Assessing the Implications of Integrating Small Modular Reactors in Modern Power Systems

Abstract

This paper investigates the long-term impact of integrating emerging Small Modular Reactors (SMR) in modern power systems. A chronological simulation of the Greek day-ahead market and real-time balancing market with fine time granularity is conducted for a future 20-year period (2032–2051) under four SMR penetration scenarios using a specialized integrated market simulation software. Simulation results indicate that SMR units can be regarded as a promising electricity generation solution in the forthcoming energy transition landscape. The introduction of up to 3 GW of SMR capacity is projected to significantly decrease reliance on gas imports by up to 62%, reduce carbon emissions by up to 52%, and lower overall electricity costs for end-consumers by up to 21% as compared to a baseline scenario without SMRs. It is anticipated that SMR units are expected to leverage their operating advantages and generally achieve positive financial results when participating directly in the wholesale market. However, their economic viability is highly dependent on their initial capital expenditure and other operating cost components, which at present are highly uncertain.

1. Introduction

1.1. Background and Motivation

The rise of global temperature during the last decades leads global organizations to ask for the reduction of anthropogenic CO₂ emissions. The United Nations warn that emissions must fall 42% by 2030 and 57% by 2035, to hold global warming to the Paris Agreement target (i.e., 1.5 °C) [1]. Considering the difficulties of this short-term global achievement, lower percentages have already been announced for the alternative target of 2 °C. For the years 2030 and 2035, the global mitigation potential for the sector of energy production is estimated to remain the highest among other sectors, that is 12.2 Gt CO₂e and 14.7 Gt CO₂e, respectively. In this context, the replacement of fossil-fuel power plants with technologies that emit zero (or almost zero) greenhouse gases (GHGs) is expected to contribute decisively to the reduction of the global temperature’s annual derivative. Although natural gas-fired power plants, which have already replaced a significant share of coal capacity worldwide, emit 60–75% less CO₂ than coal-fired power plants, more intense actions need to be taken towards the elimination of CO₂ emissions. The combination of renewable generation and nuclear energy, which has the advantage of providing dispatchable energy generation and, therefore, compensating for RES stochasticity, lies lately among the most promising solutions.

Greece is leading the global transition from coal to zero-carbon energy production, achieving a decrease of coal power generation by 41% over the recent 8-year period [1]. United Kingdom and Denmark are following with 37% and 29%. The rapid deployment of PV and wind plants in Greece has mostly contributed to this achievement, whereas their volatile and intermittent energy generation is currently compensated mainly by flexible gas-fired power plants. The integration of storage, such as battery energy storage systems or pumped-storage units, is planned for the near future. However, a lively debate of whether nuclear energy in the form of emerging Small Modular Reactors that can provide abundant, dispatchable, low-cost and nearly zero-carbon energy generation can provide a viable alternative for the successful implementation of the energy transition, has come to the fore.

1.2. Overview of SMRs

A Small Modular Reactor (SMR) is a type of nuclear reactor with modular design allowing for shorter installation times and advanced economies connected to a more production-line way of assembling its components [2]. The distribution of SMRs’ power capacities shows two local maxima: one at the range of 31 to 100 MWe and the other at the range of 201 to 300 MWe [2], pointing out their versatility as energy source, in addition to their ability to operate in load-following mode. According to a recent review [3], a 300-MW SMR will present 52% lower total capital expenditure (CAPEX) in absolute terms but 62% higher CAPEX in $/MW terms as compared to a large Nuclear Power Plant (NPP). Nevertheless, the construction cost will be reduced over time, due to the serial production of SMRs. The installation of an SMR is estimated to last about 3 to 4 years, while the installation of an NPP exceeds a period of 8 years [4]. The operation of an SMR is planned to be a simplified version of the operation of an NPP, hence the handling procedures are more automated, and fewer personnel are needed for their operation. The latter also reduces the possibility of human errors during the operation. The smaller core of an SMR eases the application of passive safety techniques, like: (a) the isolation of the core and its coolant system in a single reactor pressurized vessel, and (b) the placement of the modules under the water, providing passively ample amounts of cooling water to the containment vessels [3]. SMRs incorporate even more advanced technologies, like using molten chloride salts as both coolant and fuel carrier providing a unique passive slow-down of the fission chain reactions. A smaller reactor’s core also produces less radioactive waste, even if this is correlated also with the mode of operation. In general, SMRs exhibit longer refueling cycles [5]. Another advantage of SMRs over NPPs is the ability to install them in a larger variety of locations with limited space, like industrial zones, or turn them into floating platforms and provide energy or desalination service to isolated islands [2,6]. Increasing the operating units of an SMR upon demand over time is a more applicable option than in the case of an NPP, due to the smaller units of the fore and their practically independent operation. This independent operation of SMR units can be exploited in energy forms beyond electricity like hydrogen production, heating of buildings and desalination of seawater for public use [6]. For decommissioning, the built-in construction of SMR components standardizes the management of activated materials, allowing vendors to include this service in their initial offer.

1.3. Literature Review

In general, the modeling of the operation and economics of nuclear power plants has attracted enough attention by the research community so far. Early works address mainly large NPPs [7,8,9,10,11,12,13,14], whereas during the latest years research has mostly focused on the integration of the emerging SMR units in power systems under various configurations [15,16,17,18,19,20,21,22,23,24,25,26,27,28,29,30,31,32,33].

Regarding NPPs, a mixed-integer linear programming (MILP) formulation for the modeling of the flexible operation of nuclear power plants in a US electricity market framework, which explores the benefits that can be obtained regarding system operating costs, reactor owner revenues and RES curtailments as compared to their must-run baseload operation is presented in [7]. The load-following operation of nuclear power plants is also compared against the baseload operation in [8], where a simplified LP-based power plant dispatching model is employed in a simulation study implemented in 13 European countries for 2012 and 2050. A novel formulation of the nuclear refueling and maintenance schedule to evaluate the impact that nuclear fleet flexibility may have on the operation of a simplified French power system of the year 2006 under five different RES penetration shares is given in [9]. From a least-cost planning perspective, the impact that the implementation of brown coal limits and nuclear policy would have on the future energy mix of Czech Republic in terms of carbon reductions, RES penetration as well as on external environmental and health issues are evaluated using the TIMES-CZ model in [10]. A similar study that uses a typical unit commitment model and evaluates the impact of different operation modes of nuclear power plants on the power system operation and particularly on coal-fired and RES units in the Shandong province of China for a single year is given in [11]. The general trends regarding the impact of increasing intermittent RES generation on nuclear power plants operation along with the economic potential of maintaining nuclear plants instead of gas-fired units as back-up resources are highlighted in [12]. From a power system resource adequacy perspective, the reliability of the Slovenian power system is evaluated through the replacement of a nuclear power plant with wind plants of triple installed capacity under differentiated weather data and it is concluded that nuclear capacity is much more valuable in terms of its contribution to capacity adequacy than wind capacity [13]. From a pure economic perspective, a comparative scenario-based analysis of the economic feasibility and environmental impact of a large 4800-MW NPP against an equivalent large-scale PV plant in Turkey in terms of electricity generation volumes, CO₂ savings, costs, required land area and payback period is given in [14].

