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OPTIONS FOR REDUCTION OF UPSTREAM EMISSIONS FROM OIL PRODUCTION:
SIGNIFICANCE, IMPLEMENTATION AND CONSEQUENCES
THEODORE GOUMASKONSTANTINA NTRENOGIANNI IOANNIS STEFANOU
VDBVerband der Deutschen Biokraftstoffindustrie e. V. Am Weidendamm 1AD -10117 Berlinwww.biokraftstoffverband.de
OVID Verband der ölsaatenverarbeitenden Industrie in Deutschland e. V.Am Weidendamm 1AD - 10117 Berlinwww.ovid-verband.de
MARCH 2016
THEODORE GOUMASKONSTANTINA NTRENOGIANNI IOANNIS STEFANOU
OPTIONS FOR REDUCTION OF UPSTREAM EMISSIONS FROM OIL PRODUCTION:
SIGNIFICANCE, IMPLEMENTATION AND CONSEQUENCES
CONTENTS
ABBREVIATIONS 6EXECUTIVE SUMMARY 8
1 INTRODUCTION TO THE PROJECT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
2 OVERVIEW OF UPSTREAM EMISSION REDUCTION MEASURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132.1 Overview of Upstream Emitting Activities 13
2.1.1 Significance of venting, flaring and fugitive emissions 142.1.2 Flaring emissions 172.1.3 Venting and Fugitive emissions 18
2.2 Upstream Emission Reduction Technologies 192.2.1 Overview of APG Utilisation Options 192.2.2 Technologies for APG utilisation 222.2.3 Abatement options for methane emissions 242.2.4 Assessment of UER Technologies 242.2.5 UER technologies based on renewable sources 26
2.3 Upstream Emission Reduction Incentives 262.3.1 Overview of EU crude oil supply 272.3.2 Geography of upstream emissions 282.3.3 Russia 302.3.4 Nigeria 352.3.5 Norway 382.3.6 Iraq 412.3.7 Iran 432.3.8 Canada 44
3 POTENTIAL AND INCENTIVES OF UPSTREAM EMISSION REDUCTION . . . . . . . . . . . . . . . . . . . . . . . . . 483.1 Introduction to the FQD 483.2 Incentives and policies for Upstream Emission Reduction 49
3.2.1 Cap-and Trade Systems 503.2.2 Emission (Carbon) Tax 513.2.3 Direct Regulations 523.2.4 Current practice 52
3.3 The EU legislative context 533.3.1 Emission Intensity Standards and the FQD 533.3.2 The Renewable Energy Directive 54
3.4 The case of California 553.5 The British Columbia case 563.6 Emission offset mechanisms 573.7 The European Emissions Trading Scheme 57
4 ASSESSMENT OF UER SUBJECT TO BE ACCOUNTED FOR UNDER THE FQD . . . . . . . . . . . . . . . . . . . . 604.1 UER reporting and certification mechanisms 604.2 UER project eligibility under FQD Implementing Measure requirements 614.3 Eligible CDM/JI projects under FQD Implementing Measure 644.4 UER potential and abatement costs 674.5 Technical and economic potential of UER strategies 694.6 UER potential under the FQD 71
4.6.1 FQD implementation in selected countries 73
5 PRACTICAL ASPECTS OF UER IMPLEMENTATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 755.1 Monitoring, Reporting and Verification 75
5.1.1 Overview of ISO Standards 755.1.2 ISO standards for UER implementation 775.1.3 EU Regulations referenced in the Implementing Measure 79
5.2 Additionality 805.2.1 Definition of baseline 805.2.2 Project boundaries 825.2.3 Definition of additionality by Member States 82
5.3 Double Counting 835.4 Potential implementation by Member States 845.5 Methodological issues 86
6 KEY FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 896.1 Overview of Tasks 896.2 Concluding remarks 92
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ABBREVIATIONS
AAU AssignedAmountUnits
APG AssociatedPetroleumGas
BCM BillionCubicMeters
BCF BillionCubicFeet
MCF MillionCubicFeet
MCM MillionCubicMeters
CAPEX CapitalExpenditure
CARB CaliforniaAirResourcesBoard
CCS CarbonCaptureandStorage
CDM CleanDevelopmentMechanism
CI CarbonIntensity
CNG CompressedNaturalGas
EEA EuropeanEconomicArea
EFTA EuropeanFreeTradeAssociation
EIA EnergyInformationAdministration
EOR EnhancedOilRecovery
ETS EmissionsTradingScheme
FQD FuelsQualityDirective
FSU FormerSovietUnion
GDP GrossDomesticProduct
GGFR GlobalGasFlaringReductionPartnership
GHG GreenhouseGas
GOR Gas-to-OilRatio
GPP GasProcessingPlant
GTL Gas-to-Liquid
GWP GlobalWarmingPotential
ICCT InternationalCouncilonCleanTransportation
IEA InternationalEnergyAgency
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IOC InternationalOilCompany
JI JointImplementation
LCFS LowCarbonFuelStandard
LNG LiquefiedNaturalGas
LPG LiquefiedPetroleumGas
NGL NaturalGasLiquids
NNPC NigerianNationalPetroleumCorporation
NOAA NationalOceanicandAtmosphericAdministration
NPD NorwegianPetroleumDirectorate
RED RenewableEnergyDirective
RLCFRR British Columbia Renewable and Low Carbon FuelRequirementsRegulation
SNG SyntheticNaturalGas
UER UpstreamEmissionsReduction
USD UnitedStatesDollar
VAT ValueAddedTax
VFF Venting-Flaring-Fugitive
VIIRS VisibleInfraredImagingRadiometerSuite
WTW Well-to-Wheel
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reductiongoals.Othermeasures suchasE-Mobility, LNG,CNGor 1st and2ndGenerationBiofuels would not be needed anymore. Therefore UER could prevent the use ofRenewableEnergies in the transport sector.ThesubstitutioneffectsaredependentonmarketpricesofCO2emissionreductions.Atalowpriceof20US$/tCO2eq.alreadyhalfofthe FQD target could be met through UER. With prices comparable to those ofRenewable Energies the potential CO2 reduction through UER doubles. Anotherimportantinfluenceontheemissionsavingsisthetimeframefortheaccountabilityofthemeasure.
The scope and number of emission reduction projects, as well as the magnitude ofassociated UERs that could presumably be counted towards the FQD target remainunclear.Furthermore,withoutrestrictionsrelatedtotheeligibilityofcandidateprojects,thereisaconsiderableriskthattheFQDtargetisachievedwithreductionsfromprojectsthat would have happened anyway. This would undermine the FQD’s initial purpose:achievingadditionalreductionsinthelifecyclecarbonintensityofroadtransportfuels.
Inordertoestablishsecureandlastingemissionreductionswithoutfraud,anUERprojectisonlyeligibletocounttowardstheFQDifitmeetsanumberofISOstandards.Importantrequirements are concerning the additionally, the quality and the qualifications ofcertifyingbodies,thedeterminationofbaselinescenariosandthereportingsystem.
Other emission reduction options such as biofuels have to meet legally bindingsustainabilitycriteriaandrunthroughaLifeCycleAssessment.Inparallel,UERshouldbeobligedtorespectthesamestandards.
FactsaboutUpstreamEmissionReduction
1. Flaring,ventingandfugitiveemissionsrepresentthemostimportantsourceofGHGemissionsfromoilproductionoperations.Ventingandfugitiveemissionsarisefromoil field operations and devices. Sources include well work-overs and clean-ups,compressor start-upsandblowdowns,pipelinemaintenance,gasdehydrators,wellcellars, separators (wash tanks, free knock outs, etc.), sumps and pits, andcomponents(valves,connectors,pumpseals,flanges,etc.).Flaringofgas,eitherasameansofdisposalorasasafetymeasure,isasignificantsourceofairemissionsfromoilandgasinstallations.
2. Estimatescalculatedfromsatellite imagesofflares(NOAAdata,reportedbyGGFR)suggest that global gas flaring in 2012 was 144 billion cubic meters (bcm). Thisrepresents a massive resource waste and a considerable environmental problem,representing, in termsofemissions,some400milliontons inCO2emissionsand interms of quantity of natural gas wasted, one third of the European Union’s gasannual consumption. According to a recent study by ICCT , these global flaringquantities are comparable to the annual emissions from 125 medium sized (63Gigawatt)coalplantsintheUSA,or,inotherwords,closetotheentireemissionsofBrazil,Australia,FranceorItaly.Insomecountrieswithimportantoilproductionthisisamajorcontributortothenationalgreenhousegasemissionsinventory.
3. Whileflaringemissionscanbeestimatedwithsomedegreeofaccuracy,ventingandfugitive emissions are still very difficult to detect, creating thus an important
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uncertaintyinthequantificationoftheircontributiontoglobalupstreamemissions,ascurrently,measurementfacilitiesarenotwidespread.Somestudies indicatethatGHG emissions related to deliberate venting and leakage of natural gas (fugitive)couldrepresentashareofupto5%oftotalglobalgreenhousegasemissions.
Preconditions and practical challenges that have to bemet if UER are accounted forundertheFQD
1. Projecteligibility: TheFQDdescribes in rough lineseligibleprojects,whicharenotlimitedtothosereducingventingandflaringemissions.Projecteligibilityislefttothehandsofnationallegislatorswhohavealargedegreeofflexibility.Furthermore,ISO14064-2 limits the scope of eligible projects to those that are additional to theappropriatelydefinedbaselinescenario.Inanycase,theImplementingMeasureandtheexpectednon-legislativeguidancethatwillfollowshouldprovidecleardirectionsonwhichprojectscouldbeconsideredaseligible.
2. Additionality:Although theFQDdoesnot includea referenceonadditionality, it isessential to prove - as derived from ISO 14064 - that the emission changes areadditional to what would have been expected in a business as usual scenario.Nonetheless,pooradditionalitycriteriawouldsignificantlyundermineitspurpose.Inthis case, the project baseline, as well as the project boundaries must be clearlydefined. It is therefore essential to develop common rules between projectproponentsandnationaladministrators fromMemberStateson theestablishmentofthesetwoparameters.
4. Implementation by Member States: National administrating bodies must beappointed, which will be responsible for monitoring and receiving emissionreductions from regulated parties and for confirming that reports of emissionsreductionscomplywiththerequirementsoftheFQD.
5. Common rules and criteria among MS: In order to ensure that the appropriatequalityisdeliveredbyallFQD-eligibleUERprojects,itisnecessaryforMStoestablishappropriatecommoncriteriaformeasurementandreportingunderUERschemes.
6. CentralizedUERregistry:TheexperiencefromtheEUETSandtherecenttransitionfrom a distributed crediting system to a centralized approach with a single EUregistry,withstandardizedmonitoring,reportingandverificationproceduresamongMember States shows that under such a system, credit trading is easier, lessadministrationandtransactioncostsarerequiredandthepotentialoffraud/double-countingisreduced.
7. Equal treatment among different emission reduction options: A requirement forbiofuels is a full Life Cycle Assessment; while only a relatively simple CO2 savingcalculation is prescribed for emissions reduction in the fossil fuel sector.Furthermore,inthecaseofbiofuelsthereisactualdeployment,whileinthecaseoffossil fuelsemissions savings, theseappear tohaveanaccountingcharacter. Thus,despite the fact that the accounting of net emission savings is the correctmethodology in the context of climate change policy in the transport sector, itshouldapplytoallemissionreductionoptionsequally.
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1 INTRODUCTIONTOTHEPROJECT
TheArticle7a(1)oftheFuelQualityDirective(FQD)obligessupplierstoreportfrom2011informationon,interalia,theGHGintensityofthefueltheyhavesuppliedtoauthoritiesdesignatedbytheMemberStates.FurthermoretheEuropeanCommissionisempoweredto adopt Implementing Measures concerning the method for calculation and themechanism to monitor and reduce GHG emissions of fuels used in transport. To thisdirectiontherecentCouncilDirective2015/652on"layingdowncalculationmethodsandreportingrequirementspursuanttoDirective98/70/ECoftheEuropeanParliamentandoftheCouncilrelatingtothequalityofpetrolanddieselfuels"wasadoptedtoenforcethe implementation of Article 7a of the FQD. The notion of Upstream EmissionsReduction(UER)wasintroducedwithinthelatterDirective.
Until now, the scope and number of emission reduction projects, as well as themagnitude of associated UERs that could presumably be counted towards the FQDreduction target remains unclear. Without restrictions related to the eligibility ofcandidate projects, there is a considerable risk that the FQD target is achieved withreductionsfromprojectsthatwouldhavehappenedanyway,whichwouldunderminetheFQD’s initial purpose: achieving real reductions in the lifecycle carbon intensity of roadtransportfuels.
Currently,thereisanongoingconsultationbetweentheEuropeanCommission,MemberStates experts and key stakeholders aimed at the development of a commoninterpretationoftheFQDImplementingMeasure(CouncilDirective2015/652).Theoutputofthisconsultationwillconsistofanon-legislativeguidancedocumentonapproachestoquantify, verify, validate, monitor and report UERs. The eligibility, monitoring andverificationproceduresaswellas technicalaspects related toprojects tobeaccountedfor the acquisition ofUER credits are expected to be clarified once the consultation isfinalised and the Implementing Measure is transposed within Member States nationallegislation. The Consultant has considered to the extent possible the evolutions in thecontext of this consultation process during the elaboration of the present Study.Nonetheless,theanalysispresentedinthefollowingSectionsconsistsoftheConsultant’sbroaderunderstanding,basedonathoroughliteraturereviewofrelevantsources.
Theexact implementationofArticle7aof theFQD invariousMemberStatesandmorespecifically the economic cost for achieving the FQD (and RED) targets for emissionsreduction in the transport sector shall have a significant impact on the domesticEuropeanandnationalbiofuelmarkets.Therefore,theassessmentofUERtechnologies,theiraccountabilityinthecontextoftheFQD,theirtechnicalandeconomicpotentialisofcrucialimportancefortheprospectsofthebiofuelsector.
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For this purpose the Association of the German Biofuel Industry has commissionedEXERGIA for theelaborationof a studyonUpstreamEmissionReductionof fossil fuelsrequired in the EU transport sector, as provided in the FQD Implementing MeasureRequirements. Thepresent reportwhich is submitted inMarch 2016 covers threemainTasks:
1. Anoverviewofmeasuresaimingatthereductionofupstreamemissionsforfossilfuelpathways(Chapter2);
2. Thepotential and incentivesprovidedby the FQDand its ImplementingMeasureforupstreamemissionreduction(Chapters3and4);
3. Practical aspects relevant to the implementation of an upstream emissionreductions (UERs) scheme in the context of FQD Art. 7a and its ImplementingMeasure(Chapter5).
