National Energy and Climate Plan—Polish Participation in the Implementation of European Climate Policy in the 2040 Perspective and Its Implications for Energy Sustainability

Abstract

This paper analyses Poland’s participation in implementing European climate policy within the framework of the National Energy and Climate Plan (NECP), looking toward 2040. It assesses the feasibility of Poland’s commitments to the European Union’s decarbonisation targets, particularly with regard to transitioning from fossil fuels to renewable energy sources and nuclear power. The study highlights the challenges related to the speed of the energy transition, the security of electricity supply, and the competitiveness of the national economy. The study also assesses the energy mix scenarios proposed in the NECP, taking into account historical energy consumption data, economic and demographic projections, and expert analyses of energy security. It also critically examines the risks of delayed investment in nuclear and offshore wind, the potential shortfall in renewable energy infrastructure, and the need for transitional solutions, including coal and gas generation. An alternative scenario is proposed to mitigate potential energy supply shortfalls between 2035 and 2040, highlighting the role of energy storage, strategic reserves, and the maintenance of certain fossil fuel capacities. Poland’s energy policy should prioritize flexibility and synchronization with EU objectives, while ensuring economic stability and technological feasibility. The analysis underlines that the sustainable development of the national energy system requires not only alignment with European climate goals, but also a long-term balance between environmental responsibility, energy affordability, and security. Strengthening the sustainability dimension in energy policy decisions—by integrating resilience, renewability, and social acceptance—is essential to ensure a just and enduring energy transition.

1. Introduction

On 1 December 2024, the new European Commission (EC), formed as a result of the June European Parliament elections, began its term of office. Ursula von der Leyen has been reappointed as President of the EC. This essentially means a continuation of existing European policies, including the policy of decarbonizing the economy. On 20 January 2025, Donald Trump took office as President of the United States, and in his pre-election announcements, he alluded to his previously implemented policy of rebuilding the US economy and continuing to use fossil fuels. As a result, on the same day, he signed an executive order withdrawing the US from the 2015 Paris Agreement. The expansion of China’s electric car industry into the European market and the consequent introduction of tariffs on them have led to a tightening of economic relations between the EU and China and a halt to investment in car battery production in some member states. Starting in early 2025, the European economy will be under intense pressure from the overlapping interests of the US and China. In September 2024, Mario Draghi published a report [1] on the competitiveness of the European economy and the risk of losing it permanently. He argues in favor of continuing the green transformation of the economy, but in a way that allows it to remain competitive in global markets.

Poland took over the Presidency of the Council of the EU on 1 January 2025. The role of the presiding state in a given six-month period is to prepare and agree on a working agenda on the most important problems of the Community and to moderate the dialog on the legal framework. According to the government declaration [2], the aim of our Presidency will be to ensure Europe’s security in the broadest sense—primarily military, internal, economic, energy, information, and food and health security. Energy security, mentioned in the middle of the list, was not ‘colored’ green, but it should be assumed that only the pace of transformation, juxtaposed with the competitiveness paradigm, can be negotiated, not its direction.

On 10 October 2024, the Minister of Climate and Environment (MoE) presented the National Energy and Climate Plan (NECP) for public consultation [3]. This document is required by the Regulation of the European Parliament and of the Council on the Governance of the Energy Union of 11 December 2018 [4]. Poland originally submitted a national plan on 30 December 2019, which included commitments to meet European climate targets, but did not submit the required corrections and additions before the end of 2023. As a result, the new government submitted a version of the revised plan to the EC on 1 March 2024 under threat of sanctions [5], while starting work on a more ambitious proposal. It should be noted that the 2019 version did not take into account the climate targets adopted as a result of the December 2019 Council conclusions (climate neutrality in 2050), which were subsequently disaggregated in the draft FIT for 55 regulations [6]. The 2019 NECPC was adopted by the government as a result of the work on the Polish Energy Policy (PEP 2040) [7], which was adopted only on 2 March 2021, but the forecasts, projections of the national energy mix, and, consequently, the declarations to the EU institutions were consistent. Neighboring countries, i.e., Germany and the Czech Republic, submitted their ambition NECPs to the EU on time. Poland is one of the few countries that is still dealing with the submission issue.

The NECP, which was published for public consultation in October 2024, was prepared on the basis of the assumptions of the European climate neutrality policy and its interim targets for emissions reduction, the share of renewable energy in gross final energy consumption, and energy efficiency. Formally, however, it is in no way linked to the current 2021 energy policy. (still in force). Almost 4000 comments were submitted on the consultative version of the national plan by the deadline of 15 November 2024. It is expected that the MoE will make corrections to the original draft of the National Plan and then submit it to the formal process for adoption by the government in the first half of 2025.

The article attempts to assess the feasibility of the assumptions made in the National Energy and Climate Plan, particularly with regard to replacing fossil fuels with renewable energy sources and nuclear power—and, temporarily, gas—and balancing climate goals with the pace of transformation. The purpose of the analysis is to try to estimate the demand for coal fuels in the interim period, which can be obtained from domestic mines, and ensure the safe operation of the regulatory units of the national electricity system.

