Archive for the ‘Gulf of Mexico’ Category

Comments on the major offshore provisions:

  • The bill neither repeals nor amends the massive land withdrawals by Presidents Obama, Trump, and Biden that have fenced the OCS program into portions of the central and western Gulf of Mexico. Worse yet, the bill tacitly endorses those withdrawals by specifically stating that they are not affected in any way (Sec. 20114).
  • Sec. 20107 mandates that at least 2 lease sales be held annually in the GoM. The certainty would provide some incremental benefit, but is unlikely to stem the decline in GoM reserves. We are becoming increasingly dependent on the 4% of our OCS that may be leased, about 3/4 of which is not prospective or has limited production potential.
  • The bill also mandates at least 2 sales per year offshore Alaska. What will be offered given that most Alaska areas are off limits? We have seen how little interest there is in the Cook Inlet.
  • Sec. 20601 lowers the revenue to the US Treasury and increases the revenue to Gulf producing states. This would garner further support from those states, but will have little effect on production.
  • Sec. 20106 requires DOI to publish information and report to Congress on the processing of drilling permits. However, delayed drilling permit approvals do not seem to be a significant issue on the OCS.

Read Full Post »

The OCS Orders were the foundation for the current operating regulations in the US and many states and other countries. They were logically organized, easily updated, and published for public comment prior to being finalized.

I have an email message indicating that the first OCS Order No. 1 (Identification of Wells, Platforms, and Structures) was signed on 1/31/1957 and the first OCS Order No. 2 (Drilling) dates back to 2/3/1958! (If anyone has access to the actual documents, please let me know.) The orders were developed much further in the 1970s and 1980s.

Contents of the 1/1980 Atlantic Orders:

  • OCS Order No. 1: Identification of Wells, Platforms, Structures, Mobile Drilling Units, and Subsea Objects
  • OCS Order No. 2: Drilling Operations
  • OCS Order No. 3: Plugging and Abandonment of Wells
  • OCS Order No. 4: Determination of Well Producibility
  • OCS Order No. 5: Production Safety Systems
  • OCS Order No. 6: Well Completions and Workover Operations
  • OCS Order No. 7: Pollution Prevention and Control
  • OCS Order No. 8: Platforms and Structures
  • OCS Order No. 9: Oil and Gas Pipelines
  • OCS Order No. 10 (reserved)
  • OCS Order No. 11: Oil and Gas Production Rates, Prevention of Waste, and Protection of Correlative Rights
  • OCS Order No. 12: Public Inspection of Records
  • OCS Order No. 13: Production Measurement and Commingling

You can view the full set of 1977 Gulf of Mexico OCS Orders here

There has been much discussion, particularly since the 1988 Piper Alpha tragedy, regarding the optimal approach to offshore safety regulation be it prescription, goal setting, safety cases, management systems, or some combination, and how to best influence facility, company, and industry safety culture.

My personal view is that the quality and type of regulations are not nearly as important as the people implementing them. My take:

  • Good regulators are more important than good regulations and are the key to a successful regulatory program. 
  • Regulators must understand and be committed to their organization’s mission and the strategy for achieving that mission. 
  • While they should have a good understanding of the activities that they regulate, their focus is on challenging operators, not directing them. 
  • Regulators should audit operator activities and carefully review incident and performance data.  They should identify problems and concerns, but should not direct solutions. 
  • Safety leaders should be applauded and poor performers should be penalized. 
  • The quality of regulators is more important than the quantity. 
  • Internal and external communication and collaboration are critical to their success.
  • Management should ensure that regulators are able to focus on their mission and that organizational distractions are minimized.  

Read Full Post »

The terms for congressionally mandated Gulf of Mexico Sale 261 have been proposed. As is also the case for Sale 259, the royalty for leases in <200 m or water is 50% higher than for prior sales. This is partly because of the royalty floor (16 2/3%) established in the Inflation Reduction Act, and partly because the Dept. of the Interior opted for the highest royalty allowed (18 3/4%). The royalty for shelf leases is thus the same as for deepwater leases with much greater production potential.

