/>iAs we discussed in Part 1 of this series of Articles, there is likely to be significant future increased demand for low loss, long-distance interconnectors. While the concept of transmitting large amounts of energy with relatively low losses over long distances (e.g., from solar farms in North Africa to Europe) might be attractive in principle, significant political, economic and legal challenges face potential investors and lenders, particularly in developing jurisdictions.
We will explore below the key models for structuring and financing transmission infrastructure, including the integrated grid model, merchant investment and independent power transmission (IPT) projects.
Integrated grid model
Power transmission has traditionally been considered a natural monopoly. Globally, transmission assets are most commonly owned and/or operated by a transmission utility as part of an integrated grid. The transmission utility may be state-owned, privately owned or operating under a concession granted by the government. Under this model, investment in transmission lines is typically financed using the utility’s balance sheet and recovered through a regulated tariff. This tariff is charged to consumers as part of the overall retail electricity price. However, in countries where the transmission infrastructure is publicly owned, this model can strain public finances, particularly when governments and state-owned utilities face fiscal constraints. This often results in underinvestment in transmission infrastructure and delays to necessary upgrades.
Merchant investment
The merchant investment model is a privately funded approach to developing transmission lines where revenue is primarily derived from price differentials between two markets or zones creating arbitrage opportunities. This makes it particularly suited for cross-border interconnections or countries with an unbundled power market and multiple wholesale price zones. Many interconnection projects[1] to date have used the merchant investment model in which the investor builds and operates a transmission line. This model is typically for standalone assets—either a single line or a bundle of lines. A technical requirement for the merchant model is the ability to control and measure electricity flows, as the operator profits from directing power where it is most valuable. As such, this model is more suited for DC lines.
However, the revenue uncertainty of this model makes it more difficult to finance using project finance techniques, which require predictable revenue streams. To mitigate this risk, governments have sometimes intervened to support merchant lines. One example is the NeuConnect interconnector between the UK and Germany, which operates under a cap and floor mechanism. This reduces revenue uncertainty, improving bankability while still allowing private investors to benefit from price differentials. See below for further discussion on the NeuConnect project.
The merchant investment model is not generally viable in countries without liberalised wholesale electricity markets. This is the case for many emerging markets with a vertically integrated, state-owned power sector. The lack of a competitive wholesale market and transparent, market-based price signals limits the potential for price differentials and reduces opportunities for price arbitrage between different markets or zones that are essential for a merchant line’s revenue model.
IPT Projects
Another model which can facilitate private investment in transmission assets is independent power transmission (IPT). In essence, it involves the government (or the state-owned utility) tendering a long-term contract whereby the IPT (the winning bidder) will be responsible for building and operating a transmission line in exchange for contractually defined payments dependent upon the availability of the line.
A recent example of an IPT project, although not HVDC, is the 400 kV Lessos–Loosuk and 220 kV Kisumu–Musaga transmission lines in Kenya. This project involves the development, financing and construction of the transmission lines under a public-private partnership framework by Africa50 and the Power Grid Corporation of India Limited. The project is set to become Kenya’s first IPT and a pioneering example in Africa.
IPT projects have been adopted in many countries, albeit mostly for in-country transmission. Adopting the same model for international interconnectors is likely to be more complex, not least due to the need to coordinate between the governments of the relevant countries.
Also in the African context, the Côte d’Ivoire-Liberia-Sierra Leone-Guinea (CLSG) interconnection project, financed by the AfDB, EIB, KfW, World Bank and its member countries and completed and commissioned in 2021, illustrates one way forward. It involved the construction of a 1,300 km long 225 kV AC transmission line and associated substations connecting four participating countries’ energy systems into the WAPP. The project was implemented through a regional special purpose company (Transco), jointly owned by the national utilities of those countries, and responsible for the financing, construction, ownership and operation of the project assets.
