FINANCING OFFSHORE INTERCONNECTORS
ACROSS THE NORTH SEA
Executive Summary: Innovative approaches for scaling up future financing for the buildout of the regional offshore grid 4
1. Scaling up the North Sea offshore grid to meet policy targets requires addressing current challenges 7
1.1. The ambitious offshore wind development targets set by North Sea countries require a substantial grid buildout
1.2. The required offshore grid development necessitates a significant scaling up of investments
1.3. Offshore grid development contributes to the different objectives of the North Sea countries
1.4. Addressing financing issues will be crucial in paving the way for an operational offshore grid
2. New approach for cross-border offshore grid development combining joint planning and cost-sharing mechanisms with an innovative financing framework
2.1. Caveats in the progression from planning and cost sharing to financing
3. Current financing models face limitations and challenges requiring alternative approaches
3.2.
FOREWORD
UNLOCKING THE STRATEGIC ENERGY POTENTIAL OF THE NORTH SEA
BUILDING A BANKABLE FUTURE FOR OFFSHORE INFRASTRUCTURE
Europe’s energy transition is entering a decisive phase. The recent energy crisis reminds us how fragile our dependence on fossil fuels remains. Even if natural gas prices are low today, history shows that volatility and geopolitical exposure can return overnight.
Significantly decreasing Europe’s energy dependence—and safeguarding Europe’s prosperity and sovereignty—requires a continuous shift towards electrification and all sources of renewable energy in the right mix, as well as connectivity across Europe.
With its vast wind potential, the North Sea is set to become Europe’s green powerhouse. Offshore wind is the most predictable and industrially mature renewable source. Backed by smartly developed infrastructure it could provide affordable, domestic electricity for decades to come. Fully harnessing its 300 GW of potential by 2050 could supply up to 40% of Europe’s electricity demand, decreasing energy dependence and supporting sustainable growth.
Achieving this ambition demands a new paradigm for how we plan the offshore grid, share its costs, finance it and govern the offshore infrastructure. Regional cooperation and coordinated financing must replace fragmented national approaches. The North Sea’s development is not a national project—it is a European mission.
Elia Group has long been at the forefront of offshore innovation. As a member of the Offshore TSO Collaboration, we work with our peers to jointly plan and build an integrated grid that maximises benefits for all Europeans. In this paper, we propose a concrete financing concept—the Double SPV model—to attract institutional investors, reduce overall costs and maintain operational synergies for TSOs. It offers a way to unlock new sources of capital and turn investment challenges into opportunities for sustainable value creation.
Innovation brought us this far in technology, now it must drive us further in financing and cooperation. By acting together, we can transform the power of the North Sea into lasting prosperity, resilience and lower dependence for Europe.
Bernard Gustin, Marco Nix, CEO Elia Group CFO Elia Group
INNOVATIVE APPROACHES FOR SCALING UP FUTURE FINANCING FOR THE BUILDOUT OF THE REGIONAL OFFSHORE GRID
Context
Electrification is the key to cutting Europe’s dependence on fossil fuels, strengthening energy security and resilience and ensuring competitiveness while reducing carbon emissions in the economy at large. To accommodate this evolution, a significant expansion of low-carbon power production capacity is required. In that regard, the development of offshore wind energy can be seen as a major contributor. In Europe, offshore wind ambitions are high with the North Sea basin alone having a target of 300 GW by 2050 (Ostend Declaration, 2023).
Once offshore wind turbines are installed and are producing, the generated electrons need to be transported to the load centres located onshore. The resulting need for offshore grid infrastructure will be of a similar level of ambition as the generation capacity. To keep this grid expansion realisable and digestible, it is paramount that the future design of the offshore grid is both robust and affordable.
Even in scenarios with a slower than targeted buildout of offshore wind, proactively developing the offshore grid is a no-regret measure. Moreover, hybrid projects combining windfarm connections and cross-border interconnections can optimise scarce resources, space and materials and deliver substantial benefits to consumers through better power system and market integration. In order for these hybrid projects to see the light of day, overarching planning is needed (compared to an uncoordinated and rather inefficient project-by-project approach). Such a strategic view, however, requires early coordination across countries and institutions to build commitment from the start and facilitate project identification.
Project identification, therefore, should be the result of an integrated approach on regional planning of both offshore transmission infrastructure and generation assets in which projects within the sea basin are jointly analysed and subsequently prioritised. This step should be followed by a complementary regional approach on cost and benefit sharing in which costs of both offshore infrastructure and generation support schemes (e.g. Contracts for Difference) are allocated between countries.
A promising example can be found in the North Sea basin where different electricity transmission system operators gather in the Offshore TSO Collaboration (OTC) to identify offshore infrastructure solutions, reflect on cost-sharing methodologies and discuss joint options for financing. Their work closely aligns with that of the political decision-makers assembled in the North Seas Energy Cooperation (NSEC), demonstrating the value of combining technical planning with high-level political backing. It also complements existing European and national frameworks such as the Offshore Network Development Plan (ONDP) and the Ten-Year Network Development Plan (TYNDP) processes. Above all, a pragmatic approach based on successful steps is strived for.
Once cost shares are known within the sea basin, a regional financing framework may enable to further unlock the offshore projects. One of the main aims of such a framework is to attract both private and public financing commensurate with the scale of the challenge, including through derisking. NSEC has mandated the OTC to work on this specific matter.
Elia Group’s initiative
Elia Group, being part of the OTC, now wants to come forward with its ideas on the future financing aspect, building on its earlier work on the Offshore Investment Bank (Ørsted & Elia Group, 2024). Through its status as a listed company, it has gained extensive experience in capital markets and aims to take the ongoing discussions on offshore infrastructure financing a step further while being complementary to OTC work.
Through this paper, Elia Group wants to provide insights on potential solutions for financing that need to be addressed on a regional sea basin scale, considering the context of joint planning and cost sharing of the offshore assets. This paper describes different financing options capable of tackling the unprecedented wave of investments required for offshore interconnectors across the North Sea. Its intention is not to prescribe a single solution, but to inform and advance the debate among policymakers, TSOs and financial institutions on how to design robust, scalable and bankable structures to support the financing of the North Sea grid expansion and potentially that of other sea basins.
Although national TSOs, the traditional developers and operators of this infrastructure, have so far been largely successful in securing the capital required to meet their investment needs, some expect to face challenges in finding sufficient and affordable financing for their long-term network developments. To keep the costs of the required infrastructure expansion acceptable for society, it is necessary that the impact of this search does not trickle down to the creditworthiness of the TSOs, leading to an increase in capital costs.
Although the quantum of financing mobilised through TSOs’ balance sheets has increased rapidly, it might reach its limits at some point given the huge investment needs that lie ahead. Unlocking the vast amount of capital required will therefore demand innovative financial approaches.
Privately funded and operated models using project finance structures have been tested, with the UK leading the way, offering an interesting alternative to traditional financing by incumbent national TSOs. Yet, project-by-project approaches remain insufficient to address investment needs at the scale required.
In parallel, a major opportunity—and challenge—for Europe is to mobilise private capital to finance strategic grid infrastructure. Attracting private capital at scale and at a reasonable cost requires robust financial structuring of offshore grid projects, supported by targeted interventions and financial instruments from Public Financial institutions notably the European Investment Bank (EIB).
Content of the White Paper
In this paper, as a solution, a Double Special Purpose Vehicle (SPV) approach is put forward where one SPV is established for the purpose of owning and operating the asset, while the other constitutes a dedicated financing vehicle that pools capital from public and private investors to fund the project costs. This dual structure aims to strike a pragmatic balance between the merits of corporate finance (owning and operating the asset) and project finance (non-recourse and debt deconsolidation).
A theoretical, albeit realistic, case study involving four TSOs and based on actual regulatory constraints and economic simulations of a given project, illustrates how this conceptual approach can effectively be implemented. It confirms that the considered structuring options could be financially viable for key stakeholders involved (TSOs, financiers/ investors and authorities), but also suggests that Public Financial Institutions would be needed to close financial market gaps.
A practical roadmap to align stakeholders, among which the OTC, on designing the financial framework needed for a coordinated, timely and cost-efficient roll-out of the offshore grid should contain the following key milestones: 1) confirmation of the investment framework specifying the financial structuring options, anchor financiers and available financial instruments; 2) preliminary structuring of envisaged projects (with term sheets of key contracts and financial documentation) and finally 3) negotiations on structuring and financing, appointment of financiers and documentation. Once the documentation has been signed and permitting has been cleared, construction can start. Disclaimer
It is important to specify that the topic under scrutiny is the potential joint financing of future, regionally agreed and sea basin coordinated projects as currently discussed and identified in the context of the NSEC and OTC. The envisaged horizon for these financing solutions that could accompany this offshore infrastructure development is to be situated around 2040. It is not intended to address ongoing or planned projects nor their CAPEX needs at Elia Group.
INTRODUCTION
1. SCALING UP THE NORTH SEA OFFSHORE GRID TO MEET POLICY TARGETS REQUIRES ADDRESSING CURRENT CHALLENGES
1.1. The ambitious offshore wind development targets set by North Sea countries require a substantial grid buildout
↗ The North Sea region stands on the cusp of an unprecedented transformation in renewable energy deployment. Through the landmark Ostend Declaration of 2023, nine North Sea countries have committed to an ambitious vision of turning the North Sea into Europe’s ‘Green Power Plant ’. These commitments translate into specific, quantifiable targets of achieving 120 GW of offshore wind capacity by 2030 and scaling up to 300 GW by 2050.
↗ These targets are challenging. To put them in perspective, the installed offshore wind capacity in the North Sea basin in 2024 stood at around 33 GW. According to WindEurope, the average annual offshore wind installation rate over the past decade was approximately 2.5 GW/yr. As illustrated in Figure 1 2 meeting the 2030 target alone requires nearly quadrupling the existing capacity within just five years. This would boil down to accelerating the deployment rate to nearly nine times the historic pace. Looking further ahead, the 2050 target represents a ten-fold increase from today’s installed capacity. This scale of expansion demands an unprecedented acceleration.
Europe needs offshore wind, and offshore hybrids will be essential to achieving it efficiently and at scale. Yet we still lack financing models that match this need — innovative, collaborative, and capable of turning the opportunity of shared cross-border generation and grid infrastructure into investable deployments. Elia Group rightly highlights the need for new financing models, and we fully support the push to broaden our thinking toward more collaborative solutions.
