When Congress seems slow to solve problems, it may be only natural that those in the Executive Branch might seek to take matters into their own hands. But the Constitution does not authorize agencies to use pen-and-phone regulations as substitutes for laws passed by the people’s representatives.
Capping carbon dioxide emissions at a level that will force a nationwide transition away from the use of coal to generate electricity may be a sensible “solution to the crisis of the day.” New York v. United States, 505 U. S. 144, 187 (1992). But it is not plausible that Congress gave EPA the authority to adopt on its own such a regulatory scheme in Section 111(d). A decision of such magnitude and consequence rests with Congress itself, or an agency acting pursuant to a clear delegation from that representative body.
At first glance, the SCOTUS decision would seem to affect the regulation of GHG emissions on the OCS and possibly the Lease Sale 257 decision (now being appeal), which was based on BOEM’s failure to estimate the effect of reduced OCS production on GHG emissions outside the US.
In the short term, the U.S. government could enact measures often used in emergencies following hurricanes or other supply disruptions — such as waivers of Jones Act provisions and some fuel specifications to increase supplies. Longer term, government can promote investment through clear and consistent policy that supports U.S. resource development, such as regular and predictable lease sales, as well as streamlined regulatory approval and support for infrastructure such as pipelines.
Perhaps Exxon will return to the Gulf of Mexico if the Administration commits to regular and predictable oil and gas lease sales. The company hasn’t drilled a well in the Gulf since 2019.
The longer API letter comments on the fundamentals of refining markets and operations while also addressing the Administration’s “end fossil fuel rhetoric” and negative regulatory signals. Who would want to make major refinery investments under these circumstances?
We determined that over approximately 5 years, the energy company’s venting and flaring activities exceeded regulatory limits without the required approvals, resulting in a loss of Federal mineral royalties and resources. More specifically, we identified approximately 229,066 MCF of vented and flared natural gas as suspicious or exceeding the allowable amount across four platforms in the Gulf of Mexico between January 2014 and April 2020. We presented our findings to ONRR, which assisted us in analyzing the energy company’s venting and flaring activities and determining the amount of lost Federal mineral royalties. Based on this analysis, ONRR submitted and secured a proof of claim in the amount of $712,857.82 for unpaid mineral royalties during the energy company’s bankruptcy proceeding.
The report doesn’t name the company, but one can make an educated guess based on some of the information provided (e.g. number of platforms the company operated, bankruptcy proceedings, etc.)
The regulator usually finds out about false or misleading recordkeeping. Reports from employees, anonymous or otherwise, are a common source of such charges, as was the case here. (In my District in California, a toolpusher informed us that BOP pressure test records were being falsified. This led to multiple felony convictions.)
The IG’s recommendations to BSEE and ONRR are reasonable and appropriate:
Examine venting and flaring reports for patterns that may reflect violations or amounts that exceed permissible limits.
Develop a process to ensure that royalties are being paid for improperly flared or vented gas.
As BOE has previously reported, available public flaring data do not match. These data inconsistencies should be addressed.
BSEE/ONRR should make more detailed flaring/venting data publicly available so differences between facilities and sectors (e.g. deepwater vs. shelf) can be assessed. Efforts should also be made to post these data in a more timely manner. Data for 2021 are still not available.
Department of the Interior spokesperson: “there are 10.9 million acres of offshore federal waters already under lease to industry,” and “of those, the industry is not producing on more than three-quarters (75.7% or 8.26 million acres).”
As if the preventable expiration of the 5 year leasing program wasn’t bad enough, we get to hear the non-producing leases bit yet again. This pitch was popularized during the oil embargoes in the 1970’s and resurfaces whenever it is deemed to be politically helpful.
The decline in the number of producing leases since 2011(62%) has been less than the decline in the number of active leases (71%).
DOI’s primary concern should be the preventable decline in active leases.
Old comments:
539 days since the last US offshore oil and gas lease sale
182 lease sales since 1954, but none since 2020
Only 0.5% of US offshore land is leased for oil and gas exploration and production (assuming commercial quantities of oil and gas are discovered).
When you acquire a lease, you are not purchasing oil and gas. You are acquiring the right to explore for, and hopefully produce, those resources. Most leases will never produce.
Drilling strategies are linked to geophysical data and geologic information obtained in drilling other wells in the area and region.
Leases expire if they are not producing by the end of the lease term, which is 5 to 10 years depending on location.
You pay bonuses for all leases and annual rental fees for non-producing leases. None of these payments are returned if no discoveries are made.
These provisions were added to the bill without debate and their inclusion was a surprise to most observers. Presumably, DOI had the opportunity to review the text, because that is standard practice.
