THE GLOBAL STATUS OF CCS: 2011 - Global CCS Institute

THE GLOBAL STATUS
OF CCS: 2011

THE GLOBAL STATUS
OF CCS: 2011

© Global CCS Institute, 2011
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CONTENTS
Preface
Abbreviations
Executive summary
v
vi
vii
1 Introduction 2
1.1 Scope of this report 2
1.2 The role of CCS in CO 2
emission reductions 3
1.3 What is CCS 5
2 Projects 8
2.1 Key project developments 8
2.2 Detailed project breakdown 15
3 Technology 34
3.1 Capture 34
3.2 Transport 47
3.3 Storage and use 54
3.4 Technology costs and challenges 65
4 Policy, legal and stakeholder issues 70
4.1 Policy, legal and regulatory context 71
4.2 Status of funding support 89
4.3 Public engagement 95
5 Making the Business Case for CCS 100
Appendices
Appendix A Overview of data analysis process 106
Appendix B Asset Lifecycle Model 107
Appendix C Large-scale integrated projects 109
Appendix D Reconciliation of project changes since 2010 Status Report 122
Appendix E Policy context 125
Appendix F Public engagement quality factors 138
References 139
Tables
Table 1 LSIPs in the Operate and Execute stages 11
Table 2 CCS project submissions for NER300 to the European Commission 21
Table 3 LSIPs by region, by technology and by industry 29
Table 4 Technology Readiness Levels (TRLs) 36
Table 5 Transport cost estimates for CCS demonstration projects, 2.5Mtpa 54
Table 6 Transport cost estimates for large-scale networks of 20Mtpa 54
Table 7 ZEP cost estimates for storage 58
Table 8 Summary of recently completed CCS design cost studies 66
Table 9 CCS cost estimates from ZEP 67
Table 10 Country status of emission reduction aspirations 72
Table 11 International groupings for countries 80
Table 12 CCS policy landscape 81
iii

Table 13 Project survey responses to policy question 87
Table 14 Project survey responses to legal and regulatory question 88
Table 15 Public engagement resources 97
Table 16 Key business features of LSIPS in operation or construction 101
Table 17 Comparison of risks between a new build CCS demonstration power project
with a conventional power project 102
Table C‐1 2011 large-scale integrated CCS projects 110
Table D‐1 Reconciliation of LSIPs with 2010 Status Report 122
Table E‐1 Project responses to questions on high level policy, legal and regulatory issues 136
Figures
Figure 1 Global CO 2
atmospheric concentrations and temperature 3
Figure 2 Global CO 2
emissions and GHG emission reductions 4
Figure 3 Avoided costs of CO 2
by technology in the power sector 5
Figure 4 Geological storage options for CO 2
6
Figure 5 LSIPs by asset lifecycle and region/country 9
Figure 6 LSIPs by asset lifecycle and year 9
Figure 7 Timing of FID of LSIPs in the Define and Evaluate stages 10
Figure 8 Changes in LSIPs from 2010 to 2011 13
Figure 9 LSIPs by region and year 15
Figure 10 Volume of CO 2
potentially stored by region or country 15
Figure 11 World map of LSIPs by industry 16
Figure 12 North American map of LSIPs by industry 18
Figure 13 European map of LSIPs by industry 20
Figure 14 LSIPs by industry sector and year 24
Figure 15 Volume of CO 2
captured by industry sector and year 25
Figure 16 Volume of CO 2
captured by capture type and capture asset lifecycle stage 26
Figure 17 LSIPs by capture type and region 26
Figure 18 Volume of CO 2
by storage type and region 27
Figure 19 Comparison of capture asset lifecycle with the progress of EOR
and storage in deep saline formations or depleted oil and gas reservoirs 28
Figure 20 Layout of Gorgon CO 2
compressor train 31
Figure 21 Technical options for CO 2
capture from coal-power plants 35
Figure 22 Summary of TRL for capture technologies 36
Figure 23 Applications of capture technologies to LSIPs 37
Figure 24 Typical post-combustion capture process for power generation 38
Figure 25 Post-combustion capture TRL rankings 38
Figure 26 Projected performance of post-combustion capture technologies 39
Figure 27 TRL of pre-combustion capture components 40
Figure 28 IGCC developments to recover energy losses from CO 2
capture 41
Figure 29 TRL for oxyfuel combustion components 42
Figure 30 Oxyfuel combustion developments to recover energy losses from CO 2
capture 43
Figure 31 Cost of CO 2
avoided for capture technologies 46
Figure 32 Existing and planned CO 2
pipelines in North America 48
Figure 33 European CO 2
transport corridors and volumes, CO 2
Europipe reference scenario 2050 49
Figure 34 Western Canadian CCS potential 51
Figure 35 Ship-based CO 2
carrier: Submerged Loading System general arrangement 53
Figure 36 Current status of country-scale storage screening assessments 54
Figure 37 Brazil sedimentary basins 55
Figure 38 Schematic risk profile for a storage project 61
Figure 39 CO 2
use technologies, feedstock concentration and permanence 64
Figure 40 Scope of policy landscape 70
Figure 41 Linkages between the UNFCCC, the CEM and G8 76
Figure 42 CCS policy index 78
Figure 43 Public funding support commitments to CCS demonstrations by country 90
Figure 44 Public funding committed to large-scale CCS demonstration projects 92
Figure 45 Public funding to large-scale projects 93
Figure B‐1 Asset Lifecycle Model 107
iv THE GLOBAL STATUS OF CCS: 2011

PREFACE
Since 2009, the Global CCS Institute has produced a series of major reports which aim to provide a comprehensive
worldwide overview of the state of development of carbon capture and storage projects and technologies, and of actions
by governments to facilitate the demonstration of those technologies at a large scale.
This report is the latest in that series, and covers developments up until August 2011. It draws on the results of the
Institute’s annual project survey, completed by lead proponents of major CCS projects around the world. Survey results
were supplemented by interviews with personnel from many of these projects, and by research undertaken by
Institute staff.
The assistance of project proponents in completing survey questionnaires and taking part in interviews is particularly
acknowledged. The Institute is grateful for the very high degree of cooperation received.
Preparation of the report was led by Edlyn Gurney and many Institute staff contributed by authoring individual sections
or reviewing the document. Material in the sections on capture technologies, the policy context and legal and regulatory
developments also draw on studies by other organisations specifically commissioned for this report, as detailed in
those sections. The Institute also acknowledges the many helpful comments provided by external reviewers on drafts
of the report.
PREFACE
v

ABBREVIATIONS
TERM
DESCRIPTION
TERM
DESCRIPTION
AGR
Acid gas removal
kW
Kilowatt
ASU
Air separation unit
km
Kilometre
AWG
Ad-Hoc Working Group
LSIP
Large-scale integrated project
CCEP
Climate Change and Energy Package
MENA
Middle East and North Africa
CCS
Carbon capture and storage
METI
Ministry of Economy, Trade and Industry
CCS-R
CCS Ready
MMV
Monitoring, measurement and verification
CDM
Clean Development Mechanism
Mtpa
Million tonnes per annum; million tonnes a year
CEM
Clean Energy Ministerial
MW
Megawatt
CER
Certified emission reduction unit
MWe
Megawatts electrical capacity or output
CMP
Conference of the Major Parties
MWth
Megawatt thermal
CO 2
Carbon dioxide
NDRC
National Development and Reform Commission
CO 2
-e
CO 2
equivalent
NER
New Entrants’ Reserve
CO2CRC
COP
CPU
Cooperative Research Centre for Greenhouse
Gas Technologies
Conference of Parties
CO 2
purification unit
NGO
NO x
OECD
Non-government organisation
Nitrogen oxides
Organisation for Economic Cooperation
and Development
CSLF
Carbon Sequestration Leadership Forum
PCC
Post-combustion capture
CTL
Coal-to-liquids
psia
Pound-force per square inch absolute
EB
CDM Executive Board
ppm
Parts per million
EC
European Commission
R&D
Research and development
EEPR
EIB
EOR
EPA
EPRI
ETS
EU
FGD
FID
GHG
European Energy Programme for Recovery
European Investment Bank
Enhanced oil recovery
Environmental Protection Agency
Electric Power Research Institute
Emission trading scheme
European Union
Flue gas desulphurisation
Final investment decision
Greenhouse gas
SACCCS
SBSTA
SCR
SNG
SO 2
SO x
TRL
UNFCCC
South African Centre for Carbon Capture
and Storage
Subsidiary Body for Scientific and Technological
Advice
Selective catalytic reduction
Synthetic natural gas
Sulphur dioxide
Sulphur oxides
Technology readiness level
United Nations Framework Convention on
Climate Change
IEA
IEAGHG
IGCC
IPCC
International Energy Agency
IEA Greenhouse Gas R&D Programme
Integrated gasification combined cycle
Intergovernmental Panel on Climate Change
UNIDO
ZEP
United Nations Industrial Development
Organization
European Technology Platform for
Zero Emission Fossil Fuel Power Plants
vi THE GLOBAL STATUS OF CCS: 2011

EXECUTIVE SUMMARY
Carbon capture and storage (CCS) has an essential role in reducing global greenhouse gas emissions. As part of
a portfolio of low-carbon technologies, CCS is needed to stabilise atmospheric greenhouse gas concentrations at
levels consistent with limiting projected temperature rises to 2°C by 2050, as recommended by the United Nations
Intergovernmental Panel on Climate Change.
The specific challenge for the CCS industry is to demonstrate the entire chain at commercial scale—incorporating CO 2
capture from large point sources, CO 2
compression and then transportation and injection into suitable storage sites or
for a use that results in permanent emissions abatement.
Progress is being made
In 2011 the CCS industry exhibited measured progress, with an increase in the number of large-scale integrated
projects (LSIPs) in operation or under construction and a clustering of projects around the advanced stages of
development planning.
There are eight large-scale projects in operation around the world and a further six under construction. Three of these
projects have recently commenced construction. Importantly, these include a second power project, Boundary Dam
in Canada, and the first project in the United States that will store CO 2
in a deep saline formation, the Illinois Industrial
Carbon Capture and Sequestration (ICCS) project.
The total CO 2
storage capacity of all 14 projects in operation or under construction is over 33 million tonnes a year. This is
broadly equivalent to preventing the emissions from more than six million cars from entering the atmosphere each year.
In the Institute’s annual project survey for 2010, ten projects reported that they could be in a position in the next
12 months to decide on whether to take a final investment decision (FID) and move into construction. Power generation
projects are prominent in this group and include Project Pioneer in Canada, the Texas Clean Energy project in the
United States and the ROAD project in Europe.
While the prospect of a number of power projects moving to a FID in the next year is a positive development, this is
contrasted with other high-emitting industries such as iron and steel and cement, where there is a paucity of projects
being planned at large-scale.
In total there are 74 LSIPs recorded in this report, compared with 77 reported in the Global Status of CCS: 2010 report.
These CCS projects continue to be concentrated in North America, Europe, Australia and China with few large-scale
projects planned in developing countries. It is vital that the lessons learned from demonstration projects in developed
countries are conveyed to developing countries, and that capacity development activities and customised project
support are undertaken so that these countries can eventually deploy CCS.
Factors influencing a project’s success
As with most industrial projects, building a viable business case for a CCS demonstration project is a complex and
time consuming process that requires both the project economics and the risks to be understood prior to a FID.
All projects in operation use CO 2
separation technology as part of an already established industry process and either
use CO 2
to generate revenue through enhanced oil recovery (EOR) and/or have access to lower cost storage sites based
on previous resource exploration and existing geologic information sets. Six of the eight operating projects are in natural
gas processing, while the other two are in synthetic fuel production and fertiliser production, and five of these projects
use EOR.
A number of projects in operation or under construction are undertaking CCS in response to, or anticipation of,
longer-term climate policies and/or potential carbon offset markets. While this is promising, developing a business
case is challenging especially when projects do not have access to either revenue streams, such as EOR or other
opportunities, or where CO 2
capture is not already part of an established industrial process.
EXECUTIVE SUMMARY
vii

There are 11 LSIPs that are considered on-hold or cancelled since the Institute’s 2010 report, with eight in the
United States and three in Europe. The most frequently cited reason for a project being put on-hold or cancelled
is that it was deemed uneconomic in its current form and policy environment. The lack of financial support to continue
to the next stage of project development, and uncertainty regarding carbon abatement policies and regulations were
critical factors that led several project proponents to reprioritise their investments, either within their CCS portfolio
or to alternative technologies.
This clearly indicates that substantial, timely and stable policy support, including a carbon price signal, is needed for
CCS to be demonstrated and then deployed. This support will give industry confidence to continue moving forward
and invest in CCS. In turn, such investment would ensure continuing innovation which will ultimately help to drive
down capital and operating costs.
Both government and the private sector have a role in resolving and bringing greater transparency to business case
issues so that the demonstration of CCS progresses and associated learnings and benefits are realised.
CCS in the power sector
Power generation projects have significant additional costs and risks from scale-up and the first-of-a-kind nature of
incorporating capture technology. Electricity markets do not currently support these costs and risks, even where climate
policies and carbon pricing are already enacted. A major cost for CCS is the energy penalty or ‘parasitic load’ involved
in applying the technologies. Going forward a major emphasis in pre-, post- and oxyfuel combustion capture applied to
power stations (and other industrial applications) is on research into reducing this cost.
Despite these challenges, construction of a post-combustion capture project (Boundary Dam in Canada) and an
integrated gasification combined cycle (IGCC) project (Kemper County) is proceeding. This indicates that the
technology risk for these applications is considered manageable and the technical barriers are not insurmountable,
if other conditions are right, such as allowance for the added cost into the rate base and other incentives. Both these
projects received government support and will be selling CO 2
for EOR, thus tapping into another revenue stream.
They are also demonstrating some elements of risk mitigation in the project design, by either having a relatively low
CO 2
capture rate from the flue gas stream (in the case of Kemper County) or capturing CO 2
from a relatively small
power unit (in the case of Boundary Dam).
It is vital these and other planned demonstration power projects are successful in carrying out CCS on a commercial-scale
and operating in an integrated mode, in real electricity wholesale markets and with storage at sufficient scale to provide
the confidence and benchmarks critical for future widespread deployment.
Capture, transport and storage issues
The eight operating CCS projects in the natural gas processing, synthetic fuels and fertiliser production industries
attest to the proven nature of the capture technology in these applications. As noted above, while there are projects
proceeding to construction in the power sector, there is a need for more projects to demonstrate the range of possible
capture technologies that could be applied. There have been limited recent developments in iron and steel sector
demonstrations of capture technologies. In the cement sector, capture technology is still at an early stage. Both these
industries are major emitters and further developments are expected and necessary.
Pipeline transport of CO 2
is a proven and well developed technology, but it is the scale of the future CO 2
transport
requirements that will require strong investment support. While pipelines are expected to be a cost-effective transport
solution, with increasing distance and in certain circumstances, shipping can be cost competitive and offers greater
flexibility to serve multiple CO 2
sources and sinks. Significant economies of scale can result from shared transport
infrastructure, but establishing a network is a large investment that can add considerable risks to early mover projects.
These risks need to be understood, in particular by governments when providing incentives for demonstration.
The operating projects demonstrate storage of CO 2
in both deep saline formations and through EOR, showing that
viable storage is achievable. The storage challenge ahead is with increasing injection volumes, gaining site-specific
experience and with continuing improvements to the design and methodologies of measurement, monitoring and
verification of storage in effective and appropriate regulatory environments.
viii THE GLOBAL STATUS OF CCS: 2011

Information from project proponents indicates that storage assessment and characterisation requires considerable
investment and can have long lead times of five to 10 years or more for a greenfield storage site, depending on
the existing available geologic information about the site. Policymakers need to factor these lead times into their
assessment of a project’s progress. Projects that have not yet commenced active storage assessment may have a
challenge to achieve operation before 2020.
As with storage, public engagement is situation and site specific and on a local level must address all aspects of the
project, including its possible and potential impacts and benefits. Project proponents need to continuously review
their public engagement approach to identify and mitigate potential challenges.
Policy and legal developments
CCS applied in new and large-scale applications is at the demonstration phase and requires substantial policy
and financial support. Governments should continue to send strong, consistent and sustained policy signals
(including incentives, legislation and regulatory frameworks) to support this early stage of transitioning towards
commercial deployment. Some project proponents perceive policy uncertainty as a major risk to project
development and it is of particular concern when governments articulate policy intent without implementation.
In the past year the development of CCS laws and regulations has continued, with a number of jurisdictions
completing framework legislation and commencing implementation of secondary regulations and guidance.
Effective regulatory regimes on a national level play a significant role in the development of CCS projects globally.
Notwithstanding these efforts, project proponents have identified a number of issues that in some cases have yet to
be adequately addressed, including regulation that is incomplete in nature or delayed. A number of proposals,
amendments and review exercises have already been put in motion by regulators and policymakers across several
jurisdictions to address such issues. Whether or not these activities will sufficiently address projects’ concerns will
be an important consideration in the forthcoming years.
Many of the countries and regions that have been acknowledged as leaders in the deployment of laws and regulation for
CCS have continued in these roles. In the past year, several European Union Member States, Australia, the United States
and Canada have all sustained their regulatory momentum and delivered a number of new proposals, laws, regulations
and initiatives. The importance of effective regulation has also been recognised by the many countries that are to become
the second generation of CCS lawmakers. Korea is one such example. While many of these countries have yet to pass
legislation, or complete the design of their regulatory frameworks, it is clear that significant actions are being taken to
facilitate their development. This is particularly noticeable in a number of developing countries that are keen to integrate
CCS into future climate change mitigation strategies.
This year, the Seventeenth session of the United Nations Framework Convention on Climate Change (UNFCCC)
Conference of the Parties (COP 17) in Durban, South Africa, could see an international framework established that
provides for the institutional arrangements of CCS under any future UNFCCC mechanism and/or adopted within
national government policy settings. Inclusion of CCS in the Clean Development Mechanism (CDM) or any future
mechanism post the Kyoto Protocol’s first commitment period (2008 to 2012) is of particular importance for the
future demonstration of the technology in developing countries.
Government funding to support large-scale CCS demonstration projects has remained largely unchanged in 2011.
In total, approximately US$23.5bn has been made available by governments worldwide. Competitive funding programs
designed to measure and fund the ‘gap’ required to make projects financially viable have been widely adopted by
governments internationally. This approach will be taken by the European Union’s NER300 program where 13 CCS
projects, together with 65 innovative renewable projects, were identified as meeting the criteria to go forward to the
next stage with decisions on funding allocation expected in the second half of 2012.
In the near-term, government policy and funding levels will impact strongly on the rate at which demonstration projects
progress and their overall viability. For this to be done effectively, ongoing cooperation between government and
industry is required to address the complex challenges in establishing early-mover CCS projects. In the long-term,
the value of CCS demonstration can only be realised and supported through sustained forward looking climate change
policies and carbon-price signals that will underpin the future deployment of CCS.
EXECUTIVE SUMMARY
ix

x THE GLOBAL STATUS OF CCS: 2011

1
INTRODUCTION
1.1 Scope of this report 2
1.2 The role of CCS in CO 2
emission reductions 3
1.3 What is CCS 5

1 INTRODUCTION
1.1 Scope of this report
Technologies that prevent or minimise carbon dioxide (CO 2
) being emitted into the atmosphere from the production
or use of fossil fuels could potentially play a major role in overall efforts to limit greenhouse gas (GHG) emissions.
Significant effort is being put into research and development (R&D) of carbon capture and storage (CCS) technologies,
and governments around the world have committed funds to assist in demonstrating CCS technologies at large scale.
Such large-scale demonstration, across a range of technologies and in different operating environments, is a necessary
precursor to commercial deployment of CCS.
This report aims to provide a global overview of the current status of CCS projects that are intended to demonstrate
the technology at large scale. The spread of projects across industries and countries is detailed, in addition to the
gaps in large-scale demonstration efforts.
There are different technologies being developed and planned to be demonstrated at each stage of the CCS chain
– capture, transport, and storage or use. The current state of development of these various technologies is also
summarised, along with the priorities for future research or demonstration efforts.
Demonstration of CCS depends not only on technology, but also on adequate funding and other government support,
financing and commercial considerations around building a business case for CCS, public acceptance, and the existence
of a policy, legal and regulatory environment conducive to large-scale and long-term investments. All of these factors
are covered.
Drawing on this overview of the status of the technology and the underlying policy and business environment, this report
also addresses the factors needed for CCS to play its part in meeting CO 2
reduction targets. It is becoming apparent that
a key constraint to the large-scale demonstration of CCS is not the level of technology development, but the existence
of issues such as inadequate financial support to continue to the next stage of project development and uncertainty
regarding carbon abatement policies in key jurisdictions, which acts to constrain investment decisions. This report draws
out these issues.
The remainder of this chapter provides a brief background on the potential role for CCS in GHG emission reduction
efforts, a basic overview of the technology, and an indication of how CCS costs compare with those of other technologies
in the electric-power generation sector, which is where the bulk of eventual CCS deployment is expected to occur.
Chapter 2 discusses the current status of large-scale integrated projects (LSIPs), the projects that are intended to
demonstrate CCS at a scale necessary for eventual commercial deployment, and which include integrated projects
combining capture, transport, and storage or use of CO 2
. Changes in the nature and number of such projects since
the previous Status Reports (WorleyParsons et al. 2009; Global CCS Institute 2011a) are explained. The characteristics
and distribution of projects by country, industry, stage of development and technology type are described.
In chapter 3, the different components of the CCS chain are separately described and discussed. It is important for
project proponents and governments to understand not only the state of development of the individual technologies
that make up CCS, but also the considerations around linking the different components into integrated projects.
This chapter concludes with a discussion of the current understanding of the costs of CCS technologies.
Chapter 4 outlines recent developments in government policy, law, legislation and regulation affecting CCS. In the case
of policy, this not only includes developments specific to CCS, but also in the broader climate change, energy and
innovation policy arenas. A summary is provided of funding and other financial incentives and support available for
projects. Finally, given the importance of public awareness and acceptance of CCS as a new technology, the chapter
includes a brief discussion of issues around public engagement.
The report concludes with some observations on the current business case for CCS, and the steps needed to facilitate
further projects entering construction or operation.
2 THE GLOBAL STATUS OF CCS: 2011

1.2 The role of CCS in CO 2
emission reductions
Anthropogenic CO 2
emissions have increased greatly over the past 150 years or so, leading to significantly increased
atmospheric concentrations of the gas (Figure 1). Associated with this increase has been a significant rise in average
global temperatures.
Figure 1 Global CO 2
atmospheric concentrations and temperature
Atmospheric CO ²
concentrations (ppm)
400
380
360
340
320
300
280
260
240
220
200
-1.0
1850 1860 1870 1880 1890 1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010
Year
CO 2
(LHS)
Sources: Data from Brohan et al. (2006), MacFarling et al. (2006), Tans and Keeling (2011)
Temperature (RHS)
In 2010, the United Nations Framework Convention on Climate Change (UNFCCC) Conference of Parties 16 (COP 16)
approved a non-legally binding commitment to cap global average temperature rises to 2°C. A 2°C rise is considered
consistent with capping atmospheric CO 2
equivalent (CO 2
-e) concentration levels to 450 parts per million (ppm) by 2050
(IPCC 2007). The recorded mean level of global CO 2
in the atmosphere for 2010 measured at the Mauna Loa Observatory
in Hawaii was 390ppm, with an increase of 2.42ppm for that year (ESRL 2011). CO 2
emissions are the chief contributor to
the current approximate CO 2
-e level of 430ppm, which is only 20ppm away from the recommended target of 450ppm.
On current projections, by 2050 CO 2
emissions must reduce significantly below not only ‘business as usual’ levels,
but also current levels in order to reach the cap of 450ppm. This particularly applies to emissions of CO 2
resulting from
the use of fossil fuels – coal, oil and natural gas.
Energy emission scenarios developed by the International Energy Agency (IEA 2010a) give a least cost GHG emissions
reduction pathway (Figure 2). The IEA demonstrates that a portfolio of low-carbon technologies is needed to reduce
emissions to half their current levels by 2050. Among these technologies are energy efficiency gains, renewables,
fuel switching and nuclear. The next ten years will see the majority of the most cost-effective reductions coming from
energy efficiency. After then, renewable technology starts taking a more significant role, with most of the increased
growth in deployment projected to come from emerging energy technologies such as wind, solar (both photovoltaic
and thermal systems), biomass, and to a lesser extent geothermal.
0.6
0.4
0.2
0.0
-0.2
-0.4
-0.6
-0.8
Global temperature anomaly (°C)
INTRODUCTION
3CHAPTER 1

Figure 2 Global CO 2
emissions and GHG emission reductions
Gt CO 2
60
55
50
45
40
35
30
25
20
15
10
5
WEO 2009 450 ppm case
Baseline emissions 57 Gt
BLUE Map emissions 14 Gt
ETP2010 analysis
2010 2015 2020 2025 2030 2035 2040 2045 2050
Year
CCS 19%
Renewables 17%
Nuclear 6%
Power generation efficiency and fuel switching 5%
End-use fuel switching 15%
End-use fuel and electricity efficiency 38%
Source: IEA (2010a, p75)
Between 2025 and 2030, while there is continuing rapid growth in the deployment of renewable technologies and in
energy end-use efficiency gains, the IEA least cost scenario also has a rapidly increasing role for CCS. Once the lower
cost options for energy efficiency and renewable technologies have been pursued, CCS becomes more competitive.
By 2050 the IEA scenario has CCS contributing 19 per cent of least cost emission reductions. This contribution is more
than from renewables and more than triple the contribution from nuclear.
Any major GHG abatement effort will add a significant cost challenge to current and future energy generation,
energy intensive industries and GHG emitting projects and investments. However, the IEA estimates that without CCS,
achieving a 50 per cent emission reduction by 2050 would cost 70 per cent more than if CCS is included.
To understand this result, it is useful to look at the current costs of CCS relative to other low-carbon technologies,
particularly in the electric power generation sector.
Relative costs of CCS
Many of the low-carbon technologies that will be required in coming decades are at an early stage of development or
deployment, and significant effort will need to be put into R&D and demonstration to both prove their capability and
reduce costs. For some industrial processes which produce CO 2
, there are currently very few options available to reduce
or abate emissions. Adequate pricing of emissions to reflect the environmental impacts of CO 2
or other GHGs would
assist in the R&D, demonstration and ultimate deployment of all emission-reduction technologies.
To present a comparison of low-carbon technology costs in the electric power sector, the Institute (2011b) has undertaken
a review of studies around technology costs by the IEA (2010b), IPCC (2011), United States Energy Information
Administration (EIA 2011), United States Department of Energy National Renewable Energy Laboratory (DOE NREL
2010), DOE National Energy Technology Laboratory (NETL 2010), and WorleyParsons (2011). As these studies each
use differing methodologies and assumptions regarding key economic and technology criteria, care has been taken
to compare the data on the same economic basis and similar resource quality.
The technologies that are expected to provide most of the future abatement in the power sector have relatively high costs
(Figure 3). For most of the emerging technologies applied at large scale, particularly CCS and the solar technologies, the costs
are expected to decline, possibly substantially, with increased efforts in innovation. For commercially mature technologies, such
as wind and nuclear, any cost reductions that can be achieved are not expected to match those of the emerging technologies.
This analysis shows that for avoiding CO 2
emissions, CCS is a cost-competitive technology with other future large-scale
abatement options in the electric-power generation sector. For example, the CO 2
avoided costs for CCS used in coal-based
generation and natural gas-fired generation range from US$68 to US$123 per tonne, and US$108 to US$224 per tonne,
respectively. In contrast, solar photovoltaic (PV) and solar thermal systems have cost of CO 2
avoided ranging from US$184
to US$307 per tonne, and from US$219 to US$273 per tonne, respectively.
4 THE GLOBAL STATUS OF CCS: 2011

Figure 3 Avoided costs of CO 2
by technology in the power sector 1
US$ per tonne CO 2
350
300
250
200
150
100
50
0
-50
Geothermal
Hydropower
Wind onshore
Nuclear
Biomass
CCS (coal)
Wind offshore
CCS (natural gas)
Solar thermal
1 The costs presented in this chart are for technologies operating in the United States, and have been derived by the Institute based on
reviewing a range of studies. Technology costs vary regionally due to a range of local factors including resource availability, as well as the
costs of labour and capital inputs. Also, some options are very site specific (for example geothermal and hydropower).
Source: Global CCS Institute (2011b), data from IEA (2010b), IPCC (2011), EIA (2011), DOE NREL (2010), DOE NETL (2010a), and WorleyParsons (2011)
1.3 What is CCS
CCS is a technology that can reduce the amount of CO 2
released into the atmosphere from the use of fossil fuel in
power plants and other industries. CCS involves:
••
collecting or capturing the CO 2
produced at large industrial plants using fossil fuel (coal, oil and gas) or other
carboniferous fuels (such as biomass);
••
transportation of the CO 2
to a suitable storage site; and
••
pumping it deep underground into rock to be securely and permanently stored away from the atmosphere.
Capturing the CO 2
Capturing CO 2
emissions from industrial processes is easiest at large industrial plants where CO 2
-rich flue gas can be
captured at the facility. The separation of CO 2
is already performed in a number of industries as part of the standard
industrial process. For example, in natural gas production, CO 2
needs to be separated from the natural gas during
processing. Similarly, in industrial plants that produce ammonia or hydrogen, CO 2
is removed as part of the production
process.
As the largest contribution to CO 2
emissions is from the burning of fossil fuel, particularly in producing electricity,
three main processes are being developed to capture CO 2
from power plants that use coal or gas. These are:
••
post-combustion capture;
••
pre-combustion capture; and
••
oxyfuel combustion capture.
Further details of these capture processes and their current state of development is provided in section 3.1.
Solar PV
INTRODUCTION
5CHAPTER 1

In other industries, such as in oil refining and cement production, capture processes have not yet been demonstrated
at a large enough scale, but in most cases existing capture methods can be tailored to suit particular production
processes. For instance, capture of CO 2
in oil refineries could use post-combustion technology and cement plants may
utilise oxyfuel combustion technology. In addition, tailored capture methods are being developed specifically for iron
and steel manufacturing.
Transporting the CO 2
Once separated from other components of the flue gas, CO 2
is compressed to make it suitable to transport and store.
It is then transported to a suitable storage site. Today, CO 2
is already being transported by pipeline, by ship and by
road tanker — primarily for use in industry or to recover more oil and gas from hydrocarbon fields. The scale of
transportation required for widespread deployment of CCS is far more significant than at present, and will involve
the transportation of pure or nearly pure CO 2
in a dense phase.
Storing the CO 2
The final stage of the CCS process sees CO 2
injected into deep underground rock formations, often at depths of one
kilometre or more. At this depth, the temperature and pressure keep the CO 2
as a dense fluid. The CO 2
slowly moves
through the porous rock, filling the tiny spaces known as pore space. Appropriate storage sites include depleted oil
fields, depleted gas fields, or rocks which contain water (saline formations) (Figure 4). These storage sites generally
have an impermeable rock (also known as a ‘seal’) above them. The seal and other geological features prevent CO 2
from returning to the surface.
Such sites have securely contained fluids and gases (such as oil, natural gas, and naturally occurring CO 2
) for millions of
years, and with careful selection, they are expected to securely store injected CO 2
for just as long. Once injected, a range
of sensing technologies is used to monitor the movement of CO 2
within the rock formations. Monitoring, measurement and
verification (MMV) processes are important to assure the public and regulators that the CO 2
is safely stored.
It is also possible to use the CO 2
in industrial applications, however any use of CO 2
must result in permanent storage or
it will not contribute to GHG mitigation.
Figure 4 Geological storage options for CO 2
Image courtesy of the CO2CRC
6 THE GLOBAL STATUS OF CCS: 2011

2
PROJECTS
2.1 Key project developments 8
2.2 Detailed project breakdown 15

2 PROJECTS
KEY MESSAGES
• Overall the CCS industry exhibits measured progress over the past year with one project completing
construction and moving into operation, another three projects entering construction and a clustering
of projects in advanced stages of development planning.
• Of the 74 large-scale integrated CCS projects around the world, 14 projects are either in operation or
construction and have a total CO 2
storage capacity of over 33 million tonnes a year.
• A second power project, in addition to Kemper County in the United States, is now under construction,
being Boundary Dam in Canada. The United States also has its first project under construction that
will store CO 2
in a deep saline formation, being the Illinois Industrial Carbon Capture and Sequestration
(ICCS) project.
• A number of projects in advanced stages of development planning, including several power plants,
indicated in the Institute’s 2011 annual project survey that they could be in a position in the next
12 months to decide on whether to take a final investment decision.
• There remains a paucity of large-scale demonstration projects under development in the iron and steel,
cement and other high emitting industries where CCS needs to be applied.
This chapter provides an overview of the global status of LSIPs, and is based largely on the Institute’s annual survey
undertaken in May-August 2011 (Appendix A). A detailed assessment of LSIP status is provided, including analysis of
project dynamics, challenges and opportunities. The assessment includes comparisons with the Institute’s 2010 and
2009 Status Reports (Global CCS Institute 2011a, WorleyParsons et al. 2009).
LSIPs are defined as those which involve the capture, transport and storage of CO 2
at a scale of:
••
not less than 800 000 tonnes of CO 2
annually for a coal-based power plant; and
••
not less than 400 000 tonnes of CO 2
annually for other emission-intensive industrial facilities
(including natural gas-based power generation).
There are many more projects around the world which are of a smaller scale or only focus on part of the CCS
chain. These projects are important for R&D, demonstrating individual elements of CCS, or building local capacity.
However, if CCS is to play a substantial role in global GHG reduction, then it is essential to demonstrate and deploy
large-scale projects that involve all parts of the CCS chain from capture through to permanent storage or other
sequestration. For this reason the Institute’s project survey focuses on LSIPs.
2.1 Key project developments
The Institute has listed 74 LSIPs across the world in 2011 (Figure 5). This is a small net reduction of three projects
from the 2010 report but remains above the 64 LSIPs reported in the inaugural 2009 report (Figure 6). An explanation
of the Asset Lifecycle Model used to classify the stage of development of LSIPs is in Appendix B. The full project listing
is provided in Appendix C.
8 THE GLOBAL STATUS OF CCS: 2011

Figure 5 LSIPs by asset lifecycle and region/country
Number of projects
30
25
20
15
10
CHAPTER 2
5
Identify Evaluate Define Execute Operate
Total
United States
Europe
Australia and New Zealand
Canada
China
Middle East
Other Asia
Africa
Total
1 8 9 3 4 25
1 9 9 0 2 21
1 5 0 1 0 7
0 2 4 2 1 9
4 2 0 0 0 6
0 1 2 0 0 3
1 1 0 0 0 2
0 0 0 0 1 1
8 28 24 6 8 74
Figure 6 LSIPs by asset lifecycle and year
Operate
Execute
De ne
Evaluate
Identify
Number of projects
5 10 15 20 25 30
2011 2010 2009
The most significant recent developments in the movement of projects through the development stages are:
••
The first gas processing train of the Century Plant in Texas moved into the Operate stage in late 2010. This
first train has a CO 2
capture capacity of around five million tonnes per annum (Mtpa). A second train is under
construction and is expected to be operational in 2012, incorporating additional CO 2
capture potential of around
3.5Mtpa. Note that this addition to the Operate stage does not result in a net change in the number of projects in
this stage from the 2010 report. This is because the previously included Rangely and Salt Creek (EOR) projects
are now represented by their shared capture source, the Shute Creek Gas Processing Facility.
• • The number of projects in the Execute stage increased from two in 2009 to four in 2010 and is now at six in
2011 (Figure 6). The most recent additions to the Execute stage include the Boundary Dam power project in
Canada, the Illinois Industrial Carbon Capture and Separation (ICCS) project and the Lost Cabin Gas Plant,
both in the United States.
PROJECTS
9

••
Ten projects in the Define stage have indicated they could be in a position within the next 12 months to decide
whether to take a positive FID and thus move into the Execute stage (Figure 7). Power generation projects are
prominent in this group and include the ROAD project in Europe, Project Pioneer in Canada and the Texas Clean
Energy project in the United States. The CCS component of these power projects, together with the Kemper County
integrated gasification combined cycle (IGCC) and the Boundary Dam projects already in the Execute stage, is being
underpinned by broad government support, especially capital grants. The North American capture projects in this
group also demonstrate the importance of multiple revenue sources [and especially the reuse of CO 2
for enhanced
oil recovery (EOR) purposes] in providing a driver for development.
••
While the prospect of a number of power projects potentially moving to a FID in the next year is a positive
development, this is contrasted with other high-emitting industries such as iron and steel, for example, where there
is a paucity of projects at large-scale. This lack of representation is the result of a combination of factors, including
higher government funding allocations to power generation and weak economic conditions in many countries
forcing a focus on core business profitability.
••
The low number of projects in the Identify stage should not necessarily be viewed as an adverse development.
Some projects are advancing through the asset lifecycle, moving out of the Identify stage. At the same time,
CCS at large-scale in key sectors such as power, iron and steel and cement making is not yet in a situation
where the project development funnel is constantly being replenished. This would require continuing infusions
of significant government financial support.
Figure 7 Timing of FID of LSIPs in the Define and Evaluate stages 1
Number of projects
10
9
8
7
6
5
4
3
2
1
0
Define
Evaluate
Define
Evaluate
Define
Evaluate
≤ 12 months 13-24 months > 24 months
Estimated time to a final investment decision
1 Responses were received from 24 out of the 52 projects in Evaluate or Define stages.
Table 1 lists the 14 projects in the Operate and Execute stages. The total CO 2
storage capacity of all these projects
combined is over 33Mtpa. This is equivalent to preventing the emissions from more than six million cars from
entering the atmosphere each year and shows the significant contribution that CCS can make to reduce GHGs
(conversion factor from US Environmental Protection Agency (EPA), website cited July 2011).
10 THE GLOBAL STATUS OF CCS: 2011

Nearly all of the operating or committed capture projects listed in Table 1 are either CO 2
EOR related and/or based
on gas processing (the sole exception is the Illinois-ICCS project though it has indicated that after a period of storage in a
deep saline formation, revenue opportunities from CO 2
for EOR will be sought). This illustrates the challenge that presently
confronts projects which do not have access to either EOR revenues and/or capture which is already part of the industrial
process, such as in gas processing. This point is particularly pertinent in jurisdictions with less mature national carbon
legislation. Should opportunities for tertiary hydrocarbon production be available, many of the large-scale early mover
capture projects are likely to include CO 2
for EOR to support a positive business case.
CO 2
EOR systems act as a substitute for exploration and development drilling to increase proved oil reserves, especially in the
United States. The increasing prevalence of this practice has attracted a range of oil and gas companies, pipeline operators
and CO 2
source companies to forge mutually attractive business opportunities. This momentum will continue in the
United States as long as ‘CO 2
EOR suitable’ fields are available and oil prices remain at the levels that encourage such
investments. Over the past few years, companies such as Denbury and Kinder Morgan have built a strong portfolio of CO 2
sources, pipelines and EOR fields in the United States and opportunities for expansion are emphasised in investor briefings.
CHAPTER 2
Table 1 LSIPs in the Operate and Execute stages
NAME LOCATION CAPTURE TYPE
VOLUME CO 2
(MTPA)
STORAGE
TYPE
DATE OF
OPERATION
Operate stage
Shute Creek Gas Processing
Facility
United States
Pre-combustion
(gas processing)
7 EOR 1986
Sleipner CO 2
Injection Norway Pre-combustion
(gas processing)
1 Deep saline
formation
1996
Val Verde Natural Gas Plants United States Pre-combustion
(gas processing)
1.3 1 EOR 1972
Great Plains Synfuels Plant
and Weyburn-Midale Project
United States/
Canada
Pre-combustion
(synfuels)
3 EOR with
MMV
2000
Enid Fertilizer Plant United States Pre-combustion
(fertiliser)
0.7 EOR 1982
In Salah CO 2
Storage Algeria Pre-combustion
(gas processing)
Snøhvit CO 2
Injection Norway Pre-combustion
(gas processing)
1 Deep saline
formation
0.7 Deep saline
formation
2004
2008
Century Plant United States Pre-combustion
(gas processing)
5 (and 3.5 in EOR 2010
construction) 2
Execute stage
Lost Cabin Gas Plant United States Pre-combustion
(gas processing)
1 EOR 2012
Illinois Industrial Carbon Capture
and Sequestration (ICCS) Project
United States
Industrial
(ethanol production)
1 Deep saline
formation
2013
Boundary Dam with CCS
Demonstration
Canada
Post-combustion
(power)
1 EOR 2014
Agrium CO 2
Capture with ACTL Canada Pre-combustion
(fertiliser)
Kemper County IGCC Project United States Pre-combustion
(power)
0.6 EOR 2014
3.5 EOR 2014
Gorgon Carbon Dioxide
Injection Project
Australia
Pre-combustion
(gas processing)
3.4-4 3 Deep saline
formation
2015
1 The Institute understands that part of the natural gas supply to the Val Verde Natural Gas Plants has been diverted to the Century Plant.
At the time of publication, the Institute is determining the impact, if any, this diversion has had on CO 2
capture from Val Verde.
2 All charts and calculations using CO 2
volumes have used 5Mtpa for the Operate stage and 3.5Mtpa for the Execute stage.
3 3.4Mtpa has been used for all charts and calculations using CO 2
volume values.
PROJECTS
11

Of the 14 projects in the Operate and Execute stages, there are six projects considered ‘full’ CCS projects in that they
demonstrate the capture, transport and permanent storage of CO 2
utilising sufficient MMV systems and processes to
demonstrate permanent storage – Sleipner, Great Plains/Weyburn-Midale, In Salah, Snøhvit, Illinois-ICCS and Gorgon.
These six projects are those listed in Table 1 as using deep saline formations for storage, and those using EOR with
MMV. The remaining projects exhibit the capture, transport and injection of CO 2
but would need to implement further
MMV systems and processes to be consistent with the demonstration of permanent storage. Similar needs exist for
enhancement around the implementation of adequate MMV systems for many of the projects in the development
planning stages.
The operating or under construction projects which do not include the full MMV regime demonstrating permanent
storage are included in the Institute’s listing because experience, especially from the capture element, can critically
inform future developments. The capture element of CCS projects is usually by far the largest absolute cost component
of CCS demonstration. It is where the need for cost reduction and production learning efficiencies are greatest.
That two power projects have moved into the Execute stage and several others are close to being in a position to decide
whether to take a FID represents a significant milestone for the large-scale demonstration of capture technology.
For many of these power projects, CO 2
for EOR purposes (and, in some cases, other additional revenue sources)
is currently an important part of the business case for proceeding.
Learnings do not just come from the capture elements. The four decades of CO 2
EOR operating experience in the
United States (and, more recently, from elsewhere) has developed a set of tools, techniques and experiences that can
be adapted to other storage options being pursued. These include some of the workflows for site characterisation,
injection and well integrity guidance, detailed predictive reservoir simulation models and a range of monitoring
techniques during and after CO 2
injection operations.
CO 2
EOR experience is therefore best viewed as providing an initial ‘facilitator’ role in the demonstration of CCS in
regions with EOR potential. This role, coupled with MMV of injected CO 2
, is important to the establishment of practical
legal and regulatory regimes, to fostering community acceptance and to demonstrate permanent storage. These issues
were explored in a recent Institute report on CO 2
use (Global CCS Institute and Parsons Brinckerhoff 2011).
The eight operating CCS projects in the natural gas and chemical processing industries attest to the proven nature of
capture technology in these applications. In the power sector, despite the challenges of scale-up and improving the energy
efficiency of the capture process, construction of a post-combustion capture project (Boundary Dam) and an IGCC project
(Kemper County) is proceeding. This indicates that the technology risk for these applications is considered manageable
and the technical barriers are not insurmountable. Similarly, the operating projects demonstrate storage of CO 2
in deep
saline formations and EOR, showing that storage is safe and achievable. The storage challenge ahead is with increasing
injection volumes, gaining site-specific experience and with continuing improvements to MMV in effective and appropriate
regulatory environments.
While ‘measured progress’ provides an overarching description of the global momentum of CCS at large-scale, project
developments and policy and business settings have distinct regional differences. These regional characteristics can
be summarised as:
••
Canada – robust progress under supportive settings;
••
United States – where CO 2
separation inherent to an industrial process combines with opportunities for CO 2
reuse,
specifically for EOR, CCS project opportunities are forthcoming. However, in the absence of a national carbon
abatement mandate, the prospects for power generation and coal gasification projects are now less certain than
in 2008 or 2009 even with significant government funding in place;
••
Europe – prospects are focused around the outcome of the present New Entrants’ Reserve (NER300)
funding round, for which results are expected in the second half of 2012;
••
Australia – a focus on storage characterisation among all projects that qualify under the government’s CCS
Flagships Program;
••
China – a focus on domestic research and development into CCS technologies, with particular emphasis on
CO 2
utilisation; and
• • Middle East and North Africa (MENA) – few projects at present but promising longer term opportunities,
particularly utilising CO 2
for EOR.
12 THE GLOBAL STATUS OF CCS: 2011

LSIP changes in 2011
There are 11 LSIPs that are considered on-hold or cancelled since the 2010 Status Report, with eight in the United States
and three in Europe (Figure 8). A full reconciliation of project changes since the 2010 report, including recent name
changes, is at Appendix D.
The most frequently cited reason for a project being put on-hold or cancelled is that it was deemed uneconomic in its
current form and policy environment. The lack of financial support to continue to the next stage of project development
and uncertainty regarding carbon abatement policies were critical factors that led several project proponents to
reprioritise their investments, either within their CCS portfolio or to alternative technologies. For example, Shell cancelled
the Shell CO 2
project in Mississippi in order to focus on developing its Quest project in Canada (which is in the Define
stage). Rio Tinto decided to convert its Lynemouth power plant in the United Kingdom (previously defined within the
North East CCS Cluster) to biomass instead of retrofitting it with CCS at this time.
In the United States, both the Boise White Paper Mill and CEMEX cement projects were put on-hold after failing to
be selected for the second phase of funding by the United States DOE. As a result there are currently no large-scale
CCS projects being developed in the pulp and paper or cement industries anywhere in the world. In the case of the
Mountaineer power project, American Electric Power cited regulatory and policy uncertainties as key factors contributing
to its decision not to progress to the Execute stage.
CHAPTER 2
Figure 8 Changes in LSIPs from 2010 to 2011
Number of projects
80
75
70
65
60
77
-3
-8 +8
(0)
74
55
50
45
40
35
30
25
20
15
10
5
2010 projects Cancelled On-hold Reclassifications Newly identified 2011 projects
PROJECTS
13

