As many have learned the hard way, forecasts, regardless of how sophisticated, are
always wrong.13 So it is not surprising that when the financial markets offered up an
alternative approach it was readily embraced by the energy market players. In other
words rather than try to estimate what the market might do and the implications of
such a move, take the market’s best guess at where future prices are going and then
focus on estimating how wrong it is likely to be.
The two principal components used for this have been the forward curve price
discovery and volatility estimation.
9 Temmuz 2011 Cumartesi
Scenario analysis
As stated at the beginning of this chapter, many observers have been assessing energy
market risk for a significant time. In addition, large numbers of consultantcy firms
who specialize in the forecasting of energy prices to aid companies make investment
or other business planning decisions. In addition, large energy companies will spend
significant amounts of time and money determining their own views of the world.
Most will provide a range of possible scenarios recognizing the difficulty of providing
an accurate forecast and a business can estimate the impact of both positive and not
so positive scenarios. In other words a risk assessment of adverse price movements is
made on a heuristic ‘scenario’-based approach using some form of economic model.
Where no discernible forward curves can be established this is still the most common
form of market risk assessment. One advantage of this approach is that it can link
into known market indicators. For instance, it can take a gas and oil forward curve
and help ‘translate’ it into a power curve. As such, the models can be used as tools
to provide a number of different types of forecasts, and to estimate:
Ω A pure arbitrage model
Ω A new entrant model (assuming ‘potential’ new entrants set forward prices)
Ω A macro model incorporating political, environmental, regulatory and economic
model (e.g. a ‘game theory’ model)
Ω A micro ‘dispatch’ optimization model
The advantage of such an approach is that it can incorporate the important
regulatory or market power issues that can dominate many regional energy markets.
For instance, models that allow for the gradual deregulation of the local distribution
companies and the transition away from cost plus pricing can provide useful insights
into future price movements.
The important aspect of scenario analysis is consistency in the ‘story’ being told
and ‘buy-in’ from senior management early in the process. As such, you need to
establish that the scenarios are plausible, cover the key market risks to the business
and then go through the painstaking process to ensure internal consistency.
market risk for a significant time. In addition, large numbers of consultantcy firms
who specialize in the forecasting of energy prices to aid companies make investment
or other business planning decisions. In addition, large energy companies will spend
significant amounts of time and money determining their own views of the world.
Most will provide a range of possible scenarios recognizing the difficulty of providing
an accurate forecast and a business can estimate the impact of both positive and not
so positive scenarios. In other words a risk assessment of adverse price movements is
made on a heuristic ‘scenario’-based approach using some form of economic model.
Where no discernible forward curves can be established this is still the most common
form of market risk assessment. One advantage of this approach is that it can link
into known market indicators. For instance, it can take a gas and oil forward curve
and help ‘translate’ it into a power curve. As such, the models can be used as tools
to provide a number of different types of forecasts, and to estimate:
Ω A pure arbitrage model
Ω A new entrant model (assuming ‘potential’ new entrants set forward prices)
Ω A macro model incorporating political, environmental, regulatory and economic
model (e.g. a ‘game theory’ model)
Ω A micro ‘dispatch’ optimization model
The advantage of such an approach is that it can incorporate the important
regulatory or market power issues that can dominate many regional energy markets.
For instance, models that allow for the gradual deregulation of the local distribution
companies and the transition away from cost plus pricing can provide useful insights
into future price movements.
The important aspect of scenario analysis is consistency in the ‘story’ being told
and ‘buy-in’ from senior management early in the process. As such, you need to
establish that the scenarios are plausible, cover the key market risks to the business
and then go through the painstaking process to ensure internal consistency.
Estimating market risk
Before we jump into the issues surrounding the difficulties of estimating risk within
the energy sector it is worth putting the different products into some framework with
respect to liquidity. Let us compare the volume, open interest and the term of the
forward contracts in the products traded on the NYMEX (see Table 18.1).
