Delaware Basin sale parcels mostly in NMLea and Eddy counties, NM
The Federal onshore oil and gas program was always secondary to the offshore program, at least in the opinion of those of us who worked in the offshore program 😉. That was before the shale era revolutionized US energy production.
The table below compares the last two Big Beautiful Gulf sales and the record 2008 Gulf of Mexico sale with the BLM NM sale. Most astonishing is the record $357,129 per acre bid for a single NM tract. Devon Energy, which exited the Gulf in 2010, was the mega-bidder acquiring 24 tracts for $2.6 billion! (Devon is still bogged down in the Hogan/Houchin decommissioning dispute in the Pacific, a case which should temper enthusiasm for relaxed lease assignment and financial assurance policies.)
The attractiveness of the Permian, Delaware, and similar onshore basins has been greatly enhanced by vastly improved drilling and well completion technology. The short lead times to first production are a big advantage relative to offshore development.
The total high bids for Gulf Sale 206, which dwarfed the BBG1 and 2 sales, are still a Federal oil and gas leasing record when converted to 2026 dollars, but the sale area was much larger than for the NM sale.
Sale
date
tracts bid on
acres bid on
total high bids
highest bid/acre
BLM NM
5/20/2026
74
33,529
$4,007,609,288
$357,129
BBG2
3/11/2026
25
140,753
$46,976,423
$3,647.57
BBG1
12/10/2025
181
1,023,526
$300,425,222
$3,227.79
206
7/21/2008
615
3,323,047
$3,677,688,245 ($5.7 million in 2026 dollars)
$18,333.47 ($28,300 in 2026 dollars)
The royalty rate on Sale 206 leases is 18.75%, versus 12.5% for the other 3 sales.
Perhaps the wind industry’s problems are more fundamental than those presented by US policies. Why else would TotalEnergies, the company that jumped at the chance to annul its costly romance with US offshore wind, be looking for a way out of its German commitments?
NDR / Süddeutsche Zeitung: TotalEnergies is seeking to quit a major offshore wind energy project in Germany for which it offered to pay six billion euros in a 2023 state auction, arguing that slow grid connections and a deteriorating economic environment have triggered the decision.
According to the reports, energy company BP, which also won a successful multi-billion euro bid in 2023, could seek a similar opt-out. After transferring its offshore wind activities into a subsidiary in 2025, the new company is said to be scaling back and ultimately planning to shut down its offices in Berlin and Hamburg.
Does this sound familiar?The mood in Germany’s offshore wind industry and elsewhere in Europe has shifted markedly in recent years. While bidders in offshore auctions in 2023 were ready to pay billions of euros for the right to implement new projects, a subsequent auction round in 2025 failed to attract a single bid. According to offshore wind industry association BWO, the meager expansion of less than 1 GW annually since 2020 was mainly triggered by a spike in investment and capital costs.
Environmental NGO Deutsche Umwelthilfe (DUH, not the best acronym in English 😉) called the result a “quantum leap” for offshore wind energy. “Wind power at sea is now so economically attractive that project developers are outbidding each other for access to marine areas,” said DUH executive director Sascha Müller-Kraenner. “The fairy tale of expensive green electricity is thus finally off the table.” (This quote didn’t age well!)
“The sums are obscene,” an industry source, who was part of a non-successful bid, told business daily Handelsblatt. (Irrational bidding similar to what we saw during the 2022 U.S. Atlantic Wind Sale.)
Although BOEM’s decision matrix has not yet been posted, a comparison of the acceptances with the bids submitted tells us that the Keathley Canyon Block 828 ($1,101,202) and Atwater Valley Block 63 ($650,018) bids were rejected.
Both of the rejected bids were submitted by LLOG, partnering with 4 other companies on the Atwater Valley block. LLOG’s high bids on 3 other blocks were accepted, so their rejection rate was 40%. Interestingly, 2 of the 3 BBG1 rejected bids were also submitted by LLOG.
There is no shame in bid rejections, which are part of the legislated leasing process. Why pay more than you have to (or think a block is worth)? A bid rejection may attract future competition, but otherwise the only downside is that you don’t get a lease that you can possibly acquire at another sale if desired (an advantage of regular, predictable lease sales).
