report deliverable 3 from the norways-project entitled markets and r… · norways –report...

Title Viable Markets and Regions for introduction of hydrogen in the Norwegian energy system

Author(s) A.M. Svensson (SINTEF), Chr. Stiller (NTNU) S. Møller-Holst (SINTEF), U. Bünger (NTNU)

Date March 17th 2008

Deliverable no. D3

The NorWays project is financially supported by:

Providing decision support for introduction of hydrogen in the Norwegian energy system

NorWaysNorWaysNorWaysNorWays

The research is conducted in close collaboration between:

A Competence project to enhance knowledge and prepare for introduction of H2 in Norway

Acknowledgement: NorWays is co-financed by a number of Norwegian key stakeholders within hydrogen and The Research Council of Norway under the RENERGI-programme (Project number: 173045/S30).

NorWays –Report “Viable Markets and Regions for introduction of H2 in the Norwegian energy system”, p.2 Deliverable no.3, March 21st 2008

Summary of report

It is commonly believed that hydrogen will become a key energy carrier in a future sustainable energy system. Hydrogen may be produced from various energy sources and raw materials, and applied in a wide range of end-use technologies. In a short to medium time scale, decarbonisation of fossil fuels, in particular natural gas, will be the major source for hydrogen as a fuel in Norway similar to many other places in the world. The major international drivers for introduction of hydrogen include:

Reduction of global (= greenhouse gases) and local (= criteria pollutants) emissions. Being one of the major objectives for introduction of hydrogen, most hydrogen pathways represent zero- or close-to-zero-emission solutions.

Security of supply. Hydrogen is the most universal fuel, i.e. lending itself to be efficiently produced from almost any from of fossil energy and water which opens up the opportunity to utilize local resources and hence to reduce the dependency on energy imports from foreign large-scale producers.

International competitiveness. Due to the new more de-central infrastructures required and the need to develop new evolutionary process technologies hydrogen has a huge potential to foster new industrial and commercial developments for supply, infrastructure and end-use.

Introduction of hydrogen in the Norwegian energy system is highly dependent on international priorities, technology breakthroughs etc. In Norway, utilization of hydrogen in the transportation sector could potentially contribute to significantly reduce GHG emissions. Security of supply is not considered to be a key national driver for introduction of hydrogen, as for the foreseeable future Norway is well supplied with energy resources. However, the development of an international market for hydrogen technology will lead to opportunities for industrial developments also in Norway. Some well-established industries, in particular related to hydrogen production or infrastructure technologies, exist which would profit from a stronger role of hydrogen also in the energy markets.

Transportation (in particular road transportation) has been identified as the most viable market for introduction of hydrogen in the Norwegian energy system. Extensive stationary use of hydrogen is not foreseen, related to the low population density and challenging topography, which puts certain restrictions and extra cost to infrastructure development. However, if pre-combustion technology is chosen for natural gas power plants in order to facilitate carbon capture and storage (CCS), large scale co-production of hydrogen and electricity from natural gas could imply economic benefits, and hydrogen would become available from large scale reforming units at locations where natural gas is available in large amounts (i.e. from the major pipelines). Markets that could become important for hydrogen technologies in a relatively short timeframe are stand-alone power systems, where hydrogen could play an important role as an energy storage medium where i) grid connection is expensive, or the electricity supplied through the grid is unsatisfactory.

In this work, focus is put on the future large scale markets for hydrogen, primarily the transportation sector. A prerequisite for hydrogen to become a crucial energy carrier is that it can be produced at reasonable/competitive cost, which seems to be agreed on in several international studies. In this report, various technologies (vehicle technologies as well as alternative fuels) are evaluated for their application in the Norwegian transportation sector, with respect to their potential for emission reduction. It is shown that the ambitions of a low-emission transportation system can only be realised by a massive introduction of hydrogen in personal and light-duty vehicles, or alternatively, if biofuels are imported. The global effect of the latter is highly questionable, since it is generally agreed that the available bioresources are not sufficient to cover the demand neither in Europe nor world-wide (in addition to a number of other challenges related to extensive use of biomass for fuel production). Furthermore, an evaluation of the potential for utilising Norwgian CO2 lean energy sources (primarily wind and natural gas, including CCS) for production of hydrogen and supply to


the European market (at large scale). Results, although preliminary, indicate that hydrogen could be competitive to other solutions, in particular direct transmission of electric power, related to the high cost of establishing the infrastructure of the latter. One challenge is the large scale and corresponding huge investments required. However, these options deserve a more detailed investigation.

Based on the findings in this report, the following suggestions and conclusions are drawn:

- Extensive emission reductions in the transportation sector at a satisfactory rate (i.e as suggested by the Commission of Low Emissions) can only be achieved by use of political incentives. This is related both to the fact that the average age of vehicles is very high in Norway (19.7 years in 2006), and that environmentally friendly vehicles are more expensive since technologies are generally immature.

- As renewable resources are limited, emphasis must also be put on optimum use of energy for transportation purposes. This implies that biofuels should first of all be allocated to applications where liquid fuels are required, i.e. applications where there at present are no alternatives to liquid fuel, first of all heavy duty vehicles operating at high and constant load. The maritime sector as well as aviation are other sectors where liquid fuels are hard to replace. Electric propulsion is superior with respect to energy efficiency, and all-electric, as well as hybrid electric vehicles could contribute to significant emission reductions in a short time scale, and should be encouraged where feasible. However, the low energy density of present battery technology limits the application of all-electric vehicles, in particular, but also hybrid electric vehicles. Although improvements of battery technology are expected, the potential of all-electric vehicles will be limited in the near future. Fuel cell technology, in combination with a large or small battery pack, provides a potential zero-emission solution of improved energy efficiency with satisfactory drive-range. Once fuel cell technology is commercially available in vehicles, it’s use should be strongly encouraged in Norway.

- Norway has a vast amount of resources available for production of CO2 lean hydrogen, and the potential for Norway to become a major supplier of hydrogen to the European market deserves further investigation.

- In addition to resources, there is strong competence as well as industrial products available in the field of production and storage of hydrogen. A strengthening of industrial developments in this area should be encouraged.


Disclaimer

This Report is the result of a collaborative work between “NorWays” Industry and Institute/University partners. The results of the research were subsequently elaborated and presented in a coherent manner, which involved extensive stakeholder consultation as well as feedback from the “NorWays” Industry Partners. The ideas presented in this Report were reviewed by certain "NorWays" project partners to ensure broad general agreement with its principal findings and perspectives. However, while a commendable level of consensus has been achieved, this does not mean that every consulted stakeholder or "NorWays" Industry Partner necessarily endorses or agrees with every finding in the Report. The producer of this Report is the sole responsible for its content and recommendations.


Table of Contents

Summary of report .....................................................................................................................2

1. Drivers for introduction of hydrogen.............................................................................7

1.1 International drivers for introduction of hydrogen .....................................................8

1.2 Major national drivers for introduction of hydrogen ..................................................9

1.3 Viable markets for introduction of hydrogen in Norway .........................................11

1.4 The outline and content of this report .......................................................................13

1.5 This report’s role in the NorWays project.................................................................14

2. Main sources and costs for hydrogen production in Norway ..............................15

2.1 Sources for hydrogen production ..............................................................................15

2.2 The cost of hydrogen...................................................................................................16

3. The transportation sector as a viable market for hydrogen ..................................21

3.1 Characteristics of and forecast for the Norwegian transportation sector ............21

3.1.1 Domestic transportation demand ...............................................................21

3.1.2 Emissions from the transportation sector .................................................22

3.1.3 Energy consumption in the transportation sector ....................................23

3.1.4 Driving pattern for and density of passenger vehicles ............................23

3.1.5 Transportation demand forecasts ..............................................................25

3.2 Options for reduced GHG emissions from transportation .....................................26

3.2.1 The role of hybrid and plug-in hybrid technologies .................................27

Figure 3.2.4 CO2 emissions (g/km) for various PHEVs for a mixed drive cycle (source: Electric Power Research Institute, 2003 [EPRI]......................................28

3.2.2 Electric vehicles ............................................................................................29

3.2.3 Bio fuels..........................................................................................................29

3.2.4 Hydrogen........................................................................................................34

3.3 Scenarios for emission reductions from road transportation ................................36

3.4 Scenarios for emission reductions in the transportation sector............................38

Scenario A: Hydrogen is not introduced in the transportation sector ..................41


Scenario B: Rapid introduction of hydrogen vehicles from 2020 .........................44

4. Viable regions for introduction of hydrogen .............................................................47

5. Options for export of CO2-lean energy to Europe ....................................................51

5.1 Norwegian energy export potentials .........................................................................51

5.1.1 Onshore wind in Northern Norway.............................................................51

5.1.2 Offshore wind in Southern Norway ............................................................51

5.1.3 Natural gas (NG) from Southern Norway..................................................52

5.1.4 Natural gas (NG) from Northern Norway ..................................................52

5.1.5 Comparison of resources ............................................................................52

5.2 Estimation of central Europe’s future demand for Norwegian energy.................52

5.2.1 Potential markets for renewable energy import .......................................52

5.2.2 Energy demand situation in Germany and estimation of supply shares53

5.3 Premises and general assumptions..........................................................................54

5.3.1 Energy transport chains...............................................................................56

5.3.2 Main techno-economic assumptions .........................................................57

5.4 Results and Discussion...............................................................................................61

5.4.1 Energy input...................................................................................................61

5.4.2 Green house gas (GHG) emissions...........................................................62

5.4.3 Costs...............................................................................................................63

5.5 Qualitative factors ........................................................................................................64

5.5.1 Value creation in Norway.............................................................................64

5.5.2 Flexibility.........................................................................................................65

5.5.3 Environmental impact...................................................................................66

5.6 Conclusions ..................................................................................................................67

References …………………………………………………………………………………….68


1. Drivers for introduction of hydrogen

In this chapter the drivers for introduction of hydrogen in the Norwegian energy system are discussed, and the similarities and discrepancies between dominating international drivers and national key drivers are pointed out. Viable markets for hydrogen are assessed qualitatively and briefly discussed. The brief discussion culminates in narrowing down the scope of this report to two market segments, hydrogen as fuel for domestic road transportation and utilization of Norwegian energy resources for hydrogen production for export to Europe. Finally an outline of this report is provided and its role in the NorWays explained.

Today’s environmental challenges impose commitments on everyone. The most demanding of these challenges is global warming, to which the emission of greenhouse gases from fossil fuels used in stationary combustion and for transportation purposes is a major contributor. Various international studies indicate that the developed countries of the world must reduce their emissions of greenhouse gases by two thirds to avoid ”harmful climate changes”. Internationally, there is growing focus on security of supply and increasing awareness that fossil resources are limited. A massive introduction of renewable energy sources is regarded as a viable pathway to ensuring sustainable development. This may lead to electricity and hydrogen becoming the dominant energy carriers of the future.

In the long term perspective, hydrogen is enabling conversion of energy from a wide range of renewable sources. In an interim period, fossil fuels may also constitute a source for hydrogen by bridging the gap towards a fully sustainable energy future. Introduction of hydrogen as energy carrier will bring about radical changes which require major political and financial incentives.

It is important to underline that introduction of hydrogen into the existing energy markets must be seen in relation to existing energy supply alternatives such as natural gas, electricity, district heating and bio-fuels. Likewise, hydrogen technologies will have to supplement and compete with other promising and emerging technologies (e.g., hybrid technology for vehicle propulsion). It is, however, expected that hydrogen will eventually and finally become an integral part of the Norwegian energy system. The degree and pace of introduction of hydrogen as energy carrier will be affected by many factors such as the

characteristics of the existing energy system (energy mix, infrastructures),

development of energy prices,

availability and cost development of hydrogen technologies and specifically fuel cells,

political commitment to international agreements on emission reductions,

industrial engagement

availability of suitable energy resources for H2-production

funding of R&D as well as demonstration projects

When it comes to the availability of hydrogen technologies this report will lean on assumptions and expectations brought forward in the EU (ref. Implementation Plan 2006):

• niche markets emerging from 2015 (e.g., forklifts or speciality vehicles such as scooters) and

• commercial markets for hydrogen technologies throughout the entire energy system emerging by 2020.


1.1 International drivers for introduction of hydrogen

It is commonly believed that hydrogen will become a key energy carrier in a future sustainable energy system. Hydrogen may be produced from various energy sources and raw materials, and applied in a wide range of end-use technologies. The major international drivers for introduction of hydrogen include:

Reduction of global (= greenhouse gases) and local (= criteria pollutants) emissions. Most hydrogen pathways based on renewable energy resources represent zero- or close-to-zero-emission solutions. Even fossil fuel based energy chains for hydrogen may be close to carbon free provided that CCS technologies are applied.

Security of supply. Hydrogen is the most universal fuel, i.e. lending itself to be efficiently produced from almost any from of fossil energy and water which opens up the opportunity to utilize local resources and hence to reduce the dependency on energy imports from foreign large-scale producers.

International competitiveness. Due to the new more de-central infrastructures required and the need to develop new ?evolutionary? process technologies hydrogen provides opportunities to foster new industrial and commercial developments for supply, infrastructure and end-use.

Similar as in the U.S. the European Commission has engaged in a strategy process to involve the relevant stakeholder groups in a balanced fashion. The major milestones and key documents of this strategy are depicted in Figure 1.1 [HyNor conference, 2006].

ludwig bölkowsystemtechnik

1

Timeline European Hydrogen & Fuel Cells Strategy

2002 200520042003 2006 2007

Vision report : “Hydrogen energy and Fuel Cells – A vision of our future”June 2003

Hig

h Le

vel G

roup

H2

and

FC(2

002-

2003

)

Launch of EU‘s Hydrogen&Fuel Cell Technology PlatformJanuary 2004 involving main stakeholders

Two key foundation documents“Strategic Research Agenda” and “Deployment Strategy”Endorsed in March 2005 at Platform General Assembly

Strategic Overview of the above 2 documentsJune/October 2005

“Operations Review Days”December 2005

HFP General AssemblyAdoption Implementation PlanOctober 2006

Start of Joint Technology Initiative?

Figure 1.1. Major milestones and key documents of the European hydrogen and fuel cell strategy [HyNor conference, 2006]. A citation from the Vision Statement of the European High Level Group on Hydrogen & Fuel Cells (HLG) carries all major arguments of the European policy dimension in a nutshell [Vision Report, 2003]:


“In brief, hydrogen and electricity together represent one of the most promising ways to realise sustainable energy, whilst fuel cells provide the most efficient conversion device for converting hydrogen, and possibly other fuels, into electricity. Hydrogen and fuel cells open the way to integrated “open energy systems” that simultaneously address all of the major energy and environmental challenges, and have the flexibility to adapt to the diverse and intermittent renewable energy sources that will be available in the Europe of 2030.”

Europe should lead in undertaking rational analysis of alternative energy options and in demonstrating the benefits of a transition to a widespread use of hydrogen and fuel cells. They will have “to provide cost-effective solutions to the following key challenges – the main drivers for Europe’s future energy systems”:

• Energy security and supply, • Economic competitiveness, • Air quality and health improvements, • Greenhouse gas reduction.”

