Navigating the Crosswinds: UK Electricity Market Reform and the Investment Landscape for Dispatchable Power

The UK's electricity market stands at a defining moment. A confluence of regulatory reforms, abandoned policy pathways, and the emergence of a wholly state-owned energy company has created a landscape that is at once promising and perilously uncertain for investors in dispatchable generation assets. For those engaged in utility-scale asset development and infrastructure capital deployment, like CM Energy Insight, understanding these intersecting forces is not merely academic—it is essential to informed decision-making.

The Capacity Market's Evolution: A Second Price Cap Emerges

The Capacity Market has been the cornerstone of Great Britain's security of supply strategy since 2014, ensuring that sufficient electricity generation capacity remains available to meet peak demand. Yet the mechanism has reached an inflection point. The current price cap of £75/kW/year—unchanged in nominal terms since the scheme's inception—has declined by approximately 30% in real terms over the past decade. This erosion has effectively priced out investment in new Combined Cycle Gas Turbine (CCGT) projects, the very assets designed to provide sustained output during prolonged periods of tight supply.​

The Government's October 2025 consultation proposes a fundamental restructuring through the introduction of a Multiple Price Capacity Market (MPCM). Under this new framework, a second, higher price cap would be introduced specifically for new-build "dispatchable enduring capacity"—assets capable of generating power over extended periods without the duration limitations of battery storage. Existing capacity and short-duration assets would continue competing under the current £75/kW/year ceiling, whilst eligible new CCGTs and similar technologies could access enhanced payments if required to meet system adequacy targets.​

This dual-track approach attempts to solve a critical problem: the T-4 auctions have consistently cleared at or above £60/kW for three consecutive years, yet no new large-scale CCGTs have successfully secured contracts because clearing prices remain insufficient to underwrite the capital-intensive construction of these facilities. The Government acknowledges that without intervention, older thermal assets—including nuclear and biomass units—may retire without adequate replacement capacity to backstop an increasingly renewables-dominated system.​

REMA's Resolution: Reformed National Pricing Prevails

Perhaps the most consequential decision affecting investment confidence came in July 2025 when the Department for Energy Security and Net Zero published the outcome of its Review of Electricity Market Arrangements (REMA). After years of uncertainty that had cast a shadow over investment decisions, zonal pricing was definitively ruled out.​

The Government concluded that tolerating the inefficiencies of a reformed national pricing system strikes a better balance than accepting the risks of wholesale market fragmentation. Industry had warned repeatedly that zonal pricing would create "unnecessarily high instability and uncertainty around future prices and zonal boundaries"—precisely the conditions that drive up the cost of capital and deter the patient institutional investment that infrastructure development requires.​

The decision to retain a single GB-wide wholesale market, whilst introducing a package of reforms including the Strategic Spatial Energy Plan (SSEP), represents an evolutionary rather than revolutionary approach. The SSEP, due for delivery by the end of 2026, will spatially optimise the energy system across Great Britain, identifying optimal locations, quantities, and types of electricity infrastructure. This planning-led approach, combined with reforms to Transmission Network Use of System (TNUoS) charges and connection processes, aims to address the geographic mismatch between renewable generation in Scotland and demand centres in England—without fragmenting the market itself.​

For investors, this clarity is invaluable. As Energy UK observed, "Reformed National Pricing provides certainty for businesses across the economy, helping to drive investment and jobs". The alternative—a shift to locational marginal pricing that could not have been implemented until the 2030s—would have introduced seven years of investment uncertainty, putting Clean Power 2030 goals at risk.​

The Paradox of New CCGT Investment

Yet even with capacity market reforms on the horizon, the investment case for new gas-fired generation remains profoundly conflicted. The Climate Change Committee has recommended a 2035 phase-out date for unabated gas generation, with requirements that all new units be carbon capture and storage (CCS) or hydrogen-ready by 2025. This creates a temporal conundrum: investors are being invited to commit capital to assets that may face regulatory obsolescence within a decade of commissioning.​

