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1、April|2023Pathways to Commercial Liftoff:Carbon ManagementThis report was prepared as an account of work sponsored by an agency of the United States government.Neither the United States government nor any agency thereof,nor any of their employees,makes any warranty,express or implied,or assumes any

2、legal liability or responsibility for the accuracy,completeness,or usefulness of any information,apparatus,product,or process disclosed,or represents that its use would not infringe privately owned rights.Reference herein to any specific commercial product,process,or service by trade name,trademark,

3、manufacturer,or otherwise does not necessarily constitute or imply its endorsement,recommendation,or favoring by the United States government or any agency thereof.The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States government or any agen

4、cy thereof.Pathways to Commercial Liftoff:Carbon ManagementPathways to Commercial Liftoff:Carbon ManagementCommentsThe Department of Energy welcomes input and feedback on the contents of this Pathway to Commercial Liftoff.Please direct all inquiries and input to liftoffhq.doe.gov.Input and feedback

5、should not include business sensitive information,trade secrets,proprietary,or otherwise confidential information.Please note that input and feedback provided is subject to the Freedom of Information Act.AuthorsAuthors of the Carbon Management Pathway to Commercial Liftoff:Loan Programs Office:Ramse

6、y FahsFossil Energy and Carbon Management:Rory JacobsonOffice of Clean Energy Demonstrations:Andrew Gilbert,Dan Yawitz,Catherine Clark,Jill Capotosto,Office of Policy:Colin Cunliff,Brandon McMurtryArgonne National Labs:Uisung LeeCross-cutting Department of Energy leadership for the Pathways to Comme

7、rcial Liftoff effort:Office of Clean Energy Demonstrations:David Crane,Kelly Cummins,Melissa KlembaraOffice of Technology Transitions:Vanessa Chan,Lucia TianLoan Programs Office:Jigar Shah,Jonah WagnerAcknowledgementsThe authors would like to acknowledge analytical support from Argonne National Labo

8、ratory and McKinsey&Company;as well as valuable guidance and input provided during the preparation of this Pathway to Commercial Liftoff from:Office of Clean Energy Demonstrations:Andrew Dawson,Katrina Pielli,Allison Finder,Liz MooreOffice of Technology Transitions:Erik Hadland,Stephen Hendrickson,H

9、annah Murdoch,Katheryn(Kate)ScottLoan Programs Office:Chris Creed,Carolyn Davidson,Matt Kittell,Julie Kozeracki,Leslie Rich,Harry WarrenOffice of Policy:Carla Frisch,Steve Capanna,Neelesh Nerurkar,Elke Hodson,Paul Donohoo-Vallett,Marie FioriOffice of Fossil Energy and Carbon Management:Brad Crabtree

10、,Jennifer Wilcox,Noah Deich,Emily Grubert,Lynn Brickett,Anhar Karimjee,John Litynski,Sarah Leung,Amishi Claros,Traci Rodosta,Jeffrey Hoffmann,Jose Benitez,Tony Feric,Lisa Grogan-McCulloch,Vanessa Nez-Lpez,Devinn Lambert,Caleb WoodallOffice of the Secretary:Kate GordonDirector of the Office of Econom

11、ic Impact and Diversity:Shalanda BakerOffice of Energy Jobs:Betony JonesOffice of the General Counsel:Alexandra Klass,Avi Zevin,Ajoke AgboolaArgonne National Laboratory:Aymeric RousseauPathways to Commercial Liftoff:Carbon ManagementTable of ContentsExecutive Summary1Chapter 1:Introduction and Objec

12、tives5Chapter 2:Current State Carbon Management Technologies and Markets7Section 2.a:Technology landscape7Section 2.a.i Point-source capture8Section 2.a.ii Carbon Dioxide Removal(CDR)12Section 2.a.iii Transport14Section 2.a.iv Storage16Section 2.a.v Enhanced Oil Recovery(EOR)storage18Section 2.a.vi

13、Utilization18Section 2.b Current regulation and policies supporting CCUS and CDR development19Chapter 3:Pathways to Widespread Deployment22Section 3.a The pathway to widespread deployment22Section 3.b Implied capital formation29Section 3.c Broader implications30Section 3.c.i Supply chain31Section 3.

14、c.ii Energy and environmental justice32Chapter 4:Challenges to Commercialization and Potential Solutions36Section 4.a Overview of challenges and considerations along the value chain36Section 4.b Priority solutions40Chapter 5:Metrics and Milestones42Chapter 6:References43Pathways to Commercial Liftof

15、f:Carbon ManagementPurpose of this ReportThese Commercial Liftoff reports aim to establish a common fact base and ongoing dialogue with the private sector around the path to commercial lift-off for critical clean energy technologies.Their goal is to catalyze more rapid and coordinated action across

16、the full technology value chain.Executive SummaryModeling studies suggest reaching U.S.energy transition goals will require capturing and storing 400 to 1,800 million tonnes(MT)of carbon dioxide(CO2)annually by 2050,through both point-source carbon capture,utilization,and storage(CCUS)and carbon dio

17、xide removal(CDR).iToday,the U.S.has over 20 million tonnes per annum(MTPA)of carbon capture capacity,15%of what could be needed by 2050.1,ii,iii This scale-up represents a massive investment opportunity of up to$100 billion by 2030 and$600 billion by 2050.Americas 20 MTPA of capture capacity alread

18、y leads the world in carbon management,and the U.S.is an attractive policy and resource environment for further deployment.An increase in the value of the 45Q tax credita federal tax credit provided for stored or utilized CO2has provided a greater incentive and more certainty to developers and inves

19、tors and is likely to yield attractive returns for several types of projects.ivIn addition,recent climate and infrastructure legislation has provided$12 billion in funding to support U.S.carbon management projects.The U.S.has excellent geology for storing CO2,world-class engineering and professional

20、 talent,and relatively abundant low-cost zero-carbon energy resources that can power carbon dioxide removal(CDR)projects to maximize net carbon removed.Many large-scale carbon management projects are already proving financially attractive today with enhancements to the federal 45Q tax credit,and inv

21、estors have raised billions to take advantage of these opportunities.v,vi These investments range from early-stage equity investments in carbon capture technology providers to large-scale private equity-backed investments in CO2transport infrastructure.This report outlines the path to meaningful sca

22、le in carbon management,which we expect to develop between near-term and longer-term opportunities through 2030(Figure 1.).2,3,41.For near-term(through 2030)opportunities,projects in industries with high-purity CO2streams(e.g.,ethanol,natural gas processing,hydrogen)have the best project economics.M

23、any of these types of projects are in active development or are already in operation.Large-scale transportation and storage infrastructure is likely to emerge to serve these projects.These developmentsalong with some promising demonstration projects in higher-cost carbon management applications(e.g.

24、,steel,cement)will lay the foundation for more widespread deployment by establishing best-practices in contracting,financing,permitting,community engagement,labor agreements,workforce development,and,in some cases,through building out common carrier transport and storage infrastructure that future p

25、rojects can use.2.For longer-term(post-2030)opportunitiesindustries with lower-purity CO2streams and distributed process emissions project economics must improve to make widescale deployment likely in the absence of other drivers(e.g.,regulation).Demonstration projects from now through 2030 can supp

26、ort cost declinesboth through learning-by-doing and standardizing project development structures.And increased policy support(either via regulation or incentives)or technology premiums for low-carbon products(e.g.,low embodied carbon steel and concrete)would lead to more CCUS and CDR projects.5These

27、 end-user-backed technology premiums combined with sustained and predictable government support can provide consistent revenue streams as deployment experience reduces costs.1Note:Any use of“tonnes”in this report refers to metric tonnes;references to MTPA refer to million tonnes per annum2 Data in t

28、his report for CCUS applications focus only on incremental costs and revenues associated with retrofitting an existing facility with installing and operating carbon capture.They do not reflect the overall economics of a given facility.3 Near-term and longer-term opportunities refer to an economic an

29、alysis of carbon management projects under the current policy and regulatory environment and is not meant as a comment on the technical feasibility of these projects.A wide portfolio of carbon management technologies for a suite of applications are commercially mature and ready to deploy today.4 We

30、note that the discussion in this paper examines economic break-even points for carbon capture in the absence of regulatory drivers.Any state or federal regulatory actions could dramatically accelerate the business case for profitable investments in carbon management.5 The Federal Buy Clean Task Forc

31、e and the First Movers Coalition are both seeking to provide a clear demand signal for low embodied emissions products1Pathways to Commercial Liftoff:Carbon ManagementCurrently profitableNear-term opportunitiesLonger-term opportunitiesNascent technologyProject specific economics dependent on CO2capt

32、ure capacity,utilization,distance to storage and existing equipmentDeveloping economicsFigure 1:Concentrated sources of CO2(e.g.,in ethanol or hydrogen Steam Methane Reformer(SMR)capture facilities)are currently profitable but do not include sufficient emissions reductions alone to achieve net zero

33、goals Cost1and revenue2per industry or technology today,$/tonne1Displayed cost estimates based on EFI Foundation capture costs with transport(GCCSI,2019)and storage(BNEF,2022)costs of$10-40/tonne,except where noted.All in 2022 dollars.All CCUS figures represent retrofits,not new-build facilities.The

34、 lower bound costs represents a NOAK plant in a low cost retrofit scenario with low inflation.The higher bound costs represents a FOAK plant in a high cost retrofit scenario with high inflation.The inflation variance on each cost estimate represents the range of cost increases on a generic chemical

35、processing facility due to inflation from 2018 using the Chemical Engineering Plant Cost Index(CEPCI).2Revenues based on applicable mix of 45Q tax credit,Low Carbon Fuel Standard,Voluntary Carbon Markets and the 45V tax credit(which cannot be stacked with 45Q).Other sources of revenue(e.g.,premium P

36、PAs,EOR)are discussed in more detail in the appendix.Tax credit values do not reflect expected discounts to the face value of the credit associated with tax equity financing or transferability.For retrofits,revenue does not reflect the value of products already sold by the facility(e.g.,electricity

37、from an existing power plant)3Current hydrogen capacity is likely to grow with the growth of reformation-based capacity and future demand likely4Includes BECCS to power,biochar,and bio-oil;Biochar and bio-oil may not be eligible for 45QSource:EFI Foundation,“Turning CCS Projects in Heavy Industry&Po

38、wer into Blue Chip Financial Investments”.Hydrogen SMR-only capture costs from IEA 2019.;Coal and CCGT power plant retrofit cost of capture figures derived from NETL Revision 4a Fossil Baseline study retrofit cases adjusted to 2022 dollars and with 12-year amortizationrange represents FOAK with high

39、 retrofit factor(high figure)to NOAK with low retrofit factor(low figure).DAC costs from NETL:Direct air capture solvent and sorbent studies;Upper bound of solid sorbent from Climeworks 2018,also cited in“A review of direct air capture(DAC):scaling up commercial technologies and innovating for the f

40、uture(McQueen 2021);BiCRS cost estimates from Coalition for Negative Emissions for first-of-a-kind BECCS for power with modified financing costs same as above.Low ranges of purchase of biomass processed feedstock and biomass transport taken from FAO U.S.biomass cost estimates rather than Coalition f

