Bio-SNG - CNG Services

Bio-SNGFeasibility Study.Establishment of aRegional ProjectProgressive Energy &CNG ServicesClients: NEPICNational GridCentricaDate: 10/11/10Issue: Vs 2.3

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTDocument Control RecordDocument Title:Final ReportIssue 2.3Date Issue: 10/11/10Project Title:Bio-SNG: Feasibility Study, Establishment of a Regional ProjectPrepared by:Phillip Cozens & Chris Manson-WhittonClientsNEPIC, National Grid and CentricaAmendment RecordIssue Date of Issue Notes0.1 29/09/10 Executive summary for comment1.0 25/10/10 Internal review2.0 28/10/10 Issued2.1 29/10/10 Minor adjustments2.2 01/11/10 Adjustment to Footers2.3 10/11/10 Minor corrections following feedbackBecause this work includes for the assessment of a number of phenomena which are unquantifiable, thejudgements drawn in the report are offered as informed opinion. Accordingly Progressive Energy Ltd.gives no undertaking or warrantee with respect to any losses or liabilities incurred by the use ofinformation contained therein.2

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTContents1 Executive Summary ...............................................................................................................................42 Introduction .......................................................................................................................................... 143 Review of the fiscal, legislative and regulatory regime ....................................................................... 163.1 Renewable Energy Incentives and Instruments ......................................................................... 163.2 Energy from Waste regulations and Issues ................................................................................ 183.3 Emissions Trading ...................................................................................................................... 193.4 The Gas Safety Management Regulations ................................................................................ 203.5 Other key regulations ................................................................................................................. 204 Feedstock ............................................................................................................................................ 214.1 The significance of Bio-SNG in the energy scene ...................................................................... 214.2 „Pure‟ Biomass resources ........................................................................................................... 224.3 Properties of „pure‟ biomass fuels .............................................................................................. 244.4 Waste materials .......................................................................................................................... 254.5 Total amount of Biomass resource for Bio-SNG production ...................................................... 284.6 Commercial considerations for „pure‟ biomass ........................................................................... 284.7 Commercial considerations for wastes ....................................................................................... 294.8 Feedstock Conclusions .............................................................................................................. 315 Process and Technology Review ........................................................................................................ 325.1 Biomass reception, preparation and handling. ........................................................................... 325.2 Gasification ................................................................................................................................. 335.3 Gas Processing .......................................................................................................................... 395.4 Methanation ................................................................................................................................ 415.5 Gas conditioning, compression and metering ............................................................................ 425.6 Conclusions on Process and Technology .................................................................................. 436 Economic Assessment ........................................................................................................................ 446.1.1 Scale and operational assumptions........................................................................................ 446.1.2 Investment Cost assumptions ................................................................................................ 456.1.3 Operating Cost assumptions .................................................................................................. 486.1.4 Feedstock ............................................................................................................................... 486.1.5 Revenue Assumptions ............................................................................................................ 506.2 Levelised Cost analysis .............................................................................................................. 506.3 Sensitivity Analysis ..................................................................................................................... 546.3.1 Escalation ............................................................................................................................... 556.3.2 Impact of capital Cost, Opex, Fuel price, RHI and heat sales ................................................ 566.3.3 Comparison with an SRF fuelled electricity project ................................................................ 576.4 Financial conclusions ................................................................................................................. 587 Lifecycle carbon emissions and Cost of Carbon Analyses compared with alternatives ..................... 607.1 Lifecycle carbon emissions ......................................................................................................... 607.2 Cost of carbon abatement via Bio-SNG ..................................................................................... 648 Risk Assessment and Financing Considerations ................................................................................ 698.1 Conclusions from risk assessment and financing considerations .............................................. 749 Preliminary Scoping of a lead, beacon project .................................................................................... 759.1 Beacon Project configuration options ......................................................................................... 759.2 Location: The North East ............................................................................................................ 779.3 Site analysis................................................................................................................................ 789.4 Regional Feedstock .................................................................................................................... 8310 Conclusions ......................................................................................................................................... 843

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT1 Executive SummaryMethane is an attractive heat and transport fuel vector. It is a clean and relatively low carbon intensityfuel. It can be utilised efficiently and has established infrastructure and demand-side technologies (gasboilers for heating and an increasingly wide range of available CNG vehicles). The UK has one of themost extensive gas networks in the world. Bio-methane retains all the attributes of natural gas, with thecrucial advantage that the fuel is renewable, offering substantial Carbon Dioxide savings. Few otherrenewable vectors are as fungible, with so few demand-side constraints. Biomethane can, and is beingproduced via the upgrading of biogas from Anaerobic Digestion. However, in order to achieve a stepchange in production capacity, alternative approaches such as via thermal routes (termed „Bio-SNG‟) arenecessary. Whilst technically feasible, this approach is less mature than anaerobic digestion. Transitionfrom aspiration, to widespread operating facilities and infrastructure requires a detailed understanding ofthe technical and commercial attributes of the full chain from feedstock supply through to delivery of gridquality gas, as well as the development of the first crucial operating facility which provides the tangibleproof of concept for roll out. The chemical and processing industrial heritage in the North East, its naturalgas and services infrastructure and its track record of innovation make it an attractive region to locatesuch a project.This report provides a critical appraisal of the opportunity afforded by Bio-SNG, building on a review ofthe issues associated with biomass sourcing, a detailed analysis of the technology options andapplicability for injection into the UK grid, as well as a financial appraisal. It draws on benchmarking datato demonstrate the full lifecycle carbon dioxide savings and also demonstrates that the Bio-SNG route isa very cost effective route for decarbonisation compared with other renewables. It provides proposals forimplementation pathways, specifically how a Bio-SNG demonstration could be established in the NorthEast.Regulatory PositionImplementation of Bio-SNG will only take place with the appropriate tax, incentive and legislativeenvironment. Therefore it is critically important to establish the position that is pertinent to Bio-SNGproduction on its own account, but also in comparison with the situation for other competitive users ofbiogenic energy resources. The Renewable Obligation is most established instrument in the UK toincentivise the use of biogenic resource, in this case for provision of electricity. In order to facilitateexpansion of renewable heat and Bio-SNG in particular, the forthcoming Renewable Heat Incentive mustbe structured such that such projects are commercially attractive compared with electricity production.In addition to the incentives structures, the regulatory environment must be clear and appropriate,particularly with regard to: requirements for gas injection, emissions directives, and how the use of wasteas a feedstock is treated.4

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFeedstockIn contemplating the use of biomass for the production of Bio-SNG it must be appreciated that there arecompeting uses for biomass in many industrial sectors – building materials, chemicals, heating, electricitygeneration, and transport bio-fuels. Estimates vary widely on the potential for the production and tradingof biomass fuels but government incentives for non-fossil energy are fuelling a growing demand, globally.Global capacity for the production of bio-fuels has been estimated at 180EJ 1 per annum a figure which isonly 18 times the UK total energy consumption of 10EJ/annum. The estimates of potential indigenousbiomass production vary, but range up to a figure of 60PJ/a 2 of conventional woodfuels, and in the futurea further 60PJ, or more from energy crops 3 . The UK waste streams also represent a considerablepotential biomass resource of the order of 300PJ. The UK gas consumption is around 4EJ per annum ofwhich approximately 30% is associated with domestic heating. Combinations of imported and indigenousbiomass together with waste-derived materials have the potential, therefore to make a significantcontribution to the overall domestic heating gas load.Major users of biomass fuels are making strategic moves upstream in the biomass supply chain to securepositions that will support the long term viability of their power sector investments. It follows thatinvestment in Bio-SNG facilities will undoubtedly require similar initiatives by their owners or developers.In evaluating the merit of investment in biomass power it is important to take into account the globalmarket influence created by a variety of government backed incentive schemes that promote biomasspower plant developments throughout the world.From a technical perspective biomass fuels are generally less well understood than coal, and thetechnologies that use biomass fuels are less well developed.Hence it is particularly important tounderstand the properties of candidate biomass fuels in undertaking process design and specification,especially with respect to fuel preparation and handling and gasifier operations. Standards do exist forsolid biofuels of all types, the EU has developed via CEN/335 a comprehensive approach to theclassification and standardisation of solid bio-fuels and this should be used in transactions between sellerand buyer and by process designers in order to assure reliable and certifiable operational conditions.Waste materials represent a significant bio-energy resource, however, it should not be assumed that theyare readily available for use in energy applications. Much of the UK waste stream is under long termdisposal contracts with local authorities, however, commercial and industrial wastes are unlikely to be onlong term disposal contracts and are, in principle a potential resource.As for clean biomass, it isnecessary to go upstream in the supply chain to secure reliable supplies of suitable materials.common with the standardisation of solid bio-fuels, similar standards and classifications exist under1 1 Exajoule = 10 18 Joules2 1 Petajoule = 10 15 Joules3 Some estimates consider 550PJ of energy crops per annum a possibility, although this would require seismicchange in land usage and appropriate commercial drivers.5In

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTCEN/343 for the production of Solid Recovered Fuels (SRF) which too can be used to facilitate tradebetween buyer and seller and to inform process design.In summary, it is likely that the development of Bio-SNG facilities will require the developer to goupstream into the supply chain for both grown and waste derived fuels, however, specification and qualitycontrol are vital determinants of project success.Process and technologyThe process technology review establishes that, in principle, the major process operations required toproduce Bio-SNG can be identified and assembled from existing technology suppliers. This does notmean that a Bio-SNG development would be free from technical risk, but it does mean that there is nofundamental process development required to create a viable Bio-SNG platform.The essential first condition that must be satisfied is that feedstock specification and the process designare matched; the gasifier in particular can not be omnivorous.From a wide range of possible gasifier types the review closes in on the choice of oxygen blown directbubbling fluidised bed, either pressurised or un-pressurised. The choice of bubbling fluidised bed isinformed by commercial analysis which shows the importance of waste-derived fuels. The fluidised bedis capable of accepting both pure biomass and waste derived fuels, in contrast to the alternative entrainedflow gasifiers. Indirect fluidised bed gasifiers give a significant and beneficial direct conversion tomethane in the gasifier, reducing therefore the process losses incurred in making SNG from synthesisgas, as well as the potential to operate using air and/or steam rather than oxygen as an oxidant.However, indirect gasifiers are less well developed and do risk the leakage of significant quantities ofnitrogen into the syngas, which in turn will reduce the CV and Wobbe index of the resulting SNG.Achievement of pipeline gas quality has been taken as an indispensable condition. The indirect gasifierscan give a level of methane in syngas in excess of 10%, however, for example, the High TemperatureWinkler direct fluidised bed can give in excess of 5% methane in syngas. This level of methane contentstill gives reasonable conversion efficiencies to Bio-SNG of at least 65%. In view of the relative immaturityof the technology and the risk of nitrogen migration the benefits of the indirect fluidised bed gasifiers areconsidered to be marginal. This viewpoint is further enhanced if the heat output from the plant isvalorised by the 2 ROC electricity regime or where possible as renewable heat under the RHI; withoptimisation of the process design, the associated electricity and potential heat sales are likely at least tocompensate for any small loss of conversion efficiency to Bio-SNG.Downstream of the gasifier the gas processing operations are conventional technology: heat recoveryand power generation, gas scrubbing, water gas shift, methanation, conditioning and compression. (Thewater gas shift reaction is required to adjust the molar ratios of carbon monoxide and hydrogen in thesyngas to the ideal conditions for methanation.) Whilst these processing elements are all conventional,6

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTthey are critical for ensuring pipeline quality gas. In general the GS(M)R specification should be attainableby this process route, although the tight limit on hydrogen content may demand a higher gas recyclethrough the methanation phase than would otherwise be required, and the stringent dewpointspecification imposes drying requirements in light of the high moisture from the methanation reactor.These investigations do not identify the optimised process configuration regarding energy consumption.There is a balance to be struck between gasifier operating pressure, gas train pressures andcompression loads and the power consumption for Bio-SNG export. This should be undertaken inconceptual design where more detailed information from equipment suppliers is required.Financial AnalysisTwo representative scales of facility are analysed at 50MWth and 300MWth input. These would produceapproximately 230GWh and 1400GWh of Bio-SNG per annum based on the assumed processefficiencies. This represents sufficient gas for approximately 15-100,000 households or 25,000-150,000passenger vehicles. Three of the larger facilities would supply 1% of the UK domestic gas market.Dependent on the fuel type these facilities would require between 75-100,000 te pa of feedstock at thesmall scale and 450-600,000 te pa at the large scale. With increasing scale, the challenges associatedwith contracting sufficient fuel for the duration of the financing period of a plant increase.The feedstock price is assumed to be £7/GJ for imported wood pellets, £5/GJ for a mix of imported andindigenous woodchip and -£1.50/GJ for processed Solid Recovered Fuel from mixed waste streams. Thewoodfuel prices are 2010 figures, based on biomass prices for large scale electrical generation plants,taken from the technical annexes issued by DECC in the February 2010 RHI review 4 . The waste fuelprice is based on industry knowledge of SRF produced by Mechanical Biological Treatment with abiogenic energy content of ~60%.Using the investment 5 and operational cost assumptions derived, the levelised cost of Bio-SNG in 2010prices has been shown to range between £67-£103/MWh for the small scale facility and £32-£73/MWh forthe large scale facility dependent on the type feedstock used, with the waste based fuel being thecheapest. Assuming the RHI at £40/MWh of biogenic fraction this equates to out turn gas prices of £43-£65/MWh at small scale and £8-£33/MWh at the large scale. In conventional gas units, this analysissuggests an out turn gas price of 123-185p/therm at small scale and at large scale 24, 63 and 96p/thermfor SRF, Woodchip and pellet feedstock respectively.4 “Biomass prices in the heat and electricity sectors in the UK”, Department of Energy and Climate Change(January 2010)5 £65-£75Million for the small facility and £215-£250Million for the large facility, depending on feedstock type.7

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTComparing these figures with a central case of 59p/therm gas (DECC 6 ‟) shows that with the proposedincentive regime, a large SRF fuelled facility has the potential to provide gas effectively, as could a facilityfuelled by a mix of SRF and biomass. At this scale, a mix of indigenously sourced woodchip and importedwoodchip might be competitive, but a facility fuelled by wood pellet is unlikely to be able to compete andwould need an increase of at least £15/MWh to the RHI to enable it to compete. At the smaller scale, Bio-SNG cannot be supplied competitively from any fuel. For a competitive demonstration facility at this scale,the RHI would need to be increased by a further ~£40/MWh, or else a capital grant of ~£40M would benecessary.For the large scale facility operating on woodchip, a sensitivity analysis indicates that a change in capitalcost of 30% equates to a change in outturn Bio-SNG price of 35%. A £1.5/GJ change in biomass price(30%) equates to nearly a 40% change in outturn Bio-SNG price. This implies for example that volatility ininternational biomass shipping costs alone could readily effect a change of £0.5/GJ (£6.5/te) on feedstockand therefore 13% on Bio-SNG price. This particular sensitivity to biomass price represents a major riskonwards for the life of the plant depending on the contracting basis. Conversely, whilst capital cost is animportant factor, the capital cost is fixed at financial close, so does not represent an ongoing risk to theproject.Looking to the future, gas prices will increase, but it is contended that biomass prices are likely toescalate broadly in line with raw energy costs due to both increased international demand for renewablefeedstocks, but also simply because of the displaced cost of energy (the only perturbation on this wouldbe a significant increase in the price of carbon, although natural gas is a relatively low carbon feedstock).In isolation this would result in a somewhat increased competitive position for Bio-SNG since the fuel costis only a component of the total levelised cost. However, the extent of this effect will be ameliorated byany increase in capital and operational costs over and above inflation due to both increases in energycosts per se, and also supply/demand pressure for renewable energy.A first of a kind, large scale Bio-SNG production facility from SRF is likely to be challenging to finance andrepresents a substantial quantum of investment, yet this analysis indicates that scale is necessary toprovide an acceptable cost base. Therefore an alternative pathway is likely to be necessary. One route isto find a more commercially attractive basis to develop a syngas platform, from which a slip stream of Bio-SNG production could be established.By comparison, a 50MWth gasification plant configured to produce 13MWe using an SRF feedstock andsupported by two ROCS under the RO is more likely to be viable. Because such a case is still predicatedon some of the fundamental technical principles necessary for Bio-SNG production, it does not provide aparticularly attractive return, but might be an alternative pathway to demonstrating Bio-SNG productionusing a slipstream from an otherwise commercially viable plant, therefore limiting the level of additional6 Energy and emissions projections, DECC (June 2010) Annex F8

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTsupport to demonstrate Bio-SNG production. At 300MWth, a gasification facility configured to generateelectricity is likely to be commercially preferable to one configured to produce Bio-SNG, unless theRenewable Heat Incentive is significantly higher than the £40/MWh proposed.Carbon savingsA full lifecycle analysis of Bio-SNG production undertaken by North Energy Associates 7 shows that formany types of feedstock, the lifecycle CO 2 e savings of Bio-SNG compared with fossil fuel alternatives aretypically ~90%. This saving is similar for both conventional heating and transport applications. The annualCO 2 e savings for three of the larger facilities operating on biomass is 1Mte of CO 2 e per annum if used todisplace natural gas heating, and slightly higher if it displaces conventional transport fuel. If Biogas wereto displace a third of the domestic natural gas consumption and bio-SNG represented two thirds of that,then the CO2e savings would be ~15Mte pa when fuelled by biomass.This analysis also demonstrates that the savings for the Bio-SNG production route are very similar tothose achieved using direct biomass heating. Given that the Bio-SNG solution has much lower demandsideconstraints and therefore could achieve greater market penetration, it is an attractive route.Cost of carbon abatedStrategically the UK needs to consider the most cost effective approach for decarbonising. An analysishas been undertaken which considers the cost of decarbonising, based on the current and proposedlevels of renewable support subsidy 8 considered to be adequate to achieve market penetration of theparticular technology.For heating applications using natural gas as a counterfactual, Bio-SNG offers a cost per tonne of CO 2 eabated of ~£175/te. This compares very favourably with direct biomass combustion for domesticapplications (£395/te), for small commercial applications (£285/te) but is somewhat more expensive thandirect biomass combustion for large scale commercial applications at ~£110/te. When using oil heating asthe counterfactual, the cost per tonne of CO 2 saved reduces significantly to £135/te for Bio-SNGcompared with £305, £220 and £85 for the three cases discussed above. However it must be noted thatthe appropriate counterfactual for Bio-SNG is natural gas, as the product can only be used where there isa gas grid and where oil use is unlikely.7 “Analysis of the Greenhouse Gas Emissions for Thermochemical BioSNG Production and Use in the UnitedKingdom” Project Code NNFCC 10-009 Study funded by DECC and managed by NNFCC, North Energy Associates(June 2010)8 In deriving the cost of the emissions savings, the Government’s Impact Assessments calculation is made on thebasis of dividing the NPV of the incentive by the total tonnes of CO 2 abated. The analysis here is viewed from thepoint of view of the direct cost to the consumer, ie the subsidy cost divided by the tonnes of CO 2 saved, and wherepossible uses the full lifecycle emissions of CO 2 e.9

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTDomestic Ground source heat pumps using grid electricity indicate £5500 cost per tonne of carbonabated compared with natural gas using the recent EST report for a mid range installed unit, and over£850 when compared with oil. When using renewable electricity (2 ROC supported offshore wind) thecosts of CO 2 e abatement are ~£460/te and £360/te respectively. Again on this basis, Bio-SNG competesvery effectively. If the adoption of electrical based solutions demands more grid reinforcement than wouldbe required to the gas network by Bio-SNG solutions, then the differential in cost per tonne of carbonabated is likely to be even greater.For transport applications, Bio-SNG is also significantly more cost effective than electrical solutions(either using grid electricity - £1000/ te CO 2 e, or presuming hypothecated offshore wind derivedrenewable electricity - £600/ te CO 2 e). However, this analysis does suggest that whilst Bio-SNG doesoffer significant carbon savings for the transport sector, on a cost per tonne abated of £400/ te CO 2 e, theheating sector is a preferable end market.Compared with decarbonisation in the electricity sector, Medium scale generation supported under theFIT costs between £220 and £570/te depending on technology, offshore wind costs ~£200/te, biomasscosts ~£150/te and onshore wind costs ~£100/te against a baseline of current grid average. Thissuggests that the Bio-SNG case is preferable when compared with decarbonisation via feed in Tariffs,offshore wind and anaerobic digestionWith regards to the cost of carbon abated, the renewables routes are relatively expensive. Whilst thecurrent renewable incentive structures are based on a duration which is commensurate with projectfunding, the risk for this type of project is that in time, it is the price of carbon which becomes thedominant incentive mechanism. This will highlight the relatively expensive cost of carbon abatement viarenewables, and may drive a change in policy. Without the kind of support proposed under the RHI,projects such as Bio-SNG would not be viable.The other key driver for the adoption of renewables is to establish alternative and secure sources ofenergy through diversity, and where possible, indigenous supply. In this regard the use of waste basedfuels to provide a gas substitute offers a very low cost fuel source on a per MWh basis compared withother renewables.Risk assessment and financing considerationsThe envisaged Bio-SNG facilities are in most respects conventional process engineering projects,exhibiting the general risk profile that such developments entail. These can in the main be addressedwith a conventional contracting approach to risk management; however there are technology andfinancing risks that need to be addressed.10

