energy derivatives - crude oil and gas
TRANSCRIPT
Prepared by The Financial Markets UnitSupervision and Regulation
PRODUCT SUMMARY
E N E R G Y D E R I V A T I V E S
Crude Oil and Natural Gas
Prepared by:Karen McCannMary NordströmFinancial Markets UnitDecember 1995
PRODUCT SUMMARY
E N E R G Y D E R I V A T I V E S
Crude Oil and Natural Gas
PRODUCT SUMMARIES
Product summaries are produced by the Financial Markets Unit of theSupervision and Regulation Department of the Federal Reserve Bank ofChicago. Product summaries are published periodically as events warrantand are intended to further examiner understanding of the functions andrisks of various financial markets products relevant to the banking indus-try. While not fully exhaustive of all the issues involved, the summariesprovide examiners background information in a readily accessible formand serve as a foundation for any further research into a particular prod-uct or issue. Any opinions expressed are the authors’ alone and do notnecessarily reflect the views of the Federal Reserve Bank of Chicago orthe Federal Reserve System.
Should the reader have any questions, comments, criticisms, or sugges-tions for future Product Summary topics, please feel free to call any of themembers of the Financial Markets Unit listed below.
FINANCIAL MARKETS UNIT
Joseph Cilia (312) 322-2368
Adrian D’Silva (312) 322-5904
TABLE OF CONTENTS
Introduction ......................................................................................................................................................1
Banks’ Involvement in Energy Markets ..............................................................................................................2
Major Energy Derivative Products .....................................................................................................................2
The Over-the-Counter Energy Markets.......................................................................................................3
Average Price Options.............................................................................................................................4
Energy Swaps ..........................................................................................................................................4
The Exchange-Traded Markets ....................................................................................................................7
Domestic Crude Oil................................................................................................................................7
Natural Gas .............................................................................................................................................8
Electricity ...............................................................................................................................................8
The Term Structure of Energy Prices.................................................................................................................9
Contango/Backwardation ............................................................................................................................9
Convenience Yield ......................................................................................................................................9
Behavior of Oil Price Curves .....................................................................................................................10
Risks Associated with Energy Portfolios...........................................................................................................11
Basis Risk ..................................................................................................................................................12
Crack Spreads........................................................................................................................................12
Volatility ....................................................................................................................................................13
Stack and Roll ...........................................................................................................................................14
Examiner Guidance .........................................................................................................................................15
Appendix A.....................................................................................................................................................16
The Crude Oil Market...............................................................................................................................16
IPE Crude and the International Market................................................................................................17
OPEC...................................................................................................................................................17
The Natural Gas Market ............................................................................................................................18
Market Structure ...................................................................................................................................18
Contracting ...........................................................................................................................................19
References.......................................................................................................................................................21
1
INTRODUCTION
When the price and availability of a class of commodities affect individuals, businesses and governments as signifi-cantly as energy products do, financial hedging, managing and speculating become attractive to a broad spectrum ofplayers. Consequently, the energy markets are actively traded by individuals and institutions who never have anyintention of “taking delivery” of a physical barrel of crude oil or a million British thermal units of natural gas. In1994 we learned a great deal about how an uncertain interest rate environment can give rise to wild fluctuations inthe value of financial instruments pegged to market rates of interest; the factors which drive volatility in energy mar-kets are more complex — weather, labor strikes, political events, inflation and pipeline logistics are all capable ofaffecting the markets. Without an understanding of these factors and the unique concerns which they raise forenergy market participants, it is easy to misestimate the risk profile of an energy products portfolio.
While it is not feasible to describe every important nuance of the energy markets in a product of this scope, it isappropriate to describe the markets and identify the risks and special concerns which attach themselves to energyproducts. With a focus on natural gas and crude oil, this product summary will give examiners and other interestedparties a significant foundation from which further analysis can be directed.
2
Banks’ Involvement in Energy Markets
Unlike the more mature market for interest rate derivatives, recent deregulation of the energy markets has spawnedtremendous growth of tradeable energy futures and other derivative products. The modern oil markets — spot,forwards, futures, and other derivatives — have evolved only over the past 20 years1 and free markets for natural gasare less than 10 years old.
Commercial banks are relatively small players in the energy markets. Estimates are that they account for roughly 5-10% of trading activity in the domestic energy sector. However, the role they play as intermediaries betweenproducers and users of oil and gas products serves as an important niche for them, and for market participants as well.Banks’ role in applying tested risk management techniques and market-making skills has helped to increase liquid-ity in these markets. Additionally, their ability to transform risks as financial intermediaries has enabled entities to hedge attendant exposures, eg, credit risk, which are a component of energy transactions though not directlyrelated to the price of energy.
Banks’ participation, which is essentially limited to the larger, money center banks, stems primarily from meetingthe needs of customers with oil-contingent revenue streams. A presence in the energy markets also provides bankswith a “strategic diversification” away from more traditional banking exposures, ie, interest rates and foreignexchange.2 Other factors which may influence a bank’s decision to keep an active energy portfolio include: enhanc-ing their product line and strengthening the credit quality of a borrower, thereby providing the customer withgreater access to funds.
The relative maturity of the interest rate derivative markets in relation to the energy derivative markets suggest thatgrowth and innovation in this sector may have significant potential. In addition, more sophisticated banks’ tradingrooms — whose profits are reliant on volatility — may be more attracted to the higher volatility inherent in energyproducts during times of relative calm in financial markets. The growing focus on corporate risk management acrossindustries may also serve to increase the risk management activities of end-users and producers, contributing togrowth in this sector and a greater role for banks’ intermediary activities.
Major Energy Derivative Products
Similar to the interest rate markets, energy instruments and derivatives are actively traded in the spot (physical),exchange, and over-the-counter (OTC) markets. An understanding of the market structure for both crude oil andnatural gas enhances comprehension of the risks attendant to these products. In addition, several OTC instrumentsare structured to reflect market-specific characteristics. For interested readers, specific information on the crude oiland natural gas markets is included in this document as Appendix A. However, this background information is notcritical for obtaining a basic knowledge of the types of products discussed in this section which are most commonlyfound in banks’ energy portfolios.
Though financial markets have seen explosive growth in relatively exotic structures, energy products continue toremain very plain vanilla. This is due, in part, to the motivation of the major market participants who tend to bemore bona fide hedgers than speculators on the future trend of energy prices. Speculators in financial markets havedemonstrated a willingness to assume significant market risk in return for potential above-market returns. However,energy markets — as mentioned in the introduction to this paper — tend to react materially to disparate factors,often without warning. This uncertainty is reflected in their higher average volatility relative to many financialproducts.3 Thus, the temptation to speculate and take risk is less pronounced than in the (moderately) morepredictable financial sector.
Energy producers have a genuine need to hedge their output, protecting themselves against falling prices, while endusers have a genuine need to hedge against price increases for their relatively price-inelastic purchases of oil and gasproducts. Generally speaking, banks are not permitted to engage in the activity of buying and selling energy prod-ucts; this means they are essentially uninvolved in the physical energy markets. However, a subset of large banks areactive in both the OTC and exchange-traded derivative markets.
1Barnaud, Frédéric and Jean Dabouineau, “The Oil Market,” Managing Energy Price Risk, p. 169.
2(Barnaud and Dabouineau 169)
3Volatility is discussed in greater detail in the section entitled Risks.
3
The Over-the-Counter Energy Markets
OTC energy options and swaps are unique in that essentially all of them are average price (also known as Asian)options. These have been popular for many years and are considered very plain vanilla in the industry. More exoticoptions, such as barriers, are extremely rare in the energy sector. Greater detail on average price options follows inthe next sub-section.