BOEM is charged with making fair market value determinations and their process and decisions are publicly available. Of course, opinions differ on the value of an unexplored lease. We will see what the bidding on the BBG1 and BBG2 rejections looks like in future sales.
BOEM did accept the the high bids for the BBG2 “sweet spot” blocks (red in map below; also see the table) in the Green Canyon Area of the Gulf. These 4 blocks accounted for 17 of the sale’s 38 bids (45%) and $32.8 milion of the sale’s $47 million in high bids (70%). BP’s $21 million bid for GC 404 was by far the sale’s highest bid.
red=blocks receiving bids at BBG2; blue=BBG1 and Sale 261 leases; green=active leases issued prior to Sale 261
Thankfully, from the standpoint of those of us whose primary concerns are the integrity of the OCS program and protecting taxpayers from decommissioning liabilities, the API comments (attached), along with those submitted by Shell and Chevron, have exposed the folly of eliminating financial assurance whenever there is a financially strong company somewhere in the lease chain of custody.
Mindful of ongoing and anticipated decommissioning liability battles, API effectivelychallenges the BOEM proposal on legal grounds. API also demonstrates why revisions intended to improve regulatory efficiency and increase production would do exactly the opposite. Excerpts from the API comments (emphasis added):
Further, foisting financial assurance obligations on predecessors will not achieve BOEM’s stated aims of financial “savings” and increased OCS oil and gas production; it more likely will do the opposite. The Proposed Rule would just shift financial assurance burdens to financially stronger predecessors, many of which remain engaged in the majority of leasing and production across the OCS and are far more likely to be future investors in increased OCS development and production. By contrast, nothing ensures that entities standing to benefit from the Proposed Rule will reinvest saved financial assurance premium dollars into OCS production; in fact, such entities largely do not explore or increase reserves, but merely buy pre-discovered reserves and produce them to a lower economic limit.
Nor would the Proposed Rule promote or save costs for future OCS transactions since, in the absence of any option for BOEM-demanded financial assurance from current interest holders, assignors will demand financial assurance at sufficiently conservative levels to address the risk of residual liability if assignees default on their obligations.
Even more problematically, the Proposed Rule would retroactively impose this new regulatory burden on entities that divested their OCS property interests years (or decades) earlier—in reliance on BOEM’s regulations that required their assignees to provide any supplemental financial assurance. Such entities are no longer in privity with BOEM, and have no control over current operations on those OCS properties. The Proposed Rule would reach back even to impose these obligations on predecessors that divested their interests before the 1997 regulatory imposition of joint and several liability for assignors (a time period on which the Proposed Rule is silent).
This novel and misguided approach allows, and even encourages, current interest holders to eschew their lease and grant obligations, and instead freely operate on the backs of predecessors and taxpayers. Meanwhile, current interest holders could choose to allocate little or no funding for end-of-life obligations like decommissioning whenever they desire to conclude production, file for bankruptcy, and leave BOEM to eventually issue decommissioning orders to predecessors that have not operated the grants and leases for years or even decades. This would create higher administrative and financial burdens for the government and system as a whole, including where no viable predecessor had accrued liability for decommissioning all facilities present on the lease or grant, and potential operational impacts that a predecessor has no obligation to cure.
This new proposed obligation on predecessors is arbitrary and capricious and unlawful on multiple grounds. It violates the rule against retroactivity by creating new federal liability stemming from already-completed transactions. It violates the agency change in position doctrine, particularly given that BOEM on multiple occasions has rejected precisely the same approach as in the Proposed Rule. It is unsupported, as it overstates the burdens under the discretionary Existing Rule, disregards repeated U.S. Government Accountability Office (“GAO”) and BOEM findings calling for more robust financial assurance by current interest holders, cites only anecdotal prior comments while ignoring the bulk of countervailing comments detailing reality on the OCS, and identifies no means by which BOEM can compel collect, and assess adequate financial information for all predecessor entities. And it is self contradictory, including by tying up more capital among entities producing the vast majority of oil and natural gas on the OCS.
