For Dunbar Local Energy Innovation Consortium by 2030.* ... • Proton exchange membrane (PEM)...
Transcript of For Dunbar Local Energy Innovation Consortium by 2030.* ... • Proton exchange membrane (PEM)...
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Dunbar water electrolyser feasibility studyFor Dunbar Local Energy Innovation Consortium
Phase 3 report
May 2015
Michael Dolman
Ben Madden
Element Energy Limited
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• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
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Background: a feasibility study to investigate the potential for
electrolysis to contribute to the resolution of local energy issues
Background
• Sustaining Dunbar, together with Community Energy Scotland, has formed the Dunbar
Local Energy Innovation Consortium to explore innovative solutions to local energy issues.
• With over 100 wind turbines installed in the Dunbar area (and more planned), high levels
of wind generation have taken up all the capacity at many grid supply points.
• This is likely to lead to curtailment of renewable generation, which is a lost opportunity in
terms of renewable electricity supply and can undermine the case for further investment in
local renewable generators.
• The production of hydrogen via water electrolysis could offer benefits in terms of reduced
curtailment and increased use of local renewable energy. Element Energy was appointed
to assess the technical and economic feasibility of installing and operating a water
electrolyser in the Dunbar area.
Project
drivers
The primary objectives of any water electrolyser deployment project in Dunbar include:
Expand the potential to meet local energy needs from local resources.
Facilitate increased deployment of renewable generators and reduce the dependence of
local communities on fossil fuels (e.g. heating oil).
Explore the potential for community engagement and an on-going stake in energy
storage.
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Issue
High levels of renewable electricity generation (mainly wind power) relative to capacity
of local electricity network, leading to the possibility of increased curtailed renewable
generation with increased connections. Issues expected on the transmission and
distribution networks.
Organisations &
funding
Background work
The Dunbar Local Energy Innovation Consortium identified a number of potential uses
for hydrogen (commercial heat, pure hydrogen network, power-to-gas, district heating
with hydrogen boiler), which formed the starting point for this study.
Broader context
CES is involved in an SP Energy Networks-led project that is seeking to resolve some
of the issues associated with high levels of renewable electricity generation. The
Accelerating Renewable Connections project is supported by the Low Carbon
Networks Fund (see below).
Electricity grid upgrades are planned for the early 2020s and would be expected to
alleviate the curtailment issues, at least in the near term. However, there is a risk that
the upgrades will be delayed / cancelled.
Context: this study builds on preliminary work undertaken by the
Dunbar Local Energy Innovation Consortium
CARES: Community And Renewable Energy Scheme, LES: Local Energy Scotland, CES: Community Energy
Scotland.
Infrastructure &
innovation fundCARES, managed by LES
Dunbar Local Energy Innovation Consortium
+
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Accelerating Renewable Connections (ARC) –
project summary
See also: www.spenergynetworks.co.uk/pages/arc_accelerating_renewable_connections.asp.
Budget £7.4m
Duration Jan. 2013 – Dec. 2016
Geographic scope: East Lothian &
Borders
Solutions being implemented
Active Network
Management
(ANM)
• Real-time monitoring and control of
networks.
• Ability to send signals to generators to
request reduced output.
• This allows better use of existing assets.
Curtailment
analysis tool
• Online tool to allow assessment of potential
curtailment and costs of connection.
• Expected to be available from April 2015.
Two stage
commercial
agreements
• Novel arrangements that permit new
connections (non-firm ANM-based initially,
with a bridge to a full firm connection once
grid upgrades have been completed).
Project objectives
• Improve access to connect generators – allow connections
around constraints.
• Reduce time (and cost) of connection.
Implications for Dunbar water electrolyser feasibility study
• The local distribution network operator (SPEN) is being proactive in investigating solutions to a lack
of network capacity.
• SPEN is willing to consider innovative solutions (e.g. virtual private wire) that could improve the
case for installing a water electrolyser.
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• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
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• The global market for hydrogen is well developed (e.g. for ammonia and methanol
production, crude oil refining, unsaturated fat hydrogenation) with annual production
equating to 1.5% of global primary energy use.*
• There is now increasing use of hydrogen as an energy vector across a range of
applications, including transport, energy storage, electricity and heat generation.
There is increasing interest in hydrogen as a clean energy vector
that may provide economic, social and environmental benefits
* Global annual energy consumption = 104 PWh (IEA, 2011), global annual hydrogen production = 50 million
tonnes (NREL, 2013), H2 LHV = 33 kWh/kg.
Energy
security
Future
economic
growth
Climate change
and the
environment
Low carbon
economy
Numerous H2 production pathways can contribute towards de-risking future
energy-supply.
Locally produced fuel can provide significant balance of payment benefits.
Developing early supply chains / skills in the H2 sector can prepare regions for
export as the technology becomes widespread.
H2 vehicles only emit water, therefore increased use of the H2 in vehicles leads to
improved air quality, particularly when used in urban centres.
H2 can be produced directly from renewables, thereby contributing significantly to
reducing CO2 emissions.
H2 generation via electrolysis can create a flexible load for the electricity grid,
enabling energy storage and grid balancing.
This will help facilitate increased penetration of intermittent of renewable
generation thereby supporting the Scottish Government’s target to generate the
equivalent of 100% of Scotland’s electricity demand from renewables by 2020.
Re
leva
nt
Sc
ott
ish
po
lic
y d
rive
rs f
or
H2
Areas of the H2 supply chain (e.g. high pressure gas handling) will provide suitable
demand for Scotland’s skills and knowledge honed from the oil & gas sector.
Skills
diversification
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Globally several emerging hydrogen technologies are receiving
increased attention as alternative energy solutions
* Clean Energy Patent Growth Index 2013 Year in Review.
** Comparison of fuel cell technologies, DoW (2014) and DUKES (2013)
Most prominent early sectors for hydrogen as an energy vector
Transport Distributed generation Power-to-gas
Eliminate CO2 and air quality
impacts associated with fossil
fuel vehicle emissions – EU
proposes a 40% CO2 emission
reduction by 2030.*
Increase vehicle fuel
consumption efficiency – Internal
combustion engines have
efficiencies of 20–35% compared
to up to 60% for fuel cells.
Increase power supply reliability,
flexibility and upgradability.
Highly efficient FC power
generation – c.60% FC efficiency
vs 40% for centralised generation
(further 6% lost from
transmission and distribution).**
Help integrate intermittent
renewables into the grid by
producing H2 at times of high
generation but low demand.
Create seasonal energy storage
reserves – existing
electrochemical technologies are
suited to minutes/days of storage
duration.
Ballard Power Systems’ 1MW
CLEARgen fuel cell at Toyota’s USA HQ
in California
Large stationary fuel cell unit for off-grid
electricity generation using H2 feedstock.
Hyundai ix35 Fuel Cell
First generation fuel cell electric vehicle,
achieves mileage comparable to
conventional cars but with zero tailpipe
emissions.
E-ON’s 2 MW power-2-gas facility in
Falkenhagen, Germany
Water electrolyser units to generate H2
for injection into existing regional natural
gas transmission system.
Drivers
Relevance
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The hydrogen sector is complex and links a range of energy
sources and end uses
Hydrogen production*
Hydrogen storage,
distribution and
dispensing
Hydrogen injection into
the natural gas grid
Power and / or heat
generation
Mobility
High temperature fuel
Chemical
Domestic / commercial heating or CHP
Grid balancing
Back-up and portable power
Passenger and fleet vehicles
Buses and coaches
Boats
Industry
Chemical and refinery industry
Local / national gas grid
Methane
H2
H2
H2
H2
H2
Electricity
Hydrocarbons
Carbon Capture and
Storage
CO2 (if any)
Methanation
(synthetic methane)
Methane
Material handling and specialty vehicles
* Hydrogen can be produced via a range of
processes, including reforming fossil fuels (e.g.
SMR), gasification (of coal / biomass),
thermochemical processes, and electrolytic
processes. The focus of this study is electrolysis
and an overview of the technology is given below.
SMR = Steam Methane Reforming.
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Water electrolysis (WE) is an electrochemical process that converts water into hydrogen and oxygen.
Electricity can be used to split water via the following process:
• Oxidation of water at the (positive) anode: 2𝐻2𝑂(𝑙) → 𝑂2(𝑔) + 4𝐻+ + 4𝑒−
• Reduction of protons at the (negative) cathode: 2𝐻+ + 2𝑒− → 𝐻2(𝑔)
• Overall: 2𝐻2𝑂(𝑙) → 𝑂2(𝑔) + 2𝐻2(𝑔)
The majority of global hydrogen production is from methane (via steam methane reforming (SMR)),
which is typically carried out at large scale and produces relatively low cost hydrogen. However, there
is increasing interest in water electrolysis as a source of low carbon hydrogen (using renewable
electricity in WE leads to zero carbon hydrogen). Furthermore, electrolysers can provide a very flexible
and responsive demand for electricity, thereby helping balance supply and demand, which is
particularly valuable on grids with increasing penetration of intermittent renewable generators.
The three types of electrolyser technology currently available as commercial products are:
• Alkaline electrolysers (liquid electrolyte) – forms the majority of the currently installed capacity.
• Proton exchange membrane (PEM) electrolysers (solid polymer electrolyte, typically Nafion) –
commercially available for around ten years.
• Anion exchange membrane (AEM) electrolysers – new to market (currently one supplier).
Solid oxide electrolysis (SOE) is at an R&D stage (not commercially available). SOE operates at
significantly higher temperatures than other types of WE (500–850oC), and the technology offers the
promise of reduced cost and increased efficiency relative to today’s technology.
Water electrolysis – introduction
Overview of water electrolysis
Electrolyser types
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Water electrolyser types – a comparison of technical & economic
characteristics
Source: Study on development of water electrolysis in the EU, E4Tech and Element Energy for the Fuel Cells
and Hydrogen Joint Undertaking (February 2014); conversations with suppliers in early 2015.
Alkaline Proton exchange membrane
Development status CommercialCommercial (small to medium scale,
<300kW)
System size range1.8 – 6,000 kW
0.25 – 760 Nm3/hr
0.2 – 1,150 kW
0.01 – 240 Nm3/hr
Hydrogen purity 99.5% – 99.9998% 99.9% – 99.9999%
Indicative system capex for MW-scale
systems*c. £1,500/kW c. £1,000 – 2,500/kW
Indicative system fixed annual opex** (£/yr) 2% – 5% of capex 2% – 5% of capex
Indicative system efficiency (nominal at full
load)50 – 73 kWh/kgH2 47 – 73 kWh/kgH2
Pressurisation 10 – 30 bar 20 – 50 bar
Operating range (turn-down ratio) Typically 20% to 100% Idle to 100%
Response time
Black start: c.30 mins
Start from standby <1 min (reduced
efficiency for 15–20 mins), rapid
modulation
Black start: <10 mins
Start from standby <1 min
Modulation time <1 sec
* Indicative capital costs based on budgetary figures from suppliers. These costs are for the electrolyser equipment only and
exclude installation (site preparation, electrical connections, hydrogen storage, planning fees, project management, etc.). Costs
include purification equipment to allow production of fuel cell quality hydrogen. Further information on capex is presented below.
** Operational costs include planned & unplanned maintenance but exclude electricity costs.
Both capex and opex are a function of plant size and a range of other factors.
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Current capital costs of water electrolysis systems are in the
region £1,500/kW+, but expected to reduce over the coming years
Indicative capital costs for water electrolyser systems by type and scale • This graph shows ranges of
indicative capital costs (equipment
only) for water electrolysers.
• The figures are based on budgetary
prices from a range of suppliers
collected during 2014/15.
• The data include prices for
commercially available systems (up
to low MW scale), and target
prices for multi-MW scale
systems under development.
• For reference, the FCH JU target
capex values for electrolysers
allowing hydrogen production from
renewable electricity for energy
storage and grid balancing are*:
– £1,240/kW (2017)
– £710/kW (2020)
– £550/kW (2023)
Figures for larger systems based on
targets (products under development)
Notes
• Costs are for complete electrolyser systems (including purification
equipment) producing hydrogen at 10–35 bar.
• Exclusions: site preparation, permitting, shipping, installation,
commissioning, VAT.
• Budgetary figures converted from euros using 1.3 euro/GPB.
• Ranges shown for sizes where multiple quotations were available, “X”
indicates only one data point.
Source: Budgetary figures from suppliers. Note that the per-kW costs of small scale systems (e.g. tens of
kilowatts) can be significantly higher than the figures presented here.
* Source: FCH JU Multi Annual Work Plan (ID623483),
2014. Converted from euros at 1.3 euro per GBP.
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Supplier Location Example products Relevant experience
HQ in Canada,
manufacturing
in Germany &
Belgium
HySTAT 60
52–130kgH2/day
480 kVA
First generation HySTAT products
launched in 2001. Over 1,800 projects
in >100 countries.*
HQ in France,
presence in
Germany & Italy
Range of sizes
(2.8kW–63kW)
Large (MW-scale)
units available
Global installation of >3,000
electrolysers (mostly small scale).
6MW system installed at Audi plant in
N. Germany, 0.5MW system as part of
hydrogen refuelling station in Berlin.
HQ in
Notodden,
Norway
NEL A150
100–1,000kgH2/day
220kW–2MW
Hundreds of installations in >50
countries over the past four decades.
Unst, Shetland,
Scotland
PureH2 series
Up to 90kgH2/day
230kW
Large systems
also available
Engineering and consultancy company
that offers design and project
management services for electrolyser
systems and other clean energy
technologies.
Alkaline water electrolyser suppliers
Source: company websites, personal communication.
* www.hydrogenics.com/docs/default-source/pdf/renewable-projects-references---grid-balancing-and-ptg.pdf?sfvrsn=0
Note: Pure Energy Systems act as an integrator, they are not an electrolyser OEM.
Selection of suppliers
(non-exhaustive)
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Supplier Location Example products Relevant experience
Part of Smart
Energies,
France
E series (E5 to E60)
c. 260kW, modular
Involved in demonstration projects in
hydrogen mobility, autonomous site
backup and renewable energy storage.
HQ in Canada,
manufacturing
in Germany &
Belgium
HyLYZER
Modular PEM WE
Small scale (c.4kgH2/day)
Larger scale
pilots underway
1MW PEM power-to-gas facility in
Hamburg (under construction in 2014).
Plans for a 2MW system in Toronto.
HQ in Sheffield,
UK
HGas
25–462kgH2/day
70–1,030kW
Thüga power-to-gas plant, Frankfurt,
Germany (WE at hundreds of kW
scale).
Wallingford,
USA
M-series (MW-scale)
Smaller units
available
M-series is a new addition. Proton
OnSite has installed >2,000 PEM WE
systems in >75 countries.*
Germany
SILYZER200
1.25MW
From Q2 2015
Four SILYZER100 (100kW) units sold
to date, now discontinued to focus on
MW-scale systems.
Proton exchange membrane (PEM) water
electrolyser suppliers
Source: company websites.* http://fuelcellsworks.com/news/2015/01/14/proton-onsite-introduces-worlds-first-pem-megawatt-electrolyzer-for-the-growing-global-energy-storage-market/
Selection of suppliers
(non-exhaustive)
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• Cost of hydrogen production can be calculated by annualising the costs of installing and running
an electrolyser and normalising with respect to the quantity of hydrogen produced.
• The result is often expressed as £/kgH2, which can be converted into £/MWh, as shown on the
following slides (lower heating value of H2 = 33.3kWh/kg).
We can calculate the cost of producing electrolytic hydrogen for
comparison against incumbent fuels
* NB: Electrolyser costs are expected to fall with technology development and increasing deployment over the
coming years.