Rental terms for leases in <200 meters of water are higher and more punitive (for delayed development) than for previous sales and for deepwater leases.

Minimum bid requirements are unchanged from sales 256 and 257, and are higher for deepwater leases ($25/acre for <400m and $100/acre for >400m).

Bottom line: While the terms for deepwater leases are unchanged from Sales 256 and 257, that is far from the case for shelf leases where royalty rates were increased by 50% and rentals were increased by 43% for all lease years.

SaleDate% royalty
year 1-5/6/7/8+ rentals
($/acre, <200m)
year 8+ rentals for
leases in 400m+ ($/acre)

Read Full Post »

Of the 1.7 billion acres of Federal land on the US Outer Continental Shelf, only about 73 million acres in the Gulf of Mexico and 1 million acres in the Cook Inlet may be offered for oil and gas leasing. Official or de facto exclusions prohibit leasing in the entire US Atlantic, the entire US Pacific, all Alaska areas except the Cook Inlet, and most of the Eastern Gulf of Mexico. No other coastal nation has restricted access to oil and gas resources to this extent.

As demonstrated in recent sales, many of the tracts being offered have little or no production potential. Only 308 tracts (1.7 million acres) received bids in GoM Sale 257. 94 of the high bids were for sequestration purposes and were arguably invalid. Sale 258 in the Cook Inlet only received a single bid.

The number of active leases, currently 2153, has been at a historically low level for the past 2 years. Only 0.7% of our OCS is leased and thus open to exploration. 26% (552) of these leases are already producing, leaving a historically low number of nonproducing leases.

Oil is where you find it, not where you wish it was or want it to be. Denying access to all but a small portion of the OCS limits exploration strategies and prevents publicly owned resources from supporting our economy in the manner intended by the OCS Lands Act.

Read Full Post »

Per yesterday’s post, below are US OCS fatality data from a 2014 presentation. Ten year intervals were selected for 1975-2004. The longer 1953-1974 era was selected so the activity indicators (well starts and production) would be comparable with the next 3 intervals. The last interval (2005-2013) was limited because the presentation was prepared in 2014.

Fire/explosion fatalities exceeded fall/struck fatalities only in the first interval (1953-1974). As one would expect, the fire/explosion deaths were associated with a limited number of better known incidents (e.g. Main Pass 41, Bay Marchand, Macondo). While the overall trend is favorable, fall/struck incidents and helicopter fatalities at offshore platforms have proven to be more chronic.

I hope to update these data in the not too distant future.




Read Full Post »

The most common causes of offshore fatalities and serious injuries, falls and being struck by equipment, receive little media attention because there is no blowout, oil spill, or fire. However, these are often the most difficult types of incidents to understand and prevent. Human and organizational factors predominate, and prevention is dependent on a strong culture that emphasizes worker engagement, awareness, teamwork and mutual support, effective training and employee development, risk assessment at the job, facility, company, and industry levels, stop-work authority, innovation, and continuous improvement.

This new BSEE Safety Alert addresses such a fatal incident on the Pacific Khamsin drilling rig, and makes recommendations that have widespread applicability.

Incident summary:

While unlatching the lower Marine Riser Package from the Blowout Preventor in preparation for ship relocation, a crewmember was lifted into the air after being struck by a hydraulic torque wrench (HTW), hitting a riser clamp approximately six feet above the elevated work deck before falling to the rig floor. The crew member was given first aid and transported to the drillship’s hospital, where he was later pronounced deceased.

In an upcoming post, BOE will provide historical fatality data by cause and operations category.

Read Full Post »

The offshore oil and gas (O&G) sector is set for the highest growth in a decade in the next two years, with $214 billion of new project investments lined up. Rystad Energy research shows that annual greenfield capital expenditure (capex) broke the $100 billion threshold in 2022 and will break it again in 2023 – the first breach for two straight years since 2012 and 2013.

