Author: Csaba Polgár
Mandatory Feed-in tariff-based projects (KÁT and METÁR-KÁT) Pipelines – “The feast is over”
As a result of Hungary’s mandatory off-take subsidy scheme (KÁT and METÁR-KÁT regime) and the net metering-based household (largely rooftop) solar subsidy scheme (HMKEs), built-in and operating solar capacities have recently soared in Hungary. According to the latest communications by the Hungarian Energy Office, we estimate that utility-scale solar capacity is close to the 1.5 GW threshold, while HMKEs (rooftop installations below 50 kW) were at around 945 MW by the end of Q2 2021.
The overall share of solar power generation in the Hungarian electricity consumption mix was around 11% in August 2021 and there have been peak periods during which solar power plants generated 30-35% of Hungarian overall electricity production.
This statistical data also underlines our market experiences, by which the majority of KÁT and METÁR-KÁT-based developments have already been constructed and are in operation. While developers, investors and financiers have all been focusing on these projects in the past 3-4 years, these project pipelines are slowly drying up.
The METAR Tender - Seemingly, a success story, but will it have a happy end?
With the available ready-to-build KÁT and METÁR-KÁT portfolio numbers falling, a fair share of the solar development market has been focusing on developing projects for the METÁR-tender, a third round of which is currently in progress. Initial tender opening data shows that winning prices are likely to continue dropping. For smaller-scale projects (up to 1 MW (AC), the best-offered best price was HUF 18.5,- / kWh (EUR 52.8 / MWh), while for larger projects (up to 20 MW (AC)), the best-offered price came at HUF 15.73,- / kWh (EUR 44.9,- / MWh).
While these likely winning prices may seem fairly normal from a European perspective, a number of market participants articulated doubts as to whether (i) projects at these off-take prices are financially viable and (ii) construction project financing will be made available at reasonable terms and conditions by commercial banks, given certain country-specific circumstances and risks that are to be taken into account. Key challenges that need to be overcome are briefly summarised as follows1:
The short duration of the support period: financing banks prefer shorter loan tenors than the support period in order to ensure that there is sufficient time to restructure the loan if the need arises for any reason.
Market risk: The low, capped offtake prices fixed for the whole offtake period (except CPI minus 1%) result in lower revenues and weaker income stability, thus making revenue profiles less attractive over the financing period. It will also put pressure on expected DSCR values and may result in lower leverage, thus higher initial equity needs. It is also to be noted that the offtake price is fixed, therefore any positive difference that may arise between the calculated market reference price and the winning tender price may need to be (re)paid to the TSO.
Balancing cost exposure: generators under the METÁR-schemes must bear full balancing costs arising due to any deviation from production schedules. This means an unpredictable additional cost element in the models. In Hungary, this cost element can be multiple times that what Western European investors are used to – according to MAVIR Zrt., the Hungarian transmission system operator, the average balancing cost of solar power plants was around HUF 3.5,- / kWh in 2020. Certain recent market developments resulted in even higher short-term balancing costs, necessitating intervention by the regulator.
Collateral uncertainties for projects built on foreign land: property law treatment of renewable power plants is not uniform across the country which may have negative consequences on valuation and enforcement of collateral. This may change with the implementation of the new Act on Land Registries, entering into effect in early 2023.
Short-term exchange rate risk: given that (i) majority of the project CAPEX will be incurred in EUR, while (ii) project cash flows will be capped in HUF over the lifetime of the project, this may represent a short term exchange risk during financing, treatment of which may represent additional costs.
Commercial banks are actively engaged in discussions with potential borrowers to overcome these issues and it remains to be seen what percentage of METÁR-tender based projects will reach successful financial closing and the targeted commercial operation date.
Corporate PPAs - What everybody is talking about, yet nobody has seen materialize
As a revenue alternative to a feed-in tariff system granted by regulation or in the absence of such a system, the RES investor may consider entering into a long-term corporate power purchase agreement (CPPA) with a private third party. This can be a corporate power consumer or a utility or trading house. Such a CPPA may also be necessary within a RES support system that is based on green certificates and does not pay for power generation as such, as is the case, for example, in the Scandinavian markets with a renewable quota model.
In many power markets, including the USA, Sweden, Norway, Spain and Great Britain, CPPAs already have become a standard instrument for securing revenues for RES assets, for which investors, financiers, electricity traders and some electricity consumers already have experience. Despite the availability of general PPA templates, for example from EFET (or ISDA for financial CPPAs), there is no generally applicable standard CPPA in EU power markets, but a large number of possible design variants exist. Those details of a CPPA determine the opportunity-risk profile of the contract for the supplier and the off-taker individually.
