Case study: Power markets, permitting & interconnection — a leading organization's implementation and lessons learned

The United Kingdom's renewable energy ambitions face a critical bottleneck: as of Q4 2024, National Grid ESO reported over 700 GW of generation capacity waiting in the interconnection queue—more than seven times the country's peak demand of approximately 60 GW. This staggering backlog represents billions of pounds in stranded capital and years of delayed decarbonisation progress. For organisations seeking to develop clean energy projects or secure renewable electricity through power purchase agreements, understanding the intricacies of power markets, permitting timelines, and bankability constraints has become essential to project success.

Why It Matters

The UK government has committed to decarbonising the electricity grid by 2030, requiring an unprecedented acceleration of renewable energy deployment. However, the pathway from project conception to energisation has become increasingly treacherous. According to the Department for Energy Security and Net Zero's 2024 progress report, the average time from planning application to grid connection for large-scale renewable projects now exceeds seven years, up from approximately four years in 2018.

This delay creates cascading consequences across the energy transition. Developers face holding costs that erode project economics, while corporate buyers struggle to secure the renewable electricity needed to meet science-based emissions targets. The Climate Change Committee's 2025 Progress Report to Parliament highlighted that interconnection delays alone could jeopardise 15-20 GW of renewable capacity needed to meet 2030 targets.

The financial implications are substantial. Cornwall Insight estimated in late 2024 that projects stuck in interconnection queues represent over £45 billion in potential investment. Each year of delay costs developers approximately 3-5% of total project value through extended development costs, inflation adjustments, and opportunity costs. For a typical 100 MW solar farm with a £60 million capital expenditure, this translates to £1.8-3 million in annual holding costs.

Beyond direct project impacts, queue delays distort power markets. The wholesale electricity market increasingly reflects scarcity premiums that could otherwise be moderated through additional renewable capacity. Analysis by Aurora Energy Research in January 2025 suggested that accelerating grid connections by just two years could reduce wholesale prices by 8-12% by 2028, saving consumers billions.

Key Concepts

Power Markets: The UK operates a liberalised wholesale electricity market where generators sell output to suppliers through various mechanisms including bilateral contracts, power exchanges (such as EPEX and Nord Pool), and the balancing mechanism operated by National Grid ESO. The market clearing price is set by marginal generation costs, which increasingly reflect gas prices given the role of combined-cycle gas turbines as price-setting units. Renewable generators typically operate as price-takers, receiving market prices plus any applicable support mechanism payments such as Contracts for Difference strike prices.

Permitting: In the UK context, permitting encompasses multiple regulatory approvals including planning consent (granted by local authorities for projects under 50 MW or the Planning Inspectorate's Nationally Significant Infrastructure regime for larger schemes), environmental impact assessments under the Town and Country Planning Environmental Impact Assessment Regulations, and various licences including generation licences from Ofgem and grid connection agreements. The 2023 Electricity Act amendments introduced streamlined processes for priority grid projects, though implementation remains inconsistent.

Power Purchase Agreement (PPA): A PPA is a long-term contract between an electricity generator and a buyer (typically a corporate offtaker, utility, or trading counterparty) specifying the price, volume, and terms for electricity delivery. In the UK market, corporate PPAs have grown substantially, with the RE100 initiative reporting over 4 GW of corporate renewable procurement capacity contracted in 2024 alone. PPA structures include fixed-price agreements, contracts for difference with floor and ceiling prices, and virtual or synthetic PPAs that provide financial settlement without physical delivery.

Interconnection: Grid interconnection refers to the physical and contractual process of connecting a generation asset to the transmission or distribution network. In the UK, this involves securing a connection agreement from National Grid ESO (for transmission-connected projects above 100 MW) or the relevant distribution network operator (DNO) for smaller projects. The connection agreement specifies the connection point, capacity, technical requirements, and connection date. Projects must also secure transmission entry capacity through the Connections and Use of System Code (CUSC) framework.

Scope 3 Emissions: Within the Greenhouse Gas Protocol framework, Scope 3 encompasses indirect emissions occurring in an organisation's value chain. For electricity consumers, Scope 2 covers purchased electricity emissions, but Scope 3 Category 3 includes transmission and distribution losses. Importantly, for electricity generators, Scope 3 Category 11 covers emissions from the use of sold products—relevant when combustion-based generation is involved. Corporate PPA procurement directly impacts Scope 2 reporting when utilising market-based accounting methods, making reliable renewable electricity access essential for emissions reduction commitments.