41、or Negative Emissions,which has higher estimates applicable to a UK-based plant(“Economic analysis of woody biomass supply chain in Maine(Whalley 2017)and ICEF“Biomass Carbon Removal and Storage(BiCRS)Roadmap”(2021),Charm Industrial“Carbon Removal:Putting Oil Back Underground”(2021);Mineralization c

42、osts from author benchmark cost used in IPCC.Costs for ex situ mineralization with wollastonite,olivine-rich,and serpentine-rich tailings using heat and concentrated CO2from Kelemen P,Benson SM,Pilorg H,Psarras P and Wilcox J(2019)An Overview of the Status and Challenges of CO2Storage in Minerals an

43、d Geological Formations.Front.Clim.1:9.doi:10.3389/fclim.2019.00009;Current emissions from EPA GHGRP FLIGHT database 2019 and includes biogenic CO2emissions for pulp and paper(110 MTPA)Note:CCUS figures represent incremental costs and revenues associated only with the installation and operation of c

44、arbon capture retrofits,not the overall facility economics of the facility in question.Note:Applications are arranged left-to-right by industry,power,and CDR reflecting the rough CO2 concentration of the CO2sources associated with these applications85858585Refineries(Fluidized Catalytic Cracker)Ammo

45、nia(flue gas)Steel(Blast Furnace BOF)90Hydrogen(SMR and steam production,90%capture)66CementproductionBiCRS4Power plants-CCGT1,180Pulp&paper(Black liquor boiler)Mineralization(ex-situ)Ethanol1631956015410016128513415985176DAC6001268515685600500500Natural gas processingPower plants-CoalHydrogen(SMR o

46、nly)100N/A5031405901700Low-range CostLow-range RevenueCurrent emissions(CCUS not viable for all emissions in a given sector)xHigh-range CostHigh-range Revenue2Progress across near-term and longer-term opportunities could create commercial“lift-off”between now and 2030 as project finance mechanisms b

47、ecome de-risked,a robust ecosystem of enabling transport and storage infrastructure matures,state and federal regulatory requirements promote lower-GHG alternatives,and capital markets become comfortable with carbon management projects as an asset class.600Pathways to Commercial Liftoff:Carbon Manag

48、ementThe challenges facing widespread deployment of carbon management are real but solvable.Estimated project economics for CCUS retrofits on higher-cost-to-capture applications(e.g.,cement,and steel)will not lead to widespread deployment without cost or revenue improvements or additional policy.Fur

49、ther demonstration projects in these sectors can enable faster Capital Expenditure(CapEx)cost reductions through commercial standardization,modularization,and technology improvements.6DOE demonstration funding could spur cost improvement in these sectors.In CDR,voluntary carbon markets can be unpred

50、ictable and inconsistent,and long-term prices and volumes remain uncertain.Even with high expected growth,voluntary markets may be insufficient to support the scale of deployment required to achieve U.S.net zero goals.Increasing the transparency and certainty of the voluntary and compliance markets

51、for CDR can increase market support.Two factors could create long-term revenue sources:(1)regulations that favor CDR deployment and(2)increased technology premiums for CDR driven by end-user demand.Project funding and demand-side market support from DOE could help stabilize the market for CDR develo

52、pers and investors.Across CCUS and certain types of CDR,the need for multi-party agreements(e.g.,between emitting facilities,capture providers,transport providers,and storage facilities)and a lack of commercial standardization complicate project development.Potential solutions include creating arche

53、typal,field-tested business models and terms to enable the development and execution of partnerships.Private sector leadership and DOE-supported“hubs”for direct air capture(DAC)and CCUS could simplify project development by creating standard commercial arrangements that simplify the development proc

54、ess.7Permitting dedicated geologic storage projects(e.g.,Class VI injection wells)may be seen by developers and investors as a long and uncertain process.Congress provided funding to EPA through the Bipartisan Infrastructure Law(BIL)to support the federal Class VI permitting program as well as to pr

55、ovide grants to states,Tribes,and territories to pursue and implement Class VI primacy applications and programs.EPA anticipates approximately two years from receipt of completed Class VI applications to issuance of a permit and has developed a series of tools to help streamline the permitting proce

56、ss.viiA lack of common-use transport and storage infrastructure could hinder development and may encourage uncoordinated or duplicative source and storage matching.Projects developed today can build out CO2transportation networks and storage facilities that can serve as shared infrastructure for fut

57、ure carbon management projects located nearby.DOE will support development of shared storage facilities and transport infrastructure through Bipartisan Infrastructure Law(BIL)funding.Some groups oppose CCUS projects or policy support for them and others are unfamiliar with the technology.ixAddressin

58、g these concerns,including environmental justice considerations,requires commitment to responsible carbon management from policymakers and industry to build trust with communities considering carbon management projects.Developers must anticipate,listen to,and address stakeholder concerns through ear

59、ly,substantive,and transparent engagement on the benefits and risks of these projects.DOEs Office of Fossil Energy and Carbon Management(FECM)has launched a domestic engagement framework to outline its vision for successful engagement.The framework serves as the guiding principles to ensure that tan

60、gible environmental,economic,and social benefits flow to communities.Additionally,DOE has added requirements for carbon management funding opportunity applicants to incorporate community engagement;diversity,equity,inclusion,and accessibility;environmental justice;and quality jobs plans into their a

61、pplications and project plans.6CCUS and certain CDR technologies have significant OpEx expenses(roughly 50%of levelized costs)in the form of energy and material inputs.These persistent OpEx costs make the dramatic total cost declines observed in fuel-free energy technologies like wind and solar unli

62、kely.7 DAC is one of several CDR pathways discussed further in Chapter 2.3Pathways to Commercial Liftoff:Carbon ManagementDOE,in partnership with other federal agencies and state and local governments,has tools to address many of these issues and is committed to working with communities and the priv

63、ate sector to build out the nations carbon management infrastructure and meet the countrys climate,economic,and environmental justice goals.Carbon management is experiencing a once-in-a-generation opportunity given the current policy and market environment.The 45Q tax credit provides certainty and a

64、ttractive project economics for several project types.Funding for commercial demonstration and deployment projects in BIL and the Inflation Reduction Act(IRA)can spur carbon management projects in industries in which project economics would otherwise still be challenging,providing investors with sec

65、tor-specific blueprints for project development.Substantial and responsible investment in carbon management deployment over the next decade can prove out business models and generate the community,market,and policy buy-in that carbon management will need to contribute meaningfully to the nations ene

66、rgy future.4Pathways to Commercial Liftoff:Carbon Management8Current range is based on integrated energy modelling as discussed in the“Pathways to Commercial Liftoff:Overview of Societal Considerations and Impacts”.Expanded range based on several government and other research reports,including:Princ

67、etons Net Zero America report(2021,the White House Pathways to Net-Zero GHG Emissions by 2050(2021),The IPCC(2021,IRENA(2021),IEA(2021);Some modelled scenarios estimate figures higher or lower than this range depending on the level of deployment of other decarbonization tools(e.g.,renewable electric

68、ity,nuclear,reforestation and land use change)Chapter 1:Introduction&ObjectivesThe U.S.will likely need to capture and permanently store 4001,800 million tonnes of CO2annually(MTPA)to meet its net-zero commitments by 2050(Figure 2.).8This report provides a pathway for reaching this objective.It focu

69、ses on the near-term carbon management project types and business cases that are already attracting investor interest.The report discusses the full carbon management ecosystem,including point-source carbon capture,utilization,and storage(CCUS)and carbon dioxide removal technologies(CDR).Within point

70、-source CCUS,this report focuses on retrofits in the following subsectors:AmmoniaCoal powerCementChemicals and refiningEthanolHydrogenIron and steelNatural gas powerNatural gas processingPulp and paperWithin CDR,this report focuses on:Biomass carbon removal and storage(BiCRS)Direct air capture(DAC)M

71、ineralizationThe report also assesses opportunities for CO2utilization,including:Building materials PlasticsSynfuels5Finally,this report considers the transport and storage infrastructure that will enable projects to geologically store CO2or transport it to a point of use.Achieving a net-zero econom

72、y will require hundreds of billions of dollars of capital investment in carbon management deployments.Policy supportthrough compliance mechanisms,tax incentives,demonstration funding,procurement,and regulatory requirementswill be key,but the majority of project development and financing will be impl

73、emented by the private sector.The analysis in this report provides a primer to investors and others interested in carbon management on the basic economics of certain carbon management project types,the key risks and challenges these projects face,and potential solutions to those challenges.Pathways

74、to Commercial Liftoff:Carbon ManagementEstimates of U.S.CCUS,CDR2required to reach Net Zero by 2050,GTPA CO20.80.50.80.50.70.32021 White House Pathways toNet-Zero GHG Emissions by 2050 2021 AGU Advances2021 Energy Evolved2021 Princeton Net Zero America0.4-1.22021 IRENA2021 IPCC Report2021 IEA Net Ze

75、ro Scenario0.7-1.80.4-1.50.6-1.0Avg=1.0Specialized cases(e.g.,SSPI)only use non-technological CDR to reach Net Zero goals Five scenarios analyzed with central case of 1.1 GTPA CO2capture.No breakdown between point source and CDR included.18%Nine scenarios with no breakdown between point source and r

76、emoval included.Central case of 0.8 GTPA CO2capture14%Global analysis1 of 7.6 GTPA with 70%point source,30%CDR20%Global analysis1of 8.0 GTPA with 60%point source,40%CDR 20%Five scenarios,but no breakdown between point source and CDR included.Central scenario includes 0.8 GTPA CO2capture16%Numerous p

77、athways analyzed,with point-source modeled up to 1.3 GTPA.Breakdown not included for every pathway 20%Global analysis1 of 7.9 GTPA with 40%point source,60%CDR20%1Global estimates were scaled down using the United States share of global CO2emissions,currently reported by EPA at 15%.Amounts shown here

78、 are indicative and not a prescriptive target as sectoral heterogeneity in the emissions distribution will result in differing requirements for CCUS and CDR2It should be noted that CCUS and CDR are not interchangeable and constitute unique sets of technologies.CCUS abates CO2emissions from point sou

79、rces,while CDR can mitigate difficult to decarbonize sectors(after emissions have been released)or address emissions overshootSources:IPCC 6th Assessment Working Group,2021;IEA Net Zero Emissions Scenario,2021;IRENA 1.5 Degree Scenario,2021;Princetons Net-Zero America study,2021;Long-Term Strategy o

80、f the United States,Pathways to Net-Zero Greenhouse Gas Emissions by 2050,2021;Evolved Energy Research 350 PPM Pathways for the United States,2021;Note:Global scenarios in this figure assume U.S.CCUS and CDR deployment will reflect U.S.share of global emissions,though sectoral emissions differences

81、and other factors could drive higher or lower CCUS and CDR adoption relative to global emissions shareFigure 2:A wide range of decarbonization studies find a significant role for both CCUS and CDR to achieve net zero goals by 2050.CCUS and CDR are not interchangeable technologiesCCUS will abate emis

82、sions from point sources while CDR can address emissions overshoot or mitigate other difficult to decarbonize sectors.A portfolio of carbon management technologies for a suite of applications are commercially mature and ready to deploy today.There are several dozen commercial-scale carbon management

83、 projects in operation today and well over a hundred are in stages of project development.xiThe costs associated with a carbon management project vary based on the type of facility CCUS is applied to or the CDR technology utilized,as well as several regional and facility-specific factors that can dr