The OTC energy market is not nearly as price transparent as, for example, the OTC foreign exchange market.Despite this, corporate end-users and producers tend to prefer the OTC markets since basis4 issues are fewer andproducts can be structured to more closely replicate their cash market activities. Barnaud and Dabouineau contendthat the OTC energy markets are characterized by “very poor visibility” and that transactions are often private andconfidential.5 Thus, care in interpreting any pricing “information” is required, particularly for smaller players, suchas banks, who may not be active in the physical markets.
In order to allay risk, many banks attempt to deal only in very liquid markets or on a back to back (fully offset) basis.Liquidity concerns have prevented banks from offering an expansive energy product range. Ample liquidity doesexist, however, in many tenors of OTC average price crude and natural gas products. Because of the differences incontract design between these instruments and exchange-traded instruments (which are not average price) banks’hedging decisions — either OTC or back to back — are crucial.
Average Price Options6
Average price options comprise virtually all OTC energy options. Unlike standard options whose terminal value isthe greater of zero or the difference between the strike price and the settlement price, average price options expirebased on the greater of zero or the difference between the strike price and the average price traded during the life of the option (or stated averaging interval). This structure places them in the category of path-dependentoptions; the option’s payoff depends on the price path followed by the underlying commodity prior to the option’sexpiration.
The applicability of average price options to the energy markets is high since firms that buy gas and oil typically donot make a single, periodic purchase. Rather, their energy needs are fairly steady, causing them to be in the marketson a regular basis. Options struck at one price will not capture this “smoothing” effect, and thus will not offeroptimal protection in line with the type of risk being hedged.
Averaging for options on crude oil is generally done over the course of a calendar month. The relatively long lengthof this averaging period means that the average price begins to “set” with the passage of time so that days that falllater in the month have a less pronounced effect on the average than earlier days. This effect is also observable in thegamma statistic. The gamma of an average price option is nearly identical to that of a standard option on the firstday of the reference period. However, as the option approaches expiration and the influence of additional observa-tions diminishes, the gamma declines to below that of a standard option.
The volatility of an average price option is also less than that of a standard option. For example, an $18 call on crudeoil which settled at $22 but traded at an average price of $20 during the averaging period, would be worth $2 atexpiration ($20-$18), not $4 ($22-$18). This essentially translates into lower volatility; thus, average price optionstrade at a lower premium (ie, they are cheaper) than conventional options. The smaller gamma, in addition to themore stable volatility, differentiate these options from their standard option counterparts.
The structure of the natural gas market dictates a different approach to setting average prices for natural gas options.Most contracts for next month delivery are finalized during bid week7. Thus, most natural gas average price optionssettle to the average of the last three days’ New York Mercantile Exchange (NYMEX) futures contract settlementprice during that week. It stands to reason then that average price natural gas options exhibit less volatility andgamma stability than do average price crude oil options. Settlement prices for the last three days are taken from thelast two minutes of trading on days t-2 and t-1 and from the final half hour on settlement day (day t). This unique
4Basis is discussed in greater detail in the section entitled Risks.
5(Barnaud and Dabouineau 176)
6The following discussion assumes knowledge on the part of the reader of option fundamentals. Readers who would like further explanation of optioncharacteristics are referred to the product summary entitled Options, published in November 1994.
7A more thorough explanation of bid week is included in Appendix A under the heading The Natural Gas Market.
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characteristic of the natural gas market highlights another feature of average price options; they reduce the incentivesto manipulate the underlying price at expiration.8
Averaging is usually done via an arithmetic average though a weighted average can also be used. The difficultywhich this poses is that the options cannot be valued using a closed-form pricing solution. The basic Black-Scholesoption pricing formula is not applicable since an average of prices will not be lognormally distributed even thoughthe individual component prices will.9 Consequently, models used to price these options consist of numericalsolutions or approximations. For example, Monte Carlo models are often used to value average price options.
Popular option strategies in the energy sector include caps (long calls), floors (long puts) and collars (long a higherstruck call and long a lower struck put). For a producer who is long the physical commodity, purchase of an aver-age price floor struck at $18 affords that producer protection against average oil prices dropping below $18. For anend-user who is exposed to the risk of rising prices (equivalent to having a short position in oil) purchase of an oilcap sets a limit on the price to be paid to secure the commodity. A zero-cost collar is yet another strategy which may be employed by producers. By selling a cap and buying a floor with the proceeds, producers can lock in a trad-ing range above and below which price fluctuations will not affect them. They effect a trade-off between the possibility of upward price appreciation and the comfort of protection against price deterioration.
Energy Swaps
The birth of the market for energy swaps occurred through the initiative of Chase Manhattan Bank in October1986.10 Estimates of OTC dealer activity are currently believed to be approximately 300 to 400 million barrels of oilequivalent traded per day. Of this, approximately 75% of all OTC transactions are swaps, 20% are options and 5%are structured transactions.11 Exchange trading accounts for roughly another 300 million oil barrel equivalents.Thus, the entire energy complex trades close to 10 times daily world oil production on a daily basis.
Swaps are a natural product for the energy markets. For example, producers are subject to fluctuating revenue basedon the price of oil over which they exert little control. End-users are subject to the risk of rising energy prices forneeds which are often price inelastic. The presence of natural buyers and sellers creates a foundation for an activeswap market with a niche for financial intermediaries. Further, the addition of new long-term crude oil futures tothe NYMEX energy complex has made swaps of medium and longer terms easier to hedge without having to besubject to a “stack and roll” strategy.12 The NYMEX has exempted swap traders from position limits, furthercontributing to the growing liquidity of the OTC market.13
In a basic “fixed for floating” swap, the underlying is some fixed amount of a commodity on which payments arebased but which never physically changes hands. Producers are natural swap sellers (receivers of fixed) while end-users are natural buyers (payers of fixed). Intermediaries are important for ensuring confidentiality, assumingcredit risk, and being able to absorb (and hedge) residual market risk which may arise from contracts with slightlydifferent terms.
The floating prices of nearly all crude oil and a large portion of natural gas swaps are average prices. Often these areindexed to an average of NYMEX prices over a reference period. Alternatively, the swap may be indexed to anaverage of prices listed in trade publications such as Platt’s Oilgram Price Report or Inside FERC. Although OTC dealscan be customized in any way, the reference period for most crude oil swaps is the entire calendar month. For naturalgas, the reference period is often the last three trading days of the NYMEX contract.
Two examples follow. The first is an example of a simple fixed for floating swap with monthly settlement and the second illustrates the same swap, but with settlement based on a monthly average price instead of one day’s“floating” price.
8Trabia, Xavier, Financial Oil Derivatives: from options to oil warrants and synthetic oilfields, Oxford Institute for Energy Studies, 1992, p. 91
9 Kaminski, Vincent and Stinson Gibner, “Exotic Options,” Managing Energy Price Risk, p. 125.
10Falloon, William, “A Market is Born,” Managing Energy Price Risk, p. 13.
11(Falloon 17)
12Stack and roll is discussed in the section on Risks.
13Davey, Emma, “Pulling it all together,” Energy 1995 (A supplement to Futures and Options World), p. 4.
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Exhibit 1 details a simple fixed for floating NYMEX-based crude oil swap. In this case, the floating price is deemedto be the prevailing NYMEX settlement price on the swap settlement date. For ease of illustration, assume a three-month swap for three million barrels of oil (1 million each month) which settles monthly on the same date as theexpiration of the NYMEX futures contracts.
