Technical questions and answers

RTE is the round-trip efficiency: if we charge 100 kWh of energy into the storage system, how much of it can we get back. For modern industrial lithium-ion systems, RTE is typically 86–92%, measured on the AC side — meaning the losses of the bidirectional converter are included. The loss leaves the system as heat, which is why active cooling of the containers is not optional. RTE is a key element of the arbitrage calculation: the net spread is not simply the difference between the discharge price and the charging price, but discharge price − (charging price ÷ RTE). At 88% RTE, energy bought at 100 EUR/MWh actually costs 113.6 EUR/MWh — arbitrage is only profitable above that level. A lower efficiency therefore requires a larger daily price difference for the same margin. RTE deteriorates slowly over the service life, and partial-load operation gives a somewhat better value than charging at maximum power. When comparing offers, always clarify whether the stated RTE is DC-side or AC-side — the difference between the two can be as much as 3–5 percentage points, which is significant in the payback calculation.

SOC is the current charge level of the storage system, expressed as a percentage. For daily cycles, manufacturers typically recommend a range of 10–90%: this is the usable capacity, roughly 80% of the nominal capacity. This is decisive for sizing: from a storage system with a nominal “1 MWh”, only ~0.8 MWh can actually be moved in a daily cycle. When comparing offers, always clarify whether the stated capacity is nominal or usable — mixing the two up causes a 20% sizing error. A wider SOC window moves more energy per cycle but accelerates degradation, which is why the manufacturer’s warranty is usually tied to a specific SOC range: operating outside it, a capacity claim can be rejected. The optimal window depends on the cell chemistry and the application — daily single-cycle arbitrage requires a different setting than rarely activated peak shaving or reserve services. In practice, it is the task of the energy management system (EMS) to adapt this range to the operating profile.

Cycle life tells you how many full charge–discharge cycles a cell can withstand while maintaining its guaranteed capacity retention. Industrial LFP (lithium iron phosphate) cells typically guarantee 6,000–8,000 cycles at 70–80% capacity retention; at one cycle per day, this means 16–22 years. The cell warranty usually runs for 10–15 years and covers both the cycle count and the capacity retention at the same time — whichever is exhausted first ends the warranty. There are two pitfalls when comparing offers. The first: the cycle count always belongs to a specific set of conditions (SOC window, C-rate, cell temperature), and if the operating profile falls outside them, the warranty does not apply. The second: capacity retention means that at the end of the warranty the storage system can deliver 70–80% of its nominal capacity — not that it operates at 100% all the way until then. The financial model must therefore work with a capacity that declines with degradation. Anyone who projects the first-year performance over the entire term significantly overestimates the result.

In an AC-coupled system, the storage has its own bidirectional converter (PCS — Power Conversion System) and connects on the AC bus. It is independent of the solar inverter, can be retrofitted next to an existing PV system, and works even when the sun is not shining — which makes it suitable for both grid arbitrage and peak shaving. In a DC-coupled system, the storage connects on the DC side of the solar inverter and uses a shared inverter. It is cheaper and makes better use of clipped PV surplus, because the energy does not pass through the converter twice — but the PV and the storage share the inverter’s power, and the storage can only charge when the PV is generating. For industrial systems sized for self-consumption, AC coupling is more common, because flexibility is worth more than a gain of a few percent in efficiency. One terminological clarification worth keeping in mind: the storage uses a bidirectional converter, not an inverter — an inverter is unidirectional (DC→AC), while a PCS works in both directions.

The C-rate is the speed of charging or discharging relative to the capacity. 0.5C means that the storage system can be fully charged or discharged in two hours — for example, a system with 1 MWh capacity at 500 kW of power. 1C means one hour, 0.25C four hours. The C-rate determines the ratio of power (MW) to capacity (MWh), and these two numbers together describe the storage system: neither is enough on its own to evaluate an offer. For intraday arbitrage and peak shaving in an industrial setting, 0.5C is typically sufficient, because in the HUPX price pattern the expensive and the cheap hours come in blocks of several hours — there is no point in emptying the storage in one hour. A higher C-rate requires a larger converter and stronger cooling, which makes it more expensive, and it also degrades the cells faster. Conversely: with a C-rate that is too low, the consumption peak cannot be shaved, however large the capacity. The right ratio should be derived from the site’s 15-minute consumption profile, not from a rule of thumb.