Regarding SMR technology, a critical review of the unique features of more than 100 SMR units focusing on reactor-design, safety and security aspects and their comparison with the traditional nuclear power plants are presented in [15], whereas an extensive state-of-the-art review of SMRs from a technological, environmental, economic, and societal perspective, which highlights the progress as well as the concerns related to this power generation technology is presented in [16]. The challenges arising by the integration of SMRs in RES microgrids are examined in [17], where it is concluded that SMRs offer notable advantages (modular design and deployment, load-following capacity, capability to provide thermal energy) but there are also many open issues to be addressed in the future (dynamic behavior, sizing, real-time control and operation). A simulation study that employs SMRs with RES plants and storage capacity to full serve the system load demand of the insular power system of Grand Canary in Spain in order to determine the best combination of generation resources that leads to the lowest levelized cost of electricity (LCOE) is examined in [18]. From the optimal SMR siting point of view, a model using the analytical hierarchy process and the fuzzy analytical hierarchy process algorithms to develop a ranking system to choose proper sites for SMR power generating units is given in [19]. In the same context, a factorial optimization-based model that identifies which are the optimal places for SMR siting along with the size of the conventional fossil-fueled plants capacity that should be replaced with clean electricity generating technologies to the province of Saskatchewan, Canada, under multiple uncertainties is proposed in [20].

From a pure economic analysis perspective, a systematic literature review of the economics and finance of land-based SMR is given in [21], where multiple critical factors such as size, modularity, construction times and cogeneration capability are considered along with well-known valuation indicators such as LCOE, net present value (NPV), and internal rate of return (IRR). A very recent literature review that focuses on the life-cycle costs of SMRs also dealing with the importance of regulations, discount rates, country and project specifications and public acceptance is presented in [22], while a general framework for the comparison of the direct and indirect capital costs of SMR units against large NPPs using real vendor data is given in [23]. A fair comparison of the economic competitiveness of SMRs against coal-fired and gas-fired CCGT units for various fuel cost, CO₂ price and discount rates scenarios in terms of the levelized cost of various components (investment, fuel, O&M, carbon tax) is presented in [24]. A similar bottom-up techno-economic analysis of three SMR types (light-water, gas-cooled and molten-salt), where the economic impact of plant simplification, modularization, reduced construction times and capital subsidies are explored against conventional large NPPs and gas-fired units with and without post-combustion carbon capture, is presented in [25].

From the hybrid energy system perspective, in [26] the economic feasibility of two first-of-a-kind SMR projects is evaluated for four distinct operating scenarios (full load, load-following, cogeneration of electricity and heat, integration with BESS) and is also compared against two commercial large Pressurized Water Reactors (PWRs) using the NPV approach. The economic aspects of a hybrid system that comprises a nuclear power plant with a large-scale desalination plant are evaluated in [27] using a techno-economic model that introduces much detail from the heat and electricity consumption and cost point of view for various desalination schemes. A production cost minimization model for the optimal operation of a tightly coupled nuclear-wind hybrid plant in the US-type day-ahead market framework under three different optimization and control strategies is presented in [28]. A techno-economic feasibility study of a hybrid energy system that comprises multiple SMRs coupled with three alternative hydrogen production facilities (alkaline water electrolysis, high-temperature steam electrolysis, Sulphur-iodine cycle) is presented in [29]. The design and operation of a hybrid energy system comprising SMRs, PV and wind plants and a thermal energy storage facility is optimized to minimize the system’s LCOE for various dispatch horizons and different RES generation timeseries in [30]. From a pure technical point of view, a new flexible control scheme of a nuclear cogeneration plant in a nuclear-RES hybrid energy system to address the grid balance fluctuation caused by the intermittent RES generation in the real-time operation is given in [31]. Finally, a modeling framework for the short-term simulation of a stand-alone hybrid system that consists of an SMR unit along with PV and wind plants and is suitable for electricity generation and district heating is presented in [32], where a detailed dynamic model of the reactor and a quasi-static model of the district heating system are proposed. This work is extended by the same authors in [33] with the integration of reactor, district heating system and RES operating constraints.

1.4. Research Gap

Some of the aforementioned research works provide a systematic and very informative, yet qualitative, review of the pros and cons of the emerging SMR units from a technological, environmental, economic, and societal perspective along with the challenges that may arise from their integration in modern power systems [15,16,17,21,22]. On the contrary, other works study the economics and/or the impact that the introduction of NPPs [7,8,9,10,11,12,13,14], stand-alone SMR units [18,19,20,23,24,25] or hybrid energy systems comprising nuclear assets [26,27,28,29,30,31,32,33] may have on the power system operation from a quantitative point of view. In the latter case, the quantitative analysis is performed on the basis of two alternatives: the first one is the use of economic assessment models that employ well-known techniques and calculate standard indicators such as LCOE, NPV, payback period, etc. [23,24,25,26,29] which, however, are based on rough estimates of the long-term operational behavior of the nuclear assets in terms of electricity generation volumes, interplay with other electricity generating technologies, operating revenues and costs, etc. Alternatively, generalized short-/long-term power system simulation models [7,8,9,10,11,13,18,19,20,27,28,30,31,32,33], some of which may also be accompanied by a relevant high-level economic analysis [8,9,12,18,27,30], are used under limited time horizons (e.g., a single year or typical days) and/or coarse temporal resolution, also ignoring the detailed unit technical and operating constraints, especially for conventional generating technologies. As a result, the complex modeling of the actual wholesale market operation is ignored and, therefore, the inherent market operation dynamics that determine critical market indicators (e.g., market clearing prices, energy generation volumes, units’ cycling, market revenues, operating costs, etc.) which, in turn, better highlight the real added value of SMR units’ operation in the long-term, cannot be captured effectively. In addition, the quantified impact that different levels of SMR penetration would have on the end-consumers’ total electricity cost as well as the long-term economic viability of such novel power generation projects from the investor’s perspective for a range of capital and operating costs has not been assessed so far in the literature.

Table 1. Main features of the research works reported in the literature and compared to the work presented in this paper.

Ref.	Geographical Area	Qualitative/Quantitative Analysis	NPP/SMR	Stand-Alone (S)/ Hybrid (H) System	Use of Simulation?	Detailed Modeling of Electricity Market Operation?	Study Horizon	Temporal Resolution	Economic Aspects Addressed ?	Economic Viability Analysis of Nuclear Assets?
[7]	USA	Quantitative	NPP	S	YES	YES	1 year	1 h	NO	NO
[8]	Europe	Quantitative	NPP	S	YES	NO	2 years	1 h	YES	NO
[9]	France	Quantitative	NPP	S	YES	NO	1 year	1 h	YES	NO
[10]	Czech Republic	Quantitative	NPP	S	YES	NO	35 years	-	Partially	NO
[11]	China	Quantitative	NPP	S	YES	NO	1 year	1 h	NO	NO
[12]	France	Quantitative	NPP	S	NO	NO	1 year	-	YES	NO
[13]	Slovenia	Quantitative	NPP	S	YES	NO	1 year	-	NO	NO
[14]	Turkey	Quantitative	NPP	S	NO	NO	30 years	-	NO	NO
[15]	-	Qualitative	SMR	S	NO	NO	-	-	-	-
[16]	-	Qualitative	SMR	S	NO	NO	-	-	-	-
[17]	-	Qualitative	SMR	S & H	NO	NO	-	-	-	-
[18]	Spain	Quantitative	SMR	S	YES	NO	25 years	-	YES	NO
[19]	Canada	Quantitative	SMR	S	YES	NO	-	-	NO	NO
[20]	Canada	Quantitative	SMR	S	YES	NO	15 years	5 years	NO	NO
[21]	-	Qualitative	SMR	S	NO	NO	-	-	YES	-
[22]	-	Qualitative	SMR	S	NO	NO	-	-	YES	-
[23]	-	Quantitative	SMR	S	NO	NO	-	-	Partially	-
[24]	-	Quantitative	SMR	S	NO	NO	-	-	YES	NO
[25]	-	Quantitative	SMR	S	NO	NO	-	-	YES	NO
[26]	-	Quantitative	SMR	H	NO	NO	40 years	-	YES	NO
[27]	-	Quantitative	SMR	H	YES	NO	15 years	-	YES	NO
[28]	-	Quantitative	SMR	H	YES	DAM only	1 day	1 h	NO	NO
[29]	-	Quantitative	SMR	H	NO	NO	-	-	YES	NO
[30]	-	Quantitative	SMR	H	YES	NO	360–500 h	1 h	YES	NO
[31]	-	Quantitative	SMR	H	YES	NO	12 h	1 s	NO	NO
[32]	-	Quantitative	SMR	H	YES	NO	1 day	15-min	NO	NO
[33]	-	Quantitative	SMR	H	YES	NO	1 month	15-min	NO	NO
This paper	Greece	Quantitative	SMR	S	YES	YES (DAM, ISP, RTBEM)	20 years	1 h/ 30-min/15-min	YES	YES

