energy & environmental science · a department of chemical engineering, imperial college...

This journal iscopyThe Royal Society of Chemistry 2018 Energy Environ Sci

Cite thisDOI 101039c8ee02079e

Levelized cost of CO2 mitigation from hydrogenproduction routesdagger

B Parkinson a P Balcombe ab J F Speirs bc A D Hawkes ab andK Hellgardta

Different technologies produce hydrogen with varying cost and carbon footprints over the entire

resource supply chain and manufacturing steps This paper examines the relative costs of carbon

mitigation from a life cycle perspective for 12 different hydrogen production techniques using fossil

fuels nuclear energy and renewable sources by technology substitution Production costs and life cycle

emissions are parameterized and re-estimated from currently available assessments to produce

robust ranges to describe uncertainties for each technology Hydrogen production routes are then

compared using a combination of metrics levelized cost of carbon mitigation and the proportional

decarbonization benchmarked against steam methane reforming to provide a clearer picture of the

relative merits of various hydrogen production pathways the limitations of technologies and the

research challenges that need to be addressed for cost-effective decarbonization pathways The results

show that there is a trade-off between the cost of mitigation and the proportion of decarbonization

achieved The most cost-effective methods of decarbonization still utilize fossil feedstocks due to their

low cost of extraction and processing but only offer moderate decarbonisation levels due to previous

underestimations of supply chain emissions contributions Methane pyrolysis may be the most cost-

effective short-term abatement solution but its emissions reduction performance is heavily dependent

on managing supply chain emissions whilst cost effectiveness is governed by the price of solid carbon

Renewable electrolytic routes offer significantly higher emissions reductions but production routes are

more complex than those that utilise naturally-occurring energy-dense fuels and hydrogen costs are

high at modest renewable energy capacity factors Nuclear routes are highly cost-effective mitigation

options but could suffer from regionally varied perceptions of safety and concerns regarding

proliferation and the available data lacks depth and transparency Better-performing fossil-based

hydrogen production technologies with lower decarbonization fractions will be required to minimise the

total cost of decarbonization but may not be commensurate with ambitious climate targets

Broader contextGlobal energy consumption is expected to continue to grow requiring decarbonized energy vectors for end use applications Hydrogen as an energy carrier is onepossible solution However it is relatively expensive and not necessarily low-carbon with its method of production largely determining costs and climate impacts Inaddition comparisons between fossil-routes and renewable based hydrogen often misuse cost and emissions data to push policy makers and public opinion furtheralong the polarizing debate of the role of fossil fuels in a low-carbon energy system In this context identifying robust ranges of key parameters to describe theuncertainties for each technology and combining cradle-to-gate emissions and cost assessments provides a clearer picture of the relative merits of various hydrogenproduction pathways The analysis shows that the levelized cost of carbon mitigation from hydrogen production by technology substitution varies by over an order ofmagnitude with large emissions contributions originating from supply chains There is broadly a trade-off between the cost of mitigation and proportion ofdecarbonization achieved with cheaper options not achieving decarbonisation fractions commensurate with ambitious global climate targets

1 Introduction

The drive to decarbonise is gathering pace as nations commit toclimate change targets1 which will require innovative and sociallypalatable solutions Low-carbon hydrogen may be one solution

a Department of Chemical Engineering Imperial College London SW7 2AZ UK

E-mail bparkinson17imperialacukb Sustainable Gas Institute Imperial College London SW7 1NA UKc Department of Earth Science and Engineering Imperial College London SW7 2BP

UK

dagger Electronic supplementary information (ESI) available See DOI 101039c8ee02079e

Received 17th July 2018Accepted 16th November 2018

DOI 101039c8ee02079e

rscliees

Energy ampEnvironmentalScience

ANALYSIS

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View Article OnlineView Journal

Energy Environ Sci This journal iscopyThe Royal Society of Chemistry 2018

given its lack of direct CO2 emissions and suitability across energyservices and chemicals production2 Globally approximately 60 Mtof hydrogen is produced annually3 for the production of nitrogen-based fertilizers (49 of global H2 production) hydro-treatment inpetroleum refining (37) methanol (8) and other smallermarkets (6) including for use in stationary fuel cells and fuel cellvehicles4ndash6 However 96 of hydrogen is produced by technologiesinvolving the reforming of fossil fuel feedstocks resulting in highCO2 emissions (natural gas contributes 49 liquid hydrocarbons29 and coal 18)5 The remaining 4 is produced by electro-lysis technologies which are only low-carbon if powered by low-carbon electricity and embodied emissions of the generationtechnologies are also low7 Due to low regional gas and coal pricesand high resource availability hydrogen production in the short-to-medium term is likely to continue to rely heavily on fossil fuels8

There are many options to produce low-carbon hydrogen buteach option exhibits different levels of decarbonization whilstthere are also many barriers to production through alternativeroutes not least scale and costs9 The challenge of transitioningto more sustainable hydrogen production routes will requirefocus on the highest return on investment to minimise the costof decarbonization10 However both life cycle emissions andcosts may be highly variable and these estimates are poorlybounded within current studies

Numerous studies have investigated the merits of alternativeH2 production technologies through comparative assessmentsor overall metrics Ewan et al11 developed an overall Figure ofMerit (FOM) assessment which evaluated 14 different hydrogentechnologies on CO2 emissions intensity power density landuse and cost A clear division between low energy densityrenewable technologies and those associated with high energydensities was shown with a significantly higher FOM for thelater grouping11 Acar et al12 compared 8 different hydrogenproduction technologies for environmental impact cost andexergy efficiencies Their study used a social cost of carbon toapply economic consequences to carbon externalities to investigatethe relationship between environmental and economic factorsThis study was further extended by Dincer et al13 comparing 19different hydrogen production methods using renewable and non-renewable sources for environmental impact cost energy andexergy efficiencies The study found hybrid nuclear thermochemi-cal cycles to be the most promising candidate to produce hydrogenwith low environmental and cost impacts13 Machhammer et al14

compared two conventional technologies coal gasification andSMR with four emerging technologies metal-oxide cycles waterelectrolysis biomass gasification and methane pyrolysis on costand carbon footprint The lsquoeconologicalrsquo result yielded methanepyrolysis to be the most promising technology for low-cost and lowcarbon footprint hydrogen14 Speirs et al15 assessed the evidenceof costs and greenhouse gas (GHG) emissions of 9 hydrogenproduction routes and found that supply chain emissions associatedwith supposedly low carbon routes were non-negligible and highlyvariable across regions processes and estimation assumptions

Of the different frameworks presented in the literature forcomparing hydrogen production technologies none have directlycompared the total costs of production to CO2 emissions from a

life cycle perspective for evaluating costs of CO2 mitigation whilstmany include only a subset of available feedstocks and productionroutes Additionally none of the comparison studies includerobust ranges of both variations in cost and emissions dataavailable in the literature Therefore the goal of this study is toidentify the most cost-effective technologies for reducing thecarbon intensity of hydrogen production in terms of cost pertonne of carbon dioxide emitted ($ t1 CO2e) by conducting adetailed engineering environmental and cost assessment of afull suite of hydrogen production routes and feedstocks Keyparameters for each hydrogen supply chain are quantitativelyassessed to develop robust ranges of emissions and costs aswell as providing insight into the best opportunities for carbonreductions This output is used to estimate the levelized cost ofemissions mitigation and the degree of decarbonisation achievableto provide critical guidance on future resource allocation prioritiesand trajectory for hydrogen development pathways The technicaland financial hurdles to implementation are discussed andrecommendations for future resource allocation are made Thisstudy is the first comprehensive combined supply chain and pointsource assessment of carbon mitigation costs for the breadthof hydrogen production processes and feedstocks consideredIt aims to serve as a valuable source of data and discussionfor engineers academics and policy makers alike to providea clearer picture of the relative decarbonization merits ofhydrogen production pathways

This study focusses on technologies capable of large-scaleproduction commensurate with current hydrogen demandsTechnologies for hydrogen production fall into four categories(i) thermochemical (ii) electrochemical (iii) photo-biologicaland (iv) photo-electrochemical16 However photo-biologicaland photo-electrochemical methods are not discussed here asthese technologies are currently limited by relatively slowproduction rates early stages of commercial development and arange of technical issues to overcome before practical applicationscan be considered (see ref 17 and 18 for further information) Thetechnologies considered are shown in Table 1 The substitution ofa hydrogen production technology with a less CO2-intensivetechnology assumes it is capable of meeting the hypotheticalscale and load profile required It should also be noted thevarying stages of technological readiness of each of the path-ways considered in this analysis Other natural gas reformingroutes such as auto-thermal reforming and partial oxidationhave not been considered here Whilst these technologieshave different processing steps and reaction pathways resultingin different costs and emissions they ultimately representreforming of natural gas A more detailed comparison of thehydrogen production pathways from natural gas is the subjectof future work

2 Methodology

To achieve the above aims the study is carried out in five steps(1) A review of recent literature for hydrogen production

costs and life cycle emissions

Analysis Energy amp Environmental Science

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(2) Define and quantify the key parameters that influenceLife Cycle Emissions (LCE) and the Levelized Cost of Hydrogen(LCOH) for each technology

(3) Re-estimate total LCE and LCOH for each technologybased on key parameter ranges identified

(4) Develop a framework to evaluate technologies based onLevelized Cost of Carbon Mitigation (LCCM) and proportionalemissions reductions relative to industry standard technology (SMR)

(5) Identify the most promising technologies for low carbonhydrogen production and the areas with greatest potential forcost effective emissions mitigation

For the environmental assessments and for each productionroute this study assesses both direct and indirect emissionsassociated with raw material extraction and conditioningtransportation of feedstock processing and hydrogen productionas well as ancillary processes such as carbon capture and storagefor each process route identified in Table 1 Indirect emissionsinclude those associated with embodied emissions from infra-structure construction where available The LCE data is calculatedfrom figures quoted in the literature where all stages of productionand use are specified Whilst other environmental indicators (egwater usage land-use changes human health impacts) areimportant and may strengthen support for emerging technologiesonly greenhouse gas (GHG) emissions are considered here For thecost assessment this study assesses both capital (Capex) andoperating (Opex) costs associated with hydrogen productionThe raw material extraction conditioning transportation andpre-processing is assumed to be included in the delivered priceof raw materials unless otherwise directly specified

The study considers hydrogen supplied at the facility gatewith no additional liquefaction or pressurization taken intoaccount Revised life cycle emissions estimates are based onupdated supply chain emissions sources or calculations wherespecified In the absence of transparent LCOH or LCE for aparticular hydrogen production route the full range of valuesavailable in the literature is reported and a sensitivity analysisacross the range is performed The levelized cost of carbonmitigation (eqn (1)) is expressed by a developed frameworkwhich compares the levelized cost of hydrogen ($ t1 H2) andgreenhouse gas life cycle emissions (LCE) (t CO2e t1 H2) ofindividual hydrogen production technologies to the current

industry standard technology steam methane reforming(SMR)

LCCM $ per t CO2eth THORN

frac14 Financial Penalty

Environmental Gain

frac14LCOHTechnology X LCOHSMR

$ per t H2eth THORN

GHGLCESMR GHGLCETechnology X

t CO2e per t H2eth THORN

(1)

The LCCM is an estimate of the additional cost associatedwith reducing the emissions of hydrogen production per tonneof CO2e against emissions of hydrogen production using SMRFor fossil fuel routes Carbon Capture and Sequestration (CCS)has been included The reduction of CO2 emissions usuallyoccurs via process efficiency improvements or direct substitutionof existing technologies to less CO2-intensive alternatives Marginalcost of abatement metrics such as the carbon abatement cost(CAC) used for equipping CCS to SMR or coal gasification aredefined in relation to current technology The LCCM metriccompares the cost of decarbonization by technology substitutionLess-CO2 intensive technologies are typically more expensive thanfossil technologies resulting in a positive numerator for the LCCMmetric When a process is more expensive and more CO2 intensivefrom a life cycle perspective the LCCM would be negativemeaning that technology substitution could not effectivelyreduce emissions For example the substitution of SMR forcoal gasification without CCS results in higher emissions andcost and is therefore not included in this analysis All costsunless otherwise stated have been adjusted to 2016 USD usingthe Chemical Engineering Plant Cost Index (CEPCI)

3 Hydrogen costs and emissionsinventories

The following section summarizes the costs and emissionsinventories of each technology option presented in Table 1For each route considered we present a general process char-acterization the current technology status process costs and

Table 1 Hydrogen production technologies considered in the study

No Technology name Energy vector Input material TRL1920 a

1 Steam methane reforming Thermal Natural gas 92 Steam methane reforming with CCS Natural gas 7ndash83 Coal gasification Coal 94 Coal gasification with CCS Coal 6ndash75 Methane pyrolysis Natural gas 3ndash56 Biomass gasification Biomass 5ndash67 Biomass gasification with CCS Biomass 3ndash58 Electrolysis ndash wind Electrical Water 99 Electrolysis ndash solar Water 910 Electrolysis ndash nuclear Water 911 Thermochemical water splitting (SndashI) cycle Electrical + thermal Water 3ndash412 Thermochemical water splitting (CundashCl) cycle Water 3ndash4

a Bold text is used throughout to highlight the lower TRL of the production route where comparisons are made

Energy amp Environmental Science Analysis

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emissions and key parameters governing process costs andemissions

31 Steam methane reforming

In conventional SMR methane is reacted with steam using acatalyst at relatively high temperature 650ndash1000 1C and apressure of 5ndash40 bar to produce carbon monoxide and hydrogenAdditional hydrogen is produced by reacting carbon monoxidewith steam in the waterndashgas shift reaction21 The overall processis represented by eqn (2)

CH4 + 2H2O 2 CO2 + 4H2 DH 0 = 165 kJ mol1

DG0 = 114 kJ mol1 (2)

The final stage of the process separates high-purity hydrogen(9999) from CO2 using pressure swing adsorption Overallprocess efficiencies (CH4 HHV to H2 HHV) typically exceed7522 SMR hydrogen costs are most sensitive to natural gasprices Several correlations for hydrogen cost as a function ofnatural gas price are available Gray and Tomlinson23 developeda relationship (eqn (3)) for large facilities with productioncapacities of approximately 100 million standard cubic feetper day (SCFD) (B235 t H2 day1) and capital costs of approxi-mately $275ndash339 kg1 H2 day1 Capacities vary from 5000ndash250 000 mSTP

3 h1 24 in single and multi-train configurations Asimilar relationship was presented by Penner25 without specify-ing plant size or operating assumptions (eqn (4))

Hydrogen Cost (2001$ kg1) = 0137 Natural Gas Price

($ GJ1) + 01123 (3)


($ GJ1) + 015 (4)

