    [House Hearing, 107 Congress]
    [From the U.S. Government Publishing Office]

                  OIL AND GAS RESOURCE ASSESSMENT METHODOLOGY

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

                               OVERSIGHT HEARING

                                   before the

                           SUBCOMMITTEE ON ENERGY AND
                               MINERAL RESOURCES

                                     of the

                             COMMITTEE ON RESOURCES
                         U.S. HOUSE OF REPRESENTATIVES

                          ONE HUNDRED SEVENTH CONGRESS

                                 SECOND SESSION

                                   __________

                                 April 18, 2002

                                   __________

                               Serial No. 107-106

                                   __________

               Printed for the use of the Committee on Resources

     Available via the World Wide Web: http://www.access.gpo.gov/congress/
                                     house
                                       or
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                             COMMITTEE ON RESOURCES

                        JAMES V. HANSEN, Utah, Chairman
           NICK J. RAHALL II, West Virginia, Ranking Democrat Member

    Don Young, Alaska,                   George Miller, California
      Vice Chairman                      Edward J. Markey, Massachusetts
    W.J. ``Billy'' Tauzin, Louisiana     Dale E. Kildee, Michigan
    Jim Saxton, New Jersey               Peter A. DeFazio, Oregon
    Elton Gallegly, California           Eni F.H. Faleomavaega, American
    John J. Duncan, Jr., Tennessee           Samoa
    Joel Hefley, Colorado                Neil Abercrombie, Hawaii
    Wayne T. Gilchrest, Maryland         Solomon P. Ortiz, Texas
    Ken Calvert, California              Frank Pallone, Jr., New Jersey
    Scott McInnis, Colorado              Calvin M. Dooley, California
    Richard W. Pombo, California         Robert A. Underwood, Guam
    Barbara Cubin, Wyoming               Adam Smith, Washington
    George Radanovich, California        Donna M. Christensen, Virgin
    Walter B. Jones, Jr., North              Islands
        Carolina                         Ron Kind, Wisconsin
    Mac Thornberry, Texas                Jay Inslee, Washington
    Chris Cannon, Utah                   Grace F. Napolitano, California
    John E. Peterson, Pennsylvania       Tom Udall, New Mexico
    Bob Schaffer, Colorado               Mark Udall, Colorado
    Jim Gibbons, Nevada                  Rush D. Holt, New Jersey
    Mark E. Souder, Indiana              James P. McGovern, Massachusetts
    Greg Walden, Oregon                  Anibal Acevedo-Vila, Puerto Rico
    Michael K. Simpson, Idaho            Hilda L. Solis, California
    Thomas G. Tancredo, Colorado         Brad Carson, Oklahoma
    J.D. Hayworth, Arizona               Betty McCollum, Minnesota
    C.L. ``Butch'' Otter, Idaho
    Tom Osborne, Nebraska
    Jeff Flake, Arizona
    Dennis R. Rehberg, Montana

                          Tim Stewart, Chief of Staff
               Lisa Pittman, Chief Counsel/Deputy Chief of Staff
                    Steven T. Petersen, Deputy Chief Counsel
                        Michael S. Twinchek, Chief Clerk
                     James H. Zoia, Democrat Staff Director
                   Jeffrey P. Petrich, Democrat Chief Counsel
                                     ------

                  SUBCOMMITTEE ON ENERGY AND MINERAL RESOURCES

                        BARBARA CUBIN, Wyoming, Chairman
                  RON KIND, Wisconsin, Ranking Democrat Member

    W.J. ``Billy'' Tauzin, Louisiana     Nick J. Rahall II, West Virginia
    Mac Thornberry, Texas                Edward J. Markey, Massachusetts
    Chris Cannon, Utah                   Solomon P. Ortiz, Texas
    Jim Gibbons, Nevada,                 Calvin M. Dooley, California
      Vice Chairman                      Jay Inslee, Washington
    Thomas G. Tancredo, Colorado         Grace F. Napolitano, California
    C.L. ``Butch'' Otter, Idaho          Brad Carson, Oklahoma
    Jeff Flake, Arizona
    Dennis R. Rehberg, Montana
                                     ------
                                C O N T E N T S

                                  ----------
                                                                       Page

    Hearing held on April 18, 2002...................................     1

    Statement of Members:
        Cubin, Hon. Barbara, a Representative in Congress from the
          State of Wyoming...........................................     1
            Prepared statement of....................................     3
        Kind, Hon. Ron, a Representative in Congress from the State
          of Wisconsin, Prepared statement of........................     5

    Statement of Witnesses:
        Clarke, Kathleen, Director, Bureau of Land Management, U.S.
          Department of the Interior.................................     6
            Prepared statement of....................................     8
            Response to questions submitted for the record...........    10
        Goerold, W. Thomas, Ph.D., Owner, Lookout Mountain Analysis,
          Prepared statement of......................................    61
            Response to questions submitted for the record...........    72
        Knopman, Debra, Ph.D., Senior Engineer/Associate Director,
          RAND (Research and Development) Science & Technology.......    19
            Prepared statement of....................................    20
            Response to questions submitted for the record...........    24
        Mankin, Charles J., Ph.D., State Geologist of Oklahoma, on
          behalf of the American Association of Petroleum Geologists.    27
            Prepared statement of....................................    29
            Response to questions submitted for the record...........    36
        Morton, Peter, Ph.D., Resource Economist, The Wilderness
          Society....................................................    41
            Prepared statement of....................................    43
            Response to questions submitted for the record...........    53
        Seegmiller, Ray, Chairman, President and Chief Executive
          Officer, on behalf of Cabot Oil & Gas Corporation and
          Domestic Petroleum Council.................................    54
            Prepared statement of....................................    56
            Response to questions submitted for the record...........    59

    Additional materials supplied:
        American Petroleum Institute, Statement submitted for the
          record.....................................................    82
        Eppink, Jeffrey, Vice President, Advanced Resources
          International, Statement submitted for the record..........    86
        Whitsitt, William, President, Domestic Petroleum Council,
          Letter and paper submitted for the record..................    89

      OVERSIGHT HEARING ON ``OIL AND GAS RESOURCE ASSESSMENT METHODOLOGY''

                                  ----------

                            Thursday, April 18, 2002

                         U.S. House of Representatives

                  Subcommittee on Energy and Mineral Resources

                             Committee on Resources

                                 Washington, DC

                                  ----------

        The Subcommittee met, pursuant to notice, at 10:37 a.m., in
    room 1334, Longworth House Office Building, Hon. Barbara Cubin,
    presiding.
        Ms. Cubin. I apologize for my tardiness in getting here
    today. We were in a tangle of traffic that is like one I have
    not seen since we have been in Washington. We will get right
    with it, because we have votes coming along. We have two. I
    guess that there are votes going on now. What I think we will
    do is make the opening statement; go to vote; and then come
    back and hear the testimony as quickly as we can.

       STATEMENT OF THE HON. BARBARA CUBIN, A REPRESENTATIVE IN
                   CONGRESS FROM THE STATE OF WYOMING

        The Subcommittee today meets to explore the basis for the
    regional oil and gas assessment approaches. The Secretary of
    the Interior, in consultation with the Secretaries of
    Agriculture and Energy, is completing an assessment of the oil
    and gas resource base on the Lower-48 Federal lands, together
    with an inventory of restrictions on accessing these resources.
    This action was mandated under Section 206 of the Energy Policy
    Act of 2000. Today's hearing will primarily focus on the Rocky
    Mountain region where the controversy over oil and gas
    assessment methods has recently arisen.
        Congress and the executive branch need an objective
    scientific analysis of the oil and the gas potential of the
    public lands, together with a full understanding of the
    impediments to exploration and development. Without such an
    analysis, we cannot rationally debate options for meeting
    domestic supply requirements for natural oil and gas.
        The Rocky Mountains are a frontier gas province with about
    85 percent of its known gas reserves still in the ground. A
    National Petroleum Council assessment in 1999 estimated that 40
    percent of the natural gas resource in this province is
    affected by access restrictions. However, since the NPC study,
    new land withdrawals for national monuments and in roadless
    areas have further impacted natural gas resources in the
    Rockies. In the later case, an analysis by the Department of
    Energy has shown that an additional estimated 11.3 trillion
    cubic feet of technically recoverable natural gas is affected
    by roadless withdrawal areas.
        In February, an independent research group, RAND, released
    an interim report which criticized the current oil and gas
    resource assessments of the Rocky Mountains as overly
    optimistic, primarily because they believe too few economic
    factors are considered. RAND concluded that only economically
    viable resources should be considered in regional oil and gas
    assessments.
        RAND plans to perform its own analysis of the oil and gas
    resource base in the Intermountain West, along with an
    examination of the opportunities and constraints on
    development. This private study will apparently duplicate the
    Section 604 inventory of oil and gas resources in the Rocky
    Mountain region. The Hewlett Foundation has given RAND a
    $450,000 grant for this work. Will the RAND oil and gas
    assessment improve upon the Section 604 inventories? Many
    believe that the oil and gas assessment methodology is
    inherently conservative and, more often than not, leads to
    under-estimation, rather than over-estimation, of recoverable
    hydrocarbons.
        An example of this is in the Powder River Basin coal bed
    methane play in my own State of Wyoming. The USGS estimated in
    1995 that the technically recoverable CBM resource in the
    Powder River Basin was 1.11 trillion cubic feet. After
    production increased from less than 6 billion cubic feet in
    1996 to nearly 16 billion cubic feet in 1998, the USGS raised
    the estimate of the technically recoverable CBM resources to
    more than 14 trillion cubic feet. Production has continued to
    expand rapidly, and now exceeds 250 Bcf annually.
        The Wyoming State Geological Survey now estimates that
    technically recoverable CBM resources in the Powder River Basin
    are 25 Tcf--trillion cubic feet. And the USGS will undoubtedly
    raise their estimate for the CBM in the Powder River Basin when
    they revise their own oil and gas assessments.
        While economic considerations are important, an economic
    assessment on the scale proposed by RAND requires economic
    information on the nature and the siting of the deposit at a
    detail that is simply not known from regional assessment.
    Short-term changes in a number of factors such as market price,
    discount rate, and the cost of the capital, can dramatically
    affect an economic assessment. Thus, the economic assessment is
    even more uncertain than the underlying mineral assessment
    based on the geologic and engineering factors alone.
        The Jonah Gas Field in Wyoming is a good illustration of
    the problem with this approach. A small oil company decided to
    explore an area in the Green River Basin which others had
    drilled and abandoned before. The target was an unconventional
    basin-centered gas play of the type that RAND apparently
    believes contain little in the way of viable resources. A field
    producing 700 million cubic feet of natural gas per day has now
    been developed. But Jonah may never have been deemed viable and
    made viable for development if BLM land use decisions had been
    grounded in RAND-type assessments.
        The crux of the debate over the viability of oil and gas
    resource assessments for Federal land policymakers is the use
    of economic viability factors to prejudice where and when
    entrepreneurial explorationists ought to be allowed to search
    for domestic oil and gas. My concern is that an economic
    viability screen, like the one posed by RAND, will be used as
    the basis for denying drilling permits for the underdeveloped
    prospects that could become the next Jonah.
        Will America thwart risk-taking by our domestic industry in
    the pursuit of new types of hydrocarbon reservoirs by basing
    land use planning decisions on government assessments of
    economic oil and gas? I certainly hope not. Government must
    allow dry holes to be drilled by the risk-takers searching for
    the next giant field to replace our declining domestic
    production.
        I believe this was the intent of the 106th Congress which
    asked for the Section 604 inventory which--do not forget--was
    signed into law by Bill Clinton, not George Bush. Joe Skeen and
    I were sponsors of a very similar provision in H.R. 1985, which
    was added to the Energy Policy Act of 2000 by Senator
    Murkowski. Our choice of words, ``resources'' as well as
    ``reserves,'' was intended to ensure that meaningful data would
    be forthcoming from inventory.
        Let's not undercut that effort before it is even completed
    by insisting that only the least risky and most certain
    resources are reported to Congress. We are truly capable of
    determining the merits of the various access restrictions, when
    armed with the facts. If shielded from them, we are merely
    making legislation in the dark--a choice that I hope that we
    could all agree is very ill advised, and not representing the
    best of ourselves for the people.
        [The prepared statement of Ms. Cubin follows:]

      Statement of The Honorable Barbara Cubin, Chairman, Subcommittee on
                          Energy and Mineral Resources

        The Subcommittee meets today to explore the basis for regional oil
    and gas assessment approaches as the Secretary of the Interior, in
    consultation with the Secretaries of Agriculture and Energy, is
    completing an assessment of the oil and gas resources base on all
    lower-48 Federal lands, together with an inventory of the restrictions
    on accessing these resources.
        This action was mandated under Section 604 of the Energy Policy Act
    of 2000. Today's hearing will primarily focus on the Rocky Mountain
    region, where controversy over oil and gas assessment methods has
    recently arisen.
        Congress and the Executive Branch need an objective scientific
    analysis of the oil and gas potential of public lands, together with a
    full understanding of impediments to exploration and development.
    Without such an analysis, we cannot rationally debate options for
    meeting domestic supply requirements for natural gas and oil.
        The Rocky Mountains are a frontier gas province with about 85
    percent of its known gas reserves still in the ground. A National
    Petroleum Council (NPC) assessment in 1999 estimated that 40 percent of
    the natural gas resource in this province is affected by access
    restrictions.
        However, since the NPC study, new land withdrawals for national
    monuments and in roadless areas have further impacted natural gas
    resources in the Rockies. In the latter case, an analysis by the
    Department of Energy has shown that an additional estimated 11.3
    trillion cubic feet (Tcf) of technically recoverable natural gas is
    affected by roadless area withdrawals.
        In February, an independent research group, RAND, released an
    interim report which criticized current oil and gas resource
    assessments of the Rocky Mountains as overly optimistic, primarily
    because they believe too few economic factors are considered. RAND
    concluded that only economically ``viable'' resources should be
    considered in regional oil and gas assessments.
        RAND plans to perform its own analysis of the oil and gas resource
    base in the Intermountain West along with an examination of the
    opportunities and constraints on development. This private study will
    apparently duplicate the Section 604 inventory of oil and gas resources
    in the Rocky Mountain region. The Hewlett Foundation has given RAND a
    $450,000 grant for this work.
        Will the RAND oil and gas assessment improve upon the Section 604
    inventories? Many believe that oil and gas assessment methodology is
    inherently conservative, and more often than not, leads to
    underestimation--rather than overestimation--of recoverable
    hydrocarbons.
        An example of this is the Powder River Basin coalbed methane (CBM)
    play in my own State of Wyoming. The USGS estimated in 1995 that the
    technically recoverable CBM resource in the Powder River Basin was 1.11
    Tcf. After production increased from less than 6 billion cubic feet
    (Bcf) in 1996 to nearly 16 Bcf in 1998, the USGS raised its estimate of
    technically recoverable CBM resources to more than 14 Tcf. Production
    has continued to expand rapidly and now exceeds 250 Bcf annually.
        The Wyoming State Geological Survey now estimates that technically
    recoverable CBM resources in the Powder River Basin are 25 Tcf, and the
    USGS will undoubtedly raise their estimate for CBM in the Powder River
    Basin when they do their next oil and gas assessment.
        While economic considerations are important, an economic assessment
    on the scale proposed by RAND requires economic information on the
    nature and siting of the deposit at a detail that is simply not known
    from a regional assessment. Short term changes in a number of factors
    such as market price, the discount rate and the cost of capital can
    dramatically affect an economic assessment. Thus, the economic
    assessment is even more uncertain than the underlying mineral
    assessment based on geologic and engineering factors alone.
        The Jonah Gas Field in Wyoming is a good illustration of the
    problem with this approach. A small oil company decided to explore an
    area in the Green River Basin which others had drilled and abandoned
    before. The target was an ``unconventional basin-centered'' gas play of
    the type that RAND apparently believes contain little in the way of
    ``viable'' resources. A field producing 700 million cubic feet of
    natural gas per day has now been developed. But Jonah may never have
    been deemed viable and made available for development if BLM land-use
    decisions had been grounded in RAND-type assessments.
        The crux of the debate over the utility of oil and gas resource
    assessments for Federal land policy makers is the use of economic
    viability factors to pre-judge where and when entrepreneurial
    explorationists ought to be allowed to search for domestic oil and gas.
    My concern is that an ``economic viability``screen like the one
    proposed by RAND will be used as the basis for denying drilling permits
    for undeveloped prospects that could become the next Jonah.
        Will America thwart risk-taking by our domestic industry in the
    pursuit of new types of hydrocarbon reservoirs by basing land use
    planning decisions on a government assessment of economic oil and gas?
    I certainly hope not. Government must allow dry holes to be drilled by
    risk-takers searching for the next giant field to replace our declining
    domestic production.
        I believe this was the intent of the 106th Congress which asked for
    the Sec. 604 inventory which--do not forget--was signed into law by
    Bill Clinton, not George W. Bush. Joe Skeen and I were sponsors of a
    very similar provision in H.R. 1985 which was added to the Energy
    Policy Act of 2000 by Sen. Murkowski. Our choice of words, resources as
    well as reserves, was intended to insure that meaningful data would be
    forthcoming from the inventory.
        Let's not undercut that effort before it is even completed by
    insisting that only the least risky and most certain resources are
    reported to Congress. We are fully capable of debating the merits of
    various access restrictions when armed with the facts. If shielded from
    them, we are merely legislating in the dark--a choice I would hope we
    could all agree is ill-advised.
                                     ______

        Ms. Cubin. Before we go take our vote, I would like to
    submit for the record Ranking Member Ron Kind's opening
    statement. It will be available for all of you to read.
        [The prepared statement of Mr. Kind follows:]

    Statement of The Honorable Ron Kind, a Representative in Congress from
                             the State of Wisconsin

        I would like to begin by thanking our Chair, Representative Cubin,
    for scheduling today's oversight hearing on methodologies in oil and
    gas assessments of Federal lands.
        The Hewlett Foundation and the RAND Corporation are also to be
    commended for the invaluable assistance they are providing as Congress
    develops a new national energy policy.
        RAND's work will not replace or supplant the credible assessment
    work done by the Federal Government. Instead, it will enhance and
    increase its value to decision-makers at all levels of government and
    the private sector.
        As I read through the testimony, however, I was struck by the
    confusion that continues to exist on the definitions used to conduct
    resource assessments.
        For instance, Section 604 of Public Law 106-459, also referred to
    as the EPCA study, directs the Secretary of the Interior to identify,
    and I quote, ``the Untied States Geological Survey reserve estimates of
    the oil and gas resources underlying those [onshore Federal] lands.''
        The key phrase here being ``reserve estimates.'' While there is no
    legislative history for this provision of law, according to the
    Department of Energy, and most technical literature, reserves of crude
    oil and natural gas are the estimated quantities that, on a particular
    date, are demonstrated with reasonable certainty by geological and
    engineering data to be recoverable in the future, from known reservoirs
    under existing economic and operating conditions.
        Unlike the EPCA resource assessment being developed by the
    Administration, there is a probability associated with a proved
    reserves estimate. Generally, there is at least a 90 percent
    probability that, at a minimum, the estimated volume of proved reserves
    in the reservoir can be recovered under existing economic and operating
    conditions.
        Therefore, considering that the assessment being conducted by the
    USGS and the BLM will instead a very rough estimate of resource
    deposits at generally low confidence--policy makers will require a more
    detailed set of conclusions as to what portion of these ``technically
    recoverable'' undiscovered resources are of significant size and volume
    to warrant oil and gas leases, and whether economic and environmental
    conditions would justify such action.
        In sum, I believe the RAND study on oil and gas resource assessment
    in the Intermountain West is an improvement on the current assessment
    practices used by the USGS and the BLM.
                                     ______

        Ms. Cubin. We will be back after the last vote, as quickly
    as we can. I don't know how many there are. So we will be gone
    about a half an hour, and then we will be back. Thank you for
    your patience, and we will see you after while.
        [Recess.]
        Ms. Cubin. Well, I thank all of the witnesses for being
    here today with us, and for all of the patience that they have
    been extending our way. We hope to get this moving in a smooth
    fashion now and save your time, because I know we all have
    important things to do.
        I would like to now recognize the first panel of witnesses,
    the Honorable Kathleen Clarke, Director of the Bureau of Land
    Management; accompanied by Mr. Erick--Help me there, Erick--
        Mr. Kaarlela. Kaarlela.
        Ms. Cubin. --Kaarlela, National Office Director of the BLM;
    and Ms. Suzanne Weedman, Energy Resources Program Coordinator,
    with the USGS.
        The Chair now recognizes Director Clarke to testify for 5
    minutes. The timing lights on the table will indicate when your
    time is concluded. All witnesses' statements that are not able
    to be completed orally will be included in the record.
        And reminding the members of the Committee that Committee
    Rule 3(c) imposes a 5-minute limit on questions. The Chairman
    will recognize only members for that amount of time.
        So with that, I ask Ms. Clarke to begin testimony.

        STATEMENT OF KATHLEEN CLARKE, DIRECTOR, BUREAU OF LAND
      MANAGEMENT; ACCOMPANIED BY ERICK KAARLELA, NATIONAL ENERGY
        OFFICE DIRECTOR, BUREAU OF LAND MANAGEMENT; AND SUZANNE
    WEEDMAN, ENERGY RESOURCES PROGRAM COORDINATOR, U.S. GEOLOGICAL
                                 SURVEY

                      STATEMENT OF KATHLEEN CLARKE

        Ms. Clarke. Madam Chairman, members of the Subcommittee,
    thank you for the opportunity to appear here today to discuss
    the ongoing Energy Policy and Conservation Act (EPCA)
    scientific inventory. Madam Chairman, I also want to thank you
    for your leadership and that of your Committee in initiating
    and directing the EPCA effort. Today I am accompanied by Erick
    Kaarlela, who is overseeing the BLM Energy Office; and Suzanne
    Weedman, with USGS.
        In order to provide for our nation's vital and growing
    energy needs, the Department of the Interior, and the BLM in
    particular, are working hard to fulfill our important
    responsibilities in implementing the National Energy Policy as
    designed by the President. Recognizing that portions of the
    Federal onshore lands are off-limits to energy development or
    are open only to limited development, the President's policy
    included a specific recommendation for the Department of the
    Interior to review its land status and lease stipulations
    regarding oil and gas development on Federal lands.
        In addition, the policy directed the Department, consistent
    with existing laws, sound environmental practices, and balanced
    use of other resources, to look for potential modifications to
    foster oil and gas development and production. As part of these
    efforts, the Department also was directed to ensure full and
    meaningful consultation with the public, particularly with
    local communities, while reviewing the information and
    considering possible modifications.
        The ongoing EPCA inventory of oil and gas resources and
    reserves and their access impediments was specifically
    highlighted to be expedited by the involved Federal agencies as
    part of the President's National Energy Policy directives. Each
    agency involved in the EPCA inventory project has specific
    responsibilities associated with the study.
        The BLM is supplying Federal land status and oil and gas
    lease stipulation information from existing resource management
    plans. The Forest Service is supplying lease stipulation
    information from their forest plans. The USGS is contributing
    the undiscovered oil and gas resource data, and is working to
    update these data in support of the EPCA inventory. The
    Department of Energy is contributing proven oil and gas
    reserves data.
        The inter-agency EPCA Steering Committee identified five
    basins within the Rocky Mountain region as the priority
    geographic areas for this study. They are the Powder River
    Basin, the Green River Basin, Uinta/Piceance and San Juan/
    Paradox Basins, and the Montana Thrust Belt. The selection of
    these priority basins was based on industry interest, the USGS
    resource potential rankings, energy reserve rankings, and the
    BLM and Forest Service oil and gas needs analysis. In response
    to the President's National Energy Policy directive to expedite
    the EPCA study, we are performing the analysis for each basin
    concurrently.
        To achieve the data collection and analysis, a contract was
    issued in December of 2001 to a private contractor, Advanced
    Resources International, to perform work for the EPCA study.
    Work on the project is proceeding on schedule, to meet
    Congress' mandate for the completion of the report by the end
    of this year.
        It is important to point out that the EPCA study is not a
    decision document. All of the information gathered as a result
    of the EPCA effort will be analyzed and, as appropriate,
    integrated into BLM's ongoing land use planning efforts, and
    will include extensive public participation. By integrating the
    information into BLM's planning process, additional
    opportunities are available for the public to comment and
    provide recommendations on the specific information and how it
    might be used. In no case will any of these recommendations
    made as a result of the studies preclude full compliance with
    statutory environmental review and protections, including the
    National Environmental Policy Act.
        The BLM will review the EPCA findings regarding land status
    and lease stipulations, and analyze their effects on the
    availability of oil and gas resources for development. Data
    from the EPCA inventory will be used to evaluate potentially
    overly restrictive impediments, to determine if alternative
    methods are available that can still provide comparable and
    sound environmental protection.
        As directed by the President's energy policy, any potential
    modifications must be consistent with the existing laws, with
    sound environmental practice, and the balanced use of other
    resources; and performed with full public participation,
    especially at the local level.
        It should be emphasized that as the BLM works on reviewing
    EPCA information and considers potential land use planning
    modifications, we will continue to abide by FLMPA's principles
    of multiple use, sustained yield, and environmental protection.
    These are standards to which the BLM is completely committed.
    The BLM will only consider opportunities to increase access to
    oil and gas resources while still maintaining multiple-use
    values, including surface and subsurface resource values, and
    appropriate environmental protection.
        The BLM is committed to fulfilling its role in diversifying
    America's energy supplies and ensuring the environmentally
    responsible production and distribution of our nation's energy
    resources. The EPCA inventory is a key component of our efforts
    to fulfill these responsibilities and to implement the
    President's National Energy Policy, in order to continue to
    provide a secure energy future for our country.
        Thank you for the opportunity to testify.
        [The prepared statement of Ms. Clarke follows:]

    Statement of Kathleen Clarke, Director, Bureau of Land Management, U.S.
                           Department of the Interior

        Madam Chairman and Members of the Subcommittee, thank you for the
    opportunity to appear here today to discuss oil and gas resource
    assessments, and the Energy Policy and Conservation Act (EPCA) study,
    in particular. I want to thank you, Madam Chairman, for your leadership
    as well as that of your Subcommittee, in directing the EPCA scientific
    inventory.
        I am accompanied by Erick Kaarlela, the Bureau of Land Management's
    (BLM's) National Energy Office Director and Suzanne Weedman, the U.S.
    Geological Survey's Energy Resources Program Coordinator. Erick and
    Suzanne have been involved with the EPCA effort since its inception and
    they are here to assist in answering your questions.

                     NATIONAL ENERGY POLICY IMPLEMENTATION

        As this Subcommittee knows well, the nation's Federal lands contain
    a large portion of U.S. energy resources. In order to provide for our
    nation's vital and growing energy needs, the Department of the
    Interior, and the BLM in particular, are working hard to fulfill our
    important responsibilities in implementing the President's National
    Energy Policy. Over a quarter of the President's energy policy
    recommendations specifically relate to one or more of the BLM's energy,
    mineral, and planning-related responsibilities. To systematically carry
    out the President's policy and goals, the BLM has identified more than
    40 tasks to facilitate domestic production and transmission of both
    renewable and non-renewable energy resources, while ensuring
    environmental protection.
        Recognizing that portions of Federal onshore lands are off-limits
    to energy development or are open only to limited development, the
    President's policy included a specific recommendation for the
    Department of the Interior to review its land status and lease
    stipulations regarding oil and gas development on Federal lands. In
    addition, the policy directed the Department--consistent with existing
    laws, sound environmental practices, and balanced use of other
    resources--to look for potential modifications to foster oil and gas
    development and production. As part of these efforts, the Department
    also was directed to ensure full and meaningful consultation with the
    public, particularly with local communities, while reviewing the
    information and considering possible modifications. The ongoing EPCA
    inventory of oil and gas resources and reserves and their access
    impediments was specifically highlighted to be expedited by the
    involved Federal agencies as part of the President's National Energy
    Policy directives.

                                   EPCA STUDY

        Since enactment of the Energy Policy and Conservation Act
    Reauthorization of 2000, the Department of the Interior has been
    working expeditiously to complete the EPCA study requirements and
    comply with the Congressional directive. The BLM, as lead agency of the
    effort, is working closely with the U.S. Geological Survey (USGS), U.S.
    Forest Service (USFS), the Department of Energy (DOE), and DOE's Energy
    Information Administration (EIA), to produce a scientific inventory of
    the oil and gas resources and reserves underlying onshore Federal lands
    and to identify the extent and nature of any restrictions or
    impediments to their development. An interagency EPCA Steering
    Committee composed of senior staff of each agency was created to ensure
    an effective process for close coordination and collaboration between
    the participating agencies.

                                EPCA METHODOLOGY

    Scope/Outreach
        Early discussions among the interagency EPCA Steering Committee
    focused on the scope of the study. This included identifying current
    information and ongoing efforts, integrating the various agency roles
    and functions, developing common approaches and consistent methods for
    reserve and resource determination, and identifying the top priority
    geographic areas for study and analysis. The group also made an initial
    inventory of the nation's oil and gas resources and reserves on Federal
    lands and determined those basins of greatest oil and gas development
    potential for further analysis.
        An important aspect of the initial development of the EPCA project
    was gathering feedback from interested parties. As the EPCA effort
    progressed, meetings were held with the oil and gas industry, the
    environmental community, and Congressional staff regarding the initial
    efforts of the project and the plan for completing the inventory.

    Agency Responsibilities & Inventory Approach
        Each agency involved in the EPCA inventory project has specific
    responsibilities associated with the study. The BLM is supplying
    Federal land status and oil and gas lease stipulation information from
    existing Resource Management Plans. The USFS is supplying lease
    stipulation information from their Forest Plans. The USGS is
    contributing the undiscovered oil and gas resource data and is working
    to update these data in support of the EPCA inventory. The EIA,
    meanwhile, is contributing proven oil and gas reserves data.
        The methodology adopted was first to have the USGS and EIA utilize
    their expertise in resource and reserve estimation in making the
    required initial inventory of resources. Next, the BLM and USFS would
    conduct inventories of the various impediments to and restrictions on
    development on Federal lands. Using the information provided through
    these first two steps, and utilizing Geographical Information Systems
    and other advanced computer technologies, the group is able to map the
    amount of resources and reserves that are associated with the
    identified restrictions and impediments. These areas then are
    characterized according to the degree to which the restrictions and
    impediments may affect development.

    Geographic Priorities
        The interagency EPCA Steering Committee identified five basins
    within the Rocky Mountain Region as the priority geographic areas for
    study. They are the Powder River, Green River, Uinta/Piceance, and San
    Juan/Paradox Basins, and the Montana Thrust Belt. The selection of
    these priority basin areas was based on industry interest, USGS
    resource potential ranking, EIA reserve ranking, and the BLM and USFS
    oil and gas need analysis. In response to the President's National
    Energy Policy directive to expedite the EPCA study, we decided to
    perform the analysis for each basin concurrently.

    Contractor Involvement/Schedule
        To achieve the data collection and analysis, a contract was issued
    in December 2001 to a private contractor, Advanced Resources
    International (ARI), to perform required work for the EPCA study. ARI
    also brought in Premier Data Services as a subcontractor to aid in the
    data collection phase. Work on the EPCA project is proceeding on
    schedule to meet Congress' mandate for completion of the EPCA report by
    the end of this year.

                       USE OF EPCA INVENTORY INFORMATION

        It is important to point out that the EPCA study is not a
    ``decision'' document. All information gathered as a result of the EPCA
    effort will be analyzed and, as appropriate, integrated into the BLM's
    ongoing land use planning efforts, which include extensive public
    participation. By integrating the information into the BLM's planning
    process, additional opportunities are available for the public to
    provide comments and recommendations on the specific application of the
    information. In no case will any recommendations made as a result of
    these studies preclude full compliance with statutory environmental
    review and protections, including the National Environmental Policy
    Act.
        As the information becomes available from the EPCA inventory, the
    BLM plans to analyze the data for opportunities to improve the Bureau's
    management of the oil and gas resources on Federal lands. Direction
    will be provided to BLM Field Offices on how best to apply the EPCA
    information to facilitate environmentally-responsible development of
    oil and gas resources, both in the BLM's land-use planning process and
    the daily management of the public lands and its resources. This
    analysis and the development and consideration of potential
    modifications is one of the BLM's critical tasks in implementing the
    President's National Energy Policy directives.
        It should be emphasized that as the BLM works on reviewing the EPCA
    information and considers potential land-use planning modifications, we
    will continue to abide by the Federal Land Management and Policy Act's
    principles of multiple-use, sustained yield, and environmental
    protection. These are standards to which the BLM is completely
    committed. The BLM will only consider opportunities to increase access
    to oil and gas resources while still maintaining multiple-use values,
    including surface and subsurface resource values (such as aquifers and
    other minerals), and appropriate environmental protection.
        The BLM will review the EPCA inventory's findings regarding land
    status and lease stipulations, and analyze their effects on the
    availability of oil and gas resources for development. Data from the
    EPCA inventory will be used to evaluate potentially overly-restrictive
    impediments to determine if alternative methods are available that can
    still provide comparable and sound environmental protections. As
    directed by the President's National Energy Policy, any potential
    modifications must be consistent with existing laws, good environmental
    practice, the balanced use of the other resources and performed with
    full public participation, especially at the local level.

    Public Outreach
        As mentioned, public participation is a critical part of the EPCA
    project. In March, the BLM held a productive National Energy Plan
    Outreach Meeting in Denver, Colorado, to gather input from all
    interested parties on the more than 40 tasks associated with the BLM's
    implementation of the President's National Energy Policy. The outreach
    meeting was well-attended by representatives from environmental groups,
    industry, the general public, as well as State and other Federal
    agencies.
        As part of the outreach meeting, a presentation on the EPCA study
    and use of the EPCA inventory was conducted. The BLM requested specific
    comments from participants on how to make the EPCA project responsive
    to the needs of our stakeholders. The BLM is currently reviewing and
    evaluating comments for possible application to its efforts to
    implement the President's National Energy Policy. The BLM is planning
    additional outreach meetings to solicit further comments and
    recommendations for consideration related to its implementation of the
    President's National Energy Policy, including its efforts related to
    the EPCA project.

                                   CONCLUSION

        The BLM is committed to fulfilling its role in diversifying
    America's energy supplies and ensuring the environmentally-responsible
    production and distribution of our nation's energy resources. The EPCA
    inventory project is a key component in our efforts to fulfill these
    responsibilities and to implement the President's National Energy
    Policy in order to continue to provide a secure energy future for our
    country.
        Madam Chairman, thank you for the opportunity to testify before you
    today. We welcome any questions the Subcommittee may have.
                                     ______

        [Responses to questions submitted for the record by Ms.
    Clarke follow:]

                 Responses to Subcommittee Follow-Up Questions

         Oversight Hearing on Oil & Gas Resource Assessment Methodology

        House Resources Subcommittee on Energy and Mineral Resources

                                 April 18, 2002

    Questions from the Majority

    1. A lot has been said about including non-federal lands in EPCA oil
            and gas assessments. Isn't the starting point for any regional
            assessment an assessment of all land within a region regardless
            of ownership?
        The EPCA study utilizes data from U.S. Geological Survey's (USGS)
    1995 National Oil and Gas Assessment, which covers all lands regardless
    of ownership, as a starting point. As a part of the analysis, the
    resources were calculated for Federal lands, as the statute requires,
    and for non-Federal lands as well. The non-Federal portion will be
    displayed in the final EPCA report as surface acreage and as an
    aggregate amount of resource for each of the five study areas so that
    the relative contribution of non-Federal lands within the inventory
    area can be compared to that of the Federal lands.