84、ive variation in the cost associated with capturing,transporting,and storing or using a ton of CO2.9Costs for a specific carbon management project could vary even outside of the ranges outlined in this report depending on facility-specific characteristics and energy prices that can have a significan

85、t impact on the ultimate cost of deployment.In this report,“near-term”and“longer-term”opportunities refer to an economic analysis of carbon management projects under the current policy and regulatory environment and is not meant as a comment on the technical feasibility of these projects.Awide portf

86、olio of carbon management technologies for a suite of applications are technically and commercially mature and ready to deploy today.Moreover,the discussion in this paper examines economic break-even points for carbon capture in the absence of regulatory drivers.Any state or federal regulatory const

87、raints could dramatically accelerate the business case for profitable investments in carbon management.Finally,data in this report for CCUS applications focus only on incremental costs and revenues associated with retrofitting an existing facility with installing and operating carbon capture.They do

88、 not reflect the overall economics of a given facility.6Point source CCUSCDRLow rangeHigh rangeCarbon management mitigation contribution to Net Zero9This report has referenced the National Energy Technologies Labs(NETL)“Revision 4a”of its“Cost and Performance Baseline for Fossil Energy Plants”for CC

89、US retrofits in power the Energy Futures Initiatives recent“Turning CCS Projects in Heavy Industry into Blue Chip investments,”for CCUS retrofits in industrial applications.NETL has also published recent numbers on CCUS retrofits in industrialapplications;see National Energy Technology Laboratory.(2

90、022).Cost of Manufacturing CO2from Industrial Sources.This report has also used other estimates from trade groups and,in some cases,individual companies announced costs and cost targets.Pathways to Commercial Liftoff:Carbon ManagementChapter 2:Current State Carbon Management Technologies and Markets

91、Section 2.a:Technology landscapeThe carbon management value chain is broadfeaturing different methods and technologies at each stage(i.e.,capture,transport,utilization,and storage).Capture represents the majority of costs for most projects,while robust transport and storage or utilization networks a

92、re necessary to make projects viable.The U.S.leads the world in CCUS capacity(over 20 MTPA),driven by CO2from high-purity sources,coupled with incidental geologic storage through enhanced oil recovery(EOR).The U.S.has enough geologic storage capacity for trillions of tonnes of CO2;enough to store th

93、e entirety of U.S.emissions for hundreds of years.xiiThough storage resources are abundant,they must be characterized and developed to become commercially operational,and some in industry point to the permitting process to develop storage sites as a bottleneck to accelerated deployment in the U.S.CD

94、R technologies have less commercial deployment experience relative to CCUS,with limited technological CDR capacity in the U.S.today.A recent spate of announced projects and investments could drive cost declines over the next decade.CO2transport systems to link capture and storage sites require scale

95、-up.Current estimates suggest that 30,000 to 96,000 miles of pipe could be required to meet net zero goals by 2050(vs.5,000 miles of U.S.CO2pipelines operating today.)Beyond certain niche applications,CO2utilization pathways are nascent and currently uneconomic relative to incumbent products.Deploym

96、ent incentives such as the 45Q tax credit also provide a greater revenue source on a per-tonne basis for dedicated geologic storage relative to utilization.There are three main parts to the carbon management value chain:CO2capture(from both point-sources and the atmosphere),transport,and storage or

97、utilization(Figure 3.).Key participants in the value chain include large incumbent firms,startups,companies in emitting industries,EPC firms,CDR credit buyers,and transport and storage providers.10 A range of other players also interact with and facilitate the carbon management ecosystem,including t

98、he communities in which projects operate,the labor force that builds and operates projects,investors,landowners,and voluntary carbon marketplaces.10 Mostly large amine-capture companies,including oil and gas(e.g.,Exxon)and industrial companies(e.g.,Mitsubishi);Mostly technology driven start-ups in n

99、ew capture and removal technologies(e.g.,Climeworks)7Pathways to Commercial Liftoff:Carbon ManagementFigure 3:The value chain and applications that are in focus for this analysis are highlighted in greenSection 2.a.i Point-source capture Point-source capture is the separation of CO2from an industria

100、l facility or power plants flue gas,syngas or process stream.xiiiThese sources represent approximately 750 MTPA and 1,700 MTPA of point-source industrial and power emissions in the U.S.,though only a subset of these emissions will likely be addressed through carbon management(See Figure 4).xivA sign

101、ificant number of these CO2point-sources sit on top of,or are in close proximity to,favorable geology for large-scale carbon storage.Favorable geology includes a combination of geologic sinks with large carbon storage capacity,such as deep saline aquifers,and overlaying confining rock layers for sto

102、rage permanence.These geologic features require validation through regional characterization work and further site characterization for confirmation on a project-by-project basis.CO2compression&transportCO2use/storageCO2sources CO2capture1234Mode of transporting CO2from point of capture to point of

103、use/storage,with the green highlighted areas the focus of this report:Focus for this report includes the following green highlighted applications:Ways by which CO2can be stored or usedEOR storageUse in plasticsStorage in saline aquifers and depleted oil and gas reservoirsCO2in the atmosphere Emissio

104、ns from point-sources(e.g.,industrial facilities)Atmospheric and other capture:A variety of capture technologies,with the highlighted areas the focus of this report:Point-source capture:CO2sources,with the green highlighted areas the focus of this report:BiCRS(Incl.BECCS and biochar/bio-oil)Minerali

105、zationDirect Air Capture(DAC)Use in synfuelUse in building materialsNatural gas powerEthanolCoal powerCementSteelHydrogenNatural gas processingAmmoniaRefining and chemicalsPulp and paperNature based solutionsOcean capturePipelineRailBarge/shipTruckMineralization8NOT EXHAUSTIVE-INCLUDES FOCUS APPLICA

106、TIONS EXPLORED IN THIS REPORTFocus of this reportPathways to Commercial Liftoff:Carbon ManagementMap of U.S.point source CO2emissions by sector,20191High purity and process CO2streams are solid,with total CO2emissions shown by dotted line.Waste,non-industrial sectors,and some petroleum and NG emissi

107、ons amounting to 500 MTPA are not shown on the map and in the MTPA breakdown2Includes Summit,Navigator,ADM,and Tallgrass proposed CO2pipelines from project websites3Exploration of capture on NG transmission and distribution facilities(including LNG terminals)is out of the scope of this report,though

108、 there are expected to be CCUS-addressable emissions in that sectorSource:EPA GHGRP FLIGHT database 2019 including biogenic CO2for pulp and paper sector,additional public information on smaller point source emitters,and estimated additional emissions from ethanol facilities in EIA ethanol plant data

109、base;Summit,Navigator,ADM,and Tallgrass CO2pipeline project websites;NatCARB Atlas V Database;Estimates on proportion of CCUS-addressable emissions compiled from EPA FLIGHT database,DOE Industrial Decarbonization Roadmap,and McCoy et.al(2016)for Ethanol,Sagues Et.al(2020)for Pulp and PaperFigure 4:A

110、 substantial number of U.S.industrial point source emissions are within 50 miles of CO2transport to saline aquifers that could be suitable for geologic storage.Saline aquifers require characterization work to validate their suitability for commercial storage xv,xvi2022 was a banner year for carbon m

111、anagement project announcements.One industry database is tracking 140 MTPA in announced projects targeting completion by 2030(Figure 4).Not every announced project will successfully reach commercial operation date(COD).However,many have line of sight to firm and financeable cashflows,especially when

112、 projects tackle low cost-of-capture emissions streams.Many of these projects are backed by experienced investors and management teams.CO2proposed pipeline2CO2existing pipelineSaline Aquifers2 MTPA8 MTPAPoint source CO2emissions by sector1,MTPA 2,500 facilities10sectors561172746750174032Refineries10

113、7AmmoniaIron and steelNG ProcessingPulp and paperCement130Hydrogen77EthanolLNG equipment0Chemicals178723567604434Note:Not all emissions are addressable through carbon capture alone.Plant by plant feasibility studies are required.Unlikely to be addressed through CCUSPotentially addressable through CC

114、US9Pathways to Commercial Liftoff:Carbon ManagementU.S.point source CCUS capture capacity by year,MTPAFigure 5:The U.S.has over 20 MTPA of operational point source CCUS capacity,with an announced project pipeline of 140 MTPA as of Dec 2022 The cost of CCUS retrofits depends heavily on the plant in q

115、uestion.In general,the cost of CO2capture is inversely proportional to the CO2purity of the emission stream.But even within the same industry,several factors meaningfully impact the cost of capture,including facility design,11separation technology used in the capture process,local energy prices,emis

116、sions volumes,flue gas temperature and pressure,and the presence of emissions stream contaminants.Because of these project-specific factors,estimates can vary widely for current and projected costs.12In general,capture costs are the most expensive component in the CCUS value chain,but economies of s

117、cale,learning by doing,modularization and standardization,and novel capture technologies could all yield significant cost improvements.(Figure 6)131414233342129212892198810704020806030140509012010001101501302625320103521412221620308817212415EthanolCementNG PowerCoal PowerHydrogenNG ProcessingChemica

118、ls,Fuels,and PlasticsAmmonia/FertilizerOthersOperational Operational and announced 1Includes those expected to have commissioning in 2022Source:Bloomberg New Energy Finance,“2022 CCUS Market Outlook11 Including whether a facility must add multiple capture units or can use a single capture unit12 Som

119、e major differences between sources include financing assumptions,first-of-a-kind(FOAK)versus nth-of-a-kind(NOAK)projections,and assumed CO2purity of the exhaust stream.While estimated costs may vary between sources,the order of low-to high-cost-of-capture industries tends to be the same across the

120、literature.10Pathways to Commercial Liftoff:Carbon ManagementFigure 6:Capture drives the majority of unit costs for CCUS and represents the majority of cost reduction potential Costs and characteristics also vary significantly by capture technology.Amine-based chemical absorption processes are the m

121、ost common and mature capture technology.Other capture technologies(e.g.,advanced solvents,membranes,cryogenic,water lean solvents,and solid sorbents)and alternate processes(e.g.,Oxy-combustion,the Allam cycle)are in development and may realize future cost advantages.13,xix In amine-based processes,

122、flue gas passes through an amine solvent,which binds the CO2molecule.This CO2-rich solvent is heated in a regeneration unit to release the CO2from the solvent.The purified CO2stream is compressed and transported for storage or end-use and the released solvents are recycled to again capture CO2from f

123、lue gas.Modularizing CCUS equipment for amine solvents can speed deployment by minimizing upfront engineering design requirements and by leveraging a simplified production process.xxAs the cost of capture fallseither through experience and standardization in project development and finance or effici

124、ency improvements in already commercial technologies point-source emissions become more economically viable to capture.1Refers to CO2capture broadly across sectors examined in this report(see Figure 1);Costs drawn from EFI Foundation,“Turning CCS Projects in Heavy Industry&Power into Blue Chip Finan

125、cial Investments”2Generalized across sectors.Individual sectors will have sector-specific cost reductions3Approximate costs based on published studies by the European Zero Emission Technology and Innovation Platform,the National Petroleum Council,and GCCSI process simulation for a 30 year asset life

126、.All costs have been converted to a U.S.Gulf Coast basis.Lower end of pipeline cost assumes 20 MTPA,180 km onshore pipeline.Upper end of pipeline cost assumes 1 MTPA,300 km onshore pipeline.4Utilization routes also exist including,but not limited to,conversion of CO2into synfuels or plastics and uti