Several significant projects are nonetheless advancing. Uniper is developing the Connah's Quay Low Carbon Power project—a CCGT with integrated carbon capture technology designed to deliver approximately 1.3GW of low-carbon capacity, with the first train targeted for commercial operation before 2030. At Net Zero Teesside, a partnership between BP and Equinor has awarded an £833 million construction contract to Balfour Beatty , with completion expected in 2028. The Killingholme project in Humber is also under development by Uniper, targeting a minimum 470MW capacity.​

What distinguishes these projects is their integration with emerging CCUS infrastructure. The Government's commitment of £21.7 billion to carbon capture—confirmed through the Track 1 and Track 2 cluster sequencing process—provides a pathway for gas-fired generation to continue operating beyond 2035 if emissions can be captured and stored. The HyNet and East Coast Cluster networks are now receiving substantial public backing, with contracts signed and construction imminent.​

The investment calculation thus becomes one of technology optionality: a CCGT built today with CCS-readiness designed in from inception may command a very different risk profile than a conventional unabated plant. The Capacity Market's proposed higher price cap for "dispatchable enduring capacity" appears designed precisely to attract such investment—but questions remain about whether the enhanced economics will prove sufficient given construction cost inflation and the complexity of integrating carbon capture at scale.

Great British Energy: A State-Owned Outlier in a Privatised Market

Perhaps the most distinctive feature of the current UK energy landscape is the emergence of Great British Energy (GBE)—a 100% publicly owned company established by the Great British Energy Act 2025, which received Royal Assent in May of this year. With an £8.3 billion capitalisation over this Parliament, GBE represents the most significant intervention by the British state in energy markets since privatisation in the 1980s and 1990s.​

The company's mandate is multifaceted: to invest in, develop, and own energy generation infrastructure; to catalyse private sector investment; to strengthen domestic supply chains; and to support local and community energy projects. Crucially, the Act establishes GBE as "operationally independent"—a company with its own CEO and board, distinct from governmental direction in day-to-day operations, yet ultimately accountable to Parliament through annual reporting requirements.​

GBE's CEO, Dan McGrail, has been explicit that the company is "not here to compete, but to catalyse investment". This positioning is strategically important. Unlike EDF in France or Vattenfall in Sweden—state-owned giants that dominate their national markets—GBE's £5.8 billion operational budget (excluding the nuclear allocation) is modest relative to the estimated £200 billion of investment required across the electricity sector by 2037. The intention is not to displace private capital but to de-risk projects at their earliest, most uncertain stages, thereby crowding in institutional investment.​

The first tangible deployments reflect this philosophy. GBE has committed £180 million to install solar panels on schools and hospitals—a low-risk, highly visible investment that demonstrates capability whilst avoiding land-use controversies. The company has also announced £700 million for offshore wind supply chain development, working alongside The Crown Estate and private partners to leverage additional private investment.​

For developers accustomed to a wholly privatised market, GBE's emergence raises important questions. Will state-backed projects receive preferential treatment in grid connections or planning decisions? How will GBE's participation in joint ventures affect the competitive dynamics of asset auctions? And what happens when a publicly owned entity pursues returns alongside, or in competition with, private capital seeking the same opportunities?

The Government has set an expectation that GBE will deliver returns on its commercial activities by 2030 and produce a plan for becoming self-financing by that date. This creates inherent tensions: a company mandated to take on early-stage development risk, support communities, and strengthen supply chains must also demonstrate commercial viability. Navigating these objectives will require considerable skill—and may occasionally produce outcomes that disadvantage purely commercial competitors.​

Stability or Instability? Assessing the Investment Environment

The aggregate effect of these developments is a market simultaneously more certain and more complex than it was only twelve months ago. The ruling out of zonal pricing removed what many investors considered an existential threat to project economics. The retention of a single national wholesale price provides the predictability that underpins long-term power purchase agreements and debt financing. The proposed capacity market reforms offer a pathway for new dispatchable generation to achieve viable economics—at least in principle.​