There are eight newly identified large-scale CCS projects:
1. Medicine Bow Coal-to-Liquids (CTL) Facility (United States – Define stage) – a coal-to-transport fuels plant in
Wyoming developed by Medicine Bow Fuel and Power LLC that proposes to capture up to 3.6Mtpa of CO 2
for EOR.
2. Kentucky NewGas (United States – Evaluate stage) – a coal gasification synthetic natural gas (SNG) plant jointly
developed by ConocoPhillips and Peabody Energy, aiming to capture up to 5Mtpa for storage in an onshore
saline formation.
3. Riley Ridge Gas Plant (United States – Evaluate stage) – a gas processing project being developed by Denbury
that will capture around 2.5Mtpa of CO 2
for EOR.
4. UK Oxy CCS Demo (United Kingdom – Evaluate stage) – a new build oxy-fired power plant in North Yorkshire
developed by Alstom UK Ltd, Drax Power Ltd and National Grid plc, aiming at capturing 2Mtpa of CO 2
for storage
in an offshore saline formation.
5. C.GEN North Killingholme Power (United Kingdom – Evaluate stage) – a new build IGCC power plant developed by
C.GEN and based in North Lincolnshire that plans to capture over 2.5Mtpa of CO 2
for storage in an offshore saline
formation.
6. Pegasus Rotterdam (Netherlands – Evaluate stage) – a new build oxyfuel natural gas-fired combustor (340MWe),
to be developed by SEQ International BV as part of the Rotterdam Climate Initiative (RCI), capturing 2.5Mtpa of CO 2
for storage in an offshore depleted oil and gas reservoir.
7. Maritsa TPP CCS (Bulgaria – Identify stage) – a retrofit power project aiming to capture 2.5Mtpa of CO 2
for storage
in a deep saline formation.
8. Sinopec Shengli Oil Field EOR (China – Evaluate stage) – with plans to capture 1Mtpa CO 2
from the Shengli Power
Plant and transport it to the Shengli Oil Field for EOR.
There have also been a number of project reclassifications (Appendix D). The key classification changes are:
••
Project clusters or hubs in Europe, Canada and the Middle East regions are no longer represented singularly.
Instead, each cluster is split into its constituent parts. For example, the Masdar CCS cluster is now split into the
Emirates Steel Industries project (Define stage) and the Emirates Aluminium CCS project (Evaluate stage).
Similarly, the Enhance Energy EOR project in Canada and the North East CCS Cluster in the United Kingdom
have been separated into their constituent capture projects. Accounting for projects in this way does not diminish
the importance of cluster or hub developments in influencing the deployment of CCS projects globally.
••
The Rangely and Salt Creek EOR projects in the United States (both in the Operate stage) are now represented by
their single capture source – the Shute Creek Gas Processing Facility, which supplies anthropogenic CO 2
for EOR
to these and other fields. This is consistent with the Institute’s accounting for other project listings to emphasise
the CO 2
capture facility. Importantly, this change results in a net increase in CO 2
volume potentially stored. This is
because the capture capacity of the Shute Creek facility (expanded to 7Mtpa) is larger than the combined off-take
indicated previously for the Rangely and Salt Creek EOR operations (around 3.5Mtpa of CO 2
combined). The effect
of this reclassification is that the number of projects in the Operate stage remains at eight even though there is a
new entry in that category (Occidental’s Century gas processing plant).
• • The Rotterdam CCS Network entry (the Netherlands – Evaluate stage: 3.4Mtpa of CO 2
) was deleted as its main
constituent large-scale projects are already listed in the Institute’s database and maintaining a separate listing
would have led to double-counting.
14 THE GLOBAL STATUS OF CCS: 2011

2.2 Detailed project breakdown
LSIPs by region and number
North America and Europe contain most of the listed LSIPs (Figure 9). Specifically, the United States and Europe account
for 25 and 21 projects respectively, or 62 per cent of all LSIPs, followed by Canada (nine projects), Australia (six projects)
and China (six projects). Within Europe, the United Kingdom has the largest number of projects (seven) followed by the
Netherlands (four) and Norway (three). There are currently no LSIPs identified in other key emitting countries such as
Japan, India or Russia.
Figure 9 LSIPs by region and year
United States
CHAPTER 2
Europe
Canada
Australia and New Zealand
China
Middle East
Other Asia
Africa
5 10 15 20 25 30 35
Number of projects
2011 2010 2009
The amount of CO 2
that is intended to be stored in any given year from the 74 LSIPs provides another indicator of the
level of potential activity across location and asset lifecycle stage.
The United States is the most active area not only with regard to project numbers but also the amount of CO 2
captured
(Figure 10). Six countries – the United States, the United Kingdom, the Netherlands, Australia, Canada and China –
combined account for 86 per cent of CCS activity on the basis of potentially stored CO 2
each year.
Figure 10 Volume of CO 2
potentially stored by region or country
United States
Europe
Australia and New Zealand
Canada
China
Middle East
Other Asia
Africa
10 20 30 40 50 60 70 80
Potential volume of CO 2
(Mtpa)
Planned
Execute
Operate
The 74 listed LSIPs are shown in maps in Figure 11 with Figure 12 and Figure 13 focusing on North America and
Europe respectively. These maps also identify the industry sector and storage types of the project. In these figures,
the projects are identified by a reference number that corresponds to the detailed project listing in Appendix C.
PROJECTS
15

Figure 11 World map of LSIPs by industry
See regional map for detail
LSIPs: Global
Industry Sector
Power generation
Gas processing
Multiple capture facilities
Other industry
Storage Type
EOR (enhanced oil recovery)
Deep saline formations
Depleted oil and gas reservoirs
Various/not specified
See regional map for detail
6
37
21
59
71
74
51
39
70
68 61
69
14
58
72
42
56
64
65
16 THE GLOBAL STATUS OF CCS: 2011

United States
The United States is the most dynamic market as it is characterised by the following:
••
the highest number of projects in operation (four), in construction (three) and in development planning (18);
••
three projects indicating they will be in a position to decide on whether to take a final investment decision
in the next 12 months;
••
the largest number of projects being put on-hold (five) or cancelled (three) over the past year; and
••
significant government funding for demonstration projects.
This current level of project activity is underpinned by the opportunities provided by CO 2
EOR systems as described
earlier in this chapter and by the United States having allocated the highest amount of government grants to specific
projects (section 4.2). This is in contrast to many other jurisdictions around the world which are still occupied with
funding allocation processes and have less mature EOR opportunities.
CHAPTER 2
In the US there is momentum in industries where CO 2
is already ‘captured’ as part of the industrial process, such as
gas processing and fertiliser production, and where an opportunity is found to use that CO 2
. With a high purity
stream of CO 2
at hand, the effort in these industries is centred on compression, transport and storage. In the US,
where EOR opportunities are strongest, there is a strong incentive for deals to be done among these CO 2
capture
sources, pipeline and oil field operators.
However, where the cost of capture is relatively high, such as power generation and SNG, developing a strong business
case for CCS is a challenge. There may be exceptions to this, such as coal-based plants that yield multiple premium
products in a poly-generation mode, as represented by the Texas Clean Energy project. Such multiple products can
include electricity, high value chemicals and CO 2
.
One United States power project to date—Kemper County—has developed a viable business case and moved into the
Execute stage. Other projects, like the Antelope Valley and AEP’s Mountaineer projects, have not been able to progress
to Execute and have been placed on-hold, even with substantial government funding allocated. In the absence of national
carbon legislation (and given the higher relative capture costs), the evidence suggests that for CCS to be applied to a
power project a suite of incentives may be required to make the business case. This suite may include all or some of
the following:
1. Continuation of significant federal government grants (in the order of hundreds of millions of dollars or more)
and often with tax concessions for qualifying project owners as early movers.
2. States that are prepared to offer electricity rate recovery (in part or full) to help cover the higher operating costs of the
capture plant or to meet a low carbon portfolio state mandate (for example, California’s Climate Legislation AB32).
3. Incentives such as loan guarantees and tax credits to help offset the higher capital and operating cost of the
project with CCS.
4. Off-take agreements to generate revenue through the sale of other valued products, including CO 2
for EOR.
A significant development in 2011 is the exit of Rio Tinto and BP from the Hydrogen Energy California project,
with expectations that a deal can be closed with prospective new owner SCS Energy LLC. This company intends
to reconfigure the project as a poly-generation plant similar to the Texas Clean Energy project.
It is important to note the work being undertaken by the seven Regional Carbon Sequestration Partnerships (RCSP)
in the United States. The Partnerships form a nationwide network that is investigating the comparative merits of
numerous CCS approaches to determine those best suited for different regions of the country and to develop a set
of ‘best practices’ for CCS in North America that could be broadly applicable to other regions globally. NETL manages
the Partnership program.
One Partnership project—the Midwest Geological Sequestration Consortium’s (MGSC) Illinois Basin-Decatur Test
Injection—is expected to commence injection in the second half of 2011. The CO 2
will be captured from the
Archer Daniels Midland (ADM) ethanol plant in Decatur, Illinois, compressed and then injected into a nearby deep
saline formation. The planned capture and injection rate, at 1 000 tonnes of CO 2
per day or 365 000 tonnes per year,
is significant and very close to the Institute’s LSIP scale criteria for an industrial facility. This test injection project is
expected to operate for three years, for a total CO 2
injected of around one million tonnes. A second project at larger
scale – the Illinois-ICCS project with 1Mtpa of CO 2
captured from the ADM plant – is included in the Institute’s LSIP
listing, in the Execute stage.
PROJECTS
17

Figure 12 North American map of LSIPs by industry
29
California
36
Alberta
48
26 27
12/18
57
47
5
11
63
9
23
3
2
16
Oklahoma
Texas
54
50
10 45
32
60
Indiana
41
Kentucky
13
Louisiana
17 Mississippi
46
15
8 19 1 33
Kansas
LSIPs: North America
Industry Sector
Power generation
Gas processing
Synthetic natural gas
Fertiliser production
Oil refining
Coal-to-liquids
Ethanol plant
Hydrogen
Storage Type
EOR (enhanced oil recovery)
Deep saline formations
Various/not specified
British
Columbia
Saskatchewan
Wyoming
Colorado
North Dakota
Illinois
Pennsylvania
67 38
New
Jersey
18 THE GLOBAL STATUS OF CCS: 2011

Canada
CCS continues to play a major role in Canada’s carbon emission reduction strategy, and significant strides have been
made at the provincial level in advancing the policy regime and financial support base for projects. The possibility for
CO 2
EOR and oil sands continues to motivate CCS project development.
Major factors which have affected project development in the past 12 months include:
••
In May 2011, Shell filed for its Carbon Sequestration Lease for the Quest project under the Alberta Carbon
Sequestration Tenure Regulation. Shell has indicated that a FID may be possible in 2012 subject to financial,
permitting and community approval issues being satisfactorily progressed.
••
In April 2011, SaskPower received approval from the Saskatchewan Government to proceed with the CCS
component of Boundary Dam.
••
In March 2011, the Alberta Government launched its Regulatory Framework Assessment process, an ambitious
project to develop world class regulations for all elements of CCS.
CHAPTER 2
••
In February 2011, the Alberta Government finalised its C$495 million grant agreement with Enhance Energy for
the Alberta Carbon Trunk Line (ACTL). This decision is reinforced by approval from the Alberta Energy Resources
Conservation Board to construct the pipeline.
••
In November 2010, the Alberta Government introduced the Carbon Capture and Storage Statutes Amendment Act
to address some significant barriers to demonstrating CCS. In particular, this Act amends existing legislation
and provides the mechanisms for companies that will be seeking access to pore space for storing CO 2
, and the
associated requirements for monitoring and closure plans. In the legislation, the province will assume the long-term
liability for the stored CO 2
, after certain conditions have been met; these conditions are being developed though
Regulatory Framework Assessment. In April 2011, the Carbon Sequestration Tenure Regulation was published
which sets the conditions for a pore space tenure application.
Canada continues with a robust large-scale CCS demonstration program, including:
••
the Great Plains/Weyburn-Midale project continuing to inject around 3Mtpa of CO 2
;
••
two projects that are in the Execute stage – Agrium CO 2
Capture with ACTL and Boundary Dam; and
• • three projects which may be in a position to decide whether to progress to a FID in 2012: Swan Hills Synfuels
which has finalised a funding agreement for C$285 million in government grant support; Quest which has finalised
a funding agreement for C$865 million; and Project Pioneer which is in advanced negotiations for C$779 million in
grant support.
PROJECTS
19

Figure 13 European map of LSIPs by industry
LSIPs: Europe
Industry Sector
Power generation
Gas processing
Iron and steel production
Hydrogen production
Other industry
Storage Type
EOR (enhanced oil recovery)
Deep saline formations
Depleted oil and gas reservoirs
Various/not specified
24
52
66
53
4
22
55 49
43
United Kingdom
40 35
Netherlands
28 62
31
34
France
Spain
Norway
Germany
25
Italy
30
7
Poland
20
44
Romania
73 Bulgaria
20 THE GLOBAL STATUS OF CCS: 2011

Europe
Since the 2010 report, the most material development in Europe has been Member States of the European Union (EU)
making CCS project submissions to the European Commission (EC) for the first round of the NER300 funding program.
A total of 65 renewable and 13 CCS project proposals were submitted to the EC in May 2011 for assessment by the
European Investment Bank (EIB). The EC intends to provide clarity on the outcomes of the first round of the NER300
funding program in the second half of 2012. Funding from the total NER300 program could probably support four to
six large-scale CCS projects, though this is dependent on the quality of applications and the value of the allowances
auctioned. The expectation is that these supported projects would be operating within four years of being informed of
a funding award. Table 2 below summarises the 13 CCS submissions.
Table 2 CCS project submissions for NER300 to the European Commission
CCS PROJECT CATEGORIES
PROJECTS SUBMITTED BY NAME
NO. OF
PROJECTS
CHAPTER 2
Power generation (pre-combustion)
Power generation (post-combustion)
Power generation (oxyfuel)
Industrial applications
••
C.GEN North Killingholme (United Kingdom)
••
Don Valley (United Kingdom)
••
Eston Grange CCS (United Kingdom)
••
Getica CCS Demonstration (Romania)
••
Bełchatów (Poland)
••
Porto Tolle (Italy)
••
Longannet (United Kingdom)
••
Peel Energy CCS (United Kingdom)
••
Peterhead Gas CCS (United Kingdom)
••
UK Oxy CCS Demonstration (United Kingdom)
••
Vattenfall Jänschwalde (Germany)
••
ULCOS – Blast Furnace (France) – steel production
••
Green Hydrogen (Netherlands) – hydrogen production
3
6
2
2
From the CCS related submissions, a number of observations can be made:
••
seven countries made project submissions to the EC to compete for funds available under the NER300
funding program;
••
seven project proposals were submitted by the Government of the United Kingdom across all three power
generation categories;
••
only the Government of the United Kingdom has submitted applications for the power generation pre-combustion
category;
••
the large majority of projects are related to power generation, and in general, the capture elements of these
projects exhibit greater maturity than their storage elements;
••
there is a growing realisation in Europe that finding and licensing offshore storage sites of ‘strategic significance’ for
captured CO 2
will be the key to a winning submission – at least for the nine projects which propose offshore storage;
••
growing interest in possible application of EOR based models in the North Sea, in particular as a possible
financial underpinning for Don Valley;
••
the Dutch Government submitted only the Green Hydrogen project by Air Liquide out of four projects put forward by
industry for consideration. This non-power project will also receive €90 million of funding from the Dutch Government
if successful in the NER300 funding program;
••
four projects have already received funding through the European Energy Programme for Recovery (EEPR),
including Bełchatów (Poland), Porto Tolle (Italy), Don Valley Power Project (United Kingdom; formerly known as
Hatfield) and Jänschwalde (Germany). The Norwegian Government has also announced an additional €137 million
in funding for the Bełchatów project; and
• • the Porto Tolle project in Italy was submitted to the EC for consideration but suffered a setback over permitting
approvals for the base power plant earlier in 2011. The Institute understands that ENEL has requested the Ministry for
the Environment to re-examine the objections to the project raised in the earlier ruling issued by the Council of State.
PROJECTS
21

The EIB will assess the NER300 submissions against a number of criteria, including importantly the cost of CO 2
abatement and the financial viability of the project. Separately, the EC will confer with Member States as to what
financial support they will give to the project, as well as assess the ability of the submissions (and available funding)
to demonstrate the different technologies specified in the funding call.
Other developments include:
••
the ROAD project in the Netherlands plans to use the €180 million received through the EEPR (and an additional
€150 million from the Dutch Government) to be in a position to decide on whether to progress to a FID early in
2012 and has not provided a submission to the NER300 program;
••
the United Kingdom continues to move to finalise negotiations in relation to program support for Longannet,
with final decisions expected by the end of 2011. In addition, the government has announced support from
general revenue for two to four projects with competition arrangements to be announced in early 2012; and
••
the Compostilla Project in Spain also received €180 million of EEPR funding. However, the Spanish authorities
did not submit the project developer’s proposal for funding under the NER300 program to the EC.
Australia
Near-term storage options are not readily available in Australia, which does not have significant (nor near-term access to)
EOR potential or depleted oil and gas fields. Because of this, the search for suitable saline formation storage is
a requirement for all large-scale CCS projects. Saline formation storage is being used in the only Australian project in
the Execute stage – the Gorgon Carbon Dioxide Injection Project. A detailed case study on this project is provided at
the end of this chapter.
Against this background, in June 2011 the Australian Government announced AU$60.9 million in funding for a National
CO 2
Infrastructure Plan to study potentially suitable sites to store captured CO 2
and speed up the development of
transport infrastructure near major CO 2
emission sources. The plan includes the development of a national CO 2
drilling
rig deployment strategy and an assessment of infrastructure needs.
The Australian Government also announced that it had selected the Collie Hub project for funding under the AU$1.68bn
CCS Flagships Program. The ‘base case’ for the Collie Hub project aims to capture around 2.5Mtpa of CO 2
from an industrial
source south of Perth in Western Australia. The Australian Government is to provide up to AU$52 million to support
the studies required to move the project to the next phase of decision making. A key aspect of the next phase of project
development is the completion of a detailed storage viability study. Initial studies have identified the Lesueur formation
in the Southern Perth Basin as the best potential CO 2
storage site.
The Australian Government also announced that it will continue to progress other large-scale Australian CCS projects,
including the CarbonNet project in Victoria and the Wandoan project in Queensland. As with the Collie Hub project,
these two projects will initially focus on the development of CO 2
storage reservoirs and associated community engagement.
China
China continues to be one of the most important and challenging markets for CCS deployment. The high cost and
energy penalty and the immaturity of CCS technologies at large scale are commonly cited as the major concerns to
Chinese stakeholders. The current measures for reducing China’s GHG emissions are focused on improving energy
efficiency, energy conservation and increasing the share of non-fossil fuel energy sources. However, there is growing
recognition by the Chinese central government that while these technological options remain important, they will only
go so far and CCS will also need to play a key role in China’s climate change abatement strategies, particularly in
the medium to long term. This recognition, coupled with the desire to foster indigenous low carbon technologies,
will continue to drive CCS development in China.
The Institute identified six LSIPs in China that are largely in the planning stages. These projects are generally being
undertaken by China’s large state-owned power utilities and oil and gas companies. Some of the most prominent projects
are the Greengen IGCC project and the Shenhua Coal-to-Liquids (CTL) Plant (Ordos City). These projects have the support
of government agencies such as the National Development and Reform Commission (NDRC), as well as involvement from
international partners such as development banks, non-government organisations (NGOs) and industry.
CO 2
utilisation is considered to be critical to making CCS a commercially viable option. A number of companies in
China are already capturing and using CO 2
, including in the production of food and beverages, fertiliser, algae and
for EOR. China’s focus in the near term in this regard is likely to be unchanged. For example, Sinopec is currently
operating an integrated pilot plant that captures 0.04Mtpa of CO 2
for EOR. Based on this experience, Sinopec has
started a program to expand the capacity of this facility up to 1Mtpa CO 2
capture (Phase II). A series of research
programs will be conducted on petroleum geology investigation, environment impact and other areas concerning
CO 2
EOR. Phase II of this EOR facility is expected to be completed in 2014.
22 THE GLOBAL STATUS OF CCS: 2011

Japan
The Japanese Government is committed to reducing its CO 2
emissions. Since the March 2011 earthquake and tsunami,
the Government has revised its Basic Energy Plan, which will likely include an increased reliance on fossil fuels, at least in
the short term. The revision of the plan is being considered in line with the emissions reduction target, and could include
the adoption of CCS.
The Ministry of Economy, Trade and Industry (METI) is currently funding the development of a demonstration project in
Hokkaido. The project aims to capture more than 100 000 tonnes per year of CO 2
for storage in an offshore deep saline
formation more than 1 000 metres under the seabed in the North of Japan. In support of this project, Japan CCS Co. Ltd
is undertaking a 3D seismic survey and drilling a test borehole to identify and explore suitable formations for CO 2
storage.
The budget to develop the project is approximately ¥5.9bn in Japanese Fiscal Year (JFY) 2010 and ¥4.9bn in JFY 2011.
Korea
Korea aims to achieve commercial deployment of CCS plants and global technology competitiveness by 2020.
Two LSIPs are currently under development:
CHAPTER 2
••
Korea-CCS 1 proposes to use post-combustion technology to capture up to 1.2Mtpa of CO 2
from a 300MW
coal-fired power plant and store in a deep saline formation by 2017; and
••
Korea-CCS 2 proposes to use oxyfuel combustion or IGCC with pre-combustion technology to capture
1.2Mtpa of CO 2
and store in a deep saline formation by 2019.
The Korean Government has commenced a storage capacity assessment and geological survey of the offshore
Ulleung basin and is exploring shipping transport.
Middle East
The Middle East is a region of strong promise for CCS. This region possesses a range of drivers and natural advantages
for CCS, including:
••
significant EOR and deep saline storage potential, accompanied by a wealth of geological data;
••
strong and growing demand for power that is unlikely to be satisfied by natural gas and will require use of other
fuels, especially coal;
••
a rapidly expanding industrial base, especially in a number of high CO 2
emission sectors, such as gas processing,
refining, steel making, chemical processing, and fertilisers;
••
significant overlap between the location of existing CO 2
sources and potential CO 2
sinks; and
••
growing awareness and action to address climate change.
While there is large potential, the demonstration of CCS in the region is seen as an important precursor to deployment.
The key initiative designed to contribute towards the regional demonstration of CCS is Abu Dhabi’s Masdar program.
As a whole this program is a clean-energy initiative designed to explore a range of renewable and alternative fuel
options for the United Arab Emirates. Through Masdar, three CCS projects are being supported, all focusing on using
CO 2
for EOR:
••
Emirates Steel Industries – iron and steel;
••
Emirates Aluminium CCS – power generation (post-combustion); and
••
Hydrogen Power Abu Dhabi (a joint venture between Masdar and BP) – power generation (pre-combustion).
For several years the region has actively advocated for the inclusion of CCS in the UNFCCC’s Clean Development
Mechanism (CDM). Such an inclusion could further fuel CCS development in the Middle East by tipping near
commercial projects into viable business opportunities.
PROJECTS
23

Developing Countries
The absence of LSIPs in developing countries is noticeable. If projects struggle to build a business case in developed
countries, developing countries will have an even greater challenge, especially in the face of other priorities.
In the current context, a key avenue for support of CCS demonstration projects in developing countries is the expected
inclusion of CCS into the CDM (or any future mechanism post the Kyoto Protocol). Key decision text was adopted in late
2010 at the COP 16 climate change talks in Cancun, Mexico that legitimises the merit of CCS as a mitigation option within
the context of the UNFCCC objectives, as well as its capacity to be able to systematically generate tradable credits under
the CDM. This decision will ultimately see a framework established that could provide for the institutional arrangements
of CCS under any future UNFCCC mechanism (including Technology; Financial; and Future Markets) and/or adopted
within national government policy settings.
The inclusion of CCS in future UNFCCC mechanisms could assist the mobilisation of funds to CCS projects.
Access to capital would help encourage a greater level of interest by both developing and developed countries in CCS
demonstration projects in the developing world.
Using the CO 2
is expected to be a key component of large-scale CCS demonstration projects in emerging and developing
economies, where there is strong demand for energy and construction materials and less likelihood of the early adoption
of carbon pricing. The main focus is likely to be EOR due to its technical maturity and potential CO 2
utilisation capacity but
other technologies may also be of interest such as carbonate mineralisation, concrete curing, bauxite residue carbonation,
enhanced coal bed methane, urea yield boosting and renewable methanol.
Capacity development
A key factor that will constrain CCS demonstration in developing countries is human resource capacity. In order to
deploy CCS a technical and expert workforce will be required to facilitate project operation. Developing the existing
technical expertise of the oil and gas sector represents an early opportunity to develop CCS expertise within a country,
as they may already be familiar with related processes. As developing countries move further along the CCS lifecycle
the need for technology based capacity development activities will increase.
LSIPs by industry sector
There has been little change over the past three years in the distribution of LSIPs by industry sector (Figure 14).
Power generation projects dominate (42 LSIPs) because they represent high levels of stationary source emissions and
consequently have attracted the largest proportion of government funding for abatement. The number of gas processing
projects has also remained reasonably stable and in some cases the drivers for deployment in this sector are well advanced.
Figure 14 LSIPs by industry sector and year
Power generation
Natural gas processing
Synthetic natural gas
Fertiliser production
Coal-to-liquids (CTL)
Hydrogen production
Iron and steel production
Oil refining
Chemical production
Cement production
Pulp and paper
Other
5 10 15 20 25 30 35 40 45
Number of projects
2011 2010 2009
24 THE GLOBAL STATUS OF CCS: 2011

Since the 2010 report, there has been an overall increase in the volume of CO 2
being stripped out through natural gas
processing as well as a major shift from volumes in the Execute stage to Operate (Figure 15). The former reflects the
addition of the Riley Ridge project to the list (2.5Mtpa, Evaluate stage) and an increase in CO 2
capture capacity at the
Shute Creek facility (from 4Mtpa to 7Mtpa). This increase in capacity at Shute Creek, together with the start-up of the
first phase of Century Plant in late 2010, accounts for the large increase in CO 2
capture capacity in the Operate stage.
Figure 15 Volume of CO 2
captured by industry sector and year
Power generation
2011
2010
Natural gas processing
CHAPTER 2
2011
2010
Other industries
2011
2010
10 20 30 40 50 60 70 80 90
Potential volume of CO 2
(Mtpa)
Planned Execute Operate
As noted earlier, it is a positive development that there are now two projects in the power industry in the Execute stage
with a number indicating that a decision on whether to proceed to a FID is likely within the next 12 months.
The status of CCS demonstration in other industries currently lacks significant funding and hence momentum.
Though there are some projects in operation, these occur in the fertiliser and synfuels sectors where CO 2
is stripped out
as part of the process, and has been for decades. While there is interest in CCS deployment in these other sectors, from a
volume perspective the level of activity is minimal. There are very few or even no projects in high emitting sectors such as
iron and steel, cement and pulp and paper production. Since large-scale demonstration projects can take considerable
time to move from identification to reach operation, lack of momentum in these other industries may prove problematic
for future abatement. Without dedicated funding to these other industries, it is unlikely that CCS will be demonstrated in
these sectors by 2020.
LSIPs by capture technology
Pre-combustion capture is the most frequently chosen capture technology by LSIPs in the Operate and Execute stages
(Figure 16). Pre-combustion capture has a long history in gas processing, synfuels and fertiliser production but its
application in power generation is more recent. For example, Kemper County is the first pre-combustion power project
with CCS that has entered construction and intends to capture 3.5Mtpa of CO 2
.
Post-combustion capture technologies in the power sector have also recently moved into construction with Boundary Dam
aiming to capture 1Mtpa of CO 2
. Beyond this project, the application of post-combustion capture in other sectors and
large-scale operations is yet to be widely tested.
Most CCS projects in development planning are proposing to use pre-combustion or post-combustion capture technology,
representing 55 per cent and 27 per cent respectively of the number of all planned projects. Although oxyfuel combustion
capture is not as widely planned, it is maturing with five projects utilising this technology in the Define or Evaluate stage.
Further details regarding the maturity levels of CO 2
capture technologies can be found in section 3.1 of this report.
PROJECTS
25

Figure 16 Volume of CO 2
captured by capture type and capture asset lifecycle stage
Pre-Combustion
Post-Combustion
Oxyfuel Combustion
Industrial Separation
Not Speci ed / Various
20 40 60 80 100 120
Potential volume of C0 2
(Mtpa)
Identify
Define
Operate
Evaluate
Execute
Pre-combustion capture is the most frequently chosen CO 2
capture technology in North America and China (88 per cent
of all projects in the United States, 67 per cent in Canada and 83 per cent in China), while post-combustion capture is
the most widely pursued in Europe, representing 48 per cent of all CCS projects (Figure 17). This pattern is reflective of
government grant allocation differences between North America and Europe, and the large number of gas processing and
SNG projects in the United States.
Figure 17 LSIPs by capture type and region
United States
Europe
Canada
Australia and New Zealand
China
Middle East
Other Asia
Africa
Number of projects
5 10 15 20 25
Pre-combustion
Oxyfuel combustion
Not specified/various
Post-combustion
Industrial separation
LSIPs by transport type
Almost 95 per cent of all LSIPs use or propose to use pipelines to transport CO 2
to the storage site. Transportation
appears to remain a lower order priority for proponents as the integration challenges are assumed to be well understood.
This understanding is exemplified by the numerous CO 2
capture projects that outsource their transportation and storage
needs through existing EOR pipelines and fields. While such an approach streamlines these aspects of the CCS chain,
the creation of new pipeline routes, especially in non-industrial areas, to tap into geological storage options is not as
straightforward. This will most likely require detailed planning and public consultation in the associated land acquisition
and permitting.
Shipping is still marginal with only four LSIPs currently pursuing this option. Nevertheless shipping is increasingly being
investigated as a more flexible option for matching CO 2
sources and sinks, for example in situations where offshore storage
is preferred and where the capture facilities are not in the immediate vicinity of a pipeline entry point. Transport by truck
is still limited to smaller scale injection testing projects, and could well be included in large-scale projects to deliver CO 2
to industrial customers as a niche revenue source.
26 THE GLOBAL STATUS OF CCS: 2011

LSIPs by storage type
In the United States and Canada, almost 80 per cent of LSIPs in each country are either using or intend to use CO 2
for EOR purposes (Figure 18). Similarly, all LSIPs being developed in the Middle East are EOR-driven and China is
strongly focused on EOR and other industrial uses of CO 2
. On the other hand, CO 2
storage in deep saline formations
and depleted oil and gas reservoirs is prevalent in Europe and Australia.
Figure 18 Volume of CO 2
by storage type and region
United States
Europe
Australia and New Zealand
CHAPTER 2
Canada
China
Middle East
Other Asia
Africa
10 20 30 40 50 60 70 80
Potential volume of CO 2
(Mtpa)
Enhanced oil recovery
Deep saline formations
Depleted oil and gas reservoirs
Various/not specified
Full project integration with aligned capture and storage lifecycle stages is easier to achieve for EOR-driven projects than
for those intending to use geologic storage solutions. This is important because it is unlikely that EOR/depleted oil and
gas fields have the required capacity to be a major long-term contributor to CO 2
abatement. Current assessments strongly
suggest deep saline formations will provide the bulk of storage potential.
Two-thirds of projects with EOR, whose capture component is in the Define stage, have a commercial agreement in
place for CO 2
off-take or are in advanced negotiations with potential EOR customers (Figure 19). As CO 2
EOR systems
have been in operation in the United States for around four decades, new projects can feed into existing pipeline
and EOR networks (or planned extensions to those) and permitting and contractual arrangements are well known.
This considerably shortens the development timeframes for the storage end of the CCS chain. The capture element
becomes the key risk to project progression in conventional EOR operations.
In comparison, where deep saline formations or depleted oil/gas reservoirs are to be used, only one-third of projects,
whose capture component is in the Define stage, have the same level of storage definition (undertaking detailed site
characterisation).
This dynamic of synchronising capture and storage definition becomes much more complex when applied to greenfield
geologic storage solutions. Here the challenges for optimising limited budgets across capture desktop studies and
potentially more expensive and lengthy storage exploration/appraisal/testing work scopes are magnified, particularly under
timing constraints. This is especially true if the project is part of a competitive process and there is no history of exploration
management in the managing organisation. Where there is considerable uncertainty as to whether a compelling business
case can be made in support of the capture of CO 2
, there is little incentive for project proponents to expend potentially
large sums of capital on storage exploration or appraisal activities, especially if there is a significant chance of failure.
Project proponents may seek to delay potentially large expenditures on storage characterisation until uncertainties on the
capture business case are addressed, and then in turn mitigate storage risk through several years of site assessment,
characterisation and modelling. Such a strategy may however significantly delay project implementation. Early storage
data acquisition would also better inform regulatory and public engagement activities by project proponents.
The role for government may well extend beyond financial support for capture facilities to include supporting the
timely provision of storage (and transportation) infrastructure. The hub models being developed in Australia with
CarbonNet and the Collie Hub projects involve state governments supporting the development of the necessary
storage infrastructure to support capture project proponents. Likewise, as mentioned previously, the Australian
Government has recently announced funding for a National CO 2
Infrastructure Plan.
PROJECTS
27

Figure 19 Comparison of capture asset lifecycle with the progress of EOR and storage in deep saline formations
or depleted oil and gas reservoirs
De ne
Evaluate
Projects with enhanced oil recovery
Capture asset lifecycle stage
Identify
De ne
Identification of prospective customers
Preliminary negotiations
Advanced negotiations
Commercial agreement in place
Projects with storage in deep saline formations or depleted oil and gas fields
Evaluate
Identify
Number of projects
5 10 15
Exploration of prospective sites
Assessing suitability of site/s
Detailed site characterisation
Approved storage permit
Portfolio distribution of LSIPs
A portfolio distribution mapping the key industries, technologies and regions where current LSIPs are being considered
is a useful mechanism to summarise much of the previous discussion in this chapter (Table 3). Many of the salient
points have been made previously, including the geographical dominance of a few regions, the dominance of power
generation projects and pipeline systems within these regions, and geographical differences in the type of storage
options being pursued.
28 THE GLOBAL STATUS OF CCS: 2011

Table 3 LSIPs by region, by technology and by industry
NORTH
AMERICA EUROPE ASIA
AUSTRALIA –
NEW ZEALAND
MENA
SUB-
TOTAL
Pre-combustion 9 3 3 1 1 17
Post-combustion 4 10 2 1 17
CAPTURE
POWER
OTHER
Oxyfuel combustion 1 4 5
Various/other 1 2 3
Gas processing 6 2 2 1 11
Iron and steel 1 1 2
Cement 0
Various/other 14 1 2 2 19
CHAPTER 2
Point-to-point onshore
pipeline
Point-to-point offshore
pipeline
14 6 5 4 1 30
1 8 1 10
TRANSPORT
Network pipeline 19 5 2 3 29
Other pipeline 1 1
Ship/tanker 2 2 4
Onshore deep saline
formations
Offshore deep saline
formations
6 6 1 4 1 18
1 6 2 1 10
GEOLOGIC
Onshore depleted oil and
gas reservoirs
Offshore depleted oil and
gas reservoirs
5 1 6
0
Enhanced oil recovery 26 3 2 3 34
STORAGE
OTHER
Enhanced gas recovery 0
Other reuse 0
Combination/ TBD 1 1 2 2 6
Key: ≥ 10 projects 3-9 projects 1-2 projects No projects
PROJECTS
29

CASE STUDY
Gorgon Carbon Dioxide Injection Project
Significant progress is being made on the AU$2bn Gorgon Carbon Dioxide Injection Project since the
Chevron-operated project passed its FID in September 2009, a milestone that represented the culmination
of almost two decades of studies and a significant pre-investment.
Initial consideration of managing the Gorgon Project’s reservoir CO 2
started in 1992, before the commissioning in
1998 of regional desktop studies seeking to identify potential storage sites within 300km of the proposed project
site. This work culminated in 2003 with the publication of the Environmental, Social and Economic Review of the
Gorgon Gas Development on Barrow Island (ESE Review), which voluntarily proposed that reservoir CO 2
be injected
into the Dupuy Formation below Barrow Island and provided ongoing studies confirmed it was technically feasible
and not cost prohibitive. The Dupuy Formation was favoured as some 27 nearby well penetrations and existing 3D
seismic coverage indicated suitable geology to permanently trap the injected CO 2
.
The Gorgon Project is operated by Chevron Australia and is a joint venture of the Australian subsidiaries of Chevron
(approximately 47 per cent), ExxonMobil (25 per cent), Shell (25 per cent), Osaka Gas (1.25 per cent),
Tokyo Gas (one per cent) and Chubu Electric Power (0.417 per cent).
Legislative development
Shortly after publication of the ESE Review it was recognised that there was no legislation to enable government
to approve the proposed injection operations. To address this gap, the Barrow Island Act 2003 (WA) was passed
by the Western Australian Parliament in late 2003. The Act contains provisions dealing with the conveyance and
underground disposal of CO 2
and is believed to be the world’s first GHG storage legislation. The provisions in
the Act are brief but enable the Minister to place conditions on the approval. In effect, the Ministerial conditions
establish the regulatory framework under which the project must operate. This was done intentionally, as in
2003 it was not fully understood what issues would require regulation. Barrow Island Act 2003 approvals for the
underground disposal of reservoir CO 2
were obtained at the same time as the Gorgon Joint Venture made its FID
in 2009. A key component of the approvals imposed by the Minister is the requirement for a Site Management
Plan. This document outlines how all aspects of the project will be undertaken. The concept of a site
management plan has been subsequently adopted in the Australian Offshore Petroleum and Greenhouse Gas
Storage Act 2006 (Commonwealth).
Environmental approvals
Prior to FID, environmental approvals were required under the Environmental Protection Act 1986 (WA)
and the Environmental Protection and Biodiversity Conservation Act 1999 (Commonwealth). In September
2005, the Gorgon Joint Venture published its Environment Impact Statement and Environmental Review
and Management Plan (EIS/ERMP) for a 10Mtpa liquefied natural gas (LNG) project on Barrow Island.
Importantly, this document represented the first publication of an environmental impact assessment for a
major GHG storage project. This document detailed the nature of the geology below Barrow Island, how GHG
storage works and how the injected CO 2
becomes trapped. It also outlined risks and potential impacts on
environmental receptors. An important aim was producing a document with sufficient background data for
the general public, as well as scientific community, to have confidence in the project’s assessment of the
environmental risk associated with the injection and storage of CO 2
. Following public submissions to the
EIS/ERMP, both Federal and Western Australian environmental approvals were granted in October 2007.
Shortly after receiving these environmental approvals, the Gorgon Joint Venture made the decision that they
wished to expand the scope of the project from 10Mtpa LNG to 15Mtpa LNG. This required the original
environmental impact assessment process to be revisited, including a revision to the risks study published
previously. Federal and WA approvals for the expanded project were obtained in August 2009.
Throughout this process it was recognised that, despite the existing well penetrations and 3D seismic, significant
additional data collection was required in order to improve the geological understanding of the proposed injection
location. Indeed, the data required was comparable to the field appraisal activities that would be undertaken to
appraise an oil and gas discovery.
30 THE GLOBAL STATUS OF CCS: 2011

Case study, Gorgon Carbon Dioxide Injection Project continued
Since 2003 the Gorgon Joint Venture has invested over AU$150 million in storage appraisal. This included the
drilling of a data well in which the entire 300 metre reservoir section and overlying seals were cored, conducting
extensive well testing and a series of seismic acquisition pilots including the acquisition of a new 3D seismic survey.
Throughout this period the Western Australian Government undertook a series of independent expert reviews
to assure the quality of the technical work being undertaken by the Gorgon Joint Venture. These assurance
(or due diligence) reviews were timed to provide independent advice to government at the time it was making
important decisions about the project.
Since FID, work has continued on refining the project’s geological and dynamic simulation models and
planning for the commencement of the drilling of the injection and pressure management wells in late 2012.
The design of the wells is largely complete and contracts are currently being negotiated for the drilling rig
and associated equipment to drill these wells.
CHAPTER 2
Following FID, one of the first contracts to be awarded was for the detailed design, construction and assurance
testing of six CO 2
injection compressor trains at a cost of AU$415 million. The compressors represent a
significant piece of equipment with two compressors coupling together to form a module more than five stories
high (Figure 20). Each compressor will be equipped with a four stage compressor comprising two compressor
casings (each casing comprising two compressor stages) coupled through gearboxes on either side of a
double-ended variable frequency drive electric drive motor. Intercoolers/aftercoolers will be installed after each
compression stage. Factors requiring consideration in designing the compressors include:
••
ergonomic design focusing on improving maintenance and operational access;
••
equations of state for the CO 2
rich gas stream;
••
the presence of incidental associated substances in the CO 2
stream;
••
compressor aerodynamics, rotodynamics, material selection, drive technologies, system integration and
maintenance factors;
••
each compressor train is designed to be modularised and must meet very stringent space constraints;
••
the ability to control the 3rd stage discharge pressure to within the range of 50 to 65 bar to allow
the maximum dropout of liquid water as part of measures to manage corrosion downstream of the
compressors; and
••
the need to minimise fugitive emissions around the compressor seals.
Figure 20 Layout of Gorgon CO 2
compressor train
Image courtesy of Chevron Australia
PROJECTS
31

Case study, Gorgon Carbon Dioxide Injection Project continued
Once the first compressor train has been constructed it undergoes a full speed full load validation test in a
purpose designed and built test loop using CO 2
as the test gas. The main focus of these tests is to validate
the expected mechanical performance (torsional response, vibration, bearing temperature, and so on)
and thermodynamic performances in terms of developed differential pressure, efficiency and absorbed power
for each state. The test will maximise the use of the actual contract components including lubrication oil systems,
electric motor controls and the compressor seal equipment. The full-speed, full-load, string testing commenced
validation testing in June 2011.
Each compressor is then integrated into a module including all necessary pipe work and intercoolers before
shipping to the project site on Barrow Island. The first compressor module is due to arrive on Barrow
Island in the second half of 2013.
The lead time to undertaking the detailed design, construction and full speed, full load testing of the CO 2
compressors is significant and reinforces the long lead times and investment requirement to successfully
execute a GHG storage project of this scale.
The Australian Government has committed $60 million to the Gorgon Project as part of the Low Emissions
Technology Demonstration Fund (LETDF).
32 THE GLOBAL STATUS OF CCS: 2011

3
TECHNOLOGY
3.1 Capture 34
3.2 Transport 47
3.3 Storage and use 54
3.4 Technology costs and challenges 65

3 TECHNOLOGY
KEY MESSAGES
• It is vital that power projects proceed to demonstrate CCS on a commercial-scale and operating in an
integrated mode, in a real power grid environment and with storage at sufficient scale to provide the
confidence and benchmarks critical for future widespread deployment.
• In capture, while there have been component level technological improvements and promising new capture
concepts, more capture facilities scalable to commercial levels need to enter development planning to
support the technological advancement and cost reductions needed for deployment.
• While transport of CO 2
by pipeline is a well established technology, the scale of infrastructure and
investment required for future CCS deployment will be a challenge but it is not insurmountable. In addition,
significant economies of scale can result from shared transport infrastructure.
• Project developers need to build long lead times into project planning for storage site assessments,
especially for greenfield deep saline formation storage sites. Understanding the storage risks over the
lifecycle of the project and post-closure will lead to safer and more efficient outcomes.
While the focus in this report is on LSIPs, the different components of the CCS chain all have separate challenges and
are themselves made up of several different technologies that can be used in various combinations in any given project.
This chapter reviews the different components of CCS and provides an update of their current status of development.
The overall focus of government and industry efforts on CCS is to demonstrate the integration of the different components
at large-scale across a range of industries and technologies. At the level of individual components of the CCS chain, the
challenges are more related to continuing R&D to achieve process and technology improvements, efficiency gains or cost
reductions and a better understanding of options.
Each of the different components of the chain, being capture, transport and storage or use, is treated separately,
including a discussion of their costs. This chapter concludes with a discussion of current understanding of the overall
costs of applying CCS, particularly in power generation.
3.1 Capture
Capturing CO 2
that would otherwise be emitted to the atmosphere, treating it and compressing it to the point where
it can be transported, in most cases represents the greatest component of the additional costs of CCS. This section
outlines the current status of development of the various capture technologies and techniques, across the different
industries in which CCS can be applied. Further details can be found in a study commissioned for this report by
the Electric Power Research Institute (EPRI 2011a) as well as a series of studies produced by the United Nations
Industrial Development Organization (UNIDO 2010a, b, c, 2011) as part of a project sponsored by the Institute and
the Norwegian Ministry of Petroleum and Energy.
34 THE GLOBAL STATUS OF CCS: 2011

Major technology options for CO 2
capture
The main technology options for CO 2
capture from fossil fuel usage are:
••
post-combustion capture (PCC) from combustion flue gas;
••
pre-combustion capture from fuel gases; and
••
oxyfuel combustion – the direct combustion of fuel with oxygen.
These three approaches are shown for coal-based power systems in Figure 21.
Figure 21 Technical options for CO 2
capture from coal-power plants
Post-combustion
Coal
Power and heat
N 2
CO 2
separation
CHAPTER 3
Air
Pre-combustion
Air/O 2
Steam
CO 2
CO 2
Coal
Gasification
Shift , gas cleanup
+ CO 2
separation
Air
H 2
N 2
Power
and heat
CO 2
compression
and
dehydration
Oxyfuel combustion
Air
Air separation
Coal
Power and heat
O 2
O 2
CO 2
Source: EPRI (2011a, p1-1)
PCC can be applied to newly designed fossil fuel power plants, or retrofitted to existing plants. Absorption processes
are currently the most advanced of the PCC technologies. The PCC technologies can also be used in other industries
including cement, oil refining, and petrochemicals.
Pre-combustion capture in IGCC power plants comprises gasification of the fuel with oxygen or air under high pressure,
followed by CO 2
removal using an acid gas removal (AGR) process. The resulting hydrogen rich synthesis gas (syngas)
is supplied to a gas turbine power block. The pre-combustion capture of CO 2
using AGR processes is also practised
commercially in oil, gas and chemicals plants.
Oxyfuel combustion is the combustion of fuel with oxygen, instead of air, to eliminate the nitrogen contained in combustion
air. The flue gas containing mostly CO 2
is cleaned, dried and compressed. In a coal-fired oxyfuel power plant some flue
gas is recycled to use in the oxygen-fired boiler, effectively replacing nitrogen from air to keep the temperature at a level
acceptable for boiler tube materials.
Within each of the three major capture categories there are multiple pathways using different technologies which
may find particular application more favourably in certain climate conditions, locations and fuel types.
TECHNOLOGY
35

