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    Energy price risk Energy price risk Document Transcript

    • Tom James Energy Price Risk
    • ENERGY PRICE RISK
    • Energy Price Risk TOM JAMES
    • © Tom James 2003 All rights reserved. No reproduction, copy or transmission of this publication may be made without written permission. No paragraph of this publication may be reproduced, copied or transmitted save with written permission or in accordance with the provisions of the Copyright, Designs and Patents Act 1988, or under the terms of any licence permitting limited copying issued by the Copyright Licensing Agency, 90 Tottenham Court Road, London W1T 4LP. Any person who does any unauthorised act in relation to this publication may be liable to criminal prosecution and civil claims for damages. The author has asserted his right to be identified as the author of this work in accordance with the Copyright, Designs and Patents Act 1988. The information presented in this book has been derived from sources believed to be accurate and reliable, but it has not been independently verified in all cases. Accordingly, neither the author nor the publisher gives any representation or warranty of the accuracy, completeness or currentness of such information. The methods and examples in this book are only intended to demonstrate the relevant concepts in general terms. They may have to be adjusted or modified to be applied to real transactions. Moreover the information in this book is not intended as financial advice or as a recommendation for any financial transaction. Neither the author nor the publisher is liable for any actions prompted or caused by the information presented in this book. Any views expressed herein represent those of the author and do not necessarily represent the views of Carr Futures or its affiliated entities. First published 2003 by PALGRAVE MACMILLAN Houndmills, Basingstoke, Hampshire RG21 6XS and 175 Fifth Avenue, New York, N. Y. 10010 Companies and representatives throughout the world PALGRAVE MACMILLAN is the global academic imprint of the Palgrave Macmillan division of St. Martin’s Press, LLC and of Palgrave Macmillan Ltd. Macmillan® is a registered trademark in the United States, United Kingdom and other countries. Palgrave is a registered trademark in the European Union and other countries. ISBN 1–4039–0340–9 hardback This book is printed on paper suitable for recycling and made from fully managed and sustained forest sources. A catalogue record for this book is available from the British Library. A catalogue record for this book is available from the Library of Congress. 10 9 8 7 6 5 4 3 2 1 12 11 10 09 08 07 06 05 04 03 Printed and bound in Great Britain by Antony Rowe Ltd, Chippenham and Eastbourne
    • Contents Foreword xi Preface xiii 1 Risk Management 1 The Risk Matrix 1 Financial Risks 2 Basis Risk 3 Legal, Operational and Tax Risks 6 Summary 7 2 Energy Derivatives Markets: On-Exchange and Off-Exchange 8 On-Exchange and Over-the-Counter 9 Futures 10 Swaps and Options 15 Summary 24 Generally Accepted Oil Conversion Factors Used in the Derivatives Industry 30 Generally Accepted Gas Conversions 31 Volume 31 API Gravity and Density/Volume per Tonne 32 Power and Gas Conversion Factors 32 3 Energy Futures Contracts 33 Introduction 33 Key Facts About Futures Contracts 33 Futures Options Contracts 35 Hedging in Futures Markets 36 Exchange of Futures for Physicals (EFP) and Deliveries via Futures Markets 37 IPE (London) Brent Crude Futures Contract – Specification 44 Ipe (London) Brent Crude Options Contract – Specification 44 v
    • IPE (London) Gasoil Future Contract – Specification 46 IPE (London) Gasoil Options Contract – Specification 47 IPE Natural Gas Futures Contract – Specification 48 NYMEX WTI Light, Sweet Crude Oil Futures 49 WTI Light, Sweet Crude Oil Calendar Spread Options 52 NYMEX Heating Oil Futures 53 NYMEX New York Harbor Unleaded Gasoline Futures and Options 56 NYMEX Henry Hub Natural Gas Futures and Options 58 TOCOM Tokyo Commodity Exchange Middle East Crude Oil Futures Contract 60 TOCOM Futures Contract Specifications – Kerosene 63 TOCOM Futures Contract Specifications – Gasoline 66 Coal Futures 68 Central Appalachian Coal Futures 69 4 OTC Energy and Related Derivative Markets 72 OTC Energy Derivative Markets 72 The OTC Oil Derivatives Market 73 The Key Oil and Gas Related OTC Swaps 78 European Power and Gas Markets 81 Global Power Markets – With Developed or Developing Derivatives Markets 81 European Gas Markets 85 European Coal Swaps (Cash Settled not Physical Settlement) 88 Weather Derivatives 91 Developments – Freight Rate Swaps (Cash Settled) 96 Derivatives Forward Curve Assessments 97 5 Options – Trading and Hedging Application Strategies 107 Volatility 108 Types of Options 110 Option Strategies for Hedging Energy Price Exposure 110 The Greeks 111 Option Strategies 113 OTC Options and Popular Structures 115 Options Trading – Volatility Trading 119 6 Energy Option Pricing – Which Models Are Used? 125 Types of Options in the Energy Markets 125 General Rules for Option Values 125 Types of Options Models Utilised in the Energy Industry 127 Option Pricing Bibliography 128 vi CONTENTS
    • 7 Value At Risk and Stress Testing 130 A Risk Management Scenario 130 VAR and Other Risk Measurement Methods 131 What Does VAR Do? 133 Variance/Covariance VAR 134 Historical Simulation VAR Method 135 Monte Carlo VAR Simulation (Stochastic Process) 136 VAR Recap 137 VAR to Illustrate Hedge Effectiveness 137 Stress Testing and Value-At-Risk 138 Summary 140 8 Questions to Ask When Establishing a Risk Management or Trading Program 141 9 Management Controls 145 The Collapse of Barings 145 The Lessons of History 147 Creating a Risk Management or Trading Policy 149 Corporate Derivatives Risk Management Policy and Procedures Document 152 Back Office Systems 153 Role of External or Internal Audit and Compliance 158 A Risk Management Review 159 The Collapse of Enron, 2001 160 10 An Eavesdropper’s Guide to Hedging 164 Nine Great Sayings on Hedging Heard in the Market – With Comments 164 Conclusion 166 11 Operational Risk 167 Key Components of Operational Risk 167 Assessing and Controlling Operational Risk 169 Gathering Information on Operational Risk 172 Operational Risk Reduction, Control and Containment 173 Summary 175 12 Derivatives Contracts Application Listing and Some Hedging Scenario Examples 176 What is Hedging? 176 General Recap on Energy Derivatives 177 Energy Derivatives Selection Grid 177 Hedging Application Examples 178 CONTENTS vii
    • 13 Risk Management Process and Policy Creation Guidelines 201 The Risk Management Process 201 Trading Controls – Position Limits 203 Some Key Guidelines for a Risk Management Policy 205 14 Applied Technical Analysis in the Energy Markets 211 What is Technical Analysis? 212 The Principles of Technical Analysis 213 The Technical Analysis Bar Chart 213 Other Types of Chart 219 Price Gaps as Price Targets 222 Fibonacci Retracement Levels 224 Mathematical Indicators 225 Moving Averages 228 Chart Patterns 228 Summary 240 15 After Enron – A Practical Guide to Credit Control and Risk Mitigation Methods 241 The Collapse of Enron 241 Methods for Managing Credit Risk Exposure 244 Ways to Reduce Credit Risk via the ISDA Schedule 246 Collateralisation 249 Guidelines for Taking Collateral From Counterparts 250 Credit Insurance 252 The New Tool of the Trade – Credit Default Swaps (CDS) 253 The Development of the CDS Market 260 Total Return Swaps 262 Credit Risk Mitigation via Clearing Houses 263 Management Guidelines on Establishing a Credit Control Framework 266 16 Finance in Energy 268 Credit Status in the Energy Sector 268 Financing Using Derivative Structures 276 17 OTC Derivatives Legal Risk Control and Documentation 286 The ISDA Agreement 287 The ISDA Master Agreement 287 ISDA Publications 288 Pre-Confirmations and Long-Form Confirmations 289 ISDA Documentation Processing 290 Trading Before an ISDA is Signed 293 ISDA Master Agreement Schedule 293 viii CONTENTS
    • Step by Step Explanation of a Typical ISDA Master Agreement Schedule Between a Trader and a Bank 294 Additional Notes 311 Proposed ISDA Changes 311 The Advent of Independent Sources of Data that can be Applied to Replacement Value Calculations 315 Arbitration 315 18 International Accounting Standards for Derivatives 317 Introduction 317 Consolidation and Clarification of Accounting Standards Since 2001 319 FAS 133 – Effective From 1 January 2001 in the USA 320 International Accounting Standards Board (IAS) 323 FRS 13 – UK Accounting Standards Board 327 Closing Note 328 Totem Risk 331 19 Glossary of Terms 337 Appendices 1 Example of a Risk Management Review of a Company Using Derivatives to Hedge Oil Requirement 442 2 The Main Energy Sector and Transportation Names/Credits Traded in the CDS Market (September 2002) 457 3 The ISDA Master Agreement 461 4 Example Derivatives Trade Confirmation Under ISDA 486 Index 000 CONTENTS ix
    • Foreword Roy Leighton When Lord Keynes travelled to Bretton Woods in 1944 in his briefcase were four files to be decided upon by distinguished world financial leaders as the basis for stable economic growth and recovery after the Second World War. Three of these files came to fruition in institutions which we know today as the World Bank, WTO and IMF. The fourth file never saw the light of day – the World Commodity Fund (WTF) – this was considered too big a challenge for struggling post-War economies. Since then, the best brains of governments and business have tried to solve the economic problems of commodity-dependent countries and businesses. They have experimented with buffer stocks, price support mechanisms and other ideas, but most of these schemes have failed and been an expensive waste of scarce donor aid. In the UN and at the World Bank there is much talk of the Debt Problem of the Third World, but in many cases debt is only the symptom – the reality is a Commodity Problem. Fortunately, today the modern financial services industry has devel- oped risk management instruments to manage volatile commodity markets, and these tools are now being recognised by multilateral institu- tions as the viable alternative to wasteful traditional projects designed to aid poor countries. Risk management in energy is a top priority for heavily indebted poor countries. For the first 70 years of the twentieth century the price of energy was fairly stable, despite world conflicts, and the business of energy was largely conducted between governments and multinational blue chip corporations. Suddenly it all changed in 1973, when the Middle East real- ised the true value of their ‘black gold’ and oil prices shot up as OPEC asserted powers over supply. Since then the volume of activity on open and transparent trading markets has soared; initially in oil, then in gas and nowadays electricity and weather. Hedging activities have flourished, initially for high energy consumers – airlines, aluminium smelters, electricity generators and the like. Today xi
    • no equity investment analyst presentation for these types of companies is complete without a clear explanation of the hedging strategy and posi- tion. Energy producers are now following the hedging approach of consumers due to the economic chaos brought about by unhedged expo- sure to crude oil which quite recently saw prices of US$10 per barrel and US$28 per barrel within an 18 month period. Too often in derivatives the potential user of these price risk instru- ments is blinded by a blend of trading jargon and mathematical formulae. You don’t need to know how to price derivatives mathematically to be able to shop around and use them effectively. This book demystifies today’s world of risk management and effectively explains to the reader the mitigation tools and strategies available in the market. Failure to utilise such risk management tools is truly to speculate. Roy Leighton Chairman: European Advisory Board Crédit Lyonnais SA Futures & Options Association xii FOREWORD
    • Preface The relationship between risk and reward is at the heart of business. In any endeavour, the risk of heavy losses is seen as a justification for hand- some returns, while lower risk enterprises command more modest margins. Perhaps for this reason, the most risky and rewarding businesses are sometimes portrayed as a species of high-stakes casino. But such a comparison is misleading. All successful businesses must learn to assess and manage risk in ways that allow them to exploit opportunities while limiting their exposure to unpredictable factors in their operating envi- ronment. The more volatile the market, the more important this process of risk management becomes. The energy industry and its associated markets certainly experience more than their fair share of volatility. Indeed, historians use the more turbulent incidents in the industry’s recent past (the oil price shock of 1973, the Gulf War of 1991) as key mileposts in general economic history. So it’s no surprise that, over the years, the energy industry has honed risk management into a fine art, although still perhaps not an exact science. One of the key concepts in this ‘fine art’ is the use of derivatives: finan- cial instruments that derive their value from an underlying asset. Deriva- tives contracts allow some players in a market to hedge their risks while others take advantage of the opportunities that such hedging provides. As in other financial markets, the three main tools are futures, options and swaps. A futures contract is a way of agreeing to buy and sell an asset for delivery at a future date, while an option is a contract which confers the right, but not the obligation, to do so. A swap is an agreement to fix a price in an otherwise floating market. The idea of using derivatives in the energy market has been around for many years. The first Heating Oil (Gasoil) Futures contracts were traded on the New York Mercantile Exchange in 1979 and the first oil swap was reported in 1986 (between a bank, an oil trader and an Asian airline). But it was the Gulf War of 1991 that really brought the market to life. The perceived threat to the world’s oil supplies posed by Saddam Hussein’s invasion of Kuwait in August 1990 caused the price of crude oil xiii
    • to jump by over 50% in a single month and the markets have never forgotten that brutal lesson. Since then, the continuing tensions in the Middle East, changes in legislation and the ongoing deregulation of econ- omies and markets around the world have introduced more and more businesses to the risks and rewards of the volatile oil, power and gas markets. The result is that the demand for energy derivatives has increased exponentially over recent years. This book aims to provide a practical introduction to the trading of energy derivatives and their use as tools of price risk management. These are normally considered to be highly specialised activities, but this does not mean that they should be treated in isolation. Energy derivatives cannot be properly understood or effectively used unless they are consid- ered as part of a bigger picture. When a company chooses to control price risk through the use of derivatives it may find that it increases the risks in other areas of its business; for example, it may increase its operational, legal or tax risks. For this reason, this book covers many of the issues and topics surrounding energy price risk management to ensure that the use of derivatives does not cause any unwanted or unplanned difficulties. Tom James tomjames@energycollege.org xiv PREFACE
    • CHAPTER 1 Risk Management In most financial markets there are a fairly small number of fundamental price drivers which can be easily translated into pricing and risk manage- ment models. In currency markets, for example, the commodity that has to be delivered is cash, a piece of paper which is easily stored, transferred and not sensitive to weather conditions. But energy markets are concerned with bulky, dangerous commodities that have to be transported over vast distances through some of the most politically unstable regions of the world. This means that there are a large number of factors that can affect energy prices. A fairly short list might include: the weather, the balance of supply and demand, political tensions, comments from country leaders, decisions taken by OPEC, analysts’ reports, shipping problems, and changes to tax and legal systems. All these contribute to the high levels of volatility in energy markets which often experience sudden price movements from one day to the next, or even from one minute to the next. THE RISK MATRIX One way of understanding how these factors combine to influence energy prices is to use the risk matrix pictured in Figure 1.1. It illustrates how all the risks shown interrelate and affect one another and makes it clear that relationships between them are never two-dimensional. It also makes the point that it is impossible to manage price risk effectively without reviewing all the other risks that an individual or a firm may face. As the matrix shows, the key risks to be managed in an organisation when using derivatives for trading or price risk management purposes are: credit risk, liquidity risk, cash flow risk, basis risk, legal risk, tax risk and operational risk. All these risks will have a direct bearing on which derivatives are employed and the choice of trading partner. They will also affect decisions on where trading takes place (which is dependent on 1
    • jurisdiction and tax risk), and how much is traded (which will depend on operational risks). FINANCIAL RISKS Price risk This is the risk of losing money as a result of price movements in the energy markets and is sometimes referred to as ‘market risk’. Typically, producers will lose money when prices fall, while users will find them- selves out of pocket when prices increase. Credit risk Credit risk is the risk of financial losses due to the counterpart to a contract defaulting. It is often said that a hedge contract is only as reliable as the credit standing of the counterpart and credit risk management has moved to the top of the priority list for the energy industry. The credit crunch felt in the USA energy sector in the aftermath of the Enron disaster has prompted energy traders to review credit policies and also review effec- tive methods to control and reduce credit risk wherever possible. Liquidity risk In the context of this book, this is the risk of losses caused by a derivatives market becoming illiquid. This happened during the Gulf War when there was so much volatility in the markets that many banks and oil traders would not give a bid or offer price. Companies who were exposed to those 2 ENERGY PRI CE RI SK C T L Ca b Le Or P • Price risk – P • Credit risk – C • Liquidity risk – L • Cashflow risk – Ca • Basis risk – B • Legal risk – Le • Tax risk – T • Operational risk – Or FIGURE 1.1 The risk matrix
    • markets at the time were sometimes unable to close out their positions or could only do so at great cost to themselves. Cash flow risk This is the risk that an organisation will not be able to produce the cash to meet its derivatives obligations. In the late 1990s, Korean Airlines found itself in this kind of situation and suffered heavy losses as a result. The company had been hedging against movements in the jet fuel price by using deriva- tives which were denominated in dollars. When the Korean won suddenly fell in value against the dollar, the company found that the cost of the dollars needed to service its derivatives contracts had soared. The company lost out because it had not hedged against the risk of a negative movement in the currency differential between the won and the US dollar. BASIS RISK What is basis risk? Basis risk is the risk of loss due to an adverse move or the breakdown of expected differentials between two prices (usually different products). In the context of price risk management, basis risk describes the risk that the value of a hedge (using a derivative contract or structure) may not move up or down in sync with the value of the price exposure that is being managed. In the energy market, these market movements may be triggered by factors such as poor weather conditions, political developments, physical events or changes in regulation. These can lead to basis risk occurring in circumstances such as the following: 1 Physical material in one location cannot be delivered to relieve a shortage in another location. 2 A different quality of product cannot be substituted for an energy product in severe shortage. This often happens in the pipeline gas and power markets if there are any problems with transmission networks. 3 There is not enough time to transport or produce an energy product to alleviate a shortage in the market. When conducting price risk management, the ideal derivatives contract is one that has a zero risk or the lowest basis risk with the energy price that protection is needed from. The larger the basis risk, the less useful the derivative is for risk management purposes. The attraction of over-the-counter (OTC) swaps and options is that basis risk can at times be zero, as OTC contracts can often price against the same price reference as the physical oil. However futures contracts (sometimes referred to as ’On-exchange’ derivatives) traded on exchanges like the BASIS RISK 3
    • International Petroleum Exchange, the New York Mercantile Exchange and the Tokyo Commodity Exchange all have their pricing references and terms fixed in the exchange’s regulations. This means that if their pricing reference does not match the underlying physical exposure, the basis risk must either be accepted or an OTC alternative needs to be sought. (There 4 ENERGY PRI CE RI SK THE PERILS OF LIQUIDITY AND CASH FLOW RISK: METALLGESELLSCHAFT AG In 1993 the German conglomerate Metallgesellschaft AG announced that its Refining and Marketing Group (MGRM) had been responsible for huge losses of around $1.5 billion, which it had incurred by writing oil futures contracts on the New York Mercantile Exchange (NYMEX). The great irony of the situation was that its position had been perfectly sound from an economic point of view. The company’s difficulties stemmed from the fact that it had ignored the perils of liquidity and cash flow risk. In the early 1990s MGRM agreed to sell 160 million barrels of oil at a fixed price at regular intervals over a ten-year period. At the time this kind of forward contract looked like a lucrative strategy; as long as the spot price for oil remained lower than the price that MGRM had fixed, the company was sure to make a profit. However, it was vulnerable to a rising oil price, so it hedged this risk using futures contracts. Now, if the oil price rose it would lose on its fixed price forward contracts, but gain on its futures. If the price fell, it gained on the forward contracts, but lost on the futures. This appeared to adequately hedge MGRM’s price risk, but unfortunately failed to take account of its liquidity and cash flow risk. One of MGRM’s problems was the sheer size of the position it had taken. The 160 million barrels of oil that it had committed to sell were equivalent to Kuwait’s entire production over an 83 day period. It has been estimated that the number of futures contracts needed to hedge the position would have been around 55,000. NYMEX was known to be a large and liquid market, but its trade in contracts relevant to MGRM’s position averaged somewhere between 15,000 to 30,000 per day. There was thus a clear theoretical risk that MGRM could have problems liquidating its futures position. This risk created an imbalance in the market as many other players realised the size of MGRM’s position, which became in itself a factor in market pricing. Prices inevitably began to move against the company. This liquidity risk was compounded by the cash flow risk which resulted from the way that MGRM’s hedge had been structured. As was noted earlier, when oil prices went down, the value of the company’s fixed rate forward contracts rose and the value of the futures fell. The problem arose because although the forward contracts increased in value, they did not generate the cash flow which was needed to fund the regular margin calls that were due on the futures contracts. The structure of the hedge had succeeded in dealing with price risk over the life of the hedge, but had failed to deal with cash flow risk in the short term. This was probably the major factor in the staggering losses that the company suffered.
    • will be more on the differences, advantages and disadvantages of on- exchange versus OTC in later chapters.) Components of basis risk See Figures 1.2 and 1.3. Mixed basis risk Mixed basis risk occurs when an underlying position is hedged with more than one type of mismatch between the energy that is the subject of the price risk management and the pricing index reference of the derivatives instrument that is being used. For example, if a January Gasoil (heating oil) Cargo is hedged with a March Jet Kerosene swap, it would leave both time and product basis exposures. BASIS RISK 5 • Time basis This is a common exposure in many markets – In energy markets a time basis exposure can be very dangerous, particularly when there is a sudden shift in demand or transportation problems occur. • For example, let us take a Merchant Power generator in the USA who is expecting stronger natural gas prices in the summer time (due to additional use of air conditioning etc.). It hedges its position by buying the August contract in NYMEX Natural Gas Henry Hub futures If a severe heat wave was to arrive early in summer, say in late June, then the price of July natural gas may become much stronger than the August price. • Therefore August natural gas futures may not give adequate price risk cover against the July natural gas requirement. FIGURE 1.3 Time basis risk • Locational basis – You utilise a derivatives contract which prices against exactly the same specification of energy you are hedging price risk against. However, the derivatives contract is pricing against the same energy contract but in a different geographic region. – You have locational basis risk. Localised supply/demand factors, political tension, grid problems or, in the case of hydrocarbons/gas, pipeline problems, in either the location used for pricing the derivatives contract or the location where your physical supply is located, could make your derivatives contract a liability rather than a risk-reducing benefit, e.g. European Gasoil Singapore Gasoil FIGURE 1.2 Locational basis risk
    • LEGAL, OPERATIONAL AND TAX RISKS Legal risk This is the risk that derivatives contracts may be not be enforceable in certain circumstances. The most common concerns in this area surround clauses on netting of settlements, netting of trade, bankruptcy and the concern that the liquidation of contracts may be unenforceable. Opinions on many jurisdictions around the world can be obtained from the Interna- tional Swaps Dealers Association (ISDA). (Legal contract issues and nego- tiation pointers are covered in Chapter 17.) Operational risk The risk that may occur through errors or omissions in the processing and settlement of derivatives is known as operational risk. Internal controls alongside an appropriate back office system (whether manual or comput- erised) should be employed to reduce this risk. 6 ENERGY PRI CE RI SK BRENT CRUDE FUTURES AND THE CUSHING CUSHION The success of the Brent Crude Oil Futures contract is an interesting example of the importance of basis risk in the energy markets. This contract was first traded on London’s International Petroleum Exchange (IPE) in 1983, two years after the West Texas Intermediate (WTI) crude futures contract had been launched on the NYMEX in New York. On the surface, both contracts do similar jobs, for hedging purposes, at least. So, over the years, why have international companies chosen to hedge with the IPE Brent futures contract rather than its better established and more liquid American rival? The answer is a particular kind of basis risk, known in the industry as the ‘Cushing Cushion’ (after the Cushing refinery in Oklahoma, the destination of several of the south-east USA’s major oil pipelines). The ‘Cushing Cush- ion’ means that WTI ‘s crude price in the USA can act totally independently from international market prices. This can be because pipeline bottlenecks at the Gulf coast are preventing additional foreign crude from reaching the mid-continent refineries or it can be because bad weather has closed the Louisiana Offshore Offloading Point (LOOP), halting the offloading of foreign crude from carriers into the pipeline system. In situations like these, the first reaction of speculators and refineries which depend on oil in the pipeline system is to buy WTI NYMEX Futures. Sometimes WTI Premiums of US$3.00 a barrel over the IPE Brent price have been seen due to LOOP problems, pipeline problems or both. So for anyone hedging international crudes such as West African, Brent, Middle East crude oils, Dubai or Tapis, the WTI NYMEX contract carries a significant basis risk. The IPE Brent future, on the other hand, is exempt from this basis risk, which is almost certainly one of the keys to its success.
    • Tax risk Tax risk can occur when there are changes to taxation regulations that affect either the derivatives market directly or the physical underlying energy market in some way. This can create additional costs to the trade. For derivatives contracts the issue of imposed withholding taxes on any settlement payments is normally an issue covered by ISDA contracts (see Chapter 17). SUMMARY When designing an energy price risk management or trading program, it is essential to be aware of all the risks that are involved in the energy market and the ways in which they interrelate. These can be summarised as: credit risk, liquidity risk, cash flow risk, basis risk, legal risk, tax risk and operational risk. But it is important to remember that any hedging strategy which focuses narrowly on any one of these and ignores the others may be worse than having no hedging strategy at all. SUMMARY 7
    • CHAPTER 2 Energy Derivatives Markets: On-Exchange and Off- Exchange Derivatives normally make the headlines for all the wrong reasons. In the public mind, they are often associated with the activities of greedy specu- lators or with highly publicised corporate financial disasters. This is ironic because derivatives are essentially instruments to manage and reduce risk. They were created to provide opportunities to minimise price risk and to lock in profits, while reducing balance sheet volatility and the potential for losses. It is true that there have been cases in which the use of derivatives has led to spectacular losses, but this has normally been the result of their mistaken misuse or outright abuse by incompetent or ruth- less individuals. Certainly, in the normal course of business life, deriva- tives are a prudent and, indeed, indispensable tool of price risk management. Derivatives are financial contracts that derive their price or value from an underlying price or asset reference. They can be divided into three main types: futures contracts, swaps contracts and options. ■ Energy futures contracts are legally binding standardised agreements on a regulated futures exchange to make or take delivery of a specified energy product (oil, gas, coal, power), at a fixed date in the future, and at a price agreed when the deal is executed. ■ Energy swaps represent an obligation between two parties to exchange – or swap – cash flows, one of which is a fixed price normally agreed at execution, while the other is based on the average of a floating price index during the contract period. No physical delivery of the under- lying energy takes place; there is only money settlement. ■ Options are agreements between two parties that give the buyer of the option the right, but not the obligation, to buy or sell at a specified price 8
    • on or before a specific future date. They can apply to a specific futures contract (a futures option) or a specific cash flow (if an OTC Option) or they can be used to buy or sell a specific swap contract (if an OTC Swaption). When the option is exercised, the seller of the option (also know as the writer of the option) must deliver, or take delivery of the underlying asset or contract at the specified price (unlike a swap in which there is no obligation). The specified price is known as the ‘strike price’, which is the price level at which the option becomes profitable independent of whether you are a seller or a buyer. Derivatives are often referred to as ‘off-balance sheet’ items. This term is used because, in the past, there was no need for derivatives to appear on a company’s balance sheet (now this is only the case when hedging using derivatives). Derivatives were not required to appear on the balance sheet because a derivatives contract requires no transfer of the principal value of the contract; in other words, there is no commitment to lend money or take money. For example, when a one million dollar swap is traded, the principal value of one million dollars is not exchanged. Instead, an exchange is made of the cash flow of the difference between the agreed fixed price on the derivative instrument and the forward floating price reference that the derivative prices out against. ON-EXCHANGE AND OVER-THE-COUNTER In the energy industry, derivatives can be bought and sold in two main ways: on-exchange and over-the-counter (OTC). On-exchange refers to the futures markets which are found on regulated financial exchanges such the New York Mercantile Exchange (NYMEX) and London’s Interna- tional Petroleum Exchange (IPE). The OTC market is specific to the non- standard swaps and OTC options. These are usually traded directly between two companies (principals, players) in the energy markets. Although the futures markets are important to the energy industry, it relies much more heavily on OTC derivatives. This is because OTC deriva- tives are customised transactions, whereas their on-exchange counter- part, the ‘futures’ contract, is a standard contract. In theory, each deal on the OTC market is unique, so it is important to be alert to contract terms, pricing mechanisms and price reference when using OTC derivatives. Some companies find that the measurement and control of risks can be more difficult with an OTC contract because of the lack of price and liquidity transparency in the OTC market (unlike regulated futures exchanges, which publish public real-time price data) and this can create the possibility of an unexpected loss. There are also sometimes additional legal, credit and operational risks with OTC derivatives compared to on- ON-EXCHANGE AND OVER-THE-COUNTER 9
    • exchange futures contracts. However, the OTC market remains a popular option for price risk management purposes. Many companies find that there are benefits in the flexibility of an OTC derivative because it can be valued against the same price reference as the energy which is being produced or consumed. As the pie chart in Figure 2.1 shows, energy OTC derivatives markets are far less liquid than most other financial derivatives markets (see also Table 2.1), accounting for less than half of one per cent of the value outstanding on derivatives markets worldwide. This means that those who take part in energy markets whether as market makers, traders or end-users (usually companies with underlying price risk in the energy being hedged either as a producer or consumer), need to have clear poli- cies for derivatives usage, including strong management controls and organisational reporting structures effective before derivatives are employed. They should also provide shareholders with information that will put to rest any unjustified fears associated with their company’s use of derivatives. Indeed, as a result of the concerns of regulators and public shareholders around the world, more and more information is now required by international accounting standards (for more on this point, see Chapter 18). Table 2.2 shows more historical data. FUTURES A brief history of the futures markets Oil futures contracts have been traded on financial exchanges since the 1970s, although ad hoc negotiated physical supply contracts have been 10 ENERGY PRI CE RI SK 120 90 60 30 0 98 H1 Evolution since 1998 99 H1 00H1 01 H1 Product breakdown at end-2001 Interest rate 80.1% Equity 1.9% Commodities 0.6% Foreign exchange 17.3% FIGURE 2.1 OTC derivatives contracts: global amounts outstanding (US$ tril- lions). Source: BIS (Bank for International Settlement; http://www.bis.org/)
    • around since oil was drilled in the USA in the 1850s. The first formalised regulated futures exchange for oil was the New York Mercantile Exchange (NYMEX) which started contracts on heating oil in 1977 (relaunched as the FUTURES 11 Notional amounts Gross market values End June 2000 End Dec 2000 End June 2001 End Dec 2001 End June 2000 End Dec 2000 End June 2001 End Dec 2001 Grand total 94,008 95,199 99,755 111,115 2,572 3,180 3,045 3,788 Foreign exchange contracts 15,494 15,666 16,910 16,748 578 849 773 779 Outright forwards and forex swaps 10,504 10,134 10,582 10,336 283 469 395 374 Currency swaps 2,605 3,194 3,832 3,942 239 313 314 335 Options 2,385 2,338 2,496 2,470 55 67 63 70 Interest rate contracts2 64,125 64,668 67,465 77,513 1,230 1,426 1,573 2,210 FRAs 6,771 6,423 6,537 7,737 13 12 15 19 Swaps 47,993 48,768 51,407 58,897 1,072 1,260 1,404 1,969 Options 9,361 9,476 9,521 10,879 145 154 154 222 Equity-linked contracts 1,645 1,891 1,884 1,881 293 289 199 205 Forwards and swaps 340 335 329 320 62 61 49 58 Options 1,306 1,555 1,556 1,561 231 229 150 147 Commodity contracts3 584 662 590 598 80 133 83 75 Gold 261 218 203 231 19 17 21 20 Other 323 445 387 367 61 116 62 55 Forwards and swaps 168 248 229 217 ... ... ... ... Options 155 196 158 150 ... ... ... ... Other4 12,159 12,313 12,906 14,375 392 483 417 519 Gross credit exposure5 937 1,080 1,019 1,171 Memorandum item: exchange-traded contracts6 13,918 14,215 19,464 23,540 1All figures are adjusted for double-counting. Notional amounts outstanding have been adjusted by halving positions vis-à-vis other reporting dealers. Gross market values have been calculated as the sum of the total gross positive market value of contracts and the gross negative market value of contracts with non-reporting counterparties. 2Single- currency contracts only. 3Adjustments for double-counting estimated. 4Estimated TABLE 2.1 The global OTC derivatives market1: amounts outstanding (US$ billions). Source: BIS Report published 15 May 2002: OTC Market Size (http:// www.bis.org/)
    • current contract in 1979) which was followed by West Texas Intermediate contract (WTI crude). On the other side of the Atlantic, the International Petroleum Exchange (IPE) of London was launched in 1981 and now boasts, in the Brent Crude Oil Futures contract, the leading international benchmark for the pricing of physical crude markets around the world; approximately 70% of the world’s crude oil markets price in some way against Brent Crude Oil. Both NYMEX and IPE also operate futures markets for Natural Gas and Electricity/Power. In recent times, there has been concern that the liquidity in the physical Brent crude oil market has been getting smaller, and as a result some oil majors have taken the initiative to participate in the development of Brent–Forties–Osenberg (BFO)-related trading rather than just Brent- related trading. Pricing information services such as Platts have already modified the crudes they include in their Brent price reporting and even the International Petroleum Exchange is examining (September 2002) the use of BFO prices in its price index for settling the Brent Futures contract. In the Far East, SIMEX (now merged into SGX in Singapore) ran a popular Fuel Oil Futures contacts in Singapore until the early 1990s, when it was overtaken in popularity by the OTC (off-exchange over-the-counter derivatives market) and Asia is now totally dependent on OTC derivatives for risk management purposes in energy markets. However, a Tokyo Commodity Exchange (TOCOM) contract for Middle East crude oil has been attracting both interest and trading volume, and this could become a useful on-exchange futures contract tool for Middle East crude hedging, 12 ENERGY PRI CE RI SK Jun 1998 Dec 1998 Jun 1999 Dec 1999 Jun 2000 Dec 2000 Jun 2001 Dec 2001 Total commodity contracts 451 415 444 548 584 662 590 598 Gold 193 182 192 243 261 218 203 231 Forwards and swaps 103 76 87 119 120 101 88 101 Options 82 99 102 124 141 116 116 130 Other precious metals 25 50 62 54 57 55 25 30 Forwards and swaps 15 22 24 14 9 11 10 16 Options 11 28 38 40 49 44 15 14 Other commodities 233 183 190 251 266 389 361 337 Forwards and swaps 138 114 103 148 159 238 218 201 Options 95 69 87 103 106 152 143 135 TABLE 2.2 Billions of OTC derivatives notional outstanding. Source: BIS (http://www.bis.org/)
    • particularly since Asia is heavily dependent on Middle East crude imports for oil refinery operation. Futures versus OTC At one time it was easy to distinguish the futures market from the OTC market and also to establish the pros and cons of using one or the other. As Figure 2.2 shows, when risk managers or traders used futures contracts they knew that the contract would be traded on an exchange, that they would have an account with their futures broker and that they were oper- ating in a highly regulated market. They could also see the price of the contract on a screen and they could be sure that the security of the contract and its performance would be guaranteed by the clearing house of the exchange. This in turn was guaranteed by ‘margins’ (good faith payments by everyone with a futures position on that particular exchange), plus the funding the exchange raised itself and the funds contributed by its clearing broker members. Margins on a futures exchange can be split into two types: ‘initial margins’ and ‘variation margins’. Initial margins are the good faith deposit that is placed with the clearing house or that a broker finances (at a cost) when a trade is opened. A variation margin is the daily revaluation of a portfolio with the clearing house. If the valuation is negative, you or your broker (if you have a credit line) will have to place a margin to cover that negative variation margin. If the next day the portfolio has a positive FUTURES 13 Client A Wants to buy 1 futures Clearing house Broker trades on the Futures Exchange Broker Broker Clearing house creates 1 new futures contract: a Buy + a Sell. It guarantees the performance on these trades Broker Broker Client B Wants to sell 1 futures Client A Broker informs Client that the new Futures position has been created Client B Broker informs Client that the new Futures position has been created FIGURE 2.2 Basic futures trade transaction flow
    • variation margin (i.e. it is showing an unrealised profit), because the posi- tion has not been traded or closed out yet, some of that margin will be returned. However when OTC contracts are used there is always the credit risk of the other company in the transaction, as well as a liquidity risk and a lack of price transparency because there is no screen to display a real-time price. The convergence of OTC and futures The clear distinction between the OTC energy market and the futures markets is now disappearing as the two markets converge. Clearing houses around the world have started to accept OTC trades into their guarantee umbrella. This means that after executing bilateral OTC trades with one another, both counterparts can agree to ‘give-in’ their OTC deal to a clearing house. This process basically makes the clearing house the counterpart to the OTC deal, so that the two OTC counterparts can benefit from the higher credit quality of the clearing house as well as getting other benefits such as more netting opportunities on settlement and offsetting of positions. The usual market approach is for two OTC counterparts to trade an OTC derivative contract with one another directly and to take on one another’s credit risk: In the new convergence environment we now sometimes have a situa- tion like this: Although market share penetration has been slow in the oil sector, we have seen the newer power and gas markets embracing electronic trading platforms in a big way. This has brought about greater price transparency as users can view and trade prices onscreen like futures markets. As a result, power and gas markets have been the quickest to embrace OTC clearing. Futures contracts settlement on expiry Energy futures contracts all entail physical and cash delivery on expiry (apart from IPE Brent Crude Futures in London). So if a seller (someone 14 ENERGY PRI CE RI SK OTC counterpart OTC counterpartClearing house Two companies negotiate an OTC deal with one another but on the basis of the clearing house becoming what is termed the ‘central’ counterpart. OTC counterpart OTC counterpart
    • who is short in the market) holds the futures contract to expiry he will have to deliver the underlying physical energy (oil, gas, power) and if a buyer (someone who is long in the market) holds the contract to expiry, he will have to take delivery of the underlying physical energy. However, actual delivery via futures markets like the NYMEX or IPE is very small, normally less than 2% of the total open interest (the total amount of outstanding contracts in the market). The majority of trades on these markets are for hedging and or speculative purposes, with consumers or producers of energy preferring to make delivery via the normal physical markets rather than through the futures markets. SWAPS AND OPTIONS Swaps contracts settlement on expiry Swaps are contracts which, unlike futures, never go to physical delivery. They are by their very legal structure purely financially based contracts, which allow companies to benefit from the price/value movement of the underlying asset that the swaps price is derived from. It is called a swap because the two counterparts to the deal, the buyer and the seller (the long and the short) exchange an agreed fixed price today for the unknown floating price In the future. When traders are negotiating an OTC deal they focus on: ■ The fixed price ■ The floating price reference (see Chapter 3 for a listing) ■ Pricing period (e.g. one month, quarterly, calendar year) ■ Start date or effective date ■ End date or termination date ■ Payment due date. For example, for a swap priced against an American or European floating price reference, payment due date is normally the fifth business day after the last pricing day of each pricing period. In energy and generally commodity markets, OTC derivatives will price out monthly, so even if a quarterly contract is traded, after each month during the pricing period, one third of the volume will price out and a settlement will become due by or a payment received by the organisa- tion. For contracts pricing against an Asian-based floating price refer- ence, payment for settlement is generally due 10 business days (sometimes up to 14 business days) after each pricing period. Option contracts on expiry What happens to an option contract on expiry and when or whether it is exercised (transfers into its underlying) depends very much on the type of SWAPS AND OPTIONS 15
    • option it is and also whether it is a futures option (traded on a futures exchange, referred to as traded options) or whether it is an OTC option. When a traded options position is held on a futures exchange, if the option is ‘in the money’ on expiry, the clearing house will prompt clearing brokers to notify their customers that their option is in the money and request whether they wish to exercise the option as it is profitable to do so. An option is in the money when it has intrinsic value; i.e. exercising the option into its underlying futures contract (in respect of traded options) and then trading out (closing out) that futures contract would bring a profit. In some instances, if the traded option is heavily in the money, the clearing house of the futures exchange may even exercise it automatically, which acts as a safety net for users of the market. However, there are no safety nets in the OTC world of derivatives. If you have a profitable swaption that could exercise into a profitable swaps position for you and you forget to tell your counterpart that you wish to exercise it by the cut-off time (written in the original option contract), you will be left to negotiate with that other counterpart. It will be up to your counterpart whether they will still let you exercise the swaption and if they do, it will most probably come at a price. Types of swaps in energy markets Plain vanilla – terms used to describe a simple averaging swap A plain vanilla swap (Figure 2.3) is a monthly averaging swap with the following features. ■ Fixed prices versus floating prices in the future are exchanged; i.e. they are is swapped. ■ They are used extensively in Oil, LPG and LNG related hedging and trading. ■ When executing the deal counterparts discuss the fixed price agreed today and which floating price reference they will use to calculate the settlement. The following is a cash flow example of a plain vanilla deal: ■ Counterpart A buys fixed price 15.00 (buys fixed, sells floating) ■ Counterpart B sells fixed price 15.00 (sells fixed, buys floating ■ Floating price reference is chosen, e.g. Platts average during the price period (say) March 2003 = 16.00 16 ENERGY PRI CE RI SK A B Fixed Floating FIGURE 2.3 A plain vanilla swap
    • ■ Net result: ● Counterpart A = +$1.00 (difference between fixed/floating) ● Counterpart B = –$1.00 ● Counterpart B pays Counterpart A US$1.00. Only the difference is exchanged, not the principal notional amount. Differential swap A differential swap is like a plain vanilla swap except that instead of one fixed price versus a floating price, it is based on the difference between a fixed price in two products. In the oil sector, the most popular differential swap is the Jet Kero versus Gasoil (Figure 2.4), commonly termed the ‘regrade’ swap. The following is a cash flow example of a differential swap: ■ Counterpart A buys fixed price Kero and sells fixed price Gasoil at a difference of US$0.50 per barrel Kero premium. ■ Counterpart B sells fixed price Kero and buys fixed price Gasoil at a difference of US$0.50 per barrel Kero Premium. ■ Floating price reference is chosen, e.g. Platts Kero and Gasoil average difference during the price period (say) March 2003 = 0.60 Kero premium. ■ Net result: ● Counterpart A = +$.10 (difference between fixed differential and the floating differential) ● Counterpart B = –$0.10 cents per barrel ● Counterpart B pays Counterpart A US$0.10. Only the difference is exchanged, not the principal notional amount. Differential swaps are used across the whole energy spectrum. In the power and gas markets we see ‘spark spreads’ (Table 2.3), where hedgers and traders use derivatives pricing against the difference (referred to as the ‘dif’) between power and gas markets. This is based on the amount to be made by burning gas and selling power in a perfect world using a stan- dard percentage efficiency of the conversion of energy. The normal effi- ciency used is 49.13% and the spark spread is quoted in megawatt hours (MWh). In coal versus power there is the so-called ‘dark spread’, which works on the same principle as the spark spread with two fixed prices and two SWAPS AND OPTIONS 17 Gasoil Jet Kero FIGURE 2.4 A differential swap
    • floating prices documented in swaps confirmation. However, the net exposure is only on the differential between the two products/instru- ments. In the UK, dark spreads use an energy conversion efficiency of 5,000 MT of coal producing 55 MW of electricity at an efficiency of 38%. (There will be more detail on this in Chapter 3.) Participation swaps Participation swaps are similar to regular plain vanilla fixed for floating swaps as the fixed price buyer can be 100% protected when prices rise above the agreed fixed price or the fixed price seller can be 100% protected when prices move down below the agreed fixed price. However, unlike an ordinary swap, the client ‘participates’ in the down- side by only an agreed percentage. The percentage of participation affects the starting fixed price of the swap. A fixed price buyer who only wants to participate in a percentage of any price move lower may find that the fixed price quoted for a participation swap would be higher than a normal swap. On the other hand, if you were a seller of fixed price who wanted to participate in only a percentage of any move higher that would incur a loss on the short swap position, you might find that the fixed price quoted for a Participation Swap would be lower than a normal swap. Double up swaps By using the double up swap, swap users can achieve a swap price which is better that the actual market price, but the swap provider will retain the option to double the swap volume before the pricing period starts. If a company has price exposure to energy prices going higher, but the current plain vanilla swap is not being quoted around its budgeted level, it may find that a double up swap will let it hedge some of its required volume closer to its hedging budget level. The risk is that the market price could move against the derivatives position and the swap could price out against twice the original executed volume. Double up swaps are not commonly used in the market for price risk management purposes (hedgers tend to use options more if the current swap price is not inter- esting for them). However, double up swaps could offer an interesting 18 ENERGY PRI CE RI SK Gas price Power price Spark spread Pence per therm £/MWh £/MWh £/MWh September 12.15 4.15 12.7 4.26 October–December 20.55 7.01 16.35 2.08 July–September 16.5 5.63 14.55 3.09 TABLE 2.3 Spark spread
    • opportunity for speculators who have a strong price direction view on their particular energy focus and want to get a head start by buying at a better price level than the current plain vanilla swap, or selling at a higher level than the plain vanilla swap quotes. Margin swaps This is where an organisation can take its overall price risks from several energy inputs and outputs of the business process and get a complete swap structure that guarantees its profit margin. Organisations could construct complex hedges themselves to protect their energy inputs/ outputs. This has a cost in terms of managing many individual positions with perhaps several counterparts. It can therefore be more cost efficient and easier to enter into a margin swap with one counterpart who is willing to provide a contract that covers all the price risks (Figure 2.5). However, it should be remembered that price risk management is never free and there are always costs attached to any control function in a company internally or externally. Administration and human resources available in an organisation will have to be reviewed and adjusted if necessary depending on the level of activity the organisation expects to have in derivatives. SWAPS AND OPTIONS 19 Oil refiner Energy outputsEnergy inputs Crude oil feedstock Naphtha Jet Kero Gasoil Fuel oil Gasoline Refiner Margin swap counterparty Fixed price on feedstock Fixed price on product Floating price risk absorbed by margin swap counterparty One contract FIGURE 2.5 Example of a margin swap for an oil refiner
    • Knock-ins and knock-outs – integration with swaps and options Knock-in and knock-out options are two types of barrier option which are activated if the underlying moves through a trigger price level, in the case of a knock-in, and is cancelled or deactivated in the case of a knock-out. A market maker or trader will normally offer a more attractive price on this kind of option because the buyer is giving the seller of the option the opportunity to cancel it before its original expiry/termination date. This adds another dimension of opportunity or potentially reduced risk to the seller of the option; hence the lower price than an option of same strike price, tenure and underlying price reference without such a barrier option structure. Knock-in and knock-out triggers can be integrated with both swaps and options. Figure 2.6 shows how the barrier option either comes to life (is knocked in) or is extinguished (knocked out) under certain conditions. In practice, the event which activates or kills the options is defined in terms of a price level (the barrier). A common example is the up-and-out floor (put) which is typically purchased by an energy producer to hedge their natural long position in the energy markets. Up-and-out floor (put) may be an attractive alternative to the normal floor or put option, as it is less expensive and provides the same price protection if prices move down from current levels. However, if prices move upwards, the increase in the underlying commodity’s price reduces the need for downside risk protection at the original strike price. If the price moves up sufficiently to cross the selected ‘barrier’ price, then the option is cancelled/extinguished. The owner may consider re-entering a hedge by buying another floor at a higher strike price, which gives more valuable protection than the floor with the lower strike price which was cancelled. The barrier option may also be combined with a rebate. For a knock-out option, the rebate is paid when the option is cancelled prior to its normal expiry as a compensation to the holder. The up-and-out barrier is less expensive than a standard Asian, Euro- pean or American option because the underlying price may fall below the 20 ENERGY PRI CE RI SK Price Up Down Out In Up-and-out Up-and-in Down-and-out Down-and-in Type of option FIGURE 2.6 Barrier options – caps/floors
    • strike price after initially rising, hitting the barrier and cancelling the option. However, there may be liquidity issues with this strategy, as there are a limited number of traders in the market who may be able to quote you this more complicated option strategy. The common and more liquid option markets in energy – calls and puts, caps and floors On futures exchanges, traded options are referred to as calls and puts, while in the OTC market the same sort of contracts are referred to as caps and floors. If an organisation buys a call or cap, it gives the buyer of the option price protection against the market moving above the agreed price, the ‘strike price’, in return for the payment of a premium or fee. The strike price is the level at which the players can participate in the market via the option contract. If an organisation buys a put or floor, it gives the buyer of the option protection against the market moving below the strike price, again in return for the payment of a premium or fee. Figure 2.7 illustrates the various possibilities. Options strategies can be very flexible and can help companies achieve exactly the risk reduction or risk exposure profile they want to have. When a buyer purchases an option, the cost of the contract is the premium paid, and the buyer will not be required to pay any more than whatever the market price demands. If an option is sold on its own, it is called a naked option. This means that the seller does not own the underlying physical commodity or does not have another futures or swaps position against the option that has been sold. In this case, there is unlimited risk if the market price moves in an adverse way (Figure 2.8). SWAPS AND OPTIONS 21 Original option cost Value of commodity Call/cap Market higher Value increases Put/floor Market lower Value increases FIGURE 2.7 Calls and puts, caps and floors
    • Main option styles ■ American style – An American style option is one that may be exercised into its underlying instrument (i.e. a futures contract) on any business day until expiry. All the IPE and NYMEX traded options on energy futures contracts are American style. These options are more expensive than European options because they give so much flexibility to the buyer as to when the option can be exercised. ■ European style – These are not very common in the energy markets, as they only permit the buyer to exercise the option on expiry. European options are cheaper than American options, but generally more expen- sive than Asian-style. ■ OTC Asian style – This is the most common option style in the OTC market and they are sometimes called ‘restrospective’ or ‘path-depend- ent’ options. The reason for this is that they are average price options, with their profit being dependent on the price history of the underlying energy market that is being used as the price reference, either overall or sometimes at a specific stage in the life of the option. The cost of an option – its premium There are many types of option models available and each one has its own particular use depending on the type of option that is being used. It is not necessary to have an in-depth understanding of the mathematics of these models. However, users should understand what needs to be put into the model in order to obtain the right answers and they should be able to interpret the output results. It is fair to say, though, that the core factors that play an important role in determining the value of any option are generally those shown in Figure 2.9. Margin options These are options that can price against a complex structure of differen- tials instead of pricing against a single floating price reference. Earlier in 22 ENERGY PRI CE RI SK Cap/call Floor/put If the option is sold as a naked option: Potential unlimited loss exposure on the option if the underlying market price moves above the strike price of the option Potential unlimited loss exposure on the option if the underlying market price moves below the strike price of the option FIGURE 2.8 The risks of naked options
    • the chapter, we looked at the illustration of a margin swap for an oil refiner. That oil refiner could have bought an option on its refining margin instead of using the swap strategy. The option strategy might at first appear less attractive, as it contains an up-front premium cost, whereas the swap strategy would not require any such cost. However, the flexi- bility offered by the option strategy becomes apparent if the margin gets better. If the refiner had used the swap strategy its profitability would be fixed, although if the margin improved, any loss on the swap would be offset by better prices on the resale of its physical assets: the petroleum products. In this case, it would just have the opportunity cost. But if it paid a premium for an option strategy (e.g. a margin option) then if the margin improved more than the cost of its option strategy, it would still be able to benefit from that margin improvement. This is most useful when dealing with a present day or even forward negative margin – a situation which has been experienced by oil refiners in some of the fuel oil markets for a long time. In this case, the refiners might have good margins which they wish to lock in by using swaps on the middle distillates (e.g. Naphtha, Gasoil, Jet) but they are still faced with the need to halt any further expo- sure in the Fuel Oil margin becoming more negative (and at the same time, they do not want to lock in a negative margin). In this instance, the refiner could look at a Crack Option (Crude (feedstock) versus Fuel Oil) and still have the potential to benefit and profit from any improvement in the margin on this product in the future. Option premium cash flow When a traded option is purchased on a futures exchange, it is normal to put up ‘margin’, in the form of a good faith deposit (approximately 10% of the notional value, subject to market volatility at the time of the trade). After that, the position will be marked to market on a daily basis and there SWAPS AND OPTIONS 23 Reference rate (benchmark e.g. futures or swaps) Strike Expiry Volatility estimate Interest rate (risk-free e.g. base rate) Option pricing model Premium/ cost of option FIGURE 2.9 Option premium calculation principles – premium.
    • will be an obligation to finance any negative ‘variation margin’. In the case of an OTC option, the buyer normally pays the premium up-front to the seller. This generation of cash premium is where OTC options can offer interesting opportunities for linkage to commodity- or energy-linked projects that require financing. It is possible to create structures that offer a price risk hedge at the same time as generating prompt cash flow which can be reinvested in the project or in other business activities of the organisation (these activities are usually associated with the structured finance departments of banks). For traders who are trying to make money by speculating in the very risk of the energy price moving or not (as the case may be), options offer the ability to do the following: ■ Create trading strategies that profit from price direction moves ■ Create trading strategies that profit from the price moving in a partic- ular price band ■ Create trading strategies that profit from the price staying the same by using volatility trades; money can be made not from the market price moving up or down, but on volatility increasing or decreasing. SUMMARY The energy derivatives markets provide risk managers and traders with an enormous choice of instruments both for price risk management and for speculation. Traditionally, the energy industry has favoured over-the counter (OTC) derivatives which can be customised to meet the needs of both counterparts to the deal. However, some companies have found drawbacks to the OTC market such as a lack of liquidity or price transpar- ency. But these problems should be ironed out as the OTC market converges with the on-exchange market to provide a more effective and efficient service to all parties concerned. 24 ENERGY PRI CE RI SK
    • SUMMARY 25 KEY OPTIONS TERMINOLOGY American option An option which can be exercised on any business day up to and including the expiry date. Asian option A path-dependent option, also known as an average rate options. This is an option where the settlement is based on the difference between the strike and the average price of the underlying floating refer- ence price over a determined period of time. At-the-money An option term used to describe the fact that the option- underlying is equal to the option’s strike price. This can be applied to a futures contract, a swaps contract or some average price of an underlying energy market. Delta Delta gives you a mathematical measurement of how sensitive an option is to price changes in the underlying energy market. Delta operates on a scale of 0 to 1. For example a Delta of 0.5 implies that if the underlying moved by US$1 dollar the option could move by US$0.50, or half of the underlying energy market’s price move. European option An option which can be exercised on the expiry date only. Fair value The combination of intrinsic value and time value, as calculated by the option pricing model. Implied volatility The volatility value placed on option quotes. In-the-money It means the option is profitable, if you exercise the option or trade out of it you can gain a profit. Intrinsic value The difference between the strike price and the current market rate. Out-of-the-money The option is not in-the-money, and it would not prof- itable to exercise the option or trade out of it. Premium Price or cost of an option. Strike price The entry price into the underlying; participation level. Time value The difference between the option premium and the intrinsic value, including time until expiry, volatility and cost of carry (interest percentage). Value date The date when the underlying is settled or delivered. Volatility The normalised annualised standard deviation of the underlying futures/swap contract.
    • 26 ENERGY PRI CE RI SK KEY DERIVATIVES TERMINOLOGY Abandon Where an option holder chooses not to exercise his or her option. Arbitrage The purchase or sale of an instrument and the simultaneous taking of an equal and opposite position in a related market when the pricing is out of line. For example, in the oil markets, major arbitrages are traded between Heating Oil in New York and Gasoil in Europe, and Gasoil in Europe versus Gasoil in Singapore. Assignment (futures) Notice sent by a clearing house of a futures exchange to an option writer (option seller) that the option has been exercised. Assignment (swap) Where the original counterpart to a swap deal trans- fers the position to a third party organisation who then takes over as the counterpart to the deal. We were able to see instances of this happening during the Enron collapse in 2001. In order to reduce overall losses on its books it assigned profitable OTC derivative deals that it held in one commodity with one counterpart with losing trades held with other coun- terparts. All parties involved had to accept these assignments. Average price contract A contract which is conditional on an average of market prices rather than a single market price on one single day. Very common average price contracts are the monthly average price swaps in the OTC oil markets. Back office A term for the department handling the operation functions of processing trades done by the trading operation. Backwardation The decrease in the forward prices of the market as their expiration time increases (i.e. the energy market is cheaper the further in the future you check out the prices). Benchmark A pricing reference from which other energy markets are compared to or priced off using some pricing formula. (e.g. 70% of the world’s crude oil markets are priced off the Benchmark Brent Crude Oil in the UK North Sea. A lot of the world’s natural gas is priced of crude oil ‘benchmarks’) Book Another term for a derivatives portfolio (e.g. ‘the company’s book is long (they have bought) German Power for 4th Quarter’). Call/cap A call option is the futures market equivalent of an OTC cap option. These options give the purchaser of the option the right, but not the obliga- tion, to buy the option’s underlying asset at some future point in time at the option’s strike price. (The strike price is the price you agree you would buy at if you had bought the call/cap or sell if you had sold the call/cap whatever the option is based on, e.g. a futures contract or a swaps contract.) Carry cost The cost of storing energy, oil, gas etc. from one pricing or delivery month to another. For example, to store Gasoil in the Amsterdam–Rottderdam–Antwerp storage region in North West Europe you may find a typical storage cost of US$1.25 per MT per month. If the IPE
    • SUMMARY 27 Gasoil futures contract today was US$250 per MT and next month US$252 dollars, then in a perfect world, you could buy storage, fill it up with Gasoil at a cost of US$250 per MT, and use the futures market or OTC swaps market to lock in the value of US$252 dollars per MT and make a profit of US$0.75 per MT (US$252 minus storage cost US$1.25 minus Gasoil cost of US$250 = US$0.75 per MT). Cash-settled contract A derivative contract in which counterparties exchange money at settlement rather than delivering actual oil, gas or power, in exchange for cash. The money exchanged is based on the value of the underlying energy. Whether a derivative contract goes to physical delivery instead of the cash-settled route can affect accounting rules that can be applied even if an organisation is hedging and not speculating (see Chapter 18). Contango The situation in which forward prices increase the further forward you look (also known as a ‘normal’ market in the USA). Counterparty risk The risk of one side of a party to a contract not fulfilling an obligation of a contract. Credit derivative Also known as a Credit Default Swap or CDS for short. It enables the trading and also the risk mitigation/reduction of credit risk on a particular entity or group of entities. More widely used now in the energy sector. A CDS is usually more expensive than traditional trade credit insur- ance, where available, but there are generally more specific payout trigger events than those seen in credit insurance contracts, which brings more comfort to users. Deal capture This describes the operational process of recording a signed derivatives contract in the organisation’s trading ‘book’. Day trade A position opened and closed within the same trading day. Delivery The process of final settlement of a futures contract, swaps contract or option via cash settlement or physical delivery (in the case of futures). Delta Delta represents the change in overall value of an option given one unit change in the price of the underlying of the option (i.e. the option price movement in relation to the futures contract it is based on or the swaps contract it is based on). Derivative contract A financial contract that derives its price (value) from an underlying energy price or asset. Early exercise Indicates exercising the option prior to its expiration date. Limited to American style options. Embedded option An optionality within a contract that is not specifically referred to as an option. End user Generally refers to buyers of derivatives contracts or risk manage- ment services who use the oil, gas or power for their own purposes. EFET European Federation of Electricity Traders. This is the organisation that created the EFET master trading agreement which the forward power and natural gas markets of continental Europe tend to trade under.
    • 28 ENERGY PRI CE RI SK Events In derivatives contract terms, an event is something that happens in the real world and in turn triggers an ‘event’ in a swap agreement. For example, when Enron had its credit rating downgraded this triggered a ‘credit event’ in some of its derivatives trades and it was forced to place collat- eral with some of its counterparts, creating a huge cash flow crunch and in turn triggering its downfall. It can also mean, in terms of the market place, an extreme event that triggers rapid price movement in the energy markets. Exchange This is usually a regulated trading centre that offers standard contracts and requires the use of their clearing house and margining of trades. Exercise The process of taking up the options rights on an option contract. Exotic contract A derivatives contract with a complex structure. The opposite of a plain vanilla contract, which is simple. Exotic options New OTC options including barriers. Expiration The date on which a forward, futures, swap or option contract expires/terminates. In an OTC trade it is usually described as the end date. Extrinsic value The amount by which the premium on an option exceeds the intrinsic value, often caused by time value in the option. Front office A term to describe the trading operation of marketing, trading and managing the trading books. Usually the department that provides the means of executing a company’s hedging or trading strategy. Future A standardised contract offered by an exchange allowing a company or individual to trade or protect against future price movements. On expiry in energy markets, it usually goes to physical delivery. GTMA Grid Trading Master Agreement, created by Allen & Overy lawyers in London, UK. UK Electricity forward markets trade under this agreement, unlike other energy swaps which trade under ISDA Master Agreements. Hedge A derivative transaction that reduces or mitigates the price risk an organisation may have in its day-to-day business operation. For example, an airline hedges its exposure to Jet Fuel prices by using Jet Fuel/Kero-related derivatives contracts. Historical volatility An indication of past volatility in the energy market. Initial margin The good faith collateral placed with the clearing house for futures exchange or OTC contracts. Initial margin is paid on the opening of a new derivative position. The clearing house sets the level of initial margin required on each derivatives contract based on current market circum- stance, including price volatility. The initial margin is returned once the derivative position has been closed out either through expiry or by the user trading out of the contract by trading an opposite position. Implied volatility The volatility implied from the market price of an option. You can use an option model to reverse engineer what the level of implied volatility is from an option premium being quoted in the market. ISDA International Swaps & Derivatives Association (http://www.isda. org/), the group that created the ISDA Master Agreement 1992, the backbone
    • SUMMARY 29 for the majority of energy-related derivatives trades (with the exception of UK and European Power and Nat Gas OTC, which trade under GTMA, NBP and EFET agreements). IPE International Petroleum Exchange of London (http://www.ipe.uk. com/). Liquidity This is based on the amount of trading going on in a particular derivatives contract. The greater the liquidity, the greater a user’s confi- dence may be in the efficiency of that market and in turn the value of the prices generated by that market. Liquidity can play a big part in selecting derivatives contracts for hedging or speculation purposes. Long A trading term that describes someone who has already bought a futures contract, a call option or swap, and who is holding a derivative that benefits them if energy prices move higher. Marked-to-market The daily revaluation of a derivatives portfolio, some- times referred to as ‘marking-to-market’. The norm in the energy trading world is to mark-to-market derivatives every day for risk management and general management reporting and control purposes. Traders may refer to their MTM value, which is the latest marked-to-market value of their deriva- tives portfolio or even their derivatives plus physical energy position. Maturity The time at which a contract expires. Notional The dollar value of the underlying asset upon which a derivative contact is based. For example, a user sells 500,000 barrels of crude oil swaps at a fixed price of US$28. Besides being a pretty good level to sell crude oil on a historical basis, the notional value of the deal is 500,000 × US$28 = US$14 million. NYMEX The New York Mercantile Exchange (http://www.nymex.com). Open position The number of contracts that have not been offset by close of business. Paper contract A derivatives contract that allows the counterparties to the deal to cash-settle with money and not through physical delivery. All swaps contracts are cash-settled, but most futures contracts go to physical delivery. Settlement price The price at which all futures are margined; a represen- tative price for the close of the day’s trading. Swaption An option on a swap transaction. These options can be buyers or sellers of the underlying swap and also American or European style. Tick The standard minimum price movement, usually referring to the minimum price movement of an on-exchange futures contract. However, the OTC energy markets have created their own kind of standardisation as well. Price discovery The process of determining the market value of a partic- ular energy derivatives contract. Risk management The process of evaluating, measuring and managing the various risks within a company’s portfolio of financial and energy expo- sures as well as any assets.
    • GENERALLY ACCEPTED OIL CONVERSION FACTORS USED IN THE DERIVATIVES INDUSTRY Barrels per tonne Crude Oil 7.9–6.5 Brent Crude 7.57 Naphtha 9.0 Motor Gasoline 8.9–8.0 Gasoil and Kero/Jet 7.45 Fuel Oil 6.9–6.3 US gallons price to US$ per tonne Heating Oil (NYMEX) Heating oil price × 3.1323 e.g. 74.00 (cents per US gallon) × 3.1323 = 231.79 per MT This is utilised for calculating the arbitrage between International Petroleum Exchange of London Gasoil Futures contracts and the NYMEX New York Harbor Heating Oil, both similar grades of petroleum product. (Arbitrage is the difference in price for two similar grades of oil in different locations; if the arbitrage is ‘on’ it means you can move oil from one location to another and cover the cost of shipping). 30 ENERGY PRI CE RI SK Short Someone who has sold futures or swaps or has bought a put/floor option. They benefit from the market going lower. It can also mean someone who is naturally short in the physical market. For example, consumers of energy are naturally short, always exposed to the prices going higher, unless they hedge. VAR Value At Risk is a type of derivatives position analysis that provides users with a possible profit/loss within a set probability parameter: usually 95% or 99% confidence level over 24 hours. There are different approaches to VAR analysis, and these are discussed in later chapters. Variation Daily movements of debits and credits to and from exchange clearing members, as a result of futures and options positions being marked- to-market. With some OTC contracts now also being cleared via futures clearing houses, this is starting to be applied to OTC contracts as well.
