For Europe to successfully integrate the expected increase in renewable capacity, a key part of its energy transition, interconnections and storage should advance in parallel. However, the long planning, permitting and construction periods make it hard for interconnections to keep pace with fast-growing renewables. We expect some countries in western and southern Europe will likely fail on targeted capacity of interconnections by 2030. Nonetheless, security of supply across countries looks strong.

Because of the high investments required to develop interconnections across Europe, funding will be pivotal to successful execution. To date, European interconnections have been funded mostly through corporate financing by transmission system operators (TSOs). In more limited occasions, the financing has been done through project finance structures, usually requiring a higher level of visibility and stability on the construction and on the mechanisms that underpin the revenue generation.

Interconnections Are Crucial For Europe's Energy Transition

Electricity interconnections are key to integrating the expected increase in renewable capacity.  EU authorities expect renewable energy capacity will increase to 1,236 gigawatts (GW) by 2030 from 513 GW in 2021. This will require additional investments in internal power grids and cross-country interconnections. Interconnections are key for channeling the excess of renewable generated electricity at a certain hour and in a certain jurisdiction to another country where it is needed. This would benefit the country where the excess is generated, since that electricity would be used and not be curtailed; and benefit the country where the renewable electricity is received given it could replace more expensive generation.

On the pricing side, as renewable resources are exchanged across countries , electricity prices generally tend to reduce overall, and cross-country differences to abate. Hence interconnectors help meet national public policy aims around affordability and the EU-wide policy goal of unifying the internal market.

We believe flexibility is increasingly key to electrification before storage comes on stream large-scale.  This is because the extent and timing of local surpluses or deficits are increasingly hard to predict given generation challenges (e.g., in 2022 France's nuclear outage issues and droughts in southern Europe, which heavily hit hydro production). Moreover, some countries are retiring the more flexible generation: whether carbon-intensive like coal (across most of the continent by 2033, outside Poland); or low carbon-intensive like nuclear in Germany, Belgium (apart from two reactors until 2035), the U.K., and soon Spain. In this context, net export and import balances can also swing significantly.

Interconnections Have Developed At Different Paces Across Europe

Some European countries will likely fail on targeted capacity of interconnections.  Since 2019, after the EU guided for the 15% interconnection ratio, quite a few projects have started. There are at the moment 21 key electricity interconnector projects that are identified as projects of common interest (PCI), which benefit from accelerated permitting and funding. Additional projects are under development and we expect more in the coming years. Still, some countries will likely fail to reach the 15% goal (import interconnection capacity/total electricity installed capacity) by 2030. This will more likely happen in western and southern Europe, given that in northern and parts of eastern Europe, the development of interconnections is more advanced or the pace of renewables development is less advanced.

Stepping back, which objectives do Europe and each country pursue when strengthening interconnections?  Conflicting objectives may explain the various paces of interconnector buildup across Europe, and the challenge of reaching the 15% EU target for some countries. These conflicting objectives in our view include:

• Enhancing security of domestic supply (import perspective): Traditional exporters like France, Norway or Sweden may feel less need, from their own security point of view, for additional import connections, than for example traditional importers like Switzerland or Italy. For example, France has almost a third more export versus import capacity.
• Reducing risks of renewable generation curtailment (export perspective): Assuming generation in export markets is sufficiently decorrelated from domestic renewable generation, some countries are interested in more export (or storage) capacity to reduce outright losses of production.
• Different power prices across the EU: Hence some countries could benefit more than others from price convergence within the EU if a "single market" was created.

From a domestic supply security point of view, the ratio of import interconnection capacity/peak demand for electricity ("peak demand cover ratio") suggests Germany, the Netherlands, Portugal and Greece enjoy stronger interconnection capacity, at over 30% of national peak demand, than suggested by the ratio with total installed power capacity as denominator. The peak demand cover ratio effectively corrects for the large differences in load factors across technologies and Europe's increasingly diverse country mixes. Effectively, it factors in aggressive deployment of wind and solar in these four countries.

