Dunbar water electrolyser feasibility study For Dunbar Local Energy Innovation Consortium

Transcription

1 Dunbar water electrolyser feasibility study For Dunbar Local Energy Innovation Consortium Phase 3 report May 2015 Michael Dolman Ben Madden Element Energy Limited 1

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 2

3 Background: a feasibility study to investigate the potential for electrolysis to contribute to the resolution of local energy issues 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. Background 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. The primary objectives of any water electrolyser deployment project in Dunbar include: Project drivers 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. 3

4 Context: this study builds on preliminary work undertaken by the Dunbar Local Energy Innovation Consortium 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 CARES, managed by LES Infrastructure & innovation fund + Dunbar Local Energy Innovation Consortium Background work Broader context 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. 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. CARES: Community And Renewable Energy Scheme, LES: Local Energy Scotland, CES: Community Energy Scotland. 4

5 Accelerating Renewable Connections (ARC) project summary Project objectives Improve access to connect generators allow connections around constraints. Reduce time (and cost) of connection. Geographic scope: East Lothian & Borders Solutions being implemented Active Network Management (ANM) Curtailment analysis tool Two stage commercial agreements Real-time monitoring and control of networks. Ability to send signals to generators to request reduced output. This allows better use of existing assets. Online tool to allow assessment of potential curtailment and costs of connection. Expected to be available from April 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). Budget 7.4m Duration Jan Dec 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. See also: 5

6 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 6

7 There is increasing interest in hydrogen as a clean energy vector that may provide economic, social and environmental benefits 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. Relevant Scottish policy drivers for H 2 Low carbon economy Energy security Skills diversification Future economic growth Climate change and the environment H 2 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 Numerous H 2 production pathways can contribute towards de-risking future energy-supply. Locally produced fuel can provide significant balance of payment benefits. Areas of the H 2 supply chain (e.g. high pressure gas handling) will provide suitable demand for Scotland s skills and knowledge honed from the oil & gas sector. Developing early supply chains / skills in the H 2 sector can prepare regions for export as the technology becomes widespread. H 2 vehicles only emit water, therefore increased use of the H 2 in vehicles leads to improved air quality, particularly when used in urban centres. H 2 can be produced directly from renewables, thereby contributing significantly to reducing CO 2 emissions. * Global annual energy consumption = 104 PWh (IEA, 2011), global annual hydrogen production = 50 million tonnes (NREL, 2013), H 2 LHV = 33 kwh/kg. 7

8 Globally several emerging hydrogen technologies are receiving increased attention as alternative energy solutions Most prominent early sectors for hydrogen as an energy vector Transport Distributed generation Power-to-gas Eliminate CO 2 and air quality impacts associated with fossil fuel vehicle emissions EU proposes a 40% CO 2 emission reduction by * 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).** Drivers Relevance Help integrate intermittent renewables into the grid by producing H 2 at times of high generation but low demand. Create seasonal energy storage reserves existing electrochemical technologies are suited to minutes/days of storage duration. Hyundai ix35 Fuel Cell First generation fuel cell electric vehicle, achieves mileage comparable to conventional cars but with zero tailpipe emissions. 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 H 2 feedstock. E-ON s 2 MW power-2-gas facility in Falkenhagen, Germany Water electrolyser units to generate H 2 for injection into existing regional natural gas transmission system. * Clean Energy Patent Growth Index 2013 Year in Review. ** Comparison of fuel cell technologies, DoW (2014) and DUKES (2013) 8

9 The hydrogen sector is complex and links a range of energy sources and end uses Hydrocarbons Carbon Capture and Storage CO 2 (if any) Hydrogen production* H 2 Methanation (synthetic methane) Methane Hydrogen injection into the natural gas grid * 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. Local / national gas grid Electricity Methane H 2 Power and / or heat generation Domestic / commercial heating or CHP Grid balancing Back-up and portable power Passenger and fleet vehicles Hydrogen storage, distribution and dispensing H 2 Mobility Buses and coaches Material handling and specialty vehicles Boats H 2 High temperature fuel Industry H 2 Chemical Chemical and refinery industry SMR = Steam Methane Reforming. 9

