Possible extension of the business model for fuel cells

Possible extension of the business model

for fuel cells

Justification for potential subsidies for the installion of fuel cells from the cost accounting

perspective

SUBTASK 3 REPORT

Author: Ing. Mag. Alfred Schuch

DI Dr. Günter R. Simader

Client: FFG

BMVIT

Date: Vienna, July 2019

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Abstract

Annex 33 is an application type annex with the objective to better understand how stationary fuel

cell systems may be deployed in energy systems. The possibilities to enter the market in niche and

broad applications are investigated. One of the major tasks in the current Annex 33 is to investigate

market possibilities for residential stationary fuel cells, if and where there is a competitive viable

market for such fuel cells – so where fuel cells have advantages over competing technologies.

Another major task is to investigate the consequences, and especially the opportunities, for fuel cells

caused by the relevant EU-Directives.

So far the business model for fuel cells rests on the savings resulting from the electricity generated

by fuel cells, since the electricity generated by fuel cells does not need to be transported to the

households, hence the tariffs for the usage of the electricity infrastructure do not have to be paid for.

Mostly the usual savings resulting from the operation of fuel cells do not easily pay off the required

investment difference in comparison to a natural gas boiler in Europe – even if including subsidies, if

any. Thus the installation of fuel cells does not happen often in Europe. Therefore other – if

any - benefits have to be monetized, if not available in terms of money already, and turned into

justified subsidies or lower tariffs for the usage of the relevant infrastructure by fuel cells.

The economical analyses in this report are based on the following components:

Savings resulting from the avoided electricity grid usage costs for the amount of electricity

generated by fuel cells and consumed in the household

Feed-in tariffs for the excess electricity

Savings resulting from the installation of fuel cells on the gas grid capacities and the security

of electricity supply impacts – opportunity costs otherwise required for the investment of a

gas fired power plant

Savings in terms of lower gas storage withdrawal rates

Savings resulting from lower investment needs for the replacement and/or extension of the

existing electricity grid (not taken into consideration)


existing district heating system (not taken into consideration; currently unknown)

Revenues from selling energy efficiency measures (not considered; currently unknown).

The results of the analyses regarding the extension of the so far „usual“ business model indicate that

a natural gas „fired“ fuel cell is allowed to be roughly > 9,900 Euro more expensive than the

installation of a natural gas fuelled condensing boiler without a buffer tank and roughly > 5,000 Euro

more expensive than the installation of a natural gas fuelled condensing boiler with a buffer tank.

These figures are deviated by cross sector impacts (electricity and natural gas sector) generated by

the deployment of fuel cells, based on cost accounting principles.

Contents

1 INTRODUCTION 5

2 PRODUCTION COSTS OF SYN-GAS 6 2.1 Determining factors for the generation costs of syn-gas and the impact of energy efficiency 6

2.2 Production costs of syn-gas in concrete terms 10

2.3 Hydrogen or syn-methane path? 18

3 ENABLING THE DEPLOYMENT OF FUEL CELLS IN THE SPACE HEATING SECTOR 23

3.1 Production costs of fuel cells 23

3.2 Knock-on financing 25

3.2.1 Justification for the subsidies from the cost accounting perspective 26

3.2.2 Impacts on GHG-emission and thereto linked potential revenues 28

3.2.3 So far applied business modell for fuel cells in the space heating sector 29

3.2.4 Justified extension of the business modell 30

3.2.5 Competent institution to deal with the extended business modell 30

3.3 Calculations regarding knock-on financing 31

3.3.1 Outcome of the study „Der Wert der Gasinfrastruktur für die Energiewende in Deutschland“ 31

3.3.2 Deployment of the results taking the installations of fuel cells into account 32

3.3.3 Economical justification for fuel cell installations and preliminary estimations 33

3.3.4 Financing of the required studies 35

4 SUMMARY 36

5 LITERATURE 41

6 ABBREVIATIONS 43

7 LIST OF DRAWINGS 45

8 LIST OF TABLES 47

INTRODUCTION

Possible extension of the business modell for fuel cells

5

1 Introduction

In order to achieve the ambitious Paris climate goals, a bundle of coordinated measures will be

needed. It will be necessary to improve energy efficiency, increase the share of RES, reasonably

electrify sectors, reduce CO2-intensive fossil fuels, namely oil and coal, and apply natural gas as

bridging technology.

The more ambitious the GHG-reduction-goals are, the more synthetic gas fuels, produced by Power-

to-Gas (PtG) and synthetic liquid fuels, produced by Power-to-Liquid (PtL) plants, will be needed to

achieve the goals in the industrial, transportation and space heating sector – besides the power

sector – as well. Regarding the transportation sector, one has to consider the passenger vehicles,

heavy and light duty traffic, aviation and the navy sector where BEVs cannot be deployed in a

reasonable manner – taking the specific costs into account.

The most substantial reason for P2G syn-gas and PtL syn-liquids is the fact that there is not sufficient

biomass available to replace all of the deployed fossil fuels in combustion processes. In other words,

coal, oil and natural gas cannot be replaced by biomass, biogas and biofuels to the full extent.

According to INFRAS, biofuels (2nd generation) in the transportation sector have a global potential

between 13 – 19 Exajoule whereas the global demand will amount to 100 – 170 Exajoule in 2020. The

mentioned potential takes already the competition between the food and fuel sector regarding

available area into account.

Having said this, syn-fuels, intended to replace fossil fuels in internal combustion engines respec-

tively in space heating applications, have to be generated by using RES-electricity. By following this

approach, CO2-neutrality will be given. The most important gas will be hydrogen (H2) either to be

applied directly or deployed as input for the methanation process or for liquid syn-fuels. Whether the

role of syn-methane and syn-fuels will be a prominent one, will depend on the costs for producing

syn-methane and syn-fuels and on how much CO2 will be emitted by doing so.

The technological progress indicates the potential for production of huge amounts of syn-methane

and syn-fuels at reasonable costs. Subsequently these commodities would become part of the

solution. This is even more true because the application of syn-methane and syn-fuels – generated by

RES – does not require huge investments since the relevant infrastructure is already in place. In

addition, these fuels do have a very high energy density and can easily be stored.

On the other hand, it is clear that – in comparison to the direct application of electricity – the

outcome is not very energy efficient (energy content of the syn-fuels divided by the electricity input).

In this sense it becomes clear that the generation costs of P2G and PtL will always be higher than the

direct application of electricity. In addition there will be a significant higher demand for electricity,

hence a high demand for land for the instalment of wind mills and PVs. In case – which seems to be

realistic – not the entire amount of RES can be generated in the country where P2G- and PtL-

products are required – there will be a need for import of such products. The therefore needed

logistic chains are well-proven and the costs are similar to the costs of transportation of natural gas

(LNG) respectively refinery products.

POSSIBLE EXTENSION OF THE BUSINESS MODEL FOR FUEL CELLS

6

2 Production costs of syn-gas

The generation costs of P2G and PtL will be – besides the degree of energy efficiency achieved in

varying processes – key for the market penetration of hydrogen respectively syn-methane and syn-

fuels.

2.1 Determining factors for the generation costs of syn-gas and the impact of energy efficiency

The more transformation processes are required, either power to hydrogen – which needs one

transformation process – or power to methane, which needs two transformation processes, the

lower the energy efficiency will be. Subsequently the investment needs will increase and the thereto

related OPEX will rise as well. The investments and the OPEX will even more increase if there is a

need for a buffer for hydrogen (in order to be able to operate the methanation process at a flat

workload, thus increasing the lifetime of the thermically stressed equipment) and a need for com-

pression equipment of the syn-methane and or hydrogen. The energy efficiency range is between

0.24 – 0.84, depending on the transformation processes, compression needs etc.1)

For these reasons, the costs per energy unit of syn-methane and syn-fuels, will always be higher than

the costs for direct application of electricity. The demand for electricity – generated by RES – will

increase, hence the demand for land – necessary for the installation of wind mills and PVs – will go

along with the demand for additional electricity. Having said this, it is very likely that some parts of

the additionally needed RES-generated electricity will have to be imported, because either it would

be too costly to be generated in Europe or because of the lack of land which could be reasonably

used for the RES-plants. In Drawing 1 one can see the degree of efficiency of BEVs, FCEVs and ICEs.

