Energy Derivatives - Crude Oil and Gas
Energy Derivatives - Crude Oil and Gas
Energy Derivatives - Crude Oil and Gas
E N E R G Y D E R I V A T I V E S
Prepared by
The Financial Markets Unit
Supervision and Regulation
PRODUCT SUMMARY
E N E R G Y D E R I V A T I V E S
Prepared by:
Karen McCann
Mary Nordström
Financial Markets Unit
December 1995
PRODUCT SUMMARIES
Product summaries are produced by the Financial Markets Unit of the
Supervision and Regulation Department of the Federal Reserve Bank of
Chicago. Product summaries are published periodically as events warrant
and are intended to further examiner understanding of the functions and
risks of various financial markets products relevant to the banking indus-
try. While not fully exhaustive of all the issues involved, the summaries
provide examiners background information in a readily accessible form
and serve as a foundation for any further research into a particular prod-
uct or issue. Any opinions expressed are the authors’ alone and do not
necessarily reflect the views of the Federal Reserve Bank of Chicago or
the 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 the
members of the Financial Markets Unit listed below.
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
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 of
players. Consequently, the energy markets are actively traded by individuals and institutions who never have any
intention of “taking delivery” of a physical barrel of crude oil or a million British thermal units of natural gas. In
1994 we learned a great deal about how an uncertain interest rate environment can give rise to wild fluctuations in
the 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 of
affecting the markets. Without an understanding of these factors and the unique concerns which they raise for
energy 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 is
appropriate to describe the markets and identify the risks and special concerns which attach themselves to energy
products. With a focus on natural gas and crude oil, this product summary will give examiners and other interested
parties a significant foundation from which further analysis can be directed.
1
Banks’ Involvement in Energy Markets
Unlike the more mature market for interest rate derivatives, recent deregulation of the energy markets has spawned
tremendous 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 gas
are 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 between
producers 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 directly
related to the price of energy.
Banks’ participation, which is essentially limited to the larger, money center banks, stems primarily from meeting
the needs of customers with oil-contingent revenue streams. A presence in the energy markets also provides banks
with a “strategic diversification” away from more traditional banking exposures, ie, interest rates and foreign
exchange.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 with
greater access to funds.
The relative maturity of the interest rate derivative markets in relation to the energy derivative markets suggest that
growth and innovation in this sector may have significant potential. In addition, more sophisticated banks’ trading
rooms — whose profits are reliant on volatility — may be more attracted to the higher volatility inherent in energy
products during times of relative calm in financial markets. The growing focus on corporate risk management across
industries may also serve to increase the risk management activities of end-users and producers, contributing to
growth in this sector and a greater role for banks’ intermediary activities.
1
Barnaud, Frédéric and Jean Dabouineau, “The Oil Market,” Managing Energy Price Risk, p. 169.
2
(Barnaud and Dabouineau 169)
3
Volatility is discussed in greater detail in the section entitled Risks.
2
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 exotic
options, such as barriers, are extremely rare in the energy sector. Greater detail on average price options follows in
the 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 and
products can be structured to more closely replicate their cash market activities. Barnaud and Dabouineau contend
that the OTC energy markets are characterized by “very poor visibility” and that transactions are often private and
confidential.5 Thus, care in interpreting any pricing “information” is required, particularly for smaller players, such
as 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 does
exist, however, in many tenors of OTC average price crude and natural gas products. Because of the differences in
contract design between these instruments and exchange-traded instruments (which are not average price) banks’
hedging decisions — either OTC or back to back — are crucial.
4
Basis is discussed in greater detail in the section entitled Risks.
5
(Barnaud and Dabouineau 176)
6
The following discussion assumes knowledge on the part of the reader of option fundamentals. Readers who would like further explanation of option
characteristics are referred to the product summary entitled Options, published in November 1994.
7
A more thorough explanation of bid week is included in Appendix A under the heading The Natural Gas Market.
