A joint study between Germany’s Kiel University and Kiel Institute for the World Economy and the University of Cambridge in the UK, which conducted an in depth assessment of the economics of building a power plant with carbon capture and storage to replace an aging coal fired plant in the city of Kiel, reached an unexpected conclusion.

Sören Lindner, University of Cambridge, UK

In recent years, carbon capture and storage (CCS) has received increasing attention as one of the options to help the world reduce its greenhouse gas (GHG) emissions and to mitigate global warming. CCS is seen not only as a potentially ‘cheap’ option with high GHG reduction potential, but would also enable the continued use of coal, which is the most abundant and cheapest fossil fuel, to generate our electricity.

Currently there are a number of R&D activities, pilot and demonstration plants and storage projects being undertaken, as well as activities to develop congruent regulatory frameworks worldwide [12]. However, in addition to the necessary technological knowledge and regulatory framework, strong economic incentives are needed to bring CCS to the market.

At present, the major institutional driver for CCS in Europe is the European Commission. However, CCS is also high up on the agenda of power companies and local politicians because in coming years several power plants across Europe will have to be replaced.

For power companies and plant owners the main question is the likely ‘rentability’ or profitability of a new power plant, which depends on a number of variables with regard to cost and revenue. Assumptions on investment costs, carbon prices, fuel prices, electricity demand and their future development strongly affect the optimal plant type and size.

One case where currently a decision has to be made about a new power plant is the city of Kiel in northern Germany, where a coal fired power plant is approaching the end of its scheduled operational life. The plant has a net output capacity of 323 MW and provides 35 per cent of the city’s heat demand.

In 2007, the local municipality initiated a report to evaluate options for a possible replacement of the power plant. Potential successors were assessed by their profitability and environmental impact. Profitability was analyzed in three scenarios, each underlying different assumptions for future trajectories of carbon dioxide (CO2) permit prices, fuel prices and power revenues.

Six plant options were evaluated: an 800 MW, as well as a 360 MW power plant fired with black coal; a 400 MW natural gas and steam power plant combined or not combined with a 360 MW coal power plant; a 280 MW multi-fuel power plant, consisting of coal and biomass-firing, plus a 70 MW gas turbine; and finally a decentralized option comprising a 100 MW natural gas and steam power plant, a 4 MW block heat and power plant, 30 MW of geothermal energy and a 40 MW biomass power plant.

The final report [4] found that the 800 MW coal fired plant was the most economical choice in all three scenarios. The municipality defined an internal return of investment or internal rate of return of 6.5 per cent as the minimum level of profitability.

CCS is mentioned in the report as a possible option for a newly built coal fired power plant in the expected starting year of 2014. However, the final recommendation was to delay the decision over a plant successor for three to five years. It was assumed that by then more reliable assumptions could be made about the technological progress of CCS, the cost of the technology, fuel and permit prices, as well as about the implementation of relevant political decisions.

The aim of the latest study is to provide an additional economic and environmental evaluation of a coal power plant with CCS, with the aim of shedding light on the current incentives and the relevant trade-offs by comparing the profitability and emissions of the different options for a coal power plant with CCS with the options already evaluated in [4].

This article focuses on the economic evaluation portion of the study and does not include the findings from the environmental analysis. For information on the environmental evaluation please refer to the original paper – details of which can be found at the end of the article.

An economic evaluation was undertaken for three plant types:

  • An integrated gasification combined-cycle (IGCC) plant with pre- combustion carbon
  • A pulverized coal (PC) plant with post-combustion
  • A PC plant incorporating oxy-fuel combustion technology 

For the first two plant types the retrofitting of capture technologies is possible so this was also evaluated. 

Methodology & Cost Assumptions 

As in [4], a cash flow and net present value (NPV) analysis for the different plant types was performed. For all plant types a lifetime of 45 years was assumed. The calculations were based on the cash flow analysis of [4] for an 800 MW coal fired power plant under three different scenarios.

To derive the costs of an IGCC plant a 5 per cent increase in investment costs between the PC base plants and the IGCC plants based on a survey by [14] was assumed. Cost assumptions for plants equipped with post-combustion, pre-combustion or oxyfuel capture technology were derived from studies discussed in [10].

