Carbon Capture and Storage in thedecisive decade for decarbonisation- The case for Asia

Acknowledgement

About AIGCC
The Asia Investor Group on Climate Change (AIGCC) is an initiative to createawareness and encourage action among Asia’s asset owners and financial
institutions about the risks and opportunities associated with climate change
and low carbon investing.
AIGCC provides capacity for investors to share best practice and to collaborate
on investment activity, credit analysis, risk management, engagement andpolicy. With a strong international profile and significant network, AIGCC
represents the Asian investor perspective in the evolving global discussions
on climate change and the transition to a greener economy. AIGCC has over
50 members from 13 markets representing over USD26 trillion in assets undermanagement.
www.aigcc.net

About Wood Mackenzie
Wood Mackenzie, a Verisk business, is a trusted source of commercial
intelligence for the world’s natural resources sector. For nearly 50 years, wehave been providing quality data, analytics, and insights, establishing us as
the global research and consultancy business powering the natural resourcesindustry. We empower clients to make better strategic decisions, by arming
them with objective analysis and advice on assets, companies and markets.
Our dedicated oil, gas & LNG, power & renewables, chemicals, metals &mining sector teams are located around the world, and deliver research andconsulting projects based on our assessment and valuation of thousandsof individual assets, companies, and economic indicators such as market
supply, demand, and price trends. We partner with our customers to provide
the analytics solutions they rely on to inspire their decision making and,ultimately, accelerate the world’s transition to a more sustainable tomorrow.

www.woodmac.com

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

This report is written by AIGCC and leverages findings and figures from an
independent report by Wood Mackenzie, which was commissioned by AIGCC.

Lead authors from AIGCC
Firdaus Anuar

Project Manager

Yong-liang Por

Research Manager

Valerie Kwan

Director, Engagement

With contribution from Wood Mackenzie
Joshua Ngu

Vice President

Allen Chan

Principal Consultant

Reviewers and acknowledgement of individuals
The feedback provided by these individuals does not represent an
investment endorsement or recommendation and does not reflect any
policies or positions of their firms. With grateful thanks:
All supportive colleagues of AIGCC and IGCC, Karen Wu and team (Cathay
Financial Holdings), Courtney Foster, Josh Lowell, Laetitia Pirson, and Tracey
Cameron (Ceres), Jose Lazuen (IIGCC), Eric Nietsch (Manulife Investment
Management), Ben Pincombe (Principles for Responsible Investment), andJacqueline Tao (TransitionZero).

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

TABLE OF CONTENTS
Executive Summary........................................................................................................................................................................ 3
1. Introduction and Purpose of Report.....................................................................................................................................6
		Introduction............................................................................................................................................................................ 6

		

Purpose of the report...........................................................................................................................................................8		Context of study..................................................................................................................................................................... 9		Scenarios and assumptions.............................................................................................................................................. 10

2. Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country........................................ 11		Power generation sector................................................................................................................................................... 11			High level evaluation of technologies considered for the analysis................................................................ 12

			

Findings and analysis................................................................................................................................................... 15

		Steel sector...........................................................................................................................................................................18

			High level evaluation of technologies considered for the analysis................................................................ 19

			

Findings and analysis................................................................................................................................................... 21

		Country level summary - further analysis by AIGCC..................................................................................................23			

China................................................................................................................................................................................. 25

			India.................................................................................................................................................................................. 25

			Japan.................................................................................................................................................................................26

			South Korea....................................................................................................................................................................26

3.

A qualitative comparison of conclusions if extended to a 1.5°C pathway.......................................................... 27

		Implications for power generation sector....................................................................................................................28		Implications for steel sector............................................................................................................................................. 29

4.

AIGCC’s additional assessment of challenges and other considerations to large-scale deployment

		of CCS...................................................................................................................................................................................... 31

		

Significant environmental risks....................................................................................................................................... 31		Technical challenges facing CCS......................................................................................................................................34

		

CCS projects are difficult to finance commercially.....................................................................................................46		Societal opposition is likely.............................................................................................................................................. 37		Competitive deployment of resources by governments..........................................................................................38

5.

Conclusion.............................................................................................................................................................................39		Appendices........................................................................................................................................................................... 40			Appendix A: Storage availability in focus countries............................................................................................40

		Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country –			Power Generation Sector............................................................................................................................................42			Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector...........51

			

Appendix C: Scenarios Used by Wood Mackenzie in the Analysis................................................................... 59

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

GLOSSARY
Term

Description

AET-1.5

Accelerated Energy Transition -1.5, Wood Mackenzie's 1.5 °C scenario

AET-2

Accelerated Energy Transition -2, Wood Mackenzie's 2°C scenario

AIGCC

Asia Investor Group on Climate Change

AUD

Australian Dollar

bcfd

Billion cubic feet per day

BF

Blast Furnace

BOF

Basic Oxygen Furnace

CAPEX

Capital Expenditures

CCS

Carbon Capture and Storage

CCU

Carbon Capture and Utilization

CN

China

CSP

Crude Steel Production

DAC

Direct Air Capture

DRI

Direct Reduced Iron

EAF

Electric Arc Furnace

EOR

Enhanced Oil Recovery

ETO

Energy Transition Outlook, Wood Mackenzie's base case scenario based on current policies

EUR

European Euro

GBP

British Pound

GCCSI

Global CCS Institute

GHG

Greenhouse gas

Gt CO₂e

Gigaton (billon tons) of CO₂ Equivalent

IEA NZE

International Energy Agency Net Zero Emissions by 2050 Scenario

IEA SDSInternational Energy Agency Sustainable Development Scenario

IGCC

Integrated Gasification Combined Cycle

IN

India

IPCC

Intergovernmental Panel on Climate Change

JKIC

Japan, South Korea, India, China

JKTJapan, South Korea, Taiwan

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

1

Term

Description

JP

Japan

KR

South Korea

LCOE

Levelized Cost of Electricity

MENA

Middle East and North Africa

METI

Ministry of Economy, Trade and Industry, Japan

Mt CO₂e

Megatons (million tons) of CO₂ Equivalent

Mtpa

million tons per annum (year)

N/A

Not Applicable

NDC

Nationally Determined Contribution

NGCC

Natural Gas Combined Cycle

NPC

National Petroleum Council

O&M NPC

Operations and Maintenance National Petroleum Council

OPEX O&M

Operational Expenditure Operations and Maintenance

PCI OPEX

Pulverized Coal for Injection Operational Expenditure

ROW PCI

Rest of World Pulverized Coal for Injection

ROW

Rest of WorldSCPCSupercritical Pulverized Coal

T&D SCPC

Transmission and Distribution Supercritical Pulverized Coal

USD

United States Dollar

WM T&D

Wood Mackenzie Transmission and Distribution

ZEP WM

Zero Emissions Platform Wood Mackenzie

ZEP

Zero Emissions Platform

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

2

Executive Summary
The large-scale adoption of carbon, capture and storage (CCS) continues to be a key assumption underlying
major decarbonization pathways as a means to bridge the emissions gap1, resulting in projected CCS capacity
requirements that are an order of magnitude greater than present capacity.
To date, there have been few challenges to this assumption despite the significant obstacles that CCS faces,
including high operational costs, complex technical challenges, a myriad environmental risk and societal
opposition, resulting in a total of only 27 operating CCS facilities worldwide2 with a capture capacity of 40Mtpa/
year-to-date versus projections of up to 6 Gt/year by 2050 in some assessments.
In the decisive decade for decarbonization, the prospect of CCS deployment has become a discussion of criticalimportance. To validate whether such capacity projections for 2050 are plausible in the Asian context, AIGCC
has commissioned Wood Mackenzie to assess the drivers of CCS feasibility, consisting of cost competitivenessto alternatives, policy and regulatory support and storage availability, to assess the competitiveness of CCS in
the power generation and steel sectors of China, India, Japan and South Korea (simplified as JKIC onwards).
AIGCC leverages upon selected findings and figures from Wood Mackenzie’s report in its analysis which has
drawn the following conclusions:•

Deploying CCS capacity in the power generation sector:• Will depend on total generation capacity required from gas and coal, and incentives to deploy CCS in
these plants• Will need to reach 2.8 Gt by 2050 in the Wood Mackenzie 2°C scenario if climate targets of below 2°C are
to be met
• Will require right combination of policy support and technology, which are currently not in place

However, weighing the prospect of lowering costs of renewable energy, there exists a potential risk in CCS
implementation resulting in a prolonged transition process away from fossil fuel use.
Detailed analysis of levelised cost of electricity across different scenarios are available in Appendix B1.
•

Deploying CCS capacity in the steel sector:• Is more probable as there are no viable low-carbon alternatives in the short-to-medium term for blast
furnace applications• Will need to reach 500 Mt by 2050 in the Wood Mackenzie 2°C scenario if climate targets are to be met• Is dependent on adequate policy support to allow CCS to compete in blast furnace applications.

1

Emission gap is defined as the difference between the business-as-usual scenario (noted as ETO scenario in Wood Mackenzie
analysis) and the 2°C scenario (noted as AET-2 in Wood Mackenzie analysis)

2

The Global Status of CCS 2021 report: https://www.globalccsinstitute.com/resources/global-status-report/

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Executive Summary

However, for some lower carbon production methods such as Scrap EAF and Biomass BF-BOF in China andIndia, even with the implementation of carbon tax, steelmaking processes with CCS retrofits significantly fallshort in its cost competitiveness. Blast furnace will still be required as it will not be fully displaced by scrap
and other options. However, as fuels such as hydrogen become viable, it will also compete with CCS as adecarbonisation solution. Detailed analysis of the cost competitiveness of various steel production methods
across different scenarios are available in Appendix B2.
At the time of this report’s release, granular data within the 1.5°C scenario (referred onward as AET-1.5
scenario) is yet to be made available for application in the analysis. It is therefore important to note that
Wood Mackenzie’s analysis was based on the 2°C scenario of the decarbonization pathway. It is expectedthat the direction and feasibility of CCS will broadly remain the same in the 1.5°C pathway, but will see thefollowing nuances:•

Global energy demand and mix: Efficiency gains reduce fossil fuel demand while electricity demand grows
even more strongly•

Pace of transition: Accelerated actions in the near term; negative emissions in long term required to meetthe carbon budget•

Technology: Low carbon technologies such as renewables, nuclear and hydropower will be deployed more
rapidly and in greater volumes•

Policy: Aggressive global policies to incentivize action in hard to abate sectors and target carbon budget

AIGCC’s research further examines additional obstacles to the large-scale implementation of CCS, including:•

Environmental risks from potential leakages that are hazardous to human health and ecosystems andmay also lead to water stress given the high water intensity of carbon capture processes. This also creates
the prospect of financial liabilities for this leakage.

•

Technical challenges arising from a lack of scalability owing to the different technical specifications requiredfor different CCS projects, significant research needed to assess the suitability of storage formations anddifficulty in establishing a network of pipelines required for large scale transport of CO₂.

•

Financing dearth as commercial banks remain reluctant to finance CCS projects due to a lack of revenue
stream and high commercial failure rate, and we judge public funding for globalized CCS adoption to beunlikely.

•Societal opposition appears likely owing to the probable large expansion of industrial sites to accommodate
CCS equipment, large-scale use of hazardous chemicals and its transportation and the siting of CO₂
pipelines.

•

Competitive deployment of resources into ensuring a smooth transition into net zero will affect the overalllevel of support for CCS deployment. Policies and the different levels of international cooperation toaddress climate change and its impact to commodity prices, capital investments, sharing of capabilities andexport policies may have an indirect impact on the level of attractiveness of large-scale CCS deployment.

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Executive Summary

This analysis highlights the numerous and deep-seated obstacles facing the widespread adoption of CCS.
Combined with the improving economics of renewables in the power generation sector, AIGCC believes thatcurrent projections of CCS capacity are likely to substantially undershoot, which in turn, has significant
implications for decarbonization pathways of climate models and strategies of industries, governments andcompanies.
The following are key recommendations for various stakeholders:
Investors•

Engage with companies where CCS implementation is relied upon as a solution to decarbonize business
operations rather than an option to prolong the transition away from fossil fuel, and to understand theextent of which CCS is being considered as a decarbonization strategy.

•

As part of corporate engagement, gain deeper understanding of sector relevance of CCS implementation
for the company’s operations, while ensuring that other options to reduce emissions at source are being
fully considered and that CCS is only used to neutralize residual emissions where no other technologies
exist to decarbonize.

•

Engage with policy makers to understand CCS infrastructure support, requirements, and pre-requisites
necessary to enable the deployment of CCS.

Companies•

Acknowledge that for some sectors, a credible decarbonization pathway will require the phasing out ofhigh-carbon assets, and that the implementation of CCS is only to be used to neutralize residual emissions
and as a bridging technology in a carbon-constraint world for sectors that are hard to abate.

•

Deployment of CCS should be supported by detailed disclosure of expected contribution of CCS to carbon
emissions reduction targets. Relevant feasibility studies and contingency planning in the event of shortfall
to carbon captured through CCS project deployed at asset level should be conducted to justify the scopeand scale of CCS strategy to support the company’s decarbonization.

In conclusion:•

The attractiveness of CCS deployment is lower when other cost competitive low or zero carbon options areavailable•

In the steel sector, competition from the cost of fossil fuel-powered feedstocks and other emerging
technologies such as hydrogen as the zero-carbon feedstock will influence the level of attractiveness of
CCS deployment.