127、lization of CO2in EOR and building materials5Figure represents a levelized cost of site screening,site selection,permitting&construction,operations,and site closure and post-injection site care6Modularization will be a more critical driver for certain technology types than for othersNote:Supply chai

128、n risk and technical risk across the CCS value chain has been found to be low(DOE CCS Supply Chain Deep Dive Assessment)Source:Capture costs from EFI Foundation,“Turning CCS Projects in Heavy Industry&Power into Blue Chip Financial Investments”;Transport costs from Global CCS Institute,“Technology R

129、eadiness and Costs of CCS;Storage costs from BNEF 13 For example,membrane separation uses a polymeric or inorganic substance with high CO2selectivity and has been deployed commercially in syngas and biogas.Physical adsorption uses a solid material to capture CO2and then increases temperature or pres

130、sure to release the adsorbed CO2.Cryogenic carbon capture involves cooling the gas stream to produce solid CO2that can then be separated from the rest of the gas,pressurized,and brought back into the liquid phase.CO2capture1CO2 transport(Pipeline)CO2 storage4Current costs,$/tonneCost reductions poss

131、ible?2Large reductionsModerate reductionsSmall reductionsCurrent cost reduction leversEconomies of scale,targeting largest capture sources Modularization and standardization6Learning by doingTechnology innovations for novel capture technologiesEconomies of scale(e.g.,increasing diameter and added co

132、mpression),aggregating various CO2sources in a hub Siting close to reservoirs to minimize distance Utilization of existing right-of-waysSiting on well-characterized site with existing infrastructure and good monitorabilityEconomies of scale,leveraging large reservoir capacities Reduction of MMV cost

133、s by R&D and learning by doing25-17515-2535-155LowHighCritical drivers Other drivers 11Pathways to Commercial Liftoff:Carbon ManagementSection 2.a.ii Carbon Dioxide Removal(CDR)CDR refers to a wide spectrum of activities that remove carbon dioxide from the atmosphere.These can range from planting tr

134、ees that take in CO2as they grow to direct air capture(DAC)facilities that function like CCUS but treat ambient air instead of flue gas.The permanence of different CDR approaches vary widely:while trees may offer centuries of durable storage under some conditions,they are subject to risks of reversa

135、l,such as infections,infestations,wildfires,and logging;whereas geologic storage is expected to last 10,000 years.xxiThis section focuses on the higher-permanence removals with more established(but still nascent)approaches for monitoring,reporting,and verification(MRV)of removals.Credits for emissio

136、ns stored by CDR technologies can be sold in the voluntary carbon markets(VCM)to help companies or other institutions reach their emissions reductions goals.Companies can subtract these removal credits against any emissions they do not reduce directly.With 40 pilot-scale projects and 100 thousand to

137、nnes per year(KTPA)of global capacity,technological CDR has seen limited commercial deployment to-date(Figure 7.).xxiiMany planned projects are DAC demonstrations prompted by BIL funding,IRA incentives,and the willingness of a few credit buyers to pay high prices.Many researchers expect policies suc

138、h as a carbon tax,large-scale government procurement of CDR,or regulatory mandates will be needed to reach relevant scale.The FY2023 Congressional Omnibus budget report directs DOE to“establish a competitive purchasing pilot program for the purchase of carbon dioxide removed from the atmosphere.”xxi

139、iiThe levelized costs of the CDR approaches discussed in this report are generally higher than for point-source CCUS,due to the relatively dilute concentration of atmospheric CO2.14Investments in R&D,scale-up,and operational efficiencies are needed to lower costs and provide certainty for CDR techno

140、logy and project developers(Figure 8).Determining the precise climate benefits of some CDR technologies can be challenging.Lifecycle assessment(LCA)and MRV of removals of various CDR technologies will require further validation and standardization to ensure proper measurement of removed carbon.Direc

141、t air capture(DAC)The DAC process intakes or passively exposes air,which reacts in a contactor to bind CO2.The CO2is then separated from the DAC equipment,compressed,transported,and stored or used.The capture agent is then regenerated,usually with heat,which requires a significant energy supply,befo

142、re it is then recycled for additional capture.Today,solid sorbent and liquid solvent technologies have seen the most demonstration activity,though both approaches are still nascent.While liquid solvents are expected to be lower-cost today compared to solid sorbents,it is uncertain which technology w

143、ill be lower-cost as more projects develop.15,xxiv Other regeneration processes and capture materials(e.g.,electric-and moisture-swing solid sorbents,and membrane processes)are also emerging,with some potentially overlapping with enhanced mineralization(see below)16.Biomass with Carbon Removal and S

144、torage(BiCRS)BiCRS refers to using biomass(i.e.,plant matter)as a capture vehicle since plants take in CO2as they grow.17Like other CDR approaches,BiCRS is in its nascency.The two most prominent BiCRS processes so far are BECCS(bioenergy+carbon capture,utilization,and storage)and biochar/bio-oil.Bio

145、mass-to-hydrogen presents another BiCRS pathway and can include biomass gasification or fast pyrolysis to produce hydrogen with capture and storage,potentially resulting in net-CO2removal on a lifecycle basis,depending on the feedstock production and processing emissions.xxvBECCS refers to using bio

146、mass to produce heat,power,fuels,or other products and then capturing and using or storing the point-source emissions.Biochar and bio-oil are carbon-rich solids and liquids that are produced by decomposing biomass at high temperatures(i.e.,pyrolysis.)While bio-oil with geological storage has high du

147、rability,biochars storage durability is more uncertain,and depends on use case and elemental composition.xxviAvailability and sourcing of low-GHG biomass or biomass that yields a net-GHG reduction are key challenges for BiCRS scale-up.14 The CO2-purity of the flue gas stream is representative of tho

148、se from power plants and industrial installations(IPCC AR6 WGIII 12.3.1.1 2022).15 Liquid solvent costs are currently estimated to be$170250 per tonne CO2compared to solid sorbent costs of$365740 per tonne CO2;2050 cost estimates are$70125 and$65145 per tonneCO2,respectively(Coalition for Negative E

149、missions)16 For example,some technologies utilize limestone-based solids to adsorb CO2from air and regenerate.In general,DAC will refer to technology-based CO2capture from air,even if the sorbent is similar to those used in ex-situ enhanced mineralization 17 BiCRS does not include so-called“nature-b

150、ased solutions”like afforestation or reforestation12Pathways to Commercial Liftoff:Carbon ManagementMineralization(also known as enhanced mineralization)Mineralization is a natural process where CO2reacts with an alkaline feedstock(e.g.,containing Ca2+or Mg2+)to produce a carbonate,creating a stable

151、,solid mineral.Potential feedstocks could be alkalinity-rich geologic formations(e.g.,basalt andperidotite)or in alkaline industrial wastes(e.g.,mining wastes,steelmaking slag).The mineralization process has three primary variations:(1)in-situ,where CO2-rich fluids are injected into subsurface alkal

152、ine minerals,(2)ex-situ,whereby alkaline feedstocks are reacted with CO2in reactors at high temperature and/or pressure,and(3)surficial,in which alkaline material is reacted with CO2at ambient conditions or via sparging of high-purity CO2at low pressure.xxviiIn-situ mineralization can be paired with

153、 DAC for permanent storage.Certain components of mineralization can also be used in DAC technologies and there is some uncertainty in technology classification.For example,some technology developers are commercializing passive mineralization DAC technologies that repeatedly produce calcium carbonate

154、 by exposing calcium oxide to atmospheric CO2then employ renewable heat to produce a high purity CO2stream and a regenerated calcium oxide that can again capture CO2.xxviii5K4K65KLab and pilot scale 77 M25M1.9M+8 MEarlier scale projects#of projectsTotal capacity,TPA CO2Permanence,yearsCurrent capaci

155、ty7Announced capacity(as of Sept 2022)6,7#of projectsTotal capacity,TPA CO2CDR technologyMinera-lizationDAC370+DAC110,000112+BECCS210,000N/AN/AMineralization(ex-situ)10,00035440Biochar/bio-oilUncertain;depends on use-case,production process;and other factors,but centuries3N/A3Biomass-to-hydrogen510,

156、000 with geological storageBiCRSLimited publicly available informationSource:CDR company websites,“Direct Air Capture 2022”(IEA 2022,public announcements as of July 2022);LNNL:Getting to Neutral:Options for Negative Carbon Emissions in California(2020)1DAC announced projects include 1PointFives 70 1

157、 MTPA DAC facilities by 2035 and CarbonCaptures 5 MTPA Project Bison by 20302BECCS announcements include 15 Mt of biogenic CO2from heat and power plants,five cement plants with plans to integrate biomass feedstock in the clinker production process and retrofit CCUS,and two hydrogen facilities to run

158、 partly or fully on biomass3Biochar permanency estimates are in the decades to centuries timescale(IPCC AR6 WGIII(2022).Biochar may sequester an estimated 37%after 1000 years with estimated permanence ranging from a few decades to several centuries(Fuss 2018).Biochar as a soil amendment may sequeste

159、r carbon for anywhere from 83,500 years(“A Systematic Review of Biochar Research,with a Focus on Its Stability in situ and Its Promise as a Climate Mitigation Strategy”(Gurwick 2013).Bio-oil carbon could be sequestered for 1,000 years in depleted oil wells(“Pyrogenic carbon capture and storage”(Schm

160、idt 2018),“Biogeochemical potential of biomass pyrolysis systems for limiting global warming to 1.5C”(Werner 2018)4Primarily biochar incumbents who have not historically focused on carbon credit production5Routes include gasification and fast pyrolysis to H2.Planned projects include Chevron and Clea

161、n Energy Systems biomass to H2 plants 6Announced project timeline varies between 2024 to 20357Capacity is subject to LCA assumptions on net-GHG emissions and will differ by CDR technology pathway and specific technologies Figure 7:The removal capacity of technological approaches to CDR is expected t

162、o increase 100 x with announced capacity 13Pathways to Commercial Liftoff:Carbon ManagementCurrent costs and major cost levers by CDR technology,$/tonne CO2capturedFigure 8:Select CDR technologies costs are currently high but can be lowered through economies of scale,modularization and other levers

163、60090-120Liquid solvent1Solid sorbent1Mineralization(ex-situ)5BECCS(power)2Biochar3Bio-oil4225-355330-600125-28580-600HighTotalOpexCapex1Costs from NETL:Direct air capture solvent and sorbent studies;Upper bound of solid sorbent from Climeworks 2018,also cited in“A review of direct air capture(DAC):

164、scaling up commercial technologies and innovating for the future(McQueen 2021)2Cost estimates from Coalition for Negative Emissions for first-of-a-kind BECCS for power with modified financing costs same as above.Low ranges of purchase of biomass processed feedstock and biomass transport taken from F

165、AO U.S.biomass cost estimates rather than Coalition for Negative Emissions,which has higher estimates applicable to a UK-based plant(“Economic analysis of woodybiomass supply chain in Maine(Whalley 2017)3ICEF“Biomass Carbon Removal and Storage(BiCRS)Roadmap”(2021)4Cost for FOAK plant producing bio-o

