Toxic constraint coverage could damage Clean Power Plan

At a glance

• Constraint costs have risen in 2024 (Jan to Sept) to over £1 billion. This is a problem that must be addressed.
• Media narratives incorrectly simplify the issue of constraints, implying that rising costs are to pay off wind farms, despite 76% of constraint costs relating to payments to gas generators and systemic grid limitations.
• Compensation to wind farms amounted to less than 24% of constraint costs. This is strictly regulated – they will have received their wholesale revenue, so constraint payments are only to cover their marginal revenue losses from a loss of network services.
• Historical delays in network investments have caused significant grid bottlenecks, particularly across Scottish transmission boundaries and elsewhere in the GB network.
• In 2024, these have been exacerbated by a significant reduction in Transmission Limits across the main Scottish transmission boundaries, and elsewhere, leading to increased constraint volumes.
• Gas generators dominate current Balancing Mechanism actions due to current limitations in dispatch processes despite the availability of cheaper, alternative solutions like energy storage and demand response.
• Some have called for zonal pricing to reduce constraint costs, encourage demand response and shift constraint risk to generators. This would be a radical market redesign with severe unintended consequences, including fairness impacts and a risk to future investment
• The solution lies in a programme of Progressive Market Reform to accelerate infrastructure investment, improve competition in balancing markets, develop new constraint and flexibility markets, harness demand response and align grid, generation and interconnector investment with strategic energy goals.

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The wrong message

It’s true: constraint costs in 2024 are on track to be one of the highest ever. As of September, the National Energy System Operator (NESO) was reporting total YTD constraint costs running at £1.11bn, compared to a full calendar year total of £1.37bn in 2023. It’s not a record, though; the highest GB constraint cost year so far is the £1.95bn that occurred during the energy crisis of 2022, when gas and whole electricity prices were at their height.

The rise in constraint costs has also been highlighted to further the case that the current market is broken and can only be fixed by a radical solution like zonal pricing, splitting the GB market up into a dozen or more separate markets to give stronger price signals. We don’t think that’s true (there are better alternatives), although we do fully support the premise that we need to do more to harness wasted wind power.

Unfortunately, the two arguments – that constraint costs are rising and that we need to do more to harness the value of wasted wind – have become conflated by right-wing media into a far simpler message that constraints are caused by naughty wind farms generating too much energy in the wrong place – and it’s all the fault of the government’s push for clean power and renewable energy. Or an even simpler message, implying through headlines and loose language that the ‘billions’ spent on constraint management are to ‘pay off’ wind farms.

This could have long-term consequences if Nigel Farage and co succeed in fixing the idea in the public imagination that renewable energy equals ever-higher constraint costs. The real message is that, because of past decisions, we have insufficient network capacity and are being forced to shed low-cost wind and replace it with very expensive gas generation.

Most constraint costs are not to compensate wind farms – they are to pay gas generators

As usual in these areas, there is complexity and a fair degree of misunderstanding, making constraint costs an easy target for publicists and politicians to mount attacks on net zero based on partial truths and misleading headlines.

In fact, just under 24% of the constraint costs in 2024 YTD have been used to compensate wind farms. That’s £271 million, out of the total of £1.11 billion. £271 million is still a lot of money, and any unused low-carbon energy is a waste that needs to be addressed, but the scale of payments to wind farms is nowhere near that reported.

Rather than making money from constraints, the amount that wind farms can claim for constrained energy (that is, energy that the grid is not able to deliver to its customers under the terms of its connection agreement) is strictly controlled by Transmission Constraint Licence Conditions (TCLC)[1] and is limited to the lost marginal revenue incurred by the wind farm. Lost marginal revenue is mainly made up of lost subsidies (e.g. Renewables Obligation payments), the value of the lost Renewable Energy Generation Certificate (REGO) and, in some cases, lost CfD payments.[2]

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Addendum after criticism received that the article was misleading: Wind farms will have already sold their energy in the wholesale market and will receive revenue for this transaction, so the constraint payment received is just to compensate for their additional lost revenues in subsidies and REGO value. The wholesale revenue is not considered a constraint cost, but there is an economic cost in the form of wasted energy.

