From the April edition of pv magazine
Europe, despite being at the forefront of the energy transition in many respects, has been hesitant to adopt microgrids, largely due to complex market regulations and established practices of distribution/transmission system operators (DSOs/TSOs). The Navigant Research quarterly Microgrid Deployment Tracker shows that as of Q4 2018 only about 9% of the world’s 2,258 microgrids (19.5 GW capacity planned or installed) had been deployed in Europe. With rapid expansion of solar PV and other variable renewable generators looming in Europe, microgrids and virtual power plants (VPPs) could serve an important purpose. They both allow either spatial or temporal alignment of demand and supply in the energy market, and provide stability. Conventional means of addressing these issues are rather expensive or unsuitable for the optimal use of variable renewable energy. Peter Asmus, author and contributor to Navigant Research writes: “A unique confluence of factors makes Finland the best opportunity for microgrids in Europe. Finland is not only the global leader on smart meter deployments, with 99% of its 3.5 million customers having access to this technology, but it also has a deregulated wholesale and retail market that features 83 distribution system operators, with the largest distribution networks composed of 200,000 customers.”
Put a price tag on it
After a series of blackout events in 2011 and 2012, Finnish policymakers reacted by setting a price on power outages. Since 2013 DSOs are obligated to pay compensation to customers. Under the compensation system, single event outages between 12-24 hours will incur a 10% reduction on annual delivery fees, outages of 120-192 hours a 100% discount and outages in excess of 288 hours will result in compensation of 200%. The typical annual delivery fee for a Finnish household is €94. If an outage of 20 hour duration occurs, the cost of the interruption for the DSO will be €0.78 per household per minute. Academic Sinan Küfeoglu calculated the so-called ‘shadow prices’ of one minute of interruption for 78 of the 83 Finnish DSOs between 2013 and 2015. The analysis shows the shadow price per outage was determined at about €0.40 per minute per household for the vast majority of DSOs. With this market mechanism in place, for many DSOs, it was simple to determine the cheapest option to address the issue.
Since the problem of outages in Finland had been connected to the vulnerability of overland lines due to severe weather conditions, one solution to the problem is to lay the power lines underground. Navigant’s Asmus suggests that, “According to research performed by Lappeenranta University of Technology (LUT), the lowest cost option for 10‒40% of the medium voltage branch lines would be low voltage direct current microgrids.”
As a response, Siemens and Schneider Electric, among others, were commissioned by DSOs to build a microgrid. Finland, by putting a price on power outages, set in motion market mechanisms whereby DSOs look to reduce the costs of infrastructure adjustments and weigh up their options to stabilize the grid in the optimal way.
Learning from the Finns
Apart from microgrids, Europe’s power grid can be assisted through the implementation of VPPs. There are additional services that virtual power plants are likely to perform at a better price point than conventional means of doing it. These services include delivering system flexibility, re-dispatching of power, and grid ancillary services. The example from Finland illustrates how regulation can be a driver of technology adoption in ways that are in line with what the grid, and electricity consumers, require. Likewise, regulations for VPPs could similarly be improved in order to better manage curtailment and create an effective re-dispatching market.
Already, in some European markets, VPPs are allowed to provide grid ancillary services. At the same time “the provision of grid ancillary services through virtual power plants has brought down the costs of providing the services significantly, in the markets where it is possible,” says Daniel Hölder, management board member of BayWa Clens, a subsidiary of BayWa for energy trading and flexibility options. The German regulatory authority, Bundesnetzagentur, publishes its monitoring report once a year, in which the regulatory authority lists the full costs for grid ancillary services in Germany. In 2017, these costs came in at close to €2 billion. The cost to provide primary secondary and tertiary balancing reserve are about €145 million. A considerable portion comes from compensation for curtailment at €609 million and re-dispatch claims of €291 million. Curtailment and re-dispatch, in Germany and wider parts of Europe, are two measures TSOs perform outside of any market mechanism, but solely based on regulatory requirements.
