I have spent a lot of time recently with oil producers who, with some notable exceptions, are very gloomy indeed.

Anyone who reads my blogs or books knows that I have never forecast oil prices and I don’t intend to start now. The oil price is fundamentally unforecastable, prone as it is to political shocks and unforeseen events.  Instead I prefer to consider trading opportunities as they arise and deal with life as it is, not as I would like it to be.

Trading Opportunities for Producers

The current reality is low oil prices and a market in contango (See Chart 1).  Producers who spent last year slashing costs and have little fat left in the system may wish to consider selling options. This needs some further explanation because it is not a strategy that is suitable for every company and it requires a good deal of in-house analysis before entering the market.

Chart 1: The Forward Oil Price Curve

Source: Mercuria

Ordinarily I would expect to be advising producers to consider buying put options to protect them against further falls in the oil price, not selling them. But the response I get from many producers at the moment when I suggest spending money to buy oil price protection is hollow laughter.

For those companies that have cash and want to go on hedging against further falls, Table 1 shows some indicative quotes of what it would cost currently to buy put options that have a strike price that is $5/bbl out-of-the-money (“OTM”) and $10/bbl OTM. [Anyone who needs a quick refresher on how swaps and options work will find one in Chapter Six of “Trading Crude Oil: the Consilience Guide”. See here.]

Table 1: Put Option Premia at Varying Strike Prices

Source: Mercuria

In other words, to hedge against a further fall in prices by $5/bbl below current levels, would cost between $1.25/bbl in the second quarter of 2016 and $6.61/bbl in the fourth quarter of 2017.  So for a cost of $1.25/bbl paid upfront a producer would have full protection against prices below $35.46/bbl in the second quarter of 2016, but would have no protection against prices between $35.46/bbl and the current swap level of $40.46/bbl.

Companies who baulk at shelling out cash to buy price insurance in the form of options often finance the purchase of the options that they need for hedging purposes by selling other options. Commonly, a cash constrained producer that is risk averse may sell call options to finance the purchase of the puts it needs for hedging purposes. The price of call options that are $5/bbl and $10/bbl OTM are shown in Table 2.

Table 2: Call Option Premia at Varying Strike Prices

Source: Mercuria

A producer that is worried about, say, prices below $40/bbl in Q1 2017 might finance the purchase of $39.89/bbl put options by selling, for example 195 x $54.89/bbl call options for every 100 x $39.89/bb/ put options that it purchases. [195: 100 = $4.55: $2.34]. The producer may judge that if prices recover and it is forced to sell at $54.89/bbl, then that would be preferable to not having put option protection and having to sell at less than $39.89/bbl.

Alternatively the producer might finance the purchase of puts by also selling puts, but at different strike price levels. For example, a producer who wants to protect itself against prices below $38.70/bbl in Q4 2016, but who does not believe prices will again fall below $34/bbl, might sell 172 x $33.70/bbl put options for every 100 x $38.70/bbl put options it purchases.

This is not an approach for the faint-hearted because if the producer has called the market wrong, it may find itself being forced to buy oil at $33.70/bbl in a falling market

Any company suffering a cash flow crisis in this price environment may wish to consider simply selling options to raise cash. For example a producer facing an average 2017 swap price of $46.10/bbl may prefer to sell call options at an average strike price of $56.10/bbl and receive an upfront premium of $3.15/bbl.

If the producer sells the swap at $46.10/bbl all the price upside above $46.10/bbl is lost, but the producer is protected against a 2017 price of less than $46.10/bbl. If instead the producer sells the $56.10/bbl call option, it will retain the price upside to $56.10/bbl, but has no protection against any fall below the current 2017 price level of $46.10/bbl. However it can bank $3.15/bbl today to tide it over to see how prices unfold.

Pre-Trading Check List

Before going anywhere near the market there are some questions that producers need to ask themselves. If the company is being encouraged by a derivative provider to start dealing, that providershould also be asking the producing company these questions.