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Table 1. 2024 Constraint costs by fuel type – calendar year to date (millions)
2024/millions	Jan	Feb	Mar	Apr	May	June	July	Aug	Sep	YTD
Wind	£32	£33	£28	£32	£6	£29	£12	£68	£32	£271
Gas	£69	£79	£89	£99	£64	£133	£54	£171	£87	£846
Total	£115	£114	£121	£140	£79	£142	£66	£228	£112	£1,117
% Wind	27%	29%	23%	23%	7%	20%	18%	30%	29%	24%
% Gas	60%	70%	74%	71%	81%	94%	82%	75%	78%	76%
Volume TWh	1.18	1.33	1.41	1.53	0.94	1.62	0.78	2.33	1.10	12.22

Source: NESO Monthly Balancing Services Summary Reports 2023/24 & 2024/25

 

Why should wind farms and other generators receive any compensation at all for being turned down? This argument has gone around the houses. The reason we currently compensate generators is that they have a firm connection agreement with the network operator, remembering that they will have probably waited several years to get a connection, may well have contributed towards distribution network reinforcement and will, in constrained areas, be paying very high transmission network charges (TNUoS).[3]

So, basically, they are paying for a service they are not getting. We could not pay constraint compensation. That would be a policy decision that would reduce revenues for generation, but it would also increase investment risk and would likely either result in higher subsidy payments or lower levels of investment.

The biggest portion of constraint costs is incurred to pay gas generators, usually to increase output to meet demand and replace constrained generation. In 2024 YTD, payments to gas generators equalled 76% of constraint costs, which amounted to £846 million.

By contrast with turn-down payments to wind, gas generators can charge a market price to turn-up generation, which means that gas generation costs will increase with the wholesale price and their ability to extract excess profits (scarcity rents) because of the lack of effective competition within the balancing mechanism (BM) used to take constraint actions.

 

“We know our operational systems, processes and networks have not always kept up with the pace of this rapid transition. Challenges remain around incorporating new technologies into legacy systems and have, therefore, hindered our ability to effectively access and utilise these electricity storage assets.” 

NESO: Defining, measuring, and addressing skip rates: commitment statement 2024

 

This lack of competition and higher cost in the BM has been highlighted by the analysis on ‘skip rates’,[4] which shows that the NESO control room will tend to dispatch a gas-fired power station even though there may be cheaper alternatives available, such as energy storage and demand response. The control room’s default to gas is partly system-driven, but is also due to IT, data and process limitations, which NESO has identified, and the need to widen Balancing Market participation so that it becomes a truly competitive market for both energy balancing energy and increased utilisation of constrained energy.

Why are we seeing higher constraint costs?

Anti-renewable rhetoric is to say that wind farms are being built in the wrong places far from demand, and so the grid can’t cope. This is a contortion on the actual history of renewable energy development. The location of generation projects is determined by several factors, not least where there are resources, land/sea space and where they can get planning. A key factor, however, is whether they can get a network connection, which can take years and hence the very long queues to get a network connection we see today.

Wind farms don’t just build themselves without a (usually firm) network agreement. A problem, however, is that, over the last decade, the rate of build of new network capacity has fallen short of the capacity needed, especially in some key areas such as the north-south boundary between Scotland and England. This was known as the ‘connect and manage’ period, when there was a preference to connect new generations quickly but to delay network investments because, at the time, this was believed to be cost-effective.[5] This missing capacity has been well documented and has led to calls to massively accelerate network investment, as highlighted in Electricity Networks Commissioner Nick Winser’s report on Accelerating electricity transmission network deployment.

The failure to invest in the network capacity we need has led to a complete and radical change in how we now plan for the future energy system, accelerate infrastructure investment and manage the connection process. The new approach where network investment, new generation, storage and grid connections (plus the use of flexibility) are brought together in an aligned strategic plan should significantly reduce the constraint problem and accelerate clean power delivery. It also answers most of the challenges about giving effective investment locational signals to the market. In the meantime, however, the GB energy system is still playing catch-up after a decade of slow and inadequate network investment.

Why have constraint costs jumped in 2024?

