[House Hearing, 109 Congress]
[From the U.S. Government Publishing Office]




 
 THE VAST NORTH AMERICAN RESOURCE POTENTIAL OF OIL SHALE, OIL SANDS, 
                     AND HEAVY OILS, PARTS 1 AND 2

=======================================================================

                           OVERSIGHT HEARINGS

                               before the

                       SUBCOMMITTEE ON ENERGY AND
                           MINERAL RESOURCES

                                 of the

                         COMMITTEE ON RESOURCES
                     U.S. HOUSE OF REPRESENTATIVES

                       ONE HUNDRED NINTH CONGRESS

                             FIRST SESSION

                               __________

                    June 23, 2005 and June 30, 2005

                               __________

                           Serial No. 109-22

                               __________

           Printed for the use of the Committee on Resources



  Available via the World Wide Web: http://www.gpoaccess.gov/congress/
                               index.html
                                   or
         Committee address: http://resourcescommittee.house.gov


                                 ______

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_____________________________________________________________________________
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                         COMMITTEE ON RESOURCES

                 RICHARD W. POMBO, California, Chairman
       NICK J. RAHALL II, West Virginia, Ranking Democrat Member

Don Young, Alaska                    Dale E. Kildee, Michigan
Jim Saxton, New Jersey               Eni F.H. Faleomavaega, American 
Elton Gallegly, California               Samoa
John J. Duncan, Jr., Tennessee       Neil Abercrombie, Hawaii
Wayne T. Gilchrest, Maryland         Solomon P. Ortiz, Texas
Ken Calvert, California              Frank Pallone, Jr., New Jersey
Barbara Cubin, Wyoming               Donna M. Christensen, Virgin 
  Vice Chair                             Islands
George P. Radanovich, California     Ron Kind, Wisconsin
Walter B. Jones, Jr., North          Grace F. Napolitano, California
    Carolina                         Tom Udall, New Mexico
Chris Cannon, Utah                   Raul M. Grijalva, Arizona
John E. Peterson, Pennsylvania       Madeleine Z. Bordallo, Guam
Jim Gibbons, Nevada                  Jim Costa, California
Greg Walden, Oregon                  Charlie Melancon, Louisiana
Thomas G. Tancredo, Colorado         Dan Boren, Oklahoma
J.D. Hayworth, Arizona               George Miller, California
Jeff Flake, Arizona                  Edward J. Markey, Massachusetts
Rick Renzi, Arizona                  Peter A. DeFazio, Oregon
Stevan Pearce, New Mexico            Jay Inslee, Washington
Henry Brown, Jr., South Carolina     Mark Udall, Colorado
Thelma Drake, Virginia               Dennis Cardoza, California
Luis G. Fortuno, Puerto Rico         Stephanie Herseth, South Dakota
Cathy McMorris, Washington
Bobby Jindal, Louisiana
Louie Gohmert, Texas
Marilyn N. Musgrave, Colorado
Vacancy

                     Steven J. Ding, Chief of Staff
                      Lisa Pittman, Chief Counsel
                 James H. Zoia, Democrat Staff Director
               Jeffrey P. Petrich, Democrat Chief Counsel
                                 ------                                

              SUBCOMMITTEE ON ENERGY AND MINERAL RESOURCES

                     JIM GIBBONS, Nevada, Chairman
           RAUL M. GRIJALVA, Arizona, Ranking Democrat Member

Don Young, Alaska                    Eni F.H. Faleomavaega, American 
Barbara Cubin, Wyoming                   Samoa
Chris Cannon, Utah                   Solomon P. Ortiz, Texas
John E. Peterson, Pennsylvania       Jim Costa, California
Stevan Pearce, New Mexico            Charlie Melancon, Louisiana
Thelma Drake, Virginia               Dan Boren, Oklahoma
Bobby Jindal, Louisiana              Edward J. Markey, Massachusetts
Louie Gohmert, Texas                 Nick J. Rahall II, West Virginia, 
Richard W. Pombo, California, ex         ex officio
    officio


                                 ------                                
                            C O N T E N T S

                              ----------                              
                                                                   Page

Hearing held on Thursday, June 23, 2005..........................     1

Statement of Members:
    Cannon, Hon. Chris, a Representative in Congress from the 
      State of Utah..............................................    39
        Prepared statement of....................................    39
    Cubin, Hon. Barbara, a Representative in Congress from the 
      State of Wyoming, Prepared statement of....................    40
    Gibbons, Hon. Jim, a Representative in Congress from the 
      State of Nevada............................................     1
        Prepared statement of....................................     3
    Grijalva, Hon. Raul M., a Representative in Congress from the 
      State of Arizona...........................................     4
        Prepared statement of....................................     5

Statement of Witnesses:
    George, Russell, Executive Director, Colorado Department of 
      Natural Resources..........................................    51
        Prepared statement of....................................    52
        Response to questions submitted for the record...........    59
    Godec, Michael, Vice President, Advanced Resources 
      International, Inc.........................................     5
        Prepared statement of....................................     8
        Response to questions submitted for the record...........    11
    McKee, Michael J., Commissioner, Uintah County, Utah.........    61
        Prepared statement of....................................    63
        Response to questions submitted for the record...........    66
    O'Connor, Terry, Vice President, External and Regulatory 
      Affairs, Shell Unconventional Resources Energy.............    18
        Prepared statement of....................................    21
        Response to questions submitted for the record...........    27
    Savage, Jack S., President, Oil-Tech, Inc....................    14
        Prepared statement of....................................    16
    Stringham, Greg, Vice President, Markets & Fiscal Policy, 
      Canadian Association of Petroleum Producers (CAPP).........    30
        Prepared statement of....................................    32
        Response to questions submitted for the record...........    33

Additional materials supplied:
    Department of Energy, Government of Alberta, Canada, 
      Statement submitted for the record.........................    69
    Granados, Juan Antonio, President, Shale Oil Information 
      Center, Inc. Statement submitted for the record............    49
    Mathis, Mark, Executive Director, Citizens' Alliance for 
      Responsible Energy, Statement submitted for the record.....    75
    Smith, Murray, Former Minister of Energy, Canada, Oral 
      statement of...............................................    36


                            C O N T E N T S

                              ----------                              
                                                                   Page

Hearing held on Thursday, June 30, 2005..........................    81

Statement of Members:
    Gibbons, Hon. Jim, a Representative in Congress from the 
      State of Nevada............................................    81
        Prepared statement of....................................    82
    Grijalva, Hon. Raul M., a Representative in Congress from the 
      State of Arizona, Prepared statement of....................   105

Statement of Witnesses:
    Barna, Dr. Theodore K., Ph.D., Assistant Deputy Under 
      Secretary of Defense, Advanced Systems and Concepts, Office 
      of the Secretary of Defense, U.S. Department of Defense....    83
        Prepared statement of....................................    85
        Response to questions submitted for the record...........    88
    Calvert, Chad, Deputy Assistant Secretary for Land and 
      Minerals Management, U.S. Department of the Interior.......    98
        Prepared statement of....................................    99
        Response to questions submitted for the record...........   101
    Maddox, Mark, Principal Deputy Assistant Secretary for Fossil 
      Energy, U.S. Department of Energy..........................    90
        Prepared statement of....................................    92
        Response to questions submitted for the record...........    95

Additional materials supplied:
    Trent, Dr. Robert, Former Dean, School of Mineral 
      Engineering, University of Alaska-Fairbanks, Statement 
      submitted for the record by Dr. Daniel Fine................   120


 OVERSIGHT HEARING ON ``THE VAST NORTH AMERICAN RESOURCE POTENTIAL OF 
             OIL SHALE, OIL SANDS, AND HEAVY OILS,'' PART 1

                              ----------                              


                        Thursday, June 23, 2005

                     U.S. House of Representatives

              Subcommittee on Energy and Mineral Resources

                         Committee on Resources

                            Washington, D.C.

                              ----------                              

    The Subcommittee met, pursuant to call, at 10:03 a.m., in 
Room 1324, Longworth House Office Building, Hon. Jim Gibbons 
[Chairman of the Subcommittee] presiding.
    Present: Representatives Gibbons, Grijalva, Cubin, Cannon, 
Pearce, Drake, Jindal, and Costa.

STATEMENT OF THE HON. JIM GIBBONS, A REPRESENTATIVE IN CONGRESS 
                    FROM THE STATE OF NEVADA

    Mr. Gibbons. The Subcommittee on Energy and Mineral 
Resources will come to order.
    The Subcommittee is meeting today for the first of two 
hearings that attempt to set the record straight on the immense 
resource potential of unconventional oil in North America. 
Today, we will hear from resource experts, resource producers, 
and state and local government representatives. Next Thursday, 
June 30th, we will hear from the Departments of Interior, 
Energy, and Defense on this.
    I would guess that many of you in this room who have been 
following the energy bill debate on Capitol Hill have heard 
time and time again the misrepresentation that the U.S. has 
only 3 percent of the world's oil reserves. This myth, or 
distortion of the truth, has been used by opponents to a 
comprehensive energy bill as a means of persuading mainstream 
media and the American public that the U.S. must reduce its oil 
use or continue to be held hostage to OPEC imports.
    Today, as we discuss North American oil shale, oil sands, 
and heavy oils, we will learn that the U.S. is in quite the 
opposite position. We actually have some of the world's largest 
potential oil resources within our own borders.
    According to the Department of Energy, the U.S. alone has 2 
trillion--that is ``trillion'' with a ``T''--barrels of oil 
shale, out of some 2.6 trillion barrels of oil shale found 
worldwide. In addition, today's testimony will show the U.S. 
has 1 trillion barrels of other conventional and unconventional 
oil resources.
    It is my understanding that Saudi Arabia has some 260 
billion barrels of proven oil reserves. And so if my math is 
correct, that means the U.S. alone has almost 12 times more oil 
than Saudi Arabia. And this doesn't count the vast North 
American potential of Canada's oil sands.
    Competition for global oil resources is fierce, with the 
likes of China and India continuing their quest for more oil to 
fuel their burgeoning economies. OPEC has committed to increase 
production, and has now set their price target at $50 a barrel. 
And I only say, it wasn't too long ago, as we can all remember, 
OPEC's price span was set somewhere between $22 and $28 per 
barrel. Now they have set it at $50 per barrel.
    ``Should the U.S. continue to send billions of dollars 
overseas each year to purchase foreign oil?'' would be the 
question we should all ask. I hope no one answered ``Yes'' to 
that question. The answer is truly ``No,'' and we should not 
continue to send billions of dollars overseas each year to pay 
for foreign oil. The answer ``No'' is brought to us because we 
have enough oil of our own here at home; and ``No'' because we 
should be spending that money here at home, putting people to 
work, and securing our own economic and energy future.
    The major oil shale deposits, some 1.5 trillion barrels, 
are located in the western U.S., in the States of Colorado, 
Utah, and Wyoming. And more than 70 percent are expected to be 
on federally owned and managed land.
    But the U.S. does not have a commercial leasing program in 
place to unlock this Federal resource potential; which is why I 
worked with my colleagues on the Committee to include language 
in the House energy bill to help expedite commercial oil shale 
production.
    So, is commercial oil shale production feasible? I think 
the answer is ``Yes.'' And we will hear testimony on that 
feasibility today. Today, oil shale, oil sands, and heavy oils 
are considered unconventional. And there are detractors out 
there who would have the American public believe that 
unconventional oil shale resources are insufficient to provide 
any real stable supply of oil for our future.
    I would simply say that over the years technology and 
technological advances in the oil and gas industry have proven 
that unconventional resources of the past become the 
conventional resources of the future. We can't help but look to 
our neighbors to the north, where Alberta's oil sands were once 
just a twinkle in some scientist's eye. Alberta's 1.7-trillion-
barrel unconventional oil resource is now producing more than 1 
million barrels of oil per day.
    I welcome our witnesses today. I look forward to their 
testimony. At this time, I would like to turn it over and 
recognize our Ranking Member from Arizona, Mr. Grijalva, for 
any opening remarks he may have. Mr. Grijalva.
    [The prepared statement of Mr. Gibbons follows:]

           Statement of The Honorable Jim Gibbons, Chairman, 
              Subcommittee on Energy and Mineral Resources

    The Subcommittee meets today for the first of two hearings that 
attempts to set the record straight on the immense resource potential 
of unconventional oil in North America.
    Today, we will hear from resource experts, resource producers, and 
State and local government representatives.
    Next Thursday, June 30th, we will hear from the Departments of 
Interior, Energy, and Defense.
    I would guess that many of you in this room who have been following 
the energy bill debate on Capitol Hill have heard time and time again 
the misrepresentation that the U.S. has only 3 percent of the world's 
oil reserves.
    This distortion of the truth has been used by opponents to a 
comprehensive energy bill as a means of persuading the mainstream media 
and the American public that the U.S. must reduce its oil use or 
continue to be held hostage to OPEC imports.
    Today, as we discuss North American oil shale, oil sands, and heavy 
oils, we will learn that the U.S. is in quite the opposite position--we 
actually have some of the world's largest potential oil resources 
within our own borders.
    According to the Department of Energy, the U.S. alone has 2 
trillion--yes, trillion with a ``T''--barrels of oil shale out of some 
2.6 trillion barrels of oil shale found worldwide.
    In addition, today's testimony will show, the U.S. has 1 trillion 
barrels of other conventional and unconventional oil resources.
    Now, it is my understanding that Saudi Arabia has some 260 billion 
barrels of proven oil reserves.
    If my math is correct, that means the U.S. alone has almost 12 
times more oil than Saudi Arabia!
    And this doesn't count the vast North American potential of 
Canada's oil sands.
    Competition for global oil resources is fierce with the likes of 
China and India continuing their quest for more oil to fuel their 
burgeoning economies.
    OPEC has committed to increase production and has now set their 
price target at $50 per barrel.
    Do you remember that not too long ago OPEC's price band was set 
somewhere between $22 and $28 per barrel?
    Should the U.S. continue to send billions of dollars overseas each 
year to purchase foreign oil?
    I hope no one answered ``yes'' to that question--The answer is 
``no'', we should not continue to send billions of dollars overseas 
each year to pay for foreign oil.
    ``No'', because we have enough of our own oil here at home.
    And ``no'', because we should be spending that money here at home, 
putting people to work and securing our own economic and energy future.
    The major oil shale deposits--some 1.5 trillion barrels--are 
located in the Western U.S. in the states of Colorado, Utah, and 
Wyoming and more than 70 percent are expected to be federally-owned.
    But the U.S. does not have a commercial leasing program in place to 
unlock this federal resource potential, which is why I worked with my 
colleagues to include language in the House energy bill to help 
expedite commercial oil shale production.
    So, is commercial oil shale production feasible?
    I believe the answer is ``yes'', and we'll hear testimony on that 
feasibility today.
    Today, oil shale, oil sands, and heavy oils are considered 
unconventional, and there are detractors out there who would have the 
American public believe that unconventional oil shale resources are 
insufficient to provide any real, stable supply of oil for our future.
    I would simply say that over the years, technological advances in 
the oil and gas industry have proven that the unconventional resource 
of the past becomes the conventional resource of the future.
    We can't help but look to our neighbors to the north where 
Alberta's oil sands were once just a twinkle in some scientist's eye.
    Alberta's 1.7 trillion barrel unconventional oil resource is now 
producing more than 1 million barrels of oil per day!
    I welcome our witnesses today and look forward to their testimony.
    At this time I would like to recognize our Ranking member from 
Arizona, Mr. Grijalva, for any opening remarks he may have.
                                 ______
                                 

    STATEMENT OF HON. RAUL M. GRIJALVA, A REPRESENTATIVE IN 
               CONGRESS FROM THE STATE OF ARIZONA

    Mr. Grijalva. Thank you, Mr. Chairman. And I join with you 
in welcoming our witnesses and looking forward to their 
testimony.
    Today's hearing focuses on a potentially untapped domestic 
energy resource, oil shale and oil sands. Industry experts say 
oil shale holds great potential, with an estimated 2 to 4 
trillion barrels of oil locked in the Green River formation out 
West. Yet development of the resource has not come to fruition 
due, I believe, primarily to excessive cost.
    While the USGS has estimated there are about 2 trillion 
barrels of conventional recoverable oil in the world, it has 
done no estimates for oil shale or oil sand. Oil shale has a 
history in the western United States that is shaky at best. 
Many bold promises have been made in the past about oil shale's 
potential and about the affordability of its production, but 
few of them have come true so far. As the old saying goes in 
Colorado, ``Oil shale is the fuel of the future, and always 
will be.''
    In March of this year, The Wall Street Journal ran a story 
that reiterated both the huge resource embedded in the shale of 
the Green River region and the challenges that are involved in 
extracting oil from the rock.
    Today, however, with oil prices at all-time highs, we see 
renewed interest from industry in developing these resources. A 
recent Washington Post article on oil shale mining in Canada 
stated that major companies faced with tougher prospects for 
developing big, new oil fields around the world are doing what 
was once unthinkable: sinking billions of dollars into projects 
to wring out deposits of petroleum buried amid sand and clay.
    While there is excitement about the prospects of 
development of the resource, I join with my colleague Mark 
Udall of Colorado in urging some degree of caution on the part 
of the Federal Government. The new technologies being developed 
to extract or convert shale and sand into oil and gas should be 
adequately analyzed, and the impacts of developing these 
resources should be assessed before BLM launches into a full-
scale leasing program. Before Congress commits lands or 
financial resources to oil shale development, there are 
important issues to consider, such as the potential impacts on 
water quality and quantity, particularly in such an arid 
region.
    Finally, as we have stated before, we cannot drill or mine 
our way out of the current energy crisis. As 26 former national 
security advisors have asserted, we would be better off 
recognizing the full costs of our continuing and 
disproportionate dependence on oil from any source.
    While there may be nothing wrong with the BLM facilitating 
oil shale development, I would hope that any taxpayer revenue 
or support be devoted to energy research and development that 
would be spent on non-fossil-fuel energy technologies.
    With that, I thank the Chairman.
    [The prepared statement of Mr. Grijalva follows:]

    Statement of The Honorable Raul M. Grijalva, Ranking Democrat, 
              Subcommittee on Energy and Mineral Resources

    Today's hearing focuses on a potentially untapped, domestic energy 
resource--oil shale and oil sands.
    Industry experts say oil shale holds great potential with an 
estimated 2 to 4 trillion barrels of oil locked in the Green River 
formation out west, yet development of the resource has not come to 
fruition due primarily to excessive costs. While the USGS has estimated 
that there are about 2 trillion barrels of conventional recoverable oil 
in the world, it has done no estimates for oil shale or oil sands.
    Oil shale has a history in the western United States that is shaky 
at best. Many bold promises have been made in the past about oil 
shale's potential and about the affordability of its production but few 
of them have come true so far.
    As the old saying goes in Colorado ``oil shale is the fuel of the 
future, and always will be.'' In March of this year, the Wall Street 
Journal ran a story that reiterated both the huge energy resource 
embedded in the shale of the Green River region and the challenges that 
are involved in extracting oil from rock.
    Today, however, with oil prices at all time highs, we see renewed 
interest from industry in developing these resources. A recent 
Washington Post article on oil shale mining in Canada, stated that 
``Major companies--faced with tougher prospects for developing big new 
oil fields around the world--are doing what was once unthinkable: 
sinking billions of dollars into projects to wring oil out of deposits 
of petroleum buried amid sand and clay.''
    While there is excitement about the prospects of development of 
this resource, I join my colleague, Mark Udall of Colorado, in urging 
some degree of caution on the part of the federal government. The new 
technologies being developed to extract or convert shale and sand into 
oil and gas should be adequately analyzed and the impacts of developing 
these resources should be assessed before the BLM launches into a full 
scale leasing program.
    Before the Congress commits lands or financial resources to oil 
shale development there are important issues to consider, such as the 
potential impacts on water quality and quantity, particularly in such 
an arid region.
    Finally, as we have stated before, we cannot drill--or mine--our 
way out the current energy crisis. As 26 former national security 
advisors have asserted, we would be better off recognizing the full 
costs of our continuing and disproportionate dependence on oil from any 
source. While there may be nothing wrong with the BLM facilitating oil 
shale development, I would hope that any taxpayer revenues devoted to 
energy research and development would be spent on non-fossil fuel 
energy technologies.
                                 ______
                                 
    Mr. Gibbons. Thank you very much, Mr. Grijalva.
    We will now recognize our first panel. Welcome, gentlemen. 
Mr. Mike Godec, Vice President, Advanced Resources 
International, Incorporated; Mr. Jack Savage, President and 
CEO, Oil-Tech, Incorporated; Terry O'Connor, Vice President, 
External and Regulatory Affairs, Shell Unconventional Resources 
Energy; and Greg Stringham, Vice President, Markets and Fiscal 
Policy, Canadian Association of Petroleum Producers.
    Gentlemen, welcome. If you will all please rise and raise 
your right hand, we have a policy to swear in our witnesses.
    [Witnesses sworn.]
    Mr. Gibbons. Let the record reflect that each of the 
witnesses answered in the affirmative. We will begin with Mr. 
Mike Godec. Welcome, Mr. Godec. The floor is yours. We look 
forward to your testimony.

           STATEMENT OF MIKE GODEC, VICE PRESIDENT, 
             ADVANCED RESOURCES INTERNATIONAL, INC.

    Mr. Godec. Thank you very much, Mr. Chairman. Good morning. 
I am pleased to address this Subcommittee on the topic of 
increasing future domestic oil production from oil shale, oil 
sands, and heavy oil.
    As the Chairman stated, our Nation's oil basins are mature 
and in decline. In the past 20 years, domestic oil production 
has dropped by 3 million barrels per day; while demand for oil 
has continued to grow.
    However, the problem of declining domestic oil production 
is not due to lack of domestic resources. Not including 
domestic oil shale resources, which others testifying today can 
address more effectively than I, undeveloped domestic oil 
resources in the ground, or in place, in the U.S. still total 
over 1 trillion barrels.
    These resources include undiscovered conventional onshore 
and offshore oil; the future growth of already discovered oil 
fields; stranded light oil resources amenable to carbon dioxide 
enhanced oil recovery; shallow and deep heavy oil; residual oil 
in transition zones; and oil sands. These domestic resources 
could produce an additional estimated 400 billion barrels of 
future technically recoverable oil, as shown in Table 1 of our 
written testimony provided to this Subcommittee.
    In addition, as stated in the opening remarks, another 2 
trillion barrels exist in U.S. oil shale deposits; primarily in 
Colorado, Utah, and Wyoming, but also in lower-quality deposits 
in the eastern U.S. Of this, about 400 billion barrels is of 
relatively high quality, holding more than 30 gallons per ton 
of shale. Perhaps half of this is technically recoverable, and 
would be the target for initial development efforts.
    All told, this represents approximately 3 trillion barrels 
of remaining undeveloped oil resource in the U.S., with perhaps 
600 billion barrels technically recoverable, if not yet 
economic.
    Again, to put this in some context, according to the U.S. 
Geological Survey, current estimated recoverable oil reserves 
worldwide total about 2.3 trillion barrels. This includes the 
vast reserves in the Middle East and the former Soviet Union, 
and the recoverable proportion of the massive heavy oil and oil 
sands deposits in Canada and in Venezuela.
    In this light, the U.S. petroleum industry faces the 
challenge of developing and utilizing new concepts and 
technology for economically producing these challenging and 
more costly remaining domestic oil resources.
    Now let me focus more explicitly on just two of the 
categories of domestic oil resources that are the topic of 
today's hearing: heavy oil and oil sands. The U.S. still has 
very large volumes of undeveloped heavy oil and oil sands--
sometimes called ``tar sands''--estimated at about 180 billion 
barrels originally in place. Of this, about 100 billion barrels 
exist in heavy oil reservoirs, with another 80 billion barrels 
in oil sand prospects. However, unlike oil shale, this resource 
is quite geographically dispersed; located in California, 
Alaska, Utah, Alabama, Texas, Wyoming, Arkansas, Kentucky, 
Louisiana, Mississippi, and Missouri.
    Application of thermal enhanced oil recovery technology, 
particularly steam injection, has enabled the U.S. industry to 
already recover and produce a significant portion of the 
domestic heavy oil resource from the geologically most 
favorable, shallow portion of the resource base, primarily in 
California and Alaska.
    For example, in 2003, heavy oil production in California 
provided over 500,000 barrels of production per day; and Alaska 
produced 27,000 barrels per day. To date, we have recovered 
about 17 billion barrels of heavy oil, with about 2 billion 
barrels remaining in proved economic reserves.
    However, despite these impressive efforts by industry, the 
great bulk--over 160 billion barrels of this resource--is not 
recoverable with today's technology. But based on our past 
work, we estimate that with--another 30 billion barrels could 
become technically recoverable with modest advances in oil 
recovery technology.
    An important characteristic of heavy oil and bitumen oil 
sands is that nature, over geologic time and with heat and 
pressure, has already converted these resources from a 
geologically immature hydrocarbon in the source rock, such as 
kerogen in oil shale, to crude oil. As such, compared to oil 
shale, nature has taken care of half of the challenge.
    Still, because of its high viscosity, the remaining heavy 
oil and oil sand resource is essentially immobile. Injection of 
heat or solvents, or the direct mining of the resource, is 
still required to efficiently recover and produce the heavy oil 
and tar sands.
    Given their relative development challenges, however, and 
also their likely timing of potential future contribution to 
domestic supplies, a prudent technology development strategy 
would be one that focuses on the commercial production of, 
first, heavy oil, then oil sands, and then oil shale.
    The introduction of advanced heavy oil and oil sands 
technology, including technologies such as horizontal wells and 
CO2-based enhanced oil recovery technologies, could provide a 
valuable first start. In addition, adaptation of new 
technologies being tested and applied in Canada could help 
further unlock the domestic heavy oil and oil sands potential.
    Of particular value would be the development and 
introduction of state-of-the-art, zero-emission heavy oil and 
oil sands recovery processes that could productively use the 
byproduct CO2 that would otherwise be emitted to the 
atmosphere. Not only would this achieve a positive net energy 
balance and increase domestic production, but it would provide 
one more market-based technology option to encourage reducing 
CO2 emissions to the atmosphere.
    Several steps could be taken to help overcome the barriers 
currently facing the development of domestic heavy oil and oil 
sands resources:
    First, reduce current geological, technical, and economic 
risks through an aggressive program of research and field 
tests. Optimizing performance of current heavy oil and oil 
sands recovery practices and expanding their application will 
help overcome these current risks posed by these technologies.
    State-Federal partnerships devoted to technology transfer 
could also help address these barriers that currently inhibit 
the application of these technologies. Also, engaging in 
collaborative Canadian-U.S. efforts, such as sharing technology 
and conducting joint-funded field research, could help 
facilitate application of the best technologies appropriate for 
all North American heavy oil and oil sands resources.
    Second, invest in new technology development that could 
lead to higher oil recovery efficiencies and reduced costs. New 
models of public-private partnerships focused on developing 
domestic oil resources could enable the launching of key field 
projects to demonstrate higher oil recovery concepts and 
advanced technologies, along with the zero-emissions recovery 
processes that I mentioned.
    Third, provide risk mitigation incentives to mitigate the 
impacts of potential drops in oil prices for those producers 
willing to try new technologies. At the Federal level, recent 
modifications proposed for the Section 43 EOR tax credit could 
help accomplish this, as could royalty relief for resources 
underlying Federal lands.
    Finally, update the data and information base on domestic 
heavy oil and oil sands. The initial studies of the domestic 
heavy oil and oil sands--the ones still used today by Congress 
and other energy policymakers and those quoted today in this 
testimony--were prepared by my co-author and me for the 
Interstate Oil and Gas Compact Commission nearly 20 years ago. 
Since then, much has been learned about the domestic resource 
base, and significant advances in heavy oil and oil sands 
extraction technology have taken place.
    An up-to-date resource and technology study on domestic 
heavy oil and oil sands could provide insights on formulating 
policies, initiatives, and technology, for more effectively and 
efficiently and economically developing this large domestic oil 
resource.
    With these actions, heavy oil and oil sands could provide 
an additional 500,000 barrels per day of U.S. production within 
ten years; an additional 1 to 1-1/2 million barrels a day by 
2025, particularly from Alaska, California, Texas, Utah, and 
Wyoming.
    Thank you very much for providing me the opportunity to 
testify before the Subcommittee today.
    [The prepared statement of Mr. Godec follows:]

  Statement of Vello A. Kuuskraa ([email protected]), President, 
Michael Godec ([email protected]), Vice President, Advanced Resources 
                          International, Inc.

    Good afternoon. I am pleased to address the House Subcommittee on 
Energy and Resources on the topic of increasing future domestic oil 
production from oil shale, oil sands, and heavy oils.
    Our nation's oil basins are mature and in decline. In the past 20 
years, domestic oil production has dropped by 3 million barrels per 
day, while demand for oil has continued to grow. As a result, imports 
now provide 60% of the oil consumed in the U.S., with serious 
implications for energy security. In fact, in his recent national 
address on energy, President Bush stated: ``Our dependence on foreign 
energy is like a foreign tax on the American people. It is a tax our 
citizens pay every day in higher gasoline prices and higher costs to 
heat and cool their homes. It's a tax on jobs and a tax that is 
increasing every year.''
    However, the problem of declining domestic oil production is not 
due to a lack of domestic resources. Not including domestic oil shale 
resources, which others testifying today can address more effectively 
than I, undeveloped domestic oil resources in the ground (in-place) in 
the U.S. still total over 1,000 billion barrels. These resources 
include undiscovered conventional onshore and offshore oil; future 
growth of already discovered oil fields (``reserve growth''); 
``stranded'' light oil resources amenable to carbon dioxide enhanced 
oil recovery (CO2-EOR) technologies; shallow and deep heavy oil 
amenable to thermal and other EOR technologies; residual oil in 
transition zones; and oil sands. These domestic resources could provide 
an additional 400 billion barrels of future technically recoverable 
oil, as shown in Table 1. The U.S. petroleum industry, as the leader in 
applying exploitation and EOR technology, faces the challenge of 
developing technology for economically producing this more 
challenging--and more costly--remaining domestic oil resource.
    Now, let me focus more explicitly on two of the categories of 
domestic oil resources that are the topic of today's hearing--heavy oil 
and oil sands. The U.S. still has very large volumes of undeveloped 
heavy oil and oil sands (sometimes called ``tar sands''), estimated at 
180 billion barrels originally in-place. Of this, about 100 billion 
barrels exists in heavy oil reservoirs, with another 80 billion barrels 
in oil sands prospects. However, unlike oil shale, this resource, is 
geographically quite dispersed, located in California (47 billion 
barrels), Alaska (44 billion barrels), Utah (19 to 32 billion barrels), 
Alabama, Texas and Wyoming (each with 5 to 6 billion barrels), and 
numerous other states such as Arkansas, Kentucky, Louisiana, 
Mississippi and Missouri, 

[GRAPHIC] [TIFF OMITTED] T2327.001


    Application of thermal enhanced oil recovery (EOR), particularly 
steam injection, has enabled industry to recover and produce a portion 
of the domestic heavy oil resource, from the geologically most 
favorable, shallow portion of the resource base, primarily in 
California and Alaska. For example, heavy oil production in California 
provided 510,000 barrels per day, and in Alaska provided 27, 000 
barrels per day (both in 2003). While heavy oil production has been 
declining in California, it is counterbalanced, somewhat by increasing 
production in Alaska, Figure 2. To date, we have recovered 17 billion 
barrels of heavy oil, with 2 billion barrels in proved reserves.
    In spite of impressive efforts by industry, the great bulk over 160 
billion barrels of the resource in deep heavy oil reservoirs and in oil 
sands is not recoverable with today's oil recovery technology. Based on 
our past work, we estimate that another 30 billion barrels could become 
technically recoverable with advances in oil recovery technology.

[GRAPHIC] [TIFF OMITTED] T2327.002

[GRAPHIC] [TIFF OMITTED] T2327.003


    An important characteristic of heavy oil and the bitumen in oil 
sands is that nature, over geologic time and with heat and pressure, 
has already converted these resources from immature source rock, such 
as kerogen in oil shale, to a crude oil. As such, compared to oil 
shale, nature has taken care of half of the challenge. Still, because 
of its high viscosity (low API gravity), the remaining heavy oil and 
oil sand resource is essentially immobile. Injection of heat or 
solvents, or the direct mining of the resource, is required to 
efficiently recover and produce crude oil from heavy oil and oil sands. 
Given the challenge, a prudent technology development strategy would be 
to first address heavy oil, then oil sands, and then oil shale.
    Introduction of advanced heavy oil and oil sands technology, 
including technologies such as horizontal wells and CO2-based enhanced 
oil recovery technologies, would provide a valuable start. In addition, 
adaptation of new technologies being tested in Canada, such as SAGD 
(steam assisted gravity drainage), VAPEX (the use of a combination of 
solvent and heat), and the ``top down combustion'' process, could help 
further unlocking the domestic heavy oil and oil sands resource 
potential.
    Of particular value would be the development and introduction of 
state-of-the-art ``zero emission'' heavy oil and oil sands recovery 
processes, which could involve an upgrading and refining system 
involving gasification of heavy oil residue to produce steam, hydrogen, 
and electricity, while productively using the by-product CO2 that would 
otherwise be emitted to the atmosphere for recovery of deep heavy oil. 
Not only would this achieve a positive energy balance, but it would 
provide one more ``market-based'' technology option for reducing CO2 
emissions to the atmosphere.
    Several steps could be taken to overcome the barriers currently 
facing the development of domestic heavy oil and oil sand resources:
      Reducing current geological, technical, and economic 
risks could be accomplished through an aggressive program of research 
and field tests. Optimizing the performance of current heavy oil and 
oil sands recovery practices and expanding its application will help 
lower the geological, technical, and economic risks involved with these 
enhanced oil recovery technologies. This was the pathway used by the 
DOE and the Gas Research Institute to reduce geologic and technical 
risks which helped commercialize domestic unconventional gas, that now 
accounts for over one-third of domestic natural gas production. State-
Federal partnerships devoted to technology transfer would help address 
the barriers that currently inhibit the development and production of 
domestic heavy oil and oil sands. Also, engaging in collaborative 
Canadian/U.S. efforts such as sharing technology and conducting 
jointly-funded field R&D on oil sands and heavy oil could help 
facilitate application of the best technologies appropriate for U.S. 
heavy oil and oil sands resources.
      Investments in new technology development would lead to 
higher oil recovery efficiencies. New models of public-private 
partnerships focused on developing domestic oil resources could enable 
the launching of key field projects to demonstrate higher oil recovery 
concepts and advanced technologies. Moreover, demonstrating an 
integrated ``zero emissions'' steam, hydrogen and electricity 
generation system, that provides ``EOR-Ready'' CO2 from the residue 
products from heavy oil and oil sand upgrading and refining, would 
provide an efficient approach toward future oil recovery.
      Providing ``risk-mitigation'' incentives to provide 
protection against sharp drops in oil prices for those producers 
willing to try new technologies. At the Federal level, recent 
modifications proposed for the Section 43 EOR tax credits could help 
accomplish this, as could royalty relief for resources underlying 
Federal lands. At the state level, severance tax relief could also help 
provide risk mitigation incentives.
      Update the data and information base on domestic heavy 
oil and oil sands. The initial studies of domestic heavy oil and oil 
sands, and the ones still used by Congress and other energy policy 
makers, and those quoted today in this testimony, were prepared by the 
two authors of this Congressional Testimony for the Interstate Oil and 
Gas Compact Commission (IOGCC) nearly 20 years ago. Since these past 
studies were conducted, much has been learned about the resource base, 
and significant advances in heavy oil and oil sands extraction 
technology has taken place. An up-to-date resource and technology study 
on domestic heavy oil and oil sands could provide insights on 
formulating policies, initiatives and technology for more effectively 
developing this large oil resource, helping increase domestic oil 
production.
    With these actions, domestic heavy oil and oil sands could provide 
an additional 500,000 barrels per day of production in ten years, and 
an additional 1 to 1.5 million barrels per day of domestic oil 
production by 2025, particularly from Alaska, California, Texas, Utah 
and Wyoming.
    Thank you very much for providing us with the opportunity to 
testify before this subcommittee today.
                                 ______
                                 

 Response to Questions submitted for the record by Michael Godec. Vice 
           President, Advanced Resources International, Inc.

1.  Am I correct in understanding your testimony to be that not 
        counting oil shale, the United States still has one trillion, 
        one hundred thirty billion barrels of oil in the ground?
    Based on data published by the U.S. Geological Survey (USGS) and 
Minerals Management Service (MMS), 570 billion barrels of oil in the 
ground exist in undiscovered conventional oil fields and from the 
future growth of already discovered oil fields (``reserve growth''), 
assuming traditional oil recovery efficiency.
    Adding the ``stranded'' light oil resources in discovered fields 
amenable to CO2 enhanced oil recovery (CO2-EOR); shallow and deep heavy 
oil fields amenable to thermal and other EOR; residual oil in 
transition zones; and domestic oil sands together provide another 554 
billion barrels of resource in the ground.
    The sum of these two is one trillion, one hundred twenty four 
billion barrels of oil in the ground. (This represents a slight 
modification to the preliminary numbers submitted in our original 
testimony, which used rounded numbers.) All of these estimates are 
based on existing resource studies, as summarized (with citations) in 
Table 1.

2.   Am I further correct in understanding that you believe that at 
        least 400 billion barrels of this oil should be able to be 
        produced?
    That is correct. We estimate that these domestic resources could 
provide an additional 400 billion barrels of future technically 
recoverable oil, again as shown in Table 1. This does not imply that 
all of this is currently economic to produce, even at today's oil 
prices. This estimate includes 190 billion barrels of technically 
recoverable resources, using conventional technology, and 210 billion 
barrels of oil recovery from ``state-of-the-art'' EOR technology. 
Moreover, the EOR recoverable numbers would be significantly higher 
should technology progress occur for EOR.

3.  Do these numbers include any increases for anticipated reserve 
        growth?
    Yes, as described in my answer to Question No. 1, the 1,124 billion 
barrels of undeveloped resources in the ground include the anticipated 
growth of reserves in conventional oil fields.

[GRAPHIC] [TIFF OMITTED] T2327.016


4.  Are there any significant differences, other than quantity, between 
        the U.S. oil sands and the Alberta oil sands?
    Alberta oil sands are ``water wet'' while the U.S. oil sands are 
``oil wet'', making the extraction of Albert oil sands considerably 
simpler. In addition, Alberta oil sands, on average, tend to be a 
richer (in terms of barrels of resource per acre). Nonetheless, there 
are some deposits in the U.S. that are of comparable quality to some of 
the best deposits in Alberta.
    We believe much can be learned from cooperating with Canada on 
their pursuit of advanced oil sand extraction technology, particularly 
for new in situ oil sand recovery technology.

5.  Please prioritize the things that the Federal Government can do to 
        ensure that at least the 400 billion barrels of oil are 
        produced.
    The Federal Government, could, in priority order: (1) help reduce 
the financial barriers associated with applying ``state-of-the-art'' 
exploration and production technologies through an aggressive program 
of field demonstrations and ``risk mitigation'' actions and incentives 
to encourage industry investments, (2) encourage increased private R&D 
investment and/or provide direct Federal R&D focused on developing new, 
``next generation'' technologies that further improve the efficiency 
and reduce the costs of pursuing U.S. undeveloped oil resources; and 
(3) update the data and information base on domestic heavy oil and oil 
sands. Please see further elaboration in our answer to Question 7 
below.

6.  Looking at the whole range of extra heavy oils and tar sands you 
        cite in your testimony, what do you see as the principal 
        factors impeding development? How would you prioritize 
        attention among these resources and why?
    Pursuing undeveloped domestic extra heavy oil and oil sands pose 
considerable economic risks and technical challenges. The risks and 
challenges stem from a lack of information on the actual geologic 
condition of the remaining resource (e.g., the distribution and 
saturation of the residual oil in the reservoir's pore space), 
uncertainties on how well oil recovery technology (often adapted from 
other settings) will perform in a new geologic setting or basin, and 
the inherent volatility and uncertainty surrounding world oil prices. 
To date, this combination of geologic, technical and economic risks 
have posed severe barriers to the full development of the remaining 
domestic oil resource base, particularly for deep heavy oil and oil 
sands.
    As stated in my oral testimony, an important characteristic of 
heavy oil and oil sands is that nature, over geologic time and with 
heat and pressure, has already converted these resources from a 
geologically immature hydrocarbon in the source rock, such as kerogen 
in oil shale, to a crude oil. Compared to oil shale, nature has taken 
care of half of the challenge. As such, a prudent technology 
development strategy would be one that pursues commercial production of 
first heavy oil, then oil sands, and then oil shale.

7.  What is your view regarding the future of unconventional liquid 
        fuels, vs. conventional petroleum, i.e. what needs to happen 
        before these unconventional oils attract investment? How do you 
        see heavy oil and tar sands developing over the next 20 years?
    In my testimony, I stated that the Federal Government could take a 
series of actions to overcome the barriers currently impeding the 
development of domestic heavy oil and oil sands resources.
      First, reduce current geological, technical, and economic 
risks through an aggressive program of field tests and technology 
transfer. State-Federal partnerships devoted to field tests and 
technology transfer would help address the barriers that currently 
inhibit the application of these technologies. Also, engaging in 
collaborative Canadian/U.S. efforts, such as sharing technology and 
conducting jointly-funded field R&D on oil sands and heavy oil, could 
keep developing new technologies appropriate for all North American 
heavy oil and oil sands.
      Second, invest in research and new technology development 
toward higher oil recovery efficiencies and reduced costs. New models 
of public-private partnerships, focused on developing ``next 
generation'' oil recovery technologies and launching key field projects 
to demonstrate these higher oil recovery technologies, would be most 
important.
      Third, provide ``risk-mitigation'' incentives to mitigate 
the impacts of potential future decline in oil prices for those 
producers willing to try new technologies. At the Federal level, recent 
modifications proposed for the Section 43 EOR tax credit could help 
accomplish this, as would royalty relief for resources underlying 
Federal lands. At the state level, severance tax relief would also 
provide risk mitigation incentives.
      Finally, update the data and information base on domestic 
heavy oil and oil sands. In the last 20 years, much has been learned 
about the domestic resource base, and significant advances in heavy oil 
and oil sands extraction technology have taken place. An up-to-date 
resource and technology study on domestic heavy oil and oil sands could 
provide insights on formulating policies, initiatives and technology 
for more effectively developing this large oil resource.
    With these actions, domestic heavy oil and oil sands could provide 
up to an additional 500,000 barrels per day of U.S. production in ten 
years, and an additional 1 million barrels per day by 2025, 
particularly from Alaska, California, Texas, Utah and Wyoming. Without 
these actions, the contribution of domestic heavy oil and oil sands to 
U.S. energy supplies will grow at a substantially slower rate, if at 
all.

                               * * * * *

    In closing, I want to note that our biggest undeveloped oil 
resources ``prize'' will be from applying advanced EOR technology to 
our undeveloped domestic oil resources.
    In the preceding paragraph we set forth the oil production that 
would be realized from heavy oil and oil sands (up to 0.5 million 
barrels per day in 2015 and 1 million barrels per day in 2025). 
Pursuing the rest of undeveloped domestic oil (the light oil left 
behind after conventional oil recovery) with CO2-EOR would add an 
additional 1.5 million barrels per day by 2015 and 2.5 million barrels 
per day in 2025. (These projections of future domestic oil production 
assume that the recommend actions set forth in response to Questions 5, 
6 and 7 are successfully implemented.)
    Together, these undeveloped resources could make a most significant 
reduction in our future levels of oil imports and a most valuable 
addition to our economic and energy security.
                                 ______
                                 
    Mr. Gibbons. Thank you very much, Mr. Godec.
    We turn now to Mr. Jack Savage, President and CEO, Oil-
Tech, Incorporated. Mr. Savage, welcome here. We look forward 
to your testimony.

         STATEMENT OF JACK SAVAGE, PRESIDENT AND CEO, 
                         OIL-TECH, INC.

