**Statement of Susan Petty**

**President - AltaRock Energy, Inc.**

**Before the Senate Committee on Energy and Natural Resources**

**Regarding Senate Bill 1543**

**National Geothermal Initiative Act of 2007**

**September 26, 2007**

Mr. Chairman and Members of the Committee, I am honored to have the
opportunity to speak to you regarding Senate Bill 1543, the "National
Geothermal Initiative Act of 2007," which was introduced to the Senate
on June 5, 2007, by Senator Bingaman to encourage increased production
of energy from geothermal resources.

One of the goals of S. 1543 is to achieve 20% of electric power
generation from geothermal energy by 2050. You may be asking yourself if
this a realistic goal? In the fall of 2004, I was included in a 12
member panel led by Dr. Jefferson Tester of the Massachusetts Institute
of Technology that looked at the Future of Geothermal Energy. Our group
consisted of members from both industry and academia. While some of us
started the study convinced that it was possible to engineer or enhance
geothermal systems (EGS) with today's technology, many of us, including
myself, were skeptical. As we reviewed data, and listened to experts who
were actively researching new methods, testing them in the field, and
starting commercial enterprises to develop power projects from
geothermal energy using this emerging technology, I believe all of us
became convinced that a way had been found to tap into the vast
geothermal resource under our feet.

Everywhere on Earth, the deeper you go, the hotter it gets. In some
places, high temperatures are closer to the surface than others. We have
all heard of the "Ring of Fire, " characterized by volcanoes, hot
springs and fumaroles around the rim of the Pacific Ocean, including the
Cascades, the Aleutian Islands, Japan, the Philippines and Indonesia. We
know that along the tectonic rifts such as the Mid-Atlantic Ridge
including Iceland and the Azores, the East African Rift Valley, the East
Pacific Rise, the Rio Grande Rift running up through New Mexico and
Colorado and the Juan de Fuca Ridge the earth's heat is right at the
surface. But other geologic settings allow high temperatures to occur at
shallow depths, such as the faulted mountains and valleys of the Basin
and Range, the deep faults in the Rocky Mountains and the Colorado
Plateau. In addition, the sedimentary basins that insulate granites
heated by radioactive decay along the Gulf Coast, in the Midwest, along
the Chesapeake Bay and just west of the Appalachians can not only
provide oil and gas, but hot water as well. (See Figure 1)

The heat contained in this vast resource is so large that it is really
difficult to contemplate. Even with very conservative calculations, the
MIT study panel found that the amount of heat that could be
realistically recovered in the US from rocks at depths of 3 km to 10 km
(about 2 miles to 6 miles) is almost 3,000 times the current energy
consumption of the country. (See Figure 2) Listening to the experience
of those developing the Soultz project in France, the Rosemanowes
project in the UK and the Cooper Basin project in Australia, the panel
members began to understand that the technology to recover this heat was
here today. We can drill wells into high temperature rocks at depths
greater than 3 km. We can fracture large volumes of hot rock. We can
target wells into these man-made fractures and intersect them. We can
circulate water through these created fractures, picking up heat and
produce it at the other side heated to the temperature of reservoir
rocks. We can produce what we inject without having to add more water.
Long term tests have been conducted at fairly modest flow rates on these
created reservoirs without change in temperature over time. No power
plants have yet been built, but several are in progress in Europe.

Does this mean that we can build economic geothermal power plants based
on EGS technology right now? At the best sites, where high temperatures
occur at shallow depths in large rock masses with similar properties,
geothermal power production from EGS technology is economic today. But
to bring on line the huge resource stretching across the country from
coast to coast, we need to do some work.

I'd like to talk about the economics of geothermal power production so
you can better understand what needs to happen to enable widespread
development of power projects using EGS.

At some places in the Earth\'s crust, faults and fractures allow water
to circulate in contact with hot rock naturally. These are hydrothermal
systems where natural fractures and high permeability allow high
production rates. Even low temperature systems can be economic if the
flow rates produced are high enough. The capital cost for the wells and
wellfield-related equipment generally is between 25% - 50% of the total
capital cost of the power project. The capital cost for hydrothermal
projects can range from around \$2,500/installed kW to over \$5,000/kW,
largely depending on the flow rate per well and the depth of the wells.
The levelized break-even cost of energy for commercially viable
hydrothermal projects currently ranges from \$35/MWh to over \$80/MWh.
Of this, about \$15-25/MWh is operating cost. The rest is the cost to
amortize the power generation equipment and the wellfield.