Using a natural gas price of $4 GJ1 the HHV of hydrogenand adjusting to 2016 dollars this corresponds to hydrogencosts of $091ndash$169 kg1 H2 ($637ndash119 GJ1) These costestimates are in agreement with other studies predicting hydrogencosts of two to three times the cost of natural gas per unit of H2

produced25 A summary of hydrogen production costs from SMRreported in the literature is shown in the ESIdagger Table S1 andFig S1 The costs of current hydrogen production from thesestudies range from $103ndash157 kg1 H2 with an average of$128 kg1 H2 for natural gas prices from $325ndash831 GJ1

For literature studies including natural gas supply chaincontributions to GHG emissions the reported total range ofLCE values are 1072ndash1586 kg CO2e kg1 H2 (average of 124of kg CO2e kg1 H2)26ndash34 without CCS and 31ndash59 kg CO2e kg1

H2 (average of 43 kg CO2e kg1 H2) with CCS at 90capture2728323335 Direct GHG emissions from the SMR hydrogenproduction phase are approximately 8ndash10 t CO2e t1 H2 60 ofwhich is generated from the process chemistry while theremaining 40 arises from heat and power sources required36

The majority of CO2 produced exits in two streams a dilutedstream (stack gases with CO2 concentration 5ndash10 vol) and aconcentrated stream (approximately 50 by vol after pressure

swing adsorption)37 The relatively pure CO2 stream is readilyamenable for lower-cost CCS if appropriate geological storagereservoirs are located nearby If deep decarbonisation is requiredand emissions must be further reduced from the entire processthen an amine solvent (MEA) based CCS process might be used tocapture up to 90 of the CO2 contained in the stack gases38

although demonstrated removal rates are typically 8039

LCE emissions estimates are most sensitive to direct processemissions and fugitive emissions associated with the natural gassupply chain

311 Supply chain emissions Estimates of both methaneand CO2 emissions from the natural gas supply chain aresignificant and variable84 Most environmental studies onSMR hydrogen do not report the source of the fugitive methaneemissions value used in addition many of the studies referencethe DOE H2A model which uses an outdated GHG emissionsglobal warming potential (GWP) factor for methane of 25 and amethane fugitive emissions value of 12285 In contrast theIEA World Energy Outlook recently estimated a global averagenatural gas methane emission value of 1786 whereas Balcombeet al87 calculated a range of mean emissions of 16ndash55 acrossdifferent supply chain types from best available recent data sources

Methane emissions which occur from vents incompletecombustion and fugitive leaks exhibit high variability and areheavily skewed in distribution a small number of facilitiesexhibit large emissions87 The contribution of fugitive methaneemissions to overall LCE is exacerbated by the high relativeclimate forcing of methane compared to CO2 especially overshort timescales

For this study a central estimate (median) of 09 of totalgas delivered is used with a range of 06ndash14Dagger taken fromBalcombe et al87 as this reflects interquartile range of emissionsassociated lower-emitting supply chains utilising modern equipmentand effective operation Given that the context of this paper isregarding new hydrogen production opportunities to loweremissions the authors argue that this is an appropriateassumption Note that this includes the whole supply chainincluding low pressure distribution which is not likely to bepart of the hydrogen supply chain Thus these may be a smalloverestimate of emissions These emissions values equate to11 kg CO2e kg1 H2 with a range of 08ndash19 kg CO2e kg1 H2

based on a global warming 100 year time horizon value of36 g CO2e g1 CH4

88 and overall 76 HHV process efficiencyCO2 emissions associated with the natural gas supply chain

are typically due to fuel usage for processing and transport andare estimated to have a median of 10 g CO2 MJ1 HHV deliveredgas with an interquartile range of 82ndash148 g CO2 MJ1 HHV forbest practice supply chains87 The variation in emissions primarilyarises from different raw gas compositions and transportdistances The raw gas composition governs the fuel required

Dagger 5th 50th 95th percentile and mean emissions are 03 09 33 and 16respectively Interquartile ranges of 06ndash14 have been used to refine the dataset These are results from a set of supply chain routes considered to be usingmodern and effective equipment Note that this is different to the range of meanemissions (16ndash55) seen across all supply chains mentioned in the previousparagraph


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for processing higher fraction of impurity requires more fuelfor processing Additionally raw gas with high CO2 contentwould vent more CO2 once separated Compressor stations arerequired at set distances to boost pressure and thus a longerdistance requires more fuel for compressor duty

For unabated SMR using the updated supply chain emissionscontributions this is equivalent to 295 kg CO2 kg1 H2 for themean case with a range of 225ndash447 kg CO2 kg1 H2 using anoverall 76 HHV process efficiency Thus this study estimates amean total LCE value of 1283 kg CO2e kg1 H2 with a range of101ndash1721 kg CO2e kg1 H2 For SMR with CCS (90 capture)the supply chain contributions total 33 kg CO2e kg1 H2 for themedian case with a range of 252ndash50 kg CO2e kg1 H2 using anoverall 68 HHV process efficiency The total LCE estimate forSMR with CCS (90 capture) is 561 kg CO2e kg1 H2 with a rangeof 297ndash916 kg CO2e kg1 H2 The LCE values estimated hererepresent updated natural gas supply chain ranges combinedwith the ranges of direct process emissions presented inthe literature including external electricity contributions ofB07 kg CO2e kg1 H2333536 Combining low-range supplychain estimates with low-range point-source creates realisticlower bound estimates (and vice versa for upper limits) foroverall process emissions

312 Carbon capture and sequestration The additionalcosts incurred by equipping an SMR facility with CCS havebeen extensively studied over the past two decades (summarizedin Table S2 ESIdagger) They are typically expressed as the cost ofavoided carbon (CAC $ t1 CO2) The reported CACrsquos for SMRwith CCS alongside the year of the published study are shown inFig 1 The cost of hydrogen from these studies ranges from$122ndash281 kg1 H2 with an average of $188 kg1 H2 for CO2

capture rates from 60ndash90 The current CACrsquos reported by thestudies in Table S2 (ESIdagger) range from $1639ndash13625 t1

CO2 with included transport and storage costs ranging from$0ndash152 t1 CO2 It is apparent that early CCS studies eitherunderestimated the complexity and cost of CCS or onlyaccounted for separate aspects of the CCS technology chainwith a focus on either capture transport or storage Only foursites globally have demonstrated CO2 capture with transport

and storage integration to an SMR facility none of which havepublicly released process costs98 The most detailed publiclyavailable study is the 2017 IEAGHG sponsored Amec FosterWheeler standalone SMR based H2 plant with CCS27 whichsuggests CAC between $58ndash87 t1 CO2 depending on the level ofcapture (56ndash90) The study used $124 t1 CO2 for transportand storage costs which represents a well characterized reservoirshort transport distance and lsquolightrsquo monitoring regulations Incontrast the post-demonstration of CCS in the EU reports bythe European Technology Platform for Zero Emission FossilFuel Power Plants (ZEP) detail the costs of CO2 transport viapipeline (higher for shipping) to range from $24ndash13 t1 CO299

and storage and monitoring from $8ndash23 t1 CO273 dependingon the storage site location and degree of characterizationIt is apparent that sequestration costs for distant poorlycharacterized reservoirs in potentially onerous regulationregimes will be higher In this study the IEAGHG CAC for the90 capture scenario ($865 t1 CO2) with adjusted transportof storage costs to $22 t1 CO2 totalling $9615 t1 CO2 isused as the benchmark cost for equipping CCS to SMR for90 capture

32 Coal gasification

In conventional coal gasification pulverized coal is partiallyoxidized with air or oxygen at high temperatures (800ndash1300 1C)and pressures of 30ndash70 bar producing a syngas mixturecomposed of H2 CO CO2 and CH4 (and other impurities egCOS H2S)40 The raw syngas undergoes a waterndashgas shiftreaction to increase the hydrogen yield The syngas is scrubbedto remove particulates sulphur containing compounds andapproximately 50 of the carbon dioxide prior to hydrogenseparation using PSA23 Waste gases from the PSA rich in CO2

but also some H2 and CO can be used for power generation tooffset the high energy requirements of plant or for exportelectricity as a co-product to the hydrogen generated24 Theoverall reaction stoichiometry can be represented by eqn (5)

CH08 + 06O2 + 07H2O - CO2+ H2 DH 0 = 90 kJ mol1

DG0 = 63 kJ mol1 (5)

Compared to SMR coal gasification plants are less efficient(B55 fuel-to-hydrogen HHV) more complex and have larger singletrain capacities typically ranging from 20 000 to 100 000 mSTP

3 h124

Hydrogen costs from coal gasification are most sensitive tofacility capital costs It has been shown previously that if thecoal price changed by 25 percent the hydrogen costs onlyincrease by approximately $005 kg122 The relationshipbetween total capital cost and plant capacity presented byKonda et al41 is shown in eqn (6) Coal gasification is acommercially mature technology but due to the higher capitalcosts lower efficiencies and increased complexity for solid-fuelgasification techniques hydrogen production costs are typicallyonly competitive with SMR where oil andor natural gas isexpensive compared to coal42 Estimates of the cost of hydrogenavailable in the literature are $096ndash188 kg H2 (average of

Fig 1 Time series cost of avoided carbon ($2016 t1 CO2) Blue dots ndashstudies found in the literature search Red square ndash IEAGHG study withamended transport and storage costs to $22 t1 CO2


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$138 kg1 H2) for coal feedstock prices from $133ndash273 GJ1

(summarised in ESIdagger Table S3)

Total Capital 2002 USMillion $eth THORN

frac14 352 Capacity t H2 per dayeth THORN150

077 (6)

The lower C H ratio in coal relative to natural gas results insignificantly higher direct CO2e emissions from the process(144ndash2531 kg CO2e kg1 H2) with an average value of 1914 kgCO2e kg1 H28222843ndash45 The total LCE of unabated coal-to-hydrogenis most sensitive to the direct hydrogen conversion steps

321 Supply chain emissions The supply chain contributionto the overall LCE of coal-to-hydrogen in the past has beenoverlooked or estimated as a relatively small portion of the totalLCE from unabated coal gasification However it has been shownrecently that the contribution of fugitive methane emissions fromcoal production on the global methane budget are significantand are highly variable depending on the type of coal and methodof extraction89 Methane emissions from surface mines areproportional to the surface area exposed but are significantlylower than underground mines due to the low gas contents ofyoung and shallow coals The total methane emissions for opensurface mines contribute approximately 009 kg CO2e kg1 H2

90

using a coal HHV of 302 MJ kg1 and overall coal-to-hydrogenefficiency of 55 This represents a relatively small portion of theaverage 045 kg CO2e kg1 H2 (range 032ndash077 kg CO2e kg1 H2)for coal extraction processing and transportation reported in theliterature for subbituminous coal supply chains273045 The rangeof LCE from coal gasification with CCS (Z90 capture) pre-sented in the literature range from 077ndash52 kg CO2e kg1

H2273044ndash46 with an average of 456 kg CO2e kg1 H2Underground coal mining emissions factors vary with basin-

specific coal conditions and depth of the coal extracted90ndash92 Inthe absence of mine specific data IPCC guidelines estimateTier 1 emissions factors for underground coal mining withoutcoal mine methane mitigation range from 10ndash25 m3 CH4 t1

coal which introduces considerable uncertainty This corre-sponds to a range of 206ndash515 kg CO2e kg1 H2 using a HHV of302 MJ kg1 an overall coal-to-hydrogen efficiency of 55 anda methane GWP of 36 Accounting for coal processing andtransportation the total upstream emissions value for under-ground coal mining ranges from 251ndash56 kg CO2e kg1 H2 withan average of 45 kg CO2e kg1 H2

This study estimates total LCE values of 211 kg CO2e kg1

H2 (range 109ndash552 kg CO2e kg1 H2) and 1978 kg CO2e kg1

H2 (range 1472ndash2609 kg CO2e kg1 H2) for surface mined coalwith (90 capture) and without CCS respectively For under-ground mined coal this study estimates 2385 kg CO2e kg1 H2

and 62 kg CO2e kg1 H2 with ranges of 169ndash309 kg CO2e kg1

H2 and 276ndash957 kg CO2e kg1 H2 for underground mined coalwith and without CCS (90 capture) respectively The LCE valuesestimated here represent updated supply chain contributionsto the range of LCE values in the literature For the levelizedcost of mitigation and decarbonization fraction calculations(see Section 41) this study uses an LCE for coal with CCS of

46 kg CO2e kg1 H2 (average across surface and undergroundmine estimates) with a sensitivity of the full range of supplychain emissions ranges

322 Carbon capture and sequestration Whilst severalstudies for coal gasification integrated with CCS for powergeneration are available4748 few have focussed on specificallyCACrsquos of hydrogen production Additionally any future large-scalehydrogen generation facilities from coal are also likely to generatesome power due to the advantages provided by the productflexibility of poly-generation systems It is necessary therefore topreface any remarks concerning CO2 abatement costs or the costof hydrogen generation with this caveat as the abated costdepends heavily on CO2 burden allocations for poly-generationsystems A summary of current hydrogen production costs via coalgasification with CCS are shown in the ESIdagger Table S4 The cost ofhydrogen from these studies ranges from $126ndash36 kg1 H2 withan average of $217 kg1 H2 for CO2 capture rates from 85ndash92The current CACrsquos reported by the studies in Table S4 (ESIdagger) rangefrom $1726ndash2519 t1 CO2 with included transport and storagecosts ranging from $685ndash1534 t1 CO2

The most recent study reporting a CAC for hydrogen fromcoal gasification was conducted in 2007 Given the CAC trendfrom the SMR time series over the same time period (Fig 1) andthe substantially lower CAC values reported by coal-to-hydrogenstudies (Table S4 ESIdagger reflective of the SMR costs in the early2000rsquos) the cost of equipping CCS for coal gasification tohydrogen routes was sourced from more recent detailed coal-to-power studies with CCS For power production from coal withpre-combustion capture (necessary for H2 generation) integratedgasification combined cycle (IGCC) plants provide the mosteconomical route However for many recent studies100ndash102 theCAC reference plant for IGCC facilities for power production is asupercritical pulverized coal (SCPC) plant without capture (not asimilar IGCC plant without capture) which would be the lowercost route for coal-fired power plants without capture45 Thisresults in an increase in the average CAC from $4392 t1 CO2 (forIGCC with CCS to IGCC without) to $7734 t1 CO2 (excludingtransport and storage for both) as reported in a recent review byRubin et al45 An average value of $4392 t1 CO2 for IGCC comparedto a SMR baseline has been used45 Including the ZEP transport andstorage costs of $22 t1 CO2 the total CCS cost for 90 capturefrom coal gasification used in this study is $6592 t1 CO2

It is noteworthy the CAC value used here is significantlyhigher than that for coal with CCS as shown by the literaturestudies in Table S4 (ESIdagger) ($1726ndash2519 t1 CO2 for capture andcompression and $685ndash1534 t1 CO2 for transport and storage)However it is in agreement with the average cost of hydrogenproduced from coal with ($217 kg1 H2) and without CCS($140 kg1 H2) and the average life cycle emissions reportedin the literature for each (1837 kg CO2 kg1 H2 and 26 kgCO2 kg1 H2 for 90 capture respectively) This results in aCAC of $58 t1 CO2