Exhibit 1
Interest rates are used in combination with the number of calendar days in the settlement period to arrive at a dis-count factor. For example, in period 1, an annual interest rate of 4.54% for 28 days produces a discount factor of.9965 as per the following: 1/[1+(.0454x(28/365))]. The fixed price of the swap, $17.7734, is derived by multiply-ing each futures price by the appropriate discount factor and dividing by the sum of the three discount factors.14 Thehedge is calculated by multiplying the discount factor by the number of barrels to be hedged each month (givingthe present value — PV — of the barrels of oil) and then dividing by 1,000 to arrive at the appropriate number offutures contracts. This will have the effect of introducing rounding errors which are difficult to circumvent sincefutures cannot be bought and sold in fractional amounts.
Assume that a bank had entered into the above swap with an oil producing firm. The bank would agree to makefixed payments to the producer and receive floating. To hedge this swap, the bank has two alternatives; it can eitherbe hedged OTC or with NYMEX futures contracts. Liquidity on the NYMEX becomes a definite concern formaturities past one year; however for three months a NYMEX hedge can be easily constructed.
In order to offset their exposure to floating oil prices (akin to being long a futures contract) the bank would sell thequantity of futures contracts in each month designated in the “hedge” column. If the actual floating prices realizedwere $18.11, $18.04 and $17.63, the hedge would perform as illustrated in Exhibit 2.
Fixed for Floating Swap
Amount (barrels per month) 1,000,000
Start Date Nov. 21, 1995
Term (months) 3
Swap Price ($/barrel) $17.7734
Settle Calendar Futures Interest Discount Barrels/ FuturesPeriod Date Days Contract Rate Factor Month Price Barrels PV Hedge
1 Dec 19 28 Jan 1996 4.54% 0.9965 1,000,000 $17.97 996,529.35 996.53
2 Jan 22 33 Feb 1996 5.27% 0.9953 1,000,000 $17.75 995,257.94 995.26
3 Feb 20 28 March 1996 5.30% 0.9960 1,000,000 $17.60 995,950.71 995.95
2,987,737.99
14This number can be very closely approximated in this example by taking the simple arithmetic average of the three futures prices. However, the size ofthe swap requires greater precision.
6
Exhibit 2
As mentioned above, rounding errors create the difference between the bank’s swap position and its hedge($459,800 - $458,018.10 = $1,781.90) but the difference is negligible in terms of the total size of the trade.
Had this swap been based on the average of daily settlement prices rather than the settlement price on the expira-tion date, the hedge would be constructed differently. It is possible to use NYMEX futures contracts to hedge anaverage price swap, but the hedge requires more vigilance since futures contracts need to be repurchased each day.This swap is illustrated in Exhibit 3.
Exhibit 3
For an average price swap, determining the number of business (trading) days in the settlement period is important.The bank must average their price exposure evenly over each of those business days. The swap in the example has 61 business days, therefore the number of futures contracts to be repurchased each day would be:[3,000,000÷1,000]÷ 61= 49.18. (Again, rounding errors will be a factor.) To hedge this swap with exchange futurescontracts, the bank would sell the number of futures contracts shown for each period (49.18 x number of businessdays) and buy back 49 each business day. This procedure gives them the appropriate exposure to the average contractprice against which the swap will settle.15
Hedge Performance
Futures Producer’s Bank’s SwapDate Price Position Position Bank’s Hedge
Dec 19 $18.11 ($336,700.00) $336,600.00 ($139,514.20)
Jan 22 $18.04 ($266,700.00) $266,600.00 ($288,625.40)
Feb 20 $17.63 $143,300.00 ($143,400.00) (29,878.50)
$459,800.00 (458,018.10)
Average Price Swap
Amount (barrels) 3,000,000
Number of business days 61
Number of futures per day 49.18
Start Settle Business FuturePeriod Date Date Days Contracts
1 Nov 17 Dec 19 20 983.6
2 Dec 20 Jan 22 21 1032.78
3 Jan 23 Feb 20 20 983.6
61 2999.98
15The preceding discussion draws heavily on material presented in: Das, Satyajit, Swap and Derivative Financing, Probus Publishing, Chicago, 1993.
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Often, average price swaps will settle against a reference index other than NYMEX. Valuing these swaps using onlyNYMEX prices is likely to lead to mispriced deals and suboptimal hedges. For example, a natural gas swap may bereferenced to an average of pipeline prices on three forward dates as posted in a trade publication, such as Gas Daily.Because the basis between the NYMEX and the reference pricing point will not be constant, it would be necessaryto price the swap using the specific pipeline price, not the NYMEX. However, Gas Daily does not list forwardprices. A bank valuing a referenced index swap will look to the basis market to price the swap. There is a liquid mar-ket that trades forward basis prices. From these prices, a bank could value the swap by backing out the referencedindex forward price.
In the natural gas OTC market, basis swaps are very common. These are swaps used to hedge fluctuations in thespread between NYMEX natural gas futures (based on prices at the Henry Hub in Louisiana) and gas prices atdistant delivery points.16 With respect to certain pipelines, active basis markets exist, allowing banks to participate inthese swaps and hedge them OTC.
The Exchange-Traded Markets
Domestic Crude Oil
The NYMEX is the only exchange in North America on which crude oil futures trade. It is the world’s largestphysical commodity futures exchange, accounting for 80% of the world’s exchange-based energy trading.17 (Crudeoil trading on other exchanges is discussed in Appendix A.) Futures on light, sweet (low sulfur) crude oil began trad-ing on the NYMEX in March of 1983, and options were introduced in November of 1986. Each futures contractrepresents 1,000 barrels of crude oil and a point in price is worth $1,000. In other words, one contract purchased ata price of $17.75 would control $17,750 of crude oil. Since the time of its introduction, the contract has seen steadyincreases in volume and now trades roughly 100,000 contracts (or 100 million barrels) per day. This is significantgiven that it exceeds total daily world wide oil output and demand which is currently about 70 million barrels per day.
In the US, WTI crude serves as the benchmark crude — the reference for most crude oil transactions. WTI is anacronym for West Texas Intermediate, a grade of crude deliverable against the NYMEX crude oil futures contract.Though ten grades of crude are deliverable against the contract (six domestic and four foreign) the futures contract is commonly referred to as WTI crude oil. The US market for crude oil is the largest in the world. Thoughthe US is also one of the top three oil producing countries, imports still account for slightly more than half ofdomestic consumption.18 Transportation of crude oil in the United States is based on a pipeline system which makesit unique in terms of world crude which is largely transported by water. Pipeline disruptions are thus a major factorcontributing to volatility of the WTI contract.
For purposes of hedging long-dated (more than one year) crude oil, the OTC market is superior in terms ofliquidity. In addition, though the NYMEX has obtained the approval of the Commodity Futures TradingCommission (CFTC) to list crude futures out as far as seven years, the longest-dated futures contract available as ofthis writing is four years out, and open interest (hence, liquidity) tapers off dramatically after six months and is non-existent in certain longer-dated contracts. In the OTC market, however, it is not uncommon for a deal to bestruck for 10 and even 15 years in the future.
NYMEX crude futures are listed for thirty consecutive months, plus certain long-dated futures contracts out to fouryears as mentioned above. Options on crude are listed for twelve consecutive months with certain long-datedoptions out to three years. The contract is based on delivery at the pipeline in Cushing, Oklahoma, though mostcontracts are closed before expiration and less than 1% actually result in delivery.
In June of 1993, the NYMEX launched NYMEX ACCESSSM, an electronic trading system which allows activetrading in crude oil for more than 20 hours per day. Regular pit (open outcry) trading takes place from 9:45 am to3:10 pm EST Monday through Friday and electronic trading is available from 4:00 pm to 8:00 am the following dayMonday through Thursday and from 7:00 pm (Sunday) to 8:00 am on Monday.
