Capturing CO2 from Coal-Fired Power Plants: Challenges for a Comprehensive Strategy

Capturing CO2 from Coal-Fired Power Plants:
Challenges for a Comprehensive Strategy
August 15, 2008
Larry Parker, Peter Folger, and Deborah D. Stine
Resources, Science, and Industry Division



Capturing CO2 from Coal-Fired Power Plants:
Challenges for a Comprehensive Strategy
Summary
Any comprehensive approach to substantially reduce greenhouse gases must
address the world’s dependency on coal for a quarter of its energy demand, including
almost half of its electricity demand. To maintain coal in the world’s energy mix in
a carbon-constrained future would require development of a technology to capture
and store its carbon dioxide emissions. This situation suggests to some that any
greenhouse gas reduction program be delayed until such carbon capture technology
has been demonstrated. However, technological innovation and the demands of a
carbon control regime are interlinked; a technology policy is no substitute for
environmental policy and must be developed in concert with it.
Much of the debate about developing and commercializing carbon capture
technology has focused on the role of research, development, and deployment
(technology-push mechanisms). However, for technology to be fully commercialized,
it must also meet a market demand — a demand created either through a price
mechanism or a regulatory requirement (demand-pull mechanisms). Any conceivable
carbon capture technology for coal-fired powerplants will increase the cost of
electricity generation from affected plants because of efficiency losses. Therefore,
few companies are likely to install such technology until they are required to, either
by regulation or by a carbon price. Regulated industries may find their regulators
reluctant to accept the risks and cost of installing technology that is not required.
The Department of Energy (DOE) has invested millions of dollars since 1997
in carbon capture technology research and development (R&D), and the question
remains whether it has been too much, too little, or about the right amount. In
addition to appropriating funds each year for the DOE program, Congress supported
R&D investment through provisions for loan guarantees and tax credits. Congress
also authorized a significant expansion of carbon capture and sequestration (CCS)
spending at DOE in the Energy Independence and Security Act of 2007.
Legislation has also been introduced in the 110th Congress that would authorize
spending for carbon capture technology development. Other legislation introduced
invokes the symbolism of the Manhattan Project of the 1940s and the Apollo
program of the 1960s to frame proposals for large-scale energy policy initiatives that
include developing CCS technology. However, commercialization of technology and
integration of technology into the private market were not goals of either the
Manhattan Project or Apollo program.
Finally, it should be noted that the status quo for coal with respect to climate
change legislation isn’t necessarily the same as “business as usual.” The financial
markets and regulatory authorities appear to be hedging their bets on the outcomes
of any federal legislation with respect to greenhouse gas reductions, and becoming
increasingly unwilling to accept the risk of a coal-fired power plant with or without
carbon capture capacity. The lack of a regulatory scheme presents numerous risks to
any research and development effort designed to develop carbon capture technology.
Ultimately, it also presents a risk to the future of coal.



Contents
Introduction: Coal and Greenhouse Gas Emissions........................1
Background: What Is Carbon Capture Technology and What Is Its Status?.....3
Post-Combustion CO2 Capture...................................3
Monoethanolamine (MEA)..................................4
Chilled Ammonia (Alstom)..................................5
Ammonia (Powerspan).....................................6
Pre-combustion CO2 Capture.....................................6
Combustion CO2 Capture........................................8
DOE-Supported Technology Development..........................9
Roles for Government.............................................10
The Need for a Demand-Pull Mechanism..............................12
Approaches to a Demand-Pull Mechanism.............................15
Creating Demand Through a Regulatory Requirement:
An Example from the SO2 New Source Performance Standards.....15
Creating Demand Through a Price Signal: Carbon Taxes,
Allowance Pricing, and Auctions............................19
Current Technology-Push Mechanisms: DOE Investment in CCS R&D......21
Direct Spending on R&D.......................................21
Loan Guarantees and Tax Credits................................23
Encouraging Technology Development in the Absence of a Market:
Issues for Current Carbon Capture RD&D Policy....................24
What Should the Federal Government Spend on CCS
Technology Development?.................................26
Should the Federal Government Embark on a “Crash”
Research and Development Program?.........................27
The Manhattan Project and Apollo Program....................28
DOE-Supported Energy Technology Development...............29
Comparisons to CO2 Capture R&D at DOE....................29
The Possibility of Failure: The Synthetic Fuels Corporation........30
Implications for Climate Change Legislation...........................32
List of Figures
Figure 1. Simplified Illustration of Post-Combustion CO2 Capture...........4
Figure 2. Simplified Illustration of Pre-Combustion CO2 Capture............7
Figure 3. Status of Global IGCC Projects...............................8
Figure 4. Simplified Illustration of Oxy-fuels CO2 Capture.................9
Figure 5. The Federal Role in R&D..................................12
Figure 6. CO2 Price Projections.....................................15



Capacity of FGD Units: 1973-1996...............................18
Figure 8. Spending on CCS at DOE Since FY1997......................22
Figure 9. Expected Spending on CCS by Category in FY2008.............23
Figure 10. Annual Funding for the Manhattan Project, Apollo Program, and
DOE Energy Technology Programs...............................30
List of Tables
Table 1. Expected Costs of CCS Technology Elements....................2
Table 2. MIT Estimates of Additional Costs of Selected Carbon Capture
Technology ..................................................10
Table 3. Comparison of Various Demand-Pull Mechanisms...............33



Capturing CO2 from Coal-Fired Power
Plants: Challenges for a Comprehensive
Strategy
Introduction: Coal and Greenhouse Gas Emissions
The world meets 25% of its primary energy demand with coal, a number
projected to increase steadily over the next 25 years. Overall, coal is responsible for
about 20% of global greenhouse gas emissions.1 With respect to carbon dioxide
(CO2), the most prevalent greenhouse gas, coal combustion was responsible for 41%
of the world’s CO2 emissions in 2005 (11 billion metric tons).2
Coal is particularly important for electricity supply. In 2005, coal was
responsible for about 46% of the world’s power generation, including 50% of the
electricity generated in the United States, 89% of the electricity generated in China,
and 81% of the electricity generated in India.3 Coal-fired power generation is
estimated to increase 2.3% annually through 2030, with resulting CO2 emissions
estimated to increase from 7.9 billion metric tons per year to 13.9 billion metric tons
per year. For example, during 2006, it is estimated that China added over 90
gigawatts (GW) of new coal-fired generating capacity, potentially adding an
additional 500 million metric tons of CO2 to the atmosphere annually.4
Developing a means to control coal-derived greenhouse gas emissions is an
imperative if serious reductions in worldwide emissions are to occur in the
foreseeable future. Developing technology to accomplish this task in an
environmentally, economically, and operationally acceptable manner has been an
ongoing interest of the federal government and energy companies for a decade, but
no commercial device to capture and store these emissions is currently available for
large-scale coal-fired power plants.


1 Pew Center on Global Climate Change, Coal and Climate Change Facts, (2008), available
at [http://www.pewclimate.org/global-warming-basics/coalfacts.cfm].
2 International Energy Agency, World Energy Outlook 2007: China and India Insights
(2007), pp. 593.
3 World, China and India statistics from International Energy Agency, World Energy
Outlook 2007: China and India Insights, (2007), pp. 592, 596, and 600; United States
statistics from Energy Information Administration, Annual Energy Review: 2005 (July

2006), p. 228.


4 Pew Center on Global Climate Change, Coal and Climate Change Facts (2008), available
at [http://www.pewclimate.org/global-warming-basics/coalfacts.cfm]. Capacity factor
derived by CRS from data presented, assuming plants would operate in baseload mode with

70% capacity factors.



Arguably the most economic and technologically challenging part of the carbon
capture and sequestration (CCS) equation is capturing the carbon and preparing it for
transport and storage.5 Depending on site-specific conditions, the capture component
of a CCS system can be the dominant cost-variable, and the component that could be
improved most dramatically by further technological advancement. As indicated in
Table 1, capture costs could be 5-10 times the cost of storage. Breakthrough
technologies that substantially reduce the cost of capturing CO2 from existing or new
power plants, for example by 50% or more, would immediately reshape the
economics of CCS. Moreover, technological breakthroughs would change the
economics of CCS irrespective of a regulatory framework that emerges and governs
how CO2 is transported away from the power plant and sequestered underground.
Table 1. Expected Costs of CCS Technology Elements
CCS Element$/Metric Ton of CO2
Capture$40-$80
Storage$3-$8
Monitoring and Verification$0.2-$1.0
Source: S. Julio Friedmann, Carbon Capture and Sequestration As a Major Greenhouse Gas
Abatement Option (November 2007), p. 11.
Note: Capture and storage costs are very site-specific. These estimates reflect the magnitude of
difference between capture and storage costs; actual site-specific costs could vary substantially from
these estimates. Estimates do not include any transportation costs.
In contrast, the cost of transporting CO2 and sequestering it underground is
likely less dependent on technological breakthroughs than on other factors, such as:
!the costs of construction materials and labor (in the case of pipelines
for CO2 transport);
!the degree of geologic characterization required to permit
sequestration;
!the requirements for measuring, monitoring, and verifying
permanent CO2 storage;
!the costs of acquiring surface and subsurface rights to store CO2;
!costs of insurance and long-term liability; and
!other variables driving the cost of transportation and sequestration.6
That is not to say that the transportation and storage components of CCS are
independent of cost and timing. Depending on the degree of public acceptance of a


5 For a general discussion of carbon capture and sequestration, see CRS Report RL33801,
Carbon Capture and Sequestration (CCS), by Peter Folger.
6 For more information on policy issues related to the transportation of CO2, see CRS reports
RL33971: Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy
Issues, and CRS Report RL34316, Pipelines for Carbon Dioxide (CO2 ) Control: Network
Needs and Cost Uncertainties, by Paul W. Parfomak and Peter Folger.

large-scale CCS enterprise, the transportation and sequestration costs could be very
large, and it may take years to reach agreement on the regulatory framework that
would guide long-term CO2 sequestration. But the variables driving cost and timing
for the transportation and storage of CO2 are less amenable to technological solution.
This report examines the current effort to develop technology that would capture
CO2. First, the paper outlines the current status of carbon capture technology.
Second, the paper examines the role of government in developing that technology,
both in terms of creating a market for carbon capture technology and encouraging
development of the technology. Finally, the paper concludes with a discussion of
implications of capture technology for climate change legislation.
Background: What Is Carbon Capture Technology
and What Is Its Status?
Major reductions in coal-fired CO2 emissions would require either pre-
combustion, combustion modification, or post-combustion devices to capture the
CO2. Because there is currently over 300 GW of coal-fired electric generating
capacity in the United States and about 600 GW in China, a retrofittable post-
combustion capture device could have a substantial market, depending on the
specifics of any climate change program. The following discussion provides a brief
summary of technology under development that may be available in the near-term.
It is not an exhaustive survey of the technological initiatives currently underway in
this area, but illustrative of the range of activity. Funding for current government
research and development activities to improve these technologies and move them
to commercialization are discussed later.
Post-Combustion CO2 Capture
Post-combustion CO2 capture involves treating the burner exhaust gases
immediately before they enter the stack. The advantage of this approach is that it
would allow retrofit at existing facilities that can accommodate the necessary
capturing hardware and ancillary equipment. In this sense, it is like retrofitting post-
combustion sulfur dioxide (SO2), nitrogen oxides (NOx), or particulate control on an
existing facility. A simplified illustration of this process is provided in Figure 1.



