Scheduling windpower? Is it not irrational!

02nd July 2013  To: 02nd July 2013

Scheduling windpower  Is it not irrational  

Jami Hossain 


There was a time when we used to pay the same price for electricity, whatever be the time of the day of use.  Scheduling and forecasting, which has become common terminology was perhaps only carried out at Load Dispatch Centers.   The pricing is still uniform for domestic and agricultural sectors but in the industrial and commercial sectors, electricity at different times of the day comes at different prices.  


Let us examine as to why these changes have taken place in the electricity sector and what has been their influence on the regulatory matters concerning wind energy? To many people associated with the power sector, the question may appear as absurd or perhaps hilarious.  Nevertheless, in the hope of gaining better insights, we delve deeper into this question. 


The power system which is a composite entity comprising of different kinds and capacities of individual power-plants, operates round the clock to meet a varying load demand.  The load demand is fluctuating all the time and when the load demand is more than generation, the rotors of the generators slowdown resulting in a fall in frequency. At such times the grid is in need of more power injection. However, when the load is less than generation the rotors of generators start speeding up resulting in a rise in frequency. At such times grid is not in need of any additional power injection from the grid.


When the load demand is less than the peak demand some conventional coal based thermal power plants operate under part-load conditions or no load conditions. Coal based thermal power plants are not shut down completely under low load conditions they are maintained under hot but no load conditions so that they can quickly come on line when the load demand picks-up. Under no load or part load conditions the operation of the plants is not optimal, they continue to consume fuel and emit CO2.  The power system also consists of  other types of thermal generators such as liquid fuel and gas that can start  generating in a matter of few minutes, however, the cost of  operating these thermal plants is generally higher than that of coal based plants. Therefore, these are meant to take care of short peaks in load demand. The system also consists of hydro projects, which are generally cheaper to operate and can also take care of quick fluctuations in load demand.


Under low load conditions many coal based thermal power plants are running in hot condition. The capacity of the system to supply electricity is more and demand is less and as a result the prices are low.  On the other hand under peak  load conditions, the generating units in the system operate at full load conditions close to the optimal state. High cost generation such as diesel based generation is resorted to in order to meet the demand. In India it is customary to shut off some loads as the system cannot meet the entire demand. At such times of the day electricity comes at a premium.


How much capacity should be kept operational and how many power plants should be kept in hot or running conditions is an assessment made in the conventional power system at different levels i.e., State  and Center. This assessment should normally based on load forecast. Some generation capacity should be kept idle as spinning reserve which comes into operation in case of an unplanned shut-down of a power plant.  However, in India generally peaking load and energy requirements are higher than the total generating capacity. As a result, often there are many loads that are thrown out of the system (power shut-down).


While earlier the entire power system used to be a single monolith trying to meet the electricity demand, today’s  power system is a composite of many independent entities such as transmission companies, DISCOMs, generators,  IPPs, electricity traders, licensees, franchisees and bulk consumers. All of them are bound by contracts and regulations.  


Now imagine the system with multiple units generating electricity in a commercial mode. Electricity is being supplied under different kinds of arrangements from short-term to long-term, firm and non-firm, peaking electricity, only night and only day.  Imagine in this scenario Generator A has entered into a contract to supply Y megawatts of electricity at peak time for two hours to a consumer B.  However it so happens that the consumer B instead of  drawing power Y, draws power Y+x (Say, Scenario 1). Now this power ‘x’ has been drawn from the system in an unscheduled manner. It is also termed as Unschduled Interchange (UI).  In another scenario (Say, Scenario 2)  A supplied Y-x and B consumed Y as per its contract with A.


Multiple entities, varying load demand and issues such as UI require a system of commercial settlement. The system adopted by the regulatory commissions is that of  Unscheduled Interchange (UI), which is a way of commercially reconciling electric power-flows from multiple generators into the grid.  Under the UI mechanism, the price of  unscheduled electricity injection or drawl is pegged to system frequency.  In the example above under Scenario 1, B should compensate the system for extra power drawl (x) at a price that is derived from the prevailing frequency. Similarly, in Scenario 2, A should compensate the system for having supplied less power (x) at  the prevailing frequency. Now under the UI mechanism, as per the regulations every generator must schedule power injection over 15  minute blocks and must inform the system operator (National, State or Regional) Load Despatch Center a few hours ahead.  The necessity of scheduling primarily comes from the need for commercial settlement.  This, however is quiet problematic for renewable energy generators, particularly windfarms that generate electricity varying with wind speeds.  In order to schedule power, a windfarm owner is required to forecast output  several hours ahead in time. It has been found that this is rather difficult considering the fact that  each wind turbine is about 2 MW in capacity and forecasting even if it is attempted at Sub-station level is easier said than done. With today’s technology Forecasting and Scheduling is a major barrier to windpower integration with the grid. Not only that, it is also a major management hassle for  both the windfarm owners as well as the State Load Dispatch Center (SLDC).


Now let us look at the issue and the need for scheduling and forecasting again.  The wind is not the only variant in the system, the other variants are load demand and reliability of the conventional generators as well as the transmission links.  The load demand varies significantly over the day and entire management and operation of the grid is  about keeping it in readiness to meet the eventualities created by this variation. The SLDC have a way of forecasting load demand. If for a moment we were to set aside the issue of commercial settlement, wind or other renewable energies can be seen as adding additional variation to existing variation of load demand.  Generation from wind plants takes place in a geographically dispersed manner and most of wind energy generation gets utilized at load centers near the windfarms and in case of large windfarms, some power flows into the regional grid. Therefore, fundamentally wind power is reducing the load demand on the conventional power system.  The net of load demand after generation from wind plants is the demand that has to be met by the conventional part of the power system. Therefore, wind can be treated as a negative load. If we look at wind generation in this manner, what we need to forecast is the net or residual load demand after accounting for wind generation at aggregate levels.  The system can still perform as it was performing earlier when there was no wind injection taking place.


The need for Scheduling and Forecasting emanates primarily due to two main reasons 1) the way we operate the grid and the constraints of keeping some power plants under hot condition and 2) from the need to carry out commercial settlement and reconciliation of power injected into the grid.  Now both of these aspects are a reflection of  the technology deployed, manner in which the system is  operated and the design of the commercial settlement mechanism.  It almost appears as if  the conventional power system with its large centralized power plants (mainly coal thermal) is dictating its terms on new and renewable  energies. It is not a level playing field and the muscle of the large entrenched power plants works against small power.  


There must be some other ways of managing this issue and managing the power sector. Enforcing scheduling on windpower projects is a retrograde step and some other approaches need to be explored.  As far as wind energy ( or other renewable energies) are concerned,  the commercial settlement mechanism should be designed differently and the UI mechanism which emanates from the constraints and structure of the conventional power system should not be imposed on windfarms. As long as  forecasting is undertaken for better understanding of the residual demand on the system, it is justified but coupling forecasting to scheduling with UI implication is not fair. Asking windfarm owners to schedule power is fundamentally and logically wrong. If it was possible to schedule naturally occurring phenomenon like wind, the meteorological department would have been scheduling monsoons and not forecasting it.


In conclusion one can say that forecasting may be desirable but scheduling of windpower is illogical.



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