Table 18.1 Products traded on the NYMEX (as of 14 June 1999)
Daily volume Open interest Latest forward
(contracts) (contracts) contract
Crude oil – WTI 51 456 120 068 Dec-05
Heating oil – NY Harbor 15 228 38 815 Dec-00
Gasoline – NY Harbor 15 623 41 230 Jun-00
Natural gas – Henry Hub 23 931 67 860 May-02
Electricity – Palo Verde 121 989 Dec-00
Electricity – COB 144 1 177 Sep-00
Electricity – Cinergy 98 527 Aug-00
Electricity – Entergy 12 343 Feb-00
Electricity – PJM 9 23 Oct-99
Electricity – TVA 0 0 Sep-99
Electricity – ComEd 0 0 Sep-99
Note: The electricity contracts are relatively new: the last contract was only launched
in March 1999. It is unlikely that all the contracts will survive.
Source: NYMEX,CBOT
Given the infancy of the market, only limited liquidity exists in some of the power
products, even where the OTC market has been robust enough to launch a futures
contract. Any price data that is used must therefore be checked closely before
conclusions can be drawn. This is particularly important when looking back at a
significant period of time – many of the electricity markets simply did not exist more
than a year or so ago.
the energy sector it is worth putting the different products into some framework with
respect to liquidity. Let us compare the volume, open interest and the term of the
forward contracts in the products traded on the NYMEX (see Table 18.1).
Table 18.1 Products traded on the NYMEX (as of 14 June 1999)
Daily volume Open interest Latest forward
(contracts) (contracts) contract
Crude oil – WTI 51 456 120 068 Dec-05
Heating oil – NY Harbor 15 228 38 815 Dec-00
Gasoline – NY Harbor 15 623 41 230 Jun-00
Natural gas – Henry Hub 23 931 67 860 May-02
Electricity – Palo Verde 121 989 Dec-00
Electricity – COB 144 1 177 Sep-00
Electricity – Cinergy 98 527 Aug-00
Electricity – Entergy 12 343 Feb-00
Electricity – PJM 9 23 Oct-99
Electricity – TVA 0 0 Sep-99
Electricity – ComEd 0 0 Sep-99
Note: The electricity contracts are relatively new: the last contract was only launched
in March 1999. It is unlikely that all the contracts will survive.
Source: NYMEX,CBOT
Given the infancy of the market, only limited liquidity exists in some of the power
products, even where the OTC market has been robust enough to launch a futures
contract. Any price data that is used must therefore be checked closely before
conclusions can be drawn. This is particularly important when looking back at a
significant period of time – many of the electricity markets simply did not exist more
than a year or so ago.
6 Temmuz 2011 Çarşamba
Other energy-related products – emissions and weather
Two other trading markets have been recently developing that complement energy
trading in the USA: emissions and weather derivatives. Emissions trading become
possible with the introduction of tradable tickets for Sulfur Dioxide (SO2) on a
national basis and Nitrous Oxide (NOx ) on a regional basis. Producers must have
enough allowances to cover production of SO2 and NOx (a by-product from fossil fuelburning
stations, particularly oil and coal stations) and can sell excess allowances to
those requiring additional allowances. The value of such allowances now represents a
significant proportion of production costs and as such have a direct impact on the
pricing in the fuel oil and coal markets. The emissions market is relatively active
through a brokered OTC market and a small number of options have been traded.
Weather derivatives also play an interesting role in the energy markets that are
particularly weather sensitive. A utility’s revenue is obviously dependent on its unit
sales, which are sensitive to the weather. Given this risk, weather derivatives are now
being used by a number of utilities to hedge their exposure to temperature and other
weather-related factors. In particular, swaps against heating degree-days are now
becoming common, and options against, snow fall, snow pack (a price driver for hydrobased
systems), river flow and other weather-related factors have been seen. A number
of energy traders now actively buy and sell weather derivatives which are also of
interest to insurance companies and have obvious applicability beyond energy players.
