**Testimony**

**Status of Advanced Coal Technologies and RD&D Needs to Enable
Readiness for Commercial Application**

**Committee on Energy and Natural Resources**

**U.S. Senate**

**Jeffrey N. Phillips, Ph.D.**

**Electric Power Research Institute**

**August 1, 2007**

**[Introduction]{.underline}**

I am Jeff Phillips, Program Manager for Advanced Coal Generation for the
Electric Power Research Institute (EPRI). EPRI is a non-profit,
collaborative R&D organization with principal offices in Palo Alto,
California, and Charlotte, North Carolina, where I work. EPRI
appreciates the opportunity to provide testimony to the Subcommittee on
the topic of carbon capture and sequestration.

**BACKGROUND**

Coal is the energy source for half of the electricity generated in the
United States. Even with the aggressive development and deployment of
alternative energy sources, numerous forecasts of energy use predict
that coal will continue to provide a major share of our electric power
generation throughout the 21st century. Coal is a stably priced,
affordable, domestic fuel that can be used in an environmentally
responsible manner. Criteria air pollutants from all types of new coal
power plants have been reduced by more than 90% compared with plants
built 40 years ago. With the development and deployment of CO~2~ capture
and storage (CCS) technologies, coal power becomes part of the solution
to satisfying both our energy needs and our global climate change
concerns. However, a sustained RD&D program at heightened levels of
investment and resolution of legal and regulatory unknowns for long-term
geologic CO~2~ storage will be required to achieve the promise of clean
coal technologies. EPRI sees crucial roles for both industry and
governments in aggressively pursuing collaborative RD&D over the next
20+ years to create a portfolio of commercially self-sustaining,
competitive advanced coal power generation and CO~2~ capture and storage
technologies.

The potential return on this investment is enormous. EPRI's "Electricity
Technology in a Carbon-Constrained Future" study suggests that it is
technically feasible to reduce U.S. electric sector CO~2~ emissions over
the next 25 years while meeting the increased demand for electricity,
with the largest single contribution to emissions reduction coming from
application of CCS technologies to new coal-based power plants coming
on-line after 2020. Economic analyses of scenarios to achieve the
study's emission reduction goals show that a 2030 U.S. energy mix
including advanced coal technologies with CCS results in electricity at
half the cost of a 2030 energy mix without coal with CCS. In the case
with advanced coal with CCS, the U.S. economy is \$1 trillion larger
than in the case without coal and CCS, with a much stronger
manufacturing sector. A previous EPRI economic study based on financial
market "options" principles produced a similar result, estimating the
added cost to U.S. consumers through 2050 of not having coal's
price-stabilizing influence on the electricity system at \$1.4 trillion
(present value basis).

The portfolio aspect of advanced coal and CCS technologies must be
emphasized because no single advanced coal technology (or any generating
technology) has clear-cut economic advantages across the range of U.S.
applications. The best strategy for meeting future electricity needs
while addressing climate change concerns and minimizing economic
disruption lies in developing *multiple* technologies from which power
producers (and their regulators) can choose the option best suited to
local conditions and preferences. When it comes to CCS technology, there
is no "silver bullet," but we can develop "silver buckshot."

Toward this end, four major technology efforts related to CO~2~
emissions reduction from coal-based power systems must be undertaken:

1.  Increased efficiency and reliability of integrated gasification
    combined cycle (IGCC) power plants

2.  Increased thermodynamic efficiency of pulverized-coal (PC) power
    plants

3.  Improved technologies for capture of CO~2~ from coal combustion- and
    gasification-based power plants

4.  Reliable, acceptable technologies for long-term storage of captured
    CO~2~

Identification of mechanisms to share RD&D financial and technical risks
and to address legal and regulatory uncertainties must take place as
well.

In short, a comprehensive recognition of all the factors needed to
hasten deployment of competitive, commercial advanced coal and CO~2~
capture and storage technologies---and implementation of realistic,
pragmatic plans to overcome barriers---is the key to meeting the
challenge to supply affordable, environmentally responsible energy in a
carbon-constrained world.

**ACCELERATING RD&D ON ADVANCED COAL TECHNOLOGIES WITH CO~2~ CAPTURE AND
STORAGE---INVESTMENT AND TIME REQUIREMENTS**

A typical path to develop a technology to commercial maturity consists
of moving from the conceptual stage to laboratory testing, to small
pilot-scale tests, to larger-scale tests, to multiple full-scale
demonstrations, and finally to deployment in full-scale commercial
operations. For capital-intensive technologies such as advanced coal
power systems, each stage can take years or even decades to complete and
each sequential stage tends to entail increasing levels of investment.
As depicted in Figure 1, several key advanced coal power and CCS
technologies are now in (or approaching) an "adolescent" stage of
development. This is time of particular vulnerability in the technology
development cycle, as it is common for the expected costs of full-scale
application to be higher than earlier estimates when less was known
about scale-up and application challenges. Public agency and private
funders can become disillusioned with a technology development effort at
this point, but as long as fundamental technology performance results
continue to meet expectations, and a path to cost reduction is clear,
perseverance by project sponsors in maintaining momentum is crucial.
Unexpectedly high costs at the mid-stage of technology development have
historically come down following market introduction, experience gained
from "learning-by-doing," realization of economies of scale in design
and production as order volumes rise, and removal of contingencies
covering uncertainties and first-of-a-kind costs. An International
Energy Agency study led by Carnegie Mellon University observed this
pattern in the cost over time of power plant environmental controls and
has predicted a similar reduction in the cost of power plant CO~2~
capture technologies as the cumulative installed capacity grows.[^1]
EPRI concurs with their expectations of experience-based cost reductions
and believes that RD&D on specifically identified technology refinements
can lead to greater cost reductions sooner in the deployment phase.

![](media/image1.wmf){width="5.999305555555556in" height="3.26875in"}

Figure 1 -- Model of the development status of major advanced coal and
CO~2~ capture and storage technologies (temperatures shown for
pulverized coal technologies are turbine inlet steam temperatures)

Of the coal-based power generating and carbon sequestration technologies
shown in Figure 1, only supercritical pulverized coal (SCPC) technology
has reached commercial maturity. It is crucial that other technologies
in the portfolio---namely ultra-supercritical (USC) PC, integrated
gasification combined cycle (IGCC), CO~2~ capture (pre-combustion,
post-combustion, and oxy-combustion), and CO~2~ storage---be given
sufficient support to reach the stage of declining constant dollar costs
*before* society's requirements for greenhouse gas reductions compel
their application in large numbers.