Similar strong political initiatives also exist in other parts of the world supporting hydrogen energy, although the motivation varies. Whereas in the U.S. and Japan also energy independency is of highest importance, technological advancement/competence and economic strength scores second, environmental issues generally being of less priority than in Europe. The strategy formulation at EC level (Vision Report, Strategic Research Agenda and Deployment Strategy reports) is supported by individual research projects such as HyWays (European hydrogen energy roadmap), Roads2HyCom (European research needs and hydrogen community planning) and HyLights (Support of the large scale Lighthouse Demonstration Projects) and numerous activities of different kind in the European member states and countries.

The strategy is posed to culminate in a new type of support instrument, the Joint Technology Initiative (JTI). The proposal for a Fuel Cells and Hydrogen Joint Technology Initiative was adopted by the European Commission 10th Oct 20071. This public private partnership group will provide a ring-fenced budget for demonstration and research projects on hydrogen and fuel cell (FC) technology of 470 M€ in 6 years, taken out of the direct competition with other energy specific funding budgets, and hence safeguarding H2&FC budgets to be diluted. It is planned that it represents less than about 20% of the overall budget, other contributions coming from industry (~50%) and member (associate) states or municipalities/regions (~30%). This has to be balanced with an earlier total budget claim of 7,4 B€ indicated in the Implementation Plan which was developed by a large number of industrial and research stakeholders from all across Europe.

1.2 Major national drivers for introduction of hydrogen

Introduction of hydrogen in the Norwegian energy system is highly dependent on international priorities, technology breakthroughs etc. In Norway, utilization of hydrogen in the transportation sector could potentially contribute to significantly reduce GHG emissions. Security of supply is not considered to be a key national driver for introduction of hydrogen, as for the foreseeable future Norway is well supplied with energy resources. However, the development of an international market for hydrogen technology will lead to opportunities for industrial developments also in Norway. Some well-established industries, in particular related to hydrogen production and infrastructure technologies, exist which would profit from a stronger role of hydrogen also in the energy markets.

1 Announced at: https://www.hfpeurope.org/hfp/ec_activities

https://www.hfpeurope.org/hfp/ec_activities


Through the work of the National Hydrogen Commission and its two expert groups reports [NOU 2004:11] a relatively high level of consensus was reached with respect to why Norway should put effort to hydrogen. The report points out the main directions with respect to areas, which are of national interest to pursue. The three major drivers are shown in Figure 1.2. The involved ministries released their Strategy2 document describing the organization of a National Hydrogen Platform in the Fall of 2005, establishing the National Strategic Hydrogen Council and providing a mandate for their work.

Natural gas

EnvironmentEconomic

development

Norwegian Hydrogen Inititive

Natural gas

EnvironmentEconomic

development

Norwegian Hydrogen Inititive

In November 2006, the National Strategic Hydrogen Council delivered its Implementation Plan as requested by the ministries of Oil and energy and Transportation and Communication. The Implementation Plan provides a set of 27 concrete actions for a Comprehensive Norwegian hydrogen programme.

Figure 1.2. Major drivers for introduction of hydrogen in Norway, as pinpointed by the National Hydrogen Commission.

So far, the Norwegian government has not responded to the recommendations and suggestions neither by stating their increased commitment to hydrogen nor through allocating the required funding.

The National Strategic Hydrogen Council is now pursuing the deployment of the Implementation Plan towards the stakeholders which are explicitly pointed at as responsible for implementation of the activities.

There is a broad consensus among Norwegian politicians that Norway must fulfil its commitments under the Kyoto Protocol, while the demanding nature of this task is also recognised. Given that Norway’s stationary energy generation is already dominated by renewable energy sources (hydropower), it is obvious that most of the emission reductions will have to be made in the energy supply and the transportation sector. Norwegian politicians have recently announced that Norway will fulfil the Kyoto protocol and have further enforced Norway’s commitment to emission reductions by reducing GHG emissions by 9% in 2012 relative to 1990-emissions and by 30% by 2020 (see Figure 1.3).

2 Strategy from the Ministry of Oil and Energy and Ministry of Transportation and Communication, entitled: “Strategi for hydrogen som energibærer innenfor transport og stasjonær energiforsyning”, available in Norwegian at: http://www.odin.dep.no/filarkiv/255441/Strategi_hydrogen_aug_05.pdf

http://www.odin.dep.no/filarkiv/255441/Strategi_hydrogen_aug_05.pdf


2020- 30 %

2012- 9 %

Figure 1.3. Historic data and prognosis for 2010 of domestic GHG emissions [SSB]. National ambitions recently announced by the Norwegian Prime Minister are indicated.

1.3 Viable markets for introduction of hydrogen in Norway

In view of the characteristics of the Norwegian energy systems [D1 NorWays], transportation (in particular road transportation) was identified as the most viable market for introduction of hydrogen in the Norwegian energy system. Extensive stationary use of hydrogen is not foreseen, related to the low population density and challenging topography, which puts certain restrictions and extra cost to infrastructure development. However, if pre-combustion technology is chosen for natural gas power plants in order to facilitate carbon capture and storage (CCS), large scale co-production of hydrogen and electricity from natural gas could imply economic benefits, and hydrogen would become available from large scale reforming units at locations where natural gas is available in large amounts (i.e. from the major pipelines). An extensive survey of this possibility has been conducted by SINTEF [Coprod H2-el SINTEF].

Another potential market for hydrogen is stand alone power systems (SAPS), where there are various benefits of utilizing hydrogen as energy storage medium. These benefits are mainly related to emissions, energy efficiency, silent operation and the possibility for onsite fuel production. The high cost and immaturity of key hydrogen technologies (i.e. fuel cell technology) have, however, so far been prohibitive for extensive introduction of hydrogen in this market segment. Within the framework of the HSAPS project (Hydrogen Stand Alone Power Systems), coordinated by Institute for energy technology (IFE), the market potential for hydrogen energy technologies in stand-alone power systems was evaluated [HSAPS]. In this study, the most promising markets were identified as customers with no grid connection, or customers who would want to disconnect from the grid for the following reasons:


Grid connection is too expensive to maintain and operate for the grid owner, and there are no obligations to upgrade the connection.

High costs for customers of existing grid connection

Unsatisfactory quality of electricity supplied through the grid, in particular for critical operations

The user groups found to represent this market for hydrogen based stand-alone power systems were:

1. Residential electricity supply

2. Agricultural activities

3. Tourism

4. Water treatment and desalination

5. Back-up power systems

6. Communication

7. Others (lighthouses, food processing etc.).

Cost estimates (including projected costs for hydrogen technologies) were made within the HSAPS project. It was found that hydrogen technologies are generally expected to become competitive towards renewable (PV, wind) – battery systems, but would have difficulties in meeting the cost figures of systems based on fossil fuels (diesel) with current fuel cost.

At European level, estimates were made regarding the energy demand for SAPS, but detailed information is lacking for Norway. Although the energy contribution and thus the emission reductions of these systems will be limited, such niche applications may be very important for introduction of new and emerging technologies. Furthermore, customers would be willing to pay for the particular benefits (independence of fuel infrastructure, quiet operation etc.) that these solutions may provide, and costs per kWh supplied may therefore be decoupled from the rest of the energy market.

Maritime applications of hydrogen and fuel cells constitute another niche market of great interest to Norway. The use of hydrogen in ships, however, is far from realisation, and present demonstration projects are mainly focused on fuel cells as Auxiliary Power Units (APUs) in small and medium sized ships, such as supply ships and ferries. An overview of this market segment and potential maritime applications can be found in [FuelCellToday Niche Markets]. Conceptual studies of maritime application in various segments of shipping were conducted within the EU project FCSHIP, coordinated by MARINTEK [FCSHIP]. It is important, however, to be aware that the prime fuel for these applications will be marine diesel and eventually natural gas, and that due to legislative issues, hydrogen is not foreseen as a viable fuel for maritime applications for many years to come.

In this report, focus is put on early markets and application of hydrogen with the largest impact on the energy system, in terms of energy demand and emission reductions. Therefore, maritime and SAPS applications (briefly discussed in section 1.3) are not covered in this report. This report is focused on two major areas of potentially large scale utilization of hydrogen:

i) hydrogen as fuel for domestic road transportation, and

ii) utilization of Norwegian energy resources for hydrogen production and export in order to partially cover future demands of the European transportation sector.


1.4 The outline and content of this report

This Chapter of the present report discusses the international and national drivers for introduction of hydrogen in the Norwegian energy system.

The availability of suitable energy resources for H2-production seen from a Norwegian perspective is dealt with in Chapter 2. Chapter 4 is devoted to an introductory discussion on “Viable regions for introduction of hydrogen” in Norway. Based on a set of geographic and demographic criteria, an initial regional hydrogen demand is established.

Some potential special market segments in Norway and their characteristics were briefly assessed (Section 1.3).The two main market segments for hydrogen based on Norwegian energy resources are identified:

i) hydrogen for domestic road transportation

ii) hydrogen as energy carrier for export and use as fuel in the European market.

Chapters 3 and 5 will discuss these hydrogen utilisation areas in detail, respectively.

These two main areas for hydrogen utilization are in agreement with Hydrogen Commissions four major goals for the Norwegian Hydrogen Initiative [NOU 2004:11]:

Environmentally sound production of hydrogen from Norwegian natural gas,

early users of hydrogen vehicles in the Norwegian transportation sector,

hydrogen storage solutions for demonstration and commercial markets and

development of a hydrogen technology industry.

In Chapter 3, emphasis is put on the potential role of hydrogen in Norwegian road transportation and corresponding GHG emission reductions in light of other viable zero-emission options including electrification of vehicles (hybrid, plug-in hybrids and electric vehicles), and introduction of bio-fuels. Neither bio-fuels nor electrical vehicles have the potential to entirely cover the demand in the transportation sector alone. Therefore, more zero-emission alternatives are discussed simultaneously. Extensive introduction of hydrogen is one of the alternatives discussed in Chapter 3, and the implications with respect to establishing infrastructure for hydrogen distribution are discussed in Chapter 4.

In Chapter 5, the opportunity for Norway to use hydrogen as a means to create value from its natural resources beyond today’s oil and natural gas export in discussed. Large scale export of CO2-free or CO2-lean energy to central Europe is investigated and results from well to wheel calculations are presented. Eight different pathways for hydrogen delivery as fuel for the European market are compared with respect to efficiency for resource utilisation, specific GHG emissions and specific energy provision costs. Prime energy resources studied include natural gas and on- and offshore wind energy from southern and northern Norway, respectively.


1.5 This report’s role in the NorWays project

This deliverable supports the following of the main goals of the NorWays project:

Documenting how introduction of hydrogen as energy carrier in Norway is influenced and restricted by the characteristics of the existing Norwegian energy system.

Developing alternative scenarios and identifying market segments and regions of the Norwegian energy system where hydrogen may play a significant role, with focus on early markets.

This report (D3) constitutes the link between deliverables D1 and D4 of the NorWays project:

Report D1: “Implications for introduction of hydrogen” Report D4: “Specific markets and regions for early market introduction”

by developing alternative scenarios and pinpointing viable markets and regions in light of the characteristics of the Norwegian energy system in a European perspective. Due to agreements with HyWays of finalizing the MS-profiling report as part of the NorWays-project (as Deliverable D1), and the corresponding changes in scope for D1, this report (D3) now partly covers the original scope of D1 with respect to which implications the characteristics of the Norwegian energy systems will have for an introduction of hydrogen in Norway. The results presented here include qualitative assessments and conclusions but should still provide an indication for how to proceed and give valuable input to all three modelling tools utilised in the NorWays project for the type of work needed to achieve similar but more quantitative results from the modelling efforts.


2. Main sources and costs for hydrogen production in Norway

In this chapter the potential for hydrogen production in Norway is discussed in light of national energy resource availabilities and strategic and political recommendations. A set of key energy resources are identified and qualitative picture of their potential contribution to the overall hydrogen production in the 21st century are provided. The cost of hydrogen produced from a series of energy resources is assessed based on key international studies.

2.1 Sources for hydrogen production

Hydrogen may be produced from nearly any energy resource. This is part of the rationale why hydrogen is foreseen as having promising prospects of becoming our prime energy carrier of the future next to electricity. Norway’s energy situation is described in the previous NorWays report “Characteristics of the Norwegian Energy System” [D1 Norways], and will hence not be dealt with in detail here.

Further development of large scale hydro power is not foreseen in Norway, but there is a potential of increased power production of 11 TWh by upgrading of existing plants, which is partly expected to be realised in the future. There is also a large potential for increased utilization of other renewable energy sources. The major contribution to new, renewable energy in Norway is expected to come from large scale onshore and offshore wind parks. The official aim is an annual production of 3 TWh by 2010, but the technical potential is much higher, in particular for offshore wind power. The economic potential for small-scale hydro power is estimated at 20 TWh. The economic potential for utilization of biomass for energy purposes is also in the range of 20-25 TWh [Bioroadmap]. Furthermore, around 30 TWh of the stationary annual consumption of electric power is utilized for residential heating, and there are public incentives to reduce this figure. Increased utilization of biomass as well as heat pumps is foreseen as prime sources to replace resistive heating.

In an early phase, however, by-product hydrogen from refineries and industrial plants may contribute to supply hydrogen to certain regions e.g., Grenland (Telemark) and several sites along the western coastline especially from Stavanger and north [D1 Norways]. In the short to medium term, natural gas constitutes an environmentally benign source for hydrogen production provided that carbon is captured and stored. The huge potential for storage of CO2 at the Norwegian shelf renders hydrogen production from Norway’s natural gas reserves a viable option for many years to come (Figure 2.1).


Figure 2.1 Key energy sources to hydrogen production for the 21st century.

2.2 The cost of hydrogen

In this Section three recent studies assessing future cost of hydrogen supply are discussed. These include a summary of available information from the IEA networks with respect to hydrogen technologies [IEA April 2007], a study conducted by the National Academy of Sciences (US) to address the complex topic “hydrogen economy” [Hydrogen Economy, NAS, 2004], and the Hyways project, an integrated project conducted within the EU 6th Framework Programme.

Recent cost estimates from IEA [IEA April2007] pinpoint large scale reforming of natural gas and coal as the most cost efficient options for production of hydrogen at present and in the near future. At current natural gas prices ($6 - 9/GJ), the cost of hydrogen from NG reforming lies typically in the range $10-15/GJ H2 for large scale production. Small scale production may exceed $50/GJ. Projected CCS costs are expected to add $1-3/GJ, depending on process and scale. However, the cost of hydrogen will be very sensitive to natural gas prices, process and economy of scale. For electrolysis, the current costs are typically above $30/GJ H2, but could drop to below $20/GJ, provided that electrolysers are pressurised, operate at 80 % (HHV), and electric power is available at $35/MWh [IEA April2007].

