the potential role of power-to-gas in the e-highway2050 study · the potential role of power-to-gas...

DNV GL ©2017

OIL & GASThe potential role of power-to-gas in the e-Highway2050 study

1

Public Version

DNV GL ©20172

Report details

The Potential role of Power-to-Gas in the e-Highway2050 study Public version

DNV GL

Oil & Gas

http://www.dnvgl.com

For:European Power to Gas Platform

Date of issue: Monday, September 18, 2017

Managed by: Paula Schulze

Project Manager

Signature

Prepared by: Pieter van der WijkIvan WapstraMaurice VosBieuwe PruiksmaWim van der Veen

Team members

Signature

Verified by: Albert van den Noort

Quality Assurance

Signature

Approved by: Johan Knijp

Project Sponsor

Signature

Key words: Power-to-gas, e-Highway2050, PLEXOS, modelling, system cost analysis, renewable energy, hydrogen

http://www.dnv.com/

DNV GL ©20173

Background and approachExecutive summary I

The pan-European energy system is faced with the enormous challenge to decarbonize almost completely until 2050. 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-Highway2050 study in 2015, a study with theoverarching objective to map out a pan-European electricity transmission network capable of meeting European energy needs between 2020 and 2050, 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 100% RES scenario of the e-Highway2050 study (reference scenario). In order to reach this objective, one interconnection was chosen as object of study from the reference (100% RES) scenario form the e-Highway2050 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 100% RES scenario of the e-Highway2050 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 100% RES e-highway2050 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 0B) or used in industry (case 0C)

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 ~40% 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).

DNV GL ©20174

Results & ConclusionsExecutive summary II

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 100% RES scenario of the e-Highway2050 study, however, assumes an increase in Norwegian (pumped) hydropower capacity from currently 30 GW to 87 GW in 2050. 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 10% higher generation costs throughout Europe.

Four out of seven analyzed PtG cases showed lower total system costs compared to the 100% RES e-Highway2050 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 re-electrified 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

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 100% RES scenario of the e-Highway2050 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.

DNV GL ©20175

ResultsExecutive summary III

99

963

-94

208

-2.000 2.0000 4.000 6.000 8.000

PtG in NL

100% RES

PtG in NL

100% RES 2.711

PtG in NL

100% RES 1.436

PtG in NO

100% RES 1.478

6.289

232

322

0 4.000 8.0006.000 10.0002.000

3.363

2.788

8.760

4.156

PtG to Power PtG to Product

Replacement of 14 GW electricity cable by PtGinstallation


Replacement of 14 GW electricity cable by PtGconsidering reduced hydrostorage in Norway

Replacement of 14 GW electricity cable by a PtG in Norway, transport of H2 to the Netherlands, and electricity generation by fuel cell in the Netherlands

Change in total annual system costs compared to the alternative solution (in MEUR)

PtGlowest costs

Not investigated

Case 1B Case 1C

Case 2C Case 2D

Case 3A

Results of e-Highway2050 (100% RES) assumptions

Results of PtG alternative

Case 0C Case 0D

DNV GL ©20176

Final remarks & RecommendationsExecutive summary IV

Final remarksWhen 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 40% 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.

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

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.

DNV GL ©2017

CHAPTER SECTION PAGE

7

Table of Content

8910

121415

1718192123

252628313336

3942454851525455

57585960

Background & ObjectiveAbout e-Highway2050Scope

ApproachDescription Electricity Market ModellingDescription Total System Cost Calculation

General introduction to the 100% RES-scenario Situation Netherlands and NorwayAnalysis of the gas demand in 2050Results Case 0A and 0BSummary and interpretation of the results

Case definitionResults Case 0C and 0DResults Case 1A – 1CResults analysis potential hydropower capacity NorwayResults Case 2A – 2DResults Case 3A

Identification of relevant cost elementsCase 0C and 0DCase 1B and 1CCase 2C and 2DCase 3ASummary of results

General conclusionFinal Remarks & Recommendations

Annex A: Description Electricity Market ModellingAnnex B: Assumptions generation costs per type of renewable energy sourceAnnex C: Modelling 100% RES scenario without the NO-NL cable (Case 0B)Annex D: Glossary

Introduction

Methodology

1. Analysis of 100% RES scenario of the e-Highway2050 study

2. Analysis of PtG cases

3. Comparison of total system cost

Conclusions

Annex

DNV GL ©20178

Background & ObjectiveIntroduction

BackgroundThe pan-European energy system is faced with the enormous challenge to decarbonise almost completely until 2050. 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-gasThe 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.

AssignmentThe 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.

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-Highway2050 study in 2015, a study with the overarching objective to map out a pan-European electricity transmission network capable of meeting European energy needs between 2020 and 2050, the Platform members identified a need to investigate whether there is a potential of power-to-gas in this context.

ObjectiveThe 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-Highway2050 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-Highway2050 study, are substituted by a power-to-gas 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.

DNV GL ©20179

About e-Highway2050Introduction

Sources and notes:1. e-Highway report highway2050.eu/fileadmin/documents/e_highway2050_booklet.pdf2. e-Highway 2050 Note on PtG highway2050.eu/fileadmin/documents/Results/D3/Note_on_power_to_gas.pdf

About e-Highway2050At the end of 2015 the results of “e-Highway2050” 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-Highway2050 was the planning of a pan-European electricity transmission network, including possible “highways” capable of meeting European energy needs between 2020 and 2050.

Five challenging future power system scenarios have been created to frame the e-Highway2050 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 400 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.

The e-Highway2050 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-Highway2050 analysis.

e-Highway2050 and Power-to-GasThe e-Highway2050 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-Highway2050 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).”

http://www.e-highway2050.eu/fileadmin/documents/e_highway2050_booklet.pdf

http://www.e-highway2050.eu/fileadmin/documents/Results/D3/Note_on_power_to_gas.pdf

DNV GL ©201710

ScopeWithin the scope of this study we assessed the potential for power-to-gas in comparison with planned electricity grid extensions, as proposed in the e-Highway2050 study.

During the definition phase of the project we selected the 100% 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.

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 PtGpathways:

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.

Electricity market simulationAs 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 comparisonIn 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.

ScopeIntroduction

DNV GL ©2017


11

Methodology

8910

121415

1718192123

252628313336

3942454851525455

57585960








Introduction

Methodology




Conclusions

Annex

DNV GL ©201712

IntroductionWe 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 caseThe 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 approachThis 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 2050 resultsIn this first step DNV GL analyzed the approach and results as described under the scenarios of the e-Highway2050 study. Afterwards, DNV GL modelled the e-highway2050 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 alternativeDNV 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, long-distance energy transmission).

Step 3. Comparison total system costIn 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 power-to-gas case and the 100% RES reference case.

ApproachMethodology

2. Analysis of PtGcases

3. Comparison of total system costs

1. Analysis of 100% RES scenario of e-Highway2050

DNV GL ©201713

The e-Highway 2050 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).

ApproachMethodology

Electricity market

Hydrogen storage

Gas suppliers

Electricity Generation

Capacity extension

Interconnector

Norway Netherlands

Wind & SolarBiomass

Natural gas market

Power-to-gas Facility

H2 market

Gas-to-power Facility

Steam reformers

F2: Introduction of power-to-gas into the energy system

Electricity market

Hydrogen storage

Gas suppliers

Electricity Generation

Capacity extension

Interconnector

Norway Netherlands

Wind & SolarBiomass

Natural gas market H2 marketSteam

reformers

F1: Situation as in e-Highway2050

DNV GL ©2017

Core-Country

Non-Core Country

14

DNV GL Electricity Market ModellingFor 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.

Use in this projectDNV GL has entered the 100% RES scenario of the e-Highway2050 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).

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.

Description Electricity Market ModellingMethodology

F3: Level of detail in modelling for different EU countries

Core-Country

Non-Core Country

DNV GL ©201715

Total System Cost ComparisonThe comparison between the 100% 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 caseFor each case, the unique costs were identified which had to be included in the system cost analysis. For instance, the cost of a power-to-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 PtGfacility or the subsea cable.