summarizes the key features of research works reported in the literature so far and offers a comparative analysis with the proposed work in this paper.

1.5. Scope of This Work and Main Contributions

The scope of this paper is to assess the implications that the introduction of emerging SMR units will have on the Greek power system operation in the long-term and, in particular, on key power system and electricity market indicators. Detailed chronological simulations of the Greek wholesale electricity market are conducted for four distinct SMR penetration levels for a future 20-year period (2032–2051) under realistic simulation assumptions.

The main contributions of this paper with respect to the existing literature are as follows:

(a)

A scenario-based simulation analysis to investigate the potential operational and economic implications arising from the construction and operation of SMR units in Greece is conducted. To the best of the authors’ knowledge, this is the first time that the impact of integrating this novel power generation technology in modern power systems and wholesale electricity markets under different penetration levels is assessed in quantitative terms for a long-term horizon. Our goal is to provide an accurate view of the tangible benefits that these units may bring to the power system operation and, in turn, the society welfare, in terms of mitigating the dependence on natural gas imports, reducing carbon emissions and associated costs, as well as examining potential electricity cost savings for end-consumers. The long-term economic viability of such innovative power generation projects is also investigated from the investor’s perspective through a detailed economic valuation analysis. While the Greek power system and electricity market serve as our case study, this analysis offers valuable insights into the multi-dimensional benefits of this new power generation technology, enabling similar analyses in other regions.

(b)

Despite the long-term perspective of this analysis, all relevant wholesale electricity market processes, namely Day-Ahead Market (DAM), Integrated Scheduling Process (ISP) and Real-Time Balancing Energy Market (RTBEM) are sequentially simulated on a daily basis under finest time resolution ranging from 1 h (DAM) to 30-min (ISP) and down to 15-min (RTBEM). This allows for the effective modeling of the large set of inter-temporal constraints pertaining to the system and generating units’ actual operation and, therefore, provides a realistic assessment of their impact on the market solution results as well as on the long-term economic viability of SMR units. This is achieved by using a powerful market simulation software tool, which emulates the detailed functionalities of the official optimization solvers used by the associated Greek electricity market and power system operation institutions (Market/System Operators) for solving the actual Greek wholesale electricity market.

It is underlined that this work focuses exclusively on quantifying the impact of integrating variable SMR capacity on the long-term operation of the Greek wholesale electricity market and, particularly, on key market and power system indicators. Possible social implications and concerns associated with the adoption of nuclear energy for large-scale electricity generation remain outside the scope of this paper.

The remainder of the paper is structured as follows: Section 2 summarizes the key features of the various SMR units modeled in this study along with a high-level overview of the simulation software tool used in this work. In Section 3 the case study along with the main simulation results are discussed, while in Section 4 valuable conclusions are drawn.

2. Methodology

2.1. Types of SMR Units in This Study

In this study, four SMR types that could potentially be deployed in the Greek power system are selected: two multi-mode Light-Water Reactor (LWR)-SMRs, one single-unit LWR-SMR and one advanced (Generation IV) Sodium Fast Reactor (SFR)-SMR. The main criteria for the selection of these SMR types include: (a) the ability to operate efficiently at load-following mode, (b) the enhanced passive safety systems and (c) the low rate of fuel burning, which could lead to extended fuel cycles. Commercialization and licensing of the designs are key criteria to be considered before the selection and installation of each reactor. For instance, the seismicity of Greece is a critical factor for the determination of the best siting areas. A brief description of the main characteristics of the selected SMR types is given in the following paragraphs.

2.1.1. NUWARD^TM

NUWARD^TM Reactor is produced by EDF (London, UK). Its integrated light-water PWR design exploits two independent reactor modules of 170 MWe each. By design, the unit can be used for multiple purposes like cogeneration of electricity and heat, district heating, hydrogen production and water desalination [34]. The independent operation between the two modules offers great flexibility and allows the reactor to integrate efficiently with intermittent RES generation [35].

The plant’s refueling outage lasts 20 days every 24 months of continuous operation, and the refueling strategy is to replace half of the core in that period. The storage capacity of spent fuel assemblies in the spent fuel pool is adequate for 10 years of operation [34].

NUWARD^TM Reactor operates either in baseload or load-following mode between 20–100% of nominal capacity, whereas the rate of change is equal to 5% per minute. The design life of the reactor is 60 years and the estimated construction time, from first concrete to criticality, is 36 months [35].

As a result, the independent operation of the two modules, along with the ability to operate at a load-following mode with high ramp-rates makes it suitable for the future RES-dominated Greek power system volatile operating conditions. Additionally, its extensive fuel cycle and provisional spent fuel management are advantageous, for the time needed by Greece to develop and implement fuel recycling strategies.

2.1.2. VOYGR^TM

VOYGR^TM SMR designed by NuScale Power Co. exhibits great scalability due to its independent reactor modules, operating in a multi-module configuration. Each module is a small, light-water-cooled PWR with a nominal capacity of 77 MWe [36]. Standard configurations are: (a) VOYGR-4 with four modules (308 MWe in total), (b) VOYGR-6 with six modules (462 MWe in total) and (c) VOYGR-12 with twelve modules (924 MWe in total) [34]. This design aims at generating power with high operational flexibility. However, it could also be used for nuclear cogeneration applications, such as district heating, industrial heat application, water desalination etc. [34]. The multi-modular design allows for the cycling operation of one or more modules according to the power system needs [5].

Each power module consists of: (a) reactor core, (b) helical coil steam generators and (c) a pressurizer all within a reactor pressure vessel (RPV), making it an iPWR nuclear power module. The Nuclear Steam Supply System (NSSS), along with RPV, is protected by a containment vessel that sits at the floor of the reactor pool [34].

