The Merit of Baseload

South Australia 2015 load duration curve, annotated from Appendix A.

Over the course of a year, Australian demand for electricity tends to peak during air conditioned summer afternoons, and reach its minimum in the hours after midnight. The lumpy day-to-day profile of this demand can be rearranged in order of highest to lowest in what is termed a load duration curve.

This chart is the duration profile for South Australia in 2015, as described by the black curve. By viewing the state’s demand and proportion of wind generation this way, certain features become clear.

• Baseload of roughly 700 megawatts is defined by the grey line, and is clearly truncated below 80% of the year by the addition of wind generation. This is the basis for the diminished economics of “baseload” power stations, and the claims of no further need for such capacity.
• Wind helps meet demand between the black line and the blue line (the residual load curve) as a wavy wedge, with its least contribution up at the times of highest demand near “0%” which is instead met by expensive stand-by “peaking” capacity. The consequence is that the “baseload” and other capacity greatly displaced by wind down near 100% are the cheaper sources of power which tend to maintain downward pressure on wholesale supply prices.
• Clearly then, even with South Australia’s noteworthy wind capacity which has worked to cut state electricity sector emissions by roughly one quarter, that peak demand up around 3000 megawatts requires the operation of as much firm capacity as if the blue curve weren’t there.

Further analysis was offered recently by the Grattan Institute (page 8):

Increasing supply in any market when demand is falling or flat will push down prices. But a further characteristic of wind power suppresses wholesale electricity prices in the short run.

The marginal cost of wind generation – the amount it costs to generate an additional unit of power – is near zero. In fact, if a wind generator chooses not to generate, it will effectively lose money since it will not generate a subsidy under the Federal Government’s Renewable Energy Target (RET) scheme… This is why, at times, a wind generator may bid into the market at a negative price – it is prepared to pay the market to take its electricity because it knows it will get revenue from the subsidy.

Intermittent generators must also either dispatch or dump the electricity they create. When the wind blows, power is generated. If wind generators are to dispatch, they need to make sure that their electricity gets bought or that they pay someone to take it.

Increasing the supply of low marginal cost generation leads to changes in the ‘merit order’, reducing the price that all generators are paid in the NEM. This is known as the merit-order effect.

But these lower wholesale spot prices will not cover wind farms’ long-term costs. The long-term cost of wind generation is around $100 per megawatt hour, although this can vary with individual projects. This cost is very much higher than today’s average NEM prices of around $50 per megawatt hour. Consumers must eventually pay to cover the long-term costs of all generation.

This echoes the illustration of the merit order effect provided by Deloitte in 2015:

The merit order effect can be induced by any form of generation or demand side resource that has a lower short-run cost (i.e. ignoring fixed costs and the capital costs of building the plant) and is a feature of an efficient market. The limiting factor is usually that the new plant needs to be able to recover its fixed and capital costs over time as well, so the price cannot be pulled too far down. However, by incentivising renewable plant outside the market, policies such as the Renewable Energy Target (RET) move this limit.

Imagine that a new type of combined cycle gas turbine power station could operate without emitting carbon dioxide. The ultimate purpose of the RET – climate action – should mean it would be compensated by something like these Large-scale Generating Certificates. Suddenly, the short-run market advantage claimed by wind generation is gone.

Armed with this perspective, we can begin to see where some enthusiasts for exclusive energy supply scenarios begin to go wrong. Take GetUp/Solar Citizens, for example:

Renewable energy generators have low marginal costs (the cost of producing one extra unit of electricity), which means they can bid into the wholesale market low. This pushes more expensive generators out of the stack of successful bids and lowers the overall wholesale price of electricity for all of us. This is called the ‘merit-order effect’, and why it’s not called the ‘renewables winning effect’ is beyond us.

Hopefully at this stage it isn’t beyond you, dear reader.

So, what happens if storage is added to this equation? Household-scale batteries for the time-shifting of rooftop solar generation obviously enable the use of renewable energy after dark. In contrast, storage scaled up to the wider electrical grid – which exists only in the form of pumped hydroelectric – is dominated by the economics of covering the costs of operation, maintenance and input electricity with the revenue of selling output electricity. This means arbitraging supply from low demand periods to high. The result can be seen in this version of the load duration curve: if storage were paired with wind in South Australia, operators would effectively move supply from the thick end of the wedge back as close to the point as practicable, to maximise financial return. This could actually begin replacing high cost peaking capacity. Ironically, enough of this would start to bring baseload back, at the same time as eroding the arbitrage economics for further addition of storage. It should be obvious, though, that the absolute last position on the demand profile which would be economically served by stored capacity would be baseload itself.

 

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