Water electrolysis economics
Modelling assumptions
Metric Value Notes
Capital cost*Results for a range from
£500/kW to £2,000/kW
Capex depends on technology type, system scale, etc. The key figures is the
fully installed and commissioned system cost. Output hydrogen characteristics
(oxygen content, water content, pressure etc.) affect the capex.
Annual
operating cost2% of capex
This is at the lower end of allowances typically quoted by suppliers. A full
service package could by c.5% of capex per year.
System
efficiency57 kWh/kg Electricity input per kilogram of hydrogen produced.
Load factor 90%Baseline results are for a well utilised electrolyser, with sensitivity testing to
show the impact of lower annual run hours.
Economic
assumptions7%, 15 years Capital costs amortised at 7% over a 15 year period.
Electricity
price
Range from –£20 to +£100
per MWh
This value represents the net electricity price to the electrolyser averaged over
the year (negative price = WE being paid to run).
Other
assumptions
Water consumption of 40
litres/kgH2, price of 0.1p/litre
In terms of variable opex, the cost of water is generally very low compared to
electricity costs, but included for completeness.
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WE capex (£/kW)
125 500
550
600
650
700
750
800
850
900
950
1,00
0
1,05
0
1,10
0
1,15
0
1,20
0
1,25
0
1,30
0
1,35
0
1,40
0
1,45
0
1,50
0
1,55
0
1,60
0
1,65
0
1,70
0
1,75
0
1,80
0
1,85
0
1,90
0
1,95
0
2,00
0
-20 -19.1 -17.7 -16.3 -14.8 -13.4 -12.0 -10.6 -9.2 -7.7 -6.3 -4.9 -3.5 -2.1 -0.6 0.8 2.2 3.6 5.1 6.5 7.9 9.3 10.7 12.2 13.6 15.0 16.4 17.9 19.3 20.7 22.1 23.5
-15 -10.5 -9.1 -7.6 -6.2 -4.8 -3.4 -1.9 -0.5 0.9 2.3 3.7 5.2 6.6 8.0 9.4 10.8 12.3 13.7 15.1 16.5 18.0 19.4 20.8 22.2 23.6 25.1 26.5 27.9 29.3 30.8 32.2
-10 -1.8 -0.4 1.0 2.4 3.8 5.3 6.7 8.1 9.5 11.0 12.4 13.8 15.2 16.6 18.1 19.5 20.9 22.3 23.8 25.2 26.6 28.0 29.4 30.9 32.3 33.7 35.1 36.5 38.0 39.4 40.8
-5 6.8 8.2 9.6 11.1 12.5 13.9 15.3 16.7 18.2 19.6 21.0 22.4 23.9 25.3 26.7 28.1 29.5 31.0 32.4 33.8 35.2 36.7 38.1 39.5 40.9 42.3 43.8 45.2 46.6 48.0 49.4
0 15.4 16.9 18.3 19.7 21.1 22.5 24.0 25.4 26.8 28.2 29.6 31.1 32.5 33.9 35.3 36.8 38.2 39.6 41.0 42.4 43.9 45.3 46.7 48.1 49.6 51.0 52.4 53.8 55.2 56.7 58.1
5 24.1 25.5 26.9 28.3 29.8 31.2 32.6 34.0 35.4 36.9 38.3 39.7 41.1 42.6 44.0 45.4 46.8 48.2 49.7 51.1 52.5 53.9 55.3 56.8 58.2 59.6 61.0 62.5 63.9 65.3 66.7
10 32.7 34.1 35.5 37.0 38.4 39.8 41.2 42.7 44.1 45.5 46.9 48.3 49.8 51.2 52.6 54.0 55.5 56.9 58.3 59.7 61.1 62.6 64.0 65.4 66.8 68.2 69.7 71.1 72.5 73.9 75.4
15 41.3 42.8 44.2 45.6 47.0 48.4 49.9 51.3 52.7 54.1 55.6 57.0 58.4 59.8 61.2 62.7 64.1 65.5 66.9 68.4 69.8 71.2 72.6 74.0 75.5 76.9 78.3 79.7 81.1 82.6 84.0
20 50.0 51.4 52.8 54.2 55.7 57.1 58.5 59.9 61.4 62.8 64.2 65.6 67.0 68.5 69.9 71.3 72.7 74.1 75.6 77.0 78.4 79.8 81.3 82.7 84.1 85.5 86.9 88.4 89.8 91.2 92.6
25 58.6 60.0 61.5 62.9 64.3 65.7 67.1 68.6 70.0 71.4 72.8 74.3 75.7 77.1 78.5 79.9 81.4 82.8 84.2 85.6 87.0 88.5 89.9 91.3 92.7 94.2 95.6 97.0 98.4 99.8 101.3
30 67.2 68.7 70.1 71.5 72.9 74.4 75.8 77.2 78.6 80.0 81.5 82.9 84.3 85.7 87.2 88.6 90.0 91.4 92.8 94.3 95.7 97.1 98.5 99.9 101.4 102.8 104.2 105.6 107.1 108.5 109.9
35 75.9 77.3 78.7 80.2 81.6 83.0 84.4 85.8 87.3 88.7 90.1 91.5 92.9 94.4 95.8 97.2 98.6 100.1 101.5 102.9 104.3 105.7 107.2 108.6 110.0 111.4 112.9 114.3 115.7 117.1 118.5
40 84.5 85.9 87.4 88.8 90.2 91.6 93.1 94.5 95.9 97.3 98.7 100.2 101.6 103.0 104.4 105.8 107.3 108.7 110.1 111.5 113.0 114.4 115.8 117.2 118.6 120.1 121.5 122.9 124.3 125.8 127.2
45 93.2 94.6 96.0 97.4 98.8 100.3 101.7 103.1 104.5 106.0 107.4 108.8 110.2 111.6 113.1 114.5 115.9 117.3 118.8 120.2 121.6 123.0 124.4 125.9 127.3 128.7 130.1 131.5 133.0 134.4 135.8
50 101.8 103.2 104.6 106.1 107.5 108.9 110.3 111.7 113.2 114.6 116.0 117.4 118.9 120.3 121.7 123.1 124.5 126.0 127.4 128.8 130.2 131.7 133.1 134.5 135.9 137.3 138.8 140.2 141.6 143.0 144.4
55 110.4 111.9 113.3 114.7 116.1 117.5 119.0 120.4 121.8 123.2 124.6 126.1 127.5 128.9 130.3 131.8 133.2 134.6 136.0 137.4 138.9 140.3 141.7 143.1 144.6 146.0 147.4 148.8 150.2 151.7 153.1
60 119.1 120.5 121.9 123.3 124.8 126.2 127.6 129.0 130.4 131.9 133.3 134.7 136.1 137.6 139.0 140.4 141.8 143.2 144.7 146.1 147.5 148.9 150.3 151.8 153.2 154.6 156.0 157.5 158.9 160.3 161.7
65 127.7 129.1 130.5 132.0 133.4 134.8 136.2 137.7 139.1 140.5 141.9 143.3 144.8 146.2 147.6 149.0 150.5 151.9 153.3 154.7 156.1 157.6 159.0 160.4 161.8 163.2 164.7 166.1 167.5 168.9 170.4
70 136.3 137.8 139.2 140.6 142.0 143.4 144.9 146.3 147.7 149.1 150.6 152.0 153.4 154.8 156.2 157.7 159.1 160.5 161.9 163.4 164.8 166.2 167.6 169.0 170.5 171.9 173.3 174.7 176.1 177.6 179.0
75 145.0 146.4 147.8 149.2 150.7 152.1 153.5 154.9 156.4 157.8 159.2 160.6 162.0 163.5 164.9 166.3 167.7 169.1 170.6 172.0 173.4 174.8 176.3 177.7 179.1 180.5 181.9 183.4 184.8 186.2 187.6
80 153.6 155.0 156.5 157.9 159.3 160.7 162.1 163.6 165.0 166.4 167.8 169.3 170.7 172.1 173.5 174.9 176.4 177.8 179.2 180.6 182.0 183.5 184.9 186.3 187.7 189.2 190.6 192.0 193.4 194.8 196.3
85 162.2 163.7 165.1 166.5 167.9 169.4 170.8 172.2 173.6 175.0 176.5 177.9 179.3 180.7 182.2 183.6 185.0 186.4 187.8 189.3 190.7 192.1 193.5 194.9 196.4 197.8 199.2 200.6 202.1 203.5 204.9
90 170.9 172.3 173.7 175.2 176.6 178.0 179.4 180.8 182.3 183.7 185.1 186.5 187.9 189.4 190.8 192.2 193.6 195.1 196.5 197.9 199.3 200.7 202.2 203.6 205.0 206.4 207.9 209.3 210.7 212.1 213.5
95 179.5 180.9 182.4 183.8 185.2 186.6 188.1 189.5 190.9 192.3 193.7 195.2 196.6 198.0 199.4 200.8 202.3 203.7 205.1 206.5 208.0 209.4 210.8 212.2 213.6 215.1 216.5 217.9 219.3 220.8 222.2
100 188.2 189.6 191.0 192.4 193.8 195.3 196.7 198.1 199.5 201.0 202.4 203.8 205.2 206.6 208.1 209.5 210.9 212.3 213.8 215.2 216.6 218.0 219.4 220.9 222.3 223.7 225.1 226.5 228.0 229.4 230.8
Hydrogen production cost < £50/MWh £50–100/MWh £100–150/MWh >£150/MWh
Net
ele
c.
pri
ce (
£/M
Wh
)
Cost of hydrogen produced is sensitive to electrolyser capex and
electricity price (among other factors)
NOTE: the “equivalent” lines above are illustrative only – figures on the diagram and “equivalent” £/MWh values
are not necessarily directly comparable. Source: Element Energy.
Plot of hydrogen cost (expressed as £/MWh) as a function of electrolyser capex and net electricity
price for a fully 90% utilised electrolyser
Increasing water electrolyser capital cost
Incre
asin
g n
et e
lectric
ity p
rice
Gas heating equivalent (c. £40/MWh)
Oil heating equivalent (c. £35–55/MWh)
Electric heating equivalent (c. £120/MWh)
Access to low cost electricity is a key factor in developing an economically sustainable hydrogen
production system using water electrolysis.
Transport equivalent (c. £165/MWh)Based on 115p/litre diesel cost, 40mpg and 80km/kgH2 FCEV
Wholesale gas + RHI (c. £90/MWh)
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WE capex (£/kW)
154 500
550
600
650
700
750
800
850
900
950
1,00
0
1,05
0
1,10
0
1,15
0
1,20
0
1,25
0
1,30
0
1,35
0
1,40
0
1,45
0
1,50
0
1,55
0
1,60
0
1,65
0
1,70
0
1,75
0
1,80
0
1,85
0
1,90
0
1,95
0
2,00
0
-20 -7.7 -5.2 -2.6 -0.1 2.5 5.1 7.6 10.2 12.7 15.3 17.9 20.4 23.0 25.5 28.1 30.6 33.2 35.8 38.3 40.9 43.4 46.0 48.6 51.1 53.7 56.2 58.8 61.4 63.9 66.5 69.0
-15 0.9 3.5 6.0 8.6 11.1 13.7 16.3 18.8 21.4 23.9 26.5 29.0 31.6 34.2 36.7 39.3 41.8 44.4 47.0 49.5 52.1 54.6 57.2 59.8 62.3 64.9 67.4 70.0 72.6 75.1 77.7
-10 9.5 12.1 14.7 17.2 19.8 22.3 24.9 27.4 30.0 32.6 35.1 37.7 40.2 42.8 45.4 47.9 50.5 53.0 55.6 58.2 60.7 63.3 65.8 68.4 71.0 73.5 76.1 78.6 81.2 83.8 86.3
-5 18.2 20.7 23.3 25.8 28.4 31.0 33.5 36.1 38.6 41.2 43.8 46.3 48.9 51.4 54.0 56.6 59.1 61.7 64.2 66.8 69.4 71.9 74.5 77.0 79.6 82.1 84.7 87.3 89.8 92.4 94.9
0 26.8 29.4 31.9 34.5 37.0 39.6 42.2 44.7 47.3 49.8 52.4 55.0 57.5 60.1 62.6 65.2 67.8 70.3 72.9 75.4 78.0 80.5 83.1 85.7 88.2 90.8 93.3 95.9 98.5 101.0 103.6
5 35.4 38.0 40.6 43.1 45.7 48.2 50.8 53.4 55.9 58.5 61.0 63.6 66.2 68.7 71.3 73.8 76.4 78.9 81.5 84.1 86.6 89.2 91.7 94.3 96.9 99.4 102.0 104.5 107.1 109.7 112.2
10 44.1 46.6 49.2 51.8 54.3 56.9 59.4 62.0 64.6 67.1 69.7 72.2 74.8 77.3 79.9 82.5 85.0 87.6 90.1 92.7 95.3 97.8 100.4 102.9 105.5 108.1 110.6 113.2 115.7 118.3 120.9
15 52.7 55.3 57.8 60.4 63.0 65.5 68.1 70.6 73.2 75.7 78.3 80.9 83.4 86.0 88.5 91.1 93.7 96.2 98.8 101.3 103.9 106.5 109.0 111.6 114.1 116.7 119.3 121.8 124.4 126.9 129.5
20 61.4 63.9 66.5 69.0 71.6 74.1 76.7 79.3 81.8 84.4 86.9 89.5 92.1 94.6 97.2 99.7 102.3 104.9 107.4 110.0 112.5 115.1 117.7 120.2 122.8 125.3 127.9 130.5 133.0 135.6 138.1
25 70.0 72.5 75.1 77.7 80.2 82.8 85.3 87.9 90.5 93.0 95.6 98.1 100.7 103.3 105.8 108.4 110.9 113.5 116.1 118.6 121.2 123.7 126.3 128.8 131.4 134.0 136.5 139.1 141.6 144.2 146.8
30 78.6 81.2 83.7 86.3 88.9 91.4 94.0 96.5 99.1 101.7 104.2 106.8 109.3 111.9 114.5 117.0 119.6 122.1 124.7 127.2 129.8 132.4 134.9 137.5 140.0 142.6 145.2 147.7 150.3 152.8 155.4
35 87.3 89.8 92.4 94.9 97.5 100.1 102.6 105.2 107.7 110.3 112.9 115.4 118.0 120.5 123.1 125.6 128.2 130.8 133.3 135.9 138.4 141.0 143.6 146.1 148.7 151.2 153.8 156.4 158.9 161.5 164.0
40 95.9 98.5 101.0 103.6 106.1 108.7 111.3 113.8 116.4 118.9 121.5 124.0 126.6 129.2 131.7 134.3 136.8 139.4 142.0 144.5 147.1 149.6 152.2 154.8 157.3 159.9 162.4 165.0 167.6 170.1 172.7
45 104.5 107.1 109.7 112.2 114.8 117.3 119.9 122.4 125.0 127.6 130.1 132.7 135.2 137.8 140.4 142.9 145.5 148.0 150.6 153.2 155.7 158.3 160.8 163.4 166.0 168.5 171.1 173.6 176.2 178.8 181.3
50 113.2 115.7 118.3 120.8 123.4 126.0 128.5 131.1 133.6 136.2 138.8 141.3 143.9 146.4 149.0 151.6 154.1 156.7 159.2 161.8 164.4 166.9 169.5 172.0 174.6 177.1 179.7 182.3 184.8 187.4 189.9
55 121.8 124.4 126.9 129.5 132.0 134.6 137.2 139.7 142.3 144.8 147.4 150.0 152.5 155.1 157.6 160.2 162.8 165.3 167.9 170.4 173.0 175.5 178.1 180.7 183.2 185.8 188.3 190.9 193.5 196.0 198.6
60 130.4 133.0 135.6 138.1 140.7 143.2 145.8 148.4 150.9 153.5 156.0 158.6 161.2 163.7 166.3 168.8 171.4 173.9 176.5 179.1 181.6 184.2 186.7 189.3 191.9 194.4 197.0 199.5 202.1 204.7 207.2
65 139.1 141.6 144.2 146.8 149.3 151.9 154.4 157.0 159.6 162.1 164.7 167.2 169.8 172.3 174.9 177.5 180.0 182.6 185.1 187.7 190.3 192.8 195.4 197.9 200.5 203.1 205.6 208.2 210.7 213.3 215.9
70 147.7 150.3 152.8 155.4 158.0 160.5 163.1 165.6 168.2 170.7 173.3 175.9 178.4 181.0 183.5 186.1 188.7 191.2 193.8 196.3 198.9 201.5 204.0 206.6 209.1 211.7 214.3 216.8 219.4 221.9 224.5
75 156.4 158.9 161.5 164.0 166.6 169.1 171.7 174.3 176.8 179.4 181.9 184.5 187.1 189.6 192.2 194.7 197.3 199.9 202.4 205.0 207.5 210.1 212.7 215.2 217.8 220.3 222.9 225.5 228.0 230.6 233.1
80 165.0 167.5 170.1 172.7 175.2 177.8 180.3 182.9 185.5 188.0 190.6 193.1 195.7 198.3 200.8 203.4 205.9 208.5 211.1 213.6 216.2 218.7 221.3 223.8 226.4 229.0 231.5 234.1 236.6 239.2 241.8
85 173.6 176.2 178.7 181.3 183.9 186.4 189.0 191.5 194.1 196.7 199.2 201.8 204.3 206.9 209.5 212.0 214.6 217.1 219.7 222.2 224.8 227.4 229.9 232.5 235.0 237.6 240.2 242.7 245.3 247.8 250.4
90 182.3 184.8 187.4 189.9 192.5 195.1 197.6 200.2 202.7 205.3 207.9 210.4 213.0 215.5 218.1 220.6 223.2 225.8 228.3 230.9 233.4 236.0 238.6 241.1 243.7 246.2 248.8 251.4 253.9 256.5 259.0
95 190.9 193.5 196.0 198.6 201.1 203.7 206.3 208.8 211.4 213.9 216.5 219.0 221.6 224.2 226.7 229.3 231.8 234.4 237.0 239.5 242.1 244.6 247.2 249.8 252.3 254.9 257.4 260.0 262.6 265.1 267.7
100 199.5 202.1 204.7 207.2 209.8 212.3 214.9 217.4 220.0 222.6 225.1 227.7 230.2 232.8 235.4 237.9 240.5 243.0 245.6 248.2 250.7 253.3 255.8 258.4 261.0 263.5 266.1 268.6 271.2 273.8 276.3
Hydrogen production cost < £50/MWh £50–100/MWh £100–150/MWh >£150/MWh
Net
ele
c.
