For Dunbar Local Energy Innovation Consortium by 2030.* ... • Proton exchange membrane (PEM) electrolysers (solid polymer electrolyte, typically Nafion)

1

Dunbar water electrolyser feasibility studyFor Dunbar Local Energy Innovation Consortium

Phase 3 report

May 2015

Michael Dolman

Ben Madden

Element Energy Limited

2

• 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

3

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.

4

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

+

5

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.

http://www.spenergynetworks.co.uk/pages/arc_accelerating_renewable_connections.asp

6

• Introduction



• Demand profiles




• Conclusions

• Appendix

7

• 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

8

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

9

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.

10

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

11

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.

12

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.

13

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)

http://www.hydrogenics.com/docs/default-source/pdf/renewable-projects-references---grid-balancing-and-ptg.pdf?sfvrsn=0

14

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)

http://fuelcellsworks.com/news/2015/01/14/proton-onsite-introduces-worlds-first-pem-megawatt-electrolyzer-for-the-growing-global-energy-storage-market/

15

• 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.

16

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)

17

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


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)



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


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


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


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


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)


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.



• 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



• Demand profiles




• 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.

http://www.scottishpower.com/pages/connections_use_of_system_and_metering_services.asp

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

http://www2.nationalgrid.com/uk/services/balancing-services/

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


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


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


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


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


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



• Demand profiles




• 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.


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


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


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



• Demand profiles


– Hydrogen for heat, transport, or industry

– Hydrogen for methanation



• 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



• Demand profiles


– Hydrogen for heat, transport, or industry

– Hydrogen for methanation



• 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

http://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.

http://www.biogas-info.co.uk/


http://www.biogas-info.co.uk/ad-map.html

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


https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/384202/Biomethane_Tariff_Review_-_Government_Response_-_December_2014.pdf

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).

http://www.bbc.co.uk/news/uk-scotland-edinburgh-east-fife-11796416

http://biocat-project.com/

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



• Demand profiles




• 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 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



• Demand profiles




• 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

http://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 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



• Demand profiles




• 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



• Demand profiles




• Conclusions

• Appendix

– Electricity networks and prices

– Methanation – further details

75

Electricity network map (1)

Source: Google Earth.

76



77



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.

http://www.ofgem.gov.uk/ofgem-publications/64006/householdenergybillsexplainedudjuly2013web.pdf

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

http://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

http://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/.

http://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


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


http://www.energypost.eu/case-allowing-negative-electricity-prices/

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


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



• Demand profiles




• 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

Documents

For Dunbar Local Energy Innovation Consortium by 2030.* ... • Proton exchange membrane (PEM) electrolysers (solid polymer electrolyte, typically Nafion)