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTAlthough the process elements utilised in the development would be proven in their own right, there aresignificant technical interfaces between them that need to be managed as part of overall systemsintegration. This may require an innovative engineering and contracting approach, but it will be arequirement to assure project funders that there is no significant residual technical risk inherent in such adevelopment.The technical uncertainties implicit in the process integration will inevitably make project finance moredifficult and early development of a project financing strategy will be required in order to assure there willnot be a late in the day terminal event on this front.Government incentive schemes offer the prospect of commercial viability with a plant that would not inother circumstances be commercially viable; to that extent they are beneficial to non-fossil energydevelopments including Bio-SNG. The economic analysis shows that they do not constitute anexceptional upside return on investment. What influences the attitude of investors however is that currentsupport mechanisms offer no protection on the downside of the project risk profile. It follows that afinancing strategy needs to make provision for managing the downside risk that will be perceived byinvestors.An incremental approach to the management of technical risk would be the development of ademonstration facility, although even a reasonable scale demonstration facility might not necessarily openthe door to project finance on the first full scale plant. The demonstration plant would be required tooperate for a long time to assure process integrity, and further scale-up uncertainties associated with thefull sized plant would need to be managed Moreover this analysis suggests that a standalonedemonstration facility might itself cost in the order of £70M, a sum which would in any case represent afinancing challenge. The timeline for a demonstration facility also needs to be taken into accountespecially in consideration of the competitive uses of the biomass resources and the timing of commercialscale market penetration for BIO-SNG. Some of the investment risks could be mitigated by configuring aBio-SNG demonstration project on a syngas platform which is valorised mainly by another output productsuch as electricity, with demonstration of Bio-SNG production via a slipstream. The financing of a Bio-SNG project is a challenging prospect, however, it is important to start work on a financing strategy at theoutset of any prospective development, recognising the hurdles that do exist and devising methods toovercome them.Preliminary scoping of a demonstration platform in the North EastIn light of the financial analysis, a project at 300MWth fuelled by SRF (or even a mixture of SRF andvirgin biomass) is economically viable. However, the quantum of investment for a first of a kind project issubstantial and would not be financeable without an intermediary pathway.11

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTGiven the right support package, a demonstration project at 50MWth (75-100,000 te pa of feedstock)could be feasible, but the economies of scale mean that the level of support necessary is substantial. Thecombination of technical and commercial attributes, in addition to the current renewables incentiveregimes make a project configured to produce electricity a potentially more attractive platform. Thedevelopment of this commercial foundation could allow the demonstration of a slip stream of Bio-SNG atmore moderate additional cost.Alternatively the demonstration of Bio-SNG production could be predicated on an existing or alreadyproposed syngas platform. In the Teesside region there are a number of such projects or proposals,including the Ineos Bio facility, the proposed Air Products waste gasification scheme, or even the EstonGrange IGCC which is anticipated to utilise a biogenic fraction in the feedstock stream. This approachwould not necessarily demonstrate the preferred gasification system. However, it would demonstrate thedownstream gas processing, methanation, and gas polishing process components, provide tangibleevidence of Bio-SNG production to grid quality specification and establish the protocols and precedent forBio-SNG injection into the grid. This, combined with demonstration of the appropriate and provengasification system for syngas production elsewhere, could provide an incremental pathway towards alarge scale project, subject to the comments made in the previous section.The chemical and processing industrial heritage in the North East, its natural gas and servicesinfrastructure, its transport links and its track record of innovation make it an attractive region to locatesuch a project, particularly given the syngas projects already slated.With regards to potential new project sites, a high level screening exercise was carried out focused onprimary attributes (access to a deep water port, rail head &/or road access, gas connection NTS, or ifsufficient capacity LTS, electrical grid connection, commodities, water, cooling etc and desirable attributessources of rich hydrocarbons to boost gas quality, oxygen supplies, syngas main to valorise intermediate,& potential to link into CCS networks for carbon dioxide disposal). In Teesside, potential areas consideredwere Seaton Port, Seal Sands, Clarence Port, Billingham Reach, Norton Bottoms, South Bank, Corus,and Sembcorp. Many of these sites were generally suitable for either scale of facility, with good accessto intermediate pressure gas grid (17-40bar) with sufficient capacity. Probably the most favoured siteswould be Clarence Port and South Bank. Both these areas are part of re-development plans, and givenan appetite to progress, the commercial feasibility of project on these sites could be investigated in moredetail.Potentially one of the issues in locating the project in Teesside is feedstock supply. With regard to purebiomass, Teesside and the North East already has over 300,000te already in use (Wilton10 and co-firingat Lynemouth) with over 2 million tonnes per annum required for projects slated for development in thearea (MGT, Gaia Power and BEI). With regard to waste, SITA‟s Haverton incinerator already processes390,000te pa of waste with a recent contract award and expansion plan for a further 190,000 te pa. SITAand Sembcorp have also announced a planned Wilton 11 (400,000 te pa of household and commercial12

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTwaste), the Ineos Bio facility will use 100,000 of SRF in the first phase and the proposed Air Productsgasification project will require 300,000 te pa. Combined these represent 1.4million tonnes of waste.Many of these projects are still at the developmental stage and it is unlikely that all of these will progressto completion, and also much of this feedstock would not be sourced locally, but it does indicate potentialpressure on resource. Conversely, some of these projects could provide a basis for a Bio-SNGdemonstration, given an appetite to drive forward a project by a Bio-SNG investor and an appetite onbehalf of the host site.13

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT2 IntroductionMethane is an attractive heat and transport fuel vector. It is a clean and relatively low carbon intensityfuel. It can be utilised efficiently and has established infrastructure and demand-side technologies (gasboilers for heating and an increasingly wide range of available CNG vehicles). The UK has one of themost extensive gas networks in the world. Bio-methane retains all the attributes of natural gas, with thecrucial advantage that the fuel is renewable, offering substantial Carbon Dioxide savings. Few otherrenewable vectors are as fungible, with so few demand-side constraints.Figure 2.1 Methane, Biomethane and its merits and production routesBiomethane can, and is being produced via the upgrading of biogas from Anaerobic Digestion. However,in order to achieve a step change in production capacity, alternative approaches such as via thermalroutes (termed „Bio-SNG‟) are necessary.Figure 2.2 Schematic of Bio-SNG production14

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTThe Bio-SNG approach accommodates a wider range of input feedstocks. It also converts the full calorificvalue rather than only part of the biodegradable fraction. This also means that for Bio-SNG, the majorityof the mass and energy flow goes to the outturn product (gas). In anaerobic digestion, the majority of themass flow is to the residual digestate 9 . For these reasons the Bio-SNG approach can be executed atmore substantial scale.Whilst technically feasible, this approach is less mature than anaerobic digestion. Transition fromaspiration, to widespread operating facilities and infrastructure requires a detailed understanding of thetechnical and commercial attributes of the full chain from feedstock supply through to delivery of gridquality gas, as well as the development of the first crucial operating facility which provides the tangibleproof of concept for roll out. The chemical and processing industrial heritage in the North East, its naturalgas and services infrastructure and its track record of innovation make it an attractive region to locatesuch a project.This report lays out the key regulatory, feedstock, technical and economic issues, as well as the practicalconsiderations of a pathway from current status to an operating project.9 Digestate is an important co-product from anaerobic digestion, and its beneficial use is vital as part of asustainable biological cycle. However it does impose significant constraints on scale and location of anaerobicdigestion projects.15

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT3 Review of the fiscal, legislative and regulatory regimeImplementation of Bio-SNG will only take place with the appropriate tax, incentive and legislativeenvironment. Therefore it is critically important to establish the position that is pertinent to Bio-SNGproduction on its own account, but also in comparison with the situation for other competitive users ofbiogenic energy resources.3.1 RENEWABLE ENERGY INCENTIVES AND INSTRUMENTSOver the past decade UK government policy for renewable energy has been aimed at achievingreductions in fossil carbon dioxide emissions emanating from the generation of electricity, from transportfuels and more recently, from heating. Successive administrations have sought to achieve renewableenergy targets by means of Statutory Instruments that are intended to incentivise the development ofrenewable energy assets. Key amongst these are:The Renewable Obligations Order or ROThe RO was first introduced in 2002 and has been progressively developed in successive editions froman originally simple concept that sought to deliver renewable energy at the lowest cost to the consumerinto a complex system that now seeks to promote technology developments in certain favouredtechnology bands such as gasification and offshore wind, the lowest cost to the consumer criterion havingbeen dropped in the process 10 . The lesson to learn already from the brief history of the RO is thatincentive schemes are subject to constant adjustment, and changing political priorities. It follows thatdevelopers must take advantage of the moment to secure a position because the longer a project takes todevelop the greater the potential for a change to the incentive landscape. The RO works by accreditedgenerators earning Renewable Obligation Certificate(s) for each MWh of renewable electricity exported;electricity suppliers being obliged to sell a certain percentage of renewable electricity each year or elsepay the buy-out price for the shortfall. Funds arising from the buy-out are distributed to the generatorspro-rata to their relative renewables contributions.The Renewable Transport Fuel ObligationThe RTFO came into law in 2008 as a means by which transport fuel suppliers could demonstratecompliance with progressively increasing targets for the substitution of petroleum-based fuels in the retailtransport fuel mix. The RTFO works in a similar way to the RO concerning discharging of obligations byproduction and trading of RTF Certificates, however, the unit of measure is the litre of fuel, rather thananything that could relate to energy outputs and inputs, resource efficiency or carbon outcomes. It will bereadily appreciated therefore that a comparative assessment of the relative support levels afforded to10 . This Criterion has been noted again recently in the 2010 CSR with regard to FITS: “2.104 The efficiency of Feed-In Tariffs will be improved at the next formal review, rebalancing them in favour of more cost effective carbonabatement technologies.”16

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTrenewable electricity and renewable transport fuels is difficult to assess objectively.This becomesimportant when the market seeks to direct biomass resources to the use that gives the greatest return forthe producer – one sector may be disadvantaged relative to another. The RTFO only applies to a fewspecific liquid fuel types and does encompass biogas – for which the only support is the fuel dutydifferential between methane and diesel/gasoline. The RTFO has had a chequered history, due to arecent slowdown in targets, as well as a drafting error, the obligation has not generally provided abankable revenue stream.The Renewable Heat IncentiveThe Renewable Heat incentive is a long overdue support mechanism to rebalance renewabledevelopment into the heat sector. This incentive includes support for direct injection of renewable gas intothe network. Following the Comprehensive Spending Review, HMT made the following press release onthe 20 Oct 2010……….. “£860 million funding for the Renewable Heat Incentive which will be introducedfrom 2011-12. This will drive a more-than-tenfold increase of renewable heat over the coming decade,shifting renewable heat from a fringe industry firmly into the mainstream. The Government will not betaking forward the previous administration’s plans of funding this scheme through an overly complexRenewable Heat levy”. From this it will be seen that the RHI has survived the spending review, albeit atan ~80% reduction in support level but that there is still some clarification to be made concerning thedetails of its operation and its implementation may be delayed beyond the original target date of April2011, provisionally to June 2011. Clearly much depends upon a detailed appraisal and clarification of theRHI concerning its potential to provide an appropriate level of support for Bio-SNG developments, andhow in detail the incentive cascades back to the Bio-SNG producer.The Feed-In TariffThe Feed-In Tariff was introduced in 2010 to incentivise the production of renewable electricity from smallfacilities, avoiding the complexities of the RO by offering a fixed but uplifted electricity selling price. TheComprehensive Spending Review indicates that the next FIT review will include changes intended tofocus development on those schemes thought to be most effective. Again it will be necessary to see ifthere are any market distorting effects that could influence competition for solid bio-fuels.EU Renewable Energy DirectiveLate in the piece has come the EU Renewable Energy Directive (RED) which comes into law formallyby the 5 th December 2010. The RED sets out targets for member states for the generation of energy fromrenewable sources across all sectors, together with mandatory definitions of legal terms, units ofmeasurement and accounting.All domestic renewable energy legislation and practice must becompatible with the RED definitions etc. otherwise it will be illegal. Clearly, the obvious discrepanciesbetween the RTFO and the remainder of the UK‟s renewables instruments must be regularised at somepoint. The RED includes a definition of biogas and it appears that Bio-SNG would fall within the terms setout in the directive concerning its eligibility as a source of renewable energy 11 . The RED also anticipates11 Unlike the UK Energy Act 2008 which does have a definitional issue which is undergoing resolution.17

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTthe injection of methane from biogenic origins into the gas network and requires member states tofacilitate this activity. The RED sets specific sectoral targets including the achievement of 10% renewableenergy in surface transportation systems (a possible use of Bio-SNG) and encourages the use of wastederivedmaterials by proposing double incentives for the use of energy derived from biogenic wastes.3.2 ENERGY FROM WASTE REGULATIONS AND ISSUESThe use of waste derived fuels invokes additional regulatory considerations associated with the WasteIncineration Directive (WID) as well as the need to assure the bio-energy contribution to the energyrelease from mixed fossil / non fossil components. The drafting of the WID and its interpretation intoEnglish or Scottish law presumes that waste derived fuels would be burned in an incineration plant. Thispresumption leads to some difficulties when wastes are used in alternative energy schemes that were notanticipated at the time of the WID drafting. Firstly the question of when a recovered material ceases to bea waste continues to be a grey area. On the one hand recycled paper is considered to be recoveredwhen it is returned to raw paper pulp – the pulp then being no longer subject to regulation as a waste.The recovery of waste paper as a fuel, however, does not benefit from this interpretation; waste-derivedfuels are still considered to be wastes – irrespective of their use and their intrinsic properties. Accordinglyenergy plants fuelled by waste-derived fuels are subject to regulation under the WID, the syngasproduced by a gasifier still being regarded by the Environment Agency as a waste 12 . The prevailingwisdom from the Environment Agency is that the gas would continue to be a waste up to the point whereit is “recovered” – i.e. burned. At face value this means that if Bio-SNG was to be produced from wasteand burned in a domestic heating appliance then the domestic heating appliance would need to complywith the requirements of the WID. This is clearly a nonsense that would need to be formally andunambiguously resolved before waste-derived fuels could be used in the production of Bio-SNG.Accounting for the energy contributions from the fossil and non-fossil components of waste derived fuels(i.e. miscellaneous biomass and various plastic rejects) is necessary in order to gain accreditation forsupport for the bio-energy fraction under any of the renewables incentives listed above. To date this hasbeen a concern predominantly in the waste to electricity sector, but it is clearly going to be equallyimportant in a Bio-SNG development. Where a 100% biomass fuel is used it is a relatively simple matterto assure the bio-energy content of the fuel and this can be achieved via an agreed fuel qualitymanagement plan. With a heterogeneous waste derived fuel there are two possible methods to assessbio-energy content in the fuel – sampling and physical separation followed by classification and weighing,or selective dissolution of biomass. Both require a sampling programme, which, given the inherentvariability of waste-derived fuels is subject to significant error bands and uncertainty unless a largenumber of samples is taken into consideration. Even then it would be practically impossible to guaranteehow much of the bio-energy had reported to the final Bio-SNG product stream, and how much had beenassociated with incidental process heat losses. The practical way to measure the bio-energy content of12 A recent EU Ruling at Lahti has set a precedent that a syngas may no longer be a waste. Whilst this is underconsideration in the UK, no such formal policy position has been set out as of the date of this report.18

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTthe product SNG would be to use C 14 based techniques similar to those which are at present undergoingdemonstration to Ofgem in facilities generating electricity from wastes. Whilst the C 14 methodology fordetermination of bio-energy content appears to be the favoured approach, it must be appreciated thatthere is still some work to be undertaken before it is finally accepted by Ofgem as an appropriatemechanism for accreditation of renewable energy content. Utilisation of C 14 in Bio-SNG production fromheterogeneous fuels would entail some further work beyond that, but for Bio-SNG it is probably the onlypractical methodology for establishing bio-energy contribution from a heterogeneous fuel.Electricity plants running on waste-derived fuels can, under certain circumstances qualify for enhancedcapital allowances against corporation tax but this will also require operators to give evidence of biogenicenergy contribution for which C 14 based systems would be ideally suited. It is also unclear if such benefitscould accrue to Bio-SNG facilities.3.3 EMISSIONS TRADINGUnder the European Emissions trading Scheme (Eu ETS) all power plants with a thermal rating of greaterthan 20MW are required to register and report their GHG emissions. The implementation of the ETS isPhased from its initial introduction in 2005 (Phase 1), with Phase 2 running from 2008 to 2012 whereafterthe third and ultimate scope of the ETS will be imposed. The objective of the Eu ETS is to set a cap ongross Eu GHG emissions reducing annually from a figure of 1927m tonnes CO 2 equivalent in 2013; thisfigure being shared, by a process of negotiation, between the member states. In each phase and year ofthe implementation a progressive lowering of the free carbon allowances will be imposed, obligingthereby the operators to progressively reduce their own GHG emissions or else to buy surplus allowancesin the market from those with a surfeit of allowances. Whilst all thermal power plants of greater than20MWth are required to register under the Eu ETS, certain types of plant are exempt from the need tolimit their annual GHG emissions; these include facilities running on pure biomass. It will be apparenttherefore that a Bio-SNG plant running on pure biomass will not be required to obtain emissions permitsunder the Eu ETS, but where a waste-derived fuel that includes some fossil carbon is used then the ETSbecomes not only a regulatory consideration but fossil carbon emissions need to be accounted for andmeasured. This may require a particular treatment because some of the energy release will be local, withthe remainder being consigned to the pipeline. It should be noted that “Municipal facilities” are exemptfrom the provisions of the Eu ETS, hence a plant operating primarily to deliver a municipal wastemanagement service ought to be exempt. The status of a potential Bio-SNG plant appears to besomewhat obscure with respect to the Eu ETS, therefore it is recommended that early in the developmentprogramme clarification should be sought concerning whether such a plant would be eligible / liable, andalso how the question of a percentage of fossil carbon in the feedstock should be handled. (Note that theBio-SNG plant will be a direct producer of carbon dioxide resulting from acid gas removal post shift andpre methanation reactions. With a waste-derived fuel some of this will have a fossil origin.)19

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT3.4 THE GAS SAFETY MANAGEMENT REGULATIONSThe Gas Safety Management Regulations (GS(M)R) set out the rules for transportation of natural gasthroughout the gas network, from producer to customer and will be well understood by gas industrypractitioners. Of critical importance to the design of Bio-SNG facilities, Schedule 3, Regulation 8 of theGS(M)R defines the allowable gas composition for gas transported through the network; the relevantsection being included in this report as Appendix 3. As discussed in Section 5.5 the main challenge forBio-SNG production is the hydrogen content specified in the GS(M)R 13 , however it may be possible toachieve some derogation of this by examination of the methodology outlined in article 192 of Schedule 3of the GS(M)R 14 .3.5 OTHER KEY REGULATIONSThe Large Combustion Plant Directive (LCPD) seeks to regulate the emission of SOx, NOx and dustfrom power plants with a thermal rating of 50MWth or more. Whilst both the subject demonstration scaleplant and the full scale plant reach or exceed this thermal power input it would appear that neither wouldbe subject to the LCPD. Article 2 (&) of the Directive states:“This Directive shall apply only to combustion plants designed for production of energy with the exceptionof those which make direct use of the products of combustion in manufacturing processes.”On this basis, given that in a Bio-SNG plant the products of combustion are used to make methane, sucha plant would not be regulated under the LCPD. However, a Bio-SNG plant, just like any other largeindustrial process facility would fall within the IPPC regulations and be required to secure anEnvironmental Permit. This should not constitute a particular development hurdle, but it would constitutea significant expenditure and must be commenced early in the development to avoid the risk of delays tofinancial close.13 Unlike for anaerobic digestion derived biogas, for which oxygen content is one of the key challenges14 The full GS(M)R can be obtained as a downloadable .pdf file from:http://books.hse.gov.uk/hse/public/saleproduct.jsf?catalogueCode=978071761159120

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT4 FeedstockBiomethane production via synthesis gas can be generated from any biomass fuel which can be gasified.Potentially this encompasses pure biomasses such as woodchip, energy crops or biogenic co-productsfrom biodiesel production, crude bio-oil from wood pyrolysis, to discarded materials such as waste wood,or processed wastes such as Solid Recovered Fuels. This review will provide a high level perspective onfuel types and the technical implications on the process, as well as the commercial and sustainabilityissues.The use of bio-fuels for heating and lighting pre-dates the use of fossil fuels by thousands of years,nevertheless a systematic knowledge base of the challenges posed by solid bio-fuels is not as widelyunderstood as is the case with fossil fuels, a fact attributable to the burgeoning use of fossil fuels asexponentially increasing demand powered the industrial revolution across the globe. In the emergingpost-fossil epoch that is beginning now, producers and users of thermal power are considering the use ofbiomass in applications in which the use of fossil hydrocarbons has been dominant – electricitygeneration, heating, transport fuels, organic chemicals, synthetic materials, and synthetic natural gas orSNG.4.1 THE SIGNIFICANCE OF BIO-SNG IN THE ENERGY SCENEThe primary energy consumption of the United Kingdom is approximately 10 Exajoules per annum 15 , ofwhich nearly 40% is supplied by natural gas, making gas the UK‟s largest single energy source, with anextensive infrastructure and expertise base.Figure 4.1 Natural gas flow chart 2008 (TWh) 1615 1 Exajoule is 1X10 18 Joules, written conventionally as EJ16 Digest of United Kingdom Energy Statistic200921