pri
ce (
£/M
Wh
)
Reducing electrolyser load factor will tend to increase the cost of
hydrogen, particularly for high capital cost systems
Source: Element Energy.
Plot of hydrogen cost (expressed as £/MWh) as a function of electrolyser capex and net electricity
price for a 50% utilised electrolyser
Increasing water electrolyser capital cost
Incre
asin
g n
et e
lectric
ity p
rice
The range (in terms of electricity price / WE capex values) in which hydrogen is cost competitive
shrinks with decreasing utilisation (unless some other source of revenue becomes available).
Gas heating equivalent (c. £40/MWh)
Oil heating equivalent (c. £35–55/MWh)
Wholesale gas + RHI (c. £90/MWh)
Electric heating equivalent (c. £120/MWh)
Transport equivalent (c. £165/MWh)Based on 115p/litre diesel cost, 40mpg and 80km/kgH2 FCEV
18
Electricity price (£/MWh) @ 1,500 £/kW
130 -20
-15
-10
-5 0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100
100% 5.1 13.7 22.3 31.0 39.6 48.2 56.9 65.5 74.1 82.8 91.4 100.1 108.7 117.3 126.0 134.6 143.2 151.9 160.5 169.1 177.8 186.4 195.1 203.7 212.3
90% 9.3 18.0 26.6 35.2 43.9 52.5 61.1 69.8 78.4 87.0 95.7 104.3 113.0 121.6 130.2 138.9 147.5 156.1 164.8 173.4 182.0 190.7 199.3 208.0 216.6
80% 14.7 23.3 31.9 40.6 49.2 57.8 66.5 75.1 83.7 92.4 101.0 109.7 118.3 126.9 135.6 144.2 152.8 161.5 170.1 178.7 187.4 196.0 204.7 213.3 221.9
70% 21.5 30.1 38.8 47.4 56.1 64.7 73.3 82.0 90.6 99.2 107.9 116.5 125.1 133.8 142.4 151.1 159.7 168.3 177.0 185.6 194.2 202.9 211.5 220.1 228.8
60% 30.6 39.3 47.9 56.6 65.2 73.8 82.5 91.1 99.7 108.4 117.0 125.6 134.3 142.9 151.6 160.2 168.8 177.5 186.1 194.7 203.4 212.0 220.6 229.3 237.9
50% 43.4 52.1 60.7 69.4 78.0 86.6 95.3 103.9 112.5 121.2 129.8 138.4 147.1 155.7 164.4 173.0 181.6 190.3 198.9 207.5 216.2 224.8 233.4 242.1 250.7
40% 62.6 71.3 79.9 88.5 97.2 105.8 114.5 123.1 131.7 140.4 149.0 157.6 166.3 174.9 183.5 192.2 200.8 209.5 218.1 226.7 235.4 244.0 252.6 261.3 269.9
30% 94.6 103.3 111.9 120.5 129.2 137.8 146.4 155.1 163.7 172.4 181.0 189.6 198.3 206.9 215.5 224.2 232.8 241.4 250.1 258.7 267.4 276.0 284.6 293.3 301.9
20% 158.6 167.2 175.9 184.5 193.2 201.8 210.4 219.1 227.7 236.3 245.0 253.6 262.2 270.9 279.5 288.2 296.8 305.4 314.1 322.7 331.3 340.0 348.6 357.2 365.9
10% 350.6 359.2 367.8 376.5 385.1 393.7 402.4 411.0 419.6 428.3 436.9 445.6 454.2 462.8 471.5 480.1 488.7 497.4 506.0 514.6 523.3 531.9 540.6 549.2 557.8
Hydrogen production cost < £50/MWh £50–100/MWh £100–150/MWh >£150/MWh
WE
uti
lisati
on
Under-utilised systems are only likely to produce low cost hydrogen
if they can access very low price electricity / other revenues
Source: Element Energy.
Plot of hydrogen cost (expressed as £/MWh) as a function of electrolyser utilisation and net
electricity price for a £1,500/kW electrolyser
Increasing net electricity price
For a given total installed system cost, hydrogen production costs are minimised for well-utilised
electrolysers able to access cheap electricity.
Decre
asin
g u
tilisatio
n
• Typical net electricity prices to electrolysers are expected to be around £50–70/MWh. The plot
above suggests that the economic case for hydrogen for heating against gas / oil will be challenging
at this level.
• Accessing additional revenue streams (e.g. balancing services, finding a way to monetise avoided
grid upgrades) is likely to be important in building the case for an electrolyser installation.
19
The data above can also be expressed in terms of constant
hydrogen production cost
Source: Element Energy.
Contours of constant hydrogen production cost (expressed as £/MWh) as a function
of electrolyser utilisation and net electricity price for a £1,500/kW electrolyser
• This chart is based on the
same data as the previous
plot, but in this case contours
of constant hydrogen
production cost are plotted.
• The lines cover the range of
hydrogen values – from gas
heating equivalent
(c.£40/MWh) through to high
value use in the transport
sector (c.£165/MWh).
• These results also highlight
the need to access low cost
electricity (even for well-
utilised electrolysers) if
revenues from hydrogen
sales are based on supply to
low value markets.Hydrogen production cost
20
WE capex (£/kW) @ 50 £/MWh
154 500
550
600
650
700
750
800
850
900
950
1,00
0
1,05
0
1,10
0
1,15
0
1,20
0
1,25
0
1,30
0
1,35
0
1,40
0
1,45
0
1,50
0
1,55
0
1,60
0
1,65
0
1,70
0
1,75
0
1,80
0
1,85
0
1,90
0
1,95
0
2,00
0
100% 100.4 101.7 102.9 104.2 105.5 106.8 108.0 109.3 110.6 111.9 113.2 114.4 115.7 117.0 118.3 119.6 120.8 122.1 123.4 124.7 126.0 127.2 128.5 129.8 131.1 132.4 133.6 134.9 136.2 137.5 138.8
90% 101.8 103.2 104.6 106.1 107.5 108.9 110.3 111.7 113.2 114.6 116.0 117.4 118.9 120.3 121.7 123.1 124.5 126.0 127.4 128.8 130.2 131.7 133.1 134.5 135.9 137.3 138.8 140.2 141.6 143.0 144.4
80% 103.6 105.2 106.8 108.4 110.0 111.6 113.2 114.8 116.4 118.0 119.6 121.2 122.8 124.4 126.0 127.6 129.2 130.8 132.4 134.0 135.6 137.2 138.8 140.4 142.0 143.6 145.2 146.8 148.4 150.0 151.6
70% 105.9 107.7 109.5 111.3 113.2 115.0 116.8 118.7 120.5 122.3 124.1 126.0 127.8 129.6 131.4 133.3 135.1 136.9 138.8 140.6 142.4 144.2 146.1 147.9 149.7 151.6 153.4 155.2 157.0 158.9 160.7
60% 108.9 111.0 113.2 115.3 117.4 119.6 121.7 123.8 126.0 128.1 130.2 132.4 134.5 136.6 138.8 140.9 143.0 145.2 147.3 149.4 151.6 153.7 155.8 158.0 160.1 162.2 164.4 166.5 168.6 170.8 172.9
50% 113.2 115.7 118.3 120.8 123.4 126.0 128.5 131.1 133.6 136.2 138.8 141.3 143.9 146.4 149.0 151.6 154.1 156.7 159.2 161.8 164.4 166.9 169.5 172.0 174.6 177.1 179.7 182.3 184.8 187.4 189.9
40% 119.6 122.8 126.0 129.2 132.4 135.6 138.8 142.0 145.2 148.4 151.6 154.8 158.0 161.2 164.4 167.6 170.8 174.0 177.1 180.3 183.5 186.7 189.9 193.1 196.3 199.5 202.7 205.9 209.1 212.3 215.5
30% 130.2 134.5 138.8 143.0 147.3 151.6 155.8 160.1 164.4 168.6 172.9 177.1 181.4 185.7 189.9 194.2 198.5 202.7 207.0 211.3 215.5 219.8 224.1 228.3 232.6 236.9 241.1 245.4 249.7 253.9 258.2
20% 151.6 158.0 164.4 170.8 177.1 183.5 189.9 196.3 202.7 209.1 215.5 221.9 228.3 234.7 241.1 247.5 253.9 260.3 266.7 273.1 279.5 285.9 292.3 298.7 305.1 311.5 317.9 324.3 330.7 337.1 343.5
10% 215.5 228.3 241.1 253.9 266.7 279.5 292.3 305.1 317.9 330.7 343.5 356.3 369.1 381.9 394.7 407.5 420.3 433.1 445.9 458.7 471.5 484.3 497.1 509.9 522.6 535.4 548.2 561.0 573.8 586.6 599.4
Hydrogen production cost < £50/MWh £50–100/MWh £100–150/MWh >£150/MWh
WE
uti
lisati
on
We can also explore the impact of utilisation and capital cost at a
fixed electricity price (£50/MWh in this example)
Source: Element Energy.
Plot of hydrogen cost (expressed as £/MWh) as a function of electrolyser capex and utilisation
(load factor), based on a £50/MWh net electricity price
Increasing water electrolyser capital costDecre
asin
g u
tilisatio
n
The plot below shows the impact of varying average annual load factor (utilisation) on hydrogen
production cost for a set electricity price.
Electric heating equivalent (c. £120/MWh)
Transport equivalent (c. £165/MWh)Based on 115p/litre diesel cost, 40mpg and 80km/kgH2 FCEV
• At a realistic net electricity price (of c.£50–70/MWh), the cost of producing hydrogen with today’s
electrolysers (which cost from c.£1k/kW, often £2k/kW or above) means it is unlikely to compete
with any demand expect the highest value uses (direct electric heating or fuel cell-based transport).
• This suggests that for an economic case either the capex needs to be written off (e.g. through grant
funding), or alternative revenue streams must be found (or some combination of the two).
Water electrolysis economic analysis – conclusions
21
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
22
Investigation of the scope for low cost electricity requires an
understanding of the cost base of power supplies
* SPD Schedule of Indicative Charges and Other Tables:
www.scottishpower.com/pages/connections_use_of_system_and_metering_services.asp.
Components of electricity cost Indicative DUoS charges
15%
10%
20%55%
Other charges / levies
DUoS charges
TUoS charges
Wholesale price
24.7
21.6
3.6
30.12.5
1.48.7
110.6
19.0
Red / Black Amber / Yellow Green
LV HH Metered
LV Medium Non-Domestic
Small Non Domestic Two Rate
Small Non Domestic Unrestricted
Domestic Unrestricted
£/MWh
Source: Scottish Power*
• Red / Black, Amber / Yellow, and Green
refer to time bands (see appendix).
• Charges shown are per MWh, a fixed
daily charge (per meter) may also apply.
• The wholesale electricity price accounts
for the majority of the cost of electricity
to consumers.
• Typical wholesale prices in the UK were
c. £36/MWh – £47.5/MWh during 2014.^
• Network charges include transmission
and distribution use of system charges
(TUoS / DUoS).
Illustrative grid electricity price
breakdown in the UK
Illustrative breakdown – see for example the detailed
breakdown for domestic bills published by Ofgem
(provided in the appendix).
^ Source: APX Power UK Spot prices (monthly) – see
appendix.
23
Avoiding network charges could reduce the cost of electricity by
around £30/MWh
Figures based on the 2013 average prices (graph on the left), and typical breakdown from the previous slide.
Electricity prices over time Electricity price breakdown
£/MWh
• These figures suggest that removing
network charges (e.g. through a private
wire arrangement) could save c.£30/MWh.
• With wholesale costs and other charges
the price seen by an electrolyser would be
in the region of £65/MWh, only slightly
above the level needed to produce
hydrogen at a competitive cost for some of
the higher value markets.
• This graph shows average prices (ex. VAT)
paid by electricity consumers in the non-
domestic sector by consumption band.
• Note that a well-used electrolyser of tens of
kW peak capacity may use hundreds of
MWh/yr, while an electrolyser in the
hundreds of kW / MW-scale would
consume thousands of MWh per year.
Average electricity prices paid by non-
domestic consumers in the UK
Source: DECC – from Table 3.4.2 Prices of fuels
purchased by non-domestic consumers including the
Climate Change Levy
2010 2011 2012 2013
0
120
100
112.8
75.1
107.4
85.991.7
102.0101.1
79.1
Small (20–499 MWh/yr)
Medium (2,000–19,999 MWh/yr)
£/M
Wh
Consumer
size
11
1417
2318
50
62
Small (20–499 MWh/yr)
92
113
9
Medium (2,000–
19,999 MWh/yr)
Other charges / levies
Wholesale price
DUoS charges
TUoS charges
24
Electricity cost breakdown – summary
Cost
elementDescription
Typical value
(£/MWh)Scope for reduction
Unit
electricity
price
Price of electricity on the open
market.