Estimates of infrastructure and distribution costs are complicated by significant uncertainty, and in particular for pipeline distribution for supply to road transportation, huge investments are required. The estimates from IEA indicate an additional cost of $5-$12/GJ related to transportation, distribution and refuelling stations (incl. compression to 700 bars). The applicability of these numbers which may include large scale pipeline transportation is highly questionable under Norwegian conditions due to demography and topography. These questions will be considered by a separate infrastructure analysis within the framework of the NorWays project (Deliverable D8, Report entitled “Description of Infrastructure Analysis Model”).


The requirements for hydrogen to gain significant market share, as indicated by IEA [IEA April 2007] are:

Cost reduction of hydrogen production by a factor 3 to 10

Cost reduction of fuel cells by a factor 10

Carbon sequestration and storage must be realised

Necessary emission reduction incentives should be of the order $25-$50/t CO2

Introduction of hydrogen as energy carrier is highly dependent on the energy marked. The sensitivity of H2 production cost to energy prices and technology/process is given in Figure 2.2a) for current production costs, and 2.2b) for the projected (2020-2030) H2 production cost.

Figure 2.2. a) Sensitivity of current H2 production cost to energy price. b) Sensitivity of projected (2020-2030) H2 production cost to technologies and processes [IEA April 2007].

In the study conducted by the National Academy of Sciences [Hydrogen Economy, NAS, 2004], similar price estimates are presented, see Figure 2.3. Current cost data are in the range of $17.5/GJ for H2 produced by reforming (NG or C) to $57.5/GJ for H2 produced by electrolysis (at $0.07/kWh).

In Figure 2.3, the price of gasoline is adjusted to account for the fact that fuel cell vehicles have a higher tank-to-wheel efficiency (66 % efficiency gain of FCV is assumed). The oil price is assumed constant at $ 30 bbl/l, and deviations from this assumption will affect the energy market. Electricity from the grid is assumed to be available at $ 0.07/kWh. For the Dist PV-grid H2 production route, the analysis assumes that PV generated power is available 20 % of the time.

In Figure 2.4, the corresponding projected future costs for the same technologies are depicted. Unfortunately, the exact time frame is not given. These are estimates based on certain assumptions related to technological progress/learning curves, in particular for the new renewable power generation technologies, like wind power and photovoltaic, but also for production technologies with biomass as energy source. The major assumptions related to cost reduction are: 90 % reduction for PEM electrolysers, 50 % reduction of investments related to PV (cost reduction of power from $0.32/kWh to $0.098/kWh), improved utilization of wind mills (from 30% to 40 %) and corresponding reduction from $0.06/kWh to $0.04/kWh.


Figure 2.3. Unit cost estimates for hydrogen (energy of 1 kg H2 is 0.12 GJ) for 10 current hydrogen supply technologies, covering centralized (CS), midsize (MS) and distributed production (Distr) of hydrogen. GEA =gasoline efficiency adjusted [Hydrogen Economy, NAS 2004].

Figure 2.4. Estimated future costs of hydrogen for the technologies given in Figure 2.3 [Hydrogen Economy, NAS 2004].


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Figure 2.5. Analysis (Well to Wheel) synthesizing CO2-equivalent emissions and hydrogen supply costs for 10 European countries (2030) [HyWays Roadmap]. Within the framework of the HyWays project, projections on specific costs of hydrogen supply (CGH2) are made based on forecasts for technology development and cost evolution of fossil sources [HyWays Roadmap], see Figure 2.4. Similar to the study of the National Academy of Science [Hydrogen Economy NAS, 2004] (Figures 2.2 and 2.3), results are compared based on fuel efficiency, such that the expected improved efficiency of fuel cell vehicles is taken into account. Higher costs of fuel cell vehicles, however, are not taken into account. DoE hydrogen supply cost goals at the filling station (FS) are included. Figure 2.5 shows the minimum and the maximum emissions of the selected chains plotted against the hydrogen cost for all participants of the HyWays project (i.e., 10 European countries) [HyWays Roadmap]. Bandwidths (= colored boxes) represent variations across all 10 countries. Shaded areas indicate uncertainty which include additional costs (or failure) of CCS and for intermittent renewable electricity storage. The specific hydrogen supply costs and CO2-emissions for CGH2 from electrolysis using electricity mix as feedstock vary widely across Europe as the electricity mix is inhomogeneous. Hence, they are not displayed. The costs are typically in the range 16 Euro/GJ (onsite SMR) to 35 Euro/GJ (wind power). Finally for comparison, gasoline and diesel as reference fuels are included at around 0.02 Euro/km, which corresponds to production costs around 0.3 Euro/l.

From Figure 2.5 it can be noticed that for offshore wind energy a cost reduction against onshore wind energy can be expected. The lower limit of the prices estimated is basically related to the assumed favourable conditions for offshore wind energy in Germany, with respect to scale and full load hours (in comparison to German onshore wind) whereas for Norway average annual full load hours assumed are almost identical at 3,600 and 4,000 hrs/yr for onshore and offshore, respectively.

Other major assumptions are stated below [HyWays Roadmap]:


• Reference year is 2030, which has an impact on energy prices and technology/cost learning. The only exception is vehicle performance with reference year 2010 [Concawe WtW] as no data were available on the expected performance level for conventional cars in 2030.

• All fossil pathways consider carbon capture and storage (CCS) except on-site SMR. • Assumptions regarding technology learning are based on the numbers from the Concawe

study [Concawe WtW]. • For the hydrogen demand development between 2010 and 2050 HyWays has carried out an

analysis taking the ramp-up assumptions for hydrogen cars of the Implementation Plan (Snapshot 2020) extrapolating them to 2050 (Fig. 2.6 a)) [Implementation Panel].

• All vehicles are hybridized (= Volkswagen Golf class, >2010), gasoline and diesel internal combustion engines (ICE) for the reference and hydrogen fuel cells for all other pathways [Concawe WtW].

• As reference fuel oil at 50 €/bbl, exchange rate 1 € = 1.00 U.S.$ has been chosen [Concawe WtW].

• Fossil energy price increases have been assumed according to a consensus of the HyWays stakeholders on the basis of the WETO-H2 study (update of Energy Trends 2030) (Figure 2.6 b)) [WETO-H2]. As these assumptions have been surpassed by reality they appear to be rather modest.

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Figure 2.6. a) Hyways hydrogen vehicle fleet penetration b) HyWays energy price development [Hyways Roadmap].

It can be noticed that the cost estimates obtained within the framework of the HyWays project are generally higher than the projected cost estimates from IEA [IEA April 2007], which is probably related to higher projected energy costs. In comparison with the study of the National Academy of Science [Hydrogen Economy, NAS 2004], the price of hydrogen supplied by electrolysis is comparable, whereas the HyWays estimate of hydrogen from reforming of NG is somewhat higher than the future cost estimated by NAS. However, in general there is good agreement on the potential for cost reduction for hydrogen production technologies among these independent international studies.


3. The transportation sector as a viable market for hydrogen

The transportation sector is a major contributor to GHG emissions in Norway. This chapter is devoted to the discussion of how reductions in GHG emissions may be achieved by introducing alternative fuels, and how hydrogen can contribute to these emission reductions. Focus is put on road transportation, as hydrogen is likely to be introduced in fleet vehicles and light road vehicles first. For other sectors, like maritime transportation and aviation, which also contribute significantly to GHG emissions, the use of hydrogen is more challenging, and extensive use is not expected within the next 20 years.

Three robust solutions for future sustainable transportation are identified, i.e., hydrogen, electric and bio-fuelled vehicles. These alternatives are evaluated with respect to feasibility, drive pattern and technological status and forecasts. Two scenarios have been developed revealing the urgency of concrete and immediate action which should be taken. Synthesis of the results shows how emissions from road transportation may be reduced dramatically by 2050.

3.1 Characteristics of and forecast for the Norwegian transportation sector

3.1.1 Domestic transportation demand

Historic development of passenger transportation in the period 1960-2004 is shown in Figure 3.1.1 [SSB2005-26]. There has been an extensive increase of road transportation and aviation in this period, whereas the travelled distance in million person kilometres by rail and bus have remained rather table since 1980.

a) b)

Figure 3.1.1. a) Historic development in passenger transportation in Norway by a) bus (Buss), rail (Jernbane) and aviation (Luftfart) and b) passenger vehicles (in million person km) from 1960 to 2004 [SSB 2005-26].

Corresponding values for freight transportation are shown in Figure 3.1.2, [SSB2005-26]. As for passenger transport, the rising freight demand is primarily taken care of by steady increase in road transport, but since 1995 maritime transport has also increased significantly.


Figure 3.1.2. Historic development of freight transportation in Norway (million ton km) in the period 1960-2004 by the categories maritime (Sjø), road (Vei) and rail (Jernbane), and total (I alt) [SSB 2005-26].

3.1.2 Emissions from the transportation sector

The transportation sector contributes by 37 % to the domestic emission of GHGs, as illustrated in Figure 3.1.3. Road transportation alone contributes by 23 %, and has also been the sector with the largest growth during the last years (Section 3.1.1)., The distribution of emissions within the transportation sector is shown in Figure 3.1.4

Figure 3.1.3. Contributions to GHG emissions in Norway from the various sectors, showing that transportation contributes by 37% to the domestic emissions (sum of Road traffic (23%), Coastal traffic and Fisheries (9%) and Other mobile sources (5%)).

Personal (car+bus)

46 %

Trucks18 %

Ships28 %

Aviation8 %

Railway0 %

Figure 3.1.4. Distribution of sources of GHG emissions within the transportation sector [SSB 2005-26]. Road transportation takes a 64% share of the total emissions (Personal + Trucks).


Personal transportation (car + bus) by far dominates GHG emissions, but the contribution from maritime transport and transportation of goods (trucks) also contribute significantly (Figure 3.1.4). The GHG emission from railway transport is negligible compared to other sectors (0.3 %) due to the fact that the majority of the Norwegian railroad is electrified and powered by electricity predominantly generated from hydropower. Application of alternative fuels in aviation is not expected to be realised within the first two decades. Thus, in this report we will limit the discussion to road traffic (totalling 64% of the GHG emissions) and maritime transport (28%), and disregard aviation and railway transport.

3.1.3 Energy consumption in the transportation sector

The energy consumption in the transportation sector has increased considerably during the last decades, as illustrated in Figure 3.1.5 a) [SSB 2005-26]. In spite of improved fuel economy for vehicles, the energy consumption has increased. This is due to increased distances travelled (Figure 3.1.1.b)), increased size of the vehicles, and a reduction in the average number of passengers per car. (Figure 3.1.7) The corresponding distribution of fuels/energy sources for the sectors is shown in Figure 3.1.5 b).

a) b)

Figure 3.1.5. a) Historic development of energy consumption for maritime transport (Kysttransport), road transport (Veitransport) aviation (Lufttransport) and railways (Banetransport). b) Distribution of energy consumed for transportation purposes according to fuel/energy source in 2005 [SSB 2005-26] for petrol (Bensin), paraffin (Parafin), middle distillates (Mellomdestillater), heavy oil (tungolje), gas (Gass) and electricity (Elektrisitet).

3.1.4 Driving pattern for and density of passenger vehicles

The average number of trips by car per person per day in Norway was 3.1 in 2005 [Nasjonal Transportplan], and the distribution of trips according to travel distance is shown in Figure 3.1.6 [Mobility TØI]. This indicates that around half of the total number of person km covered by car (26,000 million person km) was carried out as trips shorter than 20 km. Figures from Sweden shows that close to 70 % of Swedish passenger vehicles drives less than 50 km pr day [Elforsk 2007]. The average number of persons in the car in relation to length of the trip is shown in Figure 3.1.7. The


average number of persons in the car per trip has decreased steadily during the last decades, from around 2.1 in 1975 to 1.75 in 2005.

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The total number of private vehicles in Norway was 2.08 mill in year 2006 [Vegvesen], and the average number of cars per household for various regions is given in Table 3.1 [Mobility TØI].

Table 3.1. Distribution of households with no car, 1 car or 2 or more cars, for the various regions in Norway [Mobility TØI].

Region No car 1 car 2 or more cars

Oslo 32 49 18

Surr., Oslo 10 45 45

Trondheim/Bergen/Stavanger 21 54 25

Surr. Tr.h/Bergen/Stavanger 5 47 48

Next 6 largest towns 11 49 41

Smaller towns 9 50 40

Other/rural areas 9 44 47

Average, Norway 13 48 39

The drive-cycle of a vehicle is decisive with respect to which benefits alternative technologies may comprehend. Hybridization may dramatically increase efficiency for urban drive-cycles, whereas little improvement is foreseen for highway driving (Section 3.2.1).

3.1.5 Transportation demand forecasts

According to official prognosis [Nasjonal Transportplan], the passenger transport by cars is expected to increase by 0.7 % annually in the period 2006-2012, and by 0.8 % annually in the period 2012-2020, whereas the increase in passenger transport by bus is assumed to increase by 0.2 % and 0.3 % in the corresponding periods. Furthermore, the annual increase in freight transportation is assumed to be 1.7 % and 0.9 %, in the periods 2006-2012, and 2012-2020, respectively.

It is important to realise the inconsistency of the political goals (also stated by the current government in the “Soria Moria declaration”) of increasing the share of public transport and these official prognosis in which the passenger transport by car is increasing significantly more than that of bus

In this work and the scenarios presented in this report, we have adapted transportation demand forecast figures from this official prognosis until 2020 [Nasjonal Transportplan] and assumed the growth rates of passenger and freight transportation in the period 2020-2050 to remain similar to the growth rates estimated for 2012-2020.


3.2 Options for reduced GHG emissions from transportation

There are several ways of realizing emission reduction from road transportation, including:

More environmentally friendly fuels and energy carriers, like

electricity, bio-fuels and hydrogen

More efficient vehicles, which can be achieved by

Power trains with improved fuel/energy utilization (including also hybrid vehicles and all-electric cars ?and drive patterns?)

Reduced weight of vehicles

Reduction of the transportation need

Reduction of transportation work in terms of person km, and ton km of transported goods

Increased number of passenger per vehicle, including increased shares of public transport, car-pooling etc.

All these factors are emphasized in a recent paper from Toyota Motor Cooperation [Toyota]. Toyota underlines that new concepts of mobility may impose changes in life-styles that completely alter the current way of moving people and goods. Such aspects are, however, not dealt with further in this context.

Focus of the present work and Chapter 3 of this report will be to investigate the most viable options for reduction of GHG emissions from road transport. These comprise electrification of vehicles (hybrid, plug-in hybrids and electric vehicles), and introduction of bio-fuels and hydrogen. In comparison to hydrogen powered fuel cell vehicles, bio-fuel as well as electric vehicles utilise mature technologies, but neither of these are likely to have the potential to entirely cover the demand for energy in the transportation sector. No all-electric car in the world today fulfils the goals of a medium sized average all-round passenger car concerning driving range, short refuelling time and costs/life expectancy, despite the fact that electrical vehicles have been around for more than a century. In contrast, today’s hydrogen fuel cell vehicle prototypes come much closer to fulfilling these goals although looking back on only 15 years of intense research and development. It is, however, important to stress that IF battery technology gets its final break-through, these will be superior to hydrogen vehicles due to their much higher efficiency. But until this is realised, the hydrogen vehicles seems to have a fair chance of taking a significant share of the market, if cost is reduced to an acceptable level.