    Mr. Savage. Thank you, and good morning, Mr. Chairman and 
distinguished members of the Committee. My name is Jack Savage. 
I am chief executive officer of a small, startup company in 
Utah, Oil-Tech, Incorporated. I am pleased to have been asked 
to participate in this hearing and discuss this very important 
natural resource--resources--of oil shale and oil sands.
    You know, there is much negativity associated with failures 
of the past, when companies back in the '70s and '80s attempted 
to commercialize shale oil. I think that when we talk about 
failure, sometimes we can refer to that as ``succ-ailure.'' We 
appreciate very much the pioneer companies who have gone before 
and who identified the problems that prevented them from 
commercializing shale oil. And it must be said that everyone 
who tried to make oil from oil shale was successful; they just 
didn't do it economically.
    We have been able to take those identified problems, and 
solve them one by one. So we are grateful for those who went 
before. May I be so bold as to suggest that if ``Black Sunday'' 
had not occurred, if industry had continued to pursue the 
commercialization of shale oil, this Nation might possibly not 
be in the foreign-oil-dependent situation that we're in today.
    We began in 1993, as a predecessor to the current Oil-Tech 
company, to work on these identified problems and solve them 
one by one. I must emphasize that Oil-Tech is complete with the 
research and development aspect of our project. We are prepared 
and ready to enter into a commercial venture to produce 
economically shale oil for commercial use.
    I would also say that in doing so, Oil-Tech has never 
requested--neither have we received--one dime from either state 
or Federal Governments. The funding for Oil-Tech has been 
handled completely by qualified, high-net-worth individuals.
    The oil shale deposit that has been referred to this 
morning is contained on about 5-1/2 million acres. And this 
tract of oil shale ground is located in the areas comprised of 
southern Wyoming, eastern Utah, and western Colorado. It is 
estimated, as has been said, that there is in excess of 3 
trillion tons of oil shale in that area, from which it is 
estimated somewhere between 2 to 3 trillion barrels of oil 
could be recovered.
    This land that we refer to is--approximately 80 percent of 
it is owned by the Federal Government. The next largest 
landowner would be state governments; and the Indian tribes own 
some of the ground; and then there's some privately owned 
ground.
    The technology that Oil-Tech has, and which I will present, 
has been independently validated by two reputable engineering 
firms--one out of Billings, Montana; one out of Tulsa, 
Oklahoma. Those validations concern our representations of 
process efficiency, cost-per-barrel, and feasibility of up-
sizing from a small commercial retort now in operation to a 
full-size, large commercial retort.
    Our current, small-capacity retort and operation in eastern 
Utah is full-sized on the vertical scale, compared to a full 
producing commercial retort unit. This is not a laboratory 
model. We felt we had to build a full-sized scale model to 
validate the process and the feasibility and the economies of 
producing oil from shale. All we would need to do would be to 
increase the footprint, or the diameter size of the retort, to 
allow more rock capacity to cook in the retort at a given time.
    The retort is modular by design. It can be assembled and 
dismantled very quickly, and moved just as easily as a drilling 
rig in conventional oil processing could be implemented and 
removed.
    The cost of our 1,000-barrel-per-day retort is indirect--is 
relative to the cost of drilling a well in the Rocky Mountain 
area, and equipping the same with the proper equipment.
    A 1,000-barrel-per-day retort design was chosen by us as 
the most feasible relative to capital cost requirements and 
productivity. If we want to produce 20,000 barrels of oil per 
day, we simply cluster 20 1,000-barrel-per-day units. And as I 
said, they are very mobile and they can be moved from one area 
to another area within a week's time, when a particular area 
might be mined out. This is a mining material-handling problem. 
And the build-out of surface retorts would be done so in 
conjunction with the build-out of an underground mine 
situation.
    I see my time is up, and I will just conclude here quickly 
by saying that we use very little energy in producing the 
potential energy of the shale oil. One thing that I learned as 
a young boy, that when trying to absorb teachings it was much 
easier to do so when there was a visual aide present. And I 
have made an assumption that you can also learn more quickly by 
looking at a visual aide, rather than listening to me. And I've 
made available these little display units which, hopefully, 
you'll display on your desk.
    There's a piece of oil shale. A lot of people don't know 
what oil shale is. And then the little vials represent the 
different stages of the shale through the process; and then the 
different products that are created thereby.
    I would just end by inviting each of you, individually or 
together as a committee, to come to Utah and visit our site and 
let us--bring your canteens; we'll fill them with shale oil. 
And we'd be happy to host you. Thank you very much for your 
time.
    [The prepared statement of Mr. Savage follows:]

         Statement of Jack S. Savage, President, Oil-Tech, Inc.

OIL-TECH: THE COMPANY
    Oil-Tech, Inc. was incorporated in the State of Utah in February 
2000. Oil-Tech (OT/the Company) is current in meeting all state 
regulations and requirements and is considered a corporation of good 
standing. OT is a nonoperating company which has just completed its 
research and development project, has received independent validation 
of its representations as to its ability to produce oil from oil shale, 
cost per barrel, feasibility of up sizing to full commercial scale, 
efficiency of process, etc. Patents have been filed with the U.S. 
Patent Office, the Patent Cooperation Treaty (PCT) and the country of 
Jordan.
    OT is a privately held Utah corporation formed exclusively to 
complete the research and development and refinement of patent pending 
technology which has its roots back to the year 1993. OT's intended 
purpose is to be an operating entity for the mining of oil shale and 
the production of shale oil on leased oil shale acreage currently held 
by the Company in order to capitalize on the Company's patent pending 
shale oil production technology.

MARKET SUPPLY AND DEMAND
    According to the World Energy Council, the largest oil shale 
reserves occur in the United States in an area of 5.5 million acres 
covering northeastern Utah, northwestern Colorado and southern Wyoming. 
It is estimated that this area contains approximately 3.3 trillion 
tons, or two-thirds of the worlds's potentially recoverable oil shale 
resource. This same resource is estimated to be capable of producing 
more than 2.5 trillion barrels of recoverable shale oil. These reserves 
contain potential oil supplies that would completely meet the United 
States' energy demands for the next several hundred years.
    The oil demand in the United States is approximately 20 million 
barrels per day with a major portion of all consumption, both crude and 
finished product, currently imported at a cost of over $150 billion per 
year, amounting to the largest single element of the United States 
trade deficit.
    United States crude oil production capacity is estimated at 5.5 
million barrels per day (mbd) from approximately 533,000 oil wells, 
averaging less than 12 barrels per well per day.

OIL-TECH ADVANTAGES
    To the best of the Company's knowledge, no other entity has a 
technological or economic advantage or has developed oil shale 
technology to the level that Oil-Tech has reached. Dr. Anton Damer of 
the Department of Energy believes OT to be 10 years ahead of any other 
company engaged in the commercialization of shale oil. Dr. James 
Bunger, consultant to the Department of Energy on oil shale matters 
believes OT to be the leader in surface oil shale retort technology.

OIL-TECH'S TECHNOLOGY AND ASSOCIATED PROCESSES
    The Company currently operates a small capacity, commercial retort 
in eastern Utah, approximately 40 miles southeast of Vernal, Utah. The 
retort has a capacity to process one ton of oil shale per hour. On 
average, one ton of oil shale will produce one barrel of shale oil. The 
proprietary retort produces 30 degree API gravity oil with a pour point 
of 53 degrees Fahrenheit. When the nitrogen compounds are removed from 
the shale oil, the resulting product is very close to JP-8 fuel. The 
refinery ready crude is comprised of approximately 10% Naphtha, 40% 
Kerosene, 40% diesel and 10% heavy residual gas oil. The entire blend 
is low in sulfur.
    The Company's existing, small capacity commercial retort was 
designed and fabricated to be full scale vertically. Full, commercial 
size on the vertical scale is essential to enable sufficient 
``soaking'' time of the oil shale in the retort produced heat. A less 
than full size laboratory model would be insufficient to prove the 
methodology of OT's proprietary technology. To move to a full capacity 
(1,000 barrel per day) commercial retort, increasing the size of the 
``foot print'' and adding additional heaters is all that remains. Up 
sizing to the full commercial scale of 1,000 barrels per day with 
anticipation of equal or enhanced results of the current operating 
model has been validated by the independent engineering firms of 
Unifield Engineering, Billings, Montana, and Tulsa Combustion, LC, of 
Tulsa, Oklahoma.
    The proprietary retort is modular by design. One full capacity 
commercial retort can be assembled and/or disassembled as quickly and 
easily as a standard drilling rig. Accordingly, it is easy and cost 
efficient to move these portable retorts when an area of oil shale has 
been mined out.
    The 1,000 barrel per day capacity retort was designed as such to be 
economical in the fabrication process (approximately $2 million for 
each retort), to be portable and any number of retorts can be mass 
manufactured and clustered together to, in combination, process the 
daily tonnage capacity of any given mine. For example, if the desired 
oil production is 20,000 barrels per day, 20 1,000 barrel per day 
retorts will be clustered together to reach the desired production 
rate. Additionally, if one retort is shut down for repair or service, 
19,000 barrels of oil are still being produced. Conversely, with a 
single, highly capital intensive 10,000 barrel per day retort, if shut 
down for service or repair, the loss of oil production is much more 
significant.
    Contrary to some oil shale processes, the Company's proprietary 
technology utilizes very little purchased energy to manufacture shale 
oil. Initially, the oil shale is heated electrically. After 
approximately 6 hours of operation, there is sufficient ``spent'' shale 
to enable co-generation. The spent shale exits the retort at 
approximately 1,000 degrees Fahrenheit. Fixed carbon remains in the 
spent shale and is combustible with the addition of air. The 
temperature of the spent shale is then raised to approximately 2,500 
degrees Fahrenheit. This is a sufficient heat source to enable 
purchased electrical power to be turned off and new oil shale to be 
adequately heated with direct heat from the spent shale. Every 60 
minutes approximately 41 tons of 2,500 degree spent shale is produced. 
This is an impressive thermal mass, to say the least. Heat is available 
for generating steam, heating refinery feeds, generating electricity, 
etc.
    Per barrel of oil production/retorting cost is $8.00 per barrel 
when utilizing purchased electrical heat and decreases dramatically to 
$4.00 per barrel when using co-generated heat. This per barrel of oil 
cost considers only the retorting costs and does not consider the 
mining costs. Mining costs range from $5.60 per ton of oil shale mined 
to $22.00 per ton depending on the development stage of the mine and 
the type of equipment utilized. Accordingly, OT's technology and 
processes can produce one barrel of shale oil at approximately $9.60 
per barrel in the best case scenario and approximately $30.00 per 
barrel in the worst case scenario.
    The Oil-Tech technology is environmentally friendly. The retort is 
an oxygen free, sealed unit under vacuum. No gases are deployed to the 
atmosphere. In fact, the only non-condensed gas produced is propane. 
This gas is captured, processed and is then marketable. OT would be the 
most environmentally friendly operation in the eastern Utah oil shale 
area which is already dotted with oil and gas wells, transportation 
pipes on the earth's surface, open, mined out, abandoned gilsonite 
veins, abandoned structures, etc.

DISPELLING THE MYTHS
    For many years, individuals and companies have wrestled with 
producing oil from oil shale. Along with this knowledge, several myths 
evolved explaining why the production of oil from shale is seemingly 
``impossible.'' These myths can be found through any Internet search. 
Previous efforts have significantly assisted Oil-Tech in attempting to 
overcome earlier identified problems. These out-of-date ``facts'' are 
dispelled by the Oil-Tech technology and development plans.
    There is oil in oil shale...UNTRUE--there is no oil in oil shale, 
only organic material. The Oil-Tech process vaporizes this organic 
material and condenses this vapor into shale oil.
    The process requires huge volumes of water...UNTRUE--past efforts 
used water to transport a shale oil ``slush'' through pipelines to a 
central processing center. The Oil-Tech technology processes oil shale 
on site and does not require water in the process. There is a nitrogen 
compound removal on site to separate the refinery feedstock from the 
asphalt additive, and water is not required in this process. Water is 
required for personnel and safety use (showers, potable water, fire 
suppression), and for mining operations, most of which is recyclable.
    The oil shale mining costs are excessive...UNTRUE--mining is indeed 
required. In the last 15 years, the technology of mining has 
dramatically changed and the cost of large scale mining operations has 
dropped from $20 to $25 per ton of material produced, to as low as $6 
per ton, depending on depth of the mining operation. The longwall and 
continuous mining technologies are key to these better economics. The 
technologies were not available during the last period of heavy 
research and the attempted production of oil from oil shale.
    Mining is environmentally disastrous...UNTRUE--with longwall and 
continuous mining technologies, very little evidence of the operation 
exists above ground and the techniques allow for an easy and acceptable 
reclamation of the surface when operations are complete.
    The technology of producing oil from oil shale is highly 
polluting...UNTRUE--the Oil-Tech process is completely contained, with 
no harmful emissions to the atmosphere. All products from the process 
are utilized within the sealed system. Even the leftover spent shale 
has the qualities of desiccated charcoal which is used in many ways to 
absorb pollutants.
    It is not economically feasible to produce oil from shale because 
of the capital required...UNTRUE--early attempts by other required 
heavy capital expenditures on huge facilities based on the alleged 
benefits of economies of scale. The Oil-Tech process reverses that 
trend and uses smaller, easily replicated and fabricated modular units. 
These may be easily transported and assembled on site, or disassembled 
for movement to another location. Any operational/service problems do 
not disrupt production by more than a minimal percentage.
    It is not economically feasible to produce oil from shale because 
of the energy required...UNTRUE--the Oil-Tech process has been 
validated to produce shale oil with a very low energy cost. The system 
can also be upgraded by utilizing co-generation and a variety of BTU 
recovery technologies that virtually eliminate the need for external 
power for any site operations.
    Transportation of the product is prohibitively expensive...UNTRUE--
this statement is based on the idea piping shale oil sludge to various 
processing centers, involving pipelines, pumping facilities and rights-
of-way disputes. It also was based on shipping raw shale oil to 
potential refining centers for pre-processing prior to normal refinery 
operation. The Oil-Tech process does not need to transport shale sludge 
or raw shale oil to a refinery based pre-processing center. Refinery 
grade feedstock is either transported in tanker trucks or injected into 
a local pipeline. The asphalt additive is easily transported with 
heated tanker trucks. On sites where the nitrogen extraction process 
will not be available, the shale oil is easily transported in tanker 
trucks.

OIL-TECH HAS COMPLETED R & D
    It is important to understand that the Oil-Tech technology has met 
the standards of independent validating engineering firms and is now 
poised to begin commercialization of shale oil. From the point of 
receiving required capital investment, Oil-Tech can be producing 1,000 
barrels of shale oil within 12 months. Production will be at 20,000 
barrels of shale oil per day at the end of a 36 month period.

INVITATION
    Oil-Tech invites any and all U.S. Congressmen/Congresswomen to 
visit the proprietary retort site near Vernal, Utah, and experience 
first hand the economical production of shale oil from our nation's 
vast supply of natural resource.
                                 ______
                                 
    Mr. Gibbons. Thank you very much, Mr. Savage. And I am sure 
that these little display items will generate a couple of 
questions for you later on. But we appreciate it, and it does 
help us immensely to have the visual aide before us.
    We turn now to Mr. Terry O'Connor, Vice President, External 
and Regulatory Affairs, Shell Unconventional Resources Energy. 
Mr. O'Connor, welcome. The floor is yours. We look forward to 
your testimony.

   STATEMENT OF TERRY O'CONNOR, VICE PRESIDENT, EXTERNAL AND 
   REGULATORY AFFAIRS, SHELL UNCONVENTIONAL RESOURCES ENERGY

    Mr. O'Connor. Good morning, Mr. Chairman and members of the 
Committee. I'm delighted to be here today to describe to you 
Shell's initiative to develop and advance--hopefully, to 
commercial success--a unique and innovative technology which we 
are increasingly optimistic can open up the vast oil shale 
resources of the Green River Basin of northwestern Colorado, 
eastern Utah, and southwestern Wyoming; which, as you have 
heard, contains an extraordinarily large quantity of 
potentially recoverable fossil fuels, both oil and gas.
    People talk about does it have a trillion, or 1.6 trillion, 
or how much does it have. We don't know how much is out there, 
because it really depends upon the technological advances that 
occur over the coming years and decades. But we are quite aware 
that, when looked upon a global standpoint, roughly two-thirds 
of all of the oil shale located in the world today is located 
in this Green River Basin.
    And it roughly equates to all--if it's roughly a trillion 
barrels, which is a report that the Department of Energy put 
out last year on the strategic importance of oil shale, may 
very well represent at least as much as all the discovered and 
proven conventional oil resources in the world today.
    This Shell technology, which we call the ``In-Situ 
Conversion Process,'' or ICP as an acronym, we believe that 
once proven thoroughly through a next stage of development, 
should allow Shell to produce clean transportation fuels of 
gasoline, jet fuel, and diesel, as well as very environmentally 
clean natural gas, in an economically viable and 
environmentally sensitive manner.
    Let's talk a little bit about where we've been and where 
we're going for a moment. Some 23 years ago, in 1982--literally 
in the shadows of the unsuccessful efforts to develop oil shale 
in western Colorado and eastern Utah--Shell commenced 
laboratory work in its laboratories in Houston to determine 
whether this in-situ conversion process technology may have 
merit. We continued with this lab research for 14 years and, in 
1996, successfully carried out our first, very small-scale 
field experiment in Rio Blanco County, which is located about 
200 miles west of Denver.
    Shell has now successfully completed four more increasingly 
complex, but still rather small, integrated projects; the last 
of which I'd like to just take a few moments to talk about a 
little bit today, because we're rather excited about the 
results.
    We successfully produced about 1,400 barrels of oil and 
associated gas from a very small site that's probably half the 
size of this hearing room today, Mr. Chairman. And we were 
really excited about this; not only because we were able to 
produce this quantity of very light end oil and associated 
natural gas from such a small site, but we were able to produce 
it almost in perfect harmony with our expected modeling from a 
time, from a volume, and from a quality standpoint. This gives 
us sufficient confidence to move to what we hope will be our 
final oil shale test before hopefully making a decision by the 
end of this decade.
    With regard to the technology itself, literally, what we 
are doing is sort of the converse of what the retort 
technologies attempt; in that we take the heat to the rock, 
rather than bringing the rock to the heat.
    What does this mean? Well, literally, what it means is we 
drill quite a number of vertical holes--not very large; about 
the size of a softball--vertically down into the oil shale; and 
we drop down electric heaters; and we slowly heat that sub-
surface resource over a period of two, three, or four years, up 
to the point when the resource itself reaches about 650 or 700 
degrees, at which time we're then able to recover the light end 
portion of this oil, as well as gas.
    And we recover about two-thirds light end oil, and about 
one-third gas. We recover it in extraordinarily high volumes. 
We currently estimate that with this technology we'll be able 
to recover somewhere in excess of a million barrels of product 
per acre, or somewhere approximately 1 billion barrels per 
square mile.
    Talking just for a moment about the environmental impacts 
of this--because this is something we're extraordinarily proud 
of and we're happy to talk about potential environmental 
effects--because the ICP process involves no mining, and thus 
creates no contaminated tailings, piles, or large waste 
disposal issues, our footprint is considerably smaller.
    It's easier to reclaim, from a surface standpoint. We use a 
lot less water. And as I indicated before, we're thus able to 
penetrate depths which other technologies may not be able to 
penetrate, and thicknesses. Some of those thicknesses of oil 
shale in the Piceance Basin of Colorado are in excess of 1,000-
foot thick. That's ideally suited for our type of technology, 
and that is a large part of the reason why we're able to get 
these extraordinarily large recoveries. It creates a smaller 
footprint because we're able to go into these thicker, deeper 
seams.
    And one of the issues from an environmental standpoint 
about which we are most proud is that we have developed a very 
robust system for protecting the ground water. This sounds a 
bit counter-intuitive, but before we heat the area that we are 
attempting to develop, we literally build an ice wall around 
the circumference of the area. Ice creates an impermeable 
substance, and we're able thus to be able to contain the area 
of impact. That results in the prevention of offsite ground 
water impacts, and allows for much more efficient and 
expeditious ground water clean-up after the process is 
completed.
    Moving on, I think it's relevant to point out that, while 
the United States--and particularly, the Green River Basin of 
Colorado, Utah, and Wyoming--are really the Saudi Arabia of oil 
shale, oil shale is nevertheless located in a number of other 
countries around the world. And in fact, four countries--
namely, Estonia, Brazil, China, and Australia--currently have 
ongoing R&D projects for oil shale, despite the fact that their 
oil shale resources are not nearly as concentrated, as rich, or 
as extensive. They're all being done with various degrees of 
public assistance.
    We think that the time has now come for the United States 
to join these other countries, to advance the technologies and 
develop commercially oil shale, as long as it can be done in an 
environmentally sensitive and economically feasible manner.
    In the interests of time, I'm not going to go into the 
specifics of several recommendations that we have submitted in 
our written testimony, but really would commend them to you for 
your proactive and favorable consideration.
    We do thank this Committee, this Subcommittee, the full 
Resources Committee, and in fact the House of Representatives, 
for including the first two of these recommendations in general 
terms in the energy bill which you passed a couple of months 
ago.
    I would also mention and thank the Bureau of Land 
Management, Department of Interior, because they just recently 
took a small but extraordinarily important step of finalizing a 
small research and development leasing program for oil shale. 
And they've really done a good job in advancing this as a first 
step. They need to now continue on toward commercialization in 
a rational manner.
    And I might also add that Secretary Norton today as we 
speak is at our site, viewing and being briefed on the aspects 
of our research and technology and where we're attempting to go 
strategically. And I, too, would invite the members of this 
Committee, individually or collectively, to come out and look 
at our ongoing research.
    In summary, we believe that the time has come for Congress 
and this Administration to conduct appropriately targeted 
legislative and regulatory measures to advance responsible oil 
shale development in this country. And we're increasingly 
encouraged that the Shell in-situ conversion process may very 
well be the first available technology to do so on a commercial 
basis. Thank you very much.
    [The prepared statement of Mr. O'Connor follows:]

Statement of Terry O'Connor, Vice President of External and Regulatory 
             Affairs, Shell Unconventional Resources Energy

    Good morning Mr. Chairman and Members of the Energy and Mineral 
Resources Subcommittee:
    My name is Terry O'Connor. I am Vice President of External and 
Regulatory Affairs for the Shell Unconventional Resources unit of Shell 
Exploration and Production Company. I am delighted to appear before you 
today to describe Shell's initiative to develop and advance, hopefully 
to commercial success, a unique and innovative technology which we are 
increasingly optimistic can open up the vast oil shale resources in the 
Western United States. This technology, once thoroughly proven 
technically, will allow Shell to produce clean transportation fuels 
such as gasoline, jet fuel and diesel as well as clean burning natural 
gas from oil shale in an economically viable and very environmentally 
sensitive fashion. Because the oil shale resource in the United States 
is extensive, this technology holds promise for significantly 
increasing U.S. domestic energy production.
    For decades, energy companies have been trying, without success, to 
unlock the large domestic oil shale resources of northwestern Colorado, 
eastern Utah and southwestern Wyoming. Oil shale can be found in large 
parts of the Green River Basin and is over 1,000 feet thick in many 
areas. According to DOE estimates, the Basin contains in excess of 1 
trillion recoverable barrels of hydrocarbons locked up in the shale. It 
is thus easy to see why there have been so many attempts to unlock this 
potentially enormous resource in the past.
    Some 23 years ago, Shell commenced laboratory and field research on 
a promising in ground conversion and recovery process. This technology 
is called the In-situ Conversion Process, or ICP. In 1996, Shell 
successfully carried out its first small field test on its privately 
owned Mahogany property in Rio Blanco County, Colorado some 200 miles 
west of Denver. Since then, Shell has carried out four additional 
related field tests at nearby sites. The most recent test was carried 
out over the past several months and produced in excess of 1,400 
barrels of light oil plus associated gas from a very small test plot 
using the ICP technology. We are pleased with these results, not only 
because oil and gas was produced, but also because it was produced in 
quantity, quality and on schedule as predicted by our computer 
modeling. With this successful test, Shell is now ready to begin work 
on the final tests that will be required to prove the technology to the 
point where there is sufficient certainty so as to make a decision to 
proceed to commercial development.Most of the petroleum products we 
consume today are derived from conventional oil fields that produce oil 
and gas that have been naturally matured in the subsurface by being 
subjected to heat and pressure over very long periods of time. In 
general terms, the In-situ Conversion Process (ICP) accelerates this 
natural process of oil and gas maturation by literally tens of millions 
of years. This is accomplished by slow sub-surface heating of petroleum 
source rock containing kerogen, the precursor to oil and gas. This 
acceleration of natural processes is achieved by drilling holes into 
the resource, inserting electric resistance heaters into those heater 
holes and heating the subsurface to around 650-700F. over a 3 to 4 year 
period. During this time, very dense oil and gas is expelled from the 
kerogen and undergoes a series of changes. These changes include the 
shearing of lighter components from the dense carbon compounds, 
concentration of available hydrogen into these lighter compounds, and 
changing of phase of those lighter, more hydrogen rich compounds from 
liquid to gas. In gaseous phase, these lighter fractions are now far 
more mobile and can move in the subsurface through existing or induced 
fractures to conventional producing wells from which they are brought 
to the surface. The process results in the production of about 65 to 
70% of the original ``carbon'' in place in the subsurface. The carbon 
that does remain in the sub-surface resembles a char, is extremely 
hydrogen deficient and, if brought to the surface, would require 
extensive energy intensive upgrading and saturation with hydrogen. 
Chart 1 illustrates the ICP process.

[GRAPHIC] [TIFF OMITTED] T2327.004


    The ICP process is clearly energy intensive as its driving force is 
the injection of heat into the subsurface. However, for each unit of 
energy used to generate power to provide heat for the ICP process, when 
calculated on a life cycle basis, about 3.5 units of energy are 
produced and treated for sales to the consumer market. This energy 
efficiency compares favorably with many conventional heavy oil fields 
that for decades have used steam injection to help coax more oil out of 
the reservoir.
    The produced hydrocarbon mix is very different from traditional 
crude oils. It is much lighter and contains almost no heavy ends. Its 
quality can be controlled by changing the heating time, temperature and 
pressure in the sub-surface. The production mix generally seen from 
Colorado oil shale is about two thirds liquids and one-third natural 
gas and gas liquids such as propane and butane. On the liquid product 
side, the typical split encountered is about 30% each of a gasoline 
precursor called naphtha, jet fuel and diesel with the remaining 10% of 
the barrel being slightly heavier. These fractions can be easily 
transformed into finished products with significantly reduced 
processing when compared with traditional crude oils.
    Because the ICP process occurs below ground, special care must be 
taken to keep groundwater away from the process, as its influx would 
seriously reduce thermal efficiency. Special care must also be taken to 
keep the products of the process from escaping into groundwater flows. 
Shell has adapted a long recognized and established mining and 
construction ice wall technology to isolate the active ICP area and 
thus accomplish these objectives and to safe guard the environment. For 
years, freezing of groundwater to form a subsurface ice barrier has 
been used to isolate areas being tunneled and to reduce natural water 
flows into mines. Where groundwater intrusion is a problem in the ICP 
process, the subsurface surrounding the rich oil shale layers is frozen 
to form a container of sorts, thus preventing the influx of water while 
at the same time containing the products formed. Shell has successfully 
tested the freezing technology and determined that the development of a 
freeze wall prevents the loss of contaminants from the heated zone. 
During this same test, Shell was able to demonstrate that traditional 
subsurface reclamation technologies such as steam stripping, pumping 
and treating and carbon bed stripping were able to remove contaminants 
developed in the ICP process from the subsurface to levels sufficient 
to meet stringent permit requirements. Though freezing the subsurface 
while simultaneously heating it is clearly a counter-intuitive 
application of technology, it is a good example of the creativity and 
unconstrained thinking that necessarily has been a major contributor to 
solving potentially vexing problems in this complex Research and 
Development project. A schematic of the basic freezing technology is 
shown in Chart 2.

[GRAPHIC] [TIFF OMITTED] T2327.005


    Because the ICP process involves no mining, no large or 
contaminated tailing piles are created. Water usage is expected to be 
considerably less than is required for traditional retort methods. 
Because the technology has the potential to recover in excess of 1 
million barrels of oil per acre in the richest parts of the Basin, or 
about ten times that possible from conventional mining and retorting, 
temporary land disturbance associated with ICP during production will 
be significantly less. This smaller and cleaner footprint, the reduced 
water needs, the reduced processing needs, a robust system for 
protecting groundwater from contamination and the production of clean, 
less Green House Gas intensive products creates an environmentally 
attractive package about which we at Shell are very proud.
    It is through well-established technologies and constant monitoring 
that Shell expects to ensure proper and transparent stewardship of the 
environment. Shell is already working closely with local communities, 
NGOs, elected officials, and regulatory agencies to ensure that our 
research addresses community needs and sensitivities while ensuring 
strong environmental protection.
    Shell is currently focused on reducing the remaining risks and 
uncertainties that could affect the commercial viability of this 
technology. For this reason, Shell has a research staff in Colorado of 
approximately 55 personnel in addition to approximately 100 Houston and 
Denver based employees assigned to the oil shale project. The focus of 
these efforts is to insure the technical, commercial and environmental 
viability of the technology via a relatively large integrated 
demonstration project. This project would represent the final step 
required before a financial investment decision would be taken by Shell 
for a commercial scale unit.
    While Shell has spent many tens of millions of dollars on research 
and development for this technology and has learned a tremendous amount 
while reducing risk and uncertainty, much work and expenditure still 
remain before the ICP process can be commercialized. Shell is anxious 
to proceed with ICP research so as to help unlock the significant 
potential that oil shale holds to increase indigenous energy supply in 
the United States. Achievement of this objective on a timely basis will 
require the active support of Congress and the Administration
    Because the commercial development of oil shale would yield many 
benefits to the U.S. economy, Shell supports responsible policy 
initiatives that will facilitate early commercial production of shale 
oil and associated gas via methods that minimize industry's footprint 
and protect the environment. Shell is committed to working with 
Congress, with the Department of Energy, the Department of Defense, the 
Department of Transportation, the Department of Homeland Security and 
the Department of Interior, the latter of which has stewardship 
responsibility over approximately 80% of the oil shale bearing lands in 
the Green River Basin of the Rocky Mountain West, in order to 
accomplish this objective.
    Key to the early development of oil shale technology is early 
access to appropriate Federal oil shale deposits to allow for pilot 
field tests to be carried out. The leasing of tracts of federal land to 
encourage research and development is an essential next step. As a 
private company, Shell supports appropriate lease terms and incentives 
for the development of new oil shale development technologies.
    As the Department of Energy has pointed out in a recently released 
two volume report entitled ``Strategic Significance of America's Oil 
Shale Resource'', while oil shale is located in many countries 
throughout the world, the Green River Basin of northwestern Colorado, 
eastern Utah, and southwestern Wyoming contains the largest, most 
concentrated quantities of potentially recoverable shale oil in the 
world. The Report indicates that the Basin may have as much as 1.6 
trillion barrels of oil in place, of which an estimated 1 trillion 
barrels ultimately may be recoverable using various recovery 
technologies. This latter number is roughly equivalent to all the 
combined proven conventional oil reserves in the world today, (see DOE 
Charts 3, 4 & 5).

[GRAPHIC] [TIFF OMITTED] T2327.006

[GRAPHIC] [TIFF OMITTED] T2327.007

[GRAPHIC] [TIFF OMITTED] T2327.008


    Given the size of the resource, Shell is committed to pursuing 
commercially and environmentally viable technologies that can unlock 
the enormous potential for oil shale that exists in the Rockies. 
Shell's advancing ICP research is getting us close to being able to 
help unlock these resources. We believe that successful utilization of 
the ICP technology could yield substantial economic impacts to 
Colorado, the rest of the Rocky Mountain West and to the United States 
as a whole.
    Clearly, Shell believes there is a role for the appropriate 
development of oil shale deposits as part of America's overall energy 
and conservation mix to meet increasing energy demand. We are committed 
to the principles of Sustainable Development, to ensuring that our 
activities minimize the impact on the environment, and to enhancing 
opportunities for local communities while facilitating our business 
objectives.
    Ironically, despite the fact that that the United States clearly 
has the largest and most concentrated oil shale resources in the world, 
several other countries have ongoing oil shale Research and Development 
projects. Australia, China, Estonia and Brazil are all progressing 
projects that are governmentally assisted or driven in one fashion or 
another. It is Shell's belief that the time has come for the United 
States to join these other nations so as to encourage, facilitate, and 
accelerate the development of this potentially vast domestic energy 
resource.
    A range of options should be seriously considered in order to 
accelerate responsible U.S. oil shale development that would enhance 
national security and protect our Nation's economy. We would offer the 
following six recommendations for Congressional consideration. While we 
are not including specific legislative language, we are eager to work 
with the House Resources Committee and this Subcommittee, as well as 
all other relevant House and Senate Committees of jurisdiction on 
specific language to create the proper mix of incentives and 
opportunities for accelerated, but responsible, oil shale development.
    Recommendations for Congressional consideration of six important 
provisions:

    1.  Shell believes that the U.S. government should recognize oil 
shale as a strategically important domestic energy source. We believe 
that Congress and the Administration should officially support public 
policy initiatives that encourage and support accelerated commercial 
oil shale development and use as a feedstock for transportation fuels 
and other products.

    2.  Shell believes that the Secretary of the Interior should 
develop a commercial oil shale leasing program on an expedited basis. 
We support the BLM's recently announced R&D oil shale leasing program 
as an important first step in the right direction. BLM should now be 
urged to implement that program on an expedited basis.

        Shell thanks the House Resources Committee and this important 
subcommittee for providing important leadership to the full House of 
Representatives for including language in the recently passed House 
Energy Bill that in general terms would adopt these first two 
recommendations. We hope that legislative opportunities will arise in 
the future to give favorable consideration to passage of language to 
address the next four topics.

    3.  Congress should act to lift the current federal acreage 
limitation under Title 30, Section 241(a) of the Mineral Lands Leasing 
Act that restricts a lessee to acquisition of but one lease of 5,120 
acres nationally. In order to facilitate commercial development for oil 
shale production, Shell believes that this acreage limitation should be 
removed. Otherwise, companies that wish to build facilities and produce 
shale oil from federal lands will forever be limited to one project. 
Such a limitation, which dates back to 1920, until changed will create 
an impediment to even first-generation projects where the costs and 
risks will be greatest.

    4.  Congress and the Administration should work to develop royalty 
rates that encourage investment in oil shale development, giving 
particular recognition to the extraordinary costs involved in literally 
bringing a new energy industry into existence. In particular, Shell 
believes that government should develop a royalty regime for first 
generation commercial oil shale production that: 1) is simple to 
administer and to enforce and eliminates the need for interpretation or 
the likelihood of litigation; 2) would deliver significant revenue to 
the U.S. Government, and thus 50% of that amount to the impacted 
states; and 3) would not involve royalty rates that so steep as to 
create another obstacle to the acceleration of large-scale first 
generation commercial oil shale projects.

    5.  Shell believes that Congress and the Administration should work 
to ensure that an appropriate system is put in place to provide 
certainty and timeliness in the permitting process for oil shale 
development without waiving substantive environmental performance 
standards. A concern is that sequential overlay of multiple federal and 
state permitting processes has the potential to add many years to what 
will already be a complex and protracted permitting process.

    6.  Congress and the Administration should identify appropriate tax 
incentives that encourage investment in oil shale technology and 
development, that recognize the research and development hurdles 
involved in oil shale technology and development, and that 
appropriately treat oil shale production as the development of a ``non-
conventional resource'' in a manner similar to other non-conventional 
energy resources. Specifically, where ambiguities may now exist 
relative to determining whether or not in-situ oil shale recovery 
technologies will qualify for tax benefits in the same manner as do 
existing mining tax regimes, those ambiguities should be cleared up as 
soon as practicable.
    In summary, the United States has a huge domestic energy resource 
in the form of oil shale. The time has come for Congress and this 
Administration to consider appropriately targeted legislative and 
regulatory measures to allow oil shale to be developed at an early 
date, provided that such development can occur in an economically 
feasible and environmentally acceptable manner. Shell is increasingly 
encouraged and optimistic that our ICP technology may very well 
represent the first available technology to do so.
    This completes my written testimony. I will be happy to respond 
orally or in writing to any questions any Committee member may have.
                                 ______
                                 

Response to questions submitted for the record by Terry O'Connor, Vice 
  President of External and Regulatory Affairs, Shell Unconventional 
                            Resources Energy

1. Please tell the Subcommittee what you think the primary strengths 
        and weaknesses are with BLM proposed R&D leasing program.
    ANSWER: BLM's final R&D leasing program provides an important and 
timely first-step opportunity to tap a previously undeveloped domestic 
energy resource and over time hopefully will strengthen America's 
domestic energy security. Thus BLM should be commended for initiating 
this important first step. The opportunity exists to ``design it 
right'' in terms of developing a regulatory federal access structure 
that is appropriate for this unique and abundant resource in a manner 
that minimizes unrestrained ``boom and bust'' socioeconomic risks and 
dramatically reduces the likelihood of environmental damage, at the 
same time as encouraging the advancement of new and innovative 
technologies to test the extraction of shale oil and gas in a 
responsible manner.
    The advantages of BLM's final R&D leasing program are many, 
including but not limited to the following examples:
      Establishing a framework for cautious, small scale 
testing of innovative shale oil and gas recovery technologies on 
Federal lands.
      Providing first-of-its-kind small scale leasing of tracts 
up to 160 acres for appropriate shale oil recovery technologies.
      Providing a vitally important mechanism that will grant 
responsible operators the eventual right to convert the small tract to 
a larger commercial sized tract upon demonstrating the advancement of 
commercial production capability, subject to the payment of a 
conversion fee, NEPA compliance and obtaining necessary state and 
federal permits.
    While BLM's final program does not have major weaknesses, Shell 
does urge BLM expeditiously to develop and finalize regulations that 
specify the amount of conversion fees plus the size of commercial 
royalties, so as to give responsible, potential oil shale developers a 
degree of economic certainty as to their future obligations to the 
Federal Government.

2.  What does the price of oil need to be for Shell to make an 
        acceptable profit using the ICP process?
    ANSWER: Based upon 23 years of laboratory and bench top research 
plus 9 years of field research and development, Shell believes that it 
can make an acceptable return in a first generation commercial project 
with oil prices in the $25-30 per barrel of crude price---assuming 
Shell can access appropriate Federal lands, first for a next stage R&D 
pilot project development and then onto commercial acreage for larger 
scale operation. This crude price assumption for Shell's ICP technology 
is not currently applicable to most other Green River Basin oil shale 
resources. Conversely, once Shell has built and operated a first-of-
its-kind commercial facility, we believe that our future learnings 
should result in recovery cost reductions for subsequent second and 
third generation project developments by Shell or others.

3.  How large does Shell think that individual lease tracts should be?
    ANSWER: For initial R&D lease tracts, Shell supports the 160-acre 
limitation for primary recovery operations, although we may need 
limited additional surface-only use for ancillary surface support 
activities. For commercial-scale lease, Shell supports the 5,120-acre 
lease size. However, it is vitally important that Congress amend 
Section 241 of the Mineral Lands Leasing Act to allow responsible 
operators to acquire more than just one oil shale lease in the United 
States.

4.  What limitations on acreage under lease should apply to each 
        developer, if any?
    ANSWER: As noted in the answer to Question 3 above, it is critical 
that Congress amend Section 241 of the MLLA to allow companies to 
acquire more than just one oil shale lease nationally. While Shell sees 
no compelling reason to provide any other arbitrary limits on acreage, 
we would not object to a 50,000-acre national total, so long as 
multiple oil shale leases can be secured.

5.  What royalty structure would Shell recommend?
    ANSWER: Given the unique but yet undeveloped nature of commercial 
oil shale production, a traditional approach to establishing an oil 
shale royalty is not feasible or equitable to either side at this time. 
Unlike other royalty matters that BLM and MMS have faced in the past, 
oil shale has never been produced in commercial quantities in the 
United States or elsewhere in the world. Thus there is no currently 
available royalty benchmark for oil shale. Traditional oil and gas plus 
coal development each have a long history of operational and marketing 
practices to establish both a valuation basis (gross value) as well as 
a rate (8%, 12 1/2%, etc.). Unlike oil and gas, where the development 
and lifting costs of the product are relatively small, oil shale 
development on a commercial basis inevitably will involve enormous and 
speculative financial risk capital as well as very substantial ongoing 
operational expenses far greater than conventional oil and gas 
development.
    It is thus critical that reasonable parameters be inserted around 
royalty provisions to avoid onerous regulatory revisions in the future 
and to assure that a royalty methodology that meets the following 
criteria is met:
      A royalty that is simple to administer and to enforce and 
virtually eliminates the need for interpretative litigation,
      A royalty that over time would deliver significant 
revenue to the U.S. Government (and thus 50% to the impacted state), 
and
      A royalty that would not be so large as to create another 
obstacle to the acceleration of large scale U.S. based commercial oil 
shale projects.
    As a result the following royalty mechanism is recommended for the 
initial 20-year primary term of a commercial oil shale lease:
    Each year the royalty should be set by the Secretary at 5% of the 
average West Texas Intermediate crude price (or a similar generally 
recognized crude price, should the WTI be discontinued in the future) 
from the average of the price during the last month of the preceding 
year. At the 20th anniversary of the lease, the royalty may be 
readjusted based upon then applicable rules promulgated by the 
Secretary.
    The calculation of royalty due and owing shall be established on a 
royalty of net oil and hydrocarbon gas in barrels of oil equivalents 
produced and sold or removed from the leased premises if no offsite 
processing or upgrading occurs, or from the final point of processing 
or upgrading, less power fuel used in the production and upgrading 
operations, said value to be measured in barrels for imported liquid 
energy sources imported to the operations, and in barrels of oil 
equivalents from the gaseous, solid or electrical energy imported to 
the lease or upgrading site.
    A net royalty is needed to allow on-lease use of produced energy in 
the recovery process. Furthermore, an offset for purchased power fuel 
should be credited given the energy intensive nature of new evolving 
in-situ technologies that have the capability of recovering up to 10 
times more oil and gas per acre than did traditional retort 
technologies but that will require the substantial import of power to 
stimulate such production. Imported power will likely represent the 
largest cost component for in situ development. Thus the above-
recommended provision should provide maximum flexibility to use any 
primary energy source.

6.  What are the most important actions for the Federal Government to 
        take in order to ensure development of a large and vibrant oil 
        shale production in this country?
    ANSWER: As reflected in more detail in Shell's written testimony, 
we believe that the following Congressional actions should be initiated 
to facilitate responsible and orderly but expedited advancement of 
shale oil recovery technologies:
    a.  The U.S. Government should officially recognize oil shale as a 
strategically important domestic energy fuel source.
    b.  The Secretary of Interior should be directed to promptly 
develop and implement a commercial oil shale leasing program.
    c.  Congress should lift the current federal acreage limitation (as 
noted in Answers to Questions 3 and 4 above).
    d.  The Secretary should be directed to establish reasonable, 
balanced and simple royalty rates for commercial oil shale development, 
as described in more detail in Answer to Question 5 above.
    e.  Congress and the Administration should work together to ensure 
that an appropriate system is put in place to provide certainly and 
timeliness in the permitting process without waiving substantive 
environmental standards.
    f.  Statutory appointment of an in-situ oil shale permitting focal 
point to expedite all state and federal NEPA compliance and permitting 
efforts should be considered. Such a position should have adequate 
authority and resource to streamline the process and avoid frivolous 
delays without waiving substantive environmental standards.
    g.  Congress should identify appropriate tax incentives to 
encourage investment in oil shale technology and development, similar 
to those now or previously provided for other non-conventional 
resources, such as the percentage depletion allowance and Section 29 
production tax credits.

7.  From an industry perspective, what would you suggest that the 
        Government can and should do to convince industry that 
        Government is willing to be a long-term, reliable partner in 
        mitigating the risks of establishing a new industry in oil 
        shale?
    ANSWER: A good first step has been the Government's recognition of 
the opportunity and its subsequent offering of the R&D leasing program 
by the BLM. Industry will respond to governmental efforts to facilitate 
and reward pioneers that have taken the R&D risk and incurred the risk 
capital to provide new technology, provided that the oil shale R&D 
technology is conducted in an environmentally responsible and 
economically feasible manner. Industry will need the U.S. Government to 
facilitate a timely regulatory and permitting process to avoid undue 
obstacles to project approvals that can and will undermine the economic 
viability of capital intensive, first-of-its-kind projects, and that 
royalties generated are properly allocated to the benefit of those 
impacted most by oil shale development.
    In addition, the potential role of the Department of Defense should 
not be overlooked. As the single largest user of transportation fuels 
and a key branch of Government with responsibilities for domestic 
security, the potential availability of an additional domestic source 
of clean transportation fuels would seem to be a good fit as the DOD 
moves toward its single battlefield fuel of the future strategy in the 
next decade. Thus appropriately structured commercial transactions may 
be an attractive win-win option for both industry and DOD.

8.  Do you agree with the perspective that we will need both in-situ 
        and surface processing facilities to make optimal use of 
        domestic oil shale resources?
    ANSWER: Although Shell has chosen to pursue exclusively the in situ 
development route, we believe that different recovery processes 
ultimately may be appropriate for different depths, thicknesses, and 
qualities of oil shale resources; thus different aspects of the oil 
shale industry will likely involve both forms of recovery. The 
financial strength of operators will be also be a major factor, as few 
companies can garner the capital resources needed to develop a large-
scale oil shale operation.

9.  If government were to assist at the R and D phase where do you see 
        the need and role of government-supported research and 
        development?
    ANSWER: In addition to the vitally important aspect of providing 
small sites upon which to conduct R&D testing (through the recently 
announced R&D leasing program by BLM), there is also an important role 
for the Government laboratories in joint research on a variety of 
technical, engineering and environmental matters (such as carbon 
sequestration).

10.  You are out in front of this in Colorado, and have an industry 
        perspective on the planning and impact mitigation process. How 
        should government manage requirements for front-end costs to 
        assure that adequate and timely revenues are available to 
        communities and are fair and attractive to industry at the same 
        time?
    ANSWER: This is an insightful question that Shell has also been 
considering to avoid/mitigate the various types and extents of social 
and community impacts that occurred in Colorado in the late 1970s and 
early 1980s. A large-scale commercial oil shale operation will have a 
significant impact on any nearby communities, the extent of which 
depends on the existing infrastructures and many other factors. Such 
development will require prudent social investments on the part of the 
operator, as well as the local, state and Federal governments to 
provide community development resources, which will be defrayed by 
severance tax and royalty generation. The extent of these needs will be 
identified in the Social Impact Assessment process, stakeholder 
engagement sessions, and other forums of public input, and it will be 
important for the governments, communities and industry to work 
together to provide a sustainable development process.
                                 ______
                                 
    Mr. Gibbons. Thank you very much, Mr. O'Connor. We 
appreciate your presence here today and your testimony is very 
helpful to us.
    We turn now to Mr. Greg Stringham, Vice President, Markets 
and Fiscal Policy, from the Canadian Association of Petroleum 
Producers. And Mr. Stringham, I notice that you have Mr. Murray 
Smith back in the audience. I'm very much aware of Mr. Smith's 
history, his background in Canadian efforts there.
    We do know that Alberta is now one of the major producers 
of oil for the United States, from its oil sand. So if you 
would like to have Mr. Smith join you at the table, please let 
me invite Mr. Smith up to join you for your testimony.
    Mr. Stringham. Thank you. That would be great. I will have 
Mr. Smith speak just following my comments, if that's OK with 
you.
    Mr. Gibbons. Absolutely. Please.
    Mr. Stringham. Thank you, Mr. Chairman.
    Mr. Gibbons. The floor is yours. We look forward to your 
testimony.

