1. What damages are available for COD delays financial CPPAs?
Whether delays in achieving the stated commercial operation date (COD) for power generation projects give rise to claims for losses tends to be one of the most heavily negotiated aspects of CPPA contracts.
This issue can arise in respect of hedged volumes, where the offtaker has hedged a proportion of the power volume they expect to receive from the generator. If the generator is late supplying the energy, the offtaker may expect to be compensated for losses on those hedges.
The outcome of these negotiations largely depends on the relative bargaining power and financial bandwidth of the parties involved in the CPPA.
Where the generating asset is relatively small, the supplier is unlikely to have the resources to cover the offtaker's losses.
With larger projects, it is possible to come to an arrangement to cover some of the losses caused by a COD delay. However, very few projects can sustain a full typical hedging loss.
In this context, the focus tends to be on mitigation of losses and ensuring the COD notification process is as finely tuned possible. A risk-sharing balance needs to be struck in the CPPA contract, usually through adapted liability and damages thresholds.
2. What are the trends in the type of entity signing CPPAs with corporates?
The supply side of the CPPA market continues to be dominated by renewable energy developers and investors.
Recently, there has been a tendency by parties financing the developer/portfolio of developers to take charge of contract negotiations. Investors are becoming involved earlier in the process, to fully understand the risks and maximise returns.
To date, European utilities have tended not to get involved in CPPA projects, however utilities from outside Europe have started to come into the market.
3. What is the role of aggregators in CPPAs?
To date, the main innovation in the CPPA market has been the rise of aggregating parties, both on the generation and offtaker side.
On the generation side, aggregators take on bundles of renewable power generation and associated risks from several projects and then contract with buyers on the generators' behalf. These aggregation structures are starting to assume an increasingly prominent role in Europe's CPPA market.
On the offtakers' side, aggregation is becoming more common in the context of large energy generation projects where electricity output exceeds the demand of a single buyer.
Some parties will approach CPPA deals as buying consortia, which makes the CPPA contract more complicated and in some cases may not be permitted by the regulator; however, such deals have been successfully negotiated and are becoming more prevalent.
Developers are generally comfortable signing a number of CPPAs for one project but may prefer to stack separate deals, rather than take on bundles of related buyers under a single CPPA. Developers will also not usually give buyers a choice about which other offtakers are involved (although the multi-party offtake structure will form part of the contract negotiations).
Aggregators' involvement tends to be curtailed by the fact that corporates typically want to limit the number of intermediaries in their energy supply chain, preferring (to the extent that this is possible in electricity markets) to enter straight contractual relationships with generators.
On the flip side, exclusivity in CPPAs with single buyers seeking to take 100% of the output of a generation project is a common request but not always acceptable to the developer/generator.
4. Is there scope for third parties to take on balancing and shape risk for CPPAs?
In some markets, this is an option and there has been a trend towards appointing third parties set up to manage these risks. These parties can be appointed by either the seller or the buyer.
Some large CPPA project developers will manage balancing and shape risk themselves, if they have a trading house function as part of their business model.
5. What damages are available for corporates taking construction risk in financial CPPAs?
CPPA contracts need flexibility to deal with, and provide remedies for, a range of construction risks, such as delays, cost overruns and insolvency of suppliers.
Corporates who take on these risks want them balanced by certain rights in the event that these risks are realised.
Corporates seeking additionality (i.e., financial support from the EU earmarked for beneficial projects that would not have gone ahead without the corporate's involvement) have to come to some sort of risk-sharing arrangement to be able to say that additionality principles have been met.
As these are not simply financial transactions, but projects which claim to offer wider benefits, most corporates appreciate that a middle ground has to be reached.
6. What role can brokers play in this sector?
Brokers can play a very active role in Europe's CPPA sector. There is a clear need for parties able to intermediate between corporates and generators.
Matching parties' objectives across the divide can be tricky, especially as there is no standard form agreement yet and risk allocation is not settled.
7. Why has there been so little progress towards the adoption of pro forma CPPA contracts in Europe?
It remains very difficult to standardise the risk profile a corporate is prepared to take in a CPPA, as every business has a different set of risk requirements.
Generators and corporates relish the freedom to draw up bespoke agreements, in contrast to rigid contracts under the traditional utility supply model.
Regulatory barriers have also been a brake on the development of standard contracts. RED II (the EU's recast Renewable Energy Directive) should force national regulatory authorities to align their approach to CPPAs across the EU, which should help with the development of standard documents.