Figure 2 depicts the major activities in each of the four technology
areas that must take place to achieve a set of robust solutions to
reduce CO~2~ emissions from coal power systems. This framework should be
considered as a whole rather than as a set of discrete tasks. Although
individual goals related to efficiency, CO~2~ capture, and CO~2~ storage
present major challenges, significant challenges also arise from complex
interactions that occur when CO~2~ capture processes are integrated with
gasification- and combustion-based power plant processes.

![](media/image2.wmf){width="5.992361111111111in"
height="3.9055555555555554in"}

Figure 2 -- Timing of advanced coal power system and CO~2~ capture and
storage RD&D activities and milestones

**REDUCING CO~2~ EMISSIONS THROUGH IMPROVED COAL POWER PLANT
EFFICIENCY**

Improved thermodynamic efficiency reduces CO~2~ emissions by reducing
the amount of fuel required to generate a given amount of electricity. A
two-percentage point gain in efficiency provides a reduction in fuel
consumption of roughly 5% and a similar reduction in CO~2~ output.
Depending on the technology used, improved efficiency can also provide
similar reductions in criteria air pollutants, hazardous air pollutants,
and water consumption.

A "typical" 500 MW (net) coal plant emits about 3 million metric tons of
CO~2~ per year. The annual power output and emissions of the current
U.S. coal fleet are roughly equivalent to 600 such plants. The
contributions attributable to individual plants vary considerably with
differences in plant steam cycle, coal type, capacity factor, and
operating regimes. For a given fuel, a new supercritical PC unit built
today might produce 5--10% less CO~2~ per megawatt-hour (MWh) than the
existing fleet average for that coal type.

With an aggressive RD&D program on efficiency improvement, new
ultra-supercritical (USC PC) plants could reduce CO~2~ emissions per MWh
by up to 25% relative to the existing fleet average. Significant
efficiency gains are also possible for IGCC plants by employing advanced
gas turbines and through more energy-efficient oxygen plants and
synthesis (fuel) gas cleanup technologies.

EPRI and the Coal Utilization Research Council (CURC), in consultation
with DOE, have identified a challenging but achievable set of milestones
for improvements in the efficiency, cost, and emissions of PC and
coal-based IGCC plants. The EPRI-CURC Roadmap projects an overall
improvement in the thermal efficiency of state-of-the art generating
technology from 38--41% in 2010 to 44--49% by 2025 (on a higher heating
value \[HHV\] basis; see Table 1). The ranges in the numbers are not
simply a reflection of uncertainty, but rather they underscore an
important point about differences among U.S. coals. The natural
variations in moisture and ash content and combustion characteristics
between coals have a significant impact on efficiency. The best
efficiencies are possible with bituminous coals, a mid-range value is
applicable to subbituminous coals, and the low end of the range is for
lignite. Thus, an equally advanced plant might have a two percentage
point lower efficiency on subbituminous coal, such as Wyoming and
Montana's Powder River basin, relative to Pennsylvania and West
Virginia's Pittsburgh #8. The efficiency for the same plant using
lignite from North Dakota or Texas might be two percentage points even
lower than that for subbituminous coal. Any government incentive program
with an efficiency-based qualification criterion should recognize these
inherent differences in the attainable efficiencies for plants using
different ranks of coal.

As Table 1 indicates, technology-based efficiency gains over time will
be offset by the energy required for CO~2~ capture. Nevertheless,
aggressive pursuit of the EPRI-CURC RD&D program offers the prospect of
coal plants *with* CO~2~ capture in 2025 that have net efficiencies
meeting or exceeding current-day power plants without CO~2~ capture.

Table 1 -- Efficiency Milestones in EPRI-CURC Roadmap

  ------------------------- ------------ ------------ ------------ ------------
                            2010         2015         2020         2025

  PC & IGCC Systems\        38--41% HHV  39--43% HHV  42--46% HHV  44--49% HHV
  *([Without]{.underline}                                          
  CO~2~ Capture)*                                                  

  PC & IGCC Systems\        31--32% HHV  31--35% HHV  33--39% HHV  39--46% HHV
  *([With]{.underline}                                             
  CO~2~ Capture\*)*                                                
  ------------------------- ------------ ------------ ------------ ------------

\**Efficiency values reflect impact of 90% CO~2~ capture, but not
compression or transportation.*

**New Plant Efficiency Improvements--IGCC**

Although IGCC is not yet a mature technology for coal-fired power
plants, chemical plants around the world have accumulated a 100-year
experience base operating coal-based gasification units and related gas
cleanup processes. The most advanced of these units are similar to the
front end of a modern IGCC facility. Similarly, several decades of
experience firing natural gas and petroleum distillate have established
a high level of maturity for the basic combined cycle generating
technology. Nonetheless, ongoing RD&D continues to provide significant
advances in the base technologies, as well as in the suite of
technologies used to integrate them into an IGCC generating facility.

Efficiency gains in currently proposed IGCC plants will come from the
use of new "FB-class" gas turbines, which will provide an overall plant
efficiency gain of about 0.6 percentage point (relative to IGCC units
with FA-class models, such as Tampa Electric's Polk Power Station). This
corresponds to a decrease in CO~2~ emissions rate of about 1.5%.

Figure 3 depicts the anticipated timeframe for further developments
identified by EPRI's *CoalFleet for Tomorrow*® program that promise a
succession of significant improvements in IGCC unit efficiency. Key
technology advances under development include: larger capacity gasifiers
(often via higher operating pressures that boost throughput without a
commensurate increase in vessel size); integration of new gasifiers with
larger, more efficient G- and H-class gas turbines; use of ion transport
membrane (ITM) and/or other more energy-efficient technologies in oxygen
plants; warm synthesis gas cleanup and membrane separation processes for
CO~2~ capture that reduce energy losses in these areas; recycle of
liquefied CO~2~ to replace water in gasifier feed slurry (reducing heat
loss to water evaporation); and hybrid combined cycles using fuel cells
to achieve generating efficiencies exceeding those of conventional
combined cycle technology. Improvements in gasifier reliability and in
control systems also contribute to improved annual average efficiency by
minimizing the number and duration of startups and shutdowns.