166、il from cellulosic biomass heated to 500C without oxygen.From Charm Industrial“Carbon Removal:Putting Oil Back Underground”(2021)5Costs for ex situ mineralization with wollastonite,olivine-rich,and serpentine-rich tailings using heat and concentrated CO2from Kelemen P,Benson SM,Pilorg H,Psarras P an

167、d Wilcox J(2019)An Overview of the Status and Challenges of CO2Storage in Minerals and Geological Formations.Front.Clim.1:9.doi:10.3389/fclim.2019.00009CDR technologyMajor cost reduction leversDACBiCRSMinera-lizationCurrent costs,$/tonneOther drivers Critical drivers Energy efficient design and bett

168、er integration of amine systemsScaling capture deployment to larger plants and standardization Carbon mineralization process improvement,creation of usable products to offset high costsR&D and manufacturing efficiency of modular componentsReduction in operating and maintenance costs through learning

169、 by doingR&D to decrease costs of pyrolyzers and major nascent technologyLow cost biomass sourcesLow cost biomass sourcesEconomies of scale from maximizimg equipment sizing;learning by doingEconomies of scale from maximizimg equipment sizing;learning by doingR&D in solvents,systems and energy manage

170、ment;low cost energyCO2 transport cost,1$/tonne CO2Global capacity,MTPAMostly used for EOR in the U.S.,Canada,Brazil,China,the Netherlands and offshore NorwaySmall-scale food grade shipping;Emerging larger-scale applications(e.g.,Northern Lights)Small scale distribution of CO2to end markets,but not

171、implemented at scaleCurrent stateMain applicationsMature,at scaleMature in small scale;in-development at large scale Mature in small scale;in-development at large scale Pipeline2Ships335-60Rail andtrucking45-2514-253702Source:Global CCS Institute,Perez et al.(2012),Technic-Economical Evaluation of C

172、O2Transport in an Adsorbed Phase,Low Carbon Economy 1Cost ranges approximate based on published studies;costs a strong function of distance and pressure at which CO2is transported2Approximate costs based on published studies by the European Zero Emission Technology and Innovation Platform,the Nation

173、al Petroleum Council,and GCCSI process simulation for a 30-year asset life.All costs have been converted to a U.S.Gulf Coast basis.Lower end of pipeline cost assumes 20 MTPA,180 km onshore pipeline.Upper end of pipeline cost assumes 1 MTPA,300 km onshore pipeline.3Approximate cost based on 20 MTPA a

174、t a distance of 180 km on the low-end and 2.5MTPA capacity at 1,500 km on the high end.All costs have been converted to US Gulf Coast basis.4Low end represents liquid CO2transport via rail for 250 km,high-end represents adsorbed CO2transported 300 km via truckFigure 9:Pipelines are currently the mos

175、t used,least expensive,and most mature CO2transportation technology,but other modes will be used for certain applicationsSection 2.a.iii TransportTransport networks connect capture sites with final storage or utilization sites.CO2will likely continue to be transported primarily by pipeline for large

176、 volumes;rail,trucks,ships,and barges may also be used for specific applications,albeit at ahigher cost versus large-scale pipeline transport(Figure 9.).14Pathways to Commercial Liftoff:Carbon ManagementCO2PipelinesCO2pipelines are the most mature,and often the most cost-effective CO2transport techn

177、ology for high volumes($525 per tonne18)and will likely form the backbone of CO2transport networks.The U.S.has more than 80%of the worlds CO2pipelines,with a network spanning roughly 5,000 miles,mostly for enhanced oil recovery(EOR).xxixSince existing pipelines largely connect naturally existing CO2

178、domes with active oil fields,new pipeline routes will be needed to link emissions sources to geological storage.19CO2pipelines near the Gulf of Mexico and other areas can be repurposed to deliver captured CO2emissions instead of geologic CO2sourced from natural domes.Recently,new pipeline projects i

179、n the Midwest are seeking to aggregate small,discrete sources of low-cost CO2from ethanol plants.20,xxxToday,pipeline siting is largely regulated at the state level.States approve any required permits and any use of eminent domain to acquire the necessary rights of way(RoW)for pipeline development.T

180、wo federal bodies that could be equipped to exercise jurisdiction over sitingthe Federal Energy Regulatory Commission(FERC)and the Surface Transportation Board(STB)have not currently been delegated jurisdiction over siting of CO2pipelines by Congress,leaving authority to states.xxxiThe DOTs Pipeline

181、 and Hazardous Materials Safety Administration(PHMSA)regulates CO2pipeline safety and is currently updating its regulations in the wake of a 2020 CO2pipeline rupture.xxxiiSome ongoing CO2pipeline developments have faced objections from some landowners along their proposed routes.These landowners hav

182、e raised concerns about compensation,safety,and other impacts(e.g.,crop productivity).Developers have attempted to address these concerns and meaningful two-way engagement with host communities can help address or mitigate these issues.Some pipeline companies have publicly explored the possibility o

183、f classifying CO2pipelines as common carriers,which carry eminent domain rights and certain service provision requirements in some jurisdictions.21,xxxiiiOther CO2transport methodsBuilding out pipeline networks is a critical enabler for U.S.carbon management markets,as CO2transport by rail and truck

184、 are generally more expensive($3560 per tonne22).Still,rail,truck,and shipping may be important for certain applications in areas where pipeline access is not feasible.CO2transport by ship requires a loading facility and temporary storage on land.23,xxxivThis method is currently used on a small scal

185、e in Europe for food-quality CO2.Expanded shipping could enable offshore hub-and-spoke storage networks,especially in global hubs that are anchored near shipping channels or ports(e.g.,the Northern Lights project in Europe).24Forecasts predict the future load size will vary between 2,00050,000 tonne

186、s of CO2per shipment,leveraging liquified natural gas(LNG)experience and infrastructure.xxxv18 Depending on pipeline width,distance,land ownership and compensation,as well as other maintenance and construction considerations.19 CO2domes are naturally occurring CO2reservoirs intentionally produced to

187、 be sent to oilfields or for other CO2uses20 Proposed projects by Summit,Navigator and ADM-Wolf would each carry 10+MTPA.Emerging projects(e.g.,Tallgrass)are also proposing the conversion of natural gas pipelines to CO2,which could potentially use some of the 320,000 miles of natural gas transmissio

188、n and distribution across the U.S.21 Common carrier is used to define pipeline that services any third party under a standard set of terms,rather than a pipeline that is for private use or only serves select parties;Eminent domain refers to the governments ability to convert private property into pu

189、blic use,compensating the owner at fair market value(e.g.,right of ways RoWs to allow the construction of pipelines);Common carrier transportation 22 These costs are offered as approximate averages and individual project economics will depend on the distance to accessible transport networks(waterway

190、s or railways),the distance to storage or conversion sites,and the capacity of the transporting vehicle(and accordingly number of trips required).23 This process is like those seen in LNG projects,which may indicate a similar scale-up potential and trajectory24 Liquid CO2carriers,with 1,000-2,000 to

191、nnes per ship,transported from large point sources to coastal distribution terminals15Pathways to Commercial Liftoff:Carbon ManagementSection 2.a.iv StorageThe U.S.has abundant storage resources that are more than sufficient to meet carbon management needs.There are three primary options for the lon

192、g-term storage of captured CO2:geologic saline aquifer storage,depleted oil and gas reservoirs,or mineralization(e.g.,in ultramafic and mafic rocks such as basalt).Table 1:25 NETL and DOE:Carbon Atlas Vestimates range from 2,37921,633 billion metric tonnes.The highest scenarios for carbon management

193、 project the U.S.injecting 1.8 billion metric tonnes annually.North America has significant CO2geologic storage resources,estimated to be sufficient to reach its net zero goals.xxxviStorage optionStorage potential,billion tonnesLowMediumHighSaline aquifers xxxvii2,3798,32821,633Depleted oil and gas

194、reservoirs xxxviii186205232MineralizationGlobal estimates:2,50025,000 billion tonnesxxxixProject developers and other industry experts believe that most of the CO2stored in the U.S.will use saline aquifers.This choice is driven by the large potential capacity across both onshore and offshore saline

195、aquifers and strong public and investoracceptance and toward storage using saline aquifers relative to other options.Capacity estimates are shown in Table 1.North America possesses 2,40021,000 billion tonnes of CO2storage resourcesenough to store hundreds or thousands of years of captured CO2emissio

196、ns.25Saline aquifers are widely dispersed across the U.S.,though specific sites require characterization and other development work to better understand their potential commercial attractiveness.16CarbonSAFE Phase III:Site Characterization and PermittingCarbonSAFE Phase II:Storage complex feasibilit

197、y projects145691078322San Juan Basin CarbonSAFE:Ensuring safe subsurface storage of CO2in saline reservoir,New Mexico Institute of Mining and Technology3North Dakota CarbonSAFE Phase III:Site Characterization and PermittingUniversity of North Dakota Energy and Environmental Research center(EERC)5Int

198、egrated Midcontinent Stacked Carbon Storage Hub:Storage complex feasibility assessmentBatelle Memorial Institute1Commercial-scale carbon storage complex feasibility study at Dry Fork Station,WyomingUniversity of Wyoming8Accelerating CCUS at Dry Fork Station,WyomingUniversity of Wyoming9Wabash carbon

199、 SAFEUniversity of Illinois10CarbonSAFE Illinois Macon Country University of Illinois7Illinois Storage CorridorThe Board of Trustees of the University of Illinois 4North Dakota integrated carbon storage complex feasibility study The Energy and Environmental Research Center6Establishing an early CO2s

200、torage complex in Kemper County,Mississippi:Project ECO2SSouthern States Energy BoardGeologic storage site development supported through DOEs CarbonSAFE initiativeFigure 10:DOE helped develop multiple CCUS sites through the CarbonSAFE storage site characterization and CO2capture assessment projects

201、Source:Extracted from NETL website-https:/netl.doe.gov/carbon-management/carbon-storage/carbonsafe Pathways to Commercial Liftoff:Carbon ManagementEstablishing storage resources for development requires drilling exploration wells,taking seismic imaging data of the reservoirand performing engineering

202、 studies.These steps cost millions of dollars and take 13 years to complete.26DOEs CarbonSAFE Initiative seeks to accelerate this process by supporting the exploration of storage sites across at least seven regions within the U.S.Ten sites with at least 50 MT of capacity have undergone either feasib

203、ility or characterization studies(Figure 10.).The CarbonSAFE program is set to expand significantly with$2.5 billion in additional funding for storage projects from the Bipartisan Infrastructure Law.xlFurther characterization by other developers,often with DOE funding,has demonstrated an additional

204、potential of at least 300 MT from at least 11 sites.27,xliAdditionally,DOEs Regional Carbon Sequestration Partnerships include 7 regions across the U.S.and facilitate characterization,validation,and development phases.The Partnerships have produced the National Carbon Storage Atlases,contributed to

205、a series of Best Practice Manuals on sequestration approaches,and collectively enabled over 12MT of CO2storage.xliiProjects funded through Bipartisan Infrastructure Law Programs could unlock more than 350 MT of additional storage capacity,although not all will be commercially attractive to develop.x

206、liiiMore of these sites are required to satisfy the 400-1,800 MTPA capacity necessary for a net-zero economy.xliv,28There is no shortage in physical storage resources,but permitting timelines for storage sites are frequently mentioned as a potential bottleneck by investors and developers.Storage wel

