An assessment of the impacts of renewable and conventional electricity supply on the cost and value of power-to-gas

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An assessment of the impacts of renewable and conventional electricity supply on the cost and value of power-to-gas Aymane Hassan 1, Martin K. Patel, David Parra* Energy Efficiency Group, Institute for Environmental Sciences and Fore Institute, University of Geneva, Boulevard Carl-Vogt 66, 1205, Gen
eve, Switzerland

article info

abstract

Article history:

Power-to-gas (P2G) is a promising enabling technology for more cross-sector integration

Received 29 June 2018

but its high cost has so far been a key barrier to implementation. Electricity supply is the

Received in revised form

greatest contributor to the levelised cost therefore it is important to understand which

14 September 2018

technologies and strategies can minimise the cost and accelerate the deployment. In this

Accepted 3 October 2018

study, a method is devised to evaluate the cost and value of combined systems comprising

Available online xxx

P2G and renewable energy technologies such as solar photovoltaics, wind and hydro as well as comparing to traditional electricity supply via the wholesale market. The proposed

Keywords:

models are based on a temporal resolution of 1 h and include partial operation and ageing

Renewable energy

throughout the system's lifespan. Our analysis covers both distributed and centralised P2G

Hydrogen

systems producing hydrogen or methane as well as various value-adding services across

Power-to-gas

different geographies. It is found that the capacity factor of a P2G system drives the eco-

Electrolyser

nomic case and therefore the electricity supply from hydropower plants is economically

Energy storage

more attractive than electricity from wind and solar photovoltaic plants in this order.

Methanation

Under today's market conditions, it is highly advisable to combine local renewable supply with wholesale-based supply but interestingly, a 20% capital cost reduction in wind technology or a P2G system efficiency of 80% are break-even points for P2G systems producing hydrogen and connected to wind plants. © 2018 Hydrogen Energy Publications LLC. Published by Elsevier Ltd. All rights reserved.

Introduction Following the reactor disaster of Fukushima in 2011, the Swiss federal government decided to progressively phase out the nuclear electricity production in Switzerland [1]. The Swiss electricity supply already has a low carbon intensity (14 gCO2/ kWhe),2 with hydropower and nuclear energy contributing

60% and 33% of the total electricity generation in 2015 [2]. However, both the heating and the mobility sector mostly depend on imported fossil fuels which is inconsistent with long-term climate change mitigation objectives and energy supply security goals. In 2016, 64.6% of final energy consumption (excluding electricity) was supplied by fossil fuels [3]. The expected deficit in the production of electricity due to

* Corresponding author. E-mail address: [email protected] (D. Parra). 1 Moved to Paul Scherrer Institute (PSI) and current e-mail address is [email protected]. 2 For specifying the type of energy and power, we use the subindex "e" for electricity and "t" for the thermal energy of a gas, namely hydrogen and methane. When "e" is used with the power rating of a RE or a P2G plant, it refers to the nominal capacity (also referred as peak). https://doi.org/10.1016/j.ijhydene.2018.10.026 0360-3199/© 2018 Hydrogen Energy Publications LLC. Published by Elsevier Ltd. All rights reserved. Please cite this article in press as: Hassan A, et al., An assessment of the impacts of renewable and conventional electricity supply on the cost and value of power-to-gas, International Journal of Hydrogen Energy (2018), https://doi.org/10.1016/j.ijhydene.2018.10.026

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the phase-out of nuclear energy combined with climate change mitigation goals call for the upgrading of the Swiss energy system [4]. The Swiss Energy Strategy 2050 advocates a package of measures including the promotion of renewable energy (RE) technologies, e.g. solar photovoltaics (PV), wind, geothermal, biomass and hydropower as well as the exploitation of the energy efficiency potential in buildings, mobility, industry and appliances [5]. In order to provide demand match capability, solutions such as energy storage, demand-side management, RE curtailment, grid reinforcement and interconnection among regions will have to be further implemented. Among them, energy storage is attracting much attention because it allows to manage RE intermittency and to provide reserve capacities, thereby ensuring the security of supply and reducing the reliance on fossil fuel imports. According to the European Climate Foundation, there is a need for 125 GWe of energy storage capacity in Europe by 2050 in a scenario with 80% renewable generation, which calls for the development of 27 GWe of additional storage capacity by 2050 [6]. And according to the Swiss Federal Office of Energy (SFOE), energy storage technologies could take up 1 TWh of electricity in 2050 [6]. Renewable electricity can be converted into gas and stored in the gas grid to be used for heating, mobility and for power generation. There are two different options, namely power-tohydrogen (P2H) and power-to-methane (P2M). In both cases, electricity is used to generate hydrogen via water electrolysis but the latter also implies the methanation of CO2. Oxygen and heat are co-products of the reaction [7]. Oxygen can be released to the atmosphere or compressed to be reused in industrial processes (in chemical industry, medical applications or wastewater treatment). Heat can be recycled to be reused onsite or it can be injected into a district heating grid 3 [6]. In the case of P2M, recycled heat can also be used for the carbon capture process in order to supply CO2 to the methanation reaction [8]. Carbon neutral gas for mobility and heating could help to substantially reduce greenhouse gas emissions. Moreover, increased RE capacity is expected to lead to longer periods of low wholesale electricity prices representing an opportunity for P2G systems [7]. Contrary to batteries, P2G systems can absorb excess electricity production over multiple days and weeks and perform the role of seasonal storage since the capacity in energy terms (i.e. the natural gas grid) is not correlated to the installed capacity of the electrolyser [9]. Also, it is a highly scalable technology which can be deployed in multiple single units ranging from few kWe to hundreds of MWe. It has been reported that P2G can provide substantial flexibility to the whole energy system. A study conducted by Lyseng et al. shows that for an energy system with a supply based on 80% renewable power, P2G can reduce RE curtailment by 23% [10]. The current investment cost of P2G technology and in particular electrolysis is one of the constraints to its economic attractiveness but the potential for cost reduction is promising 3

For low temperature electrolysis such as alkaline and polymer electrolyte membrane, it should be a district heating operating at low temperature (e.g., 50e60
C), referred to as fourth generation district heating.

[11]. For example, the capital expenditure (CAPEX) of a polymer electrolyte membrane (PEM) electrolyser systems is currently around 2000 V/kWe but it could decrease to 700 V/kWe in the near term if marked R&D efforts and production scale-up are developed.

