Fossil electricity and CO₂ sequestration: how natural gas prices, initial conditions and retrofits determine the cost of controlling CO₂ emissions

Abstract

Stabilization of atmospheric greenhouse gas concentrations will require significant cuts in electric sector carbon dioxide (CO₂) emissions. The ability to capture and sequester CO₂ in a manner compatible with today's fossil-fuel based power generation infrastructure offers a potentially low-cost contribution to a larger climate change mitigation strategy. The extent to which carbon capture and sequestration (CCS) technologies might lower the cost of CO₂ control in competitive electric markets will depend on how they displace existing generating units in a system's dispatch order, as well as on their competitiveness with abatement alternatives. This paper assumes a perspective intermediate to the more common macro-economic or plant-level analyses of CCS and employs an electric system dispatch model to examine how natural gas prices, sunk capital, and the availability of coal plant retrofits affect CCS economics. Despite conservative assumptions about cost, CCS units are seen to provide significant reductions in baseload CO₂ emissions at a carbon price below 100$/tC. In addition, the ability to retrofit coal plants for post-combustion CO₂ capture is not seen to lower the overall cost of CO₂ abatement.

Introduction

Stabilization of atmospheric carbon dioxide (CO₂) concentrations—the goal of the 1992 UN Framework Convention on Climate Change—will require substantial reductions in net emissions. Limiting CO₂ concentrations to a doubling of pre-industrial levels, for instance, will require a reduction in annual global emissions of at least 50 percent from their business-as-usual trajectory by 2050 (Wigley et al., 1996). The need to reconcile this reduction with an economy dependent on fossil fuels presents a fundamental challenge to industrial society.

It is uncertain how the needed reductions will be distributed across the economy, but there are several reasons to expect that the electric sector will be an important target for CO₂ mitigation. US electricity generation, for instance, depends on a large fleet of coal plants—readily identifiable point sources that burn the most carbon-intensive fossil fuel and account for a third of the nation's energy-related CO₂ emissions (EIA, 2000). Compared to distributed emission sources in the transportation sector, these plants make easy targets for CO₂ abatement as deep reductions might be achieved with minimal impact on energy infrastructures. At its point of use, electricity would “look” the same. Hence, the need to change both the means of supply and use—a coupled “chicken and egg” problem—would be avoided. It therefore seems likely that CO₂ reduction will be less expensive and action more rapid in the electric power industry than in other sectors of the economy.

Similarly, the centralized ownership and management of the electric utility industry facilitates regulation, and generators have gained considerable experience over the last three decades with increasingly tighter controls on conventional pollutants—analogues to CO₂. Moreover, with limited international trade in electricity, government action that raises prices in the electric sector would be less likely to cause movement of producers to less regulated countries than would be the case, say, for much of the industrial sector (Simbeck, 2001b). Owners of fossil-electric generating plants are therefore likely to be called upon to make substantial, near-term cuts in their CO₂ emissions should serious action be taken to mitigate the risk of climate change.

Atmospheric releases of CO₂, however, are not an inevitable consequence of fossil-electric power generation. Currently in use on industrial scales, the processes required to separate CO₂ from fossil fuels either before or after combustion exist as mature technologies. Furthermore, an improved understanding of relevant geological processes is increasing confidence in geological sequestration as a means of isolating CO₂ from the atmosphere on a centuries-long timescale. The integration of carbon capture and sequestration (CCS) with electricity generation may therefore provide an additional route to achieving significant reductions in CO₂ emissions over the next few decades.

The fundamental advantage of CCS as a CO₂ control strategy is its compatibility with today's electric power infrastructure and corresponding point sources of CO₂ emissions. New units with carbon capture, for instance, would be comparable to conventional fossil-electric plants in terms of their generating capacity, siting requirements, and availability for dispatch. CCS retrofits of existing plants—particularly the large US fleet of economically competitive coal-fired units—are also possible. Moreover, as new CCS plants would be built around familiar technologies, they could make use of existing construction techniques, managerial training, and equipment suppliers. The ability to capitalize on this end-to-end industry experience may encourage early electric sector support for CCS should significant reductions in CO₂ emissions be required (Keith and Morgan, 2001).

Emerging estimates also suggest that CCS might offer the prospect of lower electric sector CO₂ mitigation costs than alternatives such as non-fossil renewables (e.g., see Simbeck, 2001a, or the studies cited in David, 2000). In addition, the existence of niche markets and technical synergies—the ability, for example, to provide CO₂ for enhanced oil recovery or the compatibility of carbon capture with the polygeneration of synthetic fuels and electricity at refineries—may facilitate adoption of CCS technologies. The compatibility and maturity of CCS system components therefore affords the possibility of more rapid near-term CO₂ emissions abatement than might be the case if the technology was in an earlier phase of the innovation-development process.

Counterbalancing this optimism are the challenges of integrating component CCS technologies to build a complete system, as well as the technical and political uncertainties associated with CO₂ sequestration. The long-term ability of deep saline aquifers or depleted oil and gas reservoirs to contain CO₂, for instance, remains unproven. Important issues related to monitoring and verification, public perception and acceptance, and the place of CO₂ sequestration in the current regulatory regime must also be confronted before investors will risk capital on CCS projects. Moreover, environmental organizations have raised legitimate concerns that CCS—an “end of the pipe” approach to mitigating climate change—may incur significant opportunity costs, displacing resources and attention that would be better directed to the development of renewable and other sustainable energy resources (see, e.g., Hawkins, 2001).

