Gasification Technologies Conference, San Francisco by ncl20207

VIEWS: 68 PAGES: 29

More Info
									R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

                   Coal Low-Carbon Generation Obligation for US Electricity

                                        Robert H. Williams
                       Princeton Environmental Institute, Princeton University
                                       Princeton, New Jersey

                                          David G. Hawkins
                                  Natural Resources Defense Council
                                           Washington, DC

                                               28 July 2005

                                                 Abstract

New coal power plants will add significantly to atmospheric loadings of the global warming gas
carbon dioxide (CO2) unless they capture and store CO2 rather than vent it. The paper describes
an early action strategy to deploy CO2 capture and storage at all new US coal power plants
expected to be brought on line during 2012-2020. A coal low–carbon generation obligation for
US electricity is proposed to achieve this deployment.

The generation obligation is an economically efficient instrument to bring about CO2 capture and
storage prior to the date that greenhouse gas policies become stringent enough to encourage the
technology. It would make such new ‗low carbon‘ coal plants profitable for coal power
generators while having a near-negligible impact on electricity rate payers.

Early US action would strengthen the US economy both by enabling continued exploitation of
abundant, low-cost, and secure domestic coal resources in environmentally attractive ways and
by positioning US industry to play the lead role worldwide in providing suitable coal
technologies as one tool for addressing the climate change challenge. It would lead to early cost
lowering for CO2 capture as a result of extensive early field experience (learning by doing) for
deployed technologies. An important ancillary benefit is enhanced energy security by making
copious quantities of CO2 available for exploiting extensive US enhanced oil recovery
opportunities.

The proposed early action strategy would eliminate the risk that future new domestic coal plants
would lock in a commitment to an enormous amount of cumulative plant lifetime CO2 emissions
and thus substantial climate change. Finally, the US example would help catalyze international
early action to minimize the carbon lock-in risk at the global level.

Introduction

Although CO2 capture and storage (CCS) for coal power plants is a major climate-change-
mitigation option, most economic studies conclude that CCS will not be pursued until climate
change mitigation policies create a market price of $25 to $35 per tonne of CO2) for CO2
emissions (Williams, 2004). Delaying CCS action until that happens might lead to locking in a




                                                      1
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

commitment to an enormous amount of cumulative CO2 emissions worldwide and thus
substantial climate change.

This paper addresses this dilemma and proposes a coal low-carbon generation obligation to bring
about a shift for new US coal power plants from CO2 venting (VENT) to CCS during 2012-2020.
The costs and benefits of this proposal are described and the role this domestic initiative might
have in catalyzing early action on CCS for coal power worldwide.

Toward Early Action on CCS for New Coal Power Plants

The goal of the United Nations Framework Convention on Climate Change is to stabilize the
atmospheric composition to ‗prevent dangerous anthropogenic interference with the climate
system‘ and to achieve that goal in ways that do not disrupt the global economy. Recent studies
suggest that our energy system has already brought us close to ‗dangerous anthropogenic
interference‘ and that mitigating climate change now is desirable, with an ultimate goal of
stabilizing atmospheric CO2 at a level that is substantially less than a doubling of the pre-
industrial level (O‘Neill and Oppenheimer, 2002; Hansen, 2004). Realizing with reasonable
certainty the oft-cited goal for climate policy of avoiding a global long-term temperature increase
of less than 2 oC above the pre-industrial level is likely to require stabilizing atmospheric CO2 at
~ 400 ppmv (Hare and Meinhausen, 2004).1 Even the less ambitious goal of stabilizing
atmospheric CO2 at ~ 500 ppmv would require a radical departure from a business-as-usual
energy future: it would require holding roughly constant total global CO2 emission rate for a half
century, followed by a sharp decline during the second half of this century (see Figure 1).

Building new coal electric generating capacity without CCS is not consistent with stabilizing
atmospheric CO2 even at the less ambitious of the two above-described climate mitigation goals
and runs the risk that a large amount of CO2 emissions will be ‗locked in.‘ Forecasts for coal
power generating capacity expansion worldwide indicate how large the potential carbon lock-in
problem is. The International Energy Agency (IEA, 2004) projects in its World Energy Outlook
2004 Reference Scenario that 1393 gigawatts (GWe) of new coal capacity will be built, 2003-
2030, 2/3 of which will be in developing countries (see Table 1a). Without CCS, the lifetime
CO2 emissions of these new plants would be more than a 40% increment over the cumulative
CO2 emissions from burning all fossil fuels from the beginning of the industrial era in 1750
through the year 2000.2 This new construction would increase annual CO2 emissions from coal
power generation worldwide by 71% during 2003-2030 (see Table 1b).

But early action on CCS for coal power would be helpful and is consistent with the recent joint




1
    In 2004 the atmospheric CO2 concentration reached 377 ppmv.
2
  Assuming that these plants are operated at 75% of rated capacity on average for 60 years and are characterized by
the projected CO2 emission rate of 810 gC per kWh, the lifetime CO 2 emissions commitment would be about 440 Gt
CO2. For comparison, the CO2 from burning all fossil fuels from the beginning of the industrial era through the year
2000 was 1040 Gt CO2.



                                                         2
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

science academies statement3 calling for a global response to climate change, urging:

           ―all nations…to take prompt action to reduce the causes of climate change, adapt to its
           impacts and ensure that the issue is included in all relevant national and international
           strategies…‖

and with the academies‘ appeal to the world leaders who attended the Gleneagles G8 Summit in
July 2005 to:

           ―Identify cost-effective steps that can be taken now to contribute to substantial and long-
           term reduction in net greenhouse gas emissions. Recognize that delayed action will
           increase the risk of adverse environmental effects and will likely incur a greater cost.‖

Because there is a significant likelihood that mitigation policies sufficient to induce reductions in
emissions from coal power plants will be put into place in many major fossil-fuel-consuming
countries early in the lifetimes4 of plants being built today (e.g., in the 2020+ period), it is
important to examine the merits of early deployment of CCS technologies for such plants.

It is technically feasible to begin widespread deployment of coal power with CCS well before
2020. Although no large coal power plant with CCS has been built, all the technological
components needed are commercially proven (see Box A). Moreover, there is already a
considerable base of experience with geological storage of CO2 (see Appendix A). Thus, if a few
commercial-scale demonstration projects could be carried out in the near-term, it would be it is
feasible to consider subsequent widespread deployment of coal power with CCS—starting, say,
in 2012, when substantial growth in coal capacity additions in the US is expected to get
underway (see Table 6).

Two arguments against early action are that: (i) it is preferable to focus instead on R&D today,
and (ii) new plants built in the near term future can be retrofitted for CCS later. As will be
shown, the arguments for these alternative courses of action are not persuasive.

The argument for focusing today on R&D instead of deployment for CCS is that this strategy
would lead to lower CCS costs in the future (when we will be smarter), so that we should delay
early action. However, this view overlooks the phenomenon that most (though not all)
innovation takes place as a result of ‗learning by doing,‘ a process by which costs typically fall
10 to 30% for each cumulative doubling of production for a given technology (see Figure 2), so
that early deployment of CCS leads to acceleration in time of progress in ‗buying down‘ CCS
costs.

There are prospective future CCS technologies that not yet ready for deployment without further
R&D. Would it be worthwhile to emphasize R&D on such technologies today as a policy

3
  These are key messages set forth in a Joint science academies’ statement: Global response to climate change that
was issued in June 2005 on behalf of the academies of sciences of Brazil, Canada, China, France, Germany, India,
Italy, Japan, Russia, the United Kingdom, and the United States.
4
    The economic lifetime of a new plant is about 30 years, but physical lifetime is often 60 years.


                                                             3
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

    Box A: Commercially Ready Technologies for Carbon Capture at New Coal Power Plants
The commercially ready options for CO2 capture for coal power are post-combustion capture for steam-
electric plants and pre-combustion capture for coal integrated gasifier combined cycle (IGCC) plants.
The technology for capturing CO2 from the stack gases of coal power plants using chemical (amine)
solvents and compressing it is well established commercially in chemical process markets, although large-
scale CO2 capture at power plants has not been carried out. The costs of CO2 capture are relatively high
largely because of the high energy intensity of the equipment for regenerating the solvents and the need
for a high degree SO2 removal upstream of CO2 removal to protect the solvents. Highly efficient SCS
cycles are favored to avoid extremely low overall plant efficiencies with CO2 capture. SCS technology
with CO2 vented (SCS/VENT) is a mature steam-electric coal power generating option.
IGCC/VENT technology has been proven via operation since the mid-1990s of four commercial-scale
demonstration projects—two in the US, one in The Netherlands, and one in Spain (Williams, 2004).
Major concerns about IGCC technology expressed by prospective coal power industry users—that these
plants have operated at lower levels of reliability (measured as availability5) than the levels sought by the
industry (~ 85% availability) and the absence of commercial warrantees for plants as integrated
systems—are being addressed. One way to get high reliability is to include a spare gasifier (Williams,
2004). Also, an important development in the IGCC industry since 2004 is that now all the major gasifier
vendors have teamed up with major architectural engineering firms in strategic alliances aimed at taking
full responsibility for engineering, procurement, and construction and offering ‗turn-key‘ IGCC plants
with guarantees, and in some instances even operation and maintenance services. These new IGCC
business plans represents a radical departure from the haphazard technology licensing approach that
characterized earlier efforts to market coal IGCC technology. Under these alliances, IGCC reliability is
expected to improve substantially over what has been experienced.6
Although no IGCC plant has been built with CO2 capture, all capture components are well-established in
the chemical process industry. In IGCC plants with capture, the synthesis gas (mostly CO plus H2)
generated via coal gasification, would be cooled, cleaned, and reacted with steam via the so-called water
gas shift reaction (CO + H2O  H2 + CO2), creating thereby a gaseous mixture consisting mainly of H2
and CO2. The CO2 would be separated using an appropriate solvent and then dried and compressed for
transport to storage. The remaining H2-rich, shifted synthesis gas would then be burned in a gas
turbine/steam turbine combined cycle power plant combustor to produce electricity.
Technologies for making and shifting synthesis gas and removing CO2 are well-known worldwide. China,
for example, has much experience with CO2 capture from coal-derived synthesis gas at plants that make
NH3 using modern coal gasifiers; these plants produce relatively pure (storage-ready) CO2, much of
which is vented to the atmosphere. Also, gas turbines originally designed for natural gas operation can be
re-engineered to operate on H2 (Chiesa et al, 2003); one turbine vendor has developed options for
effectively firing commercial gas turbines with H2-rich synthesis gas and claims over 450,000 hours of
commercial experience (Todd and Battista, 2002, Shilling and Jones, 2003).