To date, the market is still at the early stages both in the USA and Europe and contracts
have tended to have a limited payoff structure (a limit on the maximum payout). 536
trading in the USA: emissions and weather derivatives. Emissions trading become
possible with the introduction of tradable tickets for Sulfur Dioxide (SO2) on a
national basis and Nitrous Oxide (NOx ) on a regional basis. Producers must have
enough allowances to cover production of SO2 and NOx (a by-product from fossil fuelburning
stations, particularly oil and coal stations) and can sell excess allowances to
those requiring additional allowances. The value of such allowances now represents a
significant proportion of production costs and as such have a direct impact on the
pricing in the fuel oil and coal markets. The emissions market is relatively active
through a brokered OTC market and a small number of options have been traded.
Weather derivatives also play an interesting role in the energy markets that are
particularly weather sensitive. A utility’s revenue is obviously dependent on its unit
sales, which are sensitive to the weather. Given this risk, weather derivatives are now
being used by a number of utilities to hedge their exposure to temperature and other
weather-related factors. In particular, swaps against heating degree-days are now
becoming common, and options against, snow fall, snow pack (a price driver for hydrobased
systems), river flow and other weather-related factors have been seen. A number
of energy traders now actively buy and sell weather derivatives which are also of
interest to insurance companies and have obvious applicability beyond energy players.
To date, the market is still at the early stages both in the USA and Europe and contracts
have tended to have a limited payoff structure (a limit on the maximum payout). 536
Coal
Coal is often seen as the poor relation in the energy market and the emergence of a
liquid commodity trading market in coal has been very sluggish. One reason for this
is that the market has traditionally sold bespoke long-term contracts to utilities.
These were very specific with respect to quality since many power station boilers
were designed to take particular quality specifications. This was more than just
sulfur and calorific differences, but would also include specifications for chlorine,
ash content, hardness (grindability), sodium, ash fusion temperature, volatile matter,
moisture and others.
Another issue rests with the transport of coal. Coal is an expensive energy product
to transport. For instance, although the cost of mine-mouth coal from an open-cast
area can be as low as $3/tonnes FOB, the delivered cost of that coal could be closer
to $30/tonne. While there is a competitive shipping market for seaborne trade,
railroads are often oligopolistic in nature.
Finally, the market has been traditionally oversupplied by a large number of
fragmented producers. This has led to extreme price competition and a market
traditionally seeing a backwardated forward market. As a result, annualized historical
volatility in this market is very low (10–15%). In addition, the lack of liquidity in
standard products means clear forward curves cannot be easily found.
The coal market is, however, slowly changing. Faced with the challenges of deregulation
and environmental constraints, utilities are moving to buying shorter-term,
more standard coal qualities. These forces have led to some industry and the
development of a coal trading market that is still in its infancy.
A reasonable international trading market exists and this is being complemented
by standardized contracts in the USA. ‘Hubs’ are developing in Powder River Basin,
Appalachia, Illinois Basin, Colorado-Utah and Pittsburgh Seam. Evidencing this
trend, NYMEX has proposed launching a coal contract based on the Big Sandy River
(Appalachia) in 1999.
Some early option and swap trading has taken place with indices being priced off
publications such as Coal Daily in the USA. However, liquidity in these products has
been very limited and, to date, they have not proved to be useful hedging mechanisms
for major producers or consumers.
liquid commodity trading market in coal has been very sluggish. One reason for this
is that the market has traditionally sold bespoke long-term contracts to utilities.
These were very specific with respect to quality since many power station boilers
were designed to take particular quality specifications. This was more than just
sulfur and calorific differences, but would also include specifications for chlorine,
ash content, hardness (grindability), sodium, ash fusion temperature, volatile matter,
moisture and others.
Another issue rests with the transport of coal. Coal is an expensive energy product
to transport. For instance, although the cost of mine-mouth coal from an open-cast
area can be as low as $3/tonnes FOB, the delivered cost of that coal could be closer
to $30/tonne. While there is a competitive shipping market for seaborne trade,
railroads are often oligopolistic in nature.