First, what is the producer’s risk profile? This is individual to each company. A good starting point in evaluating a company’s actual price risk is to establish what happens to its assets or its company if the price changes by $5, $10 or $20+/bbl up or down.  Most companies don’t have an exactly linear risk profile and there may be step changes up or down as assets start up or shut down or as fields reach payback and become subject to different marginal tax rates.

The risk profile is easier to assess for producers with production currently on-stream, but that still doesn’t make it easy. A lot depends on the company’s joint venture partners and their attitude to shutting in production if revenue falls below costs. It also depends on any term sales or other contracts to which the producer has committed.

Producers with assets already in production may contemplate selling options on future production to generate upfront premium to be paid now to relieve cash flow pressure.

Producers with assets in development might also be able to explore this avenue of cash generation, but they have to be very sure of when the asset will come on-stream and at what production level in order to construct an appropriate cash generation package.

I can recommend a good therapist to any company seeking to raise cash for exploration purposes by selling options, in isolation from any other production activity. This tool is not for you.

This is because derivative instruments typically pay out or don’t pay out depending on what happens to the oil price. Pay-out happens irrespective of whether the physical asset or field that the financial position is designed to hedge produces or not. For a producer a death-dealing double whammy would be for the price to shoot up, but for the asset to suffer an operational failure to produce. In that case if the producer had sold puts to raise upfront cash, it would be forced to buy oil at a strike price at above current market levels without being able to sell the production from the asset to offset the financial loss.

Secondly, what is the producer’s risk appetite? There are as many answers to this question as there are producing companies to answer it. Oil producing companies are some of the biggest risk takers out there who will spend millions of dollars on a single well happily, but who regard any form of market activity, other than disposing of any oil they find, as a too risky to contemplate.

Remember this old chestnut? “We cannot hedge against a fall in the oil price because that is expressing a price view. That is not an exploration and production company’s expertise nor is it what our shareholders want from us.” Such companies have been disappearing faster than characters in an Agatha Christie murder mystery.

A company can only enter into hedges if its memorandum and articles of association allow it to do so. Even if hedging is permitted, the company does not want to take its shareholders by surprise by entering into hedges that external observers at some later date may be able to characterise as speculative.

This gets us into a very grey area of when is a hedge not a hedge, but is in fact speculation? As an expert witness I wish I had a pound for every time I have encountered that question in audit committees or in courts or arbitrations. The area is grey because, in my opinion, the same action can either be a hedge or can be speculative depending on the circumstances and the intentions of the company doing the deal.

A producing company that sells swaps or buys put options can demonstrate relatively easily that it was hedging the production stream from an asset when it did the deal. But what if the production asset shuts down or, worse, fails to start up? Is it still a hedge or is it now a speculative position?

What about a producing company that buys put options, but finances the purchase by selling call options, i.e. a collar? If buying a put option is akin to taking out an all risks insurance policy, then financing the purchase of the put by selling calls may be characterised as a buying cover for only “third party, fire and theft”. In other words there is a qualification on the type of cover purchased.

The producer is hedged at prices below the put strike price, but does not have the upside above the call strike price.  If the producer would sell its oil anyway if market prices reach the call strike price level, I would argue that we are still firmly in hedging territory. Others may disagree.

How about the producer that sells calls without buying puts? Some would say that this is obviously speculative because writing options is a price risk increasing exercise. However, arguably, such an action may be considered to be hedging the company’s cash flow, rather than hedging its price risk.

If the price falls it will have to sell its production at a lower price, but its cash flow has been boosted by the call option income for calls that are not exercised. If the price rises it will be obliged to sell at the higher strike price of the call, but if it would have sold at that level anyway if it had had the opportunity to do so when it sold the calls, where is a the problem? And in the meantime its cash flow has again been boosted by the upfront call option income.

Thirdly, what is the producer’s market price view?  Oil producing companies that did not hedge when the price was $80+/bbl could be considered to be expressing the price view that prices were going to stay high or go higher. Similarly end users of oil that did not hedge when prices touched the twenties a few weeks back could be considered to be expressing the price view that prices are going to stay low or go lower. If you are in the oil business you have to have a price view otherwise how do you budget or plan?