Chevron points to their potential liability balance of ~ $2 billion for satisfying the decommissioning obligations of default owners:
John Smith and I do not agree with the industry support for the use of reserves as financial assurance. The margin of error in reserve, oil price, and decommissioning cost estimates, not to mention the potential for facility damage, the ever-changing political environment, and the administration challenges, present an unacceptably high risk for taxpayers. If companies want to guarantee decommissioning based on reserves, let them do so. Shell makes a good point about why it is especially important to prohibit the use of reserve estimates on a company-wide basis:
The oil and gas industry is crucial for Norway and for Europe. The government is today announcing new exploration areas in the APA (Allocations in Predefined Areas) to further develop the petroleum sector, so that it can continue to create great value for the community, lay the foundation for good jobs throughout the country, ensure our common welfare and contribute to Europe’s energy security and safety, says Prime Minister Jonas Gahr Støre.
Kudos to Norway for the strong, unequivocal announcement. Consistent acreage offerings are important in sustaining offshore production:
Allocations in Predefined Areas (APA) are an annual licensing round that covers the best-known exploration areas on the continental shelf. Through the APA scheme, oil companies gain predictability regarding access to exploration acreage, which is important for a long-term industry such as the petroleum industry. After more than 50 years of exploration activity, the APA scheme today covers the majority of the area that is opened and available on the Norwegian continental shelf.
New York City Comptroller Mark Levine has urged ExxonMobil shareholders to reject the proposal to move their corporate headquarters to Texas, which he claims has “less robust” shareholder rights. Apparently, he would rather that XOM remain in a State where they can more easily be targeted for frivolous law suits.
James Copland, Senior Fellow and Director of Legal Policy at the Manhattan Institute : “rather than focus on improving New York City’s business climate, the comptroller is more interested in opposing ExxonMobil’s proposed redomiciling from New Jersey to Texas, solidifying its operations in a less hostile business environment.”
Mr. Levine’s chutzpah is indeed impressive, even by NYC standards, but shareholders will not vote against their own financial interest.
ExxonMobil’s move means that the three feature pieces of John D. Rockefeller’s Standard Oil legacy will now be domiciled in Texas – Standard Oil of New Jersey (Exxon), Standard Oil of New York (Mobil), and Standard Oil of California (Chevron).
California Attorney General Bonta asks the Court to stay Energy Secretary Wright’s Order directing Sable, under the Defense Production Act to restart production and preliminarily enjoin Defendants, and all those acting in concert with Defendants (i.e. Sable), from enforcing or relying on it. See the attached Federal Court filing.
The AG’s irreparable harm and public interest arguments seem particularly weak, and this may not be the best time to attempt to halt a 20+% increase in California oil production.
Requesting a 60 day extension (double the comment period specified by BOEM)
Need more time to:
review the detailed proposed changes
conduct studies to inform agency
analyze the studies and data
consider alternatives
organize, complete, and review the findings of subject matter workgroups
In API’s favor:
Agencies have discretion on extending comment periods.
60 days is typically considered the minimum comment period; 90 days would have been more appropriate for this proposal.
API members are clearly affected parties.
The BOEM proposal relaxes financial assurance requirements for smaller companies while increasing predecessor lessee risk exposure. Those predecessors would typically be API members.
There are divisions within the industry which complicate trade association commenting.
On the other hand:
API’s letter is dated May 1, just one week prior to the end of the comment period.
The letter was not posted at Regulations.gov until May 6, 2 days before the end of the comment period. Only those tracking the comment letters would have been aware of the request even at this late date.
As of early this morning (May 7th), the docket still specifies a May 8 due date for comments.
An extension could be viewed as inequitable to other concerned parties who made special efforts to honor the deadline.
Comments:
This is why it’s best to specify a reasonable comment period at the time the regulation is proposed, and make it clear that there will be no extension. That way, everyone is treated the same.
For this proposal, 90 days would have been reasonable.
Given the number of significant issues that need to be addressed, the best outcome for this rule would be a re-proposal. See the comments submitted by John Smith and me.
