DATA REPORT: The overhaul of transmissions costs

In the first of our in-depth series drilling deep into the numbers that drive the industry, Dr Trevor Loveday gets to grips with the potential impacts of Project Transmit

Power industry stakeholders recently had their say in a consultation on changes to the charging regime for electricity transmission charging. This is the final stage of Ofgem’s Project Transmit begun in September 2010. Aims for the project were: to drive UK low-carbon generation towards the government target of 30 per cent renewables by 2020; improve security of supply; and rein in the cost of the system to industry and customers. And it is now a debate over the detail.

Detail is the focus because there is no great difference in the trajectory of transmission costs under any of the eight proposals that have emerged from earlier industry deliberations in the project. Ofgem’s impact assessment of options in industry code modification proposals, CMP213, shows the proposed changes to Transmission Network Use of System (TNUoS) charges rising from about £2.5 billion in 2014 to about £3.75 billion in 2020 and reaching roughly £4.1 billion in 2030 with 27 per cent picked up by generators and 73 per cent by users under the UK arrangement.

That’s not to say there will be no significant changes. Investors may note that Ofgem’s favoured option under CMP213 is forecast to add about £1.3 billion to generator profits in the period 2014-2020 spread just about evenly across the UK. Only offshore wind producers are expected to lose out to the tune of just under £90 million over the same period. However once supply and demand profiles begin to align with a low-carbon economy, some £8.47 billion is forecast to be wiped off UK generator profits over the period 2021-2030 with about half of that going from power producers in southern England and South Wales with offshore wind profits falling about £1.75 billion.

Overall CMP213 preserves entirely the principle in play currently which is to ensure users of the transmission system are charged according to the costs they impose through their location in the UK. There remains an incentive to build power plant closer to the demand centre in the south reflected in the current 12 MW north-south flows. The options for TNUoS changes in CMP213 are minor adjustments to the existing investment cost related pricing model for setting TNUoS charges.

An illustration of the extent of the impact of CMP213 is the spread between the proposals with the least and greatest impact on the costs to the entire power sector – costs of generation, transmission, constraints and carbon – is an increase of about £1.8 billion over the period 2014 to 2030.

Given that transmission makes up only 4 per cent of the domestic electricity bill, any increases arising from the adjustments proposed under CMP213 are not going to be significant to most of the population. Changes anticipated in the demand TNUoS element of the household bill which even in the highest cost example adds only about a fiver to the typical bill by 2030. For medium-sized businesses on non-half hourly tariffs it could add £10 a MWh to their bill while heavier users on half-hourly metering are predicted to come out unscathed.

The cost impacts for the power industry and consumers arise in the main from a proposal under CMP213 of a system of charges that differs for intermittent, low power factor plant – mostly wind turbines– and conventional thermal and nuclear power stations. This proposal is CMP213’s chief shift from the status quo. It seeks to align the TNUoS charges for each type of generator with their different call on transmission investment.

The existing TNUoS charges are based solely on the cost of making sure the network has adequate capacity to carry peak load. (Demand is treated as negative generation so the same principle applies to demand and generation TNUoS).  But peak handling is the job of plant that can be on call – not generators like wind turbines that are limited by weather conditions.

 CMP213 proposals comprise variations on a National Grid “Original” proposal and three “Diversity” options derived from the Origina, (see box, below). The variations to each include socialization of 50 per cent of the costs of direct current infrastructure and island links in Scotland.

Tariffs arising from all of the models for non-intermittent generators fall into a narrow spread in most regions of the UK  – again reflecting the incremental nature of the changes under consideration.

For 2014 Ofgem forecasts TNUoS charges of around  £18/kW ±2.50 for Northern Scotland dropping in line with the locational basis for charging to about £5±0.5/kW in South Yorkshire and North Wales.

Tariffs in London will, as now, be negative (payments) at minus £5±£2.50/kW with the rest of the south, south east and west country tariffs ranging between minus £0.6±0.5/kW and minus £3± £2/kW. For all Scottish regions the proposals come in below the current tariffs in 2014. South of the border they exceed the current tariffs on average by between £0.5/kW and £2.50/kW.

The range of impacts of the CMP213 options on renewable generators and low factor thermal plant (peak lopping) is greater, falling from about £13±5/kW in Northern Scotland to approximately £2.50±1.50/kW in South Yorkshire and North Wales while the spread in London are forecast at around minus £2±4.50/kW.

