# Economic insights for residential heating and DHW energy services: A comparative analysis with a focus on solar systems integration

Paula Pedraza Aguirre, Arnaud JAY, Monika Woloszyn, Etienne Wurtz

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Paula Pedraza Aguirre, Arnaud JAY, Monika Woloszyn, Etienne Wurtz. Economic insights for residential heating and DHW energy services: A comparative analysis with a focus on solar systems integration. Journal of Physics: Conference Series, 2025, 3149, pp.022033. 10.1088/1742-6596/3140/2/022033. cea-05535502

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# Economic insights for residential heating and DHW energy services: A comparative analysis with a focus on solar systems integration

Paula Pedraza Aguirre, Arnaud JAY, Monika Woloszyn, Etienne Wurtz

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## ► To cite this version:

Paula Pedraza Aguirre, Arnaud JAY, Monika Woloszyn, Etienne Wurtz. Economic insights for residential heating and DHW energy services: A comparative analysis with a focus on solar systems integration. CISBAT 2025, Sep 2025, Lausanne, Switzerland. 3149, pp.022033, 2025, Journal of Physics: Conference Series. 10.1088/1742-6596/3140/2/022033. cea-05535502

HAL Id: cea-05535502

https://cea.hal.science/view/index/docid/5535502

Submitted on 3 Mar 2026

HAL is a multi-disciplinary open access archive for the deposit and dissemination of scientific research documents, whether they are published or not. The documents may come from teaching and research institutions in France or abroad, or from public or private research centers.

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# Economic insights for residential heating and domestic hot water energy services: a comparative analysis with a focus on solar systems integration

**Paula Pedraza<sup>1,2</sup>, Arnaud Jay<sup>2</sup> and Monika Woloszyn<sup>1</sup> and Etienne Wurtz<sup>2</sup>**

<sup>1</sup>LOCIE, Solar Academy, Univ. Savoie Mont Blanc, CNRS, 73370, Le Bourget du Lac, France

<sup>2</sup>Univ. Grenoble Alpes, CEA, Liten, Campus Ines, 73375 Le Bourget du Lac, France

E-mail: paula.pedrazaaguirre@cea.fr

**Abstract.** Countries are responding to the need to reduce their carbon footprints by adopting new sustainable energy technologies through emerging trends and economic models. One of these trends is the "Energy-as-a-Service" (EaaS) model, where companies assume responsibility for investment, operation, and maintenance, while consumers benefit from sustainable energy services. This study aims to analyze the economic feasibility of integrating solar systems with conventional heating and domestic hot water (DHW) technologies in residential energy services, using a case study in France. Four technology configurations with two renewable energy inclusion scenarios are evaluated within an annual fee structure that covers the leasing and maintenance of the heating and DHW devices. The analysis applies financial methods such as the total annualized cost (TAC) and the benefit-cost ratio (BCR), with the provider supplying both electricity and heat. The study offers preliminary insights into how economic parameters, such as energy tariffs and financial incentives, influence the transition to energy services. The results indicate that the annual service fee varies significantly depending on factors like capital costs, equipment lifespan, discount rate, and energy prices. Furthermore, integration of photovoltaic systems (PV) suggests that the valuation of the business model can differ depending on the compensation scheme for exported generation, highlighting the need for a global sensitivity analysis to draw more conclusive insights.

**1. Introduction**

Emerging global trends such as servitization and the functional economy are reshaping industries by transforming product sales into service-oriented models that enhance customer experience and generate sustainable value [1]. In the energy sector, these trends aim to break through systemic barriers such as high initial investment costs, misaligned financial incentives, and the low cost of conventional energy sources, which hinder the transition to clean energy and circular economies [2]. This has led to the rise of the Energy as a Service (EaaS) model, where consumers pay only for the energy services they use, such as heating and domestic hot water (DHW), without the need for expensive infrastructure investments [3]. Despite growing interest in energy services, research on EaaS for space and water heating services remains limited, particularly in the French context. This article presents a methodology for evaluating heating and DHW packages within an energy service model in France, exploring the potential of service-based solutions in the energy sector.

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## 2. Methodology

The study adopts a techno-economic simulation approach for different space and water heating solutions in the residential sector. The analysis considers different technological variants (v) with the integration of renewable energy systems to assess their economic performance within an EaaS framework. The first step involves evaluating the energy performance of the building with the selected systems through a Building Energy Simulation (BES). Based on these results, the financial structure of the energy service is defined. There are different pricing and contractual approaches within the EaaS scheme, such as pay-as-you-go, metered subscription, unlimited subscription, or combinations of these [4]. In this study, energy service refers to a contract in which the end user pays a fixed annual fee that covers both the leasing of heating and DHW assets and their operation and maintenance, including energy provision with no limits on energy consumption. The financial model is structured and evaluated according to the stages outlined in figure 1.

