Variable is valuable
In energy markets there are many projects whose value depends on the flexibility of being able to delay decision-making until more information becomes available. These decisions can include delaying or accelerating production, postponing entry, scaling production and changing technology, to name but a few.
In many cases the flexibility embedded in some types of project is what drives most of their value. For example, some electricity plants are only economically viable to operate when market prices are very high, otherwise they must be “switched off”. Moreover, gas-fired plants are very valuable because relative to other plants (for instance nuclear and coal) it is easier to ramp up or ramp down according to the level of market prices. Neglecting these embedded real options may seriously undervalue some projects to the extent that they might seem to deliver a negative NPV when in fact they are viable.
In the natural gas and liquefied natural gas (LNG) industry, the value of some assets and financial instruments principally depends on the flexibility that these assets give to their management. The market value of a natural gas storage facility depends on the ability to store gas during times of low prices, and the ability to bring the stored gas to market at times of high prices.
Real options in electricity markets are also key components in project valuation. Power plants that offer operational flexibility derive most of their value from the option to produce electricity when prices are high. These options are valuable because wholesale electricity prices are extremely volatile, but the extreme behaviour of power prices makes electricity prices a difficult commodity to model.
An important feature common to all energy commodities is that their market value depends on the location and the date that the delivery of the commodity takes place. This is particularly important for electricity where date and location are crucial determinants of market clearing prices because electricity must be consumed immediately upon delivery, while consumption of other energy commodities such as gas and oil can be deferred by either postponing delivery or by storing them. In fact, as a consequence of the non-storability of electricity, one can think of electricity delivered over different intervals of the day, or throughout periods of the year, as different products.
A further consequence of not being able to store electricity is that, strictly speaking, there are no electricity spot prices as commonly understood. Market clearing prices must be agreed before delivery at a time when production and demand are not known for sure; this uncertainty is resolved at the time when the physical transaction occurs. In addition, for this market clearing process to function, it is necessary for the system operator to ensure that there is sufficient capacity in the grid to secure transmission from generators to both retailers and consumers. Therefore, the convention in the market and the literature is to treat the day-ahead prices as the spot prices, although their structure is more akin to that of a forward contract. Depending on the market one can find different day-ahead quotes (prices today for next-day delivery) for contracts that dispatch electricity over fixed-time intervals during the delivery day. For example, in the UK it is possible to individually trade each of the 48 half-hours one day prior to delivery, while in the Nord Pool it is possible to individually trade each of the 24 hours one day prior to delivery. Another standard way in which blocks of electricity are bundled is peak and off-peak. Peak hours correspond to a fixed interval of hours for business days characterized by high electricity demand, normally between 8am and 8pm. Off-peak hours belong to the interval between the end of a peak block and the beginning of the next one, and include the 24 hours of weekends’ days and holidays. The day- ahead peak and off-peak contracts specify delivery of 1 MWh for every hour of their corresponding time interval.
The owner of the interconnector capacity needs to schedule the flows according to prevailing market prices and the transmission costs in the two connected locations. In practice these decisions are generally taken on the day-ahead market. Thus, we assume that the decision to use the interconnector to dispatch electricity from A to B, or vice versa, is based on the peak and off-peak market prices observed in the day-ahead market, net of transmission costs. Therefore, every day the owner of the interconnector capacity faces various alternatives; to commit to dispatching electricity the following day from A to B, or from B to A, during the peak and off-peak hours; to decide not to dispatch electricity in any direction during the peak and/or off-peak period.
Valuing interconnection capacity – A strip of real options
Electricity markets have undergone a series of fundamental changes sparked by the liberalisation of this industry. The first stage of liberalisation required privatisation of all or most of the generation assets, as well as privatisation of the transmission grid which transports electricity from the generation points to the end consumer. Another important step in the development of the wholesale electricity markets is to exploit price differentials between locations by building interconnectors which are bi-directional transmission lines connecting the grids of two locations or the grids of two countries. Although interconnecting different grids is at the top of the political agenda in many countries, the decision to build them depends on their financial value.
Electricity prices are characterized by exhibiting extreme volatility and by undergoing abrupt changes (large upward spikes and large downward jumps), as well as fast mean reversion to a seasonal trend. This extreme behaviour is also present in the difference between prices of two locations and explains why interconnecting two markets could be profitable. One of the key features that drives the financial value of an interconnector is that the owner has the right, but not the obligation, to transmit electricity between two locations. Therefore, once it has been built, the financial value of an interconnector is given by a series of real options which are written on the price differential between two electricity markets. Thus, the value of an interconnector is given by a strip of European-style options (Bull Call Spreads) written on the spread between the two markets and the valuation formula is in closed form and is quick to implement.
“A Bull Call is an options strategy that involves purchasing call options at a specific strike price while also selling the same number of calls of the same asset and expiration date but at a higher strike. A bull call spread is used when a moderate rise in the price of the underlying asset is expected. The maximum profit in this strategy is the difference between the strike prices of the long and short options, less the net cost of options. Most often, bull call spreads are vertical spreads.”
Writing contracts on the difference between two or more assets has a long tradition in commodity markets. In the exchanges, all of the commonly traded energy spread options have the difference between a linear combination of energy futures contracts as the underlying. These standard spread option contracts are written on the difference of futures contracts between: electricity and natural gas (the spark spread), electricity and coal (the dark spread), electricity and a fuel including emission allowance costs (the clean spread), crude oil and one of its derivative products (the crack spread), and others.
All energy spread options that are traded in exchanges have payoffs based on futures contracts. Consequently, models proposed in the literature to price options on spreads are designed to capture the stylized features of the underlying futures. Compared to more traditional asset classes such as equity, modelling commodities futures is relatively more involved due to the fact that energy futures have delivery periods (which can range from one day to years) rather than spot or instantaneous delivery.
Value in the European Market
Cartea and González-Pedraz modelled five pairs of European neighbouring markets to value a hypothetical one-year lease of the interconnector and found that depending on the depth of the market, the jumps in the spread can account for between 1% and 40% of the total value of the interconnector. The two markets where an interconnector would be most (least) valuable is between Germany and the Netherlands (between France and Germany). The markets where off-peak transmission between the two countries is more valuable than transmission during the peak times are: France and Germany, France and UK, and the Netherlands and UK.
- How much should we pay for interconnecting electricity markets? A real options approach (Cartea and González-Pedraz, 2010)
- European Network of Transmission System Operators for Electricity
- ENTSO-E data portal – https://www.entsoe.eu/data/data-portal/
- Monthly statistics – https://www.entsoe.eu/publications/statistics/monthly-statistics/