Liz Bossley, with Cui Ying, Deputy Director General of the International Institute Of Green Finance and Adrian Rimmer, Director of Finance LSEG present their views to Michael Mainelli of ZYen on the subject of emissions trading schemes worldwide.
To watch the interview CLICK HERE
For a copy of Liz’s slides entitled “Investing in the Real World” CLICK HERE
...it is evident that what is now called Brent is a completely different animal from what we called Brent back in 1983, when 15-Day Brent started trading. Brent is now an artificially constructed price index based on a small number of deals, sometimes no deals at all, only bids and offers that do not necessarily result in a contract. These data points are provided by a limited pre-approved number of counterparties over a very brief period of time, a dealing “window”, each day.
Interested parties, oil companies, trading companies, price reporting agencies (“PRAs”) , exchanges, and banks have bent over backwards to keep the brand name “Brent” going long after production from the Brent oilfield dwindled to a trickle. To shore up the volume of production that can lead to reportable transactions that can inform the price assessment process, increasingly disparate grades of crude oil have been added to the basket that constitutes Brent over the years. This has necessitated the inclusion of sulphur price de-escalators and quality-related price adjustments to appease those who buy or sell Brent, but end up with delivery of Forties, Oseberg, Ekofisk or Troll instead. The inclusion of new grades in the basket has proved to be not enough historically to maintain liquidity in the Brent contract. So, datapoints emanating from transactions done CIF Rotterdam were introduced to be netted back to an FOB North Sea basis to further pad the information available to the PRAs when they construct their assessments. That was still not enough.
WTI Midland into Brent
So, from June 2023 it is intended that WTI Midland, Brent’s most credible rival for international benchmark status, will be annexed into the Brent basket. To appropriate WTI into Brent, a substantial upheaval in trading custom and practice is underway. Not only is WTI of different quality from the existing components of the Brent basket, it is located on the opposite side of the Atlantic and tends to get transported in tankers of a different size than those in common use in North West Europe. Upstream producers in the North Sea are, de facto, being asked to cooperate with an increase in cargo sizes in the upstream lifting agreements to 700,000 bbls to make them compatible with US exported WTI. This is being achieved by extending the loading time allowed for vessels to accommodate larger cargoes. There is no reason why minority partners in fields that load through the Brent basket terminals should go along with this change: for small producers the increased cargo size delays their accrual of a full cargo, which has significant pricing and cash flow implications. Small producers can still load smaller cargoes if they want to. However, if the rest of the market wants cargoes of 700,000 bbls, good luck with trying to get top dollar for a 600,000 bbls cargo. The scheduling of WTI cargoes takes place in accordance with a US domestic pipeline timetable, not a North Sea monthly lifting schedule. But to preserve the Brent brand name, US Gulf Coast terminals are changing their timetables for nominating the lifting cargoes of WTI and limiting the range of pipeline qualities they accept to allow them to sell WTI into the Brent complex via delivery CIF Rotterdam.
Who Is the Regulator?
The point where risk and title to the oil passes from WTI sellers to buyers is being changed to just outside the US economic exclusion zone, rather than FOB the loading point, which is the actual , or netted back delivery point in Brent basket contracts. This is reputedly to keep those cargoes of WTI going into Brent, and arguably Brent itself, out of US jurisdiction and the US tax net. Whether this device will be effective remains to be seen. Those readers who were trading in the late 1980s and early 1990s will recall the ruling by Judge William Connor that Brent trades constituted a futures market under the U.S. Commodity Exchange Act and came under the jurisdiction of the Commodity Futures Trading Commission (“CFTC”). This alarming statement prompted furious back-peddling by the CFTC and out-of-court settlements by the protagonists in the case. If the status of Brent with WTI included ever gets challenged in a court, it is anyone’s guess what the outcome and consequences would be.
Who Needs Who?
The WTI Midland market has legs of its own and does not need Brent. In fact, one PRA stated in an International Energy Week presentation that WTI is not joining Brent, but that Brent is being swallowed by WTI. Waning Brent needs the burgeoning volume of activity associated with WTI Midland to survive. It would be considerably simpler to let Brent atrophy and for WTI and/or some other benchmark to take over by a process of evolution. But those parties with a vested interest are going to extraordinary lengths to keep Brent alive.