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTWith the ever rising need to secure future energy diversity and reduce greenhouse gas emissions it couldbe a considerable advantage if use could be made of the gas infrastructure and the expertise of theefficient industry that has developed around it by the use of synthetic natural gas (SNG), including SNGderived from renewable resources such as biomass – “Bio-SNG”.4.2 „PURE‟ BIOMASS RESOURCESIn coming to a view on the potential merit of Bio-SNG it is necessary to consider the magnitude ofbiomass resources in order to establish the scale of the benefits that might be realised in practice. Notethat this report does not address the potential of biogas derived from the digestion of organic matter inlandfills and anaerobic digesters but concentrates upon the thermochemical production of methane frombiomass types that are generally not digestible, i.e. woody biomass. Woody biomass can be classifiedaccording to its provenance; for example energy crops, agricultural and arboricultural residues, industrialco-products, and waste materials such as recovered wood.A certain amount of work has been accomplished to date on the quantities and prices of biomass fuelsthat could be obtained both from indigenous sources and on international markets 17 , and is collated inTable 4-1Fuel type Indigenous Import GlobalEnergy crops 60 -550 PJ/a

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTfor the solid biofuels remains a considerable challenge – each depending upon the other with investmentdecisions requiring certainty for both supplier and user.Estimates vary for indigenous production capacity for energy crops ranging from 60 PJ to 550PJ perannum depending upon the extent to which subsidies may be paid to growers to compensate for the lagbetween planting and harvest and sales 18 . It is interesting to note the implicit assumption that subsidiesfor energy crops are required to get the supply chain established rather than to compensate for theintrinsically higher cost base associated with energy crops pending the date when rising fuel prices couldbe expected to reach and overtake these. An investor in a plant using solid biofuel crops ought thereforeto satisfy itself that the cost of producing energy crops is not disadvantageously indexed to the prevailingcost of energy, or else gain satisfaction that support mechanisms would be sustained for a sufficientperiod of production and operation to assure commercial viability for both producer and user.WoodchipIn the UK, half of the commercial forestry is operated by the forestry commission, with the balance underprivate management. Approximately 9 million green tonnes are extracted per annum for timberproduction. Green timber is 50-55% moisture as harvested, although with seasoning can be reduced to30% naturally over time, without additional heat. This material can be utilised as woodchip, although itsuse is in direct competition with sawlog. Small roundwood is less valuable than sawlog, so woodchip canbe sourced from this material. Other than saw-wood, there is a variety of lower grade timber availablefrom forestry and the urban environment. In managing forestry, brash (removal of ancillary stems),thinning (trees which are too small for extraction) and poor quality final crops, can be extracted. Many ofthese are left on site, however, as the market for biomass fuels expands, these are a lower cost source oftimber. The arboricultural arisings in England, Scotland and Wales by Forest district, estimated to bec.670,000 19 oven dried tonnes per annum (12PJ pa). Similarly, in the urban environment and on road andrail-sides tree management gives rise to arboricultural arisings. These are usually chipped, and oftenlandfilled, but are increasingly being viewed as another energy biomass source.Internationally woody biomass has the potential to be sourced from highly forested countries such asCanada and Russia, with often distressed products being identified (such as beetle killed spruce). In theUK over 250PJ of international woody biomass resources have been slated for use in electricity projects.Whilst these resources are substantial, these commodities require extraction, haulage, shipping,unloading and delivery into plant, noting that the energy density of biomass is low relative to fossil fuels.As international jurisdictions develop renewable energy policies and seek to secure resources for theirenergy needs, international competition for these fuels will become more intense.18 DECC - Biomass supply curves for the UK – E4Tech - March 200919Woodfuel Resource in Britain FES B/W3/00787/REP/2 DTI/Pub RN 03/1436 (2003)23

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTTrends in the biomass to power market indicate that major users of solid biofuels are moving upstream inthe fuel supply chain in order to secure their future fuel deliveries. The recent take-over of the Dutchcompany Essent by RWE was made for this specific purpose; RWE recognising that Essent had alreadyestablished a trading arm that is dedicated to the sourcing, transportation and trading of biomass fuels,with a view to expansion of this business to meet the anticipated demand for biofuels. With theexpanding demand for biofuels it is becoming increasingly clear that developers of biomass fuelledfacilities need to take overt measures to manage fuel supply uncertainties (price, quality, availability,sustainability), at least for the purpose of constructing a bankable case for project finance.4.3 PROPERTIES OF „PURE‟ BIOMASS FUELSThe development of industrial scale gasification of coal has occurred over a period of more than 100years and is the subject of a vast body of science and technology. The success of this industry is builtupon years of investment, research and development and operating experience. It is frequentlyassumed, mistakenly, that the industrial gasification 20 of biomass is more difficult, evidenced by the slowpace of development in this area. The lack of development would be more reasonably attributable to thenovelty of the process and the small scale of the industry, rather than any fundamental technologicallimitation. Nevertheless, in contemplating the production of SNG from biomass it is essential tounderstand the significant differences between biomass feedstocks and the more widely understoodproperties of coals.For gasification, the fuel properties of most interest are; fixed / volatile carbon, carbon, hydrogen, oxygen,nitrogen, ash content, ash fusion temperature, and humidity.Sub bituminous coal (typical) Wood fuel (typical)Fixed carbon % 44.7% 20%Ash content %. [DB] 4.3% 1.2%Ash Fusion temperature (°C) 1230 to 1600 > 850Sulphur % [DAF] 0.5%

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTAlthough many of the macroscopic properties of biomass are remarkably similar across a number ofspecies it is important to note that minor constituents can vary with the species 21 and undoubtedly withthe environment and soils in which they are grown. (Scientific literature is prolific on the subject of mineraltake-up from the environment, with some plant species being especially effective in accumulating, lead,zinc, mercury etc.) This is particularly important when considering the properties of biomass ashes,which in themselves are notably dissimilar to coal ashes, both in the amount and also their chemicalcomposition. This has implications for chosen gasifier operating conditions especially with respect to ashfusion temperatures and the volatile behaviour of certain alkali metal oxides at elevated temperatures.Furthermore, gas processing operations may be sensitive to small levels of both alkali metals and heavymetals in the de-activation of catalysts.The European Commission recognised the need for a systematic basis to describe solid biofuels and in2004 embarked upon a programme of work under CEN/335 entitled “Solid Biofuels”. The objective of thework was to provide a scientifically informed basis for describing the properties of solid bio fuels for thepurpose of facilitating trade between producer and user, for informing process design, (esp. materialshandling), environmental permitting, communication with stakeholders and for quality management.4.4 WASTE MATERIALSOver 98% of the potential UK indigenous biomass resource is from waste products 22 . Municipal,commercial and industrial wastes therefore provide a valuable and ubiquitous source of biomass fuel.Combustible wastes arising from household collections, commercial-industrial waste and construction anddemolition 23 . Whilst there is significant political pressure to increase recycling, analysis by Lee et alclearly shows that even extensive recycling will still leave a substantial tranche of residual material forwhich recycling is not possible. This data, Figure 4.2 shows that the residual waste from municipalsources is predicted to be fairly constant at c.28million tonnes and from commercial/industrial sources at50million tonnes. Of this c.17million and c.24million tonnes are considered to be biomass respectively.The authors estimate this residual waste resource (biogenic and non-biogenic) to be ~700PJ from bothMWS and C&I streams. This full potential analysis does not account for existing uses for the residualwastes, nor the availability of the streams (this is discussed in Section 4.7)21 Biomass and Bioenergy Vol. 4, No. 2, pp. 103-116, 199322 Gill et al, Biomass Task Force Report (2005)23 Lee P et al, “Quantification of the Potential Energy from Residuals (EfR) in the UK” Commissioned by TheInstitution of Civil Engineers. The Renewable Power Association (March 2005) Oakdene Hollins Ltd25

Million Tonnes per annumMillion Tonnes per annumBIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTMunicipal Waste arisingsCommercial and Industrial Waste arisings1001008060402002005 2010 2015 20208060402002005 2010 2015 2020Figure 4.2Bio Residual Non Bio Residual RecycledBio Residual Non Bio Residual RecycledMunicipal, commercial and Industrial waste arisings in the UKThe production of Solid Recovered Fuel (SRF) from non-hazardous wastes creates the opportunity toutilise waste derived fuels in thermal applications that are more sophisticated than the classical wastedisposal route via incineration; in particular SRF is being regarded increasingly by a number of producersand users as a potential feedstock in gasification. Hence there is the potential for the transformation ofcombustible wastes into syngas and its products – including SNG.The term SRF arises from work undertaken by the European Commission under CEN/343 to provide asystematic basis for the classification and standardisation of fuels derived from non-hazardous wastes.This work was undertaken in the anticipation that the energy content of non-hazardous wastes should beexploited in pursuit of increased resource efficiency within the EU. CEN/343 therefore set out to define ascientifically informed basis for describing the properties of waste derived fuels for the purpose offacilitating trade between producer and user, for informing process design, environmental permitting,communication with stakeholders and for quality management 24 .It will be readily appreciated that it is not feasible to design a piece of sophisticated plant such as agasifier without tailoring the design to the known properties of the fuel. This is true for a conventional coalgasifier and it is equally the case for a gasifier intended for operation on biomass or a waste-derived fuel.Given the variable provenance and properties of waste materials it becomes an indispensable conditionthat some method must be applied by which the physical and chemical properties of a waste-derived fuelcan be specified and assured, if they are to be used as a gasifier feedstock. The CEN/343 approachprovides a rigorous method to do this.The properties of solid fuels which are of most interest in gasification are common, whether they are fossilor biomass or waste. These include particle size and density, physical form, ash content, ash fusion pointand ash composition, humidity, and levels of halogens, sulphur, arsenic, and mercury. An operator of acoal gasifier can control the inputs to its plant by using coal from well characterised sources, evenindividual mines, backed up by standardised coal testing techniques that have been in use for decades.The use of SRF in gasification introduces therefore the need for an equally effective means of fuel qualityassurance.24 CEN/343 is now mandated for adoption by member states and is available from British Standards Institute.26

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTIn postulating the use of SRF for the production of Bio-SNG, it is necessary to understand the bio energycontent of the fuel. CEN/343 includes methods for making this determination, but they may not providethe best method of biomass determination. 25 It must also be appreciated that when SRF is used forproduction of SNG, a proportion of the output would contain fossil carbon, and this would needaccounting for if incentives for renewable energy were to be claimed. The composition of a typical SolidRecovered Fuel is shown in Table 4-3SRF class and originClass code : NCV 3, Cl 3, Hg 3Physical parametersParticle form : CubesParticle size : Test method: prCEN/TS 15415Unit Value Test methodTypical LimitAsh content % dm 26 14 25 prCEN/TS 15403Moisture content % ar 27 8 20 prCEN/TS 15414Net calorific value (NCV) MJ/kg ar 18 >12.5 prCEN/TS 15400Biomass fraction % GCV 65 50 prCEN/TS 15440Chemical parametersUnit Value Test methodTypical LimitChlorine (Cl) % w/w 28 0.26 1.0 prCEN/TS 15408Sulphur (S) % w/w 0.15 1.0 prCEN/TS 15408Fluorine (F) % w/w 0.02 0.5 prCEN/TS 15408Bromine (Br) % w/w 0.01 0.25 prCEN/TS 15408Mercury (Hg) mg/kg 0.49 10 prCEN/TS 15411Cadmium (Cd) mg/kg 1.26 20 prCEN/TS 15411Thallium (Tl) mg/kg < 9 20 prCEN/TS 15411Total Group II metals mg/kg 18 30 prCEN/TS 15411Antimony (Sb) mg/kg 12 150 prCEN/TS 15411Arsenic (As) mg/kg < 0.82 100 prCEN/TS 15411Chromium (Cr) mg/kg 17.6 150 prCEN/TS 15411Cobalt (Co) mg/kg 4.3 75 prCEN/TS 15411Copper (Cu) mg/kg 268 500 prCEN/TS 15411Lead (Pb) mg/kg 100 250 prCEN/TS 15411Manganese (Mn) mg/kg 90 500 prCEN/TS 15411Nickel (Ni) mg/kg 9.3 100 prCEN/TS 15411Tin (Sn) mg/kg 27 50 prCEN/TS 15411Vanadium (V) mg/kg 4.1 50 prCEN/TS 15411Total Group III metals mg/kg 538 800 prCEN/TS 15411Table 4-3 Typical SRF specificationFailure of waste gasification processes has been frequently exacerbated by not only the uncontrolledvariability of the fuel, but also by the failure of technology developers to appreciate the importance of thisissue in process design. Unlike a waste incinerator, a waste fired gasifier cannot be omnivorous; fuelspecification and plant design are inextricably linked.25 C 14 methods applied to the process output may give more reliable performance and be cheaper.26 dry matter (dm)27 as received (ar)28 wet weight (w/w)27

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT4.5 TOTAL AMOUNT OF BIOMASS RESOURCE FOR BIO-SNG PRODUCTIONNotwithstanding the considerations outlined above it is necessary to postulate the amount of biomass fuel(„pure‟ and waste derived) that could reasonably be procured for the production of SNG, both fromindigenous and overseas sources, and thereby form an estimate of the significance of the ensuing Bio-SNG production in the UK gas market. Figure 4.3 shows such a figure, assuming that 1EJ of biomasscould be sourced indigenously and from international markets, and that 33% of that could be used for theproduction of Bio-SNG for use in heat and transport applications at a conversion efficiency of 66%. Thiswould represent 15% of the UK domestic gas market.Figure 4.3Potential role for Bio-SNG as a function of the UK domestic Gas market4.6 COMMERCIAL CONSIDERATIONS FOR „PURE‟ BIOMASSTo see biomass as simply a replacement for a fossil fuel such as coal is a mistake on account of itsdispersed provenance, its chemistry, humidity and its lower energy and bulk densities. It is equallyimportant to recognise that biomass has the potential to be a feedstock across a wide spectrum of usersand industries, whether transformed into synthesis gas (syngas) - the universal feedstock for the organicchemicals industry – synthetic materials such as plastics resins and polymers, drugs and pharmaceuticals- power generation, liquid transport fuels, and SNG, or used for space heating or as it is as a constructionmaterial - timber. The growing demand for biomass in these applications will set the market priceglobally. It is also evident that potential demand for biomass feedstocks across all of these sectors could28

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTeasily exceed global production capacity from the outset, a situation that paradoxically is only justbeginning to impact on crude oil prices at the end a century of exponentially increasing oil production froma vast but finite resource. Competing users of biomass feedstocks will set the market price, withgovernmental support mechanisms for biomass electricity already having a dominant effect and beingcriticised as contributing to unfair market distortion 29 .The traded price of clean biomass fuels for biomass power generation is today in the range of £6 to £7per GJ measured as net calorific or lower heating value, a price that would be unaffordable by operatorsof biomass power stations without support through a variety of inward looking national supportmechanisms 30 . The relative generosity of the various national support mechanisms is not formallycoordinated throughout the EU, and it is most certainly uncoordinated globally. Asymmetry betweennational support schemes for power generation from globally traded biofuels remains a significantcommercial threat to the viability of schemes that utilise such fuels 31 . It is also the case that asymmetry ofsupport mechanisms across market sectors within the UK constitutes a business threat to any companyfor whom consequent price distortions would affect their business case. (Users in receipt of the mostadvantageous support will be market price makers, all others will be price takers.)The effect of asymmetry in support mechanisms is to give one class of users a dominant position in thefuel market In conditions of supply constraint this constitutes a lock-out to other potential users of abiomass resource. Hence in the domestic UK situation the Renewables Obligation (and the SRO andNIRO) rewards electrical power generation more favourably than would the RTFO reward the use of anequivalent amount of resource in the production of synthetic transport fuels. Accordingly the purchaser ofa biomass resource will seek to use it in the application yielding the greater added value – powergeneration. Developers of biomass to liquids plants will not move until an equivalence of incentives (atleast) would be forthcoming. In contemplating the development of an SNG facility, considerations ofanalogous factors should be undertaken; these would include the impending Renewable Heat Incentive(RHI), fuel costs, the specific SNG yield, power sales prices, and Bio-SNG selling price, together withplant capital and operating costs.4.7 COMMERCIAL CONSIDERATIONS FOR WASTESThe production of wastes does not mean necessarily that they are available to the market. Municipalauthorities have for many years been required to meet increasingly onerous targets for the long termmanagement of their waste streams. This has involved local authorities in committing to long termcontracts with waste contractors, in which their waste streams are likely to be tied up for periods of 20 to29 See BWPI Federation – “Large-scale biomass threatens 8,700 UK jobs... ...and risks a 1% increase in UKemissions” http://www.wpif.org.uk/Make_Wood_Work_News.asp30 Coal prices are in the region of £2 per GJ; the price differential to biomass being more than sufficient topurchase carbon offsets or allowances with carbon trading at any price up to approximately £30 per tonne.31 Note the way in which different approaches to support for transport biofuels in North America and UKprecipitated a sequence of events that seriously damaged the UK indigenous biofuels industry in 2008/9.29

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT25 years. The over-riding principle that sits behind municipal waste management is that local authoritiesneed to have long term certainty over price and deliverability from their contractors; uncertainty (includingtechnical uncertainty) over reliability of off-take or price is usually unacceptable to them.The economic driver in the commercial industrial waste market rests predominantly with the landfill tax;hence a rational market exists in which operators seek the lowest cost of disposal for those materials thatdo not command a revenue from recycling. Historically, the lowest cost of disposal has been given bylandfill, but with the inexorable increase in the level of landfill tax waste handlers are increasingly lookingto other forms of disposal that might be competitive. This has lead to an increasing interest in disposal ofcombustible wastes via energy recovery facilities, whether by mass burn incineration or via production ofsolid recovered fuels (SRF).Under certain conditions 32 energy from waste facilities have the potential to secure Renewable ObligationCertificates and hence benefit from additional power income 33 . The potential of gasification to securedouble ROC eligibility has promoted development activity in this area, where a gasification project couldbe commercially viable at a small scale given the additional revenues promised by double ROCS and agate fee for taking waste-derived fuels.In the existing UK market the users of waste-derived fuels demand and are able to receive a gate fee inthe range of £20 to £50 per tonne, irrespective of the quality or energy value of the fuel. This is becausethe next cheapest option available to producers is disposal via landfill. This represents a major benefit tothe fuel user, but there are already signs that the market is changing, with continental users offering topay a small cost per tonne, and UK producers exporting SRF to continental users in the face of anincreasing demand for the product. It follows that in creating a business case for the production ofsyngas from SRF it would be a mistake to assume that the price of SRF will always be a large negativenumber. Nevertheless, the cost benefit of SRF compared to energy crops means that the marginalscales of commercially viable facilities running on these fuels are likely to be quite different. This may beimportant for early Bio-SNG projects where the risk profile of a first-of-a-kind plant might prohibitdevelopment at the scale required to ensure a commercial return when using bio-crop fuels.32 Conditions include: either the use of an advanced thermal process such as gasification, or the achievement ofGQ CHP in a combined heat and power plant.33 The RHI holds a similar promise, though the rules regarding eligibility are not yet defined.30

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT4.8 FEEDSTOCK CONCLUSIONSIn planning the production of Bio-SNG consideration must be given to the ultimate capacity that iscontemplated and a strategy put in place to secure the quantity and quality of feedstock that would berequired, at an acceptable cost, and in a market where competing large scale uses of biomass feedstocksare being developed simultaneously throughout the world.Commercial viability will be influenced by governmental support in the renewables sector. It follows thatBio-SNG developer should seek to ensure it is able to compete in the fuel market with other biomassusers.The properties of biomass fuels should be understood and controlled to required quality levels, whethervirgin biomass, or recovered materials. Reliability of process plants will depend upon this.In summary, it is likely that the development of Bio-SNG facilities will require the developer to goupstream into the supply chain for both grown and waste derived fuels, however, specification and qualitycontrol are vital determinants of project success.31

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT5 Process and Technology ReviewThe focus of this section is not to undertake a panoramic review of potential technologies in variousstates of maturity; that has been done elsewhere 34 . Rather it is to focus on a rationale for theconfiguration of a practical plant that could, subject to commercial considerations be deployed now at anindustrial scale.Experience reveals that process developments are rarely founded on technological break-throughs;rather it is normally the case that process developments are incremental and founded upon existingproven techniques. The guiding principle in this review has been therefore, to establish whether existingtechnologies could be employed for the entire process chain from fuel reception and preparation throughto Bio-SNG compression and delivery, and in a way that gives a good level of performance in comparisonwith alternatives and with respect to efficiency, technical risk, commerciality and speed to market.The development of a processing scheme should be dominated by an understanding of the desiredoutput stream as well as the properties of the feedstock; including a precise understanding of the levels ofcontrary elements in the fuel such as heavy metals, sulphur and halogens. This drives the requirementsand specification for the intervening processing stages. An overall appreciation of the principal processoperations required for the production of Bio-SNG is shown in Figure 5.1 below.BALANCE OF PLANTFUEL PREPTHERMO-CHEMICALBREAKDOWNINTERMEDIATEPURIFICATIONINTERMEDIATECONDITIONINGMETHANATIONPOLISHING“PACKAGING”includingCOMPRESSIONPRODUCTS: HEAT, ELECTRICITY, OTHER CHEMICALS AND FUELSPRODUCTBio-SNGFigure 5.1Principal Process operationsA systematic process review therefore will begin with the fuel handling facilities - reception, storage,preparation and feeding arrangements.5.1 BIOMASS RECEPTION, PREPARATION AND HANDLING.The operational effectiveness of the gasification process plant will depend upon the continuous supply offuel exhibiting regular properties – particle size, density, humidity, calorific value, chemical analysis, etc.34 e.g. NNFCC project 09/008: Review of Technologies for Gasification of Biomass and Wastes: E4Tech June 200932