In general, there are two main drivers of increased constraint costs:

• The volume of generation and how this increases vis-à-vis network capacity.
• The wholesale price of electricity, which determines the cost paid to gas and other generators to turn up generation to rebalance the system and replace the (usually much cheaper) constrained electricity.

There is, however, also a third factor that is often overlooked: the availability of network transmission capacity at any given time over the main constraint boundaries. Networks require shut-down periods for maintenance and operational reasons, and for major upgrades and reinforcement. The level of available capacity limits (measured as a % of the nominal capacity that could be available) has been significantly lower in 2024 compared to previous years. Also, unlike previous years, the low capacity limit periods have extended from the summer months into the autumn/winter period; in fact they are still present today.

Table 2. Comparison of 2024 and 2023 – January to September. Annual summary of constraint costs, volumes and generation, 2024 and 2023
	2024 YTD Jan-Sept	2023 YTD Jan-Sept
Total volume constraint Jan – Sept	12.2 TWh	7.6 TWh
Constraint cost	£1.1bn	£0.89bn
Constraint cost/MWh	£90	£118
Wind (metered) generation Scotland England and Wales	34 TWh 60 TWh	23 TWh 51 TWh
Mean wind speeds	-0.2 knots below 20-yr mean	-0.4 knots below 20-yr mean
Installed wind (at start of year) Onshore Offshore	28.7 GW 13.2 GW 15.4 GW	27.3 GW 13.4 GW 13.9 GW
Wholesale prices Average monthly LCCC reference prices	£90/MWh	£117/MWh

Sources: NESO wind generation metered output,[6] National statistics average wind speeds and deviations from long-term mean,[7] LCCC Wholesale Reference prices, DUKES Plant installed capacity.[8] 

At 12.2 TWh, the constraint volume to September 2024 is significantly higher than the equivalent period in 2023. It is difficult to explain this increase through an increase in renewable generation capacity. Wind is not the only cause of generation constraints, but it is a significant contributor; however, wind capacity increased by around 1.4 GW between the start of 2023 and 2024 – an increase of just 5%. Additional capacity has also been added during 2024.

This year has been, however, windier than 2023. Neither were particularly windy, but 2024 had on average 0.2 knots higher mean wind speeds from January to September. That may not seem a lot, on average, but 2024 appears to have had more days with significantly higher wind generation and seasonally higher generation in late spring (March and April) and the summer months (June and August). These correspond to higher constraint months and periods when less transmission network capacity was available.

Lower transmission capacities – especially over the Scottish boundaries

The third cause of constraint – lower available capacity limits – has been a major factor. The transmission capacity available over the main Scottish and other GB-constrained boundaries has been significantly lower in 2024 than in 2023.

Focusing on Scotland, the Scotex B6 boundary has been operating at between 50% and 65% of its nominal capacity of 6,800 MW in the period from May to November. It was especially low during August and September. As of early December it was still at 56% capacity.⁹ The B4/B5 boundaries, nominally 3,400 MW, have also been operating at below 50% of their nominal capacity, as has the B6a boundary.

While we tend to focus on Scotland as the main area of constraint, constraints are now appearing in England and Wales and, in fact, one of the key constraint boundaries is East Anglia and South East England. Others that have been below their full capacity limits in 2024 are the EC5 boundary in East Anglia and GEMSNOW boundary in North Wales.[9]

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lower capacity limits are not unusual and are mainly the result of maintenance operations and upgrades during the summer months. We should expect them to continue. The B6 and B4/B5 upgrades are significant and are expected to continue over the next two years. However, 2024 does appear to have experienced longer and deeper capacity limit periods going into autumn and winter. These also corresponded to higher wind periods and therefore produce a higher volume of constraint.

August is a good example of both higher wind speeds and lower transmission capacity limits on the B6 and B4/B5 boundaries, leading to a jump in monthly constraint volume and cost.

 

 

So the story of why constraints have been higher in 2024 is a mixed picture of:

• A modest increase in wind and overall renewable energy capacity
• Higher wind speeds and, therefore wind, output, especially in Scotland in key months
• Lower transmission capacity limits over key constraint boundaries that stretch from the summer months into the autumn and early winter
• Offset, to some degree, by lower wholesale prices.