33 Biomass gasification

Hydrogen can be produced from biomass resources such aswood agricultural residues consumer wastes or crops grown


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specifically for energy purposes43 For hydrogen generationbiomass processing pathways include gasification pyrolysissupercritical extraction liquefaction and hydrolysis Gasificationhas the highest hydrogen yield per unit feedstock and is the focushere Biomass gasification is closely related to coal gasificationconsisting of steam gasification gas cleaning (ash and particularremoval) waterndashgas shift and hydrogen separation via pressureswing adsorption24 In general biomass does not gasify as easilyas coal and produces other hydrocarbons exiting the gasifierBiomass gasification occurs at temperatures from 500ndash1400 1Cand operating pressures from atmospheric to 33 bar dependingon plant scale and reactor configuration49 The general reactionis shown in eqn (7)

Biomass + H2O - H2 + CO + CO2 + CH4 + Tar + Char(7)

Despite the development of several system components anddesigns the process is still largely uncommercialized for hydrogenproduction with some promising pilot scale facilities for bio-methane and bio-hydrogen underway5051 Like coal gasificationhydrogen production costs from biomass are most sensitiveto the high cost of capital Large-scale facilities are required tooffset the high capital costs of a complex solid fuels gasificationfacility52 Overall biomass-to-hydrogen efficiencies (HHV) forlarge scale facilities of 52 have been estimated53 Hydrogenproduction costs are estimated to be $182ndash211 kg1 for1397 t H2 day1 output for biomass costs of $474ndash825 dry ton154

Removing studies concerning future biomass hydrogen productioncosts and the outliers for very small production facilities reported byYao et al55 the LCOH from biomass sources in the literature rangesfrom $148ndash300 kg1 H2 with a mean value of $224 kg1 H2 forbiomass feedstock prices of $4837ndash1152 t1 dry biomass delivered(summarised in Table S5 ESIdagger)

Although not currently economically competitive biomassgasification is an attractive option for recovering energy fromdomestic and agricultural waste Since CO2 is fixed by photo-synthesis from growing processes it is one of only a few optionsthat may result in net negative CO2 emissions when implementedwith CCS56 Only one study concerning the LCOH from biomassgasification coupled with CCS was found22 which reported avalue a $227 kg1 H2

Several LCA studies have been conducted in the field ofhydrogen production via biomass gasification The LCE valuesreported range from 031ndash863 kg CO2e kg1 H257ndash62 with anaverage of 259 kg CO2e kg1 H2 The large range stems fromvariations in biomass feedstocks (eg waste or different types ofenergy crop) and transportation requirements The inclusion ofland-use change effects may also add to environmental impactssignificantly which is not considered here and not well studiedin active literature Only one study investigating biomassgasification with CCS for hydrogen production was conductedby Susmozas et al63 This study reported the gasification of poplarbiomass with capture and sequestration of 70 of the producedCO2 resulting in an overall LCE of 1458 kg CO2 kg1 H2 Due tothe similarities between coal gasification and biomass gasification

pathways the CAC of $6592 t1 CO2 for coal gasification is used asthe avoidance cost for equipping CCS to biomass gasification Itshould be noted that due to commercial immaturity and requiredreactor modifications this is likely an underestimate of the cost ofCCS with biomass gasification

34 Methane pyrolysis

Pyrolysis involves the decomposition of hydrocarbons at hightemperatures (thermally or catalytically) in non-oxidative environ-ments to produce hydrogen and solid carbon (eqn (8)) Methanerepresents the most promising hydrocarbon for pyrolysis given itshydrogen-to-carbon ratio and large reserves (in particular if hydratesare included64) Since no water or air is present during reaction nocarbon oxides (CO or CO2) are formed eliminating the need forsecondary reactors (ie waterndashgas shift)8

CH4 2 C + 2H2 DH0 = 756 kJ mol1 DG0 = 63 kJ mol1

(8)

Without the inclusion of the waterndashgas shift and preferentialoxidation to CO reactions processing for CH4 decomposition isgreatly simplified relative to SMR65 Additionally the higher H2

concentration of the gas stream exiting the reactor for methanepyrolysis has the potential for a considerable reduction incapital and operating costs due to less downstream processingrequired to produce commercial-grade H2 relative to SMR65

The thermal decomposition of natural gas has been extensivelyinvestigated for the formation of valuable carbon products andis commercially practiced to produce carbon black for use intires and electrical equipment66 Approximately 95 of theglobal carbon black market demand (B164 million tonnes)is supplied by non-catalytic methane pyrolysis From the stoichio-metry of eqn (8) if the global hydrogen demand were supplied bypyrolysis the carbon produced would be approximately 12 timesthe size of the carbon black market For hydrogen production thetechnology is less mature with only a handful of pilot to early-stagecommercial sites in operation66

The economics of methane pyrolysis are strongly determinedby the natural gas price and value of the carbon by-product Theavailable literature studies concerning LCOH range from $103ndash245 kg1 H2 with an average of $175 kg1 H2 for natural gasprices from $32ndash68 GJ1 (summarised in Table S8 ESIdagger)Literature estimates of the LCOH alongside assumed natural gasprice and carbon product value are shown in Fig 2 Depending onthe catalyst used the carbon product formed can provide anadditional revenue stream Carbon values in the literature studiesrange from $0ndash300 t1 whereas potential carbon product valuesrange from $0ndash10 000 t1 for valuable carbon modifications(graphite carbon fibers etc)66 The preferred temperature rangescarbon products and catalyst selections have been studied indetail elsewhere and are not discussed here967 Large-scaledeployment of pyrolysis technologies for decarbonisation wouldquickly surpass demand for carbon in the absence of new marketdevelopments For a conservative approach in this study a LCOHof $176 kg1 H2 is estimated based on a recent model developedby Parkinson et al71 using a natural gas price of $4 GJ1 and a


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carbon product value of zero The range of cost estimatespresented in Table 5 are generated by varying the carbonproduct value from $10 to 150 t1 (negative value reflects ano value product with a small disposal cost)

The GHG emissions values of methane pyrolysis processesare heavily dependent on the fuel source for heating andwhether the study included emissions contributions from thenatural gas supply chain The direct emissions could potentiallybe as low as 11 kg CO2 kg1 H2 given the process chemistry ifmethane was used as the process fuel or even zero if 30ndash35of the hydrogen product was burned Several studies3568ndash70

report the direct emissions of a pyrolysis facility to range from02ndash25 kg CO2 kg1 H2 Rudimentary LCAs including upstreamfugitive emissions estimate LCE of 19ndash55 kg CO2 kg1 H2142171

The highest value of 55 kg CO2 kg1 H2 reported by Machhammeret al14 utilized an electric heater as a heat source resulting in higheremissions per kg of hydrogen product

For methane pyrolysis using the updated supply chainemissions discussed in Section 31 this study estimates thesupply chain emissions contribute 428 kg CO2e kg1 H2 for themedian case with a range of 326ndash644 kg CO2e kg1 H2 usingan overall process efficiency of 53 HHV71 This study estimatesusing natural gas as a heat source a mean LCE of 61 kg CO2e kg1

H2 with a range of 42ndash914 kg CO2e kg1 H2 This is higher thanany of the LCE values reported in the literature due to the previouslyunderestimated or not included supply chain contribution to overallLCE of a pyrolysis facility Compared to SMR more natural gasis required per unit hydrogen product which increases theimportance of accurate supply chain contributions to the overalllife cycle emissions

35 Electrolysis routes

The electrolysis of water to hydrogen (eqn (9)) is a commerciallymature process It is a promising technology for storing surplusenergy from intermittent renewable sources in the form ofhydrogen72 Low-carbon electrolytic hydrogen requires electricityfrom low-carbon technologies such as solar PV wind turbines ornuclear power The developed and commonly used electrolyzertechnologies are alkaline proton exchange membrane (PEM) andsolid-oxide electrolysis cells (SOEC)72 Alkaline water electrolysisusing an aqueous potassium hydroxide solution is the most

commercially mature of the technologies providing the lowestcapital costs but is limited by low current densities (02ndash05 A cm2) resulting in high electrical energy costs52 SOECare the most electrically efficient of the three technologies butare currently in the RampD stage facing challenges with corrosionseals thermal cycling and chromium migration73 PEM electro-lysis is currently more expensive than alkaline technologies butis an attractive future technology due to higher current densities(42 A cm2) higher efficiencies (the largest cost driver)dynamic operation and compact system design74 An excellentsummary of the technical specifications of each technology hasbeen compiled by Bhandari et al28

H2O1

2O2 thornH2 DH0 frac14 286 kJ mol1 DG0 frac14 237 kJ mol1

(9)

351 Electrolysis route emissions The direct emissionsfrom electrolytic hydrogen production are very low but theindirect emissions associated with electricity feedstock andelectrolyzer systems must be considered28 The theoreticalminimum electrolyzer energy requirement is approximately393 kW h kg1 H2 (HHV H2 at room temperature) butcommercial applications require 50ndash60 kW h kg1 H275 For afossil fuel dominated electrical grid this results in substantiallyhigher emissions compared to natural gas reforming Forexample an emissions contribution from electricity supplyalone of 23 kg CO2 kg1 H2 would result if power were suppliedby a natural gas combined cycle turbine at 467 kg CO2 MW h1

(US EPA regulation) of electricity produced21 A larger proportionof coal fired electricity as is the case in many nations would resultin significantly higher emissions

Estimates of LCE of electrolytic hydrogen vary widely acrossthe literature and the use of primary data has been very limitedFor wind electrolysis a detailed report prepared at NREL93 isthe major data source (097 kg CO2e kg1 H2) for every paperdiscussing LCA of this method Additionally none of thestudies considered the emissions contribution of the electro-lyzer unit The same applies for nuclear based electrolyticprocesses of which only two independent primary sources9495

were found For solar PV based electrolysis the values vary by over afactor of two Little data is available on the LCE contribution fromelectrolyser manufacturing and replacements with estimatessuggesting a relatively small contribution in the range of 30ndash50 gCO2e kg1 H2

287677 depending on operating lifetime utilizationrates The available LCE estimates from the literature for windelectrolysis range from 08ndash22 kg CO2e kg1 H2 (average of134 kg CO2e kg1 H2) 199ndash71 kg CO2e kg1 H2 (average of447 kg CO2e kg1 H2) for solar electrolysis and 047ndash213 kgCO2e kg1 H2 (average of 165 kg CO2e kg1 H2) for nuclearelectrolysis

LCE values are re-estimated in this study (Table 3) calculatedfrom the contributions of the LCE per kW h of the energygeneration technology and the manufacture of the electrolyzer(Fig 3) using an overall energy requirement of 512 kW h kg1

H2 The overall energy requirement was calculated from anoptimistic 85 cell voltage efficiency with a total balance of

Fig 2 Summary of the LCOH from pyrolysis processes available in theliterature32486971103ndash105 Labelled values represent the carbon sale price($ t1 carbon) assumed in the study


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plant load 504 kW h kg1 H275 For wind and solar electrolysisroutes emissions estimates were taken from a review of 153 lifecycle studies of wind and solar power generation by Nugentet al96 The interquartile ranges of LCE per kW h are 94ndash214 g CO2e kW h1 (median of 166 of CO2e kW h1) and25ndash48 g CO2e kW h1 (median of 424 g CO2e kW h1) for windand solar power respectively This generates ranges of 052ndash114 kg CO2 kg1 H2 (central estimate 088 kg CO2 kg1 H2) and132ndash25 kg CO2 kg1 H2 (central estimate 221 kg CO2 kg1 H2)for wind and solar electrolysis respectively

Several of the nuclear electrolysis routes shown in Table S7(ESIdagger) are high-temperature electrolysis processes using SOFCHere PEM electrolysis with nuclear power as a feedstock isused The LCE per kW h generated for nuclear power weretaken from a systematic review of 99 independent estimatesconducted by Warner et al97 with an interquartile range of 84ndash18 g CO2e kg1 H2 (median of 14 g CO2e kg1 H2) The generatestotal LCE estimates of 047ndash096 kg CO2 kg1 H2 with a centralestimate of 076 kg CO2 kg1 H2 for nuclear electrolysis Interquartileranges were used due to the relatively small data sets skewingstandard deviations and 5thndash95th percentile ranges As emissionsintensity per kW h varies based on utilization factors a sensitivityanalysis of the LCE of each technology was performed using theinterquartile ranges of LCE for each technology (Section 44)

352 Electrolysis route costs For isolated systems (notgrid connected) the cost of electrolysis routes is strongly dependenton the electrolyzer capital cost the cost of the electricity feed (or

capital) and utilization factor resulting in a large range of LCOHvalues A relationship presented by Acar et al12 without specifyingelectrolyzer type or cost for 1 to 1000 tpd H2 is shown in eqn (10)



085 (10)

The available literature studies concerning LCOH fromwind electrolysis range from $356ndash908 kg1 H2 (average of$564 kg1 H2) $334ndash1730 kg1 H2 (average of $1089 kg1 H2)for solar electrolysis and $195ndash620 kg1 H2 (average of$424 kg1 H2) for nuclear electrolysis Electrolyzer capitalcosts vary significantly across studies from $300ndash1300 kW1

with different resource availability estimates assumed energygeneration capital or LCOE supply A summary of the LCOH ofthe various routes from literature is shown in the ESIdaggerTable S7 Hydro-power based electrolysis has been excludedfrom the analysis due to limited resource availability given thegeographic requirements of the technology However as thecost of hydrogen produced by electrolysis can be described by alinear function of the levelized cost of electricity it can be deter-mined for specific locations and embodied emissions per kW h

In this study the LCOH was estimated with a discountedcash flow analysis using the LCOE from each energy generationtechnology and standard capacity factors (Table 2) PEM waschosen as the reference electrolyser technology operating with

Fig 3 Renewable electrolysis routes considered LCE for energy generation technologies and electrolysers considered independently on a kg CO2e kW h1

and kg CO2e kg1 H2 basis respectively

Table 2 Electrolyzer routes LCE capacity factor LCOE and capital cost data used in this study

TechnologyAverage life cycle CO2 emissionsper kW h produced (g CO2e kW h1) On-stream factor () LCOE ($ kW h1)

Electrolyzer CAPEXrange72 ($ kW1)

Wind electrolysis 166 (94ndash214) 33 006 (004ndash008)800 (400ndash1000)Solar PV electrolysis 424 (25ndash48) 20 008 (0056ndash01)

Nuclear electrolysis 14 (84ndash18) 95 01 (008ndash012)