ISDA and the Material Change Question
One possible reason is the “Material Change in Formula” provisions of the International Swaps and Derivatives Association (“ISDA”) master agreements that are entered into by over-the-counter swaps and options traders. These sit behind long-term positions entered into for the strategic hedging of oil field developments and for the loan financing of those developments. A Material Change in Formula means the occurrence since the date of the deal in question of a material change in the formula for, or the method of, calculating the contract reference price. This may constitute a “disruption event”, in ISDA terminology, and a “calculation agent determination” of an adjustment to the price to bring it back into line with the original intention of the contract. It may even constitute a “termination event”, in other words the end of the contract. This takes us into some murky legal waters outside this writer’s area of expertise.
Arguably, there have been several material changes in Brent over the years, but none quite so material in my opinion, as the inclusion of WTI into the Brent basket. So far, the fact that the benchmark has kept the brand name “Brent”, may have protected it from challenge by the occasional disgruntled contract holder sitting on a loss-making position. Traders with nothing left to lose just might be tempted to have a go in court at claiming that a deal they entered into some time ago did not envisage such a significant change to the benchmark price. Any update to the brand name following the inclusion of WTI, such as calling it “the Atlantic Basin Benchmark”, or something similar, would increase the risk of triggering claims of “Material Change” re-openers under ISDA contracts, whether justified or not.
Changing Price Differentials
The PRAs are changing their Brent price assessment process after consultation with industry, although the new methodology is not universally popular with all the major industry players. Many industry participants that use Brent as a benchmark in contracts are actually oblivious to the workings of the Brent market. They may not appreciate the fact that WTI is likely to be the most competitive grade in the Brent basket most of the time, i.e. the cheapest grade in the basket, for prolonged periods of time. WTI tends to trade at a discount to Brent. This means that the Dated Brent price in those periods will be lower than it otherwise would have been if WTI was not in the basket. This has implications for the grade differential in contracts. If the benchmark price is lowered by the inclusion of WTI, the grade differential has to be adjusted upwards to compensate for this fact. It is debatable how quickly small companies without active trading departments, national oil companies that use Dated Brent as a benchmark, or revenue authorities that use Dated Brent as their tax reference price in upstream agreements, will be cotton on to the implications of the changing composition of Brent.
“With great power comes great responsibility.”
The band aids necessary to keep the Brent brand name in common use, despite some substantial changes to the composition of the Brent basket, such as sulphur de-escalators, quality premia, freight adjustment factors etc., are not negotiated and announced by industry participants. They are assessed and announced by PRAs, albeit by observing such trades as are disclosed to them and by having discussions with some eligible market participants. No-one is forcing oil industry participants to adopt methodologies or price assessments determined by a PRA, or to use the price of Dated Brent or cash Brent as a price benchmark in their contracts. Nor are they forced to adopt the general terms and conditions of trade published by major oil companies. But for any one company to hold out against the custom and practice in common use by the dominant players in the market would be to swim against the tide.
https://ceag.org/shop/web-apps/oil-field-production-and-revenue-raah-monthly-payments/
RAAH is an easy-to-use analytical tool designed to help crude oil producers and oil asset buyers and sellers to evaluate their producing and developing oil field projects based on varying production forecasts, different price assumptions and in a wide range of royalty, cost recovery, profit sharing and tax regimes.
RAAH is not based on any one specific country’s petroleum legislation, but includes the components of the production sharing contracts that are encountered repeatedly around the world- royalty paid in cash or in-kind, cost recovery, profit sharing with the government or NOC, petroleum tax and corporation/profit tax.
This software allows the user to tailor the analysis to its own situation by inputting appropriate assumptions for each project. This encourages the user to focus on the assumptions it is making about the project and highlights the consequences if these assumptions turn out to be wrong.
RAAH provides a template to evaluate up to 20 separate oil field projects over a 20-year period, divided into calendar quarters, based on different:
The Purpose of RAAH
The RAAH software tool is designed to ensure that the revenue assumptions that are plugged into the user’s economic model of a field or project have been thought through thoroughly. It allows the user to play around with a wide range of “What if?” scenarios to make sure it has considered the consequences if its assumptions turn out to be wrong.