16“Commodities,” 1993 Year in Review, Risk, January 1994, p. 25.
17Machida-Spears, Joanne, “Crude Links,” Energy (A supplement to Futures and Options World, 1995) p. 11.
18“Up with crude,” Grant’s Interest Rate Observer, March 31, 1995.
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Natural Gas
The NYMEX natural gas contract (the first natural gas futures contract in the world) began trading on April 3, 1990and options were added on October 2, 1992. Options expire one day prior to the futures contract in order to facil-itate convergence of the exchange price to the cash market price during bid week. The contract is the fastest grow-ing in the NYMEX’s 121-year history.19 It is based on delivery at the Henry Hub, connection point for 12 pipelines,in Erath, Louisiana. The intricate pipeline transportation system in the US gives rise to numerous basis issues forusers of natural gas who require delivery at a location not directly served by those pipelines and will be more fullydiscussed later in this product summary.
Natural gas futures trades are not as voluminous as crude oil, with an average of about 20,000 contracts traded eachday. Futures are listed for eighteen consecutive months (though the exchange has received CFTC approval to listcontracts of 21, 24 and 36 month maturities), while options contracts trade for twelve consecutive months. Naturalgas futures trade on the NYMEX’s ACCESSSM electronic trading system from 4 pm to 7 pm Mondays throughThursdays. There is little need for longer market hours since, unlike crude oil, there is no active international marketwhich serves as a good proxy for the US contract.
On August 1, 1995, the Kansas City Board of Trade (KCBT) launched a Western Natural Gas Futures contractbased on delivery at the Permian/Waha Hub in west Texas. The hub connects ten pipelines and facilitates deliveryto California and the Midcontinent. The logic behind introducing a futures contract with a different delivery pointthan the NYMEX contract was to offer hedgers the ability to hedge against a different geographic location, thuslessening the basis risk of a hedged trade. For instance, it would not be unusual for the East Coast to experience asevere winter while the West Coast was balmy. Thus, higher prices for gas would prevail in the East while prices inthe West may stay steady or even fall. A West Coast producer who was hedged to the NYMEX might see that hedgequickly deteriorate as the basis between the NYMEX futures contract and spot West Coast prices widened con-siderably. The KCBT contract was designed to give hedgers an alternative to hedging only to an East Coast location. It is too soon to gauge the success of this contract. Since inception, daily volume has only been about 500 contracts/day in the front month. However, the basis between the two contracts is not stable, suggesting thattwo contracts may ultimately prevail in the US market. (The NYMEX is presently gearing up to list a competingcontract.) Exhibit 4 plots the spread between the NYMEX and KCBT natural gas contracts for the period 9/25/95through 11/22/95 (NYMEX minus KCBT in cents).
Exhibit 4
Electricity
Futures in electricity promise to be the next sector of the energy marketplace to be traded on an exchange. As wastrue of both the crude oil and the natural gas markets, liberalization of the underlying market is proving to be a slowprocess and plans for trading the futures have been slowed by regulatory issues. The NYMEX was originally sched-uled to begin trading electricity futures in 1995, but that start date has been postponed until sometime in 1996. The
$0.10
$0.12
$0.14
$0.16
$0.18
$0.20
Sep 25 Oct 4 Oct 13 Oct 24 Nov 2 Nov 13 Nov 22
NYMEX vs. KCBT Natural GasSep. 25 through Nov 22, 1995
19New York Mercantile Exchange Annual Report, 1993-1994 p. 11.
9
cash market will need to be further developed before a futures contract can be successfully launched. While theCalifornia Public Utilities Commission expects to open its market for retail competition at the beginning of 1996,new rules put forth by the Federal Energy Regulatory Commission may slow progress in this sector.20
The Term Structure of Energy Prices
Contango/Backwardation
Similar to the term structure of interest rates, commodity price curves exist which convey information about futureexpectations. In addition they reflect the prevailing yield curve (cost of carry) and storage costs.
Energy prices are said to be in contango when the forward prices are greater than spot prices; prices are said to be inbackwardation when spot prices exceed forward prices. The term structure has little forecasting power, however.Forward prices have not been proven to be accurate forecasts of future spot prices.
The future price of an energy product is determined by many factors. The no-arbitrage, cost and carry modelpredicts that futures prices will differ from spot prices by the storage and financing costs relevant to inventory. Thespot price is the only source of uncertainty in the basic model. Carry is the sum of the riskless interest rate and themarginal cost of storage. Because carry is always positive, the cost and carry model predicts that energy prices willalways be in contango.
Empirical evidence suggests, however, that the term structure of energy is not fully explained by carry. The termstructure of energy prices is not always in contango. Oil and natural gas markets often become backwardated due toexternal factors or supply concerns. Further, the market rarely shows full carrying charges. In other words, futuresprices as predicted by a cost of carry model generally exceed those observed in the market, even when prices are incontango.
Several theories have been advanced to explain why market prices are less than full carry. Keynes introduced thetheory of normal backwardation. He proposed that for most commodities there are natural hedgers who desire to shedrisk. In the oil markets, producers would act as net sellers of forward contracts in order to insulate themselves fromthe potential for future adverse price movements. They require the presence of speculators in the market, willing toassume the long side of their hedges, and must entice them with an expectation of profit. The speculators will onlybe willing to buy forward if the forward price is below the expected spot price to give them an expected profit ofthe difference between prices at the two tenors. Their expected profit is equivalent to the producers’ expected loss,but the producers are willing to accept the expected loss (pay a positive insurance premium) to guard against unfore-seen price moments.21 This theory is fundamentally flawed, largely because it ignores the hedging activities of end-users. However, it does provide a framework for describing price curve behavior which reflects the volatility of prices, the degree of risk aversion of producers and the cost of trading and inventories.
As we know, commodity markets are not always in contango or backwardation. They shift between the two typesof behavior as a result of many forces supplemental to carrying costs and hedging activity. The concept of convenienceyield is another element that sheds important light on the behavior of commodity price curves.
Convenience Yield
In the energy markets, oil and natural gas consumers are characterized by relatively inelastic demand. End users,refiners, and distribution companies cannot do business without a supply of oil and gas. Because they cannot afford to be without oil and gas, these firms hold energy inventories. The financial benefit that accrues to holdersof inventories is called convenience yield.
The value of the convenience yield influences the term structure of energy prices. One theory of backwardationholds that when excess supplies are available, inventories increase and convenience yield declines. Low convenienceyields push the market toward full carry — forward prices in steep contango. When gas and oil supplies are short,inventories are drained from the market and end-users are willing to pay more today for an uninterrupted supply ofenergy. As convenience yield increases, the market can swing into backwardation.
20(Davey 5)
21Bodi, Zvi, Alex Kane and Alan J. Marcus, Investments, p. 649.
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Behavior of Oil Price Curves
Contango markets are economically limited by full carry. Any price level above this limit would introduce anarbitrage opportunity. If the forward price exceeds the spot price by more than full carry, an arbitrageur could buythe spot commodity, store it, and sell it forward at the futures price for a riskless profit. Because a contango marketcannot steepen to arbitrarily high levels, the risk of a long basis position (long cash and short futures) is limited. Ingeneral, the closer the market is to full carry, the less risky the position.
Energy markets shift between contango and backwardation, often with little or no warning. The term structure ofcrude oil given by the NYMEX futures prices for a six-month period in mid-1994 is depicted in Exhibit 5.(Contract months are listed on the X axis.)
