1. Introduction
The Paris Agreement ratified by the world community represents a commitment to work together to mitigate the human-induced greenhouse effect [
1]. To decarbonize the energy sector and expand renewable sources of power generation, the European Commission has launched a “European green deal” [
2]. At the national level, the Finnish government has committed to achieving carbon neutrality by 2035 [
3]. The widespread integration of intermittent power generation can lead to imbalances between electricity demand and supply, resulting in power shortages or surpluses that can cause fluctuations in grid frequency [
4]. For example, in Finland, wind power capacity increased by 76% from 2021 to 2022 to 5677 MW, while the average electricity consumption was 9360 MW [
5]. As a result, ancillary services are required to respond to an unanticipated deficiency or surplus in power production or consumption in a cost-effective and efficient manner [
6]. Recently, the provision of ancillary services from wind and nuclear power has been introduced in Finland. Loviisa nuclear power plant, for example, has joined the frequency containment reserve for disturbance (FCR-D) down-regulation market [
7,
8]. Balancing markets guarantee the availability of adequate reserve capacity to meet the necessary energy demand and maintain grid frequency stability [
9].
Power-to-heat (P2H) technologies, encompassing heat pumps (HPs), electric boilers, and combined heat and power (CHP) plants, can play a crucial role in enhancing the flexibility and grid support capabilities of the electrical power system [
10,
11,
12,
13,
14]. Terreros et al. [
15] explored the potential for the utilization of HPs in the Austrian electricity market as a solution to the stochasticity of renewable heat sources and the large number of unprofitable biomass boilers in rural district heating. Through participation in both the day-ahead and balancing markets, HPs could save energy costs, while simultaneously earning additional revenues. District heating networks (DHNs) possess substantial electrical capacities due to existing CHP plants and HPs [
16,
17]. Finland’s DH sector, which boasted a 50% market share of space heating in 2021 [
18], aims to decarbonize by integrating large-scale HPs and electric boilers, alongside biomass fuels [
19]. Boldrini et al. [
20] evaluated the technical potential of DHNs to contribute to frequency containment reserves (FCR), and automatic and manual frequency restoration reserves (aFRR and mFRR) markets, and estimated the potential at country and EU levels based on appropriate assumptions. A significant degree of flexibility can be provided by DHNs based on the findings of the study. Javanshir et al. [
21] conducted a literature and industry review and proposed the optimal operation of an electrified DHN to participate in day-ahead electricity and balancing markets for a hypothetical mid-sized city DHN, considering the technical requirements of providing a reserve in each market. The results indicated the economic benefits of providing balancing services from HPs in the aFRR market. According to Wang et al. [
22], CHP plants could provide flexibility to reduce wind power production curtailment and increase revenue through providing ancillary services. They compared the flexibility of different CHP types and operation modes. Haakana et al. [
23] proposed a methodology to optimize the operation of a CHP plant in various energy markets, with a focus on electricity reserve market opportunities. The literature discusses the benefits of DHN-connected P2H units for providing balancing services. However, some of the research gaps, to the best of the authors’ knowledge, remain understudied. The interaction between the operation of a reserve unit in a DHN and other production units that do not provide reserve capacity, is often neglected in the literature [
23].
Addressing the identified research gaps, this study investigates the economic feasibility of utilizing DHN-connected HPs and electric boilers to provide reserve capacities in various FCR balancing markets in Finland. The Helsinki metropolitan area’s DHN, encompassing the interconnected DHNs in Helsinki, Espoo, and Vantaa cities, was selected as the case study. This system produced approximately 11.1 TWh of DH for over one million people in 2022 [
18]. The case study was simulated and the operation in the day-ahead electricity market and FCR balancing markets was optimized for both 2019, as the base year (with regular electricity prices), and 2025, assuming the heat generation fleet of the case study aligned with the carbon neutrality plans of the Helsinki area municipalities. A 15 min time resolution was also incorporated in modeling the reserve provision. The overarching objective was to maximize the profitability of the operator in the aforementioned markets. With the electrification of DH systems in Finland, larger capacity HPs and electric boilers are becoming available, which could contribute to the balancing markets and generate additional revenue.
The structure of the paper is as follows. In the methods section,
Section 2.1. explains the optimal operation of the case study DHN in the day-ahead electricity market (without considering the reserve provision). In
Section 2.2, the studied balancing markets, their requirements, and the operation of the system in these markets, are explained. The configuration of the case study DHN is explained in
Section 2.3. The results of the simulations and the conclusions are placed in
Section 3 and
Section 4.
3. Results
The results of the simulations are presented in this section. First, the case study was calibrated against the actual fuel consumption of each DH system for the year 2019, as gathered from the annual reports, published by the case study’s operators [
19,
33,
34].
Table A2 in
Appendix A summarizes the numerical results of the validation.
