Towards Net Zero in Poland: A Novel Approach to Power Grid Balance with Centralized Hydrogen Production Units

Abstract

The net zero emissions policy represents a crucial component of the global initiative to address climate change. The European Union has set a target of achieving net zero greenhouse gas emissions by 2050. This study assesses Poland’s feasibility of achieving net zero emissions. Currently, Poland relies on fossil fuels for approximately 71% of its electricity generation, with electricity accounting for only approximately 16% of the country’s total final energy consumption. Accordingly, the transition to net zero carbon emissions will necessitate significant modifications to the energy system, particularly in the industrial, transport, and heating sectors. As this is a long-term process, this article demonstrates how the development of renewable energy sources will progressively necessitate the utilisation of electrolysers in line with the ongoing industrial transformation. A new framework for the energy system up to 2060 is presented, with transition phases in 2030, 2040, and 2050. This study demonstrates that it is feasible to attain a sustainable, zero-emission, and stable energy system despite reliance on uncontrolled and weather-dependent energy sources. Preparing the electricity grid to transmit almost three times the current amount represents a significant challenge. The resulting simulation capacities, comprising 64 GW of onshore wind, 33 GW of offshore wind, 136 GW of photovoltaic, 10 GW of nuclear, and 22 GW of electrolysers, enable a positive net energy balance to be achieved under the weather conditions observed between 2015 and 2023. To guarantee system stability, electrolysers must operate within a centralised framework, functioning as centrally controlled dispatchable load units.

1. Introduction

The net zero policy is a cornerstone of global efforts to mitigate climate change. By 2050, the European Union (EU) aims to achieve zero greenhouse gas (GHG) emissions, a target formalised with the adoption of the European Green Deal [1]. An intermediate milestone requires a reduction in GHG emissions by at least 55% by 2030 compared to 1990 levels. In 2022, the total GHG emissions in the EU reached 3.14 Gt CO_2-eq. [2], while Poland’s emissions amounted to 380.5 Mt CO_2-eq., including 315.4 Mt CO₂ [3]. Meanwhile, China, responsible for 30% of global CO₂ emissions in 2023 (11.9 Gt CO₂) [4], has committed to achieving net zero emissions by 2060 [5]. Major companies like Microsoft and IKEA also align with net zero policies [6].

The scientific community is working to identify the best path towards the elimination of GHGs. Climate models predict changes and assess mitigation strategies, emphasising the importance of achieving negative CO₂ emissions [7,8]. Various methods, including carbon dioxide capture [9] and storage technologies [10], are being developed alongside advancements in energy storage, such as hydrogen [11], battery systems [12], pumped hydro storage (PHS) [13], or compressed air energy storage (CAES) [14]. Innovations in renewable energy technologies—solar [15], wind [16], and geothermal energy [17]—are also progressing. However, detailed research is lacking on systems that can efficiently manage energy generated from intermittent sources, such as wind and solar power, especially in the absence of demand-side regulations. In energy systems dominated by weather-dependent sources, balancing demand without imposing consumer restrictions is the primary challenge. Research is needed to develop models and strategies for efficient energy supply and demand management while maintaining reliability without imposing restrictions on consumers.

Currently, Poland’s power system operates with complete consumer freedom in electricity usage. Demand is balanced by Centrally Dispatched Generating Units (CDGU), primarily thermal power plants fuelled by coal, lignite, and natural gas [18]. Transitioning to a zero-emission system requires replacing these units with alternative solutions. Sole reliance on nuclear power is not viable, as these plants operate at a constant output with limited flexibility in adjusting power levels. CDGU must quickly adapt their production to match the current demand in the power system. Furthermore, nuclear power plants are costly and time-consuming to construct compared to renewable energy sources (RESs) [19].

Adapting the power system to weather-dependent energy sources necessitates new management principles. A critical step involves transferring the responsibility for system balance to energy consumers. Additionally, post-transition, industrial sectors will require significant hydrogen resources. In 2022, the production and consumption of hydrogen in Polish industries (primarily from natural gas) totalled 1 Mt [20]. Hydrogen is an important industrial feedstock, for which there are often no substitutes (e.g., fertiliser production). In this study, electrolysis was selected as the method for zero-emission hydrogen production, as other methods of hydrogen production are not at such a high level of readiness for implementation or are based on thermochemical biomass processes. In this study, it is assumed that 100% of the domestic biomass that can be used for biogas production is, in fact, used to produce biomethane, which, by powering electricity generators, supplements the shortfall in production from RESs. Integrating hydrogen production electrolysers into the power system could address the dual needs of system balancing and hydrogen demand. To achieve this, electrolysers must operate as part of the centralised power system, aligning their use with system requirements, especially for managing electricity surpluses.

The aim of this article is to present and analyse concepts for creating a sustainable and stable power system in Poland based on weather-dependent energy sources without imposing energy consumption restrictions on individual consumers and industries. This analysis covers 2024–2060 and shows the final result of net zero emissions in Poland achieved through power grid balance with centralised hydrogen production units.

2. The Current State of the Power System in Poland

In 2023, Poland’s energy supply was primarily based on fossil fuels: 36% from coal, 33% from oil, and 16% from natural gas. At the same time, about 71% of electricity was generated from fossil fuels (around 60% from coal and about 11% from natural gas). The share of electricity in total final energy consumption was only about 16% in 2022. Decarbonising key sectors—transport, heating, and industry—will necessitate substantial investments and the development of complementary solutions, such as hydrogen utilisation, advanced energy storage systems, and transmission infrastructure modernisation. Poland is gradually transitioning toward renewable energy, despite significant reliance on domestic coal resources [21]. The photovoltaic (PV) market is among the fastest-growing in the EU, with increasing adoption of heat pumps and ambitious plans for offshore wind energy. By 2030, Poland aims to achieve at least 3.4 GW of offshore wind capacity [22].

At the end of 2023, Poland’s installed power capacity totalled 67.8 GW, with 40.6 GW coming from conventional power plants and 27.2 GW from RES. The average annual demand was 23.1 GW, peaking at 27.3 GW [23]. Peak demand occurs during winter (from November to February), while the lowest demand is recorded between May and August (Figure 1).