![](media/image3.wmf){width="5.997916666666667in"
height="4.199305555555555in"}

Figure 3 -- RD&D path for capital cost reduction (falling arrows) and
efficiency improvement (rising arrows) for IGCC power plants with 90%
CO~2~ capture\
\* *Pittsburgh #8 coal; slurry-fed gasifier designed for 90% unit
availability and 90% pre-combustion CO~2~ capture; cost normalization
using Chemical Engineering Plant Cost Index or equivalent*

**Larger, Higher Firing Temperature Gas Turbines**. For plants coming
on-line around 2015, the larger size G-class gas turbines, which operate
at higher firing temperatures (relative to F-class machines) can improve
efficiency by 1 to 2 percentage points while also decreasing capital
cost per kW capacity. The H-class gas turbines, coming on-line in the
same timeframe, will provide a further increase in efficiency and
capacity.

**Ion Transport Membrane--Based Oxygen Plants.** Most gasifiers used in
IGCC plants require a large quantity of high-pressure, high purity
oxygen, which is typically generated on-site with an expensive and
energy-intensive cryogenic process. The ITM process allows the oxygen in
high-temperature air to pass through a membrane while preventing passage
of non-oxygen atoms. According to developers, an ITM-based oxygen plant
consumes 35--60% less power and costs 35% less than a cryogenic plant.
EPRI is performing a due diligence assessment of this technology in
advance of potential participation in technology scale-up efforts.

**Supercritical Heat Recovery Steam Generators.** In IGCC plants, hot
exhaust gas exiting the gas turbine is ducted into a heat exchanger
known as a heat recovery steam generator (HRSG) to transfer energy into
water-filled tubes producing steam to drive a steam turbine. This
combination of a gas turbine and steam turbine power cycles produces
electricity more efficiently than either a gas turbine or steam turbine
alone. As with conventional steam power plants, the efficiency of the
steam cycle in a combined cycle plant increases when turbine inlet steam
temperature and pressure are increased. The higher exhaust temperatures
of G- and H-class gas turbines offer the potential for adoption of
more-efficient supercritical steam cycles. Materials for use in a
supercritical HRSG are generally established.

**Synthesis Gas Cleaning at Higher Temperatures.** The acid gas recovery
(AGR) processes currently used to remove sulfur compounds from synthesis
gas require that the gas and solvent be cooled to about 100ºF, thereby
causing a loss in efficiency. Further costs and efficiency loss are
inherent in the process equipment and auxiliary steam required to
recover the sulfur compounds from the solvent and convert them to
useable products. Several DOE-sponsored RD&D efforts aim to reduce the
energy losses and costs imposed by this recovery process. These
technologies (described below could be ready---with adequate RD&D
support---by 2020:

-   The Selective Catalytic Oxidation of Hydrogen Sulfide process
    eliminates the Claus and Tail Gas Treating units along with the
    traditional solvent-based AGR contactor, regenerator, and heat
    exchangers by directly converting hydrogen sulfide (H~2~S) to
    elemental sulfur. The process allows for a higher operating
    temperature of approximately 300ºF, which eliminates part of the
    low-temperature gas cooling train. The anticipated benefit is a net
    capital cost reduction of about \$60/kW along with an efficiency
    gain of about 0.8 percentage point.

-   The RTI/Eastman High Temperature Desulfurization System uses a
    regenerable dry zinc oxide sorbent in a dual loop transport reactor
    system to convert H~2~S and COS to H~2~O, CO~2~, and SO~2~. Tests at
    Eastman Chemical Company have shown sulfur species removal rates
    above 99.9%, with 10 ppm output versus 8000+ ppm input sulfur, using
    operating temperatures of 800--1000ºF. This process is also being
    tested for its ability to provide a high-pressure CO~2~ by-product.
    The anticipated benefit for IGCC, compared with using a standard
    oil-industry process for sulfur removal, is a net capital cost
    reduction of \$60--90 per kW, a thermal efficiency gain of 2--4% for
    the gasification process, and a slight reduction in operating cost.
    Tests are also under way for a multi-contaminant removal processes
    that can be integrated with the transport desulfurization system at
    temperatures above 480°F.

**Liquid CO~2~-Coal Slurrying for Gasification of Low-Rank Coals.**
Future IGCC plants may recycle some of the recovered liquid CO~2~ to
replace water as the slurrying medium for the coal feed. This is
expected to increase gasification efficiency for all coals, but
particularly for low-rank coals (i.e., subbituminous and lignite), which
have high inherent moisture content. The liquid CO~2~ has a lower heat
of vaporization than water and is able to carry more coal per unit mass
of fluid. The liquid CO~2~-coal slurry will flash almost immediately
upon entering the gasifier, providing good dispersion of the coal
particles and potentially yielding dry-fed gasifier performance with
slurry-fed simplicity.

Slurry-fed gasification technologies have a cost advantage over
conventional dry-fed fuel handling systems, but they suffer a large
performance penalty when used with coals containing a large fraction of
water and ash. EPRI identified CO~2~ coal slurrying as an innovative
fuel preparation concept 20 years ago, when IGCC technology was in its
infancy. At that time, however, the cost of producing liquid CO~2~ was
too high to justify the improved thermodynamic performance.

To date, CO~2~-coal slurrying has only been demonstrated at pilot scale
and has yet to be assessed in feeding coal to a gasifier, so the
estimated performance benefits remain to be confirmed. The concept
warrants consideration for future IGCC plants that capture and compress
CO~2~ for storage, as this will substantially reduce the incremental
cost of producing a liquid CO~2~ stream. It will first be necessary,
however, to update previous studies to quantify the potential benefit of
liquid CO~2~ slurries with IGCC plants designed for CO~2~ capture. If
the predicted benefit is economically advantageous, a significant amount
of scale-up and demonstration work would be required to qualify this
technology for commercial use.

**Fuel Cells and IGCC.** No matter how far gasification and turbine
technology advance, IGCC power plant efficiency will never progress
beyond the inherent thermodynamic limits of the gas turbine and steam
turbine power cycles (along with lower limits imposed by available
materials technology). Several IGCC--fuel cell hybrid power plant
concepts (IGFC) aim to provide a path to coal-based power generation
with net efficiencies that exceed those of conventional combined cycle
generation.

Along with its high thermal efficiency, the fuel cell hybrid cycle
reduces the energy consumption for CO~2~ capture. The anode section of
the fuel cell produces a stream that is highly concentrated in CO~2~.
After removal of water, this stream can be compressed for sequestration.
The concentrated CO~2~ stream is produced without having to include a
water-gas shift reactor in the process (see Figure 4). This further
improves the thermal efficiency and decreases capital cost. IGFC power
systems are a long-term solution, however, unlikely to see full-scale
demonstration until about 2030.