The reactor core contains 37 fuel assemblies and 16 control rod assemblies. The fuel assembly is a 17 × 17 PWR. The refueling is conducted on a nominal 18-month refueling cycle, whereas the estimated refueling outage time is 10 days. The refueling process does not affect significantly the power production, considering that the rest of the modules are still operable. The spent fuel pool provides storage for up to 10 years of used fuel assemblies. Provisions include facilities for dry storage of all used fuel for the 60-year design lifetime of the plant [34].

To sum up, (a) the maneuverability in power generation, (b) the simultaneous operation and maintenance and (c) the fuel management render the VOYGR^TM SMR as an appealing option for Greece. The availability of the dry storage facility covering a 60-years period is beneficial for Greece, as solutions for the spent fuel and the radioactive waste management must be developed in the meantime.

2.1.3. BWRX-300

BWRX-300 SMR is produced by GE-Hitachi and Hitachi-GE Nuclear Energy (Wilmington, NC, USA). It comprises a small BWR single module with a nominal capacity of 300 MWe. The coolant of the core and the neutron moderation are served by light water. The circulation of the primary cycle is natural and the layout of the NSSS is a direct Rankine cycle [34,37]. The reactor is a BWR type, thus the total operating pressure of the coolant is lower than that of the LWR ones shown above (i.e., 7.2 MPa and ~15 MPa, respectively). The lower operating pressure and the lack of the secondary cycle advance the safety and cost of the reactor [37].

BWRX-300 is capable of operating in base load and load-following mode, within a range of 50–100% of its nominal capacity [37]. Due to its high thermal capacity, the reactor may also serve several applications, such as district heating, hydrogen production, synthetic fuel production and any other industrial process that requires heat [34].

The design of the BWRX-300 reactor is based on the previous features of Economic Simplified and Advanced BWR (ESBWR and ABWR) and has a design life of 60 years. Components of the nuclear boiler system include the RPV, control rod drives mechanism, control blades, chimney (the space where water evaporates), separators and a dryer. The RPV contains a removable head, the reactor internals and appurtenances enclosed by the vessel. During the maintenance and refueling, the reactor vessel is opened, and the internals could be removed [34].

One inherent advantage of the reactor is the spatial xenon stability, which allows the reactor to override xenon transients in order to follow load. This permits the BWRX-300 to daily load following over a large core power level range [37].

Refueling outages span 10–20 days and the fuel cycle lasts for 12 to 24 months depending on the customer’s needs. For the 12-month and the 24-month cycle there is a need for replacement of 32 and 72 bundles, respectively [34].

Τhe relatively low peak ground acceleration of 0.3 g before the Safe Shutdown Event (SSE) of the reactor, enables deployment in earthquake prone countries [37]. Although the precedent characteristic is present in many reactors, BWRX-300 has a higher sensitivity to earthquakes.

The ability to disable the reactor during, even small, earthquake events is a matter of great importance for Greece, due to the considerable seismicity. Furthermore, the broad load-following range of 50–100% of its nominal capacity and the simplicity of reactivity control due to xenon stability, provides improved control of this SMR in combined operation with RES. Lastly, the great safety features of BWRX-300, with five defense lines render this reactor as one of the most riskless commercially available reactors [34].

2.1.4. ARC-100

ARC-100 is produced by ARC Clean Energy (Saint John, NB, Canada). It exhibits the advanced technology of Sodium Cooled Fast Reactors (SFR) with nominal capacity of 100 MWe. The metal fuel is based on enriched uranium [34]. The high boiling point of liquid sodium (i.e., 883 °C) allows the core outlet temperature to reach 510 °C. The coolant also allows the SMR to operate at higher temperatures and lower pressures and maintain high thermal efficiency.

The heat transport system consists of primary heat and intermediate heat transport systems. The intermediate heat system leads the circulated sodium to the steam generator. The steam generator is a vertical oriented heat exchanger between sodium and water, and it is equipped with isolation valves that close on demand to isolate it from its feedwater system.

For installation in Greece, the main advantages of ARC-100 include (a) the affordability of its structure, (b) the use of fast neutrons, which allows the reactor to reburn its recycled burned fuel and achieve a closed fuel cycle, (c) the 20-years refueling period, (d) the safety of the fuel assembly and (e) the use of passive safety systems [38].

2.2. Methodological Approach

This study was conducted in two phases: First, four simulation scenarios of the Greek wholesale electricity market, which are solely differentiated in terms of the penetration level of SMR units in the Greek power system, were executed for the period 2032–2051. In each scenario, a sequential simulation of the three distinct market segments (DAM, ISP, RTBEM) was performed on a day-by-day basis for the whole study horizon. This simulation analysis provided the long-term forecasting of key market indicators, such as energy generation mix, gas consumption volumes, volumes of CO₂ emissions, market clearing prices, market revenues/costs arising from the participation of SMR units in the market, etc. Afterwards, analytical calculations based on these market indicators resulted in (a) robust estimations of the end-consumers’ total electricity supply cost and (b) the investigation of the long-term economic viability of the candidate SMR units on the basis of their operating financial results.

Four SMR penetration scenarios have been formulated, from zero penetration (Scen. 1, Baseline Scenario) to 3088 MW (Scen.4, High SMR). More details on the configuration of the four simulation scenarios are presented in

Table 2. Simulation scenarios matrix.

SMR Type	Scenario Name/SMR Installed Capacity [MW]— Number of SMR Units
	Scen. 1 No SMR (0 MW)	Scen. 2 Low SMR (648 MW)	Scen. 3 Medium SMR (1564 MW)	Scen. 4 High SMR (3088 MW)
NUWARD (340 MW)	x	✓ (1)	✓ (1)	✓ (1)
VOYGR (4/12 × 77 MW)	x	✓ (1: 4 × 77)	✓ (1: 12 × 77)	✓ (2: 12 × 77)
BWRX-300 (300 MW)	x	x	✓ (1)	✓ (2)
ARC-100 (100 MW)	x	x	x	✓ (3)

. The high-level methodological approach followed in this study is illustrated in Figure 1.

It is noted that most input data of the market simulation software and the associated optimization models, including the evolution of system load demand, RES and BESS installed capacity, gas supply prices and CO₂ emissions prices, have been considered deterministically known or, in other words, a single scenario for the evolution of each input parameter over the long-term horizon was formulated. This is because this work focuses on investigating the impact of integrating the emerging SMR generation technology in modern power systems and wholesale electricity markets under different penetration levels rather than conducting a scenario-based analysis on differentiated electricity market and power system operation conditions. In fact, the primary goal of this work is to provide a quantitative view of the tangible benefits that these units may bring to the power system operation and, in turn, the society welfare as well as to investigate the long-term economic viability of such innovative power generation projects from the investor’s perspective based on rational hypotheses on the evolution of critical market parameters, which are further presented and discussed in Section 3.2. Obviously, the formulation and execution of a larger set of market simulation scenarios based on multiple sets of input data parameters would provide a more thorough perspective on the attained study results, yet at the expense of significantly increased computational requirements and burden. In this study uncertainty is addressed in the modeling of RES generation (as further explained in Section 3.2.4) and the investment and operating cost data of a candidate type of SMR unit (as further discussed in Section 3.3.4.ii).

In the next subsection, a short, yet informative, high-level description of the integrated simulation software tool is provided. A detailed presentation of the key features of each Greek wholesale electricity market segment, along with the main characteristics of each of the constituent modules and optimization models of the deployed software tool can be found in [39].