It’s a less pithy message, but the reality is that a historic backlog of slow network investment, combined with current transmission capacity limits and higher wind output in 2024, has caused the constraint volume to increase. This has resulted in wasted wind generation and the need to pay for more expensive gas generation to replace the lost wind power.

What should we do about constraints in the future?

There is agreement that the current situation cannot continue. Some degree of constraint may be inevitable and even economically optimal, but we cannot afford to waste Terawatt hours of low-carbon generation and replace that with far more expensive and high-carbon gas generation.

Zonal pricing is not the answer

One proposed solution is to redesign the GB electricity market around zonal pricing. Splitting the market into zones that correspond to the transmission constraint boundaries. If accompanied by a removal of generation grid firm access rights, and therefore constraint payments to generation, this would drive down the price of electricity during constraint periods and, in principle, encourage higher demand. It sounds compelling, especially when it is claimed that the current market only has a single price and is unresponsive to excess supply – which is not true.

Zonal pricing and market division would, however, be a very radical upheaval of the market, bringing with it increased investment risk and a number of unintended consequences. Generators would almost certainly need to be compensated for lost revenue and/or given higher subsidies, or they would not invest. Zonal pricing would not just reduce the price of constrained energy, but the price of all electricity in the constraint zone (to negative or near zero) for the duration of the constraint. This would create a temporary bonanza of low-cost energy for those consumers that can exploit it. It would, however, have significant distribution and fairness issues for consumers with less flexibility, those who would face higher prices in zones that are demand rather than generation-constrained, and consumers everywhere who will be paying higher subsidy and CfD payment costs.

An important consideration is that the balance of supply, demand and network capacity would not be fixed. A constrained zone offering the promise of periodic low-cost energy today will disappear as networks invest in new grid capacity unless the construction of the grid is itself challenged by consumers wanting to keep constrained prices in place.

A further obstacle is that we have not been presented with a worked-up zonal design, but it is likely that the complexity and challenge of operating multiple zonal markets will entail a shift back to a more centralised and day-ahead dominated market, with less opportunity for bilateral trading and PPA transactions. This would be a step backwards, especially for the thousands of small-scale distributed generators and demand consumers.

A better way – Progressive Market Reform

This summer Regen published a paper on the alternative options to embark on a programme of ambitious but progressive market and operational reforms based on the strengths of the current national decentralised market.[10]

Focusing on the issue of constraint costs,[11] the Progressive Market Reform paper highlighted eight key steps to provide both long-term and near-term solutions to reduce the growth of constraint costs:

Step 1: An aligned energy and infrastructure plan for generation, storage, network investment and interconnectors

This addresses the fundamental problem that during the energy transition we need to ensure that the build-out of new generation is accompanied by allied investment in network and other infrastructure. The market can provide the necessary investment capital but, left to its own devices, it cannot align the timing and location of that investment. There are too many variables, most of which lie under the control of the UK government, system operators, regulators and network companies.

It is very positive that this plan-led approach now seems to be broadly accepted and is coming forward in the form of the Clean Power Plan, the Strategic Spatial Energy Plan, Central Strategic Network Plans and the more granular Regional Energy System Plans and network investment plans. We are shifting from a period when there was no overarching energy plan to one where we may, if not careful, end up with too many!

Step 2: Accelerate the pace of investment in network infrastructure

The relative slow speed (and cost) of network investment in the UK has been well documented. Electricity Network Commissioner Nick Winser’s report Accelerating electricity transmission network deployment marked a turning point on how we approach network investment with a focus on supporting strategic anticipatory investment, speeding up planning processes and decision making, increasing supply chain capability and proving incentives (and penalties) for networks to build out new capacity on time. This has been supported by a shift within Ofgem towards Accelerated Strategic Transmission Investment (ASTI) and changes that are coming for the distribution networks to increase the pace of anticipatory investment in the next price control period.