5
 The availability is the percentage of time that the plant is available to provide power when called upon to supply
electricity by the electricity grid operator.
6
  According to Lee Schmoe [Gasification Technology Manager, Bechtel (the architectural engineering firm that is in
a strategic alliance with GE, which acquired the Texaco gasifier in 2004), remarks made on a Panel on IGCC Tech-
nology—Reliability, Availability, and Maintainability, at the Platts IGCC Symposium, 2 June 2005, Pittsburgh], the
GE/Bechtel alliance expects to realize ~ 85% IGCC system availability without either a spare gasifier or backup fuel
by: exploiting alliance expertise; standardizing components and system designs; and focusing on evolutionary
rather than revolutionary technological improvements (via lessons learned in field experience).



                                                          4
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

                Box B: The Oxyfuel Option for CO2 Capture at Coal Power Plants
The oxyfuel option for CCS at steam-electric coal plants involves burning coal in oxygen instead of air,
so that the combustion product gases are not diluted by the nitrogen that would be present with
combustion in air. As a result, CO2 capture involves merely condensing out the water from the flue gas by
cooling and subsequently drying and compressing the residual dry gas (~ 96% CO2) to make it ready for
storage. Some additional research, prototype development, and commercial-scale demonstration are
needed to bring this technology to commercial readiness (Dillon et al., 2004).

The oxyfuel capture strategy is far simpler than that of the commercially ready post-combustion and pre-
combustion CO2 capture technologies described in Box A. The main disadvantages of the oxyfuel
strategy are the higher power island costs for the steam-electric cycle compared to the combined cycle
used in IGCC/CCS plants, and the large requirements for oxygen (~ 2.5 times as much oxygen is needed
per kWh as for IGCC/CCS), the production of which from air is both capital- and energy-intensive. These
costs are partially offset, however, by the absence of costs for flue gas desulfurization and NOx control
equipment.

The estimated generation cost for a future oxyfuel plant burning bituminous coal presented in Table 5 is
5% less than for a first-of-a-kind IGCC/CCS plant (see Table 4) but 12% more than for ‗the Nth‘
IGCC/CCS plant based on current technology (see Table 3). The latter comparison may be the more
relevant because in both cases the studies on which the estimated costs are based (as presented in Tables 3
and 5) were carried out for the IEA GHG R&D Programme under programme management efforts to
facilitate comparison of the technologies.

The oxyfuel option is not a promising option for retrofitting (10-15 years from now) new steam-electric
plants that might be built today, because it is not realistic to expect that new steam-electric plants would
be allowed to operate without SO2 and NOx controls during this period.7 However, the oxyfuel option
might be attractive in some retrofit opportunities involving old steam-electric plants that are not currently
equipped with flue gas desulfurization and NOx control equipment, especially if these plants were
converted to supercritical steam boilers to minimize energy cost penalties.

alternative to promoting early CCS deployment? Such a delayed deployment strategy might be
considered seriously if there were prospective advanced technologies that offer good prospects of
beating decisively the least-costly currently available CCS technologies and of being brought to
commercial readiness relatively soon. The case for R&D as an alternative to early action is weak,
however, as shown by consideration of oxyfuel options for CCS (see Box B)—the most likely
competitor on the horizon to currently available CCS technologies (see Box A).

R&D is important to the ultimate success of CCS, but its role should be as a complement to
rather than as a substitute for early action.

It is technically feasible to retrofit for CCS at a later date new coal power plants that will be built
in the decades immediately ahead. However, retrofits for CCS will always be more costly than
CCS for new plants and would be pursued primarily after CCS has been carried out for all new


7
 For a SCS plant the incremental capital cost of shifting to the oxyfuel mode as a retrofit strategy would be at least
90% higher than is indicated in Table 5 ($480/kW e vs $250/kWe) because credit cannot be taken for avoiding the
costs of flue gas desulfurization and NOx control equipment.



                                                           5
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

coal power plants (Morrison, 2004).8 Moreover, if coal power generators think chances are not
high that a stringent climate will be put into place soon, they will tend to choose familiar plant
designs such as, in the case of bituminous coals, supercritical steam (SCS) plants rather than
integrated gasification combined cycle (IGCC) designs that offer the least-costly power with
CCS for such coals.9 Furthermore, even if designs more amenable to eventual CO2 capture are
employed, such plants are unlikely to be equipped and operated for actual CO2 capture, so that
learning and early cost-reduction will not occur, and these plants will continue to vent large
quantities of CO2.10

Continued construction of new coal plants without CCS could have one or both of two
unpalatable consequences: the added amounts of capital investment in these long-lived assets
could induce policymakers to adopt less effective mitigation policies and/or overall costs of any
given mitigation policy could be increased because of the higher costs of retrofitting this
capacity.

A Coal Low-Carbon Generation Obligation for US Electricity?

Without a high carbon market price or equivalent government incentive, early CCS action would
not be taken by individual power companies, and the realization of lower CCS costs through
learning by doing would be delayed, because the result would be increased generation costs that
would make units with CCS equipment uncompetitive. The increase in the busbar generation
cost at an individual unit (the cost measure that determines the financial viability of that unit)
with current technology would be significant (35-70%--see Tables 3 and 4)11, although the
impact on consumer electricity rates would be much less even with substantial CCS
deployment.12

The high cost hurdle for early action on the part of the coal power generator as well as the
challenge of buying down the cost of coal power with CCS can be addressed by introducing a
national coal low-carbon generation obligation for US electricity modeled after the familiar
Renewable Portfolio Standard (see Box C).
8
  Eventually retrofits for CCS will be needed in many areas for climate mitigation purposes. The present analysis is
focused on CCS for new plants, the first priority.
9
  For a new bituminous coal plant, the cost of avoiding a tonne of CO 2 emissions for a SCS/CCS plant is estimated
to be 1.3 to 1.7 times that for a first-of-a-kind IGCC/CCS plant, depending on what the reference VENT plant is
assumed to be (see Table 4). The avoided cost for an IGCC/CCS retrofit plant is also expected to be less than for a
SCS/CCS retrofit plant. However, the generation cost for an IGCC plant without CO 2 capture (IGCC/VENT) is
probably 0-15% more than for the SCS/VENT option (see Tables 3 and 4)
10
  American Electric Power Corp. (AEP) is proposing to build an IGCC plant based in part on an assumption that
eventual controls on CO2 are quite probable, but AEP is not proposing to equip or operate the unit with CCS.
11
     The methodology for estimating electricity costs without and with CCS is described in Appendix B.
12
  The percentage increase in retail electricity rates would be far less for three reasons: (i) coal generation with CCS
will for a long time account for a small fraction of total coal generation; (ii) on many power systems non-coal power
sources make significant contributions (the US average is 50%); and (iii) generation costs accounts for 60-65% of
retail electricity prices.



                                                           6
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

                             Box C: The Renewable Portfolio Standard
A Renewable Portfolio Standard (it has different names in different countries), implemented (at the time
of this writing) in 18 US states and Washington, DC, and in several other countries [the UK, Italy,
Sweden, Poland, Japan, Australia, and two provinces of Belgium (Flanders and Wallonia)] is widely
regarded as an effective and economically-efficient instrument for commercializing renewable energy
technologies (van der Linden et al., 2005). A Renewable Portfolio Standard offers the potential for
meeting renewable energy targets at lower total cost to society and with less administrative involvement
by the government than other renewable energy policies (Rader and Norgaard 1996; Haddad and Jefferiss
1999; Berry and Jaccard 2001; Wiser, Porter, and Grace, 2005).

A national Renewable Portfolio Standard was passed by the US Senate in June 2005,13 but was not
included in the final energy bill that that emerged from the House/Senate Conference in July. Had this bill
passed it would have: (i) required that a growing share of electricity provided to the grid (reaching 10%
by 2020) would come from qualifying renewables, (ii) allowed trading via tradeable renewable energy
credits [the price of which would be capped at 1.5 ¢/kWh (adjusted for inflation)], and (iii) imposed a
penalty for non-compliance that is the greater of 1.5 ¢/kWh and 200% of the average market value of
renewable energy credits during the year in which the violation occurred.

