the value of post-combustion carbon dioxide capture and storage … · 2014. 9. 30. · the value...

IJGGC-120; No of Pages 10

The value of post-combustion carbon dioxide capture andstorage technologies in a world with uncertain greenhousegas emissions constraints

M.A. Wise *, J.J. Dooley

Joint Global Change Research Institute, Pacific Northwest National Laboratory, 8400 Baltimore Avenue, Suite 201, College Park,

MD 20740, USA

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a r t i c l e i n f o

Article history:

Received 1 November 2007

Received in revised form

11 June 2008

Accepted 18 June 2008

Keywords:

Carbon dioxide capture and storage

Pulverized coal

Post-combustion capture

Electricity production

East Central Area Reliability

Coordination Agreement

a b s t r a c t

By analyzing how the largest CO2 emitting electricity-generating region in the United States,

the East Central Area Reliability Coordination Agreement (ECAR), responds to hypothetical

constraints on greenhouse gas emissions, the authors demonstrate that there is an enduring

role for post-combustion CO2 capture technologies. The utilization of pulverized coal

generation with carbon dioxide capture and storage (PC + CCS) technologies is particularly

significant in a world where there is uncertainty about the future evolution of climate policy

and in particular uncertainty about the rate at which the climate policy will become more

stringent. The paper’s analysis shows that within this one large, heavily coal-dominated

electricity-generating region, as much as 20–40 GW of PC + CCS could be operating before

the middle of this century. Depending upon the state of PC + CCS technology development

and the evolution of future climate policy, the analysis shows that these CCS systems could

be mated to either pre-existing PC units or PC units that are currently under construction,

announced and planned units, as well as PC units that could continue to be built for a

number of decades even in the face of a climate policy. In nearly all the cases analyzed here,

these PC + CCS generation units are in addition to a much larger deployment of CCS-enabled

coal-fueled integrated gasification combined cycle (IGCC) power plants. The analysis pre-

sented here shows that the combined deployment of PC + CCS and IGCC + CCS units within

this one region of the U.S. could result in the potential capture and storage of between 3.2

and 4.9 Gt of CO2 before the middle of this century in the region’s deep geologic storage

formations.

# 2008 Elsevier Ltd. All rights reserved.

avai lab le at www.sc iencedi rec t .com

journal homepage: www.e lsev ier .com/ locate / i jggc

A growing body of literature is illuminating the significant

potential for the large-scale deployment of carbon dioxide

(CO2) capture and storage (CCS) technologies as central means

of reducing CO2 emissions across a broad swath of the global

industrial economy. This literature identifies coal-fired elec-

tricity production as an especially critical application for CCS

technologies and in particular the application of CCS coupled

with new purpose-built coal-fueled integrated gasification

combined cycle (IGCC) systems (IPCC, 2005). In an IGCC plant,

* Corresponding author. Tel.: +1 301 314 6770; fax: +1 301 314 6760.E-mail address: [email protected] (M.A. Wise).

Please cite this article in press as: Wise MA, Dooley JJ, The value of

in a world with uncertain greenhouse gas emissions constraints, Int. J.

1750-5836/$ – see front matter # 2008 Elsevier Ltd. All rights reserveddoi:10.1016/j.ijggc.2008.06.012

the CO2 emissions are captured prior to combustion of the

gasified fuel, and an IGCC with CCS (IGCC + CCS) can be

referred to as a pre-combustion CCS technology. IGCC + CCS is

a promising technology, and it may well turn out to be the best

or least-cost option for building new low-carbon fossil

capacity in many situations. However, there are critical

technical and economic reasons for maintaining research

and development in post-combustion CCS technologies for

pulverized coal (PC) technology (PC + CCS). Through its focus

post-combustion carbon dioxide capture and storage technologies

Greenhouse Gas Control (2008), doi:10.1016/j.ijggc.2008.06.012

.

mailto:[email protected]://dx.doi.org/10.1016/j.ijggc.2008.06.012http://dx.doi.org/10.1016/j.ijggc.2008.06.012

Table 1 – ECAR modeling assumptions

Factor Assumption

Load growth Begins at 1.9%/year and tapers down to 1.4%/year by 2045

Delivered gas prices Increase from $4.60/mmbtu in 2015 to just over $6/mmbtu by 2045

Delivered coal prices Increase from $1.40/mmbtu in 2015 to $1.60/mmbtu by 2045

Nuclear power Grows with electricity demand to maintain share

Renewable power Accelerated growth from about 4% of total in 2005 to 10% by 2045

Existing capacity No fixed future retirement age is assumed. Electricity generation capacity is retired only if

fixed costs exceed revenues

Trade Imports and exports with neighboring regions remain at current fractions

Cost of CO2 transport, storage and

measurement, monitoring

and verification

Potential CO2 storage reservoirs in the ECAR region are modeled as a graded resource and the

cost of utilizing these storage reservoirs for the electric power sector is assumed to be

between $12–15/tonne CO2a

a As described in Wise et al. (2007), it is assumed that any value added CO2 storage reservoirs in this region will be fully utilized by higher

purity/lower cost of capture CO2 point sources such as ethanol plants and natural gas processing facilities by the time large CCS-enabled power

plants are built and commence operations. This then implies that the electricity generators in this region will be reliant on the abundant deep

saline formations found across the ECAR region.