RAAH generates almost 500 tables and over 250 charts instantaneously when the user inputs data for up to 20 fields over a 20-year period. It also allows users to import data from Microsoft excel to permit rapid input of large blocks of data and to export the resulting outputs to Microsoft excel to permit the user to incorporate RAAH results into other applications
https://www.yourexpertwitness.co.uk/back-issues/1302-issue-no-62
Brent crude oil is a benchmark price for about two thirds of the world’s oil contracts. This influential benchmark, which is based on five specific grades of crude oil produced in the UK and Norway and sold FOB North Sea ports, stands at a crossroads: the trading community is being asked to accept the inclusion of the USA’s West Texas Intermediate (WTI) crude oil as a deliverable grade in the Brent benchmark contracts.
The reason for this proposal is to boost the volume of oil that is potentially available to be traded and provide a database of transactions that can be considered in the daily price assessments of the price reporting agencies (PRAs). The volume of crude that can set the price of Brent is on an ever-declining trend. Furthermore, not all of the actual deals done in Brent oil find their way into the price assessment process.
“Brent futures” is the title of the flagship contract of the Intercontinental Exchange (ICE) that trades 96 calendar months into the future. Between January and May 2022 the ICE Brent contract traded roughly 235 times more volume of Brent than total world production of all grades of oil worldwide over the same period.
Much more difficult to estimate is the considerably greater volume of over-the-counter (OTC) derivative swaps and options contract that trade worldwide within the International Swaps and Derivatives Association (ISDA) master contract framework.
The vast majority of physical contracts that use Brent as a reference price use the particular assessment published by the PRA, Platts, although such prices are also reported by their main rival, Argus Media, and the newcomer, General Index.
The Brent benchmark has evolved over the years from the 1980s into a very complex system for generating prices each day that can be plugged into contracts by companies and governments around the world many of whom have no direct market involvement themselves. It is taken on trust that the benchmark they are using is representative of the “true” market value of oil.
To recap, what we call Brent currently has the following characteristics:
Brent physical, or “cash”, contracts and the quasi-physical forward contracts are largely unregulated. No-one has the mandate to dictate how companies construct physical oil contracts. The PRA, Platts, has stepped into this regulatory void by simply excluding from the database of transactions it uses to assess daily Brent prices any deals that are not compatible with the methodology laid down by Platts. This methodology is complex and detailed[1]. The number of companies actually inputting data to Platts is limited and these can only contribute data into the “Market on Close” (MOC) price assessment process, if, and for as long as, they have been approved by Platts to do so[2].
The oil trading community continues to use the Platts Brent benchmark as the calculation reference price in its unrelated contracts. The majority of companies that use the Brent benchmark tend not to have the expertise or the market involvement to participate in the MOC price assessment process. Those that can and choose to participate in MOC activities have only to focus for a limited time period every day, the so-called “window”, which concentrates trades into 30-45 minutes before the close. This gives them input to the Brent price that is published every day by the PRAs, without the need to transact large volumes of oil throughout the day to demonstrate their belief in any particular price level. Some active oil and trading companies choose not to participate in MOC or the window, as a conscious policy decision.
The execution of MOC trades transacted in the Platts window is carried out on the ICE trading platform using the ICE matching engine.
It has now been announced by Platts that the Brent basket they consider in their Brent assessment will be expanded to include WTI Midland crude oil from June 2023. Companies are not obliged to comply by changing their contract methodology, but if they do not their deals will not qualify for inclusion in the published price assessment.
WTI Midland is an emerging benchmark in its own right[1]. Since the ban on crude exports from the USA was lifted in December 2015, WTI has and continues to become a key export grade in the international market. The volume involved is well in excess of 1 million b/d although the current picture is obscured by releases from the US Strategic Petroleum Reserve in response to the war in Ukraine. Total US exports are much higher from the USGC, but not all is WTI that has been collected at Midland.
The export logistics for WTI crude are still evolving. Comparatively stable quality light, sweet crude from the Permian Basin are collected at Midland Texas, and other gathering stations, and are exported from the ports of Houston, Corpus Christi and the Beaumont/Port Arthur/Nederland US Gulf Coast (USGC) area. This is a work- in-progress because additional storage and jetty capacity is still being added in the Texas area.
Standardisation, control and clarity of US exports from the USGC are likely to emerge over time but do not yet exist and are unlikely to exist by June 2023 when Platts would like to annex WTI Midland volume to bolster the crumbling Brent benchmark.