To encourage the use of the CLSG transmission line, an open access policy was adopted. Power purchase agreements (PPAs) were signed between Côte d’Ivoire’s national utility and those of the other three countries, with each also entering into a transmission service agreement with Transco. The transmission tariff was set using the “postage-stamp” methodology rather than an availability-based tariff, so that transmission costs are effectively charged to the power purchasers based on their relative shares of trade through the transmission line. To mitigate the risk of a funding shortfall owing to low trading volumes, Transco’s shareholders agreed to cover any shortfall from trading revenue. This pricing methodology ensures cost recovery whilst facilitating trade through the transmission line.
While the CLSG project structure does not involve any private investment, in principle a similar structure could be adopted to implement the IPT model; for example, by replacing government-owned shareholders of Transco with private sector sponsors.
To a limited extent this was the structure adopted by the Central American Electricity Interconnection System (SIEPAC) which was taken into account in structuring the CLSG project. The SIEPAC transmission company (EPR),owns the 1,793 km interconnector (230 kV) linking the power grids of six Central American countries. EPR is owned by eight national utilities or transmission companies together with a private company (ENDESA of Spain) which is responsible for managing EPR. During the project design stage, the option of relying entirely on private investment was considered, but it was ultimately decided that there might not be sufficient interest from the private sector due to perceived project risks and the natural monopoly nature of transmission. Nevertheless, there seems to be no reason why, through proper risk management and with adequate financial incentives, such a structure could not be adopted with entirely private ownership.
Regulatory and legal challenges
In many developing countries, the electricity sector remains vertically integrated with monopoly networks. Although full “unbundling” is not a necessary pre-condition for IPT projects, existing legislation and regulation will need to be reviewed and may need to be revised to enable an IPT project to operate alongside the national utility. In particular, the grid code will likely need to be modified to include operating procedures and principles. In the context of an interconnection project, this will need to be done for each country to which it connects and could be cumbersome and result in a long development period.
This challenge was highlighted by the North Core Interconnector Project (a 330 kV AC transmission line connecting Nigeria, Niger, Benin and Burkina Faso). According to the ECOWAS Master Plan, the SPV structure adopted in the CLSG project was originally considered for the North Core project but was ultimately not adopted owing to concerns over the delay that could be caused by the need to make adjustments to national legal frameworks.
In civil law jurisdictions, specific enabling legislation may also be required to implement interconnector projects. Conflicts of law and policy questions may also arise where cross-border agreements are entered into; for example, some provisions of law may have mandatory application in certain jurisdictions; and where state-owned entities are involved, legal or policy requirements may dictate a choice of a particular governing law or dispute resolution arrangement.
“Project-on-Project” risk
For a cross-border interconnector, separate SPVs (or “sub-projects”) may be established in each relevant jurisdiction. This approach offers several benefits, including ring-fencing national risks, aligning with local licensing requirements and facilitating construction delivery management. However, it also introduces a high degree of interdependency, as each project segment must be successfully completed for the overall project to function. This creates challenges in managing interface risks, project delivery alignment and providing certainty for stakeholders in each sub-project that the other sub-project(s) will be delivered as planned.
To address these risks, risk allocation between project sponsors and other contract parties must be carefully calibrated to ensure that risk levels are acceptable to all stakeholders while achieving the bankability of the project.
Financial viability
The CLSG project provided an example of how transmission tariffs can be set to meet minimum revenue requirements. Investors, however, need confidence that contractual payments will be received from the transmission line users, which are likely to be national utilities, who may be in poor financial health. Many developing countries have experience in addressing this question in the context of independent power projects (IPPs), which may provide valuable lessons for developing IPT projects. For example, credit support may be provided through the use of escrow accounts to prioritise payments to private sector market participants. Where this is insufficient, governments may provide sovereign guarantees (or other government support) for payment obligations to IPTs. Additional security may also be provided by development finance institutions (DFIs).