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTA key design consideration therefore is whether to import material of a defined specification and quality orto manufacture the fuel on site from raw biomass or residues. On the one hand manufacture on site willdemand more space, more plant, a larger workforce and a significant parasitic energy consumption,however on the other hand, bought-in ready to use fuel will be more costly, and could subject the plant togreater supply chain vulnerability. Moreover biomass drying is likely to be a significant feature of the fuelpreparation process and could represent an economically effective use of waste heat from the gasificationprocess. A balanced judgement needs to be taken, therefore, on the fuel supply philosophy, taking intoaccount, the type of raw feedstock (lumber, waste wood, wood chip, pellets, miscellaneous biomassresidues, commercial / industrial waste etc.), the plant location, the space available, and the fuel supplychain arrangements.There is extensive expertise in the area of fuel reception, preparation and handling, however, it is acommon location for serious process malfunctions; due diligence experience reveals a consistent andrecurrent problem with fuel preparation, quality and feeding. It is vital, therefore at the design stage touse proven and reliable designers, and equipment suppliers and to confirm that the process plant willoperate with the particular material specifications envisaged for fuelling the gasifier. Solids handlingsystems must be designed in consideration of the particular properties of the materials in question; forexample it would be unwise to assume that woodchip will behave in a handling system in the same wayas wood pellets. CEN/335 goes some way to describing standard test methods that can be employed todetermine the critical handling attributes of particular solid biomass fuels.5.2 GASIFICATIONThere are fundamentally three main types of gasifier:Fixed bed (down-draft and up-draft)Entrained flowFluidised bed (direct and indirect heating)Fixed bed biomass gasifiers are used extensively in some parts of the world in small, relatively crudeapplications producing a low quality gas for small scale power generation. Fixed bed gasifiers are alsoused at a large scale, however, the low carbon intensity of biomass fuels makes them unsuitable for usein large scale fixed bed gasifiers, unless they are co-fired with coal. On this account it is proposed thatfixed bed gasifiers should be excluded from further consideration where the intent is to produce biosyngasat a moderate industrial scale.33

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFigure 5.2 Fixed Bed Gasifiers 35Entrained flow gasifiers represent the state-of–the-art for gasification of pulverised hard solid fuels suchas coal or petroleum coke, or liquids such as residual oils, but are unsuitable for raw biomass or wastederivedfuels which can not be pulverised in the same manner as coal or coke. However, biomass can bepre-treated by a process such as Torrefaction, which is in effect a low temperature pyrolysis stage formanufacturing charcoal. Indeed the Choren Carbo-V gasifier undertakes this reaction within the process,thereby utilising the energy value of both the volatile carbon that is evolved in a pyrolysis step and thefixed carbon (charcoal) in an entrained gasification stage – see Figure 5.3. The heat of the gasificationreaction in a gasifier is provided by the oxidation of part of the fuel, and in an entrained flow gasifier theprocess is blown with oxygen rather than air. This is essential if it is required to minimise the nitrogenlevels in the syngas, a condition in SNG production that becomes paramount because it is very difficult(i.e. costly) to separate nitrogen from the SNG later in the process train.35 Olofsson et al, “ Initial Review and Evaluation of Process Technologies and Systems Suitable for Cost-EfficientMedium-Scale Gasification for Biomass to Liquid Fuels” (2005)34

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFigure 5.3Choren Entrained Flow Gasification systemIt will be readily appreciated that the pyrolysis and entrained flow gasification steps combine to create arelatively complex plant, albeit one that is technically demonstrated at a significant scale by Choren. Atthis point it should be appreciated that the principal aim of entrained flow gasifier concepts has been toproduce a good quality synthesis gas – a mixture of carbon monoxide (CO) and hydrogen (H 2 ) – and topresent these in a CO / H2 molar ratio that subsequently allows the efficient synthesis of more complexmolecules from these basic building blocks of organic chemistry. An efficient entrained flow gasifier willproduce very low levels of methane in the synthesis gas; methane production requires therefore theconversion of synthesis gas via a methanation step. This consumes energy and is seen by some SNGtechnology developers as a reason to pursue alternative gasification processes that provide a syngasoutput that maximises the methane content of the syngas as it is produced from the gasifier.Fluidised bed gasifiers. Fluidised bed gasifiers exhibit a number of variants – bubbling beds, circulatingbeds, indirect and direct heating, pressurised and un-pressurised, air blown or oxygen blown. Thecommon feature of fluidised bed gasifiers is that they provide a hot aerated bed of granular solid materialinto which the granulated fuel is injected. The fluidised bed provides a ”thermal flywheel” whereby heattransfer from the hot bed material is sufficient to dissociate the fuel into volatile components (syngas) andash. The gases are evolved from the top and the ash from the bottom. Conventionally, the heat of thebed is maintained by burning part of the fuel in the bed itself and the products of combustion (water andsome carbon dioxide) are evolved with the syngas.35

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFigure 5.4Fluidised Bed gasifiers (Direct and Indirect)When the intent is ultimately to produce pipeline quality SNG it becomes necessary to use pure oxygenfor the gasifier in order to eliminate nitrogen from the resulting syngas, however, the cost of theassociated air separation unit that produces the oxygen represents a considerable burden on the planteconomic case. This has provided the incentive to develop new fluidised bed concepts in which the plantis configured in such a way as to allow air firing to heat the bed material outside the gasification reactor –the so called indirect fluidised bed gasifiers. Indirect fluidised bed gasifiers also tend to produce asignificant quantity of methane in the syngas, however, it must be appreciated that indirect gasifiers arestill in development. To the extent that the syngas can be produced with a significant methane contentthis represents a potential improvement in overall fuel energy conversion efficiency. The quest for asignificant methane content in the syngas has informed research and development into new gasificationconcepts, notably indirect fluidised bed systems. These have the potential to achieve methane in syngaslevels in excess of 10%, thereby offering the promise of slightly improved overall SNG yields 36 . It shouldbe appreciated, however, that methane produced in this way does not come alone; it is accompanied byother longer chain alkanes and with a higher level of tars in the syngas. These need to be removed fromthe gas stream and represent in their own way a potential energy loss from the system.High pressure operation also favours the direct production of methane in the syngas, and there is alreadysome experience with the operation of pressurised fluid bed gasifiers such as the high temperatureWinkler process or HTW. The HTW gasifier has operational experience co-firing waste derived fuels withpure biomass and at pressures of 30 bars at which a methane-in-syngas level of 8% (dry basis) can beachieved.36 This is because 10% of the gas production does not need to be converted to methane via the exothermiccatalytic reactions required to reform synthesis gas – CO and H 236

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTThe choice of a gasification technology therefore hinges around these variants:The use of an entrained flow gasifier fuelled by torrefied biomass 37An oxygen blown fluidised bed 38An oxygen blown pressurised fluidised bed 39The selection of the Choren Carbo-V gasifier, or similar (N.B. oxygen blown)An indirect fluidised bed 40 .These process choices are nevertheless uninformed by any commercial considerations. The use ofwaste-derived fuels, even in co-firing with clean biomass has a significant and beneficial effect on theoverall cost effectiveness of Bio-SNG production. This is a strong incentive to select a gasificationtechnology that can accept waste-derived fuels; hence process selection is biased towards the choice offluidised bed gasification; entrained flow gasifiers being unsuited to such fuels.In identifying a development pathway for the production of Bio-SNG Progressive Energy is inclined to theview that selection of an indirect gasifier technology may not be an optimal course of action. Firstly thepossible prize, a slight increase in the overall efficiency of SNG production, may be insufficientjustification for delay in securing a market position that may arise from the relative novelty of thistechnology. Secondly, efficient heat recovery from the gasifier and gas processing train can be used tocreate non-fossil electricity which as an output is at least equal in value to Bio-SNG. Table 5-1illustratesthe key factors in this judgement where real world deliverability needs to be set against the theoreticalbenefits of yet to be realised technical developments. Process choice, therefore should favour an oxygenblown fluidised bed, and perhaps, if commercially justifiable the pressurised 41 oxygen blown fluidised bedgasifier, such as the HTW or pressurised HTW.There will be some variability of the syngas quality produced by the gasifier options discussed brieflyabove, notably with respect to the tar loading in the raw syngas; with an entrained flow gasifier offeringthe best quality on account of the intrinsically higher temperatures reached in such reactors. This is anadvantage but not necessarily a decisive advantage over fluidised bed systems; the gas cleaningprocesses downstream should, in any event be designed to cope with a range of syngas qualities.Beyond considerations of tar loading in the synthesis gas the next most sensitive issue for Bio-SNGproduction is the presence of nitrogen. Nitrogen can be produced through fuel-bound nitrates and via theresidual levels of nitrogen to be found either in oxygen used in the gasifier or via the circulating bedmaterial within an air-blown indirect gasifier. In either case, a small amount of nitrogen passing through37 Potential suppliers / technologies here include Udhe / Prenflo gasifier, and Choren entrained flow gasifier38 Potential suppliers include Foster Wheeler, and Thyssen / HTW, Enerkem39 Potential supplier would be Thyssen / pressurised HTW40 Potential supplier Austrian Energy / indirect CFB, future development of indirect fluid bed by ICN.41 It is more energy efficient to compress SNG than syngas and water vapour, therefore the process pressure ismost efficiently provided by high pressure gasification, followed by further SNG compression for export.37

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTthe system could reduce the Wobbe Index or Calorific value of the resulting Bio-SNG below the GS(M)Rlimits for pipeline quality. This is a key issue that would require resolution as part of the selection andspecification process for a gasification technology.ApproachNo penalty for oxygenproductionMethane content ex gasifierProven at substantive scaleDeployable at moderatescaleDeployable at large scaleFuel preparationTrack record on waste fuelsOptions to minimisepressurisation loadsTars ex unitChemical ContaminationIndirect gasification - -Direct gasification(fluidised bed) -Entrained flowPyrolysis to bio-oil - - Table 5-1Technical ideals and commercial realityGasification of wastes: It should be appreciated that for a considerable period of time the pursuit of thegasification of wastes has been focussed in the main not on the production of a quality syngas but inpursuit of the following:To assure destruction of hazardous chemicals at extreme temperaturesTo produce fused ash streams in which heavy metals may be trappedTo take advantage of particular support mechanisms (e.g. the Renewables Obligation)In an attempt to give lower emissions to the environment than conventional waste incinerationAccordingly it is important to understand that the technologies that are targeted at these objectives arenot necessarily focussed on the efficient production of a high quality syngas, which would be the overridingobjective of a gasifier producing syngas for Bio-SNG synthesis. Hence waste gasification systemsare in general unsuitable for this application. The HTW gasifier has, however, a track record of successfuloperation with waste-derived fuels 42 . Relevant examples of gasification projects are shown in Appendix1.42 The British Gas -Lurgi (BGL) fixed bed slagging gasifier at Schwartezepumpe had also some considerableoperating experienced with waste derived fuels, but only when co-fired with >70% coal.38

Contaminent mg/Nm3 gasContaminent mg/Nm3 gasBIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT5.3 GAS PROCESSINGSyngas processing requirements are determined by the gas quality limitations imposed by catalysts usedin the methanation reaction. The methanation reactions are moderately exothermic and simplyrepresented as follows:CO + 3H2 → CH4 + H 2 O - 217kJ/mole…………………… (1)C0 2 + 4H 2 → CH 4 + 2H 2 0 - 175kJ/mole……………………. (2)The reaction takes place at elevated temperature over a catalyst, for which there are a number of materialoptions including nickel, iron, chromium and copper based catalysts, however, these are invariablyintolerant of even traces of heavy metals such as mercury, lead and arsenic and intolerant of smallparticles of tar, or of sulphur and chlorine compounds. The main technical challenge posed by an SNGfacility is therefore the syngas cleaning that is required upstream of the methanation reactor.Figure 5.5shows the practical scale of syngas quality improvement that must be achieved to enablesatisfactory catalyst life to be achieved.30002500Raw Engine Synthesis1614200012101500810006450020Tars Particulate Sulphur Halides0Tars Particulate Sulphur HalidesFigure 5.5Syngas quality ex-gasifier, requirement for use in engine and for synthesisState-of–the-art gas processing technologies are capable of achieving the necessary syngas quality, thechallenge being to do this economically on a process plant of relatively modest scale and at a reasonablelevel of energy efficiency. The syngas leaving the gasifier will be at temperatures around 900 0 C and willcarry therefore a significant amount of sensible heat; this should be recovered efficiently for thegeneration of steam for use in the process and for power generation to meet plant electricity demand.39

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTHeat recovery from the hot syngas is straightforward, however, at temperatures below 300 o C tars begin tocondense with the consequent risk of fouling, therefore direct heat recovery from the syngas should beterminated at this temperature. Most gas cleaning techniques will require the syngas to be at a moderatetemperature, hence heat recovery and process re-heating form an important part of the process traindesign.Contaminant removalNon-volatile particulates (ash and char) should be separated by means of conventional processes suchas cyclones and hot gas filters at a temperature above the tar dew point, in order to avoid fouling withcondensing tars. Thereafter syngas cleaning would most probably involve gas scrubbing in contact with aliquid scrubbing medium. Conventionally syngas scrubbing would be via water based systems wherebygas/water contact removes fine particulates and tars and provides a medium for the neutralisation andabsorption of incidental products of gasification such as HCl and ammonia.Importantly, the gasscrubbing system needs to reduce the syngas temperature below the dew point of the lightest tarfractions; this will also remove mercury vapour from the gas. The use of water based systems, however,creates a large water demand, and a significant water treatment and waste water discharge burden. Oilbased syngas scrubbing techniques have been developed which can give effective tar and particulateremoval thereby offering the opportunity to reduce the significant penalties associated with tar scrubbingvia water-based scrubbing systems. Following the core gas scrubbing operations it will probably benecessary to undertake further syngas cleaning steps to achieve the gas purity levels demanded by thecatalysts. This is a subject for detail design and specification to be derived via discussions with the gasprocessing contractor and catalyst suppliers, but will involve guard filters and beds to polish the gas andguard against process upsets.Hydrogen / Carbon Monoxide Molar Ratio adjustmentDepending upon the performance of the gasifier and the chosen process configuration it will be necessaryto introduce a processing step to adjust the ratio of carbon monoxide to hydrogen in order to arrive at afavourable molar ratio of hydrogen to carbon monoxide for the methanation reaction (Equation 1) above.This is conventionally undertaken at high temperature over a catalyst (the water gas shift reaction) forwhich similar gas quality criteria would apply as for the methanation reaction itself; however some WGScatalysts are tolerant to sulphur. Given that the syngas will contain a level of hydrogen sulphide producedin the gasifier, and which would not be removed in the upstream gas cleaning process it is proposed thata sour WGS catalyst should be considered for incorporation into the design 43 . In the water gas shiftreaction carbon monoxide in the syngas is reacted with steam to produce hydrogen and carbon dioxide:CO + H 2 O → H 2 + CO 2 ………………………………(3)43 It should be appreciated, nevertheless, that not only are sour shift catalysts tolerant of hydrogen sulphide, theydo in fact rely upon a certain level of hydrogen sulphide in order to work. The threshold value of hydrogensulphide is 100ppm(v), a level that can readily be obtained with the sulphur levels existing in biomass or wastederivedfuels. Nevertheless the fuel specification needs to ensure a certain minimum level of sulphur if a sour shiftcatalyst is employed.40

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTIt will be readily appreciated that the water gas shift reaction can be used to trim the relative CO / H 2concentrations in the syngas. The water gas shift reaction is strongly exothermic and the heat of reactioncan be used to assist in returning the syngas to the temperatures required for the methanation reaction totake place – in the range 600 0 C >300 0 C.Following the WGS the syngas would have the appropriate molar balance for the methanation reaction.Some methanation process configurations however combine the shift and methanation catalytic reactionswherein simultaneously with the occurrence of the shift reaction in the combined reactor system, carbonmonoxide and hydrogen are converted to methane and water. Steam formed by the methanation reactionpromotes the shift reaction to in turn, produce the hydrogen necessary to carry out the methanationreaction. Elegant though this process arrangement appears to be, any hydrogen sulphide in the syngaswill poison the methanation catalyst. It follows that the hydrogen sulphide must be removed from thesynthesis gas following the WGS reaction and before methanation.Removal of H 2 S and CO 2:There are several proprietary systems for removal of either of these gases, however, a single processthat could remove both would be based upon physical absorption via e.g. a tertiary alcohol or aproprietary solvent such as Selexol or Rectisol. Given the sensitivity of the downstream methanationcatalyst to sulphur poisoning it may be necessary to specify a multistage system. Depending upon thevendor‟s guaranteed performance it would be prudent to incorporate a solid state (ZnO) scrubber to guardagainst any residual carry-over of H 2 S.In principle the separated biogenic CO 2 could be vented to atmosphere without incurring any GHGpenalty, however, subject to the development of appropriate industrial infrastructure it would be prudent toconsider the scope for compression and export of this gas for geological storage or enhanced oil recovery(EOR).The capture of small amounts of H 2 S represents a considerable nuisance as well as a hazard.With sulphur levels as they are in biomass fuels there is insufficient sulphur to warrant a conventionalelemental sulphur recovery plant such as the Claus process so it may be appropriate to incorporate abiological system such a Thiopaq for the recovery of elemental sulphur. (This is a particular example of acase where development at a moderate scale imposes economic burdens on the process. It is also anexample of why it is necessary to specify and control the properties of the fuel that can be accepted intothe plant.)5.4 METHANATIONMethanation of syngas is an established process, and is not specific to bio-gases, nevertheless theoptimisation of the process design with respect to energy efficiency (esp. heat recovery and minimisingcompression power) will be a significant process engineering exercise. Conventionally the methanation41

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTreaction will take place over a three stage process in cylindrical vessels packed with 6mm diametersintered catalyst beads. Flow in the reactors may be radial or axial, but the critical design consideration isthe control of heat release in the catalyst bed in order to prevent catalyst de-activation at hightemperatures that may be obtained through the exothermic reaction. Catalysts may also be deactivatedby sulphur and chlorine compounds and by a low carbon monoxide to hydrogen ratio leading to elementalcarbon deposits. The methanation of synthesis gas will consume approximately 20% of the energypotential of the gas, hence it is vital to ensure efficient recovery and use of this energy.Process intensificationProcess intensification holds the promise of achieving in small facilities the economies of scale normallyassociated with large industrial facilities. A notable development in this area is the micro channel FischerTropsch reactor that has been developed by Oxford catalysts for the synthesis of higher alkanes from anatural gas feedstock, following steam reformation and WGS. The viability of this process at moderatescale results from the significant reduction in the number of process vessels and heat exchangers, pipingand controls required, along with the high reaction rates and efficient heat recovery afforded by the microchannelconcept. Discussions with Oxford catalysts established that there is every reason to expect thatthe micro-channel reactor concept could be effective in the production of Bio-SNG.The proof anddemonstration of this, however, would entail considerable expense and a development programme of atleast two years. A balanced judgement therefore would be that the micro-channel reactor may well havesome merit for a future application, but in the meantime the use of conventional catalytic reactors isfeasible and carries no serious economy of scale disadvantage when deployed in a moderately sizedfacility. Finally, micro channel reactors are likely to be even less tolerant than conventional catalytic bedsof contaminants in the gas stream.5.5 GAS CONDITIONING, COMPRESSION AND METERINGThe Bio-SNG emerging from the methanation process will be saturated with water vapour and contain asmall amount of un-reacted hydrogen and of elemental nitrogen that originates from the 98% pure oxygenused to fire the gasifier and from fuel-bound nitrates. The achievement of pipeline quality gas would allowa small proportion of nitrogen, provide that the gas was substantially free from other inerts, apart from theinevitable loading of noble gases (He, Ar etc.). The optimisation of process design must include anassessment of the balance of advantage to be struck between the required level of oxygen purity, thelikely levels of fuel bound nitrogen and the possible propane dosing requirements that might be requiredto achieve the GS(M)R specification requirements for Wobbe Index and Calorific value.The methanation process will not achieve 100% conversion of the hydrogen from the syngas and is likelyto exceed the GS(M)R pipeline specification regarding hydrogen content (

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTpipeline gas, or by membrane separation; however, it is suggested that the specification should bequestioned to see if a slightly higher hydrogen content could be accepted.Compression to export pressure will depend upon where the gas is to be injected (National grid and/orthe LDZ). Clearly, on account of the energy requirements associated with compression, the lowestpressure option will give the greatest process efficiency. This could be a significant feature of Bio-SNGplant location. Before the Bio-SNG could be exported via the gas network it would require odorising.On account of commercial uplifts that would be necessary to make Bio-SNG viable, fiscal quality meteringwill be required along with sampling and quality assurance for biogenic carbon content. Where wastederivedfuels have been used then the only practical method of the determination of the proportions offossil / bio carbon is via a method based upon C 14 . The fundamental principles of this technique arecurrently under a process of accreditation with Ofgem in connection with electricity generation frombiomass.5.6 CONCLUSIONS ON PROCESS AND TECHNOLOGYThe following key conclusions can be drawn:Systematic understanding and control of fuel properties is vital.Bio-SNG can be produced from existing state-of-the-art process plant; the main technical riskbeing associated with first-of-a-kind process integration issues. This becomes then a riskmanagement and project finance challenge rather than an RD&D exercise.Indirect gasifiers may give a marginally greater direct production of methane (>10% cf