Literature review P2G technology should be developed considering various criteria such as efficiency, environment, economy and policy regulations involving different stakeholders [12,13]. Lyseng et al. showed the significant role P2G can play as an energy storage technology despite its still high CAPEX [10]. P2G can substitute solar and wind capacity requirements in a lowcarbon energy system by 23% and reduce the curtailment of excess renewables by 87% if connected close to the RE plants. Furthermore, operating a P2G plant during periods of surplus RE allows P2G to compete with traditional energy carriers such as natural gas [12]. Hofstetter et al. estimated the total costs for different P2G implementation scenarios for Switzerland and investigated the impact of partial operation on the economic viability of P2G projects [6]. They considered two different types of grid mixes at the wholesale level, “GreenMix” (hypothetical mix with 70% hydro, 10% wind, 10% PV and 10% biomass) and “SwissMix” (58.7% hydro, 35.8% nuclear, and 5.5% conventional thermal plus other sources). Considering a baseload operation (i.e. continuous operation of the P2G system), the levelised cost was found to be 219 $ 4/MWht and 278 $/MWht (i.e. 27% higher) for a 1 MWe P2M supplied by “SwissMix” and “GreenMix” respectively. In addition, it was found that total life-cycle costs depend mostly on electricity prices (70% of total cost). Moreover, biogas upgrading can serve as source for low-cost CO2 and benefit stacking (i.e. the combination of products and services) can contribute significantly to the value of P2G systems which may reach up to a three-fold of conventional natural gas [14]. For example, the benefit from providing grid balancing services is important as it leads to a higher utilisation of P2G thereby increasing the economic profitability of the system [15]. A techno-economic and life cycle assessment of P2G technology with methane production using CO2 from biogas upgrading also reported high operational costs due to electrolysis considering the French electric mix as the electricity supply source [16]. Garmsiri et al. calculated the payback period and conducted a sensitivity analysis to assess the feasibility of a P2G system utilising excess wind electricity to generate hydrogen and methane which were both assumed to be injected into the natural gas grid [17]. This study also showed the importance of low electricity prices for profitability and payback periods [17]. A study conducted by Mukherjee et al. reported payback periods longer than the project lifetime (20 years) for a P2G system under business-asusual conditions [18]. However, pricing incentives that allow to achieve shorter project payback periods were identified. Interestingly this study found that the economic profitability 4

The exchange rates assumed are 1 EUR ¼ 1.06 CHF and 1 $ ¼ 1CHF.

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of P2G is sensitive to CO2 emission credit incentives and $27 per tonne of CO2 was found to be required considering a short project lifetime of 8 years [18]. A review of the economic potential of P2G conducted by ENEA considered different values for electricity prices, CAPEX and operational expenditure (OPEX) of technologies for grid injection, green mobility and heating applications using grid supply from the French wholesale market [7]. The operation was optimised according to periods of low electricity prices. The authors found that the levelised cost of a 10 MWe system using alkaline electrolysis is 100 $/MWht for hydrogen production and 180 $/MWht for methane. According to their conclusions, the economic viability of P2G for gas grid injection requires enhanced operational strategies to minimise electricity prices. For example, electricity supply based on a large share of wind and PV power (60% of the power supply) and the exoneration from paying for the fixed cost of the renewable electricity mix were suggested. This could be achieved under the French regulation if the P2G plant were located at an industrial site already exempted from the carbon tax [7]. The role of P2G in a future energy system with high RE shares was addressed in a previous study by Kotter et al. including electricity and heat supply [9]. Only a large P2G system (218 MWel) with a CAPEX below 2600 $/kWe and with reuse of waste heat was found to be competitive with other storage technologies such as lithium-ion batteries. Although previous studies have indicated that the electricity supply dominates the economic performance of P2G, a systematic comparison of the impacts of various types of electricity supply and their combinations is still lacking. Most previous analyses have considered grid electricity supply from the wholesale market but interestingly, around half of the existing P2G projects are already directly connected to PV and wind power plants [19]. Direct connections to RE plants can increase the value of the produced gas but at the same time it is important to understand the implications for the capacity factor and final cost. In this study, we analyse the influence of various electricity supply sources on the total cost of P2G systems. In particular, PV, wind, hydro and wholesale-based electricity supply and their combinations are compared considering both their intrinsic dynamics (e.g. weather dependence for PV and wind and volatility of wholesale electricity prices) and typical scale of deployment. On this basis, the cost-optimal electricity mix for P2G depending on the scale is found. Finally, we also examine the cost and efficiency targets required for the economic break-even of P2G systems in view of the falling costs of RE technologies. These insights can be very useful to investors aiming to maximise the economic benefit of P2G systems including RE supply.

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CO2 supply cost. The proposed P2G and electricity supply models are based on a temporal resolution of 1 h and include partial operation and ageing throughout the system's lifespan. Geographical differentiation between Switzerland and Germany is considered but only for P2G systems connected to PV and wind power plants given the intrinsic spatial variability of these renewable resources. For the combined supply of PV power and wind power, two specific locations with favourable wind potential, namely Yverdon-les-Bains in Switzerland and Bremen in Germany have been selected because the spatial variability of the wind resource is even more marked than for PV electricity. 5 Wholesale electricity supply (both traditionally and hydropower-based) is only analysed for Switzerland since the same optimisation strategy applies regardless of the specific market [7,22]. Results are presented for a reference scale of 10 MWe which approximately corresponds to the currently worldwide largest P2G system (a 12 MWe P2G project in Delfzijl, Netherlands 6) but in addition, we analyse the impact of the scale ranging from distributed (25 kWe) to bulk systems (1 GWe) acknowledging that the current trend is for large systems. The sizes of the analysed systems and origin of electricity supply are summarized in Table 1. Each case is assessed by means of the following key performance indicators: levelised cost, levelised value and net present value (NPV) per unit of CAPEX. Finally, the sensitivity of the economic performance of P2G to future investment costs and efficiency improvements is also evaluated. Fig. 1 is a schematic representation of a P2G system supplying gas for heating and/or mobility services as modelled in this study. The system boundaries are delimited by the natural gas network and therefore our analysis do not differentiate between the two applications from a techno-economic perspective. This also means that additional costs for injecting and transporting the produced gas are not reflected. An overview of the different approaches and models adopted for simulating various electricity supply options, the performance of P2G systems and their cost is depicted in Fig. 2. A more detailed description of the P2G model is given in Section 6 of the Supplementary Information (SI). Technical data such as electricity requirements, conversion efficiencies, degradation and cost data including CAPEX, OPEX, electricity prices and grid connection charges are compiled from the literature and from consultations with experts. The reader can find them in the SI.

Electricity supply options Two different electricity supply strategies for P2G systems and their combination are compared in this study. The first one is just to purchase wholesale electricity (conventional or hydropower-based) and the second is to invest on local RE plants to supply electricity to the P2G system. Furthermore,

Methodology In this study, a Polymer electrolyte membrane (PEM) is selected for electrolysis given its better dynamic response as well as significant potential for innovation [11,20] while catalytic methanation is selected due to high technology readiness and efficiency [21]. For P2M, both CO2 supply from the air and from biogas plants were considered since they represent the least and most costly options and therefore cover the full range of

5 Wind power is proportional to the cubic function of the wind speed while solar power is a linear function of solar irradiance. 6 http://www.fch.europa.eu/sites/default/files/HighV.LO-City_ Opening%20_Groningen_siteHRS.pdf. 7 The lifetime of PV and wind power plants are assumed based on the estimates from the National Renewable Energy Laboratory (NREL), available at reference [23]. For hydropower and wholesale-based P2G systems, the lifetime is based on the electrolyser stack lifetime (cf. SI section 1.7, Table 4).

