Less than 10 years ago the Wall Street Banks were on top of the oil trading heap and their client business in derivatives was an important source of profit for the banks and a major entry point for any corporate hedger.   Things have changes in the last 10 years.

First, some open disclosure. I worked at Goldman Sachs for 17 years and I am still a shareholder. All my comments here are completely based on data in the public domain.  Here are some of the main changes in the commodity business over the last ten years. These have led to some unexpected consequences and it seems that corporate hedging is moving backwards rather than forward. Might corporate hedgers been better to stick with the devil they know?

Many things have gradually changed in the commodity markets over last 10 years. The Lehman Brothers’ bankruptcy and the 2008 crash are the stand-out events, so this is probably the best place to start.

1. Lehman Brothers (LB) bankruptcy leads to wider counterpart dealing.  Apart from triggering the 2008 financial crash, the LB bankruptcy also had the very simple effect of stopping the polarization of business within a very small group of banks.  I recall getting sometimes as much as 50-75% of a corporate client’s business. Very few banks lost money to LB as all their deals were under a zero margin trigger in their ISDA Credit support annex. A zero margin trigger means that mark-to-market position is always zero. Monies change hands ever day throughout the duration or tenor of the transaction, either positive gains or negative losses, until the final settlement day. However, the potentially daily exchange of monies requires an active treasury department. Most corporates could either not manage such daily transactions or could not be bothered. Corporate clients did lose money in the LB bankruptcy, because they did not want to post margins to Lehman or any other bank, as they were dealing on an open credit basis. In return for not paying any variation margin to LB, their corporate clients did not in turn receive any positive variation margins from Lehman Brothers. It was these mark-to-market gains that were lost in the bankruptcy. LB was no different from any other banks in its dealings with corporate clients on open credit. Sadly, it was Lehman that went bankrupt.

   It is in the public record the Lufthansa lost $20 million in the Lehman LB. Lufthansa has one of the most respected treasury departments in the airline business. It was well known in the industry that Lufthansa has a graduated hedging program that extended out to 4 years in the future. In fact, they were considered the best hedging practice model for other airlines to follow.  It was their mark-to-market gain from this hedging programme that was lost.  As the oil market fell from its peak of $145/bbl in mid-2008  to a low of $38/bbl in December 2008 many corporate clients had massive mark-to-market losses. The losses were largely on the side of consumers who are naturally short in the market and have bought forwards oil positions. As most corporates did not have margin triggers in their contracts with the banks, it was the banks who had the problem.  Thus the oil market became part of the global banking crisis

   The regulatory framework had officially changed prior to the 2008 crash when MIFID I came into effect in November 2007. Now every bank preferred to deal only with “counterparts” who, by definition, were market professionals and met high minimum net worth criteria.  Post -November 2007 any reference to client or advice was removed from all bank presentations. This was considered to release the banks of any fiduciary duty to “clients”.

2. Credit pricing or CVA. Credit Valuation Adjustment, or a price for every client that takes account of their market-determined credit valuation, is now standard when trading OTC with counterparts.  The CVA charges will take account for the counterpart’s credit rating and the price of their credit default swaps in the market. There is no CVA when counterparts deal with each other under a zero-margin trigger as there is no risk in this type of deal. A zero margin trigger means that mark-to-market position is always zero. Monies change hands ever day throughout the tenor of the transaction, either positive gains or negative losses, until the final settlement day. However, the potentially daily exchange of monies requires an active treasury department. Most corporate could either not manage such transaction or could not be bothered. Corporate clients did lose money in the LB bankruptcy, because they did not want to post margins to LB or any other bank, as they were dealing on an open credit basis. In return for not paying any variation margin to Lehman Brothers, their corporate clients did not in turn receive any positive variation margins from LB. It was these mark to market gains that were lost in the bankruptcy. LB was no different from any other banks in its dealings with corporate clients on open credit. Sadly, it was Lehman that went bankrupt.

   Zero margin trigger business was standard with interbank dealings and deals with hedge funds.  When CVA was introduced more widely post the 2008 crash, it was no longer simply a question of what price a dealer was prepared to do the transaction at, but a combination for transaction price and CVA charge. Initially different banks had a very different view of how to charge CVA. Those banks that did not charge CVA gained market share over those who did. This helped Continental European and Canadian banks get a leg up on Wall Street.  It is rather Ironic that the first-class banks who were acting in the best interest of market best practice and their shareholders lost business to second and third tier banks whose credit operation were more basic.