1 FENES et al. (2015): Bedeutung und Notwendigkeit von Windgas für die Energiewende in Deutschland

PRODUCTION COSTS OF SYN-GAS


7

Drawing 1: Energy efficiency of BEVs, FCEVs, and ICEs; Source: acatech et.al: „Sektorkoppelung“ – Optionen für die nächste Phase der Energiewende, November 2017, P. 31

Although Drawing 1 is suggesting that there is a clear advantage given for BEVs – in particular in com-

parison to ICEs and also to FCVs – all of them using fuels generated by the application of electricity

generated by RES, one has to take into consideration the:

Lifetime expectations of batteries in comparison with ICEs and thereto related additional

investment needs for a spare battery (after 8 to 10 years)

Waste management concept for discarded batteries, thereto related costs and thereby

caused environmental and social impacts – if any

Charging time of BEVs and – hence out of it deduced – a potential decrease of energy

efficiency (super chargers might need a cooling system in order to enable short charging

durations, subsequently energy efficiency will be significantly lowered)

Almost no availability of chargers for street parking

Capacity needs for electricity grids when charging takes place in intensively used time slots,

like on days before school holidays start.


8

In Drawing 2 the degrees of efficiency are indicated for different heating systems.

Drawing 2: Energy efficiency of heat Pumps, heat FCs, and heat condensing boilers

HEAT PUMP

RES -electricity

100%

Total efficiency

285% (= 95%*300% seasonal performance

factor)

HEAT

FUEL CELL

RES -electricity

100%

Hydrogen 67% (=95%*70%)

HEAT 24%

ELECTRICITY 21%

Total efficiency 45% (=24%+21%)

HEAT CONDENSING BOILER (GAS)

RES -electricity

100%

Hydrogen 67% (=95%*70%)

METHANE

53%

Total efficiency 50%



9

At first glance there seems to be a clear preference for heat pumps when it comes to the decision for

a heating system. If taking deeper analysis into account one is faced with hurdles like:

How to install heat pumps in urban areas

How to insulate highly decorative old buildings in order to be able to heat the space with

supply temperatures in the range of 40 to 45°C – generated by heat pumps – instead of the

so far needed 90°C supply temperature

How to install hot water supply tanks (buffers) in old, small apartments

How to store the additional electricity (generated via RES) needed for the operation of the

heat pump when the wind is not blowing and the sun is not shining – in particular in winter

times.

Since process heat in the industry sector is mainly (60%) required at temperature levels which are

above 200°C, heat pumps are not able to match these requirements.

As indicated in Drawing 1 and Drawing 2 and extended by additional facts to be taken into account, it

becomes clear that there is no „one size fits all“-approach possible. There is a need for more detailed

analyses – which are concentrated in Table 1.

Table 1 illustrates the prioritisation of decarbonisation options – depending on the sector and the application2.

Decarbonisation options

Direct electricity application first

Deployment of syn-methane and syn-fuels as supplement

Hydrogen P2G and PtL

Transport sector Trains, coaches and trucks (short distance haulage), trolley buses, passenger vehicles, two-wheelers, inland water vessel (depen-ding on the application)

Long distance haulage (trucks, coaches inland water vessel (depending on the application)

Aviation, international shipping, long dis-tance coaches, trucks and inland water vessel (depending on the application)

Heat Low temperature heating systems with heat pumps if the buildings are sufficiently insulated

Fuel cell-CHPs in exis-ting buildings with signi-ficant insulation restric-tions

Existing building stock with significant insula-tion restrictions and hybrid heating sys-tems with supporting boiler

High temperature process heat with direct electric hea-ting (resistance heater, plasma, etc.)

High temperature process heat for appli-cations which are diffi-cult to be electrified

High temperature process heat for appli-cations which are difficult to be electrified

Industry Production of ammonia, direct reduction process to produce steel

CO2-source for organic chemical raw material

2 Source: Frontier economics: Die zukünftigen Kosten strombasierter synthetischer Brennstoffe, P. 15


10

Electricity Short term storage Long term storage and re-electrification via gas turbines and hydrogen internal combustion engines

Long term storage and re-electrification via gas turbines

Service sector, commerce and trade

Stationary and partially mobile application (farming sector, logistics construction sector)

Mobile application (farming sector, logistics construction sector and army)

Mobile application (farming sector, logis-tics construction sector and army)

Table 1: Prioritisation of decarbonisation options – depending on the sector and the application. Source: Agora

Verkehrswende, Agora Energiewende und Frontier Economics (2018): Die zukünftigen Kosten strombasierter

synthetischer Brennstoffe, P. 15

Due to relatively high investment needs, P2G and PtL need a high work load in order being able to

allocate capital costs to a relatively high number of cost bearing units, hence lowering the total costs

per generated syn-methane respectively syn-fuel unit, thus increasing competitiveness of syn-

methane and syn-fuel in comparison to natural gas respectively gasoline and diesel. The number of

full load hours has to be above ≈ 4,000 hours per annum. In addition there is a need for relatively

competitive electricity prices, since it is mainly the commodity electricity which represents the main

variable costs. Taking a total efficiency of 50% (production of hydrogen via PEM electrolyser plus the

subsequent methanation process) as a basis, one can say that the production costs of syn-methane

will amount to at least double the price level of electricity. In case of a SOFC – once available and

commercially viable – the costs of electricity might not double since the energy efficiency is expected

to be significantly higher (> 80%) in comparison to a PEM electrolyser, but still will be relatively high.

2.2 Production costs of syn-gas in concrete terms

One is often confronted with the argument that so called excess electricity – the generated electricity

exceeds the demand for electricity – will amount to very high energy units, thus will become very

cheap and subsequently syn-methane respectively syn-fuels will be available at reasonable costs,

hence can compete with natural gas respectively fossil fuels.

It is true that there will be lack of capacity in the grid to transport the electricity to the place where it

is needed – even in an ideal environment (often cited as copperplate), hence there will be, during

some hours, excess electricity available in certain regions or locally. But basically there will not be

excess electricity available for a high number of hours per year – as long as there will be no legal

provisions in place which require a very high coverage of the electricity consumption (> 80% or even

more – depending on the region and the composition of the generation portfolio) generated by RES.

In such a case there will be a need for curtailment of the generation of electricity even if the wind is

blowing and or the sun is shining. Thus the marginal costs of electricity will converge towards zero.

Nevertheless, if RES-electricity is intended to be used for the decarbonisation of the transportation

and heat sector as well, there is a need for the generation of additional RES-electricity otherwise it

will be „just“ a shift from one sector to another. For the achievement of the Paris-Climate-goals all

sectors have to be decarbonized.



11

The costs´ components for the supply of hydrogen (costs generated by each required step in the pro-

cess) – based on different sources – are illustrated in Drawing 4. The share of the required steps of

the total costs are illustrated in Drawing 5.

A comparison of the supply cost of hydrogen in Japan – based on different sources/studies – can be

found in Drawing 6.

The column „Own results“ (project in Patagonia) is based on the following assumptions respectively

calculations:

H2-production of 8.8 Mt/a in Patagonia (use of wind energy)

Domestic transport via pipeline (4,500 km)

Liquefaction and storage in domestic harbour (Capacity: 113,600 tons per annum)

International transport via ship (Punta Arenas to Yokohama: 17,712 km).

The basic outline for the hydrogen production in Patagonia can be found in Drawing 3.

Drawing 3: Outline of the wind park project in Patagonia. Source: Krieg, D. (2012): Konzept und Kosten eines Pipelinesystems zur Versorgung des deutschen Straßenverkehrs mit Wasserstoff. RWTH Aachen University cited in Stolten, D.: Potential Hydrogen Production in Patagonia – A System Analysis


12

Drawing 4: Components of the supply cost of hydrogen – produced in Patagonia – in Japan. Source : Stolten, D., Potential Hydrogen Production in Patagonia – A System Analysis

Drawing 5: Share of the components of the supply cost of hydrogen in Japan. Source : Stolten, D.,: Potential Hydrogen Production in Patagonia – A System Analysis



13

Drawing 6: Trend of the expected/forecasted costs for syn-methane respectively syn-fuels over time – taking the different generation options into account. Source:

Drolet et al.: The Euro-Quebec-Hydro-Hydorgen Pilot Project.