3
characteristic of the natural gas market highlights another feature of average price options; they reduce the incentives
to manipulate the underlying price at expiration.8
Averaging is usually done via an arithmetic average though a weighted average can also be used. The difficulty
which this poses is that the options cannot be valued using a closed-form pricing solution. The basic Black-Scholes
option pricing formula is not applicable since an average of prices will not be lognormally distributed even though
the individual component prices will.9 Consequently, models used to price these options consist of numerical
solutions 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 higher
struck 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 an
end-user who is exposed to the risk of rising prices (equivalent to having a short position in oil) purchase of an oil
cap 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 October
1986.10 Estimates of OTC dealer activity are currently believed to be approximately 300 to 400 million barrels of oil
equivalent 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 based
on the price of oil over which they exert little control. End-users are subject to the risk of rising energy prices for
needs which are often price inelastic. The presence of natural buyers and sellers creates a foundation for an active
swap market with a niche for financial intermediaries. Further, the addition of new long-term crude oil futures to
the NYMEX energy complex has made swaps of medium and longer terms easier to hedge without having to be
subject to a “stack and roll” strategy.12 The NYMEX has exempted swap traders from position limits, further
contributing 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 are
based 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, assuming
credit risk, and being able to absorb (and hedge) residual market risk which may arise from contracts with slightly
different terms.
The floating prices of nearly all crude oil and a large portion of natural gas swaps are average prices. Often these are
indexed to an average of NYMEX prices over a reference period. Alternatively, the swap may be indexed to an
average of prices listed in trade publications such as Platt’s Oilgram Price Report or Inside FERC. Although OTC deals
can be customized in any way, the reference period for most crude oil swaps is the entire calendar month. For natural
gas, 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.
8
Trabia, 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.
10
Falloon, William, “A Market is Born,” Managing Energy Price Risk, p. 13.
11
(Falloon 17)
12
Stack and roll is discussed in the section on Risks.
13
Davey, Emma, “Pulling it all together,” Energy 1995 (A supplement to Futures and Options World), p. 4.
4
Exhibit 1 details a simple fixed for floating NYMEX-based crude oil swap. In this case, the floating price is deemed
to 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 the
expiration 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 The
hedge is calculated by multiplying the discount factor by the number of barrels to be hedged each month (giving
the present value — PV — of the barrels of oil) and then dividing by 1,000 to arrive at the appropriate number of
futures contracts. This will have the effect of introducing rounding errors which are difficult to circumvent since
futures 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 make
fixed payments to the producer and receive floating. To hedge this swap, the bank has two alternatives; it can either
be hedged OTC or with NYMEX futures contracts. Liquidity on the NYMEX becomes a definite concern for
maturities 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 the
quantity of futures contracts in each month designated in the “hedge” column. If the actual floating prices realized
were $18.11, $18.04 and $17.63, the hedge would perform as illustrated in Exhibit 2.
14
This number can be very closely approximated in this example by taking the simple arithmetic average of the three futures prices. However, the size of
the swap requires greater precision.
5
Exhibit 2
Hedge Performance
Futures Producer’s Bank’s Swap
Date 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)
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 an
average 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 futures
contracts, the bank would sell the number of futures contracts shown for each period (49.18 x number of business
days) and buy back 49 each business day. This procedure gives them the appropriate exposure to the average contract
price against which the swap will settle.15
15
The preceding discussion draws heavily on material presented in: Das, Satyajit, Swap and Derivative Financing, Probus Publishing, Chicago, 1993.
6
Often, average price swaps will settle against a reference index other than NYMEX. Valuing these swaps using only
NYMEX prices is likely to lead to mispriced deals and suboptimal hedges. For example, a natural gas swap may be
referenced 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 necessary
to price the swap using the specific pipeline price, not the NYMEX. However, Gas Daily does not list forward
prices. 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 referenced
index forward price.
In the natural gas OTC market, basis swaps are very common. These are swaps used to hedge fluctuations in the
spread between NYMEX natural gas futures (based on prices at the Henry Hub in Louisiana) and gas prices at
distant delivery points.16 With respect to certain pipelines, active basis markets exist, allowing banks to participate in
these swaps and hedge them OTC.
16
“Commodities,” 1993 Year in Review, Risk, January 1994, p. 25.
17
Machida-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.