2.3. Software Tool

The integrated electricity market simulation software “Long-Term Scheduling extended” (LTSx) was employed for the execution of the four simulation scenarios. LTSx was created by the Power Systems Lab of Aristotle University of Thessaloniki, Thessaloniki, Greece, and is based on the sequential solution of the following four models to provide a realistic mid-/long-term simulation of the Greek wholesale electricity market:

• Hydrothermal Scheduling (HS),
• Day-Ahead Market (DAM),
• Integrated Scheduling Process (ISP), and
• Real-Time Balancing Energy Market (RTBEM).

These core models are complex mathematical optimization models that consider a large set of input data, indicatively comprising the following unit and system data:

i.

Unit technical data: e.g., technical maximum power output (in MW), technical minimum power output (in MW), ramp-rates (in MW/min), minimum up/down times (in hours/minutes), unit availabilities, etc.,

ii.

Unit economic data: e.g., energy offers of the market participants (thermal units, hydro units, RES, imports, exports, storage units, etc.), reserve offers of the generating units, variable fuel cost, CO₂ emissions cost, variable operating and maintenance cost, etc.

iii.

System data: e.g., system load demand, system reserve requirements, etc.

In general, each optimization model aims at the maximization of the social welfare subject to tens of unit and system operating constraints that model accurately the actual operation of the wholesale electricity market and the power system. In this framework, the detailed operation (commitment and dispatch) of SMR units is modeled like any other conventional generating unit, including gas-fired units, hydro units, etc., and is governed by the aforementioned sets of input data and operating constraints. The optimal hourly/sub-hourly operating schedule of each resource throughout the simulation period, which in fact expresses the set of optimal decisions on which available resources (e.g., generating units, imports, etc.) to utilize in order to serve the system load demand (and system reserve requirements, when applicable) in a specific time step are determined by the solution of the said core optimization models that integrate multiple input technical and economic data alongside unit and system operating constraints within the overarching optimization framework.

The structure and functionalities of all these optimization models fully comply with the existing regulatory framework governing the wholesale electricity market in Greece, as outlined in the Day-Ahead Market & Intra-Day Market Trading Rulebook [40] and the Balancing Market Rulebook [41], as well as in the associated technical decisions issued by the Greek Market Operator (HEnEx) [42] and the Greek TSO (ADMIE) [43]. All aforementioned core optimization models were developed in the Generic Algebraic Modeling System (GAMS) and solved using the CPLEX solver [44].

Figure 2 presents a high-level overview of the key features and data requirements of each LTSx sub-model as well as the underlying dependence/correlation between the sequentially executed market segments (i.e., input/output data transfer). The hydrothermal scheduling model runs for each individual year of the study period and allocates optimally the mandatory hydro injections on an hourly basis throughout the year. Afterwards, the DAM, ISP and RTBEM models run sequentially for each day of the simulation horizon, paying attention to the proper coordination regarding the necessary data transfer between successive dispatch days. Using parallel processing that allows for the simultaneous execution of multiple simulation years on a high-performance Intel^® Core^TM i9-14900 2.00 GHz processor with 64 GB RAM running 64-bit Windows drastically reduces the required computational time and burden.

The adoption of LTSx software that performs chronological simulation and, in fact, imitates the detailed functionalities of the official wholesale market optimization solvers of the competent Greek electricity market and power system operation institutions (Market/System Operators) is highly advantageous especially for a long-term study, since it provides more accurate and detailed results regarding various critical market indicators (i.e., market clearing prices, energy balances, gas consumption and CO₂ volumes, revenues/costs of market participants, etc.) in finest time resolution.

It is highlighted that LTSx is a proprietary integrated electricity market simulation software that is privately owned, controlled, and distributed to interested parties under specific licensing terms. Nearly all vertically integrated electricity market participants in Greece have acquired end-user licenses and employ this software tool for a wide range of scenario-based simulation analyses, including the optimal management of water stored in hydro reservoirs, optimal management of gas supply and CO₂ emission rights, optimal maintenance scheduling, long-term planning analyses annual budget analyses, etc. This proves the trustworthiness and effectiveness of LTSx in addressing real-life electricity market issues.

3. Case Study

3.1. Scenarios Configuration

For the purposes of this study, four (4) simulation scenarios were formulated, which are only differentiated in terms of the number and type of SMR units and, in turn, the total SMR installed capacity considered. For the sake of comparison, all other simulation assumptions regarding various power system and market parameters, such as system load demand, RES and BESS penetration, commodity (gas and CO₂) prices, availability of thermal and hydro units, availability of cross-border interconnection lines, etc. are identical in all scenarios. The corresponding scenario matrix is shown in Table 2.

3.2. Simulation Assumptions

In this Section, the main assumptions regarding the techno-economic data of all SMR unit types as well as key parameters for the detailed simulation of the Greek wholesale market simulation are presented.

3.2.1. SMR Units’ Data

Table 3. Summary of SMR units’ main techno-economic data.

SMR Type	Pmax [MW]	Pmin [MW]	Ramp-Rate [MW/min]	CO2 Rate [tn/MWh]	Fuel Supply Cost [€/kg]	Fuel LHV [GJ/kgr]	Fuel Cycle [Months]	Thermal Efficiency [%]	Fuel Variable Cost [€/MWhe]
NUWARD	340	64	17.0	0.0120	830.5	3400	24	32.0	2.75
VOYGR 4 × 77	308	154	15.4	0.0109			18	36.0	2.44
VOYGR 12 × 77	924	462	46.2	0.0163			18	36.0	2.44
BWRX-300	300	135	15.0	0.0326			12	35.0	2.51
ARC-100	100	50	5.0	0.0102	2670	9680	240	40.0	2.48

presents a summary of the main techno-economic data of the five SMR units considered in this study. Detailed cost data, including the initial investment cost, the fixed and variable operation and maintenance costs as well as other financial parameters associated with the economic valuation analysis are presented in Section 3.3.4.

Nuclear energy is in no way “emission free”, even though it is superior than coal, oil, and natural gas in terms of emissions related to electricity generation. The mean value of emissions over the lifetime of a nuclear reactor is ~66 g CO₂/kWh [45], due to reliance on existing fossil-fuel infrastructure for plant construction, decommissioning, and fuel processing along with the energy consumption for uranium mining and enrichment. The operation of the reactor emits ~12 g CO₂/kWh [45,46]. Thus, a very low CO₂ emissions rate is considered for the operation of all SMR units, which is associated with the energy needed for maintenance, cooling and fuel cycles, backup generators, and during outages and shutdowns [45].

3.2.2. System Load Demand

The total electricity consumption and peak load demand of the Greek interconnected power system for the year 2023 were equal to 49.2 TWh and 10,385 MW, respectively [47]. Both indicators are expected to increase significantly in the forthcoming years, on the one hand owing to the scheduled interconnections of all Greek insular power systems with the mainland (i.e., Crete in mid-2025, West Cyclades in late 2025, Dodecanese in 2028 and North Aegean islands in 2029) and on the other hand owing to the anticipated positive mid-/long-term prospects of the Greek economy.

A single scenario was formulated as regards the forecast of the Greek interconnected power system total electricity consumption (in TWh) and peak load (in MW) for the years 2032–2051, based on relevant forecasts that are included in the latest Ten-Year Network Development Plan 2025–2034 of the Greek TSO (ADMIE) [48]. The long-term evolution of both total electricity consumption (TWh) and peak load demand (MW) has been estimated based on linear extrapolation and is shown in Figure 3.