AMANDA DASCH, Chief Development Officer, Ørsted
↗ To connect the new offshore wind capacity with the onshore load centres, substantial investment in grid infrastructure will be needed as was underscored in the Draghi report, warning that without such investment, grids risk ‘ becoming the next bottleneck’ 3 .
↗ Given the critical role of grids for integrating affordable renewable energy Iand supporting electrification, the European Commission announced, by the end of 2025, the publication of the European Grids Package as part of the Competitiveness Compass for the EU and the Clean Industrial Deal. Ensuring a well-integrated and optimised European electricity grid is crucial to speed up a competitive and cost-efficient energy transition.
↗ Hybrid transmission assets, which combine offshore wind farm connections with cross-border interconnection (see Figure 2), represent a crucial innovation in offshore infrastructure development as they are often more cost-efficient than standalone radial connections to the seashore. Moreover, they are able to reduce the number of landing points making better use of scarce resources and space, they typically have higher utilisation rates by combining uses and help smooth out variability in renewable generation. Therefore, these hybrid interconnectors are key to further connecting EU countries and leveraging the benefits of market and energy mix integration, leading to a reduction of wholesale power prices in the long term, implying an improved European competitiveness.
↗ The Offshore Network Development Plans anticipate that, by 2050, around 14% of total capacity (or around 50 GW) will utilise hybrid connections 4 Studies conducted by various European TSOs (e.g., Elia Group, TenneT, Energinet and Gasunie) suggest a higher potential: between 80 to 112 GW of hybrid capacity could be developed by 2050 5
↗ These hybrid projects, however, present unique challenges due to their complexity and the limited collective experience in their development. To ensure their timely and sufficient installation, several aspects must be covered which are cited in part 2.
FIGURE 2:
HYBRID INTERCONNECTORS PRESENT VARIOUS BENEFITS COMPARED TO RADIAL INTERCONNECTORS, INCLUDING SIGNIFICANT COST SAVINGS DUE TO LOWER INFRASTRUCTURE NEEDS (FEWER CABLES AND CONVERTER STATIONS)
Radial approach 10 landing points
1.2. The required offshore grid development necessitates a significant scaling up of investments
↗ The financing implications of this unprecedented transformation are substantial. According to ENTSO-E, the total investment required in European offshore electricity networks up to 2050 would reach €400 billion for the EU Member States, United Kingdom and Norway combined .
↗ The offshore grid infrastructure alone would amount to €70 to €90 billion in investment by 2030, with total transmission infrastructure needs reaching €260 billion by 2050 for the Northern Sea basin 7
↗ These investments must support the quadrupling of current offshore grid capacity by 2030 8 representing one of the most significant infrastructure buildouts in European history. The magnitude of required capital deployment necessitates to optimise and broaden financing approaches as well as the cooperation between public and private sectors.
↗ Unit costs of transmission infrastructure have also grown significantly, nearly doubling from five years ago, driven by tight supply chains and increases in prices of raw material 9
↗ The growing financial pressure on European TSOs is already becoming evident as massive network investments are not only needed for offshore wind development, but also to integrate onshore renewable energy sources, strengthen power grids to support the electrification of the economy, foster market integration through increased interconnection and refurbish existing networks.
One offshore wind farm - one export cable. Interconnections between markets planned separately.
Source: Elia Group and Ørsted(2024)-Making Hybrids Happen 10
Offshore grid and wind farms planned and built together, combining export cables and interconnectors to multilinked offshore wind farms.
3 Draghi, Mario, The Future of European Competitiveness – A Competitiveness Strategy for Europe (Part A) (European Commission, 9 September 2024).
4 ENTSO-E, TYNDP 2024 Offshore Network Development Plans – Transmission Infrastructure Needs (January 2024).
5 TenneT, Energinet, and Gasunie, Pathways 2.0 Study (North Sea Wind Power Hub Initiative); Ørsted and Elia Group, Making Hybrids Happen: Enabling Offshore Hybrid Projects to Enhance Europe’s Energy Transition (March 2024).
6 ENTSO-E, Offshore Network Development Plan (ONDP) Pan-European Summary Report (26 February 2024).
7 ENTSO-E, Offshore Network Development Plan (ONDP) Pan-European Summary Report (26 February 2024).
8 ENTSO-E,
9
10 Ørsted and Elia Group, Making Hybrids Happen: Enabling Offshore Hybrid Projects to Enhance Europe’s Energy Transition (March 2024).
Offshore wind is one of Europe’s greatest opportunities. With over 20 years of pioneering experience in the offshore wind industry, DEME sees offshore development as not merely a technological cornerstone, but as a societal imperative. Through bold collaborations across borders and sectors, and with the right enabling framework, we can help to build the backbone of Europe’s energy transition. With momentum increasingly building around the European Grids Package, now is the time to accelerate offshore infrastructure— delivering clean, affordable energy, strengthening grid resilience, and integrating markets. Let’s turn ambition into action.
Managing Director Offshore Energy, DEME
Hybrid approach 4 landing points
HUGO BOUVY,
1.3. Offshore grid development contributes to the different objectives of the North Sea countries
↗ The ambitious expansion of offshore wind in the Northern Seas is driven by a set of shared objectives among the participating countries. These common goals extend beyond renewable energy deployment as they encompass broader strategic, economic and social priorities that align national interests with regional cooperation.
• Security of supply and reduction of European states’ energy dependence. The development of North Sea offshore wind represents a crucial step towards reducing European energy dependency, especially on imported fossil fuel.
• Cost efficiency and affordability. If Europe can efficiently manage construction and supply chain constraints, plan efficiently, derisk projects and finance them at relatively good terms, costs can be kept down and competitivity and affordability assured.
Market integration. Cross-border interconnectors play a vital role in coupling markets and enabling efficient electricity trading.
Social and economic benefits. The North Sea offshore wind buildout and interconnection also hold other substantial socioeconomic benefits, including industrial development opportunities and job creation.
Climate targets and renewable integration. Europe’s ‘Green Power Plant’ for achieving European decarbonisation goals will make a decisive contribution to meeting climate commitments while establishing the region as a global leader in offshore wind development.
1.4. Addressing financing issues will be crucial in paving the way for an operational offshore grid
↗ When executing the considerable grid expansion projects, significant financing requirements arise which may pose challenges for the TSOs involved. Although North Sea TSOs may not face immediate or imminent difficulties today in financing their current or planned projects, it seems important to address these questions in a timely manner and to initiate the debate on potential solutions in order to pave the way for a smooth roll-out of the regional offshore grid, backed by investment frameworks that can accelerate capital deployment while maintaining affordability, financial attractiveness and system reliability.
↗ Keeping infrastructure affordable and, in particular, keeping financing costs down requires an efficient risk allocation and an innovative investment framework that attracts private financing at minimal cost, underpinned by targeted and optimised public sector intervention.
↗ Elia Group has taken the thought exercise on this future financing a step further. Following the publication of its ‘Making Hybrids Happen’ paper together with Ørsted which coined the term Offshore Investment Bank (OIB) for the first time, it has since made significant progress on the conceptualisation and now wants to present, with this paper, a pragmatic way of applying the approach.
The OIB concept was originally developed with the objective of centralising and harmonising public and private investments across the pipeline of greenfield hybrid interconnectors in the North Sea. Following a deeper analysis of the concept and after ample discussions with key stakeholders, Elia Group has come up with an alternative approach, starting with the design of fit-for-purpose financial frameworks and instruments that could achieve the same objectives in a more nimble and pragmatic way. It, however, does not rule out implementing the OIB concept at a later stage once the target project financial structures and corresponding instruments have been defined to enable its deployment under satisfactory conditions.
The transition to a sustainable offshore energy system in Europe demands a robust financial framework to accelerate offshore wind deployment and strengthen energy independence. Tackling cross-border challenges is crucial for long-term success, as it helps reduce costs and supports the integration of interconnected European electricity markets. To unlock the full potential of offshore wind in the EU, effective cross-border financing mechanisms for both grid infrastructure and the implementation of twosided contracts for difference are essential.
Europe’s offshore wind ambitions face serious headwinds as defence priorities and economic pressures divert attention and funding. To keep momentum, clear regulation, solid financing and renewed government commitment are needed—recognising energy independence through offshore wind and grid interconnection as a strategic pillar of Europe’s sovereignty.
Jan De Nul, and Europe’s offshore wind supply chain in general, has and still is investing heavily in next-generation offshore installation vessels and equipment to give Europe the capabilities it needs to deliver on its energy (transition) goals. If Europe wants to safeguard its sovereignty and leadership in offshore wind, now is the time for action.
2. NEW APPROACH FOR CROSS-BORDER OFFSHORE GRID DEVELOPMENT
COMBINING JOINT PLANNING AND COST-SHARING MECHANISMS WITH AN INNOVATIVE FINANCING FRAMEWORK
↗ To achieve Europe’s ambitious offshore deployment targets, the current framework based on a project-by-project approach does not seem appropriate and has already proven to be insufficient. Instead, an intensified cooperation between North Sea TSOs and with national governments on planning, cost sharing and financing is the way forward.
↗ In 2010, albeit under a different acronym, the North Seas Energy Cooperation (NSEC) was established as a regional partnership between the authorities of Belgium, the Netherlands, Luxembourg, Germany, France, Ireland, Denmark, and Norway 11 It promotes cost-effective offshore renewable energy development in the North Sea region. In 2024, the NSEC called for a new approach to offshore financing at the sea basin level, which would encompass a framework of common planning and cost sharing building on the TEN-E regulation.
↗ Regarding TSO collaboration, the Offshore TSO Collaboration (OTC 12) was launched in 2022, bringing together North Sea TSOs to advance offshore network infrastructure in line with the Esbjerg and Ostend declarations. It supports the shared vision of making the Northern Seas the ‘Green Power Plant of Europe’. The OTC proposed a regional planning process complementing ENTSO-E’s TYNDP to jointly identify and assess cross-border projects of European value 13
↗ Elia Group’s 2024 Viewpoint study ‘Going Like the Wind’ describes the potential of a ‘virtuous cycle’ to develop offshore wind in Europe and reap the full benefits of the potential for this technology. The key elements of the cycle are improved planning and cost-sharing mechanisms, jointly financing projects, derisking investments, mobilising private capital and ameliorating supply chain management.
↗ Joint sea basin level planning and cost-benefit sharing processes could facilitate decisions and accelerate offshore infrastructure development. This is illustrated in Figure 3 which pictures an efficient end-to-end approach to develop a set of promising projects, based on joint regional planning, cost sharing and financing.