What's Working and What Isn't

What's Working

Contracts for Difference Allocation Rounds: The government's CfD mechanism continues to drive utility-scale renewable deployment. Allocation Round 6, concluded in September 2024, contracted 4.8 GW of new renewable capacity at record-low strike prices averaging £47/MWh for offshore wind. The auction structure provides revenue certainty that underpins project financing, with 95% of CfD-backed projects since 2015 successfully reaching financial close. The expansion of the CfD to include repowering of existing wind farms in AR6 demonstrated policy flexibility in addressing the evolving needs of the renewables sector.

Grid Queue Reform Initiatives: National Grid ESO's 2024 Connections Reform programme has begun to address queue inefficiencies. The introduction of milestone-based progression requirements—where developers must demonstrate project viability through planning consent and financing commitments—has resulted in the removal of approximately 40 GW of speculative capacity from the queue as of December 2024. This queue cleansing improves signal quality for genuine projects and accelerates connection offers for viable developments.

Strategic Transmission Investment: The Accelerated Strategic Transmission Investment (ASTI) framework, launched in 2023, has fast-tracked £20 billion in transmission reinforcement projects. Key schemes including the Eastern Green Link subsea cables (connecting Scotland to Yorkshire) and the Bramford to Twinstead overhead line reinforcement have secured planning consent under the expedited process. These investments address fundamental network constraints that bottleneck renewable energy flow from Scotland and offshore wind zones to demand centres.

Corporate PPA Market Maturation: The UK corporate PPA market has developed sophisticated risk allocation mechanisms that improve deal flow. Aggregated PPAs, where multiple corporate buyers pool demand to underwrite a single project, have become standard for mid-sized developments. Amazon, Google, and Microsoft collectively contracted over 2 GW of UK renewable capacity through PPAs in 2024. The emergence of credit sleeve structures—where investment-grade utilities provide credit support for sub-investment-grade corporates—has expanded the buyer universe substantially.

What Isn't Working

Distribution Network Bottlenecks: While transmission-level reforms receive policy attention, distribution networks face acute constraints. UK Power Networks, the largest DNO, reported in 2024 that 78% of substations in the South East operate at or above capacity, leaving minimal headroom for new connections. Small-scale solar, battery storage, and EV charging infrastructure all require distribution access, yet queue times for distribution connections now average 18-24 months—sometimes longer than transmission connections for larger projects.

Planning Consent Timelines: Despite national policy supporting renewable deployment, local planning decisions remain inconsistent and protracted. The Planning Inspectorate's own data shows that Nationally Significant Infrastructure Projects take an average of 4.2 years from application to decision, with notable outliers exceeding six years. The 2024 proposed reform of the National Policy Statements has generated further uncertainty, with some local authorities delaying decisions pending revised guidance. Judicial review challenges, particularly relating to environmental assessments and community impacts, add months to already extended timelines.

Bankability Gap for Merchant Projects: Projects unable to secure CfD contracts face significant financing challenges. Merchant exposure—where projects sell at wholesale prices without long-term contracted revenue—commands substantial risk premiums from lenders. Analysis by Green Giraffe indicates that fully merchant UK solar projects require equity returns of 12-15% compared to 8-10% for fully contracted projects, materially increasing the cost of capital. With corporate PPA tenors typically limited to 10-15 years against asset lives of 30+ years, projects face merchant tail risk that constrains debt availability.

Grid Connection Attrition: Despite queue reforms, connection agreement withdrawal rates remain elevated. Industry estimates suggest that 35-40% of connection offers are never exercised, reflecting either project failure or strategic queue positioning. This attrition creates uncertainty in transmission planning and complicates the identification of genuine connection demand. The current connection charging methodology, which assigns costs based on connection location rather than network benefit, creates perverse incentives for developers to seek connections in constrained areas where reinforcement costs are socialised.

Key Players

Established Leaders

SSE Renewables: The development arm of Scottish and Southern Electricity Networks, SSE Renewables operates over 4 GW of onshore and offshore wind capacity across the UK. Their Dogger Bank offshore wind project, jointly developed with Equinor and Eni, represents the world's largest offshore wind farm at 3.6 GW capacity and demonstrates successful navigation of complex interconnection requirements.

Ørsted: The Danish energy major maintains substantial UK operations including the Hornsea offshore wind complex off the Yorkshire coast. Ørsted has developed sophisticated grid connection strategies, including investment in transmission infrastructure through the offshore transmission owner (OFTO) regime, positioning them to manage interconnection risks proactively.