Sale 257 was vacated by the DC Federal Court for reasons unrelated to the sequestration bids.
Questions:
What are the costs per ton of offshore carbon sequestration including emissions collection, offshore wells and platforms, the associated pipeline infrastructure, ongoing operational and maintenance costs, and decommissioning?
What is the timeframe given that the starting point is likely years away?
How long would CO2 sequestration continue.
Who pays? Polluters? Federal subsidies? Tax credits?
Who is liable for:
safety and environmental incidents associated with these projects?
CO2 that escapes from reservoirs, wells, and pipelines (now and centuries from now)?
decommissioning?
hurricane preparedness and damage?
For Gulf of Mexico sequestration, how much energy would be consumed per ton of CO2 injected? Power source? Emissions?
To what extent will these operations interfere with other offshore activities?
Relatively speaking, how important is US sequestration given:
the steady progress that is being made via natural gas and renewables?
What are the benefits of offshore sequestration relative to investments in other carbon reduction alternatives?
Will BOEM conduct a proper carbon sequestration lease sale with public notice (as required by BOEM regulations) such that all interested parties can bid?
What will be the lease terms?
Environmental assessment?
How will bids be evaluated?
What happens to the Exxon bids if the Judge’s Sale 257 decision is reversed?
What is the status of the DOI regulations mandated in the legislation with an 11/15/2022 deadline?
When will we see an Advanced Notice or Notice of Proposed Rulemaking?
Given that DOI has no jurisdiction over the State waters and onshore aspects of these projects, what is the status of parallel regulatory initiatives?
Finally and most importantly, how does drilling offshore sequestration wells instead of exploration and development wells increase oil and gas production?
….for continuing to recognize the Conservation Division of the Geological Survey (USGS) as the US offshore safety regulator, even though 40 years have passed since that was the case and there have been 3 successor bureaus. 😀
(a) Design and equipment requirements of this subchapter for OCS facilities, including mobile offshore drilling units in contact with the seabed of the OCS for exploration or exploitation of subsea resources, are in addition to the regulations and orders of theU.S. Geological Survey applicable to those facilities.
USGS North Atlantic District, Hyannis, MA, Halloween 1980
Most of us old-timers think the best regulatory framework for the offshore program was in the USGS days (pre-1982). Some of this may be nostalgia, but there are some good reasons for this thinking:
USGS was/is an internationally acclaimed scientific organization that was always headed by a renowned geologist. The regulatory program was thus somewhat insulated from political pressures. Vince McKelvey, Bill Menard, and Dallas Peck were the Directors when I worked for USGS. Their credentials are linked. Bill and Dallas visited our Hyannis office (not at Halloween 😀) and were very supportive.
The Conservation Division was responsible for onshore operations on Federal lands as well as offshore activity. This facilitated information sharing and offered diverse career opportunities. My first bosses in New Orleans had worked previously in the Farmington and Roswell, NM offices.
We had excellent synergy with the other USGS divisions. The Marine Science Center in Woods Hole was an incredible resource for our Hyannis office. The Woods Hole office, particularly Mike Bothner and Brad Butman, had a critical role in the Georges Bank Monitoring Program, the best ever (in my biased opinion) environmental study of exploratory drilling operations in a frontier area.
The USGS Conservation Division had a very small and supportive headquarter’s staff, which minimized the potential for conflict with field offices.
Prior to the formation of the Minerals Management Service (MMS) in 1982, the Bureau of Land Management was responsible for leasing, but all regulatory functions were under USGS. This included resource evaluation/conservation, plan review and approval, permitting, inspections and enforcement, and investigations. The division of MMS responsibilities, most notably the assignment of plan approval to the leasing bureau (BOEM) rather than the regulatory bureau (BSEE), complicates the work of both bureaus and is a prescription for inefficiency, confusion, overlap, and conflict.
While the previously discussed planning, cementing, and well suspension issues allowed the well to flow, there were many other equipment, operational, and management deficiencies that elevated the incident to a disaster. Below are those that bother me the most:
Blowout Preventers
The Deepwater Horizon BOP stack had a single blind shear ram. Regardless of what the regulations allowed, you don’t drill a complex well like this without redundant shearing capability (and at the time of the blowout most deepwater drillers were using rigs with dual shear rams). All well control emergencies requiring the emergency disconnect sequence, deadman, and autoshear functions are dependent on effective shearing capability. You can have redundancy in every other BOP element, but without dual shear rams, you don’t have a redundant BOP system. Further, for full redundancy both shear rams should be capable of sealing the well bore after shearing. In that regard, the present regulations and the applicable standard (API S 53) require only one shear ram capable of sealing. They are thus deficient and should be updated.
