The potential role of power-to-gas. in the e-highway2050 study. Public Version OIL & GAS DNV GL 2017

Transcription

1 The potential role of power-to-gas OIL & GAS in the e-highway25 study Public Version 1

2 Report details The Potential role of Power-to-Gas in the e-highway25 study Public version For: European Power to Gas Platform Date of issue: Monday, September 18, 217 DNV GL Oil & Gas Managed by: Prepared by: Paula Schulze Project Manager Pieter van der Wijk Ivan Wapstra Maurice Vos Bieuwe Pruiksma Wim van der Veen Signature Signature Verified by: Team members Albert van den Noort Quality Assurance Signature Approved by: Johan Knijp Project Sponsor Signature Key words: Power-to-gas, e-highway25, PLEXOS, modelling, system cost analysis, renewable energy, hydrogen 2

3 Executive summary I Background and approach The pan-european energy system is faced with the enormous challenge to decarbonize almost completely until 25. The expected shift towards renewable energies calls for extended transmission capacity and innovations that allow a decoupling of electricity production and demand. Power-to-gas (PtG) has the potential to become a sustainable and realistic solution for this need; in times of excess generation electricity is transformed into hydrogen which can be stored, reconverted into electricity or supplied to other sectors such as chemical industry and the transportation sector. The European Power to Gas Platform is a joint industry initiative with the goal to explore the viability of power-to-gas in Europe. After the publication of the e-highway25 study in 215, a study with the overarching objective to map out a pan-european electricity transmission network capable of meeting European energy needs between 22 and 25, the Platform members identified a need to investigate whether there is a potential of power-to-gas in this context. DNV GL which is chairing the Platform was engaged to perform this study in close collaboration with the partners. The present study is one of the first studies addressing the economic and system implications of using large scale power-to-gas installations in a purely renewables based European energy system. The analysis was done with the objective to assess whether or not power-to-gas could be a viable option to further optimize a set of grid extensions proposed by the 1% RES scenario of the e-highway25 study (reference scenario). In order to reach this objective, one interconnection was chosen as object of study from the reference (1% RES) scenario form the e-highway25 study and compared to number of power-to-gas cases in terms of total system costs. The choice for the 14 GW Netherlands-Norway interconnector was, along with the favourable hydrogen market in the Rotterdam area, based on assumptions with respect to the functionality of the interconnector, namely to transmit electricity over a large distance and facilitate (cheap) electricity storage in Norway. A substitution of the interconnector by power-to-gas would therefore transfer these functionalities to the power-to-gas installation and related gas infrastructure. In order to be able to perform the analysis, the 1% RES scenario of the e-highway25 study as well as the power-to-gas cases were modelled with DNV GL s European Market Model (developed in PLEXOS) simulating real-world dispatch, following the least cost principle under consideration of dynamic power plant constraints. With the help of the model the optimal unit commitment and economic dispatch of the generation assets were determined; the resulting electricity generation costs for Europe formed an important input parameter for the system cost analysis for the 1% RES e-highway25 scenario and the power-to-gas cases. In total seven power-to-gas cases were modelled and compared in terms of system costs: 1. Substituting 14 GW of the planned grid extension by a 14 GW power-to-gas plant located in the Netherlands. The produced hydrogen is either re-electrified in a gas-to-power installation (case B) or used in industry (case C) 2. Substituting 1 GW of the planned 14 GW grid extension by a 1 GW power-to-gas plant located in the Netherlands. The produced hydrogen is either re-electrified in a gas-to-power installation (case 1B) or used in industry (case 1C) 3. Reducing the hydropower capacity in Norway by ~4% and substituting the planned 14 GW grid extension by a PtG installation in the Netherlands. The produced hydrogen is either re-electrified in a gas-to-power installation (case 2C) or used in industry (case 2D) 4. Substituting the 14 GW grid extension by a PtG installation in Norway. The produced hydrogen is transported via pipeline to the Netherlands and re-electrified in a gas-to-power installation (case 3A). 3

4 Executive summary II Results & Conclusions During the electricity market simulations it became apparent that the 14 GW NL-NO interconnection is mainly used for transporting low-cost hydropower generated in Norway to the Netherlands and other parts of Northwest Europe. When taking away the proposed capacity expansion of the interconnection, the Netherlands and surrounding countries can no longer benefit from the cheap electricity supply resulting in an (in some cases massive) increase in overall electricity generation costs in Northwest Europe as expensive back-up capacity needed to be called upon to meet electricity demand in this region. The cases that showed best results in terms of system costs were therefore those not obstructing the supply with hydropower to Northwest Europe. The 1% RES scenario of the e-highway25 study, however, assumes an increase in Norwegian (pumped) hydropower capacity from currently 3 GW to 87 GW in 25. Although there is a theoretic potential for these large capacities of hydropower in Norway it is questionable if this potential is going to be exploited to that extend given the environmental concerns and possible social resistance related to this kind of projects. A comparison of different Norwegian literature sources led to the conclusion that 53 GW installed hydropower capacity is more realistic. Because Norwegian hydropower has such a big impact on European electricity generation costs, an altered reference case was also modelled. Reducing Norwegian hydropower capacity to 53 GW resulted in 1% higher generation costs throughout Europe. infrastructure can be used for hydrogen transport; the additional transmission capacity allows for an optimized use of produced renewable electricity. The major conclusion drawn form this study are the following: 1. In a highly interconnected electricity supply system as proposed by the 1% RES scenario of the e-highway25 study, there is a amount of curtailed (renewable) electricity. Power-to-gas storage leads to higher deployment of installed solar and wind power capacities. 2. Conversion of the curtailed electricity in PtG installations leads to lower electricity generation costs across Europe as less expensive back-up generation capacity needs to be called upon. 3. The use of power-to-gas as large-scale electricity storage means provides more economic benefits than using power-to-gas as green hydrogen production facility for industries. 4. Preliminary results of the analysis on transmitting electricity in the form of hydrogen through gas pipelines are encouraging to consider power-to-gas in combination with the existing gas infrastructure as an interesting alternative/complement to subsea cables. Four out of seven analyzed PtG cases showed lower total system costs compared to the 1% RES e-highway25 reference scenario. Despite the low cycle efficiency of ~45%, power-to-gas turned out to be an economically beneficial storage technology for low-cost electricity from hydropower plants in Norway and otherwise curtailed electricity from wind and solar generation capacity. When the hydrogen is reelectrified in gas-to-power installations, expensive back-up capacities do not need to be called upon reducing overall electricity generation costs throughout Europe. Also for long-distance transmission of energy, power-to-gas resulted to be an interesting option in a situation where existing natural gas 4

5 Executive summary III Results Change in total annual system costs compared to the alternative solution (in MEUR) Results of e-highway25 (1% RES) assumptions Results of PtG alternative PtG to Power PtG to Product Case C Case D Replacement of 14 GW electricity cable by PtG installation 1% RES PtG in NL Case 1B Case 1C Replacement of 1 GW electricity cable by PtG installation 1% RES PtG in NL PtG lowest costs Replacement of 14 GW electricity cable by PtG considering reduced hydrostorage in Norway Case 2C 1% RES PtG in NL 963 Case 2D Replacement of 14 GW electricity cable by a PtG in Norway, transport of H 2 to the Netherlands, and electricity generation by fuel cell in the Netherlands Case 3A 1% RES PtG in NO 99 Not investigated 5

6 Executive summary IV Final remarks & Recommendations Final remarks When evaluating the results of this study, several aspects have to be beard in mind: This study assumed that natural gas infrastructure and underground storage facilities are suitable for handling hydrogen. No costs for (eventually required) gas infrastructure modifications were taken into account in the total system cost analysis. Further analysis should clarify aspects such as the impact on safety (e.g. risk contours), pipeline integrity (materials, age, pressure fluctuations), pipeline capacity, and interoperability (connection with other networks and end users), as well as eventual costs for infrastructure adjustments. With approximately 4% less hydropower generation capacity in Norway, it is most likely that not all of the 14.7 GW grid extension between the Netherlands and Norway is realized. However, this study did not adjust for that. recommended to perform a study with the objective to quantify potential benefits in terms of avoided infrastructure costs when applying power-to-gas on distribution level. Because of the above mentioned restrictions of this study, we would like to emphasize that the cost figures should be interpreted as indicative instead of absolute. Recommendations The PtG-to-Product cases were considering hydrogen application in industry. We recommend to perform a similar study for hydrogen use in the transportation sector. This study only focussed on one particular interconnector of the European power grid. We recommend to perform a similar study for a set of interconnectors For the long-distance energy transmission case this study assumed an existing gas infrastructure that can absorb the hydrogen produced by PtG installations. We recommend to perform a similar study for far-offshore / remote energy islands which need a connection to the shore and investigate whether power cables or gas pipelines are the better option. The analysis was done purely on transmission level; considering power-to-gas on distribution level would probably reduce the required transmission grid extensions significantly. It is therefore 6