    2. In your testimony, you briefly describe how BLM will use the results
            of EPCA Phase 1. Would you elaborate on how EPCA will be
            implemented?
        As the results of the EPCA study become available, the information
    will be provided to BLM and US Forest Service managers, resource
    specialists, and technical experts for their review and consideration.
    The EPCA study will provide a sound scientific base from which these
    land management agencies can analyze the various options regarding oil
    and gas development on public lands. This information will supplement
    existing data being used in the preparation of land use plans, and it
    will be considered for current land use decisions and approvals. The
    BLM will also use the EPCA inventory as a basis to reassess the
    appropriateness and effectiveness of our leasing and operational
    decisions, and the priority areas for such a reassessment.
        Specifically, the BLM will use the EPCA information following
    Federal Land Policy and Management Act's (FLPMA) multiple-use mandate
    for making balanced decisions regarding land availability for oil and
    gas development in an environmentally-sound manner. Additionally, we
    will use the information to make decisions on appropriate and needed
    stipulation waivers and modifications as provided by regulations and
    consistent with existing land use plans. The EPCA study will provide
    both the public and the Federal decision-makers with substantive
    information about the oil and gas resources.

    3. Are you including split estate lands, in which the Federal
            Government owns the minerals and the surface is private, and
            private lands within the study? How does BLM treat split estate
            lands when an Application for Permit to Drill is received from
            an oil and gas operator?
        Split estate lands--where the oil and gas mineral estate is
    Federally-owned regardless of surface ownership--are being included in
    the EPCA study. Split estate lands are analyzed in the same manner as
    Federally-owned surface lands in the inventory.
        Oil and gas operations on Federal split estate resources are
    subject to the same environmental laws and regulations that are
    applicable to Federally-owned surface lands. The permitting process
    also is generally the same. However, regarding private surface
    involvement, an operator is required to submit as part of its Surface
    Use Plan one of the following--a copy of the signed surface owner
    agreement between the operator and the surface owner; a certification
    by the operator that an agreement was reached with the surface owner;
    or a certification of compliance with Federal regulations (43 CFR 3814)
    with respect to bonding requirements for use of the surface. In
    addition, the BLM requests that operators, prior to onsite inspections,
    contact surface owners and notify them of their proposed activity. In
    particular, the BLM asks operators to invite surface owners to on-site
    inspections. Operators must incorporate the landowner concerns or
    desires for mitigation, existing road use, and abandonment into the
    Surface Use Plan of the APD.

    4. Let me ask a hypothetical question. Much of the controversy over the
            EPCA studies is focused on the technically- versus
            economically-recoverable oil and gas resources. Would BLM be
            able to complete the Federal lands analysis without trying to
            quantify oil and gas resource estimates, in other words, only
            generally determine oil and gas potential, such as high, medium
            and low? Would the results of such a study provide meaningful
            conclusions that could be used by BLM in making informed land
            management decisions?
        In order to determine oil and gas potential on a consistent basis,
    the same data would have to be used as was employed by the USGS for its
    1995 National Oil and Gas Assessment. No maps or studies are currently
    available that classify the lands within the United States on a
    consistent basis as to their ``high,'' ``medium,'' or ``low'' potential
    for oil and gas. We believe that stacking the resource plays and
    quantifying the resource volumes, as will be shown by maps in the
    completed inventory, will adequately categorize the oil and gas
    potential of the lands within the study areas.
        Making judgments as to classifying lands as having ``high,''
    ``medium,'' or ``low'' potential would entail the evaluation of widely
    varying opinions based on speculative economic assumptions. The
    approach being used in the EPCA inventory responds to the
    Congressionally-mandated requirement and we feel will be extremely
    valuable in making informed Federal land management decisions.

    5. Some have criticized the NPC study as biased towards the oil
            industry. Does the USGS seek industry input when making their
            oil and gas assessments? Does the participation of the industry
            improve an oil and gas assessment?
        Until 1989, the USGS conducted oil and gas resource assessments
    alone, without much consultation with private industry. However, after
    a review by the National Research Council, the USGS was advised to seek
    input and review of its methodology from industry. The agency now does
    that. Most of the USGS information about past oil and gas production
    today comes from commercial databases, derived from industry sources,
    and from the Energy Information Administration. Additionally, USGS
    sometimes receives both public and proprietary data from private
    industry. While USGS does acquire data and information from private
    industry, the resource assessments are conducted solely by USGS
    geologists and engineers.
        USGS resource methodology has been reviewed and approved by the
    Committee of Resource Evaluation of the American Association of
    Petroleum Geologists, a professional society of academic, Federal, and
    private industry petroleum geologists. No one from industry or from
    another agency is allowed to participate in USGS assessment meetings to
    avoid any conflicts of interest, or the perception of conflicts of
    interest. Having industry review USGS methodology has generally
    improved industry's respect for and acceptance of USGS assessment
    results. Obtaining more detailed geologic information from industry
    also has improved the quality of the USGS assessments.

    6. Is the 1998 USGS economic evaluation (Attanasi) of the 1995 national
            assessment still valid?
        The 1998 USGS economic evaluation of the1995 National Oil and Gas
    Assessment is slightly out of date with respect to both natural gas
    resource estimates and to economic assumptions. The resource data have
    a 1992-1994 vintage and the USGS is currently in the process of
    updating these resource estimates. Also, the costs of finding,
    developing, and producing oil and gas, as well as estimates of the
    typical success rates, are taken from the same time period. Clearly,
    many advances in exploration for natural gas, especially unconventional
    gas, have taken place since the mid-1990s.
        Results of the USGS update of the resource assessment completed in
    1995 should be available over the next few years. When they are
    complete, the USGS will conduct an economic evaluation of the results.

    Questions from the Minority

    1. Director Clarke, Section 604 of EPCA directs the Secretary to
            identify the ``reserve estimate'' of the onshore oil and gas
            resource. Yet, USGS and BLM have identified, instead, the
            undiscovered, technically recoverable resource. This is a
            highly speculative and broad category. Additionally, it is not
            consistent with the language of the law.
        Basically, using the undiscovered technically recoverable
    classification will yield a best guess given the available data and
    will also produce maps covering a much wider area.
        In contrast, using reserve estimates of oil and gas--or even the
    economically recoverable resources would provide a greater certainty
    that such lands contain oil and gas in quantities that will warrant
    development.
        Why then would you conclude that Congress intended that the
    assessment be based on the highly speculative, broad category of
    undiscovered, technically recoverable resources, instead of
    economically recoverable?
        The intent of the interagency EPCA Steering Committee--consisting
    of representatives of the BLM, USGS, USFS, and DOE--has been, and
    continues to be, to provide the Congress with the information that was
    requested in the EPCA statute. When the Steering Committee first met to
    begin discussions of implementing the requirements of Section 604 of
    EPCA, we were concerned by the law's wording regarding ``USGS reserve
    estimates of oil and gas resources'' and ``the extent and nature of any
    restrictions or impediments to the development of such resources.'' The
    law's language is not consistent with USGS terminology for ``reserves''
    and ``resources.'' The EPCA Steering Committee interpreted the language
    to mean that Congress was interested in a study of both reserves and
    resources. To ensure that Congress understood the approach that the
    EPCA Steering Committee was undertaking to comply with the law, the
    group met with majority and minority staff of the Senate and House
    resource committees to describe the group's efforts.
        The Steering Committee is including both proved reserves from the
    Energy Information Administration, and undiscovered oil and gas
    resources from the USGS. Providing both reserves and resources will
    give the Congress and the Administration the full suite of both known
    and potential oil and gas accumulations under Federal Lands in the
    study areas.
        The USGS does not consider its resource assessments to be highly
    speculative, but the best estimates of resource potential available,
    ahead of exploration and drilling. USGS resource assessments have
    guided energy policies for several decades, and provide the BLM and
    Forest Service with the best information to anticipate energy industry
    interest for the lands that they manage.
        If the EPCA study included just oil and gas reserves, then the USGS
    would not have had a role in the study. The resulting GIS mapping would
    have the locations of the few known reserves, which are under land that
    currently has full access, and no information about future potential
    land use conflicts would be available.

    2. Once the identification of oil and gas resources is complete,
            overlays indicating where areas are closed or restricted will
            be superimposed. What will you do then? Will policies be
            adjusted to comply with President Bush's Executive Order to
            facilitate oil and gas development? If so, how will this occur?
        The President's National Energy Policy directs the Secretary of
    Interior to examine and review land status and lease stipulations to
    Federal oil and gas leasing. In addition, the Secretary, consistent
    with existing laws and sound environmental practices, was directed to
    look for opportunities to modify them such that they foster oil and gas
    development and production. This is to be accomplished with full and
    meaningful consultation with the public, particularly with local
    individuals through the land use planning process and other project-
    specific NEPA analysis. In addition, a Presidential Executive Order
    directs all Federal agencies to take appropriate actions to expedite
    projects that will increase the production, transmission, or
    conservation of energy
        By considering the EPCA findings in the Bureau's ongoing land use
    planning efforts, the Bureau will be complying with the President's
    directives. All information gathered as a result of the EPCA effort
    will be analyzed and, as appropriate, integrated into the BLM's ongoing
    land use planning efforts, which includes extensive opportunities for
    public participation and comment. The public will have the opportunity
    to provide specific comments on any changes that arise in the resource
    management plans or amendments. It should be emphasized that in no case
    will any recommendations made as a result of these studies preclude
    full compliance with statutory environmental review and protections,
    including the National Environmental Policy Act.

    3. What changes have been made to the DOI methodology since you
            released the Green River Study last year? In other words, are
            you now factoring known reserves into the assessment?
        The Green River Study was led by and released by the Department of
    Energy and is based on the 1999 National Petroleum Council study of
    natural gas in the Rocky Mountain Region. The BLM and USGS provided
    information and assistance for that study. The purpose of the Green
    River study was to examine in detail the restrictions to Federal
    natural gas development within the Greater Green River Basin of Wyoming
    and Colorado.
        Unlike the Green River Study, the EPCA study focuses on both oil
    and natural gas; includes resources under split estate lands; and
    incorporates further analysis of agency experts on the impacts of
    various land use restrictions. Specific criteria and factors were
    developed by the Interagency Steering Committee for the EPCA study
    which are more specific to the needs of the Federal land management
    agencies. Some of the variations include EPCA's analysis of individual
    oil and gas plays, rather than allocating gas resources on a township
    basis, and EPCA's use of only USGS resources estimates, rather than
    incorporating data from non-USGS sources.
        Furthermore, EPCA requires the Secretary to conduct an inventory
    using both oil and gas reserves and oil and gas resource estimates. The
    interagency EPCA Steering Committee includes the Energy Department's
    Energy Information Administration (EIA), which is responsible for
    maintaining information on oil and gas reserves for the United States.
    EIA's oil and gas reserve information is being incorporated into the
    EPCA inventory.

    4. One of the criticisms of the assessment is that it is producing a
            biased, or skewed set of data--that the assessment will
            erroneously foster the misconception that there is potentially
            more oil and gas in areas, such as ``roadless areas'' that is
            not being developed due to access restrictions. How do you
            respond to this criticism?
        The BLM, USGS, USFS and DOE are complying with the specific
    provisions of EPCA by using peer-reviewed assessment standards, all
    available geologic information, and statistical methods for the
    distribution of the undiscovered resource estimates. In addition, the
    interagency EPCA Steering Committee is collecting existing, publicly-
    available information on restrictions and impediments from the BLM's
    and USFS's land use management plans. It is the intention of the
    agencies to present this information clearly and objectively, and by
    using a scientific and judicious approach, to avoid misconceptions.

    5. Will the assessment take State-owned, private, and split estate
            lands into account? If so, how?
        Split estate lands--where the oil and gas mineral estate is
    Federally-owned regardless of surface ownership--are being included in
    the EPCA study. Split estate lands are analyzed in the same manner as
    Federally-owned surface lands in the inventory.
        As a part of the EPCA analysis, the resources are being calculated
    for Federal lands, as the statute requires, and for non-Federal lands
    as well. The non-Federal portion is displayed in the report as surface
    acreage and as an aggregate amount of resource for each of the five
    study areas so that the relative contribution of non-Federal lands
    within the inventory area can be compared to that of the Federal lands.

    6. How will the assessment factor slant drilling capability into
            account?
        The EPCA inventory factors in slant drilling capability by using
    the concept of an ``extended drilling zone'' (EDZ). Resources located
    beyond this EDZ are assumed to not be technically recoverable. The BLM
    and Forest Service field personnel were consulted to determine the size
    of the EDZ, which varies by jurisdiction. The EDZ is generally a
    function of the depth to the drilling objective--the deeper the
    objective, the larger the EDZ. The effect of the extended drilling zone
    in the analysis is to remove an area of land from the perimeter of
    areas where surface occupancy is prohibited. The width of this area
    removed through analytical processing is determined by Federal
    jurisdiction. The area removed then defaults to the access category
    that would otherwise apply in the absence of the no surface occupancy
    stipulation. The net effect is that the underlying resource is no
    longer considered inaccessible even though the surface cannot be
    occupied by drilling equipment.
                                     ______

        Ms. Cubin. Thank you very much. I guess I will start the
    questioning myself. I observed when I was reading the testimony
    last night of the second panel that much of it will be based on
    assessments by the USGS assesment in 1995, the National
    Petroleum Council in 1999, and Advanced Resources International
    Prototype EPCA study of the greater Green Basin in 2001.
        Can you briefly explain the similarities and the
    differences between these type assessments?
        Ms. Clarke. I am going to invite Mr. Kaarlela, who has led
    this study, to address that question.
        Mr. Kaarlela. Yes, Madam Chairman. Perhaps the best way to
    approach this is to just give a small historic summary of how
    the various studies took place. The National Petroleum Council
    study in 1999 was looking at natural gas, demand for natural
    gas in the future, and where it might come from and how it
    might be transported. And they looked at both domestic and non-
    domestic sources of natural gas, as well as looking at onshore
    and offshore sources within the United States.
        Specific to our discussion here, they found or determined
    that the Rocky Mountain region of the United States was a major
    source of future gas for the United States onshore. When they
    looked at that area, they looked at basically three sample
    areas, and they made extrapolations with regard to what
    restrictions and impediments would do to that supply of natural
    gas, or may do to that supply of natural gas.
        To have somebody do a further analysis of these areas to
    get a better handle of the natural gas in the areas and their
    specific restrictions and impediments, DOE followed up with
    that in 2000, and did their Green River study; again, of just
    natural gas. And they did a little more detailed analysis of
    restrictions and impediments, establishing a basic criteria or
    hierarchy of types of restriction, and so on.
        At the same time, of course, EPCA was passed. And we began
    looking at what we should do. And since it appeared to us that
    our study under the EPCA requirement was very similar to what
    the National Petroleum Council had done and DOE had done, we
    would use those as an example--a model, if you will--and try to
    improve upon it, and come up with what we would have to do.
        Now, our study also, of course, by requirement of the law,
    includes oil; not just natural gas. So we are doing oil and
    natural gas. That is a major difference between the studies.
        Additionally, we are required to use the U.S. Geological
    Survey's estimates of resources. The other studies did use some
    of that information, but they also combined it with other
    information from private sources and other sources. So we are
    using exclusively U.S. Geological resources estimate
    information.
        Most of the other differences that we came up with, or a
    good deal of them, were a response to criticisms that came out
    as a result of the Department of Energy's Green River study. We
    tried to take those criticisms into consideration and see,
    where those criticisms were warranted, if we could improve upon
    the way that they looked at that.
        And we made several corrections of those criticisms; such
    as there was criticism about using a sensitivity case rather
    than a base case, that didn't take into consideration such
    sensitivity factors as the ability to get to resources that may
    not be available directly from the surface but can be reached
    from directional drilling. And there were other considerations
    that concerned whether or not we should be considering split-
    estate lands, lands where the Federal Government had the sub-
    surface and the surface was owned by somebody else. We decided
    to include those in our report.
        There were considerations about whether or not the extent
    of the area of study should be based on political boundaries,
    such as townships; or should it be based on actual provinces or
    limits of the geological basins. We decided to go with the
    limits of the geological basins.
        Those are the main differences that we had in our study.
    One, ours was going to be oil and gas, not just gas; two, we
    were taking the Geological Survey's estimates as our main base;
    three, we were adding all the sensitivity factors into
    consideration under our study on EPCA.
        Ms. Cubin. My time has elapsed. Seeing no minority member
    here right now, I will yield the floor to Representative Otter
    for 5 minutes.
        Mr. Otter. Thank you, Madam Chairman.
        And thank you to the panel for being here. Ms. Clarke, I,
    too, read most of the testimony that we are going to hear today
    in a future panel before us today. There is an assessment on
    the viability of the resource based upon exploration and
    production costs--that is, those costs getting the resource to
    the wellhead; infrastructure and transportation costs--those in
    getting it to the marketplace; potential environmental impacts.
    And one other additional one that came through some of the
    testimony would be, obviously, the economic viability has to do
    with the future price that the market is going to provide.
        Does the agency have any scheme or any formula at which
    they also assess future market price? And if so, for the
    viability of the production and the exploration, what is that
    formula? And how is that assessment made? What goes into that
    assessment?
        Ms. Clarke. Well, we do not get into trying to assess
    economic viability. We feel that that is a role for the
    marketplace and for industry to pursue. And so what we are
    interested in is having good science, and making sure that data
    is available on technically recoverable resources.
        And we feel like that is the role and responsibility that
    we have. We believe that then whoever is interested in pursuing
    the potential and the commercial value of that resource needs
    to do their studies and understand the markets. And certainly,
    those values change over time dramatically. Technology changes
    over time dramatically. And so I don't think it would be
    prudent of us to get into that business.
        Mr. Otter. I understand that. But we are talking about a
    public resource. And I certainly agree with that assessment. We
    are talking about a public resource, potentially on public
    lands. And because of that, we also probably need to assess--I
    am sure the agency does assess--the potential of success. And
    part of that success depends upon what the marketplace in the
    future is going to have for the crude oil.
        And if the agency doesn't now do that--For instance, even a
    private landowner, if I were selling a piece of land to a
    potential developer, one of the things that I would want to
    know about is if he is going to build a supermarket there; if
    he or they are going to build a housing project. And if it is a
    housing project, is it going to be HUD housing, or is it going
    to be low-cost housing, or is it going to be more expensive
    housing?
        I think one of the things that we need in order to assess
    the potential development of this is the economic viability;
    just as I may or may not sell my land to a developer, depending
    upon what they are going to do with it, in terms of what the
    economic viability is. Because I want to know that they can pay
    for it. And I want to know, if they mess it up, that they can
    clean it up. And I want to know that, if there is something
    that goes awry, they are prepared to stand behind it. And the
    economic viability of that project is going to suggest to me
    whether or not they are going to have the available resources
    to repair the damage.
        Ms. Clarke. Certainly, as we contemplate leasing, there is
    an onerous process that those potential lessees and permitees
    have to go through to demonstrate that they are capable of
    performance and of bonding, of mitigation, of reclamation. And
    in the land use process, we consider economic issues, both in
    the land management plans and in use authorization.
        But we do not have a study process that at this time
    extends into that arena. It becomes part and parcel when it
    becomes of significance, because we are today dealing with an
    action or an activity. So we will have that information
    available, but it is not part of an ongoing study and an
    overall view of the world. It will become site-specific and
    activity-specific.
        Mr. Otter. When you are involved in the process of
    establishing a potential exploration and the establishment of a
    wellhead, does that also include the second ingredient that I
    talked about? And that is portability: Are we going to be able
    to get it from the wellhead to wherever we need to get it to,
    so that it can be refined or it can be produced into value-
    added and usable products for the consumers? And does that
    include the pipeline?
        So are those assessments relative to variable cost,
    relative to environmental cost and marketplace cost, also
    assessed?
        Ms. Clarke. I know that we do assessments that when someone
    comes forward with a plan they have to consider roads,
    corridors, transportation, distribution. But I don't know if it
    is all done in the same planning effort. Let me ask Erick to
    speak to that.
        Mr. Kaarlela. In our planning effort, we have a process
    called ``reasonable foreseeable development.'' And we don't
    know at that time, of course, whether or not that is what any
    particular operator may pursue; but we do go through and make a
    projection as to what we think are the types of development
    that will occur. And we try and figure out where the pipelines
    might go, where the wells might be drilled. And we use this as
    a basis for further consideration on the type of stipulations,
    type of resource conflicts, that might occur.
        Again, it is kind of our best guess, because no one quite
    knows who is going to try what type of technique. But that is
    what we use right now.
        Mr. Otter. Madam Chairman, may I inquire of the Chair? We
    are going to have a second round?
        Ms. Cubin. You can take it right now, if you wish.
        Mr. Otter. Thank you very much, Madam Chairman.
        We are talking about the Rocky Mountain West here. Would
    anybody on the panel be able to pinpoint for me the closest
    refinery to the Rocky Mountain West?
        Mr. Kaarlela. I know there are refineries that are
    extensive throughout the West. Are you talking the closest to a
    particular basin or something?
        Mr. Otter. Well, no. Excuse me, maybe my question wasn't
    clear. You know, it is difficult to think that we would be part
    of setting people up for failure. And so if they are going to
    drill an oil well in an extremely remote place, where do we
    take either the gas or where do we take the oil, so that we can
    fracture the gas and, if it is high-sulphur gas, we can split
    it, take the sulphur off it, make it sweet gas, and then
    marketable?
        And what my question goes to, if we are talking about in
    the Rocky Mountain West here, do we have the refinery or
    cracking facilities, if it is natural gas, so that we are not
    going to have to ship it to Mexico?
        Ms. Clarke. Right.
        Mr. Otter. That is where my question is coming from.
        Ms. Clarke. We will have to get back to you.
        Mr. Otter. OK.
        Ms. Cubin. Will the gentleman yield?
        Mr. Otter. The gentleman yields.
        Ms. Cubin. I don't know what volume you are speaking of,
    but certainly there are refineries in the Rocky Mountain
    region. There are several in Wyoming; albeit they are
    relatively small refineries. But there is a large refinery in
    Colorado.
        Mr. Otter. OK.
        Ms. Cubin. And so, yes, certainly there are refineries in
    the area. Again, how much of the need they will be able to
    fill, I can't answer that. But, yes, there is room for some of
    the gas discovered to be processed.
        Mr. Otter. Thank you, Madam Chairman. I am claiming back my
    time.
        The reason I am asking this question is because I want to
    revisit much of the debate that we have had about other areas
    of exploration. And part of that problem is, is it more
    economic to build a refinery, or is it more economic to build
    the pipeline?
        And if we don't already have in place facilities large
    enough to handle the potential volumes, then what is the
    economic opportunity that we have to look at in order to
    enlarge a present facility, or build a new one? And so that is
    where my question goes to.
        And I would hope in some of these assessments on economic
    viability that we would put in an equation that basically
    speaks to the question of: How do we get the resource out of
    the ground and into marketable products?
        Ms. Clarke. Right.
        Mr. Otter. I thank you, Madam Chairman.
        Ms. Cubin. I thank you, too, Madam Secretary.
        Ms. Clarke. Thank you.
        Ms. Cubin. And we really appreciate your time here. I am
    sure that some of the members who are not here will have more
    questions for you later on. So if they will submit them to you
    in the next--what, 4 days? Ten days.
        Ms. Clarke. OK.
        Ms. Cubin. We would appreciate a response. And we thank you
    very much for your testimony.
        Ms. Clarke. Thank you.
        Ms. Cubin. And we look forward to seeing you much more
    frequently. And I am sure it will be a good interchange.
        Ms. Clarke. Thank you very much.
        Ms. Cubin. Thank you.
        The next panel to come forward will be Debra Knopman,
    Ph.D., Senior Engineer and Associate Director of RAND Research
    and Development, Science and Technology; Charles Mankin, Ph.D.,
    State Geologist of Oklahoma, testifying on behalf of American
    Association of Petroleum Geologists; Peter Morton, Ph.D.,
    Resource Economist, The Wilderness Society; Ray Seegmiller,
    Chairman, President, and Chief Executive Officer, testifying on
    behalf of Cabot Oil and Gas Corporation, and the Domestic
    Petroleum Council.
        I see you are finding your way to the table. If we are
    ready to begin now the second panel, the Chairman now
    recognizes Dr. Knopman to testify for 5 minutes. The timing
    lights are on, on the table, and they will indicate when your
    testimony should come to a conclusion. All witness statements
    will be submitted for the hearing record. Thank you.
        So at this time, I would like to call on Ms. Knopman to
    testify.
        Ms. Knopman. It is ``Dr. Knopman.'' Thank you, Madam
    Chairman, for the opportunity to testify.
        Ms. Cubin. Excuse me. Doctor. Excuse me.
        Ms. Knopman. No problem.

      STATEMENT OF DEBRA KNOPMAN, PH.D., ASSOCIATE DIRECTOR, RAND
                         SCIENCE AND TECHNOLOGY

        Ms. Knopman. Thank you, Madam Chairman, for the opportunity
    to testify before your Subcommittee about methods of assessing
    oil and gas resources. I am a senior engineer at RAND, and also
    a member of the study team for RAND's recently released interim
    report on ``Assessing Gas and Oil Resources in the
    Intermountain West,'' as well as a related summary paper.
        These publications are interim products from a project that
    we expect to complete this summer. Research, as has been noted
    by you, is funded by the William and Flora Hewlett Foundation.
        Here with me today are two of my RAND co-authors, Dr. Mark
    Bernstein and Dr. Tom LaTourette. I would also like to note at
    this time that the views expressed here are my own and do not,
    nor should they be taken to reflect those of either RAND or any
    sponsors of its research.
        RAND does not have an institutional position on whether oil
    and gas exploration and production should proceed on currently
    restricted Federal lands. This is a complex policy question
    with several competing considerations, including the nation's
    need for long-term, reliable, and clean energy supplies.
    Rather, our interest is in the quality, relevance, and
    transparency of technical information that surrounds the public
    debate on future development.
        We are also interested in encouraging a broader discussion
    about constraints on exploration and production beyond that of
    access restrictions applied to Federal lands. We believe that
    such a discussion would contribute significantly to the debate
    on national energy and land management policies.
        Our main point can be summarized as follows: The debate
    over access to gas and oil resources on Federally managed lands
    in the Intermountain West would benefit from an improved
    understanding of how much resource might actually be developed,
    and at what cost.
        Our study recommends developing and publicly reporting
    estimates of viable resources in the region--Federal and non-
    Federal lands--using a step-wise approach that incorporates a
    set of economic and environmental criteria. These criteria
    include exploration and production costs, infrastructure and
    transportation costs, and environmental impacts. We also
    recommend ways in which the ongoing BLM basin-specific studies
    of the impact of access restrictions could be further enhanced.
        A broader framing of the debate about available oil and gas
    resources is important for two primary reasons. First, most
    states and regions are in the process of planning for
    substantial future dependence on natural gas as their dominant
    electricity generating fuel. Given this, decisionmakers and the
    public would benefit from a more comprehensive view of
    prospective costs and availability of long-term domestic
    supplies.
        Second, it makes sense to focus public debate about access
    to Federal lands on those resources that are most likely to be
    actually produced, in light of economic and environmental
    considerations.
        There are legitimate questions about the appropriate
    Federal role in examining the economics of exploration and
    development scenarios. Our proposed approach is not meant to
    replace industry's detailed economic evaluations at the play
    level, or replace Federal land managers' existing environmental
    assessment and permitting processes. Rather, it is meant to
    provide decisionmakers with a more comprehensive assessment of
    bounding ranges of resource viability at the regional and sub-
    regional scale.
        We think that our proposed methodology would enhance
    current efforts by BLM and other Federal land managers to
    communicate more effectively and clearly the economic and
    environmental implications of their actions. We are simply
    arguing for more comprehensive information in the policy
    process.
        RAND's interest in this issue, as it is in all of our work,
    is to improve decisionmaking through research and analysis. We
    are an independent, non-profit organization, dedicated to
    producing objective, non-partisan analysis. Our publications
    are subjected to rigorous peer review and quality assurance, in
    which we actively seek internal and outside experts to critique
    our work. The research upon which this testimony is based has
    been through this quality assurance process.
        We are currently preparing to produce a more comprehensive
    assessment methodology of the viable resource, as well as an
    application of this methodology to basins in the West. Given
    the challenge of developing such methodology, as well as its
    relevance to the current debate on energy policy, we believe
    that it was important to release this interim report at this
    time. With the publication of this report, we seek additional
    feedback on our proposed methodology as we proceed with our
    next phase of work.
        This concludes my testimony. I would like the full written
    statement to be included in the record. And I welcome any
    questions you may have. Thank you.
        [The prepared statement of Ms. Knopman follows:]

       Statement of Debra Knopman, Associate Director of RAND Science &
                                   Technology

        Thank you, Madam Chairman, for the opportunity to testify before
    the Subcommittee on Energy and Mineral Resources about methods of
    assessing oil and gas resources. At this time, I ask that my full
    written statement be entered into the record.
        I am a Senior Engineer at RAND and a member of the study team for
    RAND's just released interim report ``Assessing Gas and Oil Resources
    in the Intermountain West: Review of Methods and Framework for a New
    Approach'' and for an abridged version of that work in a paper entitled
    ``A New Approach to Assessing Gas and Oil Resources in the
    Intermountain West.'' These publications are interim products of a
    study that we expect to complete this summer. The research is funded by
    the William and Flora Hewlett Foundation. Here with me today are two of
    my RAND co-authors on those publications, Dr. Tom LaTourrette and Dr.
    Mark Bernstein.
        We are at approximately the midpoint of our study. We have
    completed the following tasks:
         A review of existing resource assessment methodologies
    and results
         An evaluation of recent studies of Federal lands access
    restrictions in the Intermountain West
         Consideration of a set of criteria that can be used to
    define the ``viable'' hydrocarbon resource, with particular attention
    to issues relevant to the Intermountain West
        We still plan to more fully address the development of a
    comprehensive assessment methodology for the viable resource, and then
    apply this methodology to Intermountain West basins.
        Given the challenge of developing such a methodology, as well as
    its relevance to the current debate on energy policy, we believe that
    it was important to release this interim report at this time. By doing
    so, we have created the opportunity to gather additional feedback on
    our proposed methodology as we proceed with the next phase of work.
        RAND's interest in this issue, as it is in all our work, is to
    improve decision-making through research and analysis. We are an
    independent non-profit organization, dedicated to producing objective,
    non-partisan analysis. Our publications are subjected to rigorous peer
    review and quality assurance in which we actively seek internal and
    outside experts to critique our work. The research upon which this
    testimony is based has been through this quality assurance process.
        Let me introduce a summary of our work to date by saying that RAND
    does not have a position on whether oil and gas exploration and
    development should proceed on currently restricted Federally managed
    lands. This is a complex policy question with several competing
    considerations, including the nation's need for long-term, reliable,
    and clean energy supplies. Rather, our interest is in the quality,
    relevance, and transparency of the technical information that surrounds
    the public debate on future development. We are also interested in
    encouraging a broader discussion about constraints on exploration and
    development beyond that of access restrictions applied to Federal
    lands. We believe that improved public understanding of the range of
    estimated costs and impacts of development and associated
    infrastructure, under different technology and economic assumptions,
    will contribute significantly to debate on national energy and land
    management policies.
        Our main point can be summarized as follows: The debate over access
    to gas and oil resources on Federally managed lands in the
    Intermountain West would benefit from an improved understanding of how
    much resource might actually be developed and at what costs. Our study
    recommends developing and publicly reporting estimates of ``viable''
    resources in the region, using a step-wise approach that incorporates a
    set of economic and environmental criteria. We also recommend ways in
    which the Bureau of Land Management's (BLM's) on-going basin-specific
    studies on the impact of access restrictions could be further enhanced.
        A broader framing of the debate about potential development of oil
    and gas resources is important for two primary reasons. First, most
    states and regions are in the process of planning for substantial
    future dependence on natural gas as their dominant electricity-
    generating fuel. Given this, decisionmakers and the public would
    benefit from a more comprehensive view of prospective costs and
    availability of long-term domestic supplies of natural gas and oil.
    Second, it makes sense for Federal land managers, as well as Congress
    and the public, to focus concerns about access restrictions on those
    resources that are prime candidates for production given economic
    viability and environmental considerations.

    SOME POLICY QUESTIONS REQUIRE MORE INFORMATION THAN WHAT TRADITIONAL
            ASSESSMENTS PROVIDE
        The goal of traditional resource assessments is to estimate the
    nation's potential supply of natural gas and oil resources. As part of
    our research, we examined four recent assessments: the U.S. Geological
    Survey National Oil and Gas Resource Assessment Team, 1995; Minerals
    Management Service, 2000; National Petroleum Council, 1999; and
    Potential Gas Committee, 2001. 1 Although the assessments
    vary, they agree that the Intermountain West contains substantial
    natural gas and oil resources.
    ---------------------------------------------------------------------------
        \1\ The four assessments are as follows: U.S. Geological Survey
    National Oil and Gas Resource Assessment Team, 1995 National Assessment
    of United States Oil and Gas Resources, U.S. Geological Survey Circular
    1118, 1995; Minerals Management Service, Outer Continental Shelf
    Petroleum Assessment, 2000, U.S. Minerals Management Service, 2000;
    National Petroleum Council, Natural Gas: Meeting the Challenges of the
    Nation's Growing Natural Gas Demand, National Petroleum Council, 1999;
    and Potential Gas Committee, Potential Supply of Natural Gas in the
    United States, Potential Gas Agency, Golden, CO, 2001.
    ---------------------------------------------------------------------------
        These assessments estimate what is called the ``technically
    recoverable'' resource 2--the amount of the resource that is
    estimated to be recoverable given certain assumptions about exploration
    and production capabilities. Resources are evaluated in terms of
    geological criteria and technical feasibility of recovery, but without
    economic or other considerations. These estimates, therefore, are not
    intended to indicate how much resource will likely be developed and at
    what cost.
    ---------------------------------------------------------------------------
        \2\ In practice, the definition of the term ``technically
    recoverable'' is unclear and is inconsistently applied among the
    different assessments. A large part of the difference between existing
    resource assessments results from differing assumptions as to what
    constitutes a technically recoverable resource.
    ---------------------------------------------------------------------------
        An enhancement to these assessments would be a range of estimates
    of the resource that can be ``viably produced,'' under varying
    assumptions about future energy prices, exploration scenarios, and
    current and emerging development technologies. Determining the oil and
    gas resources that are viable to produce depends on three main factors:
    (1) exploration and production costs (those costs incurred in getting
    the resource to the wellhead); (2) infrastructure and transportation
    costs (those costs incurred in getting the resource to the market); and
    (3) potential environmental impacts.
        It is important to note at this point that we highly value these
    existing expert resource assessments, and that we are in no way
    suggesting that they are inadequate for their intended purpose. Indeed,
    our proposed methodology builds on them. We are simply saying that more
    comprehensive estimates of resources likely to be developed would
    better focus policy discussion on key policy questions, such as, for
    example, the projected adequacy of supply and future cost of natural
    gas; and the overall effectiveness or hindrance of access restrictions
    in meeting future energy demand with adequate environmental safeguards.