<figure><img src="image_5.png" /><figcaption>Figure 1. Methodology for the economic evaluation of an energy as a service model.</figcaption></figure>

The economic assessment relies on the results of the BES simulation and the tariffs for energy purchase and PV sale. From these inputs, the Total Annualised Cost (TAC) is determined, capturing both capital (CapEX) and operational expenditures (OpEX) while integrating additional service costs and revenue from PV production when applicable. This metric provides a comprehensive view of the system's financial burden over its lifetime, incorporating the time value of money through a given discount rate (i) [5]. To account for the profit from the sale of PV production (Ppv), a comparison is made between two sales mechanisms (c): (1) surplus sale (c = 1) and (2) total production sale (c = 2). Finally, additional service-related expenses (warranties, insurance, administrative management) are captured through a simplified approach. A fixed percentage is added to CapEX to reflect the indirect costs of delivering and supporting the service, beyond the investment in equipment and installation. Similarly, an additional percentage is added to the maintenance costs to account for long-term operational support. Under a simplified assumption where operational costs and PV revenue remain constant over time, the TAC is expressed as equation 1, forming the basis for the annual service fee.

$$TAC_v [€/year] = \sum_{s} (CRC_{s=heat\ pump, PV\ system}) + (OPEX - Ppv_c) \quad (1)$$

The Capital Recovery Cost (CRC) is determined using equation 2, where CapEX is adjusted through the Capital Recovery Factor (CRF). The CRF converts the initial investment into an equivalent annual cost, incorporating a discount rate and the useful life of the system to reflect
its financial impact over time [6]. In cases where the system is financed through a loan, the discount rate used in the CRF corresponds to the loan's interest rate, as loans increase the initial cost based on the interest rate.

$$CRC_s [€/year] = CapEX_s * CRF_s \quad (2)$$

Finally, to assess the profitability of the model in terms of energy savings and solar integration, the benefit-to-cost ratio (BCR) is calculated for the technology service variants. This evaluation is based on the approach proposed by T. Hong et al. for optimizing leasing payments in PV systems [7]. In the original model, two separate BCRs are calculated: one for the customer and another for the provider, as the service fee is based on energy savings achieved through PV integration. However, in this study, the service fee is structured differently since the provider also assumes energy costs. The benefits correspond to the reduction in energy expenses and revenues from the sale of PV production. The costs are the CapEX and OpEX set out in the base model. Consequently, a single benefit-cost ratio (BCR) is used, primarily reflecting the customer's perspective. Since the customer's service fee is based on the Total Annualized Cost (TAC), which includes both CRC and OpEX, the provider can indirectly adapt their pricing scheme based on the client's economic outcomes. Thus, cost savings or additional revenues lead to lower fees for the customer and provide a basis for the provider to adjust service pricing accordingly, aligning incentives within the same BCR framework. The BCR calculation is presented in equation 3.

$$BCR = \frac{\sum_{t=0}^{n} \frac{(P1r-P1es_t)+Ppv_c_t}{(1+i)^t}}{\sum_{t=0}^{n} \left( \sum_{s} CRC_s \right) + \frac{OpEX_t}{(1+i)^t}} \quad (3)$$

where P1r stands for the energy expenditure before subscribing to the energy service, i.e. with the reference system. P1es stands for the energy expenditure under the energy service in the year t, and n stands for the contract duration of the energy service.

### 3. Case study

This study adopts a case study approach, integrating energy and economic modeling for a residential building in France. The case study focuses on a 69 m² Phenix-type house with low thermal performance. The dwelling is located in Trappes, a temperate oceanic (Cfb) climate zone [8], where heating demand is high. The house is poorly insulated, with only a small air gap (1.2 cm) and a thin layer of glass wool (4 cm) on the unheated attic floor. The windows are single-glazed, and the exterior door is uninsulated. For key input parameters such as heating requirement in daytime zones (16-19 °C for living room and kitchen), power dissipation, occupancy, and domestic hot water consumption (40 L/day.person), the study relies on the models coming from the France RE2020 thermal regulation [9]. A constant temperature of 17 °C was assumed for bedrooms and corridors [10]. Additionally, air mechanical ventilation and infiltration were considered constant at 0.6 vol/h.