![](media/image4.wmf){width="4.250694444444444in"
height="2.6666666666666665in"}

*Source: U.S. Department of Energy;
http://www.netl.doe.gov/technologies/coalpower/fuelcells/hybrids.html*

Figure 4 -- Schematic of fuel cell-turbine hybrid

**Role of FutureGen.** The FutureGen Industrial Alliance and DOE are
building a first-of-its-kind, near-zero emissions coal-fed IGCC power
plant integrated with CCS. The commencement of full-scale operations is
targeted for 2013. The project aims to sequester CO~2~ in a
representative geologic formation at a rate of at least one million
metric tons per year.

The FutureGen design will address scaling and integration issues for
coal-based, zero emissions IGCC plants. In its role as a "living
laboratory," FutureGen is designed to validate additional advanced
technologies that offer the promise of clean environmental performance
at a reduced cost and increased reliability. FutureGen will have the
flexibility to conduct full-scale and slipstream tests of such scalable
advanced technologies such as:

-   Membrane processes to replace cryogenic separation for oxygen
    production

-   An advanced transport reactor sidestream with 30% of the capacity of
    the main gasifier

-   Advanced membrane and solvent processes for H~2~ and CO~2~
    separation

-   A raw gas shift reactor that reduces the upstream clean-up
    requirements

-   Ultra low-NO~X~ combustors that can be used with high-hydrogen
    synthesis gas

-   A fuel cell hybrid combined cycle pilot

-   Challenging first-of-a-kind system integration

-   Smart dynamic plant controls including a CO~2~ management system

Figure 5 provides a schematic of the "backbone" and "research platform"
process trains envisioned for the FutureGen plant.

![](media/image5.png){width="5.999305555555556in" height="3.4375in"}

Figure 5 -- FutureGen technology platforms

Figure 6 summarizes EPRI's recommended major RD&D activities for
improving the efficiency and cost of IGCC technologies with CO~2~
capture.

![](media/image6.wmf){width="5.9944444444444445in" height="2.55625in"}

Figure 6 -- Timing of advanced IGCC and CO~2~ capture integration RD&D
activities and milestones

**New Plant Efficiency Improvements -- Advanced Pulverized Coal**

Pulverized-coal power plants have long been a primary source of reliable
and affordable power in the United States and around the world. The
advanced level of maturity of the technology, along with basic
thermodynamic principles, suggests that significant efficiency gains can
most readily be realized by increasing the operating temperatures and
pressures of the steam cycle. Such increases, in turn, can be achieved
only if there is adequate development of suitable materials and new
boiler and steam turbine designs that allow use of higher steam
temperatures and pressures.

Current state-of-the-art plants use supercritical main steam conditions
(i.e., temperature and pressure above the "critical point" where the
liquid and vapor phases of water are indistinguishable). SCPC plants
typically have main steam conditions up to 1100°F. The term
"ultra-supercritical" is used to describe plants with main steam
temperatures in excess of 1100°F and potentially as high as 1400°F.

Achieving higher steam temperatures and higher efficiency will require
the development of new corrosion-resistant, high-temperature nickel
alloys for use in the boiler and steam turbine. In the United States,
these challenges are being address by the Ultra-Supercritical Materials
Consortium, a DOE R&D program involving Energy Industries of Ohio, EPRI,
the Ohio Coal Development Office, and numerous equipment suppliers. EPRI
provides technical management for the consortium.

It is expected that a USC PC plant operating at about 1300°F will be
built during the next seven to ten years, following the demonstration
and commercial availability of advanced materials from these programs.
This plant would achieve an efficiency of about 45% (HHV) on bituminous
coal, compared with 39% for a current state-of-the-art plant, and would
reduce CO~2~ production per net MWh by about 15%.

Ultimately, nickel-base alloys are expected to enable stream
temperatures in the neighborhood of 1400°F and generating efficiencies
up to 47% HHV with bituminous coal. This approximately 10 percentage
point improvement over the efficiency of a new subcritical
pulverized-coal plant would equate to a decrease of about 25% in CO~2~
and other emissions per MWh.

Figure 7 illustrates a timeline developed by EPRI's *CoalFleet for
Tomorrow*® program to establish efficiency improvement and cost
reduction goals for USC PC plants with CO~2~ capture.

![](media/image7.wmf){width="5.991666666666666in"
height="3.8333333333333335in"}

Figure 7 -- RD&D path for capital cost reduction (falling arrows) and
efficiency improvement (rising arrows) for PC power plants with 90%
CO~2~ capture*\
\* Pittsburgh #8 coal; designed for 90% unit availability and 90%
post-combustion CO~2~ capture; cost normalization using Chemical
Engineering Plant Cost Index or equivalent*

**UltraGen USC PC Commercial Projects.** EPRI and industry
representatives have proposed a framework to support commercial projects
that demonstrate advanced PC technologies. The vision entails
construction of two commercially operated USC PC power plants that
combine state-of-the-art pollution controls, ultra-supercritical steam
power cycles, and innovative flue gas scrubbing technologies to capture
CO~2~.

The UltraGen I plant will use the best of today's proven ferritic
steels, while UltraGen II will be the first plant in the United States
to feature new, nickel-based alloys that are able to withstand the
higher temperatures involved.

UltraGen I will feature an approximately quarter-scale CO~2~ capture
system demonstration using the best established technology. This system
will be about 15 times the size of the largest system operating on a
coal-fired boiler today. UltraGen II will double the size of the CO~2~
capture system, and may demonstrate a new class of chemical solvent if
one of the emerging low-energy processes has reached a sufficient stage
of development. Both plants will demonstrate ultra-low emissions. Both
UltraGen demonstration plants will dry and compress the captured CO~2~
for long-term geologic storage and/or use in enhanced oil or gas
recovery operations. Figure 8 depicts the proposed key features of
UltraGen I and II.

![](media/image8.wmf){width="5.991666666666666in"
height="2.7569444444444446in"}

![](media/image9.wmf){width="5.99375in" height="3.303472222222222in"}

Figure 8 -- Key parameters for UltraGen I (upper schematic) and UltraGen
II (lower schematic)

To provide a platform for testing and developing emerging PC
technologies, the program will allow for technology trials at existing
sites as well as at the sites of new projects. It is expected that the
UltraGen projects will be commercially operated units dispatching
electricity to the grid. The differential cost to the host utility for
demonstrating these improved features are envisioned to be offset by tax
credits and funds raised by an industry-led consortia formed through
EPRI.

