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BOEM proposed financial assurance rule – good comment letter from Univ. of Arizona students

Posted in decommissioning, Offshore Energy - General, Regulation, tagged , , , , , , , , , , , on April 17, 2026| Leave a Comment »

Decommissioning financial assurance regulations are “instrumental in ensuring both environmental and fiscal responsibility.“- .natural resource management students

The first public comments on BOEM’s proposed revisions to the decommissioning financial assurance requirements have been posted. A good comment letter (attached) was submitted by natural resource management students at the University of Arizona. The students oppose the proposed revisions. Among their concerns (additional thoughts added in parentheses):

  • Increased environmental risks. (Accidents, hurricanes, and other events may introduce decommissioning risks that require both immediate and longer term attention and financial resources. Such incidents typically increase decommissioning costs by orders of magnitude, and can even bankrupt financially sound companies. See “Sad End for Taylor Energy.”)
  • Firms with lower credit ratings would no longer have to hold as much capital in reserve and would have a lower bar of entry into projects. (See comments by John Smith.)
  • The possibility of cascading economic impacts in the event that bankruptcy does occur. (Which predecessors will be affected and how? What about contractors? How long will bankruptcy litigation delay resolution of claims? Will bankruptcy court asset sales increase public financial, safety, and environmental risks?)
  • Taxpayers would be facing a portion of the risk. (Predecessors are only accountable for the facilities they installed, so holding predecessors liable doesn’t free the taxpayers from all financial risks.)
  • The entire energy sector faces increased risks when operating companies fail. (Prominent failures damage the reputation of the industry and the OCS program, with implications for the economy and national security.)

Before relaxing financial assurance requirements, BOEM should consider the role that lax lease assignment and financial assurance policies had in the growth of Fieldwood, Cox, Signal Hill, Black Elk, and other failed companies.

BOEM-2025-0042-0006_attachment_1Download

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John Smith Makes the Case for Reefing California Platforms

Posted in California, climate, decommissioning, energy policy, Offshore Energy - General, Regulation, tagged , , , , , , , on April 16, 2026| Leave a Comment »

HHH platforms
Herrema Balder SSCV

The Case for Reefing California Platforms by John Smith

Environmental groups like the Environmental Defense Center and Get Oil Out continue to oppose converting the jackets of California oil and gas platforms to artificial reefs despite scientific studies (Claisse et al. 2014) showing “oil and gas platforms off the coast of California have the highest secondary fish production per unit area of seafloor of any marine habitat that
has been studied.”

Another important factor environmental groups and the 2023 BOEM Programmatic EIS for Decommissioning failed to consider and acknowledge is the huge amount of air emissions that would be released by world-class heavy lift vessels like the Thialf or Balder Semi-submersible Crane Vessels (SSCVs) that would be required to safely and efficiently remove the large federal OCS platforms like Harvest, Hermosa, and Hidalgo (HHH). The HHH platforms are in waters depths ranging from 430-675 feet and have combined deck and jacket weights ranging from 20,000 – 25,000 tons. In comparison, the wrought iron structure of the Eiffel Tower weighs about 8,000 tons.

The SSCVs and accompanying Anchor Handling Tugs (AHTs) used to remove the HHH platforms will likely to be mobilized from distant locations like the North Sea or Gulf of America where they typically operate. Because SSCVs like the Thialf and Balder are too large to enter the Panama Canal, this would involve a 20,000 nautical mile roundtrip voyage around the tip of South America.

Three to four campaigns, and separate SSCV and AHT mobilizations and demobilizations, are projected to be required to fully remove the HHH platforms because the challenging oceanographic conditions offshore Point Arguello restrict heavy lift operations to a 150-day period between May and October.