Exhibit 5
During the second quarter of 1994, the market shifted from a positive carry market (contango) to an inverted (backwardated) market. The backwardation was precipitated by strong economic growth and concerns over a supplydisruption from producers including Nigeria. The oil market remained inverted only until August 1994. While oilmarkets can remain in contango or backwardation for protracted periods, this isn’t always the case. Studies haveshown that strings of either structure are almost impossible to predict.22
The term structure of natural gas prices can be greatly affected by seasonal factors. During winter months, whendemand for natural gas is high, markets may have a tendency to backwardate. During warm weather months, gasdemand usually decreases. Holding all other factors constant, however, the market generally tends towards contango.The term structure of natural gas futures prices for six months in mid-1995 is shown in Exhibit 6. (Again, contractmonths are listed on the X axis.)
$14.00
$15.00
$16.00
$17.00
$18.00
$19.00
Apr.94 Aug.94 Dec.94 Apr.95 Aug.95 Jun.96
Mar 94 Crude
$16.00
$16.50
$17.00
$17.50
$18.00
$18.50
May.94 Sep.94 Jan.95 May.95 Sep.95 Jun.96
Apr 94 Crude
$16.80
$17.00
$17.20
$17.40
$17.60
$17.80
Jul.94 Nov.94 Mar.95 Jul.95 Nov.95 Dec.96
May 94 Crude
$18.00
$18.50
$19.00
$19.50
$20.00
Jul.94 Nov.94 Mar.95 Jul.95 Nov.95 Dec.96
June 94 Crude
$18.00
$18.50
$19.00
$19.50
$20.00
Aug.94 Dec.94 Apr.95 Aug.95 Dec.95 Dec.96
July 94 Crude
$17.80
$18.00
$18.20
$18.40
$18.60
$18.80
$19.00
Sep.94 Jan.95 May.95 Sep.95 Jan.96 Dec.96
Aug 94 Crude
22Edwards, Franklin R. and Michael S. Canter, “The Collapse of Metallgesellschaft: Unhedgeable risks, poor hedging strategy or just bad luck?” The Journalof Futures Markets, Vol.15 No. 3 (May 1995).
11
Exhibit 6
The curves show that the natural gas futures prices were in contango up to approximately the December futurescontract, while prices for later contract months were backwardated. While the 1995 data suggest a clear pattern, itis very common for seasonal patterns to be overshadowed by other market factors.
Shocks to supply, unexpected weather patterns, or market structure influences significantly affect the term structureof energy prices. Changes in the balance of supply and demand are quickly reflected in the price level and termstructure. However, despite strong price fluctuations and swings between contango and backwardation, the price ofoil today (in constant terms) is at roughly the same level that it was 20 years and 100 years previous.23
This price behavior has suggested to some in the industry that the term structure of oil prices can be described bytwo factors. The first factor reflects uncertainty about the short term price movements. Because demand for oil isrelatively inelastic and immediate supply is constrained in the short term, the short term price is a function of thephysical supply situation.. The second factor reflects uncertainty about a long term equilibrium price. Because cur-rent oil prices are at levels previously observed in history, some suggest that oil prices are mean reverting to a longterm equilibrium price. This behavior suggests a second source of uncertainty with respect to the long termequilibrium price of oil. Among others, Dragana Pilipovic of Sava Risk Management Corporation, has developeda two factor model for the forward price curve. It is based on a spot price factor and a long term price factor. Thetwo factors are linked through a mean reverting process.
Risks Associated with Energy Portfolios
Firms that buy, sell, market, distribute, or design hedges for natural gas and oil are entities that have exposure tovarious risks. First, they all bear exposure to price risk. Macro-economic conditions, local disturbances, weather,supply and demand imbalances, and strikes at energy production facilities are some of the factors that influence theprice of oil and gas. Second, companies that attempt to mitigate price risk by hedging (or intermediaries that takethe opposite side of a hedge trade) may be exposed to basis risk. Basis risk is the risk of a movement in the price ofnatural gas or oil relative to the price of the hedge vehicle. Another risk which affects all hedged positions in energyproducts is volatility risk. The relatively high price volatility of oil and natural gas translates into greater uncertainty,and consequently greater risk. An additional risk which is quite prevalent in commodity products is the risk raised by a “stack and roll” hedging strategy. It was this type of risk which ultimately unhinged the hedging strategy of Metallgesellschaft in late 1993. The following sections provide additional insight to three of the above-mentioned risks.
$1.60
$1.70
$1.80
$1.90
$2.00
May.95 Aug.95 Nov.95 Feb.96 May.96 Aug.96
Apr 1995 NG
$1.70
$1.80
$1.90
$2.00
$2.10
Jun.95 Sep.95 Dec.95 Mar.96 Jun.96 Sep.96
May 1995 NG
$1.60
$1.70
$1.80
$1.90
$2.00
$2.10
Jul.95 Oct.95 Jan.96 Apr.96 Jul.96 Oct.96
Jun 1995 NG
$1.40
$1.60
$1.80
$2.00
$2.20
Aug.95 Dec.95 Apr.96 Aug.96 Dec.96 Jun.98
Jul 1995 NG
$1.40
$1.60
$1.80
$2.00
$2.20
Sep.95 Jan.96 May.96 Sep.96 Jan.97 Dec.97
Aug 1995 NG
$1.60
$1.70
$1.80
$1.90
$2.00
Oct.95 Feb.96 Jun.96 Oct.96 Feb.97 Dec.97
Sep 1995 NG
23Gabillon, Jacques, “Analysing the Forward Curve,” Managing Energy Price Risk, p. 32.
12
Basis Risk
The definition of commodity which we often use to signify like, interchangeable products cannot be applied asfreely to energy products as it is to other commodities, such as gold. That is, unlike an ounce of gold, a barrel ofcrude oil in London may not be the same thing as a barrel of crude oil in Chicago. Variances of grade, sulfur con-tent, delivery and storage costs – among other things – give rise to numerous basis issues which must be carefullymanaged.
Price risk can be reduced by hedging with either exchange traded or OTC contracts. However, if contract termsare not equivalent, substantial basis risk can result. In the natural gas market, basis risk incorporates the differencebetween the natural gas price at two different geographic points. In the crude oil market, basis risk incorporatesgrade differences as well as location differences. Liquidity, pipeline expansions and shutdowns, gas reserve develop-ment, strikes at production facilities, weather, and the pricing relationship of substitute fuels all impact basis risk.
Local events are as important to basis movements as global events are to absolute price changes. While the price ofoil may be stable on the world market, a pipeline disruption or an excessively cold winter in a local market will causethe basis between that market and the broad market to widen substantially. Consequently, hedging an out of loca-tion cash position may significantly increase basis risk. The NYMEX crude oil futures contract settles to the pipelineprice in Cushing, Oklahoma. Because factors affecting local markets can be widely disparate, a cash price for oillocated away from Cushing may not move in tandem with the NYMEX contract, leaving the position exposed tobasis risk.
Changes in the basis can occur quickly. The NYMEX natural gas contract settles to the Henry Hub price. FromFebruary 1993 through January 1994, the differential between the Chicago City Gate natural gas price and theNYMEX Natural Gas Futures contract varied from $0.36 over to $0.12 under. During first quarter of 1994, how-ever, increased demand due in part to harsh weather conditions, pushed up Chicago City Gate natural gas pricessubstantially relative to NYMEX. On February 7, 1994, the Chicago and NYMEX prices were $2.75 and $2.35,respectively. Two days later, the Chicago price rose to $4.25 while bearish sentiment on the futures market kept theNYMEX price constant. The basis climbed to $1.89. Although the basis fell back to lower levels in the subsequentperiod, Chicago cash market participants hedging with NYMEX futures contracts were exposed to substantial price risk.