Technology readiness level
In this section the term Technology Readiness Level (TRL) will be used to indicate the development level of the
technologies described (WorleyParsons et al. 2009). This TRL approach can be particularly useful in tracking the status
of individual technologies in the earlier stages of the R&D timeline. The nine TRLs are listed in Table 4.
Table 4 Technology Readiness Levels (TRLs)
READINESS LEVEL
TRL-9
TRL-8
TRL-7
TRL-6
TRL-5
TRL-4
TRL-3
TRL-2
TRL-1
DESCRIPTION
Full-Scale Commercial Deployment
Sub-Scale Commercial Demonstration Plant (>25 per cent commercial-scale)
Pilot Plant (>5 per cent commercial-scale)
Process development unit (0.1-5 per cent of full-scale)
Component Validation in relevant environment
Laboratory Component Testing
Analytical, ‘Proof of Concept’
Application Formulated
Basic Principles Observed
The achievement of a given TRL will inform process developers and organisations of the resources required to achieve
the next level of readiness. An achievement of TRL-9 indicates that the first successful operation at a scale normally
associated with commercial deployment has been achieved. Progressively higher technical and financial risks are
required to achieve the TRLs up to and including TRL-9.
It is important to note that the description in TRL-9 of ‘commercial deployment’ refers to the physical scale of deployment
(that is, at the scale required in a commercial application). Thus, a technology may reach TRL-9 and be technically
mature and still not meet project economic requirements in existing markets. The TRL system does not address the
commercial or economic feasibility of deploying the technology (EPRI 2011a).
In this context the TRL classification is not intended to express overall project development risk. This is project specific
and progress on first-of-a-kind projects may be influenced by the extent to which sophisticated project proponents have
gained confidence in technology components and their ability to integrate these into a viable process. This may mean
the project proponent may select a particular technology component with a lower TRL if the project specific business
case is better than an alternative technology component with a higher TRL.
Figure 22 summarises the current technical readiness of some of the main capture technologies.
Figure 22 Summary of TRL for capture technologies
Post-combustion capture
Pre-combustion capture
Hydrogen red gas turbine
Oxyfuel combustion
1 2 3 4 5 6 7 8 9
Technology Readiness Level (max. 9)
Source: EPRI (2011a)
36 THE GLOBAL STATUS OF CCS: 2011

In recent years, ‘full-scale’ coal-fired power plants purchased by utilities have a new capacity exceeding 400MWe and
mostly greater than 600MWe. For the purposes of a TRL assessment of advanced coal technology, it is suggested that
TRL-9 would be achieved by a power plant in the capacity range 400 to 800MW(net). By this metric, successful operation
of Kemper County air blown IGCC with capture (582MW) would achieve TRL-9 for this particular technology, while
Boundary Dam (110MWe) using amine based PCC and FutureGen 2.0 (200MWe) using oxy-firing would achieve
TRL-8 for these technologies.
These TRLs for carbon capture generally indicate the technologies are in the late development and early demonstration
stage overall in relation to power generation, with some applications more advanced than this. By contrast, there is
no TRL ranking available for renewable technology. However, an assessment of technology deployment by EPRI
indicates that, by way of example, some solar technologies using molten salt are in the late development phase, while
concentrating photovoltaics are in the early demonstration phase. Onshore wind (less than 3MW capacity) is a mature
technology while large-scale offshore wind technologies using fixed foundations in greater than 30 metres water depth
are also in the demonstration phase. Large-scale floating platform offshore wind systems are in very early development.
CHAPTER 3
In natural gas or chemical processing, carbon capture is a mature technology. This maturity is reflected in the number
of active industrial projects in the Execute or Operate stage (Figure 23). The less mature status of capture technologies
when applied to the power sector is evident, with most projects in the planning stages (Identify, Evaluate or Define).
Figure 23 Applications of capture technologies to LSIPs
Power generation
Pre-combustion capture
Post-combustion capture
Oxyfuel combustion capture
Various/not speci ed
Industry
Pre-combustion capture
Industrial separation
Number of projects
5 10 15 20 25 30
Planned
Execute
Operate
Projects in the natural gas or chemical processing industries produce a relatively pure CO 2
by-product stream suitable
for storage, while power projects carry the significant additional costs of installing capture equipment for separation of
CO 2
from the combustion gases or synthesis gas.
For power generation no single CO 2
capture technology outperforms available alternate capture processes in terms of
cost and performance (Finkenrath 2011). The range of applications worldwide, be it for new build or retrofit, for the many
types of coal and natural gas fuels, combined with the local geographical, business, commercial, public acceptability and
regulatory conditions means that all three methods, appropriately integrated into power generation plants will ultimately
be required.
Post-combustion capture
Power sector PCC applications
In the case of coal-based power, a typical PCC process is shown in Figure 24. Coal is combusted in air and the liberated
heat is converted to electricity by steam-driven turbines connected to generators. The combustion results in a flue
gas mixture which is treated using existing pollution control technologies to reduce or eliminate oxides of nitrogen and
sulphur, and ash. A PCC process then aims to selectively separate CO 2
from the remaining gas mixture, which can be
done at relatively low concentrations, in the range five to 15 per cent. PCC has the advantage in that it can be retrofitted
to existing plants, where its end-of-pipe nature provides the potential flexibility to operate without capture if required
by market conditions.
TECHNOLOGY
37

Figure 24 Typical post-combustion capture process for power generation
Fresh water Reduces NO x
Reduces ash Reduces sulphur Captures CO 2
Coal
Air
Pulverised
coal boiler
Selective
catalytic
reduction
Electrostatic
precipitator
Flue gas
desulphurisation
CO 2
removal
Flue gas
to stack
Steam
turbine
Power
Fly ash
Gypsum/waste
CO 2
for
compression and
storage, EOR,
or other use
Source: EPRI (2011a, p2-1)
The three main PCC processes are:
••
Absorption: the uptake of CO 2
into the bulk phase of another material, for example dissolving CO 2
molecules into
a liquid solution. Virtually all near-term and mid-term PCC processes under development are absorption based.
••
Adsorption: the selective uptake of CO 2
molecules onto a solid surface. The adsorbent selectively adsorbs CO 2
from
the flue gas, and is then regenerated by lowering pressure and/or increasing temperature to liberate the adsorbed
CO 2
. A claimed advantage of adsorption is that the regeneration energy should be lower relative to absorption solvents.
••
Membranes: the separation of CO 2
from flue gas by selectively permeating it through the membrane material.
Like adsorbents, membranes are claimed to potentially offer low energy capture processes.
There are currently no LSIPs operational in the power sector utilising PCC technology, although Boundary Dam with
PCC is under construction, with planned operation in 2014. While there are no others under construction at this scale
there are 16 PCC power projects in the planning stages (Appendix C).
PCC technologies for power generation are derived from commonly available amine absorption processes which are
currently at a relatively small scale. Considerable re-engineering and scale-up is needed to apply these commercially.
Technologies that can be considered near-term, all utilising the absorption process, have been tested at scale on
slipstreams no larger than five to 25MWe from coal-fired power plants.
Adsorbent and membrane technologies promise improved energy consumption, but these are in the earlier phases
of development (Figure 25). Adsorption processes for PCC are still in the small-scale kW range of demonstration while
little data exists on membrane systems for PCC, for which testing has been conducted at scales less than one tonne per
day with results that are not yet publicly available (Freeman and Rhudy 2007; Bhown and Freeman 2008, 2009, 2010).
Figure 25 Post-combustion capture TRL rankings
Absorption
Adsorption
Membrane
1 2 3 4 5 6 7 8 9
Technology Readiness Level (max. 9)
Source: Data from Freeman and Rhudy (2007) and Bhown and Freeman (2008, 2009, 2010)
The major challenges in PCC and much of the R&D trends revolve around the relatively large parasitic load CCS
imposes on a power plant, mainly due to capture and compression. Hence, development of new solvent chemistry,
new process designs, and novel power plant integration schemes are largely aimed at reducing the parasitic load of
CCS. Early-stage research is also being conducted into more novel chemistries (EPRI 2011a).
Figure 26, incorporating data from EPRI, shows the potential to improve the energy demand from PCC technologies for
a new build 595°C power plant using Powder River Basin (PRB) coal with various improvements in solvent regeneration
energies of an aqueous amine solvent (Dillon et al. 2010). The final bar shows that increasing the steam temperature to
705°C with an advanced amine solvent increases the net plant efficiency.
38 THE GLOBAL STATUS OF CCS: 2011

Figure 26 Projected performance of post-combustion capture technologies
Technology improvements
Base power plant
With full post-combustion capture
Add improved amine
Add advanced amine
Add advanced ultra-supercritical boiler
24 26 28 30 32 34 36 38 40 42
Thermal efficiency (per cent)
Source: Dillon et al. (2010) as cited in EPRI (2011a, p4-13)
CHAPTER 3
Efficient integration of PCC into existing power plants to effectively utilise waste heat is a high priority if retrofit is to be
viable for older plants. Recent studies show that even for lower efficiency power plants the opportunity exists to significantly
reduce parasitic energy use, because the capture process provides a sink for low temperature waste heat which was
uneconomic to recover in a power plant without capture. Such modifications utilise existing heat exchange technology
and in fact could be applied in near-term demonstration scale projects (Harkin et al. 2010).
There are also process operational challenges. Steam extraction for solvent regeneration reduces flow to the low-pressure
turbine with significant power-plant production and operational impact. In addition, water use is increased significantly
with the addition of PCC, particularly for water cooled plants. These situations will improve as the energy efficiency of
capture improves.
The IEA Greenhouse Gas R&D Programme (IEAGHG) has identified the need to better understand the environmental
impact of emissions from PCC. Some absorption based PCC processes use organic bases, amines, in an aqueous solution
which react with CO 2
present in the flue gas. It is recognised that certain flue gas components form by-products which
result in a loss of absorbent and an increase in operating costs. Pre-treatment of the flue gas can limit the absorbent losses.
In Europe, it is now recognised that atmospheric emissions from amine based PCC processes must be fully understood
and quantified as part of PCC deployment on a large scale, signalling the need for increased research in this area.
Non-power PCC applications
For oil refineries, the two most developed technologies likely to be used for emissions reduction from process heaters
(and utility boilers) are PCC and oxyfuel combustion. There has been limited development recently regarding PCC in oil
refinery applications. In one scenario the 196 000 barrel a day Grangemouth refinery in Scotland studied capture of the
CO 2
emissions from the fired heaters and boilers on the site (UNIDO 2010a).
PCC in cement manufacture is an ‘end-of-pipe’ option that would not require fundamental changes in the clinker-burning
process and so could be available for new kilns and in particular for retrofits to existing plants. In addition to absorption
and membrane technologies, another area of promise in cement is carbonate which is an adsorption process in which
calcium oxide is put into contact with the combustion gas containing CO 2
to produce calcium carbonate from which the
CO 2
is then released to yield calcium oxide, hence closing the loop. This is a technology currently being assessed by
the cement industry as a potential retrofit option for existing kilns and in the development of new oxy-firing kilns.
It is understood that pilot projects are being discussed within the cement industry but there have been few public
announcements. Research on CCS within the cement sector is still at an early stage, with these activities focused
on both post-combustion and oxyfuel combustion capture technologies (UNIDO 2010b).
Pre-combustion capture
Pre-combustion capture has application for power generation, oil, gas and chemicals and where not otherwise noted
this section references Booras (2011).
Current commercially available pre-combustion CO 2
capture processes are based on the use of solvents. There are two
major generic types of CO 2
removal solvents for pre-combustion capture – chemical and physical. Typically all the solvents
can accomplish greater than 90 per cent CO 2
removal. Pre-combustion capture of the CO 2
under pressure incurs less of
an energy penalty (around 20 per cent) than current PCC technology (around 30 per cent) at 90 per cent CO 2
capture.
TECHNOLOGY
39

Pre-Combustion Capture Applications
CO 2
capture from oil, gas and chemical industries
The oil, gas and chemical industries have been separating CO 2
from gas streams for decades at commercial scale.
Many of the world’s sources of natural gas contain CO 2
. In most cases the CO 2
must be removed to meet the purity
requirements of the gas customers.
Steam methane reforming, autothermal reforming and partial oxidation (with oxygen) are widely used commercially
for the production of hydrogen and chemicals such as ammonia and methanol from natural gas, refinery gas, propane,
butanes or naphtha. The CO 2
can be removed by using commercially available pre-combustion capture solvent
processes.
The gasification of coal, petroleum coke and heavy oils with oxygen is in widespread commercial use for the production of
chemicals such as ammonia, urea, methanol, dimethyl ether, SNG, gasoline and other transportation fuels. CO 2
removal
from coal gasification derived synthesis gas (syngas) is a mature commercial process widely practised throughout the
world. Again, the CO 2
can be removed by using commercially available pre-combustion capture solvent processes.
CO 2
capture from IGCC power plants
An IGCC plant is a facility which gasifies carbonaceous material (fossil or biomass or both) to produce a syngas which is
sent to a combined cycle gas turbine to generate electricity. The gasification and combined cycle sections are integrated
with each other to improve thermal efficiency. There are several IGCC plants in operation in several countries but to date
none of them has incorporated CO 2
capture.
In an IGCC plant CO 2
capture is accomplished by chemically modifying the syngas (using a catalytic process known as
a ‘shift’ which produces hydrogen and CO 2
), then removing CO 2
using commercially available pre-combustion capture
solvent processes. In the event of a need to vent the CO 2
, additional purification may be needed to remove other
associated substances.
If CO 2
capture was to be retrofitted to an IGCC plant that did not envisage the future addition of capture there are
additional cost and performance penalties over a new built plant with capture. The extent of cost and performance
penalties is highly dependent on the gasification technology and the type of syngas treatment deployed.
For an IGCC plant with capture based on current technology the TRL of the major components is listed in Figure 27.
While many of the component technologies are considered mature, there is an underlying need to construct and
operate at commercial-scale IGCC facilities with carbon capture to demonstrate the host power-generation technology
integrated with capture.
Figure 27 TRL of pre-combustion capture components
Chemical capture solvents
Physical capture solvents
ASU/gasification/shift/sulphur removal
Hydrogen- red gas turbines
CO 2
compression/drying
1 2 3 4 5 6 7 8 9
Technology Readiness Level (max. 9)
Source: EPRI (2011a, p3-5)
40 THE GLOBAL STATUS OF CCS: 2011

Pre-combustion CO 2
capture – development pathway
The major thrust in research, development and deployment for IGCC designs with capture is to reduce the energy
penalty. While the additional capital cost of capture equipment is not insignificant, it is net power output loss that is
the most significant economic detriment of capture addition (EPRI 2011a).
EPRI and the United States DOE have identified a roadmap (Schoff 2011) of IGCC technology developments that
can potentially improve the IGCC efficiency (with capture) to a level that matches or exceeds that of the current IGCC
technology without capture, as illustrated in Figure 28. Other efficiency improvement paths are possible with other
combinations of technology enhancements for a range of different IGCC technologies.
Figure 28 IGCC developments to recover energy losses from CO 2
capture
Technology improvements
Base power plant
With full IGCC and capture
Add G Frame gas turbine
Add membrane-based air separation unit
Add coal feed as CO 2
slurry
Add advanced CCS
CHAPTER 3
24 26 28 30 32 34 36 38 40 42
Thermal efficiency (per cent)
Source: Schoff (2011) as cited in EPRI (2011a, p3-11)
Oxyfuel combustion with CO 2
capture
In oxyfuel combustion processes, bulk nitrogen is removed from the air before combustion. The resulting combustion
products will have CO 2
content up to about 90 per cent (dry basis). If regulations and geochemistry permit, the raw,
dehydrated flue gas may be stored directly without the need for further purification. Otherwise, the flue gas impurities
(predominantly oxygen, nitrogen and argon) may be removed. The added process equipment consists of equipment
largely familiar to power plant owners and operators. No chemical operations or significant on-site chemical inventory is
required. As a different technology can be used for final clean up, the incremental cost (per tonne) to capture at least
98 per cent CO 2
is lower than the incremental cost to capture 90 per cent CO 2
. Current information indicates that oxyfuel
combustion with CO 2
capture is at least competitive with pre and post-combustion CO 2
capture and may have a slight cost
advantage (EPRI 2011a).
Oxyfuel combustion plants will include the following major component systems:
••
Air Separation Unit (ASU) – This system separates oxygen from air and supplies the oxygen for combustion;
••
Combustion/Heat Transfer/Gas Quality Control system – The components of this system are nearly the same as
components for a corresponding air-fired plant; and
••
CO 2
Purification Unit (CPU) – The CPU will include a flue gas drying sub-system and compressors. If required,
it will also include a partial condensation process to purify the product CO 2
and remove impurities to specified levels.
In addition, there will be material handling and thermal power utilisation systems, but these are unlikely to differ significantly
from their air-fired counterparts. Plot space requirements are significant for the ASU and CPUs.
Oxyfuel combustion may be employed with solid fuels such as coal, petroleum coke, and biomass, as well as liquid and
gaseous fuels. Ultra-low emissions of conventional pollutants can be achieved largely as a fortuitous result of the CO 2
purification processes selected, and at little or no additional cost.
TECHNOLOGY
41

Oxyfuel combustion applications and status
Oxyfuel process for power generation
A ‘synthetic air’ approach is generally used for oxyfuel combustion processes proposed for steam-electric power plants.
In the synthetic air approach, flue gas is recycled and introduced with oxygen in proportions that mimic the combustion
and heat transfer properties of air.
The gross power production (turbo-generator output) from an oxy-fired power plant will be essentially the same as a
comparable air-fired power plant. However, the oxy-fired plant will have increased auxiliary power use. This will reduce
the net power production (by approximately 23 per cent) and decrease net efficiency compared to an air-fired plant
with comparable gross output (EPRI 2011a).
The TRL of oxyfuel component technologies is shown in Figure 29.
Figure 29 TRL for oxyfuel combustion components
ASU
Oxy- red boiler
CO 2
puri cation
CO 2
compression/drying
Oxy- red boiler with capture
1 2 3 4 5 6 7 8 9
Technology Readiness Level (max. 9)
Source: EPRI (2011a, p4-10)
The greatest remaining technical challenge is integrating these systems into a complete steam-electric power plant.
There is an underlying need to construct and operate an oxyfuel power generation facility with carbon capture at
commercial scale to demonstrate the host power generation technology integrated with capture.
Two integrated oxyfuel combustion pilot plants (TRL-7) have been operated over the past two years. Vattenfall has
operated a dried lignite-fuelled 30MWth pilot plant at their Schwarze Pumpe power plant in Germany since mid-2009
and Total’s Lacq project in France, an oxy-natural gas 30MWth boiler has been in service since early 2010. Two additional
facilities will be brought into service in 2011, the CS Energy conversion of a 30MWe pulverised coal power plant to oxyfuel
combustion in Queensland, Australia and CIUDEN’s oxy-coal test facility in Spain that includes a 20MWth oxy-pulverised
coal (PC) boiler and a 30MWth oxy-Circulating Fluidised Bed (CFB) boiler (EPRI 2011a).
Five larger scale demonstration plants (TRL-8) are in development worldwide. All of these are in the planning/engineering
stages and the decision to proceed to construction has yet to be made (Appendix C).
There are currently no full-scale (TRL-9) oxy-fired projects under development.
Oxyfuel process in other industries
Combustion in process heaters accounts for up to 60 per cent of an oil refinery’s CO 2
emissions. For an existing refinery,
all heaters and boilers on site would be modified for firing with pure oxygen, produced at a central location, and flue
gases from the combustion plants would be initially treated at locations local to the stacks (UNIDO 2010a).
Two different options for oxyfuel technology within the cement industry have been proposed (UNIDO 2010b).
Partial capture is based on burning fuel in an oxygen/CO 2
environment (with flue gas recycling) in the pre-calciner but
not in the rotary kiln in order to recover a nearly pure CO 2
stream at the end of one of the dual preheaters. Total capture
is based on burning fuel in an oxygen/CO 2
environment (with flue gas recycling) in both the pre-calciner and the rotary
kiln to produce a nearly pure CO 2
stream from the whole process.
Laboratory and process development unit activities are underway to achieve TRL-6 in 2011. Construction and operation
of an oxyfuel combustion cement manufacture pilot plant is planned in the 2011-2014 time frame, achieving TRL-7
(UNIDO 2010b).
42 THE GLOBAL STATUS OF CCS: 2011

Oxyfuel combustion future direction/challenges
An oxyfuel combustion power plant is an integrated plant and oxyfuel combustion technology development will require
commitment of the whole power plant to the technology. Thus, the technology development path for oxyfuel combustion
may be more costly than that for either pre-combustion or post-combustion capture which can be developed on slip
streams of existing plants.
While retrofit/repowering schemes have been proposed, it has yet to be shown that they can result in an oxy-fired plant
that is lower in cost than an optimised, new-build plant. The large fleet of air-fired power plants in service, however,
calls for more study of this option.
Future efficiency improvements to the oxyfuel combustion process for power generation include (EPRI 2011b):
••
employing an advanced ultra supercritical steam turbine cycle: 680oC/700oC/352 bar (1256oF/1292oF/5100psia),
for an approximately 3.5 percentage point improvement;
••
gas pressurised oxyfuel combustion – reduction of recycle fan auxiliary power use and improvement of boiler
efficiency, approximately 1.4 percentage point improvement; and
CHAPTER 3
••
Chemical Looping Combustion for oxygen separation – dramatic reduction of auxiliary power used in air separation,
approximately five percentage point improvement.
These data are shown in Figure 30. However, the benefits of both gas pressurised oxyfuel combustion and chemical
looping combustion may be difficult to achieve together. Nonetheless, chemical looping combustion combined with an
advanced ultra-supercritical steam turbine cycle may well be more than adequate to make up for the added auxiliary
power in the CO 2
purification unit and recycle fan. This could result in an oxyfuel combustion plant with near zero
emissions of conventional pollutants, up to 98 per cent CO 2
capture, and efficiency comparable to the best power
plants currently being built (EPRI 2011a).
Figure 30 Oxyfuel combustion developments to recover energy losses from CO 2
capture
Technology improvements
Base power plant
With oxyfuel combustion
Add advanced ultra supercritical boiler
Add pressurised oxy- red combustion
Add chemical looping combustion
24 26 28 30 32 34 36 38 40 42
Thermal efficiency (per cent)
Source: EPRI (2011a, p4-13)
TECHNOLOGY
43

Other industrial CO 2
capture
Most industrial CO 2
capture can be accomplished using the previously described pre-, post- and oxyfuel approaches
to carbon capture.
However, in the case of iron and steel manufacture, and biochemical biomass conversion, the combination of technologies
used in these industries does not neatly fit the strict pre-, post- and oxyfuel carbon capture approaches.
Iron and steel manufacture
There is no simple process available off the shelf that can currently accomplish low emissions in the iron and steel
industry (UNIDO 2010c).
Three families of process routes involving carbon capture are being investigated for eventual scale-up to a size suitable
for commercial implementation:
••
A blast furnace variant, where the top gas of the blast furnace goes through CO 2
capture, but the remaining reducing
gas is reinjected at the base of the reactor, which is operated with pure oxygen rather than air. This has been called
the Top Gas Recycling Blast Furnace (TGR-BF). The CO 2
-rich stream is sent to storage.
••
A smelting reduction process based on the combination of a hot cyclone and of a bath smelter called HIsarna,
incorporating some of the technology of the HIsmelt process. The process also uses pure oxygen and generates
off-gas which is almost ready for storage.
••
A direct reduction process, called ULCORED, which produces Direct Reduced Iron in a shaft furnace, either from
natural gas or from coal gasification. Off-gas is recycled into the process after CO 2
has been captured, which leaves
the plant in a concentrated stream and goes to storage (UNIDO 2010c).
In the nearer term, the TGR-BF technology seems the most promising solution, as existing blast furnaces can be retrofitted
to the new technology. Where natural gas is available, ULCORED is an attractive option, but requires the construction
of purpose-built new technology shaft kilns. For greenfield steel mills, the HIsarna process will also be an option.
The TGR-BF concept has been tested on a large-scale laboratory blast furnace with positive outcomes. For the ULCORED
process, a one tonne per hour pilot is planned to be erected in the next few years by Luossavaara-Kiirunavaara Aktiebolag
(LKAB) to fully validate the concept. For the HIsarna process, an eight tonne per hour pilot is to be erected and tested
in the course of the ULCOS (Ultra Low CO 2
Steelmaking) program.
ULCOS has been running in the European Union (EU) since 2004. There are also other programs addressing this
challenge. Along with ULCOS, they are part of the CO 2
Breakthrough Program, a forum where the various national
and regional research and development programs on identifying breakthrough technologies for steel manufacture
can exchange information on their projects.
Biochemical biomass conversion
Biochemical biomass conversion processes, for example fermentation, use living microorganisms to break down the
feedstock and produce liquid and gaseous fuels. The CO 2
-rich off-gases from the fermentation tanks are dried and
compressed to facilitate transport and storage. However, CO 2
capture and storage from biomass-based industrial sources
is a mitigation technology that only receives little interest at present. There has been limited recent development regarding
capture in biochemical biomass conversion applications (UNIDO 2011).
A common first generation process to produce bio-ethanol is the fermentation of biomass, where a by-product is a
relatively pure stream of CO 2
. The CO 2
-rich off-gases are dried and compressed to facilitate transport and storage.
One of the first commercially operated ethanol plants integrated with CCS, and thus biomass-based industrial CO 2
capture and storage project, started operation at the Arkalon bioethanol plant in Kansas, United States, during the third
quarter of 2009 (UNIDO 2011). A similar pilot project in the United States, managed by the MGSC, is expected to start
operation in the second half of 2011. From the same CO 2
source as MGSC’s injection test project, the larger scale
Illinois-ICCS project commenced construction in 2011, with operation expected in 2013.
44 THE GLOBAL STATUS OF CCS: 2011

Pathway to commercial deployment of capture technologies
Important role of demonstration projects
Capture technologies applied in the current first-of-a-kind demonstration projects in the power industry are as yet far
from optimal in their performance. However, it is vital that such projects proceed urgently as they will demonstrate CCS
on a commercial-scale operating in an integrated mode, in a real power grid environment and with storage at sufficient
scale. Importantly, these will provide an understanding of the economics and performance of commercial scale plants
in an overall sense, providing the confidence that will be critical for future widespread deployment of the technology.
Optimisation and enhanced integration, combined with technology improvements, will undoubtedly be necessary to
reduce cost and improve performance at a system and component basis. Progress at the commercial CCS demonstration
scale has a key role to play in indicating the priority areas to be addressed and in providing the confidence for continued
investment in R&D for second and third generation technologies.
CHAPTER 3
If multiple CCS demonstrations with improved technologies and performance are to be achieved at large-scale (TRL-9)
by 2020 to address scaling uncertainties and allow commercial deployment to proceed at some time after that, then many
technologies need to be approaching the pilot-plant stage (TRL-7) today. Applications of CO 2
capture in the power sector
appear to be receiving enough funding to achieve pilot-plant scale, but advancing to sub-commercial scale demonstrations
and larger will require an order of magnitude greater level of funding. There are very few organisations funding
demonstrations at one-tenth to full commercial-scale. While this may not currently be constraining the advancement
of improved CCS technologies, it soon will (EPRI 2011a).
Each technology has particular implementation hurdles to overcome. Pre-combustion systems are ‘integrated’ by nature
and so operational problems in capture could impact on plant performance through lower reliability and availability.
Oxyfuel combustion systems also result in an integrated plant with potentially the same issues as pre-combustion
systems. There is also a need to improve boiler design/performance and to have lower-cost processes for oxygen
production. Although post-combustion capture can be retrofitted, significantly reducing the capital investment at risk,
there is a continuing need to reduce cost and the detrimental impact that the technology has on the performance of the
plant. These issues mean that PCC’s application to older subcritical plants may not be appropriate due to the current
high energy penalty increasing dispatch costs, thus impacting their capacity factor and reducing consequent revenue.
However, the ability to retrofit to newly installed plants or to be installed at high-efficiency plants will be a critical aspect
in ensuring that assets are not stranded and are able to operate in an increasingly carbon constrained world.
The emphasis in capture from power plants has been on coal but there is an increasing recognition that CCS will have
to be applied to natural gas-fired plants as well. The relatively recently identified increase in worldwide gas reserves
(exemplified by shale gas) will mean that there will be a greater use of gas and for longer. If the desired levels of atmospheric
CO 2
are to be achieved by 2050, CCS will have to be applied to gas-fired power plants as well as those using coal.
Importance of improving performance
Cost reductions for all types of capture remain paramount and key technology development actions are increasingly
focused on this issue, both for capital and operating costs. The detrimental impact of capture on the performance of
a power plant, combined with the high cost issue, remains another key area to be addressed.
The cost per tonne of CO 2
avoided for each of the technology types when applied to power generation with coal is
shown in Figure 31. The reference plant used for each case is a commercial supercritical PC plant. The fuel component
represents the portion of the CO 2
abatement cost attributable to the additional fuel charges necessary to operate carbon
capture relative to the reference plant. The figure suggests that a focus on reducing energy loss is warranted, with significant
potential improvement possible, particularly for PCC. Given the uncertainties involved, at this stage it is difficult to identify
any single technology with a clear cost advantage.
TECHNOLOGY
45

Figure 31 Cost of CO 2
avoided for capture technologies
Oxyfuel combustion
IGCC
Post-combustion capture
10 20 30 40 50 60 70 80 90
US$/tonne
Capital costs Operating and storage costs Fuel costs
Source: Global CCS Institute analysis
The analysis in this section has been focused on CO 2
capture technologies and potential improvements to reduce the
energy losses and capital costs associated with capture. However, a major contribution to the reduction of CO 2
emissions
from fossil based plants will be achieved through increases in the efficiency of the basic technologies of pulverised
coal combustion and combustion (gas) turbines. Improving this best-available technology in an efficiency sense,
be it component and/or system based, will partially offset the energy impact of capture on the performance of the plant,
especially if second and third generation capture technologies are also embraced. Optimisation and integration on
a component and system level is a key area which will result in improvements in performance.
For all technologies, there is an underlying need to construct and operate commercial-scale facilities with carbon
capture to demonstrate the host power generation technology integrated with capture.
Within pre-combustion capture, there is a need to improve the CO-shift and CO 2
-capture with new adsorption media,
new catalysts and by optimising process integration.
For post-combustion capture, the emphasis needs to be on improving first generation solvents through catalysts
and chemical modifications to improve loading efficiency, solvent loss and environmental impacts. In addition,
second generation solvents need developing to combine CO 2
and SO 2
removal. Longer term third generation capture
processes are also needed based upon phase change solvents, ionic liquids and adsorption based developments.
For oxyfuel combustion there is a need for more efficient cycles, such as chemical looping for coal and oxy-cycles
for gas turbines, and for a reduction in the energy penalty for oxygen production.
CO 2
specifications and the impact of impurities need to be better understood as these affect the magnitude of CCS
deployed, especially in a hub concept that brings together CO 2
from different sources prior to storage.
Consequently, there are development routes for all the three main types of capture. In addition, the ability to retrofit
future generation technologies to an existing highly efficient plant that already has capture incorporated but still has
substantial residual life will also need to be understood. This would address the minimisation of ‘stranded assets’
within a power company’s portfolio.
Importance of R&D and pilot scale projects in technology development
Small to medium-sized technology demonstration projects, even if not fully integrated, provide a number of benefits
that materially support progress of CCS towards commercialisation. These projects are essential to decrease technical
uncertainty with modest investment, but also lay the foundation for building the regional familiarity, skills and capacity
necessary for the demonstration and deployment of CCS, including:
••
on-the-job learning opportunity for technicians, engineers, scientists and managers;
••
testing the legal and regulatory system and familiarising regulators with new technologies;
••
testing equipment and boundaries in a way that could not be contemplated at large scale;
••
providing opportunities for a real-world working relationship when pursued through an industry partnership;
••
comparative assessment of the progress of technology development; and
••
opportunity for real community engagement.
46 THE GLOBAL STATUS OF CCS: 2011

There is substantial activity being undertaken globally by research organisations, technology providers and industry to
test CCS technology at pilot scale under industrial conditions. These projects face significant financial hurdles. This type
of R&D is expensive when compared with laboratory scale activities, due to its scale, operating costs, insurance and
legal costs. It requires long-term funding, in the order of five to 10 years, with certainty of cash flows, and provision of
contingency allowance. These circumstances are not a neat fit with traditional R&D funding models. Long-term funding
support for CCS R&D pilot projects is an essential element for technology commercialisation.
Both demonstration at industrial scale and ongoing R&D focused on improvement of component performance is necessary
for successful technology evolution. The early demonstration projects will identify unanticipated construction and operating
problems through ‘learning by doing’. For these reasons, they are usually conservative in design. While ‘learning by doing’
can result in improvements over time, it may not provide the significant step changes in cost and performance required to
make CO 2
capture more economically viable (DOE NETL 2010b). R&D complementary to demonstration programs is
essential to promote step changes and manage the complexity and risk with new components so that they can contribute
to improved performance in the next generation of large-scale CCS projects.
CHAPTER 3
3.2 Transport
Transport of CO 2
from its place of capture to where it will be finally stored is a vital link in the CCS chain. While for some
projects the two sites may be almost co-located, requiring the CO 2
to be moved over very short distances point-to-point,
for most projects the transport will extend to tens or even hundreds of kilometres. As this distance increases, so does the
cost and, in many instances, so do the number of challenges that need to be met. These challenges include securing
rights-of-way and public acceptance as well as technological issues such as re-compression and monitoring.
It has been estimated that to support the 3 400 industrial scale CCS projects by 2050 in the IEA BLUE map scenario,
over 200 000km of pipeline would need to be constructed, at a cost of US$2.5 to 3 trillion (Insight Economics 2011).
This means that the transport of CO 2
will become an important industrial sector requiring very significant planning and
investment over a relatively short period of time. In addition, under certain conditions, some transport is likely to be
in specially designed and built ships.
In other industries there is extensive experience in moving very large quantities of liquids and gases over long
distances, by both pipeline and ship, for example in transporting natural gas and LNG. Specifically for CO 2
there are
many years of experience in building and operating pipelines and vessels for transport, particularly in the United States.
As a result, there is well developed knowledge of the necessary technology and experience in dealing with many
of the challenges that need to be addressed. However, it is the scale of the future CO 2
transport task that poses
a major challenge.
It is likely that full commercial deployment of CCS will rely on a complex transport infrastructure with many carbon sources
being linked to storage sinks through a shared network using pipelines and in some cases ships. Establishing such
networks will result in many environmental and commercial benefits but will require early and close cooperation between
all the stakeholders, in particular industry and governments.
Pipelines
Pipelines are—and are likely to continue to be—by far the main method of transporting the very large quantities of CO 2
involved in CCS. Pipelines generally are an established technology, both on land and under the sea. In the United States
alone there are approximately 800 000km of hazardous liquid and natural gas pipelines, in addition to 3.5 million kilometres
of natural gas distribution lines.
There are currently nearly 6 000km of pipelines actively transporting CO 2
, the large majority being in the United States
network (Figure 32). This network transports approximately 50Mtpa of CO 2
and has been developed over the past 40 years.
TECHNOLOGY
47

Figure 32 Existing and planned CO 2
pipelines in North America
CO 2
pipelines in North America
In service
Proposed
Different colours represent
different pipeline operations
CO 2
Sources
Source: Data supplied by Ventyx, United States Department of Energy’s National Energy Technology Laboratory and National Sequestration Database and
Geographic Information System
48 THE GLOBAL STATUS OF CCS: 2011

The scale of pipeline infrastructure needed to support CCS deployment in the United States is estimated to range from
approximately 8 000 to 21 000km (5 000 to 13 000 miles) in 2020 and from approximately 35 000 to 58 000km
(22 000 to 36 000 miles) in 2050 (Dooley et al. 2009; ICF International 2009). Given that the United States natural
gas industry built 33 521km (20 829 miles) of pipeline between 1998 and 2007 (EIA 2008), these CO 2
construction
rates seem achievable. While achievable, CO 2
pipeline development will compete for resources, training needs,
and commodities such as steel with other pipeline construction needs.
In Europe, the CO 2
Europipe consortium has estimated the total pipeline length required to meet the existing plans for
CCS development in the EU and Norway—using both onshore and offshore storage—would be around 2 300km by
2020, 15 000km by 2030 and 22 000km by 2050 (Figure 33, Neele et al. 2010). These estimates do not include the
pipeline length required for linking individual projects to the main pipeline grid. According to the CO 2
Europipe report,
the countries with the largest amount of pipeline to be constructed are Germany, Norway and Poland mainly due to the
large quantities of CO 2
to be transported, requiring several parallel pipelines in some cases. However, France, the countries
around the Baltic Sea, the United Kingdom and Romania would need to be particularly active in the period to 2030.
In fact, for many EU Member States the largest effort in the construction of pipelines would be expected between 2020
and 2030, since the larger part of the network needs to be in place by 2030. For this scale of development the rate
of construction would need to be around 1 200 to 1 500km a year. As with the United States, Europe could meet this
pipeline construction capacity.
CHAPTER 3
Figure 33 European CO 2
transport corridors and volumes, CO 2
Europipe reference scenario 2050
Reference Scenario 2050
Indicative CO transport volumes (Mtpa)
2
Gas field clusters
Aquifer clusters
Source clusters
Source: Neele et al. (2010)
TECHNOLOGY
49

Clusters, hubs and networks
As mentioned previously, early mover projects are likely to rely mainly or exclusively on point-to-point transport through
dedicated pipelines. However, the estimates of future CO 2
transport capacities above take into account the development
of clusters, hubs and networks. The identification of potential clusters, hubs and networks is normally based on a
comprehensive review and matching of sources (CO 2
emitters) and sinks (CO 2
storage sites). Such work has already
been undertaken in many regions of the world and further studies are continuing.
Large-scale deployment of CCS should result in the linking of clusters of proximate CO 2
sources, through a hub,
to clusters of sinks by trunk pipelines. Then shorter collection, feeder or distribution pipelines would link the individual
sources and sinks into the network. A simple network would consist of a ‘tree’ where each of the branches represented
feeder pipelines from sources of CO 2
, the trunk of the tree would be the main CO 2
pipeline and the roots would be the
distribution pipelines linking to the various sinks.
There are significant economies of scale that can result from a shared infrastructure. A clustered transport system could
potentially save well over 25 per cent of expenditure compared to a point-to-point system, depending on the scale of the
cluster (McKinsey 2008; Mikunda et al. 2010). In addition, developing such a network can significantly reduce barriers
to future investment. The participation of multiple stakeholders and industries has the potential to develop business and
financing structures to underpin future commercial CCS markets. Networks can also encourage and increase the speed
of deployment in the region, for example by reducing the total number of permits that would need to be issued for pipelines.
As a result, creation of networks can reduce the financial risks associated with CCS projects and improve business cases
for individual CCS projects. Networks also open the opportunity to connect small emitters for whom point-to-point solutions
may be too expensive and to build up regional employment and expertise in the necessary technologies.
However, one major difficulty faced when establishing a network that initially invests in over-sized pipelines is that the
large investment needed can add considerable financial risk to early mover projects. While the spare pipeline capacity
is anticipated to eventually be taken up by new entrants, this risk needs to be understood, in particular by governments
when providing incentives for demonstration. This issue is also closely linked to that of third-party access to the
network pipeline infrastructure and the likely need to regulate such access. Finally, there can be issues related to the
composition of the gases, in particular the different incidental associated substances in the CO 2
stream that will vary
from source to source and how they interact when combined in the pipeline. All these issues require close cooperation
between all the different industrial partners and the local and national authorities. This needs to start early as timing can
be critical.
There are a number of hubs and clusters being proposed or developed in Australia, Europe and North America.
In Australia, the Collie Hub project is a joint venture which is currently being led by the Western Australian state
government working with its multiple industry partners. The Collie Hub is currently concentrating on its storage and
transport issues in order to progress the feasibility study. Work has commenced on the feasibility study for the pipeline
network that will support the project’s enabling and base cases. Provided the enabling case (test sequestration)
demonstrates that the target storage site is suitable for the long term storage of CO 2
the base case will proceed. The base
case first entails the capture of up to 2.5Mtpa of CO 2
from the proposed Perdaman ammonia and urea plant in 2015 and
the hub is then planned to further expand its capacity to up to 9Mtpa from coal-based industries in the Collie region.
Also in Australia, the CarbonNet CCS network, which is currently being led by the Victorian state government, is planning
to integrate multiple CCS projects and proponents across the entire CCS value chain within the next 10 years, and in doing
so progressively lower barriers to entry for new participants. Initially sized to capture and store 1.2Mtpa of CO 2
emissions
before 2018, the network will have the potential to scale-up to support over 20Mtpa thereafter, and potentially with further
growth to service Australia’s eastern seaboard.
In Europe, the most developed CCS network project to date is in the area around Rotterdam. RCI started in 2006 and
now 18 major companies are cooperating to provide feasibility level engineering studies for capture projects and a CCS
infrastructure business case (RCI 2011). There has also been a feasibility study conducted on the CO 2
Liquid Logistics
Shipping Concept that will provide emitters with a complete logistical transportation solution for captured CO 2
from their
site to an offshore storage location (Vopak and Anthony Veder 2011). Eventually the project aims to collect CO 2
from many
of the sources, collect it in an intermediate hub by means of a common transport infrastructure and then deliver the CO 2
by pipeline or ship to the end-user (including for EOR) or to store in deep geological formations under the North Sea.
Initially the network would scale-up rapidly from a demonstration phase starting capturing and storing around 2015 to
handling as much as 20Mtpa of CO 2
from the area by 2025. It is expected that the network will create economies of scale
and help lower the overall cost of CCS in the Rotterdam region.
50 THE GLOBAL STATUS OF CCS: 2011

Another important European network is developing in the South Yorkshire and Humber region of the United Kingdom.
This geographically relatively small region has many similarities with Rotterdam with several major carbon emitting
facilities (power plants, refineries and steel plants) in a relatively small area with good access to the North Sea. The total
emissions for the region are the highest in the United Kingdom at around 60Mtpa. Storage could initially take place in one
of two offshore clusters of gas fields and later in a saline aquifer in the northern sector of the southern North Sea. There is
also some EOR potential that could be realised in the region. A terminal for shipping of CO 2
could also be included in the
planning for export of CO 2
for use for EOR or for import of CO 2
for storage in the region. Three of the power plants in the
region have been put forward by the Government of the United Kingdom for support from the EU’s NER300 program.
In the United States, the approach to networks has been somewhat different with the emphasis being on identification,
characterisation and testing of potential large storage sites. In the United States the RCSP form the core of a nationwide
network to address climate change by assessing the technical and economic viability of various approaches for
capturing and permanently storing CO 2
. One of the Regional Partnerships—the Plains CO 2
Reduction Partnership
(PCOR)—also covers the important plains area of Canada (including the Weyburn-Midale site).
CHAPTER 3
Based on the outcome of the work of the Partnerships, regional pipeline networks are expected to be established which
could eventually become a national network. For example, one such regional network could be in the Midwest region
where, in the period 2020 to 2030, 2 282 miles (over 3 600km) of CO 2
trunk pipelines would be established to collect
CO 2
from as many as 95 relatively small high-purity sources and possibly eight power plants, and transport it to one of
three storage sites in the region. By 2040 basically the same pipeline network would be collecting CO 2
from the same
small sources but also from over 40 power plants. By 2050 the trunk pipeline network would have increased to around
4 300 miles (around 6 800km) and be capturing CO 2
from over 80 power plants.
The Integrated CO 2
Network (ICO 2
N) in Western Canada is a working group bringing together many large industrial
companies, including power plants and coal and oil sands producers. It is taking a lead role in advocating for the
development of integrated CCS infrastructure, whose benefits are expected to include the reduction of unit costs through
economies of scale, reduced infrastructure, and increased safety, as well as minimising environmental impact during
construction, standardising and streamlining development and easing the regulatory burden. Four CCS projects are being
developed in Alberta as part of the Government of Alberta’s CCS funding program. One of these is the development of the
Alberta Carbon Trunk Line, a pipeline system that will be used to collect CO 2
from different sources and deliver it for use
in EOR in central Alberta and then south to the Red Deer area (Figure 34).
Figure 34 Western Canadian CCS potential
Alaska
Yukon
Northwest Territories
Nunavut
British Columbia
Alberta
Saskatchewan
Manitoba
Operational Projects
1 Great Plains Synfuels
and Weyburn-Midale
Fort Nelson
5
Fort McMurray
Proposed Projects
2 Agrium Fertiliser with ACTL
3 Quest
4 Pioneer
5 Spectra Fort Nelson
6 Boundary Dam
7 Swan Hills Synfuels
8 Northwest Upgrader Refinery with ACTL
Legend
General EOR locations
Operational CO 2
pipelines
Proposed CO 2
pipelines
Potential CO 2
transport routes
Large CO 2
emissions locations
7
3
4 8
2
Edmonton
Lloydminster
Red Deer
Saskatoon
Calgary
Medicine Hat
Regina
Vancouver
1 6
Estevan
Washington
Montana
North Dakota
Beulah
Source: Integrated CO 2
Network; modified by the Global CCS Institute
TECHNOLOGY
51

