Future‑proofing asset investment: navigating the GB flexibility transition to 2030

As the UK power system accelerates towards a near‑fully decarbonised grid, traditional sources of flexibility are under pressure. A major European energy supplier used this project to reassess how, where and when flexibility will deliver value through to 2030. 

Background: When flexibility stopped behaving as expected

For decades, dispatchable thermal generation underpinned system flexibility in Great Britain (GB). That assumption is now eroding. Rapid growth in wind and solar is reshaping price formation, increasing the frequency of low price and surplus periods, and compressing running hours for conventional plant.

By the early 2030s, more than a third of all hours are expected to experience excess inflexible generation, often persisting for more than a day. For this client, a large owner and operator of flexible assets across generation and heat, this translated into a material strategic risk.

Forward projections showed that even the most competitive OCGT (Open Cycle Gas Turbine) and CCGT (Combined Cycle Gas Turbine) assets could see energy market revenues fall by up to 50 percent by 2040, with load factors dropping towards 10 percent by mid century. The challenge was not simply declining profitability, but uncertainty over which forms of flexibility would remain investable, and when decisive action was required.

The question the client needed to answer

Rather than asking whether thermal flexibility still had a future, the client reframed the problem:

• What types of flexibility will the GB system need at different timescales through to 2030?
• Which existing assets would retain strategic value, and which risk becoming redundant?
• Where are the investable opportunities that align with both market fundamentals and policy direction?

Answering these questions required moving beyond static forecasts to a view of how flexibility value would evolve under uncertainty.

Approach: Building confidence in long term decisions

The analysis was designed to give the client decision grade insight rather than generic scenarios. Using a stochastic view of the GB power system, our modelling tested how different forms of flexibility perform across a wide range of weather, demand and market conditions.

This included a examine the client’s own portfolio of assets, spanning thermal generation, biomass, battery storage, combined heat and power, and emerging demand side flexibility options. Locational effects were explicitly captured to reflect the growing importance of network constraints and regional price separation, particularly at heavily stressed boundaries between Scotland and England.

Heat was treated as a core part of the flexibility solution rather than an adjacent consideration. The modelling quantified how electrified heat, thermal storage and network charges interact, revealing sources of value that are often overlooked in power only assessments.

What changed for the client

The results prompted a fundamental shift in how the client viewed its 2030–2040 investment window:

From declining thermal value to targeted opportunity

The analysis showed that the system’s need for within week flexibility increases sharply during the 2030s. By around 2035, the opportunity of within week storage were projected to be more than four times today’s level, rising from under 4 TWh to over 18 TWh. This reframed long duration storage from a future option to a near term strategic priority.

At the same time, the modelling confirmed that revenues for peaking thermal plant continue to erode as price volatility replaces sustained scarcity. Crucially, storage assets proved more resilient because their value is driven by price spreads rather than absolute price levels.

Demand side flexibility becomes a core asset

One of the most significant insights was the scale and performance of early demand side flexibility. The first 10 GW of flexible demand was shown to achieve load factors of up to 50 percent by the mid 2030s, materially outperforming most thermal peaking assets.

This shifted demand flexibility from a marginal, consumer led concept to a bankable system asset in the client’s investment planning.

Clear signals on asset repurposing

For the existing thermal and biomass fleet, the work clarified where optionality still exists. The client is now actively assessing whether carbon capture, hydrogen conversion or alternative operating modes are justified, and where capital is better redeployed to avoid stranded assets beyond 2040.

Impact: Strategic resilience and policy alignment

The project moved the client from a defensive response to declining load factors towards an offensive, future aligned strategy.

Integrating electrical storage with district heating emerged as a credible hedge against wholesale price compression, aligning thermal demand with periods of surplus generation and unlocking additional value from network charges and ancillary services.

Equally important, the findings strengthened the client’s engagement with policy development. By grounding investment decisions in quantified system need, the client is now better positioned to respond to mechanisms such as the cap and floor regime for long duration storage and to demonstrate its role as a system critical flexibility provider in a high renewables market.