The UltraGen projects represent the type of "giant step" collaborative
efforts that need to be taken to advance PC technology to the next phase
of evolution and assure competitiveness in a carbon-constrained world.
Because of the time and expense for each "design and build" iteration
for coal power plants (3 to 5 years not counting the permitting process
and \~\$2 billion), there is no room for hesitation in terms of
commitment to advanced technology validation and demonstration projects.

The UltraGen projects will resolve critical barriers to the deployment
of USC PC technology by providing a shared-risk vehicle for testing and
validating high-temperature materials, components, and designs in plants
also providing superior environmental performance.

Figure 9 summarizes EPRI's recommended major RD&D activities for
improving the efficiency and cost of USC PC technologies with CO~2~
capture.

![](media/image10.wmf){width="5.9944444444444445in"
height="2.6743055555555557in"}

Figure 9 -- Timing of advanced PC and CO~2~ capture integration RD&D
activities and milestones

**Efficiency Gains for the Existing PC Fleet.** Many subcritical units
in the existing U.S. fleet will continue to operate for years to come.
Replacing these units en masse would be economically prohibitive. Their
flexibility for load following and provision of support services to
ensure grid stability makes them highly valuable. With equipment
upgrades, many of these units can realize modest efficiency gains,
which, when accumulated across the existing generating fleet could make
a sizeable difference.

These upgrades depend on the equipment configuration and operating
parameters of a particular plant and may include:

-   turbine blading and steam path upgrades

-   turbine control valve upgrades for more efficient regulation of
    steam

-   cooling tower and condenser upgrades to reduce circulating water
    temperature, steam turbine exhaust backpressure, and auxiliary power
    consumption

-   cooling tower heat transfer media upgrades

-   condenser optimization to maximize heat transfer and minimize
    condenser temperature

-   condenser air leakage prevention/detection

-   variable speed drive technology for pump and fan motors to reduce
    power consumption

-   air heater upgrades to increase heat recovery and reduce leakage

-   advanced control systems incorporating neural nets to optimize
    temperature, pressure, and flow rates of fuel, air, flue gas, steam,
    and water

-   optimization of water blowdown and blowdown energy recovery

-   optimization of attemperator design, control, and operating
    scenarios

-   sootblower optimization via "intelligent" sootblower system use

**IMPROVING CO~2~ CAPTURE TECHNOLOGIES**

The laws of physics and chemistry impose inherent limits on the extent
of CO~2~ reductions that can be achieved through efficiency gains alone.
Further reductions in CO~2~ emissions will require pre-combustion or
post-combustion CO~2~ capture technologies and the storage of separated
CO~2~ in locations where it can be kept away from the atmosphere for
centuries or longer.

Albeit at considerable cost, CO~2~ capture technologies can be
integrated into all coal-based power plant technologies. For existing
plants, specific plant design features, space limitations, and various
economic and regulatory considerations will determine whether
retrofit-for-capture is feasible. For both new plants and retrofits,
there is a tremendous need (and opportunity) to reduce the energy
required to remove CO~2~ from fuel gas or flue gas. Figure 10 shows a
selection of the key technology development and test programs needed to
achieve a goal of commercial CO~2~ capture technologies for advanced
coal combustion- and gasification-based power plants at a progressively
shrinking constant-dollar levelized cost-of-electricity premium.
Specifically, the target is premium of about \$6/MWh in 2025 (relative
to plants at that time without capture) compared with an estimated 2010
cost premium of perhaps \$40/MWh (not counting the cost of
transportation and storage). Such a goal poses substantial engineering
challenges and will require major investments in RD&D to reduce the
currently large net power reductions and efficiency (operating cost)
penalties associated with CO~2~ capture technologies. Achieving this
goal will allow power producers to meet the public demand for stable
electricity prices while reducing CO~2~ emissions to address climate
change concerns.

![](media/image11.wmf){width="5.9944444444444445in"
height="1.9506944444444445in"}

Figure 10 -- Timing of CO~2~ capture technology development RD&D
activities and milestones

**Pre-Combustion CO~2~ Capture (IGCC)**

IGCC technology allows for CO~2~ capture to take place via an added fuel
gas processing step at elevated pressure, rather than at the atmospheric
pressure of post-combustion flue gas, permitting capital savings through
smaller equipment sizes as well as lower operating costs.

Currently available technologies for such pre-combustion CO~2~ removal
use a chemical and/or physical solvent that selectively absorbs CO~2~
and other "acid gases," such as hydrogen sulfide. Application of this
technology requires that the CO in synthesis gas (the principal
component) first be "shifted" to CO~2~ and hydrogen via a catalytic
reaction with water. The CO~2~ in the shifted synthesis gas is then
removed via contact with the solvent in an absorber column, leaving a
hydrogen-rich synthesis gas for combustion in the gas turbine. The CO~2~
is released from the solvent in a regeneration process that typically
reduces pressure and/or increases temperature.

Chemical plants currently employ such a process commercially using
methyl diethanolamine (MDEA) as a chemical solvent or the Selexol and
Rectisol processes, which rely on physical solvents. Physical solvents
are generally preferred when extremely high (\>99.8%) sulfur species
removal is required. Although the required scale-up for IGCC power plant
applications is less than that needed for scale-up of post-combustion
CO~2~ capture processes for PC plants, considerable engineering
challenges remain and work on optimal integration with IGCC cycle
processes has just begun.

The impact of current pre-combustion CO~2~ removal processes on IGCC
plant thermal efficiency and capital cost is significant. In particular,
the water-gas shift reaction reduces the heating value of synthesis gas
fed to the gas turbine. Because the gasifier outlet ratios of CO to
methane to H~2~ are different for each gasifier technology, the relative
impact of the water-gas shift reactor process also varies. In general,
however, it can be on the order of a 10% fuel energy reduction. Heat
regeneration of solvents further reduces the steam available for power
generation. Other solvents, which are depressurized to release captured
CO~2~, must be re-pressurized for reuse. Cooling water consumption is
increased for solvents needing cooling after regeneration and for
pre-cooling and interstage cooling during compression of separated CO~2~
to a supercritical state for transportation and storage. Heat
integration with other IGCC cycle processes to minimize these energy
impacts is complex and is currently the subject of considerable RD&D by
EPRI and others.

**Membrane CO~2~ Separation.** Technology for separating CO~2~ from
shifted synthesis gas (or flue gas from PC plants) offers the promise of
lower auxiliary power consumption but is currently only at the
laboratory stage of development. Several organizations are pursuing
different approaches to membrane-based applications. In general,
however, CO~2~ recovery on the low-pressure side of a selective membrane
can take place at a higher pressure than is now possible with solvent
processes, reducing the subsequent power demand for compressing CO~2~ to
a supercritical state. Membrane-based processes can also eliminate steam
and power consumption for regenerating and pumping solvent,
respectively, but they require power to create the pressure difference
between the source gas and CO~2~-rich sides. If membrane technology can
be developed at scale to meet performance goals, it could enable up to a
50% reduction in capital cost and auxiliary power requirements relative
to current CO~2~ capture and compression technology.