    PROPOSED METHODOLOGY TO ESTIMATE THE VIABLE RESOURCE
        Our proposed methodology is designed to generate a series of map
    views of resources favorable for development under varying assumptions
    about energy prices, technology, and environmental impacts. A resource
    would be economically viable if the revenue expected from the developed
    resource is likely to exceed the costs of exploration, production,
    infrastructure, and transportation. Environmental impacts are difficult
    to predict. We intend to devise measures of existing environmental
    conditions and examine implications of change in those conditions. We
    will classify areas based on a selected set of water quality, air
    quality, and ecological measures, and relate these measures to existing
    environmental standards.
        We believe that one useful perspective is to look at these factors
    sequentially, beginning with the economic criteria. If the costs of
    getting resources from the wellhead to market would preclude
    development under some set of assumptions, then environmental
    considerations would not come into play.
        Similarly, the extent and need for various access restrictions on
    Federal lands can be viewed in the context of economic viability.
    Indeed, industry uses this same process of assessing the viability of
    developing oil and gas resources, whether on Federal or non-federal
    lands. Industry would be unlikely to pursue development if the costs of
    getting the resource out of the ground and to market exceeded revenue
    projections, or potential environmental concerns were viewed as
    significant and likely to be contentious. In essence, our proposed
    methodology would more systematically bring to the public discussion
    the multiple factors, including economic costs and environmental
    impacts, that industry must address before making a decision to move
    forward with development on public lands.
    BUILDING A COMPREHENSIVE RESOURCE ASSESSMENT METHODOLOGY
        The three factors cited above--exploration and production costs,
    infrastructure and transportation costs, and environmental impacts--
    reflect well-known and often cited issues that determine the
    availability of gas and oil resources. Aspects of these issues have
    been addressed to varying degrees in previous studies. 3
    However, the factors are generally not all considered in resource
    assessment methodologies. Building a comprehensive methodology that
    does so to the public's benefit is challenging.
    ---------------------------------------------------------------------------
        \3\ See, for example, Harry E. Vidas, Robert H. Hugman, and David
    S. Haverkamp, Guide to the Hydrocarbon Supply Model: 1993 Update, Gas
    Research Institute, Report GRI-93/0454, 1993; Emil D. Attanasi,
    Economics and the 1995 Assessment of United States Oil and Gas
    Resources, U.S. Geological Survey Circular 1145, 1998; and National
    Petroleum Council, Natural Gas: Meeting the Challenges of the Nation's
    Growing Natural Gas Demand, National Petroleum Council, 1999.
    ---------------------------------------------------------------------------
        RAND intends to develop an assessment tool that would produce
    ranges of estimates of resources that account for uncertainties. This
    tool would allow decisionmakers to vary assumptions about costs and
    constraints at each step of the analysis, improve understanding of the
    sensitivity of results to those assumptions, and determine the value of
    reducing data uncertainties within the analysis. For example, should
    the Federal Government increase investments to enhance existing
    assessments of the technically recoverable resource? How dependent are
    the results on assumptions about technological change? These are
    important questions to ask (and answer) for decisionmakers faced with
    reducing risks in long-term energy contracts or land managers faced
    with multiple choices about changing access restrictions.
    Exploration and Production Costs
        Estimating economic viability involves balancing exploration and
    production costs with resource revenues to determine if it would be
    economically logical to proceed with production. 4 Such
    costs, commonly referred to as ``wellhead'' costs, include exploration
    and development drilling, well completion, lease equipment, operations
    and maintenance, taxes and royalties; return on investment would also
    be included in this category.
    ---------------------------------------------------------------------------
        \4\ Harry E. Vidas, Robert H. Hugman, and David S. Haverkamp, Guide
    to the Hydrocarbon Supply Model: 1993 Update, Gas Research Institute,
    Report GRI-93/0454, 1993; and Emil D. Attanasi, Economics and the 1995
    Assessment of United States Oil and Gas Resources, U.S. Geological
    Survey Circular 1145, 1998.
    ---------------------------------------------------------------------------
        Estimates of economic recoverability in the Rocky Mountain Region
    are inherently uncertain and are hence best represented as a range of
    estimates rather than as a single point estimate. However, by way of
    illustration, a 1998 U.S. Geological Survey study indicated that, at a
    regional scale, significant amounts of gas and oil resources may not be
    economically viable for production in the foreseeable future. The USGS
    results (using 1994 data) showed that adding economic viability alone
    would rule out, in the near term, the recovery of a large fraction of
    the gas resource that would otherwise be deemed technically recoverable
    from the Green River Basin. 5 Of course, it is important to
    note that technological improvements and changing economic conditions
    have altered these estimates over time, particularly regarding the
    costs of developing nonconventional resources. Technology in this area
    is progressing rapidly, and the economically recoverable fractions are
    likely to be higher today than those reported in the USGS study.
    ---------------------------------------------------------------------------
        \5\ Emil D. Attanasi, Economics and the 1995 Assessment of United
    States Oil and Gas Resources, U.S. Geological Survey Circular 1145,
    1998. The U.S. Geological Survey economic assessment accounts for
    current technology only. As a result, its economic assessment is
    generally considered to be more conservative than the assessments used
    by industry. The data and forecasting assumptions used in the USGS
    study are current as of about 1994. It is important to note that
    technological improvements and changing economic conditions will alter
    these estimates over time. The use of more current recoverable resource
    estimates and cost assumptions will undoubtedly alter the results,
    particularly regarding the costs of developing nonconventional
    resources. Technology in this area is progressing rapidly, and the
    economically recoverable fractions are likely to be higher today than
    reported in the USGS study.
    ---------------------------------------------------------------------------
        Industry assessments of wellhead costs are tailored to reflect the
    unique costs of gas and oil exploration and production in the
    Intermountain West. We propose that a comprehensive assessment of the
    viable resource in the public domain reflect these differential costs.
    Further, a comprehensive assessment should account for differential
    costs resulting from the high abundance of nonconventional gas in the
    Rockies 6; well completion, lease equipment, and operating
    costs can be higher for low-permeability (tight) sandstone and coalbed
    methane deposits. It is also important to use, whenever available,
    local drilling success ratios, rather than regional averages of
    existing wells, since using ratios from existing wells biases
    assessments toward conventional deposits. Finally, other unique factors
    need to be addressed, including the steep and rugged terrain, remote
    locations, low-quality gas, and shallow formations.
    ---------------------------------------------------------------------------
        \6\ Nonconventional resources include low-permeability (tight)
    sandstone, shale, chalk, and coalbed methane.
    ---------------------------------------------------------------------------
    Infrastructure Costs
        Turning now to infrastructure costs, much of the economically
    viable resources in the Intermountain West cannot be developed without
    constructing additional pipeline and road infrastructure. Again, these
    are costs that industry knows well. We propose that a comprehensive
    assessment in the public domain reflect estimates of these costs as
    well. Capital expenditures and operating costs for infrastructure, in
    general, are comparatively high in the Rocky Mountain Region because of
    less existing infrastructure relative to other regions. If required,
    new infrastructure could add substantial costs beyond the wellhead
    costs alone.
        As was true in assessing wellhead costs, some complicating factors
    need to be considered in assessing infrastructure costs in the Rocky
    Mountain Region. These include the remoteness of existing pipeline
    infrastructure, particularly transmission pipelines; the rough terrain,
    unstable soil, and icing in colder climates; the extensive water
    disposal requirements associated with coalbed methane deposits; and the
    potential need for compressor capability to transport low-pressure gas
    from nonconventional deposits. In addition, produced water and other
    wastes may need to be removed from the site, in some cases requiring
    additional pipeline capacity.

    Environmental Impact
        Finally, we believe that there is value in looking more
    specifically, within the context of existing laws, at varying levels of
    change in existing environmental conditions that could occur as a
    consequence of exploration and development. We will likely use
    individual indicators to track a spectrum of conditions, including air
    quality, water quality, soil properties, hazardous materials, protected
    species, migration patterns, vegetation habitats, and land use. These
    conditions can be categorized and mapped to enable decisionmakers to
    understand the spatial distribution of existing environmental
    conditions within a total resource area. We do not intend to predict
    environmental impacts, but instead, we intend to show how varying
    environmental conditions relative to existing environmental standards
    could affect estimates of the viable resource.
        It is, again, important to note that RAND has not performed a
    comprehensive assessment of any area yet. We have focused the first
    phase of our work on developing a framework that would guide such an
    assessment. 7
    ---------------------------------------------------------------------------
        \7\ RAND will begin this effort by analyzing the Green River Basin.
    The analysis will specify the relationships among gas and oil deposits,
    technological options, economic costs, infrastructure requirements,
    environmental sensitivities, and other variables to allow for a
    comprehensive assessment of the viable gas and oil resource.
    ---------------------------------------------------------------------------

    CONCLUDING THOUGHTS
        Assumptions about the viability of resources--inherently uncertain
    under any method--need to be carefully examined for either excessive
    conservatism or optimism. A guiding principle of sound analysis is that
    there be consistency in whatever kinds of assumptions are used in
    assessment studies. For example, assessments that mix overly
    conservative assumptions about, say, drilling technologies with overly
    optimistic assumptions about wellhead costs or infrastructure economics
    are not useful for policymaking. In the context of understanding future
    domestic energy supply scenarios, consistency needs to further extend
    beyond a limited focus on selected Federal lands and toward a broader
    view of assessment on all lands.
        There are legitimate questions about the appropriate Federal role
    in examining the economics of exploration and development scenarios.
    Our proposed approach is not meant to replace industry's detailed,
    site-specific economic evaluations or Federal land managers' existing
    environmental assessment and permitting processes. Rather, it is meant
    to provide decisionmakers with a more comprehensive assessment of
    bounding ranges of resource viability at the regional and subregional
    scale. We believe our proposed methodology would enhance current
    efforts by the BLM and other Federal land managers to communicate more
    effectively and clearly the economics and environmental implications of
    their actions. We are simply arguing for more comprehensive information
    in the policy process.
        This concludes my testimony. I welcome any questions you may have.
    Thank you.
        [NOTE: The report ``Assessing Gas and Oil Resources in the
    Intermountain West: Review of Methods and Framework for a New
    Approach'' submitted for the record has been retained in the
    Committee's official files.]
                                     ______

        [Responses to questions submitted for the record by Ms.
    Knopman follow:]

                                  may 6, 2002

    Honorable Barbara Cubin, Chairman
    Subcommittee on Energy and Mineral Resources
    Committee on Resources
    U.S. House of Representatives
    Washington, DC 20515

    Dear Madam Chairman:

        This letter is in response to your request of April 23, 2002. In
    the enclosed attachment, I have provided written answers to your nine
    questions related to my testimony on April 18th. Please let me know if
    I may provide you with any additional information.
        I appreciated the opportunity to testify before your Subcommittee
    and look forward to working with you and your staff in the future.

    Sincerely,

    Debra S. Knopman
    Associate Director
    RAND Science & Technology

    Enclosure
                                     ______

                                   ATTACHMENT
    Questions from Chairman Cubin

    1. Did RAND ask the AAPG Committee on Resource Assessment for a peer
            review of its study? Did RAND ask anyone with extensive
            experience in studying and finding oil and gas deposits to peer
            review their study?
        As I discussed in my testimony, our report ``Assessing Gas and Oil
    Resources in the Intermountain West: Review of Methods and Framework
    for a New Approach'' and an abridged version of that work ``A New
    Approach to Assessing Gas and Oil Resources in the Intermountain West''
    are interim products of a study that we expect to complete this summer.
    We are at approximately the midpoint of our study. We have completed
    the following tasks:
         A review of existing resource assessment methodologies
    and results
         An evaluation of recent studies of federal lands access
    restrictions in the Intermountain West
         Consideration of a set of criteria that can be used to
    define the ``viable'' hydrocarbon resource, with particular attention
    to issues relevant to the Intermountain West
        We still plan to more fully address the development of a
    comprehensive assessment methodology for the viable resource, and then
    apply this methodology to Intermountain West basins. In releasing the
    interim report, we sought to gather additional feedback on our proposed
    methodology as we proceed with the next phase of work.
        RAND asked several natural gas resource experts to review the
    interim report prior to its release. These experts included Harry Vidas
    and Robert Hugman of Energy and Environmental Analysis, Inc (EEA). Mr.
    Vidas and Mr. Hugman are acknowledged experts in technical and economic
    assessments of gas and oil resources and have extensive gas and oil
    industry experience. EEA was the lead consultant on the 1999 National
    Petroleum Council (NPC) natural gas study. Mr. Vidas was the EEA
    contact for the supply subgroup on that study. Mr. Vidas was also a
    member of the Economic Assumptions & Policy and Technology Subgroups
    for the study. Because of their knowledge and expertise in these areas,
    Mr. Vidas and Mr. Hugman will be working with us as subcontractors as
    we develop our economic evaluations in the next phase of this study.
        RAND did not ask AAPG to review the interim report prior to its
    release, but we look forward to opening a dialog with AAPG and industry
    representatives as we move forward on the next phase of our work. We
    look forward to maintaining contact with industry, government, and
    other experts through the next phase of this project to provide us with
    the best available information relevant to the development and
    implementation of our methodology.

    2. Ms. Knopman, in your testimony, you spend a great deal of time
            discussion how you will use resource estimates to develop
            ``viable resource'' estimates, but you fail to mention what you
            are going to use for your Resource Base. Will you be developing
            your own resource estimates or whose resource estimates will
            you be using?
        RAND will analyze separate cases using the 1995 U.S. Geological
    Survey (USGS) resource base (including any subsequent revisions that
    have been released) and the 1999 National Petroleum Council study
    natural gas resource base.

    3. RAND states that their analysis of oil and gas resources will
            include a number of detailed economic factors that are actually
            more characteristic of a feasibility study where a lot more
            detailed data is [sic] available. How do you propose to
            determine these factors in an assessment of a region where most
            of the resource has not even been found--much less developed?
        Data is limited even under the best of circumstances when assessing
    oil and gas resources. Many of the existing assessments are done by
    extrapolation to like fields in other parts of the country. Further,
    where such data are not available, the assessments adopt assumptions
    based on judgement as do oil and gas producing companies when
    evaluating an individual property. This type of uncertainty is always
    present. Nevertheless, a significant amount of the resource is already
    being explored and developed. Technical information necessary to
    estimate wellhead economics and infrastructure requirements is
    available for tight sand, coalbed methane and conventional deposits in
    the Greater Green River Basin and other basins. Our intent is to use
    the best data available to provide the most information for policy
    analysis. Where data are not available, we will indicate that
    deficiency and represent the uncertainty in the analysis accordingly.

    4. You state in your written testimony, ``We will likely use individual
            indicators to track a spectrum of conditions, including air
            quality, water quality, soil properties, hazardous materials,
            protected species, migration patterns, vegetation habitats, and
            land use.'' You will then categorize and map those factors to
            enable decision makers to understand the [sic] spacial
            distribution of existing conditions within a resource area.
            Isn't this a duplication of the [sic] spacial resource data
            already in use by the BLM and Forest Service for making
            informed land use decisions? Also, as a follow up, how will you
            handle oil and gas leasing stipulations?
        RAND's approach will not duplicate data collection efforts by the
    Bureau of Land Management (BLM) and Forest Service or their application
    to specific parcel-scale land use decisions. The environmental
    indicators we intend to develop will be at the regional to subregional
    scale and used in conjunction with the similarly scaled wellhead and
    infrastructure cost data to improve understanding of the distribution
    of viable resources in the Intermountain West. These indicators are
    intended for use earlier in the decisionmaking process than the BLM and
    Forest Service environmental data and analysis, and meant to be used in
    conjunction with similarly scaled economic viability criteria.

    5. How do you factor the temporal aspect into your ``viable resource''
            estimate, for example in 1995 the USGS estimated that Wyoming's
            Powder River Basin contained a mean technically recoverable CBM
            resource of 1.11 trillion cubic feet of gas, however their
            current estimate is 14.26 Tcf, and an even more recent estimate
            by the Wyoming Geological Survey is 25 Tcf?
        As you point out, technically recoverable resource assessments are
    highly uncertain, and as more information becomes available, often turn
    out to be inaccurate in retrospect. The case of coalbed methane in the
    Powder River Basin, which you cite, is a good example. The USGS and
    others who assess the technically recoverable resource do not claim
    that their estimates reflect the ``total'' or ``entire'' resource base.
    Nor would we make that claim with regard to viable resource estimates.
    Because of the way in which they are defined, technically recoverable
    resource estimates exclude significant amounts of known resources (such
    as coalbed methane in the past and methane hydrates now). The amount
    and type of resources included in technically recoverable resource
    assessments changes with time as information and technology improves.
        Similarly, economically recoverable resource estimates are also
    subject to uncertainties and consequent changes over time. These
    estimates involve additional assumptions that add to uncertainty, but
    the bulk of the uncertainty is geological and is inherent in all
    resource assessments. Robust resource assessment methodologies should
    have a means of reflecting these uncertainties. They should further be
    updated with sufficient frequency to capture new information. Our
    intention is to present estimates of the viable resource in terms of a
    range and not a single estimate. The range will reflect existing
    uncertainty in technical and economic information. We also intend to
    estimate price-development curves that will indicate how estimates of
    the viable resource might change as prices changes. Further, the
    approach we are proposing is not intended to be completed as a one-time
    study providing the ``final'' answer, but will need to be updated
    periodically like other resource assessments.

    6. Can you explain Figure 1, Page 2 of the February 2002 RAND interim
            report to me? In the text you refer to the technically
            recoverable resources shown as a straight line in your graph as
            the ``available resource.'' Are you implying that the
            technically recoverable resource is the amount that can
            ultimately be recovered at a 100 percent recovery rate? Doesn't
            the technically recoverable resource also change, often
            significantly, as companies learn more about a producing area?
            Also, isn't the technically recoverable resource influenced to
            some extent by market price?
        Our discussion of Figure 1 refers to the effect of the viability
    criteria on the amount of resource that is likely to be recovered. It
    would have been clearer to refer to the ``recoverable'' rather than
    ``available'' resource.
        We intend to use the technically recoverable resource as our base
    estimate. As defined by the USGS, the technically recoverable resource
    is a function of current technology but not a function of market price.
    Their definition implies that if economics were not a factor, all of
    the technically recoverable resource could be physically extracted
    given today's technology. We use that definition in our display of
    information in Figure 1.

    7. Can RAND support the conclusion that regional assessments
            overestimate oil and gas resources? Can they cite some examples
            that illustrate that this is a problem?
        We do not say that technically recoverable resource assessments
    overestimate oil and gas resources in the ground. We believe that the
    USGS estimates are technically sound and intend to use them as a
    starting point for our own analysis. Rather, our primary conclusion is
    that technically recoverable resource estimates do not represent the
    amount of gas or oil that is likely to be recovered in the foreseeable
    future. In fact, the USGS, Potential Gas Committee, and NPC assessments
    all agree with this point. Our work is aimed at developing a
    methodology to estimate this latter quantity, which we call the viable
    resource. This is not a new conclusion, but rather an observation that
    the definition of technically recoverable resources excludes explicit
    consideration of economic factors. We think those factors are important
    considerations for policymakers and other users of publicly managed
    lands.
        A second conclusion in our work to date relates to access
    restriction studies. In Figures 3.1 and 3.2 in Chapter 3 of our interim
    report, we show how excluding proved reserves and resources under non-
    federal lands leads to a larger fraction of resources subject to access
    restrictions than would be the case if all resources were included in
    the calculation. While this is a matter of arithmetic, it is also a
    matter of policy as to what the appropriate resource base should be to
    estimate the impact of any constraint on development, including state
    and federal access restrictions.

    8. RAND's study so far has been funded by a $450,000 grant from the
            Hewlett Foundation. Has RAND received any additional grants
            from either the Hewlett or the Energy Foundation for work on
            oil and gas assessments in the United States?
        At this time, RAND has no other funding from any foundation for
    work on oil and gas assessments. We have requested but not yet received
    supplemental funds from the Hewlett Foundation to cover additional
    costs associated with the hearing and interim report.

    9. Which is more sensitive to long-term change and short-term periodic
            fluctuation, a regional assessment of oil and gas resources or
            the economic evaluation of the resource predicted from a
            regional assessment?
        We do not intend to forecast future economic conditions, but rather
    intend to show how the range of the estimated viable resource might
    change as economic conditions change. In working with ranges of
    estimates rather than point estimates, we will be communicating the
    temporal and spatial uncertainty in both resource estimates and
    economic conditions. The uncertainty of regional assessments of oil and
    gas resources has already been noted in the Chairman's 5th question and
    in our response. Short-term fluctuations in energy prices are well
    known although the long-term price trend has been relatively stable.
                                     ______

        Ms. Cubin. Thank you very much, Doctor.
        The next person to be recognized for their 5-minute
    testimony is Charles J. Mankin, Ph.D.

       STATEMENT OF CHARLES J. MANKIN, PH.D., STATE GEOLOGIST OF
      OKLAHOMA, AND SECRETARY, AMERICAN ASSOCIATION OF PETROLEUM
                               GEOLOGISTS

        Mr. Mankin. Thank you, Madam Chairman, for the opportunity
    to participate in this important hearing. I am Charles Mankin,
    director of the Oklahoma Geological Survey, and Director of
    Sarkey Energy Center at the University of Oklahoma. Today I am
    speaking on behalf of the American Association of Petroleum
    Geologists, an international professional society of 30,000
    members, for which I serve as secretary of the Executive
    Committee.
        The AAPG Committee on Resource Evaluation was chartered by
    the Executive Committee of AAPG in 1993 in response to a
    recommendation from a National Research Council committee that
    reviewed an earlier--I believe 1989--assessment of petroleum
    resources in the United States by the U.S. Geological Survey.
        That study, which I chaired, recommended that the USGS seek
    external professional expertise and data on sedimentary basins
    in the U.S. The CORE committee was thus established to
    accomplish that objective. I want to thank the members of the
    CORE committee for their efforts in assisting me in developing
    this testimony.
        For the record, I would like to define that part of the
    resource spectrum that we are concerned with today. The chart
    on our left shows a range of resources from reserves from which
    we derive our current production, the resources that through
    time and effort will be converted to reserves. Our focus today
    is on that prospective part of the resources that is
    highlighted in red.
        Ms. Cubin. Would the gentleman yield? Since there aren't
    very many people here today, could we just have that moved up
    where we can see it well?
        [Pause.]
        Ms. Cubin. Is that as close as it can come? Then we can see
    the people, too. Thank you. OK, that is good.
        Mr. Mankin. Studies by the U.S. Geological Survey and the
    National Petroleum Council have concluded that the most
    prospective areas of the U.S. for major new discoveries,
    especially for natural gas, are the Rocky Mountain sedimentary
    basins, the offshore of the Gulf of Mexico, the Atlantic and
    Pacific outer continental shelves, and the North Slope of
    Alaska. Currently, the Atlantic, Pacific, and eastern Gulf are
    restricted from mineral exploration. I suspect that the debate
    over the North Slope may well be going on as we meet. In
    addition, portions of the Rocky Mountain region are restricted
    or closed, as illustrated in that second chart that was just
    taken down.
        While others have and are proposing that the process be
    changed from the identification of technically recovered
    resources to a category that would include economic content,
    the AAPG maintains the firm belief that technically recoverable
    resources is the correct base to use when making policy
    decisions on competing use of Federal lands.
        Incorporating an economic overprint, when few of the
    economic factors can be determined with any degree of accuracy,
    simply increases the uncertainty in the magnitude of the
    resource base, and it diminishes the mean value. That is simply
    a mathematical calculation.
        Although further analysis of this resource base is
    perfectly justified, depending upon policy issues to be
    addressed, only the total resource base can be used to balance
    against other competing social environmental uses or the
    preservation of these lands.
        The United States has abundant energy resources. However,
    we are now faced with a real energy crisis, because the Nation
    has not developed and implemented a comprehensive energy
    policy. In order to ensure that our way of life is not
    dramatically impacted because of energy shortages, AAPG
    recommends the following:
        The U.S. must develop a national energy policy that
    provides dependable, affordable, and uninterruptible energy for
    public and commerce, and is based on a sound scientific
    assessment of the nation's resources and reserves.
        Energy policy must address the needs of all stakeholders,
    especially the consumers, and not over-react to the demands of
    the shrillest interest with the most money for publicizing a
    particular position.
        Energy policy must be strategic and long-term; not quick
    fixes, as in short-term crises.
        Energy policy must include a role for all energy resources,
    including coal and nuclear.
        Resource assessments are a vital planning tool for
    policymakers and industry; the agencies that perform these
    assessments and track oil and gas resources and reserves need
    continued support; they have done a good job to date.
        A major long-term and capital-intensive industry effort is
    required to explore for, develop, produce, and build the
    infrastructure necessary to deliver the energy supplies
    required to meet projected demand; energy policy must
    facilitate processes that attract capital investment in energy
    development, without creating costly and time-consuming
    regulatory roadblocks.
        Industry access to public lands which might contain
    hydrocarbon resources should be a priority to encourage
    domestic energy sources; we cannot become further and more
    dangerously dependent on unreliable foreign imports.
        The public must be assured that energy resource development
    can be accomplished in an environmentally sensitive manner; the
    technology is available to do this, and the petroleum industry
    is already practicing such environmental responsibility.
        On behalf of the AAPG, I thank the Subcommittee for giving
    us this opportunity to testify.
        [The prepared statement of Mr. Mankin follows:]

     Statement of Charles J. Mankin, Ph.D., Director, Oklahoma Geological
    Survey, and Director, Sarkey Energy Institute, University of Oklahoma,
      Norman, Oklahoma, and Secretary, American Association of Petroleum
                          Geologists, Tulsa, Oklahoma

        As a representative of the 30,000-member American Association of
    Petroleum Geologists (AAPG), I have been invited here today to testify
    as to the data, methods and technology on which hydrocarbon resource
    assessments for policy decisions should be conducted.
        AAPG was honored to be invited last year by this Subcommittee to
    comment on the oil and gas resource estimates conducted by the United
    States Geological Survey (USGS) and Minerals Management Service (MMS).
    At that hearing we testified that these agencies have used available
    geological data, have applied sound scientific principles and have done
    a good job in assessing the undiscovered hydrocarbon resources in the
    United States. Although we did not take a public position on the 1999
    National Petroleum Council's report entitled ``Natural Gas: Meeting the
    Challenges of the Nation's Growing Natural Gas Demand'', detailing the
    gas resources within the United States that are not accessible to meet
    the nation's needs, we agreed with its methods and conclusions. Today,
    I would like to repeat our appraisal of the methodologies used by USGS,
    MMS, and NPC and would also like to state in the very beginning that we
    are unable to say the same about some other methodologies being
    proposed, such as that proposed in the Rand Issue Paper.
        Assessment of a resource is a time-dynamic process. Because this
    process involves estimating the location and magnitude of an inherently
    unknown quantity, the accuracy of an assessment may be considered to be
    limited by 1) the perception and understanding of the origin and
    occurrence of the resource, 2) the quality, distribution and
    accessibility of available data from which to project estimates, and 3)
    the methods employed to conduct the assessment. Whereas USGS, MMS, and
    NPC studies have addressed all of these issues, the RAND Issue Paper
    does not offer any insight into the above three points.

    AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS
        The American Association of Petroleum Geologists was founded in
    1917. It is the largest professional geological society in the United
    States, and has members worldwide. The membership is dedicated to the
    geological study of the earth and it's environment, and the exploration
    and development of hydrocarbon resources and other energy minerals.
    Because much of the membership is engaged, either directly or
    indirectly, in the search for hydrocarbons and the economic development
    of hydrocarbon deposits, the AAPG is keenly interested in understanding
    the amount and geographic distribution of hydrocarbon reserves and
    resources. AAPG advocates a comprehensive national energy policy based
    on sound science and knowledge of the nation's resources and reserves.

    COMMITTEE ON RESOURCE EVALUATION
        In 1993, the AAPG Executive Committee chartered the Committee on
    Resource Evaluation (CORE) to ``provide input and facilitate U.S.
    Government agencies in performing assessments of U.S. hydrocarbon
    resources.'' The charter was amended in 1997 to include international
    assessments so CORE would have a worldwide view of hydrocarbon
    resources. Since inception, CORE has reviewed the methodologies and
    scientific methods used for assessments by the U.S. Geological Survey
    (USGS) and the Minerals Management Service (MMS), and, in several
    instances, has made individual AAPG members with specific knowledge of
    certain geological provinces available to the agencies. To a lesser
    degree, CORE has offered opinions and technical information to the
    Energy Information Administration (EIA). For example, CORE supplied
    feedback to the EIA regarding it's study of the economic impacts of the
    Kyoto Protocol on U.S. energy markets and made members with Deepwater
    Gulf of Mexico knowledge available to the EIA for consultation.
        The Committee membership consists of domestic and international
    managers of major petroleum companies, independent geologists and
    environmental consultants, two current and former state geologists,
    three past AAPG Presidents, Director of the Potential Gas Committee
    (Colorado School of Mines), and scientists from the USGS and MMS. All
    the members have a great deal of expertise in the science and
    technology of reserve and resource estimation. At most of its meetings,
    CORE has invited guests from the USGS, MMS, EIA and industry and
    environmental experts who can contribute to our knowledge of the
    nature, amount, and geographic distribution of known, and yet to be
    discovered resources. CORE does not restrict its interest to
    conventional hydrocarbons, but includes basin-centered gas in
    continuous reservoirs, coal bed methane, shale gas, and to some level,
    gas hydrates.
        Since its formation, CORE has consulted with the USGS on its 1995
    National Assessment of United States Oil and Gas Resources, the 1999
    Arctic National Wildlife Refuge 1002 Area assessment, and the 2000
    World Petroleum Assessment, and the currently ongoing assessment of
    unconventional gas accumulations. For all of these, the Committee on
    Resource Evaluation has recommended to the AAPG Executive Committee
    that AAPG endorse the scientific methodologies and techniques used by
    the USGS, and the AAPG has publicly done so. AAPG has not endorsed
    specific resource numbers generated by the assessments, but has
    endorsed the sound scientific process used to generate the probability
    distributions that characterize these resources. As mentioned earlier,
    the then-Vice Chair and current Chair of the Committee on Resource
    Assessment, Dr. Naresh Kumar, testified in front of this Subcommittee
    on the scientific soundness of USGS and MMS assessment methods last
    year.

    RESERVES AND RESOURCES
        For the record, I would like to define certain terminology and
    define the part of the resource spectrum that is addressed by Resource
    Assessments. Figure 1 was developed jointly in 2000 by AAPG, the
    Society of Petroleum Engineers (SPE), and the World Petroleum Congress
    (WPC), and has been published by the SPE.
        At the top of the figure, we define ``reserves'' as having been
    discovered and commercial in nature. We discuss them as being proved;
    proved plus probable; and proved plus probable plus possible; thus
    conveying a degree of certainty about the quantity.
        Figure 1 shows the highlighted box that is the primary focus of
    today's testimony. Resources are potential, undiscovered, estimated
    volumes of hydrocarbons. The estimates are based on our current state
    of geological knowledge and existing technology. Whether resources are
    ever converted to reserves is dependent on economic conditions, policy
    decisions, and incentives for companies to perform exploration
    activities. As exploration proceeds and more geological data is
    collected, our ability to make better estimates of resources increases.
    Also, as resources are converted to reserves, supply increases and the
    ability to meet demand improves. We discuss resources in terms of low
    estimate, best estimate, and high estimate. These levels of estimation
    are driven by our geological knowledge, available data, and the
    technology available to assess them.
        Let me restate: in order for resources to be converted to reserves
    and ultimately to supply, exploration and development has to take
    place. The exploration process consists of leasing acreage, acquiring
    and interpreting seismic and subsurface data, and drilling.
    [GRAPHIC] [TIFF OMITTED] T8788.001

    U.S. ENERGY RESOURCES
        AAPG believes the U.S. still has a large energy resource remaining
    to be tapped. We believe the techniques and scientific methods used by
    both the MMS and USGS are sound and provide a good basis for discussion
    of a national energy policy.
        Studies by the USGS and NPC have concluded that the most
    prospective areas for major new discoveries, particularly natural gas,
    are on public lands in the Rocky Mountain sedimentary basins, offshore
    in the Gulf of Mexico, in the Eastern Gulf of Mexico, and on the
    Atlantic and Pacific Outer Continental Shelf. AAPG concurs with this
    assessment. Despite the huge potential of these areas, Federal law
    presently prohibits exploration on the Atlantic and Pacific OCS and in
    the Eastern Gulf of Mexico. Access to much of the remaining resource
    potential of the Rocky Mountain basins is restricted or closed. The
    total estimated gas resource of these areas is 213 TCF (per NPC 1999
    study). For comparison, the US currently produces approximately 19 TCF
    per year and imports another 3+ TCF/year from Canada. It is likely that
    with further exploration, these resource figures would increase
    significantly. Unfortunately, a significant amount of that resource is
    subject to restrictions as tabulated in Table 1 and shown in Figure 2.
    In the case of the Rocky Mountain Region, the resource subject to some
    restriction amounts to two-thirds of the total estimated resource.

    [GRAPHIC] [TIFF OMITTED] T8788.002

    [GRAPHIC] [TIFF OMITTED] T8788.003

    WHICH ESTIMATE TO USE FOR PUBLIC POLICY DECISIONS?
        As this Subcommittee is well aware, under the reauthorization of
    the Energy Policy and Conservation Act in 2000, Congress asked the
    Department of the Interior to provide a scientific inventory of Federal
    Lands detailing the hydrocarbon resources estimated to be present on
    these lands and restrictions and impediments to development of these
    resources. This inventory would be used for management of land and
    energy resources and should form the basis for policy decisions
    required for balancing the nation's need for energy and the imperative
    for environmental conservation. As we understand it, these studies are
    still in progress.
        Recently, questions have been raised criticizing the 1995 USGS
    National Oil and Gas Assessment, 1999 National Petroleum Council study
    and the 2001 Department of Energy's Greater Green River Federal Lands
    Analysis. The USGS, NPC, and DOE studies described the undiscovered oil
    and gas resources that may be present on the areas addressed by these
    reports. In addition to the ``technically recoverable'' resource, the
    USGS assessment and the NPC study did address the economically
    recoverable resource under various price and development scenarios.
        The RAND Issue Paper proposes substituting viable resources for
    technically recoverable resources as the base that matters for policy
    decisions. The problem with this approach is that the viable resource
    is not a prerequisite for sound decisions, but is itself an outcome of
    many decisions, such as decisions on which technologies to develop and
    deploy, on what constitutes environmental ``acceptability'', and the
    like. The effect of land and access restrictions should be assessed in
    terms of both their short- and long-term effects on the entire nation's
    supply and security. The latter clearly requires technically
    recoverable resources.
        It is AAPG's firm belief that technically recoverable resource is
    the correct base to use when making policy decisions on competing use
    of Federal lands. Although, further analysis of this resource base is
    perfectly justified depending upon policy issues to be addressed, only
    the total resource base can be used to balance against other competing
    social and environmental uses or preservation of these lands.
        Although the economic analysis carried out by the USGS and NPC
    studies is valid and adequate, oil and gas companies considering
    exploration in any area perform their own economic analysis for their
    decisions. Each company has its own economic criteria and risk profile
    to determine whether they wish to explore in a basin. They will start
    with the technically available resource and assign their own criteria
    to make a decision. As Figure 3 shows, there are many factors that
    affect the conversion of Resources to Reserves and then Reserves into
    Supply. Legislation in the form of access or non-access, ``standard
    lease terms'' or ``restricted access'' or permanent or temporary
    moratoria are part of the equation. However, if the hydrocarbon
    resource base is to be weighed against all other competing interests in
    a given piece of land, the technically recoverable resource base is the
    logical starting point. That is also the only quantity that has the
    least chance of being manipulated for philosophical, political, and
    personal-interest reasons.
        Assumptions of price, drilling costs, transportation costs, etc.
    are only good for the day they are made. As we have seen in the last
    ten years, a two- to three-fold change in oil and gas prices is not
    uncommon, nor is a similar change in the costs associated with
    exploration. In addition, a company that is already operating in a
    basin will have a different risk profile and economic criteria than a
    company that is new to that basin. The companies look at various plays
    on a long-term basis and understand there are economic risks and that a
    continuous reservoir or non-conventional play that may take hundreds of
    wells to develop is going to have a long lifespan and the project will
    see a lot of price fluctuations during its lifetime.
        The whole objective of the studies being conducted under the EPCA
    reauthorization is to determine the balance between competing public
    interests. If the ``cost'' of environmental impact were used right in
    the beginning to diminish the volume of available resource in the
    Rockies, then according to some groups, no resources would exist.
    [GRAPHIC] [TIFF OMITTED] T8788.004

        We have a very recent example of the impact of this approach. The
    MMS conducted OCS Sale 181 in December of last year in the Eastern Gulf
    of Mexico. By all accounts, it was a successful sale with seventeen
    companies participating. A total of $459 million was bid at the sale,
    which offered 233 tracts. Successful bids on 95 blocks totaled $340
    million. However, prior to the scheduled sale, 800 blocks covering 3.4
    million acres were deleted from the sale for political concerns, even
    though the blocks were as much as 100 miles offshore. Initially, these
    800 blocks had passed the same environmental filter that the other 233
    blocks had. The Federal government lost valuable revenues and future
    royalty payments, and the nation lost potentially valuable additions to
    the resource base.
        I would directly address the question of ``viable resources''.
    Viability speaks directly to changes in costs, prices, accessibility
    and technology. After all, at one time none of the modern inventions
    that we take for granted, such as the telephone, or the computer, or
    the airplane were ``viable''. More specifically to the oil and gas
    industry, drilling and producing in 10,000 feet of water or
    multilateral drilling to access resources from a central point, or
    commercial production of coal-bed methane were not considered
    ``viable'' at one time. Thus we believe that viability hinges on market
    need. And market need drives technological innovation.