Four campaigns by the SSCV and AHT would consume about 300,000 metric tons (mt) of marine diesel oil and release approximately 470,000 mt of CO2 and 11,000 mt of NOX emissions. To put these numbers into context, 470,000 mt of CO2 and 11,000 mt of NOX are:

  • the amount of CO2 emissions released by providing electrical power to 97,600 homes annually (the city of Santa Barbara has about 38,000 housing units).
  • the amount of CO2 emissions released by burning 1.1 million barrels of oil.
  • the amount of CO2 emissions released by 102,000 gasoline burning cars annually.
  • the amount of NOX emissions released by four large oil or coal-fired power plants annually.
  • the total annual NOX emissions in Santa Barbara County.

And this is only the emissions released during mobilization and demobilization of the SSCV and AHT. If full removal is required, an additional 50 days of operational time by the SSCV and AHT is estimated to be required to remove the topside and jacket of each HHH platform. This could be reduced to about 15 days per platform if the jackets are converted to artificial reefs. Only one SSCV and AHT campaign may be required if the HHH jackets are reefed, compared to the four campaigns required for the full removal scenario. This would result in a 75 percent reduction in CO2 and NOX emissions.

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John Smith comments on BOEM’s financial assurance proposal

Posted in decommissioning, Offshore Energy - General, Regulation, tagged , , , , , , , , on April 14, 2026| Leave a Comment »

John Smith’s decommissioning presentation in Santa Barbara

John Smith‘s excellent comments on the BOE post about the proposed revisions to decommissioning financial assurance regulations warrant a separate post. John’s comments are pasted below.

It’s clear the proposed rules have been designed to reduce financial burdens on OCS oil and gas operators, especially small independents. The proposed rules do this by:

  1. Waiving the requirement of the operator/lessees to obtain supplemental financial assurance to cover decommissioning obligations if jointly and severally liable predecessors are determined to have the financial capability to cover the obligations.
  2. Lowering the credit rating threshold BOEM uses for evaluating the financial health lessees and grantees from BBB- to BB- from S&P Global Ratings (S&P) or Baa3 to Ba3 from Moody’s Investor Service Inc.
  3. Revising the level of BSEE probabilistic estimates of decommissioning cost used for determining the amount of supplemental financial assurance required from P70 to P50.

I don’t see any rationale for lowering the credit rating threshold, which would apply to both current and predecessor lessees.  A BB- and a Ba3 rating is considered “non-investment grade” or “junk,” meaning the company is more vulnerable to adverse economic conditions, such as a downturn in oil and gas prices.  Current market estimates place the 3-year probability of default for a BB- rating at approximately 12.5% to 13%. Lowering the credit rating significantly increases the risks of default by lessees and transfers the risk to the federal government and taxpayers.

Reducing the BSEE probabilistic criteria for determining the amount of supplemental financial insurance required from P70 to P50 means there is a 50% chance BSEE cost estimates for decommissioning are underestimated further increasing risks borne by the federal government and taxpayer.  

BOEM should reverse course and maintain the current credit rating threshold (BBB- and Baa3) and the P70 criteria.

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North Sea: Norway explores, UK snores

Posted in Offshore Energy - General, Norway, UK, energy policy, tagged , , , , , , , , on April 10, 2026| Leave a Comment »

Some of us remember when the UK and Norway were friendly North Sea oil and gas rivals – competing to be tops in production, technology, safety, and even promotion at conferences like OTC. Take a look at the production chart below and note the UK’s production leadership followed by the extraordinary decline.

So what happened? Norway may have better oil and gas resource potential, but that is only part of the story. While Norway was managing their offshore sector to succeed, the UK was seemingly managing theirs to fail.

Norway’s North Sea remains far more active because the government promotes exploration through predictable licensing, cost-recovery incentives, and a focus on adding resources to existing infrastructure.

The UK, by contrast, has shifted toward limited development and decommissioning. In recent years, the UK’s windfall tax on oil and gas profits was raised to 78 percent, and licences for exploratory drilling in new areas were banned.

In 2022, the UK government even changed the name of the Oil and Gas Authority to the more trendy North Sea Transition Authority. (Changing names is one thing; delivering reliable energy at reasonable prices is quite something else.)

The stark policy differences are evident in the exploration drilling numbers – sustained drilling vs. sustained decline (charts below).