    • US gallons price to US$ per barrel Heating Oil (NYMEX: http://www. nymex.com/) Heating oil price × 42 e.g. 0.74 dollars per gallon × 42 = US$31.08 GENERALLY ACCEPTED GAS CONVERSIONS Litres/tonne Ethane 2730 Propane 1962 Butane 1735 Naphtha (distillate feedstock) 1463 Aviation Turbine Fuel 1248 Aviation Turbine Fuel, Wide Cut 1260 Middle Distillate Feedstock 944 Derv Fuel 1182 Gasoil 1172 1 tonne of liquid methane 16 barrels = 50,000 cubic feet 100 million cubic feet of natural gas per day = 360 million therms per annum 1 therm = 100,000 Btu = 105.5 MJ = 29.3 kWh 1 Btu (British thermal unit) = 1.055 kJ 1 Btu/lb = 2.326 kJ/kg 1 kilowatt hour (kWh) = 3.6 MJ VOLUME 1 gallon (US) = 3.78541 litres 1 barrel = 42 gallons (US) = 158.987 litres GENERALLY ACCEPTED GAS CONVERSIONS 31
    • API GRAVITY AND DENSITY/VOLUME PER TONNE Degrees API @ 60 EF Density @ 15 EC Barrels per tonne 25.0 903.7 6.97 26.0 897.9 7.02 27.0 892.3 7.06 28.0 886.7 7.10 29.0 881.1 7.15 30.0 875.7 7.20 31.0 870.3 7.24 32.0 865.0 7.28 33.0 859.7 7.33 34.0 854.5 7.37 35.0 849.4 7.42 36.0 844.3 7.46 37.0 839.3 7.51 38.0 834.4 7.55 39.0 829.5 7.60 40.0 824.7 7.64 41.0 819.9 7.69 42.0 815.2 7.73 POWER AND GAS CONVERSION FACTORS kWh GJ therm mn Btu ft3 m3 t LNG t oe 1 kWh – 0.0036 0.0342 0.00342 3.3367 0.094515 0.000066 0.0000855 1GJ 277.8 – 9.478 0.95 950 26.25 0.018 0.022 1 therm 29.3071 0.1055 – 0.1 96.59 2.766 0.0019 0.0024 1 mn Btu 293.1 1.055 10 – 965.9 27.66 0.019 0.024 1 ft3 0.2997 0.0011 0.0102 0.001 – 0.0283 0.000019 0.000024 1 m3 10.58 0.0381 0.362 0.0362 35.3023 – 0.00072 0.00083 1 t LNG 15,000 52 520 52 48,690 1,379 – 1.2 1 t oe 11,700 42.2 400 40 39,220 1,110 0.77 – kWh kilowatt hour GJ gigajoule therm therm mn Btu million British thermal units ft3 cubic feet m3 cubic metres 1 t LNG 1 tonne Liquid Natural Gas 1 t oe 1 tonne oil equivalent 32 ENERGY PRI CE RI SK
    • CHAPTER 3 Energy Futures Contracts INTRODUCTION Futures markets have been used by traders in commodities for hundreds of years. Trading in rice futures was being conducted in Osaka, Japan as early as the 18th century. The New York Mercantile Exchange (NYMEX), the world’s largest regulated energy futures exchange, started life in 1872 as the Butter and Cheese Exchange of New York, before being renamed ten years later. Exchange-traded futures and options provide several important economic benefits, including the ability to shift or otherwise manage the price risk of cash and physical market positions. As open markets where large numbers of potential buyers and sellers compete for the best prices, futures markets like the TOCOM in Tokyo, SGX in Singapore, IPE in London, EEX in Germany, Nord Pool in Scandinavia, NYMEX in New York, and Intercontinental Exchange out of the USA, allow energy compa- nies to discover and establish competitive prices. Partly because these markets provide the opportunity for leveraged investments, they attract large pools of risk capital. As a result, futures markets are among the most liquid of all global financial markets, providing low transaction costs and ease of entry and exit. This, in turn, fosters their use by a wide range of businesses and investors who want to manage price risks. Today’s futures industry functions with a number of time-tested institu- tional arrangements, including clearing house guarantees and exchange self-regulation. KEY FACTS ABOUT FUTURES CONTRACTS A futures contract is a standardised agreement between two parties that: ■ Commits one party to sell and the other party to buy a stipulated quan- tity and grade of oil, gas, power, coal, or other specified item at a set price on or before a given date in the future. 33
    • ■ Requires the daily settlement of all gains and losses as long as the contract remains open. ■ For futures contracts remaining open until trading terminates, the expiry of the contract provides either for delivery of the underlying physical energy product or a final cash payment (cash settlement). Futures contracts have several key features: ■ The buyer of a futures contract, the ‘long’, agrees to receive delivery. ■ The seller of a futures contract, the ‘short’, agrees to make delivery. ■ The contracts are traded on regulated exchanges either by open outcry in specified trading areas (called pits or rings) or electronically via a computerised network. ■ Futures contracts are marked-to-market each day at their end-of-day settlement prices, and the resulting daily gains and losses are passed through to the gaining or losing futures accounts held by brokers for their customers. ■ Futures contracts can be terminated by an offsetting transaction (i.e. an equal and opposite transaction to the one that opened the position) executed at any time prior to the contract’s expiration. The vast majority of futures contracts are terminated by offset or a final cash payment rather than by delivery. For example, on the IPE and NYMEX less than 2% of the open interest (total contracts open) in their energy futures contracts go to physical delivery each month. A standardised energy futures contract always has the following specific items : ■ Underlying instrument: the energy commodity or price index upon which the contract is based. ■ Size: the amount of the underlying item covered by each contract. ■ Delivery cycle: the specified months for which contracts can be traded. ■ Expiration date: the date on which a particular futures trading month will cease to exist and therefore all obligations under it will terminate. 34 ENERGY PRI CE RI SK MAIN GLOBAL OIL, GAS, COAL AND POWER FUTURES EXCHANGES ■ IPE London: http://www.ipe.uk.com/ ■ EEX: http://www.eex.de/ ■ UKPX: http://www.ukpx.com/ ■ NYMEX New York: http://www.nymex.com/ ■ TOCOM Tokyo/SGX: http://www.tocom.or.jp/ ■ SGX Singapore: http://www.sgx.com/ ■ Nord Pool: http://www.nordpool.com/
    • ■ Grade or quality specification and delivery location: a detailed description of the energy commodity, or other item that is being traded and, as permitted by the contract, a specification of items of higher or lower quality or of alternate delivery locations available at a premium or discount (e.g. NYMEX WTI Crude futures contract allows traders to deliver alternative crudes and they have a table of premium and discounts that are fixed for those alternative crude oils). ■ Settlement mechanism: the terms of the physical delivery of the under- lying item or of a terminal cash payment. In fact, the only non-standard item of a futures contract is the price of an underlying unit, which is determined in the trading arena. The mechanics of futures trading are straightforward: both buyers and sellers deposit funds called initial margin (a sort of good faith deposit) with a brokerage firm who would be a clearing member of the exchange the futures contract it on. This initial margin amount is typically a small percentage – around 10% of the total notional contract value. If you buy (go long) a futures contract and the price goes up, you profit by the amount of the price increase multiplied by the contract size. On the other hand, if you buy and the price goes down, you lose an amount equal to the price decrease multiplied by the contract size. If you sell a futures contract (go short) and the price goes down, you profit by the amount of the price decrease multiplied by the contract size. If you sell and the price goes up, you lose an amount equal to the price increase multiplied by the contract size. These profits and losses are paid daily via the variation futures margin which a clearing broker must deposit with the clearing house every day on behalf of its customers. The broker either finances this for its customer or calls its customer for collateral against unrealised losses. Some futures exchanges have position limits dependent on whether you are a speculator, trader or hedger. Sometimes daily maximum price movements are also enforced. These usually only apply to USA-based exchanges contracts. For example, price limit and position limits do not apply to IPE oil futures contracts. During the Gulf War some participants found that NYMEX was forced to suspend trading, while the IPE carried on trading. These are points to consider when choosing futures contracts. FUTURES OPTIONS CONTRACTS An option is the right, but not the obligation, to buy or sell a specified number of underlying futures contracts or a specified amount of an energy commodity or index at an agreed price (based on the strike price of the option) on or before a given future date. FUTURES OPTIONS CONTRACTS 35
    • Options on futures are traded on the same exchanges that trade the underlying futures contracts and are standardised with respect to the quantity of the underlying futures contracts, expiration date, and strike price (the price at which the underlying futures contract can be bought or sold). There are two types of options – call options and put options. A call option on a futures contract gives the buyer the right, but not the obligation, to purchase the underlying contract at a specified price (the strike or exercise price) during the life of the option. A futures put option gives the buyer the right, but not the obligation, to sell the underlying contract at the strike or exercise price before the option expires. The cost of obtaining this right to buy or sell is known as the option’s ‘premium’. This is the price that is bid and offered in the exchange pit or via the exchange’s computerised trading system. As with futures, exchange-traded options positions can be closed out by offset – execution of a trade of equal size on the other side of the market from the transaction that originated the position. The major difference between futures and options arises from the different obligations of an option’s buyer and seller. A futures contract obliges both buyer and seller to perform the contract, either by an offset- ting transaction or by delivery, and both parties to a futures contract derive a profit or loss equal to the difference between the price when the contract was initiated and when it was terminated. In contrast, an option buyer is not obliged to fulfil the option contract. The option buyer’s loss is limited to the premium paid, but in order for the buyer to make a profit, the price must increase above (call option) or decrease below (put option) the option’s strike price by the amount of the premium paid. In turn, the option seller (writer or grantor), in exchange for the premium received, must fulfil the option contract if the buyer so chooses. This situation – the option’s exercise – takes place if the option has value (is ‘in the money’) before it expires. The price risk for the seller of an option can be unlimited (unless the risk is hedged with other options or futures positions) and this is why some companies to this day prohibit their traders from selling options. These companies may consider they do not have good enough controls or systems in place to monitor short sale option price risk exposure. HEDGING IN FUTURES MARKETS The purpose of a hedge is to avoid the risk of adverse market moves resulting in major losses. Because the physical cash markets and futures markets do not always have a perfect price correlation relationship, there is no such thing as a perfect hedge, so there is almost always some profit or loss (basis risk). 36 ENERGY PRI CE RI SK
    • In futures markets, hedging involves taking a futures position opposite to that of a cash market position. That is, a corn farming cooperative would sell corn futures against its crop, an importer of Japanese cars would buy yen futures against its yen liability, a precious metals merchant would purchase gold futures against a fixed-price gold sales contract and an energy producer or consumer might look at buying or selling energy futures against their price risk exposure in anticipation of a market price increase/decrease. Examples of the types of risk management activities that rely on the use of futures include: ■ Stabilising cash flows ■ Setting purchase or sale prices of commodities and securities ■ More closely matching balance sheet assets and liabilities ■ Reducing transaction costs ■ Decreasing costs of storage ■ Locking in ‘cost of carry’ forward profits, i.e. profitable situations where the market price structure is such that if you hold energy in storage from one month to another if you sell forward in the futures markets, you can lock in a profit by holding that inventory. ■ Minimise the capital needed to carry inventories and the size of security of supply inventories required, by locking in guaranteed physical delivery in the future. The clearing house guarantees performance of the contract. Figure 3.1 shows how the futures trading process works. Figures 3.2–3.4 show the structure of the oil, gas and power futures markets. With the prospect of a Pan-Asean natural gas pipeline interconnector grid, there should be some interesting opportunities over the next decade or so to see natural gas trading and indeed perhaps natural gas futures markets develop in Thailand, Malaysia, Singapore, Indonesia etc. Other physical forward contracts and OTC power markets around the world are noted in Chapter 4 on OTC derivatives markets available. EXCHANGE OF FUTURES FOR PHYSICALS (EFP) AND DELIVERIES VIA FUTURES MARKETS Two energy futures markets offer EFPs in the context of the following examples: the NYMEX market in New York and the IPE in London. Generally no more than 2% to 5% of all energy futures contracts ever go to physical delivery via the exchange. (IPE Brent is the only large energy futures contract that does not go to physical delivery on expiry; instead it goes to cash settlement.) EXCHANGE OF FUTURES FOR PHYSICALS (EFP) 37
    • 38 ENERGY PRI CE RI SK ClientB Wantstosell 1futurescontract ClientA Wantstobuy 1futurescontract Ordergivento broker Ordergivento broker FUTURESMARKET InternationalPetroleumExchange TokyoCommodityExchange SingaporeExchange NewYorkMercantileExchange Futuresbroker andclearingmember reporttracetoClientA Futuresbroker andclearingmember reporttracetoClientB Brokerexecutesbuy of1futurescontract (1lot)on thefuturesexchange Brokerexecutessale of1futurescontract (1lot)on thefuturesexchange ClientAClientB Centralclearing housee.g.London ClearingHouse Createsabuyandsell(longandshort) Contractforthefuturesbrokers whoareclearingmembers ClientAIsleftwith 1long(buying)futuresposition whichisheldinitsfuturesaccount atitsclearingbroker(FCM). TheFCMholdsthepositionattheclearinghouse. ClientBIsleftwith 1short(selling)futuresposition whichisheldinitsfuturesaccount atitsclearingbroker(FCM). TheFCMholdsthepositionattheclearinghouse. FIGURE3.1Thefuturestradingprocessillustrated.Source:EnergyCollegeLondon–http://www.energycollege.org/
    • Companies who do choose to deliver, however, have several options. They can choose standard delivery (as per the specification of the futures contracts laid down in the rule book of the futures exchange) or they can attempt to arrange an Alternative Delivery Procedure (ADP). This would normally happen if someone wishes to deliver some energy which is not in keeping with the specifications of the futures contract (so it cannot be delivered via the exchange/clearing house procedure) or two parties are stuck with a position and they just wish to negotiate directly with one another on some cash settlement. In ADP transactions, market partici- pants release both the Exchange and their clearing broker member from all liabilities related to the delivery negotiated between parties. Traders and hedgers can also execute an Exchange of Futures for Physicals (EFP). EFPs Companies using energy futures contracts for hedging purposes are often not interested in making or taking delivery at the specified locations. In many cases, they are not interested in being matched to a trading partner EXCHANGE OF FUTURES FOR PHYSICALS (EFP) 39 S UK East coast West coast U S A U S A EEC Russia MED NOR J AG AFR SGP A Oil futures contracts A AFR AG EEC J MED SGP Australia Africa Arab Gulf Europe Japan Mediterranean Singapore UK S USA NOR United Kingdom Scandinavia/Nordic markets United States of America North Asia (inc. China, Korea) FIGURE 3.2 Oil futures are traded on TOCOM Tokyo/SGX (http://www.tocom. or.jp/), IPE London (http://www.ipe.uk.com/), SGX Singapore (http://www. sgx.com/) and NYMEX (http://www.nymex.com/). The futures traded are IPE Brent Crude futures, IPE Gasoil futures, NYMEX WTI Crude Oil futures, NYMEX Heating Oil (like Gasoil) futures and NYMEX Gasoline futures
    • by the futures exchange. More often than not, a hedger using futures finds it more economical to make or take delivery of physical energy elsewhere, under terms that differ from those of the futures contract. An EFP provides the mechanism for such transactions and is usually the preferred method of delivery because it provides greater flexibility. EFPs allow companies to choose their trading partners, delivery site, the grade of product to be delivered, and the timing of delivery. The EFP mechanism allows buyers and sellers to execute their physical energy market transac- tion on the basis of negotiated price. However, the quantity of the cash commodity involved in an EFP must be approximately equal to the quan- tity specified by the number of futures contracts involved in the EFP. This is the main concern of futures exchanges, who will investigate from time to time to ensure that parties to EFPs are executing the equivalent volume of physical versus futures. After both parties to an EFP agree to such a transaction, the price at which the EFP is to be cleared is submitted to their futures broker who in turn submits it to the futures exchange which then registers the trade. The price of the futures position created by the EFP can be outside the daily 40 ENERGY PRI CE RI SK S UK East coast West coast U S A U S A EEC Russia MED NOR AG AFR SGP A Natural gas futures exchanges A AFR AG EEC J MED SGP Australia Africa Arab Gulf Europe Japan Mediterranean Singapore UK S USA NOR United Kingdom Scandinavia/Nordic markets United States of America North Asia (inc. China, Korea) J FIGURE 3.3 Gas futures are traded on NYMEX (http://www.nymex.com/) and IPE London (http://www.ipe.uk.com/). The futures traded are IPE National Balancing Point (price reference) United Kingdom Gas futures and NYMEX Henry Hub Natural Gas futures
    • trading range of that futures market. This is the nominal price of the EFP. The EFP parties can then effect the actual physical exchange at a price they negotiate between themselves. The practical mechanics of an EFP transaction EFPs can be effected between two futures market participants – a long and a short hedger – provided there is a physical market transaction between the parties. For example, a futures market long (a buyer) would take delivery of crude oil from a futures market short (the seller) with whom the EFP is conducted. In this transaction, the buyer’s hedge is liquidated, as is the seller’s, and the actual transfer of crude oil occurs between the parties not via the exchange. An EFP market is normally quoted amongst futures brokers, so this is the first point of call for any organisation looking to find some counterpart to an EFP transaction. Example: Using an EFP to initiate a position On 15 December, an oil refiner who wishes to protect a portion of his oil products inventory wishes to sell futures to protect against falling prices. EXCHANGE OF FUTURES FOR PHYSICALS (EFP) 41 S UK East coast West coast U S A U S A EEC Russia MED NOR AG AFR SGP A Power futures exchanges with liquidity A AFR AG EEC J MED SGP Australia Africa Arab Gulf Europe Japan Mediterranean Singapore UK S USA NOR United Kingdom Scandinavia/Nordic markets United States of America North Asia (inc. China, Korea) J FIGURE 3.4 Power futures are traded on Nord Pool (http://www.nordpool.com/) and EEX European Energy Exchange (http://www.eex.de/). Nord Pool trades futures and options in power for Norway, Sweden, Denmark, Finland; EEX trades futures for the German power market
    • At the same time, a Gasoil oil distributor is concerned about rising prices and looks to buy to protect his forward purchases. They agree to a price of Gasoil, net the basis, and register the EFP with the futures (IPE or NYMEX) exchange. Once registered, both parties will receive a futures positions at a price which reflects the exact basis between the futures contract chosen and the specific physical Gasoil price. On 14 January, the diesel refiner arranges with the distributor for the physical delivery of the fuel. At that time, the refiner and the distributor independently offset their futures positions on the exchange via their broker. In this case, the long (buyer) sells back its futures position into the exchange and the short (seller) hedgers buy back their short hedge from the exchange. They have ‘swapped’ futures obligations, thus terminating their contract obligations on the exchange and open interest in the relevant futures contract would therefore reduce. In other words, they have closed out their futures contracts before expiry – before they matured – in consideration of their exchange of physical market positions. The transaction occurs at the price, location, and time negotiated by the parties. Example: using an EFP transaction to liquidate (close out) a position On 15 December, a crude oil trading company wants to cover forward purchases of West African crude oil, so it buys 500 contracts of February IPE Brent futures (500,000 barrels) on the Exchange at a price of US$24 per barrel. At about the same time, a crude oil producer in Africa is seeking to protect the value of its forward floating price crude oil physical sale contracts. So it sells 500 contracts of the February IPE Brent Futures (500,000 barrels) at a price of US$24.15 (on a different day). On 12 January, the two companies agree to a cash deal for 500,000 barrels of Bonny Light crude oil, the equivalent of 500 IPE Brent Futures contracts. Since both companies have hedge positions already in their futures broker accounts, they agree to close out those hedge positions by use of an EFP. Since they can register the EFP with the Exchange at any price that they agree to, they agree to use a price that is equal to the exact basis of their delivery point and the price quoted on the Exchange. By using the EFP, the hedge was taken off using the exact basis. This avoided the possible market risk of covering the hedge in the open market at the Exchange where there is no guarantee as to the price at which the hedge would be liquidated. It also enabled the removal of timing risk as the hedge can be closed out/netted out simultaneously with the physical 42 ENERGY PRI CE RI SK
    • transaction being executed. Quite often, traders in crude oil markets are trading VLCC (Very Large Crude Carriers) which carry 2 million barrels or 2000 lots of either NYMEX WTI Futures or IPE Brent Futures. Trying to close this position out without adversely affecting the market price due to futures market liquidity issues would take many hours to conclude if it were not for the EFP mechanism. On average, the largest clips size the IPE Brent or NYMEX WTI Futures usually trade in is 100 lots or 100,000 barrels. EFPs can involve deliveries to points other than those specified in the underlying futures contracts, and/or different energy commodities, and/ or different delivery periods, while transaction prices can be negotiated between parties to the EFPs. These negotiated prices can reflect differen- tials based on quality, location and timing, including transportation and quality differentials between the two products and delivery points. The Exchange clearinghouse treats EFPs as trades for margining purposes. Once the EFP is effected, margin funds can be released on the business day following the posting of the EFP. In EFPs involving a futures market hedger and a physical product market participant that initially is not holding a futures position, the hedger’s margin funds are released on the business day following the EFP posting. The physical market participant then becomes responsible for maintaining the account established for margin funds until the hedge is liquidated or delivery of the contracts is made. The NYMEX Exchange requires written documentation on EFPs and provides standardised forms for this purpose. The IPE market in London does not require written documentation, but it still reserves the right to make enquiries at any time. Information to be supplied can include: ■ The fact that an EFP transaction is being effected. ■ A statement that the EFP has resulted in a change in ownership of a particular energy commodity. ■ The date the transaction occurred. ■ The type and quantity of the energy futures involved in the EFP transac- tion. ■ The price at which the futures transaction is to be cleared. ■ The names of the clearing broker members involved in the EFP. The buyer’s and seller’s clearing members must satisfy the Exchange that the transaction is a legitimate EFP. Evidence of a change in ownership of the cash commodity involved in the EFP (or a commitment for such a change), as well as payment received by the firm selling the product, must be made available to the Exchange and secured by the clearing broker members representing the parties to the EFP upon specific request from the Exchange. EXCHANGE OF FUTURES FOR PHYSICALS (EFP) 43
    • IPE (LONDON) BRENT CRUDE FUTURES CONTRACT – SPECIFICATION Date of launch 23 June 1988. Money settlement, no physical delivery. Trading hours Open 08:00; Close 09:45 (local time, electronic) Open 10:02; Close 19:30 (local time, open outcry) Unit of trading One or more lots of 1,000 net barrels (42,000 US gallons) of Brent crude oil. Specification Current pipeline export quality Brent blend as supplied at Sullom Voe. Quotation The contract price is in US dollars and cents per barrel. Minimum price fluctuation One cent per barrel, equivalent to a tick value of $10. Maximum daily price fluctuation There are no limits. Daily margin All open contracts are marked-to-market daily. Trading period Twelve consecutive months then quarterly out to a maximum 24 monthly and then half yearly out to a maximum 36 months. Position limits There are no limits to the size of position. IPE (LONDON) BRENT CRUDE OPTIONS CONTRACT – SPECIFICATION Date of launch 11 May 1989. Trading hours Open 10:02; Close 19:30 (local time) Unit of trading One IPE Brent Crude futures contract. Quotation The contract price is in US dollars and cents per barrel. 44 ENERGY PRI CE RI SK
    • Strike price increments Multiples of 50 cents per barrel. A minimum of five strike prices are listed for each contract month; one nearest to the previous business day’s official settlement price for that month, two (or more) above and two (or more) below that price. During any trading day the Exchange may add one or more strike prices nearest to the last price listed. Minimum price fluctuation One US cent per barrel. Maximum daily price fluctuation There are no limits. Daily margin All open contracts are marked-to-market daily. Option premium Due to futures style margining option premiums are not paid/received at the time of the transaction. Rather margins are paid/received every day according to the changing value of the option and the total value to be paid/received is only known when the position is closed (by an opposing sale/purchase, exercise or expiry). It is a fundamental prin- ciple of option trading that the buyer never pays more than the premium. Trading period The first six quoted months of the underlying IPE Brent Crude futures contract, with a new position being introduced immediately on expiry of the first option month, such that six months will always be quoted. Position limits There are no limits to the size of position. Cessation of trading Trading shall cease at the close of business on the third business day prior to cessation of trading in the underlying IPE Brent Crude futures contract. Exercise and automatic exercise IPE Brent Crude options can be exercised into Brent Crude futures contracts. IPE options contracts are of American-style exercise, allowing the buyer to exercise call and/or put options up to 1700 hours on any business day (except on expiry day) during the life of the contracts, by giving an exercise notice to LCH in respect of such options. On expiry day the buyer has up to one hour after the cessation of trading to exercise his options. At that time LCH will automatically I PE (LONDON) BRENT CRUDE OPTIONS CONTRACT 45
    • exercise all options that are in the money on behalf of the Member unless instructed otherwise by the Member. IPE (LONDON) GASOIL FUTURE CONTRACT – SPECIFICATION Date of launch 6 April 1981. Physical delivery on expiry settlement Trading hours Open 08:00; Close 09:00 (local time, electronic) Open 09:15; Close 17:27 (local time, open outcry). Scope Contracts are for the future delivery of Gasoil into barge or coaster or by in-tank or inter-tank transfer from Customs and Excise bonded storage installations or refineries in the Amsterdam, Rotterdam, Antwerp (ARA) area (including Vlissingen and Ghent) between the 16th and the last calendar day of the delivery month. Unit of trading One or more lots of 100 metric tonnes of Gasoil, with delivery by volume, namely 118.35 cubic metres per lot being the equivalent of 100 tonnes of Gasoil at a density of 0.845 kg/litre in vacuum at 15 °C. Specification Gasoil shall be delivered in bulk and free of all liens and claims, be of merchantable quality conforming to the quality specification. Origin Any origin, EU qualified. Quotation The contract price is in US dollars and cents per tonne (on an EU import duty paid basis). Minimum price fluctuation 25 cents per tonne, equivalent to a tick value of $25. Maximum daily price fluctuation There are no limits. Daily margin All open contracts are marked-to-market daily. Trading period Up to 12 consecutive months forward, then quarterly out to 24 months, then half-yearly out to 36 months. 46 ENERGY PRI CE RI SK
    • Position limits There are no limits to the size of position. IPE (LONDON) GASOIL OPTIONS CONTRACT – SPECIFICATION Date of launch 20 July 1987. Trading hours Open 09:15; Close 17:27 (local time) Unit of trading One IPE Gasoil futures contract Quotation The contract price is in US dollars and cents per tonne. Strike price increments Multiples of US$2.50 per tonne. A minimum of five strike prices are listed for each contract month; one nearest to the previous business day’s official settlement price for that month, two (or more) above and two (or more) below that price. During any trading day the Exchange may add one or more strike prices nearest to the last price listed. Minimum price fluctuation Five US cents per tonne. Maximum daily price fluctuation There are no limits. Daily margin All open contracts are marked-to-market daily. Option premium Due to futures style margining option premiums are not paid/received at the time of the transaction. Rather, margins are paid/received every day according to the changing value of the option and the total value to be paid/received is only known when the position is closed (by an opposing sale/purchase, exercise or expiry). It is a fundamental principle of option trading that the buyer never pays more than the premium. Trading period The first 11 quoted months of the underlying Gasoil futures contract, with a new position being introduced immediately on expiry of the first option month, such that 11 months will always be quoted. I PE (LONDON) GASOI L OPTIONS CONTRACT – SPECIFICATION 47
    • Position limits There are no limits to the size of position. Cessation of trading Trading shall cease at close of business on the fifth business day prior to cessation of trading in the underlying IPE Gasoil futures contract. Exercise and automatic exercise IPE Gasoil options can be exercised into Gasoil futures contracts. IPE options contracts for American-style exercise, allowing the buyer to exercise call and/or put options up to 17:00 hours on any business day (except on expiry day) during the life of the contracts, by giving an exer- cise notice to LCH in respect of such options. On expiry day the buyer has up to one hour after the cessation of trading to exercise his options. At that time LCH will automatically exer- cise all options that are in the money on behalf of the Member unless instructed otherwise by the Member. IPE NATURAL GAS FUTURES CONTRACT – SPECIFICATION Date of launch 31 January 1997 Trading hours 09:30 to 17:00 UK time, except Daily contracts (09:30 to 16:00, UK time) Trading mechanism Electronic, Energy Trading System (ETSII). Also by Exchange of Futures for Physicals (EFPs). Unit of trading 1 lot equals 1,000 therms of natural gas per day of contract duration (1 therm = 29.3071 kilowatt hours). Contract size Minimum of 5 lots of 1,000 therms per lot (example: 5 lots September = 5 × 1000 therms × 30 days = 150,000 therms). Quotation Sterling, pence per therm. Minimum price movement (‘tick size’) 0.01 pence per therm. Maximum daily price fluctuation No limit. 48 ENERGY PRI CE RI SK
    • Contract description Season contracts are strips of six individual and consecutive contract months. Season contracts are always an (April–September) strip or (October–March strip). Quarter contracts are strips of three individual and consecutive contract months. Quarter contracts always comprise a strip of (Jan–Feb–Mar) or (Apr–May–Jun) or (Jul–Aug–Sep) or (Oct–Nov–Dec). Month contracts are strips made up of individual and consecutive calendar days. A monthly contract is 28, 29, 30 or 31 individual day contracts, determined by the precise number of calendar days in the month. Month contracts are listed 9, 10 or 11 consecutive months into the future. Balance of the Month (BOM) contract is a strip of individual day contracts. The precise number of day contracts is determined by the number of days outstanding in the current calendar month. The BOM contract reduces in size on a daily basis, generating a daily delivery obligation. Day contracts are listed from day ahead (D – 1) to seven days ahead (D – 7). A contract held through to expiry obligates the seller to make physical delivery. Delivery must be made equally throughout the delivery period and equivalent to the number of lots open at the time of expiry. Initial margin Initial margin is calculated on all open contracts and called by LCH from clearing members in order to cover the costs that may be incurred by LCH in closing the position of a member that goes into default. Initial margin is returned upon closure or at expiry of a position. Variation margin All open contracts are ‘marked-to-market’ at the end of each trading day. Variation margin is calculated on the number of lots open for each contract. This process uses the day to day change in settlement price for each contract. NYMEX WTI LIGHT, SWEET CRUDE OIL FUTURES Trading unit Futures: 1,000 US barrels (42,000 gallons). Options: One NYMEX WTI light, sweet crude oil futures contract. NY MEX WTI LIGHT, SWEET CRUDE OIL FUTURES 49
    • Trading hours Futures and options: Open outcry trading is conducted from 10:00 a.m. until 2:30 p.m. After hours futures trading is conducted via the NYMEX ACCESS® Internet-based trading platform beginning at 3:15 p.m. on Mondays through Thursdays and concluding at 9:00 a.m. the following day. On Sundays, the session begins at 7:00 p.m. All times are New York time. Trading months Futures: 30 consecutive months plus long-dated futures initially listed 36, 48, 60, 72, and 84 months prior to delivery. Additionally, trading can be executed at an average differential to the previous day’s settlement prices for periods of two to 30 consecutive months in a single transaction. These calendar strips are executed during open outcry trading hours. Options: Twelve consecutive months, plus three long-dated options at 18, 24, and 36 months out on a June/December cycle. Price quotation Futures and options: Dollars and cents per barrel. Minimum price fluctuation Futures and options: $0.01 (1¢) per barrel ($10.00 per contract). Maximum daily price fluctuation Futures: Initial limits of $3.00 per barrel are in place in all but the first two months and rise to $6.00 per barrel if the previous day’s settlement price in any back month is at the $3.00 limit. In the event of a $7.50 per barrel move in either of the first two contract months, limits on all months become $7.50 per barrel from the limit in place in the direction of the move following a one-hour trading halt. Options: No price limits. Last trading day Futures: Trading terminates at the close of business on the third busi- ness day prior to the 25th calendar day of the month preceding the delivery month. If the 25th calendar day of the month is a non-business day, trading shall cease on the third business day prior to the last busi- ness day preceding the 25th calendar day. Options: Trading ends three business days before the underlying futures contract. 50 ENERGY PRI CE RI SK
    • Exercise of options By a clearing member to the Exchange clearinghouse not later than 5:30 p.m., or 45 minutes after the underlying futures settlement price is posted, whichever is later, on any day up to and including the option’s expiration. Options strike prices Twenty strike prices in increments of $0.50 (50¢) per barrel above and below the at-the-money strike price, and the next ten strike prices in increments of $2.50 above the highest and below the lowest existing strike prices for a total of at least 61 strike prices. The at-the-money strike price is nearest to the previous day’s close of the underlying futures contract. Strike price boundaries are adjusted according to the futures price movements. Delivery F.O.B. seller’s facility, Cushing, Oklahoma, at any pipeline or storage facility with pipeline access to TEPPCO, Cushing storage, or Equilon Pipeline Co., by in-tank transfer, in-line transfer, book-out, or inter- facility transfer (pumpover). Delivery period All deliveries are rateable over the course of the month and must be initiated on or after the first calendar day and completed by the last calendar day of the delivery month. Alternate Delivery Procedure (ADP) An alternate delivery procedure is available to buyers and sellers who have been matched by the Exchange subsequent to the termination of trading in the spot month contract. If buyer and seller agree to consum- mate delivery under terms different from those prescribed in the contract specifications, they may proceed on that basis after submitting a notice of their intention to the Exchange. Exchange of Futures for, or in connection with, Physicals (EFP) The commercial buyer or seller may exchange a futures position for a physical position of equal quantity by submitting a notice to the Exchange. EFPs may be used to either initiate or liquidate a futures position. Deliverable grades Specific domestic crudes with 0.42% sulfur by weight or less, not less than 37° API gravity nor more than 42° API gravity. The following domestic crude streams are deliverable: West Texas Intermediate, Low Sweet Mix, New Mexican Sweet, North Texas Sweet, Oklahoma Sweet, South Texas Sweet. NY MEX WTI LIGHT, SWEET CRUDE OIL FUTURES 51
    • Specific foreign crudes of not less than 34° API nor more than 42° API. The following foreign streams are deliverable: UK Brent and Forties, and Norwegian Oseberg Blend, for which the seller shall receive a 30¢- per-barrel discount below the final settlement price; Nigerian Bonny Light and Colombian Cusiana are delivered at 15-cent premiums; and Nigerian Qua Iboe is delivered at a 5-cent premium. Inspection Inspection shall be conducted in accordance with pipeline practices. A buyer or seller may appoint an inspector to inspect the quality of oil delivered. However, the buyer or seller who requests the inspection will bear its costs and will notify the other party of the transaction that the inspection will occur. Position limits 20,000 contracts for all months combined, but not to exceed 1,000 in the last three days of trading in the spot month or 10,000 in any one month. Margin requirements Margins are required for open futures or short options positions. The margin requirement for an options purchaser will never exceed the premium. WTI LIGHT, SWEET CRUDE OIL CALENDAR SPREAD OPTIONS In an effort to help market participants mitigate the considerable price risk that is often present between contract months of a futures contract, the New York Mercantile Exchange introduces calendar spread options on its light, sweet crude oil futures contract. The contract is simply an options contract on the price differential between two delivery dates for the same commodity. The price spread between contract months can be extremely volatile because the energy markets are more sensitive to weather and news than any other market. A widening of the month-to-month price relationships can expose market participants to severe price risk which could adversely affect the effective- ness of a hedge or the value of inventory. The calendar spread options can allow market participants who hedge their risk to also take advantage of favourable market moves. To put market relationships in perspective, one must keep in mind two terms which describe the price curve. When the price for a contract month nearer to the present time is higher than the price for a contract further into the future, the market is said to be in backwardation. Typically, this means that prices are high because supplies are tight; in this case, the 52 ENERGY PRI CE RI SK
    • strike price for a calendar spread options contract will be a positive number. Conversely, when the nearby price is less expensive than the farther-dated prices, the market is in contango. When the price curve is in contango, strike prices of calendar spread options contracts will be nega- tive. A negative price is not unusual in spread relationships. A commodity’s price curve is likely to change over time. Calendar spread options can be used to manage the exposure a business has to these changes. The risk manager for a crude oil producer will use futures contracts to hedge production. In contango markets, the producer, who is a seller of oil, would seek downside protection by buying puts; an oil buyer would purchase calls. A crude oil producer with excess storage capacity can make money when the price curve is in contango by purchasing the cheaper prompt month and selling the more expensive deferred contract month. When the markets are in backwardation, however, spare storage capacity is an asset that generates no cash flow. Selling put options on calendar spreads generates cash flow, and having the asset as a backstop enables the oil company to sell the put. Additionally, in a steeply backwardated market, it can be costly to buy back a hedge after it has appreciated in value on its way to becoming the prompt month. Buying calls on the calendar spread can reduce such costs, and can complement the short hedge by allowing for participation in the rising market. The calendar spread options contracts are similar in concept to the crack spread options contracts introduced in 1994. Light, sweet crude oil calendar spread options contracts will be available for any combination of the first four months, any pair of consecutive months during the 13 listed months; and the closest June/December, December/June, and December/ December spreads. At exercise, the buyer of a put options contract will receive a short posi- tion in the futures market for the closer month and a long position in the futures market for the farther-dated month. The buyer of a call options contract will receive a long position in the futures market for the closer month and a short position in the futures market for the farther-dated month. NYMEX HEATING OIL FUTURES Trading unit Futures: 42,000 US gallons (1,000 barrels). Options: One NYMEX Division heating oil futures contract. NYMEX HEATING OIL FUTURES 53
    • Trading hours Futures and options: Open outcry trading is conducted from 10:05 a.m. until 2:30 p.m. After hours futures trading is conducted via the NYMEX ACCESS® Internet-based trading platform beginning at 3:15 p.m. on Mondays through Thursdays and concluding at 9:00 a.m. the following day. On Sundays, the session begins at 7:00 p.m. All times are New York time. Trading months Futures: Trading is conducted in 18 consecutive months commencing with the next calendar month (for example, on January 2, 2002, trading occurs in all months from February 2002 through July 2003). Options: 18 consecutive months. Price quotation Futures and options: In dollars and cents per gallon: for example, $0. 7527 (75.27¢) per gallon. Minimum price fluctuation Futures and options: $0.0001 (0.01¢) per gallon ($4.20 per contract). Maximum daily price fluctuation Futures: Initial limits of $0.06 (6¢) per gallon are in place in all but the first two months and rise to $0.09 (9¢) per gallon if the previous day’s settlement price in any back month is at the $0.06 per gallon limit. In the event of a $0.20 (20¢) per gallon move in either of the first two contract months, limits on all months become $0.20 per gallon from the limit in place in the direction of the move following a one-hour trading halt. Options: No price limits. Last trading day Futures: Trading terminates at the close of business on the last business day of the month preceding the delivery month. Options: Trading ends three business days before the underlying futures contract. Exercise of options By a clearing member to the Exchange clearinghouse not later than 5:30 p.m., or 45 minutes after the underlying futures settlement price is posted, whichever is later, on any day up to and including the option’s expiration. Options strike prices Twenty strike prices in one-cent-per-gallon increments above and below the at-the-money strike price, and the next ten strike prices in 54 ENERGY PRI CE RI SK
    • five-cent increments above the highest and below the lowest existing strike prices for a total of at 61 strike prices. The at-the-money strike price is the nearest to the previous day’s close of the underlying futures contract. Strike price boundaries are adjusted according to the futures price movements. Delivery F.O.B. seller’s facility in New York Harbor, ex-shore. All duties, entitlements, taxes, fees, and other charges paid. Requirements for seller’s shore facility: capability to deliver into barges. Buyer may request delivery by truck, if available at the seller’s facility, and pays a surcharge for truck delivery. Delivery may also be completed by pipe- line, tanker, book transfer, or inter- or intra-facility transfer. Delivery must be made in accordance with applicable federal, state, and local licensing and tax laws. Delivery period Deliveries may only be initiated the day after the fifth business day and must be completed before the last business day of the delivery month. Alternate Delivery Procedure (ADP) An alternate delivery procedure is available to buyers and sellers who have been matched by the Exchange subsequent to the termination of trading in the spot month contract. If buyer and seller agree to consum- mate delivery under terms different from those prescribed in the contract specifications, they may proceed on that basis after submitting a notice of their intention to the Exchange. Exchange of Futures for, or in connection with, Physicals (EFP) The commercial buyer or seller may exchange a futures position for a physical position of equal quantity by submitting a notice to the Exchange. EFPs may be used to either initiate or liquidate a futures position. Grade and quality specifications Generally conforms to industry standards for fungible No. 2 heating oil. Inspection The buyer may request an inspection for grade and quality or quantity for all deliveries, but shall require a quantity inspection for a barge, tanker, or inter-facility transfer. If the buyer does not request a quantity inspection, the seller may request such inspection. The cost of the quan- tity inspection is shared equally by the buyer and seller. If the product meets grade and quality specifications, the cost of the quality inspection is shared jointly by the buyer and seller. If the product fails inspection, the cost is borne by the seller. NYMEX HEATING OIL FUTURES 55
    • Position limits 7,000 contracts for all months combined, but not to exceed 1,000 in the last three days of trading in the spot month or 5,000 in any one month. Margin requirements Margins are required for open futures or short options positions. The margin requirement for an options purchaser will never exceed the premium. NYMEX NEW YORK HARBOR UNLEADED GASOLINE FUTURES AND OPTIONS Trading unit Futures: 42,000 US gallons (1,000 barrels). Options: One NYMEX Division New York Harbor unleaded gasoline futures contract. Trading hours Futures and options: Open outcry trading is conducted from 10:05 a.m. until 2:30 p.m. After hours futures trading is conducted via the NYMEX ACCESS® Internet-based trading platform beginning at 3:15 p.m. on Mondays through Thursdays and concluding at 9:00 a.m. the following day. On Sundays, the session begins at 7:00 p.m. All times are New York time. Trading months Futures: Twelve consecutive months. Options: Twelve consecutive months. Price quotation Futures and options: In dollars and cents per gallon, for example, $0. 8522 (85.22¢) per gallon. Minimum price fluctuation Futures and options: $0.0001 (0.01¢) per gallon ($4.20 per contract). Maximum daily price fluctuation Futures: Initial limits of $0.06 (6¢) per gallon are in place in all but the first two months and rise to $0.09 (9¢) per gallon if the previous day’s settlement price in any back month is at the $0.06 per gallon limit. In the event of a $0.20 (20¢) per gallon move in either of the first two contract months, limits on all months become $0.20 per gallon from the limit in place in the direction of the move following a one-hour trading halt. Options: No price limits. 56 ENERGY PRI CE RI SK
    • Last trading day Futures: Trading terminates at the close of business on the last business day of the month preceding the delivery month. Options: Expiration occurs three business days before the underlying futures contract. Exercise of options By a clearing member to the Exchange clearinghouse not later than 5:30 p.m., or 45 minutes after the underlying futures settlement price is posted, whichever is later, on any day up to and including the option’s expiration. Options strike prices Twenty strike prices in one-cent-per-gallon increments above and below the at-the-money strike price, and ten strike prices in five-cent increments above the highest and below the lowest existing strike prices for a total of at least 61 strike prices. The at-the-money strike price is the nearest to the previous day’s close of the underlying futures contract. Strike price boundaries are adjusted according to the futures price movements. Delivery F.O.B. seller’s facility in New York Harbor ex-shore. All duties, entitlements, taxes, fees, and other charges paid. Requirements for seller’s shore facility: capability to deliver into barges. Delivery may also be completed by pipeline, tanker, book transfer, or inter- or intra-facility transfer. Delivery must be made in accordance with applicable federal, state, and local licensing and tax laws. Delivery period Deliveries may only be initiated the day after the fifth business day and must be completed before the last business day of the delivery month. Alternate Delivery Procedure (ADP) An alternate delivery procedure is available to buyers and sellers who have been matched by the Exchange subsequent to the termination of trading in the spot month contract. If buyer and seller agree to consum- mate delivery under terms different from those prescribed in the contract specifications, they may proceed on that basis after submitting a notice of their intention to the Exchange. Exchange of Futures for, or in connection with, Physicals (EFP) The commercial buyer or seller may exchange a futures position for a physical position of equal quantity by submitting a notice to the Exchange. EFPs may be used to either initiate or liquidate a futures position. NY MEX NEW YORK HARBOR UNLEADED GASOLINE 57
    • Position limits Any one month/all months: 7,000 net futures, but not to exceed 1,000 in the last three days of trading in the spot month. Grade and quality specifications Generally conforms to industry standards for Phase II Complex Model Reformulated Gasoline. NYMEX HENRY HUB NATURAL GAS FUTURES AND OPTIONS Trading unit Futures: 10,000 million British thermal units (mmBtu). Options: One NYMEX Division natural gas futures contract. Trading hours Futures and options: Open outcry trading is conducted from 10:00 a.m. until 2:30 p.m. (natural gas futures and options will close at 2:45 p.m. on any futures termination day that falls on a Wednesday). After hours futures trading is conducted via the NYMEX ACCESS® internet-based trading platform beginning at 3:15 p.m. on Mondays 58 ENERGY PRI CE RI SK Oxygen 1.7% min by weight Benzene 1.3% max by volume Month RVP VOC reduction January 15 max n/a February 15 max n/a March 13.5 max n/a April n/a 23.4 min May n/a 23.4 min June n/a 23.4 min July n/a 23.4 min August n/a 23.4 min 1–15 September n/a 23.4 min 16–30 September 13.5 max n/a October 13.5 max n/a November 15 max n/a December 15 max n/a TABLE 3.1 New York Harbor unleaded gasoline specifications: Phase II Complex Model 2000
    • through Thursdays and concluding at 9:00 a.m. the following day. On Sundays, the session begins at 7:00 p.m. All times are New York time. Trading months Futures: 72 consecutive months commencing with the next calendar month (for example, on 2 January 2002 trading occurs in all months from February 2002 through January 2008). Options: 12 consecutive months, plus contracts initially listed 15, 18, 21, 24, 27, 30, 33, 36, 39, 42, 45, 48, 51, 54, 57, 60, 63, 66, 69, and 72 months out on a March, June, September, December cycle. Price quotation Futures and options: Dollars and cents per mmBtu, for example, $2.850 per mmBtu. Minimum price fluctuation Futures and options: $0.001 (0.1 ¢) per mmBtu ($10.00 per contract). Maximum daily price fluctuation Futures: $1.00 per mmBtu ($10,000 per contract) for all months. If any contract is traded, bid, or offered at the limit for five minutes, trading is halted for 15 minutes. When trading resumes, expanded limits are in place that allow the price to fluctuate by $2.00 in either direction of the previous day’s settlement price. There are no price limits on any month during the last three days of trading in the spot month. Options: No price limits. Last trading day Futures: Trading terminates three business days prior to the first calendar day of the delivery month. Options: Trading terminates at the close of business on the business day immediately preceding the expiration of the underlying futures contract. Exercise of options By a clearing member to the Exchange clearinghouse not later than 5:30 p.m. or 45 minutes after the underlying futures settlement price is posted, whichever is later, on any day up to and including the options expiration. Option strike prices Twenty strike prices in increments of $0.05 (5¢) per mmBtu above and below the at-the-money strike price in all months, plus an additional 20 strike prices in increments of $0.05 per mmBtu above the at-the-money price will be offered in the first three nearby months, and the next 10 strike prices in increments of $0.25 (25¢) per mmBtu above the highest NY M EX HENRY HUB NATURAL GAS FUTURES AND OPTIONS 59
    • and below the lowest existing strike prices in all months for a total of at least 81 strike prices in the first three nearby months and a total of at least 61 strike prices for four months and beyond. The at-the-money strike price is nearest to the previous day’s close of the underlying futures contract. Strike price boundaries are adjusted according to futures price movements. Delivery location Sabine Pipe Line Co.’s Henry Hub in Louisiana. Seller is responsible for the movement of the gas through the Hub; the buyer, from the Hub. The Hub fee will be paid by seller. Delivery period Delivery shall take place no earlier than the first calendar day of the delivery month and shall be completed no later than the last calendar day of the delivery month. All deliveries shall be made at as uniform as possible an hourly and daily rate of flow over the course of the delivery month. Alternate Delivery Procedure (ADP) An alternate delivery procedure is available to buyers and sellers who have been matched by the Exchange subsequent to the termination of trading in the spot month contract. If buyer and seller agree to consum- mate delivery under terms different from those prescribed in the contract specifications, they may proceed on that basis after submitting a notice of their intention to the Exchange. Exchange of Futures for, or in connection with, Physicals (EFP) or Swaps (EFS) The commercial buyer or seller may exchange a futures position for a physical position or a swaps position of equal quantity by submitting a notice to the Exchange. EFPs and EFSs may be used to either initiate or liquidate a futures position. Quality specifications Pipeline specifications in effect at time of delivery. Position limits 7,000 contracts for all months combined, but not to exceed 1,000 in the last three days of trading in the spot month or 5,000 in any one month. TOCOM TOKYO COMMODITY EXCHANGE MIDDLE EAST CRUDE OIL FUTURES CONTRACT TOCOM fixes the commission rates. Date of listing: 10 September 2001 60 ENERGY PRI CE RI SK
    • Type of crude oil Middle East crude oil (the average value of Dubai and Oman which acts as the benchmark price of Middle East crude oil.) Contract unit 100 kl Trading method Computerised continuous trading. Price quotation Japanese yen per kiloliter. Minimum price fluctuation ¥10 per 1 kiloliter Daily price fluctuation Limit standard price (*Note 1) Price limit Less than ¥6,000 ¥300 per kl ¥6,000 to less than ¥12,000 ¥500 per kl ¥12,000 to less than ¥18,000 ¥700 per kl ¥18,000 and over ¥900 per kl The Exchange may change the amount of the price limit at its discretion, according to the market situation. Customer Position Limit (long position and short position each) Current contract month: 40 contracts: on and after the 10th of each month (or the first business day thereafter if the 10th falls on a weekend/ holiday) 80 contracts: from the first business day to the 9th of each month 2nd contract month: 160 contracts, 3rd contract month: 400 contracts Other contract months: 800 contracts each month; total: 2,400 contracts Initial customer margin Standard price (*Note 2) Margin Less than ¥6,000 ¥45,000 per contract ¥6,000 to less than ¥12,000 ¥75,000 per contract ¥12,000 to less than ¥18,000 ¥105,000 per contract ¥18,000 and over ¥135,000 per contract The above margins are minimum amounts determined by the Minister of Economy, Trade and Industry. The Exchange is entitled to set greater amounts. TOCOM MIDDLE EAST CRUDE OIL 61
    • Customer Trading Commission to Futures Clearing Merchants (*Note 3) ¥3,800 Trading hours 9:00 a.m. to 11:00 a.m., 12:30 p.m. to 3:30 p.m. Contract months Six consecutive months from the current contract month Last trading day Jan–Nov: the third business day prior to the last business day Dec: the third business day prior to either the 24th or the business day immediately preceding the 24th if it falls on weekend/holiday On the last trading day, those who hold positions in the current contract month must liquidate all of their positions by placing market orders at the opening of the market. No new position is allowed to be established on the last trading day. Delivery Cash settlement (no delivery) Final settlement price Yen-based average value of Dubai and Oman calculated by the Exchange based on the prices reported by Reuters, Bloomberg, Petro- leum Argus, ICIS-LOR, Rim Intelligence and Telerate. Notes: 1. An average of the closing prices on the preceding business day for all contract months except the current contract month. 2. A monthly average of closing prices for all contract months except the last three business days in the previous month. 3-1 The above commission rate is charged per side per contract, except in the case of a day trade, where the above rate is charged as roundturn fee. 3-2 Commissions are negotiable (1) between originating and clearing FCMs of an omnibus account; (2) between an FCM and a customer where orders are transmitted electronically and the registration for the exemption from fixed-commission rate is made to the Exchange by the FCM; or (3) for customers who market, produce or process phys- ical commodities (i.e. commercials). 3-3 Volume discount When the volume of customer’s executed contracts exceeds 1,000 contracts per trade or delivery, commission to FCMs on the exceeded 62 ENERGY PRI CE RI SK
    • amount is discounted by 30%. Day trade, omnibus positions, fund positions and positions established by commercials are not applicable. TOCOM also lists a futures contract for Kerosene and Gasoline which can be utilised to hedge the domestic Japanese market. It should be noted that at the time of publishing of this book, the general understanding is that the majority of the volume traded in these contracts, including the Crude Oil contract, is speculative volume from retail investors. This may effect the correlation of the futures contracts with the underlying physical markets. More physical traders/hedgers are expected to enter the crude oil market as a result of the SGX Singapore Exchange listing, towards the end of 2002, the TOCOM Crude contract, but in US$ and in barrels. OTC swaps partici- pants and traders may find interesting arbitrage opportunities between the TOCOM contract in Tokyo in yen/kilolitre, the SGX contract in US$ and Barrels and also the OTC Swaps markets in Dubai and Oman crudes. TOCOM FUTURES CONTRACT SPECIFICATIONS – KEROSENE Date of listing: 5 July 1999 Standard Kerosene of JIS K2203 Grade 1 Contract unit 100 kl Delivery unit 100 kl Trading method Computerised continuous trading Price quotation Japanese yen per kiloliter Minimum price fluctuation ¥10 per 1 kiloliter Daily price fluctuation limit Standard price (*Note 1) Price limit Less than ¥17,000 ¥400 per kl ¥17,000 to less than ¥24,000 ¥500 per kl ¥24,000 to less than ¥31,000 ¥600 per kl ¥31,000 and over ¥700 per kl TOCOM FUTURES CONTRACT SPECIFICATIONS – KEROSENE 63
    • The Exchange may change the amount of the price limit at its discretion, according to the market situation. Customer position limit (long position and short position each) Current contract month: 70 contracts 2nd contract month: 200 contracts 3rd contract month: 600 contracts Other contract months: 1,200 contracts each month Total: 4,000 contracts Initial customer margin Standard price (*Note 2) Margin Less than ¥17,000 ¥60,000 per contract ¥17,000 to less than ¥24,000 ¥75,000 per contract ¥24,000 to less than ¥31,000 ¥90,000 per contract ¥31,000 and over ¥105,000 per contract The above margins are minimum amounts determined by the Minister of Economy, Trade and Industry. Commission to FCMs (*Note 3) (per contract) ¥3,800. Delivery commission to FCMs (*Note 3) The same as above. Trading hours 9:00 a.m. to 11:00 a.m., 12:30 p.m. to 3:30 p.m. Contract months Six consecutive months from the current contract month. Last trading day The 20th of the month preceding the delivery month (if the day is a holiday, last trading day is advanced.) Delivery period Throughout the delivery month. Delivery points Refineries and oil tanks located in Tokyo, Kanagawa and Chiba, provided with both barge and lorry delivery facilities, and appointed by the Board. (In case of delivery into lorry, buyers are obliged to pay the surcharge decided by the Board.) Delivery Physical delivery (not cash settlement). 64 ENERGY PRI CE RI SK
    • Deliverable commodities Kerosene of JIS K2203 Grade 1, which is refined within Japan or cleared through the customs. Contract price and tax The contract price shall be inclusive of the cost of delivery into barge in refineries or oil tanks located in Tokyo Bay area but exclusive of consumption tax. Delivery method 1. Option of delivery points: Seller 2. Delivery method: Delivery into barge or lorry 3. Option of delivery method: Buyer 4. Option of delivery day: Buyer in principle 5. Matching of Buyer and Seller: Determined by drawing lots, except when parties to deliver find their counterparts by themselves during the period from Last Trading Day to Lottery Day. 6. Divided delivery: Delivery can be divided Quantity tolerance on delivery ±2% of the volume per delivery Notes 1. An average of the closing prices on the preceding business day for all contract months except the current contract month. 2. A monthly average of closing prices for all contract months except the last three business days in the previous month. 3-1 The above commission rate is charged per side per contract, except in the case of a day trade, where the above rate is charged as roundturn fee. 3-2 Commissions are negotiable (1) between originating and clearing FCMs of an omnibus account; (2) between an FCM and a customer where orders are transmitted electronically and the registration for the exemption from fixed-commission rate is made to the Exchange by the FCM; or (3) for customers who market, produce or process phys- ical commodities (i.e. commercials). 3-3 Volume discount When the volume of customer’s executed contracts exceeds 1,000 contracts per trade or delivery, commission to Futures Clearing Merchants on the exceeded amount is discounted by 30%. Day trade, omnibus positions, fund positions and positions established by commercials are not applicable. TOCOM FUTURES CONTRACT SPECIFICATIONS – KEROSENE 65
    • TOCOM FUTURES CONTRACT SPECIFICATIONS – GASOLINE Date of listing: 5 July 1999 Standard Regular gasoline of JIS K2202 Grade 2 Contract unit 100 kl Delivery unit 100 kl Trading method Computerised continuous trading Price quotation Japanese yen per kiloliter Minimum price fluctuation ¥10 per 1 kiloliter Daily price fluctuation limit Standard price (*Note 1) Price limit Less than ¥17,000 ¥400 per kl ¥17,000 to less than ¥22,000 ¥500 per kl ¥22,000 to less than ¥27,000 ¥600 per kl ¥27,000 and over ¥700 per kl The Exchange may change the amount of the price limit at its discretion, according to the market situation. Customer position limit (long position and short position each) Current contract month: 100 contracts 2nd contract month: 200 contracts 3rd contract month: 600 contracts Other contract months: 1,200 contracts each month Total: 4,000 contracts Initial customer margin Standard price (*Note 2) Margin Less than ¥17,000 ¥60,000 per contract ¥17,000 to less than ¥22,000 ¥75,000 per contract ¥22,000 to less than ¥27,000 ¥90,000 per contract ¥27,000 and over ¥105,000 per contract 66 ENERGY PRI CE RI SK
    • The above margins are minimum amounts determined by the Minister of Economy, Trade and Industry. The Exchange is entitled to set greater amounts. Customer trading commission to FCMs (*Note 3) (per contract) ¥3,800. Customer delivery commission to FCMs (*Note 3) The same as above. Trading hours 9:00 a.m. to 11:00 a.m., 12:30 p.m. to 3:30 p.m. Contract months Six consecutive months from the current contract month. Last trading day The 20th of the month preceding the delivery month (if the day is a holiday, last trading day is advanced). Delivery period Throughout the delivery month. Delivery points. Refineries and oil tanks located in Tokyo, Kanagawa and Chiba, provided with both barge and lorry delivery facilities, and appointed by the Board. (In case of delivery into lorry, buyers are obliged to pay the surcharge decided by the Board.) Delivery Physical delivery (not cash settlement). Deliverable commodities 1. Deliverable commodities: Regular gasoline of JIS K2202 Grade 2, which is refined within Japan or cleared through the customs. 2. Gasoline tax: Contract price does not include gasoline tax; buyers must pay the sellers the amount equivalent to the gasoline tax when taking delivery. Contract price and tax The contract price shall be inclusive of the cost of delivery into barge in refineries or oil tanks located in Tokyo Bay area but exclusive of gasoline tax and consumption tax. Delivery method 1. Option of delivery points: Seller 2. Delivery method: Delivery into barge or lorry 3. Option of delivery method: Buyer 4. Option of delivery day: Buyer in principle TOCOM FUTURES CONTRACT SPECIFICATIONS – GASOLINE 67
    • 5. Matching of Buyer and Seller: Determined by drawing lots, except when parties to deliver find their counterparts by themselves during the period from Last Trading Day to Lottery Day. 6. Divided delivery: Delivery can be divided Quantity tolerance on delivery ±2% of the volume per delivery. Notes 1. An average of the closing prices on the preceding business day for all contract months except the nearest contract month. 2. A monthly average of closing prices for all contract months except the last three business days in the previous month. 3-1 The above commission rate is charged per side per contract, except in the case of a day trade, where the above rate is charged as roundturn fee. 3-2 Commissions are negotiable (1) between originating and clearing FCMs of an omnibus account; (2) between an FCM and a customer where orders are transmitted electronically and the registration for the exemption from fixed-commission rate is made to the Exchange by the FCM; or (3) for customers who market, produce or process phys- ical commodities (i.e. commercials). 3-3 Volume discount When the volume of customer’s executed contracts exceeds 1,000 contracts per trade or delivery, commission to FCMs on the exceeded amount is discounted by 30%. Day trade, omnibus positions, fund positions and positions established by commercials are not applicable. COAL FUTURES The USA has more high-quality coal than any other country, with nearly 30% of the world’s bituminous and anthracite coal reserves. Only China produces more bituminous coal than the USA, but almost all of its produc- tion is consumed domestically. US coal exports, chiefly central Appala- chian bituminous, make up 16% of the world export market and are an important factor in world coal prices. At current rates of recovery and use, it is estimated that US coal reserves will last more than 250 years. The importance of coal can be seen from the fact that coal-fired power stations still account for approximately 55% of total electricity output in the USA. Because coal is a bulk commodity, transportation is an important aspect of its price and availability. Railroads carry more than half of the coal mined in the USA, often hauling the coal in unit trains. Unit trains with several locomotives pulling anywhere from 60 to 120 cars loaded solely with coal are a common sight in both Appalachia and the western USA. 68 ENERGY PRI CE RI SK
    • The inland waterway system is the other major mode for coal transporta- tion, especially along the Ohio and Mississippi Rivers. The impact on the environment of coal use is a serious issue. Any effort to curtail atmospheric emissions can be expected to involve reduced coal use, even though the amount of air pollution produced by coal burning has been greatly diminished during he past 30 years. For example, the volume of coal used by electric utilities leapt from 320 million tons in 1970 to nearly a billion tons in the late 1990s, an increase of more than 200%, yet sulphur dioxide emissions from coal-fired plants declined 27%. Coal prices are still mainly traded in the OTC market. However, for both the US coal mining and electric power industries, NYMEX Coal Futures provide a range of ways to mitigate risk. For the international coal trading or consuming market, it can also offer another tool for price monitoring and price risk mitigation perhaps on an arbitrage basis with European or other regional OTC hedging markets. (e.g. United Kingdom-based OTC swaps on coal grade API2). Coal producers can sell futures contracts to lock in a specific sales price for a specific volume of the coal they intend to produce in coming months. Electric utilities can buy coal futures to hedge against rising prices for their baseload fuel. Power marketers, who have exposure on both the gener- ating and delivery sides of the electricity market, can hedge with coal futures to mitigate their generation price risk, and hedge with electricity futures to control their delivery price risk. Non-utility industrial coal users, such as steel mills, can use futures to lock in their own coal supply costs. International coal trading companies can use futures to hedge their export or import prices. Power generating companies that use both coal and natural gas to produce electricity can use coal futures in conjunction with the NYMEX Henry Hub natural gas futures to offset seasonal cost variations and to take advantage of the ‘spark spread’ – the differential between the cost of the two fuels and the relative value of the electricity generated by each of the two fuels. Useful physical coal market price information and analysis can be obtained from Argus (http://www.argusonline.com/). CENTRAL APPALACHIAN COAL FUTURES Trading unit 1,550 tons of coal. Trading hours Open outcry trading is conducted from 10:30 a.m. until 2:00 p.m. All times are New York time. CENTRAL APPALACHIAN COAL FUTURES 69
    • Trading months 24 to 26 consecutive months based on a quarterly schedule. As contracts expire, the 26th month will roll forward until it becomes the 23rd month. At that point, new 24th, 25th, and 26th month contracts will be added. Price quotations US dollars and cents per ton. Minimum price fluctuation $0.01 per ton ($15.50 per contract). Maximum price fluctuation $12.00 per ton ($18,600 per contract) for all months. If any contract is traded, bid, or offered at the limit for five minutes, trading is halted for 10 minutes. When trading resumes, expanded limits are in place that allow the price to fluctuate by $24.00 in either direction of the previous day’s settlement price. There are no price limits on any month during the last three days of trading in the spot month. Last trading day Trading terminates on the fourth to last business day of the month prior to the delivery month. Contract delivery unit The seller shall deliver 1,550 tons of coal per contract. A loading toler- ance of 60 tons or 2%, whichever is greater, over the total number of contracts delivered is permitted. Delivery location Delivery shall be made F.O.B. buyer’s barge at seller’s delivery facility on the Ohio River between Mileposts 306 and 317, or on the Big Sandy River, with all duties, entitlements, taxes, fees and other charges imposed prior to delivery paid by the seller. There will be a discount of $0.10 per ton below the final settlement price for any delivery to a terminal on the Big Sandy River. Heat content Minimum of 12,000 Btus per pound, gross calorific value, with an anal- ysis tolerance of 250 Btus per pound below. Ash content Maximum of 13.50% by weight with no analysis tolerance. Sulfur content Maximum of 1.00%, with analysis tolerance of 0.050% above. Moisture content Maximum of 10.00%, with no analysis tolerance. 70 ENERGY PRI CE RI SK