If you are a producing company that worries about low prices, how low do you think they can go in reality? To zero? Clearly not. $10/bbl? Maybe, but unlikely. $20/bbl? Still a maybe, but a bit less unlikely.

The question is why would you hedge all of the downside below, say, $45/bbl down to $0.00/bbl, if you think that $0.00/bbl cannot happen? You may decide to sell some swaps for 2017 at an average price of $46.10/bbl. At the same time sell some puts at $20/bbl because you do not believe that prices will fall that far and the upfront cash is handy for paying todays bills.

Even if a company believes it has no market price view, but wants to hedge just in case the worst happens, it will still have to take a view on the price level at which to enter the market to hedge. Today’s price? Tomorrow’s price? At $45/bbl or $40/bbl?

All the esoteric option packages that are sold by derivative providers are just combinations of puts and calls at different strike prices, different maturity dates or different volumes. Tailoring a package to suit a company’s risk profile, risk appetite and market price view can be a lengthy and painstaking process. If a derivative provider is prepared to skip over this process and goes straight to pushing a particular package on a company, then warning bells should start to ring.

It would be unwise for any company to enter the market without first analysing its risk profile, risk appetite and market price view. It is essential that any trading action taken is permitted by the memorandum and articles of association of the company and that the board has issued clear delegated authorities to act to qualified personnel.  It’s a good idea to let the shareholders know what you are up to, because they do not like surprises.

Future Blogs

1. Readers of LOL blogs will be aware that there are changes afoot to the benchmark grades of crude oil in which derivative instruments are expressed. Consider the “material change in formula” and “material change in content” provisions of any International Swaps and Derivative Association contracts you enter into with a derivative provider.
2. Cash is not just King, it is the Lord High Emperor and the Grand Poobah. Most frequently trading strategies hit the headlines when a company fails to meet a margin call. Stress test your cash flow as well as your earnings when choosing a financial instrument in which to trade.
3. Producers like to see contango when they hedge, but when prices are high enough for them to want to hedge the market is often in backwardation. Two step hedging of the height and slope of the forward curve may provide an answer.
4. If you enter the market other than to dispose of physical oil, under the European Market Infrastructure Regulation you will have an obligation to, at least, report those positions to a trade repository, even if you are hedging. Be careful of derivative providers who say that this is unnecessary. It may be unnecessary for them depending on where they are located, but it might be necessary for you if you are sitting in Europe or dealing in instruments that have an impact on European markets. See We Are Informed but Are We Any the Wiser?

On 25^th November 2015 there was an agreement between the European Parliament and the European Council on the regulation of benchmarks[1], including oil benchmarks. On 17^th December 2015 the price reporting agency, Platts, held a meeting to discuss, among other things, the future make-up of the influential Dated Brent benchmark.

This brought home to me that either the oil industry will have to rethink radically its current approach to commercial confidentiality or the European rules on the regulation of benchmarks are unachievable for oil. Bear with me and I will explain.

I have blogged ad nauseam on the Dated Brent benchmark [See “WE ARE GONNA NEED A BIGGER TANK” and “The BATTLE OF THE BENCHMARKS”] and I do not intend to cover old ground in this blog.  Suffice to say that the Dated Brent benchmark, in its current form, has built in obsolescence, because the four blends of crude oil that make up the Brent (BFOE) basket – Brent, Forties, Oseberg and Ekofisk- are on a declining trend. To ensure liquidity and to prevent market abuse, further changes will have to be made to the composition of the basket.

When and how any such changes may be made raise interesting issues for oil producers in the context of the rules on the regulation of financial benchmarks.

Production Forecasts and Tipping Points

Information available to the participants in the wider oil market, including futures, forwards and derivatives traders, concerning forecast production from oil fields is very sparse and very fragmented. Such information that is available typically shows a, more or less, asymptotic smooth decline in the total over the next 5-10 years.