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT6 Economic AssessmentUsing best available information, the economic profile of bio-SNG projects is considered. Evaluation ofprocess economics is critically dependent on input assumptions. This builds on the technical review,along with a perspective on costs and impact of existing, and proposed incentives. Plant economics forsuch capital intensive processes are dependent on the state of the market, and costs associated with risktransfer for equipment supplied under EPC contract structures. Similarly, the emergent state of thebiomass market supply chain, along with competitive uses, means that biomass fuel resources will bevolatile. Therefore appropriate sensitivity analyses are undertaken. Against these scenarios, the potentialproject returns are evaluated. This review also compares (at a high level) the returns for a gasificationfacility producing power.This analysis assesses the cost of carbon abatement via this route, when compared with alternative directuses of biomass for heat and electricity as well as other carbon abatement approaches.6.1.1 Scale and operational assumptionsTwo representative scales have been assessed; a small, demonstration scale facility requiring ~100,000te pa of feedstock and a larger commercial facility of requiring ~600,000 te pa . These are outlined inTable 6-1. It is assumed that the process operates at a pressure which matches grid injection such thatdownstream compression requirements are limited. Here it is assumed this would be 20bar, so would besuitable for intermediate or high pressure distribution level injection but not NTS without furthercompression. This assumes therefore that the gasifier operates at the appropriate pressure to account forpressure drops in the gas processing train (typically ~20% from gasifier to exit of methanation reactor, iegasification at ~26bar)Whilst the facility does generate electricity recovered from the high grade heat, at the assumed SNGefficiency, the heat suitable for power production is assumed to compensate for the parasitic loads,including the ASU load (separation, oxygen compression) and sufficient CO2 compression for lockhopperinert blanket. In the event that an indirect gasification configuration is used, there would be noASU load, although it is likely that the system would operate at low or atmospheric pressure, thereforeimpose syngas compression loads. Therefore it is assumed in either case there is no excess electricity forexport.44

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTParameter Small LargeInputEnergy rating (energy per hour) 50MW th (180GJ/hr) 300MWth (1080GJ/hr)Input fuel energy per annum 0.4TWh th (1.3PJ) 2.4 TWh th (8.6PJ)Biomass fuel (pellets, 16GJ/te) pa 81,000 te pa 486,000 te paBiomass fuel (Woodchip, 13GJ/te) pa 100,000 te pa 600,000 te paSolid Recovered fuel (18GJ/te) te pa 72,000te pa 432,000 te paOperation Load factors (hrs pa) 7200 7200Baseline Efficiency to SNG 44 65% 65%OutputBio-SNG MWth 32.5MWth 195MWthBio-SNG GJ/Hr 117 702Bio-SNG therm/hr 1110 6,650Bio-SNG Nm 3 /hr 3330 20,000Bio-SNG energy per annum 0.23 TWh th (0.84PJ) 1.40 TWh th (5.05PJ)Equivalent Households ~15,000 ~100,000Equivalent Passenger Vehicles ~25,000 ~150,000Comparative Electrical facility (no SNG) 12MWe (24%efficiency assuminggas engines)Table 6-1 Project scale and output assumptions6.1.2 Investment Cost assumptions90MWe (30% efficientbased on an IGCCconfiguration)As discussed previously, there are currently no commercial scale Bio-SNG facilities in operation, andthere is only a limited number of biomass gasification facilities which create a syngas of sufficient qualityfor catalytic conversion, with still fewer operating on waste derived fuels. Therefore investment costassumptions are estimates, however these are sufficient to enable an understanding of the economics ofthe process, given that even estimates from suppliers are only +/-30% after a formal engineering study.The following investment costs are dominated by the capital costs of the materials handling, gasifier, gasprocessing, methanation and conditioning for injection. The costs also allow for utilities and services,including grid/gas connection and indirect costs (design, development, constructionmanagement/commissioning and contingency).The cost of performance guarantees being provided by an EPC cannot be readily ascertained at thisstage, as they will depend on both the detailed requirements of the funder, and also the EPC‟s appetitefor the sector combined with the ability to cascade the guarantees down the supply chain. Suchguarantees would form part of detail project negotiations, and are not included here. Final out-turn costsare a function of the final design, the financing route and cost of risk transfer as well as general economicissues including exchange rates, appetite for an EPC contractor to undertake the work and competitionfor supply in a sector with an immature supply chain. The cost estimates below are developed using thea range of data sources:44 Based on Pellets or SRF. Where the fuel has higher moisture content (eg woodchips, modelled here at 25%), thetotal efficiency can be higher when low grade waste heat is utilised to pre-dry the fuel prior to gasification. 65% isconsidered a credible conversion efficiency using existing gasifier and methanation combinations.45

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTChorenChoren has a 50MWth (input) facility operating in Freiburg (shown in Appendix 1). This is based on anentrained flow gasifier reconfigured for operation on 100% biomass (woodfuel). This facility is designed tomanufacture Syngas for conversion to BTL in a Fischer Tropsch reactor. The gasification train for thisfacility has been completed and operated, with the F-T stages undergoing commissioning since mid 2010.This is a facility which must provide a similarly high level of contaminant-free syngas to that demanded byBio-SNG. Choren estimate that the total investment for a 50MWth facility to produce hydrogen to be67MEuro (£56M) 45 . Whilst this is clearly only an estimate, their experience at Freiburg will valuably informthis figure, and it is a sound basis for the current cost for an entrained flow wood gasification system toproduce high quality hydrogen. Choren indicated an assumption that a Bio-SNG facility would be90MEuro (£75M), although they have no direct experience on this processing stage. Progressive Energyis of the view that this addition for a methanation reactor is probably overly conservative, given that theHydrogen system will already have full shift reactors, sulphur removal, CO2 removal, and a high qualitysyngas stream.GobiGasThis facility is being built in two phases, both fuelled by wood pellets. The first phase is 32MWth (input)based on indirect gasification (Repotec technology as used in Gussing), costing £75M (based oncontracting in 2010 for completion in 2012), although this is integrated with a district heating system. Thesecond phase at ~120MWth (input) designed to produce 80MWth Bio-SNG is anticipated to cost £150M,but is not expected to commence build until 2015.EnerkemEnerkem is one of the few gasification companies successfully pursuing the gasification of waste using afluidised bed gasifier, to syngas of sufficiently high quality to convert catalytically to a biofuel. They havea small scale (8MWth) facility fuelled by waste wood and are currently developing two municipal wastefacilities at 50MWth in Edmonton, Canada and Mississippi, US (shown in Appendix 1). These arereported to cost $CAN80M (£50M) and $US140M £88M) respectively, with the latter encompassing theMSW pre-processing facility from raw waste. Whilst the outturn product is bioethanol, and not Bio-SNG,both processes demand high quality, preconditioned syngas and catalytic reactor stage, and therefore thecosts are anticipated to be similar to that expected for a Bio-SNG plant.The assumed investment cost for a 50MWth plant is ~£65Million (2010) for a wood based facility. Theexperience with waste gasification is even more limited, and different facilities often have substantiallydifferent design intents (waste destruction through to efficient energy recovery). However, there are anumber of reasons why waste gasification is more challenging; the fuel is heterogeneous and thereforemay need enhanced material handling; the nature of waste imposes requirements on the gasification unititself; the fuel contains a wider range of chemical contaminants and therefore the gas processing must45 Choren, Personal correspondence, June 201046

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECThandle this 46 ; the risk margins demanded to cover the reduced experience. Therefore, for this analysis itis assumed that a waste-based system (assuming offsite preparation of the MSW to SRF) will cost 15%more than the pure biomass one, ie £75Million (2010). For a 300MWth (input) facility, the assumedinvestment cost is £215M and £250M, for pure biomass and waste fuel facility respectively. Figure 6.1shows the breakdown of costs for such a facility. Given the nature of these estimates, it is important toundertake a sensitivity analysis of at least +30% in the downside case, recognising both theunderestimate in the baseline figures, and also the requirement for provision of performance riskmanagement within an EPC. It must be noted that whilst „learning‟ is often cited as a reason thatsubsequent projects achieve a lower cost, Progressive is of the view that in novel projects such as these,initial costings on early projects (ie prior to build) are typically underestimates of the final outturn costs,negating any learning effect on early follow-on projects. At this stage it is presumed that the project willnot be leveraged at the outset (although there may be opportunity for refinancing after a track record ofsuccessful commercial operation). The build time is assumed to be 3 years in both cases, although it maybe feasible to construct the smaller facility in a shorter period of time given substantial offsite manufactureof components.Assumed investment cost Small (£000) Large (£000)Energy rating (energy per hour) 50MW th 300MWthPure biomass £65,000 £215,000Waste Fuel £75,000 £250,000Table 6-2 Investment cost assumptionsIndirects &ContingencySolid handling& PrepUtilities,services,connectionsGasificationMethanation,ConditioningSyngasprocessingFigure 6.1 Cost breakdown of major components (Large SRF facility)46 Recognising however, that the most challenging part of the gas processing is not the bulk contaminant removal,but the final ppm and ppb removal demanded by the catalysts, which is common to both biomass and waste fuels)47

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT6.1.3 Operating Cost assumptionsThe basic cost assumptions are shown in Table 6-3, based on industry norms and specific informationrelating to the feedstock type. The capital cost assumptions have assumed oxygen is supplied „over thefence‟, although in line with the efficiency assumptions, it is presumed that power is supplied FoC to theprovider (ie no benefit is taken on the revenue side from power generated). This may not be the out-turncommercial configuration, but ensures that the oxygen cost base is fully accounted for.Costs £000s Small (£000) Large (£000)Fixed costsLabour,MaintenanceInsuranceLand LeaseRates, permitting, Monitoring, ConnectionsTotal£1,000£1,300£400£100£500£3,300£1,000£4,300£1,300£200£1,500£8,300Oxygen (over the fence with powersupplied FOC)£650£25/te exclpower (3.5te/hr)£2,300£15/te excl power(21te/hr)Consumables £250 £1,000Consumables SRF £500 £2,000Disposal costs biomass £0 £0Disposal costs SRF £600£40/te & 15,000te pa (20% ash)£3,600(£40/te & 90,000te pa (20% ash)Total Biomass £4,200 £11,600Total SRF £5,050 £15,200Table 6-3 Operating Cost assumptions6.1.4 FeedstockSRF Woodchip Pellet18 GJ/te60%energy Bio13 GJ/te100%energy Bio16 GJ/te100%energy Bio-£27/te £65/te £112/te-1.5 GJ/te 5.0 GJ/te 7 GJ/teTable 6-4 Feedstock Assumptions48

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTThe biomass feedstock assumptions are shown in Table 6-4. These figures are based on a variety ofsources:The SRF data is based on knowledge of the industry for contracting SRF of this type of biogenic content.This is fuel which has been processed using biological drying. It must be noted that an SRF produced viaautoclaving would have a high biogenic content, but the energy penalty and therefore cost of processingwill be significantly higher.Woodchip. There would probably need to be an onsite drying facility for woodchip, which would entailadditional investment cost, opex and electrical loads, although it is possible to use low grade heat fordrying which might not otherwise be usable. However assuming a fuel price based on energy content(NCV), the additional drying using otherwise wasted heat is increasing the relative efficiency of the facility.In this analysis, this is assumed to compensate for the necessary drying investment and operationalcosts. The price assumption in Table 6-4 is from DECC‟s biomass fuel cost for large scale fuelgenerators, produced for the RHI evidence base 47 .Pellets command a significantly higher price than woodchip; this is a function of both the higherprocessing cost (energy required for drying to 10% moisture at the point of manufacture, along with theelectrical loads for hammer-milling and pelletising) as well as the enhanced out-turn product value due tothe enhanced fungibility compared with woodchip). .Again figures are taken from DECC‟s analysis.Waste wood may offer an alterative, feedstock, having a biogenic content of ~90% by energy. The plantwould need to handle contamination with the same degree of robustness as the SRF facility, andtherefore would need to assume the same capital cost as the SRF facility. However, the ash disposal costwould be lower. Initially the cost of the feedstock would be substantially lower than virgin biomass,potentially at zero cost or even with a small gate fee. However the expectation is that feedstock costwould increase substantially over time as demand for biomass increases and biomass combustionfacilities are constructed with the capability of co-firing waste wood with pure biomass. Securing wastewood of this quantity would be challenging. Therefore, whilst this could be a useful interim fuel, it has notbeen assumed as a base-case fuel.The DECC analysis does not provide predicted outturn prices for bulk biomass for 2020, althoughinterestingly for biomass heating applications, biomass prices are assumed to decrease relative to fossilfuels over a 2020 time frame. This is unlikely. In this analysis it is assumed that the escalation forbiomass is the same as for natural gas. This is a rationale assumption since the price will reflect, as aminimum the fuel which is being replaced. Arguably as the price of carbon impacts then the value of lowcarbon fuels may even increase faster than higher carbon intensity fuels.47 Biomass prices in the heat and electricity sectors in the UK For the Department of Energy and Climate ChangeJanuary 2010 Ref: URN 10D/546 (Feb 2010)49

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT6.1.5 Revenue AssumptionsThe Level of the RHI is yet to be formally determined, but the February 2010 consultation documentindicated a value of £40/MWh for biogas injection. It has been mooted that this figure may rise to£50/MWh although this is uncertain, so is considered as a subsequent sensitivity case.As discussed, in this analysis, it is assumed that there is no residual power after servicing parasitic loads,including oxygen demand but there will be low grade heat. However, it cannot be assumed this can besold in significant quantity, so is not considered in the base case. The impact of such sales, are howeverexplored as a sensitivity to the outturn price of Bio-SNG6.2 LEVELISED COST ANALYSISA levelised cost analysis has been carried out using these assumptions to determine the cost of Bio-SNG.The base case discount rate has been assumed to be 12% 48 , with and a three year build. The costs areall (2010 prices) and are shown real, and assume no escalation over RPI for each component. DECCJune 2010 data indicates a 2010 natural gas wholesale price of 59p/therm. The charts below show amore realistic current band of natural gas prices of 40-60p/therm.This analysis demonstrates that without the RHI, at the scales considered, Bio-SNG will not be feasible.The disparity between the Bio-SNG cost and the wholesale Natural gas price is significant.With the RHI, this analysis demonstrates that at the small scale, it is uneconomic to produce Bio-SNGrelying only on the slated RHI support level of £40/MWh. For a project of this scale RHI support wouldneed to be at least twice as high for the Bio-SNG to be competitive with natural gas. Alternatively, capitalgrant support would need to be of the order of £35-45Million for either the SRF or woodchip facility to becompetitive.At the larger scale, and with the currently proposed RHI support level, the SRF fuelled facility looks to becompetitive with natural gas, and if woodchip could be sourced at 5/GJ the cost of bio-SNG from importedand indigenous woodchip could be close to competing at the upper band of gas prices. Operation onwood pellets looks to remain uncompetitive even at this scale.By way of comparison, this is not dissimilar from analysis of bio-SNG in the RHI documentation presentedby NERA (February 2010), after accounting for the increased scale in the NERA analysis, and combinedbiomass-waste fuels.48 In reality an early project would demand a higher discount rate reflecting the risk profile (maybe up to 15%, buta mature technology might allow a lower discount rate say ~10%.This is also a function of the investors appetitefor risk in evaluating investment.50

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTIt must be noted that this analysis is a calculation of the levelised cost at a discount rate of 12% in orderto calculate an out turn cost of Bio-SNG. For an investor to have the appetite to invest, then there must bea sufficiently attractive return. From this analysis it is clear that the only case which could have sufficientscope for project return is a facility fuelled by SRF. On the assumption set given here, such a facilityprovides a pre-tax unleveraged return of 14.5% to 17% for gas prices of 40 to 60p/therm respectively.However, whether this is a sufficient return to entice investment depends on the risk profile, itsmanagement and perception of ability to secure debt on refinancing in order to enhance the project value.51

Net cost of Bio-SNG (p/therm)Net cost of Bio-SNG with RHI at £40/MWh (p/therm)BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT330300SmallLevelised Cost of Bio-SNG Without RHILarge2702402101801501209060300Figure 6.2330300TypicalNatural Gas prices rangeSRF Woodchip PelletLevelised Cost of Bio-SNG With RHI at £40/MWhLevelised Cost of Bio-SNG without RHI (p/therm)Small Large2702402101801501209060300Figure 6.3TypicalNatural Gas prices rangeSRF Woodchip PelletLevelised Cost of Bio-SNG with RHI at £40/MWh (p/therm)52

Net cost of Bio-SNG without RHI (£/MWh)Net cost of Bio-SNG after assumed RHI (£/MWh)BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT110100SmallLevelised Cost of Bio-SNG without RHILarge9080706050403020100Figure 6.4110100TypicalNatural Gas prices rangeSRF Woodchip PelletLevelised Cost of Bio-SNG without RHI (£/MWh)Levelised Cost of Bio-SNG without RHISmall Large9080706050403020100Figure 6.5TypicalNatural Gas prices rangeSRF Woodchip PelletLevelised Cost of Bio-SNG with RHI at £40/MWh (£/MWh)53

Cost per MWh (£/MWh)Cost per MWh (£/MWh)BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT6.3 SENSITIVITY ANALYSISThe figures below show how the levelised cost is made up for the large scale project.70Levelised Cost Breakdown Large SRF facility6050403020Bio-SNGIncentiveFuelOpexCapex100Figure 6.6 Levelised Cost Breakdown for Large SRF fuelled facility (RHI at £40/MWh bio)70Levelised Cost Breakdown Large Woodchip facility6050403020Bio-SNGIncentiveFuelOpexCapex100Figure 6.7 Levelised Cost Breakdown for Large Woodchip fuelled facility (RHI at £40/MWh bio)54

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFigure 6.6 & Figure 6.7, show the cost breakdown (£/MWh) for the large facilities. When fuelled bywoodchip, the capital cost and the biomass costs are both similar, and dominate over the operationalcost. At £40/MWh, the RHI is substantially more significant than either the capital or feedstock elements.When fuelled by SRF, the capital cost dominates, since the fuel is no longer a cost but provides a smallcontribution to the revenue stream. In this case, the lower biogenic fraction reduces the value of the RHI,and although this is still an important factor in viability, the SRF case will be slightly less sensitive to theabsolute level of the RHI.6.3.1 EscalationThe above analysis is “real” and considers 2010 gas prices. In the future, gas prices are likely to escalateat a different rate from inflation, as may biomass prices. In its analysis for the RHI (February 2010)DECCdoes not attempt to consider wholesale biomass prices out to 2020 for the purposes of large scale powergeneration “The prevalence and preference for long term contracts, with companies establishing bilateralcontracts with suppliers, makes it difficult to establish a clear relationship between price and feedstockcosts. There are also far more feedstock types, and fewer generators in the electricity sector, hence atypical supply chain could not be constructed. Furthermore, it is more uncertain how this sector willdevelop in the future.”Progressive Energy is of the view that biomass prices are likely to move at least in line with natural gas(and may possibly increase faster if the pressure on biomass resources increases both in the UK andinternationally). This does conflict with the prevailing DECC view which believes biomass will becomecheaper relative to natural gas. Clearly DECC‟s position would indicate a long term decrease in Bio-SNGoutturn cost compared with prevailing gas prices, and therefore improvements in the economic outlook fora project.However, even if biomass prices were to increase in line with natural gas, and other costs were to remainconstant, the price of SNG would reduce relative to natural gas since the feedstock only represents ~50%of the production cost. For example, using DECC‟s central case, natural gas is believed to increase by15% by 2020 (in real terms) to ~68p therm. This would result in only an ~8% increase in the Bio-SNGprice ie 67p/therm for the woodchip case. However using DECC‟s “high” case, natural gas wouldincrease by 50% in real terms, resulting in only a 25% increase in the Bio-SNG Cost to 77p/thermcompared with a natural gas price of 97p/therm, ie still improving the economic outlook for Bio-SNG.In reality the non-feedstock costs (investment and operational costs) are also likely to increase to adegree (in light of prevailing energy price increases and an international appetite for low carbon projects),somewhat softening this improvement.55

Net cost of Bio-SNG after assumed RHI (£/MWh)BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT6.3.2 Impact of capital Cost, Opex, Fuel price, RHI and heat sales40.035.0SRFSenstivity Analysis for large facilityWoodchip30.025.020.015.010.05.00.0Figure 6.8Base Capex +30% Opex +30% Fuel +£1.5/GJ Fuel -£1.5/GJ RHI £50Sensitivity analysis for large scale facility fuelled by SRF and woodchip.Capital cost: As shown in Figure 6.8, an increase in capital cost of 30% would be significant for bothfacilities, although as a proportion of the base case Bio-SNG price has a proportionately higher impact forSRF. However, an SRF facility might still provide an acceptable outturn bio-SNG cost, whereas awoodchip fuelled facility would not be feasible at the gas prices considered.Operational cost: this is a less sensitive variable than capital cost, but clearly must be managed.Fuel: For woodchip, +/-£1.5/GJ represents a fluctuation of +/-£19/te or +/-30% around a base case of£65/te. This variation has a significant impact on the outturn Bio-SNG cost. An increase of this levelwould provide a Bio-SNG cost significantly beyond the gas prices considered . For SRF +/-£1.5/GJrepresents a more significant fluctuation of +/-£27/te or +/-100% around a base case gatefee of -£27/te.Whilst this is a sensitive variable, the bio-SNG cost could be viable even in the stress case.RHI: The RHI is a very sensitive variable. Increasing this to £50/MWh would enable projects based onboth feedstock types to attain a competitive outturn Bio-SNG cost on the assumption set indicated, andshould provide sufficient project returns to attract investment for an SRF or SRF-Biomass blend facility.56