2. Materials and Methods

The formally binding national planning document is the Energy Policy of Poland until 2040 (PEP 2040), adopted in February 2021. The climate targets assumed in PEP 2040 are outdated, having assumed a 30% reduction in carbon emissions in 2030, as Poland’s contribution to European ambitions. After Russia’s February 2022 attack on Ukraine and the resulting resource crisis, the perception of gas as a fuel of transition has also changed. Natural gas, which, according to Poland’s Energy Policy until 2040, was to serve as a transition fuel for power and heating, proved too risky in terms of availability and price. Poland, lacking sufficient quantities of gas, was forced to import it, which entailed high costs and risks related to the timely supply of the resource. In view of the above, the government in April 2022 decided to correct Poland’s energy policy. In mid-2023, in a pre-consultation formula, the so-called Scenario No. 3 [8] was presented to the Polish Energy Policy, which set energy mix targets for 2040, assuming that 73% of electricity would come from renewable sources, which would correspond to 74% of the share of renewable capacity installed in the national system. By the end of 2023, a revision of the energy policy, which assumed the realization of the national mix like scenario 3, had failed to be adopted. In February 2024, the new government presented a proposal to revise the outdated 2019 NECP, and in October of that year, another, more ambitious version.

The new National Energy and Climate Plan, presented for public consultation in October 2024, uses methodology and IT tools for energy mix designs previously used and recognized. The starting point in the calculation methodology used for the work was an analysis of the energy intensity of the economy for the period 1994–2021. Then, based on the assumed projections of the country’s economic and demographic development, a coherent scenario was built as the basis for calculating the future level of fuel and energy demand over the considered time horizon. The first step in the calculation methodology used was to determine the future level of energy demand in the country. Electricity demand projections were made using the bottom-up approach used in the STEAM-PL (Set of Tools for Energy Demand Analysis and modeling) model, a tool developed by the Energy Market Agency ARE [9]. According to the authors, the modeling results obtained in the energy mix work require critical analysis, the reason for which is the assumptions made in the generated scenarios.

At the Central Mining Institute in 2021–2022, expert research was conducted on forecasting scenarios for energy policy, in particular the structure of the energy mix and the risk of achieving the assumed level of its decarbonization [10]. The scientific approach to the issue of forecasting is based on a number of forecasting methods and ways of classifying them. One of the basic divisions is the division into quantitative and qualitative methods. Quantitative methods are based primarily on forecasting models built on the basis of available statistical data. They allow for the assessment of the development of the value of the forecast variable and explanatory variables in the future. It is worth noting that quantitative models work well if there are no significant changes in the company’s strategy and environment. When using quantitative methods, it is always necessary to decide whether, in the forecast horizon, there will be no phenomena that significantly affect the subject of the forecast and its environment [11,12,13]. Qualitative (heuristic) methods are based on the judgments of experts (individual or groups of experts). In forecasting based on these methods, we are not dealing with a formal model, but primarily with a mental model. Survey methods, the method of successive approximations, and the Delphi method are such models. Despite the fact that they are subjected to systematic error, they perform better when there are significant changes affecting the operation of the subject and questioning the rationality of using statistical data. The following critical analysis of the energy mix for Poland in the 2040 perspective presented in the draft of the new NECP was conducted at the Central Mining Institute using expert methods. Its purpose is to indicate the risk of not achieving the assumed climate targets by the assumed date and the need to prepare an alternative scenario in case the risk materializes [14,15,16].

3. Results and Discussion

Preliminary data on electricity production and demand in 2024 in Poland are provided in

Table 1. PSE (TSO) data on electricity production and demand from January to December 2024.

No.	Specification	December			Cumulative
					January to December
		2023	2024	Changes	2023	2024	Changes
		[GWh]	[GWh]	[(b − a)/a*100]	[GWh]	[GWh]	[(e − d)/d*100]
				[%]			[%]
		[a]	[b]	[c]	[d]	[e]	[f]
1	Total production (1.1 + 1.2 + 1.3)	15,626	15,427	−1.27	163,629	166,990	2.05
1.1	Commercial power plants	12,298	12,438	1.13	128,420	124,781	−2.83
1.1.1	Professional water pp.	358	191	−46.66	3592	3057	−14.89
1.1.2	Professional heat pp	11,940	12,247	2.57	124,828	121,724	−2.49
1.1.2.1	Hard coal	7332	7157	−2.38	76,607	69,112	−9.78
1.1.2.2	Lignite	3063	3297	7.64	34,571	35,844	3.68
1.1.2.3	Natural gas	1545	1792	16	13,650	16,768	22.84
1.2	Other renewable	208	280	34.95	13,209	17,334	31.23
1.3	Wind (on shore)	3120	2709	−13.18	22,000	24,874	13.07
2	Foreign exchange balance	−217	−556	156.36	3889	1966	−49.46
3	National electricity consumption	15,409	14,870	−3.49	167,518	168,956	0.86

. These data are determined on the basis of measurements collected by the TSO during the ongoing operation of the NPS and do not specifically take into account the self-consumption of energy by prosumers. Therefore, in some cases, they may differ from the final data presented by power companies for statistical purposes.