    • Volatile matter Minimum of 30.00%, with no analysis tolerance. Hardness/grindability Minimum 41 Hardgrove Index with three point analysis tolerance below. Hardness measures how difficult it is to pulverize coal for injec- tion into the boiler flame. Size Three inches topsize, nominal, with a maximum of 55% passing one- quarter-inch-square wire cloth sieve or smaller, to be determined on the basis of the primary cutter of the mechanical sampling system. Exchange of Futures for, or in connection with, Physicals (EFP) The buyer or seller may exchange a futures position for a physical posi- tion of equal quantity/quality by submitting a notice to the Exchange. EFPs may be used either to initiate or liquidate a futures position. The EFP deadline is 10:00 a.m. (New York time) on the first business day following termination of trading. Position accountability level Any one month/all months: 5,000 net futures, but not to exceed 200 in the last three days of trading in the spot month. Trading symbol QL CENTRAL APPALACHIAN COAL FUTURES 71
    • CHAPTER 4 OTC Energy and Related Derivative Markets OTC ENERGY DERIVATIVE MARKETS Nearly all the key terms of an OTC derivatives deal are negotiable, which means that the pricing reference, the payment terms and the volume can all be adjusted to suit the counterparts to the deal. This is a benefit if an organisation has a very specialised or unique price risk which requires a one-off hedging tool. Basically, anything is possible in the OTC energy markets, although, of course, the price of the derivative instrument quoted to suit a customer’s precise and perhaps esoteric needs, may not always be attractive. Fortunately, for risk management purposes, the core energy markets, like the larger oil, gas and electricity (power) markets have some active and fairly standardised OTC contracts. They are stan- dard both in their floating price reference, and in the sort of minimum contract volume that would normally be traded. Indeed, the increasing standardisation in the plain vanilla OTC markets has led to the develop- ment of a number of electronic trading platforms. People often ask why regulated futures exchanges seem to be unable to launch new petroleum futures contracts. The answer is that the needs of the market are already being met by the now well-established and liquid OTC derivatives market. Another supporting factor of this observation is that futures exchanges have been successful in launching futures contracts in both the natural gas and power markets. The reason for this is that the regulated futures markets were launched soon after deregulation prior to or at the same time as an OTC market was establishing itself. The effectiveness of the OTC market can also be seen in Asia, which overtook Europe as the second largest oil consuming region in the world several years ago. Today, Asia includes the world’s second, third, seventh, eighth and ninth largest importers of oil: Japan, Korea, India, China and Taiwan. However, Asia still does not have a liquid and internationally 72
    • recognised futures exchange for energy market. This is because its needs for energy-related derivatives contracts seem to be well served by the established OTC market, for which Singapore is the key trading hub. There is only one bastion of support for the energy futures industry in Asia, which is the Tokyo Commodity Exchange or TOCOM. It is making great progress with its Middle East crude futures contract and product futures, but the range of market participants and liquidity is still a long way away from that seen on the IPE and the NYMEX. Singapore Exchange launched the TOCOM Middle East crude contract in Singapore but in US dollars and barrels instead of yen and kilolitres in Q4 2002, and it is still not clear whether this will be successful. Rather than trying to create a brand new contract, an interesting approach by SGX has been to create a forex hybrid of the TOCOM Middle East crude contract. Since traders should be able to offset margin calls between the SGX contract (in US$ per barrel) and the TOCOM contract (yen/kilolitres) either at the exchange/clearing house level or at their clearing broker level, there are interesting opportu- nities to trade the forex arbitrage between the two contracts, and also to trade the arbitrage between TOCOM and SGX contract with the OTC Dubai/Oman, WTI Crude Futures on NYMEX and/or Brent Futures on the IPE. Apparently, there is already some speculative trading between the TOCOM Middle East crude contract and the Dubai/Oman OTC swaps arbitrage and also against the WTI NYMEX Futures. THE OTC OIL DERIVATIVES MARKET The vast majority of physical transactions and OTC swaps are priced using an industry-recognised publication – Platts, which is a division of McGraw-Hill. Platts publishes a daily assessment of the price of any given crude oil or oil product in any given location, according to Platts’ own specifications, and also publishes an assessment of the forward curve. These daily value assessments are based on the aggregated bids and offers from many brokers and dealers around the world during a specified time window for each geographic region (usually towards the end of each busi- ness day in each major time zone: Asia (Singapore), Europe (London), USA (New York, and then the West Coast). Swaps are usually priced off the monthly average of these Platts assess- ments and lead to a monthly financial payment equivalent to the differ- ence between the traded fixed price and the calculated average floating price multiplied by the contractual monthly quantity. Only the difference is paid and there is no exchange of physical energy, hence no delivery risk. The main oil OTC trading/pricing hubs Figure 4.1 shows the main oil OTC trading/pricing hubs: THE OTC OIL DERIVATIVES MARKET 73
    • ■ ASIA: Singapore is the main pricing hub ■ EUROPE: Mediterranean prices, Arab Gulf Prices, North West Europe (N.W.E.) and Amsterdam–Rotterdam–Antwerp (A.R.A.) as the main pricing hubs. ■ USA: New York Harbor, US Gulf Coast, US West Coast (L.A. Pipeline) are some international reference points for oil markets. The one world energy derivatives market At the time of writing (September 2002), oil-related OTC derivatives (sometimes referred to as paper trading) were in a bull trend in terms of volume, number of participants and types of contracts traded. Many new entrants came into the market after the collapse of Enron, and producers and consumers have continued to feel the financial impact and advan- tages of greater price oil volatility since late 1998. With the daily physical consumption of crude oil already over 80 million barrels and annual trade valued at almost $1 trillion, the growth in paper energy trading seems assured, with new financial products evolving to meet the needs of producers, refiners, marketers and consumers. Such a large number of participants, spread so widely around the world has created a close to real-time ‘One world energy derivatives market’. Because of the close to real-time impact on the physical energy markets 74 ENERGY PRI CE RI SK S UK East coast West coast U S A U S A EEC Russia MED NOR AG AFR SGP A Key OTC oil pricing hubs A AFR AG EEC J MED SGP Australia Africa Arab Gulf Europe Japan Mediterranean Singapore UK S USA NOR United Kingdom Scandinavia/Nordic markets United States of America North Asia (inc. China, Korea) J FIGURE 4.1 The main oil OTC trading/pricing hubs
    • around the world, all energy companies now have to monitor the deriva- tives market prices, even if they are not using derivatives themselves. If they do not, they may well face situations where they will not have an explanation for their management or shareholders when big unexpected adverse price movements affect their organisation. OTC oil trading is not conducted on regulated, established financial exchanges such as NYMEX, IPE, TOCOM or SGX, and it is a market that is monitored but not regulated by government agencies. However, with the increasing level of convergence between OTC and futures, as seen in the clearing house initiatives to permit OTC derivatives to be cleared via existing futures clearing houses such as NYMEX (http://www.nymex.com/) or the London Clearing House (http://www.lch.com/), the core OTC energy deriv- atives are becoming more and more indistinguishable from futures trades. Monthly trading volume data for the OTC oil markets (2002) Singapore (Asia Oil Pricing Hub) The Singapore market is oriented to cargo size shipments, so individual transactions, sometimes referred to as ‘clips’, are quite large compared to an IPE Brent Futures contract which is a minimum trade of 1,000 barrels. Almost everything in the Singapore market is sold in 50,000 barrel clips and the typical cargo size is 150,000 barrels; High Sulfur Fuel Oil used for ships bunkering is the only exception. Both 180 CST (the main OTC Fuel Oil swap market) and 380 CST fuel oil is traded in 5,000 MT but it can also be traded in clips as small as 1,000 MT units. Although a user should expect to see a difference in price between the same fuel oil swap, the same tenure is quoted for 5,000 MT Clip volume and 1,000 MT Clip volume. This is because the market maker and the traders take a liquidity risk by quoting a swap for 1,000 MT because most people only trade in 5,000 MT. Traders may not be able to trade out of that risk or hedge that risk easily with other OTC market participants (unless they are able to build up 5,000 MT in his portfolio and then trade a 5,000 MT clip out in to the market). Singapore OTC swaps volumes (excluding options volumes) In Singapore, OTC swaps transactions were approximately 300,000,000 barrels per month on average for the months up to October 2002 according to a survey conducted by the Energy College, London (http://www. energycollege.org/). To put this into perspective in terms of growth, in 1998, the Singapore swaps market was estimated to be around 150,000,000 barrels per month. Key OTC swaps Singapore Figure 4.2 is an example of a typical quote sheet from an OTC broker in Singapore illustrating the key markets being traded in OTC oil deriva- tives. Figure 4.3 shows the breakdown of the markets. THE OTC OIL DERIVATIVES MARKET 75
    • 76 ENERGY PRI CE RI SKMarketReport(Crude,Products,Crack)AccessOct28.28-0.1116/08/200212:10Singaporetime CrudeSepSep/OctOctOct/NovNovNov/DecDecQ4,02Q4/Q1Q1,03Q1/Q2Q2,03 EFPBrent26.730.0026.730.2526.480.2526.23 IPEBrtSwap26.490.1426.350.2626.100.2625.8426.090.7725.320.6724.65 DubaiSwap25.380.2325.150.2324.920.2324.6924.920.7124.210.6423.57 TapisSwap27.090.4326.660.1426.520.1826.3426.500.5125.990.4625.53 Brent/DubSepOctNovDecQ4,02Q1,03Q2,03 EFS/Swap1.351.581.561.54WTI/BrentOct1.55 IPESwap/Swap1.111.201.181.151.171.111.08Nov1.28 AppiTapisvsSepOctNovDecQ4,02Q1,03Q2,03 EFSBrent0.36–0.070.040.11 BrentSwap0.600.300.420.500.410.670.88 DubaiSwap1.711.511.601.651.581.781.96 DatedBrtSepOctNovDecQ4,02Q1,03Q2,03 vsDubswap1.361.331.311.281.301.241.12 ProductsSepSep/OctOctOct/NovNovNov/DecDecQ4,02Q4/Q1Q1,03Q1/Q2Q2,03 Naphtha25.700.1525.550.1025.450.1025.3525.450.3025.150.2524.90 GasOil28.900.0528.850.0328.820.0228.8028.820.6028.220.4527.77 Kerosene29.75–0.4730.22–0.3030.52-0.3830.9030.550.2130.341.5228.82 Regrade0.85–0.521.37–0.331.70-0.402.101.72-0.402.121.071.05 Fuel(ton)######2.75######2.50######1.75########## CrackSpreadsvsDubaiSwapvsTapisSwap /BblSepOctNovDecQ4,02Q1,03SepOctNovDecQ4,02Q1,03 Naphtha0.320.400.530.660.530.94–1.39–1.11–1.07–0.98–1.05-0.84 GasOil3.523.703.904.113.904.011.822.202.312.472.322.23 Kerosene4.375.075.606.215.636.132.673.574.014.574.054.35 Fuel–1.15–1.34–1.50–1.54–1.46–1.94–2.85–2.85–3.09–3.18–3.04–3.72 FIGURE4.2TypicalquotesheetfromanOTCbrokerinSingapore.Source:GingaPetroleum(OTC Brokers)Singapore(http://www.ginga.com.sg/;Tel:+6562928484)
    • The pro-active OTC swaps broking community in Singapore (there are around 10 active OTC broking companies in Singapore) adds market liquidity by assisting price discovery in the market and by developing two-way markets for buyers and sellers of oil. Typically most Asian oil products and related crude oils can be traded up to 18 months forward, with most of the liquidity in 1 to 12 months forward markets. Beyond two years forward, the number of participants quoting prices become more limited (mainly to large bank traders and major international oil companies). European Oil OTC Market Volumes Figure 4.4 shows the volume of monthly swaps in metric tonnes estimated for the European market. The barrel equivalent is 600,000,000 (approx.) barrels of oil swaps traded per month in 2002 up to October 2002. THE OTC OIL DERIVATIVES MARKET 77 23% 16% 23% 30% 2% 6% AE F B C D A: Gasoil B: Kero Diff C: Fuel oil D: Dubai/Tapis E: Naphtha F: Open-Spec FIGURE 4.3 Estimated percentage breakdown for Singapore OTC swaps volume. Source: Energy College Ltd – London (http://www.energycollege.org/) 4% A B C D E F G H I J K 5% 5% 4% 8% 25% 3% 18% 23% 2% 3% A: IPE Brent Swaps B: Brent Diff Swaps C: 3.5% Barge Rotterdam D: N.W.E. Fob Cargoes E: Gasoil Arb SGP/IPE F: Gasoil V Brent G: Gasoline V Brent H: Med/N.W.E. Gasoil Cargoes V IPE Gso I: Jet Diffs J: Naphtha K: Naphtha Crack FIGURE 4.4 Percentage breakdown of European swaps. Source: Energy College Ltd – London (http://www.energycollege.org/)
    • THE KEY OIL AND GAS RELATED OTC SWAPS Asia Unless otherwise specified by traders or brokers, a quote on a Singapore- based swap will price against the mean average of Platts’ high/low assess- ment of the relevant Singapore physical market. Fixed for floating swaps, caps and collar options will normally be available certain markets. Generally speaking, the tenures versus liquidity available in these derivatives is something like: ■ Strong liquidity in 1 to 6 months forward ■ Good liquidity from 6 month to 12 month ■ Fair liquidity thereafter up to 24 months forward. Key products ■ Singapore Gasoil 0.5% ■ Singapore Jet Fuel-Kero ■ Regrade – the spread between Singapore Gasoil and Singapore Jet Fuel ■ 180 CST Fuel Oil ■ 380 CST Fuel Oil ■ Naphtha ■ Tapis Crude Oil – Malaysian exported crude oil ■ Dubai/Oman Crude Oil – Middle east marker crude, meaning many Asian refiners are buying crude oil as feedstocks for their refineries on a Dubai/Oman pricing basis Europe Unless otherwise specified by traders or brokers, a quote on a European- based swap will normally price against the mean average of Platts’ high/ low assessment of the relevant European physical market. Fixed for floating swaps and caps and collar options will normally be available in the following markets: ■ Premium Unleaded Barge FOB ARA ■ Premium Unleaded Crack Swap N.W.E. ■ Naphtha Crack N.W.E. ■ Gasoil Crack Swap N.W.E. ■ Gasoil 0.2% cargo CIF N.W.E. ■ Gasoil 0.2% Cargo FOB MED ■ LPG Propane CIF ARA Large ■ Brent/Dubai Swaps ■ WTI Crude Oil versus Brent Crude Swaps ■ Rotterdam Gasoil 0.2% sulphur barges ■ Jet Fuel, North West Europe (N.W.E.) Cargoes CIF basis ■ Jet Fuel, Rotterdam Barges FOB 78 ENERGY PRI CE RI SK
    • ■ Gasoil IPE futures look-alike swap ● Prices against the 1st line IPE Gasoil futures contract (except the last trading day when it rolls over to the next futures contract) ■ Fuel Oil 1% North West Europe (N.W.E.) Cargoes CIF basis ■ Fuel Oil 1% North West Europe (N.W.E.) Cargoes FOB basis ■ Fuel Oil 3.5% Rotterdam Barges FOB Basis ■ Fuel Oil Mediterranean 3.5% Cargoes FOB basis ■ Dated Brent related Swap (Dated Brent is spot North Sea Oil) ● Platts’ dated Brent spot market assessment now takes in to account Brent, Osenberg, and Forties crude oil trades, mainly due to industry concerns about the diminishing Brent crude oil production traded in the North Sea Physical oil market. ■ Brent IPE futures look-alike swap ● Prices against the 1st line IPE Gasoil futures contract (except the last trading day when it rolls over to the next futures contract) ■ Brent Bullet Swap ● Prices against the 1st line IPE Brent futures contract ■ Dubai Crude Oil Swap trade out of London (as well as Singapore) ■ EN590 grade Gasoil North West Europe (N.W.E.) Cargoes CIF basis ■ EN590 grade Gasoil Mediterranean (M.E.D.) Cargoes ■ Gasoline – Rotterdam Eurograde barges ■ Naphtha North West Europe (N.W.E.) CIF Cargo swap ■ European Natural Gas Firm Physical, Fixed Price ■ European Natural Gas Firm Physical, Fixed Price, Spread Zeebrugge versus NBP ■ UK National Balancing Point indexed OTC Swaps basis NBP97 contract ■ LPG Mid East/North Africa/Asia – Saudi CP Pricing used as Index for OTC Swaps ■ LPG other, which have a crude related pricing formula can be proxy hedged using crude oil swaps related to the LPG pricing. ■ LNG with Crude related pricing formula – proxy hedging in Crude futures/related OTC derivatives markets More exotic one-off derivative structures are normally available, given the higher number of participants in the European oil swaps market and the higher liquidity in the plain vanilla market. Generally speaking the tenures versus liquidity available in these deriv- atives is something like: ■ Strong liquidity in 1 to 6 months forward ■ Strong liquidity from 6 month to 12 month ■ Good liquidity thereafter up to 24 months forward ■ Fair liquidity thereafter up to 36 months forward ■ Quotes available up to 5 years forward THE KEY OIL AND GAS RELATED OTC SWAPS 79
    • ■ Quotes available from a limited number of financial institutions/oil majors for tenures up to 10 years (Longer for Crude Oil) For up to date volume data and contract information consult: http://www.platts.com/ http://www.carrfutures.com/ http://www.prebon.com/ http://www.theice.com/ http://www.tfsenergy.com/ http://www.tullett.com/ USA Unless otherwise specified by traders or brokers, a quote on a USA-based swap will normally price against the mean average of Platts’ high/low assess- ment of the relevant American physical market. Fixed for floating swaps and caps and collar options will normally be available in the following markets: ■ Nymex WTI related 1st line futures look-a-like swap ■ Nymex WTI related Bullet Swap ■ Nymex Heating Oil futures related Bullet Swap ■ Nymex Heating Oil futures related 1st line futures look-a-like swap ■ Nymex Gasoline futures related 1st line futures look-a-like swap ■ Nymex Gasoline related Bullet Swap ■ New York Harbor #2 Heating Oil Barges ■ 1% Fuel Oil New York Harbor C.I.F. Cargo basis ■ 3% US Gulf Coast Cargo ■ US Gulf Coast Gasoline 87 ■ New York Harbor Reformulated RFG Gasoline 87 Barges ■ New York Harbor Gasoline 87 Barges ■ Canadian Natural Gas Firm Physical, Fixed Price ■ Canadian Natural Gas Firm Physical, Canadian Gas Price Reporter ■ Natural Gas, Fixed for Float (Inside FERC) ■ Natural Gas, Fixed for Float (NGI) As in Europe, more exotic one-off derivative structures are normally available, given the higher number of participants in this oil swaps market and the high liquidity in the market. In the USA, the tenures versus liquidity available in these derivatives is something like: ■ Strong liquidity in 1 to 6 months forward ■ Strong liquidity from 6 month to 12 month ■ Very Good liquidity thereafter up to 24 months forward ■ Fair liquidity thereafter up to 36 months forward ■ Quotes available up to 5 years forward 80 ENERGY PRI CE RI SK
    • ■ Quotes available from a limited number of financial institutions/oil majors for tenures up to 10 years (Longer for Crude Oil like WTI crude) For up to date volume data and contract information, consult: http://www.platts.com/ http://www.carrfutures.com/ http://www.prebon.com/ http://www.theice.com/ http://www.natsource.com/ http://www.tullett.com/ http://www.nymex.com/ EUROPEAN POWER AND GAS MARKETS Figure 4.5 shows the five European energy hubs. EUROPEAN POWER AND GAS MARKETS 81 U S A U S A J SGP EEC A AFR AG MED NOR UK S England and Wales Scotland, Ireland Northern Germany, Poland, Scandinavia- Nordpool France, Germany, Benelux, Switzerland Northern Italy, Austria Southern Italy and Greece Spain & Portugal A B C D Power markets Gas trading hubs A: Zeebruge Bacton B: Emden C: Milan D: Baumgarten FIGURE 4.5 The European energy hubs
    • GLOBAL POWER MARKETS – WITH DEVELOPED OR DEVELOPING DERIVATIVES MARKETS Amsterdam (http://www.apx.nl/) ■ Day ahead power trading. ■ German power market ideas have failed. Leipzig/EEX (http://www.eex.de/) ■ Mixture of spot physical market and power futures contracts. ■ Deregulation began early compared to other European countries (in 1998). ■ Power trading in Germany is around six times actual German consump- tion. (A general rule is that a derivatives market needs to gain a critical mass of around six times underlying physical trading to be stable, so it looks like German OTC power trading is here to stay!) ■ Liquidity for the OTC market generally up to one year forward. Hanover Bank Clearing (http://www.clearing-bank.de/) ■ Physical and OTC clearing facility for German power. Powernext Paris (http://www.powernext.fr/) ■ Day ahead power trading. ■ French power supply market was opened to partial competition in February 2000. So far about 30% of the supply market is open to compe- tition. ■ In February 2003 the threshold for consumers opened for competition will become 9 GWh, opening up a total of 34% of the market. ■ Powernext to launch on-exchange trading on 26 November 2002. ■ Plans to develop OTC derivatives in 2003. ■ French power trading is a growing business. Austrian Power Exchange (http://www.exaa.at/) ■ A new exchange, so not much activity yet. ■ Just spot market for power at the moment. Warsaw Power Exchange (http://www.polpx.pl/) ■ Not much activity in 2002. ■ Day ahead physical power trading. 82 ENERGY PRI CE RI SK
    • ■ Limited futures market under development. Madrid – Spanish Power Market (http://www.spectrongroup.com/) ■ Physical system in Spain deregulated. ■ Spanish OTC power trading appears to have taken off from the first quarter of 2001. Industry estimates total volumes hit 7.9 TWh, compared with 4.3 TWh over the full year of 2000. Switzerland Power (http://www.spectrongroup.com/) ■ Swiss parliament approved the Swiss Electricity Market Law, the key to deregulation in December 2000. ■ Opening up of the market is expected to happen in 2003. ■ No power exchange in Switzerland yet. ■ OTC trading of power was estimated by industry sources at around 35 TWh in 2001. This works out at around 0.5 times total Swiss power consumption. Italy Power ■ The Italian power market was partially opened to competition in March 1999 by Decree 79/99, better known as the Bersani decree. ■ Around 2,000 large customers, accounting for 30% of Italian consump- tion, were freed to choose their suppliers from April 1999. On 1 January 2000, opening was extended to 35%. ■ A further opening on 1 January 2002 exposed 40% of the market to competition. A new law passed in March 2001 will open around 60% of the market 90 days after Enel has divested generation capacity totalling 15,000 MW. These divestments are required by the Bersani decree and must be completed by 1 January 2003. ■ In 2000 own use in the open market was 25.8 TWh, or 36% of the total open market. In fact, Enel has reported that its sales to eligible customers account for only 19% of its sales volumes at the current opening level. This exposure will rise to a still modest 25% in 2002. ■ There is no liquid forward OTC market yet. Nord Pool (http://www.nordpool.com/) ■ The most liquid trading market. ■ Covering Scandinavia. ■ OTC, Bi-Lateral, Cleared OTC, Physical forward UKPX (http://www.ukpx.com/) ■ The UK Power Exchange provides a market for trading in both spot and futures contracts in electricity. It also acts as a clearing house for OTC transactions. GLOBAL POWER MARKETS 83
    • ■ The England and Wales electricity market was a pioneer of power deregulation in 1990. ■ In June 1999 OM announced its intention to create Britain’s first inde- pendent power exchange. The UK Power Exchange (UKPX) utilises OM’s power market systems within its existing UK-based Recognised Investment Exchange, the OM London Exchange Ltd. The UK Power Exchange opened on 26 May 2000. ■ Liquid market. ■ The OTC and Exchange traded power volumes for 2001 were reported to be around three times greater than UK national consumption, with 2002 volumes growing at a high rate. US power markets (http://www.theice.com/) ■ USA market is very deregulated. ■ Power trading really took off with the advent of the Enron online system, now superseded by The Intercontinental Exchange (http:// www.theice.com/) ■ If you wish to trade OTC derivatives for trading or hedging purposes there is a vast and ever-changing array of products available. ■ The biggest issue in America has been problems surrounding the effec- tive physical distribution of power, with not enough power where it is most needed. On several occasions over the past five years or so this has created big price spikes which have damaged the energy trading community. ■ Liquidity in power trading is good. Singapore power market ■ Still early days in the development of the Singapore power market. ■ No derivatives market yet, but there is the prospect of a Pan-Asean derivatives market over the next eight years. ■ Most interesting prospect is for development of Asean interconnectors which might spur on the eventual development of a power trading grid from Thailand down through Malaysia, Singapore and Indonesia. ■ The Public Utilities Board (PUB) was formed in 1963, and is responsible for the supply of electricity, piped gas and water to the entire popula- tion of Singapore. The PUB was reorganised in October 1995 to continue supplying water, and to take on the new role of regulating the electricity and piped gas industries. ■ The vertically integrated electricity industry was restructured in 1995 to introduce competition in electricity generation and supply. Two gener- ation companies (PowerSenoko Ltd and PowerSeraya Ltd), a transmis- sion and distribution company (PowerGrid Ltd) and a supply company (Power Supply Ltd) were formed under Singapore Power Ltd. 84 ENERGY PRI CE RI SK
    • ■ The third generation company, Tuas Power, took over the development and operation of the Tuas Power Station. On 1 April 1998, the Singapore Electricity Pool (SEP), a wholesale electricity market, commenced oper- ation to facilitate trading of wholesale electricity in a competitive envi- ronment. ■ Generation companies will have to compete to sell electricity through the Pool. Electricity suppliers will purchase electricity at competitive prices from the Pool for resale at the retail level. As competition in elec- tricity generation and supply develops, there will be less reliance on regulation. ■ In 1999, the Singapore government reviewed the electricity industry structure with a view to further enhance efficiency through competition in electricity generation and retail, while ensuring reliability and secu- rity of supply. Acting on the findings of the review, the government launched the following initiatives in March 2000 to deregulate further the electricity industry: ● Competition in generation. ● Generation companies will be kept separate from PowerGrid Ltd, the grid operator, to ensure a level playing field. ● Competition in retail. Full retail competition for large industrial and commercial consumers was introduced from 1 April 2001; retail competition for smaller consumers not yet introduced. ● Formation of an Independent System Operator – An independent market and system operator (ISO) will be established by separating the system and market operator functions currently within PowerGrid. This is to make system and market operations more trans- parent to industry players. The ISO will be formed as part of PUB. ● PowerGrid is the only grid owner. ■ Goh Geok Ling, Chairman, Tuas Power Ltd, Singapore: ● ‘As the first independent electricity player in the wholesale electricity Pool, Tuas Power sees the ongoing restructuring of the electricity industry as a positive development for both industry players and consumers. The divestment of Power Senoko and Power Seraya out of Singapore Power in April 2001, redesign of the wholesale Pool rules and liberalisation of the retail market will bring about a more level playing field for industry participants.’ EUROPEAN GAS MARKETS Europe Biggest European markets ■ United Kingdom: NBP (National Balancing Point) EUROPEAN GAS MARKETS 85
    • http://www.heren.com/ http://www.ipe.uk.com/ http://www.theice.com/ http://www.spectrongroup.com/ Futures are available at the IPE futures market in London: http://www. ipe.uk.com/. OTC markets trade around six times the volume of the IPE futures markets and now OTC derivatives on UK Nat Gas executed on the Inter- continental Exchange (http://www.theice.com/) can be cleared via the London Clearing House. Although the OTC and futures contracts are not fungible and cannot be offset for settlement purposes, the London Clearing House does offer margin offsets, so a trader with an equal but opposite position in OTC versus the IPE Futures contract can obtain up to 75% margin offset, reducing the overall margin funding required for its open positions (launched September 2002). OTC markets trade futures prices as well as Heren report prices. More detail on the widely utilised Heren daily report can be found at http:// www.heren.com/. Figure 4.6 shows the level of activity in UK natural gas swaps. ■ Belgium: Zeebrugge This market is also very active, with OTC deals traded on a daily basis against this price reference. Biggest issue surrounding this is the gas interconnector. During 2002 it continued to have problems, which created volatility in the market. ■ Other hubs for gas trading in Europe: Holland: Bunde-Oude Germany: Aachen Austria: Baumgarten France: Blaregnies 86 ENERGY PRI CE RI SK 0 500000 1000000 1500000 2000000 2500000 3000000 Jun- 01 Jul- 01 Aug- 01 Sep- 01 Oct- 01 Nov- 01 Dec- 01 Jan- 02 Feb- 02 Mar- 02 Month '000Therms Series1 '000 Th Jun-01 2121827 Jul-01 2138012 Aug-01 1999754 Sep-01 2008278 Oct-01 2070710 Nov-01 1942100 Dec-01 1369323 Jan-02 2521593 Feb-02 2252378 Mar-02 2636348 FIGURE 4.6 UK natural gas swaps derivatives activity (note the drop in trading volume around the Enron collapse; Enron was a very large participant)
    • The following derivatives contracts are available to users in these gas markets: ■ Index ■ Financial swaps ■ European, Asian, and Daily financial and physical options ■ All physical forwards The following are available at all UK and Continental European points: ■ NBP ■ Zeebrugge (Hub/Flange) ■ Bunde Ouden ■ Zelzate ■ Eynatten ■ St. Fergus Capacity Spark spreads – power versus natural gas UK spark spread example – available on the UK OTC market A few years ago, a standard began to develop around 60 MW of power versus 100,000 therms of gas. The standard product defaulted to gas calendar days for power and gas. However, it is never a perfect match, as gas days remain at 06:00–6:00 hrs and power at 23:00–23:00 hrs. For example, a winter spark spread would run 23:00 30 September–23:00 31 March for power and 06:00 1 October–06:00 1 April for gas. When a spark spread order is traded in the market, it is normally quoted as a spread price in £/MWh (UK pounds per megawatt hour) and also a preferred fixed power price will be offered along with the differential spread, the required spark spread. When trading, having set the fixed power price leg of the deal using a conversion rate of 49.1349% (representing 100,000 therms/60 MW), the gas price is calculated as follows in pence/therm correct to three decimal places: Gas price in p/therm Power price Spread V = - ´ ´ ´( ) 24 100 olume of power Volume of gas Power price Spread = - ´( ) 24 100 60 100 000 ´ ´ , Contracts are based on Standard GTMA (Grid Trading Master Agree- ment), produced by Allen & Overy lawyers in London (http://www. allenovery.com/) and NBP 1997. A recent update on this received from Spectron Brokers in London (http://www.spectrongroup.com/) a leading broker in the European Power OTC market, says that this approach still remains active, but the standard has changed a bit. EUROPEAN GAS MARKETS 87
    • These days companies prefer not to match gas and power dates but rather to keep them as their generic dates, so dates could mismatch by up to about 6 days. However, if traded, it obviously makes no difference as the dates are progressively unwound. Volumes no longer have to be 60 MW and 100,000 therms, although the same efficiency has been kept. Consequently 15 MW and 30 MW with respect to 25,000 therms and 50,000 therms are common. About six market makers regularly give support to this spark spread activity. Spectron has also noted that short-term trading is regularly legged off the spark spreads and may account for as much as 50% of the total volume transacted in power/gas markets. EUROPEAN COAL SWAPS (CASH SETTLED NOT PHYSICAL SETTLEMENT) These are normally ISDA-based contracts. No coal futures have developed in Europe. The coal market The financial traded coal aims to represent the international sea-borne steam coal market, which is the kind used by power plants. The majority of coal is dug from dedicated mines and transported by rail no more than 50 miles to a power plant. In the last 20 years, there has been a 25-fold rise in traded international coal moved long distance by sea from the main exporting countries (South Africa, Australia, Columbia etc.) to the consuming countries (Europe, Japan etc.). This is partly as a result of the closure of the state-subsidised mines in the UK and uneconomic domestic producers in Japan. Size In the year 2000, sea-borne steam coal was an estimated 348 million MT – about 12% of world production. The financial swaps on coal price are mainly traded as a swap index against estimated coal prices. In terms of traded volume data is sketchy, but for the year 2000 brokers estimate it was around 85 million MT. The industry-wide view is that, following the trend of European dereg- ulation, competitive pressure and increase in hedge activity and also the continued growth of the sea-borne markets, this OTC derivatives market will grow substantially. For Europe, generally accepted estimates are that trade is increasing at around 5% annually for the next decade. This is greater than the growth in demand for electricity. 88 ENERGY PRI CE RI SK
    • OTC coal swaps There are four large producers and many consumers in the OTC coal swaps market. The main producers are BHP Billiton, RTZ, Anglo Amer- ican and Glencore, who dominate the sea-borne trade. Of lesser impor- tance, but likely to increase, are Total Elf, the Americans (e.g. Consol), Russia, China and Poland. On the consuming side, all of the integrated power generators (e.g. TXU, RWE and AEP) are involved and there are some ‘pure’ traders (e.g. Cargill and Coeclerici). At present the trading banks are not generally involved. The exception is Morgan Stanley, which has a successful joint venture with the Spanish energy house Endessa, covering coal trading as well as power trading. The key to the producers is Billiton, as it is the largest producer by equity ownership, the most active in the swap market and also has a dominant position in South Africa in the main port, Richard’s Bay (RBCT). South African tonnage for the recent years has been the base tonnage in the demand/supply balance, as it can be shipped east or west, while the new producers and China have the ‘swing’ tonnage. China’s position and recent structural changes in their production profile (lots of small mine closures etc.) is the key to the global supply and demand. There are no dominant consumers/traders but in no particular order AEP, Duke, TXU, Nuon, Essent, Cargill, EdF, Morgan Stanley are among the most important in Europe. Key brokers in the OTC market include: ■ TFS, whose price indices for coal are the basis for the majority of trade at presnt (http://www.tfsenergy.com/) ■ GFI – (http://www.gfinet.com/) ■ Spectron (http://www.spectrongroup.com/) ■ Natsource Tulletts (http://www.natsource.com/) For the coal derivatives market to develop, it is important that there is a solid critical base of consumers, producers and financial traders. The good news for the industry is that during 2002 some new large entrants, on the consumer/trade side, including Bewag, Aquilla and Nordic PowerHouse joined the market. Also, more financial traders like Goldman have been looking to join the market. The key trade pattern copied by the indices used for pricing the coal derivatives in Europe, is the traditional tonnage delivered into Antwerp–Rotterdam–Amsterdam, (the ARA region). Whilst the majority of the coal delivered into ARA is shipped ex-South Africa, it also includes tonnage (depending on market conditions) from the USA and Colombia. The pricing references for coal swaps There are a number of indices discussed in the market: EUROPEAN COAL SWAPS 89
    • ■ Global Coal’s RB index (http://www.globalcoal.com). This is nascent but must be watched, as Global Coal is a hub owned by 26 major producers/consumers. It may become dominant, but it has a long way to go. Its success will depend on physical contracts being written against this index. ■ The TFS indices (http://www.tfsenergy.com/), called the APis, are the main ones used at present for OTC trading. The key difference between Global Coal’s index and the APis is that Global’s is calculated from phys- ical trade data based on concluded deals rather than collated from esti- mates as with the APis. Coal swaps related to APi grade 2 (APi2) are liquid and also some trade in APi grade 4. It is brokered not only by TFS but by Spectron, Natsource, GFI etc. Internal estimates by leading coal brokers suggest that the OTC coal swaps market may have increased to as much as 120–150 million MT on an annualised basis by year end 2002, from a reputed figure of around 80 million MT in 2000. This figure takes into consideration the slight setback seen in this market due to the Enron collapse, so the market is doing pretty well, considering Enron was a very active participant and a major market shareholder in the coal derivatives market prior to its demise. The main pricing reference for coal swaps at present: APi indices There are four APi indices: ■ APi1 – an American contract which is dormant as nothing is really trading against this index. ■ APi2 – delivered cost, insurance freight Amsterdam–Rotterdam– Antwerp – CIF ARA. This is generally the most active contract. ■ APi3 – free on board Port Waratah, Newcastle, Australia – FOB PWCS Australia ■ Api4 – free on board South Africa – FOB RBCT SA, actively brokered by European swap brokers. It is utilised to hedge coal imports in to the ARA region from South Africa. These are swaps so they only need an ISDA in place to trade and at present there are no cleared contracts via any European derivatives clearing house. Users have to accept counterparty credit risk. Market volume breakdown About two thirds of the coal swaps business is APi2. APi3 is rarely traded. The balance is APi4 grade which tends to be illiquid, with wide spreads, not least because of the control exercised by the producers at their equity- owned RBCT terminal. The indices are announced weekly (Monday morning), and averaged for the month and year. 90 ENERGY PRI CE RI SK
    • Trading patterns spotted in the coal swaps markets The typical trade is quarters and calendars, although months do trade more on the APi2. The minimum size is 5,000 MT/month, while the normal size is 10,000 MT a month; more than 25,000 MT/month is considered large. There have been trades up to 3 years forward reported in 2002, and index-based physical contracts up to 4 years forward. The majority of participants actively trade up to 2 years forward in the cash settled coal swaps (based on ISDA agreements). Brokers report that on a busy day (as of 2002) typical daily tonnage is in the range 1–2 million MT, representing about 20–35 swaps trades. There are even reports of some cap and floor (call and put) option activity in the OTC financial coal markets. Other trading and hedging opportunities using these derivatives ■ ‘Soot’ spreads, sometimes referred to as the ‘dark spread’ (coal vs. power). ■ Relative values of gas/coal etc. ■ Arbitrage APi2/Api4 – use freight futures route equivalent to Baltic Exchange Route 4. Speculators can try to strip out the various compo- nents of freight and coal specification to lock in some margin. This is a bit like the development in Freight Rate Swaps in Singapore discussed later in this chapter. Freight Rate Swaps in Singapore are a function of the Opec-Spec Naptha exports of physical Naphtha from Singapore to Japan versus the Naphtha financial swaps in Singapore priced against Platts’ pricing. These are being brokered by Ginga Petroleum (http:// www.ginga.com.sg/). WEATHER DERIVATIVES You can’t change the weather (although in the UK we live in hope!), but, thanks to a relatively new commodity product called a weather derivative, you can protect yourself from losing money when the weather turns bad for your business. Trends in growth of weather derivatives From just a few transactions in the mid-1990s, the formalised exchange of weather risk has evolved into a big business. Weather derivative trading jumped 72% in the year ended 31 March 2002 and is now a $4.3 billion industry, according to a recent survey conducted by Price- waterhouseCoopers for the Weather Risk Management Association. ‘Weather risk’ embraces a wide variety of natural phenomena, but if the focus is limited to temperature risk, the market place starts to look almost as standardised as any commodity futures market. In fact, the 2002 survey WEATHER DERIVATIVES 91
    • conducted for the Weather Risk Management Association (WRMA – http://www.wrma.org/) showed results that weather derivatives against temperature references accounted for over 80% of the total volume (e.g. heating degree/cooling degree days). Temperature-related weather derivatives help people hedge or trade the temperature at certain agreed geographic points around the world. It is reported in the markets that in Europe alone there over 300 regularly quoted geographic points you can trade temperature derivatives against! Demand for weather risk derivatives indexed against temperature references is most probably driven by energy producers/users given the link between energy demand and fluctuations in temperature. Weather risk management developed earlier and faster in North America than elsewhere. Japan and Europe’s markets have evolved to be more diversified in terms of sectors covered, but the standard products in over-the-counter (OTC) markets are still degree day swaps and options. Although Europe’s sectoral mix has always featured a greater propor- tion of non-energy end users than in the USA, 2002 has seen a strong pick- up in energy-driven weather hedging. With the last few years’ merger and acquisition activity and the reorganisation of wholesale market practice now digested (for example, the UK’s New Electricity Trading Arrange- ments), energy firms are increasingly turning to address their weather exposure, and many new trading desks have been, or shortly will be, established. Nowhere has this growth been greater than in Germany, which has now eclipsed the Nord Pool region in terms of weather trading activity. Although London’s Heathrow Airport is still by far the most heavily traded reference station, the market is seeing a large increase in interest for prices on products referenced to previously obscure stations in locations such as Essen. Part of the recent development had been aided by the success of trades with non-energy sector end-users who have substantial risk in the oppo- site direction from the energy firms. This has expanded total capacity for risk. The entry of significant new desks at banks, reinsurers and energy firms over the last year has also had a dramatic effect. While summer 2001 in Europe featured only a handful of OTC trades, summer 2002 proceeded at a much faster pace, with 100–200 inter-dealer trades closing per month. Dealers are reporting customer requests running at rates exceeding 10 a day – and closing half of these deals. Interestingly, although dealers report increasing interest from a very wide variety of non-energy sectors, the impetus for weather element diversity (both in cross-commodity/dual-trigger products and in struc- tures based on variables other than simply temperature) has also been driven by strong demand from the energy sector. As renewable sources of energy are increasingly promoted, the interest in wind speed and precipi- tation hedges is growing. Likewise, products that allow energy firms to 92 ENERGY PRI CE RI SK
    • tailor energy risk management solutions to their customers’ precise needs (for example, managing peaking risk by ensuring adequate supply of physical energy) can be more accurately priced, and better hedged, by using weather derivative technology. Another interesting development in the market is the growth of ‘short- end’ trading. The market for monthly temperature risk products has ballooned, and now ten of these trade for every seasonal deal (the more traditional product). Very short end products (essentially the forecast risk for the next few business days) are bringing an element of familiarity to the product; energy firms’ ‘prompt’ desks (those trading day-ahead and balance-of-week risk) are now able to trade the weather dimension of their risk, separate from any physical dimensions. As a body of experience in trading this risk builds up, we are seeing increased interest in trading weather as a forecast product, rather than the actuarially valued measure it started as. Examples of energy industry use of weather hedging The most prevalent use of weather derivatives has been to hedge uncer- tainty in volumetric demand for energy, due to temperature fluctuations. For this purpose, deals are often referenced to the number of heating (or cooling) degree days in a period. This measures the daily deviation from a reference temperature (e.g. 18 °C), and sums the negative (for HDDs) or positive (CDDs) deviations over the period. It thus gives a proxy for the amount of energy that homes will consume heating or cooling their prop- erty to bring it back to ‘room temperature’. However, it is not obligatory to use the degree day construct – deals can simply reference the average temperature over the period. For example, consider the summer exposure of a gas supplier and an electricity gener- ator in a temperate country that exhibits strong ‘stickiness’ of temperature over a season – i.e. summers tend to be either ‘hot’ or ‘mild’, but rarely ‘average’. Unfortunately for both companies, households use gas but not electricity for heating, and the proportion of gas as a fuel in the power generation mix is very low. The gas company, therefore, will experience sharply stronger demand in a mild summer, and the power company will experience the opposite demand sensitivity: Figure 4.7. The companies can smooth their variability of income by exchanging payments under an average temperature swap. The actual average temperature for the summer is established at the end of the season, and for every 0.1 °C this exceeds 17.0 °C, the power company pays $20,000 to the gas company. If average temperature is below 17.0 °C, $20,000 per 0.1 °C is paid by the gas company to the power company. With a contractual maximum payment of $400,000, the deal allows both firms to smooth the variability of expected revenues within the high-probability range of possible temperature outcomes (from 15 to 19 °C): Figure 4.8. WEATHER DERIVATIVES 93
    • Both companies have achieved a smoothing of their anticipated earn- ings for the upcoming summer, allowing greater certainty in budgetary planning. One company’s ‘bad’ year in effect offsets the other company’s ‘good’ year. Not all risks can be transferred quite as easily – often risk protection is best provided by a market-maker or risk-absorber, who effectively manages a diverse portfolio of weather risks. The portfolio effect means that the hedger can receive an attractive price, even though the counterparty does not have an exactly opposing risk. Often such products come as options rather than swaps; here, the hedger’s risk is covered, against an initial payment to the hedge provider. This is analogous to the purchase of an insurance product. For example, a hydropower generator will be concerned about low rain- fall – but this risk might be described as only significant when reservoir capacity falls below a certain trigger level. The generator could purchase, for example, a precipitation put that is triggered only when annual rainfall is less than 30% of the average. Another product might pay out only if two successive years are below 50% of the average. 94 ENERGY PRI CE RI SK Gas company summer demand sensitivity – 500,000 1,000,000 1,500,000 2,000,000 2,500,000 8 13 18 23 28 Average summer temperature (degrees C) Power company summer demand sensitivity – 500,000 1,000,000 1,500,000 2,000,000 2,500,000 12 14 16 18 20 22 24 26 Average summer temperature (degrees C) Demand(USD)Demand(USD) FIGURE 4.7 Demand sensitivity for gas and power companies
    • An important point to note in valuing options is that the value to the hedger is not simply the probabilistic value of the outcome being hedged (i.e. protection against a one-in-five year event should be worth more than 20%.) The reason is that the hedger must also value the cost of doing nothing, i.e. self-hedging. The firm should include the internal cost of the capital that should be provisioned against the probability of this event happening. Additionally, other costs should be taken into consideration, such as the impact on a company’s reputation of unexpectedly depleted earnings (e.g. adverse equity analyst coverage), and impaired ability to carry out intended capital expenditure. A ‘bad weather hit’ could impair a firm’s ratings and worsen its cost of capital. Overall, weather derivatives provide a flexible and powerful risk management tool for energy firms. The products have largely evolved from the energy sector, and therefore address energy firms’ risks most directly. The use of financial weather risk management techniques has become so commonplace since 1997 that firms now have to justify why they are not using the products. WEATHER DERIVATIVES 95 Gas company sensitivity: hedged and unhedged – 500,000 1,000,000 1,500,000 2,000,000 2,500,000 8 13 18 23 28 Average summer temperature (degrees C) Hedged with swap Power company sensitivity: hedged and unhedged – 500,000 1,000,000 1,500,000 2,000,000 2,500,000 12 14 16 18 20 22 24 26 Average summer temperature (degrees C) Hedged with swap Demand(USD)Demand(USD) FIGURE 4.8 Hedging demand sensitivity
    • Widening use The big increase in weather risk management came as more businesses became aware of weather derivatives, which were created only five years ago as a way to help utilities hedge their risk of losing money to a warmer- than-normal winter or a cooler-than-normal summer. There are also new derivative products being developed that are tailored to meet the needs of specific businesses. ‘It’s one of the ways that public utilities can smooth out the bumps in their earnings’, said Mark Palazzo, a spokesman for Entergy-Koch Trading, which last year was involved in 35% of all the weather transac- tions in the world markets. ‘You don’t have to look at rate increases to cover losses from weather conditions’. DEVELOPMENTS – FREIGHT RATE SWAPS (CASH SETTLED) Freight is an integral part of the global energy business, directly or indi- rectly oil or gas shipped around the world affects power prices in some way. The biggest and in the past the least hedgeable risk in an interna- tional oil transaction, for example, has been the freight rate movements. In recent years, there have been some interesting developments in the freight swaps markets. In the past, the forward freight rate market was focused on dry freight which is helpful if you are trying to trade freight risk against coal, coffee or cocoa, but not much use to anyone trading a cargo of oil! In terms of liquidity and the number and type of participants from the energy industry, perhaps the most interesting development is the Freight Rate Swap out of Singapore. Ginga Petroleum (S) Pte Ltd (http://www. ginga.com.sg/) started developing ‘tanker freight swaps’ for clean petro- leum product tankers in Asia in May 2000. The main routes are Singapore to Japan 30,000 MT shipments, and Arab Gulf to Japan 55,000 MT shipments and Arab Gulf to Japan 75,000 MT. These are swaps (cash settled) which settle against the mean average of daily prices published by McGraw-Hill Platts’ clean tanker rate assessment (http://www.platts.com/). Tanker freight swaps are a beneficial risk management tool for the energy industry because, in the past companies sometimes had un-hedgeable freight exposure on both physical and paper positions. The main participants in this market are petroleum products traders and shipping charterers, as well as tanker owners and banks. Trading volume can be tailor-made for needs of users and most commonly traded lot is 10,000 metric ton per contract month. Most frequently talked tenures for these swaps are 2 to 3 months in the future, while bid/offer quotation is usually available for up to 6 months in the future. Figure 4.9 shows an example of tanker freight swaps. 96 ENERGY PRI CE RI SK
    • Rates quoted in the report are based on World Scale Levels and as previ- ously mentioned the swaps settle out against Platts’ clean tanker assess- ment price level reports. DERIVATIVES FORWARD CURVE ASSESSMENTS A very recent development has been the introduction by a few specialist firms of independent assessments of the forward curves for an increasing number of global energy derivatives markets. This is a wonderful new tool DERI VATIVES FORWARD CURVE ASSESSMENTS 97 Tanker Freight Swaps 29-Jul-02 Platt’s Clean Tanker Rate Assessment (WS) MR(SIN/JP) LR1(AG/JP) LR2(AG/JP) MR/LR1 spread MR/LR2 spread LR1/LR2 spread As of July 26 188 160 135 28 53 25 As of July 25 188 155 135 33 53 20 Average for July 190.95 153.4 133.3 37.55 57.65 20.1 Average for June 185.111 132.5 126.666 42.61 58.44 15.83 Average for May 164.954 134.863 122.954 30.09 42 11.91 SWAPS Requirement Period Buy Sell 30KMT (SG/JP) Aug WS190(I) Sep WS190(I) Oct Q4 WS197.5(I) WS205(I) Q1 WS190(I) WS202.5(I) 55KMT (AG/JP) Aug WS155(I) WS160(I) Sep Oct Q4 75KMT(AG/JP) Aug WS132.5(I) WS140(I) Sep WS130(I) WS140(I) Oct WS130(I) WS140(I) Q4 WS130(I) WS140(I) Last Fixtures Sing/Jpn 30kmt Santan/Jpn 190 heard on sub AG/JP 55kmt AG/JP LR1 160 on sub AG/JP 75kmt AG/JP LR2 135-137.5 SK/JP 30kmt KR/JP USD205K Trend AG/JP LR2 rate was maintained at WS135 in platts. There were no fresh fixture for AG/JP LR2 last weekend. A vessel was heard on sub for Rsea/Jpn around WS135 lvl, however, this seems considered one-off fixture. There is very limited LR2 availability for August, however, chartering activity as well seems quiet down. Shipbrokers pegged LR2 rate stable around WS135. AG/JP LR1 rate climbed up 5 pts to WS160. A couple of LR1 were reported on sub at WS160 for AG/JP 2H Augst. It looks like abt 10 vessels remaining for 2H August. Shipbrokers assessed LR1 rate around WS160-WS155. Sing/Jpn MR rate was unchanged at WS188 in the platts assessment. A vessel was heard on sub for Santan/JPn around WS190. Modern/larger MRs are said tight for 1H Aug. Shipbrokers assessed Sing/Jpn MR rate WS190 more or less. According to a report, average refinery run in Singapore as of July 26th was 55.9%. Best regards, Chisa Wada Ginga Petroleum 65-6292-8484 FIGURE 4.9 Tanker freight swap report. Source: Ginga Petroleum (S) Pte Ltd (http://www.ginga.com.sg/); Contact: Ms Chisa Wada Tel: +65 6 292 8484
    • for risk managers all over the world. It enables both bankers and end users to have a trusted third party forward curve for day-to-day valuation and accounting purposes. The Enron scandal in 2001 rocked many sharehold- ers’ confidence in companies’ use of energy derivatives as well as their pricing and accounting, so the opportunity to utilise third party market assessments of forward curves is a very positive step towards assuring that a reasonable value is attached to derivatives. Indeed, under the new accounting regimes of FAS 133 and international accounting standards (see Chapter 18) derivatives need to be revalued on a regular basis, even if they are employed by an end user such as a power producer or airline. At the time of publication, there were two companies offering this forward curve pricing service in the energy space: ■ McGraw-Hill Platts: http://www.platts.com/ ■ Totem Risk: http://www.totemvaluations.com/ Platts Forward Curve service (PFC) Platts Forward Curve was the first independent service to provide assess- ments and historical data based on actual transactions, bids and offers, for the global oil derivatives market. Platts Forward Curve provides: ■ Independent assessments of swaps in European, Asian or US petroleum markets based on real market activity rather than modes. ■ Independent swaps market commentary. Their full service covers both exchange traded futures and options and over-the-counter swaps, allowing subscribers to: ■ Mark-to-market their derivatives portfolio. ■ Benchmark risk management models. ■ Perform complete profit and loss analysis. European series Platts Forward Curve provides swap assessments, going forward as much as three years, for over 150 data points covering crude oil and crude oil products. Crude swaps assessments: ■ Brent CFD ■ Dated to frontline Brent ■ WTI-Brent ■ Brent-Dubai EFS ■ Dubai inter-month swaps Products: ■ Crack spread swaps relating the value of gasoline, naphtha and gasoil to Brent 98 ENERGY PRI CE RI SK
    • ■ A selection of European benchmark swaps including gasoline, naphtha, jet fuel, diesel and gasoil, and fuel oil. Asia series In addition to Asian assessments for swaps on Tapis and Dubai, the two regional marker crudes, Platts Forward Curve provides crack spread swap values against these two markers, and Singapore products and product timing spread swaps. American Series The American series reports on swaps traded in the USA: on the Atlantic Coast, Gulf Coast and West Coast. Crude swaps covered include Brent and WTI-Brent and products include gasoline, jet fuel, no. 2 and residual fuel oil swaps. Further information on this can be obtained from: Platts, Wimbledon Bridge House, 1 Hartfield Road, London SW19 3RU, UK. Tel: +44 (0) 20 8543 1234 Fax: +44 (0) 20 8545 6635; http://www.platts.com/. Totem Risk valuations The other firm that has recently entered the energy space to deliver forward curve data on a daily basis to the energy trading community is Totem (http://www.totemvaluations.com/). They are now quoting a large array of markets around the world. More information on Totem Risk and also how their service assists companies now faced with the new stricter accounting regime under FAS 133 and IASC accounting standards for derivatives can read more about this in Chapter 18 on international accounting standards for derivatives. Table 4.1 shows a table of forward curves published by Totem Risk. DERI VATIVES FORWARD CURVE ASSESSMENTS 99
    • 100 ENERGY PRI CE RI SK IndexShortNameUnderlyingName(index 1) Forspreadvaluations UnderlyingName (index2) Reference Publication(s) PriceUnitsConversion Factor OptionType OilIndices CrudeOilIndexGroup WTILight,SweetCrudeOil (firstnearbycontract) NYMEXUS$/BblOutrightSAOAveragerate BrentBrentCrude(firstnearby contract) IPEUS$/BblOutrightSAOAveragerate Dated/BrentBRENT(DTD)BrentCrude(firstnearby contract) PLATTS/IPEUS$/BblSpreadS Brent/DubaiBrentCrude(firstnearby contract) Dubai(frontmonth)IPE/PLATTSUS$/BblSpreadS EnergyMarketValuations RegularMarketValuationsareofferedinthefollowingcontractsandindices.Additionalcontractsorinstrumentswillbeincludedonrequest Maturitiesvaluedfollowmarketconventionsforeachunderlyingbutgernerallyincludemonths,quarters,seasonsandcalendaryearsasappropriate ContactTomCharlesworthforfurtherdetails Emailtcharlesworth@totemvaluations.com Tel+442072122693Fax+442078041735 www.totemvaluations.com Instrumentsvalued S:Swaps/Forwards A:At-the-money Options O:Out-of-the-money Options TABLE4.1TableofforwardcurvespublishedbyTotemRisk
    • DERI VATIVES FORWARD CURVE ASSESSMENTS 101 IndexShortNameUnderlyingName(index 1) Forspreadvaluations UnderlyingName (index2) Reference Publication(s) PriceUnitsConversion Factor OptionType Tapis/BrentTapisBrentCrude(firstnearby contract) APPI/IPEUS$/BblSpreadS HeatingOilIndexGroup Nymexnumber2HeatHeatingOil(firstnearby contract) NYMEXUS$/GalOutrightAOAveragerate Nymexnumber2Heat Crack HeatingOil(firstnearby contract) Light,SweetCrudeOil (firstnearbycontract) NYMEXUS$/BblSpreadS IPEGasoilGasoil(firstnearby contract) IPEUS$/MTOutrightAOAveragerate IPEGasoilCrackGasoil(firstnearby contract) BrentCrude(firstnearby contract) IPEUS$/BblSpreadS East/WestGasoilSingaporeGasoilReg0. 5% Gasoil(firstnearby contract) PLATTS/IPEUS$/MTSpread7.45Bbls/MTS USGCNo.2/NymexNo.2 HeatingOil USGCNo.2HeatingOil(firstnearby contract) PLATTS/NYMEXUS$/GalSpreadS EN590CIFNWE/IPE Gasoil CargoesCIFnewEN590Gasoil(firstnearby contract) PLATTS/IPEUS$/MTSpreadS Gasoil.2FOBMED/IPE Gasoil CargoesFOBMedGasoil.2Gasoil(firstnearby contract) PLATTS/IPEUS$/MTSpreadS Gasoil.2BargesFOB Rotterdam/IPEGasoil BargesFOBRotterdam Gasoil.2 Gasoil(firstnearby contract) PLATTS/IPEUS$/MTSpreadS Gasoil.2CIFNWE/IPE Gasoil CargoesCIFnewGasoil.2Gasoil(firstnearby contract) PLATTS/IPEUS$/MTSpreadS
    • 102 ENERGY PRI CE RI SKIndexShortNameUnderlyingName(index 1) Forspreadvaluations UnderlyingName (index2) Reference Publication(s) PriceUnitsConversion Factor OptionType JetIndexGroup JetCIFNWECargoesCIFnewJetPLATTSUS$/MTOutrightAOAveragerate JetCIFNWE/IPEGasoilCargoesCIFnewJetGasoil(firstnearby contract) PLATTS/IPEUS$/MTSpreadS USGC54Jet/NymexNo. 2HeatingOil GulfCoastJET54HeatingOil(firstnearby contract) PLATTS/NYMEXUS$/BblSpreadS JetFOBBarges/IPEGasoilBargesFOBRotterdamJetGasoil(firstnearby contract) PLATTS/IPEUS$/MTSpreadS JetFOBCargoesMED/Jet CIFNWE CargoesFOBMedJetJetCIFNWEPLATTSUS$/MTSpreadS SingaporeRegradeSingaporeKeroSingaporeGasoilReg0. 5% PLATTSUS$/BblSpreadS GasolineIndexGroup NYMEXUnleadedUnleadedNYMEXUS$/GalOutrightAAveragerate NYMEXUnleadedCrackUnleadedLight,SweetCrudeOil (firstnearbycontract) NYMEXUS$/BblSpreadS USGCUnleadedCrackUSGULFCOASTPIPELINE Unl-87 Light,SweetCrudeOil (firstnearbycontract) PLATTS/NYMEXUS$/BblSpreadS EurogradeBargesFOBRotterdam PremUnl Light,SweetCrudeOil (firstnearbycontract) PLATTS/IPEUS$/BblSpread8.33Bbls/MTAAveragerate EurogradeCrackBargesFOBRotterdam PremUnl BrentCrude(firstnearby contract) PLATTS/IPEUS$/BblSpread8.33Bbls/MTS FuelOilIndexGroup
    • DERI VATIVES FORWARD CURVE ASSESSMENTS 103 IndexShortNameUnderlyingName(index 1) Forspreadvaluations UnderlyingName (index2) Reference Publication(s) PriceUnitsConversion Factor OptionType 3.5%BargesFuelBargesFOBRotterdam3.5 PCT PLATTSUS$/MTOutrightAAveragerate 3.5%BargesFuelCrackBargesFOBRotterdam3.5 PCT BrentCrude(firstnearby contract) PLATTS/IPEUS$/BblSpread6.35Bbls/MTS East/WestFuelSingaporeHSFO180CSTBargesFOBRotterdam3. 5PCT PLATTSUS$/MTSpreadS 1%CIFNYHFuelcrackNEWYORKCARGONO61Light,SweetCrudeOil (firstnearbycontract) PLATTS/NYMEXUS$/BblSpread6.35Bbls/MTS 3%USGCFuelCrackGULFCOAST WATERBORNENO63 Light,SweetCrudeOil (firstnearbycontract) PLATTS/NYMEXUS$/BblSpreadS 1%newFuelCrackCargoesFOBnew1PCTBrentCrude(firstnearby contract) PLATTS/IPEUS$/BblSpread6.35Bbls/MTS NaturalGasIndices NorthAmericanNaturalGasIndexGroup HenryHubHenryHubNaturalGasNYMEXUS$/mmBtuOutrightSAOEuropean ANR,LaANRPipelineCo., Louisisana HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS ChicagoCityGateMidwest,Chicago Citygate HenryHubNaturalGasNYMEX/NGIUS$/mmBtuSpreadS ColumbiaGulf,LouisianaColumbiaGulfTransmis- sionCo.,Louisiana HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS PermianTranswesternPipelinesCo. ,PermianBasin HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS
    • 104 ENERGY PRI CE RI SKIndexShortNameUnderlyingName(index 1) Forspreadvaluations UnderlyingName (index2) Reference Publication(s) PriceUnitsConversion Factor OptionType SanJuanElPasoNaturalGasCo, SanJuanBasin HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS HenryHubSouthLouisiana,Henry Hub HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS HoustonShipCanalEastTexas,HoustonShip Canal,LargePackages HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS MICHICONCitygates,Mich.-MichconHenryHubNaturalGasNYMEX/GDUS$/mmBtuSpreadS MALINCalifornia,MalinHenryHubNaturalGasNYMEX/NGIUS$/mmBtuSpreadS SouthernCalifornia Border SocalTopock,Southern CaliforniaBorderAverage HenryHubNaturalGasNYMEX/NGIUS$/mmBtuSpreadS NGPL,LouisianazoneNaturalGasPipeline companyofAmerica,Loui- sianazone HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS NGPL,SouthTexaszoneNaturalGasPipeline companyofAmerica, SouthTexaszone HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS PanhandlePanhandleEasternPipe- linesCo.,TXOK (Mainline) HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS PGEcity-gatePG&Ecity-gateHenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS Northwest,Rocky Mountains NorthwestPipelineCorp., RockyMountains HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS Tennessee,Texas(zone 0) Tennessee,Texas(zone0)HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS
    • DERI VATIVES FORWARD CURVE ASSESSMENTS 105 IndexShortNameUnderlyingName(index 1) Forspreadvaluations UnderlyingName (index2) Reference Publication(s) PriceUnitsConversion Factor OptionType TETCOSouthTexaszoneTexasEasternTransmission Corp.,SouthTexaszone HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS TENN-LATennesseeGasPipelines Co.,La.&Offshore (zone1) HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS TranscoZone1Transcozone1(pooling point) HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS TranscoZone6Northeast,TranscoZone6HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS CNGSouthpointCNGTransmissionCorp., Appalachia HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS TECOColumbiaGasTransmis- sionCorp.,Appalachia HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS WAHAWestTexas,WahaHenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS TETCO-ELATexasEasternTransmission Corp.,EastLouisianazone HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS TETCO-M3MarketCenterSpot-Gas Prices,Northeast,Texas EasternzoneM-3 HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS TranscoZone3TranscontinentalGasPipe- linesCorp.,zone3 HenryHubNaturalGasNYMEX/Inside FERC US$/mmBtuSpreadS S EuropeanNaturalGasContractGroup BelgianGasZeebruggeHubNBPPhysicalDeliverypence/thermSpreadS
    • 106 ENERGY PRI CE RI SKIndexShortNameUnderlyingName(index 1) Forspreadvaluations UnderlyingName (index2) Reference Publication(s) PriceUnitsConversion Factor OptionType GermanGasBundeHubPhysicalDeliveryEuro/MWhOutrightS UKGasNBPPhysicalDeliverypence/thermOutrightSAOEuropean ElectricityIndices EuropeanPowerContractGroup AustrianPowerAustrian(St.Peter)High VoltageGrid Germanhighvoltage grid PhysicalDelivery +Financial Euro/MWhSpreadS DutchPower-baseloadDutchhighvoltagegridPhysicalDeliveryEuro/MWhOutrightS DutchPower-peakloadDutchhighvoltagegridPhysicalDeliveryEuro/MWhOutrightS FrenchPower-baselaodFrenchhighvoltagegridPhysicalDeliveryEuro/MWhOutrightS FrenchPower-peakloadFrenchhighvoltagegridPhysicalDeliveryEuro/MWhOutrightS GermanPower- baseload GermanhighvoltagegridPhysicalDeliveryEuro/MWhOutrightSAOEuropean GermanPower- peakload GermanhighvoltagegridPhysicalDeliveryEuro/MWhOutrightS NordicPowerNordpoolsystempriceNordpoolSystem Price Euro/MWhOutrightSAOEuropean SpanishPowerSpanishgridpriceSpanishGrid Price Euro/MWhOutrightS SwissPowerGermanhighvoltagegridGermanhighvoltage grid PhysicalDelivery +Financial Euro/MWhSpreadS UKPower-baseloadAsdefinedbyGTMAPhysicalDelivery£/MWhOutrightSAOEuropean UKPower-peakloadAsdefinedbyGTMAPhysicalDelivery£/MWhOutrightS
    • CHAPTER 5 Options – Trading and Hedging Application Strategies Energy ‘options’ go one step further than a simple on-exchange futures contract or even an OTC fixed or floating swap contract. They can be compared to insurance policies, because there is a premium to pay but if the market moves against you there is no requirement to pay any more money. When a family takes out a policy on the contents of their home, they are purchasing the right (or the option) to claim replacement goods if the house gets burgled. In the same way, the purchaser of an energy option is buying the right to claim price protection (or benefit as a trader) from the seller of the option if the price of the chosen energy market rises above the price specified in the contract (called the ‘strike price’). An option is exactly what the name implies: when traders buy oil options, they buy the right, but not the obligation, to purchase a certain amount of an energy market (oil, gas, power, coal) at a certain price at a certain future date. That means that the user can set a maximum price it would like to pay for the energy in December, for example, and then buy an option at that price. If somebody sells the buyer that option, they have promised to supply a particular amount of energy, in December, at that particular price. The majority of derivative options are never linked to physical delivery of energy, but merely give the user the benefit from the exposure to the cash flow of an equivalent position in the underlying energy. As discussed in Chapter 3, only a very small percentage of exchange-traded futures contract go to actual physical delivery: somewhere around 2% of total open interest. The advantages of derivative option structures over and above a straightforward futures and or swap structure are as follows: ■ Initial outlay of cash in many cases is restricted to the premium paid, which in the case of zero cost collars (buy cap, sell floor or sell cap, buy floor, depending on the underlying energy price exposure, but the two 107
    • options premium cost/revenue offset one another to create zero cost). This structure is very common among end users with a short energy price risk (they are exposed to energy prices moving higher) so they need to buy caps (calls) and sell floors (puts) in order to create zero cost protection against prices moving higher. ■ There is less opportunity cost than a swap or futures strategy, because option strategies can enable the user to protect against adverse price risk movements, but at the same time still benefit from beneficial price movements in the underlying physical energy market. ■ Another advantage of option strategies (which we discuss in this chapter) is that traders who are unsure about the outright price direc- tion of an underlying assets can take a position on volatility rather than market price. VOLATILITY Volatility plays an important part in the pricing of an option strategy, and is also an important part of evaluating whether or not an option should be considered too expensive to purchase or not. There are two types of volatility: ■ Historical volatility Normalised annualised standard deviation of the underlying energy futures/swap contract. ■ Implied volatility (IV) The volatility value placed on an option premium quotation from a trader or market maker. When an option quote is received, the premium value can be put into an appropriate option model to calculate some idea of the implied volatility that the other trader or market maker considers appropriate for this trade. In most cases, the higher the IV, the higher the premium of the option (Figures 5.1 and 5.2). By comparing 108 ENERGY PRI CE RI SK Reference rate (benchmark, e.g. futures or swaps) Strike Expiry Volatility estimate Interest-rate (risk-free, e.g. base rate) Option pricing model Premium/ cost of option FIGURE 5.1 Option premium calculation principles – premium
    • VOLATILITY 109 KEY TERMINOLOGY USED IN THE ON-EXCHANGE AND OTC OPTIONS MARKETS American option An option which can be exercised on any business day up to and including the expiry date. More expensive than European options. Asian option The main options found in the over-the-counter energy markets are Asian-style options. They are called path-dependent, because their final value is dependent on the path of the underlying energy market (e.g. in a December option, the option will eventually price out against the average price of the energy market the option is based on over the whole month of December, just like a whole month averaging swap). Basically, the profit from an Asian option depends on the price history of the underlying commodity that is being used as the price reference, over all or part of the life of the option. The advantage of the option is that if you bought the option, if the market has moved against the option position (in terms of price movement) the only cost or loss of opportunity was the cost (or premium) of the option. However, with a swap position you would be locked in and have potentially unlimited ‘opportunity cost’ if the market moved against the derivative position. These are normally cheaper than American-style or European-style options. At-the-money (ATM) Option whose exercise price is the same as the market price of the underlying energy. European option An option which can be exercised on the expiry date only. Cheaper than American options. Fair value The combination of intrinsic value and time value, as calculated by an option pricing model. In-the-money (ITM) A call is said to be ‘in-the-money’ when the value of the underlying energy futures or swap price is higher than the option’s strike price. A put is ‘in-the-money’ when its strike price is higher than the value of the underlying energy futures or swap price. Intrinsic value The difference between the strike price and the current market rate. Out-of-the-money (OTM) A call is ‘out-of-the-money’ when the value of the underlying energy futures or swap price is less than the option strike price. A put is ‘out-of-the-money’ when its strike price is less than the value of the underlying energy futures or swap price. Premium The price or cost of the option. Strike price The entry price into the underlying participation level. Time value The difference between the option premium and the intrinsic value, including time until expiry, volatility and cost of carry (interest %). Value date Date when the underlying is settled or delivered.