Electricity production in 2023 reached 163.6 TWh, a 7% decrease compared to 2022 [23]. The changes in national electricity production between 2014 and 2023 are shown in Figure 2. In 2023, the production from conventional thermal power plants returned to 2020 levels and amounted to 128.4 TWh.

At the beginning of 2024, wind power capacity reached 9.43 GW, with annual growth exceeding 1 GW in recent years (

Table 1. Annual increase in installed RES capacity in 2014–2023 in Poland, GW/y [27,28].

Year	2014	2015	2016	2017	2018	2019	2020	2021	2022	2023
Wind onshore	0.44	0.75	1.23	0.04	0.01	0.06	0.43	0.77	1.18	1.13
PV	-	0.06	0.10	0.08	0.24	0.96	2.44	3.87	4.65	4.66

). In March 2024, Poland had 1400 onshore wind installations, with large wind farms (>30 MW) contributing approximately 7 GW [24]. The total potential of the Polish part of the Baltic Sea is estimated to be 33 GW [25]. The first offshore wind farms are expected to begin production in 2026. By 2040, offshore wind capacity could provide 11 GW to the national grid [26].

By early 2024, Poland’s PV capacity had reached 17.1 GW. Micro-installations (<50 kW) accounted for 64%, small installations (50–1000 kW) for 25%, and large farms (>1 MW) for 11%, equating to approximately 1.6 GW. By March 2024, the total RES capacity exceeded 29 GW, with PV installations contributing 60% [27]. In recent years, PV capacity has grown annually by over 4.5 GW (Table 1).

Currently, Poland has no operational nuclear power plants, similar to 14 other EU countries [29]. The formulation of plans is currently in progress to build six pressurised water reactor (PWR) units, with a total capacity of 6–9 GW, by 2040 [30,31]. An alternative could be small modular reactors (SMRs), with powers of around 300 MW, which offer a flexible alternative for regions with high energy demand and limited RES potential [32]. Poland’s grid development plan includes three SMR units, totalling 0.84 GW, by 2034 [33].

In Poland, biogas and biomethane are produced at landfill sites or are generated from sewage sludge, agricultural and municipal waste, slurry, and manure [34,35]. In 2021, Poland produced 622.98 million m³ of biogas from landfill gas collection systems (107.43 million m³), sewage sludge fermentation systems at 100 wastewater treatment plants (153.74 million m³), 128 installations processing 4.9 million tons of agricultural waste (342.91 million m³), and from municipal waste composting and fermentation systems (15.65 million m³). This allowed for the production of 1345.58 GWh of electricity and 5383.47 TJ of heat [34]. Despite ranking fifth in biogas electricity production among EU-27 countries [36], Poland’s output is far below Germany’s, which generates 23 times more electricity with comparable substrate potential. Based on biogas efficiency studies conducted on nearly 3500 different substrates and analyses of the potential of the agricultural sector, Poland’s biogas production potential is estimated at 13.5 billion m³ (equivalent to 7.8 billion m³ of biomethane) [37]. Another 10.8 billion m³ of biogas could be produced following Germany’s example and using 5% of the national farmland for energy crop production. Unlocking this potential requires changes in waste logistics, biogas purification technologies, and alternative methods such as biomethanisation or cryogenic separation [35]. Legal reforms, public awareness campaigns, and financial support are also essential [37]. Regarding the environmental impact of biomethane production, it is worth noting that it is primarily based on the use of biodegradable waste materials. The controlled management of these materials is likely to have a positive environmental effect.

3. The Methods of Simulation

Calculations were conducted using an energy system simulator developed by the Polish governmental institution, the National Centre for Research and Development (NCBR) [38,39]. The model’s input parameters were calculated using MS Excel and MATLAB R2020b for various simulation time horizons, namely 2030, 2040, 2050, and 2060. In the process, three different scenarios for achieving a net zero state by 2050 or 2060 were designed.

The simulator used in the study is based on balancing the electricity system. It encompasses three energy system components: generation, storage, and consumption. The simulation is performed for an annual time horizon, with a one-hour time step, and the individual runs are aggregated over one year. The simulator also accounts for weather conditions throughout the year with a one-hour resolution. These conditions include solar radiation, wind speeds, and ambient temperature. These data are used to calculate the efficiency of weather-dependent energy sources, the heating demand (via degree-hours), and the efficiency of heat pumps. The source data necessary for the simulations are obtained from publicly available tools and databases (PVGIS [40], ENTSO-E [41], Open-meteo [42], and Instrat [43]). For simulation purposes, it is possible to select the year for which the weather data will be considered, covering the period from 2015 to 2023.

According to the simulator’s assumptions, electricity is generated by selected renewable energy sources (onshore wind, offshore wind, and PV) and nuclear power plants. Any instantaneous surplus of generated energy is sequentially sent to electrical energy storage systems (battery storage, electric vehicle batteries, and pumped hydroelectric storage), industrial heat storage, residential heat storage, and electrolysers, which are the final recipients of excess energy. Instantaneous energy shortages in the system are sequentially compensated by residential heat storage, industrial heat storage, electrical energy storage, and dispatchable generation sources powered by biomethane. The simulator determines, among other factors, the demand for biomethane to power dispatchable gas power plants and their required power levels on an hourly basis.

The starting year for this analysis is 2024. This year, Poland’s power generation capacity in the electricity system primarily consists of thermal power plants fuelled by fossil fuels (hard coal, lignite, and natural gas) [21], onshore wind turbines, and photovoltaic panels. Transportation and heating are predominantly based on fossil fuels.

The new energy system model presented in this publication, designed up to 2060, is based on a net zero policy. It anticipates an increase in electricity demand resulting from GDP growth, the complete electrification of transportation, and the electrification of industrial and residential heating. Moreover, the model assumes a transformation of the industry toward reliance on green hydrogen. No fossil fuel-powered units will remain in the energy system by 2050 (or 2060, depending on the simulation variant). Instead, onshore and offshore wind farms will be expanded, and an adequate number of nuclear power plant units will be built. Power plants or generators with gas turbines running on biomethane will complement these generation facilities. Using biomethane as a fuel ensures zero emissions from these energy sources. This study assumes that electricity, biomethane, and hydrogen will be exclusively sourced from domestic production and will not involve cross-border exchanges.