Electricity production increased by 2.05% compared to 2023, and consumption by 0.86%. In the structure of generating energy sources, a decrease in production of hard coal by 9.78% was observed, in favor of an increase in lignite by 3.68% and gas by 22.84% (see Figure 1). Production from wind sources grew dynamically by 13.07%, and other renewable (solar) sources by 31.23%. Despite such a large increase in renewable energy in the mix, its share reached 27.10% in 2024 (taking into account the self-consumption of prosumers and industrial self-producers, the share of RES in the energy mix in 2024 is expected to be around 30%). Less than 2 TWh of energy was imported into the NPS last year, down by half compared to the previous year.

The installed capacity of the national system exceeded 70 GW, of which wind sources accounted for about 10 GW and photovoltaic sources 21 GW. The highest demand for power in the NPS occurred on 9 January 2024, and amounted to 28,660 MW. The dynamic growth of weather-dependent sources in the national system, on the one hand, allows an increasing share of renewable energy in the mix, but at the same time necessitates the disconnection of some units during peak hours, when demand is lower than generation capacity. It is estimated that the quantity of renewable energy not fed into the grid in 2024 could be around 710 GWh. The biggest challenge for the next few years will be to gradually increase the flexibility of the NPS, so that while maintaining the stability of system operation, the generation of emission sources will be reduced in favor of RES.

As of 24 August 2024, electricity sellers are required to offer dynamic tariffs to their customers. A dynamic tariff means offering electricity at a price that changes, depending on the changing availability of energy in the national system over time. The customer will be able to decide to increase consumption when there is availability and a lower price, and reduce it during peak hours, with high prices. Taking advantage of dynamic tariffs requires systems that actively manage consumption.

In 2024 (Figure 1), the vast majority of domestic lignite and hard coal was used for electricity generation. Hard coal imports fell to 4.6 million Mg and were a consequence of previously concluded trade agreements.

Due to the high dynamics of renewable electricity generation in 2024 and the continuation of this trend in early 2025, demand for coal fuels is expected to decline in subsequent years. This implies the need to make adjustments to the mining plans presented in the application for notification of state aid to mining.

The National Energy and Climate Plan [3] consists of a core document and six annexes:

Anex 1: WAM scenario—active transformation scenario.

Anex 2: WEM scenario—transformation scenario in a path similar to “business as usual”.

Anex 3: Analytical assumptions and forecasting methodology.

Anex 4: Description of Energy Efficiency Measures and PEF in the Electricity Grid (describes measures to realize the required savings in final energy consumption referred to in Article 8 (1) of Directive 2023/1791 and the Primary Energy Factor (PEF) values for Poland, based on Article 31 of Directive 2023/1791).

Anex 5: Financing the climate-energy transition (including a description of investment needs).

Anex 6: Reference to the European Commission’s recommendations to the 29 February 2024 draft of the NECP.

Of key importance for further analysis are the core document and Annex 1, the ambitious transition scenario, as well as Annex 3, describing the methodology and analytical assumptions. Without going into the details of the modeling and construction of the tools themselves, according to the authors, the results of the energy mix simulation were most influenced by the assumptions and the expected final result.

Table 2. EU climate goals and Poland’s declared contribution, both historically and with current proposals.

Target	Climate Package2009	Climate Package2014	Climate Package—Final Targets 2019	Fit for 55 July 2021 Package	Polish Targets According to PEP 2040 and NECP February 2021.	REPowerEU May 2022	Final Fit for 55 February 2024 Targets	Polish Targets According to the NECP Revision (WEM/WAM, October 2024)
CO2 reduction [%].	20	40	40	55	30	55	55 (minimum)	35/50.4
Increase in RES share—gross consumption [%].	20	27	32	40	23	45	42.5 (aiming for 45)	29.8/32.6
Energy efficiency [%].	20	27	32.5	36	23	38.5	38.0 11.7 *	21.8 0.5/4.6 *

* (Final energy with respect to the PRIMES 2020 reference scenario). The efficiency target set by PRIMES 2020 for Poland is 12.8%.

shows in the last two columns the final European targets negotiated as part of the FIT for 55 package at the end of the previous EC’s term of office, and Poland’s proposed contribution to these targets in the WEM and WAM scenarios. Polish proposals have materially approached European ambitions, and where the distance still remains large, it has approached the values set for our country in EU projections (e.g., the RES target in the EU is 42.5%, but Poland’s contribution according to the impact assessment to the draft RED III directive was set at 31–32%). The column with Polish targets included in the 2019 NECP (column 4 from the end) contains a proposal almost twice as small as the current one, e.g., reducing greenhouse gas emissions, which also needs to be assessed in terms of the size of the challenges facing the economy. Thus, the ambitions expressed in the final proposals of the WAM scenario must have influenced the upsizing of investment assumptions and implementation schedules.

For the purposes of the ongoing assessment, the area of energy and heat production and related primary fuel demand was analyzed. The assumed effects of energy savings in final consumption were taken into account, as well as the progressive electrification of heating and transportation.

Table 3. NECP’s projected gross electricity and heat production. Data based on NECP (ambition transformation scenario).

	2005	2010	2015	2020	2025	2030	2035	2040
Electricity [GWh]	157,295	158,186	165,128	158,247	180,213	192,604	228,257	307,923
District heating [TJ]	336,292	335,831	274,357	285,870	280,425	251,724	229,116	221,327

and

Table 4. NECP’s projected gross electricity production by primary energy source [TWh]. Data based on NECP (ambition transformation scenario).