•

It is critically important for investors to carefully evaluate companies’ decarbonization strategies thatare reliant on CCS. Proper due diligence is needed as each CCS project tends to have specific technicalcharacteristics with different types of risk•

CCS technology and economics, including issues on leakage and liability, continue to be a prominent issue•

Carbon pricing and policies will create a better financial position to spur CCS retrofits, but will test
consumer tolerance to higher prices

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia5

1. Introduction and Purpose of Report
Introduction
Climate change risk and greenhouse gas emissions reductions are now at the top of many investors’ agendas.
The noticeable increase of net zero emissions commitments from large corporate emitters over the past
two years have signaled some progress across Asia through the mainstreaming of climate change issues. To
further support investors engaging with portfolio companies, a deeper understanding of decarbonization
pathways presented by portfolio companies is necessary for investors as for many sectors, the pathways todecarbonization are not always straightforward. Regional policies, technologies and investments available
will affect the trajectory of change. There still exists great uncertainty on the trajectory of limiting temperaturerise in line with the Paris Agreement, which requires a complex mix of policies, technologies, and investments.
For many industrial sectors with heavy carbon emissions, such as thermal power and steel, the large-scale
deployment of CCS is a key assumption underlying these sectors decarbonisation pathways, and its validity
or invalidity would have significant consequences. To bridge the emissions gap, the projected CCS capacity
requirements are normally presented in an order of magnitude greater than the present capacity.
Climate Action 100+, a global investor initiative currently with more than 615 investors, responsible for over
USD60 trillion in assets under management and engaging on climate change, have launched global sector
strategies featuring different sector papers on decarbonization expectations. The papers for the steel3 andpower4 sectors were released in Q3 and Q4 2021 respectively, with a view to map the transition to net zeroand identify priority actions required. In both papers, CCS and carbon capture, utilization and storage (CCUS)
were referenced as early-stage technologies that companies would consider as part of their decarbonization
strategy. For steel companies, any opportunities and scale of CCS and CCUS identified to be deployed for thecompany should come with specifications in as much detail as is practically possible the role expected of theemerging technology. For power companies, there are clear expectations for companies to map out a clear
decarbonization strategy that minimizes reliance on CCS and CCUS.
This report aims to triangulate the reasoning of narratives where assumptions for CCS are being deployed
to varying extents as part of corporate decarbonization strategies. By providing a sector-level analysis of
the prospect of CCS deployment, complemented with country perspectives, the report examines the costcompetitiveness of CCS and seeds questions for investors to ask of companies with regards to their approachwith CCS deployment. This is increasingly relevant as engagements in the region begin to deepen into theunderstanding of decarbonization pathways set out by companies and the role of various technologies such
as CCS. With the backdrop of increasing commitments to phase down coal as codified in the Glasgow Climate
Pact in COP26, and eventually to phase out of coal and other fossil fuels, the role of CCS in the decisive decade
to decarbonize has become a discussion of critical importance.

3

Climate Action 100+ Global Sector Strategies: Investor Interventions to Accelerate Net Zero Steel, https://www.climateaction100.
org/wp-content/uploads/2021/08/Global-Sector-Strategy-Steel-IIGCC-Aug-21.pdf

4Climate Action 100+ Global Sector Strategies Investor Interventions to Accelerate Net Zero Electric Utilities, https://www.
climateaction100.org/wp-content/uploads/2021/10/Global-Sector-Strategy-Electric-Utilities-IIGCC-Oct-21.pdf

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

6

Chapter 1: Introduction and Purpose of Report

To validate whether current capacity projections are plausible in the Asian context, especially in competition
with other low-carbon alternatives in various industries, AIGCC has commissioned Wood Mackenzie toevaluate CCS’ cost competitiveness under Wood Mackenzie’s 2°C (referred as AET-2 scenario onwards).
This is to understand if and how CCS will fit into the low-carbon future, through an evaluation of the costcompetitiveness of CCS for the power generation and steel sectors for China, India, Japan and South Korea in
2021 and 2040 respectively. Other qualitative factors which could influence the competitiveness of CCS, andother relevant conclusions on conditions required for the technology will also be covered in the report.

Exhibit XX: Illustrative of Wood Mackenzie scenario requirement of CCS capacity

Exhibit
1: Wood
Mackenzie
Scenario
Requirement of CCS Capacity (Illustrative)
WM Scenario
Requirementof CCS Capacity(Illustrative}
Gt C0₂-e per year
Estimated 2050
CCS capacity

Current view of CCS
costs & challenges inthe deployment of CCS

2021

2040 view of whether CCS canbe competitive enough to be
deployed at scale in different
sectors to reach 2050 target

2040

2050

Source: Wood Mackenzie

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 1: Introduction and Purpose of Report

Purpose of the report
This report is intended to support investors in corporate engagement but is also of value for multiple
audiences in supporting the understanding of the feasibility of large-scale CCS implementation in the powerand steel sector in key Asian markets.
Carbon capture and storage, or simply known as CCS, comprises a group of technologies that prevent carbon
dioxide (CO₂) from being released into the atmosphere, by capturing the CO₂ emitted by an industrial process(e.g., burning gas or coal for electricity, or in cement and steel production), and permanently keeping it outof the atmosphere by storing it underground. CCS can be divided into three major parts: 1) Capture andSeparation, 2) Transport, and 3) Storage and End-Uses.
CCS has been seen as a core part of most decarbonization scenarios, usually to bridge the emissions gap tothe end goal. As a result of such methodologies, projected CCS capacity requirements are often an order ofmagnitude greater than present capacity. CCS projects to date have faced significant challenges and remain apure cost in absence of policy support. The CCS value chain is complex and requires a comprehensive set ofcapabilities and technologies for safe operation.
The following are key recommendations for various stakeholders:
Investors•

Engage with companies where CCS implementation is relied upon as a solution to decarbonize business
operations rather than an option to prolong the transition away from fossil fuel, and to understand theextent of which CCS is being considered as a decarbonization strategy.

•

As part of corporate engagement, gain deeper understanding of sector relevance of CCS implementation
for the company’s operations, while ensuring that other options to reduce emissions at source are being
fully considered and that CCS is only used to neutralize residual emissions where no other technologies
exist to decarbonize.

•

Engage with policy makers to understand CCS infrastructure support, requirements, and pre-requisites
necessary to enable the deployment of CCS.

Companies•

Acknowledge that for some sectors, a credible decarbonization pathway will require the phasing out ofhigh-carbon assets, and that the implementation of CCS is only to be used to neutralize residual emissions
and as a bridging technology in a carbon-constraint world for sectors that are hard to abate.

•

Deployment of CCS should be supported by detailed disclosure of expected contribution of CCS to carbon
emissions reduction targets. Relevant feasibility studies and contingency planning in the event of shortfall
to carbon captured through CCS project deployed at asset level should be conducted to justify the scopeand scale of CCS strategy to support the company’s decarbonization.

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 1: Introduction and Purpose of Report

Context of study
The CCUS value chain is complex and requires a comprehensive set of capabilities and technologies for safe
operation. It is therefore crucial to note that this report will not cover analysis on the utilization of CO₂, basedon the assumption that current major end-use of captured CO₂ is CO₂-EOR (enhanced oil recovery). As notedfrom the IEA report, there is a limited role of CO₂ usage by industries and a large majority of captured CO₂ of
up to 95% captured in 20505 will be in geological storage.

Exhibit XX: The complexity of CCUS value chain

Requirement for CCS Capacity (Illustrative)
Exhibit
2: The complexity of CCUS value chain
Gt C0₂-e per year

CCUS Value Chain
CaptureTransport

Storage and End-Uses

33 Gt CO2 emitted globally in 2019

Storage
Project Share

STORAGE40Mt

CAPTURE/SEPARATION

40Mt

total operating
annual CO2
capture capacity

TRANSPORT

29 large-scale1 CCUS projects
currently operational, another37 are under development

30%

ENHANCED OILRECOVERY70%

ENHANCEDGEOTHERMAL

0%
Utilisation
Project Share

5000 Miles

total operating CO2
pipeline miles in
the US alone.
Transport projects
also planned inEurope, China, andrest of Asia

DEDICATED GEOLOGICALSTORAGECONVERSIONUTILIZATIONMINERALIZATION

80%

BIOLOGICAL

1%

CHEMICAL

14%

GREEN-HOUSE

1%

FOOD-PROCESSING

5%2

190 Mt(other CO2 sources)
Commercial usage
based on non-CCS
sources; 158 utilization
projects currently
operational;

NON-CONVERSION

Notes: 1. Large-scale: >0.8 Mt per year of CO2 for a coal-based power plant and >0.4 Mt per year for other emissions-intensive industrial facilities
2. CO₂ utilization is not covered in this report
Source: Wood Mackenzie, IEA, The Global CCUS Institute, Third Way

For details on Wood Mackenzie’s assessment of storage availability in China, India, Japan and Korea, pleaserefer to Appendix A: Storage availability in focus countries.

5

The CCUS chapter within the IEA NZ by 2050 Roadmap for Global Energy Sector provides detailed estimates on the marginalincrement of capture volumes over the next five years followed by more rapid expansion thereafter, with most of the CO₂
captured being stored in permanent geological storage.

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 1: Introduction and Purpose of Report

Scenarios and assumptions
Wood Mackenzie has used the AET-2 scenario as the basis of the analysis. This scenario considers significant
changes to the energy mix and demand to limit temperature rise from pre-industrial levels.
The business-as-usual scenario for Wood Mackenzie analysis is called Energy Transition Outlook (ETO), which
is based on current policies. The ETO scenario is a present-day view based on Wood Mackenzie’s models,commodity prices and cost estimates. It also reflects estimates of carbon taxes based on prevailing policies intargeted countries. The cost analysis was conducted at two points in time for the ETO scenario (2021 and 2040)
to provide a view of the current trajectory and to provide a basis of comparison against the AET-2 scenario.
For the purposes of the report, the ETO 2021 scenario is useful in mapping the current state of play, whilst the
AET-2 scenario in 2040 serves as the basis of the analysis as we continue to explore into the feasibility of CCS
deployment in industrial decarbonisation pathways.
This report aims to explore the challenges towards large-scale deployment of CCS in Asian markets, together
with how cost-competitive CCS will be in the power and steel sectors in Wood Mackenzie’s 2°C scenario. Wood
Mackenzie has yet to conduct a full quantitative analysis under a AET-1.5 scenario. However, the direction andfeasibility of CCS is unlikely to radically change in the 1.5°C pathway. Whilst this is not directly comparable tothe IEA’s Net Zero Emissions (IEA NZE) scenario nor a critique of plausibility of other scenarios, more details
are be available in Chapter 3: A qualitative comparison of conclusions if extended to a 1.5°C pathway.
For more detail on scenarios applied and the assumptions of the scenario, please refer to Appendix C:
Scenarios Used by Wood Mackenzie in the Analysis.

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10

2. Wood Mackenzie’s assessment of CCS Cost Competitiveness by
Sector and Country
Wood Mackenzie’s study relies on its tracking of CCS costs from literature review and the use of sensitivity
analyses. The cost competitiveness analysis evaluates the relative position of different options from thepresent day to a ‘transition’ state in 2040. For the purposes of the study, a common set of CCS costs based on
published literature are applied across all country comparisons with adjustments made based on countryspecific parameters such as onshore or offshore storage. A sensitivity analysis was further conducted toevaluate the potential impact of upper/lower bound assumptions on cost, carbon prices and other parameters.
Detail of the sensitivity analysis of cost competitiveness of CCS through the entire value chain in the respective
markets for power generation and steel sectors are available Appendix B-1 and B-2 respectively.

Power generation sector
Reduction in emissions associated with the generation of electricity is central to any plan to reach net zero.
The power sector is a large source of emissions today and decarbonisation is needed, not just to addressthese emissions, but to support the transition of other sectors to net zero like transport. It also plays a central
role in economic activity and everyone’s daily lives. The need for a secure supply of low-cost electricity
is a strategic imperative for most national governments and actions to decarbonize power, and can havewidespread implications. The power sector accounts for 13.5 Gt per annum, which is about 40%6, from a totalof 33.9 Gt of global CO₂ emissions in 2020.
According to Wood Mackenzie’s AET-2 scenario, the power sector is estimated to account for an approximately
10% gross reduction from baseline global CO₂ emissions (current emissions trajectory in the Energy Transition
Outlook [ETO], Wood Mackenzie’s base case scenario based on current policies) in 2040 and an approximately
16% reduction in 2050. As a result, significant reductions will be required from the industrial and power
sectors to meet 2°C targets as outlined in Exhibit 3 below.

6

Net Zero by 2050, International Energy Agency (IEA)

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

11

Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Exhibit 3: Total Global CO₂ Abatement by Sector
Total Global CO₂ Abatement by Sector% Reduction from Baseline(ETO Gross Emissions)

Mt CO₂e

2040

2050

Industrial

13.1%

22.9%

Power

10.2%

16.5%

Transport

9.6%

12.1%

Residential
Commercial
Agricultural
(RCA)

3.9%

6.6%

40,000WM ETO 2021

35,00030,00025,000WM AET-2 2021
20,00015,00010,0005,000~ 7 GT/yr emission reductions
required in Industrial sector
by 2050 in AET-2-5 GT/yr emission reductions
required in Power sector
by 2050 in AET-2~3.7 GT/yr emission reductions
required in Transport sector
by 2050 in AET-2-2 GT/yr emission reductions
required in RCA sector
by 2050 in AET-2

Reductions inclusive of CCS,
forestry credits and others

0
2000

2010

2020

2030

2040

Industrial Emissions

Power Emissions

Transport Emissions

RCA Emissions

WM ET0 2021

WM AET-2 2021

2050

Source: Wood Mackenzie;
Note: ETO = WM's Energy Transition Outlook Scenario, AET-2 = WM's Accelerated Energy Transition - 2 oC Scenario;

High level evaluation of technologies considered for the analysis
Options considered for cost competitive analysis of the power generation sector are as follow:•

Fossil fuel-based (coal and gas) option, without CCS•

Fossil fuel-based (coal and gas) option, with CCS•

Renewables based (solar and wind) option, including battery and storage options

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Exhibit
Summary
of ofpower
generation
options
evaluatedin analysis(fossil fuel-based
Exhibit4:XX:
Summary
power
generation
options
evaluatedin analysis
options)(fossil fuel-based options)
Options

Current Status• Coal still dominates ~44% share of
JKIC generation capacity in 2021
• Remains critical to grid stability asbase load

Coal Fired
Power• Advancements in supercritical &‘ultra’-supercritical plants have
improved efficiencies• Financing will be challenging given
climate change concerns

Current
Maturity

Future Trends% Capacity
Share 20401

Will decline given environmental
concerns and retirements, although
improvements are possible:• Integrated Gasification Combined
Cycle:
Convert coal to syngas prior to
combustion for greater efficiency &lower emissions

Supercritical
Coal• Oxy-fuel Combustion: Use of pure O₂ in
combustion to improve efficiency& create CO₂ rich flue gas for capture

14%

IGCC/
Oxyfuel• CCS retrofit: Retrofit of brownfield
plants to capture CO₂ pre or post
combustion• Accounts for ~8% of JKIC generation
capacity• Remains critical to grid stability as
dependable dispatch capacity

Gas FiredPower• Plant economics supported by pricesurges even at low utilisation

Market share to remain steady as
cleaner option to maintain grid stability
Potential improvements include:• Hydrogen: H₂ blending / substitution
as feed gas to reduce emissions• Allam cycle: Use of pure O₂ in
combustion price surges even at low
utilisation to generate CO₂ as working
fluid• CCS retrofit: Retrofit of brownfield
plants to capture CO₂ pre or post
combustion

Notes: (1) Capacity share In Japan, South Korea, China, India in AET-2 scenario(2) IGCC: Integrated Gasification Combined Cycle (3) NGCC: Natural Gas Combined Cycle