In the presented model, the role of stabilising generation units in the electricity system, currently fulfilled by coal-fired power plants (referred to as centrally dispatched generation units or CDGUs), will be taken over by the following:

(a)

On the generation side, generators powered by biomethane (CDGUs);

(b)

On the consumption side, hydrogen-producing units, which become centrally dispatched consumption units (CDCUs).

This means that, in the new model, shortfalls in energy production are balanced in the same way as today, with the difference that biomethane-fuelled generators will be used instead of coal-fired power plants. In turn, the management of excess production using a system of centralised electrolysers would be a new element in the Polish electricity system. Papers related to the issue of management and optimisation of hydrogen production based on an integrated RES system are known [44,45,46,47,48,49]. The adopted model does not take into account the specific management of the system, but only indicates the effect of its operation, considering the specific value of the installed electrolyser’s capacity. The integration of RES systems is necessary to achieve net zero policy targets, as it ensures the stability of electricity transmission and distribution across the country. The interconnection of systems also ensures energy security, as it reduces the need to import energy in case of local system balancing issues.

According to the authors, hydrogen must be produced exclusively from surpluses of renewable energy and stored or further processed.

The first step of the analysis involved determining the values of input parameter required for the model to achieve a net zero emission economy. The key input parameters included installed capacity in PV systems, onshore wind farms, offshore wind farms, nuclear power plants, energy storage capacity, and electrolyser capacity. Depending on the selected simulation variant, these parameters describe the electricity system in 2060 or 2050. Using these parameter values, simulations were conducted for all weather data available in the simulator. This approach provides insights into the variability of the energy balance depending on the weather conditions in a given year and allows for selecting input parameters to ensure adequate electricity production even under unfavourable weather conditions over the year. The model parameter selection ensures a balance between supply and demand in the system not only annually, but also momentarily, thanks to the anticipated storage capabilities of battery systems, hydrogen storage, and biomethane storage.

Subsequently, the pace of achieving this state and the intensity of the necessary investments were determined. The time horizons analysed were 2030, 2040, 2050, and 2060. The objective functions were calculated as the levels of CO₂ emission reductions in the four main areas of the economy included in the simulator: electricity production, transportation, heating, and industry. Zero-emission criteria were met when all of these areas collectively achieved net zero emissions. The pace of reaching net zero was analysed for three alternative scenarios:

Scenario I assumes that net zero will be achieved in 2060. This is the most gradual strategy, requiring the least investment intensity. The year 2060 is the net zero target set by the People’s Republic of China [50].

Scenario II aligns with the European Commission’s proposed European Green Deal [1], which aims to maintain net zero carbon emissions by 2050 and maintain this state through 2060.

Scenario III envisions a 90% reduction in CO₂ emissions by 2040, achieving net zero emissions by 2050 and maintaining this state through 2060 [51].

To streamline the presentation of results, the final simulation outcomes were reported based on 2023 weather conditions, which were determined during the simulation process to represent average conditions for the operation of the entire electricity system.

Additionally, a long-term simulation was conducted to analyse the storage states of green hydrogen (${Accum}_{H_2}\left(\tau \right)$) and biomethane (${Accum}_{{CH}_4}\left(\tau \right)$), the demand for power from professional gas power plants, and the effective capacity of electrolysers. The long-term simulation, which lasted nine consecutive years, was carried out using weather conditions from 2015 to 2023, while energy supply and demand values were assumed to reflect 2060. The following relationships were used to calculate hydrogen and biomethane accumulation in storage:

$${Accum}_{H_2}\left(\tau \right)=\underset{{\tau }_0}{\overset{\tau }{\int }}{Supply}_{H_2}\left(\tau \right)·d\tau -\underset{{\tau }_0}{\overset{\tau }{\int }}{Demand}_{H_2}\left(\tau \right)·d\tau$$

(1)

$${Supply}_{H_2}\left(\tau \right)={\displaystyle \frac{P_{el}\left(\tau \right)\left[\mathrm{G}\mathrm{W}\right]}{1000}}·{\alpha }_{H_2}\left[{\displaystyle \frac{\mathrm{m}\mathrm{l}\mathrm{n} {\mathrm{m}}^3{\mathrm{H}}_2}{\mathrm{T}\mathrm{W}\mathrm{h}}}\right]$$

(2)

$${Demand}_{H_2}\left(\tau \right)={\displaystyle \frac{D_{H_2}\left[\mathrm{T}\mathrm{W}\mathrm{h}\right]}{a}}·{\alpha }_{H_2}\left[{\displaystyle \frac{\mathrm{m}\mathrm{l}\mathrm{n} {\mathrm{m}}^3{\mathrm{H}}_2}{\mathrm{T}\mathrm{W}\mathrm{h}}}\right]$$

(3)

$${Accum}_{{CH}_4}\left(\tau \right)=\underset{{\tau }_0}{\overset{\tau }{\int }}{Supply}_{{CH}_4}\left(\tau \right)·d\tau -\underset{{\tau }_0}{\overset{\tau }{\int }}{Demand}_{{CH}_4}\left(\tau \right)·d\tau$$

(4)

$$Supply {CH}_4={\displaystyle \frac{S_{{CH}_4}\left[\mathrm{m}\mathrm{l}\mathrm{n} {\mathrm{m}}^3{\mathrm{C}\mathrm{H}}_4\right]}{a}}$$

(5)

$${Demand}_n {CH}_4={\displaystyle \frac{P_g\left(\tau \right)\left[\mathrm{G}\mathrm{W}\right]}{1000}}·{\alpha }_{{CH}_4}\left[{\displaystyle \frac{\mathrm{m}\mathrm{l}\mathrm{n} {\mathrm{m}}^3{\mathrm{C}\mathrm{H}}_4}{\mathrm{T}\mathrm{W}\mathrm{h}}}\right]$$

(6)

where:

• ${\tau }_0$ = 1 January 2015;
• $P_{el}\left(\tau \right)$ is the power of electrolysers in time $\tau$;
• ${\alpha }_{H_2}=254.5\left[{\displaystyle \frac{\mathrm{m}\mathrm{l}\mathrm{n} {\mathrm{m}}^3{\mathrm{H}}_2}{\mathrm{T}\mathrm{W}\mathrm{h}}}\right]$ is the volume of hydrogen produced from 1 TWh of energy
• $D_{H_2}$ is the annual hydrogen demand;
• $a$ is the number of hours in the year;
• $a=\left\{\begin{array}{c}365·24\\ 366·24\end{array}\right.$ ${\displaystyle \genfrac{}{}{0pt}{}{for 2015, 2017, 2018, 2019, 2021, 2022 and 2023}{for 2016 and 2023}}$
• $S_{C{H}_4}$ is the annual biomethane supply;
• $P_g\left(\tau \right)$ is the power of gas generators in time $\tau$;
• ${\alpha }_{C{H}_4}=201.6\left[{\displaystyle \frac{\mathrm{m}\mathrm{l}\mathrm{n} {\mathrm{m}}^3{\mathrm{C}\mathrm{H}}_4}{\mathrm{T}\mathrm{W}\mathrm{h}}}\right]$ is the volume of biomethene required to produce 1 TWh of energy.

In line with the assumptions described further, it was assumed that $D_{H_2}=66.7 \left[\mathrm{T}\mathrm{W}\mathrm{h}\right]$ and $S_{C{H}_4}=7800 \left[\mathrm{m}\mathrm{l}\mathrm{n} {\mathrm{m}}^3{\mathrm{C}\mathrm{H}}_4\right]$. For both hydrogen and biomethane, it was assumed that the storage facilities were empty at the beginning of the year.

4. Results and Discussion

The generation capacities and the amounts of electricity produced and consumed for the baseline year and the end of the simulation are shown in

Table 2. Comparison of the electricity system parameter values used to carry out simulations for 2024 and 2060 (energy values are the result of simulations).

	Production					Heat Pumps	Storage					Demand
	Wind Onshore	Wind Offshore	PV	Nuclear	Bio-CH4		Batteries	EV Batteries	PSH	Heat Storage (Industry)	Heat Storage (Household)	Transportation	Industry Heat	Household Heat	Electricity	Electrolysers/H2
	GW				mld m3	GWel	GWh					Electrification—Share of Current Demand				GW
2024	9	0	17	0	0	0.5	0	0	0	0	0	0%	0%	0%	100%	0
2060	64	33	136	10	7.8	9.8	140	230	30	35	70	100%	100%	100%	120%	22
	Energy, TWh
2024	26.7	0.0	17.3	0.0	0.0							0	0	0	167.5	0
2060	189.7	139.1	138.4	70.7	38.7							102.8	70.8	66.8	174.5	66.7

. According to the assumptions and calculations, the minimum renewable energy capacities required to ensure a positive overall energy balance under the weather conditions observed between 2015 and 2023 are 64 GW for onshore wind, 33 GW for offshore wind, and 136 GW for PV systems. While these installed capacities appear substantial, considering the long-time horizon for achieving them, these values are not excessive. Regarding wind energy, the potential onshore installed capacity in Poland ranges from 63.4 GW to 118.3 GW, depending on the minimum legally required distance of wind farms from residential areas (700 m or 500 m, respectively) [25]. For the simulation, the 700 m distance was assumed, corresponding to approximately 64 GW. The potential capacity for offshore wind farms in Poland’s Baltic Sea region is 33 GW [25], which was adopted in the simulation. The potential for PV capacity in Poland is less clearly defined, but estimates for agri-PV alone indicate a capacity of 118.8 GW [52]. In this context, the calculated target capacity of 136 GW does not appear to be overstated. The resulting PV power is the lowest value that provides a positive balance to the electricity system under weather conditions corresponding to 2015–2023. However, challenges with connecting new PV and wind installations to the grid remain significant. In 2023 alone, connection conditions were denied for PV installations totalling 83.6 GW due to an unprepared electrical grid [27]. Similarly, in 2022, connection conditions were denied for wind installations totalling 51.1 GW [28]. These figures highlight Poland’s substantial renewable energy potential, contingent upon appropriate grid expansion and modernisation investments.

Another key element in balancing the electricity system is nuclear power plants. The simulation showed that the installed nuclear capacity in 2060 (10 GW) could not be reduced while maintaining a positive energy balance under the adopted assumptions. According to estimates by the Ministry of Climate, the economic feasibility and rationale for developing nuclear power with a total capacity of 9.9 GW by 2050 have been confirmed [53]. Thus, the simulation’s target capacity of 10 GW is ambitious, but realistic.

In the proposed model, professional power plants fuelled by biomethane are the last resort for supplying energy during production shortages from renewable energy sources and nuclear power. It was assumed that biomethane would be entirely produced and consumed domestically. The projected biomethane production of 7.8 billion m³/year in 2060 aligns with national reports [37,54], based on the current total technical potential. This production level balances supply and demand during temporary shortages when nuclear power plants and energy storage facilities are insufficient.

In alignment with net zero policies, zero emissions also apply to the industrial sector, which currently uses hydrogen primarily as a feedstock in the fertiliser and petrochemical industries. The annual demand for green hydrogen (66.7 TWh, Table 2) was calculated based on recent studies [20] and is summarised in

Table 3. Annual industrial green hydrogen demand to achieve total decarbonisation based on [20].

Industry Sector	Hydrogen Demand, t	Energy, TWh
Nitrogen plants, refineries	451,318	19.8
Metallurgy, steel production	307,000	13.4
Maritime transport	354,667	15.5
Aviation	295,571	12.9
Other	-	5.0
SUM		66.7

. The study assumes the complete electrification of transportation, excluding hydrogen demand for refining processes related to conventional vehicle fuels. The primary hydrogen consumers are the fertiliser and non-fuel refinery sectors, with a combined annual demand of approximately 451 ktH₂/year. Additionally, the study assumes the complete transformation of the steel industry (297 ktH₂/year) and high-temperature heat sectors, including non-ferrous metal production, glassworks, ceramics, and cement plants (10 ktH₂/year). Furthermore, aviation and maritime transport are assumed to rely entirely on synthetic fuels derived from hydrogen and carbon dioxide, with the annual hydrogen demand estimated accordingly. A surplus of 5 TWh of green hydrogen was also included for unaccounted sectors to meet EU directives, such as AFiR (1% of road transport using hydrogen) and RED III (1% of conventional fuels from hydrogen). Based on the calculated hydrogen demand, the minimum capacity of electrolysers (22 GW, Table 2) was determined to ensure a positive hydrogen balance under the weather conditions observed between 2015 and 2023.