	2005	2010	2015	2020	2025	2030	2035	2040
Lignite	54.8	48.7	52.8	38.1	31.2	11.4	3.0	0.0
Hard coal *	88.5	89.3	79.4	70.7	64.6	31.9	16.5	4.1
Gas fuels **	5.2	5.1	6.4	17.4	23.4	30.8	26.9	9.9
Heating oil	2.7	2.6	2.1	1.7	1.8	1.4	1.2	0.9
Nuclear energy	0.0	0.0	0.0	0.0	0.0	0.0	9.5	58.1
Biomass	1.4	5.9	9.0	6.9	6.8	7.9	7.4	7.5
Biogas/biomethane	0.1	0.4	0.9	1.2	2.2	3.2	3.5	4.8
Hydropower	2.2	2.9	1.8	2.1	2.6	2.9	3.0	3.0
From pumped water	1.6	0.6	0.6	0.8	1.2	3.9	3.9	6.6
Onshore wind energy	0.1	1.7	10.9	15.8	28.6	47.4	59.2	69.5
Offshore wind energy	0.0	0.0	0.0	0.0	0.0	21.7	45.5	67.4
Solar energy	0.0	0.0	0.1	2.0	15.3	24.6	33.9	43.1
Geothermal energy	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Hydrogen	0.0	0.0	0.0	0.0	0.0	0.0	6.9	17.8
Other ***	0.7	1.1	1.0	1.5	2.5	2.4	2.2	1.8
Energy storage (Batteries)	0.0	0.0	0.0	0.0	0.0	3.1	5.7	13.5
Total	157.3	158.2	165.1	158.2	180.2	192.6	228.3	307.9

* Including coke oven gas and blast furnace gas. ** High-methane and nitrogenous natural gas. gas from mine de-methanation. gas accompanying oil. *** Inorganic industrial and municipal waste. Source: ARE S.A.’s own study. (MESSAGE-PL) on behalf of the IOC. EUROSTAT.

show projections of electricity and district heat production. These volumes are given as gross, i.e., including the power plant’s own demand and network losses. Attention should be paid to the projected value of electricity production, especially its increase in the period 2035–2040 by about 80,000 GWh. Compared to the projections in PSE’s documents [17,18], the net demand for electricity in 2040, in the dynamic transformation scenario, brings about 235,000 GWh, compared to 308,000 GWh in the NECP. Note the difference between the net and gross values, adopted differently in the PSE planning and in the work on the NECP, which causes some interpretation and comparison difficulties.

The structure of the projected energy mix is shown in Table 4. In 2030, 56.1% of electricity is assumed to come from renewable sources. At the same time, the share of coal and lignite will fall to 19%. For 2040, the percentages are 76% and 1.3%, respectively. In addition, a new category of electricity source has been created, called Storage (Batteries), which could refer to excess energy that could be stored, rather than reduced and used during periods of demand. But it is also possible to interpret it as energy from pumped hydro, in which case it is not additional energy, but produced from other sources and used through storage.

For district heating and individual heating, the target for the share of renewable energy in 2030 was set at 35.4%, assuming an increase of 0.8–1.1% year-on-year.

Table 5. NECP’s projected achievable power in the NPS [GW], broken down by primary energy sources. Data based on NECP (ambition transformation scenario).

	2005	2010	2015	2020	2025	2030	2035	2040
Lignite pp	8197	8145	8643	7445	6566	6566	3344	683
Hard coal pp	14,613	14,655	13,617	15,889	14,465	9136	5847	4572
Gas/Hydrogen pp	0	0	0	0	1332	5957	5957	6703
Nuclear pp	0	0	0	0	0	0	1170	6225
Nuclear_SMR	0	0	0	0	0	0	600	1200
Water pp	914	935	964	987	1008	1118	1148	1178
Peak-Pump pp	1679	1679	1705	1705	1767	2510	2510	4235
Industrial pp	6140	6126	1605	1945	1814	1755	1608	1110
Hard coal chp			4968	5226	4578	3757	2403	19
Gas/Hydrogen chp	760	807	928	2688	3515	5071	4581	4760
Biomass pp and chp	102	140	513	534	669	983	1116	1145
Biogas/biomethane chp			216	241	362	509	526	519
BECCS	0	0	0	0	0	0	0	0
Wind farms on shore	121	1108	4886	6499	11,996	19,028	23,042	25,816
Wind farms offshore	0	0	0	0	0	5927	12,233	17,883
Geothermal pp	0	0	0	0	0	0	0	0
Photovoltaics	0	0	108	1229	19,726	28,976	37,901	46,293
Peak_gas/hydrogen	0	0	0	0	0	0	0	805
Energy storage facilities	0	0	0	0	50	1975	3690	8706
DSR/power import	0	0	150	615	1788	2864	3524	3874
Total	32,526	33,594	33,118	39,535	69,634	96,131	111,201	135,749

shows the projected mix of installed capacity in the national system, depending on the source of primary energy. Coal-fired and gas-fired power plants in 2030, which mainly perform regulation and backup functions for RES sources, are planned in capacities of, respectively, 15.7 GW and 6 GW. In the 2025–2030 period, phased-out coal-fired units will be replaced by gas-fired power plants (the total capacity of gas-fired power plants and CHP plants reaches 11 GW in 2030). In 2040, coal- and lignite-based capacity will drop to 4.5 and 0.7 GW (the newest units will be Kozienice, Opole, Jaworzno, and Turów), while the capacity of gas units will increase slightly to 6.7 GW. In 2035, production is assumed to commence from the first unit of the nuclear power plant (capacity of 1.2 GW) and the SMR modular power plant (capacity of 0.6 GW). In 2040, nuclear power, with a total capacity of 7.4 GW, will be an important component of the system’s power and energy mix. The reduction in the level of controllable coal and gas power in the NPS means that regulatory functions will have shifted to energy storage (pumped storage and chemical storage) and, to some extent, to nuclear units.