Offshore activity is expected to account for 68% of all sanctioned conventional hydrocarbons in 2023 and 2024, up from 40% between 2015-2018.



  • Middle East investment continues to be strong
  • Good for South America thanks to Brazil (16 new FPSOs by the end of the decade) and the Guyana success story.
  • Strong forecast for Norway and the UK boosts Europe.
  • North America could do far better with less obstructive access policies.

Read Full Post »

Senator Manchin and the Alaska delegation criticized the DOI decision memo for Sale 258. The memo implied that the highest allowable royalty rate was chosen to minimize bidder interest and limit future production. Unfortunately, the “Inflation Reduction Act,” which mandated these lease sales, was not particularly helpful in creating interest in the less attractive OCS tracts like those in the Cook Inlet and the shallower waters of the Gulf of Mexico.

Sec. 50261 of the IRA raised the minimum allowable royalty rate from 12 1/2% to 16 2/3%, while capping the maximum rate at 18 3/4%. This provision favors deepwater operators, typically majors and large independents, whose royalty rates were capped at 18 3/4%, the same rate as for previous OCS sales.

Conversely, the IRA royalty provisions penalize the smaller companies and gleaners who are critical to sustaining shallow water (shelf) operations, including environmentally favorable nonassociated (gas-well) natural gas production, by raising the minimum royalty rate to 16 2/3%. DOI exacerbated IRA’s impact by electing to charge the highest allowable royalty rate for Cook Inlet and GoM shelf leases. The net result was a 50% royalty rate increase from prior sales (12.5 to 18.75%).

The table below illustrates the royalty rate implications of the IRA language and the DOI decisions.

AreaSaleDate% royalty: <200m water depth% royalty: >200m water depth
Cook Inlet2446/21/201712.512.5
Cook Inlet25812/30/202218.7518.75


  • The base primary term for GoM shelf leases is only 5 years vs. 10 years for leases in .>800 m of water.
  • In lease year 8 and beyond the rental rates are nearly double for shelf leases vs. deepwater leases ($40/ac vs. $22/ac).
  • While deepwater development typically requires more time, the higher rental penalty for delayed shelf production (which must be approved by BSEE) is not warranted. $40/acre or $240,000 per year (plus inspection and permitting fees) is a high cost for a marginal shelf lease.
  • Cook Inlet Sale 244 drew 14 high bids totaling more than $3 million. Sale 258 drew only 1 bid of $64,000. While many factors influence lease sale participation, the 50% increase in royalty rate certainly made the Cook Inlet leases less attractive.
  • Other than the increased royalty rate, the terms for both Cook Inlet sales were essentially the same. The primary lease term was 10 years and the minimum bonus bid was $25/hectare for both sales. The rental rate was increased by only $3/hectare ($13 to $16).

Read Full Post »

Presentations from the January 2023 HSAC meeting have now been posted. None of the presentations addresses the tragic crash in the Gulf of Mexico on 29 December. This is understandable given the ongoing investigation.

Attached is an update from the Helideck Committee which also addresses wind farm issues.

Read Full Post »

“I am of a firm view that the world will need oil and gas for a long time to come,” (Shell Chief Executive) Sawan, who started the job on Jan. 1, told Times Radio in the U.K. on Friday. “As such, cutting oil and gas production is not healthy.

Back in 2021, Shell predicted that its own oil production would decline every year and drop by as much as 18% by 2030. BP had a similar outlook, but CEO Bernard Looney rolled back its climate targets this year and said it will increase investment in exploration and production.

BP and Shell have trailed their U.S. peers in price to earnings ratios. Analysts have said investors interested in exposure to oil and gas have shunned them for putting more money into renewables, while investors focusing on environmental concerns haven’t rewarded them. That’s kept European energy firms trading at a discount.


It will never happen, but a separate company composed of BP and/or Shell upstream US assets would be very attractive to investors.

Read Full Post »

Older Posts »