“Platts Assessment Methodology Guide, March 2022” and “Specifications Guide Europe and Africa Crude Oil, February 2022”.
https://www.spglobal.com/commodityinsights/process/moc-participation-review-process
“Argus Media Texas Ports Guide: Fall 2020 Edition”.
The Location of a major WTI gathering point in Midland, Texas
“Argus Media Texas Ports Guide: Fall 2020 Edition”.
The Location of WTI Midland:
Unsurprisingly, commercial entities with a vested interest in prolonging the life of Brent are keen to appropriate the tempting volume of WTI Midland into the Brent basket. However, in order to accommodate WTI, it is recognised by the PRAs that the Brent contract and Brent price assessment process would need some fundamental modifications.
Shell, the widely accepted custodian of the general terms and conditions of trade (GTCs) in the Brent market, are proposing further amendments to their time-honoured Shell UK (SUKO) 1990 GTCs to accommodate WTI Midland[1].
The first issue to arise is that there is no terminal operator in the USGC accustomed to compiling and circulating a monthly schedule of standard-sized cargoes that are aggregated in accordance with standard terminal operating procedures and which are available for lifting and sale on standard contract terms. The North Sea terminal operators for Brent, Forties, Oseberg, Ekofisk and Troll release such monthly schedules on compatible, if not coordinated, timetables. The lack of similar data for WTI Midland makes it tricky to decide when cargoes exported from the USGC would arrive in Northwest Europe to qualify for inclusion in Brent.
There is no publicly available, “official” information released in advance about when WTI cargoes will actually leave the Houston area to embark on an approximate 6,000 nautical miles journey to Rotterdam[2]. It is difficult to establish when WTI cargoes would reach the Rotterdam European reference destination port, or any other port to which the buyer may require delivery to its own refinery. At an environmentally- friendly 10 knots this journey would take about 26 days. At a “caps-on-backwards” rate of 15 knots this would take 17 days.
So, there would be some doubt about into which 30-Day BFOET contract month such WTI cargoes would qualify for delivery. This is particularly problematic when there is steep backwardation or contango[3] in the market. When there is a big price difference for oil to be delivered on different future dates, the slippage of a WTI Midland cargo’s delivery date from one month to the next would make a substantial difference to the value of the cargo.
Including WTI sales made FOB the USGC would not make a lot of sense for the FOB North Sea Brent basket. So, SUKO proposes including WTI Midland on a CIF Rotterdam basis and adjusting the price for the difference in the cost of freight from the USGC to Rotterdam and the North Sea to Rotterdam. SUKO proposes using Platts freight cost assessments to adjust for this distance differential.
As mentioned above the seller, rather than the buyer as in an FOB sale, would charter the tanker in a CIF sale. So vetting tankers in advance to perform the voyage becomes an issue that is not relevant to an FOB sale in the North Sea.
Buyers of oil FOB North Sea ports must have their tankers vetted as acceptable to the relevant seller and North Sea terminal in the 7-10 days before it loads. But buying a 30-Day contract that may turn out to deliver a WTI cargo to Rotterdam at the seller’s option and in the seller’s tanker, is another matter. The tanker has to be acceptable to the buyer, but it is unclear what would happen under a 30-Day “BFOETW” deal, if that is the contract from June 2023, if WTI is the grade declared by the seller and the buyer does not approve the seller’s tanker. Presumably the 30-Day notice period gives the seller time to propose a different tanker although, if the buyer has its own vessels on time charter or under a contract of affreightment, reaching agreement may be problematic.
A further modification to standard Brent trading practice includes increasing the “Brent” cargo size from 600,000 to 700,000 bbls to reflect transatlantic freight economics. Economies of scale dictate that larger tankers are used to ship oil over longer distances. This requires a change in trading practices by North Sea producers who typically accrue or co-load 600,000bbbl parcels under their lifting agreements with the terminal operators. There is no obvious reason why upstream producers should cooperate in this fundamental change to long-established joint operating agreements, transportation agreements and lifting agreements for the convenience of PRAs, even though the upstream producers’ own traders might support it. Many producers do not have a trading department to provide an opinion to their upstream colleagues.