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countries with important oil production this is a major contributor to the nationalgreenhousegasemissionsinventory,suchasNigeriawhereflaringrepresentsoverathirdofthecountry’stotalCO2emissions(GGFR,2012a).
Figure2-1CarbonIntensitiesofmajorcrudeoilstreamsfrom"well-to-refinerygate"ingrCO2eq/MJofenergyproduced
-15,0 -10,0 -5,0 0,0 5,0 10,0 15,0 20,0 25,0
Gachsaranoilfield
WestQurna
Kirkuk
Burgan
Ghawar
Manifa
HassiMessaoud
Block17/Dalia
Girassol
GreaterPlutonio
Bonga
ForcadosYokri
CawthorneChannel
Agbada
EscravosBeach
AzeriLight
AzeriCPC
AzeriBTC
Tengiz
Halfdan
Statqord
Ekofisk
Troll
Tyrihans
Gullfaks
Buzzard
Captain
Ninian
Cantarell
Urals
SiberianLight
EsSider
ElSharara
Venezuelacrude
OffsiteemissionsTransport
Misc.
VFF
Processing
Production
Drilling
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While flaring emissions can be estimated with some degree of accuracy, venting andfugitiveemissionsarestillverydifficulttodetect,creatingthusanimportantuncertaintyin the quantification of their contribution to global upstream emissions, as currently,measurement facilities are not widespread. Some studies indicate that GHG emissionsrelatedtodeliberateventingandleakageofnaturalgas(fugitive)couldrepresentashareof up to 5% of total global greenhouse gas emissions4. The sources and the nature oftheseemissionswillbediscussedinthefollowingSections.
EXERGIAhas recently completed a studyonGHGemissionsof fossil fuels consumed intheEUtransportsector form“well-to-tank”, forDGENERastheContractingAuthority.In the context of this project, carbon intensities for allmajor crudeoil and natural gasstreams supplying the EU have been calculated by the use of actual data -whereapplicable-andengineeringmodelsdedicatedtotheestimationoflifecycleemissionsoffuels.Figure2-1presentsthecarbonintensities(referredtoinDirective2015/652as“GHGIntensities”)ofmajorMCONs (MarketableCrudeOilName) supplying theEU transportsectoruptotherefinerygate,thusincludingtheupstreamandmidstreamemissions,asdefinedandestimatedwithinthe“StudyonactualGHGdatafordiesel,petrol,keroseneandnaturalgas”.InthisFiguretheallocationofemissionstoeachlifecyclestageisclearlyillustrated.It isevidentthatventing,flaringandfugitive(VFF)contributessubstantiallytotheoverallupstreamemissions.Therefore,UERmeasureswillmostprobablyfocusoninitiatives and technologies aimed at eliminating this type of emissions. The resultsillustratedinFigure2-1arealsopresentedinTable2-1.
In the Figure 2-1, off-site emissions refer to emissions occurring outside the definedsystem boundaries of an oil or natural gas field. These emissions could result frommaterialsandservicesconsumedduringdrilling(e.g.computingenergyconsumedduringseismicdataprocessing),indirectoffsiteenergyuse(e.g.embodiedenergyconsumedtomanufacturewell casing). Offsite emissions also refer to the net balance of electricityimports/exports(andcouldthereforeappearasnegativeemissions).
Table2-1CarbonIntensitiesofmajorcrudeoilstreamssuppliedtotheEUfrom"well-to-refinerygate"ingrCO2eq/MJofenergyproduced
Drilling Production Processing VFF Misc. Transport Offsiteemissions
TOTAL
Gachsaran 1.3 10.0 0.9 6.4 0.5 1.0 0.5 20.7WestQurna 1.5 3.3 0.8 7.2 0.5 1.0 -0.3 14.0Kirkuk 1.3 4.2 0.9 7.5 0.5 0.6 -0.3 14.6Burgan 1.3 0.3 1.0 3.6 0.5 0.9 -1.3 6.3Ghawar 1.3 0.6 0.2 4.3 0.5 0.8 -0.3 7.3Manifa 10.9 4.3 0.8 4.5 0.5 1.2 2.4 24.6HassiMessaoud 1.5 2.2 0.0 6.7 0.5 0.4 0.6 11.8
4FlaringandVentingofAssociatedGas-CurrentDevelopmentsandImpactsofMarginalOil,ERA-EnergyResearchArchitecture,December2015
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Drilling Production Processing VFF Misc. Transport Offsiteemissions
TOTAL
Block17/Dalia 1.3 0.3 0.7 5.3 0.5 1.0 -0.6 8.4Girassol 1.4 0.1 0.6 5.3 0.5 0.7 -0.3 8.2GreaterPlutonio
1.3 0.2 0.8 5.6 0.5 0.7 -0.78.3
Bonga 1.3 0.2 0.8 4.3 0.5 0.8 -0.8 7.0ForcadosYokri 1.3 0.5 0.1 6.4 0.5 0.8 0.0 9.5CawthorneChannel
1.3 0.3 0.6 15.5 0.5 0.8 -0.318.7
Agbada 1.3 0.3 0.8 7.6 0.5 0.8 -0.6 10.7EscravosBeach 1.4 0.6 0.5 22.4 0.5 0.6 0.2 26.2AzeriLight 1.6 1.3 0.9 3.4 0.5 0.6 -1.2 7.0AzeriCPC 1.6 1.3 0.9 3.5 0.5 0.8 -1.2 7.4AzeriBTC 1.6 1.3 0.9 3.4 0.5 0.8 -1.2 7.3Tengiz 1.6 1.2 1.0 7.2 0.5 1.2 -1.1 11.6Halfdan 1.3 0.6 1.5 3.7 0.5 0.2 -2.4 5.3Statfjord 1.4 0.6 3.8 8.5 0.5 0.1 -9.5 5.3Ekofisk 1.4 0.2 0.7 3.5 0.5 0.4 -1.7 5.1Troll 1.3 0.5 2.2 5.1 0.5 0.3 -4.3 5.6Tyrihans 1.5 0.6 2.4 6.3 0.5 0.1 -6.0 5.5Gullfaks 1.3 0.3 0.9 3.9 0.5 0.1 -2.3 4.7Buzzard 1.4 0.6 0.6 2.6 0.5 0.5 0.0 6.2Captain 1.3 11.1 0.6 4.6 0.5 0.1 1.7 19.8Ninian 1.5 4.1 0.1 3.7 0.5 0.1 0.5 10.6Cantarell 1.3 1.0 0.8 3.4 0.5 0.8 -0.7 7.2Urals 1.3 1.0 1.2 8.5 0.5 0.8 -2.7 10.5SiberianLight 1.3 2.1 1.4 9.7 0.5 1.1 -6.7 9.4EsSider 1.3 0.9 0.8 9.0 0.5 0.6 -0.8 12.5ElSharara 1.4 0.4 0.9 9.3 0.5 0.3 -0.9 11.9Venezuelacrude 1.3 2.1 0.2 3.5 0.5 0.9 0.4 8.9
2.1.2 Flaringemissions
Inoil reservoirs, there isalwaysacertainamountofnaturalgaspresent.Dependingonthepressure in the reservoir, the gas can either be dissolved in theoil, or lay as a capabove the oil. When the oil is extracted, the dissolved gas, also labelled associatedpetroleumgas(APG),follows.Thegas-to-oil(GOR)ratiovariesgreatlyfromoneoilfieldtothenext,rangingfrom1-2m3tothousandsofm3ofgaspertonofoil5.Whentheoilandgasmixturereachesthesurface,thegashastobeseparatedfromtheoilbeforethe
5AssociatedPetroleumGasinRussia-Reasonsfornon-utilization,FridtjofNansenInstitute,2010
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oil enters thepipelines.Most flaringprocessesusually takeplaceat stack topwith thevisibleflame,asopposedto incineration,wherewastegas iscombustedatthefurnace.Flaring during well tests, production of associated gas, refining and other processingstages is used in awayof open flame. There are some reasons for that: first, gasmaycontaincorrosivecompounds,soitcanbequitedestructive,secondly,theremightbetheneedtodisposehugeamountsofgasinashorttime.
Combustionofnaturalgasiscalledflaring,whilereleasingittotheatmosphereisknownasventing.Duetounavailabilityoflocalmarketandtransportationsystemsinproductionareas, operators usually flare or vent associated gas to avoid additional treatment andprocessingexpenses.Decisionofflaringandventingorprocessingofgasmightdependonnaturalgaspriceswhichcouldhaveamajorimpactonit.Forsafetyreasons,ventingisnotacommonpractice.
2.1.3 VentingandFugitiveemissions
Fugitiveemissionsrefertounintentionalmethaneleakagesfromoilandgasoperations,whereas venting emissions are related to the intentional release of methane to theenvironmentformaintenanceorotherreasonsandtheyarebothasourceofgreenhousegasemissionsinmanycountries.Methaneemissionsoccuratallstagesofthevaluechainof natural gas and oil activities, although they concern mainly upstream activities.Methaneemissionspredominantlyoccurduringgasproductionandtransportation(e.g.from compressors, dehydrators and pumps, pneumatic devices, fugitive leakages, wellblow-downsandcompletions).Productionofoilisalsoasourceofmethaneemissionsinmanyregions(e.g.degassingoffluids,flaring/coldventingandproductstorage/loading);however oil upstream activities emit much less methane than natural gas upstreamoperations.
The principal sources ofmethane emissions in the natural gas sector are attributed tounintentional equipment or pipeline leaks. These fugitive emissions occur as the gascirculates at extremely high pressure through different parts of the infrastructure ofnatural gas systems and escapes into the atmosphere through tattered connections inthepipelines,wornpumpandcompressorseals,valvesor flanges.Emissionsalsooccurduringmaintenanceandventingactivities, aswell as throughaccidentsandequipmentfailures.Intheoilsector,methaneemissionsoccurmainlyfromgasventingfromoilwells,oil storage tanks and production equipment. Some studies indicate that methaneemissions from natural gas and oil systems account for approximately 18% and 2%,respectively,ofglobalmethaneemissions.Emissionsareexpectedtogrowasnaturalgasandoilconsumptionincreases,duetoaginginfrastructure.
These emissions are difficult to quantify with a high degree of accuracy and there issubstantialuncertaintyinthevaluesavailableforsomeofthemajoroilandgasproducingcountries(e.g.Russia).Inthepublicdomain,availabledatapredominantlyoriginatefromNorth America (i.e. US and Canada) since very few empirical studies are available forother key oil and gas regions. The main reason for uncertainty in the assessment ofmethaneemissions is the fact thatmeasurementprogrammesare timeconsumingand
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verycostlytoperform,thereforeoperatorstendtorelyontheuseofsimpleproduction-basedemissionfactorswhicharesusceptibletoexcessiveerrors.
2.2 UpstreamEmissionReductionTechnologies
In oil fieldswhere there are important quantities of associatedgas, themost commonpractice utilized until today is flaring, i.e. open air burning of APG. Flaring has severeenvironmentaleffectsandiseconomicallywasteful.Eveninsiteswithinstalledburnersofhigh flaring efficiency, there are big amounts of greenhouse gases released to theatmosphere. The output of the flaring process includes mainly carbon dioxide andquantitiesofmethane,whichcanbequite importantdependingon thecompositionofthe gas and the flaring efficiency. Methane emission from gas flares is the result ofincompletecombustionofthewastegasandthus isrelatedtothedestructionefficiencyoftheflares.
Duetothehazardousconsequencesof flaringgas, it isnotconsideredasanoptionforupstream emission reduction, although it is a solution for minimising the emission ofmethane, which is a much more potent gas than carbon dioxide, in terms of globalwarming. Therefore flaring will not be discussed as an upstream emission reductionoption in the present section, which will rather focus on alternative solutions andtechnologies.
2.2.1 OverviewofAPGUtilisationOptions
For each site where APG is flared, a number of alternative value chains may beestablishedtorecoverandutilizepartofthegas.TheeconomicviabilityofeachoftheseAPGutilisationoptions isaffectedbya largenumberoffactors,e.g.gascharacteristics,location and presence of existing infrastructure, market conditions, etc. The optimalsolutionforaparticularsiteisthushighlycasespecific.
DifferentAPGstreamscanhave largevariations ingascompositionand impurities, andthusmayrequiredifferent levelsof treatment.Thevariation incompositionalsomeansthat different APG streams will provide different product yields and thus differenteconomic values, even when applying the same technological solutions. Some gasutilisationoptions,suchasprocessing intodrygas,LPGornaturalgasoline,havebetterreturnswhentherecoverablegasstreamis“rich”,i.e.,whenitcontainsalargeportionofheavier hydrocarbons. Other options for APG use, such as large-scale electricitygeneration,generallyworkbetterwhenthegasis“lean”.AnAPGstreamwillalwaysbemoreattractivewhenitcontainsfewerimpuritiesandisatanelevatedpressure,duetoreducedcostsrequiredfortreatmentandcompression.
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ThealternativeoptionsavailableforutilizingtheAPGcanbecategorisedasfollows:
1. Reinjection(fordisposalorenhancedoilrecovery)Reinjectionisapurelylocaloption.This isprimarilydonetomaintainthepressureto sustain the levelofoil production (EnhancedOilRecovery - EOR),but thegasmay also be reinjected for preservation for future usage (or to be left in thereservoirs, thusavoidingCO2-emissions,aswellasprovidingsafedisposalofacidgases). Reinjection is a somewhat uncertain option as different geologicalfoundations to different degrees lend themselves to hold gas. It is thus, forgeological reasons, not applicable in all oil fields, and in some regions such asWesternSiberia,theregionwheremostoftheflaringtakesplace,thesedimentaryrock is not suited for reinjection. Reinjectionmay in certain cases also be costly,because the gas needs to be compressed before injected into the reservoir. Thefactthatreinjectedgasin itselfdoesnotproduceanyrevenuesmakesthisoptioneconomicallyunattractivetooilcompanies.Ontheotherhand,ifthereinjectedgascancontributetoenhanceoilrecovery,reinjectionmaybeamorefinanciallyviableoption.TheadvantagesanddisadvantagesofreinjectionarepresentedinTable2-2.