Hydrothermal power is a good deal: Clean, small foot print,
cost-effective. So why isn't more power from hydrothermal sources on
line? The issue for hydrothermal power is risk. Because the risk related
to finding the resource and successfully drilling and completing wells
into the resource is high, development by utilities is unlikely. In
order to accept this risk, independent power producers need a long-term
contract at a guaranteed price and a high return on their investment.
Utilities are loath to give a long-term contract because the payments to
the generator will be treated as debt in determining their
debt-to-equity ratio for credit and bond ratings.

Hydrothermal projects also tend to be small in size. While some of the
potential future hydrothermal projects might be large, many of these are
associated with scenic volcanic features protected as national parks or
revered by Native Americans. A large scale project might mitigate the
risk by spreading it over a much larger number of MW. In addition, there
is a true economy of scale for geothermal power projects. For instance,
the same number of people are needed to operate a 10 MW geothermal
project as operate a 120 MW, or even a 250 MW, project.

Most of the really good (i.e. economic) hydrothermal systems are in the
arid West. Not only is cooling water\--which improves project economics
by improving plant efficiency\--an issue in this part of the country,
but also the wide open spaces mean high-potential sites are often far
from transmission, operators, supplies and large population centers with
a high demand for power. Little potential for producing power from
conventional geothermal, i.e. hydrothermal, sources exists in the
Midwest, Southeast or East Coast.

Still, hydrothermal power has the potential to supply the country with
more than 20,000 MW, or about 2% of our current installed capacity.
However, the very high reliability of geothermal power means that this
would be about 4% of our current annual generation. And this power is
baseload or power that is available night and day.

Over the years, the cost of generating electricity from hydrothermal
sources has dropped from around \$130/MWh to less than \$50/MWh. This
was facilitated by incentives provided both by the market during the
mid-1980s oil crisis, and by the government in the form of tax subsidies
encourage the construction of over 2,000 MW of geothermal power that
went on line from 1986-1995. Some of this drop in cost is due to
research conducted by the US Department of Energy (DOE). For instance,
in 1980 the DOE completed the first demonstration binary power plant at
Raft River. This plant enabled the use of fluids at temperatures much
lower than had been developed in the past. Industry commercialized this
technology, and now most of the new geothermal power plants being built
today are binary plants. DOE research, together with industry, developed
high-temperature tools that are now essential to the evaluation of
geothermal wells. A combination of DOE-supported research and industry
effort as improved binary power plant efficiency by almost 50% from the
earliest commercial plants in the 1980s, and flash power-plant
efficiency by almost 35% over the same time period. This translates
directly into reduction in overall project cost and power prices because
fewer wells and less equipment is needed to generate the same amount of
energy.

The MIT study started with the current state of the geothermal industry.
The first task we realized we needed to undertake was a realistic look
at the size and potential cost of developing geothermal power across the
continent. It has long been realized by scientists that a vast
geothermal resource exists everywhere as long as technology allows us to
drill deep enough, develop a reservoir by creating fractures or
enhancing natural fractures, and connect wells to circulate fluid
through that reservoir. The US Geological Survey has been tasked with a
detailed evaluation of the US geothermal resource, but this could not be
finished in time for our study. The MIT panel, therefore, undertook a
preliminary assessment of the geothermal resource in the US.

Using data collected over the years with DOE support, maps of the
temperature at depth were developed by Dr. David Blackwell's group at
SMU. Temperature at the midpoint of 1 km thick slices was projected at 1
km intervals starting at a depth of 3 km and extending down to 10 km, a
reasonable limit for drilling using today's technology. The heat
resource contained in each cubic kilometer of rock at these temperatures
at each depth was then calculated. The amount of energy stored in this
volume of rock is so enormous that it is really impossible to
comprehend. (See Figure 1) We then looked at the studies that had
estimated what fraction of this heat might be recovered, and at what
efficiency this recovered heat might be turned into electric power.
Studies showed that for economic systems, 40% or more of the total heat
stored in the rock is recoverable. We also considered the more
conservative recoverable estimates of 2% and 20%. Even at 2%, the amount
of energy that could be realistically recovered, leaving economics and
cost considerations aside, is more than 3,000 times the current total
energy consumption of the US, including transportation uses.