In response to concerns over uncertain quality expressed by pioneering international buyers of WTI, when it first became an export grade, both Shell and Platts have stipulated quality specifications for WTI Midland as delivered FOB, including an API gravity range of 40-44o, total sulphur content of up to 0.2% and limits on bottoms, sediment and water (BS&W), reid vapour pressure (RVP) and heavy metals. Shell has also stipulated limits on organic chlorides and some distillation parameters.
Platts has defined a certain number of pipelines that bring WTI Midland to the USGC as being eligible sources for their export price assessments.
Says Ben Holt, Consilience Senior Associate[4], “At this stage there appears no plan to introduce a quality adjustment for WTI as exists for the other non-Brent grades, but Platts say they will keep this under review. WTI is lighter and sweeter than most of the other grades in the Brent basket (Brent is quoted by Platts as 37.5 API and Sulfur 0.4%) so as the relative refined product values of the different crudes change, WTI’s competitiveness will vary: it will tend to be cheap when naphtha is cheap.”
“The Midland Basin (and wider gathering region) has hundreds of producers and thousands of wells often with very different crude qualities being produced. Some control over the WTI Midland “blend” exists, but certainly not all. This has resulted in issues such as TAN spiking from time to time in cargoes loading in the Gulf. One of the specific problems with TAN is that it is nearly impossible to deal with via price escalators given that even modest amounts simply cannot be tolerated by many refineries“, adds Consilience Senior Associate, David Povey.
Shell proposes that the cargo price be in two parts:
Shell proposes that risk in and title to WTI oil shall pass from the seller to the buyer immediately as the vessel carrying the crude leaves the Economic Exclusion Zone (EEZ) of the USA[5]. This is explained by Platts and the Intercontinental Exchange (ICE) as follows: “In their respective discussions, Platts and ICE have heard that several market participants are reluctant to take risk and title to crude in US territorial waters for taxation or environmental risk reasons”[6].
Others suggest that this shifting of the point where risk and title passes out of the EEZ is because “it conveniently gets around any US legislation and oversight leaving the contract based on English law”[7]. This seems a somewhat naïve view of the reach of regulators.
Older traders, such as myself, may recall Judge William Connor’s ruling in the Transnor case back in 1990. This was that 15-day Brent, the precursor contract to today’s 30-Day BFOET, was a futures contract subject to regulation by the US Commodity Futures Trading Commission (CFTC), long before there was any suggestion that American oil could be delivered into the Brent contract. The CFTC over-turned this ruling saying that Brent was a forward contract not subject to CFTC regulation.
But the world has moved on.
On 24th May 2022, the CFTC issued an order under the US Commodity Exchange Act[8] saying “From approximately 2007 to at least 2018 (the “Relevant Period”), Glencore engaged in a scheme to manipulate oil markets and defraud other market participants through corruption and misappropriation of material nonpublic information, designed to increase profit and decrease losses from physical and derivatives trading.”
It also said “Glencore’s conduct during the Relevant Period involved the manipulation or attempted manipulation of price assessments of various fuel oil products published by S&P Global Platts (“Platts”), a price-reporting agency, and derivatives such as futures and swaps that settled by reference to those assessments, including derivatives traded on United States exchanges such as the New York Mercantile Exchange (“NYMEX”) and ICE Futures U.S. Inc.[Emphasis added] During the Relevant Period and the Charging Period, Glencore had derivatives and physical trade positions, including positions held in the United States, that exposed Glencore to fluctuations in the Platts price assessments. Glencore traders understood that Platts made price assessments of various fuel oil products based primarily on the trading activity in a daily trading window, a process through which market participants could submit bids, offers, and trades on set amounts of particular oil products. On certain days on which Glencore had significant exposure to these Platts price assessment benchmarks, Glencore traders placed bids or offers in the relevant trading window with the intent of pushing or controlling the results of the trading window, and thus Platts’s price assessments, in a direction and manner intended to benefit Glencore’s exposure arising from its associated physical and/or derivatives positions. Glencore engaged in this scheme on hundreds of days during the Relevant Period and the Charging Period in order to manipulate Platts price assessments connected to four fuel oil products, and the associated derivatives, in three different United States geographic markets.”
Glencore was ordered to pay $1.186 billion (1.186 thousand million) to settle the charges. The CFTC order against Glencore relates to the refined product Fuel Oil, not Brent. But it has placed front and centre the question of whether or not Platts benchmarks and the Platts window, in which the daily price of Brent is established, can be manipulated.