Octopus Energy Generation: The generation arm of Octopus Energy has rapidly scaled to manage over 3 GW of renewable assets under management across the UK. Their integrated model—combining development, construction, and retail supply—enables internal PPA structuring that accelerates project bankability and reduces market risk exposure.

National Grid ESO: The electricity system operator plays a central role in managing interconnection queues, operating the wholesale market, and planning transmission investment. Their Connections Reform programme and Holistic Network Design represent crucial initiatives shaping the enabling infrastructure for renewable deployment.

EDF Renewables UK: A subsidiary of Électricité de France, EDF Renewables operates onshore wind, solar, and battery storage projects totalling over 1 GW across the UK. Their balance sheet strength and established grid relationships enable consistent project delivery despite challenging market conditions.

Emerging Startups

Gridcog: This London-based software company provides grid connection optimisation tools that help developers model connection options, forecast queue movements, and identify cost-effective connection strategies. Their platform has supported connection decisions for over 5 GW of UK renewable capacity.

Modo Energy: Specialising in battery storage analytics, Modo Energy provides market intelligence that supports merchant revenue forecasting for storage projects. Given that battery storage increasingly co-locates with renewable generation to manage grid constraints, their analytics support integrated project planning.

Ripple Energy: This consumer-owned wind farm developer has pioneered a model where households directly invest in and receive electricity from specific wind projects. Their approach creates an alternative route to market that bypasses traditional PPA structures while generating bankable revenue through consumer subscriptions.

Limejump (now part of Shell): Originally a virtual power plant operator, Limejump developed AI-driven optimisation for distributed energy assets. Their platform aggregates small-scale generation and storage assets to participate in wholesale and balancing markets, creating revenue streams that support project economics.

Field: This battery storage developer and operator focuses on utility-scale storage projects co-located with renewable generation. Their integrated development approach—combining generation and storage to manage connection constraints—represents an emerging model for navigating limited grid capacity.

Key Investors & Funders

UK Infrastructure Bank: Established in 2021 with £22 billion in capital, UKIB specifically targets clean energy infrastructure investment. Their willingness to accept longer tenors and provide subordinated debt positions fills financing gaps that conventional lenders avoid.

Greencoat Capital: Managing over £7 billion in clean energy assets, Greencoat operates through multiple listed vehicles including Greencoat UK Wind. Their long-term investment horizon and sector expertise make them significant providers of project equity and refinancing capital.

Gresham House: This alternative asset manager operates dedicated clean energy funds with substantial UK exposure. Their approach encompasses development capital, construction financing, and operational asset acquisition across wind, solar, and storage technologies.

Aviva Investors: The investment arm of Aviva maintains significant allocations to UK clean energy infrastructure through both direct investment and fund structures. Their insurance-backed capital base supports long-dated debt positions aligned with infrastructure asset lives.

Schroders Greencoat: Following the 2023 acquisition of Greencoat, Schroders has substantially expanded its renewable energy asset management capabilities. The combined platform manages over £10 billion in clean energy assets with significant UK concentration.

Examples

Hornsea Three Offshore Wind Farm: Ørsted's 2.9 GW Hornsea Three project illustrates successful navigation of the UK interconnection regime. The project secured planning consent in 2020 following a four-year examination process and achieved financial close in 2024 with £8 billion in project finance. Key success factors included early engagement with National Grid on transmission design, a staged connection approach that aligned commissioning with transmission reinforcement timelines, and a CfD contract from Allocation Round 4 that provided revenue certainty for debt providers. The project demonstrates that even mega-scale developments can progress when developers invest in grid relationship management and accept phased delivery to match infrastructure availability.
Cleve Hill Solar Park: This 350 MW solar farm in Kent, approved in 2020 as the UK's first solar project to receive a Development Consent Order under the Nationally Significant Infrastructure regime, illustrates both the possibilities and challenges of large-scale solar deployment. The project combined solar generation with 150 MW of battery storage to manage grid constraints and provide ancillary services. However, the project faced a 30-month delay between planning consent and construction commencement due to grid connection negotiations and equipment procurement challenges. The integrated storage approach proved essential to securing a viable connection agreement, demonstrating that hybrid configurations may become standard for constrained networks.
ScottishPower Renewables' East Anglia Hub: ScottishPower's integrated development of three offshore wind projects (East Anglia ONE North, East Anglia TWO, and the future East Anglia THREE) totalling 2.9 GW demonstrates coordinated interconnection planning. By developing projects with shared onshore grid infrastructure—including a common connection point and cable corridor—the developer reduced per-MW connection costs by an estimated 25% compared to standalone development. The approach required complex commercial arrangements with National Grid and early commitment to transmission investment, but created a replicable model for offshore wind development in capacity-constrained regions. The hub achieved full planning consent in 2022 and continues phased construction with anticipated completion by 2028.