Looking at both metrics together, the impression remains that by 2030, the U.K., Spain, France and Poland will rely more than other European countries on their domestic electricity generation to meet demand, compared with the electricity imported via interconnections. For Spain and the U.K., this may correspond to the view that aggressive deployment of solar and offshore wind, respectively, should position both economies as easily self-sufficient. By contrast, Italy will continue to significantly depend on electricity imported via interconnections, notably to feed the heavily- populated and industrialized northern part of the country.

In our view, another critical factor for interconnection development are costs. These have historically been financed through the corporate balance sheets of transmission system operators (TSOs), which are already significant leveraged. In our view, broader financing options could help Europe meet its massive capex deployment needs on interconnections. In fact, we have already seen some interconnections financed by independent parties, through project finance.

Visibility On Revenues Have Facilitated A Few Project Finance Structures On Interconnection Projects In Europe

TSOs need to finance sharply increasing domestic capex while being already significantly leveraged– and this, even before the acceleration of the energy transition. Most rated companies have little financial buffer at the current ratings or stand-alone credit profiles (SACPs). An exception to the corporate TSOs financing of interconnections is for example ElecLink, the latest undersea power interconnector between the U.K. and France. This one is fully owned and financed by Getlink at the corporate level and is fully merchant.

Potential refinancings of existing interconnections or new developments could be funded through project-finance structures.  Under these structures, debt or equity raised for financing the construction and operating costs of an interconnection is done against future revenues. This revenue could come as regulatory exemptions from congestion rents that arise from electricity price differentials that are shared among cross border countries. It could also come from revenue derived under the relevant regulatory frameworks, that could be passed through the tariffs of end-consumers via TSOs.

Some interconnections on development have already been financed under the regulatory frameworks though project-finance structures owned by private independent firms.  This marks a change in pattern compared with the interconnections financed on TSO's balance sheets. For example, Greenlink, an interconnection between U.K. and Ireland, and NeuConnect, an interconnection between U.K. and Germany, both reached financial closure last year. On the U.K. and Ireland side, actual revenue received by the projects are subject to a floor and a cap mechanism. There is merchant exposure between the floor and cap values. The latter is calculated by reference to a regulatory asset base that ensures costs are recovered, while a rate of return is made on the investment.

On the examples mentioned previously, on the U.K. and Ireland side, following variations to the initial regulatory frameworks last year, the floor payments are made with reference to the actual debt-servicing costs. This is meant to assure lenders that the long-term cash flows produced by the asset will repay the debt when due.

Key watch points in the analysis of interconnections under corporate TSOs

These endeavors could over time add to rating pressure.  At a sector level, as European TSOs concurrently embark on multiple large projects, supply-chain and cost inflation issues become more acute, which in turn drives up project costs and financing needs.

As congestion income spiked in 2021 and 2022, we affirmed our ratings on TSOs.  In some cases a TSO's EBITDA doubled, a sure sign that physical flows are expanding and that price differences across zones may remain substantial--at least at the moment. This did not significantly affect our ratings on TSOs since we assess these as unexpected and only temporary boom in cash revenues (see "Three Northern European TSOs Ratings Affirmed As Congestion Income Is Broadly Credit Neutral; Outlooks Remain Stable," April 14, 2023).

TSO Interconnections construction debt is well-reflected in reported TSO debt and in our credit metrics.  We understand that under international financial reporting standard (IFRS) 11, rated European TSOs typically recognize their stakes in interconnectors (when they are located in a separate legal entity) as joint assets or operations. In other words, either as equity investees or pro-rata to their share. In the former case, the TSO's share of the link's debt is not consolidated, whereas it is in the latter. We do not have indications, based on rated TSOs, that the aggregate debt of equity-accounted interconnections, relative to considerable consolidated debts (for most TSOs, double-digit € billions) nor the share of EBITDA/cash flow related to these stakes are of particular significance.

Key watch points in the analysis of interconnections with project finance structures

Market risks during operations could be partially or fully mitigated under the regulatory framework.  We believe forecasting congestion rents is a complex exercise and could fully expose interconnection projects to market risks. These congestions rents arise from electricity price differentials based on the supply and demand of each country. In our view, electricity prices are subject to uncertainty, making them hard to forecast (see "EU's Proposed Energy Market Redesign Mitigates Merchant Risks And Accelerates Renewables," April 3, 2023). However, some of this market risk could be fully or partially mitigated by regulatory frameworks in both countries on each side of the interconnector. To determine the level of market risk, we would:

• analyze whether revenue is set with reference to a regulatory asset base, and
• whether it is complemented or not with congestion revenue; and
• to what extent parameters within the remuneration could change.