Norwegian Continental Shelf Directorate data
UK NSTA data:exploration wells spudded with original wellbore intent classified as “exploration” (offshore UK includes geological sidetracks).

JL Daeschler shared this excellent response by Natalie Coupar (excerpts below) to tired anti-exploration arguments that are popular in the UK and elsewhere:

“Claim: Hundreds of North Sea licences have delivered only “36 days of gas”, proving new drilling does not improve energy security.

“This actually proves the opposite. In a mature basin like the North Sea, you need a constant churn of investment and new licences just to stand still. Without ongoing activity, decline accelerates and import dependence rises faster. That is why countries like Norway continue to license and develop new projects. Their approach allows them to replace what they produce and manage decline more effectively. In industry terms, this is measured through the reserves replacement ratio – how much new resource is added compared with what is produced. Norway consistently produces a higher reserves replacement ratio than the UK. Over the 5 year period 2019-2024, through exploration, Norway replaced on average 46% of the reserves that were produced, the UK however, replaced just 14%.“

“Today, the North Sea still provides over half of the UK’s oil and gas needs. With the right conditions, we can sustain production for longer, reduce exposure to imports, and manage the transition more securely. Without licensing and investment, the UK simply becomes reliant on overseas supplies sooner – regardless of demand falling.“

Claim: 93% of UK North Sea oil and gas has already been extracted, so new drilling makes little difference.

“Official projections show several billion barrels of oil and gas still expected to be produced between now and 2050. Independent analysis commissioned by OEUK shows that, with the right conditions, significantly more could be delivered from known projects and discoveries.“

“And even beyond that, the UK’s own regulator identifies large volumes of oil and gas in:

  • approved projects
  • existing discoveries
  • areas that haven’t yet been developed“

Pressure is mounting on the UK govt to approve the Rosebank and Jackdaw projects and ease exploration restrictions. Will it work?

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Congratulations to Frank Musacchia – BSEE Inspector of the Year

Posted in Gulf of Mexico, Offshore Energy - General, Regulation, tagged , , , , , on April 9, 2026| Leave a Comment »

Frank Musacchia, a member of the New Orleans District Well Operations Unit, has been named BSEE’s Inspector of the Year for 2025.

“Honored to be named Inspector of the Year. I’m sincerely thankful to my supervisor and the management involved for recognizing my commitment to this mission, and I’m proud to work alongside the Well Operations Inspection team, whose support and professionalism elevate all of us. This award reflects our shared dedication to safety and the environment.”

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Comments from the California AG and Sable Offshore on the special permit application to PHMSA

Posted in California, energy policy, Offshore Energy - General, pipelines, Regulation, tagged , , , , , , , on April 8, 2026| 2 Comments »

I’m attaching the complete comment letters from Sable Offshore and their main antagonist, California Attorney General Bonta, in response to PHMSA’s public notice and request for comments on Sable’s special permit application.

Summary of the California AG’s assertions:

“First, PHMSA is without authority to grant such a special permit because Lines CA-324/325 are intrastate pipelines and California regulators have sole regulatory oversight over any attempt to restart these Lines and issue state waivers. Second, California has vested interests in ensuring Lines CA-324/325 operate safely and PHMSA’s proposed special permit would dilute the higher state safety standards that were imposed on Sable and therefore it is inconsistent with pipeline safety. 49 C.F.R. § 190.341(d). Third, given the fact Line CA-324 already failed and caused a catastrophic oil spill in 2015 in Santa Barbara County, even if PHMSA had authority to issue a special permit (which it does not), a more robust environmental analysis needs to be performed. Fourth, PHMSA unlawfully invokes the Endangered Species Acts’s emergency consultation procedures and has given no indication that it will consult with the National Marine Fisheries Service, in violation of the Act. Finally, Secretary Wright’s March 13, 2026, order (“DPA
Order”) does not change anything about the propriety of the Application, because the DPA Order itself is unlawful.”