▶ Joint identification of projects with
11 Acknowledging the MoU between the UK and NSEC.
12 The Offshore TSO Cooperation or OTC is a partnership between TSOs from the North Sea region. The collaboration was created in response to the Esbjerg Declaration (2022) and further concretised in the context of the Ostend Declaration (2023). Its main goal is to demonstrate how regional cooperation can contribute to the economic development of energy infrastructure in the North Sea, and by extension throughout the European Union.
13 OTC, Joint Planning in Europe’s North Seas Expert Paper III (April 2025).
▶ Cost sharing method which allows effectively taking decisions and moving forward with projects
▶ Tools that help to derisk investments leading to lower capital costs
▶ Finding ways to attract large amounts of private capital
↗ The topics of regional grid planning, identifying and prioritising project sets and sharing costs in relation to the perceived benefits are introduced in previous publications of the OTC. They are being further developed according to the mandate the OTC TSOs received from NSEC (April 2025) and is the subject of OTC’s Expert Paper IV 14 published at the third North Sea Summit in Hamburg (January 2026).
14 OTC’s Expert Paper IV will also elaborate on the financing aspect within the regional collaboration.
▶ Delivering the required infrastructure in a cost-efficient way
FIGURE 3:
OVERVIEW OF THE PROPOSED APPROACH TO SCALE UP THE DEVELOPMENT OF THE NORTH SEA OFFSHORE GRID
Regional cooperation in the North Sea’s sea basin
Cost & benefit sharing
Financing & funding
Offshore wind is a reliable European electricity source that enables large-scale, lowcost energy transition. Developing the full potential of the North Sea is essential to support the competitiveness of our industry and ensure affordability for households. Both offshore grid and generation infrastructure should be facilitated by a strong regulatory framework and broad access to capital. Cost of hybrid interconnectors should be assessed holistically and include ripple effects on generators and consumers and be fairly allocated to all markets benefitting. Offshore interconnectors are preferably linking countries with different generation mixes or largely uncorrelated renewable resources or consumption patterns to relieve congested onshore grids and minimise overall cost.
2.1. Caveats in the progression from planning and cost sharing to financing
↗ Co-optimising the development of generation and transmission assets brings benefits compared to a standalone approach that only adapts the network to the evolution of the generation capacity. The costs and benefits of the infrastructure and generation assets are interlinked, and it makes sense to assess them jointly and to share their costs and benefits in a fair and consistent manner.
As such, for these first two phases, it is relevant and efficient to follow a single process to discuss and decide on planning and cost-benefit sharing for both infrastructure and CfD support schemes for generation 15
↗ Legal and regulatory constraints, however, on the separation of ownership and operation of generation and transmission assets may prevent a joint financing approach. Indeed, the Clean Energy Package prescribes ownership unbundling between TSOs and generation/supply activities to ensure non-discriminatory access to network. Consequently, even if there is an exemption for major infrastructure projects, structuring processes that would entail joint ownership of transmission and generation capacity would raise complex legal and regulatory issues.
↗ Furthermore, wind farms and transmission infrastructure are fundamentally different asset classes with distinct timelines, revenue streams, risks, returns and securities. Bundling them would create a mix of risk exposures that may be unattractive to most investors, since different investors are interested in each type of asset class. There is indeed already market appetite and well-established financing structures for offshore wind generation investments. Market exposure and hedging instruments/support schemes also differ between the two types of assets.
↗ Moreover, the impacts of cost sharing on financing structuring of the projects entails several key points of attention. For instance, while TSOs may want—or even have a legal obligation in some countries—to keep ownership and operation responsibility over the assets located in their own territorial waters, the cost sharing may introduce a difference between the assets they own and what they have paid for. The question of regulatory recognition and refinancing of such constellations requires investigation. These challenges are further detailed in Section 4.4.
3. CURRENT FINANCING MODELS FACE LIMITATIONS AND CHALLENGES REQUIRING ALTERNATIVE APPROACHES
↗ There are two traditional sources for financing electricity infrastructure assets:
• corporate financing, i.e., financing through the TSO (on balance sheet);
• project financing, i.e., financing through a separate dedicated entity 16 (off balance sheet).
↗ For the upcoming investment wave, these traditional models may reach a limit due to:
• the size of the required future financing;
• the need to keep financing costs at reasonable levels;
• the regulatory complexities of offshore interconnectors;
• the particularities for developing these interconnectors within a regionally coordinated sea basin approach.
↗ Key hurdles of this traditional financing emerge in three areas:
• first, the ability of TSOs to rely on balance sheet financing is weakening as rising investment requirements impact credit ratings;
• second, while public financing can help catalyse private capital, its availability is finite and must be deployed selectively;
• third, private sector-led project finance could unlock additional resources but faces significant impediments for complex projects such as hybrid interconnectors in a regional interconnected offshore grid.
They will be further explained in the following sections.
↗ These dynamics underscore the rising importance of innovative financing to complement—or in some cases replace — conventional sources.
Offshore wind generation and cross-border power interconnection are key enablers for a secure, competitive, resilient and clean European energy system. Meeting the vast investment needs requires innovative financing solutions to effectively unlock and channel the necessary private capital at scale.
OLIVER SCHUBERT, Partner, Copenhagen Infrastructure Partners (CIP)
3.1. Mounting investment needs are undermining TSOs’ ability to finance projects on balance sheet without negatively impacting credit ratings
↗ TSOs plan, build and own offshore transmission assets as part of their regulated grid infrastructure, treating them as part of their overall capital expenditure program.
↗ Under the current framework, most TSOs usually finance new offshore transmission assets on their own balance sheets, mobilising both debt and equity. The expansion of offshore grid assets is therefore closely tied to each TSO’s financing capacity, i.e., its ability to raise capital at an acceptable cost, supported by the remuneration of their asset base as determined by their respective national regulatory authorities (NRAs).
↗ As the need for interconnectors grows, this model risks becoming a bottleneck, especially for tackling the massive investments required for offshore developments, potentially jeopardising the pace at which grids can be built.
↗ TSOs are either privately owned, i.e., mostly owned and financed by private investors or companies, or publicly owned, i.e., majority-owned by a state entity and/or other publicly owned companies.
↗ For publicly and privately owned TSOs alike, debt and equity constraints may hamper the adequate supply of capital:
• on the debt side: access to commercial bank financing may become more limited as some banks reach the exposure limits 17 to the power transmission sector. TSOs must also preserve sustainable credit ratings to avoid a swift increase in financing costs. Increasing leverage 18 beyond certain thresholds would weaken credit metrics as it would strain TSOs’ ability to service debt when shocks arise, in the absence of a sufficient equity buffer allowing for risks to be absorbed by shareholders.
• on the equity side: both publicly and privately owned TSOs are likely to face difficulties in securing equity injections at the pace required to meet upcoming investment needs. To address this, some are exploring innovative equity and quasi-equity instruments, potentially combined with debt, which could help overcome some of these constraints. These approaches should be considered alongside off balance sheet options, where available. That said, they remain limited to TSOs willing and legally permitted to accept such additional capital.
3.2. Public financing can catalyse private capital but remains limited and must be deployed strategically
↗ While public funding and financing mechanisms exist and are helpful, it is unlikely that they could fully bridge the financing gap. National budgets face competing demands from social spending, defence and other energy transition priorities, leaving limited budget for grid expansion, while lengthy approval and disbursement processes further constrain the timely use of public funds for interconnector projects.
↗ At the EU level, a range of public funding and financing instruments exist that could contribute to offshore grid projects financing needs:
17 Prudential rules limit bank exposures as a percentage of their equity on a sector-by-sector basis.
18 Leverage is the share of debt in the overall financing,
19 Moody’s, Ratings Outlook for Regulated Electric & Gas Networks (10 April 2025).
20 A quasi-equity instrument is a hybrid financing tool—such as subordinated debt, convertible loans or mezzanine capital— that behaves partly like equity and partly like debt, offering equity-like risk-return features without conferring full ownership.
Moody’s estimates that TSOs can maintain key credit metrics with annual investments of up to ~10% of their Regulatory Asset Base 19 . Beyond this, equity injections or quasi-equity instruments 20 are required to preserve credit quality. Since 2021, the aggregate net financial debt of major TSOs in the North Sea region has risen significantly, reflecting the scale of investment needed for the energy transition and grid expansion. Broader market signals, such as Moody’s April 2025 negative outlook on European regulated electricity networks, indicate that rising debt may translate into higher borrowing costs, further constraining TSOs’ financial flexibility and their capacity to fund critical infrastructure efficiently through debt.
↗ For both debt and equity, dependence on future NRA decisions to determine asset remuneration levels on a periodic basis creates uncertainty over TSO revenue which makes it more difficult to secure financing.
• The Connecting Europe Facility (CEF) provides grants for Projects of Common Interest (PCIs) and Projects of Mutual Interest (PMIs) 21 covering studies and a portion of construction costs for cross-border interconnections that demonstrate significant benefits for market integration and security of supply. A significant increase of the CEF has been proposed by the European Commission (within the framework of the MFF 22) for the 2028-2034 budgetary period, multiplying its energy envelope by five. This is a much needed step to keep supporting projects at scale, but it will continue to only be a complement to funds raised through other means.
• The European Investment Bank (EIB) offers various instruments:
‒ loans dedicated for interconnection projects or large infrastructure assets: typically financing up to 50% of eligible costs (or 75% for highly strategic projects), with favourable terms reflecting the projects’ contribution to EU energy and climate objectives. Elia Transmission Belgium, for example, secured a €650 million green credit facility from the EIB for the Princess Elisabeth Island project.
‒ two main types of guarantees: the first covers sovereign or regulatory risks, typically provided outside the EU though it may be considered for specific strategic projects within the EU, whilst the second covers project or liquidity risks, assessed on a caseby-case basis depending on the risk profile 23
‒ equity investments: historically non-core type of investments and mostly made outside the EU, though they may be considered for certain projects under specific European Commission programmes.
‒ bond financing desk: facilitating the issuance and acting as anchor investor24 in senior and hybrid bonds 25
↗ In 2024, the EIB Group mobilised over €100 billion in new investment for energy security, with €8 billion committed to equity and quasi-equity instruments. This included support for transmission networks, interconnectors, and storage infrastructure, with the EIB financing up to 40% of Europe’s total investment in grids and storage that year 26 Its institutional flexibility has recently been reinforced. In March 2025, the Council of the European Union approved a modification to the EIB’s statute, granting its governing body full authority over the bank’s gearing ratio.
