Next-gen PPA contracts reshaping European power markets

European electricity prices dipped below zero more times than ever before in 2025 due to the growth in renewable energy generation, while the region’s grid struggled to keep up with the demands of the new generation mix. In Spain, for example, instances of negative prices doubled in 2025 compared with 2024 when the country first started experiencing the phenomenon. France, Germany and the UK have also been experiencing pricing extremes to varying degrees. 

This price cannibalisation happens at certain times when weather conditions are favourable for wind or solar generation, and the renewable assets all produce at the same time, regardless of demand or grid capacity, which can push prices to zero or even into negative territory. As renewable energy capture prices deviate from wholesale market prices, it can increase revenue risk for developers and producers and make consumers more reluctant to sign up to a power purchase agreement (PPA). 

“In many situations, the cannibalisation is so strong that it’s having a massive impact on the value of the production profile,” says Andreas Schwenzer, partner, energy and climate change, at consultants Argon & Co, who adds this makes forecasting more complicated. “You might be in the position to do a forecast for the next year, but three, five or 10 years is really hard to predict.” This is because further development of new generation, as well as uncertainty around the future flexibility of power plants, storage and demand-side assets, will “significantly impact the hourly price structure”, he explains. “That unpredictability means that, especially if you are taking any price structure risk with your offtake, it’s more or less not predictable and therefore not priceable.”

As well as uncertainty over future renewables build, market participants are contending with massive price uncertainty in European gas and power markets due to the Middle East conflict and the closure of the Strait of Hormuz. As a result of increased levels of long-term uncertainty, financial institutions involved in renewables projects are looking at various ways of mitigating long-dated risk.

“The words ‘uncertainty’ and ‘volatility’ are taking centre stage,” says chief risk officer at Citi, Vivek Shah. “Using risk-mitigation techniques such as contract clauses for earlier mutual break/termination and collateral management for [PPA] contracts can effectively shorten long-dated risk [and] is very much the direction, or focus, of banks,” he says.

As all European power market participants look for new ways to manage this uncertainty, tailoring is becoming more common for PPAs, which have traditionally been long-term, fairly standardised contracts. As these deals become more complex and users share more risk, it’s changing market interactions and causing a shift in how energy is contracted. 

A shift from simplicity

For about a decade, vanilla PPAs – pay-as-produced, single-technology deals – were the industry standard for contracting renewable energy generation. A producer would typically enter a PPA with an offtaker for all or part of the energy produced by a project, charging per megawatt-hour and leaving the offtaker to manage intermittency risk. 

But as investment in renewables has increased, boosting solar and wind generation, participants’ needs have changed. In particular, as certain technologies – solar in Spain, for example – have proliferated, intermittency risk has become more concentrated, affecting value and prices.

“Because of the gap between supply and demand, [PPA] prices are way down compared to a few years ago, so energy producers are not seeing as many advantages in signing long-term deals,” says Nicolás Mora-Guarda, head of PPA origination at European independent power producer (IPP) Encavis. “With short-term deals, the economics look better and we can take more risk because it’s a shorter time period. But even though the risk is easier to manage, more risk brings more complexity.”

Current uncertainty around European green energy policy is also affecting the renewables market and participants’ longer term risk appetites. The energy transition has recently taken a back seat as governments deal with rising debt due to the economic effects of the Covid pandemic, as well as the ongoing Russian war in Ukraine. While the Middle East conflict has renewed calls for European countries to increase their energy security and move away from reliance on gas, it is also likely to push up the cost of materials and therefore development costs for renewables projects.  

In any case, government subsidies for renewables are likely to continue to be phased out. At an Energy Risk Europe Leaders’ Network meeting in November 2025, participants discussed the challenging effects of these developments on the ability to hedge using longer term PPAs.

Any uncertainty will make long-term, standardised contracts much less attractive. And while there’s still demand for PPAs, “every negotiation is different and every offtaker is different, which means coming up with creative ideas”, Mora-Guarda says.

This has led to the emergence of a new breed of “finely-tuned” PPA contracts, according to Mustapha Obalanlege, energy and financial risk manager at IPP Sonnedix. Such contracts balance risks differently as producers and offtakers add clauses to suit their changing appetites.

