Traditionally, power production has followed demand. Due to the growth of renewable power production, it is increasingly becoming lucrative to actively manage demand to profit from fluctuating power prices. Benjamin Bayer reports about first experiences with demand response in the US and explains how the regulatory framework needs to change in Germany.
In the electricity sector, generation has always been driven by demand. But the Energiewende could turn this paradigm on its head. In what’s known as ‘demand response’, demand reacts to market signals and electricity consumption adapts to the level of generation from photovoltaic and wind energy. To give an example: on a winter’s evening German electricity consumption is very high, but there is no sunshine or wind. As a result, the so-called residual load – i.e. nationwide electricity consumption less generation from photovoltaic and wind energy – is also very high. Traditionally, conventional back-up power plants have covered electricity consumption in these hours. But alternatively, industrial electricity consumers could also reduce their consumption at these times.
The question to what extent such consumers are willing to temporarily reduce their electricity consumption is a hotly debated topic in Germany. The financial incentives for them to do so depend on the design of the electricity market. In the current German electricity market, financial incentives would arise from very high electricity prices at the power exchange. If the market price exceeds a certain level, it could be more profitable for industrial consumers to resell electricity they have already purchased and cut back production on a temporary basis. The market price at which this is the case varies depending on the company in question and its specific context. Given that there have always been enough conventional power plants to cover peak demand, this approach has never really been tested and we have no experience to fall back on.
An alternative electricity market design offers financial rewards not just for delivering energy, but also for pledging power plant capacity
As an alternative to the German electricity market design, a scenario where not only energy delivery but also power plant capacity is remunerated is also conceivable. In practice, it works like this: the grid operator sets the required capacity for a so-called capacity market each year in advance to ensure that peak electricity consumption can be covered. Power plants that participate in these capacity markets receive an availability payment for their willingness to provide capacity if necessary. And this availability payment stays the same regardless of whether the reserved capacities are used every day or not at all. The costs incurred are transferred to all electricity consumers in the form of a so-called capacity fee.
Apart from power plants, industrial electricity customers can also participate in capacity markets. In so doing, they agree to reduce their electricity consumption for several hours if and when necessary. For the electricity market, this means that less back-up power plants need to be built. And for the industrial electricity consumer, the capacity fee is refunded. This appears to be a win-win situation that we should take advantage of. But how does it work in practice? The American electricity markets PJM Interconnection, New York and New England have a wealth of experience of this approach.
The US experience shows that some companies are prepared to reduce their electricity consumption for a few hours a year on request
To begin with, experiences gained on the US electricity market show that the basic idea of demand response works. A small proportion of commercial electricity consumers is indeed willing to reduce their electricity consumption for a few hours a year on request. Based on the required capacity in the electricity markets referred to, the capacity of conventional power plants has thus been reduced by a few percentage points. There were reductions of 0.8% in New England, 2.9% in New York and 3.8% in PJM Interconnection. In recent years participating industrial and commercial electricity customers have had to reduce their electricity consumption to the contractually agreed level up to six times a year. The cumulative dispatch duration per year was as much as 33 hours. Yet dispatches are generally far less frequent – in these markets demand response is, after all, an emergency measure.
Expressed in percentages of up to 3.8%, the willingness of companies to reduce their electricity consumption for a few hours a year seems relatively low. On the one hand this is surprising, given that different studies have claimed significantly higher figures (up to 10%) for the US electricity markets. However, these figures have been massaged to some extent.
On the other hand, the low figures are understandable when we consider that interruptions to the electricity supply, when announced at short notice (two hours or less), often lead to losses in production and comfort.
Given the different framework conditions (electricity market design, power plant fleet, industrial structure, etc.), these results are of limited use in the German context. In future, technological progress and fluctuating production from wind energy and photovoltaic may well increase the role demand response will play. The extent to which demand response asserts itself over other generation and storage technologies will be determined by politics and the market. In this process, politics should not lose sight of the overarching goal of ensuring a level playing field between the generation and demand-side options. But, as the negotiations on electricity market design in the USA show, this is no easy task. Surprising as it may seem, we don’t just need to remove the barriers to demand response, but also avoid giving demand response an unfair advantage over other capacity resources.
For more on this topic, see Benjamin Bayer’s recent article on “Current Practice and Thinking with Integrating Demand Response for Power System Flexibility in the Electricity Markets in the USA and Germany” in Current Sustainable/Renewable Energy Reports.
Benjamin Bayer is a research associate on the Transdisciplinary Panel on Energy Change at the IASS Potsdam. He conducts research on the regulatory framework for flexibility options with a special focus on demand response. The post was first published on the blog of the Institute for Advanced Sustainability Studies (IASS) Potsdam and is reposted with permission.
 In the case of both PJM Interconnection and New England, several states amalagamated to form a single electricity market. Thus PJM Interconnection comprises 14 states, while New England is made up of 6 different states on the East Coast.
 Firstly, the use of on-site emergency generators is attributed to the demand side. Secondly, the amount of interruptible loads is quoted after the first capacity auction, while no mention is made of the amount replaced in subsequent auctions. And thirdly, these figures sometimes reflect the registered capacity including non-active capacity resources rather than the capacity that is actually available.