7
Natural Gas
The NYMEX natural gas contract (the first natural gas futures contract in the world) began trading on April 3, 1990
and 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 for
users of natural gas who require delivery at a location not directly served by those pipelines and will be more fully
discussed 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 each
day. Futures are listed for eighteen consecutive months (though the exchange has received CFTC approval to list
contracts of 21, 24 and 36 month maturities), while options contracts trade for twelve consecutive months. Natural
gas futures trade on the NYMEX’s ACCESSSM electronic trading system from 4 pm to 7 pm Mondays through
Thursdays. There is little need for longer market hours since, unlike crude oil, there is no active international market
which 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 contract
based on delivery at the Permian/Waha Hub in west Texas. The hub connects ten pipelines and facilitates delivery
to California and the Midcontinent. The logic behind introducing a futures contract with a different delivery point
than the NYMEX contract was to offer hedgers the ability to hedge against a different geographic location, thus
lessening the basis risk of a hedged trade. For instance, it would not be unusual for the East Coast to experience a
severe winter while the West Coast was balmy. Thus, higher prices for gas would prevail in the East while prices in
the West may stay steady or even fall. A West Coast producer who was hedged to the NYMEX might see that hedge
quickly 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 that
two contracts may ultimately prevail in the US market. (The NYMEX is presently gearing up to list a competing
contract.) Exhibit 4 plots the spread between the NYMEX and KCBT natural gas contracts for the period 9/25/95
through 11/22/95 (NYMEX minus KCBT in cents).
Exhibit 4
$0.18
$0.16
$0.14
$0.12
$0.10
Sep 25 Oct 4 Oct 13 Oct 24 Nov 2 Nov 13 Nov 22
Electricity
Futures in electricity promise to be the next sector of the energy marketplace to be traded on an exchange. As was
true of both the crude oil and the natural gas markets, liberalization of the underlying market is proving to be a slow
process 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
19
New York Mercantile Exchange Annual Report, 1993-1994 p. 11.
8
cash market will need to be further developed before a futures contract can be successfully launched. While the
California 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
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 holders
of inventories is called convenience yield.
The value of the convenience yield influences the term structure of energy prices. One theory of backwardation
holds that when excess supplies are available, inventories increase and convenience yield declines. Low convenience
yields 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 of
energy. As convenience yield increases, the market can swing into backwardation.
20
(Davey 5)
21
Bodi, Zvi, Alex Kane and Alan J. Marcus, Investments, p. 649.
9
Behavior of Oil Price Curves
Contango markets are economically limited by full carry. Any price level above this limit would introduce an
arbitrage opportunity. If the forward price exceeds the spot price by more than full carry, an arbitrageur could buy
the spot commodity, store it, and sell it forward at the futures price for a riskless profit. Because a contango market
cannot steepen to arbitrarily high levels, the risk of a long basis position (long cash and short futures) is limited. In
general, 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 of
crude 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
$18.20
$18.50 $18.50
$18.00
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 supply
disruption from producers including Nigeria. The oil market remained inverted only until August 1994. While oil
markets can remain in contango or backwardation for protracted periods, this isn’t always the case. Studies have
shown 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, when
demand for natural gas is high, markets may have a tendency to backwardate. During warm weather months, gas
demand 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, contract
months are listed on the X axis.)
22
Edwards, Franklin R. and Michael S. Canter, “The Collapse of Metallgesellschaft: Unhedgeable risks, poor hedging strategy or just bad luck?” The Journal
of Futures Markets, Vol.15 No. 3 (May 1995).
10
Exhibit 6
$1.90 $2.00
$2.00
$1.90
$1.80
$1.90
$1.80
$1.70 $1.80
$1.70
$1.60 $1.70
May.95 Aug.95 Nov.95 Feb.96 May.96 Aug.96 Jun.95 Sep.95 Dec.95 Mar.96 Jun.96 Sep.96 $1.60
Jul.95 Oct.95 Jan.96 Apr.96 Jul.96 Oct.96
The curves show that the natural gas futures prices were in contango up to approximately the December futures
contract, while prices for later contract months were backwardated. While the 1995 data suggest a clear pattern, it
is 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 structure
of energy prices. Changes in the balance of supply and demand are quickly reflected in the price level and term
structure. However, despite strong price fluctuations and swings between contango and backwardation, the price of
oil 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 by
two factors. The first factor reflects uncertainty about the short term price movements. Because demand for oil is
relatively inelastic and immediate supply is constrained in the short term, the short term price is a function of the
physical 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 long
term equilibrium price. This behavior suggests a second source of uncertainty with respect to the long term
equilibrium price of oil. Among others, Dragana Pilipović of Sava Risk Management Corporation, has developed
a two factor model for the forward price curve. It is based on a spot price factor and a long term price factor. The
two factors are linked through a mean reverting process.