Varies continuously based on
supply and demand (see below).
30–60*
Operate at times of low demand
or high generation, or connect
directly to a renewable generator
and negotiate a power purchase
agreement (PPA).
Distribution
use of
system
charges
(DUoS)
Charges for using distribution
network.
DUoS charges are time dependant
and may have a capacity (per kW)
and a usage (per kWh)
component.
20–30
Avoid consumption during peak
periods.
Charges can be avoided by
connecting at grid transmission
point, or using a private wire off-
grid connection to a renewable
electricity generator.
Transmission
use of
system
charges
(TUoS)
Charges for using transmission
networks.
TUoS charges based on the
location on transmission system,
and import requirements.
10
Charges can be avoided by
connecting using a private wire
off-grid connection to a renewable
electricity generator.
Other
charges and
levies
Other charges for the provision of
incentives (e.g. RO, FIT), or billing
customers, or climate change.
10–20 Charges can be avoided through
using a private wire connection.
* Depends on scale, tariff type, and utility’s margin.
25
Provision of balancing services to the transmission network
operator is a potential source of revenue for water electrolysers
* Short-term operating reserve, frequency control by demand management, fast frequency response. For details
and a list of other services see www2.nationalgrid.com/uk/services/balancing-services/.
• The TSO (National Grid) must balance supply and demand on the transmission network at all
times. To accomplish this the network operator procures a range of balancing services (e.g.
STOR, FCDM, FFR, etc.).*
• The frequency response market is one of the more lucrative balancing markets, and dynamic
frequency balancing is a particularly relevant area for rapid response electrolysers.
• Dynamic frequency balancing requires a sub-2s response and is called on a fairly constant basis.
Overview of the balancing market
• Electrolysers can provide dynamic frequency balancing services, but National Grid stipulates a
minimum size for participants in this market (3MW).
• A number of companies now offer a service where they install control equipment on a large number
of relatively small sources of demand in order to present quanta (at least 3MW) of controllable
demand to National Grid.
• These aggregators provide access to balancing market revenues not otherwise available to
operators of relatively small plant. They pass on some of the revenues received from National Grid
to the owners of the plant being controlled.
• Potential revenues from balancing services vary (and may well differ in future), but a typical
payment for dynamic frequency balancing would be of the order £5–20 per MW per hour available.
• This may be expressed as an effective income of £5–20/MWh electricity consumed by the
electrolyser (i.e. –5/MWh to –20/MWh on the net electricity price). Note that some of this would
have to be shared with an aggregator for electrolysers <3MW and access to such revenues would
be subject to operating plans of the plant.
Potential revenues for a water electrolyser
26
There are a number of potential strategies for economic operation
of electrolysers in energy system applications
Strategy Description
Typical average
annual load
factor*
Indicative net
electricity price
(£/MWh)**
Co-locationSite electrolyser next to renewable generator to provide
guaranteed demand and avoid network charges.c.30–80% 40–60
Grid
services
Sell balancing services to the transmission system
operator (NB: there is currently no mechanism for
monetising services at the distribution network level).
Up to 100%
60–115
(depending on
size)
Spot price
tracking
Operate electrolyser only at times of low wholesale
electricity prices.Up to c.50% 60–90
Curtailment
avoidance
Run electrolyser mainly on otherwise curtailed
generation (e.g. using a virtual private wire
arrangement) and access a share of RES-E incentives.
<20%^ 4–40
* I.e. water electrolyser load factor such that the net electricity price over the course of a year may be within the stated range.
** Based on the ranges given in the electricity cost breakdown summary provided above.
• In general, water electrolyser operators must strike a balance between securing low (net) cost
electricity and achieving high full load run hours (high load factor). The impact of these ranges on
hydrogen production cost is illustrated on the following slides.
• The strategies above are not all mutually exclusive (e.g. it may be possible to offer grid services
and target low electricity prices through spot market tracking). However, there is uncertainty
regarding the extent to which such approaches are feasible in practice, which should reduce over
the coming years as a result of further studies and practical demonstration of electrolysers in
energy system applications.
^ Load factor depends on the size of the demand relative to the generators and details of curtailment. CES analysis
suggests that the load factor for this type of scenario could be as low as 7% (however this could change over time).
27
The optimal strategy for minimising production cost depends on a
range of factors (WE capex, revenues available, practical issues etc.)
Electricity price (£/MWh) @ 1,500 £/kW
130 0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100
105
110
115
120
100% 39.6 48.2 56.9 65.5 74.1 82.8 91.4 100.1 108.7 117.3 126.0 134.6 143.2 151.9 160.5 169.1 177.8 186.4 195.1 203.7 212.3 221.0 229.6 238.2 246.9
90% 43.9 52.5 61.1 69.8 78.4 87.0 95.7 104.3 113.0 121.6 130.2 138.9 147.5 156.1 164.8 173.4 182.0 190.7 199.3 208.0 216.6 225.2 233.9 242.5 251.1
80% 49.2 57.8 66.5 75.1 83.7 92.4 101.0 109.7 118.3 126.9 135.6 144.2 152.8 161.5 170.1 178.7 187.4 196.0 204.7 213.3 221.9 230.6 239.2 247.8 256.5
70% 56.1 64.7 73.3 82.0 90.6 99.2 107.9 116.5 125.1 133.8 142.4 151.1 159.7 168.3 177.0 185.6 194.2 202.9 211.5 220.1 228.8 237.4 246.1 254.7 263.3
60% 65.2 73.8 82.5 91.1 99.7 108.4 117.0 125.6 134.3 142.9 151.6 160.2 168.8 177.5 186.1 194.7 203.4 212.0 220.6 229.3 237.9 246.6 255.2 263.8 272.5
50% 78.0 86.6 95.3 103.9 112.5 121.2 129.8 138.4 147.1 155.7 164.4 173.0 181.6 190.3 198.9 207.5 216.2 224.8 233.4 242.1 250.7 259.4 268.0 276.6 285.3
40% 97.2 105.8 114.5 123.1 131.7 140.4 149.0 157.6 166.3 174.9 183.5 192.2 200.8 209.5 218.1 226.7 235.4 244.0 252.6 261.3 269.9 278.5 287.2 295.8 304.5
30% 129.2 137.8 146.4 155.1 163.7 172.4 181.0 189.6 198.3 206.9 215.5 224.2 232.8 241.4 250.1 258.7 267.4 276.0 284.6 293.3 301.9 310.5 319.2 327.8 336.4
20% 193.2 201.8 210.4 219.1 227.7 236.3 245.0 253.6 262.2 270.9 279.5 288.2 296.8 305.4 314.1 322.7 331.3 340.0 348.6 357.2 365.9 374.5 383.2 391.8 400.4
10% 385.1 393.7 402.4 411.0 419.6 428.3 436.9 445.6 454.2 462.8 471.5 480.1 488.7 497.4 506.0 514.6 523.3 531.9 540.6 549.2 557.8 566.5 575.1 583.7 592.4
Hydrogen production cost < £50/MWh £50–100/MWh £100–150/MWh >£150/MWh
WE
uti
lisati
on
Electricity price (£/MWh) @ 750 £/kW
109 0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100
105
110
115
120
100% 20.4 29.0 37.7 46.3 55.0 63.6 72.2 80.9 89.5 98.1 106.8 115.4 124.0 132.7 141.3 150.0 158.6 167.2 175.9 184.5 193.1 201.8 210.4 219.0 227.7
90% 22.5 31.2 39.8 48.4 57.1 65.7 74.4 83.0 91.6 100.3 108.9 117.5 126.2 134.8 143.4 152.1 160.7 169.4 178.0 186.6 195.3 203.9 212.5 221.2 229.8
80% 25.2 33.8 42.5 51.1 59.8 68.4 77.0 85.7 94.3 102.9 111.6 120.2 128.8 137.5 146.1 154.8 163.4 172.0 180.7 189.3 197.9 206.6 215.2 223.8 232.5
70% 28.6 37.3 45.9 54.5 63.2 71.8 80.5 89.1 97.7 106.4 115.0 123.6 132.3 140.9 149.5 158.2 166.8 175.5 184.1 192.7 201.4 210.0 218.6 227.3 235.9
60% 33.2 41.8 50.5 59.1 67.7 76.4 85.0 93.7 102.3 110.9 119.6 128.2 136.8 145.5 154.1 162.7 171.4 180.0 188.7 197.3 205.9 214.6 223.2 231.8 240.5
50% 39.6 48.2 56.9 65.5 74.1 82.8 91.4 100.1 108.7 117.3 126.0 134.6 143.2 151.9 160.5 169.1 177.8 186.4 195.1 203.7 212.3 221.0 229.6 238.2 246.9
40% 49.2 57.8 66.5 75.1 83.7 92.4 101.0 109.7 118.3 126.9 135.6 144.2 152.8 161.5 170.1 178.7 187.4 196.0 204.7 213.3 221.9 230.6 239.2 247.8 256.5
30% 65.2 73.8 82.5 91.1 99.7 108.4 117.0 125.6 134.3 142.9 151.6 160.2 168.8 177.5 186.1 194.7 203.4 212.0 220.6 229.3 237.9 246.6 255.2 263.8 272.5
20% 97.2 105.8 114.5 123.1 131.7 140.4 149.0 157.6 166.3 174.9 183.5 192.2 200.8 209.5 218.1 226.7 235.4 244.0 252.6 261.3 269.9 278.5 287.2 295.8 304.5
10% 193.2 201.8 210.4 219.1 227.7 236.3 245.0 253.6 262.2 270.9 279.5 288.2 296.8 305.4 314.1 322.7 331.3 340.0 348.6 357.2 365.9 374.5 383.2 391.8 400.4
Hydrogen production cost < £50/MWh £50–100/MWh £100–150/MWh >£150/MWh
WE
uti
lisati
on
Co-location
Curtailment avoidance
Spot price tracking
Grid services
Co-location
Curtailment avoidance
Spot price tracking
Grid services
Current
capex
Future
capex
Source: Element Energy.
28
165 20% 30% 40% 50% 60% 70% 80% 90% 100%
80 331.3 267.4 235.4 216.2 203.4 194.2 187.4 182.0 177.8
70 314.1 250.1 218.1 198.9 186.1 177.0 170.1 164.8 160.5
60 296.8 232.8 200.8 181.6 168.8 159.7 152.8 147.5 143.2
50 279.5 215.5 183.5 164.4 151.6 142.4 135.6 130.2 126.0
40 262.2 198.3 166.3 147.1 134.3 125.1 118.3 113.0 108.7
30 245.0 181.0 149.0 129.8 117.0 107.9 101.0 95.7 91.4
20 227.7 163.7 131.7 112.5 99.7 90.6 83.7 78.4 74.1
10 210.4 146.4 114.5 95.3 82.5 73.3 66.5 61.1 56.9
0 193.2 129.2 97.2 78.0 65.2 56.1 49.2 43.9 39.6
-10 175.9 111.9 79.9 60.7 47.9 38.8 31.9 26.6 22.3
-20 158.6 94.6 62.6 43.4 30.6 21.5 14.7 9.3 5.1
-30 141.3 77.4 45.4 26.2 13.4 4.2 -2.6 -8.0 -12.2
-40 124.1 60.1 28.1 8.9 -3.9 -13.0 -19.9 -25.2 -29.5
-50 106.8 42.8 10.8 -8.4 -21.2 -30.3 -37.2 -42.5 -46.8
-60 89.5 25.5 -6.5 -25.6 -38.4 -47.6 -54.4 -59.8 -64.0
-70 72.2 8.3 -23.7 -42.9 -55.7 -64.9 -71.7 -77.0 -81.3
-80 55.0 -9.0 -41.0 -60.2 -73.0 -82.1 -89.0 -94.3 -98.6
-90 37.7 -26.3 -58.3 -77.5 -90.3 -99.4 -106.3 -111.6 -115.9
-100 20.4 -43.6 -75.5 -94.7 -107.5 -116.7 -123.5 -128.9 -133.1
Ele
ctr
icit
y p
rice (
£/M
Wh
)
WE utilisation
£40/MWh £50/MWh £90/MWh £120/MWh £165/MWh
Source: Element Energy.
Hydrogen production cost (expressed as £/MWh) as a function of electrolyser utilisation and net
electricity price for a £1,500/kW electrolyser, overlaid with contours of constant production cost
This graphic shows
hydrogen production costs
as a function of WE
utilisation and net
electricity price (for
systems at current costs).
Contours of constant
hydrogen production cost
are also plotted, along with
boxes indicating possible
operating envelopes:
1. Curtailment avoidance
2. Co-location
3. Grid services
4. Spot price tracking
Hydrogen production cost
1
2
34
Production costs are relatively high at current water electrolyser
capex, which implies a high value use for hydrogen is needed
29
40 20% 30% 40% 50% 60% 70% 80% 90% 100%
80 235.4 203.4 187.4 177.8 171.4 166.8 163.4 160.7 158.6
70 218.1 186.1 170.1 160.5 154.1 149.5 146.1 143.4 141.3
60 200.8 168.8 152.8 143.2 136.8 132.3 128.8 126.2 124.0
50 183.5 151.6 135.6 126.0 119.6 115.0 111.6 108.9 106.8
40 166.3 134.3 118.3 108.7 102.3 97.7 94.3 91.6 89.5
30 149.0 117.0 101.0 91.4 85.0 80.5 77.0 74.4 72.2
20 131.7 99.7 83.7 74.1 67.7 63.2 59.8 57.1 55.0
10 114.5 82.5 66.5 56.9 50.5 45.9 42.5 39.8 37.7
0 97.2 65.2 49.2 39.6 33.2 28.6 25.2 22.5 20.4
-10 79.9 47.9 31.9 22.3 15.9 11.4 7.9 5.3 3.1
-20 62.6 30.6 14.7 5.1 -1.3 -5.9 -9.3 -12.0 -14.1
-30 45.4 13.4 -2.6 -12.2 -18.6 -23.2 -26.6 -29.3 -31.4
-40 28.1 -3.9 -19.9 -29.5 -35.9 -40.5 -43.9 -46.6 -48.7
-50 10.8 -21.2 -37.2 -46.8 -53.2 -57.7 -61.2 -63.8 -66.0
-60 -6.5 -38.4 -54.4 -64.0 -70.4 -75.0 -78.4 -81.1 -83.2
-70 -23.7 -55.7 -71.7 -81.3 -87.7 -92.3 -95.7 -98.4 -100.5
-80 -41.0 -73.0 -89.0 -98.6 -105.0 -109.5 -113.0 -115.6 -117.8
-90 -58.3 -90.3 -106.3 -115.9 -122.3 -126.8 -130.2 -132.9 -135.0
-100 -75.5 -107.5 -123.5 -133.1 -139.5 -144.1 -147.5 -150.2 -152.3
Ele
ctr
icit
y p
rice (
£/M
Wh
)
WE utilisation
£40/MWh £50/MWh £90/MWh £120/MWh £165/MWh
Source: Element Energy.
Hydrogen production cost (expressed as £/MWh) as a function of electrolyser utilisation and net
electricity price for a £750/kW electrolyser, overlaid with contours of constant production cost
Operating envelopes:
1. Curtailment avoidance
2. Co-location
3. Grid services
4. Spot price tracking
Hydrogen production cost
1
2
34
If electrolyser costs fall it may become feasible to use lower value
markets (e.g. heat) as the core demand for the hydrogen produced
30
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
31
• The slides below show approximated annual energy demand profiles for a range of illustrative
scenarios.
• Estimated energy demands have been converted into equivalent hydrogen demands (kg/day),
with no adjustment for different efficiencies of hydrogen vs. fossil fuel boilers.