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[24] [25] [26] [27] [28] [29] 1 kWe- 8.3 MWe 1 kWe-168 MWe 6.5 kWe-37.2 MWe 100 kWe-595 MWe 1.5 MWe- 1.26 GWe Minimum size: 0.1 MWe 30 years 30 years 20 years 20 years 600 000 h of operation 600 000 h of operation PV PV Wind onshore Wind onshore Hydropower (storage) Wholesale market

Switzerland Germany Switzerland Germany Switzerland Switzerland

25 kWe-10 MWe 25 kWe-200 MWe 25 kWe-50 MWe 25 kWe-600 MWe 1.5 MWe- 1 GWe 100 kWee1 GWe

Yverdon Bremen Yverdon Bremen Wholesale-based supply þ guarantee of origin Swiss domestic production and electricity imports

Size range compiled from literature Selected region/origin of electricity Lifetime7 Selected range Country Type of electricity supply

Table 1 e Selected PV, wind and hydropower system scale ranges and locations across Switzerland and Germany based on existing projects.

Reference

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the combination of various types of renewable electricity supply is also evaluated for the second strategy. The first step of our analysis consists of performing a literature review of PV and wind power plants in Switzerland and Germany and their key characteristics. The electricity yield of PV and wind technologies is simulated for a whole year using climate data with 1 h resolution for the year 2016. This is then used to determine the capacity factors of both RE technologies across the several locations selected for this assessment in Switzerland (Geneva, Bern and Yverdon) and Germany (Dresden and Bremen). 8 The locations selected for the analysis are provided in Table 1. Then, we determine the levelised cost of electricity (LCOE) for various RE supply options and we compare these values with wholesale electricity prices. Electricity supply from a utility company is not considered in this study since electricity prices for very large consumers are subject to negotiation and are confidential.9 For each technology, the existing deployment scale for RE projects in Switzerland and Germany is considered for connection to P2G systems. For instance, the largest German and Swiss PV systems have a nominal capacity of 168 MWe and 8.3 MWe respectively. CAPEX values and capacity factors are highly technology and region-dependent and therefore our input data and results are scale and market specific, e.g., with a distinction between small-scale and utility-scale systems for PV, and with typical wind turbine capacities between 2 and 5 MWe [30,31]. We minimise the uncertainty related to CAPEX by using datasets associated with a large sample of PV projects provided by the Swiss Federal Office of Energy as well as real-world wind projects [32,33]. For Germany, CAPEX and OPEX values are based on the latest estimations provided by Fraunhofer [34]. SI Table 5 displays the selected values also including the maintenance cost, lifetime (years) and discount rate r (%), required to calculate the LCOE of various RE systems (cf. SI Eq. (5)). For RE plants, discount factors from 6% to 12% have been reported in the literature considering that the risk of RE projects is relatively low in Switzerland and Germany as a result of safe political and economic conditions (e.g., stablished policies for the energy transition). Finally, a discount factor of 8% for Switzerland and Germany is selected in this study.

Renewable energy supply: PV and wind The selected PV panel to model PV systems for this study has a nominal efficiency of 18.6% and is therefore representative of the current state of the art. PV installations are assumed to be tilted at 30
facing south since the latitudes of the regions considered in this study are between 45
and 55
, therefore the optimum tilt angle should lie between 21
and 59
for summer and winter respectively. 10 Annual measurements of global horizontal irradiance (GHI in W/m2) and ambient temperatures with a resolution of 1 h for selected locations are used to

8 These different locations are selected for comparison purposes. 9 Small consumers are not expected to invest on P2G due to economies of scale. 10 http://www.solarpaneltilt.com/.

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Fig. 1 e Schematic representation of a P2G system including the sources of electricity supply considered in this study, and the processes involved in hydrogen and methane production. Co-products such as oxygen, heat, sources of CO2 supply (captured from the air or from a biogas plant) and potential applications (heating and mobility) are also depicted.

model the electricity yield from different PV system scales within the range of sizes provided in Table 1 [35e37]. Using GHI, the total irradiance on a tilted surface is determined using a “sky model” and a single diode model is utilised to calculate the power output of the PV system also considering the outdoor temperature [38]. The PV modelling results are presented in SI Table 6 showing capacity factors 11 in the range of between 12% and 15% for a GHI in the range 1035e1338 kWh/m2 across the various selected locations. The climate data profiles (annual temperatures and GHI) and the power output curve of a simulated 10 MWe PV system are given in SI Fig. 1. The levelised cost of PV generation for various system scales is provided in SI Fig. 3. The LCOE for PV system scales ranging from 5 kWe to 200 MWe was found to be between 223 $/MWhe and 91 $/MWhe across all selected locations. Due to the lower CAPEX of PV systems in Germany (cf. SI Fig. 3), the LCOE of PV generation is smaller than for comparable PV systems in Switzerland. Moreover, the LCOE shows a downward trend with increasing system scale for both Switzerland and Germany mainly due to decreasing specific CAPEX with scale. The LCOE then stabilises for utility scale projects since CAPEX and OPEX are assumed to increase linearly with the 11 Capacity factor is defined as the ratio of the total delivered electricity over the amount of electricity that the PV system would generate if operated baseload and at nominal conditions.

system scale for systems larger than 1 MWe. These results have been validated using previous levelised cost assessment studies (cf. SI Table 7). Regarding wind technology, wind turbines mainly differ in terms of nominal capacity, rotor diameter and hub height and we consider the range from the smallest scale to the largest scale available in the market. The techno-economic characteristics of the selected turbines are indicated in SI Table 10 and the average wind speeds at 10 m above ground in the selected regions are given in SI Table 8. The wind speed at the hub height is determined using a power law given in SI Equation 9. Power curves provided by manufacturers combined to wind speed data measured in weather stations of ^ telard (CH) and selected locations namely Yverdon (CH), Cha Bremen (DE) are utilised to simulate the annual electricity output of wind turbines ranging from 6.5 kWe to 3.6 MWe. The power curve of a 3.2 MWe wind turbine, the annual wind speed profile and the annual power output delivered bin Yverdon are provided in SI Fig. 2.