7 Table of Content CHAPTER SECTION PAGE Introduction Methodology 1. Analysis of 1% RES scenario of the e-highway25 study 2. Analysis of PtG cases 3. Comparison of total system cost Conclusions Annex Background & Objective About e-highway25 Scope Approach Description Electricity Market Modelling Description Total System Cost Calculation General introduction to the 1% RES-scenario Situation Netherlands and Norway Analysis of the gas demand in 25 Results Case A and B Summary and interpretation of the results Case definition Results Case C and D Results Case 1A 1C Results analysis potential hydropower capacity Norway Results Case 2A 2D Results Case 3A Identification of relevant cost elements Case C and D Case 1B and 1C Case 2C and 2D Case 3A Summary of results General conclusion Final Remarks & Recommendations Annex A: Description Electricity Market Modelling Annex B: Assumptions generation costs per type of renewable energy source Annex C: Modelling 1% RES scenario without the NO-NL cable (Case B) Annex D: Glossary

8 Introduction Background & Objective Background The pan-european energy system is faced with the enormous challenge to decarbonise almost completely until 25. The expected shift towards renewable energies calls for extended transmission capacity and innovations that allow a decoupling of electricity production and demand. Among the various options such as more cross-border interconnections, electricity storage facilities, and smart grids to manage demand, power-to-gas (PtG) has the potential to become a sustainable and realistic solution for this need. Optimizing the energy system towards flexibility requires industries to approach electricity and gas as energy carriers that can be converted from one to the other. Both energy carriers have strengths and weaknesses and can be complementary to each other. Instead of separate gas and electricity systems a more holistic and integrated view might be beneficial for Europe s energy system. Power-to-gas The power-to-gas concept is about converting electrical power (for instance in times of excess generation) into a gaseous energy carrier like hydrogen and/or methane. This process takes place in an electrolysis cell where water molecules are split into hydrogen and oxygen by applying an electric current. Through this process, electrical energy is converted to chemical energy in the form of hydrogen. The hydrogen can be either used directly as feedstock or fuel in the industrial or transportation sector, transmitted through the natural gas network via blending (and stored in gas storages) or further converted to methane via a methanation process. In this study, only the production of hydrogen is considered. DNV GL chairs the European Power to Gas Platform and is repeatedly engaged to perform studies when knowledge gaps are identified. After the publication of the e-highway25 study in 215, a study with the overarching objective to map out a pan-european electricity transmission network capable of meeting European energy needs between 22 and 25, the Platform members identified a need to investigate whether there is a potential of power-to-gas in this context. Objective The objective of this study was to assess whether or not power-to-gas could be a viable option to further optimize the set of grid extensions proposed by the e-highway25 study. In order to reach this objective, the techno-economic impact is evaluated for the situation that parts of the planned grid extension between Norway and the Netherlands, as described in the e-highway25 study, are substituted by a power-togas facility. This assessment focuses on the following functionalities of power-to-gas: balancing the electricity grid (by consuming excess electricity in times of overgeneration), storage of energy and back-up generation in times of electricity shortages, and transmission of energy over larger distances. Assignment The European Power to Gas Platform (hereafter called the Platform ) is a joint industry initiative, based on an integrated network of stakeholders, which aims to explore the viability of power-to-gas in Europe. The participating partners within the Platform identified a need for more insight into the potential of power-to-gas in comparison to (planned) electricity transmission grid expansions. 8

9 Introduction About e-highway25 About e-highway25 At the end of 215 the results of e-highway25 were published [1]. This study was carried out by a consortium of 28 partners throughout Europe, including TSOs, industrial associations, academics, consultants and one NGO. The project was financially supported by the European Commission. The overarching objective of e-highway25 was the planning of a pan-european electricity transmission network, including possible highways capable of meeting European energy needs between 22 and 25. Five challenging future power system scenarios have been created to frame the e-highway25 project. Simulations performed during the study of the scenarios resulted in the electricity transmission requirements identified for these different scenarios. The outcomes of the simulations were optimized towards lowest system costs. Most reinforcements were identified (up to 4 b of investment costs) for scenarios with the highest penetration of renewable generation. However, they are also those with the highest profitability brought by the grid development. e-highway25 and Power-to-Gas The e-highway25 consortium published an additional note contributing to Task 3.2 (technology assessment) of the project [2]. This note provides an assessment of and outlook for the power-to-gas technology. It was concluded that: Several business cases could be considered based on power-to-gas plants thanks to the technical flexibility of water electrolysis and methanation technologies. With regard to the e-highway25 context, power-to-gas should be considered as an option creating additional flexibility for the transmission system in an alternative manner, most likely complementary to the grid architectures resulting from the project by allowing massive storage of energy in the existing hydrogen and natural gas networks (this chemical energy could also be used in various applications including transport and energy production). The e-highway25 study focuses on transmission solutions in the electricity domain to enable demand and supply balancing and long distance transport of energy. Other options for additional flexibility to cater for more variable renewable energy were only discussed at a high-level. Power-to-gas for instance is not included in the e- Highway25 analysis. Sources and notes: 1. e-highway report highway25.eu/fileadmin/documents/e_highway25_booklet.pdf 2. e-highway 25 Note on PtG highway25.eu/fileadmin/documents/results/d3/note_on_power_to_gas.pdf 9

10 Introduction Scope Scope Within the scope of this study we assessed the potential for power-togas in comparison with planned electricity grid extensions, as proposed in the e-highway25 study. During the definition phase of the project we selected the 1% RES (Renewable Energy Sources) scenario and its identified transmission requirements as a reference case. Within the reference case the 14 GW transmission line extension between Norway (Bergen) and the Netherlands (Rotterdam) was chosen as object of study. Our choice was based on a number of assumptions. In principle, a power-to-gas installation is likely to be an attractive solution in locations with high share of (intermittent) renewable electricity generation, no storage capacity as hydropower and a market for the produced hydrogen. The costs of a PtG plant are driven by several location dependent variables such as the access to electric and gas networks, access to water supplies and storage sites as well as proximity to hydrogen markets. Rotterdam meets all the above mentioned requirements as the Rotterdam area is highly industrialized with high capacity connections to the Dutch electricity and gas grid and dedicated local hydrogen networks. Electricity market simulation As part of this exercise the DNV GL electricity market model has been used. This allowed for a detailed description of the market exchanges (prices, flows, utilization rates etc.) between the countries. Energy System Cost comparison In order to compare the cost for both the PtG solution or the expansion of the electricity grid by use of a subsea cable, this study has identified and assessed all relevant cost components. The input parameters, conditions and the output have been shared with the steering committee in a transparent way, so the basis of this study has been properly scrutinized and the used input data was agreed on. In total four different power-to-gas cases were analysed on system behavior and system costs and subsequently compared to the reference case. In three PtG cases, a differentiation was made in potential PtG pathways: A. PtG-to-Power. In this option PtG serves as an electricity storage facility. This entails that hydrogen is locally stored in times of high electricity generation from renewable sources,s tored and used to produce electricity in times of low electricity generation from renewable sources. B. PtG-to-Product. In this option the PtG facility provides balancing services by consuming power in periods of excess electricity generation. Hydrogen is produced and supplied to local industries. 1