Kamiya et al. Study on Introduction of CO2 Free Energy to Japan with Liquid Hydrogen

Teichmann et al.: Liquid Organic Hydrogen Carriers as an efficient vector for the transport and storage of renewable energy , 2012

Watanabe et. al: Cost Estimation of Transported Hydrogen, Produced by Overseas Wind Power Generation, 2010

Tokyo Commodity Exchange (2017). Gasoline price. URL: http://www.tocom.or.jp/index.html all cited in: Stolten, D.,: Potential Hydrogen Production in Patagonia – A System Analysis

http://www.tocom.or.jp/index.html


14

Drawing 7: Production costs of syn-methane and hydrogen over time (2022 to 2050) in different regions. Source: Agora Verkehrswende, Agora Energiewende und Frontier Economics (2018): Die zukünftigen Kosten

strombasierter synthetischer Brennstoffe


15

Drawing 8: Production costs of syn-methane and hydrogen over time (2022 to 2050) in North Africa. Source: Agora Verkehrswende, Agora Energiewende und Frontier Economics (2018): Die zukünftigen Kosten

strombasierter synthetischer Brennstoffe


16

Scenario on Hydrogen Basic Strategy

Drawing 9:Scenario on Hydrogen Basic Strategy. Source: NEDO, Ohira E.: Japanese Fuel Cell Success Stories, IEA Outreach Meeting, Austria/Linz, 6th November 2018, S. 5


17

One can see that there is a significant cost decrease to be expected when it comes to the production

of syn-methane, syn-fuels and of hydrogen. Hydrogen – at costs of roughly 5 €-Cent/kWh in 2050 –

can easily compete with gasoline – at today’s costs of roughly 4,4 €Cent/kWh if taking the energy

efficiency of hydrogen fuel cells cars (26%) in comparison to ICEs (13%) into account. Whether a cost

increase of gasoline is to be expected in a decreasing demand market and at the same time

extraction technology – so higher productivity - is doubtful, hence the price for gasoline will very

likely not increase as indicated in Drawing 7 but probably remain somewhere around the current

price level (in real terms).

Drawing 10 depicts the relationship of capital cost (electrolyser cost) and electricity price on the cost

of produced hydrogen assuming a 25 year lifetime, 80% capacity factor, 65% operating efficiency, 2-

year construction time and straight line depreciation over 10 years with $ 0 salvage value using solar

energy.

Drawing 10: Relationship of capital cost (electrolyser cost) and electricity price on the cost of production of hydrogen. Source: Shaner M.R., Atwater H.A., Lewis N.S., McFarland E.W.: A comparative techno-economic analysis of renewable hydrogen production using solar energy, Energy Environ. Sci. 9,2354-2371 (2016). Doi: 10.1039/C5EE02573G

Drawing 11 describes the link between fixed capital versus variable operating costs of new genera-

tion resources in the US (the data has to be adapted to EU or other countries/regions circumstances)

with shaded ranges of regional and tax credit variations and contours of total levelized cost of

electricity, assuming average capacity factors and equipment lifetimes. . It is apparent that the

variable costs of energy are $ 0 or close to $ 0 for wind and solar plants, subsequently the fixed costs

of energy determine the total levelized costs of electricity.

The very low or close to zero variable costs are the major advantage of solar and wind power in com-

parison to the total levelized costs of electricity generated by bio-power. The fixed costs of wind and

solar power plants will decrease faster than the fixed costs of bio-power (if the fixed costs of bio-

power will decrease at all) since, in particular PV, is still a young technology.


18

Drawing 11: EIA, „Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2018 (2018): www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf.

2.3 Hydrogen or syn-methane path?

Taking the production cost difference between syn-methane respectively syn-fuels and hydrogen as

given, this gives rise to the question whether to focus on the hydrogen or the syn-methane/syn-fuel-

approach. The syn-methane/syn-fuel road would enable the usage of an existing infrastructure –

namely gas grids, gas storage facilities, gas boilers, gasoline refuelling stations etc. – thus needs

significantly lower investments. Whereas the hydrogen path would require high investment needs

for the build-up of the required infrastructure. These commonly used arguments are valid to a

certain part only since:

The gas infrastructure has to be renewed once the technical lifetime of the grid has been

exceeded. At natural gas transmission grid level and at regional distribution level the techni-

cal lifetime expectations are higher than the lifetime expectation at „city“-distribution grid

level because of the different pipeline materials used (synthetic material at distribution grid

level and steel at transmission and regional distribution grid level). Having said this, parts of

mainly distribution grids have to be renewed more or less constantly and therefore these

parts could be constructed by using pipeline material which is resistant to hydrogen.

The gas pipelines at transmission and regional distribution level should be analysed regarding

the potential to reline existing natural gas pipelines using a material which can cope with the

characteristics of hydrogen. In such a case valve accessories and compressors have to be

replaced. Since such kind of equipment (moving parts) has a much shorter technical lifetime

expectation than pipelines, the replacement can be coordinated in a manner which

decreases the investment needs as reasonably as possible. Of course the energy density of

energy sources for transportation has to be taken into account.

http://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf


19

Drawing 12: Davis et al., Science 360, eaas9793 (2018): The energy density of energy sources for transportation including hydrocarbons and lithium-ion batteries, p.5

Taking the given energy density as well as the pressure restrictions of the existing gas infrastructure

(transmission grid) and the velocity restrictions of the transported gas quality into consideration, the

transportation capacity decreases as depicted in Drawing 13: Link between transportation capacity

and the injected volume of hydrogen into the natural gas grid – all else ceteris paribus.

Drawing 13: Change of transportation capacity as a function of the volume of hydrogen injected into the natural gas grid , Gas Connect Austria, Paulnsteiner R.: H2-Einspeisung: Anforderungen an Rohrleitungsnetze, Harmonisierungsanforderungen, National Workshop HyLAW, Linz, 6th November 2018, S. 10


20

Taking the required energy demand and the varying energy density into account, it becomes obvious

that the transportation capacity of the given natural gas grid infrastructure will not be sufficient to

cope with the demand. Consequently there will be a need for additional investments into hydrogen

pipelines in order to match the energy demand per time unit.

Having said this, one could start with the following process:

Inject hydrogen into the gas grids to an extent which is, from the technical point of view,

acceptable (approx. 10-15%); the Wobbe-index has to be taken into consideration – which

means that it is very likely that the nozzles of gas burners and gas turbines have to be

replaced, thus investments and the thereto related OPEX will be generated by doing so.

Drawing 14 depicts the link between calorific value (= Brennwert on the y-axis) and the

Wobbe-index (x –axis) in line with the requirements of the relevant Austrian standard ÖVGW

G31. One can see that an injection volume of more than 5% (roughly) changes the Wobbe-

index at a magnitude which requires the replacement of the nozzles in order to match the

gas quality.

Link between calorific value and Wobbe-index for gas in line with the Austrian standard ÖVGW G31

Drawing 14: Link between calorific value and Wobbe-index, Gas Connect Austria, Paulnsteiner R.: H2-Einspei-sung: Anforderungen an Rohrleitungsnetze, Harmonisierungsanforderungen, NationalWorkshop HyLAW, Linz, 6th November 2018, S. 7


21

Once this threshold has been achieved – or even earlier – one has to replace parts of the city

grid with material which is resistent to hydrogen by 100%. So in such areas 100% hydrogen

would be injected and used. When replacing material the location of electrolysers has to be

taken into consideration otherwise the transport of hydrogen to such separated areas might

be too costly or even impossible. Following strictly such a determined roadmap – based on

the political framework and thereto related decisions – would lead, at a certain point in time,

to a replacement of natural gas and therefore to a hydrogen based society. The length of the

required period of time should be ambitious but not too ambitious, otherwise voters might

get „lost“ and thus might not follow the determined steps.

The described process should start once hydrogen has been established as fuel with a relatively high share in the transportation sector: in particular in the non-public sector like the deployment of MHVs (Material Handling Vehicles like forklifts, class 1-3) or regional trains, local buses and HDV& LDV (heavy and light duty vehicles). The reason for this is that hydrogen demand in the non-public sector is

based on a commercial area

depending on logistic space

depending on freight intensity

predictable.

Subsequently the investments for non-public HRS (hydrogen refuelling station) can be tailored to

demand (upfront cost will be significantly lower in comparison to public HRS), thus the hydrogen

supply chain cost can compete with the supply chain cost of gasoline/diesel – taking the much higher

efficiency of fuel cells in comparison to ICEs (internal combustion engines) and the current taxing

rules into account. The major preconditions for the deployment of hydrogen fuelled vehicles instead

of BEVs (battery electric vehicle) is the need for

a high utilisation rate

fast fueling

a long range

a high power capacity.

Besides, the lifetime of FCEV (fuel cell electric vehicles) is usually shorter than the lifetime of heating

devices, hence switching from gasoline/diesel to hydrogen as fuel might happen quicker – in

particular if there is a federal support in place (subsidies or tax saving incentives, etc.) So in order to

efficiently and quickly establish a hydrogen „mass“ market, it seems to be logical to start with the

application of hydrogen in the transportation sector and further on to extend to the public HRS-

sector and later on to the space heating sector. By doing so the space heating sector could reap the

benefits of economies of scale, size and scope, generated by the transportation sector from the

beginning. Hence the market uptake of hydrogen operated fuel cells in the space heating sector

could be easier achieved.