Figure 1. Simplified Illustration of Post-Combustion CO2 Capture


Source: Scottish Centre for Carbon Storage. Figure available at [http://www.geos.ed.ac.uk/
sccs/capture/postcombustion.html ].
Post-combustion processes capture the CO2 from the exhaust gas through the
use of distillation, membranes, or absorption (physical or chemical). The most
widely-used capture technology is the chemical absorption process using amines
(typically monoethanolamine (MEA)) available for industrial applications. Pilot-
plant research on using ammonia (also an amine) as the chemical solvent is currently
underway with demonstration plants announced. These approaches to carbon capture
are discussed below. Numerous other solvent-based post-combustion processes are
in the bench-scale stage.7
Monoethanolamine (MEA). The MEA CO2 carbon capture process is the
most proven and tested capture process available. The basic design (common to most
solvent-based processes) involves passing the exhaust gases through an absorber
where the MEA interacts with the CO2 and absorbs it. The now CO2-rich MEA is
then pumped to a stripper (also called a regenerator) which uses steam to separate the
CO2 from the MEA. Water is removed from the resulting CO2, which is compressed
while the regenerated MEA is purged of any contaminants (such as ammonium
sulfate) and recirculated back to the absorber. The process can be optimized to8
remove 90-95% of the CO2 from the flue gas.
Although proven on an industrial scale, it has not been applied to the typically
larger volumes of flue gas streams created by coal-fired powerplants. The technology
has three main drawbacks that would make current use on a coal-fired powerplant
quite costly. First is the need to divert steam away from its primary use — generating
electricity — to be used instead for stripping CO2 from MEA. A second related
problem is the energy required to compress the CO2 after it’s captured — needed for
transport through pipelines — which lowers overall powerplant efficiency and
increases generating costs. A recent study by the Massachusetts Institute of
Technology (MIT) estimated the efficiency losses from the installation of MEA from
7 For a useful summary of carbon capture technology, see Steve Blankinship, “The
Evolution of Carbon Capture Technology Part 1,” Power Engineering (March 2008).
8 Ryan M. Dailey and Donald S. Shattuck, “An Introduction to CO2 Capture and
Sequestration Technology, Utility Engineering” (May 2008), p. 3.

25%-28% for new construction and 36%-42% for retrofit on an existing plant.9 This
loss of efficiency comes in addition to the necessary capital and operations and
maintenance cost of the equipment and reagents. For new construction, the increase
in electricity generating cost on a levelized basis would be 60%-70%, depending on
the boiler technology.10 In the case of retrofit plants where the capital costs were
fully amortized, the MEA capture process would increase generating costs on a
levelized basis by about 220%-250%.11
A third drawback is degradation of the amine through either overheating (over
205 degrees Fahrenheit [F]) in the absorber or through oxidation from oxygen
introduced in the wash water, chemical slurry, or flue gas that reacts with the MEA.
For example, residual SO2 in the flue gas will react with the MEA to form
ammonium sulfate that must be purged from the system.12 This could be a serious
problem for existing plants that do not have highly efficient flue gas desulfurization
(FGD) or selective catalytic reduction (SCR) devices (or none), requiring either
upgrading of existing FGD and SCR equipment, or installation of them in addition
to the MEA process.
Chilled Ammonia (Alstom). An approach to mitigating the oxidation
problem identified above is to use an ammonia-based solvent rather than MEA.
Ammonia is an amine that absorbs CO2 at a slower rate than MEA. In a chilled
ammonia process, the flue gas temperature is reduced from about 130 degrees F to
about 35-60 degrees F. This lower temperature has two benefits: (1) it condenses the
residual water in the flue gas, which minimizes the volume of flue gas entering the
absorber; and (2) it causes pollutants in the flue gas, such as SO2, to drop out,
reducing the need for substantial upgrading of upstream control devices.13 Using a
slurry of ammonium carbonate and ammonium bicarbonate, the solvent absorbs more
than 90% of the CO2 in the flue gas. The resulting CO2-rich ammonia is regenerated
and the CO2 is stripped from the ammonia mixture under pressure (300 pounds per
square inch [psi] compared with 15 psi using MEA), reducing the energy necessary14
to compress the CO2 for transportation (generally around 1,500 psi).
The chilled ammonia process is a proprietary process, owned by Alstom. In
collaboration with American Electric Power (AEP) and RWE AG (the largest
electricity producer in Germany), Alstom has announced plans to demonstrate the


9 Massachusetts Institute of Technology, The Future of Coal: An Interdisciplinary MIT
Study (2007), p. 147. Hereafter referred to as MIT, The Future of Coal.
10 Levelized cost is the present value of the total cost of building and operating a generating
plant over its economic life, converted to equal annual payments. Costs are levelized in real
dollars (i.e., adjusted to remove the impact of inflation).
11 MIT, The Future of Coal, pp. 27, 149.
12 Ryan M. Dailey and Donald S. Shattuck, “An Introduction to CO2 Capture and
Sequestration Technology, Utility Engineering” (May 2008), p. 4.
13 Ibid, p. 5.
14 Steve Blankinship, “The Evolution of Carbon Capture Technology, Part 1,” Power
Engineering (March 2008), p. 30.

technology on a 20 megawatt (MW) slipstream15 at AEP’s Mountaineer plant in West
Virginia, and to inject the captured CO2 into deep saline formations on site.16 Once
commercial viability is demonstrated at Mountaineer, AEP plans to install the
technology at its 450 MW Northeastern Station in Oologah, OK, early in the next
decade. The captured gas is to be used for Enhanced Oil Recovery (EOR). The target
is for full commercialization in 2015.
Ammonia (Powerspan). A second ammonia-based, regenerative process for
CO2 capture from existing coal-fired facilities does not involve chilling the flue gas
before it enters the absorber. Using higher flue gas temperatures increases the CO2
absorption rate in the absorber and, therefore, the CO2 removal. However, the higher
flue gas temperatures also mean that upgrades to existing FGD devices would be17
necessary.
This process is being developed by Powerspan.18 Called ECO2, two commercial
demonstrations designed for 90% CO2 capture have been announced with projected
operations to begin in 2011 and 2012. The first will use a 120 MW slipstream from
Basin Electric’s Antelope Valley Station in North Dakota. The second will be sited
at NRG’s W.A. Parish plant in Texas and use a 125 MW slipstream. The captured
CO2 is to be sold or used for EOR.
Pre-combustion CO2 Capture
Currently, a requirement for the pre-combustion capture of CO2 is the use of
Integrated Gasification Combined-cycle (IGCC) technology to generate electricity.19
There are currently four commercial IGCC plants worldwide (two in the United
States) each with a capacity of about 250 MW. The technology has yet to make a
major breakthrough in the U.S. market because its potential superior environmental
performance is currently not required under the Clean Air Act, and, thus, as discussed
above for carbon capture technology, its higher costs can not be justified (see the
Virginia State Corporation Commission decision, discussed below).
Carbon capture in an IGCC facility would happen before combustion, under
pressure using a physical solvent (e.g., Selexol and Rectisol processes), or a chemical
solvent (e.g., methyl diethanolaimine (MDEA)). A simplified illustration of this


15 Slipstream refers to pilot testing at an operating power plant using a portion of the flue gas
stream.
16 AEP News Release, RWE to Join AEP in Validation of Carbon Capture Technology,
(November 8, 2007).
17 Ryan M Dailey and Donald S. Shattuck, “An Introduction to CO2 Capture and
Sequestration Technology, Utility Engineering” (May 2008), p. 7.
18 Powerspan Corp., Carbon Capture Technology for Existing and New Coal-Fired Power
Plants (April 15, 2008).
19 IGCC is an electric generating technology in which pulverized coal is not burned directly
but mixed with oxygen and water in a high-pressure gasifier to make “syngas,” a
combustible fluid that is then burned in a conventional combined-cycle arrangement to
generate power.

process is provided in Figure 2. Basically, the IGCC unit pumps oxygen and a coal
slurry into a gasifier to create a syngas consisting of carbon monoxide and hydrogen.
The syngas is cleaned of conventional pollutants (SO2, particulates) and sent to a shift
reactor which uses steam and a catalyst to produce CO2 and hydrogen. Because the
gases are under substantial pressure with a high CO2 content, a physical solvent can
separate out the CO2. The advantage of a physical solvent is that the CO2 can be freed
and the solvent regenerated by reducing the pressure — a process that is substantially
less energy-intensive than having to heat the gas as in an MEA stripper.
Figure 2. Simplified Illustration of Pre-Combustion CO2 Capture


Source: Scottish Centre for Carbon Storage. Figure available at [http://www.geos.ed.ac.uk/
sccs/capture/precombustion.html ].
From the capture process, the CO2 is further compressed for transportation or
storage, and the hydrogen is directed through gas and steam cycles to produce
electricity. MIT estimates the efficiency loss from incorporating capture technology
on an IGCC facility is about 19% (from 38.4% efficiency to 31.2%).20 This loss of
efficiency comes in addition to the necessary capital and operations and maintenance
cost of the equipment and reagents. For new construction, the estimated increase in
electricity generating cost on a levelized basis generally ranges from 22%-25%, with
American Electric Power estimating the cost increase at 41%.21
There is a lot of activity surrounding the further commercialization of IGCC
technology and in the demonstration of carbon capture methods on that technology.
As illustrated in Figure 3, numerous projects are currently in the development
pipeline. Whether development will be delayed by DOE’s decision to restructure the
FutureGen initiative (as discussed later, see box) is unclear.22
20 MIT, The Future of Coal, p. 35.
21 MIT, The Future of Coal, p. 36.
22 Brad Kitchens and Greg Litra, “Restructuring FutureGen,” Electric Light & Power,
(May/June 2008), pp. 46-47, 58.