11 Methodology CHAPTER SECTION PAGE Introduction Methodology 1. Analysis of 1% RES scenario of the e-highway25 study 2. Analysis of PtG cases 3. Comparison of total system cost Conclusions Annex Background & Objective About e-highway25 Scope Approach Description Electricity Market Modelling Description Total System Cost Calculation General introduction to the 1% RES-scenario Situation Netherlands and Norway Analysis of the gas demand in 25 Results Case A and B Summary and interpretation of the results Case definition Results Case C and D Results Case 1A 1C Results analysis potential hydropower capacity Norway Results Case 2A 2D Results Case 3A Identification of relevant cost elements Case C and D Case 1B and 1C Case 2C and 2D Case 3A Summary of results General conclusion Final Remarks & Recommendations Annex A: Description Electricity Market Modelling Annex B: Assumptions generation costs per type of renewable energy source Annex C: Modelling 1% RES scenario without the NO-NL cable (Case B) Annex D: Glossary

12 Methodology Approach Introduction We have assessed the potential of power-to-gas in a purely renewables based energy system which is subject to a lot of challenges in terms of fluctuation of electricity generation. In order to guarantee security of supply, energy storage systems such as power-to-gas will play a crucial role. Selected case The planned 14 GW connection between Rotterdam (the Netherlands) and Bergen (Norway) is compared with a situation whereby the proposed capacity extension via subsea cable is completely replaced by a power-to-gas installation located in the Netherlands. The location in Rotterdam has been selected because of the anticipated high demand center for both hydrogen (industrial cluster, including refinery industry) and electricity. Phased approach This project was conducted in three consecutive project steps. The figure below provides a visual representation of the 3 main steps and activities performed within each step. Step 1. Analysis e-highway 25 results In this first step DNV GL analyzed the approach and results as described under the scenarios of the e-highway25 study. Afterwards, DNV GL modelled the e-highway25 scenario in its electricity market model. The results with a focus on the situation in Norway and the Netherlands were then reported. Step 2. Definition and analysis of the PtG alternative DNV GL defined a number of PtG cases which were subsequently modelled. Each power-to-gas case was designed to in a way that the power-to-gas facility took over a certain functionalities of the interconnection (providing balancing services, facilitating storage, longdistance energy transmission). Step 3. Comparison total system cost In order to compare the cost for both the PtG solution and the planned expansion of the electricity grid, DNV GL identified all relevant cost components and calculated the (change in) system costs for each case. Finally the (change in) total system costs was compared for the powerto-gas case and the 1% RES reference case. 1. Analysis of 1% RES scenario of e-highway25 2. Analysis of PtG cases 3. Comparison of total system costs 12

13 Methodology Approach The e-highway 25 study considered two siloed electricity and gas markets. Figure 1 illustrates this situation with the electricity market on the top and the natural gas market on the bottom. In order to be able to assess the merits of PtG as an alternative we examined the replacement of (parts of) the planned capacity extension of the Norway-Netherlands interconnector by a PtG facility (Figure 2). F1: Situation as in e-highway25 F2: Introduction of power-to-gas into the energy system Biomass Wind & Solar Biomass Wind & Solar Electricity Generation Electricity Generation Capacity extension Interconnector Norway Netherlands Electricity market Capacity extension Interconnector Norway Netherlands Electricity market Gas-to-power Facility Power-to-gas Facility Hydrogen storage Hydrogen storage Natural gas market Steam reformers H 2 market Natural gas market Steam reformers H 2 market Gas suppliers Gas suppliers 13

14 Methodology Description Electricity Market Modelling DNV GL Electricity Market Modelling For the analysis in this study we have used DNV GL s European Market Model (developed in PLEXOS) to simulate electricity market flows under the chosen scenarios and assess the utilization of these lines therein. DNV GL s European Market Model simulates real-world dispatch, following the least cost principle under consideration of dynamic power plant constraints. The model uses DNV GL s knowledge of the technical and commercial aspects of electricity generation and power markets. Combining our knowledge with the PLEXOS modelling framework provides a robust and validated tool for wide range of analyses such as support in the operations, business case assessment, portfolio optimization as well as roadmaps of the European electricity market infrastructure and regulation. Generators are dispatched in each hour according to their short-run marginal costs ( cheapest generators first ). However, hourly generation is subject to individual flexibility constraints like ramp rates, minimal stable level, start costs, scheduled maintenance and random outages and minimum up- and down-times. Furthermore, individual resource constraints like water availability of hydropower plants, solar and wind availability for variable renewables, or minimum generation levels of combined heat and power (CHP) plants are properly accommodated in the model set-up. Electricity exchanges between markets are optimised by the model in order to minimise total generation cost of the European interconnected power system (i.e. perfect market coupling). Hourly electricity wholesale prices are derived based on the (marginal) costs of supply in each hour. The model determines the optimal unit commitment and economic dispatch of the generation assets (including hydro reservoir, energy storage, demand side management, PtG facilities in the investigated alternatives). The goal of the optimization is to minimize total generation costs within Europe, assuming that generation capacities bid their electricity at their marginal costs. This mimics the situation of perfect competition. More information on the model can be found in Annex A. The model contains core countries for which the data input is more detailed compared to non-core countries for which data is included in a more aggregated level. F3: Level of detail in modelling for different EU countries Core-Country Core-Country Non-Core Country Non-Core Country Use in this project DNV GL has entered the 1% RES scenario of the e-highway25 study in its Electricity market model based on the available information: generation capacities per generation type, variable generation costs, interconnection capacities and demand profiles. Where necessary, DNV GL has complemented the model inputs with own estimates (e.g. detailed characteristics of generation technologies, hydro profiles, wind and solar availability profiles). 14

15 Methodology Description total system cost calculation Total System Cost Comparison The comparison between the 1% RES scenario of the e-highway study and the power-to-gas cases is done on the basis of the total system costs of each case. Under this approach, the system costs unique to each case are compared to each other, i.e. as each option (electricity cables or PtG) shares certain costs with other options, only relevant differences between costs are identified (change in system costs). The lowest cost alternative is the preferred one from an economic point of view. Identification of cost unique to a case For each case, the unique costs were identified which had to be included in the system cost analysis. For instance, the cost of a powerto-gas installation is unique to a PtG case and these costs are thus added to the system costs of that PtG case. Conversely, the cost of the electricity cable between the Netherlands and Norway are unique to the reference case, hence these costs are added to the system costs of that case. Clearly, these direct costs are easier to identify. However, the different cases also have indirect costs. The most prevalent example of indirect costs is the potential increase in total production costs. One alternative may increase the costs of generating electricity (e.g. increased use of biomass generation, or reserve requirements). These costs are labelled as indirect as they are a secondary effect. Nevertheless, they are taken into account in a similar way as direct costs such as installing the PtG facility or the subsea cable. However, using the total system cost calculation, this benefit of less required hydrostorage capacity is translated into an additional need for hydrostorage in the reference case (compared to the PtG alternative) and therefore is an additional cost item. Thus, benefits of one alternative are converted into cost for the other alternative in order to enable a comparison in terms of system costs. This is shown schematically in the Figure 4. Actual cost levels are based on: Market simulations, which provide part of the costs such as e.g. the costs of electricity produced. Costs are determined based on for instance capacity or volume requirements resulting from the market simulations. The actual costs are calculated by using estimates of specific investment and operational costs. All capital costs are annualized in order to compare the both scenarios using a discount rate of 4.5% in real terms (reference year is 217). F4: Schematic representation of benefits translated into cost Total cost: 15 Total cost: 11 Benefits of one alternative are seen as costs to the other Besides costs, each case may also result in certain benefits. However, under the total system cost calculation, these benefits are assigned as costs for the reference case. For instance, in the 1% RES reference case, flexibility is provided by hydrostorage in Norway. However, the PtG installation also provides for energy storage thereby introducing flexibility into the system. Therefore, it is likely that under the PtG alternative less hydrostorage is required. In principle, the reduction in the need for hydrostorage can be seen as a benefit to the PtG case PtG Electricity cables Benefits Direct costs Indirect costs 15

16 Analysis of e-highway25 CHAPTER SECTION PAGE Introduction Methodology 1. Analysis of 1% RES scenario of the e-highway25 study 2. Analysis of PtG cases 3. Comparison of total system cost Conclusions Annex Background & Objective About e-highway25 Scope Approach Description Electricity Market Modelling Description Total System Cost Calculation General introduction to the 1% RES-scenario Situation Netherlands and Norway Analysis of the gas demand in 25 Results Case A and B Summary and interpretation of the results Case definition Results Case C and D Results Case 1A 1C Results analysis potential hydropower capacity Norway Results Case 2A 2D Results Case 3A Identification of relevant cost elements Case C and D Case 1B and 1C Case 2C and 2D Case 3A Summary of results General conclusion Final Remarks & Recommendations Annex A: Description Electricity Market Modelling Annex B: Assumptions generation costs per type of renewable energy source Annex C: Modelling 1% RES scenario without the NO-NL cable (Case B) Annex D: Glossary

