Charts in Figure 7 present weekly electricity consumption profiles (W—week) in the groups of trading and sales company's key clients during the first and second lockdowns. The dashed line marks the period without restrictions (W10–11) and (W42–43) while the solid line the lockdown periods (W13–W18) and (W44–W48). The consumption values for the weeks W16, W18, and W46 are distorted because of the official days off, Easter Days (12–13 April), Labor Day, and 3 May Constitution Day (1–3 May), also Polish Independence Day (11 November).

**Figure 7.** Weekly profiles of energy consumption for key sectors.

The analysis indicates that during the lockdown, the consumption volumes of Section C clients (manufacturing) have not changed drastically, but the volume decline was visible (400 MWh in the first week and 600 MWh/week in two others). The second lockdown did not significantly reflect on the volume of energy consumed by clients belonging to this section. Furthermore, during the lockdowns, for Section D clients (electricity, gas, steam, and air for air-conditioning supply), the energy consumption decrease was significant (400 MWh in the first week and more than 2000 MWh/week in the other three). However, the second lockdown did not impact the consumption value as much as the previous one. Besides trading real estates, Section L entities also service trading-office-entertainment complexes (shopping malls), which was clearly reflected in the electricity consumption volumes during the lockdowns. Yet, in the first lockdown, the volume of consumed energy decreased by 1000–1300 MWh per week, which was ca. 50% of the total decline in that group. In the second lockdown, there is clearly visible the second wave of restrictions (associated with the limitations imposed on shopping malls), in the period W46–W48, the consumption volumes were decreasing by ca. 500 MWh per week.

Another step was conducting the volatility analysis. The tables demonstrate the computed coefficients of variation for energy consumed by the clients. They are supplemented by standard deviation and mean values. The tables include the calculations of energy consumption volumes for weeks (Table 1), a selected working day, Tuesday (Table 2), and a selected day off, Saturday (Table 3). In all cases, the volatility of consumption volumes in 2020 did not change significantly compared to 2019. However, the noticeable changes in total values were related to the pandemic limitations.

**Table 1.** Results of volatility analysis—coefficients of variation (Energy consumption—week).

**Table 2.** Results of volatility analysis—coefficients of variation (Energy consumption—a working day).

**Table 3.** Results of volatility analysis—coefficients of variation (Energy consumption—a day off).

The volatility analysis for weekly electricity consumption values (Table 1) shows that the variation in the whole year was insignificantly higher. In the analysis of shorter (quarterly) intervals, it increased significantly only in the first quarter (from 3% to 10%), which could be caused by introducing the first restrictions at the end of the quarter. Despite the lockdowns, in the second and fourth quarters, the variation in 2019 and 2020 was ca. 12%. It was influenced by the restrictions and periods with the expected total change in energy consumption values (Easter, May weekend, II quarter, All Saints' Day, and Christmas, IV quarter).

In the case of energy consumption values for a selected working day, Tuesday (Table 2), the analysis indicates a minimal increase of volatility in the yearly scale (from 6% to 8%) and individual quarters with the restrictions. In the first quarter it increased from 2% to 6%, in the second from 8% to 11%, and in the fourth from 4% to 9%, respectively. 1 January 2019 (New Year) was a day off, which is why the analysis omits the consumption values for that date.

The volatility analysis of energy consumption in the selected day off, Saturday (Table 3), indicates that in 2020, the variation was insignificantly higher than in 2019. Unlike for the values for working days, the higher variability of electricity consumption could be observed in the first, second, and third quarters.

Tables 4 and 5, Figures 8 and 9, present the analysis of weekly energy consumption volumes during the first and second lockdowns in relation to the trend outlined based on four weeks before introducing restrictions.

In the first lockdown, decreases of the actual electricity consumption compared to expected values were large. Only at the first stage of implementing restrictions (since 14 March), the decrease of consumption in the subsequent weeks was 11%, 16%, and 15%. The consequences of limiting commerce, closing shopping malls, and restrictions imposed on industry were tangible. After introducing new restrictions (1 April), one could observe an additional decrease in the weekly energy consumption values. However, the following weeks of the first lockdown could not be analyzed in detail because of the Easter holidays (21–22 April 2019 and 12–13 April 2020).

The second lockdown analysis concerned the five restricted weeks. During that period, there was no limitation on movement and entire suspending services and commerce. The differences to the appointed trend were 2%, 2%, 11%, 6%, and 2% in subsequent weeks. The second wave of restrictions is clearly marked by the moment of closing shopping malls (from W46). As in the first lockdown, the difference to the appointed trend in the first week of the restrictions was 11%. However, actual energy consumption values were lower than expected.

**Table 4.** Analysis of energy consumption in relation to the forecast trend (the first lockdown).

**Table 5.** Analysis of energy consumption in relation to the forecast trend (the second lockdown).

**Figure 8.** Analysis of energy consumption in relation to the forecast trend (the first lockdown).

**Figure 9.** Analysis of energy consumption in relation to the forecast trend (the second lockdown).

#### **6. Conclusions**

The analysis confirmed an evident decline in energy consumption volumes during the lockdowns compared to values for 2019 and from several weeks before introducing new limitations. The changes are evident in the first stage of the pandemic. Beyond the lockdowns, energy consumption volumes in 2020 were several percent higher than in 2019.

The analysis of electricity consumption volumes of the key clients from the manufacturing and electricity, gas, steam, and air conditioning supply sections showed that the values were significantly lower only during the first lockdown while in the section real estate activities, each restriction related to closing shopping malls caused noticeable changes in energy consumption.

Restrictions imposed on the functioning of shopping malls cause a substantial decrease in the volumes of consumed energy in the analyzed group of clients, although

the total value of their consumption is only ca. 15%. Moreover, energy demand profiles reflect additional limitations related to movement, commerce, and services (the so-called beauty industry).

To summarize, the restrictions caused a 15–23% decline in energy consumption during the first lockdown and a maximum of 11% during the second, against expected values. The conducted analysis demonstrates that in the context of the decline, the most significant aspect for the investigated group of clients was the limitation of commerce (including the closing of shopping malls). That and other restrictive regulations caused a ca. 9–11% decrease in energy consumption against the expected value in both periods of restrictions. The results should be verified based on data from lockdowns introduced in 2021.

The analysis demonstrates that additional restrictions (ban of movement, limiting commerce, and services) cause a higher drop in consumed energy volumes. The collected data are insufficient for concluding about exact values because some limitations were employed only one time.

The second lockdown caused changes in energy consumption profiles in the analyzed group of clients. Undoubtedly, it was impacted by the type of restrictions. During the second lockdown, there were no limitations on movement and no entire closing of commerce and services. Moreover, safety protocols used by industries have not entailed the necessity for limiting or canceling production.

The conducted volatility analysis proved that consumption volumes in 2020 did not change dramatically compared with 2019. However, the temporal increase of the coefficient of variation during the lockdowns was observed. The impact was seen particularly in analyzing energy consumption on a typical working day (Tuesday) for the first, second, and fourth quarter of the year and a day off (Saturday) for the first and second quarters.

The results are adequate to an energy trading and sales company having in its portfolio client groups mentioned in the paper (industry, services, commerce). It is possible that the implemented restrictions influenced various business activities differently. That observation justifies the need for conducting detailed analyses of the restrictions' impact on energy consumption in different branches of the economy.

The conducted research and further detailed analyses are required to improve the methods of forecasting customer energy consumption. Due to the dynamically changing electricity prices, the accurate forecasting of energy volumes significantly impacts the finances of energy trading and sales companies.

**Author Contributions:** Conceptualization, M.M., G.K. and M.C.; methodology, M.M., G.K. and M.C.; software, M.M.; validation, M.M.; investigation, M.M., G.K. and M.C.; resources, M.M. and M.C.; data curation, M.M. and G.K.; writing—original draft preparation, M.M., G.K. and M.C.; writing—review and editing, M.M., G.K. and M.C.; visualization, M.M. and G.K.; supervision, G.K. and M.C. All authors have read and agreed to the published version of the manuscript.

**Funding:** The publication has been financed using a subsidy for maintenance and development of research potential and received no external funding.

**Acknowledgments:** The work was carried out as part of the statutory activity of the Mineral and Energy Economy Research Institute, Polish Academy of Sciences and WSB University.

**Conflicts of Interest:** The authors declare no conflict of interest.

#### **References**

### *Article* **Can Decarbonisation and Capacity Market Go Together? The Case Study of Poland**

**Aleksandra Komorowska**

Mineral and Energy Economy Research Institute of the Polish Academy of Sciences, 31-261 Kraków, Poland<EMAIL_ADDRESS>Tel.: +48-12-617-16-70

**Abstract:** In recent years, numerous countries have introduced or considered capacity markets as remuneration mechanisms for long-term capacity adequacy. Since adequacy is frequently linked with thermal power generation, there is an ongoing debate as to whether this instrument could impact decarbonisation. In this context, the paper presents a quantitative assessment of the consequences of introducing a capacity market on decarbonisation pathways. The Polish power system is taken as an example due to its heavy dependence on fossil fuels. To this end, a computable model of the Polish power system is developed and applied to the study of two research scenarios. The first scenario presents the power system without introducing a capacity market, while the latter considers the system with a capacity market in place. The analysis shows that the introduction of a capacity market delays the decarbonisation of the power system and has a negative impact on carbon neutrality. Even though coal-fired units are phased out, they are mainly replaced by natural gas. The method and model developed within this study can be applied to countries where a capacity market is being discussed, and fossil fuels continue to play a dominant role.

**Keywords:** decarbonisation; energy transition; capacity market; capacity adequacy; linear programming

### **1. Introduction**

Decarbonisation of power systems is one of the solutions to the problem of climate change [1]. The phasing-out of conventional power plants and their replacement with renewable generation sources results in a significant decrease in greenhouse gas (GHG) emissions. Although the environmental impact of decarbonisation is noticeable, the energy transition in systems with high penetration of fossil fuels has to consider other factors. The policymakers, transmission system operators, and regulatory bodies are required to ensure energy security [2]. As a result, the decarbonisation processes are different in different countries [3]. Although in Refs. [4,5] the authors indicate that fulfilling the requirements for zero-carbon electricity is possible by 2050, there is a need to investigate the potential in individual countries.

Another trend that has been observed in recent years is ensuring the adequacy of capacity. Apart from the advantages of energy liberalisation [6], the current electricity market design also has numerous failures. The following causes are indicated in the literature [7–9]:

**Citation:** Komorowska, A. Can Decarbonisation and Capacity Market Go Together? The Case Study of Poland. *Energies* **2021**, *14*, 5151. https://doi.org/10.3390/en14165151

Academic Editors: Abbas Mardani and François Vallée

Received: 25 June 2021 Accepted: 18 August 2021 Published: 20 August 2021

**Publisher's Note:** MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.

**Copyright:** © 2021 by the author. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

• Price cap regulations: The price increase during periods of peak demand is administratively constrained. Therefore, fewer potential market signals occur in these periods than would be expected.

Global experience indicates that energy liberalisation has not met its major ends, and power companies do not receive sufficient revenues to cover their operational and capital costs. The situation where the electricity market revenues are too low to cover the total costs of power generation units is referred to as the missing money problem [10]. The market signals also do not provide a sufficient incentive for investors to build new power units. The lack of investment signals may result in missing capacity in the power system and, consequently, have serious implications for the entire economy and society.

#### *1.1. Capacity Market*

To this end, numerous countries have introduced or considered capacity remuneration mechanisms (CRMs), including the capacity market [11]. CRMs are energy policy instruments designed to ensure long-term capacity adequacy [12]. They provide additional remuneration for power companies in compensation for electricity generation in peak demand. They are also considered as instruments that ensure the stability of the power system during decarbonisation [13]. CRMs stimulate not only generation companies but also encourage consumers to reduce their electricity consumption in periods of peak demand. There are two essential categories of CRMs: (i) based on price: capacity payments and (ii) based on volume: strategic reserve, reliability options, capacity obligations, and capacity auctions. These mechanisms are discussed in detail in Refs. [8,10,12,14,15]. These instruments provide additional remuneration for power companies in compensation for electricity generation in peak demand. However, they may extend the economic lifetime of obsolete, usually carbon-intensive, power units.

Authors of Ref. [16] indicate that capacity mechanisms unintentionally favour peaking technologies like coal, oil and gas over wind, solar, or nuclear technologies. In Ref. [17], the authors investigate the impact of the capacity market design on power system decarbonisation in PJM (Pennsylvania-New Jersey-Maryland). The results show that the existing model of the capacity market does not specially target low-emission technologies but can be modified to fulfil the goals of power system decarbonisation. In Ref. [18], the authors review the support policies for renewable energy. Although they list numerous instruments (auctions, feed-in tariffs, and others), they do not mention any capacity remuneration mechanisms. Authors of Ref. [19] also emphasise that current designs of capacity markets do not provide incentives for intermittent renewable generation sources. The study presents a mathematical model that allows one to consider the specific characteristics of renewables in the design of capacity remuneration mechanisms. In Ref. [20], the authors analyse the consequences of the introduction of a capacity market in Poland but focus solely on the economic results. They present the impact of the mechanism on electricity prices.