Under the proposed low-carbon generation obligation, each retail power supplier would be
required to provide a growing fraction of coal power generation with CCS in its electricity
supply portfolio each year. It is proposed that the obligation be a growing percentage of total
coal power generation that is large enough to cover the new coal generating capacity expected to
be built during 2012-2020—so that the size of the coal low-carbon generation in the portfolio
would increase from 0.3% of coal power generation in 2012 to 2.2% by 2015 to 9.3% by 2020
(see Table 6), if coal electricity generation grows as projected by the Energy Information
Administration, with 30.6 GWe of new capacity added during 2011-2020 (EIA, 2005).

Such a low-carbon generation obligation could contain a lead time of five or more years before
new coal plants would be subject to the requirement, but the legislation should specify, inter alia,
that no coal power plant built after the legislation (either before or during the generation
obligation period) would be ‗grandfathered‘ against future greenhouse gas control obligations.

The coal low-carbon generation obligation would be ‗technology blind‘—it would not specify
technologies (e.g., steam-electric plants with amine scrubbers or oxyfuel or IGCC or the gasifier
type to be used for IGCC) for coal power plants—only a maximum carbon intensity, expressed
as an emission rate in pounds of CO2 emitted per MWh of electricity generated. It is proposed
that the performance standard be set at a rate equivalent to the emission rate for a coal power
plant that captures and stores underground 85-90% of the carbon in the coal as CO2—see Tables
3, 4, and 5.

The CO2 captured at a power plant under the low-carbon generation obligation would be stored
in one or more geological formations that are certified by the US government as appropriate
storage option(s), based on criteria specified in the legislation or delegated to the appropriate
agency to spell out.

13
  The Renewable Portfolio Standard was adopted by the US Senate as Amendment No. 0791 to the Senate Energy
Policy Act of 2005.



                                                      7
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

Under the proposed coal low-carbon generation obligation, each retail electricity provider would
either generate low-carbon coal power, purchase such power from independent electricity
suppliers, or purchase credits in a tradeable credit market. The credit value (in ¢/kWh) would
reflect the cost increment for coal power with CCS, and selling these credits would make it
profitable for coal power generators to pursue CCS.14 The incremental cost for CCS would
increase generation costs at low-carbon coal power plants, but the low-carbon generation
obligation would spread these costs over all ratepayers.

The rationale for spreading the cost of the low-carbon generation obligation over all ratepayers is
that all electricity consumers would benefit from accelerated deployment of coal with CCS. For
example, the presence of 50+% of coal power on the electric grid results in substantially lower
natural gas prices for all consumers (including consumers of gas for purposes other than
electricity generation) than a scenario in which coal power generation falls due to pressures to
cut CO2 emissions and the absence of a technological option for low-carbon coal. Thus, even a
service territory supplied by 100% gas generation would benefit from the program to deploy
CCS. Accordingly, it is reasonable to have all electricity customers pay for the costs of this
program.

As in the case of the Renewable Portfolio Standard there would be effective penalties (greater
than the credit value) for non-compliance.

To provide for cost control the program should contain incentives for achieving incremental
costs less than some benchmark CCS costs for the different coal types. The initial benchmarks
would be specified in the enabling legislation or the DOE would be authorized to set them. The
benchmarks would be adjusted over time in light of growing experience with the generation
obligation.

In order to motivate power suppliers to beat the benchmarks, a sliding scale incentive might be
implemented. For example, in assigning credits: a project that beats the benchmark by X% might
be assigned a credit that is 1.1 times the nominal credit; a project that is 2X% better might be
assigned 1.2 times the nominal credit, etc. Such a sliding scale would have to be carefully
constructed to avoid diluting the generation obligation significantly.

A Low-Carbon Generation Obligation for Bituminous Coals

Table 6 presents estimates of the incremental costs of CCS and impacts on electric utility rates
for the proposed coal low-carbon generation obligation, if all new plants built in the 2012-2020
period were to use bituminous coal. The calculations were carried out assuming that IGCC/CCS
is the capture and storage option (the least-costly CCS option for bituminous coals)15 and that the
reference plant against which the incremental cost is measured is a SCS/VENT plant (currently

14
  Specifically, in a given year the credit price would be set by the CCS cost increment for the last increment of coal
power with CCS required to meet the low-carbon generation obligation for that year.
15
  IGCC technology is assumed only for the purpose of making to the cost estimates. As stated earlier, the low-
carbon coal generation obligation would not specify the technology—only the maximum carbon intensity level.



                                                          8
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

often the least costly option for a new coal plant with CO2 vented)—see Table 4. The
calculations presented in Table 6 also assume that the carbon market price is zero throughout the
period 2011-2020. Details of the calculations of incremental generation costs for CCS are
described in Appendix B.

Incremental generation costs were estimated both without and with the benefits of learning by
doing. Two learning cases were considered: a substantial learning case that involves some
technological innovation and a modest learning case that involves the ‗learning out‘ of current
IGCC technology (‗Nth plant‘ cost).16 Details of the learning calculations are described in
Appendix B.

Under these assumptions for the proposed low-carbon generation obligation, the levelized
incremental annual cost of CCS during 2012-2020 is estimated to be (see Table 6):

        $1.3 billion per year with substantial learning, or
        $1.4 billion per year with modest learning, or
        $2.0 billion per year without learning.

The corresponding increase in the US average levelized electricity price seen by the consumer in
this period would be substantially less than 1%:

        0.30 mills/kWh (a 0.43% increase) with substantial learning, or
        0.34 mills/kWh (a 0.49% increase) with modest learning, or
        0.47 mills/kWh (a 0.67% increase) with no learning.

By 2020 (the year of the highest cost penalty for CCS), the average electricity price would be
0.9% higher (with substantial learning) to 1.7% higher (with no learning) than under business-as-
usual conditions (see Table 6),17 but carbon lock-in from 30.6 GWe of new coal capacity would
be avoided and the average CO2 emission rate for US coal power generation in that year would
be 6.1 to 6.7% less (depending on the amount of learning). The retail price increase projected for
2020 (0.7 to 1.2 mills per kWh) is comparable to the annual fluctuation in the retail electricity
price (see Figure 3).

16
  Although the advanced technology costs for 2020 presented in Tables 3 and 4 are reasonable targets, these
estimates are speculative, so that the economic results for the substantial learning cases are accordingly quite
uncertain. In contrast, one can have a relatively high degree of confidence in the economic results for the modest
learning cases. AEP analysts characterize the current IGCC/VENT cost estimate presented in Table 4 as
―conservative‖ (Jasper, 2005). AEP and General Electric are carrying out a major ($20 million) feasibility study to
get better estimates for IGCC costs.The detailed feasibility study is likely to indicate a lower IGCC/VENT cost.
According to Richard Rapagnani (Manager, IGCC Commercialization, GE Energy, remarks made during a Panel on
IGCC Technology—Reliability, Availability, and Maintainability, at the Platts IGCC Symposium, 2 June 2005,
Pittsburgh), the GE/Bechtel strategic IGCC alliance expects to be able to close about half of the current
IGCC/VENT-SCS/VENT cost gap suggested by the estimates in Table 4 simply by coming up with a good detailed
design of a commercial IGCC plant and to close completely the cost gap by the time the ‗Nth plant‘ is built.
17
   Under the low-carbon coal generation obligation the retail electricity price in 2020 would be 0.7 to 1.2 mills/kWh
higher (see Table 6) than the 72 mills per kWh average retail price of electricity projected for 2020 (EIA, 2005).



                                                          9
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

These calculations suggest that the impacts on ratepayers of the proposed coal low-carbon
generation obligation would be quite modest. But how robust are estimates presented in Table 6?

Explicit Consideration of Low-Rank Coals in Estimating Generation Obligation Impacts

The assumption that all new coal plants will use bituminous coal simplifies the calculations of
incremental costs, but this assumption is not realistic because it neglects costs based on low-rank
coals (sub-bituminous coals and lignite). Powder River Basin (PRB) sub-bituminous coals are
especially important. These coals account for about ¼ of total coal consumed by US power
generators and are attractive because of their low sulfur contents and low prices compared to
bituminous coals.

Although few analyses have been carried out of performances and costs for low-rank coal power
with CCS, the few studies that have been carried out suggest that incremental costs would likely
be higher than those for bituminous coals, in large part because the higher moisture and/or ash
content(s) of low-rank coals18 tend to drive up gasification costs (Holt, Booras, and Todd, 2003;
Stobbs, 2004). Thus explicitly taking into account costs for lower- rank coals would tend to drive
up incremental costs to levels higher than those indicated in Table 6.

But another simplification of the incremental cost calculations presented in Table 6 that would
tend to lower the incremental cost estimates is the assumption of a zero market price for CO2
emissions until after 2020. A more realistic scenario would be that during the entire period 2012-
2020 the CO2 price would be increasing continually.

Both of these shortcomings of Table 6 calculations are addressed in rough fashion by additional
calculations presented in Table 7 for cost penalties in the no learning case in 2020 under the
assumption that half of the 30.6 GWe of coal capacity added during 2011-2020 is based on PRB
coal and for alternative carbon prices. The focus is on the year 2020 and the no learning case
because that is the year and the case involving the highest program cost for the bituminous coal
scenario presented in Table 6.