The capacity of lithium-ion cells declines for two mutually independent reasons. Cyclic degradation depends on the number of charge–discharge cycles, while calendar degradation depends purely on the passage of time — the latter happens even when the storage system is idle. For industrial LFP systems, the typical combined value is a capacity loss of 2–3% per year, which means roughly 80% retention after ten years. Three factors accelerate it the most: high cell temperature (which is why active cooling is needed), regular operation in a wide SOC window, and a high C-rate. This has a direct financial consequence: in its tenth year the storage system moves less energy than in its first, so the savings are not linear over the term. Manufacturers usually address this with augmentation (installing additional cells later) or with a guaranteed capacity curve — it is worth looking for this point specifically in the offer, because there is a significant difference between the two. Augmentation means a later cost, whereas a guaranteed curve shifts the risk to the supplier.

The industrial electricity price consists of two main blocks, and the two behave quite differently. The first is the commercial charge (energy charge), which we pay to the supplier: the unit price of energy, the excise tax, the energy efficiency contribution, and the KÁT, premium and storage fund surcharge. The second is the network usage charge, which is regulated by MEKH and paid via the distribution system operator: volumetric charges proportional to consumption (HUF/kWh) and fixed charges payable on the contracted capacity (HUF/kW/year). Together the two make up the all-in price, and the distinction matters for savings. Solar reduces the consumption-proportional items — the energy charge and the volumetric charge — but not the contracted capacity charge, because that is determined by the peak load. Only an actual reduction of the peak lowers it, typically with battery storage. That is why the payback of an investment cannot be calculated with a single average HUF/kWh value: it depends on which items of the bill it replaces.

Four elements. (1) The unit price of energy — under a fixed-price contract it is the same every hour; under a spot contract it follows the HUPX day-ahead market price, in 15-minute resolution. (2) The KÁT, premium and storage fund surcharge, which covers the funding of the support scheme for renewable generators. It changes monthly based on MAVIR’s actual data, and it is typically higher in summer. Importantly, it is variable even under a fixed-price contract — it is the only non-fixed component, and customers who choose a fixed price often do not account for it. (3) Excise tax, regulated and fixed. (4) Energy efficiency contribution, also regulated. KÁT and premium are two different support schemes: KÁT means a guaranteed feed-in price, the premium a markup above the market price — the consumer, however, pays the combined surcharge of the two. From January 2026 the storage fund appeared as a third element. The monthly actual figures can be followed month by month on ICP’s KÁT/premium tracker.

Yes. From January 2026, alongside the KÁT and premium funds, the storage fund appeared as a third support element, intended to cover the cost of system-level integration of energy storage capacity. Based on MAVIR’s actual data for the first half of the year, its rate ranged between 0.03 and 0.21 HUF/kWh, on a rising trajectory — orders of magnitude smaller than the KÁT/premium surcharge, but worth following because of the trend. Its practical significance is twofold. First, it is also one of the consumption-proportional items, so every kWh replaced by solar saves this as well. Second, as more and more storage capacity is integrated into the Hungarian system, this component is expected to grow — meaning that the specific cost of energy drawn from the grid rises, which increases the relative value of own generation. The exact monthly values come from MAVIR’s publications and can be followed on ICP’s data hub.

Under a fixed-price contract, the unit price of energy is the same every hour. The supplier builds its risk premium into it, so it is more expensive on average but predictable in return. Under a spot (HUPX-indexed) contract, the price follows the day-ahead market price in 15-minute resolution: it is cheaper on average, but the consumer bears the full volatility. The choice has a direct consequence for how much each technology is worth at the site — and the relationship is inverse. Solar saves more under a fixed-price contract, because every kWh it replaces displaces the expensive, flat unit price; under a spot contract, however, it generates precisely in the cheapest hours, since the HUPX price is typically low in midday sunshine, so it saves less per unit. With battery storage it is exactly the opposite: it is valuable under a spot contract, because the intraday price difference is the source of arbitrage, whereas under a fixed-price contract there is nothing to arbitrage. That is why the combined installation of solar and storage is, overall, strongest for customers with spot contracts.