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTImpact of heat sales. The sale of heat can provide a cost reduction for the Bio-SNG. Depending on thelevel of RHI assumed for the heat offtake) £16-25/MWth), the biogenic content of the feedstock and thedisplaced heat cost (assumed here to be £20/MWh), for the large scale facility, the impact on thelevelised cost of heat sales range between £0.16-0.23/MWth of Bio-SNG for each MWth of heatdelivered. The recoverable heat potentially available from the large scale facility could be significant,depending on the grade of heat required, but in the case of low grade could be over 50MWth, so thelimiting factor is more likely to be the offtake requirement. For an offtake of 10MWth, this indicates thebio-SNG cost could be reduced by ~£2/MWth.6.3.3 Comparison with an SRF fuelled electricity projectBy way of comparison, an analysis has been drawn up for a small, 50MWth project configured to produceelectricity via gas engines, with an SRF feedstock.For this case, the estimated net output is 13MWe corresponding to a net conversion efficiency of 26%.The capital cost can be reduced as there is no requirement for the water gas shift, the gas processingdoes not need to be undertaken to the same level of contaminant removal and there is a small saving forgenerators compared with the assumed cost for methanation. The total capital cost is assumed to be£70Million. The same operational costs are assumed. The availability is assumed to be somewhat higherat 7600hrs. The build time is assumed to be 24months due to the simpler gas processing and packagedgenerators which allow for offsite production line manufacture, compressing the build out time.Using DECCs 2010 figures for wholesale electricity, consistent with the wholesale gas price of 59p/thermassumed for the Bio-SNG analysis, (£60/MWh) and 2 ROCS (£50/ROC) and 60% biogenic fraction, thepre-tax project return, assuming no leverage is 10% (real). Without carrying the additional costsassociated with pressurised, oxygen blown gasification (not required for reciprocating engine powergeneration only) this return could be further increased. By comparison the Bio-SNG project gives aproject return of

Net cost of Bio-SNG (p/therm) & Electricity (£/MWh)BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTprobably still marginally preferable. However this would require a further level of analysis and costingbased around a specific project to confirm where the relative advantage lay in this case. It must also benoted that there is more international activity based on gasification for power generation, the regulatoryregime and practice for connection is more established, and the RO support mechanism has a longertrack record with investors.LCof Bio-SNG (RHI at £40/MWh) & electricity with 2 ROCs ( £50/MWh200180Small Large160140120100806040TypicalNatural Gas prices range (p/therm) andelectricty price (£/MWh)200Bio-SNG (p/therm)Electricity (£/MWh)Figure 6.9 Levelised cost of Bio-SNG supported by the RHI at £40/MWh and renewableelectricity supported by 2 ROCS as Advanced Gasification based on SRF with 60% biogeniccontent6.4 FINANCIAL CONCLUSIONSFrom this analysis, the following conclusions can be drawnA support mechanism such as the RHI is critical for Bio-SNG – without it, conversion of biomassinto Bio-SNG for the purpose of Grid injection will not happen at any scale using any fuel.With the current assumed support level under the RHI of £40/MWh, a Bio-SNG Project at50MWth will not be viable (on any of the fuels assessed). Either some form of capital grant orsubsidy enhancement is necessary for a small Bio-SNG Project to operate.However at 300MWth the current support level is sufficient to enable competitively costed bio-SNG project, particularly if fuelled fully or partially by a waste derived fuel. This indicates thatthere could be a long term role for Bio-SNG commercially.58

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTThe issue is how to get from the current position to this scale of project in light of the technicaland commercial risks. This is particularly the case if the RHI does not transpire at the currentlyproposed level.Projects configured to generate electricity under the current banded RO regime are commerciallyfavourable at both scales, and particularly attractive at larger scale. A small project generatingelectricity from SRF under the RO regime may offer a development route for Bio-SNG. Byleveraging the mature and favourable electricity support regime a syngas platform could beestablished from which a Bio-SNG project could be developed.In this case, the project may just be acceptable using waste fuels, although it is unlikely that aprivate investor could countenance the risk for this level of reward without a longer termperspective or desire to operate in the sector – and ultimately develop a facility at larger scale.In all cases it is clear that the use of virgin material can only have a limited role, and that the useof waste is vital to maintain the projects commercial integrity. This financial analysis presumesthat the technical issues relating to Bio-SNG production, particularly from waste, can beovercome. The international Bio-SNG projects currently being developed are predicated onbiomass. However, there are a number of international waste-to-syngas projects underdevelopment for both GT/ICE power applications as well as bioliquids. If these succeed, then thetransition to Bio-SNG production presents no obviously insurmountable technical hurdles.The use of waste wood may provide a shorter term development route; the enhanced level ofsupport due the high biogenic fraction offsets the reduced cost of the fuel, and may be slightlyless technically challenging. However, in a market increasingly seeking low cost biomassfeedstock, waste wood is likely to become increasingly valued, particularly for larger projects, andless material is likely to be available.The quantum of investment is significant – even for the development project. In the currentfinancing climate this presents a challenge.59

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT7 Lifecycle carbon emissions and Cost of Carbon Analysescompared with alternativesBio-SNG offers two primary benefits: (a) It is a route to provide a substitute for natural gas - that is it hasa contribution to play in security of supply, and (b) it offers reduced carbon emissions by virtue of the fuelbeing biogenic, and therefore considered renewable.In analysing the latter, it is important to consider (a) the actual environmental footprint taking a wholelifecycle analysis of the different pathways of production (primarily different fuel types) as compared withalternative decarbonisation options, and (b) the cost per tonne of carbon abated by this route comparedwith other decarbonisation options.The cases considered as baseline cases and counterfactuals are:Domestic and commercial heating with counterfactuals of oil, gas, electrical (includingrenewable), direct biomass use and GSHPTransport applications with counterfactuals of petrol/diesel/conventional CNG/electrical vehicles.7.1 LIFECYCLE CARBON EMISSIONSAnalysing the full lifecycle carbon emissions 49 of a process is complex, requiring not only detailedunderstanding of fuel types, process configurations, the emissions profile of the counterfactual cases, andthe methodology for such analysis, noting particularly the role of co-products and how they are valued.Recently North Energy undertook an analysis for the National Non-Food Crop Centre for Bio-SNGproduced from a variety of different routes 50 . The key observations from this analysis are summarisedbelow.North Energy undertook the analysis using two methodologies: (a) based on the UK EA methodologyusing the UK BEAT tool developed in 2008, and (b) based on the requirements of the Renewable EnergyDirective. The key difference between these two methodologies is how „substitutions‟ and „credits‟ aretreated. Inter alia, this encompasses how the carbon savings/penalties of co-products are valued, andhow displaced product pathways are handled – for example what the presumed destination of a wasteproduct would have been, had it not been used for this application, and what the carbon profile of thatdisplaced route is considered to have been. It should be noted that ultimately the UK will need todemonstrate savings based on the final agreed EU methodology for compliance with its RenewableEnergy Directive Targets.49 Here the unit is correctly termed the Carbon dioxide equivalent (CO 2 e) emissions, as this also includes thegreenhouse gas impacts of other gases such as Methane and Nitrous oxides50 “Analysis of the Greenhouse Gas Emissions for Thermochemical BioSNG Production and Use in the UnitedKingdom” Project Code NNFCC 10-009 Study funded by DECC and managed by NNFCC North Energy Associates(June 2010)60

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BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFigure 7.1 (Overleaf) Percentage Net Greenhouse Gas Emissions for Bio-SNG fired heatingrelative to fossil fuel alternatives for (a) BEAT2 methodology and (b) EC RED methodology and,Percentage Net Greenhouse Gas Emissions for Bio-SNG transport fuel relative to fossil fuelalternatives for (c) BEAT2 methodology and (d) EC RED methodology (North Energy Associates,June 2010)The data shown illustrates that whilst the actual methodology does have an impact, the following broadconclusions can be drawn:The carbon savings in both the heating and transport sectors are similarBio-SNG from virgin biomass typically saves in excess of 90% by either methodologyIn general production from pellets offers slightly lower savings due to energy used in the pelletmanufactureIn general imported feedstock offers slightly lower savingsIn general wastes offer better savings due to the “credits” system (and this is where the differencebetween the two methodologies is most stark)The analysis of RDF (Refuse Derived Fuel) requires a further commentary. The RDF used in this analysisis a high biomass RDF manufactured from mixed waste. The baseline RDF production route used in theanalysis is an autoclave system which uses significant quantities of process heat, which erodes thegreenhouse gas savings. A more typical RDF would be processed using Mechanical BiologicalTreatment which would have a much lower specific energy consumption and would have a greenhousegas saving profile similar to that of cardboard RDF for the biogenic fraction. However in this case, thebiogenic fraction would only be 60% of the biogas, and therefore the greenhouse gas savings would be~60% of that of cardboard RDF – which would therefore offer greenhouse gas savings similar to the RDFcase shown, but for a different reason. This distinction is critical because the incentive structure wouldonly apply to the biogenic fraction, and the greenhouse gas saving per unit of incentive support remainsvery high.It is instructive to note that the detailed analysis here could be approximated by considering the savingsto be at least the full tailpipe emissions associated with individual fossil fuel pathways (ie without needingto consider the full lifecycle analysis) 51In all cases it is assumed that whilst the lifecycle analysis accounts for the emissions associated withdistribution, it is presumed that the existing infrastructure has sufficient capacity (gas and electricity) .51 For example, here the lifecycle emissions of a gas boiler is 245kg/MWh and the emissions for Bio-SNG usingimported forestry residue is 30kg/MWh is a saving of 215kg/MWh. The tailpipe emission of natural gas is185kg/MWh, so this emissions figure gives an approximate, but conservative savings estimate.62

CO2e emissions g/kmCO2e emissions kg/MWhBIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTThe key specific emissions, based on the North Energy lifecycle analysis are shown in Figures 8.2 and8.3 for heating and transport applications respectively, demonstrating the substantial emissions savingsfrom biogenic fraction of the Bio-SNG. The relative saving for SRF will be reduced according to thebiogenic fraction.200180160140Lifecycle emissions of Bio-SNG as a transport fuelcompared with Diesel & Gasoline, per kilometre120100806040200Diesel Gasoline Bio-SNGFigure 7.2 CO 2 e emissions per kilometre in the transport sector compared with fossil fuelalternatives (EU RED methodology)350Specific emissions for heating for fossil fuels, Bio-SNGand direct biomass heating300250200150100500Oil boiler Gas boiler Bio-SNG using UK forestresiduesDirect heating using UKforest residuesFigure 7.3 CO 2 e emissions in the heating sector compared with fossil fuel alternatives (EU REDmethodology)63

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTA further important comparison was also made by North Energy – comparing the greenhouse gas savingsfor the direct use of biomass for heating with that via SNG. Using the RED methodology for forestryresidue woodchip feedstock, the specific emissions for direct heating is 13kgCO 2 e/MWh th and theemissions for Bio-SNG is 15kgCO 2 e/MWh th , compared with emissions from oil and gas heating at 313and 245 kgCO 2 e/MWh th respectively. Therefore the savings in both cases are approximately 95%compared with fossil fuel, and importantly the saving using Bio-SNG is essentially the same as usingdirect heating, but with elimination of any demand-side modifications for the heat users via the SNGroute.The annual CO 2 e savings for three of the larger facilities operating on biomass is 1Mte of CO 2 e perannum if used to displace natural gas heating, and slightly higher if it displaces conventional transportfuel. If Biogas were to displace a third of the domestic natural gas consumption and bio-SNGrepresented two thirds of that, then the CO2e savings would be ~15Mte pa when fuelled by biomass.7.2 COST OF CARBON ABATEMENT VIA BIO-SNGAs discussed above, the use of Bio-SNG from biomass gives a typical CO 2 e saving equivalent to at leastthat of the tailpipe emission of fossil fuel it displaces, for heating and transport. Furthermore, a bio-SNGvector provides approximately the same saving as that achieved by direct use of biomass for heating.Strategically the UK needs to consider the most cost effective approach for decarbonising. An analysishas been undertaken which considers the cost of decarbonising, based on the current and proposedlevels of renewable support subsidy 52 considered to be adequate to achieve market penetration of theparticular technology.In this analysis, it is assumed that the existing RO regime, the proposed RHI regime and the existingtransport fuel differentials are sufficient to bring about market penetration of the technologies supported,that is to say, these incentives represent the necessary additional cost of delivered utility (heat, electricityand motive power) to a consumer compared with the conventional fossil fuel alternatives. It is alsoassumed that at present the cost of carbon under the EU ETS where it applies has simply been absorbedinto the baseline cost of electricity across the board, and due to free allowances does not at presentrelate to the cost of avoiding carbon emissions. Furthermore it is assumed that the existing infrastructure(both gas and electricity) have sufficient capacity and so no further investment is necessary specificallydue to the expansion of the carbon abatement pathway.52 In deriving the cost of the emissions savings, the Government’s Impact Assessments calculation is made on thebasis of dividing the NPV of the incentive by the total tonnes of CO 2 abated [noting that the cost is discounted overtime, but the carbon abated is not]. The analysis here is viewed from the point of view of the direct cost to theconsumer, ie the subsidy cost divided by the tonnes of CO 2 saved, and where possible uses the full lifecycleemissions of CO 2 e.64

Cost of carbon abated (£/te CO2e)BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFor the transport comparison, the vehicles assumed are the Passat Ecofuel running on Bio-SNG, thesame vehicle in the 1.4l gasoline version, and the Nissan Leaf as an electric vehicle. In each case, thevehicle is assumed to travel 20,000km pa using the appropriate fuel efficiency, and accounts for theappropriate Road tax, fuel duty including rebates, the additional incentive cost to provide the renewablegas and electricity (Offshore wind) and in the case of electric vehicles the grant support (£5000).Separately the cost of carbon abatement for a range of electrical vectors is shown by way of comparison.700600>£5000Cost of Carbon abated for heating applications5004003002001000GSHP GridelectricityGSHPrenewableelectricity at2ROCDomesticheating viadirect biomassGSHPrenewableelectricity at1ROCSmallcommercial viadirect biomassBio-SNGLargecommercial viadirect biomassFigure 7.4Cost of carbon abated for heating applications65

Cost of Abatement £/te CO2eBIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT1200Cost of Abatement10008006004002000Figure 7.5Electric car Grid Electric car renewables 2ROC Bio-SNGCost of carbon abated for transport applicationsFor heating applications using gas as a counterfactual, Bio-SNG offers a cost per tonne of CO 2 e abatedof ~£175/te. This compares very favourably with direct biomass combustion for domestic applications(£395/te), for small commercial applications (£285/te) but is somewhat more expensive than directbiomass combustion for large scale commercial applications at ~£110/te. When using oil heating as thecounterfactual, the cost per tonne of CO2 saved reduces significantly to £135/te for Bio-SNG comparedwith £305, £220 and £85 for the three cases discussed above. However it must be noted that theappropriate counterfactual for Bio-SNG is natural gas, as the product can only be used where there is agas grid and where oil use is unlikely.Domestic Ground source heat pumps using grid electricity indicate £5500 cost per tonne of carbonabated compared with natural gas using the recent EST report for a mid range installed unit 53 , and over£850 when compared with oil. When using renewable electricity (2 ROC supported offshore wind) thecost of CO 2 e abatement are ~£460/te and £360/te respectively. Again on this basis, Bio-SNG competesvery effectively. If the adoption of electrical based solutions demands more grid reinforcement than wouldbe required to the gas network by Bio-SNG solutions, then the differential in cost per tonne of carbonabated is likely to be even greater. This is likely to be the case since heat demand is seasonal, such thatthe peak demand for heat can be three times the energy required for electricity and transport combined.53 “Getting warmer: a field trial of heat pumps” EST Sept 2010. This indicates a typical “System Efficiency” from itsfield trials of 2.4 (ie accounting for COP and system electrical loads). Whilst improved system efficiencies of eg 3.0would reduce the cost per tonne of carbon abated, it is still significantly higher than for Bio-SNG.66

Cost of carbon abated (£/ te CO2e)BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTTherefore significant supply of heat via electricity would demand “significant additional generation plantand network capacity operating at low load factors” 54 .For transport applications, Bio-SNG is also significantly more cost effective than electrical solutions(either using grid electricity - £1000/ te CO 2 e, or presuming hypothecated Offshore wind derived electricity- £600/ te CO 2 e). However, this analysis does suggest that whilst Bio-SNG offers significant carbonsavings for the transport sector, on a cost per tonne abated of £400/ te CO 2 e, the heating sector is apreferable end market.£600£550£500£450£400£350£300£250£200£150£100£50£0Cost of Carbon abated compared with Renewableelectricity generated by various technologiesFIT: PV(0.1-5MWe)FIT: Wind(0.1-0.5MW)FIT: Hydro(0.1-2MWe)OffshirewindAnaerobicDigestionBio-SNGBiomasscombustionOnshorewindCo-firingFigure 7.6 Cost of carbon abated for Bio-SNG compared with renewable electricity generatedfrom various sourcesCompared with decarbonisation in the electricity sector, Medium scale generation supported under theFIT costs between £220 and £570/te depending on technology, offshore wind costs ~£200/te, biomasscosts ~£150/te and onshore wind costs ~£100/te against a baseline of current grid average. This54 National Grid: “Gas as an essential fuel in supporting the transition to a low carbon economy A discussion paperby National Grid to support Ofgem’s RPI-X@20 project.”67

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTsuggests that the Bio-SNG case is preferable when compared with decarbonisation via feed in Tariffs,offshore wind and anaerobic digestionWith regards to the cost of carbon abated, the renewables routes are relatively expensive. Whilst thecurrent renewable incentive structures are based on a duration which is commensurate with projectfunding, the risk for this type of project is that in time, it is the price of carbon which becomes thedominant incentive mechanism. This will highlight the relatively expensive cost of carbon abatement viarenewables, and may drive a change in policy. Without the kind of support proposed under the RHI,projects such as Bio-SNG would not be viable.The other key national driver is to establish alternative and secure sources of energy through diversity,and where possible, indigenous supply. In this regard the use of waste based fuels to provide a gassubstitute offers a very low cost fuel source on a per MWh basis compared with other renewables.68

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT8 Risk Assessment and Financing ConsiderationsIn accordance with good practice the development of any complex process facility should beaccompanied by an appropriate risk management strategy. The main classes of risk to be managed willinclude:Cost and schedule over-runFunctional integrityHealth and SafetyFeedstock supply, price and qualityOff-take security and security of revenuesFinancing risksRegulatory risksA well conceived project execution plan for a Bio-SNG development can take account of these risk areasthrough a range of contractual and technical provisions, however, where novel process configurations aredeveloped, and with a dependency on the nascent biomass fuel supply market, then additional riskfactors will be introduced. (It is assumed that from the existence of established infrastructure etc., there isnegligible risk of getting Bio-SNG to market – the market exists.) In addition it must be recognised thatthat the market for renewable energy of all kinds is an artificial market, augmented by a variety ofgovernment incentive schemes throughout the developed world, which being the products of politicalintervention are liable to change with changing political priorities. Thus a Bio-SNG development strategyneeds to be clear from the outset how it would manage the following issues:Political riskTechnology riskFuel supply riskResulting additional financing risksShould there be any fundamental impediment posed by any of these issues then work on other aspects ofa development would be in vain.Political risk is both domestic and international. Internationally the demand for and value of biomassfeedstocks is affected directly by the uncoordinated subsidies directed at the renewables industry bynational governments 55 . Biomass fuel suppliers will naturally sell to the market offering the best price ifnew and more valuable markets emerge. Where the viability of a full scale Bio-SNG facility dependsupon imported biomass it is clear that a fuel procurement strategy would need to be developed to securesupply price and volume for a number of years. Similar concerns extend to domestically produced fuels,55 In 2008 / 9 the uncoordinated support schemes for renewable transport fuels in the UK and the USA, together withsome loose legal definitions had the effect of decimating the UK‟s indigenous transport biofuels industry.69

