Interview: practitioners on Power markets, permitting & interconnection — what they wish they knew earlier

In 2024, over 1,500 gigawatts of renewable energy capacity sat waiting in European interconnection queues—more than double the continent's current installed renewable capacity. "We had the financing, we had the equipment contracts, and we had community support," recalls Maria Lindström, a project development director at a major Nordic renewables developer. "What we didn't have was a grid connection date within any reasonable planning horizon. That single constraint nearly killed a €200 million wind project." Her experience reflects a systemic challenge that practitioners across Europe's energy transition confront daily: the widening gap between ambitious decarbonization targets and the infrastructure bottlenecks that throttle deployment.

Why It Matters

The European Union's REPowerEU plan targets 42.5% renewable energy in final consumption by 2030, requiring an unprecedented acceleration in clean energy deployment. Yet according to the European Network of Transmission System Operators for Electricity (ENTSO-E), the average time from interconnection application to energization across EU member states reached 8.2 years in 2024—up from 5.7 years in 2019. This permitting paralysis threatens not only climate goals but also energy security objectives crystallized by the 2022 energy crisis.

The financial stakes are staggering. WindEurope estimates that permitting delays cost the European wind sector €43 billion in stranded development capital between 2020 and 2024. Meanwhile, the European Commission's 2025 State of the Energy Union report found that 67% of surveyed renewable developers cited interconnection queue management as their primary barrier to project viability—surpassing financing costs for the first time since systematic tracking began.

"The irony is painful," notes Dr. Henrik Jørgensen, who leads grid integration research at the Technical University of Denmark. "We have banks desperate to fund green projects, manufacturers scaling production, and governments setting ever-more-ambitious targets. But the transmission infrastructure connecting supply to demand operates on planning cycles established in the 1970s. The mismatch is fundamentally a governance problem, not a technical one."

For sustainability leads navigating this landscape, understanding the interplay between power market structures, permitting regimes, and bankability requirements has become essential. Projects that successfully reach commercial operation increasingly share common attributes: early engagement with transmission system operators (TSOs), sophisticated permitting strategy, and financial structures that account for timeline uncertainty.

Key Concepts

Power Markets and Market Design: European power markets operate through a combination of day-ahead, intraday, and balancing mechanisms coordinated through regional coupling. The 2024 EU Electricity Market Reform introduced capacity mechanisms and contracts-for-difference (CfD) frameworks that directly impact renewable project economics. Practitioners emphasize understanding bidding zone configurations and price formation, as locational marginal pricing discussions accelerate across the continent.

Permitting and Authorization Frameworks: The EU's revised Renewable Energy Directive (RED III), adopted in 2023, mandates maximum permitting timelines of 12 months for projects in designated "go-to" areas and 24 months elsewhere. However, implementation varies dramatically across member states. Germany's amended Federal Nature Conservation Act and Spain's Royal Decree 1183/2020 represent divergent approaches to environmental review integration, creating jurisdiction-specific complexity for multi-market developers.

Additionality: In corporate power purchase agreements (PPAs), additionality refers to whether contracted renewable generation represents new capacity that would not have been built absent the offtake commitment. The GHG Protocol's 2024 Scope 2 Guidance update strengthened additionality requirements for market-based accounting claims, making temporal and locational matching increasingly scrutinized by sustainability auditors and investors.

Demand Charges and Grid Cost Allocation: Network tariff structures significantly impact project economics, particularly for behind-the-meter installations and storage assets. The 2024 ACER Framework Guideline on Electricity Tarification pushed member states toward more cost-reflective charging, with demand-based components affecting load profiles and battery dispatch optimization strategies.

Measurement, Reporting, and Verification (MRV): Rigorous MRV protocols underpin carbon accounting claims and subsidy compliance. The EU's Carbon Border Adjustment Mechanism (CBAM) and the Corporate Sustainability Reporting Directive (CSRD) have elevated MRV requirements, with third-party verification becoming standard for renewable energy certificate (REC) claims and emissions factor documentation.

What's Working and What Isn't

What's Working

Single Environmental Permit Approaches: Denmark's "one-stop-shop" permitting model, where the Danish Energy Agency coordinates all authorization requirements through a unified process, has reduced average onshore wind permitting from 4.3 years to 1.8 years since 2022. Portugal's simplified environmental licensing for projects in industrial zones has similarly accelerated deployment, with 2.3 GW of solar reaching final investment decision in 2024 alone.

"The Danish model works because it inverts the burden," explains Anna Bergström, a permitting specialist who has worked across Scandinavian markets. "Instead of developers chasing twelve different authorities, the Energy Agency manages inter-agency coordination. It doesn't eliminate environmental review—it professionalizes it."

Anticipatory Grid Investment: The UK's Offshore Transmission Network Review and subsequent Holistic Network Design represent a paradigm shift from reactive to proactive infrastructure planning. By modeling 2050 capacity scenarios and coordinating anticipatory reinforcement, National Grid ESO reduced projected offshore wind connection delays by 4-7 years for projects in the Celtic Sea and North Sea zones. The €32 billion investment program, while substantial, demonstrates that front-loaded infrastructure spending can unlock significantly larger private renewable investment.