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on one heavily coal dominated electricity region in the United

States, this paper will seek to explore the largely under-

appreciated and potentially enduring role that PC + CCS

technologies could play in a greenhouse gas constrained world.

1. Background and objective

A recently published analysis (Wise et al., 2007) detailed an

economic modeling assessment of the potential adoption of

CCS in response to hypothetical CO2 reductions policies in

each of the North American Electric Reliability Council (NERC)

regions of the continental United States over a 40-year period

that spanned 2005–2045. That paper attempted to illuminate

the impact of the differing regional electricity market

characteristics (such as current capacity, fuel prices, and

growth rate) along with significant differences in geologic CO2storage cost and availability on each region’s response to a CO2policy. In addition to expanding nuclear and renewable

capacity as a means of reducing CO2 emissions in the face

of the imposed climate policy, between 180 and 580 GW of

IGCC + CCS generation capacity was brought on-line before

2045 to meet demand growth while simultaneously meeting

the imposed increasingly stringent CO2 emissions constraint.1

In this previous analysis, investment in PC + CCS was

relatively small, and limited to retrofits of some of the most

efficient existing coal generating units in regions where

conditions were favorable, such as the East Central Area

Reliability Coordination Agreement (ECAR) region in the upper

Midwest. But no new (i.e., post 2005 construction) PC + CCS

capacity was built in these scenarios; the use of post-

combustion CO2 capture was limited to only existing units.

The goal of that paper was to illustrate the potential large-

scale commercial deployment of CCS systems within the U.S.

1 The East Central Area Reliability Coordination Agreement inthe upper Midwestern U.S. and the South Eastern Reliability Coun-cil in particular were regions where the intensive use ofIGCC + CCS was seen in this previous analysis. Other regions inTexas and the Rocky Mountains could also be significant regionsfor the deployment of this class of low-carbon electricity genera-tion technologies.



electric power sector and to assess whether there was

sufficient geologic storage capacity in U.S. to meet this

potential demand.2 The previous paper (Wise et al., 2007)

was not intended to be an analysis of the relative merits of

future IGCC + CCS versus PC + CCS technologies, a point that

was stressed in the paper’s conclusions.

The present analysis is designed to more explicitly focus on

the relative performance of IGCC + CCS and PC + CCS systems

in a competitive, CO2 emissions constrained electricity

market. At the outset, it is important to acknowledge that

the choice between these two technologies is a deterministic

result of input cost and technology performance assumptions,

which are in reality uncertain. Future CO2 emissions reduc-

tions policy is also highly uncertain. Here, we will make the

case for the continued development of post-combustion CCS

systems and demonstrate with new modeling analyses of the

economic conditions that the availability of a post-combus-

tion technology is a valuable technology option.

2. Approach

To explore the impact of advanced post-combustion CCS

technologies, we modeled two scenarios of future technology

improvements in PC + CCS systems based on work by Rao et al.

(2006). We also modeled the impact of future CO2 emissions

price paths on investment choices by varying both the shape

of the price path and the extent to which the owners and operators

of the electricity generation system are knowledgeable about how the

future price path will evolve. This last point is a critical new

insight brought forward in the present analysis; expectations

of future CO2 emissions prices is a critical determinant in any

decision about the relative merits of near term investments in

post-combustion CO2 capture technologies. In order to avoid

duplicating work that has already been completed and to

2 Between 12–40 Gt CO2 of geologic storage was needed to meetthe demands of the cases modeled in Wise et al. (2007). Thisdemand, while significant and orders of magnitude larger thanthe cumulative global experience to date with CCS technologies,can be accommodated by the large and widely distributed geologicstorage capacity within the U.S.



http://dx.doi.org/10.1016/j.ijggc.2008.06.012

Fig. 1 – The ECAR region, its large, heterogeneous potential geologic storage capacity and large existing (greater than 0.1 Mt

CO2/year) stationary CO2 emissions point sources by type.

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facilitate comparisons across a wider range of potential

pathways for decarbonizing the U.S. electricity sector, we

have – except where explicitly noted – adhered to the same

assumptions about technologies, demand growth, fuel prices,

geologic storage cost and availability that were employed in

Wise et al. (2007).3 Table 1 summarizes the key ECAR modeling

assumptions for this study.

This analysis has employed two research tools developed at

Battelle: the Battelle CO2-GIS (Dahowski et al., 2005) to determine

the regional capacity and cost of CO2 transport and geologic

storage, and the Battelle Carbon Management Electricity Model

(CMEM) (Wise and Dooley, 2005), an electric system optimal

capacity expansion and dispatch model, to examine the

3 Assumptions of costs and performance of new electric tech-nologies for this exercise are from DOE/EIA (2005). Regional elec-tric demand load profiles and growth forecasts for this exerciseare taken from FERC filings (2005) for the near term. The authorshave decreased these region-specific growth assumptions afterthe first decade to be conservative about future demand growthand the corresponding amount of new capacity required. Regionaldelivered coal and natural gas prices for this scenario correspondto the Energy Information Administration (EIA) 2005 AnnualEnergy Outlook Reference Case (EIA, 2005) to 2025 and are extra-polated thereafter. All costs here are given in 2005 US$.



investment and operation of electric power technologies with

CCS against the background of other options. The dispatch

model is used because it is important to consider numerous

factors that extend beyond simple comparisons of the static,

levelized costs of competing power plant technologies. The

heterogeneous nature of the existing regional electric generat-

ing capacity must be considered; the fuel mix, age, plant

efficiencies, operating and maintenance costs, and emissions

rates are critical determinants of the economic response to a

CO2 emissions policy. The characteristics of electricity demand

are also crucial: both the varying nature of the electricity load

profile (from baseload to peaking) as well as future demand

growth. The competing technologies for new electricgenerating

capacity, their capital costs, efficiencies, operating and main-

tenance costs, and emissions must be weighed in building for

load growth and for replacing existing capacity.

