely by CFS, with no costs passed on to Dominion Energy ratepayers. (Good news for us Dominion Energy customers! 😀)
Fusion technology works by combining hydrogen isotopes — deuterium extracted from water and tritium from lithium — under extreme heat and pressure, using powerful magnets to fuse the elements. The process generates heat, which boils water to create steam that spins a turbine, producing electricity. The byproduct is helium.
Why BOE, and most everyone else, likes nuclear fusion:
Clean and sustainable power source.
Unlike traditional nuclear power plants that rely on fission, fusion replicates the energy-producing process of the sun.
Modest space requirements.
Generates four times more energy per kilogram of fuel than fission and nearly four million times more energy than burning oil or coal.
No radioactive waste
Safe energy source; no risk of a meltdown event
Nuclear Regulatory Commission has determined that fusion technology, unlike fission, does not require a federal license.
The implications of advanced nuclear technology, not only the holy grail of fusion energy, but also modular fission reactors, for intermittent wind and solar power are substantial.Ultradeep geothermalis on a similar timeframe, and could also supersede wind and solar.
The logic behind costly offshore wind projects is therefore questionable, and the regulators better make sure that the decommissioning of these facilities is fully funded. The most likely long-term scenario is for natural gas to continue meeting most power generation needs as the nuclear and ultradeep geothermal alternatives are phased in.
More about fusion. Most of you can start at Level 3. 😉
Forbes (USGS map of active wind turbines): “The U.S. Wind Turbine Database contains more than74,695 wind turbines built since 1980, spread between 1,699 wind power projects in 45 states. However, thousands of wind turbines are reaching the end of their operational lifespan and need to be either repowered to make way for updated (often larger) turbines or entirely decommissioned to allow for new uses of the land they occupy. Unfortunately, there is no uniform legal framework to regulate the steps involved, nor is there an accepted industry-wide set of best practices, and the environmental costs are considerable.”
Forbes: “As is often the case when new technologies come to market, unintended downstream consequences are not always immediately obvious to the players. Enthusiasm for clean energy initially pushed the first wind turbines into existence in the U.S. without considering the environmental and monetary costs that would be involved in either upgrading or bringing projects to a close later in their life cycle. “
“At the heart of the dispute are rules from the federal Bureau of Ocean Energy Management – BOEM – which require energy producers in the Outer Continental Shelf to provide a bond to pay for well, platform, pipeline and facilities cleanup if the operating company fails to do so.”
“These insurance companies and their unreasonable demands for increased collateral pose an existential threat to independent operators like W&T.”
Comment: If insuring offshore decommissioning is so risk-free and lucrative, why aren’t other companies entering the market?
“Several states, including Texas, are challenging the BOEM rule and in one case they specifically cite W&T as an example of how the rule could be misused to irreparably harm energy producers.“
Comment:As previously posted, the concerned States should propose alternative solutions that would promote production while also protecting taxpayer interests. Arguing that decommissioning financial risks are not a problem is neither accurate nor a solution.
“In over 70 years of producer operations in the Gulf of Mexico, the federal government has never been forced to pay for any abandonment cleanup operations associated with well, platform facility, or pipeline operations.”
Comment: Shamefully, from the standpoints of both the offshore industry and the Federal government, that statement is no longer true. The taxpayer has now funded decommissioning operations in the Matagorda Island Area offshore Texas (BSEE photo below) and more significant decommissioning liabilities loom.
Attached is an excellent Scientific American article featuring BOE contributor and decommissioning specialist John Smith, former colleague and marine biologist Dr. Ann Bull, and Dr. Milton Love, the leading authority on California’s offshore platform ecosystems.
I had the pleasure of taking a highly informative boat tour around Platform Holly with Dr. Love and a group of international visitors. Holly, which is pictured at sunset in the BOE header, is among the platforms awaiting decommissioning.
Dr. Love on the total removal of California offshore platforms:
“As a biologist, I just give people facts,” he says. “But I have my own view as a citizen, which is: I just think it’s criminal to kill huge numbers of animals because they settled on a piece of steel instead of a rock.”
Almost 40 years ago, four large oil and gas platforms were installed in the beautiful offshore area that was part of our Santa Maria District (Pacific Region of the Minerals Management Service). Those platforms are now within the boundaries of the Chumash Heritage National Marine Sanctuary (see map above).
We watched those platforms being installed, inspected the drilling and production operations, and performed a myriad of other duties including the curtailment of offshore operations prior to launches from Vandenberg AFB. Those Vandenberg launches weren’t always perfect as this link clearly demonstrates. Even knowing that, it was still a bit unnerving when missiles were recovered during post-abandonment site clearance trawls.
All four of those Santa Maria District platforms are now on terminated OCS leases. All were installed by companies that are now part of Chevron Corp. (Chevron, Texaco, and Unocal). They are currently maintained by Freeport-McMoRan Oil & Gas, with Chevron retaining financial responsibility for decommissioning.