207、ls are permitted through the Underground Injection Control Programs(UIC)Class VI requirements administered by EPA or implemented by approved“primacy”states,territories,or tribes.The UIC program is designed to ensure that injected CO2does not impact underground sources of drinking water or otherwise

208、impact human health and the environment.29,xlvEPA has approved six Class VI wells so far,two of which are in operation.For the first four Class VI wells,EPA issued the permits within two years;The permits for the remaining two wells took between 3 and 6 years.30EPA has publicly announced that,moving

209、 forward,it will strive to permit wells in two years and EPA has developed a series of tools to help streamline the permitting process.xlvi,xlviiEPA can approve States,tribes or territories to be the primary implementation authority for Class VI well permitting responsibilities;approved states are c

210、ommonly referred to as“primacy states”The two wells in North Dakota permitted under Class VI primacy took 810 months.31,xlviiWyoming also has primacy and has two active Class VI permit applications.Texas,Louisiana,Arizona,and West Virginia are currently in the Class VI pre-application or application

211、 process to receive primacy from EPA.xlixFPennsylvania is also planning to apply for Class VI primacy.EPA expects to complete its evaluation of Louisianas Class VI applications and request public comment on this evaluation in May 2023.liAs a result of BIL funding,EPA recently announced a grant progr

212、am for states,Tribes,and territories to defray expenses related to establishing and operating a Class VI UIC program.As a condition of receiving funding for new Class VI programs,states must incorporate Environmental Justice and equity considerations into their state permitting programs.liiCurrently

213、,four operational siteswith total initial capacity of 30 MThave received Class VI permits in North Dakota and Illinois.32Over 60 Class VI applications are currently pending at EPA with additional applications submitted in states with primacy.liiiPending applications could expand capacity by 80 MT or

214、 more.33 In some states,developers face legal ambiguity around pore space ownership(i.e.,who owns the space where CO2is injected),requiring additional and early due diligence.livIn states without comprehensive pore space regulations,the lack of legal precedent or clear law creates uncertainty regard

215、ing ownership and its impact on future legal challenges.lvMost commonly,this is an issue of split estates on lands where the surface right owner does not also own the mineral right and the primacy of mineral rights relative to pore space rights are unsettled.lviThis is also an issue that needs to be

216、 addressed with respect to federal lands,particularly in regions where mineral rights are owned by the federal government,but the surface right owner or lease may be different.In 2022,the Bureau of Land Management issued an instruction memorandum clarifying RoWs for geologic sequestration of CO2.lvi

217、iIn 2021,the BIL provided the Bureau of Ocean Energy Management with the authority to grant leases,RoWs,and easements for the subsurface storage of CO2.lviii26 Varies by developer and reservoir.2022 CCUS Institute Report27 Storage potential is impacted by geological features(e.g.,thickness,boundarie

218、s and porosity),rock quality(e.g.,permeability,pressure),and other factors(e.g.,depth,local seismicity,previous drilling,passage through freshwater aquifers especially single-source USDWs,and pipeline right of way).28 Assuming 25 years of capture and storage lifetime 29 It includes requirements for

219、site characterization,well construction,operation,monitoring,financial responsibility(including during post-injection care)and reporting/record-keeping30 Factors specific to each individual application can significantly impact how long it will take to issue a permit.Individual site conditions,commun

220、ity feedback,and the completeness or quality of the application may require additional time.For example,EPA may notify applicants of deficiencies in the application or make Requests for Additional Information.The responsiveness and completeness of applicants responses will ultimately dictate the per

221、mitting timeline.31 Differing definitions of application submission and approval between state and EPA Class VI processes make direct comparisons difficult.32 One other site(FutureGen)received Class VI approval,but did not proceed 33 Based on the Class IV Wells Permitted by EPA,the DMR and the Wyomi

222、ng DEQ 17Pathways to Commercial Liftoff:Carbon ManagementSection 2.a.v Enhanced Oil Recovery(EOR)storageHistorically,captured CO2has been primarily injected in oil fields for EOR.CO2-EOR,injecting from both naturally occurring and anthropogenic sources,was responsible for producing roughly 300,000 b

223、arrels of oil per day in the US in 2019.34,lix Nearly all of the injected CO2ultimately remains geologically stored underground while the oil in the reservoir is displaced and extracted for refining.lxCurrently,the majority of the CO2supply for EOR operations is taken from naturally occurring reserv

224、oirs,such as CO2domes.lxi,lxii,lxiiiAs industrial and atmospheric capture capacity expands,captured CO2that would have gone into the atmosphere could displace naturally occurring CO2in EOR operations.Using anthropogenic emissions for EOR can produce oil with lower lifecycle carbon emissions because

225、of the carbon initially stored to produce it.LCA performance willvary over the lifetime of a well and between wells based on well-specific practices and characteristics,but some propose a rule of thumb of 40%lower lifecycle carbon emissions per barrel of oil produced.lxiv,lxvSection 2.a.vi Utilizati

226、onCarbon utilization describes the creation of commercial products or commodities for consumption through the conversion or permanent containment of captured carbon with either CO2or carbon monoxide(CO)as feedstocks.In some cases,conversion can serve as an alternative to geologic storage for capture

227、d CO2,adding additional capacity and economic value and often replacing incumbent materials which are more emissions-intensive(Table 2.).3534 This process has mostly been used in the Permian basin,largely due to favorable geology and accessible,natural sources of CO2(NETL:CO2Enhanced Oil Recovery:Un

228、tapped Domestic Energy Supply and Long-Term Carbon Storage Solution).35 If utilization results in re-release of CO2(e.g.,in beverages or fuels)then there is no direct abatement potential.NOT EXHAUSTIVEUtilization CaseKey technologies 1Building materialsCO2-cured cement:injects CO2into fresh ready-mi

229、x cement or in pre-cast concreteCO2-based aggregates:metal oxides are extracted and carbonated using CO2from flue gas,and deposited onto a substrate creating aggregate that is composed of carbonatesClinker replacement:substitution of limestone with alkaline materials like fly ash followed by carbona

230、tion with CO22Plastics,chemicals,&new materialsCO2-derived polyethylene carbonates(PEC)polyols for heat insulation foams,transparent polycarbonate and polyurethane plasticsCO2-derived polypropylene carbonate(PPC)and polyethylene carbonates(PEC)polyols for polyurethane plastics3FuelsElectrolysis:CO2a

231、nd water converted to syngas through co-electrolysis to produce synthetic fuel(e.g.,diesel)through further processes(e.g.,FischerTropsch processes)Thermo-catalysis:liquid fuels(gasoline,diesel etc.)are synthesized from CO2and hydrogen Fischer-Tropsch:Conversion of syngas into liquid hydrocarbons thr

232、ough a catalytic chemical reactionCO conversion:Non-Fischer-Tropsch conversion of gases containing CO into liquid fuels and chemicalsTable 2:CO2can be converted to new materials like building materials,plastics,and synfuels 18Pathways to Commercial Liftoff:Carbon ManagementCO2demand for utilization,

233、excluding urea production,was 20-30 MTPA globally in 2019.lxviHowever,new commercial pathways have emerged that use conversion to create fuels,chemicals,and building materials.For many utilization applications,economics are highly uncertain and will depend on customer willingness to pay above the su

234、bsidized cost to produce.Carbon utilization processes vary in technology readiness,market dynamics,and potential for long-term CO2storage permanence.For example,building materials produced via CO2mineralization present the potential for permanent CO2storage,while producing jet fuel via Fischer-Trops

235、ch synthesis or CO conversion would have no long-term carbon storage potential(as CO2is produced and re-emitted upon fuel combustion).However,the emissions abatement from displacement of incumbent fossil-based jet fuel is sufficiently high to present an argument for continued development of these ca

236、rbon conversion pathways.lxviiAt scale,utilization is expected to account for only a fraction of the total carbon emissions capturedthe rest must be stored.While small relative to storage,North Americas CO2demand for utilization is projected to grow to 40 MTPA by 2030 and 100250 MTPA by 2050.36,lxvi

237、ii DOE has supported a diverse portfolio of carbon conversion processes,including catalytic conversion of carbon oxides to fuels and chemicals,uptake in algae and bioproducts,and mineralization for production of inorganic materials.lxvixSection 2.b Current regulation and policies supporting CCUS and

238、 CDR developmentSeveral policies support the buildout of CCUS and CDR infrastructure in the U.S.Inflation Reduction Act(IRA)45Q The 45Q tax credit is the largest and most certain incentive for carbon management in the world.By setting a reliable value forgeologically stored or utilized carbon,the 45

239、Q credit provides a consistent,performance-based revenue source that developers can use to evaluate potential projects.As amended by the IRA,the 45Q credit pays$85 per ton37;requires that qualified projects commence construction by the end of 2032;and allows the taxpayer to claim the credit for 12 y

240、ears once a project is placed in service(Figure 11).If a CCUS developer can capture and store carbon for under$85 per tonne on an all-in,levelized basis over 12 years,then the project is financially feasible.38Several other tax credits could support deployment of CCUS,including the 45V tax credit fo

241、r clean hydrogen production and the 40B and 45Z tax credits for sustainable aviation fuels and low-carbon transportation fuels.45Y and 48E tax credits are applicable for electricity generating facilities with lifecycle greenhouse gas emissions rates of zero or less.Projects cannot“stack”45Q with 45V

242、,40B,45Z,45Y,or 48E credits.The IRA also provides$5.8B to support advanced industrial decarbonization deployment,which could include carbon management projects in the industrial sector.36 Full range from the Princeton Net Zero Americas report is 100-700 MTPA by 205037$85/ton for sequestration subjec

243、t to certain labor requirements.If CO2is utilized,the credit is$60/ton.For DAC projects,45Q value is$180/ton for sequestration and$130/ton for utilization.38 Some projects may be eligible for other incentives or revenue streams,including state-level incentives like the California LCFS or the ability

244、 to sell a low-carbon product for a premium(e.g.,green steel.)19Pathways to Commercial Liftoff:Carbon ManagementFigure 11:Updates/enhancements to the 45Q tax credit from the IRA provides an enhanced 45Q tax credit for carbon captureAmount of tax credit$/tonne CO2Annual carbon capture thresholds,Thou

245、sand tonnesCO2per yearPayment method and transferabilityTax credit to capture equipment owner and transferable along the value chain if contractual arrangement in placeDirect pay for first 5 years after facility placed in service and transferable to unaffiliated third parties through a cash sale2100

246、500DACIndustrialElectric generation100Electric generation1.00IndustrialDAC18.7512.50505050353535Electric generationIndustrialDAC85851806060130Electric generation1Industrial1DAC1SequestrationEOR or utilizationPrevious 45Q(pre-Inflation Reduction Act)Updated 45Q(post-Inflation Reduction Act)1If prevai

247、ling wage and apprenticeship requirements are met2For taxable entities;Tax-exempt entities are eligible to receive direct pay for the full 12 years of the 45Q creditSource:Inflation Reduction Act 2022 Low Carbon Fuel Standard(LCFS)Low Carbon Fuel Standard programs are compliance markets that require

248、 a reduction in the carbon intensity of transportation fuels that are sold or supplied within a certain geography.State regulatory entities establish declining yearly fuel carbon intensity(CI)requirements.Fuels that exceed this mandated CI generate a credit deficit,while those below the mandated CI