These initiatives are all good as part of the mission-led Clean Power Plan. The challenge now is about delivery and whether networks, planners, investors and regulators can make good on their promises. The prize, however, is huge, as the Clean Power Plan highlights a more rapid delivery of the roughly 80 network investment projects plus some accelerated projects in the southeast of England that could reduce the potential constraint costs in 2030 from c. £6bn to c. £1bn.

Step 3: Proactively manage connections (with industry) aligned with the overall strategic plan and infrastructure build

Critics of the planned approach will highlight that there is a good chance that network investment will again fall behind schedule. In truth, this is also true of new generation and storage projects. Every dimension of the Clean Power Plan is ambitious and we are as likely to fall behind on, for example, offshore wind and interconnection targets as on grid.

So it’s important that the plan is iterative and that we are able to manage the pace and location of new connections, albeit that developers also need a degree of forward certainty in order to secure capital and deliver their projects.

Connection reform, which has been running in parallel with market reform, will have a very significant impact on the future level of constraint and how we manage this. The new approach, is summarised in an open letter from DESNZ and Ofgem: Aligning grid connections with strategic plans Nov 2024.

The summary of the new approach is that the connection queue will be reordered and managed based on two key factors: 1) the readiness of projects to move forward to construction and 2) the ‘need’ for new capacity by technology and location to meet the Clean Power Plan 2030 and, in future, the Strategic Spatial Energy Plan. This is a very different approach compared to the previous market-led, and largely uncoordinated, ‘connect and manage’ approach.

Step 4: Widen access and improve competition and operation of the Balancing Mechanism

As already highlighted, it is recognised that the current BM is not functioning efficiently. In particular, although there has been an ongoing programme to widen access to many more smaller assets, storage and demand-side response, the reality is that BM actions are still dominated by the use of gas-fired power stations. This has led to challenges from the industry about the ‘skip rates’ when cheaper assets are not being dispatched in merit order.

Fixing the BM will take time, and will require significant investment in IT and new processes within the control room, but a number of initiatives are already under way, including the implementation of the new Open Balancing Platform, which will enable the control room to schedule and dispatch multiple smaller assets, as opposed to a single large gas plant.

NESO has recognised both the challenge and opportunity to radically change and upgrade the way it manages the BM and other operational services. Overall, the programme of reform that has been proposed could save the consumer up to £18bn by 2030.[12] A significant portion of this will be in constraint costs.

“Future balancing costs are not fixed and can still be influenced by proactive initiatives from ESO and industry to reduce costs. We have been undertaking a wide range of initiatives within our balancing costs strategy that are aimed at minimising balancing costs, including our Beyond 2030 report, ASTI, new markets such as Balancing Reserve, and many others.”

– NESO, 2024¹²

Step 5: Take every opportunity to increase capacity limits and flow over the existing capacity

NESO has already embarked on a number of innovation projects and technical enhancements to improve constraint forecasting and to enable system operation that makes better use of available capacity. For example, the Constraint Management Intertrip Service (CMIS) reduces the cost of managing constraints by building post-fault intertrip links which can facilitate more power to flow on the existing transmission infrastructure pre-fault, thus reducing the amount of generation being constrained.

NESO has also launched the Constraints Collaboration Project to seek industry-led solutions to thermal constraints that can be deployed efficiently, both economically and technically, in the short term. This includes technical options such as extended intertrip schemes and the use of batteries to maximise flows over boundaries (grid-booster and transfer-booster).

Step 6: Develop new market solutions for constraint management

The BM is likely to remain the workhorse market for taking balancing actions to manage constraints. However, a disadvantage is that actions are predominantly taken after gate closure – currently one hour ahead of delivery. With the current toolset, this does not give system operators much time to optimise their constraint response.

A complementary approach would be to enable pre-gate closure constraint actions using either pre-established flexibility contracts (similar to how flexibility is currently procured on the distribution networks) and/or establishing local constraint markets.

For example, if NESO identifies that the Scottish B6 and B4/B5 boundaries are likely to be significantly below their nominal capacity limit for a two-year period, as we are now experiencing, an approach would be to set up a flexibility service with battery storage and demand response provider to provide a demand turn-up service within the constraint and a generation/demand turn-down service in northern England.