Rather than model a hypothetical or overly simplified

aggregate market, we have chosen to look at a specific market

and use it to gain real-world insights that can hopefully be

generalized to other markets. For this analysis, we have

chosen to focus on the ECAR regional electricity system which

spans all or most of Ohio, Indiana, Michigan, Kentucky, and

West Virginia as well as the western parts of Virginia,

Maryland, and Pennsylvania. Fig. 1 depicts the ECAR region:




Fig. 2 – ECAR Year 2005 modeled electric dispatch curve.

6 Cost and performance parameters for IGCC + CCS are derivedby the authors from cost and energy requirement specificationsfor CO2 capture technologies specified David and Herzog (2000).While there are too many technical parameters involved to detailhere, for comparison purposes we note that the resulting costs forCO2 capture (i.e., exclusive of the cost of transport and storage in asuitable deep geologic storage reservoir) realized in our modelingare approximately $18 to $20/tonne CO2 for new IGCC plants,depending on the energy efficiency and the capacity factor ofthe underlying plant. These are our calculations, dependent onseveral scenario-specific factors, and the reader should refer tothe paper by David and Herzog for original technology data.

7 As noted in Table 1, the cost of CO2 transport, storage, mea-surement monitoring and verification for these potentially largepower plants that would utilize CCS and would be built in ECAR is



the large number of coal and other fossil-fired power plants as

well as the significant number of large stationary CO2 point

sources from the chemical, refining, steel, ethanol and other

industries that are also potential users of CCS technologies.

Fig. 1 also shows the abundant and widely distributed

theoretical deep geologic storage potential in the ECAR

region.4 The ECAR region is interesting both because it is

one of the largest regions in terms of electrical demand and

because it has been dominated historically by coal-fired

capacity. As a consequence, it represents the largest electric

power generation CO2 emitter of all the NERC regions.

Fig. 2 is an electricity generation dispatch curve for the Year

2005 from our modeling of ECAR. From this figure, it is clear

that ECAR is dominated by coal capacity, extending beyond

the baseload into the intermediate load. A relatively small

amount of renewables and nuclear power, and a moderate

amount of gas combined cycle (gas CC) and gas peaking

capacity round out the region’s current generation capacity.

Much of the gas CC capacity has been built in the last decade

and is therefore comprised of very efficient units.

Electricity generation dispatch curves provide an informa-

tive graphical depiction of the capacity mix, dispatch order,

capacity factors, and electricity prices. Using Fig. 2 as an

example, the dispatch cost is plotted on the vertical axis

versus the cumulative capacity available at each level of

dispatch cost on the horizontal axis. Dispatch cost is defined

as the variable operating and fuel cost (and therefore does not

include sunk costs such as capital or fixed operating and

maintenance).5 With vertical lines on the figures indicating

different points on the load duration curve, the dispatch

curves provide some insight into the capacity factors of the

different types of plants as well as price levels. Specifically, all

capacity to the left of the point where the load line intersects

4 In Wise et al. (2007), we estimate that there is potentially 169 GtCO2 of theoretical geologic storage capacity in the ECAR region.

5 It is important to stress the distinction between the dispatchcost, which is the appropriate basis for determining electricitygeneration and corresponding emissions, and the capital costs,which are considered only in determining the investment in newcapacity. Decisions relating to what electricity generation capacityshould be built in a region and which generation capacity isoperated on a given day are obviously linked, but they arenone-the-less distinct.



the supply curve is economical to operate to serve the load at

that point, and the electricity price at that point (at least at the

wholesale level before any tariffs or distribution costs are

incurred) is equal to the marginal cost of generation—the

dispatch cost of the capacity at that intersection point.

3. Scenario definitions

We construct four scenarios by pairing two assumptions about

future developments in post-combustion CCS technologies

with two paths of future CO2 emissions prices. We use the

CMEM model to explore the potential impact of these sets of

assumptions on ECAR over an approximately 40-year time

horizon.

Our assumptions about future costs and performance of

PC + CCS technologies are based on work by Rao et al. (2006).6

From their paper, we have derived two sets of assumptions for

PC + CCS technologies for use here:

� Base technology assumption: PC + CCS technology performs atlevel resulting in a cost of roughly $47/tonne CO2 (depending

on assumed capacity factor and cost of coal) to capture,

dehydrate compress and otherwise ready for pipeline-based

transport off the site of the power plant facility, and

� Improved technology assumption: cost of capture from PC + CCStechnology is reduced by 35% (i.e., to roughly $30/tonne CO2)

to similarly prepare the captured CO2 for pipeline-based

transport.7

We combine these post-combustion technology assump-

tions with two paths of future CO2 emissions prices:

� CP2 path (as named in the earlier study): a smooth CO2 priceincrease starting at $12/tonne CO2 in 2015 and increasing at

5% per year in real terms, with that price increase known

with certainty to investors.8

assumed to be an additional $12–15/tonne CO2.8 The earlier Wise et al. (2007) paper included a CP1 case as well,

where CO2 emissions prices started at the same $12/tonne CO2 butrose at a lower 2.5% per year, reaching about $25/tonne CO2 by2045. No PC + CCS units were built in ECAR under this less strin-gent CP1 case and therefore we will put this case aside in thepresent analysis. We will retain the CP1/CP2 terminology from theearlier paper to facilitate comparisons across the two analyses. Forthe current study, the CP2 path is a more relevant case as it issufficiently high to induce a large-scale investment in CCS duringthe 40-year time horizon.