The current electrical capacity of heat pumps (0.5 GW, Table 2) was estimated based on the following assumptions: 220,000 units, an average thermal capacity of 8 kW, and an average SCOP (Seasonal Coefficient Of Performance) of 3.5. The calculated capacity for heat pumps in 2060 corresponds to their projected 90% share in heating (with the remaining 10% provided by electric heating and cogeneration).

The target capacity of energy storage in electric vehicles (230 GWh, Table 2) assumes 23 million electric vehicles by 2060 with average battery capacities of 50 kWh, and 20% of these batteries are used as energy storage systems. Simulations revealed that large-scale electricity storage capacities, comparable to those in electric vehicles, are essential for balancing the electricity system. The target capacity for pumped storage hydropower (PSH) was stablished at 30 GWh, with the total electricity storage capacity reaching 400 GWh. The capacities of residential and industrial heat storage were set at 35 GWh and 70 GWh, respectively, due to their limited suitability as centrally dispatchable balancing components.

All simulations conducted indicate that the balance of biomethane and hydrogen is strongly dependent on weather conditions (Figure 3).

For instance, using weather data from 2018, there was a shortfall of approximately 3.3 billion m³ of biomethane in the balance, representing 29% of the annual demand. In contrast, using weather data from 2019, a positive balance of 2.3 billion m³ of biomethane was achieved. Weather data from 2023 were selected for further simulations because this year showed a positive biomethane balance (0.47 billion m³) close to the average value for 2015–2023. The weather conditions in 2023 allowed for the production of a significant surplus of hydrogen (2.6 billion m³). The capacity of installed electrolysers was calculated, and it was set to the minimum value to ensure a positive cumulative H₂ balance across all analysed years.

The energy system simulator allows for obtaining a range of valuable partial data. For example, it provides detailed energy balance components on both the demand and supply sides. Additionally, detailed data on the amounts of energy supplied to and drawn from heat and electricity storage facilities can be accessed. This enabled the creation of a comprehensive energy system balance for Poland in 2060 (

Table 4. Energy system balance in Poland in 2060 (weather conditions as of 2023).

Supply	TWh	Demand	TWh
Wind onshore	189.7	Electricity	174.5
Wind offshore	139.1	Industry heat	70.83
PV	138.4	Household heat	66.84
Nuclear	70.74	Transportation	102.8
Methane	36.35	Hydrogen	76.80
Cogeneration	6.120	Unused	78.24
Batteries	30.99	Batteries–charging	36.93
Heat storage (industry)	1.410	Heat storage (industry)—charging	1.444
Heat storage (household)	0.6166	Heat storage (household)—charging	2.559
		Transmission losses of methane	2.413
SUM	613.5		613.5

). The primary annual energy sources in this system are wind farms and photovoltaic (PV) installations. The demand for biomethane to power conventional power plants during renewable energy shortages constitutes 5.9% of the total supply. On the demand side, the largest consumer in the system is electricity, with a 28.5% share. It is followed by transport with a 16.8% share and unutilised energy with a 12.8% share. This unutilised energy represents the surplus that cannot be stored or directed to electrolysers due to their limited capacities and power. The primary consumer of surplus energy is electrolysers, which produce green hydrogen for industrial applications, as detailed in Table 3. Green hydrogen accounts for 12.5% of the total demand. In contrast, the combined share of all electricity and heat storage facilities is almost twice as small at approximately 6.7%. This indicates that, despite the substantial total storage capacities (400 GWh), they are not the primary consumers of surplus energy. Instead, electrolysers take on this role, even with a moderate power level (22 GW). According to the assumptions, electrolysers operate with power adjusted to the real-time difference between available power and demand. If the hydrogen produced is not immediately used, it is stored. The simulation shows that the energy storage systems remain fully charged for most of the year, which prevents them from absorbing the surplus energy generated by renewable sources.

It is worth noting that, in 2024, the total electricity demand was 167.5 TWh, while in the target year 2060, it will rise to 481.8 TWh (Table 2), representing a 2.9-fold increase. This implies that the current electricity grid must be upgraded to ensure the stable transmission of significantly increased electricity volumes.

The geographical location of Poland in Central Europe results in distinct seasonal variability, which significantly impacts energy demand and the performance of various components in the energy mix. To illustrate these seasonal differences, Figure 4A presents the instantaneous power outputs of different energy sources during the first months of each quarter. The height of the areas under the demand curve indicates which energy sources are used to meet the demand. Additionally, a line representing the total instantaneous demand has been added, allowing for the easy identification of periods with surplus production relative to demand and times when gas turbines are required to maintain the stability of the energy system. Figure 4B, on the other hand, shows the instantaneous power demand across various sectors of the economy, the operation of electrolysers, and the real-time values of unused energy.

In January, representative of the winter season, wind energy, mainly offshore, plays a significant role. Due to short days and limited sunlight, the contribution of photovoltaics is negligible. During windless days in January, biomethane production, cogeneration, and energy storage facilities for electricity and heat stabilise the energy system. Nuclear energy provides a constant and stable production level, independent of weather conditions. In January 2060, the maximum power demand reaches 73.1 GW. During surplus power, storage facilities and electrolysers are activated; however, part of the excess power remains unutilised. A characteristic feature of this month is that periods of gas turbine operation and periods of surplus energy last for several days.

As days grow longer in April, the share of photovoltaic (PV) energy increases, while wind power generation remains high. PV generation sometimes helps to meet demand gaps, but occasionally results in unused energy. During this period, biomethane consumption decreases compared to winter months, and there are periodic surpluses and deficits in renewable energy production. In the simulated scenario, early April experiences surplus renewable energy production (mainly from wind), allowing for storage facilities to be filled, hydrogen to be produced, and significant amounts of unutilised energy to be observed. On days with unfavourable weather conditions for wind energy generation, demand is supplemented by energy stored in batteries and heat storage or by activating conventional power plants fuelled by biomethane. Due to higher temperatures, the maximum power demand in April is lower than in January, reaching 70.5 GW. Electrolysers are utilised more extensively because surplus power arises intermittently from both PV and wind power.

