[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



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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
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    \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.''
---------------------------------------------------------------------------
    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).
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    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
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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.
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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.
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    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\
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    \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.
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    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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