Benefits of one alternative are seen as costs to the otherBesides 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 100% 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 PtGalternative less hydrostorage is required. In principle, the reduction in the need for hydrostorage can be seen as a benefit to the PtG case.

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 2017).

Description total system cost calculationMethodology

F4: Schematic representation of benefits translated into cost

-5-4

-4 -3

-4-2

PtG

4

Direct costs

Electricity cables

Benefits

Indirect costs

3

Total cost: 15Total cost: 11

DNV GL ©2017


16

Analysis of e-Highway2050

8910

121415

1718192123

252628313336

3942454851525455

57585960








Introduction

Methodology




Conclusions

Annex

DNV GL ©201717

E-Highway2050 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 2030 targets and 2050 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-Highway2050 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.

For this study the 100% RES scenario from the e-Highway2050 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 2014 and 2050 the total installed generation capacity increases from 1,000 GW to 2,250 GW and the demand for and generation of electricity increases from about 3,250 TWh to 4,400 TWh. In 2050 there is still a (back-up) generation capacity of 75GW biogas; this is considered as biomass.

General introduction to the 100% RES-scenario1. Analysis of 100% RES scenario of e-Highway2050

F6: Electricity Generation in Europe in 2050

F5: Installed Generation Capacity in Europe

0

500

1000

1500

2000

2500

2014 2050

GW in

stal

led

Wind Solar Biomass Gas Coal Lignite Nuclear Oil Mixed Hydro

DNV GL ©201718

The e-Highway2050 100% 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 0.7 GW.

Accordingly, the cross-border capacity used in the 100% RES scenario is 14.7 GW. The interconnection capacity of the different PtG cases analysed in this study varies between 0.7 GW and 13.7 GW.

The e-Highway2050 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 40 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.

Situation Netherlands and Norway1. Analysis of 100% RES scenario of e-Highway2050

F7: European Electricity Interconnection – 100% RES

F8: Electricity Demand in NL and NO F9: Installed capacities in NL and NO

DNV GL ©201719

The PtG cases were build on the assumption of an existing gas infrastructure in 2050 becoming available for the transportation of hydrogen. A prerequisite for this situation is a continued gas demand in 2050. The e-Highway 2050 100% 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 generationThe 100% RES scenario assumes that in 2050, electricity is fully generated by renewable energy sources. Hence, no gas demand here.

TransportA high rate of electrification is assumed (90%). 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 0.5-1.0% of the total gas demand, the overall impact of this assumption is small.

Heat demand in residential, commercial and industrial sectorIn the 100% RES scenario of the e-Highway2050 study, heat demand in Europe is expected to be influenced by several developments:

• Energy efficiency is expected to reduce heat demand by 45% towards 2050. We assume that gas demand used for heating is reduced with this amount as well: Thus towards 2050, gas demand for heating is reduced by 45% to account for an increase in energy efficiency.

• The e-Highway2050 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-Highway2050 assumes growth in heat demand due to GDP growth (increased demand in industry) and population (increased demand in

the residential and commercial sector). We assume that new heat demand is fully electric in the 100% 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 80%.

Analysis of the gas demand in 20501. Analysis of 100% RES scenario of e-Highway2050

402

199

862

190

855

188

0176

176

519

1.305

-77%

2050

33

2010

5.739

1.837

33

1.574

Power generation

Residential

Commercial

Industry (heat)

Industry (process)

Industry (feedstock)

Transport

F10: European gas demand in 2010 and 2050 [TWh/year]

Note: 2010 served as the basis for the eHigh-way study. This analysis therefore departs from the same year, although more recent data are available.

DNV GL ©201720

The charts below show the impact of the assumptions of the 100%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

that there will be a remaining annual gas demand of approximately 120 TWh (the reduction in gas demand with respect to 2010 is therefore ~75%). The remaining infrastructure to transport the gas is assumed to become available for hydrogen transport in the power-to-gas cases.

Analysis of the gas demand in 20501. Analysis of 100% RES scenario of e-Highway2050

600 1.2001.0008004002000

15Lithuania 32

Latvia 19Cyprus 0

Italy 873Croatia 33France 545Spain 400

Greece 42Ireland 60Estonia 7

Germany 981Denmark 57

Czech Republic 103Bulgaria

Kosovo 0Bosnia & H. 3

Turkey 406Serbia 24

Albania 0FYROM 1

Montenegro 0Norway 100Iceland 0

United Kingdom 1.086Sweden 19Finland 50

Slovakia 65Slovenia

105

Romania 135Portugal 58

Poland 163Austria

Netherlands 507Malta

11

0Hungary 125

Ukraine 705Moldova 29

Luxembourg

30Belgium 220

Power generationTransportIndustry (feedstock)Industry (process)Industry (heat)CommercialResidential

400 1.000 1.2000 200 800600

Austria

2Luxembourg30

10Latvia 2

Lithuania

Cyprus

8Serbia56

Bosnia & H.

0Montenegro

Iceland

1

FYROM

Turkey

Norway 250

0

0

Albania

0Italy 162

12France 143Spain 67

Croatia

8Ireland 6Estonia 2

Germany 257Denmark 10

Czech Republic 28Bulgaria 10Belgium 58

59

United Kingdom 215Sweden 4Finland

25

Slovakia 21Slovenia 3Romania 39Portugal 6

Poland

0

Greece

NetherlandsMalta

120

Hungary

UkraineMoldova

2343

Kosovo

0

5

F12: Gas Demand in 2050 [TWh/year]F11: Gas Demand in 2010 [TWh/year]

DNV GL ©2017

-20000

-15000

-10000

-5000

0

5000

10000

15000

20000

0%

3%

6%

9%

11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%

Energ

y flo

w thro

ugh

NL-

NO

in

terc

onnect

ion (flo

w fr

om

NL

to N

O

is p

osi

tive

) (M

Wh)

% of hour in a year

OA

21

The e-Highway2050 100% RES scenario was simulated in DNV GL’s electricity market model (Case 0A). 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 winter-period, 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 capacitySubsequently, the e-Highway2050 100% 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 0B). Accordingly, the cross-border capacity between the two countries is limited to 0.7 GW.

The results show that the reduced interconnection capacity leads to a decrease of almost 50 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 0.7 GW provokes curtailment of 25 TWh of wind and solar power in Europe.

Results Case 0A – reference scenario1. Analysis of 100% RES scenario of e-Highway2050

F13: Flow through the NL-NO interconnector (Case 0A)

F14: Change in electricity generation due to 14 GW reduced interconnector capacity (Case 0B) in TWh/yr

1.24.6 1.9 1.6

7.2

0.0

4.70.4

8.61.3 0.8

4.10.2

-2.7

-49.5

2.2 0.6

-0.5

0.2 0.45.8

-50

-40

-30

-20

-10

0

10

20

AT BE CH CZ DE DK ES FI FR HU IE IT NI NL NO PL PT SE SI SK UK

TWh

gene

rati

on

T1: Generation costs (M€) 0A

Europe 68,451

NO 52

NL 1707

DNV GL ©201722

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 utilizationIn Case 0A 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 0B), 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.

Generation costsThe 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 7,028 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 10% of this trade volume.

Results Case 0B – Impact of 14 GW less IC capacity1. Analysis of 100% RES scenario of e-Highway2050

F15: Change in total generation costs per country (M€/yr)

T2: Impact of 14 GW less NL-NO capacity on generation costs per region

Change in generation costs (M€/yr)

EU 7,028

NO -47

NL 412

88

727

198

1,164

974

412

674

209138

-47

146

23106

16

731

1,260

554

114

-28

65

-200

0

200

400

600

800

1000

1200

1400

AT BE CH DE FR NL IT CZ IE NO PL PT SK SI ES UK DK FI HU SE NI

M€

T3: Peak hydropower utilization(GW) Case 0A Case 0B

Hydro pumped storage 17.3 13.7

Hydro Reservoir 42.5 36.0

DNV GL ©201723

Role of the Netherlands-Norway interconnectorThe 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 generationReducing the 14.7 GW to 0.7 GW interconnection capacity reduces the amount of low-cost electricity transported from Norway to the Netherlands and reduces the flow towards Norway in the summer-period. 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.