22

In the meantime fuel cells operated with natural gas should be applied in order to:

achieve quick wins regarding reduction of GHG-emissions in comparison to oil fuelled

space heaters and even electricity heaters (direct application of electricity for space hea-

ting) as long as the consumed electricity is generated by coal or gas. The reason for this is

the high CHP-coefficient of fuel cells – operated with natural gas – thus the GHG-

emissions would decrease in comparison to the emissions of centralized gas- and coal

fired CHPs

locally generate electricity thereby lower the capacity needs of electrical high and low

voltage lines, subsequently postpone eventually needed upgradings of existing electricity

grids and or lower the capacity needs of transmission and distribution electricity grids for

new lines, hence decrease investment needs for new and or replacement lines

lower the production costs of fuel cells

gain experience in the operation of fuel cells (get acquainted to the handling of fuel

cells).

ENABLING THE DEPLOYMENT OF FUEL CELLS IN THE SPACE HEATING SECTOR

23

3 Enabling the deployment of fuel cells in the space heating sector

In order to be able to follow the path described in 2.3, a clear political commitment is required which

would encourage potential investors and provide them a sound framework for the calculation of the

rate of returns for their investments. Having said this, the question arises how to finance such an

approach – in particular if taking into account that fuel cells are still relatively expensive – although in

Japan a more or less reasonable price has been achieved in the meantime and costs are expected to

further decline in the future.

3.1 Production costs of fuel cells

Above all there is a need to decrease significantly the amount of investments for the installation

(plug and play) of fuel cells in Europe. There are several levers to achieve this „main“ goal. First of all

it has to be checked how production processes – which are based on the valid European thereto

related standards – can become more efficient, thus cheaper per unit. In order to achieve the

benefits of economies of scale to the full extent, much more units have to be produced but this is

hindered by high production costs – a typical chicken and egg-issue. It has to be checked whether the

requirements – determined by European standards – can be decreased, of course without lowering

the operational safety. On top it has to be assessed whether a higher vertical integration of the

installation process of such devices could lower the plug and play installation costs.

Drawing 15 depicts the fuel cell development in terms of installed units (PEFC/SOFC) and selling

prices for PEFCs/SOFCs in Japan within the „Ene-Farm“-programme.

Drawing 15: NEDO, Ohira E.: Japanese Fuel Cell Success Stories, IEA Outreach Meeting, Austria/Linz, 6th November 2018, p. 5

250,000 unit = 175MW

Residential Fuel Cell “Ene-Farm”

micro-CHP providing 0.7kW power + hot water / total efficiency : >90%


24

Drawing 16 illustrates how an adapted regulation can help lowering the installation costs. Of course

there is a need to adapt to the European circumstances (in Japan the stationary fuel cells are instal-

led outside the house, thus some easements regarding safety provisions are given) but a harmoni-

sation of standards and legal provision as well as abolishment of administrative hurdles might be

helpful.


Another important source for cost reduction is – as indicated in Drawing 17 – given in the develop-

ment of common specification of the BoP (Balance of Plant) components like pump, invertor, sensor

etc.


Before: Based on Industry uses

Need a license as a chief engineer

Required to install N2 Gas system

Safety distance: 3m

Establish safety regulations

After: As Electric Appliance

No Need!

11%

17%

5%

47%

8% 12%

ReformerFuel Cell SystemInvertorBOPAssembly

Developed common-specification of BoP(OEM opened their own technical information)

Opened to public the specification, and called for developer(NEDO provided subsidy for R&D)

40 developer joined the program and ucceeded 75% costreduction of BoP (Pomp, Brower, Invertor, sensor, etc)


25

3.2 Knock-on financing

Subsidies might be required for the market uptake of fuel cells. At the beginning of the market

implementation process the allocation of subsidies should focus on fuel cells operated with natural

gas.

Drawing 18 illustrates the current subsidy scheme for fuel cells in Germany. The current total

installation investment amounts to € 25 000 – 35 000 for a „plug and play“ installation. A service

contract is a precondition for the eligibility of the subsidies.

Drawing 18: Birnbaum U.K.: Small stationary Fuel Cells for house energy supply and Power Generation in general. Source: https://www.eon.de/de/pk/waerme/brennstoffzellen- heizung.html?subid=at104846_a142608_ m4_p5816_t3_cDE&ref=60806-at104846_a142608_m4_p5816_t3_cDE&affmt=0&affmn=0 Translated by K.U. Birnbaum, presented in Augsburg 24th October 2018, p. 5

Drawing 19 illustrates the investment ranges of competing technologies in Germany.

Drawing 19: Birnbaum U.K.: Small stationary Fuel Cells for house energy supply and Power Generation in

general. Source: https://www.kesselheld.de/heizungsvergleich/ - called by Birnbaum U.K. on 22.10.2018.

https://www.kesselheld.de/heizungsvergleich/


26

3.2.1 Justification for the subsidies from the cost accounting perspective

Since – on the contrary to fluctuating RES – fuel cells could lower the investment needs (replacement

or extension respectively green field investment) for electricity grids, one should analyse the future

investment needs with and without the deployment of fuel cells. The difference in investment needs

could be transposed/converted into subsidies for fuel cell installments. Of course it has to be taken

into account that the interests of the electricity grid operators could (very likely) be diametrically

opposed to the interests of gas grid operators and or the public interests since electricity grid

operators would like to have high investment values in order to receive a high profit (in absolute

terms; in relative terms the profit will be the same) and in order to increase the security of supply

status from the electricity grid reliability perspective. One can see that there is a strong need to have

a look to the proposed approach from the sector coupling-perspective. So again, there is a need for a

transparent roadmap which clearly determines the time span and the steps to be done therein –

based on a strong commitment by politicians.

From the gas grids perspective one can figure out advantages as well. Fuel cells have to be operated

at or close to a „flat mode“ thus consume relatively constantly natural gas (later on hydrogen)

although at small capacities. The flat operation mode of fuel cells requires buffer tanks for the

provision of warm water and for heating water anyway in order to be able to use the generated

electricity not being demanded/consumed at a certain point in time

heat not being demanded/consumed at a certain point in time

subsequently achieve high energy efficiencies of the operating device.

Drawing 20 and Drawing 21 illustrate the conceptual design of a stationary fuel cell.

Drawing 20: Conceptual design of a stationary fuel cell; Source: https://www.google.at/search?q=panasonic+fuel+cell+technology&source=lnms&tbm=isch&sa=X&ved=0ahUKEwiivZvF-O7dAhUppIsKHWTPCyYQ_AUIDigB&biw=1536&bih=755#imgrc=TFpOGMbwNPnxSM:

https://www.google.at/search?q=panasonic+fuel+cell+technology&source=lnms&tbm=isch&sa=X&ved=0ahUKEwiivZvF-O7dAhUppIsKHWTPCyYQ_AUIDigB&biw=1536&bih=755#imgrc=TFpOGMbwNPnxSM



27

Drawing 21: Conceptual design of a stationary fuel cell; Source:

https://www.google.at/search?q=fuel+cell+household&source=lnms&tbm=isch&sa=X&ved=0ahUKEwiMjc

OE8u7dAhUcwAIHHQJsC7sQ_AUIDigB&biw=1536&bih=755#imgdii=ghMKKL3hNegBMM:&imgrc=oDZ3B-

nw2AXnxM:

Since peak demands will be coped with by heat condensing boilers –as extension of the fuel cell

respectively buffer tanks – these heat condensing boilers could require a lower capacity – in

comparison to nowadays devices. Hence the total capacity needs for natural gas as fuel for the

fuel cells plus the peak capacity needed for the natural gas fuelling of the heat condensing boilers

could be less than the current capacity needs required by usual heat condensing boilers with

higher natural gas capacity requirements. Since it is forecasted that the gas consumption will

decrease over time, on the other hand the capacity needs for industry might remain the same

and for gas fired power plants (as stand-by facilities) the capacity needs will very likely increase.

The capacity for the transport of natural gas saved by the application of fuel cells in combination

with peak heat condensing boilers could be used – without extensions of the existing gas grids –

for the increased demand for capacity needed by (natural) gas fired power plants in future. In

other words, the capacity of the existing gas grids might be eventually sufficient for the increased

capacity (not volumes) needs of future gas fired power plants. If the capacity needs for the trans-

portation of natural gas were not sufficient, the investment needs for extensions or replacement

requirements were lower in comparison to the situation without the application of natural gas

„fired“ fuel cells. In other words, the savings from the reduction of the capacity needs could be

expressed in terms of money and used to subsidise fuel cells.

Regarding gas storage facilities one can assume that the need to store the commodity natural gas

in terms of volume will decrease. On the other hand the demand for a high withdrawal rate will

very likely increase –similar to the transportation capacity demand in the gas grids.