10 Water electrolysis introduction Overview of water electrolysis 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: 2H 2 O (l) O 2(g) + 4H + + 4e Reduction of protons at the (negative) cathode: 2H + + 2e H 2(g) Overall: 2H 2 O (l) O 2(g) + 2H 2(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. Electrolyser types 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 ( o C), and the technology offers the promise of reduced cost and increased efficiency relative to today s technology. 10

11 Water electrolyser types a comparison of technical & economic characteristics Development status System size range Alkaline Commercial 1.8 6,000 kw Nm 3 /hr Proton exchange membrane Commercial (small to medium scale, <300kW) 0.2 1,150 kw Nm 3 /hr Hydrogen purity 99.5% % 99.9% % 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) kwh/kgh kwh/kgh 2 Pressurisation bar 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 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. 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

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. Figures for larger systems based on targets (products under development) Notes Costs are for complete electrolyser systems (including purification equipment) producing hydrogen at 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. 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) * Source: FCH JU Multi Annual Work Plan (ID623483), Converted from euros at 1.3 euro per GBP. 12

13 Alkaline water electrolyser suppliers Selection of suppliers (non-exhaustive) Supplier Location Example products Relevant experience HQ in Canada, manufacturing in Germany & Belgium HySTAT kgH 2 /day 480 kva First generation HySTAT products launched in 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 A ,000kgH 2 /day 220kW 2MW Hundreds of installations in >50 countries over the past four decades. Unst, Shetland, Scotland PureH2 series Up to 90kgH 2 /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. Note: Pure Energy Systems act as an integrator, they are not an electrolyser OEM. * Source: company websites, personal communication. 13

14 Proton exchange membrane (PEM) water electrolyser suppliers Selection of suppliers (non-exhaustive) 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.4kgh 2 /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 kgH 2 /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 SILYZER MW From Q Four SILYZER100 (100kW) units sold to date, now discontinued to focus on MW-scale systems. Source: company websites. * 14

15 We can calculate the cost of producing electrolytic hydrogen for comparison against incumbent fuels Water electrolysis economics 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 /kgh 2, which can be converted into /MWh, as shown on the following slides (lower heating value of H 2 = 33.3kWh/kg). Modelling assumptions Metric Value Notes Capital cost* Annual operating cost Results for a range from 500/kW to 2,000/kW 2% of capex 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. 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 efficiency 57 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 assumptions 7%, 15 years Capital costs amortised at 7% over a 15 year period. Electricity price Other assumptions Range from 20 to per MWh Water consumption of 40 litres/kgh 2, price of 0.1p/litre This value represents the net electricity price to the electrolyser averaged over the year (negative price = WE being paid to run). In terms of variable opex, the cost of water is generally very low compared to electricity costs, but included for completeness. * NB: Electrolyser costs are expected to fall with technology development and increasing deployment over the coming years. 15

16 Increasing net electricity price Cost of hydrogen produced is sensitive to electrolyser capex and electricity price (among other factors) Access to low cost electricity is a key factor in developing an economically sustainable hydrogen production system using water electrolysis. Net elec. price ( /MWh) WE capex ( /kw) Gas heating equivalent (c. 40/MWh) Increasing water electrolyser capital cost 950 1,000 1,050 1,100 1,150 1,200 1,250 1,300 1,350 1,400 1,450 1,500 1,550 1,600 1,650-5 Oil heating equivalent (c /MWh) Wholesale gas + RHI (c. 90/MWh) Electric heating equivalent (c. 120/MWh) Transport equivalent (c. 165/MWh) Based on 115p/litre diesel cost, 40mpg and 80km/kgH FCEV ,700 1,750 1,800 1,850 1,900 1,950 2,000 Hydrogen production cost < 50/MWh /MWh /MWh > 150/MWh Plot of hydrogen cost (expressed as /MWh) as a function of electrolyser capex and net electricity price for a fully 90% utilised electrolyser NOTE: the equivalent lines above are illustrative only figures on the diagram and equivalent /MWh values are not necessarily directly comparable. Source: Element Energy. 16

