The Future of DSOs: Digital Platform Provider vs. pure Asset Ownership

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Distribution network operators (DSO) are currently facing many different challenges at the same time. For simplicity, we summarize these challenges and describe three general developments that have a significant effect on how DSOs operate their grid or will operate it in the (near) future.

The Three current challenges for DSOs

1. Smart Metering and Digitalization

The digitization process in the energy sector requires that the distribution network operators install smart meters in their network. In some countries nearly all network users (households, industrial and commercial consumers as well as generators starting with small scale PV up to large wind farms) need to be equipped with these new digital devises (read this post to learn more about the digitization of the energy sector in Germany). In most cases in Europe and the US, installing and managing smart meters is a task of the local utilities/ local network operators. These companies do not only need to learn the specifications of smart meters, but they need to develop meter data management models as well. In many countries in Europe and in some states in the US the network operators/local utilities are currently developing meter data management models to address this task (to learn more about the European initiatives for meter data management systems read this post). However, though network operators are familiar with data handling for network operation, meter data management requires that the network operators extend their data processing capabilities to provide this data to the market. This is a new task in the realm of digital services, a business area that is in most cases new to the network operators. Even though this might offer new business opportunities to the network operators, it requires that these companies enter a rather new market area outside of their core business.

2. Renewables and Flexibility

The share of renewable electricity supply reaches significant levels around the globe. In most cases, renewables are connected to the networks of the distribution network operators. In Germany as well as in Spain and other European countries most RES (between 50-90% for details see Lopez & Ackermann) is connected to the distribution grid. Thereby, renewables force the distribution network operators to actively manage the grid. This is new, as in the past the distribution grids only had the task to transport electricity from the transmission grid towards the consumers. Now, electricity is fed into the distribution grid, consumed by the connected network users and surplus electricity needs to be transported to the transmission grid. The whole system has turned upside down. While this is not the norm yet in many distribution grids, there exist grid areas in Germany (e.g. north-western region operated by EWE) as well as in California where distribution network operators already have a very active role in managing production and demand. Those distribution networks with high shares of RES already today have to curtail feed-in from RES in times of low load to avoid network congestion. While curtailment in Germany currently is in most cases driven by a congestion on the transmission grid, we can expect that congestion on the distribution grid level will increase, which again increases the need for curtailment or other measures like the activation of local/regional flexibility. Local flexibility gains relevance with an increasing share of RES on the distribution grid level. So far, households and small commercial consumers were quite inflexible and had no resources to adapt their demand. Now, with electric vehicles on the rise, as well as small scale battery storage, heat pumps and air conditioning, even regular households have the potential to adapt their consumption according to signals from the networks or markets. While this potential is only rarely used at the moment, several projects are evaluating how network operators can use small scale flexibility to stabilize the grid (take a look at the enera project for more information

3.     System stability and ancillary services

Traditionally, the transmission system operators are responsible for the system stability. This makes sense, as the large generating capacities (power plants, large consumers) are all connected to the transmission grids. In the past, the transmission system operators (TSO or the ISOs in the US) used the flexibility from generators to balance the grid. Generators provided so-called ancillary services (frequency control, reactive power provision, black start etc.). This has not changed so far, but with high shares of renewables above 50%, ancillary services need to be provided on the distribution grid level as well. In a system where the largest share of generators is connected to the distribution grid it seems reasonable to assign the distribution network operators at least a shared responsibility for system stability with the transmission system operators.

Two new tasks for the distribution grid operator

Together, these three developments reshape the role of the distribution network operators. At least two new tasks could be assigned to the DSO.

First, the DSO could become responsible to operate the exchange of data from smart metering and other data sources. We discuss the pros and cons of different data management models here and the current debate about data hubs in Europe here. If the DSO becomes responsible for data management he will operate a regional digital platform that connects data sources and data sinks.

The second new task evolves at the intersection between system stability and flexibility on the distribution grid level. Flexibility can be used to provide ancillary services on the distribution grid. Either regional flexibility markets or regional price signals (e.g. network charges or regionalized prices at the central post markets) could be used to coordinate the flexibility provision on the distribution grid. In any case, the DSO will increase its interaction with the network users and theoretically might even host the market platform for regional flexibility himself.

The DSO as a Platform Provider for Smart Grids

Taking together the three current developments and the potentially new tasks for the DSO leads to the question: What should a distribution network operator look like and what services shall the network operator provide in the future? This question is currently discussed in Europe as well as in the US. These discussions evolve around the hypothesis that the distribution network operators could evolve towards physical, digital and market platform providers.