**Post-Combustion CO~2~ Capture (PC and CFB Plants)**

The post-combustion CO~2~ capture processes envisioned for power plant
boilers draw upon commercial experience with amine solvent separation at
much smaller scale in the food and beverage and chemical industries and
upon three applications of CO~2~ capture from a slipstream of exhaust
gas from circulating fluidized-bed (CFB) units.

These processes contact flue gas with an amine solvent in an absorber
column (much like a wet SO~2~ scrubber) where the CO~2~ chemically
reacts with the solvent. The CO~2~-rich liquid mixture then passes to a
stripper column where it is heated to change the chemical equilibrium
point, releasing the CO~2~. The "regenerated" solvent is then
recirculated back to the absorber column, while the released CO~2~ may
be further processed before compression to a supercritical state for
efficient transportation to a storage location.

After drying, the CO~2~ released from the regenerator is relatively
pure. However, success CO~2~ removal requires very low levels of SO~2~
and NO~2~ entering the CO~2~ absorber, as these species also react with
the solvent. Thus, high-efficiency SO~2~ and NO~X~ control systems are
essential to minimizing solvent consumption costs for post-combustion
CO~2~ capture. Extensive RD&D is in progress to improve the solvent and
system designs for power boiler applications and to develop better
solvents with greater absorption capacity, less energy demand for
regeneration, and greater ability to accommodate flue gas contaminants.

At present, monoethanolamine (MEA) is the "default" solvent for
post-combustion CO~2~ capture studies and small-scale field
applications. Processes based on improved amines, such as Fluor's
Econamine FG Plus and Mitsubishi Heavy Industries' KS-1, are under
development. The potential for improving amine-based processes appears
significant. For example, a recent study based on KS-1 suggests that its
impact on net power output for a supercritical PC unit would be 19% and
its impact on the levelized cost-of-electricity would be 44%, whereas
earlier studies based on suboptimal MEA applications yielded output
penalties approaching 30% and cost-of-electricity penalties of up to
65%.

Accordingly, amine-based engineered solvents are the subject of numerous
ongoing efforts to improve performance in power boiler post-combustion
capture applications. Along with modifications to the chemical
properties of the sorbents, these efforts are addressing the physical
structure of the absorber and regenerator equipment, examining membrane
contactors and other modifications to improve gas-liquid contact and/or
heat transfer, and optimizing thermal integration with steam turbine and
balance-of-plant systems. Although the challenge is daunting, the payoff
is potentially massive, as these solutions may be applicable not only to
new plants, but to retrofits where sufficient plot space is available at
the back end of the plant.

Finally, as discussed earlier, deploying USC PC technology to increase
efficiency and lower uncontrolled CO~2~ per MWh can further reduce the
cost impact of post-combustion CO~2~ capture.

**Chilled Ammonia Process.** Post-combustion CO~2~ capture using a
chilled ammonia-based solvent offers the promise of dramatically
reducing parasitic power losses relative to MEA. In the process
currently under development and testing by Alstom and EPRI,
respectively, CO~2~ is absorbed in a solution of ammonium carbonate, at
low temperature and atmospheric pressure, and combines with the NaCO~3~
to form ammonium bicarbonate.

Compared with amines, ammonium carbonate has over twice the CO~2~
absorption capacity and requires less than half the heat to regenerate.
Further, regeneration can be performed under higher pressure than
amines, so the released CO~2~ is already partially pressurized.
Therefore, less energy is subsequently required for compression to a
supercritical state for transportation to an injection location.
Developers have estimated that the parasitic power loss from a
full-scale supercritical PC plant using chilled ammonia CO~2~ capture
could be as low as 10%, with an associated cost-of-electricity penalty
of just 25%. Following successful experiments at 0.25 MW~e~ scale,
Alstom and a consortium of EPRI members are constructing a 1.7 MW~e~
pilot unit to test the chilled ammonia process with a flue gas
slipstream at We Energies' Pleasant Prairie Power Plant.

Other "multi-pollutant" control system developers are also exploring
ammonia-based processes for CO~2~ removal.

**Oxy-Fuel Combustion Boilers**

Fuel combustion in a blend of oxygen and recycled flue gas rather than
in air (known as oxy-fuel combustion or oxy-combustion) is gaining
interest as a viable CO~2~ capture alternative for PC and CFB plants.
The process is applicable to virtually all fossil-fueled boiler types
and is a candidate for retrofits as well as new power plants.

Firing coal only with high-purity oxygen would result in too high of a
flame temperature, which would increase slagging, fouling, and corrosion
problems, so the oxygen is diluted by mixing it with a slipstream of
recycled flue gas. As a result, the flue gas downstream of the recycle
slipstream take-off consists primarily of CO~2~ and water vapor
(although it also contains small amounts of nitrogen, oxygen, and
criteria pollutants). After the water is condensed, the CO~2~-rich gas
is compressed and purified to remove contaminants and prepare the CO~2~
for transportation and storage.

Oxy-combustion boilers have been studied in laboratory-scale and small
pilot units of up to 3 MW~t~. Two larger pilot units, at \~10 MW~e~, are
now under construction by Babcock & Wilcox (B&W) and Vattenfall. An
Australian-Japanese project team is pursuing a 30 MW~e~ repowering
project in Australia. These larger tests will allow verification of
mathematical models and provide engineering data useful for designing
pre-commercial systems. The first such pre-commercial unit could be
built at SaskPower's Shand station near Estevan, Saskatchewan.
SaskPower, B&W Canada, and Air Liquide have been jointly developing an
oxy-combustion SCPC design, and a decision on whether to proceed to
construction is expected by late 2007, with a target in-service date of
2011--12.