Again charges averaged across all options in Scotland fall below existing charges by about £4-11/kW and in England and Wales they exceed current charges by roughly £0-5/kW. So wind farms in the north are penalised less for being sited where the wind is strongest.

Differences in constraint costs for each option are negligible. As a group they rise to about £15 million above the status quo forecast in 2018 with the spread between the least and greatest reaching about £12 million and all falling below or alongside the status quo figures. Overall constraint costs are anticipated to fall to near zero by 2016 with the construction of the west and east coast High Voltage Direct Current undersea links (“bootstraps”) scheduled for delivery in 2015. That might be expected to end the contention surrounding constraint payments to wind power.  However despite a drop by more than two thirds in the amount of wind constrained in 2012-13 to 67GWh and a near 80 per cent fall in constraint payments to wind to £7 million, future trades by National Grid with wind generators to cover constraints outside the balancing mechanism increased to £18.7 million from 12.2 million the previous year.

CMP213 is complex with many interactions. For example: Diversity 3 produces the greatest investment in low carbon technology cost post 2024 but owing to that it is weakest on cumulative transmission investment. Diversity 3 breaks ranks with the other options on investment – falling some £500 million below the rest in 2019 and only rising to some £200 million shy of the pack in 2024. And in promoting renewable build including 1.2GW more offshore than Diversity 1 as well as a putative 0.4GW more nuclear than all the other options Diversity 3 produces the highest power sector costs – offshore and nuclear are the main drivers of those costs. Yet despite boosting low marginal cost renewables that is offset by contract for differences top up to the strike price.

Notably there is no significant difference between the options and variants in their capacity to achieve the government’s 30 per cent target for renewable share of annual demand or the 2030 target carbon intensity target of 100g/ kWh. 

The regulator has been besieged by the wind power lobby over transmission costs ever since the introduction of locational charging. CMP213 has been a drawn out and costly process that offers the Scottish wind farms a taste of victory. But it has also released a barrage of special pleading from industry creating byzantine complexity – the eight options in CMP213 started as 42. Ofgem defends its minded to choice as “the most cost reflective of the options and drives more efficient decisions by the market participants and policy makers which creates value for customers.” But it is difficult to conceive that there can be any confidence in its forecasts.

Transmission charging is subject to further complications in its interactions with other forces already in train. For example: Under the European Union Framework Guidelines /Network Code process a network code on balancing is to go into comitology in the second quarter of next year while an network code on HVDC scheduled for the last quarter of 2014. EU codes will take precedence over national codes, but how that will work in practice remains unclear.  But CMP213 is out of kilter with much of the rest of the EU. Based on EntsoE figures for 2013 UW calculates that two thirds of European member states base 50 per cent or more of TNUoS charges on energy rather than capacity as under CMP213. And half derive more than 75 per cent of their tariffs from energy transported.

Given the amplitude of the uncertainties that the period from now to 2030 could encompass – Scottish independence, economic recovery, capacity market, shale gas, electric transportation, community energy projects – and so on – the difference in the options under consideration in Transmit would be lost in the noise.

DEVIL IN THE DETAIL: CMP213 Options

There are eight options under CMP213: Diversities 1-3, National Grid’s Original proposal and a variant of each in how HVDC is treated. Diversities 1 and 2 are based on the same premise. They state that TNUoS charges for security at peak load – “Peak Security” charges – should be paid for by high power factor plant (over 70 per cent) while other “Year Round” charges are paid by all plant including intermittent generators. Diversity 3 does not include Peak Security as a driver for investment.

The options differ in the extent to which they accommodate limitations on sharing transmission capacity between renewable plant in a given network zone. The limitations arise from the need to run wind turbines at the same time and the high cost of constraining them off so they tighten as the concentration of wind plant increases in a zone.

Diversity 1 assumes sharing decreases after low carbon plant exceeds conventional generation in a zone. Diversity 2 and 3 take the same view but apply it to low carbon and conventional plant and apply a 50 per cent cap on sharing. Diversity 3 also does not include peak security as a driver for investment and offers the same TNUoS tariff to all generators in a zone.

A variant of each option partially socializes the cost of direct current transmission networks which will grow in significance with the construction of subsea lines running down Britain’s east and west coasts. The same variant includes part socialized costs for linking the Scottish Islands.

Under all options the tariffs are scaled by the annual load factor (ALF) of each generator. Two approaches to ALF are considered: one based on the five previous years and another forward-looking model.