Table2-2Reinjectionofassociatedgas:advantagesanddisadvantages
Option Advantages Disadvantages
Re-injectforfutureuse
Reservoirpreservation Notallformationsaresuitedforreinjectionbecauseofhighcapitalcostforlocalprocessingandcompression
Re-injectforEnhancedOil/GasRecovery(EOR/EGR)
Providesrevenuethroughincreasedoilproduction,mayallowfuturerecoveryofre-injectedgas
NotallformationsaresuitableforgasEORbecauseofhighcapitalcostforlocalprocessingandcompression
2. Powergeneration,localorregional
Power generation may be either local or regional. Local power generationproduces electricity for use on site, thus saving the oil company expenses inpurchased electricity or diesel for power generation. However, not only thesefacilitiesarecapital intensive,butalsotheenergyneedsofanoil fieldare limitedcompared to the available power produced from APG. If there are no localconsumers (industryor communities) in thevicinity that could takeadvantageofexcess power production, local power generation is thus only a limited solution.Regardlessof localor regionalconsumers,powergenerationalsorequiresaccesstoaregionalpowergridtodisposeofsurpluspower.Regionalpowergenerationgathersgas fromanumberofwells, and thus entails even largerprocessing andinfrastructure investments.The revenues fromgassales toelectricitygenerators,assumingasufficientlyhighpricelevelforelectricity,ishoweveramotivatorforoil
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producers to go for this alternative. Another option for power generation is theformulation of joint ventures between oil companies possessing neighbouringfieldsandpowergeneratingcompanies.TheadvantagesanddisadvantagesoflocalandregionalpowergenerationaresummarisedinTable2-3.
Table2-3Localorregionalpowergeneration:Advantagesanddisadvantages
Option Advantages Disadvantages
Localelectricitygeneration
Savingsinpurchasedelectricityorpurchaseddieselforpowergeneration
Capitalcost;fieldtypicallyrequiresonly30%ofthepowerthatAPGcouldgenerate.Otherlocalmarketsmaybelimitedornon-existent
Regionalelectricitygeneration
Economicandenvironmentalsavingsinpurchaseddieseltogeneratepower–engineofregionalintegration
Capitalcostofgatheringandprocessinginfrastructure;lowdomesticelectricitypriceslimitpriceofferedforgas.
3. Compressionforsaleasdrygas
AnotheroptionforAPGutilisationistoexploititcommerciallyasnaturalgas.APGhasamuchlowerdensitythannaturalgas,andastheAPGneedstobetransportedwithin the natural gas pipelines, it is necessary to compress it beforehand. Thisprocess is expensive, and in order to be economically worthwhile, the oilcompaniesneedtobeabletosellthecompressedgasatasufficientlyhighprice.There isevidentlyalso largerpotential forprofits if theflowofAPG issubstantialandstable,allowingforeconomiesofscale.
4. Processing of APG into liquid products: liquefied natural gas (LNG), liquefiedpetroleumgas (LPG–propaneandbutane),petrochemical feedstocks,ordiesel(gastoliquids–GTL)Processing the gas into LNG, Liquefied Petroleum Gas (LPG), petrochemicalfeedstocks, and gas-to-liquids (GTL) diesel for sale are other options for utilizingthe APG which may generate income for the oil company. These options mayhowever be highly capital intensive, requiring both gathering infrastructure andprocessing facilities. Both LPG and GTL processing requires external processingfacilities, and a certain scale of size is normally required for processing to be aneconomicallyviableoption.This issuemayhoweverbeovercome in therelativelynear future, as technology is currently being developed for smaller scale GTLprocessingunits.ThemaincharacteristicsoftheseproductsarepresentedinTable2-4.
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UERStudy FinalReport
EXERGIAS.A. 26
A high level qualitative assessment of available UER categories against theaforementioned aspects is illustrated in Table 2-6, where green colour stands forhigh/positive prospects, yellow stands for medium prospects and red stands forlow/negativeprospects.
2.2.5 UERtechnologiesbasedonrenewablesources
Besidesventing,flaringandfugitiveemissionsmitigation,upstreamemissionreductionsmayalsobeachievedbytheuseofrenewableenergysourcesintheextractionoffossilfuels.
SolarEOR,forinstance, isamethodforenhancedoilrecovery,whichis likelytoplayanimportantroleinthemixofEORtechnologies.Insteadofburningnaturalgastoproducesteam, solar EOR involves the use of Concentrating Solar Power (CSP) technology toproducesteam.Mirrorsareusedtoreflectandconcentratesunlightontoreceiversthatcollectsolarenergyandthenconvertittoheat.Theheatisthenusedtoproducesteamfromwater.TheuseofsolarEORcouldreducedemandfornaturalgasrequiredforEOR,which canbe redirected toothereconomicactivities, suchaspowergeneration,waterdesalination and as feedstock and energy for industrial processes. The technology ofsolar EOR can also be installed in oil fields with limited availability of associated gastherebyprovidingawaytocreateandinjectsteamforEORwithnocapitalinvestmentingasinfrastructure.ExamplesofprojectsutilizingthetechnologicaloptionofSolarSteamGeneration Enhanced Oil Recovery include the oilfields of McKittrick and Coalinga inCaliforniaaswellasthePetroleumDevelopmentinOman.
Otherrenewableenergyapplicationsforthefossilfuelupstreamsectorincludetheuseofphotovoltaicandwindturbinesforpowergeneration.Thesetechnologiescanbeusedforenergy intensive operations in oil and gas fields, such as powering compressors andpumpsfortransportingoilandgasthroughgatheringpipelinestoprocessingplants,ortogeneratetheelectricityandheatneededforon-siteoperationsandlivingquarters.Theseactivities,however,donotrepresentanimportantshareofthetotalupstreamemissionsoffossilfuels,thereforetheydonotofferextensiveemissionsreductions.
2.3 UpstreamEmissionReductionIncentives
Fossil fuel companies have various incentives and/or obligations for implementingUERmeasuresirrespectiveofFQDthatarerelatedtolegalrequirements,owninitiativesfromimprovingthetechnicalandfinancialefficiencyoftheiroperations.Thissectionprovidesan overview of the regulatory requirements, incentives of fossil fuels companies andexisting APG utilisation projects in target countries. The analysis will focus on thecountrieswhichrepresentthemostimportantsuppliersoffossilfuelstotheEU,withanemphasistotheonesthathavesignificantemissionsintheirupstreamactivities,aswellas those that have implemented successfully upstreamemission reductionpolicies andinitiatives.
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UERStudy FinalReport
EXERGIAS.A. 32
metering.ThisDecreeallowsproducerstosubtract investmentcostsforAPGutilisationprojects fromthe fines, includingfor investments ingaspipelines,compressorstations,separationunits,facilitiesproducingelectricityandheatandforre-injection.Italsoallowsacompany to reach the95%utilisation targetbyaggregatingproductionacrossallofacompany’s fields. However, if the company is not able to reach this rate throughaggregation,finesarecalculatedforeachfieldindividually.Whilethisflexibilitycouldleadto some economic efficiency in targeting APG utilisation investments, it coulddisadvantagecompaniesthathaveasmallnumberoffields.
ThelicensesissuedbytheMinistryofNaturalResourcestooilandgasproducersincludethepermissiontoprocessandsellassociatedgas,re-injectit inthereservoir,utilizeit inthefacilityorproduceelectricity,orevenflarespecifiedamounts.Insomeregions,mostnotably in Khanty-Mansiysk and Yamalo-Nenets, it is mandatory to include an APGutilisationpercentageinthelicenceagreement.
CarboncreditsFollowingaprotractedprocessanddelays,Russianauthoritiesestablishedprocedurestoapproveprojectsdevelopedundertheso-calledJointImplementationmechanismoftheKyoto Protocol and to issue Emission Reduction Units (ERUs) that can be sold in theinternationalcarbonmarkets.ThefirstprojectapprovalsweremadeinJuly2010,andthefirst carbon creditswere issued in December of the same year. Over 20 flaring-relatedJointImplementationprojectshavebeenapproved,andsuchprojectsnowrepresentoneofthelargestcategoriesofapprovedJointImplementationprojectsinRussia.However,since2011,JointImplementationprojectshavebecomelessimportant,partlybecauseofapricecollapseforcarboncreditsandpartlybecauseRussiatookthedecisionnottojointhe second commitment period under the Kyoto Protocol, hencemaking new Russiancarboncreditsfromsuchprojectsineligibleincarbonmarkets.Itnowseemsunlikelythatthe emission reduction benefits of newAPGprojectswill have any economic value forinvestors in the near future. However, there are processes internally in governmentalinstitutions in Russia to design a national emissions trading system (a cap-and-tradescheme)13.
OverviewofAPGutilisationfacilitiesThemainAPGutilisationactivityinRussiaconcernsgasprocessingplants.In2010,48%ofproducedAPGwassuppliedtogasprocessingplants,whereitwasusedasfeedstockforproduction of marketable hydrocarbon products such as dry stripped gas, liquefiedpetroleumgasandstablegascondensate.Due to thehigh liquidcontentofmanyAPGstreams,expandinggasgatheringnetworksand increasingtheavailablegasprocessingcapacity represents one of the most promising options to reduce flaring in many oil-producingregionsinRussia,particularlyinareaswithsignificantexistinginfrastructure.
13Associated Petroleum Gas Flaring Study for Russia, Kazakhstan, Turkmenistan and Azerbaijan,CarbonLimits,2013
UERStudy FinalReport
EXERGIAS.A. 33
Apart from theoil companiesbywhomAPGutilisation ismostly seen as anobligation,thereisanotheractorinRussiathathasAPGprocessingasitsmainoccupation–SIBUR.SIBURutilisesaround17bcmofassociatedgas,whichamountsto57%ofthetotalvolumeofassociatedgasprocessinginRussia.ThecompanyrendersdeepAPGprocessing,thusproducingpetrochemicalswithhighvalueadded.InordertoensurecontinuoussupplyofAPG to its processing facilities SIBUR aims at creating long-term partnerships with oilcompanies.In2010,56%ofprocessedAPGwassuppliedtogasprocessingplants(GPPs)controlled by SIBUR. Some upstream operators have entered into joint ventures withSIBURtosecurelong-termcontractsforaccesstothelatter’sprocessingcapacityandforsalesofprocessedproducts.
Surgutneftegaz14andTatneftareamongthefewcompanies in the industry thatdonotuseprocessingplantsbelongingtoSIBURsincetheyownlargegasprocessingplantsthatwere built decades ago: Surgut Gas Processing Plant and Minnibaevo Gas ProcessingPlant. As Tatneft for years has been processing APG and supplying the products of itsprocessing to the petrochemical industry, Surgutneftegaz plans in the long term toproduce advanced petrochemicals at the company’s facilities. The main share of APGproducedbySurgutneftegazhasthroughtheyearsbeensuppliedtohigh-capacitypowerplants in the region: Surgut State District Power Stations. Around 70% of the APGproducedbythecompanyin2010wassuppliedtothesepowerplantsand,inaddition,itsown electricity production constituted more than 30 percent of its total electricityconsumption, ensuring the company’s technological processes, heating of houses,buildingsandcarparks15.
MajorrecentprojectsinassociatedgasprocessingfacilitiesaresummarizedinTable2-8.Thelistisnotexhaustive;howeveritpresentsanumberofimportantprojectsinRussia.
15ReducinggasflaringinRussia:Gloomyoutlookintimesofeconomicinsecurity,JuliaS.P.Lowe,OlgaLadehaug,Poyry,2012
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Figure2-7DistributionofgasreservesinIraq(Source:IraqEnergyInstitute,2013)
InJanuary2013,Iraq’sgasproductionreached2.234bcf/day.Currently,only400mcf/dayis captured from the south and 300 mcf/day is captured from the north, leaving 1.2bcf/day wastefully flared because of the lack of infrastructure and other persistentchallenges. In addition, 340 mcf of free gas (non-associated gas) was commerciallyproducedfromthenorthernfieldofKhorMor.
Atpresent there isnospecific regulation inplaceaiming to reduce theamountsofgasflared and to promote utilisation of associated gas. However, there have been someeffortstotakeadvantageofthewastedgasthataccompaniesoilextractionactivitiesbystateownedoperators,mainlyforeconomicreasons.
OverviewofAPGutilisationfacilitiesTheKirkuk-basedNorthGasCompanyoperatestwenty-threedegassingstationsatoilandgas fields across central and northern Iraq. Twelve gas-compressor stations collectassociatedgasbeforefeedingittoagasprocessingplantatKirkuktoproduceLPG,drygas,naturalgasoline,andsulphur.TheKirkukgasprocessingplantconsistsoftwotrainswithatotalcapacityof1.2milliontonnesannuallyofLPG.
The Basrah-based South Gas Company has formed a joint venture with Shell, which isresponsibleforgatheringandprocessingassociatedgasfromtwelvedegassingstationsinthesouthernoil fieldstoproducedrygasandnaturalNGLs,aswellasoperatingLPGstorage facilities and export terminals. The company operates on four main sites: theNorthRumailaNGLplant, theKhor al-ZubairNGL/LPGplant, the Iraqi Storage Terminaland Iraqi Receiving Terminal, and the LPG shipping terminal at Umm Qasr. The NorthRumaila NGL plant had a capacity of associated gas processing of 680mcf/day, but iscurrentlyoperatingat20-35%ofthatcapacityduetothelackofgassupplies.TheKhorAl-Zubair NGL/LPG plant separates liquids from raw gas to produce propane, butane,gasoline, and dry gas and has the capacity to produce 4million tonnes per annum ofpropane and butane, plus 1.5 million tonnes annually of gasoline. The decline inprocessingratesatbothNorthRumailaandKhoral-Zubairarelargelyduetotheneedforrehabilitation; there is an insufficient number of compressors at the oil fields and an
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TheUSEnergyInformationAdministrationalsoreportedinMarch2013thatIran'sflaredgasamountin2011wasabout45mcmofgasperday.Duringthisyear,about30%ofIran'stotalassociatednaturalgasproductionwasflared.
OverviewofAPGutilisationfacilitiesThe AMAK project in Iran, which was commissioned in February 2005, is the mostextensive environmental project implemented by the National Iranian South OilCompany, to collect associatedgas fromoneof the reservoirs in theAhwazoil field inSouthern Iran. The project was so big that they needed to construct seven sour gascompressors,oneacidgascompressor,asweeteningplant,280kmlonggaspipelineand100kmofpowerlines.Thegoalofthisprojectistopreventflaringof7mcmofsourgasperday.
AnumberofotherAPGutilisationprojectsareexpectedtobeoperationalsoon,includingthe Kharg and Baregan associated gas gathering and NGL project, which involves theconstructionofagastreatmentplantandanNGLrecoveryfacilityatKhargIslandinIran.Thetwofacilitieswill receiveandprocessgasfrombothonshoreandoffshoresources.About300mcf/dayofgaswillbegatheredfromoffshorefieldsandanother300mcf/dayfromonshoreprocessingfacilities.OnshoregaswillbefedfromtheAboozar,DoroodI,IIand III and Foroozan oil processing facilities. Offshore gas will be gathered from theAboozar, Bahregansar, Foroozan, Nowrooz and Soroosh fields. The projectwill help inreducingflaringof600mcf/dayupto700mcf/dayofgasfromthesefields.