The calculations presented in Table 7 show that when half of the coal capacity additions are
based on PRB coals and the CO2 price is zero, the low carbon program cost would be about 10%
higher than for the 100% bituminous coal case. But even if the CO2 price in 2020 were as low as
$7 per tonne of CO2, the incremental cost for CCS in 2020 would be about 10% lower than for
the 100% bituminous coal case with zero CO2 price.19 If the carbon price in 2020 were as high as
$28 per tonne of CO2, the incremental cost for CCS with a 50/50 mix of bituminous and
subbituminous coals in 2020 would 70% less than for the 100% bituminous coal case with zero
carbon price; even such a high carbon price might plausibly be in place by 2020, considering that
the EU carbon trading price as of 7 July 2005 was ~ $35 (29 Euros) per tonne of CO2.
18
     PRB coals typically have a high (~ 30%) moisture content but relatively low ash content.
19
   A CO2 price of $7 per tonne equals the cap on the CO2 trading price under the economy-wide mandatory,
tradeable permits program recommended by the National Commission on Energy Policy for the initial phase of a
global warming policy (NCEP, 2004). To help put this CO 2 price level into perspective, note that it is equivalent to a
gasoline tax of 6 ¢ a gallon.



                                                           10
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.



Thus the finding for bituminous coals that the impact of the proposed coal low-carbon
generation obligation on ratepayers would be negligible seems to be a robust result even when
low rank coals are taken into account in the calculation of cost impacts of the obligation.

The low-carbon generation obligation would be a very good policy instrument for ascertaining
the most appropriate technologies for use with PRB and other low-rank coals—combustion
systems or IGCC and, if IGCC, the appropriate gasifier choice.

For IGCC technologies it is unclear what the most cost-competitive gasifier option is. Water-
slurry-fed IGCC gasifiers [GE (formerly ChevronTexaco) and ConocoPhillips] incur cost
penalties when used with Powder River Basin coals.20 Shell claims that: (i) with its dry
feed gasifier, Powder River Basin coal can be handled without a significant cost penalty and
(ii) since is first coal IGCC plant (Buggenum) went on line in the Netherlands in 1994, Shell
gasifier costs have come down a great deal,21 largely as a result of ‗learning by doing.‘ But some
think these claims are exaggerated. A low-carbon generation obligation for promoting coal
power with CCS would allow the market to discover where the truth lies. Moreover, for CCS
applications even the slurry-fed gasifiers might be radically improved by shifting from
water/coal slurries to CO2/coal slurries22—a concept that has been discussed since the late 1980s
but has not yet been demonstrated at commercial scale. However, the technology is a good
candidate for innovation via ‗learning by doing‘ that could be facilitated by the proposed low-
carbon generation obligation.

Post-2020 Carbon Price Impacts of a Coal Low-Carbon Generation Obligation

Early action on CCS via a coal low-carbon generation obligation would result in strong
downward pressure on carbon market prices in the 2020+ time frame in three ways. First, early
action would greatly reduce the need during the 2020+ period to carry out costly CCS retrofits.
Second, it would lead to identification of the least-costly technological options for power
generation with CCS based on low-rank coals. And third, for all coal power generation
technologies with CCS deployed during 2011-2020, there would be an early lowering of the CCS
cost via ‗learning by doing‘ as a consequence of field experience.
Ancillary Benefits of Early Action
20
  The challenge posed by use of Powder River Basin coal in water/coal slurry gasifiers is that water from the coal
plus that in the slurry is so high that O 2 requirements for the gasifier are much increased relative to low-moisture
bituminous coals, driving up energy penalties and costs.
21
   Shell IGCC costs are perceived by some as being higher than costs for IGCC units based on the GE and
ConocoPhillips gasifiers (FWE, 2003; EPRI, 2003). But Shell analysts claim that Shell IGCC costs are lower now—
in part because of design reoptimization [notably, new designs involve only partial integration of the air separation
unit with the gas turbine compressor, as a result of Shell’s learning via the Buggenum experience of the reliability
problems created by full integration (van der Ploeg et al., 2004)] but largely as a result of learning by doing from all
the new Shell gasifier orders in China (mainly for NH3 production).
22
  CO2 availability for slurry feed (as a result of CCS) adds two advantages: first, the coal fraction in the slurry can
be increased from 65% to perhaps 90%; second, the latent heat of CO 2 is 1/4 of that for H2O. Both of these
opportunities reduce the O2 requirements for the gasifier and thus capital and energy penalties.



                                                           11
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

The main reason for US early action on CCS for coal power plants is to reduce the risk of
locking in a huge commitment to the lifetime CO2 emissions from plants that are expected to be
built in the near term. But several ancillary benefits would also be generated by this early action.
One important ancillary benefit is the opportunity to make significant contributions in expanding
domestic oil production via enhanced oil recovery (EOR), thereby adding an appealing energy
supply security benefit of this strategy. The technical potential for EOR in the US is estimated to
be 30 billion barrels using conventional CO2–EOR techniques and an additional 30 billion
barrels using advanced techniques [Beecey and Kuuskraa (2004)]—considerably greater than
current US proved reserves of crude oil, estimated as of 2002 by the Energy Information
Administration to be 22.7 billion barrels. Although about 4% of US crude oil production is
currently accounted for by CO2-EOR, this activity is currently CO2 supply-constrained in some
regions where new coal power plants are likely to be built. This constraint could be greatly
alleviated by the proposed early action on CCS for coal power, which would make copious
quantities of CO2 available at often attractive costs.23,24
Also, early and extensive CCS activity would enable US industry to evolve a technological
leadership position in providing CCS technologies to potentially huge international markets. The
US would be starting off at a disadvantage relative to the UK, which has recently announced an
ambitious program to recover CO2 from natural gas power plants and use the CO2 for EOR in
North Sea oil fields.25 Although this British plan is already underway, a US effort catalyzed by
the proposed coal low-carbon generation obligation would enable the US to achieve a leadership
position in a relatively short period of time—both because the CO2 made available at coal
IGCC/CCS plants is much less costly than the CO2 recovered at natural gas combined cycle
power plants, and because much larger CO2 supplies would be forthcoming via a US coal-based
CCS effort.
Finally, early action on CCS would also greatly reduce uncertainty about climate mitigation
policy and thereby improve the investment outlook for coal power by reducing financial risks
posed by this uncertainty. The challenges facing those in the coal power industry, the vendors,
and the various regulators would be greatly reduced if this financial risk could be mitigated. This
‗coal power community,‘ which is involved in various aspects of making electricity from coal in
plants having economic lives ~ 30 years, has much more at stake in reducing this uncertainty
than politicians whose term of office is 2-6 years.
Conclusion

23
  The plant-gate cost of pressurized CO2 based on today’s IGCC/CCS technology (see Table 4) would be $14 to
$21 per tonne of CO2 (depending on whether IGCC/VENT or SCS/VENT is the reference plant), which would often
be competitive for EOR projects that are not too far from the power plant.
24
  The cost penalties estimated in Tables 6 and 7 for early CCS action do not take into account opportunities for
selling CO2 for EOR applications and are thus likely to be higher on average than actual penalties, because some
power projects would be able to sell CO2 for EOR applications.
25
  An initial $600 million project will involve fueling a 350 MW e combined cycle power plant near Petershead in
northern Scotland with hydrogen derived from natural gas and sending the 1.3 million tonnes per year of coproduct
CO2 to the Miller field in the North Sea, where it will be used for EOR. Plant operation is expected to start in 2009.
This initial project is a joint venture involving BP, ConocoPhillips, and Shell (with Scottish and Southern Energy
also partnering on the project).


                                                          12
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.



The present analysis shows that early action aimed at deploying CCS technologies at all new US
coal power plants expected to be brought on line during 2012-2020 could be accomplished
effectively by means of a low-carbon generation obligation—well before implementation of a
climate mitigation policy stringent enough to induce CCS for coal power generation. The
obligation would make CCS profitable for coal power generators while having a near negligible
impact on electricity rate payers.

Early action would accelerate a shift to the least-costly power generating technologies with CCS
for all coal types, and, for such technologies, would lead to early cost lowering as a result of
extensive early field experience (learning by doing).

Early experience with CCS via a coal low-carbon generation obligation would provide the US
with multiple ancillary benefits—including acceleration in the growth of oil production via EOR,
an improved positioning of US industry for competing in world CCS technology markets, and
reduction of the financial risks for coal power investments arising from uncertainties about
climate mitigation policy.

Perhaps most importantly, the proposed US initiative would create political and technological
conditions that would accelerate efforts by the rapidly growing economies of the developing
world to integrate mitigation of greenhouse gas emissions into their development strategies.
Since about 2/3 of the new coal capacity forecast to be built during 2003-2030 is in the
developing world, the multiplier value of a US-based early action program is considerable.

                                           Acknowledgments

The authors thank Robert Socolow and Tom Kreutz for extensive comments on earlier drafts of
this manuscript. RHW gratefully acknowledge financial support from the BP/Ford-supported
Carbon Mitigation Initiative at Princeton University, the William and Flora Hewlett Foundation
and the Blue Moon Fund. DGH gratefully acknowledges financial support from the Public
Welfare Foundation.

                                                References

Beecey, D.J., and V.A. Kuuskraa, 2004: Base strategies for linking CO2 enhanced oil recovery
and storage of CO2 emissions, paper presented at the 7th International Conference on
Greenhouse Gas Control Technologies, Vancouver, BC, 5-9 September.

Berry, T., M. Jaccard, 2001: The Renewable Portfolio Standard: design considerations and an
implementation survey, Energy Policy, 29: 263-277.