Fig. 3 – CO2 emissions price paths.

Fig. 4 – ECAR 2045, dispatch curve. Base PC + CCS, CP2 CO2price path, ECAR 2045.



� ‘‘Jump to CP2’’ path: a scenario in which the price of CO2emissions remains relatively low to moderate (although

certainly not negligible) for the next few decades and then

rises steeply to the CP2 by 2045, with that price increase

being a surprise to the owners and operators of power

generation assets.

The difference in expectations is a key point here. In our

modeling of the CP2 path, investment is done on an

intertemporally optimal basis. That is, investment decisions

made in each period are done with full knowledge of

conditions, including CO2 prices, of all future periods. This

assumption is fairly typical in optimization modeling, and it

provides useful insight into what the rational investment

decisions would be. This assumption, also called perfect

foresight, is one extreme. We constructed the Jump to CP2 case

to explore the other extreme: one in which investors do not

know how the climate policy will unfold in future years. In the

Jump to CP2 case, investors do not foresee the steep increase in

CO2 prices when making investment decisions and are forced

to react to it given the generation assets that exist at the time

of the spike in CO2 permit prices.

A likely reality would lie somewhere between these two

extremes of perfect foresight and complete nearsightedness,

but modeling them as such provides useful insights into

economic investment for long-lived assets such as electric

power plants. Fig. 3 shows the two CO2 price paths graphically.

4. Results and analysis

Before turning to examining the changes in ECAR’s fossil-fired

generation mix across these four scenarios, it is important to

reiterate the point made in Table 1 that underlying all of these

scenarios is an explicit assumption of significant growth in

nuclear and renewable power that is a necessary complement

to the potential large scale deployment of CCS-enabled coal-

fired power plants.

For each of these cases, it is assumed that an additional

4400 MW of nuclear capacity comes on line in ECAR between

now and 2045. That would imply the construction and

commissioning of approximately one new large nuclear power



plant in ECAR every 5 years starting in 2015. In terms of

renewable power, it is assumed that 16,600 MW of new

renewable generation capacity is brought on line between

now and 2045. To meet this growth would require hundreds to

thousands of new large wind turbines coming on line every

decade starting immediately.

A key point, and we will return to this later, is that

significant generation capacity will be built in ECAR, regardless

of what climate policy is imposed, simply to serve expected

load growth. The question at hand is to attempt to shed light

on how climate policy and the state of CCS technologies will

impact this new generation capacity and to also examine the

extent to which existing generation assets are impacted.

Dispatch curves will be used to illustrate many of the scenario

results and analysis.

4.1. The role of PC + CCS in a well-defined future CO2emissions controlled environment

First, we will compare the results of changing the post-

combustion technology assumptions under the CP2 CO2 price

path, i.e., the smoothly escalating price that is known with

certainty. Figs. 4 and 5 compare dispatch curves depicting the

ECAR generation mix in the Year 2045, for both the Base

Technology and Improved Technology Scenarios against the

CP2 policy background.

As seen in Figs. 4 and 5, the new builds in ECAR from the

present to 2045 under the CP2 path are comprised mainly of

IGCC + CCS, and gas combined cycle (labeled New Gas CC to

distinguish from capacity already in place in 2005). In these

two scenarios where it is clear that an increasingly

significant climate policy will be put in place (e.g., on the

level of the CP2 path), no new PC capacity is built in ECAR

after 2005 regardless of whether an improved post-combus-

tion CO2 capture technology is available. The main differ-

ence between these two cases is that under the Improved

PC + CCS assumptions, about 20 GW of existing PC capacity

(i.e., built before 2005) is retrofitted with CCS, while under

the Base PC + CCS assumption, none of this capacity is

retrofitted.

Under the Base PC + CCS assumptions (Fig. 4), the most

efficient existing PC capacity, which today serves as baseload




Fig. 5 – ECAR 2045, dispatch curve. Improved PC + CCS, CP2

CO2 price path, ECAR 2045.

Fig. 6 – ECAR 2035, dispatch curve. Improved PC + CCS, CP2

CO2 price path.

9 These 2035 dispatch curves are nearly identical to the BasePC + CCS technology cases as the CO2 prices are not yet highenough in 2035 to induce and new build or retrofits of PC + CCSin these scenarios.



capacity, is pushed back in the dispatch order by the CO2 prices

behind gas CC capacity, operating less than 50% of the year.