Yet significant uncertainties persist. The Government's separate consultation on retrospectively changing the indexation of Renewables Obligation payments from RPI to CPI has provoked fierce criticism from institutional investors. As the Association of Investment Companies warned, "retrospectively changing the terms of existing agreements is a sure-fire way to undermine investor confidence". If the Government is prepared to alter the basis of long-standing contractual arrangements for renewables, what assurance do capacity market participants have that their agreements will not be similarly adjusted?​

The TNUoS reform pathway also remains unclear. Ofgem has indicated that a robust new framework for transmission charging should be in place by 2029, but the intervening years will feature volatility and unpredictability in charges—particularly challenging for projects in Scotland where transmission costs are already elevated. The proposal under CMP444 for a temporary cap and floor on TNUoS charges was not supported by Ofgem, leaving developers to navigate substantial locational cost uncertainty.​

Furthermore, the sheer scale of required investment—around £50 billion annually through to 2030—means that even with policy reforms, competition for capital will be intense. NESO has advised that achieving Clean Power 2030 requires maintaining "a stable and attractive investment environment" capable of securing over £40 billion of investment annually. Against this backdrop, any policy missteps—whether on indexation, grid charging, or market design—could have amplified consequences.​

Implications for Asset Development and Commodity Strategies

For those working at the interface between utility-scale new build assets, long-term commodity requirements, and institutional infrastructure capital—the very nexus that CM Energy Insight serves—several strategic implications emerge.

First, the economics of dispatchable generation are being actively re-engineered. The proposed MPCM framework, if implemented ahead of the 2027 auctions, will fundamentally alter the investment case for new CCGTs. Projects positioned to access the higher price cap will command a significant advantage; those unable to meet eligibility criteria (likely requiring CCS or hydrogen-readiness) may find themselves stranded in the lower-price tier.​

Second, commodity agreements must reflect regulatory uncertainty. Long-term gas supply contracts for power generation assets must now account for the possibility—indeed the likelihood—that unabated gas generation will face increasingly stringent constraints through the 2030s. Hydrogen and carbon capture infrastructure timelines become critical dependencies, and supply agreements should incorporate optionality for fuel switching as these pathways mature.

Third, the financial structuring of projects must accommodate a mixed public-private landscape. GBE's participation in joint ventures, its role in de-risking early-stage development, and its mandate to catalyse private investment all create opportunities for innovative capital structures. Developers should consider how GBE partnerships might enhance bankability—whilst remaining attentive to the governance and commercial implications of state involvement.

Fourth, the retention of national pricing preserves familiar commercial frameworks—but the reforms to transmission charging and spatial planning will introduce new locational considerations. The SSEP, when published in 2026, will effectively constitute a government-endorsed map of preferred development locations. Assets aligned with SSEP recommendations may benefit from streamlined connections and reduced grid charges; those in less favoured locations may face headwinds.

Conclusion: A Market in Transition

The UK electricity market is undergoing its most significant transformation since the introduction of NETA in 2001. The capacity market reforms, the REMA resolution, and the establishment of Great British Energy collectively represent a recalibration of the relationship between state and market in ensuring security of supply and achieving decarbonisation.

For investors in dispatchable generation, the path forward is neither straightforward nor risk-free. But the fundamental direction is now clearer than at any point in recent years. Zonal pricing will not fragment the market. A mechanism for funding new CCGTs is being constructed. Public capital is entering the market—not to compete, but to catalyse.

Whether this combination of reforms produces a stable investment environment or merely reconfigures the sources of instability remains to be seen. What is certain is that the decisions made in the coming months—on price caps, on eligibility criteria, on the terms of GBE's commercial activities—will shape the generation mix that carries Great Britain through the 2030s and beyond.

The investors who navigate these crosswinds most successfully will be those who understand not only the technical parameters of market design, but the political economy that shapes it. In an era when energy policy is inseparable from industrial strategy, decarbonisation mandates, and national security considerations, the capacity to interpret regulatory signals and position assets accordingly is not merely advantageous—it is existential.

CM Energy Insight works at the interface between utility-scale asset development, long-term commodity agreements, and institutional infrastructure capital. For advisory services on navigating the evolving UK electricity market, contact our team.