Braine, B.H. (Vice President – Strategic Policy and Analysis), and M.J. Mudd, 2005: Integrated
Gasification Combined Cycle Technology, an American Electric Power Service Corporation
White Paper, 5 May.

Chiesa, P., G. Lozza, and L. Mazzocchi, 2003: Using hydrogen as gas turbine fuel, Proceedings



                                                     13
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

of ASME Turbo Expo 2003: Power for Land, Sea, and Air, Atlanta, GA, 16-19 June

Dillon, D.J., R.S. Panesar, R.A. Wall, R.J. Allam, V. White, J. Gibbins, and M.R. Haines, 2004:
Oxy-combustion processes for CO2 Capture from advanced supercritical PF and NGCC plant,
7th International Conf. on Greenhouse Gas Control Technologies, Vancouver, September.

EIA (Energy Information Administration), 2005: Annual Energy Outlook 2005 with Projections
to 2025, DOE/EIA-0383 (2005), January.

EPRI, 1993: Technical Assessment Guide: Electricity Supply—1993, Electric Power Research
Institute, Palo Alto, CA, June.

EPRI, 2003: Phased Construction of IGCC Plants for CO2 Capture—Effect of Pre-Investment:
Low Cost IGCC Plant Design for CO2 Capture, report prepared by M. Rutkowski, T. Buchanan,
M. Klett, and R. Schoff (Parsons Infrastructure and Technology Group, Inc.); EPRI project
managers: N. Holt and G. Booras, December.

FWE [Foster Wheeler Energy Ltd (Italy and UK)], 2003: Potential for Improvement in
Gasification Combined Cycle Power Generation with CO2 Capture, IEA Greenhouse Gas R&D
Programme, Report Number PH4/19, May.

Haddad, B., P. Jefferiss, 1999: Forging consensus on national renewables policy: The
Renewables Portfolio Standard and the National Public Benefits Trust Fund, The Electricity
Journal, 12: 68-80.

Hansen, J., 2004: Defusing the global warming time bomb, Scientific American, 290 (3): 68-77,
March.

Hare, B., and M. Meinhausen, 2004: How much warming are we committed to and how much
can be avoided? Report prepared for the EU Stakeholder Consultation on Action on Climate
Change Post 2012, 28 October 2004.

Holt, N., G. Booras, and D. Todd, 2003: A summary of recent IGCC studies of CO2 capture for
sequestration, paper presented at the Gasification Technologies Conference, San Francisco, 12-
15 October.

IEA (International Energy Agency), 2004: World Energy Outlook 2004, Paris.

Jasper, W.M., 2005: Direct Testimony before the Public Utility Commission of Ohio in the
Matter of the Application of Columbus Southern Power Company and Ohio Power Company for
Authority to Recover Costs Associated with the Construction and Ultimate Operation of an
Integrated Gasification Combined Cycle Electric Generating Facility, Case No. 05-376-EL-
UNC, 5 May.

McDonald, A. and L. Schrattenholzer, 2001: Learning rates for energy technologies, Energy
Policy, 29: 255-261.



                                                     14
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.



Morrison, G.F., 2004: Summary of Canadian Clean Power Coalition Work on CO2 capture and
storage, London, UK, IEA Clean Coal Centre. Available from: http://www.iea-coal.org.uk/ by
clicking on Reports then Free report downloads, 23 pp., August.

Nakicenovic, N., A. Grübler, and A. MacDonald, 1998: Global Energy Perspectives, Cambridge
University Press, Cambridge, U.K.

Ogden, J.M., 2002: Modeling infrastructure for a fossil H2 energy system with CO2
sequestration, Paper J2-5, paper presented at the 6th International Conference on Greenhouse
Gas Control Technologies, Kyoto, Japan, September.

O‘Neill, B.C., and M. Oppenheimer, 2002: Dangerous climate impacts and the Kyoto Protocol.
Science, 296, 1971-1972.

Rader, N., R. Norgaard, 1996: Efficiency and sustainability in restructured electricity markets:
the Renewables Portfolio Standard, The Electricity Journal, 9: 37-49.

Shilling, N., and R.M. Jones, 2003: The response of gas turbines to a CO2 constrained
environment, presented at the Gasification Technologies Conference, San Francisco.

Socolow, R., 2005: Can we bury global warming?, Scientific American, pp. 49-55, July.

Socolow, R., S. Pacala and J. Greenblatt, ―Wedges‖: Early Mitigation with Familiar
Technology,‖ 7th International Conference on Greenhouse Gas Control Technologies,
Vancouver, September 2004.

Stevens, S.H, V.A. Kuuskraa, and J. Gale, 2000: Sequestration of CO2 in depleted oil and gas
fields: global capacity, costs, and barriers, pp. 278-283, in D.J. Williams, R.A. Durie, P.
McMullan, C.A.J. Paulson, and A.Y. Smith, eds., Greenhouse Gas Control Technologies:
Proceedings of the 5th International Conference on GHG Control Technologies (GHGT-5),
Collingwood, Victoria, Australia: CSIRO Publishing, 1328 pp.

Stobbs, R. and P. Clark, 2004: Canadian Clean Power Coalition: the evaluation of options for
CO2 capture from existing and new coal-fired power plants, paper presented at the 7th at the
Seventh International on Greenhouse Gas Control Technologies (GHGT-7), Vancouver, Canada,
September.

Todd, D. H. and R.A. Battista, 2000: Demonstrated applicability of hydrogen fuel for gas
turbines, presented at the Fourth European Gasification Conference, Noordwijk, The
Netherlands, April.

Van der Linden, N.H. (ECN, The Netherlands), M.A. Uyterlinde (ECN), C. Vrolijk (IT Power,
UK), L.J. Nilsson (University of Lund, Sweden), K. Åstrand (University of Lund), K. Ericsson
(University of Lund), and R. Wiser (Lawrence Berkeley National Laboratory), 2005: Review of




                                                     15
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

International Experience with Renewable Energy Obligation Support Mechanisms, LBNL-
57666, May.

Van der Ploeg, H.J., T. Chhoa, and P.L. Zuideveld, 2004: The Shell Coal Gasification Process
for the US industry, Gasification Technology Conference, Washington, DC, October.

Williams, R.H., 2004: IGCC: next steps on the path to gasification-based energy from coal, in
NCEP Technical Appendix: Expanding Energy Supply, in The National Commission on Energy
Policy, Ending the Energy Stalemate: A Bipartisan Strategy to Meet America‘s Energy
Challenges, Washington, DC, December.

Wilson, T., and C. Clark (EPRI), 2005: CoalFleet Analysis of Financial Incentives for Deploying
IGCC, CoalFleet Program Update and Workshop, Indianapolis, Indiana, 26-28 April.

Wiser, R., K. Porter, and R. Grace, 2005: Evaluating experience with renewable portfolio
standards in the United States, Mitigation and Adaptation Strategies for Global Change, in press.




Appendix A: Can a Major Program of CO2 Injection into Geologic Formations Be Pursued
Now?




                                                     16
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

A program requiring CO2 capture and storage at nearly all of the coal-fired power plants forecast
to be built in the United States in the decade after 2010 would involve the injection of
considerable amounts of CO2 into underground formations—for enhanced oil or gas recovery
operations, or without resource recovery benefits in depleted oil and gas fields, in beds of
unminable coal, or in deep saline aquifier formations (at least 800 meter underground, far below
the fresh water aquifers used by humans). The required storage rate would grow from about 6
million tonnes per year in 2012 to 165 to 200 million tonnes per year by 2020, when the storage
rate would be 6 to 7 times the current CO2 injection rates for EOR purposes. Undertaking such a
large program requires confidence that it can be implemented without significant safety or
environmental risks.

While a full discussion of the risks presented by such an injection program is beyond the scope
of the present analysis,26 some observations are in order. The principal risks relate to release of
CO2 from either pipelines or the formations into which CO2 injected. Releases can be sudden or
gradual. Leakage from geological formations can be to the atmosphere or into formations where
useful resources, such as drinking water might be present. For a storage project to be certified,
regulators will have to be satisfied that gradual leakage can occur only at a very slow rate, that
sudden leakage is extremely unlikely, and that local adverse environmental impacts would be
insignificant.

Although current global experience with CO2 injection is limited, it does provide a basis for
making some judgments about our ability to keep low the risks posed by the releases described
above under a program that involves injecting hundreds of millions of tonnes of CO2 per year at
multiple sites.

Both in terms of aggregate volumes injected and number of sites, the largest current activity
involves the injection of CO2 into oil fields to increase oil production. Such enhanced oil
recovery (EOR) operations have been in operation for over twenty years at more than 75
locations around the world, with 90% of the operations located in the United States. Currently,
about 30 million tonnes of CO2 are injected annually for EOR purposes in the U.S, where in
2000 oil production via EOR reached 216,000 barrels per day (4% of total US oil production).
Most of the injected CO2 comes from natural reservoirs of CO2, but 5 million tonnes per year
comes from anthropogenic waste CO2 sources (Stevens, Kuuskraa, and Gale, 2000). Most of the
CO2 is transported to EOR sites via pipelines, in some cases over long distances.27

Since EOR facilities are not licensed nor necessarily designed for truly long-term (thousands of
years) storage of CO2 and because they have only a couple of decades of operational history,
they do not provide a robust basis to assess risks of chronic, long-term leakage back to the
atmosphere. But EOR experience is relevant to assessing risks associated with acute releases.
While a sudden CO2 releases at an EOR site is possible, such a release, if it occurs, would pose

26
     A helpful, not-overly-technical discussion of the risk issues is presented in Socolow (2005).
27
   Most EOR projects in the United States are in the Permian Basin of Texas. Most of the CO2 for these projects is
transported by pipeline from natural reservoirs of CO2 in Colorado, New Mexico, and Wyoming (e.g.,via an 800 km
pipeline from the McElmo Dome in western Colorado—which contains 0.5 Gt CO2).



