A VISION FOR THE UK

HYDROGEN ECONOMY

SUPPORTING THE ROLE OF JOHNSON MATTHEY FUEL CELLS

AS A POLICY AND COMMERCIAL LEADER

2

Overview

Hydrogen technologies offer the UK a long-term opportunity to

cost-effectively deliver secure, high quality energy services whilst

significantly reducing greenhouse gas (GHG) emissions and local

pollution. Infrastructure development is vitally needed to

facilitate the advancement of the hydrogen economy, yet this

will be slow to emerge without adequate demonstration and

growth of demand for fuel cells and hydrogen energy. The

following roadmap will outline a template for financially

practicable phases which can support the transition from small

scale demonstrations to greater energy system contribution, and

has three steps:

Phase 1

o Stationary fuel-cell applications in targeted

sources of demand (e.g. hospitals or universities)

Phase 2

o The initial development of a refuelling station

network characterised by hydrogen produced by

steam reforming, pre-determined back-to-base

vehicle fleet demand, and a ‘mother-and-

daughter’ style refuelling station network set up

Phase 3

o Further refuelling station network development,

with green hydrogen produced by water

electrolysis powered from renewable electricity

Johnson Matthey is in a unique

position to both drive the

advancement of the UK

hydrogen economy, and also

ultimately benefit from it as a

large UK-based company.

Holding a respected position

among industry peers and

government alike, Johnson

Matthey has the potential to

develop the public and private

collaborations necessary for the

development of the hydrogen

economy, and influence its

direction also. In addition with

the company selling fuel cell (FC)

components to a wide range of

applications, it has the benefit of

being able to develop synergies

between differing industries and

also being in a position to foster

a holistic image of a hydrogen

fuelled economy.

3

In terms of taking forward the conclusions of this analysis, the roadmap identifies

the following related activities:

Engage with private actors

o Proactively identify and approach in a concerted manner

specific potential consumers, including owners of captive

vehicle fleets and large building owners with significant

heating and power demand

o Lead on the formation of a consortium of companies

across the supply chain wishing to develop hydrogen hub

projects and influence policy

Engage with the new UK government;

o Pursue greater recognition for stationary applications in

government publications based on feasible policy change

(e.g. CCC’s 5th carbon budget) and ultimately support in

the form of a mandate to public bodies, and/or policy

such as a fuel cell FiT, improved CHPQA, support for

hydrogen generation etc.

o Pursue financial support for specific hydrogen hub

demonstration projects

Increased exposure and publicity

o Develop proactive and focused collaboration with policy

stakeholders so as to become the point of reference for

the hydrogen economy in the UK

o Engage in publication of informed positions on the

hydrogen economy and proactive participation in key

conferences and fora

4

5

Contents

Introduction 6

Scope 7

Key recommendations 8

Stationery fuel cell market 8

The hydrogen hub 9

A policy engagement plan for 2015/16 10

Hydrogen Hub Roadmap 12

Towards the hydrogen economy 12

Hydrogen hub roadmap overview 13

Phase 1 – Deployment of stationary fuel cells 14

Phase 2 – Targeted hydrogen hub projects 17

Phase 3 – Wider hydrogen infrastructure 21

UK Energy Policy: Energy Trilemma 25

1 – Energy cost 25

2 – Energy security 26

3 – CO2 and environmental performance 26

Appendix 28

1 – Data assumptions 28

2 – Levelised cost methodology 30

3 – Case study 1: fuel cell installations in hospitals 31

4 – Delivery of Hydrogen 35

5 – Case study 2:fuel cell material handling vehicles (MHVs) 38

6

Introduction

With a range of end-use applications and production methods,

hydrogen is an incredibly versatile energy carrier which can transform

the energy landscape. However realising the potential of hydrogen

has been hindered by low deployment volumes. Without scaling

production, costs have not been able to fall low enough to attract a

large market share. In order to break this cycle, a variety of actions

will need to be taken. Firstly, financial support can create lower costs

for consumers facilitating the higher production volumes necessary

to achieve economies of scale and learning-by-doing. There is also a

need for cohesion amongst the supply chain to avoid a first mover

disadvantage; fuel cell electric vehicle (FCEV) deployment is not viable

until hydrogen refuelling stations are deployed and vice versa.

This high level business case develops a roadmap which draws from

government support and the hydrogen supply chain to deliver

hydrogen infrastructure projects. Starting from smaller scale

operations, Ecuity assesses the opportunities for Johnson Matthey

and partners to deliver targeted schemes (hydrogen hubs) which

demonstrate hydrogen generation, distribution and utilisation in

different markets. These hydrogen hubs can help to facilitate the

necessary industry collaboration, government endorsement and

customer demand to bring hydrogen technologies to the wider

market.

7

The development and operation of hydrogen hubs

today may not be immediately profitable, but the

long-term goal of mass-market stationary and FCEV

applications has enormous potential. As this

document will demonstrate the targeted

deployment of fuel cells is already commercially

viable in many areas, whilst the development of

integrated hydrogen hubs requires further steps to

reach wider market adoption. Johnson Matthey is

in a strong position to drive this process which

begins with the demonstration that this hydrogen

future is viable from:

(a) a technical perspective

(b) that supply chains can be developed to

provide a reliable supply of hydrogen

(c) a positive consumer experience and need

Crucially the hydrogen hub should

demonstrate scalability and through wider

applications and increased volumes the

potential for learning-by-doing, expertise

and supply chain efficiencies, and

ultimately cost reductions through

economies of scale. By driving this

process Johnson Matthey will stand to

best benefit from any infrastructure and

industry development, and will become

an integral part of the supply chain.

Scope

8

Key Recommendations

2015 is an important time to start engaging with public and private actors in particular following

7th May and the voting in of a new government. Fuel cell technologies have been under-

acknowledged and supported in previous UK government documents – such as DECC’s Heat

Strategy and CCC Carbon Budgets - which underpin policy design.

The analysis included in this paper has

demonstrated the economic viability and

environmental benefits of stationary fuel

cells. The technology is easily integrated

into current energy systems and the next

step for Johnson Matthey and partners

would be engagement with:

(i) Sources of specific demand.