17 1. Analysis of 1% RES scenario of e-highway25 General introduction to the 1% RES-scenario E-Highway25 has identified an invariant set of transmission requirements in consistency and in continuity with the Ten-Year Network Development Plan conducted by ENTSO-E. The 23 targets and 25 long term goals have a direct impact on European energy infrastructures, and more specifically on the pan-european electrical power system. The proposed architectures integrate the present pan- European transmission grid. Several scenarios have been used by the e-highway25 study to cover the full spectrum of potential future impacts on the European transmission grid. These various contexts resulted in significantly different assumptions for generation, electricity demand, storage, and power exchanges. For each scenario, generation capacities are defined in Europe to meet the demand, consistent with each of the scenario backgrounds. The annual electricity demand for all European (33) countries are considered for each scenario. The demand assessment involved some of the scenario criteria, i.e. GDP and population growth, the use of electricity for heating, industry and transportation and energy efficiency measures. For each scenario, generation capacities have been defined in Europe to meet the demand, consistent with each of the scenario backgrounds. F5: Installed Generation Capacity in Europe 25 2 GW installed Wind Solar Biomass Gas Coal Lignite Nuclear Oil Mixed Hydro F6: Electricity Generation in Europe in 25 For this study the 1% RES scenario from the e-highway25 study has been selected. This scenario relies only on Renewable Energy Sources (RES). Accordingly, nuclear and fossil energy generation are excluded. In addition, high GDP growth, high electrification and high energy efficiency are assumed, while technologies like storage and demand side management are widespread. This leads to the following picture (see also figure 5 and 6): between 214 and 25 the total installed generation capacity increases from 1, GW to 2,25 GW and the demand for and generation of electricity increases from about 3,25 TWh to 4,4 TWh. In 25 there is still a (back-up) generation capacity of 75GW biogas; this is considered as biomass. 17

18 1. Analysis of 1% RES scenario of e-highway25 Situation Netherlands and Norway The e-highway25 1% RES scenario presents additional transmission capacity requirements of 14 GW between the Netherlands and Norway compared to the starting grid. The current interconnection capacity (NorNed cable) between the two countries is.7 GW. F7: European Electricity Interconnection 1% RES Accordingly, the cross-border capacity used in the 1% RES scenario is 14.7 GW. The interconnection capacity of the different PtG cases analysed in this study varies between.7 GW and 13.7 GW. The e-highway25 study estimates that the grid reinforcement of 14 GW requires an annual lifecycle costs of 1,417 M /a. This corresponds to a present value of the lifecycle costs of 28.8 billion Euro, assuming a discount rate of 4.5% and an operative life duration of 4 years. The graphs below show the development in the demand for electricity and the installed generation capacity in the Netherlands and Norway, as well as the generation costs per generation technology. These developments are included in the model to perform the simulations. F8: Electricity Demand in NL and NO F9: Installed capacities in NL and NO 18

19 1. Analysis of 1% RES scenario of e-highway25 Analysis of the gas demand in 25 The PtG cases were build on the assumption of an existing gas infrastructure in 25 becoming available for the transportation of hydrogen. A prerequisite for this situation is a continued gas demand in 25. The e-highway 25 1% RES scenario was analysed on the assumed developments with respect to use of energy carriers in the sectors power generation, transport and residential heat demand in order to draw conclusion on the remaining gas demand. Power generation The 1% RES scenario assumes that in 25, electricity is fully generated by renewable energy sources. Hence, no gas demand here. Transport A high rate of electrification is assumed (9%). For this analysis we assumed that oil-based transport is to be substituted first by electric vehicles. Thus, no reduction in natural gas use for transport is assumed. As the current gas demand in transport is.5-1.% of the total gas demand, the overall impact of this assumption is small. Heat demand in residential, commercial and industrial sector In the 1% RES scenario of the e-highway25 study, heat demand in Europe is expected to be influenced by several developments: the residential and commercial sector). We assume that new heat demand is fully electric in the 1% RES scenario; thus, gas demand for heating is not envisaged to grow due to this development. In summary, gas demand for heating purposes is reduced by electrification and secondly by the increase in energy efficiency. This results in a strong decline in gas demand for heating on a European scale of around 8%. F1: European gas demand in 21 and 25 [TWh/year] % Residential Commercial Industry (heat) Industry (process) Industry (feedstock) Transport Power generation Energy efficiency is expected to reduce heat demand by 45% towards 25. We assume that gas demand used for heating is reduced with this amount as well: Thus towards 25, gas demand for heating is reduced by 45% to account for an increase in energy efficiency The e-highway25 scenario assumes a further electrification of heat demand. For our analysis, we assumed that gas demand for heating in these sectors is reduced by the amount of electrification. Hence, we assume that the heat demand currently not supplied by electricity is electrified equally distributed among all energy carriers. E-Highway25 assumes growth in heat demand due to GDP growth (increased demand in industry) and population (increased demand in Note: 21 served as the basis for the ehighway study. This analysis therefore departs from the same year, although more recent data are available. 19

20 1. Analysis of 1% RES scenario of e-highway25 Analysis of the gas demand in 25 The charts below show the impact of the assumptions of the 1%RES scenario on the European gas demand on a country-by-country basis. In all countries, gas demand is set to reduce significantly. For this study, the outcomes for the Netherlands are of importance showing F11: Gas Demand in 21 [TWh/year] Belgium 22 Bulgaria 3 Czech Republic 13 Denmark 57 Germany 981 Estonia 7 Ireland 6 Greece 42 Spain 4 France 545 Croatia 33 Italy 873 Cyprus Latvia 19 Lithuania 32 Luxembourg 15 Hungary 125 Malta Netherlands 57 Austria 15 Poland 163 Portugal 58 Romania 135 Slovenia 11 Slovakia 65 Finland 5 Sweden 19 United Kingdom 1.86 Iceland Norway 1 Montenegro FYROM 1 Albania Serbia 24 Turkey 46 Bosnia & H. 3 Kosovo Moldova 29 Ukraine 75 that there will be a remaining annual gas demand of approximately 12 TWh (the reduction in gas demand with respect to 21 is therefore ~75%). The remaining infrastructure to transport the gas is assumed to become available for hydrogen transport in the power-to-gas cases. F12: Gas Demand in 25 [TWh/year] Belgium 58 Bulgaria 1 Czech Republic 28 Denmark 1 Germany 257 Estonia 2 Ireland 6 Greece 8 Spain 67 France 143 Croatia 12 Italy 162 Cyprus Latvia 2 Lithuania 1 Luxembourg 2 Hungary 3 Malta Netherlands 12 Austria 25 Poland 59 Portugal 6 Romania 39 Slovenia 3 Slovakia 21 Finland 5 Sweden 4 United Kingdom 215 Iceland Norway 25 Montenegro FYROM Albania Serbia 8 Turkey 56 Bosnia & H. 1 Kosovo Moldova 3 Ukraine 234 Residential Commercial Industry (heat) Industry (process) Industry (feedstock) Transport Power generation 2