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTwhether clean biomass or waste-derived materials since government support mechanisms across therenewables sector, and with respect to carbon abatement generally continue to be incoherently variablein some respects.It is anticipated that the Renewable Heat Incentive may have the potential to provide the essentialincrease in sales revenue that could make Bio-SNG production viable, however, it will be necessary toverify that the uplifted revenues would be sustained for a sufficient number of years to assure anacceptable project return; that is to say that the uplift would be “Grandfathered” from the date ofaccreditation by Ofgem. It should be noted, however, that development expenditure prior to the date ofaccreditation could be at risk of a change to the rules within the RHI. Given the substantial developmentcosts that a Bio-SNG development would entail, the developer should seek to minimise its peraccreditationrisk exposure.The technical approach proposed in this report envisages the use of conventional and proven processoperations, however, their integration into a Bio-SNG facility is, save for a small number of plantscurrently under development 56 without any precedent or reference facility. Notwithstanding the maturity ofthe process technologies that may be assembled into a Bio-SNG facility the whole plant wouldundoubtedly be seen to be novel and unproven by suppliers of debt into project finance arrangements.An objective assessment of technical risk will at the outset of a project design identify a degree oftechnical uncertainty regarding integration of the various process operations comprising the completefacility, however it is within the competence of a proficient process engineering industry to analyse andresolve these issues to a level of certainty sufficient for an investment decision (however this costs effortand money at the design stage). The question remains, however, as to whether the financial communitywould be prepared to engage in detailed technical audit and verification of a proposed development orwhether they merely demand to witness a reference plant that provides a QED for the process concept.Experience suggests that potential funding institutions would favour the latter, hence securing of projectfinance for either a demonstration plant or a full scale facility is unlikely.The perceptions of risk, and strategies for mitigation of risk have changed markedly over the last threedecades, driven largely by the development of philosophies in privatisation of utilities, corporate financeand project finance. Prior to this, risk management in industrial developments was less formal and would(wittingly or unwittingly) leave governments, company balance sheets and shareholders as the bank oflast resort. Modern norms 57 for project finance seek to devolve as many risks as possible via commercialarrangements to contracting counterparties – e.g. equipment suppliers, contractors, and banks – whilstdemanding unequivocal delivery of performance guarantees. These trends undoubtedly facilitate theefficient use of capital, and reduce the number of unanticipated cost over-runs but with the corollary thatunder such circumstances it is more difficult, or even impossible to arrange project finance for first-of-akindenergy projects. Thus contemporary norms for project finance sit uncomfortably with the emerging56 Gussing and Gobigas – see Appendix 157 i.e. the gearing of equity with non-recourse debt in order to give the lowest possible cost of capital.70

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTdemand to deploy new energy infrastructure that incorporates novel and unproven technologies or evennovel process configurations. Equally, corporate balance sheets tend to be insufficiently strong toundertake large capital projects on balance sheet; the recent history of infrastructure developments beingundertaken with a combination of debt and corporate equity. In the post 2006/8 risk-averse bankingclimate it is even more the case that conventional financing arrangements could only be used to deliverinfrastructure energy projects that use tried and tested (i.e. “proven”) technologies and designs. Thechallenge therefore is to conceive project financing strategies that can accommodate first-of-a-kindenergy infrastructure projects such as facilities for the production of Bio-SNG.It is commonly presumed by government and other stakeholders that given an adequate stimulus orincentive “the market” will move to provide the technical innovation and development necessary to meetthe opportunity. For example, the banding in the Renewables Obligation is intended to doubly incentivisethe deployment of waste and biomass gasification facilities; to date there is little to show in terms of suchnew technology plants being built and commissioned. This is equally the case for marine renewables andto a lesser extent for offshore wind developments 58 . As a strategy for bringing new biomass energyinfrastructure into commission the banding of the RO is clearly not having the intended effect, however,an appreciation of human decision making in a climate of risk shows why this should not be a surprise. 59In short, decision making within the energy industries is dominated by a reluctance to accept thedownside risks associated with technical novelty, feedstock insecurity and political vacillation; irrespectiveof the magnitude of the projected returns. Moreover, economic analysis of most renewables projects,including Bio-SNG shows that the enhanced income derived from support for renewables is required tobring project income up to a level of marginal viability, with no premium for any unusual project risk.Another popular misconception is that “demonstration” of a new technology would provide the essentialproof of concept to liberate funding from aspiring investment institutions. This has spawned a number ofgovernment initiatives to promote the building of “demonstration facilities” 60 on the presumption thatdemonstration would be a sufficient condition to satisfy funding institutions in their requirement to investonly in proven technologies. There are flaws with this line of reasoning. Firstly, demonstration projectsare likely (for reasons of cost and risk) to be a fraction of the required scale of facility that would bedeployed in a commercial plant; hence scale-up risks are still a material consideration. Secondly, theperiod during which a demonstration plant is operated can in no way give an assurance of satisfactoryperformance throughout an investment horizon for which project returns have been projected, forexample, a minimum of fifteen years.58 Meeting the 2020 Renewable Energy Targets: Filling the Offshore Wind Financing Gap – PWC July 2010. Clearly it is nowrecognised by at least one of the major management consultants that pure financial incentives are in themselvesinsufficient to ensure deployment of new energy infrastructure, and that innovative financing mechanisms arerequired.59 See The Utility Function of Risk, John von Neumann et al.60 e.g. Defra’s New Technology Demonstrator programme, the Carbon Capture and Storage competition.71

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTIt is true that venture capital funds do invest in emerging technologies, but this is invariably at a muchsmaller scale than would be required for a Bio-SNG plant and with the expectation of high returns and anearly exit for investors, coupled with the prospect of a global roll-out to a mass market; conditions that areunlikely to be realised in energy infrastructure projects where a modest number of units would beconstructed and without any prospect of above-market returns. It is not surprising therefore that venturecapital funds have not yet sponsored a break-through in biomass energy generation technologies.The result of even a successful venture capital funding or technology demonstration is the well knowninvestment “valley of death”, reflecting a state of technology development that is insufficient to attractinvestment of further and necessary resources and in which under-resourced technology developers havedifficulty in fighting their way out of the corner in which they find themselves. It follows that in the absenceof any alternative financing strategy the first-of-a-kind risks must be taken by the project owner or investorby means of a 100% equity position. A small scale, 50MWth Bio-SNG demonstration plant would cost inthe region of £70m, (and a full scale 500MWth facility in the region of £250m). In a commerciallandscape where this could not be part funded via debt this leaves the owner/shareholder or developerstaking a large amount of capital on a single, sub-commercial demonstration project in the possiblyunrealistic hope that at some point in the future it would provide sufficient demonstration to attract projectfinance. Unless it can be clearly identified at the outset that a demonstration plant offers a route tosecuring project finance then it may be necessary to see what it takes to go straight to a full scale facility.Few organisations have the balance sheet strength to contemplate this, and those that do would be facedwith the same internal investment committee justifications as would be posed by an external debtprovider. In short, the technology investment case would need to be compelling in order to secure apositive decision by a corporation to invest.Fuel supply risks are undoubtedly influenced by changes globally to the various support mechanisms ofnational governments and by the ongoing evolution of world energy markets. Increasingly they areinfluenced also by considerations of sustainability, with ever increasing requirements for users todemonstrate that their biomass fuel supplies are responsibly sourced. Some identified and existingsources of biomass fuels will run the risk of being unsustainable in the future as this criterion is appliedmore rigorously both to the existing inventory of biomass (mature woodland), or to farmed energy crops.To manage fuel supply risks some major biomass power developers such as RWE are moving upstreaminto the supply chain to secure producing assets, to gain a controlling position in the trading of biomassfuels in this emerging market and to increase the diversity of sources globally. It may not be necessary tocompete with the likes of RWE; rather it may be preferable to enter into long term fuel supply contractswith such powerful counter parties that are seeking to be market leaders in this area. Regarding the useof waste-derived fuels it will be necessary to secure long term supply contracts with waste processors.From the foregoing it may be concluded that the confirmation of the RHI at an adequate level of supporttogether with grandfathered rights may constitute necessary but insufficient conditions by which to justifyinvestment in Bio-SNG production. Some provisions would need to be made to tackle feedstock security,72

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTas well as technology and construction risks. Feedstock security is a question that a Bio-SNG developercan manage itself through development of its upstream business, by contracting with majors like RWEthat are active in this field, by futures trading etc., however, the management of technology andcontracting risks may be beyond the powers of the Bio-SNG developer to handle alone.In its report “Meeting the 2020 Renewable Energy Targets: Filling the Offshore Wind Financing Gap”PWC identifies investment barriers that impede the timely deployment of facilities required to meet theUK‟s renewable energy targets. The problem identified in this report is not peculiar to offshore wind butcommon across the sustainable energy sector; how to get substantial institutional investment into newlow-carbon energy infrastructure. PWC sets out a number of possible scenarios in its report, but keyamong them is the notion that a publicly administered infrastructure development fund should be created,perhaps from a consumer levy, that could be used in qualifying projects for project funding through thecritical engineering, construction and commissioning phases. Refinancing of projects when they reachstable operation would recycle money back to the fund for use on subsequent projects. However, theintent is to create a body of operational experience, by means of this “pump priming” exercise that willprovide the necessary confidence for institutional investors to invest in future projects of the same type.PWC suggests that the quid pro quo for a developer benefiting from this kind of funding assistance couldbe a reduction in the level of ROC support post commissioning. To the extent that ROC support is likelyto form an essential part of a project‟s economic viability, Progressive Energy would argue that this wouldconstitute another barrier to renewables project developments. Nevertheless the PWC report sets out anumber of potential scenarios for overcoming the difficulties in financing new energy infrastructure: it canbe downloaded via the link referenced in Appendix 3.To the extent that Bio-SNG (along with other significant sustainable energy sources) has the potential tomake an efficient contribution to renewable energy targets, it could be argued that the UK governmentshould be encouraged to understand that whilst the Renewables Obligation and the RHI are necessaryinstruments, they are unlikely to be sufficient for the timely realisation of facilities on the ground, and thatsome further measures - such as those proposed by PWC - need to be taken to manage technology andconstruction risks on large capital projects.73

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT8.1 CONCLUSIONS FROM RISK ASSESSMENT AND FINANCING CONSIDERATIONSUse of existing technologies will reduce technical risks but still leave a project finance hurdle.Fuel supply risks need to be addressed from the outset.A demonstration facility may not clear the way to project finance for a full scale project.The developer should have a clear perception of incentives and the political / regulatorylandscape.There are fundamental barriers to the timely funding of novel energy infrastructure.Further financial provisions may need to be made to cover technology and construction risks.Significant expenditure should not be committed until a pathway through all these issues isidentified.74

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT9 Preliminary Scoping of a lead, beacon project9.1 BEACON PROJECT CONFIGURATION OPTIONSThe philosophical approach taken in this report has been to identify a route to efficient Bio-SNGproduction that does not require research and development but is based upon the integration ofconventional and proven process operations that have been demonstrated elsewhere. Nevertheless itremains to be established whether an investment case could be advanced that would offer sufficientconfidence to invest directly in a full scale 300Mwth Bio-SNG facility, or whether some sort ofintermediate development would be required to improve confidence levels to the point where theinvestment case for a large scale plant could be accepted. This consideration is counterbalanced by therealisation that the economies of scale given by a full scale plant are needed for a commercially viableoperation. Three potential basic development cases present themselves:Small Scale Bio-SNG synthesis taking a slipstream of bio-syngas from elsewhereA small scale Bio-SNG synthesis operation taking a slipstream of bio-syngas over the fence from anexisting biomass or SRF gasification developer. There are some potential biomass / SRF gasificationprojects slated for development in Teesside, and it may be possible to piggy back a small Bio-SNGdemonstration project onto one of these, given an amenable attitude from the core project developer.Figure 9.1 shows the basic concept for this arrangement.GasificationSyngasscrubbingPowergenerationCore project5% SlipstreamSyngasconditioningMethanationetc.SNG comp.& exportFigure 9.1Small scale Bio-SNG synthesis using syngas from another projectThis process set-up would allow proof of concept for Bio-Syngas methanation, which may be seen asvaluable, however, one could make the observation that the methanation of synthesis gas (whatever itsorigin) is a banal exercise and not really worthy of demonstration. Nevertheless, it should be noted thatcatalyst manufacturers such a Johnson Matthey are undertaking developments of catalysts specifically forsyngas derived from biomass on the basis firstly that it may be possible to relax gas cleaning criteria iftolerant catalysts could be identified and secondly that there could be as yet unknown traces of particularcontaminants in bio-syngas that need to be addressed.Equally it could provide a test site for thedemonstration of a compact micro-channel reactor supplied potentially by a company such as OxfordCatalysts.This could represent an interesting development pathway since having achieved75

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTdemonstration at this scale, the up-scaling of the micro channel reactor concept entails minimal technicalrisk since it would entail replication of the standard process module proven in the demonstration plant.This development concept is a low risk, low cost step in the direction of meaningful volume production ofBio-SNG, with the potential to make substantial progress via demonstration of a micro channel reactor.However, it does rely on a third party producer of syngas, and the inherent technical and commercial risksof the core project.The development of a scalable demonstration facility at a size of around 50MWthConventional concepts of development pathways envisage “demonstration” of a technology as anessential step towards securing project finance for a full scale facility. This report suggests in Section 7that there could be flaws in this idea concerning whether the level of demonstration would be sufficient forthe purposes of securing project finance for a full scale facility. Before embarking on the development ofa demonstration project therefore it is essential to understand whether the resulting demonstration willserve the intended purpose in this respect. This report also finds that there is little prospect of even arelatively large Bio-SNG demonstration plant (50MWth) achieving commercial viability, in view of thesignificant capital cost estimate of £70M. The economic analysis that supports this report reveals that forviability such a plant would require a capital grant of approximately £45m or a hike in RHI contribution of£40/MWh th . There is a hybrid development, however that might hold some promise of viability. Inprinciple it would be viable to develop a 50MWth waste fired power plant for the production of electricity,benefiting as it would from the double ROC banding for gasification. Along the lines set out in Figure 9.1.it would be possible to fit a slipstream in due course for the evaluation and development of a syngas tomethane process train, possibly incorporating the micro channel reactors for both WGS and methanationreactions. However this would demand that the primary gasification train produces syngas suitable formethanation (for example oxygen blown), such that the primary electrical plant does not generatesufficient value to support the project. Nevertheless the challenge remains how to step up from such adevelopment to an investment in a full scale commercial Bio-SNG facility.Development of a “Full-sale” 300MWth Bio-SNG facility.In consideration of a full scale plant development it is necessary to consider whether it could bedeveloped directly or whether some intermediate development step would be required to improve investorconfidence. In terms of the probability of technical failure, a full scale 300MWth facility is no more likely torun into technical difficulties than a 50MWth demonstration plant; it is the magnitude of the relativedownside costs that is the issue rather than probability of failure. This raises the question as to whetherthe downside associated with a £70M demonstration plant could be mitigated or controlled; if not then it isdifficult to see how such a demonstration plant could be developed at all. On the other hand if thedownside risks could be controlled to an adequate level then possibly the same proposition holds true for76

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTa full scale plant development, especially given the use of conventional process technologies. Eitherway, these are unlikely to be projects that could be funded with project finance (equity plus debt), and thedeveloper would need to be able to justify the risk / reward balance as the equity holder in the project.Again, a hybrid development approach could offer risk mitigation potential, by taking syngas at full scalefrom a conventional fossil fuelled source for the production of fossil SNG. Subsequently the source offossil syngas could move to co-firing biomass. Alternatively a biomass gasifier could be developed lateron for a dedicated supply of Bio-syngas to the SNG facility. In Teesside the Progressive Energy EstonGrange development within the Teesside carbon dioxide capture cluster 61 could be a possible source ofsyngas for initial SNG production 62 . The general concept is outlined in Figure 9.2.Storage / EORGasificationSyngasscrubbingCO 2capturePowergenerationCoal(+ Poss futurebiomass)SlipstreamFuture BiomassGasifier plantSyngasconditioningMethanationetc.SNG comp. &exportFigure 9.2Hybrid development optionA full scale Bio-SNG facility of 300MWth capacity would probably be built with two gasifier trains in orderto ”standardise” on gasifier frame sizes and to offer a degree of system redundancy. These would feed asingle gas processing train in order to benefit from the economies of scale. It will be readily appreciatedtherefore that migration from fossil syngas to bio-syngas could be accomplished in stages as each of thebiomass gasifier trains is brought on line. This again assists in risk management in the gasifierdeployment, allowing also a staged ramp-up of biomass fuel supply.9.2 LOCATION: THE NORTH EASTThe North is an attractive location for the development of the type of project contemplated here. It has along history of Chemical and processing industries. Therefore it has the necessary gas and servicesinfrastructure and the transport links as well as the people and skill base. The existing industrial backdropcan accommodate the kind of processing plant under consideration, with a range of suitable and availablesites. Changes to and closure of existing industries mean that new facilities which offer employment andregeneration are welcomed, so that a balanced view is taken during planning.61 See Appendix 462 It must be noted that the increased complexity for the host project imposed by the Bio-SNG addition may provechallenging.77

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTThe North East also has a track record of innovation. There are already three syngas based projectsslated or in development. The Ineos Bio facility will take solid waste and convert it to bioethanol viagasification to syngas and subsequent biological conversion. Air Products have recently announced theirintention to build a 49MWe waste fuelled power generation facility using gasification to produce a syngas,provisionally for conversion in a Gas Turbine. Progressive Energy are developing a coal fuelled syngasfacility incorporating carbon capture and storage. Each of these facilities will produce a synthesis gaswhich could, in principle be partially converted to a Synthetic Natural Gas. In the event that the North Eastis successful in bidding for government support for Carbon capture and storage, there may also be thepossibility of integrating Carbon Capture for the residual CO2 (fossil or biogenic) which is emitted in theprocess.9.3 SITE ANALYSISA high level screening exercise of sites in the Teesside area was carried out, focusing on those whichcould accommodate a large scale facility, even if the build out was incremental. The primary attributesconsidered were:Transport infrastructure: Road/rail infrastructure for supply of indigenous fuel, and access to adeep water port for economic import of fuel.Gas connection with sufficient capacity (with a preference for lower offtake pressure than NTS,providing sufficient capacity exists)Electrical grid connection (to accommodate the supply/generation balance)Commodities: water, cooling etcThe following attributes were considered desirable.Access to Hydrocarbons to boost gas quality (LPG or high quality Natural Gas)Existing Oxygen suppliesSyngas main to valorise intermediate and give flexibilityPotential to link into CCS networks for Carbon Dioxide disposalFigure 9.3 shows the sites considered in the Teesside region. These sites have been selected for theattributes and that they have been and could be available. However, in the Teesside region there are anumber of projects under development with site deals and options being negotiated confidentiality. Thiscan only be explored as the project becomes more mature, as can the other important commercialconsiderations associated with a particular site. As can be seen, Teesside has a wide range of potentialsites. Table 9-1shows the evaluation of the sites.78

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFigure 9.3Potential site sin the Teesside regionSite Ref Port Road Rail GasGasElecSer-Cool-NTSLTSvicesingSeaton Port A Seal Sands B/C Clarence Port D ? ? Billingham Reach E/H Norton Bottoms F ? ? ? ? South Bank G Pos Corus K - Priv Sembcorp L Priv Table 9-1Evaluation of potential sitesFrom this analysis, two sites were considered as most interesting; D and G, either side of the Tees,primarily due to their proximity to port and transport infrastructure, as well as other facilities. These areshown in Figure 9.4 As can be seen, neither area is currently constrained with regard to space, even fora relatively large facility, although the exact footprint will depend critically on the level of fuel processingrequired on the site, as well as logistic and storage arrangements. An investigation into the gas79

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTinfrastructure showed that both sites have reasonable accessibility to medium to high pressure gas mainswith sufficient capacity for 20,000Nm 3 /hr (Figure 9.5). Both these sites are believed to form part ofregional development plans, specifically designed to encourage and enable development. These sites arealso relatively close to the slated syngas development projects under way, with Air Products and IneosBio on the North side of the Tees, and the Eston Grange Project on the South. Figure 9.6show thephotographs on the sites considered. The facilities shown in Appendix 1 would not be out of place inTeesside. In summary, it is clear that Teesside offers a range of potentially suitable sites for a project ofthis type.Figure 9.4North and South bank sites of most interest80

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFigure 9.5Gas Grid options81

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTFigure 9.6Images of the North and South Bank sites82

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT9.4 REGIONAL FEEDSTOCKIn addition to ascertaining the availability of potential sites, it is also important to consider the availabilityof feedstock. Teesside does have a significant number of biomass and waste projects operating or slatedas shown in Table 9-2. These represent over 2.5Mte of biomass and 1.4Mte of waste. Clearly suchprojects demonstrate that Teesside does have both the transport infrastructure and access routes to bothtypes of resources. However, these resources are clearly sought after to support these projects. Themajority of this resource is for slated/in-development projects, not all of which will happen.Existing/in-build te pa Slated te paBiomass Wilton 10 300,000 MGT Power 1,500,000Lynemouthcofiringpotential~200,000 BEI 400,000Gaia Power 400,000Waste SITA, Haverton 390,000 Ineos Bio 100,000Haverton Ext 190,000Wilton 11 400,000Air Products 300,000Table 9-2Teesside: slated feedstock consumptions83

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT10 ConclusionsMethane is an attractive heat and transport fuel vector. Bio-SNG is a production route which offers thepossibility of substantial scale renewable methane for injection into the grid and use in transport.Transition from aspiration, to widespread operating facilities and infrastructure requires a detailedunderstanding of the technical and commercial attributes of the full chain from feedstock supply throughto delivery of grid quality gas, as well as the development of the first crucial operating facility whichprovides the tangible proof of concept for roll out.Implementation of Bio-SNG will only take place with the appropriate tax, incentive and legislativeenvironment. Incentives must be structured such that such projects are commercially attractive comparedwith competitive users of biogenic energy resources, and the regulatory environment must be clear andappropriate.Whilst there is substantial indigenous and international biomass resource in the form of „pure‟ biomassand waste derived fuels, it must be appreciated that there are competing uses for biomass in manyindustrial sectors – building materials, chemicals, heating, electricity generation, and transport bio-fuels.Securing feedstock on contracts of sufficient term and appropriate price for financing presents achallenge, and it is likely that the development of Bio-SNG facilities will require the developer to goupstream into the supply chain for both grown and waste derived fuels. From a technical perspectivebiomass fuels are generally less well understood than fossil fuels, and the technologies that use biomassfuels are less well developed, however, specification and quality control are vital determinants of projectsuccess.In principle, the major process operations required to produce Bio-SNG can be identified and assembledfrom existing technology suppliers. This does not mean that a Bio-SNG development would be free fromtechnical risk, but it does mean that there is no fundamental process development required to create aviable Bio-SNG platform. The essential first condition that must be satisfied is that feedstock specificationand the process design are matched. It is proposed in this work that established gasifier configurationsare adopted, such as direct fluidised beds, rather than emergent technologies. Downstream of thegasifier the gas processing operations are conventional technology: heat recovery and power generation,gas scrubbing, water gas shift, methanation, conditioning and compression. Whilst these processingelements are all conventional, they are critical for ensuring pipeline quality gas. In general the GS(M)Rspecification should be attainable by this process route, although the tight limit on hydrogen content maylead to unnecessary processing.Two representative scales of facility at 50MWth and 300MWth input would produce approximately230GWh and 1400GWh of Bio-SNG per annum. This represents sufficient gas for approximately 15-84

