As European energy markets contend with unprecedented challenges – cannibalisation and negative price risk above all – clean energy players are stepping up to move the market forwards.
Developers like Nadara are bringing sophisticated, hybrid PPA solutions to the table that directly address market pressures, and supporting buyers to meet their renewable energy goals without shouldering unwanted risk.
We sat down with Maria Mura, Head of Origination at Nadara, to learn how they are overcoming current market hurdles and getting deals done.
Nadara is a Next-Gen Independent Power Producer (IPP+) that develops, owns and operates renewable energy sites across Europe and the US. Nadara’s technologies include over 4 GW of installed onshore wind, solar photovoltaic, biomass and energy storage, and IPP+ services that encompass energy optimisation, trading, and flexibility solutions that maximise value across the energy chain, support energy security and create long-term value that powers homes, businesses, and change.
Maria Mura is Head of Origination at Nadara, where she leads the company's commercial strategy across multiple European markets. With more than a decade of experience in renewable energy, she oversees revenue and offtake strategies for a portfolio of more than 4 GW of operating assets and an 18 GW development pipeline, helping shape the commercial future of wind, solar, battery energy storage, and hybrid projects across Europe.
LevelTen: Appetite for hybrid PPAs is growing quickly across many European markets, especially those in which solar cannibalisation is rising. How does your team think about incorporating the costs and benefits of storage into the price of a hybrid PPA that combines solar or wind with storage?
Maria: BESS has rapidly become central to PPA discussions, particularly in solar-driven markets where cannibalisation effects are increasingly pronounced. The traditional 10-year, pay-as-produced, fixed-price PPA structure is gradually evolving toward more sophisticated, multi-technology solutions.
From our perspective, incorporating storage into a solar or wind PPA pricing framework requires a holistic assessment of both value creation and cost allocation. On the value side, BESS enables profile shaping, capturing intraday price spreads, and mitigating exposure to negative or zero-price hours – an increasingly frequent occurrence in several European markets. Additionally, storage can reduce curtailment risk, whether driven by grid congestion or local node constraints, which is particularly relevant in markets such as Iberia. These benefits translate into more stable and predictable delivery profiles, which are highly valued by offtakers.
Incorporating storage into a solar or wind PPA pricing framework requires a holistic assessment of both value creation and cost allocation
From a pricing standpoint, the cost of storage must be balanced against these incremental revenues and risk reductions. This often leads to more complex PPA structures, including shaped profiles, floor-and-ceiling mechanisms, or hybrid pricing models that explicitly recognise the optionality provided by storage. In many cases, the value of BESS is not fully monetised through a simple fixed price, but rather through enhanced contract flexibility and risk-sharing arrangements between generators and offtakers.
Let’s go beyond batteries. What role will PPAs for combined solar and wind projects (what we call “combo” here at LevelTen) play alongside hybrid PPAs that incorporate BESS capabilities?
Looking ahead, we see complementary roles for both hybrid (generation + BESS) PPAs and “combo” PPAs that aggregate solar and wind assets. Solar+wind combinations naturally provide profile diversification due to their differing production patterns, reducing volatility and cannibalisation. As such, combo PPAs can offer a cost-efficient pathway to achieve partial profile smoothing.
However, hybrid PPAs incorporating BESS will play a critical role where deeper profile shaping, firming capabilities, or intraday optimisation are required, particularly for corporate buyers seeking higher levels of price stability or alignment with consumption profiles. Ultimately, the market is moving toward a spectrum of solutions, where standalone, combo, and hybrid PPAs coexist, and the optimal structure depends on the specific risk appetite, load profile, and return requirements of the counterparties involved.
More markets across Europe have been experiencing negative wholesale electricity prices with greater frequency. How is your team thinking about accounting for negative-price risks? Which contractual tools do you see as best suited for securing a fair distribution of risk sharing amongst PPA counterparties?
Negative pricing has become a very real factor in European PPA negotiations. This is particularly evident in markets with high renewable penetration like Spain, Germany, and the Nordics, where the gap between peak renewable generation and actual demand is widening.
