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Posts Tagged ‘Exxon’

BOEM has accepted 76 of the Sale 259 bids to date including 18 of the 29 legitimate (non-CCS) bids for shelf leases.

Interestingly, none of Exxon’s 69 high bids for shelf leases have been accepted to date. Given that the Exxon bids were for tracts that are presumably considered “nonviable” from an oil and gas production standpoint, those bids should have been accepted by now were they deemed to be valid.

Perhaps BOEM, to their credit, is planning to reject the CCS bids as they may when an unusual bidding pattern has been identified. It is now quire clear (unlike in the immediate aftermath of Sale 257) that Exxon was seeking to acquire these leases for carbon sequestration purposes. That is not allowed given that both Sales 257 and 259 were oil and gas lease sales. As similarly noted for Sale 257:

  • Sale 259 was an oil and gas lease sale. The Notice of Sale said nothing about carbon sequestration and did not offer the opportunity to acquire leases for that purpose. Therefore, the public notice requirements for CCS leasing (30 CFR § 556.308) were not fulfilled.
  • Because there was no draft or final Notice of Sale for CCS leases, interested parties and the public did not have the opportunity to consider and comment on CCS leasing, tract exclusions, bidding parameters, and other factors.
  • 30 CFR § 556.308 requires publication of a lease form. No CCS lease form was posted or published for comment.
  • CCS operations were not considered in the environmental assessments conducted prior to the sale.
  • No evaluation criteria for CCS bids have been published.

Meanwhile, the decision on Green Canyon Block 777 will also be of interest, given that a higher Sale 257 bid for this block was rejected.

Finally, there was a second bid (red block below) from Focus Exploration for one of the blocks Exxon bid on (blue). Will that lower bid, which was presumably for oil and gas exploration purposes, be accepted if the Exxon bids are rejected?

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There are a number of recent articles related to the Guyana Supreme Court ruling on Exxon’s financial assurance obligations. An Oil Now piece (quoted below) is the most informative. It seems that the Supreme Court decision is based on a provision of Exxon’s EPA permit and that EPA is siding with Exxon in this dispute.

The Guyana government and the Environmental Protection Agency (EPA) are set to appeal a recent Guyana Supreme Court ruling that determined that the EPA and ExxonMobil affiliate, Esso Exploration and Production Guyana Limited (EEPGL), breached the terms of the Liza 1 environmental permit. The permit was revised and granted to EEPGL last year for operations in the Stabroek Block, offshore Guyana.

Justice Sandil Kissoon granted several declarations, including that the EPA failed to enforce compliance by EEPGL of its Financial Assurance obligations to provide an unlimited Parent Company Guarantee Agreement and/or Affiliate Company Guarantee Agreement to indemnify and keep indemnified the EPA and the Government of Guyana against all environmental obligations of the Permit Holder (EEPGL) and Co-Venturers (Hess and CNOOC) within the Stabroek Block.

While acknowledging the court’s ruling, the Government of Guyana, as a major stakeholder, maintained in a statement that the Environmental Permit imposes no obligation on the Permit Holder to provide an unlimited Parent Company Guarantee Agreement and/or Affiliate Company Guarantee Agreement. The government believes that Justice Kissoon erred in his findings and that the ruling could have significant economic and other impacts on the public interest and national development.

OIlNow

Unlimited liability is a rather daunting and open-ended obligation that would trouble permittees in any industry.

In the US, the liability for oil spill cleanup costs is unlimited for offshore facilities, but there is a liability cap for the resulting damages. That cap is currently $167.8 million after a recent inflation adjustment. BP, of course, paid far more than that for damages associated with the Macondo blowout. BP’s costs, which amounted to an astounding $61.6 billion, were both voluntary and compulsory as a result of agreements and settlements. Keep in mind that the damage liability limit was only $75 million at the time. One can imagine what would have happened if a company with less financial strength or more inclination to fight had been responsible for the spill.

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In addition to the 94 nearshore Texas leases Exxon acquired in Sale 257, the company was the sole Sale 259 bidder for all but one of 69 nearshore Texas blocks. The exception was High Island 177 (in red above). So who gets that lease?

  • the company (Exxon) that was the sole participant in a de facto CCS sale (bid of $182,750)
  • the company (Focus Exploration) that was participating in the announced oil and gas lease sale (bid of $145,177)

If Exxon is just acquiring these leases for evaluation purposes in preparation for a possible CCS sale in the future, their lease acquisitions may be okay. If they are planning on retaining these leases for actual sequestration operations, that is not okay, at least not until a competitive process has been established for awarding or reclassifying such leases. To date, no lease terms or bid evaluation procedures have been proposed for carbon sequestration leases; nor has an environmental review been conducted pursuant to NEPA.

Questions about Gulf of Mexico carbon sequestration

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  • 313 blocks receiving bids
  • 353 bids
  • 32 companies submitting bids
  • High bids totaled $263.8 million

Exxon doubled down on their strategic CCS bidding; their only bids (69 in total) again appeared to be solely for carbon sequestration purposes. As previously noted, acquiring tracts for CCS purposes is not authorized in an oil and gas sale. Arguably, these bids should be rejected.