Figure 3. Status of Global IGCC Projects


Source: Emerging Energy Research (EER), “Global IGCC Power Markets and Strategies:

2007-2030” (December 2007). See [http://www.emerging-energy.com/].


Combustion CO2 Capture
Attempts to address CO2 during the combustion stage of generation focus on
increasing the CO2 concentration of the flue gas exiting the boiler. The more
concentrated the CO2 is when it exits the boiler, the less energy (and cost) is required
later to prepare it for transport or storage. The most developed approach involves
combusting the coal with nearly pure oxygen (>95%) instead of air, resulting in a flue
gas consisting mainly of highly concentrated CO2 and water vapor. Using existing
technology, the oxygen would be provided by an air-separation unit — an energy
intensive process that would be the primary source of reduced efficiency. The details
of this “oxy-fuel” process are still being refined, but generally, from the boiler the
exhaust gas is cleaned of conventional pollutants (SO2, NOx, and particulates) and
some of the gases recycled to the boiler to control the higher temperature resulting
from coal combustion with pure oxygen. The rest of the gas stream is sent for further
purification and compression in preparation for transport and/or storage.23 Depending
on site-specific conditions, oxy-fuel could be retrofitted onto existing boilers. A
simplified illustration of this process is provided in Figure 4.
23 MIT, The Future of Coal, pp. 30-31.

Figure 4. Simplified Illustration of Oxy-fuels CO2 Capture


Source: Scottish Centre for Carbon Storage. Figure available at [http://www.geos.ed.ac.uk/
sccs/capture/oxyfuel.html ].
The largest oxy-fuel demonstration projects under development are the
Vattenfall Project in Germany and the Callide Oxyfuel Project in Queensland,
Australia. The Vattenfall project is a 30MW pilot plant being constructed at
Schewarze Pumpe and scheduled to begin operation soon. The captured CO2 will be
put in geological storage once siting and permitting processes are completed.24 The
Callide Project is being sponsored by CS Energy, who, with six partners, is
retrofitting a 30 MW boiler at its Callide-A power station with an oxy-fuel process.
Operation of the oxy-fuel process is scheduled for 2010, with transport and
geological storage of the CO2 planned for 2011.25
Numerous other bench- and pilot-plant scale initiatives are underway with
specific work being conducted on improving the efficiency of the air-separation
process. MIT estimates the efficiency losses from the installation of oxy-fuel at 23%
for new construction and 31%-40% for retrofit on an existing plant (depending on
boiler technology).26 This loss of efficiency comes in addition to the necessary
capital and operations and maintenance cost of the equipment and reagents. For new
construction, the increase in electricity generating cost on a levelized basis would be
about 46%. In the case of retrofit plants where the capital costs are fully amortized,
the oxy-fuel capture process would increase generating costs on a levelized basis by
about 170%-206%.27
DOE-Supported Technology Development
As summarized in Table 2, CO2 capture technology is currently estimated to
significantly increase the costs of electric generation from coal-fired power plants.
24 For more information, see Vattenfall’s website at [http://www.vattenfall.com/www/
co2_en/co2_en/879177tbd/879211pilot/index.j sp]
25 For more information, see ES Energy’s website at [http://www.csenergy.com.au/
research_and_deve lopment/ oxy_fuel_news.aspx].
26 MIT, The Future of Coal, p. 147.
27 MIT, The Future of Coal, pp. 30, 149.

Research is ongoing to improve the economics and operation of carbon capture
technology. DOE’s National Energy Technology Laboratory (NETL) is supporting
a variety of carbon capture technology research and development (R&D) projects for
pre-combustion, oxy-combustion, and post-combustion applications. A detailed
description of all the NETL projects, and of carbon capture technology R&D efforts
in the private sector, is beyond the scope of this report. However, funding from DOE
(described later) is supporting approximately two dozen carbon capture research
projects that range from bench-scale to pilot-scale testing.28 The types of research
explored in the NETL-supported projects include the use of membranes, physical
solvents, oxy-combustion, chemical sorbents, and combinations of chemical and
physical solvents. According to the NETL, these technologies will be ready for
slipstream tests by 2014 and for large-scale field testing by 2018.29 Projects pursued
by the private sector may be ready for pilot-scale testing by 2010 and possibly
sooner. 30
Table 2. MIT Estimates of Additional Costs of Selected Carbon
Capture Technology
(percent increase in electric generating costs on levelized basis)
New ConstructionRetrofit*
Post-combustion (MEA)60%-70%220%-250%
Pre-combustion (IGCC)22%-25%not applicable
Combustion (Oxy-fuel)46%170%-206%
Source: Massachusetts Institute of Technology, The Future of Coal: An Interdisciplinary MIT Study
(2007), pp.27, 30, 36, 149. See text for discussion of technologies.
* Assumes capital costs have been fully amortized.
Roles for Government
Generally, studies that indicate that emerging, less carbon-intensive new
technologies are both available and cost-effective incorporate a price mechanism
(such as a carbon tax) that provides the necessary long-term price signal to direct
research, development, demonstration, and deployment efforts (called “demand-pull”


28 Steve Blankinship, “The Evolution of Carbon Capture Technology, Part 2,” Power
Engineering (May 2008), pp. 62-63.
29 DOE National Energy Technology Laboratory, Carbon Sequestration FAQ Information
Portal, at [http://www.netl.doe.gov/technologies/carbon_seq/FAQs/tech-status.html#].
30 For example, the American Electric Power (AEP) Mountaineer Plant in West Virginia is
planning to capture about 90% of CO2 from 15 MW(e) of the plant’s output (equivalent to
about 100,000 metric tons of CO2 per year) beginning in 2010.

or “market-pull” mechanisms).31 Developing such a price signal involves variables
such as the magnitude and nature of the market signal, and its timing, direction, and
duration. In addition, studies indicate combining a sustained price signal with public
support for research and development efforts is the most effective long-term strategy
for encouraging development of new technology (called “technology-push”
mechanisms).32 As stated by Richard D. Morgenstern: “The key to a long term
research and development strategy is both a rising carbon price, and some form of
government supported research program to compensate for market imperfections.”33
The various roles the government could take in encouraging development of
environmental technologies are illustrated in Figure 5. The federal role in the
innovation process is a complex one, reflecting the complexity of the innovation
process itself. The inventive activity reflected by government and private research
and development efforts overlap with demand pull mechanisms to promote or require
adoption of technology, shaping the efforts. Likewise, these initiatives are facilitated
by the government as a forum for feedback gained through both developed and
demonstration efforts and practical application. The process is interlinked,
overlapping, and dynamic, rather than linear. Attempting to implement one role in
a vacuum can result in mis-directed funding or mis-timing of results.
This section discusses these different roles with respect to encouraging
development of carbon capture technology, including (1) the need for a demand-pull
mechanism and possible options; (2) current technology-push efforts at the U.S.
Department of Energy (DOE) and the questions they raise; and (3) comparison of
current energy research and development efforts with past mission-oriented efforts.


31 For example, see Interlaboratory Working Group, Scenarios for a Clean Energy Future,
ORNL/CON-476 (November 2000).
32 For example, see CERA Advisory Service, Design Issues for Market-based Greenhouse
Gas Reduction Strategies; Special Report (February 2006), p. 59; Congressional Budget
Office, Evaluating the Role of Prices and R&D in Reducing Carbon Dioxide Emissions
(September 2006).
33 Richard D. Morgenstern, Climate Policy Instruments: The Case for the Safety Valve
(Council on Foreign Relations, September 20-21, 2004), p. 9.

Figure 5. The Federal Role in R&D


Source: Margaret R. Taylor, Edward S. Rubin and David A Hounshell, “Control of SO2
Emissions from Power Plants: A Case of Induced Technological Innovation in the U.S.,”
Technological Forecasting & Social Change (July 2005), p. 699.
The Need for a Demand-Pull Mechanism
Economists note that the driving force behind the development of new and
improved technologies is the profit motive.... However, market forces will
provide insufficient incentives to develop climate-friendly technologies if the
market prices of energy inputs do not fully reflect their social cost (inclusive of
environmental consequences).... Even if energy prices reflect all production
costs, without an explicit greenhouse gas policy firms have no incentive to
reduce their greenhouse gas emissions per se beyond the motivation to
economize on energy costs. For example, a utility would happily find a way to
generate the same amount of electricity with less fuel, but without a policy that
makes carbon dioxide emissions costly, it would not care specifically about the
carbon content of its fuel mix in choosing between, say, coal and natural gas.
For firms to have the desire to innovate cheaper and better ways to reduce
emissions (and not merely inputs), they must bear additional financial costs for34
emissions.
Much of the focus of debate on developing carbon capture technology has been
on research, development, and demonstration (RD&D) needs. However, for
technology to be fully commercialized, it must meet a market demand — a demand
created either through a price mechanism or a regulatory requirement. As suggested
by the previous discussion, any carbon capture technology for coal-fired powerplants
34 Carolyn Fischer, Climate change Policy Choices and Technical Innovation, Resources for
the Future Issue Brief #20 (June 2000), p. 2.

will increase the cost of electricity generation from affected plants with no increase
in efficiency. Therefore, widespread commercialization of such technology is
unlikely until it is required, either by regulation or by a carbon price. Indeed,
regulated industries may find their regulators reluctant to accept the risks and cost of
installing technology that is not required by legislation. This sentiment was reflected
in a recent decision by the Virginia State Corporation Commission in denying an
application by Appalachian Power Company (APCo) for a rate adjustment to
construct an IGCC facility:
The Company asserted that the value of this project is directly related to (1)
potential future legal requirements for carbon capture and sequestration; and (2)
the proposed IGCC Plant’s potential ability to comply cost effectively with any
such requirements. Both of these factors, however, are unknown at this time and
do not overcome the other infirmities in the Application. The legal necessity of,
and the capability of, cost-effective carbon capture and sequestration in this
particular IGCC Plant, at this time, has not been sufficiently established to render
APCo’s Application reasonable or prudent under the Virginia Statute we must35
follow.
At the same time there is reluctance to invest in technology that is not required,
the unresolved nature of greenhouse gas regulation is affecting investment in any
coal-fired generation.36 The risk involved in investing in coal-fired generation absent
anticipated greenhouse gas regulations is outlined in “The Carbon Principles”
announced by three Wall Street banks — Citi, JP Morgan Chase, and Morgan Stanley
— in February 2008. As stated in their paper:
The absence of comprehensive federal action on climate change creates unknown
financial risks for those building and financing new fossil fuel generation
resources. The Financial Institutions that have signed the Principles recognize
that federal CO2 control legislation is being considered and is likely to be
adopted during the service life of many new power plants. It is prudent to take
concrete actions today that help developers, investors and financiers to identify,37
analyze, reduce and mitigate climate risks.
Similarly, lack of a regulatory scheme presents numerous risks to any RD&D
effort designed to develop carbon capture technology. Unlike a mission-oriented
research effort, like the Manhattan Project to develop an atomic bomb, where the
ultimate goal is victory and the cost virtually irrelevant, research efforts focused on


35 State Corporation Commission, Application of Appalachian Power Company, Case No.
PUE-2007-00068 (Richmond, April 14, 2008), p. 16.
36 As stated by DOE: “Regulatory uncertainty for GHG legislation is a key issue impacting
technology selection and reliability of economic forecasts. Returns on investment for
conventional plants, including supercritical, can be severely compromised by the need to
subsequently address CO2 mitigation. Higher capital costs incurred for IGCC may make
such new plants less competitive unless their advantage in CO2 mitigation is assured.” DOE
National Energy Technology Laboratory, Tracking New Coal-fired Power Plants (June 30,

2008), p. 14.