As hydrogen fuel cell vehicles are still very costly, hydrogen powered internal combustion engines may become a crucial enabling technology for hydrogen infrastructure development and early markets. In addition, the potential for emission reductions by extensive introduction of hybrid vehicles is included. Although NG and LPG represent fuel alternatives with the potential of reducing environmental impact, their contribution to reduction of green house gas emissions is very limited, and these fuels are therefore not given further considerations in this report. In the following sections we will describe hydrogen, electric and bio-fuelled vehicles in more detail.


3.2.1The role of hybrid and plug-in hybrid technologies

By combining a conventional internal combustion engine (ICE) with an electric drive-train and batteries, the hybrid vehicles (HEVs) may reduce fuel consumption significantly, especially for city driving at varying load and through a downsized internal combustion engine due to the peak power provision from the electric motor. In addition, energy can be recovered during braking.

Figure 3.2.1. Toyota Prius Hybrid, more than 1 mill sold.

The ICE is started and operates at close to optimal conditions to charge the batteries, and during acceleration it assists the electric motor to provide adequate power. Since Toyota launched their Toyota Prius Hybrid in 1997, accumulated sales numbers recently surpassed 1 million (Spring 2007) (Figure 3.2.1).

Hybridization is expected to eventually become an integral part of all propulsion systems designed to operate in urban areas, and thus subject to frequent starts and stops (Figure 3.2.2).

The gain in efficiency upon hybridization is discussed widely and discrepancies are evident with respect to which benefit this may provide. A rather optimistic picture for HEVs is shown in Figure 3.2.3. The US06 drive cycle is a combined drive cycle (high speed and aggressive driving), whereas Japan 1015 constitute the most pronounced city drive cycles.

Plug-in HEVs (PHEVs) are given the additional function that they may be re-charged externally (from the grid). By extending the battery capacity to some 10kWh, these vehicles may cover the majority of city driving demand for an average Swedish passenger vehicle [Elforsk 2007] (see section 3.1.4).

Several auto manufacturers have recently launched plug-in hybrid prototypes which are expected to be available in the market within the next 3-4 years. Toyota has announced that their Prius PHEV will be

commercially available from 2010, with a battery range of 7 miles (11 km). GM’s Chevrolet Volt was presented at the Detroit auto show in Spring 2006, expected to have a range of 20 miles (32 km) on electric energy stored in the batteries. GM claims that the Chevrolet Volt will also be on the market in 2010. It is expected that PHEV with improved range will be available in the future. Electric Power Research Institute (EPRI) predicts that a range of 30 miles will be reached within 2015, and 40 miles within 2020, based on the expected improvements in battery technology. Estimated CO2 emissions for various types of cars and ranges for the PHEVs are depicted for mixed driving (i.e. combination of city and highway drive cycles) in Figure 3.2.4 [EPRI].

Figure 3.2.2 Toyota foresees that Hybrid Technology will become an integral part of all propulsion systems.


Figure 3.2.3 Power train efficiency gain for various drive cycles. These drive cycles vary highly in speed and acceleration [DriveCycle WtW].

Figure 3.2.4 CO2 emissions (g/km) for various PHEVs for a mixed drive cycle (source: Electric Power Research Institute, 2003 [EPRI].

The figures for reductions in CO2-emissions shown in Figure 3.2.4 are considered more realistic than those presented in Figure 3.2.3 above.


3.2.2 Electric vehicles

Electric vehicles are commercially available (at competitive prices when subject to tax exemption in Norway), both as electrified versions of small, conventional ICE cars, and as small cars which have been originally constructed as electric vehicles. There are currently 1,667 electric (mostly small city-) cars registered in Norway (01.01.2007) [Elbil] out of a total car park of around 2 million vehicles.

Electric vehicles are superior when it comes to efficiency (around 80 % WtW, based on renewable electricity), related to the power independent characteristics of electric motors. The typical drive range for electric vehicles is 100-150 km (Th!nk with new (hot ZEBRA) battery claims 200 km). Even if this is sufficient for a significant fraction of trips made by cars (83 % of all trips are shorter than 20 km, see Figure 3.1.6), the share of electric vehicles is still very low. Other major obstacles are the small size of the cars (some with only two seats), as well as the time needed for recharging (typically several hours). Fast charging is possible, but on the expense of battery lifetime. Improvements are expected for the battery technology, and the drive range is expected to exceed 200 km within the next few years. Car manufacturers indicate that next generation Li-ion batteries can be charged up to 80 % within 15 minutes. Still, there are challenges related to cost and lifetime/durability of the battery packs, and the fact that the energy density is too low for batteries to be utilized in medium to large cars for average drive cycles (city + highway driving). At present, the share of hybrid vehicles is increasing, and within the next 3-4 years, so-called “plug-in-hybrids” are expected to become commercially available, see Section 3.2.1.

Incentives for increasing the number of electric vehicles in Norway have been established, and comprise exemptions from VAT and annual fees, and permission to drive in public traffic lanes. There are two Norwegian manufacturers of electric vehicles, ElBil Norge, which produces the small electric car Kewet Buddy, and Th!nk (Figure 3.2.5), which have developed small electric vehicles, and will soon start series production. A hydrogen fuelled version with a fuel cell for range extender is also under development (Section 3.2.4)..

Figure 3.2.5.Th!nk all-electric car

3.2.3 Bio fuels Bio-fuels as bio-diesel and bio-ethanol are available as transportation fuels in most European countries (as such, or in blends). These so-called first generation bio fuels are made from plants (seeds or sugar). Forest and waste can be utilized for production of synthetic fuels (biomass-to-liquid (BTL) fuel), so-called second generation bio fuels, which however, is still at an early stage of development. The aim of the EC (Directive 2003/30/EC) is a replacement of 5.75 % of fossil fuels by bio-fuels by 2010, whereas alternative fuels in total should replace more than 20% of the petroleum based fuels within 2020. The potential for production of bio-fuels within the EU is assumed to be maximum 25-30% of the annual consumption, but there are large uncertainties related to such estimates. One challenge with respect to large scale utilization of biomass for bio-fuel production is the competition with other products based on biomass resources, in particular food, heat or chemicals synthesis. The availability of bio-fuels is increasing in Norway, either as imported fuels, or based on the conversion of imported plant oils. Due to the low growth rates at these northern latitudes, utilization of plants/farmed land for production of bio-fuels is not considered feasible in Norway, and a


domestic production of bio-fuels is foreseen to be based on forest/waste wood, agricultural waste and landfill gas (so-called 2nd generation bio-fuels). These conversion technologies are, however, still not commercially available, and major technological developments are required. Recently, a national roadmap for the establishment of domestic bio-fuel production [Bioroadmap] was launched, which provides suggestions for priorities in order to realise large scale bio-fuel production in Norway. Here, the potential for increased utilization of biomass for energy purposes is estimated to around 20 TWh annually, with a possible increase of 5 TWh if animal by-product (manure) is also utilised. It is further estimated that in a 10-20 year perspective, domestic supply of bio-fuels could account for around 20-30 % of the fuel consumption for transportation. The roadmap focuses primarily on the production of various routes for bio-ethanol from lingo-cellulose, and the production of synthetic bio-diesel by gasification of biomass, and further synthesis to Fischer Tropsch (FT)-liquids. Large scale production plants will be required for this conversion process to become profitable. An example of the estimated relationship between costs of FT-liquids and scale of plant, presented in the work of Tijmensen et al. [Tijmensen], is given in Figure 3.2.6. Biomass feedstock costs are assumed to be constant here, whereas in practice, biomass costs could significantly increase for larger scales due to higher logistics costs, which is likely to be the case for Norwegian conditions. In general, the cost of biomass is governed by the demand also for other applications. Assuming that production costs should lie in the range of 10.7 and 14.5 US$/GJ for FT-liquids to be competitive [Tijmensen], it can be seen from Figure 3.2.6 that the size of a plant should be above 400 MWth. The underlying assumptions implies a cost of biomass of 2 $/GJ, which is a little lower than typical prices of waste wood in Norway (3-7 $/GJ), whereas the cost of electric power is assumed to be 0.057 $/kWh. Still, based on the sensitivity analysis provided [Tijmensen], it is assumed that these results are applicable also in Norway. Assuming an overall LHV efficiency of around 40 %, and an annual operational time of 8,000 h, this corresponds to an annual consumption of around 8 TWh bio-mass.

Figure 3.2.6. Effect of scale on the production costs of FT-liquids [Tijmensen].


Bio-ethanol from ligno-cellulose could potentially be produced economically at smaller scale [Bioroadmap], but at somewhat lower energy efficiency. In this study, a LHV conversion efficiency of 35 % is assumed. In Figure 3.2.7, Well-to-Wheel (WtW) GHG emission vs. WtW energy consumption is summarised for a large number of bio-fuels, illustrating clearly that fabrication of bio-fuels is relatively energy demanding. Figures are based in the well known and widely accepted Concawe EUCAR-study [Concawe WtW] from 2006. Combustion of biomass is considered CO2 neutral, but overall GHG emissions from combustion of biofuels depend on production methods. Furthermore combustion of bio-fuels gives rise also to emissions of NOx, SOx, particles etc. and specifically N2O [Concawe WtW]. An extensive evaluation of WtW efficiencies for various fuels has been conducted by EuCar/JRC/Concawe, including also numerous bio-fuel chains. Underlying assumptions and results are available [Concawe WtW]. All results presented in these reports are based on the standard European drive cycle (Euro 3/Euro 4), representative for city driving.

Figure 3.2.7. WtW energy requirement and GHG emissions for non-hydrogen pathways (2010 vehicles) [Concawe WtW]. In the Figures 3.2.8 and 3.2.9, the WtW efficiency and GHG emissions for various types of bio diesels and bio ethanol are compared to conventional diesel. As can be seen from these figures, the GHG emissions related to production of bio-ethanol from waste wood are somewhat higher than for synthetic diesel from waste wood, related to the higher energy consumption of the ethanol process. These numbers would, however, be slightly altered if the energy consumption for the retrieval of wood is higher, in particular since large scale plants might be required for the production of synthetic diesel.


Figure 3.2.8. WtW energy efficiency and GHG emissions for various types of bio-diesels compared to conventional diesel, for personal vehicles [Concawe WtW].

Figure 3.2.9. WtW energy efficiency and GHG emissions for various types of bio ethanol compared to conventional diesel, for personal vehicles [Concawe WtW].


There are no environmental benefits related to the utilization of imported bio-fuels as long as there is a general shortage of supply within the European countries, but import could facilitate later use of domestically produced bio-fuels. Rough estimates indicate that an increase in CO2 emissions related to transportation of rape seed oil/bio-crude, or the product bio-fuel, over long distance (1,000-2,000 km) by truck would typically be in the order of 2-6 %. Transportation of raw material (biomass or waste) across similar distances, would lead to a significant increase in the CO2 emissions of the product fuel, typically in the order of 30-50 %, due to the low energy density of the raw material. The results from the Concawe WtW study are assumed to be representative also for Norway, although it seems reasonable to believe that due to more energy intensive forestry and generally longer distances to a production site, the numbers are likely to represent the “lower bounds” of what can possibly be achieved in Norway with respect to GHG emission reduction. Still, with wood or wood waste as raw materials, the reduction of GHG emissions by substituting gasoline and diesel with bio-fuels can be significant.


3.2.4Hydrogen

Primary energy resource(s) and fuel production: Hydrogen may be produced from nearly any energy source, either by splitting water utilising electricity generated from renewable energy such as wind, solar, wave or tidal energy, from gasification of biomass or from fossil fuels e.g., by reforming of natural gas. Technologies for hydrogen production are commercially available, both based on natural gas reforming and water electrolysis, and hydrogen is handled regularly in industrial processes at large scale. Maximum energy efficiency for hydrogen production is in the range of 75% (HHV) being close to the theoretical maximum.

Fuel availability and infrastructure: Utilisation of hydrogen as energy carrier for transportation requires the establishment of a completely new infrastructure for hydrogen distribution. Currently there are around 300 hydrogen refuelling stations world-wide3. In Norway only two refuelling stations provide hydrogen (Stavanger and Porsgrunn). The cost of establishing a fully developed infrastructure for hydrogen has been estimated to some 100-200 billion € or US$ [ref] in Europe and US [ref], respectively.

Vehicle characteristics and availability: Hydrogen may be utilised both in internal combustion engines (ICEs) and fuel cells (FCs). Conventional ICEs converted from gasoline to hydrogen typically provide 20-30% less power than the original gasoline vehicles (e.g. Toyota Prius, Mazda RX8 and BMW 7-series as shown in Figure 3.2.8). The reason for losing power is linked to the lower specific volumetric energy content of the hydrogen vs. gasoline. It is common to turbocharge these engines to regain some of the power.

Toyota Prius Hydrogen Mazda RX8 BMW 7-series Figure 3.2.8 Three hydrogen powered vehicles with ICE. Toyota Prius Hydrogen is rebuilt by Quantum. Three classes of hydrogen powered vehicles exist:

A. Conventional internal combustion engines (ICEs) o Otto engines (e.g., BMW, Ford) o Wankel engine (Mazda)

B. Hybrid vehicles (with ICEs converted to hydrogen) o Hybridization with ICE as only power source (e.g., Toyota Prius) o Plug-in hybrids (prototypes coming, e.g., Toyota, GM)

C. Fuel cell vehicles o Range extenders (e.g., Th!nk Hydrogen) o Weak or no hybridisation (e.g., Opel Zafira HydroGen 3) o Strong hybrids (e.g., Toyota FCV and Honda FCX)

3 http://www.h2stations.org/

http://www.h2stations.org/


Class A vehicles either utilise ICEs converted from gasoline to hydrogen, or custom made ICEs for hydrogen. The typical engine configuration is a conventional four-stroke Otto-Engine, but Wankel-engines4 are also being developed (Mazda). Class B may again be sub-divided into weak conventional (weak) hybrids and Plug-in HVs. One may term the Plug-in HV a “stronger” hybrid. Class C vehicles include three types. Vehicles which are primarily electrical (e.g., Th!nk, Figure 3.2.9) equipped with a small fuel cell which charges the battery pack, and extends the range typically by a factor 2. ADAM OPEL GmbH (a part of the GM group) have demonstrated Opel Zafira HydroGen 2, which is purely powered by a PEM fuel cell, thus representing no hybridization. Other fuel cell prototypes typically rely on strong hybrid configurations such as Toyota FCV and Honda FCX (Figure 3.2.10). Efficiency-wise the fuel cell vehicles are by far superior to the internal combustion engine and hybrid vehicles. The latter two may, however, constitute crucial enabling technologies until fuel cell vehicles become commercially available and competitive. Honda reports5 a tank to wheel efficiency of 60% for their latest FCX concept vehicle, providing a range of 570 km (hybrid drive train).