Wholesale electricity and hydropower supply In addition to be one of the supply options (which in particular is only considered for the Swiss context), wholesale electricity prices are also used to estimate the value of the electricity injected into the grid by RE plants in Switzerland

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Fig. 2 e Summary of technology characterisation, various modelling assumptions and outputs for each type of electricity supply and for the P2G analysis. PV and wind supplies are modelled across Switzerland and Germany while wholesale supply (both traditionally and hydro-based) is modelled only for Switzerland.

and Germany, opposite to be used locally by a P2G system. Wholesale electricity spot prices from the year 2016 taken from the European Energy Exchange with 1 h resolution and their frequency distribution for Switzerland and Germany are given in SI Fig. 5 with grid connection charges provided in SI Table 11. The average wholesale electricity price in 2016 was equal to 40 $/MWhe and 31 $/MWhe in Switzerland and Germany respectively. Wholesale electricity prices are negative in periods with particularly high RE generation and low electricity demand. Wholesale electricity prices are assumed to keep constant until 2020 in agreement with predictions of European energy exchange (EEX) [14]. From 2020 onwards, electricity prices are assumed to increase as illustrated in SI Fig. 6, based the results given by the SwissMod model by Schlecht and Weigt for Switzerland and neighbouring countries when considering projections on fossil fuels and carbon tax [39]. Regarding hydropower, given its current deployment and maturity level (with a total of 643 hydropower plants producing 36 TWhe per year in Switzerland 12), we do not assume that hydropower plants are built to serve P2G projects but hydropower electricity is also bought from the wholesale market. We however differentiate hydropower from conventional wholesale electricity supply by adding a mark-up of 1.06 12

http://www.bfe.admin.ch/themen/00490/00491/index.html? lang¼fr.

cts/kWhe as guarantee of origin based on data from the European Energy Exchange 13[6].

Cost optimisation of P2G systems In the case of the wholesale-based supply, the electrolyser operation schedule is defined such that it minimises the levelised cost of produced gas, referred here as levelised cost of energy storage (LCOES), thereby accounting for the high volatility of electricity spot prices (see SI Fig. 5) [7,22,40]. For each P2G system configuration (namely P2H and P2M), scale and for each year of operation, a price threshold is determined, i.e. electricity price beyond which the electrolyser should not operate otherwise the levelised cost would increase despite the increase of the capacity factor. SI Fig. 8 shows the variation of the LCOES and capacity factor as a function of the price signal for P2G systems of various scales. For example, for a 1 MWe P2H system, the optimised capacity factor is 77% after selecting a price threshold of 59 $/MWhe in 2016. The selection of the scale for a hybrid system comprising RE technologies and P2G systems is also a trade-off decision. Increasing the size of the RE generator increases both the electricity and gas yield but it also leads to higher CAPEX and 13

https://www.eex.com/en/market-data/environmental-markets/guarantees-of-

origin#!/2017/08/10.

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OPEX values. On the other hand, a hybrid system including a RE generator that is too small will operate with a lower capacity factor. Therefore, we optimise the size of PV and wind systems in order to minimise the levelised cost of the hybrid system for each P2G system scale. The optimum system scales of RE generators determined for the connection to P2G systems are provided in SI Table 11. For a 25 kWe P2G system, a PV plant of 60 kWe is found to be the optimum. When applied to combined systems comprising wind generators, we find that a 2.3 MWe turbine is the optimum for a 1 MWe P2G system.

Combined types of electricity supply options In addition to comparing various type of electricity supply, we also analyse the effect of combining them for running P2G systems. For all combined electricity supply scenarios, priority is given to renewable generation and in particular, wind power is given the priority over PV power due its lower levelised cost (cf. SI Fig. 3) as well as better environmental performance [41]. The period for the calculation of the levelised cost of a hybrid system based on a combined supply electricity system is equal to the longest lifetime among the electrolyser and RE plants. For example, the period for the calculation for a hybrid system including a combined wind and PV electricity supply is based on the PV system lifetime (30 years versus 20 years for the wind system) and includes several electrolyser stack replacements. To illustrate the impact of combining different types of electricity supply, SI Fig. 10 shows the operation (i.e. number of hours and delivered power) of a 10 MWe P2G system supplied by combined electricity sources. The supply of wholesale electricity is constrained by its price optimisation (explained in section Wholesale electricity and hydropower supply) and the preference given to the local RE generation.

P2G economic value in the wholesale market The gas generated by a P2G system is assumed to be sold at the European wholesale natural gas price plus a premium proportional to the RE content of the electricity supply, with a maximum renewable-based value added (i.e. 100% renewable electricity supply) equal to 70 $/MWht which corresponds to biogas [6]. For a wholesale-based supply, the premium value of P2G is adjusted according to the amount of renewable energy in the wholesale electricity supply mix. SI Fig. 6 shows the evolution of natural gas price, biogas price and the value of the gas generated by a P2G systems over time which is a function of the RE share in the electricity supply. The RE shares are determined using prospected electricity generation mix of Switzerland and Germany according to SwissMod results given by Schlecht and Weigt [57], which are depicted in SI Fig. 7. As intra-annual variations of wholesale natural gas prices are not significant (in comparison with the electricity market), we assume a constant natural gas price throughout the year. This was calculated as the average spot price over the last ten years, equalling 32 $/MWhe for the base year of the model (2015). On the other hand, natural gas price evolution over time is derived from projected trends provided by the Swiss Federal Office of Energy [42]. In future years, fossil fuel prices

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are expected to rise, thereby improving the competitiveness of P2G as source of low/neutral carbon gas if the electricity input is mainly renewable-based [43]. In addition, P2G can provide a range of economic benefits associated with various products and services provided by a P2G plant. These can be combined to increase the economic attractiveness of P2G systems (also referred to as benefit stacking) as further explained in section Key techno-economic performance indicators.

Key techno-economic performance indicators We compare the techno-economic performance of P2G systems as function of the type of electricity and CO2 supply as well as the system scale with three complimentary indicators, namely LCOES, levelised value and NPV per unit of CAPEX. 14 The CAPEX and OPEX for the key components of a P2G system are given in Table 2. The cost of water supply is not included since it is relatively not significant in the overall cost of the P2G system [6]. The LCOES ($/MWht) is the cost of producing each unit of hydrogen or methane over the lifetime and is calculated using Eq. (5). We assume a discount factor of 8% in agreement with previous P2G studies [14,22]. The levelised cost approach allows for a fair comparison between the different configurations even though lifetimes, efficiencies or equipment costs differ. The CAPEX represents the total investment costs related to a P2G system, e.g., RE plant including an inverter, an AC/DC converter, an electrolyser stack and associated balance-of-plant (BoP), a methanation reactor, a CO2 capture facility and other general BoP. The CO2 capture from air facility is assumed to be a modular technology i.e. the cost increases linearly with the scale based on manufacturer information [58]. OPEX refers to the aggregated value of O&M costs of all those components in addition to electricity costs and grid charges in the case of a wholesale-based supply. The levelised value of energy storage, LVOES ($/MWht) is calculated using Eq. (6) and gives the total revenue relative to the gas produced over the entire lifetime. Revenuesi correspond to the stacked benefits generated by selling the gas in the wholesale market in addition to providing other products and services, namely, oxygen, heat, frequency control, avoided CO2 taxes and the sale of surplus RE generation to the grid which values are given in Table 3. In addition, emission reduction credits are assumed to be granted for P2G systems supplied by 100% renewable electricity. A flexible operation of P2G system is not achievable with scenarios involving intermittent electricity supply. Therefore, for the sake of simplicity, P2G systems are not assumed to take part in the primary control market for scenarios with RE supply or combined RE and grid supplies [6,40]. In addition, a residual value is assigned to components that are still worthy beyond the assumed lifetime of the project using a linear depreciation [14]. The avoided CO2 taxes value is calculated based on the CO2 levy equals to 84 $/tCO2 which has been enforced since 2016 [44]. Finally, the net present value per CAPEX, i.e. evaluation of the relative project return to the amount of invested cash is given in Eq. (7) and is calculated

14

All results are based on the high heating value of hydrogen and methane.