37 Citi, Morgan Chase, and Morgan Stanley, The Carbon Principles: Fossil Fuel Generation
Financing Enhanced Environmental Diligence Process (February 2008), p. 1.

developing a commercial device need to know what the market wants in a product
and how much the product is worth. At the current time, the market value of a
carbon capture device is zero in much of the country because there is no market for
carbon emissions or regulations requiring their reduction.38 All estimates of value are
hypothetical — dependent on a reduction program or regulatory regime that doesn’t
exist. With no market or regulatory signals determining appropriate performance
standards and cost-effectiveness criteria, investment in carbon capture technology is
a risky business that could easily result in the development of a “white elephant” or
“gold-plated” technology that doesn’t meet market demand.
While the “threat” of a carbon regime is stimulating RD&D efforts and
influencing decisions about future energy (particularly electricity) supply, the current
spread of greenhouse gas control regimes being proposed doesn’t provide much
guidance in suggesting appropriate performance and cost-effectiveness benchmarks
for a solution with respect to coal-fired generation. For example, isolating just one
variable in the future price of carbon under a cap-and-trade program — tonnage
reduction requirement — the future value of carbon reductions can vary
substantially.39 As illustrated by Figure 6, three possible reduction targets in 2050
— maintaining current 2008 levels (287 billion metric tons [bmt]), reducing
emissions to 50% of 1990 levels (203 bmt), and reducing emissions to 20% of 199040
levels (167 bmt) — result in substantially different price tracks for CO2. Without
a firm idea of the tonnage goal and reduction schedule, any deployment or
commercialization strategy would be a high-risk venture, as suggested by the
previously noted Virginia State Corporation Commission conclusion.


38 Exceptions to this would include areas where the carbon dioxide could be used for EOR,
or where a state or region has enacted greenhouse gas controls, such as California and
several northeastern states.
39 For a fuller discussion of the uncertainties involved in estimating the cost of cap-and-trade
programs, see CRS Report RL34489, Global Climate Change: Costs and Benefits of S. 2191
(S. 3036), by Larry Parker and Brent Yacobucci.
40 Segey Paltsev, et al., Assessment of U.S. Cap-and-Trade Proposals, MIT Joint Program
on the Science and Policy of Global Change, Report 146 (April 2007), p. 16.

Figure 6. CO2 Price Projections


Note: CO2e = carbon dioxide equivalent
Source: Segey Paltsev, et al., Assessment of U.S. Cap-
and-Trade Proposals, MIT Joint Program on the Science
and Policy of Global Change, Report 146 (April 2007), p.
16. For details on the analysis presented here, consult the
report. Available at [http://mit.edu/globalchange].
Approaches to a Demand-Pull Mechanism
There are two basic approaches to a demand-pull mechanism: (1) a regulatory
requirement, and (2) a price signal via a market-based CO2 reduction program. These
approaches are not mutually exclusive and can serve different goals. For example, a
regulation focused on new construction (such as the New Source Performance
Standard under Section 111 of the Clean Air Act41) could be used to phase in
deployment of carbon capture technology and prevent more coal-fired facilities from
being constructed without carbon capture (or ensure they would be at least “ready”
for carbon capture later). At the same time, a carbon tax or cap-and-trade program
could be initiated to begin sending a market signal to companies that further controls
will be necessary in the future if they decide to continue operating coal-fired
facilities.
Creating Demand Through a Regulatory Requirement: An
Example from the SO2 New Source Performance Standards
It is an understatement to say that the new source performance standards
promulgated by the EPA were technology-forcing. Electric utilities went from
having no scrubbers on their generating units to incorporating very complex
chemical processes. Chemical plants and refineries had scrubbing systems that
were a few feet in diameter, but not the 30- to 40-foot diameters required by the
utility industry. Utilities had dealt with hot flue gases, but not with saturated flue
gases that contained all sorts of contaminants. Industry, and the US EPA, has
41 The Clean Air Act, Section 111 (42 U.S.C. 7411).

always looked upon new source performance standards as technology-forcing,
because they force the development of new technologies in order to satisfy42
emissions requirements.
The most direct method to encourage adoption of carbon capture technology
would be to mandate it. Mandating a performance standard on coal-fired
powerplants is not a new idea; indeed, Section 111 of the Clean Air Act requires the
Environmental Protection Agency (EPA) to develop New Source Performance
Standards (NSPS) for any new and modified powerplant (and other stationary
sources) that in the Administrator’s judgment “causes, or contributes significantly to,
air pollution which may reasonably be anticipated to endanger public heath or
welfare.” NSPS can be issued for pollutants for which there is no National Ambient
Air Quality Standard (NAAQS), like carbon dioxide.43 In addition, NSPS is the floor
for other stationary source standards such as Best Available Control Technology
(BACT) determinations for Prevention of Significant Deterioration (PSD) areas and
Lowest Achievable Emission Rate (LAER) determinations for non-attainment
areas. 44
The process of forcing the development of emission controls on coal-fired
powerplants is illustrated by the 1971 and 1978 SO2 NSPS for coal-fired electric
generating plants. The Clean Air Act states that NSPS should reflect “the degree of
emission limitation achievable through the application of the best system of emission
reduction which (taking into account the cost of achieving such reductions and any
non-air quality health and environmental impact and energy requirements) the
Administrator determines has been adequately demonstrated.”45 In promulgating its
first utility SO2 NSPS in 1971, EPA determined that a 1.2 pound of SO2 per million
Btu of heat input performance standard met the criteria of Sec. 111 — a standard that
required, on average, a 70% reduction in new powerplant emissions, and could be
met by low-sulfur coal that was available in both the eastern and western parts of the
United States, or by the use of emerging flue gas desulfurization (FGD) devices.46
At the time the 1971 Utility SO2 NSPS was promulgated, there was only one
FGD vendor (Combustion Engineering) and only three commercial FGD units in


42 Donald Shattuck, et al., A History of Flue Gas Desulfurization (FGD) — The Early Years,
UE Technical Paper (June 2007), p. 3.
43 For a fuller discussion of EPA authority to regulate greenhouse gases under the Clean Air
Act, see Robert J. Meyer, Principal Deputy Assistant Administrator, Office of Air and
Radiation, EPA Testimony before the Subcommittee on Energy and Air Quality, Committee
on Energy and Commerce, U.S. House of Representation (April 10, 2008).
44 For a discussion of the structure of the Clean Air Act, see CRS Report RL30853: Clean
Air Act: A Summary of the Act and Its Major Requirements, by James E. McCarthy, Claudia
Copeland, Larry Parker, and Linda-Jo Schierow.
45 42 U.S.C. 7411, Clean Air Act, Sec. 111(a)(1)
46 40 CFR 60.40-46, Subpart D — Standards of Performance for Fossil-Fuel-Fired Steam
Generator for Which Construction is Commenced After August 17, 1971.

operation — one of which would be retired by the end of the year.47 This number
would increase rapidly, not only because of the NSPS, but also because of the
promulgation of the SO2 NAAQS, the 1973 Supreme Court decision preventing
significant deterioration of pristine areas,48 and state requirements for stringent SO2
controls, which opened up a market for retrofits of existing coal-fired facilities in
addition to the NSPS focus on new facilities. Indeed, most of the growth in FGD
installations during the early and mid-1970s was in retrofits — Taylor estimates that
between 1973 and 1976, 72% of the FGD market was in retrofits.49 By 1977, there
were 14 vendors offering full-scale commercial FGD installation.50
However, despite this growth, only 10% of the new coal-fired facilities
constructed between 1973 and 1976 had FGD installations. In addition, the early
performance of these devices was not brilliant.51 In 1974, American Electric Power
(AEP) spearheaded an ad campaign to have EPA reject FGD devices as “too
unreliable, too impractical for electric utility use” in favor of tall stacks,
supplementary controls, and low-sulfur western coal.52 This effort was ultimately
unsuccessful as the Congress chose to modify the NSPS requirements for coal-fired
electric generators in 1977 by adding a “percentage reduction” requirement. As
promulgated in 1979, the revised SO2 NSPS retained the 1971 performance standard
but added a requirement for a 70%-90% reduction in emissions, depending on the
sulfur content of the coal.53 At the time, this requirement could be met only through
use of an FGD device. The effect of the “scrubber requirement” is clear from the data
provided in Figure 7. Based on their analysis of FGD development, Taylor, Rubin,
and Hounshell state the importance of demand-pull instruments:
Results indicate that: regulation and the anticipation of regulation stimulate
invention; technology-push instruments appear to be less effective at prompting
invention than demand-pull instruments; and regulatory stringency focuses54


inventive activity along certain technology pathways.
47 Margaret R. Taylor, The Influence of Government Actions on Innovative Activities in the
Development of Environmental Technologies to Control Sulfur Dioxide Emissions from
Stationary Sources, Thesis, Carnegie Institute of Technology (January 2001), p. 37, 40.
48 Fri v. Sierra Club, 412 US 541 (l973). This decision resulted in EPA issuing “prevention
of significant deterioration” regulations in 1974; regulations what were mostly codified in
the 1977 Clean Air Amendment (Part C).
49 Taylor, ibid., p. 37.
50 Taylor, ibid., p. 39.
51 For a discussion of challenges arising from the early development of FGD, see Donald
Shattuck, et al., A History of Flue Gas Desulfurization (FGD) — The Early Years, UE
Technical Paper (June 2007).
52 Examples include full-page ads in the Washington Post entitled “Requiem for Scrubbers,”
“Scrubbers, Described, Examined and Rejected,” and “Amen.” For an example, see
Washington Post, p. A32 (October 25, 1974).
53 40 CFR 60.40Da-52Da, Subpart Da — Standards of Performance for Electric Utility
Stream Generating Units for Which Construction is Commenced After September 18, 1978.
54 Margaret R. Taylor, Edward S. Rubin, and David A. Hounshell, “Control of SO2
(continued...)