Standardized PPA Structures: The emergence of standardized corporate PPA frameworks—particularly RE-Source's European PPA template and the EFET renewable energy annex—has reduced transaction costs and accelerated deal closure. Practitioners report that standardized documentation cut average negotiation timelines from 14 months to 6 months between 2022 and 2024, with legal costs declining by approximately 40%.

What Isn't Working

Queue Management Without Consequence: Despite interconnection queue reforms in Germany, Spain, and Italy, speculative applications continue to clog processing pipelines. The Spanish grid operator REE reported that only 23% of projects in its 2023 queue held viable site control, with the remainder representing speculative positions that consume administrative resources without genuine development intent. Milestone-based deposits and "use-it-or-lose-it" provisions have proven insufficient where penalties remain too modest to deter queue parking.

Fragmented Environmental Review: Multi-permit environmental processes remain the primary timeline driver in most jurisdictions. A 2024 analysis by the Florence School of Regulation found that environmental impact assessment (EIA) procedures accounted for 58% of total permitting duration on average, with judicial review risk extending projects by an additional 18-36 months in roughly one-third of cases. The absence of shot clocks for review completion and inconsistent judicial standards across member states create profound uncertainty.

Bankability Gaps for Novel Technologies: While utility-scale solar and onshore wind have achieved standardized financing structures, emerging technologies—including floating offshore wind, green hydrogen electrolysis, and long-duration storage—face persistent bankability constraints. Lenders cite technology risk, offtake uncertainty, and inadequate regulatory frameworks. "Banks want 15-year contracted revenues with investment-grade counterparties," notes Thomas Müller, a project finance partner at a leading European infrastructure advisory. "Most hydrogen projects offer 3-5 year offtake from industrial buyers with sub-investment-grade ratings. The gap is structural, not cyclical."

Key Players

Established Leaders

1. Ørsted (Denmark): The world's largest offshore wind developer, with over 15 GW of installed capacity and deep expertise in complex permitting across multiple European jurisdictions. Their Hornsea projects in the UK represent benchmark interconnection management.

2. Iberdrola (Spain): A vertically integrated utility with 43 GW of renewable capacity globally, Iberdrola has navigated Spanish permitting complexities while expanding across European markets. Their grid development subsidiary, i-DE, manages 270,000 km of distribution networks.

3. RWE Renewables (Germany): Following the 2019 Innogy integration, RWE operates 13 GW of renewable capacity with significant offshore wind, onshore wind, and solar portfolios across Northern Europe.

4. Enel Green Power (Italy): The renewable subsidiary of Enel operates 55 GW globally, with extensive experience in Italian permitting frameworks and Southern European grid integration challenges.

5. Vattenfall (Sweden): A state-owned utility with 10 GW of renewable capacity, Vattenfall has pioneered fossil-free steel partnerships and innovative grid connection approaches in Scandinavia.

Emerging Startups

1. Sympower (Netherlands): A demand response aggregator connecting industrial flexibility to TSO balancing markets, with operations across 12 European countries.

2. Kite Power Systems (UK): Developing airborne wind energy technology with novel approaches to permitting and environmental assessment for emerging generation technologies.

3. Enspired (Austria): An AI-powered energy trading platform optimizing battery storage and flexible asset dispatch in intraday and balancing markets.

4. Pexapark (Switzerland): A renewables risk management and PPA advisory platform providing transaction intelligence across 25 European markets.

5. Aurora Energy Research (UK/Germany): Analytics and forecasting services supporting project valuation, merchant risk assessment, and regulatory intelligence for renewable developers.

Key Investors & Funders

1. European Investment Bank (EIB): The EU's climate bank deployed €36 billion in clean energy financing in 2024, with particular focus on grid modernization and cross-border interconnection.

2. Copenhagen Infrastructure Partners: A specialized infrastructure fund manager with €28 billion under management, focusing on offshore wind, green fuels, and transmission assets.

3. Brookfield Renewable Partners: Global renewable power platform with significant European holdings, including recent acquisitions in Spain and Portugal.

4. Macquarie Green Investment Group: Part of Macquarie Asset Management, GIG manages €40+ billion in green investments with substantial European renewable and grid exposure.

5. SWEN Capital Partners: A French impact investor with €7 billion under management, focusing on energy transition infrastructure including grid-connected storage and flexibility solutions.

Examples

1. Germany's North Sea Wind Hub (2023-2025): The TenneT-led 2GW offshore cluster connection program demonstrates coordinated permitting at scale. By consolidating environmental review for multiple wind farms into a single strategic assessment, development timelines compressed by approximately 30%. The €3.2 billion infrastructure investment unlocked €12 billion in associated wind project financing, with first power achieved 18 months ahead of initial baseline projections.

