Oil markets need pricing benchmarks. Despite its overall size, the underlying physical market is too fragmented and too illiquid to generate reliable prices for every grade of crude oil that is produced and traded around the world. And without standard reference grades such as Brent, WTI, Dubai and Oman that can be used in contracts, physical oil trading would be much more complicated and uncertain– and oil price risk management more costly and less effective.
But oil pricing benchmarks face growing difficulties. Underlying production is falling and there are no obvious physical substitutes that can be used. Output from all the big fields in the North Sea is well past its peak and the average size of new fields is very small. The supply of Brent Blend has slumped to less than 400,000 b/d compared with around 1mn b/d in 1990 when the Brent and Ninian streams were first commingled. And plans to boost the physical volume of Brent at the Sullom Voe loading terminal with a pipeline to Norway’s Statfjord field have been shelved. As a result, there are only 20-25 cargoes available each month – less than one a day – exposing the Brent market to the risk of squeezes and making it difficult to assess price levels.
Pricing benchmarks are also under attack throughout the energy industry as regulators start to question their validity. Investigations into electricity price spikes in California by the US Federal Energy Regulatory Commission (FERC) revealed that Enron had supplied misleading information about its trading activities to the price reporting services. And other energy companies – Williams, Dynegy and American Electric Power – have admitted supplying false information about gas and electricity trades to price reporters, undermining the credibility of a wide range of energy price assessments that are used to settle physical and derivative contracts. At the same time, a US Senate Committee has been investigating claims of price manipulation in the Brent market, and the UK Financial Services Authority (FSA) has new powers to combat market abuse.
This sudden surge in regulatory interest over the past year put the Brent market in the spotlight, increasing the pressure on the oil industry to resolve persistent problems caused by declining output and reduced liquidity in the physical and forward markets. With fewer physical cargoes available to the market, dated Brent had been experiencing serious price distortions for several years, making it less acceptable as a marker for nearly 20mn b/d of Atlantic basin crude. And Saudi Arabia had already switched to using a futures market price index – the IPE Brent Weighted Average (BWAVE) – to value cargoes sold to European buyers. As a result, the industry finally saw the need to act, agreeing last summer to a wider physical base for price assessments – Brent, Forties and Oseberg (BFO) – together with a new forward 21-day BFO contract to replace the old forward 15-day Brent contract.
"the physical oil market is becoming less transparent and published price assessments are less reliable"
Although these changes have helped to reduce the risk of price distortions for this key price benchmark, the industry still faces a much greater challenge which threatens to weaken the entire structure of the global oil market. Trading is in retreat. Mergers had already reduced the need for trading before the collapse of Enron, but growing concerns about counterparty risk and market abuse have taken a further toll. Companies are much more circumspect about the type and amount of information they are willing to provide to the price reporting services, making it increasingly difficult for price reporters to do their job effectively. The physical oil market is becoming less transparent and published price assessments are less reliable – exposing the industry to the threat of greater regulation in the future.
The most important function of the Brent market has always been to establish a price for the physical commodity. When the Brent market first emerged – just over twenty years ago – the oil industry was in transition from a world characterised by short supply, term contracts and official government selling prices to one with weak demand and a growing surplus of spot crude. Companies therefore needed to find a new way of setting the price of oil that was not only independent of producer governments but also acceptable to the tax authorities.
What began as a physical oil market, buying and selling North Sea crude at fixed outright prices quickly acquired other functions. The development of the 15-day Brent contract allowed companies to sell short, creating a forward market structure that provided new opportunities for more effective price risk management in an increasingly volatile environment. Although futures markets offer similar opportunities for hedging and speculation, the companies involved preferred to develop their own market so as to maintain the essential link between physical cargoes and forward paper oil which had become so important for tax purposes. In addition, the very large size of a physical Brent cargo – originally 600,000 barrels – made it difficult to devise a credible futures contract based on physical delivery.
With about three-quarters of UK North Sea crude production being traded at arms-length by the mid-1980s, the Brent market became the undisputed locus of price discovery in the Atlantic basin. In its heyday during the late 1980s, the 15-day Brent market traded over 30 cargoes a day typically at fixed outright prices, much more than the fledgling IPE Brent futures contract, making it a significant competitor to the Nymex WTI crude futures contract at the time. But trading 15-day Brent was never easy since the market relies on a cumbersome and unpredictable clearing procedure which involves passing a dated Brent cargo along a “daisy chain” of forward 15-day contracts.