In particular organisations

with consistently high heat

loads. Aim of publicising

the technology and

reducing any perceived risk

of investment

(ii) The new government. Both

in terms of hard policy and

recognition of the benefits

of fuel cells, greater support

may be required to increase

exposure, volumes of sales

and ultimately reduce costs

Again scalability is an important element of

any strategy for Johnson Matthey. In the

case of initial demonstrations, these could

ideally be targeted at public institutions

such as universities or hospitals which are

highly visible. Publicising the experienced

benefit of such installations can lower the

perceived risk of investment in a nascent

technology for NHS Trusts and other

potential customers. This is especially

important for organisations operating in the

third sector which can commonly be

conservative in regards to investment

decisions and therefore precedents are

needed.

With organisations initially perceiving

investment in new technologies as risky,

government support can be instrumental in

addressing concerns and supporting the

growth of the nascent industry. At the very

least Johnson Matthey should be engaging

with policymakers to encourage greater

acknowledgment of fuel cells in

government publications. Ultimately the

industry would benefit from greater support

in policy perhaps through a wider feed-in-

tariff (FiT) scheme or a more supportive (of

higher electrical efficiency) CHPQA policy.

Stationary fuel cell market

8

9

The hydrogen hub

The long-term goal is the development of the hydrogen and

fuel cell economy. Johnson Matthey can deliver this vision to

a new government following the May elections. Engagement

with the Committee on Climate Change who are writing the

UK’s 5th Carbon Budget this year1, DECC, DEFRA, the

Department of Transport and the Office for Low Emission

Vehicles will all also be important. It is essential for

policymakers to understand and start endorsing the

aspirational aims of the development of hydrogen hubs.

In the nearer term, Johnson Matthey can start engaging with

other supply chain actors to develop a consortium of

companies who wish to collaborate on the delivery of at least

one hydrogen hub project. This will likely be able to attract

support from a UK public body (e.g. Innovate UK) or an EU-

wide initiative (e.g. Horizon 2020)

1. Strategic recognition for fuel cells and hydrogen

The potential strategic role of fuel cells and hydrogen is currently note capture

in strategic documents that underpin energy policy including the Heat Strategy,

the Carbon Plan or the Carbon Budgets. A review of the Heat Strategy and the

development of the 5th Carbon Budget provide an opportunity for formal

strategic recognition, subsequent policy support and market exposure.

2. Support for stationary fuel cells under FITs

Although primary legislation, based on the 2008 Energy Act, envisages support

for fuel cells under the FIT scheme currently the technology is not supported.

The formal 2015 FIT review provides an opportunity to achieve some form of

formal and separate financial support for fuel cell technologies under the

scheme.

3. Support for the generation of hydrogen

A Department for Transport (DfT) consultation during 2014 proposed to

consider allowing in the future synthetic fuels or hydrogen from renewable

electricity to receive support under the RTFO. It is important to take note and

follow up on this development, based on comprehensive evidence, so as to

achieve the support of hydrogen generation from renewable electricity.

Following the May 2015 General Elections, the focus will now return to policy

design. That generates a unique opportunity to engage policy makers towards

the attainment of strategic recognition and concrete policy support for fuel cells

and hydrogen applications and projects.

An engagement plan based on specific and feasible policy objectives is necessary

to achieve results based on prior experience with novel low carbon technologies.

Johnson Matthey, as major domestic player with a wide presence across the

supply chain, is well placed to drive discussions during 2015/16 based on the

below objectives:

A policy engagement plan for 2015/16

11

4. Enhanced support vs. conventional CHP

DECC undertook a review of CHP financial support during 2014 that did not

incorporate or consider fuel cells. DECC CHP work continued during 2015

focusing on non-financial obstacles again not capturing fuel cells. An

opportunity exists to pursue a structured review of financial and non-financial

obstacles for stationary fuel cells with a view to enhanced support or tax

incentives vs. conventional engine driven CHP applications.

5. A targeted mandate or demonstration for fuel cells

Efficiency is expected to be a central component of energy policy irrespective

of the party, or coalition of parties, that will be in power following the May

elections. A mandate or a demonstration project for a fixed number of

stationary fuel cell applications in public buildings with high energy demand

(e.g. hospitals) where the technology already makes financial sense is a

feasible and defendable policy outcome.

6. Enhancing the economics of electrolysis

The National Grid provides constraint payments to wind generators to stop

generating when balancing requirements dictate. This led to circa £55m of

payments during 2014 at an average price of £86/MWh. This is a highly

emotive topic for a range of policy stakeholders. Diverting some of these

payments for the generation of hydrogen from excess wind could be explored

as an option following the elections.

12

Hydrogen Hub Roadmap

While a hydrogen economy

has the potential to displace

much of the embedded

hydrocarbon infrastructure,

widespread uptake cannot be

achieved overnight. Hydrogen

utilisation is not viable without

supporting infrastructure, and

this infrastructure not viable

without appropriate demand.

The high capital costs of

infrastructure warrant targeted

approaches initially, where

projects are focused in

locations of suitable demand.

These initial infrastructure

projects can be described as

hydrogen hubs.

A hydrogen hub does not refer to a specific

application of hydrogen technology. Rather, it

is a broadly defined infrastructure project which

incorporates several components of the

hydrogen supply chain to serve a targeted

market. The range of scales of production,

distribution and applications of hydrogen at the

hubs is vast. By starting with smaller, more

targeted hubs with assured markets, Johnson

Matthey can begin to develop the

infrastructure, lower the production costs and

demonstrate the commercial attractiveness

which is necessary for creating a larger

hydrogen economy.

This analysis proposes a roadmap for hydrogen

deployment. The roadmap defines three broad

phases which describes how hydrogen

technologies, and their associated supply

chains, can be developed with hydrogen hubs

before widespread adoption is achieved. This

section will describe the business case for

proposed hydrogen hubs in phases one, two

and three. Each hydrogen hub proposal brings

about its own contextually specific risks,

opportunities, costs and benefits. These

characteristics are discussed within the context

of current and future policy frameworks. A

financial analysis is presented to inform what

benefits are accessible for investors and

consumers.