Summary of Sable’s position (screenshot):

You can sample the other public comments, some of which are quite good, by visiting the Regulations.gov docket.

PHMSA-2026-0464-0067_attachment_1Download
California Comment LetterDownload

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Deepwater development takes time, unless you buy a project that is already producing 😉

Posted in Gulf of Mexico, Offshore Energy - General, tagged , , , , , , , , on April 7, 2026| Leave a Comment »

Shenandoah FPU

If Beacon and HEQ are willing sellers of their majority share in the impressive Shenandoah field, as appears to be the case (per Reuters), the big dogs are interested in buying. And why wouldn’t they be? Production began last July and the targeted rate of 100,000 bopd has already been achieved from just four phase-one wells.

Reuters reports that Total, Shell, BP, Repsol, and Chevron are interested in Beacon and HEQ’s 51% stake. More about Shenandoah:

  • located in Walker Ridge blocks 51, 52, and 53
  • ~150 miles off the coast of Louisiana
  • floating production unit (FPU) in 5800′ of water in WR block 52
  • true vertical reservoir depths ~30,000′
  • high pressure ~20,000 psi
  • Paleogene, Inboard Wilcox trend
  • FPU can host production from nearby subsea systems
  • capacity is being expanded to 140,000 bopd
  • estimated 600 million BOE recoverable including nearby tiebacks
  • other owner: Navitas Petroleum (49% share)

Investment companies like Beacon (owned by Blackstone) are positive, and increasingly necessary, contributors to the offshore program. These companies bring capital and new exploration strategies that increase development and production. They must, of course, be committed to safety excellence, which seems to be the case for Beacon.

It’s noteworthy that Anadarko and Conoco Phillips, Shenandoah’s major original partners holding 33% and 30% interest respectively, withdrew from the project in 2018 citing unsatisfactory appraisal results and weak commodity prices. Evaluation mistakes like this are common, which is why broad and diverse industry participation is needed. With mergers reducing the number of US majors (remember Amoco, Arco, Sun, Texaco, Getty, Mobil, Phillips, Marathon, Unocal, Superior, Hess, etc.), investment companies play an increasingly important role in OCS development.

Shenandoah, WR 51, 52, 53 (center blocks); green=active leases prior to Sale 261; blue=leased issued after Sale 261

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2019 vs. 2025 Gulf oil production: dead heat

Posted in California, Gulf of Mexico, Offshore Energy - General, tagged , , , , , , , , on April 6, 2026| Leave a Comment »

The EIA has revised Gulf of America oil production slightly downward for Nov. and Dec. such that we now have an absolute dead heat between 2025 and 2019. Production for both years averaged exactly 1.898 million bbls/day.

Because of the ~6 month lag in obtaining verified OCS production data from the Office of Natural Resources Revenue (ONRR), the monthly EIA reports are based on ONRR’s more timely sales of production data. The final sales and production numbers are typically very close. For the 2019 record OCS production year, both the EIA and ONRR report identical Gulf production of 1.898 million bopd.

Meanwhile, 2026 Gulf production (chart below) is off to a strong start – 2.019 million bopd in January. This is the third highest monthly oil production in the history of Gulf operations.

Finally, California OCS oil production, which has been hobbling along at ~10,000 bopd (2nd chart) will see a massive increase of up to 500% should Santa Ynez Unit production continue.

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Honored to have been a guest on the G’Day Mate podcast

Posted in energy policy, Offshore Energy - General, Regulation, Uncategorized, tagged , , , , on April 3, 2026| 2 Comments »

For those who haven’t suffered enough following the BOE blog😉, you can listen to me on the G’Day Mate podcast hosted by offshore industry veterans Evan Zimmerman and Tom Pado. You may also want to check out other episodes on their excellent podcast.