    ISSUES SPECIFIC TO ROCKY MOUNTAIN BASINS
        Although the purpose of our testimony is not to specifically
    counter the points raised in the RAND report, we would like to address
    some of the issues mentioned.
        It has been suggested that any study of the basins should consider
    the restricted portion of only the economically viable resource. The
    NPC study did evaluate both technically recoverable and economic
    resources. In various scenarios evaluated in the study, NPC found that
    a high percentage of the assessed undiscovered resource base in the
    Rockies is either economic now or will become economic through the year
    2015. This conclusion has been verified by the level of industry
    interest in the region and the region's growing gas production. The NPC
    study used economic viability of new prospects as the primary
    determinant of future industry activity, reserve additions and
    production. The study showed that most of the assessed Rocky Mountain
    volumes are economic to develop, either now or in the future, and that
    a large volume of these resources is likely to be in areas where
    industry access is restricted. Gas production in the Rockies would be
    800 BCF/year greater in 2015 with less access restrictions. This
    incremental Rockies production would satisfy approximately one-quarter
    of California gas demand in 2015.
        The RAND report also questions various aspects of ``access
    restrictions'' that were tallied and considered in the NPC study.
    Through a detailed analysis of six calibration areas in the Rockies,
    the NPC Study arrived at three lease classifications and their
    percentages:

    [GRAPHIC] [TIFF OMITTED] T8788.005

        It should be pointed out that before any Federal Lands are
    available for leasing, they undergo Environmental Impact studies. The
    ``Standard Lease Terms'', although ``unrestrictive'', incorporate
    environmental objectives. Any economic study based on these terms
    already incorporates ``environmental acceptability''. Thus, to reduce
    the resource base on the basis of ``environmental acceptability'' would
    amount to a double jeopardy against that resource base.
        Those areas with higher costs were subject to increased drilling
    costs and drilling delays. The cost penalty was computed as a weighted
    average of the types of restrictions and mitigation measures that were
    expected to be encountered in the high cost areas. Some access
    restrictions are sometimes waived, but they almost always accompany
    costly mitigation measures. New access restrictions are placed on
    ``standard lease terms'' as new areas for drilling are reviewed. The
    net effect could well be a greater cost penalty than the values used in
    the NPC study. Additionally, restrictions on public lands many times
    impact access and costs of operation on non-Federal lands as well.
        One of the important conclusions of the NPC study was that the
    Rocky Mountain region could supply a growing amount of the country's
    natural gas needs. Therefore, policy makers should weigh the economic
    and environmental benefits of this potential gas supply against
    policies that might restrict access to the region's natural gas
    resources.
        AAPG has always stated that oil and gas exploration, development
    and production can and does co-exist with environmental preservation in
    every producing region of the country. Various state and Federal
    regulations and lease stipulations and monitoring ensure that. However,
    each time the Congress reviews the nation's need for growing oil and
    gas demand and attempts to find ways to secure additional domestic
    supplies, we hear calls for permanent closure of highly prospective
    areas.

    ACCESS TO GAS RESOURCES ON FEDERAL LANDS
        Even the environmental groups cite natural gas as a cleaner,
    environmentally more benign energy resource to fuel our economy.
    However, access to the huge gas potential of undeveloped public lands
    is limited, in the Western states and on the OCS. Additionally, the
    Federal regulatory maze hinders domestic petroleum exploration
    operations and investment.
        The U.S. cannot depend on gas imports from OPEC to meet rising
    demand. Natural gas is a North American commodity that is locked into a
    pipeline delivery system. Imports from Mexico will be minimal. The 1999
    NPC study projected LNG imports of less than 1% of supply through 2015.
    That same study projected U.S. gas demand in 2010 to be 29 TCFG on an
    annual basis and projected U.S. production to be 25 TCFG/yr. The
    shortfall, according to the NPC, will be made up by 4 TCFG of imports
    from Canada. What happens if the Canadian imports do not materialize?
    The United States must develop its own gas resources to meet future
    demand. This requires access to the public lands that are deemed most
    prospective for natural gas.
        Conservation and renewable energy resources often are cited as the
    solution to our energy requirements. This is not a realistic
    expectation if one appreciates the actual tiny magnitude of current
    alternative energy, and that fossil fuels supply 88% of our primary
    energy. Energy conservation has been effective in certain areas,
    particularly in regard to increased miles per gallon for automotive
    engines. Those efforts obviously, must continue. But they will not be
    sufficient. For the maintenance of a growing economy additional
    hydrocarbon resources must be identified and brought into production
    for the foreseeable future.
        Despite DOE expenditures of over $9 billion since fiscal year 1980
    on solar and other renewable energy research, alternative energy
    resources provided only 0.3% of primary energy supply in 1999,
    exclusive of traditional hydroelectric power (3.8%). Obviously time and
    effort for research must continue on alternate energy resources, but we
    cannot count on these sources to meet our nation's needs in the short
    term.
        AAPG does not advocate any reduction in alternative energy
    research. However, the fact is, that our economy will continue to
    depend on fossil fuels for the majority of the nation's primary energy
    requirements for at least another generation. On April 18, 2000 at the
    AAPG Annual Meeting in New Orleans, Jay E. Hakes, Energy Information
    Administrator, presented a paper entitled ``Long Term World Oil
    Supply''. One of the conclusions in that paper was that with an
    estimated mean ultimate recovery of 3.0 trillion barrels worldwide, and
    production growth rates of 0-3%, the estimated peak year of world oil
    production would range from 2030-2075. That is at least another one-
    half century of hydrocarbons being a significant part of our energy
    mix.

    RESOURCE ASSESSMENTS
        I would like to return to the issue of which assessment numbers
    should be used for public policy decisions. Organizations such as the
    USGS, MMS or the NPC have carried out assessment based on geological
    data, scientific knowledge, and proven tools available to them. At
    times the agencies have been ``behind'' industry's thinking, especially
    in the area of new or evolving exploration plays because they do not
    have access to all the data. For example, the latest information on
    economic production of natural gas from coal seams in the Powder River
    Basin of Wyoming is probably only known to the companies currently
    operating in that area. As a result, the assessments have sometimes
    been too conservative and have required subsequent revisions. Until
    emerging plays are proven and at least some of the data becomes public,
    the agencies assign limited resources to them, and rightly so. Once
    these kinds of ``frontier'' plays have been discovered and proven by
    the risk takers of industry, the total resource impact can be assessed.
        One of the characteristics of assessments we have discovered is
    their tendency to grow in size over time. This is due to increased
    exploration and gathering of subsurface data, improvements in
    geological knowledge, and acquisition of additional seismic data. As
    our knowledge of a basin increases, so does our ability to estimate its
    resources; which generally results in an increase in the size of the
    resource. That also is why exploration is so competitive. Different
    interpreters can look at the same data set, and draw dramatically
    different conclusions about exploration prospects. For example, in the
    late 1960's M. King Hubbert estimated the ultimate gas resource for the
    United States (excluding Alaska) to be about 1,044 TCFG. In 2000, the
    estimate is almost twice that amount at 2,000 TCFG.
        Tight sandstone reservoirs are very prominent in many basins of the
    Western U.S. In its 1995 study, the USGS assigned 200 TCFG of
    recoverable resource to this type of reservoir in the Rocky Mountain
    Basins. The USGS is currently embarking on a reassessment of resources
    in this type of reservoir, because recent exploration has established
    new geological concepts and USGS has revised its own assessment methods
    for unconventional reservoirs. Given the nation's desire to switch to
    natural gas wherever economically feasible, this could be one of the
    most important assessments the USGS will perform. AAPG has evaluated
    the revised USGS methodology to assess such reservoirs and has endorsed
    this methodology.

    SUMMARY
        RAND corporation's own statement of research principles describes
    that any research should be well designed for the problem, that it
    should be based on sound information, that it should be balanced and
    independent and should be relevant to client's interest and needs. It
    also states that it should take into account the relevance of previous
    work. We believe that the clients, the citizens of the United States,
    deserve a sound energy policy that maximizes domestic production with
    utmost care for the environment. However, the clients' needs are ill
    served by insisting that we have ample sources of energy while putting
    restrictions on its supply, that we use more natural gas while shutting
    areas from where the gas might come, by insisting that we use
    alternative energy sources while having no viable alternative source in
    the near future, and by insisting that oil and gas development by
    definition spoils the environment while the facts are otherwise. The
    RAND Issue Paper essentially argues for ``proving'' that a given area
    contains technically recoverable, economically profitable, and
    environmentally suitable resource before access issues can be decided.
    However, without access to the area in the first place, its potential
    cannot be tested or realized.
        AAPG firmly believes that the nation has a right to decide which
    type of lifestyle we should have. In order to evaluate competing
    interests in the use and nonuse of possible resources, the decision
    makers should know the total extent of possible resources just like
    they have the right to know the total extent of all other social,
    economic, and environmental concerns. Technically recoverable resource
    is the only number that addresses the full base of possible energy
    resource. All other concerns should be weighed against that number.

    AAPG ENERGY POLICY RECOMMENDATIONS
        The United States has abundant energy resources. However we are now
    faced with a real energy crisis, because the nation has not developed
    and implemented a comprehensive energy policy. In order to assure that
    our way of life is not dramatically impacted because of energy
    shortages, the AAPG recommends the following:
         The U.S. must develop a national energy policy that
    provides dependable, affordable, and uninterruptible energy for the
    public and commerce, and is based on a sound scientific assessment of
    the nation's resources and reserves.
         Energy policy must address the needs of all stakeholders,
    especially the consumers, and not over react to the demands of the
    shrillest interests with the most money for publicizing a particular
    position.
         Energy policy must be strategic and long-term, not
    ``quick fixes'' to short-term ``crises''.
         Energy policy must include a role for all energy sources,
    including coal and nuclear energy.
         Resource assessments are a vital planning tool for
    policymakers and industry. The agencies that perform these assessments
    and track oil and gas resources and reserves need continued support.
    They have done a good job to date.
         A major long-term and capital-intensive industry effort
    is required to explore for, develop, produce, and build the
    infrastructure necessary to deliver the energy supplies required to
    meet projected demand. Energy policy must facilitate processes that
    attract capital investment in energy development without creating
    costly and time-consuming regulatory roadblocks.
         Industry access to public lands, which might contain
    hydrocarbon resources, should be a priority to encourage domestic
    energy sources. We cannot become further and more dangerously dependent
    on unreliable foreign energy imports.
         The public must be assured that energy resource
    development can be accomplished in an environmentally sensitive manner.
    The technology is available to do this and the petroleum industry
    already practices such environmental responsibility.
         The impact of the Kyoto Protocol on the ability of the
    nation to supply the energy needed to fuel our economy without major
    disruptions must be carefully evaluated.
        On behalf of AAPG, I thank the Subcommittee for giving us this
    opportunity to testify.
                                     ______

        [Responses to questions submitted for the record by Mr.
    Mankin follow:]

     OVERSIGHT HEARING ON ``OIL AND GAS RESOURCES ASSESSMENT METHODOLOGY''
                                 APRIL 18, 2002

    Questions from the Majority

    1. What is the oil and gas potential of the Rocky Mountains and why is
            the EPCA inventory important?
        As the energy needs of the Nation continue to grow, the geologic
    basins in the Rocky Mountains have been identified as a significant
    future source of energy to help meet these needs. At the same time,
    this region is one where environmental concerns are paramount. This
    situation has borne the recognition that it would serve the Nation's
    interests to quantitatively assess and identify broader issues
    regarding the potential for oil and gas development based upon
    environmental considerations. Such study will help to clarify the
    debate and assist energy policymakers and Federal land managers to make
    constructive, rational decisions concerning oil and gas resource
    development in the region.
        According to the NPC (1999) study, the Rocky Mountain region has
    213 trillion cubic feet of mean technically recoverable resource. The
    comparable oil figure is 4.0 billion barrels (USGS, 1995 National
    Assessment).
        The EPCA inventory represents a systematic, multi-basin analysis
    quantifying the Nation's oil and gas resources based upon environmental
    considerations. We believe these studies will prove useful for
    highlighting those critical areas that have high oil or gas resource
    potential for supplying the Nation's energy needs, while at the same
    time quantifying the nature of environmental stewardship currently in
    place. We believe that these studies will provide a foundation for
    addressing energy and environmental concerns and should streamline
    efforts to alleviate the conflicts between them.

    2. Has there been a problem with regional oil and gas assessments being
            unduly optimistic? Can you cite any examples where regional
            assessments were too pessimistic?
        We believe that the assessments carried out by professional
    organizations such as the United States Geological Survey or the
    Minerals Management Survey are done based on the data, assumptions, and
    geological concepts prevailing at the time the assessment is conducted.
    However, the history shows that the figures tend to increase through
    time. This happens because existing fields have a history of
    ``growing'' in size through time and new geological concepts and new
    technology make previously inaccessible resources accessible and tested
    as shown in the graph below.

    [GRAPHIC] [TIFF OMITTED] T8788.006

    3. Can we determine the ultimate amount of the oil and gas in place
            from a regional assessment?
        As explained in answer to the previous question, the concepts,
    assumptions and geological information continue to expand and evolve.
    Hence, the ultimate amount of oil and gas in place from a regional
    assessment always will remain the most educated estimate at a given
    time.

    4. Which is more sensitive to long-term change and short-term periodic
            fluctuations, a regional assessment of oil and gas resources or
            the economic evaluation of the resource predicted from a
            regional assessment?
        Fluctuations in oil and gas prices obviously impact economically
    recoverable resources in the short term. However, as shown in the
    graphic above, the total resource estimates tend to grow through time.
    The same factors (geologic concepts, technology, and field growth) also
    tend to impact the economically recoverable resource in an upward trend
    as well in the long term.

    Questions from the Minority

    1. Dr. Mankin, you cite results from the 1999 National Petroleum
            Council report on gas supply and demand. In modeling future
            demand for gas, what simplifying assumptions did the NPC report
            use?
        Would you agree that these assumptions ignore the market incentives
    for these non-gas energy industries to invest in new generation
    capacity in response to market prices?

    [GRAPHIC] [TIFF OMITTED] T8788.007

        Major Demand Assumptions:
        1. GDP will grow at 2.5% per Year
        2. 140 GW of New Power will come on Line by 2015
        3. 70% of New Gas-fueled Power Projects could Switch Fuels
        4. No New Nuclear Facilities will be Built
             a. L30 GW of Nuclear Capacity up for Relicensing by 2015
             b. LOf this, 15 GW of Nuclear Generation will Retire
        5. Another 15 GW of Nuclear Power will get License Extensions
        6. Coal Capacity Utilization will increase from 64% to 75%
        As shown in the graph above, natural gas, petroleum, and coal
    account for almost 90% of the primary energy consumption. In the year
    2020, even with a significant component being derived from
    conservation, this figure would drop at best to 70%. With concern for
    the environmental effects of burning coal and large coal-bearing areas
    in the United States being off-limits to exploration and development,
    the Nation's continuing decline in oil production, and demand for
    ``clean burning'' fuels, we believe that NPC estimates are fair and
    realistic. We believe that the nation would be well served to prepare
    to meet that demand.

    2. Assuming that additional investment is forthcoming in liquid gas,
            hydroelectric or renewable energy facilities, wouldn't you
            agree that the gas demand estimates in the 1999 NPC report are
            overestimated?
        Hydroelectric supplies only 3.8% of the nation's primary energy
    supply. We do not see any additional hydroelectric facilities on the
    horizon. This is because there would be many objections due to land
    condemnation resulting from reservoir flooding. Actually, hydroelectric
    generation is lower than what the NPC projected due to drought
    conditions.
        By liquid gas, we assume that you mean Liquidified Natural Gas
    (LNG). The NPC study projects that gas from LNG projects will increase
    from 100 BCF/yr, as of 1999, to about 800 BCF by 2015. This is a very
    small part of the total demand.
        Despite a Federal expense of $9 billion in research funds for
    alternative energy sources since 1980, only 0.3% of the Nation's
    primary energy comes from alternative sources. The Nation wants clean,
    reliable and affordable source of primary energy. Against such a
    background, it can hardly be said that NPC report overestimated the gas
    demand.

    3. Why wouldn't future investment in conservation and energy efficiency
            also reduce the demand for gas estimated in the NPC study?
        The NPC Study did assume improving energy efficiency. It projected
    that 50% of increased gas demand by 2010 would be from increased
    electricity demand. The long-run income elasticity for electricity grid
    sales assumed by the NPC averaged 0.80 across all regions of the U.S.
    That is, if the economy grew 2.5 percent per year, then electricity
    sales would grow 2.0 percent. Regarding Residential and Commercial uses
    of gas, the NPC Study also factored in:
         Housing stock increasing with population
         Housing size increasing with income
         Gas market share grows for appliances
         Energy efficiency improving per household
        However, as shown in Figure 2, even with conservation and energy
    efficiency accounting for 15% of primary energy consumption by the year
    2020, more than 70% of primary energy needs have to be met by coal, oil
    or natural gas. This scenario still implies a 25% growth in the energy
    derived from coal, oil and natural gas. Thus, the NPC estimate of
    demand for gas is quite realistic.

    4. The NPC report discusses the ability of industry to access oil and
            gas with directional drilling from 5-6 miles away. In fact the
            report states (page 14) that the industry could set up
            ``drilling operations on the White House lawn and extract
            hydrocarbons from beneath most of Washington, DC and into its
            suburbs.''
    In your testimony you cite the NPC estimate of 137 TCF (trillion cubic
            feet) of gas being off-limits in Rocky Mountains due to access
            restrictions.
    In generating this estimate the ability of industry to use directional
            drilling was not considered.
    However, the NPC also report promotes directional drilling technology
            but than assuming it doesn't exist when examining access. Why
            the inconsistency?
        Actually, there is no inconsistency, but differences between
    exploration and development drilling explains this apparent
    ``inconsistency.'' While it is true that in a development setting (that
    is, once the oil or gas has been discovered and determined to be
    economic), long-offset drilling can occur and is often an economically
    advantageous way to develop a field. However, the discovery of the
    field must come first, and this is done with vertical (or high angle
    wells). Without land access (including access to seismically defined
    exploration targets), exploration wells cannot be drilled.
        By statute, directional drilling cannot be used to drill under
    unleasable lands from leasable areas. While the NPC study did not
    explicitly address the use of directional drilling, a follow-up study
    of the Greater Green River Basin did (Department of Energy, 2001).
    Federal officials and industry operators were canvassed to determine an
    appropriate distance into so-called ``no surface occupancy'' areas
    (where a drilling rig cannot be sited). The directional drilling
    capability is partially a function of the depth to drilling
    objectives--generally the deeper the objective, the farther the kick-
    out of a well can be. In practice, for exploration settings in western
    basins of the U.S., the typical kick-out distance is estimated to be
    about one-fourth of a mile.

    5. The NPC report included sensitivity analysis to see how the
            ``access'' results changed if key parameters were altered. The
            NPC report also examined the potential impacts of reduced
            access to gas resources in the Rocky Mountain Region-analogous
            to implementing the roadless area conservation rule or
            enforcing gas lease stipulations.
    In this scenario, reduced access in the Rocky Mountain region had very
            little impact on gas prices.
    The NPC report also included sensitivity analysis on access. They re-
            ran the model assuming less access in the Rocky MountainsCwhich
            can be considered a proxy for the lease stipulations.
    The NPC results found that, ``The changes that occurred in the reduced
            access sensitivity case were not pronounced'' (page 43)
    As such, it seems to me that the impacts of leasing stipulations will
            have very little impact on gas prices. Is this conclusion
            consistent with the findings in the 1999 NPC report?
            [GRAPHIC] [TIFF OMITTED] T8788.008

        The reason why the reduced access case was less pronounced was
    because the NPC Reference Case already had substantial restrictions
    built into it. Additionally, the ``Off Limits'' percentages did not
    increase all that significantly. It would have been a more interesting
    scenario if the ``Off Limits'' percentage had increased to about 25% of
    the resource base. In retrospect, the NPC did not make the Reduced
    Access Case ``bad enough''.

    6. How was the amount of economically recoverable gas estimated in the
            NPC report?
        The GRI Hydrocarbon Supply Model (HSM) was used in both the 1992
    and 1999 NPC Studies. The HSM was developed by Energy and Environmental
    Analysis, Inc. (EEA) for the Gas Research Institute (GRI) in the early
    1980's and has been continually updated since that time. The HSM is a
    PC-based analytical framework designed for simulation, forecasting and
    analysis of natural gas, crude oil, natural gas liquids and for cost
    trends in the US and Canada. The HSM is a process-engineering model
    with a very detailed representation of potential gas resources and the
    technologies with which those resources can be proved and produced. The
    degree and timing by which resources are proved and produced are
    determined in the model through discounted cash flow analysis of
    alternative investment options and behavioral assumptions in the form
    of inertial and cash flow constraints and the logic for setting
    producers market expectations (e.g., gas prices).
    7. Why is the amount of gas economically recoverable so much greater
            than the amount estimated by USGS scientists?
        It is always difficult to compare one study versus another without
    comparing the coverage, resource category definitions, methodology,
    statistical analysis and legitimate difference in data interpretation.
    The USGS study was conducted in 1995 whereas the NPC study was carried
    out in 1999. During the intervening years, the Gulf Coast offshore,
    especially the deepwater, produced significant discoveries. This fact
    might have induced the NPC study to produce a larger number. In fact,
    recent studies have pointed out that deepwater Gulf may be more oil
    prone than gas prone. Thus, gas contribution from deepwater Gulf may
    not be as much as might have been originally supposed.
        At the same time, USGS is currently reviewing its resource
    estimates for unconventional gas resources. A significant amount of new
    data have been generated in many gas-prone western US basins. USGS also
    has revised its assessment methodology for such resources. Thus, some
    of the unconventional gas resources may be revised upwards
    significantly.
        Similarly, economically recoverable estimates are highly dependent
    on the economic model applied, especially the gas-price assumptions. In
    addition, assumptions for exploration and development costs, lease
    development costs, discount factors etc., may also vary from study to
    study.
        We believe that both the NPC and the USGS studies are valid and
    utilize appropriate scientific methodology. Both studies point out that
    the Nation does not lack in gas resources. What is needed is a coherent
    national energy policy that ensures that the Nation will have ample gas
    supplies to meet the growing demand.
                                     ______

        Ms. Cubin. Thank you, Dr. Mankin.
        And I now would like to introduce Peter Morton, Ph.D.,
    resource economist with The Wilderness Society. Mr. Morton.

     STATEMENT OF PETER A. MORTON, PH.D., RESOURCE ECONOMIST, THE
                           WILDERNESS SOCIETY

        Mr. Morton. Thank you, Madam Chairman. I appreciate the
    opportunity today to testify. I am Dr. Pete Morton. I am a
    resource economist in the research department of The Wilderness
    Society, a 175,000-member national conservation group that
    focuses on public land issues.
        I would like to begin today by endorsing the methods
    recommended in the RAND report. I think the authors have done
    an excellent job evaluating the strengths and shortcomings of
    past reports in order to provide the basis for developing
    improved methods for assessing oil and gas resources.
        It is important to note that the RAND report is not a
    condemnation of past assessments, or of the utility of
    quantitative modeling for policy development. Rather, reviewing
    methods, identifying shortcomings, and making recommendations
    are a healthy part of the scientific process.
        As the RAND report correctly points out, oil and gas
    leasing stipulations that dictate where, how, and when drilling
    may occur are not in many cases binding constraints on energy
    production. Economics and the rugged and remote terrain play
    more important roles in determining the economically viable
    resource.
        I would like to focus the rest of my testimony on key
    variables that I believe should be included in assessments.
        One, resource assessment should include the private and
    public land: i.e., the entire resource base, including private
    land, is needed to address the split estate issue, private land
    with Federally owned resources located underneath. Industry has
    ready access to these resources, despite the objections of many
    private land owners. In the Rocky Mountains, for example,
    approximately 35 percent of the gas lies under non-Federal
    land.
        Two, resource assessment should include oil and gas
    reserves. Quite simply, most of our oil is located where we
    have already found it; in or near existing reserves. Since
    1990, 89 percent of oil and 92 percent of gas reserve additions
    have come from existing fields, and the USGS predicts this
    trend will continue.
        Three, resource assessments should rely on USGS data. We
    believe that USGS mean estimates provide the best unbiased
    point estimates of the expected value of undiscovered oil and
    gas resources.
        Four, resource assessments should be based on the amount of
    oil and gas that is economically recoverable; not the amount
    that is technically recoverable. The opportunity cost of a
    policy or action equals the net benefits foregone as a
    consequence of that policy or action. One of the common
    mistakes made when evaluating regulations or decisions to limit
    access is the use of gross revenues when estimating opportunity
    cost, rather than net revenues. The opportunity costs of
    leasing stipulations should equal the net economic benefits of
    oil and gas foregone. This is consistent with economic theory.
        The use of technically recoverable oil and gas, rather than
    economically recoverable, is similar to the incorrect use of
    gross revenues rather than net revenues when evaluating
    policies. The Congressional Research Service has recommended
    that economically recoverable resources be the basis of policy
    analysis. If economic constraints on production are ignored,
    the assessments will over estimate the quantity of oil and gas
    potentially off limits.
        To reiterate, if the oil and gas is not economically
    feasible to extract, there are no adverse impacts on supply or
    price from lease stipulations designed to protect wildlife,
    archeological sites, recreationsites, or other public
    resources. Since policymakers should be concerned about the
    actual impacts, not hypothetical impacts, the economically
    recoverable resource is the policy relevant measure.
        And when economic criteria are considered, the amount of
    oil and gas recoverable drops significantly. In the Green River
    area of Wyoming and Colorado, for example, 90 percent of the
    gas is tight gas, located in low-permeability geologic strata.
    According to the USGS, only 7 to 15 percent of the tight gas is
    economic to recover. Similar financial constraints apply to
    coal bed methane located more than 5,000 feet under ground. So
    coal bed methane located 10,000 feet underneath a roadless
    area, for example, would have an opportunity cost of zero,
    regardless of whether that area remains roadless.
        Resource assessments should include access available with
    directional drilling. According to the National Petroleum
    Council, directional drilling allows access to resources 5 to 6
    miles from the drill site. We therefore recommend that
    assessment utilize a conservative 3-to-4-mile directional
    drilling distance.
        Resource assessment should also consider the positive
    impact of technology on access. Technological improvements
    will, over time, reduce the amount of gas that is inaccessible,
    either through drill-bit technology or making directional
    drilling feasible from a farther distance.
        Finally, it is important to recognize that while leasing
    stipulations might reduce access to oil and gas, they help
    conserve the other multiple uses enjoyed by the public on their
    land. Seasonal closures necessary to protect raptor nest sites
    and critical elk habitat, for example, conserve the wildlife
    and other multiple uses under which public land is managed.
    Legislative intent and public sentiment indicate that public
    land should not be for the exclusive use of the oil and gas
    industry.
        Conclusions: Based on the analysis of USGS data, it is
    clear that drilling public lands will do little to affect our
    energy future. We should therefore not assume that extracting
    energy resources is the highest and best use of our public
    lands, because in many cases it is not.
        The marginal benefits from wildland conservation, leaving
    public land wild and roadless, are in most cases much greater
    than the marginal opportunity cost, in terms of the energy
    resources foregone.
        Once again, thank you for the time to testify.
        [The prepared statement of Mr. Morton follows:]

     Statement of Peter A. Morton, Ph.D., Resource Economist, Ecology and
             Economics Research Department, The Wilderness Society

        I am Dr. Peter Morton, Resource Economist in the Ecology and
    Economics Research Department for The Wilderness Society, a 175,000-
    member national conservation group that focuses on public land issues.
    I appreciate the opportunity to testify today regarding methods for
    assessing oil and gas resource and the potential access restrictions on
    extracting those resources.
        I will begin by endorsing the methods recommended in the recent
    RAND report ``Assessing Gas and Oil Resources in the Intermountain
    West: Review of Methods and Framework for a New Approach.'' I think the
    authors have done an excellent job evaluating the strengths and
    shortcomings of past assessments of oil and gas (e.g. Department of
    Energy 2001, National Petroleum Council 1999), in order to provide the
    basis for developing an improved methodology for assessing the
    ``economically viable resource''. It is important to note that the RAND
    report is not a condemnation of past assessments or of the utility of
    quantitative modeling for policy development. Rather, reviewing
    methods, identifying shortcomings, and making recommendations are a
    healthy part of the scientific process.
        As the RAND report correctly points out, much of the potentially
    restricted oil and gas resources would never be developed because they
    are inaccessible for other reasons. The oil and gas leasing
    stipulations that dictate where, how, and when exploratory drilling may
    be conducted in order to protect wildlife and the environment are not,
    in many cases, binding constraints on energy production. Economics,
    terrain and technology may in fact play more important roles in
    determining the ``economically viable resource''. I strongly agree with
    RAND's recommended improvements to base assessment on the oil and gas
    that is economically recoverable, include reserves, include private
    land, account for stipulations waived, include directional drilling,
    consider pipeline access and multi-season drilling. These
    recommendation are consistent the ones I made with respect to improving
    the Department of Energy's Green River report released last year
    (Morton 2001). As the RAND report noted, including wellhead cost,
    infrastructure costs, and environmental costs in the assessment of
    viable resource will likely have the greatest impact on the amount of
    oil and gas estimated to be economically viable. Accurately assessing
    these costs is the key, and these proposed methods will make an
    important contribution to the debate.
        In the rest of my testimony I will expand on the above points,
    focusing on what I see as the key variables or parameters in the debate
    over oil and gas assessment methodologies. These include:
         the land and resource base assessed should include
    private and public land, as well as discovered reserves;
         the assessment should utilize USGS mean estimates for
    economically recoverable oil and gas (rather than technically
    recoverable), estimated using a range of prices;
         the assessment methods should use a directional drilling
    distance of 3-4 miles, consider multi-season drilling opportunities and
    consider the increased access that will be available with future
    technology; and
         account for the market and non-market economic costs
    including those associated with increasing the scale of production
    beyond the assimilative capacity of communities and ecosystems.
    Resource Assessments Should Include Private and Public Land.
        When accessing oil and gas resources it important to account for
    the entire resource base, including private and public lands. In the
    Rocky Mountains, for example, approximately 35 percent of the gas lies
    under non-federal land (RAND 2002). A narrow focus on public lands will
    overestimate the oil and gas resources subject to access restrictions.
    Because non-federal lands are not subject to Federal lease
    stipulations, oil and gas resources underlying them are subject to
    standard lease terms that are not necessarily restrictive. Using the
    total land as a basis would therefore reduce the fractions of resources
    subject to potential access restrictions. For example, based on an
    analysis of data in the National Petroleum Council report on natural
    gas (1999), when non-federal lands are included in the analysis, the
    percent of gas in the Rocky Mountain Region subject to potential access
    restriction drops from 56 percent to 35 percent. While we are critical
    of the recent Green River study by the Department of Energy, similar
    results can be derived. When non-federal lands were included, the
    percentage of access-restricted gas drops from 68 percent to 38 percent
    (RAND 2002).
        Including private land in the assessment is needed to address the
    ability of industry to access Federal resources located underneath
    private lands (i.e. split estates). Split estates are lands where the
    surface rights are privately owned and subsurface rights are Federally
    owned and can be leased to private companies. An assessment of Federal
    resources should certainly include these private lands with Federal
    subsurface resources. Split estates are a huge challenge in the west,
    and the relatively open access to these resources--despite the
    objections from private landowners--should be included in the resource
    assessment. 1
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        \1\ Much of the land in the Powder River Basin of Wyoming is split
    estate land. An assessment of resource that focuses only on public
    land, ignoring split estate land, would mischaracterize the current
    situation by dramatically underestimating the access industry has to
    oil and gas in the Powder River. This underscores the need to include
    private land in resource assessments.
    [GRAPHIC] [TIFF OMITTED] T8788.009

    Resource Assessments Should Include Oil and Gas Reserves.
        Oil and gas reserves are important to include in the assessment as
    they play significant roles in both long-term and short-term supply.
    Quite simply, most of our oil is located where we have already found
    it--in or near existing reserves. Oil and gas reserves are by
    definition economically feasible to bring to market. 2
    ``Reserve growth'' refers to the increase in economically recoverable
    oil or gas as fields are developed. Reserve growth is perhaps THE major
    component of remaining U.S. gas resources (USGS 1996). Since 1977, 79
    percent of the oil added to America's reserves came from development
    drilling in mature oil fields, while only 21 percent came from
    exploratory drilling in new areas (DOE 2002). Since 1990, the vast
    majority of reserve additions in the U.S.--89 percent of oil reserves
    additions and 92 percent of gas reserve additions--have come from
    finding new reserves in old fields (DOE 1999). These trends will
    continue as USGS estimates that the majority of economically
    recoverable oil and gas in America will come from already discovered
    reserves and growth of those reserves--in other words, oil and gas
    fields already developed and near existing infrastructure.
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        \2\ The USGS (1998) defines reserves as ``estimated quantities of
    crude oil, natural gas, or 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.''
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        The dominant role played by our oil and gas reserves is clearly
    illustrated in Table 1. Assuming America were completely dependent on
    domestic production (we currently import 56 percent of our oil), we
    currently have about 15 years of oil and 21 years of gas in reserves
    and growth of those reserves. If, through investment in conservation
    and efficiency, we reduce our dependency on imported oil to 50 percent
    for example, our oil reserves will last twice as long as indicated in
    Table 1. Existing reserves and growth of those reserves, when combined
    with public and private investments in conservation and efficiency,
    provide us with 20-40 years to make a transition to a more efficient
    economy based on alternative energy sources such as hydrogen fuel
    cells, wind, and solar.
    [GRAPHIC] [TIFF OMITTED] T8788.010

        In contrast to reserves, the USGS estimates that only a small
    portion of undiscovered oil and gas resources can be recovered with a
    profit. As shown in Table 1, drilling the Arctic Refuge and other
    public wildlands will not significantly increase our energy supply or
    transition time. Drilling for undiscovered resources on Federal land,
    including national parks, national forests, lands managed by the Bureau
    of Land Management, and national wildlife refuges, would only meet U.S.
    demand for oil and gas for 222 days and 1.7 years respectively (USGS
    1998)--with the Arctic Refuge adding an additional 0-6 months of oil.
    While the flow of oil and gas would obviously take place over longer
    periods of time, the results clearly show why we cannot drill our way
    to energy independence. Our demand is simply too high while our
    remaining undiscovered resources are too small.
        Table 2 shows the location of our reserves and indicates that
    approximately 24 percent of our oil and gas reserves are located in
    Texas, with significant quantities in Alaska and offshore in the Gulf
    of Mexico. Somewhat surprising is that nearly 4 billion barrels of oil
    (about 20 percent of our reserves) are in reserves currently not in
    production (EIA 2001). Texas and Alaska together have around 1.3
    billion barrels of oil in non-producing reserves. Significantly, non-
    producing reserves in the US have more oil than USGS estimates will be
    economically recoverable from the Arctic National Wildlife Refuge.
        In addition to the significant contribution reserves make to long-
    term supply, reserves play an important role with respect to short-term
    supply, because reserves are most immediately available for injection
    into underground storage. And, the amount of gas in underground storage
    is a major supply factor influencing short-term market price and market
    instability (DOE 2001). With relatively inelastic demand for energy in
    the short-term, lower levels of working gas in storage (short-term
    supply) will, in general, lead to higher energy prices. Figures 2 and 3
    clearly illustrate the recent inverse relationship between gas in
    storage and gas prices--the lower the storage levels the higher the
    price. From January 2000 through September 2001, working gas in storage
    was significantly below the 5-year average, resulting in the increased
    price volatility, which is reflected in the spike in natural gas
    wellhead price. Gas inventories were not the only inventories that were
    low; similar inventory shortages occurred in all the major energy
    markets. 3
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        \3\ In late 2000 and early 2001, the short-term inventories of
    major fuels were significantly below normal ranges, contributing to
    higher prices and hence the perception of an energy ``crisis.'' An
    energy plan focused on drilling wildlands does nothing to remedy the
    causes of the recent energy crisis. A question for further
    investigation: What were the circumstances that allowed inventories--
    short-term storage levels--of all major energy markets, to be at such
    low levels during late 2000 and early 2001?
    [GRAPHIC] [TIFF OMITTED] T8788.011