21 1. Analysis of 1% RES scenario of e-highway25 Results Case A reference scenario The e-highway25 1% RES scenario was simulated in DNV GL s electricity market model (Case A). The results of the flow through the NL-NO interconnector are shown in Figure 13. It became apparent that the interconnector is predominantly used to transport low-cost hydropower from Norway to continental Europe: 14 TWh of electricity flows from NL to NO, 71 TWh from NO to NL. Especially in the winterperiod, there is an almost continuous flow from Norway to Netherlands. In summer, there is an increased flow in both directions due to solar electricity generation in Europe. The total electricity generation costs throughout Europe amount to 68,451 M /yr (see also Table 1). The assumptions on the costs of generation per type of renewable energy can be found in Annex B. Removing the 14 GW additional interconnector capacity Subsequently, the e-highway25 1% RES scenario was simulated again with a variation, namely without the additional 14 GW interconnector capacity to explore the impact on the energy system (Case B). Accordingly, the cross-border capacity between the two countries is limited to.7 GW. The results show that the reduced interconnection capacity leads to a decrease of almost 5 TWh in electricity generation in Norway (see Figure 14). This can be explained by the fact that less export capacity is is available. This decrease in Norwegian electricity generation is compensated by an increase in generation in most countries across Europe, with significant contributions from Belgium, Germany, France, Spain, Italy and UK. The change in national generation is reflected in changes in the cross-border flows, as a result of removing the 14 GW interconnection capacity. More detailed information on the cross border flows can be found in Annex B. Furthermore, the reduction of the NL-NO interconnection capacity to.7 GW provokes curtailment of 25 TWh of wind and solar power in Europe. TWh generation F13: Flow through the NL-NO interconnector (Case A) Energy flow through NL-NO interconnection (flow from NL to NO is positive) (MWh) % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% % of hour in a year F14: Change in electricity generation OAdue to 14 GW reduced interconnector capacity (Case B) in TWh/yr AT BE CH CZ DE DK ES FI FR HU IE IT NI NL NO PL PT SE SI SK UK T1: Generation costs (M ) A Europe 68,451 NO 52 NL

22 1. Analysis of 1% RES scenario of e-highway25 Results Case B Impact of 14 GW less IC capacity By removing the additional 14 GW interconnector capacity between Norway and the Netherlands, the export capacity for electricity from Norway is significantly limited. This has consequences for the utilization of the hydropower capacity and the generation costs. The change in the total generation costs for Europe and the Netherlands and Norway is presented in Table 2, while it is depicted for the countries individually in Figure 15. Hydropower utilization In Case A the peak generation from hydro reservoir and hydro pumped storage is 42.5 GW and 17.3 GW respectively. When removing the 14 GW cross-border capacity (case B), this peak generation decreases to 36 and 13.7 GW respectively (see Table 3). This means that not all of the installed hydropower capacity can be used anymore. There is a net decrease in hydropower generation of 33 TWh/yr. T2: Impact of 14 GW less NL-NO capacity on generation costs per region F15: Change in total generation costs per country (M /yr) , Change in generation costs (M /yr) EU 7,28 NO -47 NL 412 1,26 Generation costs The generation costs increase throughout Europe as generation shifts from low-cost hydro in Norway to (more) expensive generation elsewhere in Europe. The reduction in Norwegian hydropower is compensated by (more expensive) back-up generation and biomass fired power plants. The increase in backup and biomass-fired generation spreads across Europe, for example in Belgium, Germany, France, Netherlands, Italy, Spain and United Kingdom. It is observed that generation costs throughout Europe increase by 7,28 M /yr. For the Netherlands an increase of 412 M /yr is found, while generation costs decrease with 47 M /yr in Norway. To put this increase in total European annual generation costs of over 7 billion Euro into perspective: the required investment to realize the 14 GW interconnection capacity between the Netherlands and Norway is about 28.8 billion Euro. For the Netherlands, the current annual traded volume on the power spot market is about 4 billion Euro, implying that the increase of 412 M increase in generation costs is more than 1% of this trade volume. M AT BE CH DE FR NL IT CZ IE NO PL PT SK SI ES UK DK FI HU SE NI T3: Peak hydropower utilization (GW) Case A Case B Hydro pumped storage Hydro Reservoir

23 1. Analysis of 1% RES scenario of e-highway25 Summary and interpretation of the results Role of the Netherlands-Norway interconnector The 14.7 GW NorNed cable facilitates export of low-cost Norwegian hydropower to continental Europe and storage of solar electricity generated in Northwest Europe. During the winter the flow is almost one-directional from Norway to Netherlands, during the summer-period the flow is bi-directional due to increase in electricity from solar irradiation. Removing interconnection capacity causes shift in generation Reducing the 14.7 GW to.7 GW interconnection capacity reduces the amount of low-cost electricity transported from Norway to the Netherlands and reduces the flow towards Norway in the summerperiod. The reduction in export (capacity) from the Netherlands results in 25 TWh of curtailment from wind and solar power. The reduction in Norwegian export coincides with reduction in peak hydro generation: less hydro power generation capacity needs to be added. Removing interconnection capacity causes increase in electricity generation costs Due to the shift in generation from hydro in Norway to biomass and backup generation in (continental) Europe, there is an increase in generation costs. It is a shift of 33 TWh Norwegian (pumped) hydro electricity ( ~ /MWh) to expensive back-up generation (~27 TWh, 2-3 /MWh) and biomass (~7 TWh, 2-4 /MWh) generation in various European countries. Removing the 14 GW interconnector capacity between Norway and the Netherlands increases the total annual generation costs across Europe. With 7,28 M /a. For the Netherlands an increase of 412 M /a is found, while generation costs decrease with 47 M /a in Norway. Consequence of the reduction in Norwegian hydro power generation is an increase in biomass and backup generation elsewhere in Europe to maintain the supply-demand balance. This increase in generation is not only in the Netherlands, but also in other European countries as the Netherlands operated as transit country for a significant share of the Norwegian imported electricity. 23

24 Analysis of PtG cases CHAPTER SECTION PAGE Introduction Methodology 1. Analysis of 1% RES scenario of the e-highway25 study 2. Analysis of PtG cases 3. Comparison of total system cost Conclusions Annex Background & Objective About e-highway25 Scope Approach Description Electricity Market Modelling Description Total System Cost Calculation General introduction to the 1% RES-scenario Situation Netherlands and Norway Analysis of the gas demand in 25 Results Case A and B Summary and interpretation of the results Case definition Results Case C and D Results Case 1A 1C Results analysis potential hydropower capacity Norway Results Case 2A 2D Results Case 3A Identification of relevant cost elements Case C and D Case 1B and 1C Case 2C and 2D Case 3A Summary of results General conclusion Final Remarks & Recommendations Annex A: Description Electricity Market Modelling Annex B: Assumptions generation costs per type of renewable energy source Annex C: Modelling 1% RES scenario without the NO-NL cable (Case B) Annex D: Glossary

25 2. Analysis of the PtG cases A. Case definition Simulated cases The table below presents the characteristics and input parameter of the various simulations performed in this study. The power-to-gas cases differ in capacity of the NL-NO interconnector and the PtG facility as well as in the functionality that is assigned to the power-to-gas installation. Furthermore, a differentiation is made with respect to the destination of the produced hydrogen: it is either re-electrified (PtGtPower) or used in industry (PtGtProduct). Peak hydropower generation in Norway (to assess possible reduction in hydropower generation capacity investments) Outputs collected in simulations with PtG: Electricity stored (TWh H 2 ) using PtG Electricity generated (TWh elec) by PtGtPower Development of H 2 volume (TWh) stored in the PtGtPower cases Outputs collected in all simulations: Electricity generated (TWh) per generation type per country Total generation costs (M /a): sum of fuel costs, emission costs, variable operation and maintenance costs T4: Case characteristics NL-NO IC capacity Type PtG PtG functionality Location PtG Capacity PtG Location GtP Capacity GtP Comment Case A 14.7 GW (no PtG) e-highway25 1%RES Case B.7 GW (no PtG) e-highway25 1%RES Case C.7 GW To Power Balancing & storage NL 14 GW NL 6.3 e-highway25 1%RES Case D.7 GW To Product Balancing NL 14 GW e-highway25 1%RES Case 1A 13.7 GW (no PtG) e-highway25 1%RES Case 1B 13.7 GW to Power Balancing & storage NL 1 GW NL.45 GW e-highway25 1%RES Case 1C 13.7 GW to Product Balancing NL 1 GW NL n.a. e-highway25 1%RES Case 2A 14.7 GW (no PtG) Adjusted hydropower capacity Case 2B.7 GW (no PtG) Adjusted hydropower capacity Case 2C.7 GW to Power Balancing & storage NL 14 GW NL 6.3 GW Adjusted hydropower capacity Case 2D.7 GW to Product Balancing NL 14 GW Adjusted hydropower capacity Case 3A.7 GW to Power Long-distance energy transmission NO 14 GW NL 6.3 GW Adjusted hydropower capacity 25