17 Increasing net electricity price Reducing electrolyser load factor will tend to increase the cost of hydrogen, particularly for high capital cost systems 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). Net elec. price ( /MWh) 154 WE capex ( /kw) Increasing water electrolyser capital cost 950 1,000 1,050 1,100 1,150 1,200 1,250 1,300 1,350 1,400 1,450 1,500 1,550 1,600 1,650 1,700 1,750 1,800 1,850 1, Gas heating equivalent (c. 40/MWh) Oil heating equivalent (c /MWh) Wholesale gas RHI (c /MWh) Electric heating equivalent (c. 120/MWh) Transport equivalent (c. 165/MWh) Based on 115p/litre diesel cost, 40mpg and 80km/kgH FCEV Hydrogen production cost < 50/MWh /MWh /MWh > 150/MWh Plot of hydrogen cost (expressed as /MWh) as a function of electrolyser capex and net electricity price for a 50% utilised electrolyser 1,950 2,000 Source: Element Energy. 17

18 Under-utilised systems are only likely to produce low cost hydrogen if they can access very low price electricity / other revenues For a given total installed system cost, hydrogen production costs are minimised for well-utilised electrolysers able to access cheap electricity. Decreasing utilisation WE utilisation Electricity price ( 1,500 /kw Increasing net electricity price % % % % % % % % % % Hydrogen production cost < 50/MWh /MWh /MWh > 150/MWh Plot of hydrogen cost (expressed as /MWh) as a function of electrolyser utilisation and net electricity price for a 1,500/kW electrolyser 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. Source: Element Energy. 18

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). Hydrogen production cost These results also highlight the need to access low cost electricity (even for wellutilised electrolysers) if revenues from hydrogen sales are based on supply to low value markets. Source: Element Energy. 19

20 Decreasing utilisation We can also explore the impact of utilisation and capital cost at a fixed electricity price ( 50/MWh in this example) The plot below shows the impact of varying average annual load factor (utilisation) on hydrogen production cost for a set electricity price. WE utilisation WE capex ( 50 /MWh % Increasing water electrolyser capital cost 950 1,000 1,050 1,100 1,150 1,200 1,250 1,300 1,350 1,400 1,450 1,500 1,550 1,600 90% Electric heating equivalent (c /MWh) % % % % % % Transport equivalent (c /MWh) % Based on 115p/litre diesel cost, mpg and km/kgH FCEV % Hydrogen production cost < 50/MWh /MWh /MWh > 150/MWh 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 Water electrolysis economic analysis conclusions At a realistic net electricity price (of c /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). 1,650 1,700 1,750 1,800 1,850 1,900 1,950 2,000 Source: Element Energy. 20

21 Introduction Overview of hydrogen and water electrolysis Electricity prices and local generation Demand profiles Options assessment Community heat detailed assessment Large-scale system detailed assessment Conclusions Appendix 21

22 Investigation of the scope for low cost electricity requires an understanding of the cost base of power supplies Components of electricity cost Illustrative grid electricity price breakdown in the UK Indicative DUoS charges /MWh 15% 10% 20% 55% Wholesale price DUoS charges TUoS charges Other charges / levies Illustrative breakdown see for example the detailed breakdown for domestic bills published by Ofgem (provided in the appendix). 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). ^ Source: APX Power UK Spot prices (monthly) see appendix Red / Black Amber / Yellow Green Source: Scottish Power* Domestic Unrestricted Small Non Domestic Unrestricted Small Non Domestic Two Rate LV Medium Non-Domestic LV HH Metered 1.4 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. * SPD Schedule of Indicative Charges and Other Tables: 22