Shipping
Though the majority of transport networks will mainly use pipelines, for some transport corridors ship transportation
can be an alternative option.
Shipment of CO 2
already takes place, but on a very small scale. At present, only four small ships transport food-quality CO 2
(around 1 000 tonnes) from large point sources to coastal distribution terminals in Europe. However, the shipment of CO 2
in larger quantities is likely to have much in common with the shipment of liquefied petroleum gas (LPG) or LNG, an area
in which there is already a great deal of expertise and which has developed into a worldwide industry over a period of
70 years. Design work on larger CO 2
carrier vessels is already underway in Norway and Japan. It is expected that the CO 2
carriers will be very similar in design to that of semi-refrigerated LPG carriers which carry their cargoes at temperatures
around minus 50°C. The likely capacities are in the range of 10 000 to 40 000m 3 (typically 20 000 to 30 000m 3 ).
The collaborative project, CO 2
Europipe, examined the relative merits of pipelines compared with shipping for CO 2
transport
(Neele et al. 2010). It concluded that shipping can play an important role in two types of projects:
••
at the start-up of CCS, deployed during the planning and construction of pipeline projects and infrastructures.
––
Once the pipeline(s) become(s) available, the ship(s) can either be redeployed into another trade, complement
the pipeline to mitigate network downtime risks, and/or seize opportunities in developing CO 2
storage in easily
accessible smaller capacity fields; or
••
for ‘shipping-only’ projects in which shipping is the most cost-effective solution.
The location of the source is important when deciding if shipping could play an important role in transport. Sources would
normally be near the coast so that the CO 2
can be immediately liquefied prior to being stored and loaded into the ships
(such as RCI); close to other CO 2
sources, thus increasing CO 2
supply capacity and decreasing the risk of ships being idle
(as is the case in the South Yorkshire/Humber cluster); or near an important inland waterway (CO 2
from inland sources near
the waterway can be collected in ships or barges and brought to the primary loading facility before being transported to a sink).
Shipping is generally an interesting option where sources will have a relatively low capture rate at start up but then
increase their volume over time, as shipping can adequately cope with fluctuating transport volumes. Concerning sinks,
relatively small offshore fields which are remotely located, and for which a connection to the pipeline network is not
feasible or economically attractive, may be assumed to be candidates for ship transport. However, such fields still need
to have sufficient storage capacity to support a shipping project for a minimum lifetime to justify the investments on the
subsea and port infrastructure enabling the ship to discharge at the fields. Injection rates also tend to be important
as fields with relatively low injection rates result in extended round trip durations which will decrease the feasibility of
transport by ship. As maximum injection rates generally decrease over time, due to the reservoir filling up, transport
by ship is expected to be more viable early in a storage site’s lifetime.
Comparing the unit costs of CO 2
transport between ships and pipelines would indicate that pipelines are the most
cost-effective solution when sources and sinks are located close to each other. With increasing distance, the cost of
pipelines (especially capital expenses) gradually increases and can make shipping an economically more competitive
solution (ZEP 2011). For the development of CO 2
projects, it can be assumed that trades with the shorter distance
between source and sink are developed first and implemented with a pipeline network. On the other hand, shipping
is a more flexible solution and a ship can serve several different sources or hubs and transport to different storage
sites. In Europe, where a great part of the potential storage is offshore both in and around the oil and gas fields of the
North Sea, growing attention is being paid to ship transport because of this flexibility, often linked to the use of CO 2
for EOR (even for fields with a relatively limited storage capacity).
While much of western Europe’s storage capacity is offshore, there is already an extensive network of oil and gas pipelines
under the North Sea, some of which may, in future, be used for transporting CO 2
. So, while shipping may eventually
play a significant role in transport in the region, it is likely that pipelines will continue to be the first choice solution
in most instances. This, however, is not the case in many countries that have major sources close to the coast but
do not have large potential storage areas in their surrounding seas. For example, in Japan ship transport may be the
preferred option.
The Institute is sponsoring a preliminary feasibility study by the Chiyoda Corporation and the University of Tokyo on
a CO 2
Carrier for Ship-based CCS. In Japan, as in many other countries, transportation of CO 2
by ocean going vessels
may provide an attractive and viable alternative to the limitations imposed by sink/source matching conditions in the
region. As also found by the CO 2
Europipe study, ship-based CCS provides flexibility in changing the capture site,
the transportation route and storage site in a CCS project. The flexibility of time, place and size of each project component
in the CCS chain provides for flexible decision-making by the stakeholders, thus bringing about a smooth introduction of
CCS in the area. This is particularly pertinent in a country where the oil and gas industry is relatively undeveloped or weak,
unlike in some regions where the industry has exploration data that can help in site selection. In addition, a transportation
52 THE GLOBAL STATUS OF CCS: 2011

network of ship-based CCS in the east Asian region might be attractive if ocean storage sites in this region are identified
to be at depths greater than 200m, where access by ship could be easier than access by pipeline.
The objective of the Chiyoda study is to demonstrate the technical and economic feasibility of a CO 2
shuttle ship equipped
with injection facilities. In such a system (Figure 35) no ocean platform (manned or un-manned) with buffer storage
would be necessary. In addition to providing a detailed engineering study for the vessel, its storage tanks, flexible pipe
mechanism, the pick-up buoy system and the relevant communication systems, the report will also review all relevant
international and national (Japanese) regulations covering offshore storage of CO 2
.
Figure 35 Ship-based CO 2
carrier: Submerged Loading System general arrangement
Pick up buoy
Satellite
CHAPTER 3
Pick up
rope
Pick up float
Messenger line
Transponder
Pick up wire
Sinker
Tele communication
CO 2
Carrier
Coupler winch
(Sheer mount)
Battery
Communication buoy
Riser end fitting
Mooring wire
Bend
Signal & Battery charging wire
Flexible riser + Umbilical cable
Bend restrictor
Pipe protector
Anchor Christmas tree
Image courtesy of Chiyoda and University of Tokyo
Cost of transport
A number of studies have been carried out on the cost of transporting CO 2
. Most of these cover pipelines but some also
cover shipping. The most recent study is that prepared by the European Technology Platform for Zero Emission Fossil
Fuel Power Plants (ZEP 2011).
The approach was to describe three methods of transportation and for each of these present detailed cost elements
and key cost drivers. The three methods are:
••
onshore pipeline transport;
••
offshore pipeline transport; and
••
ship transport, including utilities.
For each method of transportation, the capital costs and operating costs have been estimated using information
internally available to the members of ZEP. Calculations were made for the case of demonstration plants; when the
transport was for a demonstration project with a capacity of 2.5Mtpa of CO 2
and would be point-to-point (Table 5);
and for commercially deployed CCS in large-scale networks would be in the range of 10 to 20Mtpa from a cluster
of sources (Table 6).
In brief, ZEP found that the unit cost (in € per tonne of CO 2
) is significantly less during commercial deployment than
during the demonstration phase (typically 60 to 70 per cent less) for both onshore and offshore pipelines. Not surprisingly,
the cost of onshore pipeline transport is less than that for offshore pipelines. During the demonstration phase the
cost of offshore shipping is less than for offshore pipelines, though this is not the case where the distances are short
(below 200km) and the costs of liquefaction for shipping are taken into account. During commercial deployment where
quantities to be transported are in the 10 to 20Mtpa range, shipping is more expensive than pipelines for distances
of 1 500 km or less.
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Table 5 Transport cost estimates for CCS demonstration projects, 2.5Mtpa
DISTANCE (KM) 180 500 750 1500
Onshore pipe (€/t of CO 2
) 5.4 n/a n/a n/a
Offshore pipe (€/t of CO 2
) 9.3 20.4 28.7 51.7
Ship (€/t of CO 2
) 8.2 9.5 10.6 14.5
Liquefaction (for ship transport) (€/t of CO 2
) 5.3 5.3 5.3 5.3
Source: ZEP 2011
Table 6 Transport cost estimates for large-scale networks of 20Mtpa
SPINE DISTANCE (KM) 180 500 750 1500
Onshore pipe (€/t of CO 2
) 1.5 3.7 5.3 n/a
Offshore pipe (€/t of CO 2
) 3.4 6.0 8.2 16.3
Ship (including liquefaction) (€/t of CO 2
) 11.1 12.2 13.2 16.1
Source: ZEP 2011
3.3 Storage and use
This section provides an update to the fundamental overview of storage which was provided in the 2010 Status Report
(Global CCS Institute 2011a) and covers the progress of storage, resource assessments and of work on storage issues
and methods. It also covers some developments in the use or utilisation of CO 2
, which is increasing in importance,
particularly to provide commercial drivers for CCS demonstration projects.
Progress in regional/national storage assessment
There has been additional progress on screening of potential deep saline formations in some nations since the beginning
of 2011. Grant programs, for example, the EU NER300 and the Australian Flagships program, including the National CO 2
Infrastructure Plan, are stimulating new storage screening and more detailed site assessments. Brazil’s Centre of
Excellence in Research and Innovation in Petroleum, Mineral Resources and Carbon Storage (CEPAC) has also
progressed a storage atlas program. This progress by Brazil is reflected in the current status of country-scale storage
screening assessments shown in Figure 36.
Figure 36 Current status of country-scale storage screening assessments
Deep saline formations
capacity assessment initiatives
Capacity
Characterised
Under development
Theoretical
Source: IEAGHG 2011, modified by the Global CCS Institute
54 THE GLOBAL STATUS OF CCS: 2011

Brazil
Brazil has taken a multidisciplinary approach to its source-sink matching for assessment of potential applications of
CCS. CEPAC completed a Geographic Information System (GIS) based database of CO 2
sources and sinks in 2010.
CEPAC is currently reviewing and refining database content within its Brazilian Carbon Geological Sequestration
Map (CARBMAP) program, which commenced in 2007 (Rockett et al. 2011). The project has ranked onshore and
offshore basins and delineated the greatest potential as being in the Campos and Parana basins (petroleum reservoirs,
deep saline formations and coal beds). Theoretical capacity estimates have been established for depleted petroleum
reservoirs, with the majority share (1.7Gt) in the Campos Basin (Figure 37).
In March 2011, Petrobras commenced reinjecting associated CO 2
(up to 0.7Mtpa at peak production) into the Lula
giant oil field in 2150m of water depth offshore of Rio de Janeiro. This injection occurs within the Santos Basin pre-salt
fairway and follows onshore pilot testing in 2009 (Elsworth 2011).
Figure 37 Brazil sedimentary basins
CHAPTER 3
75° W
60° W
45° W
30° W
Tacutu
Foz do
Amazonas
N
1:25.000.00
0°
Amazonas
Marajó
São Luis
Solimões
Parnaíba
Acre
Araripe
Tucano Norte e
Jatobá
Tucano Sul e
Central
Parecis
Recôncavo
15° S
São Francisco
Espírito
Santo
Paranà
Campos
Santos
30° S
Sedimentary basins
Km
0 250 500 1.000
Image courtesy of CARBMAP, Brazil
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China
China’s storage potential assessments are very high level in nature as the focus has been largely on using CO 2
for
EOR and other industrial applications, rather than permanent geological storage. Despite this, efforts to assess and
characterise China’s CO 2
storage capacity continue. The Chinese Geological Survey is currently conducting a survey
of China’s storage capacity, which is scheduled for completion in 2012 (MOST 2010).
At a project level, China is making good progress in developing and applying ways to utilise CO 2
. For example,
China Petroleum and Chemical Corporation Limited (Sinopec) has captured and injected 0.04Mtpa of CO 2
into Shengli
oil field. Similarly, PetroChina has been injecting 0.12Mtpa of CO 2
into Jinlin oil field since 2009. China Huaneng Group
have two PCC projects that capture CO 2
for use in soft drink production and other industrial uses, including a 3 000tpa
PCC pilot (Beijing) and 0.12Mtpa PCC project (Shanghai). The ENN Group China is currently operating a pilot project
that uses CO 2
microalgae production with plans to scale-up to a 0.32Mtpa pilot facility in Inner Mongolia that will use
the microalgae for production of bio-diesel and other biofuels.
The Shenhua Group have commenced injection at the CTL Plant (Ordos City) in Inner Mongolia, aiming to reach
0.1Mtpa of CO 2
injected into a saline formation. Sinopec plans to develop a 1Mtpa CCS project where the captured
CO 2
will be used in EOR at the Shenli oil field.
Europe
In Europe storage capacity assessments have continued at a national level.
In the United Kingdom the UK Energy Technologies Institute (ETI) funded a comprehensive assessment of national
CO 2
offshore storage capacity at a cost in excess of £3.5 million. The CO 2
Storage Appraisal Project (UKSAP) identifies
the storage units, their theoretical storage capacity and the associated containment risks and economics. Started in
October 2009, results were expected to be available around the end of August 2011 (UKSAP 2010).
The EC continues to support research into better defining storage capacity through the issue of tenders and the
Framework Programme 7 (FP7) call for projects. Their ‘SiteChar’ three year research projects were launched in
January and May 2011 and the FP7 call also includes new storage related topics.
Of the thirteen project proposals submitted to the EIB under the NER300 funding program on 9 May 2011, four onshore
and nine offshore storage projects have been proposed to investigate CO 2
storage in deep saline formations or depleted
hydrocarbon reservoirs and through EOR/enhanced gas recovery.
In Europe six European projects (Jänschwalde, Don Valley, Porto Tolle, ROAD, Bełchatów and Compostilla) signed an
agreement with the EEPR (2010) in 2009-2010 to share and disseminate the results of their technological advances
and project progress through the EC initiated European CCS Demonstration Project Network.
The Global CCS Institute is supporting storage programs including the RCI depleted field assessment in the southern
North Sea and the Romanian Getica project (see case study textboxes).
Finally, the Norwegian Government continues to support R&D, transport and subsea storage solutions and mapping
of relevant sites. By 2010 the Norwegian operating projects, Snøhvit and Sleipner, had stored 1.0Mt and 13Mt of CO 2
respectively in deep saline formations (Ringrose et al. 2011).
CASE STUDY
Romania
The GETICA CCS demonstration project was initiated by the Romanian Government in 2010. It is located in the
Oltenia region, the most energy intensive region in Romania which is responsible for about 40 per cent of the
country’s total CO 2
emissions. CO 2
captured from the Turceni power plant is to be stored in deep saline aquifers
approximately 50km from the power plant.
• A storage feasibility study was conducted in 2010 and 2011 by GeoEcoMar with technical support from
Schlumberger Carbon Services where existing geological, geophysical and well data was collected.
• Preliminary site screening included eleven sites of which two are considered suitable (Zone 1 and Zone 5)
for storage and will be the object of further characterisation studies.
http://www.globalccsinstitute.com/resources/projects/romanian-ccs-demo-project-Getica
56 THE GLOBAL STATUS OF CCS: 2011

CASE STUDY
The Netherlands
The Rotterdam Climate Initiative (RCI) was launched in 2006 by the port and city of Rotterdam for municipal
and regional authorities to work with the corporate sector and cut CO 2
emissions by half by the year 2025 while
adapting to climate change and promoting the regional economy.
To evaluate storage options by 2015, RCI initiated in 2010 an ‘Independent Storage Assessment’ of the Dutch
offshore depleted hydrocarbon fields, carried out by TNO and published in 2011 (Neele et al. 2011).
• In the first phase existing data was collected and reviewed, leading to a detailed and comprehensive
database on the P and Q Blocks of the Dutch Continental Shelf, including its geology, wells and
well-related data and hydrocarbon production history.
CHAPTER 3
• In the second phase a detailed feasibility study was conducted for the most promising fields: P18, Q8-A
and K12-B.
• P18 is the main candidate for the ROAD (Rotterdam Opslag en Afvang Demonstratieproject)
CCS demonstration project. Total investment costs for P18 is estimated to be €65 million, for workover
of platform and six wells, excluding onshore installations and pipeline construction. Operational costs are
of the order of €3.2 million a year; these do not include the costs of (remotely) operating the platform.
Progress in LSIP Storage
The Institute’s 2011 project survey has tried to identify the stages that individual components (capture, transport and
storage) have reached to understand the relative progress within an LSIP between these components. As storage
characterisation is site dependent, and arguably requires the longest lead times, it can often end up lagging behind the
progress on capture. However, it is important that storage assessment is at least as advanced or even more advanced
than other components in the CCS chain, particularly for greenfield deep saline formation sites, as opposed to EOR
or depleted oil and gas reservoirs which have previously been investigated.
In Canada, the Boundary Dam project moved into the Execute stage in April 2011 and is expected to begin capturing
1Mtpa of CO 2
in 2014. While much of the captured CO 2
will be targeted towards EOR activities, a significant portion
initially captured is expected to be integrated into the Aquistore geological storage project. Aquistore will target basal
Cambrian-Ordovician strata within the Williston Basin as the storage complex. The Illinois-ICCS project has also
commenced construction in 2011 and plans to initially store the CO 2
in a deep saline formation.The Quest project is
anticipated to move to Execute in 2012 and plans to store CO 2
in the basal Cambrian deep saline formation sandstone,
similar to Aquistore.
Project development complexities and timeframes will constrain the likelihood of more than one or two additional deep
saline formation LSIPs operating in the next three years, regardless of funding or grant conditions.
When projects are less advanced in storage than in the other components, this misalignment may lead to a delay in
the timelines for the integrated projects. Notably, the Quest project is very advanced in its understanding of its storage
component and is thereby enhancing its chances of meeting delivery timeframes.
Timelines for storage assessment
Based on results from the 2011 project survey, the estimated lead times for greenfield storage assessment remain at
five to 10 years or more. Often it is the project risks and activities required to progress from the Define to the Execute
stage which creates these extended timeframes.
Many countries (Figure 36) have now undertaken storage screening and have addressed the fundamental questions
concerning the opportunity for adequate storage within their jurisdictions. In many countries it is known that there is
reasonable potential for CO 2
storage. While national-scale screening remains important, there is an increasing need
to focus on maturing demonstration project storage sites and ‘learn by doing’.
TECHNOLOGY
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Costs of storage
A recent study by ZEP (2011) identified the magnitudes by which onshore storage presents lower costs relative to
offshore storage, as well as the extent to which depleted oil and gas fields present cost savings relative to deep saline
formations, particularly if there are re-usable legacy wells (Table 7). Despite the relative cost advantages of certain options,
ZEP noted that the lowest cost storage reservoirs contribute the least to total available capacity. That is, given the current
understanding of reservoir capacity in Europe, there is more storage capacity offshore than onshore, and there is more
storage capacity in deep saline formations than in depleted oil and gas fields. Overall, while characterising storage remains
an essential part of CCS, the estimated costs of storage remain low in relation to capture.
Table 7 ZEP cost estimates for storage 1 ONSHORE OFFSHORE
€ per tonne of CO 2
€ per tonne of CO 2
Depleted oil and gas fields (legacy wells) 3 6
Depleted oil and gas fields (no legacy wells) 4 10
Deep saline formation 5 14
1 Medium (or most likely) values from the ZEP scenarios presented.
Source: ZEP (2011)
Continuing and emerging issues in storage
The significance of CO 2
EOR
While it is difficult to obtain precise quantities, it is clear that at present more anthroprogenic CO 2
is geologically stored
through EOR processes than through any other method globally. There is also considerable interest in both developing
and OECD nations in CO 2
EOR for domestic oil production. This is particularly true for China, MENA and increasingly,
the North Sea. Although the vast majority of EOR has occurred within the United States, many other countries including
Canada, China, Brazil, Hungary, Trinidad, and Turkey have a history of CO 2
EOR operations (Tzimas et al. 2005).
Not all oil fields are suited to CO 2
EOR. Generally speaking, fields are suitable if they contain oils that are moderate to
light, and relatively low in wax, and other precipitates. Further, the fields should operate at pressures high enough to
enable CO 2
to mix with the oil and form a single phase liquid, and have access to significant volumes of water, which
is injected alternately with the CO 2
in most current EOR operations to minimise the use of what is presently costly CO 2
.
The oil recovery process should operate above the minimum miscible (mixing) pressure throughout the entire reservoir.
Sufficient oil saturation in the reservoir (at least 35 per cent) should be present. In general, the more homogeneous the
reservoir, the more effective the CO 2
flood will be.
Approximately 80 per cent of CO 2
used for EOR in the United States at present is from naturally occurring sources
produced from the subsurface (Global CCS Institute and Parsons Brinkerhoff 2011), which leads to a net contribution
rather than abatement of CO 2
from the atmosphere.
Alternatively, in southern Saskatchewan, Canada, as of early 2011, a cumulative total of approximately 20Mt of
anthropogenic CO 2
has been stored in the Weyburn and Midale fields. Over the life of a CO 2
EOR program, CO 2
is
produced from the oil, separated and reinjected, reducing the requirement for new CO 2
supplies. Ultimately a field may
require almost no new CO 2
, relying on the recycled CO 2
. Currently the Weyburn field injects about half ‘new’ CO 2
and
half ‘recycled’ CO 2
. Essentially, all of the CO 2
injected will remain in the reservoir zone aside from minor losses from
operations or when intentional flaring is required.
Where recycling is not undertaken (for example the Joffre field in Alberta, Canada) approximately 30 to 40 per cent of the
injected CO 2
is permanently retained underground after the CO 2
has migrated through the formation or ‘broken through’
to the oil producing wells. When a CO 2
EOR field is no longer producing enough oil to merit continuing EOR, there is an
opportunity to convert it to dedicated storage, should the incentives to store rather than extract and reuse CO 2
be in place.
In many cases though, the end of EOR production is many years in the future (between 15 and 35 years for example
with respect to the Weyburn and Midale fields under present conditions).
58 THE GLOBAL STATUS OF CCS: 2011

Generally, current EOR operations are not set up for the detailed accounting anticipated for crediting permanent storage
of CO 2
. Although many operators may measure the volumes of CO 2
injected into the reservoir and the amount of CO 2
recycled, they largely monitor the movement of the CO 2
in the subsurface to optimise production. EOR operations are,
in many jurisdictions, required to perform wellbore integrity testing and prevent any oil field influence on the soil or potable
aquifer systems but not to monitor CO 2
subsurface distribution.
For EOR to lead to abatement of atmospheric CO 2
, the following factors should be in place:
••
the CO 2
that is injected should be produced from human activity (anthropogenic) that would have otherwise been
released to the atmosphere; and
••
a system of crediting backed up by a monitoring system that demonstrates and measures net CO 2
permanently
stored must be established, including baseline monitoring.
There are a number of insights for CO 2
storage that can be derived from EOR including:
1. The easiest way to commence a CO 2
project at present onshore is through EOR, as there are existing regulations
and infrastructure in place. Moreover, EOR is presently the most cost-effective option to store anthropogenic CO 2
.
CHAPTER 3
2. Providing the knowledge is shared, CO 2
EOR provides an understanding of the subsurface response to CO 2
injection.
There are more than 30 years of history of CO 2
injection in oil fields as well as the lessons learned from long-distance
CO 2
pipeline transport. In addition, monitoring, measuring and verification methodologies can be tested if there are
regulatory and/or economic incentives in place for the operator.
3. The requirements and expectations for dedicated CO 2
storage need to consider the pragmatic approach taken for
EOR. For example, to what resolution do we need to know the extent of the CO 2
or how far it may migrate and what
are sufficient protocols to manage the impacts of variations from expected responses
The Institute is currently examining the potential of EOR to impact on storage with reviews being undertaken of the technical,
regulatory and commercial issues. In providing a revenue source for the CO 2
, EOR, with adequate MMV, can improve
the viability of CCS projects while ensuring permanent storage.
Resource interaction, assessment and management
Sedimentary basins contain many different resources, either as part of the rock mass or as associated fluids, including coal,
coal bed methane, oil, natural gas, shale gas, geothermal energy, water, salt and other minerals of value. The incursion of
fluids such as CO 2
can impact directly on other resources and also connected pressure systems, which may have both good
and bad effects. These include, but are not limited to, assisting in production through increasing pressure (good) or mingling
with the fluid and changing its chemical and physical properties (both good for example in EOR and potentially bad
for example in decreasing the pH of water).
Resources extracted including petroleum, water or even heat have a more direct and immediate revenue value to
a jurisdiction, through resource rents, production sharing or royalties, when compared to the broader environmental
benefit derived through storage of atmospheric CO 2
that is difficult to allocate. As a consequence, CO 2
storage is often
treated as the lowest value use of pore space by individual jurisdictions, particularly in the absence of a price on CO 2
emissions, and must also demonstrate little or no risk of adverse impact on other resources.
World population pressures and climate change are increasing the scarcity and value of potable surface and near
surface water. There is also increasing competition for deeper potable groundwater resources and concern about the
impacts that resource activities may have upon them. However, CO 2
storage will largely occur at greater than 800m
below the ground surface, as below this depth the CO 2
will be in a dense state. This is normally well below depths
typically accessed for groundwater production (zero to 300m).
Production of hydrocarbons in the same area as carbon storage can and does occur successfully near current
CCS projects (for example Sleipner, Snøhvit, In Salah, and Weyburn-Midale). In areas of active exploration for,
or production of, energy resources, including coal bed/coal seam methane (CBM), shale gas, geothermal as well
as more conventional petroleum, concerns can be raised about issuing multiple property rights over the same area.
Specifically, these issues can include the hierarchy of those rights, as well as the potential impact on producing
and non-producing wells as well as impacts on other resources in the vicinity.
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In some cases the storage and resource extraction activities will occur at widely separated depths, in different strata
and have little or no impact upon one another. For example, high temperature geothermal heat production for power
generation will exploit zones where the subsurface temperatures are well above 120°C. This is generally at 3 000m
or more depth, beyond the depths at which CO 2
storage will usually occur. Conversely, hydrocarbon exploration and
production, CBM production and shale gas production, can all occur at similar depths to CO 2
storage. But when
conventional hydrocarbon production is separated from the CO 2
injection interval by sealing rocks either above or below
the producing interval, CO 2
injection and production can overlap in an area and be active at the same time, as is seen
at Sleipner and other fields (Eiken et al. 2010).
The activities associated with other subsurface resources can impact on the suitability of areas for secure CO 2
storage.
For example, some of the hydraulic fracturing (fraccing) methods used in developing shale gas can impair the
containment properties for CO 2
storage to the point where CO 2
can no longer be stored under the fracced interval.
CBM production requires de-watering to depressurise the producing interval and free up methane through desorption
from the coal. If the produced water is not suited to treatment for further use at surface, it may be disposed of in
another interval in the subsurface. CBM may also compete for storage pore space for disposal of its waste water.
In summary, there are challenges in multiple resource use in the subsurface, but as long as that interaction is understood,
CO 2
injection and storage can be compatible with other subsurface resource activities. Modelling of fluid flow is vital
to address and manage competing demands on a prospective injection target, particularly if there are concerns about
impact on other resources.
Open, closed and partly closed systems
Deep saline formations are considered to have the greatest potential by far to store large quantities of CO 2
. In saline
formations, the pressures have not been depleted through production of hydrocarbons, unless they are in pressure
communication with a hydrocarbon interval that has been produced.
Concerns about the ability to sustain long-term injection of CO 2
in closed systems were discussed the 2010 Status Report.
Pressure increases associated with injection of CO 2
may attain a high enough level where the seal can fracture,
thereby compromising the integrity of the storage complex. While this threshold can be accurately modelled and pressure
monitored downhole, the large scale injection being considered in some projects necessitates careful monitoring
of pressures within the deep saline formation.
An ‘open’ saline system has little or no barrier for some distance, so that CO 2
injected can displace the saline water
through the pore system. Modelling can predict the rates of pressure build-up and dissipation and be used to optimise the
rate of CO 2
injection. Zhou and Birkholzer (2011) have simulated injection into the Mount Simon Sandstone in the Illinois
Basin, considered by the authors to be an ‘open’ system where there are no major lateral barriers to the movement of
fluids (including CO 2
). They set up 20 hypothetical injection ‘projects’ about 30km apart. Using properties consistent
for sealing formations in the basin the maximum pressure buildup over a 50 year period caused by 5Gt of CO 2
injection
does not breach the seal and is safely contained.
Zhou and Birkholzer (2011) argue that naturally closed systems are rare (a fault-bounded oil field being an example).
Even in closed systems, seal integrity can be maintained through careful monitoring of pressures within and beyond
the CO 2
plume and if necessary by releasing some salty water through designated wells.
Monitoring Measuring and Verification for risk management
Wright (2011) presented a schematic risk profile through time illustrating that the risks during the lifecycle of a CO 2
storage project are arguably at their highest near the later stages of injection, towards the end of the maximum injection
rate plateau and then reducing rapidly following the closure of a facility (Figure 38). This profile is similar to that
presented by Benson (2007) and points to the progressive reduction of risk post injection with time. Processes that
occur over time to reduce the risk include pressure dissipation and residual trapping of the CO 2
in the pore spaces.
60 THE GLOBAL STATUS OF CCS: 2011

Figure 38 Schematic risk profile for a storage project
Risk
Baseline
data
acquisition
and initial
QRA
M&V
QRA
M&V
QRA
M&V
QRA
Monitoring
Operator
Operation
(injection)
Closure
Nation/
landowner
Post-closure
Maximum risk in
developer stewardship
Stewardship
Project phase
CHAPTER 3
Construct Operate Close
Note: Monitoring and verification (M&V) and quantified risk assessment (QRA)
Source: Note: Wright Monitoring (2011), based and verification In Salah (M&V) and quantified risk assessment (QRA)
Source: Wright (2011), based on In Salah
Maximum risk in
national stewardship
Time
Dodds et al. (2011) identified, as have others, the need for both environmental and geological baseline data, initial and
ongoing risk assessment and monitoring strategies suited to the specific site prior to injection. This process will
help ensure that changes in the subsurface potentially affecting the risk profile can be detected and addressed in
a timely manner.
The fundamental objectives of a MMV program are to identify and manage risks by providing data to ensure operational
procedures are progressing appropriately, to update predictive modelling and to identify any deviation in the injection
field behaviour. The methodologies that provide the most effective coverage and detection of movement of CO 2
in the
subsurface will need to be developed on a site by site basis. For example, in some cases this may mean that monitoring
for pressures will provide an earlier and better understanding of the location and impact of the CO 2
plume than seismic
imaging, particularly where the signal quality is poor.
The monitoring strategy should be directed by the risk assessment and be fit for purpose—not unnecessarily prescribed.
From the safety perspective, the fundamental outcomes should be minimising risk and ensuring containment.
If there is no methodology and protocol which can effectively monitor CO 2
at a given site, then injection of large volumes
of CO 2
should not be pursued at that location until those methods are available and tested.
There is an expectation that early movers will pay a ‘precautionary premium’ to ensure safety but requirements should
be based more on risk assessments and mitigations, rather than prescribed.
Storage risks for an individual project will generally decrease as time passes after injection ceases. The risk profile has
reduced to a point that is an order, or orders of magnitude less than the maximum level during operation. It is expected that
some monitoring will be required by the regulator during the post injection phase until it is established that the system is
behaving as predicted and further risks are minimal. The assumption of risk/long term liability – whether it is the operator,
jurisdiction or through some trust arrangement – should consider the decreasing risk profile when assessing their exposure.
TECHNOLOGY
61

Storage capacity development and training in developing nations
Given the importance of moving beyond desktop studies toward site specific characterisation, there is a need to increase
skills and capacity in the storage disciplines; particularly in developing countries that still need to build a case for CCS.
In the first instance capacity development activities can focus upon supporting countries to undertake initial desktop
storage studies, and there are examples of this taking place. South Africa released its National Storage Atlas in 2010
and has received funding from international funding bodies to undertake more specific desktop site studies.
However, the type of activities will need to expand as developing countries make the transition from national screening
to characterisation. They could include: undertaking a technical capacity analysis of a country’s geoscience departments
to identify technical strengths and gaps; addressing gaps by providing technical training for geologists through
storage workshops and courses; providing opportunities to visit test injection sites; and engaging existing geotechnical
networks and projects.
There are already a range of storage specific courses and programs including the Geologic Carbon Sequestration
Program at Lawrence Berkeley National Laboratory and the Carbon Capture and Storage Masters Program at the
University of Edinburgh. Organisations such as CO2CRC’s CCS Otway Demonstration Project in Victoria, Australia, often
hosts site visits, as do other companies with CCS projects. The British Geological Survey has previously undertaken
‘skills gap’ analysis in developing countries and provides storage expertise in other international collaboration
projects such as the Near Zero Emissions Coal (NZEC) and the Cooperation Action within CCS China-EU (COACH),
both of which have a focus on China. The EuroGeoSurvey is an example of an existing knowledge-sharing network
of 32 geological surveys which can be utilised to provide support to European based geosciences departments.
Gaps in storage understanding and future areas for work
Research gaps
Although petroleum exploration and production provides a sound and highly sophisticated foundation of tools and
workflows in CCS, it also creates a bias that may restrict consideration of techniques outside of the current petroleum
toolkit. At the highest level, petroleum explorers are focussed on the oil or gas producing qualities of the reservoir.
By contrast the most important consideration for CCS storage is seal or containment ‘caprock’ above the storage formation.
There has been significant progress in understanding the response on subsurface equipment and materials to CO 2
and ways
of managing the impact (for example Smith et al. 2011). There is also a much better understanding of how different
impurities will impact on the subsurface infrastructure (such as well casing and cements), and injection performance,
as well as a recently internationally released framework for risk management of existing wells (DNV 2010).
Finding alternative methods of measuring the extent of the stored CO 2
in formation and its far field effects is an important
area that requires field testing. Reflection seismic has been successful as a tool to directly measure the extent of CO 2
in
some thick intervals with high porosities (such as Sleipner) but generally has been less successful in thinner intervals with
lower porosities (such as In Salah). Seismic acquisition can be intrusive onshore—for example, it can require temporary
removal of fencing—particularly if it is undertaken repeatedly in areas of multiple use. All seismic monitoring is costly.
Satellite methods such as InSAR are attractive as they are low in cost and unobtrusive. They have been used at In Salah
to measure at a millimetre scale the slight land surface deformation caused by injection, but require quite specific surface
conditions including limited or no vegetation cover. Dedicated permanent markers and other tools are being developed to
cope with vegetation cover (for example at the MGSC’s Decatur project).
62 THE GLOBAL STATUS OF CCS: 2011

Areas suggested by the Institute for further storage research:
• coupled non-linear geological, geomechanical and geochemical processes;
• plume profiles in heterogeneous reservoirs to determine capacity factors;
• modelling trapping mechanisms;
• develop and refine the numerical simulators needed to design and interpret the pilot test data;
• compare a number of simulators to develop confidence in numerical approaches;
• fault stability assessment and analysis;
• transport properties – trap integrity and trapping mechanisms;
• rock deformations;
CHAPTER 3
• thermodynamics of complex fluids and solids;
• chemical properties and geochemical transport understanding in different formations;
• understand current models and their limitations;
• experiments to define improvements;
• monitoring – dynamic imaging of plume;
• remote sensing – non invasive techniques; and
• reliability of 4D monitoring.
The challenge remains to develop alternative less costly and intrusive methods of assurance monitoring of CO 2
containment
and have them accepted by regulating agencies and other stakeholders. This may involve redefining the problem from
optimising direct image quality of the CO 2
plume to confident but indirect detection methods of determining plume effects.
Solutions may involve less direct imaging techniques, greater integration of different tools that can help constrain
results and a greater focus on early warning systems for potential future containment problems, coupled with robust
responses to avert leakage. For example, pressure monitoring beyond the plume with slimhole monitors may be both
a more effective and cost effective alternative, or possibly complementary to, lower quality seismic data.
Storage assessment and monitoring strategies must be adapted to the specific site. The clear need now is to operate
storage in real geological systems to test and broaden the number of methods available for measuring and monitoring
the response of the Earth to the injection of CO 2
. Matching the predicted outcomes with the actual results will improve
the predictions and increase the knowledge and confidence in storage. Most importantly, the extent of the impacts of
CO 2
injection (including far field pressure effects) needs to be predictable, measureable and understood with mutually
agreed limits between the operator and regulator.
When the CO 2
is injected a number of responses still need to be better understood, including but not limited to:
••
The response at the intersection of the sealing ‘caprock’ and the top of the storage reservoir when CO 2
reaches the
interface, as there is a possibility that the cooler CO 2
could lead to some fracturing.
••
The inelastic behaviour of rocks when storage occurs in depleted reservoirs, as the rocks do not necessarily return
to the same state when they are ‘repressured’ again using CO 2
. In some cases this may mean that there is a greater
risk of fracturing when CO 2
is injected.
Use of CO 2
and ‘Novel’ CCS
Algal biofuels, reforestation, increased wood based construction, mineral fixing and soil sequestration have been
considered as potential ways of storing CO 2
as well as providing other resource benefits. The key differences
between these methods and geological storage, at least for the present, is the ‘permanence’ and quantity of storage.
Unless the CO 2
is removed from the carbon cycle it does not remove the carbon from the atmosphere in the long term.
However, it may reduce net extraction of fossil fuels if it provides alternative fuels or materials that require lower
fossil energy input.
TECHNOLOGY
63

Combining geological storage with capture of CO 2
derived from the production or utilisation of biofuels has the overall
effect of removing CO 2
from the atmosphere. Bio-energy combined with CCS (BECCS) therefore goes beyond zero
emissions and achieves ‘negative emissions’. The most viable projects in this category are likely to be those, such as
ethanol plants, that produce a high concentration stream of by-product CO 2
. CCS achieves its optimum cost efficiency
at relatively large scale whereas biofuels projects are generally limited in scale by their access to feedstock. However a
number of BECCS projects are now being considered in Europe and North America (Biorecro 2011).
CO 2
use has an initial role to play in supporting the demonstration of CCS, especially in the absence of strong carbon
prices. This role is clearly visible in the use of CO 2
for EOR, as has already been described.
EOR is a commercial CO 2
use application. Other use opportunities (Figure 39) are not as far progressed as industrial
applications, as the source process does not supply concentrated CO 2
or the use is a less permanent method of storage.
Figure 39 CO 2
use technologies, feedstock concentration and permanence
CO 2
storage
Permanent
Not permanent
EOR
Urea
CO 2
feedstock
Captured high
concentration CO 2
Dilute CO 2
flue gas
ECBM
EGS
Bauxite residue
ECBM
Mineral carbonation
Concrete curing
Polymers
Renewable methanol
Formic acid
Algae cultivation
Algae cultivation
Source: Global CCS Institute and Parsons Brinckerhoff (2011)
The Australian National Low Emissions Coal Research & Development (ANLEC R&D) and Brown Coal Innovation
Australia (BCIA) along with the Institute have commissioned a study to look more closely at the alternatives to geological
storage of CO 2
in Australia. With the obvious exception of wood-based construction these technologies are largely at a
very early stage and the permanence of storage/fixing of CO 2
ranges from months to decades rather than thousands to
millions of years for geological storage. The surface footprint of some of these methods of carbon storage can also be
very large. Still, niche opportunities and potential for alternative fuel production may well see novel storage play some
role in the future.
An example of CO 2
use without permanent removal from the carbon cycle can be found in the RCI Organic Carbon for
Assimilation (OCAP) joint venture. The Shell Pernis Refinery delivers roughly 300kt a year of high purity low nitrogen and
low sulphur ‘waste’ CO 2
to about 500 greenhouses in the region. OCAP aspire to expansion to 1Mtpa for greenhouse
supply. Although greenhouse use is an early application for CO 2
and in the RCI case has helped develop the CO 2
pipeline infrastructure, horticulture applications are considered to be a relatively minor source of future CO 2
usage
when compared with other industrial applications (Global CCS Institute and Parsons Brinckerhoff 2011).
Storage Guidelines
The Institute commissioned a desktop review of publicly available storage guidelines (CO2CRC 2011) which showed
that a reasonably comprehensive suite of guidelines has been published, with the preeminent being the CO2WELLS’s
CO2QUALSTORE Guideline (DNV 2010). However, there is probably scope for guidelines that centre on the geomechanical
impacts, and risks/opportunities and treatments of exploration and development decisions of CO 2
storage.
64 THE GLOBAL STATUS OF CCS: 2011

3.4 Technology costs and challenges
A key policy goal in providing funding support for CCS demonstration projects is to gain information on the effect on the
performance and cost of certain products, predominantly electricity, when CCS is applied at commercial scale in their
production. Some information on the costs of individual components in the CCS chain was presented in the capture,
transport and storage sections. This section will focus on overall CCS costs.
In the past year detailed CCS cost studies have been released by the IEA (2010b), WorleyParsons (2011),
DOE NETL (2010a), and ZEP (2011). These studies compare the costs of different technologies using the
measures of levelised cost and avoided cost of CO 2
.
The levelised cost of electricity is a measure of the average cost of electricity that needs to be recovered over all output for
the entire economic life of a generating plant in order to justify the original investment. Receiving this value, on average,
would ensure that all costs including the initial capital investment, the return on that investment as well as fuel and other
variable costs, together with fixed operation and maintenance costs would be covered.
CHAPTER 3
The cost of CO 2
avoided reflects the cost of reducing CO 2
emissions to the atmosphere while producing the same
amount of product, such as electricity, from a reference plant that does not include CCS technologies. The cost of CO 2
avoided allows the different technologies to be ranked and compared on an equivalent basis with respect to anticipated
carbon prices.
The first three of these studies have been previously analysed (Global CCS Institute 2011a) with the major
conclusions being:
••
The largest uncertainty in the cost of large-scale demonstration plants occurs in the up-front capital costs.
Incorporating CCS facilities increases capital investment costs by around 30 per cent for an IGCC facility and
by 80 to 100 per cent for the other coal and gas-based technologies.
••
Total installed investment costs, including capture technology, represent approximately 45 to 50 per cent of the
cost of electricity from coal-based CCS plants.
••
Oxyfuel combustion has a lower relative cost on both levelised electricity costs and avoided CO 2
costs compared
with other CCS technologies. At the same time, oxyfuel technologies are the least mature technologies and have
a higher level of uncertainty.
••
Given the uncertainties, at this stage, it is difficult to identify any single technology with a clear cost advantage.
••
The levelised cost estimates in the three studies are consistently higher than those estimated three or more years
ago. Due to changing methodologies and the inclusion of previously omitted items, costs are now suggested to
be 15 to 30 per cent higher than earlier estimates.
••
The economics of CO 2
storage is affected by the geology of the target storage formation. Without an appropriate
storage site that is accessible by effective transport options, CCS may not be an appropriate option in certain
circumstances. With ideal storage conditions, storage costs contribute less than five per cent to total costs,
increasing to around 10 per cent for storage sites with ‘poorer’ geologic properties.
••
The different cost estimates observed in the various studies arise due to differences in assumptions regarding
technology performance, cost of inputs or the methodology used to convert the inputs into levelised costs.
Many of these differences disappear when the assumptions are normalised and a common methodology is applied.
The effect of any individual assumption from each of the three studies on the estimated levelised cost for power
generation is generally of the order of five per cent.
These three studies focused primarily on estimates based on technologies that would be demonstrated in the
United States (summary information is presented in Table 8). The Institute study also ‘regionalised’ the estimates to all
the regions of the world through the use of adjustments to capital, labour and technology costs as well as including cost
estimates for steel, cement, natural gas processing and fertiliser production.
In July 2011, ZEP (2011) published a study focused specifically on the power sector in Europe today (Table 9) as well
as estimates for the period post-2025. The cost estimates were developed around project and technology cost data
provided by the industrial members of ZEP. As with the studies discussed above, the costs reported in this study had
also increased, by between 15 to 20 per cent in constant dollar terms from a similar study by ZEP in 2006 (ZEP 2006).
ZEP has also noted that, when compared with the recent studies by NETL and the Institute, the ZEP cost estimates
are lower. Nonetheless, the cost estimates that reflect the costs of technologies available today from all four studies are
broadly consistent, particularly given the inherent uncertainty around individual technology elements for key parts of a
project. Design studies of the type produced by ZEP and NETL have a range of uncertainty of around ±30-40 per cent.
The ZEP study also provided costing options across a wide variety of transport options together with different storage
TECHNOLOGY
65

configurations. These costs were briefly discussed in the respective sections earlier in this chapter.
Table 8 Summary of recently completed CCS design cost studies
POST COMBUSTION IGCC OXYFUEL NGCC
WORLEY PARSONS
NETL
IEA 1
WORLEY PARSONS
(SHELL)
NETL (SHELL)
NETL
(CONOCO PHILLIPS)
NETL (GE)
WORLEY PARSONS
WORLEY PARSONS
DOE NETL
Base year 2 2010 2007 2008 2010 2007 2007 2007 2010 2010 2007
Capacity
Total
overnight cost
O&M 3
Fuel cost
MW
(net)
US$/
kW
US$/
MWh
US$/
MWh
546 550 474 517 497 514 543 550 482 474
4701 3570 3838 4632 3904 3466 3334 4430 1964 1497
16 22 14 18 12 6
34 20 13 33 18 18 17 44 72 52
Capture rate % 90 90 90 90 90 90 90 90 90 90
Efficiency 4 % 27.2 26.2 34.8 32.0 31.2 31.0 32.6 29.3 43.7 42.8
Capacity
factor
% 85 85 85 85 80 80 80 85 85 85
Lead time Years 4 5 4 4 5 5 5 4 3 3
Lifetime Years 30 30 40 30 30 30 30 30 30 30
Discount rate % 8.8 9.1 10 8.8 9.1 9.1 9.1 8.8 8.8 9.1
Transport 5
Storage 6
LCOE 7
Avoided cost
of CO 2
8
US$/
MWh
US$/
MWh
US$/
MWh
US$/
tonne
1 - n/a 1 - - - 1 1 -
6 5.6 n/a 6 5.7 5.6 5.3 6 6 3.2
131 135 90 125 151 140 134 121 123 109
81 87 ~75 67 77 93 109 57 107 106
1 IEA estimates only include the cost of capture and compression.
2 Base year in which current dollars are reported.
3 The NETL study includes payroll and property taxes, these taxes are not included in the other studies.
4 The IEA report lower heating value (LHV) net heat efficiency rates, whereas the other two studies report higher heating value (HHV) net heat
efficiency rates.
5 Transport distances are assumed to be 100km and 80km by Worley Parsons and DOE NETL studies respectively. For DOE NETL
transport costs are included in the storage item.
6 The NETL study includes payments for liability for 30 years.
7 Levelised cost of electricity.
8 Reference facility in all coal technologies is supercritical pulverised coal within each study. Values for DOE NETL studies calculated by Global
CCS Institute.
Source: IEA (2010b), DOE NETL (2010a), WorleyParsons (2011)
66 THE GLOBAL STATUS OF CCS: 2011

Table 9 CCS cost estimates from ZEP
COAL
GAS
REFERENCE:
ULTRA-SUPERCRITICAL
POST-COMBUSTION
CAPTURE
IGCC
OXYFUEL
REFERENCE:
F-CLASS TURBINE
Base year 1 2009 2009 2009 2009 2009 2009
Capacity MW (net) 736 616 900 568 420 350
POST COMBUSTION
CAPTURE
CHAPTER 3
Total overnight cost €/kW 1711 2860 3300 4060 786 1829
O&M €/MWh 7 14 15 13 6 13
Fuel cost €/MWh 18.3 26.6 28.3 28.6 56.4 68.1
Capture rate % - 90 90 90 - 86
Efficiency 2 % 46 38 36 35 58 48
Capacity factor % 85 85 85 85 85 85
Lead time Years n/a n/a n/a n/a n/a n/a
Lifetime Years 40 40 40 40 25 25
Discount rate % 8 8 8 8 8 8
Transport 3 €/MWh - 2 2 2 - 2
Storage €/MWh - 4 4 4 - 2
LCOE €/MWh 44.5 80 87 94 71.9 104
Avoided cost of CO 2
€/tonne - 46 54 65 - 114
1 Base year for the current dollar estimates of cost components.
2 LHV net heat efficiency rate.
3 ZEP estimated transport costs for 29 different transport network configurations. The values selected here are for a 2.5 Mtpa point-to-point,
onshore 180km network in order to be consistent with the results presented in Table 8.
Source: ZEP (2011)
Cost lessons from previous environmental technology innovations
Government funding for CCS demonstration is partly aimed at accelerating the rate of technology innovation. This presents
many challenges, as does accurately estimating the costs of large-scale operation on the basis of existing pilot projects.
The impact of adding technologies to existing systems can affect the performance and reliability of other technology elements
in the system in ways that are difficult to predict given limited data at smaller scales. The initial cost estimates for new
technologies based on experience from smaller-scale projects or pilot plants are typically lower than the costs subsequently
observed for the initial large-scale applications (Yeh and Rubin 2010). Costs are often added through design changes and
product performance improvements in the early stages of commercialisation (Neij 1997). However, it is then equally common
for costs to subsequently decline as technologies mature and learning is incorporated into subsequent designs.
While the technology of capturing CO 2
emitted from power generation is still in its infancy, there have been a number
of other environmental technologies developed and applied to dealing with the emissions from fossil fuel power plants
These include flue gas desulphurisation (FGD) systems for sulphur dioxide (SO 2
) control and selective catalytic
reduction (SCR) systems for nitrogen oxides control.
TECHNOLOGY
67

Development of FGD systems commenced in the early 1950s in response to funding authorised under the
Air Pollution Control Act in the United States, assisted with grants from other agencies including health departments
(Hamilton 2009). Over the period from the late 1960s through to the 1990s, innovation and development activities
increased (Taylor 2003), driven by both increased funding support and the development of a number of policies
designed to stimulate the demand for the technology as governments sought to limit the level of SO 2
emissions.
The capital costs of early FGD demonstration projects more than doubled between 1972 and 1982 as designs were
modified to achieve the system reliability and performance needed to comply with regulatory requirements. After a
decade of experience and learning, costs began to decline, falling by almost half by the mid-1990s (Yeh and Rubin
2010). Similarly, the costs of early SCR systems deployed in Europe and Japan were also higher than initially forecast
based on smaller pilot-scale plants, particularly as these cost studies often did not include contingencies to manage the
risk associated with limited commercial scale experience. After nearly 15 years of experience, capital costs eventually
ended up lower in constant dollar terms for SCR systems than even the initial design studies estimated.
A similar pattern can be observed in the costs of other technologies related to power generation. For example, natural gas
combined cycle power plant development commenced in the middle of the 20th century, and was not ready for
commercial deployment with high levels of availability until the late 1970s and early 1980s. Nonetheless, early deployment
of commercially available plants had costs increasing for the period 1981-1991 before costs subsequently declined
(Colpier and Cornland 2002).
Some lessons from these experiences have been taken on board for CCS cost estimation by those undertaking detailed
project costings or generic cost studies. Studies have made increasing allowance for contingencies around system
processes as well as integration and project management challenges. With a limited number of commercial-scale
CCS projects in operation in some sectors, and none yet in operation for coal-fired power generation, steel or cement
production, it has been estimated that early mover projects carry process cost contingencies upward of 20 per cent
(WorleyParsons 2009). Anecdotal information from project developers has suggested contingencies of up to 40 per cent
in some cases.
At the same time, there are differences in the costing methods used by different organisations concerned with CO 2
capture and storage. For the studies in the public domain there is no consistent set of cost categories or nomenclature
to define the various cost components (Rubin 2011). The time frame for cost estimates often varies between current
technology understanding (so called first-of-a-kind) and future technologies which may be after process and project
contingencies have been reduced (so called nth-of-a-kind). There are also differences in whether or even when new
technology developments such as improved capture methods have been included, or whether the transport and storage
element is part of a larger infrastructure development with a transport network and multiple storage opportunities,
or a single pairing from a capture source through to a single storage site with a dedicated point-to-point pipeline.
The challenges involved in improving the understanding of CCS costs in the public domain through better reporting
and transparency of costing methods led to the establishment of a CCS Costs Network in early 2011. This network
brings together approximately 50 cost experts from capture through transport (both pipeline and shipping) to storage.
The Network aims to improve consistency and transparency in CCS cost estimates through development of common
terminology and methodologies, including characterisation of uncertainty, together with improving the public
communication of CCS costs. The Institute is a member of the Network and actively supports its activities through
its web-based Knowledge Sharing Platform.