Towards the hydrogen

economy

13

Hydrogen hub roadmap overview

PHASE 1 PHASE 2 PHASE 3

HYDROGEN HUBS Deployment of stationary fuel cells in

targeted markets (e.g. public sector,

hospitals, retail, multifamily residential)

Targeted hydrogen hub projects with

transport applications in a mother-daughter

arrangement

Development of wider hydrogen

infrastructure to accommodate a mass

market

HYDROGEN

DELIVERY

Steam reforming of natural gas on-site Large scale steam reforming of natural gas at

“mother” stations. Delivered to “daughter”

stations by CH truck

Growth in water electrolysis using

renewable electricity

OUTCOMES Fuel cell cost reduction;

Familiarity with technology

Demonstration of hydrogen hub supply chain

in favourable settings;

Cost reduction throughout supply chain;

Initial deployment of FCEV

Hydrogen infrastructure achieves scale and

meaningful energy system contribution;

Widespread deployment of FCEV

POSSIBLE POLICY

INSTRUMENTS

FIT for stationary fuel cells above 2kW;

Mandates/standards on

heating/efficiency; enhanced CHP

support; strategic recognition

Financial support (RTFO) for synthetic fuels;

Project financing;

Air quality mandates

Binding hydrogen targets;

Support for mass roll-out of infrastructure

14

Targeted deployment of stationary

combined heat and power (CHP)

fuel cells in mid-sized commercial

applications such as hospitals,

universities, retail and multi-

residential buildings.

Hydrogen is produced onsite by

steam reforming of natural gas.

Phase 1 – Deployment of stationary fuel cells

These applications require relatively minimal

infrastructure commitment: the existing gas

grid can provide natural gas for the onsite

steam reformer, and the heat generated by

the fuel cell can be delivered via the existing

central heating system. They are therefore

likely to be easier to implement in the near-

term, as investment costs are lower and fewer

supply chain actors are required.

By targeting the suggested mid-sized

commercial markets securing demand in this

pathway is lower risk; there is no reliance on

external developments such as hydrogen

vehicle deployment to generate sources of

demand. Instead consistently high energy

demand can provide the high load factors

which may be necessary to recoup the capital

costs. Financial benefits are available

immediately with lower bills arising from

higher efficiencies as well as potential

eligibility for Feed in Tariff payments. For

Johnson Matthey demonstration will create

familiarity with hydrogen technologies,

encouraging other consumers to use

hydrogen who were unwilling to be first-

movers. As more demand is created,

manufacturing can be scaled to facilitate

learning and economies of scale. There are

opportunities to bring laboratory innovation

from Johnson Matthey’s Test Facility to the

market. These actions will lower costs and

improve performance of fuel cells and steam

reformers.

Due to the use of natural gas in the

production process, the hydrogen in this

pathway is not renewable. However, the

improvements in efficiency and lack of

combustion will lower carbon and local

pollutant emissions, meaning there is a strong

case for government backing. Critically, this is

a low cost pathway to deploy the

infrastructure which can utilise renewable

hydrogen when it becomes more

economically viable in the future.

15

Financial analysis

Financial analysis suggests that for an

illustrative hospital (modelled on the Royal

Free in Hampstead using data for the Doosan

Model 400 fuel cell), the installation of a

number of FCs meeting the building’s power

demand can lower the hospital’s levelised cost

of energy (£/MWh) by 20% whilst also

lowering annual carbon emissions by another

35% (compared to an oil boiler

counterfactual). With energy bill savings the

net present value of this investment is over £3

million, with a rate of return of 6% and a

payback period of just over 7 years (for more

details see the appendix).

£40

£45

£50

£55

£60

£65

£70

£75

£80

Fuel Cells + Auxillary Gas Boiler Grid Electricity + Gas Boiler Grid Electricity + Oil Boiler

Leve

lised

Co

st (

£/M

Wh

)

Figure 1: Levelised Cost of Energy (£/MWh)

Ecuity Economics

16

The UK has over 1,000 hospital sites. Figure 2

below considers the carbon emission savings

that could be accrued nationally if only 30

average-sized hospitals installed fuel cells

every year. The exact level of savings depends

on the proportion of oil or gas counterfactual

fuel heating systems being displaced yet by

2022 cumulatively the UK could have saved

between 7-10 Mt CO2e. To put this into the

context of national climate change and

emission targets, from 2016-2020 the UK

needs to cut national emissions by 238

MtCO2e to meet its 3rd carbon budget.1

1 Committee on Climate Change (2014) Carbon Budgets

and targets. Available from: http://www.theccc.org.uk/

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

2015 2016 2017 2018 2019 2020 2021 2022

An

nu

al C

O2e

savi

ngs

(tC

O2e )

Figure 2: CO2e savings from installation of FCs in 30 new hospitals per year

Ecuity Economics

17

Phase 2 – Targeted hydrogen hub projects

The transport sector has the potential to be

the most important market for hydrogen fuel

cells, with major opportunities for mass-

market deployment and no alternative

technology which can provide zero-carbon

tailpipe pollutants, with quick refuelling times

and long distance operation. Yet FCEVs are

unviable without refuelling infrastructure,

whilst the refuelling network is unviable

without FCEVs. Thus the primary objective of

the second phase of the roadmap is to start

developing infrastructure in targeted areas of

secure demand, with the aim of supporting

the initial deployment of hydrogen vehicles,

which will in turn increase the demand for

further refuelling stations. A contracted

vehicle fleet with back-to-base operating

regimes (e.g. busses, taxis, or material

handling vehicles) could be considered a

reliable and appropriate end-user for this

stage of demonstration.

Surveys have shown that access to more than

one hydrogen refuelling station significantly

increases consumer receptiveness to FCEVs2.

Phase 2 allows the development of multiple

refuelling stations relatively cheaply, as the

expensive generation is not required at each

site. Instead a single generator station can

operate at a higher load factor improving its

financial credentials. Once this set-up has

facilitated sufficient demand, further

generation facilities can be built and the

hydrogen refuelling network expanded.

Research focusing on Southern California3

suggests that a small number of strategically

placed stations reduces infrastructure costs

while delivering good convenience

and reliability.

2 UK H2 Mobility, 2013. Phase 1 results. 3 Ogden and Nicholas, 2011. ‘Analysis of a “cluster” strategy for introducing hydrogen vehicles in

Southern California’ Energy Policy 39(4): 1923-1938

Development of hydrogen hubs which

produce and supply hydrogen to the

nascent fuel cell electric vehicle (FCEV)

market in the UK.

