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Third-party charges. Why they mean it’s time to invest in self-generation

Third party charges. Why they mean it’s time to invest in self-generation

Also known as non-commodity, industry or non-energy charges, these are the charges that are not directly related to the cost of wholesale energy and are set by third parties (such as the National Grid), out of the control of the supplier. 

They now make up an ever-increasing share of the total electricity price and this guide will help you navigate the increasingly complex landscape and illustrate how the charges are likely to develop in future.

The charges can be categorised into two types:

  1. Network charges and security of supply
  2. Environmental charges

So why do these charges mean it’s time to invest in self-generation?

Predictions expect these costs will climb, year on year. As businesses and consumers switch to self-generation en-masse in response to the UK’s obligations under the Paris Climate Agreement, those still overly relying on the grid will pick up the tab for these third-party charges.

Third party costs will still need recouping by providers. This means that remaining grid dependent consumers and businesses can expect increases to compensate for those choosing self-generation. Self-generators will be partially or even fully exempt.

Therefore, as the number of grid dependent users declines, escalating third-party charges will soon overtake the predicted reductions in wholesale commodity costs.

The only way to insulate yourself from these rises is to invest in self-generation;  this will reduce your demand on the grid by varying degrees. Otherwise you can expect serious cost increases and profit hits over the next few decades.

The rest of this article is illustrative information provided to us by major energy supplier, Total.

The above illustrates how the reductions in wholesale commodity costs are offset by the increasing costs of non-commodity and their impact on the future electricity price.

Network and security of supply

These are the non-commodity charges associated with delivering electricity from the source of generation to the end user via the networks (TNUoS and DUoS). They will also recover costs to ensure the network is safely balanced and stable (BSUoS) and guarantee supply when it is needed most (Capacity Market).

Pylons with insulators

Transmission Use of System (TNUoS)

Transmission charges recover the cost of installing and maintaining the National Grid transmission system in the United Kingdom. Customers pay a charge based on location, whether they import or export electricity and the size of their generation or demand.

Half-hourly (HH) costs are calculated applying the half hourly TNUoS rates by demand ‘TRIADs’, these are three highest metered demand peaks during November to February with each half hour separated by 10 days.

Non-half hourly (NHH) is calculated using demand during 16:00 to 19:00 all year round.

Embedded export is charged using the same method as half hour demand however this is a credit to the generator. This is to compensate for having distribution connected generation, alleviating demand on the Transmission network during peak usage.

Embedded Export Charges

From 2018/19 the residual element of the Embedded TNUoS rates will be reduced over a 3 year period, eventually only leaving the locational element of the charge.

In some zones (such as Northern Scotland) the TNUoS locational element is negative so the TNUoS rate will remain at a floor price of zero once the residual has been removed.

No change in 2019/20 actual charges compared to the previous 2019/20 draft tariff.

Distribution Use of System
(DUoS)

 

Distribution Network Operators (DNO’s) charge for the use of their distribution network in each region to recover the costs associated with running their

network, such as maintenance, repairing and investing into the network.

This is the infrastructure that transports and delivers electricity exiting the Transmission Grid to the end user.

Due to the complex nature of the distribution network and the variance of end users, such as voltages and meter types, there are multiple DUoS tariffs for each region.

Settled at half hourly or non-half hourly both consisting of unit rates charged against consumption, as well as a fixed standing charge.

 

DUoS timebands – DCP 268

At present half hourly and non half hourly demand DUoS tariffs apply a different structure to their DUoS unit rate charging.

Half hourly is charged by applying applicable consumption to each Red/Amber/Green time band and an equivalent unit rate.

Non-half hourly DUoS unit rates are structured simply as either single or two rate.

Generation tariffs are also applied differently with HH
Non intermittent charging using the Red/Amber/Green structure, and for HH intermittent Generation applied to a single unit rate.

OFGEM have recently approved a modification to align all non-half hourly DUoS unit rate charging to use the same half hourly time banding structure, red/amber/green. Intermittent generation tariffs will also move to Red/Amber/Green.

The main reasons for the change are to simplify the current Common Distribution Charging Methodology (CDCM) DUoS tariffs, reducing the number of tariffs from 33 down to 16. It will also help suppliers create new innovative products and to better reflect Distribution network costs. This will come into effect in April 2021.

Balancing Services Use of System (BSUoS)

Balancing services Use of System (BSUoS) charges are how National Grid recover the costs of balancing the system, ensuring that the transmission network runs in an efficient and coordinated way and keeps electricity flowing steadily.

The system is balanced at each half hour and the charges are published £/MWh rate based upon the associated volumes and costs for each balancing
each period. These are published retrospectively once the costs are known.

The rapid growth of renewable System balancing intermittent generation means the costs of balancing the network are increasingly complex and volatile, due in part to network constraints – traffic jams on the motorways of the high voltage transmission system.

Network constraints occur when there is an abundance of generation in a particular region and it is not possible for the network to safely transport all of it to another region where it can be utilised. Examples of this often happen in areas such as Scotland due to the high proportion of intermittent wind generation, low local demand and also a limited capacity of high voltage transmission network supplying it to regions to the south.

In these situations, National grid provide compensation payments to generators to turn down or switch off to reduce stress on the network and then also pay generators to turn up generation in areas where the generation was needed originally.