4
POLICY, LEGAL AND
STAKEHOLDER ISSUES
4.1 Policy, legal and regulatory context 71
4.2 Status of funding support 89
4.3 Public engagement 95

4 POLICY, LEGAL AND
STAKEHOLDER ISSUES
KEY MESSAGES
• Substantial, timely and stable policy support, including a carbon price signal, is needed for CCS to be
demonstrated and then broadly deployed. This in turn will give industry confidence to continue to invest
in CCS and drive innovation.
• This year, decisions at the UNFCCC’s Conference of the Parties (COP 17) in Durban, South Africa, could
further assist CCS realise its mitigation potential in helping deliver on the objective of stabilising global
atmospheric emissions by establishing an international framework that provides for the institutional
arrangements of CCS under any future UNFCCC mechanism.
• The development of CCS laws and regulations has continued at a reasonable pace with a number of
jurisdictions completing framework legislation and commencing implementation of secondary regulations
and guidance. Notwithstanding these efforts, project proponents have identified a number of issues that
have yet to be adequately addressed, including incomplete or delayed regulation.
• Government funding to support large-scale CCS demonstration projects has remained largely
unchanged in 2011. In total, approximately US$23.5bn has been made available to date.
• Project proponents need to continuously review their public engagement approach to identify and mitigate
potential challenges. As with storage, public engagement is situation and site specific, and on a local level
must address project impacts, including benefits.
As with any industry, the policy and legal environment is an important consideration in the development of CCS.
This is even more important for CCS, however, given the stage of its development. As with several other greenhouse gas
mitigation technologies, CCS requires substantial implicit and explicit policy support, including government funding,
to make it commercially attractive to the private sector. The nature of policy support for CCS is typically expressed in
a country’s climate change strategy and/or energy plans.
This chapter characterises the policy landscapes currently affecting CCS activities, and provides a global scan of the
prevailing and evolving CCS-related policies of climate change, energy markets, industry and innovation, as illustrated in
Figure 40 below. Recent developments in legal and regulatory issues are also outlined. A particularly important area of
policy support for CCS is government funding for demonstration projects, and the second section in the chapter details
the current levels of support available around the world. The chapter concludes with a discussion on public engagement.
Public acceptance of the technology is essential, and this is an area where governments and industry must work together.
Figure 40 Scope of policy landscape
Climate
change
policy
International
National
Sub-national
Energy
policy
Projects
Industry
policy
Innovation
policy
70 THE GLOBAL STATUS OF CCS: 2011

In addition to its own analysis on global policy and regulatory environments, and surveying project proponents on
related matters, the Institute also commissioned Baker & McKenzie (2011) and Ernst & Young (2011) to undertake
independent scans of the legal and policy initiatives respectively. These sections draw on those studies.
4.1 Policy, legal and regulatory context
The current early stage of integrated CCS solutions coupled with climate change policy uncertainty more generally has
meant that there are currently few commercial investors. The impediments for new entrants over the short term are
largely due to high capital costs associated with CCS technologies and the nature of the risks they face, which are mostly
of a policy and regulatory nature.
Notwithstanding these factors, as discussed earlier in this report, the private sector has demonstrated a willingness to
invest in CCS projects in some situations, for example where a value for CO 2
, such as in EOR use, can provide a revenue
stream that helps enhance the overall economics of a project. Discussions with project proponents reveal that policy
uncertainty is perceived as a major risk, and of particular concern is where governments articulate policy intent without
implementation.
CHAPTER 4
The United States Interagency Task Force on CCS (2010) has noted that, to address CCS related market failures,
policy makers should:
••
have regard to the nature and magnitude of the market failure being targeted;
••
design policies capable of adjusting to changing circumstances over time;
••
provide policies that allow for maximum flexibility of private sector response;
••
ensure policies are complementary with other incentives; and
••
dependably deliver on policy objectives at least cost to the taxpayer and/or consumer.
These principles embrace a broad mix of possible policy approaches and apply at all levels of policy, including:
••
negotiated agreements (specific sectoral treatment);
••
information based instruments (best practice);
••
regulations and standards (emissions or technology performance standards);
••
capacity development (enhanced capacity of institutions and/or infrastructure);
••
price based instruments (carbon pricing mechanisms);
••
research and development policies (funding for innovation); and
••
financing support (grants, tax concessions and/or tax credits).
International policy and legal environment
The United Nations Framework Convention on Climate Change (UNFCCC)
The international effort to address climate change has been in earnest for over 20 years. In 1992, the UNFCCC was
adopted, entering into legal force in 1994. There are currently 194 countries that have committed to help stabilise global
atmospheric greenhouse gas concentrations at a level that prevents dangerous, ‘man-made’ climate change. In 1997,
the world moved to establish emissions reduction commitments that cap absolute global emissions over time – these
commitments are stipulated for the period 2008 to 2012 in the Kyoto Protocol, which entered into legal force in 2005.
At the last major climate change meeting in Cancun in December 2010 (COP 16), countries agreed “to hold the increase
in global average temperature below 2°C above preindustrial levels” (UNFCCC 2010). Such a vision provides the basis for
a better understanding of the role CCS must play within a context of the climate change challenge confronting the world.
In the context of the international climate change agenda, the status of the Institute’s national government Members
under the UNFCCC and Kyoto Protocol and any emission reduction aspiration is illustrated in Table 10.
POLICY, LEGAL AND STAKEHOLDER ISSUES
71

Table 10 Country status of emission reduction aspirations
EMISSION REDUCTION TARGETS AND PLEDGES
UNFCCC
Kyoto
Protocol
KYOTO PROTOCOL
COMMITMENTS
(2008-12 RELATIVE
TO 1990)
BY 2020
(UNCONDITIONAL)
BY 2020
(CONDITIONAL)
BY 2050
(CONDITIONAL)
OTHER
RATIFICATION
Australia 8% -5% relative to
2000
Up to -15% or
-25% relative
to 2000
-80% relative
to 2000
30 Dec
1992
12 Dec
2007
Brazil -36% to -39%
relative to
forecast
emissions
Bulgaria -8% -20% relative
to 2005
12 May
1995
12 May
1995
15 Aug
2002
15 Aug
2002
Canada -6% -17% relative
to 2005
-20% relative
to 2006
-60 to -70%
relative to 2006
4 Dec
1992
17 Dec
2002
China -40 to -45%
of CO 2
per unit
of GDP relative
to 2005
-17% of CO 2
per unit of GDP
by 2015 relative
to 2005
5 Jan
1993
30 Aug
2002
Egypt
5 Dec
1994
12 Jan
2005
European
Union
-8% -20% relative
to 1990
-30% relative
to 1990
-80% to -90%
relative to 1990
21 Dec
1993
31 May
2002
France 0% -14% relative
to 2006
25 Mar
1994
31 May
2002
Germany -21% -14% relative
to 2005
-60 to -70%
relative to
2006
9 Dec
1993
31 May
2002
India -20% to -25%
emission
intensity per
unit of GDP
relative to 2005
1 Nov
1993
26 Aug
2002
Indonesia
-26% relative
to business as
usual (BAU)
-25 to -30% of CO 2
relative to BAU
over 2012-15
-40% of CO 2
relative by 2025
23 Aug
1994
3 Dec
2004
Italy -6.5% -13% relative
to 2006
15 Apr
1994
31 May
2002
Japan -6% -25% relative
to 1990
-80% relative
to 1990
reduce energy
related emissions
by -30% or more
by 2030 relative
to 1990
28 May
1993
4 Jun
2002
Korea
-4% relative
to 2005
-30% relative
to ‘prospective
estimates’ by
2020
14 Dec
1993
8 Nov
2002
72 THE GLOBAL STATUS OF CCS: 2011

Table 10 continued
EMISSION REDUCTION TARGETS AND PLEDGES
UNFCCC
Kyoto
Protocol
KYOTO PROTOCOL
COMMITMENTS
(2008-12 RELATIVE
TO 1990)
BY 2020
(UNCONDITIONAL)
BY 2020
(CONDITIONAL)
Malaysia Up to -40%
per unit of
GDP relative
to 2005
BY 2050
(CONDITIONAL)
OTHER
13 Jul
1994
RATIFICATION
4 Sep
2002
CHAPTER 4
Mexico Up to -30%
relative to
business as
usual
Netherlands -6% -30% relative
to 1990
11 Mar
1993
20 Dec
1999
7 Sep
2000
31 May
2002
New
Zealand
0% -10% relative
to 1990
-20% relative
to 1990
-50% relative
to 1990
16 Sep
1993
19 Dec
2002
Norway 1% -30% relative
to 1990
-40% relative
to 1990
carbon neutrality
within 2030
9 Jul
1993
30 May
2002
Papua
New Guinea
carbon
neutrality
at least -50%
relative to
business as
usual by 2030
16 Mar
1993
28 Mar
2002
Romania -8% -20% relative
to 1990
8 Jun
1994
19 Mar
2001
Russian
Federation
0% -15 to -25%
relative to 1990
‘called for’
-50% relative
to 1990
28 Dec
1994
18 Nov
2004
Saudi Arabia
28 Dec
1994
31 Jan
2005
South Africa
-34% relative
to BAU
-42% by 2025
relative to 2005
and emissions
to peak
between 2020
and 2025
29 Aug
1997
31 Jul
2002
Sweden 4% -17% relative
to 2006
Trinidad and
Tobago
United Arab
Emirates
23 Jun
1993
24 Jun
1994
31 May
2002
28 Jan
1999
United
Kingdom
-12.5% at least -80%
by 2050
relative to
1990
-22% relative
to 1990 over
2008-12
8 Dec
1993
31 May
2002
United States -17% by 2020
relative to 2005
towards a goal
of -83% relative
to 2005
-30% in 2025,
-42% in 2030
relative to 2005
15 Oct
1992
Key: Acting in common Copenhagen Accord Pledge
POLICY, LEGAL AND STAKEHOLDER ISSUES
73

There are five main areas of interest for the CCS community arising from the December 2010 Cancun Agreements
for the COP 17 meeting that will be held in Durban, South Africa, in December 2011:
••
registration of Nationally Appropriate Mitigation Actions (NAMAs) – it was agreed that countries requiring international
support in the form of technology, finance or capacity building will be recorded in a registry where the action and
the support for that action can be matched;
••
adoption of a Technology Mechanism – it was agreed that this would be fully operational in 2012 to strengthen the
development and deployment of new technologies (including demonstration and diffusion) in developing countries.
Governance includes a Technology Executive Committee (TEC) which will assist in providing an overview of needs
(including policies and actions) for the development and transfer of technologies, and a Climate Technology Centre and
Network (CTCN) to facilitate national, regional, sectoral and international technology networks, organisations and initiatives;
••
adoption of a Financial Mechanism – includes the provision of agreed Fast-Start finance for developing countries
approaching US$30bn up to 2012; and the establishment of a Green Climate Fund worth US$100bn a year by
2020 administered (initially) by the World Bank to support adaptation and mitigation actions (projects, programs,
policies and other activities) in developing countries (the UN Secretary General’s High Level Group on Financing
judges these funding levels as possible);
••
inclusion of project level CCS projects/abatement under the CDM – it was agreed that governments will allow CCS
projects in the CDM, provided that a range of technical issues and safety requirements are resolved and fulfilled
(discussed further below); and
••
market mechanisms – it was agreed that governments will continue work towards establishing one or more new
market-based mechanisms to enhance and promote the cost-effectiveness of mitigation actions (and this will
be considered at COP 17).
The institutionalisation of CCS project level activity is currently being scrutinised under the UNFCCC, particularly through
the CDM. The CDM is a global carbon offsets market established under the Kyoto Protocol. Since 2006, it has been
rewarding the investment of developed countries (Annex I Parties to the Kyoto Protocol) in emission reduction projects
in developing countries (Non-Annex I Parties) with a tradable instrument called a Certified Emission Reduction unit
(CER). Each CER is equivalent to one tonne of CO 2
. CERs can be either be sold or acquitted against emission obligations.
CDM is clearly making a difference when it comes to mobilising financial support for local projects in developing countries.
The eligibility of CCS projects to generate CERs for the associated abatement is currently being considered in the CDM,
under the negotiating track called the Ad-hoc Working Group (AWG) on Further Commitments for Annex I Parties under
the Kyoto Protocol (see Appendix E.1 for background on UNFCCC negotiations).
Final decisions surrounding the inclusion of CCS in CDM are expected to be made at COP 17 at Durban. The process
to adopt CCS in CDM in the lead up to Durban is:
1. The UNFCCC Secretariat is to:
a. prepare a ‘synthesis’ report based on the submissions received from accredited observers in the submission
process ending 21 February 2011;
b. host a legal and technical experts technical workshop (scheduled for early September 2011 in Abu Dhabi); and
c. prepare the draft modalities and procedures for consideration by the Subsidiary Body for Scientific and
Technological Advice (SBSTA) at its 35th session in December 2011.
2. The SBSTA is to elaborate further on the issues raised by the COP serving as the meeting of the Parties to the
Kyoto Protocol (CMP) decision in Cancun last year as well as the UNFCCC Secretariat’s draft modalities and
procedures, with a view to putting recommendations to the CMP at CMP 7.
3. The Parties to the UNFCCC and Kyoto Protocol will formally negotiate in Durban the drafting of the legal text contained
in such recommendations to CMP; and then the CMP must decide whether to adopt SBSTA’s recommendations.
Despite an already extensive and transparent prosecution of the limited number of issues identified, there is no guarantee
that the CMP will adopt CCS in CDM at COP 17. The CMP may choose instead to further task SBSTA to provide additional
counsel on specific issues and/or decide on alternate arrangements.
The limited number of issues stalling the inclusion of CCS in the CDM are predominantly storage related. As the Institute
cited in its 2011 submission (Global CCS Institute 2011c) to the UNFCCC on CCS in the CDM, a legitimate approach
for managing these issues is on a risk management basis rather than imposing overly prescriptive approaches.
Assuming that CCS projects are ultimately adopted as registrable activities capable of generating CERs, proponents must
then present and have approved by the CDM Executive Board (EB) the supporting baseline and estimation methodologies.
The situation at the moment is that the EB is not considering submissions on CCS methodologies until CMP adopts a
formal position.
74 THE GLOBAL STATUS OF CCS: 2011

The Group of Eight (G8)
The G8 is an informal group of advanced economies that meets once a year at a Summit of Heads of State and Government.
Members of the G8 are France, the United States, the United Kingdom, Russia, Germany, Japan, Italy and Canada.
The G8 first announced its commitment to and support of CCS in 2005 when it released the ‘Gleneagles Plan of Action:
Climate Change, Clean Energy and Sustainable Development Declaration’ which included the statement:
“We will work to accelerate the development and commercialisation of Carbon Capture and Storage technology…”
(G8 Summit 2005).
This support was followed up in its 2006 St Petersburg and 2007 ‘Growth and Responsibility in the World Economy’
Declarations. A milestone in the G8’s support for CCS was reached in June 2008, when both the G8 Energy Ministers
(including the People’s Republic of China, India and the Republic of Korea) and Environment Ministers expressed support
for both a target number of CCS projects and a timeframe in which to deliver. The G8 Energy Ministers jointly stated:
“… strongly support the launching of 20 large-scale CCS demonstration projects globally by 2010,
taking into account various national circumstances, with a view to beginning broad deployment of CCS by 2020…”
(G8 Summit 2008).
CHAPTER 4
Under its 2009 Declaration, the G8 stated:
“The development and deployment of innovative technologies such as Carbon Capture and Storage (CCS)
is therefore expected to contribute substantially to reducing emissions…” (G8 Summit 2009).
In addition to reaffirming its 2008 commitment to launch 20 large-scale CCS demonstration projects globally by 2010,
a number of actions were also identified to support CCS including accelerating the design of policies, regulatory
frameworks and incentive schemes focused on the development and deployment of CCS technology.
In 2010, the G8 met in Canada and in its Muskoka Declaration stated:
“To address climate change and increase energy security, we are committed to building low carbon and climate
resilient economies … CCS can play an important role in transitioning to a low-carbon emitting economy.
… the progress already made on [its] Toyako commitments to launch the 20 large-scale CCS demonstration
projects globally by 2010 and to achieve the broad deployment of CCS by 2020, in cooperation with developing
countries. Several of us commit to accelerate the CCS demonstration projects and set a goal to achieve their full
implementation by 2015…” (G8 Summit 2010).
The IEA and Carbon Sequestration Leadership Forum (CSLF), with the cooperation of the Institute, submitted a report
on CCS to the 2010 Muskoka G8 Summit (IEA and CSLF 2010). In this report eight high-level recommendations were
advanced to accelerate the development and uptake of CCS, as well as a series of next steps. These recommendations are
highlighted in Figure 41.
In 2011, the G8 met in Deauville, France. No references to CCS were contained in the publicly-released declarations.
The 2012 summit is scheduled to be held in Chicago, United States.
Clean Energy Ministerial (CEM)
The second CEM forum was held in Abu Dhabi in April 2011 with some 25 countries represented at the ministerial
level. The CEM grew from the Major Economies Forum (MEF) on Energy and Climate leaders’ decision in 2009 with the
aim of accelerating the transition to clean energy technologies. In regard to CCS, the initiative aims to create greater
political momentum for advancing the deployment of CCS required to meet the global mitigation challenge.
A Carbon Capture, Use and Storage (CCUS) Action Group has been established by the CEM (along with 10 other
working groups). The membership of the CCUS includes Australia, Canada, China, France, Japan, Korea, Mexico,
Norway, South Africa, the United Arab Emirates, the United Kingdom and the United States.
Eight recommendations from the CCUS Action Group (2011) were adopted at CEM2 and will be reported on at CEM3
which is scheduled for London in April 2012. These recommendations are also highlighted in Figure 41.
The Institute continues to play a substantive role in the CEM along with the IEA by supporting its work plan to implement
the CCUS Action Group recommendations. The Institute is leading the effort under recommendation two to identify a
funding mechanism to support CCS projects in developing countries, in partnership with the Asian Development Bank,
the CSLF, the World Bank, and the World Resources Institute.
Figure 41 illustrates the relationships between all of the CCS related recommendations and issues arising from the
UNFCCC, G8, and CEM. As can be seen, all three international agendas are well harmonised in addressing outstanding
barriers that are stalling accelerated global deployment of CCS.
POLICY, LEGAL AND STAKEHOLDER ISSUES
75

Figure 41 Linkages between the UNFCCC, the CEM and G8
G8 RECOMMENDATIONS (IEA/CSLF REPORT TO THE MUSKOKA 2010 G8 SUMMIT)
1 2 3 4 5 6 7 8
DEMONSTRATING CCS
TAKING CONCERTED
INTERNATIONAL
ACTION
BRIDGING THE
FINANCIAL GAP FOR
DEMONSTRATION
CREATING VALUE
FOR CO 2
ESTABLISHING LEGAL
AND REGULATORY
FRAMEWORK
COMMUNICATING
WITH THE PUBLIC
INFRASTRUCTURE
RETROFIT WITH
CCS CAPTURE
CLEAN ENERGY MINISTERIAL (2ND CEM, ABU DHABI APRIL 2011)
RECOMMENDATIONS
1 reduce the financial gap
2 funding support in developing
economies
3 develop legal and regulatory
frameworks
4 acknowledge importance of
marine treaty amendments
5 share knowledge
6 investigate carbon dioxide
storage
7 support CCS in industry
8 report on progress
UNFCCC SBSTA ISSUES (COP 16/CMP 6)
LIMITED ISSUES TO BE RESOLVED FOR COP 17/CMP 7
a
b
c
d
e
f
g
h
i
storage site selection (integrity
of permanence)
monitoring plans (to enhance
environmental integrity of
storage site)
suitability of modelling for
monitoring plans
project boundaries (for all
associated CO 2
sources/
migratory pathways)
measurement and accounting
of emissions in monitoring plans
appropriateness of
transboundary projects
risk/safety assessment
(in monitoring plans to include
mitigation options)
liability
provisions to redress liability
Key: Consistent Strongly consistent
76 THE GLOBAL STATUS OF CCS: 2011

International marine and waste agreements
At the international level, major regulations of note that affect CCS are international conventions dealing with or possibly
applying to transboundary shipments of CO 2
.
Two such agreements are the Protocol to the Convention on the Prevention of Marine Pollution by Dumping of Wastes
and Other Matter (London Protocol), and the Convention for the Protection of the Marine Environment of the North-East
Atlantic (OSPAR Convention). The London Protocol establishes a scheme to prevent and control the pollution of the
international marine environment, while the OSPAR Convention works to identify threats to the marine environment
of the North-East Atlantic and has programs and measures to ensure effective national action to combat them.
Despite early and unwavering support for CCS as a mitigation technology through amendments to both agreements,
subsequent revisions and ratifications have been slow to progress amongst the signatory parties. In June 2011 however,
there was a significant breakthrough with regard to the OSPAR agreement. Spain, Denmark and Luxembourg notified the
Convention secretariat that their national ratification processes had been completed. Ratification of the amendments by a
required seven parties will now enable the 2007 revisions to enter into force. These revisions will specifically allow for CCS
under the Convention, including to allow for the storage of CO 2
in geological formations under the seabed.
CHAPTER 4
Steps towards the full ratification of an amendment to Article 6 of the London Protocol, which would allow for the export
of CO 2
streams in certain circumstances, remain more tentative. Twenty-seven of the current 40 contracting parties to
the Protocol are required to ratify the amendment for it to enter into force. To date however, only Norway has completed
the ratification process. The failure to ratify these amendments means that transboundary transportation of CO 2
for the
purpose of geological storage still remains proscribed under the Protocol. For a small number of countries and project
proponents, whose anticipated projects include transboundary elements, this will continue to be viewed as a major
uncertainty and barrier to further development.
While the regulation of transboundary shipments of wastes and its relevance to CCS activities has already been extensively
negotiated under the London Protocol, some lawyers, experts and NGOs have recently raised the issue of whether the
Basel Convention’s provisions also apply to the transboundary movement of CO 2
and that the position of CCS under the
treaty may require further clarification.
The Basel Convention establishes a regime for the control of the international trade in hazardous wastes, with a view
to ensuring the protection of human health and the environment. The Convention places emphasis on the principle of
proximity, requiring that hazardous wastes are to be disposed of in the state in which they are produced. Were CO 2
to
be included within the definition of hazardous wastes covered by the Convention, a number of provisions would apply
to its transportation for the purposes of CCS.
Transportation between Parties to the Convention and non-Parties is prohibited and a further ‘Ban Amendment’ was
ratified in 1995, which prohibits OECD countries from exporting hazardous waste to non-OECD countries for final disposal.
Transportation of CO 2
is only permitted under the Convention subject to the prior consent of the receiving country, which is
also entitled to prohibit this transport to, or across, its territory. As such, it remains unclear as to whether the Convention’s
provisions could seriously impact upon CCS operations.
A decision as to whether CO 2
falls within the scope of the Basel Convention has yet to be made and an interpretative
note from the Contracting Parties would be necessary. CCS has yet to be addressed by the Contracting Parties and
remains outside the Convention’s Working Group program for 2012-2013.
POLICY, LEGAL AND STAKEHOLDER ISSUES
77

National and regional policy settings
While the development of a CCS industry as a whole can be considered to be in the early stages, some countries have
implemented or have indicated interest in a suite of policies that support more advanced CCS industries. To illustrate,
Figure 42 presents a very simple index indicating the nature of the current CCS relevant policy environments for a
select number of countries.
Figure 42 CCS policy index
comprehensive
7
6
25
20
Mtpa CO 2
-e per capita
5
Coverage of CCS supporting policies
4
3
2
15
10
5
1
conceptual
India
Brazil
Indonesia
Mexico
Romania
China
Malaysia
Norway
South Africa
United Kingdom
Germany
Japan
Korea
Australia
Netherlands
Canada
United States
Saudi Arabia
R&D policies
international collaboration/capacity development
information based instruments
negotiated agreements
regulations and standards
financing arrangements
carbon pricing instruments
emissions per capita (RHS)
Index
1.00 = a policy exists
0.75 = a policy is currently being implemented
0.50 = a policy exists at sub-national level
0.25 = a policy is currently being considered
0.00 = a policy does not exist
78 THE GLOBAL STATUS OF CCS: 2011

Most countries recognise that CCS is still very much in the demonstration stage, and this partly explains why the focus
of most governments to date has been on providing public funding for pilot and demonstration-scale projects.
It is likely that in a carbon constrained world, where countries implement economy-wide policies to fully value carbon,
CCS would be commercially attractive relative to other prospective large-scale, clean-energy technologies without
the need for separate support. In the absence of such policies however, specific support is needed so that CCS can
continue to be developed alongside other technologies in order to realise its mitigation potential within a portfolio of
prospective mitigation solutions.
It is vitally important that governments continue to send strong policy signals during the demonstration phase and that
the institutional arrangements (including incentives and legislative and regulatory frameworks) can and will be in place
in a timely manner to efficiently support both the continued demonstration efforts and the early stages of commercial
deployment. Such signals are needed to provide industry with medium to longer term certainty that investing in CCS
as a mitigation option is both sensible and affordable as far as hedging their future emission risks is concerned.
Many countries are currently engaging in a dynamic public policy discussion on major next-generation climate change
policies. Most notable are Australia, China, South Africa, the United Kingdom and Japan. There are also innovative
private/public led initiatives such as the recently-launched United States National Enhanced Oil Recovery Initiative,
which aims to secure broad support for policies that increase domestic oil supply through EOR while limiting emissions
through CCS. This initiative will develop recommendations for United States federal and state policy makers in early 2012.
CHAPTER 4
The extent to which the policy objectives of environment protection (decarbonising the energy system), energy security
(preserving energy independence), and economic prosperity (optimising the value of indigenous resource endowments)
differ between countries depends on localised circumstance. As such, governments and the private sector face many
choices when settling on alternative policy options in which to hedge future carbon risks and support CCS innovation.
It is this ‘localised circumstance’ of countries that drives governments to implement nationally appropriate transition
pathways to less emission intensive economies.
While there is a commercial imperative to reduce the costs of capture given that this component can constitute over
70 per cent of the total cost of an integrated CCS solution (as indicated in Figure 31 of section 3.1), a major focus for
policy makers over the medium term could be more on issues associated with maturing CCS markets. This includes
the challenges of transitioning publicly-funded CCS activities to more integrated and complex market structures.
Examples could include:
••
the creation of common-user CO 2
distribution networks;
••
the transitioning of competitive storage exploration efforts to monopolistic, multi-user and fee for service
storage facilities; or
••
transposing the regulatory conditions of a demonstration CCS project or an EOR operation to a commercial
CO 2
storage operation.
A qualitative evaluation is provided in Appendix E.2 of the CCS policy environment for a select number of countries
identified in Table 11. These countries were selected on the basis that their ‘localised circumstance’ indicates a high
order interest in CCS mitigation, as characterised by:
••
global share of CO 2
-e emissions from fossil fuel consumption (indicating the scale of future abatement required);
••
global share of fossil fuel production (indicating the importance of export markets); and/or
••
global share of fossil fuel consumption (indicating a reliance on fossil fuels to drive local economic prosperity).
Within the context of the upcoming COP 17 in Durban, countries have been grouped according to their UNFCCC regional
classification. This may indicate to policy makers the extent of commonality among and between the groups on CCS.
POLICY, LEGAL AND STAKEHOLDER ISSUES
79

Table 11 International groupings for countries
UNFCCC GROUPINGS
OTHER INTERNATIONAL
ARRANGEMENTS
COUNTRY
UN REGIONAL
GROUPINGS
ANNEX I
ECONOMIES IN
TRANSITION (ANNEX I-EIT)
ANNEX II
NON ANNEX I
ANNEX B
AFRICAN REGIONAL
GROUP
ALLIANCE OF SMALL
ISLAND STATES (AOSIS)
GROUP OF 77 & CHINA
OPEC
OECD
G8
G20
Egypt
African States
South Africa
China
Asian States
India
Indonesia
Japan
Malaysia
Papua New
Guinea
Korea
Saudi Arabia
United Arab
Emirates
Bulgaria
Romania
Eastern
European States
Russian
Federation
Brazil
Mexico
Trinidad
and Tobago
Latin America &
The Caribbean
States
Australia
Other States
Canada
New
Zealand
Norway
United
States
France
Germany
Western
European States
Italy
Netherlands
Sweden
United
Kingdom
European Union
Key: Members Observers Other member countries
80 THE GLOBAL STATUS OF CCS: 2011

Almost all countries analysed contain a financing measure as the primary enabler for the development of projects at
this stage. The type of financing arrangements (upfront capital grants, loan guarantees, low interest loans, procurement
preferences and so on) tends to differ depending on the extent to which other complementary policies and regulations
support CCS. Table 12 characterises the prevailing and prospective policy environments by region and for selected
countries. Government funding for CCS is discussed further in section 4.2.
Table 12 CCS policy landscape
UNFCCC
GROUP
COUNTRY
CARBON
PRICING
INSTRUMENTS
FINANCING
ARRANGEMENTS
CCS RELEVANT POLICY LANDSCAPE
REGULATIONS
AND STANDARDS
POLICY
NEGOTIATED
AGREEMENTS
INFORMATION
BASED
INSTRUMENTS
INTERNATIONAL
COLLABORATION
/CAPACITY
DEVELOPMENT
RESEARCH AND
DEVELOPMENT
POLICIES
CHAPTER 4
AFRICAN
STATES
Egypt
South
Africa
Carbon Tax
✔
✔
✔
China
✔
Regional
✔ ✔ ✔
Mandatory ETS
India ✔ ✔ ✔
Indonesia
✔
✔
Carbon Tax
Japan
✔
✔
✔
✔
✔
ASIAN STATES
VETS
TMG ETS
Carbon Tax
Coal Tax
CCS-R
Malaysia
✔
✔
CCS SG
Papua New
Guinea
✔
Korea
✔
✔
✔
✔
Trial ETS
ETS
Mandatory ETS
Saudi Arabia ✔ ✔
POLICY, LEGAL AND STAKEHOLDER ISSUES
81

Table 12 continued
CCS RELEVANT POLICY LANDSCAPE
POLICY
UNFCCC
GROUP
COUNTRY
CARBON
PRICING
INSTRUMENTS
FINANCING
ARRANGEMENTS
REGULATIONS
AND STANDARDS
NEGOTIATED
AGREEMENTS
INFORMATION
BASED
INSTRUMENTS
INTERNATIONAL
COLLABORATION
/CAPACITY
DEVELOPMENT
RESEARCH AND
DEVELOPMENT
POLICIES
Bulgaria
✔
EU ETS
✔
✔
EASTERN EUROPE
Romania
✔
EU ETS
Other
✔
✔
GEO
#64/11
CCS
Directive
✔
✔
Russian
Federation
✔
✔
LATIN AMERICA AND
THE CARIBBEAN
Brazil ✔ ✔
Mexico
Trinidad
and Tobago
✔
✔
Australia
✔ ✔ ✔ ✔
Fixed Carbon
Price
ETS
Canada
✔
✔ ✔ ✔ ✔ ✔
OTHER STATES
New
Zealand
Western Climate
Initiative
✔
ETS
✔
✔
Norway
✔
✔ ✔ ✔ ✔ ✔
Carbon Tax
United
States
✔
Western Climate
Initiative
✔ ✔ ✔ ✔ ✔
82 THE GLOBAL STATUS OF CCS: 2011

Table 12 continued
CCS RELEVANT POLICY LANDSCAPE
POLICY
UNFCCC
GROUP
COUNTRY
France
CARBON
PRICING
INSTRUMENTS
✔
EU ETS
FINANCING
ARRANGEMENTS
REGULATIONS
AND STANDARDS
NEGOTIATED
AGREEMENTS
INFORMATION
BASED
INSTRUMENTS
INTERNATIONAL
COLLABORATION
/CAPACITY
DEVELOPMENT
✔ ✔ ✔ ✔
RESEARCH AND
DEVELOPMENT
POLICIES
CHAPTER 4
Germany
✔
✔
✔ ✔ ✔
EU ETS
EC
Directives
Italy
✔
✔ ✔ ✔ ✔
WESTERN EUROPE
Netherlands
EU ETS
Carbon Tax
✔
EU ETS
Carbon Tax
✔ ✔ ✔ ✔ ✔
Sweden
✔
✔ ✔ ✔ ✔
EU ETS
Carbon Tax
United
Kingdom
✔
EU ETS
✔ ✔ ✔
Climate
Change
Levy
✔
✔
✔
✔
✔
✔
✔ ✔ ✔
EU
EU ETS
DIRECTIVES
EUETS
CCS
IPPC
allowance
allocation
Key: Considered Proposed/planned Being Implemented ✔ Exists
POLICY, LEGAL AND STAKEHOLDER ISSUES
83

National and regional legislation
The proliferation of CCS-specific regulation continues in many jurisdictions worldwide, as governments continue to
reflect on and, in some instances re-address, their policy approaches to climate change mitigation. Recently there have
been several key developments in Europe, as well as at the state and provincial level in the US, Australia and Canada.
Also encouraging, is the number of developing countries who are also moving ahead with studies into the potential
mitigation opportunities offered by CCS. In many instances, these investigations include a focus on the establishment
and jurisdictional requirements of legal and regulatory frameworks for the technology. The following sections examine the
progress made to date in a number of key jurisdictions, as well as providing some illustrative country-specific activities.
‘Early mover’ countries continue to lead the way in the development of primary legislation (such as Acts), supporting
regulations (often referred to as secondary legislation) and guidance. Many of these countries appear to be adopting
logical and iterative processes for developing their regimes, which follow a clear trajectory by way of a series of key stages
and outcomes. It is the view of Baker & McKenzie that the approach adopted by a jurisdiction when implementing a CCS
regulatory regime has tended to follow one of two distinct paths; assuming either a fully integrated or piecemeal approach.
The EU for example, has chosen a model that addresses the novel aspects of the technology, while simultaneously adapting
existing environmental and energy legislation to regulate particular aspects of the process, while other jurisdictions have
selected a process which updates or amends existing legislation governing the extractive, oil and gas industries.
It remains to be seen whether the second generation of regulators and law makers, including those in some developing
countries, will also adopt similar processes and methodologies for the development of their policies and regulatory frameworks.
Europe
Europe remains a region at the forefront of legal and regulatory developments for CCS, for the most part by virtue of the
EU Member States’ obligations to transpose the requirements of the CCS Directive into their domestic laws. In order to
meet the transposition deadline of 25 June 2011, Member States quickened their regulatory activities and by 31 July 2011
around twelve countries had communicated to the Commission the actions they had taken towards implementation of
legislation to transpose the requirements of the Directive. Austria, Belgium, Denmark, France, Ireland, Latvia, Lithuania,
Luxembourg, Romania, Spain and the United Kingdom were all posted on the Commission’s webpage as countries that
had met the deadline. However, it must be noted that notification to the Commission does not necessarily mean that the
actions taken satisfy all the requirements of comprehensive transposition. A number of other States reported that they are
close to transposing the requirements of the Directive, but they had until 11 August 2011 to prepare formal reports on the
success or otherwise of their implementation processes.
The Commission will now begin the process of examining the national execution measures for conformity and
comprehensiveness and it is reported that the Commission has issued a number of formal letters to those States
that have not fully transposed the legislation.
The process of transposing legislation appears to have varied considerably between Member States. For some States,
strong political support for the technology has meant the transposition process being expedited in an efficient and
detailed manner—as is the case in the United Kingdom where the recent Electricity Market Reform White Paper has again
signalled the government’s commitment to the technology. For other jurisdictions however, the process has highlighted
a number of difficult domestic policy considerations around the technology, not least continuing public opposition in
certain States to what is seen as perpetuation of traditional fossil fuel power generation. Nowhere is this more evident than
Germany, where resistance at the Lander (state level) to the technology has consistently frustrated the adoption of national
CCS legislation. The recent adoption of a CCS Bill in the lower legislative house (the Bundestag) includes provisions which
would allow individual Lander to opt-out of its requirements, thus preventing CCS activities from taking place within their
jurisdiction. Industry has criticised the inclusion of the clause, however if unopposed by the second legislative chamber
(the Bundesrat) the Bill will pass into law by the end of the year.
A different perspective can be found in Romania, one of the more recent European accession States, where CCS has
received substantial government support through its National Reform Programme. The Romanian Government has
already informed the Commission that it has transposed the CCS Directive into national law (Governmental Emergency
Ordinance No.64 of 29 June 2011) and is expected to pass further secondary legislation to ensure the full implementation
of its requirements. The new Ordinance adopts a similar format to the Directive and focuses upon the permitting
procedure for CO 2
storage and transportation. Amendments have been made to existing water, waste and liability
laws and Parliament also made amendments to national integrated pollution prevention and control legislation to
facilitate capture activities. The new Ordinance does not however, address land and access rights, issues of conflicting
use and whether fees may be payable for undertaking CCS activities.
The Romanian Government is presently undertaking the Institute’s regulatory test toolkit exercise, with a view to
assessing the scope of its nascent permitting regime. A final report will be completed by the end of 2011 and it is
hoped that this report and the earlier workshop process will assist in resolving any remaining gaps in the regime.
84 THE GLOBAL STATUS OF CCS: 2011

United States
There have been few significant federal-level regulatory accomplishments in the United States during 2011.
Discussions around CCS and climate change more broadly in the United States remain protracted and stalled in
political disagreement. State legislatures however, have continued to advance new proposals around various aspects
of the CCS chain. To date, a number of states have introduced legislation that either regulates some aspect of the CCS
process, or supports its inclusion in wider environmental or energy policies.
At the federal level, major legislative proposals have been advanced in recent times to establish an emissions trading
scheme, with most advocating for some tranche of allowances to CCS applications. Examples are the American Clean
Energy and Security Act (HR2454) – the Waxman-Markey Bill; and the Clean Energy Jobs and American Power Act
(S1733) – the Kerry-Boxer Bill (which also sought to establish emission performance standards for new coal-fired
power plants).
The US Senate Committee on Energy and Natural Resources has also been very active in the area of CCS.
In mid-2011, two further CCS-specific Bills have been introduced including the Department of Energy Carbon
Capture and Sequestration Program Amendments Act of 2011 (S.699) – Bingaman, and the Carbon Dioxide
Capture Technology Prize Act 2011 (S.757) – Barrasso-Bingaman, to provide financial awards for CCS.
CHAPTER 4
In late 2010, the EPA finalised its reporting rule governing aspects of the CCS process, as well as its final rule for
CO 2
geologic sequestration wells as part of its Underground Injection Control Program, as established under the
Safe Drinking Water Act. The former, the Mandatory Reporting of Greenhouse Gases from Carbon Dioxide Injection and
Geological Sequestration, Subparts RR and UU, sets out monitoring, reporting and verification objectives for all facilities
conducting geological sequestration and the injection of CO 2
, while the latter creates a new Class VI well specifically for
long-term, incremental storage of CO 2
. On 4 August 2011, the EPA released a proposed rule to modify their pre-existing
hazardous waste legislation. The proposed amendments will remove injected CO 2
streams from the scope of the
hazardous waste regulations, provided they are to be injected into wells designated under the Safe Drinking Water Act.
The rule document states that the EPA is proposing this course of action because “it believes that the management
of these CO 2
streams under the proposed conditions does not present a substantial risk to human health and the
environment”.
The EPA has also published draft guidance documents to assist operators and owners of the new Class VI well.
Guidance documents for financial responsibility have already been finalised, while draft documents addressing site
characterisation, corrective action, well construction and the content of well plans were opened for public consultation
in early 2011.
A number of states have introduced or enacted legislation to regulate discrete aspects of the storage process,
or to provide financial incentives or security to operators. In the state of Mississippi a new Bill (2723) sets out a
regulatory framework for CCS, which also allows existing EOR operations to continue without conflicting with the EPA’s
underground injection control program. Under the Bill, regulatory authority for the storage of CO 2
is divested in the
environmental and oil and gas authorities and provisions are introduced governing the title to CO 2
, the approval of
storage reservoirs and the establishment of a fund to manage the long-term liabilities associated with storage sites.
In Illinois the legislature recently passed the Clean Coal FutureGen for Illinois Act of 2011, which seeks to establish a
comprehensive liability regime for the FutureGen 2.0 project. Under the Act the FutureGen Alliance is required to hold
a private insurance policy for the duration of the operational phase, as well as establish a trust fund to supplement their
insurance. Of particular note is the Act’s transfer to the State of Illinois, of all liabilities surrounding the stored CO 2
at
the end of the operational phase of the project. The Act has yet to be signed by the Governor, although it is expected
to enter into force in the next 6 to 12 months.
Australia
Australia’s regulators continue to lead the way in developing law and regulations for CCS activities and their momentum
has not been allayed despite a significant shift in federal government climate change policy and the reduction and
deferment of CCS funding.
There continued to be considerable regulatory activity at the federal level during 2011, with consequential amendments
to key legislation governing offshore CCS activities and the development of further secondary legislation. The Offshore
Petroleum and Greenhouse Gas Storage Legislation Amendment (Miscellaneous Measures) Act, entered into force
in late 2010 and made a number of amendments to the Offshore Petroleum and Greenhouse Gas Storage Act 2006
(OPGGS Act), most notably by expanding the powers of the National Offshore Petroleum Safety Authority to cover
some aspects of greenhouse gas facilities.
POLICY, LEGAL AND STAKEHOLDER ISSUES
85

