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Chapter 1
Two assets, two completely different jobs
A solar plant and a battery storage system often sit on the same site, yet they're governed by completely different rules. The distinction is fundamental — and it drives almost everything that follows. A concrete example is our project in Hungary.
The solar plant
It generates energy. When it does so is decided by the sun, not the operator. A solar plant can curtail its output, but it can't increase it or shift it in time. On the grid, it's a pure feed-in source.
Its economic problem: it produces the most exactly when every other solar plant is also producing the most. That's precisely when electricity is worth the least.
The battery storage system (BESS)
It generates nothing. It shifts energy through time. While charging, it's a consumer; while discharging, it's a producer — the same asset, two roles, often just minutes apart.
This dual role is why storage is so complicated to regulate: almost every energy law was written for a "producer" or a "consumer" — not for something that is both.
The metrics that matter
Power
How fast the battery can absorb or release energy. Determines how much it can move within a single 15-minute interval.
Capacity
The total amount of energy that fits inside. A 10 MW battery with 20 MWh can discharge at full power for two hours.
C-rate
The ratio of the two. 20 MWh ÷ 10 MW = 2 hours, i.e. 0.5 C. Short-duration systems suit balancing services; long-duration ones suit price arbitrage.
Deep dive: efficiency, degradation, and why "86%" isn't always "86%"
Round-trip efficiency (RTE) describes how much of the energy put in comes back out on discharge. Lithium-ion systems run at 92–95% at the cell level. At the system level, that often drops to 85–90%, because inverters, transformers, cooling, and control electronics constantly draw power.
Important for analysis: a ratio calculated from monthly totals — "discharged ÷ charged" — is not a true efficiency figure. It's only a reasonable approximation if the battery started and ended the month at roughly the same fill level. If the month ends with the battery half-full, efficiency looks artificially poor — the energy is simply still sitting inside. A reliable number requires state-of-charge (SoC) data.
Degradation: every full cycle ages the cells. Typical warranties guarantee 70% of remaining capacity after 10 years, or after a defined number of cycles. This caps the economics: capturing every small price gap earns more in the short term but shortens the asset's life. Trading strategies therefore price in a wear cost per cycle.
Chapter 2 · Simulation
One day, 96 quarter-hours
Since October 2025, electricity has been traded across Europe in 15-minute blocks — 96 prices a day instead of 24. Here's a typical sunny summer day. Move the two thresholds and watch how dispatch and revenue change.
Daily strip · price, dispatch, state of charge
Move the pointer for details- Discharge revenue
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- Charging cost
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- Gross margin, day
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- Full cycles
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What to look for: pull the two thresholds far apart and the asset trades less often but earns more per cycle. Push them together and you get more cycles with a thinner margin. That trade-off is the core of the storage business: spread times frequency, minus wear.
The price curve is a stylised representation of a sunny summer day, not a real measurement series. Around midday, solar output can push the price below zero — anyone charging then gets paid to take electricity off the grid.
Deep dive: why the curve dips at midday
This shape is called the duck curve. It appears when a lot of solar is on the grid: around midday, the sun covers a large share of demand, expensive power plants drop out of the merit order, and the price falls. In the evening, the sun disappears within a few hours while demand rises — and the price spikes.
Hungary is an extreme example. On 25 June 2025, the country's midday solar output reached 6.25 GW — more than total electricity demand at that moment. The steeper the curve, the more valuable flexibility becomes — and the better the economics of storage.
For solar operators, the same curve is a problem: they sell their entire output during exactly the hours when the price is lowest. The average price they actually capture therefore sits systematically below the daily average. This gap is called the cannibalisation effect (the capture rate) — and it's the strongest economic argument for pairing solar with storage.
Chapter 3
Electricity is sold multiple times before it flows
Between "I plan to deliver electricity tomorrow" and "the electricity is flowing right now" lie several trading stages. Each one corrects the last. Click through them.
The most important number in this chapter: since 1 October 2025, all coupled European day-ahead markets trade in 15-minute blocks instead of hourly ones. The switch went live on 30 September 2025 for delivery day 1 October 2025. Electricity prices are now set every 15 minutes. For storage, that's a real improvement: price spikes that used to average out within an hour are now tradeable.
Deep dive: balance groups and market coupling
Every asset belongs to a balance group — a virtual account where feed-in and offtake from all associated assets are netted against each other. The balance responsible party owes the grid operator a balanced schedule. Whatever doesn't add up at the end is settled as imbalance energy (Chapter 5).