The literature review indicates that there have been papers analysing the impact of capacity market design on decarbonisation. However, they mainly focus on the benefits of this mechanism to various technologies, especially carbon and non-carbon ones. Moreover, since previous studies mostly concern the short-term (up to five years) effects of capacity market operation, there is a limited number of studies on the long-term (more than ten years) consequences of the introduction of the capacity market, particularly in countries dependent on fossil fuels.

The Polish power system is an interesting case study to investigate the impact of the capacity market operation on the progress of decarbonisation. The capacity market is a relatively new mechanism in Poland, and its impact on hard coal and lignite consumption has not so far been studied. In 2019 the capacity installed in thermal power plants was 34.3 GW (73.4% of total installed capacity), of which the capacity of coal-fired units accounted for 31.5 GW [21]. As a result, the power system is sensitive to climate policies that emphasise the significance of decarbonisation and increasing renewable generation [22]. On the one hand, the policymakers have made decisions supporting the development of

renewables [23], energy storage, electromobility, and other concepts aimed at achieving climate neutrality by 2050 [24]. On the other, the government introduced the capacity market to ensure long-term capacity adequacy. Therefore, there is a question of the long-term impact of the introduction of such an instrument on the efficiency of the energy transition of power systems with a high penetration of fossil fuels.

#### *1.2. Study Contributions*

In this context, the main objective of the study is to conduct a quantitative assessment of the introduction of the capacity market on hard coal and lignite consumption for electricity generation in the Polish power system up to 2040. For this purpose, a techno-economic model of the Polish power system was developed. The model was formulated as a linear programming problem and implemented in MATLAB software. The impact is assessed by examining and comparing the outcomes under two scenarios: (i) with and (ii) without the operation of the capacity market. The following results are compared and discussed: (i) coal-fired generation capacity in the power system, (ii) electricity generation from coalfired power generation units, and (iii) the quantity of coal consumption for electricity generation. The changes in electricity prices over the period 2021–40 are also examined.

With this in mind, the study fulfils the research gap identified as a lack of studies on the long-term consequences of the introduction of a capacity market on the decarbonisation of coal-dependent power systems. The work contributes to the existing literature in the following ways. First, it provides a quantitative analysis on the influence of a capacity remuneration mechanism on the fuel mix of power systems with a high penetration of fossil fuels. Second, it provides the findings of the role of a capacity market in the decarbonisation process in such systems. Third, it extends the current studies on the consequences of the operation of a capacity market with a case study of Poland. Finally, the findings contribute to a discussion on the reasonability under environmental regulations of operating a capacity market in power systems dominated by coal-fired generation.

Poland is taken as an example due to the dominant share of fossil fuels in its electricity generation. However, the concept of the study and mathematical formulae can be applied to other countries where fossil fuels are prevalent and capacity remuneration mechanisms are considered or introduced. The main findings can also support the decision-making process in pursuit of carbon neutrality in such power systems.

The author is aware that the study has some limitations. The most important ones are described in this paragraph. The parameters used in the model were chosen as single points based on current reports and the best knowledge of the author. The model is a deterministic model and does not consider the probability distributions for uncertain input data [25,26]. The next step of the study will be to employ the probability distribution of each input parameter and provide ranges of results and the probability of their occurrence.

The study does not consider the adequacy indices (among others, Load of Load Probability (LOLP), Loss of Load Hours (LOLH), or Expected Energy Not Served). The power demand in the entire period of analysis (2021–2040) is based on the Polish Energy Policy until 2040. The document presents the values that include margins required to ensure power system security. However, these indices have been already studied in the previous paper [20] to investigate the economic consequences of introducing the capacity market in Poland.

The remainder of the paper is organised as follows. In Section 2, the approach and mathematical formulae applied in this study are described. This section also shows the scenarios and the assumptions regarding the input data. Section 3 presents the results of the study and discusses the main findings. Finally, conclusions are drawn in Section 4.

#### **2. Materials and Methods**

Linear programming is used in this study to assess the impact of the introduction of a capacity market on the decarbonisation of the power system [27]. Section 2.1 describes the methodology developed and employed. This section also presents the conceptual model of the Polish power system. Section 2.2 describes two formulated scenarios and their key assumptions. Section 2.3 presents the transposition of the conceptual model to the mathematical model: equations and inequalities are presented and described. Finally, in Section 2.4, the key assumptions of the input data are shown.

#### *2.1. Methodology*

The mathematical model, developed to quantify the influence of the capacity market, reflects the operation of the wholesale energy market. A schematic diagram illustrating the methodology employed is shown in Figure 1. The figure presents the inputs and outputs of the model equations and inequalities (green blocks in the scheme). For example, the objective function is related to the following parameters (grey blocks): fuel prices, CO2 European Emission Allowances, environmental charges, variable operations and maintenance costs, CO2 and pollutants emission factors, and net efficiency. Solving this equation together with all the others presented in the scheme (green blocks) results in the following outputs (brown blocks): power generated by individual units, the total variable cost of power generation, and electricity price. These values are used in the post-optimisation calculations, in line with Figure 1. The calculations are finished if all generation units have a positive profit (the "end" block). The scenarios are described in detail later in the paper.

**Figure 1.** The methodology employed in the study.

The model is formulated as a partial equilibrium model of the Polish electricity and capacity markets using the Economic Dispatch Problem (EDP) approach. The EDP approach is widely used to simulate the operation of an electricity market to calculate the optimal generation structure at the lowest total operating cost [8]. Bids submitted by generating units are ranked according to their variable costs (merit order), and the market clearing price is equal to the short-term marginal cost of the system, subject to constraints. It is assumed that the electricity market operates as a competitive market.

The model is a short-term model with a time horizon of one year and hourly intervals. The analysis period is 2021–2040, which is in line with the time horizon assumed in the Polish Energy Policy [28]. The calculation procedures presented in Section 2.2 are executed individually for each year.

Two research scenarios (described in detail in Section 2.2) are formulated to quantitatively assess the impact of the capacity market on coal consumption:

As previously mentioned, the price elasticity of electricity demand is low because consumers do not make their consumption dependent on hourly prices. Therefore, the study assumed that power demand is a parameter based on the hourly forecast demand in the power system. The values of demand also include network losses.

Power generation units are reflected in the model in the following ways:

The power generation units (individually or clustered) are described by their technical and economic parameters. The parameters are, e.g., net electrical capacity, net electrical efficiency, own-consumption factor, availability factor, capacity factor, ramp-up and rampdown rates, fuel, CO2, SO2, NOx, PM emission factors, and variable operations and maintenance (VOM) cost. The input data also includes information on the year of the decommissioning of the power generation units. In the case of refurbished units, the year, the planned increase in the generation capacity, and changes in the techno-economic parameters are included. New power generation units are considered individually in accordance with their investment schedule and techno-economic specification.

The remaining data assumed in this study are as follows:

The model of the Polish power system is formulated as a linear programming problem. The objective function is to minimise the total annual variable cost of electricity generation. The cost consists of the following components: (i) fuel costs, (ii) environmental costs, and (iii) VOM costs. The methodology presented can also be applied to investigate the operation of power systems in other countries and described by different input data.

The main constraints implemented in the model are as follows:

In order to mimic the impact of the reserve margin on electricity prices, the system marginal cost is adjusted proportionally to the level of the reserve margin.

The next step of the methodology presents the calculation of (i) the annual revenues of the individual (or clustered) power generation units, (ii) the estimated total annual costs (variable and fixed) of the individual unit, and consequently, (iii) the annual profit from the sale of electricity on the wholesale market.

#### *2.2. Scenario Assumptions*

Since the study aims to quantify the impact of introducing the capacity market on the decarbonisation of the power system, two research scenarios were formulated (Figure 2). The electricity market operation is simulated in the same way for both scenarios, in line with the methodology presented in Section 2.1. The calculation of missing money is also carried out according to the same criteria for both market structures. The differences between the scenarios embrace the operation (or not) of power generation units with insufficient revenues from the sale of electricity (missing money).

**Figure 2.** Research scenarios.

#### 2.2.1. Energy Only Market (EOM)

The EOM scenario assumes that the power generation units that do not meet the economic efficiency criterion (missing money problem) are decommissioned. In order to ensure energy safety and sufficient generation capacity in the power system, new power generation units are commissioned. The new units are selected based on economic criteria. As a result, a new structure of the power system is simulated. Then, the entire calculation procedure is repeated for the new structure. Iterations are repeated until each power generation unit in the power system has a positive financial result.

Nonetheless, it is assumed that the number of decommissioned units cannot be greater than five due to the technical and security conditions in each year. Furthermore, it is assumed that units commissioned to the power system from 2018 onwards are not decommissioned in the entire analysis period, regardless of their financial results. The calculation procedure under the EOM scenario is shown in Figure 3.

**Figure 3.** Calculation procedure under the EOM scenario.

#### 2.2.2. Capacity Market (CM)

The CM scenario assumes that the power generation units that do not meet the economic efficiency criterion (missing money problem) can participate in the capacity auction. If the units win the auction, they can sign a capacity agreement and remain in the power system. The CM scenario also reflects the real capacity auction results conducted for 2021–2024 [29]. Additionally, according to the Regulation of the European Parliament and Council [30], the study assumes that coal-fired units cannot be the beneficiaries of capacity market support from 2025.

The scenario assumes that renewable generation sources may receive more favourable financial support from the auctions dedicated strictly to renewable technologies. Since double financial support from public funds is not allowed in Poland, the study assumes that an increase in renewable generation capacity is adopted according to the Project of the Polish Energy Policy [28].

The reserve margin in the power system in the CM scenario is assumed to be 30.91%. The level is estimated based on historical capacity auctions for 2021–2024. Therefore, the generation capacity demand is the product of the maximum demand and the coefficient of 1.31. In the case of insufficient generation capacity, new capacity is added.

Finally, a simulation is made of the wholesale electricity market. Units with missing money problems and without capacity agreements are decommissioned. In the case of insufficient generation capacity, new power generation units are commissioned (selected based on economic conditions). As a result, the power system has a new technological structure.

Similar to the EOM scenario, the number of decommissioned units cannot be greater than five each year (due to the technical and security conditions). The exception is 2025, when the decommissioning of a maximum of ten units is allowed. The exception stems from the fact that information about the lack of financial support for the coal-fired units is available several years ahead. The generation companies can implement appropriate procedures and decommission additional units earlier. Moreover, the decommissioning of the greater number of units will not affect energy security because, as a consequence of the results of capacity auctions for 2021–2024, the reserve margin is at the level of 39.1% for that year. The assumption of units commissioned from 2018 onwards is similar to the EOM scenario–regardless of their financial results, they remain in the power system. The calculation procedure under the CM scenario is shown in Figure 4.

**Figure 4.** Calculation procedure under the CM scenario.

#### *2.3. Mathematical Model*

This section presents the description of the mathematical model developed. Symbols of sets, parameters, and variables used in the equations and inequalities are presented in Table 1.

**Table 1.** Symbol of sets, parameters, and variables used in the model.

The objective function of the model, the total annual operational variable cost of electricity generation (*TVGC*), is given in Equation (1). The *TVGC* is equal to the sum of the following components:

• The variable fuel cost, being the product of (i) the power generation *PGpp*,*<sup>h</sup>* by a unit or group of units *pp* at hour *h*, (ii) the fuel price *FPf* divided by the net electrical efficiency *EFpp*, and (iii) the duration *Durh*.

$$\begin{split} TVGC = \sum\_{pp,h} \left( PG\_{pp,h} \* \left( \frac{\sum\_{f} \left( Index\_{ppf} \* FP\_f \right)}{EF\_{pp}} \* Dur\_h \right) \right) \\ &+ \sum\_{pp,h} \left( PG\_{pp,h} \* VOM\_{pp} \* Dur\_h \right) \end{split} \tag{1}$$

The load and generation balance is given in Equation (2). The sum of power generation *PGpp*,*<sup>h</sup>* by a unit or group of units *pp* at hour *h* (decreased by an own-consumption factor *OCFpp*) must be greater or equal to power demand *Dh* increased by the export *Exh* and decreased by the import *Imh*.

$$\bigwedge\_{h \in H} \sum\_{pp} \left( PG\_{pp,h} \* \left( 1 - OCF\_{pp} \right) \right) \ge D\_h + Ex\_h - Im\_h \tag{2}$$

The power generation balance is given in Equation (3). The power generation *PGpp*,*<sup>h</sup>* by a unit or group of units *pp* at hour *h* must be lower or equal to the product of the generation capacity *Cpp* and the availability factor *AFpp*,*h*.

$$
\bigwedge\_{ppp \in PP} \bigwedge\_{h \in H} PG\_{pp,h} \le C\_{pp} \star AF\_{pp,h} \tag{3}
$$

The ramp-up balance is given in Equation (4). Each hour the increase in the volume of the power generation *PGpp*,*<sup>h</sup>* by a unit or group of units *pp* (compared to the previous hour) cannot be greater than the product of generation capacity *Cpp* and the ramp-up rate *MaxRampU pRatepp*.