• Understanding the potential size (and profile) of demand for hydrogen is the first step in sizing a
hydrogen-based energy system.
• There are various approaches to sizing a hydrogen production system, for example:
– Aim to meet total annual demand – size the electrolyser and storage such that hydrogen
generation over the course of the year matches annual demand.
– Size electrolyser according to a base level of demand (to achieve high annual run hours).
– Specify a small electrolyser relative to demand to ensure full utilisation.
– Over-size plant so that it runs only at certain times (e.g. night time operation only).
• The high-level economic analysis in the previous section reveals the importance of achieving a
reasonably high load factor for the electrolyser (while capex is high); i.e. a system sized to meet
peak loads which is under-utilised much of the year is unlikely to be economically viable.
• An alternative way to consider electrolyser sizing is on the basis of scope to allow renewable
generators to avoid curtailment. However, this is less likely to be suitable given (a) the relatively
high capital cost of electrolysers (£/kW), (b) the relatively low number of hours per year during
which curtailment is a major issue, and (c) the need to create a new demand for the hydrogen.
In this section we consider electrolyser sizes in the context of
potential sources of demand for hydrogen
Introduction to demand profile modelling
Water electrolyser sizing
32
1. Industrial / commercial heat – use hydrogen at a commercial plant to displace fossil fuels (e.g.
landfill gas, coal, and waste-derived fuels).
2. Pure hydrogen network – installation of a gas network in an off-grid village to supply pure
hydrogen for cooking and heating. This would involve the installation of new boilers / burners
compatible with pure hydrogen.
3. Power-to-gas – mix hydrogen with methane and inject into the existing natural gas grid (e.g. up to
10% on a volume basis).
4. Community / district heating – burn hydrogen to provide heat for a community building / district
heating network.
5. Transport – a fifth scenario (not part of the original scope due to a lack of immediate plans for
hydrogen-fuelled vehicles in the area) based on creating a demand for hydrogen in the (high
value) transport sector is also presented below.
We investigated a range of different end uses for hydrogen in the
Dunbar area
End uses considered
33
We have defined a range of demand scenarios within the categories outlined above.
We defined specific end uses within each of the four broad
categories
Opportunities for industrial uses for hydrogen (e.g. at the local cement works) were also considered during the
first phase of the study.
Demand scenarios – overview
Demand
scenarioDescription Key assumptions
1. Dedicated
hydrogen
network*
Supply a new development with
hydrogen from a dedicated pure H2
network.
Illustrative scenario: 85 new dwellings,
average fuel demands of 10MWh/yr per
dwelling (space heating, hot water and
cooking).
2. West Barns
gas spur
Power-to-gas application using the
West Barns gas spur.
Annual volumes of gas in spur and
profile based on data from CES.
Injection of up to around 10% hydrogen
(by volume) could be considered.
3. Dunbar
swimming
pool**
H2 to heat for Dunbar’s leisure
centre.
Fuel demand for heating of
c.3,000MWh/yr (based on data provided
by East Lothian Council).
* Another option could be conversion of existing off-grid demands (e.g. clusters of farm cottages /
dwellings in Tyninghame village). The new development option offers advantages in terms of less
disruption and lower up-front cost of installing a hydrogen network.
** Other options in the category of community / district heating include: Belhaven hospital / brewery,
Lammermuir house care home, etc.
34
The following slides show estimated demand profiles for a selection of the potential end use cases.
Example electrolyser sizes and key performance indicators (KPIs) are also given.
The approach to electrolyser sizing differs according to the demand scenario:
• New build development, dedicated hydrogen network serving new thermal demands –
electrolyser sized to meet peak daily demands. Given the seasonal variation in thermal demands
this means the plant is run at part load for much of the year.
• Power-to-gas (injection of hydrogen into the West Barns gas spur) – sizing is based on an
assumption that the upper limit of hydrogen in the network may be 10% by volume (with
exemption from existing regulations).* Two sizing approaches are considered: one based on
achieving high annual run hours (size to minimum demand), and one based on maximising the
amount of hydrogen that could be injected (size to peak demand and operate electrolyser to follow
demand profile).
• Existing demand, Dunbar Leisure Centre – two sizing approaches: one to meet all thermal
demands over the course of a year, and a second to meet the base load, allowing the electrolyser
to achieve higher annual run hours.
Electrolyser sizing is a trade off between plant utilisation,
proportion of demands met and storage needs
* The limit on level of hydrogen in gas networks in the UK is set by the Gas Safety (Management) Regulations
1996 and is currently 0.1% (molar basis).
Water electrolyser sizing approach
35
Potential for a dedicated hydrogen network in a new build
development
SAP = Standard Assessment Procedure, the Government-approved methodology for calculating energy
demands and emissions from new dwellings.
Water electrolyser KPIs
Sized to meet peak
demands
WE size kW / (kg/day) 340 (140)
Indicative
capex£k 580
Annual load
factor- 49%
% of annual
demand met
with H2
- 100%
Storage kgH2 300
StorageDays of peak
output2
Estimated profile of total thermal fuel demands in new 85 dwelling
development (expressed as kgH2/day equivalent). Demands and
variation by month from SAP modelling of typical new dwellings.
Storage need based on at least two days’ worth of
peak output (illustrative).
• In this example we assume hydrogen can be used as a direct
replacement for the incumbent heating fuel (e.g. via a dedicated
hydrogen network).
• A c.170kW electrolyser operating at 100% load factor could meet
the total thermal demands. However, this would require >100
days’ worth of storage (7.4t), which is unlikely to be practically
feasible or economically viable.
Other requirements
• Hydrogen pipework to distribute fuel and
compatible boilers and burners in each
dwelling.
• Energy supply agreements (without
compromising consumer choice).
36
West Barns gas spur – power-to-gas
STP = standard temperature and pressure.
Water electrolyser KPIs
High run
hours
High
injection
WE size kW / (kg/day) 15 (6) 70 (29)
Indicative
capex£k 70 280
Annual load
factor- 99% 55%
% of annual
demand met
with H2
- 1% 3%
Estimated profile of total energy demands in West Barns gas spur
(expressed as kgH2/day equivalent). Source: data from CES document
2.1 Gas Use Data v1, including 700,000m3 of natural gas (at STP).
Electrolyser sized based on always having the
option to inject hydrogen into the gas grid
assuming up to 10% (by volume) hydrogen is
feasible (not permitted under current regulations).
NB: profile and sizing based on estimated daily
demands.
• Demand profile data suggest that a MW-scale electrolyser would
be oversized relative to the gas demand in the West Barns spur.
• An electrolyser of low tens of kilowatts could be operated
throughout the year and could meet a small fraction of
downstream energy demands.
• A range of technical, regulatory, and practical issues would need
to be resolved to deliver a power-to-gas solution.
Total gas flow in spur expressed
as kg/day hydrogen equivalent
Other requirements
• Gas mixing and injection equipment.
• Commercial agreement with licensed energy
supplier to transport and sell the gas.
• Exemption from relevant regulations (e.g. Gas
Safety Management Regulations).
37
Dunbar leisure centre & community pool
Water electrolyser KPIs
Sized to
peak
Sized to
base load
WE size kW / (kg/day) 875 (370) 400 (170)
Indicative
capex£k 1,500 680
Annual load
factor- 67% 100%
% of annual
demand met
with H2
- 100% 68%
Storage kgH2 740 340
StorageDays of peak
output2 2
Profile of total thermal fuel demands in the Dunbar leisure centre
(expressed as kgH2/day equivalent).
Storage need based on at least two days’ worth of
peak output (illustrative).
• The profile above is based on monthly gas consumption data for
the leisure centre (from 2011).
• Switching from natural gas to hydrogen could provide sufficient
demand for an electrolyser in the mid to high hundreds of kW.
• To meet all thermal demands with a full utilised electrolyser a
c.600kW system would be needed. However, this would also
require c.10 tonnes of hydrogen storage (unlikely to be feasible).
Other requirements
• Hydrogen boiler, integration with heat
distribution system.
38
Sized to meet total
demands
WE size kW / (kg/day) 500 (210)
Indicative
capex£k 850
Annual load
factor- 90%
Storage kgH2 420
StorageDays of peak
output2
Equivalent
number of
vehicles (to
create
demand)
Fuel cell cars 380
Fuel cell
buses10
H2ICE vans 60
Hydrogen transport
Water electrolyser KPIs
Hydrogen demand for an illustrative transport scenario sufficient
to provide high utilisation of a 0.5MW water electrolyser
• Using hydrogen as a transport fuel could provide a relatively
stable demand for the output of a water electrolyser.
• This indicative scenario illustrates the approximate size of vehicle
fleets needed for a well-utilised 0.5MW electrolyser – e.g. a fleet
of 350+ fuel cell cars, around ten fuel cell buses, or 60 internal
combustion engine vans converted to run on hydrogen.
Illustrative demand (daily basis) assuming that
demands are constant throughout the year.
Other requirements
• Hydrogen compressing and dispensing
equipment.
• Accessible location for fuelling station.
• Fleet(s) of hydrogen-fuelled vehicles.
40
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
– Hydrogen for heat, transport, or industry
– Hydrogen for methanation
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
41
Options comparison matrix
DriverH2 network –
new buildPower-to-gas
H2 for
community heatIndustrial use^ Transport
Economic viability
Scale (relevance to
ANM system)
Emissions reduction
potential*
Community
engagement
Complexity / risk**
Scope for expansion
^ Assuming demand is sufficient to justify a MW-scale water electrolyser. NB: there is a high degree of uncertainty regarding the feasibility of the industrial
use scenario. * Linked to scale of electrolyser and fuel being offset. ** E.g. technical, commercial, regulatory.
• The matrix below compares each option against key drivers based on the analysis presented in
the previous sections.
• The assessment considers the electrolyser system on the basis that a demand for hydrogen under
each scenario could be created.
42
An H2 system is likely to be challenging to deliver in the near term
but may be a stepping stone to an innovative, sustainable solution
• The matrix above suggests that the power-to-gas and dedicated hydrogen network solutions
are the most challenging to deliver.
• Creation of demand for hydrogen in the transport sector, and potentially as a substitute for
community heat (Leisure Pool) offers more promise. However, in the case of the Leisure Pool,
the justification for a hydrogen-based solution rather than an electricity-based solution (e.g. direct
electric / heat pump) requires further analysis.
• In practice the most suitable approach may be to design a system capable of satisfying a range of
demands. E.g. begin by targeting established demands where the barriers to conversion to
hydrogen are lowest (e.g. heating a community building), with a view to expanding / diversifying
into higher value markets as they develop (such as transport).
• This type of approach is being considered for some of the demonstration projects planned /
underway in Germany (e.g. demand for hydrogen through P2G / re-electrification in the short term,
with plans to supply higher value markets such as transport and industrial gas in future).*
Options comparison – considerations
E.g. Audi’s 6MW P2G facility in Werlte, P2G project in Frankfurt (Thüga Group), Falkenhagen P2G pilot plant
(E.ON), Hamburg P2G project (E.ON).
43
The potential up-side from a large-scale system in future may
provide motivation for a pilot project in the nearer term
• In today’s world (relatively high cost electrolysers, low / uncertain demand for hydrogen, lack of
mechanism for monetising grid benefits, etc.) the case for installing a water electrolyser is
challenging.
• However, if electrolyser technology development targets are achieved, a hydrogen-based solution
to overcoming the local issues caused by excessive renewable generation could be more
competitive in the future.
• For example, there is potentially a positive case for an electrolysis system at a similar scale to the
generation on the active network management (ANM) system (e.g. tens of megawatts) if a
substantial relatively high value demand for hydrogen develops.
• This is explored in further detail in the Large-scale system – detailed assessment section below.
• A multi-MW scale electrolyser system may provide further benefit in terms of cancellation /
deferral of electricity grid upgrades.
Outlook for water electrolyser-based solutions
44
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
– Hydrogen for heat, transport, or industry
– Hydrogen for methanation
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
45
If a local source of CO / CO2 were available, methanation would be
another potential use for hydrogen in the Dunbar area
• A common issue affecting the options outlined above is the lack of / limited demand for hydrogen
produced by any potential water electrolysis system in Dunbar.
• Methanation (the production of methane from CO / CO2) is a further potential use for hydrogen
and offers the advantage of yielding a product for which there is a large demand.
• The fundamental principle is that hydrogen produced from excess renewable electricity can be
combined with a source of CO / CO2 to generate methane that is fed into the existing gas grid
(which essentially acts as a large scale store of energy).
• Feeding (synthetic) methane into the gas grid reduces the technical and regulatory barriers
compared to injection of hydrogen (as per the power-to-gas concept discussed above). However,
this application represents a low value use for the hydrogen, a source of CO / CO2 is required
(which increases system cost and complexity), and the additional conversion steps reduce the
overall efficiency (renewable electricity to useful end product).
Introduction
This section gives an overview of:
• Methanation and the different processes available.
• Existing biogas facilities in Scotland (for context).
• The scale of a biogas installation in Dunbar that could act as a source of demand for hydrogen from
a local water electrolyser.
• Further considerations and conclusions.
Section overview
46
Methanation processes can take feedstocks from various sources
and supply gas for a range of end uses
The diagram below shows the range of potential sources of hydrogen and CO / CO2 available for
methanation (left). A selection of potential end uses for hydrogen and methane is also illustrated (right).
www.gtai.de/GTAI/Content/EN/Invest/_SharedDocs/Downloads/GTAI/Fact-sheets/Energy-environmental/fact-
sheet-green-hydrogen-mass-energy-storage-for-future-en.pdf
47
CO2 methanation
• Overall: 𝐶𝑂2(𝑔)+ 4𝐻2(𝑔)⇌ 𝐶𝐻4(𝑔) + 2𝐻2𝑂(𝑔)
CO methanation
• Overall: 𝐶𝑂(𝑔)+ 3𝐻2(𝑔)⇌ 𝐶𝐻4(𝑔) + 𝐻2𝑂(𝑔)
Methanation involves the conversion of CO / CO2 to methane (CH4)
and water
Overview of methanation
Types of methanation – chemical and biological
Chemical methanation
• Chemical (catalytic) methanation is mature
and based on the Sabatier process.
• The process uses a nickel catalyst and runs
at relatively high temperatures (200–500oC).
• This type of methanation is best suited to
continuous operation and plants are typically
large scale (multi-MW).
Biological methanation
• Biological methanation uses microorganisms
to produce methane from the input gases.
• While there has been research into the
technology for decades, the process is less
mature than chemical methanation.
• Early pilot demonstrations are now beginning
operations (see appendix).
• There is interest in this technology as it is
more scalable, less complex, and more
responsive (e.g. able to modulate according
to variable levels of hydrogen generation)
than the chemical system.
48
In-situ digester
Biological methanation is carried out by hydrogenotrophic
methanogens (microorganisms that produce CH4 from CO2 + H2)
There are two main approaches to biological methanation:
• In-situ – hydrogen is injected into an anaerobic digester.
• Ex-situ – the methanation process is carried out in a separate vessel.
Further information on the relative merits of each approach is provided in the appendix.
Water electrolyser
Digester
Electricity + water
Biomass Methane
Hydrogen
Ex-situ digester
Water electrolyser
Digester
Electricity + water
Biomass
Hydrogen
CH4 reactorCO / CO2 Methane
49
There are currently around 17 anaerobic digestion plants in
Scotland (excluding those in the water industry)
In considering a potential biogas plant (as a source of CO
/ CO2 for methanation) in Dunbar, a logical initial step is to
assess the existing systems operating in Scotland. A
useful portal for information on anaerobic digestion in the
UK is: www.biogas-info.co.uk/.