26 2. Analysis of the PtG cases Results Case C Impact of 14 GW less IC capacity with PtGtPower In Case C we investigated the impact of reducing the NO-NL interconnector with 14 GW down to.7 GW combined with a 14 GW PtGtPower facility in NL. The results of this case are compared to the original 1% RES of the e-highway25 study (case A). PtG faciliy utilization In total, there is 47 TWh of electricity consumed for hydrogen production and 21 TWh of electricity generated using hydrogen (cycle efficiency 45%). The power-to-gas installation has a capacity factor of ~42% and the gas-to-power facility of ~4% (see also Figure 17). Volume of hydrogen stored The required storage capacity for hydrogen is approximately 18.7 TWh (difference between the lowest and highest level of volume of stored hydrogen, see also Figure 18). The volume of stored hydrogen decreases during the winter, as the hydrogen is used for electricity generation in a gas-to-power facility. There are a few wind-rich periods with low electricity prices in which hydrogen is stored. From April to end of October, there is a net increase in hydrogen stored. Impact on system costs Case C with its 14 GW PtGtPower facility leads to an increase in total generation costs of 4,356 M /yr compared to the reference case, which is less of a cost increase (of about 4%) compared to Case B (see also Table 5). The PtGtPower utilizes 25 TWh wind and solar generation with zero generation costs (i.e. reducing curtailment by 25 TWh). Besides, in this scenario an additional 6.6 TWh biomass-fired generation is called upon, as well as 12 TWh of (expensive) back-up generation. is used. These two effects (i.e. use of otherwise curtailed renewable electricity and reduced additional use of expensive back-up generation) lead to a lower increase in total generation costs when removing the 14 GW interconnector. F16: Duration curve of power-to-gas and gas-to-power in case C Electrolyser and fuel cell utilization (GW) F18: Volume of stored hydrogen (TWh hydrogen) Amount of Hydrogen in storage (TWh H2) % 3% 6% 9% 12% 15% 17% 2% 23% 26% 29% 32% 35% 38% 41% 44% 47% 49% 52% 55% 58% 61% 64% 67% 7% 73% 76% 79% 82% 84% 87% 9% 93% 96% 99% T5: Change in generation costs compared to case A (M /yr) % of hours of a year Time of year Case B Generation (GW elec) H2 production (GW elec) Case C EU 7,28 4,356 NO

27 2. Analysis of the PtG cases Results Case D Impact of 14 GW less IC capacity with PtGtProduct In Case D we investigated the impact of reducing the NO-NL interconnector with 14 GW down to.7gw combined with a 14 GW PtGtProduct facility in NL. The results of this case are compared to the original 1% RES of the e-highway25 study (case A). PtG facility utilization The facility is used to produce hydrogen during 34% of the hours in the year, this is illustrated in the duration curve on the lower right. The utilization is mainly at full-load during those hours. Accordingly, the annual capacity factor (e.g. annual average utilization of its capacity) is 31% (see also Figure 19). Impact on system costs As the PtGtProduct facility increases the low-cost generation without decreasing the expensive back-up generation, there is a 7,452 M /a generation costs increase compared to the base case. Power-to-Gas-to-Product creates an additional demand for low-cost electricity: the operator is assumed to be willing to pay maximum 3 /MWh for its electricity. Because of the additional demand, the Netherlands becomes a large importer of low-cost electricity: it uses the PtGtProduct facility to absorb 23 TWh of (otherwise) excess wind and solar generation (thereby reducing the curtailment) and increases the utilization of low-cost biomass-fired generation with 2 TWh. The average price paid for electricity by the PtG facility is 9.2 /MWh, and the overall electricity consumed to produce hydrogen is 38.5 TWh. GW power used for H2 product F19: Duration curve of power-to-gas and gas-to-product in case D T6: Change in generation costs (M /yr) % of hours in a year Case B Case C Case D EU 7,28 4,356 7,452 NO In comparison with case B and C, case D shows the highest increase in total generation (see also Table 6). The increase of 7,452 M compared to the reference case (Case A) is explained by the fact that electricity consumed be the PtGtProduct facility does not re-enter the electricity system, which has to be compensated for by using (more expensive) biomass and back-up generation. 27

28 2. Analysis of the PtG cases Results Case 1A Impact of 1 GW less IC capacity In case 1A we analysed the impact of reducing the interconnection capacity between Norway and the Netherlands by 1 GW from 14.7 GW to 13.7 GW. The results are compared to the reference scenario with 14.7 GW interconnection capacity between Norway and the Netherlands (case A). Flow Reducing the interconnector capacity also reduces the maximum instantaneous flow, which is shown by the lower plateaus/stable levels in the flow duration curves (see also Figure 2): at 13.7 and 13.7 GW for case 1A instead of 14.7 and GW in case A. This results in a 3 TWh decrease in the annual net flow from NO to NL. Prices Reducing the NO-NL interconnector with 1 GW has no impact on the price duration curve of the Netherlands (see Figure 21). Hydropower utilization The reduced export capacity has a small impact on the peak capacity utilization of Norwegian pumped hydro storage capacity (.1 GW reduction). Adding a PtG facility in NL does not impact the maximum instantaneous hydropower generation in Norway (see also Table 7). Generation costs The 1 GW reduction in NO-NL interconnector capacity increases the European electricity generation costs by 24 M (.4% of total costs). The generation costs increase as less hydro generation in Norway can be exported to (continental) Europe (e.g. the 3 TWh reduction in net export to NL), which increases the need for additional generation in other regions of Europe such as the Netherlands (see also Table 8). T7: Hydro (GW) A 1A Difference Reservoir Pumped storage F2: Duration curve for the flow of electricity across NO-NL interconnector (flow from NL to NO is positive)(mwh) Energy flow through NL-NO interconnection (flow from NL to NO is positive) (MWh) /MWh % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% OA % of hour in a year F21: Electricity price duration curve for the Netherlands ( /MWh) 1A % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% T8: Generation costs (M /yr) % of hours of a year A 1A A 1A Difference Difference Europe 68,451 68, % NO % NL % 28

29 2. Analysis of the PtG cases Results Case 1B Impact of 1 GW less IC capacity with PtGtPower In Case 1B we investigated the impact of reducing the NO-NL interconnector with 1 GW down to 13.7 GW combined with a 1 GW PtG facility in the Netherlands for PtGtPower (case 1B). The results of this case are compared to the reference scenario (case A). Additionally, the results are compared to the PtG case C, where the PtGtPower facility was larger (14 GW) as the interconnection capacity was reduced with 14 GW. PtG utilization The utilization of the PtGtPower facility in the Netherlands is only slightly lower in case 1B (1 GW less interconnection capacity) compared to case C: it is operating less hours compared to the larger PtGtPower facility in the 14 GW reduction case (the combined use of power-to-gas and the gas-to-power facility is ~ 7% of the year vs. ~ 83% in case C, see also Figure 22). Volume of hydrogen stored As a consequence of the lower capacity of the PtGtPower facility (1 GW instead of 14 GW) and the reduced utilization, the required storage capacity for hydrogen decreases to 1.2 TWh (see also Figure 23) instead of 18.7 TWh in case C. Impact PtGtPower on system costs The total (European) electricity generation costs are 231M (.3% of total) lower for case 1B compared to the reference scenario (case A): the PtG facility in the Netherlands reduces RES curtailment in continental Europe and reduces need for expensive backup generation. As can be expected, the generation costs in NL are a bit higher while those are slightly lower in Norway (see also Table 9). F22: Duration curve of power-to-gas and gas-to-power in case 1B Generation and storage load (MW) % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% % Hours of a year NL C GtP NL C PtG NL 1B GtP NL 1B PtG F23: Volume of stored hydrogen (TWh hydrogen) Hydrogen stored (TWh_H2) /1/25 1/11/25 1/21/25 1/31/25 2/1/25 2/2/25 3/2/25 3/12/25 3/22/25 4/1/25 4/11/25 4/21/25 5/1/25 5/11/25 5/21/25 5/31/25 6/1/25 6/2/25 6/3/25 7/1/25 7/2/25 7/3/25 8/9/25 8/19/25 8/29/25 9/8/25 9/18/25 9/28/25 1/8/25 1/18/25 1/28/25 11/7/25 11/17/25 11/27/25 12/7/25 12/17/25 12/27/25 T9: Generation costs (M /yr) NL C A 1A 1B Difference (1B A) Difference (1B-A) Europe 68,451 68,475 68, % Date NL 1B NO % NL % 29