Regarding the systems modeling, the analysis examines the renovation of the space and water heating system, replacing it with a more efficient solution. Four technological variants (v) are defined: (1) a reference system based on a low-efficiency gas boiler (GB), and (2) a dual-service system with a high-efficiency air-water heat pump (AWHP) and electric backup, evaluated in three scenarios: (2a) operating independently, (2b) coupled with a 6 kWp photovoltaic system, and (2c) acting as a backup for a solar water heater (SWH), complemented with a PV system of 3 kWp. The energy modeling and simulation are performed using Pleiades software, which determines energy consumption by source and end use. For variants 2b and 2c, the electricity balance is determined to assess the injection of electricity generated by the PV system into the grid and its self-consumption. The input data were provided by various industrial and research
actors in France, under the Enerloc project, with reference to commercial values. In this context, the industrial partner provided the performance matrices for the heat pump used, which indicate a coefficient of performance (COP) for heating ranging from 4.4 to 5.1, and a COP of +3.3 for DHW production [11]. The gas boiler, by contrast, has an efficiency of 85%, significantly lower than that of the heat pump system. These assumptions are particularly favourable for the heat pump system, considering its high efficiency and optimal operational conditions. The building energy simulation (BES) results, used for economic analysis, are presented in table 1.

<table><caption>**Table 1.** Annual energy balance by energy use and energy type of a Phenix-type dwelling.</caption><thead><tr><th>Variant</th><th>Other Use</th><th>Electric heating</th><th>Gas heating</th><th>Electric DHW</th><th>Gas DHW</th><th>Self-consumption</th><th>Energy from the grid</th><th>Energy injected into the grid</th></tr></thead><tbody><tr><td>1-GB</td><td>1829</td><td>0</td><td>17275</td><td>0</td><td>4502</td><td>0</td><td>1829</td><td>0</td></tr><tr><td>2a-AWHP</td><td>1829</td><td>3111</td><td>0</td><td>1641</td><td>0</td><td>0</td><td>6581</td><td>0</td></tr><tr><td>2b-AWHP+6PV</td><td>1829</td><td>3104</td><td>0</td><td>1641</td><td>0</td><td>1724</td><td>4832</td><td>4238</td></tr><tr><td>2c-SWH+AWHP+3PV</td><td>1829</td><td>2944</td><td>0</td><td>875</td><td>0</td><td>1159</td><td>4473</td><td>2246</td></tr></tbody></table>

For the economic input data, this study considers CapEX as the sum of investment and installation costs for each variant. Since the reference system is already in place, no additional investment is needed for the gas boiler. The upfront costs are €11,600 for the heat pump, €12,900 for the 6 kWp PV system, €6,790 for the 3 kWp PV system, and €5,259 for the solar water heater. Regarding the OpEX, it is composed of annual energy expenditure and annual maintenance cost. The latter amount to €150 for the gas boiler and €200 for the heat pump. The listed prices already include additional service costs: 25% on the CapEX of each system and 40% on the maintenance cost of the heat pump [12]. Energy-related expenses are calculated based on fixed and variable electricity and gas tariffs for 2023 in France. Meanwhile, for the profit from the sale of PV production, each mechanism has a tariff that varies according to the energy produced in kWh, with different rates applied based on the kWp capacity of the PV system [13]. Additionally, for surplus sales, an investment subsidy for self-consumption exists, depending on system capacity. These energy-related economic data were obtained from open data from the Energy Regulatory Commission (CRE) [14] and are presented in table 2.

<table><caption>**Table 2.** Tariffs for energy consumption and sale of PV production in France for the year 2023.</caption><thead><tr><th>Energy type</th><th>Capacity</th><th>Tariffs</th></tr></thead><tbody><tr><td rowspan="2">Electricity</td><td>3 kVA</td><td>Fixed tariff (€/an): 111.187, variable tariff (€/kWh): 0.2124</td></tr><tr><td>6 kVA</td><td>Fixed tariff (€/an): 145.743, variable tariff (€/kWh): 0.2124</td></tr><tr><td>Gas</td><td>&gt;6 MWh</td><td>Fixed tariff (€/an): 249.15, variable tariff (€/kWh): 0.1291</td></tr><tr><td rowspan="2">PV production</td><td>3 kWp</td><td>Surplus sale tariff (€/kWh): 0.1319, Self-consumption investment subsidy (€/kWp): 463.26, Totality sale tariff (€/kWh): 0.2181</td></tr><tr><td>6 kWp</td><td>Surplus sale tariff (€/kWh): 0.1319, Self-consumption investment subsidy (€/kWp): 347.44, Totality sale tariff (€/kWh): 0.1854</td></tr></tbody></table>

The study reflects incentives and subsidies available in the French context, including the scheme 'eco-PTZ', an interest-free loan for heating equipment acquisition. Consequently, financing in this analysis applies only to PV systems. The calculation of the annualised investment cost (CRC) for each equipment is made on the basis of their reference lifetimes (DV) of 17 years for conventional heating systems, 25 years for solar production systems and 50 years for solar thermal systems. In order to reflect realistic financial conditions, a discount rate of 2.75 % is used, which corresponds to the average of France's Long Term Interest Rate for 2023 [15]. For space and water heating systems financed with a loan at 0 % interest, equation 2 simplifies to $CRC_s = CapEX_s/DV_s$.
**4. Results and discussion**

The total annualized cost for each variant, along with the breakdown into capital cost, operating expenses, service-related cost, and PV production benefits, are shown in figure 2. The TAC is the annual charge that the customer would pay for the service, i.e. the red point in the graph.

