Meanwhile, at a seminar organised by renewables group Asociación de Productores de Energías Renovables (APPA), wind project developers demonstrated confusion over which one of the three tariff options to choose. They have three months to do make up their minds.
Regardless of the option picked, all wind plant operators will be required to schedule generation on the system ahead of time, making it necessary for them to develop wind production forecasting techniques by January 2005, at the latest. This constitutes the most radical element of the new regulation and responds to national grid operator demands to reduce overall generation uncertainties from increased amounts of wind power (Windpower Monthly, December 2004). "Forecasting is the document's weak point," says Martínez. "Experience in forecasting is low and the sector is still researching models." Nevertheless, PEE's Alberto Ceña believes "the permitted margins of forecasting error are manageable."
From last month, new plant coming online must drop into one of two new tariff options. The first is a guaranteed fixed tariff for prioritised wind, meaning local electricity distributors must buy up all wind generation, regardless of demand. The second is an incentive kilowatt hour payment for selling production on the wholesale electricity market at whatever price can be achieved. Operators may switch from one option to the other each year. The tariff law also includes a third transition option for existing wind plant.
The new fixed tariff option is set at 90% of average electricity sector billings-referred to as the Average Electricity Tariff (AET) -- for the first five years of operation. The rate then falls to 85% of the AET for the following ten years dropping to 80% for the rest of the wind plant's life. "We now have the long term stability previously lacking and vital for attracting finance," says Martínez. APPA's Manuel de Delás is dubious: "I don't know of any regulation that has lasted 20 years [the expected average life cycle of wind plant] as the new regulation promises and, therefore, can't see how it offers more stability than the regulation in force to date." Under the previous tariff model, the incentive rates were regularly revised, with developers not knowing from year to year what the future price might be.
Delás's words are especially relevant for the operators of existing wind plant who can choose a third transition option. This allows them to cling to the old tariff model, for prioritised wind, to 2010. They may switch to one of the two new tariff options at any time but they cannot switch back again. By far the most popular option under the old tariff was to sell output at the going "market" price and additionally earn an incentive payment rather than accepting a flat rate total price. The transition arrangement maintains former earning parameters. Operators receive the average hourly reference price from the "electricity pool," plus an incentive adjusted annually to keep total earnings at 90% of the AET. The old regulation's less popular fixed-tariff option is no longer available.
Even plant operators in transition between the old system and the new must introduce production scheduling by 2005. Both the transition and fixed tariff options allow production to vary by 20% either side of the 24-hour forecast. Beyond that, penalties are incurred, set at 10% of the AET, or EUR 7/MWh. Given the wide margin of permissible scheduling error, Ceña says cheaper, low-resolution meteorological forecasting models, or "even clever guess work," will be sufficient to avoid penalties. Furthermore, operators may vary their forecast, lodged with the local distributor the previous day, at intervals throughout the next day until an hour before production.
More precise forecasting, however, is needed under the second tariff option, which offers a production incentive for each kilowatt hour sold into the wholesale market. Wind plant operators playing the market alongside conventional generators will be subject to the same conditions as their competitors, with close to zero tolerance for imbalances and incurring the same imbalance penalties which result when power surplus to that scheduled has to be sold at a lower rate than the price of buying in power to make up a short fall. The penalties average EUR 3/MWh.
The big decision for wind plant operators is whether they should run the risk of giving up the right to being classed as prioritised production -- which obliges distributors to buy all wind under the fixed tariff option -- in return for the potential rewards to be had from playing the market. The production incentive for entering the market has been increased in the new legislation compared with the draft bill circulated in February. To top up the price for wind achieved on the wholesale market, an incentive payment for each kilowatt hour is set at of 50% of the AET -- a 10% increase.
In weighting up the options, wind plant operators and developers must also take into account incentives for providing grid support services. All wind plant operators can now earn extra by providing reactive power control and adding equipment that enables wind plant to ride through grid faults, rather than tripping off the system at every grid hiccup. For ride-through capability, an incentive of 5% of the AET is on offer, though only for the first four years of providing such grid support. Martínez says Ecotècnia is already installing machines with ride-through capability and knows that other manufacturers are geared up to do so.
But the overwhelming message from delegates at APPA's seminar last month was that most developers and operators need at least a year to weigh up the pros and cons before deciding which of the options to go for. APPA's Enrique Albiol adds: "It is probable that some operators will group together to go to market, aggregating production schedules [from plant] across the country in order to smooth out imbalances." Ceña believes aggregation will consolidate wind as a mainstream power sector.