30 2. Analysis of the power-to-gas cases Results Case 1C Impact of 1 GW less IC capacity with PtGtProduct In case 1C we investigated the impact of reducing the NO-NL interconnector with 1GW down to 13.7GW combined with a 1GW PtG facility in the Netherlands for PtGtProduct. The results of this case are compared to the reference scenario (case A). Additionally, the results are compared to the PtG case D, where the PtGtProduct facility was larger (14 GW) as the interconnection capacity was reduced with 14 GW. PtGtProduct utilization The PtGtProduct facility in the Netherlands has a (slightly) higher utilization in the 1GW case compared to the 14GW case (case D). The reason behind this is that in case 1C the PtG facility can profit from low cost electricity from Norway (as the interconnection capacity is 13.7GW) and from low-cost renewable electricity in Europe (reducing wind and solar curtailment). The PtGtProduct facility favours low absolute price levels as it purchases electricity until a given strike price is reached. Impact PtGtProduct on generation costs Total generation costs in Europe increase with 137 M (.2% of total) as a result of the 1 GW reduction in interconnection capacity and the additional (up to) 1 GW electricity demand for PtG conversion. The increase in generation costs is spread across continental Europe: for example, a 19 M increase (of the 137 M ) occurs in the Netherlands (see also Table 4). F24: Duration curve of power-to-gas and gas-to-power in case 1C Hourly electricity consumption for PtGtProduct (MWh) % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% T1: Generation costs (M ) % of period of a year NL D NL 1C A 1A 1C Difference (1C A) Difference (1C A) Europe 68,451 68,475 68, % NO % NL % 3

31 2. Analysis of the PtG cases Results analysis potential hydropower capacity Norway Introduction The e-highway25 1% RES Scenario assumes a tripling of installed capacity of hydropower in Norway from ~31 GW towards ~88 GW in 25. Table 11 presents the currently installed capacities (by Q4 of 216) vs. the assumptions made by the e-highway25 consortium for the development of these capacities towards 25. It can be observed that the installed capacities and the total electricity generated increase significantly. It is questionable whether this can be realized, when considering environmental factors such as available locations, preserved areas, and the development of precipitation due to climate change. For instance, the water inflow into the Norwegian hydropower system has been stable at about 125 TWh over the last 25 years. As observed case C and D of this study, the availability of low-cost Norwegian hydropower has a significant impact on total system costs in Europe. That is why DNV GL decided to undertake a literature review with publically available information from the Ministry of Petroleum and Energy, the TSO Statnett, and research papers, and consulted colleagues in Norway (of which some have worked before for a.o. Ministry of Petroleum and Energy and Statoil), to provide a clearer picture on the likely development of hydropower in Norway. The results were processed in the cases 2A, 2B, 2C, 2D and 3A. T11: Hydropower in Norway 216 E-Highway25 1%RES Total installed capacity 31.7 GW 87.9 GW Reservoir capacity 27.8 GW 42.5 GW Run-of-river capacity 2.5 GW 28.1 GW Pumped hydro storage capacity 1.4 GW 17.3 GW Total generated electricity ~133 TWh ~199 TWh F25: Development of installed capacity hydropower in Norway (MW) Findings literature hydropower development until now The Norwegian Ministry of Petroleum and Energy and the Norwegian Water Resources and Energy Directorate (NVE) keep track of the energy production and consumption in Norway and publish various reports on this topic on a regular basis. In terms of installed capacity, it is found that this has been relatively stable over the last years (see also Figure 25). 31

32 2. Analysis of the PtG cases Results analysis potential hydropower capacity Norway Proposed assumptions extension hydropower Based on the literature review, DNV GL concludes that the e- Highway25 1%RES scenario assumptions regarding the extension of hydropower in Norway are not very realistic. Based on the literature findings and expert opinion, we used the following figures for the installed capacities of the different hydropower technologies: Reservoir: no significant increases compared to the current situation, in 25 total capacity of ~3 GW. Run-of-River: significant increase compared to the current 2.5 GW, assuming an average increase based on the NVE and Statnett expectations leads to a total capacity of ~13 GW Pumped Hydro Storage: we propose to assume the lower value of the mentioned potential, 1 GW Concluding, the table is extended with the proposed capacities for 25 by DNV GL to incorporate in the model, see Table 12. It can be observed that the proposed extension of the installed hydropower capacity in Norway is significantly lower than the assumption of the e- Highway25 1%RES scenario. It will be analysed what impact this will have on the viability of the PtG alternatives, by investigating for instance the impact on total generation costs in Europe, the flows across the interconnector and the use of the PtG units. T12: Hydropower Norway 216 e-highway25 1%RES NVE potential Total installed capacity 31.7 GW 87.9 GW GW ~49 GW Statnett Other DNV GL proposal 5 GW (SINTEF) DNV GL ehighway25 1%RES 53 GW GW Reservoir capacity 27.8 GW 42.5 GW 3.4 GW 29.8 GW 3 GW GW Run-of-river capacity 2.5 GW 28.1 GW 7. GW 19 GW 13 GW GW Pumped hydro storage capacity 1.4 GW 17.3 GW ~1-2 GW na ~1-2 GW 1 GW -7.3 GW Total generated electricity ~133 TWh ~199 TWh 165 TWh na 3 TWh (WEC) na (Please note that only installed capacity is considered as input to the model, the generated electricity is an outcome of the simulations) 32

33 2. Analysis of the PtG cases Results Case 2A and 2B Impact of less Norwegian hydro To analyse the impact of less installed hydropower capacity in Norway, we performed a simulation with the original e-highway25 assumptions but with less installed hydropower capacity in Norway (case 2A). Subsequently, case 2A is taken as the new reference case to evaluate the impact of adding PtG facilities. To isolate the impact of less interconnection capacity from the impact of the PtG facility, we also ran a case 2A without the 14 NO-NL interconnector capacity (case 2B). Flow As can be seen in Figure 26, less hydropower generation capacity in Norway results in a net flow from Norway to the Netherlands which is 12 TWh lower compared to the original base case A: 45 TWh instead of 57 TWh. The flow duration curve shows that there are 2% more hours in which the interconnection capacity is not fully utilized (comparing case 2A with A). This observations implies that there is increasing price convergence between Norway and the Netherlands. Prices The price duration curve for the Netherlands shows that in case of less hydropower generation in Norway, there are almost 1% more hours in which expensive back-up generation is price-setting (see at a price of ~2 /MWh). Nevertheless, also in case 2A and 2B there are significant number of hours with low prices and with high prices (see Figure 27). Generation costs Generation costs in Europe increase from ~68 billion to ~75 billion euro due to the reduction in installed hydropower capacity in Norway (note that these costs do not include the (change in) investments costs of hydropower in Norway). Also the costs in both NO and NL increase (case 2A vs A), with a clear impact of lowering the interconnection capacity (case 2B vs 2A). The detailed results are presented in Table 12. Hydro utilization In case 2B we observed that the impact of reducing the NO-NL interconnection capacity by 14 GW has only a small impact on the peak use of hydro capacity (case 2B vs 2A), see Table 13). F26: Duration curve for the flow of electricity across NO-NL interconnector (flow from NL to NO is positive) Energy flow through NL-NO interconnection (flow from NL to NO is positive) (MWh) % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% % of hour in a year OA 2A 2B F27: Electricity price duration curve for the Netherlands ( /MWh) /MWh % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% % of hours of a year A 2A 2B T12: Generation costs (M /yr) A 2A 2B Europe 68,451 74,648 76,689 NO NL 177 1,883 2,138 T13: Hydro (GW) A 2A Difference (2A-A) 2B Difference (2B-2A) Reservoir Pumped storage