Riccardo Rossi, head of southern Europe origination at energy trading company Centrica Energy, also sees risk being distributed differently within PPA contracts. “Whether it’s balancing risk, market risk or shape risk, it’s starting to become a bit more shared,” he says. 

To address price cannibalisation, for example, a negative pricing clause can cover the risk of prices hitting zero or below. Since negative pricing wasn’t an issue three or four years ago, this is a relatively new issue to negotiate, according to Max Plumptre, director of European transactions at renewables contract infrastructure provider LevelTen Energy. “PPAs have always been built on risk-sharing principles. What’s changing today is the need for more innovative structures that address negative pricing risk, as this becomes very material in certain European markets,” he adds. LevelTen has attempted to address this complexity – and the knock-on effect on PPA negotiation timelines – with a product called LEAP, which uses template clauses to create tailored contracts more quickly and efficiently. 

A PPA can also be used to address concentration risk by covering a combination of technologies – solar and wind, for example. “This can level out a drop in capture rates [for one technology], offsetting that with a higher capture rate in the other,” says Plumptre.

And as more storage assets come online, PPAs could be used to integrate these resources to address intermittency risk. “Storage shifts those hours that are going negative to hours with more value, allowing more value to be captured from the PPA than with a pay-as-produced contract,” Plumptre adds. “And that’s really the bottom line of why storage is becoming so important; it allows that flexibility to move away from the erosion of value.”

Data from renewable energy advisory firm, Pexapark, shows that, while European PPA volumes fell to 13.1 gigawatts (GW) in 2025, nearly 12GW of battery energy storage system (Bess) capacity was contracted under flexibility purchase agreements and optimisation agreements – triple the amount in 2024. “Headwinds in power markets have slowed the pace of investment into new merchant generation, while capital has increasingly shifted toward flexibility,” according to the report. In fact, Pexapark calls 2025 a “breakthrough year” for European Bess as market participants looked for ways to manage price cannibalisation and volatility. 

But Bess remains in its infancy and participants have not yet had much experience in creating PPA contracts that combine generation with a storage element. “The challenge right now is how to price this, and it will take some time to create a standardised product that is digestible by offtakers, many of whom are not energy experts,” explains Mora-Guarda. “Right now, the market is testing different options, but until we have standardisation, it will be difficult for this to pick up.”

Once it does, storage-based hybrid PPAs could become a crucial tool for renewable energy contracting as flexibility flourishes across Europe’s renewables-focused energy grid.

Greater grid flexibility 

Bundling renewable energy generation with Bess supports project financials by adding flexibility to manage intermittency risk. A co-located battery can store any excess power so offtakers do not have to pay for unwanted production and can negotiate to take power at certain peak times to suit their needs, managing shape risk.

This flexibility brings benefits for all market participants. “A solar power producer, for example, might add battery storage so it can continue to provide power outside of peak sunlight hours,” Obalanlege says. “A battery can also access the market at times when energy is cheaper to charge up and prepare for the next time it needs to discharge. Or, if it has excess power at the end of a contracted period, that can be sold back into the market when it’s favourable.” For those not willing to play a speculative role in the markets, tolling agreements allow developers to rent out the battery to others who are.

There are also non-physical flexibility plays. “With a PPA structure, the market can be used to hedge by buying or selling the excess for any shoulders based on forecasts,” says Obalanlege. “That requires a little more speculation, but more independent power producers are developing the capacity to start using simulation models [to do this].”

Indeed, according to Pexapark, recent market volatility means “utilities are reasserting themselves as system risk managers”, while some “next-generation” IPPs – are moving towards revenue management, structuring and portfolio optimisation.

This is understandable as new variations of PPAs add layers of complexity around how to value energy arbitrage and ancillary services within a contract. “Initially, valuation of PPAs was based on market sentiment: who wants my power and what are they willing to pay?” Obalanlege says. “Now that the market has grown, with larger PPAs that are more tailored and specific, market participants will have to get quantitative in pricing these contracts, almost the same as pricing derivatives.” 

The ‘next-gen’ IPP

Specific skills and expertise are needed to manage this complexity and benefit from the additional revenue it could generate. Utilities already act as intermediaries, taking complex intermittent generation from producers and shaping it into baseload products for corporates. Sitting between project developers and end-users, utilities can absorb and manage volume, price and structural risks across a diversified portfolio of assets and contracts. 