   Post 2008 the corporate clients still wanted to deal on open credit with no variation margin arrangement.  Lufthansa led a campaign suggesting that airlines should be excluded from the financial margining and compulsory clearing proposals agreed at the G20 Summit in London in April 2009. (These has still not been fully implemented.) One of the simplest way to limit your risk and maximize your credit lines was to use more banks as counterparts. It is not at all surprising for airlines now to have 20-30 counterparts for hedging. What this means is that the amount of business many banks get from a counterpart is now so small that they are simply not worth covering from a bank sales perspective. So all sorts of ancillary services, such as what was previously called “advice” or “research” may now be lost to the client. All corporate clients are now classified as “counterparts”. As mentioned above this is considered to relieve the banks of many fiduciary duties to what used to be called clients. De facto it now also means that what were previously regarded as client services are now being cut to the bone.

   One of the alternative ways to avoid CVA is to buy options. This limits the banks credit risk to the payment of the premium on “T+2”. In other words payment of the full option premium is due two days after the transaction date. Many corporates were so obsessed with what their credit charges were for different counterparty banks that they may have lost sight for what the risk management strategy was aiming to achieve. It is now more than 30 years since NYMEX (now the CME) and shortly followed by the IPE (now ICE) began their traded options market in crude oil. Yet many corporates still “do not do options”.

   Funny how the senior executives of corporates can get their mind around their own personal stock options, but cannot manage traded options to hedge their businesses.

3. Dodd Frank. The post-crash Dodd Frank (DF) legislation in the US, specifically the Volcker Rule, and its equivalent elsewhere has put severe limits on proprietary (Prop) trading. The DF description for Prop trading runs to 300 pages.  Additionally, since all the Wall Street Banks are now supervised by the Federal Reserve, they need waivers to continue to trade in physical oil. The fall in Prop trading has impacted the volume and liquidity in the markets. Today algorithmic trading dominates 60-65 % of all futures transactions. Longer dated business has dried up.
4. Accountancy rule changes. From 2005 through to 2009 international accountancy rules changed on issues of mark-to-market on hedges and open disclosure to shareholders and investors. For example, embedded optionality is a powerful asset for any corporate. Post 2009, many firms were not prepared to openly declare their embedded options within hedges and they reverted to plain vanilla structures.  By not monetizing “natural options” that firms possess, firms may be missing a trick. In today’s market any corporate selling “natural options” with the exchange or its OTC counterparts would have to pay a variation margin. Even though this may in fact be in the best interest of the firm, it is something that many corporates cannot be bothered with.
5. Cleared business.   The G20-mandated move to make clearing compulsory has focused attention for many medium-size oil companies as to what exactly their “trading operations” are trying to achieve. Specifically, many firms are worried that they may be dragged into some form of vast regulatory net, with implication for their capital structure. This fear now seems to be limiting many firms’ risk management activity in the futures. It is easier to say that the firm does not use these trading instruments than to face what many corporates think is a potential regulatory quagmire. Opportunities are being lost.

In my many years working within the banks that offer energy derivatives, some of my corporate clients (now counterparts) knew exactly what they wanted to do. However, on many occasions I had to research the financial structure of the firms and study their annual reports and investor presentations to come up with the most efficient and effective hedges. How many banks are paying people to do this today? Not many.

I notice that a few banks have moved some key commodity people from their FICC (Fixed Income, Currencies and Commodities groups) to their Investment Banking divisions. This means that advice can be given to key corporate clients from the banking division. The other corporates that are not large enough or interesting enough to investment banking clients, will need to fend for themselves amongst the pared-down commodity banks, oil traders, futures brokers and “trading boutiques” that have sprung up since 2008. Wouldn’t it have been better to stick with the devil we knew?

Lindsay Horn. Visit Lindsay's bio HERE

The overhaul of the regulatory regime for financial instruments, including commodities, since the banking crash of 2008 constitutes a lot more than the archetypal “butterfly flapping its wings” of chaos theory.  So we should not be surprised to see far-reaching and unintended consequences in the market from the flapping of the weighty Dodd Frank and EMIR/MiFID wings of legislation.