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Sale BBG1 bidding outcomes: rejections, close calls, differences in valuations, and other interesting outcomes

Posted in energy policy, Gulf of Mexico, Offshore Energy - General, tagged , , , , , on April 2, 2026| Leave a Comment »

Companies seeking to acquire OCS leases are not only competing with each other, they are also competing with BOEM’s tract evaluations. In that regard, the bidders fared well at Sale BBG1. Only 3 of the 181 high bids were rejected by BOEM. and those rejections appear to be warranted.

The rejected bids were significantly below both BOEM’s Mean of the Range-of-Value and Lower Bound Confidence Interval for these single bid tracts (table below).

Block No.Companyno. of bidsbidMROVLBCI
EW 921LLOG1$505,777$2,900,000$2,200,000
MC 587KUSA1$700,000 $3,300,000$2,200,000
MC 588LLOG1$613,008$6,100,000$4,600,000
MROV=Mean of the Range-of-Value; LBCI=Lower Bound Confidence Interval; KUSA=Karoon (Australia) Energy USA; EW=Ewing Bank; MC=Mississippi Canyon

LLOG submitted 9 other high bids (alone or with partners) that were accepted. KUSA did not submit any other bids. We’ll see if the rejected bids for these blocks are exceeded in future sales.

Nine other high bids (table below) were less than the MROV, but all were greater than the LBCI. Those bidders “beat the house,” acquiring leases for <MROV. In that regard, Equinor led the pack with no rejections even though 3 of their 7 bids were below MROV. Similarly, 2 of Beacon’s 4 bids were <MROV, with no rejections.

Block No.Companyno. of bidsbidMROVLBCI
GC 345Beacon1$5,302,358$5,400,000$4,200,000
GC 346Beacon1$1,102,358$1,500,000$900,000
GC 547Equinor1$3,200,067$4,500,000$2,600,000
GC 549Equinor1$899,967$1,500,000$576,000
AT 64LLOG1$7,997,018$8,300,000$6,700.000
KC 386Oxy2$3,000,505$3,500,000$2,800,000
KC 429Oxy1$600,505$910,000$470,000
KC 431Woodside1$904,547$1,200,000$840,000
WR 56Equinor1$904,547$1,200,000$576,000
MROV=Mean of the Range-of-Value; LBCI=Lower Bound Confidence Interval; AT=Atwater Valley, GC=Green Canyon, KC=Keathley Canyon, WR=Walker Ridge

Perhaps most interesting were the blocks that were highly valued by industry, but not by BOEM. Each of these blocks (table below) received multiple bids and high bids >$10 million. Conversely, BOEM valued the blocks at only $576,000, which (per the terms of the sale) equates to the minimum acceptable bid of $100/acre.

Block No.high bidderhigh bidother bidsMROV
GC 845Beacon$11,802,358LLOG: $613,008$576,000
KC 25Chevron$18,592,086BP: $11,507,770
Shell: $753,029		$576,000
WR 443Woodside$15,204,547Chevron $1,596,189$576,000
WR444Woodside$12,204,547BP: $4,593,770
Chevron $1,482,378		$576,000
MROV=Mean of the Range-of-Value; LBCI=Lower Bound Confidence Interval; GC=Green Canyon, KC=Keathley Canyon, WR=Walker Ridge


All of this demonstrates yet again that:

  • the govt is leasing exploration and development opportunities, not confirmed resources,
  • commercial discoveries are far from certain,
  • informed assessments differ (I.e. great minds, and their computers, don’t always think alike 😀),
  • corporate priorities differ, and
  • exploration strategies evolve.

Superstition, tactic, AI, coded or subliminal message? 😉

  • All 58 BP bids end with 770. Examples: $1,707,770 and $807,770. (At Sale BBG2, all 5 BP bids ended with 990.)
  • All 18 Shell bids ended with 029. (At Sale BBG2, all 6 Shell bids ended with 240.)
  • 13 of 15 Anadarko bids ended with 505, the other 2 ended with 101.
  • All 9 Woodside bids ended with 547.
  • All 3 Eni bids ended with 001.
  • All 4 Arena bids ended with 912.
  • All 12 Talos bids ended with 986.
  • All 3 Beacon bids ended with 358.

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