IN Brief:
- Pexapark's European composite rose 2.3% in July to €45/MWh.
- Twenty-four publicly announced PPAs represented around 1.1GW of generation capacity.
- Nine BESS agreements covered approximately 865MW/3.1GWh, with tolling accounting for much of the capacity.
Pexapark data show that its European PPA price composite rose by 2.3% in July to €45/MWh, while contracting activity remained active across both renewable generation and battery storage. The movement was not uniform: Great Britain and Italy recorded increases, while several high-renewable markets moved in the opposite direction.
Great Britain posted the largest monthly increase in the reported country trends at 5.8%, followed by Italy at 4.3%. Prices fell by 6.3% in the Nordic region, 3.9% in Spain, and 2.9% in Portugal. The divergence illustrates how a European headline number can conceal very different local conditions around forward power prices, renewable penetration, hydrology, and expected capture prices.
The same July dataset recorded 24 publicly announced power purchase agreements representing around 1.1GW of contracted capacity. Corporate buyers accounted for 21 agreements, while utilities signed three. Solar remained the largest single technology group by disclosed capacity, with mixed-technology and onshore wind agreements also making a material contribution to the month’s activity.
Battery contracting was another prominent feature. Pexapark counted nine European BESS agreements representing about 865MW and 3.1GWh of disclosed capacity. Four were tolling agreements, including two substantial Italian deals involving Zelestra: a 300MW agreement with EnBW and a 207MW agreement with Axpo. A 100MW tolling agreement was also recorded in Great Britain, alongside a 55MW portfolio agreement in Spain.
The structure of those battery deals matters because storage projects are increasingly being financed around more than merchant trading assumptions. Under a tolling arrangement, the owner typically gives an offtaker or optimiser defined dispatch rights in return for a fixed or otherwise contracted payment. That can transfer part of the market-risk burden away from the asset owner and provide revenue visibility that lenders can model more readily.
Other structures recorded in July included revenue swaps in Spain and Hungary and merchant optimisation agreements with revenue-sharing arrangements in Germany, Poland, and Denmark. These models allocate risk differently. A revenue swap can stabilise part of a project’s income while leaving physical operation with the owner or optimiser, whereas merchant revenue sharing preserves greater exposure to market upside but also leaves more variability in the cash flow available to service debt and operating costs.
The growth of those structures is an engineering issue as well as a financial one. A contract that gives an optimiser physical dispatch rights changes how aggressively the battery may be cycled, how state of charge is managed, and which market opportunities are prioritised. Owners therefore have to align warranty limits, degradation assumptions, availability guarantees, and maintenance planning with the commercial obligations written into the offtake contract.
For renewable generators, the July PPA movements also underline the importance of generation timing. A project may produce the same annual megawatt-hours as before while earning a lower market value if output increasingly arrives during hours when similar generation is abundant. That is why capture-price assumptions, curtailment exposure, and the shape of the contracted delivery profile are becoming more important than a simple comparison between a headline PPA strike price and a wholesale baseload price.
Great Britain’s 5.8% monthly increase does not therefore mean every new British renewable project became 5.8% more valuable, nor does Spain’s decline mean project economics deteriorated by exactly the same amount. Pexapark’s market indicators track changes in the pricing environment rather than report the confidential transaction price of every signed contract. Individual projects still depend on technology, location, commissioning date, volume profile, credit quality, and the specific risk allocation negotiated between buyer and seller.
The battery figures provide a useful counterpoint. Storage is not selling an identical product to a wind or solar PPA because it can shift energy and respond to short-duration price and system signals. The appearance of tolls, swaps, and merchant revenue-sharing agreements across several markets suggests counterparties are becoming more willing to price that flexibility explicitly rather than rely on an owner’s unhedged exposure to ancillary-service and wholesale revenues.
That trend could become increasingly important as European battery fleets expand. More installed capacity can compress returns in individual services, especially where many projects chase the same frequency-response or balancing opportunity. Contracting structures cannot remove the underlying technical and market risk, but they can redistribute it between owners, traders, utilities, and corporate counterparties with different appetites and capabilities.
July’s 2.3% increase in the European composite is therefore only one part of the story. The more consequential development is the widening range of contracts being used to finance both generation and storage while power-price behaviour becomes more regional and more dependent on when electricity is produced or consumed. For developers, the route to market is becoming another design variable alongside connection capacity, equipment selection, and project duration.