The DWH BOP system did not have full bore shearing capability (available at the time) which may have sheared the deflected drill pipe.
The DWH BOP system was not properly maintained and recertified as required by regulation.
Transocean’s “condition based maintenance” was a euphenism for “fix it when it fails.” Perhaps worse, BP authorized the continuation of operations knowing that an annular preventer was leaking.
The initial flow from the well was directed to the mud-gas separator instead of being routed overboard via the diverter. Routing the flow to the diverter would have provided additional time for the crew to safely evacuate.
Gas detectors
Not all gas detectors were fully operational. As justification, Transocean’s report expressed concerns about alarm fatigue, a weak excuse. Alarm issues can be effectively managed without disabling the devices.
The gas detectors did not automatically shutdown the generators, the source of the initial explosion. This is somewhat understandable on a dynamically positioned rig that is dependent on power to maintain position. However, someone should have shut down the generators as soon as gas was detected.
Engine overspeed devices didn’t work, and apparently weren’t tested regularly. Had they worked, the engine room explosion may have been prevented.
The crew had time to activate the Emergency Disconnect Sequence, but did not.
Per BSEE’s online Incident of Non-Compliance (INC) data, 4 operating companies accounted for 64% of the INCs during Q1 of 2022 (see chart below). Fieldwood was once again cited for the most INCs (132), but GOM Shelf LLC had the highest INC/inspection ratio (1.53). All 55 of the Whitney Oil & Gas INCs resulted in Facility Shut-In orders. Whitney was cited for failing to comply with damage inspection and records requirements following Hurricane Ida.
The overall violations rate during Q1 of 2022 was essentially unchanged from 2021. A number of companies had outstanding records. We’ll comment on them later in the year.
9/30/2021 – BOEM announces Lease Sale 257 as necessary to comply with the order of the Louisiana Federal Court. DOI will “continue its comprehensive review of the deficiencies associated with its offshore and onshore oil and gas leasing programs.”
11/15/2021 – Press Secretary Psaki: “We believe the (Louisiana court) decision is wrong, and the Justice Department is appealing it. So it’s in the courts; it’s in a legal process. We’re required to comply with the injunction. It’s a legal case and legal process, but it’s important for advocates and other people out there who are following this to understand that it’s not aligned with our view, the President’s policies, or the executive order that he signed.”WTI = $80.85/bbl
11/17/2021: Sale 257 bids opened and announced despite pending litigation. In a surprising twist, Exxon was the sole bidder on 94 carbon sequestration tracts offshore Texas. Neither the Notice of Sale nor the environmental review announced or assessed carbon sequestration operations in Federal offshore waters. BOEM/DOI have not commented publicly on the CCS bidding.
1/27/2022: Judge Contreras, DC Federal Court, vacates Sale 257. The Judge agreed with the plaintiffs’ assertion that BOEM failed to consider the effect that reduced production (and thus higher prices) would have on foreign consumption and the associated GHG emissions. The judge not only decided in favor of the plaintiffs, but ruled that BOEM’s omission was so serious that the lease sale had to be vacated. The judge reached this decision even though (1) the five year leasing plan expires in June leaving the timing of any future sale very much in doubt and (2) all of the sale 257 bids, which are based on proprietary assessments, are now public information, thus compromising the integrity of the leasing process at the next sale (if and when that occurs). WTI= $87.61/bbl
2/8/2022: API and the State of Louisiana appeal the Sale 257 decision.
2/24/2022: Russia invades Ukraine
2/28/2022: The Administration announces that it will not appeal the Sale 257 decision. WTI = $96.13
3/8/2022: WTI peaks at $123.70/bbl
3/30/2022: EIAP Report for API and NOIA estimates economic impacts from leasing program delays noting: In most cases, additional leases are required to produce an existing field fully or to underpin the economics of processing and transportation infrastructure. It is thus important for the industry to have continued opportunities to secure leases through a predictable leasing program. (US lease blocks are too small for optimal development in deepwater and frontier areas, increasing the importance of regular lease sales.)
Mr. Domangue began his career with BSEE in 1997 and has more than 30 years of experience in the oil and gas industry. He has served as the Deputy Regional Director for Districts, Investigations, Environmental, and Enforcement (DIEE), as Senior Technical Advisor for the BSEE Gulf of Mexico Region and was the Acting Chief of the National Offshore Training Center. Mr. Domangue also previously served as Office Supervisor for Regional Operations, and as District Manager for the Houma District Office of the BSEE Gulf of Mexico OCS Region. He holds a BS degree in petroleum engineering from Louisiana State University.
Bud's Offshore Energy (BOE) 