Figure 9,
Figure 10 and
Figure 11 illustrate the unit-level results, encompassing the operational hours of each individual reserve unit in the day-ahead scheduling stage, the annual available capacity of each unit in FCR markets, and the annual profit generated by each unit from those markets, respectively. In contrast,
Figure 12 shows the city-level results for the Helsinki and Espoo DHNs.
Figure 9 and
Figure 10 show the relationship between the operation of a unit in the day-ahead stage and the availability of reserve capacity for that unit in FCR markets.
Figure 9 depicts the annual operational hours and annual full-load operation hours of the reserve units in the day-ahead stage for both 2019 and 2025. Notably, HPs are expected to operate more frequently in 2025 compared to 2019, driven by factors like higher fuel costs and reduced baseload CHP capacity. Electric boilers have recently gained traction in DH systems across Nordic countries, primarily utilized during periods of extremely low or even negative electricity prices. In the simulation, the electric boiler was only engaged for a very limited number of hours in 2025, operating at full capacity throughout.
Figure 10 illustrates the cumulative available reserve capacity of each reserve unit throughout the year, calculated by multiplying the unit’s available reserve capacity (calculated with Equations (1)–(3)) by the total number of hours it is available for operation in the day-ahead scheduling stage. As discussed in
Section 2.2, when a reserve unit operates at maximum capacity in the day-ahead stage, it is not available for FCR-N or FCR-D down-regulation markets. Therefore, units with a higher ratio of full-load operating hours to total operating hours in the day-ahead stage, such as Katri Vala, Esplanadi, and Suomenoja HPs in 2025 (see
Figure 9b), exhibit lower available reserve capacity for FCR-N or FCR-D down-regulation markets (see
Figure 10a,c). The limited availability of reserve capacity from Vuosaari, Salmisaari, and Vermo HPs in 2025 for FCR-N and FCR-D down-regulation markets stems from their near-constant operation at full capacity in the day-ahead stage (see
Figure 9b).
Figure 11 presents the cumulative annual net profit earned by each reserve unit, calculated as the sum of the cumulative annual capacity fees (derived from Equations (8)–(10)) and energy fees (derived from Equation (11)), from various FCR markets in both 2019 and 2025. Due to the projected decrease in the HPs’ total available reserve capacities for FCR-N and FCR-D down-regulation markets in 2025 (as indicated in
Figure 10), revenues from these markets are also expected to decline, as depicted in
Figure 11a,c. On the contrary, revenue from FCR-D up-regulation is anticipated to increase in 2025. The highest revenue is observed for the electric boiler in the FCR-D down-regulation market.
Figure 12 shows the cumulative annual net profit for each city-level DH system and the overall case study DH system, encompassing Espoo, Helsinki, and Vantaa cities. In the context of 2019, the Helsinki DH garnered significantly higher profits from the FCR-N market compared to the Espoo DH. However, with the heat generation fleet of 2025, Helsinki DH’s profit from this market would be lower than Espoo DH’s, despite the increased capacities of HPs within the Helsinki DH.
Figure 9 and
Figure 10a indicate that the Katri Vala and Esplanadi HPs within the Helsinki DH would possess considerably lower reserve capacities in the FCR-N in 2025 compared to the Suomenoja HP, which operates in the Espoo DH.
Figure 9b depicts how the shutting down of substantial CHP capacities in the Helsinki DH system would result in augmented full-load operation hours for the HPs with day-ahead schedules. As a consequence of the increased operating hours of HPs in the day-ahead scheduling in 2025, as illustrated in
Figure 9, both cities can earn more from the FCR-D up-regulation market. The electric boiler could deliver notable profits from the FCR-D down-regulation market for the Helsinki DH in 2025.
Given the intricate and uncertain nature of future energy market developments, it is crucial to pinpoint the primary factors influencing the modeling outcomes. Among these factors, electricity prices and fuel costs hold significant sway, with increasing EU ETS prices particularly impacting fuel costs for power plant operators [
28]. To address these complexities, a sensitivity analysis was conducted, varying the electricity prices and EU ETS prices for the 2025 simulations.
Figure 13 presents the outcomes for the case study DHN, with the 2025 generation fleet employing the assumed historical EU ETS prices of 2022, with an annual average of 80 EUR/tonCO
2, as well as the projected prices for 2025, with an annual average of 110 EUR/tonCO
2 [
32].
Figure 13a highlights the share of heat generated annually by HPs within each city DHN relative to their respective annual heat demand. As EU ETS prices escalate, fuel costs surge, leading to a decline in CHP production and a corresponding rise in HP production.
Figure 13b–d depicts the cumulative annual net profit for each FCR market based on various EU ETS prices. With higher EU ETS prices, revenues from all markets, except for the FCR-D down-regulation market, would increase. The reduced reserve capacity available in the FCR-D down-regulation market, due to the higher operating hours of the electric boiler in the day-ahead scheduling system, contributes to the lower achievable total net profit under higher EU ETS prices [
32]. As the operation hours of CHPs decrease in response to higher EU ETS prices, HPs must operate more extensively to meet the heat demand, thereby expanding their capacity for the FCR-D up-regulation market, as demonstrated in
Figure 13c.