↗ At the non-EU level:
the UK National Wealth Fund plays an important role in the funding and financing of interconnector projects by providing significant strategic capital to accelerate transmission infrastructure. For example, it committed a £600 million (€696 million) loan to Iberdrola to co-finance two major subsea transmission cables between Scotland and England 27
the Nordic Investment Bank supports interconnector projects through longterm lending. For example, it provided a €202 million loan to Denmark’s Energinet to co-finance the 1.4 GW Viking Link between Denmark and the UK 28
• European Export Credit Agencies (ECAs) facilitate the financing of cross-border grid infrastructure by underwriting risk and offering guarantees. For example, the Viking Link interconnector between Denmark and the UK was backed by a pioneering multi-ECA green loan, with financing provided by Italy’s SACE and Germany’s Euler Hermes 29
↗ While these mechanisms are designed to support strategic, cross-border infrastructure, they are limited in scale relative to total investment needs, focusing on derisking and enabling priority projects rather than fully financing broader investment needs.
↗ These mechanisms should be reinforced given the amount of support required, but searching for new ways to maximise their leverage and impact is key. Various options are investigated in this paper, in consideration of the various objectives and constraints identified.
3.3. Private-sector led project finance offers potential but faces significant implementation hurdles in the current market
↗ A project finance model would rely on the project’s own cash flows, rather than the balance sheet of its sponsors, to secure debt financing for the required CAPEX. In this structure, the asset is typically housed in a legally distinct SPV created solely to develop, own and operate the project. The SPV ring-fences the project’s assets, contracts and liabilities ensuring that lenders’ exposure is limited to the project itself and not the wider corporate balance sheets of the sponsors. Debt is generally non-recourse or limited recourse30 with debt repayment sourced exclusively from the SPV’s revenues.
↗ The UK has been known to advance the project finance model to finance its interconnectors, notably with the Offshore Transmission Owner (OFTO) regime, which allows private entities to acquire and operate transmission assets once construction is completed. Critical questions around long-term operation, extension and decommissioning after contract expiry, however, remain insufficiently addressed.
↗ As part of the main hurdles hindering the deployment of the private sector led project finance model for the development of the offshore network, one can highlight:
• ownership and licensing constraints: a project finance approach faces a range of regulatory constraints on ownership and licensing under current EU legislation. In some countries, a company owning a transmission asset must be a TSO31 meaning any private sector owned SPV, directly owning and operating these assets would need to obtain TSO status. This would trigger licensing requirements and regulatory obligations that may be exclusively entrusted to the domestic TSOs. Even in a SPV-favourable framework like the UK, the licensing decision can be lengthy. This requirement creates significant barriers to implementing traditional private sector led project finance structures and limits flexibility in structuring investment vehicles. In addition, regulatory complexity requires adjustments and challenges in regulatory oversight add another layer of uncertainty. Furthermore, the allocation of congestion rents, subsidies and cost sharing may present difficulties in this type of hybrid interconnectors setting.
• governance challenges: the governance and contractual framework required for project finance would necessitate intricate mechanisms to balance investor rights with states (through NRA/TSO) effective oversight, potentially leading to cumbersome decision-making processes and reduced operational efficiency, threatening system reliability and security of supply.
• control of operations: under a classic project finance approach, investors will often require guarantees that the economic value of their asset can be optimised throughout operations, in particular by optimising maintenance periods; the optimisation of a given traditional point-to-point interconnector is not necessarily aligned with the optimisation of an offshore network containing hybrid interconnectors, giving significant rise to potential issues.
3.4. Way forward: overcoming current investment barriers requires an innovative approach
↗ The analysis of various financing options reveals that both traditional TSOs on-balance sheet and traditional private-sector led project finance structures present challenges and shortcomings for offshore hybrid interconnector development within a collaborative regional context.
↗ On the one hand, the prevailing TSOs’ on balance sheet financing approach offers advantages in terms of ample experience, legal certainty and rapid deployment. It should be further explored, though, including through quasi-equity products yet to be developed, how this approach can be improved and supported so that TSOs can continue to develop (offshore) infrastructure. At a certain moment, however, due to expected limitations of their capital raising abilities, it could face constraints linked to many TSOs’ credit rating metrics. It is therefore to be considered as complementary to alternative financing solutions.
↗ On the other hand, challenges linked to licensing, ownership, operations and governance make private-sector led project finance solutions challenging in the collaborative regional environment.
↗ While the selection of the optimal financing approach may depend on project-specific circumstances, this paper presents a possible alternative in the form of a combined solution, called the Double SPV approach. This solution addresses the multiple constraints highlighted above by effectively combining elements of both TSOs corporate and project finance.
↗ Figure 5 provides a summary of the main financing options and the challenges associated with them. It also already reveals some of the benefits of the Double SPV approach which will be further analysed in the next chapters.
• TSOs raise debt and equity directly on their balance sheets to fund interconnector projects, and/or
• TSOs set up a wholly-owned SPV that holds the project assets but is consolidated, with debt ultimately supported by the parent TSOs.
• A privately-owned SPV develops, owns, and operates the project with no recourse to the TSOs.
• TSOs are only involved for system planning and management, and connection purposes.
• Example: UK OFTO regime
• TSOs retain control by developing, owning, and operating assets through an ‘Owning & Operating SPV’ (O&O SPV).
• A separate ‘Financing SPV’ raises capital from external investors, backed by revenue flows assigned to it via a Financing and Allocation of Revenue Agreements (FARA) without direct recourse to TSOs.
ASSOCIATED CHALLENGES
Increasing strain on TSO credit metrics and ratings, as equity and debt headroom may become limited on the long run.
Public funding is scarce and must be used sparingly to maximise catalytic effect.
Consolidation of project debt reduces flexibility for other TSO investments.
ASSOCIATED CHALLENGES
Ownership/licensing barriers: Many jurisdictions require TSO ownership, limiting feasibility.
Governance issues: Complex frameworks dilute accountability and slow decisions.
Operational misalignment: Investor priorities may conflict with system optimisation.
POTENTIAL BENEFITS
Preserves TSO control and compliance with national regulatory requirements.
Mobilises private capital at scale while creating conditions for partial debt deconsolidation.
Reduces reliance on scarce public funding, while keeping financing costs affordable.
Provides a more pragmatic balance between traditional TSO models and private-sector project finance ones.
FIGURE 5: HIGHLIGHT OF THE MAIN EXISTING AND CONSIDERED STRUCTURING AND FINANCING OPTIONS
Transforming the North Sea into a vast green power hub will demand unprecedented levels of investment from both the private and public sector. To attract private investors, policymakers must create frameworks that provide the longterm certainty needed to secure capital without excessive risk. At EIP, we recognise the complexities of the energy infrastructure landscape and the critical roles that both investors and TSOs play in unlocking value and accelerating Europe’s journey toward energy independence. We are eager to explore innovative solutions including the Double SPV approach, a promising concept designed to leverage the unique strengths of all stakeholders involved in developing the North Sea’s offshore network.
4. A PROPOSED INNOVATIVE APPROACH FOR FINANCING OFFSHORE INTERCONNECTOR PROJECTS
↗ To effectively bridge the financing gaps and challenges mentioned in Section 3, the Double SPV approach proposed here needs to have the following key features: affordability and bankability: lowering the cost of capital through robust risk mitigation and diversification and creating derisked, yet economically interesting investment opportunities.
• efficient use of public financing: leveraging limited resources from the EU, the EIB and national sources to catalyse private investment.
• balance between TSO control and private investment: ensuring operational synergies with the role of the TSO and enabling partial debt deconsolidation, while creating structures attractive to institutional investors.
↗ This section sets out the full architecture of the Double SPV approach, built on a:
• investor appeal: meeting institutional investors’ appetite for long-duration, low-risk, infrastructure-backed returns, while avoiding the operational and regulatory complexity of asset ownership and operation.
• practical implementation: avoiding major regulatory or policy overhauls to ensure solutions are realistic, replicable and timely across jurisdictions.
• tailored project architecture: a bespoke two-layer SPV separates financing and operational responsibilities;
• risk-balanced contractual framework: agreements distribute risks, rights and revenues among all stakeholders;
• predictable revenues and firm regulation: provide the stability required for long-term bankability and investor confidence;
• seamless integration of the cost-sharing mechanism: ensures fair allocation across jurisdictions and participants;
• targeted public support: credit-enhancement and derisking instruments mobilise private capital;
• capital market access via securitisation: recycles financing and enables scalable future development.
4.1. Presenting architecture of the proposed tailored project finance structure
↗ The Double SPV approach introduces an innovative two-layer SPV framework. At its core, the Financing SPV serves as a dedicated financing vehicle that pools capital from public and private investors to fund the project costs. This entity works in tandem with an Operating and Owning (O&O) SPV, which remains majority owned by the TSOs (with the possibility for external investors to invest aside the TSOs) and maintains responsibility for infrastructure asset development, operation and ownership
It is not possible to achieve a deconsolidation of the debt if the debt is owed by an entity that is being consolidated. It is therefore worth considering a structure where the debt and the assets are not located within the same legal entity. The debt holding entity then provides financing to the asset holding entity, allowing such entity to construct the project, in a manner that would not constitute indebtedness under International Financial Reporting Standards (IFRS). To do so, such arrangements must avoid replicating a fixed repayment obligation, as this could reclassify the financing as debt and
(with the TSO licences and regulatory responsibilities remaining at the TSOs level).
↗ One main driver for splitting ownership and financing into two separate legal entities is for deconsolidation purposes 32 In principle, (de)consolidation will be assessed at the level of the relevant legal entity. The payments from the project to the Financing SPV should be based on revenue sharing to ensure some level of risk transfer in order for them not to be classified as debt.
undermine deconsolidation. Instead, the structure should rely on revenue-sharing or pass-through mechanisms, which preserve the link to project revenue and risks without creating balance sheet liabilities for the TSOs, as detailed in Section 4.2.3. on the Financing and Allocation of Revenue Agreement (FARA). Although not explored in detail in this paper, it should be noted that equity investments from external equity investors into the O&O SPV, either directly or through the Financing SPV, could present some merits for debt deconsolidation purposes.
↗ The O&O SPV retains ownership of the asset and full operational control, so TSOs continue to manage project delivery in line with national mandates and system planning requirements, although some technical amendments of national energy legislation may be required to permit the establishment of such O&O SPVs, particularly if they would be co-owned by two or more TSOs (and possibly external private investors).