The introduction of the 2,250MW WesternLink HVDC has recently been installed to address the north/south constraint issues providing a new link between Scotland and England/Wales. However with the expected rapid increase of further intermittent renewable capacity is likely that costs will continue to rise.

BSUoS Taskforce conclusion and TCR

A National Grid ESO led task force recently investigated as to whether BSUoS charging could change to become more cost reflective and forward looking to better reflect locational costs and encourage behaviours. They concluded on the 31st of May that the nature of the charge made both of these options unfeasible and it would remain purely a cost recovery mechanism.

Assistance for Areas with High Electricity Costs (AAHEDC)
Also known as the Hydro benefit, the AAHEDC is a socialised levy to help subsidise the high costs of distributing electricity in Northern Scotland. It is added to all electricity sold from the transmission system to all users in Great Britain so is a relatively small and stable
charge.

National Grid publish the draft tariff in March
and confirm the actual charge in July.

Capacity Market (CM
Obligation)
The Capacity Market scheme is designed
to ensure security of power supply during
times of system stress during winter peak,
November to February 16:00 to 19:00,
working days. Generators and demand side
resources bid in a competitive auction to
secure a price and provide capacity during
these times. Demand Side Response offer
capacity by reducing demand. This process
allows a predictable revenue stream for CM participants to base their future investments. Forecasts are based on Capacity Market auction and administration costs and the estimated demand base consumption during the CM period.

Capacity Market Suspension
At present the Capacity Market scheme has been put into a standstill due to the European Court of Justice ruling that the European Commission failed to properly investigate the CM when it was cleared for state aid in 2014 and is now pending an appeal and further investigation.

In the meantime the government has advised that the scheme will likely be re-introduced before winter 2019/20 and organised a T-1 2019/20 auction to procure any additional capacity for the coming winter.

Environmental Charges

These are the Non-commodity charges associated with government environmental policy, incentivising investment into low carbon, renewable generation. They have played a pivotal role into the decarbonisation of the UK electricity sector however they also represent the biggest contributor to increases in the electricity price.

Feed in Tariff (FiT)
The Feed-in Tariff was introduced to incentivise small scale low carbon generation (5 MW and below) in Great Britain for the general public. A FiT generator can receive two possible payments from the scheme; a Generation payment for every kWh generated and also an Export tariff which pays for every kWh exported to the local electricity network. Introduced in April 2010 to England Scotland and Wales it has since closed as of April 2019 which should now see the overall scheme costs increases start to stabilise for consumers.

Renewable Obligation (RO)
The RO was introduced to incentivise investment into large scale renewable energy by providing generators with a payment for each MWh generated, in the form of
a ROC (Renewable Obligation Certificate).

Suppliers are obligated to buy the certificates from generators in order to meet their target for each financial year, which is a percentage of the overall supply estimate set by BEIS.

Introduced in England, Wales and Scotland in 2002, and in Northern Ireland in 2005, the RO scheme has since closed to new capacity as of 31 March 2017, with several grace periods for different technologies, with the last closing 31 March 2019. Closure and the lower yields of technologies such as sewage gas we may see the total amount of ROCs start to slowly decline as of 2020, however due to the RO being contractual for 20 years we may not see any significant reductions until the late 2020’s when we will see some generators exit the scheme as contracts end.

BEIS published the RO obligation level
for 2020/21 in September 2019. 0.471 (47.1%) for England, Wales and Scotland and 0.185 (18.5%) for Northern Ireland.

The 2020/21 RO Buy Out Price will be published in February 2020.

2019/20 was published last year at 0.484 (48.4%) for England, Wales and Scotland and 0.190 (19%) for Northern
Ireland.

The 2019/20 RO Buy Out price was published at £48.78 per ROC.

Future increases are expected tostabilise over the next few years however it remains to be seen how OFGEM and BEIS will interpret the forecast of future ROC output and eligible demand trends.

Contracts for Difference (CfD)
The CfD scheme is the latest subsidy designed to incentivise investment into low carbon generation and now represents the only subsidy available for would be large scale generation.

Via a competitive auction a successful CfD generator is awarded a pre-agreed ‘Strike
price’ for each MWh of electricity generated, guaranteeing a stable return of investment, avoiding exposure to fluctuations in the wholesale power market. The CfD scheme will provide a ‘top up’ payment to the generator to achieve the agreed strike price when wholesale prices are below the agreed price. In times when the wholesale price exceeds the strike price, the generator will pay the difference back into the scheme.

Costs are forecasted by taking into account information on awarded contracts, including Strike prices, Forward wholesale prices, latest know project capacity, commissioning dates and technological specific assumptions on load factors.

With the government recently
committing to hold a new auction for offshore wind every two years starting from 2019 and throughout the 2020’s the CfD scheme is set to expand steadily.

So far the government has committed £557 million to the auctions, with first projects due to be delivered by 2023-24.

 

Costs are forecasted by taking into account information on awarded contracts, including Strike prices, Forward wholesale prices, latest know project capacity, commissioning dates and technological specific assumptions on load factors.

If you’d like to understand your self-generation options, or what you can do if self-generation isn’t an option for your business, please get in touch with us.

There is much that can be done, whatever your circumstances.

01752 26 26 26 or email info@iuenergy.co.uk.

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