In July, the variability in energy production is primarily driven by PV output. The peak energy generation from PV typically exceeds energy demand. The instantaneous maximum power demand reaches 47.6 GW, while PV alone can generate up to 84.7 GW at its peak. In October, Poland experiences various weather conditions, resulting in varying contributions from PV and wind farms. However, the shorter daylight hours and lower sun angles reduce PV’s overall potential. Although wind energy production increases, windless days necessitate system balancing through battery storage and biomethane production. October exhibits energy production variability similar to that of January. However, the maximum power demand in October is lower, reaching 56.1 GW.

The following research stage presents three approaches to achieving net zero emissions for Poland’s entire economy by 2060 (Scenario I) or by 2050 while maintaining this state through 2060 (Scenarios II and III).

Table 5. Results of power system parameter calculation for three scenarios at various intermediate stages in the years 2030, 2040, 2050, and 2060.

Scenario	Year	Wind Onshore	Wind Offshore	PV	Nuclear	Electrolysers	Heat Pumps	Biomethane	Batteries	EV	PSH	Heat Storage (Industry)	Heat Storage (Household)	Transportation	Industry Heat	Household Heat	Electricity
		GW					GWel	mld m3	GWh					Electrification—Share of Current Demand
	2024	9	0	17	0	0	0.5	0.0	0	0	0	0	0	0%	0%	0%	100%
I	2030	15	3	29	0	0	1.1	0.6	12	0	0	0	0	0%	0%	0%	103%
	2040	25	13	59	3	5	3.1	2.6	52	46	10	5	10	20%	20%	20%	108%
	2050	44	23	96	6	12	6.1	4.6	92	138	20	15	30	60%	60%	60%	114%
	2060	64	33	136	10	22	9.8	7.8	140	230	30	35	70	100%	100%	100%	120%
II	2030	15	6	41	0	3	1.1	0.6	24	28	0	0	0	12%	0%	0%	103%
	2040	35	19	81	4	8	4.6	2.6	74	120	15	5	10	52%	50%	50%	108%
	2050	60	32	131	10	20	9.1	7.8	134	230	30	25	50	100%	100%	100%	114%
	2060	64	33	136	10	22	9.8	7.8	140	230	30	35	70	100%	100%	100%	120%
III	2030	21	9	44	0	3	1.7	0.6	30	55	6	6	6	24%	12%	12%	103%
	2040	51	29	114	8	21	7.7	6.4	100	207	26	21	41	90%	90%	90%	108%
	2050	61	32	134	10	22	8.8	7.8	135	230	30	31	61	100%	100%	100%	114%
	2060	64	33	136	10	22	9.8	7.8	140	230	30	35	70	100%	100%	100%	120%

outlines the parameters describing the power system and energy demand in sectors such as electricity, heating, transport, and hydrogen production, not only for the final simulation year, but also for the transition years (2030, 2040, and 2050). Depending on the adopted approach, these scenarios consider additional conditions for decarbonisation levels. For transitional periods, it was assumed that changes in the numerical parameters of the generation side would follow a steady rate of change wherever possible, considering additional constraints. Only for the initial period (2024–2030) was a slower rate of change adopted compared to subsequent periods (2030+) due to the gradual intensification of investment processes. This slower start reflects delays in regulatory changes and the necessary shifts in awareness among decision-makers and investors. Solving an optimisation problem requires selecting one of the many known methods. A heuristic approach was used instead of a strict mathematical optimisation algorithm to determine the system parameters for each scenario. As is known, heuristic methods do not guarantee finding an optimal solution. However, compared to methods such as linear programming, they offer several advantages, including resilience to potential nonlinearities, robustness to imperfect and uncertain data, and, in many cases, fast convergence to a suboptimal solution. Additionally, heuristic methods can be supported by expert knowledge (expert-in-the-loop approach) or data from long-term energy development programmes (e.g., nuclear energy planning). This method was supported by analysing various sources that describe the economic conditions for developing a zero-emission energy sector. On the energy consumption side, a gradual and consistent increase in parameters was assumed, including energy and heat storage capacities, the development of electromobility, the transition to heat pumps in heating, and the production capacities for hydrogen. Even the relatively moderate Scenario I requires simultaneous, intensive growth in renewable energy capacity, nuclear power plants, electrolysers, heat pumps, and energy storage facilities, as well as biomethane production from biomass. The most critical aspect is to compare the intensity of development of specific energy sources in the power system, depending on the scenario, and the necessary pace of changes in energy demand, as outlined in

Table 6. Changes per year for each power system parameter for three scenarios up to 2060.

Scenario	Years	Wind Onshore	Wind Offshore	PV	Nuclear	Electrolysers	Heat Pumps	Biomethane	Batteries	EV	PSH	Heat Storage (Industry)	Heat Storage (Household)	Transportation	Industry Heat	Household Heat	Electricity
		GW/y					GWel/y	mld m3/y	GWh/y					Annual Growth in Electrification Degree			Relative Annual Growth
I	2024–2030	1.0	0.5	2.0	0.0	0.0	0.10	0.10	2.0	0.00	0.0	0.0	0.0	0.0%	0.0%	0.0%	0.5%
	2030–2040	1.0	1.0	3.0	0.3	0.5	0.20	0.20	4.0	4.60	1.0	0.5	1.0	2.0%	2.0%	2.0%	0.5%
	2040–2050	1.9	1.0	3.7	0.3	0.7	0.30	0.20	4.0	9.20	1.0	1.0	2.0	4.0%	4.0%	4.0%	0.5%
	2050–2060	2.0	1.0	4.0	0.4	1.0	0.37	0.32	4.8	9.20	1.0	2.0	4.0	4.0%	4.0%	4.0%	0.5%
II	2024–2030	1.0	1.0	4.0	0.0	0.5	0.10	0.10	4.0	4.60	0.0	0.0	0.0	2.0%	0.0%	0.0%	0.5%
	2030–2040	2.0	1.3	4.0	0.4	0.5	0.35	0.20	5.0	9.20	1.5	0.5	1.0	4.0%	5.0%	5.0%	0.5%
	2040–2050	2.5	1.3	5.0	0.6	1.2	0.45	0.52	6.0	11.04	1.5	2.0	4.0	4.8%	5.0%	5.0%	0.5%
	2050–2060	0.4	0.1	0.5	0.0	0.2	0.07	0.00	0.6	0.00	0.0	1.0	2.0	0.0%	0.0%	0.0%	0.5%
III	2024–2030	2.0	1.5	4.5	0.0	0.5	0.20	0.10	5.0	9.20	1.0	1.0	1.0	4.0%	2.0%	2.0%	0.5%
	2030–2040	3.0	2.0	7.0	0.8	1.8	0.60	0.58	7.0	15.18	2.0	1.5	3.5	6.6%	7.8%	7.8%	0.5%
	2040–2050	1.0	0.3	2.0	0.2	0.1	0.11	0.14	3.5	2.30	0.4	1.0	2.0	1.0%	1.0%	1.0%	0.5%
	2050–2060	0.3	0.1	0.2	0.0	0.0	0.10	0.00	0.5	0.00	0.0	0.4	0.9	0.0%	0.0%	0.0%	0.5%

