Financing for photovoltaic projects is on the verge of a major change: Project developers, investors and banks are under increasing pressure due to negative electricity prices, volatile markets and new marketing models. At the same time, new opportunities for viable business models are emerging thanks to storage systems, flexibility and new regulatory approaches.
At the Forum Solar PLUS 2025, we spoke to Casimir Lorenz, Managing Director Central Europe at Aurora Energy Research, a leading provider of power market forecasting and analytics, about the future of PV financing – from power purchase agreements (PPAs) and contracts for difference (CFD) to the impact of flexibility.
In principle, yes. PV projects can be economically viable without subsidies. In the past, we have seen numerous standalone PV installations that were exclusively financed by the market and via PPAs. The situation is more difficult now because PPA prices are under pressure due to economic and political uncertainty. But we expect the market to stabilize again. A project’s success largely depends on how much developers can lower investment and financing costs. This is where the banks come in: Debt shares and costs can make or break a project’s profitability. Negative-price periods pose a particular challenge for power plants subsidized by the German Renewable Energy Sources Act (EEG), while for PPA-backed plants, the contract terms are what matter. We still believe that purely market-based PV financing is possible, especially when combined with battery storage. This combination creates a more compelling business case, albeit at the cost of greater complexity.
While negative prices indeed reduce the value of PV electricity, the price of PPAs depends largely on the number of hours with low prices. Simultaneous feed-in, which particularly affects PV, leads to many low-price hours and thus to a cannibalization of its own market value. So the problem for PPAs lies not in the number of hours with negative prices, but rather the overall decrease of PV electricity value due to cannibalization. If generation can be shifted or stored, this can increase the market value and, in turn, the PPA level.
In simple terms, yes. Storage and flexible consumers can shift electricity from periods of low prices to periods of high prices. This boosts the market value of PV, making PPAs more attractive again.
The classic model is project-based financing: each project is evaluated on its own, with financing based on its expected revenues and risks. When PPA or EEG revenues are insufficient, this model reaches its limits due to a lack of stable cash flows. One solution to this are structures in which operators deliberately take on higher short-term market risk – in other words, going merchant for several years. This can result in a higher cost of capital, as banks provide less debt capital or only at a higher cost. At the same time, portfolios are gaining importance. Several plants – such as PV, wind and storage – are bundled and financed together, often across borders. Combining plants reduces the default risk and makes market-based cash flows easier to handle for banks. Aurora supports developers and banks by modeling such portfolios, identifying ideal combinations and quantifying risks across various scenarios. These risk analyses allow more market-based portfolios to have competitive financing conditions.
As developer, I must first create a project pool before I can bundle it into a portfolio for financing. This increases organizational complexity, for example due to bridging finance and different development stages. Add to this the risk that market or financing conditions could change during the development phase. However, spreading the risk by diversifying technology, location and timing makes the overall portfolio more attractive to banks.
Ancillary services are an important field, especially in light of the storage boom. In the short term, we expect severe cannibalization in balancing markets because an increasing number of storage systems will be competing for the same revenue options. However, prices will not drop to zero because storage systems have opportunity costs and must consider alternative markets, such as the day-ahead and intraday markets. It is attractive for renewables, particularly PV, to generate additional revenue through ancillary services during periods of low market prices. Both direct marketers and integrated operators can use participation in frequency control markets to reduce costs and generate extra revenue. Over the next five years, these extra revenue streams will play an important role. They should be accounted for when it comes to financing and transactions, as they may enhance project value – even if banks are conservative about this.
What is your opinion of the upcoming electricity market reform and the mandatory use of contracts for difference (CFDs)? Will this be a game-changer for PV projects in Europe?
One problem with the electricity market reform is its late implementation, and the prolonged period of uncertainty has had a negative impact on the market. It is intensely discussed which subsidy design – such as CFDs – is the most efficient for renewable projects over the long term. Models
that are not designed to maximize generation, but rather to maximize market profits by shifting generation to financially attractive periods, are particularly interesting. Although potential-based CFDs with reference plants could incentivize such models, they entail a basic risk as the actual plant may differ from the reference plant. This additional risk creates costs and needs to be properly assessed and priced by developers, investors and banks. The current EEG has the advantage of being relatively easy to combine with PPAs: It serves as a floor, while PPAs open up additional market opportunities. Though a pure floor without cap limits earnings at higher prices, it is generally easier to manage from a financing standpoint. Whether a new CFD system delivers greater benefits depends on whether its efficiency gains outweigh the additional risks and complexities.
Do you see a conflict of goals between the introduction of CFDs and the use of PPAs in the same system?
Yes, there is a conflict of goals between CFDs and PPAs because both instruments work in a similar way but with different counterparties. In a two-sided CFD, the government promises to offset low market prices but expects repayment when prices are high. If I also concluded a PPA with an off-taker, I could risk a double claim on the same electricity. Solutions that allow you to opt out of the CFD and transition to a PPA later on would mitigate this problem to some extent, but they are quite similar to the old EEG approach. In practice, it will therefore only be possible to combine CFDs and PPAs for parts of the generation, if at all.
Would it be possible to market a project partly through CFDs and partly through PPAs?
It would make economic sense to split a project, marketing, for example, 50 percent of the output through a CFD and the remaining 50 percent via PPAs. That way, you would get steady cash flows for one part of the portfolio, while taking greater market risk and boosting your return potential for the other part. In essence, this is asset-level portfolio optimization, with structures similar to those used for battery storage systems. The degree to which a project’s revenue is hybridized depends on the targeted debt share, expected ROI and the level of risk investors are willing to take.
How uncertain are today’s electricity price forecasts? Is modeling becoming more challenging or more precise, for example through AI-driven approaches?
We continuously improve our models and methods. At the same time, the market is becoming increasingly complex due to new technologies and markets. Batteries, for example, participate simultaneously on the day-ahead, intraday and frequency control markets, creating additional uncertainty. Whether forecasts are “improving” overall is hard to answer. To some extent, advances in methods and increasing complexity are keeping each other in check. We are already using new technologies like AI in our day-to-day business operations, but they do not replace basic market logic. What matters today is not just modeling risks for central, high and low cases, but across many scenarios and sensitivities. This allows banks and investors to understand risks better and apply less generalized discounts.
What political or regulatory changes do you think are necessary to make PV investments attractive in Europe in the long term?
If we want PV investments to stay attractive in the long run, the system has to become more flexible. PV installations themselves offer limited flexibility. Real system flexibility comes from storage, controllable demand and other flexible generation sources. In terms of regulation, grid connection for storage and renewables should be given to well-developed projects rather than on a first-come, first-served basis. What’s more, storage systems should not be viewed as a nuisance, but a system-serving resource that requires the right information and price signals. One of the main goals must be to manage the battery storage boom in a way that helps relieve grid congestion rather than create more of it. To achieve this, we need the right framework conditions from the government, regulators and transmission and distribution system operators. There is also a lot of potential on the demand side: E-vehicles, heat pumps and industrial electrification could respond much more flexibly if the right incentives were in place. Today, many prosumers and residential storage system operators optimize consumption based on their own needs because they lack market- and grid-oriented price signals. In the long term, it is crucial that prices are both local and dynamic, allowing investments and business decisions to be based on actual grid situations. This can reduce system costs, as less expensive grid expansion is required and existing infrastructure is used more efficiently.
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