Concept only

NGCC

Allam Cycle

7%

H₂ blending

Pilot/Demo only

Fully commercial

Source: Wood Mackenzie

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Exhibit XX: Summary of power generation options evaluated in analysis(renewables
options)
Exhibit
5: Summaryof power generation options evaluated in analysis (renewables options)
Options

Solar

Wind

Current Status

Current
Maturity

Future Trends• Accounts for 15% of JKIC power
generation capacity• Largest capacity growth projected
given supportive policy & economics• Utility PV expected to reach parity
with coal in mid-2020s across APAC

• Rate of cost reduction will slow but
cost improvements will continue via
higher efficiencies & utilisation,
increasing unit sizes, modularisation &further economies of scale• Accounts for 12% of JKIC power
generation capacity• Sizeable capacity growth but slower
than solar given higher costs• Onshore wind expected to reachparity with coal in mid-2030s• Onshore wind capacity factors willcontinue to improve with larger
turbines & advanced dispatch models

Utility PV

Battery
Storage20%(withrenewables)

OffshoreWind• Share of capacity will rise 6x withimproving battery costs & policy
support – may be competitive vs gas
by mid-2020s• WM projections based on coupling of
Li-Ion batteries with 4-hr duration at
50% MW rating

Battery
Storage• Improvements expected to module
costs, storage efficiency & higher
capacity factors• Critical to reduce curtailment risk

Notes: Capacity share in Japan, South Korea, India and China (JKIC) in AET-2 scenario
Source: Wood Mackenzie

Concept only

34%

OnshoreWind• Offshore wind will also improve withlarger turbines & more high speed
wind sites to be developed• Storage paired with renewables
account for 2% of JKIC capacity% Capacity
Share 20401

Pilot/Demo only

12%

Fully commercial

Exhibit 6:
forforcost
competitivenessanalysisfor power
generation
Exhibit
XX:Options
Optionsconsidered
considered
cost
competitivenessanalysisfor(USD/MWh)power
generation (USD/MWh)
2021
China

India

2040
Japan

South
Korea

China

Gas (No CCS)

Gas (No CCS)

Coal (No CCS)

Coal (No CCS)

Gas + CCS

Gas + CCS

Coal + CCS

Coal + CCS

Utility Solar

Utility Solar

Onshore Wind

Onshore Wind

Offshore Wind

Offshore Wind

Utility Solar +Battery1

Utility Solar +Battery1

Onshore Wind +Battery1

Onshore Wind +Battery1

Offshore Wind +Battery1

Offshore Wind +Battery1

India

Japan

South
Korea

Note: (1) Assumes lithium-Ion battery of 4-hr duration with 50% MW rating
Source: Wood Mackenzie

For an overview of levelized cost of electricity (LCOE) competitiveness across the four countries in the power
sector, please see Exhibit 15 in page 25.
Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Findings and analysis•

In Wood Mackenzie’s 2°C scenario, CCS is expected to play a niche role in decarbonising dependable7
capacity to support grid stability. Renewables face increasing system costs8 to address grid reliability athigh penetration rates thus other dependable options are needed, while further development of battery
and storage are taking place. Cost competitiveness analysis supports a transition to renewables, but CCS
retrofits only become competitive in AET-2 to provide dependable capacity.

Exhibit 7: Power Generation Output by Type and Outlook for Power Generation Options
JKIC1 Power Generation Output by Type

Outlook for Power Generation Options• Dominant by 2050 accounting for morethan 60% of output• Low-carbon & scalable choice for new
Renewables
capacity(including storage)• Grid reliability remains a concern thus
there is a continued need for dependable
capacity% of Total
Electricity
Generated
100%
90%
80%

• Provides ~ 7% of power output by 2050
• Retains niche as dependable2
dispatchable3 capacity in lieu of otherGas-fired Power
flexible options

70%
60%
50%

• Generates 10% of power output by 2050
• Still plays key role as dependable2
capacity where renewables are not
Coal-fired Power sufficient or coal fleet is young

40%
30%
CCS is applicable only to Coal and Gas

20%
10%

Nuclear &Hydro Power

0
2021

2030

2040

Coal

Gas

Solar

Hydro

Nuclear

Others• Maintains ~20% share through to 2050
• Low-carbon & reliable but faces
environmental issues or safety concerns
hence cannot fully substitute gas & coal

2050

Wind

Other
Technologies• Other options such as biomass,
geothermal, H2• Share of total output by 2050 is small

Source: (1) Japan, South Korea, India, China(2) Dependable refers to capacity with high availability during peak demand over long duration(3) Dispatchable refers to capacity that is adjustable per grid requirements over long duration
Note: Wood Mackenzie•

Renewables will be cheapest by 2040 but fossil fuels with CCS retrofits could play a role in supporting gridreliability in AET-2•

Generation capacity in Japan, South Korea, India and China is estimated to grow by a compound annual
growth rate (CAGR) of 4.4% in AET-2 with fossil fuels declining to 21% of the capacity mix by 2040.

•

Power generation sector emissions are expected to decline sharply even without CCS as coal capacity
retires.

7

Dependable refers to capacity with high availability during peak demand over long duration

8

System costs refer to additional transmission & distribution infrastructure investments required to accommodate incremental
renewable projects. These costs are not reflected in the LCOE of individual projects but will increase with more intermittent
capacity in order to maintain the same level of reliability.

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country•

Fossil fuel power generation will decline due to costs and emissions concerns but will still play a role tomaintain grid stability.

•

Low carbon options (renewables) are well understood, highly competitive and already deployed at scalein China and India.

Future trajectory for CCS in remaining fossil fuel plants for dependable capacity
In the 2°C scenario, Wood Mackenzie estimates that CCS deployment will continue to increase from 2040 to2050 as costs improve and net zero targets necessitate retrofit of remaining fossil fuel plants.

Exhibit XX: Projected deployment for CCS in power generation post- 2040
under AET-2

Exhibit 8: Projected deployment for CCS in power generation post- 2040 under AET-2
Global Power Sector CCS Capacity1 in AET-2
Mt CO₂eCapacity

Key CCS Drivers from 2040 AET-2 Analysis
Trend

Key Conclusions in AET-2

Cost

Vs. non-CCS fossil fuels: Emerging
cost advantage due to carbon prices
to widen with CCS cost improvement

3,000

CCS deployments
continue to increase from2040 to 2050 as CCS costs
improve & net zerotargets necessitate
retrofit of remaining
fossil fuel plants

2,500

2,000

Vs. renewables: Cost gap too wide tobridge; CCS remains as backup+81%

Carbon prices unlikely to fall given
continuing focus on net zero

1,500

Policy1,000

Technology

500

National net zero targets in somecountries necessitate CCS retrofit on
remaining fossil fuel plants unlessother options are available
Long duration batteries still limited(~8 hrs) by 2050, thus CCS with fossil
fuels is unlikely to be displaced

Implications for 2050 (AET-2 Scenario):

0
2020

2025

2030

2035

2040

2045

2050

CCS Capacity in Power Gen.
Notes: (1) Please refer footnote 9Source: Wood Mackenzie

9

Trend

• If the world is to meet its 2°C target, CCS capacity is
expected to continue to grow until alternatives for
dependable capacity emerge - trajectory depends ontechnology readinessSupports CCS Growth

Reduces CCS Growth

No Change

Notes: (1) Includes significant CCS deployment for biomass power generation (BECCS) in Europe and US. BECCS, or Bioenergy with
Carbon Capture and Storage, is one of carbon removal technique where biomass (organic material) is converted into heat, electricity,or liquid or gas fuels (the bioenergy step), and the carbon emissions from this bioenergy conversion are captured and stored ingeological formations or embedded in long-lasting products (the CCS step)

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Key trends and conclusions for CCS in the Power Generation Sector as observedby Wood Mackenzie
CCS in Power Generation Sector
Implications on CCS Deployment• Global CCS capacity needs to reach ~2.8 Gt by 2050 in WM’s AET-2 scenario if targets are to be met• Achieving the required CCS capacity will be more challenging as it depends on the continued useof gas & coal power for dependable capacity, but more importantly it requires the incentivisationof CCS. Bio energy (BECCS) plants also contribute to negative emissions• The right combination of policy support & technology may put the capacity estimate within reach- but policies are not yet in place and uncertainty is high• However, CCS is still expected to play a key role as• Decarbonisation targets cannot be achieved with renewables alone• High renewables penetration reduces grid reliability & increases total system costs• Other low carbon alternatives such as hydro & nuclear cannot fully replace gas & coal

For more detail on the country-level analysis on levelized cost of electricity (LCOE) with or without CCS retrofits
for different power generation options compared against renewable energy, please refer to Appendix B-1.

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Steel sector
Steel is a metal alloy formed from iron ore, carbon, and other elements depending on the final properties
desired. Its strength and low cost make its use widespread across the construction, transport, and industrial
sectors. Steel is currently produced by two main methods. The Blast Furnace and Basic Oxygen Furnace(BF-BOF) method (comprises of approximately 70% of total production) are typically used to make virgin (or‘primary’) steel. In this process, a high grade (metallurgical) coal is used as both an energy and heat source
and as a reduction agent to remove oxygen from the iron ore.
The second method uses an Electric Arc Furnace (EAF), fed by either scrap steel or by Direct Reduced Iron
(DRI), also known as “sponge iron.” It is estimated that approximately 500 Mt of steel is recycled every year
and that 83% of the steel produced is recycled at the end of its life10. Feeding this steel “scrap” into the EAF
makes “secondary” steel, which currently accounts for 23% of the total steel produced with EAF method.
According to IEA11, steel production emitted 3.6 Gt CO₂ in 2019. The sector is currently responsible for about 8%of global final energy demand and 7% of energy sector CO₂ emissions (including process emissions). Steel’s
direct (Scope 1) emissions, largely released by the burning of coal, accounted for the largest share (62%)
followed by indirect (Scope 2) emissions (27%) from imported and onsite electricity and heat generation. The
BF-BOF process is responsible for about 85% of these emissions with the majority released during the BF
stage.
More detail about the steel industry and its climate impact are available in the Climate Action 100+ global
steel sector paper12.
Below is an illustration from Wood Mackenzie outlining the conventional iron and steel making processes.

10

Material Economics, The Circular Economy a Powerful Force for Climate Mitigation Transformative innovation for prosperous
and low-carbon industry.
https://materialeconomics.com/publications/the-circular-economy-a-powerful-force-for-climate-mitigation-1

11

IEA Energy Technology Perspectives, Iron and Steel Technology Roadmap, https://www.iea.org/reports/iron-and-steeltechnology-roadmap

12

Climate Action 100+ Global Sector Strategies: Investor Interventions to Accelerate Net Zero Steel, https://www.climateaction100.
org/wp-content/uploads/2021/08/Global-Sector-Strategy-Steel-IIGCC-Aug-21.pdf

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Exhibit XX: Introduction to conventional iron and steel making processes
Exhibit 9: Introduction to conventional iron and steel making processes
Ironmaking

Commercial
Processes
in Use

BF-BOF
Process

DRI-EAF
Process

Scrap EAF
Process

Steelmaking

Feedstock

Iron Reduction

Transformation

lronmaking requires a reducing
agent to remove oxide from ores

Blast Furnace (BF)

Basic Oxygen Furnace(BOF)

Traditional smelting
process by which oxygenis removed from iron ore
using CO as a reactant toform pig iron

Iron OreRaw iron ore

Coal & Coke

Used as fuel &reducing agent

Iron Pellet

Higher gradeiron pellets

Direct Reduction Iron(DRI)Nat Gas/Coal

Gas orcoal-based
reductantApplication of heat andreductant to convert ore
to metallic iron without
melting ore

Scrap

Recycled metal

Convert molten pig ironto steel by blowing
oxygen to reduce carbon
content of steel

CO₂ rich blast furnace gas may be
combusted in power plant & boilers

Electric Arc Furnace(EAF)

Processing

Steel Processing
Conversion of
crude steel into
finished products
via hot & coldrolling, coating,cutting, etc.

Convert scrap, DRI & pig
iron into steel by blowing
oxygen & providing heat
via electric arc

Note: Blast furnace processes where there are use for CCS retrofits are indicated as grey boxes
Source: Wood Mackenzie

High level evaluation of technologies considered for the analysis
The options considered for Wood Mackenzie’s cost competitiveness analysis for the steel sector are as follow:•

Blast furnaces options, including with CCS• Basic Oxygen Furnace (BOF)• Electric Arc Furnace (EAF)•

Coal, gas, and hydrogen with Direct Reduced Iron (DRI) options•

Scrap EAF, Biomass BF-BOF and Hydrogen BF-BOF options

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Exhibit XX: Summary of steelmaking options evaluated in the analysis

Exhibit 10: Summary of steelmaking options evaluated in the analysis
Options

Current Status

Current
Maturity% Capacity
Share 20401

Conventional

Conventional
Process:
42%

Hydrogen/BiofuelHydrogen/Biofuel:6%Gas/ Coal

Gas/Coal
Based:
11%

H2 based

H2 Based:2%

Future Trends
Share to decline given environmental
concerns but 2040 share is still sizeable
Potential improvements include:

BF-BOF
Process• Conventional BF-BOF dominates
more than 70% share of global
production due to legacy plants• Process improvements: Modifications(i.e. top gas recycling) to improve
efficiency• CCS can be retrofit to existing plants• Feedstock substitution: Low-carbon
feed-stock can partially substitute coalby 2030s• Only ~6% of current market share

DRI-EAF
Process

Scrap EAF
Process• Production is led by India which
comprises of very small coal-based
DRI-EAF mini mills• Other countries use gas-based DRI
which is less CO₂ intensive• ~21% of current market• Well established in developed
countries (Japan, S Korea) with
ample domestic scrap recycling

Share to increase given cleaner process
Potential improvements include:• Low carbon reductants: Increased
usageof gas in near term & H₂ in longterm; use of H₂ in DRI is more complex
thus will only be deployed in advanced
countries by 2040
• Expected to grow as more countries
including China increase scrap recycling

39%• Subject to availability and quality ofscrap

Notes: (1) In Japan, South Korea, China, India in AET-2 scenario
Source: Wood Mackenzie

Concept only

Pilot/Demo only

Fully commercial

The following steel production options have been selected based on the expected prevailing technologies ineach country in 2021 and 2040.

