Produce and forget is over: How value creation in energy infrastructure projects is fundamentally shifting

For a long time, calculating a solar park's profitability was a relatively simple multiplication exercise. But that world no longer exists. Battery storage, shrinking subsidies, and grid constraints are shifting value creation away from a park’s development and construction phase towards ongoing operations. Anyone developing, financing and operating energy infrastructure today must, above all, be able to assess and monetise flexibility.

The rapid rise of battery energy storage systems (BESS) is one of the clearest signs of this shift. As the International Energy Agency (IEA) states: “Battery storage is the fastest-growing power technology today. In 2025, 108 GW of new battery storage capacity was deployed worldwide, 40% more than in 2024. Installed capacity is now eleven times higher than in 2021.“

Germany is no exception. In the first quarter of 2026, utility-scale battery storage additions matched residential storage additions for the first time. By 2037, the scenario framework approved by the German Federal Network Agency (BNetzA) assumes around 41 to 94 GW of large-scale battery storage, compared with around 24 GW in the previous 2022 framework. Even the lowest scenario is around 70% higher.

The message is clear: energy infrastructure is no longer just about producing electricity. Flexibility is becoming a core asset class, and battery storage is the key enabler. Produce & Forget is over. To understand why, let’s look back.

The Renewable Energy Sources Act (Erneuerbare-Energien-Gesetz, EEG), coming into force on 1 April 2000, set the stage for the expansion of renewable energy in Germany. It replaced the Electricity Feed-in Act (Stromeinspeisungsgesetz, StrEG), which had been active since 1991. At its core, the Act required mandatory grid connection and a guaranteed tariff, generally valid for 20 years. The plant fed electricity into the grid whenever it produced it, regardless of demand. As a result, operators faced low price and marketing risk.

For a solar park, this translated into a relatively straightforward planning logic: available land x maximum installable module power x solar irradiation (specific yield) x feed-in tariff. The objective was simply to maximise output. Even the gradual integration of renewables into the market did little to change that fundamental logic. Newer installations above a certain size must sell their electricity directly on the market, while receiving a so-called market premium that covers the difference between a predefined reference value and the average market value. Importantly, this mechanism works asymmetrically: it closes the gap when market prices fall short, while the operator keeps additional revenues. The result is a business model characterised by stable, highly predictable cash flows and, consequently, a high degree of financing certainty.

In short: the approach worked. Germany’s EEG provided a powerful boost to the expansion of renewables. As a result, the share of renewable energy in gross electricity consumption grew from 6.3% in 2000 to more than 50% in 2025. At the same time, solar power became dramatically cheaper. In July 2026, ground-mounted PV projects were awarded an average tariff of just 4.79 Euro cents per kilowatt-hour, less than one-tenth of the original level. Success had changed the rules of the game.

Unlike conventional power plants, wind and solar do not follow a rigid dispatch schedule. As their share of the energy mix increases, both electricity generation and power prices become more volatile. In Germany alone, the day-ahead market recorded more than 500 hours of negative electricity prices in 2025. At the same time, the number of hours with prices above EUR 200/MWh also increased significantly.

For solar parks, this development has two consequences, although they do not affect all assets equally.

• First, electricity loses value because many plants generate and feed in at the same time, a phenomenon known as cannibalisation. Existing assets benefiting from fixed feed-in tariffs or a sliding market premium are largely shielded from this effect. Their remuneration remains stable, and the market premium increases when market values decline. Instead, assets that sell their electricity on a merchant basis without subsidy support are the ones feeling the impact directly.
• Second, operators increasingly bear the risk of negative power prices themselves, depending on the date the asset was commissioned. Plants commissioned since 2025 lose their support from the first quarter-hour of negative prices (older plants only after several consecutive hours, those commissioned before 2016 not at all). Without support, every kilowatt-hour fed in at negative prices costs money. As a result, curtailment becomes an economic decision during operations, made quarter-hour by quarter-hour. At the same time, project developers must already account for this dynamic when building the business case, estimating how often a plant is likely to be curtailed and what value its electricity can capture during the remaining hours.

