Indeed electricity does have its own set of quirks. In the short term, supply and demand must be continuously met and there is no (or very little) provision for "stock piling." Moreover, the electricity supplier or distributor has much less freedom to manoeuvre than his counterpart in manufacturing. The size of the distribution system (the transmission network) is fixed and there is no scope for ad hoc additions at times of peak demand. There must also be a certain geographical balance between supply and demand, partly to avoid reaching capacity limits on transmission lines and partly to avoid the possibility of the transmission system -- or parts of it -- becoming unstable.
In the longer term, both demand and supply change slowly and the market responds sluggishly to price changes -- it is inelastic, in economic terms. In fact the planning, control and distribution of transmission networks is arguably one of the most sophisticated tasks in the industrialised world. If it is undertaken properly by a large vertically integrated utility, then the system as a whole -- generation, transmission and distribution -- can be optimised, taking into account all the factors shown in the diagram on the facing page. Such utilities balance, for example, the cost of transporting fuel against the cost of reinforcing transmission networks, should power stations be built near coalfields. The key question, however, is just how efficient are large vertically integrated utilities?
If the market is "liberalised," all the formal links of a vertically integrated institution are cut and must be replaced by market mechanisms. If these are poorly structured, however, there is a danger that although the individual components, such as generation, may be optimised, the net result could be less efficient -- unless the market is carefully regulated to ensure that liberalising measures are not self-defeating.
In setting forth its proposals for an internal energy market, the European Commission aims to encourage greater use of national interconnections. The market also envisages that distribution networks become "common carriers," open to all, on terms which are clear, fair and transparent. The Commission notes that inter-state electricity transfers accounted for less than 5% of electricity consumption in the European Union. This despite the need to constantly balance supply with demand where the more opportunities there are for an electricity distributor to obtain supplies from alternative sources, the better the chances of managing the system efficiently and keeping costs down. Efficiency in electricity distribution systems is promoted by running as many power stations as possible continuously at full output; operation at partial loads reduces efficiency and pushes up costs. By encouraging transfers across borders, the internal market is likely to lead to greater efficiency and a reduction in energy costs.
The UK experience
Although many of the concepts currently under discussion have not yet been tested in the real world, the UK experience enables some of the claims for liberalisation to be tested. Privatisation of the electricity industry in the UK involved a radical restructuring of the industry and the separation of the generation, transmission and distribution functions. In addition, a trading mechanism for energy was set up based on bids submitted by all the generators -- the so-called "pool." This is a modification of the merit order despatch system used by many utilities (see box on next page).
The most positive aspect of privatisation for the consumer has been the opening up of the electricity generation market to all comers which, in the long term, is expected to put a downward pressure on electricity prices. A second positive benefit is that most customers -- but not yet the domestic market -- are free to purhase power from whoever they wish, a generator, distributor, or the spot market which reflects price variations on a half-hourly basis. A good example of how this works in practice is provided by Seeboard, the utility serving southeast England, which secured a valuable contract to supply Heathrow Airport, formerly a customer of the local utility.
There have, however, been problems. Much of the new generation is located in the north, exacerbating power transfer and system security problems. The National Grid Company -- which operates the transmission network -- is now concerned that the system is no longer optimised and higher costs are being incurred as a result. In addition, the distributors were allowed to generate, and so moved partially towards becoming vertically integrated monopolies. These monopolies are contrary to the principle of a "free" market and, not surprisingly, it has been argued that not all their generation is justified in economic terms.
The workings of the "pool," too, are far from smooth. Only about 15% of the electricity supply in England and Wales is genuinely traded through the pool, the rest is the subject of direct contracts between the generators and the distributors, or the major users. Moreover, capacity payments from the pool, which should have been triggered automatically, have been somewhat irregular and certainly insufficient for generators to recover the fixed costs of their plant, as was the intention. The reason for this is that the so called "dash for gas" has led to a surplus of plant, mostly in the north.
Since large industrial users and domestic consumers have seen their prices rise faster than inflation, the UK experience can be cited as demonstrating weaknesses in the case for liberalisation. However, at least some of the problems are the result of political interference with market mechanisms. The prices of all the main fuels have been subject to tampering. Nuclear and coal both have "protected status" and the price of gas was also held down for a time, accelerating the "dash for gas" and contributing to the concentration of a surplus of plant in the north. As the price of coal has since fallen it is quite possible that dearer gas plant -- many of which have "must run" contracts -- will be scheduled in preference to cheaper coal plant
Where does wind fit in?