Exhibit 11:
to considered
be consideredanalysisfor
forsteelsteel(USD/ton)
Exhibit
XX:Options
Options
in inanalysis
2021
China

India

2040
Japan

South
Korea

China

BF-BOF (No CCS)

Gas (No CCS)

BF-BOF + CCS

Coal (No CCS)

BF-EAF (No CCS)

Gas + CCS

BF-EAF + CCS

Coal + CCS

Scrap EAF

Utility Solar

Biomass
BF-BOF

Onshore Wind

Green H2
BF-BOF

Offshore Wind

Coal
DRI-EAF

Utility Solar +Battery1

Natural Gas
DRI-EAF

Onshore Wind +Battery1

Green H2
DRI-EAF

Offshore Wind +Battery1

India

Japan

South
Korea

Note: DRI = Direct Reduced Iron; BOF = Blast Fumace; EAF = Electric Arc Fumace
Source: Wood Mackenzie

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Findings and analysis
There are broadly three types of processes in use today, with the traditional blast furnace process being themost carbon intensive. While conventional BF-BOF retains the largest market share in 2040, cleaner processes
and feedstock substitution will grow steadily.
It is anticipated that the market share of conventional BF-BOF will fall from approximately 80% in 2021 toapproximately 50% by 2040 as cleaner processes and feedstock substitution grow steadily. While BF-BOF
applications will decline in market share, it will not currently be feasible to fully displace BF-BOF processes
with current alternatives as BF remains the only option to convert raw iron ore of any quality into high gradesteel. It therefore remains to be the best scalable option available to create high-grade steel. In addition to
the quality of steel output, other factors such as sunk capital already invested in blast furnaces also add tothe challenge of displacing BF-BOF application. Wood Mackenzie’s assessment is that steel produced with DRI
methods are currently only competitive in mid to low grade steel and the developmental trajectory of thetechnology for high grade DRI steel is not expected until the 2040s.
As discussed in the previous section, most emissions come from the BF process and thus CCS is most applicable
to BF applications. Based on Wood Mackenzie’s analysis, CCS will be an attractive ‘lower carbon’ option for
BF applications in the AET-2 scenario as BF cannot be fully substituted in the near to mid term. Zero-carbon
feedstock options such as hydrogen will only become viable by 2040 to start decarbonising BF applications.
Global steel capacity is expected to grow steadily but the biggest change will come from a shift in production
process and feedstock. Despite global capacity growth, steel sector emissions are expected to decline byapproximately 33% from 2021 levels by 2040 in the AET-2 scenario due to growth in scrap EAF and DRI andemergence of hydrogen-based options. An additional 20% of remaining steel sector emissions in 2040 are
expected be captured via CCS in this scenario.

Exhibit XX: Steel Output by Type and Outlook for Steel Options

Exhibit 12: Steel Output by Type and Outlook for Steel Options
JKIC1 Steel Output by Option

Outlook for Iron & Steel Making Options% of Total
Crude Steel
Production

Conventional
Blast Furnace
(BF)

100%
90%
80%
70%
60%

Conventional
DirectReduced Iron
(DRI) Options

50%
40%
30%
CCS is applicable only to Conventional BF

20%

Scrap Electric
Arc Furnace(Scrap EAF)

10%
0
2021

2030

2040

Conventional BF

Conventional DRI

H₂ DRI

H₂ / Biofuel BF

Source: (1) Japan, South Korea, India, China(2) Excluding BF with low carbon feedstock
Note: Wood Mackenzie• Declines from 73% to 20%2 of output by
2050• Continued deployment expected despitehigh emissions as it is not fullyinterchangeable with DRI• Remains only option for low grade ore
inputs or for developing countries withlimited feedstock options• Increases to 10% of output by 2040 but
drops to 6% as it is displaced by H₂-DRI
towards 2050
• Gas-based options see increased
deployment to 2040 given lower emissions& energy requirements• Scrap usage increase more than double
to 52% share by 2050
• Driven by greater availability of scrap
recycling in developing countries & low
emissions/high quality output

2050
Scrap EAF

• Accounts for 22% of output by 2050
• Expected to present competitive
low-carbon option to BF & DRI facilities
Low Carbon
though significant technical & economic
Feedstocks andchallenges remain - deployment expected
Reductantsin mid-2030s to 2040s

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Exhibit 13: Steelmaking options to be applied by 2040
Main Feedstock

Conventional
BF - BOF + CCS

Iron Reduction

Transformation

Biomass / BF BOF

Coke +
HydrogenIron
Ore orPelletCoal + Coke

Coal-Fired DRI

Coal

Nat Gas -DRI EAF

Blast Furnace (BF)

Coke +
Biomass

BF-EAF + CCS

IronPelletTraditional Option

Crude
Steel

Pig IronElectric Arc Furnace(EAF)

Direct Reduction Iron
(DRI)

Crude
Steel

DRI
Scrap

Scrap

Lower Carbon Option

Basic Oxygen
Furnace (BOF)

SteelProcessing

Hydrogen

Scrap-EAFCCS

Pig Iron

Natural Gas

Hydrogen DRI EAF

Processing
Furnace
Gas

Coal + Coke

Hydrogen BF BOF

Source:Steelmaking

Ironmaking

Options toAnalyseHigh-carbon feedstock may
be substituted with lowercarbon alternatives

CCS may be applied to BF
facilities as most emissions
come from BF process

Transformation
process generates
relatively little CO2

Processing is not
CO2 intensive &is not considered

Wood Mackenzie

CCS will need to compete against low carbon feedstock options and scrap by 2040. CCS deployments continue
to increase from 2040 as more BFs retrofit for CCS. Deployment peaks in the mid- 2040s as low-carbon
feedstocks become competitive.

Exhibit 14: Projected deployment for CCS in steel post-2040 under AET-2
Global Steel Sector CCS Capacity in AET-2

Key CCS Drivers from 2040 AET-2 Analysis

600

500

Mt CO₂e Capacity

400

Trend

CCS deployments continue
to increase from 2040 as
more BFs retrofit for CCS.
Deployment peaks in mid 2040s as low-carbon options
become competitive

+16%

Cost

Vs. scrap: Scrap usage will grow but isstill limited by availability and quality
Vs. low carbon feedstock : Highly
dependent on H₂ availability & price
Carbon prices unlikely to fall given
continuing focus on net zero

Policy200

100

Technology
2025

2030

2035

2040

2045

2050

CCS Capacity in SteelSource:Trend

Vs. conventional BF/DRI: Marginaladvantage for CCS from carbon price

300

0
2020

Key Conclusions in AET-2

Wood Mackenzie

National net zero targets in somecountries necessitate CCS retrofit,
shift to low-carbon feedstock or
shutdown of remaining mills
H₂ -BF/DRI becomes commercial inadvanced countries by 2040 and willcompete as H₂ costs drop

Implications for 2050 (AET-2 Scenario):• Policy will continue to drive CCS retrofits but capacity is
expected to peak as low-carbon feedstocks become increasinglycompetitive towards 2050
Supports CCS Growth

Reduces CCS Growth

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

No Change

22Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Key trends and conclusions for CCS in the Steel Sector as observed by Wood Mackenzie

CCS in Steel Sector
Implications on CCS Deployment• Global CCS capacity needs to reach ~500 Mt by 2050 in WM’s AET-2 scenario if targets are to be met• Achieving required CCS capacity is more probable as there are no viable low-carbon alternatives inthe short-to-mid term
• High emission blast furnaces cannot be fully substituted by 2050 and will require CCS to decarbonise• However CCS deployment also requires sufficient policy support to incentivise CCS retrofits andavoid carbon leakage• Zero-carbon feedstock such as H₂ are expected to become viable by 2040s and can potentiallydisplace CCS in the long run - but outlook is still uncertain
Source: Wood Mackenzie

Country level summary - further analysis by AIGCC
Wood Mackenzie’s analysis in power generation and steel covered the following four markets: China, India,
Japan, and South Korea13 , all major GHG emitters in Asia and users of fossil fuel-based power generationand steel producers in the region. For the power sector, market-level analysis was conducted to compare thelevelized cost of electricity in the 2021 ETO scenario with that of 2040 in the AET-2 scenario. For the steel sector,
market-level analysis was conducted to compare cost competitiveness of various steel production options in
the 2021 ETO scenario with that of 2040 in the AET-2 scenario. Detailed cost competitive comparisons for the
power and steel sector are available in Appendix B1 and B2 respectively.
For an overview of LCOE competitiveness across the four countries in the power sector, please see Exhibit 15.

13

Although Indonesia is also a major GHG emitter in Asia, it is not one of major steel producing country. Thus, in order toprovide fair comparison with other focus countries for steel sector, Indonesia is not covered in this report.

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Exhibit 15: Overview of LCOE Results by Country, USD/MWh Real 2021
Overview of LCOE Results by Country, USD/MWh Real 2021
Options

2021

20401

2021

20401

2021

20401

2021

20401

Key Observations on Cost Competitiveness

Coal

49

134

66

129

72

147

78

154

• Coal & gas LCOE become uncompetitive torenewables despite lower commodity prices

Gas

95

140

110

144

104

144

102

125

• However, a sizeable proportion (>20%) of
capacity will remain in place given continuing
need for dependable dispatchable power

Coal + CCS

112

92

138

112

161

128

165

133

• CCS retrofits become economically viable forgas & coal plants to meet this nicheGas + CCS

131

127

158

142

161

142

154

123

• Carbon pricing & subsidy will play a majorrole in enabling CCS viability

Solar

50

25

38

19

135

68

84

42

• Renewables develop sizeable LCOE
advantage as cost improvements continue

Wind 2

56

21

56

21

175

67

169

64

Renewables+ Storage 3

111

37

100

33

268

88

190

62

Decrease by 2040
Note:
Source:Increase by 2040

Cost Competitive vs Hydrocarbon (avg)• Deployment is dependent on proximity to
demand, infrastructure, land availability, etc.
• Grid volatility & overall system costs may
increase with higher renewables penetration
thus dependable capacity is still important• Battery storage costs improve but long
duration storage not yet practical by 2040

(1) In AET- 2 (2 OC Scenario) only; (2) Refers to Onshore Wind for China & India, Offshore Wind for Japan & South Korea ; (3) Average of Wind + Battery and Solar + Battery Options
Wood Mackenzie

For an overview of steel production costs and its competitiveness across the four countries in the steel sector,
please see Exhibit 16.

Exhibit 16: Overview of steel production cost results by country,
USD/ton Crude Steel Production Real 2021

Options

2021

20401

2021

20401

2021

20401

2021

20401

BF-BOF

510

558

372

492

537

600

525

599

BF-EAF

547

635

447

591

BF-BOF +
CCS

604

526

491

487

629

578

616

577

BF-EAF +
CCS

641

600

564

586

Coal – DRI EAF

319

530

Gas – DRI EAF

374

414

H₂– DRI EAF

657

495

Scrap EAF

513

409

428

479

Biomass
BF-BOF

572

507

450

466

H₂- BFBOF

585

494

559

514

Note:
Source:(1) In AET-2 (2 OC Scenario) only
Wood Mackenzie

N/A

Key Observations on Cost Competitiveness• BFs are still required due to its versatility• Conventional BF becomes uncompetitive
due to higher feedstock cost & carbon price• CCS options become competitive vsconventional BF options in all countries• Although CCS is not zero-carbon, it remains
the main option until H₂ options emerge• H₂ DRI is technologically challenging hence
deployment will be later in India, but will becompetitive in other markets by 2040
• Dependent on availability of green H₂
919

637

864

564

597

692

559

641

768

604

689

495

• Low carbon technologies likely to becompetitive vs conventional steel and CCS• Scrap steel is commercial but subject toavailability – high quality scrap costs will rise
• H₂-based BF options will be attractive under
projected prices but outlook still uncertain

Increase by 2040

Cost Competitive vs Conventionals (avg )Decrease by 2040

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

China
China is highly dependent on coal to generate electricity and is the world’s largest steel producer. According
to Wood Mackenzie’s assessment of the current state, utility PV and coal is the most competitive for power
generation in 2021. In the current scenario, gas with CCS and coal with CCS are on the highest end of thespectrum and are uncompetitive on a cost basis compared to renewables in China. However, there continues
to be a role for fossil fuel capacity due to intermittency challenges. Similarly for steel, traditional options suchas scrap EAF or BF-BOF are the most competitive.
However, projecting on to 2040 using the AET-2 scenario, renewables with the advantage of improvements inshort term battery storage will have clear LCOE competitiveness over CCS supported options for gas and coalin the power sector, even with the support of stronger carbon price. CCS supported options for fossil fuels
are only marginally increasing LCOE cost competitiveness of fossil fuel energy in China through savings incarbon tax. By 2040, in the steel sector, Scrap EAF is expected to remain the lowest cost option by 2040. Highcarbon prices will support the development of H₂-BOF options. CCS retrofits for BF options are viable but havedecreased in relative cost positioning with respect to 2040 ETO.

India
India is highly dependent on coal for power generation and is the third largest steel producer in the world. At
COP26, the country has committed to increasing non-fossil fuel installed electricity capacity to 500GW by 2030
indicating a trajectory to transition into low carbon energy. Based on Wood Mackenzie’s analysis for power
generation in 2021, renewables such as onshore wind and utility PV already have the lowest LCOE, and fossil
fuel-based power generation coupled with CCS option is currently uncompetitive in terms of cost in India.
In the steel sector, coal-based DRI-EAF is currently the most cost competitive while CCS retrofits are not yet
competitive.
By 2040 in the AET-2 scenario, renewables continue to maintain competitiveness and the reduction in capitalfor storage technologies have increased competitiveness and the reduction in capital for storage technologies
have increased competitiveness of onshore wind and solar with storage retrofits. Gas & coal LCOE continue
to increase especially with the introduction of a carbon tax. CCS retrofits will be marginally more competitive
compared to conventional gas & coal but will still be significantly more expensive than renewables. In thesteel sector, a carbon tax will change the competitiveness landscape and enable natural gas DRI-EAF andBiomass BF-BOF to become the most competitive. CCS retrofits for BF-BOF will also be competitive due tosavings from the carbon tax vs traditional BF options.
In the AET-2 scenario, a high carbon tax landscape in India would make CCS a viable option in steel whereother options continue to be in close competition, but it will remain uncompetitive in the power sector.

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Chapter 2: Wood Mackenzie’s assessment of CCS Cost Competitiveness by Sector and Country

Japan
Japan is reliant on coal in the power generation sector, especially since the Fukushima nuclear incident in2011, where strong opposition against nuclear power narrows down Japan’s options in its energy mix. In Wood
Mackenzie’s analysis, the 2021 ETO scenario indicate gas and coal to be the most cost competitive. For the
steel sector, conventional BF-BOF and scrap EAF remains the most cost competitive option in 2021. Due toprimary options for steel being not fully interchangeable, BF-BOF is considered necessary in the long term forthe production of high quality products.
By 2040 in the AET-2 scenario, renewables and storage continue to be at the more competitive end of thespectrum enjoying lower LCOE compared to other options. High carbon prices support CCS retrofit, but CCS
options remain more expensive than renewables and thus will only fulfil the role of providing dependable
capacity. In the steel sector, BF-BOF with CCS retrofits will have better cost competitiveness but hydrogen
options are also closely competitive. Momentum from the development of hydrogen as the zero-carbon
feedstock and as a decarbonisation solution for the steel industry will continue to compete with CCS
deployment.

