Our previous post, The Merchant BESS Business Case in Finland, covered how a battery earns revenue across Finland's fifteen market mechanisms and how an optimizer decides where to allocate capacity. This post picks up where that one ended.
Revenue forecasting for a battery asset requires predicting, years in advance, the prices at which it will charge, discharge, and clear ancillary service markets. That is, in practice, predicting the aggregate behavior of supply and demand across a large and increasingly complex power system.
The variables involved are numerous and interact non-linearly. On the supply side: the installed mix of nuclear, wind, solar, hydro, and thermal; their marginal costs; their availability; planned and unplanned outages; and the pace and location of new capacity additions. On the demand side: industrial load growth or decline, the timing and scale of data center buildouts, heating electrification, the seasonality and weather sensitivity of consumption. At the interconnection boundary: the capacity and direction of cross-border flows, which depend on market conditions in Sweden, Norway, Estonia, and beyond.
Layered on top of those structural factors are the shorter-cycle dynamics that drive day-to-day and hour-to-hour price formation: fuel prices, carbon prices, hydrological conditions in Norway, geopolitical events that alter gas supply or demand, central bank policy that affects industrial activity. The models that practitioners use to forecast long-run average price levels have a reasonable track record on direction but a poor track record on magnitude and timing.
Ancillary service pricing adds another layer of difficulty. Reserve markets are pay-as-cleared auctions where batteries increasingly set the marginal price. Forecasting that price requires knowing how many and with what strategy competing batteries will be running at the same time, which is itself a function of future investment decisions that may, and may not be made.
The practical result is that BESS revenue models carry wide uncertainty bands. Investors who built Finland's first-generation projects found this empirically: revenues fell faster than early models assumed, though assets have remained commercially viable.
The first wave of Finnish BESS projects was largely financed with equity, or equity-like capital from a limited number of alternative lenders. In smaller scale this was manageable. As project sizes continue to grow and return expectation decreases, attracting project debt financing is of growing importance. Not only to unlock sufficient capital to build projects, but also to decrease their overall cost of capital.
Project finance lenders advancing debt against a single SPV need a straightforward answer: will this asset generate enough cash to service debt, long-term? A wind farm has a production profile that meteorological data can bound and is selling electricity. A battery has a capability to exploit price spreads that depend on market conditions no model can predict with the same confidence, nor has it the same intuitive business plan.
To solve this challenge, risk sharing mechanisms introduced in more mature BESS markets like the UK have been slowly, but surely spreading across Europe. These mechanisms can be together called Flexibility Purchase Agreements.
Tolling
With tolling, the offtaker pays the asset owner a fixed annual fee, typically in euros per megawatt per year, in return for full dispatch rights over the battery over a certain amount of time. The offtaker assumes all market risk and keeps whatever the battery earns above the toll. The owner gets a predictable, bankable income stream and no market upside.
Tolling is effectively a lease of the battery's operational capacity. The owner's job is to keep the asset available to agreed uptime standards and deliver grid access. Revenue is fixed regardless of market conditions: if ancillary prices spike, the owner does not benefit; if they collapse, the owner is not harmed.
The offtaker acquires dispatch rights and the obligation to optimize the battery across available markets. The commercial rationale is that the offtaker can extract more from the asset than the toll costs, using its trading infrastructure and portfolio scale.
As tolling agreements leave no upside over the duration of the toll, projects are often structured as partial tolls: only part of the battery project capacity is contracted through the tolling agreement, while the remaining capacity is optimized freely by the project, who owns the realized revenues for the uncontracted part.
Floor with revenue share
A floor agreement gives the asset owner downside protection through a guaranteed minimum payment, while revenues above that level are shared between owner and offtaker. Unlike a toll, the owner retains partial merchant exposure and participates in upside when conditions are good.
With a floor the owner sells downside protection and retains a share of the economic interest above the floor. The floor is the bankable component lenders can underwrite; the revenue share above it is the equity upside.
In a floor, the offtaker provides an insurance-like service: it guarantees the floor in exchange for sharing in revenues above it, with such sharing mechanism being the equivalent of the insurance premium. If revenues fall persistently below the floor, the offtaker absorbs the shortfall. This risk profile resembles a structured product more than a trading book position, which is why financial institutions and insurers are increasingly active as floor providers.
Floors can be structured as physical or financial instruments. Financial floors let the owner or optimizer retain operational control while still providing the lender with a revenue guarantee.
Day-ahead (DA) swap
A DA swap is a purely financial contract. The offtaker pays the owner a fixed price; the owner pays back a floating amount tied to a reference index representing the theoretical day-ahead spread the battery could have earned, based on observed DA prices and an agreed profile. No dispatch rights change hands.
The owner retains full operational freedom but carries basis risk: if the battery is actually running in ancillary services rather than day-ahead arbitrage, actual revenues and swap settlement can diverge. Basis risk also realizes, when the optimizer strategy and achieved performance is different from the DA prices, or in case of asset or trading-linked items. In other words, DA swaps do not catch several revenues and costs items that BESS projects may face or exploit.
Via DA swaps, the offtaker gains synthetic exposure to day-ahead price spreads without owning or operating a battery. This is attractive for energy traders and financial institutions with views on power market development. Return depends on whether actual day-ahead revenues exceed the fixed price committed.
DA swaps have gained momentum in markets where the BESS investment case heavily relies on DA arbitrage. In the Nordic markets, their applicability is more limited for two reasons. First, the Nord Pool day-ahead market is highly liquid and well-arbitraged, which compresses the spreads available for pure DA arbitrage relative to less integrated markets. Second, a large share of Finnish BESS revenues comes from ancillary services, not captured in a DA swap. An owner entering a DA swap retains full exposure to ancillary service revenue volatility, which is often the dominant revenue component.
For Finnish BESS projects today, tolling and floor structures are the primary tools for bankability. DA swaps may become more relevant as the revenue mix continues shifting toward energy arbitrage, but they are not a primary structuring tool in the Nordic market at present.
DA swaps are heavily debated between project owners, energy traders and lenders. Project owners and lenders usually consider that the basis risk remaining is too important for these contracts to constitute bankable contracted revenues long term. Energy traders are heavily advocating for them on the other hand, as they allow them to sell back the exposure to the market easily, while securing an origination margin for an increased volume of electricity price derivatives.
Even though the contractual structures exist, and individual deals are made, FPAs are still rare in the BESS markets, if compared to the overall volume of projects. Both asset owners and offtakers are still learning how to price and negotiate these arrangements. More potential offtake counterparties are considering participation, and as volumes grow and stakeholders observe operating projects, contracts are expected to standardize and transaction timelines to shorten.
The Nordic market is following the same path more developed markets have already walked. Asset owners here are working out how much power market risk they are willing to carry, which structures fit their financing needs, and which counterparties are credible. That process takes time, but the direction is clear.
If you’re interested in hearing more about what we at Olana think about de-risking our investments, do not hesitate to reach out.
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