Because of the relatively flat operation mode of fuel cells, subsequently a steady demand for

natural gas – later on hydrogen – could be included in the Annual Contracting Quantity (ACQ) in

long term take or pay contracts – hence in the long term ship or pay contracts for trunk lines as

well.

https://www.google.at/search?q=fuel+cell+household&source=lnms&tbm=isch&sa=X&ved=0ahUKEwiMjcOE8u7dAhUcwAIHHQJsC7sQ_AUIDigB&biw=1536&bih=755#imgdii=ghMKKL3hNegBMM:&imgrc=oDZ3B-nw2AXnxM




28

Having said this, there is a lower demand – in comparison to the status without the deployment of

fuel cells – for gas storage facilities in terms of withdrawal rates.3) Nevertheless, the lower demand

can be expressed as opportunity costs which can be used to subsidise the deployment of fuel cells. It

is very likely that the gas storage operators will oppose this approach – in particular if taking the

already difficult economic situation of gas storage facility operators into account – at least from the

short- and midterm point of view. In the long run there will be a need for higher withdrawal rates if

taking

the increased peak demand for electricity and

the lower energy density of the natural gas/hydrogen mixture and later on pure

hydrogen (gaseous state)

into account.

Of course the demand for transportation capacity to the gas storage facility – and the other way

round - will decrease as well – which can be expressed in terms of opportunity costs.

Regarding cross sector coupling, there will not only be an impact on the natural gas and electricity

infrastructure, but impacts on district heating systems can be expected as well. There might be an

impact on the replacement or extension of the grid-investments. At which magnitude these invest-

ments could pop up, depends on the size of the district heating system, the share of buildings

connected to the district heating system, the base load of the district heating system, the demand

profile, the extension plans, age of the infrastructure, etc. Hence there is a need for further analysis

which could result in estimated investment savings.

3.2.2 Impacts on GHG-emission and thereto linked potential revenues

From the GHG-point of view one can say that peak heat condensing boilers with lower peak capacity

needs – in comparison with current devices – could be operated at higher work loads (on average)

thus be operated in a more efficient range, subsequently generate less GHG-emissions. Usually the

peak capacity of heat (condensing) boilers is determined by the needs for warm water provision

(based on the patience of consumers when filling for example a bathtub or a washbasin – so the

required time to fill up the bathtub, etc.). If a buffer tank is installed for warm water and heating

water – the „standard“ configuration of a fuel cell installation – a peak heat condensing boiler can be

operated at a high work load, thus the efficiency would be relatively high. The question is the size of

the peak condensing boiler. The higher the peak capacity the shorter the period of time at which the

peak condensing boiler can be operated at full load – hence at best efficiency mode.

Although modern heat condensing boilers are usually operated in a modulating mode, subsequently

the efficiency of such devices is relatively high, it is still the case that if heat condensing boilers are

operated at low workloads, their efficiency significantly decreases, subsequently the GHG-emissions

increase. Having said this, a lower peak capacity of heat condensing boilers would lead to longer full

load work hours, hence an increased operating energy efficiency. Because of the existing buffer

3 For gas storage facilities which use depleted oil- and gasfields as storage volume, it is the injection or withdrawal rate

which usually determines the investment amount whereas if salt caverns are used to store gas, it is the volume to be stored which determines the investment needs.


29

tanks, the combination of the peak condensing boiler wih lower than usual capacity plus the buffer

tank for warm water could satisfy the requirements regarding length of the filling-up time of a bath-

tub or a washbasin, etc. This efficiency increase could be regarded as energy efficiency measure – set

by grid operators.

In order to achieve the required energy efficiency improvements, Austrian energy suppliers are

required by law to lower the energy consumption by a certain percentage from the previous year to

the next year at ceteris paribus conditions. The energy suppliers have the possibility to lower the

energy consumption in their company, at their customers or by purchasing so called energy efficiency

measures from suppliers of energy efficiency measures – traded on platforms – in order to achieve

the required targets. If the targets are not achieved in line with the energy efficiency improvement

requirements, relatively expensive compensation payments have to be made by the energy supplier.

Regarding cross sector coupling in terms of district heating it is reasonable to say that all suitable

waste heat generating plants in Austria have been connected to the district heating system already.

Subsequently additional heat is injected by using the waste heat of (gas fired) power plants. So

regardless whether it is a coal fired power plant or a gas fired power plant, the efficiency of such

CHPs is – because of the strongly fluctuating demand and the thereby decreased efficiency – lower

than the efficiency of fuel cells which are operated in a relatively flat mode. So if one assumes

800,000 installed fuel cell units in Austria with a capacity of 1 kW (heat) per unit, 800 MW are

installed. If the efficiency of fuel cells is „just“ 2% higher than the efficiency of power plants with a

waste heat recovery system, then a few hundred thousand tons of CO2 could be saved. The more

concrete amount of CO2 savings depends on the time during which the operation of the gas/coal

fired power plant is triggered by the heat demand instead of the electricity demand. The calculation

of such savings requires more analyses. The CO2 savings could be sold on trading platforms.

In this sense, the above mentioned energy efficiency measures, set by the grid operator, could be

sold, hence generate revenues which should be used to subsidise fuel cells.

Improved energy efficiency reduces GHG-emissions4) and the thereto related costs –representing

opportunity costs which could be used to subsidise the instalment of fuel cells.

The decisive question is how to combine the possibilities to finance the instalment of fuel cells and

which institution could be best suited to cope with this broad approach.

3.2.3 So far applied business model for fuel cells in the space heating sector

So far the business model for fuel cells exclusively rests on the savings resulting from the electricity

generated by the fuel cell, since the electricity generated by the fuel cells does not need to be

transported to the household, hence the tariffs for the usage of the electricity infrastructure for this

amount of electricity, including the thereto related taxes, like VAT, do not have to be paid for. Mostly

the usual savings resulting from the operation of the fuel cell do not easily pay off the required

4 According to NEDO, Eiji O.: Japanese Fuel Cell Success Stories, IEA Outreach Meeting, Austria/Linz, 6th

November 2018, p. 13. The CO2-reductions amount to roughly 1,2 tons per year.


30

investment difference in comparison to a natural gas boiler in Europe – even if including subsidies, if

any (the situation is different in Japan). Hence the instalment of fuel cells does not happen that often

in Europe – at least not yet. Therefore the other, above described benefits have to be monetized – if

not available in terms of money already – and turned into justified subsidies or lower tariffs for the

usage of the relevant infrastructure by fuel cells. Of course only proper incentives have to be taken

into consideration and undesirable ones have to be avoided.

For example, to lower the tariffs for the usage of the electricity infrastructure for the amount of the

electricity which has to be supplied via the public grids, could generate more demand for electricity,

subsequently increase the demand for the scarce electricity grid capacity. In other words, the oppo-

site of the desired effect could be induced.

3.2.4 Justified extension of the business model

Basically it should be the capacity (for electricity as well as for gas) demanded by the consumer,

which determines the costs for the consumers, since it is more or less the demanded capacity which

determines the investment needs for the electricity and natural gas infrastructure. Subsequently a

progressive shape of the tariffs to be paid for the use of the capacity of the electricity and natural gas

infrastructure should be implemented. Such a tariff structure would implicitely generate incentives

to lower the capacity needs, hence lower investment needs into the electricity and natural gas infra-

structure.

The other options to support the implementation of fuel cells – in addition to the so far deployed fuel

cells business model – are to

lower the tariffs for the usage of the existing natural gas infrastructure by fuel cells or

provide direct subsidies to the installation of fuel cells or a

combinations of favourable tariffs and direct subsidies.

As mentioned above, the installation of fuel cells would reduce the need for electricity infrastructure

extensions because

100% electrification (electrification of the space heating sector) and the thereby gene-

rated extension of the electricity grids could be avoided respectively reduced

the capacity for the transport of locally generated electricity by fuel cells can be avoi-

ded.

In sum the need for extensions of the eletricity grids could be (significantly) reduced, thus the

pressure on a scarce good (capacity of electricity grids) could be lowered. On the other hand the

existing gas infrastructure could be used in a relatively flat mode, hence extensions of the gas grids

could be avoided or at least reduced. Both impacts can be calculated in terms of opportunity costs.

3.2.5 Competent institution to deal with the extended business model

The basis for the cost determination or at least for the methodology for cost determination of elec-

tricity- and gas grids is a core competence of the regulatory authorities and defined in Directive


31

2009/72/EC, Article 37 („Electricity Directive“) and 2009/73/EC, Article 41 („Gas Directive“). The

same goes for the deviation of tariffs for the usage of the electricity and gas grids.

Since all revenues and costs incurred, insofar as such revenues and costs correspond to those of an

efficient network operator and are transparent, represent the basis for the cost determination and

subsequently tariff deviation, the revenues obtained by the sale of the energy efficiency measures

will be taken into account when determining the costs of the grid operation respectively the thereto

related tariffs.