STATEMENT OF GREG STRINGHAM, VICE PRESIDENT, MARKETS AND FISCAL 
      POLICY, CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

    Mr. Stringham. Thank you. It's a pleasure for us to appear 
before you, Mr. Chairman, and Committee members. It's not very 
often that Canada takes the opportunity to be able to appear 
before these committees; but we thought that today, given our 
experience in oil sands, recognizing it is somewhat different 
than the oil shales and tar sands that you have in the United 
States, it would be useful for us to be able to share our 
experience with you, to be able to see if there are some 
learnings there that may be useful.
    As you mentioned, Mr. Chairman, the oil sands that we have 
in Canada are in full development. It was unconventional at one 
point in time. And as you said in your opening remarks, it is 
not unconventional any more. It is certainly being produced at 
a rate of 1 million barrels per day, coming out of the oil 
sands. And from Canada, that represents one out of every two 
barrels of oil that we produce. And as you know, we export well 
over half of our production to the United States at this point 
in time. So it is a very valuable resource.
    We look forward, as the projects have been announced, to 
having close to 3 million barrels a day coming out of the oil 
sands in just ten years time. So there is a very strong growth 
that's happening in the oil sands, and that will then mean that 
three out of every four barrels of oil produced in Canada will 
be coming from the heavy oil and oil sands resource. So it has 
now become a very conventional and a very important resource.
    It does also have in there--and we will use a number of 
numbers--but 174 billion barrels of established reserves. You 
mentioned in your opening comments the 1.7 trillion barrels in 
place, but we know that we can get at, with today's technology 
and economics, over 174 billion barrels. Now, that's a big 
number. To put it in context, that's well over 200 years' worth 
of production at today's levels of projected production going 
forward. Very large number.
    One of the things that I learned as a young engineer coming 
out of university, I began working in research in the oil 
sands, and that was over 20 years ago, and there were already a 
handful of commercial projects underway. This is not a short-
term research project that will provide instant results.
    But what has happened in Canada is there has been a long-
term effort of research and development and incremental 
improvements over time, similar to the projects you've heard 
from these other gentlemen, that have unlocked the key to the 
development of this key resource in Canada.
    One of the things that was really critical was the 
reduction in cost estimates. And in the information that I have 
provided to you, the supply costs for the development of the 
oil sands in Canada for the heavy oil, which is very much--
bitumen is the name of it. It's tar-like. You have a sample of 
it, I think, you've seen; almost molasses-like material. The 
cost of development, including capital costs, operating costs, 
royalties, taxes, and the return to the investor, is somewhere 
in the range of $8 to $15 a barrel U.S.
    If you upgrade it into the light sweet crude, which has no 
bottoms and then can fit right into a refinery very, very 
nicely, the cost of that is somewhere in the range of $18 to 
$23 a barrel--all in supply costs; not just operating costs. So 
you can see that it becomes very economic to develop this 
resource.
    I would like to point out the key differences that we see 
between the oil sands in Canada and the tar sands or oil shale. 
As you may or may not know, the oil sands in Canada has been 
blessed by its formation with a water layer that surrounds it. 
So you have a sand molecule that's surrounded by a water layer; 
and then the oil, or the heavy oil, sits on the outside of 
that.
    And so the separate process is somewhat different, and 
perhaps a little easier, than the oil shale. It's a lot like 
salad dressing. If you shake it up and mix it with water, the 
oil will float to the top, the sand to the bottom, and the 
water stay in the middle. And that's essentially the process. 
It can be done at about 60 to 70 degrees Fahrenheit, and 
doesn't require the extensive energy that's used in other 
processes. Whereas the oil shales and tar sands, as I 
understand that you have in the U.S., has the sand molecule 
with oil just locked right on top of it, and requires these 
additional processes.
    One of the things that I could pass on as one of the key 
elements of success that we have seen in Canada in the 
development of the oil sands has been a very strong cooperative 
relationship between industry and government on the research. 
And I'm not now just talking bench-scale and lab-scale 
research. What was a really key unlocking feature that happened 
early on, and again back in the 1990s, was cooperation between 
the government and a variety--a consortium of industry players, 
that developed technology that, when it then became successful, 
was immediately dispersed throughout the industry, because 
everyone had access to it. So there's a two-pronged approach: 
the consortia, dispersion of technology; as well as the 
individual projects like Shell and Oil-Tech and others that are 
doing right now.
    To give you an idea of investment that's being put into 
this, at a commercial level now, we are investing this year $7 
billion into the oil sands in Canada. Over the next five years 
alone, we will invest another $36 billion U.S. in the 
development of these projects. And these projects will then, as 
I said, turn around and produce close to 3 million barrels a 
day over that ten- to 12-year period.
    I've brought with me today a summary that's put together by 
our National Energy Board, your equivalent to the FERC here in 
the United States. They have done a historical, technological, 
research, and market analysis of the oil sands in Canada that 
gives you an outline of the technologies used, how the research 
was developed. And I will leave that here with the clerk for 
your information. I won't go into the detail here. But it is a 
very good summary document to provide the background for you.
    And last, I must mention that as we look forward in the oil 
sands development in Canada, we do recognize that the United 
States is a key and our primary market--a very good customer. 
The reason that we are here today is because we would like to 
share that experience, learn mutually; but also, to get you to 
recognize that as we develop this new oil sand, it will require 
new markets, including new changes to refineries, modifications 
and building of refineries, to be able to handle the oil that 
we expect to come out of Canada, as it moves into the growing 
market of North America.
    Thank you very much. Let me turn some time over to Mr. 
Smith, if that's OK, Mr. Chairman.
    [The prepared statement of Mr. Stringham follows:]

 Statement of Greg Stringham, Vice President, Markets & Fiscal Policy, 
              Canadian Association of Petroleum Producers

Overview of Canadian oil sands development and technology
    The Canadian Association of Petroleum Producers appreciates the 
opportunity to submit this overview of the Canadian experience in oil 
sands development to the House Energy and Mineral Resources sub-
committee.
    While the issue that this committee is addressing has multiple 
aspects with much more detail than provided here, CAPP believes that 
many of the experiences, technologies, policies and research processes 
used in Canada to develop its oil sands resources would be beneficial 
to the committee on this subject.
    The oil sands in Canada are a vast resource. From early discovery 
and use in the 1800's to first commercial production attempts in the 
early 1900's, and government directed pilot tests in the 1920's and 
again post WWII, they moved into early commercial production with the 
Great Canadian Oil Sands (now Suncor) in 1967. Technology has been the 
key to unlocking this resource and production now exceeds 1 million 
barrels per day. Forecasts see this growing rapidly to over 2.7 million 
barrels per day in the next 10 years.
    While oil sands are significantly different from oil shale the 
government and industry research and development process could provide 
valuable and potentially transferable insights for oil shales.
    The main difference between oil sands and oil shale is that the oil 
sands are particles of sand, surrounded by a microscopic layer of water 
that is then in turn surrounded by the heavy bitumen (thick oil), as 
shown in the diagram at the end of this submission. Separating the oil 
from the oil sands is much easier because of this water layer, since 
the oil is ``suspended'' in the water/sand layer not directly stuck on 
the sand.
    In oil shales, this layer of water is not there and the oil is 
stuck directly onto the rock making it much more difficult to separate 
the oil from the rock (shale).
    The key to unlocking the vast potential of the Alberta oil sands 
has been sustained and cooperative industry and government research and 
development. This includes research efforts under the Alberta Research 
Council, the Alberta Oil Sands Technology and Research Authority, the 
Canadian Oilsands Network for Research and Development and more 
recently the Alberta Chamber of Resources' Oil Sands Technology Roadmap 
and the research coordination of the Alberta Energy Research Institute.
    The attached set of charts and pictures outlines the oil sands 
resource in Canada, the history and the technologies that have been key 
to unlocking this vast resource. The real key to the development has 
been a long and dedicated research and development program that has 
yielded technologies and advancements that have reduced costs and 
provided economic access to the oil contained in this resource.
    In addition Canada's federal regulatory agency, the National Energy 
Board (NEB), has published two Energy Market Assessment reports on 
Canada's oil sands that provide detailed information on the Canada's 
oil sands resource, technology, research, supply costs, production, 
pipelines and markets. They are available from the NEB at www.neb.gc.ca 
under Publications, Oil Sands
    CAPP would be pleased to respond to any questions the committee may 
have regarding the Canadian oil sands and we would be pleased to do 
this either in writing or when we will be in Washington at the end of 
June 2005. Please direct any questions to:
    NOTE: Attachments to Mr. Stringham's statement have been retained 
in the Committee's official files.
                                 ______
                                 

 Response to questions submitted for the record by Greg L. Stringham, 
   Vice President, Markets & Fiscal Policy, Canadian Association of 
                          Petroleum Producers

Question 1: Alberta's oil sands production is often likened to U.S. 
        oil shale production potential. The similarities with U.S. oil 
        shale cannot be dismissed. Please tell us how your industry 
        engaged and cooperated with the various government and private 
        citizen stakeholders to create the mammoth producing capability 
        you have today.
    The key to unlocking the vast potential of the Alberta oil sands 
has been sustained and cooperative industry and government research and 
development. This includes research efforts under the Alberta Research 
Council, the Alberta Oil Sands Technology and Research Authority, the 
Canadian Oilsands Network for Research and Development and more 
recently the Alberta Chamber of Resources' Oil Sands Technology Roadmap 
and the research coordination of the Alberta Energy Research Institute.
    Stakeholder consultation and input is sought out. There is an 
extensive pre-application consultation process for sharing information 
as well as raising and addressing stakeholder concerns. In addition the 
regulatory process addresses the technical, environment and socio-
economic aspects of these projects and provides an avenue for affected 
stakeholder issues to be addressed.
    In Canadian oil sands development, there is a balance of roles 
between government and industry. The resource is owned by the province, 
which leases the resource to industry to develop and in return receive 
a royalty payment (described below). In addition, governments provide 
policy foundation and the public infrastructure necessary to enable the 
developments and the private sector provides the investment and 
expertise to construct, operate and reclaim the project. This 
combination results in environmentally sensitive development, job and 
business creation, royalty and tax revenues to governments and earnings 
to the private investors.
Question 2: What problems does your industry face as it continues its 
        exponential growth?
    The Canadian oil sands are set to increase from its current 1 
million barrel per day level to 2.7 million barrels per day in the next 
10 years. This is one of the only areas in the world with the potential 
to increase production on this scale. But it is not instantaneous nor 
without challenges. While the historical challenges of technology and 
economics have been overcome, we are still working on new technologies 
and continuing to lower costs. The main issues of this rapid growth 
that we are now facing are:
      Ensuring adequate infrastructure--roads, housing, 
municipal services
      Ensuring an adequate workforce--we are already starting 
to see shortages of skilled trades, technicians and professional 
employees
      Access to markets--with the growing oil production, new 
pipelines will be needed to access new and existing markets. We will 
also need new refineries or expansions to accommodate this growing 
supply.
    Industry is working closely with governments, labor organizations 
and other industries to address the labor challenges. Industry is also 
working with several pipeline companies, refiners to address market 
access and growth.

[GRAPHIC] [TIFF OMITTED] T2327.017


Question 3: We heard your lessons about early royalty relief and 
        expensible depreciation for oil sands plants that require high 
        front-end capital investments. But there were additional 
        hurdles to first-generation investment that Canada succeeded in 
        crossing prior, with great perseverance. What fiscal and 
        programmatic steps should the United States take to get past 
        the hurdle of establishing a first-generation oil shale 
        facility in the United States?
    There are several aspects to encouraging first generation 
technologies in the oil sands. While they may not apply directly to the 
oil shale and tar sands in the US, the Canadian experience may provide 
ideas for how the concepts were applied for oil sands in Canada and 
could be used in the U.S. or modified to apply more specifically to the 
oil shale and tar sands.
    In Canada, the successful fiscal and program steps included:
      Joint government and industry funding research and 
development--over many years starting first with government research 
labs and extending to pilot scale demonstration projects with multiple 
companies. This was more than a single program. It was multifaceted and 
wide ranging. It included government labs and research facilities, 
universities and industry pilot and demonstration projects.
      The fiscal (royalty and tax) regime was critical. While 
it started out as a case-by-case negotiation, it quickly became evident 
that the provincial royalty regimes for conventional oil and gas would 
not work. The high front end capital costs and the long lead time 
investment before production began were two unique challenges that led 
to a two tiered royalty regime. The first tier was a relatively low 
front end royalty based on production (ranging from 5% in the early 
years down to its current 1%). This royalty is in place until the 
project reaches ``payout'' where the revenues generated equal the costs 
invested. At payout, the royalty rate then increases to 25% of net 
profits (revenues minus costs). Regardless of the details, this two 
tier royalty regime was effective for helping developers cope with 
large upfront capital cost risks of these projects.
      From an income tax perspective, in 1996, the federal 
government allowed oil sands to be treated like other mining operations 
for tax depreciation. This allowed the upfront costs to be deducted up 
to the level of income from the project and made the tax treatment 
similar to exploration expenses for conventional oil.
Question 4: In the end, all development depends on a willing investor 
        to invest capital. What are the risks to investing capital that 
        might be at least partially mitigated by Government policy and 
        legislation?
    As mentioned previously, the largest initial risks in oil sands 
were technology and economics. While we believe that the market is the 
best determinant of project economics, government policy and 
legislation can both set a foundation of certainty and stability that 
can encourage the early ``pre-commercial'' stages of any resource 
development and ultimately enable commercial developments. The benefits 
of unlocking this development have broad public application from 
employment, tax base, innovation and business and economic development. 
In addition to technology, governments can focus on policies and 
legislation regarding tax and fiscal regimes, timely regulatory 
approvals, land management and provision of infrastructure such as 
roads and services that enable these developments to proceed.
Question 5: What regulatory issues should we anticipate as placing 
        unacceptable timelines on investment payout, and how has Canada 
        handled these?
    With the large upfront capital investment for oil sands projects, 
the longer the time between the initial investment and when oil 
production begin; the higher the capital risk and the more negative the 
impact on the economics. The regulatory process is a major determinant 
of the time it takes from application to production. In Canada, the 
growing complexity of the regulatory process and the duplication of 
requirements from different levels of government are creating a longer 
process.
    Industry is working with governments and regulatory agencies to 
make the regulatory process more efficient. To be clear, this does not 
lower the regulatory or environmental standards to be met, but is 
simply trying to use single window approaches or find ways to meet the 
needs of multiple regulators with a single application.
    The recent application by Imperial Oil for the Kearl Oil Sands 
Project is a good example of the timelines associated with these large 
oil sands projects and the need for an efficient regulatory process. As 
can be seen on the timetable shown below, even with an assumed two year 
regulatory process, it will be a seven year process. Pre-application 
work began in 2003 and first oil production isn't expected until mid-
2009.

[GRAPHIC] [TIFF OMITTED] T2327.018


    The Alberta Energy and Utilities Board has prepared a document 
titled Guidelines Respecting an Application for a Commercial Crude 
Bitumen Recovery and Upgrading Project that outlines the regulatory 
expectations for preparing an application for these projects that may 
be useful reference to your committee. It contains following sections:
    1.  General Information
    2.  Technical Information
    3.  Economic Information
    4.  Environmental Impact Assessment
    5.  Biophysical Impact Assessment
    6.  Social Impact Assessment
    7.  Environmental Protection Plan
    8.  Conceptual Development and Reclamation Plan
    9.  Solid Waste Management
    The complete Guideline document is available on the Board's website 
at: http://www.eub.gov.ab.ca/bbs/products/guides/g23.pdf
                                 ______
                                 
    Mr. Gibbons. Absolutely. And Mr. Smith, we appreciate the 
fact that you have been able to come and join us today. We 
understand, of course, your historical background as the former 
Minister of Energy for the Canadian Government. We would hope 
that you would be able to address maybe the idea of: How do we 
cooperate, how do we get governments to work together to 
produce and make this issue of unconventional oil resources a 
conventional oil resource for America? Thank you.

                  STATEMENT OF MURRAY SMITH, 
               FORMER MINISTER OF ENERGY, CANADA

    Mr. Smith. Well, thank you very much, Mr. Chairman. It's a 
privilege for me to appear in front of the Committee. And I 
have been assigned to Washington to represent Alberta's 
interests here. And I must thank you, this Committee, and other 
committees, for the gracious welcome I have received. It's 
actually good to be in Washington--and you don't have to buy a 
dog to have a friend.
    I want to comment just briefly on the role that government 
can play. We knew we had this outstanding commercial resource 
available. But you couldn't think of it as an oil resource; we 
had to think of it a mining resource. And in fact, because it 
is now truck-and-shovel, it is a mining process. We adjusted a 
royalty scale to attract investment.
    And the royalty structure works in such a way that we 
charge 1 percent of all production revenues until the project--
each defined, specific project--reaches a point of pay-out. 
After it reaches pay-out, the royalty structure then reverts to 
25 percent of net royalties; which then is an appropriate 
economic rent for the people of Alberta, who own the resource. 
This is all taking place on federally owned--or what we would 
call ``crown lands.''
    Transparent economic rents are a critical factor in 
developing this resource. We did not have to put any money, per 
se, toward an oil company, in terms of a direct incentive. But 
we recognized that with the potential and with the level of 
investment that they would make, that we would have to provide 
something that is both attractive to get that money in place, 
the first place; second, to develop the resource at an 
economical rate; and third, to have a degree of certainty that 
would last through the period of the resource development and 
extraction.
    That, combined with over 20 years of shared research and 
about a billion dollars--Canadian dollars--worth of research 
and shared technology, as Mr. Stringham was pointing out, 
helped us come to the point where today we produce this mining 
resource at an economical rate, where it is delivering over a 
million barrels a day, on schedule; to double within five to 
seven years; and then to go to 3 million barrels a day before 
the end of the next decade. So the resource is substantial. It 
is commercial. It has developed new technologies.
    We are also moving toward new technologies that will drop 
the operating costs even further, and that is using either the 
bitumen itself, or other processes, to substitute natural gas 
as a fuel. So we see our operating costs, which now range 
anywhere from $12 to $15 U.S., to drop by as much as 40 percent 
in the future.
    So once you get a foundation, you can then continue to 
amortize your expertise, your technology, and your skills, over 
a long period of time. And we think the oil sands will 
successfully supply crude oil to this market, to the United 
States, for the next foreseeable future.
    Mr. Gibbons. Thank you very much, Mr. Smith. We will turn 
now to questions and answers for our panelists today. And I 
think what I am going to do is withhold my questions until the 
very last. I will turn to members of the Committee in order of 
their appearance here today.
    I believe Mrs. Drake was the first on our side. Mrs. Drake, 
do you have any questions?
    Mrs. Drake. Mr. Pearce was here first.
    Mr. Gibbons. Oh, Mr. Pearce. Mr. Pearce.
    Mr. Pearce. Thank you, Mr. Chairman. Mr. Godec, did you 
have a chance to look at the report by Mr. Savage, that 
actually there's not any oil in the shale, but it's in fact 
organic compounds that are compressed and made into oil?
    Mr. Godec. No, I did not.
    Mr. Pearce. Do you agree with that assessment?
    Mr. Godec. I am not an expert on oil shale.
    Mr. Pearce. Mr. Savage, tell me about the organic compounds 
that they find, and how they are converted into oil.
    Mr. Savage. What we do with oil shale is what ``mother 
nature'' would do if we had a couple of hundred million years 
to wait on her. There is not one drop of oil in oil shale; 
there's organic material. And we take that organic material in 
the form of rock; we heat it; and under intense heat, the 
organic material escapes in vapor form. We capture that vapor, 
and condense it into liquid. And this is what ``mother nature'' 
would do with the heat and the pressure of the Earth.
    Mr. Pearce. Are those organic materials available anywhere 
else in nature?
    Mr. Savage. Well, it's algae; it's fish life, plant life. 
This area that we refer to as the Green River oil shale deposit 
was covered by a lake at one time. When that lake receded----
    Mr. Pearce. What is the magic of these? They are kind of 
expensive to extract from rock or shale, so why don't we just 
gather them out of nature in easy to gather places?
    Mr. Savage. Well, I don't know why we don't do that, but 
I'm sure that a large deposit----
    Mr. Pearce. I mean, you understand what I am saying? If we 
are able to compress these things and just get oil from them, 
my question is, why go after them in the very expensive setting 
that they are in? Why not just figure out where they are 
cheaper to get at?
    Mr. Savage. Well, it is not that expensive any more to go 
after the reserve that we refer to.
    Mr. Pearce. So you can do it at the $20 level?
    Mr. Savage. Absolutely.
    Mr. Pearce. Do you have $15 oil?
    Mr. Savage. Yes.
    Mr. Pearce. How much are you producing?
    Mr. Savage. Well, we're producing 24 barrels a day with our 
current retort. And we do not run continuously; reason being is 
we are using previously mined oil shale which is owned by the 
BLM. We purchase from them. We do not have a mine open, so 
we're not into a commercial venture at this point. But we have 
run sufficiently long to have our costs validated. They range 
anywhere from $9.60 a barrel, to $22 a barrel. That variance is 
all mining related.
    Mr. Pearce. I understand, but my idea is if you are making 
money at, you said, $15 oil, and the price is 60, that is about 
45 bucks net profit. I don't understand why you are not 
producing millions of barrels, because your profit increases as 
you generate more volume. I don't understand why we're 
producing 24 barrels instead of 24 million barrels; because you 
know that we need the energy. Tell me about the economics that 
keep you from doing that.
    Mr. Savage. Well, the difference is that we are a startup 
company, just having completed the research and development 
phase, and just beginning to move into a commercial mode which 
will consist of opening a mine and building out a series of 
1,000-barrel-per-day retorts.
    Mr. Pearce. Mr. O'Connor, are you all----
    Mr. Savage. We want to do exactly what you're referring to.
    Mr. Pearce. OK. Mr. O'Connor, are you at Shell pretty 
involved in the extraction of shale organic materials and 
converting them?
    Mr. O'Connor. Well, yes, we've been involved in this for 
almost a quarter of a century now. And I generally agree with 
what Mr. Savage just said; in that these oil shales are very 
immature product, and that they don't flow on their own. The 
oil and the gas is chemically embedded in the rock. Through 
time, heat, and pressure of tens--maybe hundreds--of millions 
of years, through this geologic time period, we would see these 
mature into a more conventional oil and gas field. But in the 
meantime, they are not free-flowing.
    With regard to your questions on the economics, we think 
that there are some resources in the Green River Basin that can 
allow us to make money in a $25 to $30 oil price world. Now, 
the question is, why are we not doing that now? Why are we not 
now today producing extraordinarily large quantities of oil and 
gas?
    First of all, this is extraordinarily difficult science and 
engineering and chemistry. We have a tremendous amount that we 
have learned, but we still have much learning to do. As just 
one example, we're inserting these heaters down into the 
resource.
    Mr. Pearce. Yes, I read that in your testimony.
    Mr. O'Connor. Yes. Some of this resource is 1,000-foot deep 
to the top of the resource, and 1,000-foot thick below that. So 
we would literally be dropping down 2,000 feet of cables or 
pipe and heating the bottom thousand feet of that. We've had a 
very difficult challenge in terms of developing a reliable 
heater that will last the many years that are necessary, as the 
rock heats up and we get the rock's chemistry as it is.
    Mr. Pearce. OK, thank you.
    Mr. O'Connor. In addition to that, while the big 
technological challenges are on the sub-surface, the big costs 
are on the surface, as we bring it to the surface and then have 
to engage in the surface processing, the transportation, the 
power generation, and the other enormous tasks that would be 
involved from a practical standpoint.
    Mr. Pearce. I thank you very much for those comments. Mr. 
Chairman, my time has elapsed. Thank you.
    Mr. Gibbons. Thank you very much, Mr. Pearce. With the 
concurrence of Mr. Grijalva, as a matter of personal privilege, 
we are going to turn to Mr. Cannon for his remarks before he 
has to leave.

    STATEMENT OF THE HON. CHRIS CANNON, A REPRESENTATIVE IN 
                CONGRESS FROM THE STATE OF UTAH

    Mr. Cannon. Thank you, Mr. Chairman. In particular, thank 
you for holding this hearing. This is remarkably important. I 
appreciate it. And I'd ask unanimous consent to submit an 
opening statement for the record, or unanimous consent that 
anyone may submit an opening statement for the record.
    Mr. Gibbons. Without objection, any Member wishing to 
submit a written opening statement may do so.
    Mr. Cannon. You know, we have some people here today who 
are dear friends. And I am not going to take five minutes; I 
just wanted to thank Mr. Savage for being here. And you know 
that we have these plaques with the material. That is 
remarkably nice. I appreciate that. And as I was walking over 
here, I was explaining to staff something about this and then, 
lo and behold, there we have the material to show them.
    And Mr. O'Connor has been a good friend for a very long 
time. And we appreciate the work that you have been doing 
there. Mr. O'Connor, the world needs this. And as you pointed 
out, there are several resources around the world that are 
similar, that may free mankind from the burden of not having 
low-cost energy for the long term.
    I would also like to thank Commissioner McKee for being 
here. He is struggling with these issues on the local level. 
And I apologize that I am not going to be able to be here to 
hear his testimony.
    But I just wanted to thank you all for being here. This is 
incredibly, remarkably important, as you look at the pressures 
that are on the world today. I mean, I thought that $2 gas 
would be really a horrible thing; but actually a lot of nice 
things have come out of it, including the fact that we may be 
looking at some of these alternatives in Canada, in shale and 
in tar sands.
    And so Mr. Chairman, again, I thank you for holding this 
hearing, and yield back.
    [The prepared statement of Mr. Cannon follows:]

 Statement of The Honorable Chris Cannon, a Representative in Congress 
                         from the State of Utah

    Thank you Mr. Chairman for holding this important hearing on Oil 
Shale, Oil Sands, and Heavy Oils. As the price of oil is projected to 
continue to escalate, our need to depend less on foreign sources is 
even more apparent. American consumers have increased their demand for 
oil by 12 percent in the last decade, but oil production has grown by 
less than one half of one percent. We import 56 percent of our oil 
today, and it's projected to be 68 percent within 20 years. 
Fortunately, a solution is available.
    Of the estimated 2.7 trillion barrels of oil held in the world's 
oil shale deposits, 2 trillion is scattered across the United States. 
That's more oil than all the countries in the Middle East combined.
    In fact, the U.S. Department of Energy estimates that the United 
States is the richest and most geographically concentrated oil shale 
and tar sands resource in the world.
    This gigantic resource of oil shale and tar sands is well known by 
geologists and energy experts, but it has not been counted among our 
nation's oil reserve because it is not yet being developed 
commercially. Companies have been waiting for the federal government to 
recognize publicly the existence of this resource as a potential 
reserve and to allow industry access to it.
    Oil shale could allow the U.S. to become the world's single biggest 
oil source, ahead of all the OPEC members. The Department of Energy's 
Office of Naval Petroleum and Oil Shale Reserves estimates oil shale's 
direct economic value to the nation might approach $1 trillion by 2020, 
not counting other equally or more valuable strategic and national 
security benefits that may not be fully measured in dollars.
    Today's hearing will help us to understand the potential of 
domestic oil to supply America's oil demand. I thank the witnesses for 
being here today and I look forward to hearing their testimony.
                                 ______
                                 
    [The statement submitted for the record by Mrs. Cubin 
follows:]

Statement of The Honorable Barbara Cubin, a Representative in Congress 
                       from the State of Wyoming

    Mr. Chairman, for three decades, this country has been on the path 
toward a serious energy supply shortage and an ever growing dependency 
on foreign oil. Transportation costs are skyrocketing; everything that 
rolls, floats, or flies costs more to operate. Add in global energy 
demand that continues to increase exponentially, and it becomes very 
clear that our nation is on the brink of an energy crisis.
    Fortunately, adequate energy deposits exist within and just off the 
coast of our borders to meet this growing demand. Technology is 
improving everyday in how to best access these energy sources, as well 
as creating new renewable energy supplies. Western oil shale deposits, 
including those that reside in the Green River and Washakie basins in 
Wyoming, have the potential to play a significant role in an energy 
supply solution.
    Through passage of the Energy Policy Act, the U.S. House of 
Representatives has taken an important first step toward the 
development of this potential resource by directing the Secretary of 
the Interior to develop an oil shale leasing program for the nearly 2 
trillion barrels of oil shale resources located in the United States.
    I look forward to hearing from our panel today what investments 
private industry is making to ensure the efficient development of oil 
shale resources in the future, as well as what economic benefits it 
would bring to local, state and federal economies.
    Thank you Mr. Chairman for holding this important hearing and I 
yield back the balance of my time.
                                 ______
                                 
    Mr. Gibbons. Thank you very much. Turn now to Mr. Grijalva. 
Thanks for your patience.
    Mr. Grijalva. Thank you, Mr. Chairman. Let me begin, I 
guess, directing to Mr. Savage and Mr. Godec the same question. 
Thinking ahead, and thinking of consequences as we go forward 
with, as Mr. Cannon said, this very important research and 
development process that we are in.
    Although apparently based on some new innovations, it is my 
understanding your approaches to oil shale production still 
involve major mining operations. And if I am correct in that 
understanding, I just ask the general question: What specific 
techniques and precautions will you use to protect surface 
water, ground water, from depletion or contamination, to 
protect top soil stability, and to control the air pollution 
from the mining and whatever other stages of operation? Those 
are precautionary questions that I think will have to be asked 
as we go along with this discussion.
    Mr. Savage. Thank you. Our process is a two-step process. 
One is the mining. And as Terry indicated, we have to bring the 
rock to the source of the heat, so it's mining, bringing the 
rock out of the ground. And then the second phase is processing 
that rock on the surface.
    I can tell you that the retort, or the surface processing 
aspect, is fully self-contained. It's a sealed unit. It's 
oxygen-free. In fact, if we allowed oxygen to get inside of our 
retort, we would have an explosion. We would combust the shale. 
So it's oxygen-free, sealed under vacuum. There are no gases or 
emissions of any type that reach the atmosphere. The only non-
condensable gas that we produce in this process is propane. And 
we capture that and, after processing it, that can also be a 
marketable product.
    The mining aspect of this, relative to the environmental 
consideration, we apply with the State of Utah in the--we have 
39,000 acres of oil shale ground under lease, which is owned by 
the State of Utah. We have applied for a mining permit. And 
they put us through the hoops and make us dot the ``i's'' and 
cross the ``t's'' as it relates to environmental impact. So we 
have geological studies conducted, paleontology studies 
conducted, archaeological studies, as well as the reports on 
our system relative to air and water control and so forth, 
where we disperse spent shale. And all of that is contained 
within the mining plan that the State of Utah will rule upon.
    We are doing nothing more than what coal mining does to the 
environment. We go underground and we remove rock and we bring 
it to the surface. And you asked about methodology.
    Mr. Grijalva. That is an interesting point. I think that 
there is an estimate that there is a $26 billion price tag on 
reclaiming coal mines across this country. And that is kind of 
the precaution and anticipation in unintended consequences that 
I think need to be looked at, as well.
    Mr. Savage. One of the things that I might mention is, in 
this area where we are currently operating there are mined out 
and abandoned gilsonite veins. Now, you wouldn't want to walk 
around in this area in the dark. We're talking about 50-foot-
wide veins that maybe go 1,000 feet deep, and they go for miles 
across the surface of the Earth. The State of Utah has asked us 
to take the spent shale and begin filling in these cavernous 
areas.
    Mr. Grijalva. Thank you, Mr. Savage, and thank you for the 
visual. Appreciate it very much. And I had asked the question 
of Mr. Godec, as well, but for the sake of time, let me begin 
with him on the second question to both the same gentlemen. 
With your anticipated ability to produce fuel from oil shale at 
such a low price, can we correctly assume or expect that you 
will be able to operate without any government subsidies or tax 
breaks?
    Mr. Godec. Is this directed to me, or to Mr. O'Connor?
    Mr. Grijalva. We will begin with you this time, because I 
cut you off on the other one.
    Mr. Godec. No, I was really not referring or speaking to 
oil shale. And so I'm really not qualified, I don't think, to 
talk about the economics of oil shale production.
    Mr. Grijalva. Mr. Savage? Mr. O'Connor?
    Mr. Savage. Well, we have never asked for, neither are we 
asking now for government subsidies. I think the position that 
Canada has taken would amply suffice for our needs, in some 
sort of royalty breaks when working upon Federal ground, and 
maybe some tax investment credits, those kinds of things.
    Mr. Grijalva. And if I could direct a question to Mr. 
O'Connor, well, the same question about the process is 
relatively low market in terms of cost and prices. Am I correct 
in assuming that that can be done without subsidies or tax 
breaks? Same question.
    Mr. O'Connor. Shell has been at this for almost a quarter 
of a century, and we've done it all on our own land. We've done 
it all without any government involvement or subsidies 
whatsoever. We're not seeking any money from the Federal 
Government going forward; despite the fact that a large-scale 
commercial operation will be very substantial in its capital 
expenditures.
    As my testimony does indicate, though, we think that there 
are areas where clarification and some parameters need to be 
set around the issues of Federal royalties; since the Federal 
Government owns somewhere between 72 and 80 percent of all the 
oil-shale-bearing lands in the basin. And also, there are some 
issues involving tax credits, where they are or in the past 
have been available for a variety of other type of non-
conventional fuels. And to the extent that it becomes 
appropriate to have discussions to seek clarification on which 
of those should be considered in the future, we think that oil 
shale should be part of those discussions.
    Mr. Grijalva. If I may, the last question, Mr. Chairman, 
Mr. O'Connor, you mentioned BLM's new experimental leases. Do 
you anticipate, or do you think Shell will seek one or more of 
these leases in the near future?
    Mr. O'Connor. Shell, in fact, has applied for an R&D lease 
on Federal lands. You've raised an interesting question, that 
I'm so glad that you asked about one or more. My testimony in 
the written form indicates that there is an 85-year-old 
provision in the Mineral Leasing Act of 1920 that restricts 
companies or individuals from acquiring more than one oil shale 
lease anywhere in the United States. It's ironic that that 
still exists.
    That provision and that restriction was created for all the 
other commodities, too: oil, gas, coal, phosphate, and all the 
other leasable minerals. And with the exception of oil shale, 
those restrictions have all been modified throughout the years.
    So we think it is extraordinarily important for Congress to 
take a look at this. Because otherwise, if a company does 
develop--does secure a Federal oil and gas lease, and then 
successfully develops a project on it, it is then out of 
business in terms of any further development on Federal lands.
    And we're not suggesting opening up the flood gates in 
terms of unrestricted leasing, but this single-lease limitation 
really does cry out for consideration in the 21st century.
    Mr. Grijalva. Thank you, Mr. Chairman, for the additional 
time. Appreciate it.
    Mr. Gibbons. Mrs. Drake.
    Mrs. Drake. Thank you, Mr. Chairman.
    Mr. Savage and Mr. O'Connor, it sounds like you are both 
doing this. I wondered what the regulatory process was, and how 
long it took you to be able to get your permitting to be able 
to do what you are currently doing, and what you think you are 
looking at--of course, if you go out on Federal lands, it is 
going to be another process--what the timeframe is going to be 
for you to do what you would like to see happen. What it took 
you to get to where you are, and what you anticipate.
    Mr. Savage. Well, currently, we have a research and 
development site which consists of an acre of ground in the 
middle of several thousand acres that we have under lease with 
the State of Utah.
    Mrs. Drake. OK.
    Mr. Savage. And the permitting process for this research 
and development aspect of the project was not long in coming. 
We were able to obtain the necessary permitting within a few 
weeks time.
    The mining permit which we have applied for, we first 
applied for that more than 12 months ago. And that's still in 
the process and will come up--as I understand it, within the 
next couple of months it will come up for a 30-day public 
review. And after that review, we may be asked to give 
additional information or more detail as to our mining 
operation plans. And then it will be ruled upon, and we'll 
either be permitted or not. We anticipate being permitted.
    Mrs. Drake. But you don't see it as a very long, extensive 
process, like we have heard in other committee meetings with 
other types of things that are being mined?
    Mr. Savage. No. It hasn't been on the state level. As we 
look at the Federal requirements, that could take substantially 
longer. And if we would have one request in addition--I think 
Terry made a very good point about the Mineral Act--but instead 
of subsidies, we would like to see more cooperation of the 
Federal Government in trying to move this project forward, 
through some relaxation, if you will, of the requirements to 
get to where we need to be.
    Mrs. Drake. Mr. O'Connor, did you want to add anything?
    Mr. O'Connor. Yes, ma'am. Despite the fact that we don't 
actually mine any of the resource, because of the peculiarities 
of the State of Colorado regulatory regime, we're regulated as 
though we are a mining operation. Having said that, in the 
past, because of the very de minimis size and disturbance 
involved in our five research projects so far, time and 
complication has not been an overriding factor for us in the 
permitting process.
    But I hasten to add, this has all been done on our own 
land. When you overplay the involvement of Federal lands, along 
with the larger and more complex size of a commercial 
operation, we fully expect that, under the best of 
circumstances, it's going to take us probably five years, at 
least, to be able to permit our first commercial operation.
    Now, I mentioned in our testimony that we're hoping to make 
a final investment decision for a large commercial operation by 
the end of this decade. That means that, despite the fact that 
our technology is yet not proven at commercial scale, although 
we're getting increasingly optimistic, we literally have to 
start now with gathering environmental data, preparing 
environmental impact statements, starting down that road, in 
anticipation of what under the best of circumstances may very 
well be at least five--and could be 15 or 20--years of 
permitting activities.
    It is here where we will desperately need government help. 
And we're not here seeking any waiver of environmental 
standards, or waiver of substantive environmental issues. But 
the large and daunting looming of multiple sequential 
permitting processes, each of which could be very complicated, 
each of which could be subject to lots of controversy for those 
that don't want to see any oil shale development, could extend 
to the point where what looks like a very attractive project or 
projects for us in the future could lose their luster as the 
years and the decades could drag out.
    Mrs. Drake. And Mr. Stringham, I wondered if you could tell 
us how the process works in Canada, and the regulation, the 
timeframe. I did notice that you are also in Saint John's, 
Newfoundland. I will actually be visiting there in August.
    Mr. Stringham. Oh, congratulations. It's a great place to 
visit.
    Mrs. Drake. Well, it is. My mother lives there. I go quite 
frequently.
    Mr. Stringham. Perfect. Well, then you understand that, as 
well. The regulatory process in Canada is not much different. 
If it is under provincial control, then certainly you can move 
more quickly. But what we have in Canada is we have provincial 
and Federal regulation overlapping, very similar to state and 
Federal here. And so from that perspective, for a large oil 
sands plant, certainly it can take a two- to three-year 
process.
    Mrs. Drake. A two- to three-year process?
    Mr. Stringham. Two- to three-year process.
    Mrs. Drake. Not 15 to 20?
    Mr. Stringham. Yes, that's correct. Although, you know, for 
the early days, certainly, it took longer than that. But we 
really tried to work it down to a two- to three-year process.
    Mrs. Drake. Thank you very, very much. Thank you, Mr. 
Chairman.
    Mr. Gibbons. Thank you, Mrs. Drake. Mr. Jindal.
    Mr. Jindal. Thank you, Mr. Chairman, first of all, for 
calling this hearing. Given the price of energy in our country, 
I think this hearing couldn't be more timely. And I want to 
thank the witnesses for their information, as well.
    The first question I'll direct at Mr. Savage and Mr. 
O'Connor, but I invite any of the witnesses, certainly, to 
respond to this. I am just curious, as we have heard about the 
wonderful resources that are potentially available to us right 
here in our own country, across North America, I am wondering, 
what are the most important steps we can take in the Federal 
Government to encourage timely production of a large volume of 
oil, not only from oil shale, but from the oil sands and some 
of the other resources we have heard about today, as we think 
about completing our work on the energy bill? I am just 
thinking in concrete terms. What do you see as the three 
biggest barriers? And what are the three specific things we 
could be doing in Congress to help speed along the development 
of this process?
    Mr. Savage. Well, I think we've mentioned a couple. When we 
realize that 80 percent of this ground that we speak of, oil 
shale property, is owned by the Federal Government, there has 
to be some cooperation from the Federal Government as to the 
land usage. The leasing of the land, as has been stated, it'll 
be required that there be more than one lease granted to one 
company. That's a given. Help with companies to meet the 
environmental impact issues; but to help us, and not stalemate 
us, in moving those forward on a more quickly [sic] basis, more 
rapid basis.
    Mr. O'Connor. Just referring in general terms to our 
written testimony, we've identified six areas where we think 
it's strategically important to have legislative and/or 
regulatory proactive support from the Federal Government.
    The first is more on the policy level; is to really have an 
official declaration from the highest levels of this 
Government, both Legislative and Executive, that oil shale is a 
strategically important energy fuel which should be developed 
on an expedited basis, if it can be done in an environmentally 
acceptable and economically feasible manner.
    Why is that? Well, very honestly, because of the failures 
of the '70s, there is so much misperception, and thus negative 
overhang, involving oil shale, that we think that even many of 
our friends remember the past failures--that largely 
precipitated from a rapid decline, an unexpected decline, in 
oil prices--and are not really particularly focusing about the 
advances of technology. And so as a result, in many cases, we 
are finding ourselves attempting to try to push something up a 
waterfall. And if we can get into a policy pull position, that 
can really make a big difference.
    Second, encouraging and directing the Interior Department 
to develop a commercial oil shale program. And as I said, you 
know, they have taken a very important initial step, but they 
need to follow through to develop--they've had authority since 
1920. And except for four oil shale leases that were issued in 
the 1970s by Executive Order from the President, no oil shale 
program, leasing program, has ever been developed. And 
certainly, the time has come. And we applaud the Department for 
taking this first step.
    Third, we've already mentioned the single-lease limitation, 
which can really be a show-stopper for long-term investment and 
approvals necessary because of the extraordinarily long capital 
that is needed.
    Fourth, the Secretary has unbridled discretion to set 
royalties at whatever rates. And while that doesn't require 
specific legislation, we think that the extraordinary amount of 
capital at the front end, and the high-risk capital, and the 
high technical risks that are involved in first-generation 
facilities that'll be the first in their kind in the world, 
literally, need recognition that some parameters on royalties, 
particularly in the first iteration of royalty setting, be set; 
perhaps along the lines of what the Canadians did.
    I've also represented or mentioned earlier about the 
permitting needs where, instead of getting involved in the 
endless cycle of multiple sequential permitting that could drag 
five years into multiples of that, some Legislative and 
Executive efforts to try to consolidate these into more 
rational concurrent reviews will make enormous sense.
    And finally, just mentioning that there are some 
ambiguities in the tax laws regarding whether or not oil shale 
would qualify for some of the same type of tax treatment that 
other unconventionals do, also needs to be clarified. Thank you 
for the question.
    Mr. Jindal. Thank you.
    Mr. Savage. May I make one more comment along those lines? 
There's a tract of land in eastern Utah that's owned by the 
Federal Government which we refer to as ``UAUB.'' This is a 
tract of land, approximately 10,000 acres, which was leased to 
the consortium of Phillips, Sun Oil, and Sohio, back when the 
commercialization of oil shale was underway.
    They have developed--``they'' being the consortium 
developed--an underground mine which, upon abandoning their 
project, that mine was turned back to the care of the BLM. And 
at one time, it was attempted to reclaim--the BLM wanted to 
reclaim that mine, for many and various reasons. It remains 
open, although there has been some signs of closure.
    If a company like Oil-Tech, which is ready with a surface 
retorting process to move forward, if we could lease that 
ground containing that mine, we could move forward very, very 
quickly. We could be producing thousands of barrels of oil a 
day very quickly.
    Mr. Godec. Just a couple of comments to reiterate, I think, 
in kind of applying it across the board to all unconventional 
oil resources, not just oil shale, I think there's a lot that 
we can learn from our neighbors to the north in Canada about 
effectively, through public/private partnerships, encouraging 
and facilitating the development of a resource that's 
technically challenging and unfamiliar to much of the operating 
community.
    And that was done in Canada, and it's what I'm recommending 
in my recommendations to this Committee; to include, you know, 
both updating and publicizing the information on the geologic 
characteristics of the resource, where it is, what its 
characteristics are; publicizing current technologies and how 
those might be applied to these resources through demonstration 
projects and field pilots; taking that best technology today 
and looking at it to see what else we can do through research 
and development and improved science to improve the recovery; 
and then providing fiscal incentives to help basically share 
the risks between government and industry in going after these 
new technologically challenging projects in a way that both 
facilitates their development, but in the long run is not a net 
subsidy forever for these kinds of resources.
    I think you can look at unconventional gas resource 
development as a prime example where, here in the United 
States, through the combination of research and development and 
effectively targeting fiscal incentives, we've been able to 
turn what was once an obscure, unconventional resource--tight 
gas and coalbed methane--into a resource now that provides one-
third of our domestic natural gas supplies.
    Mr. Jindal. I want to thank the witnesses. My time has 
expired. I just want to echo two things. One, I want to thank 
each of you for your specific recommendations. Mr. O'Connor, I 
think you said it best, in that it is incumbent upon us to 
develop our technologies in an environmentally sensitive way to 
take advantage of these energy resources that are present in 
our Nation.
    And second, even though, Mr. Stringham, I didn't get a 
chance to ask you the question I would have asked, I think we 
have a lot to learn from our neighbors to the north. And we 
certainly appreciate your coming and sharing with us how this 
regulatory regime has worked in Canada. Thank you.
    Thank you, Mr. Chairman.
    Mr. Gibbons. Thank you very much, Mr. Jindal. And in fact, 
I want to follow up a little bit with where he left off, and 
maybe question Mr. Murray [sic] with regard to the 
relationship.
    Our next panel that is going to come up is going to talk 
about the state-county relationship and their involvement, of 
course, with this resource. I would ask you a question. The 
Canadian Government, with regard to the province of Alberta, 
its local communities, what was the relationship? And how did 
they work together with the stakeholders in this in order to 
develop these oil sands in Canada with such an expedited 
timeframe, if you will?
    Mr. Smith. The original Great Canadian Oil Sands plan 
started in 1977. The first barrel out was at $35 U.S. And it 
seemed at that time that the path was going to be fairly long. 
The ownership structure of the resource is the government of 
Alberta, the province, owns the resource; and the Federal 
Government oversees inter-province or inter-state movement of 
that product. So the local ownership did play an important 
role.
    The Federal Government recognized the value of the resource 
for all of Canada, and contributed by putting money into a 
joint research fund, called the Alberta Oil Sands Technical 
Research Authority. That authority shared technologies with the 
private sector, and shared funding with the private sector over 
a 20-year period, to the tune of about $800 million.
    The companies would invest their money into oil sands 
development, into oil sands technology, and then would be 
treated differently through this stage. In 1993, what we did is 
started to take each individual lease that was rented by the 
oil company and give them certainty so that the period of 
development they would be able to keep the lease. Second, they 
would file an annual mining plan, an annual review plan, an 
annual audit plan, with the province of Alberta.
    They would be regulated in environmental practices and 
mining operations by an arms-length regulatory body called the 
Alberta Energy Utilities Board; which today monitors their 
activities on a daily basis.
    And then, in 1996, we started on what we call the generic 
royalty program; which then said, ``One percent of your 
production revenues, until the project is paid out; then we 
move to a 25 percent royalty structure of net revenues.'' And 
that really was the kick start.
    And that was combined with a Federal contribution of 
accelerated depreciation, or accelerated capital cost 
allowance, where they could write off in one year what they had 
spent in the terms of that year's investment.
    Those factors really contributed to recognizing the front-
end-load risk of capital; and through that, helped us bank a 
total investment of some $80 billion now into these oil sands. 
So it was very much certainty, very much transparency, and then 
a working partnership of shared technologies, that helped 
stimulate the development.
    And those started to move in terms of, if you mine the 
first 80 feet of oil sands, you can mine it using truck and 
shovel. However, to make the deeper deposits economical, we use 
a process called steam-assisted gravity draining. And what that 
is, is we inject steam into the bitumen and we then heat the 
rocks up enough to make the bitumen flow into a pipe, and which 
is then piped away. Eighty percent of our oil sands resource 
will be developed through this system.
    That technology was developed and is now shared by more 
than one company. And I think that that non-proprietary sense 
really accelerated our development. And so each time we 
leapfrogged in technology, we were also able to put additional 
downward pressure on cost; to the point where we, you know, see 
this now competing worldwide on a very favorable basis.
    The last thing--and you know, from a conservative 
government you sometimes wonder about the wisdom of it at the 
time--but in fact, the government of Alberta owned 10 percent 
of the oil sands, the initial oil sands development, and was an 
active equity partner; and only discharged its equity interest 
in 1995. But I think that what we found is that actually 
holding an equity interest was more of a hindrance than it was 
a catalyst. And so by divesting, we then in fact accelerated 
the growth and development of the oil sand.
    Mr. Gibbons. Well, Mr. Smith, let me follow up with what 
you just told this audience. I think it is very important to 
note that the Canadian Government, and the province of Alberta, 
stuck with this program back when oil was on the market for 
less than $20 a barrel--probably in the $10- to $20-a-barrel 
range--which says a great deal about the confidence of the 
Canadian Government, and the Alberta government, as well, with 
approaching this issue. To get to where you are today of 
producing 1 million barrels of oil per day from these oil sands 
I think gives great credit.
    We are pleased that you had the foresight, but also the 
gravamen, to stick with it, as they say, so that you are now in 
that position to demonstrate I think to not just the world your 
ability to produce, but you are actually demonstrating a 
marketable product today that when you began was questionable 
at $35 a barrel.
    I think it is just a remarkable story that you have to tell 
us, and we are very glad that you were here to explain that.
    Mrs. Drake, do you have any additional questions for this 
panel?
    Mrs. Drake. No, thank you, Mr. Chairman.
    Mr. Gibbons. You know, I have several questions for this 
panel. But I notice that the time is dragging on. We have kept 
you gentlemen here for an hour and a half. We have a second 
panel.
    I would like to mention that we would have some written 
questions to follow up to ask, very important questions about 
the process, about the efficiencies. There will be questions 
about going forward with technology: how do we share 
technology; how do we develop this resource in the short-term 
future? I think for this country, for this Nation, working 
together, developing technologies, are critical for the 
development of this resource, to overcome our dependence on 
foreign oil.
    We as a nation owe it to the people of this country to do 
what we can to expedite this energy resource, so that we have 
the ability to provide oil for the economy to make it run in 
this country. So you gentlemen sitting here today have opened 
the door to, I think, a very bright future.
    And I think we can safely say that our energy future with 
regard to oil and gas has yet to see its brightest days, 
because of what you are doing in the oil sands, the oil shales, 
and the heavy oil unconventional market today.
    So with that, I want to thank each and every one of you 
all, excuse this panel, and call up our next panel, if I may.
    The second panel will be Mr. Russell George, Executive 
Director of the Colorado Department of Natural Resources; and 
Mr. Michael J. McKee, Commissioner, Uintah County, Utah.
    While we are waiting for these gentlemen to approach the 
witness table, let me submit for the record the testimony of 
Juan Antonio Granados, President of Shale Oil Information 
Center, Incorporated.
    [The statement of Mr. Granados submitted for the record 
follows:]

            Statement of Juan Antonio Granados, President, 
                   Shale Oil Information Center, Inc.