**CO~2~ TRANSPORT AND GEOLOGIC STORAGE**

Application of CO~2~ capture technologies implies that there will be
secure and economical storage or beneficial uses that can assure CO~2~
will be kept out of the atmosphere. The most developed approach for
large-scale CO~2~ storage is injection into deep, well-sealed geological
formations, including depleted or partially depleted oil and gas
reservoirs and similar geologically sealed "saline formations" (porous
rocks filled with brine that is impractical for desalination). Partially
depleted oil reservoirs provide the added benefit of enhanced oil
recovery (EOR). \[EOR is used in mature fields to recover additional oil
after standard extraction methods have been used. When CO~2~ is injected
for EOR, it causes residual oil to swell and become less viscous,
allowing some to flow to production wells, thus extending the field's
productive life.\] Although EOR can help the economics of CCS projects,
EOR sites are ultimately too few and too geographically isolated to
accommodate much of the CO~2~ from large-scale industrial CO~2~ capture
operations. In contrast, saline formations are available in many---but
not all---U.S. locations.

Natural underground CO~2~ reservoirs in Colorado, Utah, and other
western states testify to the effectiveness of long-term geologic CO~2~
storage. CO~2~ is also found in natural gas reservoirs, where it has
resided for millions of years. Thus, evidence suggests that depleted or
near-depleted oil and gas reservoirs, and similarly "capped" saline
formations will be ideal for storing CO~2~ for millennia or longer.

Geologic sequestration as a strategy for reducing CO~2~ emissions from
the atmosphere is currently being demonstrated in several projects
around the world. Three larger-scale projects---Statoil's Sleipner
Saline Aquifer CO~2~ Storage project in the North Sea off of Norway; the
Weyburn Project in Saskatchewan, Canada; and the In Salah Project in
Algeria---together sequester about 3--4 million metric tons of CO~2~ per
year, which collectively approaches the output of just one typical 500
MW coal-fired power plant. With 17 collective operating years of
experience, these projects have thus far demonstrated that CO~2~ storage
in deep geologic formations can be carried out safely and reliably.
Statoil estimates that Norwegian greenhouse gas emissions would have
risen incrementally by 3% if the CO~2~ from the Sleipner project had
been vented rather than sequestered.[^2]

Table 2 lists a selection of current and planned CO~2~ storage projects
as of early 2007, including those involving EOR.

Table 2 -- Select Existing and Planned CO~2~ Storage Projects as of
Early 2007

  -------------- ---------- ----------- ---------- ------------- ---------- ----------
  PROJECT        CO~2~      COUNTRY     START      Anticipated              
                 SOURCE                            amount                   
                                                   injected by:             

                                                   2006          2010       2015

  Sleipner       Gas. Proc. Norway      1996       9 MT          13 MT      18 MT

  Weyburn        Coal       Canada      2000       5 MT          12 MT      17 MT

  In Salah       Gas. Proc. Algeria     2004       2 MT          7 MT       12 MT

  Snohvit        Gas. Proc. Norway      2007       0             2 MT       5 MT

  Gorgon         Gas. Proc. Australia   2010       0             0          12 MT

  DF-1 Miller    Gas        U.K.        2009       0             1 MT       8 MT

  DF-2 Carson    Pet Coke   U.S.        2011       0             0          16 MT

  Draugen        Gas        Norway      2012       0             0          7 MT

  FutureGen      Coal       U.S.        2012       0             0          2 MT

  Monash         Coal       Australia   NA         0             0          NA

  SaskPower      Coal       Canada      NA         0             0          NA

  Ketzin/CO~2~   NA         Germany     2007       0             50 KT      50 KT
  STORE                                                                     

  Otway          Natural    Australia   2007       0             100 KT     100 KT

  **TOTALS**                                       **16 MT**     **35 MT**  **99 MT**
  -------------- ---------- ----------- ---------- ------------- ---------- ----------

*Source: Sally M. Benson, "Can CO~2~ Capture and Storage in Deep
Geological Formations Make Coal-Fired Electricity Generation Climate
Friendly?" Presentation at Emerging Energy Technologies Summit, UC Santa
Barbara, California, February 9, 2007. \[Note: Statoil has subsequently
suspended plans for the Draugen project and announced a study of CO~2~
capture at a gas-fired power plant at Tjeldbergodden. BP and Rio Tinto
have announced the coal-based "DF-3" project in Australia.\]*

**Enhanced Oil Recovery.** Experience relevant to CCS comes from the oil
industry, where CO~2~ injection technology and modeling of its
subsurface behavior have a proven track record. EOR has been conducted
successfully for 35 years in the Permian Basin fields of west Texas and
Oklahoma. Regulatory oversight and community acceptance of injection
operations for EOR seem well established.

Although the purpose of EOR is not to sequester CO~2~ per se, the
practice can be adapted to include CO~2~ storage opportunities. This
approach is being demonstrated in the Weyburn-Midale CO~2~ monitoring
projects in Saskatchewan, Canada. The Weyburn project uses captured and
dried CO~2~ from the Dakota Gasification Company's Great Plains synfuels
plant near Beulah, North Dakota. The CO~2~ is transported via a 200 mile
pipeline constructed of standard carbon steel. Over the life of the
project, the net CO~2~ storage is estimated at 20 million metric tons,
while an additional 130 million barrels of oil will be produced.

The economic value of EOR with CCS represents an excellent opportunity
for initial geologic sequestration projects like Weyburn. In addition,
"next generation" CO~2~-EOR processes could boost U.S. technically
recoverable oil resources by 160 billion barrels.[^3]

**CCS in the United States**

A DOE-sponsored R&D program, the "Regional Carbon Sequestration
Partnerships," is engaged in mapping U.S. geologic formations suitable
for CO~2~ storage. Evaluations by these Regional Partnerships and others
suggest that enough geologic storage capacity exists in the United
States to hold several centuries' production of CO~2~ from coal-based
power plants and other large point sources.

The Regional Partnerships are also conducting pilot-scale CO~2~
injection validation tests across the country in differing geologic
formations, including saline formations, deep unmineable coal seams, and
older oil and gas reservoirs. Figure 11 illustrates some of these
options. These tests, as well as most commercial applications for
long-term storage, will use CO~2~ compressed for volumetric efficiency
to a liquid-like "supercritical" state; thus, virtually all CO~2~
storage will take place in formations at least a half-mile deep, where
the risk of leakage to shallower groundwater aquifers or to the surface
is less likely to occur.

![](media/image12.wmf){width="5.552777777777778in" height="3.94375in"}

*Source: Peter Cook, CO2CRC, in Intergovernmental Panel on Climate
Change, Special Report "Carbon Dioxide Capture and Storage,"
http://www.ipcc.ch/pub/reports.htm*

Figure 11 -- Illustration of potential geological CO~2~ storage site
types

After successful completion of pilot-scale CO~2~ storage validation
tests, the Partnerships will undertake large-volume storage tests,
injecting quantities of \~1 million metric tons of CO~2~ or more over a
several year period, along with post-injection monitoring to track the
absorption of the CO~2~ in the target formation(s) and to check for
potential leakage.