There are however major differences between the location and size of power generation projects, as well as considerable variations in the kinds of technologies used, so it is difficult to produce standard documents that cater to these factors.
That said, some standard contract terms are starting to emerge so the market is edging towards limited standardisation, which should help parties new to the CPPA market.
8. How can smaller corporates enter the CPPA market?
The CPPA market, while still developing, is geared towards large corporates at present.
In addition to transaction costs, the main problem for smaller companies is normally that they are not sufficiently creditworthy for banks to finance the power generation project.
Depending on the nature and size of the project and the length of the CPPA, it is not impossible for smaller corporates to enter these transactions, but it makes the task of the developer harder if they require bank financing.
Smaller companies have the option to use a private wire arrangement, which reduces the number of regulatory hurdles and associated costs involved in signing a CPPA. Standardised documentation will also help bring costs down.
Smaller companies can also participate in aggregated purchasing arrangements, as long as they are mindful of relevant competition law restrictions (see question 3 regarding the role of aggregators – this approach is starting to develop in some countries in Europe, but has so far proved quite tricky to implement).
9. Aside from buyer creditworthiness, what are the key risk aspects of CPPAs from a bankability perspective?
How risks are allocated between the energy generator and the offtaker is the main consideration for the bankability of CPPAs.
Offtakers are increasingly looking to structure deals in ways that reduce the level of risk they have historically assumed – through sleeved CPPAs; by involving third parties; or requiring generators to accept more risk than they have in the past, which can prove problematic from a financing perspective.
The basics for both sides are counterparty credit risk and credit support. Counterparty credit risk is not static and will inevitably evolve over time (as the Covid-19 pandemic has illustrated very clearly).
When dealing with offtakers that may not be at the highest quality end of the credit spectrum, developers and funders should consider the counterparty's ability to provide additional credit support and/or provisions to sell power into the market in case there is any deterioration of offtaker's financial position.
Energy pricing is an obvious factor from a bankability perspective and duration of the CPPA is key, with most funders preferring tenors in the 10-15 year bracket to shorter or longer tenors.
Provisions around termination conditions are also key. From generator's perspective, it is preferable to avoid giving offtakers exit routes for convenience reasons and where exits are due to breach of contract, it is essential to establish what remedies/penalties are available to each party in this instance.
10. How much appetite is there for short duration CPPAs, especially for assets approaching the end of their useful lives?
This issue is starting to emerge across Europe, as national renewable support schemes expire and fresh waves of existing generation capacity become available in the market every year.
Corporates considering CPPAs with legacy generators do not have to worry about bank financing requirements to construct new projects, and the shorter tenor of the deals reduces market exposure.
There is however a technical aspect to these deals, in that parties are required to obtain a technical report confirming assets are still fit for production and for how long. With the future of assets in mind, repowerings and refurbishments are underway at a number legacy projects across Europe.
The option of short duration CPPAs may also arise the event of the failure of a long-term offtaker before the tenor of their CPPA has expired. The impact of this on the generator will depend partly on whether the CPPA is virtual or physical, and on how many offtakers there are for the project's output.
While long-term revenue certainty is essential to funding the construction of a project, if the buyer drops out for any reason it is usually possible to replace them with another offtaker (although companies seeking additionality are less likely to contract with a project originally funded by somebody else).
11. Is there demand for cross-border CPPAs?
There is some interest in cross-border deals, however the complexity and cost of overcoming regulatory hurdles for financially settled CPPAs that encompass multiple generators and/or offtakers is increased when crossing international boundaries.
This aspect of the CPPA market is still developing and barriers to cross-border CPPAs should be reduced by the implementation of RED II.
One outlier is Scandinavia, which is unique with regard to its large number of hydro installations and is well set up for cross border CPPAs. Scandinavian countries are relatively unusual in having large amounts of generation and comparatively little demand, giving corporates the opportunity to trade electricity received under CPPAs in international markets.
Assuming regulatory hurdles are lowered or removed, demand for cross-border CPPAs is likely to be driven by the fluidity of the Guarantees of Origin (GoOs) market.
At present, this is hindered by sharp discrepancies between the prices of GoOs in different jurisdictions.
12. What criteria need to be met for a long-term CPPA to be considered as a lease?
It is highly recommended that offtakers seek specialist advice on the accounting treatment of a CPPA.
Lawyers can help translate this analysis into the CPPA contract. In broad terms, the accounting treatment of CPPAs is determined according to who is the effective economic operator of the energy generation asset.