The reality of achieving the climate goals declared in the draft NECP in 2030 requires a critical look at the plan’s assumptions below:

• The current energy policy assumes electricity production in 2040 of 204,000 GWh, with 60 GW of installed capacity in the NPS. The NECP project assumes, respectively, 307,900 GWh and 135.7 GW of capacity. Why such a difference in forecasts?
• Is the commissioning of the first nuclear units possible before 2035?
• Commissioning of 25 GW of new weather-dependent renewable capacity by 2030. Is it possible to implement?
• Decommissioning of 6 GW of controllable coal capacity by 2030. How to replace it?
• If 30–35 TWh of electricity from gas is assumed (in the period 2030–2040), are more gas units needed? Peak power from coal or gas?
• Will 2 million Mg of coal (4000 GWh of electricity) ensure energy security and sovereignty in 2040?
• What is the alternative scenario if the investment deadlines for offshore wind and nuclear power are moved forward by 5 years?

Critical analysis of the above assumptions, at the expert level, indicates that there is a high risk of achieving the assumed progress of electrification of heating, transportation, and industrial processes, as well as the reality of meeting the timetables for investment in new capacity, especially nuclear. The arguments that support this include the following:

• In 2024, PSE has tentatively measured electricity demand at 169 TWh and domestic production at 167,000 GWh (Table 1). To this would have to be added prosumer production, which is directly consumed, of about 3–4 TWh. Table 4 assumes gross production in 2025 of 180,200 GWh. There is some difficulty in estimating the sources’ own needs in the changing mix in subsequent years (for new coal-fired power plants, own needs are about 10% of gross production). Also, network and other losses depend on the structure of the network and the distance over which electricity is transmitted. If it is assumed that demand/production in 2025 will remain at the same level as last year or increase slightly, then the difference between gross and net value could be estimated at 12,000–14,000 GWh. The NECP in the WAM version assumes an increase in production/demand in the 2025–2035 decade by 35,700 GWh. While in the 2015–2025 decade, it was 15,000 GWh, twice as much. In the five-year period of 2035–2040, the increase doubles again, reaching 79.6 TWh. (Gross electricity production of 3,079,000 GWh in 2040). In PSE’s 2024 development plan, demand for electricity in 2040 is assumed to be between 2010 and 235,000 GWh, depending on whether the decarbonization/electrification of the economy is more or less dynamic. Expert assessment indicates that the demand for electricity assumed in the NECP is too high. This must be followed by expenditures on new generation sources, which will not be needed in case of lower demand. According to the authors, electricity demand in 2040 should be estimated at the level of PSE’s dynamic scenario, i.e., 235,000 GWh.
• At the beginning of 2025, the status of the first nuclear project, which assumes the construction of three AP1000 nuclear units by Westinghouse, does not indicate the technical or organizational feasibility of meeting the deadline for the commissioning of the first unit envisaged in the current energy policy, i.e., 2033. According to the update of the Polish Nuclear Power Program [19], which is being prepared, commercial operation of the first unit is assumed to begin in 2036, and the subsequent ones will begin in 2037 and 2038. The handover of the construction site to the contractor is to take place in 2025 (!) and the start of the actual work on the nuclear power plant in 2028. It should be recalled at this point that currently, in the project of the first nuclear power plant in Choczewo-Lubiatowo, intensive work is being carried out on the financing model, in particular, the scope of state aid. The Polish side has applied to the EC with proposals for state capital participation in the project at the level of 30%., i.e., PLN 60 billion, according to the current budget estimate, a state guarantee for the remaining outlay raised from the capital market, and a contract for difference formula for the purchase of electricity. The EC is examining the legitimacy and proportionality of the scope of the requested state aid. Domestic experience in the construction of large coal-fired power units in the previous decade indicates that there is a construction cycle of about 10, starting from the decision to initiate the bidding process. More relevant here is the experience from the construction of recent nuclear power plants in Olkiluoto in Finland, Flamanville in France, or Hinkley Point C in the UK. In the latter case, two units with a total capacity of 3.200 MW being built by France’s EdF may be delayed by about five years from the original schedule, and the budget may exceed £40 billion (the original target was to deliver the first unit in 2025, with a budget of £18 billion in total), according to the contractor’s announcements in early 2025 [20,21]. Taking this into account, an expert estimate of the delivery date for the first unit of a nuclear power plant in Poland assumes that it will be possible around 2040.