Figure 7. Number of FGD Units and Cumulative GW
Capacity of FGD Units: 1973-1996


Note: Numbers are archival through June 1994, then projected for 1994-96.
Source: Adapted by Taylor from Soud (1994). See Margaret R. Taylor, op. cit., 74.
That government policy could force the development of a technology through
creating a market should not suggest that the government was limited to that role, or
that the process was smooth or seamless. On the latter point, Shattuck, et al.,
summarize the early years of FGD development as follows:
The Standards of Performance for New Sources are technology-forcing, and for
the utility industry they forced the development of a technology that had never
been installed on facilities the size of utility plants. That technology had to be
developed, and a number of installations completed in a short period of time.
The US EPA continued to force technology through the promulgation of
successive regulations. The development of the equipment was not an easy
process. What may have appeared to be the simple application of an equipment
item from one industry to another often turned out to be fraught with unforeseen55
challenges.
The example indicates that technology-forcing regulations can be effective in
pulling technology into the market — even when there remains some operational
difficulties for that technology. The difference for carbon capture technology is that
for long-term widespread development, a new infrastructure of pipelines and storage
sites may be necessary in addition to effective carbon capture technology. In the
short-term, suitable alternatives, such as enhanced oil recovery needs and in-situ
geologic storage, may be available to support early commercialization projects
without the need for an integrated transport and storage system. Likewise, with
economics more favorable for new facilities than for retrofits, concentrating on using
54 (...continued)
Emissions from Power Plants: A Case of Induced Technological Innovation in the U.S.,”
Technological Forecasting & Social Change (July 2005), p. 697.
55 Shattuck, et. al., p. 15.

new construction to introduce carbon capture technology might be one path to
widespread commercialization. As an entry point to carbon capture deployment, a
regulatory approach such as NSPS may represent a first step, as suggested by the SO2
NSPS example above.
Creating Demand Through a Price Signal: Carbon Taxes,
Allowance Pricing, and Auctions
Much of the current discussion of developing a market-pull mechanism for new
carbon capture technology has focused on creating a price for carbon emissions. The
literature suggests that this is an important component for developing new
technology, perhaps more important even than research and development. As stated
by the Congressional Budget Office (CBO):
Analyses that consider the costs and benefits of both carbon pricing and R&D all
come to the same qualitative conclusion: near-term pricing of carbon emissions
is an element of a cost-effective policy approach. That result holds even though
studies make different assumptions about the availability of alternative energy
technologies, the amount of crowding out caused by federal subsidies, and the
form of the policy target (maximizing net benefits versus minimizing the cost of56
reaching a target).
Two basic approaches can be employed in the case of a market-based
greenhouse gas control program: a carbon tax and a cap-and-trade program. The
carbon tax would create a long-term price signal to stimulate innovation and
development of new technology. This price signal could be strengthened if the
carbon tax were escalated over the long run — either by a statutorily determined
percentage or by an index (such as the producer price index). A carbon tax’s basic
approach to controlling greenhouse gas emissions is to supply the marketplace with
a stable, consistent price signal — a signal that would also inform innovators as to
the cost performance targets they should seek in developing alternative technologies.
Designed appropriately, there would be little danger of the price spikes or market
volatility that can occur in the early stages of a tradeable permit program.57
A cap-and-trade program creates a price signal for new technology through a
market price for carbon permits (called allowances) — an allowance is a limited
authorization to emit one metric ton of carbon dioxide equivalent (CO2e). In a cap-
and-trade system, these allowances are issued by the government and either allocated
or auctioned to affected companies who may use them to comply with the cap, sell
them to other companies on the market, or bank them for future use or sale. The
resulting market transactions result in an allowance price. This price on carbon


56 Congressional Budget Office, Evaluating the Roles of Prices and R&D in Reducing
Carbon Dioxide Emissions (September 2006), p. 17.
57 In addition, some of the revenue generated by the tax could be used to fund research,
development, demonstration, and deployment of new technology to encourage the long-term
transition to a less-carbon-intensive economy.

emissions, however, can be both uncertain and volatile.58 In addition, a low
allowance price may be insufficient to encourage technology development and
refinement. For example, the 1990 acid rain control program effectively ended the
development of FGD for retrofit purposes by setting an emission cap that resulted in
low allowance prices and that could be met through the use of low-sulfur coal.
Noting that only 10% of phase 1 facilities chose FGD to comply with its
requirements, Taylor, et al., state:
The 1990 CAAA, however, although initially predicted to increase demand for
FGD systems, eroded the market potential for both dry and wet FGD system
applications at existing power plants when the SO2 allowance trading market
returned low-sulfur coal to its importance in SO2 control.... As a result, research
in dry FGD technology declined significantly. In this case, the flexibility
provided by the 1990 acid rain regulations discouraged inventive activity in
technologies that might have had broader markets under the traditional59
command-and-control regimes in place prior to 1990. [footnotes from original
text omitted]
A cap-and-trade program need not have such a result. For example, to more
effectively promote carbon capture technology, the price signal under a greenhouse
gas reduction program could be strengthened by requiring the periodic auctioning of
a substantial portion of available allowances rather than giving them away at no cost.
The SO2 program allocated virtually all of its allowance at no cost to affected
companies. Auctioning a substantial portion of available allowances could create a
powerful price signal and provide incentives for deploying new technology if
structured properly.60 The program could create a price floor to facilitate investment
in new technology via a reserve price in the allowance auction process. In addition,
the stability of that price signal could be strengthened by choosing to auction
allowances on a frequent basis, ensuring availability of allowances close to the time
of expected demand and making any potential short-squeezing of the secondary61


market more difficult.
58 For a fuller discussion, see CRS Report RL33799, Climate Change: Design Approaches
for a Greenhouse Gas Reduction Program, by Larry Parker.
59 Margaret R. Taylor, Edward S. Rubin, and David A. Hounshell, “Effect of Government
Actions on Technological Innovation for SO2 Control,” Environmental Science &
Technology (October 15, 2003), p. 4531. In a more recent article, the authors state: “Finally,
the case provides little evidence for the claim that cap-and-trade instruments induce
innovation more effectively than other instruments.” Margaret R. Taylor, Edward S. Rubin,
and David A. Hounshell, “Control of SO2 Emissions from Power Plants: A Case of Induced
Technological Innovation in the U.S.,” Technological Forecasting & Social Change (July

2005), p. 697-8.


60 Like a carbon tax, the revenues received could be at least partly directed toward research,
development, and demonstration programs.
61 Karsten Neuhoff, Auctions for CO2 Allowances — A Straw Man Proposal, University of
Cambridge Electricity Policy Research Group (May 2007), pp. 3-6. A short-squeeze is a
situation where the price of a stock or commodity rises and investors who sold short
(believing the price was going to fall) rush to buy it to cover their short position and cut their
losses.

One positive aspect of the acid rain cap-and-trade experience for encouraging
deployment of technology was the effectiveness of “bonus” allowances and deadline
extensions as incentives to install FGD. Specifically, about 3.5 million of the
allowances were earmarked for Phase 1 powerplants choosing to install 90% control
technology (such as FGD). Such units were allowed to delay Phase 1 compliance
from 1995 to 1997 and receive two allowances for each ton of S02 reduced below a
1.2 lb. per mmBtu level during 1997-1999. The 3.5 million allowance reserve was
fully subscribed, and was a major factor in what FGD was installed during Phase 1
of the program. This experience may bode well for proposed CCS “bonus allowance”
provisions in several greenhouse gas reduction schemes currently introduced in the
Congress.
Current Technology-Push Mechanisms: DOE
Investment in CCS R&D
The Department of Energy (DOE) is currently engaged in a variety of activities
to push development and demonstration of carbon capture technologies. These
activities include direct spending on research and development, and providing loan
guarantees and tax credits to promote carbon capture projects. These technology-
push incentives, and the issues they raise, are discussed below.
Direct Spending on R&D
The federal government has recognized the potential need for carbon capture
technology — as part of broader efforts to address greenhouse-gas induced climate
change — since at least 1997 when the DOE spent approximately $1 million for the62
entire CCS program. DOE spending on the CCS program has increased over the
11-year period to its highest amount in FY2008 of $118.9 million.63 If DOE
spending for FutureGen (discussed further below) is included, together with carbon-
capture technology investments through the Innovations for Existing Plants (IEP) and
the Advanced Integrated Gasification Combined Cycle (AIGCC) programs (also
within the DOE Office of Fossil Energy), then CCS spending at DOE could equal64
nearly $283 million in FY2008. If the Administration’s budget request for FY2009
were fully funded, then overall spending for CCS R&D could equal $414 million, a
46% increase over FY2008 spending levels. Figure 8 shows the trajectory of overall
DOE spending on CCS, under this accounting, since FY1997. From FY1997 to
FY2007, a total of nearly $500 million has been allocated to CCS at DOE.


62 Personal communication, Timothy E. Fout, General Engineer, DOE National Energy
Technology Laboratory, Morgantown, WV (July 16, 2008).
63 CCS research and development program line item in the DOE budget (part of the Office
of Fossil Energy), U.S. Department of Energy, FY2009 Congressional Budget Request,
Volume 7, DOE/CF-030 (Washington, DC, February 2008).
64 Ibid.