Finally, the market has been traditionally oversupplied by a large number of
fragmented producers. This has led to extreme price competition and a market
traditionally seeing a backwardated forward market. As a result, annualized historical
volatility in this market is very low (10–15%). In addition, the lack of liquidity in
standard products means clear forward curves cannot be easily found.
The coal market is, however, slowly changing. Faced with the challenges of deregulation
and environmental constraints, utilities are moving to buying shorter-term,
more standard coal qualities. These forces have led to some industry and the
development of a coal trading market that is still in its infancy.
A reasonable international trading market exists and this is being complemented
by standardized contracts in the USA. ‘Hubs’ are developing in Powder River Basin,
Appalachia, Illinois Basin, Colorado-Utah and Pittsburgh Seam. Evidencing this
trend, NYMEX has proposed launching a coal contract based on the Big Sandy River
(Appalachia) in 1999.
Some early option and swap trading has taken place with indices being priced off
publications such as Coal Daily in the USA. However, liquidity in these products has
been very limited and, to date, they have not proved to be useful hedging mechanisms
for major producers or consumers.
1 Temmuz 2011 Cuma
Electricity/power
The electricity market (often described in the USA as the power market) is very
different for one fundamental reason: both storage and transportation are incredibly
expensive.10 Let us briefly describe the nature of the power market from a trading
and risk management perspective.
First, like many products, electricity demand varies significantly throughout the
day, week and year. However, electricity has the same properties as a highly perishable
product in that not only must supply meet demand, but production must meet
demand minute by minute. The result of this unique attribute is that the market
must keep a significant amount of idle capacity in place for start-up when the
demand is there and shut-down when demand recedes. In some cases, this is a
generation station that is already running, ready to meet anticipated customer
demand. In other cases it is plant that may only be asked to start up once every few
years. Typically a local market (or grid system) will keep 15–20% more plant capacity
than it expects to use on the highest hour of demand during a normal year. This will
often represent over double the average demand.
This, coupled with the physical challenges of transporting electricity,11 leads to a
general position of over-supply combined with short periods when the normally idle
plant needs to run. At such peak times, when all the capacity on the system is
needed, spot market prices12 will rise dramatically as plant owners will need to
recover not only their higher cost of running but also their capital costs in a relatively
short period of time. This is exacerbated by the fact that electricity generation is one
of the most capital-intensive industries in the world.
The forward market will, of course, smooth this by assigning probabilities to the
likelihood of the high prices. Higher probabilities are obviously assigned during the
periods when demand is likely to be at a peak and this will generally only occur
during two or three months of the year. In the USA this is generally in the summer.
Thus unless there is a huge over-supply the summer prices will be significantly
higher than the rest of the year. When there is a potential shortage prices will be
dramatically higher, as was seen in the Cinergy market in late June 1998 where
daily prices that trade most of the year at $30/MWh increased to $7000/MWh.
It is these important market characteristics that lead to the extreme seasonality,
jumps, spikes and mean reversion that will be discussed below in the section on
Market Risk. Given the extreme nature of these factors trying to capture them on
one term structure or convenience yield is extremely difficult.
Despite this price uncertainty, a forward market for electricity has developed along
a standard commodity structure. In fact seven exchange contracts, reflecting the
regional nature of power, currently exist at Palo Verde, California/Oregon Border
(COB), Entergy, Cinergy (NYMEX), TVA, ComEd (CBOT) and Twin Cities (M. Grain
Exchange) and PJM. The forward curves for Cinergy is shown in Figure 18.2 compared
to the Henry Hub gas curve.
Figure 18.2 Forward curves for Cinergy compared to the Henry Hub gas curve. (Source: Citizens
Power,June 1999)
Some standard options are traded at the most liquid hubs. These tend to be ‘strips’
of daily European calls based on monthly blocks. However, the bid/ask on such
products are often wide and the depth of liquidity very limited.
Forward curve price discovery – the problems with power
Let us focus on two major differences in power:
Ω Storage First, you have virtually no stack and roll storage arbitrage. In other
words, since you cannot keep today’s power for tomorrow there is no primary
‘arbitrage’ linkage between today’s price and tomorrow’s. There are, of course,
many secondary links. The underlying drivers are likely to be similar – demand,
plant availability, fuel costs, traders’ expectations and general market environment.