Action Checklist

FAQ

Q: What is the current average wait time for a transmission-connected renewable project in the UK to receive a grid connection? A: As of late 2024, the average wait time from connection application to energisation for transmission-connected projects exceeded 10-12 years for new applications in constrained areas. However, this figure is heavily influenced by queue composition—many applications represent speculative capacity that will never progress. For genuine, well-prepared projects that meet milestone requirements, realistic timelines are typically 5-7 years from application. The 2024 Connections Reform has begun to address queue inefficiency, with National Grid ESO targeting a reduction to 7-year maximum timelines by 2027, though achieving this target will require sustained reform momentum and significant transmission investment delivery.

Q: How do Contracts for Difference impact project bankability compared to merchant or PPA-based revenue strategies? A: CfD contracts provide the strongest bankability signal, enabling debt financing with leverage ratios of 70-80% and interest rate margins of 150-200 basis points over reference rates. The guaranteed strike price and 15-year contract tenor eliminate both price and volume risk (subject to availability). PPA-backed projects typically achieve 60-70% leverage with margins of 200-300 basis points, reflecting counterparty credit risk and tenor limitations. Fully merchant projects face the most constrained financing terms, with leverage rarely exceeding 50% and equity return requirements of 12-15% reflecting wholesale price exposure. Many projects pursue hybrid strategies with partial CfD or PPA coverage combined with merchant tail exposure, requiring sophisticated financial structuring to optimise capital costs.

Q: What role does battery storage play in addressing interconnection constraints? A: Co-located battery storage increasingly serves as a grid constraint management tool rather than solely a revenue-generating asset. By charging during periods of high renewable output and discharging when grid capacity is available, storage can enable higher export volumes from constrained connections. Some developers have accepted reduced connection capacities in exchange for earlier connection dates, using storage to capture and time-shift output that would otherwise be curtailed. National Grid has also developed Active Network Management schemes where storage participates in automated curtailment protocols, receiving compensation for constraint management services. The business case for co-located storage must therefore consider both energy arbitrage revenues and the value of enhanced connection utilisation.

Q: How should developers approach planning consent in the context of extended interconnection timelines? A: Planning consent and grid connection represent interdependent but separately managed processes that create coordination challenges. Current best practice involves initiating connection applications before planning submission, as queue position determines timeline regardless of planning status. However, planning consent is increasingly required to meet connection milestone requirements, creating circular dependencies. Developers should target planning consent achievement within 18-24 months of connection application to align with typical milestone windows. Where planning extends beyond this timeframe—common for NSIP projects requiring Development Consent Orders—developers may need to negotiate milestone extensions or risk queue position loss. The emerging trend of Local Electricity Bills, which propose community benefit requirements linked to planning consent, adds further complexity to the planning-connection nexus.

Q: What policy changes are anticipated that could affect power markets and interconnection processes? A: The Review of Electricity Market Arrangements (REMA), with final decisions expected in 2025, could fundamentally restructure wholesale market design. Options under consideration include locational marginal pricing, which would create geographically differentiated wholesale prices that reward generation in high-demand areas and penalise output in congested zones. This would dramatically affect project economics and site selection criteria. Separately, the Connections Reform programme continues to evolve, with proposals for paid connection queues, technology-specific allocation mechanisms, and tighter milestone enforcement. The Net Zero Electricity Strategy, anticipated in mid-2025, will set out transmission investment priorities and may introduce accelerated permitting for strategic projects. Developers should incorporate policy scenario analysis into project planning, recognising that 5-10 year development timelines will span multiple policy iterations.

Sources

National Grid ESO. "Connections Reform: Consultation and Industry Engagement." December 2024.
Department for Energy Security and Net Zero. "Clean Power 2030: Progress and Pathways." November 2024.
Climate Change Committee. "2025 Progress Report to Parliament." January 2025.
Cornwall Insight. "Interconnection Queue Analysis and Investment Implications." Q4 2024.
Aurora Energy Research. "GB Power Market Outlook." January 2025.
Ofgem. "Network Price Control RIIO-ED2 Final Determinations." November 2022.
RE100. "Annual Disclosure Report 2024: Corporate Renewable Procurement." December 2024.
Green Giraffe. "UK Renewable Energy Finance: Market Conditions and Trends." October 2024.