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an 85 cell voltage efficiency (B51 kW h kg1 H2)106 For windand solar technology routes the lower LCOE sensitivity boundsare the projected minimum LCOE costs based on technologylearning curves to 2050 projected by Wiser et al107 andthe IEA108 respectively The lower bound LCOE for nuclear poweris based on mid-range future estimates by the World NuclearAssociation109 although they note drawing any strong conclusionsabout future nuclear power costs based on a specific countriesexperience may not be indicative of future pricing This generatescost ranges of $461ndash1001 kg1 H2 (central estimate $786 kg1 H2)$71ndash1487 kg1 H2 (central estimate of $1200 kg1 H2) and $499ndash821 kg1 H2 (central estimate of $679 kg1 H2) for wind solar andnuclear electrolysis respectively Further assessment assumptionsare detailed in the ESIdagger Tables S9ndashS12

36 Nuclear thermochemical cycles

The inefficiencies of several energy conversion steps fromnuclear heat to hydrogen via electrolysis has prompted signifi-cant research into direct use of the nuclear heat for watersplitting via thermochemical cycles54 Over 100 different thermo-chemical cycles have been identified78 but only twenty five cycleswere found to be feasible by Brown et al79 At present the mostpromising high-temperature and low-temperature cycles are thesulphurndashiodine (SndashI) cycle and copperndashchloride (CundashCl) cyclerespectively80 The SndashI cycle is a thermally driven cycle describedby eqn (11)ndash(14)13

H2SO4 aqeth THORN heat 300500 Ceth THORNH2O geth THORN thorn SO3 geth THORN (11)

SO3ethgTHORN heateth800900 CTHORN 1

2O2ethgTHORN thorn SO2 geth THORN (12)

SO2(g) + I2(g) + 2H2O(l) - 2HI(g) + H2SO4(aq) (13)

2HIethgTHORN heateth425450 CTHORNH2ethgTHORN thorn I2ethgTHORN (14)

As there are no side reactions from eqn (10)ndash(13) recyclingthe products of each step is a relatively straightforwardprocess81 The reliance on high temperature to drive the reac-tions requires either nuclear power or concentrated solar ofwhich nuclear power has been the primary research focus dueto intermittency of solar resources The CundashCl cycle is lessefficient than the SndashI cycle (B40 vs 60 respectively) butoperates at lower temperatures (350ndash550 1C) significantly redu-cing the engineering challenges80 The most common CundashClcycle is characterized by five main steps shown in eqn (15)ndash(19)

2CuCl2ethsTHORN thorn 2H2O geth THORN 450 C2HClethgTHORN thorn Cu2OCl2ethsTHORN (15)

Cu2OCl2ethsTHORN 500 C2CuClethlTHORN thorn

1

2O2ethgTHORN (16)

4CuClethaqTHORN 25 C2CuCl2ethsTHORN (17)

2CuCl2 aqeth THORN 90 C2CuCl2 leth THORN (18)

2CuethsTHORN 450 C2HClethgTHORN thorn 2CuClethlTHORN thornH2ethgTHORN (19)

Available studies concerning the cost of hydrogen producedby the above thermochemical water splitting cycles are shownin the ESIdagger Table S8 The LCOH for the SndashI and CundashCl cyclesrange from $147ndash271 kg1 H2 and $147ndash27 kg1 H2 withaverages of $181 kg1 H2 and 213 kg1 H2 respectivelyThermochemical cycle cost data is limited with none of thestudies publishing the capital cost data used to determine theLCOH Thus there is significant and unquantifiable uncertaintyin the LCOH estimates Deployment of the thermochemicalcycles have so far been limited to pilot-scale testing by the JapanAtomic Energy Agency and further RampD by the Idaho NationalLaboratory Large production scales would be required to matchthe heat produced by nuclear facilities built at-scale

The LCE values reported for the SndashI and CundashCl cycles rangefrom 041ndash22 kg CO2 kg1 H2

121382 and 07ndash18 kg CO2 kg1

H2121383 with averages of 12 kg CO2 kg1 H2 108 kg CO2 kg1

H2 respectively As no greenhouse gas emissions are producedfrom the operation of thermochemical water cycles the life cycleemissions are generated from the materials of constructionreplacement of inventory and waste disposal There is signifi-cant uncertainty in the limited emissions estimates available asthe sources of contributions to overall emissions values are nottransparent

37 Summary of hydrogen costs and emissions inventory

A summary of the ranges in the literature of emissions for eachtechnology route is compared to the re-estimates in this study isgiven in Table 3 In the absence of detailed quantitative data forthe supply chain analyses for biomass gasification and thermo-chemical nuclear cycles no emissions re-estimates from existingliterature have been made More robust supply chain analysis isrequired for these technologies for appropriate ranges to bededuced and should be the subject of future research Likewisea summary of the literature cost data versus re-estimates in thisstudy is given in Table 4 No updated estimates are provided forunabated SMR and coal gasification as they are technologicallymature with well-established cost structures No updatedestimates are provided for biomass gasification and nuclearthermochemical cycles due to the absence of detailed and trans-parent quantitative data

4 Results41 The levelized cost of carbon mitigation

The LCCM was calculated using eqn (1) using the re-estimatedcentral LCOH and LCE values from Section 3 In the absence ofupdated values for some technology routes the median referencevalues from the literature presented in Tables 3 and 4 are used todetermine the LCCM The estimates of the LCCM are given inFig 4 for each technology relative to the baseline SMR values

As the LCCM value for each technology is dependent on itsown LCOH and LCE as well as the reference values used forSMR the error bars in Fig 4 show the sensitivity of varying the SMRreference values by changing the natural gas price and overall LCEThe natural gas price has been varied from $$2ndash6 GJ1 to reflect


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variation in region-specific prices and future uncertainty and theoverall SMR LCE from low to high (1009ndash1721 kg CO2e kg1 H2) Inaddition to changing the reference value the varying natural gasprices and supply chain contributions to LCE also directly affectsnatural gas using technologies such as SMR with CCS and pyrolysis

42 Variation of key parameters affecting costs and emissionsinventories

In this section we determine the impact of varying the keyunderlying parameters influencing the levelized cost and life

cycle emissions for each hydrogen production technologies onthe LCCM The parameter ranges used for this sensitivityanalysis are presented in Table 5 by hydrogen productiontechnology The results of this sensitivity analysis are presentedin Fig 5 and the most promising technologies and areas forinnovation are discussed in the remainder of this section

The LCCM results shown in Fig 4 and 5 show a cleardivision of 04ndash1 orders of magnitude between technologiesthat utilise naturally-occurring energy-dense fuel and electrolysisroutes that use less energy dense sources with more complexsupply chain routes The high LCCM values for electrolysis routesdespite very low LCE are due to the low overall efficiencies createdby multiple conversion steps resulting in very high LCOH valuesThe lowest LCCM routes are nuclear based thermochemical cyclesfollowed by biomass gasification and methane pyrolysis The sensi-tivity of the LCCM values to changes in SMR reference values do notchange the relative orders of magnitude of mitigation costs Forbiomass gasification with CCS despite the significantly higher costthe large reduction in LCE values results in small variations tothe LCCM for the changes in the reference SMR values It isinteresting to highlight technologies of lower TRL have thelowest LCCM values

The LCCM is an estimate of the additional cost associatedwith reducing the emissions of hydrogen production per tonneof CO2e against emissions of hydrogen production using SMRIt is important to recognize that LCCM reveals the lowest costsassociated with any emission reduction where lower proportionalemission reductions are typically much less costly The pro-portional reduction in emissions and cost increase relative toSMR is shown in Fig 6 along with an indication of thevariability in emissions and costs from the ranges defined inthis study Fig 6 uses the ranges from Tables 3 and 4 for eachtechnology An emissions reduction of 100 represents areduction in emissions equivalent to the life cycle emissions ofunabated SMR or in other words a net zero life cycle emission

Table 3 Summary of the emissions inventories available in the literature from Section 3 compared to the re-estimates in this study Literature estimatesare a summary of the full range of literature values presented in Section 3

Technology

Literature estimates (kg CO2e kg1 H2) Our estimates (kg CO2e kg1 H2)

Low Central High Low Central High

SMRa 1072 124 1586 1009 1324 1721SMR w CCSa 31 43 592 297 561 916Coalb 144 1914 2531 1472169e 19782385e 2609309e

Coal w CCSb 078 18 52 109327e 21162e 5521035e

CH4 pyrolysisa 19 372 554 42 61 914Biomass 031 26 863 031 26 863Biomass w CCSc 1458 1166 1458 1750Electrolysis windd 085 134 22 052 088 114Electrolysis solard 199 447 71 132 221 25Electrolysis nucleard 047 165 213 047 076 096SndashI cycle 041 12 22 041 12 22CundashCl cycle 07 108 18 07 108 18

Our lsquolsquoLowndashCentralndashHighrsquorsquo estimates utilize a supply chain contributions of 06ndash14 (central 09) fugitive methane emissions and 82ndash148 g CO2 MJ1 HHV(central 10 g CO2 MJ1 HHV) to the full emissions range presented in the literature b the IPCC Tier 1 emissions ranges of 10ndash25 m3 CH4 t1 forunderground coal and 032ndash077 kg CO2e kg1 H2 (central estimate of 045 kg CO2e kg1 H2) for surface mined coal supply chain contributions to the fullemissions range presented in the literature c20 of the single reference study d the interquartile ranges of the g kW h1 emissions from powergeneration study reviews (Section 35) combined with electrolyser contributions of 40 g CO2e kg1 H2 e First value represents total LCE estimates fromsurface mined coal and the second value total LCE estimates from underground mined coal

Table 4 Summary of the cost inventories available in the literature fromSection 4 compared to the re-estimates in this study Literature estimatesare a summary of the full range of literature values presented in Section 3

Technology

Literature estimates($ kg1 H2)

Our estimates($ kg1 H2)


SMR 103 126 216 103 126 216SMR w CCSa 122 188 281 193 209 226Coal 096 138 188 096 138 188Coal w CCSb 14 217 36 224 246 268CH4 pyrolysisc 103 175 245 136 176 179Biomass 148 224 300 148 224 300Biomass w CCSd mdash 227 mdash 315 337 36Electrolysis winde 356 524 1082 461 786 1001Electrolysis solare 334 887 173 71 1200 1487Electrolysis nucleare 329 463 601 499 679 821SndashI cycle 147 181 271 147 181 271CundashCl cycle 147 213 27 147 213 27

Our lsquolsquoLowndashCentralndashHighrsquorsquo estimates use aan updated SMR CCS cost of$9615 t1 CO2 20 for a 90 point source capture scenario from theliterature median hydrogen production cost of $126 kg1 H2 b an updatedcoal gasification CCS cost of $6592 t1 CO2 20 for a 90 point sourcecapture scenario from the literature average cost of $138 kg1 H2 c adjustedcarbon sale price from $10 to 150 t1 carbon product for $4 GJ1 naturalgas cost d an updated biomass gasification CCS cost of $6592 t1 CO220for a 90 point source capture scenario from the literature reference cost of$227 kg1 H2 and e the technology specific LCOE and capital cost boundsshown in Table 2 and economic assumptions shown in Tables S9ndashS12 (ESI)


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The only technology considered capable of exceeding this limit toproduce negative emissions is biomass gasification with CCSTechnologies on the lower end of the cost increase scale representmore cost-effective mitigation options but deeper decarbonisationoptions require much larger costs

43 Fossil fuel routes

The sensitivity range of decarbonization fractions presented inFig 6 shows under current practices all of the fossil-basedroutes do not exceed 65 decarbonization (76 69 and 92best case for SMR CCS pyrolysis and surface minded coal withCCS respectively) These decarbonization fractions are not

commensurate with the decarbonization targets required intransport heat and industry under many scenarios particularlyas global aspirations turn to net zero emissions in the secondhalf of the 21st century84 This highlights that technologiessuch as carbon capture and sequestration may potentially be anexpensive exercise in heroic futility if all aspects of hydrogensupply chains are not addressed No cost is currently applied tomethane emissions and the costs of mitigating supply chainemissions are less well understood than emissions at the pointof conversion It has been suggested that 75 of global methaneemissions from oil and gas supply chains are mitigatable withhalf of these achieved at a positive net present value85 Yet the

Fig 4 The LCCM for each hydrogen production technology considered in this study relative to the baseline SMR values for LCOH and LCE The errorbars show the sensitivity of the LCCM to variations in the natural gas price from $2ndash6 GJ1 with a base value of $4 GJ1 and the SMR LCE emissions from1009ndash1721 kg CO2e kg1 H2 with a base value of 1324 kg CO2 kg1 H2 Technologies highlighted by red text represent technologies with TRL levels of 5or less

Table 5 Summary of technology specific LCOH and LCE key parameter variations identified in Sections 4 and 5 of this study

Technology LCOH sensitivity parameters LCE sensitivity parameters

SMR + CCS CCS CAC price (20 of $96 t1 CO2) Full LCE range 90 capture (297ndash916 kg CO2 kg1 H2)Coal gasification + CCS CCS CAC price (20 of $6592 t1 CO2) Full LCE range 90 capture (109ndash1035 kg CO2 kg1 H2)Methane pyrolysis Carbon selling price ($10ndash150 t1 carbon) Full LCE range (42ndash914 kg CO2 kg1 H2)Biomass gasification LCOH (literature range 148ndash300 kg1 H2) LCE literature range (041ndash863 kg CO2 kg1 H2)Biomass gasification + CCS CCS CAC price (20 of $6592 t1 CO2) LCE literature (20 of LCE value of 1458 kg CO2 kg1 H2)Electrolysis ndash wind LCOE amp electrolyzer capex ($004ndash008 kW h1

$400ndash1000 kW1)Wind power carbon intensity (94ndash214 g CO2 kW h1)

Electrolysis ndash solar LCOE amp electrolyzer capex ($0056ndash01 kW h1$400ndash1000 kW1)

Solar power carbon intensity (25ndash48 g CO2 kW h1)

Nuclear SndashI cycle LCOH (literature range $147ndash271 kg1 H2) LCE literature range (041ndash22 kg CO2 kg1 H2)Nuclear CundashCl cycle LCOH (literature range $147ndash270 kg1 H2) LCE literature range (07ndash18 kg CO2 kg1 H2)Electrolysis ndash nuclear LCOE amp electrolyzer capex ($008ndash012 kW h1

$400ndash1000 kW1)Nuclear power carbon intensity (84ndash18 g CO2 kW h1)


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fact that these emissions remain suggests either there are hiddenadditional costs or that industry are not acting cost-optimallyWith enough incentive (eg via pollution tax as per ref 86) thereis potential to constrain emissions considerably as this studydemonstrates under a low supply chain emissions scenario (and90 capture rates) a LCE of 297 kg CO2 kg1 H2 an 76reduction from the median estimate of SMR without CCS

431 SMR with CCS Understanding and managing emissionsfrom the natural gas supply chain networks is critical todecarbonizing hydrogen supply even for SMR equipped with