In order to understand the technology needed to recover this energy, we
turned to the published literature on the experiments done in the past
at Fenton Hill, Rosemanowes, Hijiori, Ogachi and Soultz. We also brought
in experts who are currently working on the Soultz project and on
commercial engineered and enhanced geothermal projects in Europe and in
Australia to tell us about the status of their work and their future
efforts and needs. By the end of the study, we had concluded that EGS
technology is technically feasible today. We can:

-   Drill wells deep enough and successfully using standard geothermal
    and oil-and-gas drilling technology with existing infrastructure to
    tap the geothermal resource across the US, including areas in the
    Midwest, East and Southeast

-   Consistently fracture large rock volumes of rock

-   Monitor and map these created or enhanced fractures

-   Drill production wells into the fractured rock

-   Circulate cold water into the injection well and produce heated
    water from the production wells

-   Operate the system without having to add significant amounts of
    water over time

-   Operate the circulation system over extended test periods without
    measurable drop in temperature.

-   Generate power from the circulating water at Fenton Hill and Ogachi

In addition, EGS power projects are scalable. Once the first
demonstration unit has been tested at a site, the potential exists to
develop a really large scale project of 250 to 1000 MW. Combined with
the fact that good EGS sites where large bodies of hot rock with fairly
uniform properties can be found across the US, that the sites are so
many that they can be selected to avoid places with no transmission
capacity or those located near areas of scenic beauty or environmental
sensitivity, generating power from EGS technology looks like a winning
proposition.

The real question then becomes, not is it realistic to anticipate
generating 20% of our nation's electric power from geothermal energy,
but can we make it cost effective?

The MIT panel included members from industry and research who are
experts in the economics of power generation. The panel developed a list
of key technologies that could help reduce the cost of generating power
from EGS. They considered the changes in the cost of power generation
from hydrothermal systems over the last 20 years, and the current state
of EGS technology. They also considered research currently underway, not
only that sponsored by DOE through universities and the national
laboratories, but that being done by industry. Using models developed by
both DOE and MIT, the cost of power and the impact on that cost of these
possible technology improvements was examined. In addition, the panel
looked at the impact of "learning by doing" on the cost of power.

We concluded that at the best sites, those with very high temperatures
at depths of around 3-4 km in areas with low permeability natural
fractures, EGS is economic today. Figure 3 shows the relative cost of
power from a 300°C site at a depth of 3 km. With current technology
power from this site could be generated for a levelized cost of power of
about \$74/MWh. This isn't the price that power could be sold for, since
it doesn't include profit. It does, however, include financing charges
at higher than utility rates, operating costs and the cost of amortizing
the capital investment in the welfield and power plant. At deeper depths
and lower temperatures, the cost of generating power using EGS
technology is much higher, about \$192/MWh. (Figure 4)

With incremental technology improvement, the cost of power could be cut
in half or more, particularly for the deeper high temperature systems.
These incremental technology improvements include things like improving
conversion cycle efficiency, being able to isolate the part of the
wellbore that has been treated so that untreated parts can be fractured,
redesigning wells to reduce the number of casing strings and improved
understanding of rock/fluid interaction to prevent or repair short
circuiting through the reservoir. None of these technology improvements
require game changing strategies, just the kind of advancement that
comes from persisting in extending our knowledge to the next level.
Looking at the high temperature example in Figure 3, the levelized cost
of power could be cut to \$54/MWh or about 27% with these technology
improvements implemented. The moderate temperature site could see a much
larger reduction of over 60% to \$74/MWh.

Figure 5 shows a supply curve for EGS based geothermal power for the
entire US. This curve shows the amount of power available at a certain
cost. However, this is cost of power not price. In other words, this is
not the price that an independent power producer would charge a utility
for this power if they were selling it to them. However, it does give an
idea of what could be economic in the future. The two sets of dots are
calculated using current technology and the projected cost using future
incrementally improved technology. Once the cost of power increases to
around \$100/MWh, it is clear that more than 400,000 MW would be
available or development. This means that the amount of power we could
develop is not limited by the resource available, but by the cost. And
the cost is limited by the technology and the fact that we aren't doing
this here in the US.