Graph plotted based on data from www.biogas-info.co.uk. Note that while there are c.17 AD plants in Scotland,
according to the same source there are c.174 across the UK (excluding water industry installations).
Map of operational anaerobic digestion (biogas)
plants in ScotlandRed = community, yellow = industrial, green = agricultural.
Most installations (15 out of 17) are configured as CHP plants.
Agricultural plants tend to be small scale (tens of kW), with the
energy used on site (heat only or CHP).
Source: www.biogas-info.co.uk/ad-map.html
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
5,500
2006 2007 2008 2009 2010 2011 2012 2013 2014
AD – community CHP
AD – industrial CHP
Year commissioned
Syste
m e
lectr
ical
ca
pa
city (
kW
e)
Size of anaerobic digesters in Scotland
with combined heat and power
The data above suggest that AD plants in Scotland (with
CHP) range in size from a few hundred kWe to 5.5MWe.
50
• The majority of existing anaerobic digestion plants
in the UK involve production of electricity (and
heat). This type of application is supported by the
Feed-in Tariff.
• The Renewable Heat Incentive offers support for
biomethane (either for on-site combustion or
injection into the gas grid). It was first introduced in
November 2011 and offered a payment of
7.5p/kWh for biomethane injection.
• Following a review and consultation on
biomethane injection, DECC announced a change
to the tariff structure in December 2014.* Subsidy
levels for installations accredited on or after
01/04/15 are based on a tiered structure linked to
annual production (7.62p/kWh for the first
40,000MWh/yr dropping to 3.45p/kWh).
• Partly as a result of the financial support available,
a number of new AD plants injecting biomethane
into the gas grid were commissioned in the UK in
2014. These are mainly agricultural installations
and range from 600 to 2,000Nm3/hr biogas
capacity [Source: www.biogas-info.co.uk].
Support for renewable energy production via biogas is in place in
the UK
* www.gov.uk/government/uploads/system/uploads/attachment_data/file/384202/Biomethane_Tariff_Review_-
_Government_Response_-_December_2014.pdf.
Incentives for biogas installations
AD – scale p/kWhe
<250kWe 11.21
250 – 500kWe 10.37
>500kWe 9.02
Biomethane injection p/kWh
First 40,000 MWh/yr 7.62
Next 40,000 MWh/yr 4.47
Remaining MWh of
eligible biomethane3.45
Feed-in Tariff
Renewable Heat Incentive
For installations commissioned from 01/10/14
For installations commissioned from 01/04/15
51
To understand the scale of electrolysis system that would be compatible with a biogas (anaerobic
digestion) plant, the example below considers a 600Nm3/hr digester, which is representative of the
lower end of the scale of plants installed in the UK in 2014.
A relatively small scale AD plant could provide demand for a MW-
scale electrolyser for conversion of CO2 to methane
* www.bbc.co.uk/news/uk-scotland-edinburgh-east-fife-11796416.
** http://biocat-project.com/.
Sizing a methanation plant for Dunbar
Water
electrolyser
Digester
Electricity + water
Biomass
Hydrogen
CH4 reactor
Biogas
(e.g. 60% CH4, 40% CO2) Methane
4.5 MW, 70% load factor
600 Nm3/hr
c. 35,000 t/yr
c. 960 Nm3/hr
c. 240 Nm3/hr CO2
(360 Nm3/hr CH4)
240 Nm3/hr CH4
+ 360 Nm3/hr CH4
(from digester)
Example system – ex-situ digester
Notes
• The amount of feedstock required depends on its composition – a figure of 35kt/yr for a plant of
this scale is indicative based on published figures for similar plants.
• For reference, the amount of food waste in Edinburgh has been estimated at around 50kt/yr (and
the council has in the past taken steps to collect a portion of this).*
• While there are no known examples of this type of plant operating in the UK, demonstration
activities are underway elsewhere – e.g. the BioCat project** with an installation near
Copenhagen (see appendix for further details).
52
Small scale biological methanation is currently at a demonstration
stage – advances will be needed for viable commercial solutions
The graph below (from a study into methanation for a consortium based in France) shows that the
production costs of hydrogen / methane are currently relatively high, but could reduce over time.
Element Energy’s own techno-economic analysis of methanation gave production cost figures similar to
those shown below.
Source: Study on hydrogen and methanation as means to give value to electricity surpluses, E&E Consultant for
Ademe, GRTgaz, and GrDF (September 2014).
Source: E&E Consultant (2014)
53
A methanation-based solution in Dunbar is unlikely to be a short-
term solution and will require further detailed feasibility work
The development of a methanation facility using hydrogen from renewable electricity and carbon
dioxide from biogas would require further consideration of a number of factors (non-exhaustive list):
• Siting – a suitable location would be needed for the installation of all equipment, taking into
account access to renewable electricity, gas grid access (for injection), access for vehicles
delivering feedstock, etc.
• Feedstock – a megawatt-scale facility would require thousands / tens of thousands of tonnes of
feedstock per annum. A range of sources could in theory be used. In practice it would be
necessary to secure a stable, long-term supply of organic material to feed the plant.
• Logistics – a system of delivering feedstock to the site would be required, with consideration of
associated impacts of vehicle movements.
• Financing – a plant of this scale represents a multi-million pound investment which would have to
be suitably financed.
• Skills – this type of plant tends to operate on a near-continuous basis. Organisations / individuals
with specific skills would be needed to operate and maintain all aspects of the plant.
Methanation – further considerations
• A number of companies are seeking to develop small-scale methanation plants (based on
biological processes) that use hydrogen produced from excess renewable electricity.
• The technology is at a pre-commercial stage and work is underway to increase system efficiency,
lower production costs, and develop sustainable business cases for the technology.
• A methanation plant could provide a source of demand for a MW-scale electrolyser in Dunbar, but
this is likely to be a medium-term opportunity and would require further detailed feasibility work.
Methanation – conclusions
54
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
55
The information below covers:
• Scenario definition
• Key assumptions for the cash flow analysis
• Cash flow results
• Risks and practicalities
• This option is based on the installation of a water electrolyser and hydrogen boiler to serve the
existing thermal demands at the Dunbar Leisure Pool.
• Given that hydrogen for heat is a low value use of the fuel, we assume that the electrolyser
system would be modified to serve higher value markets in future, in particular the mobility sector.
• This would involve installation of additional hydrogen compression and dispensing equipment –
assumed to occur in the early 2020s to coincide with the introduction of fuel cell electric vehicles.
• For the purposes of this assessment the “upgrade” does not include expanding the electrolyser
capacity – i.e. the hydrogen produced is assumed to be diverted from satisfying heat demands to
vehicle fuelling (we assume that alternative sources of heat will be available for the Leisure Pool).
This section explores a solution based on establishing a demand
for H2 for heat initially before starting to serve the transport sector
Introduction
“Community heat” scenario – overview
56
• The analysis below is based on a water electrolyser (and hydrogen boiler) system sized to meet
all thermal demands of the Dunbar Leisure Pool throughout the year (i.e. the system is sized to
peak rather than according to the base load – see Demand profiles section above).*
• This leads to a relatively low load factor (67%), but means that for most months of the year the
electrolyser is operating below peak output and could offer a flexible source of demand to the
electricity grid.
* In the medium term (if electrolyser costs fall) there could be a case for installing an over-sized electrolyser that could offer the flexibility to
absorb excess power even on days of peak demand. Increasing the amount of hydrogen storage is another way to achieve a similar effect.
Overview of the “community heat” scenario and recap on sizing
approach
Profile of total thermal fuel demands
in the Dunbar leisure centre
(see Demand profiles section)
Existing gas
boilers
Water
electrolyser
Hydrogen
boiler
Thermal demands
(pool + leisure
centre heating)
Hydrogen
refuelling
station
Hydrogen-fuelled
vehicles
Retained for back-up
Potential future source
of hydrogen demand
Heat
Heat
H2
H2
H2
Schematic representation of the community heat scenario
57
Techno-economic assumptions for cash flow analysis –
community heat scenario
* Additional equipment costs could be of the order £400–600k for hydrogen refuelling station equipment. A portion of these costs is
included here as the economic analysis considers the period to 2025 only (whereas HRS equipment installed in 2020 would be expected to
have at least a ten year life).
Modelling assumptions (Central scenario)
Metric Value Notes
WE capex £1.5m Budgetary cost of a 875kW system (based on £1,700/kW).
Other capex £150k + £200k in 2020
Budgetary figure to cover hydrogen boiler, heat distribution system, civil
engineering, installation and commissioning. Capex in 2020 to cover additional
equipment to allow dispensing to FCEVs.*
WE fixed
opex£60k/yr Based on 4% of WE capex per annum.
System
efficiency57 kWh/kg
Load factor 67% From profile modelling above.
Economic
assumptions7%, 10 years
Net present value (NPV) calculated over a period of ten years using a relatively
low discount rate of 7%.
Electricity
price£60 per MWh
Figure towards the lower end of the “grid services” operating strategy defined
above. With these assumptions every kilogram of hydrogen has a production
cost of £3.42 based on the electricity consumption alone.
Other
assumptions
Water consumption of 40
litres/kgH2, price of 0.1p/litre
Water costs make up a small proportion of the overall variable opex (electricity
costs dominate).
Value of
hydrogen
From £1.33/kg (2016) to
£5.57 (2025)
Initial figure based on equivalent value to natural gas (at 4p/kWh), value
increases from 2020 assuming an increasing proportion of hydrogen is sold
into the transport market (from 2% of annual output in 2020 to 93% of output in
2025). This corresponds to a fleet of c. five FCEVs using the station initially,
growing to 200 by 2025.
Value in transport sector assumes no duty on hydrogen.
58
A WE system mainly supplying hydrogen for heat is unlikely to
provide a positive investment case
-2.5
-2.0
-1.5
-1.0
-0.5
0.0
0.5
2019201820172016 20252024202220212020 2023
Fixed opex
Capex
Variable opex
Revenue
£m
in
ye
ar
NPV
(2016–2025) at
7% discount rate
–£3.6m
• With the central case assumptions set out above the NPV of this type of application is negative.
• The graph indicates that initially (while hydrogen is used for heating), opex greatly exceeds
revenues on an annual basis. The gap reduces over time with the assumptions of growing
demand from the transport sector, but in this example the net cash flow is negative even in 2025.
• Note that even with free electricity, the NPV over this period remains negative (–£0.83m), mainly
as a result of the low revenues from hydrogen sales relative to the capex and fixed opex.
• Breakeven could be achieved under a scenario where all the capital cost (electrolyser and
hydrogen refuelling equipment) is written off and very low cost electricity is available (c.£25/MWh).
• Conclusion: Using electrolytic hydrogen for heat is unlikely to be economically sustainable at
current technology costs.
All values in 2015 prices
Community heat (& transport) scenario – annual cash flow
59
Community heat + transport option – sensitivity testing
Sensitivity test scenarios
Sensitivity test – results
Scenario Differences relative to the Central scenario
No transport demand No upgrade costs in 2020, no increase in value of hydrogen over time (£1.33/kg).
No transport demand, double gas prices No upgrade costs in 2020, revenues from hydrogen sale doubled (£2.67/kg).
No transport demand, subsidy supportNo upgrade costs in 2020, value of hydrogen increased to £3.60/kg (representing
an RHI-type subsidy).
High diesel pricesAs per the Central scenario, but diesel price (used for calculating value of H2 for
transport) increased from £1.25/litre to £2/litre (2015 prices).
BreakevenZero initial capex (e.g. 100% grant funded), £28/MWh electricity, high diesel price
(£2/litre).
0.03
-3.40
-1.85-2.60
-3.67-3.58
BreakevenNo transport
demand,
double gas
prices
High diesel
prices
(£2/litre)
No transport
demand
No transport
demand,
subsidy
support
Central
NPV (2016–2025), 7% discount rate (£m) • When supplying hydrogen mainly to
low value markets (such as heating),
a combination of very low electricity
prices and capex write-off is likely to
be needed to achieve breakeven.
• Even with an RHI-type subsidy, the
NPV remains negative due to the
relatively high capex and opex of the
system.
60
Community heat scenario – risk register
Risk Mitigation
Insufficient local grid capacity to connect new water electrolyser
of the required scale.
Enquire with local DNO, include budget for new power
supply as required.
Unable to access low cost electricity, leading to increasingly
negative business case.
Seek to secure long-term supply agreements. Work with
suppliers to develop innovative tariffs. Seek other revenue
sources (e.g. frequency services for the TSO).
Risk of poor technical performance (relatively little experience of
using hydrogen for heating).
Select suppliers with experience and reference installations.
Retain incumbent heating system as a back-up.
Demand from the transport sector fails to develop.Stress test business case against a range of alternative
future values of hydrogen.
Electrolyser supplier is unable / unwilling to support equipment
over its lifetime.Select an established supplier with a proven track record.
Long lead time for supply of specialist equipment needed
leading to delays in installation and commissioning.
Factor in sufficient time for design and procurement in
programme.
Leisure Pool operator unwilling to enter into long-term energy
supply agreement.
Commit to providing lower cost energy than counterfactual
option.
Planning / consents – objections from locals / issues with
securing permission to install and operate the system.
Engage local community early in the project, ensure all
relevant safety experts are involved in development of
plans.
WE system potentially in the wrong location to serve both local
community heat demand and mobility sector.
There are few options for mitigating this risk. The project
team will have to judge the compatibility of the preferred site
with the alternative markets to be addressed.
Grid upgrades in early 2020s undermining the case for a local,
flexible demand for renewable electricity.
Maintain contact with network operators to understand the
impact of planned upgrades in the context of increasing
renewable generation capacity connecting to the network.
61
A number of practical issues will need to be addressed to develop a project of the type described
above, for example:
• Siting and layout – defining precisely where the plant would be installed such that the various
demands can be satisfied while complying with relevant safety and planning guidelines. The
leisure pool is in a conservation area, which means that obtaining planning permission could be
challenging. The potential to supply demands from the transport sector in future should be
considered (see below).
• Integration with existing heating system – any new primary heating system is likely to make
use of the existing heat distribution system within the leisure centre. Details of the interface
between new and existing plant will need to be specified at the detailed design stage. Note that
the existing heating system could be retained as a back-up.
• Choice of supplier and securing demand for hydrogen – energy sector regulations dictate that
consumers must have a choice of energy supplier. Making an attractive offer to the leisure centre
(or any other heat customer) may involve offering to peg hydrogen prices to counterfactual fuel
(i.e. gas) prices.
• On-going maintenance and support – plant maintenance requires specialist skills. Equipment
providers typically offer a range of service packages (maintenance contracts) from minimal on-
going support (plant owner is responsible for maintenance) to full preventative maintenance and
component replacement.
Practical considerations include siting, ownership, and on-going
support arrangements
Ownership is a further consideration (i.e. who would own the plant) – the appropriate solution will depend on
various legal, commercial, and regulatory issues.
Practicalities
62
• An advantage of the Dunbar Leisure Centre
site is that there appear to be few space
constraints.
• This suggests there could be flexibility in terms
of siting an electrolyser and new heating plant
(subject to planning constraints).
• One option could be to install the system in /
alongside the existing building. The optimal
siting strategy will be dictated by a number of
factors: location and configuration of existing
heating plant, preferred site for vehicle
refuelling facility (HRS), cost and practical
implications of running hydrogen pipework to
location of future HRS, planning
considerations, etc.
• As mentioned above, including the option to
supply the transport sector helps the
economics of the project. However, from a
siting perspective a more logical place for an
HRS would be alongside the A1 (although
there is no suitable energy demand at such
sites in the near term).
