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Grid Charging and the Road to Net Zero

RenewableUK recently published an analysis by Baringa which aims to bring much needed clarity to the debate which surrounds network charging policy. In this blog, our Policy Analyst Yonna Vitanova explores the key issues for the industry and the importance of a grid charging regime which supports efforts to achieve net zero in a post-covid world.

With most of the world under some form of lockdown, we thought it would be a good time to get up to speed on the key issues which the energy industry is focusing on. Grid charging is one which might have dropped off your radar unless you’re a geek like me!

For some time now, Ofgem had been carrying out a fundamental review of the grid access and charging policy, driven by its objective of creating a regime that supports the transition to a smarter, low carbon energy system.

Ofgem has already published two working papers, followed by an open letter with shortlisted policy options on the issue, and it is fair to say that the regulator has painted a complicated landscape of potential changes to the current framework. The overall short-term impact of this to network users is significantly increased uncertainty. Clarity in policy direction through this wave of changes will be particularly important for the future development of renewables and flexibility on the system.

The aim to deliver net-zero by 2050, as well as a green economic recovery after the pandemic should fundamentally be aligned to the reforms proposed under this review, and those of other ongoing changes in the energy market. These targets mean that the progress we have seen so far, and the technology delivered to date, will now have to go further and faster. While the review on charging and access was launched before net zero by 2050 became law, the way forward should take into account the long-lasting implications of both net zero and the green economic recovery post-COVID on efforts to achieve economy-wide decarbonisation. We recently released a report which aims to bring much needed clarity to the debate which surrounds network charging policy and the impact these reforms could have on decarbonisation efforts.

What is the impact to renewable generation?

There are multiple pieces of research concluding that the recent reforms to the distribution of network costs (or more widely known as network charging arrangements) under the Targeted Charging Review (TCR) would have a negative impact on network users such as renewables and flexible assets across all voltages.

As a reminder the TCR reforms set the scene on how residual network charges (or those unavoidable costs network companies incur as a result of investing in the grid) are distributed across different network users, including renewables. Final policy direction under this workstream was announced in November last year looking to enforce changes across a number of areas and over different period of time:

· Generation residual will be set to zero, subject to maintaining compliance with the EU range on transmission charges 838/2010,

· Demand residual charges will be charged on a fixed basis,

· Suppliers will no longer be able to reduce their exposure to balancing charges (BSUoS) through contracting with distribution-connected generation (BSUoS embedded benefits will be removed),

[For a recap on the TCR go check out our earlier blog]

All generators (both currently operational and in development) will have to adapt to the new residual charging arrangements once reforms have been put into the Codes governing these network charging arrangements from as early as April 2021.

The key directions given as a result of the TCR will further remove embedded benefits from existing and planned distribution-connected generation, to the cost of around £2.50-5/MWh – against an expected market price of onshore wind of no more than £30-35 per MWh in the upcoming CfD auction in 2021. A 15% increase in costs will be extremely damaging to the competitiveness of onshore wind relative to other technologies. Onshore wind is the cheapest form of generation, while a less favourable grid charging arrangements could put pressure on deployment, placing significant risk on the development of the most efficient sites.

The economy-wide net zero ambition means that we have to get to a renewables-based system as cheaply and quickly as possible. We do not currently have a market framework to support this. The ongoing reforms to the charging arrangements are just one aspect of the market framework. The changes as currently indicated could significantly undermine the progress we have made to date and hamper our ability to achieve the much-needed rapid deployment to comply with the net zero target. In addition, it is very likely that initial impact from the TCR reforms will be further compounded by increased volatility in network charges as a result of the ongoing period of lower demand, with embedded renewables, which offer consumers decarbonisation at lowest costs, likely to bear most of the burden.

How badly is it going to affect embedded generation?

The overall impact looks to be quite significant.

Looking at the Access and Forward-Looking Charges Significant Code Review (Access SCR) reforms alongside the TCR, there do not seem to be any benefits in Access SCR which will mitigate the impacts of the TCR. Options under the review include:

1. levying additional network charges to smaller embedded generation – these are transmission network charges like TNUoS,

2. changing how network charges are levied based on predominant system flows e.g. either demand or generation dominated – these are distribution network charges like DUoS,

3. changing the upfront connection cost charges which network users of the system have to pay before they connect to the system (amending the connection charging boundary at distribution to shallower regime),

4. creating new network access rights options at distribution such as curtailable and time-profiled access.