But that is not how decisions are taken on the future production from oil fields. There are tipping points.  Theoretically oil fields are decommissioned when the cost of production exceeds the revenue from the sale of oil. These decisions are taken in Joint Operating Committee (JOC) meetings by the partners in each field based on a forecast of revenue and costs.

The JOC meetings that have been taking place this quarter have been informed by a forward oil curve well below $50/bbl. It is likely that we will see a spate of oil field closure announcements during the first quarter of 2016 some of which will involve fields currently forming the blends in the BFOE basket.

When sufficient fields using particular infrastructure such as terminals and pipelines cross their tipping point and shut down, this precipitates an economic decision on the closure of the infrastructure itself because infrastructure also has a commercial tipping point.

Any decision to close down an asset is complicated by the impact on the NPV of the asset when the abandonment costs and the tax breaks that are given to companies to cushion the impact of abandonment costs are taken into account.

These are complex calculations that have to be approved by the partners in each joint venture before any action is taken. But in the case of the oil fields and the infrastructure associated with the Brent (BFOE) benchmark it appears that the decision makers may be subject to sanctions, including criminal sanctions, under the Market Abuse Directive if the asset owners do not make these decisions available to market participants promptly and widely.

Information with an Impact on Benchmarks

The EC’s statement on benchmarks referred to above defines a benchmark as “an index or indicator used to price financial instruments and financial contracts or to measure the performance of an investment fund.” The new regulation is in line with the International Organization of Securities Commissions (IOSCO) Principles on Financial Benchmarks published in July 2013.

The EC expresses the opinion that the changes being made “to its market abuse and criminal sanctions proposals alone will not improve the way benchmarks are produced and used. EU regulation is necessary to improve the functioning and governance of benchmarks and to ensure that benchmarks produced and used in the EU are robust, reliable representative and fit for purpose and that they are not subject to manipulation.”

Anyone wanting a quick overview of how the European regulation of markets has worked in the past and is now changing can find this in Consilience’s article “We are better Informed, but are we any the wiser?”

But the significance of European Regulations for oil benchmarks lies in the definition of market abuse.  Market abuse can involve the spreading of false information or it may involve insider dealing.

What constitutes inside information is what now puts oil producers at risk of skating on thin ice. If there is a company or a group of joint venture companies who have taken the decision to close down oil fields or assets that have an impact on a price benchmark, then it is my interpretation of the new rules that the companies are obliged to make these facts known to the market in general.

For example, if you are a market participant say in the USA who is dealing in Brent futures or Brent swaps and options with respect to oil for delivery in, say, the 2016-2020 period aren’t you entitled to know that the value of that benchmark is likely to be depressed by increasing quantities of Buzzard in Forties Blend, the blend that usually sets the price in the Brent (BFOE) basket? Or that one or more of the BFOE pipelines or terminals will shut down if particular fields are shut down so that there is likely to be a material change in formula or content of the price benchmark, using International Swaps and Derivatives Association (ISDA) terminology?

I don’t know the answers to these questions, but I would like to know at what point does compliance with a confidentiality clause in a Joint Operating Agreement crosses the line and become market abuse by with holding price sensitive information? If the joint venture owners of the assets that make up the benchmark do not disclose all they know about the forward production profile of the asset does any action on their part to buy or sell the benchmark grade, or components thereof, become market abuse by virtue of insider dealing?

Call me old-fashioned, but to my mind if I invest in an asset, or invest my shareholders’ money in an asset, I should reasonably expect to enjoy quiet title to the production from that asset without third parties, who may be competitors, or regulators continually knocking on my door for the details of my decisions related to that asset. But it appears that that may no longer be the case. If my asset has an impact on a benchmark price it seems I am required to bare my soul to the outside world, whether it is in my commercial interests to do so or not.

Who is in the Hot Seat?

