Energy Update 2025: UK Electricity Supply Risks, Interconnector Uncertainty & Rising Non-Commodity Costs

UK Power Market Developments

The UK power market goes into winter more exposed to the on-the-day performance of wind and solar than ever before or 47% across all UK-originated renewable energy.

This is now complicated further by new concerns over the inter-connector imports. Notably those from Norway whose 1.4 GW of hydro production has been relied on to provide peak-day cover, well below the price cap pertaining to other inter-connector cables, whose import prices will vary by auction with a theoretical price cap which only comes into play to stop import prices exceeding £3,000/MWh (£300/kWh)

As well as the direct export question relating to the UK, raised political tensions may also affect exports to Denmark via the 4 wire Skagerrak link which supplies 1.6 GW; 29% of its Nordic neighbour’s needs. Conceivably, any new imbalance here could see Denmark competing with or producing a wider draw on surplus European electricity, exports otherwise available or destined for the UK.

To compounded this, Norway so far has seen unusually low reservoir levels this year and it has no physical pumping capacity of any kind which could place practical limits on volumes available. However, the question of renewables’ availability is not exclusive to Norway. Cable network-reliability and power supply-availability issues elsewhere will equally affect exports via other principal inter-connectors, namely the 1.0 GW NEMO cable from Belgium, the 1.5 GW BritNed power line from Holland and 2.0 GW IFA 1 and 1.0 GW IFA-2 inter-connectors from France.

Forward Gas Generation Supply Cover

Reliable peak-load generation, oil-fired but chiefly combined Cycle Gas-fired Turbine power plants, is known to be in short supply. Regardless of the trajectory of oil or gas prices from this point, the limitation is likely to stay amid the quest for Net Zero. Also practical limits are now on the building of any new CCGTs, even if existing government policy was loosened soon. Whilst it may have taken 18 to 24 months in order to build a new CCGT plant 15 or 20 years ago, the figure had grown to 3 years by 2020. Such are the bulging order books of the main manufacturers, General Electric, Siemens and Mitsubishi and competition for both new plants and spares from new-build developers, notably in the Middle East and South East Asia, UK power generators would are now looking at a 7 year wait for equipment alone, so government policy and planning consents will not be the only hold up. The delivery cost per MW capacity has also risen markedly with entry-level 800 MW turbines doubling in price since 2020 to circa £950/kW + installation, albeit cheap at the price still compared with the latest new-build estimate for Sizewell C, which with construction costs now weighs in at £10,000/kW based on a £32 billion spend and twin 1,600 MW reactors.

Non-Commodity Cost Increases

Rising prices of spinning reserve and imported renewable, nuclear and coal-fired electricity have all played a role in boosting the Balancing Services Use of System charge (BSUoS). This is transmission & distribution network power quality and load-management surcharge added to all business bills. Hitherto a ‘trace’ or ‘nuisance extra’ charge, BSUoS has risen faster than any of Non- Commodity cost (of which there are now 47 in total) and it is now a significant bill element in its own right. The BSUoS surcharge has risen from barely ¼ p/kWh some 15 years ago to 3¼ p/kWh now and may reach 3¾ p/kWh within the next 12 to 18 months.

Non-Commodity charges now account for 65% of a typical I&C bill. Whichever way the Commodity Price of electricity moves from here, bills still look set to rise.

Especially larger but non energy-intensive users with only limited rebate concessions offered by Ofgem which has just sanctioned steep rises in transmission costs (Transmission Network Use of Service charges (TNUoS charges)) from April 2027 to be followed by rises in distribution costs (Distribution Network Use of Service charges (DNUoS charges)) just two years later or sooner. The 45 other network surcharges including Climate Change levies will remain in a state of flux and anyway also rise with inflation in most cases.

Energy Cost Reduction Options for I&C Users

However, consumers may reduce or mitigate the impacts. For example by fine-tuning their off-take pattern and moderating consumption to fall inside a more favourable distribution zone price band; a demand optimisation strategy which could including battery storage.

Further by re-auditing invoices. To identify inefficient usage, flag up recurring over-charging, evaluate and reclaim current contract year and past contract year over-payments.

Finally, high volume electro-intensive users could enhance their purchasing by way purchasing power off the OTR (Over-the-counter Trade Registration) market as opposed to the traditional, bi-lateral OTC route. The OTR would entail the I&C power user trading directly with the exchange (e.g. Nord Pool) or direct with an inter-dealer broker (e.g. Marex Spectron); in each case, the user will buy off them, the sole principal to all trades. This would first reduce legal and administration costs , potentially cut counter-party risk too. The OTR would furthermore reduce the Weighted Average Cost of Electricity (WACoE) because the user will now have access to The Entirety of the power trading market, i.e. with de facto direct access to all 75 + market participants including smaller generators who trade on the exchange or who deal through that broker. Over a period of time, this will reduce the average purchase price of electricity.

Even a nominal reduction in the mean purchase price can result in significant long-term savings with a new, marginally lower WACoE now transposed across the entire purchased volume in the current as well as all future years.