. The calculated rates of change in the system are the most achievable (and thus the most realistic) in Scenario I. They demonstrate the minimum investments needed across all areas of electricity production and other sectors responsible for greenhouse gas emissions to achieve a climate-neutral economy by 2060 at the latest. As seen in the data for Scenarios II and III, achieving climate neutrality earlier requires a significant increase in these investments. The results in Table 6 can serve as guidelines for a detailed action plan throughout the transition period from 2024 to 2060.

Applying the energy system simulator also enables the estimation of transformation costs. Given that energy transition scenarios, analysed in this paper, are long-term processes, economic analysis is inherently subject to high prediction uncertainty. Our primary objective was to conduct a simplified cost assessment solely to compare the different scenarios. The cost balance was calculated using the energy simulator [38] and includes the construction, maintenance, and operation costs of individual system components, excluding biomethane production. The simulator also does not account for other transformation costs, such as the expansion and modernisation of the power grid or the costs of transporting and storing biomethane and green hydrogen. Nevertheless, the obtained data allow for a direct comparison of the selected scenarios. Regardless of the chosen scenario, the total costs amount to approximately EUR 496.8 billion by 2060 (Figure 5). While this figure may seem substantial, it averages around EUR 13.8 billion annually. The annual costs peak at EUR 33.4 billion during 2030–2040 in Scenario III, whereas in the most moderate Scenario I, the maximum annual costs reach EUR 18.4 billion during 2050–2060. When these figures are compared to Poland’s net energy and fuel import costs (exceeding EUR 25 billion annually in 2021–2023 [55]), it becomes apparent that the costs of building the new energy system components do not require additional financial resources. The analysis revealed the challenges posed by Scenario III, which aims for a 90% reduction in CO₂ emissions by 2040 and net zero emissions by 2050. In this scenario, the investments during 2030–2040 would need to be 165% higher compared to Scenario I. Additionally, the assumed growth rates for installed capacities—3 GW/year for onshore wind, 7 GW/year for PV, and 7–16 GWh/year for battery storage—would present significant challenges and appear unlikely to be achievable.

On the other hand, considering the depleting carbon budget [56], Scenarios II and III are more desirable compared to Scenario I. In Scenario I, the transport and heating sectors contribute significantly to current GHG emissions, accounting for 80% in 2040 and 40% in 2050, respectively (

Table 7. Comparison of emission reductions under different scenarios and their share of the current value.

Year	Scenario	Electricity	Industry (Hydrogen)	Transportation	Heat
2024	I, II, III	100.0%	100.0%	100.0%	100.0%
2030	I	62.3%	100.0%	100.0%	100.0%
	II	52.1%	97.8%	88.0%	100.0%
	III	50.3%	96.1%	76.0%	88.0%
2040	I	17.5%	81.5%	80.0%	80.0%
	II	26.1%	71.4%	48.0%	50.0%
	III	9.9%	9.5%	10.0%	10.0%
2050	I	9.3%	44.6%	40.0%	40.0%
	II, III	0.0%	0.0%	0.0%	0.0%
2060	I, II, III	0.0%	0.0%	0.0%	0.0%

). Meanwhile, the industrial sector in Scenarios I and II still emits over 70% of its current GHG emissions by 2040. The simulation results indicate that achieving net zero policy targets is feasible by 2050, and a 90% reduction in GHG emissions across all sectors can be reached as early as 2040. However, this would present a significant challenge for all branches of industry.

In the subsequent part of the study, the focus is limited to a detailed presentation of the transformation process for Scenario I, as it is considered to be the most feasible for implementation (Figure 6). For Scenarios II and III, the transformations will follow a similar pattern; however, they will occur faster (Table 5). The simulation results for various time horizons in Scenario I indicate that, currently, utility power plants fuelled by fossil fuels (here referred to as methane) are responsible for 71.1% of the energy supply. According to the adopted assumptions, no significant changes in the electrification of transport and heating will occur by 2030, and hydrogen for industrial use will still be almost entirely produced from non-renewable sources. From 2030, the growth rate of renewable energy capacity will double compared to 2024–2030, and the first units from nuclear power plants will come online. At the same time, the electrification of transport and heating will begin. With the increasing capacity of renewable energy sources (RESs), surplus energy will emerge, a portion of which will be absorbed by electrolysers to produce green hydrogen. By 2040, hydrogen is expected to account for approximately 5% of energy demand, but it will not be until 2060 that its production will be sufficient to meet the demand fully.