Starting from the top of this list, levying TNUoS on smaller embedded generation could significantly increase the costs to some embedded renewables, especially in the north of England and in Scotland. Those areas have a larger proportion of generation capacity relative to demand (generation-dominated) and a significant part of that is renewables, due to the plentiful, natural renewable resources leading to overall site efficiency. On its own, levying additional charges to smaller embedded generation such as TNUoS could present an immense hurdle for onshore wind development, ruling out project development in areas where the resources are excellent, but demand on the grid is low. This charge would be in addition to charges they will pay for access to the distribution network to which they are connected.

The wider context could shine some positive light on this. It would be helpful to consider whether some of the differences which exist between the treatment of small embedded generation and transmission connected generation could be addressed outside the Access SCR, for example through industry-led network code changes. Amendments to the codes are already been worked out, to the extent that levying TNUoS on smaller embedded generation might not be needed or necessary should these changes be incorporated into the codes.

Changing how network charges are levied with incentives for generation to optimise its location based on spare network capacity (or sharper DUoS signals) will be particularly damaging for regions where renewable resources are abundant but demand on the grid is low. A design of the network access and charging arrangements for a net zero energy system would need to recognise that renewables are unable to optimise their location in such a way or factor in highly volatile network charging signals while being faced by external pressure to continually reduce investment costs. Currently the planning framework restricts development of wind in higher demand-dominated regions in the south of the country. Often the wind resource is poorer there too. In the current system sharper network incentives such as speed of connections would not be enough to solve this problem.

There are some positives though.

Connection charges, which are delivered to project developers once a connection offer is received from the distribution company, vary considerably for new distributed generation and are often vastly more up-front than connection charges for new transmission generation (and their ongoing grid costs are much lower). The Access SCR has helpfully noted the current downsides of the regime at distribution level. Under the current arrangements embedded generation has to pay for any network investment which is ‘triggered’ to ensure there is enough network capacity to carry the additional generated power. This is not limited to the extra cables which will be used by a specific party ‘triggering’ the need to upgrade the grid. Such arrangement prevents a more equal sharing of costs and in some cases results in renewable generation having to pay high costs to connect to the distribution network even though they won’t be the sole user of those assets further down the line. The Access SCR is looking at reviewing the current set up, so that costly grid updates and network reinforcement are apportioned over time and new generation is only required to pay for the direct cost of connection. This is the move to a ‘shallower connection’ charging regime with the decrease in cost burden potentially encouraging fairer treatment across new generation and greater competition entry. This could well increase the risk of grid cost volatility over the lifetime of the generating asset, and Ofgem will need to ensure that the resultant methodology does not “bake-in” this risk, for example by ensuring that the grid charges are fair, predictable and transparent over time.

It is important to continue investigating certain network access options going forward.

There is a risk that if small distributed generation (SDG) is paying generation TNUoS on an equivalent basis as transmission generation (under the first option set out in the bullets above), but without financially firm access, then SDG will be overcharged for the grid access rights it has. Financially firm access is a type of contractual arrangement which allows for network operators to compensate generation for times when the grid is unable to transmit power to the location of demand (or in grid-speak, in periods where the system is constrained). Network operators will face the cost of balancing the electricity system with new generation connecting to the network before the grid investment has been rolled out (also known as ‘connect and manage’ policy). Financially firm access to the distribution network will require network security standards to improve which take significant amount of time under current code development processes. As it stands these arrangements have been ruled out for assessment and apply only at transmission - where they have successfully incentivised wider development of renewables such as offshore wind across the country. It is fair to mentioned that similar arrangements to ‘connect and manage’, which allow for grid constraint compensation apply for both transmission and distribution in Germany. It would be useful if financially firm access arrangements could be explored further as an option that is able to resolve the lack of parity which currently exists across transmission and distribution.

Other options under the review, where grid access is curtailed or time-limited, could allow for better use of spare capacity. These options would allow for project developers and the network company to manage expectation on the number of times assets would have to be instructed to turn down (or curtail) or are able to export energy under pre-determined times in advance (time-profiled). There could be some relative benefits from these options to renewables as long as the correct balance is put in place between the new access options, the sharper network signals and ability to make effective investment decisions.

It certainly is right to re-evaluate if the approach taken and the options which have been listed for further consideration could have a significant impact on decarbonisation goals. A specific objective on net zero is currently missing from the driving principles of the Access SCR. Including this would demonstrate a commitment to incorporating the Decarbonisation Action Plan, and the goal to achieve decarbonisation at lowest cost to the consumer, into all currently ongoing work, as well as new work. A net zero objective will demonstrate that the review is considering the full range of costs across the system as a result of net zero. This is crucial to the success of the Access SCR in relation to achieving a green economic recovery in the aftermath of the pandemic as it will actively creating the framework for a market which can achieve net zero.



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