In Part One of this series we took an overview of the regulatory policy objectives of the G20 group of Finance Ministers and their aim to restore global growth, strengthen the international financial system and reform international financial institutions following the 2007/2009 banking crisis and subsequent recession.

The two largest international financial centres, the USA and Europe, have been at the forefront of compliance with the G20. This article considers the USA response to the G20 call to arms in regulating the financial markets.

The Dodd-Frank Act

The 2010 Dodd Frank Wall Street Reform and Consumer Protection Act ('Dodd-Frank') is a work in progress, coming into effect in stages that started with the Commodity Futures Trading Commission ('CFTC') rules in November 2012. Dodd Frank set up the Financial Stability Oversight Council ('FSOC') chaired by the Treasury and made up of members from the main regulatory authorities, including the Securities and Exchange Commission ('SEC') and the CFTC, and the insurance industry.

FSOC's purpose is to identify future risks to the financial system by information sharing and coordination, commissioning reports from a new Office of Financial Research ('OFR'), responding to future emergencies and promoting discipline by disseminating the message that there will be no future bail-outs.

In addition Dodd Frank created the Office of Credit Rating Agencies within the SEC. This addresses the failure of the rating agencies to evaluate accurately the structured finance instruments and securities that led to the financial collapse. Consequently conservative funds, such as pension funds, continued to invest in supposedly Triple A securities that were later revealed to be junk.

Read full story ›

Read Part One Here

Liz Bossley and Valerie Pivkina

Commodity markets have been caught in the cross fire of the battle, declared at the 2008 G20[1] Finance Ministers’ Summit, to restore global growth, strengthen the international financial system and reform international financial institutions following the banking crisis.

The meltdown witnessed in 2007/2008 did not start in the commodity markets. But the commoditisation of oil, gas and power by the increased use of derivative instruments - forwards, futures, swaps and options - for risk management and project finance means that these commodities have been press-ganged into the fight for a safer financial system.

The Aims of the G20

There are three features to the G20 strategy to secure the financial system:  increased transparency through timely and clear reporting; the enforced migration of opaque over-the-counter (“OTC”) deals onto more transparent regulated exchanges; and, an enhanced obligation to collateralise open positions adequately, re-enforced with a system of margin calls to ensure that no-one is playing “double or quits” with the financial system.

These features aim to ensure that when business is transacted it can be done, and can be seen to be done, in a secure environment. A major consequence of the G20 succeeding in all these goals would be the concentration of risk in a small number of central counterparty (“CCP”) hands for clearing. This could potentially create CCPs that are too big to fail, replacing the risk of banks that are too big to fail.

Cognisant of this fact, the Financial Stability Board (“FSB”), created in April 2009 by the G20, published on August 16th 2016 a discussion note entitled “Essential Aspects of CCP Resolution Planning”. This invites consultation responses by the tight deadline of 18th October 2016. The FSB coordinates the monitoring and reporting of the implementation of the G20’s financial reforms. Under the FSB umbrella standard-setting bodies will be responsible for “monitoring and reporting on national implementation in their respective areas.”

One of several such bodies of particular significance to the commodity market is the International Organisation of Securities Commissions (“IOSCO”). IOSCO presides over a policy committee for the Commodity Derivatives Markets. It is not responsible for physical commodity markets. This is the nub of the problem: the distinction between physicals and their derivatives contains many grey areas in the commodity market that do not occur in the financial markets. Yet commodity markets were intended to receive the same regulatory treatment as financial markets. As time goes on and the new regulatory instruments are being translated from broad statements of policy into detailed procedures manuals, the inextricable link between commodity derivatives and the underlying cash commodities that can either be settled in cash or by physical delivery, requires increasing customization of the Regulations to fit the commodity model.

One of the first stages of new regulation is to collect vast quantities of increasingly granular data. There is intended to be a lot of “monitoring and reporting” going on within the new regulatory framework. But it is less clear who will be “interpreting and acting on” the vast flow of data in time to head off problems before they occur. This is a particular issue for commodities because the interpretation of data requires detailed and specialised understanding of how each branch of each commodity market works. By the time the data is received and comprehended it is likely that whatever problem it was designed to spot and stop will already have happened. The new regulations run the risk of allowing us to conduct an excellent “post-mortem”, but not to prevent the “murder” in the first place.