The EPRI-CURC Roadmap identifies the need for several large-scale
integrated demonstrations of CO~2~ capture and storage. This assessment
was echoed by MIT in its recent *Future of Coal* report, which calls for
three to five U.S. demonstrations of about 1 million metric tons of
CO~2~ per year and about 10 worldwide.[^4] These demonstrations could be
the critical path item in commercialization of CCS technology. In
addition, EPRI has identified 10 key topics where further technical
and/or policy development is needed before CCS can become fully
commercial:

-   Caprock integrity

-   Injectivity and storage capacity

-   CO~2~ trapping mechanisms

-   CO~2~ leakage and permanence

-   CO~2~ and mineral interactions

-   Reliable, low-cost monitoring systems

-   Quick response and mitigation and remediation procedures

-   Protection of potable water

-   Mineral rights

-   Long-term liability

Figure 12 summarizes the relationship between EPRI's recommended
large-scale integrated CO~2~ capture and storage demonstrations and the
Regional Partnerships' "Phase III" large-volume CO~2~ storage tests.

![](media/image13.wmf){width="5.99375in" height="1.457638888888889in"}

Figure 12 -- Timing of CO~2~ storage technology RD&D activities and
milestones

**CO~2~ Transportation**

Mapping of the distribution of potentially suitable CO~2~ storage
formations across the country, as part of the research by the Regional
Partnerships, shows that some areas have ample storage capacity while
others appear to have little or none. Thus, implementing CO~2~ capture
at some power plants may require pipeline transportation for several
hundred miles to suitable injection locations, possibly in other states.
Although this adds cost, it does not represent a technical hurdle
because long-distance, interstate CO~2~ pipelines have been used
commercially in oilfield EOR applications. Nonetheless, EPRI expects
that early commercial CCS projects will take place at coal-based power
plants near sequestration sites or an existing CO~2~ pipeline. As the
number of projects increases, regional CO~2~ pipeline networks
connecting multiple industrial sources and storage sites will be needed.

**Policy-Related Long-Term CO~2~ Storage Issues**

Beyond developing the technological aspects of CCS, public policy need
to address issues such as CO~2~ storage site permitting, long-term
monitoring requirements, and liability. CCS represents an emerging
industry, and the jurisdiction for regulating it has yet to be
determined.

Currently, efforts are under way in some states to establish regulatory
frameworks for long-term geologic CO~2~ storage. Additionally,
stakeholder organizations such as the Interstate Oil and Gas Compact
Commission (IOGCC) are developing their own suggested regulatory
recommendations for states drafting legislation and regulatory
procedures for CO~2~ injection and storage operations.[^5] Other
stakeholders, such as environmental groups, are also offering policy
recommendations. EPRI expects this field to become very active soon.

Because some promising sequestration formations underlie multiple
states, a state-by-state approach may not be adequate. At the federal
level, the U.S. EPA published a first-of-its-kind guidance (UICPG \# 83)
on March 1, 2007, for permitting underground injection of CO~2~.[^6]
This guidance offers flexibility for pilot projects evaluating the
practice of CCS, while leaving unresolved the requirements that could
apply to future large-scale CCS projects.

**Long-Term CO~2~ Storage Liability Issues**

Long-term liability of storage sites will need to be assigned before CCS
can become fully commercial. Because CCS activities will be undertaken
to serve the public good, as determined by government policy, and will
be implemented in response to anticipated or actual government-imposed
limits on CO~2~ emissions, a number of policy analysts have suggested
that the entities performing these activities should be granted a large
measure of long-term risk reduction.

**RD&D INVESTMENT FOR ADVANCED COAL AND CCS TECHNOLOGIES**

Developing the suite of technologies needed to achieve competitive
advanced coal and CCS technologies will require a sustained major
investment in RD&D. As shown in Table 3, EPRI has estimated that an
expenditure of approximately \$8 billion will be required in the 10-year
period from 2008--17. The MIT *Future of Coal* report estimates the
funding need at up to \$800--850 million per year, which approaches the
EPRI value. Further, EPRI expects expected that an RD&D investment of
roughly \$17 billion will be required over the next 25 years.

Investment in earlier years may be weighted toward IGCC, as this
technology is less developed and will require more RD&D investment to
reach the desired level of commercial viability. As interim progress and
future needs cannot be adequately forecast at this time, the years after
2023 do not distinguish between IGCC and PC.

Table 3 -- RD&D Funding Needs for Advanced Coal Power Generation
Technologies with CO~2~ Capture

  ---------------------- ----------- ----------- ----------- ----------- -----------
                         2008--12    2013--17    2018--22    2023--27    2028--32

  Total Estimated RD&D   \$830M/yr   \$800M/yr   \$800M/yr   \$620M/yr   \$400M/yr
  Funding Needs\                                                         
  *(Public + Private                                                     
  Sectors)*                                                              

  *Advanced Combustion,  25%         25%         40%         80%         80%
  CO~2~ Capture*                                                         

  *Integrated            50%         50%         40%                     
  Gasification Combined                                                  
  Cycle (IGCC), CO~2~                                                    
  Capture*                                                               

  *CO~2~ Storage*        25%         25%         20%         20%         20%
  ---------------------- ----------- ----------- ----------- ----------- -----------

By any measure, these estimated RD&D investments are substantial. EPRI
and the members of the *CoalFleet for Tomorrow*® program, by promoting
collaborative ventures among industry stakeholders and governments,
believe that the costs of developing critical-path technologies for
advanced coal and CCS can be shouldered by multiple participants. EPRI
believes that government policy and incentives will also play a key role
in fostering CCS technologies through early RD&D stages to achieve
widespread, economically feasible deployment capable of achieving major
reductions in U.S. CO~2~ emissions.

[^1]: IEA Greenhouse Gas R&D Programme (IEA GHG), "Estimating Future
    Trends in the Cost of CO~2~ Capture Technologies," 2006/5, January
    2006.

[^2]: http://www.co2captureandstorage.info/project_specific.php?project_id=26

[^3]: http://www.adv-res.com/pdf/Game_Changer_Document.pdf

[^4]: http://web.mit.edu/coal/The_Future_of_Coal.pdf

[^5]: http://www.iogcc.state.ok.us/PDFS/CarbonCaptureandStorageReportandSummary.pdf

[^6]: http://www.epa.gov/safewater/uic/pdfs/guide_uic_carbonsequestration_final-03-07.pdf