        The following text from monthly reports from the Department of
    Energy underscore the important role that underground storage has on
    gas prices.
        ``For the month of December [2000], the spot wellhead price
    averaged an unheard of $8.36 per thousand cubic feet. Never have spot
    gas prices at the wellhead been this high for such a sustained period
    of time''.. the predominant reason for these sustained high gas prices
    was, and still is, uneasiness about the winter supply situation. For
    much of the summer, low levels of underground storage raised concerns
    about the availability of winter supplies. Now that the winter has
    really started, the most severe assumptions about low storage levels
    have come true. The low levels of gas storage have put the spot market
    in an extremely volatile positionUnderground working gas storage levels
    are currently 31 percent below year-ago levels and a remarkable 23
    percent below the previous 5-year average (emphasis added).'' EIA
    Short-Term Energy Outlook, January 2001.
        ``The duration of these high gas prices is unprecedented'' it will
    be a while (if ever) before prices at the wellhead return to the low
    level of $2.00 per thousand cubic feet''.One factor keeping those
    prices relatively high is, once again, concern over the adequacy of
    injections into underground storage. The gas supply situation this
    injection season bears close monitoring'' (emphasis added).'' EIA Short
    Term Energy Outlook, April 2001
        ``Underground storage levels set records last month.'' For the end
    of November [2001], the storage level is estimated to have been about
    29 percent above last year's level. We project that natural gas
    wellhead prices will generally stay below $2.40 per thousand cubic feet
    through the winter.'' EIA Short-Term Energy Outlook, December 2001.
        The shortage in underground storage was perhaps the dominant causal
    factor in the spike in gas prices, the market instability, and the
    ephemeral energy crisis of 2001. Given the language included in the
    1999 Energy Policy and Conservation Act (EPCA), that emphasized
    reserves, combined with the importance of reserves for long-term supply
    as well as short-term supplies for injection into underground
    inventories, we recommend that the resource assessments include an
    analysis of the location and accessibility of gas and oil reserves.
    Resource Assessments Should Rely on USGS Data.
        Section 604 of the Energy Policy and Conservation Act Amendments of
    2000 requires an inventory that identifies United States Geological
    Survey reserve estimates of the oil and gas resources. While we
    recommend the use of USGS data, it is important to note that there is
    considerable uncertainty involved when making estimates of the
    undiscovered quantities of oil. There is geologic uncertainty as to
    whether any oil-gas even exists, and there is market uncertainty with
    respect to future oil prices. To stress the significance of this
    uncertainty, the USGS describes quantities of oil in terms of
    probabilities (Figure 4). Quantities of oil that might be economically
    recoverable are stated in terms of the 95th percentile (19 in 20),
    expected mean value, and 5th percentile (one in 20) probabilities of
    exceeding a stated quantity. Using Figure 4 as example, there is a 95%
    chance of at least volume V1 of economically recoverable oil, a 50%
    chance of at least volume V3, and a 5% chance of at least V2 of
    economically recoverable oil. We believe that the USGS expected mean
    estimates provide the best, unbiased point estimate of the expected
    value of undiscovered oil and gas resources. 4
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        \4\ The mean is technically an average for the mathematically
    derived probability distribution that is generally close to the 50-
    percent probability. However, the statistical procedure used to arrive
    at mean estimates tends to produce a figure that is greater than one
    estimated with a 50 percent probability (Economic Associates, Inc.
    1983).
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        While we support the use of mean estimates, we express considerable
    skepticism when it comes to quantities of undiscovered oil or gas
    estimated with only a 5-percent probability. Estimates with just a 5-
    percent probability can be expected to be wrong 19 out of 20 times.
    Predictions that are wrong 19 out of 20 times are rarely relevant in
    policy debates. To emphasize this point, consider the following
    example. If an environmental group ran a computer model that estimated
    global temperatures would increase 15 degrees in the next 10 years if
    we keep emitting carbon dioxide at current rates, but the model
    prediction was wrong 19 out of 20 times--would anyone take the estimate
    seriously? Would decision-makers, scientists, or the press give the
    estimate any credibility? Pro-drilling forces would certainly scoff at
    the scare tactics and pseudo-science behind a dire environmental
    prediction that may be correct only 5% of the time. With this in mind,
    we believe that quantities of oil and gas, estimated with just a 5-
    percent probability, should be heavily discounted, if not ignored, by
    decision-makers

    [GRAPHIC] [TIFF OMITTED] T8788.012

    Resource Assessments should be based on the Amount of Oil and Gas
            Economically Recoverable.
        We believe that economically recoverable amount of oil and gas--not
    the technically recoverable amount--is the correct measure of the
    opportunity costs of protecting the environment. The concept of
    opportunity costs is the appropriate construct for valuing both
    benefits and costs of public policies. Opportunity costs equal the net
    benefits foregone as a consequence of the policy or action. One of the
    common mistakes made when evaluating regulations or decisions to limit
    access, is the use of gross revenues when estimating opportunity costs,
    rather than net revenues. The opportunity costs of leasing stipulations
    should equal the net benefits of the oil or gas foregone. If the full
    cost of extracting a resource is greater than market price, the net
    benefits are negative, the resource is not an economic resource, and
    there are no opportunity costs from protecting the environment.
        Technically recoverable oil represents the quantity of oil in place
    that is recoverable using current technology but without regard to
    costs or profits. Economically recoverable oil as estimated by the USGS
    (2001) is the quantity of technically recoverable oil that can be
    recovered based on exploration, production and transportation costs,
    plus a 12 percent profit margin. The Congressional Research Service
    concludes that a useful analysis for policy purposes should focus on
    estimates of oil resources that are economically recoverable (Corn,
    Gelb and Baldwin 2001). 5 Virtually every report on gas
    supply over the last 20 years has reported results in terms of
    economically recoverable resources (Environmental Law Institute 1999).
    Since policymakers should be concerned about the actual impacts--not
    the hypothetical impacts--from lease stipulations, economically
    recoverable resources, as estimated by USGS scientists, are the policy-
    relevant measure and should be the basis for the EPCA studies.
    6
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        \5\ Corn, M.L., B.A. Gelb and P. Baldwin. 2001. The Arctic National
    Wildlife Refuge: The Next Chapter. Congressional Research Service.
    Updated August 1, 2001
        \6\ In fact we believe that EPCA requires economics to be
    considered. Section 604 of the Energy Policy and Conservation Act
    Amendments of 2000 is titled Scientific Inventory of Oil and Gas
    Reserves. Section 604 requires an inventory that identifies United
    States Geological Survey reserve estimates of the oil and gas resources
    underlying these (federal) lands. Reserves are by definition
    economically feasible to recover.
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        When economic criteria are considered the amount of oil and gas
    actually recoverable drops significantly (USGS 1998). Within the Rocky
    Mountains and Northern Great Plains, 81 percent of the undiscovered gas
    is in unconventional deposits. Of this, the USGS estimates that only 8
    and 4 percent is economically viable at $3.34 and $2 per mcf,
    respectively (RAND 2002)--underscoring the drop in accessible resources
    due solely to financial constraints on production. In the Green River
    study area, 90 percent of the technically recoverable gas is
    continuous-type, tight gas (DOE, Table 2, p. 10, 2001). The high costs
    associated with extracting continuous-type gas from low permeability
    geologic strata result in only a small percent of the technically
    recoverable gas being profitable for a company to extract. USGS
    scientists (1998) estimate that between 7 and 15 percent of technically
    recoverable, continuous-type, tight gas in the lower 48 is economically
    recoverable. The actual impacts on gas supplies from lease stipulations
    are therefore much less than estimated in the DOE Green River report.
        Similar financial constraints apply to coal bed methane (CBM).
    Papers presented at a recent coalbed methane conference indicated that
    CBM below 5000 feet, while technically recoverable, is not economical
    to extract. CBM located 10,000 feet underneath a roadless area, for
    example, would therefore have an opportunity cost of zero--even without
    roadless area protection, no one would drill for the CBM as it is not
    an economic resource. In such cases, roadless area protection would not
    be the binding constraint on production; the binding constraint is the
    financial cost associated with extracting gas 10,000 feet below the
    surface.
        We remain concerned that if the EPCA access studies continue to
    ignore economic constraints on production they will overestimate the
    quantity of oil or gas potentially off-limit, and, therefore,
    overestimate the opportunity costs associated with lease stipulations
    that protect the environment. To reiterate, if the gas is not
    economically feasible to extract, there are no adverse impacts on gas
    supply or prices from lease stipulations designed to protect wildlife,
    archeological sites, recreation sites and other public resources. The
    use of technically recoverable oil-gas rather than economically
    recoverable, is similar to incorrect use of gross revenues rather than
    net revenues when evaluating the opportunity costs of policies. It is
    for these reasons that we recommend resource assessments be based on
    economically recoverable oil and gas, not technically recoverable. When
    estimating economically recoverable oil and gas, market price is a key
    factor. To account for the economic uncertainty inherent in price
    forecasts, we recommend using the USGS high and low expected mean
    estimate of oil and gas that is economically recoverable. 7
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        \7\ Economists at the USGS estimated economically recoverable
    resources using two price scenarios ($18 and $30/barrel of oil, $2.00
    and $3.34.tcf of gas--all prices in 1996 dollars).
    ---------------------------------------------------------------------------

    Resource Assessments should fully account for the Non-market Costs
            Associated with Resource Extraction.
        The USGS economic analysis for the lower 48 only includes the
    financial costs of oil and gas production, including items such as the
    direct costs of exploration, development, and production. Not included
    in the USGS calculus are non-market costs such as the off-site
    ecological costs and cumulative negative environmental impacts that
    might result from drilling. The USGS economically recoverable analysis
    more closely resembles a financial analysis than an economic analysis.
    A financial analysis only examines costs and benefits as measured by
    market price; it is the viewpoint of private industry and is more
    concerned with profits or losses. In contrast, an economic analysis of
    benefits and costs must account for non-market benefits and costs, as
    well as those more readily observed and measured in market prices. An
    economic analysis is conducted from the viewpoint of society, which
    should also be the viewpoint of politicians and managers of the public
    estate.
        While many non-market costs are difficult to estimate, academic and
    Federal agency economists have made great advances in developing
    methods to value non-market costs (e.g. erosion, noxious weeds,
    pollution) and benefits (biodiversity conservation, ecosystem services,
    passive-use; Morton 2001) 8. Many heretofore-unquantifiable
    wildland benefits and costs are now quantifiable and available to
    agency officials responsible for developing the policies and procedures
    for guiding public land management. We therefore recommend that the
    resource assessment include full consideration of these costs. RAND
    (2002) recommendation for utilizing spatial indices of areas with
    vulnerable environments is a creative technique and, at least on the
    surface, has the potential to be an excellent method for internalizing
    the difficult-to-quantify, non-market environmental costs associated
    with energy development. The development of an appropriate
    environmental vulnerability index based on, for example riparian areas,
    steep slopes, archeological sites, critical habitat, roadless areas,
    wilderness study areas, etc., will be an important factor in the
    success of the methods proposed.
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        \8\ Morton, P. 2001. Testimony before the Subcommittee on Forests
    and Public Land Management Committee on Energy and Natural Resources,
    United States Senate, April 26, 2001.
    ---------------------------------------------------------------------------
        We also encourage the USGS to internalize non-market costs into
    future cost functions developed for estimating economically recoverable
    resources. If the economic analysis fully accounted for the non-market
    costs associated with oil and gas extraction, the quantities of oil and
    gas estimated to be economically recoverable would be less than
    reported by USGS scientists.

    Public Land Agencies Should Consider the Socio-Economic Costs
            Associated with Resource Extraction.
        While in past testimony we have focused on the environmental and
    ecological costs from oil and gas production (Morton 2001), here we
    would like to focus on the costs to communities from accelerated
    resource extraction. An historic emphasis on resource extraction
    industries has resulted in repetitious cycles of socio-economic
    distress for rural communities in the west. However, in the last 15
    years, the economies of the Rocky Mountain states have diversified and
    are not dependent on resource extraction. For many of these states and
    communities, service jobs, retirees, recreation and hunting are the
    mainstays of the economy. In the new economy, public lands have an
    indirect role in attracting non-recreational businesses and retirees.
    There is a growing body of literature suggesting that the future
    diversification of rural western economies is dependent on the
    ecological and amenity services provided by public lands in the west
    (Power 1996, Rasker 1995, Haynes and Horne 1997). These services (e.g.
    watershed protection, wildlife habitat, and scenic vistas) improve the
    quality of life, which in turn attracts new businesses and capital to
    rural communities. Public lands in the west represent natural assets
    that provide communities with a comparative advantage over other rural
    areas in diversifying their economies. As such, it is important to
    recognize and analyze the potential negative impacts of oil and gas
    exploration on the service and recreation industries, as well as on
    retirees and other households with investment income.
        Past research indicates significant social costs (e.g. seasonal
    employment, higher unemployment rates) associated with economic
    specialization and dependency on resource extractive industries. In
    essence, resource extractive communities have an inherent economic
    instability associated with them. This instability, in income and
    employment, for example, is a result of laborsaving technological
    improvements, business cycles sensitive to interest rates and housing
    starts, and fluctuations in world resource markets--macroeconomic
    forces outside local control.
        Economic instability is of concern to community leaders because if
    a local economy is unstable, economic development plans are more likely
    to fail. The economic instability created in the ``boom and bust''
    economies associated with resource extraction increases the risk
    associated with capital investment in linked industries. As such,
    resource specialization and the resulting economic instability can
    prevent the formation of forward and backward economic linkages in the
    local and regional economy and can negatively impact workers.
        Resource extractive workers tend to get stuck in a vicious cycle of
    relatively high paying jobs with frequent layoffs and unemployment.
    This cycle is what Freudenburg (1992), a sociologist, calls the
    ``intermittent positive reinforcement regime;'' one of the most
    effective of all behavioral reinforcements (Freudenburg and Gramling
    1994)
        While resource extractive workers develop high skills, such skills
    are not readily transferable to other jobs and the workers become
    overspecialized (Freudenburg and Gramling, 1994). Investment in
    education and job retraining is low because ``the potential return on
    their investment in their education is either too low or too uncertain
    to justify sacrifice (Humphrey et al. 1993). The resultant pattern of
    ``rational under-investment'' in the development of skill and other
    forms of human capital can result in reduced economic competitiveness
    in resource-dependent and specialized communities.
        The current emphasis on oil and gas exploration is pushing rural
    communities into another boom-bust cycle, and there are indications
    that the bust is already here. Between November 2001 and February 2002,
    New Mexico lost 900 jobs in oil and gas industry (New Mexico Department
    of Labor 2002). In Wyoming, over 1500 workers in oil and gas extraction
    lost their job between September 2001 and February 2002 (Wyoming
    Department of Employment Research and Planning 2002). The primary cause
    of the employment bust is the significant drop in gas prices over the
    last year.
        The current boom-bust cycle has also generated significant costs to
    communities in the Powder River Basin of Wyoming--costs that must be
    considered by public agencies rapidly promoting energy development.
    Many landowners are spending thousands of dollars on attorneys in order
    to negotiate a surface damage agreement to protect their property (i.e.
    the split estate problem). Other landowners have seen dramatic declines
    in property values. 9 The City of Gillete has experienced a
    12 to 15 percent increase in truck traffic plus a 26 percent increase
    in traffic violations between 1999 and 2000 (Pederson Planning
    Consultants 2001). As a result, the expected life of city streets has
    decreased, while road operation and maintenance costs have increased.
    Dust from poorly constructed access roads causes health problems with
    horses, reduces the grass available for cattle, and negatively impacts
    air quality and visibility. County officials and residents area
    concerned that they will have to pay for clean up and restorations
    costs as the bonds posted by CBM companies for plugging and abandoning
    a well are inadequate.
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        \9\ This is particularly true on the western side of the Basin,
    near Sheridan and Buffalo, where land values are based not on the
    agricultural values but on scenery and wildlife values (Jill Morrison,
    personal communication). One ranch, a high dollar ranch and hunting
    retreat, went up for sale for around $9 million. The ranch was under
    contract for purchase, but the buyer found out the minerals were leased
    and slated for CBM development. The buyer wanted to back out, but the
    seller agreed to a $3 million dollar reduction in the price and the
    buyer purchased the ranch for about $6million.
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        As a result of recent coalbed methane boom, Campbell County has
    seen an increase in larceny, traffic accidents, destruction of private
    property, family violence, and child abuse--resulting in the county
    spending money to add 36 cells to its existing jail. The fire
    department has seen a 40 percent increase in emergency calls between
    1997 and 2000 (Pederson Planning Consultants 2001). Similar trends have
    occurred in other counties in the Powder River Basin. There has also
    been a shift in the labor force. County workers have left for CBM jobs,
    resulting in instability in the labor force and making it more
    difficult to hire public workers (e.g. policemen, firemen) at a time
    where the counties and cities are stretched thin to handle the
    increased work load. The accelerated energy development has left many
    counties and communities unable to pay for or finance the increase in
    public service costs. We have every reason to believe that similar
    costs and burdens will be placed on other communities where public and
    private land is threatened by energy development. The socio-economic
    risks and costs associated with energy development, while perhaps
    beyond the scope of EPCA, should be acknowledged as part of the NEPA
    process involved with current energy development in the west.

    Environmental Stipulations in Oil and Gas Leases Protect Public
            Resources.
        While recognizing that stipulations have the potential to reduce
    access to oil and gas, it is important to recognize the benefits of the
    environmental stipulations. Public and scientific concerns for
    protecting sensitive lands and resources are the justification for
    including environmental protection stipulations in drilling leases on
    public land. These stipulations are designed by agency professionals to
    protect multiple public resources, including water quality, critical
    winter range for elk and antelope, sage grouse leks, archeological
    sites, and recreation sites. Seasonal closures, necessary to protect
    raptor nest sites, elk populations, and the quality of the outdoor
    recreation experience, may slow down the rate of gas exploitation but
    protect the wildlife and other multiple uses under which public land is
    managed, as well as the quality of life for local residents. Such
    protection is warranted economically, as watershed protection, hunting,
    fishing, and recreation generate significantly more economic benefits
    to all Americans, including affected residents and businesses in the
    Rocky Mountain Region, than do oil and gas extraction. Legislative
    intent and public sentiment indicate that public lands should not be
    for the exclusive use of the oil and gas industries and that managers
    must attempt to balance the many uses that occur on public land. Leases
    with environmental protection stipulations help internalize the
    environmental and ecological costs associated with oil and gas
    extraction by protecting other multiple uses enjoyed by the public.

    Resource Assessments Should Include the Potential Access Available with
            Directional Drilling.
        The Green River EPCA study utilized a directional drilling distance
    of just 0.25 mile (1/4 mile) when examining access to resources, even
    though industry officials have repeatedly asserted that contemporary
    drilling technology enables operators to reach oil and gas resources at
    considerable distances from a drilling site. 10 For example,
    the National Petroleum Council (1999, page 15) states that ``extended
    reach drilling allow access to resources 5 to 6 miles from the drill
    site''. In addition, a 1999 DOE report titled ``Environmental benefits
    of advanced oil and gas exploration and production technology'' states
    that ``resources'' can now be contacted and produced without disrupting
    surface features above them'' (page 13). We recommend that the EPCA
    studies assume a slant drilling distance that is more consistent with
    current technology and industry statements regarding the efficacy of,
    and advances in, slant drilling. For example, a 3-4 mile slant drilling
    distance would be reasonable to analyze. 11
    ---------------------------------------------------------------------------
        \10\ Based on a discussion with BLM officials, the 0.25 mile
    drilling distance used in the Green River study was selected as being
    the distance that is feasible for industry to drill. The dominating
    factor in determining the feasibility of slant drilling is economics,
    as slant drilling can be expensive. The consideration of economic
    factors in determining the feasible distance for slant drilling
    underscores the need to also include economic factors when estimating
    oil and gas resources affected by lease stipulations. While there might
    be significant oil and gas resources in the Green River Basin, if they
    are not economically feasible to extract, they should not be considered
    inaccessible due to leasing stipulations. The implicit inclusion of
    economic factors when determining the feasibility of slant drilling
    distances is inconsistent with the exclusion of economic factors when
    estimating the feasibility of recovering resources. These
    methodological inconsistencies must be addressed in order to improve
    the reliability of the findings in future EPCA reports.
        \11\ With over 400,000 miles of road on the national forests alone
    and a backlog of over $8 billion dollar in road maintenance, lack of
    access to oil and gas on public lands is not really an issue. On
    average, the annual maintenance cost of a mile of road is about $1,500
    per mile (USDA FS 1999). Each new mile of road added to the FS
    transportation system competes for limited road maintenance funding, as
    Congressional funding is less than 20% of the funding necessary to
    maintain the existing road infrastructure. One must seriously question
    the wisdom of building more roads when current roads can't be
    maintained, and each year's unmet maintenance needs increase the
    backlog as roads deteriorate and the costs of repair increase over
    time.
    ---------------------------------------------------------------------------

    Resource Assessments Should Consider the Potential to Increase Access
            with Future Technology.
        Technological improvements are often cited as the reason that
    predicted costs of compliance often turn out to be less than actual
    costs (OTA 1995). Trends in technological improvements should be
    incorporated into the resource assessment because technological
    improvements will, in general, increase access and reduce the amount of
    oil or gas estimated to be inaccessible with today's technology.
    History has shown that advances in drilling technology, such as remote
    sensing methods, have increased industry's ability to access resources
    in an environmentally friendly manner. Advances in remote sensing
    technology, for example, will improve the accuracy of drilling and will
    make slant drilling economically feasible from greater and greater
    distances, perhaps 6-10 miles or more.
        Advances in drilling technology (e.g. improved drill bits) will
    also reduce drill times, reducing any impact seasonal wildlife
    stipulations may have on the ability of industry to access resources.
    For example, a 15,000-foot well in Oklahoma takes about 39 days to
    drill, a decrease from 80 days in 1970 (DOE 1999). Technological
    advances will reduce the quantity of oil and gas estimated to be
    inaccessible due to current leasing stipulations. We therefore
    recommend that the EPCA studies include a sensitivity analysis of the
    increasing access to resources on public land that results from
    technological innovations by the oil and gas industry. Information on
    the marginal increase in accessible resources from advances in
    technology will provide industry an incentive for investing in such
    technology.

    Resource Assessments Must Consider Cumulative Impacts and the
            ``Diseconomies of Scale.''
        When examining the economically viable resource, it is important to
    recognize the cumulative negative impacts from increasing the scale of
    production. While increasing the scale of production typically
    decreases the financial costs to a producer (i.e. economies of scale),
    larger scale projects will, in general, increase the non-market
    economic and community costs--resulting in what we will call the
    ``diseconomies of scale''. As a result, the socio-economic and
    environmental constraints on the scale of oil and gas production will
    increase costs and may limit full development of technically
    recoverable resources.
        While oil and gas development on a small scale may have limited
    negative impact on communities and ecosystems, as the scale of
    production increases, the ability of those systems to assimilate the
    impacts is jeopardized. For example, as the scale of coalbed methane
    increased in the Powder River Basin of Wyoming, the increase in
    traffic, crime and immigrants overwhelmed the capacity and budgets of
    communities and counties for handling these problems. While the CBM may
    be financially recoverable, local community concerns over the
    cumulative negative impacts from future production will increase the
    cost and may prevent the development from actually occurring.
        Similarly, the cumulative negative impacts of CBM production on
    clean air and clean water may be a constraining factor on the scale of
    production--irrespective of whether the CBM is financially or
    technically feasible to extract. The amount of CBM wells drilled in
    Wyoming have increased dramatically (Figure 5). As a result, the amount
    of water discharged from CBM wells in Wyoming has skyrocketed in recent
    years, increasing from approximately 98 million gallons (300 acre feet)
    per year in 1992, to 5.5 billion gallons (17,000 acre feet) per year in
    1999 (Wyoming State Engineer's Office cited in Darin 2000). The water
    discharged from oil and gas wells is highly saline with a very high
    sodium absorption ratio (SAR)--a ratio that affects how water interacts
    with soil. Water with a high SAR can permanently change chemical
    composition of soils, reducing water permeability and thereby
    decreasing native plant and irrigated crop productivity. To be
    sustainable and to maintain water quality, the increase in SAR water
    should not exceed the SAR assimilative capacity of the regional river
    systems. As the scale of CBM production increases, it is more likely
    that the cumulative quantities of SAR will exceed the assimilative
    capacity of regional watersheds.

    [GRAPHIC] [TIFF OMITTED] T8788.013

        Similar arguments can be made with respect to the negative impacts
    of CBM production on air quality. Based on an analysis by Bob Yunke of
    the Environmental Defense Fund (2002), the total emissions associated
    with developing the more than 50,000 wells expected in the Powder River
    will exceed Clean Air Act limits in the surrounding Class I airsheds
    (Northern Cheyenne Reservation in Montana and the Badlands National
    Park in South Dakota). As a result of CBM development in the Powder
    River, there could be a 60 percent decrease in visibility in the
    Badlands on peak air pollution day. The loss of clear skies will reduce
    the quality of life for local residents and decrease the quality of the
    recreational experiences in nearby wilderness areas and national
    parks--all of which will translate to negative economic impacts on
    local communities.
        In summary, the assimilative capacity of communities and ecosystems
    represent constraints on oil and gas production that may limit future
    production, even though the oil-gas may be financially feasible for a
    corporation to produce. Cumulative impacts and constraints on the scale
    of production should therefore be considered when assessing
    economically viable resource,

    Conclusions
        Based on analysis of USGS data, it is clear that drilling public
    wildlands in the west will do little to affect our energy future.
    Public lands provide greater benefits to society when left in their
    wild and roadless condition for current and future generations to
    enjoy. The marginal benefits from wildland conservation are, in most
    cases, much greater than the marginal costs in the form of the
    undiscovered, economically recoverable energy resources foregone.
        The current fixation on access to undiscovered resources in remote
    wildlands overestimates the importance of undiscovered resources in
    reducing market instability and reducing the energy prices paid by
    consumers. Decision-makers concerned about high energy prices and price
    volatility (the main components of the energy ``crisis'') would be
    better served by focusing on transporting gas from existing reserves
    into short-term storage. In addition, requiring industry to maintain a
    higher minimum underground storage level will reduce price volatility
    and the cause of high energy costs for consumers and businesses. In
    contrast, drilling public wildlands will do little to address the root
    causes of the 2001 ``energy crisis'', nor will it reduce the energy
    costs for families--despite claims to the contrary made by industry
    officials.
        Regardless of whether there is high access to resources or high
    investment in drilling technology, the downward trend in America's
    crude oil production will continue. In other words, we have already
    discovered the best reserves America had to offer. Of the 4.6 million
    oil wells worldwide, 3.4 million have been drilled in the U.S and a
    majority of America's wells were dry wells. Why subsidize the drilling
    of more dry wells? Rather than propping up old industries, increasing
    profit margins for corporations, and sacrificing America's remaining
    wildlands, taxpayer subsidies would be far better spent promoting new
    markets in alternative energy, efficiency and conservation. The bottom
    line is that the first country to wean itself from oil wins.
    References (partial list).
        U.S. Office of Technology Assessment 1995. Gauging control
    technology and regulatory impacts in occupational safety and health.
    Cited in OMB draft report
        U.S. Department of Energy, 1999. Environmental benefits of advanced
    oil and gas exploration and production technology. Office of Fossil
    Fuel
        U.S. Office of Management and Budget, 1996. Economic analysis of
    Federal regulations under executive order 12866.
                                     ______

        [Responses to questions submitted for the record by Mr.
    Morton follow:]

        Oversight Hearing on Oil and Gas Resource Assessment Methodology

                                 April 18, 2002

                    Follow-up questions from Chairman Cubin

                               Pete Morton, Ph.D.

                             The Wilderness Society

    1). You have criticized the DOE Green River Basin assessment as biased
            because of gas industry participation. How could a useful
            assessment of oil and gas resources be done without the
            participation of those who study and find America's oil and gas
            fields?
        A useful, unbiased assessment could be completed by utilizing the
    team of USGS scientists, including Emil Attanasi at the USGS, which
    completed the recent USGS Oil and Gas Assessment for the U.S. Of
    course, such studies should be critically reviewed by interested
    parties, including government and university scientists, the energy
    industry, and the environmental community.
        For the most part, I have no quarrel with the energy industry's
    participation in such studies. I do remain concerned with the practice
    of letting the energy industry dominate such studies, often to the
    absolute exclusion of input from other stakeholders. The energy
    industry is not the only entity with knowledge of resources on our
    public lands. And the energy industry is the LAST entity that is likely
    to offer an impartial assessment of the regulations governing energy
    development on public lands. Nor does the energy industry have adequate
    expertise on the non-energy resources--wildlife, fishing, recreation,
    watershed protection, or scenic beauty--that American's value from
    their public lands. Oil and gas are not the only, nor even the most
    important, values on America's public lands. Any analysis that excludes
    full consideration of these other broad public values is sure to be
    biased in industry's favor.
        With respect to the Green River Basin assessment, the lack of
    critical review of the assumptions, methods and parameters used in the
    study resulted in a biased report that overestimated the amount of
    economically recoverable gas made inaccessible due to environmental
    protection stipulations included in oil and gas leases.
    2) Do you ever plan to release any part except the Executive Summary,
            of the report entitled ``The Department of Energy's ``Federal
            Lands Analysis Natural Gas Assessment : A Case of Expediency
            over Science?'' If so, when?
        We were hoping to have this report published by now, but as you
    know, the last year has been extremely busy for those concerned with
    the health of the land, and we are behind in publishing the full
    report. We fully expect to include the text from the referenced study
    in an upcoming Wilderness Society report on oil and gas in the West. We
    hope to finish this report by the end of the summer and will be glad to
    send you a copy. Thank you for your interest in our research.
                                     ______

        Ms. Cubin. We certainly thank you for your testimony.
        Our next witness will be Ray Seegmiller, Chairman,
    President, and Chief Executive Officer, testifying on behalf of
    Cabot Oil and Gas Corporation, and the Domestic Petroleum
    Council. Mr. Seegmiller.

