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Ross McCracken

Ross McCracken

Ross is an energy analyst, writer and consultant who was previously the Managing Editor of Platts Energy Economist

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Uncertain Times For Dated Brent


The global crude oil benchmark Dated Brent is set to change once again this November as S&P Global Platts, the benchmark’s custodian, introduces trade in North Sea grades delivered on a CIF Rotterdam basis.

Change is by no means new to the benchmark; it has evolved constantly over the last two decades, essentially reflecting the decline of North Sea oil production. The basic problem is ensuring liquidity i.e. that there are enough physical, tradeable cargoes of oil. If volumes fall too far, the physical market becomes increasingly susceptible to manipulation.

The original system, developed in the 1980s, was based on trade in crude from the prolific North Sea Brent/Ninian system, but cargoes of the actual Brent Blend are now few and far between, with the system now producing only around 100,000 b/d.

The solution has been the steady addition of North Sea grades to the benchmark – in 2002 Forties and Oseberg, the first Norwegian crude to be included, then Ekofisk in 2007 and most recently in January 2018 Troll. The inclusion of new crude grades is not simply about volume, but also supply and demand-side diversity. New grades tend to expand the number of companies with equity in the system and the range of buyers. This too is a safeguard against manipulation.

A second means of expansion has been to extend the loading dates of crude cargoes that can be included. This has been changed from 7-15 days to 10-21, then to 10-25 in 2012 and finally to 10 to one calendar month forward in 2015.

A third means of benchmark evolution has been the use of derivatives as value indicators. For example, Brent contracts for difference for a particular loading period provide a good indication of physical cargo value in that period relative to other loading periods.

All in all, this provides a range of data points in addition to actual cargo trades, adding to the accuracy and robustness of the price assessment.

Rising complexity

However, the benchmark’s evolution has been accompanied by increased complexity as a result of differences in the qualities of the grades included. Oseberg, for example, typically trades at a premium to Brent, and a quality premium must be applied.

Similarly, Forties typically trades at a discount to Brent and suffers from fluctuations in its sulphur content depending on how much of the crude stream is being made up by the Buzzard field. As a result, a sulphur de-escalator is included. Like the quality premiums, it is intended to normalise trade in different grades to provide a level comparison of values.

All of the grades currently included in the benchmark are traded on a free-on-board basis, so the inclusion of CIF (cost-insurance-freight) trades marks a significant departure and additional complexity.

Statfjord, one of the North Sea’s largest crude streams, has never been included because it is traded on a CFR (cost-and-freight) basis with a dedicated fleet of tankers. The freight cost element of the traded price is therefore opaque, preventing accurate value normalisation against other grades.

Future evolution

Further benchmark evolution is a certainty. A study by the Oxford Institute of Energy Studies published in March says summer maintenance could reduce the volume of oil available for Dated Brent price assessment well below 800,000 b/d this year, a level which the study says is “usually considered the minimum needed to ensure the benchmark’s liquidity and its integrity.”

It cites a Platts estimate that the total volume of current benchmark grades will fall below 500,000 b/d by 2024.

There are many possibilities for expanding the benchmark, but all bring with them difficulties, some of them perhaps opportunities.

Nigerian crudes have been considered, but not found favour, in part because they tended to trade into the US east coast rather than the North Sea, trade which has now declined as a result of US shale oil. The frequency of disruptions as a result of social unrest in the Niger Delta and the high level of corruption that pervades the Nigerian oil industry have also weighed against Nigerian crudes.

The other major crude flow into Northern Europe is Russian Urals Blend traded CIF out of Baltic Sea ports. However, this too presents problems. First, the quality difference is large, Urals being a heavier crude oil with higher sulphur than the lighter North Sea grades. Urals quality is also declining as lighter, sweeter grades are being sent east to China.

Second, upstream equity ownership is dominated by state-owned Russian companies, which tend to use subsidiaries and intermediaries to trade Urals, where transparency is again an issue.

CIF trade inclusion

As a result, Platts has stuck with the North Sea format, although introducing CIF Rotterdam trade may not greatly expand the volume of trade included in the benchmark, nor address the underlying production decline of crudes currently included in the assessment.

Moreover, CIF Rotterdam cargoes perhaps invite controversy. Normalising a CIF Rotterdam trade means adjusting for freight, insurance, transportation time and port costs, as well as “different types of optionality”, as Platts puts it.

In some cases, the freight cost and options may be directly visible, if reported in the freight market, but in general a freight adjustment factor will be applied and typical charter party options assumed.

The degree to which CIF Rotterdam cargoes are reported to Platts might in itself prove an indicator of their usefulness to traders. Cargoes loaded from land-based storage other than the crude’s original loading terminal are sensibly excluded.

Toe in the water

However, longer-term solutions to underpin Dated Brent’s benchmark status are close by. Norway’s state oil company Equinor is well advanced in the development of the North Sea Johan Sverdrup field, from which first phase production is estimated at 440,000 b/d, rising to peak production of 660,000 b/d in 2023.

Johan Sverdrup crude (API 28.0) is heavier than Buzzard (API 32.6), the main grade of Forties Blend, but lower in sulphur at 0.8% by weight compared with Buzzard’s 1.4%. Its ownership is fairly broad, including Equinor (operator, 40.03%), Lundin (22.6%), although Equinor also owns 20.1% of Lundin, Aker BP (11.57% -- a partnership of Aker, BP and DNO shareholders), Petoro (17.36% - the Norwegian state’s direct stake) and Total, via its 2018 acquisition of Maersk Oil, (8.44%).

It seems a good fit for inclusion, so why then has Platts opted for the complexity of CIF trades?

The timing of the field’s start-up is an issue, but as OIES study author Adi Imsirovic points out, the introduction of CIF Rotterdam trade may be a stepping stone to the introduction of light, sweet US crudes, which trade into Europe on a CIF basis out of the US Gulf Coast.

This would provide potentially long-lasting crude streams, addressing the inevitable long-term decline of North Sea oil, Norway’s production renaissance notwithstanding. It would also provide a new elasticity in available volumes as US crudes move to Asia, Europe and elsewhere, the direction of travel depending on demand and price.

Brent/WTI spread liquidity provides for easy hedging between the international (Brent) and inland (WTI) benchmarks. It could bring a wider range of US producers into the physical Brent market.

In turn, this may consolidate Brent’s global role, but may also serve to internationalise WTI, with a key pricing point emerging on the US Gulf Coast, particularly as the locus of oil import demand shifts to Asia. It could diminish the current status of the Oman/Dubai assessment, which is used to price crude into Asia, but which has historically failed to develop a liquid futures market on the scale of Brent or WTI.

Despite its quality differences, the inclusion of Johann Sverdrup into the Dated Brent benchmark appears likely sooner rather than later. However, it would represent yet another stop-gap. US crude inclusion potentially offers a longer-term solution, one which ties in liquidity to the Brent/WTI trading complex, but potentially also shifts trading volume away from London to the US.

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