This would not replace the BM but would provide a complementary and competitive service to manage specific constraint boundaries for a specific timeframe. It would also create more competition within the BM and provide a stimulus for investment in both storage and demand response, potentially saving the consumer many millions.

Trials of flexibility and local constraint markets have been undertaken, but there is a need to be more ambitious in this area, recognising that constraint costs are increasing and are already costing the consumer many millions

Step 7: Harnessing demand side response

There is no doubt that a significant cost of constraints is wasted low-carbon renewable energy. This goes beyond the compensation payments made to generators and includes the inherent value of the energy lost and its carbon reduction potential.

A zonal pricing approach would send very strong price signals to encourage demand at times of constraint, but for reasons already described, this may not be efficient and would have other unintended consequences.

Approaching the problem more directly, a combined approach could be taken that would encourage decentralised demand response:

• Improving future constraint forecasting and transparency. The BM, for example, is locational in that actions are taken to address specific boundaries, but the locational aspects of the BM are not well understood by the market, nor are future constraint forecasts.
• More rapid implementation of half-hourly metering and reducing settlement periods.
• Widening access to the BM and greatly increasing the utilisation of DSR flexibility – see Step 4.
• Implementation of flexibility and local constraint markets that are designed to encourage DSR solutions – See Step 5.

A key advantage of this targeted approach, as opposed to a locational wholesale price signal, is that it would encourage different innovative solutions from a wider range of market actors, it would also encourage investment in flexibility service provision by storage and DSR providers. The further important point is that it should be easier to then coordinate flexibility services between different voltage levels (a key role for Elexon) and reduce the risk of either contradictory signals or the loss of load diversity on the low-voltage network.

Step 8: Improving management of interconnector flows and our cross-border arrangements

Interconnectors are complex and deserve a paper in their own right. Regen and others have been calling for a mission control taskforce to look at the whole question of interconnectors and our wider trading arrangements with the EU, which are currently in poor shape and costing UK consumers millions through inefficient processes and ‘de-coupled’ transactions. This is a wider issue than just the question of constraints that also includes strategic planning, energy security and future carbon trading (CBAM).

The link to constraint is that interconnector flows could begin to exacerbate constraints in areas where imports from our neighbour markets, responding to national price signals, are flowing into parts of the network that are already constrained. At present, because of the challenge of reversing interconnector flows, this is likely to lead to a further turn-down of domestic generation.

Zonal pricing would offer a partial fix to this problem because the zonal price would reflect the zonal constraint and affect the interconnector flow. It is a partial fix because the zones would have to exactly match the constraint boundaries, which will change over time, and there is a likelihood that interconnector scheduling/trading based on day-ahead zonal prices would not capture all constraints or could even set flows based on a constraint that does then not materialise. This forecast error issue does not feature in models that are based on perfect foresight.

LCP Delta has now modelled interconnector flow benefits as the most significant source of system value from a shift to zonal pricing. Regen, and others, believes that these benefits  have been overstated by modelling hypothetical worst-case-location interconnectors that are unlikely to be built (for example, into the North of Scotland), modelling greater interconnector capacity in 2030 than would be built or required, using perfect foresight assumptions and using high counter-trading prices to change flows in the national model. More transparency and realistic assumptions to underpin future modelling is required.

Nevertheless, there is an argument that zonal pricing would help alleviate interconnector constraint impacts and improve flows. The key question is whether a comparable improvement could be made within the current national market arrangements and whether this could be done more quickly. We think the answer is yes, but it will require some innovation and a willingness of the UK government, system operator and regulator to fully engage in the reform process and be willing to negotiate with our EU neighbours. This will be a challenge, but in the context of forging better trading arrangements with Europe, there is also an opportunity for the energy sector to lead the way towards greater cooperation. Failing a cross-EU approach, there is also an opportunity to enter into bilateral cooperation agreements with Norway and Ireland in particular.