↗ This structure creates a clear separation between financing and operational activities to ensure technical optimisation of infrastructure use. The arrangement ensures compliance with regulatory requirements on ownership and unbundling, while enabling efficient commercial arrangements between the entities.
↗ A core legal arrangement that governs the allocation of project revenue and risks from the O&O SPV to the Financing SPV is established (called FARA). Its main purpose is to enable the progressive remuneration associated with the development and operation of offshore grid infrastructure, financed through the Financing SPV.
↗ By keeping financing provided by the Financing SPV off the TSO’s balance sheet, and/or by generating credit metrics impacts that would be lower than classic debt, this model could enable TSOs to raise substantial volumes of capital without triggering negative impacts on their credit metrics.
The scheme presented here relies on the option of having one O&O SPV and one Financing SPV in a project subset. However, in practice, the perimeter and number of SPVs depends on a few parameters:
regarding the O&O SPV(s), having one or more in a given project subset will depend on:
the regulatory constraints in each country;
the finetuning of risks and responsibilities to be negotiated;
the potential deconsolidation impact of diluting each TSO’s share into a joint structure.
regarding the Financing SPV(s), having one or more will depend on the market’s appetite for diversifying
4.2. Structuring the project’s contractual agreements to balance risks, rights and revenue amongst stakeholders
↗ A robust contractual framework is needed to underpin the Double SPV approach, ensuring clear allocation of risks, responsibilities and revenues among stakeholders. It rests on three key pillars:
• the Framework Agreement bringing together TSOs, EU institutions, governments and financial partners (such as the EIB or the UK-NWF), to define common investment processes and responsibilities, standardised terms and credit enhancement mechanisms. Some anchor equity investors and commercial banks may also be invited to participate. This agreement provides a stable, yet flexible, environment for the development and financing of target projects;
• the Joint Development Agreement (JDA) which sets out the detailed roles and responsibilities of each TSO, establishes rules for risk and cost sharing and defines the flows of revenues between the TSOs and the O&O SPV. It also ensures consistent governance and mitigates project-on-project risks 33 across jurisdictions;
• the Financing and Allocation of Revenue Agreements (FARAs) which govern the allocation of revenue and risks from the O&O SPV to the Financing SPV. These agreements define clear protocols for cash flow management and risk distribution and create bankruptcy-remote income streams, reinforced by formal regulatory undertakings. Instead of relying on physical asset security, the framework secures receivables and accounts to provide investors with predictable and enforceable cash flows.
4.2.1. Framework Agreement
↗ At the core of the contractual architecture, a framework agreement would be established between the TSOs, the European Commission, NSEC governments, the EIB (and possibly other Public Financial Institutions such as the UK-NWF), and potential other key financiers.
↗ The framework agreement would define common investment decision-making processes and responsibilities, as well as standardisation elements, including commitments from various parties. It aims at providing a stable and predictable environment for all stakeholders, while retaining the flexibility to accommodate national legal requirements and project-specific needs.
↗ Main components that should be envisaged within the Framework Agreement would be:
• cost-sharing principles: general principles for cost sharing would be set out in this agreement;
• revenue allocation: a key component would be the development of revenue allocation mechanisms. These become particularly important where, for debt deconsolidation purposes, traditional repayment obligations (essentially debt-like agreements) are replaced with transfers of future revenue streams;
regulatory undertakings and revenue assignability: to reinforce robustness, it may be necessary for NRAs or governments to commit that regulated revenue streams (whether tariff-based, Cap and Floor mechanisms or congestion revenues) can be assigned to third parties (including project SPVs and their creditors). Likewise, undertakings from public entities guaranteeing continued payment in the event of insolvency of a TSO or project SPV would reduce risks and, therefore, reduce financing costs;
Public Financial Institutions engagement: in-principle agreement of Public Financial Institutions to consider specific financial instruments and contributions to the target set of projects;
regulatory stability: the framework agreement could also include commitments from authorities regarding long-term regulatory stability and protection against retroactive measures that could undermine investor confidence.
FIGURE 7: STRUCTURE OF THE DOUBLE SPV APPROACH INCLUDING ITS THREE PILLAR CONTRACTS
4.2.2. Joint Development Agreement
↗ A JDA would be entered among all TSOs involved in the project and the project O&O SPV(s).
↗ It defines governance, risk allocation and revenue and cost sharing, ensuring clarity of roles among TSOs, and compliance with national and EU frameworks.
↗ The JDA would clearly set out the following elements:
• the project objectives and description;
• common technical standards and timelines to ensure coordinated development and commissioning;
• a unified operations protocol, including outage coordination and data sharing;
• the governance framework;
• the responsibilities and rights of each TSO and of the O&O SPV(s) for the development, construction and operation of the project—covering both TSOs hosting, constructing and financing the asset and those contributing only to cost sharing—together with the related risk-sharing modalities;
• the mechanisms for calculating and implementing cost and revenue sharing among TSOs;
• the allocation of market revenue between TSOs and the O&O SPV (with some sources of revenue, such as congestion rents, potentially collected directly by the O&O SPV, as is the case already today for certain point-to-point interconnectors);
• the cash flow waterfall between the TSOs and the O&O SPV(s);
processes for managing changes in scope, regulatory conditions or other unforeseen developments;
other risk allocation mechanisms, including liability and indemnity provisions;
procedures for eventual decommissioning; and
dispute resolution and change-of-control mechanisms to ensure stability and continuity throughout the life of the project.
4.2.3. Financing and Allocation of Revenue Agreements
↗ The FARA is a core contractual instrument that underpins the Double SPV approach. It is established between the Financing SPV and the O&O SPV and governs the share of two primary revenue streams:
regulated revenue derived from tariff-based mechanisms such as Regulated Asset Base (RAB) or Cap and Floor regimes;
market revenue, primarily congestion income generated from cross-border electricity flows.
↗ The bankability of the structure depends heavily on the robustness of these agreements and the predictability of the revenue streams they secure. FARAs clearly allocate revenue and risks, establish payment priorities and ensure stable, transparent cash flows for all stakeholders.
↗ Key features include:
• purpose and structure: the FARA ensures that revenue collected by the O&O SPV is chanelled to the Financing SPV in a transparent and pre-agreed upon way. This mechanism allows the Financing SPV to progressively reimburse the funds invested in the construction of the offshore grid while ensuring that the TSOs retain full operational control of the assets;
• predictability and investor confidence: to make the structure bankable, the FARA must give investors confidence that the project’s revenue will remain stable and enforceable over time. This means that payments under the FARA should not depend on future discretionary decisions and that they should remain valid even in case of financial stress or changes in ownership. In practice, this can be supported by safeguards such as escrow accounts, security over receivables and direct agreements between key parties;
• alignment with national frameworks: because offshore hybrid projects involve several countries, FARAs must be adaptable to different national regulatory frameworks. They should build on the revenue mechanisms that already exist (such as national RAB or Cap and Floor regimes) while ensuring that the overall structure remains consistent with EU market integration objectives. Early coordination between regulators and TSOs is therefore key to provide clarity on the revenue parameters and to ensure that the same approach can be replicated across multiple projects.
• balance sheet relief for TSOs: A properly designed FARA also helps achieve balance sheet relief for TSOs. Instead of relying on direct debt repayment obligations, the FARA allows for the assignment of future project revenue from the O&O SPV to the Financing SPV, with this revenue serving as the primary source for the Financing SPV’s debt repayment. In principle, the outstanding risks associated with the assigned share of revenue should then be passed through to the Financing SPV in order to avoid any potential consolidation of the Financing SPV’s capital at the TSOs level. For this to work effectively, the assigned revenue must be:
‒ clearly identifiable and linked to a specific project and its outstanding project risks;
‒ legally transferable under applicable laws;
‒ protected against claims from other creditors;
‒ secure, even in the event of insolvency or payment default.
By meeting these conditions, FARAs make it possible for TSOs to limit the consolidation of project debt on their own balance sheets, while still ensuring that investors benefit from reliable, long-term cash flows.
4.3. Predictable revenues and robust regulatory frameworks are needed to ensure bankability
4.3.1. Revenue framework
↗ Interconnectors’ revenue flows originate from two types of sources:
• market revenue, or congestion rent, arising from the price differences between both ends of the interconnector;
• regulated revenue, from tariffs applied to all grid users, to balance out partially (in Cap and Floor) or fully (in RAB) the costs of the project and its revenue (in financial, not economic, terms).
As represented in Figure 8, market revenues can either: 1) be collected by the TSOs (option 1), or 2) flow directly to the O&O SPV (option 2);
• in option 1, exemplified by most intra-EU interconnectors, all revenue goes through the TSOs;
• in option 2, exemplified by several existing point-to-point offshore interconnectors, revenue flows to/from the TSOs will only balance out the missing/ exceeding remuneration collected by the O&O SPV.
FIGURE 8: POTENTIAL CIRCUITS OF REMUNERATION CASH FLOWS
↗ These respective cash flow structures will have implications on the way the FARAs are structured, remunerations are defined and on securities that lenders would be entitled to claim.
↗ In some jurisdictions, however, alienation of certain TSO assets or revenues may trigger regulatory approvals or restrictions, such as the need for a prior opinion from the NRA. These regulatory requirements must be carefully mapped and integrated into the FARA framework to avoid enforceability issues. Revenue collected at the O&O SPV will be allocated according to a transparent ‘cash waterfall’. This framework ensures predictable, transparent revenue allocation, strengthening the Financing SPV’s bankability while maintaining TSO oversight and operational control of the assets.
↗ At the Financing SPV level, revenue would consist exclusively of FARA payments received from the O&O SPV. This revenue would be structured to be bankruptcy-remote 34 ensuring predictable cash flows even in the event of financial distress at the O&O SPV or the TSOs.
4.3.2. Regulatory frameworks
↗ The proposed approach aims at accommodating the existing regulatory frameworks, at both EU and country-specific levels, so that no significant reform is a prerequisite for the successful implementation of the scheme. Doing so requires careful consideration of multiple regulatory aspects.
↗ The structure must align with EU unbundling rules to ensure TSOs maintain their independence while facilitating private investment.
for the Financing SPV, that is an advantage of the proposed structure, considering the absence of control or ownership over the project assets by the Financing SPV;
for the O&O SPV, it means ensuring that private investors potentially contributing to its equity do not have stakes in power generation, or that justified exemptions are cleared prior to investment.