Certain features of the 15-day contract such as “clocking” and the “tolerance game” made trading Brent a risky proposition. Since the contract specified that cargo nominations must be made by five o’clock on a working day with a minimum of 15 days notice of the first day of the date of the bill of lading, a company that had both bought and sold on the forward market could suddenly find that it was unable to pass on a dated cargo in the time available, leaving it unexpectedly both long and short in the physical market. In addition, the 15-day contract allowed the seller to vary the quantity supplied by plus or minus five per cent for operational reasons, creating an opportunity for sellers to maximise profits and minimise losses while increasing the risks for buyers. Consequently the oil industry found other ways of hedging its dated Brent price exposure without trading directly on the forward Brent market and the number of active participants in the 15-day Brent market dwindled over time.
there was a gap in the forward market structure that needed to be covered
But the industry still needed the forward Brent market – or something very much like it – because it formed an essential bridge between the much more liquid IPE and Nymex crude oil futures markets and the less liquid prompt market. Since both the IPE Brent and the Nymex WTI futures contracts expire up to six weeks ahead of the physical oil market in the Atlantic basin, there was a gap in the forward market structure that needed to be covered by other kinds of derivative trading instrument that companies could use to manage the residual price risk. With most of the crude oil traded in the Atlantic basin priced using formulas related to Platts dated Brent assessments, the gap was filled by a mixture of forward trading using standard 500,000 barrel 15-day Brent cargoes, smaller “partial” Brent contracts which could be settled financially, and Brent CFDs – a swap or “contract for differences” based on the weekly average price differential between Platts assessments for dated and forward Brent.
This gap in the forward market structure still exists, which is why the industry has had to find an alternative to Brent that could be used both as a pricing benchmark and as a link between the futures markets and the underlying physical oil market. Although the IPE is now looking seriously at the possibility of adapting its cash-settled Brent futures contract to physical delivery, this is far from straightforward. The very large size of a physical cargo means that delivery could only occur in blocks of 600 contracts, making it difficult to match long and short positions. While the industry has identified other obstacles, such as legal and operational constraints, counterparty risk and taxation, which would need to be overcome.
For the time being, the industry has little option but to try to make BFO work. It cannot manage without a physical price assessment to use as a benchmark in contracts. And it still needs the forward contract to provide the cash-settlement prices for the IPE Brent futures contract. But BFO trading volumes and market liquidity remain depressed, with activity concentrated around the expiry of the IPE Brent futures contract and the narrow pricing window used by Platts to determine its BFO price assessments. There are very few full cargo trades – which the IPE needs for cash-settlement – and most of reported deals are for partial Brent. Although BFO provides a bigger physical base (1.5mn b/d) reducing the risk of squeezes, it is a less precise benchmark making it less attractive to trade. In normal circumstances, Forties and Oseberg trade at a premium to Brent, but the BFO price assessment mechanism and the forward 21-day BFO contract allow them to be used as a direct substitute for Brent, and this optionality creates an additional price risk.
for the time being the industry has little option but to try to make BFO work
In the longer term, the oil industry needs to find a more effective solution to the problem of pricing benchmarks. One alternative (suggested in a CGES Global Oil Market Report, March-April 2001) would be to create a market based around a spot crude price index, which could be derived either from assessments published by the price reporting agencies or by explicit reference to the futures markets for Brent or WTI. Price index markets are already used successfully in financial markets, for example the FTSE 100 or S&P 500, but have not yet been tried in oil where the peculiarities of the physical oil market seem to pose so many difficulties. Nevertheless, simply substituting the word “Index” for “Brent” or “BFO” in the current North Sea market structure makes surprisingly good sense.
A spot price index based on a weighted-average blend of North Sea crudes would have several advantages compared with BFO that could help to improve liquidity and price tranparency. It would eliminate the grade options which blur the value of the benchmark and deter forward market trade. It would also provide a more effective link between the futures market and the underlying physical oil market by eliminating the gap in the forward market structure that creates a need for alternative hedging instruments. If the IPE futures contract was settled using a spot price index rather than forward BFO it would improve the convergence between futures and physical oil, reducing the risks of trading in the six-week delivery window that is currently outside the scope of the futures market.
Although the industry has always been reluctant to move away from physical benchmarks such as dated Brent or BFO, it may be running out of time. If the change to BFO does not improve liquidity and transparency soon, the industry will have to find a better method of pricing oil – or risk having a solution forced upon it.
This article was published in Oxford Energy Forum (February 2003) as a contribution to a debate on the future of the Brent/BFO market.