This blog is pleased to include a guest piece from Lindsay Horn, an ex-Goldman Sachs, Lehman Brothers, AIG and Drexel employee. He gives a view from the sharp end of the impact of financial regulation on the banks that once provided hedging and financing solutions to the oil industry, but do so no longer.

What is most difficult to measure is how the loss of ancillary services once provided by the banks is changing the structure of physical oil contracts. Lindsay Horn mentions that opportunities are being lost by oil producers and refiners that do not engage with the futures and derivatives markets for fear of being sucked into, at best, time-consuming regulatory compliance or, at worst,  accidental non-compliance. These opportunities are best exemplified by the “embedded optionality” that is an integral part of being an oil producer.

We have just come through the annual renegotiation of physical oil contracts and we are seeing increasing premia being paid over the reported spot price of different grades of crude oil for term contracts in the same physical oil. It has long been a feature of the industry that buyers of term physical oil are prepared to pay a premium over the spot price of the same oil as reported by the Price Reporting Agencies (PRAs). The more flexibility that the producer offers the buyer in terms of determining the date range and size of cargoes and in choosing the price formula, the greater the premium the buyer will pay. The more of the same grade of oil that the buyer has from other sources, preferably including an equity production position of its own, the more the buyer is prepared to pay as premium over the reported spot price. This premium can be >$1/bbl and represents the embedded optionality in the physical position of equity producers.

Uninformed producers that do not analyze the value of the optionality embedded in their position as a physical producer sometimes leave this premium on the table. But most producers are now waking up to the fact that they should be seeking a premium over the spot prices reported by PRAs for flexible term contracts.

We are also seeing a resurgence of the phenomenon of “trigger pricing”, i.e. the buyer permits the seller to choose the moment when key components of the oil price formula are fixed. This is a very handy option for sellers that do not want to engage with short-term operational hedging in the futures or CFD markets for fear of the regulatory compliance consequences, but who still want some control over their financial realization from the sale of oil. This trigger option costs the buyer little, if anything, because the buyer will probably already be hedging the price formula to lock in an arbitrage profit. So whether it closes those hedges in accordance with a standard average price formula or in tranches at a time of the seller’s choosing makes little difference to the buyer.

Given the state of flux in which oil price benchmarks find themselves (read it HERE) what conclusions can we draw about the price of oil and the impact of financial regulation? On December 4th last year the International Organisation of Securities Commissions (IOSCO) stated:

“Examples of relevant considerations of appropriateness for a user could be, to the extent they are applicable:

• the way in which the benchmark is determined, including the size, liquidity and potential evolution of the market being measured by the benchmark and other aspects of the relevant methodology, along with the transparency of the methodology;
• whether the benchmark provides an appropriately accurate and reliable representation of the market it seeks to measure, and is likely to remain so, and how factors that might result in a distortion of the price, rate, index or value of the benchmark are eliminated or reduced;
• in the case of interest rate benchmarks, whether or not it is desirable or necessary for the benchmark to include a term risk or credit risk element;
• how the benchmark is disseminated to users;
• the  governance of, and accountability for, the benchmark determination process;
• the process by which changes to the benchmark’s methodology can be made, e.g. relevant consultation procedures;
• how the administrator deals with significant decisions affecting the compilation of the benchmark and any related determination process, including contingency measures in the event of insufficient or no inputs (e.g. the use of expert judgment), market stress or disruption, and failure of critical infrastructure;
• the provisions which could apply in the event of material changes to the benchmark and how they would operate in practice; and
• whether, and under what circumstances, provisions relating to cessation of the benchmark should apply.”

This is good advice. It is unwise to continue relying on old oil price benchmarks without an understanding first, of how those benchmarks are changing and, secondly, of the impact that the withdrawal of a key group of actors in the physical market, the banks,  has had on the structure of term oil contracts.

When Shopping, Always Remember to Keep the Receipt!

A mere 6 weeks after completing its purchase of the Forties Pipeline System (FPS), INEOS declared force majeure and shut down this key piece of North Sea infrastructure, throwing the influential Brent market into confusion: Forties makes up about half of the physical supply underpinning the Brent contract.

Speculation is rife about whether INEOS is being overly cautious by shutting down the whole system to deal with what appears to be a minor onshore leak in order to be able to pass back repair costs to the vendor. Others whisper darkly that if the onshore pipeline is showing hairline cracks how much worse must be the much larger web of offshore pipes?

