Trend watch: Power markets, permitting & interconnection in 2026 — signals, winners, and red flags

The UK interconnection queue exceeded 700 GW of requested capacity by the end of 2025, roughly seven times the country's peak electricity demand. Meanwhile, the average time from planning application to energisation for onshore wind projects stretched to 4.7 years. These two statistics capture the central tension defining UK power markets in 2026: record-breaking demand for clean energy connections colliding with permitting and grid infrastructure systems that were never designed for this pace of change. For sustainability professionals navigating procurement decisions, corporate PPA negotiations, or net-zero strategy execution, the trajectory of permitting and interconnection reform will determine whether clean energy targets remain achievable or slip further out of reach.

Why It Matters

The UK electricity system is undergoing its most significant transformation since privatisation in the 1990s. The government's target of a decarbonised power sector by 2030 requires approximately 50 GW of new offshore wind, solar, and other low-carbon generation capacity. Achieving this within the remaining timeline demands a pace of deployment roughly three times faster than the rate achieved over the previous decade. The bottleneck is no longer technology cost or investor appetite. Solar module prices fell below $0.10 per watt in 2025, and offshore wind strike prices from Allocation Round 6 came in at $44 per MWh, both record lows. The binding constraint is the physical and regulatory infrastructure connecting generation to consumers.

Ofgem's 2025 review found that 65% of projects in the GB interconnection queue had been waiting more than three years without receiving a connection offer with a firm date. National Grid ESO estimated that resolving the queue backlog under existing processes would require until the early 2040s, a timeline fundamentally incompatible with 2030 targets. This mismatch between project readiness and grid access creates cascading effects: developers face higher capital costs from extended construction timelines, corporate buyers struggle to secure PPAs with reliable delivery dates, and the UK risks losing clean energy investment to markets with faster permitting regimes.

The financial stakes are substantial. The UK Electricity Networks Commissioner estimated that accelerating connections by just two years across the current queue would unlock over $12 billion in additional economic value through earlier carbon reduction, lower wholesale prices, and reduced reliance on gas-fired peaking plants. For companies with science-based targets, delays in grid access translate directly into gaps between committed emissions reductions and achievable procurement pathways.

Key Signals to Watch

The Connections Reform Programme

The most consequential policy development for UK power markets in 2026 is the Connections Reform programme led by Ofgem and National Grid ESO (transitioning to the National Energy System Operator, NESO). Launched in late 2024, the programme introduces a "first ready, first connected" model replacing the legacy "first come, first served" queue. Projects must demonstrate planning consent, land rights, financing, and supply chain commitments to maintain queue position. Ofgem's preliminary assessment indicated this reform could remove 300-400 GW of speculative capacity from the queue, reducing average connection timescales from 10-15 years to 3-5 years for shovel-ready projects.

The signal to watch is execution speed. NESO has committed to publishing the reformed queue methodology by Q2 2026, with the first reassessed queue positions issued by Q4 2026. Any slippage in this timeline would signal continued institutional inertia and should prompt sustainability professionals to reassess procurement timelines and consider alternatives such as private wire arrangements or co-located storage solutions.

Planning Reform and the NSIP Regime

The Nationally Significant Infrastructure Project (NSIP) regime governs consent for major energy infrastructure, including offshore wind farms, transmission lines, and large solar installations. Average determination times under the NSIP process increased from 2.6 years in 2018 to 4.1 years in 2025, driven by judicial review challenges, cumulative environmental impact assessments, and staffing shortages at the Planning Inspectorate. The government's response includes doubling Planning Inspectorate staffing for energy cases and introducing streamlined environmental assessment processes under the Levelling Up and Regeneration Act provisions.

The key metric to track is the determination time for applications entering the system in 2025-2026. If average times begin falling below 3 years, this would confirm that reforms are gaining traction. If times remain above 4 years, the 2030 target becomes effectively unreachable under current deployment models.

