Who pays for the grid?

30 September 2016

Changes announced for the future treatment of embedded benefits

The question of who pays for the grid, and the methodology used to calculate network charging has vexed energy policy makers for some time and is now a hot topic in the UK.

In recent weeks Ofgem has made two very significant interventions that will have a direct impact on embedded or distributed generators, energy storage providers and any high energy users with demand side response or behind the meter generation, to avoid peak transmission or distribution grid charges.

The interventions are:

• Open Letter: Charging arrangements for embedded generation
• Distribution Connection and Use of System Agreement (DCUSA) DCP228 – Revenue Matching in the CDCM.

This insight article looks at some of the issues behind Ofgem’s interventions and offers a Regen view on how a future grid charging methodology ought to be developed. The article draws on a recently published Regen SW paper: Network Charging for a Flexible Future.

Paying for the grid – network charging for a flexible future

To put this into some sort of context, the national grid electricity transmission network costs account for around 4 per cent of a customer’s bill. The Transmission Network Use of Service (TNUoS) charge is expected to cost £2.7 billion per annum in 2016/17, rising to just over £3.7 billion by 2020/21[1]. Added to that is another billion[2] for balancing services (BSUoS) which have to be purchased to keep the grid voltage and frequency in line and to cover the cost of electricity transmission losses, which are running at just under 2 per cent across the GB network.

The distribution network currently costs circa £6 billion[3] per year to operate and maintain and accounts for around 16 per cent of a customer’s bill. The main Distribution Use of Service (DUoS) charge is levied based on demand usage, using a banded tariff with a significantly higher tariff for evening peak usage during the “Red Band” and winter evening “Super Red Band” periods.

The approach for UK network charging has been developed over a number of decades and, as you might expect, there are now a large number of different mechanisms and an alphabet soup of acronyms.

Several of these charging methods are outmoded and in some areas the calculations used are no longer reflective of true costs and may in fact be distorting the market. There is now a general acceptance that the regime should be overhauled to reduce the impact of market distortions and encourage the most efficient use of the networks. Many would also argue that the charging principles need to be redefined to reflect new energy priorities and changing market structures.

The ongoing grid charging debate has raised a number of key questions:

• Charging demand vs. generation – one of the issues in the debate is the balance between charges paid by generators to use the grid versus the charges made to demand customers who rely on the grid to deliver their power. Bearing in mind that ultimately it will always be the customer who pays, and following the principle that it is energy usage that causes the costs, there has been a general presumption that the majority of costs should be charged directly to demand customers. In some EU countries demand pays for 100 per cent of grid costs. In the UK there are generational costs, with a strong locational factor, but over 75 per cent of costs are made as demand charges.
• Peak demand charging – whether it is right, under the current system, that the main transmission and distribution network charges are weighted heavily towards peak demand users on the basis that it is the peak demand, sometimes called the marginal demand, that is the main driver of investment in grid infrastructure.
• Locational price signals – there are locational factors, both for demand and generational charges that are intended to encourage new generation in higher demand areas and likewise to incentivise demand in high generation areas. Both controversial and emotive, there is a debate about whether locational signals are strong enough, or indeed whether all locational costs should be removed and socialised across the network.
• Network charge avoidance – whether it is right to encourage cost avoidance by demand customers that are able to reduce their demand during peak periods, either by reducing their actual demand (Demand Side Response) or reducing their net demand by reverting to local generation or energy storage solutions.
• Embedded benefits – as a corollary to the above, the extent to which local generators, and in future energy storage providers, should benefit by providing energy during peak demand periods to allow their customers to avoid network costs.
• Rewarding flexibility, security and decarbonisation – whether network charging should consider only short term cost reflectivity or play any role in actively rewarding technologies and business models that will deliver long term benefits to the UK energy system.

The debate is full of contradictions and dilemmas. For example, seen through the prism of equitable cost recovery, the ability of electricity customers to avoid network costs by targeted demand reduction may seem unfair. On the other hand reducing demand during peak periods is exactly the behaviour the UK energy system wants to encourage, both to reduce the need for even greater investment in infrastructure and to maintain capacity margins to help ensure the lights stay on.

A further dilemma is the extent to which network charges should be purely reflective of current costs, or whether network charges should be used to encourage innovation and investment in new, more flexible (low carbon) technologies, which will be more cost effective over the longer term.

Ofgem’s interventions

In the past month Ofgem has made two very significant interventions that have already had an impact on investor confidence:

1) Ofgem’s Open Letter Charging arrangements for embedded benefits

This letter, published on 29 July 2016, sets out in very strong terms that Ofgem considers the existing charging regime for Transmission Network Charging to be broken.