2.3.8 CanadaCanada is one of the most important unconventional oil producing countries in theworld. Its resources of crude oil were estimated to have a remaining potential of 339billionbarrelsasofDecember2012.Ofthis,oilsandsaccountfor90%andconventionaloil10%. There are twomajorproducingareas inCanada, theWesternCanadaSedimentaryBasin,whichincludesAlberta,SaskatchewanandpartsofBritishColumbiaandManitoba,andoffshoreeasternCanada.AlthoughCanadaisthesixthlargestproducerintheworld,it produces only about 4% of total daily production. In 2013, 71% of Canadian crudeproductionwasexportedtotheU.S.andonly2%wasexportedtooverseasmarkets.
The EU is not currently being suppliedwith oil from Canada, as unconventional fuels -whicharefarmoreemittingthanconventionalones-aregenerallynottracedintheEUenergybalance.However,itisanticipatedthatunconventionalcrudeoilfromCanadawillbeimportedinEuropeinsignificantquantitiesinthefuture.ThereasonisthatCanadianauthorities have imposed very strict regulations on upstream emissions, thus the EUinitiativefor“cleaner”fuelswilldrivethemarkettowardsnewsuppliers,suchasCanada.The total emissions of Canadian crude oil pathways (tar sands), compared to theweightedaverageofEUcrudepathwayarepresentedinFigure2-9.
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The largest part of unconventional deposits until very recently was extracted viaconventional mining techniques. In 2011, according to Alberta oil and gas industry,approximately 51% of oil sands production came through mining extraction. Currently,approximately2/3ofoilsandsareextractedviain-situmethodsandapproximately1/3viamining.Albertainthefuturewillrelytoagreaterextentonin-situproduction,as80%ofthe province’s proven bitumen reserves are too deep to recover using conventionalminingtechniques.
UpstreamemissionsregulationThelargestemittingprovincesofCanada,intermsofupstreamactivitiesareAlbertaandBritish Columbia. Both of these provinces have taken legislative measures aiming atreducingtheirupstreamemissions;atthesametime,bothAlbertaandBritishColumbiapossesstheirownregulatedoffsetmechanisms.
Alberta
Alberta is the country's largest emitter but was also the first province to regulategreenhousegasemissionswiththe2003ClimateChangeandEmissionsManagementAct(and latertheSpecifiedGasEmittersRegulation).Existingfacilitiesthatemitmorethan100,000tonnesofgreenhousegasperyearhavetocaptheiremissionsintensityat12percentbelowtheiraveragefor2003-2005.Facilitiesbuiltinthelast15yearscanphaseinthecapovereightyears.
Emissions intensity doesn'tmeasure emissions in absolute terms but factors in GDP tomeasureGHGasaunitofproduction.Thismeansthatifproductionincreases,emissionscan increase and still fall within the target. Alberta has estimated that its absoluteemissionswon'tbegintodeclineuntil2020.
LargefinalemittersarerequiredtoreducetheirGHG intensitybyupto12%peryear,aspartofthe2002ClimateChangeandEmissionsManagementAct(CCEMA)andthe2007SpecifiedGasEmittersRegulationpassedbytheAlberta legislature,bypayingapenaltyof $15 for every tonne over their limit. The money is invested in emission reductiontechnologies by the Climate Change and EmissionsManagement Corporation. Emitterscan purchase credits to offset emissions from those who have already reached theirtargetsorarenotsubjecttotheregulationsbuthavevoluntarilyreducedemissions.
Alberta'semissions-reductionstrategyreliesheavilyoncarboncaptureandstorage(CCS)and Enhanced Oil Recovery (EOR). The province plans to reduce 70% of its emissionsthrough CCS. GHG reductions from substitution of a proportion of the bitumen binderusedinconventionalhotmixasphaltforasulphurproductarealsoquantified.
BritishColumbia
Introducedin2008,thetaxonfossilfuelsnowstandsat$30/tonneofCO2eq.andappliestogasoline,diesel,naturalgas,heating fuel,propaneandcoal—and topeatand tireswhen used to produce energy. Revenue raised, which was $1.21 billion in fiscal year2013/14, goes toward loweringother taxes. The tax covers about 70per centofBritish
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Columbia (B.C.)'s emissions, and it's estimated it will reduce emissions by about threemilliontonnesannuallyby2020.
B.C. is amemberof theWesternClimate Initiative underwhich severalU.S. states andfourCanadianprovinceshaveagreedtoestablisharegionalcap-and-tradeprogramandseta regionalemissions-reduction targetof 15percentbelow2005 levelsby2020.TheBritish Columbia Renewable and Low Carbon Fuel Requirements Regulation (RLCFRR)includes both aminimum requirement for renewable content in petrol (5%) and diesel(4%)fuelsandacarbonreductionrequirementforthesefuelsbytargetinga10%reductionby2020.Asystemofcredittransactionsforbothrenewablefuelsupplyandlowcarbonfuel supply between oil suppliers has been established under the auspices of theregulatoryauthority. Inpractice theoil companieswereable toallocateonpaper theirlowerCarbonIntensity(CI)fueltotheBritishColumbiamarket,whileallocatingalltheirhigher CI fuels to other markets. This fact led the authorities to revise the RLCFRRtowardsconsideringsinglereportablepetrolanddieselCI.
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3 POTENTIALANDINCENTIVESOFUPSTREAMEMISSIONREDUCTION
3.1 IntroductiontotheFQD
The Fuel Quality Directive (FQD) sets a target of 6% (Article 7a) reduction of GHGemissions from road transport. Moreover, the FQD (Article 7a(1)) obliges suppliers toreport from 2011 information on, inter alia, the GHG intensity of the fuel they havesuppliedtoauthoritiesdesignatedbytheMemberStates.FurthermoretheCommissionisempoweredtoadoptImplementingMeasuresconcerningthemethodforcalculationandthemechanismtomonitorandreduceGHGemissionsoffuelsusedinroadtransport.TothisdirectionarecentCouncilDirective(2015/652)on"layingdowncalculationmethodsandreportingrequirementspursuanttoDirective98/70/ECoftheEuropeanParliamentand of the Council relating to the quality of petrol and diesel fuels"was launched tosupportimplementationofArticle7aoftheFQD.
The main features of the recent Directive regarding the method for calculatinggreenhousegasemissionsoffuelsarebasedonaveragedefaultvaluestorepresenttheGHGintensityperfuelandonharmonizedannualreportingbysupplierstoMSandMSto the Commission. In otherwords theDirective assigns all suppliers a single, EU-wideaverage carbon emissions intensity for each oil and gas form supplied each year,regardless of the great spread of GHG emissions of particular fuel feedstocks andproduction pathways associatedwith individual suppliers. In addition, Article 7a of theFuel Quality Directive (FQD) allows for the opportunity of suppliers to use ‘UpstreamEmissions Reductions’ (UERs) to comply with targets in order to reduce the carbonintensityoftheirtransportfuelsupply.
Therefore the FQD does not include an explicit mechanism to favour the usage ofconventionaloil/gasoverhighcarbonemittingunconventionaloils/gases,evenofsomehigh emitting conventional oils/gases over other less emitting ones.Moreover, despitethe fact that flaring and venting comprise by far the largest part of GHG emissionscompared toother sources throughout theoil andgas supply chain, theFQDdoesnotclearlyfocusonthesetwoemittingprocesses.
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3.2 IncentivesandpoliciesforUpstreamEmissionReduction
There are many policy tools available to help induce greenhouse gas emissionsreductions,includingvoluntaryactionsandagreements,financialincentivesandsubsidiesandinformationinstruments.
Market-basedapproachesarethoughttobemosteffectivebecausetheysignalthatGHGemissions have amonetary value, stimulating actions thatwill lead emitters to reducetheir emissions. There are different ways of pricing carbon that can be used incombination with other mechanisms, such as restrictive regulations. While it isacknowledgedthatputtingapriceoncarbonisaneffectivewaytoreduceemissions,thebestmarketmechanismsorcombinationofmechanismsforpricingcarbonismuchmoredifficulttoestablish.
GHGemissionsunits can take the formof allowancesor credits.Allowances are issuedundercap-and-trademechanisms,wheretheemissionsofacountry,asector,oragroupof installations are capped and allowances are issued and allocated to the country orentitiesinlinewiththecap;anexampleisthetradingofAssignedAmountUnits(AAUs).Emissions Trading Schemes (ETS) are a sub-formof cap-and- trademechanisms,wherethe allowances are allocated to individual installations or companies; examples includethe EU ETS or the California ETS. Credits are units that are issued under a creditingschemeforemission reductionsachievedagainstacreditingbaseline;examples includethe CDM, JI, the bilateral Joint Crediting Mechanism (JCM) established by Japan, orvoluntary offsetting schemes (e.g. Climate Action Reserve, Verified Carbon Standard,GoldStandardFoundation,etc.).
Mechanisms can be established under international, bilateral, or domestic governance.Under international governance the issuance of units is governed by an internationalbody according to internationally agreed rules, such as the CDM under the KyotoProtocol. Under domestic governance, the issuance of units is governed by one Party;while under bilateral governance two (or more) Parties are involved in the issuance,transferanduseofunits.ExamplesaredomesticorregionalETS,suchastheEUETSandtheCaliforniaETS,ortheJCMestablishedbyJapan.
Finally, when referring to mitigation pledges, we mean pledges or commitments byPartiesmadeundertheUNFCCC,includingitsprotocols,amendmentsanddecisions,thatexpressalimitonGHGemissionsforaneconomyorasectorofaneconomy.Mitigationpledgescanvarywithregardtotheirscopeandcoverageandtheirlegallybindingstatus.Examples of mitigation pledges are commitments under the Kyoto Protocol or theeconomy-widemitigationpledgesmadeundertheCancunAgreements18.
18 Addressing the risk of double counting emission reductions under the UNFCCC, StockholmEnvironmentInstitute,2014
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These creditsmay alsobe allowed to apply to a facility’s targetwithin adomestic cap-and-trade system. The price of international credits and carbon offsets, as well as thequantityofthemthatwouldbeallowedforuseagainsttargets,willinfluencethepriceofcreditswithinthecap-and-tradesystem.Thecredibilityofthecreditswouldinfluencetheeffectivenessofthescheme.
3.2.2 Emission(Carbon)Tax
A “carbon tax” or a tax on GHG emissions imposes a direct fee (the carbon price) onemissionsourcesbasedontheamountofGHGtheyemit,butdoesnotsetalimitonGHGemissions. In a manner similar to cap-and-trade options, the tax could be imposedupstreamordownstream.Itcouldrequireimporters,producersanddistributorsoffossilfuelstopayafixedfeeontheCO2containedinfuelsoldand/oritcouldrequireemitterstopaybasedontheiractualemissions.
Inordertomakeataxmorepoliticallyacceptable,revenuesgeneratedbycarbontaxesaretypicallyrecycledbacktoemittersandthegeneralpublic,whomaybepayinghigherpricesforgoodsandservicesaffectedbythetaxes.Revenuerecyclingcouldtakemanyforms, including compensating adversely impacted firms and segments of society,proportionally returning revenue based on tax paid, reducing other labour or capitaltaxes,orinvestingintechnologyandinnovation.
Anemissiontaxprogram,unlikeacap-and-tradescheme,doesnotguaranteethatagivenemissions reduction targetwill bemet,becauseemittersmaychooseeither topay thetaxortoreduceemissions.Asaresult,thelevelofthetaxwilllikelyhavetobeadjustedover time to meet a given emission target. This system does, however, provide pricecertainty,becausethetaxlevelissetbeforethepolicyisimplemented.
Analyses have shown that an emission tax is more likely to allow for adoption of thecheapest mitigation strategies, as well as easier administration, than a cap-and-tradescheme. How policy-makers distributed revenues from the tax would determine theeconomicimpactandeffectivenessofthetax.However,politicalacceptabilityislikelytobe a major obstacle, since new taxes and fuel price increases would garner negativereaction.Anemissiontaxmaybemorepoliticallyattractiveaspartofalargertaxreformprogram.
Generallyspeaking,existingcarbontaxesareprimarilyaimedatfossilfueluseandrelatedemissions, and have beenmostly applied to the household sector and services sector.Industry typically benefits from various exemptions because of concerns aboutinternationalcompetition.BritishColumbia’scarbontaxissomewhatdifferentinthatitisbroadinscopeandtherearefewexemptions.
Althoughsomecorrelationshavebeenfoundbetweencarbontaxesandgreenhousegasreductions,itisdifficulttospecificallyattributeemissionreductionstoacarbontaxforanumberofreasons,including:
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easytocouplewithreductiontargetsandarepoliticallyverydifficulttobeimplemented.Cap-and-trade systems are more complex to be implemented, must be very carefullyplanned (the compliance mechanisms and the volume and distribution of permits, inparticular, must be well-thought-out) and do not provide cost assurance. In addition,companiesmaypassontoconsumersthecosts incurredbyacap-and-tradesysteminaway that is less transparent than a tax. Scandinavian countries pioneered the use ofcarbon taxes in the early 1990s. While a few other jurisdictions,most recently BritishColumbia,havesincefollowedsuit,carbontaxeshavenotbeenwidelyadopted.Rather,the cap-and-trade system has emerged as the internationally preferred marketmechanism formitigatingGHGemissions. Despite some initial problems, the system isgrowing both in scope and in importance. Various legislative initiatives in the UnitedStatesalsoindicatethatacap-and-tradeschemeislikelytobecomethedominantmarketmechanism for mitigating GHG emissions in the United States, particularly given thepoliticaldifficultiesinvolvedwithintroducinganewtax.InCanada,authoritiesclaimthatoftheoptionsavailable,the“mosteffectiveandefficientpolicythatwouldresultindeepGHGemission reductions is amarket-basedpolicy, suchasanemissions tax, a cap-and-trade system, or a combination of the two. This core policy then needs to becomplementedbyother regulatorypolicies, to forceemission reductions frompartsoftheeconomythatdonotrespondtoapricepolicy.”However, it isdifficult toestablishtheexactmixofpricingpolicieswhichwouldbemosteffectiveandpoliticallyacceptable.
