It is high time that there was an independent and objective review of the electricity market. Bryan Leyland, industry consultant.
MARKETS WORK IF the inducements reflect the requirements. To provide a reliable and economic power supply it can be argued that three separate commodities are needed: a long-term supply of energy (kWh) at a reasonable price; sufficient MW to meet peak demands with a reasonable margin and sufficient energy held in reserve for a dry year.
Our existing market provides energy on a short-term basis. Among its achievements so far are: a steady increase in the price of electricity; a number of wind farms that don’t get charged for the backup supplies that are needed when the wind doesn’t blow; the virtual abandonment of ripple control – which has resulted in our peak demand being at least 500MW higher than it needs to be – and ignoring the need for reserve energy to avoid blackouts and high prices in a dry year. The cost to the consumer has been well in excess of $1 billion.
Providing sufficient MW
A rational market would recognise that every extra kilowatt of demand costs more than $3000 in generating plant, transmission lines and distribution lines. It would provide rewards for power stations that contributed to meeting peak demands and equivalent rewards for anything that would reduce demand during peak periods.
At the moment, Transpower’s charge of about $100/kW of maximum demand provides a low, but useful, signal on the cost of meeting peak demand. But the latest move by the Electricity Authority is to reduce this charge to about $30/kW.
If this happens, less attention will be paid to minimising peak demand so more power stations will be needed and the system operator will have to spend even more money incentivising people to get into demand-side management. The Electricity Authority seems to have totally lost the plot.
Surely it would not be difficult to arrange annual payments based on the actual output during peak demand periods and with payments to those generators held in reserve together with a reasonable peak demand charge – say $150/kW.
If this happened, reliable generators would be more profitable, less reliable generators – like wind and solar – would be less profitable and, now that most consumers are on smart meters, domestic users could be levied on the demand over peak demand periods. This would induce people to sign up for time of use tariffs and, for instance, install smart thermostats on their water heaters that would do everything that ripple control did and a lot more.
I see little chance of this happening because it would first be necessary for the Electricity Authority to admit that the market is flawed. I don’t think it will happen under the current management.
The dry year shortage risk
Before the advent of the electricity market the major concern for the power planners was ensuring sufficient reserve thermal capacity to get us through a dry year when the output of the hydropower stations drops by nearly 10 percent of annual energy demand.
Up till now we have survived a few dry years reasonably well because demand has not increased as rapidly as expected and surplus plant was available. But in the past year or so, a number of older or unprofitable thermal stations have been shut down and we are, once again, in a situation where there is a very real risk of blackouts in a dry year.
Early in 2016 Transpower issued a system security review that warned of a risk of shortages in a dry year in the near future. The review assumes that the thermal stations will, if necessary, run for six months at 90 percent plus capacity factor during a dry year to make up the shortfall in hydropower generation. The six-month period and the capacity factors were decreed by the Electricity Authority even though, in reality, a dry year lasts three to four months.
The 90 percent capacity factor is high for most of the power stations listed. It assumes that they will be very reliable and they will have sufficient coal or gas. Without detailed knowledge of their gas contracts, the size of the coal stockpile at Huntly and whether or not it will be possible to get extra gas from, say, the methanol plant, a 90 percent capacity factor is a very risky assumption.
The Electricity Authority also appears to have assumed that the cogeneration stations will be able to operate at maximum output during this period. In the case of Whareroa and Te Rapa dairy factories at least, this is most unlikely because they shut down for three months during autumn/early winter and are likely to have scheduled their co-gen plant for maintenance during this period.
During a dry year it is also possible that thermal generating plant may shut down in the early hours of the morning if the price drops – this happened during a dry period a few years ago – so, although it is important to generate flat out to conserve water storage, the market drivers needed to keep the stations running continuously may not exist.
Windfarms are assumed to operate at their annual average capacity factor of 40 percent. This is probably optimistic because, during the autumn/early winter dry periods the output of wind farms drops by about 10 percent.
Of course, it is always possible to shut down the aluminium smelter. But, because restarting pot lines is expensive, time-consuming and difficult it carries a risk to the economy and Southland because the smelter may then be abandoned.
If the dry year generation period is reduced to a more realistic four months and adjustments are made for the shorter period available, the actual situation with reserve fuel, the lower output of windfarms and cogeneration plants, then the dry year margin shown in the Transpower review is likely to disappear.
This is not good news because the damage to the economy from a shortage will be far greater than the probably minor damage to the generators. Thermal generators with sufficient fuel reserves may even come out of a shortage with windfall profits.
Plain common sense
The solution is to predict the amount of dry year reserve that is needed for the next five years or so and request offers for reserving dry year hydro storage that would not be used in a normal year, holding fuel in a coal stockpile or providing underground gas storage. The offers would need to be accompanied by guarantees that sufficient generating plant was available. The annual payments would compensate generators for the loss of working hydro storage, the cost of providing a coal stockpile or gas reserves and the associated cost of keeping generating plant ready to run when needed. Although it seems like plain common sense it is unlikely that the Electricity Authority would contemplate something like this.
The Electricity Authority seems to be dominated by economists who have no idea of the complexities of maintaining a reliable and economic supply and the inducements needed to make sure that this will happen. Until there is some substantial input by experienced power system engineers, or a drought hits and causes serious shortages and political uproar, the situation is unlikely to change.
I strongly believe that Transpower, the government and the Electricity Authority should commission an objective look at the electricity market and take the dry year risk very seriously.
There should be a review of the market itself and all assumptions associated with dry years in the light of past experience, and the relatively short duration between the time that the market realises that we could be heading for a dry year and ramps up generation.