249、generate a credit surplus.As a result,low-carbon fuels(e.g.,ethanol produced with CCUS)can receive revenue for credits.Additionally,in the California LCFS market,DAC can generate project-based credits for tonnes captured and storedeven if the capture occurs outside of the LCFS geography.Currently LC

250、FS markets operate in California,Oregon,and Washington;additional states are considering LCFS market adoption.The value for credits in Californias LCFS market has been volatile in recent years,ranging from$60 to$200 per tonne of CO2.20Pathways to Commercial Liftoff:Carbon ManagementBipartisan Infras

251、tructure Law(BIL)The BIL provides$12 billion in funding for high-potential projects across the carbon management value chain,including funding for demonstration and pilot projects.lxxThe BIL also includes$8B for Regional Clean Hydrogen Hubs,at least one of which must prioritize projects that use CCU

252、S to generate clean hydrogen and$500M for Industrial Emissions Demonstration Projects that could include carbon management technologies.Carbon Capture Demonstration Projects Program($2.5B)Carbon Capture Large-scale Pilot Projects($937M)Carbon Capture Technology Program,Front-End Engineering and Desi

253、gn($100M)Carbon Dioxide Transportation Infrastructure Finance and Innovation($2.1B)40Carbon Storage Validation and Testing($2.5B)Carbon Utilization Program($310M)Commercial Direct Air Capture Technologies Prize Competitions($100M)Precommercial Direct Air Capture Technologies Prize Competitions($15M)

254、Regional Direct Air Capture Hubs($3.5B)Carbon Negative ShotThe Carbon Negative Shot establishes an objective to advance CDR pathways that will capture and store CO2at gigatonnescale for less than$100 per net tonne of CO2-equivalent within the decade.This effort is part of DOEs Energy EarthshotsIniti

255、ative,which aims to accelerate breakthroughs of abundant,affordable and reliable clean-energy solutions.Procurement of Low-Carbon Products or Carbon Utilization ProductsSeveral state and local governments have passed laws that mandate the consideration of the embodied emissions of the products they

256、purchase,including California,New York,and Colorado.lxxiiCurrently,these policies focus mostly on building materials(particularly concrete),and can enable the technological maturation of CO2utilization in concrete and aggregates by decreasing the economic challenges to the use of these products.Rece

257、ntly,the Department of Energy released a Notice of Intent to provide grants to state and local governments that will help pay the added cost of procuring carbon utilization products.40 Funding covers“credit subsidy”associated with a loan,meaning$2.1B in appropriations could translate to$10B+in loan

258、authority21Pathways to Commercial Liftoff:Carbon ManagementChapter 3:Pathways to Widespread Deployment Key takeawaysMany carbon management technologies are mature and operating at commercial scale in the U.S.today.The carbon management ecosystem will scale between near-term and longer-term opportuni

259、ties.Initially,a low-cost transport and storage backbone can develop by connecting high-purity CO2streams(e.g.,ethanol,hydrogen SMR,and natural gas processing).Investors and project developers are working on more than$10B in projects in this space across the carbon management value chain.In parallel

260、,pilots and commercial demonstration projects can help reduce the cost of higher-cost point-source and CDR technologies Six main dynamics define the potential build-out of carbon management technologies:Development of low cost-of-capture sectors that are profitable today will aid initial transport a

261、nd storage build-outPilot and commercial demonstration projects in lower-purity CCUS applications and CDR will help to decrease costs and establish repeatable commercial arrangementsAdditional commercial revenue streams,policy incentives,or regulations may be needed to reach the scale of carbon capt

262、ure required for net-zero by 2050Significant scale-up of carbon-free energy and transmission capacity is needed for DAC and carbon utilization deployment that achieves GHG reductions on a life cycle basis Build-out of transport and storage for CCUS and CDR infrastructure must be swiftFinancing carbo

263、n management projects will depend on a robust tax equity market and implementation of 45Q tax credit“transferability”Section 3.a:The pathway to widespread deploymentCarbon management is a mature technology with over 20 MTPA in capture capacity already deployed and operating in the U.S.and several pr

264、ojects in advanced stages of development.This section outlines the path to widespread commercial deployment at scale.The carbon management ecosystem is scaling through two overlapping tracks(Figure 12):In the near-term,industries with high-purity CO2streams(e.g.,ethanol,hydrogen from steam methane r

265、eforming(SMR),and natural gas processing)and other large,integrated projects will lead the way through 2030.These early projects have more favorable economics and can anchor the buildout of large-scale transport and storage infrastructurelaying the foundation for carbon management applications in ot

266、her industries(e.g.,steel,cement).Longer-term,industries with lower-purity CO2streams will see cost declines supported by pilot and commercial demonstration projects now through the mid-2030s.Demonstration funding and project-specific factors(e.g.,proximity to storage,end-customers willingness to pa

267、y)will unlock FOAK deployments in many of these sectors prior to 2030.22Pathways to Commercial Liftoff:Carbon Management41 Net-zero decarbonization scenarios forecast of what it would take to reach net-zero by 2050 under unconstrained renewable and transmission capacity(on the low end)and a technolo

268、gy spike case on the high end where the development of other technologies continues at current momentum and carbon management plays a larger role in decarbonization.Modeling completed for this Pathways effort.Figure 12:Near-term opportunities focus on high-purity streams;longer-term opportunities in

269、 lower purity streams require demonstration projects 41,lxxii1Ethanol,natural gas processing,and hydrogen SMR2Abated emissions are based on the modeling with the ranges corresponding to net zero and high technology case scenarios.Full range of emissions abated given other reports range from 400-1800

270、 MTPASource:Deployment and investment figures in this section are based on modeling conducted for this report by McKinsey&Company in accordance with Government Contract No.DE-AC02-06CH11357 and subcontract 2J-60009.Deployment numbers fall within the general ranges expected from several government an

271、d other research reports,including:Princetons Net Zero America report(2021,the White House Pathways to Net-Zero GHG Emissions by 2050(2021),The IPCC(2021,IRENA(2021),IEA(2021);)205020302040$50-80 B$130-200 B$300-600 BInvestment required,$B280-420570-1,2202Emissions abated,MTPA70-110DescriptionNear-t

272、erm horizonLonger-term horizonDemonstration projects in lower purity CO2streams to achieve cost declines in high capture cost industries,enabling breakeven and eventual profitability Longer-term opportunities-accelerated build-out in lower purity streams as additional projects become economicalForma

273、lization of carbon markets enable revenue streams or market signals beyond 45QScaled deployment to reach net zero scale of CCUS and CDR to achieve net zero targets Near-term opportunities-development in industries with high-purity CO2streams1and other large,integrated projectsBuild out large-scale t

274、ransport and storage infrastructure 23Pathways to Commercial Liftoff:Carbon ManagementCarbon capture costs1excluding storage and transport costs,$/tonne CO2Figure 13:Carbon capture cost is a function of CO2concentration and other facility-specific factorsAcross both opportunities,70110 MTPA of carbo

275、n-management capacity is expected by 2030,primarily from the capture of high-purity CO2streams and demonstration projects in lower-purity and diffuse steams.42High-purity CCUS already has momentum,with developers working on large-scale pipelines to connect ethanol,ammonia,gas processing,and some hyd

276、rogen projects that address relatively low cost-of-capture streams.However,some other project types become economic only with additional government support or policy,alternative carbon markets or revenue streams,or cost reduction from demonstration projects(Figure 14.).Some particularly attractive p

277、rojects in the lower-purity industries(e.g.,very large emissions sources close to transport and/or storage)are being developed,but broader lift-off could require additional financial or regulatory incentivesand regulatory developments in particular could play a dramatic role in accelerating the path

278、ways described here.1Displayed cost estimates based on EFI Foundation capture costs with transport(GCCSI,2019)and storage(BNEF,2022)costs of$10-40/tonne,except where noted.All in 2022 dollars.All CCUS figures represent retrofits,not new-build facilities.The lower bound costs represents a NOAK plant

279、in a low cost retrofit scenario with low inflation.The higher bound costs represents a FOAK plant in a high cost retrofit scenario with high inflation.The inflation variance on each cost estimate represents the range of cost increases on a generic chemical processing facility due to inflation from 2

280、018 using the Chemical Engineering Plant Cost Index(CEPCI).2Based on liquid solvent range of$225-355/tonne and solid sorbent range of$330-600/tonne from NETL:Direct air capture solvent and sorbent studies and Climeworks(for solid sorbent)3CO2concentration is not the only driver of cost in difficult

281、to abate sectors.Multiple units/emissions streams,impurities,and other factors can contribute.4Includes BECCS to power,biochar,and bio-oilSource:EFI Foundation,“Turning CCS Projects in Heavy Industry&Power into Blue Chip Financial Investments”.Hydrogen SMR-only capture costs from IEA 2019.;Coal and

282、CCGT power plant retrofit cost of capture figures derived from NETL Revision 4a Fossil Baseline study retrofit cases adjusted to 2022 dollars and with 12-year amortizationrange represents FOAK with high retrofit factor(high figure)to NOAK with low retrofit factor(low figure).DAC costs from NETL:Dire

283、ct air capture solvent and sorbent studies;Upper bound of solid sorbent from Climeworks 2018,also cited in“A review of direct air capture(DAC):scaling up commercial technologies and innovating for the future(McQueen 2021);BiCRS cost estimates from Coalition for Negative Emissions for first-of-a-kind

284、 BECCS for power with modified financing costs same as above.Low ranges of purchase of biomass processed feedstock and biomass transport taken from FAO U.S.biomass cost estimates rather than Coalition for Negative Emissions,which has higher estimates applicable to a UK-based plant(“Economic analysis

285、 of woody biomass supply chain in Maine(Whalley 2017)and ICEF“Biomass Carbon Removal and Storage(BiCRS)Roadmap”(2021),Charm Industrial“Carbon Removal:Putting Oil Back Underground”(2021);Mineralization costs from author benchmark cost used in IPCC.Costs for ex situ mineralization with wollastonite,ol

286、ivine-rich,and serpentine-rich tailings using heat and concentrated CO2from Kelemen P,Benson SM,Pilorg H,Psarras P and Wilcox J(2019)An Overview of the Status and Challenges of CO2Storage in Minerals and Geological Formations.Front.Clim.1:9.doi:10.3389/fclim.2019.00009;Current emissions from EPA GHG

287、RP FLIGHT database 2019 and includes biogenic CO2emissions for pulp and paper(110 MTPA)Note:Applications are arranged left-to-right by industry,power,and CDR reflecting the rough CO2concentration of the CO2sources associated with these applicationsExtremely low purity CO2streams123High-purity CO2str

288、eamsMedium to low purity CO2streams 1752200200150050600100Steel(Blast Furnace BOF)Hydrogen(SMR only)18-26Direct air capture2Refineries(Fluidized Catalytic Cracker)Hydrogen(SMR and stream production,90%capture)Pulp&paper(Black liquor boiler)CementproductionAmmonia(flue gas)Power plants-CoalPower plan

289、ts-CCGTBiCRS4Mineralization(ex-situ)14-2082-1365076-12168-11475-11953-8690-600225-60061-9476-12386-116Natural gas processingEthanol80-600High purity sourceCurrent emissions,MTPAMed to low purity sourceExtremely low purity sourcex42 Low case projecting 40-50%of all ethanol,ammonia,and natural gas pro