A number of regulations have also been developed under the auspices of the OPGGS Act, including: the Offshore
Petroleum and Greenhouse Gas Storage (Management of Greenhouse Gas Injection and Storage) Regulation 2011,
the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulation 2011,
and the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Amendment Regulation 2011.
These regulations address a range of issues related to the rights and obligations of titleholders under the OPGGS Act,
including management and administrative responsibilities related to CCS operations.
Further amendments to the OPGGS Act are anticipated under Bills introduced into Parliament in May 2011.
These proposals introduce, amongst other items, new regulatory bodies, cost recovery levies and other consequential
amendments to support government policy.
In 2011 a number of state jurisdictions have also commenced work on regulatory frameworks for CCS. Western Australia
is presently drafting a Greenhouse Gas Storage Bill, which will amend the Petroleum and Geothermal Energy Resources
Act 1967 and adopt a similar approach to the federal OPGGS Act. The Bill is expected to be introduced to Parliament
in the latter half of 2011. The Government of New South Wales also introduced its Greenhouse Gas Storage Bill to
Parliament in November 2010, however, it failed to pass as a result of a delay to the legislative process caused by the
subsequent state elections. The proposed legislation provided a full permitting and licensing regime for the permanent
storage of CO 2
, including provisions for the post-closure transfer of liabilities to the Crown.
Canada
Canada’s provincial governments continue to lead national efforts in the development of law and regulation for CCS.
The Governments of Alberta and Saskatchewan have both introduced further legislation to regulate CCS at the
provincial level in late 2010 and into 2011.
Alberta’s Carbon Capture and Storage Statutes Amendment Act 2010 entered into force in December 2010 and makes
several amendments to provincial statutes to provide clarification around the regulation of CCS activities in Alberta.
The Act does not present a full regulatory framework, however, it does address a number of key issues, including a
determination that pore space in the province is owned by the government. The Act includes provisions for the transfer
of long-term liabilities to the government upon the provision of data demonstrating the containment of the injected CO 2
as well as establishing a post-closure stewardship fund. The adoption of the Carbon Sequestration Tenure Regulation
in April 2011, established a further process for those seeking pore space tenure rights for carrying out CO 2
geological
storage. The Regulation sets out further guidance around the terms, areas and boundaries and MMV requirements
associated with evaluation permits and carbon sequestration leases.
Alberta is also undertaking a Regulatory Framework Assessment to examine the regulatory regime in Alberta, in particular
the environmental, safety and assurance processes and requirements, and determine whether they meet the requirements
of the commercial deployment of the technology. The process is a considerable achievement and draws upon both domestic
and international expertise. The final report and recommendations are to be provided to the Ministry of Energy in 2012.
The Government of Saskatchewan has also begun work to address CCS activities within its provincial regulatory regime.
The provincial government has sought to include CCS within its existing regulatory portfolio and as such, has adapted a
number of existing laws to accommodate the technology. Recent amendments to the Pipelines Act, Crown Minerals Act
and Oil and Gas Conservation Act are expected to adequately facilitate the transportation and storage phases of the
process. Saskatchewan’s participation in Alberta’s Regulatory Framework Assessment may also lead to the development
of further legislation or the adoption of a more holistic and integrated approach to regulation.
‘Second generation’ CCS lawmakers and capacity development
As a part of incorporating CCS within national and sub-national policies, governments and policy-makers have inevitably
sought to examine the potential structure and essential components of a domestic regulatory regime for the technology.
Many of the jurisdictions discussed in the preceding sections have both pioneered particular approaches to regulation,
and led the way in securing relevant amendments to international agreements. A second wave of law and policymakers
now appear to be commencing similar processes, as they try to reconcile their future policy commitments and the
restrictions posed by existing regulatory regimes.
Korea is one country that has made substantial commitments to CCS in recent years, including the release of a
Comprehensive National CCS Implementation Plan in July 2010, which highlighted a number of proposed activities
around the need for the development of the technology and government investment. Although Korea has yet to establish
an integrated legal framework for the technology, it adopted a Ministerial Decree to the Marine Environment Management
Law Amendment in late 2010, to permit captured CO 2
streams to be disposed of at sea. The Korean Carbon Capture
and Storage Association has also commenced a review of the domestic legal and regulatory system for CCS in Korea.
The report, which is to be released in the next twelve months, is expected to include a number of recommendations
for regulatory development.
86 THE GLOBAL STATUS OF CCS: 2011

Beyond the many developed countries that have already commenced the development of regulatory regimes, a number
of developing countries are also paying increasing attention to the need to examine the capacity of their regulatory regimes
to incorporate CCS activities. CCS has advanced in the policy agendas, to a lesser or greater extent, in a number of
developing countries, with South Africa, Indonesia, Malaysia, Brazil, India and China all indicating considerable interest
in the technology. Among these nations, South Africa has already taken a number of steps in recent years to advance
the uptake of the technology. Attention within government has also shifted towards designing regulation for CCS and
several activities have been completed under the auspices of technical assistance programs with the IEA and World Bank.
An analysis of South Africa’s legal and regulatory capacity will also be included in a scoping study, presently underway
to assess the South African Centre for Carbon Capture and Storage (SACCCS) test injection exercise.
Regional analyses have been undertaken by the Asian Development Bank (ADB) in several countries in South East Asia.
The ADB is working with stakeholders, through its technical assistance program, in Indonesia, the Philippines, Thailand
and Vietnam to complete a legal and regulatory analysis for CCS in those jurisdictions. The Asia Pacific Economic
Cooperation (APEC) has also commenced a project titled ‘Permitting Issues Related to Carbon Capture and Storage for
Coal-Based Power Plant Projects in Developing APEC Economies’ which will require an analysis of the existing permitting
regimes in relevant countries.
CHAPTER 4
In addition, organisations such as the Institute and the IEA have supported developing countries in seeking opportunities
to learn from work that has been undertaken internationally. For example in July 2011, South African delegates met with
officials from the Australian and the Victorian governments to discuss the process that was undertaken and issues these
jurisdictions considered when developing CCS legislation. Another benefit of speaking with different jurisdictions is to gain
insight into how they managed the relationships between different governance bodies.
Providing further opportunities for developing countries to learn from the experiences of other jurisdictions would
be beneficial. Facilitating access to insights would help to ensure that developing countries understand the thought
processes that underpinned the development of existing CCS legislation and assist them in tackling similar challenges.
Project level issues
In the Institute’s 2011 project survey, project proponents were asked to respond to the following questions:
••
Does the current policy environment provide adequate policy support for your project over the short,
medium and long term
••
Do the current regulatory requirements facilitate an investment decision within your organisation
Responses to these open-ended questions have been consolidated into a number of high level policy issues in
Table 13 and Table 14. The countries where the projects reside have been categorised into regional groupings
to observe confidentiality of project identity.
Table 13 Project survey responses to policy question
QUESTION: DOES THE CURRENT POLICY ENVIRONMENT PROVIDE ADEQUATE POLICY SUPPORT FOR YOUR PROJECT
OVER THE SHORT, MEDIUM AND LONG TERM
% OF RESPONSE IF NO, WHAT ARE THE NATURE OF THE ISSUES
UNFCCC
GROUPS
Yes No No
comment
Uncertain
or lack of
carbon value
High cost
project
economics
Insufficient
government
support
Uncertainty
legislation/
regulations
Uncertain policy
environment or
implementation
Asian States
Eastern Europe
Western Europe
Other States
Key: 0% > 0% to 25% > 25% to 50% > 50% to 75% > 75% to 100%
POLICY, LEGAL AND STAKEHOLDER ISSUES
87

Table 14 Project survey responses to legal and regulatory question
QUESTION: DO THE CURRENT REGULATORY REQUIREMENTS FACILITATE AN INVESTMENT DECISION WITHIN YOUR
ORGANISATION
ISSUES RAISED BY PROJECTS
EUROPE
NORTH
AMERICA
MIDDLE
EAST ASIA AUSTRALASIA
Delays in project approvals
General site-specific regulatory issues
(eg. permitting and planning regulations)
Uncertainty surrounding the regulation of CO 2
(eg. lack of a carbon price or policy support for CCS)
Incomplete in nature or delay to regulation
International marine legislation
Uncertainty surrounding long-term liability
Trans-boundary transportation of CO 2
Monitoring requirements
Uncertainty surrounding CO 2
transport and storage
Uncertainty around financial guarantees and insurance
Authorised under project-specific or pre-existing
legislation (eg. regulated as an EOR activity)
Activity excluded from scope of implemented
legislation (eg. R&D project)
Enacted legislation provides sufficient certainty
Positive response received, but no clarification
provided by the project
Key: Positive Negative
The nature of the issues identified as key challenges to projects included:
••
uncertainty and/or slow implementation of supporting climate change and energy policies;
••
uncertainty over the future value of carbon, and/or current lack of a carbon price;
••
uncertain access to, and/or insufficient level of government funding over the medium to longer term;
••
high upfront capital costs of CCS;
••
insufficient government financial support; and
••
uncertainty over the implementation of supporting regulations.
These observations are strongly reinforced by the Institute’s follow-up interviews with eight major CCS project proponents
held after the 2011 project survey. Appendix E.3 provides a list of the more substantive comments freely offered by project
proponents, as classified into five major policy related categories including: policy challenges, carbon pricing issues, project
specific challenges, project economics and legal and regulatory issues.
The responses suggest that the regulatory environment continues to provide a significant challenge to project activity,
with many of the projects surveyed highlighting a range of issues requiring additional regulatory intervention. Despite the
growth in regulation for CCS activities over the past few years across many jurisdictions, particularly those previously
detailed, it would appear that further improvements are required to provide projects with the security they want.
A broader or high-level consideration surrounding the price to be placed upon carbon and enduring policy incentives for
the technology continues to affect the confidence of project proponents in several jurisdictions, while for many projects in
Europe a more select grouping of concerns have been raised. Uncertainty or the failure of regimes to sufficiently address
long-term liability for stored CO 2
and the perceived delay or incomplete nature of regulation, have also been emphasised
by projects as critical to their future investment decisions.
A positive perspective may be found in the ability of pre-existing or project-specific legislation to address the needs
of some projects, with a number of jurisdictions citing successful examples. The legislation already enacted in Canada
would also appear to provide an example of regulators successfully addressing the needs of projects.
88 THE GLOBAL STATUS OF CCS: 2011

Observations and outlook
The development of law and regulation for CCS activities has continued at a considerable pace since the
2010 Status Report, with a number of jurisdictions completing work on their framework legislation and commencing
the implementation of secondary regulations and guidance documents. It is also noticeable, however, that political
pressures, changes in governmental policy and public opposition continue to impact upon the pace of development
and the desire to enact CCS legislation.
Many of the countries and regions that have been acknowledged as leaders in the deployment of laws and regulation for
CCS have continued in these roles. European Member States, Australia, the United States and Canada have all sustained
their regulatory momentum and delivered a number of new proposals, laws, regulations and initiatives in the past twelve
months. The importance of effective regulation has also been recognised by the many countries that are to become the
second generation of CCS lawmakers. While many of these countries have yet to pass legislation, or complete the design
of their regulatory frameworks, it is clear that significant actions are being taken to facilitate their development. This is
particularly noticeable amongst a number of developing countries who are keen to integrate CCS into future climate change
mitigation strategies. The inclusion of CCS in the CDM, or under any future UNFCCC mechanism, could also aid CCS
demonstration in developing countries.
CHAPTER 4
Internationally the picture remains less clear, with a number of issues still unresolved or pending. The ratification of the
OSPAR Convention by the requisite number of parties will finally see the entry into force of the 2007 amendments and is a
positive sign for those seeking to undertake offshore CCS activities. This achievement must however, be tempered with the
failure of the majority of the Parties to the London Protocol to ratify the amendment to article 6 of the agreement, a factor
that continues to prevent the Parties from cooperating on offshore storage.
Effective policy and regulatory regimes clearly have a significant role to play in the development of CCS projects globally.
Notwithstanding the significant efforts of governments around the world to develop and implement regulatory
frameworks, the project responses clearly indicate a core of issues, which for project proponents have yet to be adequately
addressed. The pace of regulation, or its incomplete nature, long-term liability and the sufficiency of incentives are all
identified as areas of deficiency and it will be important for regulators and policymakers to address these concerns in a
timely manner. A number of proposals, amendments and review exercises have already been put in motion by regulators
and policymakers across several jurisdictions. Whether or not these activities will sufficiently address projects’ concerns will
be an important consideration in the forthcoming years.
4.2 Status of funding support
Governments around the world have provided a range of different types of funding support to CCS demonstration
projects. The discussion in this section refers to all direct financial support, including tax credits, not just allocations
such as grants. Government support arrangements for the large-scale demonstration program currently under
way were primarily developed and announced in 2008 and 2009. The funding is associated with both a desire to
accelerate innovation activities for CCS as a low-carbon technology and the need for economic stimulus activities.
In total, approximately US$23.5bn has been made available to support large-scale CCS demonstration projects (Figure 43).
At the end of 2010, approximately 55 per cent of the available funding had been allocated to specific projects. In 2011,
this has remained largely unchanged. Canada (including Alberta), the Netherlands and the United States have
allocated all grant arrangements to specific projects, with some tax credit arrangements in the United States still
to be allocated. Australia, the United Kingdom and the European Commission are working through competitive
tendering processes.
POLICY, LEGAL AND STAKEHOLDER ISSUES
89

Figure 43 Public funding support commitments to CCS demonstrations by country 1
United States
6.1
1.3
European Union
1.4
4.2
Australia
0.5
3.6
Canada
2.9
United Kingdom 2
1.6
Norway
Korea
Netherlands 3
0.8
0.3
1.0
1 2 3 4 5 6 7
US$bn
Allocated
Unallocated
1 Projects in China are supported by state-owned enterprises 1 Projects together in China with support are supported from the by state-owned international enterprises community. together Funding with arrangements support from for
these projects are not included.
the international community. Funding arrangements for these projects are not included.
2 The UK has committed to supporting three additional projects beyond the current
2 The United Kingdom has committed to supporting three additional demonstration projects competition beyond the process. current The demonstration funding commitment competition to support process. this The policy funding is yet
commitment to support this policy is yet to be announced, to but be announced, according to but estimates according made to estimates in 2009, made the in total 2009, support the total required support for required a program for
of four demonstration projects could be in the range of £7.2-9.5bn. a program of four demonstration projects could be in the range of £7.2-9.5bn.
3 Includes a Dutch government funding commitment to Air Liquide that is conditional on
3 Includes a Dutch government funding commitment to Air being Liquide selected that is in conditional the NER300 on funding being program. selected in the NER300 funding program.
With these remaining tendering processes still being worked through, there has been little change in overall funding
arrangements in 2011. In June, the Australian Government selected the Collie Hub project for funding under
the AU$1.68bn (US$1.84bn) Carbon Capture and Storage Flagships Program. A provisional AU$333 million
(US$365 million) has been provided. This comprises AU$52 million (US$57 million) for funding the first key phase of
the project development, the completion of a detailed storage viability study. Should this first phase of the Collie Hub
project be successful, the Australian Government anticipates contributing another AU$281 million (US$308 million)
in funding with the aim of leveraging over AU$660 million (US$723 million) in industry and state government funding
required to complete the project.
North America
In North America, there are mixed outcomes in 2011 in relation to total funding available to projects. In the United States,
total funding for demonstration projects was significantly increased in 2009 under the American Recovery and
Reinvestment Act (ARRA). Over 90 per cent of the US$3.4bn made available under the ARRA has been allocated
to large-scale projects with power (seven projects) or industrial (three projects) applications. The rest of the funding has
been directed towards supporting storage site characterisation and research and development in capture technologies.
Should any of these projects not proceed, the funding received under the ARRA is returned to the United States Treasury
and used for other purposes. At the moment, the near halt in climate change policy development by the United States
legislature is affecting many projects. Since the 2010 Status Report, there have been eight projects put on-hold or
cancelled (not all of which receive United States government funding support), with one of the key reasons for this being
uncertainty regarding public carbon abatement policies and the lack of a national carbon mandate. Two of these projects,
Mountaineer project and Antelope Valley are not going forward, the former being suspended and the latter being cancelled
with its funds rescinded and returned to the United States Treasury. In addition to ARRA funding, Mountaineer also received
US$188 million under the Clean Coal Power Initiative (CCPI) administered by the Department of Energy. In contrast to ARRA
funding, which by statute must be returned to the Treasury if a project is cancelled, the availability of returned funding
under CCPI for other CCS projects is decided on a case-by-case basis by the United States’ Office of Management and
Budget unless stipulated otherwise by the Congress.
90 THE GLOBAL STATUS OF CCS: 2011

In contrast, projects in Canada continued to move forward with funding arrangements and expanding support during
2011. The Governments of Canada and Alberta are seeking to exploit the abundant oil sand resources within Alberta
and are providing support to abate the associated large emissions through using CCS technologies. The governments
finalised funding arrangements totalling C$1.7bn (US$1.8bn) for three projects earlier this year. At the same time, the
Government of Alberta increased support for all refining or bitumen upgrading projects that capture and store CO 2
in
geological (non-EOR) storage through changes to the Specified Gas Emitters Regulation. The change effectively doubles
the level of support provided through the offset credit mechanism currently available, and also provides opportunities
for further support if credit prices in Alberta increase.
Europe
In May 2011, 13 CCS projects, together with 65 innovative renewable projects, were identified as meeting the criteria
to go forward to the next stage of the NER300 program. The NER300 is a funding instrument where 300 million carbon
allowances under the EU Emissions Trading System (ETS) are set aside (or reserved for new entrants also known as
the ‘new entrant reserve’). It is expected that these permits will be sold from late 2011 through to late 2012 to provide
funding for innovative renewable and CCS projects. For CCS projects, the funds can cover up to 50 per cent of relevant
CCS costs which includes the incremental investment costs as well as the net present value of operating costs less
revenue streams.
CHAPTER 4
As at August 2011, the price of a December 2012 futures contract for a carbon allowance under the EU ETS is
approximately €13. At this price, the total funds raised under NER300 would be approximately €3.9bn (US$5.6bn).
This funding is for both CCS and innovative renewable projects. Assuming 75 per cent of the NER300 funds are used
for CCS projects, this would provide total funds around €2.9bn (US$4.2bn).
The maximum any project can receive is 15 per cent of the funds raised by NER300, or €585 million (US$840 million)
under the above assumptions. If each project were to receive this maximum amount, up to five projects could be
funded if they meet the criteria. More projects could be funded if less than the maximum is provided. Some projects
being considered received funding under the European Energy Programme for Recovery (EEPR). Total funding from
the European Commission cannot exceed 50 per cent for both funds combined, and any allocation from the NER300
fund will be adjusted for any EEPR funding to remain below the 50 per cent limit.
The EIB is currently carrying out financial and technical due diligence of the project proposals and will pass the
information on to the European Commission. Together with the Member States, the Commission will ‘rank’ each of the
projects, with those ranking highest being those with the lowest cost per tonne of carbon stored. The ranking of the
projects will be adjusted to take into consideration the need to demonstrate the different CCS technologies available.
Up to eight of the highest ranked CCS projects can receive funding under the NER300 program. However, as noted
above, the final number of projects supported will depend on the total additional cost for each project that has been
put forward, and the maximum amount of funding that can be provided to any particular project. Final decisions
as to which projects will be funded are expected in the second half of 2012. Overall, the Institute anticipates that the
NER300 program will support between four to six CCS projects in Europe.
Funding arrangements by industry, technology and storage
Over 75 per cent of all the funding allocated to CCS activities to date has been allocated to large-scale demonstrations.
Of this, US$8.1bn, or 76 per cent, has been allocated to power projects (Figure 44a), with projects in the fertiliser,
oil or coal gasification industries accounting for a further 20 per cent.
Pre-combustion technologies are used in both the power industry and for gasification of fossil fuels for a variety of
purposes including fertiliser production. Consequently, pre-combustion technologies account for 50 per cent of all
funding awarded to large-scale demonstrations (Figure 44b).
POLICY, LEGAL AND STAKEHOLDER ISSUES
91

Figure 44 Public funding committed to large-scale CCS demonstration projects
(a) by industry
Power generation
Oil refining and/or fertiliser
Chemical production
Other industrial
Ethanol
Gas processing
1 2 3 4 5 6 7 8
US$bn
(b) by capture technology
Pre-combustion
Post-combustion
Oxyfuel combustion
Gas processing
To be decided
1 2 3 4 5 6 7 8
US$bn
(c) by capture technology for power generation projects
Pre-combustion
Post-combustion
Oxyfuel combustion
1 2 3 4 5 6 7 8
US$bn
(d) by storage type
EOR
Deep saline formations
Depleted oil/or gas fields
Not specified
Combination
1 2 3 4 5 6 7 8
US$bn
However, in considering only the power sector, pre-combustion technologies (that is, IGCC) account for around
40 per cent (Figure 44c). With a stated desire by a number of governments, such as the United States, to switch more
recent funding activities towards post-combustion approaches in the power sector, these technologies also account
for 40 per cent.
92 THE GLOBAL STATUS OF CCS: 2011

The IPCC has estimated that there is 1 700 to 11 000Gt of storage potentially available across a variety of storage types
with deep saline formations making up more than 90 per cent of suitable geological formations (IPCC 2005). In the
distribution of funding to date, projects using deep saline formations account for 41 per cent of funding allocation
where a storage type has been identified (Figure 44d). In contrast, projects using EOR in active oil fields accounts
for almost 50 per cent of allocated funding to date. The share of funding allocated to projects associated with EOR
storage operations may reflect the extent that CO 2
EOR is providing an initial ‘facilitator’ role in the demonstration of CCS
in regions of EOR potential, as discussed earlier.
Nearly 40 large-scale demonstration projects have received government funding totalling more than US$10bn worldwide.
Not all of these projects are considered to be fully integrated CCS projects with storage options. Also, some of these
projects have since been cancelled or put on-hold, and some have only received relatively small funding for early
stage assessment. However, the bulk of funding allocated to date has been awarded to twenty-one projects receiving
US$200 million or more each. In total, these LSIPs have been allocated US$9.6bn, accounting for some 89 per cent
of total CCS project funding awarded (Figure 45). FutureGen 2.0 is the largest single project recipient receiving
US$1.048bn.
CHAPTER 4
Figure 45 Public funding to large-scale projects 1 200 400 600 800 1000
FutureGen 2.0
Quest
Project Pioneer
Kemper County
Texas Clean Energy
Alberta Carbon Trunk Line 2
ROAD
Taylorville Energy Center
Lake Charles Gasi cation
Korea-CCS 1 3
Korea-CCS 2 3
Collie Hub
HECA
Swan Hills Synfuels
Mongstad (CCM)
Bełchatów CCS
Compostilla
Don Valley
Jänschwalde
Air Products
Boundary Dam
US$ million
Power
Industry
1 Variable year dollars.
1 Variable year dollars.
2 The Alberta Carbon Trunk Line, while recipient of the funding from the Canadian and
2 The Alberta Carbon Trunk Line, while recipient of the funding Alberta from governments, the Canadian forms and part Alberta of two projects governments, – Agrium forms and part the Northwest of two projects Upgrader. –
Agrium and the Northwest Upgrader.
3 Funding amounts attributed to the Korean CCS-1 and CCS-2 projects were evenly split
based on the total Korean Government funding for demonstration activities, although
3 Funding amounts attributed to the Korean CCS-1 and CCS-2 projects were evenly split based on the total Korean Government funding
project-specific allocation decisions are yet to be made.
for demonstration activities, although project-specific allocation decisions are yet to be made.
POLICY, LEGAL AND STAKEHOLDER ISSUES
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Capacity development funding arrangements
Over the past three years there has been a concerted effort by several countries and organisations to advance capacity
development activities in developing countries. Organisations and countries that have contributed significant funds in this
space include the European Union, the Institute, the Norwegian Government, and the United Kingdom Government.
These contributors have provided direct support by financing specific activities as well as contributing to CCS capacity
development funding mechanisms. For example, Norway has contributed or allocated over US$200 million to be spent
between 2009 and 2014.
Contributions have been made to capacity development funding mechanisms that are managed by the World Bank and
the Carbon Sequestration Leadership Forum. In terms of individual projects (amongst others) Norway provides financial
support to the IEAGHG international summer school, SACCCS and the UNIDO Global CCS Industrial Roadmap which
will provide relevant information on actions and milestones to government and industry decision-makers to facilitate the
deployment of CCS in industry.
The Institute has provided over US$25 million to capacity development activities, including the UNIDO roadmap.
The Institute has also contributed to the Asian Development Bank, World Bank and CSLF funds. In addition to committing
to funding mechanisms and activities managed by others, the Institute also has its own capacity development program.
The Government of the United Kingdom has been particularly active in providing support to capacity development
activities in China. Events such as the Local Clean Coal Seminar and the CCS Symposium in South West China have
raised CCS awareness with Chinese stakeholders, including generation companies and local and regional government.
Activities such as these and the China Low-carbon Energy Action Network have brought together relevant industries
and academics to introduce and discuss in detail the issues related to CCS with target audiences. Additionally,
the United Kingdom has provided strong support to the CSLF capacity development fund and SACCCS.
Who should pay for demonstration activities
Firms in the energy supply sector, particularly equipment suppliers undertake strong R&D programs to innovate
in both existing as well as new technologies, including CCS technologies. Governments also support the R&D efforts
of private firms through tax arrangements, and other funding opportunities as well as funding much of the so-called
‘basic research’ that occurs in universities. The policy rationale for this funding is driven by the existence of ‘spillovers’
from research. These are benefits to society from innovation that cannot be fully captured by those undertaking costly
research and development. Investments in innovation generate knowledge that spills over to other firms and users,
reducing the returns to innovators and hence the incentives to marshal sufficient resources to fully support innovation
in new technologies. This leads to underinvestment in developing new technologies and a slower and less efficient
path of innovation.
This provides a rationale for governments to increase the total flow of funds to innovation activities through use of
general revenues arising from taxation, or through taxation concessions. A key challenge in designing policies to support
innovation is to encourage private investments that would not otherwise occur and that generate total returns, both private
and spillover (or societal), that are sufficiently positive to exceed the costs associated with the policy measures.
In the absence of policies that effectively address this market failure, the challenge of addressing the risks of climate
change would lead to higher total costs to society than otherwise, particularly if innovation in low-carbon technologies
is left solely to the incentives associated with pricing carbon through market measures to reduce greenhouse
gas emissions.
Governments, in anticipation of large potential returns for managing climate change risks, have provided the funding
to support a large-scale CCS demonstration program across the world. The anticipated benefits relate to achieving
commercialisation of CCS technologies earlier than otherwise through cost reductions and performance improvements.
These benefits arise from actions to support and exploit the knowledge spillovers through accelerated knowledge
sharing requirements associated with the funding support.
In addition to the benefits to society that arise from accelerating innovation for low-carbon technologies, firms that
supply inputs for use by low carbon technologies can also benefit from accelerated development of CCS technologies.
Any technology innovation along a supply chain that supports or increases demand for a particular set of inputs may
convey a benefit to the owners of those inputs. In some cases, the owners of those inputs may have an incentive
to support technology innovation. Sometimes such support arrangements may require the coordinating support of
governments to manage potential free rider issues.
In a world where there is global or even partial, policy action that constrains CO 2
emissions, CCS technologies increase
the demand for fossil fuels relative to the absence or reduced availability of the technology. To the extent that the
94 THE GLOBAL STATUS OF CCS: 2011

increased demand creates, or increases, any economic surplus associated with the production of fossil fuels, this can
create an incentive for owners of fossil fuel resources to also contribute to innovation activities for CCS, including
demonstration activities. One example of this is the COAL21 fund established by the Australian Coal Association in
2006. Through a voluntary levy on the production of black coal, the industry aims to raise approximately AU$1bn
(US$1.1bn) over ten years. As at December 2010, the levy had raised AU$234 million (US$256 million) with
approximately AU$141 million (US$154 million) expended (Australia, Senate Standing Committee on Economics, 2011).
In ensuring sufficient resources are directed to support research and demonstration projects, an issue arises over the
extent to which coordinating payments from beneficiaries of research or demonstration outcomes can be improved
through government involvement, leading to more efficient outcomes overall.
As an extractive resource industry there is also potential to draw on the resource rents generated in the industry
without altering either the production or use of fossil coal and gas resources as a potential funding source for
innovation activities. At the same time, the changing patterns of resource extraction in anticipation of future changes
in consumption patterns due to both climate change policy as well as the developments of competing renewable
technologies, presents challenges in identifying whether changes to those arrangements will result in improvements
to both the industry and to the community more generally.
CHAPTER 4
4.3 Public engagement
Continued need for effective management of public engagement
Public engagement continues to present risks and opportunities to CCS projects. The area covers interaction with
stakeholders able to influence project progress and success such as regulators and site communities, as well as the
broader public, including media and NGOs. CCS industries seek balance between levels of general public awareness
that help project communications to become more effective, and collaboration with local communities to understand
and address their specific concerns.
As more projects progress through the final stages of development planning, it is important to continuously review
their approach to identify and mitigate potential public engagement challenges. These stages are where the majority
of work to reduce and manage public engagement risk should be conducted and where CCS projects will continue
to require support from each other, as well as from tools to effectively plan and deliver stakeholder engagement that
comprehensively addresses any of the public’s concerns.
Identification and utilisation of the lessons learnt from existing projects will help other project proponents or developing
country governments to implement more effective approaches.
CASE STUDY
The Collie South West Geosequestration Hub –
Community consultation with the local communities
As part of its public engagement approach, the Collie South West Geosequestration Hub – located in the
south west of Western Australia – engaged CSIRO to assist with a local community consultation workshop
(Jearnneret et al. 2011). The aims of the workshop were to:
1. assess the public’s knowledge and attitudes towards climate change science and low emissions energy
technologies, particularly CCS;
2. establish a framework for future public participation in studies and evaluation of the Collie Hub concept; and
3. explore the effectiveness of a participatory one-day workshop process to enable more informed dialogue
about the issues and risks regarding climate change science and energy technology options.
The aggregated outcomes of the workshop provides Collie Hub with a deeper understanding of the local
community’s perceptions and attitudes, in order to develop an appropriate strategy for providing fact-based
information on the key areas of interest. Furthermore, CSIRO is able to collate the information from other workshops
conducted throughout Australia, enabling comparisons between different regions and communities, and a more
holistic understanding of climate change views and low-carbon energy technology. This type of information is
valuable to governments and project proponents for evaluating what types of communications can assist in
informing different audiences and potentially changing attitudes.
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Institute further monitors public engagement activities
To better understand the status of public engagement strategies, the Institute sought specific information from project
proponents in this year’s project survey. The aim was to allow the industry to identify indicators of a quality strategy,
test the quality of their relevant approaches and begin to share depth around these indicators for a more accurate
assessment of overall industry progress and risk exposure.
Of the projects that responded to the question of whether or not a public engagement strategy was ‘in place’,
‘in development’, ‘still required’ or ‘not required’, 75 per cent indicated that one was either ‘in place’ or in ‘development’.
This represents a quite positive outcome.
Further survey questions centred around four main areas, including:
••
understanding of the site community;
••
interpreting data for effective strategic planning;
••
activities to mitigate risks; and
••
the ongoing monitoring of public engagement risks.
Each of these areas focus largely on the community hosting the storage site, as this is often where the greatest uncertainty
exists for stakeholders, which leads to the highest risks around building relationships and trust. Projects were asked to
self-assess against each quality factor by identifying sets of corresponding outputs. Details of these quality factors and
outputs are given in Appendix F. They highlight the difficulty in attempting to generalise results in an area which requires a
customised approach for each project community location. This limits comparability of detailed activities from one project
to another. However, it can inform data around high-level progress and provide other observations which can potentially
be used to further advance the tools and support instruments available for public engagement activities.
Finally, it is clear that data collection for projects in developing countries is in its early stages. As the number of projects in
developing countries grows, the skills and resources required to successfully complete a project will also need to take
into account public engagement.
CASE STUDY
ScottishPower – A unique approach to educating key
audiences on CCS
As part of their public engagement strategy, ScottishPower supported the implementation of a grassroots approach
in engaging specific audiences within local communities, to broaden knowledge of CCS within the context of
climate change mitigation and an energy portfolio strategy. ScottishPower and the Scottish Government jointly
funded a project to create an ambitious high school education program focussed on CCS. This program was built
on the earth sciences education programs developed by the Scottish Earth Sciences Education Forum (SESEF)
at Edinburgh University, and had a dual purpose:
• to improve understanding of CCS in the local communities near Longannet Power Station
(the site of ScottishPower’s flagship CCS demonstration); and
• to use a real life example of cutting edge science and technology to bring to life traditional subjects like
chemistry, maths, physics and geography for high school pupils in the process of choosing their future
study options.
One of the most important elements of the program was using the SESEF team as the independent delivery partner.
This meant that the students’ initial introduction to the concept of CCS was presented in the context of one of
many options for climate change mitigation, and they then had access to the expertise of the CCS team at the
power station.
96 THE GLOBAL STATUS OF CCS: 2011

Resources to assist public engagement strategy development
As CCS industries continue to develop, so too has there been measured progress in the sophistication and quality of
tools and resources developed by various organisations, including the Institute, to assist CCS stakeholders with engaging
various audiences.
Table 15 below highlights recent publications designed to inform and assist project proponents and other interested
stakeholders.
Table 15 Public engagement resources
PUBLICATION
Communications
& Engagement Tool
for CCS Projects
DESCRIPTION
A practical guide to help project proponents
more effectively plan their engagement activities.
It provides a range of methods and activities to
guide public engagement approaches for addressing
social considerations for successful CCS project
demonstration.
ORGANISATIONAL
CONTRIBUTORS
CSIRO, ECN,
Pacific Northwest
Laboratory, AJW Inc.,
University of Illinois,
Global CCS Institute
(Ashworth et al. 2010).
LOCATION
Global CCS
Institute website
CHAPTER 4
Public Engagement Self
Assessment Tool
This tool helps project proponents to effectively plan
and deliver quality stakeholder engagement strategies.
It allows projects to self-assess their public engagement
approach by identifying the recommended outputs at
each phase of the development cycle.
Global CCS
Institute (2011d),
World Resources
Institute.
Global CCS
Institute website
Public Engagement:
Lessons Learned
from European
CCS Demonstration
Projects Network
A report that assists CCS project proponents
in understanding the effectiveness of different
public engagement and communication activities
implemented, and how projects can structure a
holistic approach to the public engagement function.
European CCS
Demonstration
Project Network
(2010) – European
Commission.
European CCS
Demonstration
Network website
Social Site Characterisation
Report
This report begins to examine why and how project
developers can conduct social site characterisation
for CCS projects.
CSIRO, AJW
Inc. (Wade and
Greenburg 2011).
Global CCS
Institute website
The Management of Public
Engagement at the Local,
State and Federal Levels
for the Tenaska Trailblazer
Energy Center Project
Tenaska’s Trailblazer Energy Center is a coal-fuelled
electric generating plant currently under development
in Texas, United States. This report discusses the steps
Tenaska has taken to educate the public, inform them
of the facts, and seek to gain support for the Project.
Tenaska Inc. (2010).
Global CCS
Institute website
Special Eurobarometer
Report – Public Awareness
and Acceptance of CO 2
Capture and Storage
The European Commission released the results of a
public opinion survey about awareness and acceptance
of carbon capture and storage in 12 (of its 27)
Member States in May 2011.
TNS Opinion
& Social (2011)
at the request of
Directorate-General
for Energy.
European
Commission
website
CCS and Community
Engagement:
Guidelines for Community
Engagement in Carbon
Dioxide Capture, Transport,
and Storage Projects
This report was widely consulted and was designed
to provide guidance to CCS project developers,
regulators, and local communities as they engage in
discussions regarding potential CCS projects.
World Resources
Institute
(Forbes et al. 2010).
World Resources
Institute website
This table is a non-exhaustive list, and there are numerous other reports and references available to assist understanding
in public engagement and to build capability and shared knowledge of CCS.
As can be seen from Table 15, there has recently been a focus on researching and benchmarking broader public
perceptions about climate change and energy technologies (such as the CCS perceptions research by Eurobarometer).
This has also occurred on a local level, to help project proponents inform their messaging and community approach.
The next textbox gives an example of this project-specific research undertaken by TransAlta’s Project Pioneer in Canada.
POLICY, LEGAL AND STAKEHOLDER ISSUES
97

CASE STUDY
Project Pioneer – Utilising public perception research to inform
public engagement strategy development
Understanding public perceptions and attitudes is a key step in developing and shaping an effective public
engagement strategy. In Canada, Shell and TransAlta commissioned research to understand climate change,
CCS perceptions and public acceptance from a number of different audiences to help inform their stakeholder
approach. The research was focused in Alberta, where oil, gas and coal are integral to the economy, as well as
across the different Provinces to establish a national perspective. The polling was designed to establish both a
baseline, to determine the holistic levels of public acceptance for CCS, as well as for the local community for
Project Pioneer.
The research provided metrics around the understanding of CCS overall, and the acceptance of it as a climate
mitigation technology. The key take-outs were that the local populations in oil and gas communities tend to
have a much higher understanding, and accordingly a more positive view, of CCS and the benefits that it can
provide – both socially and economically. Furthermore, Canadians are generally very environmentally aware with
most respondents indicating they recognise the urgency of action to mitigate climate change and global warming.
The results directed the proponents as to the key data-driven messages to be developed, to communicate with
audiences on a number of different levels.
TransAlta planned as of mid-2011, to re-examine the perception issues surrounding CCS. It will also be
important to ask the same questions again, to see whether public perceptions have shifted at all, and whether
this means a change in direction, or additional public engagement activities. The results and data interpretation
will continue to shape the public engagement strategies of TransAlta and Shell.
Increased and continuous learning can be facilitated by project leaders sharing information in project to project sessions
designed to help them learn from each other. A number of mechanisms are in place for project leaders to meet and form
relationships that could lead to productive information exchange. One such mechanism was trialled and facilitated by the
Institute to bring together successful practitioners from the Lacq project in France, which indicated ‘finalised’ responses
for each risk understanding and management activity, to support and advise the ROAD project in the Netherlands.
The outcome was successful for the ROAD leadership team, which indicated ‘on track’ progress towards their risk
activities in the 2011 project survey.
The ROAD project has consulted intensively with the people from the Global CCS Institute, mainly on the
preparation of its outreach strategy. They sent the right people in the sense of knowledgeability and very obvious
track records in comparable challenges. The solutions they came up with were obvious but easy to overlook.
The pragmatism was very well appreciated by the ROAD team. If you would ask me for the most appealing
benefit in this respect, the first thing that comes to my mind is ‘keep it simple and make it tangible’.
Hans Schoenmakers, Director Stakeholder Management, ROAD
Given the importance of effective and genuine public engagement to the success of CCS projects, the Institute and
other organisations such as the World Resources Institute and development banks, will continue to work with projects
and governments to share knowledge and develop capacity. Lessons from existing projects and reports can be utilised
to implement good practice approaches, and future knowledge sharing reports will focus on topics such as: evaluating
CCS communication materials, attitudes of environmental activist groups to CCS technologies, and research into public
perceptions of low carbon energy technologies from different regions. Building this knowledge and understanding will
improve stakeholder engagement, which is key to the success of CCS projects.
98 THE GLOBAL STATUS OF CCS: 2011

5
MAKING THE BUSINESS
CASE FOR CCS

5 MAKING THE BUSINESS
CASE FOR CCS
KEY MESSAGES
• As with most industrial projects, building a viable business case for a CCS demonstration project is a
complex and time consuming process that requires both the project economics and the risks to be
understood prior to a final investment decision.
• All projects in operation use CO 2
separation technology as part of an already established industry process
and either use CO 2
to generate revenue through EOR and/or have access to lower cost storage sites based
on previous resource exploration and existing geologic information sets.
• A number of projects in operation or under construction are undertaking CCS in response to, or anticipation
of, longer-term climate policies and/or potential carbon offset markets.
• Power-generation projects have significant additional costs and risks from scale-up and the first-of-a-kind
nature of incorporating capture technology. These costs and risks are not supported by electricity markets,
where there is strong pressure on profit margins. A risk mitigation option for power projects to progress to
construction has been to reduce the CO 2
capture rate from the flue gas stream (Kemper County) and the
scale of the project (Boundary Dam).
• Both government and the private sector have a role in resolving and bringing greater transparency to
business case issues so that the demonstration of CCS progresses and associated learnings and benefits
are realised.
The long-term deployment of any low-carbon technologies will be shaped by the climate change policies of governments.
Policies that place a predictable, long-term financial value on reducing CO 2
and other greenhouse gases – either directly
through a carbon price or indirectly through regulation – are essential to adopt mitigation technologies. In the shorter term,
the development of low-carbon technologies is being accelerated through governments and industry actively contributing
large amounts of funding to research, development and demonstration activities.
In the development of CCS technologies, this effort is focused on proving up capture and storage applications in current
and future high emitting industries, such as power generation. To date, measured progress has been observed in these
large-scale CCS demonstration activities. Progress is dependent on particular industry, country and regional conditions.
Nonetheless, a common challenge across all industries and regions for such large-scale demonstration projects remains
the need to establish a viable business case, derived from both public and private sources of project funding together
with the various revenue streams that may be available.
As with most industrial projects, building a viable business case for a CCS demonstration project is a complex and
time-consuming undertaking that requires both the economics of the project and its risks to be understood prior to
a final investment decision.
The economics of the business case involves defining the individual revenues and costs of a project so that a return
on investment is achieved or, if targets like technology development and research and development are prevailing,
major losses are avoided. For example, in a CCS demonstration project in the power sector, determining the economics
of a business case would factor in the sale price of power, policy impacts such as a price on carbon, government grants,
potential revenues, capital and operating costs of CCS technology and site specific costs.
On top of the usual ‘base case’ project economics, the project risk profile (and potential mitigations) also needs to be
analysed when determining the range of possible financial outcomes. Agreements to lay-off or share these risks with
other project participants have to be forged and contingencies developed for the residual risks. The higher the project
risks the more difficult it is to build a viable business case. The risks to a CCS project may include performance risk,
market and regulatory risk, construction risk and community acceptance risk.
100 THE GLOBAL STATUS OF CCS: 2011

While it is easy to dissect a business case into its components, the reality of bringing the components together is challenging
and highlights the uncertainty faced in demonstrating CCS. This uncertainty adds further complexity to the business case
and increases the time required to adequately define the project to the point that investment decisions can be made.
Project progress
Progress is occurring where projects can establish a viable business case and this often involves the use of mature
capture technology coupled with EOR and/or already well characterised storage reservoirs. However, progress is slower
where projects aim to apply CCS to power generation and ‘greenfield’ storage sites in deep saline formations. For projects
in the construction or operation stages, the key factors affecting the business case (Table 16) are:
••
relatively low cost storage options, including revenue generation through EOR;
••
remote or offshore locations; and
••
the maturity of the capture technology and the sector in which it is applied.
CHAPTER 5
For nearly all projects in the Execute and Operate stages, CO 2
is being stored in already well characterised storage
reservoirs, benefitting from previous subsurface activity of the oil and gas sector, or the CO 2
is being used for EOR
purposes. For example, the Sleipner, In Salah and Gorgon CO 2
Injection projects all inject into deep saline formations
in the near vicinity of appraised gas or oil reservoirs. This has allowed each of these projects to draw upon a wealth of
developed geological data to help identify and characterise the storage site. Other projects, such as the Shute Creek
or the Great Plains/Weyburn-Midale projects draw on EOR opportunities which provide a revenue source in addition
to having well understood geological properties and existing infrastructure.
Many of these projects are also located in remote or offshore locations, or sometimes in communities already engaged
in oil and gas operations. This results in limited community impact in these locations and reduces the costs and risks
in developing and implementing the project overall.
Projects with storage in greenfield deep saline formations, however, have a very different proposition. The expenditures
and timeframe required to characterise a suitable saline formation to the criteria required for a final investment decision
mirror those for new oil and gas exploration, and similarly have no guarantee of success. The timeline can be five to
10 years or more and involve tens to hundreds of millions of dollars in expenditure.
Table 16 Key business features of LSIPs in operation or construction
CLEAR BUSINESS CASE
WHERE REVENUE EXISTS
FOR CO 2
USE
CLEAR BUSINESS CASE IN
RESPONSE TO, OR ANTICIPATION OF,
CLIMATE POLICIES
BUSINESS CASE THAT
REQUIRED BROAD GOVERNMENT
SUPPORT AND OTHER REVENUE
Project
examples
••
Shute Creek Gas
Processing Facility
••
Enid Fertilizer
••
Great Plains/Weyburn-Midale
••
Sleipner CO 2
injection
••
Agrium with ACTL
••
Gorgon CO 2
Injection
••
In Salah
••
Kemper County
••
Boundary Dam
••
Illinois ICCS
CCS
related
project
features
••
CO 2
separation part of
established industry process.
••
Injection into operating
oil fields.
••
CO 2
separation part of established
industry process.
••
Storage site development simplified
through previous resource exploration
and existing geologic information sets.
••
CO 2
separation applied in novel
large-scale industries (power)
at high cost.
••
Injection into operating oil fields
or development of greenfield
deep saline formations.
Business
case
drivers
••
EOR revenues.
••
Reduction in current or future carbon
cost liabilities.
••
Potential revenue from carbon offset
markets.
••
Government grants.
••
Reduction in current or future
carbon cost liabilities.
••
EOR revenues.
••
Risk sharing.
For the non-power projects another factor is that the CO 2
is already captured as part of the production process in
established industries using mature capture technologies. These industrial projects (including gas processing and
synfuel or fertiliser production) produce a relatively pure stream of CO 2
as a processing necessity which then only
requires compression and transport to a storage location. In developing an integrated project, the capture processes
employed in these industries and the associated performance and market risks are well understood.
MAKING THE BUSINESS CASE FOR CCS
101

Overall, these projects capture CO 2
in an existing market environment. They are finding additional revenue support
through EOR or through existing climate policies, such as the carbon tax in Norway, which help to support the
additional costs of compression, transport and storage. Some projects may have owners acting pro-actively in anticipation
of longer-term climate policies. In others, there is anticipation of developments in carbon markets, such as the carbon
offset markets driven by the UNFCCC’s CDM process in the case of the In Salah project. Together, these drivers help
to create a business environment for CCS applications.
However, for power generation projects, which are the focus of large-scale demonstration programs, there are
significant additional costs and risks in the incorporation (at large-scale and for the first time) of capture technology to
separate CO 2
from combustion gases or synthesis gas for solely greenhouse gas reduction purposes. These additional
costs and risks are not supported in most electricity markets where there is strong pressure on profit margins.
Two projects that have been able to make the business case for the application of CCS to power generation are
Kemper County and Boundary Dam. Both of these projects have received government funding which has helped to
cover the additional costs of adding capture. Kemper County has been allocated US$705 million and Boundary Dam
has been allocated C$240 million (US$251 million).
In building a viable business case, it is interesting to note that Kemper County has set its CO 2
capture rate at a relatively
low 65 per cent across 582MW of power while Boundary Dam will capture 90 per cent of the CO 2
from a relatively
small power unit of 110MW. Both approaches reduce the scale of capture equipment required, hence reducing the
capital cost of the project and the capture plant’s operational energy requirements. This may have helped to improve
the business case by reducing costs and increasing prospective revenue through higher power output. Also, capture
technology and performance risks may have been reduced. Furthermore, both projects will use CO 2
for EOR,
minimising storage risk and gaining additional revenue.
Beyond the two power projects in construction, several power projects have been at an advanced level of project planning
for longer than expected, even though government funding has been committed. Hence, government funding is a
necessary component to many business cases of CCS projects but provides no guarantee of success.
Incorporation of capture technology in particular into new power plants introduces greater risks. Risks during construction
as well as operation of the plant increase, for various reasons (Table 17). Many of these risks cannot or can only partly be
laid off or shared with other project participants. Also, the means of mitigating risks and building financial contingencies
may not always be available to address the residual risks of demonstration projects.
Table 17 Comparison of risks between a new build CCS demonstration power project with a conventional power project
PROJECT
STAGE
RISK CATEGORY
IMPACT ON FINANCING
RISK FOR CCS
DESCRIPTION OF RISKS
CONSTRUCTION Cost overrun or delay Higher Price premiums for fixed price and schedule.
Performance Higher Focus on component guarantees.
Interest and exchange
rate variation
Higher
Higher budgets.
Force majeure Same Weather, industrial relations,
equipment delivery risk.
OPERATION Regulatory Higher Storage regulation untested.
Operational performance Higher No reference plants to prove reliability.
Fuel supply Higher Management of oversupply if plant unreliable.
Electricity off-take Higher Supply shortfall penalties if plant unreliable.
CO 2
storage off-take Additional Possible costs if storage off-take unreliable or
minimum supply volumes not met.
Interest and exchange
rate variation
Same
Currency and financial market exposure.
Force majeure Same Weather and industrial relations risk.
Storage closure Additional Liability must be dealt with up front.
102 THE GLOBAL STATUS OF CCS: 2011