$$\bigwedge\_{pp \in PP} \bigwedge\_{h \in H} PG\_{pp,h} - PG\_{pp,h-1} \le \mathbb{C}\_{pp} \ast \text{ MaxRam} LfpRate\_{pp} \tag{4}$$

The ramp-down balance is given in Equation (5). Each hour the decrease in the volume of the power generation *PGpp*,*<sup>h</sup>* by a generation unit or group of units *pp* (compared to the previous hour) cannot be greater than the product of the generation capacity *Cpp* and the ramp-down rate *MaxRampDownRatepp*.

$$\bigwedge\_{pp \in PP} \bigwedge\_{h \in H} PG\_{pp, h-1} - PG\_{pp, h} \le \mathcal{C}\_{pp} \* MaxRampDownRate\_{pp} \tag{5}$$

The power generation constraint is given in Equation (6). The sum of the power generation *PGpp*,*<sup>h</sup>* by a unit or group of units *pp* at hour *h* divided by the sum of the generation capacity *Cpp* cannot be greater than their capacity factor *CFpp*.

$$\bigwedge\_{pp} \frac{\sum\_{\mathbf{l}} \left( PG\_{pp,\mathbf{l}} \* Dur\_{\mathbf{l}} \right)}{\sum\_{\mathbf{l}} (\mathbb{C}\_{pp} \* Dur\_{\mathbf{l}})} \le |\mathbb{C}F\_{pp}| \tag{6}$$

The market clearing price is calculated using Equation (7). The market clearing price *MCPh* at hour *h* is a product of the hourly system marginal price *SMPh* and the hourly margin *UpLi f th*.

$$\bigwedge\_{h \in H} MCF\_h = SMP\_h \* \mathcal{U}pLift\_h \tag{7}$$

The revenue from the power generation *Revenuepp*,*<sup>h</sup>* of a unit or group of units *pp* is a product of the power generated *PGpp*,*<sup>h</sup>* by them at hour *h*, the market clearing price *MCPh*, and the duration *Durh*.

$$\bigwedge\_{pp \in PP} \bigwedge\_{h \in H} \operatorname{Revenue}\_{pp,h} = PG\_{pp,h} \* MCP\_h \* Dur\_h \tag{8}$$

The total cost of power generation *TotalCostpp* in a unit or group of units *pp* is given in Equation (9). The total cost is equal to the sum of (i) the variable cost of power generation, and (ii) the product of the fixed cost *FCpp* and the generation capacity *Cpp*. The variable cost consists of the following elements: fuel, environmental, and VOM costs. The components are also presented in Equation (1).

$$\begin{split} \bigwedge\_{ppp \in P} \text{TotalCost}\_{pp} &= \left( \left( \sum\_{h} \left( PG\_{pph} \ast \left( \frac{\sum\_{f} \left( Index\_{ppf} \ast FP\_{f} \right)}{EF\_{pp}} \ast Dur\_{h} \right) \right) + \sum\_{p,h} \left( PG\_{pph} \ast ER\_{ppp} \ast EP\_{p} \ast Dur\_{h} \right) \right. \\ &\left. + \sum\_{h} \left( PG\_{pph} \ast VOM\_{pp} \ast Dur\_{h} \right) \right) \ast 10^{-6} \right) + \left( FC\_{pp} \ast C\_{pp} \right) \end{split} \tag{9}$$

The profit from power generation *Pro fitpp* of a generation unit or group of units *pp* is calculated as the difference between (i) the sum of the revenues *Revenuepp*,*<sup>h</sup>* of a unit or group of units *pp* at hour *h*, and (ii) the total cost of power generation *TotalCostpp* (Equation (10)).

$$\bigwedge\_{pp \in PP} Profit\_{pp} = \sum\_{h} \left( Review\_{pp,h} \right) - Total Cost\_{pp} \tag{10}$$

The missing money *MissingMoneypp* of a generation unit or group of units *pp* is a quotient of (i) its *Pro fitpp* and (ii) the product of the capacity generation *Cpp* (decreased by an own-consumption factor *OCFpp*) and the availability factor *AFpp*,*<sup>h</sup>* (Equation (11)). The missing money is calculated exclusively for the units or group of units *pp* that do not make a profit from electricity generation.

$$\bigwedge\_{pp \in PP} \text{MissingMoney}\_{pp} = \frac{Profit\_{pp}}{\mathbb{C}\_{pp} \* \left(1 - OCF\_{pp}\right) \* AF\_{pp}} \tag{11}$$

The chemical energy demand *ChemEnDemandpp* that is required for power generation in a unit or group of units *pp* is calculated using Equation (12). *ChemEnDemandpp* is equal to a quotient of (i) the product of power generation *PGpp*,*<sup>h</sup>* and the duration *Durh*, and (ii) the unit conversion rate 3.6.

$$\bigwedge\_{ppp \in PP} \text{ChernEn Demand}\_{pp} = \frac{\sum\_{h} \left( PG\_{pp,h} \* Dur\_{h} \right)}{3.6} \tag{12}$$

The hard coal consumption *HardCoalConsumptionpp* in a generation unit or group of units *pp* is a product of the chemical energy demand *ChemEnDemandpp*, and the calorific value of the fuel *Qf* used for power generation (Equation (13)). Therefore, the total hard coal consumption in the power system *TotalHardCoalConsumption* is equal to the sum of the hard coal consumption in all hard coal-fired generation units or groups of units (Equation (14)).

$$\bigwedge\_{pp \in PP} \text{HardCoalConsumption}\_{pp} = \text{ChernEnDemand}\_{pp} \* Q\_f \* \text{Index}\_{pp,f} \tag{13}$$

$$\text{TotalHardCoolConsumption} = \sum\_{pp} \left( \text{HardCoolConsumption}\_{pp} \right) \ast \ 10^{-3} \tag{14}$$

The lignite consumption *LigniteConsumption pp* in the generation unit or group of units *pp* is a product of the chemical energy demand *ChemEnDemandpp*, and the calorific value of the fuel *Qf* used for power generation (Equation (15)). Therefore, the total lignite consumption in the power system *TotalLigniteConsumption* is equal to the sum of the lignite consumption in all lignite-fired generation units or groups of units (Equation (16)).

$$\bigwedge\_{ppp \in pp} \text{LightConsummation}\_{pp} = \text{ChemEnDemand}\_{pp} \* Q\_f \* Indexp\_{pp,f} \tag{15}$$

$$\text{TotalLightCon consumption} = \sum\_{pp} \left( \text{LightCon consumption}\_{pp} \right) \times \text{10}^{-3} \tag{16}$$

#### *2.4. Input Data Assumptions*

#### 2.4.1. Power Demand

The hourly electricity demand curve of the reference year (2018) is shown in Figure 5. The total electricity demand was 171.2 TWh. The power demand curves for consecutive years of the study (2021–2040) are developed from the shape of the curve in the reference year and the average annual growth rate (1.5%) forecast by the Ministry of Energy [28]. The assumptions for specific years are shown in Table 2. The volume of power demand published in the Polish Energy Policy includes the reserve margin that is required to ensure power system security.

**Figure 5.** Power demand in the Polish power system in 2018 (based on [31]).

**Table 2.** Electricity demand in 2018–2040.

#### 2.4.2. Import and Export

The study considers the volume of imported and exported electricity from neighbouring countries. The Polish power system has (i) synchronous connections with the German, Czech, and Slovak power systems and (ii) non-synchronous connections with the Swedish, Lithuanian, Ukrainian, and Belarusian power systems. The conditions of these connections are discussed in Ref. [32]. The total electricity import and export amounted to 13.8 TWh and 8.1 TWh in the reference year (2018).

Due to the complexity of estimating the electricity prices in European electricity markets, the study assumes that the rate as a percentage of cross-border exchange of electricity between Poland and the neighbouring countries is the same in each year of the analysis. As a result, net import (the difference between import and export) constitutes 3.30% of the total electricity demand each year.

#### 2.4.3. Power Generation Units

The power generation units are characterised by their technical, economic, and environmental parameters. The data is sourced from governmental and international agency databases and reports. The main sources are the Transmission System Operator, the Energy Market Agency, the Energy Regulatory Office, the Central Statistical Office, the ENTSO-E platform, and databases managed by the Mineral and Energy Economy Research Institute of the Polish Academy of Sciences (MEERI PAS).

The public information on commissioning and decommissioning power generation units is also considered in the study. Additionally, the study assumes the commissioning of three nuclear power units of 1.3 GW in 2033, 2035, and 2038 [28]. Since uranium is not mined in Poland, the total volume is imported. Additionally, the study assumes that the nuclear units work as base-load due to their high start costs.

Electricity generation by CHP plants in 2021–2040 is based on the generation profile from the reference year (Figure 6). Industrial CHP plants supply the same volume of electricity to the power system every hour of the year.

**Figure 6.** The average utilisation rate of CHP plants in 2018 (based on [33]).

The generation capacity of intermittent renewable units (solar, onshore, offshore, and hydro run-of-river) is assumed based on Ref. [28] (Figure 7). Electricity generation in 2021–2040 considers the generation profile of each technology in the reference year. As no offshore wind farms were operating in Poland in 2018, the generation profile was based on the German units (due to the weather conditions being similar to Poland) [34]. The study assumes that renewable generation sources are price-takers in the electricity market due to the low variable costs of generation.

**Figure 7.** Renewable capacity in 2018–2040 (based on [28]).

The share of the demand-side response is assumed at a different level under the scenarios examined. The EOM scenario assumed that the share of DSR is at the level of 0.85% of maximum electricity demand. The capacity numeration mechanism supports these units. Therefore, the share of DSR in the CM scenario is greater and is different in each year of analysis (see subsection: Capacity market).

Finally, the study assumes that CHP plants, industrial power plants, and renewable generation sources sell their electricity generation in the electricity market in priority. Centrally dispatched power generation units cover the remaining demand (based on merit order).

#### 2.4.4. Fuel Prices

Hard coal and natural gas price forecasts until 2040 are developed according to the Current Policies Scenario (CPS) of the World Energy Outlook Report [35]. As there are no long-term forecasts of lignite and biomass prices, they were calculated based on hard coal prices and the historical price relationship between them and hard coal prices. The fuel price assumptions are shown in Figure 8.

Uranium prices are assumed based on long-term contract prices (73.74 €/kgU in U3O8) and the forecast presented in Ref. [36].

2.4.5. Environmental Charges

A forecast of CO2 European Emission Allowances has been prepared according to the Current Policies Scenario (CPS) of the World Energy Outlook Report [35]. The results are shown in Figure 9. The calculation also includes environmental charges for the emission of pollutants (NOx, SO2, PM) and carbon dioxide. They are assumed according to national

regulations and adjusted by the inflation rate each year of the analysis.

**Figure 9.** CO2 European Emission Allowances in 2018–2040 (based on [35,39]).

#### 2.4.6. Capacity Market

As previously mentioned, the average annual growth rate of power demand is 1.5% in the EOM scenario (36.36 GW in 2040). In the CM scenario, demand is calculated as a product of the forecast power demand and a coefficient of 1.31 (reserve margin). The assumptions are shown in Table 3. The generation structure is developed individually for each year of analysis based on the outcomes of the previous years.

Source: Own analyses based on [28].

The study assumes that the TSO acquires the entire required capacity in the main auction (auxiliary auctions are ignored in the analysis). Existing units may sign capacity agreements for one year and new units for fifteen years. In some cases (specified in Ref. [40]), capacity agreements can be signed for a period longer by two years (the green bonus). Moreover, according to the current regulations, coal-fired units cannot participate in the capacity auction from July 1, 2020 [30].

The capacity remuneration mechanism encourages demand-side response to participate in the market. Therefore, the study assumes that the volume of DSR capacity will increase from 0.6 GW in 2018 (2.25% of total power demand) to 3.1 GW in 2040 (6.56%).

Energy storage can also participate in the capacity auction. However, it has exclusively been pumped hydro storage (PHS) that has participated in the auctions conducted so far (for the supply years 2021–2024). Forecasts published by the Polish government do not assume an increase in the generation capacity of PHS technology but assume the growth in other technologies of energy storage systems (EESs) [28]. The study assumes that the capacity in EESs will increase by 20% each year due to decreasing capital expenditure [41,42]. Therefore, the EESs' capacity will increase from 90.9 MW in 2021 (0.33% of total power demand) to 2.5 GW in 2040 (5.48%). These values exclude generation capacity in PHS (approx. 1.7 GW throughout the period). Power generation units deployed in adjacent power systems did not participate in the capacity auction for 2021–2024. The study assumes that this will continue throughout the analysis period.

#### 2.4.7. Other Assumptions

Value of Lost Load (VoLL) is assumed at EUR 3000/MWh [43]. The assumed prices and costs (e.g., fuel prices, environmental charges, VOM costs, fixed costs, and VoLL) are adjusted for inflation [44].

The study does not assume any constraint on the supply of hard coal. Hard coal can be acquired from domestic producers or be imported. However, in the case of lignite, the demand cannot exceed the maximum current and forecast production of domestic mines [45].