                                                            17
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

mainly an occupational hazard, and adverse impacts can be mitigated, as in the case of blowouts
for conventional oil or gas wells. Minimizing risks requires a good understanding of the
properties of CO2 and having in place appropriate procedures for dealing with potential
accidents. The probabilities of such accidents can be kept low with good project design and
regulations.28 Today‘s EOR operations are typically regulated by state oil and gas agencies,
which establish design, work practice, and reporting requirements. The adequacy of current
programs with expanded injection operations is an important issue to address.

The issue of scale is also relevant—‗megascale‘ CO2 injection rates are required. A 500 MWe
coal power plant would produce for storage about 3 million tonnes of CO2 per year. Most
individual EOR projects are considerably smaller than this. However, there are several large
injection projects (both EOR and non-EOR) that indicate scale-up to power-plant size injection
can be carried out safely. Since 1996, Statoil has injected about 1 million tonnes of CO2 annually
from an offshore gas platform into a deep saline aquifer under the floor of the North Sea. One
EOR project launched in 2000 involves transporting byproduct CO2 from a North Dakota plant
making synthetic natural gas from coal to the Weyburn oil field in Saskatchewan (Canada); the
300 km pipeline carries 1.5 million tonnes of CO2 annually to this EOR site. Most recently, BP
began injecting 1 million tonnes of CO2 annually into a geologic formation at its In Salah gas
field in Algeria. There have been no sudden releases from any of these large projects.

The CO2 storage experience to date indicates that a program such as that proposed to capture
CO2 from a significant amount of coal plant capacity can be carried out without significant risks
from sudden CO2 releases. However, given its larger scale and different purpose, such a program
would require an enhanced regulatory structure to assure the required performance of such
operations.

But what about the risks of slow leakage over long periods of time? Obviously, we do not have
hundreds of years of experience with human-engineered injection of CO2. What we do possess is
knowledge of natural geologic formations containing CO2 and other buoyant substances. Those
formations are an existence proof that some types of formations can retain CO2 for millions of
years. Geologists have extensive knowledge of the structures and processes that can achieve
‗permanent‘ storage, and they believe they understand and can avoid the pathways that could
result in significant leakage, even over periods exceeding tens of thousands of years. While this
knowledge provides some assurance, it is prudent to assume that some slow leakage will occur
for initial repositories on a long-term basis, even if every effort is made to select sites and design
operations to achieve high performance.

At first blush, this might suggest a ―go-slow‖ approach, with injection limited to pilot scales for a
decade or more to gather more experience. If no additional CO2 were being emitted to the air
during such a prolonged trial period, such an approach might make sense. But substantial
expansion of coal generating capacity is expected, and those new plants will release 100% of
their CO2 to the atmosphere until CCS commences. A program that starts CCS without further
delay almost certainly will result in radically lower atmospheric releases of CO2 from those
plants even if one assumes that the initial repositories do not achieve perfect permanent
retention.
28
     The climatic impacts of occasional sudden releases at EOR sites would be small.


                                                          18
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.



This does not imply society should be complacent about the design and operational criteria for
such initial storage sites; only that, if despite careful permitting requirements we later learn that
there is a likelihood of some significant long-term leakage from some sites, the total releases to
the atmosphere will still be greatly reduced compared to the alternative of letting such plants
vent all their CO2 until we have completed additional decades of smaller-scale injection research.
Moreover, it is likely that a program involving multiple injection sites with relatively high
volumes of CO2 will generate knowledge much more rapidly about how to achieve required
performance levels than would a program involving only a few smaller-scale projects.

To maximize the benefits of the experience with CO2 storage associated with the proposed coal
low-carbon generation obligation, it would be desirable to make essentially every project a
laboratory in which there are detailed monitoring of the migration underground of the injected
CO2 and modeling of its ultimate fate, and a variety of scientific and engineering studies are
carried out.




           Appendix B: Methodology for Estimating Coal Power Generation Costs

30-Year Levelized Costs for Coal Power Generation



                                                     19
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.



Thirty-year levelized costs for coal power generation both with CO2 vented (VENT cases) and
with CO2 capture and storage (CCS cases) were evaluated for bituminous coals using alternative
conversion technologies (Tables 3, 4, and 5) and assuming:(i) investor-owned utility (IOU)
financing29 (see Table 2), (ii) a coal price of $1.3/GJ,30 and (iii) plants operated at 85% capacity
factor,31 on average. For all cases it is assumed that the captured CO2 is transported 100 km and
stored in an aquifer 2 km underground.32

For current SCS and IGCC technologies (see Table 4), both with CO2 vented and with CO2
captured and stored, performance and capital cost estimates provided in an American Electric
Power White Paper on IGCC were assumed (Braine and Mudd, 2005). SCS performance and
cost are well established by market experience. Estimates for IGCC are preliminary and for
‗first-of-a-kind‘ plants.

Additional estimates of ‗Nth plant‘ performances and costs for current IGCC technologies with
CO2 vented and with CO2 captured and stored are presented in Table 3. These costs are based on
a study carried out for the International Energy Agency‘s GHG R&D Programme by Foster
Wheeler Energy of the UK and Italy (FWE, 2003). Table 3 also presents performance and cost
projections for IGCC plants that might be built in 2020, also based on FWE (2003).

The performance and cost analysis for oxyfuel plants presented in Table 5 is also based on study
carried out for the International Energy Agency‘s GHG R&D Programme (Dillon et al., 2004),
so that the results are appropriately compared to the current IGCC technology performanace and
cost estimates presented in Table 3.

Coal Low-Carbon Generation Obligation Cost Analyses

Bituminous coal analyses: In calculating the incremental cost for CCS in the low-carbon
generation obligation for bituminous coals, it is assumed that the reference plant is a SCS/VENT
plant—the least costly coal power option without CCS.

The incremental CCS costs estimated in the low-carbon generation obligation analysis take into
account that the annual capital charge rate declines over the 30-y life of the plant when financing
is via the EPRI TAG rules (see Table 2). Accordingly, for the no learning case, the incremental
cost for an IGCC/CCS plant coming on line in 2012 is 2.67 ¢/kWh in that year and declines to
29
   However, generation costs would be the same for the plausible independent power producer (IPP) financial
structure indicated in Table 2.
30
     The average coal price for US electric generators was $1.29/GJ in 2004.
31
   The US average capacity factor for coal power plants was 71.7% in 2003 but is projected to increase to 81.3% by
2010, 82.7% by 2015, and 83.2% during 2020-2025 (EIA, 2005). Currently available IGCC plants can be operated
at 85% capacity factor if equipped with a spare gasifier (see Table 3).
32
   The CO2 transport and storage model is for aquifer disposal and is based on Ogden (2002) except that the
maximum CO2 injection rate per well was changed from 2500 tonnes per day to 1000 tonnes per day (the rate for the
In Salah CO2 storage project in Algeria), which is likely to be appropriate for many mid-continental aquifers.



                                                          20
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

2.45 ¢/kWh in the year 2020. (For comparison, the 30-y levelized cost increment for IGCC/CCS
in this case is 2.38 ¢/kWh—see Table 4).

In the low-carbon generation obligation analysis for bituminous coals, generation costs for
IGCC/CCS were estimated both without and with the benefits of learning by doing. Two
learning cases were considered: a substantial learning case that involves some technological
innovation and a modest learning case that involves the ‗learning out‘ of current IGCC
technology (‗Nth plant‘ cost).33

For the no-learning cases, it is assumed that the generation cost for a new IGCC plant is constant
at the level of the current IGCC/CCS cost, as estimated in Table 4. For the learning cases, it is
assumed that the generation cost for a new IGCC/CCS plant declines with cumulative experience
at a constant learning rate34 until the cost reaches the target level for a new plant in 2020. For the
substantial learning case it is assumed that the total cost of a IGCC/CCS plant built in 2020 is
5.18 ¢/kWh (see Table 4), which is 0.793 times that for a new IGCC/CCS plant based on current
technology.35,36 Alternatively, it is assumed for the modest learning case that the generation cost
for a new IGCC/CCS plant built in 2020 is 5.58 ¢/kWh [the FWE (2003) estimate of the Nth
plant cost based on current technology—see Table 3], which is 0.855 times the assumed current
new plant cost level (6.53 ¢/kWh, see Table 4).