Economic analysis and field evidence will

demonstrate that in the early stages of

adoption the hub is best clustered around

specific sources of secure demand, with a

large station producing the hydrogen and

supplying smaller refuelling stations. This

model of distribution has been termed the

mother and daughter model and has been

demonstrated by Tokyo Gas in Japan.1

To reduce costs, phase 2 considers hydrogen

produced by steam reforming of natural gas.

18

Initial demand for the fuel should be secured

in advance. A fleet of vehicles with regular,

back-to-base routes may be most appropriate

when there are few refuelling stations; buses,

taxis and material handling vehicles present a

suitable opportunity to offer this early

demand. Indeed the French Mobilité

Hydrogène programme offers a good

example of a targeted roll-out of clustered

refuelling stations centring on “captive fleets,”

which offer predictable demand to the station

operators4. As this phase incorporates much

more of the hydrogen supply chain, there is

greater potential for scaling and learning, to

reduce overall costs. Beyond the tangible

increases in production volumes and

improved manufacturing techniques, supply

chain actors can strengthen relationships and

coordinate their business activity. There is an

opportunity for Johnson Matthey and its

supply chain partners to create a separate

business entity which can manage delivery of

hydrogen hub projects.

Financial analysis

Mother & Daughter versus distributed model

Figure 5 – Hydrogen station configurations: Distributed vs Mother & Daughter

Ecuity’s economic modelling compared the

cost of hydrogen produced and supplied

through a distributed refuelling network of 5

stations with onsite reformers, to a clustered

4 Mobilité Hydrogène France (2015) Proposition d’un plan de déploiement national des véhicules

mother and daughter model which utilises

one station’s large reforming capabilities to

supply 4 refuelling stations with hydrogen.

Both scenarios envisage a total of 2,000 kg of

hydrogène Available from: http://www.afhypac.org/

D

D

D D

M M M M M

M

19

£5.0

£5.1

£5.2

£5.3

£5.4

£5.5

£5.6

Distributed Model Mother & Daughter

Co

st o

f H

ydro

gen

(£

/kg)

Figure 6: Distributed Model vs. Mother & Daughter

6% reduction

hydrogen being supplied daily (400 kg from

each station).

When distribution is involved, this is done

through the operation of compressed gas

tube trailers which Ecuity’s modelling has

demonstrated to be the lowest cost option for

delivery from mother to daughter stations

(see Appendix for details of analysis).

Figure 6 illustrates the cost savings

graphically. The distributed model which

consists of 5 separate stations producing

(through steam methane reforming) and

dispensing condensed hydrogen, delivers the

gas at a cost-price of £5.51/kg. The

introduction of a clustered mother and

daughter model – whereby one large station

reforms natural gas (at a rate of 2,000 kg/day)

and supplies 4 refuelling station – reduces the

cost-price of hydrogen at the pump by 31

p./kg. Given that over the assumed 15 year

lifetime (for other modelling assumptions see

the appendix) both scenarios have been

calibrated to produce and supply over 8.4

million kg of hydrogen, the cost saving is thus

sizeable and in the region of £2.5 million.

Scalability – economies of scale

Table 1 – Cost of Hydrogen (£/kg) Distributed Model Mother & Daughter

Capital & Installation Costs £2.02 £1.84

NPV of Operating Costs £3.49 £3.36

Total £5.51 £5.20

Ecuity Economics

20

Hydrogen hub projects need to demonstrate

cost-down properties over time as scale is

increased. Figure 7 gives a demonstration of

this (utilising data sources that are available in

the appendix), with the volume of hydrogen

produced and supplied by hubs increasing

over time as demand follows the

development of infrastructure.

As the size of the mother station is increased,

despite further expenditure needed to meet

the need for additional infrastructure and

daughter stations, the overall cost-price of

hydrogen falls.

Ecuity Economics

£0

£2

£4

£6

£8

£10

£12

£14

400 1000 2000

Co

st o

f H

ydro

gen

(£

/kg)

Hydrogen Hub Size (kg/day)

Figure 7: Impact of scale on cost of hydrogen

D

DD

M

D

DD

MD

DD

M

D

Capex & installation costs

Total hydrogen

cost

NPV of operating

costs

21

Phase 3 – Wider hydrogen infrastructure

Following phase 2, hydrogen has reached

high levels of familiarity and consumer

receptiveness. This is facilitated and enhanced

by the expanding infrastructure; the refuelling

network is sufficient for members of the

public to uptake hydrogen FCEVs in

significant volumes, massively increasing the

fuel cell market.

The transition to WE is an essential part of the

developing hydrogen economy. Firstly, as the

hydrogen generated in phase 3 is renewable,

the contribution towards meeting the UK’s

carbon targets increases substantially. Access

to more generous subsidy schemes is likely,

while, the fuel cell technologies will be

shielded from “green levies” such as carbon

prices or pollution taxes.

Secondly, hydrogen begins to make a

meaningful energy system contribution in this

stage. As the penetration of intermittent

renewables in the power sector increases,

hydrogen offers a mechanism to store this

energy. When wind generating capacity

exceeds electrical demand, the excess

electricity can be used to generate hydrogen

at zero marginal cost. When there is a deficit

of generation on the grid, the stored energy

can efficiently generate electricity in stationary

fuel cells. In an analysis undertaken by H2

Mobility, the services offered by WE in

balancing and stabilising the grid could lead

to a 20% reduction in the cost of hydrogen

production2.

Phase 3 continues to focus on the

transport industry, but envisages a

movement from hydrogen produced from

steam methane reformation, to water

electrolysis (WE).

Phase 3 considers the mother and

daughter model with onsite electrolysers

producing hydrogen centrally, before

being distributed to daughter stations via

compressed gas trucks.

Following the proliferation of renewable

electricity generation the production of

hydrogen could be seen as an efficient

mechanism to help balance the grid.

22

Financial analysis

Under commercial electricity prices, WE is a

more expensive method of producing

hydrogen than SMR. Ecuity’s modelling

suggests that given the same mother and

daughter model replicated in phase 2, the

utilisation of WE increases the cost of

hydrogen by £3.31/kg (a 64% increase), from

£5.21 to £8.52/kg.