3.2.3. Domestic Generation Capacity

The Greek electricity sector is expected to be heavily transformed in the forthcoming period including, among others, the permanent decommissioning of the entire lignite units’ fleet by the end of 2028 (lignite phase-out), the aggressively increasing RES penetration, the construction of new flexible and very efficient gas-fired units along with the gradual retirement of old and inefficient gas-fired power plants, which are complemented by the progressive introduction of battery energy storage systems and new pumped-storage plants. Figure 4 illustrates the evolution of the domestic generation capacity per technology (excluding the potential SMR units) as considered in this study, which is mainly based on the core provisions of the revised NECP.

Regarding RES generation, the key advantages of PV generation (i.e., low cost, versatile sizes, easy installation, light maintenance) renders it as the dominant RES technology in the future, whereas offshore wind plants are expected to be introduced by the beginning of next decade and contribute substantially towards the green energy transition. On the contrary, hydro generation seems already saturated, since potential sites that could be used for developing new large hydro projects have already been reserved for the development of new pumped-storage plants. The latter are deemed necessary along with other storage technologies, such as battery energy storage systems, to cope with the increasing system flexibility and ancillary services provision needs that stem from the integration of very high shares of RES generation in the power system.

3.2.4. Modeling of RES Generation

Regarding RES electricity generation modeling, we address RES generation uncertainty by modeling two types of stochasticity:

i.

Annual RES generation uncertainty: In order to model the fact that RES generation profiles may change from year to year due to differentiated climatic conditions, actual hourly electricity generation profiles of wind and PV units of the Greek power system from a past four-year period were adopted, expressed in injected MWh/installed MW or, equivalently, in p.u. For each individual RES technology, these profiles are rolled every four years in hourly time step covering the entire study horizon (2032–2051) and the resulted RES generation data are used in the DAM solution framework. This is similar to the modeling technique adopted by ENTSO-E to incorporate climatic years in its European Resource Adequacy Assessment (ERAA) Study [49].

ii.

Integration of short-term RES generation forecasting error: Time-series of random system imbalances in appropriate time resolution for the scheduling phase (30-min for ISP) and the dispatch phase (15-min for RTBEM) based on the statistical properties of historical system imbalances timeseries (empirical cumulative distribution function of the associated load and RES short-term forecasting errors) were created by the software tool by applying the methodology described in [50]. A smoothing function was then applied on the derived 30-min/15-min imbalances in order to perfectly simulate the system imbalances that appear during the actual power system operation, and which follow a smooth variation profile without oscillating between negative and positive values in consecutive time intervals. This modeling technique incorporates appropriate short-term RES generation forecasting errors to be addressed in the relevant market segments (ISP, RTBEM) and provides a realistic integration of the short-term RES generation uncertainty.

3.2.5. Commodities (Gas and CO₂) Prices

Natural gas and ETS (CO₂) prices have historically exhibited significant volatility across various commodities exchanges. Both are largely dependent on a variety of international factors, including supply-demand balance, geopolitical tensions, market dynamics, infrastructure and logistics, energy transition policies, etc. Therefore, the long-term forecast of their price evolution is rather uncertain and falls outside the scope of this study. For the purpose of this work, relevant simplified projections based on recent historical data complemented with the authors’ experience have been made for their long-term evolution.

For gas, a constant annual gas supply price of 35 €/ΜWh HHV has been considered for the entire study horizon. However, instead of flat annual gas supply price forecasts (i.e., same gas price for all months of each year), we adopted appropriate monthly price forecasts using publicly available historical data [51], in order to capture the monthly variation of gas supply prices during the course of any calendar year (i.e., higher prices are usually observed during winter months and lower prices during summer months).

Regarding CO₂, annual ETS prices have been considered, which are assumed to increase from 85.9 €/tn CO₂ in 2032 (settlement price of the EEX EUA future for December 2032 on 6 March 2025 [52]) to 180 €/tn CO₂ in 2051, to comply with the known EU goals for decarbonizing the electricity sector.

3.2.6. Cross-Border Interconnections

Besides the cross-border interconnection lines that currently interconnect Greece with its neighboring countries, the following new cross-border lines have been considered [48]:

• a new 1000-MW cross-border line interconnecting Greece and Cyprus (also called “Great Sea Interconnector”), which is considered to become commercially available in January 2030,
• a new 200-MW cross-border line interconnecting Greece and Albania, which is considered to become commercially available in January 2032,
• a new 600-MW cross-border line interconnecting Greece and Turkey, which is considered to become commercially available in January 2032,
• a new 1000-MW (DC) cross-border line interconnecting Greece and Italy, which is considered to become commercially available in January 2035.

Figure 5 shows that Greece has been a net electricity importer from neighboring countries during the recent past (2014–2023).

3.3. Simulation Results

In this paragraph, the main results of the Greek wholesale electricity market simulation for the period 2032–2051 are analytically presented and discussed.

3.3.1. Energy Generation Mix

In each simulation scenario, the evolution of the energy generation mix over the years of the study period is the net result of the co-existence of various factors, such as the availability of gas-fired and SMR generating units, RES and BESS installed capacity, availability of pumped-storage units, etc. along with the merit order of the domestic thermal power system.

For comparison purposes, Figure 6 and Figure 7 illustrate the annual energy generation mix for the two extreme scenarios, namely Scen.1 (No SMR) and Scen.4 (High SMR). In Scen.1, the aggressive penetration of new RES plants leads progressively to very high RES shares that naturally restrict the electricity production of all other resources, including the production of the efficient new gas-fired units whose production decreases over the study period.

Similarly to gas units’ production, since Greece is expected to gradually suffer from severe oversupply conditions, annual volumes of net imports also follow a decreasing trend over the years (or, equivalently, annual volumes of net exports continuously increase), since they are highly affected by the large and increasing volumes of renewable generation. In this context, the higher RES generation calls for more frequent and intense activation of fast-start and fast-ramping storage entities such as BESS and PSPs to counterbalance RES intermittent generation (besides the contribution already provided by gas-fired units), since they take advantage of the higher volatility that both net load demand (system load—RES generation) and, subsequently, market clearing prices present during the course of the day over the years. However, the potential introduction of SMR units is going to partially alter this pattern: the higher the SMR installed capacity and, in turn, the annual SMR units’ generation, the lower the respective annual gas-fired units’ generation and the higher the volumes of net exports. This is clearly shown in Figure 7, which illustrates the annual energy generation mix for the High SMR scenario (Scen.4). In this case, SMR units take advantage of their very low variable cost (15–30 €/ΜWh) and operate almost at baseload for most of the time. This leads to substitution of the high-cost gas-fired generation as well as to reduction of the market clearing prices and, in turn, notable increase of the cross-border export volumes.

The interplay between SMR and gas-fired units for all simulation scenarios is more clearly presented in Figure 8 and Figure 9. In all scenarios, SMR units present a rather stable annual generation profile under high annual capacity factors (70–75%), which stems from the fact that they are prioritized in the merit order against most available resources, such as gas-fired units and net imports. On the other hand, gas-fired units face the risk of being pushed out of the market, especially in the case of high SMR penetration.