In our view, long construction periods and delays on interconnectors are a challenge for project finance.  The EU Agency for Cooperation of Energy Regulators (ACER) noted in its 2023 report on the progress of PCIs that the average actual or expected duration of 59 electricity transmission PCIs is about 10 years; this includes interconnectors and internal projects, from planning approval to commissioning. ACER also pointed that the timeline for about 29% of the PCI interconnection projects were delayed. Reasons for delays include permit-granting, tendering issues, or delays in construction work and deliveries of key equipment, among others.

The length, location (land or subsea), type of terrain and its condition determine the complexity of constructing and operating the project.  More-complex assets are most exposed to technical issues, delays in completion, and cost overruns. Unproven technology track records and design complexity and advancement could further increase construction complexity. Our analyses during the construction period are mainly focused on the ability of the project to be completed on time and on budget. In our view timing delays and cost overruns are common risks, especially in the context of an inflationary environment. Hence, understanding how projects manage the timing gaps between construction finish and initial debt repayments, who bears the risk for cost overruns, and if mitigants are built into the structures, are key to their credit quality.

Counterparties creditworthiness is generally not a constraining factor during operations but it could pose a constraint during construction.  We typically classify most construction counterparties as material and consider that the associated risks can't be fully mitigated. Therefore, the creditworthiness of the project during construction, if the exposure is deemed material, can range from no uplift to six notches above the contractor's creditworthiness. The uplift against the contractor's creditworthiness is determined by the field of alternative counterparties, complexity of the works, the amount of funds available to replace the counterparty if needed and the estimated cost to replace it. If revenue from the regulatory framework comes from the TSO, which passes such charges to end-consumers, then the credit quality of the TSO would generally not constrain the creditworthiness of the project during operations, as they are seen as merely intermediaries.

Foreign exchange could be a risk if not hedged or mitigated.  We would analyze if the debt payments are in the same currency of the cash flow generation in each country during operations and whether any mismatch exists during construction funding.

Harnessing The Power Of Common Work

We believe greater diversity of funding could facilitate energy transition in Europe. This could include using both public and private financing sources--and within the latter both corporate and project-level debt raisings--to better integrate power markets.

The common work on power integration cuts across energy systems and geographies. It requires close coordination on national generation, interconnections, and batteries, and between the EU and the U.K., Norway, and Switzerland. A smooth integration process could contain curtailment and leverage for TSOs. While Europe is well on its way, we still expect a lot of changes over this decade and next.

Digital design: Tim Hellyer

External Related Research And Sources

• "Consolidated report on the progress of electricity and gas Projects of Common Interest," ACER, June 2023
• "CRU21034 Greenlink Electricity Interconnector - Cap and Floor Regulatory Framework," Commission for Regulation of Utilities, September, 2021
• "Update to the provisional cap and floor level for the Greenlink Interconnector," UK government (Ofgem), August 2022
• "Decision on the Final Project Assessment of the NeuConnect interconnector to Germany," UK government (Ofgem), July 2022
• "NeuConnect – Interconnectors go large," PFI, December 2022

Our Related Research

• Utilities Handbook 2023: Western Europe Regulated Power, Oct. 18, 2023
• Europe's Utilities Face A Power Price Cliff From 2026, June 22, 2023
• Three Northern European TSOs Ratings Affirmed As Congestion Income Is Broadly Credit Neutral; Outlooks Remain Stable, April 14, 2023
• Selling Its German TSO Could Improve TenneT's Credit Quality, Depending On The Size And Use Of Proceeds, April 13, 2023
• Getlink Outlook Revised To Positive From Negative On Lower Leverage Expectations; 'BB-' Ratings Affirmed, April 11, 2023
• EU's Proposed Energy Market Redesign Mitigates Merchant Risks And Accelerates Renewables, April 3, 2023