CCS achieving 90 capture rates The emissions contributionsfrom supply chain networks to the total LCE of hydrogenproduction in the past have not been given enough considerationand are non-negligible For example a supply chain with 14methane emissions and CO2 emissions of 148 g CO2 MJ1

CH4 HHV (the upper estimate for supply chain contributions)delivered would contribute 5 kg CO2 kg1 H2 (76 overallefficiency HHV) which exceeds the current literature estimatesof total LCE from SMR with CCS (43 kg CO2 kg1 H2) Inthis study supply chain emissions were varied from 297 to916 kg CO2 kg1 H2 which resulted in a LCCM variation of97ndash110 $ t1 CO2 The small range of LCCM values is generatedfrom the additional gas requirement for equipping CCS relativeto unabated SMR

The supply chain emissions ranges presented in this studyresult in a higher upper estimate LCE values for SMR SMR withCCS methane pyrolysis and coal gasification with CCS thanreported elsewhere in the literature The deployment of CCSat-scale is the only method widely considered to be available tosubstantially mitigate CO2 emissions from fossil fuels which sofar has failed to meet ambitious expectations and continueddelays of demonstration projects are causing considerableuncertainty about the role CCS will play in carbon mitigation87

This study has shown that equipping CCS to SMR (90 capture)only effectively reduces the life cycle GHG footprint of hydrogenproduction by 38ndash76 depending on the contribution of supplychain emissions Additionally the capture rates may currently belower than 9039 And whilst 90 or 95 capture is achievableit is not guaranteed thus emissions may be even higher Theadditional contributions to the overall GHG footprint from the

Fig 5 LCCM results for technology specific variations to LCOH and LCE values as detailed in Table 5 LCOH parameter variations show are thecombined variation of LCOE and electrolyzer capital costs as per the ranges in Table 5 Technologies highlighted by red text represent technologies withTRL levels of 5 or less

Fig 6 Proportional reduction in emissions against percentage costincrease relative to SMR The variability of emissions and cost parametersshown reflect the full ranges of emissions and costs values used in thisstudy and presented in Table 5 Biomass with CCS emissions reduction of213 and a cost increase of 168 has been omitted from the chart as anoutlier to allow focus on other technologies


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supply chain are clearly significant and decarbonization com-parisons need to focus on more than just point-source emissions

The cost of equipping CCS to SMR operations is highlyvariable (Fig 1) with actual process costs by the few demon-stration plants not publicly available The operational andcapital costs would also change with different capture rateswith higher capture rates requiring greater fuel duty andequipment88 In Fig 5 the sensitivity bounds of the CAC arevaried by 20 of the $96 t1 CO2 (point-source cost) used inthis study resulting in a range of CAC from $78ndash118 t1 CO2

(Fig 4 and 5) It is likely that in the absence of an effective priceon GHG emissions (in the form of carbon taxation or emissionstrading schemes) there will be no economic incentive fordecarbonizing hydrogen supply from SMR operations and assuch no reductions in avoidance costs As the business case forCO2 abatement is quite different to that of CO2 enhanced oilrecovery or enhanced coal bed methane these applicationshave not been considered here A detailed review of carboncapture and utilization options is presented by Hunt et al89 TheCO2 storage potential to such economic uses in any case is smallrelatively to depleted oil and gas fields and saline aquifers73

Amine-based CO2 absorption systems are also commerciallymature technologies in the chemicals sector90 Without a step-change in separation technologies the cost of MEA-based CO2

separation is unlikely to contribute significantly to future costreductions for CCS Several proposals for equipping CCS toindustrially active clusters with shared transport and storageinfrastructure have been proposed and it is widely agreed thelargest cost reductions can be achieved here91ndash95 The transportand storage costs used in this study ($$22 t1 CO2) correspondto approximately 22 of the overall CCS cost for SMR andas such represent a potentially achievable cost reductionHowever it should be noted that the storage capacity of CO2

is a factor of which the cheapest storage reservoirs alsocontribute the least to total available capacity73 Long termmonitoring of storage sites is also required to ensure leakage ratesto the atmosphere of less 01 year1 needed to ensure effectiveclimate change abatement are maintained9697 Commercial scalestorage sites will also have to manage the risks of financialpenalties for unforeseen leakages98 These ongoing costs areexcluded from this study but may be non-negligible over time

432 Coal gasification with CCS The LCCM for coalgasification with CCS shown in Fig 4 and 5 is approximately$140 t1 CO2 with a full range of $104ndash440 t1 CO2 The lowerC H ratio in coal would suggest the higher quantity of CO2 perunit hydrogen should be costlier to sequester which is notapparent from the lower CAC of B$65 t1 CO2 There are twomain factors contributing to the LCCM values obtained inthis study First coal gasification for hydrogen production iscommercially competitive with SMR where the gas prices arehigh or economies of scale are present The studies concerningCAC for CCS of coal-to-hydrogen plants are large-scale facilitiesdistributing CCS capital across larger production volumesCoupled with very low feedstock costs the reduced capital burdenper tonne of hydrogen product skews the CAC for equipping CCSSecondly CAC are associated with costs of reducing CO2 emissions

from within a process facility and do include emissions fromsupply chain networks included here Fig 7 shows the influenceof the coal supply chain on the overall LCCM and total LCEof hydrogen production from coal gasification with CCS(90 capture)

The supply chain emissions from coal mining are only smallfor shallow mined coals only representing a significant portionof total LCE when high CO2 capture rates (485) are achievedThe differences reported for surface mined coal are within theuncertainty ranges of the effectiveness and cost of coal gasifica-tion with CCS For coal gasification with CCS (90 capture)decarbonization percentages of 58ndash92 22ndash75 relative toSMR without CCS are achievable for overground and under-ground mined coal respectively For underground mined coal itis apparent that previous hydrogen production assessmentshave underestimated the potential contribution of the supplychain to overall LCE It should be noted however there is alarge body of literature that suggests up to 60 of coal minemethane mitigation is achievable at relatively low cost99100 Thelow sensitivity of LCOH to coal prices suggest there is potential toreduce the 405 kg CO2e kg1 H2 for underground mines closer tothe surface mining value of 045 kg CO2e kg1 H2 without asignificant increase in the LCOH Other than minimizing surfacearea there are currently no available options for reducing fugitivemethane emissions from open-surface mines For CCS with 90capture and 55 HHV overall efficiency the central estimate of21 kg CO2e kg1 H2 from surface mined coal is the lowest LCE ofany of the fossil fuel routes presented

Coal-to-hydrogen processes are however less prevalent asdedicated hydrogen producers with advanced coal gasificationconcepts aiming to integrate CO2 separation with waterndashgasshift reactions to achieve higher process efficiencies with ease ofCO2 capture101 Whilst reduction of CCS costs may be achievablewith technological development the order of magnitude is entirelyspeculative Like SMR with CCS the integration of industrialclusters with shared transport and storage infrastructure may

Fig 7 Influence of the coal source on the total LCE and LCCM from coalgasification with CCS (90 capture) The supply chain for underground minedcoal is varied from 251ndash56 kg CO2 kg1 H2 (base 405 kg CO2 kg1 H2) andsurface mined coal from 032ndash077 kg CO2 kg1 H2 (base 045 kg CO2 kg1 H2)combined with the low middle and high estimates used in this study


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provide future cost reductions The order of magnitude estimatesfor coal-to-hydrogen with CCS are likely to remain around the$60ndash100 t1 CO247

433 Methane pyrolysis The LCCM for methane pyrolysisis most sensitive to the natural gas price carbon selling priceand the supply chain emissions The base LCCM for methanepyrolysis shown in Fig 4 and 5 is approximately $70 t1 CO2with a full range of $136ndash857 t1 CO2 The sensitivity of theLCCM to variations of individual key parameters is shown inFig 8 The other parameters were kept constant at the basevalues used in this study for each variation except where theLCOH and LCE for SMR were also influenced Variations inthe natural gas feedstock and fuel prices from $2ndash6 GJ1 (base$4 GJ1 for SMR and pyrolysis) has a significant impact theLCCM The US 2016 average gas price of $2 GJ1 yields LCCMcosts as low as B$28 t1 CO2 making it the lowest mitigation costof the technologies shown in Fig 5 Conversely the increasednatural gas consumption for methane pyrolysis reduces theeconomic competitiveness for higher natural gas prices Thehigher natural gas usage also negatively impacts the LCCM dueto higher supply chain emissions

The most sensitive factor for pyrolysis economics (and thusthe LCCM) is the product value assigned to carbon produced(Fig 8) The large-scale implementation of pyrolysis processesfor global decarbonization efforts would generate massivequantities of carbon of which the only solid-manufacturedproduct used in comparable volumes today is concrete Assigningvalue to the carbon products (4$B170 t1 carbon) makespyrolysis more economically competitive than SMR at $4 GJ1

gas prices and the LCCM zero At gas prices of approximately$2 GJ1 pyrolysis becomes more economically competitive thanSMR with carbon values exceeding $90 t1 carbon The physicaland electrical properties of the solid carbon will strongly determineits value as a co-product Initial process developments will likelyfind receptive markets for high value carbon products includinggraphite for lithium-ion batteries carbon fibers for reinforcedcomposite materials or needle coke for graphite electrodes inelectric arc furnaces Catalysed decomposition has in the past

been investigated primarily for this reason67 An excellentsummary current available carbon markets and relative sizesis presented in a recent review by the Argonne NationalLaboratory66

Using current practices methane pyrolysis and natural gasas a heat source only achieves a decarbonization fraction of38ndash67 Alternatively direct emissions from pyrolysis could bereduced to zero by using nuclear as a heat source or by burningB35 of the hydrogen product to supply the necessary heat70

This however would further increase the required capital andnatural gas utilization adding an additional $40 t1 CO2 to theLCCM despite the reduced LCE emissions The LCE range of42ndash914 kg CO2 kg1 H2 for methane pyrolysis presented in thisstudy identified a central estimate of 61 kg CO2 kg1 H2 whichis higher than any LCE value for pyrolysis reported elsewhereThis decarbonization fraction (B54 reduction compared toSMR without CCS) may be insufficient in western economieswith ambitious carbon mitigation targets This finding isof particular importance as the technology is regularly citedin academic literature as a means of producing CO2-freehydrogen24691419216668ndash70102ndash106 which is only achievable ifsupply chain emissions are low It should be noted however incontrast to technologies such as CCS the storage of a solidby-product carbon is relatively simple either temporarily orpermanently an idea first proposed as the lsquocarbon moratoriumrsquoby Kreysa104 Storage of solid carbon or the lsquoreverse carbonchainrsquo may provide a practical low-cost carbon sequestrationsolution for locations where gaseous CO2 storage sites arelimited (or non-existent) or expensive There may also be anadvantage in storing the carbon in an easily recoverable formpending future technological developments

Given that pyrolysis processes have had little commercialdevelopment for hydrogen applications it is anticipated thatcapital costs will be significantly reduced through researchinnovation and deployment at scale There are several technicalchallenges associated with management of the solid carbonproduced which fouls (cokes) solid catalysts102107ndash109 Howeverproponents of the technology claim these limitations can beovercome with appropriate process and reactor design to alloweasy separation of the carbon product1052106110 If pursued asa cost-effective mitigation option innovation in reactor designcarbon removal schemes and high temperature processingequipment could substantially enhance cost competitivenessReactor designs that can facilitate carbon separation andachieve high conversion will be critical for commercial pyrolysisprocess


Despite the low LCE of electrolysis routes the overall LCCM foreach route is 04ndash1 orders of magnitude higher For wind andsolar electrolysis the intermittent nature of power supplyresults in low-utilization of high electrolyzer capital increasingthe LCOH values The full LCCM range is $271ndash707 t1 CO2

(base $534 t1 CO2) and $529ndash1233 t1 CO2 (base $973 t1 CO2)for wind and solar electrolysis respectively For nuclear electro-lysis the high utilization factor minimizes the LCOH sensitivity

Fig 8 Sensitivity of the methane pyrolysis LCCM to major LCOH and LCEvariables used in this study


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to electrolyser capital and the LCOE dominates the LCOHThis results in a full LCCM range of $298ndash556 t1 CO2 (base$443 t1 CO2) for nuclear electrolysis The sensitivity bounds inFig 5 show the full combined range of electrolyzer capital andLCOE variations for each route The individual LCOE andelectrolyzer capital contributions to the LCOH are shown viaa sensitivity analysis in Fig 9

The LCOH values estimated in this study are higher than theranges presented in the literature Given the capital-intensivenature of renewable power generation and the fact that short-run marginal operating costs are low-to-zero the overall systemefficiency and weighted average cost of capital (discount rate)used in project evaluations have a critical impact on projecteconomics110 The standard capacity factors used for eachtechnology will likely show significant regional variations drasticallyaltering the realized LCOH The capacity factors presented hererepresent generic installations It should be noted however the

weighted average cost of capital (10) used in this study isconsistent with other techno-economic hydrogen productionstudies achieving similar hydrogen production costs111

It is interesting to note that electrolysis avoidance costsin their current status are comparable to negative emissionstechnologies such as direct capture estimated to be $600ndash700 t1 CO2 avoided111112 This however does not reflect costreductions available to electrolysis (in particular solar andwind capital cost reductions) pathways which would requireradically new designs for negative emissions technologies toreduce further Electricity prices from solar and wind power arehighly variable and largely depend on location specific factorsElectricity produced from solar is approximately proportionalto solar irradiance and wind proportional to the cube of thewind speed Effective deployment of each technology in highresource availability areas undoubtedly increases the resultingcapacity factor For example wind capacity factors have increasedmarkedly in the past decade and in some sites (eg Denmark)may exceed 50113 To reflect region-specific variability Fig 10(a)shows the influence of technology capacity factor using thecurrent and future LCOE and electrolyzer costs used in thisstudy Note that this assumes the electrolyser is sized formaximum generation capacity thus this capacity factor is thesame as the generation capacity The design of the electrolysermay be optimised to improve overall system efficiency if it wereundersized depending on the electricity generation profile Thisis not considered here but may serve to moderately reducetotal costs

Under ideal conditions with optimistic future costs theLCCM reaches minimum values of $200 t1 CO2 and $300 t1

CO2 for wind and solar respectively (Fig 10(a)) It is possible tosupply additional grid-based electricity to increase the electro-lyzer capacity factor but the carbon intensity of the grid supplystrongly influences the LCE of the hydrogen produced This isillustrated in Fig 10(b) which shows the effect of increasingthe utilization of an optimistic 50 capacity factor future wind

Fig 9 Sensitivity of electrolysis routes to supplied LCOE electrolyzercapital cost and emissions intensity of the power supply Utilization ratesand cost inputs are summarized in Table 2 and economic assumptions inTables S9ndashS12 in the ESIdagger

Fig 10 (a) Variation in wind and solar energy generation technology capacity factor using the current and future LCOE and electrolyzer costs reportedin this study (b) Impact of improving electrolyzer utilization factor by providing additional grid electricity to a 50 capacity factor wind electrolysissystem