3.3.2. NG Consumption and CO₂ Emissions

The volumes of natural gas consumption are directly related to the volumes of electricity generation by gas-fired thermal generating units. As expected, the availability of SMR units is going to contribute decisively towards reducing the required volumes of gas consumption in all scenarios which, in turn, mitigates the dependence of Greece on gas imports. Figure 10 illustrates the average annual natural gas consumption (in billion Nm³ or bcm) for all scenarios examined. In quantitative terms, the reduction of total gas consumption is directly dependent on the assumed SMR installed capacity and ranges from 0.5 bcm/y (−21%, Low SMR) to 1.6 bcm/y (−62%, High SMR). Equivalently, gas consumption volumes decrease (on average) from 0.05 bcm to 0.08 bcm for every 100 MW of new SMR installed capacity added to the power system.

Similarly to gas consumption, given that SMR technology is characterized by nearly zero CO₂ emissions (see Table 3) in contrast to gas-fired units whose CO₂ emissions rate lie in the range of 0.33–0.42 tn/MWh, a notable decrease of annual CO₂ emissions from 1 million tn CO₂/y (−20%, Low SMR) to 2.6 million tn CO₂/y (−52%, High SMR) can be obtained in presence of SMR units (see Figure 11). Equivalently, CO₂ emissions decrease (on average) from 86,000 tn CO₂ to 159,000 tn CO₂ for every 100 MW of new SMR installed capacity added to the power system.

In cost terms, the penetration of SMR units in the Greek energy generation mix and the associated substitution of gas-fired generation can lead to notable annual cost savings originating from both the reduced CO₂ emission allowances and the reduced gas imports. Figure 12 illustrates that the combined NG and CO₂ cost savings can climb from 356 million €/y (Low SMR) to 1 billion €/y (High SMR), (equivalently, from 32 million €/y to 55 million €/y for every 100 MW of new SMR installed capacity), which also indirectly affects the end-consumers’ electricity cost, as analyzed in the following paragraph.

3.3.3. End-Consumers’ Electricity Cost

The electricity cost for end-users is closely linked to the expenses incurred by Retailers in meeting the electricity procurement requirements of their customer portfolios. Although Retailers may utilize a mix of sources—such as bilateral agreements, imports, forward contracts, or purchases from the Day-Ahead Market (DAM) and/or the Intra-Day Market—these transactions are generally executed at prices that align with or closely follow the expected DAM price. For the purpose of this analysis, it is assumed that Retailers fulfill their entire portfolio demand exclusively through purchases settled at the forecasted hourly DAM price.

In addition to DAM procurement costs, Retailers in Greece are subject to supplementary charges imposed by the Transmission System Operator (TSO) through Uplift Accounts (UAs). These charges include: UA-1, covering transmission system losses; UA-2, related to reserve provision costs; and UA-3, which ensures the financial neutrality of the balancing market. UA-3 allocates any residual balances after calculating the debits and credits associated with activated balancing energy, non-balancing activations, and the Imbalance Settlement for Balance Responsible Parties (BRPs). In this study, both the DAM procurement costs and UA charges are determined using high-resolution wholesale market simulation results (hourly or 15-min intervals) across all four simulated scenarios.

Figure 13 illustrates the evolution of the average annual DAM clearing prices for the entire study horizon for all simulation scenarios. First, it is observed that the low variable cost of SMR units along with their high capacity factors (see Figure 8 and Figure 9) leads to lower DAM prices as SMR units capacity increases (“merit order” effect). In quantitative terms, the annual DAM clearing prices decrease (on average) from 3.5 €/MWh (−3.3%) to 9.9 €/MWh (−9.5%) and down to 26.1 €/MWh (−25%) for the Low, Medium and High SMR scenarios, respectively, as compared to the Baseline Scenario (Scen. 1, No SMR).

Although the SMR penetration level is the determinant factor that defines DAM prices, for each simulation scenario, DAM prices are also highly dependent on the main scenario assumptions that mainly affect the gas-fired units’ variable costs, namely the gas and CO₂ prices, given that CCGT units are usually the price-makers during all years. In this context, the constant gas prices in combination with the increasing CO₂ prices lead to moderate increase of the gas-fired units’ variable cost over the years, which, in general, offsets the downward effect that the aggressively increasing RES generation has on the DAM clearing prices, thus resulting in increasing annual average DAM clearing price trajectories.

In the above context, the operation of SMR units is expected to allow for notable electricity procurement cost savings for all Retailers on an annual basis, ranging from 202 million €/y (2.5%) to 667 million €/y (8.4%) and up to 1.68 billion €/y (21%) for the Low, Medium and High SMR scenarios, respectively, as compared to the Baseline Scenario (Scen. 1, No SMR) (see Figure 14). In other words, the average annual cost savings that can be obtained for all Retailers for every 100 MW of new SMR capacity are estimated from 31.3 up to 54.4 million € per annum. Obviously, these cost savings are expected to be transferred from Retailers to end-consumers, thus allowing for a notable reduction of the associated end-consumers’ electricity cost from 3.1 €/ΜWh up to 25.3 €/ΜWh for the aforementioned SMR penetration scenarios.

3.3.4. Economic Valuation Analysis

In this section, the economic valuation analysis of the candidate SMR units is presented and discussed. For the sake of simplicity, the economic valuation is performed indicatively for the SMR unit NUWARD (340 MW). However, similar results can be obtained for any SMR unit used in this study. The economic valuation has been performed on the basis of the participation of the said SMR unit in the various wholesale market segments (DAM, ISP, RTBEM). For this purpose, in addition to relevant cost and typical financial data associated with the project construction and operation (e.g., total investment cost, fixed operating costs, funding parameters, etc.), analytical simulation results regarding the said SMR’s market revenues and operating costs from the simulated scenarios for the period 2032–2051 have been used. It is clarified that additional annual revenue streams (in €/y) that may originate from the participation of this SMR unit in a possible “out-of-the-market” financial support scheme, such as a long-term Capacity Remuneration Mechanism (CRM), are neglected in the present economic valuation analysis. The pure operating financial results that are expected to arise from the participation of this SMR unit in the Greek wholesale electricity market are analyzed to define standard project valuation indicators, such as the Project Internal Rate of Return (Project IRR) and Equity IRR.

i.

Investment and O&M cost data

Both the investment cost (CAPEX) and operation & maintenance (O&M) cost for SMR technology are currently highly uncertain. NREL in its 2024 annual technology baseline provides relevant cost projections from 2030 onwards based on an extended compilation of historical and more recent cost estimates for various advanced nuclear energy technologies along with historical U.S. costs for nuclear plant construction [53]. The cost ranges provided are not for so-called “first-of-a-kind” but rather for “next commercial offerings”. Three distinct cost evolution scenarios are available for both CAPEX and Fixed O&M costs, namely conservative (high cost), moderate (medium cost) and advanced (low cost) scenario. In order to investigate the impact that the level of these cost items will have on the economic valuation indicators of the said SMR unit, a relevant sensitivity analysis has been conducted.

Regarding CAPEX, cost projections beyond 2030 are based primarily on assumed learning rates for nuclear reactors. A compilation of a broad base of references on nuclear reactor learning rates was made, including a mix of historically observed costs and detailed bottom-up projections of cost evolutions [54]. Following the said NREL cost projections, three different CAPEX values for the year 2031 have been considered in this study, namely 5900 $/kW (advanced scenario), 9300 $/kW (moderate scenario) and 12,500 $/kW (conservative scenario) [53].