Liquid Fuels from American Shale and Tar Sands--The Challenge-- The 
        Mission
    Today, 70 percent of all liquid fuels are used to sustain our 
efficient transportation system; the envy of the world; our Achilles 
heel. Damage to it, will destroy our economic system. What we are 
talking about here today will take 10 or 15 years to be fully 
implemented ``if we start this year, enough time for the enemies of 
America, in the Middle East and in Venezuela to bring us to our knees. 
Thereto, our challenge here today. And $150.00 oil, maybe?
    In 1979 the late Dr. Armand Hammer prophetically wrote ``The 
escalating price and growing shortage of petroleum are beginning to 
influence our life styles and employment patterns, and to compromise 
our standard of living''. He said this while promoting the development 
of our oil shale resource. What happened?
    This Congress can elect to take the high and responsible road to 
promote the full and reasonable development of the Colorado/ Utah/ 
Wyoming oil Shale and tar sands resource as soon as possible. This is 
the true national challenge and should be the mission undertaken.
    In 1976, two short years after we were all waiting in line to get 
gas, the then President Carter gave a speech announcing an energy 
program that he described as the ``moral equivalent of war''. At that 
time there was still plenty of easy to discover and to recover oil, 
and, plenty of excess capacity at OPEC's disposal as well as outside 
OPEC.
    Both Alaska and North Sea oil were in a full upward production 
swings. But today?. Today, we are not as fortunate.
    There is plenty of evidence that has emerged over the past decade 
that the epoch for easily, and cheaply discoverable oil is behind us 
now. Yet the world demand for liquid fuels has been steadily increasing 
and has already approached available maximum production. This steadily 
increasing demand ``which has been underestimated by many experts, has 
been to satisfy the new needs for liquid fuels in the newer emerging 
economies of Eastern Europe, India, Southeast Asia and China.
    This past year alone, the combined demand increases by both China 
and India have exceeded the yearly, daily average net new production 
capacity additions from non-OPEC sources. This newer capacity additions 
had been averaging about 1 million barrels per day every year for the 
last 10 years, and are expected to accelerate to about 1.5 millions 
barrels per day per year, for the next several years. But this is not 
enough, so our dependence on OPEC oil will continue to increase, and so 
thus our vulnerability.
    Therefore, we have to expect that without increases in new liquid 
production from other sources, such as shale oil, supply growth will 
constrain future demand growth, and our economic growth and well-being 
will slow down or deteriorate. The only time, supply additions will 
grow faster than demand, would be if there is a severe recession.
    How can we as a nation sit and watch impassively while the mayor 
oil companies are all loaded with tons and tons of cash, not knowing 
what to do with it, while our oil shale resource remains unused?
    Does it not, therefore, make sense for us to create the ``right'' 
incentives for the oil companies to invest all that accumulated cash? 
Does not this accumulation of cash signal two evident warnings--One, 
that the oil companies are short of available new prospects, and two, 
that whatever is available is considered too risky for them to invest? 
Does this not suggest that this is an unsustainable national security 
situation?
    Our responsibility goes beyond proposing to Congress a limited 
program to develop the technology to extract the liquid from the rock, 
it goes to propose a comprehensive program that addresses all the 
issues and create the necessary incentives and guarantees so that our 
cash loaded oil companies proceed to the intense and responsible 
industrial undertaking of massively extracting the oil from the rock 
from the entire shale and tar sand resource. A maximum priority of our 
National Security.
    If adequate market incentives are in place that eliminate or reduce 
market risks and assure reasonable profits, the oil companies will come 
up with the technology. We will shorten the time for the availability 
of the fuel from the shale and the tar sands by many years.
    The Bureau of Land Management (BLM) must again make available the 
land containing the shale oil to these companies. Our government must 
provide a guarantee that each barrel of liquid fuel that goes into our 
domestic pool and that was extracted from U.S. shales or tar sands is 
guaranteed an indexed minimum price that reduces investment risk and 
provides an adequate return to the investor. My educated guess is that 
that price today is equivalent to $50.00 or $60.00 a barrel of crude. 
This guaranteed minimum is needed so that there is not a repetition of 
the earlier mistake with the shale oil program. The extraction projects 
were abandoned, when the price of crude dropped and when the newly 
elected President Reagan cancelled the subsidized purchases of fuel 
from U.S. shales by the Department of Defense. An accelerated 
depreciation schedule until the year 2035, that would allow writing off 
in less than three years the equipment required to extract the oil from 
the rock, should be authorized to stimulate industry to make the 
enormous investment required. Finally a ten year tax holiday beginning 
on January 1, 2006, ending on December 31, 2015 to incentivate industry 
to jumpstart the reasonable commercial development of the resource.
    I want to share with you my experience in the ethanol for fuel 
program which was successful and very profitable. It is important that 
we draw lessons from the past so that we can set the right course from 
the beginning. My contributions were essential to getting the alcohol 
fuels program going. Later my commercial activities continued to be 
profitable to me and many others. I had the opportunity to watch from 
the sidelines what happened to the alcohol fuel program. Mainly its 
successes. Successes and failures, also occurred in the earlier shale 
oil program. We cannot afford for the sake of our national security and 
our economic survival to make the same mistakes.
    Congress came out with a program which incentivated demand and use 
by exempting from the excise tax on motor fuel each gallon blended with 
10 percent anhydrous ethanol. This was sufficient to encourage a large 
grain processing company to begin making the investments in the 
distilleries to manufacture the ethanol. For a while there was only one 
big producer, since the other large grain processors did not believe 
that the incentives would be politically sustainable over the long 
term. The one company accepted the political challenge, and today, 25 
years later all of them are in the business and the incentives continue 
to exist. And the excise tax exemption continues to exist, with 
additional incentives for the production of ethanol.
    If similar market incentives were made available to each barrel of 
liquid fuel produced from American shales or tar sands, similar 
considerations would be given in the board rooms of the big oil 
companies. It is my belief that the risk that these incentive could be 
discontinued could be managed by a coalition of blenders, refiners, 
consumers and Americans concerned with the security of our 
transportation system. Let's not forget that what the American consumer 
wants most is the ability to gas up, and not wait in line. They are 
willing, as demonstrated by the recent experience over the last few 
months, to pay well over $2 per gallon as long as that gasoline is 
available to them. So supply reliability is upper most in the 
consumer's mind, more so than prices. Europeans, have gotten accustomed 
at paying over $5/gallon, and our consumers will eventually do 
likewise, if we can prove to them that the alternatives are long lines 
at the gas stations.
    It is time to do what must be done. It is today that it must be 
done. Ten years from now it will be too late. We owe it to the brave 
young men and women that are risking and losing their lives defending 
our freedoms. Let us do our part.
                                 ______
                                 
    Mr. Gibbons. And gentlemen, before you sit, we still have 
that procedure to go through of swearing you in. So if you 
will, just raise your right hand and repeat after me.
    [Witnesses sworn.]
    Mr. Gibbons. Let the record reflect that our witnesses 
answered in the affirmative.
    We turn now to Mr. Russell George, Executive Director, 
Colorado Department of Natural Resources. Mr. George, welcome 
to the Committee. Thank you for coming this far to help us 
better understand this issue. The floor is yours. We look 
forward to your testimony.
    May I say, also, that we have a little clock in front of 
you that shows five minutes. If you can sum up, we have your 
written statement, which will be submitted in complete order 
for the Committee. So if you want to summarize and talk a 
little bit about your ideas in the five minutes you have, that 
is also very helpful.
    So Mr. George, the floor is yours.

       STATEMENT OF RUSSELL GEORGE, EXECUTIVE DIRECTOR, 
            COLORADO DEPARTMENT OF NATURAL RESOURCES

    Mr. George. OK. Thank you, Mr. Chairman and members of the 
Committee.
    I did take advantage of your rule that allows me to add 
appendices to our own comments. And because we're talking about 
state and local government aspects here today, I took that 
opportunity to enclose a recent statement from a consortium of 
local governments in northwest Colorado that I thought was very 
important to share with you. And I'm quite confident that as we 
talk about Utah, local government views will be very similar 
and very compatible. So I would urge you to also note that that 
document is present in my remarks.
    A very complicated subject, very hard to summarize in the 
few minutes; so I'm going to just bounce across what I think 
are the main points that we think about at the state level. And 
certainly, I want you to know that Colorado is a very willing 
partner in the development of this resource. We regard the 
resource as abundant, as we've been hearing here today, and its 
development very much in the national interest.
    But we're very specific about some conditions of how the 
development of that resource should proceed. First, we would 
agree with others that technology and environmental oversight 
must be very rigorous, from beginning throughout.
    Second, we believe that development must use the best 
available practices, best management practices, to minimize all 
impacts that come from this kind of heavy industry.
    Next, we believe that state and local needs must be 
anticipated ahead of time, and some arrangement made ahead of 
time for funding; and that development on public land--and in 
northwest Colorado, this will occur mostly on public land--must 
be prioritized by resource and region. Just noting that in the 
last 20 years, since we had the last oil shale effort, we now 
have on this same property a rapidly expanding natural gas 
development. And there are other resource uses also existing 
that all need to be prioritized, and allow all to work 
together.
    Also, it's our view that the cumulative impact of mineral 
and energy development on all public lands, as well as private 
lands, must be mitigated.
    Colorado has consistently supported the development of the 
oil shale resource in western Colorado. But we've insisted, and 
would again insist, that the projects be fiscally and 
environmentally sound from beginning and throughout, and that 
the communities, local governments, do not incur extraordinary 
economic burdens. The development of the energy project must 
pay ahead of time its own way, so that the remaining 
communities can keep pace but not have to generate other 
resources to respond.
    Oil shale leasing on top of existing energy development and 
changing land uses--for example, we have increasing tourism and 
recreation; we have an expanding urban population throughout 
western Colorado--all of this may put more pressure on an 
already fragile ecosystem and public temperament.
    The response to that, of course, is we need to be careful, 
be respectful, as we go forward. We think we should go forward, 
but paced and respectful is the way to do that.
    So there are three things that we think we can do and 
should do. Federal financial support must be sustainable over 
an extended period of time, to encourage private sector 
investment. Also, a thorough environmental review process must 
occur. And, a financial safety net for local governments that 
allows for growth to pay its way and allows front-end 
financing.
    Three things should not occur. This is something we've 
learned from our history and our past mistakes. One, processes 
that preempt or supersede local and state land use and 
environmental processes should not occur. In other words, we 
can't have the Federal system saying, ``We'll supersede local 
and state rules and requirements.'' We can do this together in 
a type of joint review process, but not one over the other.
    The development of technologies cannot occur without 
adequate oversight. We need to ensure both public acceptance 
and environmental compatibility.
    And also, the national effort must address financial and 
infrastructure needs at the local level. And we have a number 
of ways of doing that. There is a revenue stream, because this 
is public land, that can help us do that.
    I think that's enough time for now. I'll be available for 
your questions, Mr. Chairman. Thank you very much.
    [The prepared statement of Mr. George follows:]

           Statement of Russell George, Executive Director, 
                Colorado Department of Natural Resources

    Mr. Chairman, thank you. I appreciate your invitation to 
participate in this hearing. I am Russell George, Executive Director of 
the Colorado Department of Natural Resources. As the lead state agency 
responsible for natural resource management, I appreciate the 
opportunity to provide our perspective on renewed oil shale development 
in Northwest Colorado.
    We are excited to be partners in this effort to move our great 
nation closer to energy independence. With perhaps as much as two 
trillion barrels of oil locked in the shales of western states, this 
vision is achievable in our lifetimes.
    As a lifelong resident of ``Shale Country'', I would like to share 
some thoughts with you on three decades of lessons learned regarding 
the impacts and possible tools to manage the development of the 
resource successfully.

Background Principle
    The State of Colorado has consistently supported the development of 
oil shale resources in Northwest Colorado since the Arab Oil Embargo of 
the early 1970's. Our focus has been on making sure that the projects 
are fiscally and environmentally sound, and that the communities do not 
incur extraordinary economic burdens. As history has shown, if 
development pays its way, the community impacts are less if the 
projects do not materialize.

History
    Let me summarize the key elements of the oil shale development 
cycles of the last three decades.
    Oil Shale Lease Bids. The federal government leased two tracts in 
each state--Colorado, Utah, and Wyoming--in the early 1970's. Bonus 
payments accompanied each of these leases--that determined the winning 
bid for the lease. Half of those bonus payments were distributed back 
to the state. The General Assembly established the State Oil Shale 
Trust Fund and Program which developed planning and coordination 
mechanisms for federal, state, and local governments and provided 
funding for designated local government services and projects ($100+ 
million). The goal was to mitigate the ``boom town'' syndrome.
    The Energy Mobilization Board. As the energy crisis worsened in the 
late 1970's, the Executive Branch of the Federal Government pondered a 
national board that could declare the development of a resource in the 
national interest--thus preempting local land use regulations and much 
of the state permitting process. The Western Governors, in particular, 
led the effort to oppose this preemptive measure by the federal 
government. The Board never materialized.
    Synthetic Fuels Corporation. Congress funded the Synthetic Fuels 
Corporation to initiate oil shale projects in a manner that would allow 
several technologies to develop simultaneously. Congress allocated $15 
billion in price guaranties and price incentives that were 
competitively awarded on a multiple year cycle. In a large part, this 
approach made the federal government a partner in accelerated 
technology development.
    Joint Review Process. In response to the national focus on the oil, 
gas, oil shale, coal and uranium resources in Northwest Colorado, 
Colorado developed the concept of a Joint Review Process. That process 
consisted of a centralized facilitation of the permit process at the 
local, state, and federal level. The Joint Review Process Program 
determined the timelines of the various required permits, coordinated 
the scoping process for the environmental impact statements, and 
facilitated public hearings and public comments. The overall 
coordination of the effort could allow for the application of several 
permits for an individual project to occur simultaneously. All the 
major oil shale projects, associated power plant projects, and coal 
mines used the Joint Review Process.
    Cumulative Impacts Task Force. In addition to the permitting and 
environmental analyses related to the simultaneous development of 
multiple resources, the State of Colorado was also concerned about the 
fiscal impact to individual communities and counties in high 
development areas. To that end, the state developed the concept of the 
Cumulative Impacts Task Force that modeled the budgets, revenues and 
expenditures of 104 jurisdictions in Northwest Colorado. The key task 
was to determine what projects would cause what economic impacts to 
what jurisdictions in what years based on different population and 
development scenarios.
    The effort proved to be extremely valuable when Exxon closed its 
Parachute Creek facility. At that time, because of the front-end 
analysis work, the distribution of energy impact funds, and the use of 
the Oil Shale Trust Fund, long-term economic impacts were manageable. 
At the time of the Exxon pullout, only one school district had a 
multiple hundred thousand dollar residual impact.
    DOE Technology Partnership. In the late 1980's, Occidental Oil 
under the leadership of Armand Hammer, proposed the cooperative 
development of an improved oil shale technology at the C-b Oil Shale 
Tract in Northwest Colorado. This was to be a 50-50 partnership of 
Occidental and the Department of Energy. Through the work of the state, 
the Department of Natural Resources, and the Associated Governments of 
Northwest Colorado, a seven-year commitment of funds was secured from 
the Department of Energy for this demonstration project. The other oil 
shale states contributed to the technology analysis for the project. 
The primary market was not for processing shale oil into motor fuels, 
but as chemical feedstocks for other uses. The project terminated upon 
the death of Armand Hammer when corporate directions were changed.

Technology and the Environment
    In the 1970's and 1980's, the Project Independence Technology 
Assessments and the Synthetic Fuels Corporation financial plan focused 
on both in-situ (in the ground), surface, and modified in-situ 
technologies. The goal for synthetic fuels was an industry that would 
convert coal, tar sands, and oil shale to liquid fuels at a level of 
two million barrels per day by 1992--the majority of which would have 
come from western oil shale.
    The dimensions of the proposed technologies were immense. A surface 
oil shale mine associated with a minimum-sized (50,000 BPD) commercial 
plant would be comparable in size to the largest iron and copper mines 
in the world. This scale was necessary since it required 2.5 tons of 
rock to produce one barrel of oil.
    Underground (in-situ) processes would have recovered less resource. 
Such mines would need to produce as much as 100,000 tons of rock each 
day to support a 50,000 BPD facility. The ore would be processed 
(retorted) above ground. Disposal of the spent shale in some cases 
would have filled valleys.
    The most advanced technology was modified in-situ. That technology 
mined a portion of the deposit by conventional methods for surface 
processing. The remaining shale was then fractured by underground 
detonations, the rubble ignited, and the oil transmitted to the 
surface. This process would recover less, but with less surface impact.
    As you can see, the surface area requirements for mining, 
retorting, or spent shale disposal were significant. Costs were 
enormous even in 1980 dollars--an average of $2 billion for each 50,000 
BPD plant. Based on the applicable 1977 Clean Air Act standards, 
production in NW Colorado would have been limited to 400,000 BPD. Water 
requirements for a 50,000 BPD facility would require 8500 acre-feet per 
year of water.
    In the end, the oil shale industry collapsed of its own weight--
given the volumes of material to be removed and processed, the 
enormously fluctuating world oil price, and the lack of a consistent 
national vision for the development of this resource that could focus 
private capital investment.
    While we do not know the specifics of the technologies that may be 
pursued over the next decade, we do know water availability, materials 
handling, power requirements, and transportation networks must be 
assessed in detail and the impacts mitigated appropriately.

What Worked--What Didn't Work
    If the Federal Government is to contemplate a renewed oil shale 
effort, it must do so based on the lessons learned over the past thirty 
years. While the technologies are changing, so are the characteristics 
of ``energy country'' in Northwest Colorado.
    As in the 1970's, we have record coal production that is straining 
existing transportation networks. We have record natural gas production 
levels and increasing permitting for natural gas development. The 
diverse development of this resource has dotted the landscape, 
increased truck traffic on county roads, and access to the resource has 
impacted many private landowners where the surface and mineral estates 
are severed. Additionally, there is a growing public sensitivity to in-
situ activities, such as fracking with ``proprietary fluids''.
    This development overlaps an area with increasing tourism and 
recreation opportunities and an expanding urban population. Oil shale 
leasing on top of this existing network of energy development and 
changing land uses may put more pressure on an already fragile 
ecosystem and public temperament.
    We do not control world oil markets, nor do we control the actions 
of OPEC. Therefore, the development of oil shale cannot be purely price 
driven. It must be a commodity of national interest developed on public 
lands in the national interest. That implies a prioritized use of 
public lands for the development of specific resources. Federal 
financial support must be sustainable over several decades to encourage 
private sector investment. An environmental review process must be 
thorough. A financial safety net for local governments that allows for 
growth to pay its way, and allows front-end financing of some 
infrastructure needs and analytical tools, is essential.
    All this said, the implication is that bonus lease payments from 
federal leases for local government facilities and services are good. 
Long-term federal financial support that fosters private investments is 
good. A coordinated permit process with adequate public input is good. 
And analytical tools that allow state agencies and local governments to 
anticipate the timing and amount of revenues for impact mitigation are 
essential.
    What will not work are processes that preempt or supersede local 
and state land use and environmental permit processes. What will not 
work is the development of technologies without adequate oversight to 
insure both public acceptance and environmental compatibility. What 
will not work is a national effort that does not address financial and 
infrastructure needs at the local level.

Colorado Recommendations
    Colorado is excited to be a partner in the development of a 
resource that is both abundant and in the national interest. But it 
does intend that technology and environmental oversight be rigorous, 
that development use the best available practices to minimize impacts, 
that state and local needs are anticipated and funded, that development 
on public land be prioritized by resource and by region, and that the 
cumulative impact of mineral and energy development on both public 
lands and private lands be mitigated.
    Oil Shale Lands Suitable for Development. Given the density of 
natural gas and coal development in some areas of NW Colorado, the need 
for recreational/wildlife habitat/undeveloped areas, and the network of 
privately held oil shale lands that did not exist in the last boom, the 
federal government must determine those areas where oil shale 
development could be accommodated in a manner that is least disruptive 
to communities and existing activities. Not all types of resource 
development can occur everywhere. The carrying capacity of the land, 
communities and infrastructure must be evaluated. That will determine 
the suitable areas for coal, natural gas, and oil shale development.
    One type of mineral and energy development today, may preclude or 
limit another type of resource development tomorrow. We cannot forget 
that a consequence of the oil shale pull-out of the 1980's, and the 
sustained soft energy market in the 1980's, has been the transformation 
of the NW Colorado economy from an energy base to a tourism, 
retirement, second home and recreation base--and public attitudes have 
changed as well. That cannot be underestimated if accelerated 
development is to resume.
    The lead federal agency in this new effort should provide this 
cumulative impact analysis and identification of areas suitable for oil 
shale development as an element of any development and leasing plan. 
Furthermore, we should insist that parcels available for leasing should 
be of sufficient size and number to ensure that operations are 
commercially viable and similarly situated with lease programs for 
other mineral and energy resources.
    Oil Shale Lease Bids. Along with an oil shale lease process that 
generates front-end revenue and production royalties for the federal 
government, the 1970's concept of the bonus bid should be applied to 
any oil shale leases in the future. For the tracts leased in Colorado, 
a sum of over $100 million was collected and distributed to the 
impacted counties. This economic cushion is essential to community 
stability, and the ability to withstand the economic shock of a project 
termination.
    The federal leasing program to be implemented in this new effort 
should insure that the bonus bid concept continues, and the proceeds 
are distributed to the state in which the lease is located.
    Federal Financial Support. Several options have been pursued 
through the years to fund technology development. Tax credits have been 
one avenue that proved very successful for coalbed methane development. 
Incentives like those of the Synthetic Fuels Corporation have been 
another. The DOE Demonstration Project route like that at Logan Wash is 
another. And the DOE cost-share like the Occidental C-b Oil Shale 
Project is another.
    Oil shale technology development is still fraught with uncertainty. 
Once a technology appears promising, it must be field tested. And then 
limited commercial scale production may occur. Collectively, this could 
span a decade or more. But the lesson learned from the 1970' and 1980's 
is that any financial incentive program must have a duration comparable 
with the timeframes for private investment that include a realistic 
timeframe for technology development and implementation, or the private 
dollars will not come.
    The Department of Energy should poll the industry prior to the 
passage of any legislation to determine the adequate minimum timeframe 
to encourage private investment.
    Coordinated Permitting Process. Given the economic transformation 
of NW Colorado in the past 20 years, coupled with the increasing level 
of natural gas development, a coordinated and integrated permitting 
process is essential. The environmental and land use permitting process 
can be complex and time-consuming when all the local, state and federal 
requirements are considered. Coordinating the process is essential, and 
cannot be underestimated. For the requirements in place 20 years ago, 
the average timeframe to permit an oil shale project was about 42 
months. Some processes have become more complex since then--and 
certainly public interest is more organized and focused.
    As a reminder, the Colorado Joint Review process grew out of the 
concerns raised over the concept of the Energy Mobilization Board. That 
Board would have had the power to preempt local and state regulatory 
requirements in the national interest. The reaction in the West was to 
coordinate and streamline, not dismantle, the existing process. And it 
worked. Attempts in recent years to truncate the process have been met 
with public criticism and lawsuits. Such efforts have proven to be 
counterproductive to the goal of developing these important resources.
    The Colorado Joint Review Process is an option that the federal 
government should consider fully funding, or partially funding along 
with industry, to assure a rigorous review with adequate public input 
and consultation.
    Economic Impact Analysis. Once the development area is determined, 
a procedure must be established to evaluate economic impacts at the 
local level. The federal government should fund, either through the 
bonus bid process or authorizing legislation, a concept similar to the 
tools used by the Cumulative Impacts Task Force. This analysis would 
not only guide the timing of needed permanent and temporary community 
services and infrastructure, but also allow local governments to 
establish fiscal tools that would insure that growth could pay its own 
way.
    The true cost of the development of strategic resources such as oil 
shale must be evaluated not only in the context of their technology and 
development costs, but also the costs and benefits to the community. 
Securing a safety net is the primary lesson of the last bust.
Conclusion
    It is essential that Congress consider the life cycle of oil shale 
development as it contemplates a renewed national oil shale effort. 
Only this view will portray the complete picture, so that the 
appropriate technology, environmental and economic structures can be 
defined and funded for a successful long-term effort. I look forward to 
working with you in the months ahead.
                                 ______
                                 
                               Appendix A

          A Local Government Perspective on Federal Oil Shale 
                    Research and Development Efforts

    Mr. Chairman and Members of the Committee:
    My name is Jim Evans, Executive Director of the Associated 
Governments of Northwest Colorado (AGNC), representing cities and 
counties in the 5-county region of Garfield, Mesa, Moffat, Rio Blanco 
and Routt Counties in Northwest Colorado. On behalf of our local 
governments I want to express our appreciation to your committee for 
asking our local government views on the development of oil shale 
technology.
    Our local government association was formed at the start of the 
last oil shale development cycle as the ``Regional Oil Shale Planning 
Commission'' with the specific charge to address the socioeconomic and 
environmental impacts of a potential commercial scale oil shale 
industry. Now, renamed as the Associated Governments of Northwest 
Colorado, we are still concerned with this issue. This time around it 
appears that our region will need to address the potential growth and 
infrastructure impacts of oil shale development on top of the 
socioeconomic impacts already occurring in our region from record 
levels of natural gas, oil and coal production. With estimates of from 
600 billion barrels to 1.8 trillion barrels of recoverable oil from 
shale in our region, we recognize the national interest in developing 
the technology for this resource. In particular, the needs identified 
for the Department of Defense for a secure domestic source of fuel make 
us realize that the importance of the resource cannot be ignored. We 
also understand the potential economic benefit development of this 
resource can play on our national balance-of-trade and G.N.P.
    Since more than 80% of the oil shale resource is located on 
federally-owned public land and recognizing that the future development 
is driven by national interests, local governments in our region 
believe the federal government must play a lead role in addressing 
these socioeconomic and environmental impacts and costs. We do not want 
to see local governments (and local taxpayers) stuck with the costs of 
new infrastructure and the mitigation of environmental impacts. So we 
are pleased to see that your Committee and the Department of Energy as 
we begin this next cycle in Oil Shale development are addressing these 
issues up front. This is a refreshing difference than the start of the 
last cycle. Back then, with an oil embargo facing the country, Congress 
first responded with a proposal for an Energy Mobilization Board with 
the power to declare Northwest Colorado as a ``National Sacrifice 
Zone''. Fortunately, that proposal did not make it all the way through 
Congress and as my following testimony indicates, we learned a lot 
during a fairly painful 18-year boom/bust cycle prematurely attempting 
to develop commercial scale projects.
    This time we appreciate the ``Research and Development'' type 
approach being put forward by the Department of Energy, and by the 
recognition of your Committee up front that you are looking for 
development of an environmentally friendly technology, and an approach 
not dependent upon the price of oil.
    Because we support your stated approach it gives me the opportunity 
to say,
        ``I am from the Local Government, and I am here to help you.''
    I would like to start my help by submitting for the record the 
following resolution from Club 20, the community based Colorado 
organization representing cities, counties, businesses and citizens 
throughout Western Colorado. This resolution was unanimously adopted by 
the Club 20 Board of Directors endorsing a Research & Development 
program as being considered by your Committee.
                                 ______
                                 

 Club 20 Support for an Economically Viable And Environmentally Sound 
                        Oil Shale R & D Program

Whereas Oil shale may still be the largest untapped resource available 
        for transportation fuels;
Whereas the richest deposits of oil shale in the world are located in 
        Northwestern Colorado and Eastern Utah;
Whereas a DOE report indicates that oil shale development may still be 
        important for our country's National Security (as an 
        alternative to imported oil) and for our Economic Security (to 
        improve our balance of trade); and
Whereas without a well conceived federal R & D program this region may 
        again someday be faced with another crisis oriented commercial 
        scale oil shale program.
Now therefore be it resolved that Club 20 supports research and 
        development efforts leading to an economically viable and 
        environmentally sound oil shale program.
Further, Club 20 supports DOI/DOE/DOD efforts to develop a national oil 
        shale policy and long-term R & D plans.
                                    Approved, Feb. 15, 2005
                                   Club 20 Energy Committee
                        Club 20 Natural Resources Committee
                                    Approved, April 1, 2005
                                 Club 20 Board of Directors
Background: Last Oil Shale Development Cycle 1974-1992
      The last oil shale cycle started with the Arab Oil 
Embargo in 1974. This was a Sudden Oil Shortage, resulting in long 
lines at gas pumps, temporary high gas prices, and a staggering impact 
on the U.S. Auto Industry and U.S. economy, aggravated by gasoline 
rationing.
      Congress responded in a crisis mode.
      The first industry proposal to local government was: Get 
out of the way and we will develop Oil Shale! Congress responded with a 
Proposal for Northwest Colorado to be declared a ``National Sacrifice 
Area'', including an Energy Mobilization Board with power to override 
Federal, State and Local environmental and land use laws. State and 
Local governments responded on an adversarial basis.
      President Jimmy Carter instead got Congress to establish 
the Synfuels Corp. with $15 Billion in price guarantees and price 
incentives.
      In our region 12 projects were underway at peak of cycle 
(either in planning, permitting or construction).
      An Exxon White Paper suggested a socioeconomic impact of 
a one-million population increase in NW Colorado by 1990. It appeared 
that all the construction workers in USA would be required for the 
effort if all the companies went forward at the same time.
      The Colorado projects reaching construction or testing: 
Exxon Colony Project, Unocal, Oxy (CB), CA consortium. The DOE Anvil 
Points facility in the meantime was pretty much abandoned, except for a 
look at an asphalt additive byproduct.
      The cycle collapse (Bust) started May 2, 1982 with an 
abrupt Exxon Colony closure. In the Boomtown Blues book, this event was 
blamed for the U.S. and worldwide recession.
      The Unocal project & Oxy continued their efforts through 
1990-92. This somewhat mitigated the ``bust'' cycle. At the peak of the 
cycle, the combined population of the 2 most impacted counties 
(Garfield and Mesa) increased from 1981 to 1983 by 12%, from 112.0 
thousand to 125.6 thousand. Then in the next 2 years the combined 
population dropped back to 111.8 thousand.
      Congress then overreacted and shut down virtually all oil 
shale research programs, despite recommendations from many sources that 
research and development activities should continue.
Was Anything Learned During This Cycle? Yes!
      Congress in 1975-76 enacted Mineral Leasing Act 
Amendments at the urging of States and Local Governments. The State 
share of federal royalties increased from 37 1/2% to 50% with priority 
for local governments impacted by Mineral Leasing activities, such as 
Oil Shale, Oil, Natural Gas and Coal.
      Congress enacted Payments-In-Lieu of Taxes (PILT) Act to 
compensate counties for tax exempt federal land thereby giving direct 
assistance to rural public land counties.
      States in turn enacted Severance Taxes, also with a 
priority to address socioeconomic impacts.
      Local governments in turn enacted Major Impact Land Use 
Mitigation Ordinances.
      The Colorado Joint Review Process (CJRP) was initiated. 
This was a voluntary program designed to coordinate and speed up 
federal, state and local permitting.
      Local Government Energy Impact Programs were established 
by States with the new Revenue from Mineral Leasing and Severance 
Taxes. These programs today address the ongoing impacts of mineral 
development. The Energy Impact Program in Colorado actually started 
with the formation of the Regional Oil Shale Planning Commission (now 
AGNC) and the enactment of the Oil Shale Trust Fund (OSTF). From the 
OSTF $75 million plus interest was allocated to NW Colorado counties. 
The $75 million was Colorado's 37.5% of federal Oil Shale leasing 
bonuses.
      Negative impacts of the abrupt Exxon Colony Project 
closure actually resulted in a positive turnaround on State/Local/
Industry relationships and communications as Unocal and Oxy proceeded 
with their projects with local support.
      Local governments also supported continuation of the 
Unocal and Oxy projects, including proposals to turn them into federal 
oil shale technology demonstration projects.
      Support for a Federal Oil Shale R & D program was 
generated in Colorado, Utah, Wyoming, Kentucky, Illinois and 
California, but to no avail.
      New Paraho Corp. temporarily continued oil shale asphalt 
testing at Anvil Points to demonstrate the byproduct approach to make 
oil shale economically viable. Some of the asphalt test strips are 
still in place with no repairs required.
    Local Government Advice to Industry for the Next Oil Shale 
Development Cycle: Communicate! Communicate! Communicate!
    The Shell Oil Shale Project is on the right track. Shell Oil is the 
only company in Colorado who is currently continuing with field-
testing. Local governments appreciate these efforts. Their efforts have 
included ongoing meetings with County Commissioners, Cities, school 
districts and citizen groups. They have sponsored and organized town 
meetings. These were very successful from a local perspective. These 
should continue at the beginning of each phase of an R & D program.
    The Department of Energy also appears to be on the right track. The 
Naval Petroleum and Oil Shale Reserve Office of DOE has prepared a well 
documented and thorough report indicating the National interest in 
developing the oil shale resource (trade deficit impact on the economy 
and national defense interest in a secure oil source.) We believe 
addressing the socioeconomic and environmental issues in the DOE 
proposal for a National R & D program and demonstration facility is on 
target. Virtually all groups and industry involved in the last oil 
shale cycle have recommended the need for an ongoing federal oil shale 
research program.
    These Groups and individuals back in 1991 were: The Rocky Mountain 
Oil & Gas Association, The Western Oil Shale Action Committee, Club 20, 
Associated Governments of Northwest Colorado, The Garfield County 
Citizen Alliance, Governor Roy Romer, Senator Tim Wirth, Representative 
Ben Campbell, The Rebuild America Foundation, The Alternate Energy 
Research Institute, and The Rocky Mountain Institute. There may have 
been others. These were the ones that I was aware of.
Recommendation to Address the Socioeconomic Impacts of the Next Oil 
        Shale Cycle
    With the renewed interest in oil shale development, the Department 
of Energy needs to provide funding for socioeconomic programs to:
      Assemble and update impact data from the last cycle.
      Identify appropriate computer systems/models to assess 
projected impacts.
      Development of baseline economic data for current 
activities.
      Help identify and provide revenue streams for local/state 
government services/infrastructure potentially impacted by oil shale 
development.
    DOE also needs to identify and recommend appropriate federal, state 
and local policies to encourage prudent and environmentally sound oil 
shale development.
Recommendation to Address Environmental Impacts of Oil Shale 
        Development
    The DOE Demonstration program/projects should address:
      Surface disturbance impacts and ongoing reclamation 
requirements.
      Air Quality impacts.
      Water Quality and Quantity impacts.
      Wildlife protection and mitigation requirements.
      Employee health, safety and training needs.
    Regular communications with news media and environmental groups 
should address the potential environmental impacts of various oil shale 
technologies.
    The Colorado Department of Public Health and Environment should be 
actively involved in monitoring air quality and water quality impacts.
    The State of Colorado Department of Natural Resources and its 
Wildlife Division should be actively involved in these reclamation and 
wildlife issues.
    The Department of Interior should develop a leasing program to 
accommodate access to oil shale for research and demonstration project 
purposes. Any commercial scale leasing proposals must include 
provisions that recognize the ``carrying capacity'' concepts for 
socioeconomics and the environment that are part of the BLM Piceance 
Basin Resource Management Plan.
Recommendation to Provide the Funding for Oil Shale Research Costs and 
        Incentives
    We believe it is fortunate that Congress may have already provided 
a potential source of funding for Oil Shale R & D efforts. This revenue 
may be currently available from the Naval Oil Shale Reserve (NOSR) 
lands themselves located in Northwest Colorado. As indicated in the 
attached letter from the Department of Interior, some $43.7 million may 
be accumulated by March 2007 in a U.S. Treasury account from the 
current natural gas leases on their NOSR lands. These NOSR lands were 
transferred by Congress from DOE to the Department of Interior with a 
Congressional priority established for natural gas leasing.
    Some of these funds, estimated at $5.8 million, are earmarked for 
environmental cleanup of the Anvil Points spent shale pile. Otherwise, 
we believe Congress has the opportunity for the remainder of these 
funds to be made available to address the socioeconomic and 
environmental aspects of oil shale development in Northwest Colorado.
    In the future, more revenue should be available from this source. 
According to industry estimates, additional leasing of the NOSR lands 
could produce leasing bonuses of up to $360 million (to be shared 50% 
federal and 50% state) plus ongoing production leases of an estimated 
$32 million annually for at least 20 years. That would be another $640 
million total also to be split 50/50 federal and state. Congress should 
establish a priority to address oil shale and other energy development 
impacts in Northwest Colorado from these leasing revenues.
    We believe this type of funding is necessary to make sure the DOE 
research and demonstration projects can proceed without interruptions 
from fluctuations in the price of oil.
    Thank you for this opportunity to testify. I would be happy to 
answer any questions you may have.
                         Jim Evans, AGNC Executive Director
                                 ______
                                 

   Response to questions submitted for the record by Russell George, 
      Executive Director, Colorado Department of Natural Resources

    We appreciate the State of Colorado's position, as stated in your 
testimony, that through the production of oil shale and other resources 
our Nation can become energy independent in our lifetime. We thank 
Colorado for its commitment to support production of the vast oil shale 
resources within its boundaries. We agree with you that this must be 
done in a responsible manner and we look forward to the Federal 
Government working closely with the western oil shale States as we move 
to produce this vast resource for the American people.

1.  What is the source of funds that the Congress should look to in 
        order to provide the financial resources to compensate for 
        socioeconomic and environmental impacts?
    Lease Bid Bonus Payments collected and distributed in advance are 
the most effective tool for the front-end financing of socio-economic 
impacts. As production develops, federal royalties and state severance 
taxes can also reimburse local communities for such impacts. This model 
worked in the 1970's/1980's, and should still be effective. This 
approach is validated in the testimony provided by the Associated 
Governments of Northwest Colorado.
    Environmental impacts are the responsibility of the permittee, and 
are embodied in the stipulations of the necessary federal, state and 
local permits required for such a project to proceed. For this reason, 
the existing public permitting processes should not be short-circuited 
to expedite production. Their timeframes allow for adequate public 
review and comment, as well as the regulatory tools to mitigate 
impacts.

2.  Given the fact that all resource development is contingent upon the 
        economics of production, which is primarily derived from the 
        price the product can command and the costs of production, what 
        can the Federal Government do to ensure that oil shale 
        production is economical?
    The State of Colorado is not convinced that it is the role of the 
federal government to make oil shale production economical. The 
economics of alternative fuels, like oil shale, are ultimately set in 
the international marketplace. However, it is an appropriate role of 
the federal government to support technology development, that can be 
done in three ways. First, through the development of oil shale 
technologies at federal facilities--such as the national laboratories. 
They played such a role in the 1970's/1980's effort. Second, the 
federal government can make federal lands and facilities available to 
the private sector to test oil shale technologies. All NEPA 
requirements would prevail. Finally, the federal government could make 
technology development grants available for private technology 
development projects. All these actions would in effect subsidize the 
cost of technology development, and ultimately the cost of the product.

3.  What policies of the State of Colorado will ensure that the local 
        governments receive their fair share of the State's one-half of 
        Federal royalties and the State severance tax on the production 
        of Federal oil shale?
    The appropriate state statutes guiding federal royalty 
distributions and state severance tax distributions have been in place 
since the 1970's. There is no need for modification at this time.

4.  How do you recommend that coordination with the State and local 
        governments on leasing and production be handled?
    It is the intention of the Department of Natural Resources to seek 
reauthorization of the Colorado Joint Review Process in the 2006 
legislative session. That process was developed in the 1970's partially 
in response to the oil shale boom. It creates a forum for public 
participation in the scoping of federal leasing and NEPA documents, as 
well as coordinated public review and comment in the federal, state and 
local permitting process. The core funding would come from the state 
severance tax fund. The federal participation will be funded through 
the relevant federal agencies, and the project proponents would fund 
the costs of the process specific to their project. Regulatory 
oversight under existing federal, state and local laws will guide the 
production and reclamation phases.

5.  What mechanisms should be put in place for engaging communities in 
        federal planning and program development? For example, would 
        Memoranda of Understanding with Regional Planning councils be 
        of value?
    As outlined in Question 4, the principal state process will be the 
Colorado Joint Review Process for leasing and permitting decisions at 
the federal, state, and local level. Local governments will coordinate 
the socio-economic impact analysis using funds distributed through the 
Bonus Lease Bid Process. There are no regional planning councils in 
Colorado. Their equivalent would be councils of government which may 
not have energy impacts within their purview. Therefore, the 
distribution of Bonus Lease Bid Funds as guided by state statute would 
ensure that the affected local governments would have access to the 
appropriate funds.