       STATEMENT OF RAY SEEGMILLER, CHAIRMAN AND CHIEF EXECUTIVE
     OFFICER, CABOT OIL AND GAS CORPORATION, AND PAST CHAIRMAN AND
                  DIRECTOR, DOMESTIC PETROLEUM COUNCIL

        Mr. Seegmiller. Thank you, Madam Chairman. I appreciate the
    opportunity to testify before the Subcommittee today. I am Ray
    Seegmiller, Chairman and Chief Executive Officer of Cabot Oil
    and Gas. I am extremely pleased to be with you today to address
    a critical issue which, unfortunately, is often misunderstood
    by Members of Congress and Administration officials alike. It
    is the issue of how Cabot and hundreds of other companies like
    Cabot make decisions that determine the supply of oil and
    natural gas to fuel our economy, generate our power and heat
    our homes. In another way, it is a question of how we put
    dollars at risk and decide whether or where to explore and find
    our energy sources for the future.
        Today I speak not only for Cabot, but also for the Domestic
    Petroleum Council, an association of the producing community's
    22 largest and most active independent exploration companies.
    And at this time, I would like to request that my full written
    statement be entered into the record. Thank you.
        Continuing analysis of our domestic energy resource base,
    especially natural gas and the factors that restrict access to
    it, are extremely important in helping policymakers understand
    the direction we need to be moving to supply future demand.
        The studies of the National Petroleum Council, as well as
    ongoing studies by several executive branch agencies, are very
    helpful to government and the general public with respect to
    resource assessment. Of particular use to the government and
    the public is analysis of specific restrictions on exploration
    and production. However, we also hear hypothetical and often
    illogical statements that are either confusing or simply
    irrelevant to those of us who make our living by putting real
    money to work in the hope of finding real resources.
        For example, statements to the effect that a large
    percentage of public lands are open to oil and natural gas
    leasing and development continually ignore the fact that only a
    portion of the most prospective areas may be available. Those
    who claim that we should not be concerned about access until we
    are sure that resource exploration and production will be
    economic, only stifle development.
        Likewise, those who claim that issues regarding capital
    infrastructure, such as the development of pipeline and
    gathering system capacity, should come before resolving access
    issues, turn the decision-making process totally upside down.
        We, the producers, must first believe with confidence that
    we have access to the resource, prior to tackling those down-
    the-line issues. Think about it, without resource access, there
    is no reason to resolve those other challenges. Nothing else
    matters, unless there is available resource to find, develop
    and produce.
        So let me do a quick summary of how we at Cabot explore for
    natural gas regardless of the policy-oriented studies. As an
    explorer for natural gas for over a hundred years, Cabot Oil
    and Gas has worked with many other companies in our business.
    Each company's approach to the exploration of natural gas is
    very consistent, even though the final evaluation of potential
    reserves may differ drastically.
        What drives exploration success is primarily good geology.
    By this, I mean we need to acquire as much data about an area
    that is economically feasible and provides a reasonable
    expectation of making a discovery. This requires confidence
    that we will have access to the acreage being studied.
        Once we are confident we will have access, our
    geoscientists map the surface and sub-surface geology, looking
    for clues that suggest the presence of hydrocarbons and
    reservoir-quality rock. To do this, we utilize a variety of
    data, including: surface geological maps; remote sensing
    techniques; electric logs from well bores in the area; and
    seismic data, whether it be 2-D or 3-D. If the data is not
    available from outside sources, we may have to hire a
    contractor to do this field work, such as seismic surveys.
        Almost always, we have to obtain permits to do this work,
    even though we have access to the area under review. Being able
    to acquire this data on a timely basis is very important to the
    economics of any such project.
        On a step-by-step basis, Cabot proceeds with an exploration
    process as follows. And by the way, in consideration of time, I
    will only list them in sequence. There is more detail in my
    written report.
        First, we do a regional geologic analysis.
        Second, we map any hydro-bearing trends, like sandstones,
    etcetera.
        Then we map the geologic structure.
        Fourth, we will develop leads where we think there might be
    hydrocarbons present.
        And next, if we feel there is a possibility of
    hydrocarbons, we will obviously shoot 3-D or 2-D seismic.
        Once we have this data, we will integrate it into the sub-
    surface geology.
        Then we will determine whether or not the drilling
    prospects are there, and second, we will rank them as to
    potential.
        Then we determine the risk-weighted rate of return of the
    total prospect, including infrastructure and the transportation
    costs to get this product to market. This may include
    transportation. It may be stripping, as far as impurities,
    nitrogen, CO2, etcetera.
        If the potential return is satisfactory in our estimation,
    at the expected gas prices we see for the future, we would
    apply for a drilling permit and would have to meet all of the
    environmental issues that are in that area.
        And last, then, of course, we drill the well.
        The cost of the first well in some of these remote areas
    can be very expensive. However, if the reservoir potential is
    perceived to be large enough, we will take that risk. Once a
    discovery is made, the infrastructure to get the gas to market
    will be put in place, if the prospect size justifies the
    additional cost. As in the movie ``Field of Dreams''--``Build
    it, and they will come''--In our case, if a discovery is large
    enough, the infrastructure will be there and the processing
    plants will be there to take care of this production.
        The point I want to make is that without access to the
    acreage, there is no reason for a company like Cabot or all of
    our peers to put their dollars at risk; and therefore, none of
    the above is possible. Cabot has followed this process in two
    recent cases on Federal lands where we acquired access. In each
    case, there could have been an argument that infrastructure did
    not exist and there were no assurances of an economic resource.
    But it was our job as a company to take that resource risk.
        The first case is in the Paradox Basin in southwest
    Colorado. And this is an area where we have had two very
    successful wells, and the infrastructure, of course, was put in
    place. Another was in Wyoming, which was in the Wind River
    Basin. And that is in my written testimony.
        In final conclusion, I would just like to conclude by
    saying that we, Cabot, and other producers, continue to do our
    best to apply the latest technology in the search for the
    nation's natural gas and oil. But we do it based on real-world
    information, in areas where we believe we will have access to
    the resource and then be able to work with the Federal, state
    and local governments, surface owners and users, as well as
    others, to ensure that what we do is environmentally sound and
    in our collective best interests.
        Thank you very much for your attention. And I am glad to be
    here to answer any questions.
        [The prepared statement of Mr. Seegmiller follows:]

      Statement of Ray Seegmiller, Chairman and Chief Executive Officer,
     Cabot Oil & Gas Corporation, and Past Chairman and Director, Domestic
                               Petroleum Council

        Madam Chairman and Members of the Subcommittee, my name is Ray
    Seegmiller and I am the Chairman and Chief Executive Officer of Cabot
    Oil & Gas Corporation.
        I'm extremely pleased to be with you today to address a critical
    issue which, unfortunately, is often misunderstood by members of
    Congress and Administration officials alike. It is the issue of how
    Cabot and the hundreds of other companies like Cabot, make decisions,
    which determine the supply of oil and natural gas to fuel our economy,
    generate our power and heat our homes.
        In another way, it is a question of how we decide whether or where
    to explore with the hope of finding energy supplies.
        Today, I speak not only for Cabot, but also for the Domestic
    Petroleum Council, an association of the producing community's 22
    largest and most active independent exploration companies.
        Continuing analysis of our domestic energy resource base,
    especially natural gas and the factors which restrict access to it, are
    extremely important in helping policymakers understand the direction we
    need to be moving to supply future demand.
        The studies of the National Petroleum Council as well as ongoing
    studies by several Executive Branch agencies are very helpful to
    government and the general public with respect to resource assessments.
    Of particular use to the government and the public is analysis of
    specific restrictions on exploration and production. However, we also
    hear hypothetical and often illogical statements that are either
    confusing or simply irrelevant to those of us who make a living by
    putting at risk real dollars in the hope of finding real resources.
        For example, statements to the effect that a large percentage of
    public lands are open to oil and natural gas leasing and development
    continually ignore the fact that only a portion of the most prospective
    areas may be available. Those who claim that we should not be concerned
    about access until we are sure that resource exploration and production
    will be economic; will only stifle development. Likewise, those who
    claim that issues regarding capital infrastructure, such as development
    of pipeline and gathering system capacity, should come before resolving
    access issues turn the decision making process totally upside-down.
        We, the producers, must first believe, with confidence that we can
    access the resource prior to tackling those ``down the line'' issues.
    Think about it, without resource access there is no reason to resolve
    those other challenges. Nothing else matters unless there is an
    available resource to find, develop, and produce.
        So, let me now do a quick summary of how we at Cabot Oil & Gas
    Corporation explore for natural gas and oil, regardless of the policy-
    oriented studies.
        Cabot Oil & Gas Corporation is a domestic explorer and producer of
    natural gas with over 1.2 Tcfe of reserves. The Company's four core
    areas are the onshore Gulf Coast, Appalachia, the Mid-Continent and the
    Rocky Mountains. In the Rocky Mountains we currently have over 500
    natural gas wells, most of which are in Wyoming and we drill between
    20-50 wells per year in that area. Mostly on Federal lands in western
    Wyoming.
        As an explorer for natural gas reserves for over 100 years Cabot
    Oil & Gas has worked with many of the other companies in our business.
    Each company's approach to the exploration for natural gas is very
    consistent even though the final evaluation of potential reserves may
    differ.
        What drives exploration success is primarily good geology. By this,
    I mean you need to acquire as much data about an area that is
    economically feasible and provides a reasonable expectation of making a
    discovery. This requires our confidence that we will have access to the
    acreage being studied.
        Once we are confident we will have access, our geoscientists map
    the surface and sub-surface geology looking for clues that suggest the
    presence of hydrocarbons in reservoir quality rocks. To do this we
    utilize a variety of data including surface geologic maps, remote
    sensing techniques (i.e., gravity, magnetic and geochemical), electric
    logs from any well bores in the area and seismic data (both two
    dimensional and three dimensional). If the data is not available from
    outside sources we may have to hire contractors to do field work such
    as seismic surveys. Almost always we have to obtain permits to do this
    work even though we have access to the area under review. Being able to
    acquire this data on a timely basis is very important to the economics
    on any such project.
        On a step by step basis, Cabot proceeds with an exploration project
    as follows:
         1. Regional geologic analysis--In the area of interest and the
    region surrounding it what are the indications of hydrocarbon bearing
    formations.
         2. Map the sandstone trends--Map the reservoir rock trends in the
    area and estimate their porosity and permeability by looking at
    outcrops, well bore data in the region (if any), etc. Sandstone
    pinchouts associated with effective seals could hold entrapped
    hydrocarbons.
         3. Map the geologic structure--Map the simple anticlines, faults
    and structural trends. These could provide traps for hydrocarbon
    accumulation.
         4. Develop lead ideas--From the previously completed data
    determine if there are areas that might potentially hold hydrocarbons.
         5. Acquire seismic data, either 2-D or 3-D, over the potential
    hydrocarbon areas.
         6. Map the seismic and integrate it into the subsurface geology
    previously prepared.
         7. Determine those drilling prospects with the highest potential.
         8. Determine the potential risk weighted rate of return for the
    total prospect including infrastructure and transportation costs.
         9. If potential return is satisfactory at expected gas prices--
    apply for a drilling permit and comply with all environmental issues.
        10. Drill the first well.
        The cost of the first well in certain areas can be very expensive
    however, if the reservoir potential is perceived to be large enough we
    will take that risk. Once a discovery is made, the infrastructure to
    get the gas to market will be put in place if the prospect size
    justifies the additional costs. As in the movie Field of Dreams--
    ``Build it and they will come''. In this case if the discovery is large
    enough the infrastructure will come.
        The point I want to make is that without access to the acreage none
    of the above is possible.
        Cabot has followed this process in two recent cases on Federal
    lands where we acquired access. In each case there could have been an
    argument that infrastructure did not exist and there were no assurances
    of an economic resource. But, it's our job to take the resource risks,
    so the first case in the Paradox basin of southwest Colorado with our
    partners, we prepared the regional geologic analysis, followed with
    seismic acquisition, which resulted in the drilling of two significant
    producing wells, with more to follow. These discoveries more than
    justified the pipeline extension to get the gas to market. In another
    area we drilled a dry hole and we are now reviewing our geology using
    the new data from this well. Cabot alone has spent over $8 million in
    seismic and drilling on this 300,000 acre play so far.
        In the Wind River Basin of central Wyoming, Cabot is currently
    preparing to drill the second wildcat well on a 60,000-acre block where
    we followed this same procedure. We did our basic homework in
    evaluating all the available surface and subsurface data, shot over 100
    square miles of three dimensional seismic and then mapped several
    structural prospects. The well on the first prospect was dry. We will
    drill the second prospect his fall, which is a large structural trap
    that could hold substantial reserves. To date, Cabot alone has spent
    close to $3 million for acreage, seismic and well costs.
        Finally, let me add a footnote before concluding my remarks.
    Despite the best efforts of the exploration and production sector or
    the government, our projections are often conservative when it comes to
    energy resources. We'll continue to be conservative because of the
    risks involved, but consider just two examples of the national benefit
    from companies that were willing to take the risk, and applying the
    latest technology, despite conservative--some would say pessimistic--
    resource estimates.
        The initial reserve estimate for Alaska's Prudhoe Bay field, North
    America's largest oil field, was 9.6 billion barrels of technically
    recoverable oil based on a recovery factor of about 40 per cent. This
    field has now produced more than the original estimate and eventual
    recovery is now expected to exceed 65 per cent, or 15 billion barrels.
        In the Green River Basin of Wyoming, a fledgling McMurry Oil
    Company managed to ``bring to production'' in 1992 two small wells that
    were more than thirty miles from the nearest gathering line. That
    field, the Jonah Field, now produces in excess of 700,000 mcf/day,
    enough gas to heat most of southern California on a cold winter day.
    During the first year of production, there was one summer month where
    the mainline price for gas was $1.14/MMBtu (meaning a wellhead netback
    price of less than $.75/MMBtu), but with improved pricing and strong
    production the area has been very economic. The average price for gas
    in the Green River Basin in 2001 was $3.65/MMBtu
        In conclusion, we'll continue to do our best to apply the latest
    technology in the search for the nation's natural gas and oil. But
    we'll do it based on real-world information in areas where we believe
    we'll be able to access the resource and then be able to work with the
    Federal, state and local governments, surface owners and users as well
    as others to ensure that what we do is environmentally sound and in our
    collective best interests.
        Thank you for your attention. I'd be glad to answer any questions
    you may have.
                                     ______

        [Responses to questions submitted for the record by Mr.
    Seegmiller follow:]

                                  May 1, 2002

    Ms. Daisy Minter
    Committee on Resources
    Subcommittee on Energy & Mineral Resources
    U.S. House of Representatives
    1626 Longworth House Office Building
    Washington, D.C. 20515

    Dear Ms. Minter,

        The letter is being submitted as a result of the additional
    questions outlined in Chairman Cubin's letter dated April 23, 2002 from
    members of the Subcommittee on Energy & Mineral Resources. The
    questions are in the order submitted with the responses requested for
    the hearing record.

    Questions from the Majority

    1. Some have criticized the NPC study as biased towards the oil
            industry. What interest does the industry have in inflating oil
            and gas resources in a regional assessment? Can a useful
            regional oil and gas assessment be made without the
            participation of the industry?
        The energy industry does not have an interest in inflating resource
    estimates. One could make the argument that it has an interest in
    presenting rather conservative estimates of the resource base. Dismal
    projections of resource estimates would make for easier analytical
    argument for increased access.
        It should be noted that the NPC Study was not the most optimistic
    resources base assessment at the time of its publication. The 2000 GRI
    Baseline Study, released several months after the NPC Study, estimated
    the Lower 48 resource base at 1,748 TCF versus the 1,466 TCF NPC
    estimate.
        Without industry's insights into exploration and production
    methodology, we believe that an objective assessment would be very
    difficult.

    2a. Mr. Seegmiller, as an oil and gas operator in the Rocky Mountains,
            would you agree with Mr. Goerold's and Mr. Morton's criticism
            of the use of , mile directional drilling limit for the Green
            River Basin Gas Study when examining access to gas resources
            under lands with a ``no surface occupancy'' stipulation?
        As Dr. William Whitsitt stated in his follow-up letter to you dated
    April 24, 2002, ``While it is true that industry has demonstrated that
    it can directionally drill 5 or 6 miles, that does no mean it can be
    done everywhere. And it is not a viable practice in exploration
    settings, especially in the Rockies.''
        The geology of the Rockies is very complex and principally ``hard
    rock'' country. Requiring directional drilling in excess of , mile
    would in most cases make any potential drilling uneconomic.

    2b. Mr. Morton further states that the EPCA studies should assume a
            directional drilling distance that is more realistic, 4 to 5
            miles. Given your considerable experience, is this reasonable
            at the present time or in the, say next 10 years given the
            economics of exploring and developing Rocky Mountain gas
            deposits? Do you know of any areas where 6-mile directional
            drilling is economic?
        In Alaska there is up to six-mile directional drilling. However,
    this is not the case in the Rockies for the following reasons:
        a. The geology of the Rockies is more complex than the northern
    slope of Alaska. In fact when you refer to the Rockies, you are talking
    about a very heterogeneous environment (from a geological standpoint)
    vis-a-vis Alaska. The geology of the Green River Basin will be
    different from the Wind River Basin, which will be different from the
    Powder River Basin and so on. As an illustration of the geologic
    complexity, approximately 85% of the oil and gas resources in the
    Rockies are unconventional gas (on an energy-equivalent basis).
    Unconventional gas is much more risky to develop, thus the use of long-
    range directional drilling would be limited. The more complex the
    environment that you are drilling into, the more mitigating
    circumstances come up, like higher drilling costs.
        b. Aside from geology, targeted reserve sizes matter also. The
    drilling costs of these long deviated holes, such as those in Alaska,
    are a lot higher than vertical holes. This is due to 1) the more
    complex (expensive) equipment needed and 2) penetration rates slow
    down. In Alaska this is acceptable because the reserve estimates per
    well bore are substantial. In the Rockies, extremely high reserve
    estimates per well bore are the exception rather than the rule.
        c. While it is true that industry can directional drill 5 or 6
    miles, this is not a practice in EXPLORATION settings, especially in
    the Rockies. The composition of the industry in the Rockies is
    different from Alaska. More independents and less majors, such that the
    tendency to use directional drilling will be less, all other things
    being equal, because of the higher financial risks.

    3. In the Rocky Mountains, have areas that are currently restricted
            from oil and gas exploration always been closed to such
            development?
        We understand that exploration activity took place for several
    decades in many of the areas which are now considered ``off-limits'' to
    exploration.

    4. Is there any useful data available from previous oil & gas activity
            in areas that were previously open, but are now closed to
            development?
        In some areas there is limited data available, but it's
    questionable how useful the data would be today given the technological
    advances of the last decade. Acquiring useful exploration data to
    justify the exploration risk will require open access to these areas.

    5. Can you give us an example where a currently closed area of the
            Rockies might have developed into a significant discovery of
            reserves?
        There has been significant interest by a number of industry
    participants in the Rocky Mountain front of Montana due to the
    significant potential for new discoveries that would provide needed
    fuel for our nation.

    Questions from the Democrats

    1. Mr. Seegmiller, what percentage of your high yield wells are
            adjacent to, part of, existing reserves? In your experience,
            are most deposits found close to known reserves or are they
            more ``the luck of the draw?''
        Historically our highest yield wells have been discoveries in new
    prospect areas. Non-producing reserves adjacent to producing reserves
    are considered in a company's reserve base as proven or probable
    reserves, so they are not considered new discoveries. We find new
    reserves through the extensive technical efforts of our geoscientists
    once we have access to a prospective area, not by ``the luck of the
    draw''.

    2. Would you agree that when searching for new gas discoveries, the
            size of the minimum economically viable field is greater the
            farther the new discovery is from existing pipeline
            infrastructure?--see answer under 3.

    3. And to follow-up, that in general, the minimum economic field size
            decreases if the gas discovery is closer to existing pipeline
            infrastructure?
        Economics are dependent primarily on the size of a discovery. Gas
    and oil prices will fluctuate over time and are difficult to forecast,
    while pipeline infrastructure is only put in place to connect new
    discoveries. Thus, most significant discoveries are made in areas where
    there is not existing pipeline infrastructure and the nearest pipeline
    infrastructure must be extended to the new discovery. An operator, like
    ourselves, wouldn't drill a new prospect if we felt the reserve
    potential was not large enough to justify the extension of an existing
    pipeline to the new field.

    4. Would not you agree with the RAND report, that proximity to pipeline
            infrastructure is an important factor to consider when
            estimating the economically viable resource?
        The RAND report has it backwards; pipeline infrastructure is only
    put in place to new discoveries whose reserves are adequate to justify
    the incremental cost. Thus, if we had to wait until pipelines were
    extended to areas that may contain oil and gas reserves to drill the
    first well in a new prospect, it wouldn't happen and companies like
    ourselves would gradually go out of business due to the inability to
    replace our depleting reserve base.
        I hope the above comments are useful. Should you or anyone on the
    subcommittee have any questions or need additional information, please
    contact Greg Moredock at (281) 589-4679.
    Sincerely,

    Ray Seegmiller
    Chairman and Chief Executive Officer
    Cabot Oil & Gas Corporation
                                     ______

        Ms. Cubin. Thank you, Mr. Seegmiller.
        The last witness on panel two is ill today, and unable to
    make it here to testify. I am satisfied that he really can't
    make it. And so, without objection, his testimony will be
    entered into the record. And questions from the Committee can
    be sent to him, as well.
        [The prepared statement of Mr. W. Thomas Goerold follows:]

      Statement of W. Thomas Goerold, Ph.D., Resource Economist, Owner of
                           Lookout Mountain Analysis

        I am Dr. Thomas Goerold, Resource Economist and Owner of Lookout
    Mountain Analysis in Golden, Colorado. My firm specializes in analyzing
    many different policy alternatives to domestic and foreign energy and
    mineral issues.
        I appreciate the opportunity to testify today regarding the impacts
    of different oil and gas resource estimates and their potential impacts
    on energy policy and energy security. My testimony will not concentrate
    so much on examining the different number estimates that may be drawn
    from these different assessment methodologies, but instead will look
    more broadly at how to best use this nation's energy policy tools to
    achieve energy security. My testimony examines the implications on
    energy policy of recognizing the increasingly finite supply of oil and
    gas remaining in the U.S.
        The first section examines attempts by the U.S. Geological Survey
    (USGS) to estimate the amount of oil remaining in the U.S. and the
    world. After examining the distribution of U.S. and world oil and gas
    resources, the remainder of this testimony analyzes some of the most
    effective U.S. energy policies.
        I would like to introduce into the record two reports that I have
    prepared that are particularly relevant to energy resource assessment
    methodologies and results; (1) Examination and Critique of ARI Report:
    Undiscovered Natural Gas and Petroleum Resources Beneath Inventoried
    Roadless and Special Designated Areas on Forest Service Lands Analysis
    and Results, with Additional Discussion of U.S. Geological Survey and
    National Petroleum Council Reports; and (2) A Brief Examination of the
    Adequacy of Future U.S. Natural Gas Infrastructure and Resources and
    The Role of Public Lands in U.S. Natural Gas Production.

                   USGS WORLD AND U.S. OIL AND GAS ASSESSMENT

        The USGS 2000 World Oil and Gas Assessment projected that
    (excluding the U.S.) the world's undiscovered conventionally
    recoverable oil, natural gas liquids (NGL), and natural gas is about
    1,634 billion barrels of oil, expressed as barrels-of-oil equivalent
    (BOE). This estimate is about 5 percent higher than the USGS 1994
    estimate of 1,556 billion BOE. (USGS, 2000). The USGS 2000 estimate
    includes a 20 increase in undiscovered oil, a 130 percent rise in NGL,
    and a 14 percent decrease in undiscovered natural gas. The large
    volumes of oil, gas, and NGL from reserve growth were not previously
    assessed by the USGS. Including U.S. resources, the 2000 USGS estimate
    shows a 9.5 increase overall in billion BOE, with oil up 24 percent,
    NGL up 104 percent and gas down 10 percent (USGS, 2000).
        Compared with their previous estimate, the 2000 USGS study shows
    (1) more oil and gas in the Middle East and North Africa, (2) more oil
    and gas in eastern South America, (3) generally less oil and gas in
    Mexico and China, and (4) much less gas in the Former Soviet Union
    (especially in the Arctic). Other Arctic areas of some basins in China,
    and the Alberta Basin of Canada are now expected to produce smaller
    amounts of gas than in previous USGS studies.
        Areas with the greatest volumes of undiscovered conventional oil
    include the Middle East, northeast Greenland Shelf, the West Siberian
    and Caspian areas of the former Soviet Union, and the Niger and Congo
    delta areas of Africa. Newly identified areas of oil potential with no
    previous production history include northeast Greenland and offshore
    Suriname.
        Areas with the greatest volumes of undiscovered conventional gas
    are the West Siberia Basin, Barents and Kara Seas shelves of the former
    Soviet Union, the Middle East, and offshore Norwegian Sea. Promising
    areas without current development are located in East Siberia and the
    Northwest Shelf of Australia.
        As shown in Table 1 below, not including the U.S., the average
    volumes of undiscovered world resources are 649 billion barrels of oil,
    4,669 Tcf of gas, and 207 billion barrels of NGL. In addition, the
    estimated mean additions to reserves from discovered fields are 612
    billion barrels of oil, 3,305 Tcf of gas, and 42 billion barrels of
    NGL. About 75 percent of the world's grown conventional oil endowment
    and 66 percent of the world's grown gas endowment have already been
    discovered in the areas assessed (outside of the U.S.). Also, for these
    areas, 20 percent of the world's grown conventional oil and 7 percent
    of the world's grown conventional gas had been produced by the end of
    1995.
        As of January 1, 1996, average U.S. estimates of undiscovered
    conventional oil are about 83 billion barrels, with reserve growth from
    existing fields contributing another 76 billion barrels, and known and
    identified reserves standing at approximately 32 billion barrels.
    Cumulative production to 1995 was about 171 billion barrels.
        In summary, the U.S. could be expected to produce about 191 billion
    barrels of additional petroleum from domestic supplies. At current
    rates of consumption, if one assumes that all domestic consumption
    could be supplied by domestic oil sources it would take about 29 years
    to exhaust the 191 billion barrels of additional domestic oil sources.
    By contrast, assuming that current rates of domestic production are
    maintained and that oil imports will grow to satisfy increasing demand
    (about 2.6 billion barrels of annual oil production), it would take
    about 73 years to consume the 191 billion barrels of identified
    domestic oil. These two scenarios bracket the likely maximum amount of
    time that this country has before the costs of using oil exceed the
    benefits of consuming it.
        Other studies, including at least one by the Rand Corporation,
    concentrate on quantifying the amount of domestic oil resources that
    may be economically producible. As such, these studies impart valuable
    information about the distribution and amounts of oil left in this
    country. But, the basic conclusion is nevertheless the same'the U.S.
    does not have enough oil and gas resources left in the ground that it
    can (or should) produce every barrel that it consumes. And, oil and gas
    imports are expected to become increasingly cheaper to consume than
    domestically produced energy. The larger question thus becomes, given
    these geological facts on the domestic energy supply, what is the best
    course of long-term U.S. energy policy.
    [GRAPHIC] [TIFF OMITTED] T8788.014

                           U.S. ENERGY POLICY OPTIONS

        When estimating a country's remaining energy resources it is
    generally assumed that the least expensive and most abundant oil and
    gas resources are found and consumed first. And, as a country consumes
    more and more domestic energy, progressively more expensive oil
    resources are found and consumed. But, there is another option to
    consuming all domestically produced energy--foreign oil imports can be
    substituted for domestic production.
        In fact, most countries' oil consumers seek to find the least
    costly sources of oil, regardless of whether they are derived from
    domestic or foreign sources. If imported oil is cheaper and more
    readily available to consumers, foreign oil will be preferentially
    consumed.

    A. Energy Security
        Much has been written about the security of U.S. supplies of oil--
    whether it is from domestic production or from imports. A particularly
    strong argument about energy security is that security of energy
    supplies increases as diversity of sources increases. This is the same
    concept that investment advisors counsel their clients'security comes
    from not placing all of your eggs in one basket. Thus, a mix of
    domestic production and imports from a multitude of foreign sources
    actually represents most countries' best source of energy security.
    Currently, the U.S. imports as much oil from non-OPEC as OPEC sources.
    The four largest sources of U.S. oil imports include not only Saudi
    Arabia, but also Canada, Mexico, and Venezuela. In many ways this
    reliance on disparate geographical sources of oil imports decreases
    U.S. dependence on domestic sources of oil and thus increases our
    energy security.
        This presumption seems to fly in the face of the common implicit
    assumption that domestic oil production is preferred to imports. But,
    there are at least two disadvantages to exclusively consuming domestic
    oil; (1) a barrel of domestic oil consumed now means that there is one
    less barrel of oil in the ground for future consumption'thereby
    decreasing future policy options and increasing the effect that any
    potential future foreign oil import interruption may have on this
    country.
        And, (2) U.S. domestic oil production tends to be more expensive to
    produce than imported oil'the costs of lifting, transported, and
    marketing U.S. domestic oil tend to exceed similar imported oil costs.
    The reason for this is that U.S. oil is produced from the world's most
    mature energy province. Most of the cheapest and most abundant oil has
    already been produced in the U.S. Meanwhile there are many foreign
    sources of oil--including non-OPEC, OPEC, Western and Eastern
    Hemisphere sources that are not as intensively explored and therefore
    the costs of bringing this oil to U.S. markets is much lower than
    domestic production.
        Yet another potential disadvantage of using only U.S.-produced oil
    is that it comes from a huge number of sites throughout the U.S.
    Domestic oil and gas is shipped by pipeline, tanker-truck, and other
    sources. The terrorists of 9/11 showed that America's huge geographical
    breadth is not immune from attackers. The vast pipeline network,
    domestic oil refineries and petrochemical complexes represent a
    tempting target for future terrorists. One might argue that these large
    spider-webs of oil refining and shipping might at least as vulnerable
    as the large supertankers that ship U.S. oil imports from many
    different points of the globe.

    B. U.S. Domestic Oil and Gas Endowment
        Virtually all studies have shown that, if every acre of U.S. land
    was opened up to drilling--including all parks, wilderness areas, and
    every offshore acre out as far as the 200-mile limit, the U.S. can
    never realistically expect to be able to produce all of its own energy.
    Not now, and not in the future. And, even if this country were able to
    produce every barrel of oil that it consumes, it may not be a desirable
    U.S. policy to maximize domestic energy production.

    C. U.S. Supply-Side and Demand-Side Energy Policy Options
        Nature has endowed this country with a finite amount of petroleum
    that cannot be changed by any government's policies. It can be argued
    that supply-side actions, such as subsidizing the production of ever-
    decreasing amounts of domestic oil at progressively greater costs is
    ultimately wasteful and counter-productive if one is pursuing energy
    security.
        One might say that this country could learn from the fundamental
    changes in international energy markets that started in the 1970s.
    Instead of encouraging more production of more expensive domestic oil
    and gas, this country could be concentrating on managing more
    productive energy policies. That is, this country could look not at
    supply-side policies, but instead could try to manage the demand-side
    of the energy equation.
        That is not to say that no supply-side actions might be
    appropriate'subject to the other potential uses of the land. There are
    strong arguments that this nation could support research into more
    efficient extraction of domestic energy resources. Of special interest
    are those policies that support research into wringing out more barrels
    of oil and gas from existing oil- and gas-fields. Currently producing
    fields typically do not produce as much as one-half of the identified
    oil-in-place. Productive energy policies could include advances in
    better visualizing the underground reservoirs and increasing the
    proportion of oil-in-place that is actually produced. These enhanced
    oil recovery (EOR) technologies tend to be expensive, but can be
    applied to known fields that already have the entire energy production
    infrastructures in place. In addition, existing energy production
    regions, such as the Gulf Coast onshore and offshore also tend to
    already have a well-trained, experienced workforce in a region that is
    currently set up to produce oil and gas efficiently. Another
    significant benefit of these EOR policies would be that fewer or no new
    pristine and un-roaded areas need to be disturbed for energy
    production.
        Drawing on this nation's recent history, there are some proven and
    very effective demand-side energy strategies. These effective policies
    that have been used before concentrated on (1) using oil and gas more
    efficiently, and (2) researching energy alternatives to conventional
    oil and gas. Collectively, these two broad strategies have had the
    effect of decreasing the amount of oil and gas needed by the country
    and thereby have increased the energy security of this nation. Also,
    recent U.S. history has shown that pursuing greater energy-use
    efficiencies and alternative energy sources does not mean that
    consumers must degrade their standard of living and make do with less.
    Instead, these two strategies can lead to an ever-increasing standard
    of living at a lower overall cost.
        For example, as we have seen in the last 20 years, Detroit has not
    raised the fuel efficiency of automobiles and light trucks. The average
    miles-per-gallon of these vehicles has actually decreased since the
    mid-1980s. But, in the 1970s and early 1980s Congress passed a binding
    set of standards that mandated higher fuel efficiency from these
    vehicles. Average fuel efficiency increased by 50 percent and more from
    earlier levels. The effect of this legislation was that consumers in
    the late 1980s drove cars and light trucks that were (1) more fuel
    efficient, (2) produced much less air pollution, (3) employed many more
    safety standards, and (4) actually produced greater power than vehicles
    of the 1970s. Instead of degrading the standard of living in this
    country the Corporate Average Fuel Efficiency (CAFE) standards actually
    led to improvements in every aspect of driving--including significant
    reductions in pollution and greenhouse gases. Both consumers and the
    automotive industry thrived.
        And, the impact of CAFE standards was not just isolated to a small
    portion of the energy sector. About two-thirds of all oil used in this
    country is used in the transportation sector. Congressional actions to
    improve fuel efficiency had a very significant impact on increasing
    this nation's overall energy security, resulting in a large reduction
    in U.S. oil demand.
        However, since the mid-1980s the U.S. has not moved to raise CAFE
    standards. In fact the standards have actually declined slightly since
    that time. Instead of building on past triumphs, the U.S. has been
    content to rest on its laurels. In the absence of a mandate from
    Congress, Detroit has not moved on its own to raise the mileage of cars
    and light trucks. As a result, the country's appetite for oil has been
    growing faster than it would have with more efficient cars and trucks.
    Another impact of this policy is that the production of airborne
    pollutants from cars and trucks has also not been controlled.
        The Bush Administration has proposed that energy incentives should
    be differentially applied to the supply-side of the energy sector.
    These incentives would largely have the effect of producing an ever-
    greater proportion of this nation's finite supply of oil. At the same
    time, the Administration is not concentrating on effectively using the
    demand-side incentives to use our oil and gas more efficiently.
    Pursuing this course of action will likely lead the U.S. to use up our
    domestic oil and gas at increasing rates, and allow less-efficient
    energy technologies to produce more pollution.
        The most-effective and least-intrusive energy policies that this
    country could pursue might be three-fold. (1) Get the most energy out
    of currently producing oil and gas fields using enhanced oil recovery
    (EOR). (2) Concentrate on making this nation's stock of energy-using
    technologies more efficient, so that every barrel of oil and every Mcf
    of gas could produce greater benefits to the users. And (3) develop new
    technologies that would give this country alternatives to conventional
    oil and gas--and substitute renewable energy sources such as solar,
    wind power, and biomass for conventional energy sources.
                                   references
        U.S. Geological Survey, 2000, World Petroleum Assessment 2000,
    Description and Results.
        [NOTE: The report entitled ``Examination and Critique of ARI
    Report: Undiscovered Natural Gas and Petroleum Resources Beneath
    Inventoried Roadless and Special Designated Areas on Forest Service
    Lands Analysis and Results, with Additional Discussion of U.S.
    Geological Survey and National Petroleum Council Reports'' has been
    retained in the Committee's official files.]
                                     ______

        A Brief Examination of the Adequacy of Future U.S. Natural Gas
                          Infrastructure and Resources

                                      and

            The Role of Public Lands in U.S. Natural Gas Production

                       A Report to The Wilderness Society

                          By Lookout Mountain Analysis

                            W. Thomas Goerold, Ph.D.

                                 June 18, 2001

                           I. INTRODUCTION AND LAYOUT

        This paper gives a concise description of some of the known and
    undiscovered natural gas resources that may underlie this nation's
    public lands. Included in this paper is an outline of current producing
    areas and a discussion of the locations of likely future producing
    areas--with distinctions drawn between Federal, non-Federal, onshore
    and offshore lands. Also found in this study is a summary of some of
    the constituents of U.S. natural gas infrastructure and recent trends
    in the sector. This paper additionally gives descriptions of the
    magnitude of existing, planned, and permitted natural gas pipeline
    projects. This information informs the reader about imminent additions
    to near-term future gas capacity and increased deliverability. Finally,
    this study briefly summarizes projected future U.S. natural gas supply,
    prices, and conclusions.
        Section II describes locations of currently producing areas.
    Section III looks at a statewide summary of the locations of current
    major gas reserves. Section IV examines the likely areas where future
    gas production will occur, with a brief discussion of contributions
    from Federal, non-Federal, onshore, and offshore lands. Section V
    briefly explains the components of the nation's natural gas supply
    network and summarizes recent trends in gas prices and consumption.
    Section VI lists recent and planned near-term future natural gas
    infrastructure improvements, with an analysis of their planned impacts
    on increasing the total quantity and efficiency of national natural gas
    supplies. Section VII summarizes the Department of Energy's projections
    on future price and availability of natural gas in the Untied States.
    Finally, Section VIII gives a summary and major conclusions of this
    report and Section IX discloses selected references.

             II. CURRENT GAS PRODUCTION FROM ONSHORE FEDERAL LANDS

        Total onshore- and offshore-marketed U.S. gas production in 2000
    was about 20.1 trillion cubic feet (Tcf) (DOE/EIA, 2001a). Gas
    production from all onshore Federal gas leases amounted to
    approximately 2.0 Tcf, or about 10 percent of national gas production.
    New Mexico public lands produced about 5.5 percent of all U.S. gas
    production in 2000.
        Approximately 53 percent of all onshore Federal gas royalties can
    be traced to New Mexico producing wells, 33 percent from Wyoming, 4
    percent from Colorado, 4 percent from Utah, 2 percent Texas, 1 percent
    Oklahoma, and about 0.1 percent Louisiana. Sixteen other states
    accounted for the other 3.6 percent of Federal gas royalties from
    onshore production. Using an average annual citygate price for all U.S.
    natural gas production of $4.70 per Mcf, total marketed value in 2000
    was about $94 billion. Total receipts from these onshore Federal gas
    royalties gas were about $611 million in 2000--approximately 0.7
    percent of the value of total U.S. natural gas output.

                     III. CURRENT U.S. NATURAL GAS RESERVES

        Detailed data are not readily available to show the Federal/non
    Federal breakdown of current natural gas reserves. An examination of
    gas reserves on a statewide basis shows that the seven largest
    concentrations of reserves, comprising 75 percent of total U.S. gas
    include onshore Texas (24 percent), followed by New Mexico (9 percent),
    Wyoming (9 percent), Oklahoma (7 percent), Alaska (6 percent), and
    Louisiana (6 percent). Offshore Federal areas in the Gulf of Mexico
    collectively contain about 15 percent of current U.S. natural gas
    reserves.

             IV. UNDISCOVERED ECONOMICALLY RECOVERABLE GAS RESERVES

    All Onshore Lands and State Offshore Lands
        USGS data show that there is about 196.3 Tcf of natural gas yet to
    be discovered in onshore and state offshore (up to three miles out to
    sea) areas at a gas price of about $3.90 per Mcf (2001 dollars) (USGS,
    1995). About 70.5 Tcf (36 percent) of this gas is expected to come from
    the onshore and state offshore areas bordering Texas and Louisiana.
    Another 29.1 Tcf (15 percent) is expected to be found in the Rocky
    Mountains and Northern Great Plains regions, about 35.2 Tcf (18
    percent) from the Colorado Plateau and Basin and Range provinces, as
    well as about 13 Tcf (7 percent) from West Texas and Eastern New
    Mexico, and about 14.2 Tcf from Midcontinent areas (7 percent).

    Federal Onshore Lands
        According to USGS estimates there is likely about 36.9 Tcf of
    economically recoverable gas at prices of about $3.90 per Mcf to be
    found in all onshore Federal lands--about 19 percent of total
    undiscovered U.S. onshore gas and 12 percent of total economically
    recoverable undiscovered U.S. gas resources. The region with the
    largest amount of the gas in Federal onshore lands is the Colorado
    Plateau and Basin and Range Province (parts of CO and NM, AZ, UT, NV)
    with about 19.4 Tcf. Also, the Rocky Mountain and Northern Great Plains
    Province (MT, ND, ID, WY, parts of CO) contains about 14.3 Tcf. The
    remaining 3.2 Tcf of economically recoverable gas that is expected to
    be found underneath other Federal onshore lands is scattered throughout
    the rest of the country (including Alaska).