#### **3. Results and Discussion**

This section presents and discusses the results of the study. Since the Polish power system is heavily dependent on fossil fuel-based generation from hard coal and lignite, the changes related to these fuels are mainly discussed in the following subsections. Results regarding other energy sources in terms of installed capacity and electricity production are provided in Annex 1.

Key measures are used to analyse and compare results between the EOM and CM scenarios in order to adequately address the research question of this study:

Additionally, the section presents electricity prices under two research scenarios (3.4. Electricity Prices).

#### *3.1. Coal-Fired Power Generation Capacity*

The total generation capacity in the Polish power system was 42.4 GW in the reference year (2018). The share of coal-fired generation capacity was almost 70% of total capacity installed and over 93% of capacity installed in carbon technologies (20.6 GW of hard coal-fired power generation units and 8.7 GW of lignite-fired units).

In the following years of the analysis (2021–2040), the total generation capacity in the Polish power system increases regardless of the scenario analysed; however, the volume is higher each year under the CM scenario (Figure 10). This effect is a consequence of guaranteeing a reserve margin in the case of capacity market operation. The greatest difference between scenarios is observed in 2021–2024 (10.4–14.7%). In these years, numerous inefficient, hard coal-fired units that are decommissioned under the EOM scenario are financially supported in the CM scenario. The difference follows a decreasing trend over the next four years, and from 2028 to the end of the analysed period, it remains at the level of 6.0%.

**Figure 10.** Generation capacity in the power system under the EOM and CM scenarios in 2021–2040.

Figures 11 and 12 show the hard coal-fired and lignite-fired generation capacity under the EOM and CM scenarios in 2021–2040. The extensive generation structures of the power system in the reference year (2018) and specific years of analysis (2021, 2025, 2030, 2035, and 2040) are presented in Appendix A (Table A1).

**Figure 11.** Hard coal-fired generation capacity under the EOM and CM scenarios in 2021–2040.

**Figure 12.** Lignite-fired generation capacity under the EOM and CM scenarios in 2021–2040.

Although hard coal-fired generation capacity decreases over the entire time horizon of analysis regardless of the research scenario, the volume of capacity is different in specific years in the EOM and CM scenarios (Figure 11). The results indicate that the greatest difference between scenarios is in 2021–2024. The difference stems from the fact that a significant number of coal-fired power generation units have insufficient profits from the energy only market, and in consequence, missing money problems occur. In the CM scenario, these units received additional income from the capacity market. Therefore, they are maintained in the system.

As previously mentioned, hard coal-fired units cannot be supported by public funds from 2025. Additionally, environmental charges have an increasing influence on the total generation cost of electricity. Under those circumstances, the difference between the scenarios decreases to 2034. After this year, the generation capacity is almost the same under both scenarios examined by the last year of analysis (units commissioned to the power system after 2018). Therefore, according to the assumptions, they are not decommissioned from the power system regardless of their financial outcomes.

Table 4 presents the generation capacity in hard coal-fired units in specific years. The table also includes information about changes compared to the reference year (2018).

**Table 4.** Generation capacity in hard coal-fired power generation units.

Unlike the generation capacity of hard coal-fired units, the difference in the lignite-fired generation capacity is not that significant (Figure 12). The costs of electricity generation in lignite-fired power units are significantly lower. Consequently, these units are base-load under both scenarios in the first years of the analysis (2021–2032). The decrease in the generation capacity in these years is a consequence of the decommissioning of certain units due to technical, not economic reasons.

The difference between the EOM and CM scenarios is only observed in 2033–2024 because of the long-term capacity agreement of the two units. The increasing environmental charges result in a missing money problem in units that are decommissioned in the EOM scenario.

The decrease in the generation capacity in both scenarios is still observed in 2035–2038. In the two last years of analysis, the generation capacity is at the same level in both scenarios (only units commissioned to the power system after 2018).

Table 5 shows the generation capacity in lignite-fired units in specific years. The table also includes details of the changes compared to the reference year (2018).

**Table 5.** Generation capacity in lignite-fired power generation units.

As previously mentioned, the general structure of the power system is presented in Table A1, Appendix A. The table shows the study results in 2021, 2025, 2030, 2035, and 2040. It can be observed that the share of coal-fired units decreases. According to the developed research concept, in the case of insufficient capacity in the system, new capacities (with the lowest investments cost) are added, which enable balancing the demand and supply in the power system. Under the EOM scenario, the volume of commissioned power is 700 MW in 2021. On the other hand, under the CM scenario, the total capacity available in the power system is sufficient. Therefore, new generation capacities are not commissioned. In 2021, the capacity in renewable units (biomass, biogas, water, wind, and photovoltaic units) is 11.3 GW, which is a 21.7% increase compared to 2018. Under the EOM scenario, the share of renewable units is 27.2%, while under the CM scenario, it is 24.6%.

In 2025, under both scenarios analysed, the total capacity in the power system is sufficient in each of the analysed years (2022–2025). Therefore, no new units are added. In 2025, the capacity available in renewable units amounts to 18.5 GW, which is a 63.9% increase when compared to 2021. Under the EOM scenario, the share of renewable units is 38.9%, while under the CM scenario, it is 35.8%. In 2025, the first offshore wind farms are commissioned to the power system.

In 2026–2030, due to the lack of sufficient capacity meeting the economic efficiency criterion in the system, new units with a total capacity of 5.3 GW are added under the EOM scenario and 5.2 GW under the CM scenario. In 2030, the capacity available in renewable units amounts to 23.9 GW, which is a 29.7% increase compared to 2025. Under the EOM scenario, the share of renewable units is 44.3%, while under the CM scenario, it is 41.7%.

In line with the adopted assumptions, under both scenarios, two nuclear units are commissioned to the system with a generating capacity of 1,300 MW each. The first unit is put into operation in 2033, and the second in 2035. In 2031–2035, new generating units with a total capacity of 6.2 GW are added due to the lack of sufficient capacity in the system under the EOM scenario. Under the CM scenario, natural gas units with a total generating capacity of 8.0 GW are added. In 2035, the capacity available in renewable units is 30.0 GW, which is a 25.5% increase compared to 2030. Under the EOM scenario, the share of renewable units is 48.1%, while under the CM scenario, it is 45.7%.

In 2038, another 1,300 MW nuclear unit is commissioned to the power system under both scenarios. Under the EOM scenario, the lack of sufficient capacity in the system occurs in 2036–2037 and 2040. In the remaining years, the capacity available in the power system is sufficient to balance the demand. Under the CM scenario, gas capacities are added in the same years. In 2036, 600 MW of new capacity is commissioned, while 400 MW in 2037 and 150 MW in 2040. In 2040, the capacity of renewable units is 36.9 GW, which is a 22.7% increase when compared to 2035. Under the EOM scenario, the share of renewable units is 52.1%, while under the CM scenario, it is 49.2%.

#### *3.2. Electricity Generation from Coal-Fired Units*

Figures 13 and 14 present volumes of hard coal-fired and lignite-fired electricity generation under the EOM and CM scenarios in 2021–2040. The extensive structures of electricity production in the reference year (2018) and specific years of analysis (2021, 2025, 2030, 2035, and 2040) are presented in Appendix A (Table A2). The figures present the key changes in the years ahead.

**Figure 13.** Electricity generation from hard coal-fired units under the EOM and CM scenarios in 2021–2040.

**Figure 14.** Electricity generation from lignite-fired units under the EOM and CM scenarios in 2021–2040.

Similar to the results of the generation capacity, electricity production from hard coal-fired power units also decreases throughout the period of analysis, regardless of the scenario and the assumptions adopted (Figure 13).

The greatest difference between the EOM and CM scenarios is observed over the period 2021–2030. The difference stems directly from the technology structure. The share of hard coal-fired units in the EOM scenario is lower. Therefore, a lower volume of electricity is generated by these units.

Between 2031 and 2036, electricity production is at a similar level in both scenarios because hard coal-fired units gradually reduce their share in the total generation of the power system. Additionally, the increasing environmental charges mean that electricity is mostly generated in other units. The renewable, natural gas-fired, and nuclear units are characterised by lower generation costs, and consequently, they have priority to access the transmission grid.

In 2037–2040, the quantity of electricity generated in hard coal-fired units is greater in the EOM scenario. The trend is changing due to the fact that the hard coal-fired units have a greater share in the power system. On the other hand, in the CM scenario (in which the reserve margin is secured), the capacity of natural gas-fired units and demand-side response is greater. These units meet the power demand first.

Table 6 provides detailed information about changes in the electricity generation from hard coal-fired units over the period analysed and scenarios examined.

**Table 6.** Electricity generation in hard coal-fired power units.

There is no significant difference in electricity generation from lignite-fired power units up to 2030 under the scenarios examined (Figure 14). These are base-load units due to the low generation cost. The decrease in electricity generation in 2025 and 2030 stems from the decommissioning of certain units due to their technical condition, not due to the missing money problem.

A difference between the EOM and CM scenarios is observed in 2031–2032. Increasing environmental charges result in an increase in generation costs in lignite-fired power units. After this year, the share of natural gas-fired units, commissioning of nuclear units and increasing share of renewables result in decreased electricity production from lignite in both scenarios examined.

From 2038, the quantity of electricity generated in lignite-fired units is greater in the EOM scenario. Similar to the hard coal-fired units, the change in the trend is due to the fact that the lignite coal-fired units have a greater share in the power system under this scenario. On the contrary, in the CM scenario (in which the reserve margin is secured), the capacity of natural gas-fired units and demand-side response is greater, and these units sell electricity before more expensive ones.

Table 7 provides information about changes in the electricity generation from lignitefired units over the period analysed and scenarios examined.

**Table 7.** Electricity generation in lignite-fired power units.

The fuel-mix of electricity generation in 2021, 2025, 2030, 2035, and 2040 are presented in Table A2, Appendix A.

In 2021, under the EOM scenario, electricity production in hard coal-fired units is 81.2 TWh (2.4% lower when compared to 2018). Under the CM scenario, production in these units amounts to 88.0 TWh (an increase of 5.9% when compared to 2018). The difference between the scenarios is a consequence of maintaining the coal-fired units under the CM scenario, which signed contracts of the capacity obligation, and the commissioning of new natural gas units under the EOM scenario. Natural gas units have lower generation costs than obsolete coal units these years. Therefore, the demand is covered by production from these units in priority.

In 2025, the total volume of electricity is 183.6 TWh, an increase of 6.1% compared to 2021. The results show that hard coal remains the dominant fuel. Electricity production in lignite units is the same under both scenarios and amounts to 43.7 TWh, which is a decrease of 7.9% compared to 2018. It is a consequence of withdrawing lignite-fired units from the system due to their technical condition. In 2025, under the EOM scenario, production in hard coal-fired units is 72.2 TWh and is 11.1% lower compared to 2021. Under the CM scenario, production in these units is 76.6 TWh, which is a decrease compared to 2018 by 13.0%. Hard coal consumption decreases under both scenarios due to the cheaper electricity produced in natural gas units. The total electricity production in natural gas units is 33.2 TWh under the EOM scenario and is 50.5% higher compared to 2021. Under the CM scenario, the volume of electricity is 28.9 TWh, which is an increase of 79.8% when compared to 2021.

In 2030, the total volume of electricity is 197.8 TWh, which is an increase of 7.7% when compared to 2021. Most electricity under both scenarios is produced in natural gas units. It is a consequence of the increase of new natural gas units added to the system in order to cover the power demand. Considering the increasing prices of CO2 European Emission Allowances, these units are characterised by a lower cost of electricity generation than most units using solid fossil fuels. The volume of electricity produced in lignite-fired units is the same under both scenarios in 2030 and amounts to 40.5 TWh, which decreases by 7.3% compared to 2025. The progressive increase in prices of carbon certificates means that lignite-fired units produce electricity at a higher production cost than new natural gas units. In 2030, under the EOM scenario, production in hard coal-fired generation units is 43.7 TWh and is 39.5% lower compared to 2025. Under the CM scenario, production in these units is 48.4 TWh, which is 36.8% less when compared to 2018.

In 2035, the total volume of electricity produced this year is 213.1 TWh, 7.7% higher when compared to 2030. The dominant units in the electricity production fuel-mix are natural gas-fired units. Electricity production in natural gas units under the EOM scenario is 89.7 TWh, which is an increase of 37.9% when compared to 2030. Under the CM scenario, the production volume is 89.9 TWh and is higher by 48.9% when compared to 2030. The decline in the growth rate of electricity production from natural gas-fired units is a consequence of the commissioning of two nuclear units to the power system. These units are characterised by lower production costs than other conventional units, so the electricity produced in them meets the demand in prior. Electricity production in nuclear units is the same under both analysed scenarios and amounts to 21.6 TWh.

In 2040, the total volume of electricity produced is 229.6 TWh, 7.7% higher when compared to 2035. Natural gas is also the dominant fuel. Electricity production in natural gas-fired units is 106.4 TWh under the EOM scenario, 18.7% more than in 2035. Under the CM scenario, the production volume is 108.2 TWh and is higher by 20.3% compared to 2030. Production in nuclear units is the same under both scenarios and amounts to 32.2 TWh, which is an increase of 50.0% compared to 2035.