Legacy regulations
VPP providers BayWa Clens and Nextkraftwerke both argue that VPPs can tackle both curtailment and re-dispatch, more cheaply and efficiently than conventional methods. Re-dispatch describes the process by which a TSO decides to use loads from two or more power plants in a different way than had been agreed upon the day before, to avoid grid bottlenecks. The TSO has the authority to ramp down the power output of one power plant before a bottleneck and increase the power output of one that sits behind that bottleneck.
In countries where this process is not yet market driven, TSOs are rather unlikely to consider small-scale generators, such as 100 kW biogas or 2 MW solar PV plants in the process. The problem is that in most European countries the “distances between large thermal power stations can be more than 100 kilometers and can only be adjusted in intervals of 10 or more megawatts,” Jan Aengenvoort, Communications Director at Nextkraftwerke explains. This results in the effect that if a bottleneck is to be avoided, only a single power plant operator can be considered. This is not only logistically complicated for the grid, but it eliminates competitive market impulses. Since there are no other options available, the operator of the plant required to make the adjustment dictates the price. There is no competition.
Turning the measure into a market exercise allows VPPs to make smaller and local adjustments by tinkering with the power outputs of distributed generators, which can be adjusted with high granularity and are spread much more evenly throughout the country, Aengenvoort asserts. In so doing, the prices for re-dispatching could be seriously undercut.
The absence of a market mechanism might have made sense at a time when the grid was fed by very few large power stations. At that time grid operators would pick up the phone to notify the plant operators and request changes in the power output. Over the last two decades, the European power system featured incrementally more distributed assets, which still have yet to be optimized. “Virtual power plants need markets, and when we have markets VPPs are a suitable instrument to manage large amounts of assets,” says Hölder.
In another piece of legacy regulation from the olden days of energy infrastructure, many European markets incentivize flattened consumption profiles of industrial consumers. Of course, thermal generators (can) produce without fluctuation, and hence to eliminate fluctuations from the consumption profile worked in grid operators’ favor. Therefore, industrial consumers managing to flatten their consumption profile received discounts on their energy bill. In obscure cases in Germany, this has worked to the effect that golf courses, as Aengenvoort explains, get a discount on their grid charges if they had their lights running all night illuminating acres of land. Hölder adds that in other instances, factory owners could be financially penalized if they were to switch on an additional piece of heavy equipment. The reason is that the additional load puts them at a higher peak load class. That would be the case even if, from a grid operation perspective, it would even be helpful to increase consumption in a factory, because of the high availability of variable renewable energy.
Instead, TSOs must resort to curtailment because industrial consumers not only lack incentivization but are financially penalized when they try to help balance demand and supply. In 2017, curtailment in Germany had been up 47% year-on-year and accounted for nearly a third of all the system-related ancillary service costs.
Winter package no remedy
The market operation of curtailment and re-dispatching, in particular, is not without criticism. “Until 2021, re-dispatch and curtailment are supposed to operate under a single rule,” says Hölder. “But I also know that within Bundesnetzagentur [the Federal Network Agency] and the German Ministry for Economic Affairs there are sceptics for a market-based regulation of re-dispatch.” Regulators fear that plant operators will purposely create bottlenecks to then participate in the markets to remedy the problems that they have created. For Hölder, it is not that black and white and while he understands the concerns of the regulators, he also suggests that these solutions are still needed, and a good market design is possible. The Netherlands has already moved forward and allows for market-based re-dispatching.
While the EU’s new clean energy package foresees a slow turn towards market-based approaches for curtailment and re-dispatch, it is unlikely that within the immediate future a unified EU-wide approach will be found. The package also clearly identifies the important role of VPPs and will allow for their use in ancillary service markets. For now, the positive experience of providing balancing power and frequency control using VPPs has not inspired policymakers to use the same technology to address the costly issues of re-dispatching and curtailment.
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