As illustrated in figures 6 and 7 the cost of

hydrogen is increasingly determined by the

electricity price as it is produced by the more

energy intensive process of electrolysis. Thus

the economic viability of the hydrogen hub

becomes increasingly linked to the cost paid

for the electricity consumed in the production

process.

£3.20 £4.20 £5.20 £6.20 £7.20

Distance (km)

Capex

NPV of opex

Electricity price

Cost of Hydrogen (£/kg H2)

Figure 6: SMR Sensitivity Analysis (CH2 Truck)

+20%

-20%

Ecuity Economics

£6.52 £7.52 £8.52 £9.52 £10.52

Distance (km)

Capex

NPV of opex

Electricity price

Cost of Hydrogen (£/kg H2)

Figure 7: Water Electrolysis Sensitivity Analysis (CH2 Truck)

+20%

-20%

Ecuity Economics

23

The analysis in this paper utilises the Contract

for Difference strike price (9.5p./kWh)

allocated by DECC for wind energy, which is

indicative of an industry price for electricity

generated by turbines in the UK. However

there exists the potential for hydrogen hubs

to benefit from a lower electricity price,

because of the opportunity for hydrogen

production to assist in the difficult task of

balancing an ageing and geographically

disparate grid network. When power supply

exceeds demand, as part of the settlement

process the National Grid will bid to

generators to stop supplying electricity in

exchange for a balancing payment. At these

times wind energy can be thought of as

having a negative resource cost for the

National Grid. To be more specific the largest

wind farms in the UK which own Transmission

Licences and operate in the balancing

mechanism, receive constraint payments

when they cannot use the access to the

network that they have paid for. This often

happens because of difficulty distributing the

electricity generated in one area of the

country (e.g. Scotland) to another (e.g. South

East of England). It thus follows that there is

an opportunity for this excess electricity to be

utilised more efficiently if powering water

electrolysers and the production of green

hydrogen. Indeed there is an opportunity for

policy to mandate that the national grid

should be paying the owners of the

electrolysers, who in turn could purchase the

excess electricity from the generators. Thereby

supporting low-cost renewable hydrogen and

FCEVs, whilst also effectively managing the

balancing of the grid.

Figure 8 considers how a reduced price of

power could significantly reduce the cost of

producing and distributing hydrogen to end-

users under the phase 3 mother and daughter

assumptions. Every £10 reduction in the price

of electricity (£/MWh) results in a 70p

reduction in the cost of hydrogen (£/kg), and

given a £40/MWh price of electricity the cost-

price of renewable green hydrogen reaches

parity with SMR-produced gas.

24

The above analysis has focused on wind

energy because of the significant capacity

installed in the UK and the opportunity for

hydrogen production to assist with the

balancing mechanism in regard to wind farms.

It should however be noted that hydrogen

hubs and refuelling stations can operate from

other forms of renewable energy. Honda’s

200kg/day refuelling station in Swindon is a

good example of a hub generating green

hydrogen and powered by a 15MW solar

power plant. Note that perhaps a constraint

of using solar rather than wind energy as the

renewable energy source is the potential for

scaling to bigger sized stations and more

applications. Using Ecuity’s modelling an

averaged sized (400 kg/day) station with

onsite electrolyser would require 5,000 m2 of

installed capacity of solar panels, given an

average UK PV production rate of

2.3kWh/m2/day. With an estimated solar

irradiance to hydrogen process efficiency of

8%, a 400kg/day station would need a solar

plant in excess of 15MW.5

5 Hankin, A. (2015) Hydrogen Production using Solar Energy. Online webinar

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CfD strike price Av capacity payment price Wholesale price of electricity Free

Pri

ce o

f el

ectr

icit

y (£

/MW

h)

Co

st o

f H

ydro

gen

(£

/kg)

Figure 8: Impact of electricity price on cost of hydrogen under WE

Cost of hydrogen (£/kg) Price of electricity

Ecuity Economics

25

UK Energy Policy: Energy Trilemma

1. Energy cost

As demonstrated by the analysis in phase 1 of

the roadmap, stationary fuel cells in certain

applications deliver energy at a lower total

resource cost than traditional sources. For the

hospital modelled in this paper, the site

stands to save around £3 million a year in

energy bill savings, which given a 10 year fuel

cell system lifetime amounts to just under £30

million savings in current prices (£25 million

in present value terms). This is in excess of the

initial £20 million capital cost and

demonstrates the cost effectiveness of

stationary fuel cells.

Toyota estimate that it will cost around $50

(£34) to fill a Mirai with hydrogen. Ecuity’s

analysis of water electrolysis produced

hydrogen suggests a price closer to £50 per 5

kg of hydrogen needed to fill the tank. Given

a 300 mile range, this pricing though

speculative is competitive with petrol and

diesel-ran vehicles. The problem is that FCEVs

are currently expensive to buy, yet there are a

number of niche applications today where

they can be considered the most cost-

effective solution, as demonstrated in section

5 of the appendix which profiles indoor

material handling vehicles. Looking to the

future, it is expected that increased volumes

will lower both fuel and vehicle costs.

In addition the Renewable Energy

Foundation6 calculate that during 2014 the

National Grid paid generators to stop 658

GWh worth of wind electricity being supplied,

at a total cost of £53 million. Thus it follows

that to the extent that the production of

hydrogen could mitigate some of the need for

those capacity payments by utilising excess

electricity, that the operation of green

hydrogen hubs is even more cost effective

from a national perspective.

6 Renewable Energy Foundation (2015) Balancing Mechanism Wind Farm Constraint Payments.

Available from: http://www.ref.org.uk/constraints/indextotals.php

The concept of an energy trilemma shapes much of the

rhetoric used by politicians when discussing energy

issues, and has thus been influential on policy objectives

and details. The argument and vision for the

development of hubs and more broadly the hydrogen

economy can be framed in this context.

26

2. Energy security

Under the hospital modelling scenario used in

this paper, the operation of 11 Doosan fuel

cells would in net terms save 6,800 MWh of

gas consumption annually compared to a gas

boiler and grid electricity counterfactual. As

with the analysis above, assuming that this

installation is by 30 new sites per year, by

2018 the operation of fuel cells in 120

average-sized hospitals would cut gas

consumption aggregately by 817 GWh a year.

