Oil Pricing Systems

The broad details of how oil is priced in the world market have remained the same for more than thirteen years. Indeed, the current system has now survived for as long as direct setting of an administered price by OPEC did. The system itself may have been stable, but the past thirteen years have seen major changes in the underlying fundamentals of the oil markets, and also in the nature of oil trading.

In the physical market, the pattern of world trade flows has changed. The US import gap has risen steadily, and now represents about of quarter of the volume of international trade in crude oil. Within that increase, the balance of US imports has shifted away from long-haul towards short-haul sources, and towards heavier crude oil. The Asian import gap has also risen sharply, while Europe’s has contracted due to the steady increase in North Sea production. West African crude oil now occupies a pivotal position, and swings into all three of the main crude oil consuming regions according to market conditions.

The changes in the physical market may have been profound, but the rate of change has been greater in oil trading. When producer countries first adopted market linked indexing as a pricing system, the NYMEX light sweet crude oil contract was only in its fourth year, and the current IPE Brent contract was still a year from fruition. Since then the volume of futures market trading has increased remorselessly, and the volume on informal markets such as forward Brent has declined. From being a novelty, futures have grown to be the dominant part of the trading system. Trade in absolute prices in spot markets was universal in the mid-1980s, now it is almost extinct and the role of price discovery in the market has moved to NYMEX and IPE. In general terms, the futures markets set the level of prices, and the physical markets set the differentials.

Added to the above changes are the changes in the physical base of the main markets. In short, all three of the key world marker crude oils, WTI, Brent and, most severely, Dubai are in long term production decline. So, if the world has changed, if the nexus of trading is now the futures exchanges and if the production levels of the marker crudes are declining, does that mean that the current system of pricing crude oil is under pressure? Over the next decade or so, will it mutate through evolution, or by forceful change?

Let us start with production levels. There is no unique answer as to how low production levels can go before the integrity of a market is threatened. As long as confidence is maintained, and as long as the narrowness of the production base does not lead to constant squeezes and distortion, a market can persevere. An extreme example of this is the market for Alaskan North Slope (ANS) delivered into the US Gulf. The major change in oil pricing mechanisms over the last decade has been the substitution of ANS by WTI in producer country formulae for exports to the USA. However, before this substitution occurred, the market had survived for some time with absolutely no traded physical base at all. California took an increasing proportion of ANS, and only a trickle was left to make the long journey into the US Gulf, and even that tended to be an internal company transfer rather than traded into the market. The quotation became based entirely on journalists’ summaries of traders’ perceptions of the price that ANS in the Gulf would be trading at, if there actually was any. It may sound bizarre, but this normally produced reasonable numbers. It is after all rather hard to squeeze a market that doesn’t exist.

The ANS market represents an extreme, but at least demonstrates that there is no critical lower limit on production. For WTI and Brent, production declines are in any case not of any magnitude sufficient to cause too much trouble over the next decade. The Dubai market is another story. For several years I have argued that Dubai has ceased to be a meaningful market, and has become increasingly distorted. The production decline only exacerbates the problem.

What then of the idea of linking prices to futures market prices? When formula pricing began, there was a suspicion in the minds of some key producers about the nature of futures prices, and using Platt’s quotations for the physical market implied a greater grounding in the physical market. The suspicions may have abated, but the most important numbers in the world oil trade remain the Platt’s quotations for forward WTI and for dated Brent.

In the case of the US market, there is no reason at all why NYMEX prices should not be used in formulae, indeed it would make little difference if they were. The NYMEX contract is a physical one, in that being a pipeline contract delivery can be made for the one thousand barrels volume of a single contract. What Platt’s assess is the same thing, albeit in its informal forward rather than futures manifestation. The only major difference is the timing of the quote, with Platt’s assessing WTI for time in the hour after the NYMEX close. One could argue that linking directly to NYMEX creates an incentive to manipulate the closing price in the frenetic last few minutes of trading, but that incentive already exists as an way of influencing the information available to the Platt’s journalists.

Direct pricing using futures prices would work in the USA, but would not represent any major change to the system. For Brent, however, matters are more complicated. A major feature of the Brent market is that it works extremely well as long as one does not think about it too hard. Physics may say that the bumble bee can not fly, but the bumble bee does not think about it. Financial theory would not produce a design like Brent, but Brent traders should also not think about it. The market has in general evolved more through chance than design, and IPE Brent is the one formal element within in interrelated mesh of markets. While EFP provisions can be used, the contract is not physical. It is cash settled as delivery can not be made for the standard contract volume in what is a cargo and not a pipeline market. In the USA, the futures market has supplanted the informal forward market. For Brent, the two markets are complementary, in that the futures market relies on the forward market to provide a physical grounding through the construction of the IPE index.

In the USA, the near month NYMEX contract is as close as one can practically get to spot pipeline crude oil, given the logistics of pipeline scheduling. In that sense, there is no such thing as dated WTI. In Brent of course there is the problem of dated Brent. The Platt’s quote for dated Brent directly or indirectly prices about two-thirds of all oil moving in international trade. Yet dated Brent is prone to chronic distortions: there is little reported trade, no trade in absolute prices as opposed to a differential, and the quote is leveraged by CFD market activity. One can not get away from the fact that the quote is often manipulated. By contrast, IPE Brent has a volume of trade around a hundred times greater, and is for all practical purposes just about impossible to manipulate sustainably. So, should the role of dated Brent be taken by futures Brent?

The answer depends on how badly dated Brent is distorted. The logic of using dated Brent as an index is that with delayed pricing from time of loading, it guarantees competitiveness of long haul crude oil with short haul at the time of delivery to Europe. Moving away from this reduces that competitiveness, as the basis risk between futures and spot can be significant. On the other hand, if dated Brent is prone to wander off on its own due to distortions, then its use does not exactly pick up true spot values, and leaves both producers and refiners prone to frequent annoyance and discontent. By contrast, futures prices are highly transparent. In short, the best index is an undistorted dated Brent. Without that, to my mind both futures prices and distorted dated Brent prices are both less than ideal, but all in all one might as well use futures prices.

A move to futures indexing has been in progress, advanced notably by the changes in Saudi Arabian pricing formulae for exports to Europe. However, one should be under no illusion that this represents a triumph for the market. It is a major defeat, in that it implies that self-regulation had failed in the area of pricing spot crude oil. The latter is a disaster in several ways, which is why I am always perplexed when significant oil companies distort the physical Brent market through a deliberate trading strategy. Perhaps the idea of trading as an independent and separate profit centre has just gone too far in some modern corporations.

Ultimately, the power to make major changes in the oil pricing system rests solely with the major producing countries. Such changes are often discussed, and the price weakness of 1998 and early 1999 increased the depth and range of such discussions. Currently the policy of ‘if it ain’t broke don’t fix it’ still holds sway, and indeed the Saudi Arabian changes are to some extent superficial given that dated Brent still plays an explicit role. The current system can generate $30 per barrel for the producers, and it can generate $10 per barrel. The volatility in prices is related to the efficiency of output management, regardless of the system used. If the current system begins to creak, then producers have plenty of options for alternatives, and the change could be drastic. The onus is again put on major oil companies to behave responsibly, unless they wish to hasten the move back to at least a semi-directly managed method of price formation. The transition has happened several times in the past, and one should not assume that the oil market over the next decades will be immune to radical change.

A version of this article first appeared in Pipeline, the magazine of the International Petroleum Exchange.

By: Paul Horsnell


Energy Economics , Energy Policy , Oil


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