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Table 2 e Various values for CAPEX and OPEX of P2G systems together with the reference. P2G component cost Electrolyser stack [$/kWe] Electrolyser BoP [$/kWe] Compressor [$/kWe] Methanation reactor [$/kWe] Methanation reactor's BoP [$/kWe] General BoP CAPEX [$/kWe] Electrolyser O&M [% CAPEX] Methanation O&M [% CAPEX] BoP O&M cost [% CAPEX] CO2 capture from air (Climeworks) [$/ton] Biogas upgrading cost [$/ton]

Values

Values from the literature

Reference

1000 1090 134 145 340 300 2 5 7 200 0

763-1233 $/kWe (60% of system cost) 763e1416 134 101e188 236e439 301 2 5 7 200 Free of charge

[40] [6] [6] [6] [6] [6] [6] [6] [6] [14] [14]

Table 3 e Economic value related to the various products and services generated in a P2G system together with the reference for the selected value. P2G service

Selected Values

Values in literature

Oxygen supply

0.1 $/kg

0.02e0.18 $/kg

Heat supply

60 $/MWht

Frequency control Premium due to renewable content

210000 $/MWe.year 70 $/MWht

CO2 tax

 84 $/tCO2 in Switzerland  106 $/tCO2 in Germany 50 CHF per credit

 44e88 $/MWht  ~60$/MWht 210000 $/MWe.year  121 $/MWht for biogas price  The ecological premium is 37e74 CHF/kWht  84 $/tCO2  106 $/tCO2 40-60 CHF per credit

Emission reduction credits (ERCs)

based on the annual cash flows CFi (see Eq. (8)) which balance revenues and various costs. CAPEX þ

Nreplife P stack i¼1 n P

LCOES ¼

i¼1

CAPEXstack ð1þrÞi

þ

n P OPEX i¼1

ð1þrÞi

(5)

Ei ð1þrÞi

n P Revenuesi

LVOES ¼

i¼1 n P i¼1

NPVperCAPEX ¼

ð1þrÞi

(6)

Ei ð1þrÞi

n X

CFi i

i¼1

ð1 þ rÞ  CAPEX

CFi ¼ Revenuesi  OPEXi

1

(7)

(8)

Results P2G system performance Average hourly capacity factors for P2G systems depending on the type of electricity supply are given in Fig. 3-a. On an average day, a P2G system directly connected to a PV power plant and wind power plant runs at capacity factors between 0%-58% and 25%e40% respectively, reaching 37%e73% for combined PV and wind supplies. The average hourly capacity factor of P2G systems supplied with grid electricity (wholesale

Reference For Switzerland [6], for Germany [45]  For Switzerland [6],  For Germany [46], [14]  Switzerland [47],  Germany [6],  For Switzerland [44],  For Germany [7,48], [6]

or somewhat more expensive hydropower) is above 60%. The annual capacity factor of P2G systems for various electricity supply options is given in Fig. 3-b. The limited availability of the solar resource constrains the operation of the electrolyser which results in an average annual capacity factor of at least 15% (lowest value across all electricity supply scenarios). Overall, a grid connection strongly improves the capacity factor. Using grid electricity and operating at nominal conditions greatly enhances the annual capacity factor (76% for wholesale-based and hydropower supply scenarios). The combination of PV and wind 15 does not offer a significant improvement compared to the wind-only scenario (the capacity factor increases by only 3% compared to the scenario involving a direct connection to wind power). The system efficiency and electricity consumption as a function of the system scale is also negatively affected by partial operation from RE generators leading to lower efficiencies (see SI Fig. 14).

Levelised cost of P2G The levelised cost displayed in Fig. 4 is given in USD per unit of thermal content of generated gas (hydrogen or methane). Here we show results for P2M systems with CO2 capture from the air since this option is not limited to any geographical requirement from the CO2 source. This configuration is the 15

We refer to the combination of two types of electricity as "electricity supply source 1"- "electricity supply source 2". For example PV-Wholesale refers to a P2G system supplied by a local PV power plant and the main grid.

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600

600

500

500

400

400 Levelised cost ($/MWht)

Levelised cost ($/MWht)

Fig. 3 e a) Average hourly capacity factor throughout the year of the electrolyser for a 10 MWe P2G system as a function of the type of electricity input in Switzerland; b) Annual capacity factor of a 10 MWe P2G system as a function of the type of electricity supply. Although not represented, the capacity factor of hydro supply is equal to wholesale electricity in Switzerland.

300

200

100

v

b)

300

200

100

0

0 P2M

P2H PV

P2M

P2H

Wind P2G system Wind system

P2M

P2H

Hydropower

P2M

P2H

Wholesale

Grid electricity PV system

P2M

P2H

PV-Wind

P2M

P2H

PV-Wholesale

P2G system Wind system

P2M

P2H

WindWholesale

P2M

P2H

Wind-PVWholesale

Grid electricity PV system

Fig. 4 e Levelised cost of generated gas for a 10 MWe P2H and P2M systems in Switzerland using CO2 captured from the air depending on the electricity supply strategy: a) individual and b) combined.

most costly option given the low CO2 concentration in the atmosphere and the unconstrained injection of methane in the natural gas grid (in contrast to hydrogen). The levelised cost of a storage system for a building application based on a lead-acid battery ranges between 750 and 1000 $/MWhe which is comparable to the 25 kWe P2G system reaching 900 $/MWht [49]. The cost of electricity supply represents 37% (wholesale

scenario) to 85% (combined PV-Wind scenario) of the total LCOES. The latter high share is due to the significant costs of building and operating RE plants as well as to the partial operation of the electrolyser (in particular for P2G systems driven by PV and wind technologies). RE systems contribute to more than 75% and 60% of the overall LCOES for P2H and P2M respectively. And combining PV and wind supply only