At the time (2011) when the so called 3rd package (Electricity and Gas Directive) was put into effect,

the linkages between the electricity sector and the natural gas sector had not been analysed in

depth, thus the mutual impacts were not obvious at the level of detail as nowadays. Since the

advantages of the so called sector coupling become more and more obvious, the European

Commission is currently in the phase of developing a „big picture perspective“ to be taken into

consideration by the regulatory authorities. Having said this, the investment savings resulting from

one sector, having a positive impact on the other sector, could be easier taken into account, since in

previous cost determination processes – regardless whether for the gas or the electricity sector – the

separation was much more pronounced, hence it was much more difficult to take the mutual

impacts, in terms of money, into account. In particular, the different interests of the gas grid and

electricity grid operators have to be taken into consideration. To this effect, it was extremely

important to provide such inputs via the IEA and or the national regulators respectively via the

Agency for the Corporation of Energy Regulators (ACER) to the European Commission in due time. So

concrete legislative proposals for the successive relevant Directives have to be made, expressing the

provision that a cross sector cost and tariff determination – taking opportunity costs into account –

shall be applied by the regulatory authorities.

3.3 Calcination regarding knock-on financing

In order to assess the potential mutual impacts of the gas sector and the electricity sector one can

use/adapt the figures calculated/estimated in the study „Der Wert der Gasinfrastruktur für die

Energiewende in Deutschland“5.

3.3.1 Outcome of the study „Der Wert der Gasinfrastruktur für die Energiewende in Deutschland“

The study compares the costs of three scenarios, namely:

a. 100% electrification of the energy system in Germany –electricity is the only form of energy

carrier

b. electricity plus storage of syn-methane which itself is converted into electricity in regular

CHPs

c. electricity plus local deployment of syn-methane in the household, industry and power

sector.

5 Frontier Economics: Der Wert der Gasinfrastruktur für die Energiewende in Deutschland, September 2017


32

Based on analysis which indicates very high costs for the variant „100% electrification of the energy

system in Germany“, the authors shifted their focus to the two options dealing with syn-methane. It

turned out that the local deployment of syn-methane in the household and industry sector (scenario

c) generates – in comparison to the deployment of syn-methane for power generation only (scenario

b) – annual savings of 6.3 billion € (4.4 billion distribution and 1.9 billion transmission level). The

savings are due to the application of syn-methane burning devices instead of electrically driven heat

pumps. The deployment of fuel cells and the out of it resulting impacts have not been analysed yet.

3.3.2 Deployment of the results taking the installations of fuel cells into account

If one assumes that fuel cells are mainly applied in the household and SME-sector, one can figure out

at the first step the savings resulting from the space heating and warm water requirements and at

the second step for the electricity generated via fuel cells locally.

Although scenario c (see 3.3.1) requires more energy for space heating and warm water in total (519

TWh) in comparison to scenario b (510 TWh) in Germany, the demand for electricity decreases from

194 TWh (scenario b) sharply to 57 TWh (scenario c), thus the investment needs decrease as well.

The capacity needs in the electricity grids for the household and SME sector decrease by 80 GW

(assumption: annual full work load hours for the space heating sector are 1,700) – so roughly by 40%

referring to the household and SME space heating and warm water sector or by 20% referring to the

total capacity requirements for the transport of electricity demanded by the household, SME,

transportation and industry sector. The annual savings amount roughly to 1.3 to 1.7 billion Euro in

total in Germany.

Taking one tenth of these figures for Austria as a basis (rule of thumb) the annual savings would be at

around 130 to 170 million Euro – based on the (by 8 GW) decreased capacity needs for the electricity

grids supplying the space heating and warm water of the household and SME sector.

In addition, the avoided capacity demands, resulting from the locally generated (decentralized)

electricity via fuel cells, have to be taken into account. Assuming that in the very long run, 800,0006

households in Austria will be equipped with fuel cells with a peak electricity capacity of 1 kW per

unit, 0.8 GW do not need to be generated centrally, thus investments into CHPs (for the security of

electricity supply purposes) and into gas transmission and distribution grids will be reduced. Very

roughly speaking around 15 to 20 million Euro could be annually saved as opportunity costs for the

construction of a gas fired power plant. The quantification of savings regarding avoided investments

in the extension of the electricity transmission and distribution grids cannot be done at this stage

because of the missing – so far not accurately determined - national PV and wind programme which

6 In case stationary fuel cells are regarded as must run power plants, the amount of stationary fuel cell units were restricted

because being in competition with run-of-river-plants and PV-plants as well as with wind parks. All three of them with very low (close to zero or even zero) marginal costs. So in case the capacity sum of run-of-river-plants, PV plants, windparks and stationary fuel cells would exceed the base load, it is likely that the stationary fuel cells had to be turned off because of higher marginal costs than run-of-river-plants, PV-plants and wind parks. On the other hand the potentially positive security of electricity supply impact has to be taken into consideration as well. De facto investment (≈ 550 – 600 million Euro for a 800 MWel gas fired power plant) and out of it resulting costs for a gas fired power plant - needed in periods when the sun is not shining, the wind is not blowing and in periods of low tide - can be avoided.


33

very likely will be the determining factor for the electricity grid capacity, at least on a local and

regional level).

Taking the possibility to lower the peak capacity of condensing heat boilers from 22 kW to 15 kW for

around 800,000 units (a bit more than 50% of the households and SMEs which are currently supplied

with natural gas) a capacity of roughly 500,000 Nm3/h (current total peak capacity roughly 2.8

million Nm3/h in Austria) could be freed up in the relevant gas grids for the use by gas-fired CHPs.

This amounts to annual savings of roughly 10 to 15 million Euro in addition. So in Austria the

application of fuel cells could generate annual savings of roughly 155 to 205 million Euro which could

be used to promote the market penetration of fuel cells. As already mentioned, for preliminary

calculations regarding the economical justification for fuel cell installations, the savings regarding

avoided investments in the extension of the electricity transmission and distribution grids will not be

taken into consideration because of the so far not accurately determined national PV and wind

programme, subsequently savings of 25 – 35 millions € will be taken as a basis for the further steps.

It has to be emphasized that the mentioned estimates (very rough approach) can be realized to the full extent only, once the fuel cells have achieved the market penetration of roughly 800,000 units. In order to achieve such a high rate, pre-investments like:

subsidies (either feed-in tariff or installation subsidies)

tax advantages for the owner of a fuel cell, or

legal provisions

are required.

3.3.3 Economical justification for fuel cell installations and preliminary estimations

The economical justification for fuel cell installations is based on the following components:

Savings resulting from the avoided grid usage costs for the amount of electricity generated

by the fuel cells and consumed in the household (for a typical household with 2 persons) are

roughly 150 Euro per annum7); consumption ≈ 4 MWh per year

Feed-in tariffs for the excess electricity – depending on the spot price (for example) 45

Euro/MWh – 35 Euro/MWh natural gas = 12 Euro/MWh * ≈ 4 MWh ≈ 50 Euro per annum

Savings resulting from the installation of fuel cells (see above) of around 385 Euro per year (>

30 million Euro per year8)/80,000 units per year; in case of installing 80,000 units per year the

stock could be built up to 800,000 within 10 years)

Savings in terms of lower gas storage withdrawal rates of around 520 Euro per year (42

million Euro savings per year9)/80,000 units per year)

7 E-Control (Regulatory authority for electricity and gas in Austria - Tariff calculator: https://www.e-control.at/konsumenten/service-und-beratung/toolbox/tarifkalkulator, access: 25th February 2019. 8 Sum of opportunity costs for the construction of a gas fired power plant and the possibility to lower the peak capacity of condensing heat boilers from 22 kW to 15 kW for around 800,000 units; thus capacity in gas grids could be freed up for the use by gas-fired CHPs. Description see 3.3.2. 9 The sum of operated fuel cells amounts to 1,600 MW baseload [800,000 units each 2 kW (electricity plus thermal - taking the efficiency factor into account)] plus avoided peak capacity of 3,900 MW [= delta between current peak capacity of gas condensing boilers and condensing boilers with reduced capacity (22-15 kW) *800,000 units *0.7 assumed simultaneity factor and the out of it reduced withdrawal

https://www.e-control.at/konsumenten/service-und-beratung/toolbox/tarifkalkulator

https://www.e-control.at/konsumenten/service-und-beratung/toolbox/tarifkalkulator


34

Savings resulting from lower investment needs for the replacement and or extension of the

existing electricity grid (not taken into consideration; currently unknown because of the so

far not accurately determined national PV and wind programme which very likely be the

determining factor for the electricity grid capacity – at least on a local and regional level)

Savings resulting from lower investment needs for the replacement and or extension of the

existing district heating system (not taken into consideration; currently unknown)

Revenues from selling energy efficiency measures on the trading platform (not taken into

consideration; currently unknown).