But as you move forward in time, secondary links break down quickly and
so does the price relationship. Figure 18.3 shows the forward correlation between
an April contract and the rest of the year. As you can see, almost no relationship
exists between April and October and most of the relationship has evaporated
once you are beyond one month. In other words, the October Cinergy contract
has no more relationship with the April contract than, say, an oil, gas or even
interest rate market.
Ω Transportation Second, you have limited ‘hub basis’ arbitrage. Since there are
numerous logistical limitations on moving electricity it is difficult to arbitrage
between many of the power markets within the USA (never mind internationally).
Even hubs that are relatively close show large variations in the spread between
prices. Figure 18.4 shows some of the correlations between major power hubs in
the USA. Rather than thinking of them as one market, it is more accurate to view
the power market as at least twelve (the final number of hubs is still being
determined by the marketplace) independent markets with some but often little
relationship.
Once you put all these factors together you see a picture similar to the one a global
risk managers in a big bank will have experienced, a huge number of independent
products that need to be combined for risk purposes. Instead of having one forward
curve for US Power, we have up to eighteen independent months for twelve independent
markets, in other words 216 products. This brings both the curse of lack of
liquidity and data integrity for each product and, on the positive side from a risk
perspective, diversity.
Forward curves up to 24 months are traditionally built using daily trader/broker
marks for monthly peak/off-peak prices, with the breakdown, where necessary, into
smaller time periods (down to an hourly profile) using historical prices adjusted for
normal weather conditions. Prices beyond two years are significantly less liquid and
where information is available bid/ask spreads can increase significantly. Forward
price curves (and volatility curves) beyond 24 months thus need to be created through
more of a mark to model rather than mark to market process. As noted above, using
a model to connect price quotes inevitably involved a number of assumptions about
how the market behaves. In power, this involves not just fitting a serious of different
price quotes together, but also filling in the gaps where price quotes are not available.
The price structure will have to make certain model assumptions based on historical
observation about seasonality and the year-to-year transition process. Models
can be bought (such as the SAVA forward curve builder) or, more often, built inhouse.
However, given the developing nature of the market this still tends to be a
relatively manual process to ensure all the relevant market information can be input
into the curve and minimize the error terms.
It needs to be remembered that in making assumptions about the structure of the
curve in this process to estimate the fair value of a transaction that the forward
curve, while objective, unbiased and arbitrage-free, may be unreliable given the
incomplete data sets. Throughout the process it is thus necessary to estimate the
impact of such assumptions and modeling or prudency reserves are likely to need to
be applied against the fair value under these circumstances. The collection of market
data with an illiquid market also becomes a major operational issue with a need to
continuously verify and search for independent data. 534
different for one fundamental reason: both storage and transportation are incredibly
expensive.10 Let us briefly describe the nature of the power market from a trading
and risk management perspective.
First, like many products, electricity demand varies significantly throughout the
day, week and year. However, electricity has the same properties as a highly perishable
product in that not only must supply meet demand, but production must meet
demand minute by minute. The result of this unique attribute is that the market
must keep a significant amount of idle capacity in place for start-up when the
demand is there and shut-down when demand recedes. In some cases, this is a
generation station that is already running, ready to meet anticipated customer
demand. In other cases it is plant that may only be asked to start up once every few
years. Typically a local market (or grid system) will keep 15–20% more plant capacity
than it expects to use on the highest hour of demand during a normal year. This will
often represent over double the average demand.
This, coupled with the physical challenges of transporting electricity,11 leads to a
general position of over-supply combined with short periods when the normally idle
plant needs to run. At such peak times, when all the capacity on the system is
needed, spot market prices12 will rise dramatically as plant owners will need to
recover not only their higher cost of running but also their capital costs in a relatively
short period of time. This is exacerbated by the fact that electricity generation is one
of the most capital-intensive industries in the world.