3.3 TheEUlegislativecontext
3.3.1 EmissionIntensityStandardsandtheFQD
TheFQDaims to create a system that sets tough standards for emissions intensitybutdoesnotexplicitly favour theuseofcomparativelycleaner fuels. Itdoesnot includeanexplicitmechanismtofavourtheusageofconventionaloiloverhigh-GHGunconventionaloils and lacks a mechanism to distinguish various conventional oils, which display asurprisinglywidespreadofemissionsintensities,insomecasesevenhigherthanthoseofmanyunconventionaloils.Operationalfactorssuchastheflaringorventingofmethaneare thekeyelementsdrivingtheemissions intensityofGHG intensiveconventionaloils.Yetthesefactorsarepoorlyunderstoodandcharacterizedincurrentpolicy.20
Similar systems as the FQD,manipulating emission intensity standards, combinedwithoffsetcreditsmechanisms(suchasUERcredits)havealreadybeenimplementedinothercases.Specifically,thefirst low-carbonfuelstandardmandate intheworldwasenactedby California in 2007, with specific eligibility criteria defined by the California AirResourcesBoard(CARB)inApril2009buttakingeffectinJanuary2011.Similarlegislation
20Emissionintensitystandardsandthepushforcleanerfuels,DavidLivingston,December2014
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The RED requiredMember States to submit by June 2010 National Renewable EnergyActionPlans settingout inter alia the contributionexpectedof each renewableenergytechnologytomeetthe2020targets,includinginthetransportsector.AccordingtotheNationalRenewableEnergyActionPlans,MemberStatescollectivelyintendedtoslightlyover-achieve the 10% target. Their intention was to use about 8.5% of first generationbiofuels, 1% of second generation biofuels and 1% of renewable electricity,most of thelatter in railways rather than in cars. In total this adds up to approximately 10.5%renewable energy in transport; with the different weight factors that the Directiveappliestosecondgenerationbiofuelsandrenewableelectricityusedincars itwouldbecountingasapproximately11.5%.However,thistargetwillmostprobablynotbeachieved,astherecentECDirective1513/2015,issuedon9September2015,statesthattheshareofenergyfromfirstgenerationbiofuelsshallbenomorethan7%ofthefinalconsumptionofenergy intransport intheMemberStates in2020.Therefore,anoverachievementoftheREDtargetbyMemberStatesisnowadayshighlyunlikely.
Accordingtoreliablesources21,the10%shareofrenewableenergy intransporttargetedby the RED for Member States is expected to contribute approximately 4% in thereduction of GHG emissions of the FQD target. It is, therefore, expected that theremaining2%willbecoveredbytheuseofUERunits,asprovided inthe ImplementingMeasure.
3.4 ThecaseofCalifornia
CaliforniaisapioneerinestablishingasystemofcalculatingandreportingGHGemissionssetting as objective the reduction ofwell-to-tank Carbon Intensity (CI) of fuels used intransport. The relevant regulationLCFS (California Low Carbon Fuel Standard)requiresfuelproviderstoreducethecarbonintensityoftransportationfuelsby10%by2020compared to 2010. Since 2011 and after long discussions and implementation of firsteffortstomonitorandcontroltheCIofoilproducts,theCaliforniaAirResourcesBoard(CARB) decided the adoption of the California Average Approach. By that system theaverage emissions intensity of the California crude basket is to be calculated usingOPGEE,anemissionsmodellingtooldevelopedbyCARB,takingintoconsiderationtheCIofallcrudessuppliedtoCaliforniainayear.IncasetheaverageCIoftheCaliforniacrudebasket was higher than the baseline year CI, then an additional “California averageincrementaldeficit”inGHGemissionsisestimated.Thedeficithastobecoveredbyalloilsuppliersbyobtainingasoffset theproperCA-LCFScredits. IncasetheCaliforniacrudebasket evolved to a lower averageCI than in thebaseline year, then the fuel supplierswerenotbenefitedwith any specific credit.A fuel provider for a list of predeterminedalternative fuels (electricity, biogas CNG, biogas LNG, fossil CNG derived from NorthAmerican sources, etc.) with low CI may generate LCFS credits for that fuels only byelectingtooptintotheLCFS.
21UKDepartmentofTransport
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Under this system the allocation of the cost of the poor performance of one year isimplemented to all oil suppliers either achieving the CI reduction target individually ornot.Thereforetheincreasedcostsofpoorperformancewillbespreadacrossthewholeoil industryandevidentlytheCaliforniaAverageApproachwillbeparticularlyineffectivein preventing increase in fossil fuel GHG emissions. However, there is an incentive tosupport,throughtheoffsetsystem,lowcarbonfuels,whichwill increasepenetrationinthemarketandthuscontributetothedecreaseoftheoverallCIofthefuelsused.
3.5 TheBritishColumbiacase
The British Columbia Renewable and Low Carbon Fuel Requirements Regulation(RLCFRR)includesbothaminimumrequirementforrenewablecontentinpetrol(5%)anddiesel (4%) fuels anda carbon reduction requirement for these fuelsby targetinga 10%reduction by 2020.A systemof credit transactions for both renewable fuel supply andlowcarbonfuelsupplybetweenoilsuppliershasbeenestablishedundertheauspicesoftheregulatoryauthority.
ThereisamethodologyofRLCFRRallowingfuelCItobecalculatedinoneofthreeways.ThedefaultCIvaluesforfossilfuelsarereportedandpublicizedandthebiofuelsuppliersare allowed to report the default value for their corresponding fossil fuel rather thanhaving feedstock specific defaults. Alternatively by the use of the GHGenius modelspecificCI values for fuelsmightbeestimated,or the regulatoryauthoritymight, at itsdiscretion,allowotherapproachestobeused.
Currently there is no incentive for a supplier of a higher than the default CI diesel orpetroltocalculateafuelspecificcarbonintensityvalue,thusdieselfromtarsandswouldbenot reportedat its actualCI,but ratherat the lowerCIof thedefault value.On thecontrary, forfossil fuelsofCIbelowthedefaults,there isan incentivetoreportamoreaccurateCI.ThereisalsoanincentivetoreduceCIforarefiningorproductionprocessincase the produced fuel CI becomes better than the default, or improves further theexisting lower than the default CI. For some big oil suppliers operating in severaljurisdictions andusing various crudes, theRLCFRR systemallows them the situationoffuelshufflingratherthanactualCIreduction.InpracticetheoilcompanieswereabletoallocateonpapertheirlowercarbonintensityfueltotheBritishColumbiamarket,whileallocatingalltheirhigherCIfuelstoothermarkets.ThisfactledtheauthoritiestorevisetheRLCFRRtowardsconsideringsinglereportablepetrolanddieselCI.
TheRLCFRRcomplementsotherprovincialandfederalGHGpolicies.Thefederalvehicleemissions regulations are increasing the energy efficiency of the transportation sector,while thecarbontax isaffectingdriverbehaviorandvehiclepurchases.Meanwhile, theRLCFRRwillensurethateachunitofenergythatisconsumedfortransportationresultsinfewer GHG emissions from a full lifecycle perspective, including production,transportation and consumptionof the fuels.Once theRLCFRR iswell established, thecarbon intensityof fuelscanbe further reducedtomatch theneed forGHGreductionsandcreatethedemandformorelowcarbonfuels.Thepolicycreatesalargermarketfor
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mayexclude installationsfromtheEUETSwhichannuallyemit lessthan25,000tonsofCO222.
The EU ETS currently represents a “downstream” emissions trading system: it is theconsumers of fossil fuel, i.e. the emitters ofGHGs,whohave to acquire allowances. Inotherwords,allowanceshavetobeheldnotbythesuppliersoffossilfuelatthetopofthesupplychain,butbyinstallationoperatorsorairlinesatthebottomthatactuallyemittheGHGs.ItsefficiencycouldbeenhancedbyextendingittoothersectorswithhighGHGemissionlevels,suchastheupstreamoilandgassector.However,asmentionedbefore,the European upstream oil and gas sector does not have a significant potential foremissionreduction,thustheEUETSwouldnotcontributetoaconsiderableextenttothegenerationofUERs.
22 Art. 2, 3a-3g, 4 and 24 Directive 2003/87/EC of 13 October 2003 establishing a scheme forgreenhousegasemissionallowancetradingwithintheCommunityandamendingCouncilDirective96/61/EC.
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national interpretation of the option to credit Upstream EmissionsReductions (UERs) or through a voluntary scheme with the intention ofgeneratingcreditstofeedintoMemberStateimplementations.
− The second sub-option (Option 3b, ‘the Implementing Measurerequirements’)outlinedhowtherequirementsforUERreportingcontainedin the ImplementingMeasure for FQDArticle 7a are to be implemented attheMemberStatelevel.
Eventually,Option3bprevailedandwasincorporatedinDirective2015/652/EC.
4.2 UERprojecteligibilityunderFQDImplementingMeasurerequirements
The ImplementingMeasurerequirements thatwereeventuallyadopted in theDirectiveprescribe that eligible projects are not explicitly limited to those reducing venting andflaring emissions, and could potentially include other types of UER projects. Morespecifically, the eligibility criteria of the Directive (Annex I, part 1), as well as a briefanalysisoncontroversialeligibilityaspectsarepresentedinTable4-1.
Table4-1UEReligibilitycriteriainthecontextofDirective2015/652/EC
Eligibilitycriterion
Directive2015/652phrasing
Interpretation
Typeofeligiblefacilities
UERsshallonlybeappliedtotheupstreamemission'spartoftheaveragedefaultvaluesforpetrol,diesel,CNGorLPG.
The language used in the Directive allows for theeligibility of projects at natural gas extraction siteseven though the emission reduction potentialcomparedtooilfieldsissignificantlylower,sincetherearealreadynaturalgas transport facilities and there isan absolute economic incentive to utilize gas. Inaddition, natural gas use in the EU transport sector iscurrently very limited and is not expected to risesignificantlyinthefollowingyears.
Furthermore, the Directive allows for the eligibility ofprojectsbeyondventingandflaring.For instance,fuelswitchingfromafuelwithcarbonintensitytofuelwithlower carbon intensity could be considered ascreditable with appropriate argumentation andreporting.
Typesof In cases where gas-lift gas is necessary in order to
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Eligibilitycriterion
Directive2015/652phrasing
Interpretation
associatedgas
increasewell pressure (EOR), associated gas from thesame oilwell is compressed and effectively reinjectedasgas-liftgas.Insomecaseswhereahigh-pressuregasfieldislocatednearby,operatorsimportthisgastouseasgas-liftgasintheoilwell,becauseitislessexpensivethancompressingandrecyclingassociatedgas.Incaseswhere associated gas from the local oil well orpressurized gas-lift gas is imported from independentgas fields, it is eligible for crediting if that gas waspreviously being flared but can be captured by theproject.
Transporttothemarket
There is no restriction related to the way thatrecovered gas is transported to market. This includestransportbypipeline,trailers,trucks,carriers,andCNGmobile units. The gasmay be processed into dry gas,LPG, etc. or compressed into CNG before transport(althoughinsuchcasessomeadditionalmonitoringandreportingisrequired).
Flaringefficiency
UERsshouldbeestimatedandvalidatedinaccordancewithprinciplesandstandardsidentifiedinInternationalStandards,andinparticularISO14064,ISO14065andISO14066.
ISO 14064-2 does not directly prohibit projects thatcontribute to the improvement of flaring efficiency,which could in theory be eligible. Certainly, the ISOallows for “appropriate GWPs” to be used in theassessmentofemissionsreductions(ISO14064-2article5.8). This would support the possibility of creditingmethanedestructionbasedonthedifferencebetweenthe GWP of the combusted methane and that of theresultantCO2.Althoughthereisnodirectrestrictiononthe eligibility of emissions savings delivered throughimproved flare efficiency, there are requirements fortreatmentofaccuracyanduncertaintythatmight limitthepossibilitytocreditsuchprojects.
Providing UER credits to such projects includes largeuncertainty due to measurement difficulties andinaccuracies. As an adverse effect, it could evenincrease emissions as operators would have theincentive to flare inefficiently until the UER projectrealization. Therefore, flaring efficiency improvementprojects are most probably not going to be counted
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Eligibilitycriterion
Directive2015/652phrasing
Interpretation
towardstheacquisitionofUERcredits.
Ventingandfugitiveemissionseligibility
Venting and fugitive emissions are treated with largevariationsamongdifferentemissionreductionschemeswith respect to crediting. In the CDM/JI ventingreduction projects do not receive additional creditsrelated to the higher global warming potential ofmethanecomparedtocarbondioxideanditisassumedthat methane is flared. In contrast, the Directive2015/652 allows the crediting of methane destruction(as the Alberta Offset System), even though someattentionisrequiredwithrespecttotheinterpretationoftheISO14064.
Priorflaring,modeoftransport,enduse
-
The Directive poses no restrictions with respect towhether flaring or venting occurred before projectcommencement,modes of transport, end uses of thegas, the types of gas to be eligible (i.e. associated orgasorgaslift).
Geographicallocationofprojects
UERsoriginatingfromanycountrymaybecountedasareductioningreenhousegasemissionsagainstfuelsfromanyfeedstocksourcesuppliedbyanysupplier.
The Directive sets no geographical restrictions on thecountriesinwhichUERsmaytakeplace,contrarytotheCDMmechanism.Projectsfromallcountriesandfieldswill be eligible under the FQD and its ImplementingMeasure.
Completiondate
UERsshallonlybecountediftheyareassociatedwithprojectsthathavestartedafter1January
Existingprojects (i.e. those thathavebeencompletedprior to 1 January2011)arenoteligible to receiveUERcreditsastheydonotrespecttheruleofadditionality.Oneissuethatcouldcreatecontroversyisthefactthatcertain projects could be proven to be financially notviable under the current value of CERs and thusfinancial support could be required. Nonetheless, thespecificissuerequiresthoroughinvestigationandstrict
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Eligibilitycriterion
Directive2015/652phrasing
Interpretation
2011. regulation.
Additionality
ItisnotnecessarytoprovethatUERswouldnothavetakenplacewithoutthereportingrequirementsetoutinArticle7aofDirective98/70/EC;
The ImplementingMeasure requirement excludes theprincipleofadditionality(i.e.therequirementtoprovethatreductionswouldnothavetakenplacewithouttheadditional incentives of the Fuel Quality Directive).Nonetheless, ISO standard 14064 deals with theconcept of additionality in a way that there is somecontroversy.
More specifically, emission reductions may only beaccounted towards compliance with the FQD if theproject generating them can be demonstrated to beadditional in the context of ISO 14064-2. This impliesthattheprojectdevelopershouldproveacasetoarguethat theproject is additional, in particularwith regardto any legal obligations on the company, and to thequestion ofwhether the projectwould have occurredanywayforcommercialreasonsregardlessofemissionsconcerns.