↗ The treatment of congestion revenue presents a particular regulatory challenge. Under Article 19 of the Electricity Regulation, congestion income must be
used primarily for guaranteeing actual capacity availability, maintaining or increasing interconnection capacities, compensating offshore producers for insufficient capacity or reducing network tariffs. Any deviation from these restrictions requires obtaining a new interconnector exemption, which must be carefully structured to ensure compatibility with the proposed revenue model, particularly when implementing Cap and Floor mechanisms.
↗ Cost-recovery mechanisms and tariff structures must be established through transparent regulatory processes with sufficient lead time to be incorporated into financial models and credit assessments. As regulatory frameworks differ between participating countries, it is assumed, under the proposed solution, that an asymmetric application of mechanisms is necessary. Applying such an approach will require close coordination with NRAs to ensure that revenue, whether delivered through transmission tariffs or equivalent mechanisms, will be available for the full operational lifespan of the infrastructure, subject only to per-
mitted adjustments. The upside of this approach is that it does not require a full harmonisation of regulatory tariff structures or the establishment of a single type of solution such as an offshore tariff.
↗ It is worth noting that each national government or NRA typically determines the applicable tariffs period and revision frequency during which the allowed revenue and tariff methodologies are fixed and subsequently reviewed. Such review cannot change the fundamental principle that the applicable tariff methodology(ies) must reflect actual costs incurred insofar as they correspond to those of an efficient and structurally comparable network operator; a principle which is enshrined in EU law. The possibility of such review, however, may create some uncertainty from the perspective of investors. The regulatory framework may benefit from an evolution to remove this (perceived) risk, to meet the objective of minimising the increases of end-user tariffs despite growing investment needs.
4.4. A cost-sharing framework aligned with the Double SPV approach
↗ The goal of the regional cost-sharing mechanism is to split the costs of the projects based on the actual economic benefits retained by each participating country, even for those not hosting the new infrastructure. The proposed structuring framework reflects the cost shares of involved TSOs through financial contributions, while not interfering with the breakdown of asset ownership, for the sake of simplicity and ease of integration into existing national regulatory frameworks. Contractual provisions within the JDA would therefore define the revenue transfers and the distribution of risk between TSOs. This framework integrates seamlessly with the Double SPV by relying on the FARAs to allocate revenue and cost flows predictably between participating entities. By doing so, it provides stability and transparency in project economics, while preserving flexibility to accommodate different participation levels among TSOs.
↗ As illustrated in Figure 9, the approach has distinct balance-sheet implications depending on each TSO’s cost share and its own level of equity participation. The TSO finances its own equity stake in the O&O SPV by raising equity or debt itself. The cost share which it does not finance itself, however, is alternatively financed by the Financing SPV which will receive committed FARA payments in return. The key principle is that the regulatory asset base would need to be adjusted to reflect the revenue to be generated by each TSO
to cover its share of the costs allowing to refinance its own equity stake or the part financed by the Financing SPV. These principles must be validated by each involved NRA. Conversely, the associated liabilities would also be adjusted from an economic perspective. In the figure, a part of TSO A’s assets and liabilities are netted of the value of TSOs’ B & C financial contributions, and TSOs’ B & C assets and liabilities are increased by the value of their contributions, accounted for as a right of use on the asset side.
↗ This structure offers several advantages:
• it maintains ‘business as usual’ for construction and ownership responsibilities;
• it ensures predictable revenue and cost flows, essential for long-term project bankability;
• it provides consistency between exante and ex-post cost allocations35 reducing the risk of disputes and enhancing regulatory clarity.
↗ By aligning cost sharing and regulated revenue recognition, this framework supports a fair and transparent allocation of both the project’s costs and benefits, while respecting each TSO’s financial and regulatory context. As a result, ownership shares may differ from cost shares.
FIGURE 9:
Illustration of TSOs regulatory balance sheets under the Double SPV approach
4.5. Tailored public support to derisk and mobilise private investment
↗ Public Financial Institutions (PFIs), primarily the EIB, are critical to the Double SPV approach, not only as lenders but as providers of credit enhancement and risk-sharing mechanisms. Their role is to use limited public capital strategically to mobilise far larger volumes of private investment, while improving affordability by reducing the overall cost of capital.
↗ Together with the EIB and National Promotional Banks and Institutions (NPBIs), the European Commission should develop financial instruments mobilising private capital for grid investments to limit the risks that could translate into higher prices for consumers or into higher financing from public budgets.
↗ Under this model, PFIs could provide a layered package of support, including:
• mini-perm debt: short-term financing (3-5 years) to bridge construction completion and long-term financing which helps stabilise operations and improve appeal for lenders who would struggle in taking on construction risks;
• subordinated or junior financing:
‒ delivered as subordinated loans or bonds, these tranches act as a first loss layer, absorbing risks during construction or operations;
‒ this risk cushion would allow senior lenders to offer lower-cost debt and improves the project’s overall bankability;
guarantees:
‒ to enhance credit quality;
‒ to derisk long term loans for private capital investors and tackle refinancing risks associated to the long economic lifetime of grid assets;
‒ direct guarantees could secure timely debt service to senior lenders or capital market investors;
‒ counter-guarantees could share credit risk with commercial banks, encouraging them to maintain or expand lending to the sector;
‒ Regulation Risk Guarantees (RRGs) could be a targeted form of guarantee, protecting Financing SPV’s debt service in case of adverse regulatory or policy changes. Backed by indemnity agreements with NSEC governments (as part of the Framework Agreement introduced above) and/or supranational entities such as the European Commission, they would provide strong assurance to investors and rating agencies; these mechanisms, proven in other European infrastructure sectors (e.g., transport and energy storage), enhance credit quality, reduce financing costs and catalyse the participation of institutional investors, which helps turn scarce public funds into a powerful multiplier for private capital mobilisation.
FIGURE 10:
↗ Figure 11 summarises the Double SPV approach, integrating all the features presented above.
FIGURE 11: COMPLETE ILLUSTRATION OF THE DOUBLE SPV APPROACH
4.6. Diving into a promising financial structure: accessing the capital market through securitisation
↗ As a complement to the Double SPV approach, securitisation could offer a compelling refinancing mechanism designed to mobilise long-term institutional capital once projects reach stable operations. It is not an alternative to the
overall framework but a second-phase tool that can recycle scarce public and bank financing into the next wave of offshore grid projects. It is depicted in
Under this business securitisation option, upon project completion, the Financing SPV would issue notes backed by the FARA receivables, which are stable and predictable revenue streams allocated from the O&O SPV. This structure would enable the refinancing of the initial construction debt once the project transitions into the operational phase. The proceeds from the note issuance would be used to repay commercial banks and public financiers, freeing up scarce bank and public capital for redeployment in new projects, while offering institutional investors a low-risk, long-duration instrument aligned with their investment appetite.
Refinancing of the Financing SPV
FIGURE 13: TIMELINE OF SECURITISATION OPTION
4.7. Conclusion
↗ The approach proposed in this section aims to pragmatically address the financing challenges faced by TSOs in developing offshore interconnectors. It seeks to mobilise private capital at scale while ensuring affordability for end-users, minimising reliance on public resources and ensuring operational synergies with the role of the TSO.
↗ By introducing a Double SPV architecture, the proposed framework could provide a practical and replicable solution to the constraints of traditional TSO financing models. It may allow TSOs to pursue ambitious investment programmes without overburdening their balance sheets or jeopardising their credit standing, a critical condition for maintaining low network tariffs, overall system affordability and the long-term sustainability of TSOs as strategic actors in the energy transition. The structure also responds to the need for new sources of long-term, low-cost capital, combining public and private financing under a common, transparent framework. It is designed to complement existing national regulatory regimes, requiring only limited adjustments rather than systemic reforms, and could therefore be applied consistently across jurisdictions.
↗ In doing so, the Double SPV approach: separates financing and operational responsibilities, allowing TSOs to retain technical and regulatory control while accessing alternative financing channels;
aligns the interests of investors, public authorities and TSOs through a clear, risk-balanced contractual framework and predictable cash flow allocation; facilitates the mobilisation of institutional capital by providing bankable, long-duration investment opportunities backed by robust regulatory undertakings;
leverages targeted public support from entities such as the EIB to enhance credit quality and affordability; possibly creates a pathway to access capital markets through securitisation, recycling scarce public and bank resources for future projects.
↗ While conceptually promising, it is worth stressing that the proposed financial framework is still at a preliminary stage and needs to be further assessed to test its robustness through iterative discussions with key stakeholders, including private investors, public financial institution (such as the EIB) and credit rating agencies, in particular on the treatment of debt and deconsolidation aspects.
↗ While primarily conceived to address future offshore grid financing, this framework’s flexibility and pragmatic design
make it relevant to other strategic TSO investment needs where similar balance sheet and affordability challenges might arise. These include onshore reinforcements, cross-border interconnections, and grid modernisation. In essence, the Double SPV approach could provide a scalable financial architecture capable of unlocking the large volumes of capital required for Europe’s energy transition, while maintaining the stability, affordability and public accountability that remain at the core of the TSO model.
5. THE GOLDFISH PROJECT
– ILLUSTRATING AND QUANTIFYING
THE DOUBLE SPV APPROACH
The fictitious case study presented here tests the structuring concepts developed under the Double SPV approach, including detailed financial modelling, stress-testing and cost-sharing implications.
Preliminary results suggest that the considered structuring options are viable and in line with expectations from key stakeholders involved (TSOs, private and public financiers and investors and national authorities including regulators).
↗ Why two SPVs ?
• the O&O SPV allows to isolate and ring-fence project ownership, operations and related cash flows under a single dedicated umbrella — a structure commonly used for regulated infrastructure projects in Europe and already applied in interconnector projects.
• the Financing SPV allows to isolate and ring-fence project financing, based on a dedicated allocation of project revenue and risks through the FARA arrangements. This is standard practice in project finance schemes, including securitization structures widely used across United States infrastructure assets and, more recently, to finance European data centers or even in emerging markets for large infrastructure projects.
This innovative approach relies on a hybrid model that combines limited TSO on balance sheet equity and operational control over strategic assets, with off balance sheet capital raised through project finance mechanisms, thereby tapping into a diversified range of investors, potentially offering attractive financing conditions.
It provides a framework to evaluate these concepts in a realistic regulatory and financial environment, based on existing benchmarks of costs, market conditions and regulatory schemes, as well as market modelling, with a strong focus on cash flow dynamics, risk allocation and financial market gaps that must be addressed to secure the mobilisation of significant private capital at the lowest possible cost.
