What is the future for distribution networks? The European description of them as distribution system operators (DSOs) illustrates the issue: should they be active players in electricity supply and system management, or should they be independent facilitators for other market players? And what should be their charging structure when distributed generation, storage and flexible consumers make per-kWh charges outdated?
The issue was a key question arising at electricity supplier lobby group Eurelectric’s annual meeting in Berlin in July 2015. And the question of whether DSOs should be ‘market facilitators’ or active players has been a live one at least since the third package set out unbundling requirements at the transmission level. It is not clear yet what the final form of the local networks will be, although Brussels has said it has “no appetite” for unbundling distribution networks, which in Europe are often local suppliers, with both customers and storage or generation assets.

Compared to bulk transport, network users at the distribution level are much more variable and many are new to the energy system, so some believe an active DSO, which can own and use assets like storage,  will be the best way to make progress. But the requirement to maintain good competitive practice remains and many believe that third parties, aggregators and new entrants will be more innovative and effective than DSOs at developing the market.
The likely result may be a path somewhere between the two options – something Ofgem has tried to pioneer with its Low Carbon Network Fund and Network Innovation initiatives, which aim to provide space for innovation within regulated networks.

Albert Potoschnig, director at European regulator’s group Acer, said there would be “serious concerns” over any framework that mixed natural monopoly activities and the market. “We need strong separation; they must not distort or bend the market”, he said. He also said data needed to be kept separate from the market, whether that was by a regulated DSO, acting as neutral market facilitator, or another organisation.
“Can that be achieved by legal separation or do we need more than that? It’s a debate to be had,” Potoschnig said.
A snap poll among Eurelectric meeting attendees found that a large majority – 68% – expected that the future would be close co-ordination between TSOs and DSOs, with the latter actively managing constraints on their systems. Nearly a fifth of the audience (19%) thought that TSOs and DSOs would eventually merge, while less than a tenth of members (8%) thought that DSOs would manage new assets to help balance and just a few (4%) thought that they would eventually take over balancing responsibilities from TSOs.

Who owns and operates?
The EU’s “third package” of energy legislation required “unbundling” of transmission systems. Cross ownership of transmission and generation assets was outlawed and independent system operators required, to ensure companies had no financial interest in “reserving” their own network capacity to the detriment of other users. That has allowed competition to grow. The question is whether there should be a similar requirement or distribution networks – in practice, largely the case in the GB market – or whether they should have a more active role, encouraging and promoting distributed generation and proving network services.
Antonio Mexia, incoming Eurelectric chairman and chief executive of EDP, seemed to want to have it both ways, saying: “there is an increasing role for DSOs as technology enablers and market facilitators for demand side response, distribute generation, etc”. He said the first requirement was to allow competition to develop.  Patrick O’Doherty, chief executive of ESB, said there needed to be “Very clear demarcation between regulated markets and those that are available for market” suggesting that DSOs would become a procurers of services provided by aggregators.

Hildegard Mueller, chair of the management board of German energy lobby group BDEW, said the new role of the DSOs was as the “bridgehead” for accessing distributed generation and so-called prosumers.

Who pays?
Along with the question of scope there were questions about how the costs of the network would be borne in future. Two issues arose.

The first was who pays for the network itself. Currently distributed generation is growing rapidly: in some cases it requires grid strengthening and in most, even with the potential advent of storage alongside generation, users remain connected to the grid as “backup” or occasional customer.
That makes the traditional volume-based charging structure, where charging is per kWh, hard to justify in the long term. Several contributors at the conference suggested that at some point there would have to be at least a partial shift to capacity-based charging for grid connections.

Several also raised the question of which customers are disadvantaged, as distributed generation is generally an investment for those with disposable income while less well-off customers have little option but to bear system costs. “Are we creating a two-tier energy system where the costs of going off-grid are borne by those who can’t afford to do so?,” asked OPower president Alex Laskey. And Mexia said “the problem will be free riders who think they do not have to make investment”.

“Are we creating a two-tier energy system where the costs of going off-grid are borne by those who can’t afford to do so?”

Marguerite Sayers, managing director at ESB Networks, summed up the difficulty when more and more people are off-grid and not paying for the grid, although they still have access to it. “One section of society can afford it, and they are subsidised by others and incentivised to go off-grid. [We are] ever closer to connection charges and capacity charges, “ she said, asking , “will we have to charge upfront to remove cost recovery risk?”
The second issue also concerned charging and arises at both transmission and distribution level. It is how the value of security and flexibility could be reflected in pricing, in a situation where the system has nominal overcapacity but much of it is variable. Johannes Teyssen, chief executive of E.On, said “if the price is the same for a retailer who is guaranteeing supply, and a retailer gambling on the grid [to step in], why should [a generator] invest in secure supply? You create a value that is not being rewarded.”

 

First published in the July 2015 issue of New Power.

More on this debate (subscribers login to read)

Not a subscriber? Email [email protected] for details