In Iberia, for example, we expect this risk to continue increasing through 2027. Solar capacity is expanding rapidly, but grid flexibility, storage, and demand-side response are not scaling at the same pace. Over time, those structural improvements should help rebalance the system, but in the near term, negative pricing is clearly becoming more frequent.
As a result, negative price clauses are now a central element of PPA structuring. Broadly speaking, we’re seeing three main approaches in the market.
The first is the most aggressive from the buyer’s perspective: no settlement during negative price hours. In this case, no payment is made and the seller bears the full exposure. This is particularly challenging for solar projects, for which revenues can drop by around 13–14% when these clauses are in place, compared to roughly 6–7% for onshore wind. This structure can be problematic from a financing standpoint, as lenders are often reluctant to support projects unless there are mitigating mechanisms in place.
The second approach is a more balanced risk-sharing model, where the agreed PPA price is still paid, but the seller absorbs the negative market price. In some cases, this is combined with caps on the number of hours or volumes exposed, to limit downside risk.
Finally, we’re seeing growing adoption of hybrid or conditional clauses. These structures introduce mechanisms such as caps on volumes or payments, limits on consecutive negative price hours, or benefit-sharing features – for example, adjusting the strike price when negative pricing occurs, or triggering the clause only after a certain threshold is reached.
Ultimately, these hybrid solutions aim to strike a balance: they provide cost protection for the buyer while preserving some revenue stability for the seller. Given that, in most fixed-for-floating PPAs, the seller already forgoes the upside when market prices exceed the strike price, it is increasingly considered fair for buyers to share at least part of the downside risk as well.
Given that, in most fixed-for-floating PPAs, the seller already forgoes the upside when market prices exceed the strike price, it is increasingly considered fair for buyers to share at least part of the downside risk as well.
As C&I buyers seek to de-risk PPA delivery profiles (especially for pay-as-produced contracts), do you see structured deal types like baseload PPAs gaining traction? Is wind-backed baseload emerging as the primary alternative to pay-as-produced wind deals, or are solar+BESS contracts taking the lead?
Wind continues to be a premium technology, highly sought after by both utilities and corporate offtakers. Its strong value proposition remains clear, particularly in its ability to provide stable, complementary profiles that smooth variability, enhance solar+BESS output, and make combined portfolios more attractive to buyers.
Wind continues to be a premium technology, highly sought after by both utilities and corporate offtakers.
While solar+BESS PPAs are more numerous - reflecting solar’s faster development timeline and the practical necessity of pairing with storage in many geographies - wind plays a critical role in shaping multi-technology portfolios. I would not say that baseload wind is “taking over,” but we expect an increasing number of baseload-style PPAs built around multi-technology combinations, where wind provides the stable backbone to complement solar and storage assets.
In which European markets are you seeing the greatest offtake appetite amongst buyers? Which emerging regions do you see as being particularly compelling for new development in the coming years, and why might these areas be of interest to prospective corporate buyers?
In terms of PPA activity, 2025 was once again led by Spain, followed by Germany and Italy, with the Nordic markets also maintaining a strong and steady level of engagement. Spain in particular has continued to benefit from a mature renewables pipeline and an active corporate offtake market. Germany remains a key hub driven by a large industrial base, while Italy continues to demonstrate robust corporate demand for PPAs.
That said, the Italian market is also evolving. The coexistence of public auctions and support schemes such as Energy Release is increasingly shaping market dynamics, influencing both pricing expectations and the structuring of long-term contracts for buyers and developers alike.
At the same time, Northern European markets continue to play an important role, supported by their established infrastructure and long-standing experience with PPAs. While growth in these regions remains more incremental compared to emerging markets, there is a clear expectation of increasing electricity demand driven by the expansion of data centres. This trend is likely to support additional PPA activity going forward, as data centre operators increasingly seek long-term renewable sourcing to meet their energy needs.
Looking ahead, we observe a gradual shift in buyer interest towards markets where supply and demand fundamentals are more closely aligned. Eastern European countries are attracting growing attention, largely due to the concentration of industrial load in those regions. This creates a more natural fit between renewable generation and local consumption, making these markets particularly compelling for new development and corporate offtake strategies.