Only the protagonists know, but for INEOS’ sake I hope the deal was done under English law, not Scottish law: as any house buyer knows, under Scottish law it is the responsibility of the buyer to complete all its surveys before submitting a bid, while under English law bids can be made subject to subsequent completion of a satisfactory survey and withdrawn if the survey uncovers any problems.

Calling Oil Lawyers

Irrespective of whether or not the buyer and seller of FPS end up in court over the pipeline closure or have made sensible provisions in the sale and purchase deal for the asset, it looks like it will be a Merry Christmas and an even happier New Year for lawyers in the oil sector as traders reach for their contracts to see what can and cannot be done legally when force majeure is declared.

Producers in the 70-80 fields that use FPS have signed largely similar deals to use the Forties transportation system. These deals give INEOS broad rights to delay, withhold or suspend the delivery of cargoes of Forties Blend when circumstances beyond the control of the operator interrupt pipeline services. Some traders are already attempting to argue that if the operator had maintained the pipeline the cracks would not have appeared and the force majeure would not have had to be declared. INEOS could not have been actually responsible for any alleged shortfalls in the maintenance of the pipeline because it has only owned the asset for a few weeks. But presumably it has taken on the responsibility of the previous owner to keep the FPS in good working order.

But that is only one aspect of the legal quagmire in which the Brent market now finds itself. Readers of these LOL blogs will have heard me point out ad nauseam that the published price of “Brent”, which is a key benchmark for setting about 50-66% of the world’s physical oil, is actually the price of the lowest of a basket of crudes including Brent, Forties, Oseberg, Ekofisk and, for contracts deliverable from January 2018 onwards, Troll (BFOET). The 30-Day forward BFOET market, on whose price the much larger Brent futures contract is also based, allows sellers to deliver any one of these 5 different grades of oil in satisfaction of a forward sales contract.

This 30-Day forward market operates using Shell UK general terms and conditions of trade (GTCs)  1990 edition (SUKO 90), supplemented by the various updates that have been needed over the last 27 years as the forward contract has evolved. The SUKO 90 terms are quite unusual in that they provide for the fact that forward contracts tend to involve cargoes that change hands many times forming long chains of owners starting with an equity producer and ending with an end user who will load it onto tanker for transport to a refinery. These terms state that only the Prime Supplier, an equity producer, and the last FOB buyer, i.e. the buyer that charters a ship to lift the oil, can initiate reliance on the “Exceptions” clause, which is SUKO 90 terminology for force majeure (although there are legal niceties distinguishing between force majeure and exceptions, which are beyond my trading brain). So far, so good.  The Prime Supplier of a cargo that has been cancelled because of  force majeure can cancel its contract for the forward sale and supply of a Brent, Forties, Oseberg, Ekofisk or Troll cargo if it so chooses, but it is under no obligation to do so.

However a further complication arises because the trader planning to supply a cargo into a 30-Day forward chain may not be a “Prime Supplier”, defined in SUKO 90 as a company with an  “equity entitlement” to one of the 5 grades of crude oil.  When cargoes of Brent, Forties, Oseberg, Ekofisk and Troll are bought and sold as physical cargoes, i.e. not as a 30-Day BFOET cargo, the contracts rarely use SUKO 90 terms. Instead these physical contracts may use BP GTCS, ConocoPhillips GTCs or Statoil GTCs, depending on which grade is being delivered. So if a trader wants to withdraw a delivery of, say, Ekofisk from a 30-Day BFOET contract because of the Forties Force Majeure, it can find itself meeting resistance because it is, arguably, not a Prime Supplier

So What is the Price of Brent?

Trade in 30-Day BFOET, and in the individual components that make up the Brent basket, is opaque. Traders already nervous about the advent of the European Benchmarks Regulation have been driven further underground: it takes a brave company to provide a price assessment to a price reporting agency in such a confused market, particularly when that assessment is leveraged by forming a key price benchmark for so many contracts -physical, forward, futures and derivative – around the world. No-one wants to risk the wrath of a regulator by guessing at where the price would be if trade was taking place: that’s what got the LIBOR guys into trouble.

So those who rely on Brent price assessments in any of their contracts anywhere in any geographic location would be well advised to examine those prices closely. Just how much data is informing their compilation and how realistic are they?