In particular Ofgem has identified that the main component of demand charging (TNUoS Residual Demand Charges), which are calculated based on the Triad peak demand periods, is no longer cost reflective and may be excessively rewarding distributed generators who are enabling their customers to avoid network charges. While demand reduction is to be encouraged,Ofgem argues that the impact of cost avoidance may ultimately lead to the fewer remaining customers paying ever increasing costs for the grid.

Of more immediate concern, the profits made by decentralised generators, and specifically diesel generators, is having a knock on impact in the Capacity Market by reducing capacity market payments to the extent that new large scale gas projects are unable to compete.

The letter suggests a number of options which Ofgem is minded to consider (some based on modifications already submitted), but does not detail how Ofgem would tackle the main issue of transmission cost charging and embedded benefits.

To put this into context, for a distributed energy generator specifically targeting Triad avoidance, the cost in lost revenues (or costs avoided) if all embedded benefits were removed could be worth up to £45,000 per MW per year.  For a variable generator (wind or run of river hydro for example) the loss of embedded benefits would be less severe, but could still amount to circa £4-5 per MWh per year. This shows a significant revenue loss compared to the current wholesale price.

The Association for Decentralised Energy has also issued a very useful analysis of the potential impacts of changes to embedded benefits compiled by Cornwall Energy^[4].

2) Ofgem’s decision to approve DCP228[5] (raised by British Gas) a change in the calculation of Revenue Matching in the Common Distribution Charging Methodology (CDCM)

The second intervention, which may have been missed by anyone not closely following the development of the CDCM, approves a significant change to the way in which distribution network charges are allocated across the main Distribution Use of System (DUoS) banding periods.

The rationale for the change is that the existing charging calculation is not cost reflective and puts too much cost towards peak demand customers. When implemented in 2018, it will generally[6] reduce the network charges made to peak demand during the Red Zone periods, 16:00 – 19:00 evening peak, with charges being reallocated to off peak periods.

As an illustrative example for high voltage, half hourly billed customers in the WPD south west licence area, it has been estimated that the highest Red Zone charges could reduce from 18.014 p/kWh to 6.397 p/kWh with consequential increases in the off peak amber and green zone periods.

As well as tending to shift charges away from peak demand customers towards the general usage customers (from which there will be winners and losers), the effect of this change will be to reduce the incentive for demand side reduction and/or local generation during the peak red zone demand periods.

The impact this change will have on renewable energy generators will vary according to technology and by region. The impact will be felt most strongly by those generators that are actively targeting generation during the evening peak ‘red band’ periods, such as electricity generating AD and CHP energy from waste plants. It will also severely impact diesel and gas reciprocating engine generators.

For variable generators, such as onshore wind and PV, the impact will be less severe since variable technologies do not actively target the ‘red band’ periods, and in the case of PV, no evening embedded benefits are earnt. Since distribution network costs will now be more evenly distributed across the day, the net impact on embedded benefits should in theory be neutral. A lot will depend on the specific terms of a generator’s Power Purchase Agreement.

The most worrying impact will be on those companies that are considering implementing energy storage or demand side response schemes and who have used network cost avoidance as part of the business case. It may well be that the current charging methodology is wrong, but once again this opaque change to charging rules will make investors increasingly nervous when considering the firmness of future revenue streams. Regen has already spoken to a number of investors who are putting their projects on hold.

Regen is happy to field questions from our members on this subject. We would advise you to contact your DNO to find out how tariffs will change and review your PPA terms.

Regen SW response

The Ofgem open letter is open to consultation and Regen has responded on behalf of its members with an emphasis on ensuring that any new charging methodology recognises the benefits of decentralised low carbon generation and the inherent value of building more flexibility into the UK energy system, through initiatives like demand side response, energy storage, local supply and local network balancing.

While we agree that the network charging system needs to be overhauled, we are concerned that the two potential change options identified in the letter would a) not address the distortion Ofgem has identified in the transmission network charging methodology and b) would arbitrarily penalise decentralised generators including future energy storage and demand side response providers.

It seems odd that, having set out a broad case that the existing system is not fit for purpose, Ofgem would consider two very short term fixes:

• Modification proposal CMP264₂₀ raised by Scottish Power would stop any new distributed generator connecting after June 2017, from receiving embedded benefits. Such a change would not address the issue of cost reflectivity for existing generators and would arbitrarily penalise new entrants.
• Modification proposal CMP265₂₁ raised by EDF, would remove the ability to get TNUoS demand residual payments from all distributed energy generator with capacity market contracts. Again this would not address the issue of cost reflectivity but is intended mainly to rebalance the capacity market away from diesel generators.