South Korea
South Korea has approved a plan to phase out all coal power by 2050 to support the newly proposed NDCtargets and is amongst the few Asian countries that have made the most significant upgrade of their targets
in the lead up to COP26. With the backdrop of a nationally approved roadmap for 2050 carbon neutrality,
utility PV is nearing LCOE parity with coal in 2021, while wind and CCS is at the high end of the cost spectrum
rendering those option uncompetitive. In the steel sector, conventional BF and scrap EAF are the mostcompetitive, while the CCS retrofitted BF-BOF option is positioned to be more competitive than options
deploying hydrogen feedstock.
By 2040 in the AET-2 scenario, renewables and short duration storage are significantly cheaper compared tofossil fuels with CCS retrofits. Offshore wind with storage will also see significant improvement in relative LCOE
positioning with respect to a 2040 ETO scenario owing to decreased capital costs. In the steel sector, hydrogenand CCS-based BF options become more competitive than conventional BF, whilst hydrogen options gain themost significant relative improvement in cost positioning with respect to a 2040 ETO scenario.
In the AET-2 scenario, there is limited competitiveness for CCS deployment in power generation and adecarbonization roadmap complemented with strong supporting carbon policies will result in increased
competitiveness of hydrogen options and to some extent CCS-based BF options.
Detailed cost competitive comparisons for the power and steel sector are available in Appendix B1 and B2
respectively.

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3. A qualitative comparison of conclusions if extended to a
1.5°C pathway
In July 2021, the International Energy Agency published its first comprehensive energy roadmap, Net Zero by2050 (NZE), outlining an energy pathway requiring unprecedented transformation to bring global energyrelated CO₂ emissions to net zero by 2050 and to allow the world to limit global temperature rise to 1.5°C.
Whilst Wood Mackenzie’s analysis based on an in-house 2°C scenario will have variations in the pace andscale of the transformation, the underlying conclusions are broadly consistent. The relevant qualitative
differences of Wood Mackenzie’s AET-2 scenario with IEA’s NZE are as follows:
Different end goals: NZE represents a much more rapid transition to net zero than AET-2:•• NZE reflects a 1.5°C pathway14 to reach global net-zero by 2050
• AET-2 reflects a 2°C pathway, which assumes developed countries reach net zero by 2050 and global net
zero is reached by 2070•

Pace of change: NZE assumes faster deployment of CCS as well as nascent technologies such as hydrogenand Direct Air Capture (DAC)15 thus changing the trajectory of the transition•

CCS deployment: NZE projects up to 7.6Gt of CCS/DAC capacity by 2050 while AET-2 projects only up to 4.6Gt
by 2050

Exhibit 17: Key Uncertainties for the CCS Cost Competitiveness under Wood Mackenzie’s
1.5 °C Pathway
Requirement for Global CCS Capacity (Illustrative)
Gt CO2-e per year

1.5 °Crequirement

Uncertainties for CCS
Trajectory in AET-1.5
Speed of Near Term CCS Adoption

WM’s AET-1.5 pathway will require
even more CCS capacity than AET-2
to capture residual emissions &achieve net zero earlier

How fast would CCS ramp up in the nearterm with the right policy support?
How fast will CCS costs decrease andimprove CCS competitiveness?

However, several key factors caninfluence the trajectory of the global
requirement for CCS

2 °C
requirement

Timing of Low Carbon Substitution

How soon will low carbon options becomecommercially viable?
How fast can they become competitive vs
CCS and displace need for CCS at scale?

Key uncertainty around timing & speed of CCS
adoption vs substitution by low carbon technologies

Resilience of CCS Retrofits

Will businesses which have already retrofit
with CCS be willing to write off sunk costs?

Long Term Need for Negative Emissions

2020

2030

2040

2050

What is the long term need for negativeemissions such as DAC and BECCS?

Source: Wood Mackenzie

14

AET-1.5 scenario by Wood Mackenzie noted throughout the report is aligned with IEA NZE 2050, thus aligned with 1.5°C
pathway.

15

Direct air capture (DAC) technologies extract CO₂ directly from the atmosphere. According to IEA, two technology approaches
are being used to capture CO₂ from the air currently: liquid and solid DAC.

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Chapter 3: A qualitative comparison of conclusions if extended to a 1.5°C pathway

Implications for power generation sector
The IEA’s NZE envisions faster decarbonization of the power sector supported by rapid innovation anddeployment of hydrogen. It also has a smaller role for fossil fuels. CCS requirement for the power sector in
AET-2 is higher due to several factors:•

Higher global electricity demand by 2050 in AET-2•

Lower proportion of generation output from hydro, nuclear, hydrogen blending by 2050•

More aggressive carbon prices in NZE drives faster phase-out of fossil fuels

Exhibit 18: High Level Comparison of IEA’s NZE scenario conclusions to Wood
Mackenzie’s analysis for power sector

CCS in Power Generation Sector• Faster transition with additional options for dependable capacity: Reniewables still expected tolead sector decarbonisation, with nuclear, hydro & bioenergy playing a sizeable role in providing
dependable capacity• Gas & coal diminished but in a similar role: Thermal power maintains role for dependable capacity
but gas & coal will also be displaced by biomass, ammonia & battery storage; thus only ~1.4Gt of
CCS1 is expected in power by 2050.
• Conclusions are consistent: Gas & coal power still needed for dependable capacity, but accelerated
transition leads to faster demand shift & new technology which reduce but does not eliminate
deployment of CCS in power
Notes: (1) IEA projection includes CCS for power from fossil fuels as well as for power from bioenergy
Source: Wood Mackenzie

Key differences in assumptions in the power sector for demand, technology, policies and emissions between
the WM AET-2 and IEA NZE scenarios are outlined below. In both scenarios, wind and solar energy penetration
are expected to be at comparable levels by 2050. However, in a 1.5°C pathway, other zero carbon technologies
will assume a stronger role with more aggressive carbon pricing accelerating the phasing out of fossil fuels.

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Chapter 3: A qualitative comparison of conclusions if extended to a 1.5°C pathway

Comparisonof AET -of2 AET-2
Assumptions
to IEAtoNZE
for Power
Generation
Exhibit
19: Comparison
Assumptions
IEAAssumptions
NZE Assumptions
for Power
Generation
WM AET-2 Assumptions
Electricity
Mix

Larger electricity demand &share met by fossil fuels§ ~70,000 TWh demand by 2050
§ Low carbon1 has 81% share in 2050
but wind/PV is comparable with NZEHydrogen has limited power role

Technology§ H₂ production drives power demand
but plays small role in power gen.
via blending in gas turbines

Relatively moderate policies
PolicyEmissions§ Global carbon price is set at level toincentives CCS in hard-to-abate
sectors (~USD110/t)

Not fully decarbonised§ Advanced economies decarbonisedby 2050, global net zero by 2070

IEA NZE Assumptions
Bullish nuclear & hydro growth§ ~60,000 TWh demand by 2050
§ Hydro & nuclear capacity doubles by
2050 – much faster than AET-2§ Low carbon has 90% share in 2050

Hydrogen plays large role
§ Hydrogen co-firing will address 2.5%of power output by 2050
§ 100% blending of H₂/ammonia in
unabated coal plants by 2050

Aggressive carbon policies§ Carbon price rises to USD250/t,
pushing phase out of fossil fuels§ Further support for grid reliability &nuclear life extensions/additions

Decarbonised by 2040
§ Power sector decarbonised by 2035
for advanced economies, by 2040
for others

Source: Wood Mackenzie, IEA NZE Scenario;
Note: (1) Low carbon includes wind, PV, nuclear, hydro & other low carbon options

Implications for steel sector
IEA’s NZE relies more heavily on the use of CCS and slightly less on scrap EAF in the steel sector to meet alower carbon budget. CCS requirement in steel under AET-2 is lower than NZE due to:•Higher use of Scrap EAF in AET-2 (as % of market share)•

Less aggressive decarbonization trajectory in AET-2•

Lower carbon prices in AET-2, which resulted in lower CCS capture rates

In both scenarios, CCS and hydrogen-based options are needed.

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Chapter 3: A qualitative comparison of conclusions if extended to a 1.5°C pathway

Exhibit 20 : High-level comparison of IEA’s NZE scenario conclusions to Wood
Mackenzie’s analysis for steel sector
CCS in Steel Sector• Aggressive decarbonisation with similar options: High carbon price (up to $250/tCO₂ by 2050) spur
greater CCS deployment and aggressive substitution of coal by EAF, electrolysis and H₂-based
options by 2050 (up to ~70% of demand)• Coal use not fully substituted: Coal still provides ~30% of steel energy demand by 2050 & is mostly
abated by CCS with 670Gt of capacity by 2050
• Conclusions are consistent: Policy, subsidy & global trade agreements are necessary to allow sector
to decarbonise. Coal is not fully substitutable thus CCS is required to abate emissions in order tomeet emissions targets
Source: Wood MacKenzie

Key differences in assumptions in the steel sector for demand, technology, policies and emissions between the
WM AET-2 and IEA NZE scenarios are outlined below. In both scenarios, the pace of emergence of hydrogenbased options are critically important. Both scenarios will also require international policies in place toestablish a level playing field for export.

Exhibit 21: Comparison of AET-2 Assumptions to IEA NZE Assumptions for SteelWM AET-2 Assumptions
Greater use of scrap EAF
SectorDemandTechnology

PolicyEmissions§ Higher steel demand growth met bycomparatively larger proportion of
scrap EAF (~52%) by 2050
§ Low carbon 1 share is similar (~22%)

IEA NZE Assumptions
Greater reliance on CCUS
§ Lower use of scrap EAF (~46%)
results in higher reliance on CCUS
with conventional options by 2050

Slower emergence of hydrogen

Faster emergence of technology§ H2 - based BF & DRI become viable inmid-2030s in advanced economies
but accelerates from 2040 -50§ Electrolysis is not viable before 2050

§ H2 -based options begin deployment
in mid - 2020s§ Iron ore electrolysis emerges as
option in addition to hydrogen

Moderate carbon prices

Aggressive carbon prices§ Relatively moderate carbon price(USD110/t) support CCS retrofits§ Similar policies will be required tosupport trade of low -carbon exports§ Very high carbon prices (USD250/t)
drive higher CCS capture rates§ International policies required toestablish level playing field for export

Not fully decarbonised

Nearly decarbonised by 2050

§ 46% of gross residual emissions arecaptured via CCS§ Net emissions fall to 0.8 Gt by 2050

§ Emissions fall to 0.2 Gt by 2050
§ ~90% of non low carbon production
is equipped with CCS

Note: (1) Low carbon includes wind, PV, nuclear, hydro & other low carbon options
Source: Wood Mackenzie, IEA NZE Scenario

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4. AIGCC’s additional assessment of challenges andother considerations to large-scale deployment of CCS
Other than the economic competitiveness analysis provided by Wood Mackenzie mentioned in previous
chapters, AIGCC’s own research further examines additional obstacles to the large-scale implementation of
CCS.

Significant environmental risks
The most substantial risk associated with CCS is the leakage of CO₂ from storage sites. The Intergovernmental
Panel on Climate Change (IPCC) predicts with 90-99% certainty that well-designed reservoirs will hold 99% of
CO₂ injected for 100 years. However, there are many technological unknowns such that the risks of leakages
cannot be externalized nor discounted16. There are two types of CO₂ leakages: abrupt leakages that could
result from naturally occurring events or equipment fault; and gradual leakages that could occur because ofincorrect site selection and inadequate preparation.
In particular, there are concerns over the common choice of depleted oil and gas fields as storage sites as
the area could potentially contain geological fracture and risk of natural fissures, hence more comprehensive
geological site selection or seabed screening is needed before captured CO₂ can be safely stored. For example,
in 2012, scientists found a fracture close to Statoil’s North Sea Sleipner CCS site. Although Sleipner CCS projectis a saline aquifer, it is located on an oil and gas production area where natural fissures pose risk for CO₂
leakage.
Seepage of CO₂ from long-term CCS projects may lead to delayed global warming unless this seepage can betightly controlled. A Nature Geoscience report concluded that unless the seepage rate of sequestered CO₂ canbe held to 1% every 1,000 years, the overall global temperature increase could still reach dangerous levels
that cause some of the worst sea-level rise and ocean acidification projections.
Furthermore, CO₂ leaks can result in the following hazards:•

Human health: CO₂ is benign and non-toxic at low concentrations, but at high concentrations and in
confined space it can cause asphyxiation. CO₂ is denser than air, so when released, it tends to accumulate
in shallow depressions, a risk that increases in confined spaces close to the ground.

•Contaminate groundwater: According to this report by Environmental Management, the primary concernof leakage of CO₂ into a groundwater resource is that the increased acidity of these fluids could increase
the absorption of commonly occurring minerals such as lead and arsenic, which could exceed maximum
concentration limits.

16

Estimating geological CO₂ storage security to deliver on climate mitigation (12 June 2018) https://www.nature.com/articles/
s41467-018-04423-1#Abs1

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Chapter 4: AIGCC’s additional assessment of challenges and other considerations to large-scale deployment of CCS•

Damage terrestrial and marine ecosystems: A Environmental and Experimental Botany report concluded
that crop root and shoot growth and crop yield were significantly lower in cases of elevated soil CO₂,
demonstrating the severity of damage to terrestrial vegetation from CO₂ leakage. This Marine Environmental
Research report concluded that seawater acidification induced by CO₂ emissions was responsible for theloss of diversity of bacterial organisms, reducing community stability and harming ecosystem resilience.

•

Induce seismicity: A National Academy of Sciences report concluded that earthquakes can be triggeredby the injection of large volumes of CO₂ if the local geology is not suitable for injection. Local geologicalcharacteristics need to be appraised carefully.

The widespread deployment of CCS may also lead to water stress as:•

CCS technologies typically involve large water consumption during their energy-intensive capture process17.
Most CCS projects currently in operations use absorption technologies, with common absorbents consistingof aqueous bases that contain amine groups that bind CO₂. The circulation of large quantities of solvents
results in significant water loss by evaporation, leading to a maximum water consumption increase of 90%.

•

A Nature Sustainability report concluded that certain geographies lack sufficient water resources to meet
the additional water demands of CCS technologies, with 43% of global coal-fired power plants experiencing
water scarcity for at least one month a year and 32% experiencing scarcity for five or more months per
years. Further research to develop new absorption technology, such as membrane separation that may
require less water, is needed to minimize this risk.