The lack of price transparency may increase basis risk for hedged natural gas or oil positions. Many natural gascontracts are priced off a published reference index. Commonly referenced price indices include Inside FERC, Gas Market Report, Gas Daily, Natural Gas Week, and Natural Gas Intelligence. The published prices are determinedby surveying industry participants throughout the marketing chain and do not represent actual transaction prices.Because of a lack of price transparency, the potential exists to alter survey prices for economic gain. Prices corre-sponding to illiquid markets can be particularly vulnerable to manipulation as they are derived from a very limitednumber of survey participants. Inaccurate price information may cause published index prices to respond differentlyto market conditions as compared to true transactions prices. This may introduce additional basis risk for contractspriced off published indices.
Crack Spreads
One common form of basis risk in the crude oil sector is the so-called “crack spread.”24 This represents the pricedifferential between refined and unrefined products. While banks’ virtual absence in the physical markets means that their activity in this sector is extremely limited, a thumbnail sketch of the activity in the crack spread may bebeneficial.
The NYMEX launched options contracts on two crack spreads (crude oil vs. either gasoline or heating oil) inOctober 1994. Exercising these options results in a spread position (one long, one short) in two futures contracts.Crack spreads can also be traded with the futures contracts outright, allowing for different ratios than the one-to-one ratio implicit in the option contract.
Refiners comprise the bulk of the participation in the crack spread markets. OTC, crack swaps are another popularhedging vehicle. Hedging the crack spread allows refiners to exercise some control over the refining margin whichfluctuates with supply and demand factors, seasonal pressures, inventory levels and other market factors.
24An equivalent in the natural gas sector is known as the “frac” spread.
13
Volatility
Volatility of crude oil and natural gas is quite a bit higher than that for many financial instruments. Volatility isgenerally referenced as either historic or implied. Historic price volatility is a measure of how the price of the futurescontract has actually been changing over a given period. Implied volatility is “implied” by the option price on agiven futures contract25 and is the market’s perception of how that underlying futures contract will trade in thefuture. There may be major divergences between historic and implied volatility at different times depending onmarket conditions, though over the long run they tend to be similar.
Exhibit 7 is a chart of 1995 implied volatility for the US Treasury Bond options, natural gas and crude options onthe December futures contracts. As can be seen, natural gas is the most volatile of the three, and crude is still quitea bit more volatile than the Treasury Bonds. Though 81⁄2 months is not an adequate timeframe for making sweepinggeneralizations, it is an accurate depiction of the type of relationships that would be observed over a longer period.
Exhibit 7
Data on historic volatility for mid-June 1991 through mid-March 1994 reveals that historic natural gas volatilityranged between 10% and 83%; historic crude oil volatility ranged between 15% and 38% and historic volatility forTreasury Bonds ranged from about 6% to 13% during that 3-year period.26 Since volatility is a measure of risk (oruncertainty) we can conclude that, all else equal, a portfolio of natural gas options would be riskier than a portfolioof crude oil options, which would be riskier than a portfolio of Treasury Bond options.
The term structure of volatility — how volatility in more distant months relates to that in closer months — tendsto be downward sloping for both natural gas and crude (as is true of most commodities). The term structure ofimplied volatility for crude oil as it looked on November 28, 1995 is illustrated in Exhibit 8.
5
10
15
20
25
30
35
40
Date
Crude NGas Bond
Implied VolatilityFeb. 22 through Oct. 23, 1995%
25Implied volatility is a number that can be backed out if an option’s underlying price, strike price, days to expiration, and the risk free interest rate are allknown. As implied volatility increases, so does the price of the option. It is not a stable measure, and can change numerous times intra-day. At any given time,however, it is the market’s best prediction of how the price of the underlying security will move during the remaining life of the option.
26Fitzgerald, Jay and Joseph T. Pokalsky, “The Natural Gas Market,” Managing Energy Price Risk, p. 189.
14
Exhibit 8
The information flow affecting the physical situation is much greater than the flow that acts to create the long-termprice equilibrium (the price of oil is generally believed to be mean-reverting), resulting in this decreasing volatilitypattern. This pattern also supports observations that movements of short-term prices are large and erratic, while theprices of longer maturities tend to remain relatively stable.27
Stack and Roll
Hedgers with large positions will often choose to reduce liquidity risk by “stacking and rolling” the hedge. A stackhedge is a position concentrated in one specific futures contract month as opposed to a string of contracts thatextend out to the maturity of the swap, or obligation being hedged.
A hedger employing a stack and roll hedge will typically hedge the vast portion (or all) of their exposure in thenearby contract. As that nearby contract approaches maturity, the hedger must roll out of the hedge by closing outthe nearby contract and reestablishing the hedge in the next month contract. As the position is rolled forward,hedgers will reduce their position by the reduction in the commitment.
In the simplest example, assume a producer wanted to hedge 100,000 barrels of oil over a 10-month period. Ratherthan selling 10 futures contracts in each of the months to be hedged, the producer could sell 100 contracts in thefront month to establish the hedge. When that month was expiring, the producer would buy back 90 of the frontmonth contracts (the hedge would be reduced by 10 contracts each month) and then sell them in the next monthcontract, until the conclusion of the period.
Because the term structure of energy prices is not stable, however, this strategy can be extremely risky. If the marketis in backwardation, a short basis position (short cash, long futures) will always show a profit. Because nearby pricesare higher than deferred prices, rolling the position forward means that the price at which futures are sold (nearbycontract) is greater than the purchase price of the next month contract. However, if the market shifts into contango,the short basis position will incur losses. The opposite scenario holds for a long basis position. The possibility of asudden change in the term structure from contango to backwardation, or vice versa, can put a stack and roll “hedge”at great risk.
14%
15%
16%
17%
18%
19%
20%
Jan Mar May Jul Sep NovContract Month
Crude Oil - Volatility Term StructureNov. 28, 1995
27Gabillon, Jacques, “Analysing the Forward Curve,” Managing Energy Price Risk, p. 32.
15
EXAMINER GUIDANCE
As emphasized in this product summary, the major risks of an energy portfolio are basis risk, volatility risk and —in certain cases — liquidity risk. Banks whose customers are seeking to hedge basis risk between an out of location(other than NYMEX) delivery point and the NYMEX delivery point, could be exposed to substantial basis risk ifthe bank’s side is not perfectly offset with another transaction. Volatility tends to be quite a bit higher in energyproducts than it is in many of the popular financial products (eg, government bonds and currencies). Higher volatil-ity means higher risk for like exposure. Thus, ongoing scrutiny to the many factors which influence energy priceswould be an expected characteristic for a trading group which accepts exposure to those factors. Hedging strategieswhich implement a “stack and roll” process should demonstrate an appreciation for the enhanced exposure to curverisk which such a strategy introduces. The following specific questions, when used in conjunction with guidanceprovided in the Federal Reserve’s Trading Activities Manual, will help examiners to assess the specific market riskswhich may be present in a bank’s energy portfolio:
1) What percentage is your energy book relative to your total trading portfolio?
2) How much overnight risk are you able to assume in the portfolio?
3) Are any of your energy swaps indexed to a pipeline other than NYMEX delivery points? If so, are those hedgedto the NYMEX or hedged to the specific pipeline?
4) To what other pipelines are you willing to take exposure (trade swaps)?
5) Do you make markets in basis swaps (ie, NYMEX vs. some other location)? If so, how liquid is the market forthat basis? How many players are in that market?
6) Do you ever employ a stack and roll hedging strategy? What are your guidelines for rolling the hedge?
7) How would your book perform if the energy term structure inverted tomorrow? Do you simulate this exposureon a regular basis?