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.

Removing interconnection capacity causes increase in electricity generation costsDue 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 ( ~0 €/MWh) to expensive back-up generation (~27 TWh, 200-300 €/MWh) and biomass (~7 TWh, 20-40 €/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 7,028 M€/a. For the Netherlands an increase of 412 M€/a is found, while generation costs decrease with 47 M€/a in Norway.

Summary and interpretation of the results1. Analysis of 100% RES scenario of e-Highway2050

DNV GL ©2017


24

Analysis of PtG cases

8910

121415

1718192123

252628313336

3942454851525455

57585960








Introduction

Methodology




Conclusions

Annex

DNV GL ©201725

Simulated casesThe 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).

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

• Peak hydropower generation in Norway (to assess possible reduction in hydropower generation capacity investments)

Outputs collected in simulations with PtG:• Electricity stored (TWh H2) using PtG• Electricity generated (TWh elec) by PtGtPower

• Development of H2 volume (TWh) stored in the PtGtPower cases

A. Case definition2. Analysis of the PtG cases

T4: Case characteristics

NL-NO IC capacity Type PtG PtG functionality Location

PtGCapacity

PtGLocation

GtPCapacity

GtP Comment

Case 0A 14.7 GW (no PtG) e-Highway2050 100%RESCase 0B 0.7 GW (no PtG) e-Highway2050 100%RESCase 0C 0.7 GW To Power Balancing & storage NL 14 GW NL 6.3 e-Highway2050 100%RESCase 0D 0.7 GW To Product Balancing NL 14 GW e-Highway2050 100%RES

Case 1A 13.7 GW (no PtG) e-Highway2050 100%RESCase 1B 13.7 GW to Power Balancing & storage NL 1 GW NL 0.45 GW e-Highway2050 100%RESCase 1C 13.7 GW to Product Balancing NL 1 GW NL n.a. e-Highway2050 100%RES

Case 2A 14.7 GW (no PtG) Adjusted hydropower capacityCase 2B 0.7 GW (no PtG) Adjusted hydropower capacityCase 2C 0.7 GW to Power Balancing & storage NL 14 GW NL 6.3 GW Adjusted hydropower capacityCase 2D 0.7 GW to Product Balancing NL 14 GW Adjusted hydropower capacity

Case 3A 0.7 GW to Power Long-distance energy transmission NO 14 GW NL 6.3 GW Adjusted hydropower capacity

DNV GL ©201726

In Case 0C we investigated the impact of reducing the NO-NL interconnector with 14 GW down to 0.7 GW combined with a 14 GW PtGtPower facility in NL. The results of this case are compared to the original 100% RES of the e-Highway2050 study (case 0A).

PtG faciliy utilizationIn 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 ~40% (see also Figure 17).

Volume of hydrogen storedThe 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 costsCase 0C 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 40%) compared to Case 0B (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.

Results Case 0C– Impact of 14 GW less IC capacity with PtGtPower 2. Analysis of the PtG cases

F16: Duration curve of power-to-gas and gas-to-power in case 0C

F18: Volume of stored hydrogen (TWh hydrogen)

T5: Change in generation costs compared to case 0A (M€/yr) Case 0B Case 0C

EU 7,028 4,356

NO -47 -47

02468

10121416

0% 3% 6% 9% 12%

15%

17%

20%

23%

26%

29%

32%

35%

38%

41%

44%

47%

49%

52%

55%

58%

61%

64%

67%

70%

73%

76%

79%

82%

84%

87%

90%

93%

96%

99%El

ectr

olys

er a

nd f

uel c

ell

utili

zatio

n (G

W)

% of hours of a year

Generation (GW elec)

H2 production (GW elec)

0

5

10

15

20

25

30

Am

ount

of H

ydro

gen

in s

tora

ge

(TW

h H

2)

Time of year

DNV GL ©201727

In Case 0D we investigated the impact of reducing the NO-NL interconnector with 14 GW down to 0.7GW combined with a 14 GW PtGtProduct facility in NL. The results of this case are compared to the original 100% RES of the e-Highway2050 study (case 0A).

PtG facility utilizationThe 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 costsAs 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 30 €/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.

In comparison with case 0B and 0C, case 0D shows the highest increase in total generation (see also Table 6). The increase of 7,452 M€ compared to the reference case (Case 0A) 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.

Results Case 0D– Impact of 14 GW less IC capacity with PtGtProduct2. Analysis of the PtG cases

F19: Duration curve of power-to-gas and gas-to-product in case 0D

T6: Change in generation costs (M€/yr) Case 0B Case 0C Case 0D

EU 7,028 4,356 7,452

NO -47 -47 -461

0

2

4

6

8

10

12

14

16

GW

pow

er u

sed

for

H2

prod

uct

% of hours in a year

DNV GL ©201728

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 0A).

FlowReducing 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 20): at 13.7 and –13.7 GW for case 1A instead of 14.7 and -14.7 GW in case 0A. This results in a 3 TWh decrease in the annual net flow from NO to NL.

PricesReducing the NO-NL interconnector with 1 GW has no impact on the price duration curve of the Netherlands (see Figure 21).

Hydropower utilizationThe reduced export capacity has a small impact on the peak capacity utilization of Norwegian pumped hydro storage capacity (0.1 GW reduction). Adding a PtG facility in NL does not impact the maximum instantaneous hydropower generation in Norway (see also Table 7).

Generation costsThe 1 GW reduction in NO-NL interconnector capacity increases the European electricity generation costs by 24 M€ (0.04% 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).

Results Case 1A – Impact of 1 GW less IC capacity2. Analysis of the PtG cases

-20000

-15000

-10000

-5000

0

5000

10000

15000

20000

0%

3%

6%

9%

11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%

Energ

y flo

w thro

ugh

NL-

NO

in

terc

onnect

ion (flo

w fr

om

NL

to N

O

is p

osi

tive

) (M

Wh)

% of hour in a year

OA 1A

050

100150200250300350400

0% 3% 6% 9% 11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%

€/M

Wh


0A 1A

T8: Generation costs (M€/yr) 0A 1A Difference Difference

Europe 68,451 68,475 +24 +0.04%

NO 52 49 -4 -4.7%

NL 1707 1719 +12 +7%

T7: Hydro (GW) 0A 1A Difference

Reservoir 42.5 42.5 +0.0

Pumped storage 13.8 13.7 -0.1

F21: Electricity price duration curve for the Netherlands (€/MWh)

F20: Duration curve for the flow of electricity across NO-NL inter-connector (flow from NL to NO is positive)(MWh)

DNV GL ©201729

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 0A). Additionally, the results are compared to the PtG case 0C, where the PtGtPower facility was larger (14 GW) as the interconnection capacity was reduced with 14 GW.

PtG utilizationThe utilization of the PtGtPower facility in the Netherlands is only slightly lower in case 1B (1 GW less interconnection capacity) compared to case 0C: 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 ~ 70% of the year vs. ~ 83% in case 0C, see also Figure 22).

Volume of hydrogen storedAs 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 0C.

Impact PtGtPower on system costsThe total (European) electricity generation costs are 231M€ (0.3% of total) lower for case 1B compared to the reference scenario (case 0A): 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).