Figure 3.2.9. The Th!nk Hydrogen vehicle from Th!nk Nordic with a PEM fuel cell extending the range from 125 to 250 km.

Figure 3.2.10. Honda FCX, a hybridized PEM fuel cell prototype vehicle with 580 km driving range.

Hybrid vehicles for hydrogen (rebuilt Toyota Prius by Quantum, Figure 3.2.8) are semi-commercially available, and currently sold for around 800 kNOK (100 k€) per vehicle.

Fuel cell vehicles are not yet commercially available. These are expected to become available at acceptable cost by about 2015 and at competitive prices around 2020 according to EC’s strategic documents [ref].

Potential for GHG emission reduction

The potential for zero-emission and the flexibility with respect to energy source constitute the key rational for utilising hydrogen as energy carrier for transportation applications. The GHG emission reduction is, however, highly dependent on the source of energy utilised for the production of hydrogen. When generating hydrogen based on renewable energy, GHG emissions are close to zero. Producing hydrogen from biomass may generate CO2-emissions related to the energy demanding production process and transportation of the biomass. Reforming of natural gas provides hydrogen with CO2-emission reductions proportional to the retention potential of Carbon Capture and Storage (CCS) for the production process which is typical in the order of 80-85%.

Primary market segment within transportation

Hydrogen is expected to find its prime market as fuel for passenger vehicles and buses in urban areas. For maritime applications additional hurdles need to be overcome especially related to safety issues. For truck applications the drive cycle (high load over long distances) does not favour fuel cell

4 The Wankel rotary engine is a type of internal combustion engine, invented by German engineer F. Wankel, which uses a rotor instead of reciprocating pistons. This design delivers smooth high-rpm power from a compact, lightweight engine. 5 http://world.honda.com/FuelCell/FCX/FCXCONCEPT/

http://world.honda.com/news/2007/c070625FCXConcept/photo/pages/02.html

http://world.honda.com/FuelCell/FCX/FCXCONCEPT/


technology and efficiency characteristics as well, and bio-fuels are thus expected to be the preferred solution in this market segment.

3.3 Scenarios for emission reductions from road transportation

The Norwegian Commission on Low Emissions [NOU 2006:18] has made proposals for an overall emission reduction of around 50-80 % by 2050, based on the requirement that the level of CO2 in the atmosphere should be stabilized at around 450 ppmv (ca 550 ppmv CO2 equiv.), Figure 3.3.1.

Figure 3.3.1. Recommendations for reduction of GHG emissions for various sectors with reference to a “business-as-usual” case (“Referansebanen”) from the Norwegian Commission on Low Emissions [NOU 2006:18].

For the transportation sector suggestions from the Commission on Low Emissions on how the requirements on emission reductions should be met are summarized in Table 3.2 (with reference to the “Business-as-usual”-path). As can be inferred from Table 3.2, major emission reductions are suggested for road transportation, aiming at eliminating all emission from road transportation by 2050. Modest emission reductions are envisaged for the maritime sector, and related to an unspecified reduction of transportation demand, whereas no emission reductions are foreseen for the aviation sector (only domestic flights are accounted for in the balance of Table 3.2).


Table 3.2. Suggested changes in emissions, in Mton CO2-equiv per year, from the various transportation segments with respect to the “business-as-usual” pathway [NOU 2006:18]:

Year 2005 2020 2035 2050

Road transportation 11.4 12.5 12.5 12.9

Aviation (domestic) 1.2 1.9 2.3 2.5

Maritime transportation 3.3 3.3 3.1 3.0

“Business as usual” pathway (Referansebanen)

Total 15.9 17.7 17.9 18.4

Zero and low emission vehicles 0 -1.2 -5.5 -8.4

Bio-fuels 0 -2.5 -3.3 -3.4

Maritime transport 0 -1.0 -1.0 -1.8

Reduction of transportation 0 0 -1.0 -1.0

“Low emission” pathway (Lavutslippsbanen)

Total 15.9 12.9 7.4 4.0

In the following, the aims of extensive emission reductions in road transportation are elaborated in terms of how they can be fulfilled for the projected transportation demand, with relation to available technology and technology forecasts. Furthermore, implications of such extensive emission reductions are discussed. The limitations for road transportation are related to the fact that there are uncertain issues related to the use of hydrogen for heavy vehicles, and also for the maritime sector, where requirements for hydrogen storage requires technological as well as legislative breakthroughs before extensive use of hydrogen in these segments can be realised.


3.4 Scenarios for emission reductions in the transportation sector

In order to elucidate on possible pathways for emission reduction for road transportation, two scenarios have been developed. The first scenario is an evaluation of existing technologies, and technologies close to commercialisation, whereas the latter scenario is relatively optimistic regarding introduction of hydrogen vehicles after the year 2020.

The scenarios are based on the currently available demand forecast for the transportation sector, knowledge of the status of technologies, available information on the car pool, distribution of length of trips, average number of passengers etc. The assumptions common for all the scenarios are summarized below:

The increase in person transport as well as goods transport is assumed in accordance with public forecasts [Nasjonal transportplan].

In order to achieve agreement between the foreseen increase and the reference path suggested by the Commission of Low Emission [NOU 2006:18], the fuel economy improvement factor, related to both improved fuel economy, and substitution of old cars in the car pool, is estimated to increase by 30 % in the given timeframe (2005-2050). This factor applies both to person transport and goods transport.

It is assumed that the number of private cars increases in accordance with the increase in person-km, but that the distribution of trips, distribution of cars between households (see Table 3.1), and average number of passengers in the cars (see Figs. 3.6 and 3.7) remains unchanged. This implies that the average distance per car per year remains constant.

It is assumed that the number of new cars per year corresponds to 5 % of the car pool, and that the average lifetime of a car is 20 years, which is close to the situation for the last decade.

The reference scenario suggested by the Commission of Low Emission does not make any distinction between person transport and goods transport. Here, it is therefore assumed that their relative contribution to emissions (i.e. for the reference scenario) remains unchanged.

The distribution of trips, as given by Figure 3.6, indicates that 52 % of person-km is covered by trips of 20 km and shorter. Combined with available information on average number of trips/length per person and average number of passengers per car (Figure 3.1.7), and average vehicle-km per year is estimated.

Battery-electric cars are assumed to be introduced primarily in households with 2 cars (households with more than 2 cars are neglected), and the electric car is then assumed to cover all short trips in these households. For households with 1 car, it is assumed that 52 % of the trips are “short”, and 48 % of the trips are “long”. It is further assumed that the driving distance is independent of the number of cars in the household.

It is assumed that short trips, on the average, are conducted in a city drive cycle, and that long trips are primarily conducted on main roads highways at high speed. This is furthermore taken into account when emissions are estimated. For conventional cars, a difference in fuel economy of a factor 1.4 is assumed, such that for the average car pool in 2005 (NOT average 2005 car), the emissions related to city driving are 245 g CO2/km, and for highway driving 175 g CO2/km. For hybrid cars, a fuel economy factor of 1.5 is assumed for city driving, and emissions are assumed to be equal for city driving and highway driving. Hybrid cars are otherwise subject to the same improvements in fuel economy as conventional cars in the given time frame.


Imported bio-fuels are not considered in this study, as import of bio-fuels would not contribute to emissions reduction at a global scale.

Based on the Roadmap of bio-fuels [Bioroadmap], the available bio fuels originate from domestic supply of synthetic diesel and ethanol (second generation bio fuel) from farmed wood, assuming that a total of 20 TWh of biomass is available for bio-fuel production. The production is assumed to occur primarily in large scale production plants for synthetic diesel, which is believed to be the most energy efficient production route, in order to maximize utilization of the biomass and minimize emissions:

o First full scale production site for synthetic diesel in 2012, production of synthetic diesel, from a total of 8 TWh biomass. From 2016, production of ethanol in smaller production facilities, total of 4 TWh biomass utilised. From 2022, production of synthetic diesel in another 400 MW production site (8 TWh raw materials). Assuming 40 % conversion efficieny for the production of synthetic diesel, and 35 % for the production of ethanol from wood, this implies that the bio fuel available on the market is:

12 PJ synthetic diesel from 2012

12 PJ synthetic diesel and 5 PJ ethanol from 2016

25 PJ synthetic diesel and 5 PJ ethanol from 2022

Available bio-fuel is introduced primarily as fuel for heavy duty vehicles (trucks). This is related to the fact that heavy duty vehicles contribute by around 29% of the CO2 emissions from road transportation, and for the near future, there are few other viable options for improved fuel economy for heavy duty vehicles. Hydrogen powered trucks are not foreseen to be commercially available for the next 20 years, as fundamental problems related to fuel storage need to be solved. Neither is hybridization a viable option for heavy vehicles driving on high and relatively constant speed. It is assumed that bio-fuel can be introduced in existing vehicles (i.e. that modifications can make existing vehicles suitable for bio-diesel?(ethanol).

Private cars fuelled by hydrogen are assumed to be available from 2010. From 2010, hydrogen ICE cars are assumed available, hybrid hydrogen ICE cars from 2015, and fuel cell vehicles from 2020. The number of hydrogen cars in Norway in 2020 is assumed to be around 10 000, in accordance with the most moderate EU forecast (see Section 1.3.1)

If the source of hydrogen is natural gas, Carbon Capture and Storage (CCS) is assumed with 85 % degree of carbon removal.

In Prime Minister Jens Stoltenberg’s approach parts of Norway’s emission reduction were to be fulfilled by buying quota from other countries. In all scenarios in this report we have, however, assumed that emission reduction takes place domestically. The moral aspect of buying quota abroad will probably be debated intensely between Norwegian politicians. The shares between domestic emission reductions versus purchase of quota have recently been estimated by the Minister of Finance (Kristin Halvorsen), indicating that ½ to 2/3 of the emission reduction will be realised domestically6.

6 http://www.zero.no/klima/finansminister-kristin-halvorsen.pdf

http://www.zero.no/klima/finansminister-kristin-halvorsen.pdf


Natural gas is expected to take shares of the fuel supply in certain areas such as maritime transport and maybe within public transportation. As this report focuses on road transportation and the CO2-emission reduction of substituting conventional fuels with natural gas is limited to a maximum of 10-15% for bus applications, natural gas is not taken into consideration by the scenarios discussed in this report.


Scenario A: Hydrogen is not introduced in the transportation sector

- emission reductions to be achieved only by bio-fuel (domestic production) and introduction of hybrid and electric vehicles.

In this scenario, the car pool will be gradually substituted by either electrical or hybrid vehicles. The following assumptions apply for this scenario:

Major assumptions, Scenario A

- Bio-fuel is produced domestically, in accordance with the assumptions on establishment of large scale production plants, and reserved for heavy duty vehicles.

- Growth in transport demand is assumed according to public forecasts.

- Maximum number of electric vehicles is assumed to constitute around 30 % of the car park, corresponding to 1 car for every household with 2 or more cars.

The assumed rate of substitution of Scenario A, expressed as share of new cars sold, is depicted in Figure 3.4.1.

0

0.2

0.4

0.6

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1

1.2

2000 2010 2020 2030 2040 2050

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e of

new

car

s

Electric carsHybrid carsConv. cars

Figure 3.4.1 Suggested transition from conventional ICE cars based on fossil fuels to hybrid or electric cars (all personal cars) of Scenario A, expressed as share of new vehicles sold.


It should be stressed that the introduction of electric as well as hybrid vehicles shown in Figure 3.4.1 is around 3 % of all new cars being electric or hybrids already in 2010, corresponding to around 3,000 new vehicles of each category pr year. By 2020 the percentage of non-conventional vehicles in the vehicle park has then grown dramatically to almost 40%.

The resulting evolution of the composition of the car pool is given in Figure 3.4.2, in light of an average vehicle lifetime of 20 years. Although less than 10 % of new cars sold in 2030 are conventional ICE cars, the share is still more than 50% of the car pool.

0 %

20 %

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100 %

2005

2010

2015

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2025

2030

2035

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poo

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Electric cars

Hybrid vehicles(fossil)Conv. cars

Figure 3.4.2. Calculated shares of electric, hybrid and conventional cars when vehicles are introduced as shown in Figure 3.4.1.

The corresponding emission reduction related to this scenario is given in Figure 3.4.3. The emission reduction curve also includes the contribution from introduction of domestically produced bio-fuels, as described in the assumptions. However, as this fuel is allocated to heavy duty vehicles, and is assumed not to require major changes of the car pool, it is not included in Figures 3.4.1. and 3.4.2, respectively. It should be noted, that the emission reduction depicted in Figure 3.4.3. REQUIRE THAT BIO-FUELS ARE RESERVED FOR HEAVY DUTY VEHICLES. Other means of reduction of emissions from this sector are assumed to be limited in this timeframe. As can be seen from Figure 3.4.3, the zero-emission vision cannot be reached by heavy introduction of relatively mature low-emission vehicle technologies, the results indicate that emissions can be cut by around 50%. Further GHG emission reductions could, of course, be obtained if large quanta of bio fuels are imported. However, there are a number of other environmental impacts related to bio fuels, and in addition, there are challenges related to the amount of biofuel that can be produced, in particular in Europe. In this respect, import of bio fuels is equivalent to CO2 quota.


0

2

4

6

8

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14

2000 2010 2020 2030 2040 2050 2060Year

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O2

equi

v pa

Reference pathBio+hybrid+electricLow emission path

Figure 3.4.3. Emission reductions for Scenario A, given the substitution of vehicles as shown in Figure 3.4.1.

- If plug-in hybrid electric vehicles are extensively introduced, such that in 2050, all personal cars are PHEVs, the estimated CO2 emission in 2050 is around 6 Mton CO2 equiv per year (vs. 7 for all HEV or all-electric cars).

- If available biomass resources (20 TWh) are used for residential heating, thereby replacing 15 TWh of electricity, this could potentially give rise to an emission reduction of 12 Mton CO2 equiv per year, provided that power is transferred to the other Nordic countries and replaces partly fossil fuelled electricity production.

- It is estimated that electric vehicles (31% of all cars) could potentially cover 24 % of the total vehicle km travelled, and that the total energy consumption of these vehicles is around 2.2 TWh. The corresponding emission reduction amounts to 2.2 Mton CO2 equiv per year. The power consumption of plug-in hybrid vehicles can be assumed to be of the same order of magnitude.

-The estimated emission reductions related to the introduction of bio-fuels is 2.2 Mton CO2 equiv per year, somewhat lower than the reduction of 3.4 Mton CO2 equiv per year, as estimated by the Low Emissions Commission in 2050.

- Domestically produced bio-fuels have the potential of around 62 % coverage of the energy demand of the goods transportation sector.

