The topic of generator Transmission Network Use of System (TNUoS) is becoming a subject of increasing interest for stakeholders as regulation, policy, and the generation mix create potential volatility for future charging trends. The significant costs posed through TNUoS are an important consideration for generators, with high variability between regions and charging years having large implications for the feasibility of new build sites and the ongoing costs for existing assets.
Most recently, TNUoS charges have attracted concerns from developers in Scotland, particularly Northern Scotland, over high and rising TNUoS costs which now pose a potential barrier to the development of new onshore wind and remote island projects. To explore this topic further, in this blog we have undertaken an analysis of the long-term trends in TNUoS charges, using Northern Scotland and Central London as two examples at different ends of the charging spectrum. We demonstrate how costs have developed over time and outline some of the key drivers behind these changes, as well as the potential for future changes.
Using historical tariff data from National Grid ESO for 2005-06 to 2019-20, confirmed final tariffs for 2020-21 and 2021-22 and the latest five-year forecast out to 2025-26 we have created a timeline of TNUoS charges. Data for Northern Scotland and Central London are outlined in Figure 1, assuming costs for a typical renewable generator, with key developments also plotted along the timeline. These regions have been used to showcase the large differences in locational charges between them as well as for consistency with both regions being maintained as TNUoS charging zones throughout the assessment period.
Across the 20 years, some interesting trends can be seen, showing how regulation, policy, the growth of renewables and the changing generation mix have impacted charges. Firstly, it is worth asking the “why?” of the differences in generator costs. Charging methodologies for TNUoS utilise location based signals, and for generation this has typically meant that generators in regions where power is assumed to be flowing further to reach customers will face higher charges than those deemed closer to demand. Power flows have typically been north to south, with historic economic factors typically seeing higher demand bases in the Midlands, London and South East and greater levels of power generation in the North, typically linked to historic coal field use or North Sea gas access. The trend for more northern located generators has been magnified in recent years by the growth in onshore wind in Scotland.
Therefore, zones further north have typically faced higher generator TNUoS charges, with those farthest south often seeing very low costs or even TNUoS credits. This methodology is clearly seen in our chart with the two zone differences, but it is also worth noting how tariffs in Northern Scotland have shown much greater variability than southern regions over the years.
On the chart, we also highlight how changes coincide with key regulatory and charging developments over the last decade. These include:
- RIIO-1: An increase of 15.8% and 66.7% can be observed across Northern Scotland and Central London respectively around the same time as implementation of the RIIO-1 price controls in 2013-14. Following this increase, tariffs in Central London show a general trend of decline out to 2020-21 whereas Northern Scotland sees significant variability over the same period.
- Project Transmit: Came into place in 2016-17 and established a separate, lower TNUoS tariff for intermittent technologies. Regions supporting high proportions of intermitted renewable technologies, such as Northern Scotland, saw a significant impact from this development with charges across many regions dropping substantially following its implementation. In 2016-17 charges in Northern Scotland dropped by 55.3%, to £11.43/kW. Meanwhile there appears to be little to no impact to charges in Central London where renewable integration is considerably lower.
- Power flows and the Western HVDC link: Tariffs in Northern Scotland increased in the two years following the implementation of Project Transmit, rising to £24.02/kW in 2018-19 and regaining much of the loss observed in 2016-17. During this period, the Western HVDC Link came into operation and facilitated increased power flows from north to south. The net effect being greater power flows from north to south and an increased locational charging signal, with resulting higher costs for those north of this. The proposed Eastern link, whilst facilitating further flows of power, would also have a similar net effect on TNUoS charges in Northern Scotland.
- Targeted Charging Review (TCR): Most recently the TCR has impacted charges, with TNUoS tariffs from 2021-22 set to rise by 42.3% and 58.1% for Northern Scotland and Central London respectively. This rise relates to the implementation of the TCR decision to remove the residual component of TNUoS charges. This residual was a negative figure and once removed for all regions alongside a general increase to tariffs results in a ~£5.00/kW increase across GB for 2021-22.
Looking forwards, based on National Grid’s five-year view of charges, tariffs in Northern Scotland are then expected to gradually increase out to 2025-26. This increase in an already expensive region for electricity generation is of significant concern for developers. We have calculated that annual TNUoS costs for a typical 40MW onshore wind site in Northern Scotland are expected to rise from £0.46mn in 2016-17 to £1.28mn by 2025-26, representing an increase of roughly 180% across the nine years.
Both the volatility in TNUoS and the overall £/kW level are now being seen by some developers as a potential barrier for further deployment of renewables assets on the pathway to Net Zero. Whilst locational signals are important in incentivising generators to locate closer to demand, potentially saving network reinforcement and development costs as well as reducing losses, many generators face little optionality on development locations. Put more frankly, large onshore wind developments are only viable in a few specific locations across the country, notably Northern Scotland, and incentives to locate further south to benefit from lower network charging are unlikely to align with other requirements such as wind speeds, land costs and likelihood of planning approval.
Other parties are also publishing their positions on this topic, with SSEN Transmission releasing a discussion paper on transmission charges on 15 February, calling for views on the current TNUoS charging regime. The paper outlines SSEN Transmission’s findings on TNUoS charging in Northern Scotland and explores the issue of TNUoS volatility and unpredictability. SSEN argues that this variability is largely a result the number of inputs to the methodology that can change each year and suggests that the supporting data and sensitivities used to develop National Grid’s five-year view is “wildly erroneous”. SSEN Transmission is consequently calling for the TNUoS charging regime to be reviewed.
Whilst the current National Grid five-year forecast does provide a view on potential future charges, SSEN’s point on volatility may persist with a number of regulatory changes currently paused or awaiting decision and not currently factored into these five-year views. These include potentially changing the expansion constant calculation (CMP 315) which could stretch and enhance locational signals, and reforms to the current 27 charging zones.
Whilst the outcome of these reforms is uncertain, it is clear that TNUoS charges and associated regulatory interactions now form a material part of the business case assessment for new build assets, especially those in Scotland.
Our independent 15-year TNUoS forecast provides generators with a clear long-term view of potential cost trajectory beyond the typical lens of five-year assessments. We also provide bespoke long-term assessments on the impacts of regulatory change for TNUoS on a site specific and portfolio basis. For more details on our services please contact James Brabben on email@example.com