Results Case 1B– Impact of 1 GW less IC capacity with PtGtPower 2. Analysis of the PtG cases

02000400060008000

10000120001400016000

0%

3%

6%

9%

11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%Genera

tion

and

sto

rage

load

(M

W)

% Hours of a year

NL 0C GtP NL 0C PtG NL 1B GtP NL 1B PtG

T9: Generation costs (M€/yr) 0A 1A 1B Difference

(1B – 0A)Difference

(1B-0A)

Europe 68,451 68,475 68,220 -231 -0.3%

NO 52 49 48 -4 -7.7%

NL 1707 1719 1739 +32 +1.2%


F22: Duration curve of power-to-gas and gas-to-power in case 1B

02468

101214161820

01/0

1/20

5001

/11/

2050

1/21

/205

01/

31/2

050

02/1

0/20

502/

20/2

050

03/0

2/20

5003

/12/

2050

3/22

/205

004

/01/

2050

04/1

1/20

504/

21/2

050

05/0

1/20

5005

/11/

2050

5/21

/205

05/

31/2

050

06/1

0/20

506/

20/2

050

6/30

/205

007

/10/

2050

7/20

/205

07/

30/2

050

08/0

9/20

508/

19/2

050

8/29

/205

009

/08/

2050

9/18

/205

09/

28/2

050

10/0

8/20

5010

/18/

2050

10/2

8/20

5011

/07/

2050

11/1

7/20

5011

/27/

2050

12/0

7/20

5012

/17/

2050

12/2

7/20

50

Hydr

ogen

sto

red

(TW

h_H2

)

Date

NL 0C NL 1B

DNV GL ©201730

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 0A). Additionally, the results are compared to the PtG case 0D, where the PtGtProduct facility was larger (14 GW) as the interconnection capacity was reduced with 14 GW.

PtGtProduct utilizationThe PtGtProduct facility in the Netherlands has a (slightly) higher utilization in the 1GW case compared to the 14GW case (case 0D). The reason behind this is that in case 1C the PtGfacility 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 costsTotal generation costs in Europe increase with 137 M€ (0.2% 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).

Results Case 1C– Impact of 1 GW less IC capacity with PtGtProduct2. Analysis of the power-to-gas cases

T10: Generation costs (M€)

0A 1A 1C Difference (1C – 0A)

Difference (1C – 0A)

Europe 68,451 68,475 68,588 +137 +0.2%

NO 52 49 49 -4 -5.8%

NL 1707 1719 1726 +19 +1.1%

0

2000

4000

6000

8000

10000

12000

14000

16000

0% 3% 6% 9% 11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%

Hou

rly e

lect

ricity

con

sum

ptio

n fo

r Pt

GtP

rodu

ct (M

Wh)

% of period of a year

NL 0D NL 1C

F24: Duration curve of power-to-gas and gas-to-power in case 1C

DNV GL ©201731

IntroductionThe e-Highway2050 100% RES Scenario assumes a tripling of installed capacity of hydropower in Norway from ~31 GW towards ~88 GW in 2050. Table 11 presents the currently installed capacities (by Q4 of 2016) vs. the assumptions made by the e-Highway2050 consortium for the development of these capacities towards 2050. 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 0C and 0D 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.

Findings literature – hydropower development until nowThe 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).

Results analysis potential hydropower capacity Norway2. Analysis of the PtG cases

T11: Hydropower in Norway 2016 E-Highway2050 100%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)

DNV GL ©201732

Proposed assumptions extension hydropowerBased on the literature review, DNV GL concludes that the e-Highway2050 100%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 2050 total capacity of ~30 GW.

• Run-of-River: significant increase compared to the current 2.5 GW, assuming an average increase based on the NVE and Statnettexpectations leads to a total capacity of ~13 GW

• Pumped Hydro Storage: we propose to assume the lower value of the mentioned potential, 10 GW

Concluding, the table is extended with the proposed capacities for 2050 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-Highway2050 100%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.

Results analysis potential hydropower capacity Norway2. Analysis of the PtG cases

T12: Hydropower Norway 2016 e-Highway2050 100%RES

NVEpotential Statnett Other DNV GL proposal

DNV GL –eHighway2050

100%RES

Total installed capacity 31.7 GW 87.9 GW 37.4 – 57.4 GW ~49 GW 50 GW (SINTEF) 53 GW -32.9 GW

Reservoir capacity 27.8 GW 42.5 GW 30.4 GW 29.8 GW 30 GW -12.5 GW

Run-of-river capacity 2.5 GW 28.1 GW 7.0 GW 19 GW 13 GW -15.1 GW

Pumped hydro storage capacity 1.4 GW 17.3 GW ~10-20 GW na ~10-20 GW 10 GW -7.3 GW

Total generated electricity ~133 TWh ~199 TWh 165 TWh na 300 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)

DNV GL ©201733

To analyse the impact of less installed hydropower capacity in Norway, we performed a simulation with the original e-Highway2050 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).

FlowAs 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 0A: 45 TWh instead of 57 TWh. The flow duration curve shows that there are 20% more hours in which the interconnection capacity is not fully utilized (comparing case 2A with 0A). This observations implies that there is increasing price convergence between Norway and the Netherlands.

PricesThe price duration curve for the Netherlands shows that in case of less hydropower generation in Norway, there are almost 10% more hours in which expensive back-up generation is price-setting (see at a price of ~200 €/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 costsGeneration 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 0A) , with a clear impact of lowering the interconnection capacity (case 2B vs 2A). The detailed results are presented in Table 12.

Hydro utilizationIn 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).

Results Case 2A and 2B– Impact of less Norwegian hydro2. Analysis of the PtG cases

-20000

-15000

-10000

-5000

0

5000

10000

15000

20000

0% 3% 6% 9% 11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%

Ener

gy flo

w th

roug

h NL

-NO

inte

rcon

nect

ion (f

low

from

NL

to N

O is

posit

ive) (

MWh)

% of hour in a year

OA 2A 2B

050

100150200250300350400

0% 3% 6% 9% 11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%

€/M

Wh


0A 2A 2B

T12: Generation costs (M€/yr) 0A 2A 2B

Europe 68,451 74,648 76,689

NO 52 77 45

NL 1707 1,883 2,138

T13: Hydro (GW) 0A 2A Difference (2A-0A) 2B Difference (2B-2A)

Reservoir 42.5 30.0 -12.5 30.0 +0.0

Pumped storage 13.8 9.7 -4.1 9.5 -0.2

F26: Duration curve for the flow of electricity across NO-NL interconnector (flow from NL to NO is positive)

F27: Electricity price duration curve for the Netherlands (€/MWh)

DNV GL ©2017

02000400060008000

10000120001400016000

0% 3% 6% 9% 11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%Gen

erat

ion

and

stor

age

load

(M

W)

% Hours of a year

NL 0C GtP NL 0C PtG NL 2C GtP NL 2C PtG

34

For case 2C we repeated the analyses done in case 0C (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 utilizationThe utilization of the PtGtPower facility in the Netherlands in case 2C is almost similar to the 0C case: the overall utilization of the electrolyser (PtG) and the fuel cell (GtP) in case 2C is slightly lower compared to case 0C (20 TWh vs. 21 TWh). The required storage volume is slightly higher in case 2C being 20 TWhcompared to 18.7 TWh in case 0C.

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 50% of the hours with electricity price below 50 €/MWh.

Impact PtGtPower on generation costsThe 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 0C), the following is observed: whereas in Phase I generation costs in Europe increase (case 0C – 0A), 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.

Results Case 2C – Impact of less Norwegian hydro and PtGtPower2. Analysis of the PtG cases

T14: Generationcosts (M€/yr) 2A 2C Difference

(2C – 2A) 0C Difference (0C – 0A)

Europe 74,648 73,675 -973 72,807 +4,356

NO 77 45 -32 5 -47

NL 1,883 2,288 +405 2,323 +616

F28: Duration curve of electricity consumed and produced using PtG


0

5

10

15

20

25

01/0

1/20

5001

/11/

2050

1/21

/205

01/

31/2

050

02/1

0/20

502/

20/2

050

03/0

2/20

5003

/12/

2050

3/22

/205

004

/01/

2050

04/1

1/20

504/

21/2

050

05/0

1/20

5005

/11/

2050

5/21

/205

05/

31/2

050

06/1

0/20

506/

20/2

050

6/30

/205

007

/10/

2050

7/20

/205

07/

30/2

050

08/0

9/20

508/

19/2

050

8/29

/205

009

/08/

2050

9/18

/205

09/

28/2

050

10/0

8/20

5010

/18/

2050

10/2

8/20

5011

/07/

2050

11/1

7/20

5011

/27/

2050

12/0

7/20

5012

/17/

2050

12/2

7/20

50

Hyd

roge

n st

ored

(TW

h_H

2)

Date

NL 0C NL 2C

DNV GL ©201735

In case 2D we repeated the analyses of case 0D (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, 0D and 2D are compared with each other.