23 /MWh Avoiding network charges could reduce the cost of electricity by around 30/MWh Electricity prices over time Average electricity prices paid by nondomestic consumers in the UK Consumer size Small ( MWh/yr) Medium (2,000 19,999 MWh/yr) Source: DECC from Table Prices of fuels purchased by non-domestic consumers including the Climate Change Levy This graph shows average prices (ex. VAT) paid by electricity consumers in the nondomestic 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. Electricity price breakdown Small ( MWh/yr) Wholesale price DUoS charges /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 Medium (2,000 19,999 MWh/yr) TUoS charges Other charges / levies Figures based on the 2013 average prices (graph on the left), and typical breakdown from the previous slide. 23

24 Electricity cost breakdown summary Cost element Description 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) * 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 Avoid consumption during peak periods. Charges can be avoided by connecting at grid transmission point, or using a private wire offgrid 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 Charges can be avoided through using a private wire connection. * Depends on scale, tariff type, and utility s margin. 24

25 Provision of balancing services to the transmission network operator is a potential source of revenue for water electrolysers Overview of the balancing market 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. Potential revenues for a water electrolyser 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. * 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/. 25

26 There are a number of potential strategies for economic operation of electrolysers in energy system applications Strategy Co-location Grid services Spot price tracking Curtailment avoidance Description Site electrolyser next to renewable generator to provide guaranteed demand and avoid network charges. Sell balancing services to the transmission system operator (NB: there is currently no mechanism for monetising services at the distribution network level). Operate electrolyser only at times of low wholesale electricity prices. Run electrolyser mainly on otherwise curtailed generation (e.g. using a virtual private wire arrangement) and access a share of RES-E incentives. Typical average annual load factor* Indicative net electricity price ( /MWh)** c.30 80% Up to 100% (depending on size) Up to c.50% <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). 26

27 The optimal strategy for minimising production cost depends on a range of factors (WE capex, revenues available, practical issues etc.) Current capex WE utilisation Future capex WE utilisation Electricity price ( 1,500 /kw % Grid services 90% % Co-location 70% % Spot price tracking 50% % % Curtailment avoidance 20% % Hydrogen production cost < 50/MWh /MWh /MWh > 150/MWh Electricity price ( 750 /kw % Grid services 90% % Co-location 70% % Spot price tracking 50% % % Curtailment avoidance 20% % Hydrogen production cost < 50/MWh /MWh /MWh > 150/MWh Source: Element Energy. 27

28 Production costs are relatively high at current water electrolyser capex, which implies a high value use for hydrogen is needed 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 Electricity price ( /MWh) Hydrogen production cost WE utilisation % 30% 40% 50% 60% 70% 80% 90% 100% /MWh 50/MWh 90/MWh 120/MWh 165/MWh 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 Source: Element Energy. 28

29 If electrolyser costs fall it may become feasible to use lower value markets (e.g. heat) as the core demand for the hydrogen produced 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 Electricity price ( /MWh) Hydrogen production cost WE utilisation 40 20% 30% 40% 50% 60% 70% 80% 90% 100% /MWh 50/MWh 90/MWh 120/MWh 165/MWh Operating envelopes: 1. Curtailment avoidance 2. Co-location 3. Grid services 4. Spot price tracking Source: Element Energy. 29

30 Introduction Overview of hydrogen and water electrolysis Electricity prices and local generation Demand profiles Options assessment Community heat detailed assessment Large-scale system detailed assessment Conclusions Appendix 30

31 In this section we consider electrolyser sizes in the context of potential sources of demand for hydrogen Introduction to demand profile modelling 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. Water electrolyser sizing 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. 31

32 We investigated a range of different end uses for hydrogen in the Dunbar area End uses considered 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. 32

33 We defined specific end uses within each of the four broad categories Demand scenarios overview We have defined a range of demand scenarios within the categories outlined above. Demand scenario 1. Dedicated hydrogen network* 2. West Barns gas spur 3. Dunbar swimming pool** Description Supply a new development with hydrogen from a dedicated pure H 2 network. Power-to-gas application using the West Barns gas spur. H 2 to heat for Dunbar s leisure centre. Key assumptions Illustrative scenario: 85 new dwellings, average fuel demands of 10MWh/yr per dwelling (space heating, hot water and cooking). 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. 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. Opportunities for industrial uses for hydrogen (e.g. at the local cement works) were also considered during the first phase of the study. 33