The forward market will, of course, smooth this by assigning probabilities to the
likelihood of the high prices. Higher probabilities are obviously assigned during the
periods when demand is likely to be at a peak and this will generally only occur
during two or three months of the year. In the USA this is generally in the summer.
Thus unless there is a huge over-supply the summer prices will be significantly
higher than the rest of the year. When there is a potential shortage prices will be
dramatically higher, as was seen in the Cinergy market in late June 1998 where
daily prices that trade most of the year at $30/MWh increased to $7000/MWh.
It is these important market characteristics that lead to the extreme seasonality,
jumps, spikes and mean reversion that will be discussed below in the section on
Market Risk. Given the extreme nature of these factors trying to capture them on
one term structure or convenience yield is extremely difficult.
Despite this price uncertainty, a forward market for electricity has developed along
a standard commodity structure. In fact seven exchange contracts, reflecting the
regional nature of power, currently exist at Palo Verde, California/Oregon Border
(COB), Entergy, Cinergy (NYMEX), TVA, ComEd (CBOT) and Twin Cities (M. Grain
Exchange) and PJM. The forward curves for Cinergy is shown in Figure 18.2 compared
to the Henry Hub gas curve.
Figure 18.2 Forward curves for Cinergy compared to the Henry Hub gas curve. (Source: Citizens
Power,June 1999)
Some standard options are traded at the most liquid hubs. These tend to be ‘strips’
of daily European calls based on monthly blocks. However, the bid/ask on such
products are often wide and the depth of liquidity very limited.
Forward curve price discovery – the problems with power
Let us focus on two major differences in power:
Ω Storage First, you have virtually no stack and roll storage arbitrage. In other
words, since you cannot keep today’s power for tomorrow there is no primary
‘arbitrage’ linkage between today’s price and tomorrow’s. There are, of course,
many secondary links. The underlying drivers are likely to be similar – demand,
plant availability, fuel costs, traders’ expectations and general market environment.
But as you move forward in time, secondary links break down quickly and
so does the price relationship. Figure 18.3 shows the forward correlation between
an April contract and the rest of the year. As you can see, almost no relationship
exists between April and October and most of the relationship has evaporated
once you are beyond one month. In other words, the October Cinergy contract
has no more relationship with the April contract than, say, an oil, gas or even
interest rate market.
Ω Transportation Second, you have limited ‘hub basis’ arbitrage. Since there are
numerous logistical limitations on moving electricity it is difficult to arbitrage
between many of the power markets within the USA (never mind internationally).
Even hubs that are relatively close show large variations in the spread between
prices. Figure 18.4 shows some of the correlations between major power hubs in
the USA. Rather than thinking of them as one market, it is more accurate to view
the power market as at least twelve (the final number of hubs is still being
determined by the marketplace) independent markets with some but often little
relationship.
Once you put all these factors together you see a picture similar to the one a global
risk managers in a big bank will have experienced, a huge number of independent
products that need to be combined for risk purposes. Instead of having one forward
curve for US Power, we have up to eighteen independent months for twelve independent
markets, in other words 216 products. This brings both the curse of lack of
liquidity and data integrity for each product and, on the positive side from a risk
perspective, diversity.
Forward curves up to 24 months are traditionally built using daily trader/broker
marks for monthly peak/off-peak prices, with the breakdown, where necessary, into
smaller time periods (down to an hourly profile) using historical prices adjusted for
normal weather conditions. Prices beyond two years are significantly less liquid and
where information is available bid/ask spreads can increase significantly. Forward
price curves (and volatility curves) beyond 24 months thus need to be created through
more of a mark to model rather than mark to market process. As noted above, using
a model to connect price quotes inevitably involved a number of assumptions about
how the market behaves. In power, this involves not just fitting a serious of different
price quotes together, but also filling in the gaps where price quotes are not available.
The price structure will have to make certain model assumptions based on historical
observation about seasonality and the year-to-year transition process. Models
can be bought (such as the SAVA forward curve builder) or, more often, built inhouse.
However, given the developing nature of the market this still tends to be a
relatively manual process to ensure all the relevant market information can be input
into the curve and minimize the error terms.