PtG utilizationThe utilization of the PtGtProduct facility in the Netherlands (case 2D) is slightly lower compared to case 0D (~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 0D in which there is more hydropower generation available in Norway (see also Figure 30).

Impact PtGtProduct on generation costsThe 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 0D, the following is observed: the increase in total generation costs in Europe of 7.4 billion for case 0D – 0A) 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).

Results case 2D – Impact of less Norwegian hydro and PtGtProduct2. Analysis of the power-to-gas cases

T15: Generation costs (M€/yr) 2A 2D Difference

(2D – 2A) 0D Difference (0D – 0A)

Europe 74,648 76,732 +2,084 75,903 +7,452

NO 77 46 -31 -409 -461

NL 1,883 2,120 +237 2,151 +444

F30: Duration curve of electricity consumed using PtG

0

2000

4000

6000

8000

10000

12000

14000

16000

0% 3% 6% 9% 11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%

Hou

rly e

lect

ricity

con

sum

ptio

n fo

r Pt

GtP

rodu

ct (M

Wh)

% of period of a year

NL 0D NL 2D

DNV GL ©2017

050

100150200250300350400

Hyd

roge

n flo

w (G

Wh_

H2)

Date

H2 transport (GWh H2) (Case 3A) Power transport (GWh elec) (Case 2A)

36

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, H2transport via pipeline from Norway to Netherlands (transport time of 24hrs), and a 6.3 GW gas-to-power facility in NL.

Pipeline utilizationThe H2 transport through the pipeline compensates the 14 GWelreduction in power transmission capacity: the combined power and H2transport from Norway to the Netherlands is 2.0 TWh electricity and 23 TWh H2, which is comparable to the power flow in the case with 14.7 GW power transmission capacity (case 2A) which was 44 TWh.

Note that in Figure 18 the H2 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 utilizationThe 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, 20 TWh of electricity is generated using power-to-gas and one requires a storage tank of maximum 20 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 costsLocating 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.

Results 3A – Long distance energy transmission2. Analysis of the power-to-gas cases

F31: Daily H2 flow from NO to NL through pipeline (GWh)

F32: Duration curve of electricity consumed & produced using PtG

02000400060008000

10000120001400016000

0% 3% 6% 9% 11%

14%

17%

20%

23%

26%

29%

31%

34%

37%

40%

43%

46%

49%

51%

54%

57%

60%

63%

66%

69%

71%

74%

77%

80%

83%

86%

88%

91%

94%

97%

Gen

erat

ion

and

stor

age

load

(M

W)

% Hours of a year

NL 2C GtP NL 2C PtG NL 3A GtP NO 3A PtG

T16: Generation costs (M€/yr) 2A 3A Difference

(2C – 2A)Difference (2C – 2A)

Europe 74,648 72,813 -1,836 -2.5%

NO 77 287 +210 +373%

NL 1,883 2,163 +280 +14.9%

DNV GL ©201737

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 80% of natural gas for high calorific natural gas under the same circumstances and approximately equal for low

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 GWel. 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.

Results 3A – Long distance energy transmission2. Analysis of the power-to-gas cases

F33: Energy-transport losses for hydrogen-natural gas mixtures

80%

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 compressors2. Reciprocating compressors

Centrifugal compressors are well-suited for large flows and relatively low compression ratios (Pout/Pin). 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.

DNV GL ©2017


38

Comparison total system cost

38

8910

121415

1718192123

252628313336

3942454851525455

57585960








Introduction

Methodology




Conclusions

Annex

DNV GL ©201739

As each option (electricity cables or PtG) shares certain costs with other options, only relevant differences between costs are identified. Costs unique to an option (in comparison with the other option) are added to the system costs of that option. The table below shows all relevant cost items, including a description of the cost element.

Identification of relevant cost elements 3. Comparison total system cost

T17: Relevant Cost Elements

Description

Electricity production costs A difference may occur in the costs of producing electricity. Therefore, for both scenarios the costs of electricity produced will be calculated and compared. For both scenarios, the market simulations will provide these costs.

Power-to-gas plant The power-to-gas alternative requires the installation of a power-to-gas plant. Hence, these costs are added to the power-to-gas scenario. The costs of the power-to-gas plant consists of the elements shown below.

Electrolyzer As the principal component of a power-to-gas plant, the costs of electrolysis equipment is added to the power-to-gas scenario. It is assumed that the electrolyzer comes with a water desalination unit.

H2 storage Given the quantities of H2 produced by the PtG plant, a storage facility for temporarily storing hydrogen are taken into account. The size of the storage facility results from the market simulations.

Fuel cell In case the produced hydrogen is used to generate electricity in times of low demand, fuel cells are required to convert hydrogen to electricity. When hydrogen is supplied to other market segments (e.g. industry or mobility), the costs of fuel cells do not have to be taken into account.

Electricity The power-to-gas plant requires electricity to produce hydrogen. The plant will only be put into operation if electricity prices are low. The market simulations provides the average electricity price (over the whole year) for the Netherlands where the PtG plant is located.

Electricity cable The costs of the electricity cable between the Netherlands and Norway, and between France and the UK, are added to the e-Highway2050s scenario.

Hydrostorage The costs of hydrostorage in Norway are added to the e-Highway2050s scenario.

Conventional H2production

In the e-Highway2050s scenario the costs for producing hydrogen for industrial purposes in a different way than using PtGneed to be added. It is assumed that steam methane reforming (SMR) is used as an alternative way of producing hydrogen. In the PtG scenario, these costs are not included as the PtG plant produces hydrogen.

Natural gas usage Natural gas is used as feedstock for steam methane reforming and the costs of purchasing natural gas should thus be added to the e-Highway2050s scenario.

DNV GL ©201740

The PtG cases were compared to the results of e-Highway2050 (100% RES, the ‘reference case’) to indicate which costs are unique for each option. To estimates these costs, an assessment of the differences between both options is carried out. This assessment shows where the costs should be included.


T18: Costs Base case (100% RES e-Highway2050)

PtGtProduct(Cases 0D, 1C, 2D)

PtGtPower (Cases 0C, 1B, 2C, 3A)

Electricity production costs Yes, simulation Yes, simulation Yes, simulation

Power-to-gas plant

Electrolyzer No Yes Yes

H2 storage No Yes Yes

Fuel cell No Yes Yes

Electricity No Yes, simulation Yes, simulation

Purified water No Yes Yes

Fuel cell No No Yes

Electricity cable Yes No No

Hydrostorage Yes No No

Conventional H2 production Yes No Yes

Natural gas Yes No Yes

DNV GL ©201741

The table below shows the specific CAPEX and OPEX of the different cost categories. Where applicable, total costs are calculated by multiplying the specific cost with the capacity of the respective asset as shown on the next slide. In turn, capacities of the assets are either the result of specific assumptions made (e.g. PtG plant and thus electricity cables) or results from the market simulation (e.g. hydrostorage).

In addition, the costs of electricity production are provided as a result from the market simulation. This also applies for the cost of electricity input to the PtG plant. In fact, the latter is already included in the total production costs provided by the simulation. Furthermore, the cost of purified water – required for electrolysis - is included in the CAPEX and variable O&M of the electrolyzer.