34 Electrolyser sizing is a trade off between plant utilisation, proportion of demands met and storage needs Water electrolyser sizing approach 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. * 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). 34

35 Potential for a dedicated hydrogen network in a new build development Water electrolyser KPIs Sized to meet peak demands WE size kw / (kg/day) 340 (140) Indicative capex Annual load factor k % % of annual demand met - 100% with H 2 Storage kgh Estimated profile of total thermal fuel demands in new 85 dwelling development (expressed as kgh 2 /day equivalent). Demands and variation by month from SAP modelling of typical new dwellings. 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. Storage Days of peak output Storage need based on at least two days worth of peak output (illustrative). Other requirements Hydrogen pipework to distribute fuel and compatible boilers and burners in each dwelling. Energy supply agreements (without compromising consumer choice). 2 SAP = Standard Assessment Procedure, the Government-approved methodology for calculating energy demands and emissions from new dwellings. 35

36 West Barns gas spur power-to-gas Total gas flow in spur expressed as kg/day hydrogen equivalent Water electrolyser KPIs High run hours High injection WE size kw / (kg/day) 15 (6) 70 (29) Indicative capex Annual load factor k % 55% % of annual demand met - 1% 3% with H 2 Estimated profile of total energy demands in West Barns gas spur (expressed as kgh 2 /day equivalent). Source: data from CES document 2.1 Gas Use Data v1, including 700,000m 3 of natural gas (at STP). 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. 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. 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). STP = standard temperature and pressure. 36

37 Dunbar leisure centre & community pool Water electrolyser KPIs Sized to peak Sized to base load WE size kw / (kg/day) 875 (370) 400 (170) Indicative capex Annual load factor k 1, % 100% % of annual demand met - 100% 68% with H 2 Storage kgh Profile of total thermal fuel demands in the Dunbar leisure centre (expressed as kgh 2 /day equivalent). Storage Days of peak output 2 2 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. 37

38 Hydrogen transport Water electrolyser KPIs Sized to meet total demands Illustrative demand (daily basis) assuming that demands are constant throughout the year. WE size kw / (kg/day) 500 (210) Indicative capex Annual load factor k % Storage kgh Storage Days of peak output 2 Hydrogen demand for an illustrative transport scenario sufficient to provide high utilisation of a 0.5MW water electrolyser Equivalent number of vehicles (to create demand) Fuel cell cars 380 Fuel cell buses 10 H 2 ICE vans 60 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. Other requirements Hydrogen compressing and dispensing equipment. Accessible location for fuelling station. Fleet(s) of hydrogen-fuelled vehicles. 38

39 Introduction Overview of hydrogen and water electrolysis Electricity prices and local generation Demand profiles Options assessment Hydrogen for heat, transport, or industry Hydrogen for methanation Community heat detailed assessment Large-scale system detailed assessment Conclusions Appendix 40

40 Options comparison matrix 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. Driver H 2 network new build Power-to-gas H 2 for community heat Industrial 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. 41

41 An H 2 system is likely to be challenging to deliver in the near term but may be a stepping stone to an innovative, sustainable solution Options comparison considerations 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).* 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). 42

42 The potential up-side from a large-scale system in future may provide motivation for a pilot project in the nearer term Outlook for water electrolyser-based solutions 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. 43

43 Introduction Overview of hydrogen and water electrolysis Electricity prices and local generation Demand profiles Options assessment Hydrogen for heat, transport, or industry Hydrogen for methanation Community heat detailed assessment Large-scale system detailed assessment Conclusions Appendix 44

44 If a local source of CO / CO 2 were available, methanation would be another potential use for hydrogen in the Dunbar area Introduction 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 / CO 2 ) 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 / CO 2 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 / CO 2 is required (which increases system cost and complexity), and the additional conversion steps reduce the overall efficiency (renewable electricity to useful end product). Section overview 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. 45

45 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 / CO 2 available for methanation (left). A selection of potential end uses for hydrogen and methane is also illustrated (right). 46