17

The nexus of water and CCS: A regional carbon sequestration partnership perspective.
https://cyberleninka.org/article/n/965321.pdf

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Chapter 4: AIGCC’s additional assessment of challenges and other considerations to large-scale deployment of CCS

Exhibit XX: Comparison of water consumption per net power
using
recirculation
Exhibitwet
22: Comparisonof towers
water consumption per net power using wet recirculation tower
Water Consumption,
gal/MWh net
1000

Cooling Tower
FGD1

800

WGS2
Gasiﬁer

600

400

200

0

No CC

CC

Subcritical PC

No CC

CC

Supercritical PC

No CC

CC

No CC

CC

IGCC(slury-fed)

IGCC(dry-fed)

No CC

CC
NGCC

Total

517

985

452

844

309

452

295

475

192

338

Cooling Tower

449

884

392

759

290

355

243

355

192

338

FGD

68

101

59

86
52

WGS
Gasiﬁer

19

45

49
53

71

Source: Gerdes K, Nichols C. Water requirements for existing and emerging fossil fuel-based plant technologies. Ofﬁce of Systems, Analyses and Planning,
National Energy Technology Laboratory, DOE/NETL-402/020108 (2009)
Notes: [1] FGD: ﬂue gas desulfurization[2] WGS: water-gas shift reactor

Based on an assessment by the Global CCS Institute on geological studies done to date on CCS storage
potential, the focus countries in this report (Japan, South Korea, India and China) have conducted somestudies into geological storage potential but all will require further assessment to improve confidence in thecertainty of storage potential estimates (please refer to Appendix A).
The cost of ramifications for the above risks outlined could far outweigh the benefits of GHG emissions abatedor other relevant benefits from an economic perspective given the potential compounded effect in terms ofpotential impact. Even if there is a low likelihood of occurrence, a substantial leakage in a worst-case scenario
could have an impact that is outsized in terms of affecting climate change or neighboring communities andwould therefore warrant a comprehensive and detailed assessment of the impact of all risks by various multidisciplinary expertise.

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Chapter 4: AIGCC’s additional assessment of challenges and other considerations to large-scale deployment of CCS

Technical challenges facing CCS
A key challenge facing CCS is to reduce costs so that it is competitive with other low carbon technologies.
However, we believe this understates the significant technical barriers that large-scale projects would
encounter, including:•

Scalability – equipment needed for CCS projects differ widely depending on the source of CO₂. For
example, the gas composition in gas separation plants have different properties from the exhaust gases at
a power plant. Gas produced from a deep-sea gas field arrives at the surface under high pressure and low
temperature, so the separation of CO₂ from natural gas needs to be tailored for this. The complexity andcustomization of the required equipment make it difficult to quickly scale up.

•

Suitability – According to the Society of Petroleum Engineers, a major difference between CO₂ injection
into underground saline aquifers compared to depleted oil and gas fields is that the former requires
injected CO₂ to be accommodated by compression of the formation and formation water. The resultant
increase in pressure limits the injection rate and total amounts that can be stored. Appraisal of the suitable
CO₂ injection into the subsurface and significant research and development in subsurface modelling are
required.

•Transport - the scaling up of CCS is likely to require the construction of a pipeline network to transport CO₂
as the most efficient mode of CO₂ transport. Such a network would require multiple CO₂ streams which arecharacterized by varying impurity levels and handled by individual operators to be linked to the pipeline,
posing additional corrosion and safety challenges, as detailed in this Renewable and Sustainable Energy
Review. Identifying the appropriate size of the pipelines required for a CO₂ transportation network is achallenging task that has to balance a wide range of factors whilst ensuring assets are not under or overutilized.

Case study: Chevron Gorgon LNG CCS in Western Australia
The Gorgon LNG project is one of the world’s largest LNG projects with a production of 2.3 billion cubicfeet per day (Bcf/D) and a lifespan of 40 years, located off the northwest coast of Western Australia.
This project includes a commercial-scale CCS project which is:• Designed to store 3.4 – 4 Mtpa of CO₂ and a total of 120 Mt over the project’s lifetime equivalent toat least 80% of reservoir emissions as part of the project’s environmental approval.
• CO₂ will be captured directly from the gas field, liquefied and transported by a 7 km pipeline to be
injected into the Dupuy saline aquifer, located 2.3km beneath Barrow Island.
• Originally estimated to cost a total of AUD 2 billion (about USD 1.5 billion), of which AUD 60 million(about USD 45 million) was funded by the Australian government and includes AUD 150 million(about USD 112 million) of storage appraisal costs and AUD 415 million (about USD 311 million) for
the development of six CO₂ injection compressor trains.

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Chapter 4: AIGCC’s additional assessment of challenges and other considerations to large-scale deployment of CCS

In January 2021, independent energy news outlet, Boiling Cold, published reports obtained under
Freedom of Information laws revealing that:• Chevron and its main partners, Shell and ExxonMobil, had spent a total of AUD 3.1 billion (about
USD 2 billion) to mid-2020, a significant escalation in costs.
• Chevron had started injecting CO₂ underground in August 2019 despite its pressure management
system not working and that the regulator had issued multiple extensions for Chevron to keep
operating despite this issue.
• CO₂ injection started more than three years after Gorgon first produced LNG because the water in
the CO₂ corroded pipework, resulting in an additional 7 Mt of CO₂ vented into the atmosphere.
This project highlights that burying up to 4 million tons per annum (Mtpa) of CO₂, in this case, isa complex task. Here, CO₂ is injected into a layer of sandstone 400 m thick and more than 2000 m
underground, and about 4km away, water is pumped to the surface from the same layer to makeroom for the CO₂. This water is then pumped into a different layer of rock above the CO₂. If the water
is not moved, the pressure required to inject the CO₂ will rise, reducing the amount that can be stored
and eventually risk fracturing the rock around the CO₂ injection wells.

Exhibit xx: Gorgon CO₂ pressure management system
Exhibit 23: Gorgon CO₂ pressure management system
Pressure
management wells

CO₂ injection
wells

W

E
Barrow GroupP Electric submersible pump
Dupuy Formation

Source: Chevron

Source: Chevron

The performance of the Gorgon CCS project is to be assessed on a five-year average and if targets are
not met, approval conditions state that Chevron will be obliged to offset the emissions. This review
is due later in 2021. The difficulties faced by this project could therefore also result in substantial
financial penalties for the project sponsors.

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Chapter 4: AIGCC’s additional assessment of challenges and other considerations to large-scale deployment of CCS

In July 2021, Chevron confirmed that it was not going to meet its promised injection rates, with the
project only capturing a fraction of the carbon dioxide expected during its first five years of operation,
where only 5 million tons of CO₂ had been injected since the August 2019 start-up18. Chevron later
announced that it will have to resort to purchase of offsets to make up for the deficit over a five-year
period to July 2021 and to ensure that the facility meets regulatory requirements19.

CCS projects are difficult to finance commercially
To date, there are no examples of commercial banks financing CCS projects outside of the USA due to theconsiderable uncertainties facing the financial viability of CCS projects including:•Difficulty in assessing earnings since projects outside the US do not generate any apparent revenue stream.

•

High historical failure rate, for example, under the European Energy Programme for Recovery (EEPR) thatran from 2008-2017, six CCS projects that were sponsored at a cost of EUR 424 million were either cancelled
or wound up, without ever having become operational, except for a pilot plant in Spain, which did notdemonstrate the use of CCS on a commercial scale.

The deployment of CCS in the USA has been relatively more successful, with the US hosting 10 of the 19
operating CCS plants globally. We attribute this to the introduction of CCS-specific values for carbon througha tax credit known as the 45Q, which was significantly expanded in 2019 and provides up to USD35/t for CO₂
used for EOR and USD50/t for CO₂ stored in dedicated geologic storage20.
This allowed CCS projects in the US such as Petra Nova and Lake Charles Methanol to secure financing basedon revenues that are reliant on the sale and use of CO₂ for EOR and tax credits. We note that there remains
a degree of commercial risk, as we detail in our case study on the recent closure of the Petra Nova CCS plant
due to the fall in oil prices.
Other recent examples of the reliance on government support can be seen in:•

the Norwegian government’s decision in 2020 to fund the scale-up of a CCS project for EUR 2 billion or 80%of the total costs of the project, which would transport liquified CO₂ from a cement factory and waste-toenergy power plant to undersea storage carried out by the Northern Lights CCS project.

•

the Dutch government’s grant of EUR 2 billion in May 2021 to a consortium including Shell and ExxonMobil
to capture CO₂ from the Port of Rotterdam and store it in empty Dutch gas fields in the North Sea.

•

the UK government’s launch in May 2021 of a plan to develop industrial CCUS clusters and projects which
will be supported from the GBP 1 billion Carbon Capture and Storage Infrastructure Fund, which will
primarily support capital expenditure on transport and storage networks and industrial CCS.

18

https://www.upstreamonline.com/energy-transition/blow-for-ccs-chevrons-giant-carbon-capture-project-falling-short-oftargets/2-1-1041696

19https://www.energyvoice.com/renewables-energy-transition/ccs/363627/

20

Meeting The Dual Challenge: A Roadmap to At-Scale Deployment of Carbon Capture, Use, and Storage, Chapter 3 – Policy,
Regulatory, and Legal Enablers, https://dualchallenge.npc.org/documents/CCUS-Chap_3-030521.pdf?a=1624655845

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

36

Chapter 4: AIGCC’s additional assessment of challenges and other considerations to large-scale deployment of CCS

Case study: Petra Nova CCS project in Texas
Petra Nova was a joint venture CCS project between NRG Energy and JX Nippon which received a
USD190 million grant from the US government and started up in 2017. The plant was designed to:• capture 90% of CO₂ from a 240MW slipstream of flue gas and sequester 1.4 Mtpa of CO₂ at NRG
Energy’s Unit 8 Parish Generating Station.
• utilize a proven process by Mitsubishi Heavy Industries and Kansai Electric Power that uses a highperformance solvent for CO₂ absorption and desorption.
• compress and transport the CO₂ through a 129 km pipeline to the West Ranch oil field for enhanced
oil recovery (EOR) and ultimately sequestered.
The Petro Nova plant was idled on 1 May 2020 and subsequently mothballed in late July 2020, which
NRG Energy attributed to a collapse in oil prices and made the project uneconomical. During theperiod of its operation, we note that:• according to the Department of Energy (DOE), the facility missed its carbon capture targets byabout 17%, succeeding in capturing 3.8Mt of CO₂ during its first three years, short of the 4.6Mt that
had been projected.
• utilization rates at the Unit 8 Parish Generating Station were similar to utilization rates before the
CCS project coming online, resulting in no benefit to utilization rates at the retrofitted plant.
We believe the failure of this project highlights the manifold technical and economic difficulties
that CCS projects face, while a lack of disclosure on this project leaves many unanswered questions,primarily the reasons for the technical difficulties and the actual cost of capture and sequestration.

Societal opposition is likely
There is a lack of publicly available research about community attitudes towards CCS projects in Asia due to alack of large-scale projects in Asia thus far. Nevertheless, we believe that inferences can be drawn about CCS
infrastructure from experience with similar energy infrastructure, which we believe points towards potential
societal opposition stemming from:•

Significant plant site expansion – Power plants are likely to require significantly larger space toaccommodate the additional process facilities, and a study from the Imperial College London suggeststhat depending on the technology employed, the site area required for CCS equipment could approach
the size of the power generating plant itself. This is likely to cause difficulties for existing plants that do
not have space available and would entail expansion into adjacent communities, which is likely to facecommunity resistance.

•

Presence of hazardous material – Certain CCS technologies may use or produce hazardous materials inlarge quantities. For example, a study in the International Journal of Greenhouse Gas Control concludes
that amine-based CCS technologies generate wastes in chemical reclaimers that are toxic, including
chemicals such as vanadium, antimony and cyanide.

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Chapter 4: AIGCC’s additional assessment of challenges and other considerations to large-scale deployment of CCS•

Hazardous chemical transportation – Large quantities of ammonia, hydrogen sulfide and other chemicalsolvents are needed for CCS in power plants. These chemicals have never been used in power plants at
this scale and would require the construction of chemical delivery pipelines that would require more
space while increasing the risks to communities from potential spills.

•

CO₂ pipeline siting – The scaling up of a CO₂ pipeline network, as discussed above, is also likely to facepublic opposition. A study in Energy Policy highlights the main concerns as being: 1) safe operation of
the pipeline; 2) risks to people, livestock and vegetation from leakage; 3) lack of operational pipelines todemonstrate the technology; and 5) disruption to local communities during pipeline construction.

The effects on communities and the environment could potentially impact those living in proximity tothe project sites and therefore would be experiencing the impacts of CCS projects the most directly. The
climate justice perspective of how projects are being planned is therefore a critically important additional
consideration.

Competitive deployment of resources by governments
The pace and magnitude of carbon policies rely on governments’ commitment to achieving net zero targets
despite socio-economic impacts and cost incurred. In particular, where countries and regions experience
power shortages as a result of increasingly higher coal prices, the competitive deployment of resources into
ensuring a smooth transition into net zero will affect the overall level of support for CCS deployment. Policies
in the forms of subsidies, taxation and caps will incentivize different technologies and outcomes.
Additionally, the different levels of international cooperation to address climate change and its impact tocommodity prices, capital investments, sharing of capabilities and export policies may have an indirect impact
on the level of attractiveness of large-scale CCS deployment.

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38

5. Conclusion•

This report shows that there are a wide range of factors affecting the cost effectiveness of large-scale
deployment of CCS technologies. The attractiveness of CCS deployment decreases where there is theavailability of other low carbon alternatives such as the case in the power sector where renewableenergy technologies are well developed.

•

On the contrary, where other low carbon options are unclear, as in the case for hard-to-abate sectors suchas steel, the attractiveness of CCS deployment increases as more aggressive carbon pricing and relevant
policies come in place.

•In the steel sector, competition from other emerging technologies such as hydrogen as the zero-carbon
feedstock, and the cost of fossil fuel-powered feedstocks will influence the level of attractiveness of
CCS deployment. In traditional blast furnace operations, hydrogen cannot eliminate all carbon emissions,due to the presence of process emissions from steelmaking. This to say the attractiveness of CCS will also
depend on what share of emissions are under the scope of abatement. Although the study does not coversectors beyond power and steel, similar conclusions could be drawn for other hard to abate sectors suchas cement.

•

It is therefore critically important for investors to carefully evaluate the companies with decarbonization
strategies using CCS as the strategy to transition and request as much detail as practically possible on theplanned role of CCS. Proper due diligence is needed as each CCS project tends to have specific technicalcharacteristics with different type of risk.