Sources and notes:1. Sgobbi et al., E4Tech, Sterner, IEA Technology Review. Includes stack replacement, and labour and others.2. IEA Technology Review, PtG Roadmap Flanders, Sgobbi et al. Includes stack replacement, oxygen, and labour and others. 3. NorNed, BritNed, and NorGer4. Sgobbi et al.5. Jakobsen and Åtland, “Concepts for Large Scale Hydrogen Production”, Norwegian University of Science and Technology, June 20166. IRENA, “Renewable Energy Technologies: Cost Analysis Series - Hydropower”, June 2012

T19: Specific Cost Capex Variable O&M Fixed O&M Lifetime (yr)

Electricity production costs Results from market simulation

Power-to-gas plant

Electrolyzer (1) 500 €/kW 5.9 €/MWhH2 28 €/kW/yr 15

H2 storage (4) 10.77 €/(MWh/yr) 0.91 €/(MWh/yr) 40

Fuel cell (2) 500 €/kW 5.6 €/MWhel 28 €/kW/yr 15

Electricity Results from market simulation

Electricity cable (offshore) (3) 2000 €/MW/km 1377 €/km/yr 50

Hydrostorage (6) 1000 €/kW Simulation 2.5% of installed cost p.a. 100

Conventional H2 production incl. CCS (5) 1770 €/kg/day 5% of installed cost p.a. 30

Natural gas 11.0 €/GJ

DNV GL ©201742

Input parametersThe table below shows the capacity of the various assets for case 0C and case 0D and how these capacities were derived (‘Source’). A key assumption is the decision to replace the entire grid reinforcement capacity of 14 GW by a PtG installation.

Therefore, the capacity of the electrolyzer equals 14 GW. Apart from the length of the H2 grid connection, most of the other values result from the simulation.

Case 0C and case 0D 3. Comparison total system cost

T20: Input parameters system cost analysis case 0C and 0D

PtGtProduct - Case 0D PtGtPower - Case 0C Source

Electrolyzer capacity [GW] 14 14 Based on capacity of electricity cable

Fuel cell capacity [GW] n.a. 6.3 Resulting from simulation

Hydrogen production [TWh] 25.8 31.5 Resulting from simulation

Electricity input electrolyzer [TWh] 38.5 47 Resulting from simulation

H2 grid connection length [km] 10 km 10 km Assumption by DNV GL

Compressor power requirement [MW] 44 44 Calculated based on hydrogen production

Hydrogen storage [TWh] 18.6 18.6 Resulting from simulation

Reduced hydrostorage in Norway [GW] 10 10 Resulting from simulation

Replaced electricity cable length [km] 1 000 1 000 Based on distance Rotterdam-Bergen

DNV GL ©201743

Case 0C - PtGtPowerThis Power-to-Gas-to-Power case is less expensive when solely looking at the investment and operational costs associated with the assets required. Annual costs are around 1.9 billion Euros compared to 4.2 billion Euros for the e-Highway2050 solution.

However, the Power-to-Gas-to-Power alterative is considerably more expensive than the 100% RES scenario of the e-Highway2050 study when including the increase in production costs across Europe. Norway produces low cost hydropower which cannot reach Europe when removing the interconnection between the Netherlands and Norway. This increases the cost of generation in Europe considerably, with nearly 4.4 billion Euros annually.

As mentioned before, a key assumption in this analysis was the decision to remove the 14 GW additional interconnector capacity between Rotterdam and Bergen in its entirety. With this capacity limitation, low-cost Norwegian hydropower can only be partly transported to the rest of Europe. As a result, more expensive generation needs to produce the required electricity. This increases the total generation costs.

Results for Case 0C3. Comparison total system cost

7.000

9.000

1.000

0

2.000

3.000

4.000

5.000

6.000

8.000

27,910,9

17,0

Gas grid TSO

0,5

669,3651,8

1.321,1

Electrolyzer Hydrogen storage

282,23,3

5,18,4

Compression

4.356,0

Generation cost

increase

6.289,4

Total

293,3

575,5

0,5

Fuel Cell

0,1

4.356,0

CAPEXOPEX

4.000

3.000

2.000

1.000

0

9.000

8.000

7.000

6.000

5.000

1,4

Total

2.711,3

Hydrostorage

1.293,1

865,6427,5

Electricity cable

1.418,2

1.416,9

F34: Case 0C – annual costs (M€/a) F35: Case 0A – annual costs (M€/a)

CAPEXOPEX

1,933

Costs w/o increase in generation costs

DNV GL ©201744

Case 0D - PtGtProductThe Power-to-Gas to Product alternative is again less expensive when solely looking at the investment and operational costs associated with the assets required. Annual costs are around 1.3 billion Euros compared to 4.2 billion Euros for the e-Highway2050 solution.

However, similarly to Case 0C, the PtG to power alterative is considerably more expensive than the e-Highway2050 alternative when including the increase in production costs across Europe. Generation costs in Europe increase by 7.5 billion Euros annually.

The same conclusion can be drawn as on the previous slide: the complete removal of the electricity cable was limits the ability of low cost Norwegian hydropower to reach the rest of Europe. This in turns leads to a large difference in the total generation cost. The fact that the electricity that is converted into hydrogen is redirected to industries and does not enter the electricity system again in times of high demand reinforces this effect.

Results for Case 0D3. Comparison total system cost

9.000

3.000

2.000

1.000

0

8.000

7.000

6.000

5.000

4.000

0,50,5

Total

8.759,7

Production cost

increase

7.452,0

Compression

8,45,1

3,3

Hydrogen storage

619,210,9

17,0

Gas grid TSO

651,8

1.270,9

Electrolyzer

0,1

27,9

CAPEXOPEX

4.000

7.000

6.000

5.000

9.000

8.000

3.000

2.000

1.000

0Total

4.156,2

Conventional H2 production

1.444,9

194,9

1.250,0

Hydrostorage

1.293,1

865,6427,5

Electricity cable

1.418,2

1.416,9

1,4


CAPEXOPEX

1.307

Costs w/o increase in generation costs

DNV GL ©2017

T21: Input parameters system cost analysis case 1B and 1C

1B - PtGtPower 1C - PtGtProduct Source

Electrolyser capacity [GW] 1 1 Based on capacity of electricity cable

Fuel cell capacity [GW] 0.45 n.a. Resulting from simulation


Electricity input electrolyser [TWh] 3.028 3.037 Resulting from simulation

H2 grid connection length [km] 10 km 10 km Assumption by DNV GL

Compressor power requirement [MW] 8.2 8.2 Calculated based on hydrogen production

Hydrogen storage [TWh] 1.29 n.a. Resulting from simulation

Reduced hydrostorage in Norway [GW] 0.816 0.816 Resulting from simulation


45

Capacity, volumes and length requirementsThe table below shows the capacity of the various assets under the two cases 1B and 1C and how or where these capacities were derived (‘Source’). A key assumption is the decision to replace 1 GW of interconnection capacity by a PtG installation.

Therefore, the capacity of the electrolyzer equals 1 GW as well. Apart from the length of the H2 grid connection, most of the other values result from the simulation.

Case 1B and 1C 3. Comparison total system cost

DNV GL ©201746

Case 1B - PtGtPowerThe economic comparison between case 1B and the reference case 0A is carried out on the basis of total system costs. Under this approach, the system costs unique to each case are compared to each other, i.e. as each option (0A and 1B) shares certain costs with other options, only relevant differences between costs are identified. The case featuring the lowest system costs is the preferred one from an economic point of view.

Figure 38 illustrates the annual (system) costs of case 1B. The CAPEX and OPEX related costs for the PtGtPower installation amount to approximately 136 M€/yr. In comparison, costs related to the

installation and operation of the electricity cable and the hydrostoragefacilities in Norway totals 208 M€/yr (see also Figure 38).

The delta in electricity generation is represented as a cost reduction for case 1B. The negative total system costs of -94 M€/yr mean that the decrease in electricity generation costs more than compensates for the costs for the installation and operation of the PtG facility.

The results of the system cost analysis suggest that by replacing a 1 GW electricity interconnector between Norway and the Netherlands by a 1 GW PtGtPower installation in the Netherlands, total annual costs will decrease by approximately 302 million Euros on an annual basis.