Europe's day-ahead markets are linked through market coupling (single day-ahead coupling, SDAC): a shared algorithm simultaneously sets prices for all bidding zones and allocates the scarce cross-border capacity between them. Thirty transmission system operators take part; outside the system sit, among others, the UK, Switzerland, the Western Balkans, and Turkey. As a result, prices in Hungary, Austria, and Germany are closely linked and only diverge when cross-border capacity runs short.
Chapter 4
Balancing power: paid to stand ready
The power grid must run at a constant 50 Hertz. When frequency deviates, three tiered reserves kick in one after another — each faster and more expensive than the next. For batteries, this is the most attractive market, because they can react in milliseconds.
Reacts within seconds, fully engaged after 30 seconds at the latest. Activates automatically and simultaneously across the whole European synchronous grid — it stops a frequency drop but doesn't correct it. Batteries dominate this market because their response time is unbeatable.
As the secondary reserve, aFRR gradually takes over from FCR after around 30 seconds, freeing up Continental Europe's shared primary reserve so it's ready again as a safety net. In Austria, activation happens within five minutes at most. Unlike FCR, aFRR only acts within the control area where the imbalance occurs. Activation is automatic. For larger storage assets, aFRR is usually the most important revenue source alongside spot trading.
The tertiary reserve supports or replaces aFRR after around 12.5 minutes. It's activated manually and exists to free up the faster reserves again so they're ready for the next disturbance.
Two revenue streams, not one: providers of balancing power receive a capacity price simply for being available — even if never called on — plus an energy price for power actually delivered. The capacity price is predictable, which makes it especially valuable for financing.
Deep dive: prequalification, European platforms, and market risk
Before an asset can offer balancing power, it must be prequalified: the transmission system operator tests whether it reliably delivers the promised output fast enough. That's a months-long process and a hard requirement — in Hungary, for example, aFRR accreditation from the grid operator is a condition for the national storage subsidy programme.
The national markets are converging: PICASSO is building a shared platform for exchanging aFRR across borders. MARI is the corresponding project for a European mFRR platform, which already involved 32 transmission system operators as of June 2023. Both platforms launched with 15-minute time slots and uniform marginal pricing across all participating countries.
The risk: balancing prices are scarcity prices. When many new batteries connect at once, prices fall fast. A business model built purely on today's FCR or aFRR prices is vulnerable to that build-out — which is why most projects rely on a mix of revenue streams, known as revenue stacking.
Chapter 5
Imbalance energy: the bill for deviations
Anyone who feeds in more or less than scheduled gets billed for the difference. It isn't a penalty — it's a price, and it can run in either direction.
The logic is simple: the grid operator had to balance the deviation and passes the cost on to whoever caused it. But anyone who happens to deviate in the right direction — feeding in more precisely when the system is short of energy — has helped the grid, and gets paid.
Deviating against the system
You feed in less than scheduled while the grid is already short of energy. The operator has to call on expensive reserves. You pay.
Deviating with the system
You feed in more than scheduled exactly when energy is short. You've relieved the reserve. You get paid.
For a storage asset with no fixed schedule, the line between "trading" and "imbalance energy" blurs: if nothing was scheduled, all the energy dispatched counts as a deviation — and is settled accordingly. That can be a viable business model, but it's considerably more volatile than a planned schedule.
Deep dive: why imbalance prices can run wild
Imbalance prices are driven by the cost of the most expensive reserve called on. When little reserve is available, they can spike to extreme levels. Hungary experienced this first-hand: after the price cap on positive aFRR and mFRR energy prices was removed, while a cap of −50,000 HUF/MWh remained in place for negative balancing energy, perverse incentives emerged. The background was that growing renewable output had already pushed conventional power plants out of the day-ahead merit order, so through the second and third quarters of 2023 they ran mainly on the reserve market instead — with the effect that the available spinning reserve kept shrinking.
The regulator responded with a new cap: it's benchmarked to the clean spark spread, applies only when the market is classified as concentrated under the HHI index, and is measured every 15 minutes. The grid operator also introduced incremental bidding, letting a 200 MW unit submit 200 separate per-megawatt price bids instead of one bid for the whole block.
Rule of thumb for evaluating a storage project: imbalance-energy revenue is real, but it depends on rules that can change — and in Hungary, they recently have, more than once.
Chapter 6
From revenue to available cash
A monthly statement is made up of a good dozen line items. Click one to see what's behind it.
Charge cheap, discharge expensive. The most classic revenue source, and the only one that works without any accreditation or prequalification. The achievable margin tracks the daily price spread directly — the more solar on the grid, the wider that spread gets.
Payment for simply standing ready to deliver power on call. Paid even if never activated. Because this revenue is predictable, it carries disproportionate weight in financing — banks treat it differently from trading revenue.
