1 Executive summary

In May 2009, a consortium led by WorleyParsons and comprising Schlumberger, Electric Power Research Institute and Baker & McKenzie was engaged to undertake the Strategic Analysis of the Global Status of Carbon Capture and Storage (CCS).

The consortium was tasked with undertaking a comprehensive survey of the status of CCS and to develop a series of reports analysing CCS projects, the economics of CCS, policies supporting CCS development and existing research and development networks. A fifth report – the Synthesis Report – was also developed and this summarised the findings of the first four reports, and provided a comprehensive assessment of the gaps and barriers to the deployment of large-scale CCS projects, including strategies and recommendations to address these issues.

The second of this series of reports (Foundation Report Two) presented a detailed analysis of the capture, transport and storage costs for power plants and a select range of industrial applications. The costs of CCS were presented on a levelised cost of production basis, as well as for the cost of carbon dioxide (CO2) captured and avoided. Foundation Report Two also considered the application of CCS in first-of-a-kind (FOAK) systems and nth-of-a-kind (NOAK) systems.

The modelling determined that the cost of CCS for power generation, based on the use of commercially available technology, was found to range from US$57–107 per tonne of CO2 avoided or US$42–90 per tonne of CO2 captured. The lowest cost of CO2 avoided was at US$57 per tonne of CO2 for the oxyfuel combustion technology, while the highest cost at US$107 per tonne of CO2 for the natural gas-fired combined cycle (NGCC) with post-combustion capture (PCC). This compared with the lowest cost of captured CO2 for the IGCC and oxycombustion technologies at US$39 and US$42 per tonne of CO2 respectively and the highest of $90 per tonne of CO2 for NGCC technologies. The metrics were determined for the reference site in the United States of America (USA) with fuel costs based on values typical for 2010.

For the reference cases, taking into account currently available technologies, the levelised cost of electricity (LCOE) for FOAK pulverised coal (PC) supercritical technology was the greatest at US$131/MWh, while the oxy-combustion was the lowest of the commercially available technologies at US$121/MWh. While the cost of CO2 avoided and captured range by a factor of two, the LCOE estimates ranged between US$121–131/MWh with currently available technologies.

The percentage increases in costs that the application of CCS has over non-CCS facilities were also explored. For power generation, facilities that had the lowest cost increases were IGCC (37 per cent), NGCC (40 per cent), followed by oxyfuel combustion (53 to 65 per cent) and PC supercritical (61 to 76 per cent) technologies.

The application of CCS for FOAK industrial applications showed that cost of CO2 avoided was lowest for natural gas processing (US$19) and fertiliser production (US$20) followed by cement production and blast furnace steel production (US$54).

The lowest cost increase was for natural gas processing (1 per cent) followed by fertiliser production (3 per cent). This was unsurprising given that these industries already have the process of capturing CO2 as a part of their design. The production of steel (10 to 14 per cent) and cement (39 to 52 per cent) had the highest percentage cost increases with the application of CCS because the capture of CO2 is not inherent in the design of these facilities.

The margin of error in this study made it difficult to select one technology over another based on the LCOE. Projects employing different capture technologies may be viable depending on a range of factors such as location, available fuels, regulations, risk appetite of owners and funding.

In July 2010, WorleyParsons and Schlumberger were engaged to undertake an update of Foundation Report Two. The objectives of this update were to:

  • improve the regional localisation estimates;
  • update and enhance capital cost estimates for power and a select range of industrial activities that could apply CCS; and
  • update the economic model (having regard for the two previous items) to consider what, if any, material changed have occurred to the economics of CCS since 2009.

To meet these objectives, changes/modifications to the economic assessment methodology included:

  • the revision of overnight capital costs used in the 2009 report to early 2010 US$;
  • the revision of regional specific factors to move the capital costs from the reference location to the location of interest;
  • the review of coal and natural gas prices on a regional basis, including the consideration of whether the fuels were locally sourced or imported and subject to international market prices;
  • the adjustment of process parameters (heat rate, CO2 emissions and CO2 capture) according to regional coal composition and emissions requirements;
  • a change in the approach for CCS on the oxyfuel combustion power generation to include an additional purification step of the CO2 to increase the CO2 purity to greater than 95 per cent;
  • the modification of the reference pipeline length to 100km, based on findings for large-scale integrated CCS projects as identified in Foundation Report One;
  • a revised approach to CO2 storage, which considered two cases of a ‘good’ reservoir and a ‘poorer’ reservoir with either 3Mtpa or 12Mtpa injection scenarios; and
  • consideration of variations in storage costs across regions. Recent data on CO2 storage costs were obtained for Australia/New Zealand, Europe and North America for CO2 injection wells and associated services.

The revised results of the economic assessment of CCS technologies are presented in Table 1-1.

Table 1-1 Summary results of the economic assessment of CCS technologies

  Power generation Industrial applications
  PC supercritical & ultrasupercritical*1 Oxyfuel combustion standard & ITM*1 IGCC NGCC Blast furnace steel production Cement production Natural gas processing Fertiliser production
Dimensions US*/MWh US*/MWh US*/MWh US*/MWh US*/tonne steel  US*/tonne cement US*/GJ natural gas US*/tonne ammonia
Levelisedcost ofproduction Without CCS*2 73–76 73–76*3 91 88 570–800 66–88 4.97 375
With CCSFOAK*3 120–131 114–123 125 123 82 34 0.056 11
With CCSNOAK*4 117–129 112–121 123 121 74 31 0.056 11
% Increaseover withoutCCS*5 61–76% 53–65% 37% 40% 10–14% 39–52% 1% 3%
Cost of CO2avoided*6 ($/tonne CO2) FOAK 62–81 47–59 67 107 54 54 19 20
NOAK 57–78 44–57 63 103 49 49 19 20
Cost of CO2captured ($/tonne CO2) FOAK 53–55 42–47 39 90 54 54 19 20
NOAK 52 41–45 38 87 49 49 19 20


1 The ultra-supercritical and ITM technologies are currently under development and are not commercially available. These technologies represent options with the potential for increasing the process efficiency and reducing costs.