What needs to be done with interconnectors? There is not space to do justice to the subject here, but in general terms three steps are needed:

1. Aligned interconnector investment plans

Interconnectors need to be included within the overall Strategic Spatial Energy Plan. There is no point in building interconnectors in the wrong place and wrong timeframe via-a-vis transmission and generation deployment. This should greatly reduce the more extreme scenarios of detrimental interconnector flows. In this regard, it is understood that interconnectors will be included in the SSEP and Ofgem is already taking a more deterministic approach in the award of Cap and Floor contracts to ensure that interconnectors provide overall system value.[13] NESO has also begun to consider the optimal interconnector configuration for different net zero pathways.[14]

2. Interconnector capacity limit management/pre-allocation

There is some debate about the extent to which system operators can adjust interconnector capacity limits in order to address overall system efficiencies. It is clear that they can bilaterally change capacities for system security purposes and it is also clear that they should not arbitrarily change capacities post interconnector trading and scheduling.

If, however, an SO is faced with a prolonged system inefficiency – an interconnector flowing into a grid-constrained area – there is some ambiguity about what it can do to either limit or manage interconnector capacities on a medium-term basis. A recent example is Norway, which, in consultation with the GB SO, restricted flows on the 1400 Viking link to 1100 MW with a daily limit allocation in order to reduce what it considered to be uneconomic flows into GB and Europe.

More work is needed to look at the terms of the post-Brexit TCA Section 2, Article 311(1b), especially clause F and G, which refer to constraint management. Even if the current TCA would seem to restrict capacity limits there could be a good case to renegotiate this as part of the updated TCA or by bilateral agreement.

A change to approach would have to address the impact on future Interconnector investment through the Cap and Floor mechanism

3. Enhancement to improve interconnector counter-trading, flow management and SO-to-SO trading (balancing)

There is a lot that can be done to improve the performance of interconnector flows and enable SOs to trade within the market more effectively to effect flow in a cost-efficient way. My colleague Simon Gill has looked at these in more detail, including innovative approaches that are being used between Germany and Denmark to enable cross-border balancing.

Conclusion

The toxic, and sometimes daft, media coverage of the constant cost rise is a reminder that we need to get ahead of the genuine concerns that people have about the cost of the net zero transition and where it will fall. Unfortunately, in energy, there are seldom simple, digestible answers. The temptation, then, is to reach for soundbites and headlines, especially if trying to promote a specific reform proposal. These may grab public and policymakers’ attention but, over the longer term, will foster a greater degree of mistrust.

Measuring, understanding and solving the constraint problem is not a simple proposition. We hope this post has shed some light on the underlying causes and how these could be addressed.

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For a straightforward guide to countering misinformation, see our recent work with the All-Party Parliamentary Group on Renewable & Sustainable Energy, Onshore Renewable Energy: Common Myths.

 

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References

[1] TCLC Conditions are controlled and have resulted in generator fines (for both wind farms and gas generators) for overcompensation (higher bid prices in the Balancing Mechanism).

[2] There is a proposed code modification (P462) to remove subsidy payments from the bid prices and constraint costs on the basis that these are policy payments for investment.

[3] TNUoS charges are significantly higher in constrained parts of the network and especially in Scotland.

[4] The Skip Rate issue has been well documented in the past year and acknowledged by NESO as a significant problem that must be addressed.

[5] It is widely understood that ‘connect and manage’ was badly managed and that the cost of constraint management CBA was over-optimistic, based on far lower gas prices.

[6] NESO data portal https://www.neso.energy/data-portal/monthly-operational-metered-wind-output

[7] https://assets.publishing.service.gov.uk/media/67447e8e1034a5f4a58568f2/ET_7.2_NOV_24.xlsx

[8] https://assets.publishing.service.gov.uk/media/66a7dab0fc8e12ac3edb068f/DUKES_5.12.xlsx

[9] Details of Transmission Capacity Limits can be found through the Operational Transparency Forum weekly updates 11 December and the Daily Capacity Limits Dataset.

[10] Regen : Progressive Market Reform for a Clean Power System, 2024

[11] see Regen presentation for the DESNZ Select Committee on Constraint Costs Reduction,  Feb 2024

[12] For more detail see NESO Balancing Costs and Future Projections 2024

[13] Ofgem https://www.ofgem.gov.uk/decision/initial-project-assessment-window-3-interconnectors-decision

[14] NESO https://www.neso.energy/document/349166/download