The physical market for Brent, Forties, Oseberg and Ekofisk (BFOE) represents the delivery mechanism for ICE Brent Futures and is linked to crude oil contracts worldwide. This year the trading in the BFOE forward market has been limited to just 20 cargoes a month from the Forties stream. Today we describe producer’s efforts to increase market liquidity.
This is Part 3 in our series on the physical Brent crude market. What follows will make more sense if you read Part 1 and Part 2 first. In Part 1 we explain that the Brent crude used as a benchmark for international pricing that underlies the ICE Brent futures contract – is made up of crude oil produced in dozens of different North Sea fields and delivered to market in four different streams – Brent, Forties, Oseberg and Ekofisk (BFOE). In Part 2 we explain the linkage between the small Brent physical crude market that trades in 600 MBbl parcels costing upwards of $60 MM at today’s prices and the Brent ICE futures contract that trades in 1000 Bbl lots. Prices in the two markets are linked together by a cash settlement process using a Brent Index price based on forward trades in the physical market. The Brent Index settlement is an exchange for physical (EFP) mechanism that ensures convergence between futures and physical markets.
The convergence mechanism in futures markets used to be something taken for granted in international crude trading. Futures exchanges like ICE and the CME NYMEX were considered an add-on service for the oil industry to hedge price risks - secondary to the physical market. That was the old days. Now futures trading volumes dwarf physical market transactions (in Part 2 we showed that ICE Brent futures trades 500 times the physical BFOE crude production volumes each day). Nevertheless the futures contracts still have to relate back to underlying physical crude oil prices in order to function efficiently. That can sometimes cause unexpected results.
The sudden wide price gulf that opened up between the US NYMEX futures contract that is linked to West Texas Intermediate (WTI) crude delivered at Cushing, OK and ICE Brent futures in August 2010 is a good example. After years of trading close together with WTI at a slight premium over Brent the two crudes became disconnected. Since then WTI has traded at a discount to Brent that has exceeded $25/Bbl at times and is currently just over $18/Bbl. The WTI price discount opened up because supplies of crude into the Midwest and the Cushing delivery point exceeded refinery requirements and pipeline takeaway capacity constraints resulted in a crude stockpile buildup at Cushing. As a result the value of physical WTI has been discounted heavily against prices like Brent that are set in the international market. Many market participants (particularly producers realizing discounted prices) would have preferred this price divergence not to happen but it truly reflected underlying market fundamentals.
Concerns about just such a disruption happening in the physical market for Brent crude lie behind recent efforts by North Sea producers and price reporting agency Platts to bolster the volumes traded in the physical BFOE market. The participants in the BFOE market – a limited number of large oil trading firms – are trying to ensure that prices set in the Brent forward market are not subject to undue manipulation and volatility. Their fears stem from an ongoing reduction in the number of BFOE trades that are included in price assessments. Recent proposals led by Shell on the producer side and Platts as the principal reporting agency are being discussed at the moment with a view to changing the way that BFOE crudes are traded in the forward market. That forward market sets Brent physical prices that are linked closely to the ICE Brent futures contract through the EFP mechanism.
This is not the first time that the BFOE market has suffered as a result of declining crude volumes. We explained in Part 1 that what originally started out as just a market for Brent North Sea crude morphed over time into a mixture of dozens of different North Sea crudes that are delivered as four streams at terminals in the UK and Norway. The reason they kept adding to the crudes included in the BFOE definition was to counter declining production volumes. The overall BFOE production volumes are still declining – down from about 1.6 MMb/d in January 2006 to just over 1 MMb/d today (source: Platts). The problem is that as the production volumes decline, the number of cargoes of crude (sold in 600 MBbl parcels) available to trade in the physical market is reduced and the risk of market manipulation goes up.
Unfortunately for the BFOE market participants, the declining volume of crude production is not the only constraint on the trade assessment process. A new dimension to the trading liquidity challenge has arisen in the past 6 years that lies at the heart of the present market discussions – the issue of crude quality. RBN readers familiar with the crude oil markets will know that every crude is different and that the relative values of crudes depend on certain key attributes such as sulfur content and density. Generally speaking those crudes that have lighter density (expressed by the oil industry in Degrees API Gravity) and low sulfur are more valuable than crudes that are heavier and sour (meaning high sulfur). These quality differences mean that each crude has a different market value and that over time the quality of a particular crude may change as its production declines.