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electrolysis scenario using the average EU (B0275 kg CO2 kW h1$0081 kW h1 114115) and French (B0050 kg CO2 kW h1$00596 kW h1 114115) electricity grids It is apparent from theincrease in LCCM for the EU grid average that the decrease inLCOH for higher utilization factors is outweighed by theincreased LCE of electricity production Comparatively use ofthe French grid supply consisting of approximately 75 nuclearpower maintains the LCCM at approximately $200 t1 CO2 aselectrolyzer capacity factors approach 95

Despite this wind and solar electrolysis routes are promisingtechnologies for achieving highly decarbonized hydrogen supply(91ndash96 and 81ndash90 respectively) Wind and solar power havewitnessed substantial cost reductions over the past two decadesand potential areas of future cost reduction have been identifiedby others116 The ability of solar PV to meet the required costreductions to be a more cost competitive mitigation optionrequires a balance between the investments required to produceand install a module the total energy provided by that moduleand its lifetime and conversion efficiency117 New materialsrealising sufficient efficiency stability and cost will be required118

Assuming such radical new designs and materials are possible theperformance and cost of the active components remain to bedemonstrated simultaneously17 Similarly one of key drivers ofthe increasing competitiveness of wind power has been continuedinnovation in turbine design and operation Continuous increasesin the average capacity of turbines hub-heights and swept areashave allowed higher utilization factors and reduced costs119

Continued innovation in turbine-design leading to higher utilizationfactors is required to further reduce costs

Cost reductions of a similar magnitude are also required inelectrolyzer manufacturing as the future PEM electrolyzer costsof $400 kW1 used in this study are substantially lower thantodayrsquos costs72 Cost decreases of this magnitude will requiremass production of PEM electrolyzers with streamlined marketintegration automated and standardized manufacturing processeswith robust quality control methods for avoiding componentfailure during operation72 However based on the analysispresented it is unlikely that future developments utilizingexisting technological pathways will reach cost competitivenessas mitigation options using current technological pathwaysTo be cost competitive with fossil fuel mitigation costs andnatural gas prices in the $3ndash6 GJ1 range this would require aLCOH of less than $3 kg1 H2 for wind electrolysis and lessthan $250 kg1 H2 for solar electrolysis with current embodiedemissions ranges Reducing the LCOH using grid electricityonly achieves relatively constant mitigation costs (B$200 t1

CO2) with increasing utilization factors for the best-case windelectrolysis scenario (50 capacity factor) if the grid-supplyis less carbon intense than the generation technology or iflow-cost nuclear power is available This highlights that for ahighly decarbonized hydrogen supply via electrolytic routescommensurate with demand profiles of current hydrogen appli-cations low-cost nuclear power is required

Whilst LCOH and LCE associated with the nuclear electro-lysis option are lower than those from wind and solar PV theadditional conversion steps and capital for nuclear electrolysis

routes compared to thermochemical cycles substantially increasesthe LCOH resulting in an average LCCM of $455 t1 CO2 Wheremultiple conversion steps are involved the overall efficiency of theprocess is the product of the individual conversion efficienciesThermal efficiencies of nuclear and combustion power plants toelectricity operating through Rankine cycles range from 31 for aMagnox type to around 40 for an advanced gas cooled reactor120

Using a 35 reactor conversion efficiency and combining this withthe optimistic 85 electrolyser efficiency used in this study theoverall efficiency of nuclear electrolytic routes is 2975 Usingoptimistic future costs of $400 kW1 electrolyzer costs and the lowerbound LCOE of $008 kW h1 the LCCM of nuclear electrolysis isreduced to B$300 t1 CO2

Government policy may further support regulatory structuresto enhance project viability by minimising the cost of debt ofrenewable-based projects Alternatively regulatory structuresto support business models leading to a high penetration ofrenewables with lengthy periods of excess electricity generatedthat would otherwise be wasted could enhance utilizationfactors of electrolyzers at no cost In either case both mechanismsrequire policy intervention to support one technological pathwayover others Such interventions may be required to achieve veryhigh decarbonization fractions in the future but initial investmentsshould focus where the highest return on investment (dollars spentper tonne of carbon avoided) are achieved To reduce costs in linewith current production methods they require higher capacityfactors lower electrolyzer costs andor low-cost low-carbon electricitysupply likely provided by nuclear Nevertheless hydrogen pro-duction from decentralized electrolysis will likely find cost-competitive decarbonization applications in the future reflectinga scenario-based constraint that some hydrogen demand is in areasthat cannot be sensibly accessed by centrally produced hydrogennetworks


From Fig 5 the direct conversion of nuclear heat from powerplants to hydrogen via the two thermochemical cycles discussedare promising candidate technologies for low mitigation costsand high decarbonization fractions The LCCM of the SndashI andCundashCl cycles of $46 t1 CO2 and $72 t1 CO2 respectively are thelowest base-case values obtained Although the thermochemicalcycle efficiencies (B50) have yet to be demonstrated at scale ithas been the subject of significant research by the Japan AtomicEnergy Agency121 General Atomics122 and Westinghouse123 Thefull range of LCOH and LCE values reported in the literaturegenerate LCCM ranges of $17ndash120 t1 CO2 and $117ndash118 t1 CO2

for the SndashI and CundashCl cycles respectivelyNuclear thermochemical cycles and nuclear electrolysis all

achieve decarbonization fractions in excess of 90 comparedto SMR without CCS It is important to note however that nocapital costs were reported in the studies comparing the LCOHand LCE of the two thermochemical cycles investigated whichhave been shown to be highly location specific Although unitcosts for technologies usually decrease with increasing volumeof production nuclear power has consistently seen the oppositewithin the United States which reflects the idiosyncrasies of


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the regulatory environment as public opposition grew andregulations were tightened124 Lovering et al125 reviewed globalhistorical construction costs of nuclear reactors and found incontrast to the rapid US cost escalations much milder costescalations and in some cases cost declines existed elsewhereThey concluded that there is no inherent cost escalation trendassociated with nuclear technology and the large variancewitnessed in cost trends over time and across different countrieseven with similar nuclear reactor technologies suggests that costdrivers other than learning-by-doing have dominated the costexperience of nuclear power construction125 Additionally as themajority of literature on nuclear power costs have focussed almostexclusively on the United States and France there is an incompletepicture of the economic evolution of the technology125

The true production costs of hydrogen via nuclear thermo-chemical cycles and nuclear electrolysis will likely be largelyuncertain until political rhetoric surrounding nuclear powersubsides and scientists and engineers are free to innovate inthis sector Nonetheless nuclear thermochemical cycles asenergy dense highly decarbonized energy sources are promisingroutes provided an actual LCOH of around $2 kg1 with currentembodied emissions values is achievable In particular the CundashClmay be capable of using low-grade waste heat from nuclearreactors after power generation increasing the value propositionof nuclear reactors


Biomass gasification appears to be an effective and relativelycheap means of carbon mitigation from hydrogen productionThe calculated LCCM from literature values range from $68ndash85 t1 CO2 and $21ndash213 t1 CO2 biomass gasification with andwithout CCS respectively The large variability of unabatedbiomass gasification stems from the large spread of embodiedemissions from biomass cultivation and capital cost of thefacilities The very low or negative LCE footprint results in ahigh degree of decarbonization (Fig 5) relative to SMR The lowrange for biomass gasification with CCS reflects a 20 of thevalues obtained for the single study available

Despite the high decarbonization fraction of biomassgasification routes the current concept of biomass-to-hydrogenhas several limitations Only a very small percentage of solarenergy is converted to hydrogen (B6ndash12 wt H2 kg1

biomass126) meaning that large land requirements for energycrops are necessary to contribute significantly to the existinghydrogen demand (or potential future hydrogen uses) Biomassenergy crops may also be geographically constrained to areasnot in competition with food production or to the utilization ofagricultural waste For example a hydrogen yield of 797 wtfrom purpose grown energy crops (449 dry tonnes acre1)would require B48 of the US agricultural crop area of545 000 square miles to satisfy current global hydrogen demandof 60 million tonnes per annum22 This number would likelygrow substantially if other sectors such as heat and transportwere decarbonized with H2 supply The costly transportation oflarge quantities of dispersed low-energy density biomass tocentral processing plants is another one of the major issues of

the technology Furthermore the environmental impact fromthe significant demand on land nutrient supply fertilizers andwater for bioenergy crops would reduce the environmentalbenefits of such an approach

The utilization of waste biomass or waste agriculturalresources may increase the economic and environmental benefitsin the displacement of landfill A recent report127 suggests withanticipated improvements in agricultural practices and plantbreeding feedstocks may exceed 244 million dry tons at afarm-gate price of $60 dry ton1 It has also been proposed thatwaste biomass feedstocks could be co-fired in coal gasificationfacilities to further reduce the net CO2 closer to zero withminimal impact on the downstream flue gas treatment unit128

In a plant with post-combustion capture this increases the cost ofelectricity by 6 and has no impact on the cost of CO2 avoidancebut the cost depends strongly on the cost of biomass128 Whileresearch and development focuses on gasification synergies withother fuel production process (biofuels) may accelerate the rate ofmarket uptake should biomass be pursued3

The production of hydrogen from biomass with CCS is oneof only a few technologies that may deliver negative emissionsat relatively modest costs which may become important forglobal decarbonization issues in the second half of this century129

But basic feedstocks are location-limited and competition withother more efficient liquid biofuel routes and direct powergeneration from waste feedstocks may restrict the role biomass-to-hydrogen routes fulfil This is reflected by several commercialexamples of biomass for heat and power130 but no completedindustrial-scale demonstrations of any biomass technology forhydrogen production126 The relative paucity of studies quanti-fying costs and emissions drives the relatively small ranges forbiomass gasification with CCS when compared to the largerranges of estimates for other technologies seen in Fig 6 Achallenge for future research is to better quantify all parametersrelating to biomass gasification with CCS costs and emissions

5 Conclusions

As with all comparisons between fossil routes and renewablescost and emissions data are frequently misused by advocates ofall parties to push policy-makers and public opinion furtheralong the polarizing debate of the role of fossil fuels in a low-carbon system The best approach to decarbonizing hydrogensupply at least cost is not to champion or demonize specifictechnologies but to jointly provide evidence to policy-makers tosupport higher levels of climate ambition Ultimately thedevelopment of low-CO2 large-scale and economically competitivehydrogen production processes is fundamental to the productionof low-carbon fuels fertilizers and other petrochemicals Toachieve this there is a significant amount of research going onto improve the performance of existing methods and to findnew promising routes to generate hydrogen

In this work technical economic and environmental aspectsof 12 different hydrogen production techniques were evaluatedand compared using the LCCM and decarbonization fraction


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Production costs and life cycle emissions were parameterisedand re-estimated from currently available estimates producingrobust ranges to describe the uncertainties for each technologyThe LCCM and decarbonization fraction was utilised as a basisfor providing an overall measure of the additional costs requiredto decarbonize hydrogen supply for any future uses Such anoverview provides a clearer picture of the relative merits ofvarious pathways than an isolated measure and the outcomesof this research are summarized presently

There is broadly a trade-off between the cost of mitigationand the proportion of decarbonization achieved The cheapestmethods of decarbonization are via the fossil routes due totheir low cost of extraction and processing but they only offermoderate decarbonisation levels with a largest central estimatereduction of 69 from surface mined coal with CCS (90capture) There is an order of magnitude difference in LCCMbetween renewable electrolytic routes and fossil-based hydrogenproduction suggesting that to decarbonize hydrogen supplyfor current and potential future uses cost-effective low-CO2

bridging technologies that take advantage of fossil-feedstocksmay be required This will allow the necessary time for therequired infrastructure and end-use applications to sustain alarge penetration of hydrogen into the energy economy to bedeveloped and minimize cost barriers for renewable-basedtechnologies

However emissions associated with the fossil fuel routesmay be higher than previously considered due to an under-estimation of upstream emissions to the overall footprintEmissions from supply chains vary significantly and are non-negligible particularly methane emissions across natural gasand coal supply chains The sensitivity range of decarbonizationfractions (Fig 6) showed central estimates under current practicesfor all of the fossil-based routes do not exceed 69 decarboni-zation (76 67 and 92 best cases for SMR CCS pyrolysisand surface minded coal with CCS respectively) These decarboniza-tion fractions are not commensurate with the decarbonizationtargets required in transport heat and industry under manyscenarios particularly as global aspirations turn to net zeroemissions in the second half of the 21st century in line with theParis Agreement84 This highlights that technologies such ascarbon capture and sequestration may potentially be an expensiveexercise in heroic futility if all aspects of hydrogen supply chainsare not addressed No cost is currently applied to methaneemissions and the costs of mitigating supply chain emissionsare less well understood than emissions at the point of conversionThis remains an important area for future research

Methane pyrolysis however may be the most cost effectiveshort-term mitigation solution that encourages building infra-structure necessary to sustain a high penetration of hydrogeninto the energy economy Its decarbonization fraction is heavilydependent on managing the contribution of supply chainemissions whilst cost-effectiveness will be governed by theprice of solid-carbon product and innovation in reactor designsThe LCE range (42ndash914 kg CO2 kg1 H2) presented in this studyidentified a median value of 61 kg CO2 kg1 H2 which is higherthan any LCE value for pyrolysis reported elsewhere in academic

literature This finding is of particular importance as thetechnology is regularly cited in academic literature as ameans of producing CO2-free hydrogen24691419216668ndash70102ndash106

which is only achievable if supply chain emissions are lowWhilst electrolysis routes offer significantly higher emissions

reductions than fossil routes (80ndash95 compared to SMR with-out CCS) costs are 04ndash1 orders of magnitude higher It isinteresting to note that hydrogen from electrolysis avoidancecosts in their current status are comparable to negative emissionstechnologies such as direct capture estimated to be $600ndash700 t1

CO2 avoided Production routes are more complex than thosethat utilise a naturally-occurring energy-dense fuel and electro-lyser costs are high at modest capacity factors They may indeedplay an important role in deep decarbonization pathways (especiallyin the absence of negative emissions technologies) but to reducecosts in line with current production methods they require highercapacity factors lower electrolyser costs andor a low-cost nuclearelectricity supply For cost-effective hydrogen commensurate withcurrent demand profiles low-cost low-carbon and reliable electricitysupply is essential Government policy may further supportregulatory structures to enhance project viability by minimisingthe cost of debt of renewable-based projects Alternativelyregulatory structures to support business models leading to ahigh penetration of renewables with lengthy periods of excesselectricity generated that would otherwise be wasted couldenhance utilization factors of electrolyzers at no cost In eithercase both mechanisms require policy intervention to supportone technological pathway over others Such interventions maybe required to achieve very high decarbonization fractions butinitial investments should focus where the highest returnon investment (dollars spent per tonne of carbon avoided) areachieved