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT100,000 households or 25,000-150,000 passenger vehicles. Three of the larger facilities would supply 1%of the UK domestic gas market.The levelised cost of Bio-SNG in 2010 prices has been shown to range between £67-£103/MWh for thesmall scale facility and £32-£73/MWh for the large scale facility dependent on the type feedstock used,with the waste based fuel being the cheapest. Assuming the RHI at £40/MWh of biogenic fraction thisequates to out turn gas prices of 123-185p/therm at small scale and at large scale 24-96p/therm for SRF,Woodchip and pellet feedstock respectively. With the proposed incentive regime, a large SRF fuelledfacility has the potential to provide gas effectively. At this scale, a mix of indigenously sourced woodchipand imported woodchip might be competitive, but a facility fuelled by wood pellet is unlikely to be able tocompete. At the smaller scale, Bio-SNG cannot be supplied competitively from any fuel. A gasificationfacility configured to generate electricity is likely to be commercially preferable to one configured toproduce Bio-SNG, unless the Renewable Heat Incentive is significantly higher than the £40/MWhproposedFull lifecycle analysis of Bio-SNG production shows that for many types of feedstock, the lifecycle CO 2 esavings of Bio-SNG compared with fossil fuel alternatives are typically ~90%. This saving is similar forboth conventional heating and transport applications. This analysis also demonstrates that the savings forthe Bio-SNG production route are very similar to those achieved using direct biomass heating. Given thatthe Bio-SNG solution has much lower demand-side constraints and therefore could achieve greatermarket penetration, it is an attractive route.Strategically the UK needs to consider the most cost effective approach for decarbonising. For heatingapplications using natural gas as a counterfactual, Bio-SNG offers a cost per tonne of CO 2 e abated of~£175/te. This compares very favourably with direct biomass combustion for domestic applications(£395/te) and for small commercial applications (£285/te), as well as with Ground source heat pumps(£5500/te). If the adoption of electrical based solutions demands more grid reinforcement than would berequired to the gas network by Bio-SNG solutions, then the differential in cost per tonne of carbon abatedis likely to be even greater. For transport applications, Bio-SNG is also significantly more cost effectivethan electrical solutions, however, this analysis does suggest that on a cost per tonne abated, the heatingsector is a preferable end market.The envisaged Bio-SNG facilities are in most respects conventional process engineering projects,exhibiting the general risk profile that such developments entail. These can in the main be addressedwith a conventional contracting approach to risk management; however there are technology, fuel supplyand financing risks that need to be addressed. Government incentive schemes offer the prospect ofcommercial viability with a plant that would not in other circumstances be commercially viable; to thatextent they are beneficial to non-fossil energy developments including Bio-SNG. The economic analysisshows that they do not constitute an exceptional upside return on investment. What influences theattitude of investors however is that current support mechanisms offer no protection on the downside of85

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTthe project risk profile. It follows that a financing strategy needs to make provision for managing thedownside risk that will be perceived by investors.An incremental approach to the management of technical risk would be the development of ademonstration facility, although even a reasonable scale demonstration facility might not necessarily openthe door to project finance on the first full scale plant. In light of the financial analysis, a project at300MWth fuelled by SRF could be economically viable. However, the quantum of investment for a first ofa kind project is substantial and would not be financeable without an intermediary pathway, such as onepredicated on an existing or already proposed syngas platform.The chemical and processing industrial heritage in the North East, its natural gas and servicesinfrastructure, its transport links and its track record of innovation make it an attractive region to locatesuch a project, particularly given the syngas projects already slated. High level site screening analysisindicates that there are sites in the Teesside region suitable for either scale of facility with good transportinfrastructure, although there is potential pressure on feedstock resources in the region.86

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTAppendix 1Examples of Relevant Gasification ProjectsDakotaThe largest SNG facility in the world, with 3GWth input capacity (producing ~200,000 Nm3/hr CH4),fuelled by lignite. Started operation in 1984. Gasifiers: Lurgi Dry Ash with Rectisol gas cleaning. HasCarbon capture fitted.GussingFuel: woodchip, 8MWth input to power. ~40,000 Gasifier and engine hours. Bio-SNG produced June200987

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTGobi GasFuel: Wood pellets. Indirect gasifier. Phase 1: 32MWth input, Contracting 2010. Phase 2 (2015):120MWth input, Technology undefinedHigh Temperature WinklerProduction of Methanol at various scales fuelled by lignite and MSW88

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTChoren50MWth facility fuelled by woodchip for the production of Biodiesel using Fischer Tropsch. Gasifieroperational, F-T in commissioning as of 2010.89

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT90

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT91

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTAppendix 2Extract from the Smartest Energy Informer, 02 August 2010Consultant calls for Government to plug offshore funding gapAs the Government continues to push for aggressive growth in offshore wind investment, a recentconsultant report has highlighted the need for further public support.In Meeting the 2020 Renewable Energy Targets: Filling the Offshore Wind Financing Gap published latelast month, PricewaterhouseCoopers‟ (PwC) said a “quantum leap” in offshore wind capacity wasrequired to meet current government targets. But an “equal leap” was needed in support structures todeliver investment.The report proposed four solutions to supplement the current incentive framework:• underwriting construction and technology risks by a consumer levy. This solution would share the risksin construction among the developer and consumer for a limited time through a levy on electricityusage, but this would be recouped through a lower Roc award level once the project was operational;• a regulated asset regime. This solution would share the construction and commissioning risk betweenthe developer and an administrator. Any potential shortfall in selling to the market would be coveredthrough a consumer levy. Once the wind farm had demonstrated “operational stability”, it would beauctioned off, and the winning bidder would be the one offering the lowest required return on thecapital on the regulated asset base;• additional Rocs for a limited period. This solution would boost the short-term financial return for theinvestor in the “first couple of years” of operation. Suppliers, and indirectly consumers, would bear thecosts through increased Roc payments; and• bonds or an equity fund. This solution could increase the returns on investment rather than reducingthe risk. It would involve making investments in offshore wind projects tax free to the public throughan extension of the current ISA allowances. The taxpayer would bear the eventual cost in the form ofreduced income tax.This report suggests current measures still fall short of what is needed to crystallise the necessaryinvestment.For the full PWC report see:http://www.pwc.co.uk/eng/publications/meeting_the_2020_renewable_energy_targets.html92

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTAppendix 3 – Extract from the Gas Safety (Management) RegulationsSchedule 3 Content and other characteristics of gasRegulation 8Part I Requirements under normal conditions1 The content and characteristics of the gas shall be in accordance with the values specified in the tablebelow.Content or characteristic Valuehydrogen sulphide content ≤5mg/m3;total sulphur content (including H2S) ≤50mg/m3;hydrogen content ≤0.1% (molar);oxygen content ≤0.2% (molar);impurities shall not contain solid or liquid material which may interfere with the integrity or operation ofpipes or any gas appliance (within the meaning of regulation 2(1) of the 1994 Regulations) which aconsumer could reasonably be expected to operate;hydrocarbon dewpoint and water shall be at such levels that they do not interfere dewpoint with theintegrity or operation of pipes or any gas appliance (within the meaning of regulation 2(1) or the 1994Regulations) which a consumer could reasonably be expected to operate; WN (i) ≤51.41 MJ/m3, and(ii) ≥47.20 MJ/m3; ICF ≤0.48 SI ≤0.602 The gas shall have been treated with a suitable stenching agent to ensure that it has a distinctive andcharacteristic odour which shall remain distinctive and characteristic when the gas is mixed with gaswhich has not been so treated, except that this paragraph shall not apply where the gas is at a pressureof above 7 barg.3 The gas shall be at a suitable pressure to ensure the safe operation of any gas appliance (within themeaning of regulation 2(1) of the 1994 Regulations) which a consumer could reasonably be expected tooperate.4 (1) Expressions and abbreviations used in this Part shall have the meanings assigned to them in Part IIIof this Schedule. (2) ICF and SI shall be calculated in accordance with Part III of this Schedule.Part II Requirements for gas conveyed to prevent a supply emergency1 The requirements of the gas referred to in regulation 8(2) and (4) are –(a) WN –(i) ≤52.85 MJ/m3, and(ii) ≥46.50 MJ/m3; and(b) ICF≤1.49,and in all other respects the gas shall conform to the requirements specified in Part I of this Schedule, asif those requirements were repeated herein.2 (1) Expressions and abbreviations used in this Part shall have the meanings assigned to them in Part IIIof this Schedule.(2) ICF and SI shall be calculated in accordance with Part III of this Schedule.Part III Interpretation1 In this Schedule –“bar” means bars (absolute);“barg” means bars (guage);“C” means degrees Celsius;“C3H8” means the percentage by volume of propane in the equivalent mixture;“equivalent mixture” means a mixture of methane, propane and nitrogen having the same characteristicsas the gas being conveyed and calculated as follows –(i) the hydrocarbons in the gas being conveyed, other than methane and propane, are expressed as anequivalent amount of methane and propane which has the same ideal volume and the same averagenumber of carbon atoms per molecule as the said hydrocarbons, and(ii) the equivalents derived from (i) above, together with an equivalent for all of the inert gases in the gasbeing conveyed, expressed as nitrogen, are normalised to 100%, such that the equivalent mixture ofmethane, propane and nitrogen has a Wobbe Number equal to that of the gas being conveyed;93

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT“ICF” means the Incomplete Combustion Factor;“mg/m3” means milligrams per cubic metre at 15C and 1.01325 bar;“MJ/m3” means megajoules per cubic metre where the calorific value of a dry gas is determined on thebasis that the water produced by combustion is assumed to be condensed;“N2” means the percentage by volume of nitrogen in the equivalent mixture;“PN” means the sum of the percentages by volume of propane and nitrogen in the equivalent mixture;“relative density” means the ratio of the mass of a volume of the gas when containing no water vapour tothe mass (expressed in the same units) of the same volume of air containing no water vapour under thesame conditions of temperature and pressure;“SI” means the Soot Index;“WN” means the Wobbe Number;trigonometric functions are to be evaluated in radians.190 The Wobbe Number of gases should be determined on the basis that any water vapour in the gashas first been removed.2 In this Schedule, ICF, SI and WN shall be calculated in accordance with the following formulae –ICF = WN-50.73+0.03PN 1.56SI = 0.896 tan-1 (0.0255C3H8 - 0.0233N2 + 0.617)WN = calorific value“relative density” means the ratio of the mass of a volume of the gas when containing no water vapour tothe mass (expressed in the same units) of the same volume of air containing no water vapour under thesame conditions of temperature and pressure;“SI” means the Soot Index;“WN” means the Wobbe Number;trigonometric functions are to be evaluated in radians.190 The Wobbe Number of gases should be determined on the basis that any water vapour in the gashas first been removed.2 In this Schedule, ICF, SI and WN shall be calculated in accordance with the following formulae –ICF = WN-50.73+0.03PN 1.56SI = 0.896 tan-1 (0.0255C3H8 - 0.0233N2 + 0.617)WN = calorific valuerelative densityGuidance on determining whether gases fall within the criteria set out in Parts Iand II of Schedule 3191 The characteristics of a gas which can be accepted into the network under normal conditions (Part Iof this Schedule), and those which may be authorised by the NEC (Part II of this Schedule) to prevent asupply emergency, have been derived from work carried out by Dutton et al (see references section at theend of this publication) on gas interchangeability. The work was carried out against a background ofdeclining gas supplies from the southern North Sea and replacement supplies being provided from anincreasing number of other sources. It was necessary to ensure that these new gas supplies wereinterchangeable with existing supplies, and that established standards of appliance performance andsafety could be maintained without the need to adjust appliances.192 Gases from diverse sources were burned on several types of gas appliance and their performanceobserved. From this parameters were established within which gases could be safely consumed. This ledto the production of a 3-dimensional diagram together with equations for calculating the related indices forgases that contained significant quantities of hydrogen, and a simplified 2-dimensional version of thediagram for essentially hydrogen-free gases. As gases supplied to the UK are hydrogen-free, the 2-dimensional diagram, modified to suit existing conditions, has been used. The diagram has axes ofWobbe Number and equivalent mixture (propane plus nitrogen).193 The following technique should be used to determine whether a particular gas composition complieswith these Regulations:94

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT(a) The Wobbe Number (real, gross) is calculated by methods outlined in International Standard ISO6976: Natural gas. Calculation of calorific values, density, relative density and Wobbe index fromcomposition 2nd Edition 1995, at standard conditions of 15C and 1.01325 bar.(b) The equivalent composition of the gas (and hence the equivalent propane plus nitrogen) is calculatedas follows:(i) the non-methane/propane hydrocarbons are converted to methane and propane inaccordance with Dutton, where:n all isomeric forms of an alkane (eg, normal, iso and neo pentane) have the sameequivalence;n alkenes and aromatic components have the same equivalence as the alkane of the samecarbon number;(ii) all the inert gases are expressed as an amount of nitrogen which when added to theamounts of methane and propane from (i) above, and normalised to 100%, gives a mixturehaving the same Wobbe Number (real, gross) as the original gas.The normalised mixture in (ii) is also the equivalent gas having the equivalent amounts of propane plusnitrogen.(c) Acceptable gas mixtures are those where the intersection of Wobbe Number and equivalent mixture(propane plus nitrogen) lies within the envelope of gas conforming to Parts I or II of this Scheduledepending on the circumstances.95

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTAppendix 4The North East CCS ClusterThe proposed North East CCS Cluster is in the heartland of the UK‟s heavy process and chemicalindustries. Design and pre-FEED engineering has been undertaken for all elements of the CCS chain andkey arrangements put in place to support a project plan which aims for first operation before the end of2015.Captured CO 2 will be transported in a new pipeline for storage, and potential EOR, in an oil field in theCentral North Sea. The pipeline is routed to also allow storage in a saline aquifer with a CO 2 storagecapacity in excess of 1bte providing risk management to the storage element and allowing storage in alarge saline aquifer to be demonstrated. The offshore pipeline has been sized to accommodate additionalCO 2 from Teesside and the wider North East.Development work has been undertaken on two substantial anchor CO 2 capture sources either or both ofwhich could underpin the commercial development of the network, as well as provide demonstration ofpre-combustion capture at a scale of at least 400MWe. The facility at Teesside will be a new build syngasplant which generates decarbonised hydrogen from coal for conversion to power in a CCGT (ie operatingas an IGCC) as well as for use by Industry in the area. At Lynemouth, configuring the existing coal powerstation with pre-combustion capture provides demonstration of an IGCC retrofit with capture to an existingcoal power station. Each facility would capture in excess of 2.5million tonnes of CO 2 per annum.The region has numerous substantial emitters of carbon dioxide which will be able to link into the coreCO 2 infrastructure, either via capture from their existing facilities, or by the use of decarbonised feedstockand fuel. Specific existing industrial players are actively pursuing the decarbonisation options that CO 2infrastructure would offer. Furthermore the network will enable inward investment into the UK by otherhigh carbon emitters from around Europe for whom the unique storage opportunities afforded by theNorth Sea enables decarbonisation of their industry.Eston Grange IGCC, Teesside Offshore Infrastructure Lynemouth Power Plant96

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTThe need and timescale for CCS in the UKIn the short term CCS is needed in the UK to enable coal generation to be maintained in the energy mix,strengthening security of supply by avoiding over dependence on imported gas. New generating capacityis required from 2015 onward and there is an incentive to either extend the life of existing coal stations byfitting CCS or build new stations to begin operation on this timescale.In the longer term it is expected that gas generation will also need to be decarbonised in order to reachemission reduction targets in 2030 and beyond. However the higher specific CO 2 emissions and moreurgent need associated with coal generation indicate that the policy of focussing on coal and supporting 4coal fired CCS projects in the first instance is appropriate.UK industry will become exposed to increased costs from the Emissions Trading Scheme from 2013.Many industrial sources are smaller than those associated with power generation but nevertheless theemissions cost can have a significant effect on profitability. There is concern in Teesside, which has oneof the highest concentrations of energy intensive and process industries in the UK, that the increasedcosts may cause significant business contraction and job losses.By themselves most industrial emitters are unable to support the full capital costs of transport and storageas well as capture. The availability of CO 2 transport and storage infrastructure is needed to supportdecarbonisation of these industries, some of which of have very low capture costs but no means ofdisposing of the captured CO 2 . For some industries other decarbonisation strategies may be appropriateincluding, as is proposed at Teesside, using decarbonised feedstock from a dedicated plant producingdecarbonised syngas for industrial as well as power industry use.Certainly for Teesside it is crucially important that, at the least, CO 2 transport and storage infrastructure isput in place as soon as possible to allow industries that become exposed to the ETS in 2013 to considerinvestment in capture plant or use of decarbonised syngas to mitigate the risk to their business. Themarginal cost of sizing the spine pipeline from the first capture project to CO 2 store to accommodate CO 2from additional geographically clustered, capture projects is low. Right sizing of the pipeline againstanticipated future need provides real benefits to UK plc by providing a framework for investment decisionsfor industry and other power station owners to decarbonise their own operations.The UK oil province is mature and annual production is falling rapidly. CO 2 injection into mature oil fieldsis an established technique for recovering otherwise unrecoverable oil. Durham University have estimatedthat the use of CO 2 to enhance oil recovery has the potential to recover >3b barrels of oil from the NorthSea if applied soon. The network which has been designed to transport CO 2 from Teesside and thewider North East takes CO 2 to the central North Sea where it is available for commercial EOR use. Thespine pipeline has been sized to transport c15mteCO 2 /yr. If applied for EOR this could produce c1bbarrels of otherwise unrecoverable oil extending the life of existing oil fields for up to 20 years.97

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTThe status of CCS & the role of the UK Demonstration ProgrammeThe operation of the CCS chain has already been, and continues to be, demonstrated at 3Mte CO 2 /yr bythe Dakota Synfuels plant which has 10 years experience of operation of the full chain. The Synfuelsplant consists essentially of a syngas production unit which uses pre-combustion capture to produce adecarbonised hydrogen rich syngas which at Dakota is used in the manufacture of synthetic natural gas.In the power generation application, which is technically more straight-forward than synthetic natural gasproduction, decarbonised syngas is combusted in a Combined Cycle Gas Turbine to produce electricity –3Mte/yr of captured CO 2 equates to a power plant of ~500MWe underlining that there no scale issuesassociated with use of this capture technology and hence full scale commercial projects can beconstructed now 63,64 . However there are no clear reference plants for such Integrated GasificationCombined Cycle Power Stations with capture. This first-of-a-kind risk makes the attraction of debt intoearly projects challenging.There are examples of CO 2 storage in gas fields, oil fields and saline aquifers across the world, includingNorth Sea experience, although most injections are less than 1mte CO 2 /yr. This area has higheruncertainties than the capture element and requires demonstration at large scale in the North Seaenvironment for the different reservoir types available.Hence technology exists, and whilst there are clearly substantial uncertainties, the challenge is for themost developed options to move from the RD&D phase to early market applications. This is primarily anissue of putting in place the appropriate commercial framework to enable the first of a kind risks anduncertainties to be managed. Pre-combustion capture projects at say 400-800 MWe are possible now.The captured CO 2 can be stored, with the uncertainty being the scale of injection irrespective of reservoirtype. The UK has offshore oil fields, gas fields and saline aquifers which may be used for storage.Storage in oil fields holds the prospect of providing the greatest value added as CO 2 injection can beused to recover otherwise unrecoverable oil – this is an established technique on-shore with c25-30mteCO 2 injected annually in oil fields in the USA for this purpose. However offshore experience is minimal atpresent.The Programme therefore needs to address the real first-of-a-kind uncertainties in the early CCS projectseven where the technology exists, notably full CCS chain reliability and large scale storage. It needs to beon a basis which makes CCS a credible investment decision alongside renewables and gas CCGT.Investment capital is limited for all candidate investors – including the major utilities and so thedemonstration programme needs to be structured to enable debt to be secured, and such that the widestpossible range of investors can be involved, as has been achieved for renewables.63 In contrast other capture technologies suitable for power generation (post combustion and oxyfuel) have onlyoperated at small scale and do require substantial scale up.64 Pre-combustion capture can also be used to repower existing coal power stations to utilise cost effectively existing assetswith enhanced output compared with alternative refit options such as post-combustion.98

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECTIn combination, the state of readiness of the technology and the opportunities for value creation support apolicy which seeks to introduce and deploy CCS in the UK as soon as possible. Clearly the currentfinancial environment limits what is affordable by consumers. However, even these first capture projectswill require less support than many other low carbon options.The overriding objective from this tranche of4 CCS projects is not the demonstration of individual capture technologies, but must be to demonstratehow to introduce CCS into the country‟s economy to create long term value.99