We concluded that at the best sites, those with very high temperatures
at depths of around 3-4 km in areas with low-permeability natural
fractures, EGS is economic today. With incremental technology
improvement, the cost of power could be cut in half or more,
particularly for the deeper high temperature systems. These incremental
technology improvements include things such as improving conversion
cycle efficiency, being able to isolate the part of the wellbore that
has been treated so that untreated parts can be fractured, redesigning
wells to reduce the number of casing strings and improved understanding
of rock/fluid interaction to prevent or repair short circuiting through
the reservoir. None of these technology improvements require
game-changing or revolutionary strategies, just the kind of advancement
that comes from persisting in extending our knowledge to the next level.

The cost of this type of technology improvement is not high. The panel
felt that an investment of \~\$368,000,000 over a period of about 8-10
years combined with industry involvement could result in 100,000 MW on
line by 2030. This would be 10% of the current installed capacity and
over 20% of the current electric generation of the country. Combined
with the hydrothermal resource, it is a very realistic goal to have
geothermal energy provide 20% of the nation's electricity by 2030.
However, the effort would require federal support, university,
laboratory and industry research, and development and a real commitment
to renewable energy use.

Currently more than eight companies are developing EGS power projects in
Europe and more than 20 companies are working to get power on line using
this technology in Australia. AltaRock Energy Inc. is the only company
focused on commercializing power generation from EGS technology in the
US. In Europe, price subsidies and European Union-sponsored research are
helping to start more than 50 EGS projects. In Australia, government
grants, help with transmission access, research, and legislation
requiring generation from renewable energy sources are driving EGS
technology to commercialization. Other countries with fewer economic
geothermal resources are planning to include geothermal energy in their
generation portfolio. The US needs to commit to this clean, baseload,
renewable power source for our own energy future.

Summary

-   ***The Future of Geothermal Energy: Impact of Enhanced Geothermal
    Systems (EGS) on the United States in the 21st Century***

    -   <http://geothermal.inel.gov/publications/future_of_geothermal_energy.pdf>

    -   12 member panel lead by Dr. Jefferson Tester through MIT

-   **Conclusions:**

    -   EGS power is technically feasible today

    -   Potentially 100,000 MW can be on line by 2030 with federal
        investment of \~\$350,000,000

    -   Resource extends across US

    -   Best resources economic today at high temperature, shallow sites

    -   With incremental technology improvement, cost can be cut in half

    -   With learning by doing and innovative technology improvement
        cost can be reduced for deep resources to ¼ cost with current
        technology

-   **Hydrothermal Systems**

    -   Natural permeability

    -   High flow rates

    -   Few big systems

    -   Located in Western US

    -   Exploration drilling is needed and remains risky

    -   Economic now even for low temperatures

    -   \>2800 MW on line growing by about 300 MW/yr

    -   Potential for as much as 20,000 MW at economic costs over next
        40 yrs

    -   \>95% average availability

    -   Technology improvement reduced cost (not price) -13¢ per kWh in
        1986 to about 5¢ per kWh in 2006

-   **Enhanced Geothermal Systems (EGS)**

    -   Resource is vast

    -   Distributed across the US, but best sites in West

    -   Low or no natural permeability

    -   Reservoir must be engineered to:

        -   Obtain high flow rates

        -   Develop good heat exchange area

    -   Exploration risk reduced

        -   Temperature only needed

        -   Drill deeper to get greater temperature

    -   Large systems can be developed

    -   Uses proven state-of-the-art drilling technology

    -   Fracturing technology developing

    -   MIT study identified key areas of technology improvement needed
        to reduce cost

    -   Potential for CO2 sequestration

    -   8 companies in Europe; \~20 companies in Australia working to
        commercialize

    -   AltaRock Energy -- first US company focused on EGS technology
        development

f![](media/image1.png){width="5.7555555555555555in"
height="3.5541666666666667in"}

Figure 1 -- Temperature at a depth of 6.5 km -- Continental United
States

![](media/image2.wmf){width="5.96875in" height="4.065277777777778in"}

Figure 2 -- Comparison of Stored thermal energy in place with potential
recoverable energy between 3 km and 10 km.

![](media/image3.wmf){width="5.997222222222222in"
height="3.6847222222222222in"}

Figure 3 -- Levelized breakeven cost of EGS power from a high
temperature site at 3 km.

![](media/image4.wmf){width="5.996527777777778in" height="3.775in"}

Figure 4 -- Levelized breakeven cost of EGS power from a moderate
temperature site.

![](media/image5.wmf){width="7.289583333333334in"
height="4.982638888888889in"}

Figure 5 Supply curve for EGS Power in the United States -- plots the
levelized breakeven cost of power against the developable power assuming
a 30 year project life.