It is unclear to me from the new rules who is obliged to make “market participants” aware of information that may have an impact on a benchmark price? The field operator? The terminal or pipeline operator? Each of the Joint Venture partners in any “relevant” asset however defined? I am not a lawyer but I do not think the European Directives or Regulations have developed far enough to make that responsibility clear.

Using the example I have cited here- the Brent (BFOE) benchmark- there are a few possible names in the frame of responsibility.

1. There are the oil companies themselves, probably but not certainly, the major oil companies who broadly run the terminals and who also trade in BFOE benchmark instruments, because they could reasonably be expected to understand the market implications of shutting down a producing asset, pipeline or terminal.
2. There is the Norwegian Petroleum Directorate, which has oversight of Norwegian producing assets and infrastructure.
3. There is the UK Department of Energy and Climate Change and/ or the UK Oil and Gas Authority.

The Norwegian and the two UK authorities cited above have historically taken in reports from oil companies concerning their investment and decommissioning plans but have typically stopped short of taking any view or disseminating any recognition of the impact of such decisions on the functioning of price benchmarks. That has not in the past been their jobs. Such government departments have a duty of confidentiality on the commercial aspects of the data reported to them.

The question is does the EC ruling concerning the regulation of benchmarks require such authorities to break this duty of confidentiality in the cause of the market transparency and the integrity of benchmarks?

It seems that the Law of Unintended Consequences has again raised its head in the oil market.

[1] http://ec.europa.eu/finance/securities/benchmarks/index_en.htm

Sale and purchase contracts are likely to need some revision before the ink has dried on supply commitments for 2016. Also those who have hedged their operating revenue or have financed capex based on the forward oil price curve of one of the existing benchmarks – Brent, Dubai or “WTI” – better familiarise themselves with the concept of basis risk. Because it is all change again in the world of price benchmarks.

Dubai

We wrote back in September about the Chinese dominance of the Dubai price benchmark and mentioned that the Dubai basket, then Dubai, Oman and Upper Zakum, was likely to be boosted to include Al Shaheen. (“https://ceag.org/the-battle-of-the-benchmarks/”)

This is now the subject of an industry consultation with the addition of Murban as well as Al Shaheen to pad out the volume even further to dilute the dominance of China. It is unlikely that the traders who exited the market like scalded cats in August will be tempted back that easily.

Oh no! Not Brent Again!

Brent is again up for re-definition as production of the four basket grades that make up “Brent” – Brent, Forties, Oseberg and Ekofisk – continue to decline and need another transfusion of oil to keep it going a bit longer.

There is a meeting scheduled for 17^th December to discuss which oil to add next.  Ideas continue to circulate about adding increasingly disparate qualities of oil from different geographic regions to the basket. My heart sinks at the very thought! We are already in a pickle over appropriate quality differentials for the four reasonably similar oils in the Brent basket. Bringing in oil that is even more dissimilar from further-flung regions is storing up even more quality differential trouble and adds in a freight distortion that might have to be resolved by subjective freight differentials too.

I fear that what may be proposed to sort Brent’s problems is some form of contract that requires foreign grades of oil to tranship through Sullom Voe, the loading point of Brent, in order to become part of the Brent basket. I can envisage that idea being seductive to anyone who has never been involved at the sharp end of trading.

The logic might run as follows: Sullom Voe is the loading point of Brent, so to keep the Brent brand name active, foreign grades of oil should sail up to Sullom Voe, discharge oil into under-utilised facilities at Sullom Voe to be load onto ships as part of the forward Brent (Brent / Forties / Oseberg / Ekofisk) market. With North Sea production declining even more sharply than previously anticipated because of low oil prices and with West of Shetland oil migrating to Rotterdam (witness Schiehallion) Sullom Voe has under-utilised assets that will require the payment of prohibitive abandonment costs to shut down.

There is a line of argument that suggests that using the Sullom Voe facilities to tranship “foreign” oil through the North Sea to support the Brent benchmark brand of price index may solve the problem. It won’t. For example, how much African, Caspian or South American oil is refined in N. W. E. and is brought as far north as the Shetlands by the natural pattern of trade? Not a lot, because when it comes to shipping oil around the globe fundamental freight and inter-regional oil price differentials inform the basic economics of decision-making and dictate where oil is refined and traded.