For the BFOE market the quality issue came to a head because the terms that govern physical trades between participants – the Shell UK Oil company “SUKO 90” contract – involve trading on a forward basis during the months before producers are allocated physical crude. Transactions in this forward market then become “wet” when a seller nominates a 3-day window for the buyer to pick up the cargo. The contract says that you can deliver any of the 4 crude streams against these forward commitments. This was not a problem originally when the quality of the Brent crude stream was consistent. Over time, as crude streams were added – marked differences in quality arose. In 2007 production from the huge Buzzard field was added to the Forties stream causing the sulfur content of Forties crude to increase considerably. Up until that point most North Sea crudes had been light sweet crudes with low sulfur. Buzzard is a heavier sour crude that has a lower market value than the other BFOE crude streams. As a result all BFOE forward contracts were pretty much bound to have Forties cargoes delivered against them. That is because – given the choice – a producer will deliver the least valuable crude against a forward contract that stipulates any BFOE grade is acceptable. That in turn reduced the market size from 4 crude streams to just Forties and reduced the price of forward Brent assessed by the reporting agencies because everyone assumed the deliverable would be Forties.
The BFOE participants addressed the Forties sulfur issue by adding a quality de-escalator clause to the SUKO 90 contract in July 2007. The current (March 2013) sulfur content of the Forties stream crude is 0.79 percent compared to Brent (0.45%), Ekofisk (0.23%) and Oseberg (0.27%). The idea of the sulfur quality de-escalator is that the price of Forties cargoes traded in the BFOE market is discounted by a factor (currently $0.35/Bbl) for every 0.1% sulfur above a 0.6 percent “standard”. [This sulfur de-escalator is similar to the density escalation factors that US crude buyers use in their posted price bulletins (see The Bakken Buck Starts Here – Part I).] With the agreement of the BFOE participants, Platts set up the de-escalator and advise changes in the factor over time based on the relative values of refined products with high and low sulfur content.
The purpose of the sulfur de-escalator is to level the crude stream playing field. Price reporting agencies assess the BFOE market as a whole based on the ability to deliver any of the 4 crude streams but if the seller delivers Forties they have to “rebate” the buyer with the sulfur de-escalator. That means the lower price of Forties will not drag down the overall BFOE assessment. However the mechanism is far from perfect and the price of Forties cargoes continues to track lower than other crude grades in BFOE. During 2012 individual cargoes of Forties (not sold into the BFOE market) traded about $0.25/Bbl below Brent, $1.00/Bbl below Ekofisk and $1.25/Bbl below Oseberg on average. As a result those participants that deliver cargoes into the BFOE forward market almost always deliver Forties crude to meet their commitments.
In effect the number of Forties cargoes now dictates the size of the BFOE assessed market. The quantity of crude in the Forties stream has fluctuated over time but is around 400 Mb/d at the moment – amounting to 20 X 600 MBbl cargoes each month. In recent months two additional factors have impacted the Forties market and with it BFOE price assessments. The first is that maintenance work in the Buzzard field has reduced production causing a decline in Forties cargoes. At the same time a Free Trade Agreement between the EU and South Korea has given that country a tax incentive to buy North Sea crude. The Koreans desire to buy medium sour crude and have been snapping up cargoes of Forties directly from producers without going through the BFOE market.
So larger BFOE producers such as Shell and BP are once again looking to implement reforms to the BFOE market terms in order to increase the number of crude streams that participants will deliver against the contract. The latest proposals – still being ironed out between producers and Platts – involve quality premiums being included in the price of Ekofisk and Oseberg crudes. Shell and BP also want a quality premium included for Brent crude but Platts want to consider market feedback before agreeing with that. The idea of the quality premiums is similar to the sulfur de-escalator for Forties. If sellers deliver Ekofisk, Oseberg or Brent against a BFOE contract the buyer would have to pay a premium based on prior month average spreads between assessments for these crudes.
At the moment the original Shell proposal to unilaterally alter the terms of its SUKO 90 contract beginning in May 2013 to reflect quality premiums has been postponed until June while the industry works out a compromise on which crudes will attract premiums and how they will be calculated. Since none of the parties involved has any interest in dividing the market into two separate camps, it is likely that they will agree terms before long. Then the market will hold its breath to see if more BFOE trades materialize based on the new “level playing field”.
Hearing all these woes from billion dollar trading companies concerned about a few cargoes of crude a month you might be forgiven for thinking “so what?” The trouble is that all these quality differences and concerns about physical market liquidity are closely linked to the Brent ICE futures market and that in turn is linked to crude oil pricing formulas around the world. What impacts Brent then impacts WTI. For example the continued strength of the Brent price against WTI is in part due to the limited supplies of BFOE cargoes causing Brent futures to strengthen against the US benchmark.
In conclusion even though the vast majority of crude trading these days is carried out in futures markets the exchanges do not work effectively unless they are linked to underlying physical prices. The convoluted terms of the BFOE contract and the sky-high price of playing in the 600 MBbl cargo market should not detract from their critical role in setting world oil prices at the margin. Recent US crude market experience has shown the extent to which physical disruptions can impact prices. The continued efforts of North Sea producers to preserve order in their household is perhaps more understandable in the circumstances. That might be worth remembering that when you hear calls for new market pricing mechanisms for light crude streams flooding into the US Gulf Coast market.