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marginally reduces the levelised cost regarding wind supply alone. On the other hand, combining renewable generation with grid electricity brings remarkable levelised cost reductions. The largest levelised cost reduction (47%) is observed for the addition of wholesale electricity to PV supply. Besides, a connection to the grid brings 30% and 20% reduction of LCOES compared to scenarios involving a stand-alone wind power plant and a scenario with combined wind and PV power plants respectively. While the combined RE and grid supply offers large cost reductions, the renewable content of the electricity mix is reduced and thus generates less economic value (see Section Levelised value of P2G). The levelised cost of P2M plants using CO2 from biogas plants is depicted as a function of the scale in SI Fig. 12 and SI Fig. 13. Using CO2 captured from the air increases the levelised cost by 75 $/MWht compared to a CO2 supply from a biogas plant and by 122 $/MWht compared to P2H in average regardless of the type of electricity supply. This results from the fact that CO2 capture from the air induces additional costs (investment costs and electricity consumption of the CO2 capture plant) while biogas upgrading does not induce any additional costs for CO2 supply (the CO2 content of biogas has to be reduced anyway). Fig. 5 displays the levelised cost of P2M and P2H as a function of the type of electricity supply and the size of the system. Due to the economies of scale that characterise the various components of hybrid systems (cf. SI Section 6), the LCOES steadily decreases with increasing system scales [22]. However, the positive impact of the system scale is less meaningful for grid supply (i.e. wholesale-based or hydro) and for P2M systems with CO2 capture from the air due to the modularity of this technology. The size of the RE system has a strong impact on the levelised cost of P2G. For example, the LCOES of P2G is 23% lower for a 100 kWe system as compared to a 25 kWe system and the cost decreases by the same percentage between a 100 kWe and a 1 MWe system. However, economies of scale become less significant for system scales

larger than 1 MWe and the LCOES of a P2G system supplied by a PV power plant drops by only 8% from 1 MWe to 10 MWe. For P2G systems supplied by a wind power plant, the LCOES decreases by 22% from 1 MWe to 10 MWe and then by 4% from 10 MWe to 100 MWe (larger wind farms are not assumed to offer any scale benefits). PV electricity is the costliest option for electricity supply due to the very low capacity factor as discussed above. On the other hand, wholesale and hydro electricity are the most costeffective supply options but the LCOES of P2G systems supplied by hydropower is by 10% higher than with a wholesale supply due to incorporated cost for the guarantee of origin. Building and operating PV and wind power systems to supply P2G systems leads to LCOES in the range of 490e910 $/MWht and 314e418 $/MWht respectively for P2M with CO2 captured from the air (value ranges reflect system scale). For P2H, the LCOES is in the range of 311e612 $/MWht and 192e271 $/MWht using PV and wind power systems respectively (cf. SI Fig. 11). The best economic case is achieved with wholesale electricity supply and the LCOES reaches 157 $/MWht for a 1 GWe P2M with CO2 capture from air and 83 $/MWht for a 1 GWe P2H system.

Levelised value of P2G The levelised value is also given in USD per unit of thermal content of generated gas (hydrogen or methane) in Fig. 6. Not all revenue streams are available for all types of electricity supply, e.g., emissions reduction credits are available for RE supply only (due to the share of fossil fuels in the electricity from the wholesale market illustrated in SI Fig. 6) and primary control is only possible with grid supply. The dominating contributor to the value of the produced gas is the ecological premium which represents 40% of the total LVOES with RE supply scenarios, namely PV, wind and hydropower while it accounts for 26% of the total LVOES for wholesale electricity

Fig. 5 e Levelised cost of P2M with a CO2 supply from the air as a function of the type of input electricity and system scale for Switzerland. Please cite this article in press as: Hassan A, et al., An assessment of the impacts of renewable and conventional electricity supply on the cost and value of power-to-gas, International Journal of Hydrogen Energy (2018), https://doi.org/10.1016/j.ijhydene.2018.10.026

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200

200

180

180

160

160

140

140

Levelised value [$/MWht]

Levelised value [$/MWht]

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y x x x ( 2 0 1 8 ) 1 e1 7

120 100 80 60 40

120 100 80 60 40 20

20

0

0 P2H

P2M PV

P2H

P2M

Wind

Export to the grid Emission reducƟon credits Primary control heat gas

P2H

P2M

Hydropower

P2H

P2M

Wholesale

Residual value CO2 levy O2 premium

P2H

P2M

PV-Wind

P2H

P2M

PV-Wholesale

Export to the grid Emission reducƟon credits O2 premium

P2H

P2M

P2H

WindWholesale

P2M

Wind-PVWholesale

Residual value CO2 levy heat gas

Fig. 6 e Levelised value of generated gas for a 10 MWe P2H and P2M systems in Switzerland providing various products and services depending on the electricity supply strategy: a) individual and b) combined.

supply. The economic value from selling the gas in the wholesale market accounts for 19%e33% of the LVOES among various electricity supply scenarios, with variations related to the lifetime of the project (e.g., 43 $/MWht for PV electricity supply with a lifetime of 30 years and 35 $/MWht for a wholesale-based electricity supply with a lifetime of 10 years for a 10 MWe system). Furthermore, combinations of different types of electricity supply lead to variations in the created value. For example, the LVOES is reduced by nearly 20% when grid electricity is combined with local RE supply. The evolution of the LVOES with the system scale is provided in Fig. 7 for P2M with CO2 captured from the air and in SI Fig. 11 and SI Fig. 12 for P2H and for P2M with a CO2 from biogas upgrading respectively. Variations of the levelised value with the system scale are less marked than for the LCOES because the system efficiency only increases smoothly with the scale (SI Fig. 14). The slight decrease in value with increasing scale is related to some value streams such as frequency control and oxygen which decrease with the gas yield since they are not correlated to the gas production [14].

Net present value per unit of CAPEX To assess the profitability of the various options, we present the NPV per unit of CAPEX in Fig. 8, which balances the various costs and revenues considering the time value of money. The profitability of a P2G system supplied by RE technologies is restricted by its low capacity factor. The costs incurred due to additional methanation and CO2 capture make P2M systems unprofitable for all the scenarios except for hydropower. An economic case is only achieved for three out of eight electricity supply scenarios, namely for hydropower, wholesale and e with much lower profitability - the combination of wind and wholesale electricity. The best economic case is reached with hydropower supply because it combines high capacity factor with high value associated with the 100% renewable supply. Finally, as also shown in Fig. 9, the NPV per unit of

CAPEX becomes less negative (or even positive for hydropower supply) when the size of the P2G system increases following the trends of the LCOES and LVOES.