    • data from volatility and implied volatility, judgement calls can be made on whether IV is looking expensive. A simple scenario is if you buy an option when IV is very high, and then afterwards the market does not move but IV drops, you will most probably find the value of the option that you purchased will have reduced (all other factors remaining equal). TYPES OF OPTIONS ■ In futures markets: ● Calls – the right but not the obligation to buy the underlying futures contract at the strike price. ● Puts – the right but not the obligation to sell the underlying futures contract at the strike price. ■ In swaps markets ● Caps – Over-The-Counter (OTC) name for what structurally gives users the same protection and or exposure to market price movement as calls in the futures market. ● Floors – Over-The-Counter (OTC) name for what structurally gives users the same protection and or exposure to market price movement as puts in the futures market. OPTION STRATEGIES FOR HEDGING ENERGY PRICE EXPOSURE Simple option strategies for hedging against market price movements can be summarised as follows: 110 ENERGY PRI CE RI SK Reference rate (benchmark, e.g. futures or swaps) Strike Expiry Implied volatility, i.e. implied by premium Interest-rate (risk-free, e.g. base rate) Option pricing model Premium/ cost of option FIGURE 5.2 Option premium calculation principles – implied volatility
    • To hedge a ‘short’ energy exposure with options To hedge a ‘long’ energy exposure with options Buy call or cap Sell call or cap Sell put or cap Buy put or cap Buy call spread Sell call spread Sell put spread Buy put spread Financial exposure and/or protection received when using options compared to swaps/futures contracts can be summarised as in Table 5.1. The flexibility of options really starts to become clear when we look at combinations of the above strategies of buying some calls/caps or selling some puts/floors at different tenures and different strike prices, and for differing volumes. The variety of combination structures that can be created using options is endless; the possibilities are only limited by our own creativity and the complexity of the exposure that needs to be protected against (or in the case of an investor/trader, the exposure that they wish to become exposed to). However, there are some quite regularly applied structures in the energy derivatives markets which can be discussed here as a base for traders/hedgers to work from. THE GREEKS In the rest of this chapter, we will look at strategies that can give investors or traders exposure to or protect hedgers from: ■ Changes in market price risk ■ Changes in market volatility But before we can look further into option trading and hedging strate- gies we need to look more closely at what could be described as the atomic THE GREEKS 111 Position Risk Reward Long call Limited to premium Unlimited Long put Limited to premium Almost unlimited* Short (written) cap/floor (call/put) Unlimited (if option posi- tion is not hedged) Cash premium received Long (purchased) under- lying swap/future Almost unlimited* Unlimited Short (sold) underlying swap/future Unlimited Almost unlimited* *Since asset value or derivative contract value cannot fall below zero TABLE 5.1 Summary of exposures: options vs. swaps/futures
    • structure of options: the components or forces in action in an option’s price and also how it reacts to changes in the underlying energy market it Is valued/priced off. These components or forces in action in an option’s price are commonly known as the ‘Greeks’: ■ Delta ■ Gamma ■ Theta ■ Vega Delta Delta shows how much the option’s price changes when there is a change in the underlying asset price. It is closely related to but not equal to the probability that the option will be exercised. From a risk management perspective, the delta of an option is important for creating a risk-neutral portfolio, i.e. you are trying to hedge the underlying cash commodity or futures or swap using options. Gamma ■ Gamma measures the rate at which delta changes. Some options have very high gamma which means that a small change in the underlying asset’s price can lead to a significant change in delta. ■ Gamma can be a major headache for risk managers, because they must delta hedge their portfolio on a regular basis, i.e. they must constantly watch the delta change due to a high gamma situation to make sure they are not under-hedged via options. ■ Gamma is at its highest when the option is ‘at-the-money’ and reduces as the energy price goes up or down, pushing the option either in-the- money or out-of-the money. ■ Risk managers should be aware that the writer (seller) of an option is always negative gamma, whether the option is a call or a put. ■ The holder or buyer of an option is therefore positive gamma. ■ For traders who are negative gamma, the only way to reduce this gamma exposure is to go long on other options. ■ Negative gamma is dangerous because an adverse movement in the underlying can lead to a substantial loss while a favourable (profitable) move leads to only a minor profit. Theta ■ This measures the time decay in an option. A person who is long on an option (bought, buyer), whether a call (cap) or put (floor), suffers from time decay, because as the option approaches maturity its value gets closer to its intrinsic value. 112 ENERGY PRI CE RI SK
    • ■ There is a relationship between theta and gamma: when gamma is high, theta is also high, which means that the option loses value more quickly as it approaches maturity, its expiration date. ■ From a risk perspective, an option with high theta could be good news for a counterpart who is short (already has sold) and bad news for the trader who is long (already bought). ■ However, along with high theta is high gamma, and the counterpart who has sold the high theta option is effectively holding a ‘risky’ option. ■ The general understanding is that if you sell an option time is in your favour, as you profit from time decay. ■ ‘Theta pays for gamma’: this means you benefit from theta but are suffering from high gamma. ■ You can’t have it both ways; you cannot benefit from theta and gamma on the same option! Vega ■ This measures the sensitivity of an option to a change in volatility of the underlying asset. ■ Delta, however, tells you the sensitivity of the option’s price to a change in the underlying asset/swap etc. ■ For example, traders who are very certain that volatility in the market is going to increase would try to build their portfolio so that it had very high vega. ■ As with theta, the option is most sensitive when it is at-the-money. ■ Vega is positive when you are long calls and also puts. ■ An increase in the volume makes the option more valuable. ■ Vega calculations are important for volatility trading (strategies discussed later in this chapter – butterflies, straddles, strangles). ■ You would calculate the ‘implied volatility’; if you feel it is too high you could sell both a call and a put and then buy them back at a cheaper price as volatility calms down – as it reduces. OPTION STRATEGIES Figure 5.3 illustrates how the value of caps in the OTC market (and calls in futures market) and floors in the OTC market (puts in the futures market) move compared to the overall value of the energy commodity they are valued against. To recap: ■ Buying caps/calls A buyer of a cap (call) is protected for a fixed premium on the market price becoming stronger OPTION STRATEGIES 113
    • ■ Buying floors/puts A buyer of a floor (put) is protected for a fixed premium on the market price becoming weaker Figure 5.4 illustrates the selling of caps/floors. To recap: ■ Selling caps/calls ● A seller of a cap (call) receives a fixed premium for selling the option. ● Cash is received for selling the option (premium), this is what becomes useful in finance deals with derivatives. ● There is exposure if the average market price during the life of the option goes above the fixed cap price/strike price. ■ Selling floors/puts ● A seller of a floor (put) receives a fixed premium for selling the option. ● Cash is received for selling the option (premium); this is what becomes useful in finance deals with derivatives. 114 ENERGY PRI CE RI SK Original cost Value of option Value of commodity Cap value increase Floor value increase FIGURE 5.3 Caps/floors (calls/puts). Source: Energy College Ltd, London (http:// www.energycollege.org/) Original cost Value of option Value of commodity Cap value increases Seller of option may start to lose moneyFloor money as market Price value increases Seller of option may start to lose drops FIGURE 5.4 Seller of caps/floors
    • ● There is exposure if the average market price during the life of the option goes below the fixed floor price/strike price. Tables 5.2 and 5.3 show how to hedge using options. OTC OPTIONS AND POPULAR STRUCTURES The option products that are most frequently used in the oil market are caps, floors and collars, and the most commonly traded OTC options are Asian options. These do not exercise into any other contract, they just OTC OPTIONS AND POPULAR STRUCTURES 115 Anticipations Characteristics Short call Implied volatility down Limited profit; unlimited loss; limited protection; cash credit; risk profile at expiration equiva- lent to a short put Long put Implied volatility up Unlimited profit; limited loss; unlimited protection; impor- tant cost; risk profile at expira- tion equivalent to a long call Short call spread or bull spread Implied volatility direction depends on the strikes: ● Sell call and buy call with higher strike ● If a rise in implied volatility is expected: buy ATM call/sell ITM call equal volume ● If a fall in implied volatility is expected: buy OTM call/sell ATM call with equal volume Unlimited profit; unlimited loss; limited protection; low cost; risk profile at expiration equiva- lent to a long semi-futures Long put spread or bear spread Implied volatility direction depends on the strikes: ● Sell put and buy put with higher strike ● If a rise in implied volatility is expected: buy ATM put/sell OTM put equal volumes on both options ● If a fall in implied volatility is expected: buy ITM put/sell ATM put equal volume again Unlimited profit; unlimited loss; limited protection; low cost; risk profile at expiration equiva- lent to a long semi-futures TABLE 5.2 Hedging short energy positions with options
    • 116 ENERGY PRI CE RI SK Anticipations Characteristics Short call Implied volatility down Limited profit; unlimited loss; limited protection; cash credit; risk profile at expira- tion equivalent to a short put Long put Implied volatility up Unlimited profit; limited loss; unlimited protection; impor- tant cost; risk profile at expi- ration equivalent to a long call Short semi- futures Implied volatility direction depends on the strikes: ● Buy put and sell call with a higher strike ● If a rise in implied volatility is expected: sell OTM call/buy ATM put, equal volumes ● If a fall in implied volatility is expected: sell ATM call/buy OTM put, equal volumes Limited profit; limited loss; unlimited protection; low cost; risk profile at expiration equivalent to a long fence or a bull spread Short call spread or bull spread Implied volatility direction depends on the strikes: ● Sell call and buy call with higher strike ● If a rise in implied volatility is expected: buy ATM call/sell ITM call equal volumes ● If a fall in implied volatility is expected: buy OTM call/sell ATM call, equal volumes Unlimited profit; unlimited loss; limited protection; low cost; risk profile at expiration equivalent to a long semi- futures Long put spread or bear spread Implied volatility direction depends on the strikes: ● Sell put and buy put with higher strike ● If a rise in implied volatility is expected: buy ATM put/sell OTM put, equal volumes ● If a fall in implied volatility is expected: buy ITM put/sell ATM put, equal volumes Unlimited profit; unlimited loss; limited protection; low cost; risk profile at expiration equivalent to a long semi- futures TABLE 5.3 Hedging long underlying positions with options
    • cash-settle against the underlying price reference (unlike futures options which end up expiring into a futures contract which must be traded out of). The next most popular kind of option is a swaption, which can be Amer- ican- or European-style. This exercises into a swaps contract buy or sell at the strike price selected. Asian options ■ The profit from an Asian option depends on the price history of the underlying commodity that is being used as the price reference, over all or part of the life of the option. ■ It is sometimes referred to in the financial markets as a ‘path-dependent option’. ■ Cheaper than European options. ■ Cannot use the Black–Scholes formula for pricing options; because this is an average price option, the average prices are not lognormally distributed. ■ The alternative option pricing method is the Monte Carlo approach (see Chapter 6 for more details on this option model). The zero cost collar The collars structure is very popular with hedgers in the energy market. In particular, end-user consumers of energy often use the ‘zero cost collar’, as it offers cheap insurance with no up-front cost. It is made by simulta- neously buying a cap and selling a floor (Figure 5.5). The option strategy pays the buyer of the collar (i.e. the buyer of the cap, the seller of the floor) if the market rises. However, if the market falls below the floor the expo- sure is open. An oil consumer who buys a collar gets protection from an adverse upward move but pays nothing for it. However, the oil consumer does not necessarily give away all of the benefit of lower prices. Barrier options Barrier options were invented to reduce the initial cost of hedging with buying of options. The barrier option either comes to life (is knocked-in) or is extinguished (knocked out) under certain conditions. In practice, the event that activates or kills the option is defined in terms of a price level (barrier). OTC OPTIONS AND POPULAR STRUCTURES 117 Cap Floor FIGURE 5.5 A zero cost collar
    • The barrier option may be combined with a rebate: for knock-out options, the rebate is paid when the option is cancelled as a compensation to the holder. A typical example of a barrier option is the ‘up-and-out floor’ (put). Barrier options – caps/floors, knock-in/knock-out All the combinations illustrated in Figure 5.6 linked to a cap or floor are available in the OTC market. Up-and-out floor (put) This is typically purchased by energy producers who want to hedge their natural long position in the markets. An up-and-out floor (put) may be an attractive alternative to the normal floor/put option, as it is less expensive and provides the same price protection if prices move down from current futures/swap quoted levels. However, if prices move upwards the increase in the underlying commodity’s price reduces the need for down- side risk protection at the original strike price. If the price moves up suffi- ciently to cross the selected ‘barrier’ price, the ‘knock-out’, then the option is cancelled or extinguished: it is ‘knocked-out’. The hedger may then consider re-entering the market with a new hedge by buying another floor but at a higher strike price. The up-and-out barrier is less expensive that a standard Asian, European or American option because the underlying price may fall below the strike price after initially rising, hitting the barrier and cancelling the option. Crack and spread options Some banks and traders or market makers will even quote options on differentials such as the refinery margin – crude versus products. This is particularly useful when having to deal with negative system margins. When running a refinery an organisation cannot choose to stop producing some petroleum product. Refinery engineers may be able to reduce the production of a loss-making product, but in the end you will still have to protect against the negative margin becoming worse. A crack option offers protection against the margin becoming worse, but at the same time allows an organisation to benefit from an improvement in the margin. 118 ENERGY PRI CE RI SK Price Up Down Out In Up-and-out Up-and-in Down-and-out Down-and-in Type of option FIGURE 5.6 Barrier options – caps/floors
    • Compared to using swaps or futures to lock in the negative margin, you will not be able to appreciate from an improvement In the margin. This applies to petrochemical margins and power production margins such as spark spread options. It is even possible to create a zero cost collar spark spread option, or refinery option, where you can sell the margin option at one level and buy protection against the margin at another, giving protection from the margin going below the floor price margin option and locking in the margin at the strike price sold on the cap margin option. Other spread or arbitrage options seen in the market from time to time include: crude versus crude, the complete refinery margin options, and individual cracks between crudes and petroleum products such as gasoil, jet fuel and fuel oil. There are also spark spread options, i.e. natural gas versus power prices, or gasoil or fuel oil versus power prices. Delayed start date options As well as the knock-in and knock-out option into the caps and floors used for trading or price risk management, it is now also possible to obtain a delayed start date from traders and market makers. One example of the application for this can be found in the chapter on hedging examples/ scenarios. If an organisation were trying to hedge the production of a new refinery, oil field, petrochemical plant or utility power station, it is quite possible that it would have an approximate start date for production or completion, but between now and that date some delay might occur. The nightmare scenario for hedgers or risk managers is to be stuck with a hedge but the asset/energy to be hedged not turning up or being ready. Immediately that hedge becomes a speculative position for accounting purposes and is an unwanted, unprotected risk in its own right. This could certainly undermine a company’s cash flow forecasts. So, to reduce this risk it is possible (at a price) to obtain delayed start dates built into option structures and sometimes the optionality of this start date delay can be embedded into a swaps hedge structure as well. It usually means that at a certain date, perhaps three months before the derivatives hedge start date kicks in, the user of the hedge can nominate on a particular day, or any day up to a certain cut-off point, to delay the start of the hedge to another date. The delayed start date would normally be fixed; alternatively, it would be possible to delay the hedge to another specified date or delay it by X number of days. OPTIONS TRADING – VOLATILITY TRADING Options can be used to trade the market price; in other words, they can be used to benefit from movements in the underlying swaps or futures OPTIONS TRADING – VOLATILITY TRADING 119
    • market. However, for investment trading purposes, options can also be used to benefit from the market going nowhere! At the beginning of this chapter we talked about two types of volatility, one of which was implied volatility. This is an important component in the cost or value of an option. By using special combinations of calls and puts or caps and floors for OTC markets, it is possible to make a trade based on whether as a trader you think volatility will increase or decrease. This is done by what is known as volatility trading and involves setting up a delta neutral portfolio (delta neutral = market price neutral). Volatility strategies A trader who wants to take advantage of the underlying volatility of the market increasing or decreasing can use the following option strategies: ■ Straddles Sell call (cap) and sell put (floor) at the same strike price in the same market. It is important to appreciate that although a short straddle is delta neutral (± balanced), it is not gamma neutral. ■ Strangles These are essentially the same as straddles except that a trader will use out-of-the money options. They also use different strike prices. A trader who thinks that volume is going down would normally sort (sell) these options, while if he or she thinks that volume is going up, the trader would go long (buy) them. Butterfly strategy The only issue with using straddles and strangles is the potentially unlim- ited loss on the strategy. This can be managed, but it must be actively 120 ENERGY PRI CE RI SK ■ Your view = Volatility is going to increase ● Buy (long) a straddle or strangle Long straddle involves buying purchasing the put (floor) and the call (cap) at the same strike price. ● Short (sell) butterfly strategy ■ Your view = Volatility is going to decrease ● Short (sell) straddle or strangle Short straddle involves selling (writing) the put (floor) and the call (cap) at the same strike price. ● Long (buy) butterfly strategy
    • hedged and monitored. However, because of this risk concern there are other trading strategies that have less up-front risk. The butterfly (Figure 5.7) is an option strategy that has both limited risk and restricted profit potential. It is created by using four strike prices. The strategy may be set up using caps or floor options. A short or long butterfly: ■ Allows the trading of volatility. ■ Has an advantage over a straddle and even less risk than a strangle because the structure creates a fixed cap on maximum loss. This is already built into the strategy, so active position management require- ments are reduced. A long (buy) butterfly: ■ Requires option premiums to be paid ■ Offers limited risk ■ Is used when the view is that volatility is going to decrease Buy 1 × call Sell 2 × call Buy 1 × call Strike US$20 US$22 US$24 A short (sell) butterfly: ■ Receives more premium then premia paid out ■ Has limited risk ■ Is used when the view is that volatility is going to increase OPTIONS TRADING – VOLATILITY TRADING 121 + – Price of underlying – + Profit Fixed profit upside between these two points Profit The cost of the option FIGURE 5.7 Butterfly strategy
    • Sell 1 × call Buy 2 × call Sell 1 × call Strike US$20 US$22 US$24 Ratio backspreads It is also possible to trade both the market price and volatility at the same time by using special options structures called ratio backspreads. A backspread is a delta neutral spread which is achieved by buying options with smaller deltas and selling options with large deltas. It will also consist of more long (bought) options than short (sold) options with all options expiring at the same time. ■ Ratio call backspread Consists of buying calls at a higher strike price than the strike price of call options sold. ■ Ratio put backspread Consists of buying puts (floors) at a lower strike price than the strike price of the puts (floors) sold. Typically a trader will execute a backspread for some positive cash flow (i.e. some credit premium in their favour), since the amount of option premium received for the sold options is greater that the premium paid for the options bought in the strategy. In a call (cap) backspread strategy (which is a directionally bullish strategy), if the energy market price collapses, then all the options in the strategy will most probably expire with zero value. In a put (floor) backspread strategy (which is a directionally bearish strategy), if the energy market price rises by an extreme measure, then all the options in the strategy will most probably expire with zero value. A trader would choose the type of backspread, either a cap or floor, which directionally reflected his or her price direction expectations. Call backspread option strategy In a call backspread (Figure 5.8), the profit potential is unlimited if the market price of the underlying energy market moves higher. The key to a backspread is that some price movement will happen during the lifetime of the option strategy. If the market price does not really move much, any backspread strategy is more than likely to end up being a losing strategy. Example: Strike prices in a crude oil call backspread option strategy could look something like this: Long 600 December US$25 strike Calls @ 24 cents Short 200 December US$20 strike Calls @ 78 cents Long 400 March US$27 strike Calls @ 23 cents Short 200 March US$22.50 strike Calls @ 51 cents 122 ENERGY PRI CE RI SK
    • Put backspread option strategy In a put backspread strategy (Figure 5.9) the profit potential is unlimited if the market price falls. Again it should be noted that if the market price does not really move much any backspread strategy is more than likely to lose. Example: Strike prices in a crude oil put backspread option strategy could look something like this. OPTIONS TRADING – VOLATILITY TRADING 123 + – Price of underlying – + Sell the higher exercise (strike) price Buy the lower strike (exercise) price Profit Profit potential unlimited if the market price moves lower below the put/floor purchased FIGURE 5.9 Put/floor backspread option strategy + – Price of underlying – + Sell the lower exercise price Buy a higher exercise price Profit FIGURE 5.8 Call backspread option strategy
    • Long 600 December US$20 strike Puts @ 20 cents Short 200 December US$25 strike Puts @ 120 cents Long 400 March US$22.50 strike Puts @ 150 cents Short 200 December US$25 strike Puts @ 249 cents Recap on option trades against market implied volatility 124 ENERGY PRI CE RI SK Result of a large market price swing in the underlying swaps or futures contract Increase in implied volatility Decrease in implied volatility Time value effect Ratio call backspread Beneficial Beneficial Not beneficial Not beneficial Ratio put backspread Beneficial Beneficial Not beneficial Not beneficial Long straddle Beneficial Beneficial Not beneficial Not beneficial Short straddle Not beneficial Not beneficial Beneficial Beneficial Long strangle Beneficial Beneficial Not beneficial Not beneficial Short strangle Not beneficial Not beneficial Beneficial Beneficial Long butterfly Not beneficial Not beneficial Beneficial Beneficial Short butterfly Beneficial Beneficial Not beneficial Not beneficial TABLE 5.4 Comparison of option trades against implied volatility
    • CHAPTER 6 Energy Option Pricing – Which Models Are Used? Modern option pricing techniques are considered to be among the most mathematically complex of all applied areas of finance, although these modern techniques have their origins in work that dates back to 1877. At that time Mr Charles Castelli wrote a book The Theory of Options in Stocks and Shares. Mr Castelli’s book introduced the general public to the hedging and speculation aspects of options, but lacked any usable theoretical base. The financial markets really had to wait until the work of Fischer Black and Myron Scholes was published in 1973 for anything that was very practical for options valuations. That was when they introduced their landmark option pricing model: Black–Scholes, perhaps the most famous of all option models. TYPES OF OPTIONS IN THE ENERGY MARKETS The most popular options in the energy futures markets such as IPE/ NYMEX are all American-style options. However, in the over-the-counter (OTC) markets, Asian options (path-dependent options) are the most popular. The distinction between American, European and Asian-style options is an important one, because of the models that are needed to value them. For the purposes of this book, the Black–Scholes model cannot be applied to bottom line Asian options because they are whole month average options, and distributions of arithmetic averages of a set of lognormal distributions do not have analytically tractable properties. GENERAL RULES FOR OPTION VALUES American-style options ■ The minimum value for a call (cap) is zero and the maximum is the difference between the underlying energy futures or swap market price 125
    • and the strike price (exercise price) of the option, whichever is the greater. The option value cannot be a negative value. ■ The minimum value for a put (floor) is zero and the maximum is the difference between the underlying energy futures or swap market price and the strike price (exercise price) of the option, whichever is the greater. The option value cannot be a negative value. ■ The maximum value for a put (floor) is its strike price. The underlying futures/swap cannot become negative in value, so the biggest profit on a put (floor) is the difference between its strike price (exercise price) and zero. ■ Time to expiry – the value of a call (cap) option with a longer time value/ validity time until expiration must be at least the same as that of a corre- sponding shorter-dated American-style call. For example, if you take quotes for at-the-money call (cap) for the month of December and the at-the-money call (cap) for the month of January, the January at-the- money call (cap) should be worth more than December because of an extra month’s of time value in the option. ■ American-style call (cap) options should sell for at least the same price as a European-style call option, and normally they will cost more than European style options. This is because American style options give the buyer the right to trigger/exercise the option into its underlying futures/ swaps contract at any time during the lifetime of the option. However, European style options give much less flexibility, by only allowing the option to be exercised at a single point in time, usually the expiry date of the option. European-style options ■ The minimum value for a call (cap) is zero and the maximum is the difference between the underlying energy futures or swap market price and the strike price (exercise price) of the option, whichever is the greater. The option value cannot be a negative value. ■ The minimum value for a put (floor) is zero and the maximum is the difference between the underlying energy futures or swap market price and the strike price (exercise price) of the option, whichever is the greater. The option value cannot be a negative value. ■ The maximum value for a put (floor) is its strike price. The underlying futures/swap cannot become negative in value so the biggest profit on a put (floor) is the difference between its strike price (exercise price) and zero. Asian options The majority of over-the-counter (OTC) energy option transactions are made up of Asian-style caps, floors and zero cost collars. Asian options are a type of path-dependent option, sometimes referred to as a look-back 126 ENERGY PRI CE RI SK
    • option where the buyer has the right to exercise the option at the average price of the underlying energy market over the period of the option. Asian options are cheaper than ordinary European style options because the volatility of an average is lower that the volatility surrounding just one point in time, as is the case for a European style option. In the energy markets we usually deal with quite long averages, and like swaps, Asian options in energy markets tend to cover whole month averages (20 pricing days approximately). For more on the mathematics and developments in financial modelling, visit the University of Oxford Mathematical Institute at http://www. maths.ox.ac.uk/. There is also some interesting new development work in various risk management modelling including energy sector work by Professor Robert Jarrow at http://www.kamakuraco.com/. There is an online option calculator at the following Web site: http:// www.optionvue.com/FairMarketValueCalculator.htm. Effect of market changes on an option’s value Table 6.1 shows the effect of market changes on the value of options. Figure 6.1 shows the relative cost of different types of option. TYPES OF OPTIONS MODELS UTILISED IN THE ENERGY INDUSTRY All traded options on the energy markets of the New York Mercantile Exchange and the International Petroleum Exchange are American style options. The models that can be applied to these are a combination of: TY PES OF OPTI ONS MODELS UTILISED IN THE ENERGY I NDUSTRY 127 American style options European style options Asian style options Most expensive Cheapest FIGURE 6.1 Cost of options. Cap value (call) Floor value (put) The price of the energy futures/swap rises Increases Decreases The price of the energy futures/swap falls Decreases Increases Volatility increases Increases Increases Volatility decreases Decreases Decreases Time decay effect Decreases Decreases TABLE 6.1 Effect of market changes on an option’s value
    • ■ the Barone-Adesi and Whaley model; and ■ the famous Black–Scholes model Black–Scholes is perhaps the most famous option model because it is a simple solution to what can be a complicated problem. The model requires a limited number of data inputs and requires relatively simple mathemat- ical calculations. Although the Black–Scholes model was originally devel- oped just with European options in mind (an analytical option pricing formula which is used to price European options on non-dividend asset), it can be extended to price American options as well. Option calculators will often use the Barone-Adesi and Whaley method. This method prices an American option by valuing the corresponding European option using the Black–Scholes method and then adds on an early exercise premium (since unlike European style options, an American style option can be exercised on any day and at any time up to and including its expiry date if the underlying price exceeds some market price level calculated by the model). However, this model cannot be applied to Asian options Asian option pricing Monte Carlo simulation is the tool to use for Asian options, since when an Asian option is defined in terms of arithmetic averages of the underlying energy price over a one month period (which is 99% the case in energy markets), no Black–Scholes or analytical pricing formula is going to be of any use. Monte Carlo simulation is a simulation of many possible paths that the underlying energy price may take. The estimate of value of the option in this case is the average of the expected gain/profit, discounted from the end of the life of the option to the beginning, using the risk free interest rate. A more detailed definition of Monte Carlo simulation is that it is a math- ematical technique for calculating derivative values which can be only predicted statistically. The name is derived from the analogy of gener- ating a sequence of random numbers as if from the roulette wheel at the casino in Monte Carlo, where the result arrives by chance. OPTION PRICING BIBLIOGRAPHY This is a recommended bibliography for mathematical discussions on pricing models for American, European, and Asian style options. J. Barraquand and T. Pudet (1996) Pricing of American path-dependent contingent claims. Mathematical Finance, 6(1):17–51. This is a comprehensive theoretical analysis of pricing path-dependent deriva- tives. It introduces the Forward Shooting Grid numerical technique. 128 ENERGY PRI CE RI SK
    • H. Ben Ameur, M. Breton and P. L’Ecuyer (1999) A numerical procedure for pricing American-style Asian options. Technical Report G-99-39, GERAD. A formulation of the problem of pricing Asian options as a dynamic program- ming problem. M. Broadie and P. Glasserman (1996) Estimating security price derivatives using simulation. Management Science, 42(2):269–285. D. P. Leisen (1998) Pricing the American put option: a detailed conver- gence analysis for binomial models. Journal of Economic Dynamics and Control, 22:1419–1444. Theoretical and numerical investigation of the convergence of different bino- mial models for American put option pricing. Introduction of a new method for decreasing initial errors. F. Longstaff and E. Schwartz (2001) Valuing American options by simula- tion: a simple least-squares approach. The Review of Financial Studies, 14(1):113–147. Least squares Monte Carlo approach for pricing options with American-style exercise opportunities. Examples of application to a wide variety of options. R. Zvan, P. Forsyth and K. Vetzal (1998) Robust numerical methods for PDE models of Asian options. Journal of Computational Finance, 1:39–78. D. Pilipovic (1997) Valuing and Managing Energy Derivatives. McGraw-Hill. F. Black and M. Scholes (1973) The pricing of options and corporate liabili- ties. Journal of Political Economy, 81(3):637–654. R. M. Bookstaber (1981) Option Pricing and Strategies in Investing. Addison- Wesley. E. Corcoran (1990) Fischer Black calculated risks enable mathematician to turn a profit. Scientific American, March, 78–79. J. Hull (1989) Options, Futures, and other Derivative Securities. Simon & Schuster. J. Hull (1991) Introduction to Futures and Options Markets. Simon & Schuster. M. Kripalani (1991) Formula for success. Forbes, 28 October, pp. 203–204. J. M. Laderman (1984) Fischer Black is practicing what he teaches. Business Week, 6 August, p. 75. J. F. Marshall and V. K. Bansal (1993) Financial Engineering. Kolb Publishing Company. Mathsoft Inc. (1994) Mathcad for Windows User’s Guide. A. C. Shapiro (1992) Multinational Financial Management. Allyn and Bacon. R. A. Strong (1994) Speculative Markets. HarperCollins College Publishers. A. L. Tucker (1991) Financial Futures, Options & Swaps. West Publishing Company. R. Whaley (1986) Valuation of American futures options: theory and empirical tests. Journal of Finance, 41(1), March, pp. 127–150. D. S. Wilford, C. W. Smith and C. W. Smithson (1995) Managing Financial Risk. Irwin Inc., pp. 312–400. OPTION PRICING BIBLIOGRAPHY 129
    • CHAPTER 7 Value At Risk and Stress Testing ‘It is not the size of the position, but the capital at risk that really matters.’ When an organisation embarks on trading or hedging in the energy markets, it is important that a methodology for market risk measurement is adopted. One of the key concepts of risk measurement in the energy sector is now the probability-based risk measurement method known as value-at-risk or VAR for short. The results produced by a VAR model (and there are different types of VAR) is simple for all levels of staff from all areas of an organisation to understand and appreciate. That is why VAR has been adopted so rapidly across many industries. A RISK MANAGEMENT SCENARIO Let’s create a scenario. A risk manager at ABC Trader Ltd is responsible for managing the company’s natural gas positions. The Board of Directors call this person in for a meeting, after hearing about derivatives losses suffered by other companies in the natural gas market. The Board want to know if the same thing could happen to their company. That is, they want to know just how much market risk the company is taking. How should the risk manager reply? The risk manager could start by listing out and describing the company’s natural gas derivatives positions, but this isn’t likely to be helpful and does not answer the Board’s real question: ‘How much market risk is the company taking?’. The risk manager is in a tricky position. Listing the positions of the company only helps if the Board of Directors actually understand all of the positions and all the derivative instruments and the risks inherent in each and every one. Of course, all guidelines point out that the Board of Direc- tors should be involved in approving risk management policies and they should have a broad general understanding of derivatives, but the reality is that they are not involved in the day-to-day risk management and 130
    • trading functions and so will probably not be able to appreciate these details, however well the risk manager explains them. The risk manager could perhaps talk about the portfolio’s sensitivities. He or she could explain how much the value of the portfolio changes when various underlying market rates or prices change, and perhaps option deltas and gammas. But even if the risk manager is confident in his or her ability to explain these in plain language, this does not clearly quan- tify what risk the company taking in the natural gas market! The risk manager could make the bold statement (if true) that the organisation, in line with Risk Management Policy, never speculates but rather uses derivatives only to hedge. This would mean that there could be a loss of opportunity but there would be no massive risk of uncovered losses as a result of speculation gone wrong. But the Board of Directors by this stage might ask again, ‘How much is the company at risk in the natural gas market? Are our hedges effective?’. Maybe the risk manager’s best answer would start with: ‘The value at risk of our natural gas positions is X million dollars’. This is the kind of answer that the VAR method is designed to supply. Value-at-risk is a mathematical approach to modelling financial risk in a derivatives port- folio that, put simply, poses the question: How much money could an organisation lose over a given period of time on its trading portfolio? VAR AND OTHER RISK MEASUREMENT METHODS Value-at-risk (VAR), was conceived in 1993 partly in response to various financial disasters. Work started on its development in 1988 after central banks wanted a methodology to set minimum capital requirements in banks to protect against credit risk in trading. Banks began adopting it around 1993–1995 and, in recent years, non-bank energy traders and end- users have begun to use VAR. Now the majority of major oil companies and traders are using the VAR method for risk measurement. As a practitioner, when using VAR in the energy markets, it should be remembered that any valuation model is simply a representation of a possible reality or a possible outcome, based on certain probability and confidence percentage parameters. It is all too easy to experience a false sense of security when using VAR and to believe that its valuations repre- sent the limit of what an organisation could lose in a 24 hour period. For this reason, some stress testing of derivative portfolios should be used alongside VAR. For example, a company could periodically take its trading position and test the result of a three standard deviation move in energy market prices, as well as changes in market prices and volatility (if VAR AND OTHER RISK MEASUREMENT METHODS 131
    • the company has option positions). Value-at-risk, like any risk measure- ment tool, is not sufficient on its own, and so an organisation should have a number of risk measurement tools as part of its risk management policy. Figure 7.1 shows some of the main measurement techniques available to complement VAR. The use of stress tests and sensitivity analysis alongside VAR will be examined later in this chapter. Before VAR was developed, trading companies only had risk measure- ment tools such as ‘add-on’ approaches, in which companies would set an in-house margin rate (capital charge) for derivative trades. The percentage was based on a percentage of notional value and would vary depending on the tenure of the derivatives deal. For example, the add-on rule could be that when a deal is in the tenure range of one to six months forward, a value of 10% is taken of the notional value as the add-on risk. So, for a deal involving 50,000 barrels of Jet Fuel at US$25 per barrel the notional value would be US$1.25 million, which would mean that 10% of that figure (US$125,000) would be booked to be used by the company’s trader on this derivative position. Then, in addition to this, every day any unrealised loss would be added to the position and the add-on value would be revalued based on the most current fair value of the derivative. 132 ENERGY PRI CE RI SK Complementary risk measurement methods Sensitivity analysisStress testsValue At Risk Maximum expected loss within a certain time frame and % probability The What if? scenarios testing What if? All energy prices change by 5%, 10%, 25%, 50%? Variance/covariance Historical VAR What if history repeats? Monte Carlo VAR Looks at large number of possible outcomes all sharing certain defined statistics FIGURE 7.1 Risk measurement methods
    • The problem with this approach is that, as Bank of International Settle- ment research has indicated, ‘add-on’ methodologies can create situations in which too much capital is being used on a risk, and sometimes not enough capital is being allocated to reflect the risk being taken as a trader. For this reason, companies still using an ‘add-on’ methodology should seriously review their position. WHAT DOES VAR DO? There are different types of VAR model which will be examined in this chapter from a practical application standpoint, but, basically, VAR measures the worst expected loss over a given time horizon with a certain confidence – or probability – level. VAR allows management to see the probable risk their company is taking, or, in the case of companies hedging, it can also illustrate reduction in possible financial exposure. It has great appeal, since VAR can summa- rise all the market risks of the entire portfolio of a firm (e.g. oil, gas, power, coal, forex) across physical and derivatives positions and represent that as one number in US dollars. The key use of VAR is for assessing market risk (exposure to losses in the market place through physical and derivative positions) although VAR is being used more frequently to assess credit risk (credit VAR modelling). However, VAR does not give a consistent method for measuring risk, as different VAR models will come up with different VAR results. It should also be noted that VAR only measures quantifiable risks; it cannot measure risks such as liquidity risk, political risk, or regulatory risk. In times of great volatility, such as war, it may also not be reliable. For this reason, VAR models should always be used alongside stress testing, as mentioned earlier in the chapter. To calculate VAR, a VAR mathematical model needs to be chosen and, in some cases, historical price data on the relevant markets should be obtained. Then a time horizon should be selected (for example, overnight) and a probability – or confidence – factor should be chosen. Most VAR models use a time horizon of one day (sometimes referred to as the ‘holding period’) and, in the energy industry, the most common confi- dence level is around 95% (although more conservative companies often prefer a higher figure). A 95% confidence level means that the company is expecting this value at risk loss to be exceeded, on average, one day in every twenty. The confidence level should, of course, be reviewed and approved at the Board of Directors level in the organisation at the time of approving the organisation’s Risk Management Policy. There are several different types of VAR and in terms of practical appli- cations some are better than others. The three most important types are: WHAT DOES VAR DO? 133
    • ■ Variance/covariance VAR This is generally the most popular method among energy market participants. ■ The historical method In essence, this method ask ‘What if history repeats itself?’ ■ Monte Carlo VAR simulation This method looks at a large number of possible outcomes all sharing certain defined statistics and is also known as stochastic simulation. VARIANCE/COVARIANCE VAR The variance/covariance approach was pioneered by JP Morgan with its product RiskMetrics (which can still be found on the Internet at http:// www.riskmetrics.com/). It involves using information on the volatility and the correlation between the various markets in which an organisation is holding derivative and physical positions. VAR takes into account the price correlation relationships between the various parts of an organisa- tion’s energy derivatives/physical portfolio. One would expect that a buy and a sell even in two different energy markets which were highly corre- lated with one another would produce a low VAR. However, if an organi- sation held a long (buy) position in coffee beans and a short (sell) in North Sea Brent Crude oil, one would expect that these would not have much of a price correlation relationship and the VAR would be much higher, as there would be no offsetting between the long and the short positions within the organisation’s portfolio. 134 ENERGY PRI CE RI SK NICK LEESON AND THE COLLAPSE OF BARINGS In February 1995 the world was shocked by the news that the UK’s oldest bank, Barings, had collapsed. Investigations revealed that its downfall was largely due to the activities of one of its young investment officers, Nick Leeson. Mr Leeson worked in the bank’s Singapore office and traded on the Singa- pore Monetary Exchange (SIMEX). His risky and unauthorised derivatives investments in the Japanese futures market resulted in losses of around 1.3 billion dollars. This huge loss wiped out the firm’s entire equity capital and led inevitably to the bank’s the collapse. Putting aside the lack of properly enforced risk management policies for a moment (these will be discussed in Chapter 9: Management Controls), it is interesting to note that under normal market conditions the potential loss of Mr Leeson’s trading positions would have exceeded US$835 million 5% of the time. If these VAR calculations had been in place, the parent company Barings Bank in London may have been able to provide some protection against the disaster that was awaiting them.
    • Variance/covariance models are fairly easy and quick to compute and calculate, as they can be produced on a spreadsheet, and they are useful for the intra-day management of simple futures/swaps portfolios. However, they are not suitable for complex portfolios of derivatives. An analysis of options contracts, for example, will often produce erroneous results under this model. Monte Carlo VAR is the only methodology that can produce precise VAR results for more complex derivatives portfolios that include options. Summarising variance/covariance methodology: ■ Strength ● Easily calculated in markets which have readily available market data. ■ Weakness ● Historic correlations and volatility relationship may break down under extreme market conditions. ■ Requires ● VAR calculator. HISTORICAL SIMULATION VAR METHOD The historical VAR method is simple to understand and uses real historical data from the markets that an organisation is active in. If the data is avail- able, it is possible to use this method to run a historical VAR on a trading portfolio as if it were going through the Gulf War of the early 1990s, for example. The method works by running the position of the current organisation’s portfolio against historical market movements to create a P+L scenario. For example, if an organisation’s current portfolio consists of 30% Natural Gas, 50% Singapore Fuel Oil and 20% UK APi2 Coal, it should obtain the historical market data for the three components of its portfolio for the last 720 data items (720 market/business days = approximately 3 years). Then for each day over that 720 day historical period the value of the current portfolio can be calculated. The drawback of this approach is that it is very time-consuming and can be very demanding on computer resources if the portfolio is complex or if it is run over many years of historical data. Summarising the historical VAR model: ■ Strengths ● As well as being simple, the historical VAR approach is more realistic than the variance/covariance approach, since the volatilities and correlations in this approach are not actual figures, but just estimates based on averages over a specified time. HISTORICAL SIMULATION VAR METHOD 135
    • ● It does not require mapping, unlike variance/covariance. Mapping is the sometimes painful process of trying to fit a derivatives position into the volatility statistics which are available. ■ Weaknesses ● Time-consuming, computer resource hungry. ● Reliant on history repeating itself. MONTE CARLO VAR SIMULATION (STOCHASTIC PROCESS) The Monte Carlo simulation method can be used to handle complex deriv- ative portfolios including OTC/exotic options and it has a number of simi- larities to the historical simulation model. The key difference is that the historical simulation model carries out the simulation using the real observed changes in the market place over the last X periods (using histor- ical market price data) to generate Y hypothetical portfolio profits or losses, whereas in the Monte Carlo simulation a random number gener- ator is used to produce tens of thousands of hypothetical changes in the market. Many energy market participants will use a minimum of 30,000 calculations in this process. These are then used to construct thousands of hypothetical profits and losses on the current portfolio, and the subse- quent distribution of possible portfolio profit or loss. Finally, the VAR is determined from this distribution according to the parameters set (e.g. 95% confidence level). The more hypothetical simulations that are used the better the result will be, but this will depend on how long you can wait and how fast your computer is! The large number of calculations required by this method means that the computation of this VAR on a large complex portfolio can take hours. However, with computing power getting rapidly cheaper this is no longer such an issue as it once was. The Internet is also enabling soft- ware firms to allow companies to use their computers to do the calcula- tions, removing the need to invest in lots of in-house computing power. This type of outsourcing approach is becoming more popular even in the investment banking community. Two firms pioneering this in the energy trading industry are Innova (http://www.ifs.dk/) and http://www.sknt. com/. Although the Monte Carlo simulation process is rather complex, in terms of precision it is certainly considered by users as the most effective of the three VAR methods discussed in this chapter. Summarising Monte Carlo simulation: ■ Strengths ● The most precise/effective VAR model. 136 ENERGY PRI CE RI SK
    • ● Can handle complex derivative portfolios, including options. ● Generally more realistic results. ■ Weaknesses ● The most complex to calculate. ● The slowest to calculate. ● As an organisation’s trading activity/position increases over time additional computer processing power requiring hardware upgrades may be required. VAR RECAP The great thing about VAR in terms of practical implementation and appli- cation across an organisation is that the output of VAR calculations is easy for everyone to understand. This has been the key factor in promoting its widespread adoption across non-financial traders, energy companies and end-users. The output from VAR calculations is a currency value, which in the energy industry is usually given in US dollars. It shows clearly how much an organisation is risking over the chosen time horizon within a certain confidence level. If the VAR result for Trader A’s portfolio is US$2 million but for Trader B’s portfolio is US$3 million, it is easy to see who is putting the company at more risk. So, by using the above scenario of Traders A and B, a risk manager might report to her management that within a 95% confidence level, the company is risking a potential loss of no more than US$5 million over the next 24 hours. As a result, the energy sector can decide how to allocate economic capital as a trader or speculator and how to trade off risk and return. VAR TO ILLUSTRATE HEDGE EFFECTIVENESS Both producers and consumers can use VAR to assess and quantify the effectiveness of hedges in an easy-to-understand format, but it should be remembered that an effective hedge is not necessarily a profitable one. It is possible to have an effective hedge that loses money on the deriva- tives side of the hedge but still allows the company to profit from cheaper physical energy as a consumer, or higher physical prices as a producer. Companies which are hedging may suffer an ‘opportunity cost’ in economic terms, but as long as they do not have too much basis risk, the derivatives hedge + physical purchase/sell should net out. Until VAR began to be adopted more widely by the energy industry (from around 1998 onwards), staff who were responsible for hedging programs in companies were often faced with difficult questions about VAR RECAP 137
    • why hedges lost money on the derivatives side of the deal. For them, it was difficult to show how effective a hedge was. Most of the time, compa- nies would gauge the effectiveness of a hedge by whether they made money on their derivatives hedge. But with VAR it can be shown that swaps, futures and/or options positions actually reduce a company’s potential risk to exposure by a US dollar value. After all, the fundamental aim of hedging is to protect against disaster scenarios, to reduce balance sheet volatility or profit/loss volatility and to protect operating profit margins from being eroded. With VAR, it is easy to take a simple, practical approach to demon- strating the effectiveness of a hedge position. A physical energy position can be put into the VAR model and then run to show how much money is being risked in the chosen time horizon and confidence level by not hedging. If an opposing hedge derivatives position is added to the model, the reduction of potential risk exposure can be presented as a clear figure in US dollars. This makes it easy for management from all divisions and business areas to appreciate the amount of risk reduction. So, VAR can illustrate the effectiveness of a hedge strategy, or highlight that a supposed hedge is actually increasing risk due to bad correlation between your physical energy and the chosen derivatives contract. This is particularly the case when using a ‘proxy’ hedge. This is a derivatives contract (swaps, futures, or option) that is not pricing against exactly the same pricing index as the underlying physical energy buy/sell and so in rare cases the amount of potential risk reduction is not worth the cost of hedging. (See ‘Basis Risk’ and ‘Hedge or trade’, Chapter 1, for more details) STRESS TESTING AND VALUE-AT-RISK So, VAR can be used to provide a probability-based boundary on likely losses for a specified holding period and confidence level (for example, the maximum loss that is likely to be experienced over one day with a 95% level of confidence). It can also be used to assess the risk-adjusted perfor- mance of individual business units. However, we have to recognise that there are limitations to the ability of statistical models such as VAR to accu- rately capture what happens in exceptional circumstances. VAR may be able to tell us that within a 95% confidence level certain things will happen, but it does not tell us what might happen in that 5% gap! By definition, exceptional circumstances occur rarely, and statistical inference is imprecise without a sufficient number of observations. Although Monte Carlo VAR simulation can get a user close to perfection through tens of thousands of calculations, stress testing is still advisable alongside this approach. 138 ENERGY PRI CE RI SK
    • Stress testing analysis methodologies In stress testing, two standard ways of developing scenarios are commonly employed: ■ Historical scenarios (using historical price data). ■ Hypothetical scenarios. Energy sector traders tend to use a mixture of both approaches. Historical scenarios employ shocks that occurred in specific historical episodes. A simple way to do this is to identify days in the past that were ‘stressful’ and use the observed changes in market risk factors on those days. For example, a portfolio of market risk exposures could be stress tested by seeing how its value would change given the changes recorded for market risk factors for a day, or over a longer period. The selection of the day, or period, is typically based on ‘headline’ disturbances, such as the Gulf War in the oil markets, Iraq invading Kuwait, big OPEC decisions, or the power crisis in California. One advantage of this technique is that the structure of market factor changes is historical rather than arbitrary. The fact that the market moves used are historical fact enhances the credibility of the exercise from the point of view of risk management, due diligence and, as a result, senior management. Another advantage of historical scenarios is their transpar- ency. A statement like ‘if the Gulf War happened tomorrow, the firm would lose X million dollars’ is easy to understand and put in to perspective. One disadvantage of historical scenarios is that firms may (consciously or unconsciously) structure their risk-taking to avoid losing money on shocks that have occurred in the past, rather than anticipating future risks that do not have a precise historical parallel. This could represent a conscious choice on the part of traders, if firms give traders an incentive to minimise exposure to stress tests through limits or capital charges. It could also represent an unconscious choice, if traders overestimate in their own minds the likelihood of shocks that they have first-hand experience of. Another obvious but key disadvantage of historical scenarios is that they may be difficult to apply to derivatives products which did not exist at the time of the historical event in question. This is one of the reasons why hypothetical scenarios are also important. The hypothetical or sensitivity stress test approach One reason why an organisation may choose to conduct hypothetical stress testing as well as historical stress testing on its derivatives portfolio is that hypothetical stress tests allow them to assess the extent to which the conventional wisdom (based on the history of recent market moves) may be driving position-taking (or lack thereof as the case may be!) Hypothetical scenarios use a structure of shocks thought to be plausible in some foreseeable circumstances for which there is no exact parallel in STRESS TESTING AND VALUE-AT-RISK 139
    • recent history. This begs the question how far back in history do you go. Generally many energy traders do not look back beyond more than five years of historical data. This is because the further one looks back in history, the bigger the chances are that the fundamental supply/demand factors of the energy market will have changed. This, in turn, affects the benefit of applying that historical price movement to a current live deriva- tives portfolio. Perhaps the most prudent approach to stress testing is to use a mixture of the last five years’ data plus a few snapshots of data related to particular disaster scenarios like the Gulf War. Limitations of stress tests In practice, stress tests are often neither transparent nor straightforward. They are based on a large number of risk management choices as to what risk factors to stress, what range of values to consider, and what time frame to analyse. Even after such choices are made, risk managers are faced with the considerable tasks of analysing the results and trying to identify what implications, if any, the stress test results may have for their organisation. A well-understood limitation of stress testing is that there are no proba- bilities attached to the outcomes. Stress tests simply help to answer the question ‘How much could be lost?’. SUMMARY Over recent years, the development of VAR models of risk measurement has greatly improved the risk manager’s ability to assess market and credit risks and to help others in the organisation understand what those risks mean. However, even the most rigorous VAR analysis cannot capture the potential effects of all exceptional circumstances, and for this reason VAR should be used alongside periodic stress testing of an organisation’s trading, derivatives portfolio and exposures, in order to obtain a balanced risk measurement policy. 140 ENERGY PRI CE RI SK
    • CHAPTER 8 Questions to Ask When Establishing a Risk Management or Trading Program These are some of the key questions to ask when collecting information that will help to create a policy for the usage of derivatives either as a trader, speculator or hedger. 1. What is your organisation? A consumer, a producer or a trader? 2. What products does the organisation have price risk in? ● Products ● Fixed or floating price risks 3. Is your organisation’s aim hedging or trading? Which of these are you trying to do? ● Mitigate a disaster risk scenario ● Protect budgeted levels ● Control overall price risk ● Trade risk as speculator 4. Will you let traders speculate or only hedge? 5. What is your total volume of energy to hedge or how much do you wish to trade? 6. As a hedger, how much do you want or need to hedge? ● When hedging look at up to 50% of exposure for general day-to-day hedging requirements. ● Any hedging over 50% of consumption or production volume is spec- ulative and should only be considered as rare case pre-emptive measures ahead of a ‘disaster scenario’. This could be during protracted periods of extreme high prices (as a consumer) or extreme low prices as a producer of energy. Or it could be as opportunistic 141
    • hedging opportunities when historically high profitability can be ensured in by locking in low prices as a consumer or high returns as a producer. – One exception to this guideline is when as a consumer you have 100% of sales/income fixed (e.g. a charter airline which has pre-sold all seats on flights and is exposed to floating price jet fuel). – Another example is if you are a trader buying a feedstock for your own refinery system, or you are buying power or gas for your company and you need to fix this cost so that other departments in the organisation can cost delivery of finished goods or products for customers. – Usually end-users will hedge around 20% to 30% of volumes around budget levels up to 18 months forward, leaving an addi- tional 20% to 30% (up to 50% total) for opportunistic hedging if levels come below budget levels. – End-users should also generally look to have another policy for hedging in times of extreme price moves, allowing the energy procurement department or the dedicated risk management departments to act quickly to protect the firm against extreme price moves that might be seen in times of war etc. For example, if you were an electricity consumer in the USA when power costs spiked to US$10,000 per MWh, you would have wanted to protect yourself before that happened, perhaps by up to 100%. Or, as an airline, as tension increased, you would have wanted to protect yourself ahead of the Gulf tension in the Iraq/Kuwait confrontation. Answering all these previous questions will help an organisation to then look at the next step of putting together a risk management policy. 1. What types of derivatives should be used? ● Futures ● Options – OTC? On-exchange? – Can traders only buy options or will they be allowed to sell options as well? (This can incur open exposures for companies if not as part of a larger structure. Also in some derivative disasters, the sale of options has been used to generate cash flow to cover up losses else- where in a portfolio.) ● Swaps 2. What tenures/how far forward the organisation can utilise these derivatives? ● Normally, an organisation should state in its risk management policy (as a hedger) or derivatives usage document (as a speculator) which derivative types can be used, in which markets they can be used and also how far forward each type of derivative contract (futures, 142 ENERGY PRI CE RI SK
    • options, swaps) in each market (e.g. Singapore Gasoil, Dubai Crude, Brent, Fuel Oil Rotterdam). 3. Which derivatives markets to utilise? ● For hedgers – this decision will be based on how well the available energy derivative markets correlate in terms of price (and also causa- tion relationship) with the underlying energy markets that are to be hedged and in which the organisation has price risk exposure. Then, once a list of possible energy derivatives that match requirements are selected, an organisation must then review this list with the contract liquidity in mind. (Checking with brokers on the average daily volume, normal bid/offer spread gap, number of active counterparts). If liquidity is bad then an organisation may have to consider a proxy hedge. ● A proxy hedge example – IPE Brent Futures to hedge Middle East crude exposure. IPE Brent is not a Middle East crude contract, but it has high liquidity and has some price correlation relationship with Middle East crudes. This might be instead of using the OTC Dubai or Oman swaps which are much more closely linked with Middle East crude, but price transparency and overall liquidity may not be good enough for some organisations. ● For traders/speculators – this decision will be based upon liquidity of the energy derivatives markets (volume and number of counterparts trading the market) and also the level of price transparency that exists. For a trader/speculator the lack of price transparency can be an attraction, whereas for a hedger, price transparency is more impor- tant than liquidity. Liquidity is more important for traders, since they will normally wish to trade out/close out a position ahead of its expiry/settlement. An organisation hedging will normally let deriva- tives contracts run their full term through to expiry as it is hedging an underlying energy price risk. So, for a hedger, the ability to trade out/ close out a derivatives position may be less of a concern. The price linkage between the derivative and the energy price risk being hedged may be more important to the hedger than the liquidity of the market. 4. How will the operations department manage these derivative positions? ● Will the organisation require new IT infrastructure to process and manage these derivative positions? ● Does the organisation have the relevant skill sets or will training be required prior to the start of this activity? ● How will these derivative positions be valued? – Valued against third party forward curve assessment, e.g. Platts Forward Curve or broker quotes/dealer quotes? ● How often will these derivative positions be valued? QUESTIONS TO ASK 143
    • – Daily, weekly, monthly, quarterly ● For a trader/speculator, how will the position limits be set? – Volumetric limits? – Notional value limits? – Will the limits be set by tenure and product? – Which traders can trade what products and which types of deriva- tives can they trade? ● Who will be responsible for monitoring these positions and reporting any break in the organisation’s policy for derivatives usage? ● What reports will be produced to assist risk monitoring/performance function? – Open position reports – Market value reports – Profit and loss reports – Hedge effectiveness reports (correlation analysis between the derivatives used for hedging and the underlying energy risk being hedged) ● How often will these reports be produced? ● Who has to see these reports and sign them off as read? ● Prior to any activity starting, the organisation must assess the opera- tional risk of this new business, as well as credit risk, market risks, legal risks, tax risks etc. Who will be responsible for ensuring that there are ongoing regular reviews of these risks? This is certainly not an exhaustive list, but all of these questions can assist an organisation’s management to start looking at policy decisions and to put together a short paper on what they propose to let their risk managers and traders do. Accounts departments can also get a good idea of what type of accounting for derivatives will have to be handled, either as hedges or speculative trades (see Chapter 18). All the information from this short paper, and feedback on it from the relevant line managers in the organisation, should then be put together for presentation to the Board of Directors/Board of Management, who should create a general policy and reporting structure for the organisation. Line managers should then take this general policy and, with reference to the Board’s decision, fine-tune a more detailed risk management deriv- ative usage guidebook for traders, operations and managers. This opera- tional document should be submitted again for approval by the Board of Directors. 144 ENERGY PRI CE RI SK
    • CHAPTER 9 Management Controls THE COLLAPSE OF BARINGS On 18 July 1995, the world’s financial institutions received a shocking wake-up call. That was the day when the UK’s oldest bank, Barings, offi- cially collapsed, posting a loss of US$1.3 billion. The firm’s entire capital had been wiped out as a result of unauthorised and extremely risky deriv- atives investments in the Japanese futures markets made by one of its young investment officers, Nick Leeson. Many in the media blamed the disaster on the nature of derivatives themselves, but the real reason for the bank’s collapse was the complete lack of enforced management controls throughout the organisation. On the face of it, Barings collapsed because it could not meet the enor- mous trading obligations that Leeson had established in its name. When it went into receivership on 27 February 1995, Barings had outstanding notional futures positions on Japanese equities and interest rates of US$27 billion: US$7 billion on the Nikkei 225 equity contract and US$20 billion on Japanese government bond (JGB) and Euroyen contracts. Leeson had also sold 70,892 Nikkei put and call options with a nominal value of $6.68 billion, which had allowed him to generate up-front premium (positive cash flow) to offset any losses on the futures. The size of the Barings posi- tions was obviously huge, particularly when compared with the bank’s reported capital of about $615 million! The alarming size of the positions should have been clear to Barings’ management at the time. In January and February 1995, Barings Tokyo and London transferred US$835 million to the Singapore office to enable Leeson to meet his margin obligations on the Singapore International Monetary Exchange (SIMEX). The transfers were so large that Barings’ management was asked several times by the British Treasury why so much cash was being sent to Singapore. If the managers responsible had taken notice of these warnings and undertaken a proper investigation of the activities of the Singapore office at that time, the collapse of the bank might well have been averted. 145
    • The cash, or at least around US$500 million of it, was put down as loans futures to customers of Barings Futures Singapore. The credit risk implica- tion of the client advances represented by these ‘top-up’ balances would have been significant if the total funds remitted to Singapore were to meet genuine client margin calls. Yet the credit risk department did not ques- tion why Barings was lending over US$500 million to its clients to trade on SIMEX and collecting only 10% in return. It did not seem to have any idea of who these clients were, yet Barings’ financial losses would have been significant if some of these clients defaulted. After all, the bank’s capital was only US$615 million! No credit limit per client or on the total ‘top-up’ funds was set. Indeed, clients who were advanced money this way appear not to have undergone any credit approval process. The credit committee never formally consid- ered the credit aspects of the ‘top-up’ balance, although they could see the growth of these advances as recorded on the balance sheets. Plainly put, the credit risk controls of Barings did not exist. The fact that such important indicators as cash flow and credit risk were ignored is bad enough, but the management of Barings also broke one of the other key rules of any trading operation. They allowed Leeson to settle his own derivatives trades by putting him in charge of both the dealing desk (the front office) and the back office (the administration of derivatives trades). This is a clear breach of the principle of segregation of duties. To put it simply, the front office executes derivatives trades, while the back office records all the trade confirmations, settles the trades, checks them and assesses the accuracy of prices used for its internal valuations and marked-to-market reports (MTM). It also accepts and releases payments for derivatives trades. Since Leeson was in charge of the back office, he had the final say on payments, ingoing and outgoing confirmations and contracts, reconciliation statements, accounting entries and position reports. In other words, he was perfectly placed to relay false information back to London. Abusing his position as head of the back office, Leeson hid information in the now infamous ‘88888’ account. Barings London did not know of its existence because Leeson had asked a systems consultant to remove error account ‘88888’ from the daily reports which Barings Futures Singapore sent electroni- cally to London. The lack of segregation of duties at Barings Singapore office was perhaps the most serious failing of management controls. But what was even worse in this case is that some managers were fully aware of this position. Tony Hawes, the Group Treasurer, reported the unsatisfactory nature of the situation as early as February 1994, but nothing was done. He subsequently made his views known to James Baker, who undertook an audit of Barings in Singapore in July/August 1994. The internal audit report made specific recommendations on the segregation of job roles, but 146 ENERGY PRI CE RI SK