23
Gabillon, Jacques, “Analysing the Forward Curve,” Managing Energy Price Risk, p. 32.
11
Basis Risk
The definition of commodity which we often use to signify like, interchangeable products cannot be applied as
freely to energy products as it is to other commodities, such as gold. That is, unlike an ounce of gold, a barrel of
crude 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 carefully
managed.
Price risk can be reduced by hedging with either exchange traded or OTC contracts. However, if contract terms
are not equivalent, substantial basis risk can result. In the natural gas market, basis risk incorporates the difference
between the natural gas price at two different geographic points. In the crude oil market, basis risk incorporates
grade 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 of
oil may be stable on the world market, a pipeline disruption or an excessively cold winter in a local market will cause
the 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 pipeline
price in Cushing, Oklahoma. Because factors affecting local markets can be widely disparate, a cash price for oil
located away from Cushing may not move in tandem with the NYMEX contract, leaving the position exposed to
basis risk.
Changes in the basis can occur quickly. The NYMEX natural gas contract settles to the Henry Hub price. From
February 1993 through January 1994, the differential between the Chicago City Gate natural gas price and the
NYMEX 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 prices
substantially 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 the
NYMEX price constant. The basis climbed to $1.89. Although the basis fell back to lower levels in the subsequent
period, 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 gas
contracts 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 determined
by 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 limited
number of survey participants. Inaccurate price information may cause published index prices to respond differently
to market conditions as compared to true transactions prices. This may introduce additional basis risk for contracts
priced 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 price
differential 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 be
beneficial.
The NYMEX launched options contracts on two crack spreads (crude oil vs. either gasoline or heating oil) in
October 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 popular
hedging vehicle. Hedging the crack spread allows refiners to exercise some control over the refining margin which
fluctuates with supply and demand factors, seasonal pressures, inventory levels and other market factors.
24
An equivalent in the natural gas sector is known as the “frac” spread.
12
Volatility
Volatility of crude oil and natural gas is quite a bit higher than that for many financial instruments. Volatility is
generally referenced as either historic or implied. Historic price volatility is a measure of how the price of the futures
contract has actually been changing over a given period. Implied volatility is “implied” by the option price on a
given futures contract25 and is the market’s perception of how that underlying futures contract will trade in the
future. There may be major divergences between historic and implied volatility at different times depending on
market 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 on
the December futures contracts. As can be seen, natural gas is the most volatile of the three, and crude is still quite
a bit more volatile than the Treasury Bonds. Though 81⁄2 months is not an adequate timeframe for making sweeping
generalizations, it is an accurate depiction of the type of relationships that would be observed over a longer period.
Exhibit 7
Implied Volatility
% Feb. 22 through Oct. 23, 1995
40
35
30
25
20
15
10
5
Date
Crude NGas Bond
Data on historic volatility for mid-June 1991 through mid-March 1994 reveals that historic natural gas volatility
ranged between 10% and 83%; historic crude oil volatility ranged between 15% and 38% and historic volatility for
Treasury Bonds ranged from about 6% to 13% during that 3-year period.26 Since volatility is a measure of risk (or
uncertainty) we can conclude that, all else equal, a portfolio of natural gas options would be riskier than a portfolio
of 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 — tends
to be downward sloping for both natural gas and crude (as is true of most commodities). The term structure of
implied volatility for crude oil as it looked on November 28, 1995 is illustrated in Exhibit 8.
25
Implied 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 all
known. 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.
26
Fitzgerald, Jay and Joseph T. Pokalsky, “The Natural Gas Market,” Managing Energy Price Risk, p. 189.