• Between 2025 and 2030, an increase in renewable capacity of 25 GW has been assumed. The largest increase, by 9.3 GW, is expected to come from photovoltaic power plants, followed by onshore wind power plants, by 7 GW, and on the Baltic Sea, by 5.9 GW. The rest are energy storage plants, assuming that they store surplus renewable energy that would otherwise be lost. Investments in photovoltaic power plants are not complicated, but on the side of ensuring the introduction of electricity produced by them into the grid, the matter looks much more serious. Currently, these are not commercially preferred solutions, unless considered with large-scale storage combined. The cheapest electricity can be produced by onshore wind power plants. Unfortunately, the development of investment in this segment has stagnated, and there is no indication that a compromise on the so-called “distance law” will be reached soon, allowing new locations for these power plants [22]. Retrofits of older wind power plants, with lower towers and capacities, and thus lower efficiency and hours of operation, are also expected soon. There is a serious risk to the feasibility of increasing capacity in this technology by 1.5 GW every year. Offshore wind farms are slowly entering the implementation period. The largest Polish projects of Orlen, PGE, and Polenergia are being implemented with foreign partners. In January 2025, PGE announced the start of a joint investment with Denmark’s Overstate in the 1.5 GW Baltica 2 wind farm, with a budget of PLN 30 billion. It should be mentioned that this project is covered by a contract for difference, with a price guarantee, and that the price is expected to exceed PLN 500 per MWh. While regulatory risk is important in the case of onshore wind farm investments, offshore wind farms will primarily face technological risk. Only the first work on the foundation and installation of the turbines will make it possible to assess the risk of meeting the schedule for building the towers with turbines and generating the power. It is expertly assumed that the implementation of any new technology involves technological and budgetary risks, as well as the occurrence of so-called “childhood diseases.” According to the authors, there is a risk of postponing the commissioning date of offshore wind farms, as well as the capacity of wind power plants commissioned by 2030.
• The draft NECP assumes a rapid reduction in coal-fired capacity in the national mix. It has been assumed that, as a result of the cessation of support from the capacity market for power plants emitting more than 550 kg of carbon dioxide per MWh, most of these units will be decommissioned from mid-2025. Work is currently underway to extend support until 2028, but the annual auction formula proposed in the amendment to the law means that units that do not win support for 2026 will not be willing to wait for the 2027 auction, bringing losses to the operator in the meantime. Analyses carried out in PSE’s Development Plan show that if the 6 GW of controllable coal capacity planned in the NECP is set aside by 2030, despite the commissioning of new gas units, the balance of increasing demand for controllable power in the system is unfavorable. There is a growing risk of the occurrence and prolongation of power outages for customers beyond ENTSOE standards. In the expert assessment for the period 2025–2030, it is necessary to prepare an analysis of the demand for controllable power in the NPS, in specific locations, power volumes, and timeframes, prepared by PSE. If this analysis identifies excess capacity, it should be permanently set aside. For units that are necessary from the point of view of the system operator, financing should be provided under the strategic/balance reserve formula, over and above the existing capacity market, and regardless of the planned capacity market after 2030. According to the authors, in the 2030 perspective, it is necessary to maintain most of the existing reserves in 200 MW class units as controllable power sources.
• The NECP assumes that in 2030, natural gas-fired power plants and CHPs, and after 2035 with the addition of renewable gas fuels, will produce 30.8 TWh of electricity. The maximum production from gas in the 2035 perspective will not exceed 35 TWh. The key issue remains the mode of operation of the planned gas-fired power plants and their role in the NPS. If it is assumed that 6 GW of gas-fired capacity will be operating in the NPS in 2030, they will be more than capable of supplying the NPS with 35 TWh of electricity. However, if it were to be assumed that gas-fired units would be regulatory, then an analysis should be made of the right proportion of coal-fired (existing) and new gas-fired (to be built) capacity to ensure the lowest cost to consumers. According to the authors, in order to mitigate the risk of natural gas availability and price, it is necessary to maintain coal and gas capacity (6 GW in 2030, in the ongoing Ostrołęka, Grudziądz, Rybnik projects). In addition, only open-cycle gas units can be considered as peaking capacity. Investments in new CCGT units will not ensure the profitability of these units and are unjustified.
• The national plan assumes a virtual shift away from coal in the power industry in 2040. The assumed production of 4100 GWh of electricity implies a demand for 2 million Mg of hard coal and implies an accelerated liquidation of domestic mining. Although the WEM version of the plan assumes a scenario with demand for hard coal in 2040 at 10 million Mg, which corresponds to the social agreement signed by the government with the representation of the mining industry, achieving the declared climate goals is possible only with the ambitious scenario. Decarbonization of produced electricity is expected by the domestic industry. According to the authors, any steps towards increasing renewable energy in the energy mix should be prioritized, but with the principles of stability of operation and security of the national system. Expert studies conducted at the Central Mining Institute indicate a demand for thermal coal in 2040 at 10–12 million Mg (Figure 2). The chart presented here includes projections based on the current energy policy (19.1 million Mg of coal in 2040) and the NECP project (2 million Mg). In the scenario of high emission allowance prices and Scenario 3, from June 2023, which was not adopted, the volume of demand oscillates between 10 and 11 million Mg in 2040. The main reason for the differences in demand lies in the risk of delaying investments in nuclear power and offshore wind farms. If the realistic date for the commissioning of the first nuclear unit is estimated to be around 2040, then the question of filling the primary energy sources and the generation gap between 2035 and 2045 will remain open.