Figure 14 presents the simulation outcomes for the 2025 generation fleet under varying electricity prices. It is crucial to emphasize that the up-regulation and down-regulation prices are cleared in accordance with the day-ahead prices, as depicted in
Table 1. Hence, altering the day-ahead prices in the sensitivity analysis leads to simultaneous modifications in the up-regulation and down-regulation prices.
Figure 14a illustrates the proportion of HP-generated heat within each city’s DHN relative to its annual heat demand, along with the annual average of the spot prices on the right y-axis, while
Figure 14b-d showcase the cumulative annual net profit for each city’s DH system and the entire network derived from the FCR-N, FCR-D up-regulation, and FCR-D down-regulation markets, respectively. Rising spot prices translate into higher revenue generated from electricity sales by CHP units in the day-ahead market. Consequently, CHP operation rates increase, while HPs experience reduced hours of operation in the day-ahead scheduling, as illustrated in
Figure 14a.
As there are no HPs or electric boilers in the Vantaa DHN, increasing electricity prices have no impact on CHP operation, and Vantaa’s CHP units are not depicted in the figure. The reduced operation of HPs and the electric boiler in the day-ahead scheduling with increasing electricity prices results in higher income from FCR-N and FCR-D down-regulation markets. Conversely, FCR-D up-regulation would generate lower profits in higher electricity prices.
4. Conclusions
In their pursuit of carbon neutrality by 2035, district heating network (DHN) operators in Finland aim to decarbonize their systems by retiring fossil-fueled combined heat and power plants (CHPs) and investing in large-scale heat pumps (HPs) and electric boilers (electrification approach). The decommissioning of CHP units, however, eliminates the benefits of simultaneous electricity and heat production, a feature particularly valuable during periods of elevated electricity market prices and in the cold Nordic climate. This necessitates exploration of new revenue streams for electrified heat generation units through alternative markets, such as balancing markets. Additionally, the growing integration of wind power generation into the Finnish electricity grid, with installed capacity surpassing 60% of average electricity demand in 2022 [
35], underscores the demand for alternative balancing providers. This study delved into the techno-economic analysis and economic feasibility of utilizing HPs and electric boilers operating within a large and electrified DHN to provide ancillary balancing services to the Finnish electrical power system. Simulations were conducted using the interconnected DHNs of Helsinki, Espoo, and Vantaa cities, serving 1.1 million people in the capital region of Finland. The key findings from this study are summarized below:
Among the markets studied, the FCR-D up-regulation market is expected to be the most lucrative balancing market for large HPs. In total, HPs could achieve achievable net profits of EUR 285,000 and EUR 940,000 in the analyzed cases of 2019 and 2025 DHNs, respectively, from this market. In both cases examined, the FCR-N market was the least profitable for HPs and electric boilers.
Electric boilers, which have recently been introduced into Finnish DH systems, are primarily employed during periods of low day-ahead electricity prices. While the electric boiler in the case study DHN would be in operation for merely 1% of hours in 2025 in the day-ahead scheduling, it could generate a net profit of approximately EUR 2.2 million for the Helsinki DH system from the FCR-D down-regulation market, exhibiting the most substantial individual benefits among the ancillary services markets analyzed.
Higher CO2 emission allowance prices (EU ETS prices) increase the net profit derived from the FCR-N and FCR-D up-regulation markets. Considering the upward trend of CO2 emission allowance prices in recent years, an increasing profit from these markets is anticipated in the upcoming years. The profit from the FCR-D down-regulation market was shown to decline marginally with higher ETS prices.
Currently, DH systems in Finland face significant uncertainties regarding their future operating conditions. The interruption of natural gas and biomass imports from Russia to Finland since 2022 has propelled the prices of these fuels, and future price levels remain unpredictable. They could persist at a higher level than anticipated in this study, enhancing the competitiveness of HP technologies, while also highlighting the need for a diversified and secure energy supply. This study suggests that DHN operators must remain adaptable to changing market conditions. The fluctuating nature of electricity and EU ETS prices requires dynamic management strategies to maximize revenues and maintain operational efficiency. The findings indicate the necessity for strategic planning in the integration of HPs and electric boilers. This includes considerations for operational scheduling and balancing market participation to optimize financial returns and energy efficiency.
Considering the increasing integration of renewable energy sources, such as wind power, future studies could explore the role of other potential balancing providers in complementing HPs and electric boilers. Other suggestions for future works include analyzing the long-term sustainability and environmental impact of the shift to HPs and electric boilers in DHNs, considering the entire lifecycle of these technologies, and investigating the potential for diversifying energy sources within DHNs to enhance the resilience against fuel supply uncertainties and fluctuating prices, thereby ensuring a stable and secure energy supply.