Distribution System Platform Providers in New York State

So far, the DSO provides the physical platform for electricity markets, the electricity grid. In addition, DSOs could provide digital as well as market platforms, evolving towards a full-market facilitator. This is the idea behind the Distribution System Platform Providers (DSP) in New York, which is to our knowledge the most advanced concept for a DSO platform so far. The idea in New York is this:

The utilities acting in concert will constitute a statewide platform that will provide uniform market access to customers and DER providers. Each utility will serve as the platform for interface among its customers, aggregators, and the distribution system. […]Simultaneously the utility will serve as a seamless interface between aggregated customers and the NYISO  (MDPT 2015:21)

The DSP will be regulated in both roles, the traditional utility and the new market facilitator role. The DSP shall fulfil three tasks:

  1. Integrated system planning: The DSP fulfils the traditional task of network planning, but needs to establish a transparent process that allows third parties to make investment decisions in renewables orflexibility devices based on this planning process. 
  2. Grid operations: The DSP shall become the intermediate between end users, the market parties and the transmission system (ISO). As part of this function as an intermediate, the DSP has the responsibility to supervise load and network status and to curtail market-based renewables.
  3. Market operations: The market design of the DSP will be based on standardized processes for market participation and fundamental functionalities. While each DSP operates its own market platform, it shall be interoperable with all other DSPs in the country so that the consumer and market parties enter a single and uniform market platform across the US. While specific products and functionalities may vary between the different DSPs, the fundamental functions should be the same for all DSPs.

The DSP concept delegates a lot of responsibilities towards the local utility/DSO. So far, the local utility in the US (in most cases investor-owned utilities (IOU)) owns and operates the distribution grids and is active as a retailer. In addition, most utilities own and operate generation capacities. In 2012, only 35% of all generation capacities (for details see here) were owned by independent power producers (IPP), vice versa, IOUs own a large share of generation in 2012. Against this background, the question has been raised whether we can trust the utility to operate the future smart grid platforms, the physical and digital infrastructure as well as regional flexibility markets. This is a highly controversial issue, especially from a regulatory perspective that focuses on non-discrimination, transparency and efficiency.

From platform provision to pure asset ownership - the different models

De Martini and Kristov provide a detailed analysis of the potential concepts for the distribution network operators to address the upcoming challenges from RES and digitalization. They define different future models for the distribution network operator in the future that we want to introduce here briefly:

  1. The TSO concept: Here, the transmission system operator (TSO) has the responsibility to balance the grid and has full access to the data on the distribution grid level. The TSO directly dispatches on the local level. The DSO in this model ‘only’ has the responsibility to secure the operation of the distribution grid but has no new role with respect to local flexibility markets or RES integration.
  2. The Minimal DSO: In this model the TSO is still responsible for dispatching RES, but has no information about the distribution grid. The DSO receives an order from the TSO to dispatch a certain amount of RES in a specific region and executes this order. Therefore, the TSO and the DSO need to have a close coordination mechanism. This model equals the status quo in Europe and the US.
  3. The Market DSO: In this concept the DSO is responsible for the aggregation of flexibility at the interconnection between the distribution and the transmission grid. Either the DSO aggregates himself and thereby provides one single bid towards the TSO, or the DSO coordinates the different aggregators in its grid area to secure that the aggregators meet the TSOs’ demand. In both cases, the DSO could make use of different mechanisms like regional flexibility markets or other regional price signals to coordinate the flexibility in its grid area.

Model 1 would result in a significant change of roles and responsibilities in the electricity sector, reducing the DSO’s task to traditional network operation. Model 2 more or less represents the current situation in most European states and in the US. Model 3, however, increases the responsibilities of the DSO to a very large extent and is comparable to the DSP concept in New York. A similar concept is discussed in California, where the DSO could become responsible to operate distribution-level transactive markets to facilitate peer-to-peer transactions (details about the concept in California can be found in the Integrated Distributed Energy Resources Plan (IDER)). Especially the strong linkage between regulated activities of the DSO and market roles/functions that are operated by the DSO in model 3 triggered a discussion about further unbundling of the DSO.  

Does platform provision require stronger unbundling? The European and US perspectives

In Europe, this discussion focuses on the question whether legal unbundling (i. e. the DSO is an independent company but part of the same holding as retail and generation) sufficiently secures non-discrimination of market parties by the DSO who might favour affiliated retailers or generators. This risk increases with new tasks at the borderline between network operation and markets (for flexibility or data). On the European level, the Council of European Energy Regulators (CEER) therefore calls for a stronger unbundling regime, if the DSO becomes responsible for new tasks like data management or regional market operation. In a recent discussion paper on flexibility the German regulator stressed that a non-discriminatory congestion management that involves market mechanisms is only possible with ownership unbundled DSOs.

The discussion in the US heads into a similar direction with the independent distribution system operator (IDSO) concept. The IDSO is a regional version of the ISO concept on the transmission level: It is an independent and regulated entity that plans and operates the distribution grids. Independent here means that the IDSO is not owned or affiliated with market parties from retail, generation or other market parties like aggregators. In addition, the IDSO could operate regional flexibility market to balance the distribution grid. Thereby, the IDSO becomes a viable option for model 3 above, the market DSO.

Both concepts, the IDSO model or ownership unbundling are discussed to reduce the incentives of the DSO to discriminate market parties. With flexibility markets on the regional level and aggregation tasks the possibility and implications of discrimination increase. The same accounts for a DSO that becomes responsible for data management or the provision of a digital platform for smart grids. Therefore, if the DSO becomes a facilitator for digital or regional markets it seems reasonable to discuss these concepts.

The question then is: Do the advantages of making the DSO the market facilitator for digitalization and flexibility on the regional level exceed the costs of introducing ownership unbundling or the IDSO model? What do you think?

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