Kirill Ryzhov, lead originator at Uniper, says the European energy company offers structured power products, for example. These introduce floors to make projects bankable when projected capture prices fall below the levelised cost of electricity (LCOE) and share upside when market prices rise. It offers ‘PPA firming’, or volume-firming products to simplify and derisk offtake.  

Utilities can use their trading and risk capabilities to decide “where we take the risk, how we restructure a position, how […] we sell the position later on”, Ryzhov adds. This allows them to transform complex, long-dated risks from renewables projects into simpler, more acceptable products for corporate and industrial offtakers who cannot hedge or price these exposures as effectively.

The changing market picture is also encouraging some IPPs to consider evolving from passive asset owners to actively manage revenue. “The time of IPPs building renewable energy plants, tacking on a PPA and then saying, ‘it will produce when it produces and we’ll get revenue from that’ has started to disappear,” says Obalanlege. “[Some] IPPs are now taking a little more ownership of the production and usage of their energy by really tailoring PPAs. And by doing so, they can optimise their revenue.” 

He says Sonnedix is evolving toward a next-gen IPP model as more energy consumers look beyond simply “buying electricity” and instead want a competitive energy strategy that suits an increasingly complex market. Contractual flexibility is key to Sonnedix’s proposition, Obalanlege says.

Mora-Guarda says Encavis has also stepped up how it negotiates with offtakers, providing a new type of product it calls “full supply”, for example. “We ask corporate offtakers to share their consumption profile with us and then we develop a solution to cover it using different tranches,” he says. “We combine baseload tranches with solar, wind and a merchant component to cover all of their energy consumption.”

Transitioning from the traditional approach of project financing on an asset-by-asset basis to more of portfolio-based approach requires new skills and expertise. “Trading can be done in many different ways, from a very complex RWE-style entity to a small shop managing four or five assets,” Rossi explains. “But it’s a different mindset. IPPs going in that direction need specific skills and capabilities that do not always fit with how they think and operate right now. It’s creating a shift.”

Making this shift involves developing modelling capabilities and the ability to manage a portfolio of assets. For Encavis, for example, an in-house risk management team develops models using elements including price curves and weather forecasts, which can underpin more complex products like its full-supply PPA.

And with current market conditions characterised by uncertainty and volatility, that also impacts pricing. “Fundamentally, you can model PPA transactions as derivatives transactions, but this modelling involves making a lot of input assumptions,” Shah says. “As a bank, we have to do a lot of stress testing around these assumptions – if we’re assuming a certain curve, we will shock it in different ways, for example.”

This is something banks, energy trading companies and utilities have experience in doing. “Understanding what exposure you have, how to hedge those exposures, having access to the market and risk management in terms of credit risk but also cash risk [and] market risk. Managing all of those things is more typical for a trading company,” Rossi says.

Firms also need specialists who understand energy markets specifically, Obalanlege adds. “[They need to know] how to dispatch energy in an optimised way, as well as the technology, the software and the licences to access that, and the people to manage it,” he explains.

Finding value in volatility

“Those best positioned to optimise PPA value today are the market participants that combine flexibility, storage capabilities and a diverse portfolio to adapt to Europe’s evolving renewables-focused power markets” Plumptre says.

Right now, utilities hold an advantage because they have the expertise in the intraday trading and ancillary markets to optimise the value of a PPA, particularly with the growing need for flexibility across Europe’s renewables-focused electricity markets. 

But could 2026 be a defining year for next-gen IPPs? “The race is on. IPPs, utilities and hedge funds are converging on the same prize: capturing the value from volatility,” Pexapark’s director, commercial strategy, Itamar Orlandi, said in its recent outlook report. “By end of 2026, we’ll know who has the scale and skill to compete. Leading IPPs will separate from the pack. The rest become acquisition targets.”

Regardless of how companies shift to address changing market trends and mounting uncertainty, it looks like quantitative skills will be in demand to help price more complex PPA contracts. As renewable energy generation continues to expand across European power markets, market participants will need scale as well as expertise to manage ongoing uncertainty and volatility, while incorporating new technology and assets into their portfolios.