Regarding O&M costs, these are built on a range of observed costs and do not account for potential technological changes that could lead to future decreases even for the advanced scenario [53]. The variable non-fuel O&M costs include the power-dependent consumables (and are considered equal to 2.6 $/MWh in all scenarios), whereas the fixed O&M costs include associated expenses for fixed maintenance expenses, inspections, operational staff, indirect support and management staff, annualized decommissioning payments and property taxes. Following the aforementioned NREL cost projections, in this study three different (yet constant over the whole study horizon) Fixed O&M values have been considered, namely 118 $/kW-y (advanced scenario), 136 $/kW-y (moderate scenario) and 216 $/kW-y (conservative scenario) [53].

Besides the SMR unit-wise CAPEX and O&M cost data, the relevant economic valuation analysis has been made on the basis of the following core assumptions:

–

The economic valuation period is equal to 20 years (2032–2051).

–

A salvage value equal to 30% of the initial CAPEX is considered in the last year of the project economic valuation to model the remaining value of the SMR unit beyond the 20-year study period, since the average useful lifespan of a typical nuclear unit exceeds 50–60 years.

–

A debt/equity ratio equal to 80%/20% has been considered for project financing. Following current conditions for energy-related projects financing, the cost of equity is considered equal to 10.0% and the cost of debt (interest rate) is considered equal to 5.0%.

–

The corporate tax rate is taken equal to 22% for the whole valuation period.

Based on all above indicators, the Weighted Average Cost of Capital (WACC) is calculated equal to 5.12%.

ii.

Economic valuation results

It is expected that SMR units will be able to fully exploit their operating advantages (low variable cost, high flexibility) and obtain positive operating financial results from their direct participation in all wholesale market segments. Figure 15 illustrates the average market revenues, operating costs and gross profits (=market revenues − operating costs) for the 340-MW NUWARD unit for the three different SMR penetration levels over the entire study period. It is clearly shown that the market revenues of SMR units are heavily affected by the assumed SMR penetration level: the higher the SMR penetration level, the higher the cannibalization of these units, which, in turn, leads to notably lower market revenues and pushes downwards the gross operating profit of these units.

However, it is expected that the 340-MW NUWARD will be able to obtain a positive economic valuation (It is considered that the economic valuation of the project is positive when the respective project IRR is higher than the respective WACC adopted in this study (5.12%) or, equivalently, the respective project Net Present Value (NPV) is positive.) in all scenarios assuming low or medium CAPEX under moderate Fixed O&M cost assumption, irrespective of the SMR penetration level, as shown in Figure 16. On the contrary, under high CAPEX, the valuation results deteriorate significantly and render this project loss-making in the long-term.

In order to assess and quantify the impact that both the CAPEX and the Fixed O&M values have on the said project valuation, a relevant sensitivity analysis has been conducted, and the results are shown in

Table 4. Economic valuation results for the 340-MW NUWARD—Sensitivity analysis.

CAPEX [$/kW]	Fixed O&M [$/kW-y]	Project IRR [%]			Equity IRR [%]
		Low SMR	Medium SMR	High SMR	Low SMR	Medium SMR	High SMR
5900	118	13.0	12.3	9.7	30.2	26.9	18.5
	136	12.7	12.0	9.4	29.2	26.0	17.7
	216	11.5	10.9	8.2	24.8	22.0	14.0
9300	118	7.7	7.3	5.5	12.9	11.5	6.6
	136	7.5	7.1	5.3	12.4	11.0	6.1
	216	6.7	6.3	4.3	10.1	8.8	4.1
12,500	118	5.2	4.9	3.2	5.9	5.2	1.7
	136	5.0	4.7	3.0	5.6	4.8	1.4
	216	4.3	4.0	2.1	4.0	3.3	0.0

.

In this Table, the Project IRR and Equity IRR are shown for all possible combinations of CAPEX and Fixed O&M costs scenarios assumed. Bold fonts indicate the cases that lead to positive valuation in terms of Project IRR. It is concluded that the said SMR unit will be able to obtain positive valuation for almost all scenarios assuming low or medium CAPEX, irrespective of the Fixed O&M cost and SMR penetration level considered. On the contrary, the high CAPEX is likely to discourage the investment on such projects.

Finally, a critical financial aspect that may pose severe difficulties in implementing such projects is the very high CAPEX needed in absolute terms (in $): For the three CAPEX scenarios examined in this analysis, the investment expenditure for the 340-MW NUWARD ranges from 2.0 to 4.25 billion $. This may render such projects questionable in terms of their bankability, especially as compared to other mature and competitive conventional and RES technologies, such as PV, wind or even gas-fired CCGT units, whose initial investment cost is currently less than one tenth of the estimated CAPEX of SMR units.

4. Conclusions and Future Research

This paper explored the long-term implications of integrating emerging Small Modular Reactor (SMR) units into the Greek power system, specifically focusing on key electricity market and power system operation indicators. A detailed chronological simulation of the Greek wholesale market has been performed for a future 20-year period (2032–2051) under four SMR penetration scenarios using a specialized integrated market simulation software.

From a system operation point of view, simulation results indicate that SMR units can be regarded as a viable and promising electricity generation option in the long-term. Specifically, the addition of up to ~3 GW of SMR capacity could potentially reduce carbon emissions by up to 2.6 million tn CO₂ per year, decrease gas imports dependence by up to 1.6 bcm per year, and also lower the overall end-consumers’ electricity cost by up to 25.3 €/ΜWh as compared to the baseline scenario without SMR units.

From the economic valuation point of view, it is expected that SMR units will be able to fully exploit their operating advantages, such as the low variable cost and high flexibility, and obtain positive financial results when participating directly in the various wholesale market segments. However, the higher the SMR penetration level, the higher the cannibalization of these units, which, in turn, leads to notably lower market revenues and pushes downwards their gross operating profits. A sensitivity analysis indicated that a typical 340-MW SMR unit will be able to obtain a clearly positive economic valuation for almost all scenarios assuming low or medium CAPEX irrespective of the SMR penetration level and without any “out-of-the-market” financial support scheme. However, high CAPEX can negatively impact valuation results, resulting in a project IRR lower than the WACC, which may cause the project to be marginally loss-making in the long term. Finally, the bankability of such projects remains questionable, since very high capital is initially required for their financing.

All in all, the present study was based on a long-term simulation analysis and provided a quantitative view of the tangible benefits that the SMR units may bring to the power system operation and, in turn, the society welfare. Although various operating and financial aspects were addressed under a realistic simulation modeling and economic valuation framework, competent energy market authorities, decision-makers or potential investors should conduct a more thorough investigation based on extensive scenario-based analyses to account not only for the long-term uncertainty of critical market and power system operation parameters such as commodity prices but also for risks associated with the investment decision, construction and long-term operation of such an emerging generation technology in a competitive electricity market framework.

Furthermore, while this analysis provides valuable insights into the multi-dimensional benefits of this new power generation technology and serves as a potential model for similar analyses in other regions, the quantitative results should be evaluated specifically for the mentioned power system. Direct comparisons with other similar studies may not be straightforward.

Our future work will focus on conducting a comparative simulation analysis to identify the implications that the construction and operation of novel SMR units against conventional large nuclear power plants may entail in modern power systems and wholesale electricity markets supplemented by a scenario-based analysis by developing and running multiple scenarios that reflect the evolution of various uncertain electricity market and power system operation parameters.