Figure 8. Spending on CCS at DOE Since FY1997


$45 0
$40 0
$350DOE CCS Program
$30 0) Fu t u r e Ge n
$250ionsAIGCC Program
$20 0mill
$150($IEP Program
$100Annual Total
$5 0
$0
97 98 99 00 01 02 03 04 05 06 07 08 09
FY FY FY FY FY FY FY FY FY FY FY FY FY
Source: Personal communication, Timothy E. Fout, General Engineer, DOE National Energy
Technology Laboratory, Morgantown, WV (July 16, 2008); and U.S. Department of Energy, FY2009
Congressional Budget Request, Volume 7, DOE/CF-030 (Washington, D.C., February 2008).
Note: Funding for FutureGen shown is the appropriated amounts. AIGCC means Advanced Integrated
Gasification Combined Cycle, and IEP means Innovations for Existing Plants; both are programs
under DOEs Office of Fossil Energy. Funding for FY2009 are the requested amounts.
According to DOE, the CCS line item in its Fossil Energy budget allocated
approximately 12% of the FY2008 budget to carbon capture technology specifically,
or approximately $14.3 million. Nearly $68 million, or 57% of the FY2008 CCS65
budget, was allocated to the regional partnerships, which are primarily pursuing
projects to store CO2 underground, not to develop capture technologies. The
remaining third of the FY2008 budget was allocated to other aspects of CCS, such
as technologies for monitoring, mitigating, and verifying the long-term storage of
CO2, other aspects of sequestration, breakthrough concepts (which includes capture
technologies), and others. (See Figure 9 for the breakdown of the DOE CCS
program spending in FY2008.) Of the $283 million in total funding for CCS in
FY2008 (by one estimation, which includes IEP and AIGCC funding (Figure 8)),
less than half is likely allocated for developing carbon capture technology.
65 Beginning in 2003, DOE created seven regional carbon sequestration partnerships to
identify opportunities for carbon sequestration field tests in the United States and Canada.

Figure 9. Expected Spending on CCS
by Category in FY2008


Source: Personal communication, Timothy E.
Fout, General Engineer, DOE National Energy
Technology Laboratory, Morgantown, WV
(July 16, 2008).
Note: Total expected spending for CCS in
FY2008 shown on this chart equals $118.91
million. Also, MMV as shown on the chart
stands for measurement, monitoring, and
verification.
Loan Guarantees and Tax Credits
Appropriations represent one mechanism for funding carbon capture technology
RD&D; others include loan guarantees and tax credits, both of which are available
under current law. Loan guarantee incentives that could be applied to CCS are
authorized under Title XVII of the Energy Policy Act of 2005 (EPAct2005, P.L. 109-
58). Title XVII of EPAct2005 (42 U.S.C. 16511-16514) authorizes the Secretary of
Energy to make loan guarantees for projects that, among other purposes, avoid,
reduce, or sequester air pollutants or anthropogenic emissions of greenhouse gases.
The Consolidated Appropriations Act for FY2008 (P.L. 110-161) provides loan
guarantees authorized by EPAct2005 for coal-based power generation and industrial
gasification activities that incorporate CCS, as well as for advanced coal gasification.
The explanatory statement66 directs allocation of $6 billion in loan guarantees for
retrofitted and new facilities that incorporate CCS or other beneficial uses of carbon.
66 The explanatory statement was published with the Committee Print of the House
Committee on Appropriations, Consolidated Appropriations Act, 2008, H.R. 2764/Public
Law P.L. 110-161. The Committee Print, which was published in January 2008, is available
at [http://www.gpoaccess.gov/congress/house/appropriations/08conappro.html].

Title XIII of EPAct2005 provides for tax credits that can be used for Integrated
Gasification Combined Cycle (IGCC) projects and for projects that use other
advanced coal-based generation technologies (ACBGT). For these types of projects,
the aggregate credits available total up to $1.3 billion: $800 million for IGCC
projects, and $500 million for ACBGT projects. Qualifying projects under Title XIII
of EPAct2005 are not limited to technologies that employ carbon capture
technologies; however, the Secretary of the Treasury is directed to give high priority
to projects that include greenhouse gas capture capability. Under the same title of
EPAct2005, certain projects employing gasification technology67 would be eligible
to receive up to $650 million in tax credits, and these projects would also receive
high priority from the Secretary of the Treasury if they include greenhouse gas
capture technology.
Encouraging Technology Development in the
Absence of a Market: Issues for Current Carbon
Capture RD&D Policy
Each of the funding mechanisms described above — appropriations, loan
guarantees, and tax credits — are examples of government “pushing” carbon capture
technologies (the upper left arrow in Figure 5) via direct spending and through
private sector incentives. Thus far, however, these activities are taking place in a
vacuum with respect to a carbon market or a regulatory structure. Lacking a price
signal or regulatory mandate, it is difficult to assess whether a government-push68
approach is sufficient for long-term technology development. Some studies appear
to discount the necessity of a price signal or regulatory mandate, at least initially, and
place a higher priority on the successful demonstration of large-scale technological,
economic, and environmental performance of technologies that comprise all of the69
components of an integrated CCS system: capture, transportation, and storage. So
far, however, the only federally sponsored, fully integrated, large-scale CCS
demonstration project — called FutureGen (see box) — failed in its original
conception, which may have been due, in part, to the lack of a perceived market.
DOE announced it was restructuring the FutureGen program because of its
rising costs, which are difficult to assess against the project’s “benefits” without a
monetary value attached to those benefits (i.e., the value of carbon extracted from the
fuel and permanently sequestered). A carbon market would at least provide some
way of comparing costs against benefits. One could argue that the benefits of CCS


67 Under Title XIII of EPAct2005, gasification technology means any process which
converts a solid or liquid product from coal, petroleum residue, biomass, or other materials,
which are recovered for their energy or feedstock value, into a synthesis gas (composed
primarily of carbon monoxide and hydrogen) for direct use in the production of energy or
for subsequent conversion to another product.
68 See quote by Morgenstern above. In that analysis, government-supported research is
needed to compensate for market imperfections. In the current situation, there is no market,
and thus its imperfections are moot.
69 MIT, The Future of Coal, p. xi.

accrue to the amelioration of future costs of environmental degradation caused by
greenhouse gas-induced global warming. Although it may be possible to identify
overall environmental benefits to removing CO2 that would otherwise be released to
the atmosphere, assigning a monetary value to those benefits to compare against costs
is extremely difficult.
Trying to Pick a Winner: FutureGen
On February 27, 2003, President Bush proposed a 10-year, $1 billion project to
build a coal-fired power plant that integrates carbon sequestration and hydrogen
production while generating 275 megawatts of electricity, enough to power about 150,000
average U.S. homes. As originally conceived, the plant would have been a coal-2
gasification facility and produced between 1 and 2 million metric tons of CO annually.
On January 30, 2008, DOE announced that it was “restructuring” the FutureGen program
away from a single, state-of-the-art “living laboratory” of integrated R&D technologies
— a single plant — to instead pursue a new strategy of providing funding for the addition
of CCS technology to multiple commercial-scale Integrated Gasification Combined Cycle70
(IGCC) power plants. In the restructured program, DOE would support up to two or71
three demonstration projects, each of at least 300 MW, and that would sequester at least2
1 million metric tons of CO per year. In its budget justification for FY2009, DOE cited
“new market realities” for its decision, namely rising material and labor costs for new
power plants and the need to demonstrate commercial viability of IGCC plants with72
CCS. A policy question that emerged following the DOE’s decision to scrap the
original FutureGen concept was whether such a concept can be viable without a long-
term price signal for carbon. FutureGen supporters have indicated that the rise in
FutureGen’s projected costs were consistent with the rise in global energy infrastructure73
projects due to inflation, implying that rising costs are not unique to FutureGen.
Nevertheless, the reasons given by DOE in its decision to cancel the original concept are
prima facie evidence that lack of a price signal for carbon in the face of known and rising
costs for plant construction created too much uncertainty for the agency to continue the
project. It is unclear whether a long-term price signal would have supported the
FutureGen concept anyway, given the project’s other uncertainties, such as its choice of74


a capture technology and disagreements over the private cost-share agreement.
70 See [http://www.fossil.energy.gov/news/techlines/2008/08003-DOE_Announces
_Restructured_FutureG.html ].
71 See [http://www.fossil.energy.gov/news/techlines/2008/08013-DOE_Takes_Next_Steps
_With_Restruct.html ].
72 DOE FY2009 Budget Request, p. 16.
73 FutureGen Alliance press release (April 15, 2008), at
[http://www.futurege na lliance.org/ news/releases/pr_04-15-08.stm].
74 See, for example, Michael T. Burr, “Death of a Turkey, DOE’s Move to ‘Restructure’
FutureGen Clears the Way for a More Rational R&D,” Public Utilities Fortnightly (March

2008); and David Goldston, “Demonstrably Wrong,” Nature, Vol. 453, No. 16 (April 30,


2008), p. 16.



What Should the Federal Government Spend on CCS
Technology Development?
As discussed above, several studies underscore the value of a long-term price
or regulatory signal to shape technological development and, presumably, to help
determine a level of federal investment needed to encourage commercialization of
an environmental technology such as carbon capture. As stated by Fischer:
With respect to R&D for specific applications (such as particular manufacturing
technologies or electricity generation), governments are notoriously bad at
picking winners... [e.g., the breeder reactor]. The selection of these projects is
best left to private markets while the government ensures those markets face the75
socially correct price signals.
Despite the lack of regulatory incentives or price signals, DOE has invested
millions of dollars since 1997 into capture technology R&D, and the question
remains whether it has been too much, too little, or about the right amount. In
addition to appropriating funds each year for the DOE program, Congress signaled
its support for RD&D investment for CCS through provisions for tax credits
available for carbon capture technology projects in EPAct2005, and through loan
guarantees authorized in the Consolidated Appropriations Act for FY2008 (P.L. 110-
161). Congress also authorized a significant expansion of CCS spending at DOE in
the Energy Independence and Security Act of 2007 (EISA, P.L. 110-140), which
would authorize appropriations for a total of $2.2 billion from FY2008 through
FY2013. Although EISA places an increased emphasis on large-scale underground
injection and storage experiments, the legislation authorizes $200 million per year
for projects that demonstrate technologies for the large-scale capture of CO2 from a
range of industrial sources.
Legislation has also been introduced in the 110th Congress that would authorize
specific amounts of spending for CCS and capture technology development.
Notably, the Carbon Capture and Storage Early Deployment Act (H.R. 6258), if
enacted, would authorize distribution utilities76 to collect an assessment on fossil-fuel
based electricity delivered to retail customers. The assessment would total
approximately $1 billion annually, and would be issued by a corporation —
established by referendum among the distribution utilities — as grants or contracts
to private, academic, or government entities to accelerate commercial demonstration
or availability of CO2 capture and storage technologies and methods. This legislation
contains elements that resemble, in many respects, recommendations offered in the77
MIT report.
Some bills introduced in the 110th Congress include incentives such as tax
credits, debt financing, and regulations to promote CO2 capture technology


75 Carolyn Fischer, Climate Change Policy Choices and Technical Innovation, Resources
for the Future Climate Issue Brief #20 (June 2000), p. 9
76 A distribution utility is defined in the legislation as an electric utility that has a legal,
regulatory, or contractual obligation to deliver electricity directly to retail customers.
77 MIT, The Future of Coal, p. 102.