So let’s hope that the December 17^th meeting avoids the obvious trap of asking the market to ship oil to where there happens to be empty tanks rather than to where the refineries and the seat of demand are located.

An Ideal World

It would be great to be able to start again with a whole new benchmark that works in today’s and tomorrow’s circumstances without the constant need for tinkering.

The characteristics of an ideal benchmark would be:

1. A large volume of production, such that it is difficult for any party to “corner the market”;
2. A large number producers to prevent one company, whether a NOC, an oil major or a large independent, controlling supply;
3. Stable quality that does not have any particularly difficult physical attributes, so that the grade can be bought by a large number of refiners;
4. Good loading terminal logistics with enough storage to accommodate a number of days of production with sufficient flexibility to handle operational changes and shipping delays;
5. Sufficient  jetties with capacity to load a range of tankers to optimise freight and promote inter-regional arbitrage;
6. A transparent lifting schedule so that all buyers and sellers can assess the changing availability of cargoes on an equal footing;
7. Standardised, transparent general terms and conditions of trade, so that companies can buy and sell repeatedly on back-to-back terms; and,
8. A benign host government that does not intervene in either price or supply.

There are no obvious candidates to take over the role of international crude oil price benchmark by ticking all these boxes. But it is not beyond the realms of possibility to create one.

If I had a magic wand I would create an independent storage facility somewhere between Gibraltar and Cyprus, let’s say in good stable old Malta, just for illustrative purposes.  The Med market is a great passing place for oil from the Caspian, the Black Sea, West, North and East Africa, and even the North Sea.

This Malta facility would offer three sets of commingled storage tanks for light, medium and heavy crude. There would be limits on the quality of oil that could go into the three sets of tanks and those quality ranges would define the three blends known as, say, Malta Light, Malta Medium and Malta Heavy.

There would be a value adjustment mechanism, based on cracking or coking, so that there would be a price escalator and de-escalator to apply to individual cargoes to adjust for the extent to which input and output from the tanks varied from the reference quality for each blend.

There would be plenty of jetties and a very transparent schedule of tankers loading and unloading at the port in any given month.

Anyone could put oil in by agreement with the facility operator based on the terminals standard terms and conditions of trade. The depositor would receive a negotiable storage warrant. Anyone could take oil out of the tank by turning up with the storage warrant endorsed to their account. (And, please, let’s have electronic documentation of cargoes, not the parchment and quill pen system we are stuck with because the industry cannot reach consensus on which electronic system to use.)

Traders, hedgers and speculators could trade forward cargoes in any of the Malta Blends the way they currently trade the limping 30-Day BFOE contract. If any company tried to squeeze it or manipulate it they would be foiled by ability of the shorts to supply a much wider range of oils from anywhere in the world of the appropriate quality range.  We could even continue to call it Brent Blend if we wanted to maintain the brand. After all, what’s in a name?

Pipe Dream

But let’s not get carried away. This is never going to happen. Markets evolve, they cannot be created by individuals or companies. Even if a new contract idea is workable and serves a market need, players will not trade it if it has been introduced by a competitor or appears to give a competitor some sort of advantage.  And a market with no liquidity or no diversity of participants is no market at all.

Let’s just hope that the 17^th December meeting does not try to solve Brent’s current problems by trans-shipping Russian or African oil through Sullom Voe because it happens to have under-utilised tanks that are casting around for a way to avoid decommissioning costs.

With North Sea oil in general and Brent in particular dwindling at an accelerated rate, it would make no economic sense whatsoever to freight oil from other regions up to the Shetland Isles when the seats of oil production and consumption are increasingly located elsewhere. The answer to the benchmark problem lies where the heaviest trade routes are located. That answer has to be promoted by an independent entity without a vested interest in maintaining the unsatisfactory status quo.