As a consequence, access to third party financing and, in particular, common project finance is extremely limited
for CCS demonstration projects. The first operating demonstrations will need to act as reference plants for financiers
by showing the availability and performance of CCS technology and its impact on standard plant operation.
These reference plants will have to provide confidence that the construction and operation risks can be managed and,
most importantly, that minimum levels of power generation necessary for electricity sales to underpin debt servicing
and cover fixed costs can be achieved.
Limited and non-limited project finance will only become available for integrated CCS power generation projects based
on viable business cases and improved risk profiles. As such, the construction and successful operation of plants
demonstrating reliable, integrated capture and storage is essential.
Way forward
Many governments have embarked on early stage development of climate-change policies designed to bring about the
deployment of low or zero carbon energy technologies, primarily through market mechanisms. In setting an explicit
price on carbon, or in shaping expectations around future costs of emissions, these environmental policies provide
support to both CCS demonstration projects and more commercial ventures.
CHAPTER 5
At the same time, the CCS specific policy frameworks being developed by governments cover a range of objectives
including demonstration activities, identifying viable geological storage areas and supporting public awareness
and consultation activities. Project specific financial support programs pursued by governments are focused on
demonstration projects and accelerating the innovation and development of pre-commercial CCS technologies.
All these policies are essential to bridge and shorten the ‘time to market’ for CCS technology. Uncertainties around
the development and timing of policies will also result in postponed decisions for demonstration projects.
The time taken by project proponents to make a final investment decision has been slower than anticipated,
particularly for power projects. Some of the delay arises from the time taken to devise and implement funding
mechanisms and their requirements, such as the NER300 program in Europe and the competition program
in the United Kingdom. Without certainty on funding levels, project proponents are not in a position to consider
the viability of the project. In Europe, the time taken to develop and reach agreement on broad-scale funding
support is affecting both project definitions and initial timelines.
Uncertainty around the development and timing of policies that place a price on carbon also affects construction decisions.
In the United States, the lack of resolution to achieve bipartisan support on the need to mitigate CO 2
emissions significantly
impacts the business case for power projects. This is due to the uncertainty around the level and timing of incentives for
energy consumers to substitute towards any low-carbon energy options. Beyond achieving support to mitigate emissions,
uncertainty regarding the timeframe to implement policy, and the stringency of the policy will delay progress. In an
uncertain world, there are always benefits to developers from postponing decisions in order to better understand the state of
the world that is likely to emerge in the future.
Demonstration projects are underpinned by climate policy, CCS specific policy and an effective regulatory environment.
The rate of project development to date suggests that the absence of any one of these policy supports creates uncertainty
and impedes project progress. Consistent and coherent policy settings across climate change and CCS policy environments
are required. This is the case not only in the breadth of the supporting environment but also with clarity around current and
future settings, particularly anticipated carbon prices or emission reduction pathways.
Project proponents also have a role in increasing the transparency between project cost and technology risks.
This will aid in permitting efficient sharing of the risks between public and private interests in the demonstration process.
While projects face risks in developing a sound business case in an uncertain technology and policy environment,
governments also face policy challenges in identifying the appropriate level of support for CCS from a range of competing
policy needs both within and outside climate policy. At the same time, there are political risks associated with
unsuccessful projects that further highlight the need for more transparency from projects around risks.
Project proponents need to undertake early community engagement as well as continuous monitoring of activities
throughout the project lifecycle. As community sentiment and other factors can shift over time, strategy adaptation may
be required. Individual project sites require tailored strategies based on specific community attributes and regional needs.
Proponents should therefore research and understand the key perceptions and attitudes of the local community and
region, to help inform communications and to build trust and credibility with their key stakeholders.
MAKING THE BUSINESS CASE FOR CCS
103

With the current expectations of CCS costs, particularly as technology issues are resolved through the demonstration
phase, CCS remains a technology that has a mitigation role at significant scale across a variety of industry sectors in the
medium to long term.
Hence, there is value in examining sources of funding to support demonstration activities beyond governments and
project proponents. For example, in a carbon-constrained world, fossil fuel producers may significantly benefit from
the deployment of CCS technologies. The extent to which the fossil fuel industry benefits from CCS is uncertain and
requires careful consideration. However, as seen in Australia, there may be opportunities to raise additional funds from
this sector to support demonstration-scale activities.
Only with ongoing broad cooperation can the demonstration program progress, and the associated learnings and
benefits be realised. Both government and the private sector have a role in addressing and resolving the challenges
necessary to create transparency and resolve business case issues.
104 THE GLOBAL STATUS OF CCS: 2011

APPENDICES
Appendix A Overview of data analysis process 106
Appendix B Asset Lifecycle Model 107
Appendix C Large-scale integrated projects 109
Appendix D Reconciliation of project changes
since 2010 Status Report 122
Appendix E Policy Context 125
Appendix F Public engagement
quality factors 138

APPENDIX A
OVERVIEW OF DATA ANALYSIS
PROCESS
Since 2009, the Institute has sought to maintain the most comprehensive database on CCS projects in order to quantify
progress made towards CCS demonstration. Historically, the Institute’s dataset on LSIPs has been compiled from an annual
survey completed by lead proponents. This survey monitors projects’ progress through the asset lifecycle. It is supported by
independent research undertaken by the Institute’s Australian, North American and European offices, with results retained
for proprietary analysis and displayed in summary form on the Institute’s public website and in its Status Reports.
In 2011, the Institute has improved data quality and relevance to more accurately understand and report on project
demonstration and movement. At the time of publication, returns were received from 85 per cent of projects surveyed
between the months of May to August 2011. This forms an empirical basis for analysis.
Importantly, the Institute has now changed the way it defines an individual project for this and future years to more closely
reflect the capture source and to identify the boundaries of a project that individual proponents have control over. This has
resulted in the renaming of a number of projects and the disaggregation of CCS clusters and networks into their constituent
projects (Appendix D). These changes have been made to:
••
better understand the nature of integration across the CCS value chain;
••
improve the basis for comparison across multiple years (time-series); and
••
reduce the error of double-counting CO 2
volumes and other metrics.
A key element to the improvement efforts has been adopting a statistical framework which drives stronger process
and control through survey efforts, but also creates the appropriate supporting structures to reinforce this.
There are five phases to the Institute’s framework:
••
Development phase: during which planning for the conduct of the survey and the topics on which information
is to be collected are determined.
••
Collection phase: covers those activities undertaken up to and including the lodgement of the completed survey
forms from projects.
••
Processing phase: covers the capture of responses on survey returns and representation in Institute systems.
••
Analysis/Dissemination phase: involves producing a statistical package which informs annual reporting on
overall development of CCS projects and their respective contributions toward the demonstration of CCS.
••
Evaluation phase: evaluation activity brings together all phases to assess performance in preparation for the
following year/s.
This sequence provides the Institute with the ability to adopt a repeatable process with the necessary supporting
structures in place.
106 THE GLOBAL STATUS OF CCS: 2011

APPENDIX B
ASSET LIFECYCLE MODEL
The Asset Lifecycle Model represents the various stages in the development of a project, small or large, as it moves
through planning, design, construction, operation and closure. There are different systems available to define project
stages, sometimes using different terminology, but all effectively use a similar lifecycle model. This framework
(Figure B‐1) reflects the decision points in a project lifecycle where developers either decide to continue to commit
resources to refine the project further (gateways) or assess that future benefits will not cover the expected costs.
APPENDICES
Figure B‐1 Asset Lifecycle Model
FINAL INVESTMENT DECISION
PLANNING
ACTIVE
Project
phase
IDENTIFY
EVALUATE
DEFINE
EXECUTE
OPERATE
CLOSURE
Developer’s
goals
Consider
high-level options
Short list options
for further study
“What could
it be”
Examine
short-listed
options and
sub-options
Establish if any
fatal flaws
Select one
best option for
taking forward
“What should
it be”
Examine selected
option and
provide further
definition to
allow investment
decision to
be made
Demonstrate the
technical and
economic viability
of the project;
“What will it be”
Be capable of
being audited by
third parties
(i.e. peer reviewers,
investors)
Undertake
remaining
(detailed) design
Build organisation
to commission
and manage
asset
Undertake
construction
activities
Undertake
commissioning
Operate the asset
within regulatory
compliance
requirements,
for the operating
life of the asset
Decommission
asset to
regulatory
compliance
requirements
Rehabilitate site
for future
defined use
Build organisation
and provide
resources for
post-closure
Activities
Capture and
Transport
• Concept
studies
• Prefeasibility
studies
• Estimate
overall project
capital cost
(±20-25%) and
operating costs
(±10-15%)
Single option selected
• Feasibility
studies
• Estimate overall
project capital
cost (±10-15%)
and operating
costs (±5%)
Handover to owner for operations
• Project
execution
• Asset
operation
• Asset
decommissioning
Storage
• Site screening
studies
• Site
assessment
studies
• Site selection
studies
• Design and
installation
• Operate
• Close
Source: from WorleyParsons 2009, modified by Global CCS Institute
APPENDICES
107

A project is considered in ‘planning’ when it is in the Identify, Evaluate or Define stages and is considered ‘active’ if it has
made a positive final investment decision and has entered construction (Execute stage) or is in operation (Operate stage).
As a project progresses through each stage, the level of definition increases with an improved understanding of the scope,
cost, risk and schedule of the project. This approach reduces the uncertainty surrounding the project while managing
upfront development costs.
In the Identify stage, a proponent carries out early studies and preliminary comparisons of alternatives to determine
the business viability of the broad project concept. For example, an oil and gas company believes that it could take
concentrated CO 2
from one of its natural gas processing facilities and inject and store the CO 2
to increase oil production
at one of its existing facilities. To start the process the company would conduct preliminary desktop analysis of both
the surface and subsurface requirements of the project to determine if the overall project concept seemed viable and
attractive. It is important that the Identify stage considers all relevant aspects of the project (stakeholder management,
project delivery, regulatory approvals and infrastructure as well as physical carbon capture and storage facilities).
Before progressing to the Evaluate stage, all the project options that meet the overall concept should be clearly identified.
In the Evaluate stage, the broad project concept is built upon by exploring the range of possible options that could
be employed. For the oil and gas company this would involve exploring:
••
which of its facilities, and possibly even facilities of other companies, might be best placed to provide the
concentrated CO 2
for the project;
••
possible pipeline routes that could be utilised from each of these sites and even alternative transport options
such as shipping if relevant; and
••
which oil production field is suitable for CO 2
injection based on its proximity to the concentrated CO 2
, the stage
of oil production at the field and other site factors.
For each option the costs, benefits, risks and opportunities would be identified. The Evaluate stage must continue
to consider, for each option, all relevant aspects of the project (stakeholder management, project delivery, regulatory
approvals, infrastructure as well as physical carbon capture and storage facilities). At the end of this stage,
the preferred option is selected and becomes the subject of the Define stage. The preferred option must be sufficiently
defined. No further key options are to be studied in the Define stage.
In the Define stage, the selected option is investigated in greater detail by carrying out feasibility studies and preliminary
front end engineering and design (FEED). For the oil and gas company this would involve determining the specific
technology to be used, the design and overall costs for the project, the permits and approvals required and the key
risks to the project. In addition, it involves undertaking a range of activities such as focused stakeholder engagement
processes, seeking out finance or funding opportunities and tendering for and selecting an engineering, procurement
and contracting supplier.
At the end of the Define stage, the level of project definition must be sufficient to allow for a FID to be made. The level
of confidence in costing estimates should be ±10-15 per cent for overall project capital costs and ±5-10 per cent for
project operating costs. Collectively, the Identify, Evaluate and Define stages can take between four and seven years.
Development costs to reach a FID can be in the order of 10 to 15 per cent of overall project capital cost depending on
the size, industry and complexity of the project.
In the Execute stage, the detailed engineering design is finalised. The construction and commissioning of the plant
occurs and the organisation to operate the facility is established. Once completed, the project then moves into the
Operate stage.
In the Operate stage, the CCS asset is operated within regulatory requirements and maintained and, where needed,
modified to improve performance.
In the Closure stage, the CCS asset is decommissioned to comply with regulatory requirements. The site is rehabilitated
for future defined use and resources are allocated to manage post-closure responsibilities
108 THE GLOBAL STATUS OF CCS: 2011

APPENDIX C
LARGE-SCALE INTEGRATED
PROJECTS
Large-scale integrated projects are defined as those which involve the capture, transport and storage of CO 2
at a scale of:
••
not less than 800 000 tonnes of CO 2
annually for a coal-based power plant; and
• • not less than 400 000 tonnes of CO 2
annually for other emission-intensive industrial facilities
(including natural gas-based power generation).
APPENDICES
APPENDICES
109

Table C‐1 2011 large-scale integrated CCS projects
OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011 PROJECT NAME DISTRICT COUNTRY INDUSTRY CAPTURE TYPE
Operate 1 Val Verde Natural Gas Plants
(formerly Sharon Ridge)
Texas United States Natural gas
processing
Pre-combustion
Operate 2 Enid Fertilizer Oklahoma United States Fertiliser
production
Pre-combustion
Operate 3 Shute Creek Gas Processing
Facility
Wyoming United States Natural gas
processing
Pre-combustion
Operate 4 Sleipner CO 2
Injection North Sea Norway Natural gas
processing
Pre-combustion
Operate 5 Great Plains Synfuels Plant
and Weyburn-Midale Project
Saskatchewan Canada Synthetic
natural gas
Pre-combustion
Operate 6 In Salah CO 2
Storage Wilaya de
Ouargla
Algeria
Natural gas
processing
Pre-combustion
Operate 7 Snøhvit CO 2
Injection Barents Sea Norway Natural gas
processing
Pre-combustion
Operate 8 Century Plant
(formerly Occidental Gas
Processing Plant)
Texas United States Natural gas
processing
Pre-combustion
Execute 9 Lost Cabin Gas Plant Wyoming United States Natural gas
processing
Pre-combustion
Execute 10 Illinois Industrial Carbon
Capture and Sequestration
Project
Illinois United States Chemical
production
Industrial
separation
Execute 11 Boundary Dam Integrated
Carbon Capture
and Sequestration
Demonstration Project
Execute 12 Agrium CO 2
Capture with
ACTL
Saskatchewan Canada Power
generation
Alberta Canada Fertiliser
production
Post-combustion
Pre-combustion
110 THE GLOBAL STATUS OF CCS: 2011

OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011
TRANSPORT
DETAILS
PRIMARY
STORAGE
OPTION
CAPTURE
VOLUME
(Mtpa)
YEAR OF
OPERATION
CAPTURE
ASSET
LIFECYCLE
STAGE
TRANSPORT
ASSET
LIFECYCLE
STAGE
STORAGE
ASSET
LIFECYCLE
STAGE
Operate 1 132km
onshore point
to onshore
point pipeline
Operate 2 192km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
Enhanced
oil
recovery
1.3 1972 Operate Operational
pipeline
0.7 1982 Operate Operational
pipeline
Commercial
agreement
EOR
Commercial
agreement
EOR
APPENDICES
Operate 3 190km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
7 1986 Operate Operational
pipeline
Commercial
agreement
EOR
Operate 4 0km offshore
point to
offshore point
pipeline
Offshore
saline
formations
1 1996 Operate Operational
(direct
injection)
Operating
storage
facilities
Operate 5 315km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
3 2000 Operate Operational
pipeline
Commercial
agreement
EOR
Operate 6 14km
onshore point
to onshore
point pipeline
Onshore
saline
formations
1 2004 Operate Operational
pipeline
Operating
storage
facilities
Operate 7 150km
onshore point
to offshore
point pipeline
Offshore
saline
formations
0.7 2008 Operate Operational
pipeline
Operating
storage
facilities
Operate 8 256km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
8.5 1 2010 Operate Operational
pipeline
Commercial
agreement
EOR
Execute 9 370km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
1 2012 Execute Construction
of pipeline
Commercial
agreement
EOR
Execute 10 1km onshore
point to
onshore point
pipeline
Onshore
saline
formations
1 2013 Execute Construction
of pipeline
Constructing
storage facilities
Execute 11 100km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
1 2014 Execute Design of
pipeline
Advanced
negotiations
EOR
Execute 12 234km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
0.6 2014 Execute Construction
of pipeline
Advanced
negotiations
EOR
APPENDICES
111

Table C‐1 continued
OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011 PROJECT NAME DISTRICT COUNTRY INDUSTRY CAPTURE TYPE
Execute 13 Kemper County IGCC Project
(formerly Plant Ratcliffe)
Mississippi United States Power
generation
Pre-combustion
Execute 14 Gorgon Carbon Dioxide
Injection Project
Western
Australia
Australia
Natural gas
processing
Pre-combustion
Define 15 Air Products Steam Methane
Reformer EOR Project
Texas United States Hydrogen
production
Pre-combustion
Define 16 Coffeyville Gasification Plant Kansas United States Fertiliser
production
Pre-combustion
Define 17 Lake Charles Gasification Louisiana United States Synthetic
natural gas
Pre-combustion
Define 18 Northwest Upgrader Refinery
with ACTL
Alberta Canada Oil refining Pre-combustion
Define 19 Texas Clean Energy Project Texas United States Power
generation
Pre-combustion
Define 20 Bełchatów CCS Łódź Poland Power
generation
Post-combustion
Define 21 Emirates Steel Industries Abu Dhabi United Arab
Emirates
Iron and steel
production
Industrial
separation
Define 22 Longannet Project Fife United Kingdom Power
generation
Post-combustion
Define 23 Medicine Bow
Coal-to-Liquids Facility
Wyoming United States Coal-toliquids
(CTL)
Pre-combustion
Define 24 OXYCFB 300 Compostilla
Project
Leon Spain Power
generation
Oxyfuel
combustion
112 THE GLOBAL STATUS OF CCS: 2011

OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011
TRANSPORT
DETAILS
PRIMARY
STORAGE
OPTION
CAPTURE
VOLUME
(Mtpa)
YEAR OF
OPERATION
CAPTURE
ASSET
LIFECYCLE
STAGE
TRANSPORT
ASSET
LIFECYCLE
STAGE
STORAGE
ASSET
LIFECYCLE
STAGE
Execute 13 75km
onshore point
to onshore
point pipeline
Execute 14 10km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
Onshore
saline
formations
3.5 2014 Execute Design of
pipeline
3.4-4 2015 Execute Construction
of pipeline
Commercial
agreement EOR
Constructing
storage
facilities
APPENDICES
Define 15 Onshore
point to
onshore point
pipeline
Enhanced
oil
recovery
1 2012 Define Operational
pipeline
Commercial
agreement EOR
Define 16 112km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
0.9 2013 Define Design of
pipeline
Commercial
agreement EOR
Define 17 Onshore
point to
onshore point
pipeline
Enhanced
oil
recovery
4.5 2014 Define Design of
pipeline
Commercial
agreement EOR
Define 18 234km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
1.2 2014 Define Construction
of pipeline
Advanced
negotiations
EOR
Define 19 ≤50km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
2.7 2014 Define Operational
pipeline
Commercial
agreement EOR
Define 20 61-140km
onshore point
to onshore
point pipeline
Onshore
saline
formations
1.8 2015 Define Design of
pipeline
Assessing
suitability of
storage site/s
Define 21 50km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
0.8 2015 Define Design of
pipeline
Advanced
negotiations
EOR
Define 22 251-300km
onshore point
to offshore
point pipeline
Offshore
depleted
oil and gas
reservoirs
2 2015 Define Design of
pipeline
Detailed site
characterisation
Define 23 Onshore
point to
onshore point
pipeline
Enhanced
oil
recovery
3.6 2015 Define Operational
pipeline
Commercial
agreement EOR
Define 24 120km
onshore point
to onshore
point pipeline
Onshore
saline
formations
1.1 2015 Define Design of
pipeline
Assessing
suitability of
storage site/s
APPENDICES
113

Table C‐1 continued
OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011 PROJECT NAME DISTRICT COUNTRY INDUSTRY CAPTURE TYPE
Define 25 Porto Tolle Veneto Italy Power
generation
Post-combustion
Define 26 Project Pioneer Alberta Canada Power
generation
Post-combustion
Define 27 Quest Alberta Canada Hydrogen
production
Pre-combustion
Define 28 Rotterdam Opslag en Afvang
Demonstratieproject (ROAD)
Zuid-Holland Netherlands Power
generation
Post-combustion
Define 29 Spectra Fort Nelson CCS
Project
British
Columbia
Canada
Natural gas
processing
Pre-combustion
Evaluate 30 Vattenfall Jänschwalde Brandenburg Germany Power
generation
Oxyfuel
combustion
Define 31 Green Hydrogen
(formerly Air Liquide)
Zuid-Holland Netherlands Hydrogen
production
Pre-combustion
Define 32 Taylorville Energy Center Illinois United States Power
generation
Pre-combustion
Define 33 Tenaska Trailblazer Energy
Center
Texas United States Power
generation
Post-combustion
Define 34 ULCOS – Blast Furnace Lorraine France Iron and steel
production
Industrial
separation
Define 35 Eemshaven CCS Groningen Netherlands Power
generation
Post-combustion
Define 36 Hydrogen Energy California
Project (HECA) 2 California United States Power
generation
Pre-combustion
Define 37 Hydrogen Power Abu Dhabi
(HPAD)
Western
Region
United Arab
Emirates
Power
generation
Pre-combustion
114 THE GLOBAL STATUS OF CCS: 2011

OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011
TRANSPORT
DETAILS
PRIMARY
STORAGE
OPTION
CAPTURE
VOLUME
(Mtpa)
YEAR OF
OPERATION
CAPTURE
ASSET
LIFECYCLE
STAGE
TRANSPORT
ASSET
LIFECYCLE
STAGE
STORAGE
ASSET
LIFECYCLE
STAGE
Define 25 101-150km
onshore point
to offshore
point pipeline
Define 26 90km
onshore point
to onshore
point pipeline
Offshore
saline
formations
Enhanced
oil
recovery
1 2015 Define Design of
pipeline
1 2015 Define Design of
pipeline
Assessing
suitability of
storage site/s
Preliminary
negotiations
EOR
APPENDICES
Define 27 84km
onshore point
to onshore
point pipeline
Onshore
saline
formations
1.2 2015 Define Design of
pipeline
Detailed site
characterisation
Define 28 ≤50km
onshore point
to offshore
point pipeline
Offshore
depleted
oil and gas
reservoirs
1.1 2015 Define Design of
pipeline
Detailed site
characterisation
Define 29 20km
onshore point
to onshore
point pipeline
Onshore
saline
formations
2.2 2015 Define Design of
pipeline
Detailed site
characterisation
Evaluate 30 51-100km
onshore point
to onshore
point pipeline
Onshore
saline
formations
1.7 2015 Define Design of
pipeline
Exploration of
prospective
sites
Define 31 600km ship/
tanker
Enhanced
oil
recovery
0.5 2016 Define Design of
shipping
terminal
Preliminary
negotiations
EOR
Define 32 ≤50km
onshore point
to onshore
point pipeline
Onshore
saline
formations
3 2016 Define Design of
pipeline
Detailed site
characterisation
Define 33 201-250km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
5.8 Not
specified
Define
Not
specified
Identifying
prospective
EOR
Define 34 51-100km
onshore point
to onshore
point pipeline
Onshore
saline
formations
0.7 2016 Define Design of
pipeline
Assessing
suitability of
storage site/s
Define 35 Ship/tanker Enhanced
oil
recovery
1.2 2017 Define Design of
shipping
terminal
Identifying
prospective
EOR
Define 36 6.4km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
2 Not
specified
Define
Design of
pipeline
Advanced
negotiations
EOR
Define 37 201-250km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
1.7 2017 Define Design of
pipeline
Advanced
negotiations
EOR
APPENDICES
115

Table C‐1 continued
OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011 PROJECT NAME DISTRICT COUNTRY INDUSTRY CAPTURE TYPE
Define 38 PurGen One New Jersey United States Power
generation
Pre-combustion
Evaluate 39 Sinopec Shengli Oil Field
EOR Project
Shangdong China Power
generation
Post-combustion
Evaluate 40 C.GEN North Killingholme
Power Project
North
Lincolnshire
United Kingdom
Power
generation
Pre-combustion
Evaluate 41 Cash Creek Generation Kentucky United States Power
generation
Pre-combustion
Evaluate 42 Collie – South West CO 2
Geosequestration Hub
(Collie Hub)
Western
Australia
Australia
Fertiliser
production
Pre-combustion
Evaluate 43 Don Valley Power Project South
Yorkshire
United Kingdom
Power
generation
Pre-combustion
Evaluate 44 Getica CCS Demonstration
Project
Gorj County Romania Power
generation
Post-combustion
Evaluate 45 Indiana Gasification Indiana United States Synthetic
natural gas
Pre-combustion
Evaluate 46 Mississippi Gasification
(Leucadia)
Mississippi United States Synthetic
natural gas
Pre-combustion
Evaluate 47 Riley Ridge Gas Plant Wyoming United States Natural gas
processing
Pre-combustion
Evaluate 48 Swan Hills Synfuels
“An In-Situ Coal Gasification/
Power Generation Project”
Alberta Canada Synthetic
natural gas
Pre-combustion
Evaluate 49 Eston Grange CCS Plant North East
England
United Kingdom
Power
generation
Pre-combustion
Evaluate 50 FutureGen 2.0
Oxy-Combustion
Large Scale Test
Illinois United States Power
generation
Oxyfuel
combustion
116 THE GLOBAL STATUS OF CCS: 2011

OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011
TRANSPORT
DETAILS
PRIMARY
STORAGE
OPTION
CAPTURE
VOLUME
(Mtpa)
YEAR OF
OPERATION
CAPTURE
ASSET
LIFECYCLE
STAGE
TRANSPORT
ASSET
LIFECYCLE
STAGE
STORAGE
ASSET
LIFECYCLE
STAGE
Define 38 160km
onshore point
to offshore
point pipeline
Evaluate 39 ≤50km
onshore point
to onshore
point pipeline
Offshore
saline
formations
Enhanced
oil
recovery
2.6 2017 Define Design of
pipeline
1 2014 Evaluate Not
specified
Detailed site
characterisation
Commercial
agreement
EOR
APPENDICES
Evaluate 40 Onshore
point to
offshore point
pipeline
Offshore
saline
formations
2.5 2015 Define Design of
pipeline
Exploration of
prospective
sites
Evaluate 41 Onshore
point to
onshore point
pipeline
Enhanced
oil
recovery
2 2015 Evaluate Design of
pipeline
Advanced
negotiations
EOR
Evaluate 42 51-100km
onshore point
to onshore
point pipeline
Onshore
saline
formations
2.5 2015 Define Design of
pipeline
Assessing
suitability of
storage site/s
Evaluate 43 Onshore
point to
offshore point
pipeline
Enhanced
oil
recovery
4.8 2015 Evaluate Design of
pipeline
Advanced
negotiations
EOR
Evaluate 44 40km
onshore point
to onshore
point pipeline
Onshore
saline
formations
1.5 2015 Define Design of
pipeline
Assessing
suitability of
storage site/s
Evaluate 45 Onshore
point to
onshore point
pipeline
Enhanced
oil
recovery
4.5 2015 Evaluate Design of
pipeline
Commercial
agreement
EOR
Evaluate 46 176km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
4 2015 Evaluate Design of
pipeline
Commercial
agreement
EOR
Evaluate 47 Onshore
point to
onshore point
pipeline
Enhanced
oil
recovery
2.5 2015 Evaluate Design of
pipeline
Preliminary
negotiations
EOR
Evaluate 48 51-100km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
1.4 2015 Evaluate Design of
pipeline
Advanced
negotiations
EOR
Evaluate 49 225km
onshore point
to offshore
point pipeline
Offshore
saline
formations
2.5 2016 Define Design of
pipeline
Assessing
suitability of
storage site/s
Evaluate 50 ≤50km
onshore point
to onshore
point pipeline
Onshore
saline
formations
1.3 2016 Define Design of
pipeline
Assessing
suitability of
storage site/s
APPENDICES
117

Table C‐1 continued
OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011 PROJECT NAME DISTRICT COUNTRY INDUSTRY CAPTURE TYPE
Evaluate 51 GreenGen IGCC Project Tianjin China Power
generation
Pre-combustion
Evaluate 52 Peel Energy CCS Project North Ayrshire United Kingdom Power
generation
Post-combustion
Evaluate 53 Peterhead Gas CCS Project Aberdeenshire United Kingdom Power
generation
Post-combustion
Evaluate 54 Sweeny Integrated
Gasification Combined
Cycle Power Project
Texas United States Power
generation
Pre-combustion
Evaluate 55 UK Oxy CCS Demonstration
Project (formerly Drax)
North Yorkshire United Kingdom Power
generation
Oxyfuel
combustion
Evaluate 56 Wandoan CCS Project 3 Queensland Australia Power
generation
Pre-combustion
Evaluate 57 Bow City Power Project Alberta Canada Power
generation
Post-combustion
Evaluate 58 Browse Reservoir CO 2
Geosequestration
Western
Australia
Australia
Natural gas
processing
Pre-combustion
Evaluate 59 Emirates Aluminium CCS
Project
Abu Dhabi
United Arab
Emirates
Power
generation
Post-combustion
Evaluate 60 Kentucky NewGas Kentucky United States Synthetic
natural gas
Pre-combustion
Evaluate 61 Korea-CCS 1 Not decided Republic of
Korea
Power
generation
Post-combustion
Evaluate 62 Pegasus Rotterdam Zuid-Holland Netherlands Power
generation
Oxyfuel
combustion
118 THE GLOBAL STATUS OF CCS: 2011

OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011
TRANSPORT
DETAILS
PRIMARY
STORAGE
OPTION
CAPTURE
VOLUME
(Mtpa)
YEAR OF
OPERATION
CAPTURE
ASSET
LIFECYCLE
STAGE
TRANSPORT
ASSET
LIFECYCLE
STAGE
STORAGE
ASSET
LIFECYCLE
STAGE
Evaluate 51 151-200km
onshore point
to onshore
point pipeline
Evaluate 52 301-350km
onshore point
to offshore
point pipeline
Various 2 2016 Evaluate Not
specified
Offshore
depleted
oil and gas
reservoirs
2 2016 Evaluate Design of
pipeline
Exploration of
prospective
sites
Assessing
suitability of
storage site/s
APPENDICES
Evaluate 53 Onshore
point to
offshore point
pipeline
Offshore
depleted
oil and gas
reservoirs
1 2016 Evaluate Conversion
of pipeline
Detailed site
characterisation
Evaluate 54 ≤50km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
5 2016 Evaluate Design of
pipeline
Advanced
negotiations
EOR
Evaluate 55 Onshore
point to
offshore point
pipeline
Offshore
saline
formations
2 2016 Define Design of
pipeline
Assessing
suitability of
storage site/s
Evaluate 56 ≤50km
onshore point
to onshore
point pipeline
Onshore
saline
formations
2.5, scale
under
review
2017/18 Evaluate Design of
pipeline
Assessing
suitability of
storage site/s
Evaluate 57 ≤50km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
1 2017 Define Design of
pipeline
Preliminary
negotiations
EOR
Evaluate 58 Pipeline Saline
formations
or
depleted
gas
reservoir
3 2017 Define Design of
pipeline
Assessing
suitability of
storage site/s
Evaluate 59 351-400km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
2 2017 Define Design of
pipeline
Advanced
negotiations
EOR
Evaluate 60 ≤50km
onshore point
to onshore
point pipeline
Onshore
saline
formations
5 2017 Evaluate Design of
pipeline
Exploration of
prospective
sites
Evaluate 61 Ship/tanker Offshore
saline
formations
1.2 2017 Evaluate Not
specified
Exploration of
prospective
sites
Evaluate 62 101-150km
onshore point
to offshore
point pipeline
Offshore
depleted
oil and gas
reservoirs
2.5 2017 Evaluate Design of
pipeline
Assessing
suitability of
storage site/s
APPENDICES
119

Table C‐1 continued
OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011 PROJECT NAME DISTRICT COUNTRY INDUSTRY CAPTURE TYPE
Evaluate 63 Quintana South Heart
Project
North Dakota United States Power
generation
Pre-combustion
Evaluate 64 CarbonNet Project Victoria Australia Power
generation
Various
Evaluate 65 Southland Coal to Fertiliser
Project
Southland New Zealand Fertiliser
production
Pre-combustion
Evaluate 66 Full-scale CO 2
Capture
Mongstad (CCM)
Hordaland Norway Power
generation
Post-combustion
Identify 67 Good Spring IGCC Pennsylvania United States Power
generation
Pre-combustion
Identify 68 Lianyungang IGCC with CCS
Project
Jiangsu China Power
generation
Pre-combustion
Identify 69 Dongguan Taiyangzhou IGCC
with CCS Project
Guangdong China Power
generation
Pre-combustion
Identify 70 Korea-CCS 2 Not decided Republic of
Korea
Power
generation
Not specified
Identify 71 Shenhua/Dow Chemicals
Coal to Chemicals Plant
Project (Yulin)
Shanxi China Coal-toliquids
(CTL)
Pre-combustion
Identify 72 Coolimba Power Project Western
Australia
Australia
Power
generation
Not specified
Identify 73 Maritsa Thermal Power
Plant CCS Project
Stara Zagora Bulgaria Power
generation
Post-combustion
Identify 74 Shenhua Coal to Liquids
Plant Project (Ordos City)
Inner Mongolia China Coal-toliquids
(CTL)
Pre-combustion
1 5Mtpa of CO 2
is in the Operate stage and another 3.5Mtpa is in the Execute stage.
2 Project information as of July 2011, with purchase by SCS Energy LLC still to be finalised.
3 Since the conclusion of the second stage of the Australian Government’s CCS Flagship program, the project is in revision and project information
is largely based on the 2010 survey data.
120 THE GLOBAL STATUS OF CCS: 2011

OVERALL
ASSET
LIFECYCLE
STAGE
LSIP
NO.
2011
TRANSPORT
DETAILS
PRIMARY
STORAGE
OPTION
CAPTURE
VOLUME
(Mtpa)
YEAR OF
OPERATION
CAPTURE
ASSET
LIFECYCLE
STAGE
TRANSPORT
ASSET
LIFECYCLE
STAGE
STORAGE
ASSET
LIFECYCLE
STAGE
Evaluate 63 Onshore
point to
onshore point
pipeline
Evaluate 64 51-100km
onshore point
to offshore
point pipeline
Enhanced
oil
recovery
Offshore
saline
formations
2.1 2017 Evaluate Not
specified
1.2 2018 Evaluate Design of
pipeline
Identifying
prospective
EOR
Exploration of
prospective
sites
APPENDICES
Evaluate 65 100km
onshore point
to onshore
point pipeline
Onshore
saline
formations
1 2018 Evaluate Design of
pipeline
Assessing
suitability of
storage site/s
Evaluate 66 Onshore
point to
offshore point
pipeline
Not
specified
1 Not
specified
Evaluate
Design of
pipeline
Assessing
suitability of
storage site/s
Identify 67 ≤50km
onshore point
to onshore
point pipeline
Various 1 2014 Define Not
specified
Exploration of
prospective
sites
Identify 68 201-250km
onshore point
to onshore
point pipeline
Enhanced
oil
recovery
1 2015 Identify Design of
pipeline
Preliminary
negotiations
EOR
Identify 69 101-150km
onshore point
to offshore
point pipeline
Offshore
depleted
oil and gas
reservoirs
1 2017 Identify Not
specified
Exploration of
prospective
sites
Identify 70 Ship/tanker Offshore
saline
formations
1.2 2019 Identify Not
specified
Exploration of
prospective
sites
Identify 71 Onshore
point to
onshore point
pipeline
Identify 72 51-100km
onshore point
to onshore
point pipeline
Various 5 2019 Identify Not
specified
Various 2 2020 Identify Not
specified
Exploration of
prospective
sites
Exploration of
prospective
sites
Identify 73 Onshore
point to
onshore point
pipeline
Onshore
saline
formations
2.5 2020 Identify Design of
pipeline
Exploration of
prospective
sites
Identify 74 Onshore
point to
onshore point
pipeline
Onshore
saline
formations
1 2020 Evaluate Not
specified
Exploration of
prospective
sites
APPENDICES
121

APPENDIX D
RECONCILIATION OF PROJECT
CHANGES SINCE 2010
STATUS REPORT
Table D‐1 below provides a full reconciliation of the major changes made to the Institute’s database of large-scale integrated
projects since the release of the Global Status of CCS: 2010 report. This reconciliation identifies:
••
Projects that have been put on-hold. These projects are not being actively developed at present but may be
revitalised as conditions improve.
••
Projects that have been cancelled with reduced expectation of them being resumed.
••
Projects that have recently been identified as large-scale integrated CCS projects by the Institute.
••
Projects whose classification has been revised to provide greater consistency in overall project representation.
••
Projects that have had a reassessment in their overall asset lifecycle.
••
Projects that have been moved back in their overall asset lifecycle.
••
Projects that have had a significant name change.
••
Projects that have changed their actual or proposed volume of CO 2
by 0.5Mtpa or more.
Table D‐1 Reconciliation of LSIPs with 2010 Status Report
PROJECTS ON-HOLD (‘DORMANT’)
Europe Eemshaven Nuon Magnum 1.3Mtpa Possible gasification of biomass and coal at the Eemshaven (gasfired)
power plant – presently under construction – postponed due to
commercial and environmental reasons.
Immingham CCS Project 4-7Mtpa Owner has reprioritised investment.
Kedzierzyn Polygeneration
Power Plant
2.5Mtpa
Case for investment was deemed difficult at present.
United
States
AEP Mountaineer 235-MWe
CO 2
Capture
1.5Mtpa
Owner will not pursue project at this time beyond FEED due to the
current uncertain status of national climate policy and weak economy.
Boise White Paper Mill 0.7Mtpa Not selected for phase II of government funding.
CEMEX CO 2
Capture Plant 1Mtpa Not selected for phase II of government funding.
CO 2
Global – Project Viking 1.2Mtpa Considered on-hold.
Entergy Nelson 6 CCS Project 4Mtpa Project was put on-hold due to the current uncertain status of national
climate policy and weak economy.
PROJECTS CANCELLED
United
States
Faustina Hydrogen 1.5Mtpa Considered cancelled – no recent publicly available data.
Freeport Gasification 2Mtpa Cancelled following the onset of the global financial crisis.
Shell CO 2
1Mtpa Cancelled due to Shell’s prioritisation of Quest CCS project.
NEWLY IDENTIFIED PROJECTS
China
Sinopec Shengli Oil Field
EOR Project
1Mtpa
Retrofit of post-combustion CO 2
capture at a fluidised bed boiler power
generation plant in Shangdong Province.
122 THE GLOBAL STATUS OF CCS: 2011

Table D‐1 continued
NEWLY IDENTIFIED PROJECTS
Europe
C.GEN North Killingholme
Power Project
2.5Mtpa
New IGCC plant in North Lincolnshire.
United
States
UK Oxy CCS Demonstration
Project (Drax)
Maritsa Thermal Power Plant
CCS Project
2Mtpa
2.5Mtpa
Selected by the United Kingdom government for NER300 submission.
Retrofit of post-combustion capture technology at a 120 MW net
sub-critical lignite-fired power plant in Bulgaria.
Pegasus Rotterdam 2.5Mtpa ‘Oxyfuel’ combustor combined within a CCGT power plant – part of the
Rotterdam Climate Initiative.
Kentucky NewGas 5 Mtpa New synthetic natural gas plant in Kentucky with pre-combustion
CO 2
capture.
APPENDICES
Medicine Bow CTL Facility 3.6Mtpa New coal-to-transport fuels project in Wyoming.
Riley Ridge Gas Plant 2.5Mtpa Gas processing plant under construction in Wyoming with intention
to apply CCS.
RECLASSIFICATIONS
Canada Enhance Energy EOR Project 1.8Mtpa Removed – CO 2
for EOR sourced from the Agrium fertiliser plant and
Northwest Upgrader refinery.
Agrium CO 2
Capture with ACTL 0.6Mtpa New entry – formerly included under Enhance Energy EOR project.
Northwest Upgrader Refinery
with ACTL
1.2Mtpa
New entry – formerly included under Enhance Energy EOR project.
Europe North East CCS Cluster 7.5Mtpa Removed – cluster was split into its two constituent projects.
(note: the Lynemouth project is now on-hold)
Eston Grange CCS Plant 2.5Mtpa Formerly included under the North East CCS Cluster.
Rotterdam CCS Network 3.4Mtpa Removed – constituent LSIPs are listed separately.
Middle
East
Masdar CCS Project 4.3Mtpa Removed – cluster now split into its two constituent projects.
Emirates Steel Industries 0.8Mtpa New entry – formerly included under Masdar CCS Project.
Emirates Aluminium CCS Project 2Mtpa New entry – formerly included under Masdar CCS Project.
United
States
Shute Creek Gas Processing
Facility
7Mtpa
New entry – substitutes for Rangely and Salt Creek EOR.
(volume of CO 2
was set at 7Mtpa to correspond with the capture
volume of the plant)
PROJECT PROGRESS
Rangely 1Mtpa Removed – CO 2
for EOR sourced from Shute Creek.
Salt Creek EOR 2.4Mtpa Removed – CO 2
for EOR sourced from Shute Creek.
Canada
Boundary Dam Integrated Carbon
Capture and Sequestration
Demonstration Project
1Mtpa CCS portion moved to Execute in April 2011.
Spectra Fort Nelson Carbon
Capture and Storage Project
2.2Mtpa
Project moved to Define.
United
States
Century Plant 8.5Mtpa Moved to Operate in late 2010 – 5Mtpa of CO 2
captured in the first
operational train and a further 3.5Mtpa under construction.
Illinois Industrial Carbon Capture
and Sequestration (ICCS) Project
1Mtpa
Project moved to Execute.
Lost Cabin Gas Plant 1Mtpa Project moved to Execute.
PurGen One 2.6Mtpa Project moved to Define.
Taylorville Energy Center 3Mtpa Project moved to Define.
FutureGen 2.0 Oxy-Combustion
Large Scale Test
1.3Mtpa
Project moved to Evaluate.
APPENDICES
123

Table D‐1 continued
REASSESSMENTS
China
Dongguan Taiyangzhou IGCC
with CCS Project
1Mtpa
Project was moved from Define to Identify. Reassessment due to
improved survey information on the phased development of the
base plant and CCS components.
Lianyungang IGCC with CCS
Project
1Mtpa
Project was moved from Define to Identify. Reassessment due to
improved survey information on the phased development of the
base plant and CCS components.
RENAMING
Europe Green Hydrogen 0.5Mtpa Formerly Air Liquide (proponent’s update).
Don Valley Power Project 4.8Mtpa Formerly Hatfield (following purchase by 2Co Energy).
Peel Energy CCS Project 2Mtpa Formerly Hunterston Power APL (proponent’s update).
United
States
Great Plains Synfuels Plant
and Weyburn-Midale Project
3Mtpa
Formerly Weyburn-Midale Storage Project (to reflect capture origins).
Illinois Industrial Carbon
Capture and Sequestration
(ICCS) Project
1Mtpa
Formerly ADM Company Illinois Industrial CCS.
Kemper County IGCC Project 3.5Mtpa Formerly Southern Company IGCC/Plant Ratcliffe (proponent’s update).
Century Plant 8.5Mtpa Formerly Occidental Gas Processing Plant (proponent’s update).
Val Verde Natural Gas Plants 1.3Mtpa Formerly Sharon Ridge (to reflect capture origins).
CHANGES IN CO 2
VOLUME (CHANGES GREATER THAN 0.5MTPA)
Australia CarbonNet Project 1.2Mtpa Volume of CO 2
was revised down from 3.3Mtpa to 1.2Mtpa.
Collie – South West CO 2
Geosequestration Hub (Collie
Hub)
2.5Mtpa
Volume of CO 2
was revised down from 2.5-7.5Mtpa to 2.5Mtpa.
Other
Asia
Korea-CCS 2 1.2Mtpa Volume of CO 2
was revised down from 1.5-2.5Mtpa to 1.2Mtpa.
Europe
OXYCFB 300 Compostilla
Project
1.1Mtpa
Volume of CO 2
was revised down from 1.6Mtpa to 1.1Mtpa.
United
States
Indiana Gasification 4.5Mtpa Volume of CO 2
was increased from 1Mtpa to 4.5Mtpa.
Kemper County IGCC Project 3.5Mtpa Volume of CO 2
was increased from 2.5Mtpa to 3.5Mtpa.
Lake Charles Gasification 4.5Mtpa Volume of CO 2
was increased from 4Mtpa to 4.5Mtpa.
Century Plant 8.5Mtpa Total volume of CO 2
was revised down from 9Mtpa to 8.5Mtpa.
5Mtpa of CO 2
captured in the first operational train and a further
3.5Mtpa under construction.
Sweeny Integrated Gasification
Combined Cycle Power Project
5Mtpa
Volume of CO 2
was increased from 3Mtpa to 5Mtpa.
Taylorville Energy Center 3Mtpa Volume of CO 2
was increased from 1.9Mtpa to 3Mtpa.
124 THE GLOBAL STATUS OF CCS: 2011