development. For example, S. 3132, the Accelerating Carbon Capture and
Sequestration Act of 2008, provides a tax credit of $20 per metric ton of CO2
captured and stored.78 S. 3233, the 21st Century Energy Technology Deployment Act,
would establish a corporation that could issue debt instruments (such as bonds) for
financing technology development. A priority cited in S. 3233 is the deployment of
commercial-scale CO2 capture and storage technology that could capture 10 million
short tons of CO2 per year by 2015. A bill aimed at increasing the U.S. production
of oil and natural gas while minimizing CO2 emissions, S. 2973, the American
Energy Production Act of 2008, would require the promulgation of regulations for
clean, coal-derived fuels. Facilities that process or refine such fuels would be
required to capture 100% of the CO2 that would otherwise be released at the facility.
Other legislation introduced invokes the symbolism of the Apollo program of
the 1960s to frame proposals for large-scale energy policy initiatives that include
developing CCS technology.79 The relevance and utility of large-scale government
projects, such as the Apollo program, or the Manhattan project, to developing carbon
capture technology are explored in the following sections.
Should the Federal Government Embark on a “Crash”
Research and Development Program?
Some policymakers have proposed that the United States invest in energy
research, development, and demonstration activities at the same level of commitment
as it invested in the past during the Manhattan project and the Apollo program. As
analogues to the development of technologies to reduce CO2 emissions and thwart
long-term climate change, the Manhattan project and Apollo program are imperfect
at best. They both had short-term goals, their success or failure was easily measured,
and perhaps most importantly, they did not depend on the successful
commercialization of technology and its adoption by the private sector.
Nevertheless, both projects provide a funding history for comparison against CO2
capture technology cost projections, and as examples of large government-led
projects initiated to achieve a national goal. The Manhattan project and Apollo
program are discussed briefly below.
The federal government’s efforts to promote energy technology development in
response to the energy crisis of the 1970s and early 1980s may be a richer analogy
to CO2 capture technology development than either the Manhattan project or Apollo
program. After the first oil crisis in 1973, and with the second oil crisis in the late

1970s, the national priority was to reduce dependence on foreign supplies of energy,


particularly crude oil, through a combination of new domestic supplies (e.g., oil
shale), energy efficiency technologies, and alternative energy supplies such as solar,
among others. The success of these efforts was to have been determined, in part, by
the commercialization of energy technologies and alternative energy supplies and


78 S. 3132 would also provide a $10 per metric ton credit for CO2 captured and used as a
tertiary injectant in an enhanced oil and natural gas recovery project.
79 For example, H.R. 2809, the New Apollo Energy Act of 2007; and H.R. 6385, the Apollo
Energy Independence Act of 2008.

their incorporation into American society over the long-term. Similarly, many
analysts see the development of CCS technology as a necessary step needed over the
next several decades or half-century to help alleviate human-induced climate change,
which is itself viewed as a global problem for at least the next century or longer. As
discussed more fully later, the outcome of the federal government’s efforts to
promote energy technologies in the 1970s and 1980s may be instructive to current
approaches to develop CCS technology.
The Manhattan Project and Apollo Program. The Manhattan project
took place from 1942 to 1946.80 In July 1945, a bomb was successfully tested in New
Mexico, and used against Japan at two locations in August 1945. In 1946, the
civilian Atomic Energy Commission was established to manage the nation’s future
atomic activities, and the Manhattan project officially ended. According to one
estimate, the Manhattan project cost $2.2 billion from 1942-1946 ($21 billion in
2007 dollars), greater than the original cost and time estimate of approximately $148
million for 1942 to 1944.81
The Apollo program encompassed 17 missions including six lunar landings that82
took place from FY1960 to FY1973. Although preliminary discussions regarding
the Apollo program began in 1960, Congress did not decide to fund it until 1961 after
the Soviets became the first country to send a human into space. The peak cost for
the Apollo program occurred in FY1966 when NASA’s total budget was $4.5 billion83
and its funding for Apollo was $3.0 billion. According to NASA, the total cost of
the Apollo program for FY1960-FY1973 was $19.4 billion ($95.7 billion in 2007


80 U.S. Department of Energy, Office of History and Heritage Resources, “The Manhattan
Project: An Interactive History,” webpage at [http://www.cfo.doe.gov/me70/
manhattan/1939-1942.htm]. F.G. Gosling, The Manhattan Project: Making the Atomic
Bomb, January 1999 edition (Oak Ridge, TN: Department of Energy).
81 Richard G. Hewlett and Oscar E. Anderson, Jr., A History of the United States Atomic
Energy Commission: The New World, 1939/1946 ,Volume I, (University Park, PA: The
Pennsylvania State University Press, 1962). Appendix 2 provides the annual Manhattan
project expenditures. These costs were adjusted to 2007 dollars using the price index for
gross domestic product (GDP), available from the Bureau of Economic Affairs, National
Income and Product Accounts Table webpage, Table 1.1.4., at
[http://www.bea.gov/ bea/dn/nipaweb/].
82 There is some difference of opinion regarding what activities comprise the Apollo
program, and thus when it begins and ends. Some include the first studies for Apollo,
Skylab, and the use of Apollo spacecraft in the Apollo-Soyuz Test Project. This analysis
is based on that provided by the National Aeronautics and Space Administration (NASA),
which includes the first studies of Apollo, but not Skylab or Soyuz activities, in a 2004 web
update by Richard Orloff of its publication entitled Apollo By The Numbers: A Statistical
Reference, NASA SP-2000-4029, at [http://history.nasa.gov/SP-4029/Apollo_00_
Welcome.htm].
83 The funding data is available at [http://history.nasa.gov/SP-4214/app2.html#1965]. It is
based on information in NASA, The Apollo Spacecraft - A Chronology, NASA Special
Publication-4009, at [http://www.hq.nasa.gov/office/pao/History/SP-4009/contents.htm].
This data is from Volume 4, Appendix 7 at [http://www.hq.nasa.gov/office/pao/History/
SP-4009/v4app7.htm] .

dollars).84 The first lunar landing took place in July 1969. The last occurred in
December 1972. Figure 10 shows the funding history for both the Manhattan project
and Apollo program.
DOE-Supported Energy Technology Development. The Department
of Energy has its origins in the Manhattan project,85 and became a cabinet-level
department in 1977,86 partly in response to the first oil crisis of 1973, caused in part
by the Arab oil embargo. Another oil crisis (the “second” oil crisis) took place from
1978-1981 as a result of political revolution in Iran. Funding for DOE energy R&D
rose in the 1970s in concert with high oil prices and resultant Carter Administration
priorities on conservation and development of alternative energy supplies. Crude oil
prices fell during the 1980s and the Reagan Administration eliminated many energy
R&D programs that began during the oil crisis years. Figure 10 shows the rise and
fall of funding for DOE energy technology programs from 1974 to 2008.
Comparisons to CO2 Capture R&D at DOE. Current DOE spending on
CCS technology development (discussed above) is far below levels of funding for the
Manhattan project and Apollo program and for the energy technology R&D programs
at their peak spending in the late 1970s and early 1980s. The development of CO2
capture technology is, of course, only one component of all federal spending on
global climate change mitigation. However, the total annual federal expenditures on
climate change, including basic research, are still far less than the Manhattan project
and Apollo program, although similar to DOE energy technology development
programs during their peak spending period.87 For comparison, the FY2008 budget
and FY2009 budget request for DOE’s energy technology R&D is approximately $3
billion per year. (See Figure 10.)
Even if spending on CO2 capture technology were increased dramatically to
Manhattan project or Apollo program levels, it is not clear whether the goal of
developing a commercially deployable technology would be realized. As mentioned
above, commercialization of technology and integration of technology into the
private market were not goals of either the Manhattan project or Apollo program.
For the Manhattan project, it did not matter what the cost was, in one sense, if a
consequence of failing to build a nuclear weapon was to lose the war. For CO2
capture, the primary goal is to develop a technology that would be widely deployed
and thus effective at removing a substantial amount of CO2 over the next half century


84 Richard Orloff, Apollo By The Numbers: A Statistical Reference, NASA SP-2000-4029,
2004 web update, at [http://history.nasa.gov/SP-4029/Apollo_00_Welcome.htm]. The
funding data is available at [http://history.nasa.gov/SP-4029/Apollo_18-16_Apollo_
Program_Budget_Appropriations.htm]. It is based on information in NASA, The Apollo
Spacecraft - A Chronology, NASA Special Publication-4009, at [http://www.hq.nasa.gov/
office/pao/History/ SP-4009/contents.htm] .
85 Department of Energy, “Origins & Evolution of the Department of Energy,” webpage at
[http://www.doe.gov/about/origi ns.htm] .
86 The Department of Energy Organization Act of 1977 (P.L. 95-91).
87 CRS estimates that budget authority for federal climate change programs was $5.44 billion
in FY2007. See CRS Report RL33817, Climate Change: Federal Funding and Tax
Incentives, by Jane A. Leggett.

or more, which necessarily requires its commercialization and widespread use
throughout the utility sector.
Figure 10. Annual Funding for the Manhattan Project, Apollo
Program, and DOE Energy Technology Programs