6.  We have heard proposals to direct mineral lease royalties from the 
        Naval Oil Shale Reserves in Colorado to the planning and impact 
        mitigation efforts of Colorado, Utah and Wyoming. Would 
        Colorado support this proposal?
    Assisting in local and regional impact planning and mitigation 
efforts is something Colorado has always supported. In the short-term 
Colorado would support using royalties from NOSR 1 and 3 for these 
purposes both here and in neighboring states, until such time the 
federal government is fully reimbursed for the infrastructure costs and 
environmental restoration work that was required as part of the 
transfer legislation. At that point, and we understand the full $43 
million will be realized in 2007, it would be necessary to resume the 
normal state share royalty distribution formula for federal minerals 
produced in NOSR 1 and 3.

7.  Oil shale may provide long-term energy security for the US. Would 
        Colorado support program planning and managing of this resource 
        as a Petroleum Reserve?
    Yes, as long as the management of such a reserve would be subject 
to adequate public participation including opportunities for public 
review and comment. Oil shale country in Colorado is also the site of 
competing resource development (coal, oil and gas), and competing land 
uses (recreation, agriculture, and mineral and energy development). 
This is the basis for Colorado's request that the federal government 
identify those areas suitable for oil shale development in light of 
competing land uses. The competing uses, as well as community needs, 
are the basis for a Colorado Joint Review Process to allow adequate 
public input on complex issues such as a Petroleum Reserve.
                                 ______
                                 
    Mr. Gibbons. Thank you very much. And we certainly 
appreciate the State of Colorado's position on this and your 
commitment and support for developing this, as well.
    We turn now to Mr. Michael McKee. Commissioner, welcome. We 
are happy to have you. I know it is a long way from Uintah 
County, Utah, here to be with us, and we certainly appreciate 
that. Welcome. The floor is yours.

         STATEMENT OF MICHAEL J. McKEE, COMMISSIONER, 
                      UINTAH COUNTY, UTAH

    Mr. McKee. Thank you, Mr. Chairman, and Committee members 
and staff members. And greetings from Uintah County, Vernal, 
Utah--Utah, dinosaur land.
    As has been brought out, there are vast energy resources in 
our area; including oil and gas, gilsonite, coal, tar sands, 
and oil shale. This past year, the Vernal BLM field office was 
the second-busiest field office in the United States, 
processing approximately 700 APDs, or Approved Permits To 
Drill. This past month, they processed over 100. So they're 
clicking right along.
    Moving to oil shale real quickly, a significant portion of 
the oil shale resources of the Green River formation are 
located in Uintah County, Utah. These resources are believed to 
be the most concentrated accumulations of hydrocarbons on 
Earth.
    The commercial attractiveness of these zones measure from 
50,000 barrels per acre to more than 1 million barrels per 
acre. This formation contains, and depending on testimony this 
morning, which numbers you look at, somewhere between 1 and 3 
million barrels per acre. That could equate to 2 to 3 trillion 
barrels of oil. And as has been mentioned, that's many more 
times than the total reserves located in the Mideast.
    In addition to oil shale, there are billions of barrels of 
tar sands of oil in our area. The issues in regard to 
development of tar sands mirror in many ways those of oil 
shale. We're speaking primarily of oil shale here today, but we 
have abundance of resource of both commodities.
    The majority of these resources are located on Federal 
lands managed by the BLM. The remaining resources are located 
on that of the state and of private companies, individuals, and 
Indian tribes.
    In the '70s and '80s, there was considerable interest in 
the development of oil shale. Driven by gas shortages of the 
'70s, the government, along with industry, put considerable 
resources into development of an oil shale facility in Uintah 
County, Utah. Local interest in oil shale development did not 
decline when that of the general government and industry did.
    One company, in particular, has conducted resource and 
development activity since 1993. The results are the 
development of a working retort that processes oil shale. This 
facility is currently attempting to obtain adequate feed stock 
to run their retort to enable an independent certification of 
its operation.
    Uintah County fully supports the development of oil shale 
and tar sands. And one of the main points we would make is the 
mistakes of the past should not be repeated. The President and 
Department of Energy have determined that increasing liquid 
fuel supply from domestic sources is an important national 
objective. Clearly, there's no greater opportunity to achieve 
this goal than the development of the Nation's oil shale 
resources.
    Some of the benefits that would come from that, as we're 
aware, is it would bring the balance of trade closer in line; 
reduce the competition for energy resources with Third World 
countries and developing nations; stabilize American industry 
with a more dependable fuel source; and provide the military 
with a source of fuel. Numerous byproducts could be produced.
    We believe that there is immediate need for action. We 
believe that government must play a critical role in removing 
impediments to the development. I'm going to list several 
suggestions, though this is in the testimony:
    Authorize and direct the BLM to develop a commercial 
Federal oil shale leasing program;
    It's been mentioned here this morning, but to repeal or 
modify the Mineral Leasing Act that currently restricts oil 
shale leases to one lease per company and a maximum 5,120 acres 
per lease, which of course is eight sections;
    Authorize and direct the BLM to exchange Federal lands for 
public or private lands, where appropriate, to facilitate 
development of the resources;
    Direct all of the Federal agencies to refrain from 
management practices that restrict access to resource and 
prevent the development of these resources, including the water 
resources;
    Authorize and direct the Department of Energy, in 
cooperation with the BLM, to access and make available the 
existing White River Mine, which was mentioned here earlier 
this morning, and facilities, as well as oil shale stockpiles 
for use by industry;
    This next point is a very important point to us in local 
government. Authorize the one-third of the total oil shale and 
tar sand royalties to come back to the county of origin. This 
funding would assist in mitigation of developing and 
maintaining social and economic impacts created with all 
energy-related development production;
    All forms of transportation will be necessary;
    We are suggesting that at task force be created consisting 
of Federal, state, and local government officials. Authorize 
this task force to utilize expertise of industry, scientific, 
and collegiate academia. Uintah County has considerable 
expertise and experience, and we would like to be part of this 
resolution.
    We would also like to, just as has been mentioned earlier 
here this morning, make an invitation to all members or any 
members of this Committee or this Subcommittee or members of 
the Resource Committee, to come out to our area and see what we 
have out there. We would certainly host you. We would be happy 
for you to come. And thank you for the opportunity to be here.
    I might also just mention we provided a little bowl that 
has some tar sands. That came from a mountain, or a hill about 
a couple of miles just west of Vernal. And there are mountains 
of these tar sands in our area.
    This also is a piece of oil shale that came from the White 
River Mine. If you were to break this oil shale open and were 
to smell it, it would smell a little bit like diesel. But 
essentially, it's algae.
    Thank you very much.
    [The prepared statement of Mr. McKee follows:]

             Statement of Michael J. McKee, Commissioner, 
                          Uintah County, Utah

               Oil Shale & Tar Sands, Uintah County, Utah

I. A BRIEF HISTORY
    In the '70s and '80s, there was considerable interest in the 
development of oil shale. Driven by the gas shortage of the 70s the 
government, along with industry, put considerable resources into the 
development of an oil shale facility in Uintah County.
    The decline in crude oil prices in the 80s resulted in the loss of 
government support for oil shale research and development, and 
subsequent termination of industry interest.
    All that remains of this effort is the White River Oil Shale Mine 
and associated facilities in declining condition and oil shale stock 
piles.

II. WHERE WE ARE TODAY
    A major portion of the oil shale resources of the Green River 
Formation are located in Uintah County. These resources are believed to 
be the most concentrated accumulation of hydrocarbons on earth. The 
commercially attractive zones measure from 50,000 barrels per acre to 
more than 1 million barrels per acre. The richness of these zones are 
well known.
    The majority of these resources are located on federal land managed 
by the BLM. The remaining resources are owned by the state of Utah, 
individuals, private companies, and Indian tribes.
    Because of the amount of resources existing under the federal 
lands, BLM resource management on these lands will greatly affect their 
development.
    Local interest in oil shale development did not decline when that 
of the general government and industry did. One company, in particular, 
has conducted resource and development activities since 1993. The 
results are the development of a working retort that processes oil 
shale. This facility is currently attempting to obtain adequate feed 
stock to run their retort to enable an independent certification of its 
operation.
    Uintah County fully supports the development of oil shale and is 
very concerned that the mistakes made in past efforts should not be 
repeated. Specifically, the lack of comprehensive and coordinate 
planning, impacts on community development and local infrastructure 
were not properly planned for or funding needs considered.

III. POSSIBLE BENEFITS
    The President and the Department of Energy have determined that 
increasing liquid fuel supply from domestic sources is an important 
national objective. Clearly, there is no greater opportunity to achieve 
this goal than the development of the nation's oil shale resources.
    The Green River formation located in our area contains three 
trillion tons of oil shale, which is 2-3 times more than the reserves 
located in Saudi Arabia.
    If these resources are developed, the United States could greatly 
reduce, and with conservation efforts, eliminate our dependency on 
imported oil and help reduce the balance of trade.
    Uintah County, the intermountain area, and the nation would benefit 
from oil shale development. As this development occurs, the following 
goals could be accomplished:
      Keep the social and economic benefits of the $20 billion 
per month spent on imported oil and spend it on development in the 
United States.
      Depending on the method used, there are numerous by-
products that could be produced.
      Provide the military with a long term and secure source 
of fuel.
      Stabilize American industry by having a more dependable 
fuel source.
      Reduce global conflicts related to energy access.
      Reduce the competition for energy resources with third 
world countries and developing nations.

IV. TAR SANDS DEVELOPMENT
    In addition to oil shale Uintah County has considerable tar sands 
resources. There are billions of barrels of oil in the tar sands in our 
area. The issues in regards to the development of tar sands in Uintah 
County mirror those for oil shale.
    Uintah County supports the development of tar sands, however, most 
of the comments in this document are on oil shale.

V. NEED FOR ACTION
    Government must play a critical role in removing impediments to 
developments, and neutralizing and mitigating investment risk.
    Policies, regulations and legislation are needed to make these 
resources available on terms attractive to industry while ensuring 
efficient resource development and equitable economic returns on 
investments.
      Authorize and direct the BLM to develop a commercial 
Federal Oil Shale Leasing Program with the goal of initiating leasing 
by December 31, 2006.
      Repeal or modify the Mineral Leasing Act that currently 
restricts oil shale leases to one (1) lease per company and a maximum 
of 5,120 acres per lease.
      Authorize and direct BLM to exchange Federal lands for 
public or private lands where appropriate to facilitate development of 
the resource.
      Direct all affected Federal Agencies within the confines 
of existing law, to refrain from management practices that restricts 
access to the resource and prevents the development of water resources 
needed for production and support infrastructure.
      Authorize and direct the Department of Energy (DOE), in 
cooperation with BLM, to access and make available the existing White 
River Mine and facilities, as well as, oil shale stock piles for use by 
industry to support demonstration and commercialization of oil shale 
technologies.
      Authorize the return of 1/3 of the total oil shale and 
tar sand royalties to the county of origin. This funding would assist 
in mitigation of developing and maintaining social and economic impacts 
created with all energy related development and production.
      All forms of transportation, including rights-of-way, 
roads, pipelines and other means, are necessary to the success of oil 
shale development. There are immediate needs for transportation 
improvements during the research and development phase. Once production 
starts there will be a need to transport the materials out. It is 
imperative to have cooperation between Federal and State land holders 
to allow access.
      Existing delays in energy related development and 
production permit approvals must be resolved to insure this problem 
doesn't carry over into the processing of oil shale leasing. Create a 
task force consisting of Federal, State and Local government officials. 
Authorize this task force to utilize expertise of industry, scientific 
and collegiate academia. Uintah County has considerable experience and 
has access to expertise related to this issue and would like to be part 
of the resolution.
      Impacts to other resources such as wildlife, grazing, 
soil and water must be offset by improvement in existing habitats and/
or carefully planned mitigation of impacts.

Mitigating Investment Risks
    Oil shale production is characterized by high capital and operating 
costs and long periods of time between expenditure of capital funds and 
the realization of production revenues. For ``first-generation'' 
facilities there is substantial uncertainty over the magnitude of 
capital and operating cost. Revenue uncertainty is imposed by not 
knowing future market prices. These and other uncertainties pose 
investment risks that currently make oil shale investment less 
attractive than other investment options.
    Public policy and legislation can lower investment risk by reducing 
cost and revenue uncertainties and by sharing in the financial risks. 
Public action is warranted when pursuing public goals of secure 
domestic fuel supplies and enhanced business and economic activity. The 
most effective of these actions include:
    Demonstration Projects. A cost-shared oil shale demonstration 
program would:
      Accelerate the timetable to the all-important first-
generation commercial production by helping to remove cost uncertainty,
      Broaden the base of investment interest among 
intermediate and independent producers that could not carry the 
development risks alone, and
      Serve as evidence of the public's commitment to this 
resource.
    Market Assurance: Authorize and direct the Department of Defense to 
specify and qualify shale oil derived aviation turbine fuels and to 
enter into purchase agreements at a guaranteed minimum and maximum 
price. This will serve to minimize market-acceptance risk and price-
volatility risk.
    Production Tax Credit: A production tax credit, indexed to 
inflation and capped or phased out at a ceiling price per barrel will 
enable oil shale to directly compete with foreign conventional oil. 
This could be accomplished by amending current ``Section 29'' tax 
credits for non-conventional fuels or through a new provision crafted 
for oil shale.
    Federal Royalty Relief: Federal royalty structure is not yet 
defined for oil shale extraction. Providing royalty relief in the 
research and development stages will significantly improve project 
economics. A fair return to the Federal government can be achieved by 
graduated royalty rates in later years, after investment payback.
    Accelerated Depreciation: Allowing front end capital investments to 
be depreciated in a shorter time than is allowed under current law 
could improve cash flow and could stimulate investment by enabling 
earlier payback. Royalty holidays and expended depreciation are 
credited as the two most important fiscal measures stimulating the 
production growth of Alberta oil sands.
    Investment Tax Credit: Congress should allow an investment tax 
credit similar to that which is proposed for coal-to-liquids projects 
to reduce up-front capital costs and accelerate payback.
    Depletion Allowance: Congress should allow oil shale projects to 
qualify for a percentage depletion allowance (similar to that for oil 
and gas resource extraction). This latter provision helps provide 
parity for private resource holders relative to the royalty holidays 
afforded federal lessees.

Community Development and Infrastructure Support
    Oil shale industry development and operation will cause significant 
population growth in the local communities, accompanied by requirements 
for investment in community infrastructure, such as roads, schools, 
hospitals, and other support services. Uintah County is a water short 
area. Adequate water supplies must be developed for both domestic and 
industrial use.
    Costs for engaging in the federal planning process and for planning 
and construction of infrastructure occur long before tax and royalty 
revenues are received from oil shale operations and associated economic 
activity. Development delays or industry failure pose additional risks 
to local communities. Planning must include a strategy to avoid boom/
bust cycles in local economy.
    To minimize the severity of impacts and mitigate the financial 
risks the following action is recommended:
      Authorize and direct the DOE, in cooperation with DOI and 
DOD, to develop a well-conceived federal Oil Shale Program so as to 
avoid a crisis-oriented response,
      Communicate with stakeholders to identify issues of 
concern and take measures to mitigate those concerns,
      Provide advance financial support for the communities and 
States to facilitate their engagement in the program development 
process and to mitigate cost burdens that occur before tax and royalty 
revenues are realized.

Streamline Regulatory Permitting
    Environmental impacts must be effectively mitigated through best-
available resource technologies and rigorous management utilizing 
adaptable and goal oriented management, not exclusionary management 
that is not practiced. Control of air emissions, water effluents, 
leachates from spent shale disposal, land reclamation design, and other 
environmental issues will need to meet published regulatory standards.
      Complying with these standards will require complete and 
comprehensive applications which should receive prompt review and 
action.
      Consistent with Executive Order 13212 ``Actions to 
Expedite Energy Related Projects'', it is recommended that the 
Interagency Task Force be reconvened and directed to coordinate with 
the EPA and state regulatory agencies and to review Federal 
environmental requirements that impact oil shale development and 
identify areas where permitting can be streamlined to achieve national 
energy goals. To date, the provisions of this executive order have not 
been implemented at the field office level or reflected in the recent 
resource plan.

Government/Industry Coordination
      Development and implementation of a well-considered and 
coordinated Oil Shale Program Plan requires goal-oriented management in 
government. To complement the short-term insurance policy provided by 
the Strategic Petroleum Reserve Congress should authorize and direct 
the Secretary of Energy to establish an Office of Strategic Fuels 
within the DOE Petroleum Reserves.
      The mission of this Office is to promote fuels security 
for the United States, provide the analytical basis for strategic fuels 
planning, oil shale program development and management, establish and 
administer functions of an interagency government/industry oil shale 
task force and manage outreach and education efforts related to Federal 
oil shale efforts. The charter for this office should include 
interaction with the Departments of Defense, Interior, and Treasury.
      Congress should authorize and direct DOE to establish a 
Federal Oil Shale Task Force, to include representatives from DOE, DOD, 
DOI, and the Department of Treasury, technical experts, and advisors 
from industry, impacted states and communities, and other stakeholders 
to coordinate and facilitate oil shale industry development efforts in 
an integrated fashion.

VI. PROPOSED OIL SHALE, RESEARCH, DEVELOPMENT AND DOCUMENTATION (RD&D) 
        PROGRAM
    In the supplementary information provided in the RD&D Program 
draft, it says that BLM intends to ensure that states and local 
communities have the opportunity to be involved in the development of a 
commercial program. Uintah County would like to see this involvement 
extended to include all NEPA and mitigation and mitigation issues 
associated with both RD&D and commercial development.
    In earlier comments Uintah County expressed concern regarding the 
adequacy of 40 acres to conduct RD&D operations. In the latest draft 
the 40 acres has been changed to 160 acres. The County's recommendation 
remains 640 acres.
    BLM considers 160 acres adequate to accommodate an R&P activity 
that can be envisioned. The County proposed 640 acres so as not to 
limit the type of R&D that can be located on the site. Perhaps 160 
acres could be established as a limit unless the proponent can, based 
on development plans, justify additional acreage not to exceed 640 
acres.
                                 ______
                                 

  Response to questions submitted for the record by Michael J. McKee, 
                   Commissioner, Uintah County, Utah

1.  What are the most important things that the Federal Government can 
        do to ensure that production of large quantities of oil from 
        oil shale happens in a timely manner and under appropriate 
        conditions?
    Response: There are several ways to ensure production of large 
quantities of oil from oil shale in a timely and appropriate manner. 
They are:
      Develop a national policy and strategic plans that 
recognizes oil shale development as a way to reduce our dependence on 
imported oil that provides for it's development in a coordinated manner 
and fully involving local governments and in recognition of the impacts 
of the development on them.
      Establish regulation for the commercial development of 
oil shale and expedite access to oil shale resources.
      Structure royalties and provide tax incentives that will 
allow lessee to accelerate recoupment of investment so as to encourage 
rapid development.
      Use planning method similar to that used by the National 
Petroleum Reserve to provide orderly and coordinate planning that will 
insure impacts to local communities are addressed and that 
infrastructure needs are well planned and such projects are in place 
prior to onset of development. There is a need to implement the 
planning process now.

2.  We note Uintah County's full support of oil shale development. Does 
        the State of Utah have policies in place that you feel will 
        provide Uintah County with it's appropriate share of revenues, 
        including royalties and severance taxes, that will be derived 
        from oil shale production? Do you feel that counties in which 
        production is located should receive a direct portion of the 
        royalties and bonus bids?
    Response: Utah does have policies in place for revenue sharing. 
However, political demographics prevent the counties of origin from 
receiving a proper share that adequately reflects impacts to 
infrastructure and governmental services. While County's such as Uintah 
create the majority of the mineral revenues for the State of Utah the 
portion of revenues return to the County is not reflective of that 
contribution. Uintah County strongly supports counties of origin 
receiving directly portions of revenues from development of natural 
resources on public lands within their jurisdiction. In previous 
testimony Uintah County has supported the return of 1/3 (one third) of 
total royalties generated and bonus receipts to the county of origin to 
offset cost of increased services, development of and improvements to 
infrastructure and impacts to the community.

3.  Should the State of Utah, and it's counties, set up a joint process 
        with the BLM to coordinate and speed leasing and permitting 
        decisions?
    Response: Yes. Uintah County has considerable expertise in this 
issue and has for some time been active in leasing and permitting 
process on federal land through cooperation and coordination of NEPA 
processes and by facilitating dialog on current leasing and permits 
back logs and addressing the issues of uncertainty in the lease and 
permitting process. The County has actively sought additional funds to 
provide adequate staffing in the local BLM office.
    The funding and staffing needed for a county to participate in 
these activities has put a burden on county resources which with the 
onset of oil shale development are sure to increase. Compensation for 
increases in governmental service associated with the increase in 
activity will help leasing and permitting decisions. It is imperative 
that the Bureau of Land Management office is funded adequately for such 
activities.

4.  What can the federal government do to ensure that local communities 
        have the up-front financial resources needed to plan for 
        development and mitigate impacts? Is there an immediate need?
    Response: Uintah County recognizes the immediate need for up front 
cost for planning and development and to mitigate impact. The County is 
supportive of the suggestions made by Jim Evans (in Russ George's 
testimony to the Senate Energy Subcommittee) that allocates current 
royalties produced from NOSR lands to this effort. We also feel that an 
additional portion of mineral lease revenue (now expanding because of 
regional gas production) could be allocated to the Counties of Origin.
    The use of these funds provides immediate access to needed funds 
and would be recouped by increased revenue from oil shale development.
                                 ______
                                 
    Mr. Gibbons. Mr. McKee, thank you very much for your 
testimony. Thank you for the visual aides that you provided, as 
well. Thank you for your suggestions about how we should work 
together in incorporating the stakeholders, local government, 
county governments, as well.
    And again, Mr. George, your requests certainly are agreed 
upon, that we need to approach this with the full understanding 
that we have to do it sensibly and correctly, considering the 
environmental concerns that we all have in this certainly.
    We have two votes that have been called. We have about ten 
minutes or less remaining. I am going to turn questions over to 
our two panelists here, so that we might be able to wrap this 
up; because when we go to vote, who knows when we will get 
back. I don't want to hold you and this hearing open.
    Mrs. Drake, do you have any questions?
    Mrs. Drake. Thank you. And I will be real quick, because I 
am sure we will submit other questions to you. Does this type 
of resource exist in China? I am sure you probably saw that 
article today about China doing an unsolicited bid to take over 
one of our oil companies, an $18-1/2 billion bid. I think we 
are all concerned about China. But does this type of resource 
exist in China, that if this technology is developed here, 
maybe they would be able to meet their own needs there? It is 
completely off the subject, but it is a thing that hit my mind.
    Mr. McKee. There are others that certainly would know the 
geology of this better than what I do. But I do know that the 
Green River formation located in eastern Utah, western 
Colorado, and southern Wyoming, is the best resource in the 
world, by far. And while there may be resources, and I'm sure 
there are, in many other parts of the world, we have the best 
resource.
    Mrs. Drake. And I would assume both of you would agree that 
this is not a shaky industry or shaky research or a shaky 
resource for us to develop, like we heard earlier?
    Mr. McKee. We believe that this actually is around the 
corner. We believe that, with some help, if we can remove some 
of these impediments--there may need to be some tax credits. It 
depends on how fast we want to move along with this, in my 
estimation. If we want to kind of just go along the way we're 
going, it's going to take longer. If we want to streamline the 
process, I believe with some tax credits and some things up 
front, that it will expedite and help this to happen in more 
rapid fashion than it will naturally.
    Mrs. Drake. I would like to thank both of your states for 
being visionaries. Thank you.
    Mr. George. May I respond to your last comment? Have I got 
just a minute to do that? I was born and raised in the shadow 
of oil shale in western Colorado. And growing up, we heard 
about ``Boom-bust, oil shale will never happen.'' Oil shale has 
chemistry to it that matters for human uses. So it will become 
a source of hydrocarbons for a number of uses, as time occurs.
    What Colorado would like to suggest is that we should not 
have stopped research and development with the last bust 20 
years ago. We have made virtually no progress on the science 
and the technology in the last 20 years. What we don't think 
would be wise is for us to have our successors come back here 
in 20 years and say again what I have just said.
    We need to get on with it. We can do it. We can see how to 
do it. Our friends to the north in Alberta have shown us a way. 
And we need to get on about doing it ourselves.
    Mrs. Drake. Thank you very much.
    Mr. Gibbons. Thank you very much. And to our witnesses, 
both of you, I apologize for the fact that we do not control 
the schedule on the Floor. They vote when they want to vote and 
set those in accordance. And sometimes they interfere with the 
great work that we are doing on these committees.
    Your testimony, your presence here today, has been 
absolutely very valuable. Let us hope that we on the Federal 
side when we develop our policies can work with the county 
governments, state governments, that have these resources 
within their borders, to formulate expedited processes with 
regard to permitting, etcetera, so that we do it uniformly; 
that we do it without a lot of delay and bureaucratic 
obfuscation, if you will; so that we can get to this resource 
that is so vitally critical to the economy of this country.
    I do appreciate the fact that each of you have taken a 
great deal of your time to come here today. We will submit 
written questions that we would like to ask for each of the 
panels to respond to accordingly and report back their answers 
to us; probably within a ten-day timeframe, if you could.
    With that, again, I want to thank each and every one of 
you; apologizing for the interruption of our hearing today with 
the votes on the Floor. And again, your testimony has been 
critical to a better understanding. This is part one of a two-
part hearing series. And we certainly look forward to future 
information and, as I said, to a brighter future with an energy 
policy that takes in oil sands, oil shales, and heavy oil, and 
unconventional sources.
    With that, this hearing is adjourned. Thank you very much.
    Mr. George. Thank you, Mr. Chairman.
    Mr. McKee. Thank you.
    [Whereupon, at 11:45 a.m., the Subcommittee was adjourned.]

    [Additional material submitted for the record follows:]

    [A statement submitted for the record by the Department of 
Energy, Government of Alberta, Canada, follows:]

    Statement submitted for the record by the Department of Energy, 
Government of Alberta, Canada, 14th Floor, North Petroleum Plaza, 9945 
       - 108th Street, Edmonton, Alberta Canada T2K 2G8, http://
                      www.energy.gov.ab.ca/89.asp

    The Government of Alberta, Canada, is pleased to provide this 
written submission on the Alberta Oil Sands to the U.S. Subcommittee on 
Energy and Mineral Resources.
    Included herein is a brief overview of the Province of Alberta; our 
role in North American energy security; the extent of oil sands 
resources in Alberta including reserves based on currently available 
extraction technologies; the role the Government of Alberta plays in 
bringing these valuable resources to market; and, importantly, the 
direct effect this has had on increasing investment and production. 
Production of crude oil from Alberta's oil sands has the potential to 
close the U.S. energy gap.

The Province of Alberta
    Albertans are a breed apart. They are driven by the pioneering 
spirit that first settled the land. They hold dear the ethics of hard 
work and personal responsibility. They cherish the ideals of family and 
community that built the province.
    Our policies focus on free trade and competitive markets as the 
best way to allocate scarce resources. Provincial law prevents the 
government from subsidizing any commercial business entity. The 
Province has no sales tax, a 10% flat personal income tax, and no 
debt--something that has not been achieved anywhere else in Canada, and 
something of which Albertans are justifiably proud.
    Year after year, Alberta's economic growth leads Canada, averaging 
3.7% annually over the past 10 years. We lead the nation in job 
creation, and our unemployment rate is consistently among the lowest in 
Canada. Alberta's per capita disposable income and standard of living 
are the highest in Canada. Not surprisingly, we continue to experience 
the strongest population growth in Canada, with people from all over 
Canada and around the world migrating to our province to experience the 
Alberta Advantage for themselves and their families.

North American Energy Security
    Alberta is rich in hydrocarbon resources--producing almost 1.7 
million barrels per day of crude oil, and 13.8 billion cubic feet per 
day of natural gas.
    Both Alberta and Canada are vital to the energy security of the 
United States--we are reliable, secure and, importantly, stable 
suppliers of energy to the US. In 2004, for the sixth year running, the 
U.S. Energy Information Administration recognized Canada as the largest 
supplier of oil (crude and refined) to the US.
    Approximately 12% of U.S. crude oil imports and 11% of its natural 
gas consumption come from Alberta alone.

[GRAPHIC] [TIFF OMITTED] T2327.009


What are oil sands?
    Oil sands are deposits of bitumen, a molasses-like viscous oil that 
requires heating or dilution with lighter hydrocarbons in order to 
flow. Second only to the Saudi Arabian reserves, Alberta's oil sands 
deposits have been described by Time Magazine as ``Canada's greatest 
buried energy treasure,'' which ``could satisfy the world's demand for 
petroleum for the next century.''
    Deposits are found in three major areas in northeastern Alberta: 
Peace River, Athabasca (Fort McMurray area), and Cold Lake (north of 
Lloydminster), totaling approximately 54,400 square miles--an area 
larger than the state of Florida.

[GRAPHIC] [TIFF OMITTED] T2327.010

Size of Alberta Oil Sands Reserves
    Alberta is home to the largest oil sands reserves in the world. 
Established reserves of 174.5 billion barrels are second only to Saudi 
Arabia reserves.

[GRAPHIC] [TIFF OMITTED] T2327.011


    This data is on the public record and confirmed by the Alberta 
Energy & Utilities Board (AEUB), an arms-length regulatory agency. Over 
56,000 wells and 6,000 cores were the basis of the analysis.
    Since December 2002, these figures were recognized by the Oil & Gas 
Journal, followed by the U.S. Energy Information Administration in 
2003.
[GRAPHIC] [TIFF OMITTED] T2327.012


Growth in Oil Sands Production
    Oil sands raw bitumen production in Alberta averaged close to 1.1 
million barrels a day in 2004 (about one-third of total Canadian 
production). By the end of this decade, we expect production to rise to 
2 million barrels a day. See Appendix 1: Oil Sands potential: 3 million 
bpd by 2020, 5 million bpd by 2030.
    Annual oil sands production is growing steadily by about 200-250 
barrels per day (bbl/d) per year, as the industry matures. Output of 
marketable production increased to 962,000 bbl/d in 2004 from 853,000 
bbl/d in 2003. It is anticipated that in 2005, Alberta's oil sands 
production may account for one-half of Canada's total crude output and 
10 per cent of North American production.

Production Methods: Mining and In-Situ
    There are two methods of oil sands production methods: mining and 
in-situ. Oil sands mining involves open pit operations. Oil sands are 
moved by trucks and shovels to a cleaning facility where the material 
is mixed with warm water to remove the bitumen from the sand. Today, 
all operating oil sands mines are linked with upgraders that convert 
the bitumen to synthetic crude oil.
    For oil sands reservoirs too deep to support economic surface 
mining operations, some form of an in-situ or ``in place'' recovery is 
required to produce bitumen. In-situ oil sands production is similar to 
that of conventional oil production where oil is recovered through 
wells. Present operating costs, not including capital recovery, vary 
between $10-15/per barrel.
    The AEUB estimates that 80% of the total bitumen ultimately 
recoverable will be with in-situ techniques. In general, the heavy, 
viscous nature of the bitumen means that it will not flow under normal 
conditions. Numerous in-situ technologies have been developed that 
apply thermal energy to heat the bitumen and allow it to flow to the 
well bore. These include thermal (steam) injection through vertical or 
horizontal wells such as cyclic steam stimulation (CSS), pressure 
cyclic steam drive (PCSD) and steam assisted gravity drainage (SAGD). 
Other technologies are emerging such as pulse technology, vapor 
recovery extraction (VAPEX) and toe-to-heel air injection (THAI).
    In general, oil sands mines operations are found in central 
Athabasca deposits (around Fort McMurray). In-situ production is used 
in the Cold Lake, south Athabasca and Peace River deposits.

Government Framework
    The mineral rights in approximately 97% of Alberta's 54,000 square 
miles of oil sands area are owned by the Government of Alberta (i.e., 
state-level) and managed by the Alberta Department of Energy. The 
remaining 3% of the oil sands mineral rights in the province are held 
by the federal Government of Canada (i.e., federal-level) within First 
Nation reserves, by successors in title to the Hudson's Bay Company, by 
the national railway companies and by the descendents of original 
homesteaders through rights granted by the Government of Canada before 
1887. These rights are referred to as ``freehold rights''.
    The Alberta government departments of Environment and Sustainable 
Resource Development administer complementary environmental policies. 
The Alberta Energy & Utilities Board (AEUB) regulates oil and gas 
activities in the province.
    The Alberta Department of Energy is responsible for administering 
the legislation that governs the ownership, royalty and administration 
of Alberta's oil, gas, oil sands, coal, metallic and other mineral 
resources. The Department's main objective is to manage these non-
renewable resources to ensure their efficient development for the 
greatest possible benefit to the province and its people.

Oil Sands Royalty Structure
    In 1996, Alberta announced a new generic royalty regime for oil 
sands based on recommendations from a joint industry/government 
National Oil Sands Task Force (NOSTF). This regime is defined in the 
Mines and Minerals Act and the Oil Sands Royalty Regulation 1997, as 
amended (OSRR 97). Royalty is calculated using a revenue-less-cost 
calculation.
    In early project years before capital investment and other costs 
are recovered, the royalty rate is lower than the rate that is applied 
after costs are recovered. This helps project cash flows in early 
years. Once costs are recovered, the Province shares in project 
profits. Details are provided below.
      In the pre-payout period (before the project has 
recovered all of its costs), projects pay royalty tied to 1% of gross 
revenue;
      In the post-payout period (after the project has 
recovered all of its costs), projects pay royalty tied to the greater 
of 1% of gross revenue or 25% of net revenue.
    Since 1990, oil sands royalties have totaled over $2.5 billion.

Announced Investment
    Since 1996, when the generic royalty regime was introduced, an 
estimated $35 billion of investment in the oil sands has occurred. 
Looking forward, it is expected that new capital investment could range 
from $2.5-$4 billion per year.

[GRAPHIC] [TIFF OMITTED] T2327.013

[GRAPHIC] [TIFF OMITTED] T2327.014


The Way Forward
    To date, only about 2% of the established oil sands resource has 
been produced. Alberta's oil sands industry is the result of multi-
billion-dollar investments in infrastructure and technology required to 
develop the non-conventional resource. In the last five years alone, 
industry has allocated an estimated $28 billion towards oil sands 
development, and the Government of Alberta invested over $700 million 
over a 20-year period.
    Alberta encourages the responsible development of these extensive 
deposits through planning and liaison among government, industry and 
communities to ensure a competitive royalty regime that is attractive 
to investors, appropriate regulations and environmental protection and 
the management of the Province of Alberta's rights to oil sands while 
taking into account some of the barriers--higher technological risk and 
higher capital costs--faced by oil sands developers.
    In 2004, Alberta's oil sands were the source of over half of the 
province's total crude oil and equivalent production and over one third 
of all crude oil and equivalent produced in Canada. Over the last three 
fiscal years, through to 2003/2004, oil sands development returned $565 
million to Albertans in the form of royalties paid to the Provincial 
government.
    Continuing technology improvements will lead to greater energy 
efficiency and a reduction in natural gas as a fuel input source. As 
the future unfolds, the only impediment to oil sands production could 
be shortages of skilled labour to complete the projects. Oil sands 
projects will compete for the same skilled workforce as the Mackenzie 
and Alaska natural gas pipelines.
    Development of Alberta's oil sands resources represents a triumph 
of technological innovation. Over the years, government and industry 
have worked together to find innovative and economic ways to extract 
and process the oil sands and energy research is more important today 
than ever before. Working through the Alberta Energy Research 
Institute, the Alberta government is committed to a collaborative 
approach with counterparts in Canada and the United States to spur new 
technology and innovation programs that will reduce the impact of 
greenhouse gases and other emissions, and reduce the consumption of 
water and gas.

[GRAPHIC] [TIFF OMITTED] T2327.015

                                 ______
                                 
    [A statement submitted for the record by Mark Mathis, 
Executive Director, Citizens' Alliance for Responsible Energy, 
follows:]

             Statement of Mark Mathis, Executive Director, 
               Citizens' Alliance for Responsible Energy

    My name is Mark Mathis. My address is 8419 Vina Del Sol Dr. NE, 
Albuquerque, NM 87122. I am a former television news reporter and 
anchor. I've been a media consultant for the past eleven years. Two and 
a half years ago I began consulting with the Independent Petroleum 
Association of New Mexico. It took only a short period of time for me 
to understand the great frustration endured by energy producers. They 
are under constant attack by anti-development groups posing as 
environmentalists. Much of the time the accusations and rhetoric 
dispensed by these groups is greatly distorted if not entirely false. 
Within a year's time I could see that something needed to be done. It 
was at that time that I began contemplating starting a non-profit 
organization for the purpose of educating the public about energy 
issues. I believe a better-informed public will result in government 
leaders making better decisions concerning our national energy policy. 
I have some experience in standing up for the public. In 2001, I formed 
an organization called ``The 505 Coalition'' to fight a new and 
unnecessary area code from being implemented in New Mexico. As a result 
of the efforts of the 505 Coalition rulings by the federal and state 
governments were rescinded, saving an estimated $50 million in public 
and private funds. I wish to apply that same type of activism to the 
critical task of safeguarding our nation's energy supply.

The Wildlands Project
    To date, the most comprehensive environmental coalition to appear 
on the scene is the Wildlands Project. This coalition is the most 
radical in purpose: to ``re-wild'' America, that is, to gradually 
remove people and raw material production from the rural United States 
with no definite stopping point. In their own words: 1
    ``The Wildlands Project calls for reserves established to protect 
wild habitat, biodiversity, ecological integrity, ecological services, 
and evolutionary processes. In other words, vast interconnected areas 
of true wilderness and wild lands. We reject the notion that wilderness 
is merely remote, scenic terrain suitable for backpacking. Rather, we 
see wilderness as the home for unfettered life, free from human 
technological and industrial intervention.''
    ``Extensive roadless areas of native vegetation in various 
successional stages must be off-limits to human exploitation.''
    ``To function properly, nature needs vast landscapes without roads, 
dams, motorized vehicles, power lines, over-flights, or other artifacts 
of civilization, where evolutionary and ecological processes can 
continue. Such wildlands are absolutely essential to protect 
biodiversity.''
    The Wildlands Project has proposed to set aside at least half of 
North America for ``the preservation of biological diversity.'' The 
resulting ``wildland reserves'' would contain:
      Cores, created from public lands such as national forests 
and parks, allowing for little, if any, human use
      Buffers, created from private land adjoining the cores to 
provide additional protection;
      Corridors, a mix of public and private lands usually 
following along rivers and wildlife migration routes;
but would allow no cities, roads, homes, businesses, no aircraft over-
flights, or natural resource extraction, i.e., an ever expanding area 
of America would be depopulated and de-developed.
    A decade ago such proposals would not have been taken seriously. 
Even today this kind of proposal would seem highly unrealistic to a lot 
of people. However, such grand visions are not accomplished over night. 
They happen incrementally. Even though the term ``Wildlands Project'' 
is not widely known, it still presents a formidable threat to private 
property ownership, mineral and resource extraction, and national 
security. Countless anti-development organizations are pursing the 
goals of Wildlands without specifically using the term.
    In the late 1990s, the Clinton Administration adopted aspects of 
The Wildlands Project philosophy pushed largely by Vice President Al 
Gore. In Mr. Clinton's term we witnessed a moratorium on road 
construction in undeveloped areas. There were proposals to breach dams 
on the Columbia River. The expansion of the Endangered Species Act 
continued unabated.
    The Wildlands Project is technically a coalition strategy project 
with a single lead organization: North American Wilderness Recovery, 
Inc. (2000 revenue: $1,451,459), originally based in Tucson, Arizona, 
but relocated in 2000 to Richmond, Vermont. The organization is an 
outgrowth of a 1981 Earth First! idea called the North American 
Wilderness Recovery Project.
    North American Wilderness Recovery has been supported by foundation 
grants since before its exemption 1992, particularly by Doug Tompkins' 
Foundation for Deep Ecology, in annual amounts ranging from $50,000 in 
1992 to $150,000 in 1996 and 1997. The Richard and Rhoda Goldman Fund 
gave $75,000 in 1996 and the Educational Foundation of America gave 
$50,000 in 1997. 2

A Public Deceived
    We have entered the great information age. Media is all around us 
in television, radio, newspapers and magazines. We've got CDs, DVDs, 
MP3s, and satellite TV. With our computers and the Internet massive 
amounts of information is just a few mouse clicks away. We can learn 
about the most obscure subject in great depth without ever leaving our 
homes. And yet, in the midst of this sea of information, many Americans 
are either ignorant or misinformed about some the most fundamentally 
important issues to their lives. This is the great irony of the 21st 
Century. We don't live in the information age. We live in the age of 
disinformation.
    I believe the most critical and misunderstood issue of our time is 
the balance between energy development and the environment. We all know 
we need energy for our daily lives--electricity for lights, appliances, 
computers and hundreds of other devises. We know we need gasoline for 
our cars, jet fuel for airplanes, diesel for big trucks and ships and 
all kinds of other fuels such as propane and butane. We depend on this 
energy for absolutely everything, and yet hardly ever think about where 
this life-sustaining power comes from.
    While Americans sit in their comfortable homes with every 
conceivable necessity and luxury they watch the morning news. There's 
another protest about ``environmental destruction'' caused by fossil 
fuels. Then they read a newspaper story about the rapid and 
catastrophic loss of endangered species. Then it's off to work where a 
radio ad informs them that some ``pristine'' wilderness is about to be 
destroyed by oil and natural gas development. While cruising along the 
highway they see a billboard warning them of the dangers of nuclear 
power. They press on the gas, take a swig of bottled water and shake 
their heads at those awful energy companies that are ruining their 
lives.
    From every direction Americans are being fed a litany of lies and 
distortions. As preposterous as it is, people have been trained to 
despise the energy sources that are the foundation of unprecedented 
health, longevity and prosperity. Americans have been fed so much 
disinformation for so long that they no longer trust their own 
experience. They just assume the disinformation is true and those 
assumptions are rarely if ever challenged.
    Because the public is so misinformed, a relatively small number of 
people who participate in vocal, well organized and very well funded 
activist groups are given undue influence over public policy. They 
demand unreasonable regulations and restrictions on energy development 
and they get a lot of attention from the press.
    For example, The Wildlands Project and other activist groups claim 
we are in the ``6th great extinction of species.'' However, a 1995 
United Nations report states that there have never been so many species 
as there are in the modern era. 3
    On The Wildlands Website, Stanford University professor Paul 
Ehrlich is quoted as saying:
        Although the Wildlands Project's call for restoring keystone 
        species and connectivity was met, at first, with amusement, 
        these goals have now been embraced broadly as the only 
        realistic strategy for ending the extinction crisis. 
        4
    It's surprising that The Wildlands Project would give Ehrlich such 
a prominent place on its website. Ehrlich is not so much famous as he 
is notorious for making doomsday predictions that do not come true. In 
1981 Ehrlich predicted that we would lose 250,000 species every year. 
The widely discredited futurist claimed that half of all species would 
be gone by the year 2000 and that all species would be dead between 
2010 and 2025. 5
    True environmentalists, such as GreenPeace founder Patrick Moore, 
cite biological evidence that less than one percent of species may be 
lost in the next century.
    Moore left GreenPeace many years ago because he said the 
environmental movement was ``basically hijacked by political and social 
activists''. Moore was interviewed for the segment ``Environmental 
Hysteria'' by Showtime's Penn & Teller program. Moore told Penn & 
Teller that these phony environmentalists, ``came in and very cleverly 
learned how to use green rhetoric or green language to cloak agendas 
that actually had more to do with anti-corporatism, anti-globalization, 
anti-business and very little to do with science or ecology.'' 
6
    The Wildlands Project and other groups that support the same anti-
development agenda are effective in spreading disinformation through 
their skill in using the news media. They know that they can make 
outrageous claims and the chance that those claims will actually be 
challenged is very small. They know that journalists typically don't 
know enough about these complex issues to even ask the right questions, 
let alone to challenge the sensational assumptions. Reporters are not 
given enough time or resources to do more than simply repeat the 
activists' claims. Of course, some reporters are believers in the 
obstructionist movement and their bias heavily influences their 
stories. But more than anything, the press cannot resist emotional, 
sensational, fear-based claims. It's their bread and butter in the 21st 
century.
    Journalistic arrogance, of course, is another problem. Syndicated 
columnist Stanley Crouch recently informed readers of The New York 
Daily News, ``The recent congressional vote for Arctic drilling would 
not have been necessary if we had maintained commitment to developing 
nuclear power as an energy source.'' It apparently didn't occur to Mr. 
Crouch that there's no such thing as a nuclear-powered car, tractor-
trailer or airplane. 7
    I have considerable knowledge in this area of media manipulation. I 
was a news reporter for nine years in four states and I've been a media 
consultant for more than 11 years. In my book, Feeding the Media Beast, 
I devote a chapter to ``The Rule of Emotion'' and another to ``The Rule 
of Repetition''. Anti-development groups are very good at using these 
powerful rules to their advantage. 8

The Renewable Deception
    Supporters of the Wildlands Project philosophy are big supporters 
of renewable energy sources such as wind, solar, and biomass. They 
continually urge the public and government leaders to reject fossil 
fuels and to embrace the energy sources of the 21st century. These 
kinds of politically correct statements receive broad approval because 
they sound so good. However, the fact is renewable energy sources 
running our world is nothing more than pure fantasy for at least 
several more decades and probably longer. 9
    Professional obstructionists and even some politicians have led 
people believe that a greater investment in wind and solar power will 
somehow make us less dependent on foreign oil. That's ridiculous. Wind 
turbines and solar panels generate electricity, which does nothing to 
replace the oil that fuels virtually all forms of transportation. Even 
the electricity generation of wind and solar power is minuscule at this 
point, contributing less than one half of one percent to our 
electricity needs. 10
    To the uninformed, this distinction may seem trivial. In reality 
its importance couldn't be greater. We don't have an electricity 
problem in this country (though we could use more power plants and an 
upgraded grid); we have a deadly serious liquid fuels crisis that 
threatens our economy, our national security and indeed all that we 
hold dear.
    There are other groups such as the Energy Future Coalition and The 
Governors' Ethanol Coalition made up of governors from 33 states. These 
organizations want Congress to increase a federally mandated use of 
ethanol above the 5 billion gallons required by 2012. 11 
These governors score points--and votes--by appearing to actually be 
doing something about our thirst for foreign oil and desire to have a 
cleaner environment. Farm belt governors score double points because 
95% of ethanol is made from corn.
    However, this is just another energy deception. It takes more fuel 
to produce and deliver ethanol than it provides, meaning we import more 
foreign oil, not less. While ethanol is advertised as burning cleaner 
than gasoline, on balance it actually produces more and worse 
pollution. Ethanol emits higher levels of NOx emissions contributing to 
smog, and it makes gasoline evaporate faster, reducing its value while 
increasing pollution. It also must be shipped separately and mixed at 
distribution terminals, which simultaneously drives up costs, fuel 
usage and emissions. 12

The Big Hammer: The Endangered Species Act
    No single tool has been more effective in advancing the goals of 
The Wildlands Project than the Endangered Species Act. Say ``Endangered 
Species Act'' and most Americans believe this is a federal law that 
protects species in danger of becoming extinct. While that was the 
original intent, today the Act has very little to do with protecting 
species in trouble. It is a simply a tool for anti-development groups 
posing as environmentalists to shut down any and all uses of public 
land, energy development being number one on the list.
    One of the fundamental flaws of the ESA is that species do not 
recognize state boundaries. If a species is determined to be 
``endangered'' in one state it may become listed as such even though an 
abundance of the species exist in other parts of the country or in 
other nations. For example, the Aplomado Falcon is listed as endangered 
in New Mexico when the species hasn't even existed in the state for the 
past half century. 13 The Bureau of Land Management has 
restricted energy development on 36,000 acres on Otero Mesa just in 
case the falcon decides to come back. Even worse, the falcon can be 
found in great abundance on the entire continent of South America, 
throughout Central America, all of Mexico, and into Texas. 
14 An additional 88,000 acres on Otero Mesa are off-limits 
for other conservation concerns. Dozens upon dozens of cases such as 
this can be found all across the country.
    Another big problem is that once a species is listed it is 
extraordinarily difficult to get it de-listed. In the 32-year history 
of the ESA only 10 species have been removed from the endangered list 
because of ``recovery''. Even then, critics charge that some of those 
species were saved by private efforts and other activities such the 
banning of DDT.
    In New Mexico the Gila Trout was first listed as endangered in 
1967. The U.S. Fish & Wildlife Service proposed downgrading it to 
threatened in 1987 but under pressure withdrew the proposal. Another 
request came in 1996. It didn't happen. Today the USFW is attempting a 
third time but is running into stiff objections from anti-development 
groups. 15
    Enforcing the ESA is very expensive to taxpayers as well as private 
property owners. In the west, the U.S. Fish and Wildlife Service 
estimates it will cost about $30 million to $40 million every year to 
protect the endangered southwestern willow flycatcher. Unfortunately, 
this kind of outrageous expense for species protection is the rule 
rather than the exception. Remember, there are 1,262 Endangered Species 
and obstructionists are filing lawsuits and lobbying hard to have more 
added all the time.
    There are many other flaws in the Endangered Species Act such as 
the fact that in many cases access to land is restricted based on the 
``Best Available Data'', which often stands for ``BAD'' data because 
data are incomplete and sometimes non-existent. Another flaw is the 
fact that private landowners lose use of their land because of an 
endangered species and they receive no compensation from the 
government. There are more problems, however the intent of this 
testimony is not to make suggestions on how to fix the ESA, but simply 
to point out that the Act is highly flawed and yet very powerful in 
restricting access to land for all purposes, most importantly to energy 
development.