Payment for energy actually called on. Can be very high, but isn't predictable: whether and how often it's activated is decided by the grid operator based on system needs.
Billing for the deviation between the schedule and actual dispatch. Can be revenue or cost, depending on whether the deviation helped or hurt the system. For assets with no schedule, this is effectively the main revenue line.
The marketer keeps a margin, usually a percentage of the exchange price plus a fixed amount per MWh. Watch the basis it's calculated on: it often applies to the gross volume in both directions, not the net.
A charge from the grid operator for using the network. The most politically contentious line item for storage — if it applied on both charging and discharging, the asset would pay twice for the same kilowatt-hour. Several countries offer time-limited exemptions for exactly this reason.
Levies for the grid operator's system services. In some settlement models, already bundled into the trading statements — always check before recording it in your own model, or you'll double-count it.
Maintenance, insurance, land lease, monitoring, administration. Largely fixed, which is why a single weak trading month quickly turns a project negative: the costs keep running even when revenue doesn't.
Principal and interest. Usually the largest single line item for debt-financed projects. What matters isn't the amount alone, but whether cash flow reliably covers it — which is exactly what the bank measures via the debt service coverage ratio.
The trap with trading fees: many fees aren't based on the net of charging and discharging, but on the sum of both directions. A battery that charges 100 MWh and discharges 90 MWh has a net of 10 MWh — but a fee-liable gross volume of 190 MWh. Confusing the two in a model will understate costs many times over.
Deep dive: what the bank wants to see
A debt-financed project isn't judged on profit, but on its ability to service its debt. The key metric is the debt service coverage ratio (DSCR):
A DSCR of 1.0 means it's exactly enough — no buffer. Banks typically require values well above that and attach consequences to it: distribution locks if the ratio falls short, and in extreme cases loan default.
Lenders often also require a debt service reserve account (DSRA): a locked account holding several months' worth of payments. During the ramp-up phase, surplus cash flows there first — nothing is distributed to shareholders until the account is full. This matters for liquidity planning: a project can be profitable and still pay out nothing in its first months.
Both sit in the loan agreement, not the security documents. Anyone building a cash flow plan should check these two points first — they determine which part of the money is actually free to use.
Chapter 7
The same battery, three legal frameworks
Technically identical assets pencil out differently in Hungary, Austria, and Germany. The biggest lever is almost always the same question: does the storage asset pay a grid fee on the electricity it stores?
Hungary
- Grid operator
- MAVIR Zrt. is the transmission system operator, HUPX is the power exchange. The regulator is MEKH.
- Market conditions
- Very high solar penetration paired with comparatively little storage — the daily price spread is correspondingly wide. Having broken into the world's top ten for solar capacity per capita, Hungary is now catching up on batteries too.
- Support scheme
- There's a national storage subsidy programme with clear conditions: at least 2 MWh per subsidised MW of storage capacity, at least 0.5 MW of storage power, at least ten years of availability retaining at least 70% of initial capacity, aFRR accreditation from the grid operator, and monthly reports to MEKH on actual revenue, costs, and activity.
- Notable
- The balancing market has been in flux recently — price caps and bidding procedures have been adjusted. So far, batteries mostly participate in the aFRR market as part of aggregators.
Austria
- Grid operator
- Austrian Power Grid (APG) operates the transmission network and the balancing markets. The regulator is E-Control.
- Balancing market
- The permanently reserved primary control reserve for the APG control area is ±75 MW for 2026, up from ±65 MW in 2025. Through delivery day 30 April 2026, the tertiary reserve stood at +205 MW positive and −195 MW negative. Procurement runs daily in six four-hour products, with a minimum bid size of 1 MW. The market is considerably smaller than Germany's.
- Legal framework
- The new Electricity Industry Act (Elektrizitätswirtschaftsgesetz) was passed by the National Council with a two-thirds majority on 11 December 2025, by the Federal Council on 17 December, promulgated on 23 December, and generally entered into force on 24 December 2025. It replaces the 2010 ElWOG and includes a dedicated chapter on energy storage. Some provisions, including the new system usage charges, take effect later.
- New for solar from 2027
- Operators of larger solar plants will pay a grid fee on feed-in — termed a "supply infrastructure contribution" in the law. Plants under 20 kW are exempt. From June 2026, new plants with grid-effective capacity from 3.68 kW must be remotely controllable by the grid operator.
- Support scheme
- The Renewable Expansion Act (EAG) supports solar through a sliding market premium. If the day-ahead price for the Austrian bidding zone goes negative for six or more consecutive hours, the market premium drops to zero for that entire period. That immediately raises the value of storage.
Germany
- Grid operator
- Four transmission system operators share the control areas, and balancing power is procured jointly. The regulator is the Bundesnetzagentur.