•

For example, with some cases of CCS deployment in the power sector, investors should evaluate theprospect of the deployment despite challenges with cost competitiveness, as CCS may be deployed tofurther prolong the use of fossil fuels.

•

Understanding the barriers and incentives to the deployment of CCS in respective markets and competition
from other technologies is critically important for a comprehensive view of the cost effectiveness of CCS
deployment.

•

CCS technology and economics, including issues of leakage and the associated liability, continue to bea prominent issue. The technological unknowns of the risks of leakages cannot be discounted, not only
from the perspective of cost-effectiveness, but also for concerns with the impact of leakage to humanhealth, groundwater contamination, damage on terrestrial and marine ecosystems and associated induced
seismic activity, all of which will further exacerbate other environmental problems.

•

Carbon pricing and policies will create a ‘level playing field’ to spur CCS retrofits and will test consumer
tolerance to higher prices. Government’s ability to develop well-defined regulations for storage andinfrastructure requirements will also have a role to play in the attractiveness of deployment of CCS.
It is therefore important to understand that there are geopolitical considerations at play impacting
international cooperation and coordination of investments supportive of CCS.

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

39

Appendices
Appendix A: Storage availability in focus countries
According to Global CCS Institute, global storage potential is currently estimated at 6,700 – 29,500 Gt, withfeasibility dependent on further evaluation of site geology. To date, 260 Mt of CO₂ has been permanently
stored. Even with high estimated levels of national or regional capacity, project feasibility and economic
viability are both entirely site-specific, depending on seismic activity, soil composition and a variety of otherkey geological factors.

Exhibit
24: Potential
CO₂ Storage
Potential
by Region
CO₂ Capacity)
Potential
CO2 Storage
Potential
by Region(Gt CO2(GtCapacity)

200(North Sea)
200 - 430

1,120 - 4,130

300

100
1- 5

2,000 - 21,000

5 - 25
5 - 30100

47 - 63

2 -228

140
9

12

23

140
7

2,000
150

220 - 410

16

High confidence
Medium confidence
Low confidence
Very low confidence
Source:Wood Mackenzie, Global CCS InstituteCO₂ is transported and stored as a supercritical fluid due to desirable properties. It transforms from gas tosupercritical fluid at high temperature (>31.1°̊C) and pressure (>72.9 atm). At depths of more than 80 m, CO₂
natural temperature and pressure exceed a critical point and allow denser storage as fluid. Greater depths
do not mean greater storage capacity, because fluid density stays constant. Wood Mackenzie also stated thatmultiple options exist for CO₂ storage with depleted oil and gas reservoirs, with saline aquifers having thehighest potential and are the most attractive geological storage options for permanence and scale. Saline
aquifers offer the greatest storage potential, but depleted oil and gas reservoirs benefit from better geologicalunderstanding, associated infrastructure, and cost synergies.

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Appendix A: Storage availability in focus countries

Exhibit 25: Introduction to CO₂ Storage Options
Oil and Gas
Reservoirs

Methods

Challenges

Benefits• Residual trapping : injectedsupercritical CO2 displaces
existing fluid in porous rock;small pockets of residual CO 2
trapped between rock grains• Most common application is
EOR, where CO2 is injected toenhance hydrocarbon
production by pushing fluids
towards producing wells• EOR and CCUS areperceived as poor
solutions for
decarbonization as
they extend the use offossil fuels• EOR project
economics are
sensitive to oil price• Most CCUS projects
today are linked to EOR• Proven technology• EOR adds economic
value via increased
recovery of oil & gas• Attracts capital to CCUS
& allows greater learning• Required capabilities
overlap with oil & gas

SalineReservoirs• Solubility / Mineral trapping :Portion of injected CO2
dissolves into the brine water
within the porous rockformation.
• Some CO 2 combines withavailable hydrogen atoms toform HCO3 , which can reactwith the minerals in the rock toform solid carbonate minerals

Other
Options• Unmineable coal seams• Basalt• No additional revenue
streams• Few developed
projects thus limiting• Large potential for CO2
operational knowledge
storagebase• Requires additionalsurface infrastructuredevelopment

Source: Wood Mackenzie, DOE

Exhibit 26: Comparison of different types of geological storage and the importance toclimate goals

Projected lead time1

Cost advantages

Additional revenue streams(e.g. through oil and gas
production)

Technology Maturity

Proximity to CO2 emissions
sources

Synergies with existing
infrastructure

Geographic distribution

Depth of geologicalunderstanding

Volumetric Potential

Percentage of CO 2 Storage

Importance to climate goals

Depleted oil and gas
reservoirs
Saline aquifers
Enhanced Oil Recovery(EOR)
Unmineable coal /Organic shale
BasaltNote:(1) Fuller Harvey Balls denote shorter lead times
Source: Wood Mackenzie

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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Result by Country –Power Generation Sector
Wood Mackenzie has developed three scenarios to test the impact of key variables on CCS cost competitiveness.
Wood Mackenzie has developed two separate sensitivity cases to test the potential impact of flexing key costand pricing parameters. The sensitivity cases are a combination of key input parameters including policy(carbon price), technology (cost of CCS and alternatives), and market (commodity prices) which can influence
the relative cost competitiveness of various options. To simplify the overall analysis, Wood Mackenzie has
defined two cases representing an ‘optimistic’ case and ‘constrained’ case for CCS competitiveness to represent
the upper and lower bounds of how much these parameters can change cost competitiveness in aggregate.
•‘Optimistic’ Case represents a set of parameters which are most favorable for the competitiveness of CCS.
This case applies a higher carbon price (consistent with a 1.5 °C pathway), lower estimates for CCS costs
and higher costs for non-CCS alternatives and commodity prices.

•‘Constrained’ Case represents a set of parameters which are least favorable for the competitiveness of CCS.
This case applies a lower carbon price (consistent with current projections), higher estimates for CCS costs
and lower costs for non-CCS alternatives and commodity prices.

China
For China, Wood Mackenzie found that renewables are at parity with coal as the lowest LCOE option in 2021,
while CCS is much more expensive.

Exhibit 27: 2021 ETO China LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

200

O&M

Fuel

OthersCarbon Tax

CCS

180

Increasing LCOE
Competitiveness

160
140
120
100
80

60
40
20
0

Gas + CCSWind Onshore+ Storage

Coal + CCS

GasSolar + Storage

Wind Onshore

Utility PV

Coal

Note: Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Note:

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating

Source: Wood
Wood Mackenzie
Source:Mackenzie

But in 2040, the findings will change. In the ETO scenario, renewables will have a clear advantage while carbon
prices are insufficient to spur CCS retrofit. In the AET-2 scenario, renewables and storage extend advantage
while high carbon prices support CCS retrofit.

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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country – Power Generation Sector

Exhibit 28: 2040 ETO China LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

200

O&M

Fuel

OthersCarbon Tax

CCS

180

Increasing LCOE
Competitiveness

160
140
120
100
80

60
40
20
0

Gas + CCS

Gas

Coal + CCS

CoalWind Onshore+ Storage

Note:
Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Source: Wood Mackenzie

Solar + Storage

Relative LCOE positioning
with respect to 2021 ETO

IncreaseWind Onshore

Utility PV

Maintain

Decrease

Exhibit 29: 2040 AET-2 China LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

200

O&M

Fuel

OthersCarbon Tax

CCS

180

Increasing LCOE
Competitiveness

160
140
120
100
80

60
40
20
0

Note:
Source:Gas

Coal

Gas + CCS

Coal + CCS

Storage assumes lithium-ion battery of 4 -hour duration at 50% of MW rating
Wood Mackenzie

Wind Onshore+ Storage

Solar + Storage

Relative LCOE positioning
with respect to 2040 ETO

Increase

Utility PV

MaintainWind Onshore

Decrease

For LCOE competitiveness sensitivity analysis result, renewables’ substantial cost advantage remains even in
the most optimistic scenario.

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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country – Power Generation Sector

2040 AET-2
LCOE
CompetitivenessSensitivity
Analysis
Exhibit
30:China
2040
AET-2
China LCOE
CompetitivenessSensitivity Analysis
USD/MWh
Real 2021
Base AET -2

200

Optimistic

Constrained

180

Increasing LCOE
Competitiveness

160
140
120
100
80
60
40
20
0

Gas

Coal

Gas + CCS

Coal + CCS

Wind Onshore+ Storage

Solar + Storage

Utility PV

Wind Onshore

Source: Wood Mackenzie

India
Contrary to China, Wood Mackenzie found that renewables already have the lowest LCOE in India.

Exhibit 31: 2021 ETO India LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

200

O&M

Fuel

OthersCarbon Tax

CCS

180

Increasing LCOE
Competitiveness

160
140
120
100
80

60
40
20
0

Note:
Source:Gas + CCS

Coal + CCS

Wind Onshore+ Storage

Gas

Solar + Storage

Coal

Wind Onshore

Utility PV

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Wood Mackenzie

Renewables will continue to be most competitive in the 2040 ETO scenario in India, with renewables plus
storage also becoming competitive and CCS remaining uneconomic without carbon pricing. In the AET-2
scenario, CCS options become viable with a high carbon tax, while renewables LCOE will fall even further.

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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country – Power Generation Sector

Exhibit 32: 2040 ETO India LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

200

O&M

Fuel

OthersCarbon Tax

CCS

180

Increasing LCOE
Competitiveness

160
140
120
100
80

60
40
20
0

Note:
Source:Gas + CCS

Gas

Coal + CCS

Wind Onshore+ Storage

Storage assumes lithium-ion battery of 4- hour duration at 50% of MW rating
Wood Mackenzie

Coal

Solar + Storage

Relative LCOE positioning
with respect to 2021 ETO

IncreaseWind Onshore

Utility PV

Maintain

Decrease

Exhibit 33: 2040 AET-2 India LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

200

O&M

Fuel

OthersCarbon Tax

CCS

180

Increasing LCOE
Competitiveness

160
140
120
100
80

60
40
20
0

Note:
Source:Gas

Gas + CCS

Coal

Coal + CCS

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Wood Mackenzie

Wind Onshore+ Storage

Solar + Storage

Relative LCOE positioning
with respect to 2040 ETO

IncreaseWind Onshore

Utility PV

Maintain

Decrease

For the LCOE competitiveness sensitivity analysis, results indicate similar sustained cost advantage forrenewables across both optimistic and constrained sensitivity cases.

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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country – Power Generation Sector

Exhibit 34: 2040 AET-2 India LCOE Competitiveness Sensitivity Analysis
USD/MWh
Real 2021
Base AET-2

200

Optimistic

Constrained

180

Increasing LCOE
Competitiveness

160
140
120
100
80
60
40
20
0

Source:Gas

Gas + CCS

Coal

Coal + CCS

Wind Onshore+ Storage

Solar + Storage

Wind Onshore

Utility PV

Wood Mackenzie

Japan
In Japan, contrary to more competitive renewables in China and India, Wood Mackenzie found that coal andgas are the lowest cost options in 2021, while renewables still have a sizeable gap in LCOE.

Exhibit 35: 2021 ETO Japan LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

330

O&M

Fuel

OthersCarbon Tax

CCS

300

Increasing LCOE
Competitiveness

270
240
210
180
150
120
90
60
30
0

Note:
Source:Wind Offshore+ Storage

Solar + Storage

Wind Offshore

Gas + CCS

Coal + CCS

Utility PV

Gas

Coal

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Wood Mackenzie

By 2040 in the ETO scenario, utility PV has the lowest LCOE. CCS options are still uneconomical at a USD 40/t
carbon price. In the AET-2 scenario, renewables and storage have the lowest LCOE and high carbon prices will
support CCS deployment.
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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country – Power Generation Sector

Exhibit 36: 2040 ETO Japan LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

300

O&M

Fuel

OthersCarbon Tax

CCS

270

Increasing LCOE
Competitiveness

240
210
180
150
120
90
60
30
0

Note:
Source:Wind Offshore+ Storage

Gas + CCS

Coal + CCS

Solar + Storage

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Wood Mackenzie

GasWind Offshore

Relative LCOE positioning
with respect to 2021 ETO

Increase

Coal

Utility PV

Maintain

Decrease

Exhibit 37: 2040 AET-2 Japan LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

300

O&M

Fuel

OthersCarbon Tax

CCS

270

Increasing LCOE
Competitiveness

240
210
180
150
120
90
60
30
0

Note:
Source:Coal

Gas

Gas + CCS

Coal + CCS

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Wood Mackenzie

Wind Offshore+ Storage

Solar + Storage

Relative LCOE positioning
with respect to 2040 ETO

IncreaseWind Offshore

Utility PV

Maintain

Decrease

For the LCOE competitiveness sensitivity analysis, given high renewables with storage costs, coal with CCS
costs could be competitive if CCS project characteristics are very favorable.

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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country – Power Generation Sector

Exhibit 38: 2040 AET-2 Japan LCOE Competitiveness Sensitivity Analysis
USD/MWh
Real 2021
Base AET-2

300

Optimistic

Constrained

270

Increasing LCOE
Competitiveness

240
210
180
150
120
90
60
30
0

Source:Coal

Gas

Gas + CCS

Coal + CCS

Wind Offshore+ Storage

Solar + Storage

Wind Offshore

Utility PV

Wood Mackenzie

South Korea
Similar to Japan, PV is nearing LCOE parity with coal, but wind and CCS remains a long way off in South Korea
in 2021.

Exhibit 39: 2021 ETO South Korea LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

300

O&M

Fuel

OthersCarbon Tax

CCS

270

Increasing LCOE
Competitiveness

240
210
180
150
120

90
60
30
0

Note:
Source:Wind Offshore+ Storage

Wind Offshore

Coal + CCS

Gas + CCS

Solar + Storage

Gas

Utility PV

Coal

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Wood Mackenzie

By 2040 in the ETO scenario, PV and storage have a clear LCOE advantage. A USD 37/t carbon price (cheaper
than Japan) is insufficient for CCS. In the AET-2 scenario, renewable and storage LCOE falls further while highcarbon prices support CCS deployment.