Corporates wishing to avoid being deemed to be in economic control of the asset need to ensure this is reflected in what the contract states regarding ownership and operation of the assets, including provisions for grid access and notifying maintenance.
If a corporate is judged to be the operator of the generating asset, this brings with it additional duties that many corporates will want to avoid.
13. If public authorities or state-backed companies decide to use CPPAs, what features of these deals need to moderated by regulators?
If the offtaker is public, the developer needs to look at the general and specific regulatory requirements for public procurement in that jurisdiction to ensure they can comply with these rules.
Public procurement processes tend to be the main barriers to CPPAs in this area, as sometimes public counterparties will come to market without a clear view of whether the market can meet their specific requirements (for example, some will require the power generation project to be "local", which can be highly restrictive depending on their definition of what is local).
Once the parties are over the public procurement hurdle, the risks and risk appetite involved in dealing with public offtakers are broadly the same as they are with a private offtaker. Various public bodies, including city authorities and universities, are increasingly participating in the CPPA market.
One advantage for developers of dealing with a public offtaker is that it is usually easier to satisfy banks regarding credit support, as public bodies typically have much stronger credit standings than 'normal' corporate offtakers.
14. What opportunities are there for energy storage technologies in Europe's CPPA market?
Battery storage is very useful when it comes to dealing with intermittency of renewable energy generation.
The two main barriers for battery storage are: first, that the cost of batteries is still very high; and second, regulatory regimes generally have not caught up with the role batteries can play in power markets or how they should be treated in law.
In both cases, it is likely to be just a matter of time until these barriers are reduced and ultimately removed.
Some projects are starting to combine energy generation with battery storage and it will be interesting to see how these models fare in the market.
In addition to batteries, there has been recent interest in the role hydrogen could potentially play in energy storage.
With the development of large offshore windfarms, price volatility is likely to increase and with it negative pricing.
Anything that can divert energy from the grid and store it in a way that keeps its value and helps provide pricing certainty to the market is going to be very important for renewables in general and for CPPAs.
15. Are discounts to market prices available in some CPPAs?
This will largely depend on the power market context. Generators (and regulators) prefer deals at market prices, but demand for discounts is increasing, particularly in the Netherlands where GoOs have some of the highest values in Europe.
Developers are usually willing to discuss discounts and, depending on market conditions and tenor, may come to an arrangement.
Hybrid structures that have both fixed and floating price elements are also possible and tend to be more acceptable to generators and finance providers.
Larger developers will be more flexible about this than smaller developers, but generally CPPAs are about certainty of energy prices and eliminating the risk of fluctuation, rather than achieving discounts.
16. What factors will chiefly determine the development of the CPPA market in Europe?
Tariff and regulatory issues will principally determine which markets enable CPPAs to proliferate and thrive.
It will also depend on how risk sharing arrangements evolve, and on the renewable potential of different countries and how well their local networks function to facilitate CPPAs.
17. How prevalent are take or pay obligations in CPPAs?
Most CPPAs have 'a take if generated' obligation. This provides that, if the contracted source of power is generating, that power will be taken by the licensed supplier and, by extension, by the corporate.
This is practically necessary because power will flow onto the system from the generator in any event.
In some jurisdictions, it may be possible to sell on excess power that is not required by the corporate to the licensed supplier/grid through net-metering arrangements.
This is not a classic take or pay agreement and the financial consequences of over-generation tend to fall on the corporate, whereas failing to achieve declared generation volumes sits with the generator (exposing them to imbalance pricing).
Some CPPAs impose no minimum volume on the generator, only an obligation to generate when it can, which is far more accommodating of intermittent renewable technologies.
This means corporates need to manage the supply profile coming from the generator within their own mini energy supply portfolio. While this is an onerous obligation, in the long term it could provide corporates with lucrative opportunities to supply energy management services back to the grid.
These FAQs were answered collectively by Fieldfisher's CPPA specialists, Daniel Marhewka, Lis Blunsdon and David Haverbeke. For more information on our CPPA expertise, please contact one of the authors or download our thought leadership report and industry survey "Think GIG: The rise of corporate PPAs".
Further useful information for parties new to CPPAs can be found in the EU's RE-Source Buyers’ Toolkit.
For more information on the effects of Covid-19 on CPPAs, read our article "Covid-19: Ill wind or sunshine after rain for corporate PPAs?"
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