    • again there was a major control failure and none of the recommendations was implemented. Since Leeson controlled the back office and because Barings had no independent unit checking the accuracy of his reports, the market risk reports generated by Barings’ risk management unit were totally inaccu- rate. Leeson’s futures positions showed zero market risk because trades were supposedly offset by opposite transactions on another exchange (arbitrage between SIMEX and TOKYO). The unfortunate result was that Barings’ shareholders learnt the painful truth behind the saying ‘garbage in, garbage out’ because a system is only as good as the data put into it! Barings’ problems could also have been avoided if appropriate manage- ment had reviewed transactions and management information reports and held discussions with appropriate personnel about the nature of busi- ness transacted. Such approaches provide line management with an objective look at how decisions are being made and ensure that key personnel are operating within the parameters set by the organisation and within the ‘Internal Control Framework’ (ICF – the guidelines and policies for usage and reporting of derivatives in the organisation). But what really shocked the financial world and made a lot of compa- nies rethink their internal reporting and control structures was the simple fact that the Nikkei 225 and JGB futures contract that Nick Leeson traded were plain vanilla derivative instruments. As listed contracts, they were extremely transparent (unlike OTC) and Barings was required to pay (or receive) daily Initial and Variation margins and so needed funds from London. In January and February 1995 alone, Leeson asked for US$835 million. He could not hide his build-up of positions on the OSE because the exchange publishes weekly numbers. Other banks could see Barings’ enormous positions, and many assumed that the positions were hedged as arbitrage positions because such large positions were far too big compared to the bank’s capital base (US$615 million). Barings’ collapse is an extreme example of internal control and informa- tion system failures, all adding up to a massive unexpected loss. Deriva- tives can be very beneficial for organisations looking to control price risk or for companies looking to trade in the energy derivatives markets in a controlled environment. However, senior management of companies using derivatives must never disregard the guidelines and recommenda- tions which have been drawn up by practitioners, regulators and risk management advisors. THE LESSONS OF HISTORY Dealers and end-users should use derivatives in a manner consistent with the overall risk management and capital policies approved by THE LESSONS OF HISTORY 147
    • their Boards of Directors. These policies should be reviewed as busi- ness and market circumstances changes. Policies governing deriva- tives use should be clearly defined, including the purpose for which these transactions are to be undertaken. Senior management should approve procedures and controls to implement these policies and management at all levels should enforce them.’ This short paragraph was written by the G30 group in the early 1990s and it serves as a good starting point to explain controls for derivatives users. Particularly important is the recommendation that organisations should have a policy that defines the purpose of using derivatives; in other words, it should be clear whether they are being used for speculation or hedging. This is even more relevant in today’s market than it was at the time it was written, since even non-bank users of derivatives are now required to make accounting disclosures for derivatives. The accounting approach depends on whether the derivatives contracts are for hedging or speculation. This is an example of how controls and requirements are interlinked and how policies need to be reviewed regularly. Accounting and reporting regulations can modify controls and reporting require- ments to the outside world. Many control failures that resulted in significant losses for derivatives users could have been substantially reduced or even avoided if the Board and senior management of the organisations had established strong risk management controls. It is worth pointing out that the occurrence of deliberate fraud in organisations is very low; in the majority of cases the main problem is simple human error. By examining what could be termed derivative ‘disasters’, like the collapse of Barings, it can be seen that the typical control breakdowns have been in five broad categories: 1. Management control Senior management can weaken controls by promoting and rewarding managers who are generating profits but who fail to implement internal control policies or address issues identified by risk manage- ment reviews and internal audits. Such approaches send a message that internal controls are considered secondary to other goals in the organi- sation, and this in turn can reduce the commitment to and quality of its controls. 2. Risk assessment Companies which have sustained large losses in the past have often neglected to assess the risks of new derivatives instruments or trading activities. It is essential to review procedures and risk management systems when an organisation decides to move from using simple derivatives (futures, plain vanilla swaps) to more complex derivatives such as traded options, or OTC option structures. 148 ENERGY PRI CE RI SK
    • 3. Segregation of duties One of the main causes of derivatives disasters has been the lack of segregation of duties. This has sometimes occurred when senior management have assigned a highly regarded individual responsibility for supervising two or more areas with conflicting interests. For example, if one individual is supervising both the front office (execu- tion of derivatives trades) and the back office (the department where trades are reconciled and exception reports are generated for manage- ment information), then this person’s duties are clearly not properly segregated. 4. Reporting (communication) To have any chance of being effective, policies and procedures must be communicated to all staff involved in the use of derivatives. Senior management should ensure that the organisational structure and management accountability are clearly defined. Sometimes losses in companies have occurred because key staff have not been fully aware of the derivatives usage policies of their own organisation. As a result, activities that were outside the scope of the authorised usage of deriva- tives were never reported to higher management. Until it was too late! 5. Reviews/audits There have been cases in which auditors or internal reviews have exposed weaknesses in a company’s controls or reporting structures but these have been ignored by senior management. CREATING A RISK MANAGEMENT OR TRADING POLICY The risk management and trading policy parameters for the usage of derivatives will vary from organisation to organisation, but here are some key guidelines and key stages that can help. Component 1 – Board level approval The Board of Directors should establish and approve an effective policy on the use of derivatives which is consistent with the strategy, commercial objectives and risk appetite of the underlying business and should approve the instruments to be used and how they are to be used. The Board of Directors should: 1. Review the proposed purpose and use of derivatives. 2. Ensure that this is consistent with management capabilities, financial position and commercial objectives, including any legal restraints. 3. Approve a list of derivatives and agree the reason for using them. 4. Ensure that the appropriate policies and control procedures are in place. CREATI NG A RI SK MANAGEMENT OR TRADING POLICY 149
    • 5. Implement an independent review of risks and rewards. 6. Nominate two or more Board members to be responsible for derivatives. 7. Regularly review actual derivative usage. 8. Ensure that management reports are fit for purpose. 9. Ensure on-going training of key personnel. Component 2 – policies and procedures Senior managers should establish clear written procedures for imple- menting the derivatives policy set by the Board. These should cover: 1. Trading authority – who can trade and what they can trade. 2. Management reporting lines. 3. Position limits in derivatives markets. 4. Counterparty approvals. 5. Documentation approvals. 6. Valuation procedures. Checklist: 1. Appoint a senior manager to be responsible for policies and procedures. 2. Design and document limits for market and credit risk. 3. Design and document procedures for when limits are passed. 4. Design and document procedures for approving brokers or counterparties to be used. 5. Ensure that accounting policies have been established. 6. Ensure that all taxation implications have been considered. Component 3 – control and supervision Senior Management should ensure that derivative activities are properly supervised and are subject to a clear framework of internal controls and audits to ensure that derivative usage is in compliance with corporate policy (and external regulation in the case of a financially regulated institution). Checklist: 1. Regularly review the level of expertise in the organisation. 2. Perform an independent review of the internal controls. 3. Ensure that management reports are fit for purpose. 4. Examine computer systems and check they are robust and cannot be amended by unauthorised personnel. 5. Ensure regular internal audit checks. Component 4 – organisation, roles and responsibility Senior management should establish a sound risk management function providing an independent framework for reporting, monitoring and controlling all aspects of the risk matrix (see Chapter 1). 150 ENERGY PRI CE RI SK
    • Checklist: 1. Allocate very clear responsibilities to individuals using organisation charts and clear job descriptions. 2. Use appropriate market risk and valuation techniques. 3. Ensure that all significant limit excesses are reported to the Board of Directors (in exception reports). 4. Perform price movement stress testing to assess the effect of abnormal market movements on positions. Component 5 – credit procedures All credit risks to which the organisation will be exposed should be measured and analysed, and these risks should be minimised through the use of effective credit management (e.g. collateralisation of positions with credit weak counterparts, credit defaults derivatives, credit insurance). Checklist: 1. Analyse the risks inherent in both exchange-traded and OTC derivatives. 2. Minimise credit risk through netting agreements and other techniques. 3. Establish credit risk limits in derivatives markets (overall limits) and counterpart by counterpart limits. 4. Establish procedures for authorising credit limit excesses. Decide on the person responsible for giving approvals and the person who will depu- tise in his or her absence. 5. Establish policies and procedures in the event of a counterparty or broker becoming insolvent. If positions are held in futures markets with a broker, the organisation’s funds should be segregated from the oper- ating capital of the broker. This is the regulatory norm these days, but it is worth checking the agreements with the broker, as it means that the funds are protected if the broker goes bankrupt. Component 6 – legal and documentary Procedures should be in place for monitoring legal risk, covering legal capacity, authority, compliance and the need for the appropriate documentation. Checklist: 1. Establish that the organisation has the power (internally and exter- nally) to use derivatives in the manner envisaged. 2. Ensure that the authority to deal in derivatives is delegated to the appropriate staff. 3. Complete a list of authorised existing and potential brokers and counterparties. Note any restrictions. 4. Obtain warranties from each broker or counterparty as to its power to deal in derivatives. CREATI NG A RI SK MANAGEMENT OR TRADING POLICY 151
    • 5. Review documentation. 6. Use master trading agreements for OTC derivatives. The use of stan- dard ISDA agreements for cash-settled OTC deals will mean that an organisation will have access to lots of legal and other expertise on matters relating to their derivatives deals. This can help keep up-front legal costs down as well as creating greater legal assurance and certainty in situations of default or disputes. 7. Ensure that margin or credit arrangements are well documented. All of the guidelines and information compiled from these components of the management control matrix will help an organisation to produce a risk management policy document (sometimes referred to as a risk management or derivatives usage procedure manual). This should be distributed to all heads of business units in the organisation and to all front office and back office staff. The policy document will enable staff to conduct their day-to-day activities effectively, referring to the document as required to ensure they are operating in line with their organisation’s operating procedures. A section on management reporting lines in the policy document should clearly inform staff who they should report to for special approval if they need to take any action involving derivatives contracts that is outside the normal boundaries set by the risk manage- ment policy document. CORPORATE DERIVATIVES RISK MANAGEMENT POLICY AND PROCEDURES DOCUMENT The primary components of a sound risk management process are: ■ A comprehensive risk measurement approach e.g. VAR. ■ A detailed structure of position limits. ■ Guidelines and other parameters used to control the usage of deriva- tives (either for hedging or speculative purposes). ■ A strong management information system for controlling, monitoring and reporting risks. By expanding on these primary components we can illustrate the key contents of a typical derivatives policy or manual. Example of key contents in policy document 1. What is the organisation’s purpose in using derivatives? ● Speculation (to take advantage of risk opportunities)? ● Hedging (to reduce price risk exposures)? ● Both? 152 ENERGY PRI CE RI SK
    • 2. What type of derivative instruments is the organisation willing to utilise? ● On-exchange futures. ● On-exchange options (traded options). ● OTC swaps. ● OTC option (exotics). 3. Which markets can the organisation’s traders utilise? ● What are the limits of the derivatives positions? ● Overall company-wide position limits. ● Individual trader limits. ● Position limits for each of the energy derivatives markets that traders have access to, in order to control liquidity risk. 4. What percentage of the energy exposure should be hedged? ● The minimum amount to be hedged. ● The extra volume allowed for opportunistic hedging if prices are within budgets. 5. What are the limits on the tenure of derivatives utilised? ● This may be listed by energy derivatives market. The decision on how far forward traders can trade in a particular market will depend on counterpart credit worthiness and the general liquidity in the market. 6. Which counterparts are used for OTC? ● A list of authorised counterparts regularly updated and passed to traders (front office and back office) to prevent accidental unauthor- ised trades. ● Clear policy on credit quality required for counterparts in OTC markets. 7. Policy on types of legal documentation that must be in place prior to any derivatives trading commencing with new counterparts. 8. Management reporting lines ● A clear diagram showing reporting lines will help front and back office staff and management handle problems quickly and efficiently. 9. Reports to be generated daily ● A list of reports and who is to produce them on a daily basis; e.g. exception reports, position reports, profit and loss reports. 10. Exception reports ● Clear policy on who is to see these reports and who must sign off and be responsible for taking action to resolve matters. BACK OFFICE SYSTEMS An organisation may succeed in putting in place a clear management and reporting structure, with a written risk management policy that all staff BACK OFFICE SYSTEMS 153
    • are familiar with, but all this effort will have been wasted if an appropriate back office system is not in place. The back office is vital for protecting an organisation, as it is where all data on trades are collected, where positions are valued each day and where core management information reports are generated (e.g. exception reports). Any back office or control system is only as good as the quality of the data inputted. These inputs can be summarised as follows: ■ New transactions. ■ Exercises (options that expire and create a new swap/futures position or even exercise into physical). ■ Market price data. ■ Close-outs and settlements. ■ Deliveries. ■ Receipts and payments. ■ Data on any documentary credits/guarantees from trading counterparts – values, expiry, type. Controls of input data Whether a reporting/control system is manual or computerised, the proper control and validation (double checking) of input is essential (Figure 9.1). Responsibility for particular input tasks should be clearly allocated, with password control used for screen operators. Input routines should require a standard format containing all relevant detail for a new transaction (e.g. date, counterparty and full transaction data – volume, settlement and price). Source documents (trading tickets from trading desk) should be time-stamped, or otherwise marked to indicate the time of execution, and then also marked by the back office to indicate that they have been inputted. All input should be subject to validation routines (e.g. 154 ENERGY PRI CE RI SK Trader writes deal ticket Back office collects trade ticket every 15 minutes or 30 minutes (banks) Back office inputs deal ticket in to system Trade comes to settlement Information printed out Re-typed in to Accounts system Payment due so payment instruction then typed into banking system or manually requested Back office retypes data into accounting system; Accounts then request guarantees from counterparty if required FIGURE 9.1 Controls of input data
    • computer proof listings of new transactions entered requiring confirma- tion or validation prior to updating the main transaction records). A unique reference number should also be assigned within the system to each item of validated input – on most occasions this number is the actual ticket number written out and time-stamped by the trader on the trading desk. Straight through processing Some companies are already moving towards what is known as straight through processing, or STP for short (Figure 9.2). Futures markets are very close to this already with trades from the exchanges going into Clearing House systems and Clearing Broker member systems automatically. The OTC market is slowly moving this way too, with several organisations starting e-confirms for OTC derivatives transactions. These allow confir- mations of deals done on and off electronic trading platforms to go straight into counterpart back office and risk management systems. OTC is generally still recapped by postal confirmations and faxes. By reducing the human involvement in the trade processing and back office manage- ment, companies are already trying to reduce the risk of human error in inputting deal data. According to the International Swaps and Derivatives Association (ISDA;Operational Benchmarking Survey Summary), many organisations are now well on the way to implementing STP as a key part of their back office systems. The Association’s 2002 Operational Benchmarking Survey BACK OFFICE SYSTEMS 155 STP Trader types in deal information direct in to back office system All system records updated and reports generated automatically Deal comes to settlement System automatically invoices counterparty or notifies accounts of payment due and bank Bank notified to make payment or receive payment confirms process actioned electronically Back office monitor Systems sends request to Accounts/ Treasury, perhaps to request Documentary Credit against a particular counterparty position FIGURE 9.2 Controls of input data (reduction in human error risk through multiple to different systems)
    • Summary was based on responses from 65 firms around the world and reported that: ■ Front office trade data is available for same day processing as follows: 100% for forward rate agreements; 98% for plain vanilla swaps. ■ Errors in front office trade data, which most commonly occur in dates, are more common for credit derivatives (21%) than for FRAs (10%) and plain vanilla swaps (17%). It appears that plain vanilla swaps are more automated than credit and equity derivatives. It is also interesting that the most common results are either no automation or substantial automation, suggesting an ‘all or nothing’ approach: that is, once a firm institutes some automation for straight through processing, it applies it across the company. Functions with a high degree of automation include the transfer of data from the front office to the back office operations systems, transfer of trade data from the operations system to the general ledger and addition of data to the front office trade record. Reports and records Transaction records A back office system should create and maintain complete records of all transactions and should be able to break up reports between trader, counterparty (for OTC products), the product traded, trade/executed date, volume, time traded, and broker used, where appropriate. Position records With open positions, it is essential that each input transaction settlement is accurately reflected in statements of position. Margins and equity Exception reports assist effective monitoring by highlighting potential risk situations, such as: ■ Position limits being broken. ■ Counterparty’s equity falling below a certain level. ■ Contracts nearing delivery date (futures) or expiry (options), or pricing out (swaps). Counterparty documentation Appropriate counterparty documentation should be generated for the confirmation of contract (on a daily basis) settlement account, to advise counterparty of details of contracts closed out (netted off) or priced out and the profit or loss agreed and then settled between counterparties. Management information/risk manager This individual should deal with: 156 ENERGY PRI CE RI SK
    • ■ Exception reports and positions close to expiry. ■ Critical area – knowledge of different delivery processes for on- exchange derivatives such as futures is vital. ■ Position reports. ■ Profitability reports presented in various ways, e.g. ● by department/individual trader ● by market/product ● by period – showing performance trends ● value at risk for the firm – calculations Who should look at the report and records? In most medium to large organisations, a corporate treasurer or risk manager is responsible for identifying and managing risk. Where the scale of the trading or risk management activity is not sufficient to justify a separate independent risk management function, responsibility for moni- toring risk is usually allocated to members of management who are not directly involved in the day to day management of risk (e.g. traders). Derivative back office management It is essential to have tight security on back office systems. A company should not rely on just one risk manager or person to monitor or pick up errors. It should also have a system that prevents people who are active in the risk management and trading areas from altering records. To check for irregularities, some banks and brokers have asked their employees to take at least five consecutive business days as holiday at short notice. The person who takes over has a good chance of picking up on mistakes that have been made through operational error, losing posi- tions which have been concealed or, indeed, fraud. This should certainly allow the organisation to expose skill shortages in the organisation and perhaps target staff for further training so that the organisation is not over reliant on any particular individual. Internal controls and the back office Here is the basic framework of internal controls that any back office system should be able to support: ■ Risks ● Business risks ● Position risks ● Human and operational risks ● Credit risks ■ Fundamental controls ● Authority levels and limit setting features ● Automatic exception reporting and monitoring of position limits ● Profitability reporting BACK OFFICE SYSTEMS 157
    • ■ Organisational controls ● Legal considerations ● Policy monitoring ● Segregation of duties and the operation of internal checking ■ Position risk ● Trading, types of derivative ● Limits in markets ● Limits with counterparties (OTC swaps) ● Monitoring and reporting against limits ● Hedge reporting ■ Counterparty authorisation ● Back office system should preferably be integrated with the trading desk in order to stop trades being finalised with counterparties who have already exceeded credit limits or position limits. ● Remember that when your traders agree the deal, it doesn’t matter whether it is a futures trade or OTC swaps trade on the telephone: your firm is committed! ■ Counterparty setup ● The credit department or risk manager should be the only people able to set up new counterparts on the system. They should also be the only people with access to setting trader and counterpart position limits. Ideally the back office system should be able to automatically produce an alert or print-out of exception reports (e.g. loss limits, counterpart credit limit breaches and internal trader position limit breaches). Operational risk and the back office It is difficult to talk about internal control systems without looking at the structure of back offices. Operational risk then comes into play when designing the back office. One definition of operational risk is the risk of loss caused by failures in operational processes or the systems that support them, including those adversely affecting reputation, legal enforcement of contracts and claims. Thus it is important to structure the back office system in such a way as to help prevent underlying causes of operational risk and, in turn, to keep internal controls and risk management processes operating effectively. (Refer to Chapter 11 for more data.) ROLE OF EXTERNAL OR INTERNAL AUDIT AND COMPLIANCE Derivative operations should be subject to periodic reviews (e.g. quar- terly, half yearly) by the company’s internal audit function or external auditors if in-house expertise for this is not available. 158 ENERGY PRI CE RI SK
    • It should be the responsibility of the Board of Directors of the company to ensure that internal audit and compliance department (if applicable) are staffed with personnel with sufficient skill and expertise to undertake reviews of the company’s derivative operations. The exact role of external auditors and the processes that they use will vary from country to country. However, auditors should check that financial statements are free from material misstatements, and check the derivative transactions and records supporting financial statements and balances and disclosures. An external auditor should assess the accounting principles used for derivatives, and also comment on the scope, adequacy and effectiveness of a company’s internal control system and derivative pricing methodologies (if any), including any internal audit approach/system that exists. Reconciliation and accounting: key points for management to consider Large profits that are not properly understood can often be a bigger danger than large losses that are understood all too well. Derivatives disasters have shown that people who never take holidays or who always stay late are not necessarily great examples of dedication to their jobs. Their ‘work lifestyle’ may be covering negative business realities. Accounting entries can be manipulated; cash disbursements cannot. Cash is the fundamental control, so make sure it adds up. Unfortunately, more often than not, accounting losses reflect a business reality. Last but not least, computer systems should be carefully monitored. Computers are an open door to the very nerve centre of a business. It is important to ensure that there is good security on the network and that computer data is backed up as often as possible, preferably off-site. A RISK MANAGEMENT REVIEW A risk management review is something that should be done on an annual basis at the very least. Its purpose is to gather guidance for management on ways to improve existing operational procedures and controls, or to highlight lack of controls in specific areas where regulations may have changed since the last time risk management policies were reviewed. This review is usually carried out by an independent external consul- tant or, if available, risk management staff from another office could take up this task if you operate in a large international organisation, as long as those conducting the review are considered independent of the operation they are reviewing. Risk management reviews, unlike audits, focus on providing valuable feedback to management so that they can improve processes and controls to keep up with the latest industry and (where appropriate) financial A RISK MANAGEMENT REVIEW 159
    • regulatory guidelines. They tend to rely more on verbal representations from staff than an audit. Most large accounting firms, when auditing companies, look at trading controls and reporting structures and quite often auditors will make comments or notes in their annual accounting reports. An example of a risk management procedure review can be found in Appendix 1. THE COLLAPSE OF ENRON, 2001 No single factor brought Enron crashing down to earth from its sky high success. The involvement of key individuals like Jeffrey Skilling (the former CEO of Enron), Kenneth Lay (the former chairman and CEO), and Andrew Fastow (the former Chief Financial officer of Enron) is already well documented so this section is not going to focus on individuals but on the general failure. So, what were the possible combinations of factors in the failure of risk management processes that were contributory factors to Enron’s downfall? The framework of the five key internal controls as illustrated in Figure 9.3 can be used to answer this question. Management oversight control culture The problems at Enron were top-down; no single rogue trader was present as in the case of Barings Bank. There were position controls and state-of-the-art risk management systems in place to document sophisti- cated derivatives instruments and trades. However, management had been spurred on by stock option profits to develop an expansionist culture at (it would appear) any cost. For Enron, this meant expansion in terms of 160 ENERGY PRI CE RI SK Management oversight Control culture Risk assessment Controls Information and Communication Monitoring FIGURE 9.3 Internal controls consist of five key interrelated areas
    • revenue and markets covered, and new market activities were seen as positive and good for public relations. Also, in the boom years of the dotcom era, stock investors were focusing on percentage revenue increases to boost stock prices. Enron’s employment culture affected its risk management culture. Its hire-and-fire policy meant that employees had to operate in an internal cut-throat environment where they not only had to compete with the outside market, but were in constant strong competition with colleagues with the threat of unemployment continually hanging over them. In this working culture, most employees were afraid to express their opinions or to question unethical and potentially illegal business approaches. If they reported these to the senior managers who were creating this environ- ment, they risked getting fired. No reporting structure can save a company if the top management are the ones at fault. Shareholders of trading companies should ensure that the management are operating truly independent audit operations, not only for accounting but also for risk management procedures and the handling of derivatives. One possible route for restoring shareholder confidence in a shaken-up industry could be to offer the staff and management of trading companies access to external auditors if they feel they ever have a concern over busi- ness practices in their organisation. It has also become even more popular to introduce business ethics training across trading organisations post- Enron. Risk assessment Enron may have had sophisticated risk management systems, but the expansionist policy pushed by senior management to generate bigger and bigger revenues to fuel the share price accelerated Enron’s move into markets in which it had little experience. It was reported that in every Enron trading room around the world there was a price ticker screen showing the Enron stock price to staff. This policy flouted the funda- mental principle of risk management: ‘know your market’. It is essential for companies to ensure that they have sufficient internal expertise and resources to manage derivatives or trading in these new markets. However, because the focus at Enron was always on the share price, risk assessment took second place. The biggest illustration of this was Enron’s move into bandwidth trading (the trading of telecom time etc. via cable). Enron’s rapid expansion into new markets placed it at a disadvantage against more experienced players in those fields and in turn put Enron at risk of big losses. From Enron’s core business of natural gas, oil and power trading, it ended up in new, low liquidity rather esoteric markets such as sea freight, pulp and paper, Japanese aluminium, and Australian and Japanese weather derivatives, as well as bandwidth. THE COLLAPSE OF ENRON, 2001 161
    • Controls In the case of Enron one big failure of controls appears to have come from the lack of appropriate external regulatory controls that allowed Andersen Accounting to audit and also consult for Enron. This meant there was a clear lack of segregation of duties and, for fear of losing very profitable consulting business (compared to the lower fees from accounting auditing), it is thought that a lot of tough questions on how Enron was operating were never asked by Andersen. What can we learn from Enron? It is relatively easy for the management of a company to develop a risk culture that rewards people by increasing revenues in any way possible. The company can simply hire the brightest graduates and give them the resources they need. They will build revenues and push the stock price through the roof. However, as Enron shows, this is not a sustainable busi- ness practice. Enron has also shown that we must question how independent advisors and auditors really are. Truly independent external auditors have a key role to play in the trading arena to help ensure that shareholders are noti- fied if companies overstep the mark. Shareholders can then make an informed decision as to whether or not to support the company. Ulti- mately, it is up to the owners, the shareholders of companies, to ensure that their interests are being served correctly by an auditor. If we look at Enron, shareholders were blinded by massive returns on their shares, with the share price moving from around US$20 per share in the early 1990s to a peak of around US$90 per share in 2001. In the case of Barings Bank, management did not hear the concerns and questions raised by the British Treasury about the large amounts of money being sent to Barings Singapore, as they were blinded by the huge false profits they thought were being made by Nick Leeson. It would seem that a pattern is emerging here. A lot of people rode on the success of Enron, and a lot of questions were not asked because everyone thought it was doing so well that they did not want to rock the boat. But it is also important for management to create a balance. Excessive controls can lead to an oppressive control culture in a firm and that in turn can inhibit new ideas and creative thinking which can positively benefit an organisation. It is not easy for management to create the right balance. However, it seems that some basic truths have emerged. When a firm starts producing 250% increases in revenues (as was the case at times for Enron) or when a firm starts creating massive profits from a small division in an overseas subsidiary in the case of Barings, ask questions! In the Enron case, questions have been raised about the role of Andersen who were both consulting and also auditing for them. To restore shareholder confidence over financial statements, management 162 ENERGY PRI CE RI SK
    • could ensure external auditing activities are carried out by firms not serving the company in other ways that may create a perception of conflicts of interest. In the case of risk management using derivatives, if financial auditors do not have the expertise, a specialised external risk management auditing firm could be employed to review mark-to-market methodologies and to highlight any shortcomings of these methodologies that may create potential risks for the organisation. Post Enron, politicians and regulatory bodies are calling for senior management of organisations to be far more accountable if things go wrong. So it is now more important than ever to have regular risk manage- ment reviews and an open culture where people can question what the company is doing and how it is doing it. Firms should also foster a culture where management are seen to be receptive to well-founded and constructive criticism as well as new ideas from staff. THE COLLAPSE OF ENRON, 2001 163
    • CHAPTER 10 An Eavesdropper’s Guide to Hedging Perhaps the only people who truly understand hedging are those who see it as a branch of horticulture. Certainly, there are many myths and misun- derstandings that surround hedging in the financial world. Here are a few things overheard in the corridors, boardrooms, back offices and trading pits of the world’s corporations and exchanges. The names, of course, have been withheld to protect the guilty parties! NINE GREAT SAYINGS ON HEDGING HEARD IN THE MARKET – WITH COMMENTS 1. ‘We’re not hedging this year because we lost money doing it last year’. Hedging is not about making money all the time. For consumers of energy, it is about consistently reducing balance sheet volatility. For traders, hedging may be to lock in profits or to reduce loss exposure, and as a producer of energy it could be part of an overall strategy to hit sales and profit targets. Hedging should not ‘lose’ an organisation money. It may generate loss of opportunity in economic terms, but if it is true hedging that is being conducted, there should be an almost equal and opposite cash flow in the energy physical consumption or produc- tion activities of the company. It is very important that management and shareholders fully appreciate this. 2. ‘Go ahead and hedge... just don’t do anything stupid!’ I guess the manager who said this had not put together a risk manage- ment policy! It is very important that before embarking on any hedging (or derivatives speculation, for that matter), that an organisation has a clear written policy of ‘do’s and ‘don’t’s, including a clear written reporting structure and control structure to ensure trading or hedging 164
    • does not get out of control and too big. There is more detail on this in Chapter 9. 3. ‘Our risk management committee can’t agree on whether energy prices are going to get stronger or weaker.’ Now, hold on a minute! The main reason for hedging is that no one knows where prices are going to move over the next financial year. In fact, just trying to predict energy prices over the time frame of one week is pretty impossible. Looking at operating budgets as a consumer or targets as a producer should enable management to work out some strategy for hedging some percentage of exposure or profit margin now, and to develop some game plan around ‘What if?’ scenarios for further hedging activity subject to market price movements. 4. ‘Sometimes we hedge 0% and sometimes we hedge 100%. Other times, we go back and forth.’ Again, this is not a very effective risk management policy. Either hedge or don’t hedge at all and take the risk. By having no clear policy you can create many other problems for an organisation including proper cash flow management and forex management etc. 5. ‘We only hedge when we have strong views on the market.’ Only hedging when you have a strong price view is not hedging but speculation. It is probably fair to say that an organisation should have some overall percentage volume hedge locked in before going into its next financial year (as an end-user consumer). Even large oil majors who control a lot of energy market infrastructure – pipelines, refineries, oil fields – do not always get the market direction right! Sometimes a hedger may initiate some additional hedges if there are strong views that an upcoming event could create a very big market move. In this case, it may be worth examining option strategies so the loss of opportu- nity risk is reduced to premiums paid for the options. 6. ‘Our hedging program is great. It consistently makes us money!’ I would be worried if my hedging program always made money. It would mean there could be something very fundamentally wrong with the way I was trading physical markets, or buying or selling my phys- ical energy as a consumer or producer. 7. ‘Our management is in favour of doing some hedging, but not at these prices.’ If only the management had looked at hedging before the market got to these prices! In cases where either profit margins are negative or margins are expected but not guaranteed to improve in the near term, option hedging structures can enable companies to protect against the situation becoming worse, while still gaining from improvements in NINE GREAT SAYINGS ON HEDGING 165
    • margins and or prices. For example, for an extended period of time in Asia, oil refiners experienced reasonable margins on middle distillates such as gasoil and jet fuel. However, fuel oil was a loss maker. In this instance, refiners could look at an option structure which protected them against fuel oil versus crude oil margins becoming still worse, but would allow them to benefit from an improvement in the margin back to profitability. 8. ‘Hedging is too expensive; I cannot afford more staff to conduct this hedging business.’ Which is really more expensive: seeing the organisation’s profit margin disappear and become negative altogether, or having some comfort knowing that some of your profit margin/revenue has been safely guarded against the unknown? 9. ‘We never speculated. We just simply over-hedged our physical requirements.’ There is not such thing as over-hedging. If an organisation or trader deliberately hedges using a greater volume of derivatives versus phys- ical energy flow this is over-hedging. The only exception to this rule is when an organisation is having to ‘proxy hedge’. This could mean that they are having to use a derivative contract on a different energy product than the energy they are actually physically exposed to or wish to trade in. Sometimes, because of basis risk, traders are forced to use a greater volume in the derivative than in the underlying physical energy, to try to compensate for the basis risk between the two. In other words, the energy derivatives contract may be less volatile than the underlying physical that the organisation is trying to hedge. CONCLUSION October is a particularly dangerous months to buy the market. Other particularly dangerous months are July, January, September, April, November, May, March, June, December, August and February! The truth is that most people who try to predict the movement of the energy market get it wrong some of the time – and there are some people who always get it wrong! 166 ENERGY PRI CE RI SK
    • CHAPTER 11 Operational Risk Operational risk: ‘Risk of loss caused by failures in operational processes or the IT systems that support them, including those adversely affecting reputation, legal enforcement of contracts and claims’. Until fairly recently, energy price risk management focused mainly on market risk, liquidity risk and credit risk. But over the past few years, there has been a new focus on operational risk, particularly after some big fail- ures in the financial commodity markets, like the Barings Bank collapse in 1995 and the Sumitomo Corporation’s losses in metals in the late 1990s. Most organisations can be affected by operational risk in a number of ways, both directly and directly. Direct financial losses can be caused by a lack of operational capability to transact business. For example, losses could result from a fire at an organisation’s offices, or from a back office computer system being unavailable due to a hardware failure. An error in a transaction can also lead to direct losses: if an organisation loses the data that proves a deal has been transacted, the company may be exposed to market price movement and lose money in this way. Indirect losses may be the result of damage to an organisation’s reputation or client relation- ship. For example, if a broker has an online trading system which breaks down, this could have both a revenue loss and also an indirect loss as customers lose confidence in the system and don’t come back to use it again. KEY COMPONENTS OF OPERATIONAL RISK Core operational capability The most obvious kind of operational risk concerns the risk of loss or damage to an organisation’s core operational capacity. This can be the result of a number of events, including: ■ Damage caused by fire, bombs, technical problems or all manner of natural disasters. 167
    • ■ Loss of utilities such as power, water or transportation. ■ Loss of key operational personnel. ■ Inadequacy or loss of systems capabilities, e.g. due to computer viruses. Human risk People are a company’s most important resource, but they have often been overlooked when evaluating operational risk, as it is difficult to apply a mathematical model to measure the risks of human error. However, it is possible to make a brief list of the most probable reasons for human error: ■ A lack of integrity and honesty. ■ A lack of segregation of duties and the risk of collaboration. ■ A lack of professionalism. ■ A lack of teamwork and respect for the individual. ■ Over-reliance on a few key individuals who may go on holiday or be sick at crucial times, or who may leave the company altogether. ■ Insufficient skills, training, management or supervision. Human error continues to be the major contributory factor to many dramatic corporate failures. For this reason, it must be targeted, despite the difficulty of measuring it. It is certainly a common cause of problems in the back office, so a well-designed system and a process of internal control to pick up on any input errors quickly will save a lot of time chasing prob- lems later on. Transaction processing systems The quality of data is vital in risk management. Any sound risk manage- ment program relies heavily on accurate, prompt and efficient capture of trade data and the creation of management reports from processing this data. The most important areas to look at under transaction processing system risks are (Figure 11.1): ■ Processes associated with the execution of trades. ■ Trade capture (sometimes referred to as data capture) and the processing of data. ■ Trade confirmation (contracts). ■ Settlement operational risk. Here, settlement operational risk is different from settlement risk. Settlement risk is associated with the credit risk of a counterpart – the risk that someone may not pay up on a settlement of a trade. However, settle- ment operational risk focuses on losses that can be caused by errors in the settlement process. 168 ENERGY PRI CE RI SK
    • Reconciliation and accounting A well-structured back office system that is integrated with an accounts system is crucial for managing risks associated with reconciliation and accounting. It is important for treasury or accounts people to have at least read-only access to back office transaction data in order to anticipate any foreign currency requirements against derivatives margin payments or realised losses on hedges and to allow them to ensure that adequate forex hedging risk management is carried out. The reconciliation of settlement data with funding and accounting results is also a key process in protecting the user of derivatives against undisclosed positions or undis- closed losses within its organisation. See Figure 11.2 for a summary of operational risk. ASSESSING AND CONTROLLING OPERATIONAL RISK The core objective of an operational risk program should be to avoid finan- cial and non-financial losses through operational risk failures. To do this, the program should enable the organisation to anticipate risks by more efficient and effective measurement and reporting of operational risk. This can be achieved through the following five-step approach. Step 1: Identify the risks An organisation must identify its operational risks. It can identify these by looking at the tasks its department has to handle and the processes ASSESSI NG AND CONTROLLING OPERATIONAL RISK 169 Derivatives trade execution and ‘Order capture’ Credit risk control system Price risk management system Collateral/ margining system Trade settlement processing system Contracts and confirmations Trading book accounts system treasury system FIGURE 11.1 Derivatives process environment in which OR exists.
    • 170 ENERGY PRI CE RI SK Operational risk Operational failureBusiness environment strategy risk • People • Technology (IT systems) • Organisation/business processes Risk of choosing the wrong business strategy in response to factors including: • Tax • Government • Regulations • Competition AREAS THAT MAY CONTAIN OPERATIONAL RISK ■ Process risks ● Marketing ● Selling ● New customer ● Trade execution/processing error ● Trade fraud ● Contract/trade recapping risk ● Product complexity ■ Technology risk (process risk) ● Data corruption (either by accident or deliberately) ● Programming errors ● Viruses ● Telecommunication failures ● System capacity risks ● System failure ● Strategic risks, i.e. the system provider goes bankrupt and cannot support a system any further ● Security breach, e.g. external hacker attack ■ Human risks ● Fraud ● Collusion between people to commit fraud ● Unauthorised use of information ● Rogue traders ● Staff competency/skill sets ● Over-dependency on a few key personnel ● Health and safety ■ External business environment risk ● External supplier risk ● Physical security ● Compliance ● Money laundering ● Tax ● Financial reporting/ accounting standards ● Natural disaster – fires, floods, weather ● Strikes – transportation problems ● Legal risk (litigation) ● Terrorist threat FIGURE 11.2 Operational risk
    • undertaken by the organisation in its day-to-day trading and business operations. Step 2: Assess the risks Once this has been completed, the operational risks need to be categorised in terms of possible severity (e.g. if the core risk management system went down, it would take around 5 hours to get a backup system running) and in terms of the probability of these operational risks actually happening. Step 3: Assess possible risk control measures An organisation should then list the operational control choices it can make that can help reduce the identified operational risk. The four main control decisions that can be made by an organisation are as follows: ■ Avoid the risk Totally avoid the business activity that is creating the risk. ■ Transfer the risk An organisation could look to transfer the risk. A prime example of this is where a firm takes out ‘rogue trader’ insurance. This transfers the operational risk of fraudulent trading into a credit risk with the counter- part to the insurance policy. Insurance is a key way to transfer a large majority of operational risks. ■ Reduce the risk Changes in the way business is conducted in the organisation (referred to by experts as the ‘transaction chain’) can help to reduce risk. The other key way is by allocating more cash or capital to systems and human resources (skills training updates and more personnel to cover risk areas). ■ Accept the risk An organisation’s research may have found that the probability of a particular operational risk event occurring is so remote that the company decides just to accept the risk. This normally happens when the cost of implementing new procedures or systems far outweighs the risk to the company. Step 4: Execute control measures If action of some kind is taken, someone needs to follow up and make sure that implementation of new measures is executed correctly. Step 5: Create supervisory role(s) to monitor the ongoing risk A supervisory role needs to be established. The person or persons respon- sible for the operational risk program should write management progress reports (see Figure 11.3) and comparison studies on any reduction of losses associated with operational risk, to illustrate the effectiveness of the ASSESSI NG AND CONTROLLING OPERATIONAL RISK 171
    • program. Management should discuss these reports and if no appropriate response is taken to any risk event, they should, of course, create some strategy to prevent it occurring again. Operational risk programs should also be reviewed regularly (probably at least twice a year) to accommodate any changes in external business environments, the general business activities of the company and the size of those activities. GATHERING INFORMATION ON OPERATIONAL RISK It is essential that organisations gather as much information as possible on operational risks. This can be done by interviewing business and operational 172 ENERGY PRI CE RI SK Page 1 Losses Current month Year to date Operational losses Credit losses Market losses Subtotal: Loss/revenue ratio: Page 2 Risk events Event Exposure Response 1 IT system failure Lost revenue of US$2 million New backup system put in place 2 3 4 5 6 7 8 FIGURE 11.3 Monthly risk reporting example (incorporating OR)
    • line managers who may reveal concerns over potential operational risks that have not yet occurred but could unless action is taken. The following company reports and documents should also be reviewed with operational risk in mind: ■ Management reports (these may have highlighted operational prob- lems and issues in the past). ■ Budgets. ■ Business plans. ■ Operations plans. ■ Disaster recovery plans (if an organisation does not have one, this is an immediate source for operational risk – business recovery). ■ External reports. ■ Audit reports (increasingly, financial auditors are looking at operational risks in an organisation that may add potential points of failure. Rating agencies also focus a lot on operational risk issues when assessing a company’s credit rating). ■ Any regulatory reports (if an organisation is a regulated entity in some way). ■ Historical data on losses (especially in transaction errors etc., where losses were posted against specific operational failures). OPERATIONAL RISK REDUCTION, CONTROL AND CONTAINMENT Risk reduction In any operational risk program, the first steps that management can take are to reduce the risks inherent in the organisation’s business processes. Wherever possible, retyping of data by human operators should be elimi- nated from the process, by integrating existing IT systems or investing in new ones. Hiring additional staff will also help to reduce dependency on key individuals and reduce the pressure on understaffed areas of the busi- ness process. Risk control Appropriate preventative measures can be taken to minimise the chance of an operational risk situation occurring. For example, operational system risk could be controlled by introducing or improving firewalls, passwords and authorisation processes surrounding trading and who is allowed to trade. Internal audit checks can be introduced and control functions can be assigned to specific staff with a responsibility for main- taining control standards. OPERATI ONAL RI SK REDUCTION, CONTROL AND CONTAINMENT 173
    • Risk containment and transfer Tightening up procedures and investing in IT systems, automation and staff will certainly reduce an organisation’s operational risk. But such risks can never be completely eliminated, which means that it is also important to have ways of containing those operational risks that still remain. An organisation can buy insurance against loss of revenue from fire, flood or other natural disasters at the organisation’s office. Insurance like this transfers operational risk over to a credit risk of the insurance company. It can also look at computer disaster recovery procedures and business continuity planning. For trading companies this could entail setting up a hot backup site which staff could move to if the primary office location was non-functional. The importance of this was seen in the after- math of the disaster of 9/11 in which the World Trade Center was destroyed. A lot of businesses ground to a halt as financial markets closed, but companies still had to process trades from around the world and keep their back offices running, which could only be done by activating their backup sites. Trends in operational procedures Many financial institutions are now adopting automation to tackle human error by implementing what is known as ‘straight through processing’ (STP). STP, at its most integrated level, allows a derivative trade to be executed by a trader on an electronic trading platform and for the infor- mation to feed from there directly into the organisation’s back office and administration systems. The removal of the repeated manual typing of trade data eliminates one area of consistent problems for operational risk. However, the energy industry appears to be lagging behind this trend at the moment. According to the Bank for International Settlements Survey Report 2001, the oil majors have sophisticated back office systems in place permitting STP of physical and derivative transactions. However, international traders are not all so up to speed with the latest technology advances, and end-users even less so. This situation will undoubtedly change rapidly over the next few years. According to the BIS: Overall, the results of the interviews indicate that practices for processing trades and managing counterparty risks are broadly similar in all the G-10 countries. Standard legal agreements and confirmation templates (especially those developed by the Interna- tional Swaps and Derivatives Association (ISDA) but also some national master agreements) are used to document most transac- tions. Transaction processing, from data capture through confirma- tion and settlement, is increasingly automated, although the more structured transactions still usually require manual intervention. 174 ENERGY PRI CE RI SK
    • Netting and, to a growing extent, collateral agreements are used to mitigate counterparty credit risks. Finally, the vast majority of OTC transactions are settled bilaterally between the counterparties; within the G-10 countries. SUMMARY The term ‘operational risk’ covers some of the most serious and dramatic risks that an organisation faces: for example, natural disasters, fraud and failures of technology. It might seem that there is little an organisation can do to plan for such unexpected catastrophes. However, an assessment of operational risk and the development of appropriate systems can go a long way towards controlling and reducing it. An assessment may also show that, where risks which cannot be controlled, they can be contained by measures such as the adoption of insurance cover. SUMMARY 175
    • CHAPTER 12 Derivatives Contracts Application Listing and Some Hedging Scenario Examples WHAT IS HEDGING? Hedging is the process in which an organisation with energy price risk will take a position in a derivative instrument (swaps, options, futures) that gives an equal and opposite financial exposure to the underlying physical position to protect against major adverse price changes. The volumetric price exposure of the derivatives hedging instrument should be equal and opposite to the price exposure of the physical energy commodity that the organisation wishes to reduce its price risk exposure in. Energy consumers such as power stations, airline companies using jet fuel, shipping companies using bunker fuel or metal ore smelters using coal, natural gas, oil or electricity do not normally hedge all of their phys- ical volume consumption; nor do they ignore hedging altogether. The majority of active hedgers in the energy markets typically hedge up to a maximum of 50% of their physical volume in order to reduce their company’s balance sheet volatility. They hedge more than 50% only when the market is extremely volatile, for example during periods like the Gulf War. However, most of the time an end-user consumer of energy may only hedge 30% to 50% of energy requirements and as far forward in the future as the end of its next financial year-end. The only regular exceptions to this rule are charter airlines which have already sold all seats on flights to travel agencies, so their income is fixed and they have 100% exposure to jet fuel movements. In this case, charter airlines tend to hedge 100% (or close to it) of their planned consumption volume. There is no such thing as ‘over-hedging’ or creating a derivatives posi- tion greater than your physical consumption or production volume (if you are a producer of energy). If an organisation is doing this it is simply 176
    • speculating! Companies should ensure that any derivatives activity remains within the parameters agreed by the Board of Directors and the risk management committee or risk manager. GENERAL RECAP ON ENERGY DERIVATIVES ■ Swaps usually settle as calendar monthly, against the average of the daily commodity price in that period. For example, January will cover the pricing period 1 January to 31 January. ■ Quarterly and annual structures are possible, but even these settle out every month. For example, in a quarterly contract, one third will be settled out each month during the pricing period. ■ Energy futures contracts tend to have expiry/termination dates during the month they are named. So January IPE Brent will expire 3 days prior to the 15th day of January. It is important to make sure that the futures contract chosen will give price coverage for the required time window. ■ In swaps pricing against oil markets, there are half month contracts (for example, 1st–14th of the month, and 15th through to the last trading day of the month), but these are not as liquid and are usually only available for relatively prompt dates. ■ Natural gas is typically traded on spot markets, then calendar month contracts in the future and winter/summer month periods trade as pack- ages. ■ Coal markets typically are traded as calendar monthly contracts as well both in OTC and futures (where available) ■ Power markets around the world trade in off-peak, peak and monthly forwards, and weekly periods, and spot markets (like day ahead) are generally traded in 30 minute blocks, so there are 48 contracts in one 24 hour day. Weekends tend to trade at different prices from weekdays. ■ Payment due dates tend to differ, so for petroleum products in Asia payment due dates on OTC derivatives tend to be between 10 business days to 14 business days after the last settlement date of the contract (this is always specified in the contract confirmation). ■ Cash flow risk should be predicted and planned for when hedging so that provisions can be made for it. This kind of risk can be created when the timing of payables/receivable on physical energy buying/selling and derivatives hedges do not match up. ENERGY DERIVATIVES SELECTION TABLE Anyone who thinks the number of energy derivatives can be counted on the fingers of two hands should think again. Table 12.1 highlights some of GENERAL RECAP ON ENERGY DERIVATIVES 177
    • the more liquid energy derivatives that I have been able to identify around the world. It is a non-exhaustive listing, since many more OTC contracts are created on an almost weekly basis. This is a dynamic and rapidly growing industry with the prospect of oil futures markets in China perhaps as early as 2003, the creation of petrochemical hedging tools in Europe, and some brokers trying to develop petrochemicals in Asia. To use this listing, select the energy cash market you are interested in hedging from the left-hand columns. Note that this is a guideline to point you in the right direction. Further analysis as to the suitability of the deriv- atives contracts for trading or hedging needs should then be undertaken. HEDGING APPLICATION EXAMPLES The following examples can be applied across airlines, shipping compa- nies, and in fact anyone consuming energy, oil, gas, coal etc. All that is required is to replace the example given with a different pricing reference index. Example 1: fixed price swap hedge by an airline In Figure 12.1, an airline buys a fixed price swap from a bank or trader against its jet fuel price exposure. It trades this swap under its ISDA Master agreement with its counterpart. In the majority of cases, airlines will hedge into the next financial accounting year, so from 1 month up to around 18 months forward. Hedging volumes vary from airline to airline, but in general at least 20% to 30% of volumes are hedged ahead of the start of the next financial year around the annual budgeted price, with addi- tional volumes of 10% to 20% of total annual requirements locked in as 178 ENERGY PRI CE RI SK Airline Jet fuel physical cost Jet fuel hedge cash flow +/– Net costJet/Kero swap counterpart Airlines are naturally short of jet fuel as consumers. Therefore they are exposed to price risk if jet prices move higher Airline buys fixed price Airline sells floating price Sells the fixed price to the airline FIGURE 12.1 Fixed price swap hedge by an airline
    • HEDGING APPLICATION EXAMPLES 179 DERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE 1WTI1stlineswapUSD/bblNYMEXlinkedpricingGLOBALCRUDE 2WTIbulletswapUSD/bblNYMEXlinkedpricingGLOBALCRUDE 3Brent1stlineswapUSD/bblIPELinkedpricingGLOBALCRUDE 4BrentbulletswapUSD/bblIPELinkedpricingGLOBALCRUDE 5Dubai1stlineswapUSD/bblPLATTSlinkedpricingASIACRUDEIMPORTS 6Tapis1stlineswapUSD/bblhttp://www.gvsi.com/ press_releases/pr- APPIfinal.htm ASIACRUDEIMPORTS 7WTIbullet/BrentbulletUSD/bblNYMEXlinkedpricingCRUDEEXPORTARBITRAGEBETWEENEUROPE/WESTAFRICAANDUSA 8WTI1stline/Brent1stlineswapUSD/bblNYMEXlinkedpricingCRUDEEXPORTARBITRAGEBETWEENEUROPE/WESTAFRICAANDUSA 9Brent1stline/Dubai1stlineswapUSD/bblIPELinkedpricingHEDGINGWESTAFRICANCRUDESROUTEDTOASIA 10Dated/Brent1stlineswapUSD/bblPLATTS/IPEHEDGINGBASISRISKBETWEENDATEDBRENTANDIPEBRENTFUTURES 11Tapis1stline/Brent1stlineswapUSD/bblAPPI/PLATTSLOCKINGINTAPISVERSUSBRENTLEVEL-MOVINGPRICEEXPOSURE TOBRENTAMORELIQUIDCONTRACT 12Tapis1stline/Dubai1stlineswapUSD/bblAPPI/PLATTSLOCKINGINECONOMICSOFTAPISCRUDEUSEVERSUSDUBAI RELATEDCRUDES 130.5%SulphurSingaporeGasoilswapUSD/bblPLATTSHEDGINGASIANGASOILPRICES 14IPEGasoil1stlineswapUSD/mtIPELinkedpricingWHOLEMONTHAVERAGEOFIPEGASOILFRONTLINE-HEDGING TRADINGEUROPEANGASOIL 15HeatingoilbulletswapUSD/galNYMEXlinkedpricingUSAHEATINGOIL(GASOIL)HEDGINGANDTRADING 16HeatingOil1stlineswapUSD/galNYMEXlinkedpricingUSAHEATINGOIL(GASOIL)HEDGINGANDTRADING 17GO1stline/Brent1stlineswapUSD/bblIPE/IPEHEDGINGEUROPEANMIDDLEDISTILLATEREFINERYMARGIN 18HO1stline/WTI1stlineswapUSD/bblNYMEX/NYMEXHEDGINGUSAMIDDLEDISTILLATEREFINERYMARGIN 19HObulletswap/WTIbulletswapUSD/bblNYMEX/NYMEXHEDGINGUSAMIDDLEDISTILLATEREFINERYMARGIN 200.5%Sing/Dubai1stlineswapUSD/bblPLATTS/PLATTSHEDGINGREFINERYMARGININMIDDLEDISTILLATESUSINGDUBAI RELATEDCRUDES TABLE12.1Energyderivativesselectiongrid
    • 180 ENERGY PRI CE RI SKDERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE 21NYHBargesnumber2/HO1stline swap USD/bblPLATTS/NYMEXHEDGINGBASISRISKBETWEENPLATTSANDNYMEXHEATINGOIL 22NYHBargesLSnumber2/HO1stline swap USD/bblPLATTS/NYMEXHEDGINGBASISRISKBETWEENPLATTSANDNYMEXHEATINGOIL 23EN590newCIF/GO1stlineswapUSD/mtPLATTS/IPETRADING/HEDGINGSPREADBETWEENEN590ANDIPEGASOIL FUTURES 24EN590GASOILMEDITERRANEAN (MED)CIF/GASOILFUTURESrelated 1stlineswap USD/mtPLATTS/IPETRADING/HEDGINGSPREADBETWEENEN590INMEDITERRANEAN ANDIPEGASOILFUTURES 25Gasoil(GO)MEDFOB/Gasoil(GO) Futuresrelated1stlineswap USD/mtPLATTS/IPEHEDGINGTHEDIFFERENTIALSPREADBETWEENMEDITERRANEAN GASOILANDIPEGASOILFUTURES 26GORdamBarges/GO1stlineswapUSD/mtPLATTS/IPEGASOILHEDGINGBASISRISKBETWEENROTTERDAMGASOILBARGESANDTHE IPEGASOILFUTURES 27GOnewCIF/GO1stlineswapUSD/mtPLATTS/IPEGASOILGASOILNORTHWESTEUROPEHEDGINGOFSPREADAGAINSTIPE GASOILFUTURES1stLINEFUTURES 28ULSDRdamBarges/GO1stlineswapUSD/mtPLATTS/IPEGASOIL FUTURES HEDGINGBASISRISKBETWEENROTTERDAMGASOILBARGESANDTHE IPEGASOILFUTURES 29ULSDnewCIF/GO1stlineswapUSD/mtPLATTS/IPEGASOIL FUTURES HEDGINGBASISRISKBETWEENNORTHWESTEUROPEGASOIL CARGOESANDTHEIPEGASOILFUTURES 300.5SingaporeGasoil/GO1stline swap USD/mtPLATTS/IPEGASOIL FUTURES TRANSFERORLOCKINSPREADRISKBETWEENSINGAPOREGASOIL ANDIPEGASOILFUTURES 31180cstSingFuelOilswapUSD/mtPLATTSHEDGEASIAFUELOILMARKETS 321%RdamFOBBargesSwapUSD/mtPLATTSHEDGEEUROPEAN1%FUELOIL 331%newFOBCargoswapUSD/mtPLATTSHEDGEEUROPEAN1%FUELOIL 343%USGCWswapUSD/bblPLATTSHEDGEUSGULFCOAST3% 353.5%RdamBargesswapUSD/mtPLATTSHEDGEEUROPEAN3.5%FUELOIL 361%NYHCargoswapUSD/bblPLATTSHEDGE1%NEWYORKHARBORFUELOILCARGOES 373.5%MEDFOBCargo/3.5%Rdam Bargesswap USD/mtPLATTSHEDGE3.5%MEDITERRANEANFREEONBOARD(FOB)VERSUS ROTTERDAMMARKET
    • HEDGING APPLICATION EXAMPLES 181 DERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE 38180cstSingaporeFuelOilCaroges/ 3.5%RotterdamFuelBargesswap USD/mtPLATTSLOCKIN/TRANSFERPRICERISKFROMSINGAPOREFUELOILTO3.5% EUROPEANMARKET 391%RotterdamFuelBarges/1%new FOBCargo USD/mtPLATTSLOCKINBASISRISKBETWEENBARGEQUANTITYVERSUSCARGOSIZE PRICE 401%NewYorkHarborFuelOilCargo/ 3%USGCWswap USD/bblPLATTSTRADE/HEDGEDIFFERENCEBETWEENNEWYORK/USGULF,1%GRADE VERSUS3%GRADE 41180cstSingaporeFuelOil/Dubai Crude1stlineswap USD/bblPLATTSHEDGE/TRADEASIANREFINERYMARGINFORFUELOIL 423.5%FuelOilRotterdamBarges/ Brent1stlineswap USD/bblPLATTS/IPEBRENTHEDGE/TRADEEUROPEANREFINERYMARGINFORFUELOIL 431%newFOBCargo/Brent1stline swapFUELOIL USD/bblPLATTS/IPEBRENTHEDGE/TRADEEUROPEANREFINERYMARGINFORFUELOIL 441%NYHNewYorkHarborCIF Cargo/WTI1stlineswapFUELOIL USD/bblPLATTS/NYMEXHEDGE/TRADEUSAREFINERYMARGINFORFUELOIL 453%USGCW/WTI1stlineswapFUEL OILVersusWTICrudeFuturesSwap USD/bblPLATTS/NYMEXHEDGE/TRADEUSAREFINERYMARGINFORFUELOIL 46SingaporeJetKeroseneswapUSD/bblPLATTSHEDGEASIANJETFUEL/KEROPRICES 47SingaporeRegradeswap(Thespread betweenJetKeroseneandGasoil) USD/bblPLATTSHEDGEPRICESPREADBETWEENGASOILANDJETFUEL 48USGulfCoast(USGC)54Jet/Heating oilNYMEXFutures(HO)1stline swap USD/galPLATTS/NYMEXHEDGEORTRADEBASISRISKSPREADBETWEENUSGULFCOASTAND NYMEXFUTURES 49newCIFCargo/GO1stlineswapUSD/mtPLATTS/NYMEXTRADE/HEDGEBASISRISKBETWEENNORTHWESTEUROPEANCIF GASOILCARGOESANDIPEGASOILFUTURES 50RdamBargesFOB/NWECIFCargo swap USD/mtPLATTS/PLATTSTRADE/HEDGEBASISBETWEENBARGESIZEGASOILPARCELSAND CARGOSIZEGASOIL 51MEDCargoFOB/NWECIFCargo swap USD/mtPLATTSHEDGE/LOCKINMARGINBETWEENMEDITERRANEANGASOILCAROES ANDNORTHWESTEUROPEGASOILCARGOES 52USGC54Jet/WTI1stlineswapUSD/bblPLATTS/NYMEXWTIUSGULFCOASTJETREFINERYMARGINAGAINSTWTICRUDEOIL
    • 182 ENERGY PRI CE RI SKDERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE 53RdamBargesEurogradeswapUSD/mtPLATTSHEDGEFOREUROGRADEGASOLINEINEUROPE 54GasolinebulletswapUSD/galNYMEXGASOLINE UNLEADED HEDGEFORUSAGASOLINE 55Gasoline1stlineswapUSD/galNYMEXGASOLINE UNLEADED HEDGEFORUSAGASOLINE 56USGCConvUnl87/WTI1stline swap USD/bblPLATTS/NYMEXWTI FUTURES USGULFCOASTUNLEADEDGASOLINEGRADE87MARGINAGAINST WTICRUDEOIL 57RdamBargesEurograde/Brent1st lineswap USD/bblPLATTS/IPEBRENT FUTURES HEDGEFORREFINERYMARGINONGASOLINEINEUROPEAGAINST BRENTCRUDEOIL 58Gasolinebulletswap/WTIbullet swap USD/bblNYMEXGASOLINE/ NYMEXWTI HEDGEINUSAFORREFINERYMARGINFORGASOLINEVERSUSWTI CRUDEOIL 59Gasoline1stline/WTI1stlineswapUSD/bblNYMEXGASOLINE/ NYMEXWTI HEDGEINUSAFORREFINERYMARGINFORGASOLINEVERSUSWTI CRUDEOIL 60USGulfCoastConvUnl87/USGC number2HOswap USD/galPLATTSLOCKINPRICESPREADBETWEENGASOLINE/HEATINGOIL 61Gasoline1stline/HeatingOil1stline swap USD/galNYMEXLOCKINPRICESPREADBETWEENGASOLINE/HEATINGOIL 62HU(Gasoline)bulletswap/HO (HeatingOil)bulletswap USD/galNYMEXLOCKINPRICESPREADBETWEENGASOLINE/HEATINGOIL 63NYH(NewYorkHarbor)BargesUnl 87RFG/HU1stlineswap USD/galPLATTS/NYMEXHEDGEBASISRISKBETWEENPLATTSGASOLINE/NYMEXGASOLINE FUTURES 64NYH(NewYorkHarbor)BargesUnl 87/HU1stlineswap USD/galPLATTS/NYMEXHEDGEBASISRISKBETWEENPLATTSGASOLINE/NYMEXGASOLINE FUTURES 65USGCUSGulfCoast(USGC)Conv Unl87/HU1stlineswap USD/galPLATTS/NYMEX GASOLINEFUTURES HEDGEBASISRISKBETWEENPLATTSGASOLINE/NYMEXGASOLINE FUTURES 66RotterdamBargesEurograde/GO1st lineswap USD/mtPLATTS/IPEGASOIL FUTURES LOCKINTRADESPREADBETWEENEUROPEANGASOLINEANDIPE GASOILFUTURES 67NaphthaSingaporeFOBCargoswapUSD/bblPLATTSHEDGENAPHTHAACROSSASIAPACIFICREGIONINCLUDINGJAPAN
    • HEDGING APPLICATION EXAMPLES 183 DERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE 68Naphthanew(NorthWestEurope) CIFCargoswap USD/mtPLATTSHEDGENAPHTHAINEUROPE 69NaphthaSingaporeFOBCargo/ Dubai1stline USD/bblPLATTS/PLATTSHEDGEREFINERYMARGINBETWEENNAPHTHAANDDUBAIRELATED CRUDES 70NaphthanewCIFCargo/Brent1st lineswap USD/bblPLATTS/IPEBRENT FUTURES HEDGEREFINERYMARGINBETWEENNAPHTHAANDBRENTRELATED CRUDES 71NaturalGasFirmPhysical,Fixed Price USD/MMBtuNATURALGASHEDGEUSA 72NaturalGasFirmPhysical, IntercontinentalExchangeDaily USD/MMBtuNATURALGASHEDGEUSA 73NaturalGasFirmPhysical,GasDaily Daily USD/MMBtuNATURALGASHEDGEUSA 74NaturalGasFirmPhysical,Inside FERC USD/MMBtuNATURALGASHEDGEUSA 75NaturalGasFirmPhysical,Natural GasIntelligence USD/MMBtuNATURALGASHEDGEUSA 76NaturalGasFirmPhysical,Canadian GasPriceReporter USD/MMBtuNATURALGASHEDGEUSA 77NaturalGasFirmPhysical,NYMEX LD1 USD/MMBtuNATURALGASHEDGEUSA 78FixedPriceforIntercontinentalFirm PhysicalNaturalGasPriceBulletin USD/MMBtuNATURALGASHEDGEUSA 79NaturalGasSwingSwap,Fixedfor GasDailyDaily USD/MMBtuNATURALGASHEDGEUSA 80NaturalGasSwingSwap,Inside FERCforGasDailyDaily USD/MMBtuNATURALGASHEDGEUSA 81NaturalGas,FixedforFloat(Inside FERC) USD/MMBtuNATURALGASHEDGEUSA 82NaturalGas,FixedforFloat(NGI)USD/MMBtuNATURALGASHEDGEUSA
    • 184 ENERGY PRI CE RI SKDERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE 83NaturalGasSwap,FixedforNYMEX LD1 USD/MMBtuNATURALGASHEDGEUSA 84NaturalGasSwap,FixedforNYMEX LD1,Spread USD/MMBtuNATURALGASHEDGEUSA 85NaturalGasBasisSwap,NYMEXLD1 forInsideFERC USD/MMBtuNATURALGASHEDGEUSA 86NaturalGasBasisSwap,NYMEXLD1 forNaturalGasIntelligence USD/MMBtuNATURALGASHEDGEUSA 87NaturalGasSwingSwap,GasDaily DailyforNYMEXLD1 USD/MMBtuNATURALGASHEDGEUSA 88CanadianNaturalGasFirmPhysical, FixedPrice CAD/GJNATURALGASHEDGEUSA 89CanadianNaturalGasFirmPhysical, CanadianGasPriceReporter CAD/GJNATURALGASHEDGEUSA 90CanadianNaturalGasFirmPhysical, GasDailyDaily CAD/GJNATURALGASHEDGEUSA 91EuropeanNaturalGasFirmPhysical, FixedPrice p/ThermNATURALGASHEDGE/TRADEINEUROPE 92EuropeanNaturalGasFirmPhysical, FixedPrice,SpreadZeebruggeversus NBP p/ThermNATURALGASHEDGE/TRADEINEUROPE 93UKNationalBalancingPointindexed OTCSwapsbasisNBP97contract p/ThermNATURALGASHEDGEINTHEUNITEDKINGDOM 94LPGSwapsEurope–Propaneswaps againstBPindex EuropeLIQUIDPETROLEUMGASHEDGEINEUROPE 95LPGMidEast/NorthAfrica/Asia– SaudiCPPricingusedasIndexfor OTCSwaps MidEastLIQUIDPETROLEUMGASHEDGEFORMIDDLEEAST&ASIAREGION
    • HEDGING APPLICATION EXAMPLES 185 DERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE 96LNGwithCruderelatedpricing– proxyhedginginCrudefutures/ relatedOTCderivativesmarkets GlobalN/A USWestFirmLDPeakPower(physicaldeliveryforwardcontracts) 97PaloVerdeUSD/MWh 98NorthPath15USD/MWh 99SouthPath15USD/MWh 100MidColumbiaUSD/MWh 101Mead230USD/MWh USEastPeakPower(physicaldeliveryforwardcontracts) 102PJM-WestUSD/MWh 103IntoTVA,Seller’sDailyChoiceUSD/MWh 104NEPoolPTFUSD/MWh 105NEPoolMassHubUSD/MWh 106NEPoolSeller’sChoiceUSD/MWh 107ErcotUSD/MWh 108Ercot-HoustonZoneUSD/MWh 109Ercot-WestZoneUSD/MWh 110Ercot-SouthZoneUSD/MWh 111Ercot-NorthZoneUSD/MWh 112IntoSoCo,Seller’sDailyChoiceUSD/MWh 113IntoAEP,Seller’sDailyChoiceUSD/MWh 114IntoFPL,Seller’sDailyChoiceUSD/MWh 115IntoFPC,Seller’sDailyChoiceUSD/MWh
    • 186 ENERGY PRI CE RI SKDERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE USFinancialSwapPeak(cashsettlementnophysicaldelivery) 116PJM-WestDayAheadUSD/MWh 117PJM-WestRealTimeUSD/MWh 118PJM-WestBal-DayUSD/MWh 119NEPoolPTFBalDayUSD/MWh 120NEPoolPTFRealTimeUSD/MWh 121PJM-West,FPforICEUSD/MWh 122Cinergy,FPforICEUSD/MWh 123NYPOOLZoneA(NewYorkpower pool) USD/MWh 124NYPOOLZoneGUSD/MWh 125NYPOOLZoneJUSD/MWh 126NYPOOLZoneABal-DayUSD/MWh 127NYPOOLZoneGBal-DayUSD/MWh 128NYPOOLZoneJBal-DayUSD/MWh 129Ercot-HoustonZoneBal-DayUSD/MWh 130Ercot-NorthZoneBal-DayUSD/MWh 131Ercot-SouthZoneBal-DayUSD/MWh 132NP15,FPforIntercontinental Exchange(www.theice.com) USD/MWh 133SP15,FPforIntercontinental Exchnage(www.theice.com) USD/MWh 134MidColumbia,FPforICEUSD/MWh 135PaloVerde,FPforICEUSD/MWh USEastFinancialSwapOffPeakPower(cashsettlementnophysicaldelivery) 136NYPOOLZoneAUSD/MWh
    • HEDGING APPLICATION EXAMPLES 187 DERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE 137NYPOOLZoneGUSD/MWh 138NYPOOLZoneJUSD/MWh EuropeanFirmPeakLoadPower(physicaldeliveryforwardcontract) 139RWEGrid,GermanyEUR/MWh 140RTEGrid,FranceEUR/MWh 141UKGrid,UKGBP/MWh 142LaufenburgGrid,SwitzEUR/MWh 143StPeterGrid,AustriaEUR/MWh 144TenneTGrid,HollandEUR/MWh EuropeanFirmBaseloadPower(physicaldeliveryforwardcontract) 145RWEGrid,GermanyunderEFET agreementwww.efet.org EUR/MWhwww.eex.de&www. theice.com 146RTEGrid,FranceEUR/MWh 147UKGrid,UK-underNETAcontractGBP/MWh 148LaufenburgGrid,SwitzEUR/MWh 149StPeterGrid,AustriaEUR/MWh 150TenneTGrid,HollandEUR/MWh CoalSwaps 151FinancialSwapCoal,FPforTFSAPI2 grade(themorepopulargradefor swaps) USD/Tonnewww.tfsenergy.com 152FinancialSwapCoal,FPforTFSAPI4USD/Tonnewww.tfsenergy.com 153NYMEXCoalFutureswww.nymex.com (USA) USD/Tonnewww.nymex.com