3. CO2 and environmental performance

Hydrogen is inherently a zero carbon energy

carrier; combustion or conversion to electrical

energy in a fuel cell produces no carbon

emissions. However, there can be carbon

emissions associated with the generation of

hydrogen. Steam reforming, whereby

hydrocarbons are reacted with high

temperature steam, is currently the dominant

form of hydrogen production, and is

associated with carbon emissions as a

consequence of utilising fossil fuels. Steam

reforming also offers a method by which the

chemical energy in natural gas can be

harnessed without releasing harmful local

pollutants which are associated with its

combustion in air. The lower temperature

employed leads to emissions from fuel cells

being about one tenth of those from gas-

combusting technologies per kWh of fuel

input7. Meanwhile, water electrolysis, the

production method proposed in phase three

provides potential for near zero-carbon

hydrogen generation. This process, in which

an electric current splits water into hydrogen

and oxygen, will only be as carbon intensive

7 H2FC Supergen, 2014. The Role of Hydrogen and Fuel Cells in Providing Affordable, Secure Low-Carbon Heat.

as the electricity. Therefore, the proposed

wind driven system means lifecycle pollution

emissions of hydrogen production will be

incredibly low as wind produces no pollution

during operation.

Transport emissions account for

approximately 25% of all CO2 released in the

UK8. Since 1990, emissions have fallen just

2.4%, lower than any other sector accounted

for. With operating regimes similar to current

petrol and diesel vehicles hydrogen presents

the UK with a substantial opportunity to

reduce carbon emissions in this sector.

HFCEVs can be expected to achieve 75%

lower emissions than their diesel counterparts

by 2030 in accordance with UK H2 Mobility’s

roadmap2. This is based on an assumption

that HFCEVs would require 254,000 tonnes of

hydrogen per year, and this demand would be

met through an approximately 50:50 mix of

water electrolysis and steam methane

reforming. This UK H2 Mobility analysis uses

only production methods which are currently

commercially available, and thus there is the

8 DECC, 2014. 2013 UK Greenhouse Gas Emissions, Provisional Figures and 2012 UK Greenhouse Gas Emissions, Final Figures by Fuel Type and End-User

27

potential for emissions to fall further with

technological developments.

Figure 13 Carbon savings associated with roll out of HFCEVs towards 2050 (UK H2 Mobility, 2013)

The vehicles also provide the benefit of

reducing local pollutants. Measured annual

mean values of nitrogen dioxide, 46% of

which is associated with traffic9, exceeded

annual target values in 38 of 43 geographical

zones of the UK in 201210. The consequences

of vehicular associated air pollution can be

severe. Public Health England11 estimates

29,000 premature deaths are related to long-

term exposure to poor air quality; in some

urban areas, this amounts to 8% of all

mortality. Recent national headlines brought

the issue to public attention as the

Environmental Audit Committee described air

pollution as a public health crisis9.

9 Environmental Audit Committee, 2014. Action on Air Quality 10 Defra, 2014. Updated Projections for Nitrogen Dioxide (NO2) Compliance.

11 Public Health England, 2014. Estimates of mortality in local authority areas associated with air pollution

28

Appendix

1. Data Assumptions

Economic Assumptions

Discount rate 3.5%

GHG emission factors

(kgCO2/MWh)

Source: DEFRA (2014)

Gas 184.97

Electricity 494.26

Oil 272.12

Energy prices (p/kWh)

*Source: DECC (2014)

Gas* 3.15

Electricity (stationary)* 10.52

Electricity (H2 hub=CfD strike price) 9.50

Oil (estimated on $65/bbl) 3.80

Stationary Application Data

Stationary Fuel Cell – based on Doosan Model 400

System size (kWe) 400

Lifetime (years) 10

Capital cost (£/unit) £1,890,000

Fixed operating cost (£/unit/year) £75,600

Doosan FC emission factor (kgCO2/MWh) 476

Heat output (kWh/hour) 454.15

Gas consumption (kWh/hour) 1,172

Hospital counterfactual heating system (source: DECC, 2013)

System size (MW) 4.6

Efficiency (%) 90%

Load factor (%) 89%

Capital cost (£/kW) £103

Fixed operating costs (£/kW/year) £3.31

29

Hydrogen Hub Data

Source: Nicholas and Ogden (2010)

Capital cost for 400 kg/day onsite reformer station (£ millions) 3.40

Capital cost for 1000 kg/day onsite reformer station (£ millions) 5.48

Natural gas feed (kWh/kg H2) 45.754

SMR station H2 compression rate (kWh/kg H2) 3.08

SMR station fixed operating cost (£/year) £237,916

Capital cost for 400 kg/day onsite electrolyser station (£ millions) 3.71

Capital cost for 1000 kg/day onsite electrolyser station (£ millions) 6.54

Electrolysis station fixed operating cost (£/year) £259,680

Capital cost for LH2 refuelling station (£ million) 1.99

LH2 station compression rate (kWh/kg H2) 0.33

LH2 station fixed operating cost (£/year) £218,414

CH2 station fixed operating cost (£/year) £115,066

Pipeline station fixed operating cost (£/year) £156,886

Source: NREL (2014)

Installation factor 1.3

CH2 truck station compressor efficiency 80%

CH2 truck station compressor cost £240,706

CH2 truck station system electricity usage (kWh/kg H2) 1.53

CH2 truck station storage cost £97,482

CH2 truck station dispenser cost (x2) £141,724

CH2 truck station cooling cost £152,972

CH2 truck station electrical cost £30,744

CH2 pipeline station compression cost £781,356

CH2 pipeline station compressor efficiency 65%

CH2 pipeline station system electricity usage (kWh/kg H2) 1.89

CH2 pipeline station low pressure storage costs £187,466

CH2 pipeline station cascade costs £145,473

CH2 pipeline station dispenser costs (x2) £141,724

CH2 pipeline station cooling costs £170,219

Liquefier capital cost £4,574,231

Liquefier capacity (kg/day) 1091

Liquefier electricity needed (kWh/kg H2) 13.27

30

CH2 pipeline capital costs (£/km) £175,021

CH2 pipeline land costs (£/km) £87,593

Source: Hydrogenics (2014) – HySTAT 60 electrolyser

Possible nominal hydrogen flow/unit (Nm3/hour) 60

Water consumption (l/Nm3 H2) 2

Electricity consumption (kWh/Nm3) 4.9

Source: Hexagon Composites (2014)