Energy is Everything
    It is almost impossible to overstate the importance of oil and its 
powerful brother, natural gas. Without them our world would be 
completely different, more different than any of us can possibly 
imagine.
    Look around you and try to spot a single item that would still be 
there if oil were not. When people think of oil and natural gas they 
typically consider its obvious uses'gasoline for the car, a lubricant 
for the engine, and a power source for electricity generation and the 
heating of homes. What about rubber for tires, shoes, and seals on 
refrigerators, ovens, and car doors? Consider the importance of 
asphalt, fertilizers, pesticides, and glue. What would life be like 
without magic markers, lipstick, pantyhose, credit cards, dental floss, 
toothpaste, baby bottles, telephones, TVs, computers, soccer balls, 
paint, and synthetic fibers for today's clothing?
    The vast quantity of everyday items that contain some byproduct of 
petroleum is astonishing. Take these products away and our world would 
come to a sudden and catastrophic end. If somehow we could instantly 
remove the contribution of petroleum to our world you would find 
yourself standing naked and unsheltered in an open landscape among 
millions of other naked and unsheltered souls.
    It's a little unnerving just to think about it. There's only one 
thing more important to our survival than oil and natural gas, and 
that's oxygen. Yes, water, food, clothing, and shelter are essential, 
but in today's world the vast majority of the population cannot get 
these life-sustaining necessities without petroleum.
    Yet, in spite of these sobering realities, a misinformed public 
stands by while access to oil and natural gas are denied under the 
pretense of ``environmental protection.''

Oil & National Defense: A Sobering Reality
    Oil--as well as all other energy sources--is directly tied to the 
success and survival of the United States of America. The same can be 
said of any other country. Fundamentally, no society can endure--let 
alone prosper--without two things: an adequate and affordable food 
supply and the availability of affordable energy. Because our food 
supply is almost completely dependent on oil, petroleum is the most 
important commodity we have.
    While it's quite clear that our economy and standard of living are 
completely dependent upon oil, it may be less clear that petroleum is a 
key ingredient in our freedom, too. Without adequate fuel supplies for 
fighter jets, battleships, tanks and other armored vehicles America 
would be vulnerable to any nation that wished to take what we have as 
their own, and that includes our liberty as well.
    Allied forces defeated the Axis powers in World War II for a 
variety of reasons--brave men and women, intelligent military leaders, 
and a home-front that made great sacrifices to give the military all 
that it needed while still running a nation. However, no level of 
bravery or sacrifice would have mattered if the United States hadn't 
had sufficient oil supplies to fuel victory.
    Freedom isn't free. It takes enormous sums of bravery, skill, 
passion, human ingenuity and the fuel to make it all work.
A Promising Alternative: Oil Shale
    One of the most promising alternatives to oil is what's called 
``oil shale''. The potential resource is enormous. It's estimated that 
there is over 200 times more oil shale than there are conventional 
reserves. Better yet, the United States is estimated to have 62% of the 
world's potentially recoverable oil shale resources at 2 trillion 
barrels. According to The World Energy Council the largest of the 
deposits is found in the 42,700 km2 Eocene Green River formation in 
north-western Colorado, northeastern Utah and southwestern Wyoming. 
16
    The name is actually a misnomer because it does not contain oil and 
it is not often found in shale. The organic material in oil shale is 
kerogen and it's contained in a hard rock called marl. When processed, 
kerogen can be converted into a substance similar to petroleum. During 
this process the organic material is liquefied and processed into an 
oil-type substance. The quality of the product is typically better than 
the lowest grade of oil produced from conventional reserves.
    Unfortunately, oil shale poses several significant problems. 
Processing of oil shale requires significant amounts of energy and 
water. It also produces massive amounts of waste product. In the 1970's 
major oil companies in the U.S. spent billions of dollars in various 
unsuccessful attempts to commercially extract shale oil. However, as 
the price of conventional oil rises the economics of shale oil will 
improve. When that happens we can expect groups supporting The 
Wildlands Project philosophy to mount a well-funded and well-organized 
protest. As always, disinformation will lead their plan of attack.

A Difficult Task
    Getting the American public and government leaders to focus on the 
critical importance of responsible domestic energy production is no 
easy task. Re-educating the public about the nation's true 
environmental condition will be even more difficult. However, CARE was 
formed to address these issues because the stakes are extraordinarily 
high. The stability of our economy and the foundation of our national 
security are directly tied to our ability to produce domestic energy. 
It is bad public policy to continue to become more dependent on foreign 
and often unstable governments to fulfill our energy requirements, 
especially when environmentally responsible production is a reality 
today.

                                ENDNOTES

 1 Ron Arnold, Undue Influence, Free Enterprise Press, 1999, 
        p. 171-172; www.twp.org, Internet Archive 1998
 2 North American Wilderness Recovery, IRS form 990, 1993-
        1997; Foundation Center Database
 3 Bjorn Lomborg, The Skeptical Environmentalist, Cambridge 
        Press, 1988, p. 249; United Nations Environment Programme 1995: 
        204, 206, 207
 4 The Wildlands Project Website: http://www.twp.org:80/cms/
        page1089.cfm
 5 Lomborg, The Skeptical Environmentalist, p. 249
 6 ``Penn & Teller BullShit,'' Showtime Networks, 
        ``Environmental Hysteria'' Season 1
 7 Albuquerque Journal, April 1, 2005
 8 Mark Mathis, Feeding the Media Beast: An Easy Recipe for 
        Great Publicity, Purdue University Press, May, 2002
 9 Robert L. Bradley, Richard W. Fulmer, Energy: The Master 
        Resource, p.185-186 Kendall Hunt Publishing Co. 2004
10 Energy Information Administration, U.S. Department of 
        Energy, ``Renewable Energy Trends 2003'', July 2004, p. 5
11 Energy Future Coalition, www.energyfuturecoalition.org; 
        The Governors' Ethanol Coalition, www.ethanol-gec.org/
        Transmittal--Letter--to--White--House--pdf
12 Robert L. Bradley, Richard W. Fulmer, Energy: The Master 
        Resource, p.57-58, 129-130, 131, 134-135, 162, Kendall Hunt 
        Publishing Co. 2004
13 The Peregrine Fund, www.peregrinefund.org, restoration 
        projects page, Aplomado Falcon
14 Th e Peregrine Fund, www.peregrinefund.org/Explore--
        Raptors/falcons/aplomado.html
15 Albuquerque Journal, May 18, 2005
16 Wo rld Energy Council: www.worldenergy.org/wec-geis/
        publications/reports/ser/shale/shale.asp


 OVERSIGHT HEARING ON ``THE VAST NORTH AMERICAN RESOURCE POTENTIAL OF 
             OIL SHALE, OIL SANDS, AND HEAVY OILS,'' PART 2

                              ----------                              


                        Thursday, June 30, 2005

                     U.S. House of Representatives

              Subcommittee on Energy and Mineral Resources

                         Committee on Resources

                            Washington, D.C.

                              ----------                              

    The Subcommittee met, pursuant to notice, at 10:02 a.m., in 
Room 1324, Longworth House Office Building, Hon. Jim Gibbons 
[Chairman of the Subcommittee] presiding.
    Present: Representatives Cannon, Pearce, and Drake.

STATEMENT OF THE HON. JIM GIBBONS, A REPRESENTATIVE IN CONGRESS 
                    FROM THE STATE OF NEVADA

    Mr. Gibbons. The Subcommittee on Energy and Mineral 
Resources will come to order.
    Today's hearing, entitled ``The Vast North American 
Resource Potential of Oil Shale, Oil Sands, and Heavy Oils,'' 
is Part Two of a series of hearings. The Subcommittee today 
meets to hold its second of those two-part hearings on this 
very subject.

  STATEMENT OF HON. JIM GIBBONS, A REPRESENTATIVE IN CONGRESS 
                    FROM THE STATE OF NEVADA

    Mr. Gibbons. At part one of this hearing, we focused on 
dispelling the myth that the United States has only three 
percent of the world's oil reserves. A report by the Department 
of Energy, that can be found in the Subcommittee's website, 
estimates that the U.S. has two trillion barrels of oil shale, 
out of the 2.6 trillion barrels found worldwide. The domestic 
production possible from this resource would be sufficient to 
replace all of the United States' foreign oil imports except 
those from Canada and Mexico.
    Also, at the first part of this hearing, this Subcommittee 
heard from resource experts, resource producers, and state and 
local government representatives on a range of topics, with a 
focus on the vast North American unconventional oil resource 
potential.
    Witnesses discussed the feasibility of developing 
unconventional oil resources through the lessons learned from 
the oil sands production in Alberta, Canada; as well as 
recommendations to facilitate commercial leasing and production 
of oil from federally owned oil shale. We learned that 
unconventional oil development is not only feasible, but has 
the promise of delivering low-cost oil to consumers.
    I was very encouraged by the enthusiasm for oil shale 
production at the last hearing, and look forward to hearing 
from officials from the Departments of Defense, Energy, and 
Interior, on their view of the Federal Government's role in 
managing, utilizing, and facilitating production of these 
unconventional sources of oil.
    With approximately 70 percent of the land containing 
potential oil shale development being owned by the Federal 
Government, the Federal Government will have a vital role in 
the facilitation of production. I believe the Government has a 
responsibility for development of these valuable resources, and 
this includes looking for ways to remove barriers to 
production.
    As this Subcommittee has discussed in previous hearings, 
dependence on trans-oceanic energy imports is dangerous to our 
economic and national security. Despite promises from OPEC to 
increase production from member countries, oil prices have 
continued their movement higher and higher. Recent projections 
show that oil prices could reach more than $100 per barrel in 
the not-too-distant future.
    World oil supplies are growing tighter due to the inability 
of oil production to grow as fast as increases in oil demand; 
primarily because of increased demand from countries with 
rapidly growing economies, such as China and India.
    Global oil supplies are also strained because areas that 
would be highly prospective for energy production are either 
off limits to leasing, or the resources are not otherwise being 
made available for leasing; such as America's vast resources of 
oil shale.
    It is vital as a nation that we look to unconventional and 
non-traditional sources of energy to foster greater North 
American energy independence.
    I look forward to the testimony of our witnesses today. And 
when our Ranking Member arrives, or a member of the other party 
arrives for this hearing, we will offer them an opportunity to 
make an opening statement.
    [The prepared statement of Mr. Gibbons follows:]

           Statement of The Honorable Jim Gibbons, Chairman, 
              Subcommittee on Energy and Mineral Resources

    The Subcommittee meets today to hold the second of a two-part 
hearing on ``The Vast North American Resource Potential of Oil Shale, 
Oil Sands, and Heavy Oils''.
    At Part 1 of this hearing we focused on dispelling the myth that 
the United States has only 3 percent % of the world's oil reserves.
    A report by the Department of Energy that can be found on the 
Subcommittee website estimates that the U.S. has 2 TRILLION barrels of 
oil shale out of the 2.6 trillion barrels found worldwide.
    The domestic production possible from this resource would be 
sufficient to replace all of the United States' foreign oil imports 
except those from Canada and Mexico.
    Also at the first part of this hearing, the Subcommittee heard from 
resource experts, resource producers, and State and local government 
representatives on a range of topics, with a focus on the vast North 
American unconventional oil resource potential.
    Witnesses discussed the feasibility of developing unconventional 
oil resources.
    Through the lessons learned from the oil sands production in 
Alberta, Canada, as well as recommendations to facilitate commercial 
leasing and production of oil from federally-owned oil shale, we 
learned that unconventional oil development is not only feasible, but 
has the promise of delivering lower-cost oil to consumers.
    I was very encouraged by the enthusiasm for oil shale production at 
the last hearing and look forward to hearing from officials from the 
Departments of Defense, Energy and Interior on their view of the 
federal government's role in managing, utilizing, and facilitating 
production of the these unconventional sources of oil.
    With approximately 70 percent of the land containing potential for 
oil shale development being owned by the federal government, the 
federal government will have a vital role in the facilitation of 
production.
    I believe the government has a responsibility to development of 
these valuable resources and this includes looking for ways to remove 
barriers to production.
    As this Subcommittee has discussed in previous hearings, dependence 
on transoceanic energy imports is dangerous to our economic and 
national security.
    Despite promises from OPEC to increase production from member 
countries, oil prices have continued their movement higher.
    Recent projections show that oil prices could reach more than $100 
per barrel in the not too distant future.
    World oil supplies are growing tighter due to the inability of oil 
production to grow as fast as increases in oil demand, primarily 
because of increased demand from countries with rapidly growing 
economies such as China and India.
    Global oil supplies are also strained because areas that would be 
highly prospective for energy production are either off-limits to 
leasing or the resources are not otherwise being made available for 
leasing, such as America's vast resources of oil shale.
    It is vital that as a nation we look to unconventional and non-
traditional sources of energy to foster greater North American energy 
independence.
    I look forward to hearing the testimony of our witnesses.
                                 ______
                                 
    Mr. Gibbons. At this time, I would like to welcome our 
guests and witnesses on our panel: Dr. Theodore K. Barna, 
Assistant Deputy Under Secretary of Defense, Advanced Systems 
and Concepts, Office of the Secretary of Defense for the U.S. 
Department of Defense; Mr. Mark Maddox, Principal Deputy 
Assistant Secretary, Office of Fossil Energy, U.S. Department 
of Energy; and Mr. Chad Calvert, Deputy Assistant Secretary, 
Land and Minerals Management, U.S. Department of the Interior.
    Gentlemen, before I turn to your testimony, we have a 
procedure to swear in our witnesses. So if each you would, rise 
and raise your right hand.
    [Witnesses sworn.]
    Mr. Gibbons. Let the record reflect that each of the 
witnesses answered in the affirmative.
    We will turn now to Dr. Barna, Assistant Deputy Under 
Secretary of Defense, for your remarks. Dr. Barna, the floor is 
yours. We look forward to your testimony.
    We do have a light system here. Each of your written 
remarks will be entered into the record. You may feel free to 
summarize or discuss your ideas within the five-minute time 
limit. But since I am the only one here, you can take as much 
time as you want.
    [Laughter.]
    Mr. Gibbons. Dr. Barna.

    STATEMENT OF THEODORE K. BARNA, ASSISTANT DEPUTY UNDER 
SECRETARY OF DEFENSE, ADVANCED SYSTEMS AND CONCEPTS, OFFICE OF 
      THE SECRETARY OF DEFENSE, U.S. DEPARTMENT OF DEFENSE

    Dr. Barna. Thank you very much, Mr. Chairman. I am Ted 
Barna, and I am very honored and delighted today to have the 
chance to appear here and discuss the production of fuels for 
the Department of Defense.
    While I believe the Department of Defense, DOD, has 
legitimate concerns about future access to energy--for example, 
increasing amounts of imports and refined products, which you 
just mentioned--today I would like to concentrate on the work 
that we, DOD, have performed to investigate and certify these 
fuels in military equipment. The end goal is to validate the 
use of these fuels, and also reduce the number of fuels that we 
need to operate.
    We started this, actually, back in 2003, before the current 
run-up in prices, when I was asked to manage a program designed 
to investigate alternative fuels. This is an ongoing study. It 
was initially sponsored by Senator Inhofe and Congressmen 
Sullivan and Cole, all of Oklahoma. And we researched fuels 
produced via the Fischer Tropsch process from natural gas.
    Now, to accomplish this, I initiated a multi-service, 
multi-agency program, led by the Army's National Automobile 
Center--Automotive Center, I guess, the NAC--in Warren, 
Michigan. And the NAC then formed a collaborative program with 
the Air Force, with the Navy, with the Department of Energy, 
with the Department of Energy National Labs in West Virginia 
and Pennsylvania, and Southwest Research Institute in San 
Antonio.
    We also were joined by several universities and industry; 
the industry partner being Syntroleum Corporation, who actually 
made the fuel. We would use this to conduct a preliminary 
evaluation of how these fuels could be, or would be, used in 
aircraft, tactical vehicles, and ships.
    It is important to note that we did not address any of the 
economics of manufacturing these fuels. We were looking solely 
at their potential use by the military.
    As a result of this initial look, this initial look 
indicated that these Fischer Tropsch fuels have a strong 
potential to produce lower-pollutant emissions in diesel 
engines, reduce particulate emissions in jet engines; they have 
superior high temperature and low temperature characteristics; 
and they actually provide improved storage characteristics, 
especially on ships.
    Based on these positive results, in 2004 I expanded this 
effort then to include not just Fischer Tropsch fuel made from 
natural gas, but looked at all the variety of resources we as a 
nation have at our disposal; mainly, oil shale, sands, coal, 
biomass, and petroleum coke.
    And although this, what we term as our OSD Clean Fuel 
Initiative, looks at the total energy picture, today I will 
just discuss two of these: coal, very briefly; and shale, in 
more detail.
    As you mentioned the U.S. has the necessary resources of 
coal in Appalachia, the western United States, and Alaska--and 
this is probably in excess of 800 billion barrels equivalent of 
oil--to produce clean military fuels using Fischer Tropsch 
processes. And as I stated previously, our work thus far has 
demonstrated these fuels have excellent characteristics, and 
will be beneficial.
    In addition, the gasification process used to produce these 
fuels theoretically can be used to generate electricity, 
hydrogen, fertilizers, and chemicals. So it is a good 
opportunity for industry.
    America's shale, though, western shale, as you stated, 
deposits in Colorado, Utah, and Wyoming, contain the equivalent 
of at least a trillion barrels. And that would be well suited 
for producing a premium quality diesel and jet fuel for the 
military.
    Eastern oil shale also represents about 400 billion barrels 
potentially of oil. And 90 percent of these near-surface 
mineable resources are in Kentucky, Ohio, Indiana, and 
Tennessee. So we do have shale in the east, actually; not in 
the strong concentrations we have in the west.
    DOD tests conducted in the early 1980s, back when we were 
interested in shale, demonstrated that shale oil derived from 
kerogen, when properly hydrogenated, has properties similar to 
crude oil. For example, a U.S. Navy report of the period states 
that reasonable quality JP-5, which is the Navy jet fuel, and a 
marine diesel could be produced from shale oil, by virtue of 
their tests.
    At the time, the Air Force also investigated JP-4, which we 
all remember as our old jet fuel from the Air Force, and 
performance was found satisfactory; although there were some 
lubricity issues, that are easily solved.
    A fresh look, though, at shale-derived fuels will be 
required, because now we use a different fuel. It's called JP-
8, which is a version of the commercial Jet-A-1. This fresh 
test includes new specifications designed to yield fuels that 
produce less tailpipe emission SOXs and particulate matter, and 
have improved low temperature characteristics; and then to 
certify use in all military tactical vehicles, such as tanks, 
ships, and airplanes.
    We know that this is just a burgeoning industry, but we 
have already made arrangements with Shell Oil to get some of 
their shale-derived fuel and start this testing.
    Looking in the future, shale-derived fuels could also be 
used in fuel cells and advanced propulsion systems, such as 
hypersonics.
    Therefore, based on our experience from the '80s, plus new 
specifications and applications for extraction and refining, 
there is no reason to expect that shale oil cannot be processed 
into high-quality, clean fuels which are suitable for tactical 
and non-tactical military equipment.
    So in conclusion, if economic, utilizing all our energy 
sources--the largest of which are shale and coal--while 
reducing the number of fuels we employ, would have significant 
operational and logistics consequences for the Department of 
Defense. Finally, cleaner fuels would bring DOD more in line 
with current and evolving EPA regulations, and contribute to 
advanced technologies like hydrogen vehicles, fuel cells, and 
scram jets.
    Mr. Chairman, I look forward to working with you and 
members of the Committee as we pursue this mission of improving 
DOD's energy security. Thank you.
    [The prepared statement of Dr. Barna follows:]

   Statement of Dr. Theodore K. (Ted) Barna, Assistant Deputy Under 
         Secretary of Defense, (Advanced Systems and Concepts)

Introduction
    Mr. Chairman and members of the Committee, I am Dr. Ted Barna, 
Assistant Deputy Under Secretary of Defense, Advanced Systems and 
Concepts. I am honored and delighted to have the chance to appear today 
to discuss opportunities to produce superior fuels for the Department 
of Defense (DoD).

DoD's Concerns
    Supply vulnerabilities: As you are well aware, the U.S. currently 
imports over 56% percent of its oil and the Energy Information Agency 
estimates that it will increase to 68% by 2025.
    Refining concerns: We are also increasingly dependent on foreign 
refined fuels, estimated to increase to four million barrels a day of 
finished product by 2025.
    EPA Exemptions: The military currently has EPA national security 
exemptions to use jet fuels in our tactical equipment that in some 
cases exceed local EPA requirements. As President Bush stated ``America 
must have an energy policy that plans for the future, but meets the 
needs of today. I believe we can develop our natural resources and 
protect the environment.''
    Reduce the number of fuels: If economic alternatives can be founds, 
a reduction in the number of fuels DoD currently uses would generate a 
tremendous operational and logistic benefit. Therefore, a significant 
goal of our ongoing program is geared to eventually having one 
battlefield fuel which can be used in the air, on ground, or at sea. 
Since this fuel would be suitable for the intended function (fit for 
use) the source of the fuel (synthetic, shale, biomass, petroleum) 
would be immaterial to the ultimate consumer.
    Sources of energy: A quick estimate of total energy resources 
(shale, coal, oil, and other resources such as biomass and petcoke) 
comes to approximately 2.3 trillion barrels (bbl) potentially available 
in the US. (This total estimate includes: 1.4 trillion bbl of shale; 
800 billion bbl coal; 60 billion bbl of petroleum, including enhanced 
oil recovery using CO2; plus renewables, which are not yet quantified). 
This compares with an estimated 700+ billion barrels total proved 
reserves (producible at today's prices) in the entire Middle East.) 
Please note, (``resource'' is a technical term that indicates supplies 
of energy that may be in the ground, but are not economically 
producible at today's prices).
    Note: EIA estimates U.S. proved oil reserves at 24.0 billion 
barrels as of the beginning of 2003. For technically recoverable oil 
resources, EIA uses estimates from the U.S. Geological Survey and 
Mineral Management Services, to arrive at an estimate of 142.8 billion 
barrels as of the beginning of 2003. The 800 billion bbl estimate for 
coal represents recoverable reserves only, not total resources. DOE 
estimates oil shale resources at more than 2 trillion barrels, although 
the economics of the recoverability of this resource is not considered.
    In sum, if economic, the development of the vast national energy 
resources we have in this country could provide a dispersed, diverse, 
less vulnerable supply of fuels for the military such that it can meet 
its national security objectives in the near and far term.

DoD Involvement
    Starting in 2003, before the current run up in prices, I was asked 
to manage a program designed to investigate alternative fuels. This 
ongoing study, sponsored by Senator Inhofe and Congressmen Sullivan and 
Cole, all of Oklahoma, researched fuels produced via the Fischer 
Tropsch (FT) process from natural gas. To accomplish this task I 
initiated a joint program, led by the Army National Automotive Research 
Center (NAC) in Warren, Michigan, to investigate the military utility 
of these fuels and to evaluate the potential of producing and using a 
new generation of clean fuels for the military. The NAC in turn formed 
a joint collaborative program with the Air Force Research Laboratory at 
Wright-Patterson AFB, Ohio, the Naval Air Systems Command located at 
Patuxent River, Maryland, the Department of Energy National Technology 
Laboratory in Pittsburgh, Pennsylvania, and the Southwest Research 
Institute, San Antonio, Texas. They were joined by the University of 
Dayton Research Institute in Dayton, Ohio, and Syntroleum Corporation, 
Tulsa, Oklahoma (which supplied the fuel) to conduct a preliminary 
evaluation of the technological potential of these fuels for use in 
aircraft, tactical vehicles and ships.
    The team has concluded a preliminary assessment of the chemical 
properties, storage stability, thermal stability, low temperature 
characteristics and emissions in diesel and jet engines. It found that 
neat (100%) FT fuel will require modification for use in legacy (older) 
military equipment, but these modifications can be made with existing 
technologies. For example, since the fuel is highly processed, it has a 
lower lubricity than normal petroleum derived fuels and could lead to 
premature pump failures. The research team has determined that 
conventional lubricity additives or blends with petroleum derived fuels 
could easily remedy this problem. Also, since these fuels are very good 
solvents, they can cause the elastomers (seals and o'rings) found in 
legacy systems to shrink and potentially cause leaks. Continuing 
research to solve this problem includes novel additives, aromatic 
blends, and blends with conventional petroleum derived fuels.
    Bottom line is these are fuels that meet or exceed military and EPA 
standards. Use of pure synthetic fuels pose some difficulties in the 
areas of lubricity and seal swell, especially in legacy (older) 
equipment, but the problems can be solved at some cost, initially by 
using blends and ultimately by the addition of additives. They also 
bring us more in line with EPA and EU regulations. Testing and 
characterization now pro-actively identifies and could significantly 
ease future difficulties.
    It is important to note this effort did not address the economics 
of using clean fuels for the military, nor whether or not it is ever 
likely that commercial scale production by the private sector will 
occur.
    The results of this initial look indicated FT fuels, using updated 
processes and procedures, have the strong potential to produce lower 
pollutant emissions in diesel engines, reduce particulate emissions in 
jet engines, have superior high temperature and low temperature 
characteristics, and provide improved storage characteristics. Even the 
use of clean fuel blends, designed to counter problems of lubricity and 
seal-swell, provide significant (50%) reductions in tailpipe emissions.
    Based on these finding, in 2004 I expanded this initial effort to 
include a wider variety of resources for the production of clean fuels, 
notably: oil shale, oil sands, coal, biomass and petroleum coke. 
Although this OSD Clean Fuel Initiative looks at the total energy 
picture, today I'll concentrate on only two of these resources: coal 
(briefly) and shale (in more detail).

Coal
    The U.S. has the necessary recoverable reserves of coal in 
Appalachia, the western United States, and Alaska (approximately 
equivalent to 800 billion barrels) to produce clean military fuels via 
the above mentioned Fischer-Tropsch process or through direct 
liquefaction. In either case, since the coal is gasified to carbon 
monoxide and hydrogen, then recombined over a catalyst, these processes 
remove most if not all pollutants, including sulfur and mercury. When 
coupled with carbon strategies, such as CO2-sequestration, while more 
costly than alternatives, the entire process is certainly more 
environmentally friendly. In addition to producing military fuels, this 
coal gasification process can be used technically to generate 
electricity, hydrogen, fertilizers, and chemicals.

Oil Shale
    America's Western Oil Shale is the largest unexploited hydrocarbon 
resource on earth. It's estimated that deposits in Colorado, Utah and 
Wyoming contain approximately 1 trillion barrels of recoverable oil 
(equivalent) that are well suited for producing premium quality diesel 
and jet fuels for the military. For example, Shell Oil is currently 
conducting a shale oil conversion pilot project which will convert 
kerogen to oil and gas via thermal cracking and in situ hydrogenation. 
Eastern Oil Shale could provide 400 billion of barrels of oil based on 
estimates in the 1990's, (Dr. Ari Geertsema, Center for Energy 
Institute, University of Kentucky). These eastern oil shale deposits 
are not as concentrated as western shale It is of interest that, while 
not as concentrated a Western Shale, Eastern Shales are low in 
carbonate content and retorting will not cause decomposition and the 
production of large amounts of CO2. Greater than 90% of the near-
surface mineable resources are in Kentucky, Ohio, Indiana and 
Tennessee.
    DoD demonstrated in the early 1980's that shale oil derived from 
kerogen, when properly hydrogenated, has properties similar to crude 
oil. Since no shale fuels have been produced lately because of the cost 
of production, our evaluation relies on interpreting archival data. The 
technical literature reports early laboratory work on producing quality 
jet fuels from shale oil as early as 1951. Understandably, DoD interest 
increased dramatically in 1973 following the Arab Oil Embargo.
    The initial large scale evaluations of petroleum refined from shale 
oil were sponsored by the Navy and the Naval Petroleum and Oil Shale 
Reserves Office. These investigations looked at gasoline, JP-4 (Air 
Force standard jet fuel during this period), JP-5 (Navy aircraft fuel), 
diesel fuel marine (DFM) and a heavy fuel oil. Eventually, quality 
fuels were produced under these contracts and the Navy and DOE 
conducted extensive tests in military and commercial equipment. The 
initial focus of the testing was on the DFM product for naval shipboard 
use and included evaluating the fuel in fuel pumps and fuel 
distribution equipment to assure compatibility with Navy fuel system 
materials. After a complete evaluation, the Navy conducted hardware 
tests in diesel engines, Navy boilers, marine gas turbine engines, and 
conducted a shipboard test on the USS Scott. The Navy reports showed 
that DFM produced from shale oil was suitable for shipboard use.
    The Navy also conducted tests of a shale derived JP-5 fuel in 
aircraft engines. The Navy report of the period states that a 
reasonable quality JP-5 could be produced (although the fuel was 
somewhat more corrosive than some petroleum derived fuels) and required 
the addition of lubricity additives for fuel pump durability. Engine 
tests were conducted by Allison on the T63-A-51 and T56-A-14 engines; 
General Electric on the TF34-GE-400 engine; and Pratt and Whitney TF30-
P-414 engine. The shale derived JP-5 fuel performed satisfactory in all 
tests.
    At the same time, the Air Force investigated shale derived JP-4 
fuels. The fuel was tested in combustion rig tests conducted by Pratt 
and Whitney and General Electric and the fuel found to be suitable for 
testing in full scale engines and aircraft. Accelerated durability 
testing was also conducted by United Technologies on shale derived JP-4 
in the TF30 and F100 fighter engines. Performance was found to be 
satisfactory in these engines tests, although the reports recommended 
additional research on fuel lubricity additives. Based on these 
positive results from the engine tests, a plan was developed to use the 
fuel at Air Force Bases in Utah (Hill AFB) and Idaho (Mountain Home 
AFB). The program was abruptly brought to an end by the announcement by 
Exxon of the closure of the Colony Project signaling the end of this 
phase of oil shale development.
    Therefore, our conclusion is that shale oil can technically be 
processed using conventional refining techniques into high quality 
clean fuels, which are suitable for general use, to include use in 
tactical military equipment.
    Notwithstanding these favorable results, a fresh look at shale 
derived fuels will be required by the military since the main jet 
turbine fuel is now JP-8, a version of commercial jet fuel Jet-A1, 
which replaces the JP-4 (gasoline/kerosene fuel blend) used by the Air 
Force and diesel fuel used by the Army. This fresh look includes 
developing new specifications designed to yield fuels that produce less 
tailpipe emissions (SOx and particulates), have improved low 
temperature characteristics, and allow use in all military tactical 
vehicles such as Army tanks, Navy ships, and Air Force and Navy 
aircraft.
    Looking to the future, economic shale derived fuels produced to 
clean fuels specifications could also be used in fuel cells and 
advanced propulsions systems required for hypersonics.
    Therefore, based on our experience from the 1980's, plus new 
specifications and application of modern extraction and refining 
techniques, there is no reason to expect that shale oil cannot 
technically be processed into high quality clean fuels, which are 
suitable for use in tactical and non-tactical military equipment.

Conclusion
    If economic, a reduced number of fuels would have significant 
operational and logistics consequences, and supply chain vulnerability 
would be reduced by having more, dispersed refineries. Cleaner fuels 
would bring DoD more in line with current, and evolving EPA 
regulations, reduce the possibility of limits on potential deployment 
(i.e. EU) locations, and contribute to technology advancements, (for 
example hydrogen vehicles, fuel cells, and scram jets).
    Mr. Chairman, I look forward to working with you and the members of 
the Committee as we pursue our mission of providing DoD energy 
security.
    I would be pleased to answer any questions.
                                 ______
                                 

Response to questions submitted for the record by Dr. Theodore K. (Ted) 
 Barna, Assistant Deputy Under Secretary of Defense, (Advanced Systems 
                             and Concepts)

1.  What are the three most important things that the Federal 
        Government can do to ensure timely production of large volumes 
        of oil from oil shale?
    First, the Department of Defense (DoD) can act as a preferred 
customer of the jet fuel produced from the shale. Historically, DoD was 
slated to be the first user of fuels produced from oil shale in the 
late 1970's and early 1980's. Plans were in place to use the fuel at 
key Hill and Mountain Home USAF bases prior to the program being 
cancelled. A similar approach to be a dedicated customer would be a 
good first step to a broader usage by the DoD.
    Second, another key role the DoD can play is to evaluate, certify, 
and demonstrate that fuels produced from the shale oil are fit-for-
purpose for use in trucks, aircraft and ships. DoD working closely with 
the original equipment manufactures (OEM's) to assure compatibility, 
performance and durability, paves the way for the military to use fuels 
produced from this resource.
    Third, DoD can serve as the focal point for developing new fuel 
specifications, in concert with manufacturers, that meet the needs of 
the military and civilian clients. These revisions are long overdue and 
can serve as the basis for improved efficiencies and lessened logistics 
tails.

2.  Specifically, what does the Department of Defense plan to do, if 
        anything, to ensure production of oil from oil shale? Would it 
        be possible for DOD to enter into long-term contracts for the 
        purchase of oil produced from oil shale, with provisions 
        allowing for protection of the producer from downside price 
        risks, while allowing DOD to be protected against large price 
        increases?
    The Department of Defense is following the programmatic efforts of 
the Department of Energy and industry to develop the resources. The DoD 
is developing plans to evaluate, certify, demonstrate and implement use 
of fuels produced from oil shale that would mesh with the development 
of the resource.
    Currently the DoD by statute can enter in to multiyear contracts 
for fuel produced from shale oil at market price. That is, while the 
contract is for a longer term, the price is renegotiated yearly. The 
DoD could offer a preference for fuel produced from oil shale in its 
open solicitations for jet fuel. Currently DoD is prohibited from 
entering into contracts that would allow protection of the producer for 
downside price risk, or the DoD to be protected against large price 
increases (floors and collars).

3.  What quantity of oil and products derived from oil does DOD consume 
        annually? Of this amount, how much do you foresee could be 
        provided by oil and products produced from oil shale?
    The Defense Energy Support Center (DESC) issued contracts in FY04 
to purchase 127.4 million barrels (5.35 billion gallons) of fuel. 75.6 
million barrels (3.18 billion gallons) was purchased domestically. 
(Reference DESC Fact Book 2004) When the oil shale resource is 
developed, shale derived fuels could provide a significant share of the 
fuel we use domestically and supply key military bases in the western 
United States.

4.  Does DOD consider that relying on vast quantities of transoceanic 
        oil imports is a threat to the national security of the United 
        States?
    For the foreseeable future, the U.S. will continue to rely on 
imports for a majority of its fuel needs. However, fuel is a fungible 
commodity traded in an efficient global market. Reselling quickly and 
substantially mitigates the effects of supply interruptions at any one 
source as well as to any particular market.
    While the U.S. economy will be affected by long-term increases in 
global fuel prices stemming from, e.g., increased global demand and 
political instability among energy suppliers, several factors attenuate 
the danger to national security:
      The U.S. economy is less ``energy intensive'' (defined as 
the fraction of every dollar of GDP spent on energy) than any other 
major mature market economy, and therefore can absorb price increases 
more easily.
      Because of technological innovation in energy use and 
advances in exploration, the historical trend in global energy prices 
has been downward, consistently defying forecasts.
      Even assuming upward price trends in the future, as 
energy prices increase, alternative sources of energy (such as shale 
oil) will become cost-effective at different points, thereby dampening 
further price increases for traditional sources.

5.  What are your recommendations for coordinating the Defense mission 
        with Energy and Interior missions? If Congress were to 
        establish a tri-agency Task Force to complete the program 
        planning, would that fit with your vision?
    The Department of Defense would support a tri-agency Task Force and 
support the development of multi-agency plans. The task force could 
develop plans and roadmaps to assure rapid development of the resource 
and reduce the impediments and hurdles industry currently faces to 
develop the resources. The task force could streamline the federal 
processes related to environmental assessments, federal land usage, 
surface and underground shale retorting, shale oil upgrading and 
distribution.

6.  You testified that it is your mission to design new fuel 
        specifications, perhaps for a dual-purpose fuel, and to qualify 
        fuels conforming to these specifications. As we build an oil 
        shale industry, do you see your qualifying program as having 
        implications to the civilian sector? Would you outline the 
        prospective steps to accomplish your mission?
    Original equipment manufacturers (OEM's) will have reluctance to 
certify the use of fuels from any non-petroleum resources until they 
are satisfied that the fuel is fit-for-purpose, does not cause any 
adverse performance or durability issues, and offer similar or better 
operational performance compared to conventional petroleum derived 
fuels. As the military uses equipment that is similar to some of the 
equipment the civil sector uses, the qualification and demonstration of 
the fuel in military hardware would allay concerns the OEM's would 
have. The military would work closely with OEM's during the evaluation, 
certification and demonstration phases and the results should be 
available for them to help certify the use of the fuel in civilian 
equipment.
    The fuel would be evaluated using standard laboratory tests to 
determine the physical and chemical characteristics and determine the 
differences compared to petroleum derived fuels. Fuels will be tested 
in reduced scale weapon system simulators and in subscale components. 
The fuels would be tested to assure compatibility with the materials of 
construction of vehicle fuel systems, and tested at the component level 
to assure performance, suitability and durability for testing in full-
scale equipment. The fuel would be tested in army ground tactical 
vehicles, aircraft and ships to assure long term durability and 
performance and to achieve certification for continuous use by the 
OEM's. Weapon system documentation will be updated and as production 
increases the fuel use would be implemented at test bases. The initial 
bases will be monitored to collect long term use information and full 
implementation would progress as fuel supplies become available.
                                 ______
                                 
    Mr. Gibbons. Dr. Barna, thank you very much for your 
testimony. It is certainly a pleasure to have you with us 
today, and you have been very helpful.
    We will turn now to Mr. Mark Maddox, the Principal Deputy 
Assistant Secretary, Office of Fossil Energy for the United 
States Department of Energy. Mr. Maddox, welcome. The floor is 
yours.