Major implications, Scenario A


Scenario B: Rapid introduction of hydrogen vehicles from 2020

- and elimination of fossil fuels in road transportation within 2050

In this scenario, the following assumptions apply:

Major assumptions, Scenario B

- Bio-fuel is produced domestically, and reserved for heavy vehicles, similar to scenario A.

- Growth in transport demand is assumed according to public forecasts

- Maximum number of electric vehicles is assumed to constitute around 30 % of the car park, corresponding to 1 car for every household with 2 or more cars.

- Extensive introduction of hydrogen vehicles is assumed from the year 2020, such that in 2040, all new cars purchased will be either hydrogen vehicles, or electric vehicles.

- The transition of cars occurs at the highest possible rate which will lead to maximum emission reduction by use of domestic resources, only, in 2050.

In Scenario B an introduction of new cars occurs as depicted in Figure 3.4.4. In an interim period of about 30 years hybrid vehicles are foreseen to take a dominating share of the new low emission cars sold. The corresponding development of the total car pool is shown in Figure 3.4.4.

0

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Hydrogen carsElectric carsHybrid carsConventional cars

Figure 3.4.4. Scenario B; suggested transition from conventional ICE vehicles to electric, hybrid and hydrogen cars.


0 %

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40 %

60 %

80 %

100 %

2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Year

Car

poo

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HydrogenElectricHybridConventional

Figure 3.4.5. Estimated share vehicles in car pool when vehicles are introduced according to Scenario B (Figure 3.4.4).

The emission reductions are depicted in Figure 3.4.6. The reason why the emission reduction obtained in this Scenario (including bio-fuelled, hybrid, electrical as well as hydrogen vehicles) fails to meet the Low emission path is related to i) emissions from the category “other mobile sources”, like scooters, forklifts etc. are included in the reference path, but means of reducing emissions from this category are not included in the scenarios (amounts to around 1.1 Mt CO2 equiv). ii) Lack of bio-fuel supply, since bio-fuel is assumed to originate from domestic production, only, and some emissions from combustion of biofuels (see Figures 3.2.5 and 3.2.6). This corresponds to a total of around 2.2 Mt CO2 equiv. (since heavy duty vehicles are assumed to be fuelled either by bio fuels or by fossil fuels).

The emission from hydrogen vehicles depend on the resource for hydrogen production. As all hydrogen is assumed to be low emission (i.e., produced from renewables or natural gas with CCS) the difference between the yellow and orange curves is minor. When based on natural gas, 85% of the carbon is taken care of by the CCS-process. The difference between these two production options is also included in Figure 3.4.6.


0

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Reference path

Bio+hybrid+el+H2 (ely)

Bio+hybrid+el+H2(NG,CCS)

Low emission path

Figure 3.4.6. Potential for emission reductions for the transition of vehicles as given in Figure 3.4.4.

Major implications, Scenario B

- Regarding the introduction of electric vehicles and bio-fuel, the implications are the same as for scenario A

- The predicted emission reductions from introduction of hydrogen:

- If available biomass resources (20 TWh) is utilized for production of hydrogen by gasification, the potential GHG emission reduction amounts to 6.2 Mton CO2 equiv per year if utilized in fuel cell vehicles, and 3.8 Mton CO2 equiv per year if utilized in a ICE H2 hybrid vehicle

- If, in 2050, all hydrogen vehicles are fuel cell vehicles, with an average TtW efficiency of 38 % and all hydrogen is provided from renewable sources (i.e. from renewable power and electrolysis), the corresponding demand for power is around 12 TWh annually. If all hydrogen is produced by reforming of natural (with CCS), and all vehicles are H2 ICE hybrid vehicles, the corresponding annual energy requirement in 2050 is around 17 TWh NG (LHV).

The extensive introduction of hydrogen vehicles of Scenario B requires a corresponding expensive infrastructure development, in order to facilitate fuel availability. Infrastructure development is elaborated upon in the following chapter.


4. Viable regions for introduction of hydrogen

Based on a set of geographic and demographic criteria (Table 4.1), an initial regional hydrogen demand scenario has been established. In this scenario, the following types of vehicle uses are considered:

1. Local fleet-bound vehicles: e.g. buses, mail delivery cars, care (drive short

distances, high usage, need few refueling stations, early phasing in) 2. Private cars used locally: more small and less larger cars (drive mainly short

distances, average usage, need more refueling stations, phasing in after fleets) 3. Private cars used on highways: more large and less smaller cars, but

overlapping with 2. (drive mainly longer distances, average usage, need highway - refueling station network, phasing in after local private cars)

The penetration rates for fleet vehicles were adopted from the HyWays project (high policy support scenario) [Hyways Roadmap], and private cars were taken from Scenario B described above. For the fleet vehicles, buses for local services have been considered exclusively. The average penetration rates of fleet and private hydrogen cars can be seen in Figure 4.4.1.

For the regional distribution of the hydrogen car fleet, it is assumed that only people living in municipalities with hydrogen fuelling stations will consider buying hydrogen cars. Hence, assuming a country-wide average penetration rate target, the share of population with access to hydrogen in their municipality is very decisive for the local share of hydrogen cars among all new cars sold (i.e., if only few municipalities of a country have hydrogen fuelling infrastructure, the local share of hydrogen car sales must be higher than if many municipalities have fuelling stations to reach a given total penetration target). Too low regional availability of hydrogen may even lead to inconsistencies (i.e., the local annual sales are not sufficient to reach the target penetration growth rate). Hence, the regional distribution must be chosen carefully. Figure 4.1.1 shows the share of population with access to hydrogen. With the given vehicle replacement rates, area-wide supply from 2040 is a prerequisite to reach the target penetration rate.

0%10%

20%30%

40%50%60%

70%80%

90%100%

2010 2020 2030 2040 2050

Fleet penetration

Private car penetration

Population with accessto hydrogen

Oslo!

0%10%

20%30%

40%50%60%

70%80%

90%100%

2010 2020 2030 2040 2050

Fleet penetration

Private car penetration

Population with accessto hydrogen

Oslo!

Figure 4.4.1. Basic scenario for penetration of hydrogen vehicles.


In order to develop a scenario for the distributed hydrogen demand on a national basis, it was pre-assumed that hydrogen deployment is initiated in Oslo in 2010 (demonstration and fleet vehicles), and is then introduced in Trondheim, Bergen, Stavanger in 2015, and in Tromsø in 2025. For the supply of hydrogen along highways, the following was assumed:

2010: Oslo-Stavanger (HyNor project) 2025: Oslo-Bergen, Oslo-Trondheim, Bergen-Stavanger 2040: Trondheim-Tromsø

In order to estimate the propagation of hydrogen on a regional level and to facilitate commuting and short trips, it is further assumed that highways 50 km around areas with local vehicles are equipped with refueling stations.

Beside these pre-set regions and highways, the further order of regional propagation of hydrogen refueling infrastructure was determined following a ranking of municipalities due to several demographic indicators. The indicators chosen and their weight for the ranking are depicted in Table 4.1. Also included in the ranking are dynamic “bonuses” for municipalities where hydrogen is available in a neighboring region, and for municipalities where hydrogen fleet vehicles are operated already.

Table 4.1 Weight of indicators for propagation of hydrogen infrastructure for private cars

+10%Area has hydrogen fleet vehicles+10%Neighbor area has hydrogen20%Cars per person20%Gross income60%Population of larger area (50 km)

60%Population density40%Population

WeightPrivate

WeightFleetIndicator

+10%Area has hydrogen fleet vehicles+10%Neighbor area has hydrogen20%Cars per person20%Gross income60%Population of larger area (50 km)

60%Population density40%Population

WeightPrivate

WeightFleetIndicator

Beside the supply order (i.e., the year the first hydrogen fuelling station is installed in a specific municipality), the local penetration in the municipalities is a degree of freedom where an assumption is required. Here, it was assumed that each newly connected municipality would have a backlog in regional hydrogen car penetration against municipalities connected earlier, but that the penetration growth rate (i.e., the share of newly sold hydrogen cars) would be equal in all regions with hydrogen infrastructure, independent from their year of first connection.

The resulting hydrogen regional hydrogen vehicle penetration, where regions are grouped according to the time their first hydrogen infrastructure connection is shown in Figure 4.4.2, along with the average country-wide hydrogen car penetration.


Figure 4.4.2. Estimated regional penetration rate

0%

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2010 2020 2030 2040 2050

AverageRegions supplied from 2010Regions supplied from 2015Regions supplied from 2020Regions supplied from 2025Regions supplied from 2030Regions supplied from 2035Regions supplied from 2040Regions supplied from 2045Regions supplied from 2050

Loca

l veh

ic

With the timely supply order and the local vehicle penetration, the hydrogen demand per region can be calculated and visualised on a map as in Figure 4.4.3. For Scenario B of rapid introduction of hydrogen vehicles presented in Section 3.4, the requirement was that from the period 2035-2040, all new cars are either electric cars or hydrogen cars, in order to realise zero-emission road transportation by 2050. This implies an even more rapid evolution of the regional hydrogen demand than depicted in Figure 4.3, as hydrogen should be available in practically all regions from 2040. However, as the population density is very low in the regions supplied late (2040, 2045, 2050), the demand scenario as depicted in Figure 4.4.3 may be assumed to be fairly representative also for the average hydrogen vehicle penetration rates given in Figures 3.4.4 and 3.4.5.

le p

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n

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2010 2020 2030 2040 2050

ion

Averageat Regions supplied from 2010Regions supplied from 2015Regions supplied from 2020Regions supplied from 2025Regions supplied from 2030Regions supplied from 2035Regions supplied from 2040Regions supplied from 2045Regions supplied from 2050

Loca

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ice

pene

trl


Figure 4.4.3 Estimated regional development of hydrogen demand 2010-2050.


5.Options for export of CO2-lean energy to Europe

This chapter considers a set of alternative energy chains for delivering hydrogen to central Europe for utilisation as fuel for transportation and/or stationary applications. All energy chains are, thus, assessed in a well-to-tank-perspective. Two energy sources are included: Wind-power and natural gas (NG).

At first, an attempt is made to compare the energy potential available for export to the energy demand in central Europe, with the intention to classify what share of this energy demand could be supplied from Norway. This is followed by a case study which compares export options to central Europe for four specific energy sources.

5.1 Norwegian energy export potentials

The following section earmarks the potentials for export of CO2-lean energy from wind power and natural gas. Focus is put on two extreme locations, namely southern Norway due to its proximity to central Europe, and the far north of Norway due to its dilemma situation with high energy potentials but extreme remoteness from consumer centres. The geographically more modest locations in between these two extremes are considered advantageous for domestic energy supply (especially renewable energy) and are therefore not considered for export.

5.1.1 Onshore wind in Northern Norway

The overall potential for wind energy utilisation in Norway is very high, due to the high wind speeds and furthermore the low population density. A total theoretical potential of 900 TWh/a has been estimated by Hofstad [Hofstad 2005]. The same author [Hofstad 2005a] has estimated that from all onshore areas that are available and potentially economically viable for use of wind energy (i.e. >7m/s average wind speed), an amount of 245 TWh could be produced annually. This exceeds slightly the total energy use of Norway in all sectors in 2005 [Faktaheftet 2007]. The study reveals further that 163 TWh, or 66% of the total potential, accrue only in Finnmark, the northernmost county of Norway (correspondingly 7% of the total area of Finnmark is used for wind power). Under the used cost assumptions, 150 TWh could be produced at specific costs not higher than 4.4 ct€/kWh. However, including a potential minor export to Finland, only app. 0.9 TWh/a can be adapted by the current grid without substantial investments for upgrading transmission lines.

5.1.2 Offshore wind in Southern Norway

A theoretical physical potential of 180 TWh/a for areas with less than 10 m water depth, and 829 TWh/a for water depth up to 50 m have been estimated [NorWind]. No estimation has been found giving the potential of all areas that are practically exploitable (i.e., not excluded due to shipping, military, conservation etc.). A relevant estimation might be that 20-40% of the physical potential might be available for use [Hersleth]. Considering only areas not farther than 10 km from the shore, the above values are reduced by approximately 10% and 20%, respectively. More than two thirds of this potential accrues in the mid to mid-north of the country (Møre og Romsdal to Nordland). The south and west of the country contribute only with app. 12%. Still, wind energy from the south west is expected most feasible, due to the lower requirements for infrastructure investments. Offshore wind parks more than approximately 50 km from land are out of sight, which is critical for the public acceptance. The potential of future floating wind turbines (without fixed connection to the sea bed) located farther than 50 km from the shore is obviously huge.


5.1.3 Natural gas (NG) from Southern Norway

Unlike the declining Norwegian oil production, NG production is still increasing and a peak is not expected within the next years. The total proven NG reserves per end of year 2006 amount to 2302 bill. Nm³. At 1061.9 bill. Nm³, the Troll field in the Southern Norwegian North Sea contains nearly half of these overall reserves. The expected production from Troll in 2007 is 30 bill. Nm³ [Faktaheftet 2007]. Assuming a lower heating value (LHV) of 10 kWh/Nm³ natural gas, an energetic amount of approximately 300 TWh is produced annually in the Troll field, with a static range of approximately 35 years.

5.1.4 Natural gas (NG) from Northern Norway

In Northern Norway, the Snøhvit field is the largest NG field with total reserves of 160.6 bill. Nm³ [Faktaheftet 2007]. Statoil assumes reserves of 193 bill Nm³ [Snøhvit] and an annual production of 5.67 bill Nm³ LNG, which in energy terms represents approximately 57 TWh per year and a static range of around 30 years.

5.1.5 Comparison of resources

Table 5.1 summarises the annual potentials of all energy sources regarded in this study.

Table 5.1: Potential of the energy sources regarded for export

Region Current annual NG production Technical wind energy potential

Southern Norway 300 TWh/a (Troll) 33-332 TWh/a (offshore) 7

Northern Norway 57 TWh/a (Snøhvit) 163 TWh/a (onshore)

5.2 Estimation of central Europe’s future demand for Norwegian energy

This chapter evaluates the outreach of the Norwegian energy export potentials at the available markets. Natural gas is a successful export good already today. Supposed that no binding CO2 regulations will be adopted, no new infrastructure is required. Therefore this section focuses primarily on export of wind energy. However, the need for CO2 capture and sequestration due to CO2 quota or taxation could change the case of natural gas export as well.

5.2.1 Potential markets for renewable energy import

The dependency of a country on energy import depends strongly on its population and its available resources. Already today all central European countries are net importers of fossil energy. With the transition to stronger use of renewable energy, where especially wind energy plays an ever more important role in central Europe, the dependency situation will shift somewhat between the countries. Assuming a scenario where energy supply in all sectors heavily relies on renewable energy, new major influence factors to qualitatively determine the dependency on import are population density (since renewable energies are distributed and extensive energy forms requiring large areas) and, especially with respect to offshore wind energy, the size of territorial waters. Even

7 33 TWh: minimum assuming water depth <10 m, distance from shore <10 km, 20% of physical potential. 330 TWh: maximum assuming water depth <50 m, 40% of physical potential.


though being a pioneer in wind energy usage today, Germany here sticks out to have a limited potential with its comparatively high population density as well as relatively small shore and territorial waters area. Other countries with high dependency on import might be Belgium (due to high population density, limited shore access) and the landlocked countries south and east of Germany. Most other countries (UK, France, Poland) have huge territorial waters and will therefore tend to be less interested in energy import from Norway. Obviously, for a proper assessment of offshore wind potentials, the water depth in vicinity to the coast has to be regarded. Nevertheless, due to its geographical position and situation of domestic potentials, Germany is believed to be a very promising client for Norwegian CO2-lean energy in the future.