8) How do you stress test your energy book? Do you shock spot prices, curve shape, or any elements of carry?What are the assumptions underlying the shocks? How frequently do you revisit the insight behind the assumptions?
9) How (if at all) does the risk management methodology differ from that used for non-energy books?
16
Appendix A
The Crude Oil Market
The free market for crude oil is more mature than that for natural gas, but still only dates back to about the mid-1970’s. With the myriad of refined products which emanate from crude oil (including heating oil, jet fuel,propane and gasoline) few corners of our industrial and commercial marketplaces are untouched by price and supplyfluctuations in crude oil.
Because of its unique transportation method (pipelines instead of barges) pipeline disruptions are a major factorcontributing to the volatility of the WTI contract. With few exceptions, US legal restrictions prohibit the export ofdomestic crudes except in the form of refined products.28 However, on November 28, 1995, President Clintonsigned into law a bill which will lift the 22-year-old ban on oil exports, allowing exports of Alaska North Slopecrude oil by June 1996. The effect of this new law is unclear, though analysts expect it to have little impact on worldoil prices.29
Bans on crude exports have meant that US crude is not internationally tradable and thus it is possible for therelationship between WTI and other benchmark crudes to become severed in times of international upheaval, suchas occurred during the Gulf crisis. At that time, the price differential between Brent (the major benchmark crudeoutside the US) and WTI crudes got as high as $3/barrel30 (Brent over WTI) largely because WTI crude essentiallycould not be exported to meet international demand imbalances. As a point of reference, this relationship histori-cally trades at approximately $1.50.
Crude oil presently accounts for approximately 40% of world energy supply and is the world’s most actively tradedcommodity.31 Outside of the US, Brent crude is actively traded on the International Petroleum Exchange (IPE) inLondon as well as the Singapore International Monetary Exchange (SIMEX) as of June 1995. On September 8,1995, the NYMEX linked their electronic ACCESSSM system with the Sydney Futures Exchange’s (SFE) Sycomelectronic trading system. This link allows SFE members to trade NYMEX energy products during the lengthyACCESSSM trading hours. The success of this link will depend on the success of hedging Tapis (that region’sbenchmark crude oil) with WTI crude which is not the customary pricing mechanism in the region.32
Oil is denominated in US dollars internationally. This factor has caused chagrin among OPEC (and other interna-tional) producers during times of dollar weakness. Exhibit 9 plots the price of the front month crude oil future rel-ative to the US Dollar Index during the period 2/1/95 through 8/21/95. While numerous other factors impact theprice of crude oil, it can be seen that dollar weakness is often accompanied by an increase in the price of crude oil.
Exhibit 9
28Horsnell, Paul and Robert Mabro, Oil Markets and Prices – The Brent Market and the Formation of World Oil Prices, Oxford University Press for the OxfordInstitute for Energy Studies, 1993, p. 277.
29Walsh, Simon, “President Signs Bill Lifting Alaskan Oil Export Ban,” Bloomberg Business News, Nov. 28, 1995.
30(Horsnell and Mabro 231)
31New York Mercantile Exchange Energy Complex, New York Mercantile Exchange, December 1994 p. 1.
32(Machida-Spears 11)
$16.00
$17.00
$18.00
$19.00
$20.00
$21.00
80
82
84
86
88
90
Date
Dollar Index Crude
Crude Oil vs. US Dollar IndexFeb. 1 through Aug. 21, 1995
17
During the Gulf War of 1991, the last major disruption in world crude prices, both the NYMEX and the IPE marketwere closed at the time of the initial confrontation, leaving the cash WTI and the forward Brent markets as the onlyopen trading vehicles. Prices gyrated wildly during the night that US forces began their attack on Baghdad, withprice swings moving as much as $14/barrel.33 With the addition of the NYMEX ACCESSSM and the SIMEX Brentcontract, however, accessing reasonably liquid crude markets around the clock is very plausible. Thus, even duringan event of extreme uncertainty, the ability of so many market participants to transact virtually around-the-clockwould probably serve to stem volatility.
IPE Crude and the International Market
The IPE (London’s International Petroleum Exchange) Brent crude futures contract is still relatively young, havingbegun trading on June 23, 1988. Like the NYMEX contract, the IPE contract for Brent crude is based on 1,000barrels with each price point worth $1,000. Unlike the NYMEX, it is cash-settled with an optional delivery alter-native and is based on the 15-day forward Brent crude market which has evolved into the world’s most transparentand internationally traded forward market for crude oil.34 Contracts are available for 12 consecutive months withliquidity being concentrated largely in the first three months. Thus, the ability to hedge long-dated crude oil is onthe IPE is significantly more limited than on the NYMEX.
The IPE Brent futures contract is not nearly as liquid or actively traded as the NYMEX “equivalent.” On a dailybasis, volume tends to be roughly 20,000-30,000 contracts or roughly 1/4 of the NYMEX volume. Yet, the con-tract is a vital link in the trading of international crude and the overall Brent crude market. Dated (or spot) Brent isthe terminology used to reference the cash market and is the most important price in international oil trade.35
However, in the strict sense of the word, dated Brent is not exactly “spot” as many of the trades are for cargoes withseveral days’ lead time to loading.
The advent of trading of the SIMEX contract in June of 1995 allows for greater access to trading of the Brent crudefutures and this contract has a mutual offset arrangement with the IPE. While the IPE contract trades between thehours of 5:02 am and 3:15 pm EST, the SIMEX makes the contract available during the hours of 8:25 pm to 11:30pm EST. Exhibit 10 depicts the exchange hours in the New York time zone for the NYMEX (including ACCESSSM)the IPE and the SIMEX on a typical trading day. As illustrated, the only hour of the day during which crude oil doesnot trade on an exchange is between 3:15 and 4:00 pm.
Exhibit 10
OPEC
The influence of the Organization of the Petroleum Exporting Countries (OPEC) has diminished since the heightof their influence in the 1970s and their contribution to the reverse oil price shock of 1986 (prices fell to less than$10/barrel from $30/barrel in 9 months as OPEC members abandoned production discipline36). However, their
Midnight 2am 4am 6am 8am 10am 12pm 2pm 4pm 6pm 8pm 10pm Midnight
NYMEX
IPE
SIMEX
Midnight 8am 9:45am 3:10 pm 4:00pm Midnight
5:02am 3:15pm
1:30am 3:58am 8:25pm 11:30pm
33(Horsnell and Mabro 169)
34Brindle, Alban, “Exchanges and the OTC Market,” Managing Energy Price Risk, p. 258.
35(Horsnell and Mabro 113)
36(Horsnell and Mabro 167)
18
influence over world oil prices should not be summarily dismissed. OPEC continues to agree to a daily outputceiling (though it tends to be exceeded by as much as one million barrels per day) in an effort to keep prices neartheir target level. However, their production ceiling (24.52 mbpd as of this writing) has declined on a percentagebasis of world oil trade. For example, as recently as 1991, total international trade in crude oil amounted to about30 mbpd, of which OPEC produced about 21 million or 70%.37 Today’s daily figure is closer to 70 mbpd of whichOPEC produces 25 million or 36%. The growth of oil production from non-OPEC countries, particularly emerg-ing market economies, has served to reduce their ability to influence oil prices through cartel behavior. Yet, theirpercentage production of world oil output is still substantial enough that periodic OPEC meetings continue togarner the market’s attention.