46 Methanation involves the conversion of CO / CO 2 to methane (CH 4 ) and water Overview of methanation CO 2 methanation Overall: CO 2 (g) + 4H 2(g) CH 4(g) + 2H 2 O (g) CO methanation Overall: CO (g) + 3H 2 (g) CH 4(g) + H 2 O (g) 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 ( o C). 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. 47

47 Biological methanation is carried out by hydrogenotrophic methanogens (microorganisms that produce CH 4 from CO 2 + H 2 ) 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. In-situ digester Electricity + water Water electrolyser Biomass Digester Hydrogen Methane Ex-situ digester Electricity + water Water electrolyser Hydrogen Biomass Digester CO / CO 2 CH 4 reactor Methane Further information on the relative merits of each approach is provided in the appendix. 48

48 System electrical capacity (kwe) 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 / CO 2 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: 5,500 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 Size of anaerobic digesters in Scotland with combined heat and power AD community CHP AD industrial CHP Year commissioned The data above suggest that AD plants in Scotland (with CHP) range in size from a few hundred kwe to 5.5MWe. Graph plotted based on data from 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 Scotland Red = 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: 49

49 Support for renewable energy production via biogas is in place in the UK Incentives for biogas installations 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 These are mainly agricultural installations and range from 600 to 2,000Nm 3 /hr biogas capacity [Source: Feed-in Tariff AD scale p/kwhe <250kWe kWe >500kWe 9.02 For installations commissioned from 01/10/14 Renewable Heat Incentive Biomethane injection p/kwh First 40,000 MWh/yr 7.62 Next 40,000 MWh/yr 4.47 Remaining MWh of eligible biomethane 3.45 For installations commissioned from 01/04/15 * _Government_Response_-_December_2014.pdf. 50

50 A relatively small scale AD plant could provide demand for a MWscale electrolyser for conversion of CO 2 to methane Sizing a methanation plant for Dunbar To understand the scale of electrolysis system that would be compatible with a biogas (anaerobic digestion) plant, the example below considers a 600Nm 3 /hr digester, which is representative of the lower end of the scale of plants installed in the UK in Example system ex-situ digester Electricity + water Biomass c. 35,000 t/yr Notes Water electrolyser 4.5 MW, 70% load factor Biogas (e.g. 60% CH 4, 40% CO 2 ) Digester 600 Nm 3 /hr c. 240 Nm 3 /hr CO 2 (360 Nm 3 /hr CH 4 ) Hydrogen c. 960 Nm 3 /hr CH 4 reactor Methane 240 Nm 3 /hr CH Nm 3 /hr CH 4 (from digester) 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). * ** 51

51 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: E&E Consultant (2014) Source: Study on hydrogen and methanation as means to give value to electricity surpluses, E&E Consultant for Ademe, GRTgaz, and GrDF (September 2014). 52

52 A methanation-based solution in Dunbar is unlikely to be a shortterm solution and will require further detailed feasibility work Methanation further considerations 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 conclusions 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. 53

53 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 54

54 This section explores a solution based on establishing a demand for H 2 for heat initially before starting to serve the transport sector Introduction The information below covers: Scenario definition Key assumptions for the cash flow analysis Cash flow results Risks and practicalities Community heat scenario overview 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). 55

55 Overview of the community heat scenario and recap on sizing approach Schematic representation of the community heat scenario Existing gas boilers Retained for back-up Heat Profile of total thermal fuel demands in the Dunbar leisure centre (see Demand profiles section) Water electrolyser H 2 Hydrogen boiler Heat Thermal demands (pool + leisure centre heating) H 2 Hydrogen refuelling station H 2 Hydrogen-fuelled vehicles Potential future source of hydrogen demand 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. 56

