Historically, electrical energy from wind turbines was not competitive in commercial markets with other forms of generation, particularly the use of a combined cycle gas turbine (CCGT) plant burning natural gas. Hence, in order to take account of external costs, and to meet commitments to reduce CO2 emissions, various support mechanisms have been used by governments to encourage the development of wind power as well as other forms of renewable energy. These support mechanisms, together with the markets for electrical energy, are subject to very rapid change but the main principles are described.
Perhaps the most obvious approach to support wind power is to require fixed premium tariffs to be paid for all power generated by renewable sources. This was the basis for the 'Public Utilities Requirement to Purchase Act (PURPA) introduced in the USA in 1978 but abandoned in the late 1980s and the German 'Electricity Feed-in-Law'. A similar approach was adopted in Spain and Denmark for a period. The PURPA legislation was based on 'avoided cost', i.e., the marginal cost of generation from an alternative plant was paid. This varied from state to state but in California in the early 1980s the avoided cost was calculated to be US$0.06/kWh. This rate coupled with an inflation factor and tax incentives led to some 2000 MW of wind turbine capacity being installed between 1981 and 1989. However, development slowed dramatically as gas fired CCGT plant reduced the avoided cost. The German 'Electricity Feed-in-Law' required the utility to purchase wind generated power at 90 percent of the average price paid by all customers. As the bulk wholesale price of electrical energy is typically a third of the retail price it may be seen that this was a most attractive arrangement for wind farm operators. The cost of the 'Feed-in-Law' was borne by the utilities who made efforts to have the law rescinded. Denmark also operated a similar system with the utilities paying 7085% of the retail price for wind-generated power. This rate, together with tax incentives, encouraged individuals and co-operatives to buy wind turbines and some 75% of turbines in Denmark are owned in this way.
The general effect of this type of premium tariffs is to provide very considerable stimulus to the development of wind power. However, this form of support may not apply strong downward pressure on wind farm costs. Hence, the price paid per kWh in Germany in 2000 was approximately double that available under the last round of the Non Fossil Fuel Obligation in the UK which was based on an auction of renewable contracts. However, it should be noted that the UK sites generally had higher wind speeds than many of those in Germany. It is difficult to reconcile the concept of fixed premium tariffs with that of a deregulated market for electrical energy and so this form of support may not be acceptable to European Union competition authorities in the long term.
Both the UK and Ireland have used a process based on competitive auctions of fixed-term, fixed-price power purchase contracts. This type of support mechanism has the effect of providing very considerable downward pressure on costs and also offers the developer stability as the price is guaranteed for the long term (in the UK for 15 -20 years with an additional allowance for general inflation). The major disadvantages are that: (1) the auctions are held intermittently and so there is no continuous market for the turbine manufacturers; (2) very considerable costs are incurred in bidding which may be wasted if the bid is unsuccessful; and (3) there is little penalty on not constructing the projects and so some bids may be unrealisti-cally low. The UK Non Fossil Fuel Obligation (NFFO) was remarkable in reducing the price for wind energy by two-thirds from 1989 (9p/kWh) to 1999 (2.9p/kWh) although the 1989 contracts were for only 9 years while the 1999 contracts were for 20 years. However, only limited capacity was actually built. The NFFO has now been abandoned and has been replaced by an obligation on electricity suppliers to provide a percentage of their energy from renewable sources and a system of tradable 'Green Certificates'.
The use of some form of 'Green Certificates' together with an obligation on users or suppliers to ensure that a fraction of their electrical energy comes from renewable sources is presently seen as the most likely future development for support mechanisms. There need be no physical connection between the 'Green Certificate' and the electrical energy and the 'Certificates' may be traded in one market and the energy (kWhs) in another. The advantages of this type of arrangement are that: (1) it is compatible with a competitive market for electrical energy; (2) it is likely to exert a downward pressure on costs; (3) it may develop a large market attractive to major companies; and (4) the full range of market instruments (e.g., futures markets) may be developed.
If Government support mechanisms are to be based on some form of 'Green Certificates' then the wind farm operator is still left with the problem of selling the energy. In markets for electrical energy, the wholesale price varies considerably throughout the day and year and so the wind farm operator is likely to be exposed to volatile prices. After privatization of the electricity supply industry in the UK a pool-type trading arrangement was developed whereby any generator might sell into the pool at the system marginal price of generation. Additional contracts made outside the pool, the so-called 'contracts for differences' were used by many conventional generators to manage the uncertainty of the variation of the pool price but the availability of the pool marginal price always provided a reference price for power. However, the pool is now being superseded by a system of bilateral energy contracts which will place a very high premium on controllability and predictability of generating plant. The New Electricity Trading Arrangements (NETA) will comprise three elements: (1) long-term bilateral contracts between generators, large customers and those supply companies serving smaller customers; (2) a short-term market, 24-3.5 hours ahead of delivery, between generators, customers and suppliers; (3) a balancing mechanism, 3.5 h ahead of delivery, operated by the National Grid Company (the Transmission Operator). Failure to match contracted demand with supply will probably result in higher costs in the short-term market or balancing market. This is likely to provide considerable difficulties for wind farm operators due to the intermittent and unpredictable nature their output.
Some consumers are prepared to pay a premium for electrical energy provided from renewable sources. This 'Green Pricing' is being developed in Germany and the UK but the extent of the market demand it is not yet clear. There are also difficulties with accrediting which generating plants are 'green' and suitable for such a scheme.
In parts of the USA 'net metering' is allowed for some small wind turbines. This is the use of a single electricity meter which operates backwards to reduce the measured kWh at times of export from the wind turbine and its local load, typically a house or farm. In economic terms this approach can be criticized as it ignores the variation with time in the value (and price) of electrical energy and also that a large element of the cost of electrical energy delivered to the customer is associated with the transmission and distribution facilities and their management.
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