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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country – Power Generation Sector

Exhibit 40: 2040 ETO South Korea LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

300

O&M

Fuel

OthersCarbon Tax

CCS

270

Increasing LCOE
Competitiveness

240
210
180
150
120

90
60
30
0

Note:
Source:Wind Offshore+ Storage

Coal + CCS

Gas + CCS

Gas

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Wood Mackenzie

CoalWind Offshore

Relative LCOE positioning
with respect to 2021 ETO

Increase

Solar + Storage

Utility PV

Maintain

Decrease

Exhibit 41: 2040 AET-2 South Korea LCOE Competitiveness Analysis
USD/MWh
Real 2021
Capital

300

O&M

Fuel

OthersCarbon Tax

CCS

270

Increasing LCOE
Competitiveness

240
210
180
150
120

90
60
30
0

Note:
Source:Coal

Coal + CCS

Gas

Gas + CCS

Storage assumes lithium-ion battery of 4-hour duration at 50% of MW rating
Wood Mackenzie

Wind Offshore+ Storage

Relative LCOE positioning
with respect to 2040 ETO

Wind Offshore

Increase

Solar + Storage

Utility PV

Maintain

Decrease

For the LCOE competitiveness sensitivity analysis, the inherent cost gap between CCS and renewables remains
even under an optimistic scenario for CCS costs.

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Appendix B-1: Wood Mackenzie’s LCOE Competitiveness Analysis Results by Country – Power Generation Sector

Exhibit 42: 2040 AET-2 South Korea LCOE Competitiveness Sensitivity Analysis
USD/MWh
Real 2021
Base AET-2

300

Optimistic

Constrained

270

Increasing LCOE
Competitiveness

240
210
180
150
120
90
60
30
0

Source:Coal

Coal + CCS

Gas

Gas + CCSWind Offshore+ Storage

Wind Offshore

Solar + Storage

Utility PV

Wood Mackenzie

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector

China
For China, Wood Mackenzie found that traditional BF-BOF and scrap EAF options are the most competitive in 2021.

Exhibit 43: 2021 ETO China Steel Production Competitiveness Analysis
USD/ton csp
Real 2021
Capital800

O&M

Feedstock

OthersCarbon Tax

CCS
Increasing Cost
Competitiveness

700
600
500
400

300
200
100
0

H₂-DRI-EAF

BF -EAF + CCS

BF - BOF + CCS

H₂- BF -BOF

Biomass - BF -BOF

BF - EAF

Scrap EAF

BF -BOF

Source: Wood Mackenzie

Source: Wood Mackenzie

By 2040 in the ETO scenario, scrap EAF has a clear cost advantage, but carbon prices are insufficient to spur
CCS or hydrogen use in BF-BOF applications. Traditional BF-BOF is expected to remain in use as scrap EAF isconstrained by scrap availability. In the AET-2 scenario, scrap EAF remains the lowest cost option, but highcarbon prices mean CCS and Hydrogen-BF options are viable.

Exhibit 44: 2040 ETO China Steel Production Competitiveness Analysis
USD/ton csp
Real 2021
Capital800

O&M

Feedstock

OthersCarbon Tax

CCS
Increasing Cost
Competitiveness

700
600
500
400

300
200
100
0

Source:H₂- DRI- EAF

Wood Mackenzie

H₂- BF-BOF

BF -EAF + CCS

BF - BOF + CCS

BF -EAF

Biomass - BF-BOF

Relative Cost positioning
with respect to 2021 ETO

Increase

BF - BOF

Maintain

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

Scrap EAF

Decrease

51

Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector

Exhibit 45: 2040 AET-2 China Steel Production Competitiveness Analysis
USD/ton csp
Real 2021
Capital800

O&M

Feedstock

OthersCarbon Tax

CCS
Increasing Cost
Competitiveness

700
600
500
400

300
200
100
0

Source:BF- EAF

BF - EAF + CCS

BF -BOFBF - BOF + CCS

Biomass - BF -BOF

Relative Cost positioning
with respect to 2040 ETO

Wood Mackenzie

H₂ - DRI -EAF

Increase

H₂-BF-BOF

Scrap EAF

Maintain

Decrease

For the cost competitiveness sensitivity analysis, scrap EAF maintains an advantage across both pricesensitivity cases, while all other options are in close competition.

2040 AET 46:-2 China
Steel
Production
Competitiveness
Analysis
Exhibit2040
AET-2
ChinaCost
Steel
ProductionSensitivity
Cost CompetitivenessSensitivity Analysis
USD/ton csp
Real 2021
Base AET-2

800

Optimistic

Constrained
Increasing Cost
Competitiveness

700
600
500
400
300
200
100
0

Source:BF-EAF

BF - EAF + CCS

BF - BOF

BF - BOF + CCS

Biomass - BF - BOF

H₂ - DRI-EAF

H₂ -BF-BOF

Scrap EAF

Wood Mackenzie

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Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector

India
Slightly different from China, Wood Mackenzie found that conventional BF and DRI options are the clear lowcost options for India in 2021.

Exhibit 47: 2021 ETO India Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital900

O&M

Feedstock

OthersCarbon Tax

CCS

800

Increasing Cost
Competitiveness

700
600
500

400
300
200
100
0

BF - EAF + CCS

H₂-BF-BOF

BF-BOF + CCS

Biomass- BF-BOF

BF-EAF

Scrap EAFNat Gas DRI- EAF

BF-BOF

Coal -DRI-EAF

Source: Wood Mackenzie
Source:Wood Mackenzie

By 2040 in the ETO scenario, the status quo largely remains as traditional BF and DRI remain the mostcompetitive given a lack of carbon pricing. In the AET-2 scenario, a high carbon tax changes the landscapesignificantly with biomass and CCS based BF becoming competitive.

Exhibit 48 : 2040 ETO India Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital900

O&M

Feedstock

OthersCarbon Tax

CCS

800

Increasing Cost
Competitiveness

700
600
500

400
300
200
100
0

Source:H₂- BF - BOF

Wood Mackenzie

BF-EAF + CCS

BF-BOF + CCS

BF-EAF

Biomass- BF-BOF

Scrap EAFNat Gas DRI -EAF

BF-BOF

Coal - DRI-EAF

Relative Cost positioning
with respect to 2021 ETO

Increase

Maintain

Decrease

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector

Exhibit 49: 2040 AET-2 India Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital900

O&M

Feedstock

OthersCarbon Tax

CCS

800

Increasing Cost
Competitiveness

700
600
500

400
300
200
100
0

Source:BF-EAFBF-EAF + CCS

Coal - DRI-EAF

H₂-BF-BOF

BF-BOF

BF-BOF + CCS

Relative Cost positioning
with respect to 2040 ETO

Wood Mackenzie

Scrap EAF

Biomass- BF-BOF

Increase

MaintainNat Gas DRI -EAF

Decrease

For the cost competitiveness sensitivity analysis, in an optimistic case using lower CCS cost estimates andhigher carbon prices, BF-BOF with CCS could potentially be even more cost competitive against some low
carbon options such as scrap and H₂-BF-BOF.

Exhibit 50: 2040 AET-2 India Steel Production Cost Competitiveness Sensitivity Analysis
USD/ton csp
Real 2021
Base AET-2

900

Optimistic

Constrained

800

Increasing Cost
Competitiveness

700
600
500
400

300
200
100
0

Source:BF-EAFBF-EAF + CCS

Coal -DRI-EAF

H2 - BF-BOF

BF-BOF

BF-BOF + CCS

Scrap EAF

Biomass- BF-BOF

Nat Gas DRI-EAF

Wood Mackenzie

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Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector

Japan
In Japan, Wood Mackenzie found that conventional BF-BOF and scrap EAF are the most competitive optionsin 2021.

Exhibit 51: 2021 ETO Japan Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital

1,000

O&M

Feedstock

OthersCarbon Tax

CCS

900

Increasing Cost
Competitiveness

800
700
600
500
400

300
200
100
0

H₂-DRI-EAF

H₂- BF-BOF

BF-BOF + CCS

Scrap EAF

BF-BOF

Source: Wood Mackenzie

Source:
Wood
By
2040
inMackenzie
the ETO scenario, conventional BF-BOF remains the lowest cost option, while a carbon price is not
sufficient to support low-carbon options including CCS. In the AET-2 scenario, a high carbon price supports the
deployment of CCS-based BF-BOF with hydrogen-based options also becoming competitive.

Exhibit 52: 2040 ETO Japan Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital

1,000

O&M

Feedstock

OthersCarbon Tax

CCS

900

Increasing Cost
Competitiveness

800
700
600
500
400

300
200
100
0

Source:H₂ -DRI-EAF

Wood Mackenzie

H₂ - BF -BOF

Scrap EAF

Relative Cost positioning
with respect to 2021 ETO

BF -BOF + CCS

Increase

BF-BOF

Maintain

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

Decrease

55

Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector

Exhibit 53: 2040 AET-2 Japan Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital

1,000

O&M

Feedstock

OthersCarbon Tax

CCS

900

Increasing Cost
Competitiveness

800
700
600
500
400

300
200
100
0

Source:Scrap EAF

H₂ -DRI-EAF

H₂ -BF-BOF

BF-BOF

Relative Cost positioning
with respect to 2040 ETO

Wood Mackenzie

Increase

BF-BOF + CCS

Maintain

Decrease

For the cost competitiveness sensitivity analysis, CCS becomes the most competitive option in the optimistic
case, while traditional BF-BOF remains the most competitive in the constrained case.

Exhibit 54: 2040 AET-2 Japan Steel Production Cost Competitiveness Sensitivity Analysis
USD/ton csp
Real 2021
Base AET-2

1,000

Optimistic

Constrained

900

Increasing Cost
Competitiveness

800
700
600
500
400
300
200
100
0

Source:Scrap EAF

H₂-DRI-EAF

H₂-BF-BOF

BF-BOF

BF - BOF + CCS

Wood Mackenzie

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Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector

South Korea
Similar to Japan, conventional BF and scrap EAF are the most competitive options in 2021.

Exhibit 55: 2021 ETO South Korea Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital

1,000

O&M

Feedstock

OthersCarbon Tax

CCS

900

Increasing Cost
Competitiveness

800
700
600
500
400

300
200
100
0

H₂ -DRI-EAF

H₂ -BF-BOF

BF-BOF + CCS

Scrap EAF

BF-BOF

Source: Wood Mackenzie

Source: Wood Mackenzie
By
2040 in the ETO scenario, conventional BF remains the lowest cost option while scrap costs increase, andcarbon prices are insufficient for CCS. In the AET-2 scenario, hydrogen and CCS-based BF options become
closely competitive with conventional BF.

Exhibit 56: 2040 ETO South Korea Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital

1,000

O&M

Feedstock

OthersCarbon Tax

CCS

900

Increasing Cost
Competitiveness

800
700
600
500
400

300
200
100
0

Source:H₂ - DRI-EAF

Wood Mackenzie

H₂ -BF-BOF

Scrap EAF

Relative Cost positioning
with respect to 2021 ETO

BF-BOF

BF-BOF + CCS

Increase

Maintain

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

Decrease

57

Appendix B-2: Wood Mackenzie’s Steel Production Cost Comparison by Country – Steel Sector

Exhibit 57: 2040 AET-2 South Korea Steel Production Cost Competitiveness Analysis
USD/ton csp
Real 2021
Capital

1,000

O&M

Feedstock

OthersCarbon Tax

CCS

900

Increasing Cost
Competitiveness

800
700
600
500
400

300
200
100
0

Source:Scrap EAF

BF-BOF

BF-BOF + CCS

H₂-DRI-EAF

Relative Cost positioning
with respect to 2040 ETO

Wood Mackenzie

Increase

H₂ -BF-BOF

Maintain

Decrease

For the cost competitiveness sensitivity analysis, low-carbon options extend their advantage over conventional
options in the optimistic case, with hydrogen alternatives as the most competitive. In the constrained case,traditional BF-BOF will compete against hydrogen-based options.

Exhibit 58: 2040 AET-2 South Korea Steel Production Cost Competitiveness Sensitivity Analysis
USD/ton csp
Real 2021
Base AET-2

1,000

Optimistic

Constrained

900

Increasing Cost
Competitiveness

800
700
600
500
400
300
200
100
0

Source:Scrap EAF

BF-BOF

BF -BOF + CCS

H₂-DRI-EAF

H₂- BF-BOF

Wood Mackenzie

Carbon Capture and Storage in the decisive decade for decarbonisation - The case for Asia

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Appendix C

Appendix C: Scenarios Used by Wood Mackenzie in the Analysis
Introduction to Wood Mackenzie’s Energy Transition Scenarios (from Energy Transition Service)

Base Case (3 oC Scenario)(Energy Transition Outlook)• Base Case view across all commodity
and technology business units

Likely outcome
based oncurrent trends• Incorporates evolution of current
policies and technology advancement
playing out in the future• Broadly consistent with a 3 ⁰C global
warming view for 2021 (limiting global
temperature rise to 3⁰C)

2 oC Scenario(Accelerated Energy Transition – 2)
• A scenario developed to show whatneeds to happen to achieve a 2 oC
scenario.
• Cumulative emissions trajectory aligns
with the upper temperature limit statedin the Paris Agreement• Assumes a rapid decarbonisation of
power and other sectors to reduce
emissions

Accelerating
trends inbase case outlook
to meet
2 oC target• Assumes developed countries reach net
zero by 2050 & global net zero in 2070
Estimated 2050 CCS Capacity: ~0.86 Gt

Note:

Required 2050 CCS Capacity: ~4 Gt

Based on H₂ 2020 scenario dataset

Source: Wood Mackenzie
Appendix
C Energy Transition Service

Boundaries of Wood Mackenzie’s Analysis
What this study is

What this study is NOT• Provides a top-down evaluation & indicative trendsof how CCS costs compare to other options in key
CO₂ emitting sectors• Not meant to be a bottom-up evaluation of CCS
economics nor a quantification of CCS deployment• Focuses mainly on the cost perspective and the rolethat CCS could play in each sector as a result• Highlights implications on the conditions thatwould be required to support CCS deployment given
WM’s findings on cost
• Based on & supported by assumptions & inputs
from Wood Mackenzie’s 2 oC scenario• Not meant to be a comprehensive evaluation of all
external factors which could influence CCS
deployment• Not meant to conclude on whether CCS is plausible
or how much would be deployed• Is not directly comparable to 1.5 oC scenarios suchas IEA’s NZE nor meant to be a critique of theplausibility of various scenarios

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Appendix C: Scenarios Used by Wood Mackenzie in the Analysis

Key assumptions regarding indicative CCS costs that being used by Wood Mackenzie in their analysis:

Capture:•Reflects cost of capture excluding transport and storage•

Input data based on consistent technology assumption – i.e., no mixing of SCPC/Oxy fuel/IGCC,
etc.

•

Future costs derived using published estimates for “next of a kind” or historic learning curves

Transport:•

Costs assumed to be constant given mature tech.

•

Onshore/offshore costs applied based on potential storage reservoir location•

Pipeline sharing assumed, normalised to 250 km length

Storage:•

Costs assumed to be constant given mature technology.

•

Onshore/offshore costs applied based on potential storage reservoir location•

Assumes saline aquifers given greater availability

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