    Federal Offshore Lands
        The Minerals Management Service (MMS) gives estimates of
    undiscovered economically recoverable gas from Federal offshore lands
    of 116.3 Tcf (MMS, 2001). However, the agency uses a gas price of only
    $2.11 per Mcf. As a result, the MMS estimate of 116.3 Tcf at $2.11 per
    Mcf almost certainly significantly underestimates the amount of
    undiscovered natural gas that would be economically recoverable at gas
    prices of $3.90 per Mcf. Combining the very conservative MMS estimate
    with USGS estimates yields a total estimate of economically recoverable
    gas in all onshore and offshore lands of at least 313.1 Tcf with gas
    prices of about $3.90 per Mcf.

    Gas Resource Distribution by Land Categories
        Figure 1 graphically shows the relative contributions of
    undiscovered economically recoverable natural gas reserves from onshore
    Federal and non-Federal lands, and from offshore Federal lands. The
    relative endowment of economically recoverable natural gas from
    offshore lands is likely to be very underestimated relative to onshore
    estimates. Offshore resource estimates from MMS assume a gas price of
    just $2.11 per Mcf gas. In contrast, the USGS onshore resource
    estimates assume a gas price of $3.90 per Mcf gas.

    [GRAPHIC] [TIFF OMITTED] T8788.015

        Despite the different gas price estimates, Figure 1 gives some
    indication of the relative importance of the different types of land
    for natural gas resource estimates. Figure 1 shows that the maximum
    contribution of economically recoverable natural gas from onshore
    Federal lands is about 12 percent of the estimated total undiscovered
    gas resource of 313 Tcf. Non-federal onshore lands likely hold at most
    51 percent, and offshore lands hold at least 37 percent of total
    undiscovered economically recoverable natural gas.
        Likely locations of future reserves of as-yet-unidentified bodies
    of natural gas have been detailed by the USGS. About 33.7 Tcf of
    undiscovered economically gas (at $3.90 per Mcf) is likely to be found
    underneath western Federal onshore lands. This quantity represents
    about a maximum of 11 percent of the nation's total future gas
    reserves. Most of the expected undiscovered economically recoverable
    gas is expected to be found within non-Federal onshore lands (<51
    percent), and from Federal offshore lands (>37 percent).

                    V. NATURAL GAS INFRASTRUCTURE AND TRENDS

    Infrastructure
        Several entities collectively comprise the U.S. natural gas system.
    Producers are individuals and companies that find and produce natural
    gas from the ground. Prices at the wellhead (point at which the gas
    emerges from the ground) are unregulated. Producers have freedom to
    negotiate any mutually agreeable prices and terms with downstream
    parties.
        Gathering lines from multiple wellheads transmit gas to processing
    plants where noxious gases and natural gas liquids are removed prior to
    the gas entering transmission pipelines. Most gathering pipelines fall
    under state jurisdiction.
        Transmission pipelines convey processed gas to specific delivery
    points that may include storage facilities, other transmission
    pipelines, or a ``citygate'' (entry point of gas from transmission
    pipeline to a Local Distribution Company [LDC]). Pipelines that span
    more than one state have their rates and terms and conditions of
    service regulated by the Federal Energy Regulatory Commission (FERC).
    Pipelines confined to one state are typically regulated by that state's
    Public Utility Commission (PUC).
        Natural gas is not consumed at a uniform rate throughout the year.
    It is used at a much greater rate during winter months, primarily for
    space heating. In anticipation of the greater drawdown of gas during
    the winter months, much of the gas produced during other seasons is
    ``parked'' in storage facilities. Gas can then be drawn at a greater
    rate from storage facilities than from initial production and
    processing areas as it is needed throughout the year.
        Local Distribution Companies (LDCs) move the gas from citygates to
    intermediate and final users of natural gas. Much of the end-user cost
    of natural gas can be traced to the capital and operating costs of
    building and maintaining the spider-web of small pipeline networks that
    convey the gas to the multitude of end users.
        Marketers are companies that perform ``packaging'' functions for
    natural gas consumers. These firms may contract with a variety of
    producers, pipelines, LDCs, and other companies to sell a discrete
    package of natural gas supply, storage, and delivery under various
    prices and conditions.
    Recent Trends

                                  CONSUMPTION

        Consumption of natural gas reached a record level of 22.8 trillion
    cubic feet (Tcf) in 2000--a growth of about five percent over 1999
    (DOE/EIA, 2001b). Most of the annual variation in natural gas
    consumption can be attributed to winter temperatures. Colder winters
    produce a greater demand for gas.
        But, trends in natural gas consumption are more complex than
    weather patterns. In 2000 about 40 percent of gas consumption came from
    the industrial sector. Gas is primarily used in this sector for
    cogeneration (combined power and heating), and as a feedstock to
    produce other hydrocarbon-based goods. Seasonal demand in this sector
    is the least temperature-sensitive. Although some industrial users of
    natural gas can switch between fuels (a typical gas substitute is fuel
    oil) with energy price changes, most industrial users of natural gas do
    not have that capability.
        The residential and commercial sectors collectively consumed about
    40 percent of gas in 2000. Increases in natural gas demand in the
    residential sector can be linked to increases in the average size of
    homes and the fact that in 1999 more than 70 percent of new homes use
    natural gas for heat, compared with 47 percent in 1986. Commercial use
    of natural gas has increased even faster than residential use. Both of
    these sectors' natural gas consumption is quite temperature sensitive.
    Peaks in gas consumption almost invariably occur during January and
    February for these users.
        The other 20 percent of natural gas consumption in 2000 can be
    traced to the electrical generation sector. Natural gas is used as a
    fuel for at least two types of electrical generators (1) combustion
    turbines and (2) combined-cycle plants. Combustion turbines have the
    advantage of being relatively cheap and quick to build, have high
    efficiencies, and can be turned on and off quickly to satisfy short-
    term peaks in demand for electricity. But, combustion turbines are not
    usually the only source of electricity at generating stations because
    they are relatively expensive to operate. Combined-cycle plants use
    gas-fueled boilers and apparatus to combine power-generation and
    heating functions. Seasonal peaks in natural gas demand occur during
    the summer months in the electrical generation sector (air-conditioning
    demand), with smaller peaks during the winter months (space-heating
    demand). Thus, to some extent, seasonal peaks in the electrical
    generation sector are not coincident with industrial, commercial, and
    residential sectors.

                                     PRICES

        Prices of natural gas reached unusually high seasonal peaks during
    the winter months of 2000-2001, particularly natural gas prices in the
    Western U.S. and California. Citygate prices during the winter ranged
    from about $6.60 in Chicago, to more than $15.00 in Southern
    California. In the third quarter of 2000, prior to the winter of 2000-
    2001, natural gas prices varied from about $4.50 in Chicago to $5.30 in
    Southern California.
        While it is common for natural gas prices to rise during the winter
    months, the amount of seasonal and regional variation seen last winter
    is unusual. Most experts attribute the large price increases to several
    factors; (1) a long-term trend of relatively low natural gas prices
    during most of the 1990s that limited producers' cashflow and led to
    low levels of natural gas exploration and production, resulting in
    decreases in the natural gas supply; (2) increases in gas consumption
    that were encouraged by the relatively low gas prices (see the
    preceding sections); (3) unusually cold winter months over much of the
    U.S. during January and February 2001; (4) uncharacteristically low
    levels of rainfall in the western U.S. that led to smaller-than-normal
    amounts of hydropower available for electrical generation in the
    Western U.S.; and (5) an August 2000 rupture in an El Paso natural gas
    pipeline connecting natural gas from producing centers in Colorado,
    Texas, Wyoming, and New Mexico to consuming centers in California,
    Arizona, and New Mexico.

                               NATURAL GAS SUPPLY

        In a free market economy prices represent an investment signal.
    Increases in natural gas prices that commenced in about 1999 were
    interpreted by natural gas producers as a call for increasing natural
    gas supplies. With the increased cashflow available from higher natural
    gas sales revenues, producers stepped up their natural gas drilling
    campaigns. The Oil and Gas Journal reported that 154 independent U.S.
    producers increased capital spending by 48 percent from 1999 to 2000
    and planned a further increase of 35 percent in 2001 (as reported in
    DOE/EIA, 2001b).
        The frenzied pace of natural gas exploration and production in this
    country shows no signs of abating soon. As a matter of fact, as
    reported by Natural Gas Week, U.S. contractors and service companies
    are ``flinging themselves into a headlong rush for rigs as the boom is
    beginning to take on fabled proportions.'' First quarter 2001 profits
    reported by one of the largest natural gas service companies, Baker and
    Hughes, rose by 600 percent compared with a year earlier (as reported
    in DOE/EIA, 2001b).
        In 2000 there were about 720 rotary rigs working, an increase of 45
    percent from 1999. There are now few or no inactive drilling rigs now
    available in this country. Clearly, the natural gas sector is now in
    the midst of a boom fueled by the relatively high natural gas prices.
    There is not apparent shortage of available targets in the U.S. for
    producers that are completely utilizing available natural gas drilling
    rigs.
        Only now are the results of the increased exploration and
    production actions commencing in late 1999t beginning to be seen in the
    marketplace. The lag between drilling and the addition of natural gas
    reserves is usually about 6 to 18 months. After hitting a low of 18.6
    Tcf of production in 1999, natural gas production increased by 0.7 Tcf
    in 2000, with significant additional production increases likely as
    time goes on.
        In tandem with recent increasing domestic activity, imports and
    exports of natural gas from Canada and Mexico, and imports of Liquified
    Natural Gas (LNG) from abroad have increased as well. About 94 percent
    of all gas imports into the United States came from Canada in 2000. Our
    northern neighbor has very extensive deposits of the fuel. Canada
    continues to link its large natural gas resources with major U.S.
    consuming centers. Imports of Canadian gas showed annual increases of 5
    percent in 2000, 10 percent in 1999, 5 percent in 1998, 1 percent in
    1997, and 2 percent in 1996. Most of the import increases were due to
    increased pipeline capacity within and between the two countries.

                  VI. NATURAL GAS INFRASTRUCTURE IMPROVEMENTS

        The large price differential between citygate prices of natural gas
    of Southern California and Chicago in early 2001 discussed above
    ($15.00 vs. $6.60), shows the importance of natural gas infrastructure
    in determining end-user natural gas prices. The natural gas
    infrastructure was not able to deliver enough gas from the wellhead to
    the end users in Southern California. The result was a more than $8.00
    price differential between citygate prices. Improvements in the natural
    gas infrastructure will help ensure that gas delivery flexibility will
    exist in the future to help eliminate very large regional price
    differentials. The problem was not an inadequacy of natural gas at the
    wellhead, but a deficiency in the natural gas delivery mechanism to the
    end user.
        More than 165 U.S. inter- and intra-state pipelines contain about
    278,000 miles of transmission lines along with many related structures
    and facilities. About 1,300 LDCs deliver gas to intermediate and end
    users through another 700,000 miles of pipelines.
        Most often, the sources of natural gas are not located near the
    population centers containing the majority of the users of natural gas.
    As new sources of gas are found and developed they must be linked with
    new and existing pipelines to deliver the gas to the ultimate users.
    The natural gas infrastructure must also be linked with extensive
    storage facilities in order to maximize the efficiency in delivering
    this fuel whose demand has so much seasonal variation. Pipeline
    utilization levels in some parts of the West (particularly California)
    have recently been consistently above 95 percent (DOE/EIA, 2001b). Such
    high utilization rates leave little time for essential maintenance and
    capital improvements.
        Since 1999, more than 60 natural gas pipeline projects have been
    completed and placed in service. These projects have increased capacity
    by more than 12.3 billion cubic feet per day (bcfd)--an increase of 15
    percent over the 1998 level (DOE/EIA, 2001b). Most recent pipeline
    capacity additions have focused on bringing more Canadian gas into the
    U.S. Northeast and Midwest.
        Also, increases in coalbed methane production from the Rocky
    Mountains in Wyoming and Montana have created the need for more
    pipeline capacity from that region to end users. Only recently have
    proposal been made to move the large increases in gas seen in the Rocky
    Mountain region to areas where it is can be used.
        In the last five years there have been very extensive pipeline
    improvements made in order to transport the huge amounts of gas found
    in the Gulf of Mexico to consuming regions. From 1997 to 1998, 14 gas
    pipeline projects added about 6.4 billion cubic feet per day of
    capacity to the region.
        The Department of Energy reports that there are 88 announced
    pipeline projects proposed over the next several years. These proposals
    would add an additional 20.8 billion cubic feet per day of capacity.
    The Midwest would add the most capacity (5.1 bcfd), followed by the
    Northeast (4.8 bcfd), Southeast (4.2 bcfd), Far West (2.6 bcfd),
    Southwest (2.0 bcfd), and Centeral (2.0 bcfd). These projects would
    collectively increase the nation's gas transportation capacity by about
    22 percent.
        LDCs have also been expanding at a rapid rate. American Gas
    Association estimates show that construction projects by distribution
    companies increased by 16 percent in 1998 and 1999 compared with 1996
    and 1997 (as reported in DOE/EIA, 2001b).

                 VII. NATURAL GAS PRICE AND SUPPLY PROJECTIONS

        The energy sector is notorious for going through periods of boom-
    and-bust, especially in the last three decades. One only has to look
    backwards to 1998 to early 1999 to see that the natural gas industry in
    a bust cycle. The booms and busts in oil and gas are not necessarily
    coincident.
        The Department of Energy (DOE) projects that the natural gas sector
    will continue to in a ``boom period'' during the near term. The next
    few years will likely exhibit relatively high natural gas prices and
    concomitant high levels of domestic exploration and development, as
    well as elevated levels of capital spending on infrastructure
    improvements. From 2000-2002 natural gas consumption is projected by
    DOE to grow at an annual level of 3.6 percent, compared with the 1994-
    1999 annual level of 0.9 percent (DOE/EIA, 2001c).
        But, the same relatively high prices that encourage increased
    activity on the natural gas supply side will also discourage new and
    existing investments in natural-gas-using equipment. Also, high gas
    prices will especially encourage the industrial sector to invest in
    fuel-switching capabilities that would allow them to decrease their
    natural gas demand during periods of high prices.
        DOE estimates that natural gas resources are expected to be
    adequate to meet future gas demand through 2020 (the last year of the
    forecast). In concert with this conclusion, long-term prices of natural
    gas in this country are expected to return to a lower price path in
    2005 and then gradually increase to about $3.05 per Mcf in 2020.
    Advances in drilling and production efficiency applied to domestic gas
    resources, greater availability of imports from Canada and Mexico, and
    LNG imports from abroad are expected to adequately satisfy U.S. demand
    for natural gas to at least 2020.
        The National Petroleum Council (NPC) agrees with DOE in its
    assessment of the size and availability of natural gas resources,
    saying that ``the estimated natural gas resource base is adequate to
    this increasing demand for many decades, and technological advances
    continue to make more of those [natural gas] resources technically and
    economically available (NPC, 1999).''

                               VIII. CONCLUSIONS

        Gas production from all onshore Federal gas leases in 2000 amounted
    to approximately 2.0 Tcf, or about 10 percent of national gas
    production. New Mexico public lands produced about 5.5 percent of total
    U.S. gas output and 53 percent of all onshore Federal gas royalties.
    Wyoming, Colorado, Utah, Texas, and Oklahoma Federal lands also
    contributed Federal royalties from gas production Total receipts from
    these onshore Federal gas royalties gas represented about 0.7 percent
    of the market value of total U.S. natural gas output in 2000.
        Future contributions from onshore Federal lands to domestic natural
    gas production is likely to be limited to about 37 Tcf--about 12
    percent of the estimate of total national economically recoverable
    undiscovered gas resources of 313 Tcf. Non-federal onshore lands likely
    hold at most 51 percent, and offshore lands hold at least 37 percent of
    likely future gas production.
        Natural gas in the ground is usually found by producers, fed into
    gathering lines that move the gas to processing facilities, and then
    route it into gas pipelines. These pipelines then typically convey the
    gas to (1) storage facilities, or (2) citygates where it is further
    distributed by Local Distribution Companies (LDCs), or (3) other
    pipeline nodes.
        Consumption of natural gas reached a record level of 22.8 trillion
    cubic feet (Tcf) in 2000--a growth of about five percent over 1999.
    Prices of natural gas also reached unusually high seasonal peaks during
    the winter months of 2000-2001.
        While it is common for natural gas prices to rise during the winter
    months, the amount of seasonal and regional variation seen last winter
    is unusual. Most experts attribute the large price increases to several
    factors; (1) a long-term trend of relatively low natural gas prices
    during most of the 1990s that limited producers' cashflow and led to
    low levels of natural gas exploration and production, resulting in
    decreases in the natural gas supply; (2) increases in gas consumption
    that were encouraged by the relatively low gas prices; (3) unusually
    cold winter months over much of the U.S. during January and February
    2001; (4) uncharacteristically low levels of rainfall in the western
    U.S. that led to smaller-than-normal amounts of hydropower available
    for electrical generation in the Western U.S.; and (5) an August 2000
    rupture in an El Paso natural gas pipeline connecting natural gas from
    producing centers in Colorado, Texas, Wyoming, and New Mexico to
    consuming centers in California, Arizona, and New Mexico.
        With the increased cashflow available from higher natural gas sales
    revenues, producers stepped up their natural gas drilling campaigns.
    The Oil and Gas Journal reported that 154 independent U.S. producers
    increased capital spending by 48 percent from 1999 to 2000 and planned
    a further increase of 35 percent in 2001. Clearly, the natural gas
    sector is now in the midst of a boom fueled by the relatively high
    natural gas prices. There is no apparent shortage of available
    prospective natural gas drilling targets, as evidenced by the almost
    complete utilization of available drilling rigs.
        After hitting a low of 18.6 Tcf of production in 1999, natural gas
    production increased by 0.7 Tcf in 2000, with significant additional
    production increases likely as time goes on. In tandem with recent
    increasing domestic activity, imports and exports of natural gas from
    Canada and Mexico, and imports of Liquified Natural Gas (LNG) from
    abroad have increased as well.
        The large price differential between citygate prices of natural gas
    of Southern California and Chicago in early 2001 discussed above
    ($15.00 vs. $6.60), shows the importance of natural gas infrastructure
    in determining end-user natural gas prices. The natural gas
    infrastructure was not able to deliver enough gas from the wellhead to
    the end users in Southern California. The result was a more than $8.00
    price differential between citygate prices. Improvements in the natural
    gas infrastructure will help ensure that gas delivery flexibility will
    exist in the future to help eliminate very large regional price
    differentials. The problem was not an inadequacy of natural gas at the
    wellhead, but a deficiency in the natural gas delivery mechanism to the
    end user.
        Since 1999, more than 60 natural gas pipeline projects have been
    completed and placed in service. These projects have increased capacity
    by more than 12.3 billion cubic feet per day (bcfd)--an increase of 15
    percent over the 1998 level (DOE/EIA, 2001b). Most recent pipeline
    capacity additions have focused on bringing more Canadian gas into the
    U.S. Northeast and Midwest. In the last five years there have been very
    extensive pipeline improvements made in order to transport the huge
    amounts of gas found in the Gulf of Mexico to consuming regions. From
    1997 to 1998, 14 gas pipeline projects added about 6.4 billion cubic
    feet per day of capacity to the region. The Department of Energy
    reports that there are 88 announced pipeline projects proposed over the
    next several years. These proposals would add an additional 20.8
    billion cubic feet per day of capacity--an increase in capacity of
    about 22 percent.
        The Department of Energy estimates that natural gas resources are
    expected to be adequate to meet future gas demand through 2020 (the
    last year of the forecast). In concert with this conclusion, long-term
    prices of natural gas in this country are expected to return to a lower
    price path in 2005 and then gradually increase to about $3.05 per Mcf
    in 2020. Advances in drilling and production efficiency applied to
    domestic gas resources, greater availability of imports from Canada and
    Mexico, and LNG imports from abroad are expected to satisfy U.S. demand
    for natural gas up to at least 2020.
        The National Petroleum Council (NPC) agrees with DOE in its
    assessment of the size and availability of natural gas resources,
    saying that ``the estimated natural gas resource base is adequate to
    this increasing demand for many decades, and technological advances
    continue to make more of those [natural gas] resources technically and
    economically available (NPC, 1999).''

                                 IX. REFERENCES

    Department of Energy/Energy Information Administration (DOE/EIA),
            2001a, Natural Gas Monthly, various months.
    Department of Energy/Energy Information Administration (DOE/EIA),
            2001b, U.S. Natural Gas Markets: Recent Trends and Prospects
            for the Future, May 2001.
    Department of Energy/Energy Information Administration (DOE/EIA),
            2001c, Annual Energy Outlook 2001With Projections to 2020.
    Minerals Management Service (MMS), 2001, MMS News Release, January 17,
            2001, ``MMS Updates Estimates for Oil and Gas Resources on the
            OCS.''
    National Petroleum Council (NPC), 1999, Natural Gas: Meeting the
            Challenges of the Nation's Growing Natural Gas Demand.
    U.S. Geological Survey (USGS), 1995, Open File Report 95-75-N, 1995
            National Oil and Gas Assessment and Onshore Federal Lands.
                                     ______

        [Responses to questions submitted for the record by Mr.
    Goerold follow:]

                                  May 8, 2002

    Barbara Cubin, Chairman
    Committee on Resources
    Subcommittee on Energy and Mineral Resources
    1625 Longworth HOB
    Washington, DC 20515

    Dear Ms Cubin:

        I was a scheduled witness for the April 18, 2002 Oversight Hearing
    on Oil and Gas Resource Assessment Methodology. Although I did submit
    written testimony for the hearing record, I was unable to attend the
    hearing and give oral testimony, because of illness.
        This letter responds to four questions submitted to me after the
    April 18, 2002 Hearing:
        Q1. Regarding your analysis entitled ``Examination and Critique of
    ARI Report: Undiscovered Natural Gas and Petroleum Resources Beneath
    Inventoried Roadless and Special Designated Areas on Forest Service
    Lands ``,'' did the Hewlett Foundation or the Energy Foundation pay for
    any of this study?
        A1. Absolutely not.
        Q2. Please cite the studies that show ``that if every acre of U.S.
    land was opened up to drilling, including all parks, wilderness areas,
    and every offshore acre out as far as the 200-mile limit, the U.S. can
    never realistically expect to be able to produce all of its own energy.
    Not now and not in the future.
        A2. There are many contributory studies that give estimates of the
    amounts of discovered and yet-to-be-discovered oil, gas, and other
    energy sources in the United States. When one matches up the estimates
    of future domestic energy production with estimates of future U.S.
    energy consumption, it becomes readily apparent that the U.S. does not
    and will not have the capability of producing all of its energy needs
    as measured by any defensible mineral economics estimates.
        One document that I can use to support the questioned statement in
    my recent testimony is from the U.S. Geological Survey. It is titled
    ``Economics and the 1995 National Assessment of U.S. Oil and Gas
    Resources'', U.S.G.S. Open-File Report 95-75-M, by Emil D. Attanasi.
        Mr. Attanasi projects that a maximum of 69 billion barrels of oil
    (BBO) could be available for production from 1994 to 2015 (USGS OFR 95-
    75-M). The 69 BBO is derived from summing discovered and undiscovered
    conventional and unconventional oil resources that would be available
    at real oil prices up to $30 per barrel (in 1994 dollars).
        DOE's Energy Information Administration (EIA) shows historical and
    projected U.S. oil consumption from 1994 to 2000 and projected
    consumption from 2000 to 2015 (EIA, website, Table 5.1 Petroleum
    Overview 1949-2000, and Table 21, International Petroleum Supply and
    Disposition, 1999 to 2020). Adding together the total petroleum
    products consumed from 1994 to 2000 (47.59 BBO) and projected
    consumption for the same commodities from 2001 to 2015 (125.00 BBO),
    results in a total historical and projected petroleum product
    consumption of 172.58 BBO for the period 1994-2015. This amounts to
    103.58 BBO more than the maximum available amount of 69 BBO, as
    estimated by Mr. Attanasi.
        The above exercise shows that U.S. petroleum product consumption
    during Mr. Attanasi's study period (1994-2015) would amount to about
    250 percent of the maximum possible domestic petroleum supply. And,
    this exercise also assumes that all U.S. oil would be completely
    consumed by the year 2015. This is not a likely scenario.
        It is possible that the inflation-adjusted oil price could exceed
    $30 per barrel (in 1994 dollars, I believe). It is also possible that
    Mr. Attanasi has under-estimated the amounts of economically producible
    oil that is known and yet-to-be-discovered in the U.S. However, Mr.
    Attanasi's estimates would have to be more than 250 percent in error in
    order to come to the conclusion that the U.S. has enough domestic oil
    to supply its own needs from 1994 to 2015.
        A second piece of evidence to support my assertion that the U.S.
    cannot be self-sufficient in oil production can be inferred by looking
    at the attached graph that I produced (Figure 1). This graph compares
    EIA estimates of future petroleum consumption, domestic production, and
    the potential impact of a 3.2 billion barrel find of oil from the
    Arctic National Wildlife Refuge (ANWR), Alaska.
        Figure 1 shows the huge gap between domestic oil production and
    projected consumption. Short of a combination unforeseen and miraculous
    events, I believe that no reasonable energy analyst will predict that
    any policy actions by the U.S. could result in this country producing
    all of its oil needs.
        Q3. I have enclosed a recent article in Newsday that describes
    ongoing research at Woods Hole Oceanographic Institution indicating
    that some U.S. oil and gas reservoirs are being recharged, perhaps from
    an as yet unknown source. In some cases known structures are refilling
    relatively rapidly. This is evident in the Gulf of Mexico and may very
    well be occurring elsewhere. Would you comment on the implications this
    ongoing research could have [on] the long term outlook for U.S. oil and
    gas supply, both generally and particularly with regard to the
    statement above?
        A3. The U.S. has been producing oil since the mid-1850s. In that
    time this country has become the most thoroughly-explored oil province
    on earth. I believe that the observations referred to in the above
    article are apparently very preliminary and have not yet been exposed
    to scientific scrutiny over time. Because I am not familiar with these
    specific circumstances, my statements are only speculative in nature.
        Having qualified my remarks, I would say that, if there were shown
    to be a mechanism that is recharging depleted and depleting oil fields
    over time, that the rate of recharge would most likely be measured in
    geologic time, not in years. Otherwise the recharge phenomenon would
    have already been observed in the approximately 150 years worth of
    historical U.S. oil production.
        But, if science does show that there is some ``rapid-recharge''
    mechanism working in this country, it would strengthen some of the most
    prominent statements that I made in my written testimony to this
    Committee.
        The cheapest and most environmentally benign sources of future oil
    and gas in the U.S. are likely to be found within the boundaries of
    already discovered oil fields, not in the few remaining unexplored
    regions. Because most mineral economists assume that we have already
    found the majority of oil and gas that existed within U.S. boundaries,
    the largest sources of any ``rapid-recharge oil'' would also likely be
    found in already identified oil fields.
        Additionally, the U.S. can reap an added bonus from more intensive
    exploitation of known oil fields. On average, even in ``depleted'' oil
    fields there is likely more oil still remaining in known oil fields
    than has ever been produced from them. By concentrating on recovering
    the 50 percent-or-more of remaining oil in known fields, this country
    can leverage the huge investment already made in oil field
    infrastructure, pipelines, refineries, companies, and people that exist
    in known oil fields and regions.
    [GRAPHIC] [TIFF OMITTED] T8788.016