Location, location, location!

The list of G20 countries, supposedly all aligned in their regulatory objectives, is so wide-ranging it is unlikely that market players can escape regulatory over-sight by moving to another country. Companies decamping to Singapore and Switzerland may well have different views on the length of the G20’s regulatory arm. Ultimately such financial hubs will be caught in the regulatory net by their need to deal with counterparties that are subject to enhanced financial regulation and consequently cannot deal with entities that do not adopt G20-style commitments.

[1] Argentina, Australia, Brazil, Canada, China, France, Germany, India, Indonesia, Italy, Japan, Republic of Korea, Mexico, Russia, Saudi Arabia, South Africa, Turkey, United Kingdom, United States, and European Union. Hence the UK remains a G20 country despite Brexit.

China and Hong Kong make an interesting exception. Despite China’s membership of G20, it would be a brave regulator who tried to sanction Chinese companies for their activities in commodity markets. The Dubai oil market is a case in point. Whether Chinese dominance of this market is deliberately abusive or just an inevitable consequence of the sheer size and number of its transactions is difficult to determine. Nevertheless, China’s presence or absence makes the Dubai market perilous for any oil buyer that links its contract prices to the unregulated Dubai OTC contract, rather than the Dubai Mercantile Exchange’s Oman futures contract. Both the OTC and the regulated instruments are linked to physical Dubai crude oil through their delivery mechanisms. But in the case of the futures contract the regulator has the ability to impose position limits on dominant companies, which cannot happen in the OTC commodity market.

 

Regulation of commodity markets part 2

 

 

My last blog (See “Producers, strapped for cash? What are your Options?")  looked at a trading strategy for producers to manage cash flow associated with a low absolute price of oil, i.e. to hedge the height of the forward oil curve, A. See Chart 1.This blog will look at a strategy for producers to hedge the slope of the forward oil curve, T.

The earlier blog, referred to above, discussed the possibility of producers raising cash by selling options when oil prices are low. This blog addresses the issue that, when oil prices are low and producers are hesitant about locking in low levels, the slope of the forward curve is typically in an attractive contango formation, i.e. forward prices are higher than current prompt prices. Producers like contango because it allows them to sell forward contracts at prices that are higher than the prompt prices that they, and their shareholders, see reported in the press.

 

Hedging the Slope of the Curve

Chart 1: The Forward Oil Price Curve -Contango

Source: ICE

But high prices typically mean that the forward oil curve is in backwardation, i.e. forward prices are lower than the prompt prices that make the producers want to hedge in the first place.  Chart 2 provides an example of high prices with the market in backwardation.

What constitutes a “high” price or a “low” price is entirely subjective. For some producers the fact that they can simply sell forward oil for delivery after the second half of 2016 at $45+/bbl may sound like a good hedge of some particular project. In which case all the hedger needs to do is sell forward oil for delivery in 2H2016.

Chart 2: The Forward Oil Price Curve - Backwardation

Source: ICE

In an ideal world producers want a contango forward oil price curve in a high oil price environment, i.e. the value of the absolute price, A is high and the value of the slope of the forward curve, T, is low, less than $0/bbl. This can and does occur naturally, often just before prices crash because there is too much prompt oil around.

Producers who want to hedge now may judge that the height of the curve is less than ideal, i.e. absolute prices are too low to lock in. Such producers may find that a two-step programme helps achieve the ideal of hedging at high prices in a contango market. Here’s how it would work:

1. Buy the slope of the forward oil curve, T, while it is in contango, i.e. <$0/bbl.
2. When prompt prices reach the level at which the producer wants to hedge, sell the absolute price of the forward oil curve, A.

If all goes well for this two-step strategy and prices recover, the producer should generate a profit as the slope of the curve moves from contango to backwardation, i.e. the value rises from <0 to >0. Then when it deems prices to be high enough to support its project or budget, it sells absolute price hedges. It will have the “slope” profit to add to the absolute price hedge to effectively achieve a hedge at a high price in a contango market.

 

The Mechanics of Buying and Selling the Slope of the Curve

The secret of this strategy is to get the timing right. Not only the time at which the traders execute the hedges, which is always a bit of a lottery given the unpredictable nature of prices, but the timing of the closing of positions to coincide with the time that the physical production being hedged is priced under the producer’s physical sales contract.