In total there could be savings of > 1,105 Euro per year in comparison to a condensing gas boiler

without a buffer tank.

Based on a lifetime expectation of the devices of 10 years, and based on a WACC of 4% and a target

inflation rate of 2%, the present value of the savings respectively revenues per year, were roughly >

9,900 Euro. In other words, the installation costs (plug and play) of a fuel cell unit – using natural gas

– are allowed to be by > 9,900 Euro higher than the installation costs for a natural gas fuelled boiler

without a buffer tank and roughly 5,000 Euro higher than the installation costs for a natural gas

fuelled boiler with a buffer tank

These figures are based on very preliminary estimates because:

it is implicitely assumed that the savings

o resulting from the lower capacity needs in the electricity grids

o resulting from the lower capacity needs in the natural gas grids

are already given.

The pre-investments in a high number of fuel cell installations could take much longer.

The assumptions of the WACC-determination will not change.

The annual savings – resulting from the decreased capacity needs for electricity respectively gas grids

– could be provided either as

direct investment subsidies or

lower tariffs of the usage of the natural gas grids.

In case of lower tariffs of the usage of the natural gas grids the following assumptions respectively

analyses have to be made:

Workload: An assumed workload of 8,000 hours per year and fuel cell unit would result in an

annual gas consumption of roughly 16,000 kWh; the current costs of the usage of the gas

grids amount to 350 Euro per year (VAT excluded) in Austria – which is very close to the

savings of 375 Euro – consequently the tariffs for fuel cells of the usage of the gas grids could

rate multiplied by the gas storage costs per relevant capacity unit. Source for the gas storage costs: https://www.rag-energy-storage.at/speicherdienstleistungen/tarifrechner.html


35

be very close to 0 Euro. Theoretically the tariffs could be even lower – which means the fuel

cell operator would receive some money for the operation of the fuel cell. This approach is

very similar to a „pure“ entry-exit-system but of course customers have to get used to

negative tariffs (they are used to negative balancing energy prices and negative electricity

prices as well).

The peak capacity of the generated electricity by the fuel cell operator: the higher the peak

the higher the potential capacity needs reduction in the electricity grids.

The share of the generated electricity consumed by the fuel cell operator: the higher the

share of consumption of the generated electricity the higher the savings resulting from the

non-usage of the public electricity grid.

3.3.4 Financing of the required studies

For the sake of completeness it has to be made clear that for the financing of the relevant analysis/

studies of the proposed ideas/approaches, Article 37 (8) of Directive 2009/72/EC and Article 41 (8) of

Directive 2009/73/EC state: “In fixing or approving the tariffs or methodologies and the balancing

services, the regulatory authorities shall ensure that transmission and distribution system operators

are granted appropriate incentive, over both the short and long term, to increase efficiencies, foster

market integration and security of supply and support the related research activities”.


36

4 Summary

In order to achieve the ambitious Paris climate goals, a bundle of coordinated measures will be

needed. It will be necessary to improve energy efficiency, increase the share of RES, reasonably

electrify sectors, reduce CO2-intensive fossil fuels, namely oil and coal, and apply natural gas as

bridging technology.

According to INFRAS, biofuels (2nd generation) in the transportation sector have a global potential

between 13 – 19 Exajoule whereas the global demand will amount to 100 – 170 Exajoule in 2020. The

mentioned potential takes already the competition between the food and fuel sector regarding

available area into account. In other words, coal, oil and natural gas cannot be replaced by biomass,

biogas and biofuels to the full extent. Subsequently the more ambitious the GHG-reduction-goals

are, the more synthetic gas fuels, produced by Power-to-Gas (PtG) and synthetic liquid fuels,

produced by Power-to-Liquid (PtL) plants, will be needed to achieve the goals in the industrial,

transportation and space heating sector – besides the power sector – as well. Regarding the

transportation sector, one has to consider the passenger vehicles, heavy and light duty traffic,

aviation and the navy sector where BEVs cannot be deployed in a reasonable manner – taking the

specific costs into account.

The most important gas will be hydrogen (H2) either to be applied directly or deployed as input for

the methanation process or for liquid syn-fuels.

The technological progress indicates the potential for production of huge amounts of syn-methane

and syn-fuels at reasonable costs. Subsequently these commodities would become part of the

solution. This is even more true because the application of syn-methane and syn-fuels – generated by

RES – does not require huge investments since the relevant infrastructure is already in place – at

least partially. In addition, these fuels do have a very high energy density and can easily be stored. In

case – which seems to be realistic – not the entire amount of RES can be generated in the country

where P2G- and PtL-products are required – there will be a need for import of such products. The

therefore needed logistic chains are well-proven and the costs are similar to the costs of

transportation of natural gas (LNG) respectively refinery products.

Fuel cells, as stationary application as well as in the transportation sector will very likely play a crucial

role in the mid and long term energy sector-scenarios. Initially the stationary fuel cells will be

„powered“ by natural gas and later on hydrogen will be „digested“ by fuel cells in the stationary

application as well as in the transportation sector. In order to get familiar with the deployment of

stationary fuel cells – taking the thereto related economics into account – the bill to be paid for by

the final customer is of utmost importance.

So far the business modell for stationary fuel cells rests on the savings resulting from the electricity

generated by fuel cells, since the electricity generated by fuel cells does not need to be transported

to the households, hence the tariffs for the usage of the electricity infrastructure do not have to be

paid for. Mostly the usual savings resulting from the operation of fuel cells do not easily pay off the

required investment difference in comparison to a natural gas boiler in Europe – even if including

SUMMARY

37

subsidies, if any. Thus the installation of fuel cells does not happen often in Europe. Therefore other

– if any - benefits have to be monetized, if not available in terms of money already, and turned into

justified subsidies or lower tariffs for the usage of the relevant infrastructure by fuel cells.

The economical analyses in this report are based on the following components:

Savings resulting from the avoided electricity grid usage costs for the amount of electricity

generated by fuel cells and consumed in the household

Feed-in tariffs for the excess electricity

Savings resulting from the installation of fuel cells on the gas grid capacities and the security

of electricity supply impacts – opportunity costs otherwise required for the investment of a

gas fired power plant

Savings in terms of lower gas storage withdrawal rates


existing electricity grid (not taken into consideration yet)


existing district heating system (not taken into consideration yet; currently unknown)

Revenues from selling energy efficiency measures (not considered yet; currently unknown).

The results of the analyses regarding the extension of the so far „usual“ business modell indicate that

a natural gas „fired“ fuel cell is allowed to be roughly > 9,900 Euro more expensive than the

installation of a natural gas fuelled condensing boiler without a buffer tank and roughly > 5,000 Euro

more expensive than the installation of a natural gas fuelled condensing boiler with a buffer tank.

These figures are deviated by cross sector impacts (electricity and natural gas sector) generated by

the deployment of fuel cells, based on cost accounting principles.

In case the current investment (plug and play) in Japan – which amounts to roughly € 7500 per

stationary fuel cell system - could be achieved in Europe as well, this were a real boost for the

market uptake for the installation of fuel cell systems in Europe.

SUMMARY

39

About the author

Alfred Schuch is an expert in energy- and waste-related topics and project manager at the Austrian Energy

Agency. His work focuses on the natural gas sector - including hydrogen linked with the electricity sector, the

security of energy supply, industrial facilities and fuel cells. Alfred Schuch has been with the regulatory

authorities in Austria and further on with the Secretariat of the Energy Community – as Head of the

Hydrocarbons Unit – dealing with the liberalisation of network-related energy sectors in close co-operation

with the Ministerial Council of the Energy Community, European Commission, European Regulators’ Group for

Electricity and Gas, and International Financing Insitutions. He is an engineer and also holds a Master’s degree

in business administration.

41

5 Literature

acatech et.al: „Sektorkoppelung“ – Optionen für die nächste Phase der Energiewende,

November 2017

Agora Verkehrswende, Agora Energiewende und Frontier Economics (2018): Die zukünf-

tigen Kosten strombasierter synthetischer Brennstoffe

Birnbaum U.K.: Small stationary Fuel Cells for house energy supply and Power Generation in

general. Source: https://www.kesselheld.de/heizungsvergleich/ - called by Birnbaum U.K. on

22.10.2018.

Davis et al., Science 360, eaas9793 (2018): The energy density of energy sources for trans-

portation including hydrocarbons and lithium-ion batteries

Drolet et al.: The Euro-Quebec-Hydro-Hydrogen Pilot Project

EIA, „Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2018 (2018): www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf.