Basically, CPPAs can be divided into contracts that either have no direct link to a specific generation asset (financial or virtual CPPA) or CPPAs that are linked to the generation of a specific asset (physical or asset-backed CPPA). Financial/virtual CPPAs are settled against a specified price index (e.g. a wholesale power price or capture price index), which defines it as a derivative contract. Physical CPPAs (so-called “direct wire”), by contrast, involve the physical delivery of power into the offtaker’s balancing group. Both types of CPPAs typically include the delivery of guarantees of origin (GOOs), a phenomenon which we will also see more often in Hungary in the coming years.
In addition, a distinction can be made between CPPAs that are closed for direct delivery of power to an end-user (a “typical” corporate PPA, normally with an industrial user), possibly supplemented by regulations for the necessary residual electricity procurement, and those CPPAs that do not deliver electricity directly to a consumer but to an intermediary, e.g. a trading company (utility PPA). The intermediary will then sell the power from that utility PPA to the wholesale markets and/or structure products for its customers to consume that power (partially). The classification of (corporate) CPPAs and utility PPAs is illustrated in the following graph.
Corporate PPA – Basic Contractual Scheme2
Generally, in CEE and SEE, sleeved CPPAs do not have any preferential legal regime, no special tariff regimes for using public grid infrastructure have been implemented and (commercial) balancing is required. Also, no preferential legal regime has been implemented for behind-the-meter (physical) CPPAs, which means that licensing requirements are not much less stringent even if the project is not connected to the grid.
By signing a CPPA, the operator of a RES project (as well as the investor and/or bank behind that project) enter a long-term revenue scheme that provides a price known in advance (or at least a price corridor/formulae). The CPPA can be designed in a way that is basically comparable to a regulated feed-in tariff with regard to the fixing of a long-term level of remuneration. However, some relevant differences remain, which can turn out to be advantages and disadvantages compared to a remuneration scheme provided by the state.
It is advantageous that the contracting parties of a CPPA are largely free to design the contract. For example, the price and quality of the electricity and the duties around structuring and marketing can be individually agreed upon. This sets such an individual agreement apart from the specified procedures for regulated subsidies, which must be met by the RES operators.
However, even if CPPAs provide a certain hedge against the price risk inherent in pure spot marketing (merchant risk), market-related risks cannot be fully eliminated. For example, there remains uncertainty regarding revenues after the expiration of the CPPA and for volumes that might be generated outside the CPPA. Also, negative prices and deviations in generation volume, as well as asset availability, might pose risks not covered fully by such a contract. In addition, any CPPA is subject to the underlying contractual/credit risks, since the partners are private entities that always have a risk of default.
When comparing these advantages and disadvantages of CPPAs and taking into account the exposures inherent in the tender-based METAR system in Hungary, the question ultimately arises as to how attractive a METAR tender-based project is in comparison with a CPPA. Answering this question is key to selecting the most suitable revenue option for any RES asset in Hungary. Lenders will evaluate the CPPA of a RES project in detail as a central revenue element and set minimum requirements, for example, to secure debt service coverage. In this context, power price forecasting and scenario analysis are usually used, which quantify the effects of future electricity market developments on CPPA price and project economics.
So far, long-term electricity sales contracts have played a limited role in Hungary and in wider CEE/SEE power markets. However, this is expected to change in the future if RES generation costs continue to decrease and power prices continue to increase and make CPPAs increasingly viable.
It is also to be noted that the majority of the risks and exposures listed above for tender-based METÁR-projects are also applicable for CPPAs - except the FX risk, given that CPPA cash flows will be denominated in euros. Depending on the selected price formulae, CPPAs may also be more accommodating with regard to future price increases, in contrast with tender-based METÁR-projects where cash flow is capped.
An additional cost element for CPPAs that needs to be taken into account is high-voltage grid access reservation costs. Introduced by MAVIR Zrt. at the beginning of September 2021, developers of projects that intend to connect to the high voltage transmission system operated by MAVIR Zrt, will be required to pay HUF 4,500,000,- / MVA (cc EUR 13,000 / MVA) grid access reservation fee to MAVIR in a transitionary period until 31 December 2021.
Auction rules for high and medium-voltage grid access reservations are currently being worked out by the TSO and the DSOs. Market expectations are that grid access reservation fees will remain the same and ranking between applicants will be based on a set of criteria, including - but not limited to - (i) whether the projects are subsidized in any way and (ii) whether the developers intend to use any reduction from the grid access costs.
1 Financing the Hungarian Renewable Energy Sector, National Bank of Hungary, December 2020
2 Source: RENEWABLE ENERGY INVESTMENT GUIDE, CENTRAL EASTERN & SOUTHEAST EUROPE, Windpower, Large-scale Solar, Electrification of District Heating (PONTES the CEE Lawyers • Karanovic & Partners • enervis energy advisors), 2021