The least efficient PC capacity is pushed even further back,

some to the point where they would likely be retired. However,

under the Improved PC + CCS assumptions (Fig. 5), the most

efficient PC capacity is retrofitted with CCS and continues to

operate at or near baseload capacity factors, while only the

less efficient PC capacity is displaced by gas CC in the dispatch

order. Also evident from Figs. 4 and 5 is that dispatch costs are

lower between the minimum dispatch and 50th percentile

points with the retrofit PC + CCS in place, which indicates

lower off-peak electricity prices for consumers and businesses

in the ECAR region due to the ability to reduce emissions in a

more cost effective manner, made possible by the presence of

the Improved PC capture technology.

Given the cost assumptions for both the Base and Improved

PC CO2 capture systems, it might seem that the CO2 price in

CP2 is sufficiently high by 2045 to induce retrofits of PC to

PC + CCS for either technology scenario, but the analysis must

consider other factors. One factor is the additional cost of CO2transport, storage, measurement, monitoring and verification

which as noted in Table 1 is assumed to be $12–15/tonne CO2for these large power plants in ECAR. A second factor is the

initial energy efficiency of the PC capacity to be considered for

retrofit. Capturing CO2 from an existing PC can be thought of as

a parasitic energy requirement, so a plant that generates

electricity less efficiently to start with will result in a higher

CO2 capture cost. Finally, a perhaps more subtle factor that

requires a dispatch model to consider fully is the resulting

capacity factor of the retrofit capacity. Technical specifications

of CO2 capture cost are typically presented at a fixed, baseload

capacity factor. Lower capacity factors mean fewer units of

output for amortizing the capital costs, resulting in higher per

unit costs of capturing CO2. And, as seen when comparing

across Figs. 4 and 5, it cannot be assumed that retrofit PC + CCS

will be able to compete with other baseload capacity in the

system and operate at a baseload capacity factor. In these

scenarios, the Improved PC CO2 capture technology is needed

to allow for retrofitted PC + CCS unit to compete with new

capacity being built and therefore justify the cost of the

retrofit.



4.2. The role of PC + CCS in an ill-defined future climatepolicy environment

We now examine the impact of the steep and unforeseen

increase in CO2 emissions prices which characterizes the Jump

to CP2 case on how ECAR would decarbonize its generation

capacity. Before moving to examine the changes at the end of

the study period (i.e., in the Year 2045), it is first instructive to

examine the extent of changes in the ECAR system in the Year

2035 immediately before this spike in CO2 permit prices is

introduced. From Fig. 3, the CO2 price is about $32/tonne CO2 in

the CP2 path in 2035, with the increase to $52/tonne CO2 by

2045 known, while the CO2 price is about $13/tonne CO2 in 2035

in the Jump to CP2 path, with the increase to $52/tonne CO2 by

2045 not known. Figs. 6 and 7 show electric dispatch curves for

the Year 2035 under the CP2 and the Jump to CP2 CO2 price

paths, respectively, both with the common assumption of

Improved PC + CCS technology for comparison purposes.9

Fig. 6 shows the same scenario as in Fig. 5 previously, but

here for the Year 2035 and can therefore be used to shed light

on the temporal evolution of changes in ECAR’s generation

mix in the well-defined CP2 case. From Fig. 6, it can be seen

that the CO2 price is already sufficient by 2035 to induce

investments in about 20 GW of IGCC + CCS, in addition to the

expansion of renewables, nuclear, and gas CC capacity.

Although the CO2 price path is too high to allow builds of

new venting PC plants, it is not so high that the existing PC

plants are yet pushed behind gas CC in the dispatch order, as

they will be in 2045. In fact, most of the PC capacity still serves

as baseload power even with this CO2 price. This result is

important in that it highlights both the continued value, along

with the continued CO2 emissions, from today’s PC capacity

even under a CO2 policy. The CO2 price does result in a higher

operation cost, which can be seen by comparing to the 2005

dispatch curve in Fig. 1, resulting in lower margins than they




Fig. 7 – ECAR 2035, dispatch curve. Improved PC + CCS,

jump to CP2 CO2 price path, ECAR 2035.

Fig. 8 – ECAR 2045, dispatch curve. Base PC + CCS, jump to

CP2 CO2 price path, ECAR 2045.

Fig. 9 – Dispatch curve. Improved PC + CCS, jump to CP2

CO2 price path, ECAR 2035.



would without a CO2 price. So the value to the owners of the

capacity is certainly affected by the CO2 policy.

Comparing Fig. 6 with Fig. 7, the most striking difference is

that there are no power plants capturing CO2 in ECAR in the

Year 2035 under the Jump to CP2 case (Fig. 7). The Jump to CP2

policy in place in 2035 and expectations of how it will unfold in

the future are insufficient to warrant the investment to build

let alone operate CCS-enabled units as a means of decarboniz-

ing ECAR’s fossil-fired electricity generation. To draw out this

point more explicitly, the main difference is that almost the

same amount of new capacity that was IGCC + CCS under the

CP2 path is instead new PC capacity under the Jump to CP2

path. The growing electrical load in ECAR is still largely being

served by coal-fired generation in both cases. However, in the

Jump to CP2 case it is still economic to construct and operate

new PC capacity that vents CO2 emissions to the atmosphere

at these CO2 price levels. In 2035, the existing PC capacity has

lower dispatch costs and will earn higher margins relative to

the dispatch costs of the gas capacity that will be setting the

electricity price much of the time. Therefore even though a

penalty must be paid for every tonne of CO2 vented to the

atmosphere (whether it be from a coal plant or a natural gas

fired facility) there is no reason to engage in massive fuel

switching to natural gas.