<figure><img src="image_6.png" /><figcaption>**Figure 2.** Total annualized cost breakdown</figcaption></figure>

Non-energy expenses (CapEX, maintenance, additional service cost) show a significant share in the overall breakdown. Especially in variants with solar technology, where they account for more than half of the costs included in the service fee. This is influenced by several factors. First, interest-free financing applies only to certain technologies: for example, variant 2a, which includes only a heat pump, has the lowest CapEX share (21%) due to full financing at 0% interest. In contrast, PV systems are not eligible for this financing scheme, requiring a broader analysis. This is the case for variant 2c which integrates more systems than 2b, but has a lower CRC. The outcome results from a combination of interest-free financing, the long lifetime of the solar water heater, and reduced PV investment. Second, the investment subsidy for self-consumption lower upfront costs by 16 to 20%, but once adjusted for loan interest, the effective CapEX reduction is below 10%. Third, additional service expenditures account for 10% and 15% of the costs. These findings underline the importance of strategies to reduce CapEx and maintenance costs, as well as exploring alternative configurations of the business model itself. In particular, a comparative analysis of subsidies versus interest-free financing could offer valuable insights into improving the economic viability of integrating solar technologies into space and water heating services.

Energy-related costs reflect the impact of system efficiency and energy prices. Although the electricity tariff is nearly double that of gas, switching to a heat pump in variant 2a reduce energy expenditures by half. The cost drop is notably significant but is congruent with the reduction in operating costs estimated by other studies [16]. This suggests that the reduction is mainly due to the heat pump's higher efficiency compared to the gas boiler (85% efficiency). The COP values used, based on manufacturer data under optimal conditions, serve as a benchmark to assess the economic potential of high-efficiency systems. Future analyses could explore more conservative efficiency scenarios since performance data are essential in system modeling and BES-based analyses because they directly impact operational costs and EaaS tariffs.
Regarding solar integration, variant 2c (c=1) shows about a 30% reduction in electricity expenditures compared to variant 2a with only a heat pump. This highlights the significant role of solar generation in lowering operating costs. Variants combining solar thermal and PV systems, especially with export schemes, tend to have lower TAC. As noted in the methodology, breaking down service fee is key to understanding how investment, maintenance, and energy tariffs affect EaaS viability. However, if only the TAC is considered, selling the entire production might seem more profitable because the surplus sale tariff is lower than the retail electricity price, making the energy savings from self-consumption less valuable compared to the higher tariff received when selling all production. In contrast, from the perspective of BCR, self-consumption represents greater energy savings compared to the reference system, which makes the surplus sale scheme more advantageous, as shown in figure 3.

<figure><img src="image_7.png" /><figcaption>**Figure 3.** BCR for different types of space and water heating configurations.</figcaption></figure>

Variants that adopt a surplus sale mechanism are financially more attractive, as indirect benefits are maximised and the ratio of value generated to cost invested is improved. The extent of savings depends on the amount of energy generated and consumed, making the installed PV capacity a key factor. In France, the current regulatory framework encourages systems with lower capacity (3 kWp) through higher subsidy levels and more advantageous sale tariffs. As a result, these systems tend to achieve a higher BCR, even if they generate less energy. Larger systems (e.g., 6 kWp), while producing more electricity, are subject to lower feed-in tariffs and higher upfront costs, which can lead to a less favorable BCR under the same evaluation criteria. A further global sensitivity analysis would be valuable to assess how variations in tariffs, subsidies, and energy generation affect the economic performance of photovoltaic systems in different service-related scenarios.

In this study, BCRs are generally below 1, indicating that the initial investment is not fully recovered through the calculated benefits over the 17-year time horizon. However, this does not suggest that the EaaS model is unfeasible, but rather highlights the need to adjust financing conditions and energy and sales tariffs to improve its competitiveness.

**5. Conclusions and perspectives**

This study contributes to the energy as a service literature by introducing a methodology for economic assessment and hybrid modelling. The case study serves to illustrate the methodology and highlights the need for further exploration, particularly through sensitivity analyses of the most influential parameters. The practical approach used to explore various heating and DHW systems with solar integration in the context of energy services demonstrates that the profitability of EaaS depends not only on equipment costs but also on financing conditions, incentive policies, and strategies for valorizing solar production. The obtained findings are limited to a single case of EaaS, so the methodology and model development should be understood as a started point, which opens a space for future improvements in the structuring and analysis of energy services.
## Acknowledgments

This research was supported by the Solar Academy Graduate School, grant ANR-18-EURE-0016. The authors would like to thank the ENERLOC project team for the technical and economic data provided for this study.

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