13
Exhibit 8
The information flow affecting the physical situation is much greater than the flow that acts to create the long-term
price equilibrium (the price of oil is generally believed to be mean-reverting), resulting in this decreasing volatility
pattern. This pattern also supports observations that movements of short-term prices are large and erratic, while the
prices of longer maturities tend to remain relatively stable.27
27
Gabillon, Jacques, “Analysing the Forward Curve,” Managing Energy Price Risk, p. 32.
14
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 if
the bank’s side is not perfectly offset with another transaction. Volatility tends to be quite a bit higher in energy
products 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 prices
would be an expected characteristic for a trading group which accepts exposure to those factors. Hedging strategies
which implement a “stack and roll” process should demonstrate an appreciation for the enhanced exposure to curve
risk which such a strategy introduces. The following specific questions, when used in conjunction with guidance
provided in the Federal Reserve’s Trading Activities Manual, will help examiners to assess the specific market risks
which 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 hedged
to 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 for
that 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 exposure
on 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?
15
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 supply
fluctuations in crude oil.
Because of its unique transportation method (pipelines instead of barges) pipeline disruptions are a major factor
contributing to the volatility of the WTI contract. With few exceptions, US legal restrictions prohibit the export of
domestic crudes except in the form of refined products.28 However, on November 28, 1995, President Clinton
signed into law a bill which will lift the 22-year-old ban on oil exports, allowing exports of Alaska North Slope
crude oil by June 1996. The effect of this new law is unclear, though analysts expect it to have little impact on world
oil prices.29
Bans on crude exports have meant that US crude is not internationally tradable and thus it is possible for the
relationship between WTI and other benchmark crudes to become severed in times of international upheaval, such
as occurred during the Gulf crisis. At that time, the price differential between Brent (the major benchmark crude
outside the US) and WTI crudes got as high as $3/barrel30 (Brent over WTI) largely because WTI crude essentially
could 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 traded
commodity.31 Outside of the US, Brent crude is actively traded on the International Petroleum Exchange (IPE) in
London 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) Sycom
electronic trading system. This link allows SFE members to trade NYMEX energy products during the lengthy
ACCESSSM trading hours. The success of this link will depend on the success of hedging Tapis (that region’s
benchmark 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 the
price of crude oil, it can be seen that dollar weakness is often accompanied by an increase in the price of crude oil.
Exhibit 9
$20.00 88
$19.00 86
$18.00 84
$17.00 82
$16.00 80
Date
Dollar Index Crude
28
Horsnell, Paul and Robert Mabro, Oil Markets and Prices – The Brent Market and the Formation of World Oil Prices, Oxford University Press for the Oxford
Institute for Energy Studies, 1993, p. 277.
29
Walsh, Simon, “President Signs Bill Lifting Alaskan Oil Export Ban,” Bloomberg Business News, Nov. 28, 1995.
30
(Horsnell and Mabro 231)
31
New York Mercantile Exchange Energy Complex, New York Mercantile Exchange, December 1994 p. 1.
32
(Machida-Spears 11)
16
During the Gulf War of 1991, the last major disruption in world crude prices, both the NYMEX and the IPE market
were closed at the time of the initial confrontation, leaving the cash WTI and the forward Brent markets as the only
open trading vehicles. Prices gyrated wildly during the night that US forces began their attack on Baghdad, with
price swings moving as much as $14/barrel.33 With the addition of the NYMEX ACCESSSM and the SIMEX Brent
contract, however, accessing reasonably liquid crude markets around the clock is very plausible. Thus, even during
an event of extreme uncertainty, the ability of so many market participants to transact virtually around-the-clock
would probably serve to stem volatility.
Exhibit 10
NYMEX
5:02am 3:15pm
IPE
SIMEX
Midnight 2am 4am 6am 8am 10am 12pm 2pm 4pm 6pm 8pm 10pm Midnight
OPEC
The influence of the Organization of the Petroleum Exporting Countries (OPEC) has diminished since the height
of 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
33
(Horsnell and Mabro 169)
34
Brindle, Alban, “Exchanges and the OTC Market,” Managing Energy Price Risk, p. 258.