An initial assessment suggests space is not a major constraint – a
more detailed review is required to identify a preferred location
View of the Dunbar Leisure CentreSource: Google Earth
Street view of the Dunbar Leisure CentreSource: Google
63
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
64
The information below covers:
• Scenario definition
• Key assumptions for the cash flow analysis
• Cash flow results
• Risks
• As an alternative to a small electrolyser located near a source of existing energy demand, here we
consider a multi-MW system that could provide a significant amount of flexible demand for local
renewable generators.
• Such a system could be co-located with renewable generators and thus avoid electricity network
charges. It may even allow upgrades to the electricity grid to be delayed / cancelled – the benefit
of this is not captured in the analysis that follows.
• A project of this scale would require extensive planning. Demand for (and value of) the hydrogen
produced is a key risk that would have to be addressed.
• We have developed this scenario on the basis that hydrogen would be transported by road and
delivered to a range of other markets.
This section explores the option of establishing a large scale WE
plant that could have a major impact on local curtailment issues
Introduction
“Large-scale system” scenario – overview
Source: www.windbyte.co.uk
65
• The following analysis considers a 30MW water
electrolysis system. A plant of this scale would produce
over ten tonnes of hydrogen per day (at 80% load factor).
• This is sufficient to satisfy the demand of a fleet of around
20,000 fuel cell cars (or over 500 fuel cell buses) – i.e. a
relatively high and consistent demand would be required to
justify such a system.
• The following would be needed in addition to the hydrogen
production system: compression, storage, distribution,
dispensing, source of demand, etc.
This scenario envisages a centralised hydrogen production
facility in Dunbar with an associated logistics operation
Scope of economic analysis
Water
electrolyser
On-site
storage
On-site
compression
Hydrogen
dispensing
(HRS)
Hydrogen
logistics
(tube
trailers)Vehicles
(source of
H2 demand)
Included in following
analysisExcluded from following analysis
A 500 bar tube trailer (capacity = 1.1tH2,
fill / unload time is c. 60 minutes).
Source: Linde
66
Techno-economic assumptions for cash flow analysis – large-
scale system scenario
* The sizing (30MW ) is illustrative. Smaller scale (but still multi-MW) systems may still be considered as grid
scale and offer advantages in terms of reduced need for grid upgrades.
Modelling assumptions
Metric Value Notes
WE capex £21mBudgetary cost of a 30MW system (based on £700/kW, which is a target figure
for large-scale electrolysers – note that current costs are far higher).*
Other capex £0.5m
Budgetary figure to cover civil engineering, installation and commissioning.
Note that no allowance is made for further on-site compression, storage, or the
logistics operation that would be required to transport the hydrogen (tube
trailers etc.).
WE fixed
opex£420k/yr Based on 2% of capex per annum.
System
efficiency55 kWh/kg Improvement on current values in line with technology developers’ aims.
Load factor 80% This is a relatively high value (optimistic assumption). Tested as a sensitivity.
Economic
assumptions7%, 10 years
Net present value (NPV) calculated over a period of ten years using a relatively
low discount rate of 7%.
Electricity
price£45 per MWh
Within the range of figures from the “co-location” operating strategy defined
above.
Other
assumptions
Water consumption of 40
litres/kgH2, price of 0.1p/litre
Water costs make up a small proportion of the overall variable opex (electricity
costs dominate).
Value of
hydrogen
From £3/kg to £4/kg, central
case of £3.50/kg
This corresponds to the value of hydrogen from the electrolyser (i.e. pre-
compression and distribution). A value of £3.50/kg gives scope for costs of
compression, distribution and dispensing to the transport sector (where a sale
price in the region of £6–7/kg could be expected). The results below explore
the impact of a range of assumptions regarding the average value of hydrogen.
67
For a large-scale system the potential returns are highly sensitive
to the on-going costs and revenues
* This is in contrast to the community heat scenario explored above, where capital costs have a far greater
influence on the overall economic case.
-40
-30
-20
-10
0
10
20
2020 20222021 2024 20292023 2028202720262025
Revenue (£3.50/kg)
Fixed opex
Variable opex
Capex
£m
in
ye
ar
NPV
(2020–2029) at
7% discount rate
+£3.4m
• This scale (30MW) would require significantly higher levels of capex compared to the community
heat option; e.g. the net cash flow after the first year of operation of this project is –£18m.
• The cash flows above are based on revenues from hydrogen sale of £3.50/kg. This value is
consistent with supply to the transport market (with scope for logistics costs to be added).
• Failure to secure this level of revenue from hydrogen sales is a major risk to the economic case –
i.e. NPV rapidly turns negative with a reduction in value of hydrogen produced.
• At a net electricity price of £50/MWh (rather than £45/MWh as shown above), the NPV is –£4m.
• As the graph shows, if capital cost reduction targets can be met, then the economics of this type of
solution are dictated mainly by the on-going costs and revenues – i.e. the NPV is highly sensitive to
electricity price and hydrogen selling price assumptions.*
All values in 2015 prices
Large-scale WE scenario – annual cash flow
68
Large-scale system – sensitivity testing
Sensitivity test scenarios
Sensitivity test – results
Scenario Test values (all other values as per the Central scenario)
Electricity price seen by electrolyserResults for net prices of £40/MWh and £50/MWh shown (Central value =
£45/MWh).
Value of hydrogen produced Sensitivity test results for £3/kg and £4/kg (Central value = £3.50/kg).
Plant utilisation Average annual load factor values of 65% / 90% tested (Central value = 80%).
-1.6
+16.8
-10.0
-4.0
+10.8
+3.4+6.7
£50/MWh
electricity
90%
utilisation
65%
utilisation
H₂ value
£4/kg
H₂ value
£3/kg
£40/MWh
electricity
Central
NPV (2016–2025), 7% discount rate (£m)
• These results highlight the highly
sensitive nature of the economic
case to on-going costs (electricity)
and revenues (hydrogen sales).
• Seeking long-term agreements
(particularly PPAs and hydrogen
supply) would be an important
aspect of de-risking an investment
on this scale.
69
Large-scale system scenario – risk register
Risk Mitigation
Water electrolyser technology development less rapid than
anticipated, leading to higher cost equipment.
Engage with electrolyser OEMs to understand pace of
technology development. Test sensitivity of business case
to higher capital cost equipment.
Poor reliability / availability of equipment (especially if
undertaking first-of-a-kind installation).
Select technology based on proven designs (systems are
modular, which means a large-scale installation would
comprise multiple smaller units). Include budget for
preventative maintenance and contractual commitments for
availability.
Difficulties in obtaining planning permission and safety case
sign-off.
Engage local community early in the project, ensure all
relevant safety experts are involved in development of
plans.
Lack of skills to install and operate this type of plant.Work closely with equipment supplier, plan specialist
training to develop skills.
Lack of demand for hydrogen produced.
Secure a number of anchor demands for hydrogen (ideally
long-term contracts) in parallel to developing the project.
Consider developing alternative demands (e.g. methanation
plant).
Limited access to low cost electricity, leading to high production
costs and undermining the business case.
Secure long-term agreements with local generators for
purchase of power at mutually beneficial rates.
Operational risks arising from complexity of the operations
(which would require establishment of logistics operation with
regular delivery of hydrogen beyond the Dunbar area).
Develop robust operating plans and procedures to follow in
the event of any issues.
70
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
71
• This feasibility study considered a range of potential end uses for hydrogen generated by an
electrolyser using locally generated renewable electricity.
• During the first phase of the study a number of options were ruled out:
– Power-to-gas – on the basis of poor economic viability, high complexity, regulatory barriers,
and limited local benefit.
– Dedicated hydrogen network – analysis suggests that serving distributed heat demands is
unlikely to provide a sustainable business case. Scope for expansion with this option is also
relatively limited.
– Industrial use – despite engagement with businesses such as Lafarge (cement works) and
the Belhaven Brewery, no clear opportunity for hydrogen in industrial applications was
identified.
• More detailed investigation of using hydrogen to meet a concentrated local heat demand (e.g. the
leisure centre) revealed that the economic case is challenging (and relies on access to very low cost
electricity). The investment case can be improved by seeking to serve other higher value markets –
in particular the transport sector as the number of hydrogen-fuelled vehicles in operation grows.
• A more medium to long-term solution would involve the installation of an electrolysis system at a
scale that could remove / delay the need for grid upgrades (e.g. tens of megawatts). This type of
project would rely on development of a significant high value demand for hydrogen (beyond
Dunbar), technology advances (including lower costs), and could take a number of years to develop.
The leisure pool is a potential source of demand for H2 in the near
term, but higher value uses are needed to improve the economics
Dunbar water electrolyser feasibility study – conclusions
72
This study’s strategic drivers (meeting local energy needs from local resources, facilitating increased
deployment of renewable generators, reducing dependence on fossil fuels) are relevant to other
communities across Scotland and beyond. This study’s analysis leads to the following conclusions.
• Hydrogen-based energy storage solutions can contribute to increased deployment and use of
renewable generators from a technical perspective (e.g. responsive electrolysers offer a flexible
source of local demand for electricity). However, the economics of these types of system are often
challenging, mainly as a result of high set-up and operating costs and the lack of a high value use
for hydrogen locally.
– Equipment costs are currently fairly high, hence a positive economic case typically requires
high annual full load run hours. However, this type of operating mode is not necessarily
consistent with using electrolysers as a flexible load (i.e. demand side response applications).
– The most promising opportunities for deployment of commercially viable hydrogen-based
energy storage systems are in communities with high fuel costs, severe network constraints
(leading to availability of very low cost electricity), and access to power behind the meter (via a
private wire / virtual private wire) so that network charges can be avoided.
• For a meaningful impact in terms of facilitating greater uptake of renewable generators, megawatt-
scale solutions are required, which can only be justified if relatively large demands for hydrogen can
be established (tonnes per day). These types of solution would involve on-going logistics operations
to deliver hydrogen to sources of demand and may become feasible if the value of delaying /
removing the need for grid upgrades could be captured and if electrolyser costs fall over time.
A combination of low cost electricity and relatively high value use
for hydrogen is needed for a positive WE investment case
Water electrolyser feasibility – conclusions
74
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
– Electricity networks and prices
– Methanation – further details
75
Electricity network map (1)
Source: Google Earth.
76
Electricity network map (2)
Source: Google Earth.
77
Electricity network map (3)
Source: Google Earth.
78
Breakdown of household (domestic) electricity bills
* www.ofgem.gov.uk/ofgem-publications/64006/householdenergybillsexplainedudjuly2013web.pdf.
4%
5%
16%58%
5%
11% Wholesale energy, supply costs & profit margin
DUoS charges
TUoS charges
VAT
Other costs
Environmental charges
Illustrative grid electricity price breakdown for domestic customers in the UK
Based on electricity prices in December 2012, average annual electricity bill of £531 (GB average).
Source: Ofgem Factsheet 98 (February 2013)*
• Environmental charges cover costs of government programmes to reduce emissions and tackle
climate change (Energy Company Obligation, Renewables Obligation, Feed-in Tariff).
• Other costs include costs of installation and maintenance of meters, and electricity balancing system.
79
Red / amber / green time bands (which affect DUoS charges) – half
hourly metered properties
Source: Scottish Power
www.scottishpower.com/userfiles/document_library/SPD_Indicative_LC14_Statement_2015.pdf
80
Red / amber / green time bands (which affect DUoS charges) – half
hourly unmetered properties
Source: Scottish Power
www.scottishpower.com/userfiles/document_library/SPD_Indicative_LC14_Statement_2015.pdf
81
Variations in UK electricity spot market price on an annual /
monthly basis – values range from c.£30–50/MWh
0
44
46
48
42
40
38
Mar AugMayFeb DecNovJan June SeptApr OctJuly
0 5 10 15 20 25 30
40
0
35
45
50
APX Power UK electricity spot price (2014)
£/M
Wh
Maximum 47.5
Average 42.1
Minimum 36.1
£/MWh
Maximum 50.0
Average 38.5
Minimum 31.4
£/MWhAPX Power UK electricity spot price (January 2015)
Day of month
£/M
Wh
Source: APX Group: www.apxgroup.com/market-results/apx-power-uk/dashboard/.
82
Intraday prices may show greater variations, but negative prices
are not currently permitted in the GB intraday market
70
50
60
0
40
13 1914 221712 16 18 21207653 1582 101023 9 114
APX Power UK Day-Ahead Auction – Results (18th February 2015)*
£/M
Wh
Maximum 69.95
Average 40.7
Minimum 29.75
£/MWh
* Source: APX Group: www.apxgroup.com/market-results/apx-power-uk/dashboard/.
Hour of day
“In GB, negative electricity prices are not supported in the intraday market, but are allowed on the day-ahead
market (By September 2014, this development had not yet occurred.) Because the lowest price limit for
participants in the GB intraday market is zero, negative prices cannot occur as market participants cannot
enter a potential trade with a value below zero. This lower limit is, however, being investigated, and may well
change to harmonise with the day-ahead market, where the lower limit is minus £400 (a negative price of
£400). If this happens, the GB intraday spot market price would then have the potential to become negative.”
Source: Edward Barbour, Grant Wilson, Peter Hall & Jonathan Radcliffe (2014) Can negative electricity prices encourage
inefficient electrical energy storage devices?, International Journal of Environmental Studies, 71:6, 862-876, DOI:
10.1080/00207233.2014.966968
http://dx.doi.org/10.1080/00207233.2014.966968
83
Typical price duration curves for electricity in Britain are relatively
flat for a significant portion of the year
APX Power UK Day-Ahead Auction results – average prices (2013)*
* Source: APX Group: www.apxgroup.com/market-results/apx-power-uk/dashboard/.
Days per
year% of year
Average
base price
(£/MWh)
36 10% 42.10
100 27% 44.54
180 49% 45.95
275 75% 47.46
• The price duration curve above is based on data published by APX Group on day-ahead auction
results for 2013. The table shows the average prices (using “base” data) for selected proportions of
the year (assuming a flexible demand that could consume power during periods of lowest prices).
• As the previous slide suggests, negative prices are permitted on the day-ahead market in Britain but
have not been observed to date. The lower price limit on the intraday market in GB is zero.
• While negative prices are allowed in some markets (e.g. the European Power Exchange, covering
France, Germany, Austria, Switzerland), their occurrence is rare – e.g. negative prices in Germany
were observed for 56 hours in 2012 and 48 hours in 2013 (0.64% and 0.55% of the year
respectively). Source: EPEX, as report at www.energypost.eu/case-allowing-negative-electricity-prices/
Average base prices if targeting lowest
wholesale prices
Base price average over
lowest 275 days per year
Average over lowest
36 days per year
84
Price duration curves in the wholesale market are expected to
alter with changes to the generation mix over time
* Source:
• Previous studies (e.g. by Pöyry)
have considered the potential
impact of changes to the generation
mix on electricity price in Britain.
• The curves shown are from models
of the GB electricity system out to
2030, for scenarios with tens of
gigawatts of wind capacity installed.
• These results suggest that by 2020
there may be a small number of
periods of zero prices, and that by
2030 negative prices may be seen
(at the other end of the scale the
price spikes also become more
extreme).
• Clearly there is some uncertainty
regarding how wholesale electricity
prices will change over time, but
there is currently little evidence to
suggest that very low or negative
prices will be sustained for
significant portions of the year.
Price duration curves with high penetration of wind
generation in 2020 and 2030Source: Impact of intermittency: how wind variability could change the shape of the British
and Irish electricity markets, Summary Report, Pöyry (July 2009), (Figure 11, p.13).