The analysis of cost differences between coal fired plants and CCS plants focuses on the investment costs required for the capture unit, increased fuel costs because of a higher energy demand, plant derating and the related decrease of power revenue, as well as annual costs for transport and storage. Average values for the additional costs were derived from [5, 9, 10, 11, 13]. Costs for retrofitting were adopted from [2, 14].

Retrofitting power plants with capture units decreases the performance of plants to a greater extent than capture units that are integrated from the start. In particular, [1] found that fuel requirements increase by around 29 per cent after retrofitting PC coal plants, and 22 per cent after retrofitting IGCC plants, as opposed to 25 per cent and 20 per cent respectively for plants with a capture unit initially installed.

In addition, plants experience a stronger derating after the retrofit. For PC power plants a derating of 30 per cent of the output capacity of the base plants can be expected and 18 per cent for IGCC plants.

Costs for transport and storage can be separated into one-time investment costs and annual (variable) costs. Transportation of CO2 by pipeline for 100 km to a storage site in Nordfriesland was assumed. Average investment costs from the studies [3, 7, 8] were €0.44 million/km ($0.64 million/km). Annual transportation costs were assumed to be €1.2 million for a post-combustion plant, €1.9 million for an IGCC plant, and €1.6 million for an oxyfuel plant [8]. True transportation costs will probably deviate slightly, because of region specific cost factors that might affect the pipeline route, such as highways, proximity to property, etc. Costs are also expected to increase if protests cause a delay in construction.

Storage costs are region specific, increase with increasing storage depth and vary with the geological storage medium. Storage in a saline aquifer in Nordfriesland was assumed and costs were adopted from [6], which proposes a range of storage costs from $1.9/tCO2 to $6.2/tCO2, with a mid range value of $2.8/tCO2 in Europe. One time investment costs were assumed to be €12.4 million while annual costs are estimated to be €11 million for a PC coal fired plant. Table 1 summarizes the assumptions for the cash flow analysis. 

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Scenarios & sensitivity analysis 

The costs of power plants were evaluated using three scenarios with different relevant variables. The same three scenarios as described by [4] were used, which assume that the key parameters, i.e. CO2 permit price rise more or less linearly from 2015 to 2050.

In addition to varying CO2 and fuel prices and power revenues, a sensitivity analysis was also undertaken with respect to the cost assumptions for CCS plants. For this, the NVP was calculated under two extreme assumptions where either the highest costs and derating or the lowest that could be found in the literature were taken. 

Option that makes economic sense 

The initial aim was to compare the different CCS technologies to the other power generating options presented for the city of Kiel in the three scenarios. Figure 1 shows a comparison of the NPV for all options. The values for options 1 (800 MW coal plant) and 5–9 are taken from [4], while options 2, 3 and 4 are the different types of CCS plants. The bar shows the NPV for the best-guess cost assumptions and the lines show the variation in the sensitivity analysis. A number of conclusions can be drawn regarding the optimality of CCS plants.

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Figure 1: NPV of all plant options in scenario 1–3 (from left under each scenario: 800 MW coal plant; PC post-combustion; IGCC pre-combustion; Oxfuel combustion; 360 MW coal plant; natural gas plant/coal combined plant; multi-fuel option; and decentralized option

Among the different available technologies for carbon capture, pre-combustion capture applied to an IGCC plant is the most economical choice in all three scenarios. IGCC plants with a capture unit demonstrated the lowest decrease in efficiency factors compared to the other two capture technologies. They thus need the least fuel. This is clearly shown in scenario 3, which includes a fuel price trajectory approximately three times higher than in scenario 1. In contrast, a capture plant with oxyfuel technology demonstrates the highest capacity derating and therefore is the most expensive CCS plant.

A coal fired plant equipped with oxyfuel capture is not only always the least profitable option among the three capture plants but even among all non-CCS options. Even under the most favourable cost assumptions the NPV of such a plant is negative in all scenarios.