It needs to be remembered that in making assumptions about the structure of the
curve in this process to estimate the fair value of a transaction that the forward
curve, while objective, unbiased and arbitrage-free, may be unreliable given the
incomplete data sets. Throughout the process it is thus necessary to estimate the
impact of such assumptions and modeling or prudency reserves are likely to need to
be applied against the fair value under these circumstances. The collection of market
data with an illiquid market also becomes a major operational issue with a need to
continuously verify and search for independent data. 534
29 Haziran 2011 Çarşamba
Gas forward curve
Price discovery in gas is not as transparent as in the oil market. The transport and
storage capabilities of the gas market is relatively inflexible compared to the oil
market. The market is also more regional7 than the oil market, with international
trade being restricted by pipeline costs and LNG (liquefied natural gas) processing
and transport costs.
The US gas trading market (although probably the most developed in the world) is
much more fragmented than in the oil market with a large number of small producers,
particularly at the production end. Given the inability to hedge through vertical
integration or diversity this has resulted in a significant demand for risk management
products. The market after the deregulation in the 1980s and early 1990s has been
characterized by the development of a very significant short-term market. This sets
prices for a thirty-day period during what is known as ‘bid week’.8 The prices
generated during this ‘bid week’ create an important benchmark9 against which
much of the trading market is based.
The futures contracts in gas have been designed to correspond with the timing of
bid week, the largest and most developed contract being known as Henry Hub. This
has been quoted on NYMEX since 1990, supports a strong options market and
extends out three years on a relatively liquid basis. Basis relationships between
Henry Hub and the major gas-consuming regions within the USA are well established
and, in the short term, fairly stable. The OTC market supports most basis locations
and a reasonable option market can be found for standard products. It is worth
noting that, credit aside, in energy the value of the futures market and the OTC
forward market is the same, albeit the delivery mechanisms are different. This is
true because there is no direct correlation to interest rates and the EFP (Exchange
for Physical) option imbedded in the futures contract.
In gas, storage costs play a critical role in determining the shape of the forward
curve. A variety of storage is employed from line pack (literally packing more gas
molecules into the pipe) to salt caverns and reservoirs (gas can be injected and
extracted with limited losses) and the pricing and flexibility of the different storage
options varies significantly.
As a general rule, the gas market stores (injects) during seven or eight ‘summer’
months and extracts during the winter months. Significant short-run price movements
occur when this swing usage is out of balance. In these circumstances gas
traders will spend much of the time trying to predict storage usage against their
demand estimations it order to determine what type of storage will be used during
the peak season and thus help set the future marginal price.
Like the oil market, the gas markets exhibit mean reversion, and are subject to
occasional jumps due to particular ‘events’ such as hurricanes shutting down
supplies. But most importantly, despite this storage, gas remains significantly more
seasonal in nature than most of the oil market.
Basis trading from Henry Hub plays a vital part in the market with differentials to
the major consumption zones being actively traded in the OTC market. These basis
prices are less stable than those seen in the oil market given the more constrained
transport infrastructure and volatility in demand. As a result, the monitoring of these
basis relationships under normal and extreme conditions becomes critical.
Risk managers should be very wary of basis traders or regional traders marking
their books against a contract in a different region such as Henry Hub who are
seen to have large ‘book’ profits based on future positions. There have been a
number of instances where such regional traders have had their positions wiped
out overnight when the correlations have broken down under extreme market conditions.
In other words, you need to ensure that the higher volatility or ‘spike potential’
in less liquid regional markets compared to a large liquid hub has been reflected
in the pricing.
Historical ‘basis’ positions may also fundamentally change as the pipeline positions
change. For instance, the increasing infrastructure to bring Canadian gas to the
Chicago and North US markets could significantly change the traditional basis
‘premium’ seen in these markets compared to Henry Hub.