35
(Horsnell and Mabro 113)
36
(Horsnell and Mabro 167)
17
influence over world oil prices should not be summarily dismissed. OPEC continues to agree to a daily output
ceiling (though it tends to be exceeded by as much as one million barrels per day) in an effort to keep prices near
their target level. However, their production ceiling (24.52 mbpd as of this writing) has declined on a percentage
basis of world oil trade. For example, as recently as 1991, total international trade in crude oil amounted to about
30 mbpd, of which OPEC produced about 21 million or 70%.37 Today’s daily figure is closer to 70 mbpd of which
OPEC 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, their
percentage production of world oil output is still substantial enough that periodic OPEC meetings continue to
garner the market’s attention.
Market Structure
The market structure of the natural gas industry has been marked by recent regulatory change. In 1989, the Natural
Gas Wellhead Decontrol Act was passed to complete the process of decontrolling wellhead prices. Beginning in the
1980’s, Federal Energy Regulatory Commission (FERC) orders mandated the separation of existing economic
entities 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 marketing
subsidiaries). Since the pipelines were no longer able to purchase directly from producers and handle sales, FERC
regulation effectively shifted the purchasing function to end-users and local distribution companies. This legislation
37
(Horsnell and Mabro 37)
38
Glasser, 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.
39
Natural Gas Issues and Trends 1994, Energy Information Administration.
18
and regulation resulted in a restructuring of the entire industry. New institutional structures such as market hubs and
secondary markets for pipeline capacity rights emerged as a result of the regulation. The resulting restructured
market is characterized by intense competitive pressures.
The marketing chain is comprised of distinct market segments including producers, marketers, pipelines, and local
distribution companies. Production facilities, located at the wellhead, begin the marketing channel. The market is
characterized 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. Intrastate
pipeline companies are not regulated by FERC. These companies both transport and merchandise gas. A quarter of
a million miles of pipeline traverse the continental US moving gas primarily in a northeast direction. Approximately
110 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 which
previously belonged to the pipelines. Many large producers, local distribution companies, and pipelines have
marketing arms.
Local distribution companies (LDCs) serve the residential and commercial market. Required by regulatory mandate
to 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 bundled
services from pipeline companies. They faced little price risk since they were able to pass along cost increases in the
price 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 and
forcing them to be more competitive. Problems can result if LDCs contract to supply end-users without securing
adequate quantities of natural gas. In addition, LDCs face supply risk in maintaining sufficient supply, especially
during 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 futures
and 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 and
transportation services. Pipeline capacity is sold on either a firm or an interruptible basis. Firm transportation is high
priority service that is interrupted only for “force majeure.” Interruptible transportation is a lower priority service
subject 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 long
duration; several extended up to 20 years. In the late 1970s, wellhead price regulation provided little incentive to
increase 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 price
in order to meet their contractual obligations with end-users. Tight supply conditions were instrumental in their
negotiations 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. As
stated 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, previously
negotiated 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 hard
pressed to meet their take-or-pay liabilities, producers attempted to sell to end-users on a short term basis and the
natural gas spot market was born.
40
(Fitzgerald and Pokalsky 192)
41
(Fitzgerald and Pokalsky 195)
19
Spot natural gas contracts are not “spot” in the strictest sense of the word. They are contracts for delivery and receipt
of natural gas within one month. Spot trading accounts for approximately 75% of the natural gas market, according
to 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 will
not take the gas from the seller or the seller will not deliver the gas to the purchaser. In these cases, the price of gas
may 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, shippers
nominate, or make capacity arrangements, with pipelines. Because the quantity that a shipper can move is limited
by the capacity arrangement, the gas price and quantity are finalized during this same period. Bid week occurs at
the end of each month. These contracts have particular economic benefit for firms that have fuel switching
capabilities since they can be renegotiated each month to reflect the most cost-effective fuel choice.
20
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Brindle, Alban, “Exchanges and the OTC Market,” Managing Energy Price Risk, Risk Publications,
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“Commodities,” 1993 Year in Review, Risk, January 1994
Das, Satyajit, Swap and Derivative Financing, Probus Publishing, Chicago, 1993.
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21