A site in the South of Scotland, with an annual consumption of 5GWh, has forward purchased its wholesale electricity for October 15 to September 20 with a 1.7% increase in cost. So far so good, however the bad news is that the delivered cost of electricity will increase 32% over the same period.


So what is the cause of these future increases in cost? Increases are all down to those mystery charges usually referred to as non-commodity. This group of charges include industry charges to deliver electricity to a meter and government levies. However, it is not unknown for additional profit to be hidden within the complexity of the non-commodity charges.


Cost increases of this scale are likely to pose a risk to any organisation. The first stage of any risk management strategy involves identifying risks and then moving on to developing methods to manage these risks. The final stage of any strategy should also include continual review to determine if the management methodologies implemented are effectively controlling risks.


The first stage is to identify the risks. By simply providing the electricity Supply Number (MPAN), site available capacity and 12 months of half-hourly consumption data 4prime will calculate the likely future non-commodity costs. Some of the charges are based on total consumption, but others are specific to particular timebands. The first piece of good news is that because there is full transparency of the costs there is nowhere for additional profits to be hidden. These additional profits have typically been around 5% to 10% of the delivered cost of electricity.


Now that the individual non-commodity costs have been identified the impact of changing consumption patterns can be investigated. Basically, if consumption is reduced in high cost timebands then there will be a much higher return on any investment in technologies adopted to reduce this consumption.


It is important any future electricity supply contracts are fully transparent and all non-commodity charges are clearly identified. Future invoices should show non-commodity costs, which should be billed at the prevailing rates at the time of invoicing.


There is no “one size fits all” solution to what is the most cost effective technology, or technologies, for managing risks associated with non-commodity costs. These technologies will include load management strategies, on-site generation and energy storage. Also participating in National Grid’s demand side response programmes will have the additional benefit of reducing consumption during high cost timebands.

This all sounds very complicated, but the first question for any organisation should be “What can be achieved practically on this site without interfering with the business process?”. Energy Market Price’s tools can then be used to investigate the cost benefit of adopting each of the possible technologies, or combination of technologies.


Simply using data from historic invoices is not going to give an accurate assessment of the cost benefits because there are a number of significant changes being introduced along with additional levies over the next few years:

  1. April 2017 the process (P272) should have been completed to migrate all meters with profile classes 05 to 08 to half-hourly settlements.
  2. April 2017 any meter that meets the necessary technical requirements can be migrated to half-hourly settlements.
  3. November 2017 to February 2018 the first Supplier Capacity Market Obligation Levy will impact on bills.
  4. April 2018 DCP161 will come into effect and introduce additional charges for any sites that exceed the agreed available capacity.
  5. April 2018 DCP228 will reduce the differential in cost between the DUoS Red, Amber and Green timebands.Over the next five years the TNUoS Demand Tariff (TRIAD) will significantly increase in all distribution areas.


Average Cold Spell GB demand for 2016/17 was forecast to be 52.7GW and including minimum reserve 53.6GW. Although available generation is 73.7GW the derated capacity is 55GW. The derated value takes into account breakdowns, planned outages and other any operational issues that may prevent a plant from generating. Currently there is 55GW of renewable energy generation that is operational, under construction or has planning consent. Of this total, 45GW is accounted for by intermittent technologies wind and solar photovoltaics.


A consequence of this growth in renewable energy generation is that there will be further expensive changes needed in the transmission and distribution networks required to accommodate this change from centralised to localised generating capacity. The intermittent nature of wind and photovoltaic technologies will also lead to a growth in energy storage solutions and an increase in the Capacity Market,

Contracts for Difference and Renewables Obligation Levies and Feed in Tariff. Some of the large scale renewable energy technologies may transfer from the Renewables to the Contracts for Difference Levy, so the Renewables Obligation Levy may decrease, but tAnchorhis reduction will be more than balanced by the increase in Contracts for Difference Levy.


To further complicate the picture, the introduction of the Demand Side Response programme combined with the action of sites to avoid TRIAD periods will result in the forecasting of TRIAD periods becoming much more difficult. National Grid’s Demand Tariff (TRIAD) is like death and taxes, it cannot be avoided.