More ambition needed for RIIO2 outputs*
Catherine Mitchell, IGov Team, 14th June 2018
Ofgem is currently consulting on multiple issues: RIIO2, network charging, post-supplier hub model, settlement and metering – and the sum of the decisions made about these consultations will form the basis of regulation for the next 10 years or so. It is therefore important to get these consultations ‘right’ – and from my perspective ‘right ‘ equals putting in place an energy system which removes barriers to delivering, whilst positively encouraging, the move to a smart and flexible energy system which is affordable, secure and sustainable. And by sustainable I mean that they together deliver a decarbonised electricity system by 2030, as is required by the Committee on Climate Change (CCC) carbon budgets. When viewed in this way, RIIO and the other consultations have a number of make or break decisions to make.
As the CCC 2017 Report to Parliament makes clear, the electricity sector has been the main source of the GHG reduction since 1990: primarily moving from coal to gas, and the increase in renewable electricity (RE, mainly variable power wind and solar). Hardly a dent has been made in transport emissions (ie minimal reductions), and very little progress has been made on heat emission reductions.
As the CCC also shows there is a policy gap across all sectors. In addition, all sectors, whether heat or transport or the now more difficult emission reductions in electricity, requires changes in governance – where governance is taken to mean policies, institutions, market design and its rules and incentives, network rules and incentives, retail policy, the costing methodology framework (ie supplier hub or its replacement), and customer and user preferences.
Reducing emissions from the electricity sector has altered from being mainly about policies for supply to being about how to operate the electricity system differently (in order for it to be suitable for increased proportions of variable power and delivery of more flexibility; and because of the increased decentralisation of resources and digitalisation of communication). Governance has to alter to transfer value from the centralised, top down fossil-based energy system to this decarbonised, smart and flexible energy system. If GB does not get this governance ‘right’ then costs to customers will be far greater than they need to be; system security will be more of a concern; and the environmental benefits of RE will be lower than their potential with knock on effects of not meeting our GHG reduction targets as early, or as cheaply, as we could.
Regulated companies are to a large extent creatures of their regulatory compact. If we want our energy systems, and in this instance in particular our electricity systems, to be operated differently, then we need a new regulatory compact. RIIO-EDI comes to its end in 2023. RIIO2 is now being discussed and this will last from 2023-2028 (if it is for 5 years) or 2023-2030 (if the price control continues at 8 years). Thus RIIO2 has to be set up so that the electricity distribution network companies do their part to deliver a decarbonised electricity system, as required by the CCC, by 2030.
This means that the current discussions about the role of distribution network operators and how they should transform into distribution system operators (DSO) or distribution service providers (DSP) is very important – and of course, a DSO or a DSP will need very different regulatory incentives. The two broad ways of regulating network companies are via cost of service – the DNO say before a price control determination how much money it will cost them to run the network for the network period – so it is input based – and they are allowed the amount (after negotiation). The other way is a combination of cost of service and performance based regulation (PBR), the latter being related to particular outputs. The DNO will only get the revenue linked to the PBR if they deliver those outputs. RIIO is a PBR mechanism because an additional 6.5% of the regulatory agreed business plan can be earnt by providing certain outputs (although currently nothing to do with environmental outputs). However, PBR could in theory be up to 100% of revenues. In this sense, RIIO1 has a very limited PBR mechanism but one can imagine it could be ramped up over time. In general, a cost of service regulatory mechanism gives more control to the network company over how the network will develop and be operated.
Of course, ultimately it is not the name (DSO or DSP) that matters but the functions and how they are regulated. I would, broadly, argue that the difference in function between a DSO and a DSP is that the former retains more control of the development and operation of the network because there is a higher proportion of their revenues deriving from cost of service inputs; encourages various system services (such as provisions to reduce constraints) but usually at the higher kVs than at the residential kV level; and does not undertake a coordinating and balancing market for distributed electricity – so only deals with system service type markets rather than energy markets. This is more active than the current passive DNO but not very much.
A distribution service provider on the other hand operates a coordinating and balancing market for electricity under grid supply points, which are nested into the wholesale market; acts as a market facilitator and coordinator of other private platforms, and of energy and system services; is incentivised to enable new transactions, in part by opening up data about the system operation and revealing price (through distributed energy resource (DER) assessments; is incentivised more directly to deliver public policy goals; is incentivised to enable customer wishes, whether this be lots of photovoltaic panels (with or without storage) or communities which would like to municipalise their wires. A DSPs network operation and development is more linked to incentivised outputs, and therefore their revenues and rate of returns are related to them doing what is wanted of them. Finally, it should be fully ‘active’ at all kV levels, and as far as possible between electricity, heat and mobility.