    • 188 ENERGY PRI CE RI SKDERIVATIVECONTRACTUNIT MEASUREMENT PRICINGLINKCOMMONUSAGE OilFutures 154IPEBrentCrudeFutureswww.ipe.uk. com USD/Barrel 155IPEGasoilFutureswww.ipe.uk.comUSD/Barrel 156NYMEXWestTexasIntermediate crudeoilfutureswww.nymex.com USD/Barrel 157NYMEXHeatingOil(Gasoil)Futures www.nymex.com USD/Gallon 158NYMEXGasolineUnleadedFutures www.nymex.com USD/Gallon 159NYMEXNaturalGasHenryHub Futureswww.nymex.com USCents/BTU 160TOCOMTokyoMiddleEastCrude OilFutureswww.tocom.or.jp Yen 161TOCOMKeroseneFuturesdomestic marketJapanwww.tocom.or.jp Yen 162TOCOMGasolineFuturesdomestic marketJapanwww.tocom.or.jp Yen 163SingaporeExchange(SGX)MECO MiddleEastCrudeOilFutures contractwww.sgx.com USD/Barrel PetrochemicalSwaps 164EthyleneEuropeUSD/MTICISLORPricing 165EthyleneSingapore(www.ginga.com. sg) USD/MTwww.icislor.com 166 167 Benzene Xylene USD/MT USD/MT alsoswapspricedagainst thePlattspricesalso availablewww.platts.com
    • opportunistic or protective hedges whenever prices drop below the annual jet fuel purchasing budget price target. In ‘disaster’ scenarios airlines hedge prices for up to 100% of short-term requirements (short- term – present day to, say, around 3 months forward). This can happen in a situation like the Gulf War, which would prompt oil prices to move higher on Middle East tension. Long-term large hedging of 100% of volumes is only seen in the market by charter airlines which have fixed income through forward seat sales to holiday companies. This means they have no way to increase prices later to accommodate higher jet fuel prices and therefore need to protect their usually thin and fixed profitability by fully hedging the price of forward jet fuel requirements. In the above example, an airline buys US$25 fixed price swap for 50,000 barrels per month, against Singapore MOPS as the pricing reference (Mean of Platts Singapore; http://www.platts.com/) for the calendar year 2003. In ISDA contract terminology, the airline is the ‘fixed price payer’. Total volume is 50,000 barrels × 12 months = 600,000 barrels. Remember that when asking for quotes from traders directly or via brokers the quote is normally good for 50,000 barrels per month for products quoted in barrels or 5,000 MT per month for products quoted in barrels (unless otherwise specified). In oil swaps there is a financial settlement every month (unlike financial markets like interest rates which usually have a settlement at the end of the swaps whole pricing period; e.g. a 3 month interest rate swap would have a settlement at the end of the 3rd month). Taking this into consideration the cash flow of this 12 month hedge would look something like Table 12.2. As this is an Asian-based swap (Mean of Platts Singapore) the cash settlement is normally going to be due on the 10th business day of the month preceding the month already priced out (e.g. for January 2003 the last pricing day would be Friday 31 January 2003). Payment for the cash settlement would be due on 14 February 2003 (subject to any banking holidays). Example 2: collar structure for end-user hedging This is more flexible because airlines normally want protection against a disaster scenario increase in jet prices. Using the swaps market means they must lock in their minimum net price receivable at the current perceived swap value (e.g. US$25 in Example 1). However, by using a collar structure as shown in Example 2 the airline can still protect itself from a worrying price increase, but can keep its minimum net price receiv- able locked in at a lower rate than the current swap price. Using a collar structure you can tailor the protection point to suit your jet fuel budget level. It is created by buying a cap and selling a floor option. The purchase of the cap protects you against jet fuel prices rising above the strike HEDGING APPLICATION EXAMPLES 189
    • of the cap, which in the example is US$24. The sale of the floor reduces the cost of the premium in the purchase of the cap (which can be sizeable given the usual 12 month or more tenures in airline hedging programs). A popular approach by end-users is to create a zero cost collar by selling enough floor options and receiving enough premium from these sales to compensate for the cost of the cap purchase (Figure 12.2). The US$24 collar gives you 100% upside protection on any month that the average price of the market moves above US$24. The sale of the floor locks in the minimum net price you will receive on your jet fuel but at a lower level than the swap price you would have received at the same execution time point at this collar. By playing with the level of the cap and the floor and also the volumes of the cap and/or floor it is possible to create a zero cost collar where the purchase of the cap is 100% subsidised by the sale of the floor (Figure 12.3). Table 12.3 is an example cash flow for the collar hedge structure using the prices illustrated above, with 50,000 barrels per month as the contract volume. Example 3: electricity producer risk profile In this example, a power producer (utility) has a more complex risk than an airline, which is only worried about jet fuel price risk (and maybe forex 190 ENERGY PRI CE RI SK 50,000 barrels per month Jet Kero Calendar 2003 A B C Monthly settlement Volume Fixed price ‘MOPS’ (C – B) × A Jan-03 50,000 25 24 –50000 Feb-03 50,000 25 25 0 Mar-03 50,000 25 26 50000 Apr-03 50,000 25 26.5 75000 May-03 50,000 25 27 100000 Jun-03 50,000 25 27 100000 Jul-03 50,000 25 25 0 Aug-03 50,000 25 23 –100000 Sep-03 50,000 25 22 –150000 Oct-03 50,000 25 24 –50000 Nov-03 50,000 25 26 50000 Dec-03 50,000 25 28 150000 Total vol. 600,000 barrels 175000 TABLE 12.2 Cash flow of a 12 month hedge
    • risk). A power producer (except nuclear) may have up to four different types of fuel for power production: coal, fuel oil, gasoil, and natural gas, as shown in Figure 12.4. Because of this a power producer will have to observe movements in the spark spread, which is the term used to HEDGING APPLICATION EXAMPLES 191 Sold $16 floor Bought $24 cap $28 $26 $24 $22 $20 $18 $16 $14 Jan03 Feb03 Mar03 Apr03 May03 Jun03 aaaaaaaa aaaaaaaa aaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaa US$2 payout to airline US$24US$26 US$22 US$21 MOPS monthly average FIGURE 12.3 Collar hedge structure Airline Jet fuel physical cost Jet fuel hedge cash flow +/– Net cost Sell floor Buy cap $28 $26 $24 $22 $20 $18 $16 $14 NO PROTECTION OR EXPOSURE WITHIN THE PARAMETERS OF THE COLLAR FIGURE 12.2 Zero cost collar
    • describe the gross margin (excludes cost of power company operation) between the cost of the chosen fuel for power production and the resale price of the forward electricity/power produced. A utility can control some of its price risk or profit margin risk (depending on the type of power stations it operates) by switching fuels if, for instance, gasoil looks more cost effective than fuel oil or vice versa. It will depend on the types of facility it operates. A coal power station would not switch over to oil-based products, nor would it switch from coal to natural gas and vice versa. On rare occasions when utilities are very close to a refinery they may sometimes utilise naphtha for power production. In normal circumstances, though, naphtha is not a cost-effective fuel and either coal, or fuel oil/gasoil or natural gas is utilised. In America there are coal futures on NYMEX and swaps, good liquidity in the NYMEX natural gas futures and there is also the OTC derivatives market. The OTC power market is USA is very well developed, so there are no issues there. Also for heating oil (gasoil) and fuel oil the OTC markets 192 ENERGY PRI CE RI SK Collar Calendar 2003 A FLOOR CAP C Monthly settlement Volume Strike Strike ‘MOPS’ Jan-03 50,000 16 24 14 –100000 Feb-03 50,000 16 24 21 0 Mar-03 50,000 16 24 22 0 Apr-03 50,000 16 24 26 100000 May-03 50,000 16 24 24 0 Paid/ received 0 Jan– March TABLE 12.3 Cash flow for the collar hedge structure Electricity producer (utility) Nat. gas Fuel oil/ Gasoil Coal Power Input prices – floating price risk Output prices Fixed/floating risk FIGURE 12.4 Risk profile for an electricity producer
    • are very well developed and on the East Coast USA there is the possibility of using heating oil futures, although the majority of utilities will trade the natural gas versus the electricity spark spread. In Europe utilities have a well developed oil petroleum product swaps markets to utilise for hedging purposes and the IPE futures market also offers gasoil futures which may offer some protection. On the natural gas side, UK utilities can hedge in the IPE natural gas futures, and there is also a well developed natural gas NBP (natural balance point) UK gas swaps markets (trading circa mid-2002 approximately 6 times the volume of IPE NBP UK Nat Gas futures). Spark spreads are available from OTC traders as well, allowing the trading of the profit margin between natural gas piped in from the European North Sea and UK NETA forward power markets. In Continental Europe utilities and traders are able to utilise electricity futures markets as detailed in Chapters 3 and 4. Natural gas markets are not very deregulated in continental Europe. In most parts it has allowed countries to keep a control on overall power prices by controlling utility feedstock prices. This is changing gradually, though. Coal can be hedged in Europe by using coal swaps based on APi2 grade mainly as detailed in Chapters 3 and 4. UK spark spread recap When a spark spread order is given it is usually quoted as a spread price in £/MWh (UK pounds per megawatt hour). A preferred power price will be given and negotiation will develop from there via brokers or directly with another principal. Obviously, natural gas is not traded normally in MWh, so the natural gas price has to be converted into an electricity equivalent. In the UK spark spread market a conversion rate of 49.1349% is used (representing 100,000 therms/60MWs). Once a preferred fixed price on the power is confirmed, the gas price is then calculated in pence/therm correct to three decimal places: Gas price in p/therm Power price Spread V = - ´ ´ ´( ) 24 100 olume of power Volume of gas Power price Spread = - ´( ) 24 100 60 100 000 ´ ´ , Contracts are based on the Standard GTMA (Grid Trading Master Agreement mentioned in Chapter 17 on legal risk) and the NBP 1997 Terms (which is the contract under which natural gas is traded in the UK). The trade (if reported by brokers) is reported in as the spark spread price level, and the fixed prices agreed for the gas and power (creating the spread) are not normally disclosed by OTC brokers. HEDGING APPLICATION EXAMPLES 193
    • Example 4: metal producer In the situation shown in Figure 12.5, the metal producer can lock in the spread by using swaps or options between the energy markets utilised and the finished metal. Some banks can offer structures that give metal producers power prices/ energy prices for their operation in a price related to the finished metal they produce. This is achieved by locking in the spread by selling forward metal derivatives and buying forward energy derivatives. The smelter is exposed to energy prices going up which is protected by the long (purchased) energy derivatives. The smelter’s profit margin is protected by the short (the sale) of metal derivatives. Example 5: crude oil hedge from Middle East to Asia Typically, for crude oil cargoes you would be given a 3 or 5 day pricing window. Take an example of a cargo of 500,000 barrels which is destined for Singapore 1–5 December 2002. Using January 2003 futures you can sell 500 contracts of the SGX Middle East Crude oil futures (equivalent of 500,000 barrels of crude). A trader might typically sell these contracts 100,000 barrels per day on 1, 2, 3, 4, 5 December as your crude cargo was pricing out against the Mean of McGraw-Hill Platts physical market assessment price (Figure 12.6). Now imagine that in this scenario the refinery has put the crude oil into storage after the long journey from West Africa/Middle East to Singapore for refining. The refinery in this example is consuming 50,000 barrels a day, so during the course of 10 days × 50,000 (500,000 barrels) the trade will wish to remove (close out) the futures (or indeed swaps) hedge against the physical crude oil, otherwise the crude oil will be consumed, leaving the trader with a naked derivatives position (i.e. with no physical commodity), so that overnight it would turn into a speculative trade (Figure 12.7). 194 ENERGY PRI CE RI SK Metals smelter Raw metal ore Electricity Coal Finished metal Input prices – floating price risk Output prices Fixed/floating risk Fuel oil FIGURE 12.5 Risk profile for a metal producer
    • HEDGING APPLICATION EXAMPLES 195 500,000 barrels pricing out over 5 days, i.e. 100,000 barrels per day MECO futures contract 1000 barrels per contract – so 100 contracts per day must be sold to lock in a hedge December barrels contracts Selling 1st 100,000 100 Selling 2nd 100 Selling 3rd 100 Selling 4th 100 Selling 5th 100 so by close of business 5th December you are long (bought) 500,000 barrels of physical and also now short (sold) 500,000 barrels or 500 contracts of MECO futures 6th Journey Time 16th 17th 18th 19th 21st December – As a user of the crude oil you may have storage facilities and use the oil slowly over another 10 days time period in which case every day you buy back 50 lots or 50,000 barrels of hedge as you consume the oil 20th Buying 21st 50,000 50 Buying 22nd 50,000 50 Buying 23rd 50,000 50 Buying 24th 50,000 50 Buying 25th 50,000 50 Buying 26th 50,000 50 Buying 27th 50,000 50 Buying 28th 50,000 50 Buying 29th 50,000 50 Buying 30th 50,000 50 FIGURE 12.7 Crude oil hedging (2) 500,000 barrels pricing out over 5 days, i.e. 100,000 barrels per day MECO futures contract 1000 barrels per contract – so 100 contracts per day must be sold to lock in a hedge December barrels contracts 1st 100,000 100 2nd 100 3rd 100 4th 100 5th 100 so by close of business 5th December you are long (bought) 500,000 barrels of physical and also now short (sold) 500,000 barrels or 500 contracts of MECO futures 6th Journey Time 16th 17th 18th 19th December the cargo is sold at this point you wish to close out the hedge by buying back 500 contracts in the market or via EFP FIGURE 12.6 Crude oil hedging (1)
    • Example 6: hedge cash flow for a crude oil import hedge Table 12.4 shows an example of where a refinery which is naturally short crude, since a refinery must consume crude oil and can’t be switched on or off. In fact, most refineries have to run at a minimum of 60% capacity, otherwise they have to be shut down, and that plus restarting a refinery is an extremely expensive and dangerous process. The risk profile here is that the refiner is exposed to crude oil prices moving higher and threat- ening its profit margin on refining crude oil into petroleum products. So the US refiner buys NYMEX WTI Crude futures (or whole month average swaps based against WTI pricing). In this example the refiner wants to protect its January crude physical requirements from a price increase. 1 October Buys January NYMEX WTI Futures @ US$23.00 10 December The refiner purchases its crude oil @ US$24.75 Sells same volume futures @ US$24.75 Profit on futures US$ 1.75 The effective netted buying price is: Hedge + physical purchase price = US$24.75 – US$1.75 hedge profit = US$23.00 Example 7: crude oil producer hedge A simple crude oil producer hedge would be as follows. A crude producer is naturally long crude because it has crude in the ground, so it is exposed to prices going down. It therefore needs to create a short position in a derivatives hedge structure. For this example the producer sells its crude oil on a Brent crude oil related price basis, so its price exposure is in terms of Brent crude oil. The 196 ENERGY PRI CE RI SK Bought fixed cash Sold fixed futures 1st to 5th 26 26.35 Sold cash Bought futures 21st to 30th 25 25.35 Gross profit (loss) –1 1 Net position 0 TABLE 12.4 Hedge cash flow for a crude oil import hedge
    • producer has seen crude prices reach a high level due to some Middle East political tension and related concerns, so it is too expensive to buy some put options (floor) on their own. One possibility is to do the following: ■ Sell Brent-related futures, e.g. IPE Brent Futures in London. This is a good idea if the producer wishes to remain anonymous and not scare the market that they are selling. ■ Sell Brent-related OTC swaps with other oil companies and banks. This may be more flexible, but given that this is a key producer hedging they might not wish to reveal their intentions directly with other traders in the OTC market place. An example using IPE Brent Futures: 5 December Sells January IPE Brent Futures @ US$ 29.50 per barrel 15 January Sells Physical crude @ US$30.50 per barrel Buys back same volume of futures @ US$30.50 per barrel Futures loss @ US$ 1.00 per barrel Effective netted crude sale price is Hedge + physical sale price = US$30.50 + US$1.00 loss = US$29.50 per barrel Example 8: crude producer hedge using floors with a knock-out The other alternative which can be applied not only to a crude oil producer but to any energy producer situation is using floors (puts) with a knock-out option. In this scenario, the producer had found that because the oil price had been moving higher, and it thought that prices would continue to move higher, it did not wish to sell futures or swaps and lock in the price, creating some potential loss of opportunity if prices continued to rise (as shown by the previous example with a loss on the hedge). A more appetising solution is to buy floors (puts). In this scenario we will say that the cost of buying a floor is too expensive, so the producer could look at introducing a knock-out into the floor (put) structure in order to try to reduce the overall cost of the option. In a hedging scenario, whatever the type of energy product being produced, you would look to buy an ‘out-of-the-money’ floor (put) and request a knock out above the market. In the scenario of Figure 12.8 the trader or market maker has given the producer a cheaper floor option to protect against prices going down, HEDGING APPLICATION EXAMPLES 197
    • because the producer has given the seller some optionality. This optionality is the knock-out. What the producer has said to the seller of the floor is that if the market goes up to US$31.00 during the lifetime of the option, the option is automatically cancelled. So the seller of the option has the added chance – the added potential – of receiving a premium for a long-term option, which may actually be cancelled before it reaches matu- rity or expiry date. This lets the seller of the option off the hook without any more exposure to the producer. A rebate structure can also sometimes be negotiated. In this instance, if the option were cancelled, the producer who is hedging might receive back some percentage of the original premium it had paid out for the option. Example 9: refinery margin hedge when margin positive on some products and negative on others In this example (see Figure 12.9) a refinery has good margins on jet kero and gasoil, but fuel oil margins are negative (fuel oil makes up to 25% of 198 ENERGY PRI CE RI SK Price Current market price Floor Purchased @ strike price of US$27.00 32 31 30 29 28 27 26 25 Knock-out at US$31.00 chosen by producer FIGURE 12.8 Hedging using a floor with a knock-out Oil refiner Energy outputsEnergy inputs Crude oil feedstock Naphtha Jet Kero Gasoil Fuel oil Gasoline FIGURE 12.9 Energy inputs and outputs for an oil refinery
    • the output of some older refineries, although newer ones tend to repro- cess a lot of fuel oil and a modern refinery may only produce an estimated 10% fuel oil). This refinery is using crude oil from the Middle East, pricing against the average of Platts Oman crude oil. To hedge the crude oil imports for the refinery the traders will sell OTC crude oil swaps pricing against Platts Oman average. Thus the refinery buys 2,000,000 barrels of Middle East crude priced against Oman on 1–5 January. Since not all of the petroleum product output is being hedged, the first thing to do is to add up the volume of the products (convert into barrels where necessary) and make sure that only this amount of crude is hedged. For example, see Figure 12.10. Using the figures above we are hedging 1,000,000 barrels of product, so we also need to lock in 1,000,000 barrels of the crude. So every day for 5 days during the pricing window 1–5 January, the traders will sell 125,000 barrels of Platts Oman related swaps, except for the last day, which is 500,000 barrels, since the crack option on the fuel oil is placed in the option market all in one go. By day 6, the trader will have a cargo of physical on the water on its way to the refinery and a paper hedge of 1,000,000 barrels notional quantity protecting the value of the crude. At the same time as hedging the crude oil cargoes, the trader starts hedging the future production of the refinery from this crude oil that is on its way to the refinery. For jet fuel and gasoil, the margin is looking healthy, so the trader may just sell the forward swaps to lock in the value of the jet fuel and gasoil. He makes sure that he sells swaps which cover the time period that the refinery will be producing petroleum products from the crude on the water on its way to the refinery. For example, if someone bought West African crude and shipped it to Japan for refining, it could take four weeks to get there. So, if you were hedging the crude oil you would want to make sure that the derivatives contract would not expire before the products could be produced from the crude. Also, it might mean that the products would not actually be sold from the refinery for several months after the crude was purchased. The issue in this scenario is that the fuel oil has a negative refining margin. They cannot shut the refinery down, so they need to protect HEDGING APPLICATION EXAMPLES 199 Crude Oil Import Petroleum Product Production Hedge Feedstock Sold Swaps Sold Swaps FUEL OIL CRACK OPTION Jet Kero Gasoil BOUGHT FLOOR @ US$110 per MT Physical Hedge Short Volume (using 6.7 conversion from MT to barrels) January 1st 25 24.95 125,000 50,000 75,000 0 2nd 24.89 24.84 125,000 50,000 75,000 0 3rd 24.86 24.81 125,000 50,000 75,000 0 4th 24.5 24.45 125,000 50,000 75,000 0 5th 24.65 24.6 500,000 50,000 75,000 375,000 TOTAL 6th 24.78 24.73 1,000,000 FIGURE 12.10 Petroleum product production hedge
    • against this margin getting still worse. However, if they were to sell the swaps markets in fuel oil it would lock in the price 100%, and if the refinery margin improved they would not be able to benefit from that improvement. However, the refinery in this scenario decides to utilise a crack option. As discussed in earlier chapters, you can buy (or even sell) crack options on refinery margins (the same thing in the power industry would be considered spark spread options – the spread between input energy like natural gas, gasoil, fuel oil, or coal and the output of electricity in MWh). So, the refinery could buy a floor (put) option against the margin getting worse. The benefit of the option is that if the refinery margin improved, the refinery could benefit from 100% of the improvement (after the margin has improved enough to cover the cost of the option for the hedge). To reduce the cost of the crack option strategy, the refiner could ask market makers, banks and traders to quote a zero cost collar crack option structure. In this case the refiner would still buy a floor (put) on the crack margin against fuel oil, but would also sell some caps (calls) on the crack margin against fuel oil to generate some cash premium and subsi- dise or totally net out the cost of the floor crack option. In doing this the refiner would put a limit on the amount of improvement of the crack margin it can benefit from, but at least the cap can be placed higher than the current swap level. So the refiner would still have more chance to benefit from improvement than if it merely sold the fuel oil swaps at current market levels. 200 ENERGY PRI CE RI SK
    • CHAPTER 13 Risk Management Process and Policy Creation Guidelines THE RISK MANAGEMENT PROCESS The primary components of a sound risk management process are: ■ A comprehensive risk measurement approach. ■ A detailed structure of derivative position limits. ■ Clear guidelines and other parameters used to govern risk taken by offi- cers of the organisation. ■ A strong risk management information system for: ● Controlling risk. ● Monitoring risk. ● Reporting risk. These components are fundamental to both derivatives and non-deriva- tives activities. The underlying risks associated with derivatives activities, such as credit, market, liquidity, operations and legal risk, are not unique to the energy trading sector, but their measurement and in turn their management can be more complex than physical energy deals. As with all risk-bearing activities, the risk that an organisation takes in its derivatives activities should be properly supported by adequate working capital. The organisation should also ensure that its capital base is sufficiently strong to support all derivatives risks on a fully consolidated basis and that adequate capital is maintained in all of its group entities which are engaged in these activities. This is of even more importance if an organisation’s subsidiaries or any of its affiliates are ‘Specified Entities’ in any of its ISDA agreements. Any default, perhaps on a loan or even deriva- tive contract payment from one of its group companies, could impact on its own trading position in the markets and see counterparts closing out its positions due to a group company’s default (see Chapter 17 for more details about Specified Entities). 201
    • An organisation’s system for measuring the various risks of derivatives activities should be both comprehensive and accurate. These are some of the key points on risk recording: ■ Risk should be measured and aggregated across all derivatives activities to the fullest extent possible. ■ An organisation that uses derivatives should have a system in place that enables management to assess exposures on a consolidated basis. ■ The risk measurement system used, e.g. VAR, should be good enough to reflect accurately the multiple types of risks facing the organisation. (This will vary depending on the types of derivatives used.) ■ Risk measurement standards should be understood by relevant personnel at all levels of the organisation – from individual traders to the Board of Directors – and should provide a common framework for limiting and monitoring risk-taking activities. ■ The process of marking derivatives positions to market (for fair value accounting and management control purposes) is fundamental to measuring and reporting exposures accurately. ■ An organisation speculating in energy OTC derivatives and other traded derivatives should aim to have the ability to monitor the following on a daily basis: ● Credit exposures. ● Physical and derivative trading positions. ● Market price movements. Derivative position stress testing should also be included in any risk management policy. VAR can be a good system for clearly illustrating the US dollar risk that an organisation may take overnight within a certain level of confidence (e.g. 95% confidence level). However, VAR only predicts a possible reality and does not show exactly what that reality will be. For this reason, it is prudent to use stress testing alongside a VAR system. This should be conducted on a regular basis to assess the impact on the organisation should a disaster occur. For example, if there were a large standard deviation move from normal market situations (perhaps a 3 standard deviation market move), would the organisation survive the cash flow crunch? In the oil industry, the Gulf War period in the early 1990s provides a good real life scenario to run through a system using historical data. Sound risk measurement practices should include identifying possible events or changes in market behaviour that could have unfavourable effects on the institution and assessing the ability of the institution to withstand them. These analyses should consider not only the probability of an adverse event but also ‘worst case’ scenarios. It should also be noted that these same reports can help management and accounts departments to write up narrative disclosures for derivatives accounting disclosures, in 202 ENERGY PRI CE RI SK
    • line with more recent disclosure requirements (see Chapter 18 for infor- mation on international accounting standards for derivatives). Ideally, such ‘worst case’ analysis should be conducted on an organisa- tion- or group-wide basis by taking into account the effect of unusual changes in prices and or volatilities. It should also look at ‘What if?’ scenarios of market liquidity and the ‘What if?’ scenario created by early termination events under ISDA OTC Derivatives via a key default of a large counterpart across the derivatives and the physical energy trading portfolio. This scenario should include input from the organisation’s legal department to ensure that contingency plans for disaster scenarios are understood fully by all line managers. For a risk management process to be complete, these regular stress tests should not be limited to quantitative computation of potential losses or gains. They should include more qualitative analyses of the action plan that management might take under particular ‘disaster’ scenarios. It is certainly better for both management and traders to have a written policy for guidance in ‘What if?’ scenarios. These can be used to develop contingency guidelines and plans outlining operating procedures and lines of communication, both formal and informal. If something bad happens, the panic that follows could cost more in terms of lost reputation and money than the original problem. However, with forethought and contingency planning it is possible to bring some calm to such a situation. Even if the contingency plans don’t exactly meet the demands of the situa- tion faced, they will make everyone focus on resolving the issue rather than allowing the problem to get worse. TRADING CONTROLS – POSITION LIMITS A sound system of integrated organisation limits and risk-taking guide- lines are essential components of the risk management process. This is the first line of defence against internal fraud, as well as enabling derivative position control, risk management reporting and subsequent action plans by management and traders alike. The system may require a big invest- ment in terms of both human resources and cash, but it will pay for itself many times over, especially if it is implemented from the start of deriva- tives trading. Such a trading/position limit system should set boundaries for organisa- tional risk-taking and risk-reduction through hedging and should also ensure that positions that exceed certain predetermined levels receive prompt management attention. Any position control breach should trigger the creation of what is termed an ‘exception report’ which manage- ment should review on at least a daily basis. The derivative position limit system should be consistent with the effectiveness of the organisation’s TRADING CONTROLS – POSITION LIMITS 203
    • overall risk management process and with the adequacy of its capital posi- tion. Just because an organisation is not speculating but hedging does not mean that position controls are not needed. It is important that manage- ment can make sure the extent of hedging is within board-approved remits and policy. If derivative position limits are breached, such occur- rences should be made known to senior management and the position should be reduced immediately or the larger position approved only by authorised personnel. Although position limits are not restricted to the size of a position, they also include the types of derivatives used and the choice of energy prod- ucts in which derivatives can be used by the organisation. Clear details should be written in the risk management policy and made available to traders so they know which derivatives in which energy products they can use, and sometimes for hedging which risks. If the organisation is also speculating then the policy would go through in detail the size limits of positions based on tenure (how far forward). Due to liquidity concerns an organisation may, for example, say that a trader can trade Naphtha Swaps up to 6 months forward but no further. An accurate and timely management information system is essential to the proper operation of derivatives activities, the more real-time the better. In terms of accuracy, as they say, garbage in, garbage out: a system is only as good as the quality of the data going in to it. (This is discussed in Chapter 9.) In speculative trading operations, there should be reports across all markets on the gross plus net exposures broken down by energy market and counterpart, showing the net position on each market and the overall VAR or other risk measurement result for the organisation. This report plus profit and loss statements should be reported at least daily to managers not active in trading (i.e. those who supervise but who do not 204 ENERGY PRI CE RI SK POSITION LIMITS ■ By energy product/type, e.g. Dubai crude, UK NBP Gas, Singapore Gasoil 0.5%, New York Harbor Unleaded Gasoline ■ By type of derivative – swaps, futures, options, exotic options ■ By tenure – how big a position can be put on and how far forward, e.g. Dubai Crude swaps 2 million barrels – 1 to 6 month forward and 1 million barrels 7 months to 12 months forward. ■ By division or office ■ By individual trader ■ By group of offices/divisions (depending on size of operation)
    • themselves conduct trading activities) to ensure an adequate segregation of duties. End users who are using derivatives infrequently for long-term hedging are still advised to generate profit and loss statements (i.e. fair value marked-to-market calculations of their hedge versus underlying energy market exposure to ensure that their hedge is effective and how it is performing on a close of business basis every day). Any other position and disaster scenario reporting may seem excessive and lots of additional reporting and assessment of cash-flow risk and risk reduction through hedging may not be necessary. However, it is up to the management of the organisation to make a final choice as to what level of reporting seems appropriate and what level seems excessive, given their firm’s level of derivatives usage. Reports on derivatives positions for higher levels of senior management and the Board may occur less frequently, but the frequency of reporting should provide these individuals with adequate information to assess the changing nature of their organisation’s risk profile. After all, they are ulti- mately responsible to shareholders if anything goes wrong. For compa- nies using derivatives for hedging purposes for long-term energy exposures who do not frequently change their derivatives position, quar- terly reporting to the Board is probably sufficient in most cases. If an organisation is changing or adding to its derivatives positions on a more frequent basis, then monthly reporting to the Board may be more prudent. Better still, if an organisation implements a computerised risk manage- ment system, it will allow the Board members at any time to view a snap- shot of the organisation’s derivatives and (if applicable) physical energy portfolio as well as the resultant risk profile of the firm. This should be backed up with a mandatory update to the board, perhaps every quarter or when felt appropriate to the organisation’s specific needs. Risk management information systems should ideally translate the measured risk for derivatives activities (combined with physical energy trading activity if applicable) from a technical and quantitative format to one that can be easily read and understood by senior managers and direc- tors. VAR methodologies can be very useful in this situation as, by their very nature, they present risk as a monetary value over a given time period within a certain percentage probability. SOME KEY GUIDELINES FOR A RISK MANAGEMENT POLICY The following is a non-exhaustive list of guidelines for a risk management policy. It tries to capture both the spirit of what a risk management policy SOME KEY GUI DELINES FOR A RISK MANAGEMENT POLICY 205
    • should be aiming to cover and the core contents of a policy for any organisa- tion, whatever its purpose of using derivatives. Of course, every organisa- tion’s needs are different, but this should give a flavour of what is required. ■ Approve risk management policy at Board level. This level of approval should include the scope of the organisation’s usage of derivatives and the general policies to be applied. What is the goal of the organisation by using derivatives? Hedging or trading? ■ Value derivatives positions on a daily basis at fair value/market value, at least for risk management reporting purposes. ■ Quantify the organisation’s market risk under adverse market condi- tions against limits by performing stress testing simulations. ■ Assess the credit risk arising from derivatives activities based on frequent measures of current and potential exposure against credit limits and counterparts. Is there too much exposure to any single coun- terpart? Is there a credit risk mitigation and control policy? Can the organisation utilise credit derivatives or credit insurance? ■ Do not become involved in a product at significant levels until senior management and all relevant personnel (including those in risk management, internal control, legal, accounting and auditing) under- stand the product and are able to integrate the product into the organi- sation’s risk measurement and control systems. ■ Reduce credit risk by broadening the use of multi-product master agree- ments with netting provisions. ■ Establish market and credit risk management functions with clear authority independent of the front office derivatives trading function (segregation of duties). ■ Authorise only professionals with the required skills and experience to transact and manage the energy risks, as well as to process, report, control and audit derivatives activities. ■ Establish management information systems sophisticated enough to measure, manage and report the risks of the types of derivatives used. ■ Adopt fair value derivatives accounting and disclosure practices (e.g. FAS 133 or IAS39) ■ Value derivatives portfolios of dealers based on mid-market levels less specific adjustments, or on appropriate bid or offer levels. Mid-market valuation adjustments should allow for expected future costs such as unearned credit spread, close-out costs, investing and funding costs, and administrative costs. ■ Once a method of risk measurement is in place, market risk limits must be based on factors such as: management tolerance for low probability extreme losses versus higher probability modest losses, capital resources, market liquidity, expected profitability, trader experience and business strategy. 206 ENERGY PRI CE RI SK
    • ■ An organisation using derivatives should use a consistent measure to calculate on a daily basis the market risk of their derivatives positions and compare it to market risk limits. Market risk is best measured as ‘value at risk’ using probability analysis based upon a common confi- dence interval (e.g. two standard deviations) and time horizon (e.g. a one-day exposure). ■ Dealers should regularly perform simulations to determine how their portfolios would perform under stress conditions. ■ Dealers should have a market risk management function, with clear independence and authority. ■ Stress testing should be included in any sound risk management policy. These simulations should reflect both historical events and future possi- bilities. Stress scenarios should include not only abnormally large market swings but also periods of prolonged inactivity. The tests should consider the effect of price changes on the mid-market value of the port- folio, as well as changes in the assumptions about the adjustments to mid-market (such as the impact that decreased liquidity would have on close-out costs). Dealers should evaluate the results of stress tests and develop contingency plans. ■ Dealers should periodically forecast the cash investment and funding requirements arising from their derivatives portfolios. The frequency and precision of forecasts should be determined by the size and nature of mismatches. A detailed forecast should determine surpluses and funding needs by currency over time. It also should examine the poten- tial impact of contractual unwind provisions or other credit provisions that produce cash or collateral receipts or payments. There have been instances of currency problems for hedgers using derivatives. One highly publicised case in the late 1990s was Korean Airlines, which hedged Jet Fuel using US dollar-denominated swaps. However, the core cash flow of the company was in Korean won. Unfortunately, the won versus US dollar currency rate moved dramatically and Korean Airlines wound up with compounded losses via forex risk on deriva- tives hedges as it had to buy additional US dollars at a bad exchange rate to meet settlements on maturing Jet Fuel swaps. ■ Independent risk managers should ensure that the following responsi- bilities are carried out: ● The development of risk limit policies and the monitoring of transac- tions and positions for adherence to these policies. ● The design of stress scenarios to measure the impact of market condi- tions, however improbable, that might cause market gaps, volatility swings, or disruptions of major relationships, or might reduce liquidity. ● The monitoring of any variance between the actual volatility of port- folio value and that predicted by the measure of market risk (e.g. VAR). SOME KEY GUI DELINES FOR A RISK MANAGEMENT POLICY 207
    • ● The review and approval of pricing models and valuation systems used by front- and back-office personnel, and the development of reconciliation procedures if different systems are used. ■ Organisations are advised to set up a market risk management function. This is usually headed by a Board level or near Board level executive in the organisation. ● The market risk manager should act as a catalyst for the development of sound market risk management systems and procedures. He or she should review trading performance by deciding whether results are consistent with those suggested by analysis of value at risk (if this is the risk measure employed by the organisation). The market risk manager is rarely involved in actual risk-taking decisions. End users could have someone on the Board who is trained on derivatives and who can act as another backstop to questioning the success of risk management or trading programmes. ■ End-users should adopt the same valuation and market risk manage- ment practices that are recommended for speculative traders (as appro- priate to the nature, size and complexity of their derivatives activities). Specifically, they should consider: regularly marking to market their derivatives transactions for risk management purposes, periodically forecasting the cash investing and funding requirements arising from their derivatives transactions, and establishing a clearly independent and authoritative function to design and assure adherence to position and or risk limits set by the organisation. ■ Most end-users may not expect any significant change in the combined value of their derivatives positions and the underlying energy expo- sure, as they are hedging an underlying or future exposure to energy price. But even if this is expected to be the case, an end-user should establish hedge performance assessment and derivatives/management control procedures that are appropriate for their derivatives activities. ■ Speculative traders and end-users hedging using derivatives should measure their credit risk exposure on derivatives in two ways: ● Current exposure, which is the replacement cost of derivatives trans- actions, that is, their market value. ● Potential exposure, which is an estimate of the future replacement cost of their derivatives transactions. It should be calculated using probability analysis based upon broad confidence intervals (e.g. two standard deviations) over the remaining terms of the transactions. This allows them to answer the following important questions about credit risk: ● If a derivatives counterpart was to default today, how much would it cost to replace the derivatives transaction with that counterpart? ● If a counterpart defaults in the future, what is a reasonable estimate of the future replacement cost? 208 ENERGY PRI CE RI SK
    • ■ Any credit risk on derivatives, and all other credit exposures to a single counterpart should be aggregated, taking into consideration any enforceable netting arrangements. Credit exposures should be calcu- lated regularly and compared to credit limits. In calculating the current credit exposure for a portfolio of transactions with a counterpart, the first question is whether netting applies. If it does, the current exposure is simply the sum of positive and negative exposures on transactions in the portfolio. Master netting agreements which cover both physical energy and derivatives positions are still in the early stages of develop- ment, but they are possible. More common are the netting agreements for derivatives within ISDA master agreements. ■ Traders and end-users of derivatives should have an independent credit risk management function with analytical capabilities in deriva- tives, responsible for: ● Approving credit exposure measurement standards. ● Setting credit limits and monitoring their use. ● Reviewing credits and concentrations of credit risk with counterparts. ● Reviewing and monitoring risk reduction arrangements and working with legal departments or lawyers to check their enforceability. (This may vary, depending on the jurisdiction of the counterpart.) ■ The credit risk management function should continually review the creditworthiness of counterparts and their credit limits. ■ Traders and end-users should have a policy to use one master agree- ment as widely as possible with each counterpart to document existing and future derivatives transactions. Master agreements should provide for payments netting and close-out netting, using a full two-way payments approach (see Chapter 17). ■ All users of derivatives should have a clear policy on credit risk reduction arrangements that can be useful in the management of counterpart credit risk (e.g. collateral and margin arrangements, and third-party credit enhancement such as guarantees or letters of credit – see Chapter 1). ■ Organisations using derivatives must ensure that their derivatives activities are undertaken by professionals in sufficient numbers (to reduce operational risk via dependence on single individuals) and with the appropriate experience, skill levels, and degrees of specialisation. These professionals should include specialists who transact and manage the risks involved, their supervisors, and those responsible for processing, reporting, controlling and auditing the activities. ■ Financial statements of derivatives users should contain sufficient infor- mation about their use of derivatives to provide an understanding of: ● Why derivatives transactions are undertaken. ● The extent of the transactions, in which markets and how much volume is transacted. SOME KEY GUI DELINES FOR A RISK MANAGEMENT POLICY 209
    • ● The degree of risk involved or how much this activity aims to reduce the overall risk of the organisation, if hedging. ● How the transactions have been accounted for (i.e. which accounting standard the organisation has adopted for accounting its derivatives positions on its balance sheet). ■ Know the market; have a policy for assessing new derivatives markets and whether they are appropriate for the organisation’s trading or risk management needs. From this assessment an organisation should be able to answer key questions like: ● Is the new market appropriate for the organisation? ● Does it offer effective hedges? If so, against which exposures of the organisation? ● What are the liquidity issues? ● Who are the main participants in this market? Are there any credit issues with these counterparts? 210 ENERGY PRI CE RI SK
    • CHAPTER 14 Applied Technical Analysis in the Energy Markets Timing is the key to any successful trading or hedging program. But getting the timing right will always be more of an art than an exact science. However, there are some tools that can help to build up a clearer picture of when the market price trend may change, which in turn should provide an idea of market direction and timing. There are two main types of analysis that can be carried out: funda- mental analysis and technical analysis. Fundamental analysis deals with the supply and demand factors of the physical energy world, whereas technical analysis is concerned with the price history of the market. In reality, most people use a combination of the two – what could be termed ‘techno-fundamental’ analysis. In other words, when a general technical picture of market direction and timing has been established, any new fundamental information can be incorporated into the picture as it is announced. If a trader starts with a clear technical picture, then whenever news or information comes into the market during the trading day, he or she should ask three key questions: Is this new news? Is this fresh news? Has the market already seen this? The last question is important, because some- times information or events are rumoured in the market and, as the saying goes, people ‘buy the rumour and sell the fact’. The can sometimes lead to a situation in which the market will fall on bullish news or rise on bearish news. In these instances the news or information was already in the price, so the confirmation of the news gave the signal for people who were specu- lating on the rumour to take their profit and close out their position. This chapter presents the key technical approaches and tools that work well together when applied to major energy futures markets. Note the word ‘together’: technical analysis is a bit like detective work, in that it requires ongoing attention to all evidence that might support any theory on the direction of price trend and the timing of entry and exit. 211
    • WHAT IS TECHNICAL ANALYSIS? Figure 14.1 is a typical futures bar chart, each bar representing a single time period. The example above is a daily bar chart, so each bar represents one trading day. The line on the left-hand side of the bar represents where the market opened (first traded price of that trading day) and the top of the bar is the high of the day and the lowest level of the bar is the low of that day. The line on the right-hand side of the bar represents the closing price (last traded price/official settlement price). The arithmetic scale is the most popular one used for bar chart construction showing price and time. The logarithmic scale is of little use for technical analysis, although it can be useful for bringing different commodities down to the same scale for analysing which markets are taking the lead in percentage terms. There are a number of ways of defining technical analysis, but, in a nutshell, it is the study of market prices, with price charts being the primary tool (see Figure 14.1). It is based on the idea that historical price movements of a commodity can be used to predict the sentiment and the expectations of market participants with regard to the future price trends. Another way of looking at technical analysis is to see it as applied social psychology, because it sets out to recognise trends and changes in crowd behaviour. In many ways, technical analysis is all about trying to predict what the majority of traders believe will happen next, in terms of the price direction of the market. In fact, one of the main reasons that technical analysis works is simply that everyone believes it works. The majority of people trading in the markets are influenced by technical analysis, so its predictions can be, to some extent, self-fulfilling. It therefore follows that 212 ENERGY PRI CE RI SK H O C L FIGURE 14.1 Technical analysis – bar chart. A bar chart displays a security’s open (if available), high, low, and closing prices. Bar charts are the most popular type of security chart
    • we must examine the key technical analysis tools that the majority will be basing their decisions on. One thing is certain: technical analysis can help when making timing and market direction predictions. However, it is not enough to rely on a single technical tool; a combination of five or six technical tools and approaches is needed to help build up a good picture of market trend price targets and timing. It should also be remembered that there are certain types of market price movement that can render some technical analysis tools useless and too unreliable to follow. The key here is to recognise when technical analysis tools should be treated with caution. THE PRINCIPLES OF TECHNICAL ANALYSIS Technical analysis works on some key principles. These are:- ■ That all known market fundamentals (news in the market) are accounted for and are reflected in market prices. The market has absorbed all the news, and the price represents a consensus on where price should be, based on all known data. This is certainly true in effi- cient markets which have good trading volume (liquidity). ■ That prices move in trends and trends persist. ■ That market action is repetitive or cyclical. ■ If we accept the fact that human emotions and expectations play a role in commodity pricing, we should also admit that our emotions play a role in our decision making. The key rules for anyone looking to use technical analysis are: ■ Keep it simple. ■ Go with technical analysis tools and approaches that most of the world will be looking at. After all, you are trying to predict what the majority of traders are thinking. So it is important to watch the tools that they will be looking at, which in turn will affect their own perspective on future price trends to some extent. It is also useful to refer to news agency reports on the market, as these often discuss technical analysis tools on the market. You can be sure that these tools will have some bearing on perceptions of future trends. THE TECHNICAL ANALYSIS BAR CHART A history of technical analysis The roots of modern-day technical analysis are in the Dow Theory, devel- oped around 1900 by Charles Dow. Stemming either directly or indirectly THE PRINCIPLES OF TECHNICAL ANALYSIS 213
    • from the Dow Theory are principles such as the trending nature of prices, prices discounting all known information, volume mirroring changes in price and support and resistance. Of course, the widely followed Dow Jones Industrial Average is a direct offspring of the Dow Theory. The price of a commodity represents a consensus. It is the price at which one person agrees to buy and another agrees to sell. The price at which an investor is willing to buy or sell depends primarily on his or her expecta- tions. If she expects the security’s price to rise, she will buy it; if the investor expects the price to fall, she will sell it. These simple statements are the cause of a major challenge in forecasting commodity prices, because they refer to human expectations. As we all know, humans are not easily predictable. This fact alone will keep any mechanical trading system from working consistently. Because people are involved, many investment decisions are based on criteria that might be considered not strictly relevant. After all, our confi- dence, expectations and decisions in the market can all be influenced by a large number of factors: relationships with family, neighbours and employer – or even traffic, income or previous success and failures, none of which could ever be successfully quantified in a statistically based model! 214 ENERGY PRI CE RI SK BULLS AND BEARS The origins of the terms bull trend (market moving higher) or bear trend (market moving lower) come from the days of the early commodity markets In London. At the time, bull fighting and bear fighting were both popular spectator sports in the city. The terms for the direction of financial and commodity markets are based on the way in which bulls and bears fight. A bull will attack with its horns, pick up its opponent and throw him up in the air, whereas a bear will stand up on its back legs and drop down on top of its opponent, crushing him with its weight.
    • Trendlines Before getting into any mathematical analysis calculations, there is a lot of information and guidance on future price movements that we can extract from the basic open, high, low, close price chart (Figure 14.2). The concept of a trend is essential to this approach to technical analysis. Generally, the trend is simply the direction of the market. More precisely, market moves are usually a series of zigzags, resembling a series of waves with fairly obvious peaks and troughs. It is the overall direction of these peaks and troughs which constitute market trend. Most of the time, traders watch for a change in trend and subsequent confirmations that the trend is changing or has changed before acting on that information. Trendlines play an important part in illustrating that a change has been made and also give traders an indication of the price levels that might trigger a price change or a new buying or selling interest. Trendlines should be drawn off two price points – a high or low and the earliest price points that can be found. The trendline should then be confirmed by a third test as illustrated in Figures 14.3 and 14.4. Other notes on trendlines The relative steepness of the trendline is also important. In general, most trendlines tend to approximate to an average slope of 45°. Such a line reflects a situation where prices are advancing or declining at such a rate that price and time are in perfect balance. It is rare to find a trendline which is exactly at a 45° angle, but we can say that, in a bullish market, if the trendline is too steep (above 45°), it indicates that prices are advancing too rapidly and that the current steep move up will not be sustained. Figures 14.5 and 14.6 show some features of trendlines. For trendline A, the support trendline initially holds as support but is then broken. THE TECHNICAL ANALYSIS BAR CHART 215 H O C L FIGURE 14.2 Trendlines
    • For trendline B, the support trendline holds as support and then resis- tance and then support again (it is quite common for a trendline to offer both support and resistance). For trendline C, the resistance trendline then becomes support a few months later. 216 ENERGY PRI CE RI SK Rising trendline FIGURE 14.3 Uptrend or bull trend chart sourced from and © FutureSource UK Inc. Trendline FIGURE 14.4 Downtrend or bearish trend chart sourced from and © FutureSource UK Inc.
    • THE TECHNICAL ANALYSIS BAR CHART 217 A B C FIGURE 14.5 IPE Brent Crude Oil; chart sourced from and © FutureSource UK Inc. A B C = Successful test and confirmation of Trendline FIGURE 14.6 NYMEX WTI Crude Oil; chart sourced from and © FutureSource UK Inc.
    • Trendline and breakout A breakout is where a trendline is finally broken (see Figure 14.5, line A), indicating that if good trading volume is seen at the same time, a change in price trend could be taking place. Other indicators help to identify when a trend change may take place, which is usually followed by a break in the trendline, giving confirmation of a trend change; see Figure 14.7. It is important to remember that the more times a trendline is tested and held, whether as resistance or support, the greater will be the subsequent market price move or reaction away from that trendline when it is finally broken with the inevitable breakout. Support and resistance Alongside trendlines on charts, clear patterns of support and resistance can also be spotted. If the energy price is thought of as an ongoing war between the bull (the buyer) and the bear (the seller), then support and resistance levels can be seen as the battlefields in that war. In other words, support and resistance levels represent barriers to change. A good way to quantify expectations following a breakout from a trendline or from resistance or support levels is to look at the volume asso- ciated with the price breakout. If prices break through the support/resis- tance level with a large increase in volume (Figure 14.8) and the move back is on relatively low volume (resistance becomes support) it implies that the new expectations will rule (a minority of traders are unconvinced). Conversely, if the breakout is on moderate volume and the move-back period is on increased volume, it implies that very few traders’ expecta- tions have changed and a return to the original expectations (i.e. original price trend) could be seen. Volume Low volume levels are characteristic of indecision (if there are no major international holidays at the time!) or an expectation of possible change. This typically occurs during price consolidation periods – periods when prices move sideways in a trading range. Low volume also often occurs in the indecisive period during market bottoms or tops. Sometimes traders and brokers will refer to the market ‘bottoming out’ or ‘looking toppy’. This means the market may reverse its previous trend. 218 ENERGY PRI CE RI SK 1 2 3 4 5 Breakout FIGURE 14.7 Breakout
    • On the other hand, high volume levels are characteristic of market tops when there is a strong consensus that prices will move higher. High volume levels are also very common at the beginning of new trends (i.e. when prices break out of a trading range). For example, just before market bottoms, volume will often increase due to panic-driven selling. Volume can also help determine the health of an existing trend, by indi- cating whether it is a strong or weakening. A healthy uptrend should have higher volume on the upward legs of the trend and lower volume on the downward (corrective) legs. A healthy downtrend usually has higher volume on the downward legs of the trend and lower volume on the upward (corrective) legs OTHER TYPES OF CHART Candlestick charts In the 1600s, the Japanese developed a method of technical analysis to analyse the price of rice contracts. This technique is called candlestick charting. Candlestick charts display the open, high, low and closing prices in a format similar to a bar chart, but in a way that highlights the relationship between the opening and closing prices (Figure 14.9). Candlestick charts are simply another way of looking at prices that don’t involve any calculations. They have their uses, especially for traders in markets such as bonds, but in the energy markets there is only one key formation that is worth OTHER TYPES OF CHART 219 Resistance Support FIGURE 14.8 Breakout and increasing volume
    • looking out for, as it can give an early warning of a major trend change. This is the ‘DOJI’ formation as illustrated in Figure 14.10. I have noticed this ‘DOJI’ formation on three or four occasions over the past seven years, and when it has shown up in Nymex or IPE Futures contracts, it has been followed by a trendline support break, and in one instance the market dropped some US$3 a barrel on IPE Brent in just a few days. The VIP relationship (volume, open interest and price) It is possible to build up a good picture of what the market is thinking from a combination of trendline analysis (using charts, support/resistance levels), volume (using the total market volume) and open interest information. 220 ENERGY PRI CE RI SK The highest price (‘upper shadow’) The lowest price (‘upper shadow’) The opening or closing price, whichever is greater The opening or closing price, whichever is less The centre section (‘real body’) is filled in if the close is lower than the open. Otherwise it is left empty. FIGURE 14.9 A candlestick chart 14.00 13.90 13.80 13.70 13.60 13.50 13.40 13.30 13.20 13.10 13.00 Dollars OR Open and close at the same level Of particular interest on a trading day when a new price extreme has been tested but the has failed to close towards it FIGURE 14.10 The DOJI formation
    • Volume is a simple but key aid when analysing the market. It can give a good real-time signal as to the level of interest in a new trend starting or an old trend finishing. This, combined with open interest (which is available in futures markets contracts but not equities), gives a very good combina- tion tool to analyse whether a trend could continue or may be coming to an end. Open interest is the net number of futures or option contracts in exis- tence on an exchange, counting a bought contract and a sold contract as one open contract, or a figure of 1 in open interest terms. Table 14.1 lists the various VIP relationships. Figure 14.11 is a graphical illustration of the VIP relationship. In section (1), the market is moving higher, volume is increasing and open interest is increasing. This shows that the bullish uptrend is well supported with new buyers coming into the market. In section (2), the market is moving higher, but volume and open interest are decreasing. This shows that there is no new interest in contin- uing the bullish trend and in fact, with open interest decreasing, the market looks like it is closing out of (selling out of) previously bought OTHER TYPES OF CHART 221 Price Volume Open interest Trend (1) (2) (3) (4) Strong Weak WeakStrong FIGURE 14.11 The VIP relationship Price Volume Open interest Market is... Rising Increasing Up Strong bullish Rising Decreasing Down Trend weakening; watch for reversal Falling Increasing Up Strong bearish Falling Decreasing Down Trend weakening; watch for reversal TABLE 14.1 The VIP relationship
    • (long) positions which could be showing a profit. This market trend is showing signs of weakness, so watch out for a change in direction. In section (3), the market has changed direction and started moving lower. Volume and open interest both increased, illustrating new selling interest coming into the market, which in turn supported the bearish trend. In section (4), the market is moving lower still but on lower volume; open interest is also reducing, showing that some players are slowly losing confidence in the current trend continuing. As a result, they are buying back previously sold positions, taking profits and closing out their posi- tions, which is reducing open interest. End of trend signal The end of a trend is often signalled when volume becomes progressively smaller and smaller each trading day and the price range of trading days (the distance between the high and low price of the day) is also reduced. The period between one trend nearing its end and a new trend starting can be a time when the market is waiting to make a decision on a new trend. The decision is made once a trendline is broken or key support or resistance triggers renewed trading interest with increased volume. It is also worth emphasising that a significant increase in volume should always be seen when a trendline or a key support/resistance level is finally broken. If not, then it may be a false breakout. This can sometimes occur when markets are very quiet. Indeed, some speculators may be tempted to force the market on low volume through a well-publicised trendline level in an attempt to trigger some reaction in the market. PRICE GAPS AS PRICE TARGETS Another good way of determining where the market may head is to look out for price gaps on price charts (Figure 14.12). Energy futures markets often use price gaps as targets. A question many traders ask is how far back in time they should look for price gaps. I have found that on daily bar charts (where each bar represents one trading day) you can often see that price gaps that have occurred as much as three months in the past are still watched by the market. But price gaps are not just indicators of price targets. They can also indi- cate whether an old trend is going to start again. This can be seen in the case of a bullish trend, when a market breaks support and then comes down to aim for a price gap. If the market fills the price gap and holds the 222 ENERGY PRI CE RI SK
    • bottom of the gap (as in Figure 14.13) then it can be expected that buyers will come back and that the bullish trend will have a lease of new life. In Figure 14.13 the market has been in a bullish trend, but corrects downwards. The price gap is filled, but the market holds the bottom of the gap to continue the original bullish trend. In a case like this, renewed buying interest can normally be seen. In Figure 14.14, the market has been in a bearish trend and corrects upwards. The price gap is filled, but the market holds the top of the gap to continue the original bearish trend. In this case, renewed selling pressure can normally be seen. PRICE GAPS AS PRICE TARGETS 223 BREAKAWAY GAP EXHAUSTION GAP ISLAND REVERSAL TOP DOWNSIDE BREAKAWAY GAP RUNAWAY (or measuring) GAP FIGURE 14.12 Example of price gaps Price gap FIGURE 14.13 Price gap in a bullish trend
    • FIBONACCI RETRACEMENT LEVELS So far we have looked at trendlines which can help to identify trends and establish key support or resistance levels which can highlight a trend being broken. We have seen how volume data, open interest data and price data (VIP relationship) can give early warnings of trends coming to an end and how much interest there is from market participants to help continue the current trend. We have also looked at price gaps as price targets that give traders an idea of how much the market might move in a particular direction. Another good way to predict price targets is by using Fibonacci percentage retracement. Fibonacci was the nickname of the thirteenth century mathematician, Leonardo Pisano, who (re)discovered what is today known as the Fibonacci sequence. This is calculated by adding 1 + 1 and then contin- uing to add the sum to the previous number in the equence. The sequence gives rise to the following numbers: 1, 1, 2, 3, 5, 8, 13, 21, 34, 55 and so on. Ratios of these numbers to each other give us important values: 61.8%, 50% and 38.2%. The prevalence of these ratios can be found all around us – from the double helix of DNA to spiral galaxies. The pioneering work of traders like W. D. Gann (Gann lines) and R. N. Elliott (Elliott wave theory) also showed that these ratios are prevalent in the financial markets. When properly applied to energy futures markets, they are surprisingly reliable and the market watches these retracement levels avidly. Energy futures markets (e.g. IPE, NYMEX) tend to reverse or consoli- date once they reach one of these ratio levels (measured from the distance of the previous trends reversal). This means that they can be very useful as position entry and exit levels. There is a tendency for the energy futures markets to retrace down (during a bullish trend) or recover (during a bearish trend) by 50% before continuing the original trend. In the example given in Figure 14.15, the market retraces 50% then carries on the original bullish trend. Besides this 50% retracement, there are minimum and maximum retracements that should be allowed for: 38.2% and 61.8% respectively. What this means is that in a correction of a very strong trend, the market may only retrace 38. 2% of the previous move. If a trader is looking for a buying or selling opportunity (depending on the trend) the trader can compute the 224 ENERGY PRI CE RI SK Price gap FIGURE 14.14 Price gap in a bearish trend
    • Fibonacci retracement levels and use them as a reference point to enter or exit the market. Chart reading To identify Fibonacci retracement levels, the most recent highest point and lowest point in the futures chart should be identified. Once this is done, you are ready to measure the retracement percentages. Most energy futures contracts, after making long sustained moves in one direction, will eventually retrace a portion of the move, before contin- uing on to extend it. Most commercially sold stock-charting software packages will automatically draw in Fibonacci levels between short, medium, and long-term pivot points using traditional 38.2%, 50%, 61.8% and 100% retracement levels. These levels can be watched as price targets or resistance points when selling (profit-taking on long positions) or, when calculating levels in the opposite (downward) direction, price targets as support points where short covering (buying back) may occur and fresh buying interest should come in to the market. For technical analysis, the important thing is that, in the oil markets, people follow Fibonacci percentage retracements and in fact it works so well that sometimes the market has been seen to touch the Fibonacci target level exactly and then hold and recover its trend. MATHEMATICAL INDICATORS There are many types of mathematical indicators in the technical analysis field, but here we focus on some key ones which work on a consistent basis MATHEMATICAL INDICATORS 225 200 190 100 110 120 130 140 150 160 170 180 61.8% Retracement 50% Retracement 38.2% Retracement FIGURE 14.15 Fibonacci retracement levels
    • for the energy futures markets. These indicators can give a trader a simple yet very effective tool for building up a view on price direction and timing, when used in parallel with bar charts, support/resistance levels, gaps, trendlines, volume and open interest information. The RSI (Relative Strength Index) The easiest way to describe how RSI reflects the market is to say that RSI treats the futures market price as if it were a rubber band. The rubber band can be stretched just so far, but after a certain point, unless it breaks, it is forced to contract. The idea was developed by J. Welles Wilder and presented in his 1978 book, New Concepts in Technical Trading Systems. The RSI is a fairly simple formula: RSI = - + æ è çç ö ø ÷÷100 100 1 ( / )U D where: U = An average of upward price change D = An average of downward price change Basically, the RSI equals the average of the closes of the up days divided by the average of the closes of the down days. The time frame specified determines the volatility of the indicator. A lot of technical analysis books and even news reports talk about a 9 period, or 14 period and/or a 21 period time span for analysis. These time periods are usually applied most effectively to daily bar charts; however, there is nothing to stop you from applying the RSI to longer or shorter time frames. It is probably a good idea to use two RSIs rather than one. Using one short time period and one longer time period can help a trader to assess how much an energy futures market is overbought or oversold. (For energy futures, a 3 day RSI and a 14 day RSI are suggested.) ‘Overbought’ means that the market price has moved higher too quickly in the time period under analysis on the RSI, while ‘oversold’ means that the market price has moved lower too quickly in the period. RSI simple calculation method example For a 14 day RSI calculation, the following steps are involved: 1. Add the closing values for the up days and divide this total by 14. 2. Add the closing values for the down days and divide this total by 14. 3. Divide the up day average by the down day average. This results in the what we term the RS factor in the formula. 4. Add 1 to the RS. 5. Divide 100 by the number arrived at in Step 4 above. 226 ENERGY PRI CE RI SK
    • 6. Subtract the number arrived at in Step 5 above from 100. = 14 period RSI% RSI periods recommended for energy futures (14 day and 3 day) ■ 14 day RSI ● If the RSI is over 75%, the futures contract is overbought and it may be difficult for prices to move any higher. Prices should soon correct to the downside more severely than if the 3 day RSI were overbought. ● If the RSI is below 35%, the futures contract is oversold and prices should find support i.e. the market should find it difficult to move lower. Prices should correct to the upside ■ 3 day RSI – a very useful short-term entry/exit indicator ● If over 90%, the market is very overbought and if the market is trading technically it will probably struggle to move higher and the market should have a good intra day correction to lower prices. ● If below 20%, the market is very oversold and if the market is trading technically it will struggle to move lower. In this case, the market should have a good intra day recovery to higher prices. The guiding principle of the combined use of the 3 day and 14 day RSI is that if the market is looking overbought/oversold on the 3 day and the 14 day RSI you can gauge that more than just a one-day price correction may be seen; a price correction could be seen over several days. Figure 14.16 shows an example. MATHEMATICAL INDICATORS 227 3 day RSI 14 day RSI Nymex WTI Crude Oil Trendline The 3 day & 14 day RSI gave very overbought reading, signalling a correction to lower prices 2 days before it happened at point [A] [A] FIGURE 14.16 NYMEX WTI Crude Oil; chart sourced from and © FutureSource UK Inc.