The expert assessment [23] is that there is a high risk that the timetable for implementing the nuclear power program will be postponed by about five years. Thus, if instead of the nuclear power production of 58,100 GWh assumed in the NECP in 2040, this volume will be 95,000 GWh (as assumed in 2035), and then the question is, from what energy source can the missing energy be supplied? The situation is similar in the offshore wind power segment. The materialization of the risk of delaying the implementation of the multi-directional investment program in this segment could result in the under-delivery of about 21,900 GWh to the grid in 2040 (the difference between the assumed production of 67,400 GWh in 2040 and 45,500 GWh in 2035). In total, the estimate of the undersupplied electricity to the national system in 2040 is about 70,000 GWh. In the 2035–2040 period, this figure will grow, along with the last coal-fired power plants being decommissioned, to about 70,000 GWh in 2040.

It is necessary to analyze what sources of primary energy will be available in the period 2035–2040 and what investments should be made to provide alternative sources of power supply to the electricity system. From the point of view of the availability of domestic primary energy sources, the availability of domestic hard coal should be assumed with a high degree of certainty, as well as the small reserves of lignite in the Turow area. Poland does not have its own deposits of natural gas, and the volume of extraction, available domestically, will not significantly increase (extraction amounted to 3.4 bcm in 2023). The network infrastructure and the availability of gas fuel from Norwegian deposits, or the import capacity of liquefied gas, fully secure the needs of the domestic economy, including the energy sector. If one ignores the risk of conflicts in the region and the associated certainty of supply, and the attendant risk of high price volatility, gas could be considered a fuel of the transition period, and, therefore, also for the alternative scenario. Both gas and coal, from the point of view of climate policy, are considered transitional fuels, and because of their emissivity, are recommended for rapid phase-out. Mention should also be made of the marginal cost of electricity generated using them, which is burdened by a carbon fee. Poland does not have energy resources from water, nor does it have a significant availability of biomass, as well as biogas, due to its allocation to other segments of the economy, which cannot be considered a significant potential to increase the amount of electricity for the alternative scenario.

Significant overcapacity is emerging in the onshore wind and solar power segments. In the case of the former, the NECP assumes an installed capacity of 25 GW in 2040, with production of 69,500 GWh, and in the case of photovoltaics, 46.3 GW capacity and 43,100 GWh production, respectively. The large excess of installed capacity over system needs results in these sources, especially photovoltaics, being reduced by the system operator during the hours of maximum sunshine. It can be estimated that the amount of electricity not injected into the grid, in both of these technologies, will be about 10,000 GWh in 2040. Assuming the import-export neutrality of the national system and the future availability of existing coal-fired power plants, including those with built-in CCS facilities [20], and the availability of additional imported gas, the provision of electricity in the period 2035–2040 should be considered under alternative options.

Alternative scenario assumptions:

• The annual average generation gap between 2035 and 2040 is estimated at 60,000 GWh (with a maximum of 70,000 GWh in 2040).
• Available capacity of coal-fired power plants in 2040 (Kozienice, Opole, Jaworzno, and Turów)—4.2 GW. In addition, some units of the 200 MW class, in particular, the Połaniec power plant, with a capacity of about—1 GW, generate about 35,000 GWh of electricity per year. No new coal-fired units are assumed.
• CAPEX for carbon capture facilities is estimated at EUR 1.2 billion/1 GW.
• Energy storage facilities for storing excess energy from the RES that cannot be fed into the grid will be implemented, with a capacity of about 2.5 GW, in four-hour chemical storage facilities. If pumped storage capacity is built in three locations: Młoty, Tolkmicko, Rożnów, it will also be about 2.5 GW.
• CAPEX for chemical energy storage is estimated at about EUR 1 billion/1 GW, in four-hour storage.
• Capital expenditures for new large-scale gas CCGT units are estimated at about EUR 1.1 billion/1 GW.
• The price of emission allowances will increase in 2035–2040 from EUR 120 to EUR 250 (as assumed by the NECP), averaging EUR 185 per allowance per year.

Three options for filling the generation gap in the period 2035–2040 were analyzed:

• Gas scenario with renewable energy surplus storage.
• Coal scenario with energy storage redundant with RES.
• Coal scenario with CCS, with energy storage redundant with RES.

In the gas scenario (see

Table 6. Comparison of alternative scenarios.

No.	Indicators	Gas + Storage Scenario	Scenario Coal + Storage	CCS Coal + Storage Scenario
1	Capacity of new/existing generation units	7.0 GW	5.2 GW	4.2 GW
2	Capital expenditures	EUR 7.0 billion	EUR 0.5 billion	EUR 5.5 billion
3	Expenditure on storage	EUR 2.5 billion	EUR 2.5 billion	EUR 2.5 billion
4	Electricity production/year	60,000 GWh	45,000 GWh	35,000 GWh
5	Fuel requirements	6.5–7 bcm. gas	20 million Mg. coal	20 million Mg. coal
6	Emissivity of electricity production/average increase in MWh cost due to emissions	approx. 0.35 Mg/MWh 65 EUR/MWh	approx. 0.80 Mg/MWh 144 EUR/MWh	approx. 0.05 Mg/MWh 9 EUR/MWh

), there is the possibility of building an additional 7 GW of gas capacity, which will provide the possibility of generating about 50,000 GWh of electricity per year and, together with energy storage facilities, will fill the gap for the alternative scenario. In the coal scenario, the capacity of disposed coal-fired power plants will be about 5 GW, which will provide the possibility of generating about 35,000 GWh of electricity. Including stored energy, this gives a potential of about 45,000 GWh per year. In the scenario with the equipping of existing new coal-fired power plants (without 200 MW units) with CCS facilities, the capacity to cover the generation gap will decrease to about 25,000 GWh, due to the decrease in efficiency.