56 Techno-economic assumptions for cash flow analysis community heat scenario 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 System efficiency 60k/yr 57 kwh/kg Based on 4% of WE capex per annum. Load factor 67% From profile modelling above. Economic assumptions Electricity price Other assumptions Value of hydrogen 7%, 10 years 60 per MWh Water consumption of 40 litres/kgh 2, price of 0.1p/litre From 1.33/kg (2016) to 5.57 (2025) Net present value (NPV) calculated over a period of ten years using a relatively low discount rate of 7%. 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. Water costs make up a small proportion of the overall variable opex (electricity costs dominate). 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 Value in transport sector assumes no duty on hydrogen. * Additional equipment costs could be of the order k 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). 57

57 m in year A WE system mainly supplying hydrogen for heat is unlikely to provide a positive investment case Community heat (& transport) scenario annual cash flow All values in 2015 prices NPV ( ) at 7% discount rate 3.6m Capex Fixed opex Variable opex Revenue 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 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. 58

58 Community heat + transport option sensitivity testing Sensitivity test scenarios Scenario No transport demand No transport demand, double gas prices No transport demand, subsidy support High diesel prices Breakeven Differences relative to the Central scenario No upgrade costs in 2020, no increase in value of hydrogen over time ( 1.33/kg). No upgrade costs in 2020, revenues from hydrogen sale doubled ( 2.67/kg). No upgrade costs in 2020, value of hydrogen increased to 3.60/kg (representing an RHI-type subsidy). As per the Central scenario, but diesel price (used for calculating value of H 2 for transport) increased from 1.25/litre to 2/litre (2015 prices). Zero initial capex (e.g. 100% grant funded), 28/MWh electricity, high diesel price ( 2/litre). Sensitivity test results Central NPV ( ), 7% discount rate ( m) When supplying hydrogen mainly to 0.03 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 No transport demand No transport demand, double gas prices No transport demand, subsidy support High diesel prices ( 2/litre) Breakeven Even with an RHI-type subsidy, the NPV remains negative due to the relatively high capex and opex of the system. 59

59 Community heat scenario risk register Risk Insufficient local grid capacity to connect new water electrolyser of the required scale. Unable to access low cost electricity, leading to increasingly negative business case. Risk of poor technical performance (relatively little experience of using hydrogen for heating). Demand from the transport sector fails to develop. Electrolyser supplier is unable / unwilling to support equipment over its lifetime. Long lead time for supply of specialist equipment needed leading to delays in installation and commissioning. Leisure Pool operator unwilling to enter into long-term energy supply agreement. Planning / consents objections from locals / issues with securing permission to install and operate the system. WE system potentially in the wrong location to serve both local community heat demand and mobility sector. Grid upgrades in early 2020s undermining the case for a local, flexible demand for renewable electricity. Mitigation Enquire with local DNO, include budget for new power supply as required. 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). Select suppliers with experience and reference installations. Retain incumbent heating system as a back-up. Stress test business case against a range of alternative future values of hydrogen. Select an established supplier with a proven track record. Factor in sufficient time for design and procurement in programme. Commit to providing lower cost energy than counterfactual option. Engage local community early in the project, ensure all relevant safety experts are involved in development of plans. 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. Maintain contact with network operators to understand the impact of planned upgrades in the context of increasing renewable generation capacity connecting to the network. 60

60 Practical considerations include siting, ownership, and on-going support arrangements Practicalities 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 ongoing support (plant owner is responsible for maintenance) to full preventative maintenance and component replacement. Ownership is a further consideration (i.e. who would own the plant) the appropriate solution will depend on various legal, commercial, and regulatory issues. 61

61 An initial assessment suggests space is not a major constraint a more detailed review is required to identify a preferred location 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). View of the Dunbar Leisure Centre Source: Google Earth Street view of the Dunbar Leisure Centre Source: Google 62

62 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 63

63 This section explores the option of establishing a large scale WE plant that could have a major impact on local curtailment issues Introduction The information below covers: Scenario definition Key assumptions for the cash flow analysis Cash flow results Risks Large-scale system scenario overview Source: 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. 64