The other super-majors, BP, Chevron, and Shell, were active participants as were many independents.

It was good to see BOEM Director Liz Klein announcing bids. This shows respect for the OCS oil and gas program.

It was also good to hear that Red Willow, a native American corporation, was again an active participant.

More to follow.

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BOEM published their Sale 257 Decision Matrix on Friday (2/24/2023), and my previous speculation regarding the rejected Sale 257 high bid has proven to be partially incorrect. The rejected high bid was submitted by BP and Talos and was for Green Canyon Block 777. BOEM’s analytics assigned a Mean of the Range-of-Value (MROV) of $4.4 million to that tract, which tied for the highest MROV for any tract receiving a bid. The BP/Talos bid was $1.8 million or just 40% of BOEM’s MROV. BOEM’s tract evaluation is interesting given that the other bid on this wildcat tract (by Chevron, $1.185 million) was considerably lower than the rejected BP/Talos bid.

The Sale 257 bid that I thought might have been rejected was for lease G37261. This lease was never issued per the lease inquiry data base and the final bid recap. BHP’s bid of $3.6 million for that tract (Green Canyon Block 79) was more than 5 times BOEM’s MROV of $576,000, and was accepted per the decision matrix. Why was the lease never issued?

Both Green Canyon 79 and 777 should again be for sale in legislatively mandated Sale 259, which will be held in just a few weeks on March 29, 2023, just 2 days prior to the deadline. It will be interesting to see what the bidding on those tracts looks like.

Meanwhile, Exxon and BOEM are still mum about the 94 Sale 257 oil and gas leases that Exxon acquired for carbon sequestration purposes. Note the large patches of blue just offshore Texas on the map above. These leases were all valued by BOEM at only $144,000 each, which is equivalent to the minimum bid of $25/acre. This valuation reflects the absence of perceived value for oil and gas production purposes. Exxon bid $158,400 for each tract, $27.50/acre or 10% higher than the minimum bid. Given that (1) the Notice of Sale only provided for lease acquisition for oil and gas exploration and production purposes, and (2) it was common knowledge that these tracts were acquired for carbon sequestration, should these bids have been rejected?

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A.S. Bull and M.S. Love

When Exxon was unable to get approval for an onshore oil processing facility, the company installed this offshore storage and treatment (OS&T) vessel and single anchor leg mooring (SALM) 3.5 miles from shore, just seaward of the State-Federal boundary. The OS&T, a converted tanker, operated from 1981 to 1994. By 1994, the onshore gas processing facility in Las Flores Canyon had been expanded to process Santa Ynez crude, eliminating the need for the OS&T. While the OS&T had a very good performance record, the highly visible vessel was less than endearing to most Santa Barbara County residents, and there was no apparent sadness when the OS&T and SALM were decommissioned in 1995.

Current Santa Ynez Unit facilities:

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Per our previous post on the complex status of the Santa Ynez Unit, Lars Herbst has brought this informative article to our attention. Here is the bottom line:

With this deal, Exxon is essentially lending Flame, Sable’s management team and PIPE investors the money to buy the facilities from itself. If they are able to get them back online, great, Exxon gets its $623 million loan paid back with 10% interest. If not, it presumably repossesses the facilities and their associated headaches.

This is what has been produced and what remains:

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Only 3 years after first oil, Guyana’s offshore production has soared to nearly 400,000 BOPD, and that rate should triple by 2027. If you want to see the production details, Guyana is doing a good job posting their oil and gas production data.

The startup and compressor issues that contributed to high gas flaring volumes seem to have been resolved, and the recent flaring record is exceptional. Over the month of November 2022, the volume flared averaged less than 0.2% of the gas produced, better than the 1.0-1.5% flaring/venting rate for oil-well gas in US GoM from 2015-2021. Using the World Bank’s flaring intensity metric (m3/bbl), the current flaring intensity for Guyana is a remarkable ~0.07 m3 flared per bbl of oil produced.

The next step is to use the associated offshore gas to power Guyana. The two videos embedded below, while promotional, provide good information on plans to use natural gas for onshore power generation, new industry, and other beneficial purposes. This step will only use 50 million cu ft/day, leas than 1/8 the volume that is currently being reinjected. Increased use of the associated gas resource will be dependent on expanded pipeline and power generation capabilities, and LNG facilities to provide for gas exports.

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Exxon is now producing >360,000 bopd from just two Guyana FPSOs. So these two FPSOs are producing about 20% as much oil as the Gulf of Mexico or Norway. A third FPSO will add 220,000 bopd in 2023.

Guyana’s oil output is expected to increase significantly in 2023, as both projects maintain steadier production at capacity throughout the year, and as the third project, Payara, comes on stream in the second half of the year. Payara will add another 220,000 bpd of production capacity to Stabroek Block output, taking it to 580,000 bpd.

Oil Now

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