Bud's Offshore Energy (BOE) 
Restart seems likely for decommissioning financial assurance rule
Posted in decommissioning, energy policy, Regulation, tagged API, BOEM, Chevron, comments, decommissioning, financial assurance, NEFSA, proposed regulation, Shell on May 18, 2026| Leave a Comment »
Thankfully, from the standpoint of those of us whose primary concerns are the integrity of the OCS program and protecting taxpayers from decommissioning liabilities, the API comments (attached), along with those submitted by Shell and Chevron, have exposed the folly of eliminating financial assurance whenever there is a financially strong company somewhere in the lease chain of custody.
Mindful of ongoing and anticipated decommissioning liability battles, API effectively challenges the BOEM proposal on legal grounds. API also demonstrates why revisions intended to improve regulatory efficiency and increase production would do exactly the opposite. Excerpts from the API comments (emphasis added):
Further, foisting financial assurance obligations on predecessors will not achieve BOEM’s stated aims of financial “savings” and increased OCS oil and gas production; it more likely will do the opposite. The Proposed Rule would just shift financial assurance burdens to financially stronger predecessors, many of which remain engaged in the majority of leasing and production across the OCS and are far more likely to be future investors in increased OCS development and production. By contrast, nothing ensures that entities standing to benefit from the Proposed Rule will reinvest saved financial assurance premium dollars into OCS production; in fact, such entities largely do not explore or increase reserves, but merely buy pre-discovered reserves and produce them to a lower economic limit.
Nor would the Proposed Rule promote or save costs for future OCS transactions since, in the absence of any option for BOEM-demanded financial assurance from current interest holders, assignors will demand financial assurance at sufficiently conservative levels to address the risk of residual liability if assignees default on their obligations.
Even more problematically, the Proposed Rule would retroactively impose this new regulatory burden on entities that divested their OCS property interests years (or decades) earlier—in reliance on BOEM’s regulations that required their assignees to provide any supplemental financial assurance. Such entities are no longer in privity with BOEM, and have no control over current operations on those OCS properties. The Proposed Rule would reach back even to impose these obligations on predecessors that divested their interests before the 1997 regulatory imposition of joint and several liability for assignors (a time period on which the Proposed Rule is silent).
This novel and misguided approach allows, and even encourages, current interest holders to eschew their lease and grant obligations, and instead freely operate on the backs of predecessors and taxpayers. Meanwhile, current interest holders could choose to allocate little or no funding for end-of-life obligations like decommissioning whenever they desire to conclude production, file for bankruptcy, and leave BOEM to eventually issue decommissioning orders to predecessors that have not operated the grants and leases for years or even decades. This would create higher administrative and financial burdens for the government and system as a whole, including where no viable predecessor had accrued liability for decommissioning all facilities present on the lease or grant, and potential operational impacts that a predecessor has no obligation to cure.
This new proposed obligation on predecessors is arbitrary and capricious and unlawful on multiple grounds. It violates the rule against retroactivity by creating new federal liability stemming from already-completed transactions. It violates the agency change in position doctrine, particularly given that BOEM on multiple occasions has rejected precisely the same approach as in the Proposed Rule. It is unsupported, as it overstates the burdens under the discretionary Existing Rule, disregards repeated U.S. Government Accountability Office (“GAO”) and BOEM findings calling for more robust financial assurance by current interest holders, cites only anecdotal prior comments while ignoring the bulk of countervailing comments detailing reality on the OCS, and identifies no means by which BOEM can compel collect, and assess adequate financial information for all predecessor entities. And it is self contradictory, including by tying up more capital among entities producing the vast majority of oil and natural gas on the OCS.
Chevron points to their potential liability balance of ~ $2 billion for satisfying the decommissioning obligations of default owners:
John Smith and I do not agree with the industry support for the use of reserves as financial assurance. The margin of error in reserve, oil price, and decommissioning cost estimates, not to mention the potential for facility damage, the ever-changing political environment, and the administration challenges, present an unacceptably high risk for taxpayers. If companies want to guarantee decommissioning based on reserves, let them do so. Shell makes a good point about why it is especially important to prohibit the use of reserve estimates on a company-wide basis:
Lastly, kudos to the New England Fisherman’s Stewardship Association for raising the concern about financial assurance for decommissioning offshore wind facilities
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