Source: Pöyry (2009)
85
There may be scope to develop electrolyser-specific electricity
tariffs that take advantage of variations in wholesale power prices
APX Power – half hourly reference price data (2014)*
* Source: APX Group: www.apxgroup.com/
Half hourly
periods per
year
% of year
Average
price
(£/MWh)
1,728 10% 27.1
4,800 27% 30.7
8,640 49% 33.4
13,200 75% 36.6
• This price duration curve shows APX Group’s Reference Price Data (half hourly only) for 2014. The
table shows the average prices for selected proportions of the year (assuming a flexible demand that
could consume power during periods of lowest prices).
• In the UK half hourly electricity meters are typically installed at sites where peak loads exceed 100kW.
• To take advantage of the flexibility of a water electrolyser installation (i.e. the ability to rapidly respond
to price signals), the plant operator would need a trading partner (with a supply licence). This could be
a traditional energy supplier, or a specialist broker / trader. Systems to exchange information on
consumption in near real time would also need to be implemented.
Average half hourly prices if targeting
lowest price electricity
Average over lowest
75% of the year
Average over
lowest 10%
of the year
86
A number of wind projects in the Dunbar area are facing the prospect of curtailment (from c.2017):
• Ferneylea, 1.5 MW, operational
• Hoprigshiels, 6–9 MW, consented
• Neuk Farm / Kinegar Quarry, 5 MW, consented
Curtailment assessments suggest that Ferneylea’s output may be curtailed on c.95 days per year
(mainly in winter), with a loss of generation of up to around 20% of the unconstrained output.
The chart below shows the number of days per year on which a given level of curtailment is expected.
A number of operational and planned wind farms (MW-scale) risk
curtailment over the coming years
Source: data from CES.
Example wind projects facing curtailment
Potential curtailment – further details
345
12
24
47
56-69% >68%14-28% 42-56%28-42%Up to 14%
Da
ys
pe
r ye
ar
Curtailment level (% of peak daily output)
No curtailment on c.270 days/yr
(75% of the year)
Note: network upgrades planned for the early 2020s could have a significant impact on curtailment
(i.e. reduce / eliminate such events).
87
WE capex (£/kW)
125 500
550
600
650
700
750
800
850
900
950
1,00
0
1,05
0
1,10
0
1,15
0
1,20
0
1,25
0
1,30
0
1,35
0
1,40
0
1,45
0
1,50
0
1,55
0
1,60
0
1,65
0
1,70
0
1,75
0
1,80
0
1,85
0
1,90
0
1,95
0
2,00
0
-20 -19.1 -17.7 -16.3 -14.8 -13.4 -12.0 -10.6 -9.2 -7.7 -6.3 -4.9 -3.5 -2.1 -0.6 0.8 2.2 3.6 5.1 6.5 7.9 9.3 10.7 12.2 13.6 15.0 16.4 17.9 19.3 20.7 22.1 23.5
-15 -10.5 -9.1 -7.6 -6.2 -4.8 -3.4 -1.9 -0.5 0.9 2.3 3.7 5.2 6.6 8.0 9.4 10.8 12.3 13.7 15.1 16.5 18.0 19.4 20.8 22.2 23.6 25.1 26.5 27.9 29.3 30.8 32.2
-10 -1.8 -0.4 1.0 2.4 3.8 5.3 6.7 8.1 9.5 11.0 12.4 13.8 15.2 16.6 18.1 19.5 20.9 22.3 23.8 25.2 26.6 28.0 29.4 30.9 32.3 33.7 35.1 36.5 38.0 39.4 40.8
-5 6.8 8.2 9.6 11.1 12.5 13.9 15.3 16.7 18.2 19.6 21.0 22.4 23.9 25.3 26.7 28.1 29.5 31.0 32.4 33.8 35.2 36.7 38.1 39.5 40.9 42.3 43.8 45.2 46.6 48.0 49.4
0 15.4 16.9 18.3 19.7 21.1 22.5 24.0 25.4 26.8 28.2 29.6 31.1 32.5 33.9 35.3 36.8 38.2 39.6 41.0 42.4 43.9 45.3 46.7 48.1 49.6 51.0 52.4 53.8 55.2 56.7 58.1
5 24.1 25.5 26.9 28.3 29.8 31.2 32.6 34.0 35.4 36.9 38.3 39.7 41.1 42.6 44.0 45.4 46.8 48.2 49.7 51.1 52.5 53.9 55.3 56.8 58.2 59.6 61.0 62.5 63.9 65.3 66.7
10 32.7 34.1 35.5 37.0 38.4 39.8 41.2 42.7 44.1 45.5 46.9 48.3 49.8 51.2 52.6 54.0 55.5 56.9 58.3 59.7 61.1 62.6 64.0 65.4 66.8 68.2 69.7 71.1 72.5 73.9 75.4
15 41.3 42.8 44.2 45.6 47.0 48.4 49.9 51.3 52.7 54.1 55.6 57.0 58.4 59.8 61.2 62.7 64.1 65.5 66.9 68.4 69.8 71.2 72.6 74.0 75.5 76.9 78.3 79.7 81.1 82.6 84.0
20 50.0 51.4 52.8 54.2 55.7 57.1 58.5 59.9 61.4 62.8 64.2 65.6 67.0 68.5 69.9 71.3 72.7 74.1 75.6 77.0 78.4 79.8 81.3 82.7 84.1 85.5 86.9 88.4 89.8 91.2 92.6
25 58.6 60.0 61.5 62.9 64.3 65.7 67.1 68.6 70.0 71.4 72.8 74.3 75.7 77.1 78.5 79.9 81.4 82.8 84.2 85.6 87.0 88.5 89.9 91.3 92.7 94.2 95.6 97.0 98.4 99.8 101.3
30 67.2 68.7 70.1 71.5 72.9 74.4 75.8 77.2 78.6 80.0 81.5 82.9 84.3 85.7 87.2 88.6 90.0 91.4 92.8 94.3 95.7 97.1 98.5 99.9 101.4 102.8 104.2 105.6 107.1 108.5 109.9
35 75.9 77.3 78.7 80.2 81.6 83.0 84.4 85.8 87.3 88.7 90.1 91.5 92.9 94.4 95.8 97.2 98.6 100.1 101.5 102.9 104.3 105.7 107.2 108.6 110.0 111.4 112.9 114.3 115.7 117.1 118.5
40 84.5 85.9 87.4 88.8 90.2 91.6 93.1 94.5 95.9 97.3 98.7 100.2 101.6 103.0 104.4 105.8 107.3 108.7 110.1 111.5 113.0 114.4 115.8 117.2 118.6 120.1 121.5 122.9 124.3 125.8 127.2
45 93.2 94.6 96.0 97.4 98.8 100.3 101.7 103.1 104.5 106.0 107.4 108.8 110.2 111.6 113.1 114.5 115.9 117.3 118.8 120.2 121.6 123.0 124.4 125.9 127.3 128.7 130.1 131.5 133.0 134.4 135.8
50 101.8 103.2 104.6 106.1 107.5 108.9 110.3 111.7 113.2 114.6 116.0 117.4 118.9 120.3 121.7 123.1 124.5 126.0 127.4 128.8 130.2 131.7 133.1 134.5 135.9 137.3 138.8 140.2 141.6 143.0 144.4
55 110.4 111.9 113.3 114.7 116.1 117.5 119.0 120.4 121.8 123.2 124.6 126.1 127.5 128.9 130.3 131.8 133.2 134.6 136.0 137.4 138.9 140.3 141.7 143.1 144.6 146.0 147.4 148.8 150.2 151.7 153.1
60 119.1 120.5 121.9 123.3 124.8 126.2 127.6 129.0 130.4 131.9 133.3 134.7 136.1 137.6 139.0 140.4 141.8 143.2 144.7 146.1 147.5 148.9 150.3 151.8 153.2 154.6 156.0 157.5 158.9 160.3 161.7
65 127.7 129.1 130.5 132.0 133.4 134.8 136.2 137.7 139.1 140.5 141.9 143.3 144.8 146.2 147.6 149.0 150.5 151.9 153.3 154.7 156.1 157.6 159.0 160.4 161.8 163.2 164.7 166.1 167.5 168.9 170.4
70 136.3 137.8 139.2 140.6 142.0 143.4 144.9 146.3 147.7 149.1 150.6 152.0 153.4 154.8 156.2 157.7 159.1 160.5 161.9 163.4 164.8 166.2 167.6 169.0 170.5 171.9 173.3 174.7 176.1 177.6 179.0
75 145.0 146.4 147.8 149.2 150.7 152.1 153.5 154.9 156.4 157.8 159.2 160.6 162.0 163.5 164.9 166.3 167.7 169.1 170.6 172.0 173.4 174.8 176.3 177.7 179.1 180.5 181.9 183.4 184.8 186.2 187.6
80 153.6 155.0 156.5 157.9 159.3 160.7 162.1 163.6 165.0 166.4 167.8 169.3 170.7 172.1 173.5 174.9 176.4 177.8 179.2 180.6 182.0 183.5 184.9 186.3 187.7 189.2 190.6 192.0 193.4 194.8 196.3
85 162.2 163.7 165.1 166.5 167.9 169.4 170.8 172.2 173.6 175.0 176.5 177.9 179.3 180.7 182.2 183.6 185.0 186.4 187.8 189.3 190.7 192.1 193.5 194.9 196.4 197.8 199.2 200.6 202.1 203.5 204.9
90 170.9 172.3 173.7 175.2 176.6 178.0 179.4 180.8 182.3 183.7 185.1 186.5 187.9 189.4 190.8 192.2 193.6 195.1 196.5 197.9 199.3 200.7 202.2 203.6 205.0 206.4 207.9 209.3 210.7 212.1 213.5
95 179.5 180.9 182.4 183.8 185.2 186.6 188.1 189.5 190.9 192.3 193.7 195.2 196.6 198.0 199.4 200.8 202.3 203.7 205.1 206.5 208.0 209.4 210.8 212.2 213.6 215.1 216.5 217.9 219.3 220.8 222.2
100 188.2 189.6 191.0 192.4 193.8 195.3 196.7 198.1 199.5 201.0 202.4 203.8 205.2 206.6 208.1 209.5 210.9 212.3 213.8 215.2 216.6 218.0 219.4 220.9 222.3 223.7 225.1 226.5 228.0 229.4 230.8
Hydrogen production cost < £50/MWh £50–100/MWh £100–150/MWh >£150/MWh
Net
ele
c.
pri
ce (
£/M
Wh
)
• Generators typically receive c.£50/MWh for their
output, plus any incentive payments (ROCs / FiT).
• The current values of these incentives are shown in
the table.
Electricity may be available at below retail prices but very low cost
(or free) power is not likely to be available throughout the year
Incentives for RES-E generation
Implications for a local water electrolyser
RES-E incentives £/MWh
Wind >500 kW – 1.5 MW (<30/09/14) – FiT 80.4
Wind >500 kW – 1.5 MW (from 01/10/14) – FiT 72.4
Solar PV (>250 kW) – FiT 63.8
Export tariff (01/04/14 to 31/03/15) – FiT 47.7
Onshore wind (0.9 ROCs/MWh) 39.0
• It is unlikely that an electrolyser will be able to access very low cost (£50/MWh or less) electricity
throughout the year (the business case for wind farms depends on receiving market value for the
output). This is particularly true for large electrolysers with relatively high electricity demands.
• Mechanisms to provide electrolysers with some of the benefit (incentive payments) from allowing
otherwise curtailed generation may be possible.
• These could give low net electricity prices at
certain times but will not guarantee a constant
supply of cheap electricity.
Net electricity price to
electrolyser is likely to
be in this range
88
• Introduction
• Overview of hydrogen and water electrolysis
• Electricity prices and local generation
• Demand profiles
• Options assessment
• Community heat – detailed assessment
• Large-scale system – detailed assessment
• Conclusions
• Appendix
– Electricity networks and prices
– Methanation – further details
89
Chemical versus biological methanation
Source: ITM Power (2014) and Electrochaea (2014).
Parameter Chemical Biological
Maximum scale sold ~500MW ~500kW
Operating pressure ~50 bar Atmospheric, up to 50 bar
Operating temperature 200–500oC ~50oC
Contamination tolerance
(H2S, O2, KOH)Low High
Heat produced in reaction Useful Useless
Operating range50–100%
(H2 storage required)
0–100%
(less H2 storage required)
Scalability Low High (can be scaled down)
Energy requirements when
offNone
Heat needed to prevent
freezing
90
Biological methanation – in-situ vs. ex-situ
In-situ
• Hydrogen is injected into an anaerobic digester.
• This may cause the pH to rise inside the reactor, as the hydrogenotrophic methanogens consume
CO2 which would otherwise form a bicarbonate buffer; this may inhibit microbial activity especially
at higher loading rates. The “in-situ” process may allow the methane content in the biogas to be
increased from about 50% to over 75%. This leads to approximately a 50% increase in the energy
output of the reactor. However, further upstream upgrading will still be required to remove the
remaining CO2 if the gas is to be used as a transport fuel or grid-injected.
Ex-situ
• Methanation process is carried out in a separate vessel.
• It has been suggested that despite the additional CAPEX costs, ex-situ upgrading is preferable to
in-situ upgrading as it avoids many of the biological and mechanical challenges present in
anaerobic digestion. The ex-situ process may be fed with CO2 from a biogas upgrading system.
However it is preferable to feed raw biogas to the ex-situ process as this can replace the traditional
biogas upgrading step. Typically the traditional biogas upgrading step (such as water scrubbing)
would cost approximately 25% of the CAPEX of the whole biomethane facility and be energy
intensive (consume 0.5 kWeh/mn 3 biomethane). The methanogens are fed with 4 moles of H2 for
each mole of CO2, as well as a nutrient medium to maintain the microbial population. Industry
sources indicate that it should be possible to achieve grid-injection standards using this technique.
Source: A perspective on the potential role of renewable gas in a smart energy island system, Ahern et al,
University College Cork (2015).
91
Examples of methanation projects – completed (non-exhaustive)
Project Location Scale Period Partners
Electrochaea
pre-commercial
field trial
Foulum,
Denmark10,000 litre reactor Jan – Nov 2013
KIC project
DemoSNG
Cortus
gasification
plant
Bench scale
(10m3/h)2011 – 2014
DVGW-EBI
KIT
KTH
Cortus Energy
Gas Natural Fenosa
ZSW &
SolarFuel
(ETOGAS)
Stuttgart250kWe alkaline
WE, 12.5m3/h CH4)
Commissioned Oct
2012
ZSW
Fraunhofer
SolarFuel
92
Examples of methanation projects – on-going (non-exhaustive)
SOEC: solid oxide electrolyser cell.
Project Location Scale Period Partners
BioPower2GasViessmann HQ,
Allendorf, Eder
5,000 litre fermenter
WE of 100s of kW,
60Nm3/h H2,
15Nm3/h CH4
Sept 2013 –
August 2016 (plant
commissioning
Sept 2014)
Viessmann
Cube
EAM
IdE
BioCat
SVC Avedøre,
near
Copenhagen
1MW alkaline WE,
biological
methanation
Feb 2014 – Dec
2015
Electrochaea
Hydrogenics
Audi, Insero
Neas Energy
HMN Gashandel
Biofos. Energinet.dk
Audi e-gas Werlte
6MWe alkaline WE,
methanation reactor
from MAN +
ETOGAS
(chemical)
Operational since
2013
Audi
ETOGAS
ZSW, EWE
Fraunhofer
MT BioMethan
HELMETH
Proof-of-concept for
high efficiency
power-to-methane
technology (SOEC
WE + chemical
methanation)
April 2014 – March
2017
Karlsruhe Institute of
Technology (KIT)
Sunfire GmbH
Turbo Service Torino
+ other research
institutes & universities