APPENDIX E
POLICY CONTEXT
E.1 Background to UNFCCC negotiations
The Kyoto Protocol provides the compliance arrangements in which countries that have ratified the Protocol can deliver
on their emission reduction targets. CCS is explicitly recognised in Article 2.1:
Each Party included in Annex I, in achieving its quantified emission limitation and reduction commitments
under Article 3, in order to promote sustainable development, shall:
APPENDICES
[a] implement and/or further elaborate policies and measures in accordance with its national circumstances,
such as … [iv] Research on, and promotion, development and increased use of, new and renewable forms
of energy, of carbon dioxide sequestration technologies and of advanced and innovative environmentally
sound technologies
There are currently two negotiating tracks under the Convention – the Ad-hoc Working Groups (AWG) of:
••
the Long-term Cooperative Action under the Convention (AWG-LCA)—established under the Bali Action Plan
and is responsible to the Conference of Parties (COP) for implementation issues under the Convention; and
••
on Further Commitments for Annex I Parties under the Kyoto Protocol (AWG-KP)—responsible to the Conference
of the Parties serving as the meeting of the Parties (CMP) for post first commitment (2008-12) emission reduction
commitments and workings of the flexibility mechanisms (including CDM).
The negotiations under the AWG-LCA are important as it defines the:
••
carbon constraints over time – this consists of the long-term global goal for emission reductions which in turn drives
the need for large scale clean energy options such as CCS;
••
Nationally Appropriate Mitigation Actions or NAMA – this includes arrangements for recording support received
for mitigation actions and verifying those actions; and relationships to finance, technology and capacity-building
mechanisms;
••
market mechanisms – guiding principles for measures at the international level to enhance the cost effectiveness
of mitigation, and engage the private sector in such efforts; and opportunities for new market mechanisms;
••
financing – establishes a new fund (Green Climate Fund) with commitments by developed countries to
mobilise US$30bn of funding to 2012 (i.e. ‘fast start’) and US$100bn per annum by 2020 for both mitigation
(could include CCS) and adaptation activities in developing countries;
••
technology – operational and governance arrangements for the Technology Mechanism (a new institutional
arrangement to enhance technology transfer especially in developing countries); and
••
capacity development – determine institutional arrangements for capacity building, including provision of finance.
The negotiations under the AWG-KP are important as it defines the:
••
emission reduction commitments – to determine whether the Protocol will exist post-2012 (including the longevity
of the associated Flexibility Mechanisms and in particular CDM); and the aggregate and individual scales of
emission reductions to be achieved by Parties;
••
provide a basis for the inclusion of CCS in CDM – as per decisions made at COP 16/CMP 6 (Cancun): and
••
transforming pledges to targets.
APPENDICES
125

E.2 National and regional policy environment
Australia
Australia is currently engaged in a public debate on the establishment of a carbon price. The government released
in July 2011 its strategy titled Clean Energy Australia, providing for a transition pathway to a cap and trade emissions
trading scheme (ETS) in 2015.
The policy includes (among other things) the introduction of a fixed price of AU$23 a tonne CO 2
starting on 1 July 2012
and increasing by 2.5 per cent a year in real terms. The fixed price will transition to a fully flexible price under an
emissions trading scheme starting 1 July 2015, with the price determined by the market.
The government has established a National Carbon Capture and Storage Council to oversee the implementation of the
National Low Emissions Coal Strategy and the National Carbon Mapping and Infrastructure Plan. In addition to this,
the government is providing substantial support under its CCS Flagships Program which aims to construct two to four
commercial scale CCS projects with an electricity generating capacity of 1 000 megawatts (MW) or an equivalent size
for other industrial processes.
There is also strong public sector support for CCS R&D. Under the Cooperative Research Centre Program, the Cooperative
Research Centre for Greenhouse Gas Technologies (CO2CRC) is engaging the services of over 200 researchers looking
into the capture of CO 2
from stationary industrial sources; compression; transport; and storage in deep geological
reservoirs. An Education and Investment Fund also supports the research infrastructure component for short-listed
CCS Flagships projects.
In 2006, the Federal government enabled CCS activities to occur in Commonwealth offshore waters through the
Offshore Petroleum and Greenhouse Gas Storage Act.
In 2010, the government made an election commitment called Cleaner Future for Power Stations which includes
the establishment of new emissions standards and reporting requirements for power stations, commencing in
2011. All new coal-fired power stations will need to meet best practice emissions standards and be built CCS Ready
(CCS-R). In late 2010, the Department of Resources, Energy and Tourism (the lead portfolio) released a discussion
paper proposing a way forward to defining and implementing CCS-R. Additional monies were also appropriated in
the government’s 2011-12 Budget to help deliver this task.
Australia is strongly supportive of CCS in the CDM, and has made several formal submissions to the UNFCCC over
the years expressing this view.
At the state level:
••
The Queensland government continues to allocate substantial resources from its Queensland Future Growth Fund
to support the continued sustainable development of CCS activities, as well as having passed enabling legislation
for the permitting of onshore storage activities under its Greenhouse Gas Storage Act. It has also adopted under
its climate change policy titled ClimateQ a CCS-R permitting condition on new coal-fired power stations.
••
The New South Wales Government (NSW) has established a Clean Coal Act to underpin its Clean Coal Fund.
CCS activities are also deemed eligible for funding support under its Climate Change Fund. In 2003, the government
established an ETS called the NSW Greenhouse Gas Abatement Scheme, although the scheme does not provide
direct incentives for the development of CCS projects.
••
Victoria has established the Energy Technology Innovation Strategy (ETIS) which provides funding for prospective
clean energy technologies to drive down their cost curves and so minimise the economic impact of a cost on carbon.
A request for proposals for the second phase closed in September 2010. In 2008, Victoria passed the Greenhouse
Gas Geological Sequestration Act governing the injection of CO 2
in geological formations.
• • Western Australia (WA) is in the process of establishing CCS legislation under its Petroleum and Geothermal Energy
Resources Act. It has already passed the Barrow Island Act which establishes a ministerial approval process for
the Gorgon Gas Processing and Infrastructure Project on the Barrow Island (listed as a National Heritage site).
In March 2010, the WA Environmental Protection Authority released a recommendation that a proposed new coal-fired
power station expansion be approved on the basis that it be CCS-R. A directions paper supporting the development
of WA’s new energy vision titled Strategic Energy Initiative 2031 acknowledges that coal will continue to be a significant
part of WA’s energy mix when used in conjunction with CCS.
126 THE GLOBAL STATUS OF CCS: 2011

Brazil
In December 2010, Brazil passed into law a commitment to reduce its emissions relative to forecast emissions by 2020.
The government has established a Climate Change and Environmental Quality Secretariat responsible for all matters
relating to climate change, as well as policies and instruments to regulate the carbon market such as the CDM.
As a UNFCCC non-Annex I member, Brazil can access the CDM. In mid-2010, Brazil’s formal position on CCS in
CDM was released. The government has expressed formal support (under the UNFCCC’s Common but Differentiated
Responsibilities and respective Capabilities of Countries) for the acceleration of research on CCS technologies as
well as the development, deployment and diffusion (including transfer) of those CCS technologies that are already at
least at demonstration phase. But while Brazil acknowledges CCS is a legitimate option for climate change mitigation,
particularly for Annex I Parties, it states that CCS is not appropriate in the CDM framework and subsequently CCS
projects should not be eligible for crediting.
Canada
In 2007, the then Canadian government passed the Kyoto Protocol Implementation Act which requires the government
to prepare, a climate change plan, a statement on emissions, and to ensure that it meets its obligations under the
Kyoto Protocol. Under Section five of the Act, the Canadian government released in May 2011 the fifth iteration of its
Climate Change Plan for 2011. However, the current government has publicly stated that Canada will only adopt a cap
and trade ETS if the United States signals that it will do the same. The same principle applies to harmonising its climate
change regulations.
APPENDICES
In 2006, the government released a Carbon Dioxide Capture and Storage Technology Roadmap that aims to help
industry, its supply chain, academic and research groups, and governments jointly identify and prioritise strategic R&D,
marketing and investment decisions.
The government has released draft regulations to apply a stringent performance standard to new coal-fired electricity
generation plants and coal-fired units that have reached the end of their economic life. Final regulations are expected
to be released later in 2011.
At the provincial level:
••
Alberta has stated that CCS will deliver 70 per cent of its abatement to 2050. It has established: a C$2bn CCS Fund
(supported by the CCS Statutes Amendment Act establishing a regulatory framework); enacted a Climate Change
and Emissions Management Amendment Act that regulates CO 2
‐e emissions from emitters; released the Alberta
Energy Innovation Strategy (2004-2014) which specifically includes CCS, the Innovative Energy Technology Program
(a royalty relief program for EOR projects), and EcoTrust Funding which is supported by a federal allocation and
includes support for the promotion of CCS.
••
British Columbia (BC) passed (but has not enacted) the Greenhouse Gas Reduction (Cap and Trade) Act which
enables the province to join a regional cap and trade ETS (including the Western Climate Initiative) as well as regulates
industry emission levels. BC has also passed a carbon tax aimed at encouraging investment in low carbon solutions,
while raising revenue to generally reduce the incidence of other taxes. Under the BC Energy Plan—A Vision for Clean
Energy Leadership, the government requires all new electricity generation projects to have zero net emissions; as well
as all existing grid connected oil and gas generation power plants completely offsetting their emissions by 2016.
• • The Saskatchewan government continues its consultations on its proposed Management and Reduction of
Greenhouse Gases Act (which proposes a requirement for emitters to reduce their emissions by 2 per cent annually
over the baseline emission levels of 2010 to 2019; proposes the establishment of a Saskatchewan Technology
Fund Corporation funded by non-compliance fines; provides for negotiated performance agreements outside of
regulations; and offers offset performance credits and credit for early action specifically catering for CCS).
APPENDICES
127

China
The NDRC is the lead institution responsible for energy (through the National Energy Administration) and climate change
(through the Department of Climate Change) policy development. The NDRC recently released a Climate Change Policy
and Actions 2010 Annual Report. This followed a 2009 Climate Change Annual Report that stated the government
had facilitated:
… multiple channels for the development of the critical technological support system for addressing climate
change, including that for CCS.
While many bilateral and multilateral initiatives currently exist in China, as do several Memoranda of Understanding
(MOUs) on CCS between various Ministries and governments, China is yet to implement a CCS specific policy.
China’s National People’s Congress approved the 12th Five Year Plan (FYP) in March 2011. The establishment of the
clean energy sector as one of seven new Strategic Emerging Industries should help enhance the future role of CCS.
This is especially pertinent given the government’s long lived priority of meeting increasing energy demand while
simultaneously reducing pollution, and maintaining coal as a dominant energy source.
China aims to reduce the emission intensity of its economy by 17 per cent per unit of GDP over the five years to
2015. For the immediate future, China has set an emission reduction target of 3.5 per cent per unit of GDP in 2011.
These emission reduction targets provide a pathway to the longer term aspiration to cut emissions intensity by up to
40 per cent by 2020 relative to 2005.
China will also establish ‘low carbon zones’ in eight cities and five provinces, and intends to introduce a carbon
pricing regime. The carbon price could start from about –Y10 per tonne CO 2
-e and increase to –Y40 per tonne by 2020.
There are also plans to also establish some form of ETS in six major cities and provinces (including Beijing, Chongqing,
Shanghai and Tianjin and the provinces of Hubei and Guangdong) by 2013 and expand it nationally by 2015.
China is also considering a carbon tax proposed to be launched in 2012.
European Union
In 1994, the EU adopted the UNFCCC’s objective to stabilise atmospheric greenhouse gas concentrations at a level
that would prevent dangerous climate change (Decision 94/69/EC).
In 2009, the Climate Change and Energy Package (CCEP), also known also as the 20-20-20 Targets, was adopted.
This package sets the climate and energy targets to be met by 2020 including: 20 per cent reduction in emissions
relative to 1990 emissions; 20 per cent of energy consumption to come from renewables; and 20 per cent reduction
in primary energy use compared with projected levels through improved energy efficiency. The CCEP measures
relevant to CCS include:
••
the New EU ETS Directive (Directive 2009/29/EC); and
••
CCS Directive (Directive 2009/31/EC).
The EU ETS (Directive 2003/87/EC) is a cap and trade ETS. The amendments to the Directive, proposed as a part
of the Commission’s CCEP, includes expanding the coverage of activities to include CCS. Under the revised Directive,
CO 2
that has been successfully captured and stored will be viewed as ‘not emitted’, therefore removing the obligation
to surrender allowances, while ending the allocation of free allowances to the power sector, and takes effect in Phase III
(2013 to 2020).
The provisions under the CCS Directive include:
••
creation of a permit based CCS storage regime and amendment of existing EU legislation which prohibits or inhibits CCS;
••
establishment of a regime for operators holding storage permits to conditionally pass long term liability for leakage
from storage sites to Member States; and
••
imposes through incorporation within the EU’s Integrated Pollution Prevention and Control on Industrial Emissions
(Directive 2008/1EC and 2010/75/EU) a requirement that all new combustion plants over 300MW in scale are built
to be CCS-R.
In regard to liability, the CCS Directive applies the Environmental Liability Directive (2004/35/EC) to ensure the
prevention and remedy of any damage by the operators. The surrender of allowances under the EU ETS will address
any fugitive emissions. Also, if there is leakage any shortfalls would have to be made up by the acquittal of allowances.
128 THE GLOBAL STATUS OF CCS: 2011

In December 2009, the European Energy Programme for Recovery (EEPR) was adopted with some 26 per cent of
the EEPR (€1.05bn) being subsequently awarded to six CCS projects. The EEPR aims to help accelerate the CCEP.
To facilitate knowledge sharing the EC also established the European CCS Demonstration Project Network. This Network
aims to foster knowledge sharing amongst large-scale demonstration projects and contribute to raising public
understanding of the potential of this technology, for ultimately achieving commercially viable and safe CCS by 2020.
For the purposes of the EU ETS, stored CO 2
will not be accounted for as an emission, and as such, power plants
will not be required to acquit allowances for the associated emissions. The EU ETS will also provide targeted CCS
funding by freeing up an allocation of up to 300 million allowances from the NER300 to support at least eight CCS
demonstration projects. Submissions under NER300 were discussed in chapter 2. To be eligible for the NER300
assistance, member states are required to transpose the CCS Directive into national law.
The Strategic Energy Technology Plan (SET Plan) is the technology pillar of the EU’s energy and climate policy.
In November 2010, the EC released Energy Strategy 2020. It notes that despite the SET Plan setting out a medium-term
strategy valid across all sectors, the development and demonstration of CCS projects (among other technologies) needs
to be speeded up.
APPENDICES
The EC also released its Energy Infrastructure Priorities for 2020 and Beyond – A Blueprint for an Integrated European
Energy Network which expresses the following timelines for CCS project deployment: pilot plants to come on line in 2015;
commercial rollout in electricity generation and industrial applications by 2020-2025; and a global rollout around 2030.
In March 2011, the EC adopted a Roadmap for moving to a competitive low carbon economy in 2050 which commits
the EC to a 25 per cent reduction in emissions by 2020, a 40 per cent reduction by 2030, 60 per cent by 2040,
and at least 80 per cent by 2050 against 1990 levels. The report states:
… carbon capture and storage would also need to be deployed on a broad scale after 2035, notably to capture
industrial process emissions (e.g. in the cement and steel sector). This would entail an annual investment of
more than €10bn.
Germany
Germany’s CCS policy environment is heavily influenced by the policy decisions of the EC. In 2007, the government
released its Integrated Energy and Climate Programme which contains 29 actions—the focus of Action 3 is CCS,
which states the government has adopted a ‘no regrets’ strategy for CCS and its aim is to enable CCS technologies
to obtain market status by 2020.
In September 2010, the government released its Energy Concept – for an Environmentally Sound, Reliable and Affordable
Energy Supply. As part of its 10 point plan, intended to be implemented by 31 December 2011 and reported on back
to the Bundestag by 31 March 2012, action item nine relates to CCS stating:
The German government will adopt a draft act on CCS in the near future to create a legal basis for testing the
safe storage of CO 2
. This testing is designed to gain the necessary experience. On this basis, the legislature will
then decide on the further implementation of CCS. The act will include high precautionary standards based on
the state of the art in science and technology to ensure safe storage.
India
In its National Action Plan on Climate Change, the Indian government assumes a cautious policy approach to CCS
stating that it still questions the cost as well as permanence of storage repositories. However, some Indian organisations
have commenced dialogue with international organisations regarding CCS, and the Indian Government is a member
of the Carbon Sequestration Leadership Forum, suggesting there is interest in investigating the technology further.
As of 1 July 2010, the government has imposed a levy of INR50 for every tonne of coal (including lignite) produced
in the country or imported. In the 2010-11 Budget, provisions were created for a National Clean Energy Fund through
revenues raised from the coal tax. While a roadmap is yet to be established for how this money is to be invested, it is
expected to go towards the eight missions highlighted in the National Action Plan on Climate Change.
The coal tax is not a carbon tax, and it does not establish a price of carbon. It may do little to encourage CCS unless
some of the revenues are directed towards encouraging CCS mitigation activities, especially in those industries
dependent on fossil fuels.
APPENDICES
129

Indonesia
In 2009, the Ministry of Finance released a Green Paper titled Economic and Fiscal Policy Strategies for Climate Change
Mitigation in Indonesia. The paper reveals the simulated effects of a carbon tax levied on fossil fuel combustion. It also
outlines a strategy to transition from a carbon tax (to be introduced in 2014) to an emissions trading scheme over time.
Although not government policy, the Green Paper floats a rate of Rp80 000 per tonne of CO 2
, rising in real terms by
five per cent per year until 2020. The Ministry of Finance has also formulated a road map and strategy for emission
reductions for the cement and steel sectors.
In 2008, the President established under law the National Council for Climate Change to formulate national policies
to control climate change (including mitigation, transfer of technology and mechanisms for carbon trade). In late 2010,
it released a paper titled Indonesia’s Greenhouse Gas Abatement Cost Curves, which indicates an abatement cost of
about US$14 per tonne CO 2
-e for a new coal-fired CCS plant combined with EOR.
Indonesia’s National Medium Term Development Plan (2010-14) highlights climate change as one of four core action
programs on the environment, and that it is necessary to mainstream mitigation policies in the development plan.
Indonesia’s National Energy Policy indicates that it will increase the share of coal in its total energy mix to at least
33 per cent in 2025. This makes Indonesia’s pledge to reduce its emissions by 25 to 30 per cent relative to business
as usual by 2012-15 and 40 per cent by 2025 all that more challenging, and justifies its current strong yet cautious
interest in CCS.
In late 2009, the government released Indonesia’s Climate Change Sectoral Roadmap which acknowledges that if
no specific measure (such as the introduction of CCS) is applied to the development of coal-fired power plants under
the Accelerated 10 000MW Power Program Phase II, then emissions will definitely increase significantly over the
coming years.
Japan
The Japanese Government has articulated an objective to develop commercially viable CCS technology by around
2020 and introduce CCS in the coal-fired power sector by 2030; subject to the availability of the technology. It also
aims to develop commercially viable capture technology by around 2020 in the steel sector. Specifically, it plans to
promote commercialisation through large-scale demonstration projects that will also focus on safety and environmental
examinations.
Its Basic Energy Plan (administered by METI and revised by Cabinet in June 2010) also states (pursuant to the
Basic Act on Energy Policy) that new coal thermal plants will need to be CCS-R, and be equipped with CCS by 2030
on the pre-condition of commercialisation.
In its Action Plan for Building a Low Carbon Economy (2008), the government highlights CCS (especially applied to
coal and steel production) as one of 21 innovative energy technologies to be financially supported under the Cool Earth
— Innovative Energy Technology Program (2008). The Cool Earth program outlines Japan’s development roadmap for
both highly efficient coal-fired generation and CCS. It also acknowledges that non-ocean storage potential in Japan is
very limited, and as such this makes the exchange of information through international forums a key focus.
Further, METI cites under section seven of its 100 Actions to Launch Japan’s New Growth Strategy (August 2010)
that Japan will upgrade to sophisticated uses of fossil fuels by allocating ¥1.79bn to the development, demonstration,
and overseas expansion of low carbon technologies such as clean coal and CCS, and to introduce it on a full-fledged
basis in the late 2020s.
The Ministry of Environment (MOE) launched the Japan Voluntary Emissions Trading Scheme in 2005. The approximate
price of the associated credits was ¥1 200 per tonne of CO 2
-e. In 2009, METI launched the Domestic Emission Reduction
Certification Scheme for small and medium sized companies. In April 2010, the Tokyo Metropolitan Government launched
its cap and trade ETS, which is expected to facilitate over the period 2010 to 2014 a 6 per cent reduction in emissions
relative to an average of actual emissions of facilities over the past three years; and 17 per cent over the period 2014
to 2019. Power plants and steel plants are covered in the scheme.
In March 2010, the Cabinet approved a new bill titled Basic Act on Global Warming Counter Measures. It includes
provisions for the establishment of a domestic ETS and a carbon tax. The Bill effectively postpones the implementation
of a mandatory ETS by about a year after the Bill enters in force. The Bill is currently awaiting the National Diet’s
consideration and approval.
130 THE GLOBAL STATUS OF CCS: 2011

Korea
In July 2011, the Ministry of Environment announced that it will lead the development and commercialisation of CCS
technology through cooperation with related departments. The ministry describes CCS as the main technology for reaching
the emissions reduction goal of 30 per cent below 2020 BAU levels.
The government has also announced that it plans to begin the commercial operation of two CCS plants by 2020.
In July 2010, the government announced its National CCS Masterplan along with plans to invest around US$1.9bn
by 2019 to support carbon capture technology and industrial infrastructure.
It is expected that Parliament could approve a cap and trade ETS bill later this year, with the scheme likely to start
from 2015. It appears at this stage that 90 to 95 per cent of permits could be freely allocated over the first two years
of operation, with provisions to auction off additional permits as a price control measure. Korea initiated a trial ETS
in January 2010, to operate until 2012.
Further, a greenhouse gas and energy target management system (which allocates emission reduction targets to entities)
is expected to be operational in late 2011, covering firms emitting more than 25 000 tonnes of CO 2
-e per year. There is
also public discussion on a carbon tax.
APPENDICES
The Five Year National Plan for Green Growth finalised in 2009 outlines ten policy directions including (among others)
the effective mitigation of emissions; reduction of the use of fossil fuels; and the development of green technologies.
CCS has also been factored into the modelling of mitigation scenarios and the development of 27 core green technologies.
The Framework to Act on Low Carbon provides the legal basis for the Committee to foster financing for green
technology research and development and green investment; mandates tax reform to promote environment friendly
outcomes; and mandates government to set concrete targets for emissions reduction. Article 46 stipulates an ETS,
however a separate Bill has been proposed.
Malaysia
The five main strategic policy settings affecting CCS developments are outlined in the National Green Technology Policy
(2009), The National Climate Change Policy (2009), The New Energy Policy (2011-2015), The Clean Air Action Plan
Regulations and the 10th Malaysia Plan (2011 to 2015).
While none of these policy documents explicitly refer to CCS activities, Malaysia’s Second National Communication
submitted to the UNFCCC states that:
… success in meeting the 2020 voluntary emissions intensity reduction scenario is conditional upon adequate
access to technology. New areas such as … clean coal, carbon capture and storage … should be considered.
The following are some of the key areas where technology transfer would provide a substantial benefit in terms
of reducing emissions: … (v) methane/CCS/use.
Mexico
In its National Strategy on Climate Change (2007), the government lists CCS as a priority for energy generation and use,
as well as mitigation R&D.
The government also indicates in its Special Climate Change Program 2009-2012 that Mexico is aiming to decarbonise
its economy. The strategy states that to achieve this will require an increase in the use of low or neutral technologies
including CCS. The program lists over 105 objectives and 294 ‘goals’ to help deliver on the country’s emission
reduction target, and this includes a formal objective to enhance the national capacity for the possible application
of CCS and two CCS goals.
The government also expresses support for CCS in its Fourth National Communications to the UNFCCC. Mexico played
a pivotal role in the CCS in CDM negotiations at COP 16 in Cancun. The high-level bilateral discussions on CCS clearly
and positively assisted negotiations.
APPENDICES
131

Netherlands
The Netherlands is currently in phase two (post 2008) of its CCS Roadmap, which includes supporting pilot projects
and transposing the EC CCS Directive. Phase three (2015-20) includes supporting large scale demonstration projects,
and phase four (post 2020) is the commercial deployment of CCS and a review process of the CCS Directive.
As a consequence of its second National Environmental Policy Plan, a regulatory energy tax entered into force in 1996.
Companies that extract or import coal and gas are subject to the tax. In addition to this, the policies for achieving
the emission reduction target are elaborated on in the New Energy for Climate Policy in the Netherlands—Clean and
Efficient work program. The program is scheduled for review in 2011.
The pricing of carbon under the EU ETS is noted as the major driver for abatement in the energy sector, and in the
context of CCS, the government requires new coal-fired power stations to be constructed in such a way that they are
CCS-R. The government is also making agreements with operators of new coal-fired power stations concerning a
reduction in emissions additional to the EU ETS.
The EC CCS Directive is being implemented by means of amending the Dutch Mining Act. In January 2011, the Dutch
Parliament approved the ‘Implementation Proposal’ and it entered into national law in June 2011.
In June 2011, the government released its Energy Report 2011. CCS is being supported within the context of ensuring
a reliable energy supply, and states:
The fact is that, for the time being, Europe is dependent on fossil fuels … and fossil fuels can be made cleaner
by investing in CCS technology. The Dutch economy can benefit greatly from this area as the Netherlands is a
… global leader in the area of CCS.
In its Policy Document of the North Sea (2009), the government states that an inevitable interim step in the transition
to sustainable energy management is through capturing CO 2
at source and transporting it to deep underground storage
facilities. In this context, CCS is considered an issue of national importance. CCS also features in translating one of the
three social development tasks into targets and policy choices under the North Sea Policy.
In February 2011, the government announced that it was not prepared to permit onshore geological storage and is currently
only permitting CCS projects for offshore storage.
Norway
The government articulates in its Fifth National Communications (2010) that it will continue to take a leading role in
the development and deployment of CCS. It characterises its support for CCS research as being complementary to that
of market based mechanisms and highlights that it intends to build on the experiences gained from the Sleipner and
Snøhvit storage projects. This includes Mongstad through an implementation agreement between the government and
Statoil, with permitting by the Ministry of the Environment.
In early 2010, the government released Climate Cure 2020, outlining a number of measures and instruments that can
help achieve Norway’s climate goals – a reduction of between 30 and 40 per cent relative to 1990 by 2020. For CCS,
it specifically highlights measures such as taxes, negotiated agreements, a fund and/or state support.
The government is providing a supportive CCS environment through: stipulating that two thirds of the required abatement
should be made domestically; a carbon tax (introduced in 1991); a cap and trade ETS (implemented in 2005 and linked
in 2007 to the EU ETS); provision of tax incentives for CCS related research (up to 20 per cent on expenses through the
SkatteFUNN Scheme); and a requirement that all new gas-fired power plants are CCS-R. It has also prioritised CCS under
its Energi21 initiative on energy research. In addition to Energi21, Gassnova is managing on behalf of the government the
CLIMIT Programme, which is the national program for CCS research and provides grants for the demonstration of CCS
technologies.
Romania
In April 2011, the government released its National Reform Programme (2011-2013) which states a commitment
to reduce emissions by 20 per cent by 2020 relative to 1990, primarily by applying CCS.
The Ministry of Economy, Trade and Business Environment (METBA) is managing the National Programme for Carbon
Capture and Storage – until 2020. In 2010, the Prime Minister and relevant ministers signed an Action Plan to implement
a demonstration project regarding CCS in Romania. The plan provides for studies and projects to be carried out by 2015
pertaining to the implementation of the CCS project.
132 THE GLOBAL STATUS OF CCS: 2011

Romania has also advised the Commission on progress to transpose the EC CCS Directive. As such, it appears eligible
to access funding under the NER300. Romania has announced its candidacy for NER300 funding.
The National Sustainable Development Strategy 2013-2020-2030 cites that a national objective is to align Romania’s
performance with the EU average in terms of energy and climate change indicators; to meet Romania’s commitments
on reducing emissions in accordance with existing international and EU agreements; and to implement further
measures for adjustment to the effects of climate change. In this regard it states that:
The use of clean technologies for power and heat production will be expanded in generating plants using energy
resources and technologies producing very low levels of carbon emissions and provided with facilities for the
capture and underground storage of CO 2
.
METBE is the lead agency for the policy development of CCS incentives, and is apparently considering the possibility
of levying a new tax on the final consumer with a view to ensuring financing for CCS projects.
Saudi Arabia
The Institute, the Norwegian Government and the United Nations Industrial Development Organization (UNIDO) co-sponsored
a workshop on a Global Technology Roadmap for CCS in Industry in mid-2010, which led to an observation cited in the
final report that CCS (with EOR) in Saudi Arabia could take 10 to 15 years to materialise.
APPENDICES
Saudi Arabia is investing the majority of its resources into CCS R&D. It is one of four oil producing countries that have signed
up to the 4-Kingdom CCS Initiative (the others being the United Kingdom, Norway and the Netherlands). This initiative,
which was established in 2008, aims to encourage a coordinated approach to enhancing national expertise on CCS through
knowledge sharing and the transfer of technology. Its first thematic technical workshop on EOR and its impacts on project
economics was held in February 2011.
The government’s Ninth Development Plan states that oil is the primary source of revenue for the state budget directed
to meeting the needs of public expenditure. The policy settings seem conducive to enhancing the level of CCS activity
in Saudi Arabia.
Saudi Arabia is a very strong advocate for CCS under the CDM, and played a constructive role in related UNFCCC
negotiations at COP 16/CMP 6.
Saudi Aramco’s (state owned national oil company) Carbon Management Technology Roadmap indicates the implementation
of an EOR-CCS demonstration project in Gawhar by 2013.
South Africa
The construction of South Africa’s first CCS demonstration plant is not expected until around 2020, but there is currently
an evolving and dynamic policy dialogue.
As a developing nation heavily dependent on fossil fuel based energy (comprising some 90 per cent of primary energy),
South Africa offers a nexus between the competing challenges of climate change. This includes pursuing sustainable
and local economy development opportunities while continuously improving the emission intensity of energy supply
and industrial activity.
The potential of mitigation options to support the government’s emission reduction aspirations are outlined in a discussion
paper released by the Department of Environmental Affairs late last year titled National Climate Change Response Green
Paper 2010. CCS is explicitly referred to in the plan, including the need to develop a legislative policy and regulatory
framework to support CCS. A White Paper is expected to be submitted to Cabinet later this year.
Resource policy development is led by the Department of Energy, with provision of advice from the South African
Centre for Carbon Capture and Storage (SACCS). In 2009, the Department of Energy initiated a study to investigate
where the gaps in the mineral extraction and carbon storage exist.
SACCCS has developed a five point CCS roadmap. The five points of the roadmap are:
••
investigating the preliminary potential for CCS;
••
completing a geological storage atlas;
••
undertaking a CO 2
injection experiment;
••
building a demonstration plant; and
••
commercial deployment of CCS.
The first and second phases have been completed, including the release of an ‘Atlas on geological storage on carbon
dioxide in South Africa’ in 2010. SACCCS is currently working towards the third phase—the test injection.
APPENDICES
133

United Kingdom
In 2008, the government introduced the Climate Change Act which established a binding emission reduction target of
at least 80 per cent by 2050 relative to 1990 levels. It also introduced a long-term framework for managing emissions
through a system of national carbon budgets: -22 per cent, -28 per cent and -34 per cent relative to 1990 levels over
the periods 2008 to 2012, 2013 to 2017 and 2018 to 2022 respectively.
The government strongly recognises the need to substantially decarbonise the power sector and that CCS has
considerable scope to contribute. Like all EU members, the United Kingdom CCS policy is very much affected by the
policy decisions of the EC.
In 2009, the government announced that new fossil fuel power stations over 300MW would have to be designed
CCS-R; and required to meet the emission standards of a new gas-fired power station without CCS.
The delivery of the United Kingdom’s CCS demonstration strategy is largely the responsibility of the Office of Carbon
Capture and Storage (OCCS) that resides within the Department of Energy and Climate Change (DECC). OCCS is
developing a CCS Roadmap out to 2050 consistent with the United Kingdom meeting its climate change targets.
The government is currently consulting on new electricity market arrangements, and in July 2011 it released Electricity
Market Reform—White Paper 2011, proposing: long-term contracts (stable financial incentives); supporting CCS
demonstrations with contracts that are designed to recognise the uncertainties of these early projects; an emissions
performance standard (EPS) set at 450g of CO 2
per KWh to limit the CO 2
emissions allowed from new coal-fired power
plants; and a carbon price floor (to further incentivise investment in low carbon generation now). The White Paper also
indicates that new gas plants will be required to be built CCS‐R.
The government recently announced the introduction of a carbon floor price starting on 1 April 2013 at £16 per tonne
CO 2
-e and following a linear path to £30 per tonne CO 2
-e in 2020 (both in 2009 prices). The floor price aims to provide
certainty and support for low-carbon investment independent of the carbon price in the EU ETS.
The United Kingdom already has statutory reporting requirements under its Energy Act 2010 which requires the
government to report on progress on decarbonising the electricity system and on the development and use of CCS.
The government remains committed to providing public funding for four CCS demonstration plants. In March 2011,
it decided not to proceed with a CCS levy, but instead to fund these commitments from general taxation. Following
detailed negotiations between the Government of the United Kingdom and project applicants, the Longannet project
is the only remaining active participant in the competition, with final outcomes expected by the end of 2011.
Legislation relating to specific tax relief for CCS will be introduced in the 2012 Finance Bill, to be followed by secondary
legislation later in 2012.
United States of America
In 2003, the government through the United States DOE established the RCSP, which are outlined earlier in this report.
CCS provisions are also contained in the Energy Policy Act of 2005 including: the tasking of DOE to initiate supportive
programs with the private sector for CCS R&D, demonstration, and commercial application over a 10 year period.
The regulation and reporting of CO 2
from storage facilities is already required under the Clean Air Act (CAA), administered
by the US EPA which also administers the Underground Injection Control program under the Safe Drinking Water Act
(which regulates the underground injection of CO 2
). As of January 2011, the EPA also requires large stationary sources
obliged to obtain permits under the Clean Air Act to also address their greenhouse gas emissions.
In late 2006, the Strategic Plan – US Climate Change Technology Program (CCTP) was authorised in the Energy Policy
Act of 2005. The overall program is managed by DOE and organised around five technologies, of which CCS constitutes
the CCTP’s 3rd Goal, led by the United States Department of Agriculture (USDA).
In 2009, the American Recovery and Reinvestment Act was passed, providing substantial additional funding for the
United States DOE’s Office of Fossil Energy (FE). Specific programs funded by the Act include: the RCSP, the Fossil
Energy Research and Development, the Clean Coal Power Initiative (round III), Industrial Carbon Capture and Storage,
Geologic Site Characterisations and the Geologic Sequestration Research and Training.
134 THE GLOBAL STATUS OF CCS: 2011

In February 2010, a Presidential Interagency Task Force on CCS was established including fourteen Departments
and Federal Agencies and co-chaired by DOE and EPA. The group was tasked through a Presidential Memorandum
to develop a
… proposed plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years,
with a goal of bringing five to 10 commercial demonstration projects online by 2016. The plan should explore
incentives for commercial CCS adoption and address any financial, economic, technological, legal, institutional,
social, or other barriers to deployment.
The Task Force identified four major barriers to CCS deployment in the United States including:
••
the existence of market failures (especially a lack of climate policy);
••
the need for a legal/regulatory framework;
••
clarity with respect to the long term liability for CO 2
; and
APPENDICES
••
integration of public information, education, and outreach throughout the lifecycle of CCS projects.
In August 2010, the Task Force released its final report containing a series of conclusions and recommendations.
It reaffirmed the important role CCS can play in reducing domestic emissions, and concluded that there are no
insurmountable technological, legal, institutional, regulatory or other barriers preventing CCS from playing a mitigation
role. It also concluded that the wide-scale and cost effective deployment of CCS will occur only when driven by a policy
designed to reduce emissions. The Task Force also recommended that to encourage early demonstration projects,
an increase in the coordination in applying drivers and incentives is needed.
The government is providing through the DOE loan guarantees to early stage CCS projects for up to 80 per cent of costs
(with equity contributions by project sponsors making up the difference). The USDA Rural Utilities Service (RUS) also
makes direct loans and loan guarantees to power plants (and currently includes at least one CCS project).
The government also provides tax incentives for low emission projects on a technology agnostic basis. Qualifying R&D
expenditures and deductions can receive a conditional tax credit of 20 per cent (30 per cent for IGCC) of eligible
expenses. Special amortisation provisions are also provided for certain qualified CCS assets such as capture equipment
certified by the EPA for the purposes of pollution control.
In 2009, the Committee on Climate Change Science and Technology Integration submitted to the President and the
Congress a report titled Strategies for the Commercialisation and Deployment of Greenhouse Gas Intensity Reducing
Technologies and Practices, which states that:
[CCS] could emerge as a crucial element of US and international strategies to reduce GHG emissions, especially in
view of the dominance of fossil-fuels as the primary energy source in the near- to mid-term.
A number of legislative proposals over the recent past have also called for the establishment of substantive policies that
could strongly support CCS, as detailed in section 4.1.
At the state level:
••
California set into law (AB32) in 2006 mandatory emissions reductions (approved a limit of 1990 emissions in
2020) and reporting, as well as an emission performance standard for new base load generation plants (SB1386)
at about 500 kg per MWh. AB32 also identifies a cap and trade ETS as a major strategy to help mitigate emissions,
and is legislated to begin in 2012. To this end, California is working closely with the Western Climate Initiative (WCI)
implementation of a regional ETS.
••
Colorado recognises in law that it is in the public interest of the state to support the deployment of CCS and offers
project cost sharing and incentives to projects via tax exemptions, reduced sales tax, taxation at lowered market
value, and tax credits (HB06-1281).
••
Illinois has established a state funding source for CCS through mandating (SB1592) utilities to charge a fee to create
the Renewable Energy Resources Trust Fund, for which a portion is allocated to supporting CCS projects and research.
It also authorises the Illinois Power Agency to prioritise the construction of plants that use Illinois coal, giving preference
to those with access to viable storage sites. In 2009, the Clean Coal Portfolio Standard Law (SB1987) entered
into force establishing emission performance standards for new coal-fired plants (50 per cent capture 2009 to 2015;
70 per cent from 2016-2017; and 90 per cent post 2017). The State also assumes the long term liabilities (SB1704)
associated with sequestered CO 2
, as well as any current or future environmental benefits, marketing claims, tradable
credits, emissions allocations or offsets.
• • Many states are supporting CCS through policies like tax incentives, CCS mandates and/or property right legislation,
including: Kansas; Louisiana; Mississippi; Massachusetts; Montana; North Dakota; New Mexico; Oklahoma;
Pennsylvania; Texas; Utah; West Virginia; and Wyoming.
APPENDICES
135

E.3 Policy, legal and regulatory observations from project survey
Table E‐1 aim to give a contemporary feel for the nature of the policy and regulatory challenges occupying projects,
including the sufficiency of existing policy settings and/or need for additional policy measures. These project responses
are drawn from follow-up interviews with eight major CCS project proponents held after the 2011 project survey.
Table E‐1 Project responses to questions on high level policy, legal and regulatory issues
ISSUES
POLICY
CHALLENGES
PROJECT REPONSES TO OPEN ENDED QUESTIONS ON HIGH LEVEL POLICY AND LEGAL
AND REGULATORY ISSUES
a general policy shift away from supporting nuclear could well increase the motivation for CCS deployment
there will be a continued reliance on fossil fuels and this should mean that new coal plants should at least be
‘capture ready’
there are many ambiguities in policy when considering how to practically handle issues such as the long term
liability; monetising risks; and financial sureties
the policy ‘atmosphere and tendency’ is good but the devil is in the detail, and many issues still need to be
dealt with at the national level
the most ‘difficult’ CCS project should be pursued first (not EOR-CCS)
a critical success factor has been the close and productive engagement of the ministry, and the government
as major stakeholder
the project is the driving force behind discussions with the government (in parallel to the project’s development)
for a statutory support/bonus scheme: could be a feed-in tariff, purchase power agreements, or environmental
certificates
we are very conscious of sovereign risk and the credence given to government promises made
CCS is entirely about reducing emissions, otherwise CCS projects would not exist (CO 2
in US affects Australia –
so it is a ‘small world’)
policy uncertainty is the project’s biggest issue – simply talking up an intent of policy without implementation
is damaging
the project is mostly influenced by state level policies [although still accessing national funding; tax credits;
loan guarantees] – the economics of IGCC is deemed comparable to natural gas combined cycle; and the
project economics is more about meeting regulated native load demand and volatility of fuel prices rather
than any future national carbon legislation
the forward operational risks are mostly related to federal policy settings
political risk is a concern at both federal and state levels (for climate change policy and the need for a coherent
carbon pricing mechanism)
the localised policy environment is fairly positive in terms of supporting this project
CARBON
PRICE
the demonstration phase is well covered by competitive funding and other government contributions, but the
operational phase requires additional policy support to what the EU ETS is expected to provide
project sponsors have invested a premium up-front to ensure that the project is viable – it is competitively
advantaged even though there is no CO 2
penalty or CO 2
avoided reward policy in place
a carbon price has not been factored into the economics of this project (the alternative was to repower or build
a gas-fired plant and the economics is about the same) – conventional coal-fired power generation is simply
unsustainable in a carbon constrained world
the project’s economics require broader revenue streams (ie. a way to monetise the avoided emissions)
136 THE GLOBAL STATUS OF CCS: 2011

Table E‐1 continued
ISSUES
PROJECT
CHALLENGES
PROJECT REPONSES TO OPEN ENDED QUESTIONS ON HIGH LEVEL POLICY AND LEGAL
AND REGULATORY ISSUES
funding was identified as the main challenge with the EU ETS not expected to make up for the difference in
the levelised cost of electricity resulting from the addition of CCS combined with future expectations of market
prices for electricity
the project needs to take on much of the storage risk
there can be substantial time pressures related to meeting the milestones required by the respective funding grants
operational uncertainties include: future value of carbon prices; nature and sufficiency of support schemes;
and development of national regulation
the decision to proceed was not so much an economic decision but the ethos behind sustainable
environmental management (not just due to compulsion)
APPENDICES
the best thing would be for the government to offer a higher off take price for the power and then the project
would be prepared to take on the storage risk
PROJECT
ECONOMICS
no real issues in regards to negotiating and striking service contracts on a fee for service basis
the project is economic as a capture ready plant (through a power off take arrangement) – but compression
and storage aspects will need policy help
access to national grant funding and oil royalty credits allows the project to break even based on electricity
prices alone
all project partnerships are on a fee for service basis
CO 2
use for EOR has been a critical driver in the economics for the project
electricity is the lowest value commodity in the project’s offtake arrangements for: electricity; CO 2
for EOR;
urea production; hydrogen production
EOR is the bridge to other forms of CCS over time
LEGAL AND
REGULATORY
ISSUES
legislation is continuously changing as is the nature of project permitting and this makes the financial decision
even more challenging
there are many guidance documents (EU) for national governments to implement CCS but they leave a lot
of issues as open
the time allocated by the national government for exploration is not long enough
regulatory issues are not so much about government not trusting proponents, it is more about government
not knowing what questions to ask
projects will be so unique that it will be difficult to put forward a uniform set of rules and criteria that meets all
of them (comes back to government needing to ask the right questions)
emission performance standard exists which means coal related emissions can not exceed natural gas
combined cycle emissions
focusing upon long-term liability is the wrong approach – getting site selection right is more important
it will be more important to agree the ‘criteria’ for the transfer of liability, than the timeframe for the transfer
operators need to be responsible for a finite period of time before transfer to the state
the availability of financial guarantees and insurance for the long term is critical
property rights are key, particularly with regard to stored CO 2
and broader liabilities
too much emphasis placed upon protocols and guidelines, especially when the uniqueness of individual
projects is considered
framework legislation does encourage investment in CCS
frameworks are already in place and operators just have to ‘get on with it’
the pace of regulation is too slow
environmental permitting arrangements are relatively straightforward, however they impose a substantial effort
and are costly to perform
there is ongoing and fruitful dialogue with government
local authorities have taken significant steps to support the development of CCS
APPENDICES
137

APPENDIX F
PUBLIC ENGAGEMENT
QUALITY FACTORS
Understanding the community
The first quality question tested projects’ progress towards understanding their local communities through research
and data collection. It asked to what extent the data acquired about the impacted local communities was sufficient to
evaluate project public engagement risk. Projects indicating the first stage of this work was finalised should understand:
••
the unique circumstances of the local communities, for example, the historical productivity or otherwise
of relationships between industrial scale constructors, governments and the local community;
••
who the local influencers were, how they were connected and what concerned them;
••
the local reputation and levels of trust in the project proponents; and
••
the extent to which the proponents planned to work in collaboration with local individuals and groups.
Data interpretation and planning
The second question testing quality examined how community consultation had impacted project planning. It asked
to what extent consultation activities with impacted local communities was sufficient to anticipate and mitigate public
engagement risk. Success indicators for a ‘finalised’ self-assessment indicated that the project had:
••
set targets to improve their local reputation and trust;
••
incorporated public engagement into project risk, resource allocation and crisis response planning;
••
appointed appropriately skilled people resources as the project’s link with the local community and to prepare a
public engagement strategy; and
••
established a variety of channels of interaction for information exchange between the community and project proponents.
Activities to mitigate risks
The third quality question tested the implementation of mitigation activities related to the identified risks. It asked to what
extent projects’ mitigation activities with impacted local communities was sufficient to offset public engagement risk.
Projects responding they had finalised this activity should have:
••
established a system to record stakeholder interactions and monitor/manage issues;
••
a process in place to regularly assess the project’s reputation (brand awareness and trust) with the local community
••
put landowner permitting agreements in place, along with a quality and service promise to meet landowner expectations;
••
continued implementation of the public engagement strategy with assigned budget and local people involved
actively in discussions;
••
established a local presence/shopfront; and
••
established a community investment plan based on preserving and enhancing the local community’s uniqueness.
Ongoing monitoring and analysis
The final quality question tested the ongoing monitoring and analysis of operational activities. It asked to what extent
ongoing operational activities with impacted local communities were sufficient to manage public engagement risk.
Responses of ‘finalised’ indicate that:
••
reputation performance continues to be assessed regularly; and
••
the stakeholder interaction system/database to monitor and manage operational and construction issues is kept
up-to-date. The public engagement strategy, including the community investment plan, is regularly reviewed and revised.
138 THE GLOBAL STATUS OF CCS: 2011

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