They also highlight potential financial market gaps in terms of covering some construction and revenue risks that must be tackled through targeted interventions and tailored instruments. Addressing these risks is critical for enhancing bankability and mobilising private capital at reasonable terms, ensuring the long-term affordability and scalability of these investments.
5.1. The Goldfish Project: a theoretical hybrid interconnector project between three hosting sea basin countries and one non-hosting country
5.1.1. The Goldfish Project as an example
↗ The Goldfish Project (hereafter the Project) discussed in this section is a purely theoretical initiative involving four countries within a sea basin. Countries A, B and D are connected by the project to an offshore wind farm located in the Exclusive Economic Zone (EEZ) of Country D that lies between these countries. Country C is included as a non-hosting beneficiary of the Project.
↗ The theoretical project is based on a single hub for the sake of simplicity. A cluster of different combined hybrid projects will more likely be applicable in practice in the medium run. It would work in the same way in terms of structuring.
↗ As stated earlier in this paper, the projects expected to be financed are assumed to be the outcome of an improved regional collaboration exercise. The fictional Goldfish Project is therefore assumed to be an outcome of a regional planning exercise whereby the respective countries of the sea basin supported its construction because of the benefits it brings to the region. It also assumed these countries
have agreed on sharing project costs based on the identified benefits for each of them.
↗ Key assumptions are described below and detailed in Appendix 1. Some are based on the results of a market model but are adapted here for illustrative purposes. Costs (both CAPEX and OPEX) and congestion rents are considered shared between the four countries pro rata of the socio-economic welfare impact of the project that have been defined ad hoc for the sake of the demonstration: 30% for TSO A, 45% for TSO B, 15% for TSO C and 10% for TSO D 36 This implies that TSO regulated revenue will also be calculated on the basis of these respective shares of CAPEX, applying remuneration rules specific to each country.
↗ The baseline total CAPEX for grid assets of the Project is €11.5 billion with a construction duration of five years and an operational lifetime of 25 years. Each line is designed for a capacity of 2,000 MW.
↗ The congestion rent calculated for these three lines through the energy market model for the Project is between €0.9 and €1.8 billion per year. It is assumed to vary through time based on variations of climatic conditions and other developments of the overall European power system.
↗ It is assumed that the Project is subsidised at 5% of overall CAPEX, spread evenly between participating countries and disbursed at the same rate pari passu with CAPEX expenses.
5.1.2. The Project illustrates local regulatory and financial specificities
↗ The assumption is taken that Country D’s TSO, benefiting from particularly favourable financing conditions, funds its share of the project costs directly on its own balance sheet. In contrast, the TSOs of the other three countries adopt a joint financing structure, raising their share of the financing through dedicated SPVs under the Double SPV approach described above.
↗ In terms of revenue regimes, it is assumed that Country A uses a Cap and Floor revenue regime, while the other countries chose a RAB revenue regime. Blending these two regulatory regimes into a single exercise allows for insight into what can happen when pooled financing solutions are sought for projects which interconnect different countries with different regulatory regimes in a single sea basin. This exercise therefore aims to paint a realistic and robust picture that can help with its future implementation.
↗ The baseline characteristics of the structuring and contractual set-up considered follow the structure described in Section 4.1 to 4.5.
↗ As one of the main objectives of the Double SPV model is to deconsolidate project capital of the TSO’s balance sheets, it is required that, together with the project revenue streams, the related outstanding risks are assigned to the Financing SPV.
15:
Each national regulatory regime shields projects in each jurisdiction from a variety of risks. In practice, for a given project subset across several countries, there will be some outstanding risks not covered by regulation throughout the full duration of the project’s life. These outstanding risks are the ones that will need to be mitigated and/or allocated between project stakeholders.
FIGURE
ILLUSTRATION OF THE PROJECT UNDER THE DOUBLE SPV APPROACH
5.1.3. Base case financial assumptions in line with real cases
↗ The financial model used here combines:
• project finance modelling at an aggregated level for the Financing and O&O SPVs;
• cash flow modelling on the TSOs side.
↗ The key financial assumptions 37 for debt raised at the Financing SPV level are as follows:
• 65% gearing calibrated according to Debt Service Coverage Ratio (DSCR) 38 thresholds of average 1.3 and minimum 1.1;
• a debt repayment method with fixed principal instalments, considering that it matches well the revenue flows;
• 2.8% interest rate for a 15-year debt based on benchmarks of existing financing conditions in the sector;
a 6-month Debt Service Reserve Account (DSRA) 39 and lock-up dividends at 1.10xDSCR, following common market practice.
↗ For the Country D TSO that finances its share independently, a cost of financing corresponding to a 2.7% pre-tax Weighted Average Cost of Capital (WACC) is assumed.
↗ The regulatory WACC assumptions both for RAB and Cap and Floor are based on a benchmark of regulatory WACCs among North Sea countries:
regulatory pre-tax WACCs for RAB remunerations are set at 4.3% for countries B&C, and 2.7% for Country D; for Cap and Floor calculations, a 2.8% rate is used for floor and a 6.5% rate for cap.
5.2. Key results and lessons learnt
5.2.1. The baseline scenario is relatively attractive
↗ As explained in Subsection 5.1.1., assumptions have been calibrated as to make the base case compelling enough for illustrative purposes.
↗ The financial robustness and attractiveness of a standalone project are usually assessed with the aid of key indicators, as demonstrated for the Project in Table 2.
• average and minimum DSCRs are among the key metrics measuring the Project’s ability to serve its debt, both ahead of the Final Investment Decision (FID), where lenders will set minimal levels for the base case, and during project life, where these indicators will be used in credit facility agreements to trigger safeguard effects if cash levels are low;
• project IRR is used to measure the overall financial soundness of the project before taking financing into account. The project can be considered viable if its IRR is greater than its expected WACC;
• shareholders IRR is used to measure the return to equity for investors.. The project will be considered attractive on their side if they consider that 1) the return is adequate considering the level of risk taken, and 2) this risk-return couple is in line with their investment policy.
↗ Regarding the TSO of country D, the TSO IRR derived from the project is 2.7%, aligned with both the TSO’s regulatory WACC and its average cost of financing set at 2.7% in our example. In practice, any TSO that would find more satisfactory conditions through corporate financing than through the joint approach would be welcome to mobilise its share of financing on its own. Therefore, both options of corporate financing and Double SPV approach could cohabit and should be considered complementary rather than competing.
↗ The resulting cash flow structure and breakdown between TSOs 40 taken together on the one hand and aggregated SPVs on the other are depicted below:
• as can be seen in Figure 16, TSO revenue is higher than that of the SPVs, as TSOs are directly remunerated and cover OPEX before transferring the remaining revenue to the SPVs.
FIGURE
FIGURE 18: DETAILED CASH FLOW TSOs (€)
5.2.2. Stress tests highlight the robustness of the structure while identifying and quantifying potential market gaps
↗ Stress testing performed on a project finance model aims to assess how key financial metrics would evolve if one or several risks were to materialise and threaten the project’s financial strength.
↗ Stress tests for the Project were designed based on an analysis of a wide range of risks, with the aim of identifying the most relevant ones and calibrating their likelihood and magnitude as accurately as possible, drawing on both past trends and benchmarks, and internal calculations. Our benchmarking exercise involved reviewing past projects that experienced the described adverse events, assessing their frequency relative to the total number of projects and evaluating the potential impact of these events on project performance.
↗ The risks identified as the most sensitive ones have been targeted for stress-tests summarised in the table below.
↗ In the present example, outstanding risks used as illustration are:
CAPEX overrun not associated with additional remuneration, which is an outstanding risk for the Cap and Floor leg of the project; market risks on congestion rent, which is an outstanding risk for the Cap and Floor leg of the project; regulatory remuneration instability (as regulatory remuneration can change from one tariff period to another), for the RAB legs of the project.
Higher risk profiles (e.g., under Cap and Floor) are associated with higher returns. When a project encompasses multiple regulatory regimes, its total risk profile is more diversified.
Sensitivities Main financial impacts on Project’s key financial metrics
For countries B, C, and D under RAB), no significant impact is observed as RAB-based remuneration is increased when the cost of the investments increases 41
For country A (under Cap and Floor) 42 its contribution to the financial balance of the SPVs is deteriorated as the Project IRR for its share goes down from 5.0% to 3.2%.
Net CAPEX overrun (+20%) funded by the Financing SPV (debt and equity contributing pari passu)
Due to the joint impact of the two regulatory regimes mentioned above on the joint Financing SPV, this leads to an overall project IRR of 3.8%. Assuming that the financing gap (€2.1M) is covered 50/50 between a debt amount extension (at the same cost as initial debt) and additional equity (from TSOs and potential external investors), such a stress translates into a moderate impact on financial metrics, with an SPV shareholder IRR before tax of 4.0% (down from 5.0%) and the DSCR criteria slightly crossing the target floors (1.28 average, slightly below the 1.30 target, and 1.09 minimum, slightly below the 1.10 target).
For country A (under Cap and Floor), no impact is observed, by definition.
Decrease in regulatory WACC for countries under RAB:
- 1% from year five of operations onwards
Weak congestion income:
-10% per year compared to baseline
For countries B and C (under RAB), their contribution to the financial balance of the SPVs is deteriorated as the Project IRR for its share goes down from 4.0% to 3.5%.
Due to the joint impact of the two regulatory regimes mentioned above on the joint Financing SPV, this leads to an overall project IRR of 4.0% (down from 4.3%), translating into a moderate impact with an SPV shareholder IRR before tax at 4.6% (down from 5.0%), with DSCR criteria safely remaining above the target thresholds.
For countries B, C, and D (under RAB), no impact is observed, by definition.
For country A (under Cap and Floor), its contribution to the financial balance of the SPVs is deteriorated as the Project IRR for its share goes down from 5.0% to 3.9%.
Due to the joint impact of the two regulatory regimes mentioned above on the joint Financing SPV, this leads to an overall project IRR of 4.0%, translating into a moderate impact with an SPV shareholder IRR before tax at 4.4%, with a minimum DSCR of 1.16 close to but not trespassing minimum DSCR criteria of 1.10.