The Natural Gas Market
As recently as the early 1980’s, the US government imposed stringent price controls on natural gas. For years, gaswas believed to be a vanishing resource which should be reserved for residential and light commercial use.38 In 1978,however, perhaps realizing that price controls were contributing to the severe gas shortages which characterized themid to late 1970’s, the Carter Administration proposed and won a hard-fought passage of the Natural Gas Policy Act(NGPA) of 1978 which phased out price controls on natural gas by 1985. Once the artificial price barriers wereremoved, competitive, economic factors could steer the market, creating an opportunity for an exchange-tradedfutures contract. Today, natural gas is actively traded both on the NYMEX as well as OTC, allowing risk manage-ment opportunities for producers, refiners and end-users and giving rise to intermediation opportunities — a rolefilled by varied financial and brokerage firms, including banks.
Unlike the market for crude oil, the North American natural gas market is purely a domestic market. Natural gasaccounts for nearly a quarter of all energy consumption in the US. It is primarily produced from reserve basins inTexas, Louisiana, and Oklahoma. These three states account for approximately 70% of total North American naturalgas production.39 Alberta, Canada is also a significant producer. Due to recent pipeline expansions, approximately10% of US demand is met by Canada. The states with the highest net receipts of natural gas include Illinois,California, and New York. Consumption in these states typically exceeds local production.
Overseas natural gas markets will most likely continue to be segregated from the North American market in the nearfuture, primarily due to transportation logistics. Markets that are geographically isolated from pipeline connectionscan acquire natural gas in the form of liquefied natural gas (LNG). However, imports of LNG to the US are verymarginal due to the high costs of transportation and handling. The cost to liquefy and unliquefy natural gas is pro-hibitively high relative to the total cost of the product. Consequently, LNG would only be used as a last resort inperiods of peak demand.
The North American market is connected via a network of pipelines. However, local markets can be segregated dueto geographic barriers. For instance, difficulties in building pipelines through mountainous regions have effectivelysevered the California market from other domestic markets. The relative isolation of the Californian (or Western)market, in combination with other factors such as weather, often result in substantial price variation from otherregions. This factor was largely responsible for the introduction in 1995 of an exchange-traded natural gas contractspecifically for the Western US on the Kansas City Board of Trade.
Market Structure
The market structure of the natural gas industry has been marked by recent regulatory change. In 1989, the NaturalGas Wellhead Decontrol Act was passed to complete the process of decontrolling wellhead prices. Beginning in the1980’s, Federal Energy Regulatory Commission (FERC) orders mandated the separation of existing economicentities and allowed open access to pipeline transportation. Pipelines were forced to unbundle sales and transporta-tion services and retain only the transportation function (though many now own non-affiliated marketingsubsidiaries). Since the pipelines were no longer able to purchase directly from producers and handle sales, FERCregulation effectively shifted the purchasing function to end-users and local distribution companies. This legislation
37(Horsnell and Mabro 37)
38Glasser, Sam, “Natural Gas Futures Put the Crowning Touch on the Evolution of a Free Market,” Energy in the News, New York Mercantile Exchange,Spring 1995, p. 3.
39Natural Gas Issues and Trends 1994, Energy Information Administration.
19
and regulation resulted in a restructuring of the entire industry. New institutional structures such as market hubs andsecondary markets for pipeline capacity rights emerged as a result of the regulation. The resulting restructuredmarket is characterized by intense competitive pressures.
The marketing chain is comprised of distinct market segments including producers, marketers, pipelines, and localdistribution companies. Production facilities, located at the wellhead, begin the marketing channel. The market ischaracterized by a large number of producers. Currently, there are more than 5,000 oil and gas producers in the US.The largest 20 companies, however, produce approximately 45% of total annual production.40
Interstate pipeline companies primarily transport natural gas from the production regions to market areas. Intrastatepipeline companies are not regulated by FERC. These companies both transport and merchandise gas. A quarter ofa million miles of pipeline traverse the continental US moving gas primarily in a northeast direction. Approximately110 companies control the flow of natural gas across the US through these pipelines.41
Marketers are intermediaries that have emerged from the new regulation. Marketers match buyers and sellers of gas, trade natural gas, and can arrange transportation; in short, they have assumed the merchant function whichpreviously belonged to the pipelines. Many large producers, local distribution companies, and pipelines havemarketing arms.
Local distribution companies (LDCs) serve the residential and commercial market. Required by regulatory mandateto provide the public with natural gas, these companies are the largest suppliers of heat and energy to industrial,commercial and residential customers in non-gas producing states. Prior to FERC, LDCs purchased bundledservices from pipeline companies. They faced little price risk since they were able to pass along cost increases in theprice of the commodity, transportation, or service charges directly to customers. In the post regulatory era, how-ever, LDCs contract separately for gas supplies, transportation, and other services, exposing them to greater risks andforcing them to be more competitive. Problems can result if LDCs contract to supply end-users without securingadequate quantities of natural gas. In addition, LDCs face supply risk in maintaining sufficient supply, especiallyduring periods of peak demand.
Deregulation has spawned a futures market for natural gas. With deregulated wellhead prices and increased com-petitive pressures, all segments in the industry faced greater price volatility. The introduction of natural gas futuresand options created price transparency and allowed firms to manage elements of price risk in a low cost manner.
Contracting
Purchasing and moving natural gas from wellhead to burnertip requires contracting for both physical supply andtransportation services. Pipeline capacity is sold on either a firm or an interruptible basis. Firm transportation is highpriority service that is interrupted only for “force majeure.” Interruptible transportation is a lower priority servicesubject to interruptions on short notice, and therefore can be arranged at a lower cost.
Supply contracts negotiated in the 1970’s when natural gas prices were high and supplies scarce were often of longduration; several extended up to 20 years. In the late 1970s, wellhead price regulation provided little incentive toincrease gas reserves. A shortage developed which led to prices of approximately $8.59/Mcf (thousand cubic feet),compared with roughly $1.40/Mcf today. Pipelines had attempted to lock in long term sources of gas at any pricein order to meet their contractual obligations with end-users. Tight supply conditions were instrumental in theirnegotiations of “take-or-pay” contracts with producers. These contracts required the gas purchaser to pay for a min-imum production from a producer at an agreed upon price, whether or not the purchaser took that quantity. Asstated above, some of these contracts were for periods as long twenty years! (Contract tenors have declined substan-tially in the post-regulatory era.)
When gas prices declined in the 1980s due in part to the recession and the impact of lessening regulation, previouslynegotiated take or pay deals required pipelines to buy gas at prices as much as six times the then prevailing spot price.During this time, fuel oil was cheaper and thus became an economical substitute for gas. As pipelines became hardpressed to meet their take-or-pay liabilities, producers attempted to sell to end-users on a short term basis and thenatural gas spot market was born.
40(Fitzgerald and Pokalsky 192)
41(Fitzgerald and Pokalsky 195)
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Spot natural gas contracts are not “spot” in the strictest sense of the word. They are contracts for delivery and receiptof natural gas within one month. Spot trading accounts for approximately 75% of the natural gas market, accordingto some estimates.1 Prices for spot deals are most often fixed to a published price benchmark such as Gas Daily.Occasionally, when gas prices change substantially between contract execution and final delivery, the purchaser willnot take the gas from the seller or the seller will not deliver the gas to the purchaser. In these cases, the price of gasmay be renegotiated by both parties. This practice, known as retrading, is allowed under certain circumstances.Contracts with retrading provisions essentially have option value attached.
Most contracts for next month delivery are finalized during what is known as bid week. During bid week, shippersnominate, or make capacity arrangements, with pipelines. Because the quantity that a shipper can move is limitedby the capacity arrangement, the gas price and quantity are finalized during this same period. Bid week occurs atthe end of each month. These contracts have particular economic benefit for firms that have fuel switchingcapabilities since they can be renegotiated each month to reflect the most cost-effective fuel choice.
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