Although neither of these options would directly impact behind the meter generation for high energy users, the Ofgem letter suggest that further measures may be taken to curtail behind the meter generators.

“We have considered that changes to embedded benefit arrangements could lead to unintended consequences since it may push more connection of generation behind the meter or connection via private wires, which is likely to lead to inefficient outcomes. This is an important issue that will aim to take into account in future related network charging work.”  

Overall the approach suggested seems counter-productive. The UK energy system needs more, not less flexibility. There is also an imperative to reduce peak demand and encourage demand side response. While accepting that incentives and rewards should be set appropriately, the risk of changing the system in an ad hoc manner will be to potentially increase peak demand and reduce available flexible capacity.

Although Ofgem has encouraged the ‘industry to get involved’, there is also a concern that the detailed charging code modifications raised by large utility generators, who clearly have a commercial interest in the charging mechanism, may not be fully considered by the wider industry, high energy users and key stakeholders. Neither the Open Letter, nor the changes to the distribution network charging methodology, have assessed the widespread impact of changes to the treatment of embedded benefits.

As a further observation we would highlight that the papers used to document charging modifications (for example DCP228) are almost impossible to read and understand by anyone outside the sanctum of network charging.

In the past, with only a few generators and supply companies in a select club, this may not have been an issue, but now with the democratisation of energy generation and the direct engagement of a large number of high energy users through demand side response, a more open and transparent engagement is needed.

Rather than pursuing either of the proposed modifications options, Regen would encourage Ofgem to look more holistically at the problem and endeavour to create a long term framework that will encourage, and not dissuade, future investment.

Underpinning such a charging system should be a set of key principles including, cost reflectivity and the promotion of competition, but also recognising:

1. The inherent network saving of decentralised energy generation and local supply
2. That peak demand, although not the only cost driver, is still the primary driver for infrastructure investment
3. The value of flexibility through measures such as energy storage, Demand Side Response and local supply and network balancing
4. The need to encourage innovation and enable new technology for long term cost effectiveness
5. The overall priorities for decarbonisation and energy security
6. The need to engage with, and understand the impacts on, a much wider range of stakeholders including community generators, energy users and local stakeholders.

It would also make sense to try to harmonise and align the methodologies for network charging across the transmission and distribution networks in order to facilitate the transition towards a Distribution System Operator (DSO) model.

The National Infrastructure Commission report Smart Power Revolution makes a very strong case in favour of a smarter, more flexible and decentralised energy system, which could ultimately save the UK consumer over £8 billion per annum compared to a system based on redundancy and over capacity. While it may not be the job of the network charging regime to achieve this outcome, it is important that any changes to network charging do not inhibit its development.

Following Ofgem’s call for evidence, Regen issued a response paper, Network Charging For Flexible Future September, which asks Ofgem to take a more holistic approach and consider the wider impacts of any changes to the grid charging review. As well as supporting innovation and the development of new technologies, the paper makes the case for a full strategic review of grid charging to ensure that it is appropriate for the UK’s future energy system and supports greater levels of energy flexibility through energy storage, demand side response and local network balancing.

Get involved

It’s an arcane subject but the future of network charging will have a significant impact on the UK’s future energy system and will undoubtedly affect investor confidence and the business case for local supply, storage and generation markets.

We would welcome your comments and contributions to the debate and would like to encourage our members and wider business colleagues to engage with Regen and the renewable energy trade bodies on this subject.

[1] National Grid TNUoS Tariff Forecasts 2017/18 to 2020/21

[2] Based on BSUoS SF charges August 2016-July 2016 – National Grid Current BSUoS data

[3] Based on total DNO “Allowed Revenue” for 2014/15 in 2012/13 prices – Ofgem Electricity Distribution Company performance 2010 to 2015

[4] Cornwall Energy :  A Review of the Embedded Benefits accruing to Distribution Connected Generation in GB May 2016

[5] Ofgem Distribution Connection and Use of System Agreement (DCUSA) DCP228 – Revenue Matching in the CDCM

[6] The actual banding changes are complex and will vary by region. Regen SW suggests that generators and demand customers ask your local Distribution Network Operator for an analysis.

Author: Johnny Gowdy

Contact: jgowdy@regensw.co.uk