#### *3.3. Coal Consumption for Electricity Generation*

Fuel consumption is directly dependent on the structure of electricity generation. Therefore, coal consumption depends on generation by coal-fired capacity in the power system and the availability of generation units. In order to convert demand for coal consumption from energy units to mass units, the calorific value is adopted in line with data published by the Energy Market Agency (e.g., 21,075 MJ/Mg in hard coal-fired power plants, 21,952 MJ/Mg in hard coal-fired CHP, and 8,019 MJ/Mg in lignite-fired power plants) [37].

#### 3.3.1. Hard Coal Consumption

Hard coal consumption over the period 2021–2040 under both scenarios is shown in Figure 15, and the differences between the scenario results are presented in Figure 16. Hard coal consumption for electricity generation decreases in both the EOM and CM scenarios, but the characteristics of these changes are different. Table 8 provides detailed information about these differences over the period analysed and the scenarios examined. The changes over the periods are greater than changes in electricity generation in hard coal-fired units which stems from the increase in net electrical efficiency in existing and new hard coal-fired power generation units. % start a new page without indent 4.6cm

**Table 8.** Hard coal consumption for electricity generation.

**Figure 15.** Hard coal consumption for electricity generation under the EOM and CM scenarios in 2021–2040.

In 2021–2024, hard coal consumption decreases from 37.2 million Mg to 32.3 million Mg under the CM scenario. In this period, the consumption under the EOM scenario is lower on average by 9.7%. The difference is mainly due to the lower generation capacity in hard coal-fired power plants and CHP plants. Consequently, there is a lower volume of electricity generated in these units under the EOM scenario. In the CM scenario, some units with negative financial results from the energy market receive financial support from the capacity market and are still in the power system.

In 2025–2026, hard coal consumption still decreases in both scenarios. Additionally, some units are decommissioned from the power system due to their technical condition. As a result, the consumption in the CM scenario is higher by 7.8% in 2025 and 10.2% in 2026 when compared to the EOM scenario.

In 2027–2029, hard coal consumption decreases to 21.9 million Mg in the CM scenario. However, the difference between the two scenarios increases compared to the previous years and reaches 19.2% (3.5 million Mg) in 2029. The maintenance of hard coal-fired power generation units in the power system through the support mechanism results in the commissioning of a smaller volume of new generation capacity. Thus, the operation of the capacity market contributes to maintaining the existing generation units that meet the peak power demand. There are no requirements to commission many new units in the CM scenario.

In 2030, hard coal consumption in the CM scenario decreases to 19.9 million Mg. The difference between the scenarios decreases to 2.1 million Mg due to the fact that

there are also smaller differences between hard coal generation capacity in the system in both scenarios in 2030. It should also be noted that due to the increasing prices of the CO2 European Emission Allowances, hard coal-fired units are becoming less and less competitive when compared to other technologies. In the following years, the differences between the hard coal consumption in the scenarios are much smaller, and in 2034 hard coal consumption is almost the same in both scenarios.

In 2035–2040, hard coal consumption in the CM scenario reaches 4.2 million Mg (7.6% lower than the EOM scenario). The change of the trend is caused by the greater volume of gas-fired capacity generation in the CM scenario. Natural gas-fired power units are characterised by much lower generation costs than hard coal-fired units due to further increases in the prices of the CO2 European Emission Allowances.

#### 3.3.2. Lignite Consumption

Lignite consumption over the period 2021–2040 under both of the scenarios examined is shown in Figure 17. As is the case with hard coal consumption, the decrease is observed throughout the entire period of analysis and under the two scenarios. Similarly, periods with characteristic differences are observed (Figure 18). Table 9 provides detailed information about these differences over the period analysed and the scenarios examined.

**Figure 17.** Lignite consumption for electricity generation under the EOM and CM scenarios in 2021–2040.

**Table 9.** Lignite consumption for electricity generation.

In 2021–2030, lignite consumption decreases from 59.4 million Mg to 50.2 million Mg. The reduction stems from the fact that some lignite-fired power generation units are decommissioned. However, as previously mentioned, the causes of the decommissioning are technical, not financial. The results indicate that lignite-fired units meet the condition of economic efficiency, and they work as base-load units in these years.

The difference between the scenarios is the greatest in 2031–2032. During this period, lignite-fired power units generate a smaller amount of electricity in the EOM scenario because other units have priority due to lower generation costs (e.g., renewable, gas-fired). Increasing prices of the CO2 European Emission Allowances result in increasing costs of electricity generation in lignite-fired power generation units when compared to other technologies. In the following years, lignite consumption is similar under the scenarios examined (2033–2034) or even the same (2035).

In 2037–2040, the lignite consumption is greater in the EOM scenario (4.9 million Mg compared to 4.5 million Mg in the CM scenario). The change of the trend stems from the fact that there is a lower gas-fired generation capacity in the EOM scenario (with a lower cost of power generation). This level is higher in the CM scenario due to reserve margin requirements in the power system at 30.91%.

#### *3.4. Electricity Prices*

The electricity prices in both scenarios are shown in Figure 19. The prices are higher under the EOM scenario regardless of the year of analysis. They range from EUR 62.2/MWh to EUR 84.4/MWh, while in the CM scenario, electricity prices range from EUR 47.7/MWh to EUR 78.8/MWh. This is because electricity prices reflect not only the generation cost but also the reserve margin in the power system. Since the assumption of a reserve margin at 30.91% was adopted in the capacity market (based on past auctions), this is sufficient to maintain lower prices. In the EOM scenario, the reserve margin is always lower, resulting in greater electricity prices.

**Table 10.** Average annual electricity prices.

**Figure 19.** Electricity prices under the EOM and CM scenarios in 2021–2040.

Table 10 provides more detailed information about changes in the electricity prices over the period analysed and the scenarios examined.

#### **4. Conclusions**

The research carried out in this paper forms the first study on the quantitative assessment of the long-term impact of the introduction of a capacity market on decarbonisation in power systems with a high penetration of fossil fuels. Since the capacity market has been introduced in Poland relatively recently, the results of the analyses and the conclusions drawn on their basis constitute a significant contribution to the discussion on the legitimacy and consequences of its implementation.

The impact of the introduction of a capacity market on the decarbonisation of the Polish power system was assessed based on the (i) coal-fired generation capacity in the power system, (ii) electricity generation from coal-fired units, and (iii) quantity of coal consumption for electricity generation. Additionally, the forecasts for electricity prices in 2021–40 were also calculated.

The findings show that the introduction of the capacity market results in the slowing down of the decarbonisation process in Poland. This instrument mainly provides support for thermal power plants that consume fossil fuels. The consequences of lengthy capacity agreements (for as long as 15 years) are observed in the long-run. As a result, coal-fired power units are maintained far longer than without the capacity remuneration mechanism.

The results indicate that the decarbonisation of the Polish power system is inevitable by 2040 regardless of the scenario analysed. Hard coal consumption decreases by 86.9% and 87.9%, respectively, in the EOM and CM scenarios. Lignite consumption is reduced by 91.8% and by 93.0%, respectively. Research findings point out, however, that the introduction of a capacity market results in a delay in the process of decarbonisation of the Polish power system. A slowing down of the process of withdrawing hard coal-fired power generation units is observed in 2021–2030, and in the case of lignite-fired units in 2031–2032. The greatest difference between hard coal consumption for power generation under EOM and CM scenarios is as much as 19.2% per year. Whereas, in the case of lignite, the greatest difference is 18.2%.

Coal consumption for electricity generation also decreases regardless of the research scenario. Differences are observed between the two scenarios, especially in the case of hard coal consumption. The capacity market supported these units in the first years of its operation. The results indicate that numerous hard coal-fired power units would have to be decommissioned from the power system without the support from the capacity mechanism because maintaining them in the system would be unprofitable. The introduction of the capacity market does not significantly impact lignite consumption. In the first ten years of the analysis, the volume of generation capacity in the system is the same for both scenarios. Lignite consumption decreases regardless of the scenario considered (due to the technical condition of the plants, not because of economic inefficiency). These units generate electricity at a sufficiently low price to operate as the base-load of the power system. The differences between the scenarios occur when the increase in the price of the CO2 European Emission Allowances is large enough to push them out of the system by units with lower generation costs.

In the last year of analysis, the hard coal and lignite consumption is greater in the scenario without a capacity remuneration mechanism. This stems from the fact that coalfired units have a greater share in the EOM scenario. Consequently, more coal-fired units generate electricity in peak demand than is the case in the CM scenario.

The decarbonisation of the Polish power system through the phasing-out of coal-fired units is inevitable by 2040 regardless of the scenario analysed. The capacity market does not stop the transformation, although it delays the process significantly, particularly in the upcoming years. As a result, the capacity market has a negative impact on carbon neutrality in the short- and mid-term.

However, the operation of the capacity market ensures an adequate reserve margin in the power system. As a consequence, energy security is improved. In addition, the implementation of the capacity remuneration mechanism ensures the stability of energy supplies during the first phase of the decarbonisation process of the Polish power system. The support mechanism also extends the time for the preparation of new regulations and support schemes for other technologies (e.g., renewables, energy storage, demand-side response) and the climate and energy policies required for further phases of the energy transition and decarbonisation of the Polish power system.

**Funding:** This research was funded by the National Science Centre, Poland, grant number 2019/35/ N/HS4/00171.

**Institutional Review Board Statement:** Not applicable.

**Informed Consent Statement:** Not applicable.

**Data Availability Statement:** Not applicable.

**Acknowledgments:** The author would like to thank Jacek Kami ´nski and Pablo Benalcazar for their insightful comments and suggestions.

**Conflicts of Interest:** The author declares no conflict of interest.

#### **Abbreviations**

#### **Appendix A**

**Table A1.** Structure of generation capacity under the EOM and CM scenarios.

**Table A1.** *Cont.*

**Table A2.** Fuel-mix of electricity generation under the EOM and CM scenarios.

#### **Table A2.** *Cont.*

#### **References**

### *Article* **Limestone Sorbents Market for Flue Gas Desulphurisation in Coal-Fired Power Plants in the Context of the Transformation of the Power Industry—A Case of Poland**

**Jarosław Szlugaj \* and Krzysztof Galos \***

Mineral and Energy Economy Research Institute, Polish Academy of Sciences, J. Wybickiego 7A, 31-261 Kraków, Poland

**\*** Correspondence<EMAIL_ADDRESS>(J.S<EMAIL_ADDRESS>(K.G.); Tel.: +48-(12)-617-16-19 (J.S.); +48-(12)-617-16-02 (K.G.)

**Abstract:** Since the beginning of the 1990s, due to international regulations on air quality, a large number of flue gas desulphurisation (FGD) installations have been constructed in the Polish coalfired power industry. Thanks to that, SO2 capture in this industry increased to ca. 90%. Since wet lime or fluidized bed boilers were mostly used for FGD purposes, a significant increase in the domestic demand for lime sorbents has been reported. Between 1994 and 2019, it has increased from virtually zero before 1994 to about 3.3–3.4 million tpy (tonnes per year) today. On the basis of official governmental data and completed surveys of the Polish power companies, the paper analyses the process of the implementation of FGD in Poland along with limestone sorbents consumption and FGD gypsum production in the Polish coal-fired power plants. It also presents the current and potential limestone resource base for production of limestone sorbents applied in FGD. Electric energy mix in Poland is expected to be changed radically in the coming 30 years. Share of coal-based electricity is still very high—ca. 80%—and it will remain dominant for at least next decade. With the next coming FGD installations, further moderate increase of limestone sorbents consumption is expected, up to 3.7 million tpy in 2030. After 2030, a significant, quick decrease of share of coal-fired electricity is expected in Poland, down to max. 30% just before 2050. This will result in a gradual decrease in limestone sorbent demand, to max. 1.3 million tpy before 2050 and virtually zero after 2050, which will be followed by collapse of FGD gypsum production.

**Keywords:** limestone sorbents; flue gas desulphurisation; FGD gypsum; coal-fired power plants; energy transition; climate policy

#### **1. Introduction**

Global climate warming and pollution-related effects on human health have placed air pollution at the heart of EU policy decision-making [1]. Although from a global perspective, coal will remain one of the main sources of energy for a long time [2], the European Union have implemented strict regulations to improve air quality, including—or even especially—in the Eastern European countries admitted to the EU in 2004 and 2007. First air quality directives at European level were introduced in 1970, 1980 and 1985 [3]. However, a significant step was made in 1996, when the EU adopted a series of actions to decrease pollutant emissions throughout Europe, also implementing harmonised structure for monitoring, reporting and managing air quality across the EU through 1996 Air Quality Framework Directive [4] and its daughter directives, e.g., setting limit values and alert thresholds for major pollutants. The first such daughter directive [5] established limit values for sulphur dioxide, nitrogen oxides, lead and particulates. In 2005, according to 2005 Thematic Strategy on Air Pollution [6], the European Commission proposed to consolidate the Framework Directive and the first three daughter directives into a single Ambient Air Quality Directive, what was finally adopted as [7], providing the current framework for

Limestone Sorbents Market for Flue Gas Desulphurisation in Coal-Fired Power Plants in the Context of the Transformation of the Power Industry—A Case of Poland. *Energies* **2021**, *14*, 4275. https://doi.org/ 10.3390/en14144275

**Citation:** Szlugaj, J.; Galos, K.

Academic Editors: Dimitrios Katsaprakakis and Jacek Kami ´nski

Received: 21 May 2021 Accepted: 12 July 2021 Published: 15 July 2021

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**Copyright:** © 2021 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

the control of ambient concentrations of air pollution in the EU. As a consequence of these actions, further more detailed actions have been carried out by the European Commission for individual types of activities related to the emission of pollutants into the air. For large combustion plants these have been: the European Union's Directive 2001/80/EC [8], Directive 2010/75/EU [9] or BAT reference documents [10]. As a result, also intensive Flue Gas Desulphurisation investments have been conducted in recent decades in coal-based power industries of numerous countries, not only in those belonging to the EU [11–13].