The network usage charge consists of two types that behave differently. (1) Volumetric charges in HUF/kWh, payable on actual consumption: the uniform transmission volumetric charge (3.39 HUF/kWh in 2026) and the distribution volumetric charge, which depends on the connection voltage level. Solar reduces these directly, since every kWh generated on site means that much less drawn from the grid. (2) Contracted capacity charges in HUF/kW/year, payable on the contracted capacity — even if the capacity is not used. Solar does not reduce this, because the contracted capacity is determined by the peak load, which typically does not fall in sunny periods; this item can be reduced with battery storage, by shaving the peaks. In addition, there is a basic charge (HUF/connection point/year) and a reactive energy charge (HUF/kVArh). Importantly, the network usage charge does not depend on whether the commercial contract is fixed-price or spot: it is regulated by MEKH and is the same in both cases.

The higher the voltage level at which a consumer connects, the lower its specific distribution charge — it uses less distribution network infrastructure. For time-series settlement, according to MEKH’s 2026 tariff decree, the distribution volumetric charge is 1.98 HUF/kWh at high voltage (NF), 3.42 at high/medium voltage (NF/KÖF), 8.39 at medium voltage (KÖF), 14.92 at medium/low voltage (KÖF/KIF), and 22.20 HUF/kWh at low voltage (KIF). At every level, the uniform transmission volumetric charge of 3.39 HUF/kWh is added to this. Most industrial customers connect at medium voltage, where the total volumetric charge is therefore 11.78 HUF/kWh. The contracted capacity charge follows a different logic and is not monotonic: NF 2,376, NF/KÖF 8,004, KÖF 15,924, KÖF/KIF 16,608, KIF 13,248 HUF/kW/year. It is worth knowing that from 2025 to 2026 the total volumetric charge decreased by exactly 2.33 HUF/kWh at every voltage level, while the basic charge, the capacity charge and the reactive charge remained unchanged.

In time-series settlement, consumption is actually metered in 15-minute intervals, and the bill is based on these data. This is the industrial standard, and its tariff rates are lower. In profile-based settlement, there is no 15-minute metering: consumption is allocated according to standard, statistically based profiles, and the tariff rates are higher — this is typical for smaller consumers. The difference matters for two reasons. First, in the tariff level: on a time-series medium-voltage connection the total volumetric charge in 2026 is 11.78 HUF/kWh, whereas with profile-based, low-voltage all-day settlement it is 23.40 HUF/kWh — roughly double. Second, in predictability: a spot-price contract and battery storage arbitrage only really work with time-series metering, because 15-minute settlement is their basis. If a profile-based customer can provide 15-minute data from a sub-meter, we use it in the simulation for sizing — the settlement and the tariff rates, however, continue to follow the profile-based tariff.

The contracted capacity charge is paid on the contracted capacity, regardless of whether we use it. The storage system reduces this item by discharging during consumption peaks, so the peak power drawn from the grid becomes lower — this is called peak shaving. If, based on the permanently lower peak achieved this way, the contracted capacity can also be reduced in agreement with the distribution system operator, that is an immediate saving that recurs every year. In terms of magnitude: on a medium-voltage connection the contracted capacity charge in 2026 is 15,924 HUF/kW/year, so a 100 kW peak reduction means an annual saving of roughly HUF 1.6 million — and this is completely independent of how much energy the storage system moves. Two conditions, however, are essential. The reduction must be reliable: a single missed peak shave can override the entire annual contracted capacity. And sizing requires the site’s 15-minute profile, because the frequency and duration of the peaks decide how much capacity is needed.