Nuclear thermochemical cycles appear to be highly cost-effective mitigation options but the political landscape surroundingnuclear utilisation is regionally varied and severely restricted due toa lack of public approval and political creativity Additionallythe supporting data lacks depth and transparency and shouldbe considered speculative at best Further work is neededto demonstrate thermochemical cycle efficiencies and costat-scale For hydrogen without fossil fuels low-cost nuclear isrequired to minimize cost This therefore remains an importantresearch priority

Biomass gasification offers a very high decarbonizationpotential (B80 without CCS compared to SMR withoutCCS) and is one of the few routes to potentially achieve negativeemissions at relatively low cost This may become importantin the second half of this century as the drive to deeplydecarbonize further increases But despite this it may continueto represent a small contribution to hydrogen productiondue to limited resource availability relatively low conversionefficiencies and competition for agricultural land required forany substantial market penetration The relative paucity ofstudies quantifying costs and emissions remains a challengefor future research to better quantify all parameters relating tobiomass gasification in particular the costs and emissionswhen coupled with CCS


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Conflicts of interest

There are no conflicts of interest to declare

Acknowledgements

Brett Parkinson would like to thank the generous support of theGeneral Sir John Monash Foundation Funding for the Sustain-able Gas Institute is gratefully received from Royal Dutch ShellEnagas SA and from the NewtonNERCFAPESP Sustainable GasFutures project NEN0186561 Note that funding bodies werenot involved in the implementation or reporting of this study

References

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2008 33 6804ndash68393 G Simbollotti IEA Energy Technology Essentials-Hydrogen

Production and Distribution 20174 A Konieczny K Mondal T Wiltowski and P Dydo Int

J Hydrogen Energy 2008 33 264ndash2725 A H Fakeeha A A Ibrahim W U Khan K Seshan

R L Al Otaibi and A S Al-Fatesh Arabian J Chem 201811 405ndash414

6 U P M Ashik W M A Wan Daud and H F AbbasRenewable Sustainable Energy Rev 2015 44 221ndash256

7 M Granovskii I Dincer and M A Rosen J Power Sources2006 157 411ndash421

8 N Muradov Int J Hydrogen Energy 2017 42 14058ndash140889 N Muradov and T Veziroglu Int J Hydrogen Energy 2005

30 225ndash23710 L Weger A Abanades and T Butler Int J Hydrogen

Energy 2017 42 720ndash73111 B C R Ewan and R W K Allen Int J Hydrogen Energy

2005 30 809ndash81912 C Acar and I Dincer Int J Hydrogen Energy 2014 39 1ndash1213 I Dincer and C Acar Int J Hydrogen Energy 2015 40

11094ndash1111114 O Machhammer A Bode and W Hormuth Chem Eng

Technol 2016 39 1185ndash119315 J Speirs P Balcombe E Johnson J Martin N Brandon

and A Hawkes Energy Policy 2018 118 291ndash29716 A Haryanto S Fernando N Murali and S Adhikari

Energy Fuels 2005 19 2098ndash210617 J W Ager M R Shaner K A Walczak I D Sharp and

S Ardo Energy Environ Sci 2015 8 2811ndash282418 J R McKone N S Lewis and H B Gray Chem Mater

2014 26 407ndash41419 N Z Muradov and T N Veziroglu Carbon-neutral fuels and

energy carriers CRC Press 201120 The Royal Society Options for producing low-carbon hydrogen

at scale Report DES4801_2 The Royal Society 201821 B Parkinson M Tabatabaei D C Upham B Ballinger

C Greig S Smart and E McFarland Int J HydrogenEnergy 2018 43 2540ndash2555

22 National Research Council The hydrogen economy oppor-tunities costs barriers and RampD needs Report 0309091632National Academies Press 2004

23 D Gray and G Tomlinson Mitretek Technical Paper MTR2002 31 2002

24 F Mueller-Langer E Tzimas M Kaltschmitt and S PetevesInt J Hydrogen Energy 2007 32 3797ndash3810

25 S Penner Energy 2006 31 33ndash4326 A H Stroslashmman and E Hertwich Hybrid life cycle assess-

ment of large-scale hydrogen production facilities 200427 J Ruether M Ramezan and E Grol Life-cycle analysis of

greenhouse gas emissions for hydrogen fuel production in theUnited States from LNG and coal DOENETL-20061227November 2005

28 R Bhandari C A Trudewind and P Zapp J Cleaner Prod2014 85 151ndash163

29 J Lane and P Spath Technoeconomic analysis of the ther-mocatalytic decomposition of natural gas National Renew-able Energy Lab Golden CO (US) 2001

30 E Cetinkaya I Dincer and G F Naterer Int J HydrogenEnergy 2012 37 2071ndash2080

31 C Koroneos A Dompros G Roumbas and N MoussiopoulosInt J Hydrogen Energy 2004 29 1443ndash1450

32 D Sadler H21 Leeds City Gate Report Northern Gas Net-works 2016

33 J Dufour D P Serrano J L Galvez A Gonzalez E Soriaand J L Fierro Int J Hydrogen Energy 2012 37 1173ndash1183

34 L Tock and F Marechal Int J Hydrogen Energy 2012 3711785ndash11795

35 J Dufour D P Serrano J L Galvez J Moreno andC Garcıa Int J Hydrogen Energy 2009 34 1370ndash1376

36 M Melania Current central hydrogen production fromnatural gas without CO2 sequestration version 3101

37 G Collodi and F Wheeler Chem Eng Trans 2010 1937ndash42

38 G Collodi G Azzaro N Ferrari and S Santos EnergyProcedia 2017 114 2690ndash2712

39 P Balcombe J Speirs E Johnson J Martin N Brandonand A Hawkes Renewable Sustainable Energy Rev 201891 1077ndash1088

40 R Kothari D Buddhi and R L Sawhney RenewableSustainable Energy Rev 2008 12 553ndash563

41 N V S N M Konda N Shah and N P Brandon IntJ Hydrogen Energy 2011 36 4619ndash4635

42 C E G Padro and V Putsche Survey of the economics ofhydrogen technologies National Renewable Energy LabGolden CO (US) 1999

43 Royal Belgian Academy Council of Applied Science Hydrogenas an energy carrier 2006

44 P Chiesa S Consonni T Kreutz and R Williams IntJ Hydrogen Energy 2005 30 747ndash767

45 P Burmistrz T Chmielniak L Czepirski and M Gazda-Grzywacz J Cleaner Prod 2016 139 858ndash865

46 A Verma and A Kumar Appl Energy 2015 147 556ndash56847 E S Rubin J E Davison and H J Herzog Int J Greenhouse

Gas Control 2015 40 378ndash400


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48 IEAGHG Co-production of hydrogen and electricity by coalgasification with CO2 capturendashupdated economic analysis 2008

49 P Nikolaidis and A Poullikkas Renewable SustainableEnergy Rev 2017 67 597ndash611

50 GoGreenGas BioSNG Demonstration Plant Project Close-Down Report 2017

51 T L Group Green Hydrogen from Biomass httpswwwlinde-engineeringcomeninnovationsgreen_hydrogen_from_biomassindexhtml accessed April 2018

52 J D Holladay J Hu D L King and Y Wang Catal Today2009 139 244ndash260

53 D Wang S Czernik D Montane M Mann and E ChornetInd Eng Chem Res 1997 36 1507ndash1518

54 J R Bartels M B Pate and N K Olson Int J HydrogenEnergy 2010 35 8371ndash8384

55 J Yao M Kraussler F Benedikt and H Hofbauer EnergyConvers Manage 2017 145 278ndash292

56 A Mehmeti A Angelis-Dimakis G Arampatzis S J McPhailand S Ulgiati Environments 2018 5 24

57 A Valente D Iribarren and J Dufour Int J Life CycleAssess 2017 22 346ndash363

58 M Martın-Gamboa D Iribarren A Susmozas andJ Dufour Bioresour Technol 2016 214 376ndash385

59 A Susmozas D Iribarren and J Dufour Int J HydrogenEnergy 2013 38 9961ndash9972

60 Y Kalinci A Hepbasli and I Dincer Int J HydrogenEnergy 2012 37 14026ndash14039

61 J Moreno and J Dufour Int J Hydrogen Energy 2013 387616ndash7622

62 D Iribarren A Susmozas F Petrakopoulou and J DufourJ Cleaner Prod 2014 69 165ndash175

63 A Susmozas D Iribarren P Zapp J Linben and J DufourInt J Hydrogen Energy 2016 41 19484ndash19491

64 D Mahajan C E Taylor and G A Mansoori J Pet SciEng 2007 56 DOENETL-IR-2007-089

65 A M Amin E Croiset and W Epling Int J HydrogenEnergy 2011 36 2904ndash2935

66 R A Dagle V Dagle M D Bearden J D HolladayT R Krause and S Ahmed An Overview of Natural GasConversion Technologies for Co-Production of Hydrogen andValue-Added Solid Carbon Products Pacific NorthwestNational Lab (PNNL) Richland WA (United States) ArgonneNational Lab (ANL) Argonne IL (United States) 2017

67 N Shah D Panjala and G P Huffman Energy Fuels 200115 1528ndash1534

68 M Steinberg Int J Hydrogen Energy 1999 24 771ndash77769 N Z Muradov Energy Fuels 1998 12 41ndash4870 B Parkinson J W Matthews T B McConnaughy D C Upham

and E W McFarland Chem Eng Technol 2017 40 1022ndash103071 S Postels A Abanades N von der Assen R K Rathnam

S Stuckrad and A Bardow Int J Hydrogen Energy 201641 23204ndash23212

72 S M Saba M Muller M Robinius and D Stolten IntJ Hydrogen Energy 2017 43 1209ndash1223

73 Zero Emissions Platform The Costs of CO2-Storage ndash Post-Demonstration CCS in the EU 2011

74 K E Ayers C Capuano and E B Anderson ECS Trans2012 41 15ndash22

75 G R Saur B James and W Colella Hydrogen and fuelcells program production case studies

76 J C Koj A Schreiber P Zapp and P Marcuello EnergyProcedia 2015 75 2871ndash2877

77 M Fischer M Faltenbacher and O Schuller Life CycleImpact Assessment ECTOS 2005

78 K R Schultz M B Gorensek J Stephen M A L HerringR Moore J E OrsquoBrien P S Pickard B E Russ and W ASummers Carbon-Neutral Fuels Energy Carriers 2011 203

79 L Brown J Funk and S Showalter Initial screening of thermo-chemical water-splitting cycles for high efficiency generation ofhydrogen fuels using nuclear power General Atomics San DiegoCA (US) University of Kentucky Lexington KY (US) SandiaNational Labs Albuquerque NM (US) 1999

80 M T Balta I Dincer and A Hepbasli Int J HydrogenEnergy 2009 34 2925ndash2939

81 L C Brown G E Besenbruch R Lentsch K R SchultzJ Funk P Pickard A Marshall and S Showalter Highefficiency generation of hydrogen fuels using nuclear powerGENERAL ATOMICS (US) 2003

82 Z L Wang G F Naterer K S Gabriel R Gravelsins andV N Daggupati Int J Hydrogen Energy 2010 35 4820ndash4830

83 A Ozbilen I Dincer and M A Rosen Int J HydrogenEnergy 2011 36 11321ndash11327

84 M R Allen V R Barros J Broome W Cramer R ChristJ A Church L Clarke Q Dahe P Dasgupta and N K DubashIPCC fifth assessment synthesis report 2014

85 IEA World Energy Outlook 2017 201786 C Munnings and A Krupnick Comparing Policies to Reduce

Methane Emissions in the Natural Gas Sector 201787 J P Marshall Energy Policy 2016 99 288ndash29888 A B Rao and E S Rubin Ind Eng Chem Res 2006 45

2421ndash242989 A J Hunt E H Sin R Marriott and J H Clark ChemSusChem

2010 3 306ndash32290 T S Chung D Patino-Echeverri and T L Johnson Energy

Policy 2011 39 5609ndash562091 R Bell The Production of Low Carbon GasndashConsultation

Response SCCS response to the Carbon Connect consultationon the production of low carbon gas 2018

92 M Bui C S Adjiman A Bardow E J Anthony A BostonS Brown P S Fennell S Fuss A Galindo and L A HackettEnergy Environ Sci 2018 11 1062ndash1176

93 IEAGHG Enabling the deployment of industrial CCS clusters2018

94 Global CCS Institute The Global Status of CCS SpecialReport Understanding the Industrial CCS Hubs and ClustersMelbourne Australia 2016

95 i24c Deployment of an industrial carbon capture and storagecluster in Europe A funding pathway Cambridge UK2017

96 I Enting D Etheridge and M J Fielding Int J GreenhouseGas Control 2008 2 289ndash296

97 P M Haugan and F Joos Geophys Res Lett 2004 31 L18202


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98 C R Jenkins P J Cook J Ennis-King J UndershultzC Boreham T Dance P de Caritat D M EtheridgeB M Freifeld and A Hortle Proc Natl Acad Sci U S A2012 109 E35ndashE41

99 J Banks and C A T Force Clean Air Task Force 2012100 US EPA Coal Mine Methane (CMM) Finance Guide 2009101 H Yang Z Xu M Fan R Gupta R B Slimane A E Bland

and I Wright J Environ Sci 2008 20 14ndash27102 N Muradov Catal Commun 2001 2 89ndash94103 N Muradov Thermocatalytic CO2-free production of

hydrogen from hydrocarbon fuels 2000104 G Kreysa ChemSusChem 2009 2 49ndash55105 T Keipi H Tolvanen and J Konttinen Energy Convers

Manage 2018 159 264ndash273106 T Abbasi and S Abbasi Renewable Sustainable Energy Rev

2011 15 1828ndash1834107 M-S Liao and Q-E Zhang J Mol Catal A Chem 1998

136 185ndash194108 R Aiello J E Fiscus H-C Zur Loye and M D Amiridis

Appl Catal A 2000 192 227ndash234109 P Tang Q Zhu Z Wu and D Ma Energy Environ Sci

2014 7 2580ndash2591110 T Geiszligler A Abanades A Heinzel K Mehravaran

G Muller R Rathnam C Rubbia D Salmieri L Stoppeland S Stuckrad Chem Eng J 2016 299 192ndash200

111 M D Eisaman J L B Rivest S D Karnitz C-F deLannoy A Jose R W DeVaul and K Hannun IntJ Greenhouse Gas Control 2018 70 254ndash261

112 R Socolow M Desmond R Aines J Blackstock O BollandT Kaarsberg N Lewis M Mazzotti A Pfeffer and K SawyerDirect air capture of CO2 with chemicals a technologyassessment for the APS Panel on Public Affairs AmericanPhysical Society 2011

113 World Energy Council World Energy Resources WorldEnergy Council London UK 2016

114 UK Government International Industrial Energy Prices(httpswwwgovukgovernmentstatistical-data-setsinter-national-industrial-energy-prices)