Estimates of the extent to which CCS would lower the cost of reducing electric sector CO₂ emissions and the effective carbon price at which CO₂ capture plants would enter an actual power-generation system are also uncertain. Both depend on assumptions about the use and retirement of existing generating units, as well as competition from abatement alternatives such as advanced natural gas technologies and non-fossil renewables. In general, the cost of CO₂ mitigation via CCS will vary directly with the utilization of carbon capture plants, where the dispatch of individual plants is a function of the marginal operating costs of all available units. An examination of how CCS plants would enter and operate in an existing electric-power system is therefore required.

Consider first the need to incorporate the dynamics of plant dispatch in assessments of CO₂ mitigation costs. As new generating units are integrated into an existing power pool, and as electricity demand and factor prices change with time, the utilization of individual plants will vary. Increased use of both existing and new gas plants, for instance, will likely be the least-cost alternative for moderate reductions in CO₂ output. Gas-fired units will therefore fall to the bottom of the dispatch order and displace coal plants as carbon prices begin to rise. When the cost of carbon emissions is high enough that CCS becomes competitive, however, capital-intensive carbon capture plants would enter the generating mix with the lowest marginal operating costs and displace existing fossil-energy units. The use of conventional coal plants in particular would then decline as their operating costs increase with both the price of CO₂ emissions and the corresponding reduction in load factors. These shifts in the dispatch order affect the mitigation cost at which CCS enters, though the magnitude of this effect depends on how all available generating units interact to meet a specific demand profile when both demand and factor prices vary with time.

Consider next the need to account for existing capital. Today's electric power system is not “optimized” for the current economic, technological, and regulatory environment. In particular, vintage coal-fired plants, with little of their original capital investment left to be recovered, often remain competitive with newer and more efficient plants (Ellerman, 1996). The long lifetimes of these plants preserve an infrastructure that does not match what would be built given more recent technology and factor (especially fuel) prices. The gradual turnover of this infrastructure, coupled with a trend toward the increased use of natural gas and the availability of more efficient coal technologies will yield an emissions reduction absent a constraint on CO₂, and therefore lower mitigation costs. This effect, however, is vulnerable to gas price volatility. A modeling framework in which sunk costs matter is needed to capture these dynamics.

Finally, it is unclear whether retrofit or new CCS plants would be favored, and if the availability of retrofits would significantly increase the attractiveness of CCS as an abatement option. Conversion of existing units for carbon capture would lead to a reduction in plant output due to the energy requirements of the CO₂ separation process. The desirability of the retrofit option would be a function of this energy penalty, the base plant efficiency, and the means through which the plant derating is offset. New generating capacity, for instance, could compensate for the loss in output, or units currently reserved to meet peak demand might be dispatched more often. Understanding the role that carbon capture retrofits might play thus requires consideration of plant dispatch.

Previous studies of carbon sequestration have either included a less detailed representation of CCS technologies in economy-wide studies of CO₂ abatement (e.g., Biggs et al., 2001; Edmonds et al., 1999), or have addressed mitigation costs on an individual plant basis (e.g., David, 2000; Herzog and Vukmirovic, 1999; Simbeck, 2001a). Macroeconomic models, for instance, seek to balance production and consumption across all sectors of the economy and are typically constrained by computational requirements from including plant dispatch and a detailed characterization of existing generating capacity in their assessment of CO₂ mitigation costs (Hourcade et al., 1996). Plant-level assessments, in contrast, compare the cost of electricity for a base generation technology to figures from a similar plant with carbon capture, and then compute the carbon emissions mitigated per unit of cost. As the authors of these studies clearly note, a plant-level approach is necessarily limited to parametric consideration of sunk capital and unit dispatch (see, e.g., David, 2000). An assessment of how specific CCS generating technologies would be used in an actual electric power system is therefore required.

Incorporating these analytical needs, this assessment takes a perspective intermediate to existing studies and looks at CCS in the context of a centrally dispatched regional electric market. The analysis examines how the potential integration of CCS technologies depends on both internal factors like the natural turn-over of generating capacity and external cost drivers such as fuel prices, and assesses the impact of CCS on the cost of CO₂ control. As important as context is the timeframe under consideration. Falling between that of the Kyoto Protocol (now less than a decade) and century-long studies of global climate change, the assessment's 25–30 year perspective ensures that costs sunk in current infrastructure remain relevant and allows time for technological diffusion, but remains free of assumptions about the emergence of unidentified radical innovations.

The following section of this paper describes the modeling framework in which these issues are examined. Section 3 then discusses the calculation of mitigation costs in an electric market context. The following sections build on this analytical framework, examining the effects of sunk capital and natural gas prices (Section 4) as well as coal plant retrofits and the cost of CO₂ sequestration (Section 5). The conclusion provides a summary of the analysis and discusses the likely impact of those factors that remain outside of its boundaries.