Electricity Market Reform and Locational Pricing

The UK government's Review of Electricity Market Arrangements (REMA) has been progressing since 2022, with a final decision on market design expected by mid-2026. The central question is whether the UK adopts zonal or nodal pricing, replacing the current single national wholesale price. Locational pricing would create price signals reflecting actual transmission costs and constraints, potentially accelerating investment in areas with strong renewable resources and available grid capacity while discouraging development in congested zones.

National Grid ESO modelling suggests locational pricing could reduce annual constraint costs by $1.5-2.5 billion, costs currently socialised across all consumers. However, the transition creates winners and losers: Scottish wind developers would benefit from reduced curtailment, while demand-heavy zones in southern England could face higher wholesale prices. Corporate buyers with flexibility in facility location would gain a strategic advantage.

Emerging Winners

Developers with Grid-Ready Sites

Companies that invested early in securing grid connections with firm dates now hold increasingly valuable positions. Developers like SSE Renewables, which controls over 7 GW of consented or under-construction renewable capacity with secured grid access in Scotland, are positioned to capture premium PPA pricing as corporate buyers compete for limited near-term supply. The lesson for sustainability professionals: grid access has become as important as generation economics in evaluating PPA counterparty credibility. Due diligence on connection agreements, including milestone conditions and potential queue position risks, should be standard practice.

Battery Storage and Flexibility Providers

Grid constraints create value for assets that can operate at the margins of congested networks. UK battery storage capacity reached 4.8 GW operational by the end of 2025, with an additional 8.5 GW in construction or consented. Companies such as Zenobe Energy and Harmony Energy have built portfolios of grid-scale batteries co-located with constrained renewable generation, capturing revenue from both wholesale trading and Balancing Mechanism participation. Constraint payments to batteries and flexible generators exceeded $2.1 billion in 2025, a figure that will grow until transmission reinforcement catches up with generation build-out.

For corporate buyers, co-locating demand with behind-the-meter storage increasingly makes economic sense. Industrial facilities in grid-constrained areas can reduce exposure to transmission charges (TNUoS), which rose 23% in 2025, while accessing lower-cost renewable electricity through private wire or sleeved PPA structures.

Network Companies Investing in Anticipatory Capacity

Ofgem's decision in 2024 to allow anticipatory investment in transmission infrastructure marked a significant regulatory shift. Under the traditional model, network companies could only invest in response to firm connection agreements. The new framework permits investment ahead of confirmed demand, reducing the lag between generation readiness and grid availability. National Grid Electricity Transmission, SP Energy Networks, and SSEN Transmission have collectively submitted over $28 billion in proposed transmission investment for the RIIO-T3 price control period (2026-2031), including strategic reinforcement corridors in Scotland, East Anglia, and the North Sea coast.

The winners among sustainability professionals will be those who align procurement strategies with these planned network upgrades, targeting PPAs and site selection in areas where new transmission capacity will arrive first.

Red Flags

Community Opposition and Judicial Review Risk

Planning consent for onshore infrastructure remains politically contentious. The East Anglia transmission corridor proposals have generated organised opposition from local communities, with multiple judicial review applications anticipated. If major transmission projects face sustained legal challenges, the delivery timeline for reinforcements supporting offshore wind connections could extend by 2-3 years, creating a second bottleneck beyond the generation queue itself.

Supply Chain Constraints for Grid Equipment

High-voltage transformers, subsea cables, and HVDC converter stations face global supply chain tightness. Lead times for grid transformers increased from 12-18 months in 2020 to 36-48 months in 2025, according to industry surveys by the European Network of Transmission System Operators for Electricity (ENTSO-E). The UK is competing with the EU, US, and Asian markets for limited manufacturing capacity. If transformer delivery timescales do not improve, even well-planned network reinforcements will face material delays.

Political Risk Around Market Design

The REMA process has been subject to repeated delays, with the consultation period extended three times since its launch. Uncertainty about future market design chills investment in new capacity, as developers cannot model long-term revenue streams with confidence. If the government fails to reach a final decision on locational pricing by the end of 2026, investor confidence could erode, particularly for projects with 20-30 year operational lifetimes that need revenue certainty to secure financing.