FENES et al. (2015) Bedeutung und Notwendigkeit von Windgas für die Energiewende in

Deutschland

Frontier economics: Die zukünftigen Kosten strombasierter synthetischer Brennstoffe

Gas Connect Austria, Paulnsteiner R.: H2-Einspeisung: Anforderungen an Rohrleitungs-

netze, Harmonisierungsanforderungen, National Workshop HyLAW, Linz, 6th November

2018

https://www.google.at/search?q=fuel+cell+household&source=lnms&tbm=isch&sa=X&ved=0

ahUKEwiMjcOE8u7dAhUcwAIHHQJsC7sQ_AUIDigB&biw=1536&bih=755#imgdii=ghMKKL3

hNegBMM:&imgrc=oDZ3B-nw2AXnxM:

https://www.google.at/search?q=panasonic+fuel+cell+technology&source=lnms&tbm=isch&sa=X&ved=0ahUKEwiivZvF-O7dAhUppIsKHWTPCyYQ_AUIDigB&biw=1536&bih=755#imgrc=TFpOGMbwNPnxSM: Kamiya et al. Study on Introduction of CO2 Free Energy to Japan with Liquid Hydrogen

Krieg, D. (2012): Konzept und Kosten eines Pipelinesystems zur Versorgung des deutschen

Straßenverkehrs mit Wasserstoff. RWTH Aachen University cited Stolten, D.: Rolle

chemischer Speicher für die Energiewende 2017

https://www.kesselheld.de/heizungsvergleich/

http://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf








42

NEDO, Eiji O.: Japanese Fuel Cell Success Stories, IEA Outreach Meeting, Austria/Linz, 6th

November 2018

Shaner M.R., Atwater H.A., Lewis N.S., McFarland E.W.: A comparative techno-economic

analysis of renewable hydrogen production using solar energy, Energy Environ. Sci. 9, 2354-

2371 (2016). Doi: 10.1039/C5EE02573G

Stolten, D.: Potential Hydrogen Production in Patagonia – A System Analysis

Teichmann et al.: Liquid Organic Hydrogen Carriers as an efficient vector for the transport

and storage of renewable energy, 2012

Tokyo Commodity Exchange (2017): Gasoline price. URL: http://www.tocom.or.jp/index.html

Watanabe et. al: Cost Estimation of Transported Hydrogen, Produced by Overseas Wind

Power Generation, 2010

http://www.tocom.or.jp/index.html

43

6 Abbreviations

ACQ Annual contracted quantity

BEV Battery electric vehicle

BoP Balance of point

CCS Carbon capture storage

CHP Combined heat power

CO2 Carbon dioxide

FC Fuel cell

FCEV Fuel cell electric vehicle

FCV Fuel cell vehicle

GHG Green house gas

H2 Hydrogen

HDV Heavy duty vehicle

HRS Hydrogen refueling station

ICE Internal combustion engine

LDV Light duty vehicle

LNG Liquid natural gas

OPEX Operational expenditure

P2G Power to gas

PEM Polymer electrolyte membrane

PtL Power to liquid

PV Photovoltaic

RES Renewables

SME Small medium sized enterprises

SOFC Solid oxyde fuel cell

VAT Value added tax

WACC Weighted average cost of capital

45

7 List of drawings

Drawing 1: Energy efficiency of BEVs, FCEVs, and ICEs; Source: acatech et.al: „Sektorkoppelung“ –

Optionen für die nächste Phase der Energiewende, November 2017, P. 31.......................................... 7

Drawing 2: Energy efficiency of heat Pumps, heat FCs, and heat condensing boilers ........................... 8

Drawing 3: Outline of the wind park project in Patagonia.................................................................... 11

Drawing 4: Components of the supply cost of hydrogen – produced in Patagonia – in Japan ............ 12

Drawing 5: Share of the components of the supply cost of hydrogen to Japan ................................... 12

Drawing 6: Trend of the expected/forecasted costs for syn-methane respectively syn-fuels

over time – taking the different generation options into account. ...................................................... 13

Drawing 7: Production costs of syn-methane and hydrogen over time (2022 to 2050) in different

regions. .................................................................................................................................................. 14

Drawing 8: Production costs of syn-methane and hydrogen over time (2022 to 2050)

in North Africa ....................................................................................................................................... 15

Drawing 9: NEDO, Ohira E.: Japanese Fuel Cell Success Stories, IEA Outreach Meeting,

Austria/Linz, 6th November 2018, p. 5 ................................................................................................. 16

Drawing 10: Relationship of capital cost (electrolyser cost) and electricity price on the cost of

production of hydrogen, Shaner M.R., Atwater H.A., Lewis N.S., McFarland E.W.: A comparative

technoeconomic analysis of renewable hydrogen production using solar energy,

Energy Environ. Sci. 9,2354-2371 (2016). Doi: 10.1039/C5EE02573G .................................................. 17

Drawing 11: EIA: „Levelized Cost and Levelized Avoided Cost of New Generation Resources in the

Annual Energy Outlook 2018 (2018): www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf. ... 18

Drawing 12: Davis et al., Science 360, eaas9793 (2018): The energy density of energy sources for

transportation including hydrocarbons and lithium-ion batteries, p.5 ................................................ 19

Drawing 13: Change of transportation capacity as a function of the volume of hydrogen injected into

the natural gas grid , Gas Connect Austria, Paulnsteiner R.: H2-Einspeisung: Anforderungen an

Rohrleitungsnetze, Harmonisierungsanforderungen, National Workshop HyLAW, Linz,

6th November 2018, S. 10 ......................................................................................................... 19

Drawing 14: Link between calorific value and Wobbe-index, Gas Connect Austria, Paulnsteiner R.:

H2-Einspeisung: Anforderungen an Rohrleitungsnetze, Harmonisierungsanforderungen,

National Workshop HyLAW, Linz, 6th November 2018, S. 7 ................................................................ 20







Drawing 18: Birnbaum U.K.: Small stationary Fuel Cells for house energy supply and Power

Generation in general. Source: https://www.eon.de/de/pk/waerme/brennstoffzellen-

heizung.html?subid=at104846_a142608_m4_p5816_t3_cDE&ref=60806-

at104846_a142608_m4_p5816_t3_cDE&affmt=0&affmn=0 ............................................................... 25


46

Drawing 19: Birnbaum U.K.: Small stationary Fuel Cells for house energy supply and Power

Generation in general. Source: https://www.kesselheld.de/heizungsvergleich/ - called by

Birnbaum U.K. on 22.10.2018. .............................................................................................................. 25

Drawing 20: Conceptual design of a stationary fuel cell; Source:

https://www.google.at/search?q=panasonic+fuel+cell+technology&source=lnms&tbm=isch&sa=X&v

ed=0ahUKEwiivZvF-

O7dAhUppIsKHWTPCyYQ_AUIDigB&biw=1536&bih=755#imgrc=TFpOGMbwNPnxSM: ..................... 26

Drawing 21: Conceptual design of a stationary fuel cell; Source

https://www.google.at/search?q=fuel+cell+household&source=lnms&tbm=isch&sa=X&ved=0ahUKE

wiMjcOE8u7dAhUcwAIHHQJsC7sQ_AUIDigB&biw=1536&bih=755#imgdii=ghMKKL3hNegBMM:&imgr

c=oDZ3B-nw2AXnxM: ............................................................................................................................ 27

47

8 List of tables

Table 1: Illustrates the prioritisation of decarbonisation options – depending on the sector and the

application. .............................................................................................................................................. 9

49

ABOUT THE AUSTRIAN ENERGY AGENCY (AEA)

The Austrian Energy Agency offers answers for the future of energy. We provide scientifically founded advice for decision-

makers in politics, business and administration – both nationally and internationally. As a competence centre for energy we

concentrate on three strategic areas: missionzero, transformation and smart energy.

Focusing on missionzero the Austrian Energy Agency pursues the long-term objective of building a fossil-fuel free future

through strategy development und the implementation of concrete measures. Relating to the transformation of the energy

system we consider the associated changes and profitable business opportunities in the energy-relevant sectors. With

regard to smart energy we engage in the intelligent and flexible energy system of the digital future.

Our focus lies on promoting energy efficiency and renewable energy sources between the poles of competitiveness, climate

and environmental protection, and supply security. The Austrian Energy Agency develops strategies for sustainable and

secure energy supply, provides advice and training, and is the networking platform for the energy industry. klimaaktiv, the

climate protection initiative launched by the Austrian Federal Ministry of Sustainable Development and Tourism (BMNT) is

managed by the Austrian Energy Agency and coordinates the various measures in the areas of mobility, energy saving,

construction & renovation and renewable energy. In addition, the Austrian Energy Agency operates the Energy efficiency

monitoring body on behalf of the BMNT. www.energyagency.at

http://www.energyagency.at/

www.energyagency.at

Documents

Possible extension of the business model for fuel cells