For example, say the producer has a physical sales contract that sets the price at the average of the published Dated Brent prices over each month of 2017. The producer will not know the price at which it sells its physical oil until the end of each delivery month in 2017. What price level an individual company finds acceptable -$40? $50? $60? – will depend on its price assumption for planning purposes and/or the cost structure of the asset it is hedging.  It may wish to ensure that it sells its oil in 2017 at, say, not less than $60/bbl, so hopes to hedge its oil for delivery in 2017 at ≮$60/bbl and it wants to do this before the end of the year, i.e. before end December 2016.

A price of $60/bbl is not currently achievable for oil to be delivered in 2017 because the market is about $15+/bbl below that level. But there is about $3.50/bbl of contango between the price of oil for delivery in the second half of 2016 and oil for delivery in 2017. In other words the slope of the curve between July-December 2016 and 2017 is roughly minus $3.50/bbl. The producer cannot hedge the absolute price, A, at a satisfactory level, but it can hedge the slope of the curve, T, at          -$3.50/bbl, which it may find acceptable.

To make the numbers easy let’s say the producer’s physical contract is to sell 100,000 bbls of oil in each month of 2017, i.e. 1,200,000 bbls in total. So today the producer would, in trader parlance, buy 1,200,000 bbls of the 2H2016/2017 spread at -$3.50/bbl from an OTC swap provider. It would cash settle the spread by effectively selling 200,000 bbls of the 2H2016/2017 spread in each of the months of July-December 2016.

If the absolute level of the price curve increases before the year end, then there is a good chance that the slope of the curve will move from from contango to backwardation. There is no law that dictates that there will always be backwardation when absolute prices are high and contango when they are low, but over time I have observed this frequently to be the case.

For illustrative purposes, let’s say the actual average 2H2016/2017 spread over the six months of July-December 2016 eventually works out at $0.25/bbl of backwardation. The producer cash settles the spread swap by selling it back to the swap provider at +$0.25/bbl. The producer makes $3.75/bbl on the 2H2016/2017 spread (sells at $0.25, buys at -$3.50=$3.75/bbl).

If the front end of the forward curve has moved up to, say $60/bbl, the producer will want to hedge the absolute price to fulfil the original objective of ensuring that it sells its oil in 2017 at not less than $60/bbl. But if the prompt price of oil for delivery in January 2017 has shot up to $60/bbl, then chances are the market will have moved into backwardation, so a $60/bbl hedge absolute average sales price for the whole of 2017 may not be achievable.

For example, there may now be $2-3/bbl of backwardation between oil for delivery in January 2017 and oil for delivery in December 2017. The average swap price for oil for delivery in all the 12 months of 2017 at which the producer can sell its absolute price hedge may be only, say, $57/bbl. So the producer cannot fulfil its board mandate to hedge before the end of 2016 its physical sales contract volume for delivery in 2017 at ≮$60/bbl, even though the board members may be seeing an oil price of $60/bbl in its FT or WSJ.

But the producer has a $3.75/bbl spread swap profit in hand, so it can achieve an effective 2017 hedge price of $60.75/bbl, i.e. $57+3.75/bbl.  The two step hedge has got the producer where it wanted to be.

 

Is this a Hedge?

The big risk is that absolute prices do not recover and the slope of the curve does not move from contango to backwardation. In which case the producer will either breakeven or make a loss on its slope of the curve hedge swap and will never get the opportunity to place its absolute price hedge. This is a real risk of a financial loss and there is no offsetting gain on the physical sales contract, which is what you would expect to see when hedging.

A loss on a slope hedge taken in isolation could be easily misconstrued as a speculative punt that went wrong. So any producers planning a two-step hedge of this nature had better have a well-informed management and shareholders on-board with the strategy before they set out.

Whether this activity would qualify for hedge accounting treatment or would be recognised as a hedge within the meaning of EMIR regulation [click here for an explanation of EMIR]  is difficult to say, but I expect that buying a spread swap that loses money could be challenged as a speculative adventure, particularly if the deal made a financial loss. The producer would be losing on both sides of an apparent hedge.

Hedging the slope of the curve may be easier to justify by having the producer buy a call option on the spread swap rather than buying the spread swap itself. Such options exist and are traded in the OTC market. So a producer could buy an option to buy the 2H2016/2017 spread swap at a strike spread of, say, -$3/bbl.