2 Without CCS cost of production for industrial process are typical market prices for the commodities.

3 Oxyfuel combustion systems are not typically configured to operate in an air fired mode. Therefore, oxyfuel combustion without CCS is not an option. The values here are the PC without CCS value to be used as a reference for calculating the cost of CO2 avoided.

4 For industrial processes, levelised cost of production presented as cost increment above current costs.

5 Expressed with respect to current commodity prices of industrial processes.

The updated modelling yielded the findings listed below.

  • All of the coal-fired technologies showed a decrease in fuel costs related to the lower coal costs in 2010.
  • For the reference cases, taking into account currently available technologies, the lowest LCOE was for oxyfuel combustion at US$114/MWh, in contrast to 2009 where LCOE for NGCC technologies was the lowest at US$112/MWh. Consistent with the findings in 2009, the LCOE for PC supercritical and IGCC technologies were the greatest at US$131/MWh and US$125/MWh respectively.
  • The percentage increases in costs that the application of CCS has over non-CCS facilities have remained relatively unchanged since 2009.
  • There was an increase in the capital contribution to the LCOE for oxyfuel combustion with CCS, reflecting the inclusion of an additional purification process when capturing CO2.
  • CO2 capture still represents the greatest contribution to the cost of CCS, with the majority of the cost increases being due to changes in the capture system.
  • The reduction in the length of the pipeline for the reference case has reduced the overall transport costs and the contribution of transport cost to the overall cost of CCS.
  • Consistent with the findings from Foundation Report Two in 2009, the range in coal price lead to a US$10/MWh variation in the LCOE, while for the natural gas price range the variation in the LCOE was around US$30/MWh.
  • For a supercritical PC with CCS technology, for a fixed fuel cost, the sensitivity of the CO2 capture installed capital costs and LCOE to the labour costs was reduced. The installed capital costs increased by 23 per cent (32 per cent in 2009), while the LCOE increased by 11 per cent (21 per cent in 2009). A similar trend would be observed for the other coal-fired technologies as they tend to be relatively labour-intensive installations.
  • The installed CO2 capture equipment cost and LCOE increased across all technologies in India. This was due to the consideration of a 30 per cent increase in equipment being imported into the country as well as India's typical coal heating value being very low, resulting in a greater capital cost.
  • Costs increased across all technologies in Eastern Europe, primarily due to the increase in the reference coal price for the region.
  • A 20 per cent increase in the technology cost in Australia which can be accounted for by the higher coal price utilised this year.
  • A significant increase in the costs in Brazil, partially because of a lower labour rate being used in 2009. The revision of the coal type to one with a lower heating value also lead to a higher capital cost. Finally, additional costs associated with importing capital equipment contributed to the increase in CO2 capture costs in Brazil.
  • Only NGCC costs are displayed for Saudi Arabia, reflecting that there are no coal-fired power generation applications in the region.
  • The breakpoint for the CO2 credit value for oxyfuel has decreased from US$60/tonne of CO2 in 2009 to US$55/tonne, which can be attributed to the lower coal costs offsetting the additional purification step included in this study. This analysis continues to indicate that oxyfuel still has the lowest CO2 credit value breakpoint of approximately US$55/tonne of CO2.
  • The IGCC breakpoint, with respect to supercritical PC technology has decreased from $80/tonne in 2009 to $70/tonne of CO2. This reflects the increase since 2009 in the LCOE and cost of CO2 avoided and captured for IGCC with CCS.
  • The cost breakpoint for the supercritical technologies is approximately $80/tonne of CO2, an 11 per cent decrease from the 2009 breakpoint of $90/tonne of CO2.
  • The high breakpoint for NGCC technology has remained relatively unchanged at $112/tonne of CO2, reflective of the lower CO2 emission intensity of natural gas and higher cycle efficiency compared to coal-fired technologies.
  • For the industrial processes, the incremental levelised product costs and the cost of CO2 avoided/captured have increased by a small amount consistently across all applications.
  • The cost to transport CO2 is estimated to be between US$1–2 per tonne of CO2, a decrease from US$3–4 per tonne of CO2 in 2009. This is due to the reduction of the pipeline length in the reference case from 250km in 2009 to 100km.
  • The contribution of storage cost to the LCOE was found to range from US$6–13 per tonne of CO2 depending on whether the ‘good’ or ‘poorer’ reservoir option was considered.

Though minor changes in the costs of CCS across power generation and industrial applications have occurred, the costs of CCS still remain high. This is expected, given that it has only been 12 months since the initial Foundation Report Two, and major developments that have the potential to dramatically reduce the cost of CCS have not yet occurred.

Despite the costs of CCS being high relative to traditional power generation and industrial facilities, it is important to consider that these traditional methods currently emit large amounts of CO2 into the atmosphere. Given the current and anticipated restrictions on facility emissions, these facilities will not be allowed to continue to operate as they have in the past.

The high costs of CCS as identified in this study should be considered with other low emission technologies to allow consideration of approaches to low emission power and industrial production. Further, if CCS is compared against the anticipated cost that may be imposed on facilities for emitting CO2 it is likely to appear more competitive in a low carbon market.