Curtailment Escalation

Renewable curtailment in Great Britain reached 12.4 TWh in 2025, representing approximately 8% of available renewable generation. Curtailment costs exceeded $1.8 billion, paid through consumer bills. If curtailment rates continue rising toward 15% in 2026 as new wind capacity comes online without matching grid reinforcement, the economic case for renewable investment weakens, and the cost burden on electricity consumers becomes politically untenable.

What Practitioners Should Do Now

The convergence of queue reform, planning acceleration, and market redesign creates a window of strategic opportunity for sustainability professionals who act decisively.

First, audit existing PPA portfolios and procurement pipelines for interconnection risk. Request detailed connection agreement documentation from counterparties, including milestone dates, queue position under the reformed methodology, and contingency plans for delays. Projects lacking firm connection dates should be weighted differently in portfolio planning.

Second, align facility and site selection decisions with planned grid reinforcement corridors. NESO's Holistic Network Design and its updates identify the geographic areas where new transmission capacity will arrive first. Co-locating demand near these corridors reduces transmission charges and improves access to competitively priced renewable electricity.

Third, evaluate behind-the-meter and private wire options as hedges against grid delay risk. For organisations with flexible demand profiles, direct connections to adjacent renewable generation bypass the public grid entirely, eliminating queue risk and reducing exposure to rising network charges.

Fourth, engage with the REMA consultation process. Locational pricing will redistribute costs and benefits across the system, and organisations that understand the implications for their geographic footprint can position procurement strategies accordingly.

FAQ

Q: How will the reformed connections queue affect existing PPA agreements? A: Existing PPAs with secured connection dates should be unaffected, but PPAs contingent on future connections may face repricing or delay risk if counterparty projects lose queue position under the "first ready, first connected" model. Review contractual provisions around force majeure and connection delay.

Q: Is locational pricing likely to increase or decrease corporate electricity costs? A: It depends on location. Organisations in areas with surplus renewable generation (Scotland, northern England) would likely see lower prices. Those in demand-heavy, generation-poor areas (London, the South East) could face increases of 5-15% at the wholesale level, partially offset by reduced constraint costs currently socialised across all consumers.

Q: What is the realistic timeline for meaningful queue reduction? A: NESO targets removing 300-400 GW of speculative capacity by end of 2026, but the remaining queue of 200-300 GW still substantially exceeds buildable capacity. Expect meaningful improvements in connection timescales for shovel-ready projects by 2027-2028, with broader systemic relief dependent on transmission reinforcement delivery in the 2028-2031 period.

Q: How should companies with science-based targets adjust for grid delay risk? A: Build contingency into interim targets by maintaining a pipeline of procurement options exceeding committed requirements by 20-30%. Consider energy attribute certificates (REGOs) as bridging instruments while physical PPAs await connection, and document grid delay as a scope 2 reporting consideration.

Sources

• Ofgem. (2025). Connections Reform: Consultation on Queue Management and Prioritisation. London: Ofgem.
• National Grid ESO. (2025). Holistic Network Design: Updated Transmission Reinforcement Priorities. Warwick: NGESO.
• UK Electricity Networks Commissioner. (2025). Accelerating Electricity Transmission Network Build: Final Report. London: HMSO.
• Department for Energy Security and Net Zero. (2025). Review of Electricity Market Arrangements: Second Consultation. London: DESNZ.
• ENTSO-E. (2025). European Power System Equipment Supply Chain Assessment. Brussels: ENTSO-E.
• BloombergNEF. (2025). UK Renewable Energy Curtailment and Grid Constraint Analysis, Q4 2025. London: Bloomberg LP.
• Cornwall Insight. (2025). GB Electricity Market Outlook: Connections, Pricing, and Policy Reform. Norwich: Cornwall Insight.