4.3. In an uncertain policy environment, it is better to havemore options

We now shift our focus to explicitly examine the value of

advanced PC-based CO2 capture systems in the Jump to CP2

case during the interval 2035–2045 where CO2 permit prices are

increasing rapidly. Figs. 8 and 9 are electricity dispatch curves

for 2045 under the Jump to CP2 path with Base PC + CCS

technology and Improved PC + CCS technology, respectively.

From Figs. 8 and 9, the new PC capacity built in the period

between 2005 and 2035 under the assumption of a continua-

tion of relatively low and slowly increasing CO2 permit prices

that characterize the pre-2035 Jump to CP2 scenario is

retrofitted to PC + CCS under either set of assumptions about

the cost of CO2 capture technology. Of significance to the

owners and operators of these new PC units is that the ability



to utilize the Improved PC + CCS technology results in lower

dispatch cost and therefore higher margins than if they are

limited to using only the Base CO2 capture technology shown

in Fig. 7.

These scenarios differ also in the extent of retrofitting pre-

existing PC capacity (i.e., that already operated in ECAR by

2005). Under the Base PC + CCS technology assumptions, it is

not economic to retrofit any of this capacity, and all existing

pre-2005 PC plants are pushed behind gas CC in the dispatch

order. However, under the Improved PC + CCS assumptions,

the most efficient existing PC capacity is retrofitted and

continues to dispatch at or near the baseload.

Table 2 summarizes key points across these four scenarios.

In all but the CP2/Base PC + CCS case, there appears to be a

significant rationale for the continued development of PC-

based CO2 capture systems in managing the costs of reducing

CO2 emissions within ECAR. In a case in which CO2 prices are

known with certainty, it is critically important to develop

IGCC + CCS technology. But it is also important to develop

advanced PC-based CO2 capture systems for deployment

centering on existing PC units. But in perhaps the more likely

case that future CO2 prices are not known, a robust, proven

and cost effective PC + CCS technology is a hedge that allows

new PC capacity to be built and later retrofit and continue to




Table 2 – Summary of scenario results

CP2 price pathwith base

PC + CCS capturetechnology

CP2 price pathwith improved

PC + CCScapture

technology

Jump to CP2price pathwith base

PC + CCS capturetechnology

Jump to CP2price path

with improvedPC + CCS capture

technology

CO2 emissions price $/tonne

2035 ($) 32 32 14 14

2045 ($) 52 52 52 52

Pre-2005 PC retrofit to CCS by 2045 0 22 0 22

New (post-2005 builds) PC + CCS by 2045 0 0 0 17.7

IGCC + CCS by 2045 (GW) 81 70 72 57

Cumulative CO2 stored in ECAR

by 2045 (million tonnes)

4300 4900 3200 3600

Fig. 10 – Dispatch curve. IGCC + CCS not competitive,

improved PC + CCS, CP2 CO2 price path, ECAR 2045.

Fig. 11 – Dispatch curve. PC + CCS not competitive, jump to

CP2 CO2 price path, ECAR 2045.



serve as baseload power. The ability to deploy improved

PC + CCS technologies also helps to contain the escalation in

baseload electricity prices that would be caused by such a

rapid increase in CO2 permit prices and therefore is a means

for protecting the larger macro economy if there is a need to

rapidly reduce CO2 emissions.

4.4. IGCC + CCS and PC + CCS as options to manageuncertainty in technology development

In each of the preceding four scenarios, there was an explicit

assumption that the IGCC + CCS technology is a lower-cost

option than PC + CCS for building new electric generating

capacity with CCS. That is an input assumption, not a result of

our analysis. This assumption was employed to allow for a

clearer focus on the role of post-combustion CCS in the event

that IGCC + CCS does in fact succeed.

Here we relax this assumption and briefly examine a

scenario in which PC + CCS turns out to be a lower-cost option.

Fig. 10 shows the dispatch curve for a hypothetical scenario in

which the CP2 CO2 price path is followed but IGCC + CCS is not

competitive. Here, we have also assumed the Improved

PC + CCS assumptions, but the same point could be made

with the Base PCC + CCS assumptions. As can be clearly seen

from Fig. 10, the electricity system in ECAR responds to the

imposed climate policy with a large scale deployment of new

PC + CCS capacity, along with substantial retrofits of pre-

existing PC capacity to PC + CCS. These units serve to provide

baseload power under such a scenario.

And in the last scenario analyzed here, Fig. 11 shows the

dispatch curve in the Year 2045 under the Jump to CP2 CO2price path but now assuming for whatever reason a viable PC-

based CO2 capture technology does not exist. The combination

of the significant spike in CO2 permit prices and no viable

means for capturing CO2 from the vast PC infrastructure built

out between 2005 and 2035 in the Jump to CP2 case, results in

massive changes in ECAR’s generation mix in the relatively

short interval 2035–2045. From Fig. 11, it is clear that one

immediate response is the rapid build out of new IGCC + CCS

units (more than in any of the previous cases) as the CO2 prices

are too high to operate the large numbers of post 2005 PC units

at high capacity factors. The new PC units built in the

preceding decades are pushed back behind new gas CC in the

dispatch order, providing much less power and value than its

investors had anticipated. Interestingly, this leaves little need



for the pre 2005 existing PC capacity to operate, and most of it

is retired as a result. Admittedly, this last case represents an

extreme scenario, and the real world response would probably

not be as quick or drastic. However, it does highlight the

enormous economic pressure that would be placed on the

system if something like this path is followed without the

ability to utilize improved PC-based CO2 capture technologies.