115 European Environment Agency Electricity Generation ndashCO2 emissions intensity (httpswwweeaeuropaeudata-and-mapsdavizco2-emission-intensity-3tab-googlechartid_

chart_11_filters=7BlsquolsquorowFiltersrsquorsquo3A7B7D3Blsquolsquocolumn-Filtersrsquorsquo3A7Blsquolsquopre_config_ugeorsquorsquo3A5BlsquolsquoEuropean20Union20(2820countries)rsquorsquo5D7D7D 2018)

116 E Lantz M Hand and R Wiser Past and Future Cost of WindEnergy Preprint National Renewable Energy Laboratory(NREL) Golden CO 2012

117 S Almosni A Delamarre Z Jehl D Suchet L CojocaruM Giteau B Behaghel A Julian C Ibrahim and L TatrySci Technol Adv Mater 2018 19 336ndash369

118 M R Shaner H A Atwater N S Lewis and E W McFarlandEnergy Environ Sci 2016 9 2354ndash2371

119 IRENA Renewable Power Generation Costs in 2017International Renewable Energy Agency Abu Dhabi 2018

120 G F Hewitt and J G Collier Introduction to nuclear powerCRC Press 2000

121 N Sakaba H Sato H Ohashi T Nishihara and K KunitomiJ Nucl Sci Technol 2008 45 962ndash969

122 J Norman G Besenbruch L Brown D Orsquokeefe andC Allen Thermochemical water-splitting cycle bench-scaleinvestigations and process engineering Final report February1977-December 31 1981 GA Technologies Inc San DiegoCA (USA) 1982

123 L Brecher S Spewock and C Warde Int J HydrogenEnergy 1977 2 7ndash15

124 N E Hultman J G Koomey and D M Kammen EnvironSci Technol 2007 2087ndash2094

125 J R Lovering A Yip and T Nordhaus Energy Policy 201691 371ndash382

126 P E Dodds and W McDowall UCL Energy InstituteUniversity College London 2012

127 US DOE Book US Billion-Ton Update Biomass Supply for aBioenergy and Bioproducts Industry 2011

128 IEAGHG CO2 Capture at coal based power and hydrogenplants Report 20143 Cheltenham UK 2014

129 S Fuss J G Canadell G P Peters M Tavoni R M AndrewP Ciais R B Jackson C D Jones F Kraxner N NakicenovicC Le Quere M R Raupach A Sharifi P Smith andY Yamagata Nat Clim Change 2014 4 850ndash853

130 V S Sikarwar M Zhao P Clough J Yao X Zhong M ZMemon N Shah E J Anthony and P S Fennell EnergyEnviron Sci 2016 9 2939ndash2977


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given its lack of direct CO2 emissions and suitability across energyservices and chemicals production2 Globally approximately 60 Mtof hydrogen is produced annually3 for the production of nitrogen-based fertilizers (49 of global H2 production) hydro-treatment inpetroleum refining (37) methanol (8) and other smallermarkets (6) including for use in stationary fuel cells and fuel cellvehicles4ndash6 However 96 of hydrogen is produced by technologiesinvolving the reforming of fossil fuel feedstocks resulting in highCO2 emissions (natural gas contributes 49 liquid hydrocarbons29 and coal 18)5 The remaining 4 is produced by electro-lysis technologies which are only low-carbon if powered by low-carbon electricity and embodied emissions of the generationtechnologies are also low7 Due to low regional gas and coal pricesand high resource availability hydrogen production in the short-to-medium term is likely to continue to rely heavily on fossil fuels8

There are many options to produce low-carbon hydrogen buteach option exhibits different levels of decarbonization whilstthere are also many barriers to production through alternativeroutes not least scale and costs9 The challenge of transitioningto more sustainable hydrogen production routes will requirefocus on the highest return on investment to minimise the costof decarbonization10 However both life cycle emissions andcosts may be highly variable and these estimates are poorlybounded within current studies

Numerous studies have investigated the merits of alternativeH2 production technologies through comparative assessmentsor overall metrics Ewan et al11 developed an overall Figure ofMerit (FOM) assessment which evaluated 14 different hydrogentechnologies on CO2 emissions intensity power density landuse and cost A clear division between low energy densityrenewable technologies and those associated with high energydensities was shown with a significantly higher FOM for thelater grouping11 Acar et al12 compared 8 different hydrogenproduction technologies for environmental impact cost andexergy efficiencies Their study used a social cost of carbon toapply economic consequences to carbon externalities to investigatethe relationship between environmental and economic factorsThis study was further extended by Dincer et al13 comparing 19different hydrogen production methods using renewable and non-renewable sources for environmental impact cost energy andexergy efficiencies The study found hybrid nuclear thermochemi-cal cycles to be the most promising candidate to produce hydrogenwith low environmental and cost impacts13 Machhammer et al14

compared two conventional technologies coal gasification andSMR with four emerging technologies metal-oxide cycles waterelectrolysis biomass gasification and methane pyrolysis on costand carbon footprint The lsquoeconologicalrsquo result yielded methanepyrolysis to be the most promising technology for low-cost and lowcarbon footprint hydrogen14 Speirs et al15 assessed the evidenceof costs and greenhouse gas (GHG) emissions of 9 hydrogenproduction routes and found that supply chain emissions associatedwith supposedly low carbon routes were non-negligible and highlyvariable across regions processes and estimation assumptions

Of the different frameworks presented in the literature forcomparing hydrogen production technologies none have directlycompared the total costs of production to CO2 emissions from a

life cycle perspective for evaluating costs of CO2 mitigation whilstmany include only a subset of available feedstocks and productionroutes Additionally none of the comparison studies includerobust ranges of both variations in cost and emissions dataavailable in the literature Therefore the goal of this study is toidentify the most cost-effective technologies for reducing thecarbon intensity of hydrogen production in terms of cost pertonne of carbon dioxide emitted ($ t1 CO2e) by conducting adetailed engineering environmental and cost assessment of afull suite of hydrogen production routes and feedstocks Keyparameters for each hydrogen supply chain are quantitativelyassessed to develop robust ranges of emissions and costs aswell as providing insight into the best opportunities for carbonreductions This output is used to estimate the levelized cost ofemissions mitigation and the degree of decarbonisation achievableto provide critical guidance on future resource allocation prioritiesand trajectory for hydrogen development pathways The technicaland financial hurdles to implementation are discussed andrecommendations for future resource allocation are made Thisstudy is the first comprehensive combined supply chain and pointsource assessment of carbon mitigation costs for the breadthof hydrogen production processes and feedstocks consideredIt aims to serve as a valuable source of data and discussionfor engineers academics and policy makers alike to providea clearer picture of the relative decarbonization merits ofhydrogen production pathways

This study focusses on technologies capable of large-scaleproduction commensurate with current hydrogen demandsTechnologies for hydrogen production fall into four categories(i) thermochemical (ii) electrochemical (iii) photo-biologicaland (iv) photo-electrochemical16 However photo-biologicaland photo-electrochemical methods are not discussed here asthese technologies are currently limited by relatively slowproduction rates early stages of commercial development and arange of technical issues to overcome before practical applicationscan be considered (see ref 17 and 18 for further information) Thetechnologies considered are shown in Table 1 The substitution ofa hydrogen production technology with a less CO2-intensivetechnology assumes it is capable of meeting the hypotheticalscale and load profile required It should also be noted thevarying stages of technological readiness of each of the path-ways considered in this analysis Other natural gas reformingroutes such as auto-thermal reforming and partial oxidationhave not been considered here Whilst these technologieshave different processing steps and reaction pathways resultingin different costs and emissions they ultimately representreforming of natural gas A more detailed comparison of thehydrogen production pathways from natural gas is the subjectof future work

2 Methodology

To achieve the above aims the study is carried out in five steps(1) A review of recent literature for hydrogen production

costs and life cycle emissions


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Environmental Gain


$ per t H2eth THORN



(1)









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CH4 + 2H2O 2 CO2 + 4H2 DH 0 = 165 kJ mol1

DG0 = 114 kJ mol1 (2)




($ GJ1) + 01123 (3)


($ GJ1) + 015 (4)

















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DG0 = 63 kJ mol1 (5)


3 h124




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077 (6)



90

















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(8)






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H2O1


(9)










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085 (10)












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1

2O2ethgTHORN (16)















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Technology




Coal w CCSb 078 18 52 109327e 21162e 5521035e




Technology







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5 Conclusions




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Acknowledgements


References
















































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Environmental Gain


$ per t H2eth THORN



(1)









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CH4 + 2H2O 2 CO2 + 4H2 DH 0 = 165 kJ mol1

DG0 = 114 kJ mol1 (2)




($ GJ1) + 01123 (3)


($ GJ1) + 015 (4)

















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DG0 = 63 kJ mol1 (5)


3 h124




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077 (6)



90

















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(8)






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H2O1


(9)










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085 (10)












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1

2O2ethgTHORN (16)















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Technology




Coal w CCSb 078 18 52 109327e 21162e 5521035e




Technology







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5 Conclusions




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Acknowledgements


References
















































Publ

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CH4 + 2H2O 2 CO2 + 4H2 DH 0 = 165 kJ mol1

DG0 = 114 kJ mol1 (2)




($ GJ1) + 01123 (3)


($ GJ1) + 015 (4)

















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DG0 = 63 kJ mol1 (5)


3 h124




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077 (6)



90

















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(8)






Publ

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H2O1


(9)










Publ

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085 (10)












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1

2O2ethgTHORN (16)















Publ

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Technology




Coal w CCSb 078 18 52 109327e 21162e 5521035e




Technology







Publ

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Publ

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Publ

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Publ

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Publ

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Publ

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Publ

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5 Conclusions




Publ

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Publ

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Acknowledgements


References
















































Publ

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Publ

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Publ

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DG0 = 63 kJ mol1 (5)


3 h124




Publ

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077 (6)



90

















Publ

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d on

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(8)






Publ

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H2O1


(9)










Publ

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085 (10)












Publ

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17

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ge L

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1

2O2ethgTHORN (16)















Publ

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d on

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d by

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n L

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Technology




Coal w CCSb 078 18 52 109327e 21162e 5521035e




Technology







Publ

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d on

17

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Publ

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d on

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Publ

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Publ

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Publ

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Publ

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Publ

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5 Conclusions




Publ

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Publ

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Acknowledgements


References
















































Publ

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d on

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Publ

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Publ

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077 (6)



90

















Publ

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d on

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(8)






Publ

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d on

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H2O1


(9)










Publ

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d on

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085 (10)












Publ

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ge L

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1

2O2ethgTHORN (16)















Publ

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d on

17

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n L

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Technology




Coal w CCSb 078 18 52 109327e 21162e 5521035e




Technology







Publ

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d on

17

Nov

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Publ

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d on

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Publ

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Publ

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Publ

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Publ

ishe

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Publ

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d on

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5 Conclusions




Publ

ishe

d on

17

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Publ

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d on

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Acknowledgements


References
















































Publ

ishe

d on

17

Nov

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Publ

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Publ

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(8)






Publ

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17

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H2O1


(9)










Publ

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d on

17

Nov

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r 20

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d by

Im

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al C

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n L

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085 (10)












Publ

ishe

d on

17

Nov

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r 20

18 D

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d by

Im

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ge L

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n L

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1

2O2ethgTHORN (16)















Publ

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d on

17

Nov

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d by

Im

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al C

olle

ge L

ondo

n L

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Publ

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Publ

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5 Conclusions




Publ

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Publ

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Acknowledgements


References
















































Publ

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Publ

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Publ

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H2O1


(9)










Publ

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085 (10)












Publ

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1

2O2ethgTHORN (16)















Publ

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Technology




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Technology







Publ

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Publ

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Publ

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Publ

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Publ

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Publ

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Publ

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5 Conclusions




Publ

ishe

d on

17

Nov

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Publ

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Acknowledgements


References
















































Publ

ishe

d on

17

Nov

embe

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Publ

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Publ

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Nov

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085 (10)












Publ

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17

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1

2O2ethgTHORN (16)















Publ

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17

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Technology




Coal w CCSb 078 18 52 109327e 21162e 5521035e




Technology







Publ

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Nov

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Publ

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Publ

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Publ

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Publ

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Publ

ishe

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Publ

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d on

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5 Conclusions




Publ

ishe

d on

17

Nov

embe

r 20

18 D

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d by

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al C

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ge L

ondo

n L

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n 12

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Publ

ishe

d on

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Nov

embe

r 20

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d by

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n L

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n 12

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Acknowledgements


References
















































Publ

ishe

d on

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Nov

embe

r 20

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Publ

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Publ

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1

2O2ethgTHORN (16)















Publ

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17

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d by

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ondo

n L

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152

24

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Technology




Coal w CCSb 078 18 52 109327e 21162e 5521035e




Technology







Publ

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Nov

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Publ

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Publ

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Publ

ishe

d on

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Publ

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d on

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Publ

ishe

d on

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Publ

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d on

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5 Conclusions




Publ

ishe

d on

17

Nov

embe

r 20

18 D

ownl

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d by

Im

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al C

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ge L

ondo

n L

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n 12

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Publ

ishe

d on

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r 20

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Acknowledgements


References
















































Publ

ishe

d on

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Nov

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Publ

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Publ

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n L

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n 12

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Technology




Coal w CCSb 078 18 52 109327e 21162e 5521035e




Technology







Publ

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Publ

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Publ

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Publ

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Publ

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d on

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Publ

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d on

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Publ

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d on

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Nov

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5 Conclusions




Publ

ishe

d on

17

Nov

embe

r 20

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d by

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Publ

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d on

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ge L

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n L

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n 12

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Acknowledgements


References
















































Publ

ishe

d on

17

Nov

embe

r 20

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d by

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Publ

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d on

17

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n L

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Publ

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d on

17

Nov

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r 20

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Publ

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d on

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Publ

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Publ

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Publ

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Publ

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d on

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Publ

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5 Conclusions




Publ

ishe

d on

17

Nov

embe

r 20

18 D

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d by

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ge L

ondo

n L

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n 12

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Publ

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d on

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Nov

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r 20

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d by

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n L

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Acknowledgements


References
















































Publ

ishe

d on

17

Nov

embe

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Publ

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d on

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d by

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Publ

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d on

17

Nov

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n L

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Publ

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d on

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Nov

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n L

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5 Conclusions




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Publ

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Publ

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Publ

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Publ

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Publ

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5 Conclusions




Publ

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Publ

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Acknowledgements


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Publ

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Publ

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Publ

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Publ

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Publ

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Publ

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5 Conclusions




Publ

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Publ

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Acknowledgements


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Publ

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Publ

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Publ

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Publ

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Publ

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5 Conclusions




Publ

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Publ

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Acknowledgements


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Publ

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Publ

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Publ

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Publ

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5 Conclusions




Publ

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Publ

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Acknowledgements


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Publ

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Publ

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Publ

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5 Conclusions




Publ

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Publ

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Acknowledgements


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Publ

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Publ

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Publ

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Publ

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Publ

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Publ

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