    • MOVING AVERAGES There are three types of moving average available: simple, weighted and exponential. The critical element in a moving average is the number of time periods used in calculating the average. When using hindsight, it is always possible to find a moving average that would have been profitable. The 39 week moving average has an excellent track record in timing the major (long-term) market cycles. In energy markets on daily bar charts, a 13 day moving average based on closing (or last) traded price gives a very good buy/sell signal. A 13 day simple moving average (based on last market close price) can also prove very profitable as a buy/sell indicator for the oil futures markets. It is a Fibonacci number, but the reality is probably that this moving average has been highly publicised in the energy market and plenty of traders watch it closely. As with all technical indicators, simple moving averages should never be used on their own as they do have some disadvantages. One such disadvantage is that you have to wait for the market close to get the final indication whether to buy or sell! However, it can be a very valuable confirmation tool to add to your other indicators and build up your view of the market. Interpretation The most popular method of interpreting a moving average is to compare the relationship between a moving average of the commodities price with the commodities price itself. A buy signal is generated when the security’s price rises above its moving average and a sell signal is generated when the security’s price falls below its moving average; see Figure 14.17. The drawback to moving averages is that they can create false signals if the market is ‘range bound’, although they work really well in a trending market. The length of a moving average should fit the market cycle you wish to follow. Table 14.2 shows typical moving average periods. CHART PATTERNS What is a price chart pattern? Chart patterns are formations which appear on price charts of futures contracts (in this context) that can be classified into different categories. The type of chart pattern observed can give some big clues as to whether the market is going to continue its current price trend or whether it might 228 ENERGY PRI CE RI SK
    • reverse it. Some patterns will also give a clue as to how much the market may move. How many groups of chart patterns are there? There are two major groups of chart patterns: reversal patterns and continuation patterns. Reversal chart patterns indicate that a reversal in the market price trend is in the process of taking place. Continuation chart patterns suggest that the market is consolidating – it is resting perhaps because it was very overbought or oversold (this can be established by referring to the RSI level, as discussed earlier). Once this position has been relaxed the market will resume its original bull or bear trend. CHART PATTERNS 229 Trend Moving average Very short term 5–13 days Short term 14–25 days Minor intermediate 26–49 days Intermediate 50–100 days Long term 100–200 days TABLE 14.2 Typical periods for moving averages Sell Rangebound market triggers Buy then Sell Buy Sell 13 day moving average on IPE Brent Crude Oil 2002 US$7 dollar profit per barrel FIGURE 14.17 13 day moving average on IPE Brent Crude Oil; chart sourced from and © FutureSource UK Inc.
    • By examining charts on a regular basis, a trader can develop a profes- sional intuition and observational skill as to whether or not a chart pattern that is forming is a reversal pattern or a continuation pattern. The earlier this can be detected, the better. Triangle formations During the development of triangle formations, volume should diminish as the price swings narrows within the triangle. The tendency for volume to contract is true of all consolidation patterns. The volume should increase significantly once the market breaks out of the triangle forma- tion. A lack of volume increase may warn that the market is not confident of this market direction. A benefit of the triangle formation is that it gives both an indication of timing when a breakout will occur and also an idea of the direction of that breakout. Symmetrical triangle at the beginning of an uptrend (continuation pattern) The symmetrical triangle at the beginning of the uptrend in Figure 14.18 signals that a bigger uptrend is still to come. Notice the reduction in volume during the formation of the triangle and the sudden burst of volume trading activity on the breakout. Symmetrical triangle in the middle of an uptrend (continuation pattern) The symmetrical triangle at the beginning of the uptrend in Figure 14.19 signals a bigger uptrend still to come (continuation pattern). Notice the levelling of the volume during the formation of the triangle and the burst of activity on the breakout. All triangle formations not only give us an indication of a continuing trend but also an indication of a price target. 230 ENERGY PRI CE RI SK Volume reduces during formation of triangle Clearly increases on breakout FIGURE 14.18 Symmetrical triangle at the beginning of an uptrend; chart sourced from and © FutureSource UK Inc.
    • Symmetrical triangle at the beginning of a downtrend (continuation pattern) Figures 14.20 and 14.21 show symmetrical triangles at the beginning and in the middle of a downtrend. Ascending triangle in an uptrend (bullish continuation pattern) Figures 14.22 and 14.23 show ascending triangles in an uptrend. Volume falls off during the formation, picks up and then expands on the breakout and following upmove. CHART PATTERNS 231 Volume reduces during formation of triangle Clearly increases on breakout FIGURE 14.19 Symmetrical triangle in the middle of an uptrend; chart sourced from and © FutureSource UK Inc. To gauge a target price, measure the height of the gap at the widest part of the triangle and project this distance from the breakout point FIGURE 14.20 Symmetrical triangle at the beginning of a downtrend; chart sourced from and © FutureSource UK Inc.
    • 232 ENERGY PRI CE RI SK Volume reduces during formation of triangle then clearly increases on breakout FIGURE 14.21 Symmetrical triangle in the middle of a downtrend; chart sourced from and © FutureSource UK Inc. FIGURE 14.22 Ascending triangle in an uptrend; chart sourced from and © FutureSource UK Inc. Notice flat top FIGURE 14.23 Ascending triangle in an uptrend; chart sourced from and © FutureSource UK Inc.
    • Descending triangle in a downtrend (bearish continuation pattern) Figures 14.24 and 14.25 show descending triangles in a downtrend. Falling wedge – bullish pattern Figure 14.26 shows a falling wedge in an uptrend. After more than a $2.00 rally, the market pauses before continuing higher for bull run. Volume is reduced during this pause and then picks up on the final breakout. Again a useful thing about triangle formations is that they can help predict when a breakout will happen. A trader can extend the trendlines forming the triangle and see when the lines converge, and this will give a good idea of the latest date for the market to break out by default, even if it just continues to trade sideways. CHART PATTERNS 233 Notice flat bottom Volume reduces during formation of triangle then clearly increases on breakout FIGURE 14.24 Descending triangle in a downtrend; chart sourced from and © FutureSource UK Inc. FIGURE 14.25 Descending triangle in a downtrend; chart sourced from and © FutureSource UK Inc.
    • Falling wedge in downtrend (bullish pattern) This pattern (Figure 14.27) was able to reverse the downtrend nicely. Volume drops off in the wedge and then comes back as the market moves out of the pattern. Rising wedge (bearish pattern) The rising wedge (Figure 14.28) will put a stop to an uptrend. Volume tails off as the trend struggles to continue. Finally, volume expands as the market falls through the bottom of the wedge and the new downtrend begins. The rising wedge of Figure 14.29 seemingly presented an area of indeci- sion. However, within a few weeks, the market resolved itself in the direc- tion of the trend (down.) As usual, volume increases on the breakout after diminishing during the pattern. 234 ENERGY PRI CE RI SK FIGURE 14.27 Falling wedge in a downtrend Volume reduces during formation of triangle then clearly increases on breakout FIGURE 14.26 Falling wedge in an uptrend; chart sourced from and © FutureSource UK Inc.
    • The head and shoulders (reversal pattern) This is probably one of the most difficult chart patterns to spot, but it is a clear signal of impending change. Apart from being one of the more complex chart patterns, it is probably one of the best known and most reli- able reversal patterns. Figure 14.30 shows an example. The head and shoulders pattern of Figure 14.31 reversed a one-year- long bullish trend in the NYMEX WTI Crude Oil Futures Market. Referring back to gaps, this crude oil technical move even had a ‘break- away gap’ as well which triggered even more aggressive selling pressure, than a mere break of the ‘neckline’ trendline of the head and shoulders reversal pattern. Inverted head and shoulders (reversal pattern) The inverted head and shoulders pattern of Figure 14.32 reversed a minor downturn in NYMEX Unleaded Gasoline Futures and we could even see a CHART PATTERNS 235 FIGURE 14.28 A rising wedge FIGURE 14.29 A rising wedge: indecision
    • breakaway gap, showing real momentum for the new uptrend. Volume increased on the breakout of the neckline trendline. Notes on head and shoulders formations The left and right shoulders should be about the same height, most impor- tantly the right shoulder should not be above the left. The head should be higher than both shoulders. Volume should be declining during the formation of this pattern. The neckline can be drawn from the lows made after the formation of the left shoulder and the head. Once this neckline is broken, the formation is completed. This formation gives an idea of market direction and also an idea on price targets. A trader can take the distance from the head to the 236 ENERGY PRI CE RI SK Uptrend proceeding with no signs of a top Correction to this level on lighter volume At this point (head) an experienced technician may spot that the rally to new highs is on smaller volume than on the last rally (shoulder) Correction to this low level below the left shoulder followed by a move to develop the right shoulder completed trend reversal the formation and warns of a major FIGURE 14.30 Head and shoulders pattern Breakaway gap Neckline trendline FIGURE 14.31 Head and shoulders pattern reversing a bull trend
    • neckline, and project this downward from the point that the neckline was broken to give us a price target indication. In the oil markets though, the head and shoulder pattern has been seen to work except that only about 75% of the price target was reached. This is fairly common and a lot of people watch out for the formation, so many traders pre-empt and trade ahead of the price target being reached. Head and shoulders (bearish continuation pattern) This bearish continuation pattern cannot be confused with the reversal head and shoulders (although the pattern is identical) because the pattern is preceded by a bearish market. The same volume patterns apply and volume should decrease during the formation of the shoulders and head. Flag formations (continuation pattern) The flag formation is quite common in the oil futures market. The flag represents a brief pause in a large market move. In fact, one of the require- ments for the flag is that it is preceded by a sharp and almost straight line move. It represents situations where a steep advance or decline requires a pause, before running off again in the same direction The flag should slope against the trend. Volume should reduce during the formation and build up again on the breakout. The flag usually occurs near the midpoint or halfway mark of the move. Bull flag in an uptrend (halfway mark) This chart pattern (Figures 14.33) indicates that the trend has only reached half of its potential. The market could be consolidating due to RSIs being overbought before carrying on with its trend. CHART PATTERNS 237 Head Left shoulder Right shoulder FIGURE 14.32 Inverted head and shoulders pattern
    • Bear flag in a downtrend (halfway mark) Figure 14.34 shows a bear flag in a downtrend. Pennants Pennants are a continuation pattern. In Figure 14.35, the bullish pennant is preceded by a bull trend. In Figure 14.36, the bearish pennant is preceded by a downtrend. Double tops and bottoms Figure 14.37 – a double top – is an example of a trend reversal. The failure of prices to exceed the previous peak followed by a downside break of the previous low constitutes a downside trend reversal. Figure 14.38 is an example of a bottom reversal pattern, Usually the first sign of a bottom is the ability of prices to hold a previous very recent low. 238 ENERGY PRI CE RI SK FIGURE 14.33 Bull flag in an uptrend FIGURE 14.34 Bear flag in a downtrend
    • This is then confirmed once recent resistance is broken. Volume should look to increase and the speed of the market moving away from the bottom should increase. CHART PATTERNS 239 FIGURE 14.35 A bullish pennant FIGURE 14.36 A bearish pennant Double top FIGURE 14.37 A double top
    • SUMMARY There are a large number of tools that can be used for technical analysis of the market and it is important that they be used in combination with each other. But even if the five or six most appropriate analytical tools have been chosen to study the prevailing conditions, the results may still not always prove utterly reliable. The truth is that in the real world there are some days when technical factors drive the market and others when it is driven by fundamentals. The key is to identify and keep asking the same questions over and over again: What is driving the market – technical factors or fundamentals? Is there fundamental news that has not yet been absorbed by the market price in turn, by the technical analysis? Successful traders know that important fresh news will always have to be absorbed into the price before it turns up in the charts. 240 ENERGY PRI CE RI SK Double bottom FIGURE 14.38 A double bottom
    • CHAPTER 15 After Enron – A Practical Guide to Credit Control and Risk Mitigation Methods The energy industry is the lifeblood of global economies, and a key lesson that the energy industry has learnt from the Enron situation in 2001 is that credit is the lifeblood of the energy industry. Keeping a strong credit rating should be central to an energy firm’s goals. It is fair to say that since the collapse of Enron far more energy companies have been managing their credit lines in similar ways to banks, by stressing the role of margining. This chapter reviews some of the established and new methods that corpora- tions have at their disposal to manage credit risk exposure effectively. THE COLLAPSE OF ENRON Enron never had a particularly good credit rating, but its standing in the market was as a key player; companies in the energy markets had to be able to trade with Enron. This often meant that energy players were commercially forced into a position where they had to take larger credit risks than they might have normally with a BBB+ rated entity, otherwise they would lose profitable trading opportunities. The advent of Enron Online made it even more difficult for energy market participants to have any chance of avoiding credit exposure with Enron. What is quite stunning and also rather unnerving was the speed at which Enron, a company held in high regard by the energy market, went from BBB+ to Chapter 11: 15 October 2001 to 3 December 2001: ■ 15 October 2001: Enron released earnings announcing a $2.2 billion equity write-down, including $1.2 billion stemming from the erroneous accounting of various financial partnerships. 241
    • ■ 16 October 2001: Rating agencies reaffirmed Enron’s BBB+ rating. Standard & Poor’s press release stated: ‘The equity account reductions will have no direct effect on Enron’s cash flow. However, the company’s financial flexibility may be impaired because of the decline in Enron’s equity value, which could lead the company to rely more on debt for its future financing needs. Capital expenditures over the near to medium term are manageable and can be financed out of operating cash flow, which will ease any liquidity concerns and help maintain credit quality. Asset sales, such as the recently announced Portland General Electric Co. deal, should therefore be fully available to enable Enron to strengthen its balance sheet and other credit measures in a timely manner.’ ■ 25 October 2001: Enron’s BBB+ rating holds, but rating agencies revised the outlook for Enron to negative. Standard & Poor’s press release stated: ‘Despite the negative outlook, several factors supportive of Enron’s credit quality have been sustained throughout the uncertainty surrounding the company. The funda- mental strength of Enron’s energy marketing and trading franchise has remained steady. Standard & Poor’s has detected no lapses in the company’s risk management practices and trading discipline. No signif- icant deterioration in trading volumes or willingness of counterparties to transact with Enron has been revealed to Standard & Poor’s in contacts with major energy market participants.’ ■ 1 November 2001: Enron’s rating is lowered by S&P to BBB and they place Enron on CreditWatch Negative. Standard & Poor’s press release stated: ‘The downgrades indicate Stan- dard & Poor’s determination that Enron’s plan to employ asset sales and other means to repair its damaged balance sheet will be insufficient to restore its long-term credit quality to the historical triple-B-plus level. The negative CreditWatch listing recognises the uncertainties that surround the company and its credit quality in the short run due to the possibility of further unanticipated developments in the capital markets.’ 242 ENERGY PRI CE RI SK Ratings Worst historic annual default rate (%) for 1970–1997 Aaa 0.0 Aa 0.61 A 0.26 Baa 1.33 Ba 5.30 B 23.38 TABLE 15.1 Worst historic yearly default rates. Source: Moody’s Investors Services, ‘Historical Default Rates of Corporate Bond Issuers 1920–1997’
    • ■ 8 November 2001: Enron files an 8K with the SEC disclosing the severity of the non-cash impact to earnings (cumulatively restating earnings going back to 1997 by approximately $600 million), and the negative impact on its balance sheet from the effects of various financial vehicles that should have been consolidated in Enron’s financial statements pursuant to GAAP. Following Enron’s 8K filing, Dynegy publicly confirms that it was discussing a possible business combination with Enron. ■ 9 November 2001: S&P lowers Enron’s rating down to BBB– and retains its CreditWatch Negative status. Standard & Poor’s press release stated: ‘The Enron downgrade is prompted by the credit implications of the company’s restatement of financial statements going back to 1997 due in part to a legal and accounting review of certain related-party transactions by a special committee of Enron’s board of directors. The investment-grade rating is predicated on the prospect for improvement of credit quality with the acquisition by the financially stronger Dynegy and the near-term liquidity enhancement, through the injection of $1.5 billion of equity capital, that came with the signing of the merger agreement.’ ■ 19 November 2001: Enron 10-Q filing is made disclosing a ratings trigger event (at BBB–) involving the acceleration of a $690 million note to 26 November 2001 from 2003. ■ 21 November 2001: Dynegy issues statement on the Enron merger status. ■ 28 November 2001: Standard & Poor’s lowers its Enron rating to B– and places the rating on CreditWatch Developing. Standard & Poor’s press release stated: ‘The rating action is based on Standard & Poor’s loss of confidence that the Dynegy merger will be consummated. The willingness of Dynegy to complete its planned acquisition of Enron has been compromised by the continued drop in confidence in the capital markets that the transaction would hold. The market reaction has spread to the energy markets, where Enron’s trading and marketing franchise has, in Standard & Poor’s opinion, sustained significant damage that, together with rising potential legal liabilities, weakens Dynegy’s commitment to purchase Enron.’ ■ 30 November 2001: Standard & Poor’s lowers Enron’s rating to CC and places the rating on CreditWatch Negative. Standard & Poor’s press release stated: ‘The rating action reflects Stan- dard & Poor’s expectation that following the dissolution of Enron’s announced merger with Dynegy Inc., burdensome debt restructuring requirements, negligible liquidity, and limited access to capital will likely cause Enron to seek bankruptcy protection. The change in CreditWatch implications to negative reflects Standard & Poor’s belief that such a filing in the very near term is probable.’ THE COLLAPSE OF ENRON 243
    • ■ 3 December 2001: Enron’s rating lowered to D following Enron’s 2 December 2001 filing for Chapter 11 bankruptcy protection. METHODS FOR MANAGING CREDIT RISK EXPOSURE Master netting ■ Reduces credit risk exposure through netting. This is discussed in more detail later in this chapter under ‘Reducing credit risk via the ISDA Master Agreement & Schedule’. ■ The cost of this is low. Collateralisation ■ Collateralisation of credit exposures in the OTC derivatives market has increased rapidly in recent years. Most dealers now collateralise expo- sures arising from OTC derivatives business to some degree. Dealers use collateral to mitigate their credit exposures and thereby engage in more transactions than would otherwise be possible. Collateralisation agree- ments are now usually documented under ISDA’s credit support annex (see Chapter 17 for an example) which is added to an ISDA master agree- ment between two counterparts. This provides for collateralisation of the 244 ENERGY PRI CE RI SK Kenneth Lay, CEO & Chairman ‘Incredibly cheap stock’ Fortune magazine criticises accounting. Enron just says ‘sour grapes’ by stock analysts Who failed to get investment banking business. 2 December 2001 Enron files for Chapter 11 bankruptcy protection ‘…customers continue to put their confidence in us and our core businesses are strong and performing well.’ Kenneth Lay, CEO & Chairman Enron in a press release dated 25 October 2001 FIGURE 15.1 Fall in Enron’s share price; chart data courtesy of http://www. StockCharts.com/
    • net current exposure on the portfolio of transactions covered by the ISDA master agreement. ■ The cost of this is low. Financial guarantee ■ In the energy markets this is normally an Irrevocable Standby Letter of Credit from the other counterpart. ■ It is sometimes possible to buy silent guarantees where, for example, counterpart ‘A’ concerned with the credit of counterpart ‘B’, goes to a bank and buys cover against counterpart ‘B’ defaulting (this is usually priced like a letter of credit risk). The cover is normally against a specific exposure – for example, a particular swap or energy contract. In a silent guarantee, counterpart ‘A’ pays for the guarantee and counterpart ‘B’ never knows that ‘A’ has bought this protection; hence the term ‘silent guarantee’. ■ The cost of this approach varies and depends on the tenure of the deal, the credit quality of the counterpart and the size of the deal (in US dollars). Credit insurance ■ Transfers counterpart credit risk to an insurance firm. ■ Partial coverage, long lead time on payout (30–90 days can be longer) and then the organisation claiming against the insurance usually has to exhaust other routes of getting its money back before the insurance will pay out. ■ The terms and conditions of credit insurance can include a lot of provi- sions against which the insurance will not pay out. ■ The cost varies, but this is usually cheaper than credit derivatives. However, in practice, credit derivatives are seen as having much more transparency in terms of the events that trigger payout. It is also not easy to obtain credit insurance against derivatives deals. Credit insur- ance is more suited to ‘nuts and bolts’ transactions like physical energy assets, e.g. a specific oil cargo or energy supply contract. Credit derivatives ■ Transfers single (sometime a basket of counterpart) credit risk. ■ Cost varies, but it is reputed to be more expensive in terms of basis point equivalent charge than credit insurance. However, there are very clear trigger events for payout. ■ One problem is that energy sector names covered are usually large names, and even this is a developing market and liquidity can be an issue. It is normally decided on a case by case basis. METHODS FOR MANAGING CREDIT RISK EXPOSURE 245
    • Assignment ■ This is not very common. It involves the assignment of an OTC deriva- tives deal to a third party. The industry did see this happening in the Enron collapse, where Enron, to try to reduce its net loss exposure to the energy industry, assigned profitable swaps in its trading book to third parties who they had loss-making swaps positions with. The tricky thing here is that it requires the consent of the other original counter- part to the deal and they have to accept the credit risk of the new third party who takes over as their counterpart to the deal. ■ It is also difficult to administer, requires approvals and can sometimes (depending on the jurisdiction of the counterparts involved) create tax liabilities. This may be the biggest cost of using this alternative. Clearing OTC energy derivatives ■ This reduces credit risk and transfers the credit risk. It achieves this by novating a trade (transferring the buy and sell of an OTC trade to a clearing house) to a highly creditworthy clearing house who then become the central counterpart to both the buy and sell of the OTC transactions. Several initiatives have been launched in this area by London Clearing House (http://www.lch.com/) and the New York Mercantile Exchange (http://www.nymex.com/). ■ The cost of this is high compared to the other routes. ■ Not all OTC energy derivatives are supported by clearing houses. WAYS TO REDUCE CREDIT RISK VIA THE ISDA SCHEDULE Trading before an ISDA is agreed Although many dealers aim to complete a master agreement before executing their first derivatives deals, many energy traders sometimes undertake trades with new counterparties before signing a master agree- ment (although this is increasingly uncommon due to the increased credit risk for a firm, as discussed here). The failure to complete a master agree- ment prior to trading can exacerbate credit risks by jeopardising a dealer’s ability to close out transactions and net obligations in the event of a counterparty’s default. However, a properly completed ISDA agreement can really help to reduce counterparty credit risk exposure. Close-out netting provisions in ISDA agreements are powerful tools for mitigating credit risk. A master agreement typically provides that, in the event of a counterparty’s default, the non-defaulting counterparty can accelerate and terminate all outstanding derivatives transactions and net the trans- actions’ market values so that a single sum will be owed by, or owed to, the non-defaulting counterparty. Legally enforceable netting provisions 246 ENERGY PRI CE RI SK
    • reportedly can reduce aggregate counterparty credit exposure by 20% to 60%! Not bad. Whether a netting provision in an ISDA agreement is enforceable or not will depend on the jurisdiction of the counterpart in default. ISDA spends a lot of time and resources obtaining opinions on the enforceability of ISDA agreements and netting provisions. ISDA regularly updates a list of countries for which they have received netting opinions. It is up to each counterpart to interpret the opinions themselves. Table 15. 2 shows the list of countries at 1 September 2002 that ISDA has received an opinion on. (To obtain these opinions contact ISDA http://www.isda. org/.) Ensuring the enforceability of the netting provisions of the ISDA Master Agreement remains a key initiative for ISDA because of its importance in reducing the credit risk arising from the business. ISDA has expanded the number of countries solicited to 38. The scope of the opinions includes the enforceability of the termination, bilateral close-out netting and multibranch netting provisions of the 1992 Master Agreements. ISDA updates these annually to comply with requests from various central banks. It also continues to expand its efforts related to the enforceability of netting provisions in emerging markets jurisdictions, working with the relevant legislative and regulatory representatives. Reducing credit risk via the ISDA Master Agreement & Schedule The ISDA Master Agreement and Schedule are discussed in much more detail in Chapter 17. However, it is worth highlighting some ways in which the ISDA Schedule can be used to advantage in reducing possible credit risk. With reference to the ISDA Schedule and 1992 ISDA Master Agreement: ■ Specified Entities ● Under Section 5 of the ISDA agreement (events) the other counter- part’s affiliates or group of companies can be added as ‘Specified Entities’. ■ Threshold amount/cross default ● Put a low threshold amount in for the other counterpart to the ISDA Schedule. A low threshold dollar value means that the defaulting counterpart’s affiliates etc. who are ‘Specified Entities’ do not have to default on much (e.g. loans, other deals perhaps) before breaking the threshold dollar level and triggering a default. This event then allows the non-defaulting counterpart to terminate all deals under the ISDA Schedule. ■ Collateral/credit support in ISDA Schedules ● Take collateral in the form of Irrevocable Standby Letters of Credit which are very popular in the OTC Swaps trading arena (as good as cash) or cash. If other forms of collateral are accepted (e.g. bonds or WAY S TO REDUCE CREDIT RISK VIA THE ISDA SCHEDULE 247
    • 248 ENERGY PRI CE RI SK Country Received Counsel Australia Yes Mallesons Stephen Jaques Austria Yes Schönherr Barfuss Torggler & Partners Bahamas Yes Higgs & Johnson Belgium Yes Coudert Brothers; Coppens Van Ommeslaghe & Faurès Bermuda Yes Appleby, Spurling & Kempe British Virgin Islands Yes Walker Smiths Canada Yes Stikeman, Elliott Cayman Islands Yes Maples & Calder Denmark Yes Gorrissen Federspiel Kierkegaard England Yes Allen & Overy Finland Yes Hannes Snellman France Yes Gide Loyrette Nouel Germany Yes Hengeler Mueller Weitzel Wirtz Hong Kong Yes Allen & Overy Indonesia Yes Ali Budiardjo, Nugroho, Reksodiputro Ireland Yes McCann FitzGerald Italy Yes Ughi e Nunziante Japan Yes Mitsui, Yasuda, Wani & Maeda Luxembourg Yes Beghin & Feider Malaysia Yes Shearn Delamore & Co. Mexico Yes Ritch Heather y Mueller The Netherlands Yes De Brauw Blackstone Westbroek Netherlands Antilles Yes Clifford Chance New Zealand Yes Bell Gully Norway Yes Wiersholm, Mellbye & Bech Philippines Yes SyCip Salazar Hernandez & Gatmaitan Portugal Yes Abreu & Marques, Vinhas Scotland Yes Dundas & Wilson Singapore Yes Allen & Gledhill South Africa Yes Webber Wentzel Bowens South Korea Yes Kim & Chang Spain Yes Allen & Overy Sweden Yes Wistrand Switzerland Yes Prof. Dr Dieter Zobl and Dr Thomas Werlen Taiwan Yes Lee and Li Thailand Yes Baker & McKenzie Turkey Yes Pekin & Pekin United States Yes Cravath, Swaine & Moore TABLE 15.2 Countries on which ISDA has received an opinion (at 1 Sept 2002)
    • gold), you should allow for the possible cost of selling these assets to get your cash back and also the possible price volatility of these assets. In banking terminology, a ‘haircut ‘ is applied to the collateral (e.g. for bonds you might only take 95% of the face value of the bond in to account). ● Credit support documents – These could be a parental guarantee for subsidiaries which on a standalone basis may represent too big a credit risk. USA companies frequently give parental guarantees against their overseas subsidiaries. The majority of trading companies will not highly capitalise their overseas trading operations but instead for control purposes support the company via parental guarantees or by securing banking facilities for the subsidiary by giving them access to standby letters of credit. Funds may be received more quickly under an Irrevocable Standby Letter of Credit since no proof is needed – it is simply submitted to the bank branch. Obtaining funds under a parental guarantee will take longer and require a lot more paperwork. The ISDA Master Agreement gives strong protection to users. The addition of some of the measures touched upon in this section will further strengthen the credit risk benefits of trading under an ISDA legal framework. Beyond simple ISDA-based netting of derivatives transactions, some companies are now working on ‘Master Netting Agreements’ (sometimes in liaison with ISDA). This nets financial and physical deals between different energy types/commodities, contract types and even across affiliates and subsidiaries. This is something not practised widely yet, and, in the case of American companies, there is still a lack of a clear opinion providing for netting of physical and financial deals in the US bankruptcy code. Watch out for more developments in MNA (Master Netting Agreements)! Given tight credit and the cost of credit in the energy sector, anything that frees up capital and trading lines to permit more business is good for the industry, and it will no doubt be pursued by more counterparts in the future. COLLATERALISATION Credit exposure reductions can also be made via collateralisation of trades. In the energy derivatives industry most counterparts who require collateral will request Irrevocable Standby Letters of Credit from their counterpart (this form of collateral having already been listed in their credit support annex to their ISDA Master Agreement or other Master Agreement form). COLLATERALISATION 249
    • Unfortunately, this is not very efficient and Letters of Credit can also be expensive, and difficult to modify and distribute. The wording and proce- dures of Letters of Credit (LCs) were built to cover specific trade finance exposures which do not change (e.g. if a cargo of crude oil is purchased at a cost of US$15 million, the payment can be covered by an LC). This type of document is not very well suited to covering derivatives exposures which change daily, and amending Letters of Credit is time-consuming. Some banks have created specific LCs with flexible wording in an attempt to give cover on the daily variable exposures of unrealised/realised losses on OTC swap positions, although some LCs with this flexible wording have paid out up to ten times the amount they were originally issued for! There are also some legal issues over whether this type of LC could really be tested in a court of law in terms of forcing a bank to pay out more than the stated face value of the LC. Commercially though, the bank may wish to try to accommodate the counterpart when it tries to draw more than the face value of the LC with this flexible type of value wording in order to avoid loss of face and loss of future business. Collateral requirements The size of collateral required will depend on whether or not the trader requiring collateral has also granted some unsecured credit line to the other counterpart or not. However, if we can take an example of a first tier market maker bank supplying a fuel oil swaps hedge to a shipping company, they would typically require a 10% cover of notional cover as an LC. The Bank for International Settlement (http://www.bis.org/) states that a bank’s internal cover against commodity derivatives exposures should not really exceed 10% of notional. However, most internal risk models used by banks create a capital charge of around 6% to 8% of notional on trade date. The capital charge can be compared to the initial margin a futures exchange charges when a trader opens a futures position. There are some instances of a few very conservative banks using an add- on methodology and charging 15% of notional value for deals 1 to 12 months forward + MTM re-valued on a daily basis. GUIDELINES FOR TAKING COLLATERAL FROM COUNTERPARTS Financial instruments used as collateral Where a financial instrument is used as collateral, market practice suggests that most firms apply one or more ‘haircuts’ on its value to reflect market and FX risk – this offers protection if it is necessary to liquidate the financial instrument to realise the cash against a loss. 250 ENERGY PRI CE RI SK
    • GUI DELI NES FOR TAKI NG COLLATERAL FROM COUNTERPARTS 251 EXAMPLE STANDBY LETTER OF CREDIT WORDING WITH FLEXIBLE WORDING ON VALUE OF THE LC AGAINST AN OTC DERIVATIVE POSITION Typical Standby Letter of Credit Wording issued by bankers against its customer’s OTC Swap exposure with another counterpart. TO: XYZ BANK LTD We hereby open our irrevocable standby letter of credit no 12345 dated 10 January 2003, as follows: Applicant: ABC SMALL TRADER LTD Beneficiary: XYZ BANK LTD Amount: USD 100,000.00 (United States Dollars One hundred thousand only) Expiry date: 10 JANUARY 2003 Available for payment at our counters at sight against presentation of the following documents: [A] Copy of Telex Invoice showing actual settlement amount or marked to market exposure calculation. [B] Beneficiary’s statement signed by authorised signature reading as follows: ‘We, XYZ BANK LTD, certify to you that the amount covers the outstanding amount due to us by ABC SMALL TRADER LTD pursuant to the following paper swap transactions: 1. Contract Ref: 12345abc Deal date: 20 December 2002 Product: Singapore HSFO 180 CST Quantity: 5,000 MTS Exactly Fixed price: USD 134.50 Per MT Floating Price: From and including 1–31 MAY 2003 Special conditions: 1. Multiple/partial drawings are permitted. 2. All banking charges at Beneficiary’s bank for Beneficiary’s account. All Bank charges at Opener’s Bank for opener’s account. 3. The amount of this Standby Letter of Credit is automatically adjusted for any increase/decrease in the marked to market exposure calcula- tions (including adjustment for any increase to any amount in excess of the amount initially available and payable under this standby letter of credit) without further amendment on our side. Reimbursement instructions:
    • The purpose of the ‘haircuts’ is to protect against price declines during the holding period, as well as the costs likely to be incurred in liquidating the collateral. ‘Haircuts’ are typically expressed as a percentage deducted from the value of the collateral. The level of ‘haircut’ an organisation may use is up to them, but Table 15.3 can help as a starting point. CREDIT INSURANCE The insurance market also has some solutions for transferring credit risk. However the clarity of payment triggers is not always very clear. Credit insurance is usually limited to trade credit insurance against physical trade and it is very difficult to find insurance cover against credit default on derivatives positions such as swaps and options. It is more suited to general cover with a counterpart which has a regular flow of physical energy. Users of insurance should pay attention to indemnity clauses, 252 ENERGY PRI CE RI SK £ 5 year > 5 year Cash 0% 0% Sovereigns rated AA and above(1)(2) 0.5% 1% Other investment grade sovereigns 2% 5% Non-investment grade sovereigns 10% 15% Corporates rated A and above(1) 7% 10% Corporates (BBB) (1) 10% 15% Non-investment grade corporates 20% 25% Equity main index: – Investment Grade Issuers 20% – Others 30% Precious metals 10% FX haircuts: – In major currencies (3) 5% – In others 10% (1) Or equivalent (2) Sovereigns are broadly defined to include supra-nationals (3) A major currency is a floating currency, following the International Monetary Fund approach. The use of financial assets not covered in this table should be reviewed by supervisors as part of Pillar II. TABLE 15.3 Suggested collateral haircuts. Source: ISDA Report February 2002
    • default triggers and liquidity. Unlike Standby Letters of Credit, where a beneficiary can just apply to the bank for the funds without having to prove the monies owed, insurance will normally require a significant amount of documentation. In addition, a beneficiary will normally have had first to exhaust all normal methods of trying to recover the monies owed before applying for payout from the insurance policy. Payouts on a default usually take 30 to 90 days, so there is a cash flow risk for the benefi- ciary to consider as well. However, payout on default via insolvency or Chapter 11 can be much quicker because of public record stating the fact that a company has gone into bankruptcy; payout for this type of default can be within 1 day to 10 days. More Information on credit insurance can be found at http://www. eulergroup.com/ and information on bunker fuel supply insurance is at http://www.bunkerinsure.se/. THE NEW TOOL OF THE TRADE – CREDIT DEFAULT SWAPS (CDS) A Credit Default Swap (CDS) is the most straightforward type of credit derivative. It is a contract that transfers credit default risk from one party to another. In a nutshell, one counterparty is selling insurance and the other counterparty is buying insurance against the default of the third party. The buyer of a CDS pays a premium to the seller, usually in the form of a basis point (like an interest rate) charge per annum on the notional of the contract. A payment is due to the buyer when there is what is termed a ‘credit event’. There are three main types of credit event: ■ Bankruptcy. ■ Restructuring. ■ Failure to pay. If no credit event takes place, the buyer of the CDS pays the basis point charge on the notional cover from the contract to the seller. For example, US$10 million CDS against XYZ Bank Ltd costs 95 basis points (0. 95% per annum charge), so the buyer would pay US$95,000 per year for this cover of US$10 million dollars. If XYZ Bank actually triggers a credit event then the CDS will cover the buyer for US$10 million of credit default (Figure 15.2). In a CDS the buyer of protection (‘Buyer’) typically pays a periodic fee in exchange for the seller of protection (‘Seller’) contracting to make a payment should a pre-agreed corporate or sovereign (‘Reference Credit’) THE NEW TOOL OF THE TRADE – CREDIT DEFAULT SWAPS (CDS) 253
    • suffer some kind of pre-agreed credit crisis as mentioned in brief earlier (‘Credit Event’). The use of credit derivatives is broadly divided between risk manage- ment and investor applications. Risk management use applies to situa- tions where the user is a buyer and so is reducing credit exposure (although not necessarily motivated entirely by risk reduction) and investor/trader applications where the user is a seller and wants to increase its credit exposure. With CDSs, even if you have a portfolio of credit risk with investment grade firms, you may have a large percentage of that risk with just a handful of firms. Part of any credit policy should be to spread out risk and have maximum limits on any one counterpart or group of companies. The most commonly used credit derivative is the CDS on either a single company (also referred to in the credit market as a ‘name’) or a basket of names. A company could use a CDS against a basket of names as a general credit risk hedge against a portfolio of regular credit risk that it takes in the energy market. In the context of this chapter on credit risk control and mitigation we will focus on the following uses of CDSs: ■ Risk reduction ■ Credit line management Risk reduction through CDSs The most obvious and indeed common use of a CDS is to reduce credit risk in a situation where the user is concerned for the quality of the credit that is being hedged. This could arise where some commercially negative news 254 ENERGY PRI CE RI SK Protection Seller Protection Buyer 3rd Party entity the CDS is against Also referred to as the “Name” or “Reference Credit” or sometimes as the “Reference Entity” If no credit event takes place then X basis points is paid by the buyer to the seller If a credit event stated in the CDS takes place then the seller has to pay the buyer the stipulated $ cover in the swap FIGURE 15.2 Credit Default Swaps
    • about a reference credit (name/entity) has been released by newswires etc. and the organisation with the exposure chooses to hedge actual exposure. Speculative traders may buy a CDS to take a negative position on a partic- ular sector, region or specific entity’s creditworthiness becoming worse. Credit line management through CDSs In contrast to risk reduction, CDSs are often used to reduce credit expo- sure in a situation where the user is very positive about the credit quality of the credit being hedged, but, due to factors such as internal limit issues, there is insufficient credit line to allow a planned transaction. A prime example is Petronas, the Malaysian State oil company, which is a very actively traded CDS. However, it has a very high rating and solid financial foundation and trades very actively in the energy markets with many counterparts. So the CDS is used to manage the credit line of the borrower in question and the need for a hedge arose because of a positive view of the reference credit and the need to free up some more credit to enable more trading. In the example of Figure 15.3, company A sells 500 MW of power, elec- tricity, per month to company B. Let us say that this involves a monthly payment from company B to company A of about US$1 million. In order to mitigate the risk it has against a credit default by company B, company A enters into a credit default swap with a CDS provider. The CDS will involve periodic payments being made to the swap provider – what might be termed the fee (not for tax purposes!) for the credit protection given through the swap structure. Typically, this payment would be made up of a credit spread plus other costs. In the example given, if company B had a rating of BBB and the CDS counterparty (i.e. the provider) was an AA rated bank, the credit spread would be derived from the difference in the rating of BBB versus AA. Other costs might include the cost of funding and the capital cost from the use of the CDS provider’s balance sheet. THE NEW TOOL OF THE TRADE – CREDIT DEFAULT SWAPS (CDS) 255 Company A Company B CDS Counterparty ElectricityPayments Credit premium Contingency payment FIGURE 15.3 Credit default swap example: electricity market
    • Obstacles and limitations: counterparty credit risk The transacting of CDSs often suffers from the so-called ‘credit paradox’ whereby you can never totally eradicate credit risk. Credit risk from credit derivatives can appear in the following ways: 1. A protection buyer creates a counterparty credit risk with the CDS seller. More often than not an organisation using CDSs may be able to spread its credit risk better by reducing overall exposure to any one entity or sector. A trader in the energy sector is going to be exposed to a lot of energy traders, but by using CDSs some of this credit risk might be transferred to the credit risk of banks or investment funds who are market-making in CDSs. Note the use of the term ‘transfer’: the trader does not eradicate credit risk altogether, but shifts some of its energy sector exposure over to the financial/banking sector or fund sector. 2. The theory goes that it may be the case that the best quote on a CDS may come from the least suitable counterparties in terms of credit risk. In other words, it may come from those CDS counterparts that are likely to have existing exposures to the reference entity and therefore may present increased correlation risk. This means that the CDS seller may have large exposure to the reference entity. If the reference entity defaults it could cause problems for the CDS seller and in turn leave the buyer with zero protection. In this situation, there are two defaults instead of just one with the reference entity whose credit risk was being hedged in the first place. If the credit quality of the protection seller (the CDS seller) starts to get worse after an organisation has bought a CDS from it, and there has not yet been a credit event affecting the reference entity (so no payout has been made yet on the CDS), the buyer has the choice of trying to terminate the CDS early (although this could be difficult, since early termination provisions apparently are not normally included in CDS deals under ISDA), or the CDS buyer could buy credit protection against the CDS seller. The decision rests on the creditworthiness of the reference entity and on the correlation between a default by the CDS seller and a default by the reference entity. This could be the case if they are in the same country that has just had its rating downgraded, or perhaps there is some potential war or conflict close to the country of the reference entity and the CDS seller. It is important, especially as a buyer, to check prior to the execution of a CDS that the credit risks of the reference entity are not strongly posi- tively correlated with the seller of the CDS. For traders and investors who are CDS sellers, the risk is much simpler, as they do not receive the premium due on the CDS. Non-payment of the basis point premium will normally enable the seller to terminate the contract. 256 ENERGY PRI CE RI SK
    • Basic overview of pricing and valuation mechanics A common approach is to use the asset swap spread for the reference credit in the maturity of the CDS contract and to adjust it up or down, based on factors such as expected financing rate and liquidity. This can be illustrated by the following example. Suppose that the benchmark interbank rate is Libor and that the funding rate for a risky bond is also Libor. Consider a transaction where an investor has a long position (they have bought the bond) in a risky bond earning Libor +80 basis points (bps) hedged with a CDS. Ignoring counterparty risk, the net effect of this transaction is to mitigate the trader’s default risk exposure to this risky bond. Hence, the default protection should cost the investor 80 bps. If the CDS spread is less than 80 bps, the investor in a perfect world could buy the bond, finance it at Libor and buy default protection to earn a small positive return for no risk. Similarly, if the default swap spread is higher than 80 bps, the investor can short the bond, sell default protection and receive a small positive return. It is fair to say that this basic approach is the favoured starting point for pricing and is likely to become more meaningful as liquidity moves from the bond market to the credit derivative market. What credits can be traded? Although market participants do trade CDSs on non-rated entities, it is still not that common. Furthermore, most market participants insist on a reference obligation which is normally a fixed rate bond issued by the reference entity. In the absence of a rating and any relevant bond issu- ance, potential liquidity for that ‘name’ or company diminishes significantly. However, some traders are willing to look at almost any credit and decide whether they want to make a price on it, so it is worth asking around. The fallback to CDSs would be Letters of Credit from the counter- part, silent guarantee or credit insurance (certainly for physical energy transactions, although tricky to obtain cover against derivatives marked- to-market loss coverage). See Appendix 2 for a list of some of the main energy sector and transportation names traded in the CDS market. Documentation for credit derivatives The documentation for credit derivatives has become both more sophisti- cated and more standardised. ISDA (International Swaps and Derivatives Association http://www.isda.org/) has helped to speed up documenta- tion time for new deals and reduce documentation risk. The majority of credit default swaps or CDSs are traded on an ISDA basis. ISDA’s drive to assist the credit derivatives market is also illustrated by the inclusion in 2001 of its Derivatives Market Activity Survey. ISDA THE NEW TOOL OF THE TRADE – CREDIT DEFAULT SWAPS (CDS) 257
    • 1999 Credit Derivatives definitions (plus supplements) are used with stan- dard ISDA Master Agreements. These guides are available from ISDA. THE DEVELOPMENT OF THE CDS MARKET Enron and CDSs The Credit Default Swaps market proved its worth in the Enron crisis of 2001 by sounding alarm bells about the energy giant several months before it collapsed. Enron’s stock did not begin its most breathtaking plunge until mid-October, when the company’s offshore partnerships were uncovered. But two months before that the trouble signs showed up in the credit derivatives markets. On 15 August the day after Enron chief Jeffrey Skilling abruptly resigned, Enron stock barely budged, closing just above the $40 mark. But on the same day, the price of an Enron credit contract jumped 18%. Contracts bought that day were priced at 185 basis points ($185,000 annu- ally for protection against default on a $10 million loan). And by 25 October, as the troubles sparked headlines, Enron stock had dropped more than 50%, while the credit contract had soared in price to $900,000 per $10 million annually. Even at the much higher price, it was actually a great deal! Of course, after Enron announced Chapter 11 in early December 2001, US energy companies were severely hit by the credit fall-out in the energy sector. In the week after the Enron collapse, the five year credit default swap spreads on El Paso widened to around 325 bps from 225 bps the week before Enron’s demise. Williams Energy also got hit with its credit spread widening to 295 bps from about 180 bps In the same week. But rather than halting developments in CDS, it seems that the Enron collapse has demon- strated the effectiveness of this new method of credit risk mitigation and the CDS market in the energy and transportation sector continues to grow at a rapid rate. As Figures 15.4 and 15.5 illustrate, growth dipped around the Enron collapse, but quickly rebounded and has not looked back since January 2002. Both the number of energy-related companies (names) quoted in the CDS market and the number of quotes requested in the market has been on a steady bull trend. Although it is impossible to eradicate credit risk completely, it is possible to enhance or upgrade the credit risk an organisation has to take. There is a cost to this process, but when balanced against the potential cost of taking the hit of a major default, it may appear cost-effective. This was also seen in the Enron scenario: Enron assigned profitable OTC deals to companies to whom they owed money, some OTC trades were converted 258 ENERGY PRI CE RI SK
    • via EFS transaction (exchange futures for swaps) on to exchanges (OTC natural gas positions in USA Henry Hub GAS and also UK Natural Gas NBP (National Balance Point) were all seen EFSed over into the clearing THE DEVELOPMENT OF THE CDS MARKET 259 0 100 200 300 400 500 600 700 800 900 Jul-02 Apr-02 Jan-02 Oct-01 Jul-01 Apr-01 Jan-01 Oct-00 Jul-00 Apr-00 Jan-00 Oct-99 Jul-99 Apr-99 Jan-99 Oct-98 Jul-98 Apr-98 Jan-98 Oct-97 Jul-97 0 10 20 30 40 50 60 70 Total number of quotes Number of names priced Names Quotes FIGURE 15.4 Market growth in the energy sector, 1997–2002. Source: data provided by CreditTrade. For further information please call London +44 (0)20 7400 5050 or visit http://www.credittrade.com/ 0 50 100 150 200 250 300 Jul-02 Apr-02 Jan-02 Oct-01 Jul-01 Apr-01 Jan-01 Oct-00 Jul-00 Apr-00 Jan-00 Oct-99 Jul-99 Apr-99 Jan-99 Oct-98 Jul-98 Apr-98 Jan-98 Oct-97 Jul-97 0 2 4 6 8 10 12 14 Total number of quotes Number of names priced Names Quotes FIGURE 15.5 Market growth in the transport sector, 1997–2002. Source: data provided by CreditTrade. For further information please call London +44 (0)20 7400 5050 or visit http://www.credittrade.com/
    • house mechanism with margins to keep counterparts happy and reduce OTC exposures. The size of the CDS market ISDA began reporting the size of Credit Default Swaps in 2001. In its end of year 2001 members survey findings (in which 80 members participated), it reported the Credit Default Swaps market’s outstanding notional value at $918.9 billion. This is small compared to the currency markets or interest rate derivatives, which are measured in trillions, but the growth in credit swaps is still remarkable; for the second half of 200, growth was recorded in the region of 45%. As Keith Bailey, the Chairman of the Board of ISDA said, ...The credit derivative numbers show impressive growth during a difficult period.... This is testimony to the value that these products bring to market participants in managing risk in times of volatility and uncertainty. Most active geographic regions for CDSs It may sound surprising, but Europe is taking the lead in terms of the number of counterparts active in CDS, with around 50 market makers in Europe compared to around 20 market makers in New York, who do about 90% of the business in the USA. America is in second place and Asia still continues to develop in third place. Up to 3 years swaps liquidity is good and it is possible on some names to get protection for 5 to 10 million per credit name for up to 5 years tenure. Ten years cover appears to be the maximum term really possible on good names. TOTAL RETURN SWAPS A Total Return Swap (TRS) is a term for a credit derivative swap where one party agrees to pay the other the total return of a defined asset in return for receiving a stream of, typically, Libor-based cash flows (Figure 15.6). The underlying asset is typically a single stock or stock index, a bond or portfolio of credit instruments. The TRS is merely a mechanism for the user to enjoy the economic benefits of owning as asset without using the balance sheet and can be used to give general protection against country or political risk. TRS vs. CDS The difference between a TRS and a Credit Default Swap (CDS) is that a CDS simply transfers credit risk and requires a credit event default to 260 ENERGY PRI CE RI SK
    • trigger a payout by reference to some designated reference asset (usually a bond or other rated instrument issued by the reference entity). However, a Total Return Swap transfers all the risks of owning the designated asset. The TRS transaction keeps the reference obligation (e.g. the bond) on the investment/trading book of the counterpart who was originally holding it. The counterpart buying into the returns on the Reference Obli- gation is seeking those returns without buying the asset. Country risk application A CDS may look very like a TRS, but there are significant differences in the timing and the extent of coverage. Whereas a CDS needs to have its matu- rity set to be the same as the asset that is being hedged (if full protection is needed), a TRS does not. Whatever the time period, the TRS will cover any economic deterioration during that time, as well as paying out an economic benefit or appreciation. The buyer undertakes to pay the seller for each defined period the amount of any interest received on the asset, plus capital appreciation. In return, the seller commits to pay a floating interest rate plus any capital depreciation. In the energy industry an organisation may decide to use a TRS when it is concerned about political unrest in a country and wishes to reduce its exposure to that country, while still being able to trade with local counterparties. (In credit limit policies it is quite normal to have counter- part by counterpart limits and then overall country risk credit limits.) An example of this could be the exporter of oil cargoes or LNG/LPG cargoes to an emerging market who wants to protect against sovereign or political risk during a period of uncertainty. In this case, the TRS credit derivative could have as a reference asset a sovereign bond issued by that country. The great thing about the TRS (over the CDS) is that the TRS will generate positive returns for the buyer if the credit quality of the emerging TOTAL RETURN SWAPS 261 Total return payer Total return receiver Credit reference Appreciation/depreciation Return Libor + x Synthetic exposure via total return swap Actual exposure or short position FIGURE 15.6 Total Return Swaps
    • market in question merely deteriorates. It does not actually need to default, unlike in the case of a CDS. Obstacles and limitations to TRSs The main problem holding back the growth of Total Return Swaps usage has been the difficulty of calculating the appreciation or depreciation of the reference obligation (e.g. the sovereign bond in the earlier example). In the absence of an actual market transaction or a default, a very illiquid bond/asset will present significant price discovery problems, and whilst there are a number of structuring solutions to this, the majority of credits do not have enough liquidity to enable TRS usage. Another impediment is the lack of a market standard structure. Whereas the credit default swap is now considered a standard product with similar documentation used by all (e.g. ISDA based agreements), the TRS is a long way from this status. CREDIT RISK MITIGATION VIA CLEARING HOUSES The ultimate credit risk tool is a well-capitalised central clearing house. Centralised clearing provides multilateral netting, standard margining, and a highly rated guarantor in case of a default. This safety does not come cheap; it is also probably the most expensive route to guarantee an OTC derivative transaction. An overview for the process of a clearing house becoming a central counterpart to an OTC deal is: ■ Two OTC market counterparts, e.g. A and B negotiate and agree a deal with one another. This takes place in the normal manner either over the phone or via an electronic trading platform. ■ Once the deal has been concluded on the basis of becoming a ‘cleared’ deal, it is automatically ‘novated’ up to the clearing house. This takes place under some master clearing agreement with the clearing house. This legal approach of novation allows the clearing house to take over as counterpart to the deal. ■ From this moment onwards the clearing house is the legal counterpart to A and B, i.e. it replaces A as B’s counterpart, and replaces B as A’s counterpart to the OTC derivative deal. ■ The OTC derivative is then subject to the terms and conditions and the rule book of the clearing house. ISDA terms no longer prevail. ■ The clearing house will charge a fee on every contract cleared and finan- cially guaranteed. ■ The clearing house will normally charge a ‘good faith deposit’ on the opening of the OTC derivative (same as for futures contracts) called 262 ENERGY PRI CE RI SK
    • CREDI T RI SK MITIGATION VIA CLEARING HOUSES 263 CREDIT SWAPS TERMINOLOGY Buyer The buyer of protection or fixed rate payer refers to the party that is laying off credit risk by way of a credit derivative. Cash settlement Following a credit event a Credit Default Swap termi- nates, and if cash settlement is the form of settlement chosen, then a payment is due from the seller to the buyer equal to the notional of the contract multiplied by 100 minus the final price. Credit event A credit event is the event (or events) that triggers the termi- nation and settlement of a Credit Default Swap. The standard events used are bankruptcy, failure to pay and restructuring. With the exception of bankruptcy, these events all apply to the reference obligation(s). Credit line An internal limit imposed on the amount of credit exposure that can be extended to a single corporate or sovereign borrower. Deliverable obligation An asset or assets as defined in the confirmation that can be delivered as part of a contract using physical delivery as a form of settlement. Economic capital The amount of capital that a portfolio model calculates is necessary to support the economic risk of a bank’s risky assets. The computation of economic capital is currently not a regulatory requirement. Failure to pay The failure by a reference credit, after the expiration of any applicable grace period, to make payments due under a reference credit. Physical delivery Following a credit event a Credit Default Swap termi- nates, and if physical delivery is the form of settlement chosen, then on the settlement date the buyer delivers a notional amount of the deliverable obli- gation equal to the notional of the contract to the seller in exchange for receipt of the notional of the contract from the seller. Reference credit The reference credit is the legal entity that is being hedged by way of a credit derivative. Reference obligation The reference obligation is an identified asset or assets, normally issued by the reference credit, that may be used to identify whether there has been a credit event and may be used to determine cash settlement following a credit event. Regulatory capital The amount of capital that a bank is required by its regulator to hold in support of its risky assets. The current rules (part of the 1988 Basle Capital Accord) generally require $8 of capital for every $100 of corporate exposure, $1.6 of capital for every $100 of OECD bank exposure, and $0 for capital for any OECD sovereign exposure. Restructuring A term referring to changes to a reference obligation that have a material impact on its economics. These are defined at length in the ISDA Credit Derivatives Definitions but are revised in the ‘Modified Restruc- turing’ language also available from ISDA. The market uses two definitions: ‘Mod R’ and ‘Old R’. Seller The seller of protection or floating rate payers refers to the party that is taking on credit risk by way of a credit derivative.
