The development of the electricity sector has been driven by various factors in recent years, largely powered by the EU’s low-carbon policies and the national vision for their implementation. Currently, energy efficiency efforts in the country are focused primarily on the widespread adoption of energy-efficient appliances, the modernization of technical installations, and the introduction of new technologies for managing electricity consumption. Parallel to these efforts is the electrification of transportation, as well as the transition to using electricity for heating and cooling. It is difficult to predict which of these processes will become sustainable over time and how they will combine, but it is precisely for this purpose that scenarios are being developed to help identify the challenges facing the development of the energy system.

This year’s draft of the ten-year network development plan (2026–2035), published in the second half of March, once again primarily considers two scenarios for the development of electricity consumption in the country—a minimum and a maximum scenario. There are no changes to the projected consumption growth rates compared to the forecast in the ten-year plan (2025–2034) approved by the Energy and Water Regulatory Commission (EWRC). Traditionally, the “minimum scenario” is based on assumptions of intensive implementation of energy efficiency measures. Electricity consumption (excluding pumps and storage) is projected to remain stable over the entire period, with an increase of 700 GWh by the end of 2030. In contrast, the “maximum scenario” projects a total increase of 1,600 GWh over the next four years. The forecast for this scenario is based on the trend of the European Commission’s reference scenario for final electricity consumption in the country for the period 2015–2025, assuming a delay in the implementation of innovative measures to improve energy efficiency.

What type and how many capacities will work in the country?

A forecast for the development of generation capacity, based on investment plans announced by power generation companies, indicates a slower pace of construction for new wind, solar, biomass, gas, and cogeneration plants compared to last year’s forecast. Investor interest is shifting toward energy storage systems. Based on the updated forecasts, calculations show that by the end of 2030, 7,160 MW of new capacity from electricity storage facilities (ESFs) will be connected to the grid. This represents over 90% of the projected new capacity for the 2026–2035 period. Just a year ago, the forecast projected 4,922 MW by the end of 2030.

New generation capacity by source type, based on investment intentions, in MW

	2026	2027	2028	2029	2030	2031	2032	2033	2034	2035	Total for the period
Gas & Cogen plants	21	80	45	2	9	2	42	262	242	218	921
BESS	4724	1597	190	179	470	150	150	50	50	50	7610
RES, incl.	2743	2631	974	636	462	235	1735	135	1735	135	11422
HPPs	1	5	0	0	0	0	1600	0	1600	0	3206
Wind Plants	81	300	140	3	208	3	3	3	3	3	747
Solar (PV) plants	2661	2325	834	632	246	231	131	131	131	131	7452
BioPlants	1	1	1	1	8	1	1	1	1	1	17
Total	7488	4309	1209	817	941	387	1927	447	2027	403	19952

Source: Draft Ten- year grid development plan, March 2026, ESO

Regardless of the information received, the grid development plan is based on the installed capacities specified in National Energy and Climate Plan (NECP). The data has been refined to reflect the currently connected capacities, with the necessary adjustments made for specific technologies: it has been noted that for PV and BESS, the NPEC design capacities are already being exceeded, while for wind power plants, the pace of development is significantly slower than initially anticipated. The end of the forecast period also anticipates the emergence of new nuclear capacity, which, due to its highly concentrated nature, has a significant impact on the grid configuration.

A new feature of the draft EU plan is the inclusion of maps showing the distribution of installed renewable energy capacity (solar PV, wind power, hydropower, and biomass) by municipality for 2030 (the EU target), as well as energy storage systems (battery energy storage systems and pumped-storage hydroelectric power plants).

The NECP plan envisages coal-fired power plants to remain part of the portfolio without being completely shut down and their capacity to be activated as needed. Their annual electricity generation of 8 TWh is projected to gradually decrease year by year to 0.5 TWh. In practice, however, without financial support, coal-fired power plants will not generate electricity for economic reasons. This effect has been noticeable since mid-2019 and has since raised the issue of diversifying and ensuring the security of the electricity system through domestic energy resources.

The ESO’s analysis of power balances highlights a significant imbalance between the capacity to meet domestic demand and the potential for electricity exports. During the winter months, there will be a need to import electricity at competitive prices. Conversely, the summer season is characterized by a significant production surplus, the sale of which on external electricity markets is directly dependent on renewable energy production, specifically from photovoltaic power plants (PVPPs). The sale of this surplus generation capacity as exports can be achieved provided there are good forecasts for hourly RES electricity generation and the implementation of expert economic strategies, including long-term contracts and integration with the BESS. The lack of flexible participation by local producers in regional markets poses a risk not only of missed export benefits but also of the entry of competitive electricity imports

Flexibility of production capacity and the ability to address potential issues

The specific variable nature of the primary energy source for thermal power plants and wind power plants makes it difficult to maintain a balance between production and consumption. Our country’s geographical location does not allow for the complete replacement of coal-fired condensing power plants with RES, despite the significant growth in installed capacity of this type. The design characteristics of renewable sources and their intermittency do not allow for the reliable supply of power to heavy industry facilities (e.g., electric arc furnace production), which require high stability of electrical power parameters. There are challenges to the security of the electricity system regarding the continuous (24/7) maintenance of frequency and power exchange capacities, maintaining voltage within permissible limits, system stability and inertia, as well as the suppression of low-frequency active power oscillations.

The decommissioning of units at large condensing TPP will deprive the Bulgarian power system of its key ability to restore power using its own generating sources (“black start”). Due to their technologically limited capacity, small power plants cannot ensure the formation of energy recovery corridors in the country, but can meet local energy needs.

In the event of a collapse of the country’s power system following a major accident, restoration is carried out by ESO dispatchers in accordance with the “Major Accident Recovery Plan.” The priority option for restoring our power system is through the formation of power corridors from neighboring power systems to specific Bulgarian power plants on a “top-down” basis, with assistance from neighboring power systems. If no neighboring power system is able to provide electricity assistance to Bulgaria, a second option is used, involving the formation of primary energy corridors on a “bottom-up” basis. This principle involves the phased restoration of the power system from initial hydroelectric power plants to priority thermal power plants. Such priority TPPs include Units 5 and 6 of the Maritsa East 2 TPP, Units 3 and 4 of the Contour Global – MI3 TPP, and Units 2 and 3 of the Bobov Dol TPP. The draft 10-year plan does not explain why AES Maritsa East I TPP is not included, even though it is more modern than the other two large TPPs in the Maritsa East complex and possesses the necessary technological capabilities.

BESSs can provide a “black start” and contribute to island formation, but due to technological limitations on battery capacity, this capability of BESS cannot be used to form energy restoration corridors, but only for local needs.

If the units at the large condensing thermal power plants are decommissioned, the Bulgarian power system will lose its ability to restore balance using its own generation sources.

ESO notes existing issues with voltage regulation at the point of connection for energy storage systems when they are operating in charging mode. BESSs exploit market price differentials and switch from one mode to another very quickly and simultaneously. This can lead to low voltages and increased technical losses for the system operator.

To ensure sufficient and flexible development of generation capacity, additional measures must be taken. Some of these measures, which are a priority for the ESO and the IBEX, are market-based and have already been implemented, while others are to be implemented in the coming years. Among the possible additional solutions mentioned is the establishment of a mechanism to maintain a critical minimum of synchronous capacity through the implementation of market-based or regulatory instruments to ensure the continuous operation of the necessary fleet of synchronous generators to provide inertia and reactive power.