Does that mean that a producer with a mandate to hedge, but not to speculate, should not enter into outright spread swaps, but should only buy spread options? Perhaps. No market activity should ever be undertaken without an analysis of the company’s risk profile, risk appetite and market price view.

If a trader is in doubt about whether a particular deal is permissible under its mandate, chances are what they are about to do was never considered by the board when it issued delegated authorities. It is never a good policy to take the board or shareholders by surprise. A bit of spadework explaining the strategy upfront can avoid a lot of grief later on, including the necessity of hiring me, or someone like me, as an expert witness in a court case.

 

If You Don’t Ask You Don’t Get

Knowing what the company wants to achieve with its hedges is considerably more than half the battle in tailoring an appropriate and successful hedging package. The rest is just mechanics. But it is in the mechanics that companies often trip up, usually by under-estimating the deep pockets needed to meet margin calls or by failing to get buy-in by stakeholders to the strategy in advance.

Small producers who are wary of getting involved directly in the market and worry about the chairman having to report “hedge losses” to shareholders have a much simpler route to market:   build a range of pricing mechanisms into the physical sales contracts themselves. When selling to major oil companies or to the large trading houses it is a simple matter to build all the optionality that a producer wants into the physical contract price clause, without going near the futures or OTC markets.

A plain vanilla sales contract based on, say monthly average published benchmark prices, can very easily be modified to give the seller an option to over-ride the default monthly average price and lock in all or part of the price at a time of the seller’s choosing. This is known as “trigger pricing” and is pretty old hat in oil sales contracts.

But if the producer wants to get fancier and have the option to lock in the absolute price, A, in the sales contract at, say, $40/bbl even if the market price falls below this level, this can be written into the physical contract. Similarly, if the producer wants the option to lock in contango, T, this too can be achieved in the physical sales contract.  If the producer knows what it wants it is a simple matter for certain categories of buyer to provide it: whatever the price clause says, either plain vanilla or choc-full of options, the buyer will in all likelihood be hedging it anyway, and it matters very little which price formula it is hedging.

It should be clear that writing optionality into a physical sales contract is not a free lunch. Trigger pricing is typically provided for free, but including puts and calls in the physical contract price structure will involve the same cost as if the options were being purchased separately in the OTC market.

The benefit is that it can isolate the producer from messy market mechanics and margining issues and it side-steps some of the accounting and reporting issues with which small producers are typically ill-equipped to deal. It may even avoid the necessity of entering into a weighty International Swaps and Derivatives Authority (ISDA) contract. From a management perspective it means that, while the company may have an opportunity cost if it structures its physical oil price clause unwisely, it will not have a separate, reportable financial outflow from hedging.  Whether that is a good thing or a bad thing depends on the company and the quality of the information it provides to its shareholders.

The pitfall to avoid is whether a complex price clause in a physical contract will be recognised by the taxation authorities or the National Oil Company dealing with the producer’s exploration and development cost recovery and profit sharing. But that will be the subject of another blog.

 

 

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

$/bbl		$5/bbl OTM		$10/bbl OTM
	Swap	Put Strike	Put Premium	Put Strike	Put Premium
Q2 2016	40.46	35.46	1.25	30.46	0.45
Q3 2016	42.31	37.31	2.7	32.31	1.40
Q4 2016	43.70	38.70	3.69	33.70	2.15
Q1 2017	44.89	39.89	4.55	34.89	2.75
Q2 2017	45.77	40.77	5.53	35.77	3.53
Q3 2017	46.59	41.59	6.03	36.59	4.00
Q4 2017	47.13	42.13	6.61	37.13	4.55

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

$/bbl		$5/bbl OTM		$10/bbl OTM
	Swap	Call Strike	Call Premium	Call Strike	Call Premium
Q2 2016	40.46	45.46	1.06	50.46	0.38
Q3 2016	42.31	47.31	2.30	52.31	1.19
Q4 2016	43.70	48.70	3.14	53.70	1.83
Q1 2017	44.89	49.89	3.87	54.89	2.34
Q2 2017	45.77	50.77	4.70	55.77	3.00
Q3 2017	46.59	51.59	5.13	56.59	3.40
Q4 2017	47.13	52.13	5.62	57.13	3.87

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?