Illustration credit: Kellen Riell / The New Bedford LightGlauconite has been identified within the boundaries of lease areas marked with green. Credit: Kellen Riell / The New Bedford Light
Anastasia Lennon has published several informative articles in the New Bedford Light on the challenges posed by the presence of glauconite on North Atlantic wind leases. The above illustrations explain those challenges and identify where glauconite has been found to date. Per her latest article:
Preliminary geotechnical analysis for New England Wind, an Avangrid project, showed a risk of turbine pile foundation refusal in 50 of nearly 130 turbine locations, or about 40%, according to 2023 records obtained through a Freedom of Information Act request.
The mineral’s behavior poses a “significant risk” to offshore wind development, said BOEM, the federal regulator of offshore wind, in a paper last year.
As summarized below and explained in the attachment, the more realistic independent estimates were 2-3 times higher than the operators’ “high end” estimates.
BOEM’s “Rule to Streamline and Modernize Offshore Renewable Energy Development” is intended to “make offshore renewable energy development more efficient, [and] save billions of dollars. Unfortunately, the savings associated with relaxed decommissioning financial assurance requirements translates to increased risk for customers and taxpayers.
BOEM signaled their intentions on offshore wind (OSW) decommissioning three years ago when they granted a precedent setting financial assurance waiver to Vineyard Wind. Despite compelling concerns raised by commenters, the “streamlining” regulations have codified this decision.
Cape May County, New Jersey, was among the commenters objecting to BOEM’s departure from the prudent “pay as you build” financial assurance requirement. The County commented as follows (full comment letter attached):
“[e]nergy-utility projects are in essence traditional public-private partnerships where technical and financial risks are transferred to the private sector in exchange for the opportunity to generate revenues and profit. Under the proposed rule, the Federal government is instead transferring risks associated with decommissioning to the consumer rather than to the private sector.”
Cape May added:
“[w]hile BOEM believes that if a developer becomes insolvent during commercial activity that a solvent entity would assume or purchase control, the County believes this is a risky assumption as the most likely reason for default is that a constructed wind farm developer is unable to meet its contractual obligations set forth under a Power Purchase Agreement (PPA) because its energy production revenues are not in excess of its operating costs. A change of hands would not remove these circumstances or make the project profitable.”
Cape May and others also commented on the threat of premature decommissioning as a result of storm damage. In response, BOEM asserts that these risks have been addressed in the latest standard for North American offshore wind turbines (Offshore Compliance Recommended Practices: 2022 Edition (OCRP-1-2022)). However, design standards, particularly those for offshore facilities, are not static. The recommended practice for OSW is likely to change multiple times in the coming years as storm, operating, and turbine performance data are updated and analyzed. The design standard for Gulf of Mexico platforms has been repeatedly refined and improved and is now in its 22nd edition.
In their response to public comments on the decommissioning risks, BOEM repeatedly asserts that they can adjust the amount and timing of required financial assurance as they monitor a lessee’s financial health. Unfortunately, a company’s finances can change quickly and BOEM’s options will be limited when it does. Increasing the financial burden on a struggling company that is providing power to a regional power grid will not be a simple proposition.
Decommissioning specialist John Smith has summarized the major provisions of BOEM’s decommissioning financial assurance rule for OCS oil and gas operations. He has highlighted his comments in red.
Proved reserves should not be a basis for reducing supplemental assurance. The uncertainty associated with reserve estimates and decommissioning costs can easily negate the assumed buffer in BOEM’s 3 to 1 reserves to decommissioning costs ratio. That approach failed completely at the Carpinteria Field in the Santa Barbara Channel (Platforms Hogan and Houchin). See other points on this issue.
Given that the reverse chronological order process for determining predecessor liability was dropped from consideration last April, there is no defined procedure for issuing decommissioning orders to prior owners. The absence of such a procedure increases the likelihood of confusion, inequity, and challenges, particularly when orders are first issued to companies that owned the leases decades ago, in some cases prior to the establishment of transferor liability in the 1997 MMS “bonding rule.”
BOEM’s concern (below) about investment in US offshore exploration and production is interesting given that their 5 year leasing plan strongly implies otherwise.
BOEM’s goal for its financial assurance program continues to be the protection of the American taxpayers from exposure to financial loss associated with OCS development, while ensuring that the financial assurance program does not detrimentally affect offshore investment or position American offshore exploration and production at a competitive disadvantage
I’m just guessing here, but my sense is that BOEM was pressured to finalize this rule in a timely manner (<10 months is timely for such a complex rule) and was thus reluctant to make any significant changes to the proposal published last summer. A public workshop during the comment period would have been a good idea to facilitate informed discussion on the important issues addressed in this rule. Such workshops were once commonplace for major rules.
Houston, TX, March 29, 2024. Beacon Offshore Energy LLC (“Beacon”) announced today the completion of the divestment of its non-operated interests in certain fields in the deepwater Gulf of Mexico in accordance with a previously executed definitive agreement with GOM 1 Holdings Inc., an affiliate of O.G. Oil & Gas Limited. The divestment includes Beacon’s 18.7% interest in the Buckskin producing field, 17% interest in the Leon development, 16.15% interest in the Castile development, 0.5% interest in the Salamanca FPS/lateral infrastructure, and 32.83% interest in the Sicily discovery.
According to BOEM records, GOM 1 HOLDINGS INC, a Delaware company, registered with BOEM effective 3/15/2024. The parent entity, O.G. Oil & Gas Limited, is a privately held E&P company incorporated in 2017 and based in Singapore.
O.G. Oil & Gas Ltd is part of the Ofer Global Group, “a private portfolio of international businesses active in maritime shipping, real estate and hotels, technology, banking, energy and large public investments.”