Results for Case 1B3. Comparison total system cost

500

250

450

400350

300

-150

200150

10050

0

-100

-50

1

231

2

-94

Change in generation

cost

1

Fuel CellElectrolyzer

92

Total

4621

Hydrogen storage

Gas grid TSO

47

219 1

401

CAPEXOPEX

-100-150

-50

250

150

50

200

450

100

0

300

400

500

350

Electricity cable

10635

208

71

Hydrostorage

103

101

1

Total

OPEX CAPEX

F38: Case 1B – annual costs (M€/a) F39: Case 0A – annual costs (M€/a)

DNV GL ©201747

Case 1C - PtGtProductThe economic comparison between case 1C and the reference case 0A is carried out on the basis of total system costs. Under this approach, the system costs unique to each case are compared to each other, i.e. as each option (0A and 1C) shares certain costs with other options, only relevant differences between costs are identified. The case featuring the lowest system costs is the preferred one from an economic point of view.

Figure 39 illustrates the annual (system) costs of case 1C. The CAPEX and OPEX related costs for the PtG installation amount to approximately 94 M€/yr. In comparison, the costs related to the installation and operation of the electricity cable, the hydrostorage facilities in Norway

and the conventional H2 production facilities (SMR) totals 322 M€/yr(see also Figure 40).

Case 1 C features higher electricity generation costs of 137 M€/yrcompared to the reference case 0A. However, total system costs amount to 232 M€/yr for the PtGtProduct case, compared to 322 M€/yrfor the eHighway reference case.

In conclusion, the results of this analysis suggest that by replacing a 1 GW electricity interconnector between Norway and the Netherlands by a 1 GW PtGtProduct installation in the Netherlands, total annual costs will be lower by approximately 90 M€.


500

450

400

350

300

250

200

150

100

50

0Change in

production cost

137

2

Gas grid TSO

11

Total

232

Electrolyzer

92

47

46

CAPEXOPEX

150

400

500

450

350

300

250

200

100

50

0

106

71

35

Electricity cable

103

101

1

Total

322


114

15

99

Hydrostorage


OPEX CAPEX

DNV GL ©2017

T22: Input parameters system cost analysis case 1B and 1C

2C - PtGtPower 2D – PtGtProduct Source

Electrolyser capacity [GW] 14 14 Based on capacity of electricity cable

Fuel cell capacity [GW] 6.3 n.a. Resulting from simulation


Electricity input electrolyser [TWh] 45.4 36.0 Resulting from simulation

H2 grid connection length [km] 10 10 Assumption by DNV GL

Compressor power requirement [MW] 115 115 Calculated based on hydrogen production

Hydrogen storage [TWh] 20 n.a. Resulting from simulation

Reduced hydrostorage in Norway [GW] 0.134 0.134 Resulting from simulation


48

Capacity, volumes and length requirementsThe table below shows the capacity of the various assets under the two options (2C - ‘PtG to Power’ and 2D - ‘PtG to Product’) and how or where these capacities were derived (‘Source’).

It is noted that the major difference with the cases 1B and 1C is the size of the electrolyzer which was set at 14 GW again replacing the entire electricity cable between Norway and the Netherlands.

Identification of relevant cost elements for case 2C and 2D 3. Comparison total system cost

DNV GL ©201749

Case 2C - PtGtPowerThe economic comparison between case 2C and the new reference case 2A is carried out on the basis of total system costs. Under this approach, the system costs unique to each case are compared to each other, i.e. as each option (2A and 2C) shares certain costs with other options, only relevant differences between costs are identified. The case featuring the lowest system costs is the preferred one.

Figure 41 illustrates the annual (system) costs of case 2C. The CAPEX and OPEX related costs for the PtGtPower installation amount to approximately 1,936 M€/yr. In comparison, the costs related to the installation and operation of the electricity cable and the hydrostoragefacilities in Norway totals 1,435 M€/yr for case 2A (see also Figure 42).

The delta in electricity generation is represented as a cost reduction for case 2C. The total system costs amount to 963 M€/yr for case 2C, compared to 1,436 M€/yr for the new reference case 2A.

The results of the system cost analysis suggest that by replacing a 14 GW electricity interconnector between Norway and the Netherlands by a 14 GW PtGtPower installation in the Netherlands, total annual costs will decrease by approximately 473 M€ on an annual basis.

Note: case 2A did not adjust the interconnector capacity for the reduced hydrostorage capacity in Norway. However, with ~ 40% less hydropower capacity compared to the e-Highway2050 reference case (0A), the extension of the interconnector capacity between NO and NL would most probably not reach 14 GW.


2.500

1.000

1.500

500

2.000

0Total

279

293

572

Electrolyzer

660

973

12 18

Gas grid TSO

22

Fuel Cell

914

Hydrogen storage

30

963

1.312

652


cost

CAPEXOPEX

500

0

1.500

2.000

1.000

2.500

1.418

1.417

117

12

Electricity cable

61.436

TotalHydrostorage

OPEX CAPEX

F41: Case 2C (PtGtPower) – annual costs (M€/a) F42: New reference case 2A – annual costs (M€/a)

DNV GL ©201750

Case 2D - PtGtProductThe economic comparison between case 2D and the new reference case 2A is carried out on the basis of total system costs. Under this approach, the system costs unique to each case are compared to each other, i.e. as each option (2A and 2D) shares certain costs with other options, only relevant differences between costs are identified. The case featuring the lowest system costs is the preferred one from an economic point of view.

Figure 43 illustrates the annual (system) costs of case 2D. The CAPEX and OPEX related costs for the PtGtProduct installation amount to approximately 1,278 M€/yr. In comparison, the CAPEX and OPEX costs for the electricity cable and the conventional H2 production facilities (SMR) totals 1,787 M€/yr for case 2A (see also Figure 44).

The comparison of costs below shows that it is not cost efficient to place a Power-to-Gas to Product installation in the Netherlands as compared to an electricity cable between the Netherlands and Norway. Total annual costs are 575 MEUR higher than the annual costs incurred under the e-Highway solution.

The major determinant for this difference is the increase in the total production costs in Europe which alone accounts for roughly 2 billion Euros in additional costs. This is more than 60% of the total costs of the PtG to Product alternative. Furthermore, total annual costs of the e-Highway alternative include the costs for producing H2 in a conventional manner, which is a large share of the total costs for this alternative.

Results for Case 2D3. Comparison total system cost

500

0

1.000

3.000

2.500

2.000

1.500

3.500

Gas grid TSO Total

3.363

Production cost increase

2.084

Electrolyzer

1.256

652

605

2214 9

OPEX CAPEX

3.000

0

1.000

2.000

3.500

2.500

1.500

500

17

Hydrostorage

1.170

182

1.352


2.788

TotalElectricity cable

11.418

1.417

612

F43: Case 2D – annual costs (M€/a) F44: New reference case (2A) – annual costs (M€/a)

OPEX CAPEX

DNV GL ©201751

Figure 45 shows the total system cost of placing an electrolyzer in Norway, transporting hydrogen to the Netherlands, and converting it to electricity using fuel cells in the Netherlands. Investments required for the power-to-gas alternative are lower than those required for electricity transmission (blue bars labelled ‘CAPEX’). Including operational expenditures (green bars labelled ‘OPEX’) makes the power-to-gas alternative more expensive in terms of direct costs.

It is worth noticing that the indirect costs (the costs of electricity generation in Europe) of the all-electric solution (‘reference case’) are greater than those under the power-to-gas alternative. Stated differently, there are large savings on electricity generation costs to be made when chosing the power-to-gas alternative over the reference case in which electricity transmission is the preferred option.

Thus, the reduction in European-wide electricity production cost is remarkable and almost negates the other direct costs required (i.e. electrolyzer, fuel cells, gas grid and hydrogen storage) under the power-to-gas alternative. These relative savings, compared to the ‘new reference case’ in which electricity is transported, make power-to-gas a very attractive alternative compared to a all-electric solution. It is noted that this applies to the particular case studied and that, also provided the results of the other cases, a generalization of these results may not be justified on the basis of this single case. However, the analysis does show that power-to-gas may bring large benefits over a system solely based on electricity transmission. As such, depending on the particular case, power-to-gas and hydrogen transport can be regarded as a valid and economically attractive solution for a system largely based on electricity.