PRB coal analysis: Although, as noted in the main text, very little analysis has been carried out
for CCS with low-rank coals, a rough estimate of prospective costs based on PRB coals was
carried out for the low-carbon generation obligation incremental cost analysis, the results of
which are presented in Table 7. Holt, Booras, and Todd (2003) present an heuristic estimate that
the capital cost for both an EGAS-based IGCC/CCS plant and a SCS/CCS plant might be ~
$2100/kWe, the value assumed here, along with an assumed plant efficiency of 32.0%. The

33
  Although the advanced technology costs for 2020 presented in Tables 3 and 4 are reasonable targets, these
estimates are speculative, so that the economic results for the substantial learning cases are accordingly quite
uncertain. In contrast, one can have a relatively high degree of confidence in the economic results for the modest
learning cases. AEP analysts characterize the current IGCC/VENT cost estimate presented in Table 4 as
―conservative‖ (Jasper, 2005). AEP and General Electric are carrying out a major ($20 million) feasibility study to
get better estimates for IGCC costs.The detailed feasibility study is likely to indicate a lower IGCC/VENT cost.
According to Richard Rapagnani (Manager, IGCC Commercialization, GE Energy, remarks made during a Panel on
IGCC Technology—Reliability, Availability, and Maintainability, at the Platts IGCC Symposium, 2 June 2005,
Pittsburgh), the GE/Bechtel strategic IGCC alliance expects to be able to close about half of the current
IGCC/VENT-SCS/VENT cost gap suggested by the estimates in Table 4 simply by coming up with a good detailed
design of a commercial IGCC plant and to completely close the cost gap by the time the ‗Nth plant‘ is built.
34
  The learning rate is defined as the percentage reduction in generation cost for each cumulative doubling of
decarbonized generating capacity additions. The implicit learning rates are 4.4% and 3.4% for the substantial and
modest learning cases, respectively.
35
  This assumed ratio equals the ratio of generation cost projected for 2020 to the current generation cost as
estimated in Table 3 (FWE, 2003).
36
  Alternatively, one might assume for the substantial learning case that the IGCC/CCS generation cost in 2020 is
4.43 ¢/kWh, based on the FWE (2003) projection—in which case the generation cost in 2020 would be 0.678 times
the assumed cost for new IGCC/CCS plants coming on line in 2012. This more aggressive cost reduction scenario
was not considered in the present analysis.


                                                          21
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

reference plant is assumed to be a 37.6% subcritical steam-electric plant costing $1236/kWe. The
price of sub-bituminous coal is assumed to be 0.87*1.3 = $1.13/GJ, based on the observation that
in 2000 the average delivered price of PRB coal paid by US electric generators was 87% of the
average coal price in that year. Under these conditions, the incremental CCS cost for a PRB plant
with CCS coming on line in 2012 is 3.19 ¢/kWh in that year and declines to 2.90 ¢/kWh in the
year 2020, and the 30-y levelized cost increment in this case is 2.81 ¢/kWh—18% more than the
30-y levelized cost increment estimated in Table 4 for an IGCC/CCS plant burning bituminous
coal.




                                                     22
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

          Table 1a: Reference WEO 2004 Projections of New Coal Capacity Additions by Period (GWe)
                      US +     Other    Total,     Transition  China    Other DCs      Total DCs            World
                     Canada    OECD    OECD       Economies
2003-2010               0        12      12            1        150        59             209                222
2011-2020              100       84      184           11       168        138            306                501
2021-2030              137       81      218           19       226        207            433                670
Total, 2003-2030       237      177      414           31       544        404            948               1393

                          Table 1b: Reference WEO 2004 Projections for Electricity by Period
Year:                                                                  2002             2020           2030
Global primary energy for electricity, EJ/y                            158.1            236.4          278.4
   Coal                                                                 68.9            101.2          118.2
   Oil                                                                  12.1             12.8           11.8
   Natural gas                                                          33.4             63.5           81.1
   Nuclear                                                              29.1             32.6           32.1
   Hydro                                                                 9.4             13.5           15.3
   Biomass & wastes                                                      3.2              6.9           10.8
   Other renewables                                                      2.0              5.8            6.2
Global final electricity consumption, TWh/y                           13,300           21,400         26,400
Global CO2 emissions from electricity, GtC/y                            2.57             3.89           4.57
   Coal                                                                 1.81             2.65           3.09
   Oil                                                                  0.25             0.27           0.25
   Natural gas                                                          0.51             0.97           1.24

Source for Tables 1a and 1b: IEA (2004).

                             Table 2: Assumed Financing Rules for Electric Generatorsa
Investor type:                                                                    IOU                 IPP
Construction period, years                                                          4                   4
Number of equal payments for plant during construction                              4                   4
Inflation rate, %/year                                                              2                   2
Book/tax life, years                                                             30/20               30/20
Depreciation for tax purposes                                                   MACRS               MACRS
Corporate income tax rate, %                                                      39.2                39.2
Property taxes and insurance, %/year                                                2                   2
Nominal return on equity/debt, %/year                                           11.5/6.5            13.0/8.0
Equity/debt share, %                                                             45/55               30/70
Real discount rate, %/year                                                        5.67                5.74
Owner‘s cost as % of total plant investment                                        5.5                 5.5
Real annual levelized capital charge rate (ALCCR), %/year                        12.04               12.04
a
         Assuming EPRI Technical Assessment Guide (EPRI, 1993) financing rules and key financial parameter
values for investor-owned utilities and independent power producers as suggested in Wilson and Clark (2005).
IOU = investor owned utility; IPP = independent power producer. MACRS = modified accelerated capital recovery
system. Discount rate = after-tax weighted real average cost of capital.




                                                      23
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7 August 2005. Do not cite without authors‘
permission.

                                                             Table 3: Current and Future IGCC Costsa
                           [based on study Carried Out for the IEA GHG R&D Programme (FWE, 2003) but with EPRI TAG IOU Financing]
    Technology and status:                                                  Current [GE (formerly ChevronTexaco) gasifier] Advanced (~ 2020) technology
    Fate of CO2                                                                       VENT                    CCS           VENT              CCS
    Plant output, MWe                                                                 826.5                   730.3           879              776
    Capacity factor, %b                                                                  85                     85             85               85
    CO2 emission rate, g CO2/kWh                                                        833                    152            647              110
    CO2 storage rate, g CO2/kWh                                                           -                    858              -              623
    Efficiency, % (HHV)                                                                36.1                    29.9           46.5             41.0
    Owner costs, 106 $                                                                 56.1                    62.5           56.8             55.4
    Overnight construction cost, 106 $                                                938.2                  1043.4           949             926.4
    Total plant cost, $/kWe                                                            1135                   1429           1080             1194
    Total plant investment, $/kWe                                                      1235                   1555           1175             1299
    Electricity generation, (TWh/y                                                    6.154                   5.438          6.545            5.778
    Annual levelized capital charge rate (ALCCR)                                       0.12                    0.12           0.12             0.12
    Generation cost, ¢/kWh
       Capital charge                                                                 1.997                   2.514          1.900            2.101
       Coal @ $1.3/GJ                                                                 1.296                   1.564          1.007            1.140
       Operation and maintenance
           Variable (maintenance, waste disposal, chemicals, consumables)             0.653                   0.820          0.578            0.637
           Fixed (labor)                                                              0.135                   0.153          0.127            0.144
           Total operation and maintenance                                            0.788                   0.973          0.705            0.781
       Total generation cost                                                          4.082                   5.051          3.611            4.021
    Avoided cost with CO2 capture, $/t CO2 ($/ tC)                                        -                 14.2 (52.2          -         7.64 (28.0)
    CO2 transport and storage cost, $/t CO2c                                              -                   6.215             -             6.542
    CO2 transport and storage cost, ¢/kWh                                                 -                   0.533                           0.408
    Total generation cost with CO2 capture + storage, ¢/kWh                               -                   5.584             -             4.429
    Incremental cost, ¢/kWh                                                                                   1.500                           0.818
    Avoided cost with CO2 capture + storage, $/t CO2 ($/t C)                              -                22.0 (80.8)          -         15.2 (55.8)
a
  Performances (with LHV converted to HHV) and costs are based on FWE (2003). In that study corporate income taxes were neglected, and property taxes and
insurance (PTI) were included in O&M costs. With the assumed EPRI TAG financing model, corporate income taxes are taken into account, and PTI is
accounted for in the ALCCR (Table 2). Also, overnight construction costs (OCCs) reported in FWE (2003) include costs for land purchases and surveys (43.2,
48.1, 43.7, and 42.7 million dollars for current/VENT, current/CCS, advanced/VENT, and advanced/CCS options, respectively), which are elements of owner‘s
costs. Here these costs are separated from the OCCs and included instead as part of the owner‘s cost, assumed here to be 5.5% of the total plant investment for all
cases [higher than the owner‘s costs assumed in FWE (2003)]. The charges to electricity production for owner‘s costs are reflected in the ALCCR (see Table 2).
b
    The current FWE design includes a spare gasifier, which makes feasible the assumed 85% capacity factor (CF).
c
    Assumes CO2 pipeline transport 100 km for storage (in aquifer 2 km underground) and the maximum injection rate = 1000 t/d per well (In Salah rate).


                                                                                24
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7 August 2005. Do not cite without authors‘
permission.