The grid adds another layer of complexity. Large volumes of electricity flow between generation centres and demand centres, placing increasing strain on the grid and creating overload risks. In 2025, overload and congestion management measures, including redispatch and reserve power plants, cost EUR 3.1 billion, while grid constraints curtailed 3.5% of renewable electricity generation. Network access itself has also become a bottleneck. Grid operators impose technical requirements regarding grid connection and plant operation that further complicate project development.

This is where BESS come in. From a system perspective, they help balance the fluctuations of wind and solar generation, relieve pressure on the grid, and prevent excess renewable electricity from going to waste. From a private market perspective, they turn price volatility into a business opportunity and help operators comply with grid requirements without undermining the business case.

In Germany, approximately 29.59 GWh is in battery storage systems, of which domestic storage accounts for around 22.1 GWh, commercial storage around 1.6 GWh, and large-scale battery storage around 5.9 GWh. At the same time, the utility-scale energy storage market is transforming. In the past, battery storage systems were built almost exclusively to provide frequency containment reserves (FCR). Today, additional value streams include energy arbitrage, integrating large-scale solar and wind farms, and using storage as a grid booster. The assets themselves are changing as well: increasingly, wind and solar parks are being paired directly with battery storage systems.

The rise of storage is also bringing new actors into the ecosystem. Alongside traditional power marketers, specialised optimisation providers are emerging. Companies such as enspired trade storage assets simultaneously across multiple available markets through cross-market trading.

As a consequence, value is no longer determined solely by how much electricity an asset generates. Instead, it matters when, where, and under which market conditions it is deployed. Two technically identical storage assets can deliver vastly different economic outcomes depending on where they are connected and which markets they participate in. Value creation is shifting: An asset's value is no longer defined by the asset itself, but by the decisions surrounding its operation.

Under these conditions, flexibility becomes the key value driver. How a project utilises this flexibility, and to what extent, depends on three factors:

• Market environment: Price spreads, ancillary services prices, and cannibalisation determine the value of flexibility, and this value is not static.
• Grid connection point (i.e. local grid conditions): Where capacity is scarce, grid operators offer flexible connection agreements. FCAs can enable a faster grid connection, but typically limit export and import capacity, ramp rates, and participation in ancillary services.
• The financing and commercialisation structure behind the assets: Whether a storage asset operates entirely on the market (merchant), is made available to a third party under a tolling agreement in return for fixed payments, or operates with a guaranteed minimum revenue fundamentally changes its risk and return profile.

This is where the implications for project development and operations lie: The trading opportunities available at a specific location determine the business case; more specifically, how large the storage system should be relative to PV capacity and grid connection capacity, whether an FCA with ramp-rate limits still supports the business case at all, and whether a tolling agreement facilitates financing or comes at the cost of revenue opportunities.

Commissioning does not complete this calculation; it only starts it. During operation, operators make continuous decisions about when the plant is curtailed, when the storage system charges, and which markets it offers capacity to.

At the same time, the assumptions underlying the business case are changing. As storage deployment increases, market saturation and cannibalisation become potential risks. Dynamic FCAs may restrict export and import capacity differently over time, and a commercialisation agreement that was appropriate when signed may limit revenue opportunities years later.

As a result, the business case is significantly more dynamic and complex than multiplying land area, modules, solar irradiation, and tariff, and it remains so throughout the asset's entire lifetime.

Combining these elements and managing them over time is complex. As a result, project develop-ers, investors, and operators need a new approach to continuous modelling, valuation, and adaptation of the offset structure. An asset's value is no longer created primarily before COD, but through the quality of ongoing decisions made throughout its lifetime.

That's why we are interested in solutions that enable dynamic project development and continuous optimisation for the operations phase in increasingly dynamic energy systems.

The next question is: what does this mean for the people developing, financing, and operating these assets? How should investment and operating decisions change when flexibility itself becomes the key value driver? We'll take a closer look at that in our next blog post!

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