CH2 tube trailer cost £382,430

CH2 tube trailer size (kg) 616

CH2 tube trailer pressure (bar) 250

2. Levelised Cost Methodology

𝐿𝐶𝑜𝐸 =𝐼 + ∑ (

𝐶𝑡(1 + 𝑟)𝑡

)𝑇𝑡=1

∑ (𝐸𝑡

(1 + 𝑟)𝑡)𝑇

𝑡=1

Where:

I = Initial capital cost

Ct = Operating cost (in year t)

r = Interest rate

Et = Energy generated/used (in year t)

31

3. Case Study 1 – Fuel Cell Installation in Hospitals

A cheaper source of energy

A valuable feature of fuel cells is their ability

to operate efficiently at high load factors and

match the load profile of the buildings they’re

installed in. They thus represent an effective

solution to the energy generation demands of

hospitals. The following analysis will consider

the financial and environmental implications

of the installation of multiple fuel cells

providing baseload generation for an

illustrative hospital (modelled on the Royal

Free Hospital in Hampstead).

Financial modelling based on current market

data suggests that the operation of 11, 400

kWe fuel cells (modelled on the Doosan Model

400) with an auxiliary gas boiler providing the

illustrative hospital with power and heat, is a

lower cost option over the lifetime of the

investment than the use of grid electricity in

conjunction with either a gas or oil boiler

providing heat. Figure A1 below illustrates this

graphically, and shows the respective levelised

cost of energy of each scenario, with the

installation of fuel cells reducing the cost of

energy for the hospital by ~£11.50/MWh

compared to the gas boiler counterfactual

and by ~£15.50/MWh compared to the oil

boiler counterfactual, over the technologies

lifetime (assumed to be 15 years).

£40

£45

£50

£55

£60

£65

£70

£75

£80

Fuel Cells + Auxillary Gas Boiler Grid Electricity + Gas Boiler Grid Electricity + Oil Boiler

Leve

lised

Co

st (

£/M

Wh

)

Figure A1: Levelised Cost of Energy (£/MWh)

Ecuity Economics

32

Over an assumed 10 year lifetime of the

investment, figure A2 below illustrates the

positive return on investment available for the

illustrative hospital. In this scenario where the

fuel cell is providing baseload power for the

site in addition to heat which replaces oil-

fuelled generation, the NPV is in excess of £3

million with a 6% rate of return. The hospital

stands to break even (as illustrated

graphically) just after 7 years following the

initial investment.

Lower emissions

Another benefit of operating a large-scale

stationary fuel cell is the reduction of carbon

emissions. For a private company, public

institution or hospital a precedent exists to

control and where possible lower carbon

emissions. Thus switching from traditional

sources of energy and generation to the

operation of a fuel cell which provides both

power and heat, offers the opportunity to

lower emissions and potentially save money.

Figure A3 below considers the annual carbon

emissions of the hospital under three

scenarios. The first involves the building’s

electricity demand being met by the grid, and

heat demand being serviced by condensing

gas boilers. The second setup considers oil

boilers providing heat. The final scenario

considers the multiple fuel cell and auxiliary

gas boiler scenario. The installation and

operation of stationary fuel cells reduces

annual carbon emissions by 26% compared to

the gas boiler counterfactual and by 35%

compared to the oil boiler counterfactual.

-£25,000,000

-£20,000,000

-£15,000,000

-£10,000,000

-£5,000,000

£0

£5,000,000

£10,000,000

0 1 2 3 4 5 6 7 8 9 10

Period (years)

Figure A2: 11 Doosan 400 PureCell Fuel Cells

Expenditure Energy Bill Savings Cumulative cashflow

Ecuity Economics

33

Figure A4 illustrates these emission savings

graphically. Consider also that hospitals in the

UK are regulated under the EU Emission

Trading Scheme (ETS) and despite being

exempt from having to trade and hold credits,

they are obliged to meet certain specific

emission targets. If the party exceeds their

limit they incur a pecuniary penalty.

There is often a cost to bear when abating

emissions, which as described the hospital

may be obliged to do so. DECC valued the

marginal cost of reducing 1 tCO2 in the non-

traded sector of the EU ETS to be £66 (2015

prices)12. Under classical economic theory

assuming that the MAC is equal to the value

of marginal social damage then this £66/tCO2

could be considered to be equivalent to the

efficient level of carbon tax/permit price. Thus

figure A4 also uses the MAC to provide a

monetary value to the hospital’s annual

carbon emission abatement – which

depending on fuel source counterfactual is

between £400,000 and £620,000 a year.

12 DECC (2012) EU ETS Small Emitter and Hospital Phase III Opt-Out: Impact Assessment. Available from: https://www.gov.uk/government/

0

5000

10000

15000

20000

25000

30000

35000

Fuel Cells + Auxillary Gas Boiler Grid Electricity + Gas Boiler Grid Electricity + Oil Boiler

An

nu

al C

arb

on

Em

issi

on

s (t

CO

2 )

Figure A3: Annual Carbon Emissions

Ecuity Economics

34

Monetising the carbon emission savings also has an impact on the financial attractiveness of the

stationary fuel cell proposition, and as shown in figure A5, reduces the levelised cost for the hospital

by an additional £6 for every MWh of energy consumed over the 15 years modelled.