    • Initial Margin, this needs to be maintained with the clearing house for the duration of the OTC contract being kept at the clearing house. ■ On a daily basis the clearing house will perform marked-to-market calculations to determine the most reasonable fair value of a client’s positions. Any unrealised loss that is calculated on the open position of the OTC contracts with the clearing house will have to be financed. This is generally referred to as Variation Margin. The cost of clearing trades via a clearing house is primarily made up of the cost of financing the margins placed at the clearing house against OTC derivatives positions and the fees charged per contract for clearing the trade. Also collateral placed with clearing brokers or with the clearing house directly against OTC positions may create other business costs. This working capital may not then be available to take advantage of business/ trading opportunities, so there is an opportunity cost which may be diffi- cult to calculate. Summary of OTC clearing house initiatives Intercontinental Exchange electronic trading platform (ICE) and London Clearing House (http://www.theice.com/) – 2002 ■ Clears ICE executed swaps and option deals in some natural gas and power OTC derivatives in USA and Europe, with aims to offer oil deriv- atives clearing in 2003. ■ Deals are executed via the ICE electronic trading platform as cleared deals and automatically flow in to LCH system. ■ Users must have the tripartite OTC clearing agreement signed between them, their nominated clearing broker (an LCH member) and the LCH. ■ Users also have to members of ICE, once they have their ICE terminal log-in and password, they can nominate which clearing broker they want to clear their trades. ■ Then their nominated clearing broker will set up account details on their Clearing Administration ICE screen. ■ Once this is all set up, trades executed as ‘cleared’ trades will automati- cally flow into their clearing account at their broker. If a company already has a futures account with an LCH Clearing member, only the tripartite documentation will usually need to be signed. OTC cleared trades will be booked into their existing futures account. UKPX: http://www.ukpx.com/ – 1999 ■ UK Power Exchange (UKPX) is the energy market operated by OM London Exchange Limited, a recognised investment exchange in the UK. OM London Exchange is regulated by the Financial Services Authority as an investment exchange and in its operation of a clearing house. UKPX was established as Britain’s first independent power 264 ENERGY PRI CE RI SK
    • exchange, and is unique in offering integrated trading and clearing for spot and futures contracts in power. ■ UKPX’s clearing house offers its members a clearing service for OTC physical contracts in UK natural gas and power. In September 2002 it also launched clearing for German physical forward power contracts. ■ The UKPX act as central counterparty to both sides of cleared contracts and will guarantee the financial performance of all such contracts. Since the UK and German power and gas markets are physical delivery contracts the UKPX also performs physical nomination and notification functions. Nord Pool ■ Nord Pool began in 1996 through deregulation of power markets in Nordic countries (http://www.nordpool.no/) ■ Through NECH’s clearing service, clearing members are offered clearing of contracts traded over the Nordic Power Exchange and finan- cial contracts traded in the bilateral market. Clearing means that NECH acts as an intermediary in contracts and as the clearing member’s counterparty. In doing this, sellers and buyers only have one legal counterparty, and NECH guarantees financial settlements. ■ NECH offers complete solutions for clearing of current products traded on and outside the Nordic Power Exchange. For financial electricity contracts, this means that standard contracts are evaluated together and the clearing member is given one net position in each contract series. This net position is the foundation for calculating the daily margin call and settlement. ■ Clearing of physical electricity contracts applies to contracts traded in Elspot and Elbas. Nord Pool Spot AS is contractual counter party for contracts traded on the physical delivery market. However, NECH administrates all clearing services. ■ For NECH to take on counterparty responsibility, each clearing member wishing to trade and clear its electricity contracts must provide collat- eral covering the daily margin call, which comes in addition to an initial margin call. ■ The volume of electricity contracts cleared by NECH in 2001, including all trade at the Nordic Power Exchange, was 2,769 TWh, at a value of NOK 412 billion (approx. US$54 billion). ■ At the end of 2002 NECH had 302 clearing members and clearing clients from a total of 11 countries. ■ NECH operates from the Head Office at Lysaker in Oslo and from its branch office in Stockholm with a total of 17 employees. EEX – European Energy Exchange (http://www.eex.de/) ■ This clearing house clears and guarantees spot and future transactions in German power. These contracts go to delivery. It is possible to post CREDI T RI SK MITIGATION VIA CLEARING HOUSES 265
    • OTC power trades on to the exchange for a reduced clearing fee than that of EEX futures contracts. ■ The future of EEX is in question, as UKPX in September 2002 launched a cheaper clearing alternative to EEX for German power and UKPX is supported by a leading OTC Broker Spectron. New York Mercantile Exchange (NYMEX) (http://www.nymex.com/) – 2002 ■ Clearing a range of OTC crude oil, oil products, gas, power and USA coal-related OTC derivatives trades via its online Internet-based system. ■ This system is not attached to any electronic trading platform and offers perhaps a bit more flexibility than the ICE–LCH approach. Since OTC brokers can give trades for their customers into the NYMEX clearing system, OTC brokers cannot participate really in the ICE–LCH approach. MANAGEMENT GUIDELINES ON ESTABLISHING A CREDIT CONTROL FRAMEWORK Establishing a credit risk environment ■ The Board of Directors should have responsibility for approving and periodically reviewing the credit risk strategy and significant credit risk policies of the organisation. ■ Senior management should have responsibility for implementing the credit risk strategy approved by the Board of Directors and for devel- oping policies and procedures for identifying, measuring, monitoring and controlling credit risk. Such policies and procedures should address credit risk in all of the bank’s activities and at both the individual credit and portfolio levels. ■ Organisations should identify and manage credit risk inherent in all products and activities. Organisations should ensure that the risks of products and activities new to them are subject to adequate procedures and controls before being introduced or undertaken, and approved in advance by the board of directors or its appropriate internal committee. Operating under a sound credit process ■ Organisations should establish overall credit limits at the level of indi- vidual counterparties and groups of connected counterparties. ■ Organisations should have a clearly established process in place for approving new credit lines and counterparts (even if they are going to place collateral with an organisation prior to trading) as well as the extension of existing credits. It is just as important for organisations to 266 ENERGY PRI CE RI SK
    • know their counterparts really well to protect against fraud and money laundering as it is to assess counterparts as worthy credit risks. ■ Organisations should have management information systems and credit analysis techniques that can enable senior management to measure the credit risk in all on- and off-balance sheet activities. The management information system should also provide information on any concentrations of credit risk, either in particular entities or group of companies or even country risk concentrations that may require atten- tion. Ongoing adequate controls over credit risk ■ Organisations should look to establish independent, ongoing credit review procedures and the results of such reviews should be communi- cated directly to the Board of Directors and senior management. ■ Organisations should establish and enforce internal controls and other practices to ensure that any exceptions to credit policies, procedures and credit limits are reported quickly to the right management who have a control function in the company. ■ Organisations should have internally approved contingency plans/ procedures in place for managing problem credit risks. ESTABLI SHING A CREDIT CONTROL FRAMEWORK 267
    • CHAPTER 16 Finance in Energy CREDIT STATUS IN THE ENERGY SECTOR Financing for any business is affected by its credit status. In the energy industry, this is particularly the case, as it is generally perceived to be a high-risk sector. So it is crucial that energy organisations know how credit rating agencies such as Standard & Poor’s and Moody’s operate. They should also know what the key factors are when a rating agency or third party assesses them. In the energy sector, company rating agencies will often examine: ■ Business strategy. ■ Energy market presence and the diversity of its energy business. ■ Competitiveness of the company. ■ Risk management operations. ■ Management oversight of energy market and business risks. ■ Risk tolerance: how a company manages its price risk (market risk). ■ Methods of valuation of its derivatives portfolios. ■ Credit risk policy. ■ Business and risk management control systems. ■ Supply access to energy markets, including operating costs, product pricing and diversity. ■ Financial risk and performance. The key to a profitable energy trading business is its risk management operations. Most credit agencies, when assessing risk management, concentrate on management supervision of the trading business, toler- ance of risk, credit risk policies and the systems and reporting structure in place to control the risk management process. Analysis of these areas helps rating agencies to determine an energy trader’s ability to succeed in the market. This means that the effective implementation of an appro- priate price risk management strategy with derivatives can help an organisation give a good impression to agencies assessing credit- worthiness. 268
    • Some rating agencies (e.g. Standard & Poor’s) consider a risk control system as an absolute necessity to gain an investment grade credit quality. This is typically anything above a BBB for S&P and Baa for Moody’s are considered investment grade. (See example of rating comparisons in table opposite.) The energy sector’s general business risks are high, given that there is a significant energy pricing risk and the expectation that traders will specu- late. This means that the average energy sector credit quality assessment is at the low BB category, according to Standard & Poor’s. CREDIT STATUS IN THE ENERGY SECTOR 269 Investment Grade Moody S&P Probability of default Aaa AAA 0.001 Extremely strong capacity to pay Aa1, Aa2, Aa3 AA+, AA, AA– 0.01 Very strong capacity to meet its finan- cial commitments it differs from AAA only in a small degree A1 A+ 0.02 Strong capacity to meet its financial commitments A2, A3 A, A– 0.04 but more susceptible to adverse effects of economic changes Baa1 BBB+ 0.15 Capacity to meet its financial commitments Baa2 BBB 0.3 is adequate but could be weakened by adverse business conditions Baa3 BBB– 0.6 Below Investment Grade/or speculative Ba1 BB+ 0.90 The least vulnerable of speculative grade Ba2 BB 1.25 Very moderate protection of interest and principal payment Ba3 BB– 1.60 Very moderate protection of interest and principal payment B1,B2,B3 B+,B, B– 5.00 Capacity of meeting financial commit- ments is weak Caa CCC 14.00 Currently vulnerable to default Ca, C, CC, C 17.00 Currently vulnerable to default D D 100.00 Default, actual or imminent TABLE 16.1 Credit rating comparisons
    • Energy traders of higher credit quality tend to have that higher credit rating because they not only provide the physical energy to people, but these companies usually have some or all of the following: ■ A leading national and international market position (e.g. Shell, BP) ■ Diversity in most aspects of the business and/or the integration of downstream and upstream activities, which reduces exposure to finan- cial margin erosion. (Exxon for many years considered hedging as unnecessary because it had crude oil fields upstream and it has its own refineries and petrol stations downstream.) ■ Advantages as low-cost providers of physical energy/feedstocks for industry (oil, gas, power, petrochemicals). ■ Expertise in using and selling financial derivatives, and substantial physical liquidity. Making the (investment) grade A rating agency will look at risk management operations closely as many consider this to be the cornerstone of a successful energy trading business. They would expect to see the effective monitoring and control of the following: ■ Complete oversight of its trading business. ■ Market risk. ■ Credit risk policies. ■ The systems used to control and monitor its physical and derivatives trading and settlement processes. Agencies will also look for a clear management control structure for the use of derivatives. They will expect to see an established set of policies, ensuring that at least the following reports are produced and distributed to a senior management committee at the beginning of every business day: ■ A ‘daily position report’ including ● mark-to-market ● credit exposure to counterparts ● value-at-risk (VAR) report ● report detailing any exceptions that have occurred (violation of poli- cies e.g. trading limit breaches) Strong senior management involvement is noted by credit agencies (this is usually picked up in narrative disclosures in notes to accounts or via interviews with company officials). As discussed in the chapter on management controls, the Board of Directors should have overall responsibility for approving an organisa- tion’s trading policy, including the trading procedures and portfolio limits 270 ENERGY PRI CE RI SK
    • endorsed by a risk management committee. Generally, a risk management committee will comprise designated Board members, senior ‘non-trading’ related management and trading managers. A risk management committee should clearly be responsible for reviewing any proposed changes to the trading policy and trading limits of an energy company. It should also evaluate new risk management techniques and hedging strat- egies, and it should approve new derivatives to be traded. Ideally, a credit rating agency will want to see that the Board of Directors are taking an active interest in overseeing trading operations. This can sometimes be illustrated by an organisation requiring board approval for large energy trades, and placing responsibility for internal and external audits of the organi- sation’s trading risk management policy with a Board subcommittee. Risk tolerance: managing the market risk An organisation’s management of market risk and valuation needs to be undertaken by adhering to established policies and procedures outlined in its trading risk management policy and this adherence needs to be illus- trated in audits conducted, so that outside agencies can see this. Credit reference agencies do take note of how frequently an organisa- tion’s trading policy is reviewed so this should happen at least twice a year to reflect any changes in the business, or to improve processes. If an energy company is speculating, its traders could expose the company to significant potential financial losses, so credit rating agencies look closely at how an organisation’s exposure is minimised and how strict adherence to established energy trading and risk management policies and proce- dures is maintained. A clear way to illustrate this to the outside world is for an organisation to show that it is producing trading reports, as high- lighted earlier in this chapter. Valuation of derivatives positions Credit rating agencies have always looked at how a company keeps track of the value of its energy portfolio of both derivatives and physical assets, but since the spate of accounting mishaps in the energy sector (Enron being a key one), the outside world is even more concerned and critical of how an organisation values its portfolio. Companies should adopt a Monte Carlo simulation VAR methodology to quantify their exposures associated with derivatives risk portfolios. The VAR model output is a standard and it allows credit rating agencies to compare the risk a company is taking with any other energy sector company also using VAR. Credit risk management policy Rating agencies will be looking for counterparty credit exposure associ- ated with OTC trades to be managed by establishing dollar credit limits. CREDIT STATUS IN THE ENERGY SECTOR 271
    • Not many companies use credit VAR yet and the simpler US dollar unreal- ised loss limit is seen in the majority of cases in the energy sector. Credit agencies will also be looking out for the use of ‘netting arrangements’ on payments due from derivatives activities, as this can reduce credit risk (Chapter 17 covers this in greater detail). Business and risk management control systems A rating agency (or counterpart to an organisation, for that matter) will be looking at systems, and checking that the organisation can professionally manage its positions in the market. The outside world will want to know what sort of IT infrastructure is in place and whether there are any disaster recovery plans and backup systems to maintain business continuity. A company with its core risk management system shut down for a long period of time will find it difficult to operate effectively or manage its trading positions. Any organisation in the energy sector using derivatives should create business continuity plans so that it can state in its accounts or reports that if IT infrastructure did become inoperative or unavailable for any reason, the monitoring, confirmation of trades, billing and settlements can also be completed manually. Some companies put into their narratives to accounts that ‘Interruptions to the company’s electronic systems can be managed through easy access to documentation and the cross-training of personnel’. For example Standard & Poor’s considers sophisticated computer systems essential to controlling an organisation’s risk. It would look for a system that keeps track of all transactions (credit, trading and other limits) and performs exposure calculations daily. Traders should ideally be equipped with systems that model transactions and keep track of shifting market prices, demand, and inventory. Another important feature is the automatic notification to traders of trading limits and the appropriate pricing of a transaction. The system should also link accounts receivable information with trading programs, prohibit a transaction that exceeded any limits and require senior management authorisations to complete the deal. An even more sophisticated system would calculate all risk positions and forward pricing curves on a transaction-by-transaction basis. In addi- tion, all branch office transactions and multiple trading sites should be linked to one trading and risk management system to capture the full risk exposure and hopefully limit or prevent any rogue trading. The closer to real-time the better, as this gives a level of control and transparency that allows management to make better informed decisions and gives positive signals to the outside world when people are assessing credit risk. A company with an antiquated risk management system that breaks down all the time and calculates values and invoices incorrectly is a big risk for an energy trader. 272 ENERGY PRI CE RI SK
    • Market standing An organisation’s size of operation and its share of sales within geographic markets are important because there are economies of scale in trading in the energy markets. Large organisations also have an advan- tage in terms of information and intelligence on that market. A company which is at the centre of the information flow is at a big advantage because it has a better chance of knowing the direction of the market in the very short term. Size is usually related either to sales or by the number of known active counterparts that an organisation has. It can also be judged by the number of sales contracts and ISDA agreements with counterparties. (ISDAs are discussed in more detail in Chapter 17.) Generally, greater size is a positive credit factor because larger participants in the energy markets gain more knowledge of many different transactions in the market. Diversity of an energy company’s market activity Another important feature of the higher credit quality energy companies is strong diversity and reliability of products and services. These are companies which should be able to provide either oil, natural gas or power any time, anywhere, and at fixed or variable prices and volumes. A key to a successful energy trading operation is delivering exactly what the customer wants and needs. It may be old fashioned to say that owning assets is good, but when looking at the overall credit rating risk of an organisation, assets still count. This is because an energy company will normally have more control over an energy commodity if it actually owns natural gas reserves, some gas storage, power generation plants, refineries, petrochemical plants etc. Of course, the downside is that the organisation would also have the risk of operating the facilities, and the credit risk assessors will look at the quality and experience of the staff and management to try to quantify whether there is any cause for concern in terms of operational risk. Rented assets, such as purchased power and gas contracts, tolling agree- ments, and commitments to use transmission or storage capacity, offer less control over the energy market, but have no operational risks. However, there is credit risk; that is, the risk that a supplier will default on its obligation to deliver the oil, or gas, or power. This leads neatly to supply sources. When looking at the credit risk of an organisation, third parties will check out the sources of supply, and if an organisation is buying energy from a high credit risk company, this may affect the rating of the organisation. Most credit rating agencies view assets favorably, but the only real way to measure an energy trader’s skill at generating profits is through perfor- mance. If an organisation proves it can create more sales with fewer assets, then credit rating benefit will be given in the analysis. CREDIT STATUS IN THE ENERGY SECTOR 273
    • Energy companies certainly benefit from having a large number of traders with good trading relationships in the market. Traders are an energy trading company’s core assets. The depth of their experience, their ability to trade physical and or derivative products, and their ability to source trading information are all critical factors in an energy trading firm’s competitive position. Management track record Credit rating agencies will often scrutinise a firm’s management by exam- ining factors such as the following: ■ Level of risk management background. ■ Knowledge of trading. ■ Familiarity with derivative products. ■ Does top management have a background in managing price risk? ■ Does management understand the risks of using financial derivatives? Are they aware of the funding requirements that could be associated with cash flow surrounding date mismatches over physical trade settle- ments and derivative trade settlements? They should also know about the collateralisation of derivatives with exchanges or counterparts. ■ Is day-to-day funding actively monitored? ■ What does top management do to ensure that proper controls are in place before trading new products? ■ Segregation of duties (highlighted in Chapter 9). Anyone assessing credit risk will look at the controls in place to prevent fraud within an organisation. An example is that the internal credit department should be physically separated from the trading floor. A rating agency will take note of this, as would a bank assessing a customer for credit lines. Capital reserves The other important factor that anyone assessing credit will look at are capital reserves. In other words, they will check how much capital liquidity an organisation has compared to its credit exposures with coun- terparts in the energy market. An organisation should check that it has enough capital reserve to cover its trading activities by evaluating its counterparties in the market, assigning a rating to each and then examining the total credit lines that exist at each credit rating. Table 16.2 applies Standard & Poor’s default risk probabilities by their respective S&P rating category to generate some hypothetical credit limits and so produce a weighted average credit exposure to each rating group, using a one year default probability. 274 ENERGY PRI CE RI SK
    • The appropriate amount of risk capital an organisation sets aside should incorporate these embedded risks. It is worth noting that whether with Standard & Poor’s or with any other credit rating agency, any energy trading firm wishing to gain a higher credit rating should carry multiples of this ‘capital at risk’ in terms of credit lines with counterparts. Note that this capital at risk is not a replacement for, but is in addition to, any VAR calculation which assesses market risk. Credit status: summary To be considered a good company for financing purposes or for pure counterparty credit purposes, a company needs to make sure it has suffi- cient working capital to cover exposures in: ■ Credit, which we have discussed already in this chapter. ■ Price risk, which VAR or the organisation’s chosen risk methodology can help managers determine ■ Operational risk: the organisation should allocate capital for disaster recovery, new systems, more personnel based on increased in turnover etc. It is fair to say that an energy market participant who has a proven ability to hedge open positions would have lower market exposure. Also, an energy market participant who had a robust credit risk management program (see Chapter 15 for more details) could reduce their credit expo- sure. Therefore if the management of a firm wants to make sure their organisation is seen as a good credit risk, they should ensure they develop a capital structure which is appropriate to their organisation’s stated busi- ness strategy and the level of risk it expects to incur in the three risk types just mentioned. CREDIT STATUS IN THE ENERGY SECTOR 275 Rating US$ millions credit lines % Default probability Capital at risk US$ AAA 200,000,000 0.00100 2,000 AA 125,000,000 0.01000 12,500 A 100,000,000 0.04000 40,000 BBB 100,000,000 0.30000 300,000 BB 50,000,000 1.25000 625,000 CCC 25,000,000 14.00000 3,500,000 Total 600,000,000 4,479,500 TABLE 16.2 Weighted average credit exposure; source: Standard & Poor’s and Tom James
    • FINANCING USING DERIVATIVE STRUCTURES Derivatives are proving to be an increasingly popular funding method for organisations in the energy sector. Here, we review some of the more common ways of using derivatives to achieve this end. Energy indexed loans An index linked loan is a way of wrapping price hedging and financing into one package. The major benefits of debt indexed to fixed amounts of energy exposure include: ■ Additional security for lenders and creditors This security comes as a result of a reduction in the volatility of the producer’s cash flows and its exposure to energy prices. ■ A price hedge for the borrower/issuer of the debt The energy price link creates a hedge for the consumer as illustrated in the term sheet example below. It may be better to create this type of hedge (a sort of synthetic hedge because derivatives are not directly traded, but the same result is achieved), since it may permit a hedge to be created for a longer period of time than is available in the derivatives market directly due to lack of liquidity in far forward transactions. It may therefore be more cost effective in terms of the price a borrower is able to achieve for its hedge protection, in addition to being more credit efficient. This is because it combines the hedge with funding via the loan, effectively collateralising the hedge. For example, if a consumer of natural gas seeks a hedge for its gas price exposure in the form of a gas indexed loan, the structure for the loan would look like the following. The borrower may be a power station; the lender could be the producer of the gas, or a trader who arranges funding for the power station to buy into a long-term supply contract. Via this loan structure, the borrower gets a hedge against the natural gas price being higher on maturity of the loan and the lender would have exposure to prices moving higher, so would need to hedge somehow, either with a back-to-back physical contract or through some derivatives structure with another counterpart. Natural Gas indexed loan for Natural Gas consumer: Principal amount: GBP10,000,000 Term: 10 years Repayment: In full at maturity Commodity index: UK NBP Natural Gas Index Fixed commodity price: 20 pence per therm (GBP0.20) Under this loan transaction, the borrower (the consumer of natural gas, e.g. a power station) receives GBP10,000,000 at the start of the financing. 276 ENERGY PRI CE RI SK
    • This is the cash equivalent of an agreed GBP0.20 pence per therm basis price (notional natural gas position of 50,000,000 therms equivalent, 10,000,000 × 20 pence per therm). The borrower’s principal (amount borrowed) repayment has a link to movements in UK natural gas prices in accordance with the following simple formula: Principal repayment – [(Natural gas price (at maturity) – Fixed commodity price) × Notional commodity position] Assuming the natural gas price has moved to 25 pence per therm, the cash amount due at maturity would be: GBP10,000,000 – [(25 pence per therm – 20 pence per therm) × 50,000,000 therms] = GBP7,500,000 The principal repayment at maturity in this scenario is GBP2,500,000 less than the face value of the loan. This saving can provide a hedge against the increased operational costs from the higher natural gas price of 25 pence per therm for the borrower. Energy indexed bonds An attraction for investors to the following structure, which has been seen in metals and energy markets in the past, is that it offers investors an interest rate return plus an exposure linked to an energy price. The key advantage for the issuer of the bond is that it appreciates from a hedge against its underlying energy risk, since with increasing interest rates of the bond, the bond issuer is benefiting from increases in cash flow due to the higher revenues from its physical oil sales. The reverse of this is a consumer situation: for example, airlines some- times look at this type of funding for aircraft, where the interest rate is linked to jet fuel prices, which can account for up to a third of an airline’s operating costs. In this case the bond would be structured so that if jet fuel prices rise then, based on a formula, the interest rate would decrease, easing the tighter cash flow situation due to higher jet fuel prices. When jet fuel prices went down below a certain level then interest rates would increase (usually with a cap set in the agreement). Energy producer bond issuer example Issue: Energy producer Maturity: 10 years Specified energy amount: X amount of energy Principal amount of the bond: Principal amount equal to the market value of the specified energy amount as at the date of issue FI NANCING USING DERIVATIVE STRUCTURES 277
    • Interest rate: X% of the principal bond amount Interest: Interest is payable in US$ at the interest rate calculated on the basis of the average market value of the energy for an agreed number of days prior to the interest payment Principal redemption: The bonds will be redeemed in US$ based on the specified amount of energy calculated on the basis of the average market value of the energy for an agreed number of days prior to redemption. Security interest: The bonds are fully secured by mort- gage/lien over the energy source (perhaps an oil field?) Airline/shipping company bond/loan issue In an airline or shipping company bond/loan scenario, banks can offer to buy a bond or issue a loan on the basis that if jet fuel prices increase for an airline, the interest rate on the bond or loan decreases (with some floor). However, if jet fuel prices decrease then, since the airline will appreciate from better operating revenue and operating profit, the interest rate on the bond or loan increases with some pre-agreed cap. Sometimes this sort of financing approach can be linked to specific aircraft or ship financing deals. Banks offer this kind of deal because they can hedge their exposure using derivatives in the oil markets. Also, by easing cash flow for their customers when their energy prices are high, they can reduce the inherent credit/business risk for that entity and in turn reduce the potential default risk to the buyer of the bond or the lender. Inventory financing example This sort of structure can be useful for producers, traders, and consumers with an energy exposure. It is mainly restricted to energy types that can be stored easily, for example gas or petroleum. Electricity presents more problems, although it may be possible to structure something around hydroelectric power (the water at higher ground being considered the inventory needed to introduce some weather swaps – in this instance to protect against adverse weather conditions). In the power markets, compressed air storage tanks have sometimes been used as a synthetic storage of power. Off-peak power is used to create the compressed air in storage and it is then released to generate more expensive peak load power at the appropriate moment. (This is the same principle as pumped water storage used by hydroelectric power stations.) 278 ENERGY PRI CE RI SK
    • Common uses of inventory financing ■ A consumer, e.g. an industrial user, has to keep strategic stock of fuel oil or gasoil etc. on-site to ensure business continuity. However, this ties up important working capital that might be better off applied to other busi- ness development or research and development work. Using inventory financing the company can normally maintain the energy source on-site at its factories. However, this is hedged using derivatives and a percentage of the value of the energy stored on-site is released back (minus structure and financing costs) to the industrial user. The loan is collateralised by the energy in storage onsite. This can be a lower cost route of funding for corporates. ■ Energy producers or traders with energy in storage can approach finan- cial institutions to lock in the value of this energy using forward markets such as derivatives. Again the advantages may be cheaper forms of releasing working capital in the business as the stored energy and the hedge is used as collateral. This approach also creates a collateralised hedge. Tripartite financing Even if a company is not looking to borrow funding against stored and hedge funding, if it can show both sides of this transaction equation to its bankers it may appreciate from lower costs of funding. But energy compa- nies that do not have huge amounts of capital to play with can look at sourcing tripartite financing lines (Figure 16.1). This can allow traders to trade more and bankers to lend more. An energy trader gives its funding organisations lien over the derivatives hedge cash flow and also the cash flow from the physical energy transaction. The bank that is funding the deal has lower risk because it has a balanced position – a hedge on a phys- ical energy transaction. It just has to contend with whatever basis risk may FI NANCING USING DERIVATIVE STRUCTURES 279 Bank Skilful energy trader Physical market counterpart Derivatives market counterpart Tri-partite agreement FIGURE 16.1 Tripartite financing. In effect, the energy trader assigns rights over the cash flows of both the physical deal and the derivative hedge to the bank, which guarantees the credit performance of the energy trader to its physical market counterpart and its derivative market counterpart. The bank can feel comfortable to do this as it has rights over both sides of the transaction and has a balanced book (subject to any basis risk on the hedge.
    • be present between the hedge and the underlying energy product. This approach can usually permit a bank to lend much more to energy traders and for energy traders to gear up on their capital base much more. The bank will focus on the skill set and track record of the traders and manage- ment of an organisation closely when evaluating whether or not to extend this type of funding arrangement. Another key advantage here is that tripartite lines of credit automatically guarantee lines for the hedge. Coun- terparts may not ask for cash up front, but any trading derivative contracts or physical energy uses up an organisation’s credit capacity in the market. However, it uses up much less credit capacity if a counterpart (like a bank who is funding the organisation) can see the hedge and the physical side of the cash flow. Pre-payment financing example In the past, several OPEC and non-OPEC countries have used pre-payment structures to realise future cash flow on physical sale agreements today. These structures are a form of forward contract where the buyer agrees to pay the seller the present value of the price of the oil in advance. In effect, the buyer has provided a loan to the seller based on the subsequent supply at the forward date. Sometimes the forward physical purchase and the funding is handled by a trader or one energy organisation. More commonly, due to the lack of investment grade entities in the energy sector, an energy trader works with a group of banks to structure this sort of deal for a producer. Pre-payment structures are normally left for medium term financing (five years or more), because of the initial setup costs of establishing the struc- ture. Producers of energy, such as a crude oil producing nation or an oil 280 ENERGY PRI CE RI SK Oil buyer (lifter) Agent and security trustee Oil producer Derivatives hedge counterparty Contractors Lender FIGURE 16.2 Pre-payment financing structure
    • refiner, can obtain a structure where forward production of crude oil or petroleum products is hedged in the derivatives markets (usually with the assistance of a trader who agrees to buy the oil produced and dispose it in the oil markets for the bank). In this case, banks will pay the producer value today a percentage of the forward value of the energy production which has been hedged. The bank uses the forward production as collateral. With this method of funding, there may be funding cost advantages in long-term funding arrangements. It can also be useful in cases where straight corporate financing may not be possible for the entity due to its bad credit rating. This type of pre-payment does not have to go on the accounting books of a firm or sovereign entity as a debt because it is a pre- payment on a commercial deal to purchase physical energy. The advantages of this structure are: ■ Oil does not need to be project linked. ■ Payment risk offset for financers. Major offtaker (buyer) pays for the oil and in doing so repays the loan principal and interest. The disadvantages are: ■ It is a complex structure, so legal costs can be high. ■ A willing and acceptable off taker/buyer has to be found (since credit risk is transferred to the buyer of oil). ■ Delivery risk remains (but this is the case in any financing structure built around a physical commodity). Figure 16.2 shows how the agent and security trustee oversee the whole process as a neutral third party, assisted by contractors who report oil flows and deliveries. This data should match against cash flows. The lender via the trustee passes the loan of money which is collateralised FI NANCING USING DERIVATIVE STRUCTURES 281 Oil buyer (lifter) SPVOil producer Contractors Lender FIGURE 16.3 Pre-payment financing with SPV
    • against the forward production of the oil to the oil producer in the above scenario. If this were a national oil company, it might pass the funds directly to the government’s treasury. The forward oil value is locked in via a hedge which the oil producer locks in itself, or sometimes the lender organises this as part of the package. The hedge may be made up of futures, swaps and/or options. The cash flow of the hedge is pledged to the agent and security trustee/lender, as is the cash flow of the oil sales. The oil company receives cash flow from its oil sales minus repayment fees and interest and costs from the agent and security trustee. The lender receives the repayment of principle and interest from the agent and secu- rity trustee. The oil buyer or lifter or sometimes called the offtaker of the oil sends any payment of the oil to the agent and security trustee, who then pays out monies to the lender, the oil company and hedge counterparty if any losses on the hedge are due and payable. The Special Purposes Vehicle (Company) in respect to pre-payment structures In case of default under the terms of a pre-payment structure, the lender will normally have some rights over the oil production and possibly other assets. So, sometimes, companies or countries wishing to raise money in this manner try to ensure that the only assets that a lender has rights over, are very specific oil fields or other assets. In this instance an SPV or Special Purposes Vehicle may be set up. This is normally done for the following reasons: 1. For prepayment financing flexibility for the borrower to sell the oil to any potential lifter, not fixed to sell the oil to only one dedicated lifter as in the previous case. 2. Sometimes certain countries or banks cannot have a direct contract with certain other countries. 3. To ring fence the finance project. The SPV has no assets other than its rights against the ‘real’ borrower of the money. 4. It may assist to raise the overall credit rating of the transaction by moving the lending to the SPV away from the ‘real’ borrower behind the SPV. As Figure 16.3 shows, the Special Purposes Vehicle becomes the actual legal counterpart to the whole deal, with its asset being its rights against the ‘real borrower’ which is, in this case, the oil producer. The SPV sells the physical oil to the oil buyer and has a back-to-back physical contract with the oil producer. The SPV pays the lender capital repayments and interest out of the oil sale cash flow. The remaining cash is paid to the oil producer for the oil. The contractor checks that everything is operated in accor- dance with lending agreements and acts on behalf of the lender. This is a 282 ENERGY PRI CE RI SK
    • complex structure which often requires a lot of tax advice as well as legal structuring. Loans with embedded option structures (structured notes) Loans with embedded option structures can be used to reduce the overall cost of borrowing by generating cash flow, otherwise known as premium (as discussed in Chapter 5). This can be used to a borrower’s advantage by placing an option inside a loan structure to reduce the basis point cost of funding. Example of an oil-linked structured bond This is an example of an oil option-based note issue. The redemption value of the bond is linked to the price of WTI Crude. The bond has an embedded 1 year European style floor (put) option on WTI. The sale of the option allows the issuer to create a Libor minus 1 funding rate. Key terms: Amount: US$100 million Maturity: 1 year Coupon: 20% per annum Issue price: 100.875% Commission charges: 0.875% Redemption: The redemption value of the bonds linked to the a formula e.g. ■ If the price of the oil index at maturity is greater than the redemption strike price of the oil index, then the redemption of the bond is at par value. ■ If the price of the oil index is below the redemption strike price per barrel then the bond holder will receive less than par on his principal determined as below per US$1,000 bond: 1,000 × (Redemption strike price/ reference price) For the redemption formula: Reference price: West Texas Intermediate crude Redemption strike price: The New York Mercantile Exchange Settle- ment price per barrel on 13 August 2002, for the WTI light sweet crude oil futures contract for delivery during the month of October 2002, as quoted in the price source. US$17.50 FI NANCING USING DERIVATIVE STRUCTURES 283
    • Reference price: The arithmetic average of New York Mercantile Exchange Settlement Prices for WTI light sweet crude oil futures contract for delivery during the month of October 2003, as quoted in the price source, for the three NYMEX trading days immediately preceding but excluding two days prior to the maturity date. Price source: Wall Street Journal Settlement: Cash payment as per redemption formula The redemption formula embeds a 1 year European style floor option on WTI crude oil at a strike price of US$17.50 per barrel. The floor option was sold by the bond buyer in favour of the bond issuer. At maturity, if the reference price for WTI is above the redemption strike price of US$17.50, then there is no cash flow under the option and the issuer repays the bond holder the par value of the bonds. However, if the WTI price is below US$17.50 (for example US$16), then the cash flow would look like this: ■ The energy company that issued the bonds repays the bond holder in accordance with the redemption formula: 91.428% of par calculated as follows: 1000 × (16/17.50) = 914.2857. ● This is equivalent to US$91,428,570. ● The difference between the par value of US$100 million and US$91,428,570 redemption value of US$8,571,430 is paid by the energy company who issued the bonds to the floor option counter- part representing the value of the option at maturity (European style). The use of this structure creates cheaper up-front funding, while the downside exposure for the bond issuer can be protected through other derivative hedging structures. For example, if there is an implied volatility on the embedded floor option sold by the bond buyer of around 23% and the prevailing market level for the volatility of comparable options is around 30%, this would represent a difference in option premium of potentially several million dollars (based on WTI). This difference would benefit the bond issuer and this premium profit could be put towards funding interest payments, and this is where the bond issuer is able to potentially get a NET – a negative Libor funding rate. Example of oil index notes Oil index notes issued by a trader (effectively caps/call options on oil) 284 ENERGY PRI CE RI SK
    • Maturity: 15 years Value: US$37.5 million Strike price: US$25 per barrel For the buyer of the notes from the energy trader, if the oil price is above US$25 dollars per barrel, the investor will receive an amount reflecting the price increase of the value of the call option that the energy trader is in effect issuing via this oil index note. However, in the event that the oil price is at US$25 or below the options will expire unexercised and the investor will just receive back the face value of the notes. These notes are useful for investors who want the potential for much higher returns than interest rates can offer, but who are willing to take the risk of only getting their original capital invested back. Financing trade receivables Many companies wish to finance their trade receivables in order to make cash immediately available and so retain their ability to borrow money. A typical energy physical deal has a minimum value of several million US dollars. As credit is quite expensive for the majority of the sector (with the average credit rating not being above a BB), energy traders and producers can release much needed working capital tied up in trade receivables. Specialised financing companies have emerged in this area to finance these trade receivables; one of the leaders in this field is the Euler Group, probably due to its link with the general reinsurance and credit insurance markets: http://www.eulergroup.com/corpo/en/corpo1/services.cfm. This approach can also help companies to give longer credit terms to its customers, which can be pushed as a competitive advantage, both as a way of attracting new customers and a way of keeping them. FI NANCING USING DERIVATIVE STRUCTURES 285
    • CHAPTER 17 OTC Derivatives Legal Risk Control and Documentation The International Swaps and Derivatives Association (ISDA) is the global trade association that represents leading participants in the privately negotiated derivatives industry and the so-called ‘ISDA Master Agree- ment’ provides the main legal framework for energy derivatives markets. There are some players in the market who may wish to use their own non- ISDA based agreement, but these days it is very rare to meet one. ISDA’s 2002 Operational Benchmarking Survey found that the use of master agreements has been steadily increasing. ISDA members reported that signed master agreements are in place with over 92% of their OTC derivatives counterparties; an increase from 85% in 2001. ISDA Master Agreements now cover products such as interest rate swaps, currency swaps, forward rate agreements, commodity swaps (for energy deriva- tives), equity/equity index swaps, options including caps, collars, floors, forex, credit derivatives and gold bullion. It is worth noting that swaps (i.e. purely cash-settled derivative instru- ments with no physical delivery) are mainly traded under ISDA Master Agreements. However non-financial power and gas markets, such as UK power and gas markets, trade under the GTMA (General Trading Master Agreement) produced by Allen & Overy (http://www.allenovery.com/) and European power and gas normally under the European Federation of Electricity Traders (EFET). The fact that derivatives contracts use money (cash) settlement is impor- tant when it comes to accounting for these contracts and it affects the operational risk of these contracts. There is much more risk when dealing with GTMA- and EFET-based OTC contacts which on expiry go to phys- ical delivery. This means that there are fewer financial traders like banks involved in these physical delivery markets. Since its creation in 1985, ISDA has pioneered efforts to identify and reduce the sources of risk in the derivatives and risk management busi- ness. Among its key achievements have been: 286
    • ■ Developing the ISDA Master Agreement (the energy industry tends to utilise the 1992 Master Agreement). ■ Publishing a wide range of related documentation materials and instru- ments covering a variety of transaction types. ■ Producing legal opinions on the enforceability of netting (available only to ISDA members). ■ Securing recognition of the risk-reducing effects of netting in deter- mining capital requirements. ■ Promoting sound risk management practices, and advancing the under- standing and treatment of derivatives and risk management from public policy and regulatory capital perspectives. THE ISDA AGREEMENT ISDA agreements are made up of two important parts: the ISDA Master Agreement is a standard format which does not change (an example is included at the end of this chapter for your reference) and the ISDA Schedule to the Master Agreement. The Schedule is the part that is negoti- ated between counterparts and contains information such as procedures on settlement, early termination, default, netting arrangements (if any) and banking details for both organisations party to the Master Agreement. Sometimes the Credit Support Annex is attached to this, an example of which is also included at the end of this chapter. (This Annex could be replaced in the near future by a new Margin Annex: see notes later on about this.) The majority of crude oil, petroleum products, and financial power and gas over-the-counter derivatives (i.e. derivatives that are money settled, not involving any physical delivery of the commodity – OTC Swaps/ Options) use the 1992 ISDA Master Swaps Agreement Multi-currency Cross- border version. In addition to this, counterparts in the market generally use this Master Swaps agreement with 1993 ISDA Commodity Derivatives definitions and the 2000 supplement to the 1993 ISDA commodity deriva- tives definitions. THE ISDA MASTER AGREEMENT Any non-legal manager taking their first look at an ISDA agreement usually has a shock. It’s a big document and consists of fourteen sections, as follows: 1. Interpretation. 2. Obligations. THE ISDA AGREEMENT 287
    • 3. Representations. 4. Agreements. 5. Events of default and termination events. (An event is anything that has to happen to trigger some action in the contract. For example, when a counterpart goes bankrupt, it is considered to be an event and this may then allow certain action to be taken under the ISDA agreement.) 6. Early termination. 7. Transfer. 8. Contractual currency (in the energy industry this is normally always US dollars). 9. Miscellaneous. 10. Offices. 11. Expenses. 12. Notices. 13. Governing law and jurisdiction (normally English law). 14. Definitions. ISDA PUBLICATIONS ISDA publishes some very useful books to help business managers under- stand the meanings of the contract sections of its agreements, in particular the meaning of the 1993 and 2000 Supplementary ISDA agreements and terms. 1993 ISDA Commodity Derivatives Definitions These definitions are designed to facilitate the documentation of commodity transactions under the 1992 Master Agreements. Sample forms of confirmation are included. 2000 Supplement to the 1993 ISDA Commodity Derivatives Definitions The Supplement is an update of the 1993 ISDA Commodity Derivatives Definitions (the ‘1993 Definitions’), which many participants in the over- the-counter commodity derivatives markets have incorporated into existing confirmations or other agreements. As is the case with the 1993 Definitions, the Supplement is designed for use by participants in the markets for commodity derivatives transactions in documenting cash- settled commodity swaps, options, caps, collars, floors and swaptions or such other cash-settled commodity derivatives transactions as the parties desire. The Supplement includes additional Commodity Reference Prices for Energy, Metals and Paper. The Supplement may not include all the 288 ENERGY PRI CE RI SK
    • commodity reference prices available for a particular commodity and used by market participants, but it adds significantly to the number of commodity reference prices set forth in the 1993 Definitions and includes the Commodity Reference Price Framework from the 1993 Definitions, which facilitates the definition of a commodity reference price that is not set forth in the Supplement. In addition to an expanded Commodity Reference Price Section, the Supplement allows parties to incorporate price materiality into the Price Source Disruption Event defined in Section 7.4 2000 ISDA Definitions and Annex This is what the majority of players In the energy market are using at the moment, although this may change in the not-too-distant future. PRE-CONFIRMATIONS AND LONG-FORM CONFIRMATIONS Banks and financial institutions aim to have ISDA Agreements negotiated and signed off within 3 months, although it can often take between 3 and 6 months to have an ISDA put in place with a counterpart. Because of the time it takes to set up an ISDA, it is common to see counterparts trading with one another on the basis of an ISDA being put in place eventually (or under negotiation whilst trading). Most risk management policies prohibit any trading before an ISDA has been signed off by both parties; however, the commercial need to trade sometimes takes precedence over this policy (with management approval). But trading without an agree- ment does add considerable legal risk to a business and if trading must go ahead with a counterpart it may be better to use what is termed a ‘pre- confirmation’ and or a ‘long-form confirmation’. A ‘pre-confirmation’ states the terms of the derivatives transaction and choices of provisions that would appear in the ISDA Master Agreement. The idea behind this is to commit counterparties to this wording before the agreement is signed. However, these are becoming less common due to a tightening of risk management policies over documentation and controls over trading prior to ISDA Master Agreements. These days ‘long-form confirmations’ are far more frequently used. (They get their name from the fact that they usually consist of about nine feet of telex roll or fax paper!) Basically, this is a one-off derivatives contract for a specific deal which covers all the main eventualities. This type of confirmation is probably best for dealing with entities which are not regular trading partners and so do not warrant the legal cost of creating an ISDA. It can also be helpful in situations in which there is an PRE-CONFI RM ATI ONS AND LONG-FORM CONFIRMATIONS 289
    • urgent need to trade, but an ISDA has not been signed off yet. ‘Long-form’ contracts should be used for short dated ‘plain vanilla’ derivatives, with a counterpart in a familiar jurisdiction. ISDA DOCUMENTATION PROCESSING Figure 17.1 shows the ISDA documentation required. When entering into an ISDA agreement, one of the counterparts will usually take the initiative and send its standard ISDA Schedule draft wording for the other party to review and comment on. As mentioned earlier, the ISDA Master agree- ment is not changed by counterparts; the ISDA Schedule is the negotiated document. At this stage of proceedings, no negotiation has begun on the specific terms in the ISDA Schedule. Prior to negotiation on terms, the credit department must first process the counterpart details and pass the details of internally approved credit terms to the legal department who need this for inclusion in the ISDA Schedule; this also affects whether or not Credit Support Annexes are required. Before rushing into the expense of processing legal documentation with a new OTC counterpart, it is useful to check the memorandum and articles of association of the counterpart’s organisation. These are known as the ‘M&As’ and provide the legal incorporation details of the organisation, specifying what business functions it can carry out and sometimes what it is prohibited from doing. It is very important to check that there is nothing 290 ENERGY PRI CE RI SK Credit support documents offering protection against credit risk: • 1994 Credit support annex New York Law • 1995 Credit support annex English law • 1995 Credit support annex Japanese law 1992 MASTER AGREEMENT (multi-currency cross border) • Incorporates Confirmations • Includes representations and events of default/termination events • Specifies early termination provisions Confirmations – Short Form confirmations are made possible by the signing of a Master Agreement • Incorporate definitions • Refer to signed master agreement • Specify economic terms of each transaction • Include any individual modifications Definitions • 1993 commodity derivatives Definitions and Year 2000 supplement • 2001 margin provisions FIGURE 17.1 ISDA documentation for energy
    • in the M&As of the firm that prevents it from entering into OTC derivative contracts with other companies. If the M&As are satisfactory then both parties should be ready to put together an ISDA agreement. Although the ISDA Master Agreement is a standard document there are areas of it which give rise to different types of risk for counterparts and are therefore often areas of negotiation in the Schedule. (Remember that the Schedule is where counterparts make the choices of how certain areas of the Master Agreement will effect their derivatives transactions.) These areas are as follows: ■ Legal risk ● Section 1(b) Inconsistency – Where there is any inconsistency between the ISDA Master Agreement text and the ISDA Schedule (which is negotiated between the counterparts to the agreement) the Schedule will prevail. Also a key point is that if there is any conflict between a Confirmation and the ISDA Master and the Schedule, the Confirmation will prevail for the trade the Confirmation is recapping. This can contribute to operational risk, so trade confirmations must go out correctly. ● Section 1(c) Single Agreement – If trades are closed out, this section makes sure the values of all trades between the two counterparts are calculated and netted off against each other, so only one payment is required between the two counterparts. This avoids a situation called ‘cherry picking’, where if a company has gone bankrupt, the liqui- dator can call in payments on trades that are profitable for the bank- rupt client, but refuse to pay out on trades which are not profitable. For example, imagine that Counterpart A and Counterpart B do two derivatives trades, with Counterpart A making US$2 million dollars on one deal (this is a zero sum game, so Counterpart B is losing US$2 million), and on the other deal Counterpart B is making US$1.5 million dollars (with Counterpart A losing US$ 1.5 million dollars). In this situation, if Counterpart B went bankrupt and Section 1(c) was not in place (because it had been deliberately excluded via the wording in the ISDA Schedule), then Counterpart A could end up being forced to pay to Counterpart B US$1.5 million dollars (even though the net position is that Counterpart B owes Counterpart A US$500,000). The single agreement concept reinforces the position that a liquidator cannot do this. It collapses and nets out the entire portfolio of derivatives trades into one single payment due to one counterpart or the other. ● Section 5(a) Events of Default is a key area – This covers a party’s failure to make any payment or delivery under Section 2 of the Master agreement which covers the counterparts’ obligations. In the past, the energy industry adopted a grace period of 3 days; however, this is ISDA DOCUMENTATION PROCESSING 291
    • increasingly being shortened to sometimes just 1 day grace period on payments. The section also covers Credit Support Default, Misrepre- sentation, Default under Specified Transactions (we look at this in more detail in the ISDA Schedule example later in this chapter), Cross Default, Bankruptcy, Merger, Illegality and Credit Event upon Merger. ● Section 7 Transfer of the Agreement – Normally, counterparts are not allowed to transfer the ISDA Agreement or any rights and obligations under it without written consent from the other party. There are a few exceptions to this rule but these are rare instances where a counter- part wants to transfer the agreement to avoid an ‘event’ (e.g. Ille- gality, Tax Event, certain cases surrounding a Merger) and a counterpart transfers the close-out money payable to it by a defaulting counterpart to another firm. ● Section 8 Contractual Currency – This protects counterparts from foreign exchange losses on settlement and close-out payments. ● Section 9(d) Miscellaneous (Remedies Cumulative) – When a coun- terpart is faced with another counterpart defaulting, it should not forget that the termination of derivatives trades is not the only course of action. A counterpart can leave the trades open or even sue for damages, if it chooses to do so. ● Section 13 Governing Law and Jurisdiction – The majority of energy derivatives trades under ISDA outside the USA, even with American companies, are conducted under English Law and the jurisdiction of the English courts. Under ISDA there is a choice between English Law and English Courts or State of New York Law and the jurisdiction of the courts of the State of New York and the US District Court located in the Borough of Manhattan in New York. ■ Counterparty risk ● Section 5 Events of Default and Termination Events – This is exam- ined from a practical standpoint in the ISDA Schedule example later in this chapter. ■ Market risk ● Section 6 of the ISDA Master Agreement – This covers early termina- tion especially with Automatic Early Termination. We look at this in the ISDA Schedule example later in this chapter. ■ Documentation risk ● Section 4 Agreements – This covers the agreement of what docu- ments both counterparts agree to provide one another (e.g. company certificates of incorporation, copies of licenses and renewals). It also covers agreement that in some case counterparts must maintain certain licenses and also pay any stamp duty taxes on any agreements etc. 292 ENERGY PRI CE RI SK
    • ■ Payment on settlement risk ● Section 2 – This key area is where counterparts agree on details of how payments are to be made and how netting is performed, and also covers provisions protecting counterparts against withholding tax deductions. TRADING BEFORE AN ISDA IS SIGNED There is a documentation risk in the time period between the execution of an OTC derivatives trade and an agreement being agreed upon and signed. If a trade does take place prior to an ISDA being signed between the two counterparts (which is not advisable unless there are considerable commercial pressures to put a hedge on very quickly) then the Trade Confirmation sent out will normally state that both counterparts to the deal must use ‘best endeavours’ (a legal term as to the amount of effort used to achieve an agreement) to enter into an ISDA agreement. In the Confirmation it usually states that the derivatives trade is subject to the terms of an ISDA Master Agreement without a Schedule, so it is basically unamended. The lack of a Schedule, though, means that the two counterparts cannot make their own choices over key issues in the Master Agreement. These issues would include: choices over what triggers automatic early termina- tion of derivatives deals, payment netting and methods, what happens if a company merges with another, termination currency, tax representations (regarding withholding taxes on settlement payments), credit support (any parent companies willing to support the credit exposure on the derivatives trades) and which entities are included in Specified Entities (the other companies that for the purposes of triggering a default are included in the agreement). The biggest risk for an organisation if it trades without an ISDA Agree- ment is that if the other counterpart goes into bankruptcy or liquidation, a liquidator could end up ‘cherry picking’ any profitable deals. ISDA MASTER AGREEMENT SCHEDULE The ISDA Master Agreement Schedule basically states which sections of the Master Agreement will be in force between the two parties to the agreement. As this is the case, it is often the centre of much discussion and negotiation. Although ISDA Schedules will differ slightly from one another in commercial terms, there are still key parts that turn up again and again, so in this chapter we will go through an example of an ISDA TRADING BEFORE AN ISDA IS SIGNED 293
    • Master Agreement between a bank and a non-financial institution energy trader. The ISDA Schedule is always executed (signed off) at the same date as the Master Agreement it refers to. If an organisation updates a Master Agreement Schedule at a later date and it has some OTC derivatives currently outstanding with the other firm under its old agreement, it is common practice for energy trading companies to backdate the new ISDA Schedule agreement with the same date as the old one so that old transac- tions are covered by the updated ISDA Schedule. The Schedule is made up of the following core sections: ■ Termination provisions ■ Tax representations ■ Agreement to deliver documents ■ Miscellaneous ■ Other provisions In the following section, we go through an ISDA Master Agreement Schedule and note some of the key areas. STEP BY STEP EXPLANATION OF A TYPICAL ISDA MASTER AGREEMENT SCHEDULE BETWEEN A TRADER AND A BANK AGREEMENT DATED AS OF 15 December 2002 BETWEEN ABC SMALL TRADER LIMITED (Party A) AND XYZ BANK LIMITED (Party B) [First of all, the Schedule names the two counterparts to the agreement: the two organisations (or groups) that want to trade with one another] PART 1 TERMINATION In this Agreement: 1. ‘Specified Entity’ means in relation to Party A for the purpose of: Section 5(a)(v): [Default under specified transactions] Section 5(a)(vi): [Cross Default] Section 5(a)(vii): [Bankruptcy] Section 5(b)(iv): [Termination event – credit event upon merger] 294 ENERGY PRI CE RI SK
    • ‘Specified Entity’ means in relation to Party B for the purpose of: Section 5(a)(v): Not applicable Section 5(a)(vi): Not applicable Section 5(a)(vii): Not applicable Section 5(b)(iv): Not applicable [This is about Party B getting as much credit cover as possible against Party A in the event of defaults. In this example Section 5 XYZ Bank Ltd does not have to give these assurance back to ABC Small Trader Ltd. ABC Small Trader Ltd though is basically agreeing that if it defaults on any OTC contract with XYZ Bank, XYZ Bank has the right to close out all transactions under this agreement. Note that Credit Support providers of ABC Small Trader Ltd (e.g. its parent company) are automatically joined to this provision in the 1992 ISDA Master Agreement. The aim of the Specified Entity provision is to draw in those organisations whose capital is closely correlated with that of ABC Small Trader Ltd. Banks rarely offer this Specified Entity provision because most of the assets of its group will be in the bank itself and they see little point in opening themselves to the risk of ABC Small Trader Ltd, for example, closing out trades under this agreement through the default of a small bank subsidiary in another agreement with ABC Small Trader Ltd or one of its specified entities.] 2. ‘Specified Transaction’ will have the meaning specified in Section 14 of this Agreement. [Section 14 is in the Master Agreement and unless it states otherwise, which in this example it does not, it means any OTC Derivative transaction existing in another agreement between the parties to this Schedule or their Affiliates or specified entities. The bottom line is, if ABC Small Trader Ltd has lots of swaps and OTC options positions with XYZ Bank Ltd, and a subsidiary of ABC Small Trader Ltd called EFG Trader decides under another agreement with XYZ Bank Ltd to enter into a Swap with XYZ Bank Ltd, and this subsidiary EFG Trader then goes bust and defaults then, under this agree- ment, XYZ Bank Ltd could go back and close out ABC’s positions! Changes in Specified Transaction provisions are being proposed which could widen the scope beyond OTC transactions being in default to allow the party not in default to close out all transac- tions with the defaulting party.] 3. ‘Cross Default’: The provisions of Section 5(a)(vi) will apply to Party A and Party B. [This provision catches contractual terms and payment defaults in relation to borrowed money in agreements between the two parties to this ISDA agreement and their Specified Entities or Credit Support Providers with any third party. Such a default has to exceed a defined limit, termed the Threshold Amount. This means that if ABC Small Trader Ltd or any of its companies in its group, or any company that is providing Credit Support in this agreement to permit trading between ABC and XYZ, defaults on any agreement under which it has borrowed money, then XYZ Bank Ltd can close out the transactions under this ISDA Agreement.] ‘Specified Indebtedness’ will have the meaning specified in Section 14 of this Agreement except that (i) such term shall not include obligations STEP BY STEP EXPLANATION 295
    • in respect of deposits received in the ordinary course of a party’s banking business and (ii) there shall be added at the end thereof ‘or any money otherwise raised whether by means of issue of notes, bonds, commercial paper, certificates of deposit or other debt instruments, under financial leases, deferred purchase schemes or under any currency or interest rate swap or exchange agreement of any kind whatsoever or otherwise.’ [In this schedule XYZ Bank Ltd is extending what the borrowing of money is related to, e.g. noted, bonds, commercial paper or financial leases. XYZ Bank Ltd wants to protect itself against the higher risk of ABC Small Trader Ltd, working on the notion that a default somewhere else in some loan or lease etc. may be the early warning signs of a bankruptcy on its way. XYZ Bank Ltd then has the ability to close out its OTC positions and control its losses. In this section XYZ Bank has excluded the banking deposits it may receive from its bank customers, which is quite common. Technically, these deposits are money borrowed by the bank from its customers so some may argue over this. The usual problem faced by a bank is that its customer bank account deposits are very large and would easily breach any threshold amount level.] ‘Threshold Amount’ means with respect to Party A an amount of US$10,000,000 or the US dollar equivalent of any obligations stated in any other currency, currency unit or combination thereof, with respect to Party B, an amount equal to 5% of stockholders equity as of the end of its most recently completed fiscal year (or its equivalent in any currency). [The threshold amount is the amount of money or limit of specified indebtedness, below which XYZ Bank Ltd cannot trigger its close-out rights under this agreement’s Cross Default Clause. In this case, for ABC Small Trader Ltd, the limit is US$10,000,000. XYZ Bank Ltd is a huge entity and its capital base can be very vari- able, so instead of a fixed monetary amount, a formula based on a percentage of stockholders’ equity is used. This is quite common for Wall Street refiners, i.e. financial institutions trading in the energy derivatives markets.] 4. ‘Credit Event Upon Merger’: The provisions of Section 5(b)(iv) will apply to Party A and Party B as amended as follows: Whether, for the purposes of Section 5(b)(iv) of this Agreement, the resulting, surviving or transferee entity (hereinafter ‘Y’) is ‘materially weaker’ shall be a matter to be determined in the reasonable discretion of the other party. Notwithstanding the foregoing, the creditworthi- ness of Y shall not be determined to be materially weaker if Y agrees to and does within two local Business Days of demand provide Eligible Credit Support (as defined in the Credit Support Annex) in an amount equal to or in excess of the Delivery Amount (as defined in the Credit Support Annex) on the basis that the Threshold for Y shall be zero notwithstanding anything to the contrary in the Credit Support Annex and thereafter maintains such Eligible Credit Support in accordance with the Credit Support Annex as amended by this provision. 296 ENERGY PRI CE RI SK
    • [Sometimes, to avoid dispute, parties to an ISDA Schedule will be specific as to what ‘Materially weaker’ actually means for the purposes of their Schedule agreement. For example, ‘If either ABC Small Trader Ltd or XYZ Bank Ltd fails to maintain a long-term, unsecured and unsubordinated debt rating of at least BBB– as determined by Stan- dard & Poor’s Ratings Group, or Baa3 as determined by Moody’s investors Service Inc. ’ These ratings are used because anything below these ratings is generally considered non-investment grade or perhaps even junk bond status. Terminology like this may be used in a Schedule between two large entities, perhaps two large banks. Enron almost certainly suffered as a result of OTC transactions being closed out when its rating was lowered, because others who had only put in their Schedule cover against default on a trade or borrowing of money had to wait while they saw Enron going down fast, but not defaulting on loans as banks tried to bail them out. Needless to say what defines a ‘Default’ has been under great scrutiny in the world of OTC derivatives since Enron.] A credit Event shall also occur if: (a) any person or entity acquires directly or indirectly the beneficial ownership of equity securities having the power to elect a majority of the board of directors of X, any Credit Support Provider of X or any applicable Specified Entity of X or otherwise acquires directly or indirectly the power to control their policy making decisions; or (b) X, any Credit Support Provider of X or any applicable Specified Entity of X enters into any agreement providing for any of the Credit Events specified in Section 5(b)(iv) of the Agreement or in clause (a) above. 5. The ‘Automatic Early Termination’ provision of Section 6(a) will apply to Party A and Party B. [Automatic Early Termination – impacts Events of Default on Bankruptcy. The effect of this provision is that all Transactions under the agreement are deemed terminated as of a date immediately before a winding-up order is presented against the Defaulting Party and immediately at the time bankruptcy proceedings are insti- tuted against the Defaulting party in all other cases. This means that the non- defaulting party can exercise its rights outside the insolvency proceedings. 80% of the time having this section included in a Schedule is a choice. There are some countries, though, where it is advisable to use this section 6(a) – a fully updated list of countries is available from ISDA (http://www.isda.org/).] 6. Payments on Early Termination. For the purpose of Section 6(e) of this Agreement: (i) The Market Quotation Method will apply. (ii) The Loss Method will apply. (iii) The Second Method will apply. [In the energy markets there are three choices on how to calculate the amount owed between the counterparts in the event that contracts are terminated early and payment is required: the Market Quotation Method, the Loss Method, and the Second Method. The Market Quotation Method is very popular as it is simple to use for plain vanilla instruments such as fixed for floating swaps, where there is typically good STEP BY STEP EXPLANATION 297
    • liquidity. It involves obtaining a series of usually three or four quotations from market makers (not brokers) for the replacement value of the derivatives to be terminated. If the derivatives to be terminated are more complex than plain vanilla swaps, you could encounter problems obtaining reasonable quotes from the market makers, in this circumstance loss could be used as a Fallback and put in the Schedule as a Fallback provision. Loss is the non-defaulting party’s ‘good faith’ determination of its losses and costs (minus its gains) in respect of replacing terminated transactions. Last but not least, the Second Method basically means the defaulting party has to pay anything it owes to the non-defaulting party, but if the non-defaulting party owes the defaulting party money it has no obligation to pay any amount to the defaulting party until it has received confirmation that all transactions have been terminated under this schedule, and that all obligations (matured or unmatured) of the defaulting party or any of its affiliates to the non-defaulting party or any affiliate of the non-defaulting party has been made.] 7. ‘Termination Currency’ means the currency selected by the party which is not the Defaulting Party or the Affected Party, as the case may be, or where there is more than one Affected Party the currency agreed by Party A and Party B. However, the Termination Currency shall be one of the currencies in which payments are required to be made in respect of Transactions. If the currency selected is not freely available, or where there are two Affected Parties and they cannot agree on a Termination Currency, the Termination Currency shall be United States Dollars. [Simply, the currency into which all derivatives transactions are converted to on close out and settlement. The above Section 7 illustrates very common wording in ISDA Schedules. It allows the non-defaulting to choose the currency. If the currency chosen for any reason is not freely available then the Schedule defaults to US dollars.] 8. ‘Additional Termination Event’ shall apply as follows: [Additional termination events include: Change of Control, Ratings Downgrade (like in the case of Enron), even Death or resignation of key staff (if you are dealing with a small entity or one controlled perhaps by key management), breach of agreements, sovereign event (maybe if you are dealing with a company that is based in a politically less stable region). This example Schedule shows Change of Ownership example wording and also wording for Ratings Downgrade.] Change of Ownership. Mega Corporation either directly or indirectly ceases to own directly or indirectly 51% of the issued share capital of ABC Small Traders Ltd carrying voting rights in ordinary circumstances in a general meeting of shareholders or a comparable meeting of ABC Small Trader Ltd or otherwise directly or indirectly ceases to control the board of directors of ABC Small Trader Ltd and or ABC Small Trader Ltd cease to be a fully consolidated subsidiary of Mega Corporation. Downgrade (i) S&P or Moody’s or both rate the long term, unsecured, unsubordinated debt obligations of ABC Small Trader Ltd or 298 ENERGY PRI CE RI SK
    • XYZ Bank Ltd at least three modifiers (a modifier being 1, 2, or 3 for Moody’s or plus, neutral, minus for S&P) lower than the highest rating which had previously applied (from the date of this agreement) to the long term unsecured, unsubordinated debt obligations of ABC Small Trader Ltd, or XYZ Bank Ltd. (ii) ABC Small Trader Ltd or XYZ Bank Ltd cease to be rated by both S&P and Moody’s. For the purposes of the foregoing Termination Event, the affected party shall be the party that was downgraded or ceased to be rated. [This is self explanatory: if the rating gets too badly affected than OTC derivatives contracts under this agreement can be terminated by the ‘Affected’ party.] PART 2 TAX REPRESENTATIONS [Tax representations are left over from the early years of OTC derivatives when there was even uncertainty in the USA as to whether a payer’s tax authority would levy a withholding tax on settlement payments made on OTC swaps transactions. The ISDA agreement covers both counterparts against any with-holding tax ever being required to be paid on any derivative settlements via Section 2(d) (i) (4) of the Master Agree- ment which makes it the responsibility of the payer (the company sending the payment) to ensure that the payee (the company receiving the payment) gets full payment. The payer must gross up the payment to the payee so that the payee receives, after deduction of the payer’s jurisdictional withholding tax, the full settle- ment required on the derivatives trade. I have only come across one such jurisdiction where there was a clear withholding tax issue for energy derivatives: Thailand. Any organisation entering into an ISDA agreement with a new counterpart should get a legal opinion on the country that they are going to be dealing through.] Payer Tax Representations 1. For the purpose of Section 3(e) of this Agreement, both parties make the following representation: It is not required by any applicable law, as modified by the practice of any relevant governmental revenue authority, of any Relevant Jurisdic- tion to make any deduction or withholding for or on account of any Tax from any payment (other than interest under Section 2(e), 6(d)(ii) or 6(e) of this Agreement) to be made by it to the other party under this Agreement. In making this representation, it may rely on: [Relevant jurisdiction in the ISDA Schedule refers to the payer’s home jurisdiction, where the office actually executing the trades is based, the jurisdiction where it executed the Agreement and also the jurisdiction from which it makes payments including settlement payments for any transactions under this agreement.] (i) the accuracy of any representation made by the other party pursuant to Section 3(f) of this Agreement; and (ii) the satisfaction of the agreement of the other party contained in Section 4(a)(i) or 4(a)(iii) and the accuracy and effectiveness of STEP BY STEP EXPLANATION 299
    • any document provided by the other party pursuant to Section 4(a)(i) or 4(a)(iii) of this Agreement; and (iii) the satisfaction of the agreement of the other party contained in Section 4(d). Provided that it shall not be a breach of this representation where reli- ance is placed on Clause (ii) and the other party does not deliver a form or document under Section 4(a)(iii) by reason of material prejudice to its legal or commercial position. [The Payer Tax representation actually does not include default interest payments or any interest that could be charged due to an early termination payment. This Payer Tax Representation section is very standard, and there are a few jurisdictions where ISDA may not have been tested and some where overseas payment and or tax regula- tions have been outpaced by the local adoption of derivatives instruments usage. If it does not appear in an ISDA Schedule you are being asked to agree to, query it!] Payee Tax Representations 2. For the purpose of Section 3(f), both parties make the following representation: Each payment received or to be received by it in connection with this Agreement relates to the regular business operations of the party (and not to an investment of the party). [This section is not always included because of the existence of many double tax trea- ties around the world which have income and interest provisions giving protection against withholding taxes.] OTHER REPRESENTATIONS 1. Each party represents and warrants to the other (which shall be deemed to be repeated by each party on each date on which a Transac- tion is entered into) that: (a) There has been no material adverse change in its financial condi- tion since the last day of the period covered by its most recently prepared audited financial statement and that ‘Accuracy of Spec- ified Information’ as provided for in Section 3(d) will apply to the financial information which a party is required to deliver to the other party under this Schedule. (b) It is entering into this Agreement and each Transaction as prin- cipal (and not as agent or in any other capacity, fiduciary or otherwise). 2. Each party will be deemed to represent to the other party on the date on which it enters into a Transaction that (absent a written agreement between the parties that expressly imposes affirmative obligations to the contrary for that Transaction): (a) Non-Reliance. It is acting for its own account, and it has made its own independent decisions to enter into that Transaction and as to whether that Transaction is appropriate or proper for it based 300 ENERGY PRI CE RI SK
    • upon its own judgment and upon advice from such advisers as it has deemed necessary. It is not relying on any communication (written or oral) of the other party as investment advice or as a recommendation to enter into that Transaction; it being under- stood that the information and explanations related to the terms and conditions of the Transaction shall not be considered invest- ment advice or a recommendation to enter into that Transaction. No communication (written or oral) received from the other party shall be deemed to be an assurance or guarantee as to the expected results of that Transaction. (b) Assessment and Understanding. It is capable of assessing the merits of and understanding (on its own behalf or through inde- pendent professional advice), and understands and accepts, the terms, conditions and risks of that Transaction. It is also capable of assuming, and assumes, the risks of that Transaction. (c) Status of Parties. The other party is not acting as a fiduciary for or an adviser to it in respect of that Transaction. 3. Absence of Litigation. Section 3(c) of the Agreement is hereby amended by limiting the definition of ‘Affiliate’ for the purposes of this represen- tation to such Affiliates, if any, as may be a Specified Entity for purposes of Section 5(a)(v). PART 3 DOCUMENTS TO BE DELIVERED For the purpose of Section 4(a)(i) and (ii) of this Agreement each party agrees to delivery of the following documents, as applicable: [Below is a standard list of documents often required by banks entering into an ISDA Agreement with a corporate entity before trading begins. Here it will also note what documents are exchanged after each derivatives trade/transaction. A certified copy of a board resolution authorising execution of the agreement is very important to get hold of, otherwise trade conducted may not be enforceable on one or both parties to the agreement. In practical terms, counterparts may say that it will take 3 months or more to get a Board resolution due to the infrequency of the Board of Directors meeting, but it is worth waiting for.] Party required to deliver Document Form/Document/ Certificate Date by which to be delivered Covered by Section 3(d) Representation Party A A certified copy of a board resolution authorising the execu- tion, delivery and performance of this On or before execution hereof and if any change in authority has Yes STEP BY STEP EXPLANATION 301
    • Agreement and each Confirmation executed hereunder together with the names, titles and specimen signa- tures of the persons entitled to execute this Agreement and each Confirmation executed hereunder. occurred prior thereto, on or before the execution of each Confirmation. Party A In respect of each transaction an accepted Confirmation signed by an author- ised signatory. Within 24 hours of receipt of the relevant Confir- mation from Party B. Yes Party A A capacity certificate in the form attached to this Agreement as Appendix A. On or before execution hereof. Yes PART 4 MISCELLANEOUS [Don’t be fooled by the term ‘Miscellaneous’; it is still important. In Part 4 parties set out their contact details for notices, mainly for admin purposes.] 1. Address for Notices. For the purpose of Section 12(a): Address for notices or communications to Party A: ABC Small Trader Address: Canary Wharf, London Attention: United Kingdom Telex No: 12345 Answerback: ABCSTrader Facsimile No: +44 123 456789 Telephone No: Address for notices or communications to Party B: Address: XYZ Bank Limited, Bank of England Road, London, United Kingdom Attention: Swaps Back Office (Confirmations only) Mr N. Leeson (All other notices or communications) Telex No: 98238 XYZ Facsimile No: +44 207 681 1201 Telephone No: +44 207 12345678 2. Process Agent. For the purpose of Section 13(c): [A process agent will usually need to be appointed if a party is not incorporated in England, if the ISDA is under English Law (which is the preferred industry norm for the majority of OTC energy contracts outside the USA) or not incorporated in New York for a New York Law-based agreement. So if an organisation does not have an office or is 302 ENERGY PRI CE RI SK
    • not incorporated in these jurisdictions, it will need to nominate an organisation or lawyer in London or New York to act on its behalf. A process agent receives writs or termination notices or other legal documentation associated with the ISDA agreement.] Party A appoints as its Process Agent: Party B appoints as its Process Agent: Not applicable [Not applicable for Party B indicated that XYZ Bank Ltd is incorporated in England (as this example is under English law), or it would indicate that it was incorporated under New York law if this contract was under New York Law. XYZ Bank can accept legal notices directly it does need a Process Agent.] 3. Offices. The provision of Section 10 (a) will not apply. [Section 10a provides that if one of the companies signing this Schedule enters into a derivatives trade through one of its branches, its obligations will be the same as if it had executed the trade through its Head Office.] 4. Multibranch Party. For the purpose of Section 10(c): Party A is not a Multibranch Party. Party B is not a Multibranch Party. [If Section 10c did apply then it would mean that both companies signing this Schedule were effectively providing an implied payment guarantee for any derivatives trades that their branch offices entered into. The benefit of Multibranch is that an organisation, via one ISDA agreement with its Head Office, can permit all is branches to trade with the other counterpart to this ISDA Schedule. It would look like this: ‘(d) Multibranch Party. For the purposes of Section 10 (c) of this agreement: Party A is a Multibranch and may act through the following Offices: Tokyo, Singapore, Frank- furt, London, New York, Houston.’ Party B can also put down whether it wants to use Multibranch or not.] 5. Calculation Agent. The Calculation Agent is Party B, unless otherwise specified in a Confirmation in relation to the relevant Transaction. [This is the counterpart in the agreement that has to determine the floating rate values and calculate payments. It is usual for a financial institutional trader like a bank to insist that it is the Calculation Agent where the agreement is with a corporate hedger or non-financial institution trader. Whoever is not the Calculation Agent will always have to double check the Calculation Agent’s figures and can dispute any big differences. Most of the time with Platts price-related energy derivatives, any differ- ence in calculations often arises from the Calculation Agent simply not picking up on a change of the Platts price for a particular day, as the correction of the price may have been published much later in the contract month. If two counterparts cannot agree on who will be the calculation agent, they can agree to both be calculation agents, i.e. co-calculation agents. The Calculation Agent also has to establish whether a ‘Market Disruption Event’ has occurred and remedy it (see Section 5 later on in this example Schedule).] STEP BY STEP EXPLANATION 303
    • 6. Credit Support Document. Details of any Credit Support Document: In respect of Party A: Parental Guarantee Dated 10th December 2002 In respect of Party B: Not applicable [This is where any form of unconditional and irrevocable credit support against deriva- tives transactions under this ISDA Schedule is specified. For example, in OTC Energy Swaps, the majority of companies utilise ‘irrevocable standby letters of credit (LCs)’ from a bank, a ‘bank guarantee’ or (less often) Parental Guarantees from their parent holding company, if a subsidiary. In this example Party A which is ABC Small Trader Ltd is offering a parental guarantee from its Parent ‘Mega Corporation’.] 7. Credit Support Provider Credit Support Provider means in relation to Party A: Mega Corporation [Mega Corporation is the parent company offering the Parental Guarantee noted in paragraph 6 above so it is named here.] Credit Support Provider means in relation to Party B: Not applicable 8. Governing Law. This Agreement will be governed by and construed in accordance with the laws of England. [This example is showing English law – as mentioned earlier in the chapter, the two key laws and jurisdictions used are English and New York State in the USA. Any other jurisdictions should be avoided unless an organisation is prepared to get legal advice on the effect that the new jurisdiction’s law will not have an adverse impact on ISDA provisions and the Master Agreement. ISDA contracts are already well tested under English and New York State law. For reference, if this example