On 18^th September Platts reported that “The International Organization of Securities Commissions (IOSCO) on Thursday said that price reporting agencies had made its recommended operating principles an "integral part" of their practices and said it saw no more need for annual reviews of their implementation.”

Also on 18^th September Bloomberg reported that “Major oil companies including Royal Dutch Shell Plc and price publisher Platts were told by regulators to redact business secrets from documents obtained during antitrust raids in a sign the European Union may be moving ahead with a two-year-old probe..”

A quick recap for those who have not been following this story.

• The G20 Seoul Summit Leaders' Declaration on November 11 – 12, 2010, requested "the IEF, IEA, OPEC and IOSCO to produce a preliminary joint report, by the April 2011 Finance Ministers’ meeting, on how oil spot market prices are assessed by oil price reporting agencies (“PRAs”) and how this affects the transparency and functioning of oil markets". These four organisations appointed yours truly along with my good friend Dr. John Gault (“the Consultants”) to research and write the report requested by the G20. That report was confidential, but shortly after delivering the report Consilience made a public response to IOSCO’s consultation on the functioning and oversight of the PRAs.

• Consilience’s response said, amongst other things, “selective reporting of deals leaves the price reporting system wide open to abuse, particularly when non-arm’s length deals could be reported to the PRAs or transacted on the Platts e-window software as if they were arm’s length…” Consilience Response to IOSCO Consultation........

• IOSCO introduced its “Principles for Oil Price Reporting Agencies” in October 2012, pointing out that that IOSCO has a brief to consider the derivatives market, not the physical market. The prices that are taken up and used as a benchmark to set the value of the price in contracts around the world are physical/OTC forward prices. These prices are then used by the futures and derivatives market. The physical market itself is unregulated.

• The EC then rocked the market by launching its own investigation into oil prices and kicked off with a raid on the offices of BP, Platts, Shell, and Statoil in May 2013. Despite rumours of other companies being drawn into the investigation no formal statement of the EC’s findings has been forthcoming.

So that is the Sound of Another Shoe Falling

With this history in mind the Bloomberg story on 18^th September takes on considerable significance and is being regarded as the precursor to “the big reveal” by the Commission of against whom who they intend to take action and for what. The logic is that if the EC was planning to say that there was no case to answer there would be no need for redaction of documents, which was the step taken before the EC made a complaint against Google.   It remains to be seen if the EC will give Platts and the companies providing it with deal evidence as clean a bill of health as IOSCO appears to have given to the PRAs.

Those waiting with bated breath for an outcome must include the participants in a class action suit in the New York courts against a number of major oil companies alleging the manipulation of Brent.

What is Happening Now

What may or may not have happened in the past is all very interesting, but for market participants it is what is happening now with benchmarks that is the most immediate cause for concern. One consequence of the IOSCO and EC investigations is that many companies have shied away from giving any data to PRAs at all, in case it comes back to bite them in the future. The less data that informs assessments, the less objectively representative of the market are those assessments likely to be.

The Platts Dubai price assessment is the spinning plate most likely to fall first, although Singapore gasoline is also wobbling alarmingly.

The market was deeply worried in August when it became apparent that out of a total of 78 Dubai cargoes, 72 were held by China Oil, allegedly all purchased through the Platts e-window. [Oman and Upper Zakum are deliverable grades against the Dubai contract]

August Dubai Market

The price of Dubai leapt from $0.45/bbl below Brent to more than $2.50/bbl above Brent as this situation unfolded. Platts is consulting industry to establish whether the addition of a new grade, Al Shaheen, will dilute the Chinese power to play such a dominant role in the market. This is being seen by some as a sticking plaster for a haemorrhage.

But in the meantime the viability of Dubai as a benchmark is being further undermined by the disappearance of the trading houses and many of the major companies from the Dubai market. Refiners who are buying any oil anywhere based on the Dubai benchmark had better fasten their seatbelts. It’s going to be a bumpy ride.