One key result evident in all of these cases is the vast

amount of IGCC + CCS or PC + CCS that is built within the ECAR

region. Although most of the capacity additions are due to




Fig. 12 – ECAR power sector CO2 emissions, by scenario.

Fig. 13 – Installed coal-fired capacity in ECAR by vintage

and plant type.

11 Compare this path to the CP1 emissions path in Wise et al.(2007). With a CO2 emissions price rising to $25/tonne, ECAR powersector CO2 emissions peak and decline to just under 2005 levels by2045.12 The primary reference for data on new coal builds in ECAR isNETL (2007). The authors also relied on press accounts and otherpublicly available information to update (in all cases to delete or



continued load growth, some of the new CCS-enabled coal-

fired capacity is needed to replace capacity losses due to

retrofits of existing units, as well as some retirements. The

amount of this CCS-enabled coal-fired capacity whether IGCC-

or PC-based appears large, but the scale of growth required for

any of these technologies, including renewables, nuclear, and

natural gas-fired capacity is also large.10 With continued load

growth, a great deal of new generation capacity will be built

within the ECAR region; the real question is what the mix of

technologies will be.

4.5. Resulting CO2 emissions for ECAR

Fig. 12 summarizes the impact of these CO2 emissions price

path and technology assumptions on the region’s CO2emissions. From the figure, it is clear that the CP2 price path

is a substantial policy that would result in deep emissions

reductions, and have a profound impact on the way electric

10 We believe we are being conservative by assuming lowerfuture growths than historical and by not presuming any fixedretirement ages for current capacity. If we were to assume thatcurrent capacity would be forced to retire at a certain age, muchmore new capacity would be required than shown here.



power is generated.11 Differences in prices through 2025 do not

result in significant deviations in emissions levels. CO2 prices

are not sufficiently high to change investment decisions

between coal and gas, or high enough to invest in CCS. In 2035,

emissions reductions are much greater under the CP2 path

than the Jump to CP2 path, but by 2045 the emissions are fairly

consistent.

The Jump to CP2 case also results in an additional 2900

million tonnes of CO2 released to the atmosphere. This is

notable for at least two reasons. First, it is clear that these

policies while ending up with the same emissions levels on

2045 are not equivalent in terms of cumulative emissions

reductions to the global environment. Second, from Table 2

the difference in the amount of CO2 stored between the CP2

and Jump to CP2 cases is significantly less, approximately 1300

million tonnes of CO2, and thus in the CP2 cases less coal is

built and the coal plants are operated less while generation

from gas increases.

As noted, the drop in emissions in the Jump to CP2 path

would be a shock to the system and would likely be more

difficult to realize than what any model might suggest.

5. Discussion

According to publicly available documents, there are currently

plans to build approximately 9200 MW of new coal-fired

capacity in ECAR over the next decade.12 Approximately

5100 MW of new natural gas-fired capacity could be on line by

2010 (EIA, 2006). The majority of this planned coal-fired

capacity, 6800 MW, will be PC units, with the remaining

2400 MW of the announced capacity slated to be IGCC-based

units. While it is difficult to know which planned or

announced power plants will actually get built, it is important

to note that a handful of these units are already under

construction and one relatively small PC unit (less than

300 MW) could come on line by 2010.13 It is therefore worth

reflecting upon what the foregoing analysis says about this

large potential investment in coal-fired generation capacity.

Fig. 13 shows installed and planned coal-fired generation

capacity within ECAR by vintage and by plant type. While it is

clear that the most of the existing coal-fired capacity in ECAR

is already at least 35 years old, it is also clear that there is

substantial capacity of a much more recent vintage. This data

also shows there is a substantial amount of coal capacity that

has been operating for more than 40 or 50 years.14

delay) coal plants that were contained in the NETL (2007) report.13 East Kentucky Power Cooperative’s 278 MW PC-based Spurlock#4 Unit is scheduled to come on line in the Spring of 2009. http://www.ekpc.coop/Generation/EKPCGeneratingProjects3.htm.14 This point provides support for our modeling assumption thatexisting plants may continue to operate and have value in thecoming decades, rather than simply retiring at a fixed lifetime.



http://www.ekpc.coop/Generation/EKPCGeneratingProjects3.htmhttp://www.ekpc.coop/Generation/EKPCGeneratingProjects3.htmhttp://dx.doi.org/10.1016/j.ijggc.2008.06.012



At present, there is more than 20 GW of installed coal-fired

capacity in the ECAR region that is of fairly recent vintage and

which has been fitted with both SOx and NOx controls. Given

the significant investment entailed in installing these emis-

sions control devices, it is perhaps fair to assume that these

are highly efficient units that their owners/operators believe

will still be productive assets for decades to come. Further the

significant investment in SOx and NOx controls at many of the

newer plants is germane to any discussion of the potential for

PC + CCS to deploy in ECAR as most amine-based CO2 capture

systems would require that SOx and NOx be removed before

CO2 is sent to the CO2 scrubber to minimize solvent losses

from the reaction with these acid gases (IPCC, 2005). This is not

to say that these plants will or will not be retrofitted with CCS

at some point in the future but rather to suggest that there is at

least some basis in reality for thinking that substantial PC-

based generating capacity could still be operational well into a

climate constrained environment and therefore there is

potentially significant value in the continued development

of post-combustion CO2 capture technologies.