Both deliver the same system, but ownership and risk sit in different places. With EPC (Engineering, Procurement, Construction), you finance the investment, the system becomes your property and goes on your balance sheet, and the full savings are yours from day one — as are the technical risk beyond the scope of the warranties and the responsibility for operation. This is the right choice if the investment budget is available and the company wants to keep the asset under its own control. With Energy Infrastructure as a Service, ICP designs, builds, finances and operates the system, and you pay a service fee for the available infrastructure. No investment of your own is required, and availability and technical performance are contractual obligations on the service provider’s side. At the end of the contract period, the system can be purchased. Which of the two routes delivers the better result depends on the site’s consumption profile, the tax position and the investment policy — this is best compared with concrete numbers after a site survey.

The two are different in nature: the Jedlik Ányos Program is a non-repayable grant, while the allowance under TAO Act 22/H. § is a corporate tax allowance, which can be claimed in the tax year in which the battery storage is commissioned or in the following tax year, and then in the subsequent five tax years. They can be combined, but the maximum aid intensity under the EU General Block Exemption Regulation (GBER) applies to the combined amount of the two: 50% for small enterprises, 40% for medium-sized enterprises and 30% for large enterprises. In other words, if the grant does not provide support up to the ceiling, the difference can be filled with the TAO allowance — but it is not possible to go above the ceiling. One frequently overlooked limitation: for the same investment, 22/H. § cannot be cumulated with the 22/E. § (energy efficiency) or the 22/B. § (development) allowance. As separate investments, however, it can — for example, 22/H. for the storage and 22/E. for the solar system. A further condition is that a valid grid connection agreement and network usage agreement must be in place by the filing of the tax return for the tax year of first use.

Approximate breakdown: panels 35–40%, inverters 10–15%, mounting structure 10–12%, cabling and electrical fittings 8–10%, labor 15–20%, design and permitting 5–8%, grid connection 3–5%. These are indicative proportions — the actual split is significantly affected by the site’s conditions. The specific price (EUR/kWp) decreases with system size, because the fixed costs (design, permitting, mobilization, connection) are spread over a larger capacity. Two items cause the largest variation, and these two produce the most surprises when comparing offers. The first is the grid connection: if a new connection point or transformer is needed, this item can be a multiple of the range above. The second is the condition of the roof structure — structural reinforcement or waterproofing renovation is not a cost of the solar system, but it is a cost of the project. That is why every ICP offer starts with an on-site survey: without it, the specific price is only an estimate, not an offer.

Approximate breakdown: cells and modules 50–55%, PCS (bidirectional converter) 15–18%, BMS and EMS 5–8%, container, rack and cooling 8–10%, cabling and protection 5–8%, installation 5–8%. For storage, the specific price is driven mostly by three parameters, and all three are the result of technical decisions. The first is the C-rate: at the same capacity, higher power requires a larger converter and stronger cooling, which increases the PCS and cooling items. The second is capacity — economies of scale apply here too. The third is the cell warranty: a warranty with a longer term and higher promised capacity retention means a more expensive cell. For this reason, a bare EUR/kWh figure is misleading: without knowing the nominal and usable capacity, the guaranteed cycle count and the C-rate, two quotes cannot be compared. The fire protection design, which is determined by the installation location and its surroundings, can be a separate item.

The EXIM Green Investment Loan is a fixed-rate investment loan product available under the Demján Sándor Program, which can also be used to finance the own-contribution portion of a Jedlik Ányos grant. The term is up to 15 years, and the product can even be used without any own contribution. The interest rate depends on the currency: in the range of 2.7–4.7% for euro loans and 3.46–5.46% for forint loans. This product suits an energy investment well because its term matches the life of the asset — a solar system generates for 25–30 years, a battery storage system operates for 15–20 years, so a 15-year term does not overburden cash flow. In terms of aid intensity, the aid content of a subsidized-rate loan may count toward the GBER ceiling, so when it is used together with a grant and the TAO allowance, it is worth calculating the combined intensity in advance. The terms of the product may change — always check the current product description before applying.