34 2. Analysis of the PtG cases Results Case 2C Impact of less Norwegian hydro and PtGtPower For case 2C we repeated the analyses done in case C (reducing the NO-NL interconnection capacity by 14GW and adding a PtGtPower facility), but now for the situation where less hydropower generation capacity is available in Norway. Subsequently, the outcomes of case 2A and 2C are compared with each other. PtG utilization The utilization of the PtGtPower facility in the Netherlands in case 2C is almost similar to the C case: the overall utilization of the electrolyser (PtG) and the fuel cell (GtP) in case 2C is slightly lower compared to case C (2 TWh vs. 21 TWh). The required storage volume is slightly higher in case 2C being 2 TWh compared to 18.7 TWh in case C. The explanation for the rather similar PtGtPower performance is that the reduced hydro generation capacity has not a significant impact on the distribution of the electricity prices (differential) in the Netherlands. There is an increase in overall hours with high electricity prices, but there are still 5% of the hours with electricity price below 5 /MWh. Impact PtGtPower on generation costs The substitution of 14 GW NO-NL interconnector capacity by a 14 GW PtGtPower facility in the Netherlands decreases the European generation costs by almost 1 billion Euro (1.4% of total costs) compared to the reference case with less hydro and full interconnector capacity (case 2A). By comparing this result with adding PtGtPower in Phase I (case C), the following is observed: whereas in Phase I generation costs in Europe increase (case C A), in Phase II total generation costs decrease (case 2C 2A). This can be explained by the findings that with reduced hydro generation capacity, removing the interconnection capacity has a smaller impact on the generation from hydropower in Norway. This is also reflected by the change in generation costs in NL and NO. Generation and storage load (MW) F28: Duration curve of electricity consumed and produced using PtG % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% % Hours of a year NL C GtP NL C PtG NL 2C GtP NL 2C PtG F29: Volume of stored hydrogen (TWh hydrogen) Hydrogen stored (TWh_H2) /1/25 1/11/25 1/21/25 1/31/25 2/1/25 2/2/25 3/2/25 3/12/25 3/22/25 4/1/25 4/11/25 4/21/25 5/1/25 5/11/25 5/21/25 5/31/25 6/1/25 6/2/25 6/3/25 7/1/25 7/2/25 7/3/25 8/9/25 8/19/25 8/29/25 9/8/25 9/18/25 9/28/25 1/8/25 1/18/25 1/28/25 11/7/25 11/17/25 11/27/25 12/7/25 12/17/25 12/27/25 T14: Generation costs (M /yr) 2A NL C 2C Date NL 2C Difference (2C 2A) C Difference (C A) Europe 74,648 73, ,87 +4,356 NO NL 1,883 2, ,

35 2. Analysis of the power-to-gas cases Results case 2D Impact of less Norwegian hydro and PtGtProduct In case 2D we repeated the analyses of case D (reducing the NO-NL interconnection capacity by 14GW and adding a PtGtProduct facility instead), but now for a situation with less hydro power generation capacity in Norway (case 2D). Subsequently, the outcomes of case 2A, D and 2D are compared with each other. PtG utilization The utilization of the PtGtProduct facility in the Netherlands (case 2D) is slightly lower compared to case D (~3% less). The PtGtProduct facilities in the Netherlands use 36 TWh of electricity for hydrogen production, which is 2 TWh less than the original case D in which there is more hydropower generation available in Norway (see also Figure 3). Impact PtGtProduct on generation costs The European generation costs increase with around 2 billion Euro for case 2D (removing 14 GW interconnector capacity and adding a PtGtProduct facility in NL) compared to case 2A. By comparing this result with case D, the following is observed: the increase in total generation costs in Europe of 7.4 billion for case D A) is over three times larger than the increase in phase II (2 billion for case 2D 2A). The main reason for this difference is the smaller impact of removing interconnector capacity due to the reduced hydropower generation in the cases 2A-2D. This is also reflected by the change in generation costs in NL and NO (see also Table 15). F3: Duration curve of electricity consumed using PtG Hourly electricity consumption for PtGtProduct (MWh) T15: Generation costs (M /yr) % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% 2A 2D % of period of a year NL D NL 2D Difference (2D 2A) D Difference (D A) Europe 74,648 76,732 +2,84 75,93 +7,452 NO NL 1,883 2, ,

36 2. Analysis of the power-to-gas cases Results 3A Long distance energy transmission In case 3A we have investigated the viability of PtG for long distance transmission of energy from Norway to the Netherlands; as reference case we used the reduced hydropower generation capacity in Norway and no NO-NL interconnector capacity extensions (hence case 2A). This PtG case assumes a 14 GW power-to-gas facility in Norway, H 2 transport via pipeline from Norway to Netherlands (transport time of 24hrs), and a 6.3 GW gas-to-power facility in NL. Pipeline utilization The H 2 transport through the pipeline compensates the 14 GW el reduction in power transmission capacity: the combined power and H 2 transport from Norway to the Netherlands is 2. TWh electricity and 23 TWh H 2, which is comparable to the power flow in the case with 14.7 GW power transmission capacity (case 2A) which was 44 TWh. Hydrogen flow (GWh_H2) F31: Daily H 2 flow from NO to NL through pipeline (GWh) Date H2 transport (GWh H2) (Case 3A) Power transport (GWh elec) (Case 2A) Note that in Figure 18 the H 2 flow is not directly similar to the power flow of case 2A because it is not related to the instantaneous price spread NL-NO but takes into account a delay of at least 24 hrs. PtGtPower utilization The power-to-gas facility in Norway and the gas-to-power facility in the Netherlands have comparable utilization levels as in the original PtGtPower facility in the Netherlands (Case 2C), see also Figure 32). In both cases, 2 TWh of electricity is generated using power-to-gas and one requires a storage tank of maximum 2 TWh in the Netherlands. This shows that in this particular scenario, the location of the PtG facility (Netherlands or Norway) does not change the utilization significantly. Impact PtGtPower on generation costs Locating the PtG facility may not impact the overall utilization, but it does double the cost reduction in generation costs compared to PtG in Netherlands (case 2C): 1,8 billion euro Europe wide (see also Table 16). This configuration allows Norway to export potential excess hydropower generation and reduces wind and solar curtailment in continental Europe. F32: Duration curve of electricity consumed & produced using PtG Generation and storage load (MW) % 3% 6% 9% 11% 14% 17% 2% 23% 26% 29% 31% 34% 37% 4% 43% 46% 49% 51% 54% 57% 6% 63% 66% 69% 71% 74% 77% 8% 83% 86% 88% 91% 94% 97% T16: Generation costs (M /yr) % Hours of a year NL 2C GtP NL 2C PtG NL 3A GtP NO 3A PtG 2A 3A Difference (2C 2A) Difference (2C 2A) Europe 74,648 72,813-1, % NO % NL 1,883 2, % 36

37 2. Analysis of the power-to-gas cases Results 3A Long distance energy transmission For case 3A is assumed that the existing gas pipelines between Norway and the Netherlands become available for transporting hydrogen. After calculating the amounts of hydrogen produced by the power-to-gas facility throughout the year, it was evaluated whether existing pipeline capacities would be sufficient to transport the peak production volumes of hydrogen to the Netherlands. According to ENTSOG data, current pipeline capacity between Norway and the Netherlands is around 41.2 GW for natural gas. Although hydrogen has a lower energy content than natural gas (approximately one-third), the velocity of hydrogen through a pipeline is around 3 times higher due to its lower density. In energy terms, maximum flows for hydrogen are around 8% of natural gas for high calorific natural gas under the same circumstances and approximately equal for low F33: Energy-transport losses for hydrogen-natural gas mixtures 8% calorific natural gas. This is shown in the chart below. Hence, the maximum energy flow if hydrogen would be transported equals approximately 33 GW. The power-to-gas facility in Norway has a capacity of 14 GW el. Assuming an efficiency of 67% results in a hydrogen output of maximum 9.4 GW. This shows that the capacity of the existing pipeline is more than sufficient. As a general rule, compressor power requirements are approximately three times higher for hydrogen than for natural gas to achieve the same pressure step. However, as the energy-flow for hydrogen is only around one-third of the maximum energy-flow of the pipeline (9.38 GW vs. 33 GW), the existing compressor station should be sufficient. The suitability of existing compressor station is also dependent of the type of compressor used. In principle, there are two different kinds of compressors used in natural gas transport: 1. Centrifugal compressors 2. Reciprocating compressors Centrifugal compressors are well-suited for large flows and relatively low compression ratios (P out /P in ). Centrifugal compressors are less suited for hydrogen transport due to hydrogen s low molecular weight. This reduces the compression ratio as compared to compressing natural gas. For reciprocating compressors the type of gas used is of less importance. Therefore, reciprocating compressors used for natural gas transport can be used without major design modifications although attention should be given to the seals. It is unknown what kind of compressors are used to transport gas from Norway to the Netherlands. Nevertheless we assume that hydrogen needs to be compressed before entering the pipeline and have thus assumed the associated costs for it. 37