At present, payments for wind energy are almost universally made on the basis of fixed energy prices, either set on the basis of the costs of wind (as in the case of the UK) or, as in the case of Denmark and elsewhere, at a fixed proportion of the domestic electricity price.
The latter approach implicitly recognises that wind has a higher value than centralised generation but there have been relatively few attempts to assess the true value of wind energy. The tendency has been to regard wind energy as being produced in much the same way as energy from a large thermal power station and its value has been assessed in line with the marginal costs of the fuel it displaces. Similar thinking, post privatisation in the UK, has assigned wind a valuation at pool price. However, there is an increasing recognition that local generation, which feeds into the low voltage networks, should be assigned a higher value since the avoided costs to a utility should include provision for the transmission costs associated with delivering an equivalent amount of energy from a centralised power system via a number of transformers and the high voltage transmission network. In the UK, generation costs average about £0.034/kWh, transmission costs add about £0.005/kWh and the average value of electricity leaving the 132 kV system is about £0.048/kWh. A recent study by the European Commission has assigned distributed generation a value 25% higher than centralised generation.
This argument presupposes that wind would attract a capacity credit which is a vexed issue. However, most utilities who have studied the problem have concluded that such credits are allowable and the UK pool system should pay these automatically to all generators supplying power at the time of periods of maximum demand. Wind would therefore attract a capacity credit automatically and the fact that the balance between capital and running costs is different from that of thermal plant is of little relevance.
If -- as has happened in the UK -- transmission systems are no longer optimum after liberalisation, wind is strongly placed to exploit this situation, by virtue of its short construction time, the fact that it is dispersed, can connect into low voltage networks and -- depending on the type of machine -- can be used for power factor correction. All these aspects enhace its value. Taking this argument a step further, since all markets are inherently unpredicable, any technology which has built-in flexibility, such as wind power, will be an attractive option for investment.
There are two other ways in which wind energy may benefit from current trends in the electricity market. At first sight, direct contracts between wind farm operators and energy users seem difficult to realise, but these would simply mirror the trend now emerging in other areas of the market. In the UK, a business with a load of 100 kW or more can now buy electricity from any source. As commerce and agriculture pay around £0.07 (about ten US cents) a unit, it may make sense for wind farms to sell their output locally. The local utility would charge for the use of its system, but the arithmetic may balance. Such contracts would probably need to be backed up with supplies from a conventional source, but legislation provides for this and costs could be reduced by taking advantage of another emerging trend -- demand side management. DSM allows the consumer the freedom to have his supplies curtailed (either actively or passively) in response to price signals. As a result, power systems may become less sensitive to demand variations and more able to accommodate wind.
The market mechanisms under discussion in the US mirror the UK pattern and aim to give customers freedom to place contracts with any supplier. This gives suppliers the stability they need for long-term planning and will clearly encourage the more efficient -- and cheaper -- suppliers to thrive. However, UK experience indicates there are drawbacks. Critics of UK privatisation warned of cyclic swings in the plant margin. They seem to have been right. One of the concerns about "free" markets is whether they are self-regulating in this respect. A large thermal-planted utility must have a plant margin of about 25% -- that is 25% more capacity than maximum demand. If it is less, there is a greater risk of demand not being met, if it is more the plant will not be properly utilised, and hence costs will be too high overall. Although plant is now being shut down in the UK to correct the current surplus, it does not follow that this will lead to the most economic solution.
Since the American utilities are not state-owned, the process of liberalisation is likely to be even more protracted and complex than in the UK. Many problems can be foreseen, not least what happens to the renewables. In one respect, however, wind is already on a firmer commercial footing thanks to the one-and-a-half cent production incentive payment for each kilowatt hour produced. But this does not guarantee wind a place at the table of generators. The key is intelligent regulation -- on both sides of the Atlantic -- which not only focuses on narrow economic criteria, but takes into account issues such as conservation, energy efficiency and reduction of polluting emissions. In other words, the broader economic issues.