                                     ______

        Ms. Cubin. So with that, we would like to begin questioning
    members of this panel, and thank them very much for their well
    thought-out and very important testimony.
        I think I will start with Mr. Morton. And honestly, that is
    for no particular reason. It was just on top. Did the $172,000
    grant from the Hewlett Foundation to The Wilderness Society pay
    for your study entitled, ``The Department of Energy's Federal
    Lands Analysis Natural Gas Assessment: A Case of Expediency
    Over Science?''
        Mr. Morton. No.
        Ms. Cubin. Do you know where that grant did come from?
        Mr. Morton. I believe that the grant you are talking about
    was a grant to hire experts to review some of the environmental
    impact statements, etcetera, that are currently coming out.
    Those were experts in academia and other places that were not
    with The Wilderness Society.
        Ms. Cubin. Right.
        Mr. Morton. So that grant came probably--I don't know--six,
    7 months after I did the critique in July. And so that wasn't
    part of that. We didn't get any money from Hewlett. I would
    have liked to have had some money; but we didn't get any money
    to complete that. That was all on our own dime.
        Ms. Cubin. But it was peer-reviewed?
        Mr. Morton. What was peer-reviewed? I'm sorry?
        Ms. Cubin. But was it peer-reviewed?
        Mr. Morton. My critique?
        Ms. Cubin. Correct.
        Mr. Morton. I got advice from other people in the field,
    including Dr. Tom Goerold, who is not here. But it wasn't
    through a formal peer-review process.
        Ms. Cubin. OK. Mr. Morton, you have criticized the USGS
    several oil and gas assessments as being overly optimistic.
    These assessments' methods have been around since about the
    late '50's. Can you identify any regional oil and gas
    assessment that time has proven to be overly optimistic?
        Mr. Morton. I think you are mischaracterizing my criticism.
    My point with the USGS, for example, was that a lot of the non-
    market costs that go along with oil and gas extraction were not
    included. They do simply a financial analysis, which is just
    cost in dollars and a cash-flow, looking at bringing the gas to
    the wellhead.
        What I was looking at are some of the non-market costs--
    mitigation, restoration of damages, etcetera--that aren't
    included in that economic calculus. So I'm not that critical of
    the USGS. I am just making a note that these are very difficult
    to quantify values and costs, but they need to be considered in
    public land management.
        With the NPC report and some of the other ones, I was
    critical of the lack of adequate consideration of economic
    constraints. And I think in my testimony, when you are looking
    at the opportunity cost of something you need to look at the
    net benefits. And that's where the economics kind of plays in.
        Ms. Cubin. I lost my notes here. I will come across them
    soon. You talked about that all of the land had to be used in
    the resource management areas. How do you propose to mitigate
    or compensate the surface holder when land is to be developed,
    or is approved to be developed?
        Or I guess, what mitigation do you think there should be
    for the surface holder?
        Mr. Morton. I think the surface owner needs to get some
    consent agreement on the treatment of their property before
    they allow drilling to occur. I mean, we have this split estate
    problem, where a lot of the land owners have not been notified
    about the oil and gas companies coming. And I have heard horror
    stories from ranchers in Wyoming about oil companies just
    coming, and dropping a well, and building poorly designed
    roads, and impacting their grazing, and building water
    impoundments that take up a lot of land for them, without
    really any consideration of their damages to their land.
        And so I think you need to have some consent agreement from
    the private property owner before the drilling occurs, to take
    care of the damages that occur to their land.
        Ms. Cubin. I do, too. I think that, you know, the noise
    that is made by one of those compressors being 6 feet away from
    someone's house can certainly devalue the property owner's
    investment and, you know, maybe even drive him off his home. So
    I think those are things that need to be taken care of, and
    need to be decided. Some people shouldn't receive all the
    reward while others lose out just because that is where they
    live. Thank you very much, Mr. Morton.
        Now, Mr. Mankin, in your opinion, would the RAND approach
    work well for regional oil and gas assessments?
        Mr. Mankin. No, Madam Chairman, I don't think it would.
    What it does is, it applies an additional level, or an
    additional layer, of uncertainty on top of what is already an
    uncertain process. And simply adding that increases the bounds
    of uncertainty, and decreases the mean value.
        For example, I don't think there is a person in this room
    that could identify or properly predict the price of a barrel
    of oil or a cubic foot of natural gas five to 10 years from
    now, when some of these properties might eventually be
    developed.
        In addition to that, until you drill that first well, that
    discovery well, you know very little about the reservoir
    conditions. You don't know whether you have got a homogeneous
    reservoir. You don't know whether you have got a segmented
    reservoir. You don't know how many wells it is going to take to
    develop the resource. You don't know how much water you may
    have to contend with in connection with your production. You
    don't know what the quality or quantity of the resource may be
    in detail.
        And so all of these are factors that cannot be determined
    in advance. And to try to impose an economic value on a
    resource before you know anything about those conditions
    imposes an unreasonable burden to anyone attempting to consider
    that for potential development.
        Finally, every oil company has their own economic set of
    conditions, and none of them are the same.
        Ms. Cubin. Right.
        Mr. Mankin. Over the 35 years that I have been director of
    the Oklahoma Geological Survey, I have had an opportunity to
    visit with an awful lot of particularly smaller companies and
    independent operators, and have looked at their economic
    conditions. And I can assure you, they range all over the
    place.
        So their economic assessment would be different from any
    one organization's assessment. And therefore, I think it
    imposes an additional burden, an unnecessary burden, on the
    process. The AAPG believes that the only proper thing to do is
    to use technical resources for such assessments.
        Ms. Cubin. Mr. Otter, do you have any questions of the
    panel?
        Mr. Otter. Yes. Thank you very much, Madam Chairman.
        And I appreciate the panel's discussion and testimony thus
    far on this issue. Mr. Morton, I got to read briefly most of
    your testimony prior to the part that I didn't hear. I want you
    to know that I have become aware of it, even though I didn't
    get to be here while you were testifying. And much, I would
    say, of the testimony that you provided relies heavily on some
    concepts that have been adopted from the RAND report. Is that
    right? ``Assessing Gas and Oil Reserves in the Intermountain
    West?''
        You quoted extensively--I guess what I am saying in here--
    some of the opinions that were expressed in the RAND report.
    For instance, in quoting the RAND report you indicate that,
    ``The oil and gas leasing stipulations that dictate where and
    how and when exploratory drilling may be conducted in order to
    protect wildlife and the environment are not in many cases
    binding constraints on energy production.'' And you quote that
    from the RAND report.
        So do you consider the RAND report an authentic report, and
    one that you have digested, and one that has had peer review
    and everything?
        Mr. Morton. Yes, I do. I was actually one of the peer
    reviewers on the report, and I have digested that report quite
    heavily.
        Mr. Otter. I see. And in that RAND report, there certainly
    is the question--and I don't know if you were here when we had
    the first panel up--my question, as to how we assess economic
    viability of these. And do you agree, then, too, with the RAND
    report as far as that goes?
        Mr. Morton. Yes, I do. I think, if you look at economic
    theory, you need to look at the net benefits of oil and gas
    extraction. And I thought your line of questioning of the first
    panel was right on the money, because you can't just estimate
    gross amounts. You need to say, ``What is it going to cost us
    to get this to market?'' Because that is a comparable
    comparison to the net cost, or net benefits, that you are
    giving up.
        Mr. Otter. Right. And you heard the response that I
    received from the panel. And maybe I an re-asking the same
    question that the good Chairman asked, but can you point me to
    a project where these assessments were not made and the result
    was that the expectation, A, was not filled; B, it was not
    economically viable; and, C, we ended up holding the bag?
        Mr. Morton. Well, I have heard stories from ranchers in
    Wyoming, where people came in and dropped in dry wells, and
    left, and left them with all of the cost of cleaning up.
        Mr. Otter. On public lands?
        Mr. Morton. Well, this was split estates; so Federal and--
        Mr. Otter. But Mr. Morton--and I don't want to banter with
    you--you heard the assessments that the agency makes. It seems
    to me that perhaps that private land owner didn't make those
    same assessments. And I would think that whoever owns the
    land--And being an advocate of private property, I certainly
    wouldn't want the government coming in and making an assessment
    on my property as to whether I should or should not invite
    exploration of the sub-surface wealth on my property.
        And so do you basically, then, agree with what the first
    panel said relative to their assessments?
        Mr. Morton. I am not sure what I am agreeing to.
        Mr. Otter. OK. All right.
        Mr. Morton. But there are a lot of abandoned wells on
    public land that have not been reclaimed. All right? Hundreds
    of them, thousands of them. So there are a lot of cases. In
    fact, the majority of wells drilled in the U.S. have been dry
    wells, and a lot of those have been on public land. And a lot
    of those have left scars on the land which have not been
    reclaimed and have not been restored.
        Mr. Otter. And when did this happen?
        Mr. Morton. Over the last 50 years.
        Mr. Otter. And of course, that is my point. Wouldn't you
    agree that there are now, because of what the agency themselves
    said, safeguards in place that would guard against that
    happening again? When was the last time a dry well was left and
    the scar was left on the earth?
        Mr. Morton. I don't have exact information.
        Mr. Otter. OK.
        Mr. Morton. My point would be, even if you have
    stipulations that are designed to protect the environment, a
    lot of the times the bonding requirements are not enough to
    cover the cost of reclamation.
        Mr. Otter. Isn't that an assessment that then we should
    include and have to make?
        Mr. Morton. Yes.
        Mr. Otter. OK. I agree. Is it ``Knopman''?
        Ms. Knopman. Yes.
        Mr. Otter. Ms. Knopman, it was your testimony that you have
    given on this panel that I was referring to in many cases to
    the other panel. And I am once again using this as a blueprint
    for some of my questions.
        Did you agree or disagree with the Bureau of Land
    Management's response to my question to them relative to those
    four key areas?
        Ms. Knopman. Well, the purpose of our proposed methodology
    is to get at the very points that you raised in your line of
    questioning; which is that there is relevance in the arena of
    public policymaking for understanding economic viability:
    wellhead costs, and the transportation and infrastructure
    costs.
        This is what we do in all other areas of energy policy, as
    well as other kinds of development. The President's energy
    policy itself is, I think, to a large measure, built around
    notions of economic viability; a certain kind of realism over
    the next ten, 20, 30 years, of what we can do technologically.
    So I think these are relevant lines of inquiry.
        Mr. Otter. Madam Chairman, are we going to have a second
    round?
        Ms. Cubin. Without objection. Go ahead.
        Mr. Otter. Thank you, Madam Chairman. I don't object.
    Certainly.
        [Laughter.]
        Mr. Otter. I have noticed, with some curiosity, that on the
    front page of your testimony, under all the salutations and
    everything, it says that, ``This statement is based on a
    variety of sources, including research conducted at RAND.
    However, the opinions and conclusions expressed are those of
    the author, and should not be interpreted as representing those
    of RAND or any of the agencies or others sponsoring its
    research.''
        So I guess what I am going to ask you is, who is the ``we''
    that you constantly cite, and ``our''? And who is this
    plurality of people that you constantly cite in your report?
        Ms. Knopman. There are eight authors on this report, and I
    am one of those authors. I can read the names for the record,
    if you would like.
        Mr. Otter. I would like those names in the record. Madam
    Chairman, without objection?
        [Pause.]
        Mr. Otter. [Presiding.] I guess I am the Chairman.
        Ms. Knopman. The authors' names are Tom LaTourette, Mark
    Bernstein, Paul Holtberg, Christopher Pernin, Ben Vollaard,
    Mark Hanson, Kathryn Anderson, and myself, Debra Knopman.
        Mr. Otter. OK. And so then this represents not the RAND
    Corporation; but this then represents yourself and your co-
    authors' report?
        Ms. Knopman. That is right.
        Mr. Otter. But I will tell you, that was very misleading.
    Because I have been the benefactor of some terrific RAND
    reports, and seeing that on the front of your testimony copy,
    and the constant reference to that in here, led me to believe,
    until I saw the disclaimer--not unlike what I have to put on
    every one of my political commercials; I hope not with the same
    result--I would say that it is very misleading.
        And I don't mean that necessarily as criticism, but only as
    a clarification; that if I thought this was the result of
    RAND's acceptance, and drawing the conclusions that are drawn
    in this report and in this testimony, then for me--And mostly,
    it is because I guess I don't know you very well, and I am not
    familiar necessarily with your work; but I am very familiar
    with RAND, and it has a high degree of integrity for me. And so
    for that reason, I guess I might say I was confused.
        Ms. Knopman. If I could just clarify, RAND does not have an
    institutional position on any issue. And that disclaimer is
    standard, whether someone from RAND would be here talking about
    national security, or education, or health, or civil justice,
    or any of the other areas that we work in.
        So this is not particular to this study, for this study did
    go through the RAND peer review and quality assurance process.
    And beyond these authors, other people at RAND have been
    involved in the review of this work. But this is standard for
    all of our work.
        Mr. Otter. OK. We agree then that this is not RAND's
    production, and RAND has not adopted this? Would RAND offer the
    same disclaimer that you offered?
        Ms. Knopman. RAND offers the same disclaimer on every
    publication it produces.
        Mr. Otter. OK. I want that made clear, and I want that for
    the record. And I have to keep talking until the Chairman gets
    back--which is not hard for me to do.
        My next question then goes to the equation that you set up
    for recovering the cost of development and market access. Are
    you aware of any company that would invite exploration, or
    would undertake exploration, that wouldn't make those
    assessments?
        Ms. Knopman. Well, that is precisely our point, that the
    companies do this. The issue that we address in our proposed
    method is that some of this information--not at the detailed
    level that the companies are talking about, but certainly on a
    basin-wide and regional level--that this is relevant
    information to be in the public domain for public debate.
        And it is not just for decisions that relate to the supply
    side of the energy equation, but, as I said in my testimony,
    there are many states, there are private business concerns
    trying to understand what our energy prospects are in the
    future, in particular for natural gas. And having some sense of
    what our resource base is, and what is available at what cost
    under varying assumptions about cost, under varying assumptions
    about technology, is very useful information from the
    perspective of putting together an energy portfolio. So there
    are multiple users of that kind of economic viability
    information.
        Dr. Mankin is exactly right when he talks about the
    uncertainties in the economic estimates, as well as the
    uncertainties in the estimate of what is in the ground, the
    resource.
        Mr. Otter. Well, the uncertainties of energy supply are
    certainly going to be reflected in the cost at the marketplace.
        Ms. Knopman. Sure. That is right.
        Mr. Otter. The uncertainty right now of a war on terrorism
    is going to reflect those same costs; the uncertainty of how
    many people are going to go on vacation; the uncertainty of
    whether or not the weather is going to be good or bad. You
    know, we are turning on the air conditioning in Washington,
    D.C., at an unusually early time of year--even from my short
    stay here I recognize that--while we just had a beautiful
    blanket of 12 inches of snow in Idaho. And so there are lots of
    uncertainties.
        But I am not sure if we can make that in a theoretical
    bubble, near as well as those people who are putting their
    dollars on the line, and their reputations on the line, and
    their marketplace holdings on the line, can make that
    assessment. And having been in business for 30 years,
    certainly, when I bought potatoes in the spring of the year,
    when people were putting them in the ground--long before the
    well was drilled--and I had to pay $5 a hundredweight for those
    potatoes, I had to speculate pretty much, and make a
    scientific--I won't finish the rest of that--make a scientific
    guess on what McDonald's was going to pay in November. And so
    making those assessments is one of the major risks in markets.
        And they labor to an exhaustive state sometimes, trying to
    make sure that that assessment is right. Because all the
    stockholders, their future viability in business all depends
    upon that. So I understand what it takes to develop an oil
    field.
        And would you agree, or disagree, that it is more
    economically viable to drill fewer wells and fewer
    explorations, as was suggested in your report, with combining
    the public lands with the private adjacent holdings? Would you
    agree, or disagree, that it is less costly to drill fewer wells
    than more wells?
        Ms. Knopman. I actually can't speak to that question. Our
    concern has to do with the resource assessment itself and
    understanding the available resource under different cost
    scenarios. These are planning scenarios for public land
    managers, as well as states planning their own energy futures.
    They need a better understanding of what the possibilities
    might be, given all of these uncertainties.
        We don't stop making estimates, just as you didn't stop
    making estimates of what the market might look like at the time
    you were ready to harvest your crop.
        Mr. Otter. But I want you to know, the United States
    Department of Agriculture didn't make that assessment. Because
    most of the time, they were wrong. They didn't have their
    checkbook on the line. And what they had on the line was trying
    to create a market suggestion of what was going to happen down
    the line.
        We have seen it happen in cattle, we have seen it happen in
    all kinds of agricultural commodities, where the report in
    January, February, or March, whether it is orange juice or
    cattle or potatoes, says one thing; yet the marketplace, from
    all other kinds of stimulations or inhibitions, has something
    else that is going to happen. If I had taken that marketplace
    report and used that as my business plan, I would have been in
    serious trouble, and I would have passed up a lot of
    opportunities.
        But from your report, I assess that economic viability is
    important. And I also know from my old days in the drilling
    business, in the oil business, that it costs a lot of money to
    drill one well. And it costs twice as much money to drill two;
    and three times as much, operationally, to drill three or four
    or five.
        And so it would seem to me that if we can assess a
    resource, a sizable resource, that you can drill one well,
    instead of ten or 20 or 30, that that is the resource that we
    ought to retract to, that is the resource that we ought to go
    to.
        Ms. Knopman. Yes, well, I think you are right. And I think
    part of the advantage of having this out for public debate is
    to gain some notions of understanding. We are not suggesting
    that there will be a single estimate of what the viable
    resources are going to be. There are going to be ranges. Those
    ranges are going to be based on assumptions that will be
    clearly defined, as well as showing how these things vary over
    time.
        Mr. Otter. So then, having said that, would you agree or
    disagree--and I am sure you have heard the rumors, or at least
    invited listening to them--that for every one oil well we would
    drill in ANWR, we would have to drill about 30 or 40 or 50 in
    the Continental United States? Do you agree or disagree with
    those non-peer-reviewed rumors?
        Ms. Knopman. I haven't looked at them. I haven't analyzed
    it. And I am not going to hazard a guess on what the value of
    information is, which is what you are really talking about when
    you go and put in a well.
        I will say--and Dr. Mankin's testimony and Mr. Seegmiller's
    testimony also addressed this--there are multiple ways to find
    out, to learn about, or make estimates of the resource in the
    ground. We have remote sensing techniques. We have a number of
    non-intrusive methods besides the drilling. But in some cases,
    drilling is the only way that you will get the kind of
    additional information you need to make a more reasoned
    judgment about whether to proceed with development or not.
        We don't have a position on whether or not exploration
    should or should not proceed. We are only saying that we think
    there are multiple uses and multiple public benefits of having
    some credible economic estimates, estimates of economic
    viability, out on the table as we are thinking about our energy
    future.
        Mr. Otter. Well, let me just conclude, and perhaps I am not
    even soliciting a response to this, Madam Chairman. But let me
    just conclude that my feeling is, all other things being equal,
    probably the best people making the assessment on the economic
    viability are the people that are going to pay for it. Thank
    you, Madam Chairman.
        Ms. Cubin. [Presiding.] The Chair would like to now put
    four documents into the record, without objection of course.
    Two of them will be additional statements by Dr. Goerold, who
    is not here today.
        Ms. Cubin. And a statement of the American Petroleum
    Institute.
        [The prepared statement of the American Petroleum Institute
    follows:]

                 Statement of the American Petroleum Institute

        The American Petroleum Institute (API) welcomes this opportunity to
    present the views of its member companies on the methods of resource
    evaluation employed by the United States, and the role of these methods
    in Federal policies affecting access to energy resources on Federal
    lands. API is a national trade association representing more than 400
    companies engaged in all sectors of the U.S. oil and natural gas
    industry, including exploration, production, refining, distribution,
    and marketing.
        We are gratified that this Committee appreciates the importance of
    the Federal lands in our nation's future energy supply. We applaud the
    Bush Administration for including access to Federal lands in its review
    of energy policy by a Cabinet-level task force on the subject, and we
    are encouraged that you and other Members of Congress of both parties
    are putting access to those lands high on your agendas.
        Today, we are asked to comment on the methods of resource
    evaluation employed to guide decisionmaking related to energy resources
    located on Federal lands. A number of recent studies, such as those by
    the National Petroleum Council in 1999 and by the Department of Energy
    in 2001, have made significant progress in quantifying the restrictions
    currently imposed on resource development on these lands. Ongoing
    studies mandated by Congress promise to further contribute to this
    pioneering effort to inventory the volumes and accessibility of energy
    resources on Federal lands. We applaud these efforts.
        We also recognize that there are a number of unanswered questions
    raised by the results of these studies. These questions form an agenda
    for a new round of research that builds on the efforts completed and
    ongoing. This agenda needs to be put in place promptly. We are
    encouraged by Secretary Abraham's recent call to the National Petroleum
    Council for a new study of natural gas, which provides a forum to do
    precisely that. But we are also concerned with a number of recent
    efforts that attempt to fill these unanswered gaps with implausible
    assertions aimed at discrediting the results completed to date. In this
    testimony, we lay out a view of what we regard as a legitimate agenda
    for such future research. We also challenge the assertions made to
    discredit the work to date, particularly the claims made by the
    Wilderness Society and by RAND in recent statements and studies.
    The NPC and DOE studies have pioneered new ground
        It is our belief that the analysis prepared by the NPC in 1999 and
    in several DOE studies of the Rocky Mountains since that time have been
    pioneering efforts which have greatly improved the information base
    supporting Federal land use decisions affecting energy supply. However,
    it is particularly difficult to quantify the constraints applied to gas
    resources on Federal multiple use land in the Western states.
    Approximately 205 million acres of Federal lands in these states are
    under the control of two Federal agencies with broad discretionary
    powers. The Bureau of Land Management (BLM), whose land management
    planning authority is derived from the Federal Land Policy and
    Management Act (FLPMA) of 1976, and the U.S. Forest Service (USFS),
    whose jurisdiction is derived from the National Forest Management Act,
    administer these Federal, non-park lands. Both agencies are required to
    manage most of these lands under the congressionally mandated concept
    of multiple use. Yet, BLM and USFS discretionary actions have withdrawn
    Federal lands from leasing, and long delayed other leasing decisions
    and project permitting.
        Prior to the 1999 NPC study, there was little information available
    quantifying the significance of these restrictions. We knew that the
    Rocky Mountains were one of the areas of the U.S. with the greatest
    potential, containing an estimated 346 TCF of remaining technically
    recoverable gas, and we knew that much of this resource was on Federal
    land. We also knew what lands were available for lease. However, we did
    not have a clear idea of how exactly access restrictions affected the
    producibility of the lease.
        Often getting a lease is not the most significant problem for
    producers. Difficulties in acquiring permits to drill wells on onshore
    government lands and overly restrictive lease stipulations are also
    responsible for limiting natural gas production. These are
    restrictions, such as ``no surface occupancy'' or seasonal
    stipulations, that go above and beyond the normal environmental
    stipulations and can prevent economic development of the lease without
    commensurate environmental benefit. The NPC study revealed that almost
    half of the untapped natural gas on multiple-use government lands in
    the Rockies is in areas either off limits or restricted by this type of
    stipulation laid down by one Federal agency or another.
        Likewise, the U.S. Forest Service recently banned our companies
    from exploring for oil and natural gas on promising government lands
    when it published rules to bar road building on nearly 60 million acres
    in the Forest System that, according to a Department of Energy study,
    could hold 11 trillion cubic feet of natural gas. Furthermore, the
    roadless rule case illustrated how Federal land use actions have
    disregarded energy potential as an important consideration. In the
    Rocky Mountains, access to about 83% of the affected gas resource could
    have been preserved by less than a 5% reduction in the roadless
    acreage. It was not.
    But the NPC study contained a dual message, leaving a key question
            unanswered
        While it suggested that there was a large volume of gas resources
    on Federal lands subject to restriction, it also identified a much
    larger volume of resources (>1000TCF) on property not subject to such
    restriction (either because it is not on Federal land or because it is
    not subject to access restrictions). This leaves open the question of
    whether, or to what extent, the identified access constraints are
    likely to be binding. To answer this question would require an explicit
    characterization of the relative cost of different components of these
    resources. That is, unless the restricted areas have some cost
    advantage over unrestricted areas, they will not be developed even if
    the restriction is removed.
    Recent challenges have suggested that access constraints are not
            binding
        This gap in our information has been exploited by those who do not
    believe greater access to government lands is needed to develop
    domestic energy supplies and enhance our security. Two examples of such
    efforts are recent statements by the Wilderness Society and by RAND.
    Wilderness Society.
        The first example was presented by the Wilderness Society in
    testimony before this committee and in a study submitted for the record
    last year. That statement concluded that only a small percentage of BLM
    lands in five western states is off limits to leasing and development.
    For example, while the numbers presented by the Wilderness Society do
    show that only about 3.5 percent of the BLM lands in Wyoming, Utah, New
    Mexico, Montana, and Colorado is strictly off limits to development,
    oil and gas resources in those states are not distributed uniformly
    across BLM lands. Specifically, while the Wilderness Society says only
    3.5 percent of BLM lands are off-limits, the NPC study identifies
    another 3.2 percent that are subject to No Surface Occupancy. The NPC
    study indicates that this 6.7 percent of BLM lands represents 15
    percent of the BLM natural gas resources, which are either off-limits
    or significantly impinged.
        More important, however, is the role of non-standard lease
    stipulations. The Wilderness Society's data show that seasonal and
    other non-standard stipulations restrict access to an additional 32
    percent of BLM lands. However, this impacts access to 47 percent of the
    natural gas resources estimated to exist on BLM lands in the Rockies.
    When all of these restricted and off-limit BLM lands are combined they
    total 38.7 percent, affecting 62 percent of the natural gas resources.
        Further, BLM is not the only Federal land management agency making
    such restrictions. The U.S. Forest Service, the Bureau of Indian
    Affairs and the departments of Defense and Energy in their computation
    of Federal multiple-use lands that are restricted to oil and gas
    development. In total, the National Petroleum Council estimates that
    some 137 Tcf of natural gas resources lie beneath Federal land in the
    Rockies that is either off limits to exploration, or heavily
    restricted. This is 48 percent of the natural gas on Federal land in
    the region, equivalent to the amount of gas needed to heat 120 million
    homes for more than 20 years.
        This does not include the more than 11 trillion cubic feet (Tcf) of
    natural gas that was summarily placed off limits in 2000 alone by the
    USFS ``Roadless'' rule.
        But stipulations are not the only impediments to bringing the oil
    and natural gas to America's consumers. Inadequate agency resources in
    many BLM offices and required but outdated resource management plans
    often make it difficult to get drilling permits, seriously delaying
    viable projects for up to 100 days, or sometimes years. In the Rawlins,
    Wyoming BLM office, for example, thousands of Applications for Permits
    to Drill are awaiting action because of manpower shortages. In the
    Buffalo, Wyoming office, thousands more are not being accepted by BLM
    because of limitations of the resource management plans (RMP) for the
    area. This is because the ``Reasonable Foreseeable Development'' (RFD)
    figures, estimates of future development, failed to recognize the
    interest in developing coal bed methane (CBM). Updating these RMPs and
    RFDs takes the BLM two or more years to complete, thus preventing any
    further oil and gas activity in that area until the plans are finished.
    RAND.
        The recent Rand Issue Paper, ``A New Approach to Assessing Gas and
    Oil Resources in the Intermountain West,'' provides another, more
    serious, challenge to the significance of the need for improved access
    to Rocky Mountain gas resources. It challenges the principal
    conclusions regarding access made by the 1999 NPC study, and the
    conclusions likely to come out of the ongoing Energy Policy and
    Conservation Act (EPCA) study being conducted by ARI. The principal
    conclusion of the RAND study is that these efforts at quantifying
    restrictions have grossly overstated the access problem, by assuming
    that the technically recoverable resources under such restriction would
    in fact be developed without the restriction. RAND asserts, based on
    resource economics developed by USGS in connection with its 1995
    national assessment, that only a small fraction of the technically
    recoverable resource is actually economically viable, so that many of
    the ``constraints'' discussed by NPC and the upcoming EPCA study are
    not in fact binding.
        While it is true that the NPC and other efforts cited do not
    present a full comparison of the relative cost of the abundance of
    resources identified in those studies, it does not follow that those
    studies have overstated the effect of access constraints, as RAND
    maintains. In fact, by its own admission, the RAND study rests on shaky
    foundations. It is hard to tell whether the conclusions presented are
    even conclusions at all. Some of the text seems more consistent with
    the language of a proposal for study rather than conclusions drawn from
    a study. For example, after presenting conclusions based on the USGS
    1995 cost analysis, the authors caution the reader to ``Note that these
    results do not necessarily reflect RAND's analysis. The costs of
    exploring and developing gas and oil deposits in the Rocky Mountain
    Region are decreasing with technological advances. Our economic
    analysis will use different data and assumptions and may produce
    different results.'' While the study cites a longer RAND study with a
    2001 publication date, this earlier study is not included on RAND's
    website list of publications, and a call to one of the study's authors
    revealed that the citation was in fact an error. The cited study has
    not yet been published or even completed.
        USGS itself has produced different results in recent years as it
    redoes its national assessment. In the Powder River Basin, for example,
    the USGS has already increased its estimate of the basin's technically
    recoverable CBM resources to 14.26 Tcf, up from 1.11 Tcf in 1995.
    Finally, it should be noted that the technically recoverable resource
    concept used both by ARI in its analysis and by NPC in its 1999 study
    are not the same as that used by the USGS, but are in fact concepts
    much closer to that of economically viable resources that RAND
    proposes.
    But the conclusion of the RAND study is highly implausible given recent
            experience
        The RAND study fills the gap left by the NPC study with a
    particularly implausible assertion, namely that the bulk of the
    unconventional Rocky Mountain gas is likely to be uneconomic relative
    to alternative supplies elsewhere. But the experience of the past
    decade suggests just the opposite. That is, the experience suggests
    that the unconventional resources of the Rockies enjoy a significant
    economic advantage over gas resources elsewhere.
        The Rockies have been the most dynamically changing portions of the
    domestic resource base. For example, coal bed methane production was
    negligible prior to the 90s, but by 2000 accounted for 8% of domestic
    gas production and 60% of the growth in total US gas production during
    the 90s. The basin has been undergoing a boom as producers increase
    their understanding of the techniques needed to produce the gas. The
    number of producing wells increased to 6,469 in July 2001 from 515 in
    July 1998. Production in July 2001 in the Wyoming portion of the basin
    reached 784 million cubic feet per day, a nearly 40-percent increase
    over July 2000 and a 190-percent increase over July 1999.
        As of July 2001, the basin contained less than 15 percent of the
    50,000 wells that are believed to be needed to fully tap the resource.
    Based on the productivity of the wells drilled to date, this would mean
    that the basin could produce over 5 billion cubic feet per day, more
    than the capacity of the proposed pipeline that would bring gas from
    Prudhoe Bay to the Lower 48 States. A major impediment to attaining
    this potential are the delays in the completion of the Powder River
    basin CBM environmental impact statement.
        Given these facts, it simply seems implausible to assert that only
    a small portion of the resource is expected to be economic or that the
    constraints are not likely to be significant. In fact, given the
    dominance of the area in recent growth, it seems far more plausible to
    conclude that such areas possess an economic advantage over
    alternatives.
    There is a legitimate need for further study
        The NPC study broke much new ground in exploring the potential role
    of access to Federal lands in the development of new US gas supply, but
    it left unresolved a key question as to the significance of the
    constraints it identified. To resolve this question, the next logical
    step should be to identify the cost characteristics of each of the key
    areas of the resource base. The RAND study makes no useful contribution
    to plausibly closing that gap. Identifying the relative cost of the
    restricted areas relative to the unrestricted areas is in fact a
    legitimate research issue that would enhance the value of the 1999 NPC
    study. As the NPC considers future extensions of its natural gas
    research, evaluating these relative costs should be seriously
    considered within their research agenda.
                                     ______

        Ms. Cubin. And the RAND report.
        [NOTE: The report of RAND Science and Technology submitted
    for the record has been retained in the Committee's official
    files. The report is accessible from the RAND home page, http:/
    /www.rand.org]
        Ms. Cubin. So the record will be held open. These will be
    placed in the record, but the record will be held open 10
    business days after this, if there are any remarks that you
    wanted to make in regard to those studies.
        I really sincerely thank the witnesses for their valued
    testimony, and the members for their questions. Members of the
    Subcommittee may have some additional questions, as I stated
    before; in which case, they would like to send these questions
    to you in writing. And we will hold the hearing record open for
    10 business days for those responses.
        If there is no further business then before the
    Subcommittee, the Chairman again thanks the members and the
    staff that were here. And the Subcommittee hearing is now
    essentially adjourned.
        [Whereupon, at 12:29 p.m., the Subcommittee was adjourned.]

        [A statement submitted for the record by Jeffrey Eppink,
    Vice President, Advanced Resources International, follows:]
                        ADVANCED RESOURCES INTERNATIONAL
                                 april 29, 2002

    The Honorable Barbara Cubin
    Chairwoman
    Subcommittee on Energy and Mineral Resources
    Committee on Resources
    U.S. House of Representatives
    1626 Longworth House Office Building
    Washington, DC 20515

    Dear Representative Cubin:

        I attended the hearing held by your Subcommittee on April 18, 2002
    on ``Oil and Gas Resource Assessment Methodology'' and would like to
    take the opportunity to comment on testimony and supporting documents
    submitted by Dr. Thomas Goerold. The information provided by Dr.
    Goerold addresses work performed by my firm, Advanced Resources
    International, for the U.S. Department of Energy. I would appreciate
    having this letter and its attachment made a part of the hearing
    record.
        While we welcome discussion on these issues, we believe many of the
    conclusions reached by Dr. Goerold to be inaccurate and a more thorough
    examination of the issues shows our work to be valid. We document
    multiple, representative examples in our attachment by way of
    illustration.
        If you have any questions or if you or your staff wishes to discuss
    any of the foregoing, please do not hesitate to contact me at (703)
    528-8420 or via email at jeppink@advres. com.

    Sincerely,

    Jeffrey Eppink
    Vice President
                                     ______

      Advanced Resources International Comments on Goerold Testimony and
      Documents for Subcommittee Hearing on April 18, 2002, ``Oil and Gas
                       Resource Assessment Methodology''

        Arguments Concerning the Importance of Domestic Production. The
    comment in Goerold's testimony\1\ is made: ``oil and gas imports are
    expected to become increasingly cheaper to consume than domestically
    produced energy''. This statement is incorrect. Because oil (and
    increasingly natural gas) is a fungible commodity, its price is set not
    on the basis of domestic production, but in the worldwide market by
    entities such as OPEC. Quite simply, if the costs associated with
    domestic production are too high, domestic resources will not be
    produced. This argument cannot be used, therefore, as a basis for
    obviating domestic production--production levels are set in the
    marketplace.
    ---------------------------------------------------------------------------
        \1\  ``Testimony of W. Thomas Goerold, Ph.D., Resource Economist,
    Owner of Lookout Mountain Analysis Before the Subcommittee on Energy
    and Mineral Resources Committee on Resources United States House of
    Representative'', Lookout Mountain Analysis, April 18, 2002.
    ---------------------------------------------------------------------------
        Further, the testimony argues that domestic production need not be
    increased, stating: ``there are two disadvantages to exclusively
    consuming domestic oil'' [emphasis ours]. It is widely recognized that
    domestic U.S. oil production will never again be able to satisfy
    growing U.S. demand as long as oil remains the primary transportation
    fuel. Goerold then seems to argue that oil resources should be saved
    for future consumption, but does not argue that they should not be
    produced. If that is the case, the issue becomes one of timing, not
    about whether domestic oil (and gas) should be produced.
        De--emphasis of Natural Gas. Consistently, we note, the Goerold's
    documents emphasize domestic oil production issues rather than a more
    balanced view of oil and gas production. At the conclusion of his
    testimony, Goerold states: ``The most-effective and least intrusive
    energy policies that this country should pursue [would include getting]
    the most energy out of currently producing oil and gas fields using
    enhanced oil recovery (EOR)'' [emphasis ours].
        On a thermal basis, over half the energy from domestically produced
    oil and gas comes from natural gas. Further, while we agree that EOR is
    needed (typically 30 to 40 percent of the oil is left in the
    reservoir), the same is not true for natural gas, where generally about
    70 percent of the resources in a field are recovered. At the same time,
    depletion rates in natural gas reservoirs are increasing. In the Gulf
    Coast of the U.S. depletion rates of 40 percent per year can occur, and
    the average size of the new fields discovered is decreasing.
        Goerold also asserts\2\ ``After hitting a low of 18.6 Tcf of
    production in 1999, natural gas production increased by 0.7 Tcf in
    2000, with significant additional production increases likely as time
    goes on'' [emphasis ours]. It is not at all clear that domestic natural
    gas production is increasing despite significant increases in drilling
    and, in fact, recent data from the Energy Information Administration
    (EIA)\3\ indicate that natural gas production is not increasing, but
    has flattened. It is unclear what the long-term trend will be.
    ---------------------------------------------------------------------------
        \2\ ``A Brief Examination of the Adequacy of Future U.S. Natural
    Gas Infrastructure and Resources and The Role of Public Lands in U.S.
    Natural Gas Production, A Report to the Wilderness Society'', by
    Goerold, Ph.D., W. Thomas, Lookout Mountain Analysis, June 18, 2001.
        \3\ Energy Information Administration, see the DOE website: http://
    www.eia.doe.gov/pub/oil--gas/natural--gas/data--publications/natural--
    gas--monthly/current/txt/ngprod mo.txt, 2002
    ---------------------------------------------------------------------------
        Given the accelerating depletion of natural gas resources in the
    Gulf Coast\4\, the Nation looks increasingly toward the deepwater Gulf
    of Mexico and the Rocky Mountains to provide potential supply. And for
    consuming states such as California, the Rockies represent a viable
    potential source of natural gas for power generation needs. So natural
    gas is extremely important and leads us to discussion of the ``roadless
    areas'' of the Rocky Mountains.
    ---------------------------------------------------------------------------
        \4\ Energy Information Administration, Accelerated Depletion:
    Assessing Its Impacts on Domestic Oil and Natural Gas Prices and
    Production -- Executive Summary, see the DOE website: http://
    www.eia.doe.gov/oiaf/servicerpt/depletion/, 2000
    ---------------------------------------------------------------------------
        Resources Associated with Roadless Areas. Advanced Resources
    estimates, on a thermal basis in major basins in the Rocky Mountains,
    over 85 percent of the oil and gas resources are natural gas. Rocky
    Mountain natural gas resources are overwhelmingly (over 90 percent)
    ``unconventional'' in nature (i.e., ``tight gas'' and coalbed methane).
    Thus, any discussion regarding these Rocky Mountain resources is
    essentially a discussion about unconventional natural gas, which is why
    we emphasized natural gas in our roadless analyses.\5\
    ---------------------------------------------------------------------------
        \5\ ``Undiscovered Natural Gas And Petroleum Resources Beneath
    Inventoried Roadless And Special Designated Areas On Forest Service
    Lands, Analysis And Results'' (see the U.S. DOE website http://
    www2.fossil.energy.gov/oil--gas/reports/roadless/ari--112000.pdf. ),
    2000 and ``Economically Recoverable Natural Gas Resources Beneath
    Inventoried Roadless Areas On Forest Service Lands, Analysis And
    Results'' (see the U.S. DOE website http://www2.fossil.energy.gov/oil--
    gas/reports/roadless/ari--113000.pdf. ), 2000
    ---------------------------------------------------------------------------
        In our analyses, our study area comprised the Forest Service's
    roadless and ``special designated'' areas (IRAs and SDAs), as opposed
    to the whole of the Rocky Mountain regions. We find Goerold's emphasis
    on the whole of the Rocky Mountain region to be misleading regarding
    the conclusions he draws concerning the size of the resource.\6\
    ---------------------------------------------------------------------------
        \6\ ``Examination and Critique of ARI Report: Undiscovered Natural
    Gas And Petroleum Resources Beneath Inventoried Roadless and Special
    Designated Areas on Forest Service Lands Analysis and Results, with
    Additional Discussion of U.S. Geological Survey and National Petroleum
    Council Reports'', by Goerold, Ph.D., W. Thomas, Lookout Mountain
    Analysis, undated, pp. 7-13.
    ---------------------------------------------------------------------------
        Regarding methodology\7\, we agree with Goerold that use of a
    homogeneous distribution of resources is a reasonable assumption,
    especially given the preponderance of unconventional natural gas
    resources in the Rockies, with their distributed nature of occurrence.
    Regarding the slope analysis, Goerold contends that this introduces an
    overestimation bias into our calculations. We fail to see how this
    could be true, given that, to account for slope variability, we used a
    lower resource estimate than would otherwise be the case. We believe
    the confusion may be that Goerold is failing to recognize that we made
    high, medium, and low estimates.
    ---------------------------------------------------------------------------
        \7\ Ibid., pp. 13-15
    ---------------------------------------------------------------------------
        Concerning the rate of technology change, use of technology
    improvements is an empirical observation and is a commonly recognized
    aspect of resource development economics (and in fact is modeled as
    such in the EIA's National Energy Modeling System)\8\. It is specious
    to think that, were roadless areas open to development, such technology
    improvement would be applied elsewhere, but would not be applied in
    roadless areas. In fact we maintain, that increased pressure would be
    brought to bear to use advanced technology on such oil and gas
    developments to meet environmental requirements.
    ---------------------------------------------------------------------------
        \8\ EIA, Annual Energy Outlook 2002 with Projections to 2020, (see
    the EIA website: http://www.eia.doe.gov/oiaf/aeo/appg.html. ), 2001
    ---------------------------------------------------------------------------
        Further, we do maintain, in contrast to the USGS analysis cited by
    Goerold,\9\ that drilling ``sweet spots''\10\ will increase
    economically recoverable resources. Goerold correctly notes that the
    USGS used a simplifying assumption that ignores ``the localized
    richness of some areas within each play.'' However in the real world,
    sweet spots do occur. According to Goerold's logic, the Jonah natural
    gas field, an unconventional field located in southwestern Wyoming
    producing over 700 million cubic feet of gas each day (enough to supply
    Los Angeles on most days), should not exist.
    ---------------------------------------------------------------------------
        \9\ USGS, ``Economics and Undiscovered Conventional Oil and Gas
    Accumulations in the 1995 National Assessment of U.S. Oil and Gas
    Resources: Conterminous United States'', 1998
        \10\ Op. cit., p. 17.
    ---------------------------------------------------------------------------
        Finally, Goerold asserts\11\ ``A primary ARI assumption is that any
    resources underlying IRAs would not be producible without building
    access roads within the IRAs.'' We believe this to be true and do not
    believe that directional drilling would be used extensively beneath
    roadless areas for exploration. As Goerold asserts, while it is true
    that industry can directional drill 5 or 6 miles, this is not a
    practice in exploration settings, especially in the Rockies.
    ---------------------------------------------------------------------------
        \11\ Op. cit., p. 18.
    ---------------------------------------------------------------------------
        Once a discovery is established, it could be developed with
    directional drilling. However, if one makes the general statement that
    long-range directional drilling is applicable in assessing roadless
    areas and wants to apply that to a 5 to 6 mile accessibility rim within
    those areas, it is equal to saying that the typical discovery in the
    roadless areas will be developed with a long-range directional
    drilling, which is clearly not the case, even if one were to use an
    (untenable) aggressively advancing technology scenario. We do recognize
    that our roadless analyses could be refined by modeling use of
    directional drilling, but based upon discussions with Federal officials
    and industry operators, the appropriate distance would be about ,
    mile.\12\
    ---------------------------------------------------------------------------
        \12\ Federal Lands Analysis, Natural Gas Assessment, Southern
    Wyoming and Northwestern Colorado, Study Methodology and Results, June
    2001, available on the DOE website: http://fossil.energy.gov/techline/
    tl--ggrb--gas.shtml.
    ---------------------------------------------------------------------------
        In conclusion, while we believe Goerold's testimony and documents
    raise some interesting points, we do not believe that it invalidates
    the basic conclusion that sizeable quantities of natural gas resources
    can be associated with roadless areas.
                                     ______

        [A letter and paper submitted for the record by Mr. William
    Whitsitt, President, Domestic Petroleum Council, follow:]

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