Only in scenario 2 with very favourable conditions for CCS (i.e. high carbon prices, low fuel prices) is such a plant getting close to an internal rate of return of 6.5 per cent. The IGCC plant is the preferable option for maximizing the NPV in scenario 2 where it outperforms all other options, even when taking into account the cost uncertainty.

In scenario 3 with high carbon and fuel prices, an IGCC plant has the second highest NPV of all options. Only an 800 MW coal fired plant has a higher NPV. Yet, under favourable cost assumptions the IGGC plant has the highest NPV in this scenario as well. This is also true for scenario 1, but here only the lowest cost assumptions lead to an NPV for the IGCC plant that is higher than the NPV of the 800 MW coal fired plant. However, there is also the possibility that an IGCC plant does not reach the minimum internal rate of return of 6.5 per cent.

The non-coal options all have a negative NPV in scenarios 1 and 2, and with one exception also in scenario 3, and do not reach the minimum required rate of return. Only the natural gas plant has a small positive NPV in scenario 3. Thus, it must be noted that even a higher permit price reaching €85/tCO2 in 2050 is not sufficient to put plant options that are low in CO2 emissions in a position where they are attractive alternatives to coal fired options for the plant owner. For carbon capture plants however, the price increase does have a high enough impact to make an investment profitable.

The second major aim of the study concerned the optimality of retrofitted CCS plants. To analyze this, the NPV for the two plant types in the three scenarios was calculated, assuming a retrofit in different years. The results are shown in Figure 2. The dotted lines show the level of the plants with CCS from the start.

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Figure 2: A comparision between lifetime NPV and year of retrofit

The earliest year where retrofitting leads to a positive NPV is in 2022 for the IGCC plant in scenario 3, seven years after the initial construction of the plant. Retrofitting of a PC plant leads to a positive NPV 14 or even 18 years after construction. In scenarios 2 and 3 retrofitting of IGCC plants with pre-combustion technology could occur between five and seven years earlier than post-combustion technology for PC plants.

A price increase for carbon emissions clearly sets back the year to retrofit. In scenario 1, retrofitting occurs 19 or 23 years after the initial construction of the base plant, respectively. In this timeframe, no plant owner is likely to feel the need to retrofit because the amortization period for the plant is set to 35 years.

In terms of profitability, a later retrofit is preferable and the NPV rises with longer run-times without the retrofit. The same investment costs are discounted more the further they appear in the future. A CCS plant also leads to lower costs under high permit prices, which are assumed to grow over time.

The one exception in this case is the IGCC plant in the favourable CCS scenario 2, where the permit prices are high and fuel prices are low so that the variable costs of the IGCC plant are already considerably lower than for a coal plant without CCS, so that this effect dominates the less-discounted investment cost at some point in time. As a result the NPV starts to fall after 2035 and becomes negative for a very late retrofit after 2048.

Retrofitting an IGCC plant is never preferable to investing in an IGCC plant with CCS from the start. The NPV of a retrofitted plant is always lower and it only reaches the NPV of the IGCC plant with CCS from the start for a retrofit close to the end of the lifetime in scenario 3. Retrofitting a PC plant is also less preferable than building an IGCC plant with CCS from the start in the scenarios 2 and 3. Only in scenario 1 does retrofitting a PC plant after the year 2035 lead to the same or higher NPV. 

IGCC comes out top 

This economic evaluation demonstrates that IGCC plants equipped with CCS in all scenarios are either the first or the second choice when maximizing the NPV. Even in the reference scenarios where the 800 MW coal fired power plant has the highest NPV, an IGCC plant has a positive NPV and reaches the minimum rentability.

These results are not significantly affected by the cost uncertainties surrounding the building of an IGCC plant. It is only in the reference scenario that unfavourable cost assumptions lead to a profitability that is slightly below the set level. According to the analysis, an IGCC plant with CCS is an option that could currently be accepted by the operators.Yet, there is very little experience with IGCC technology and only 4 GW of IGCC power plants have been installed in the world to-date. Even though it should be possible to build an IGCC plant with CCS in Kiel there is clearly uncertainty associated with commercializing this technology that goes beyond the cost uncertainties that are covered by the sensitivity analysis.