5.2.2 Energy demand situation in Germany and estimation of supply shares

When used for transportation, hydrogen has a higher efficiency than conventional fuels due to the possibility to use it in fuel cells. Further uncertainty is induced by the trends in transportation (shift to smaller cars, goods transport by rail, public transport, etc). The HyWays project proposes a hydrogen demand for transportation in Germany of <10 TWh/a by 2020, 10 to 60 TWh by 2030, and 90 to 150 TWh by 2050 (representing 36-70% of all cars; goods transport not included). These scenarios are depicted in Figure 5.2.1.

The Norwegian potential of wind energy available for export estimated above varies from 196 to 495 TWh/a. Assuming an energy use of approximately 2 kWh per kWh of hydrogen delivered to Germany (see section 5.3), this means that a 98 - 297 TWh of hydrogen could be delivered if all wind energy were used for hydrogen production. Therewith, wind power from Norway has the potential to supply the major part of the German hydrogen demand for transportation in 2050, and probably much more than that.

0

50

100

150

200

250

300

2020 2025 2030 2035 2040 2045 2050

Year

H2 d

eman

d fo

r tra

nspo

rtatio

n in

Ger

man

y (T

Wh/

a)

HyWays Very High PolicySupportHyWays High PolicySupportHyWays Modest PolicySupportLower bound of Wind-H2 potential

Upper bound of Wind-H2 potential

Figure 5.2.1. Hydrogen demand for transportation in Germany (HyWays)


5.3 Premises and general assumptions

The E3database tool [E3database] was used for all calculations and the timeframe of this study is year 2020-2030. This study is focussed at large-scale production and transport (1-4 GW hydrogen output) and hence large-scale data are used for all equipment. Since the economies of scale differ between the technology options, the options studied here have individual capacities that match their typical economic optimum scale8. The chosen timeframe has implications on the costs of innovative technologies subject to technology learning (large-scale H2 liquefaction, offshore wind power). The cost estimations based on currently available forecasts are obviously uncertain, but provide some indications for the economic requirements for the installations under consideration. Furthermore full utilisation of all equipment, i.e. a fully developed market, is assumed.

Energy resources considered are NG and offshore wind from Southern Norway (i.e. Troll field/Rogaland), and NG or onshore wind from Northern Norway (i.e. Snøhvit field /Finnmark). For each energy source, two competing transport options are compared, namely transporting the energy in its primary state (NG or electricity from wind) vs. transporting locally produced hydrogen.

All chains end with hydrogen delivered at a central terminal in Northern Germany (e.g. Hamburg). The underlying assumption is that hydrogen will be used as a large-sc

ale transportation fuel in the studied timeframe (2020-2030). For the chains using energy resources from Northern Norway, the end-product is liquid hydrogen (LH2) and for the chains using energy resources from Southern Norway, it is compressed gaseous hydrogen (CGH2) at 20 MPa for pipeline or gas trailer delivery. This facilitates direct comparability of the competing transport options when the end product and location of delivery coincide. The reason to distinguish between CGH2 and LH2 is that hydrogen produced in Northern Norway can only be exported economically in the liquid state by LH2 ship. Hence hydrogen arrives in liquid form, and evaporating it at the terminal would make the chain uneconomic against gaseous transport chains from the South. Considering that LH2 is well suited for transport by truck, it is assumed that hydrogen from Northern Norway will be distributed further in Europe in the liquid form, while gaseous hydrogen (from Southern Norway) will be used locally and distributed through pipelines and gaseous hydrogen trucks.

To avoid from a strong economic impact of CO2 prices, but still facilitate a fair cost comparison, it is assumed that all chains are CO2-lean9 or virtually CO2-free. This implies that carbon capture and storage (CCS) technology is feasible (at 85% CO2 recovery) within the considered timeframe, and that sufficient CO2 storage capacities are available both in Northern Germany and in Norway. The residual emissions are taxed implying minor cost, while CO2 captured in Southern Norway may be used for Enhanced Oil Recovery (EOR) and is consequently assumed to have a modest value.

8 E.g., the technical maximum of single HVDC sea cable capacity seems to be 1-2 GW, and beyond that no significant specific cost degression can be achieved by further up-scaling. In contrast, pipelines have stronger economies-of-scale in this size.

9 CO2-lean implies that carbon capture and storage be applied to the main conversion processes. This mitigates green house gas emissions, but does not totally eliminate them due to only 85% of the CO2 being captured and furthermore due to distributed emissions (e.g. from recompression stages).


Destination

NG (e.g. Kårstø)

Offshore Wind (Rogaland)

NG (Snøhvit)

Onshore Wind (Finnmark)

NG/H2 pipeline

Figure 5.3.1 Map showing energy chains included in this study, the location of energy resources, transport options and destination for hydrogen delivery to Europe.


5.3.1Energy transport chains

In this study the following energy transport chains have been considered: 1. NG from Southern Norway to CGH2

a. NG pipeline: NG is exported via an existing 580 km NG pipeline. At the destination in Northern Germany, it is reformed to hydrogen by SMR with CCS (CO2 is stored in local geological formations). The resulting hydrogen is compressed to 20 MPa for further distribution using a small amount of German grid mix electricity (~3.5% of the hydrogen LHV).

b. H2 pipeline: NG is reformed (SMR with CCS) to hydrogen at the Kårstø gas processing plant. The separated CO2 gas is used for enhanced oil recovery (EOR). The hydrogen is transported to Northern Germany in a dedicated 580 km H2-pipeline. Also here German grid mix electricity is used for compression to 20 MPa.

2. Offshore wind from Southern Norway to CGH2 a. HVDC sea cable: Wind electricity from floating wind generators is collected offshore

and directly transmitted to Northern Germany by HVDC cable. There, it is used for production of hydrogen from water by electrolysis and compression to 20 MPa.

b. H2 pipeline: Wind electricity from floating wind generators is collected and transferred to the Norwegian mainland (50 km cable). There hydrogen is produced by electrolysis, and sent to Northern Germany through a hydrogen pipeline (see 1b). German grid mix electricity is used for compression to 20 MPa.

3. NG from Northern Norway to LH2 a. LNG ship: NG is liquefied locally at the Melkøya plant and transported to Northern

Germany by LNG ship (2400 km). There, most of the LNG is used for hydrogen production through SMR with CCS (local CO2 storage). The electricity needed for hydrogen liquefaction is generated from part of the LNG by a combined cycle gas turbine (CCGT) plant with CCS. As opposed to gaseous H2 compression, grid electricity is not used here due to the significantly higher electricity requirement for liquefaction and thus correspondingly higher CO2 emissions.

b. LH2 ship: NG is reformed by SMR+CCS at Melkøya (local CO2 storage, but no EOR possible). Part of the NG is used to generate electricity in a CCGT plant for hydrogen liquefaction. The liquid hydrogen is transported to Northern Germany by ship.

4. Onshore Wind from Northern Norway to LH2 a. HVDC: Onshore wind electricity is transported by HVDC transmission (1800 km along

the Norwegian mainland through a dedicated overhead line + 580 km sea cable) to Northern Germany. There, it is used to produce hydrogen by electrolysis and liquefaction. Integrated transport through the Norwegian electricity grid does not seem feasible for large-scale long-distance transmission due to issues with grid capacity, reactive power and efficiency. However, partial integration of the hydro reservoirs along the way could increase the capacity factor of the transmission line by providing energy buffering, which is not regarded here.

b. LH2 ship: Onshore wind electricity is transported to the coast (e.g. Melkøya) with AC lines. There, it is used to produce hydrogen by electrolysis and to liquefy it. The liquid hydrogen is transported to Northern Germany by ship.

The energy chains described above are illustrated in Figure 5.3.2.


LH2LH2

GTGT

SMRSMR

Chain 4b

Chain 4a

Chain 3b

Chain 3a

Chain 2bChain 2a

LNGLNG

LH2LH2

H2H2

SMRSMR

NGNG

H2H2

Chain 1aChain 1b

GH2

GH2

SMRSMR

LH2

LH2

GTGT

SMRSMR

580 km

580 km

600 km

580 km

50 km

2400 km

2400 km

2400 km

1800 km HVDC land 600 km sea

100 km

NorthSouth

EOR

HydrogenElectricityNatural gasCO2

Figure 5.3.2. Energy chains considered in this Chapter.

5.3.2Main techno-economic assumptions

Table 5.2 through Table 5.5 show the main techno-economic assumptions for the equipment used in the chains studied. Where available, the widely accepted dataset of the CONCAWE-EUCAR-JRC [ConcaweWtW] and the HyWays projects [HyWays] have been used. All financial calculations are based on an interest rate of 8%, and a depreciation period of 20 years (except cables and pipelines which are depreciated over 40 and 50 years, respectively). As mentioned above, the scales are approximately chosen according to typical economic optimum of the technology options. Where available data deviate from the 2020-2030 timeframe, this is indicated in the reference column. For most cost data, a bandwidth of uncertainty has been assumed according to the maturity of the technology and the quality of the data.


Table 5.2: Feedstock data

Source Costs

(€/MWh) CO2 equiv. (kg/MWh)

Comment / Reference

NG South 37 ± 30% 5.2 Norwegian gas, Concawe/GEMIS [Concawe WtW], [ConcaweWtT], [GEMIS], market price

LNG (North) 37 ± 30% 21.3 Market price

Onshore wind electricity

38 ± 15% 0 3000 full load hours, 2 MW units, HyWays [HyWays]

Offshore wind electricity

w/o transmission / 50 km cable

45 / 50 ± 30% 0 4300 full load hours [Climate Database]10

Grid mix electricity in Germany

62 ± 20% 524 German electricity mix 2030 (Primes), grid distribution to low voltage level

Table 5.3: Assumed costs and revenues for CO2

Costs/Revenue (€/ton)

CO2 EOR revenue 10 ± 50%

CO2 emission burden 50 ± 50%

10 Average value of the given range (3800-4800 full load hours for <50 km)


Table 5.4: Process technology data

Process

Feed-stock / Energy

Product Scale (MW out)

Energy input (MWh/MWh)

Costs

(€/ MWhout)

CO2 equiv.

(kg/ MWh)

Comment / Reference

SMR (CCS) NG/LNG GH2 (6.1 MPa)

844 1.37 8.7 ± 15% 42.7 2010, 85% CO2, Foster Wheeler [HyWays]

Electrolysis Electricity GH2 (3 MPa)

2.411 1.43 9.5 – 13.512 ± 30%

0 2030, Hydrogenics [HyWays]

H2 Liquefaction

GH2 (3 MPa), Electricity

LH2 300 1+0.21 11.6 13

± 15%

0 2030, [ConcaweWtW, WtT], [HyWays]

NG Liquefaction

NG LNG 7220 1.069 1.9 14 17.7 2030, includes GT plant with 41% efficiency

[ConcaweWtW]

Combined Cycle GT (w/CCS)

NG Electricity 432 2.214 15.0 ± 15% 43.6 Amine cycle, 90% CO2, [ConcaweWtW]

H2 compression

GH2 (3 MPa), Electricity

GH2 (20 MPa)

2 1+0.036 2.5 0 Sulzer

[HyWays]

11 Electrolysis plants are modular

12 Lower value for 4300 full load hours (offshore South), upper value for 3000 full load hours (onshore north)

13 Liquefaction is assumed at 8000 full load hours (wind path: possibility to increase utilisation by load management of electrolyser/liquefaction)

14 Included in market price for LNG


Table 5.5: Transport technology data

Mode of

Transport

Side energy (MWh/MWh)

Feedstock efficiency

Scale (MW out)

Costs (€/MWhout)

CO2 eqv. (kg / MWhout)

Comment / Reference

NG pipeline 650 km

(Compres-sor NG-powered)

95.5% 28100 0.424

9.6 Europipe II (Error! Reference source not found., Error! Reference source not found.) – usage of existing pipeline

H2 pipeline 650 km

No recom-pression

100% 4400 2.822 ± 10%

0 HyWays 800 km pipeline + 50% contingencies [HyWays]15

HVDC sea cable 580 km

97.2% 1200 15.63 / 22.40 ± 15%

0 4300 / 3000 full load hours, Upscaled from NorNed [Tenne 2007]

HVDC: 1800 km overhead line

91.9% 2500 9.87 ± 20%

0 3000 full load hours [Statnett];

no converters (used in sequence with sea cable)

LH2 ship (2400 km)

Electr. 0.011

96.3% 1300 13.29 ± 50%

0 SWATH carrier [Backhaus], [HyWays]

LNG Ship (2400 km)

Electr. 0.002

Fuel oil 0.007

97.2% 4400 1.88 ± 10%

7.7 2400 km distance [HyWays]

15 800 km sea pipeline from HyWays – case „Norway 2a“, downscaled to 650 km, 50% cost contingencies added. Please note that for hydrogen pipelines, the economic optimum conditions differ from NG pipelines: Since hydrogen is a refined product and has different flow characteristics, a design with a lower flow speed avoiding recompression is more beneficial.


5.4 Results and Discussion

Using the main assumptions above (Section 5.3 / Tables 5.2 through 5.5) supplemented by a set of required and general techno-economic assumptions comprised in E3database [E3database], the chains have been compared in terms of energy efficiency, costs, and green house gas (GHG) emissions. The results are presented in this section.

5.4.1Energy input

0.0 0.5 1.0 1.5 2.0

1a - NG => CGH2, NG-Pipe

1b - NG => CGH2, H2-Pipe

2a - Wind offsh. => CGH2, HVDC

2b - Wind offsh. => CGH2, H2-Pipe

3a - NG => LH2, LNG-Ship

3b - NG => LH2, LH2-Ship

4a - Wind onsh. => LH2, HVDC

4b - Wind onsh. => LH2, LH2-Ship

Primary energy use (kWh / kWh H2)NG Wind PE for Grid electricity

Figure 5.6.1 Specific energy requirements for production and transport chains compared in this study.

Figure 5.6.1 shows the specific energy requirements for the delivery of 1 kWh of hydrogen to the European market for all energy chains included in this study. It can be seen that all chains need between 1.5 and 2.1 kWh energy input per kWh of hydrogen. The LH2 chains require higher energy input and are, hence, less efficient than the CGH2 chains. This is primarily due to the energy intensive liquefaction process, but also linked to losses imposed by the long distance (2400 km) between energy resource and delivery site. Comparing the wind energy pathways, it can be seen that for the short distance HVDC and pipeline transport are equally efficient, while for the long distance LH2 ship is more efficient than HVDC. The LNG/LH2 pathway (chain 3a) energy use could decrease by up to 0.05 kWh/kWh if the refrigeration potential of LNG were utilised to pre-cool the hydrogen prior to liquefaction. Still this chain constitutes the most energy demanding option with an energy requirement exceeding 2 kWh per kWh H2 delivered. For NG from the South of Norway, a hydrogen pipeline is more efficient than a NG pipeline due to the lower recompression work required.