Assessment of future capital cost and efficiency improvements Since a direct connection of P2G to PV and wind power plants (or combinations of them) do not offer any positive business case (see also a more detailed analysis for both Switzerland and Germany in SI Fig. 16), we perform a sensitivity analysis on the cost of various components including both RE generators and P2G systems to establish the impact of future cost improvements on the profitability of P2G projects. The selected time horizon is 2025. Future costs of RE and P2G technologies used in this sensitivity analysis are provided in SI Table 11 (up to 60% and 20% reduction of capital costs for PV and wind power respectively). They are based on the projected massive implementation of RE technologies in future years, followed by the deployment of P2G and other storage technologies [40,50e52]. Fig. 10 shows the evolution of the NPV per unit of CAPEX considering potential cost trajectories for P2G, PV and wind technologies. The current situation corresponds to the origin of the contour plots. The highest improvement in NPV per CAPEX (i.e. largest change towards positive values) is identified for P2H, in particular by 47% and 25% for PV and wind scenarios respectively by 2025 compared to the current situation. In this case, we can see that the slope of contours are steeper compared to P2M scenarios. Despite larger improvement for PV technology, the final NPV per CAPEX is less attractive than for wind power since the capacity factor of PV power remains a barrier to amortise capital investments. For P2M, we find that the impact of the type of CO2 supply (CO2 capture from air in Fig. 10-c and in Fig. 10-d or from a biogas plant in Fig. 10-e and in Fig. 10-f) on the change in profitability is remarkable. For P2M with CO2 captured from the air, the NPV per unit of CAPEX improves by 17% and 16%

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Fig. 7 e Levelised value of P2M with CO2 capture from the air as a function of the system scale and for various electricity supply strategies in Switzerland.

PV 4.00 Wind-PV-Wholesale

3.00

Wind

2.00 1.00 0.00 Wind-Wholesale

Hydropower

-1.00

PV-Wholesale

P2M P2H

Wholesale PV-Wind

Fig. 8 e NPV per unit of invested capital as a function of the type of electricity supply for a 10 P2H and P2M system using CO2 captured from the air in Switzerland.

with PV and wind supply by 2025 respectively compared to the current situation. However, in the case of a CO2 supply from a biogas plant, the NPV per CAPEX improves by 31% and 19% with PV and wind supply respectively compared to the current situation. The moderate improvement of profitability for P2M is related to additional costs and reduced efficiency resulting from the methanation and CO2 capture processes. Our results also show that CAPEX reductions in RE technologies will have more impact on the overall NPV per unit of CAPEX of hybrid systems than reductions in P2G system costs. However, in order to reach profitability, the CAPEX of both P2G and renewable technologies must decrease. Considering the expected cost reduction trajectories, we conclude that wind supply will continue to be more suitable in the near future (2025) due to higher capacity factor of the wind power in

comparison with PV power. For example, a 20% CAPEX reduction of wind power plants would allow for a positive economic case for P2H. This again illustrates how the economic performance of P2G is sensitive to partial operation of the electrolyser. Furthermore, the impact of electrolysis efficiency 16 on the profitability of P2G systems is assessed with Fig. 11. We utilise a 10 MWe P2G system to illustrate the sensitivity of NPV per unit of CAPEX to efficiency of both P2H and P2M systems. The system efficiency for P2M reported in the x-axis in Fig. 11-b 16

The system efficiency is defined as the ratio of hydrogen output based on the high heating value over the electricity consumed by electrolysis and general BoP during the lifetime of the project.

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Fig. 9 e Net present value of P2M with CO2 captured from the air as a function of system scale and for various electricity supply strategies in Switzerland.

Fig. 10 e Evolution of net present value per unit of CAPEX for P2G integrated into hybrid systems with renewable energy technologies based on estimations of future costs: for P2H supplied by: a) PV power and b) wind power; for P2M with a CO2 captured from the air supplied by: c) PV power and d) wind power; and for P2M with a CO2 supply from a biogas plant supplied by: e) PV power and f) wind power. includes the methanation process which explains lower values compared to P2H, however electrolysis efficiency is of the same magnitude for both P2H and P2M. Current state of the art nominal efficiency for PEM electrolysis is close to 80% (see

SI Table 1) but it can decrease below 60% due to ageing and partial operation at the end of the lifetime (see SI Fig. 14-b). As shown in Fig. 11, the impact of efficiency improvement on profitability is substantial, e.g., the NPV per CAPEX steadily

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Fig. 11 e Evolution of NPV per unit of CAPEX of a 10 MWe P2G system as a function of the electrolysis efficiency for a) P2H, b) P2M with CO2 captured from the air, and c) P2M with a CO2 supply from a biogas plant. Different trends are presented depending on the type of electricity supply.

increases with increasing efficiency and shows positive economic cases for combinations of wind and wholesale electricity supply, and PV and wholesale electricity supply. Despite potential efficiency improvements, operating a P2G plant with a stand-alone PV power plant is not economically beneficial regardless to the type of generated gas. An efficiency of 80% 17 is the break-even for a P2H system supplied only with wind electricity. Furthermore, a combination of RE (both solar and wind) and wholesale electricity supply is economically attractive above a 70% overall system efficiency. P2M with a CO2 supply from the atmosphere is unprofitable for all scenarios even when considering electrolysis efficiency improvements. For methane production with CO2 supply from a biogas plant, electrolyser efficiency above 59% and 66% are the break-even points for combination of wholesale supply electricity with wind and PV electricity respectively.

Discussion Our findings demonstrate that the type of electricity supply determines the profitability of a P2G plant by impacting both the levelised cost and levelised value of the system. Our techno-economic assessment quantifies the impact of the 17 Efficiency of P2H plant can be considered equivalent to the efficiency of the electrolyser system as the general BoP electricity consumption is relatively very small.

type of electricity supply on key parameters such as capacity factor, levelised cost and NPV. These indicators are highly relevant for various stakeholders while previous publications mainly focus on the levelised cost (see SI Table 14). Our study shows that the type of electricity supply can increase the levelised cost by a factor of 3 which is significantly larger that the values reported by previous studies for wholesale-based electricity supply [6,7,14,22,53]. Capacity factors, levelised cost, levelised value and NPV values depending on the type of electricity supply were quantified and compared for different configurations of P2G systems. The results highlight the importance of achieving a high capacity factor for the electrolyser, which strongly depends on the geographic location of the RE power plant for hybrid systems. The calculations presented in this study account for PV and wind power profiles with high temporal resolution as well as dynamic efficiencies of conversion processes (see SI Section 6 and 7) and the impact of the system scale and can therefore inform different stakeholders interested in the deployment of low carbon gas such as manufacturers, utility companies and government technology agencies. A direct connection to a RE plant is unprofitable in the short and mid-term for P2M. The still high CAPEX (see Fig. 10) and relatively low efficiency (see Fig. 11) hinder the economic attractiveness of hybrid systems integrating RE and P2G plants. In addition, the RE share in the electricity supply strongly influences the economic value of the produced gas.