STATEMENT OF MARK MADDOX, PRINCIPAL DEPUTY ASSISTANT SECRETARY, 
       OFFICE OF FOSSIL ENERGY, U.S. DEPARTMENT OF ENERGY

    Mr. Maddox. Thank you, Mr. Chairman, for this opportunity 
to testify on oil shale and its potential for increasing our 
Nation's energy security by mitigating our dependence on 
imported oil.
    Our domestic shale oil resource of more than 300 billion 
barrels of recoverable oil could play a significant role in 
meeting the Nation's future demand for liquid fuels. With high 
oil and gas prices, industry has strong incentives to develop 
technologies that can bring shale oil and other non-
conventional fuels into production on an economically and 
environmentally sound basis.
    This Administration strongly supports efforts by the 
private sector that could result in adding shale oil to the 
Nation's energy portfolio, therefore strengthening energy 
security. The Nation's oil shale resource is concentrated in 
pockets in Utah, Colorado, and Wyoming, and 80 percent of the 
resource is owned by the Federal Government. The resource is so 
large, even if only partially developed, it could deliver 2 to 
3 million barrels per day for decades.
    But in order to tap this enormous energy resource, industry 
must develop economically and environmentally sound 
technologies, as we attempted to do after the oil interruptions 
and price shocks of the 1970s, when the Federal Government 
encouraged the development of oil shale and other 
unconventional domestic resources.
    Those efforts were abandoned when both government and 
industry concluded that the world oil market could provide 
adequate supplies, reasonable prices, and sufficient excess 
capacity. Many current observers of the market, however, 
question whether that conclusion still holds today, or will 
hold again.
    From the beginning in 2001, President Bush has emphasized 
the desirability of reducing our reliance on imported oil. The 
benefit of 2 to 3 million additional barrels per day of secure 
domestic oil from shale is obvious. If that oil were available 
today, it would reduce our dependence on imported oil by as 
much as 25 percent. Combined with the Administration's other 
long-term programs to reduce oil demand growth, shale oil could 
have a powerful and beneficial effect on future oil import 
levels.
    But there are numerous challenges to development, including 
the attitude of the public, business and investment 
considerations, and land access and usage, and environmental 
concerns. These challenges are surmountable, given a real 
commitment and close coordination among all the players, public 
and private, in the energy sector.
    Unfortunately, the shale oil development work of 30 years 
ago left a legacy of uncertainty for industry and the public, 
particularly for people living in the centers of development. 
The affected areas enjoyed a boom period during development, 
followed by a devastating bust that has left them 
understandably wary.
    Fortunately, it appears the citizens of these areas are 
ready to give oil shale another chance and support a new 
development effort, but only with more planning and support for 
infrastructure and development.
    The oil industry today is finding most of its attractive 
investment opportunities overseas. But as conventional oil 
plays become more difficult and conventional oil production 
peaks, industry will again look to the development of higher-
cost resources such as shale oil.
    How long this process will take is an open question. The 
answer will depend on economics, and the economics will be 
determined by projected oil price trends, tax rates, resource 
access, royalty regulations, permitting requirements, and the 
receptivity of state and local populations to development.
    Looking down the list, it is clear the Federal Government 
and state governments will have a large role to play in 
removing road blocks and encouraging private sector interest in 
shale oil development.
    A key development concern will be the environmental impact 
of extracting oil from shale by using technologies to heat the 
rock, either above or below ground. Despite the significant 
research and development work conducted 20 to 30 years ago, the 
industry has not yet reached a consensus on the best technology 
to use.
    Regardless of the process, shale oil operations will have 
some environmental impact, as does any industrial operation. As 
always, the job of everyone involved in development will be to 
ensure that the impact is minimal and acceptable.
    Fortunately, we have a very successful model for the 
development of oil shale, through the production of over 1 
million barrels per day of oil from Canada's Alberta oil sands, 
where production is expected to exceed 2 million barrels per 
day in eight years.
    Many parallels exist between shale oil and oil sands 
technologies, markets, and economics. We cannot be certain that 
oil shale economics will parallel those of the Alberta tar 
sands. There are important physical differences between oil 
sands and oil shale, and the extraction technology for one 
cannot directly be transferred to the other.
    But comparisons suggest that the domestic oil shale 
industry is in some ways similar to the Canadian oil sands 
industry of 30 years ago. As part of its energy security goal, 
the Department is committed to improve energy security by 
developing technologies that foster a diverse supply of 
reliable, affordable, and environmentally sound energy, and 
improve our mix of energy options.
    This prospect of adding 2 to 3 million barrels a day of 
secure domestic oil to our Nation's energy supply for decades 
to come demands our attention and our support. The Department 
will work to achieve this goal in support of the economic 
security of the United States, in line with our commitment to 
deliver results for the American taxpayer.
    Mr. Chairman, this concludes my prepared statement. I will 
be happy to answer any questions from you and the Committee.
    [The prepared statement of Mr. Maddox follows:]

  Statement of Mark Maddox, Principal Deputy Assistant Secretary for 
                Fossil Energy, U.S. Department of Energy

    Mr. Chairman, Members of the Subcommittee, thank you for this 
opportunity to testify on oil shale and other non-conventional oils, 
and their potential role in elevating our Nation's energy security by 
mitigating our dependence on imported oil. U.S. energy security is 
important by virtue of the crucial role it plays in achieving economic 
security.
    I would like to share with you today our thoughts on the oil shale 
resource in these areas--first, oil shale's magnitude and potential; 
then, the history of past unsuccessful attempts to develop it; and, 
finally, barriers to development as they exist today. In addition, I 
will compare the prospects for oil shale with the commercial 
development experience of another non-conventional resource, Alberta's 
vast oil sand resources.
    Ensuring the present and future energy security of the United 
States is a primary goal of the Office of Fossil Energy, and we are 
committed to the President's goal of elevating our energy security 
through increased production of economic domestic resources. Domestic 
oil shale represents a resource of more than 300 billion recoverable 
barrels of oil and is a resource which, if economical, could play a 
significant role in meeting the Nation's needs for more liquid fuels 
over the next several decades.
    We also have potential domestic sources of non-conventional liquid 
fuels such as the technologically mature but uneconomic Fischer-Tropsch 
coal liquefaction, recovery of stranded oil, undiscovered oil and other 
currently uneconomic resources. With high oil and gas prices, industry 
has strong incentives to develop technologies that will facilitate 
exploration of non-conventional domestic resources, and in fact there 
is evidence that they are doing so.
The Resource
    The total U.S. oil shale resource is estimated to be 1.8 trillion 
barrels and is primarily concentrated in the Green River formation in 
northeastern Utah, northwestern Colorado, and southwestern Wyoming. 
Over 50% of the world's oil shale resources are in this area, 80% of 
which are owned by the Federal Government. It is estimated that over 
400 billion barrels of oil equivalent exist in oil shale at 
concentrations greater than 30 gallons/ton. In 1980, the Office of 
Technology Assessment published An Assessment of Oil Shale 
Technologies, which estimated that between 189 and 315 billion barrels 
of oil would be recoverable from this high quality shale. Oil and Gas 
Journal, in its August 9th 2004 issue, suggested that 100 billion 
barrels of oil from domestic oil shale could be reclassified as proven 
reserves if the technology became commercially viable. Suffice it to 
say, if it were financially feasible to even partially develop, the 
resource could sustain an industry of 2-3 million barrels per day for 
decades.
    The factors that limit the development of oil shale have nothing to 
do with the potential quantity of the resource. Historically, oil shale 
production hasn't been economical. The cost of production has been too 
high compared to the cost of producing from conventional resources. 
This problem has been compounded by the need to build an infrastructure 
to support oil shale and the cost of disposal of byproducts. Although 
the Federal Government attempted to make oil shale economical in the 
late 1970's and early 1980's, this effort was abandoned because shale 
oil production could not be sustained in the face of abundant and cheap 
conventional crude oil. This was true even though the Government 
embarked on this effort at a time when oil prices were higher in real 
terms than they are today. The failure of the Government's efforts in 
the 1980's was not due to the failure of the resource, the technology, 
or environmental problems; economically it was simply too expensive. 
Recently, however, industry has shown renewed interest and has begun 
committing resources.
What is the Commercial History of Oil Shale in the United States?
    After the oil interruptions and price shocks of 1973-74, the 
Federal Government encouraged the development of unconventional 
domestic resources including oil shale. The Department of the Interior 
offered commercial leases for development in 1973. Bonus bids totaled 
$450 million for four oil shale leases and industry began development. 
Economic incentives were later offered for oil shale development 
including a guaranteed price floor ($42.50 indexed to the CPI), and a 
production tax credit of $3 per barrel. In total we estimate $5 billion 
was invested in oil shale facilities beginning roughly in 1975. Major 
players at that time included Exxon, Shell, Mobil, Occidental, Atlantic 
Richfield, Chevron, and Unocal. In the early 1980's these projects 
began to close and the last closed in 1992.
    The consensus of the industry was that oil prices simply did not 
stay on a price path over the long term that would assure a reasonable 
return on investment for an unconventional crude oil. In addition, 
policy changes accompanying new administrations removed the subsidies 
for synthetic fuels. Witness the demise of the Synthetic Fuels 
Corporation, which was chartered during the Carter Administration but 
allowed to expire during the Reagan Administration. The oil price 
collapse of 1986 assured the end of the U.S. synthetic fuels industry.
    The general impression left following the demise of the U.S. oil 
shale industry was very negative. During the boom period, the influx of 
workers into Western Colorado strained and ultimately overwhelmed the 
local infrastructure and housing, producing lasting socioeconomic 
effects. When the industry collapsed, the local towns were left with 
infrastructure in excess to their needs, shrunken property values and a 
tax base incapable of supporting the infrastructure.
How is Oil Produced from Oil Shale?
    Kerogen, a low grade form of immature oil, is extracted from oil 
shale in a process called ``retorting'', which requires heating of the 
rock to about 900 degrees Fahrenheit. Two generic methods of retorting 
have been developed:
      In situ: This method leaves the rock in place and injects 
a heat source that releases the oil from the kerogen. The shale oil 
then flows to a well and is pumped to the surface. The source of the 
heat is a technical issue still open to research and testing. The only 
active pilot project in the U.S., owned by Shell Oil, is using down 
hole electric resistance heaters, but optional technologies involve 
steam, microwaves, and fire.
      Surface retorting: This technology depends upon mined ore 
for a feedstock. The ore can be either surface mined or mined 
underground. The ore is brought to the surface, crushed and placed into 
a retort. The shale oil is removed and the spent shale sent for 
disposal. The shale oil is upgraded by the addition of hydrogen and 
then is conventionally refined to produce finished products. Several 
different retort designs have been constructed and tested in the United 
States as a part of earlier development efforts. However, there are 
currently no commercial surface retorts in the U.S. processing oil 
shale.

Challenges to Commercialization
    Perceived Risk: Shale oil activities in the late 1970s and early 
1980s have left a legacy of uncertainty. Members of industry and the 
citizenry alike are uncertain about the risks associated with 
commercial development.
    Current Oil Industry Economics: U.S. domestic oil production is 
high cost compared to many parts of the world because our fields are 
mature and declining. Private investment dollars are directed to the 
most economic areas where costs of production are low, like West 
Africa, Brazil, the Middle East, Russia and Central Asia. As long as 
current geopolitical and market conditions persist, we expect more 
money to flow to energy extraction on a world wide basis; however, not 
a large share of it is expected to be invested in the United States in 
the immediate future. As conventional oil plays become more difficult 
to find, and as conventional domestic oil production peaks, industry 
will again begin to focus on the development of the resources that can 
be extracted profitably at higher prices, including oil shale.
    Prospects for commercial oil shale production will depend on the 
private sector's perception of the relative profitability of oil shale 
versus competing resources. Factors that will determine economics are 
projected oil price trends, tax rates, cost of production, resource 
access, royalty payments, permitting requirements, cost of byproduct 
disposal, and the willingness of the State and local populations to 
host a new industry.
    The size of the industry will be limited by existing distribution, 
pipeline capacity, water availability, power distribution, and refining 
capacity in this region of the Rocky Mountains. If the oil shale 
industry develops to any appreciable size, investments will be required 
to expand the limited infrastructure.
    Land Access and Usage: A major driver of shale oil extraction 
economics is the concentration of the resource. Movement of ore to the 
retort can be very expensive, because the ore is mostly rock with only 
a little oil (more than one ton of ore per barrel of oil). Therefore, 
the ore must be processed at or near the geologic formation where it is 
found. While the natural resource is very concentrated in Colorado, 
Utah and Wyoming, the ownership is not. The Federal Government owns 80 
percent of the resource base, and the remaining tracts are broken up. 
At this time the Department of the Interior does not have a commercial 
leasing program, although it recently established a leasing process for 
small tracts to conduct research, development, and demonstration 
projects and is accepting nominations from industry for parcels to be 
leased.
    Environmental Impact: The environmental impacts of shale oil 
development are significant. Like the resource, they will primarily be 
concentrated in small geographic locations. Because oil shale is mined, 
there are surface impacts. Oil shale production is water intensive, 
which is an important limited resource in the regions with oil shale 
deposits. Because the retorting processes are energy intensive, there 
are combustion emissions in areas where the air is currently very 
clean. The mining or in situ technologies may also disturb the local 
water tables. In the case of the in situ technology, the spent shale in 
place may contain toxins that need to be kept away from ground water. 
In the case of surface retorting, the spent shale, processing water, 
and other byproducts must be disposed of in a safe manner. How to do 
that on a massive scale has not been defined. To produce a million 
barrels of oil would require disposal of more than a million tons of 
byproducts.
    The positive aspect of the resource is that its density is so great 
that most of the environmental impacts can be restricted to a 
relatively small area within two or three States. However, because 
shale oil production is energy intensive, the industry could add 
significantly to green house gas emissions during production. 
Similarly, greenhouse gas emissions will be released when the fuel is 
consumed.
    Extraction Technology: Despite the significant research and 
development conducted 20-30 years ago, there is no accepted benchmark 
for the best technology to use. Furthermore, because of modern 
developments in environmental protection and resource conservation, it 
will be important for the existing technologies to improve from an 
efficiency, and environmental impacts perspective. Companies will have 
to advance extraction technologies through research, development, and 
demonstration.

Comparison with Alberta Oil Sand Commercialization
    Commercial production from formerly uneconomical resources occurs 
as markets change and drive technology development. Oil from Alberta 
oil sand, once considered to be an unconventional resource, is being 
commercially produced today. Oil was first produced at a commercial 
scale from Alberta oil sand more than 35 years ago. Today, oil sand 
production is over one million barrels per day and is expected to 
exceed 2 million barrels per day within the next eight years. A strong 
partnership between government and industry stimulated more than $65 
billion in private investment to accelerate development and achieve 
industry scale operations during this decade.
    Like oil sands, U.S. oil shale is rich, accessible, geographically 
concentrated, and well defined. However, the technologies required for 
exploitation of oil shale are very different from those required for 
oil sands. The richness of the respective resources are similar, with 
oil sands yielding approximately 25 gallons per ton of bitumen while 
some oil shale deposits yield an average of about 30 gallons per ton. A 
comparison of the qualities of the two oils shows them to produce a 
similar product after processing. The Athabasca sand produces 34 degree 
API oil and the oil shale produces 38 degree API oil. However, there 
are important physical differences between oil sands and oil shale and 
the extraction technology for one cannot directly be transferred to the 
other.

Summary
    In summary, we need to examine all of our resource bases if we are 
to do a credible job in protecting the United States' energy security 
interests. As part of its energy security goal, the Department is 
committed to improving energy security by developing technologies that 
foster a diverse supply of reliable, affordable, and environmentally 
sound energy and improve our mix of energy options. The Department will 
work to achieve this goal in support of the economic security of the 
United States, in line with our commitment to deliver results for the 
American taxpayer. Mr. Chairman, and members of the Subcommittee, this 
concludes my prepared statement. I will be happy to answer any 
questions you may have at this time.
                                 ______
                                 

    Response to questions submitted for the record by Mark Maddox, 
Principal Deputy Assistant Secretary for Fossil Energy, U.S. Department 
                               of Energy

Ensuring Oil Shale Production
Question 1. What are the three most important things that the Federal 
        Government can do to ensure timely production of large volumes 
        of oil from oil shale?
    Answer 1. It is most important to make land available for oil shale 
research and, eventually, the production of oil shale. The first step 
in this area is progressing as the Bureau of Land Management is 
currently accepting nominations of parcels for a potential research and 
development scale leasing program.

Economical Analysis
Question 2. Your written testimony stated that U.S. oil shale 
        resources contain at least 300 billion barrels of recoverable 
        oil IF ECONOMICAL. Has the Department of Energy performed an 
        analysis of whether production of oil shale is ECONOMICAL at 
        this time? If you have not performed such an analysis, when do 
        you plan to do so?
    Answer 2. We have performed an analysis of the economics of oil 
shale. As part of our analysis of the industry we have developed a 
model to evaluate project economics for the application of oil shale 
technologies to selected resource tracts, and the relative impact of 
various incentives on project economics.
    As there are no commercial oil shale facilities operating in the 
United States, our analysis cannot be based on realized costs from any 
such current operations. Several oil shale projects were undertaken 
domestically in the 1970s and 1980s, most notably Unocal's operations 
in Parachute Creek, Colorado. However, we have no direct information on 
the costs these operations experienced. Some indirect evidence comes 
from the fact that Unocal ultimately determined its operations to be 
uneconomical, despite receiving a guaranteed price of $41.50 per barrel 
under a long-term supply contract reached in 1981 with the Department 
of Defense. Converting from 1981 dollars, this guaranteed price would 
correspond to more than $80 per barrel in 2005.
    In the absence of data on realized costs, our analysis is based 
primarily on engineering models developed in the 1970s in conjunction 
with the 1974 Prototype Oil Shale Leasing Program (POSLP). These models 
provide capital cost and production cost estimates for various 
technologies, which we have escalated to 2004 dollars using Bureau of 
Labor Statistics data and have further validated with current vendor 
quotes. The analysis also applies resource characterization data from 
surveys conducted by the U.S. Geological Survey (USGS) in preparation 
for the POSLP. The economic analysis examined the USGS defined resource 
tracts to determine the most efficient technology for resource 
extraction at each location. The production cost estimates and resource 
characterization data were then used to calculate minimum economic 
prices.
    We define the minimum economic price as the break even price for a 
mature industry, one that has already recovered substantial initial 
costs (associated with research and development, permitting and land 
access) and has achieved substantial cost reductions through learning-
by-doing. If we were to include estimates of these initial costs and 
the likely inefficiency of early plants into our calculation of minimum 
economic prices, the figures listed in the table below could more than 
double.
    Our model estimates cash flow for the various projects by 
evaluating plant capacity, development schedule, market prices for oil 
and natural gas, leasing royalty structure, operating costs, capital 
costs, and tax structure. The table below summarizes the model results 
for the four known extraction technologies. The average minimum 
economic cost shown in the table below represents the average of the 
breakeven prices for a given technology across the resource tracts 
where it is being applied. Capital costs are the sum of investments 
needed per barrel of installed capacity. These costs include 
investments in mining, retorting, solid waste disposal, refining and 
upgrading, plant utilities, and other facilities. Operating costs 
include fuel, operating and maintenance personnel, consumable equipment 
and other non-capital costs for mining, retorting, refining and 
upgrading. The components of both capital and operating costs are 
different for various technologies used for mining, retorting, and 
upgrading.

[GRAPHIC] [TIFF OMITTED] T2327.019

Reclassification of Proven Reserves
Question 3. Am I correct that when that analysis has been completed, 
        and assuming that the analysis shows that production of oil 
        from oil shale is economical, large quantities of domestic oil 
        shale resources could be reclassified as proven reserves? 
        Wasn't this confirmed by the Oil and Gas Journal in its August 
        9, 2004 issue?
    Answer 3. No. The classification of proved oil and gas reserves is 
regulated by the Securities and Exchange Commission. Proved reserves 
are defined in Rule 4-10(a) of Regulation S-X of the Securities 
Exchange Act of 1934.
          ``Proved oil and gas reserves are the estimated quantities of 
        crude oil, natural gas, and natural gas liquids which 
        geological and engineering data demonstrate with reasonable 
        certainty to be recoverable in future years from known 
        reservoirs under existing economic and operating conditions, 
        i.e., prices and costs as of the date the estimate is made. 
        Prices include consideration of changes in existing prices 
        provided by contractual arrangements, but not on escalations 
        based upon future conditions.
          ``Existing economic and operating conditions are the product 
        prices, operating costs, production methods, recovery 
        techniques, transportation and marketing arrangements, 
        ownership and/or entitlement terms and regulatory requirements 
        that are extant on the date of the estimate.''
    As the rule indicates, the resource needs to be under development 
with commercially proven technologies to be classified as a proved 
reserve. In addition, Rule 4-10(d) of the same law explicitly prohibits 
oil from oil shale (along with coal and gilsonite) as being classified 
as a proved oil and gas reserve. This prohibition is based largely on 
economic uncertainties, including the lack of existing markets. The 
rule leaves open the possibility of classifying these types of 
resources as proved reserves if markets develop and companies 
demonstrate commitment to develop the necessary production. However, 
the SEC currently treats oil shale development as a mining activity. 
The classification of proved reserves of ore for mining activities is 
regulated by SEC Industry Guide 7 and it appears that the geologic 
analyses conducted by the USGS would be sufficient to recharacterize 
the oil shale resources as proved reserves, if they were developed.
    As a comparison, the Alberta oil sands resource is estimated to 
total well over 1 trillion barrels. It was only in 2004, however, that 
174 billion barrels were finally reclassified as proved reserves, this 
coming after over 40 years of work developing the resource. Again, this 
is because, as with U.S. law, Canadian law requires that the resources 
be developed, that commercially viable production be demonstrated, and 
that economic conditions support the long-term exploitation of the 
resource.

EIA Reserves Estimate
Question 4. On April 12, you testified before the Senate Committee on 
        Energy and Natural Resources that ``our domestic total oil 
        shale resource is more than 1.8 trillion barrels, with perhaps 
        100 billion to 200 billion barrels commercially viable.'' Based 
        on this position, when will the Energy Information Agency take 
        action to recharacterize that amount of resource as reserves?
    Answer 4. The Energy Information Administration (EIA) currently 
recognizes a very small part of the nation's oil shale resource as 
proved reserves as does the Securities and Exchange Commission (SEC). 
These oil shale reserves, unlike those discussed in my testimony, meet 
the definition of proved reserves--they are developed or are being 
developed and they are economic with current prices and existing 
technology.
    While SEC rules state that oil shale (along with coal and 
gilsonite) should not generally be classified as a proved oil and gas 
reserve, it leaves open the possibility of doing so if markets develop 
and companies demonstrate commitment to develop the necessary 
production. For example, the SEC and EIA have both recognized large 
amounts of coalbed methane as proved gas reserves. EIA will recognize a 
larger portion of the oil shale resource base as proved reserves when 
and if it is developed and meets the definition for proved reserves.

Environmental Impact
Question 5. Your testimony stated ``it will be important for existing 
        technologies to improve from an efficiency, and environmental 
        impacts perspective.'' You also state that ``the environmental 
        impacts of shale oil development are significant.'' How can DOE 
        make these statements if it has not performed an environmental 
        impact statement on oil shale production? Isn't it possible 
        that the impacts could be mitigated to a point where they might 
        not be ``significant''?
    Answer 5. As there has never been a full-scale operational oil 
shale development in the United States, there need to be technological 
advances to improve the effectiveness and efficiency of the industry. 
The environmental impacts are no greater than other very large 
industrial developments, such coal mining and petroleum refining 
operations, but they are significant. These are very large mineral 
extraction and upgrading operations, with all of the environmental 
issues and problems associated with that kind of development. Due to 
the significant amount of energy currently required to extract a useful 
product from oil shale, it is also likely that net greenhouse gas 
emissions from oil shale production will exceed that of conventional 
fuels.

Greenhouse Gases
Question 6. You also stated that ``greenhouse gas emissions will be 
        released when the fuel (shale oil) is consumed.'' How would 
        these emissions be different from consumption of conventional 
        oil?
    Answer 6. In assessing the overall greenhouse gas impact of oil 
shale, it is necessary to look at the complete production/consumption 
cycle. Oil shale production--whether through surface retorting or an in 
situ process--is substantially more energy-intensive than conventional 
oil production. Assuming fossil fuels are used to provide the energy 
input for oil shale production, the net greenhouse gas impact of 
developing oil shale resources is likely to be substantially higher 
than the per-unit impact of convention oil production. The production 
of greenhouse gasses will vary by the technology employed. The use of 
low temperature conversion in in situ processes will reduce greenhouse 
gas emissions.
    For most surface retorting operations the level of green house 
gases released from the ground during development, will likely be very 
similar to emissions resulting from the production of conventional oil. 
It should be noted, however, that very high temperature retorting 
processes (i.e. direct combustion) could generate higher amounts of 
carbon dioxide. Western oil shales are rich in carbonate compounds, 
which when combusted will release carbon dioxide. It is likely the 
application of indirect heat and slower heating rates, as are currently 
being employed in small operations, will help minimize these increased 
carbon dioxide emissions. Elevated carbon dioxide emissions are not 
anticipated from in situ production. Again, the rate of heating and the 
low temperatures (relative to direct combustion) avoid conversion of 
carbonate compounds to carbon dioxide.
    The liquid fuels produced from western shale oil will be low in 
sulfur and rich in hydrogen that when consumed will produce less carbon 
dioxide per unit of energy than conventional fuels.

Energy Requirements
Question 7. One of the issues sometimes raised is one of energy 
        requirements for producing oil shale, which is central to 
        sustainability. Does your agency have any analysis of energy 
        requirements? What needs to be done to reduce the energy costs 
        of production?
    Answer 7. How much energy is consumed in the production of energy 
is usually described as the energy balance. The oil shale industry has 
often been criticized for consuming large amounts of energy in the 
manufacture of the output energy. Shell Oil reports that in their ICP 
In situ process they consume 1 Btu for every 3 Btu's of energy 
produced. This ``energy balance'' is substantially lower than for many 
other fuel sources. However, the utilization of natural gas produced 
during the ICP in situ process doubles the energy efficiency to 6 btu's 
of energy produced for each btu consumed. One of industry's primary 
goals is to increase this energy balance, which would both improve the 
economics of oil shale production and reduce its environmental impact, 
particularly in terms of net greenhouse gas emissions. There are also 
opportunities to improve energy balances once pilot and demonstration 
plants are running.

Task Force
Question 8. How do you propose that DOE engage industry, local 
        communities and other stakeholders in program planning efforts? 
        Would you support the tri-agency Task Force concept advanced by 
        Senator Hatch?
    Answer 8. The Budget does not include funds for an oil shale 
program and the Administration isn't pursuing a new program promoting 
the development of oil shale.
                                 ______
                                 
    Mr. Gibbons. Thank you very much, Secretary Maddox. Again, 
your testimony is very helpful to the Committee, and we 
certainly appreciate your presence here before us today.
    We will turn now to Mr. Chad Calvert, Deputy Assistant 
Secretary, Land and Minerals Management, U.S. Department of the 
Interior. Secretary Calvert, welcome back to the Committee once 
again. It is a pleasure to see you before us, and the floor is 
yours.

STATEMENT OF CHAD CALVERT, DEPUTY ASSISTANT SECRETARY, LAND AND 
      MINERALS MANAGEMENT, U.S. DEPARTMENT OF THE INTERIOR

    Mr. Calvert. Thank you, Mr. Chairman. I appreciate having 
the opportunity to testify today on behalf of the Department of 
the Interior and the Bureau of Land Management, which is a part 
of Land and Minerals Management at the Department.
    Let me start out by saying that the Secretary has taken a 
real interest in the issue, and she recognizes that we are at a 
very unique time, with oil around $60 a barrel and technology 
evolving across the world for development of oil shale. She 
recently visited eastern Utah and western Colorado and actually 
went out and looked at some of the development that is going on 
on private lands there; and was very encouraged by the 
technology and the development of it; and has encouraged BLM to 
move forward as quickly as they can to develop commercial 
leasing.
    I will speak about BLM's role here as the land manager, the 
land and resource manager, and our responsibility to manage 
public lands for multiple use; which includes, of course, the 
development of oil shale.
    On Federal lands in Wyoming, Utah, and Colorado, we have 
roughly 72 percent of the surface oil shale reserve, and as 
much as 82 percent of the Nation's reserve in those three 
states on Federal land.
    The BLM currently has no commercial leasing regs. They 
developed drafted regs in the 1980s in response to high prices. 
And after the 1974 oil shale prototype program had begun, BLM 
decided, in roughly '83, not to complete those regs, because 
technology and prices just weren't keeping up with enabling 
development of oil shale, and they abandoned the regulatory 
process at that time. And there has been no industry interest 
in redeveloping regs since the early '80s, until now.
    Currently, the President's national energy policy outlined 
recommendations for the BLM to diversify and increase energy 
supplies, which included development of oil shale. BLM 
developed a plan containing 54 discrete tasks designed to 
implement the President's directives. And one of those was to 
establish an Oil Shale Task Force to develop recommendations 
for the BLM on how we should move forward.
    The Oil Shale Task Force was designed to address four 
points: how to access unconventional resources on public lands; 
to identify impediments to oil shale development; to coordinate 
and combine for public land managers what industry interest was 
in research and development of commercial opportunities on 
public lands; and to provide Secretarial options to enable us 
to capitalize on the opportunities. The task force has a draft 
report which is being finalized and, hopefully, we can provide 
to this Committee expeditiously.
    On November 22, 2004, BLM, on a recommendation from the 
task force, proposed an oil shale lease form and a request for 
information to solicit comments on an initial oil shale leasing 
program. Ninety percent of the comments were favorable to 
developing a research, development, and demonstration program.
    On June 9th, just roughly three weeks ago, we finalized 
regulations in the ``Federal Register,'' requesting nominations 
for RD&D--which is research, development, and demonstration 
activities--and requested industry to supply or to nominate 
potential research parcels within the next 90 days, until 
September 7th.
    This program would allow tracts of land up to 160 acres to 
be used to demonstrate the feasibility of technologies. The 
lease terms would be ten years, with an option to extend for 
five years on a showing of diligence of research. Royalties 
would be waived during the lease, and rentals would be waived 
for the first five years.
    Applicants would also at the time of the nomination be able 
to identify an additional 4,960 acres that they would have a 
preferential right to lease, on the showing of commercial 
development on the 160-acre lease.
    One of the principal reasons we decided to move forward 
with the RD&D lease program was because we really lacked the 
ability to do more extensive or comprehensive NEPA on 
technologies that we didn't know would be utilized in areas 
that we didn't know would be located. And we decided that it 
was better to move forward with small scale; determine what 
could be done using an environmental assessment tiered to the 
land-use plan; and then, based on what was developed as part of 
that 160-acre lease, move forward with additional NEPA in the 
future that would enable commercial development in a way that 
was appropriately covered by the National Environmental Policy 
Act.
    I will close by saying we are committed to developing a 
commercial leasing program, and we believe that what we have 
proposed is the best way to go about doing that. Thank you, Mr. 
Chairman.
    [The prepared statement of Mr. Calvert follows:]

  Statement of Chad Calvert, Deputy Assistant Secretary for Land and 
     Minerals Management, United States Department of the Interior

    Mr. Chairman and Members of the Committee, thank you for the 
opportunity to appear here today to discuss the Bureau of Land 
Management's (BLM) efforts to facilitate and promote oil shale research 
and development on public lands.
    America faces an energy challenge. As recently as April 5, 2005, 
Federal Reserve Chairman Alan Greenspan commented extensively on this 
challenge. He stated,
        ``Markets for oil and natural gas have been subject to a degree 
        of strain over the past year not experienced for a generation. 
        Increased demand and lagging additions to productive capacity 
        have combined to absorb a significant amount of the slack in 
        energy markets that was essential in containing energy prices 
        between 1985 and 2000.''
    For a considerable time, many have believed that oil shale, if 
economic, has the potential to be a major source of domestic energy 
production, especially since it is suited for refinement as jet fuel 
for the military and the airline industry. Recently, the BLM, which has 
the authority to issue leases for oil shale under the Mineral Leasing 
Act and to receive rental payments and royalties, has received 
expressions of interest from industry for conducting research and 
development projects on public lands in the Green River Formation in 
the tri-state area of Colorado, Utah and Wyoming. It is BLM's hope that 
renewed interest in oil shale research and development efforts will 
lead to environmentally responsible ways of unlocking the vast oil 
shale resources contained in the United States, and presents a 
potential means of helping to reduce the imbalance in domestic energy 
consumption and production that currently exists in this country.

Background
    Oil shale is a type of rock formation that contains large 
concentrations of combustible organic matter. When processed, oil shale 
can yield significant quantities of shale oil. Various methods of 
processing oil shale to remove the oil have been developed. A common 
element among those methods is the use of heat to separate out the oil 
from the rock.
    The United States has significant oil shale resources, primarily 
within the Green River Formation in Wyoming, Utah and Colorado. These 
oil shale resources underlie a total area of 16,000 square miles and 
represent the largest known concentration of oil shale in the world. 
Federal lands comprise roughly 72% of the total oil shale acreage in 
the Green River Formation.
    In the latter years of World War II, several tests were conducted 
to determine the economic viability of oil shale extraction 
technologies. However, in the years following World War II, petroleum 
producers looked to more easily accessible and economically viable 
supplies and interest in oil shale extraction declined. More recently, 
during the mid 1970s through the late 1980s, the Department of the 
Interior and the BLM made oil shale resources on public lands available 
through the Oil Shale Prototype Program, which was designed to allow 
companies to develop and refine the technology for extracting oil from 
oil shale. Additionally, in the 1980's, the U.S. Geological Survey 
(USGS) had an active oil shale mapping program, which mapped the major 
oil shale fields of the United States and conducted geological research 
on the Green River deposits. The USGS also conducted mineralogical and 
geochemical studies aimed toward characterizing oil shale for the 
commercialization of this resource.
    Precipitated by the oil price spikes of the early 1970s, companies 
showed significant interest in exploring domestic oil shale 
development. Previous oil shale research showed that it was possible to 
extract shale oil from the rock; however, despite government subsidies, 
the extraction process was energy-intensive and costly. Through a 
series of experiments, industry attempted to find more effective ways 
to extract shale oil from oil shale rock, but the easing and subsequent 
collapse in petroleum prices led the companies to conclude that 
production was not economically viable. The participants in the Oil 
Shale Prototype Program withdrew from their research efforts before the 
BLM could promulgate permanent regulations for oil shale leasing and 
operation.
    Most USGS activities related to this commodity have also diminished 
significantly. However, since the latter half of the 1980s, the USGS 
has maintained a small effort in oil shale studies, both domestically 
and abroad, which included evaluation of world oil shale resources and 
a cooperative effort funded by the Department of Energy to create a 
National Oil Shale Database, in which shale oil analyses and other data 
were entered and compiled. With the recognition that oil shale is a 
potentially important domestic fossil energy resource, the USGS has 
continued in these efforts to the present day. Although no 
comprehensive oil shale assessment has been done, the USGS has 
completed oil shale resource studies on some of the most promising 
areas. One example of this is ``Thickness, oil-yield, and kriged 
resource estimates for the Eocene Green River Formation, Piceance Creek 
basin, Colorado'' USGS Oil and Gas Investigations Chart OC-132. Another 
example is USGS Open-File Report 91-0285 ``Oil-Shale Resources of the 
Mahogany Zone in eastern Uinta Basin, Uintah County, Utah.'' USGS is 
currently working with the State of Utah to evaluate all oil shale 
lands in the eastern Uinta Basin, compiling, among other things, 
geologic maps, cross sections, geophysical and lithologic logs, and 
drill hole information.
    Elsewhere in the world, efforts continue to harness oil shale 
resources. For example, in Gladstone, Queensland, Australia, there is a 
large-scale demonstration project where, from June 2001 through March 
2003, 703,000 barrels of oil, 62,860 barrels of light fuel oil, and 
88,040 barrels of ultra-low sulphur naphtha were produced from oil 
shale. In January 2003 alone, the operation produced 79,000 barrels of 
oil. Significant oil shale reserves also exist in the Republic of 
Estonia, where active oil shale deposits amount to about 9.2 billion 
barrels of oil.

Current BLM Efforts
    The President's National Energy Policy outlined a number of 
recommendations to diversify and increase energy supplies, encourage 
conservation, and ensure environmentally responsible production and 
distribution of energy. In response, the BLM developed a plan 
containing 54 tasks designed to implement the President's directives, 
including efforts to promote the development of oil shale resources on 
the public lands. To carry out this task in an environmentally 
responsible manner, and in keeping with our multiple-use mandate, the 
BLM established its own Oil Shale Task Force.
    The Oil Shale Task Force was established to address: 1) access to 
unconventional resources (such as oil shale) on public lands; 2) 
impediments to oil shale development on public lands; 3) industry 
interest in research and development and commercial development 
opportunities on the public lands; and; 4) Secretarial options to 
capitalize on the opportunities. The Task Force has prepared a report 
concerning the development of oil shale resources on Federal lands in 
order to determine whether technological advances have reached the 
point where it is possible to develop those resources economically and 
in an environmentally responsible manner.
    On November 22, 2004, the BLM published a proposed oil shale lease 
form and request for information in the Federal Register to solicit 
comments and suggestions from interested parties about the design of 
the oil shale leasing program. The report recommendations and BLM's 
analysis of the responsive comments to the Federal Register notice led 
to the design of an Oil Shale Research, Development and Demonstration 
(RD&D) program.
    BLM published a new, final oil shale lease form in the Federal 
Register on June 9, 2005, and invited interested parties, from June 9, 
2005 through September 7, 2005, to nominate public lands for oil shale 
RD&D activities. The nominations must be accompanied by a non-
refundable application fee of $2,000. The RD&D lease program design 
allows tracts of land up to 160 acres to be used to demonstrate the 
economic feasibility of today's technologies over a lease term of ten 
years, with the option for an extension of up to five years. The 
payment of royalties will be waived during the RD&D lease, payment of 
rental will be waived for the first 5 years of the RD&D lease, and an 
applicant may identify up to an additional contiguous 4960 acres that 
it requests be reserved for a preference right commercial lease should 
RD&D efforts prove successful in demonstrating the economic feasibility 
of oil shale production.
    One of the principal reasons to offer small RD&D leases before 
issuing commercial leases for oil shale is to obtain a better 
understanding of the environmental effects of the new technologies and 
the effectiveness of various mitigation measures. Consequently, given 
the small scale of the RD&D leases, BLM has determined that for 
environmental review under NEPA, site-specific environmental 
assessments (EAs) would be more appropriate than a programmatic 
environmental impact statement (EIS) document. The complexity of the 
analysis required for the RD&D lease will depend on the location, the 
type of project proposed, and the type of technology to be used.

Conclusion
    Thank you for the opportunity to testify today about the BLM's Oil 
Shale Development efforts. I would be happy to answer any questions you 
have.
                                 ______
                                 

 Response to questions submitted for the record by the Bureau of Land 
              Management, U.S. Department of the Interior

1.  Question: What are the three most important things that the Federal 
        Government can do to ensure timely production of large volumes 
        of oil from oil shale?
    Answer: The Department of the Interior believes three things must 
happen before commercial oil shale production will take place: 1) oil 
shale resources must be made available for research and development of 
extractive technologies; 2) extractive technology must be improved to 
increase efficiencies while minimizing environmental impacts, and 3) a 
market for oil shale end products must develop.
    The Department of the Interior's Bureau of Land Management (BLM) 
has taken the first step by making Federal oil shale resources 
available through the BLM's recently-created Research, Development and 
Demonstration (R,D&D) leasing program. In addition, the BLM will 
promulgate permanent leasing regulations in accordance with the 
recently-signed energy bill.
    The BLM's R,D&D leasing program makes it possible for interested 
parties to proceed with the second step of improving extractive 
technologies. In light of current market prices for crude oil, private 
companies should have ample incentive to conduct R,D&D and improve 
their oil shale technology.
    The final step, development of a market for the end products, will 
ultimately depend on the economic viability of oil shale.

2.  Question: On April 12, 2005, Mr. Tom Lonnie from the BLM testified 
        before the Senate Committee on Energy and Natural Resources 
        that BLM has not examined the Canadian program that has led to 
        the production of large quantities of oil from oil sands. When 
        will the Department conduct an analysis to learn the 
        significant features that made their program a success?
    Answer: The BLM intends to examine and evaluate the Canadian 
experience and process to see if there are lessons we can learn and 
apply to our unconventional resource development efforts. However, it 
is important to note that oil sands and oil shale are distant resource 
cousins and there are vastly different economic and technological 
challenges associated with developing these resources. Any formal 
analysis of the Canadian oil sands program is beyond the mission of 
DOI.

3.  Question: Your testimony mentioned the June 9 Federal Register 
        notice on RD&D leasing. The Subcommittee will present questions 
        to you about this leasing proposal to be answered as part of 
        the record. Generally, we have some concern about the lack of 
        specificity about several very important aspects such as the 
        price for companies to receive a commercial lease on the 
        preference right acreage, the royalty and regulatory schemes 
        that will apply to production and activities on the leases, and 
        other important provisions. Could you provide more details NOW 
        on these items?
    Answer: The BLM expects to develop a methodology for determining 
fair market value for bonus bids to convert a R,D&D lease to a 
commercial lease, including any preference right acreage. However, the 
data currently available on oil shale that could be used to determine 
fair market value is very limited and unreliable. Also, the R,D&D 
program is designed to allow the demonstration of new technology where 
the economics are not fully understood at this time. What is known at 
this time is that conversion would be based on the ability of the 
lessee to produce commercial quantities of shale oil from the lease, 
documentation of consultation with state and local governments on the 
mitigation of socio-economic impacts, and the BLM's determination, 
following NEPA analysis, that the environmental consequences of 
developing the preference right area are acceptable.
    The BLM expects to gather more reliable data from the R,D&D leases. 
The Secretary has the authority under the Mineral Leasing Act to 
establish royalty rates, and plans to do so prior to the commencement 
of commercial production. The goal of the BLM is to promulgate final 
commercial leasing regulations prior to the conversion of R,D&D leases 
to commercial leases, incorporating the establishment of royalty rates 
as an integral aspect of the final rulemaking

4.  Question: Would you agree that the 5120 acre limit and the one 
        lease per lessee restriction of the Mineral Lease Act of 1920 
        are impediments to commercialization of oil shale? Would you 
        agree that removing these restrictions would be an important 
        step toward commercialization?
    Answer: The BLM is aware of assertions that the 5120 acre limit 
could constitute an impediment to commercial oil shale development. 
However, with the enactment of H.R. 6, the Energy Policy Act of 2005, 
the per 5120 acre limit has been increased to 5760 acres and the number 
of acres a lessee may hold in any one state has been increased from 
7680 acres to 50,000 acres. These changes should have a positive impact 
on commercialization efforts. However, until oil shale development 
proves to be economic and moves beyond the RD&D phase, these 
limitations should have little practical impact on commercialization 
efforts.

5.  Question: In Utah, and possibly Wyoming, prospective developers now 
        need to deal with more than one agency to put together a 
        logical development unit? Would land exchanges designed to 
        block up logical development units help solve this impediment?
    Answer: Oil shale deposits, like other natural resources, occur on 
Federal, State, Indian, and private lands. As a result, developers may 
need to deal with more than one agency to assemble a logical 
development unit It should be noted, however, that through Section 
369(n) of the recently-enacted Energy Policy Act of 2005, Congress has 
directed the Secretary to consider using land exchanges where 
appropriate and feasible to consolidate land ownership and mineral 
interests into manageable areas. This provision directs the Secretary 
to identify public lands containing oil shale or tar sands deposits 
within the Green River, Piceance Creek, Uintah and Washakie geologic 
basins and to give priority to implementing land exchanges within these 
basins.

6.  Question: You testified that the BLM owns about 72% of the Resource 
        acreage, with the remaining acreage is held by non-federal 
        interests. Holders of these other 28% may wish to nominate 
        federal lands under your recent Call for Nominations--Oil Shale 
        Research, Development and Demonstration (R, D, and D) Program 
        contiguous to their non-federal holdings. Is there anything in 
        your process that would prohibit a holder of non-federal lands 
        from conducting their R, D and D activities on non-federal 
        lands and qualify the nominated BLM property for conversion 
        (subject to the conversion requirements in your regulations) at 
        a later date? It would appear that cases like this would 
        improve the likelihood of commercialization, which is the goal. 
        Do you agree?
    Answer: The process established by the BLM does not prohibit those 
conducting oil shale research and development on private lands from 
applying for a Federal lease. The criteria for nominating and 
qualifying for a preference right lease are set forth in the June 9, 
2005, Federal Register notice. In order to qualify for conversion, the 
applicant would need to produce shale oil in commercial quantities from 
the Federal lease before its expiration.

7.  Question: You testified that NEPA requirements are a reason why 
        progress has been slowed in preparing lease regulations. 
        Uncertain permitting timelines also put investment at risk, and 
        are an impediment to investment. Do you have any suggestions 
        for Congress to mitigate these impediments? For example, if 
        Congress were to supply the financial resources for BLM to work 
        with applicants to assure that applications are complete upon 
        first submittal, would that help? Can Congress help eliminate 
        indefinite delays by placing limitations on timeframes for 
        protests? What about reducing or eliminating NEPA requirements 
        below a certain impact level?
    Answer: Conducting NEPA analysis does take time. In complicated 
projects, Federal law also brings into play numerous other 
environmental statutes, such as the Endangered Species Act, the Clean 
Air Act, the National Historic Preservation Act, etc. We note that the 
Energy Bill contains a provision in Section 369(k) that designates the 
Department of the Interior as the lead Federal agency for coordinating 
applicable Federal authorizations and environmental reviews and directs 
the Secretary to issue regulations necessary to implement this 
provision within six months of enactment.
    The immediate challenge for the oil shale program is that it is 
unclear what the proposed actions of commercial leasing would be, given 
that we do not yet have proposals for commercial projects. For this 
reason, and at this time, BLM would prefer to conduct site-specific 
NEPA analysis instead of doing a regional programmatic environmental 
impact statement (EIS) document.
    One of the principal reasons to offer small research and 
development leases before issuing commercial leases for oil shale is to 
obtain a better understanding of the environmental effects of the new 
technologies and the effectiveness of various mitigation measures. As 
stated in the call for nominations, the complexity of the analysis 
required for the R,D&D lease will depend on the location, the type of 
project proposed, and the type of technology to be used. It is 
anticipated that more intensive NEPA analysis will be performed before 
the award of a preference right lease, using information generated 
during the R,D&D phase. Approval of conversion to a commercial lease 
would then also depend on a determination that a commercial operation 
on the acreage selected could be conducted in an environmentally 
acceptable manner.
    The BLM works closely with industry to ensure that the required 
information is provided prior to the submittal of any application for a 
use authorization. This helps to eliminate potential delays due to 
incomplete applications. In addition, the BLM is performing full and 
meaningful consultation with the public, particularly with local 
individuals through the land use planning process and other project-
specific NEPA analysis. The BLM is also working on creating more 
effective governmental partnerships, through the lead agency-
cooperating agency relationship and its application to the planning and 
associated environmental assessment responsibilities. This will help 
the BLM to work together and foster a commitment by local, tribal, and 
state governments and other Federal agencies to recognize common goals 
and achieve balanced resource management.
    The BLM has existing authority to limit protest periods, and this 
is among the options the BLM will be considering in drafting the final 
commercial leasing regulations. However, there are pros and cons to 
limiting protest periods, and BLM will need to weigh both in making any 
final decision to impose such limitations.

8.  Question: Mr. Calvert, it is my understanding that Shell's in situ 
        conversion process, even though based on heating the ore 
        underground, involves nearly 100% surface disturbance, removing 
        all vegetation and disturbing the soil. If BLM approves a plan 
        to allow this, how would DOI ensure that the inevitable and 
        significant damage to the land be reduced so that others would 
        be able to use the land after mining is through?
    Answer: The BLM anticipates that the proposed R,D&D program will 
include some level of surface disturbance, regardless of the 
methodology employed. The in situ conversion process involves drilling 
vertical holes, as is done in oil and gas recovery, but does not have 
any mining component. The in situ process, like any other major 
operation, is expected to disturb a portion of the surface of the lease 
parcel at any given time. As with many oil and gas technologies, one 
might expect a reduced surface impact over time as in situ evolves into 
second and third generation technology. The R,D&D program is designed 
to require a phased reclamation approach. First, there will be 
intermediate reclamation of disturbed areas when those areas are no 
longer needed in the ongoing operations. As the operation terminates, 
the disturbed area of the lease is to be fully reclaimed before the 
lease bonds are released.
    The BLM recognizes that the complexity of the NEPA analysis will 
depend on the site selected, the type of project proposed, and the type 
of technology to be used. The BLM will use the NEPA process to analyze 
the impacts to the land surface, vegetation, soil, underground water, 
air, surface water and fisheries and identify mitigation strategies to 
minimize adverse impacts. Additionally, as shown in the June 9th 
Federal Register notice, prior to conducting operations on the leased 
land, a lessee must submit a plan of operations that will include a 
description of best management practices for interim environmental 
mitigation and reclamation.