Platform
Install yr.
installed by
water depth (ft)
Est. removal weight (short tons)
wells drilled
Harvest
1985
Texaco
675
35,150
19
Hermosa
1985
Chevron
603
30,868
13
Hidalgo
1986
Chevron
430
23,384
14
Irene
1985
Unocal
242
8,762
26
BSEE reports that the 46 wells on Harvest, Hermosa, and Hidalgo have been plugged and tested, and that the well conductors have been removed. No information has been posted on the status of the wells at Platform Irene, but presumably they are (or will soon be) plugged in accordance with BSEE regulations.
Will the inclusion of these platforms in the Chumash Marine Sanctuary further complicate the already difficult decommissioning process? Decommissioning specialist John Smith thinks it may:
“In addition to the BOEM and BSEE approval process, Chevron and FMC are going to be dealing with the NOAA permitting regime for Sanctuaries. Those permitting and environmental compliance requirements are extensive. NOAA’s NEPA documentation for West Coast marine sanctuaries will also need to be amended to include the Chumash.”
So the “Mission Impossible” that is California OCS decommissioning now has yet another complex regulatory element.
“Even though most of the SYU facilities are outside the Sanctuary, the proximity of the operations to the Sanctuary is problematic. The Chumash are now going to be a co-manager of the Sanctuary, adding another player in the process. Sable is going to obtain multiple Federal, State and local permits to restart SYU, and law suits are likely at every stage of the process.”
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?
The previously discussed sale of Cox assets in 6 GoM fields to W&T was completed in January for $72 million, $16.5 million less than the proposed price. W&T, an established GoM operator, believes they can increase the pre-bankruptcy production (8300 boepd) through workovers, recompletions, and facility repairs.
The extent to which W&T is assuming decommissioning liability for the Cox assets is unclear to this observer. Decommissioning information from W&T’s SEC filing is pasted at the end of this post.
In February, Cox won court approval to sell “about a dozen oil fields to Natural Resources Worldwide LLC for about $20 million following a bankruptcy court auction.” This sale is more concerning given that the purchaser has no operating history in the GoM, and scant information about the company can be found online. Perhaps they are affiliated with Natural Resources Partners L.P., an energy investment firm which “owns mineral interests and other rights that are leased to companies engaged in the extraction of minerals,” but “does not mine, drill, or produce minerals, has no operations, and conducts business solely in an office environment.”
Per BOEM data, Cox filed requests to assign a number of leases to Natural Resources Worldwide (NRW) in May, but those requests have yet to be approved. Hopefully, BOEM is taking a hard look at these requests and their obligations following the court auction. Decommissioning liabilities should be their number one concern. (Note: NRW was just listed as the operator of the former Cox platform at EI 361, so presumably at least some of those assignments have now been approved.)
According to BOEM’s platform data base, Cox and affiliates Energy XXI and EPL still operate 243 platforms, down from 435 in June 2023. Also per the data base, the Cox companies have not removed any platforms during 2023 or 2024 YTD, so the reduction in platforms is presumably the result of the W&T transaction. Most of the remaining Cox platforms are old – 16 of their 77 major platforms were installed in the 1950s!
Meanwhile, Cox and affiliates continue to be the GoM violations leader by far with 549 incidents of non-compliance (INCs) in 2024 YTD, 45% of the GoM total for all operators. No other company has more than 100 INCs (although Whitney Oil and Gas has a disappointing 93 INCs, including 33 facility shut-ins on only 65 inspections!)
operator
platforms/ major platforms
warning INCs
component shut-in INCs
facility shut-in INCs
Cox
209/69
407
44
4
Energy XXI
19/7
73
1
2
EPL
5/1
16
1
1
Total Cox
233/77
496
46
7
Total GoM
1519/736
831
317
68
INCs are for 2024 as of 9/17/2024. A major platform has at least 6 well completions or more than 2 pieces of production equipment.
The Company may be subject to retained liabilities with respect to certain divested property interests by operation of law. Certain counterparties in past divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. Due to operation of law, the Company may be required to assume decommissioning obligations for those interests. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company no longer owns these assets, nor are they related to current operations.
During the three months ended March 31, 2024, the Company incurred $2.6 million in costs related to these decommissioning obligations and reassessed the existing decommissioning obligations, recording an additional $5.3 million. As of March 31, 2024, the remaining loss contingency recorded related to the anticipated decommissioning obligations was $20.8 million.
Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise the Company’s opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on the Company’s results of operations in the period in which the amounts are accrued and the Company’s cash flows in the period in which the amounts are paid. To the extent that the Company does incur costs associated with these properties in future periods, the Company intends to seek contribution from other parties that owned an interest in the facilities.
Bud's Offshore Energy (BOE) 