To address the energy balance deficits, utility gas power plants fuelled by biomethane are proposed. As mentioned above, biomethane would be sourced exclusively from domestic production and generated continuously at a steady output in the proposed system. The produced biomethane could be used to periodically fuel gas power plants, while any surplus would be stored. Similarly, green hydrogen would be produced during periods of surplus energy availability and continuously consumed by industry, with any surplus also stored. In this case, it is also assumed that the demand for hydrogen remains constant throughout every hour of the year. Based on these assumptions, a long-term balance of biomethane and green hydrogen resources was prepared for weather conditions similar to those from the years 2015–2023, with energy demand and supply levels projected for 2060 (Figure 7). It was assumed that, at the beginning of the analysed period, both storage facilities would be empty. An additional assumption was the inclusion of an element of international trade (imports). The analysis indicates that, during the first three months of the simulation, deficits in both hydrogen and biomethane occur. Biomethane storage shortages continue in the subsequent four years at the beginning of the year (January–March). In contrast, hydrogen shortages are observed primarily during the first two years of the analysis. In later years, there is no longer a need to purchase biomethane or hydrogen, as storage levels remain high. At the end of the 9-year analysed period, the green hydrogen storage level reached 5.4 billion m³ (21,365 TWh) and the biomethane storage level reached 7.7 billion m³ (38,188 TWh). Currently, in Poland, the active capacity of underground natural gas storage is approximately 3.3 billion m³ [57]. Therefore, the simulated volumes of biomethane and hydrogen exceed the capacity of national storage facilities. In such a scenario, several options arise: expanding the capacities of domestic gas storage facilities or exploring favourable conditions for new applications of these gases in the domestic market. Alternatively, the produced gases could be sold to other countries, or, if storage or utilisation is not possible, the production of these gases could be halted. Moreover, despite the adopted assumptions, the levels of biomethane and hydrogen imports were found to be insignificant (Figure 8). During the 9 years, it would be necessary to import a total of 38.2 TWh of biomethane and 20.1 TWh of hydrogen, while simultaneously ending the period with large surpluses of these gases and a significant amount of unutilised energy (581 TWh).

A long-term analysis of gas power plants fuelled by biomethane during 2015–2023 revealed that their operation is required for approximately 15.5% of the time on an hourly basis. The peak power output of these plants is necessary to ensure that the balance of the energy system reaches 83.2 GW (Figure 9, 26 February 2018, 19:30). Assuming that this is the total installed capacity of gas power plants, they would operate, on average, at only 5.2% of their capacity, or approximately 4.3 GW on average. For comparison, data on electrolysers with an assumed capacity of 22 GW operating under similar weather conditions during 2015–2023 show that they are operational for 40.4% of the time on an hourly basis and that their capacity is 34.7%, with an average power output of 7.6 GW. This level of utilisation is more acceptable than that of utility gas power plants.

Furthermore, when examining monthly energy demand (Figure 10, with a maximum of 16.8 TWh in January 2017) or annual energy demand (Figure 8, with a maximum of 54.9 TWh in 2018) for biomethane-fuelled energy generation to compensate for renewable energy shortages, and comparing these figures to annual surplus energy (Figure 8, 48–78 TWh), a positive energy balance emerges on an annual basis. This is despite occasional deficits at a variable but not excessively high level. It should be noted that the simulation does not include cross-border trade, as this aspect falls outside the capabilities of the simulator used. In practice, the construction of large capacities (around 80 GW) is not economically justified. The optimal capacity of utility gas power plants, and thus the desired biomethane demand and the required capacities of biomethane facilities, could be the subject of a separate simulation.

Another way to manage surplus electricity production could be the production of green hydrogen in quantities exceeding the proposed domestic industrial demand (Table 3). The hydrogen obtained could be used to develop existing sectors (such as the fertiliser industry, the polymer industry, etc.), in other areas of the economy (such as energy storage, to power fuel cell vehicles, in the space industry, as a substrate for CO₂ capture processes from the atmosphere, etc.), or it could be sold on the international market. The simulation results (Figure 11) indicate that, in the analysed example, fully utilising the surplus energy production would require as much as 130 GW of electrolyser capacity, which would be utilised only 13.6% of the time. Installation of such a large electrolyser capacity does not appear to be technically or economically justified. Similarly to the case of installed capacity in gas power plants, determining the optimal levels of installed electrolyser capacity also requires multifactor simulations that consider many parameters not included in this study.

5. Conclusions

Research has shown that it is possible to achieve a self-sufficient, sustainable, zero-emission, and stable energy system in Poland by 2060, even though the energy sources it relies on are uncontrollable and primarily based on weather-dependent systems. The capacities assumed in the simulation, namely 64 GW of onshore wind, 33 GW of offshore wind, 136 GW of PV, 10 GW of nuclear power, and 22 GW of electrolysers, together with an appropriate system of electricity and heat storage, allow for a net positive energy balance in the zero-emission system under the weather conditions observed between 2015 and 2023. The stability of the system requires the electrolysers to operate in a centralised system, as dispatchable receiving units are controlled centrally.

It has been demonstrated that the energy transition toward a net zero policy requires intensive changes in almost all sectors of the economy, including a complete shift in transportation and heating systems to electricity-based solutions and industrial activities to those based on green hydrogen. The cost of building, maintaining, and operating individual system components has been estimated to be a maximum of EUR 18.4 billion per year for 2050–2060. A challenge appears to be preparing the power grid to handle an annual energy transmission 2.9 times greater than the current level.

The simulation results indicate that sectors of the economy related to green hydrogen and biomethane production will also need to increase their current production capacities significantly. It has been proven that the electrolyser system will play a key role in managing energy production surpluses. As a result of the long-term nine-year simulation, it has been shown that energy self-sufficiency is achievable. Moreover, significant amounts of surplus green hydrogen (5.4 billion m³ or 21,365 TWh), biomethane (7.7 billion m³ or 38,188 TWh), and 581 TWh of unused energy are generated. This provides opportunities for the development of all current and future sectors of the economy, and the green hydrogen produced can find numerous applications, meeting both current and new potential demand.

Thanks to the strategy presented here, which combines the management of weather-dependent energy resources with hydrogen production implemented using electrolysers operating as centrally dispatchable elements, the energy system gains the ability to increase the capacity of installations based on renewable energy significantly. This combination enables the efficient utilisation of energy surpluses produced during periods of high output from renewable sources such as solar and wind energy. Such an oversizing of weather-dependent sources relative to current power demand not only increases the share of renewable energy in the energy mix, but also contributes to system stability by storing surplus energy in the form of hydrogen. This is a step towards a more sustainable and flexible energy system that can better address the challenges of ensuring energy security and reducing CO₂ emissions.