EPC contract questions
The structuring of an interconnector project may present challenges in negotiating an EPC contract. For example, where multiple procuring parties decide to use a single entity (e.g., a special purpose vehicle company) to act as the employer under an EPC contract, with assets transferred to them as third party owners, particular concerns may arise for both the procuring parties and the contractor under the EPC contract, including in respect of risk allocation, indemnities, insurance and ensuring that the asset owners obtain the full benefit of rights under the EPC contract whilst the EPC contractor maintains adequate recourse against parties of sufficient financial substance; and bespoke amendments are likely to be required to standard construction contracts, e.g., those based on FIDIC forms.
The European interconnector experience and project revenue support regimes
The European market offers examples of successful privately financed submarine HVDC interconnector projects, underpinned by revenue support arrangements to make investment sufficiently attractive to sponsors and risks more palatable to prospective lenders.
The NeuConnect interconnector will create the first direct power link between Germany and the UK, two of Europe’s largest energy markets, and allowing trading of electricity between them. Construction of the pair of 725 km long terrestrial and subsea 525 kV HVDC cables is in progress and will create 1.4 GW of transmission bi-directional transmission capacity, sufficient to power 1.5 million homes.
The project has a capital cost of around £2.4 billion and achieved financial close in 2022, involving Meridiam, Allianz Capital Partners, Kansai Electric Power Grid and TEPCO Power Grid as sponsors and a consortium of more than 20 major banks and financial institutions as lenders (including EIB and JBIC). NeuConnect Britain Ltd. (NBL), incorporated in England, is responsible for all aspects of the project in the UK (as well as construction works in Dutch waters) while NeuConnect Deutschland GmbH & Co. KG, incorporated in Germany, is responsible for all aspects of the project in Germany.
NeuConnect states that it will facilitate non-discriminatory, fair and transparent access to capacity through a range of standardised auctioned products, detailed in Access Rules which are compliant with relevant regulations. The project however takes limited merchant risk as its revenues are underpinned by a 25 year cap and floor regime in the UK, which broadly covers 50% of project costs and 50% of the total revenues earned by the interconnector. Under this scheme, the project is entitled to a minimum revenue (the “notional floor”) but in return agrees to a defined cap above which all revenues will in effect be paid back to the electricity consumers. This mechanism is intended to ensure that end-consumers obtain value for money by capping investment returns if the project outperforms revenue expectations in exchange for the protection granted through the floor, with an element of commercial risk for the project in between, thereby providing an incentive for private investors to develop interconnector projects, as compared with other regimes where revenues are purely regulated and return on equity is generally insufficiently attractive.
Ofgem approved regulatory changes to the pre-existing UK cap and floor regime to allow the project to go ahead. Meanwhile, in Germany, legislative change was needed to accommodate the project. Pre-existing German legislation (the EnWG law) did not cover interconnector assets that were not owned by a German TSO, requiring an amendment to extend the German StromNEV regime to NeuConnect. Under this regime, the project receives statutory revenues based on its assessed cost base, including depreciation of the RAB and return on such RAB (differentiated between equity and debt). NeuConnect receives its regulatory revenues from TenneT TSO GmbH, the local transmission system operator in northern Germany.
In both jurisdictions, it is understood that the revenue support arrangements are adjusted based on the level of availability of the interconnector in order to incentivise the project to maximise availability.
Threats
Recent geopolitical events have highlighted the vulnerability of subsea data cables, gas pipelines and submarine electricity cables to deliberate sabotage or damage from ships’ anchors. It seems unlikely that insurance will be available for such risks and unless governments are willing to underwrite remediation costs and lost revenues, future private investment in submarine HVDC cables may be thrown into doubt in vulnerable areas of the world.
Conclusions
While AC power transmission and distribution systems are likely to remain for many years to come and may never be entirely replaced, HVDC is certain to play a vital role in providing backbone infrastructure to support a low carbon future. Investors, lenders, utilities, regulators and policymakers alike will be taking a keen interest in this exciting technology.
Endnote
[1] Outside Europe, where interconnectors are subject to regulation unless they are formally exempted. Even in the latter case, conditions may be placed on the exemption, such as an overall IRR cap.