4.3 EligibleCDM/JIprojectsunderFQDImplementingMeasure
Various CDM projects could be eligible for compliance under the FQD. As discussed,therearethreeapprovedCDMmethodologiestocreditdisplacementofgasproductionthroughreductionsinventingandflaringofgasfromoilproduction:AM0009,AM0037,andAM0077.ThesearepresentedinTable4-2.Table 4-2 Comparison between approved CDMmethodologies to credit reductions in
ventingandflaringofgasfromoilproduction(source:ICCT)
Methodo-logy
PriorVenting/Flaring
Required
EligibleSourcesofgas
EligibleTransportOptions
Eligibleenduses
Leakageincalcs
Fugitivesincalcs
AM0009None(butoilwellsmustbein
Associatedgas+lift
Pipelineorbytrailer,
Notspecified;
Required Notincluded
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Methodo-logy
PriorVenting/Flaring
Required
EligibleSourcesofgas
EligibleTransportOptions
Eligibleenduses
Leakageincalcs
Fugitivesincalcs
operation) gas truck,carriersasCNG
partialuseonsiteallowed
AM0037 3years
Associatedgas
Not
specified
Gasusedasfeedstockandpartiallyasenergysourceinchemicalprocess
Notincluded
Required
AM0077
3years Associatedgas
CNGmobileunitsorpipeline
Heat(inthecaseofCNGmobileunittransport)
Required Notincluded
AccordingtotheNon-profitAssociation“TransportandEnvironment24”13projectsthatqualifywith the FQD’s requirements are illustrated in Table 4-3, including one projectlocatedinaLeastDevelopedCountry(Angola).Intotal,these13projectshaveestimatedannualemission reductionsofmore than 18million tonnesCO2eq.The totalupstreamemissionreductionsfromtheflaring&ventingprojectinAngolacouldaccumulateupto13.7milliontonnesofCO2eqperyearforexample,morethanenoughtomeetthefull6%GHGintensityreductiontarget.Table4-3Numberofprojectsregisteredsince2011andemissionreductionsaccordingto
hostcountries
Hostcountry NumberofprojectsEmissionreductions
(metrictCO2e/annum)
Angola 1 13,709,960
24ΤheroleofinternationaloffsetsintheFuelQualityDirectiveDecember2014.
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Hostcountry NumberofprojectsEmissionreductions
(metrictCO2e/annum)Indonesia 3 386,799
China 2 359,635
India 1 65,811
Ghana 1 2.603,226
Nigeria 1 288,147
Oman 1 775,250
PapuaNewGuinea 1 57,438
Thailand 1 26,163
UnitedArabEmirates 1 109,142
TOTAL 13 18,381,571
Similarly JI projects can be eligible to prove compliance with the FQD. Out of all theregisteredJIprojects, just4ofthemconcentrateonassociatedgasutilisation,butallofthesehavebeensetupinRussia.ThesearepresentedinTable4-4.Table4-4RegisteredJIprojectsconcerningassociatedgasutilisation
ITLprojectID Title Hostparty Lastupdated
RU1000200 Yety-Purovskoe Oil fi eldAssociated gas recovery andUtilisationproject
RussianFederation
15Dec10
RU1000229 Associated Petroleum GasRecovery for the Kharampur oilfieldsofRosneft
RussianFederation
09Mar11
RU1000230 Associated Gas Recovery ProjectfortheKomsomolskoyeOilField
RussianFederation
09Mar11
RU1000239 SNGgasgathering RussianFederation
17Mar11
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4.4 UERpotentialandabatementcosts
Variousstudieshaveassessedinvestmentandabatementcostsforemissionsreductionsfrom flaring and venting. Each study has used different methodology and focused ondifferent geographic areas and technologies. Table 4-5 lists only the CO2eq reductionpotentialthatcanbeachievedatnegativecosts,(i.e.profits)asreportedintheliterature,for the oil sector only, while Table 4-6 reports the reduction potential and associatedabatementscostsforoilandgassectorsgiventheavailabilityofcarbonpricesforcreditsgeneratedfromassociatedpetroleumgas(APG)recovery.
Total carbon mitigation potential from economically profitable flaring and ventingreductionprojectsintheoilsectorinEU-15,Canada,Nigeria,RussiaandtheUScombinedcanbeintherangeof127-143MtCO2eperyear. It istobenotedthatthemagnitudeofcarbon abatement will increase if the price, APG can fetch in the market. increases.Moreover,asTable4-6indicates,additionalreductionscanbeachievediftheprojectscanaccruerevenuesfromsellingcarboncredits.Atacreditpriceof$100/tonneCO2e,carbonmitigation can increase to 41.8 MtCO2e/yr in 2020 from projects in Libya, Nigeria,Iran/YemenandRussia/Azerbaijan compared to 20MtCO2e/yr in theabsenceof carbonprices.Thesecountries/regionstogetheraccountfor54%oftotalEUcrudeoilimports.
Table4-5Reportedcarbonmitigationpotentialatabatementcostfortheoilsector
Study Region/Country
ProjectType Flaring/venting
ReductionPotential(mtCO2e)/
year
InvestmentCost(pertCO2e)
AbatementCost(pertCO2e)
Ecofys,2001
EU-15
Increasedgasutilisation,
maintenance,and
improvementsof
compressors
emissionsfromassociatedgas,processventsandflares,engines,turbines,
compressorsandpumps,
systemupsets,and
transmissionanddistribution
activities.
0.6€0-30($0-
41.4)€-1to-4(-$1.4
to5.5)
JohnsonandCoderra,2012
Alberta-CA
Collection,compression
andpipeline
Flaringandventing
17-33 US$-40to<0
PFCEnergy,
RussiaVarietyof
projectsfrom 70
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Study Region/Country
ProjectType Flaring/venting
ReductionPotential(mtCO2e)/
year
InvestmentCost(pertCO2e)
AbatementCost(pertCO2e)
2007 electricitygenerationtoacombination
ofgasprocessing
plantsanddrygassales
ICF,2013
Russia/Azerbaij
anand
Nigeria
Flaringfugitiveandventing
20 <0
ICF,2014US-
onshoreoil
Fugitiveandventingemissioncontrol
25.6 US$6.9US$-5.7to
$-0.5
TotalreductionpotentialfromEU-15,Canada,Nigeria,Russia,andUSfromprofitableprojects
127-143MtCO2e
Table4-6Mitigationpotentialandcostsforprojectsthatareprofitablewithadditionalrevenuethroughcarbonprices
Study Region/Country
ProjectType
Emissionstype
ReductionPotential(mtCO2e)/
year
InvestmentCost(per
tCO2e)
AbatementCost(per
tCO2e)
Ecofys,2001 EU-15
Emissionsfromassociatedgas,
processventsandflares,engines,
turbines,compressorsandpumps,systemupsets,and
transmissionanddistributionactivities.
25.4 N/A$1.38-124.2
Ecofys,2009
EU
(a)eliminatingchronicleaksfrompipelines,distributionfacilities,
etc.fornaturalgas,(b)eliminatingchronicleaksfrompipelines,distributionfacilities,etc.forAPGfromoilproduction(c)reducingflaringemissionsand
10.3 N/A
$2.89-14.9
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Study Region/Country
ProjectType
Emissionstype
ReductionPotential(mtCO2e)/
year
InvestmentCost(per
tCO2e)
AbatementCost(per
tCO2e)(d)eliminationofventing.
GEEnergy,2010(Projectlevelassessment(notatcountrylevel)
Indonesia,Tanbun
MiniLPGplant,pipeline
flaring0.4 $30 $15
QatarProcessing,NGLandpipeline
flaring2.4 $260
$6.5
NigeriaProcessingNGLandpipeline
flaring2.6 $302
$7.5
NigeriaProcessingNGLandpipeline
flaring0.3 $32 $10
ChinaProcessingNGLandpipeline
flaring0.3 $30 $11
ICF,2013
Libya
Variousoptions
Flaringfugitiveandventing
1.8 -
Upto$100
Nigeria 11.1 -Iran/Yem
en1.2 -
Russia/Azerbaija
n26.6 -
ICF,2014
US-onshoreoilandgas
Fugitiveand
ventingemissioncontrol
11618.9
Upto$27.8
JohnsonandCoderre,2012
Alberta,Canada
Collection,compressionandpipeline
Flaringandventing
28-46 Upto$15
CarbonLimits,2013
Russia,Kazak,
Turkmenistan
Azerbaijan
Flaring
reductionsinexistingfields
31.5US$8billion
N/A
4.5 TechnicalandeconomicpotentialofUERstrategies
Flaring and venting emission reduction projects in most of the times entail costs tooperator. This implies that the number of projects could be registered under the FQDemissionreductionschemes,andthusthelevelofCO2reductionthatcouldbeachieved,
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is heavily dependent on the value of emission reductions credits. Thus, in practice thetheoretical emission reductionpotential,which is estimated tobe in the rangeof 127–140MtCO2eq,issignificantlylower.ICCTinordertoconcludetoarealisticUERpotentialin thecontextof theFQD, in itsanalysis,hasusedthree levelsofcreditprices: amoremodestpriceof$20pertonofCO2eabatement,amoderatepriceof$50pertonandamoreaggressivepriceof $200per tonCO2e.Thehigherprice is consistentwith typicalestimates,giventhecostofcarbonabatementthroughthesupplyofbiofuels,whicharelikelytobetheprimaryalternativeroutetoFQDcompliance.
ICCThasassessedtheannualemissionsavingspotential25 forthefouroptions,byusingand re-analysing26 results from previous studies. It should be noted that there isconsiderableuncertaintyrelatedtotheexactportfolioofprojectsthatwouldbeeligibleunderalloptions.ThisuncertaintyishigherfortheImplementingMeasurerequirementsoption as some issues with respect to project eligibility have to be elucidated anddiscretionisleftondecidedbyMemberStatestodecidewhichprojectsareeligible.
TheresultsoftheanalysisbyICCTbasedonICFandEnergyRedefinedprimaryworkareillustrated in Table 4-7. The precise methodology and the underlying figures used forconcluding to the specific results are described within the original studies. At a CO2creditvalueofcarbonpriceof$20/tCO2e,approximately24MtCO2eofannualUERcouldbe delivered for a cumulative crediting period. Thiswould amount to slightly less thanhalf of the FQD target of a 6% reduction in the carbon intensity of European transportfuels. Inthecasethatonly1year iseventuallyaccountedforascreditingperiod(2020),i.e.whattheImplementingMeasurerequirementprescribes,thepotentialissignificantlylower ranging from 2.30 million tonnes CO2eq (for $20/tCO2e carbon price) to 15.5milliontonnesCO2eqfor(for$200/tCO2ecarbonprice).Thisisapproximatelybetween5%and30%ofthe6%FQDtarget.
Table4-7Totalemissionssavingsthatcouldbeachievedwiththeprescriptiveoptionforboth15-20and1yearcreditingperiods
TOTALSAVINGS(MILLIONTONNESCO2)
TOTALSAVINGS(MILLION$GASVALUEAT$2/MBTU)
Creditprice $20/tCO2e $50/tCO2e $200/tCO2e $20/tCO2e $50/tCO2e $20o/tCO2e
15-20yearcreditingperiod
23.57 37.44 42.94 555.0 881.7 1010.3
25ThereductionofupstreamGreeenhouseGasEmissionsfromflaringandventing.ReportbytheInternationalCouncilofCleanTransportationtotheEuropeanCommission,DGforClimateAction,2014.26ThisrepresentstheachievableemissionssavingscalculatedbyICFplustheadditionalemissionssavings that could be achieved as a result of more streamlined requirements under theprescriptiveoptions
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Thefouroptionsarecomparedalsowiththegapremainingtoachievethe6%FQDtarget.The latter target is set by considering that the 10% renewable energy target under theRenewable Energy Directive (RED) has already been achieved and is indicated by thedottedpurpleline.
ThepotentialforOptions2,3aor3btodelivermorethanhalfoftheemissionsreductionsrequiredtomeetthefull6%GHGintensityreductiontarget.At$50pertonCO2e,Options3bcouldsupply75%ofthistarget.Thisconclusioniscontingentuponanadequatecreditpriceandadequatetime(andmarketconfidence)toinitiateprojects.Uncertaintyorlackof confidence in upstream emission reduction credits could substantially reduce theactuallevelofinvestment.
Figure4-2Potentialemissionsreductionsfromventingandflaringundereachoptionifcreditsareawardedover theproject lifetime(source: ICCTbasedonEnergyRedefinedandICFflaringreport)
According to estimates and assuming a clear framework of incentives, UERs could beenough to cover the gap between the emissions reductions expected from REDcomplianceand theFQD target.Nonetheless,currently theFQDonlyhasa singleyearwithabindingcompliancetarget(2020),whichwillsignificantlyreducethepotentialtodeliverreductionscomparedtoasystemthatdeliveredongoingvalue.
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Figure4-3Potentialemissionsreductionsfromventingandflaringundereachoptionifcredits are awarded in one year (2020) only (source: ICCT based on EnergyRedefinedandICFflaringreport).
Thus,ifcreditvaluewasonlyconsideredfor2020,thepotentialwouldbegreatlyreducedaccordingtotheICCTanalysisandexplainedintheprevioussection.Thisisillustratedin
Figure 4-3 where UERs could only make a significant contribution to meeting the 6%carbonintensityreductiontargetundertheFQD,ifcreditpriceswerehigh.Furthermore,it should be considered that this could significantly overestimate the potential, asaccordingtoICCTtheassessmentassumesthatinvestorswouldtreatthecarbonpriceasguaranteed, whereas in fact the willingness of oil field operators to invest could belimited. Inpractice, thisproblemcouldbe largely resolved ifMemberStates implementtheoptional interimGHGreductiontargets,or ifMemberState implementationsof theFQDdonotexpirein2020.
4.6.1 FQDimplementationinselectedcountries
SomecountriessuchasGermanyandtheCzechRepublichaveintroducedinterimtargetsfor GHG emission targets in the transport sector prior to 2020 moving beyond therequirementsoftheFQDwhichrefersonlyto2020.
Before 2015, the use of biofuels in theGerman transport sector was promoted by anobligation requiring the use of biofuels. This obligation was usually met by blendingbiofuels with fossil fuels. According to EU legislation, the share of renewables in the
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transportsectoristobeincreasedto10%by2020.In2015,thesocalledGHGReductionQuotawas implemented inGermany.Now themineraloil industry isobliged to reducetheGHGemissionsstemmingfromtheirproduceby3,5% in2015and2016respectively.From2017ontheGHGreductionwillhavetoamountto4%eachyearandwillriseto6%in2020whereitistoremain.Apartfromblendingwithbiofuelsthereisalsothepossibilityof Upstream Emissions Reductions, E-Mobility and Liquified Petrolem Gas (LPG) orCompressedNaturalGas(CNG)countingtowardsfulfillment.