While most trades up to three years are transacted as forward or future positions
an active swap market also exists, particularly for longer-term deals where the
counter-parties do not want to take on the potential risks associated with physical
delivery. These index trades are generally against the published Inside FERC Gas
Market Report Indices although Gas Daily and other publications are also used
regularly. It is necessary to be aware that indices at less liquid points may not be
based on actual transaction prices at all times, but may be based on a more
informal survey of where players think the market is. This may lead to indices being
unrepresentative of the true market. 531
storage capabilities of the gas market is relatively inflexible compared to the oil
market. The market is also more regional7 than the oil market, with international
trade being restricted by pipeline costs and LNG (liquefied natural gas) processing
and transport costs.
The US gas trading market (although probably the most developed in the world) is
much more fragmented than in the oil market with a large number of small producers,
particularly at the production end. Given the inability to hedge through vertical
integration or diversity this has resulted in a significant demand for risk management
products. The market after the deregulation in the 1980s and early 1990s has been
characterized by the development of a very significant short-term market. This sets
prices for a thirty-day period during what is known as ‘bid week’.8 The prices
generated during this ‘bid week’ create an important benchmark9 against which
much of the trading market is based.
The futures contracts in gas have been designed to correspond with the timing of
bid week, the largest and most developed contract being known as Henry Hub. This
has been quoted on NYMEX since 1990, supports a strong options market and
extends out three years on a relatively liquid basis. Basis relationships between
Henry Hub and the major gas-consuming regions within the USA are well established
and, in the short term, fairly stable. The OTC market supports most basis locations
and a reasonable option market can be found for standard products. It is worth
noting that, credit aside, in energy the value of the futures market and the OTC
forward market is the same, albeit the delivery mechanisms are different. This is
true because there is no direct correlation to interest rates and the EFP (Exchange
for Physical) option imbedded in the futures contract.
In gas, storage costs play a critical role in determining the shape of the forward
curve. A variety of storage is employed from line pack (literally packing more gas
molecules into the pipe) to salt caverns and reservoirs (gas can be injected and
extracted with limited losses) and the pricing and flexibility of the different storage
options varies significantly.
As a general rule, the gas market stores (injects) during seven or eight ‘summer’
months and extracts during the winter months. Significant short-run price movements
occur when this swing usage is out of balance. In these circumstances gas
traders will spend much of the time trying to predict storage usage against their
demand estimations it order to determine what type of storage will be used during
the peak season and thus help set the future marginal price.
Like the oil market, the gas markets exhibit mean reversion, and are subject to
occasional jumps due to particular ‘events’ such as hurricanes shutting down
supplies. But most importantly, despite this storage, gas remains significantly more
seasonal in nature than most of the oil market.
Basis trading from Henry Hub plays a vital part in the market with differentials to
the major consumption zones being actively traded in the OTC market. These basis
prices are less stable than those seen in the oil market given the more constrained
transport infrastructure and volatility in demand. As a result, the monitoring of these
basis relationships under normal and extreme conditions becomes critical.
Risk managers should be very wary of basis traders or regional traders marking
their books against a contract in a different region such as Henry Hub who are
seen to have large ‘book’ profits based on future positions. There have been a
number of instances where such regional traders have had their positions wiped
out overnight when the correlations have broken down under extreme market conditions.
In other words, you need to ensure that the higher volatility or ‘spike potential’
in less liquid regional markets compared to a large liquid hub has been reflected
in the pricing.
Historical ‘basis’ positions may also fundamentally change as the pipeline positions
change. For instance, the increasing infrastructure to bring Canadian gas to the
Chicago and North US markets could significantly change the traditional basis
‘premium’ seen in these markets compared to Henry Hub.
While most trades up to three years are transacted as forward or future positions
an active swap market also exists, particularly for longer-term deals where the
counter-parties do not want to take on the potential risks associated with physical
delivery. These index trades are generally against the published Inside FERC Gas
Market Report Indices although Gas Daily and other publications are also used
regularly. It is necessary to be aware that indices at less liquid points may not be
based on actual transaction prices at all times, but may be based on a more
informal survey of where players think the market is. This may lead to indices being
unrepresentative of the true market. 531
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