The potential significant build out of new coal-fired

capacity depicted at the right of Fig. 13 within this one region

of the U.S. is instructive and provides perhaps an important

insight into expectations for how climate policy will unfold

and the impact of future climate policy on these generation

assets. In particular, the significant 6800 MW build out of PC-

based units in ECAR is suggestive that something less

stringent than the modeled CP2 case is expected by many

participants. On the other hand, the announced 2400 MW of

IGCC capacity would seem to indicate that at least some

participants in the ECAR market are preparing for a more

significant climate policy.

If nothing else, these data about the differing approaches

being taken just within ECAR in terms of building PC units or

IGCC units is suggestive of a lack of certainty in the real world.

Given that the forgoing analysis would strongly suggest that

the continued development of advanced PC-based CO2 capture

systems is an important complement to continued develop-

ment of IGCC and IGCC + CCS technologies. Advanced post-

combustion CO2 capture technologies serve as a hedge against

the significant risk associated with uncertainty centered on

future climate policy as well as a hedge against uncertainty in

success of development of IGCC. But to be clear on this point,

PC + CCS still has value even if IGCC + CCS is successful. This is

true for the ECAR region studied here and likely also other

NERC regions in the U.S. It is also true for regions like China

that are growing rapidly and whose electricity generation



infrastructure is and apparently continues to be dominated by

pulverized coal power plants.

r e f e r e n c e s

Dahowski, R.T., Dooley, J.J., Davidson, C.L., Bachu, S., Gupta, N.,2005. Building the cost curves for CO2 storage: NorthAmerica. Technical Report 2005/3. IEA Greenhouse Gas R&DProgramme.

David, J., Herzog, H., 2000. The cost of carbon capture. In:Proceedings of the Fifth International Conference onGreenhouse Gas Control Technologies (GHGT-5), Cairns,Australia.

IPCC, 2005. In: Metz, B., Davidson, O., de Coninck, H.C., Loos, M.,Meyer, L.A. (Eds.), IPCC Special Report on Carbon DioxideCapture and Storage. Prepared by Working Group III of theIntergovernmental Panel on Climate Change. CambridgeUniversity Press, Cambridge, United Kingdom and NewYork, NY, USA, 442 pp.

Rao, A., Rubin, E., Keith, D., Morgan, M.G., 2006. Evaluation ofpotential cost reductions from improved amine-based CO2capture systems. Energy Policy 34 (2006). Elsevier, pp. 3762–3772.

U.S. Department of Energy, Energy Information Agency (EIA),2005. Assumptions for the Annual Energy Outlook 2005.DOE/EIA-0554 (2005).

U.S. Department of Energy, Energy Information Agency. (EIA),2006. Electric Power Annual. Table 2.4 Planned NameplateCapacity Additions from New Generators, by Energy Source.http://www.eia.doe.gov/cneaf/electricity/epa/epat2p4.html(October 4, 2006).

U.S. Department of Energy, National Energy TechnologyLaboratory (NETL), 2007. Tracking New Coal-fired PowerPlants: Coal’s Resurgence in Electric Power Generation.http://www.netl.doe.gov/coal/refshelf/ncp.pdf (May 1,2007).

United States Federal Energy Regulatory Commission (FERC),2005. Form 714, Annual Electric Control and Planning AreaReport Data. http://www.ferc.gov/docs-filing/eforms/form-714/data.asp (updated December 2005).

Wise, M.A., Dooley, J.J., 2005. Baseload and peaking economicsand the resulting adoption of carbon dioxide capture andstorage systems for electric power plants. In: Rubin, E.S.,Keith, D.W., Gilboy, C.F. (Eds.), Greenhouse Gas ControlTechnologies, vol. I. Elsevier Science, pp. 303–311.

Wise, M.A., Dooley, J.J., Dahowski, R.T., Davidson, C.L., April2007. Modeling the impacts of climate policy on thedeployment of carbon dioxide capture and geologic storageacross electric power regions in the United States.International Journal of Greenhouse Gas Control 1 (2), 261–270, doi:10.1016/S1750-5836(07)00017-5.



http://www.eia.doe.gov/cneaf/electricity/epa/epat2p4.htmlhttp://www.netl.doe.gov/coal/refshelf/ncp.pdfhttp://www.ferc.gov/docs-filing/eforms/form-714/data.asphttp://www.ferc.gov/docs-filing/eforms/form-714/data.asphttp://dx.doi.org/10.1016/S1750-5836(07)00017-5http://dx.doi.org/10.1016/j.ijggc.2008.06.012

The value of post-combustion carbon dioxide capture and storage technologies in a world with uncertain greenhouse gas emissions constraintsBackground and objectiveApproachScenario definitionsResults and analysisThe role of PC+CCS in a well-defined future CO2 emissions controlled environmentThe role of PC+CCS in an ill-defined future climate policy environmentIn an uncertain policy environment, it is better to have more optionsIGCC+CCS and PC+CCS as options to manage uncertainty in technology developmentResulting CO2 emissions for ECAR

DiscussionReferences

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