A VISION FOR THE UK HYDROGEN ECONOMY - Ecuity · a vision for the uk hydrogen economy supporting...
Transcript of A VISION FOR THE UK HYDROGEN ECONOMY - Ecuity · a vision for the uk hydrogen economy supporting...
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
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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.
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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
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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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£0
£10
£20
£30
£40
£50
£60
£70
£80
£90
£100
0
2
4
6
8
10
12
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
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