18
16
14
s
12llar
o
10f D
8ns o
io
6Bill
4
2
0Manhattan Apollo Program
Project (FY1960-FY1973)DOE Energy Technology Programs (FY1974-FY2008)
(FY1942-FY1946)
Current DollarsConstant 2007 Dollars
Source: Congressional Research Service. Manhattan Project data: Richard G. Hewlett and Oscar E.
Anderson, Jr., A History of the United States Atomic Energy Commission: The New World,
1939/1946,Volume I. Apollo program data: Richard Orloff, Apollo By The Numbers: A Statistical
Reference, NASA SP-2000-4029, 2004 web update. DOE data: CRS Report RS22858, Renewable
Energy R&D Funding History: A Comparison with Funding for Nuclear Energy, Fossil Energy, and
Energy Efficiency R&D, by Fred Sissine.
The Possibility of Failure: The Synthetic Fuels Corporation. A
careful study of one of the federal projects initiated in response to the energy crisis
of the 1970s and early 1980s — the Synthetic Fuels Corporation (SFC) — may
provide a valuable comparison to current thinking about the federal role in CO2
capture technology development:
The government’s attempt to develop a synthetic fuels industry in the late 1970s
and early 1980s is a case study of unsuccessful federal involvement in
technology development. In 1980, Congress established the Synthetic Fuels
Corporation (SFC), a quasi-independent corporation, to develop large-scale
projects in coal and shale liquefaction and gasification. Most of the projects
centered on basic and conceptual work that would contribute to demonstration
programs in later stages, although funds were expended on several prototype and
full-scale demonstration experiments. Formed in response to the 1970s energy
crisis, the SFC was intended to support projects that industry was unable to
support because of technical, environmental, or financial uncertainties. Federal
loans, loan guarantees, price guarantees, and other financial incentives totaling
$20 billion were authorized to spur industry action. Although SFC was designed
to continue operating until at least 1992, the collapse in energy prices,
environmental concerns, lack of support from the Reagan Administration, and

administrative problems ended the synthetic fuels program in 1986.88 [citations
from original text omitted]
One of the primary reasons commonly cited for the failure of the SFC was the
collapse of crude oil prices during the 1980s, although other factors contributed.89
Without a stable and predictable price for the commodity that the SFC was
attempting to produce in specific, mandated quantities, the structure of the SFC was
unable to cope with market changes:
The failure of the federal government’s effort to create a synthetic fuels industry
yields valuable lessons about the role of government in technology innovation.
The synthetic fuels program was established without sufficient flexibility to meet
changes in market conditions, such as the price of fuel. Public unwillingness to
endure the environmental costs of some of the large-scale projects was an added
complication. An emphasis on production targets was an added complication.
An emphasis on production targets reduced research and program flexibility.
Rapid turnover among SFC’s high-level officials slowed administrative actions.
The synthetic fuels program did demonstrate, however, that large-scale synthetic
energy projects could be build and operated within specified technical90
parameters. [citations from original text omitted]
It may be argued that the demise of DOE’s FutureGen program (as originally
conceived, see box above) was partly attributable to the project’s inflexibility in
dealing with changing market conditions, in this case the rise in materials and
construction costs and the doubling of FutureGen’s original price estimate. However,
the analogy between FutureGen and the SFC is limited. Although the SFC failed in
part because of collapsing oil prices (the costs of the SFC program could be
measured against the benefits of producing oil), for FutureGen the value of CO2
avoided (i.e. the benefit provided by the technology) was not even calculable for
comparison to the costs of building the plant, because there is no real global price for
CO2.
The market conditions that contributed to the downfall of the SFC, however,
could be very different from the market conditions that would arise following the
creation of a price for CO2 emissions. The stability and predictability of the price
signal would depend on the mechanism: carbon tax, allowance pricing, or auctions.
A mechanism that allowed for a long-term price signal for carbon would likely
benefit CO2 capture technology R&D programs.


88 The National Academy of Sciences, “The Government Role in Civilian Technology:
Building a New Alliance” (National Academy Press, Washington, DC, 1992), pp. 58-59.
89 For a variety of reasons, Canada’s experience with producing synthetic fuels, specifically
oil sands development, has differed from the U.S. experience. For more information, see
CRS Report RL34258, North American Oil Sands: History of Development, Prospects for
the Future, by Marc Humphries.
90 Ibid., p. 59.

Implications for Climate Change Legislation
Any comprehensive approach to reducing greenhouse gases substantially must
address the world’s dependency on coal for a quarter of its energy demand, including
almost half of its electricity demand. To maintain coal as a key component in the
world’s energy mix in a carbon-constrained future would require developing a
technology to capture and store its CO2 emissions. This situation suggests to some
that any greenhouse gas reduction program be delayed until such carbon capture
technology has been demonstrated. However, technological innovation and the
demands of a carbon control regime are interlinked; therefore, a technology policy
is no substitute for environmental policy and must be developed in concert with it.91
This linkage raises issues for legislators attempting to craft greenhouse gas
reduction legislation. For the demand-pull side of the equation, the issue revolves
around how to create the appropriate market for emerging carbon capture
technologies. Table 3 compares four different “price” signals across five different
criteria that influence their effectiveness in promoting technology:
!Magnitude: What size of price signal or stringency of the regulation
is imposed initially?
!Direction: What influences the direction (up or down) of the price
signal or stringency of the regulation over time?
!Timing: How quickly is the price or regulation imposed and
strengthened?
!Stability: How stable is the price or regulation over time?
!Duration: How long is the price or regulation imposed on affected
companies?
In general, the criteria suggest that regulation is the surest method of forcing the
development of technology — price is not necessarily a direct consideration in
decision-making. However, regulation is also the most limiting; technologies more
or less stringent than the standard would have a limited domestic market (although
foreign opportunities may be available), and development could be frozen if the
standards are not reviewed and strengthened periodically. In contrast, allowance
prices would provide the most equivocal signal, particularly if they are allocated free
to participants. Experience has shown allowance prices to be subject to volatility
with swings both up and down. The experience with the SO2 cap-and-trade program
suggests the incentive can be improved with “bonus” allowances; however, the
eligibility criteria used could be perceived as the government attempting to pick a
winner.


91 Carolyn Fischer, Climate Change Policy Choices and Technical Innovation, Resources
for the Future Climate Issue Brief #20 (June 2000), p. 9.

CRS-33
Table 3. Comparison of Various Demand-Pull Mechanisms
Mechanism M agnitude Di rection Timing Stability Duration
Depends on availableSubject to periodicDepends on frequencyVery stable — canDepends on the
technology orreview by regulatoryof regulatory reviewbecome stagnant ifregulatory procedures
performance standardauthorities based onand pace ofdiscourages furtherfor reassessment
technological progresstechnological progressinnovation or regulators
rarely review standard
ance PricesDepends on stringencyMarket-driven based onDepends onCan be quite volatileDepends on
of emissions cap andthe supply and demandenvironmental goal andenvironmental goal and
other provisions of thefor allowancesspecified schedule ofspecified schedule of
cap-and-trade programemission reductionsemission reductions
iki/CRS-RL34621
g/wDepends on level of taxGenerally specified byDepends on escalatorStableDepends on the
s.orlegislationprovisions in legislationspecified schedule of
leakthe carbon tax
://wikiance AuctionsSame dynamics asSame dynamics asSame dynamics asAllowance priceSame as for allowance
httpallowance prices; canallowance prices unlessallowance prices unlessvolatility can beprices, but includes the
be strengthened bylegislation specifies alegislation includes atempered by a reservedetails of the auctioning
100% auctioning ofreserve pricereserve price — then itprice and the specificsprocedures
allowances anddepends on anyof the auctioning
specifying a reserveescalator clauseprocess
price
Congressional Research Service.



In contrast, carbon taxes and allowance auctions (particularly 100% auctions
with a reserve price) provide strong market-based price signals. A carbon tax is the
most stable price signal, providing a clear and transparent signal of the value of any
method of greenhouse gas reductions. Substantial auctioning of allowances also
places a price on carbon emissions, a price that can be strengthened by incorporating
a reserve price into the structure of the auction.
However, each of these signals ultimately depends on the environmental goal
envisioned and the specifics of the control program: (1) the stringency of the
reduction requirement; (2) the timing of desired reductions; (3) the techniques
allowed to achieve compliance. The interplay of these factors informs the technology
community about the urgency of the need for carbon capture technology; the price
signal informs the community what cost-performance parameters are appropriate for
the emerging carbon market. The nature of that price signal (regulatory, market,
stability) informs the community of the confidence it can have that it is not wasting
capital on a “white elephant” or on a project that the market does not want or need.
The issues for technology-push mechanisms are broader, and include not only
the specifics of any reduction program and resulting price signal, but also
international considerations and the interplay between carbon capture technology,
storage, and the potential need for CO2 transport. Groups as diverse as The Pew
Center, the Electric Power Research Institute, DOE, and MIT have suggested
“roadmaps” and other schemes for preparing carbon capture technology for a pending
greenhouse gas reduction program.92 Generally, all of these approaches agree on the
need for demonstration-size (200-300 MW) projects to sort out technical
performance and cost effectiveness, and identify potential environmental and safety
concerns. The Energy Independence and Security Act of 2007 (P.L. 110-140)
reflected Congress’ desire for more integrated demonstration projects, and DOE’s
restructured approach to FutureGen purportedly provides incentives for integrating
capture technology on IGCC plants of 300 MW or greater.
Finally, it should be noted that the status quo for coal with respect to climate
change legislation isn’t necessarily the same as “business as usual.” The financial
markets and regulatory authorities appear to be hedging their bets on the outcomes
of any federal legislation with respect to greenhouse gas reductions, and are
becoming increasingly unwilling to accept the risk of a coal-fired power plant with
or without carbon capture capacity. This sort of limbo for coal-fired powerplants is
reinforced by the MIT study, which makes a strong case against subsidizing new
construction (allowed for IGCC under the EPAct2005) without carbon capture
because of the unattractive costs of retrofits:


92 For example, see Pew Center on Global Climate Change, Coal and Climate Change Facts,
(2008), available at [http://www.pewclimate.org/global-warming-basics/coalfacts.cfm]; Coal
Utilization Research Council and Electric Power Research Institute technology roadmap at
[http://www.coal.org/roadmap/]; DOE Energy, National Energy Technology Laboratory,
Carbon Sequestration Technology Roadmap and Program Plan 2007 available at
[http://www.netl.doe.gov/technologies/carbon_seq/refshel f/proj ect%20portfolio/

2007/2007Roadmap.pdf; and, MIT, The Future of Coal, pp. xi-xv.



Coal plants will not be cheap to retrofit for CO2 capture. Our analysis confirms
that the costs to retrofit an air-driven SCPC [supercritical pulverized coal] plant
for significant CO2 capture, say 90%, will be greater than the costs to retrofit an
IGCC plant. However, ... the modifications needed to retrofit an IGCC plant for
appreciable CCS are extensive and not a matter of simply adding a single simple
and inexpensive process step to an existing IGCC plant.... Consequently, IGCC
plants without CCS that receive assistance under the 2005 Energy Act will be
more costly to retrofit and less likely to do so.
The concept of a “capture ready” IGCC or pulverized coal plant is as yet
unproven and unlikely to be fruitful. The Energy Act envisions “capture ready”
to apply to gasification technology. [citation omitted] Retrofitting IGCC plants,
or for that matter pulverized coal plants, to incorporate CCS technology involves
substantial additional investments and a significant penalty to the efficiency and
net electricity output of the plant. As a result, we are unconvinced that such93
financial assistance to conventional IGCC plants without CCS is wise.
[emphasis in original]
As noted earlier, lack of a regulatory scheme (or carbon price) presents
numerous risks to any research and development effort designed to develop carbon
capture technology. Ultimately, it also presents a risk to the future of coal.


93 MIT, The Future of Coal, pp. 98-99.