In recent years, energy and climate started to be one of the cornerstones of EU policy [14]. This process was initiated by establishing a scheme for greenhouse gas emission allowance trading in 2003 [15], improved and extended in 2009 [16]. Recently, the EU energy and climate goals have been incorporated into the Europe 2020 Strategy for smart, sustainable and inclusive growth. The EU has set overarching targets of greenhouse gas (GHG) emissions reduction known as so-called 20/20/20 targets, namely, reduction of GHG emissions by 20%, increase of Renewable Energy Sources (RES) share to 20% and increase of energy efficiency by 20%, until 2020 [17,18]. In 2019, the EC adopted "Clean Energy for Europe Package" which upheld the right of the EU member states to continue their own energy mix, but with an increased share of renewables in it (on average, 32% in 2030 in the EU), with appropriate measures to accommodate such rising share of renewable energy [19]. As a result, decarbonisation of electricity systems together with substantial increase in renewable energy sources is one of the main policy priorities to foster EU energy transition. Thus, energy mixes are at the moment coal-free in 6 EU and 3 EEA countries and are planned to be coal-free until 2030 in the next 12 EU countries, but this is still not the case for numerous Eastern EU countries, including Poland [20].

The above-mentioned EU actions have been followed by detailed actions at the level of individual EU countries [21]. In Poland, the most important of them are at the moment: the "National Air Protection Program by 2020" adopted in 2015 [22], a 2021 Energy Policy of Poland until 2040 adopted in February 2021 [23], and National energy and climate plan for 2021–2030 adopted in December 2019 [24].

In Poland, coal has been a key driver of energy security for decades. Hard coal and lignite are traditionally the most important fuels used in Poland due to their abundant resources available in the country. Despite all transition trends resulting in its declining role, it still accounts for majority of the Polish electricity mix [25,26]. Without doubt, the Polish power industry stands at a crossroads, facing pathways with various ambitions of emission reductions, being strongly affected by environmental and decarbonisation regulations. According to the latest Energy Policy of Poland until 2040, the share of coal in the Polish electricity mix will decrease to a maximum of 56% in 2030, while share of RES will rise to 32%. In the next decade, pace of further decrease of coal in electricity mix will heavily depend on EU ETS allowances prices, achieving 37% in 2040 [24]. Various electricity mix scenarios in perspective of 2050 are still possible. In the strong decarbonisation (high EU ETS allowances prices) scenario, it is assumed that in 2050 coal will be used in Poland at most in CHP (Central Heating Plants) generating electricity together with hot water for district heating networks, with coal-based electricity generation decreasing from ca. 130 TWh in 2015 down to 30–50 TWh in 2050, constituting ca. 15% of the electricity mix. A complete phase-out of coal-based power industry by 2050 also cannot be excluded [26,27].

As the Polish power industry has traditionally relied on the combustion of coal (hard coal and lignite), it has generated significant amounts of SO2 and other gases. Commercial power generation emitted about 1.6 million tonnes SO2 in 1990, about 0.8 million tonnes SO2 in 2000, and only about 0.25 million tonnes SO2 in 2018. The total amount of SO2 generated from combustion processes (mainly coal combustion) was much higher, but there has been a fundamental change in the extent of active flue gas desulphurisation (FGD) systems at domestic power plants and combined heat and power plants over the last 30 years. As a result, the amount of SO2 retained at these FGD plants increased from ca. 0.33 million tonnes SO2 in 1990 to ca. 0.60 million tonnes SO2 in 2000 and ca. 1.9 million tonnes SO2 in 2018 [28–30], meaning that these FGD plants were already retaining nearly 90% of the SO2 generated.

Due to the above-mentioned factors, an intensive modernisation process in the Polish power industry started in the early 1990s, concerning in particular the construction of FGD plants, or in the case of general modernisation of power units, sometimes introduction of fluidized bed boilers, where the desulphurisation process takes place in the boiler immediately after the combustion of fuel (mainly coal) [29]. The technological solutions applied to capture the SO2 generated during combustion vary; nevertheless, two approaches have gained the greatest importance in Poland: construction of FGD using the wet limestone method, and semi-dry method, at the existing, modernized or newly built power units burning hard coal or lignite, or the aforementioned introduction of fluidized bed boilers. In both cases, limestone of suitable quality is used as sorbent, with limestone flour, of finer granulation, in the wet limestone method and limestone sand, of slightly coarser granulation, in fluidized bed boilers. In the semi-dry method of flue gas desulphurisation, the main type of sorbent is a quicklime [31,32].

The progressing process of implementation of FGD methods in the Polish power industry (as well as in industrial power sector and partly in the heat industry) contributed to the development of domestic demand for limestone sorbents from practically zero level at the beginning of 1990s to about 3.5 million tpy (tonnes per year) at present. As a result, the power industry has become one of the most important customers of the Polish lime industry, which, on the other hand, have experienced a significant reduction in demand for traditional lime products, in particular for various types of lime [33].

By considering all of the factors mentioned above, this article aims to analyse sources of limestone sorbents in Poland, as well as their use in the Polish power industry for FGD purposes. It has been done not only to recognize current situation, but also with an attempt to forecast in this respect in the perspective of 2050, taking into account the most important economic, technological, environmental and policy factors, both at the EU and at the national level.

#### **2. Materials and Methods**

Extensive analyses of the limestone resource base and of limestone use in Poland were performed. For these purposes, the most important sources of information were: annual publications on mineral resource base in Poland [34–36], publications reviewing this resources base [37,38], older analyses of industrial limestone market in Poland [39], and official data of the Statistics Poland (GUS) [28,40]. Other official reports on the domestic power generation industry were also used [41,42].

For obtaining reliable information on limestone flour consumption by the Polish power generation industry, the authors surveyed relevant power companies in the field of applied FGD methods, type, amounts and sources of limestone sorbent applied, as well as amount of FGD gypsum (and other FGD products) obtained. In total, 18 power companies were surveyed, of which 14 responded (including all seven major ones). Quantity of limestone consumption and FGD-gypsum production for power industry companies, which did not respond to the survey, were deduced from their actual energy production and known parameters of their FGD installations, as well as their prior available data on sorbent consumption.

#### **3. Results**

*3.1. Methods of Desulphurisation Used in the Polish Power Plants and Central Heating Plants and the Main Sorbents Applied*

The aim of flue gas desulphurisation processes is removing sulphur (mainly in the form of SO2, less frequently other sulphur compounds) from flue gases generated in various industrial processes. The main sources of emissions of sulphur compounds are processes of combustion of fossil fuels (in Poland: especially hard coal and lignite), which in numerous countries still remain the main source for generation of electricity and heat. The amount of sulphur oxides produced in these processes depends on the type of fuel, the content of sulphur compounds in the fuel, as well as the combustion conditions in different types of furnaces [10].

Many methods are known for the removal of sulphur oxides from the flue gases of production processes. All of them involve the introduction of a sorbent into the system, which reacts with the gaseous SO2 contained in the flue gas, binding it into solid compounds, with the removal of the reaction products from the system. Desulphurisation can be carried out on both dust-free gases and those carrying considerable quantities of dust. Moreover, desulphurisation processes can be carried out before, during and after fuel combustion. Sorbents most commonly used in desulphurisation processes are ground limestone (limestone flour), hydrated lime and ground quicklime. Much less commonly used are ground dolomite, calcined magnesite, sodium carbonate, and some industrial wastes (e.g., carbide lime) [10,43,44].

With respect to the ways of introducing the sorbent into the desulphurisation system and receiving the desulphurisation products, the following methods are distinguished: dry, semi-dry and wet. Dry methods are characterised by the fact that SO2 chemical fixation processes take place in the dry state, i.e., in a gas–solid system, and desulphurisation products are obtained in the dry state. They are based on adsorption on solid sorbents with simultaneous drying of desulphurisation products. The most common dry FGD system of dust-free flue gases is spray dry FGD system with use of hydrated lime [45], while, e.g., furnace sorbent injection or duct sorbent injection have minor importance. Circulating Fluid Bed dry scrubbing in fluidized bed boilers is another important method, but in this case limestone or lime sorbent is introduced into the boiler before the combustion process [32,43]. In semi-dry and wet methods SO2 sorbent is introduced to the desulphurisation plant in the form of suspension in liquid, while the desulphurisation products are received in dry state (semi-dry method) or in the form of suspension (wet method). According to the criteria given above, dry desulphurisation methods include also desulphurisation carried out during combustion in furnaces of fluidized bed boilers. The products of desulphurisation by dry and semi-dry methods are so-called desulphurisation ashes (sulfate-rich ashes). They are a mixture of ashes, desulphurisation products and unreacted sorbents. For the wet lime method, the main product is synthetic gypsum with a small amount of unreacted sorbent [10,46–48].

Limestone sorbents (lime flour or sand), in some cases also burnt or hydrated lime constitute the most numerous group of reagents used in flue gas desulphurisation systems. It is also the case of Poland, where they are applied mainly in the wet lime method and in fluidized bed boilers, to a lesser extent in semi-dry and dry methods (Table 1). In the Polish power industry, they are used in almost all existing flue gas desulphurisation plants. This is due to their widespread availability, low purchase cost and, in the case of the wet limestone method, the ease of disposal of the resulting synthetic gypsum. In general, calcium desulphurisation sorbents include: in dry desulphurisation methods—ground quicklime and limestone, in semi-dry desulphurisation methods—hydrated lime and ground quicklime, and in wet desulphurisation methods—ground quicklime, ground limestone and chalk [49,50].

#### *3.2. Sources and Production of Limestone Sorbents in Poland*

Limestones are sedimentary rocks whose main component is calcite CaCO3, isomorphic with magnesite MgCO3, siderite FeCO3 and other anhydrous carbonates, as a result of which admixtures of MgO, FeO, etc., are present. Depending on the admixtures of other minerals, a number of varieties of transition rocks can be distinguished: with increasing amounts of clay minerals, these are marl limestones, marls and clayey marls, with admixture of silica—gaizes, and with quartz—sandy limestones and calcareous sandstones. The admixture of the dolomite mineral CaMg[CO3]2 is particularly common in rocks of mixed nature—dolomitic limestones and calcareous dolomites. A particular variety of limestone rocks, both in terms of genesis and properties and use, is the chalk [37,51].

Poland has numerous deposits of limestone rocks with the exception of the most noble varieties of sculptural and architectural marbles. The limestone resource base is divided into limestone and related minerals documented for various purposes: limestone for the lime industry, limestone and related rocks for the cement industry (both collectively known as industrial limestone), limestone for the production of crushed aggregates, as well as chalk and lake chalk. In practice, this division has a conventional meaning, as, e.g., cement and lime combinations operate on individual deposits, using the purer parts for lime products, and the remaining parts for cement or crushed aggregate production [37,52].

Limestone deposits for the lime industry are known mainly in the Swi ˛ ´ etokrzyskie province (60% of total resources, mainly Devonian and Jurassic limestone) as well as in the Łódzkie, Opolskie and Sl ˛ ´ askie provinces. The total resources of 120 deposits amounted to 5.4 billion tonnes at the end of 2019 [35]. Deposits of limestone and related rocks for the cement industry are found in the following provinces: Lubelskie (26%, predominantly Cretaceous marls and chalk), Swi ˛ ´ etokrzyskie (17%, Devonian and Jurassic limestone), Łódzkie (15%, Jurassic limestone), Mazowieckie (12%, Jurassic limestone), smaller ones in Kujawsko-Pomorskie, Opolskie and Sl ˛ ´ askie. Total resources of 69 deposits amounted to 12.7 billion tonnes at the end of 2019. Limestone deposits mostly for crushed aggregates production are found mainly in the Swi ˛ ´ etokrzyskie region (about 90% of resources, Devonian and Jurassic limestone). Many deposits were also documented in the Cracow-Cz ˛estochowa Upland and single ones in the Carpathians, Sudety Mountains, Lublin Upland and others. The total resources of 142 deposits of limestone and limestone-related rocks for crushed aggregates production amounted to 2.0 billion tonnes at the end of 2019 [35].