Looking ahead, we observe a gradual shift in buyer interest towards markets where supply and demand fundamentals are more closely aligned.
With Europe achieving 19 GW of new wind capacity in 2025, should we expect to see grid capacity constraints shift the focus to repowering legacy projects in some markets? How do developers view government auctions - like we see in Italy or Germany - compared to corporate PPAs with respect to offtake options?
The continued increase in renewable capacity across Europe is placing significant pressure on existing grid infrastructure. Grid expansion and reinforcement are essential, but they remain costly and time-consuming processes. As a result, grid congestion is already emerging as one of the primary bottlenecks to the energy transition, with implications such as rising curtailment, increasing occurrences of negative pricing, and, ultimately, potential constraints on the pace of new renewable deployment.
In this context, repowering is expected to play an increasingly important role. By upgrading existing assets developers can better utilize existing grid connections and mitigate some of the limitations associated with new grid access. Beyond repowering, strategies such as overpowering, co-location, and hybridization with storage, are gaining traction. These approaches enable developers to optimize grid utilization and deliver more structured generation profiles, which is becoming increasingly relevant for offtakers.
On the offtake side, developers today are typically balancing between government-backed schemes and corporate PPAs. Regulated auction mechanisms, such as those seen in markets like Italy and Germany, continue to attract strong interest. These frameworks-such as Italy’s FER X and Energy Release schemes-offer several advantages, including long-term visibility, inflation indexation, settlement mechanisms often linked to zonal pricing, and minimal counterparty credit risk. From an investor perspective, they provide highly bankable and predictable cash flows, which explains why these auctions are frequently oversubscribed.
Compared to corporate PPAs, these regulated schemes are often perceived as lower risk and more straightforward to finance. However, this comes at the cost of heightened competition, which can lead to compressed returns for developers. Corporate PPAs may offer greater pricing upside and flexibility in structuring, but they also introduce considerations around credit risk, tenor, and price volatility.
Overall, developers are increasingly adopting a dual approach, evaluating both auction-based mechanisms and corporate PPAs as complementary routes to market. The optimal choice often depends on the project’s risk appetite, return expectations, and the ability to secure long-term, stable offtake arrangements in an increasingly constrained grid environment.
Markets are waiting for clarity on proposed changes to Greenhouse Gas Protocol (GHGP) guidance, which bring the potential to require hourly and geographical matching for buyers. If such changes were to make it into the updated GHGP standards, how do you foresee the corporate PPA market responding, and how feasible do you believe these changes are to implement?
The proposed revisions by the European Commission to the GHG Protocol, particularly around Scope 2 accounting, are already reshaping how buyers approach PPA negotiations. The increasing regulatory uncertainty has led many buyers to pause pan-European PPA strategies, instead prioritising transactions in markets where electricity consumption can be more closely aligned with generation.
As a result, as previously mentioned, we are seeing growing offtake appetite in Eastern European markets, where a significant share of industrial demand is concentrated. These regions are becoming particularly attractive for new renewable development, as they offer stronger alignment between local generation and consumption profiles - an aspect that is likely to become increasingly important under potential hourly matching requirements.
If such hourly correlation becomes mandatory, traditional “pay-as-produced” structures may lose competitiveness. In response, we expect to see increased demand for more sophisticated delivery profiles, alongside a growing role for battery storage solutions to help shape output. This will significantly enhance the value proposition of multi-technology PPAs, combining complementary generation assets to better match demand patterns.
We expect to see increased demand for more sophisticated delivery profiles, alongside a growing role for battery storage solutions to help shape output.
At the same time, physical PPAs are likely to gain prominence, while purely financial (virtual) PPAs may face reduced demand.
This shift could have notable implications for markets with high renewable penetration and structurally low power prices, such as Iberia, which have historically relied on virtual PPAs to drive large-scale renewable deployment. A more limited pool of eligible corporate buyers, combined with stricter procurement requirements, may ultimately slow the pace of new project development in these regions.
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