41 RAB remuneration is based on the asset cost, hence if the asset cost increases, so does the remuneration in the same
42 No ex-post CAPEX adjustments are assumed in the definitions of the Cap and Floor.
TABLE 3:
Summary of stress test results
↗ In this example, all project legs under the joint financing mechanism—each with distinct risk profiles stemming from different regulatory frameworks—have been pooled into a single joint O&O SPV and a single joint Financing SPV. In practice, however, regulatory requirements may call for separate legal entities for operations, and investors may likewise prefer to participate through distinct SPVs (one for each leg), depending on the alignment with their respective desired investment risk profiles.
↗ This stress test exercise allows us to illustrate potential risk-sharing measures that would strengthen the overall structure by addressing these outstanding risks:
• for CAPEX overruns (for legs under a Cap and Floor regime):
‒ pre-agreed senior debt amount extension and additional equity injections could be set and would work well under a RAB framework as illustrated by the first sensitivity in Table 3. If required, a junior loan facility provided by a Public Financial Institution could be envisaged to absorb additional CAPEX spending;
‒ another option would be to have TSOs bearing the risks associated with CAPEX overruns, absorbing the additional cost as a loss. Requesting TSOs to fully bear this risk would, however, require financial compensation;
‒ for lower-than-forecasted congestion income, the primary objective under the Cap and Floor framework should be to ensure that the floor level itself is set at a sufficiently attractive level;
for regulatory WACC changes, for RAB regimes:
‒ robust commitments from states and NRAs should be secured to maintain a stable WACC throughout the project’s lifetime (and that any regulatory change on remuneration will be only forward-looking to new projects). Ideally, the regulatory approach to tariffs would evolve to remove this risk by guaranteeing a remuneration for the whole lifetime of the project, i.e., extending beyond the classic tariff setting period;
‒ a Regulatory Risk Guarantee as presented in Section 4.5. which would be provided by PFIs and would be supported by NSEC governments could also further mitigate such risk.
↗ Risk allocation fine-tuning through the contractual framework of each project subset, in particular the JDA and the FARAs, will shape the way that each risk impacts the respective project stakeholders. The aim will be that each party ends up with an attractive and manageable allocation of both risks and revenue.
5.3. Conclusion
↗ The present fictional case has demonstrated how the Double SPV Approach could operate in a realistic regulatory and financial environment, supported by detailed financial modelling and stress testing. The example confirms that the concept aligns with the key objectives pursued under this framework:
• providing a robust structure for sharing risks and financing responsibilities among TSOs, while remaining compliant with national regulatory constraints;
• mobilising significant volumes of private capital under acceptable conditions.
↗ At the same time, the analysis highlights that to minimise financing costs—and ultimately the cost to society—targeted credit enhancement mechanisms should be considered to reduce the overall risk profile of such investments. These could include:
• pre-agreed contingent financing measures such as junior loan facilities from PFIs or additional equity injections from TSOs in the event of CAPEX overruns;
• appropriate calibration of floor levels under Cap and Floor regimes to ensure sufficient revenue protection;
• strong commitments from states and NRAs to maintain regulatory stability over the project lifetime, potentially supported by a RRG instrument provided by PFIs such as the EIB.
↗ Taken together, these measures would enhance bankability, strengthen investor confidence and ensure that the Double SPV Approach remains both financially sound and scalable for future hybrid interconnector developments.
6. IMPLEMENTATION ROADMAP
The structures proposed in this paper are concepts aimed at addressing challenges that will only arise in the medium to long run and still need to be co-developed with and validated by different stakeholders (including the TSOs, respective NRAs, the European Commission, governments, industry, investors, and so on). It nevertheless constitutes a valuable exercise to properly prepare for the future and already consider the different steps required to implement these solutions. An offshore infrastructure financing roadmap can help visualise these steps by identifying key milestones and required activities to pave the way for concrete implementation of the proposed solutions.
The enormous amount of capital required for the energy transition and decarbonisation of our economy necessitates innovative approaches to financing and capitalisation. Robust international partnerships between strong players are also needed to create the right conditions for attracting the required capital.
FELIPE MONTERO, CEO Iberdrola Germany
6.1. Mid-term ambitions to prepare for adequate project development and financing framework
↗ The first projects will require fine-tuning to materialise, in particular regarding clearance of principles with states and national regulators, drafting terms and conditions for the associated financial products, designing key contracts and other project documentation and so on.
↗ A corresponding indicative timeline for the next steps is presented below.
↗ A key element of such a timeline is that the required innovative solutions on the financing side cannot wait to be initiated until the stream on joint planning and cost sharing has been successfully terminated. To avoid extending project development lead times, it is essential that the creation of effective and cost-efficient financing solutions does not become a critical path in project implementation. The financing workstream should start in a timely manner and progress in parallel.
6.2. The Hamburg North Sea Summit constitutes an important milestone towards a concrete implementation of solutions
↗ A major near-term political milestone is the North Sea Summit organised in Hamburg in January 2026. This Hamburg Summit is the third of its kind, after successful summits in Esbjerg (2022) and Ostend (2023). During both previous summits, pledges to turn the North Seas into the ‘Green Power Plant of Europe’ were made, with the Ostend Declaration setting the bar of offshore generation capacity at 300 GW by 2050.
↗ According to dena and the German Federal Ministry for Economic Affairs and Climate Action, the goal of the third summit is to further accelerate the expansion of offshore energy and to achieve it as synergistically and cost-efficiently as possible. Regional grid planning, cost sharing and financing are high on its agenda.
↗ Last year, European climate and energy ministers, the EU’s energy commissioner and international leaders from the leading companies in the wind sector gathered for the North Seas Ministerial Meeting at Odense. The participants discussed how the ambitious goals for offshore wind installations in the North Sea could be achieved. This resulted in a set of concrete recommendations towards the European Commission.
↗ This year’s ministerial meeting is organised in Ostend where there will be stocktaking of the progress on the regional initiatives. It is paving the way for the Hamburg Summit where an updated OTC report on (a.o.) insights on cost-sharing and financing frameworks is expected through the mandate the OTC received from NSEC (April 2025).
↗ Beyond the Hamburg Summit, collaborative works between various stakeholders (European Commission, NSEC governments, OTC, EIB, among others) should continue to streamline project identification and work on the structuring of financing packages, based on engagements taken at or after the summit.
↗ Some ambitions and deliverables of the different organisations are:
• as stated in its Expert Paper III, the OTC will communicate on its vision and progress towards regional cost sharing and financing for offshore grid infrastructure at the Hamburg Summit. Its Expert Paper IV will be published on that very occasion;
• NSEC’s work programme for 2025-2027 includes continued achievements in the field of financing and specifically states:
‘... analysing and developing additional options for financing for hybrid and joint projects, including under the next Multiannual Financial Framework (MFFs) in close cooperation with Support Group 1 and relevant stakeholders, such as the EIB, where applicable.’
as can be witnessed from EIB’s mission statement and investment portfolio, it attaches great importance to the energy transition in general and the development (and financing) of grids in particular. In 2025, the EIB has committed a record €11 billion in new financing for energy grids, nearly tripling the level in 2023. It participates in green hybrid bonds, contributes to investments plans of TSOs and is able to reduce risk in grid investments and to attract private investment. It can blend financing with EU guarantees and offer favourable lending conditions. Further reflection on innovative tools and structuring options is attended from the EIB by the Hamburg Summit.
7. CONCLUSIONS AND RECOMMENDATIONS
7.1. Summary of key findings
↗ The transformation of the North Sea into Europe’s ‘Green Power Plant’ requires unprecedented levels of investment, with offshore grid infrastructure alone needing €70-90 billion by 2030 and reaching €260 billion by 2050. Traditional TSO balance sheet financing approaches beyond 2035 may prove insufficient, as already evidenced by mounting financial pressure on the TSOs of the Northern Seas whose combined net debt has increased by two-thirds since 2021, to more than €100 billion.
↗ A coordinated regional approach integrating planning, cost sharing and financing offers the most promising path forward. This framework would enable efficient capital deployment while ensuring appropriate risk allocation between public and private stakeholders.
↗ The traditional corporate financing of TSOs which has been widely used so far will continue to be an essential cornerstone of financing in the future to fully secure the considerable capital expenditures.
↗ While corporate financing remains an option for certain projects, the Double SPV approach presented in this paper emerges as a promising solution for effectively addressing multiple constraints. By combining elements of both direct investment and project finance while maintaining TSO’s operational
control through O&O SPVs and enabling efficient financing through dedicated Financing SPVs.
↗ This approach offers a comprehensive framework to address the complex challenges of financing offshore interconnectors at scale, while ensuring affordability for society at large, meeting investor requirements and complying with the regulatory constraints of TSOs.
↗ A theoretical case study involving four countries, based on actual regulatory constraints and economic simulations of a given project, has allowed to show how this approach can effectively be implemented. It confirms that the considered structuring options could be financially viable for key stakeholders involved (TSOs, financial investors and authorities), but also suggests that PFIs would be needed to close financial market gaps to reach the objective of mobilising private capital at an acceptable cost;
7.2. Next steps and call to action
↗ Upcoming key milestones include the Hamburg North Sea Summit in January 2026. A strong and coordinated mobilisation of key stakeholders such as NSEC governments, European Commission and the EIB is key in the following months to ensure this summit can become a decisive turning point on the journey towards implementing a framework that resolves the financing challenges related to future offshore networks within a sea basin.
↗ Recommendation for the following actions to be confirmed at the Hamburg Summit:
• continuing the reflection on offshore asset investment structuring options that would address both investors’ and TSOs’ constraints and interests;
• coordinating and cooperating with the different NRAs with the support of ACER to thoroughly discuss these topics and examine the details of their implementation;
• continuing the iterations with the EIB and other market players to design and ultimately implement innovative and optimal solutions;
• prioritising the forthcoming grid package of the European Commission and the place of offshore infrastructure as key enabler of affordable, clean electricity required for a competitive European industry;
• foreseeing sufficient financial means in the next Multiannual Financial Framework (MFF 43 of the European Commission to facilitate future offshore infrastructure financing.
↗ The work will be far from over after the Hamburg Summit. Continuous efforts from the various parties will be needed to ultimately secure project identification, cost sharing, structuring and financing to realise investment decisions for the required projects and overall value creation for society.
8. APPENDICES
Appendix 2: list of acronyms
Financing Offshore Interconnectors across the North Sea
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Elia Group has benefited from the support of F. Roques, C. Verhaeghe, S. Woerther & T. Cladière from Compass Lexecon FTI Consulting in preparing this White Paper. The views and opinions expressed herein are those of Elia Group only.
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