Over the past few weeks, through our work with clients, I have been following a new round of renewals of commercial electricity supply agreements with Elektroprivreda Srbije (EPS). In practice, EPS most often concludes these agreements for twelve months, which means many companies are setting one of their key operating costs for the next business year right now.

What stands out this year is the price. In several renewal offers we have had the opportunity to review, the electricity price for the next contractual period is roughly 30–40% higher than in the previous period.

A handful of offers is, of course, not a market-wide statistic. Still, it is hard to ignore that this is happening in a year when several unfavorable circumstances have come together and are directly affecting EPS and the wider market. The first is the hot and dry summer, which showed very clearly how exposed our power system becomes when hydrology underperforms, consumption increases, and part of the missing electricity has to be sourced on the market.

EPS itself confirmed this during August, when it was reported that HPP Djerdap 1 was producing only around 20% of its usual output and Djerdap 2 around 30%, with historically low Danube inflows. During the same period, daily consumption was expected to rise to around 100 GWh.

There is not much to overthink here: if you produce less while consumption rises, it is only logical that the difference has to be secured elsewhere, for example by purchasing electricity on the market.

On the other hand, the definitive CBAM regime has been in effect since 1 January 2026 and has made electricity exports from Serbia to the European Union significantly less profitable. In June, I came across a statement by the CEO of EPS that in previous years EPS had exported an average of around 1,000 GWh per year to the EU, worth approximately EUR 150 million, while after CBAM took effect, that export has practically disappeared.

This has significantly reduced EPS’s ability to place surplus electricity on the EU market when prices there are more favorable. Imports and exports, of course, do not offset each other megawatt-hour for megawatt-hour, but they are part of the same portfolio. Revenue and margin earned in favorable periods can soften the cost of periods when missing electricity must be purchased on the market. If poor hydrology increases the need for market purchases while CBAM limits profitable exports in the same year, this combination clearly puts additional pressure on EPS.

But neither the drought nor CBAM is the real core of the problem. They mainly expose how vulnerable the system is when new-generation capacity development does not keep pace with market changes.

Just to be clear, I am not talking here about theoretical capacity, i.e., megawatts that exist only on paper. Looking only at those figures, one could even say that the situation is not so bleak: ten new projects with a total capacity of 645 MW received support in the second round of market premium auctions, while, according to Elektromreža Srbije, around 11 GW of new wind and solar capacity is currently in the transmission grid connection process.

However, megawatts in an auction or a connection process do not help today’s power balance until the projects are actually built and connected. There is still a long way to go, and it will require greater support from the state and a much more efficient public administration.

More importantly, developing new projects is becoming more difficult at precisely the moment when development needs to accelerate. CBAM has changed the conditions of regional electricity trading and narrowed access to more profitable exports to the EU, while the domestic market for long-term PPAs is still not sufficiently developed to give investors a stable electricity sales model for project financing.

And this brings us to the last part of the equation: the corporate PPA market. A PPA is not the right solution for every buyer or every project, but it is one of the key market mechanisms through which a large consumer can make part of its energy cost more predictable over the long term, while giving a renewable energy investor the more stable revenue needed to finance a project.

At first glance, this may look like a problem for the power system and the state. However, rising electricity prices show that the burden ultimately falls on businesses and, indirectly, on consumers. A large part of the Serbian economy still buys electricity through relatively short-term supply agreements, meaning that market risk returns to the buyer every twelve months. If an agreement is renewed at an unfavorable moment, the company has to build a materially higher energy price into its budget for the next year and, where possible, into the price of its products or services.

What, then, are the practical solutions?

The answer is not simple.

Larger consumers should certainly consider developing their own generation capacity in order to reduce the amount of electricity they purchase from a supplier. Since the prosumer model for businesses is limited to 150 kW, this simple, practical self-supply model is, as a rule, insufficient for large consumers. One possible solution for them is the active customer model, for which the regulatory framework has recently been completed.

However, this is still a relatively new model, and it remains to be seen how it will work in practice, particularly regarding grid connection and, most importantly, the cost of balancing responsibility, acquiring balancing responsible party status, and system access charges.

A second solution is a more direct link between businesses, i.e., large consumers, and investors planning to build new generation capacity. Long-term PPAs can help both sides: they give the buyer greater predictability of electricity costs, while giving the investor greater revenue certainty and making project financing easier.

The problem is that both of these solutions take time. A power plant cannot be designed, built, and connected within a few months, and a serious long-term PPA is not negotiated overnight either.

So what can a company whose electricity supply agreement expires now actually do?

First, it should not focus only on a single number in an offer based on a fixed price per MWh. Other contracting models already exist, including SEEPEX-linked contracts and hybrid models in which part of consumption is contracted at a fixed price, and part remains linked to the market price.

Such a model does not, of course, automatically mean cheaper electricity. For a company that can manage its consumption more actively, however, it may mean that it does not have to lock its entire annual consumption at one price precisely when market conditions are unfavorable.

Although this is not an ideal solution, it can serve as a transitional one until companies build their own capacity and the PPA market becomes more developed.

What is fairly clear, however, is that businesses already under pressure from other costs face another difficult year, in which electricity will remain a significant item in their operating budgets.