64 This scenario envisages a centralised hydrogen production facility in Dunbar with an associated logistics operation Scope of economic analysis Water electrolyser On-site compression On-site storage Hydrogen logistics (tube trailers) Hydrogen dispensing (HRS) Vehicles (source of H 2 demand) Included in following analysis Excluded from following analysis 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. A 500 bar tube trailer (capacity = 1.1tH 2, fill / unload time is c. 60 minutes). Source: Linde 65

65 Techno-economic assumptions for cash flow analysis largescale system scenario Modelling assumptions Metric Value Notes WE capex 21m Other capex WE fixed opex System efficiency 0.5m 420k/yr Budgetary 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).* 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.). Based on 2% of capex per annum. 55 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 assumptions Electricity price Other assumptions Value of hydrogen 7%, 10 years 45 per MWh Water consumption of 40 litres/kgh 2, price of 0.1p/litre From 3/kg to 4/kg, central case of 3.50/kg Net present value (NPV) calculated over a period of ten years using a relatively low discount rate of 7%. Within the range of figures from the co-location operating strategy defined above. Water costs make up a small proportion of the overall variable opex (electricity costs dominate). This corresponds to the value of hydrogen from the electrolyser (i.e. precompression 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. * 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. 66

66 m in year For a large-scale system the potential returns are highly sensitive to the on-going costs and revenues Large-scale WE scenario annual cash flow All values in 2015 prices NPV ( ) at 7% discount rate + 3.4m Capex Fixed opex Variable opex Revenue ( 3.50/kg) 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.* * This is in contrast to the community heat scenario explored above, where capital costs have a far greater influence on the overall economic case. 67

67 Large-scale system sensitivity testing Sensitivity test scenarios Scenario Electricity price seen by electrolyser Value of hydrogen produced Test values (all other values as per the Central scenario) Results for net prices of 40/MWh and 50/MWh shown (Central value = 45/MWh). 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%). Sensitivity test results +3.4 Central NPV ( ), 7% discount rate ( m) /MWh electricity /MWh electricity H₂ value 3/kg H₂ value 4/kg % utilisation % utilisation 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. 68

68 Large-scale system scenario risk register Risk Water electrolyser technology development less rapid than anticipated, leading to higher cost equipment. Poor reliability / availability of equipment (especially if undertaking first-of-a-kind installation). Difficulties in obtaining planning permission and safety case sign-off. Lack of skills to install and operate this type of plant. Lack of demand for hydrogen produced. Limited access to low cost electricity, leading to high production costs and undermining the business case. Operational risks arising from complexity of the operations (which would require establishment of logistics operation with regular delivery of hydrogen beyond the Dunbar area). Mitigation Engage with electrolyser OEMs to understand pace of technology development. Test sensitivity of business case to higher capital cost equipment. 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. Engage local community early in the project, ensure all relevant safety experts are involved in development of plans. Work closely with equipment supplier, plan specialist training to develop skills. 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). Secure long-term agreements with local generators for purchase of power at mutually beneficial rates. Develop robust operating plans and procedures to follow in the event of any issues. 69

69 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 70

70 The leisure pool is a potential source of demand for H 2 in the near term, but higher value uses are needed to improve the economics Dunbar water electrolyser feasibility study conclusions 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. 71

71 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 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, megawattscale 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. 72

72 Introduction Overview of hydrogen and water electrolysis Electricity prices and local generation Demand profiles Options assessment Community heat detailed assessment Large-scale system detailed assessment Conclusions Appendix Electricity networks and prices Methanation further details 74

73 Electricity network map (1) Source: Google Earth. 75

74 Electricity network map (2) Source: Google Earth. 76

75 Electricity network map (3) Source: Google Earth. 77

76 Breakdown of household (domestic) electricity bills Illustrative grid electricity price breakdown for domestic customers in the UK 5% 4% 16% 5% 11% Wholesale energy, supply costs & profit margin 58% DUoS charges TUoS charges VAT Environmental charges Other costs 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. * 78

77 Red / amber / green time bands (which affect DUoS charges) half hourly metered properties Source: Scottish Power 79

78 Red / amber / green time bands (which affect DUoS charges) half hourly unmetered properties Source: Scottish Power 80