Ofgem is currently expecting the DNOs to produce plans of how they intend to move to a DSO. Only two of the DNOs have published those plans – and hats off to UKPN and WPD as the two which have done that, and to WPD as the only one which has costed that (about £150 million). On reading their plans – their long term intention may be to become a DSP, but their short term plan (ie in RIIO2 and by 2030 or so) is to become something nearer my definition of a DSO. So far, it broadly seems that Ofgem is expecting the DNOs to work out what it is to be a DSO in RIIO1, and then have RIIO2 as the time that DNOs alter their function to become a DSO. This is breathtakingly under-ambitious.
Ofgem should be arguing that all DNOs deliver a plan to become a DSP by the end of RIIO1; and that they spend RIIO2 implementing it in agreed stages so that they become DSPs by 2030. Part of this would be undertaking a distributed energy resource assessment (DERA) ASAP in RIIO1. It seems to me that a DNO should anyway know what the DER resource is of their area, down to, and including, the residential level (where DER is both energy supply and demand side possibilities but also system services; and at all kV levels by time and place ). A DER assessment is the first step in operating a distribution system to deliver desired outcomes most cost effectively. Without a full area-system assessment, it is simply not possible to know what the relative ‘value’ of different services are – whether within a distribution area but also between transmission and distribution.
Nor is it expensive or difficult to undertake these assessments – relative to the £1bn we pay the DNOs every year. There are platforms available now which the DNOs can use to help transform them into DSPs relatively easily (see DEx of Australia for example) and at low cost – a few million pounds for each DNO license annually. Moreover, these platforms can certainly undertake the DER assessments within the RIIO1 period (ie by 2023 – and in theory quicker!). These distributed energy management systems (DERMS) enable distribution companies to undertake these assessments, and they also open up the potential of what DSPs should be, and how they should , or could, be regulated.
At the moment, a DNO is effectively a joint wires company and system operator. In theory, a DSP could be SO only. The separated distribution wires company would be regulated and would bid in for system provisions, as any other provider. However, that SO portion of the DSP does not, conceptually, have to be formed from the DNO. In other words, the DNO could continue as it is without a SO function. A ‘new’ SO institution could be added to the distribution area. This new ‘platform’ would be regulated to undertake a DER assessment in a dynamic way, and to operate the area most cost-effectively (including via tenders etc) depending on the desired outputs.
In this situation, this new platform displaces the DNO but this kind of platform can also be a tool for ‘activating’ the DNOs (ie the platform would not displace the DNO but rather is something that would help turn the DNO into a DSP). This area wide platform would also complement the newly developing platforms like Origami.
There is a clear distinction between an area-wide platform which captures all DER in the area, thereby revealing value, and working for the public good; and private platforms which work for the best private interests of a company. There is nothing wrong with these private platforms – on the contrary they should be encouraged. However, it is important that there is some form of area market and balancing coordinator to understand what distortions private interests may be injecting into system operation and development, to make sure public policy goals are delivered.
It is remarkable how many people argue that ‘passive’ DNOs are incapable of becoming ‘active’ DSPs however much they are incentivised; and therefore (1) the SO role should be hived off from the wires business; or (2) the DNOs should be re-nationalised.
However, my preference – at least in the short term and unless something changes considerably – is that the wires and SO aspect of the DNOs remain together as they move to a DSP. This is because there should be so much energy and system activity that it should be easier to reveal value if they remain together. However, other companies should undertake the non-wires provision and the distribution company should be regulated with an increasing proportion of their revenues linked to performance based regulation. This regulatory change would not have to happen immediately but the DNO companies would have to know that, over the next 10 or so years, their regulatory risk is going to change considerably (ie for example 6,5% of additional value of PBR now to say 50% of earnt revenues related to PBR), and that there is very clear end point of delivering the network aspects of a decarbonised electricity system by 2030.
It may be that it becomes clear that the DNO SO should be separated from the DNO wires company but I think this is a RIIO3 activity – and only once it has become clear what the trade-offs are.
In network development terms, 2030 decisions are upon us. It is vital that the regulatory measures being coordinated by Ofgem lead to outcomes which fit with the CCC budgets. Ofgem currently has a responsibility to future customers and, in theory, this should mean that Ofgem should be thinking about the environment. As it so happens, in this case, the economic case – for the DSP – is also the environment case. As such, Ofgem should be ensuring DNO actions in RIIO1 will lead to DSPs by the end of RIIO2. I can see no reason why they should not be the case.
* This is a slightly amended version of an article from this week’s Energy Spectrum published by Cornwall Insight: https://www.cornwall-insight.com/publications/energy-spectrum-and-daily-bulletin