£0

£90,000

£180,000

£270,000

£360,000

£450,000

£540,000

£630,000

£720,000

0

2000

4000

6000

8000

10000

12000

Grid Electricity + Gas Boiler Grid Electricity + Oil Boiler

Mo

net

ised

An

nu

al C

arb

on

Sav

ings

(£

/yea

r)

An

nu

al E

mis

sio

n S

avin

gs (

tCO

2 /ye

ar)

Counterfactual Technology

Figure A4: Fuel Cell Annual Emission Savings - Compared To Counterfactual

Ecuity Economics

£40

£45

£50

£55

£60

£65

£70

£75

£80

Fuel Cells (with monestisedemission savings) + Gas Boiler

Fuel Cells (without monestisedemission savings) + Gas Boiler

Grid Electricity + Gas Boiler Grid Electricity + Oil Boiler

Leve

lised

Co

st (

£/M

Wh

)

Figure A5: Levelised Cost of Energy (£/MWh)

Ecuity Economics

35

4. Delivery of Hydrogen

Hydrogen has a low volumetric energy density at normal

temperatures and pressures, and therefore is best

transported in a compressed or liquefied state. This gives

three principal options for hydrogen delivery from

production (steam reformer or water electrolysis in our

scenarios) to the refuelling station:

i. Compressed hydrogen transported by tube trailers

ii. Liquefied hydrogen transported by tube trailers

iii. Compressed hydrogen passed through gas pipelines

This analysis considers the use of pipelines to transport

hydrogen as involving the construction and operation of

specialist infrastructure. A separate analysis would be needed

to assess the viability of blending hydrogen with natural gas

in the UK’s existing pipelines. This process would involve

hydrogen separation from natural gas, which requires a

significant investment in capital and the extraction process

can increase costs by £1-£7/kg H21 (depending on production

and delivery method this can be anywhere from 10%-100%

of total cost). It thus remains a prohibitively expensive

delivery method under current low volumes, but could be

considered a potential option in the future given increased

scale of demand and supply.

36

Least Cost Option

Given the SMR mother and daughter model

proposed in phase 2 of the hydrogen hub

roadmap, figure A1 compares the forecourt

cost-price of hydrogen given the three

different delivery methods, from mother to 4

smaller daughter stations. This analysis

assumes no existing infrastructure, and

compares the cost of installation and

operation of the three scenarios. Note that

compressed hydrogen can be transported in

the natural gas pipeline infrastructure, but

requires separation technologies which

command a high upfront capital cost. This

could become an economic form of delivery

in the future given greater volumes.

Table A1 – Cost of Hydrogen CH2 Truck LH2 Truck CH2 Pipeline

Capital & Installation Costs £1.84 £3.24 £3.33

NPV of Operating Costs £3.36 £5.01 £3.60

Total £5.20 £8.25 £6.93

Especially for initial low volumes of hydrogen

production and delivery, compressed

hydrogen trucks will remain the lowest cost

method at £5.20/kg. As illustrated in the

sensitivity analysis below (figures A7, A8 and

A9) compressed gas trucks are in large part

the cheapest current delivery option because

of the modest capital costs involved in

relation to liquefied trucks (liquefiers require

high upfront costs and operating costs) and

compressed gas pipelines.

£0

£1

£2

£3

£4

£5

£6

£7

£8

£9

CH2 Truck LH2 Truck CH2 Pipeline

Co

st o

f H

ydro

gen

(£

/kg)

Figure A6: Comparison of Hydrogen Hub Delivery Methods

Capital & Installation Costs NPV of Operating Costs

Ecuity Economics

37

£3.20 £4.20 £5.20 £6.20 £7.20

Distance (km)

Capex

NPV of opex

Electricity price

Cost of Hydrogen (£/kg H2)

Figure A7: Sensitivity Analysis - CH2 Truck

+20%

-20%

Ecuity Economics

£6.25 £7.25 £8.25 £9.25 £10.25

Distance (km)

Capex

NPV of opex

Electricity price

Cost of Hydrogen (£/kg H2)

Figure A8: Sensitivity Analysis - LH2 Truck

+20%

-20%

Ecuity Economics

£4.93 £5.93 £6.93 £7.93 £8.93

Distance (km)

Capex

NPV of opex

Electricity price

Cost of Hydrogen (£/kg H2)

Figure A9: Sensitivity Analysis - CH2 Pipeline

+20%

-20%

Ecuity Economics

38

5. Case Study 2 – Fuel Cell Material Handling Vehicles (MHVs)

Material handling vehicles (MHVs) are

currently powered by either electric motors or

internal combustion engines. For many indoor

applications electric MHVs are preferred

because of the potential for lower running

costs and zero exhaust emissions. Though

currently more expensive in relation to the

upfront cost of capital, fuel cell MHVs can be

considered a more attractive alternative to

electric MHVs for a number of reasons.

Firstly unlike batteries fuel cells operate

consistently and deliver the required power

level at temperature extremes and in

particular cold conditions (such as in

refrigeration units perhaps)13. In addition

figure A10 illustrates graphically the reduced

refuelling times that a fuel cell powered MHV

(6 minutes per day) enjoys over an electric

alternative (closer to 50 minutes per day).

Consider also that batteries require up to 8

hours cooling time in between change overs,

and the potential for improved productivity

per vehicle (and battery) when operating fuel

cell MHVs is clear.

13 Mansouri, I. & Calay, R, K. (2012) Materials handling vehicles; policy framework for an

emerging fuel cell market. World Hydorgen Energy Conference 2012

0

10

20

30

40

50

60

FC MHV Electric MHV

Min

ute

s p

er v

ehic

le p

er d

ay

Figure A10: Time for refuelling/changing batteries

Source: NREL (2013) http://www.nrel.gov

39

This improved productivity has a financial

bearing on the operation costs associated

with running a fuel cell MHV. Figure A11

utilises data from a US Department of Energy

study on the comparative costs of MHVs to

demonstrate the cost savings that can be

obtained when investing in the fuel cell option

rather than an electric alternative over the

lifetime of the investment14.

14 NREL (2013) U.S. Department of Energy-Funded Performance Validation of Fuel Cell Material

Handling Equipment. Available from: http://www.nrel.gov

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

FC MHV Electric MHV

Figure A11: NPV of MHVs (US$)

NPV of capital costs NPV of operating costs

Source: NREL (2013) http://www.nrel.gov

40

Turning energy policy insights into commercial results This report has been produced by Ecuity Consulting LLP on behalf

of Johnson Matthey Fuel Cells to develop a hydrogen economy

vision in the UK and promote the company’s role as a driver for

positive change to making this reality.

Ecuity’s mission is to make sustainable energy mainstream by using

our unique strategic insight to connect the commercial day to day

reality of running a business and the political challenges of

sustainable energy policy making.

Ecuity Consulting LLP ǀ Radcliffe House ǀ Blenheim Court ǀ

Solihull ǀ B91 2AA T: +44 (0) 121 709 5587 ǀ E

info@ecuity.com ǀ www.ecuity.com