                                  Table 4: Electricity Costs for Supercritical Steam (SCS) and IGCC Power Plants
               [based on AEP IGCC White Paper (Braine and Mudd, 2005) for Current Technologies but with EPRI TAG IOU Financing ]
    Technology and status                                                 SCS, Current             IGCC, Current           IGCC, 2020
    Fate of CO2                                                     VENT            CCS      VENT           CCS      VENT            CCS
    Plant output, MWe                                                 600           460        600          530        600           530
    Capacity factor, %                                                 85            85         85           85         85            85
    CO2 emission rate, g CO2/kWh                                      788           102        789           97        665            75
    CO2 storage rate, g CO2/kWh                                         -           922          -          873          -           679
    Efficiency, %, HHV                                                39.3          30.2       39.2         31.9       46.5          41.0
    OCC (overnight construction cost), 106 $                          774           989        930         1033.5     835.6         822.1
    Total plant cost, $/kWe                                          1290          2150       1550          1950      1393          1551
    Total plant investment, $/kWe                                    1404          2340       1687          2122      1516          1688
    Electricity generation, TWh/y                                    4.468         3.425      4.468        3.946      4.468         3.946
    Annual levelized capital charge rate (ALCCR)                    0.1204        0.1204     0.1204        0.1204    0.1204        0.1204
    Generation cost, ¢/kWh
       Capital charge                                                2.270         3.783      2.727        3.431      2.450         2.729
       Coal @ $1.3/GJ, HHV                                           1.192         1.550      1.193        1.467      1.007         1.140
       O&M (assumed to be 4%/y of OCC)                               0.693         1.155      0.833        1.048      0.748         0.833
       Total generation cost                                         4.154         6.487      4.753        5.946      4.206         4.703
    Avoided cost for CO2 capture, $/t CO2 ($/t C)
       If IGCC/VENT is the reference plant                              -             -          -       17.2 (63.2)     -        8.4 (30.8)
       If SCS/VENT is the reference plant                               -       34.0 (124.6)     -       25.9 (95.1)     -        7.7 (28.2)
    CO2 transport and storage costb, $/t CO2                            -           6.89         -          6.74         -           7.09
    CO2 transport and storage cost, ¢/kWh                               -          0.635         -         0.588         -          0.481
    Total generation cost with CO2 capture + storage, ¢/kWh             -          7.123         -         6.534         -          5.184
    Incremental cost, ¢/kWh
       Relative to IGCC/VENT                                            -             -          -         1.781         -          0.978
       Relative to SCS/VENT                                             -          2.968         -         2.380         -          1.030
    Avoided cost for CO2 capture + storage [$/t CO2 ($/t C)]
       If IGCC/VENT is the reference plant                              -             -          -       25.8 (94.4)     -       16.6 (60.7)
       If SCS/VENT is the reference plant                               -        43.3 (159)      -       34.4 (126)      -       14.4 (53.0)
a
         For SCS and current IGCC technologies, capacities, efficiencies, and capital costs are from Braine and Mudd (2005). Generation costs are estimated for
plants operated at 85% capacity factor, coal @ $1.3/GJ, and IOU financing (see Table 2). IGCC plant efficiencies for 2020 are from FWE (2003), converted from
LHV to HHV assuming LHV = 0.95 x HHV for coal. IGCC capital costs for 2020 were estimated assuming the same ratio of electricity cost in 2020 to current
generation cost as in the FWE (2003) study (see Table 3): 0.885 for the VENT case and 0.793 for the CCS case.
b
        Assumes CO2 pipeline transport 100 km for storage (in aquifer 2 km underground) and the maximum injection rate = 1000 t/d per well (In Salah rate),
based on CO2 transport and storage model developed in Ogden (2002).



                                                                              25
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.

               Table 5: Electricity Costs for SCS Plant s with Oxyfuel Strategy for Decarbonization
                          [based on Dillon et al. (2004) but with EPRI TAG IOU Financing)]
Assumed Technology                                                   SCS/VENT            Oxyfuel SCS for CCS
Plant output, MWe                                                         677                    532
Capacity factor, %                                                         85                      85
CO2 emission rate, g CO2/kWh                                              722                    84.6
CO2 storage rate, g CO2/kWh                                                 -                     831
Efficiency, %, HHV                                                        42.0                   33.6
OCC (overnight construction cost), 106 $                                  853                     989
Total plant cost, $/kWe                                                  1260                    1857
Total plant investment, $/kWe                                            1371                    2021
Electricity generation, TWh/y                                            5.041                  3.961
Annual levelized capital charge rate (ALCCR)                            0.1204                 0.1204
Generation cost, ¢/kWh
   Capital charge                                                        2.217                  3.268
   Coal @ $1.3/GJ, HHV                                                   1.115                  1.392
   O&M (assumed to be 4%/y of OCC)                                       0.677                  0.998
   Total generation cost                                                 4.008                  5.658
Avoided cost with CO2 capture, $/t CO2 ($/t C)                              -
CO2 transport and storage costb, $/t CO2                                    -                    6.70
CO2 transport and storage cost, ¢/kWh                                       -                   0.557
Total generation cost with CO2 capture + storage, ¢/kWh                     -                   6.214
Incremental cost, ¢/kWh                                                     -                   2.206
Avoided cost with CO2 capture + storage [$/t CO2 ($/t C)]                   -                 34.6 (127)




                                                      26
  R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7 August 2005. Do not cite without authors‘
  permission.

              Table 6: Impacts on Consumers of Low-Carbon Generation Obligation for All New US Coal Capacity Added During 2012-2020
                                        (Assuming Zero Carbon Market Price and That All Plants Use Bituminous Coal)
                                Capacity Added,      Incremental Cost for CCS          Cost Penalty on All Electricity  Increase in Retail Electricity Price
                                     GWe                       ($109/y)                  from Generation Obligation        from Generation Obligation
                                  (% of coal                                                    (mills/kWh)                            (%)
                                electricity with
                                     CCS)
Amount of learning:                                Substantial    Modest None       Substantial      Modest       None  Substantial     Modest        None
Year of capacity additions:
  2012                             0.9 (0.3)         0.179         0.179   0.179       0.042          0.042       0.042    0.063         0.063       0.063
  2013                             1.2 (0.7)         0.380         0.389   0.416       0.089          0.091       0.097     0.13          0.13        0.14
  2014                             2.0 (1.4)         0.670         0.703   0.809        0.15           0.16        0.19     0.22          0.23        0.27
  2015                             2.4 (2.2)         0.979          1.05    1.28        0.22           0.24        0.29     0.32          0.34        0.42
  2016                             3.2 (3.2)          1.35          1.48    1.91        0.30           0.33        0.42     0.43          0.47        0.60
  2017                             3.8 (4.4)          1.75          1.96    2.64        0.38           0.43        0.58     0.55          0.61        0.82
  2018                             4.5 (5.7)          2.19          2.49    3.50        0.47           0.54        0.75     0.66          0.75        1.06
  2019                             5.1 (7.2)          2.64          3.07    4.48        0.56           0.65        0.95     0.77          0.90        1.32
  2020                             7.5 (9.3)          3.25          3.87    5.93        0.68           0.80        1.23     0.94          1.12        1.71
Total additions, 2012-2020            30.6              -             -       -           -              -           -        -             -           -
Levelized values, 2012-2020:            -             1.28          1.44    1.98        0.30           0.34        0.47     0.43          0.49        0.67

 Table 7: Generation Obligation Impacts on Consumers in 2020 Assuming No Learning and That 50% of All New Coal Plants Use Sub-Bituminous Coala
        Carbon Market Priceb ($/t CO2)           Incremental Cost for CCS       Cost Penalty on All Electricity  Increase in Retail Electricity Price
                                                          ($109/y)                from Generation Obligation        from Generation Obligation
                                                                                         (mills/kWh)                             (%)
                      0                                     6.49                             1.35                               1.88
                      7                                     5.31                             1.11                               1.45
                     14                                     4.14                             0.86                               1.06
                     28                                     1.78                             0.37                               0.41
  a
           See Appendix B for a discussion of the details of the incremental cost penalty for PRB coals.
  b
          Near the end of the period 2011-2020 it is expected that there will be a price on carbon emissions that would reduce the incentive required via a low-
  carbon generation obligation significantly as shown by this analysis for the incentive needed and retail electricity cost penalty for the year 2020.




                                                                                 27
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7 August 2005. Do not cite without authors‘
permission.




Figure 1: Global GHG Emissions Trajectory for Stabilizing Atmospheric CO 2 @ 500 ppmv Compared to a BAU GHG Emissions Trajectory

Source: Socolow et al. (2004).




                                                                           28
R.H. Williams and D.G. Hawkins, Coal Low-Carbon Generation Obligation for US Electricity. Review draft, 7
August 2005. Do not cite without authors‘ permission.




                                                                                                                              RD&D phase
                                                        20000       1981
                                                         1983                Photovoltaics                                    Commercialization
                                                                             (learning rate ~ 20%)                            phase
                                                    10000
                                                                     USA
                                                                     Japan                  1992
                                                         5000
                                                                                             1995

                                                                                          Windmills (USA)
                                         US(1990)$/kW
                                                                             1982         (learning rate ~ 20%)
                                                        2000


                                                        1000
                                                                                                                  1987


                                                             500
                                                                                                    1963


                                                                                                           Gas turbines (USA)          1980
                                                             200                                           (learning rate ~ 20%, ~10%)



                                                             100
                                                               10                   100               1000               10000              100000
                                                                                             Cumulative MW installed

Figure 2: Experience curves for photovoltaics, wind generators, and gas turbines

These curves illustrate the well-established phenomenon that, for new technological products amenable to the
economies of standardized production techniques, prices tend to decline with cumulative production.

Source: Nakicenovic, Grübler, and MacDonald (1998).


                                                        78

                                             77.5

                                                        77

                                             76.5
                        2004 mills/kWh




                                                        76

                                             75.5

                                                        75

                                             74.5

                                                        74

                                             73.5
                                                2000                          2001                   2002                  2003                   2004
                                                                                                     Year




Figure 3: Annual Average US Retail electricity Price, 2000-2004




                                                                                                    29

								
To top