Results for Case 3A3. Comparison total system cost

F45: Case 3A (PtGtPower) – annual costs (M€/a)

1.000

500

0

2.000

2.500

1.500 1.418

Hydrostorage

1.4781

Total

40 20

Electricity cable

59

1.417

CAPEXOPEX

F46: New reference case 2A – annual costs (M€/a)

2.000

1.500

0

2.500

1.000

500

571

Fuel Cell

658

293

33


cost

3112

Gas grid TSO

20 13

652

19

109

1.836

Hydrogen storage

TotalElectrolyzer

1.310

278

CAPEXOPEX

DNV GL ©201752

Summary of results3. Comparison total system cost

99

963

-94

208

-2.000 2.0000 4.000 6.000 8.000

PtG in NL

100% RES

PtG in NL

100% RES 2.711

PtG in NL

100% RES 1.436

PtG in NO

100% RES 1.478

6.289

232

322

0 4.000 8.0006.000 10.0002.000

3.363

2.788

8.760

4.156

PtG to Power PtG to Product



Replacement of 14 GW electricity cable by PtGconsidering reduced hydrostorage in Norway

Replacement of 14 GW electricity cable by a PtG in Norway, transport of H2 to the Netherlands, and electricity generation by fuel cell in the Netherlands

Change in total annual system costs compared to the alternative solution (in MEUR)

PtGlowest costs

Not investigated

Case 1B Case 1C

Case 2C Case 2D

Case 3A

Results of e-Highway2050 (100% RES) assumptions

Results of PtG alternative

Case 0C Case 0D

DNV GL ©2017


53

Conclusions

8910

121415

1718192123

252628313336

3942454851525455

57585960








Introduction

Methodology




Conclusions

Annex

DNV GL ©201754

Summary of activitiesThe present study issued by the European Power to Gas Platform 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 100% RES scenario of the e-Highway2050 study (reference scenario). In order to reach this objective, the reference scenario was compared to number of power-to-gas cases in terms of total system costs. In this study, the following cases have been analysed:

1. Substituting 14 GW of the 14 GW planned grid extension with a 14 GW power-to-gas facility in the Netherlands

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 expansion in Norway by ~40% and substituting the 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).

ConclusionsFour out of seven analysed PtG cases showed lower total system costs compared to the 100% RES e-Highway2050 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 in Norway and otherwise curtailed electricity from wind and solar generation capacity.

When the hydrogen is re-electrified 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 infrastructure can be used for hydrogen transport; the additional transmission capacity allows for an optimized use of produced renewable electricity.

These are the top five conclusions from our analysis:

1. The cost-optimized pan-European electricity system as proposed by the e-Highway2050 study can be further optimized by deploying power-to-gas.

2. In a highly interconnected electricity supply system as proposed by the 100% RES scenario of the e-Highway2050 study, there is a amount of curtailed (renewable) electricity. Power-to-gas in combination with energy storage leads to higher utilization of installed solar and wind power capacities.

3. 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.

4. 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.

5. 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.

Summary and conclusions4. Conclusions

DNV GL ©201755

Final remarksWhen 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 40% 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.

• In those cases where power-to-gas leads to lower total system costs compared to the reference case(s), the reductions in system costs amount to 30-300% of the total power-to-gas installation and operational costs.

• When putting the benefits of the power-to-gas cases into perspective with the overall annual generation costs throughout Europe (between 68 and 75 billion euro, depending on the reference case), the achievable benefits calculated in this study seem to be rather small (maximal 2.5% of the total generation costs). However, this analysis only considered one single interconnector of the European transmission system. The potential benefits might therefore be higher when doing this analysis for a set of transmission lines.

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 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.

Final remarks and recommendations4. Conclusions

DNV GL ©2017

Contact details

SAFER, SMARTER, GREENER

www.dnvgl.com

PROJECT MANAGER PROJECT SPONSOR

56

Paula [email protected]+31 26 35 63 021

Johan [email protected]+31 26 356 24 23

DNV GL ©201757

DNV GL’s market model is based on the commercial software PLEXOS. PLEXOS is a state-of-the-art generation optimisation and price forecasting model. PLEXOS was specifically developed for the electricity industry and is a powerful simulation tool.

The figure below illustrates the dataflow within PLEXOS. On the left hand side there is an non-exhaustive list illustrating the input data. Based on this input, PLEXOS performs the simulation in two steps: the medium term schedule that optimizes the utilization of large hydro reservoirs across a whole year using a coarse time-resolution. The

short-term schedule performs the detailed hourly unit commitment and economic dispatch optimization, taking into account the hydro generation from the medium term schedule and amongst others the detailed representation of thermal generation, variability in renewable generation, and transmission constraints.

Simulations result relevant for this study are for example the total generation costs, interconnector flows and utilization of the PtG facilities.

Description Electricity Market ModellingAnnex A

PLEXOS

Integrated optimisation of dispatch

Optimal resource allocation

» Emission targets

» Fuel usage

» Hydro optimisation

Optimal dispatch

» Unit commitment and dispatch

» Total generation costs

» Load flows and exchanges

» Spot prices

» Load data

» Reserve margin

» Existing generation structure

» Network constraints

» New built options

» Fuel and CO2 prices

» Emission caps

» Reserve requirements

» RES profiles

Input data

Medium-Term Schedule

Short-Term Schedule

1

2

Outputs

F4: PLEXOS model structure

DNV GL ©201758

Assumptions generation costs per type of renewable energy sourceAnnex B

Technology Generation costs (€/MWh)

Solar 0

Hydro 0

Wind 0

Biomass 20-40

Back-up 200-300

DNV GL ©201759

The change in national generation is reflected in changes in the cross-border flows, as a result of removing the 14 GW interconnection capacity.

These changes in the annual electricity flow between countries are shown in the Figure B.1 for both directions (i.e. the green and the blue bars). It can be observed that the Netherlands increases its import from Belgium and Germany, while import is logically significantly reduced from Norway. Furthermore, the Netherlands decreases its exports to Belgium, Germany, and obviously Norway.

Regarding Norway, its imports are increased from Germany, Denmark, Sweden and the UK (but of course decreased from the Netherlands) . Besides, Norway increases its exports to Germany, Denmark, Sweden and the UK (while it is significantly reduced to the Netherlands).

Modelling 100% RES scenario without the NO-NL cable (Case 0B)Annex C

B1: Change in annual flows due to excl 14GW NL-NO for both directions

0.0

-0.9 -1.1

-8.2

5.3

-3.90.0 -1.4

0.1

-2.0

20.2

4.5

-0.4

1.4 0.02.6

-12.6

-1.2

6.44.1

-25

-20

-15

-10

-5

0

5

10

15

20

25

Cha

nge

in f

low

per

die

ctio

n (T

Wh)

-3.5

0.13.0

4.4

-21.7

2.3

-2.0

0.4

-1.4

1.3

-5.9

8.5

1.7

6.9

1.5

-3.0-66.5

1.2 0.5

-0.3

-25

-20

-15

-10

-5

0

5

10

15

Cha

nge

in f

low

per

die

ctio

n (T

Wh)

DNV GL ©201760

GlossaryAnnex C

TERM DESCRIPTION

CAPEX Capital expenditures

CHP Combined Heat and Power

DSO Distribution System Operator

GW Gigawatt

GtP Gas-to-Power

IC Interconnector

kEUR Thousand Euro [1,000 euro]

MEUR Million Euro [1,000,000 euro]

OPEX Operational Expenditures

MW Megawatt

PtG Power-to-Gas

PtGtPower Power-to-Gas-to-Power

TERM DESCRIPTION

PtGtProduct Power-to-Gas-to-Product

RES Renewable Energy Sources

TSO Transmission System Operator

TWh Terawatt hours

UGS Underground Gas Storage

WGC Working Gas Capacity

WGV Working Gas Volume

VO&M Variable Operational and Maintenance costs

the potential role of power-to-gas in the e-highway2050 study · the potential role of power-to-gas...

Documents