9.  Question: Although industry is touting some new innovations, their 
        approaches to oil shale production still involve a major mining 
        operation. What specific techniques and precautions will DOI 
        require to ensure protection of surface water and ground water 
        from depletion and contamination, to protect topsoil stability, 
        and to control air pollution from that mining?
    Answer: Prior to the award of any lease, the BLM will conduct a 
NEPA analysis to determine that this protection is possible at the site 
using the proposed technology. Under the R,D&D program, a lessee will 
be required to submit a bond sufficient to cover actual expenses 
associated with total reclamation and abandonment prior to the issuance 
of a lease. The amount of the bond will be estimated based on the 
technology to be used and projected disturbance associated with such 
technology. Also, a lessee must submit an annual plan of operation to 
be reviewed and approved by an appropriate BLM official, subject to 
reasonable modifications to assure protection of the environment. 
Furthermore, a lessee will be required to provide an interim 
reclamation plan under which the lessee will be required to 
continuously reclaim disturbed portions of the lease as soon as such 
areas are no longer needed for operation.
                                 ______
                                 
    Mr. Gibbons. Thank you very much, Secretary Calvert. Again, 
the Committee appreciates your presence and the testimony here 
today.
    Before we turn to questioning and answering of the 
Committee and interaction with the panel, a couple of 
housekeeping requirements. What I would like to do is ask 
unanimous consent to submit for the record the opening 
statement of Mr. Grijalva, the Ranking Minority Member, which 
will be done without objection.
    [The prepared statement of Mr. Grijalva follows:]

    Statement of The Honorable Raul M. Grijalva, Ranking Democrat, 
              Subcommittee on Energy and Mineral Resources

    Today's hearing again focuses on a potentially untapped, domestic 
energy resource--oil shale and oil sands.
    As I noted last week, while industry experts say oil shale holds 
great potential with an estimated 2 to 4 trillion barrels of oil locked 
in the Green River formation out west, it has a history in the western 
United States that is shaky at best. Many bold promises have been made 
in the past about oil shale's potential and about the affordability of 
its production but few of them have been realized so far.
    It is important that we get clear facts about oil shale's fuel 
potential and about new methods for its production and that we are 
honest about analyzing and discussing those facts. We often hear, for 
example, that the United States currently consumes almost 20 million 
barrels of oil a day. Saudi Arabia now produces roughly 11 million 
barrels a day. If, as Chairman Gibbons suggested last week, this 
country could produce 60 percent of its oil needs from oil shale and 
tar sands, that would essentially mean equaling the current Saudi 
production figures, with much of it coming from Western Colorado.
    However, as the Colorado newspaper, the Grand Junction's Daily 
Sentinel, editorialized on June 26, ``No one who values the West's open 
spaces, wildlife and natural landscapes--in short, most Coloradans--
would want to see a major swath of northwestern Colorado turned into a 
vast industrial zone that would make the likes of Gary, Indiana, look 
like a garden spot. To build the sort of oil-shale industry [Chairman] 
Gibbons envisions, the Rocky Mountain West as we know it today would 
have to be torched along with the shale itself.''
    So, we need to be careful about claims and projections and keep 
them in perspective.
    Research phases need to examine not only ways to improve the 
technical aspects of oil shale production, but also the environmental 
consequences that could come from commercial operations. We need to 
know what damage an expanded industry could do to the water, air, 
scenic beauty, and recreation opportunities of the West and put in 
place the technical refinements and restrictions that reduce that 
damage.
    Finally, as I stressed last week, with oil trading at $50 to $60 a 
barrel, and as evidenced by Shell's success in developing oil shale, 
Congress should not underwrite domestic oil shale development. The BLM 
proposal to lease tracts of public land for research and development is 
unobjectionable. But, American taxpayers do not need to subsidize oil 
shale development.
                                 ______
                                 
    Mr. Gibbons. And we also want to ask unanimous consent to 
submit for the record two publications from the Department of 
Energy: Volume One, dated March 2004, and Volume Two, dated 
March 2004; titled ``Assessment of Strategic Issues,'' for 
Volume One, and Volume Two is ``Oil Shale Resources Technology 
and Economics,'' for the record. That will be done, without 
objection, as well.
    [NOTE: The information submitted for the record has been 
retained in the Committee's official files.]
    Mr. Gibbons. Let me begin, perhaps, with Dr. Barna over 
there. The issue of the Department of Defense and its role in 
assisting with or encouraging the development of oil shale 
products is primarily restricted not to technology, but to 
assessment of the product that is produced from whatever 
technology or whatever source of that.
    Will there be interaction between DOD and our research and 
development and demonstration programs that the Department of 
Interior is proposing, as we go through the next ten years, to 
find the best or most suitable, not just product, but process 
by which we get product to the commercial? Will there be 
coordination?
    Dr. Barna. Absolutely. We intend to work with the 
Department of Interior, the Department of Energy. As you say, 
our primary role is to certify, to categorize, to help in the 
setting of specifications. But this has to be done as a group 
process. It's just not going to be done in isolation; because 
our overall goal is to provide the catalyst for them to then 
develop an industry.
    Mr. Gibbons. Describe your process. What is it that you 
actually do when you get a product into your lab?
    Dr. Barna. Well, what we do is we actually run it on jet 
engines; we run it on diesel engines. We carefully monitor the 
energy inputs and outputs, and the particulate matter--NOXs and 
LXs, and when appropriate, SOXs. And we grade it.
    And then we look at ways that we can change or improve 
specifications. One good example is--this is a recent 
experience with Fischer Tropsch fields. We may be able to 
change the specifications so that we get one fuel that does 
both jet and diesel. This helps industry, as well as helps us, 
because now we have one less fuel on the battlefield that we 
have to manage.
    Mr. Gibbons. Sure.
    Dr. Barna. So it is in the area of specifications, as well. 
So that is, I think, the area where we will have the best 
impact.
    Mr. Gibbons. Hopefully, we have provided a sample of what 
was provided to us from Oil-Tech, of products that come from 
oil shale, and the production of fuels. I presume that each of 
these products that you see up there, except for the waste rock 
after the oil has been removed, is a product that comes to you 
for that sort of testing.
    Dr. Barna. We would get the finished--we are interested in 
the finished fuel products. So we would be interested in the 
JP-8-like product or the----
    Mr. Gibbons. Diesel.
    Dr. Barna. Or the diesel product, exactly. And so sometimes 
we forget that there is a difference between what comes out of 
the ground and the finished product that goes into the machine. 
And our interest there is in that machine.
    But we are very interested that they are all fit for use. 
So the jet fuel is jet fuel to the user. He doesn't really care 
if it comes from shale, biomass, oil, whatever; it's fit for 
his use. So that is where we would get very heavily involved.
    Mr. Gibbons. Secretary Maddox, has the Department of Energy 
performed an analysis of whether production of oil shale is 
economic?
    Mr. Maddox. That is part of the construction economics. We 
have looked at the numbers. And I think one of the things we 
have looked at is understanding the difference between profit 
versus competing investment alternatives. Right now, in this 
price range, yes, I would say oil shale is economic.
    Mr. Gibbons. Well, my question was, you are giving me your 
opinion.
    Mr. Maddox. Yes.
    Mr. Gibbons. Has the Department officially analyzed it and 
reported on the economics of it?
    Mr. Maddox. We have analyzed it. I don't know whether we 
have published those analyses. We will be happy to supply them 
to the Committee. But we have looked at the comparative costs 
of oil shale with other products in the market.
    Mr. Gibbons. And I assume this analysis would be with 
current technology?
    Mr. Maddox. Yes.
    Mr. Gibbons. Secretary Calvert, what are the three most 
important things that your Department and the Federal 
Government can do to assist in expediting the development of 
oil shale, or oil sands, or unconventional oil sources in this 
country?
    Mr. Calvert. I can speak on behalf of the Department of 
Interior. And as far as the rest of the Government goes, I'm 
not sure that I am qualified to say what DOD or DOE can best be 
doing to help.
    But for the Department of the Interior, I feel, as the land 
managers here, it is our duty and responsibility to provide 
adequate NEPA coverage for development; to ensure that our land 
use plans under FLPMA are properly amended or supplemented; and 
then to process permits in a timely way and ensure that there 
is monitoring that goes along with it, so that we don't get 
snagged in legal battles.
    Mr. Gibbons. My time has expired. We will turn to Mr. 
Pearce for questioning. Mr. Pearce?
    Mr. Pearce. Thank you, Mr. Chairman. Mr. Maddox, we had a 
witness last week who said he could withdraw oil from shale for 
$18 to $24 a barrel. Do you believe that is possible?
    Mr. Maddox. That is probably an optimistic number. I would 
probably guess a little bit higher. Probably, at the $20 range 
would probably be fair, out of the ground.
    Mr. Pearce. And at the $20 range, why are we not doing it? 
Oil is at a $60 range.
    Mr. Maddox. Well, the fundamental economics are that you 
can get a lot of other oil out of the ground cheaper. And if 
you look at most corporate planning numbers, they look at a 
market price of $18 to $20 as kind of what most people are 
using for a planning number.
    Most investment decisions are based on an historical 
average price, which I think now is just moving to $20 for a 
lot of companies. And so while people say, ``OK, we can get it 
out of the ground for 20,'' that means a market price closer to 
25, high 20s. And that does not work on an internal planning 
number for most corporations when they decide where to expend 
the money.
    Mr. Pearce. Do you think we don't have any entrepreneurs 
out there willing to risk? Right now, the margin is 40 bucks. 
You risk 20, and you make 60. From a business perspective, you 
don't find those kinds of rates of return. Why don't we have 
any takers?
    Mr. Maddox. Well, to compare the capital costs, you have a 
$70,000-per-barrel capital cost for oil shale, versus about a 
$33,000-per-barrel cost in oil sands, for instance. So there is 
a significant capital barrier. And so now you need an option in 
order to take a risk.
    Mr. Pearce. Does your estimate of cost--20, 25, or 
something in that range--include capital costs?
    Mr. Maddox. That's production cost.
    Mr. Pearce. Just production cost?
    Mr. Maddox. Yes.
    Mr. Pearce. So you mentioned in your written testimony that 
we should be able to squeeze out 2 to 3 million barrels a day, 
if we were able to access our resource and use it properly. How 
many acres would it take to get that kind of production?
    Mr. Maddox. I'm trying to remember that number. Basically, 
we are looking at 10,000 square miles.
    Mr. Pearce. Ten thousand square miles?
    Mr. Maddox. Yes.
    Mr. Pearce. To get that kind of production? And is that at 
30 gallons per ton? How many tons do you get off of an acre?
    Mr. Maddox. At maximum concentration, we can get 
approximately 2-1/2 million barrels per acre.
    Mr. Pearce. So 2-1/2 million?
    Mr. Maddox. Barrels of oil.
    Mr. Pearce. Say that again?
    Mr. Maddox. Two and a half million barrels of oil per acre, 
per day.
    Mr. Pearce. Per what?
    Mr. Maddox. Per day.
    Mr. Pearce. No, I was asking about the number of tons of 
material per acre. In other words, you are saying you can get 2 
to 3 million barrels a day out of shale oil. And I wonder how 
many acres it is going to take to get that done. How many 
acres?
    Mr. Maddox. Yes, one acre.
    Mr. Pearce. You said 10,000. I am trying to verify that 
with the number of----
    Mr. Maddox. Oh, for the----
    Mr. Pearce. Go ahead.
    Mr. Maddox. Well, we are looking to sustain this 
development long term.
    Mr. Pearce. That is what I am looking at, too.
    Mr. Maddox. Yes. Yes.
    Mr. Pearce. We are not talking about----
    Mr. Maddox. Yes, we are looking at approximately a 300-
million-barrel--billion-barrel resource. So, I will have to, 
you know--let me clarify those numbers. I will be happy to 
submit them for the record.
    Mr. Pearce. I would like to find out the number. I would 
like two or three approaches. You say it is going to take 
10,000 acres, and I would like some verification of that 
number. It is all I am trying to get.
    Mr. Maddox. Yes. I will be happy to supply those.
    Mr. Pearce. It will require us to consider the number of 
tons per acre of material that we are going to move. And to me, 
if we get 30 gallons per ton, that is not even yet a barrel per 
ton of material. And we will kind of come back to that, if you 
could help give us some documentation.
    Mr. Chairman, I have other questions, but I will wait until 
the next round. I see that my time has about expired.
    Mr. Gibbons. Mr. Pearce, let me explain from an engineering 
standpoint that a ton of rock is literally pretty close to a 
cubic meter worth of rock. So one cubic meter, you could get 
about a ton of rock out of it. So that is probably this shale 
that is sitting right in front of us.
    So a ton of material being that size, you would have to 
calculate the depth, thickness of the formation, the extent, 
the length, all of that. In an acre, if it is a 1,000-foot 
thickness, you can understand how many tons you are going to 
get off that real quickly.
    Mr. Pearce. I can work with the rock----
    Mr. Gibbons. That is why I gave it to you, so you could 
have something to do with that bright mind of yours besides sit 
here and ask questions.
    Mr. Cannon?
    Mr. Cannon. Thank you, Mr. Chairman. The other interesting 
thing about the size of a ton is that it equals about a barrel 
of oil, I understand. So it is interesting calculations.
    But let me ask you this question, Dr. Barna. Are you 
familiar with the two technologies that have been presented? 
You have the Shell in-situ process, where they heat the shale 
and draw off the liquid; and then the, I don't know, we call it 
the ``Savage process,'' essentially the old process but with 
some technical--do you happen to know how much water is 
required in either of those processes industrially? Are we 
talking about a significant amount of water?
    Dr. Barna. I do not, I am sorry to say. I am familiar with 
the process of how Shell Oil is going to use the in-situ and 
the above-ground retorting. But I am not a process expert. I am 
more at the consumer end of it.
    Mr. Cannon. Thank you. Mr. Calvert or Mr. Maddox, do either 
of you have a sense about how much water either of these 
processes is going to take, on a per-barrel or other basis?
    Mr. Maddox. I am sure I have this here in my notes, if you 
give me a second to dig through this. When we are looking for 
oil shale, our production is probably 1 or 2 barrels of water 
for every barrel of oil we produce. About two-thirds of that 
water, though, is dedicated to human resources, supporting 
people and infrastructure around it. That is compared to oil 
sand production, which is about 2 to 4 barrels of water per 
barrel produced.
    Mr. Cannon. Does that analysis distinguish between the in-
situ Shell process and the ``Savage process''?
    Mr. Maddox. It is generally considered approximately the 
same.
    Mr. Cannon. OK.
    Mr. Maddox. From a planning standpoint. Somewhat, it is 
geared to the offsite support mechanisms; not necessarily the 
process.
    Mr. Cannon. Do you have some documentation that analyzes 
that, that utilization?
    Mr. Maddox. We will be happy to----
    Mr. Cannon. If you have something, I would really very much 
appreciate that.
    Mr. Maddox.--yes, submit it, in some form, either a 
question for the record, it would be great, and we can just 
submit it through there.
    Mr. Cannon. Thank you. That would be perfect. Thank you 
very much.
    Dr. Barna, you were talking about coming up with a fuel, a 
single fuel that would meet two purposes. Can you just 
elaborate a little bit on what it would take for a diesel fuel 
to be equivalent to--I think you were talking about jet fuel--
for those two? Is that a technically hard thing to do?
    Dr. Barna. We think it is possible. We have put out a draft 
specification to industry, and they are taking a hard look at 
that. We have an excellent opportunity with the Fischer Tropsch 
type fuels, because when they are recombined over a catalyst 
you can almost do it boutiquely. You can add the number of 
carbons that you want and the amount of branching.
    So this just gives us the opportunity to look at what is 
available and then, rather than using specifications or 
certifications that go back to quite some time and tend to be 
patchwork, to look at the possibility of issuing new 
specifications that could cover this.
    Mr. Cannon. Would that be specifications for the engines or 
motors, or would that be specifications for the fuel itself?
    Dr. Barna. It would be for the fuel itself. Our goal is, we 
don't want an 18-year-old on the battlefield to have to make a 
decision on--you know, if it is fuel for his vehicle, or her 
vehicle, it is going to work, it is going to be fit for that 
purpose. But it may be the same fuel that they are putting into 
a ship or an aircraft as well as a tank.
    Mr. Cannon. Well, you are familiar with the fractions that 
come off naturally in the two processes. Are those fractions in 
the ballpark of the kinds of fuels that you are thinking in 
terms of?
    Dr. Barna. Well, I did that more of an illustration, sir, 
of, you know, sort of looking forward to see if we can make 
this process even better. We really haven't got our hands on 
enough of the fuel right now to do the testing we need to do. 
So as soon as that starts coming off the line, we will do that. 
And just as in the case of coal, we will look at reducing the 
number of fuels that the Department of Defense has to use.
    Mr. Cannon. How much fuel do you need coming out of this 
testing process, to get a sense of that?
    Dr. Barna. Well, we are getting very little right now. Just 
on the Fischer Tropsch side, to do all the evaluation that we 
need, we are talking somewhere in terms totally of about 20 
million gallons.
    Mr. Cannon. OK.
    Dr. Barna. And that is the bottom.
    Mr. Cannon. Thank you, Mr. Chairman. I see my time is about 
up. I yield back.
    Mr. Gibbons. Thank you very much, Mr. Cannon.
    Let me also ask Secretary Calvert, with regard to the 
research, development, and demonstration project acreage, the 
160-acre limit that you have out there, who decides on which 
acreage, or chooses the acreage? I am sure that there is a 
variation in terms of quality of oil shale that is out there, 
to make a determination. Who makes the decision on which 160-
acre parcel you get?
    Mr. Calvert. Well, that is correct, Mr. Chairman. There is 
a big difference in the quality of the oil shale from place to 
place. And what we have asked is for companies to come in and 
nominate the 160-acre parcels. We leave it to them to identify 
where the best prospects are and to come in and nominate them.
    Mr. Gibbons. Is there a process by which they can go out 
and evaluate these oil shale deposits, in terms of vertical 
thickness or quality, without having to go through a long, 
torturous EIS process?
    Mr. Calvert. Well, let me just check this, because what I 
am assuming is that they will be relying on previous USGS 
assessments of what was out there. If you will give me just a 
moment, please.
    [Pause.]
    Mr. Calvert. Yes. The assessment was done in the mid-'80s, 
and they will be relying on that, is our assumption, to 
identify the high-quality locations.
    Mr. Gibbons. Those were mostly surface examinations of the 
deposit; were they not?
    Mr. Calvert. They were done with core samples, maps, 
surface identification, yes.
    Mr. Gibbons. OK. Where are you with regard to your 
commercial leasing regulation of oil shale? Where is the 
process right now? What is the expectation in terms of time to 
finish producing a regulation which will allow for commercial 
leasing of oil shale?
    Mr. Calvert. Congressman, we haven't actually begun the 
rulemaking process for that. But the BLM is prepared, once we 
got this rule out three weeks ago, to start this process. We 
estimate 18 months to two years for commercial leasing regs. 
The Department has the authority, under the Mineral Leasing 
Act, to issue such regulations, and we intend to move forward 
with that.
    Mr. Gibbons. When do you intend to move forward with it?
    Mr. Calvert. I can't give you an exact date, but we would 
like to move forward with it as soon as possible.
    Mr. Gibbons. Mr. Maddox, let me ask, if you in the 
Department of Energy do your economic analysis of oil shale 
using current technologies, using current economic pricing 
index, and find that oil shale is an economic resource, will 
that change the definition of the resource to a proven reserve, 
once you have done your economic analysis?
    Mr. Maddox. The definition of ``proven reserves'' actually 
is a Securities and Exchange Commission term. And that would 
have to imply commercial development plans and expenditures are 
being done on the property, and does not move to that point 
until production has actually started or the work toward 
production is started.
    So from an SEC standpoint, it would take someone actually 
doing work and committing resources to bring it into 
production. From our standpoint, that's a reserve that exists; 
it is there; it is available. And the only thing preventing its 
development is the decision by someone to develop that 
resource.
    Mr. Gibbons. So if some company--say, Shell Oil Company--
decides that its process is economically recoverable and that 
it wants to engage in that, and you make an economic 
determination in your publications--or you make that economic 
determination somehow--you would then see that if Shell is 
doing it economically, then according to SEC--the Securities 
and Exchange Commission--terminology, that it would change----
    Mr. Maddox. Right.
    Mr. Gibbons.--the resource to a proven reserve oil base in 
this country?
    Mr. Maddox. Correct. And that is one of the reasons why 
there was a shift a year or two ago on the oil sands; that it 
was deemed as being developed and an appropriate level of 
private-sector development. So it was moved from an unproved 
reserve; which is why such a huge jump in the reserves in 
Canada.
    Mr. Gibbons. You don't see any obstacles with regard to 
environmental mitigation for development of this, do you, at 
this time?
    Mr. Maddox. Everyone understands that environmental issues 
need to be addressed. And I have complete confidence that they 
can be addressed.
    Mr. Gibbons. Now, getting back to my previous question, if 
I may take just a minute beyond my time, because I think I want 
to fully develop this idea about proven reserves, isn't this 
exactly what happened in the Canadian oil sands?
    Mr. Maddox. Exactly. It was not recognized as proven 
reserves until about two years ago, when you kind of had 
critical mass of investment.
    Mr. Gibbons. And did you have any involvement as the DOE 
with regard to designating them as proven reserves once this 
process took place?
    Mr. Maddox. No, we did not.
    Mr. Gibbons. So it was simply an industry regulation.
    Mr. Maddox. Right.
    Mr. Gibbons. Or an industry determination.
    Mr. Maddox. Uh-huh.
    Mr. Gibbons. All right. Mr. Pearce?
    Mr. Pearce. Thank you, Mr. Chairman.
    Secretary Calvert, how long has your task force been going 
on? When did it start?
    Mr. Calvert. I believe it was convened in 1993.
    Mr. Pearce. 1993?
    Mr. Calvert. Yes, sir.
    Mr. Pearce. In 1993, the price was about 18 bucks; and in 
1999, it eased down to 6 bucks. Now it is up to 60 bucks----
    Mr. Calvert. I'm sorry, 2003.
    Mr. Pearce. Oh, 2003?
    Mr. Calvert. Yes, sir.
    Mr. Pearce. In 2003, what was the price of oil?
    Mr. Calvert. Somewhere in the 20s, as I recall.
    Mr. Pearce. Now we are somewhere in the 60s. Do you have a 
department in your agency that says, ``You know, the price just 
went from 20 to 60; can we accelerate this process?'' Do you 
have a department that does that?
    Mr. Calvert. Accelerate the task force?
    Mr. Pearce. Accelerate the concept that we are becoming 
every day more dependent on oil; that the price of oil has the 
potential to break the economy; and that you have a resource 
there that is possibly--maybe not, but possibly--a source of 
great production. And do you ever get a little more, ``Pick up 
your feet just a little, troops; let's move a little bit more 
fast, because the price could be 100 as easily as it could be 
back to 20''? Do you do that kind of discussion?
    Mr. Calvert. Well, of course, we do that kind of 
discussion. I have no doubt in my mind that there is 
commercially developable oil shale that not only can be 
produced, but can be transported in an economical way.
    Mr. Pearce. Why do you not have a doubt about that? Because 
right now, it appears you are even unwilling to take on the 
NEPA process for the 4,900-acre tract, or whatever, on top of 
the 160. You prefer to stay on the 160s.
    Mr. Calvert. Well, the problem with that is that we don't 
have any proposals. We have several different technologies out 
there, and it is hard to do the NEPA without the proposals.
    Mr. Pearce. You don't have any proposals right now to 
lease?
    Mr. Calvert. No, sir.
    Mr. Pearce. Lease land? Dr. Barna, does the fact that you 
are investigating alternative sources for DOD--because I am 
sure you are worried about national security and the 
availability. And in your report you say you have 1.4 trillion 
barrels of oil available; and yet you see the BLM doesn't even 
have a request out there. Does that make you wonder in the 
middle of the night if you really have correctly evaluated how 
much oil is really available to us?
    Dr. Barna. Well, I think that it is available as a 
resource, sir.
    Mr. Pearce. No, no, but if it is an available resource, 
that means we could go out and tap it. And yet, you see the 
process started in 2003, and the price has gone from 20 to 60, 
and the process hasn't picked its pace up at all. It is going 
to continue wandering on through this bureaucratic maze. And 
you say it is available, and I am not sure it is.
    Dr. Barna. When I say it is available; potentially 
available. You know, as soon as we can get it out of the 
ground. We have the processes to do it. We have the resources, 
but----
    Mr. Pearce. No, you only have the resources when you have 
the resources.
    Dr. Barna. When we have them. Right.
    Mr. Pearce. I have a desire to put a lot of money in the 
bank; but until I get it there, the banker is not going to loan 
me a house on it.
    Secretary Calvert, you feel certain that when you get 
through this 18 months to two years that the Chairman talked 
about, that you will start leasing, if the plans were 
available?
    Mr. Calvert. Well, what we have is, we have land-use plans. 
And we would like to be able to do environmental assessments to 
those land-use plans for these 160 acres. They are much easier 
to do. We don't have to do full-scale EIS's on something that 
we don't actually know at this point----
    Mr. Pearce. Now then, we go over to Mr. Maddox's discussion 
about the number of tons per acre.
    Mr. Calvert. Well, we don't know. It could be the retort 
technology, it could be in-situ----
    Mr. Pearce. Is a 160-acre block economically viable?
    Mr. Calvert. Well, the economic viability is a commercial 
quantity of the available area, so it is a----
    Mr. Pearce. No, no, no, the economic viability--if I am 
drilling an oil well, the economic viability is the cost of 
that oil well and the amount of oil I can get out of it. And I 
am asking, is a 160-acre tract, if that is what you are going 
to lease because the NEPAs are a little bit difficult on the 
larger tracts, is a 160-acre tract an economically viable 
number?
    Mr. Calvert. [No response.]
    Mr. Pearce. I think we probably should have an answer to 
that at some point. And I guess my last question would be on 
this. So we are going to go 18 months to two years, and we are 
going to get this process for leasing. Why would I believe that 
this shale oil is going to be any more available than natural 
gas, when the BLM refuses to give leases in areas that have 
been previously drilled?
    Again, I am trying to address the question of Dr. Barna 
there of: Do we have enough fuel; do we have enough energy for 
our own DOD requirements, our own defense? And I see the BLM 
unwilling to give leases on natural gas. What makes me think 
that in a process that is far more invasive, that we are ever 
going to even lease one acre? Can you give me an answer to 
that?
    Mr. Calvert. I think that is a legitimate concern. I am not 
sure exactly which BLM leases you are talking about, but the 
NEPA--I hold no illusions. NEPA on oil shale will not be a 
simple process. Depending on the technology, it could be very 
invasive, and depending on the location and the process that 
you go through. I don't anticipate it is going to be painless.
    This is why, in order to expedite at least getting people 
onto BLM land, we decided to use EAs, instead of going straight 
for a full lease and have to do EIS's; because then we would be 
in a two-year process before they could ever even go out and 
start designing their plans. And I share your concern. We 
intend to proceed as aggressively as possible.
    Mr. Pearce. My time has expired, but I want to get my staff 
to give you exactly leases where the BLM in the Rocky Mountains 
is not issuing APDs so that people can drill, in areas that 
have been previously drilled. It is not like it is pristine. I 
will get you that information.
    In the meantime, Dr. Barna, you might look at powering 
those airplanes and tanks with something else.
    Mr. Gibbons. Mr. Pearce, let me try to clarify your 
question about the 160-acre and economic viability. The 160-
acre is simply for a research and demonstration project. It is 
not necessarily a determination. That 160-acre would be a 
limited amount for a commercial operation. It is there to 
determine whether or not the process by which they are trying 
to develop under the RD&D principle is suitable. So you are 
right, 160 acres would not----
    Mr. Pearce. I think that, in effect, this is something that 
we have to be aware of downstream. If the agency has got some 
concerns right now about NEPA processes, why are we saying this 
stuff is available? It may not ever be touched. And we need to 
be honest with ourselves if we are in this Committee hearing.
    Mr. Gibbons. I was only answering the question about the 
economic side of it before that. And there is an opportunity 
for extending the 160 acres.
    Did you say 140, Mr. Calvert?
    Mr. Calvert. Up to the statutory maximum, which is 5,120.
    Mr. Gibbons. Five thousand, one hundred and twenty acres. 
All right. Mr. Cannon?
    Mr. Cannon. Thank you. First of all, let me just point out 
that I love the idea of a ``Department of Acceleration.'' That 
actually makes a lot of sense.
    Following up on this, with the RD&D lease starting at 160 
acres, the cost of developing that, depending upon the depth 
and lots of other things, could be very great. I mean, the 
operation in eastern Utah, as I recall, was 200 or 300 million 
dollars, just to develop the mine site. And you can hardly do 
that unless you are pretty sure you are going to go way, way 
beyond 160 acres.
    Mr. Calvert, does that 160 acres relate also to the Shell 
process, where they are looking at a section of land? And with 
the resources they are dealing with, they are looking at a 
billion barrels of oil out of one section, but it is a 
terrifically expensive process to do; and yet, there is a 
certain minimum. And 160 acres is probably, I would think, in 
that situation too little acreage to really get an economically 
viable test, especially when you have two or three years.
    Is that 160 acres going to be limiting for them? Or are you 
going to do an EIS process to make that a larger test?
    Mr. Calvert. Well, if they were to exercise their right to 
expand up to the 5,120 acres, it is our anticipation that, 
unless there were a programmatic EIS in place to cover it, we 
would have to do site-specific EIS's on those 5,000-acre 
developments.
    Whether or not they can show commercial quantities on 160 
acres, the reg that we issued in June is a little vague, 
because it is new territory what commercial quantities are and 
what commercial viability is; and essentially, put the burden 
on the company to show to the authorized officer that they can 
produce.
    It is an equation that we exercise in coal leasing, for 
example, about diligence on commercial coal operations. These 
are functions that the BLM can do, I am certain. It is just not 
something that they have done before.
    Mr. Cannon. You know, as each of the western states was 
brought into the Union, each state passed, or the Federal 
Government passed an organic act for each state, which were 
almost--or for the western states, public land states--were 
uniform in the obligation to do several things: set aside 
school trust lands; there was an obligation to sell the public 
lands and give a percentage of the proceeds of those sales, 
typically 5 percent, to the various states, and that would 
move, of course, Federal lands into productivity, and frankly 
into taxpaying status.
    As Mr. Pearce has pursued this concept of how long it would 
take to get this resource into production, does it make sense 
for the Federal Government to be thinking in terms of getting 
the heck out of the business of controlling public lands and 
turning it over to states?
    In particular, Mr. Bishop is about to introduce a bill that 
would require the Federal Government--which has not sold these 
public lands, as they are mandated to do by law--to take 5 
percent of the Federal lands and turn them over to the states, 
probably to the school trust lands organizations.
    Does it make sense to let the states choose lands, 
especially in Utah, Colorado, Wyoming, these shale oil lands, 
so that we can move them into production faster than it appears 
that the Department is able to do?
    Mr. Calvert. Well, this is kind of a trick question.
    Mr. Cannon. Oh, it's a very straightforward question. For 
the Federal Government, it may be tricky.
    Mr. Calvert. If a bill were to pass to convey 5 percent of 
the lands to the states, then it would make sense for the 
states to choose lands that were productive for oil shale, and 
for oil and gas, and coal and everything else. It depends on 
how the bill were written.
    Mr. Cannon. But of course, this is tricky because you don't 
have a departmental position on this thing yet.
    Mr. Calvert. Right.
    Mr. Cannon. But I was asking your opinion. Does it make 
sense for America to get these lands in a context that is a 
state-owned context, so they could be developed more quickly?
    Mr. Calvert. It makes sense for America to get these lands 
into a context where they can be developed, yes, sir. Whether 
the states or the Federal Government can do it faster, I am not 
sure.
    Mr. Cannon. Maybe not all states can do it faster than the 
Federal Government, but I can assure you that some would.
    Mr. Calvert. The State of Utah probably can.
    Mr. Cannon. And with that, Mr. Chairman, I am going to 
yield back. My time is almost gone, but that is a great point 
to turn my time back, so I will do that.
    Mr. Gibbons. Thank you, Mr. Cannon. And we have been joined 
now by Mrs. Drake. Thelma, do you have any questions that you 
want to ask at this time? The floor is yours.
    Mrs. Drake. Thank you, Mr. Chairman. I would just like to 
thank all of you for being here. I truly apologize for being so 
late today. But I was in the first meeting that we had on this 
issue; found it very, very informative. I think what I came 
away with on that one the most is that our friends in Canada 
have found a way to do this, to do it efficiently, to cut 
through the permitting process. My concerns are about where we 
are in the U.S.
    You have probably already answered all of those questions, 
but I think that this is a national security issue. I think 
that we need to be certain that we are energy independent. I 
think this plays a major part in it. And I look forward to 
working with you.
    And if any of you have comments, that is fine. You don't 
need to comment, because I know you have already answered a lot 
of questions from a lot of other people, and I am walking in 
right at the last minute. Mr. Chairman, thank you for pursuing 
this issue.
    Mr. Gibbons. You are welcome. And Mrs. Drake does raise a 
very valuable question for our Committee. I would turn to Dr. 
Barna, and ask how important is it to DOD, for example, to have 
a secure and reliable source of oil outside of a foreign source 
of oil dependency that we are in today?
    Dr. Barna. Well, I think it is very important. If we are 
importing half of our oil--and it is going to go close to 70 
percent here by 2025, I believe are the estimates--we could be 
relying on people that don't necessarily have the same 
interests that we do and could cause a cut. And we certainly 
don't want to get where there is another limited supply, where 
then there have to be determinations made on how you use that 
supply.
    So it is very important to us. And having an indigenous, 
secure supply of energy I think is certainly in the interests 
of the Department of Defense.
    Mr. Gibbons. Well, when you talk about the military, how 
much oil, and its products of oil, on a daily or annual basis, 
does the Department of Defense consume?
    Dr. Barna. We use approximately 4 percent of the energy, 
the jet fuel and the diesel that are used in the United States. 
So we are really not the big dogs on the porch there. But we 
use enough that we can perhaps influence----
    Mr. Gibbons. What, in terms of gallons or barrels, is that 
a day?
    Dr. Barna. I believe that is--let me check. About 300 to 
350 thousand barrels a day, right now.
    Mr. Gibbons. That sounds like a whole lot more impressive 
than just saying 4 percent; although many people out there, if 
they knew the total amount of our consumption, could calculate 
that. Very important for you to say 350,000 barrels a day.
    Dr. Barna. And just to clarify, three-quarters of that is 
jet fuel. So that is really where our impact is made in this 
JP-8.
    Mr. Gibbons. And do you have an estimate of how much of 
that 350,000-barrels-per-day consumption is produced from 
foreign sources?
    Dr. Barna. I don't. Let me see.
    [Pause.]
    Dr. Barna. We buy oil worldwide. And since we import about 
half of it, I assume it to be about half. But I really don't 
have the hard numbers to back that up.
    Mrs. Drake. Mr. Chairman?
    Mr. Gibbons. Mrs. Drake.
    Mrs. Drake. Wouldn't he be doing what we are doing as a 
nation, which is about 60, 62 percent, would be foreign oil? I 
mean, he doesn't have his own source.
    Dr. Barna. Right, exactly. I would assume that since we do 
a worldwide supply, that we are going to be importing--or our 
domestic resources would be somewhere around 50 percent, and 
the other half would come from outside America.
    Mr. Gibbons. We do have a strategic defense oil reserve; do 
we not?
    Dr. Barna. Yes, we do. That is under the Department of 
Energy, by the way.
    Mr. Gibbons. And today, are we filling that, or drawing oil 
out of it?
    Mr. Maddox. We are filling it at this point, I think.
    Mr. Gibbons. With $60-a-barrel oil?
    Mr. Maddox. That is actually royalty-in-kind oil, so it is 
oil coming in from the Gulf that is part of our lease payments.
    Mr. Gibbons. OK. Let me ask Mr. Maddox, in some of your 
publications from the Department of Energy, and indeed in some 
of your comments here, you talk about the greenhouse gas 
emission from the production of oil shale. Is not there a 
greenhouse gas emission from the production of oil from 
standard oil fields?
    Mr. Maddox. Yes, there is.
    Mr. Gibbons. So in essence, what we are saying is that 
regardless of how we get oil out of the ground, there will be a 
greenhouse gas emission?
    Mr. Maddox. That is correct.
    Mr. Gibbons. So it really isn't something that ought to 
prevent us from stopping production of oil shale because, as 
you say, there is a similar or like emission of greenhouse 
gases from production of an oil well in Texas or any place, 
Oklahoma, or the Gulf of Mexico?
    Mr. Maddox. Yes. Emissions are a fact of life in 
production. In fact, that is one of the issues Saudis are very 
interested in, in fact, is trying to learn how to capture some 
of that for EOR and other----
    Mr. Gibbons. Well, and also, if you look at the consumption 
of unconventional oils versus conventional oil--conventional 
oil being what we are talking about, Texas crude, Gulf of 
Mexico crude--is there a difference in the emissions that would 
come from oil produced from shale, versus conventional oil?
    Mr. Maddox. I just want to confirm that, actually. It is 
possible in the retort process, because of the high 
temperatures, you could have a higher level of emissions than 
you would under conventional oil.
    Mr. Gibbons. Doesn't a retort keep completely enclosed the 
environment in which the material is being heated?
    Mr. Maddox. My understanding is there are emissions; that 
it does not completely enclose; that there is a certain foaming 
and everything else, but there is a release point.
    Mr. Gibbons. Well, because one of the things they produce 
right here from this oil shale is propane. So if you had a 
release of propane, you have a real serious fire out there.
    Mr. Maddox. Yes.
    Mr. Gibbons. So they do control----
    Mr. Maddox. Capture, yes.
    Mr. Gibbons. They do control or capture the gases coming 
off of a retort.
    Mr. Maddox. As much as they can. But traditionally, CO2 is 
not captured. And that would be the issue. Now, there are uses. 
Again, you know, most of these are located near gas fields and 
other areas, and there is potential enhanced oil recovery use 
for that CO2; which is what we are doing in a number of 
demonstration projects right now.
    Mr. Gibbons. How about the in-situ recovery of oil, where 
it is a down-the-hole heating of the environment? What 
difference would there be from an in-situ versus a retort, with 
regard to greenhouse gas emission?
    Mr. Maddox. In-situ would actually have a lower level, 
because the heat and power that is generated is essentially 
created from an associated gas stream that powers the local 
generation. So essentially, you have something more similar to 
a low-emission natural gas generation facility. So you actually 
have a pretty low emission level coming in an in-situ process.
    Mr. Gibbons. So somehow, they recover the CO2, then, from 
the heating of the elements, or whatever power generation is 
required to heat the element that is down-hole?
    Mr. Maddox. The carbon is created above the hole in the 
generation of electricity, which is used to heat down-hole. So 
there is actually no CO2, or minimal CO2 produced from in-situ.
    Mr. Gibbons. Well, gentlemen, I commend each of you for 
your testimony here today, your presence, and the interest you 
have shown in what I believe is probably one of the most 
encouraging oil resources that we have seen or looked at in a 
long time to meet the energy needs of America.
    As we know, the energy of our economy runs on oil. And the 
oil shales, oil sands of this country have all of the 
earmarkings of an enormously important product or process for 
assisting in the oil consumption of our economy, and one which 
I don't think we can either ignore; nor do I believe we can 
wait long to have it developed.
    I think when the American public sees $100-per-barrel oil, 
they will be asking their government, ``What did you do? What 
did you not do, knowing that it was coming, that could have 
expedited the production of oil, that could have mitigated or 
suppressed the per-barrel cost of oil in this country?''
    We say it is ten years off from this point, down the road. 
I say it is ten years off because we lack the will power to do 
what is necessary to make sure that it is onboard, that it is 
being developed in a commercially expedited fashion.
    And I think Mr. Pearce and Mr. Cannon are right. We need a 
government that looks down the road and says, ``How can we make 
this happen quicker?'' We have an obstacle mentality in 
government, for some reason. We look at this and say, ``There 
are so many obstacles that we can't overcome them quickly.''
    I think we ought to be looking at how the industry faces 
these challenges. And the industry faces them from saying, 
``These are obstacles that we can overcome, and we can overcome 
them if we work together as a team.''
    I am pleased that the Department of Defense, the Department 
of Energy, and the Department of Interior, all have a related 
role in this. And every one of us, from the legislative branch 
to the administrative branch of government, have an obligation 
to see to it that we assist in the determination of this 
resource as to its viability in producing the energy sources to 
relieve the dependence of this country on foreign sources of 
energy.
    That is an obligation that you have, as well as I do. And 
it is one which I take very seriously; and I hope you do, too. 
So I hope that the information we have gained from this allows 
for us to start thinking about: How do we expedite the process? 
How do we get this to the public? So that we can avoid the 
$100-per-barrel catastrophe that this is going to have on the 
U.S. economy.
    With that, Mrs. Drake, do you have any additional 
questions?
    Mrs. Drake. No, thank you, Mr. Chairman.
    Mr. Gibbons. Again, I want to thank our witnesses. You have 
been very good. We had planned to have us here for a little 
longer, but the good luck of the Irish got you out a little 
early.
    We will submit written questions to each of our witnesses 
here today that we would like you to review and respond back to 
this Committee within ten days. The record will remain open for 
a period of about ten days, for members to submit written 
questions as well as opening statements.
    With that, again, I hope you can see the interest that we 
have in developing alternative and unconventional sources of 
energy for this country. And this appears to be one of the very 
promising resources that we have.
    And let's hope for America that we do it right, and that we 
do it expeditiously; that we do it efficiently; that we do it 
environmentally soundly; and that we can answer the American 
public's demand for energy in this country in a timely and 
economic process.
    With that, the hearing is adjourned.
    [Whereupon, at 11:12 a.m., the Subcommittee was adjourned.]

    [A statement submitted for the record by Dr. Robert Trent, 
Former Dean, School of Mineral Engineering, University of 
Alaska-Fairbanks, follows:]

              Statement of Dr. Robert Trent, Former Dean, 
    School of Mineral Engineering, University of Alaska-
                               Fairbanks

    While $60.00 per barrel crude oil has generated panic-driven calls 
for an ``alternative Energy industry,'' hydrocarbons have begun the 
transition from conventional to Non-conventional oil. The historic 
inclusion of oil sands in Alberta as proven reserves Of bitumen 
deposits assessed at 178 billion barrels is the transformative bench-
mark Between conventional and non-conventional. Expectations of a 
million barrels oil Per day from Alberta's tar sands has launched 
exploratory extractive and technology Interest in other sources from 
China to Venezuela to Utah.
    The estimated oil sand resources in the United States are in excess 
of 60 billion barrels of proven and estimated reserves. In the lower 
48, the majority of these reserves occur in four states: Utah, Alabama, 
Texas and California. Utah contains the largest of these reserves with 
estimates by the U.S. Geological Survey of approximately 11.3 billion 
barrels. Utah contains in excess of 40% of the United States estimated 
reserves and approximately 60% of the measured reserves. Utah has 
identified 54 oil sand deposits of which 10 are considered as major.
    Two of the largest Utah deposits near an infrastructure that will 
be required for a timely production of the sands are Sunnyside and 
Asphalt Ridge. There are other large deposits in Utah, however they are 
remote and will require major capital for roads, power and pipelines. 
Sunnyside is the largest single oil sand deposit in the United States 
and is located in the southern portion of the Unita Basin. The 
Sunnyside deposit was estimated by the United States Geological Survey 
to contain 728 million barrels of 10 to 12 API gravity oil. Asphalt 
Ridge is estimated by Covington and others to contain 250 million 
barrels of oil.
    The oil sands of the Sunnyside deposit lie on the southern flank of 
the Unita Basin. Elevation of the deposit ranges from 8,500 to 10,000 
feet. The oil sands are in the upper part of the Wasatch formation and 
the lower part of the Green River formation. The most significant of 
oil occur in the Wasatch portion of the deposit. The saturated beds 
range in thickness from a few inches to more than 350 feet. Regional 
dip of the formation is north and east at 6 to 8 degrees. Much of the 
Sunnyside deposit can be surface mined and therefore offers an 
excellent target for economic development. The deposit is approximately 
eight miles from the Denver and Rio Grand Western Railroad and about 
six miles north of the coal mining area of Sunnyside. The United States 
Geological Survey estimates the deposit contains 1,600 million cubic 
yards of sands of which over 50% is commercial. Commercial grade is 
considered to contain in excess of 9% bitumen. As noted above, the 
Geological Survey estimates the deposit to contain 728 million barrels 
which is described as 450 million yards of measured and indicated 
material and 350 million yards as inferred material.
    Asphalt Ridge runs Northwest/Southeast for approximately 10 miles. 
The ridge is approximately 3 miles from the town of Vernal Utah and is 
cut by highway 40. The more erosion resistant portions of the formation 
form the ridge for which it is named. The ridge is made from the 
Mesaverde sandstones and shales. The formation dips 8 to12 degrees to 
the southwest. The major bitumen saturation is in the Tertiary and 
Cretaceous age beds.
    The bitumen is 12 degree API gravity and extremely low in sulfur. 
Vernal is a town where mining and conventional oil production is a 
large part of the economy and therefore the infrastructure to support 
an oil sand facility is present. Although the Asphalt Ridge deposit is 
not as large as Sunnyside it has received the most attention and 
research due to its location and infrastructure. Over the years several 
projects have tried to produce the oil and currently there is a new 
1,500 barrel/day refinery on the north edge of Vernal that is 
mothballed because the operator was not able produce enough crude using 
their process.
    Prior research includes various compounds that act a diluents. 
These include diesel, hydrogen, hot water, centrifuges and solvents. In 
almost all cases the processes required heat. With the current cost of 
natural gas the economics of many of these processes is questionable. 
There have been bench scale tests of new products that do not require 
heat. These bench scale tests need to be expanded to demonstrations and 
pilot phases to prove the economics are favorable.
    We do not believe the processes and methods used to produce bitumen 
in Canada can be economical in Utah. They require large amounts of 
energy in the form of natural gas and water. However, U.S. tar sands 
(Utah) recovery could begin with less capital ``intensive and more 
energy-efficient recovery systems appropriate to smaller reserve Sites. 
This could take place with an efficient modular reconfigurable designed 
recovery System approach which, with demonstrated economics, will 
introduce Utah tar sands As an unconventional source of oil 
(hydrocarbons) in diminishing American dependence On imported 
fuels.

                                 
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