The Czech Republic is another country that has introduced interim GHG emissionreduction targets in the transport sector. The target set by the European CommissionundertheDirective2009/28/EC istoreach13%shareofenergyfromrenewablesourcesagainstgrossfinalenergyconsumptionanda10%shareofrenewableenergysourcesintransportby2020.TheCzechRepublic ingeneraldoesnothavesignificantproblems inmeeting its targets, although in 2010 they did not fulfil the target to replace 5.75 % ofenergy content of fossil fuels consumed in transportation with biofuels. Blending ofbiofuelswith fossil fuelshasbeenmandatory in theCzechRepublic sinceSeptember 1,2007. The Czech Republic transposed the European Renewable Energy Directive (RED)intoActonAirProtectionno.201/2012and toGovernmentDirectiveno.351/2012.GoalsstemmingfromthatlegislationareshowninTable4-8.
Table4-8GHGemissionreductiontargetsinthetransportsectorinCzechRepublic
PeriodObligationtoreduceGHGemissionsby(%)
MinimumGHGemissionssavingsin
biofuels(%)
Shareofbiofuelsandrenewableelectricityintransportationontotalconsumption(%
energycontent)
2014-2016 2 35 5,71
2017-2019 4 50 8,00
2020 6 60 10,00
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5 PRACTICALASPECTSOFUERIMPLEMENTATION
ThepresentSectionconcernstheassessmentofUERaccountingandimplementationintheEUand inMemberStates,basedon theavailable information todate. Theanalysisfocuses on the issues of verification, additionality, double counting and potentialimplementationproceduresthatareexpectedtoberequiredbytheMemberStates.
5.1 Monitoring,ReportingandVerification
The FQD Implementing Measure requires that the upstream emissions reductions arecalculatedandverifiedinaccordancewithinternationalstandards,specificallyISO14064,ISO14065andISO14066:
“UERs shall be estimated and validated in accordance with principles and standardsidentified in InternationalStandards,andinparticular ISO14064, ISO14065andISO14066.TheUERsandbaselineemissionsaretobemonitored,reportedandverified inaccordancewith ISO 14064 and providing results of equivalent confidence of Commission Regulation(EU) No 600/2012 (1) and Commission Regulation (EU) No 601/2012 (2). The verification ofmethods for estimating UERs must be done in accordance with ISO 14064-3 and theorganisationverifyingthismustbeaccreditedinaccordancewithISO14065.”
In the following paragraphs, the relevant ISO standards are being further analysed, inorder to provide a better understanding of the implications and issues relevant to themeasurementandmonitoringofGHGemissionstowardsUERassessment.
5.1.1 OverviewofISOStandards
ISO14064consistsofthreeparts,eachwithadifferenttechnicalfocus.Parts1and2arespecifications for the quantification, monitoring and reporting of GHG emissions andemission reductions (as well as removal enhancements), respectively, and Part 3 is aspecificationforthevalidationorverificationofGHGassertions.
Part1ofthestandardisentitled“Specificationwithguidanceattheorganizationlevelforquantificationand reportingofgreenhousegasemissionsand removals”.Thispartof thestandard addresses the conducting of greenhouse gas emission inventories oforganizationsusingabottomupapproachtodatacollection,consolidationandemissionsquantification, by providing principles and requirements for the development of theorganization’sGHGinventories.
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ISO14065 isentitled“Requirements forgreenhousegasvalidationandverificationbodiesfor use in accreditation or other forms of recognition”. It requires that a validation andverificationbodyestablishesandmaintainsaproceduretomanagethecompetenceofitsauditing personnel. GHG validation and verification bodies must ensure that auditingteams have the necessary competence to effectively complete the validation orverificationprocess.Supportingtheseprinciplesaregeneral requirementsbasedonthetasks that the validation or verification teams must be able to perform, and thecompetencerequiredtodoso.
ISO14066:“Competencerequirementsforgreenhousegasvalidationteamsandverificationteams” provides GHG validation teams and verification teams with guidance forevaluation.Toachieveconsistency in the internationalmarketplaceandmaintainpublicconfidence in GHG reporting and other communications, there is a need to definecompetencerequirementsforGHGauditingteams.ISO14066isusedinconjunctionwithISO14065.
Figure5-1presentstherelationshipand interactionbetweenISO14064(allthreeparts),14065and14066.
ISO 14064-2 specifies principles and requirements for determining project baselinescenariosandformonitoring,quantifyingandreportingprojectperformancerelativetothebaselinescenarioandprovidesthebasisforGHGprojectstobevalidatedandverified.It sets, therefore, acomprehensive framework inassessingUERprojects,whichare inturnvalidatedinaccordancewithISO14064-3byateamofcompetentverifiersaccordingtoISO14066workingforacompetentorganizationfollowingtheprinciplesofISO14065.
5.1.2 ISOstandardsforUERimplementation
ISO 14064-2 “includes principles and requirements for determining project baselinescenariosandformonitoring,quantifyingandreportingprojectperformancerelativetothebaseline scenario”. It is, therefore, vital to determine the baseline level of emissionsrelevanttotheconcernedproject.Thedefinitionofbaselinescenario,asgivenintheISOStandard: “hypothetical scenarios for GHG emissions and removals that would haveoccurredintheabsenceofaproposedproject”,indicatesthattheassessmentofbaselineGHGemissionsmustbebasedonabusiness asusual scenario, so as toprove that anyconcernedprojectisadditionalto“commonpractice”.Thenotionofadditionalityandtheissueslinkedtoitwillbeaddressedinthenextparagraphs.
It must also be noted that ISO 14064 defines a set of requirements concerning theprinciples of conservativeness, completeness, consistency and accuracy. The termconservativenessmeansthatinemissionsestimationoneshouldtakereasonablestepstoavoid overestimating emission reductions, even where this creates a possibility thatreductionswillbeunderestimated.CompletenessmeansthatallrelevantGHGemissionsand sinks should be assessed, and all relevant information should be provided tovalidators and verifiers. Consistency allows comparisons to be made in GHG related
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results inGHGemissions reductionsor removalenhancements thatareadditional towhatwouldoccurinthebaselinescenario”.Itis,thus,essentialtodefinewhatisconsideredasbaselinescenarioineachcase.
ISO14064-2providesadefinitionofbaselinescenarioasthe“hypotheticalreferencecasethat best represents the conditions most likely to occur in the absence of a proposedgreenhousegasproject”andnotesthat“thebaselinescenarioconcurswiththeGHGprojecttimeline”. The project proponent needs to consider “the project description, includingidentifiedGHGsources,sinksandreservoirs;existingandalternativeprojecttypes,activitiesand technologiesprovidingequivalent typeand levelof activityofproductsor services tothe project; data availability, reliability and limitations; other relevant informationconcerning present or future conditions, such as legislative, technical, economic,sociocultural, environmental, geographic, site-specific and temporal assumptions orprojections”. The principle of conservativeness dictates that “the predictive quality ofquantifying many baseline scenarios, where there is the risk of over-estimating GHGemissions, requires a different approach. Consideration should be given to all feasiblebaseline scenarios forGHGemissions,and the selectedscenario shouldbeplausibleoverarange of assumptions for the duration of the baseline application. Usually a baselinemethodology is used to select the baseline scenario. A conservative scenario is usuallyadopted among scenarios that are equivalent in terms of completeness, consistency,transparencyandrelevance”.
Inestablishing thebaselinecase itwouldbeexpected thataprojectproponent shoulddemonstrateeither that thebaselinecasewouldbeconsistentwith local legislation,orthatlocallegislationrepresentsnormalbusinesspractice.Itshouldalsobedemonstratedthat the baseline case would be considered financially viable – i.e. that financialconsiderations alone would not have been reasonably expected to cause the projectparticipant to implement the project in question. In brief, a system of additionalityrequirementsbasedonISO14064woulddetermineadditionalityatthediscretionofthequalifiedvalidatorappointedfortheproject,andwithreferencetoanyguidelinesset inplace by the body administering the crediting scheme in question, whether a privateentityoranationaladministrator27. InordertoensureequalcreditingcriteriaacrosstheEU, itwill,therefore,be importantforMemberStatestoestablishappropriateschemesformeasurementandreportingofUERs.
In addition, according to ISO 14064-2, “the criteria may consider a balance betweenpracticalityandcost-effectivenesswith theGHGprojectprinciples”.Averificationschememay therefore legitimately allow an alternative definitionof baseline dictating that thecost reduction delivered by the project must be proportionate to any reduction ofemissions.
Emissionsavingsmustbecalculatedasthedifferencebetweentheprojectandbaselinescenarios.Foremissions reductions tobeeligible tobe claimedasUERs theymustbe
27“Thereductionofupstreamgreenhousegasemissionsfromflaringandventing”,ICCT,2014
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additional to anyemission changes thatwouldhavebeenexpected in themost likelyscenario (baseline). Under certain conditions, projects may be considered ineligibleunless theyaredevelopedwithanexplicit scopeofGHGemissions reduction, includingenergyefficiencyprojects.
5.2.2 Projectboundaries
For the purpose of the FQD Implementing Measure, “upstream emissions means allgreenhouse gas emissions occurring prior to the raw material entering a refinery or aprocessingplantwherethefuel,asreferredtoinAnnexI,wasproduced”,whileinAnnexI,itisstatedthat“UERsshallonlybeappliedtotheupstreamemission'spartoftheaveragedefaultvaluesforpetrol,diesel,CNGorLPG”.Therefore,anyfacilityorprocessincludedinthefossilfuelsupplychainpriortoenteringtherefinery,forthecaseofoilproducts,ortheprocessingfacility,inthecaseofnaturalgas,iseligibletoreportemissionreductions.
According to ISO 14064-2, the reported emissions must cover all sources, sinks andreservoirs controlled, related to, or affected by the project in question. Asmentionedpreviously, this part of ISO 14064 does not contain any definition about projectboundaries.ISO14064-1,ontheotherhand,setstheprinciplesforGHGinventorydesignand development, in terms of organisational and operational boundaries, although itdoes not explicitly define the system boundaries in which the concerned emissionreductionsareset.
In terms of geographical location, the project boundarywill typically include the fossilfuelextractionsite,collection,transport,andprocessinginfrastructureuptothepointatwhich any processedmaterial leaves the site, and all new infrastructure developed aspart of the project aiming at reduction of GHG emissions. It could also include neworexisting offsite infrastructure if these are determined to be relevant to the emissionsperformance of a project, such as a gas gathering and processing plant for APGutilisation. ICCT gives a detailed analysis of potential emission sources that may beincluded within the UER project boundaries. However, there is still a lot of room forinterpretation for system boundaries of projects accounted under UER creditingmechanisms.Theirdefinitionmustbebasedonacommonunderstandingamongprojectproponents in order to avoid uncertainty in proving the additionality of proposedprojects.
5.2.3 DefinitionofadditionalitybyMemberStates
The interpretation of the principle of additionality byMember States authorities musttakeintoaccountalllegal,economicandtechnicalrequirementsregardingthedefinitionof baseline relevant to a UER project. Member States must have a commonunderstanding and set criteria in order to verify eligible projects. The baseline shouldreflect a business as usual case thatmay change over time, and thus cannot be fixedbasedonemissionsratesatagivenmoment.Assessmentofsourcesandsinkscontrolledby the project proponent or affected by the project, particularly in projects located in
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countries outside the EU (whichwillmost probably be themost common case), couldprovetobeconsiderablydifficult.
5.3 DoubleCounting
Double counting occurs when a single GHG emission reduction or removal, achievedthrough a mechanism issuing units, is counted more than once towards attainingmitigation pledges or financial pledges for the purpose ofmitigating climate change28.ProjectproponentswithwhomfuelsuppliersenterintocommercialarrangementsmustnotmakethesameUERsavailabletootherfuelsuppliersorredeemthemforcompliancewithotherregulations.
TheFQDImplementingMeasuredoesnotexplicitlyspecifyanystepsthatmustbetakento prevent double counting. Depending on whether Member States feel that it isnecessarytoimplementmeasurestopreventdoublecounting,theremaybeahighriskofithappening.ItisexpectedthateachMemberStatewillappointanationaladministratorresponsible for receiving and confirming reports of emissions reductions. Such anadministrator would be expected to verify that UER projects are not double countedwithinaMemberState.
Doublecountingmayoccur,inthecaseofUERs,intwodifferentways:
1. byclaimingthesameUERsinmorethanoneMemberState;2. by issuing UER credits for projects that have also been registered for crediting
withinothermechanisms,suchastheCDMorJI.
Assessingandaddressingdoubleclaimingismoredifficultinthesecondcase,wheretwoseparate mechanisms are involved. In a fragmented carbon market, with multiplemechanisms under international, bilateral, national or non-governmental governance,there is a risk that two mechanisms issue units for the same emissions or emissionreductions.Overlap could also occur between cap-and-trademechanisms and creditingmechanisms,suchtheCDMandtheEUETS.
InordertoavoiddoubleclaimingbetweenMemberStates, ideally, registrationsystemsshouldbeinplacetoensurethatanycreditscanonlyberedeemedinoneMemberStateonly.ThiscouldbeenabledbytheestablishmentofacentralEuropeandatabase,orbyotherinformationsharingmeasuresbetweennationaladministrators.Forthepurposeofidentifyinganyattemptedmultipleclaiming,nationaladministratorswillneed toaccessinformation on UERs claimed for compliance in all other Member States. This can besolvedbyestablishingasystemofuniqueidentificationofUERsgeneratedbythesameproject within the same year. It is important that all Member States share a common
28 Addressing the risk of double counting emission reductions under the UNFCCC, StockholmEnvironmentInstitute,2014
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CDMetc.)arenotaccountedtowardstheFQDtarget,eveniftheyarecompletedwithintheperiod2011-2020.
InterpretationbyMemberStatesMemberStatesmayimposetheirowninterpretationtothereferencedISOstandards.InordertocomplywiththeGHGreportingrequirementsexplainedinthepreviousSections.Member States representatives may impose additional verification and monitoringcriteria,inlinewiththeprinciplessetbytheISOstandards.
ISO 14064 is generally compliant with most GHG emissions reductions programmes,either voluntary or not. In caseMember States allow crediting of UERs issued by themeans of other GHG programmes or schemes, ISO provisions should be applied to allcandidateprojects,inordertoensurecompliancewiththerequirementsoftheFQDanditsImplementingMeasure.
In order to ensure that the appropriate quality is delivered by all of FQD-eligible UERsacross the EU, it is therefore necessary for Member States to establish appropriatecommoncriteriaformeasurementandreportingunderUERschemes.
ComplianceagainsttheFQDbaselineyearAmethodologicalissuerelatedtotheachievementoftheFQDtargetsin2020isthefactthatemissionreductions(whencomparedtothebaselineof2010)couldbeachievedonlyphenomenallyandspecificallyforthepurposeoftheFQDcompliance.Thisisduetothefactthatactualemissionsmight increaseordecreasebetweenthebaselineof2010andthe targetyear2020andcould, thus, liehigheror lower thanthebaselineemissionsof2010minus theemission reductionsprescribedunder theFQD.Thismeans that in2020rough savings (brutto) could allegedly appear as significant but net actual (netto)emissionscouldbelowerorevenincrease.