After a partial takeover by O.G Oil & Gas Limited in 2018, New Zealand Oil and Gas is now 70% owned by the Ofer Global Group. Among other interests, NZ Oil and Gas produces from fields offshore Taranaki, NZ.
Because they are jointly and severally liable for safe operations and decommissioning, minority investors should take a strong interest in safety management and financial assurance. Investors should remember that partners are adversely affected by the mistakes of the operating company. Anadarko and Mitsubishi took a hit following the Macondo blowout. To what extent had they been monitoring bp’s risk and safety management programs for drilling operations?
A post from last March discussed the high and seemingly unfair royalty and rental rates for new leases in the shallow waters of the Gulf of Mexico shelf. A 50% increase in the shelf royalty rate for lease sales 259 and 261 combined with rather punitive rental rates have likely contributed to the sharp decline in bidding for shelf lease blocks (see table below).
This decline in shelf bidding is unfortunate because the smaller companies that operate in the shallow waters of the Gulf are critical to sustaining the production infrastructure. These companies are also significant producers of environmentally favorable nonassociated (gas-well) natural gas.
lease sale
shelf blocks with bids (excluding CCS bids)
sum of high shelf bids ($million, excluding CCS bids)
BOEM has completed their evaluation of the Sale 261 shelf bids (see below). Each of these blocks received only a single bid, and every bid was accepted. Ironically, the invalid CCS bids for blocks that have no oil and gas value, were the first to be accepted. This was also the case for Sales 257 and 259.
Company
Block
high bid ($) per acre ($)
date accepted
Byron
SM 60
128,750 25.75
2/2
Byron
SM 70
182,235 33.32
2/20
Cantium
GI 35
125,000 25.00
2/20
Cantium
GI 36
125,000 25.00
2/20
Cantium
MP 314
125,000 25.00
3/12
Cantium
SP 63
125,000 25.00
3/12
Arena
EI 231
135,000 27.18
2/20
Arena
EI 277
135,000 27.18
2/20
Arena
EI 281
135,000 27.18
2/20
Arena
EI 340
135,000 27.18
2/20
Arena
EI 343
135,000 27.18
2/20
Arena
WD 119
135,000 26.75
3/12
Focus
V 152
121,152 25.16
2/20
Repsol
36 CCS bids
187,200 (1) 32.50
1/23
(1) All of the Repsol bids were $32.50/ac. Total bids varied by block size, but were $187,200 for the 5760 acre blocks.
Suggestions:
Seek a legislative fix to the Inflation Reduction Act😉 provision that established a 1/6 royalty rate floor for all OCS leases (formerly the royalty rate was 1/8 for leases on the shelf).
In the interim, administratively lower the royalty for shelf leases to 1/6 (from 18 3/4%).
For future oil and gas lease sales, accept all high bids that exceed the specified minimum bid (currently $25/ac for the shelf). The Gulf of Mexico shelf has been extensively explored and developed for 70 years. While prospects remain, they are generally marginal as evidenced by the recent lease sale results. Fair market value is what any company is willing to bid (above the specified minimum).
Focus on assuring that lease purchasers are technically qualified to minimize safety risks, and that financial assurance for decommissioning (for new and existing leases owned by the high bidder) has been fully addressed.
Rincon Island and the onshore facility were constructed in 1959 and used for oil and gas production. In December 2017, Rincon Island Limited Partnership, the most recent lessee, transferred its lease interests to the State after becoming financially insolvent. Phase 1 of decommissioning included the plugging and abandonment of all oil and gas wells and removal of service equipment at Rincon Island.
The proposed Phase 2 project, analyzed within the Environmental Impact Report (executive summary attached), would prudently retain Rincon Island and the Rincon Island Causeway in their current configuration. Phase 3 will prepare Rincon Island and the Onshore Facility to be leased for yet-to-be determined new uses.
Bayou Bend CCS LLC commenced drilling an offshore (Texas State waters) and an onshore stratigraphic well for carbon sequestration in the first quarter 2024.
Is offshore carbon disposal ocean dumping?One of the provisions that was slipped into the “2021 Infrastructure Bill” exempted carbon sequestration from the Marine Protection, Research, and Sanctuaries Act of 1972 (Ocean Dumping Act). This exemption revises the OCS Lands Act and thus does not apply to State offshore lands. The Texas offshore wells must therefore be permitted by EPA as “Class VI wells,” as is the case for onshore disposal wells. However, Texas and Louisiana have asked the EPA for “primacy,” which would allow state agencies to approve and oversee these operations.
Meanwhile, the regulations for carbon disposal on the OCS, which the Infrastructure Bill mandated by November 2022, have yet to be published for comment. The latest Federal regulatory agenda indicates a publication date of 12/00/2023 for these regulations. Presumably the staff work has been completed and the rule is stalled in the review process.
Despite the absence of a regulatory framework, BOEM has accepted sequestration bids at the last three oil and gas lease sales. These bids were evaluated as if the leases were being acquired for oil and gas exploration and production, even though the bidders’ intentions were widely known. Why was BOEM a willing participant in this charade, not just at one sale, but at three sales in succession?
Given that the perceived carbon disposal bonanza is dependent on mandates and subsidies, one has to wonder about the massive revenue projections for this industry and raise concerns about the associated public and private financial risks. What is the long term business plan for this industry? Who will be monitoring the offshore wells (in perpetuity)? How will the public be protected from financial assurance and leakage risks? We will see how the myriad of carbon sequestration issues are addressed in the proposed regulations.
Bud's Offshore Energy (BOE) 