In the reference scenario and in scenario 2, the PC plant with post-combustion is the third choice after the large coal plant without CCS and the IGCC with CCS. However, in scenario 3 it is clearly outperformed by a small coal power plant without CCS, by a natural gas plant and by a combined coal/natural gas plant.

Retrofitting an existing coal power plant with CCS in the future leads to a lower profitability than building a CCS plant initially. A mandatory retrofit, for example in 2020, would lead to a negative NPV. Only for a retrofit after the year 2025 or even later, depending on the scenario, does the NPV become positive. Only in scenario 1 retrofitting after 2030 (PC plant) and 2047 (IGCC plant) leads to a higher NPV than building a CCS plant initially.

Overall, the economic evaluation has shown that there are already incentives to build CCS plants given the expectations of costs and revenues. Yet, if politicians believe in this technology, support for demonstration projects of IGCC plants with CCS and additional R&D to reduce the technological uncertainties of this technology would be helpful.

In addition, a decision about whether and when retrofitting plants with CCS technology becomes mandatory is important for the choice of technology and the decisions of plant owners. 

References 

1. Bohm, M., 2006. Capture-ready power plants – options, technologies and economics. Thesis (Masters). Massachusetts Institute of Technology, Cambridge, MA. USA

2. Bohm, M., et al., 2007. Capture-ready coal plants – options, technologies and economics. International Journal of Greenhouse Gas Control, 1, 113–120.

3. Chandler, H. ed., 2000. Heavy Construction Cost Data. 14th Annual Edition. Kingston, MA: R.S. Mean Company.

4. Freischlad, H., et al., 2008. Vergleich von Heizkraftwerksvarianten für die Stadtwerke Kiel. Technische, wirtschaftliche und ökologische Bewertung. Endbericht [online]. Available from: https://stadtwerke-kiel.de/pdf/unternehmen/endbericht_gkk.pdf.

5. Gray, D. & Tomlinson, G., 2002. Hydrogen from coal. Mitretek Technical Paper. MTR 2003–31.

6. Hendricks, C., Graus, W. & van Bergen, F., 2004. Global carbon dioxide storage potential and costs. Report Ecofys and TNO, Ecofys Report EEP02001.

7. Hendricks, C., Wildenborg, T., Feron, P., Graus, W. & Brandsma, R., 2003. EC-Case. Carbon dioxide sequestration M70066, Dec 2003. Utrecht: Ecofgs/TNO.

8. IEA GHG, 2002. Transmission of CO2 and energy. Report PH4/6.

9. IEA GHG, 2004. Improvements in power generation with post-combustion capture of CO2. Report PH4/33. I

10. IPCC, 2005. IPCC Special report on carbon capture and sequestration.

11. Parsons Infrastructure and Technology Group, 2002. Updated costs and performance estimate for fossil fuel power plants with CO2 removal. Report by US DOE/NETL, Pittsburgh, PA, USA.

12. Praetorius, B. & Schumacher, K., 2008. Greenhouse gas mitigation in a carbon constrained world: the role of carbon capture and storage. DIW discussion papers, 820. Berlin: Deutsche Institut für Wirtschaftsforschung (DIW).

13. Rubin, E., Rao, A. & Chen, C., 2005. Comparative assessments of fossil fuel power plants with CO2 capture and storage. In: Proceedings of 7th international conference on greenhouse gas control technologies, Volume 1.

14. Sekar, R.C., et al., 2007. Future carbon regulations and current investments in alternative coal-fired power plants design. Energy Policy, 35, 1064–1074.

The article is based on ‘An economic and environmental assessment of carbon capture and storage (CCS) power plants: a case study for the City of Kiel’, published in the J. Environmental Planning and Management (Vol. 53: No.8, December 2010). It should be noted that the study was conducted at the end of 2008 under a different policy environment that currently exist in Germany. Nonetheless the study makes an interesting contribution to the continuing debate on the commerialization of CCS.

The author would like to thank his co-authors, Sonja Peterson, Kiel Institute for the World Economy, Germany, and Wilhelm Windhorst, University of Kiel, Germany, for their invaluable contribution. 

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