290、cessing and accessible H2 install capture,as well as one demonstration project at average plant size in power,refining,cement,steel,DAC,and other CDR.Current emissions from EPA GHGRP FLIGHT database.High case represents 70-80%of ethanol,ammonia and H2,50%of natural gas processing,2 demonstration pro

291、jects at average plant size in power,refining,cement and steel,and announced capacity of leading DAC player.24Pathways to Commercial Liftoff:Carbon ManagementCosts and potential revenues for CCUS point source retrofits in higher cost-of-capture applicationsFigure 14:Lower purity point sources requir

292、e further cost reductions or additional revenue streams 1Revenue includes 45Q for all industries,with a value of$60-85/tonne.Pulp and paper includes potential VCM revenue.Hydrogen revenue includes PTC,estimated to be$100/tonne.2.Industrial applications from EFI Foundation,“Turning CCS Projects in He

293、avy Industry&Power into Blue Chip Financial Investments”Coal and CCGT power plant retrofit cost of capture figures derived from NETL Revision 4a Fossil Baseline study retrofit cases adjusted to 2022 dollars and with 12-year amortizationrange represents FOAK with high retrofit factor(high figure)to N

294、OAK with low retrofit factor(low figure).Transport(GCCSI,2019)and storage(BNEF,2022)range from$10-40/tonnePower plants-coalCement productionSteel(Blast furnace BOF)Pulp and Paper(Black liquor boiler)Power plants-CCGTRefineries(Fluidized catalytic cracker)Hydrogen(SMR and steam production,90%capture)

295、Ammonia(flue gas)85-28585-15963-12686-1618571-1348596-1568586-163858578-15485-10092-17685-100Dynamics impacting pathways to commercialization scaleSix dynamics impact the commercialization pathway for carbon management.Development of low-cost-of-capture sectors that are solidly investable today will

296、 aid early infrastructure build-out,but is not sufficient to reach net-zero goals Today,build-out of CCUS is primarily in industries with a low cost of capturing CO2,typically enabled by high-purity CO2streams(e.g.,ethanol,natural-gas processing,hydrogen from SMR).Business case modeling suggests tha

297、t ethanol CCUS projects could see unlevered internal rates of return(IRRs)of 1015%or more with the enhanced 45Q tax credit from the IRA.Project development in these low cost-of-capture applications is ongoing and accelerating.Although these projects constitute a fraction of overall carbon management

298、 potential,they can jumpstart the build-out of shared transport and storage infrastructure.Higher cost-of-capture CCUS and CDR may not deploy absent additional drivers,such as regulationsCurrent average costs are estimated to be close to or above the$85 per tonne CO245Q credit in higher-cost applica

299、tions(e.g.,cement,iron and steel,power including BECCS),and sustained inflation could increase costs further given that the IRA suspends inflation adjustment for 45Q until after 2025.Limited revenue sources for captured CO2beyond the 12-year 45Q tax credit window results in carbon management project

300、s that are economically challenged today(Figure 14.)Individual project dynamics(e.g.,close proximity to storage)are critical,and projects will be sensitive to any cost overruns.Regulations constraining emissions from any of the relevant sectors could shift commercialization significantly.For DAC,the

301、 new IRA 45Qtax credit of$180 per tonne is still insufficient without further cost declines or strong markets for carbon removal credits.45Qutilization45QstorageProjected revenue(low)1,$/tonneTotal cost(low)2,$/tonne Total cost(high)2,$/tonne Projected revenue(high)1,$/tonne25Pathways to Commercial

302、Liftoff:Carbon ManagementDemonstration and initial commercial projects are critical to achieving cost declines through“learning-by-doing”.Retrofitting CCUS in some contexts can require some facility-specific designs that may not be perfectly transferrable to other facilities.Nevertheless,creation of

303、 standard(e.g.,starting point)designs,increased modularization,and dissemination of operationallearnings will enable cost reductions over time.Researchers and developers expect cost declines with deployment,though the persistent energy requirements for many carbon management technologies mean that t

304、he drastic cost declines observed in no-fuel technologies like wind and solar are unlikely.Researchers have modeled potential CapEx learning rates for DAC of 10-20%(that is,a 10-20%decline in CapEx costs for every cumulative doubling of capacity.)Developers have set aggressive cost reduction targets

305、.Start-ups have announced pathways to achieve$30-50/tonne cost of capture for industrial sources(from$60-120/tonne today)and DAC developers Carbon Engineering and Climeworks claim a pathway to$100/tonne within ten years.lxxiii,lxxiv,lxxvCost declines in CO2transport and storage are achievable throug

306、h building shared regional pipeline and storage networks but given their relatively small share of total costs for higher cost-of-capture applications these reductions alone may not make retrofit projects profitable in the absence of other drivers.Additional revenue streams or regulation may be requ

307、ired to reach the scale of carbon capture needed for net-zero by 2050.If cost declines do not bring levelized costs of carbon management below expected revenues,additional revenue sources or regulation will be needed for carbon management to reach a scale of deployment commensurate with its emission

308、s reduction potential.In many cases,FOAK deployments financed by BIL and IRA will establish baseline costs and subsequent facilities will realize cost reductions as a result of project development,technology,permitting,and community engagement learnings,as well as economies of scale and enabling inf

309、rastructure.While 45Q constitutes the primary incentive for carbon management in the US today and is scheduled to sunset for new projects beginning construction after 2032,industry players across CCUS and CDR expect regulations and private sector action to continue incentivizing or driving growth of

310、 carbon management in the future.Mechanisms could include extension of 45Q,regulations such as emissions standards,cap and trade programs or carbon taxes,or support for other revenue streams(e.g.,voluntary carbon markets,technology premiums,premium PPAs and revenues from other products.).Build-out o

311、f DAC and CO2utilization could be limited if clean energy build-out is constrained.Todays DAC technologies require significant energy and heat to operate;current technology requires 68 GJ per tonne CO2captured.lxxviWith current configurations,thermal energy accounts for 80%of total energy needs for

312、sorbent-based DAC.lxxviiAchieving net-negative emissions,therefore,will require significant clean power and thermal energy for DAC technologies.Clean energy is also needed for utilization pathways in which CO2and CO are converted to other molecules(e.g.,synfuels,plastics).lxxviiiUp to 9,300 TWh per

313、year of additional zero-carbon electricity capacity could be needed to achieve net-zero aviation globally by 2050.lxxixThis level of generation represents more than double the total annual electricity consumption in the U.S.Build-out of transport and storage infrastructure for carbon management must

314、 be swift.The build-out of CO2transport and storage infrastructure is critical.Currently,the U.S.has 5,000 miles of operational CO2pipelines,largely developed for enhanced oil recovery(EOR).Significant new transport infrastructure that can enable geologic saline aquifer storage will be crucial as th

315、e carbon management ecosystem develops.Several studies have attempted to optimize the required pipelines based on varying estimates of CO2that will need to be transported.Regardless of the scenario,studies suggest transport capacity must be scaled to 30,000-96,000 miles by 2050(Figure 15.).lxxxIn ad

316、dition to expansion in pipeline capacity,other modes of CO2transport including barge,ship,train,and trucks are likely to serve an important role in facilitating offshore storage,shorter routes,and collection from multiple proximate facilities.lxxxi26Pathways to Commercial Liftoff:Carbon ManagementFi

317、gure 15:Different pipeline network configurations have been proposed by various studies,with 30,000 to 96,000 miles of pipeline expected to be required by 2050The scale of CCUS deployment will also require significant storage capacity to be developed.The timeline to permit and develop storage capaci

318、ty must be accelerated to meet the amount of storage needed to support 70110 MTPA by 2030.More than 50 MTPA of Class VI applications are currently awaiting or under review.lxxxiiState Class VI primacy and EPA achieving its goal of 2-year processing timelines can alleviate this potential bottleneck.P

319、roject finance will depend on a robust tax equity market and implementation of 45Q“transferability”Like other clean energy technologies,carbon management projects must use the future delivery of federal tax credits to finance large upfront construction costs.In carbon managements case,these are the

320、45Q tax credits projects receive from the IRS for each tonne of captured carbon emissions they successfully store or utilize.While 45Q projects developed by for-profit entities can receive direct payment of the face value of the credit for the first five years of project operations,most projects cre

321、dits in years 6-12 must be used directly by the project sponsor,monetized via a tax equity investor,or sold to another entity with a tax liability under the new“transferability”provisions in the IRA.43Carbon management projects have substantial operational costs and,absent other drivers,projects may

322、 not be able to profitably continue operation of captureequipment once they stop receiving 45Q credits after 12 years of operations.44As a result,project finance investors in carbon management projects generally must plan to hit their return thresholds within 12 years.Carbon management projects coul

323、d pursue financing through tax equity or through traditional project finance.Both approaches face uncertainties that could complicate project development.Source:NETL Review of CO2Pipelines in the United States,Princeton net-zero Americas,Great Plains Institute Current state(4,500 miles)CasePipeline

324、scenarioGreat Plains Institute(30,000 miles)Net Zero Americas(70,000 miles)DOE stress case from Net Zero America(96,000 miles)CasePipeline scenario43 Not-for-profit entities like rural electric cooperatives can receive direct payment for all 12 years of the credit.44 Many investors expect further po

325、licy support or regulation to come into play as 45Q facilities start reaching the end of this 12-year period,but this support is not certain.27Pathways to Commercial Liftoff:Carbon ManagementTax equity is the primary way clean energy developers,especially in wind and solar,have monetized their tax c

326、redits if they do not have a sufficient tax liability of their own.Tax equity allows entities with a large tax bill to put up upfront capital in the project in exchange for the right to the tax credits generated.These tax equity investors can then use these tax credits to lower their tax liability.T

327、ax equity requires complex project structuring and developers generally cede a portion of the face value of the credit to their tax equity partner.Challenges for carbon management projects using tax equity include:The size of the tax equity market is constrained:Historically,only large financial ins

328、titutions have had the persistent tax bill and structured finance wherewithal that make tax equity an attractive proposition.The total market for tax equity is$20 billion/year and two banksJP Morgan and Bank of Americaaccount for 50%of tax equity volumes.lxxxiiiFuture growth of the tax equity market

329、 may be constrained.The large number of tax equity-eligible projects seeking to partner with a relatively small number of tax equity investors has led to projects consistently accepting tax equity investment at a significant effective discount to face value.Carbon management projects will compete wi

330、th other clean energy projects for tax equity investors interest:Historically,tax equity investors have focused almost exclusively on wind and solar projects.Wind and solar are well-understood asset classes with reliable tax equity structures that tax equity investors are comfortable with.The expans

331、ion of 45Q,the extension of renewable energy credits,and the creation of large new credits like 45V for hydrogen production could create hundreds of billions of dollars in projects seeking tax equity compared to a tax equity market of$20 billion/year.Traditional project finance,in which projects rec

332、eive debt against expected future cashflows,may become a more viable option for carbon management projects with the passage of the IRA.Tax-exempt entities can receive direct payments for 45Q tax credits,simplifying project finance for these developers dramatically.For non-tax-exempt developers,direc

333、t payment is available for the first five years of the project.After year five,the IRA allows for-profit entities to transfer tax credits to taxpayers uninvolved in a project.Projects can sell those credits directly to entities with a tax bill they are trying to minimize.These carbon management projects may seek a loan from commercial banks underwritten by the expected revenues from transferring c