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Using hydroelectricity as supply leads to the best economic case. However, we acknowledge that there are currently no economic incentives to supply electricity to P2G systems for some hydropower plants such as hydro storage. The reason for this is that the optimal operation of a P2G plant requires supply of electricity both in peak and off-peak periods to guarantee a high capacity factor, while the operators of hydro storage plants currently maximize the revenue by selling electricity only in peak periods. For example, the highest price for the Swiss wholesale market in 2016 was equal to 121 $/MWhe (i.e. the upper limit for hydropower revenue) and the price signal for optimal operation of a 10 MWe P2G system is equal to 49 $/MWhe. As a result, supplying electricity to a P2G plant would translate into a 60% loss in economic value for hydro storage plants in such periods of peak prices. Alternatively, some synergies may occur between P2G and run-ofthe-river plants which offer constant supply. Run-of-theriver and hydro storage plants accounted for 26.9% and 32.1% of the total Swiss electricity supply in 2016. Under current market conditions and in order to reach profitability, a P2G plant can also be operated with a wholesale-based supply or a combination of wind and wholesale electricity supply. Importantly, the results presented here point to cost performance targets for both renewable and P2G technologies and suggest that industry stakeholders and technology developers have a key role in the implementation of hybrid systems as part of the energy transition. Our results also suggest that P2G plants supplied by wind electricity will become profitable in the mid-term (2025) based on projected cost improvement trajectories for both P2G and wind technologies. In terms of efficiency improvements, a system efficiency of 80% is required to ensure an economic case for stand-alone wind power systems supplying P2H (such high electrolyser efficiencies are achievable in the long term (2050) according to estimates made by a previous study [48]). This threshold could also be potentially achieved using solid oxide electrolysis which offers an efficiency up to 95% [54]. The current range reported for the nominal efficiency of alkaline and PEM electrolysersis between 55% and 80% (slightly higher for PEM), but also there is some scope for improvement for PEM beyond an 80% efficiency [11,55]. On the other hand, the efficiency of a methanation reactor can go up to 90% provided that waste heat is reused [56]. We finally focus on the CO2 tax for P2G systems using renewable electricity, and in particular perform a sensitivity analysis for a 10 MWe P2M system with CO2 capture from airin SI Fig. 17. We find that 137 $/MWht is the break-even for a cost effective P2G supplied by wind power, which is 8 fold higher than the current CO2 tax of 17 $/MWht. In contrast, P2G supplied by PV electricity would not become economically viable, not even at very high CO2 levies (up to approximately 200 $/MWht). This study gives a method to assess the cost and value of P2G systems depending on the type of electricity supply, it is not without its limitaitons, which in turn call for future reserach. Additional research is needed to account for the costs of using and distributing the produced gas. For example, since the injection of hydrogen in the natural gas network is constrained, this should lead to additional monitoring costs which are not accounted for in our model. Furthermore, future

15

studies could map the geographical availability of local resources which are fed into P2G plants such as solar electricity, wind electricity and CO2 sources as well as demand centers for gas, heat and oxygen. In this study, we include CO2 supply from the atmosphere (most costly supply option) and biogas upgrading plants (free supply), thereby spanning the full cost range of CO2 supply. Future studies can go deeper and include other sources, e.g. from cement and waste incineration plants, and more synergies could be identified by coupling P2G plants with other industrial applications[12]. In addition, the value of low-carbon gas as a function of the RE content of electricity supply strongly influence the economics of combined systems and is therefore recommended as subject of future research. Finally, future climate policy may well lead to more constrained environmental regulations and a higher carbon tax and/or increased value of emission reduction credits, thereby improving the economic value of low carbon gas generation.

Conclusions The implications of the type of electricity supply on the techno-economic behaviour of P2G systems is investigated in this study. This is done in two steps: we firstly compare various electricity supply options (PV, wind, hydropower and wholesale-based supply and combinations among individual options) and then create hybrid systems incorporating P2G systems located in selected regions in Switzerland and Germany. Our analysis includes various applications and services to maximise the value of P2G as well as different scales of deployment. Our analysis confirms electricity supply as a major contributor to the total cost of P2G (37%e85%) but also shows that the electricity supply choice and in particular the share of renewable energy strongly impacts the value of P2G (the LVOES decreases by 20% when the P2G facility is operated using electricity from the wholesale market). In order to reach profitability, the operation of P2G systems should not be constrained by the availability of solar and wind resources and combining different electricity supply sources is necessary. For example, a capacity factor of 15% of PV power is a strong limiting factor to reach profitability. We show that hydropower use for hydrogen production could be a very attractive business case, followed by hydrogen production using electricity sourced from the wholesale market (the best economic case uses hydropower and offers a NPV per unit of CAPEX of 3.7). Methane production using electricity from hydropower is at the threshold of economic viability, and likewise hydrogen produced using a combination of wind power and wholesale electricity on the MWe scale (larger than 10 MWe for P2H and 100 MWe for P2M with CO2 from a biogas plant). However, P2M is not economically viable at the moment with any electricity supply apart from hydropower. The economic viability can be improved by combining solar and wind power with electricity from the wholesale market. Economic viability could also be in reach for wind power plants which offer a capacity factor higher than 30% and considering a reduction of CAPEX by 20% (expected by 2025). Furthermore, our results suggest that the economic

Please cite this article in press as: Hassan A, et al., An assessment of the impacts of renewable and conventional electricity supply on the cost and value of power-to-gas, International Journal of Hydrogen Energy (2018), https://doi.org/10.1016/j.ijhydene.2018.10.026

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attractiveness of P2G systems connected to RE plants is more sensitive to scale for than P2G systems supplied with wholesale electricity. For a large-scale (e.g., 100 MWe deployed at the national scale), the levelised cost including RE supply ranges between 200 V/MWht and 300 V/MWht for P2M with CO2 supply from air while it increases by a factor of two and three for systems installed in buildings (e.g., 25 kWe) and districts (e.g., 1 MWe) respectively.” The cost trajectories considered in this study through a sensitivity analysis reveal the important role of cost reduction for renewable energy technologies. It is also found that profitability is also highly sensitive to the electrolyser system efficiency and specific break-event points are reported for P2H and P2M. Therefore, these findings can support the development of roadmaps for the future implementation of P2G and inform utility companies, policy makers and manufacturers. Given the importance of the type of electricity supply and the need for optimal supply strategies, many utility companies are in a good position to run P2G projects since they operate different types of power plants and also have a gas business unit.

Acknowledgements This research is financially supported by the Swiss Innovation Agency Innosuisse and is part of the Swiss Competence Center for Energy Research SCCER HaE. The authors are also grateful to the wind data and information given by Services
ve (SIG) in the context of their support of Industriels de Gene the Chair for Energy Efficiency at University of Geneva.

Appendix A. Supplementary data Supplementary data to this article can be found online at https://doi.org/10.1016/j.ijhydene.2018.10.026.

references

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Please cite this article in press as: Hassan A, et al., An assessment of the impacts of renewable and conventional electricity supply on the cost and value of power-to-gas, International Journal of Hydrogen Energy (2018), https://doi.org/10.1016/j.ijhydene.2018.10.026