- Grid fee exemption
- Storage assets commissioned since 4 August 2011 are exempt from grid access charges on the energy they draw for storage, for twenty years, provided the electricity is taken from a grid and fed back into that same grid with a time delay. The legal basis is Section 118(6) of the Energy Industry Act (EnWG).
- What's changing right now
- The Bundesnetzagentur has dropped its initial plan to retroactively scrap the storage exemption; storage assets that reach final investment decision before the new rule takes effect, and that come online by 4 August 2029, keep their twenty-year exemption. The framework decision is scheduled for late 2026, with entry into force no earlier than 1 January 2027.
- Market size
- The region's largest balancing market — correspondingly high competition and noticeable price pressure from battery build-out. Business models relying purely on balancing revenue are seen as riskier here than they were a few years ago.
Important: the grid-fee question is currently in flux in all three countries. What's shown here reflects the position as of August 2026 and is explicitly no substitute for case-by-case review. For a twenty-year investment decision, regulatory change should be priced in as a risk of its own — not treated as a footnote.
Chapter 8
Glossary
Search for a term, its definition, or the abbreviation.
- Arbitrage
- Exploiting price differences over time: buy low, sell high.
- Automatic frequency restoration reserve aFRR
- Secondary control. Activated automatically, taking over from the primary reserve after about 30 seconds.
- Balance group
- A virtual account where feed-in and offtake from multiple assets are netted against each other.
- Balancing energy
- Payment for balancing power actually called on, as distinct from simply being available.
- C-rate
- The ratio of power to capacity. Describes how quickly a battery can be fully charged or discharged.
- Cannibalisation capture rate
- The effect where solar plants sell exactly when many others are also feeding in — and the price is low.
- Capacity price
- Payment for simply making balancing power available, regardless of whether it's ever called on.
- Day-ahead market
- The auction held the day before at noon, where most electricity is traded.
- Debt service coverage ratio DSCR
- Cash flow before debt service, divided by principal plus interest.
- Debt service reserve account DSRA
- A locked reserve account holding several months' worth of debt service payments.
- Degradation
- Age-related capacity loss in the cells, driven mainly by cycling and temperature.
- Duck curve
- The daily electricity price shape under high solar penetration: a midday dip, then a steep evening rise.
- Final schedule
- The last binding schedule submission before delivery. The reference point for imbalance energy.
- Frequency containment reserve FCR
- Primary control. Reacts within seconds and stops a frequency drop simultaneously across Europe.
- Full cycle
- One complete charge and discharge of the usable capacity. The benchmark for wear.
- Grid usage fee
- A charge for using the power grid. Contentious for storage, since it could apply twice.
- Imbalance energy
- Billing for the difference between the scheduled dispatch and what actually happened.
- Intraday market
- Continuous trading after the day-ahead auction, running until shortly before delivery.
- Manual frequency restoration reserve mFRR
- Tertiary control. Activated manually, freeing up the faster reserves again.
- Manually activated reserves initiative MARI
- A European platform for the cross-border exchange of mFRR.
- Market time unit MTU
- The smallest tradeable time slice. 15 minutes across Europe since 1 October 2025, down from an hour.
- Merit order
- The dispatch order of power plants, ranked by short-run marginal cost.
- Operating expenditure OPEX
- Ongoing operating costs: maintenance, insurance, land lease, monitoring, administration.
- Platform for aFRR exchange PICASSO
- A European platform for the cross-border exchange of aFRR.
- Power
- How fast energy can be absorbed or released, given in megawatts.
- Prequalification
- A technical approval test by the grid operator, required before an asset may offer balancing power.
- Revenue stacking
- Combining several revenue streams in a single asset to reduce dependence on any one market.
- Round-trip efficiency RTE
- The share of stored energy that's available again on discharge.
- Single day-ahead coupling SDAC
- A shared European algorithm that sets day-ahead prices and cross-border capacity simultaneously.
- State of charge SoC
- The battery's current fill level, usually expressed as a percentage of usable capacity.
- Energy capacity
- The total amount of energy that can be stored, given in megawatt-hours.
No matches. Try a shorter search term.
About this content. This interactive explainer was created with the assistance of Claude (Anthropic) and reviewed by our team. All numerical examples and the price curve in the simulator are stylised illustrations, not real operating data. Regulatory information reflects the position as of August 2026 and does not replace legal, tax, or financial advice for individual cases.
Sources include: EPEX SPOT and the European Commission on the 15-minute market time unit · MAVIR and MEKH on the Hungarian market · APG and E-Control on Austria · Bundesnetzagentur on Germany · FfE and Next Kraftwerke on balancing products.