5.4.2Green house gas (GHG) emissions

Figure 5.6.2 shows the specific CO2-equivalent emissions per kWh H2 produced. It can be seen that even though CCS is applied to the reforming process, significant GHG emissions are generated along the NG paths. Chain 3a (NG => LNG Ship) with 115 g/kWh has the highest emissions, but remains still significantly lower than hydrogen produced from onsite SMR without CCS (360 g/kWh).

The main sources of CO2 emissions for the NG paths are the production of NG (methane emissions and energy demand – app. 40 g CO2 eq./kWh H2) and the remaining emissions from the SMR where only 85% of the CO2 is captured (app. 40 g CO2 eq./kWh H2).

The low emissions in paths 2b (Wind offshore => H2-Pipe) and 4b (Wind onshore – LH2 ship) result from the German grid mix electricity used for H2 compression and the LH2 terminals, respectively. The HVDC chains are virtually CO2 free.

0 50 100 150 200 250 300 350 400









Reference-onsite SMR (w/o CCS)

CO2 equivalent emissions (g/kWh H2)

NG/LNG production Transport NG SMR (85% CO2 captured)Electricity for liquefaction Auxiliary grid electricity Reference

Figure 5.6.2. Specific GHG emissions of the compared production and transport chains


5.4.3Costs

-0.02 0.02 0.06 0.1 0.14 0.18









Costs (€/kWh H2)Feedstock production Feedstock transport H2 productionH2 liquefaction H2 transport EOR revenue (10 €/t)CO2 burden (50 €/t)

Break even bandwidth with today's conventional untaxed fuel

Figure 5.6.3. Specific hydrogen costs of the production and transport chains compared in this study, including red bars indicating the uncertainty of the cost estimates.

Figure 5.6.3 shows the costs per kWh of hydrogen energy delivered at the terminal for all eight chains, split into feedstock production, feedstock transport, hydrogen production, hydrogen liquefaction (where applicable) and hydrogen transport. The red error bars show the range of costs when applying the uncertainty bandwidths of Tables 2-4. The white transparent box shows the range where the hydrogen (including distribution to fuelling stations) would break-even with today’s conventional untaxed fuels16.

From Figure 5.6.3 it can be seen that • At the assumed market prices NG from Southern Norway induces the lowest overall

hydrogen provision costs at app. 7 ct€/kWh H2, with the H2 pipeline option 1b being slightly cheaper than the NG pipeline due to lower pressure losses and possibly the CO2 revenue from EOR.

• Offshore wind from Southern Norway has comparatively higher costs at 9-10.3 ct€/kWh H2. Here, the pipeline option is the cheaper one due to high costs for HVDC transmission.

• NG from the North results in the medium hydrogen price segment at app. 10-11 ct€/kWh H2. The transport by LNG ship is cheaper than by LH2 ship due to the higher volumetric energy density of LNG. Likewise, no LH2 tanker has ever been built and data from the EQHHPP project are quite aged, resulting in a higher cost uncertainty. A possible CO2 burden would, however, have a lower impact on the LH2 tanker chain due to lower emissions.

• The costs for onshore wind from the North do strongly depend on the transport mode. While LH2 ship transport seems quite competitive here with app. 10.5 ct€/kWh H2, the long-distance HVDC pathway does not represent an economic option at app. 14.5 ct€/kWh. This is primarily

16 assuming 6.5 ct€/kWh oil-based fuels, an efficiency factor of fuel cell over ICE vehicles of 1.6 (Error! Reference source not found.). Minimum border: CO2 burden 0 €/ton, hydrogen delivery distribution costs of 3 ct€/kWh (Error! Reference source not found.) subtracted; maximum border: CO2 burden 50 €/ton, hydrogen delivery distribution costs of 0.5 ct€/kWh (Error! Reference source not found.) subtracted.


due to the high costs for the long-distance HVDC transport. The specific hydrogen costs for this option may, however, be reduced if advanced HVDC technology become available (e.g. ultra high voltage direct current).

• The cost reduction through CO2 usage for EOR is very limited under the current assumptions.

• Pipelines generally appear to constitute an inexpensive transport option. However, it must be kept in mind that pipelines from a certain length need recompression for gas transport, which reduces energy efficiency for longer distances. Hence, utilising hydrogen pipeline transport from the Northern Norway would significantly increase the feedstock use and therefore not be economic.

• Except chain 4a, all results are within the bandwidth of per-km cost competitiveness with conventional untaxed fuels.

• Highest uncertainties are assumed in the data for LH2 ship transport (outdated data) and future electrolysis (major cost reductions expected through technical learning).

5.5 Qualitative factors

In addition to GHG emissions, energy use and costs, there are other arguments not easily quantifiable which also have an influence on decisions which energy chains and to pursue and technologies to apply.

Among others, such arguments can be found with respect to value creation and contribution to research and development in Norway, flexibility of an investment with respect to future changes of the energy system, and environmental impact of the installations. These factors are discussed for the compared energy chains in the following sections.

5.5.1 Value creation in Norway

Qualitatively, a higher refining stage of an exported product (e.g. gasoline instead of crude oil) will lead to a higher value creation in the exporting country. However, a quantification of this value creation is subject to substantial uncertainty since process technology is often developed and produced in other countries. This makes the value creation to some extent independent of where the equipment is installed, while operation of the plant in most cases will be conducted by local operators and hence contributes to value creation locally.

For a specific project the subcontractors for development, production, installation and operation will be determined by tender procedures and therefore the corresponding domestic value creation cannot be easily predicted. However, in the following a general and qualitative assessment has been carried out by looking at the expertise of Norwegian industry and research communities for the relevant technologies as well as existing infrastructure projects:

• Wind turbines: In the current market for wind energy, Norwegian companies only play a marginal role. The only company developing wind turbines is ScanWind. As of today, they are supported by the mid Norwegian energy supplier NTE, but they are currently not cost competitive with the volume manufacturers in Denmark, Germany and the USA (. The expected value creation in Norway is low.

• Natural gas production: Process industry expertise and research groups within production of NG are considered strong in Norway and today’s projects significantly contribute to value creation there.

• Steam methane reforming: As of today, few large steam methane reformers have been installed in Norway. Aker Kværner company is a Norwegian player in this field, however no concrete plants are known by the authors. The expected value creation in Norway is rather low (operation of the process plant, with imported core components).


• CO2 capture: This topic is in strong focus by the Norwegian industry and research community and a high contribution to value creation can be expected. Realised projects including CO2 separation and storage so far are located at the Sleipner and Snøhvit fields, and a CCGT plant in Mongstad is planned by Statoil with support from the Norwegian government. High value creation in Norway is expected.

• Electrolysis: Norsk Hydro’s electrolyser division (Hydrogen Technologies) has a high ranking in today’s rather confined market for electrolysers. They are producing both large scale industrial and small scale electrolysers for on-site supply of first hydrogen fuelling stations. Electrolysis is hence likely to increase value creation in Norway, specifically as Norsk Hydro’s activity is the only major European industry effort remaining.

• Liquefaction: The Snøhvit LNG plant realised at Melkøya in 2004-2007 has been a joint venture by Norwegian Statoil and German Linde, using a jointly developed technology for NG liquefaction (MFC - mixed fluid cascade). Norwegian research and development skills of NTNU and SINTEF went into it; however, the installation was mainly done by Linde. As for H2 liquefaction plants, all plants installed in Europe are built by Linde, AirProducts and AirLiquide. The expected value creation potential in Norway is thus considered to be moderate.

• LH2/LNG ships: Even though Norway still has a series of state-of-the-art shipyards and ample know-how on designing LNG carriers (former Moss Rosenberg and Kværner Moss), the LNG carriers for the Snøhvit project were all built by Japanese yards (Mitsubishi Heavy Industries, Mitsui, Kawasaki). The LNG-tankers utilising spherical tanks were developed at NTNU/SINTEF in the 1970s. This type of ships still takes a 60 % share of the market for LNG-transport. Norwegian expertise within new ship designs and maritime sector in general is considered of high international standards. Norwegian stakeholders are also leading the development towards application of new cleaner fuels and have developed regulations, codes and standards for utilisation of LNG as fuel for ships. The first ferry was built at the Norwegian ship yard Langsten Slip & Båtbyggeri AS and put in operation in February 2000, predominantly utilising foreign technologies. Another 5 ferries have been purchased and some are already in operation. The expected value creation in Norway is thus considered moderate.

• Pipelines: Europipe I and II are operated by Norwegian Gassco, and the technical service provider is Statoil. Rather high value creation in Norway is expected for both NG and hydrogen pipelines.

• HVDC: For the NorNed project, the cable has been produced and installed by Nexans, a French company with a strong local activity in Norway. The converters have been built in Sweden by ABB. The expected value creation in Norway is considered moderate.

5.5.2 Flexibility

The flexibility of a transport infrastructure with respect to the utilised energy feedstock could be an important topic in the future when the fossil energy sources will decrease and a shift to renewable energy is expected. Here, the hydrogen and electricity transport infrastructures have high flexibility since these energy carriers can be produced from any source of energy. The LNG ship option is less flexible because they can only transport LNG; a conversion to e.g. liquid hydrogen would probably cause high refurbishment costs due to the different operating temperatures (20 K vs. 110 K) and higher insulation requirements. Conversion of NG pipelines for transporting hydrogen is theoretically feasible but needs to be studied on a case-to-case basis due to limitations in materials and equipment.

Since it is expected that the energy demand side will face significant changes, end-use flexibility of the imported energy carrier in the receiving country (here Germany) is crucial. In this context, hydrogen, as the highest refined product has the limitation that it should primarily be used for transportation. Hydrogen used for heating or in stationary electricity production would efficiency-wise


be inferior to the direct use of electricity or NG. The latter two let, in contrast to hydrogen, the receiving country has the freedom to choose in which sector they prefer to utilised the energy; however with the limitation that the use of NG will cause local CO2 emissions.

5.5.3 Environmental impact

The environmental impact of transport options can be crucial for the acceptance of a large-scale project. Here, all pipe or cable based transport options may face problems since they interfere with the sea bed (respectively, overhead lines affect the natural scenery) and may need to go through protected areas (such as the German Wattenmeer, or Hardangervidda). On the other hand similar pipelines and cables currently operating prove that the environmental impact is acceptable. The ship options may be advantageous here since they do not interfere with protected areas, and furthermore the increase in ship traffic and emissions is very limited due to the low frequency of sailings. On the other hand, ships will possibly cause significant pollutant emissions.

Table 5.6 summarises the factors discussed above for the compared chains. Table 5.6: Evaluation of qualitative influence factors (green: positive, yellow: modest, red: negative.

Option

Value creation in Norway

Feedstock flexibility

End-use flexibility

Environmental Impact

1a – NG => CGH2, NG-Pipe

NG, pipeline only NG feedstock; may be convertible to hydrogen

direct use (CO2!) stationary electricity or transportation H2

sea bed pipelines; recompression stations


NG, pipeline, CCS

can come from any primary energy

stationary use inefficient; only transportation



few process steps


Stationary electricity or transportation H2

sea bed cables


electrolysis, pipeline





NG, operation of process steps

only NG can be feedstock

direct use (CO2!) stationary electricity or H2

few ship sailings; no sea bed/overhead installations


NG, CCS, operation of process steps





few process steps


Stationary electricity or transportation H2

sea bed cables; overhead lines


electrolysis, operation of process steps





5.6 Conclusions

The current paper evaluates and shows the results of an assessment of large scale energy export options from Norway to continental Europe in the 2020-2030 timeframe. Norway offers a huge stranded wind energy potential, large remaining NG reserves and furthermore the possibility of CO2 storage. This could strategically facilitate a large-scale export of CO2-lean energy to central Europe. From the evaluation of different energy chains, the following results have been achieved:

NG from Southern Norway can be exported by pipelines and reformed to hydrogen in the

receiving country, or reformed locally and exported through a hydrogen pipeline. The costs of both options are similar (7 ct€/kWh H2), but the hydrogen pipeline provides higher value creation in Norway and slightly lower emissions. The flexibility of the hydrogen export option is higher with respect to the energy feedstock used; however lower with respect to the end-use in Europe. Yet, it needs to be considered that with rising natural gas prices, the cost advantage over renewable energy sources may diminish or even disappear.

Offshore wind from the South can be exported via HVDC sea cable and used for electrolysis in the country of destination, or hydrogen can be produced locally and exported via pipeline. The latter option is cheaper (9 vs 10.3 ct€/kWh H2), but induces marginal CO2 emissions because grid electricity is needed for compression in the receiving country. Energy input is similar for both options. Value creation in Norway appears higher for the piped hydrogen case, while the end-use flexibility is higher when electricity is delivered.

NG from the North can be exported by LNG ship and reformed in the destination country, or reformed and liquefied locally for export via LH2 ship. LNG ship is the cheaper option (10 vs 11 ct€/kWh H2), however it induces higher emissions and energy input as well as lower value creation in Norway and lower flexibility with respect to energy feedstock than the LH2 ship path. In turn LNG gives more flexibility in end-use than the higher refined LH2.

Onshore wind from Northern Norway can be exported via HVDC and electrolysis in the destination country, or via local electrolytic hydrogen production and liquefaction and LH2 ship transport. The HVDC option is very expensive (14.5 ct€/kWh H2) and induces high energy losses due to long electric transmission distances (2400 km). The LH2 ship option (10.5 ct€/kWh H2) is in a competitive cost range and offers high value creation in Norway, however at the cost of lower end-use flexibility.

In general, value creation and feedstock flexibility for the options where hydrogen is exported seem to have advantages over the export of the primary energy carrier, however at the cost of a limited end-use flexibility. Environmental impact is qualitatively rated somewhat lower for the ship options than for the pipe or cable-bound options.

All options except a HVDC line from Northern Norway allow for production of hydrogen fuel at cost levels competitive to today’s conventional fuels, if hydrogen is used in fuel cell vehicles.

Overall, assuming that hydrogen is utilised as fuel for transportation, export of hydrogen from NG and direct NG export result in an stand-off (however with higher value creation for Norway in case that hydrogen is delivered). Export of hydrogen from renewable electricity from Norway to central Europe seems economically advantageous against HVDC transmission. It needs to be kept in mind that while NG prices are posed to only rise for scarcity and market reasons, renewable hydrogen is posed to become cheaper in the future due to an expected cost reduction of innovative technologies involved. Hence, at some point in the future the NG and renewable energy costs will cross each other, shifting renewable energy to also become advantageous for economic reasons


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