By age of limestone formations, the most significant are Jurassic limestones (over 59% of resources), followed by Cretaceous limestones and related rocks (over 21%), Devonian limestones (about 8%), Triassic limestones (about 8%), Tertiary limestones (about 3%), and marginally—Carboniferous, Cambrian and Precambrian limestones [34,35].

In 2019, limestone was mined in Poland in 86 open pits, of which there were 19 limestone and marl mines delivering the batch to the cement industry, 22 limestone mines—for the lime industry, 36 mines extracting limestone deposits documented for crushed aggregates production, as well as 9 chalk mines [35].

Limestone rocks are used in Poland to produce several groups of products: cement, lime, unburned lime products, crushed limestone aggregates and fertilizers. Burnt and hydrated lime, as well as unburned limestone products, with a diverse range, are manufactured by more than a dozen plants. Some lime plants produce also significant quantities of limestone rock for sale, used as a blast furnace flux or in sugar factories for the production of quicklime necessary for beet juice purification (Table 1). Limestone crushed aggregates for construction are obtained mostly from limestone crushed aggregates deposits, as well as in some industrial limestone mines. Fine waste fractions from limestone crushed aggregates production are often destined for calcium carbonate fertilizers manufacture [39].

At present, fine-grained limestone sorbents, often called limestone flour, with grain size under 100/120 μm are used in the Polish power industry as a sorbent for flue gas desulphurisation in the wet limestone method, while coarse-grained sorbents (so-called limestone sand), with grain size above 100/120 μm, are used mainly for desulphurisation during combustion in fluidized bed boilers.

**Table 1.** Mining production of limestone in major mines, delivering industrial limestones as the main or additional products (kt) <sup>1</sup> [34].

<sup>1</sup> Mines delivering limestone or similar rock only for cement production are excluded, mines delivering a different type of limestone flour are marked **in bold**. Applications: a—crushed aggregates, c—cement production, d—dimension limestone, f—limestone fertilizers, l—lime, p—limestone flour (powder), s—limestone rock for sale.

> The majority of the Polish limestone milling plants which produce limestone flour for diverse purposes are located in the direct vicinity of extracted limestone deposits, which minimizes the cost of limestone transportation from the mine to the processing plant. This is why the largest limestone milling plants are located in the Swi ˛ ´ etokrzyskie province, as well as in the neighbouring provinces: Łódzkie and Małopolskie.

> The most important domestic suppliers of limestone sorbents include: Lhoist Polska Sp. z o.o. (Bukowa, Tarnów Opolski, Górazd˙ ze, Wojciesz ˙ ów/Połom plants), KW Czatkowice Sp. z o.o. (Czatkowice plant), ZPW Trzuskawica S.A. (Trzuskawica/Sitkówka and Bielawy plants), Nordkalk sp. z o.o. (Ostrówka, Ch ˛eciny-Wolica, Sławno plants), Labtar Sp. z o.o. (Tarnów Opolski plant), EGM Sp. z o.o. (Wierzbica plant) and WKG Sp. z o.o. (Raciszyn plant) (Tables 1 and 2). One of the basic parameters determining the effects of flue gas desulphurisation is the chemical purity of limestone. This usually means that for such desulphurisation limestone flour should exhibit CaCO3 content of min. 94%, Fe2O3 content usually under 0.4%, and MgO usually <1%, with variable content of SiO2 [49].

> The largest limestone flour supplier in Poland is Lhoist Polska, where the production of limestone fine sorbents for FGD wet limestone method (at ca. 700,000 tpy) is carried out in two plants: Bukowa—using Jurassic limestone of Bukowa deposit, and Tarnów Opolski—using Triassic limestone of Tarnów Opolski deposit. Sorbents from the Bukowa plant have a high content of CaCO3 (97–98%), while limestone from the Tarnów Opolski plant is slightly inferior in quality (94.7–96.5% CaCO3). Based on Tarnów Opolski limestone, production of small quantities of fine-grained sorbents is also operated by Labtar Sp. z o.o. (Table 2).

> The Czatkowice Limestone Mine (part of the Tauron Polska Energia power company) in Krzeszowice near Krakow is a significant supplier of high-quality limestone sorbents (over 450,000 tpy). It exploits the Czatkowice Carboniferous limestone deposit. It offers limestone sorbents in the form of limestone flour or limestone sand, characterised by high content of CaCO3 (over 96%) and excellent sorption properties [52] (Table 2).

*Energies* **2021**, *14*, 4275

**Table 2.** Basic quality parameters

 of major limestone sorbents produced in Poland and utilised in wet limestone FGD process (surveyed producers' data).

Significant amounts of sorbents (over 200,000 tpy) are obtained on the basis of Jurassic Ch ˛eciny-Wolica limestone deposit in the Wolica plant near Kielce owned by Nordkalk Sp. z o.o. Moreover, less than 100,000 tpy of medium-grained sorbents with grain size < 0.15 mm are supplied by ZPW Trzuskawica (belonging to the Irish concern CRH) on the basis of Devonian highest-purity limestone from the Trzuskawica deposit. Smaller manufacturers of fine-grained limestone sorbents of high purity are EGM Sp. z o.o. (Wierzbica Jurassic limestone mine) and WKG Sp. z o.o. (Raciszyn Jurassic limestone deposit) (Tables 1 and 2).

In the future, it may be possible to commence the production of limestone flour sorbents on the basis of other limestone deposits characterised by the appropriate degree of purity (over 94% CaCO3). It is worth mentioning that the largest domestic Bełchatów Power Plant have recently started to produce limestone sorbents in its own limestone milling plant for the needs of its own 12 power units. Limestone for such purposes is purchased mostly from the Raciszyn, Morawica and Bukowa mines, while the newest Bełchatów power unit uses limestone flour produced among others by Nordkalk, Trzuskawica, WKG Raciszyn and Czatkowice. Moreover, production of limestone flour for the needs of their own desulphurisation plants is carried out in Turów and Połaniec Power Plants.

The total production potential of the Polish plants delivering limestone flour for a variety of applications, is at the moment estimated at approximately 6.0 million tpy, with an increase of approximately 1.5 million tpy over the past decade due to the expansion of a number of existing milling plants (Bełchatów, Sławno, Wolica, Turów, Raciszyn, Wierzbica, Turów and Połaniec). In the coming years it should increase primarily as a result of the expansion of the milling plant located at the Bełchatów Power Plant by approximately 0.4 million tpy. Development of limestone flour production capacity could potentially take place, e.g., at the EGM plant in Wierzbica and at the ZPW Trzuskawica plant in Sitkówka [52].

#### *3.3. Use of Limestone Sorbents in the Polish Power Industry with Obtaining FGD Gypsum and Other Desulphurisation Products*

Among numerous desulphurisation methods used in large power plants and combined heat and power plants, with coal burning in conventional boilers, the non-regenerative wet limestone method of flue gas desulphurisation using fine limestone flour turned out to be the most effective, including in Poland. In this method, the dust-free flue gases are purified in the absorber by a limestone flour suspension flowing in counter-current. The sulphur dioxide (SO2) present in the flue gas reacts with calcium carbonate (CaCO3), the main component of limestone, resulting in intermediate calcium sulfite (CaSO3·1/2H2O) and then—after oxidation with air supplied from outside and after crystallization—gypsum (CaSO4·2H2O). This desulphurisation product is received in the form of water suspension with subsequent water removal on appropriate belts or vacuum filters. Implementation of this method requires relatively high investment outlays, but is characterised by high desulphurisation efficiency (92–99%) and obtaining a fully economically useful product, i.e., synthetic gypsum [31,43,49].

The first wet limestone flue gas desulphurisation plants in Poland were put into operation at the Bełchatów Power Plant in 1994. It initiated in Poland the use of suitable limestone flour (limestone sorbent) for flue gas desulphurisation in power plants, together with the production of synthetic gypsum from flue gas desulphurisation. In the following several years, FGD plants using the wet limestone method were put into operation at 11 power plants (PPs) and 5 combined heat and power plants (CHPs) (Table 3). Currently, the maximum total demand of the Polish PPs and CHPs for the sorbent—limestone flour < 0.1 mm—is estimated at about 3.5 million tpy (which corresponds to synthetic gypsum production capacity of about 4.8 million tpy). The actual consumption of this flour in 2019 has been estimated at about 2.4 million tonnes, with synthetic gypsum production amounting to ca. 3.3 million tonnes.

**Table 3.** The main flue gas desulphurisation installations in the Polish power plants and central heating plants (as of 29 November 2019) [41,42], surveyed sorbent user data.

> At present the most important users of limestone flour (sorbents) < 0.1 mm and synthetic gypsum producers in Poland are (Table 3):

The flue gas desulphurisation at the Bełchatów Power Plant has been in operation—as mentioned above—since 1994 and after gradual expansion it is currently the largest flue gas desulphurisation plant in Europe, operating on all active units. The maximum demand for limestone sorbent in this power plant reached 1.6 million tpy and the actual sorbent consumption in flue gas desulphurisation process in recent years has been approaching 1.5 million tpy (Table 3). Bełchatów Power Plant, as one of three in Poland, has its own limestone milling plant where the level of sorbent production reaches almost 1.3 million tpy, with limestone supplied from numerous mines. For flue gas desulphurisation in the newest power unit, there are used approximately 0.3 million tpy of sorbents supplied from the their main domestic suppliers.

Subsequent flue gas desulphurisation plants using the wet limestone method were commissioned successively at the following power plants and combined heat and power plants:

Conducting the desulphurisation process during fuel combustion in fluidised bed boilers is the second most popular—after the wet limestone method—technological solution in Polish power plants and combined heat and power plants. It also began to be implemented in Poland in the 1990s. The choice of such solution resulted, among others, from the low temperature of the combustion process (850–950 ◦C), the possibility of reduction of both SO2 and NOx emissions and the opportunity to use low-quality fuels [53]. Nowadays, fluidised bed boilers with a capacity of up to 500 MWe are in operation [54]. In fluidised bed boilers, ground fuel and sorbent (limestone sand) are fed into the combustion chamber where they form a so-called "bed" together with an inert material (e.g., sand). Continuous mixing of the bed particles with the air stream allows complete combustion of the fuel and capture of sulphur dioxide [55].

In Poland, for capture of sulphur dioxide emitted during fuel combustion in fluidised bed boilers, limestone sorbent (limestone sand) is primarily used, with the necessary stoichiometric excess of the sorbent. In the combustion process, a very important factor is the granulation of individual components forming the bed, which is usually within the range of 0.1–1.2 mm [31].

The first power units with fluidised bed boilers were commissioned in Poland between 1993 and 2004 in the Turów Power Plant (six boilers in total). At the same time, use of suitable limestone sand (coarse-grained sorbents) for flue gas desulphurisation in such boilers in Poland was initiated. In the following years, fluidised bed boilers were put into operation in the next three PPs and five CHPs. Currently, the maximal total demand of these PPs and CHPs for coarse-grained sorbent (limestone sand 0.1–1.2 mm) is estimated at about 1.5 million tpy, while the actual consumption is estimated at about 1.0 million tpy, including up to 0.5 million tpy at the Turów PP only.

At present, the most important users of coarse-grained sorbent (limestone sand 0.1–1.2 mm) used for desulphurisation in fluidised bed boilers in Poland are (Table 3):

In the first phase of fast introduction of flue gas desulphurisation technologies in the Polish coal-based power plants in the years 1994–2000, the consumption of limestone flour showed a powerful upward trend. It was halted in the years 2001–2006 when domestic electricity generation was reduced (Figure 1). In order to meet the new gas emission standards introduced by Directive 2001/80/EC [8], Directive 2010/75/EU [9] and the obligations contained in the Accession Treaty following Poland's accession to the European Union [56], intensive activities were carried out in subsequent years, as a result of which FGD installations were built at numerous subsequent plants. The development of the use of the wet limestone method resulted in a parallel development of the production and consumption of the fine-grained limestone sorbent necessary for this method. A close correlation is observed between the development of limestone sorbent consumption and synthetic gypsum production coming from this process (Figure 1).

**Figure 1.** Comparison of the production volume of synthetic gypsum and consumption of limestone sorbents applied in flue gas desulphurisation in wet method (surveyed gypsum producers' and sorbent consumers' data).

As a result, during the last 25 years, the Polish demand for limestone sorbents (limestone flour) with granulation < 0.1 mm for flue gas desulphurisation by wet limestone method has gradually increased, reaching about 2.4 million tpy (Figure 1). At the same time, the consumption of coarse-grained sorbents (i.e., limestone sand with granulation of 0.1–1.2 mm) used as sorbents in fluidised bed boilers increased in Poland to about 1.0 million tpy. The overall consumption of ground limestone for use as a SO2 sorbent in the domestic power industry in recent years has reached about 3.3–3.4 million tpy, and production of synthetic gypsum has stabilized at the level of approx. 3.3 million tonnes (Figure 1).