2. Spain's Solar Auction Reforms (2024): Following chronic queue congestion, Spain's Ministry for Ecological Transition implemented mandatory milestone deposits (€40,000/MW) and 36-month development deadlines for successful auction bidders. Within 12 months, 8.4 GW of speculative capacity exited the queue, while genuine developers reported 40% faster grid study processing. The reforms contributed to 5.6 GW of solar reaching commercial operation in 2024—a national record.

3. Nordic-Baltic Interconnection Acceleration (2024-2025): The NordBalt2 cable project between Sweden and Lithuania leveraged the EU's Projects of Common Interest (PCI) framework to achieve a 4-year permitting timeline—half the historical average for cross-border transmission. Coordinated environmental assessment across two jurisdictions and streamlined maritime spatial planning approvals demonstrated the potential for regulatory cooperation to accelerate strategic infrastructure.

Action Checklist

• Engage transmission system operators 24-36 months before planned construction to understand queue positions and realistic connection timelines
• Map all required permits across environmental, planning, and grid authorization tracks to identify critical path dependencies
• Assess "go-to area" designation status and proactively engage with regional authorities on renewable acceleration zones
• Structure PPA negotiations to address additionality requirements and temporal matching expectations from corporate buyers
• Build permitting delay contingencies into financial models, stress-testing returns under 12-24 month extension scenarios
• Establish milestone-based payment structures with EPC contractors that align with interconnection date uncertainty
• Implement robust MRV systems that satisfy both subsidy compliance and voluntary carbon market verification standards
• Monitor regulatory developments across target jurisdictions, particularly EU directive transposition timelines
• Develop relationships with specialized legal counsel experienced in environmental litigation and judicial review defense
• Participate in industry associations and regulatory consultations to shape permitting reform implementation

FAQ

Q: How long should developers realistically plan for European grid interconnection in 2025? A: Planning horizons vary significantly by market. In Scandinavia and the Netherlands, 3-5 years remains achievable for well-prepared projects. In Germany and Italy, 6-8 years is more realistic for greenfield developments. Practitioners recommend engaging TSOs before site acquisition and building 24-month buffer into baseline timelines. Projects in designated go-to areas under RED III transposition may benefit from accelerated tracks, but these remain limited in geographic scope.

Q: What makes a renewable project "bankable" in current European markets? A: Bankability rests on four pillars: contracted revenues (typically 10-15 year PPAs with investment-grade counterparties), proven technology with established operating track records, comprehensive permitting including final grid connection agreements, and experienced developer/operator teams. The 2024 interest rate environment has tightened lender requirements, with debt service coverage ratios typically >1.3x and gearing limited to 70-75% for project finance structures. Merchant exposure tolerance has declined, with most financings requiring >70% contracted revenues.

Q: How do additionality requirements affect corporate renewable procurement strategy? A: Post-2024 GHG Protocol guidance and CDP reporting frameworks increasingly scrutinize additionality claims. Corporates seeking credible Scope 2 emissions reductions should prioritize PPAs with new-build projects that demonstrate clear financial additionality—meaning the offtake contract was necessary for final investment decision. Temporal matching (hourly or sub-hourly) is becoming standard expectation for 24/7 carbon-free energy claims, driving interest in storage-paired PPAs and portfolio approaches across multiple generation sources.

Q: What regulatory changes should practitioners monitor in 2025-2026? A: Key developments include: member state transposition of RED III permitting provisions (deadline December 2025); ACER network code revisions for demand response participation; EU grid code amendments for storage integration; and CSRD implementation affecting energy-related disclosure requirements. The EU's proposed Net Zero Industry Act may introduce additional manufacturing content requirements affecting equipment procurement timelines. National capacity mechanism design reviews in Germany, France, and Poland will also impact merchant revenue assumptions.

Q: How can smaller developers compete with integrated utilities for grid capacity? A: Smaller developers increasingly pursue portfolio strategies, aggregating multiple smaller projects to achieve scale efficiencies in grid engagement and permitting. Strategic partnerships with utilities for offtake and grid connection—structured as development agreements rather than outright sales—allow independent developers to access utility-grade interconnection resources while retaining project economics. Several member states, including Portugal and Denmark, have introduced queue priority mechanisms for community energy and smaller-scale developments that merit investigation.

Sources

• European Commission. (2025). State of the Energy Union 2025. Brussels: Publications Office of the European Union.
• ENTSO-E. (2024). Ten-Year Network Development Plan 2024: System Needs Study. Brussels: ENTSO-E.
• WindEurope. (2024). Wind Energy in Europe: 2024 Statistics and Outlook. Brussels: WindEurope.
• Florence School of Regulation. (2024). Permitting of Renewable Energy Projects in the EU: A Comparative Analysis. Florence: European University Institute.
• International Energy Agency. (2024). World Energy Investment 2024. Paris: IEA Publications.
• Council of European Energy Regulators. (2024). Status Review of Renewable Energy Support Schemes in Europe. Brussels: CEER.
• GHG Protocol. (2024). Scope 2 Guidance: Market-Based Accounting Clarifications. Washington: World Resources Institute.