Another significant issue is that of the equal treatment among different emissionreduction options, which count against the FQD target. For instance, there is arequirementoffullLCAforbiofuels;whileonlyarelativelysimpleCO2savingcalculationis prescribed for UER. Furthermore, in the case of biofuels there is actual deploymentwhile in the case of UER savings these appear to have an accounting character. Thus,despitethefactthattheaccountingofnetemissionsavingsisthecorrectmethodologyitshouldapplytoallemissionreductionoptionsequally.
CreditingofmethaneemissionsUnderCDMandJI,ventingreductionprojectsdonotreceiveadditionalcreditsrelatedtothe higher global warming potential of methane. In contrast, the Directive 2015/652allowsthecreditingofmethanereduction,byusingtheappropriateGWPtotransformtonnes of emittedmethane into tonnes of CO2 equivalent. However, the principle ofconservativeness,asdictatedby ISO14064,requiresthatreductionofmethanesourcesshould be credited only for the GHG benefit of reducing the equivalent emissions ofcarbondioxide.
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Infact,CDMmakestheassumptionthatallassociatedgasrelatedtoacertainoilfieldwillbe burned either way, whether by flaring for no practical purpose, or at a powergeneration facility. If CDM and JI methodologies are taken as reference for an UERaccounting methodology and taking into account the principle of conservativeness,methane emissions will most probably be accounted on the “safe side”, i.e. byconsideringthatallAPGproductionwouldbeflaredinabusinessasusualscenario.Thereis thereforeanuncertaintyonthewaytotreat thecredits reductionofactualmethaneemissionsintheupstreamsector,whichneedstobeclarified.
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6 KEYFINDINGS
6.1 OverviewofTasks
The 1st Task of the Study (Chapter 2) provides an overview of upstream emissionreductionmeasures,coveringmainlytechnologicalsolutionsandincludesthreeparts:
1. Overviewofupstreamemittingactivities:Themainsourcesofupstreamemissionsareassessed,particularlyintheoilsector.Flaring,ventingandfugitiveemissionsrepresent the most important source of upstream GHG emissions from oilproductionoperations.CombustionofAssociatedPetroleumnaturalGas(APG)iscalled flaring,while releasing it to theatmosphere is knownas venting. Fugitiveemissions refer to unintentionalmethane leakages from oil and gas operations,whereas venting emissions are related to the intentional release ofmethane tothe environment for maintenance or other reasons. Methane emissionspredominantly occur during natural gas production and transportation,whereasoil upstream activities mainly emit CO2 which comes from combustion. Sincenatural gas is not widely used in the EU transport sector, methane is notconsidered as a significant contributor to the total GHG emissions of the EUtransportsector.
2. Upstream emission reduction technologies: Major technologies aimed mainly atventingand flaring reductionandAPGutilisationarepresentedandqualitativelyassessed against a list of criteria/drivers. For each site where APG is flared, anumberofalternativesolutionsexist,whichaimatrecoveringandutilizingpartofthegas.TheeconomicviabilityofeachoftheseAPGutilisationoptionsisaffectedby a large number of factors, e.g. gas characteristics, location and presence ofexisting infrastructure, market conditions, etc. The optimal solution for aparticular site is thus highly case specific.Regardingmethane emissions, whilethere ishighpotentialforabatementofmethaneemissionsmainly inthenaturalgas sector, they are not currently widely applied for technical and economicreasons.
3. Upstream emission reduction incentives: Specific oil producing countries areanalysedwithrespecttoregulationstheyhaveadoptedtoreduceflaringaswellas major flaring reduction projects that have been constructed or are currentlyunder development. The countries, which have been assessed, are those beingamongthehighestupstreamGHGemittersand inparallelsignificantsuppliersoftheEU,namelyRussia,Nigeria, Iraqand Iran.To thesecountries, theConsultanthas added Norway, due to the technological and regulatory best practices itimplements,alongwithCanada,asitisamajorproducerofunconventionalfuels.
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Unconventional oil and gas are expected to play an increasing role in the EUmarketinthenearfuture.FlaringemissionsfromRussianoilfieldsareextremelyhigh-thelargestamongalloil producing countries. According to the World Bank’s GGFR satellite studies(2011), Russia was in 2010 by far the country in the world flaring the biggestamount of associated gas (34.2 bcm), followed by Nigeria (15.2 bcm), Iran (11.3bcm)and Iraq(9.1bcm).All thesecountriesaremajor fossil fuelsuppliersof theEUand they relate to importantupstreamemission reductionpotential.RussiancompanieshavebeenmakingeffortstodevelopAPGutilisationfacilitiesinthelastfew years, some of which may be used for UER crediting. Other major APGutilisationprojectsareoperatingorareunderdevelopment inNigeriaandinIranthatcouldpotentiallybeaccountedtowardstheFQDtargets.
The2ndTask(Chapters3and4)dealswiththepotentialofupstreamemissionreduction,while analysing policies and incentives undertaken worldwide for this purpose. In thiscontextthefollowingissuesarebeinganalysed:
1. Incentives and policies aimed at upstream emissions reduction: Relevant policyoptions are presented, with a specific focus on market mechanisms based onemissionintensitystandards,whichwillpresumablyformthebasisforthecreationofanUERcreditingscheme.Cap-and-tradesystemsareparticularlypresented,asthey have emerged as the internationally preferred market mechanism formitigatingGHGemissions.SpecialreferenceismadetothecasesofCaliforniaLowCarbonFuelStandardand theBritishColumbiaRenewableandLowCarbonFuelRequirements Regulation, as well as emission offset mechanisms such as CDMand JI, since projects registered under these mechanisms are candidate to beeligibleforUERcrediting.
2. Assessment of UERs subject to be accounted for under the FQD requirements:Eligibilityofpotentialprojects inanUERscheme isassessed, followedbyabriefestimation of technical and economic potential of UER. According to pertinentliterature, total carbonmitigation potential from economically profitable flaringandventingreductionprojectsintheoilsectorintheEU,Canada,Nigeria,RussiaandtheUScombinedcanbeintherangeof127-143MtCO2eperyear,atnegativeabatementcosts(i.e.profits),withRussiabeingabletodeliverapproximatelyhalfofthatpotential.With respect to FQD compliance, at a CO2 credit value of carbon price of$20/tCO2e, approximately 24 MtCO2e of annual UER could be delivered for acumulativecreditingperiodof15-20years.Thiswouldamounttoslightlylessthanhalf of the FQD target of a 6% reduction in the carbon intensity of Europeantransport fuels. In the case that only 1 year creditingperiod (2020) is eventuallyapplicable(accordingtotheImplementingMeasurerequirement)thepotential issignificantly lower ranging from 2.3million tonnes CO2eq (for $20/tCO2e carbonprice) to 15.5 million tonnes CO2eq for (for $200/tCO2eq carbon price). Thisestimation corresponds to a percentage being approximately between 5% and30%ofthe6%FQDtarget.
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multiple claiming of the same credits, it is important to set up a scheme thatallowsuniquelyidentifyingeachbatchofUERcreditsbyusingproperverificationprocedures.Thenationaladministratorsmaythenrefertoacentraliseddatabase,operatedbytheEC,inordertoverifythatclaimedUERsarenotalreadyredeemedbyanotherentity.
4. Potential implementation by Member States: Practical transposition matters arebeingdiscussed. In eachMemberState anational administratingbodymustbeappointed, which will be responsible for monitoring and receiving emissionreductions from regulated parties and for confirming that reported emissionsreductionscomplywiththerequirementsoftheFQD.
6.2 Concludingremarks
TheEuropeanCommissionhasprescribedthedevelopmentofamechanismforcountingofUERsavingsexclusivelytowardsthecomplianceundertheFQDtarget.UERscannotbecountedtowardstheachievementofthetargetsofUNFCCCortheKyoto-Protocolfora specific Member State. According to the GHG inventory methodologies, projectsleading toupstreamGHGemission reductionshave tobeaccounteda) in thecountrieswheretheseareimplemented,orb)intheindustrysectoroftherespectivecountries.
TheUERschemecannotbeconsideredasanexplicit climatechangepolicy tool in thecontextofawiderframework(suchastheEUETSfortheimplementationoftheKyotoProtocol) but as an accounting mechanism towards the FQD compliance specificallyaddressedtotheEUtransportsector.Nonetheless, intheConsultant’sview,UERshaveto be seen from a broader point of view with respect to the climate protectioncommitment of the EU (20% decrease of GHG emissions by 2020) and furthermeasurements to reach the 1,5° CgoalofCOP21 inParis. Therefore, even thoughUERscould inprinciple forman instrument for climate changepolicy, the current single yeartargetof2020andthefragmenteddesignofthemechanismsofardonotguaranteetheeffectivenessoftheUERmechanisminthelongerrun.However,itshouldbenotedthatthe revisionof theFQDwhich isexpectedby theECwithin2016could setnew targetsandcreatenewobligationsinthefossilfuelsector.
Much discussion and interpretation is currently in place on whether credits should beawarded inoneyear (2020)only,orwhetheremission reductions takingplaceover the2011-2020periodcouldbeaggregatedforreachingthetarget inthecomplianceyear. IntheConsultant’sperspective,emissionreductioncreditsarenotexpectedtobecheckedforcompliance inacumulativemanner, thusonlyUERsgenerated inthecorrespondingcalendaryearshouldbeconsideredeligible.
TheactualimplementationoftheUERmechanismasameansfortheachievementoftheFQDtargetcouldfaceseveralchallenges.ThewaytheImplementingMeasureattemptstosettlevariouspracticalandmethodologicalissueswithrespecttoUERimplementationleaves several vague and unclear points that could hamper its effectiveness. Thesepointsaredeterminedbytheissuesof1)projecteligibilityandthecorrespondingnotion
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of 2) additionality, 3) double counting and 4) the development of common rulesbetweenMS,aswellasofacentralizedEUregistryforUERs.Furthermore,theongoingdiscussionandconsultationforthepracticalimplementationofUERcanbecharacterizedbylargedelaysandambiguitieswhichcouldseverelyaffectthesmoothimplementationof theUERmechanism. In theConsultant’sopinion, thecompleteestablishmentof theUERmechanism could take up to 3 years (i.e. end of 2018)whichwould entail a largeadministrative burden and cost, potentially disproportionate to its envisagedeffectiveness.Theissuesthatneedclarification,relatedtotheimplementationofaUERschemearesummarizedinthefollowing:
1. Project eligibility: A major issue with respect to UER implementation is theeligibility of projects against FQD compliance as thiswill determine the level ofdifficulty in the achievement of targets and eventually the financial cost ofcomplianceforobligedstakeholders(suppliers).TheFQDdescribesinroughlineseligible projects, which are not limited to those reducing venting and flaringemissions. Project eligibility is left to a large extent to the hands of nationallegislatorswhohavea largedegreeofflexibility.Furthermore, ISO14064-2 limitsthe scope of eligible projects to those that are additional to the appropriatelydefined baseline scenario. In any case the Implementing Measure and theexpectednon-legislativeguidancethatwill followshouldprovidecleardirectionsonwhichprojectscouldbeconsideredaseligible.
2. Additionality: Project eligibility is inextricably related with the issue ofadditionality.AlthoughtheFQDdoesnot includea referenceonadditionality, inorderforemissionreductionprojectstobequantifiedtowardstheacquisitionofUERcredits,itisessentialtoprove-asderivedfromISO14064-thattheemissionchangesareadditionaltowhatwouldhavebeenexpectedinabusinessasusualscenario.Therefore,eventhoughprojectproponentsmustprovethattheprojectwouldnothavebeenimplementedunderbusinessasusualassumptions,it isnotnecessarytoprovethattherequirementsoftheFQDand/orUERcreditingwereadriverofprojectdevelopment.The effects from removing or loosening additionality requirementswould allowfor many more UER projects to be eligible and remove significant part ofadministrativeburden.Nonetheless,pooradditionalitycriteriawouldsignificantlyundermine its purpose. In this case, the project baseline, as well as the projectboundariesmustbeclearlydefined. It is thereforeessential todevelopcommonrules between project proponents and national administrators from MemberStatesontheestablishmentofthesetwoparameters.
3. Doublecounting:TheFQDImplementingMeasuredoesnotexplicitlyspecifyanystepsthatmustbetakentopreventdoublecounting.DependingonwhetherMSconsiderthat it isnecessaryto implementmeasurestopreventdoublecounting,theremaybeahighriskofoccurrence.ItisexpectedthateachMSwillappointanational administrator responsible for receiving and confirming reports onemissionreductions.SuchanadministratorwouldbeexpectedtoverifythatUERprojectsarenotdoublecountedwithinaMemberState.
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4. Establishment of common rules and criteria amongMS: In general,monitoringandverificationwillbeimplementedaccordingtothereferencedISOstandards.Nonetheless, in order to complywith theGHG reporting requirements,MemberStatesrepresentativesmayimposeadditionalverificationandmonitoringcriteria,in linewith the principles set by the ISO standards. In order to ensure that theappropriatequalityisdeliveredbyallFQD-eligibleUERprojectsacrosstheEU,itisthereforenecessaryforMemberStatestoestablishappropriatecommoncriteriaformeasurementandreportingunderUERschemes.
5. Centralised UER registry: The experience from the EU ETS and the recenttransition from a distributed crediting system to a centralized approachwith asingle EU registry, with standardized monitoring, reporting and verificationproceduresamongMemberStatesshowsthatundersuchasystem,credittradingiseasier, lessadministrationandtransactioncostsarerequiredandthepotentialoffraud/doublecountingisreduced.It isthereforeassumedthatthis isthemostplausibleapproachtobeimplementedalsofortheUERregistry.
Furthermore, it must be highlighted that actual emissions might increase or decreasebetweenthebaselineof2010andthetargetyear2020andcould,thus,liehigherorlowerthanthebaselineemissionscalculatedfor2010minustheemissionreductionsprescribedundertheFQD.Thismeansthat in2020roughsavings(gross)couldallegedlyappearassignificantbutnetactualemissionscouldbelowerorevenincrease.
Last but not least, a significant issue is that of the equal treatment among differentemissionreductionoptionswhichcountagainsttheFQDtarget.For instance,thereisarequirementoffullLCAforbiofuels;whileonlyarelativelysimpleCO2savingcalculationisprescribedforemissionsreductioninthefossilfuelsector.Furthermore,inthecaseofbiofuels there is actual deployment,while in the case of fossil fuels emissions savings,theseappeartohaveanaccountingcharacter.Thus,despitethefactthattheaccountingof net emission savings is the correct methodology in the context of climate changepolicyinthetransportsector,itshouldapplytoallemissionreductionoptionsequally.
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