#### **4. Discussion**

Attempts to forecast the amount of limestone sorbent consumption in flue gas desulphurisation in Poland in the years to come have highly uncertain results, although there is no doubt that this amount will not be significantly reduced in a few years' perspective, and even, on the contrary, it should increase noticeably. The main factors influencing this will be, among others, the structure of electricity production (the so-called energy mix), current and expected share of hard coal and lignite burning in electricity production, the expected sulphur content in coals to be burnt, the range and scope of planned upgrading of existing power units or their replacement with new ones (taking into account the type of fuel used), and finally—the expected share of electricity generated from renewable sources [57,58].

Leaving aside the issues of the development of the energy mix and the growing share of renewable energy sources in total electricity production, there is no doubt that due to many years of backwardness of the Polish power industry, so far dominated by coal-fired power plants, significant investments are necessary to launch new electricity production capacities and transmission networks. Currently in Poland, 48% of active boilers and 44% of turbine sets are over 30 years old, and about 30% of boilers and about 32% of turbine sets are between 20 and 30 years old [25]. According to the actual Polish Energy Policy until 2040 [23], Poland will try to cover its power demand from its own resources. Polish coal resources will remain an important element of the country's energy security, but an increase in demand for energy will be met from sources other than coal-fired units. It is assumed that the share of coal in the energy consumption structure will be below 56% in 2030, and with the likely increase in EU ETS allowance prices it may reach the level of approximately 38%. In addition, renewable energy sources will play an increasingly important role, and their share in the structure of net domestic energy consumption will reach no less than 32% in 2030 [23]. This will be achieved primarily through the development of photovoltaics and offshore wind farms, which due to their characteristics of economic and technical conditions have the greatest potential for development. In addition, it is necessary to develop transmission infrastructure, energy storage technologies, as well as to expand the use of gas units as regulating capacity. It is assumed that from 2033, nuclear power will be implemented (a total of six nuclear power units with a total capacity of between six and nine GW are planned to be built), which will ensure the stability of the energy system and clearly reduce emissions from the sector. In subsequent years, low-efficiency generation units will be gradually phased out and replaced with higher-efficiency units (including cogeneration). Ultimately, a completely new energy system based on low- and zero-emission sources will be created by 2040 [23]. The implementation of the assumptions of this plan will significantly change the structure of the domestic energy sector in the future and will directly affect the demand for mineral sorbents for flue gas desulphurisation and for the production of synthetic gypsum.

Since 2016, the production of FGD synthetic gypsum in Poland remained at a similar level of about 3.3–3.4 million tpy, while the demand for limestone flour for the wet FGD method—at the level of 2.4–2.5 million tpy, and demand for limestone sand for fluidised bed boilers—ca. 1.0 million tpy. However, between 2018 and 2020, new flue gas desulphurisation plants were commissioned at four new coal-fired power units at Kozienice PP, Opole PP and Jaworzno III PP. Moreover, it is planned to complete the construction of the last new coal-fired power unit at the Turów PP with a capacity of 490 MW in 2021, also equipped with a flue gas desulphurisation plant using the wet limestone method. The construction of these new, conventional, power units allowed to replace a number of worn-out, oldest units. After 2021, new hard coal-fired or lignite-fired power units will not be built in Poland. So, eventually, starting from 2022, with perspective towards at least 2030, the total demand for limestone flour and limestone sand as FGD sorbents in Poland may achieve the record level of ca. 3.5–3.6 million tpy, including about 2.6 million tpy of fine-grained flour for flue gas desulphurisation in wet limestone method, and about 1.0 million tpy of coarse-grained flour (limestone sand) for desulphurisation in fluidised bed boilers and, subordinately, using dry or semi-dry methods. At the same time, the total production capacity of FGD synthetic gypsum in all Polish power plants can increase to about 5.7 million tpy, while its real production volume—to at least 4.6 million tpy. In the next few years, further new power units will undoubtedly be built in Poland, but they will not be based on hard coal or lignite burning, being mostly gas units and sometimes biomass units [23,57].

Forecasting the role of coal-fired power generation in Poland after 2030, and consequently the demand for limestone sorbents for desulphurisation in this sector, is extremely difficult and burdened with enormous uncertainty. The forecast error may even exceed 50%. The final shape of the Polish power industry is a matter of considerable uncertainty, especially in relation to economy decarbonisation processes pushed by the EU, with pos-

sible rapid reduction of the coal share in the energy mix in favour of increasing the RES share. After 2030, there will be another phase of phasing out the oldest power units, e.g., in Kozienice, Dolna Odra, Bełchatów and many other power plants. They are to be replaced mainly by gas units, nuclear units and renewable energy sources such as wind turbines and photovoltaic [23]. In such a scenario, total demand for limestone sorbents for desulphurisation will systematically fall and in 2050 may reach maximum level of about 1.3 million tpy, of which ca. 1.0 million tpy for wet limestone FGD method (Figure 2) and about 0.3 million tpy for flue gas desulphurisation in fluidised bed boilers. As a result, the production of synthetic gypsum in 2050 may decrease to only max. 1.5 million tpy. At that time, only those power units that were built between 2017 and 2021, and maybe also a few older coal-fired units that were upgraded in recent years, are likely to remain in operation. However, we cannot rule out that in 2050 the share of coal in the Polish energy mix may decrease even to zero, with closure of the last coal-fired PPs and CHPs. As a result, the consumption of sorbents for desulphurisation of flue gas coming from coal combustion will also practically disappear at this moment.

**Figure 2.** Forecast of limestone sorbents consumption for flue gas desulphurisation by wet limestone method in the years 2020–2050 (maximum expected forecasted quantities).

#### **5. Conclusions**

Measures taken since the beginning of 1990s to reduce SO2 emissions in the Polish power industry (being mainly based on coal burning) resulted in the construction of numerous flue gas desulphurisation plants in the last 30 years. In Poland, they are mainly using the wet limestone method of dust-free flue gases, or use of fluidised bed boilers where the desulphurisation process takes place in the boiler immediately after coal combustion. In both main desulphurisation methods used in Poland, ground limestone of appropriate granulation is used for desulphurisation. This resulted in quick increase in demand for limestone sorbents: from zero in the early 1990s to about 3.4–3.5 million tpy at present. For the production of such limestone sorbent (limestone flour for wet limestone FGD method and limestone sand for fluidised bed boilers) different varieties of limestone are used in a few regions of the country, and they must meet basic requirements regarding, among others, chemical composition and granulation. At present, mostly Jurassic limestone, but also Devonian, Carboniferous and Triassic limestone varieties have the greatest significance in limestone sorbents production in Poland.

In 2022, after the completion of the last new investment project in the Polish coal-fired power industry in 2021—the new power unit in Turów Power Plant, the total demand for limestone FGD sorbents in domestic power plants will reach the maximum level of about 3.7 million tpy. Such a demand should be maintained until 2028–2030, after which it will systematically decrease in the following years, as a result of the gradual closure of subsequent coal-fired power units, while new production capacities based on hard coal or lignite are not expected to be built anymore. As a result of gradual decommissioning of coal-fired units in the 2050 perspective, the total consumption of sorbents in the domestic power sector should be reduced to a maximum of 1.3 million tpy, of which about 1.0 million tpy will be used for limestone flour consumption in wet limestone FGD installations and about 0.3 million tpy for limestone sand consumption in fluidised bed boilers. After 2050, it will probably be reduced practically to zero. As indirect consequence, the production of desulphurisation products, including in particular synthetic gypsum from the wet limestone method, will also decrease. Production of the latter could fall from about 3.6 million tpy in the coming years to only max. 1.5 million tpy just before 2050 and practically to zero after 2050.

**Author Contributions:** Conceptualization, K.G., J.S.; methodology, K.G., J.S.; validation, J.S., K.G.; investigation, J.S., K.G; writing—original draft preparation, J.S., K.G.; writing—review and editing, K.G., J.S. All authors have read and agreed to the published version of the manuscript.

**Funding:** This research was financed from the statutory subsidy of the Mineral and Energy Economy Research Institute, Polish Academy of Sciences.

**Institutional Review Board Statement:** Not applicable.

**Informed Consent Statement:** Not applicable.

**Data Availability Statement:** Data sharing not applicable.

**Acknowledgments:** The preparation of this paper was supported by the Polish National Agency for Academic Exchange under Grant No. PPI/APM/2019/1/00079/U/00).

**Conflicts of Interest:** The authors declare no conflict of interest.

#### **References**

### *Article* **The Economic Aspect of Using Different Plug-In Hybrid Driving Techniques in Urban Conditions**

**Piotr Wróblewski 1,\*, Jerzy Kupiec 2, Wojciech Drozd˙ z˙ 3, Wojciech Lewicki <sup>4</sup> and Jarosław Jaworski <sup>3</sup>**

**Abstract:** Plug-in hybrids (PHEV) have become popular due to zero-emission driving, e.g., in urban areas, and using an internal combustion engine on longer distances. Energy consumption by the PHEV depends on many factors which can be either dependent or independent of the driver. The article examines how the driver can use the vehicle's capabilities to influence its wear. Determining the optimal driving technique, due to the adopted nature of the timetable, is the basic variable that determines the profitability of using a given drive system. Four driving techniques have been selected to determine which one can offer the largest advantages. A vehicle-dedicated application has recorded the drivetrain performance on a predetermined route through an urban area. The analysis of results has demonstrated which of the driving techniques provides measurable effects in terms of reduced energy consumption and the shortest travelling time. The study shows longitudinal acceleration and torque generated by the electric drive. The information included in the study can help any PHEV user reduce the operating cost by applying an appropriate driving technique. The proposed research introduces the possibilities of assessing the influence of the driving style on energy consumption. The innovative side of this research is the observation of stochastic phenomena that are difficult to detect when using approximation modelling.

**Keywords:** electric car; electromobility; PHEV; data analysis; driving technique; energy consumption

#### **1.  This impact is already generated at the stage of manufacturing and operation. Manufacturers make every effort to make the construction of vehicles as light as possible [1,2]. Hence, internal combustion engines can use less fuel and produce small volumes of toxic compounds emitted to the atmosphere [3–5]. Alternative fuel technologies [6–8] and hybrid vehicle propulsion systems [9–11] have been extensively developed.

When analyzing the above technologies, it can be noted that hybrid vehicles are considered to be the most sensible solutions to reduce fuel consumption and toxic emissions without compromising the vehicle's drivability [9–13]. PHEVs use energy management systems to reduce fuel and energy consumption originating from several energy sources [14–16]. Among hybrid vehicles, the largest attention of researchers has been drawn to the electric plug-in hybrid vehicles (PHEV) due to their batteries and an advanced propulsion system [17–21]. These are universal vehicles designed to produce zero-emission while driving in urban areas, and travel long distances while using the combustion engine. The

**Citation:** Wróblewski, P.; Kupiec, J.; Drozd˙ z, W.; Lewicki, W.; Jaworski, J. ˙ The Economic Aspect of Using Different Plug-In Hybrid Driving Techniques in Urban Conditions. *Energies* **2021**, *14*, 3543. https:// doi.org/10.3390/en14123543

Academic Editors: Ignacio Mauleón and Omar Hegazy

Received: 10 March 2021 Accepted: 11 June 2021 Published: 14 June 2021

**Publisher's Note:** MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.

**Copyright:** © 2021 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

complex propulsion system helps reduce carbon dioxide emission, in particular in urban areas [22,23].

PHEVs are cheaper than electric vehicles and, at the same time, still have advantages over internal combustion engine vehicles (ICEV) [24]. The analysis of distances covered by owners of conventional vehicles shows that most of them travel less than 32 km per day and, in the case of PHEV users, it is less than 11 km per day [25]. The plug-in hybrid (PHEV) is used to describe a conventional hybrid vehicle with a battery rechargeable from a conventional power socket, recuperated energy from braking or by a combustion enginedriven generator [26,27]. The PHEV uses an electric motor of 60–70 kW [28]. The optimal battery capacity compared to the BEV enables to maintain the range in the urban driving mode and a partial reduction of the combustion engine use over the distance [29,30]. When the battery is discharged, the internal combustion engine starts to drive the vehicle and the generator operated until the battery is recharged. The combustion engine also operates at the start-up when the outside temperature is low. This is referred to as a cold start and occurs after a continuous 12-h shut-down [31]. This is the cause of fuel consumption when driving on short distances with fully charged batteries.

The combination of an internal combustion engine and an electric engine makes the vehicle independent from access to the electric charger. However, if one travels on short distances in a zero-emission mode, the vehicle uses electricity. To reduce the energy used during a journey, one should plan the route well and take into account the traffic. Although the approach is presented by authors of numerous publications [32,33], the final energy needed to cover the route depends on yet another factor that has not been addressed by scientific research. It is the driving technique that, in addition to the factors mentioned above, such as the construction and capability of a vehicle and conditions and road infrastructure, has untapped potential in terms of energy saving. The driver is able to use systems installed in the vehicle and his assessment of the road traffic to use less energy on a previously planned route [34–36]. In the opinion of the authors, it is worth determining the extent and benefits of a few simple driving techniques in combination with systems made available by the vehicle manufacturer. The subject of electromobility of exhaust emissions and trends in discharged systems in Poland was discussed in the works [37–42].