Data is not in the public domain as to how exactly Glencore manipulated the Platts Fuel Oil benchmarks and how the CFTC became aware of the issue. If a company can manipulate one benchmark, is it perhaps time to review the PRA Principles, which set standards for governance and control systems for all PRA benchmarks? These principles were introduced by the International Organization of Securities Commissions (IOSCO) and endorsed by the G20 in October 2012.
The eyes of traders tend to glaze over when the International Swaps and Derivatives Association (ISDA)[9] is mentioned. Embarking on an analysis of ISDA without a safety net, and a competent lawyer, is inadvisable. As a trader, rather than a lawyer, the question that immediately occurs to me is “would the inclusion of an American crude into a North Sea contract constitute what ISDA calls a Material Change in Formula or a Material Change in Content and constitute a Market Disruption Event”?
ISDA defines these material changes as:
This is a question that may well be asked by any company sitting on loss-making contracts seeking to mitigate those losses or terminate the ISDA contract altogether by claiming, rightly or wrongly, a market disruption event leading to a termination event.
Every ISDA is different depending on which option boxes the counterparties to the transaction has ticked. Counterparties may well have had the foresight to pre-agree a fallback reference price to apply when the benchmark they are using undergoes a material change. It is more usual for there to be “calculation agent determination” of the commodity reference price when there is a market disruption event. In many cases the calculation agent is one of the two parties to the deal, particularly when one of the counterparties is a small company without much involvement in the market and the other is a major oil company, trading company or bank that is providing hedging services within an ISDA framework to the smaller company to support, say, asset acquisition financing. So, in many cases, any issue of a replacement price may lie in the hands of only one of the counterparties to the deal. The position of calculation agent is an influential one, not to be relinquished lightly.
There will be many ISDA agreements in existence stretching a number of years into the future that were agreed before the prospect of WTI Midland joining Brent was envisaged. But since it is looking increasingly likely that Platts and SUKO will proceed to include WTI Midland into Brent from June 2023, those entering into ISDA Master Agreements from now on would be well advised to consider the implications for their positions and consider how they can protect themselves, if there is a challenge to the revised composition of the Brent benchmark.
In my opinion, putting WTI Midland into Brent is just too complicated and it would further obscure the transparency of a key benchmark, which is already very convoluted.
If Brent were to be shown to be manipulated or to produce unrepresentative prices as the volume of oil that we call Brent declines further, companies would choose to stop using it. Companies instead might decide to use WTI Midland as a new benchmark in its own right, or Murban/Oman, or any other new benchmark grade that emerges over time. Trade does not stop when there is a problem with a benchmark.
Letting individual companies choose how to trade must be better than pushing the industry to change their trading practices to prolong an international benchmark, Brent, that should really be allowed to fade into a more regional role. But, it is unlikely that companies with too much invested in Brent will permit that to happen. If WTI is not forced into Dated Brent like a square peg in a round hole, then something else will be.
[1] suko-90-final-amendments-2023.pdf (shell.com)
[2] http://ports.com/sea-route/port-of-houston,united-states/port-of-rotterdam,netherlands/
[3] The definition of contango is that at any given moment in time oil for delivery in the near future is worth less than oil for delivery further forward in the future. The definition of backwardation is that at any given moment in time oil for delivery in the near future is worth more than oil for delivery further forward in the future.
[4] https://ceag.org/senior-associates/
[5] SUKO 90 Final Amendments 2023: https://www.shell.com/business-customers/trading-and-supply/trading/general-trading-terms-and-conditions/_jcr_content/par/toptasks_copy.stream/1653300136349/ca261c49650e0c850ee18c6e82650ad3dfdfba95/suko-90-final-amendments-2023.pdf
[6] “The Brent Benchmark Complex: Evolving Necessity”, July 2021.
[7] “The Future of the Brent Oil Benchmark” Adi Ismirovic, The Oxford Institute for Energy Studies, March 2022.
[8] CFTC Docket No. 22-16 and https://www.cftc.gov/PressRoom/PressReleases/8534-22
[9] Commodities Annex ISDA 0321 and 2005 Supplement Commodity Definitions and Document Listing