Comparing the alternative scenarios presented in Table 6, the following conclusions can be drawn:

• With a generation gap of about 60,000 GWh per year between 2035 and 2040, only the gas scenario with storage of surplus energy from RES offers the possibility of fully covering this gap.
• Coal scenarios, assuming only necessary upgrades, including the development of CCS facilities for new units, will not provide sufficient generation to cover the gap.
• With the assumed price path for emission allowances, investments in CCS facilities are profitable and can ensure the lowest carbon intensity of the energy produced. The critical path is to prepare the national infrastructure for carbon dioxide transport and storage.
• The least investment and upgrades are required in a carbon scenario without CCS, but it leaves the highest carbon footprint.
• If the coal scenario is chosen, with or without CCS, it will be necessary to fill the generation gap with gas fuel, including the construction of new gas-fired power plants.
• Filling the generation gap with energy from chemical energy storage facilities, in a long-term storage formula, may prove unprofitable and significantly increase the cost of electricity.
• Maintaining energy independence indicates the need, at least in part, to implement one of the carbon scenarios.
• It was assumed that the price of emission allowances would increase from EUR 120 to EUR 250 between 2035 and 2040 (in line with the NECP), averaging EUR 185 per allowance per year. A sharper increase in the price of allowances, i.e., to EUR 400 in 2040, would result in an average of EUR 280 and a 55% increase in the cost of allowances in MWh of generated electricity in all scenarios.

4. Conclusions

Taking into account the beginning of the new term of the European Commission, as well as the Polish presidency of the European Union, whose task will be, among other things, to prepare legislative initiatives for the reconstruction of the European economy, especially its competitiveness, we would like to draw attention to the following conditions of the presented National Energy and Climate Plan:

• The ambitious transformation of the country’s power and heating industry toward renewable and low-carbon sources is not debatable in terms of direction. What matters is the pace. Increasing the amount of renewable energy from weather-dependent sources injected into the national system is partly possible by improving the flexibility of the NPS by making demand more flexible, increasing storage capacity, including thermal storage, electrification of certain sectors of the economy (sector coupling), and increasing the regulation capacity of existing conventional units. We call for synchronizing the pace of increasing the flexibility of the NPS (including long-term storage) with the implementation of planned investments in renewable sources, so that the output of newly built sources can be maximized.
• Existing coal-fired units are the cheapest reserve of the NPS during the transition period. Throughout the entire period of technological transformation of the energy sector, it is always necessary to ensure a momentary balancing of energy demand with energy supplied to the NPS. The condition for stable operation of the NPS for the next 10–15 years is the maintenance of a sufficient amount of fossil fuel controllable capacity. For this group of units, whose revenues do not cover costs (too short operating time), it is necessary to build financial mechanisms to guarantee coverage of fixed costs (balance/strategic reserve). For new low-carbon controllable sources (gas and other technologies), it is necessary to continue the power market mechanisms. We assumed that the NPS controllable reserve should be maintained mainly on the basis of existing coal-fired power plants and gas-fired sources built so far (the cost and emissivity of the fuel are not significant in peak operation).
• Need to synchronize the coal phase-out program with power generation needs for the transition period. Until the planned nuclear power capacity is built, it is necessary to plan the demand for power capacity and primary energy sources (2025–2045). For such planned capacities in the system, it is necessary to determine the expected volume of production and the necessary primary energy sources, including coal from domestic mines (according to cost and quality ranking). The security and energy sovereignty of the state dictate that minimum domestic primary energy sources and generation resources be secured in case of external threats. We call for reconsideration of the volume of coal demand for energy purposes in 2040 (assumed to be about 2–10 million Mg).
• Distributed generation and local use of electricity. It is most efficient to generate and use energy locally. In the energy policy/NECP and support mechanisms, this area should receive special attention. Previous initiatives to build clusters and local energy communities have proved unsuccessful. We call for building effective mechanisms for this area to reward local energy generation and use.
• Electricity with a low carbon footprint and at a competitive price is a condition for industrial development. The demand for rapid transformation and lowering the carbon footprint of electricity produced is understood and not questioned by energy producers. However, the inertia of the transition away from fossil fuels, especially in controllable units, leads to a renewable energy deficit and high prices. We call for additional analyses to be carried out to determine price and carbon footprint forecasts for electricity and heat over the plan horizon.

It is necessary to re-examine some of the assumptions of the proposed NECP, in view of the risks cited above. External commitments to EU institutions should be made after a particularly careful assessment of the impact on the national economy and social issues. According to the authors, the adoption of the NECP should be preceded by an update of the energy policy and alignment with the national industrial policy. We also draw attention to the new term of the European Commission, which began at the end of 2024, and the need to synchronize national policies with the EC’s priorities for 2024–28 [24].